United States
Environmental Protection
iAgency
SPCC Guidance
for Regional Inspectors
Tice of
nergency
anagement
ivember 15, 2013
EPA 550-B-13-002
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This document was prepared by the Regulation and Policy Development Division of the EPA Office of
Emergency Management under the direction of Mark Howard, Patricia Gioffre, and Troy Swackhammer.
Technical research, writing, and editing was provided under EPA Contracts No. 68-W-03-020 and
EP09H001292.
Original publication date: November 25, 2005. Revised: November 15, 2013.
The Office of Emergency Management gratefully acknowledges the contributions of EPA's program and
regional offices in reviewing and providing comments on this document.
Copies of this document may be obtained online at www.epa.gov/oilspill. In addition, updates to the
document will be available online.
Office of Emergency Management (5104A)
EPA 550-B-13-001
SPCC GUIDANCE FOR REGIONAL INSPECTORS
November 15, 2013
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Revision History since August 28, 2013 Publication
November 2013
Chapter 2 - Navigable waters: Replaced the reference to Rapanos guidance with a link to the Office of
water page on Waters of the US. (http://water.epa.gov/lawsregs/guidance/wetlands/CWAwaters.cfm).
Chapter 5 - Figure 5-7: Revised the representation of the OWS in the diagram.
Chapter 6 - Section 6.3: Added a reference to 40 CFR 110.6 regarding notification requirements and an
excerpt of the regulation.
Chapter 7 - Section 7.5.2: Changed the subsection heading to "No Applicable Industry Standard- Hybrid
Inspection Program Established"
Chapter 7 - Figure 7-4: Revised the summary of integrity testing and inspection program documentation
to add cross-references to footnote in the figure.
The text of the guidance identifies these revisions with the symbol
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Contents
Contents ii
List of Tables and Figures x
Tables x
Figures x
List of Abbreviations xiii
Disclaimer xvi
EPA Oil Program Contacts xvii
Chapter 1 Introduction 1-1
1.1 SPCC Background 1-1
1.1.1 Purpose and Scope 1-2
1.1.2 Statutory Framework 1-3
1.2 Regulatory History 1-5
1.2.1 Initial Promulgation and Early Amendments 1-6
1.2.2 SPCC Task Force and GAO Recommendations 1-6
1.2.3 Proposed Revisions-1991,1993, and 1997 1-8
1.2.4 2002 Amendments 1-9
1.2.5 Additional Amendments to Streamline the SPCC Rule 1-10
1.2.6 Compliance Date Amendments 1-10
1.3 Revised Rule Provisions 1-14
1.3.1 Rule Organization 1-15
1.3.2 Summary of Major 2002 Revisions 1-17
1.3.3 Summary of 2006 Revisions 1-18
1.3.4 Summary of 2008 Revisions 1-21
1.3.5 Summary of Navigable Waters Ruling 1-25
1.3.6 Summary of the 2009 Amendments to the 2008 Rule 1-25
1.3.7 Effective Date of the 2008 and 2009 Amendments 1-26
1.3.8 Summary of the Milk and Milk Product Container Exemption 1-26
1.4 Using This Guidance 1-26
Chapter 2 SPCC Rule Applicability 2-1
2.1 Introduction 2-1
2.1.1 Summary of General Applicability 2-1
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2.2 Definition of Oil 2-3
2.2.1 Petroleum Oils and Non-Petroleum Oils 2-4
2.2.2 Synthetic Oils 2-4
2.2.3 Animal Fats and Vegetable Oils (AFVO) 2-5
2.2.4 Asphalt 2-5
2.2.5 Natural Gas and Condensate 2-5
2.2.6 Oil and Water Mixtures 2-6
2.2.7 Produced Water 2-6
2.2.8 Hazardous Substances and Hazardous Waste 2-7
2.2.9 Denatured Ethanol used in Renewable Fuels 2-7
2.2.10 Biodiesel and Biodiesel Blends 2-8
2.3 Activities Involving Oil 2-8
2.4 Facilities 2-9
2.4.1 Definition of Facility 2-9
2.4.2 Definitions of Onshore and Offshore Facility 2-11
2.4.3 Definition of Production Facility 2-12
2.4.4 Drilling and Workover Facilities 2-13
2.4.5 Definition of Farm 2-14
2.4.6 Examples of Aggregation or Separation 2-15
2.4.7 Natural Gas Production/Treatment Facilities and Pipelines 2-23
2.5 "Non-Transportation Related" - EPA/DOT Jurisdiction 2-27
2.5.1 Tank Trucks 2-29
2.5.2 Railroad Cars 2-30
2.5.3 Loading/Unloading Activities 2-30
2.5.4 Marine Terminals 2-30
2.5.5 Vessels (Ships/Barges) 2-31
2.5.6 Breakout Tanks 2-31
2.5.7 Motive Power 2-32
2.5.8 Flowlines and Gathering Lines 2-32
2.6 Reasonable Expectation of Discharge to Navigable Waters in Quantities That May Be Harmful 2-33
2.6.1 Definition of "Discharge" and "Discharge as Described in §112.l(b)" 2-33
2.6.2 Reasonable Expectation of Discharge 2-34
2.6.3 Geographic Scope 2-36
2.6.4 Definition of "Navigable Waters" 2-36
2.7 Storage Capacity Thresholds 2-37
2.7.1 Storage Capacity Calculation 2-37
2.7.2 Definition of Storage Capacity 2-37
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2.7.3 Tank Re-rating 2-39
2.8 Exemptions to the Requirements of theSPCC Rule 2-40
2.8.1 Permanently Closed Containers 2-40
2.8.2 Offshore Oil Drilling, Production or Workover Facilities Subject to Minerals Management Service
Regulations 2-41
2.8.3 Underground Storage Tanks 2-42
2.8.4 Underground Emergency Diesel Generator Tanks at Nuclear Power Stations 2-44
2.8.5 Wastewater Treatment Facilities 2-45
2.8.6 Motive Power 2-46
2.8.7 Hot-mix Asphalt and Hot-mix Asphalt Containers 2-48
2.8.8 Heating Oil Containers at Single-family Residences 2-48
2.8.9 Pesticide Application Equipment and Related Mix Containers 2-49
2.8.10 Intra-Facility Gathering Lines Subject to Department of Transportation (DOT) Requirements 2-49
2.8.11 Milk and Milk Product Containers 2-50
2.8.12 Summary of Exemptions 2-50
2.9 Determination of Applicability by the Regional Administrator 2-51
2.10 SPCC Applicability for Different Types of Containers 2-52
2.10.1 Bulk Storage Container 2-52
2.10.2 Double-walled or Vaulted Tanks or Containers 2-53
2.10.3 Oil-filled Equipment 2-53
2.10.4 Oil-filled Operational Equipment 2-53
2.10.5 Oil-filled Manufacturing Equipment 2-54
2.10.6 Oil-powered Generators ("Gen-sets") 2-55
2.10.7 Bulk Storage Containers at Tank Battery, Separation and Treating Areas 2-56
2.11 Determination of Applicability of Facility Response Plans 2-58
2.12 Role of the EPA Inspector 2-58
Chapters Environmental Equivalence 3-1
3.1 Introduction 3-1
3.2 Substantive Requirements Subject to the Environmental Equivalence Provision 3-2
3.3 Policy Issues Addressed by Environmental Equivalence 3-5
3.3.1 Facility Drainage 3-6
3.3.2 Corrosion Protection and Leak Testing of Completely Buried Metallic Storage Tanks 3-8
3.3.3 Overfill Prevention 3-10
3.3.4 Facility Transfer Operations, Pumping, and Facility Process Requirements 3-12
3.3.5 Flowline/lntra-Facility Gathering Line Maintenance Program 3-16
3.3.6 Security (Excluding Oil Production Facilities) 3-19
3.3.7 Integrity Testing and Inspection Requirements for Bulk Storage Containers at Onshore Facilities 3-21
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Contents
3.3.8 Alternative Measures for Containers at Onshore Oil Production Facilities 3-21
3.4 Review of Environmental Equivalence 3-21
3.4.1 Consideration of Costs 3-22
3.4.2 SPCC Plan Documentation 3-22
3.4.3 Role of the EPA Inspector 3-25
Chapter 4 Secondary Containment and Impracticability 4-1
4.1 Introduction 4-1
4.1.1 Overview of Secondary Containment Provisions 4-2
4.2 General Secondary Containment Requirements 4-7
4.2.1 Alternative Measures for General Secondary Containment Requirement: Qualified Oil-Filled
Operational Equipment 4-11
4.2.2 Alternative Measures for General Secondary Containment Requirement: Flowlines and Intra-facility
Gathering Lines 4-15
4.3 Specific (Sized) Secondary Containment Requirements 4-16
4.3.1 Role of the EPA Inspector in Evaluating Secondary Containment Methods 4-17
4.3.2 Sufficient Freeboard 4-19
4.3.3 Role of the EPA Inspector in Evaluating Sufficient Freeboard 4-23
4.4 Issues Related to Secondary Containment Requirements 4-23
4.4.1 Passive versus Active Measures of Secondary Containment 4-24
4.4.2 "Sufficiently Impervious" 4-29
4.4.3 Facility Drainage (Onshore Facilities) 4-32
4.4.4 Man-made Structures 4-35
4.4.5 Double-walled or Vaulted Tanks or Containers 4-36
4.5 Overview of the Impracticability Determination Provision 4-39
4.5.1 Meaning of "Impracticable" 4-40
4.6 Required Measures when Secondary Containment is Impracticable 4-40
4.6.1 Integrity Testing of Bulk Storage Containers 4-41
4.6.2 Periodic Integrity and Leak Testing of the Valves and Piping 4-41
4.6.3 Oil Spill Contingency Plan and Written Commitment of Resources 4-42
4.6.4 Difference between Contingency Plans and Active Containment Measures 4-44
4.6.5 FRP Implications for Impracticability Determinations 4-44
4.6.6 Role of the EPA Inspector in Reviewing Impracticability Determinations 4-46
4.7 Selected Issues Related to Secondary Containment and Impracticability Determinations 4-50
4.7.1 Piping (General Secondary Containment Requirement, §112.7(c)) 4-50
4.7.2 Loading or Unloading Area (or Transfer Area) (General Secondary Containment Requirement,
§112.7(c)) 4-51
4.7.3 Loading/Unloading Rack (Specific Secondary Containment Requirements, §112.7(h)(l)) 4-54
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4.7.4 Onshore Bulk Storage Container (Specific Secondary Containment Requirements, §112.8(c)(2) and
§112.12(c)(2)) 4-57
4.7.5 Mobile/Portable Containers (Except for Mobile Refuelers and Other Non-Transportation-related Tank
Trucks) (Specific Secondary Containment Requirements, §§112.8(c)(ll) and 112.12(c)(ll)) 4-59
4.7.6 Mobile Refuelers and other Non-transportation-Related Tank Trucks (General Secondary
Containment Requirement, §112.7(c)) 4-60
4.7.7 Bulk Storage Containers at Oil Production Facilities (Sized Secondary Containment Requirements,
§112.9(c)(2)) 4-61
4.7.8 Onshore Drilling or Workover Equipment (Secondary Containment Requirements, §112.10(c)) 4-62
4.8 Alternative Measures in Lieu of Secondary Containment at Oil Production Facilities 4-63
4.8.1 Flow-through Process Vessels at Oil Production Facilities (General Secondary Containment
Requirements, §112.7(c) and Alternative Requirements) 4-63
4.8.2 Produced Water Containers at Oil Production Facilities (General Secondary Containment
Requirements, §112.7(c) and Alternative Requirements) 4-65
Chapters Oil/Water Separators 5-1
5.1 Introduction 5-1
5.2 Overview of Provisions Applicable to OWS 5-2
5.2.1 Wastewater Treatment Facilities 5-2
5.2.2 OWS Used for Secondary Containment 5-2
5.2.3 Oil Production Facilities 5-3
5.2.4 Oil Recovery and/or Recycling Facilities 5-3
5.3 OWS Used for Wastewater Treatment 5-2
5.3.1 OWS Used for Wastewater Treatment 5-2
5.3.2 Applicability of the SPCC Rule to OWS Used for Wastewater Treatment 5-3
5.3.3 Wastewater Treatment Exemption Clarification for Dry Gas Production Facilities 5-5
5.4 OWS Used to Meet SPCC Secondary Containment Requirements 5-5
5.4.1 OWS Used to Meet SPCC Secondary Containment Requirements 5-5
5.4.2 Applicability of the SPCC Rule to OWS Used to Meet Specific SPCC Secondary Containment
Requirements 5-7
5.5 OWS Used in Oil Production 5-10
5.5.1 OWS Used in Oil Production 5-10
5.5.2 Applicability of the SPCC Rule to OWS Used in Onshore Oil Production 5-12
5.5.3 Applicability of the SPCC Rule to OWS Used in Offshore Oil Production 5-13
5.5.4 Wastewater Treatment Exemption and Produced Water 5-14
5.6 OWS Used in Oil Recovery or Recycling Facilities 5-15
5.7 Documentation Requirements and the Role of the EPA Inspector 5-16
5.7.1 Documentation by Owner/Operator 5-16
5.7.2 Role of the EPA Inspector 5-17
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Contents
Chapters Facility Diagram and Description 6-1
6.1 Introduction 6-1
6.2 General Facility Description 6-2
6.2.1 Oil Types and Container Capacities 6-2
6.2.2 Discharge Prevention Measures 6-2
6.2.3 Drainage Controls 6-3
6.2.4 Countermeasures 6-3
6.2.5 Disposal Methods 6-3
6.2.6 Contact List 6-4
6.3 Notification Requirements 6-4
6.4 Preparing a Facility Diagram 6-6
6.4.1 Purpose 6-6
6.4.2 Tier I Qualified Facility Exclusion 6-6
6.4.3 Requirements for a Facility Diagram 6-7
6.4.4 Level of Detail 6-8
6.4.5 Fixed Storage Containers 6-9
6.4.6 Mobile or Portable Containers 6-9
6.4.7 Underground Storage Tanks 6-10
6.4.8 Intra-facility Gathering Lines 6-10
6.4.9 Piping and Oil-filled Equipment 6-10
6.4.10 Use of Diagrams Created for Other Programs or Uses 6-13
6.5 Facility Diagram Examples 6-13
6.5.1 Example #1: Bulk Storage and Distribution Facility 6-13
6.5.2 Example #2: Manufacturing Facility 6-17
6.5.3 Example #3: Oil Production Facility 6-19
6.6 Review of a Facility Diagram 6-22
6.6.1 Documentation by Owner/Operator 6-22
6.6.2 Role of the EPA Inspector 6-23
Chapter 7 Inspection, Evaluation, and Testing 7-1
7.1 Introduction 7-1
7.2 Inspection, Evaluation, and Testing under the SPCC Rule 7-2
7.2.1 Summary of Inspection, Evaluation and Integrity Testing Requirements 7-2
7.2.2 Regularly Scheduled Integrity Testing and Inspection of Aboveground Bulk Storage Containers (at
Onshore Facilities Other than Oil Production Facilities) 7-10
7.2.3 Removal of Oil Accumulations in BulkStorage Container Diked Areas 7-14
7.2.4 Integrity Testing and Inspection for AFVO BulkStorage Containers 7-15
7.2.5 Regular LeakTesting of Completely Buried Tanks 7-19
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7.2.6 Brittle Fracture Evaluation of Field-Constructed Aboveground Containers 7-20
7.2.7 Inspections of Piping at Onshore Facilities (Other than Oil Production Facilities) 7-21
7.2.8 Inspection of Drainage Area and Bulk Storage Containers at Onshore Oil Production Facilities 7-22
7.2.9 Alternative Inspection requirements for Flow-through Process Vessels at Oil Production Facilities 7-23
7.2.10 Alternative Inspection Requirements for Produced Water Containers at Oil Production Facilities 7-26
7.2.11 Inspection of Facility Transfer Operations at Onshore Oil Production Facilities 7-29
7.2.12 Maintenance of Flowlines and Intra-Facility Gathering Lines 7-30
7.2.13 Inspection and Corrective Action Requirements at Offshore Facilities 7-32
7.3 Role of Industry Standards and Recommended Practices in Meeting SPCC Requirements 7-33
7.4 Baselining 7-37
7.4.1 Aboveground Bulk Storage Container for Which the Baseline Condition Is Known 7-38
7.4.2 Aboveground Bulk Storage Container for Which the Baseline Condition Is Not Known 7-38
7.5 Specific Circumstances 7-41
7.5.1 Integrity Testing Scenarios for Shop-built Containers 7-42
7.5.2 Integrity Testing and Inspection Requirements for Bulk Storage Containers at Onshore Facilities -
Environmental Equivalence 7-44
7.5.3 Suggested Minimum Elements for a PE-Developed Site-Specific Integrity Testing Program (Hybrid
Inspection Program) 7-48
7.6 Documentation Requirements and Role of the EPA Inspector 7-51
7.6.1 Evaluating Tank Re-Rating Alterations 7-52
7.6.2 Evaluating Inspection, Evaluation and Testing Programs 7-56
7.7 Summary of Industry Standards and Regulations 7-60
7.7.1 API Standard 653 -Tank Inspection, Repair, Alteration, and Reconstruction 7-62
7.7.2 STI Standard SP001-Standard for the Inspection of Aboveground Storage Tanks 7-64
7.7.3 STI Standard SP031 - Standard for Repair of Shop Fabricated Aboveground Tanks for Storage of
Combustible & Flammable Liquids 7-66
7.7.4 API Recommended Practice 575 - Guidelines and Methods for Inspection of Existing Atmospheric and
Low-Pressure Storage Tanks 7-67
7.7.5 API Recommended Practice 12R1- Recommended Practice for Setting, Maintenance, Inspection,
Operation, and Repair of Tanks in Oil Production Service 7-68
7.7.6 API 570 - Piping Inspection Code: In-Service Inspection, Rating, Repair, and Alteration, of Piping
Systems 7-69
7.7.7 API Recommended Practice 574 - Inspection Practices for Piping System Components 7-71
7.7.8 API Recommended Practice 1110 - Pressure Testing of Steel Pipelines for the Transportation of Gas,
Petroleum Gas, Hazardous Liquids, Highly Volatile Liquids or Carbon Dioxide 7-72
7.7.9 API Recommended Practice 579-1/ASME FFS-1, Fitness-for-Service, Part 3 7-73
7.7.10 API Standard 2610 - Design, Construction, Operation, Maintenance, and Inspection of Terminal and
Tank Facilities 7-74
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7.7.11 RP FTPI 2007-1 Recommended Practice for the In-service Inspections of Aboveground
Atmospheric Fiberglass Reinforced Plastic Tanks and Vessels 7-75
7.7.12 ASMEB31.3-Process Piping 7-76
7.7.13 ASME Code for Pressure Piping B31.4-2006 - Pipeline Transportation Systems for Liquid
Hydrocarbons and Other Liquids 7-77
7.7.14 DOT 49 CFR part 180.605 - Requirements for Periodic Testing, Inspection, and Repair of Portable
Tanks and Other Portable Containers 7-78
7.7.15 FAA Advisory Circular 150/5230-4A - Aircraft Fuel Storage, Handling, and Dispensing on Airports 7-79
7.7.16 FAA Advisory Circular 150/5210-20 - Ground Vehicle Operations on Airports 7-79
Index 7-1
Appendix A: CWA311(j)(l)(c) 1
Appendix B: Selected Regulations 1
Appendix C: Summary of Revised Rule Provisions 1
Appendix D: Sample Bulk Storage Facility Plan 1
Appendix E: Sample Production Facility Plan 1
Appendix F: Sample Contingency Plan 1
Appendix G: SPCC Inspection Checklists 1
Appendix H: Other Policy Documents 1
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List of Tables and Figures
Tables
Table 2-1: Examples of some oil-related activities that may be regulated under 40 CFR part 112 2-9
Table 2-2: Examples of transportation-related and non-transportation-related facilities from the 1971 DOT-ERA
MOU 2-28
Table 2-3: Summary of oil storage capacity calculation as described in §112.1(d)(2)(i) and (ii) 2-51
Table 2-4: Process for an RA determination of SPCC applicability and appeals 2-52
Table 3-1: Requirements eligible for environmental equivalence at all facilities 3-3
Table 3-2: Requirements eligible for environmental equivalence at onshore facilities (excluding oil production) 3-4
Table 3-3: Requirements eligible for environmental equivalence at onshore and offshore oil production, drilling,
and workover facilities 3-5
Table 3-4: Summary of inspection and leak testing elements of an API-570 program for unprotected buried
piping - additional inspection and testing requirements are specified in API 570 (refer to the full text
of API 570 for details) 3-15
Table 3-5: SPCC provisions subject to environmentally equivalent measures under §112.7(a)(2) 3-27
Table 4-1: Secondary containment provisions in 40 CFR part 112 4-3
Table 4-2: Example methods of secondary containment listed in §112.7(c) 4-9
Table 4-3: Reportable discharge history criterion for oil-filled operational equipment 4-12
Table 5-1: SPCC rule applicability for various uses of OWS 5-1
Table 7-1: Summary of SPCC inspection, evaluation, and integrity testing program provisions and associated
recordkeeping requirements 7-3
Table 7-2: Summary of industry standards and recommended practices (RP) for ASTs 7-35
Table 7-3: Summary of industry standards and recommended practices (RP) for piping, valves, and
appurtenances 7-36
Table 7-4: Owner/Operator tank inspection checklist (from Appendix F of 40 CFR part 112) 7-51
Table 7-5: Summary of facility components covered in industry standards for inspection, evaluation, and testing 7-61
Figures
Figure 1-1: Aboveground storage tank in Floreffe, Pennsylvania 1-7
Figure 1-2: Graphical representation of 40 CFR part 112 sections 1-17
Figure 2-1: Separation of tracts at a farm 2-16
Figure 2-2: Separation of parcels at an oil production facility 2-18
Figure 2-3: Aggregation of equipment at an oil production facility 2-20
Figure 2-4: Mile-long flowline at an oil production facility 2-20
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List of Tables and Figures
Figure 2-5: Separation of areas at a military base (or other large facility) 2-21
Figure 2-6: Separation of functions at a dual-purpose facility 2-22
Figure 2-7: Separation of equipment on private property 2-23
Figure 2-8: Summary of applicability flowchart 2-59
Figure 2-9: Applicability assessment worksheet 2-60
Figure 3-1: Fencing around oil storage area 3-20
Figure 3-2: Example 1: Insufficient Documentation of Environmentally Equivalent Protection for Drainage of
Diked Areas (§112.8(b)(l) and §112.8(b)(2)) 3-23
Figure 3-3: Example 2: Sufficient Documentation of Environmentally Equivalent Protection for Drainage of Diked
Areas (§112.8(b)(l) and §112.8(b)(2)) 3-24
Figure 4-1: Secondary containment provisions in 40 CFR part 112 related to onshore storage facilities (§§112.7
and 112.8 or 112.12) 4-4
Figure 4-2: Secondary containment provisions in 40 CFR part 112 related to onshore oil production facilities
(§§112.7 and 112.9) 4-5
Figure 4-3: Secondary containment provisions in 40 CFR part 112 related to onshore oil drilling and workover
facilities (§§112.7 and 112.10) 4-6
Figure 4-4: Secondary containment provisions in 40 CFR part 112 related to offshore oil drilling, production, and
workover facilities (§§112.7 and 112.11) 4-7
Figure 4-5: Sample calculation of containment size, using two design criteria 4-21
Figure 4-6: Sample secondary containment calculations, for multiple tanks in a containment area 4-22
Figure 4-7: Example of inadequate impracticability determination: Bulk Storage Containers 4-47
Figure 4-8: Example of adequate impracticability determination: Bulk Storage Containers 4-47
Figure 4-9: Checklist of required components of state, local, and regional oil removal contingency plans. Please
refer to the complete text of 40 CFR §109.5 4-49
Figure 4-10: Sample calculation of appropriate general secondary containment capacity at a transfer area 4-53
Figure 4-11: Facility with separate unloading area and loading rack. The tank unloading area is subject to
§112.7(c). The tank truck loading rack is subject to §112.7(h)(l) 4-56
Figure 4-12: Facility with co-located unloading area and loading rack. This containment area is designed to meet
the more stringent §112.7(h)(l) provision 4-57
Figure 4-13: List of SPCC requirements eligible for impracticability determinations 4-1
Figure 5-1: OWS subject to wastewater treatment exemption 5-4
Figure 5-2: OWS used to satisfy SPCC rule requirements 5-1
Figure 5-3: OWS at oil production facilities 5-2
Figure 5-4: OWS at oil recovery and/or recycling facilities 5-1
Figure 5-5: Standard gravity oil/water separator 5-2
Figure 5-6: Enhanced gravity oil/water separator 5-3
Figure 5-7: Example calculation of secondary containment for a drum storage area using an oil/water separator 5-9
Figure 5-8: Low pressure free-water knockout 5-11
Figure 5-9: Two-phase oil/water separator 5-11
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List of Tables and Figures
Figure 5-10: Gun barrel oil/water separator 5-11
Figure 5-11: Three-phase oil/water separator 5-11
Figure 6-1: Example of a facility diagram showing how manufacturing equipment could be represented. Note
that more detailed diagrams would need to be available at the facility 6-12
Figure 6-2: Example showing how a complex piping area could be represented in a facility diagram. Note that
more detailed diagrams would need to be available at the facility 6-12
Figure 6-3: Example facility diagram, including a loading rack and a separate loading area 6-15
Figure 6-4: Example facility diagram, including oil-filled equipment, complex piping, and completely buried
storage tanks 6-18
Figure 6-5: Example facility diagram for an oil production facility 6-21
Figure 6-6: Example general facility location diagram for an oil production facility 6-22
Figure 7-1: Example baselining plan to determine the integrity testing and inspection schedule using API 653 7-40
Figure 7-2: Example baselining plan to determine the integrity testing and inspection schedule using STI SP001 7-41
Figure 7-3: Shop-built containers elevated on saddles 7-43
Figure 7-4: Summary of integrity testing and inspection program documentation for bulk storage containers at
onshore facilities, by type of SPCC Plan and standard applicability case 7-58
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List of Abbreviations
AC Asphalt cement
API American Petroleum Institute
AFVO Animal Fats and Vegetable Oils
ASME American Society of Mechanical Engineers
ASNT American Society for Non-Destructive Testing
AST Aboveground storage tank
ASTM American Society for Testing and Materials
ATG Automatic Tank Gauge
BMP Best management practice
BOEM Bureau of Ocean Energy Management
BSEE Bureau of Safety and Environmental Enforcement
CERCLA Comprehensive Environmental Response, Compensation, and Liability Act
CFR Code of Federal Regulations
CRDM Continuous release detection method
CWA Clean Water Act
DOI U.S. Department of the Interior
DOT U.S. Department of Transportation
E&P Extraction and production
EO Executive Order
EORRA Edible Oil Regulatory Reform Act
EPA U.S. Environmental Protection Agency
ERNS Emergency Response Notification System
FAA Federal Aviation Administration
FDA Food and Drug Administration
FIFRA Federal Insecticide, Fungicide, and Rodenticide Act
FR Federal Register
FRP Facility Response Plan
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List of Abbreviations
FTPI Fiberglass Tank and Pipe Institute
FWPCA Federal Water Pollution Control Act
GAO Government Accountability Office
HMA Hot Mix Asphalt
IBC Intermediate Bulk Container
LACT Lease automatic custody transfer
MIC Microbial Influenced Corrosion
MFL Magnetic Flux Leakage
MMS Minerals Management Service
MOD Memorandum of Understanding
MSO Marine Safety Office
MTR Marine transportation-related [facility]
NACE National Association of Corrosion Engineers
NASS National Agricultural Statistics Service
NEPA National Environmental Policy Act
NCP National Contingency Plan
NDE Non-destructive examination
NFPA National Fire Protection Association
NODA Notice of Data Availability
NPDES National Pollutant Discharge Elimination System
NRC National Response Center
NRC Nuclear Regulatory Commission
OEM Office of Emergency Management
OMB Office of Management and Budget
OPA Oil Pollution Act of 1990 (OPA)
OSHA Occupational Safety and Health Administration
OWS Oil/water separator
PE Professional Engineer
PEI Petroleum Equipment Institute
PMAA Petroleum Marketers Association of America
PMO Pasteurized Milk Ordinance
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List of Abbreviations
POTW
PSM
RBI
RCRA
RA
RP
RPDD
SCADA
SPCC
STI
UIC
UL
ULC
UN
USCG
UST
UT
UTS
UTT
WQIA
Publicly owned treatment work
Process Safety Management
Risk-based inspection
Resource Conservation and Recovery Act
Regional Administrator
Recommended Practice
Regulatory and Policy Development Division
Supervisory Control and Data Acquisition [system]
Spill Prevention, Control, and Countermeasure
Steel Tank Institute
Underground Injection Control
Underwriters Laboratories
Underwriters Laboratories of Canada
United Nations
U.S. Coast Guard
Underground storage tank
Ultrasonic Testing
Ultrasonic Thickness Scan
Ultrasonic Thickness Testing
Water Quality Improvement Act
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Disclaimer
This document provides guidance to EPA inspectors, to owners and operators of facilities that may be
subject to the requirements of the Spill Prevention, Control, and Countermeasure (SPCC) rule (40 CFR Part 112)
and to the general public on how EPA intends the SPCC rule to be implemented. The guidance is designed to
facilitate nationally-consistent implementation of the SPCC rule.
The statutory provisions and EPA regulations described in this guidance document contain legally
binding requirements. This guidance document does not substitute for those provisions or regulations, nor is it a
regulation itself. In the event of a conflict between the discussion in this document and any statute or
regulation, this document would not be controlling. The guidance does not impose legally binding requirements
on EPA or the regulated community, and might not apply to a particular situation based upon the circumstances.
The word "should" as used in this guidance is intended solely to recommend or suggest, in contrast to "must" or
"shall" which are used when restating regulatory requirements. Similarly, model SPCC Plans in Appendices D, E,
and F, as well as examples of SPCC Plan language in the guidance, are provided as suggestions and illustrations
only. While this guidance document indicates EPA's preferred approach to assure effective implementation of
legal requirements, EPA retains the discretion to adopt approaches on a case-by-case basis that differ from this
guidance where appropriate. Any decisions regarding a particular facility will be made based on the statute and
regulations.
References or links to information cited throughout this guidance are subject to change. Rule provisions
and addresses provided in this guidance are current as of August 2013. This guidance is a living document and
may be revised periodically without public notice. This document will be revised, as necessary, to reflect any
relevant future regulatory amendments. Interested parties are free to raise questions and objections about the
substance of this guidance and the appropriateness of the application of this guidance to a particular situation.
EPA welcomes public comments on this document at any time and will consider those comments in any future
revision of this guidance document.
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EPA Oil Program Contacts
For more information on the Spill Prevention, Control, and Countermeasure rule, or to contact U.S. EPA
headquarters and regional offices about this guidance or related issues, please refer to the following contact
information.
Contact information is also provided for the National Response Center, the sole national point of contact
for reporting all oil, chemical, radiological, biological, and etiological discharges into the environment anywhere
in the United States and its territories.
Super-fund, TRI, EPCRA, RMP and Oil Information Center
The Superfund, TRI, EPCRA, RMP and Oil Information Center is a publicly accessible service that provides up-to-
date information on several EPA programs. The Information Center does not provide regulatory interpretations,
but maintains up-to-date information on the availability of publications and other resources. The Information
Center is open Monday - Friday from 10:00 a.m. - 5:00 p.m. Eastern Time (except federal holidays).
Toll free: (800) 424-9346
In the Washington, DC, area: (703) 412-9810
TDD (800) 553-7672
TDD in the Washington, D.C. area: (703) 412-3323
http://www.epa.gov/superfund/contacts/infocenter/index.htm
U.S. EPA Headquarters
The EPA Office of Emergency Management (OEM) is responsible for EPA's emergency prevention, preparedness,
and response duties, including the Oil Program.
Office of Emergency Management
Regulatory and Policy Development Division (RPDD)
William Jefferson Clinton Federal Building - Mail Code 5104A
1200 Pennsylvania Avenue, Washington, DC 20460
202-564-8600
www.epa.gov/oilspill
oilinfo@epa.gov
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EPA Oil Program Contacts
U.S. EPA Regional Offices
R1
NH
vr ME
MA
C1
DE
MO
American Samoa
Northern Mariana
-
Region 1 - CT, ME, MA, NH, Rl, VT
5 Post Office Square, Suite 100
Mail Code OSRR02-2
Boston, MA 02109-3912
(617)918-1252
(617)918-1111
Region 2 - NJ, NY, PR, USV1
2890 Woodbridge Avenue
Building 205 (MS211)
Edison, NJ 08837-3679
(732)906-6964
(732)906-6198
Region 3 - DE, DC, MD, PA, VA, WV
1650 Arch Street (3 HS61)
Philadelphia, PA 19103-2029
(215)814-5000
(800)438-2474
Region 4-AL, FL, GA, KY, MS, NC, SC, TN
61 Forsyth Street
Atlanta, GA 30365-3415
(404)562-9900
P«
Region 5 - IL, IN, Ml, MN, OH, Wl
77 West Jackson Boulevard (SC-5J)
Chicago, IL 60604-3590
(312)353-2000
Region 6 -AR, LA, NM, OK, TX
1445 Ross Avenue (6SF-RO)
Dallas, TX 75202-2733
(214)665-2200
Region 7- IA, KS, MO, NE
11201 Renner Blvd.
Lenexa, KS 66219
(913)551-7003
Region 8 - CO, MT, ND, SD, UT, WY
1595 Wynkoop St.
Denver, CO 80202-1129
(800)227-8917
Region 9-AZ, CA, HI, NV, AS, GU, CNMI
75 Hawthorne Street (ENF-3-2)
San Francisco, CA 94105
(415) 972-3000
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EPA Oil Program Contacts
Region 10-AK, ID, OR, WA
1200 6th Avenue (ECL-116)
Suite 900
Seattle, WA 98101
(800)424-4372
(503)326-2917
Alaska
U.S. EPA Alaska Operations Office
Federal Building/ Room 537
222 West 7th Ave. #19
Anchorage, AK 99513-7588
National Response Center
The National Response Center (NRC) is the sole federal point of contact for reporting oil, chemical, radiological,
biological, and etiological discharges into the environment anywhere in the United States and its territories. The
NRC operates 24 hours a day, 7 days a week, 365 days a year.
United States Coast Guard (CG-MER-3)
2100 2nd Street, SW Stop 7238
Washington, DC 20593-7238
(800)424-8802
(202) 267-2675
Fax: 202-267-1322
TDD: 202-267-4477
http://www.nrc.uscg.mil
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Chapter 1 Introduction
In accordance with the Oil Pollution Prevention regulation at 40 CFR part 112, the U.S. Environmental
Protection Agency (EPA) requires certain facilities to prepare, amend, and implement Spill Prevention, Control,
and Countermeasure (SPCC) Plans. The regulation is largely performance-based, which allows flexibility in
meeting the rule requirements to prevent discharges of oil to navigable waters or adjoining shorelines.1 The
SPCC rule was promulgated in 1973, with significant amendments published in 2002. EPA finalized additional
revisions in 2006, 2008, 2009, and 2011. EPA developed this guidance to assist regional inspectors in
implementing the SPCC program and in understanding its applicability, and to help clarify the role of the
inspector in reviewing a facility's implementation of performance-based flexibility provisions, such as
environmental equivalence and impracticability.
This chapter provides a basic introduction to the SPCC rule and is organized as follows:
• Section 1.1 describes the rule and its statutory framework.
• Section 1.2 describes the rule's regulatory history, including the amendments since 2002 and
compliance dates.
• Section 1.3 provides further detail on each of the amendments.
• Section 1.4 provides the reader with tips on how to use this guidance.
1.1 SPCC Background
The Oil Pollution Prevention regulation promulgated
under the authority of §311 of the Federal Water Pollution
Control Act, or Clean Water Act (CWA) sets forth
requirements for prevention of, preparedness for, and
response to oil discharges at specific non-transportation-
related facilities. To prevent oil from reaching navigable
waters or adjoining shorelines, and to contain discharges of
oil, the regulation requires these facilities to develop and
implement SPCC Plans and establishes procedures, methods,
and equipment requirements.
§112.2
Spill Prevention, Control, and Countermeasure
Plan; SPCC Plan, or Plan means the document
required by §112.3 that details the equipment,
workforce, procedures, and steps to prevent,
control, and provide adequate countermeasures
to a discharge.
Note: The above text is an excerpt of the SPCC rule.
Refer to 40 CFR part 112 for the full text of the rule.
EPA uses the phrase "navigable waters or adjoining shorelines" throughout this Guidance as shorthand for the jurisdiction
description in Section 311(b)(l) of the Clean Water Act which prohibits the discharge of oil "into or upon the navigable waters
of the United States, adjoining shorelines, or into or upon the waters of the contiguous zone, or in connection with activities
under the Outer Continental Shelf Lands Act or the Deepwater Port Act of 1974, or which may affect natural resources
belonging to, appertaining to, or under the exclusive management authority of the United States (including resources under the
Magnuson-Stevens Fishery Conservation and Management Act of 1976)."
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1.1.1 Purpose and Scope
Subparts A through C of 40 CFR part 112 are often referred to as the "SPCC rule." Focusing primarily on
facility-related oil spill prevention, preparedness, and response, the SPCC rule is designed to protect public
health, public welfare, and the environment from potential harmful effects of oil discharges to navigable waters
or adjoining shorelines. The rule requires certain facilities that could reasonably be expected to discharge oil in
quantities that may be harmful into navigable waters of the United States or adjoining shorelines to develop and
implement SPCC Plans. The Plans ensure that these facilities put in place containment, controls, and
countermeasures that will prevent oil discharges. The requirements to develop, implement, and revise the SPCC
Plan, as well as train employees to carry it out, allow owners and operators to achieve the goal of preventing,
preparing for, and responding to oil discharges that threaten navigable waters and adjoining shorelines.
Part 112 also includes requirements for Facility Response Plans (FRPs) that address oil discharge
preparedness requirements for a subset of SPCC-regulated facilities. These requirements define who must
prepare and submit an FRP and what must be included in the Plan, and are found in Subpart D of 40 CFR part
112 (and related appendices). These requirements are often referred to as the "FRP rule."2 Although the SPCC
and FRP rules are related, this guidance specifically covers the prevention requirements of the SPCC rule (40 CFR
part 112, subparts A, B, and C).
The SPCC rule implements EPA's authority under CWA §311, as delegated through various Executive Orders.
Pursuant to Executive Order 11548, EPA was delegated the authority to regulate non-transportation-related
onshore and offshore facilities that could reasonably be expected to discharge oil into navigable waters of the
United States or adjoining shorelines (35 FR 11677, July 22, 1970). Executive Order 11548 was superseded by
Executive Orders 11735 and 12777, respectively (38 FR 21243, August 7, 1973; 56 FR 54757, October 22, 1991).
These Executive Orders delegated authority to the U.S. Department of Transportation (DOT)3 over
transportation-related onshore facilities, deepwater ports, and vessels. A Memorandum of Understanding
(MOU) between the Secretary of Transportation and the EPA Administrator, dated November 24, 1971 (36 FR
24080, December 18, 1971), defines non-transportation-related facilities and transportation-related facilities. A
portion of this MOU is included as Appendix A to 40 CFR part 112. In addition, the U.S. Department of the
Interior (DOI) regulates specific offshore facilities, including associated pipelines. The jurisdictional
responsibilities of EPA, DOT, and DOI in relation to offshore facilities are further discussed in another
Memorandum of Understanding, dated November 8, 1993. (This MOU is included as Appendix B to 40 CFR part
112.)
The FRP rule applies to a subset of SPCC facilities, which are those that (1) have 42,000 gallons or more of oil storage capacity
and transfer oil over water to or from vessels; or (2) have 1,000,000 gallons or more of oil storage capacity and lack secondary
containment, are located at a distance such that a discharge from the facility could cause injury to fish and wildlife and sensitive
environments or shut down a public water intake, or have experienced a reportable oil spill in an amount greater than or equal
to 10,000 gallons within the last 5 years. See 40 CFR part 112.20.
DOT delegated authority over transportation-related facilities and vessels to the U.S. Coast Guard (USCG).
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^ FYI - Jurisdiction
EPA, USCG, DOT and DOI share responsibility for establishing spill prevention and response planning regulations under
the Clean Water Act following the jurisdictional boundaries established in Executive Orders and MOUs.
However, EPA and USCG regulatory jurisdiction may differ from EPA and USCG response authority jurisdiction.
1.1.2 Statutory Framework
The Federal Water Pollution Control Act (FWPCA) of 1972, as amended, commonly known as the Clean
Water Act (CWA), is the principal federal statute for protecting navigable waters, adjoining shorelines, and the
waters of the contiguous zone from pollution.4 Section 311 of the CWA addresses the control of oil and
hazardous substance discharges, and provides the authority
for promulgation of a regulation to prevent, prepare for, and
respond to such discharges. Specifically, §311(j)(l)(C)
mandates regulations establishing procedures, methods,
equipment, and other requirements to prevent discharges of
oil from vessels and facilities and to contain such discharges.
(See Appendix A of this guidance for the text of CWA
§112.2
Oil means oil of any kind or in any form,
including, but not limited to: fats, oils, or greases
of animal, fish, or marine mammal origin;
vegetable oils, including oils from seeds, nuts,
fruits, or kernels; and, other oils and greases,
including petroleum, fuel oil, sludge, synthetic
oils, mineral oils, oil refuse, or oil mixed with
wastes other than dredged spoil.
Note: The above text is an excerpt of the SPCC rule. Refer
to 40 CFR part 112 for the full text of the rule.
Under CWA §311(a)(l), "oil" is defined to mean "oil
of any kind or in any form..." In 1975, EPA published a notice
on the applicability of the SPCC rule to non-petroleum oils.
The notice affirmed that all facilities processing and storing
non-petroleum oils (such as animal fats and vegetable oils or
AFVOs) in the quantities and under the circumstances set out
in 40 CFR part 112 are required to prepare and implement an SPCC Plan in accordance with that part (40 FR
28849, July 9, 1975). EPA stated that the broad and comprehensive definition of "oil" in the CWA is consistent
with the expressed congressional intent to strengthen federal law for the prevention, control, and cleanup of oil
spilled in the aquatic environment. Both EPA and the U.S. Coast Guard5 have consistently interpreted and
administered §311 as applicable to spills of non-petroleum-based oils, particularly because of the common
physical and chemical properties of AFVOs and petroleum oils as well as their common potential for adverse
environmental impact when discharged into water.
FWPCA was enacted in 1948 and was amended on April 3,1970 (Public Law 91-224) by the Water Quality Improvement Act
(WQIA) of 1970. The WQIA amended the prohibitions on discharges of oil to allow such discharges only when consistent with
regulations to be issued by the President and where permitted by Article IV of the 1954 International Convention for the
Prevention of Pollution of the Sea by Oil (33 U.S.C. 1321). In issuing regulations, the President was authorized to determine
quantities of oil which would be harmful to the public health or welfare of the U.S., including, but not limited to, fish, shellfish,
and wildlife, as well as public and private property, shorelines and beaches.
DOT delegated authority over transportation-related facilities and vessels to the U.S. Coast Guard. In March 2003, the Coast
Guard formally transferred from the DOT to the Department of Homeland Security, but retains this CWA authority (Executive
Order 13286, 68 FR 10619, March 5, 2003).
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The Oil Pollution Act of 1990 (OPA) streamlined and strengthened EPA's ability to prepare for and
respond to catastrophic oil discharges. Specifically, OPA expands prevention and preparedness activities,
improves response capabilities, ensures that shippers and owners or operators of facilities that handle oil pay
the costs associated with discharges that do occur, expands research and development programs, and
establishes an Oil Spill Liability Trust Fund. OPA §4202(a)(6) amended CWA §311(j) to require promulgation of
regulations to require owners or operators of certain vessels and facilities to prepare and submit Facility
Response Plans (FRPs) for responding to a worst-case discharge of oil and to a substantial threat of such a
discharge (CWA §311(j)(5)). EPA published the FRP rule on July 1, 1994, as an amendment to 40 CFR part 112.
The FRP requirement for onshore facilities applies to any facility that, "because of its location, could reasonably
be expected to cause substantial harm to the environment by discharging into or on the navigable waters,
adjoining shorelines, or the exclusive economic zone."
OPA defined oil under §1001 differently than the CWA §311(a)(l) definition. Under OPA, "oil" means "oil
of any kind or in any form, including petroleum, fuel oil, sludge, oil refuse, and oil mixed with wastes other than
dredged spoil, but does not include any substance which is specifically listed or designated as a hazardous
substance under subparagraphs (A) through (F) of section 101(14) of the Comprehensive Environmental
Response, Compensation, and Liability Act (42 U.S.C. 9601) and which is subject to the provisions of that Act."
The OPA definition did not amend the original CWA definition of oil and therefore was not incorporated into 40
CFR part 112.
While OPA did not result in revisions to the SPCC rule, OPA section 4113(a) required that the President
conduct a study to determine whether liners or other secondary means of containment should be used to
prevent leaking or aid in leak detection at onshore facilities used for the bulk storage of oil located near
navigable waters. Executive Order 12777 tasked EPA with conducting this study.
The resulting study was completed in May 1996s and focused on the technical feasibility of using liners7
and related systems to detect oil leaking from aboveground storage tanks (ASTs) and to prevent the leaking oil
from contaminating soil and navigable waters. EPA assessed the technical feasibility of installing liners made
from synthetic materials as well as earthen materials within secondary containment structures and under ASTs
(i.e., undertank liners). EPA also assessed the feasibility of installing double bottoms on vertical ASTs as "other
secondary means of containment," which could be used in place of undertank liners. The agency examined other
technologies to aid in leak detection and looked at available data on liner costs. The study concluded that
existing sources of information evaluated by EPA did indicate that a significant number of ASTs may be leaking
or spilling oil. The study also showed that each of the different types of liners, such as impervious soil, coated or
uncoated concrete, and geomembrane liners, can be effective in preventing groundwater contamination and in
detecting leaks if properly installed and maintained. However, poor maintenance can significantly reduce the
effectiveness of certain types of liners. The study resulted in EPA's recommendation to initiate a voluntary
program to prevent leaks and spills, rather than a regulatory amendment. In the preamble to the 2002 SPCC rule
EPA Liner Study: Report to Congress, Section 4113(a) of the Oil Pollution Act of 1990. May 1996. OSWER 9380.0-24, EPA
540/R95/041, PB95-963538. See Appendix H.
For purposes of the study, EPA defined a liner as "an engineered system that makes secondary containment structures more
impervious."
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Chapter 1: Introduction
amendments, EPA clarified that it is not necessary for facility owner and operators to install liners in order to
comply with the SPCC rule: "'effective containment' does not mean that liners are required for secondary
containment areas. Liners are an option for meeting the secondary containment requirements, but are not
required by the rule." (July 17, 2002, 67 FR 47102).
In 1995, Congress enacted the Edible Oil Regulatory Reform Act (EORRA). The statute mandates that
most federal agencies8 differentiate among and establish separate classes for various types of oils, specifically,
animal fats and oils and greases, fish and marine mammal oils, oils of vegetable origin, and other oils and
greases (including petroleum). In differentiating among these classes of oils, EORRA directed federal agencies to
consider differences in these oils' physical, chemical, biological, and other properties, and in their environmental
effects. On August 12, 1994, several agricultural organizations submitted to EPA a Petition for Reconsideration
of the FRP rule as it applies to facilities that handle, store, or transport AFVOs.9 On October 20, 1997, EPA denied
the petition to amend the FRP rule (62 FR 54508) because it did not substantiate the petitioners' claims that
AFVOs differ from petroleum oils in properties and effects. EPA concluded that the facts did not support a
further differentiation between these groups of oils under the FRP rule. Instead, EPA found that a worst-case
discharge or substantial threat of a discharge of AFVOs to navigable waters, adjoining shorelines, or the
exclusive economic zone could reasonably be expected to cause substantial harm to the environment, including
wildlife that may be killed by the discharge.
However, in amendments to the FRP rule on June 30, 2000, in response to EORRA requirements, EPA
promulgated a separate approach for calculating planning volumes for a worst-case discharge in the FRPs for
animal fat and vegetable oil facilities (65 FR 40776). EPA also published an advanced notice of proposed
rulemaking requesting ideas from the public on how to differentiate among the SPCC requirements for facilities
storing or using various categories of oil (64 FR 17227, April 8, 1999). In the 2002 revision of the SPCC rule, EPA
established new subparts to facilitate differentiation among categories of oil listed in EORRA; however, the
actual requirements in each of the subparts were identical. As discussed in Section 1.3.3 of this chapter, EPA
later removed and reserved certain sections that are not applicable to facilities that store or handle AFVOs. The
2008 SPCC rule amendments provided differentiated requirements for AFVOs in the form of revised integrity
testing requirements at §112.12(c)(6) that are applicable to containers that meet specific criteria. Chapter 7:
Inspection, Evaluation, and Testing discusses the differentiated integrity testing requirements for AFVO
containers in detail.
1.2 Regulatory History
The SPCC rule was initially promulgated in 1973, with a few early revisions, and further modifications to
the SPCC requirements were proposed for public comment on several occasions. EPA finalized many aspects of
three proposals resulting in final revisions in the Federal Register (FR) in July 2002. In 2006, EPA amended the
SPCC rule to streamline the requirements for a subset of facilities. In December 2008, EPA again amended the
The Food and Drug Administration and the Food Safety and Inspection Service are exempted from the requirements of EORRA.
"Petition for Reconsideration and Stay of Effective Date," August 12,1994, submitted on behalf of the American Soybean
Association, the Corn Refiners Association, the National Corn Growers Association, the Institute of Shortening & Edible Oils, the
National Cotton Council, the National Cottonseed Products Association, and the National Oilseed Processors Association.
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rule to provide increased clarity, to tailor requirements to particular industry sectors, and to streamline certain
requirements. EPA promulgated revisions to the December 2008 amendments in November 2009 and finalized
one additional amendment to the SPCC rule in April 2011. Throughout this time, EPA extended the compliance
dates in the SPCC rule for amending and implementing existing SPCC Plans. EPA also extended the compliance
dates for developing and implementing new Plans developed under 40 CFR part 112.
1.2.1 Initial Pro mulgatio n and Early Amendments
The SPCC rule was originally proposed in the Federal Register on July 19, 1973 (38 FR 19334). The final
rule was published on December 11, 1973 and became effective on January 10, 1974 (38 FR 34164). The
regulation established oil discharge prevention procedures, methods, and equipment requirements for non-
transportation-related facilities with an aboveground (non-buried) oil storage capacity greater than 1,320 U.S.
gallons (or greater than 660 U.S. gallons aboveground in a single tank) or a buried underground oil storage
capacity greater than 42,000 U.S. gallons. Regulated facilities were also limited to those that, because of their
location, could reasonably be expected to discharge oil into the navigable waters of the United States or
adjoining shorelines. The rule included sections on general applicability, relevant definitions, and requirements
for preparation of SPCC Plans; provisions for SPCC Plan amendments; civil penalty provisions; and requirements
for the substance of the SPCC Plans.
Two early revisions were made to the original SPCC rule. On August 29, 1974, the regulation was
amended (39 FR 31602) to set out EPA's policy on civil penalties for violation of the CWA §311 requirements. On
March 26, 1976, the rule was again amended (41 FR 12657), primarily to clarify the criteria for determining
whether or not a facility is subject to the regulation. Specifically, EPA clarified that manmade structures may not
be used in the applicability determination relating to a facility's reasonable expectation of an oil discharge to
navigable waters or adjoining shorelines when they restrain, hinder, contain or otherwise prevent a discharge to
navigable waters or adjoining shorelines. This rulemaking also clarified that SPCC Plans must be in writing and
specified procedures for mobile facilities to develop and implement Plans.10
On May 20, 1980 (45 FR 33814), amendments were proposed to reflect the changes in the jurisdiction of
section 311 of the CWA that were brought about by the 1977 amendments to that Act. The notice also proposed
amendments to the applicability criteria, requirements for new facilities, availability of SPCC Plans for review by
EPA personnel, review of SPCC Plans by owners or operators, and other SPCC Plan requirements.
1.2.2 SPCC Task Force and GAO Recommendations
In January 1988, the shell plates of a reconstructed four-million gallon aboveground storage tank in
Floreffe, Pennsylvania, experienced a brittle fracture failure. Brittle fracture is a type of structural failure in
aboveground steel tanks, characterized by rapid crack formation that can cause sudden tank failure.11 The tank
split apart, collapsed, and discharged approximately 3.8 million U.S. gallons of diesel fuel. Of this amount,
approximately 750,000 U.S. gallons were discharged into the Monongahela River. The spill temporarily
Some examples of mobile facilities include onshore drilling or workover rigs, barge-mounted offshore drilling or workover rigs,
and portable fueling facilities.
For more information on brittle fracture evaluations see Chapter 7: Inspection, Evaluation, and Testing.
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contaminated drinking water sources, damaged the ecosystems of the Monongahela and Ohio Rivers, and
negatively affected private property and local businesses. Following the discharge, an SPCCTask Force was
formed to examine federal regulations governing discharges from aboveground storage tanks. The Task Force,
consisting of representatives from EPA headquarters and regions as well as other federal and state agencies,
issued its findings and recommendations in May 1988. The findings focused on the prevention of catastrophic
discharges and recommended changes to the SPCC program.12 Specifically, the Task Force recommended that
EPA establish additional technical requirements for SPCC Plan preparation and implementation, including:
• Adopting industry standards for new and relocated tanks;
• Differentiating SPCC requirements based on facility size;
• Modifying timeframes for SPCC Plan preparation, implementation, and review;
• Requiring strengthened integrity testing and periodic inspection of tanks and secondary
containment;
• Requiring a more stringent attestation for a Professional Engineer to certify an SPCC Plan;
• Ensuring that employees undergo response
training; and
• Modifying definitions and providing additional
preamble discussion.
The Task Force also recommended that EPA expand the
scope of the regulation to include requirements for facility-
specific contingency planning and to specify countermeasures to
be employed if a discharge should extend beyond the site in an
uncontrolled manner. To better identify violations and enforce
compliance, the Task Force recommended that EPA strengthen
its facility inspection program. The Task Force also found that
EPA did not have an adequate inventory of facilities subject to
the regulation, and that improvements in national response
coordination may be possible. Finally, the Task Force
commented on the role of state and local resources and other
federal agencies in oil discharge prevention and response
efforts, and also recommended funding research on the
development of oil discharge removal and control technology.
In response to both the Monongahela River spill and an
Figure 1-1:
Aboveground storage tank in
Floreffe, Pennsylvania.
U.S. EPA, "The Oil Spill Prevention, Control, and Countermeasures Program Task Force Report," Interim Final Report, May 13,
1988) Available in EPA docket OPA-1991-0001.
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oil spill that occurred at an oil refinery in Martinez, California in April 1988, the U.S. General Accounting Office
(which is now referred to as the U.S. Government Accountability Office, or GAO) examined the adequacy of the
federal regulations of aboveground oil storage tanks and the extent to which they addressed the unique
problems of inland oil discharges. GAO's report, "Inland Oil Spills: Stronger Regulation and Enforcement Needed
to Avoid Future Incidents," contained recommendations on regulations, inspections, enforcement, and
government response that were similar to those of the SPCC Task Force (February 1989, GAO/RCED-89-65).13 To
amend the SPCC regulation, GAO recommended that EPA require:
• Aboveground oil storage tanks to be built and tested in accordance with industry and other
specified standards;
• Facilities to plan how to react to a spill that overflows facility boundaries; and
• Stormwater drainage systems to be designed and operated to prevent oil from escaping through
them. (Oil escaped through the drainage system during the oil spill in Martinez, California).
For inspections, GAO recommended that EPA (1) strengthen its aboveground oil storage facility
inspection program by coordinating with state and local authorities, developing procedures for conducting and
documenting inspections, defining and implementing minimum training procedures for inspectors, and
establishing a national policy for fining violators; and (2) consider advantages and disadvantages of
supplementing EPA inspection resources with state and local inspection resources, and require that facilities
obtain certification from independent engineers indicating that facilities are in compliance with the regulations.
Finally, the report included a recommendation to Congress that it amend the CWA to explicitly authorize the
federal government to recover the costs of monitoring oil spill cleanups performed by private responsible
parties, and suggested that it consider re-establishing the oil spill research and development program.
1.2.3 Proposed Revisions - 1991,1993, and 1997
Following the Monongahela River and Martinez, California spills and recommendations of the SPCC Task
Force and GAO, EPA proposed substantive revisions to the SPCC requirements on three occasions (1991, 1993,
and 1997) and solicited public comment on these revisions. Specifically:
• On October 22, 1991 (56 FR 54612), EPA proposed changes in the applicability of the SPCC rule
and in the required procedures for completing SPCC Plans, as well as the addition of a facility
notification provision. The proposed rule also reflected changes in the jurisdiction of CWA §311
made by the 1977 and 1978 amendments to the Act.
• On February 17, 1993 (58 FR 8824), EPA published an additional proposed rule to incorporate
new requirements added by OPA that directed facility owners and operators to prepare plans
for responding to a worst-case discharge of oil and to a substantial threat of such a discharge
(the FRP rule). EPA promulgated the FRP rule on July 1, 1994 (59 FR 34070). The 1993 proposed
rule also included revisions to the SPCC requirements, including (1) a requirement for an SPCC
Available at www.regulations.gov, docket ID: EPA-HQ-OPA-1991-0001-0042.
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Plan to address training and methods of evaluating containers for protection against brittle
fracture; (2) provisions for Regional Administrators to require amendments to an SPCC Plan and
to require a Plan from an otherwise exempt facility when necessary to achieve the goals of the
CWA; and (3) a requirement for Plan submission if an owner or operator invokes a waiver to
certain technical requirements of the SPCC rule.
• On December 2, 1997 (62 FR 63812), EPA proposed further revisions to the SPCC rule in an
effort to reduce the information collection burden without creating an adverse impact on public
health or the environment. The proposed revisions were intended to give facility owners and
operators flexibility to use alternative formats for SPCC Plans; to allow the use of certain records
maintained pursuant to usual and customary business practices, or pursuant to the National
Pollutant Discharge Elimination System (NPDES) program, in lieu of records mandated by the
SPCC requirements; to reduce the information required to be submitted after certain
discharges; and to extend the interval between SPCC Plan reviews by the facility
owner/operator. At this time, EPA also proposed amendments to the FRP requirements, which
were finalized on June 30, 2000 (65 FR 40776).
1.2.4 2002 Amendments
On July 17, 2002, EPA published a final rule amending the Oil Pollution Prevention regulation (67 FR
47042). The final rule became effective on August 16, 2002, and incorporated many of the proposed revisions
from the 1991, 1993, and 1997 proposals. As a performance-based regulation, the amendments provided
flexibility to the regulated community in meeting many of the oil discharge prevention requirements and the
overall goal of preventing oil spills that may impact navigable waters or adjoining shorelines. In addition, the
final rule included new subparts outlining the requirements for various classes of oil (pursuant to EORRA),
revised the applicability of the regulation, amended the requirements for completing SPCC Plans, and made
other modifications. The final rule also contained a number of provisions designed to decrease regulatory
burden on facility owners and operators subject to the rule. The specific amendments to the SPCC rule are
discussed in more detail in Section 1.3, Revised Rule Provisions, below, as well as in Appendix Cto this guidance,
Summary of Revised SPCC Rule Provisions.
In response to the final SPCC amendments, several members of the regulated community filed legal
challenges to certain aspects of the rule.14 Settlement discussions between EPA and the plaintiffs led to an
agreement on all issues except the definition of navigable waters. On May 25, 2004, EPA published a notice in
the Federal Register (69 FR 29728) clarifying specific provisions of the SPCC rule to reflect settlement
agreements. The Federal Register notice clarified statements regarding loading/unloading racks and
impracticability that were challenged by the plaintiffs. In addition, EPA clarified aspects of a wastewater
treatment exemption and specified which definition of "facility" applies when determining applicability of the
FRP rule under §112.20(f)(l). EPA also announced the availability of a letter from EPA to the Petroleum
See American Petroleum Institute v. Leavitt et al., No. 1;102CV02247 PLF and consolidated cases (D.D.C. filed November 14,
2002). Lead plaintiffs in the cases were the American Petroleum Institute, Marathon Oil Co., and the Petroleum Marketers
Association of America.
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Marketers Association of America (PMAA), which provided additional guidance on equivalent environmental
protection with respect to requirements for integrity testing, security, and loading racks.15
1.2.5 Additional Amendments to Streamline the SPCC Rule
On September 20, 2004, EPA published two Notices of Data Availability (NODAs). The first NODA
solicited comments on letters or other documents submitted to EPA that requested more focused or
streamlined requirements for facilities subject to the SPCC rule that handle oil below a certain threshold
amount, referred to as "certain facilities" (69 FR 56182). The second NODA solicited comments on whether
alternate regulatory requirements would be appropriate for facilities with oil-filled and process equipment (69
FR 56184). In December 2005, based on the comments received on the NODAs as well as other information
received, EPA proposed to amend the SPCC rule. The proposed amendments addressed a number of issues,
including requirements pertaining to a subset of smaller facilities, oil-filled operational equipment meeting
certain qualifying criteria, motive power containers, airport mobile refuelers, animal fats and vegetable oils, and
the compliance date for farms (70 FR 73524, December 12, 2005). EPA finalized revisions in December 2006 (71
FR 77266, December 26, 2006). The 2006 final rule provided more streamlined, alternative approaches for
compliance with oil spill prevention requirements for these entities. Its goal was to streamline the regulation in
an effort to improve compliance, resulting in greater environmental protection.
The December 2006 SPCC rule amendments addressed only certain areas of the SPCC requirements and
specific issues and concerns raised by the regulated community. The EPA Regulatory Agenda and the 2005 Office
of Management and Budget (OMB) report on "Regulatory Reform of the U.S. Manufacturing Sector" highlighted
other areas where further changes may be appropriate. Accordingly, in October 2007, EPA proposed additional
amendments to the SPCC rule to address these changes (72 FR 58378, October 15, 2007).
EPA finalized these revisions in December 2008 (73 FR 74236, December 5, 2008), with modifications
finalized in November 2009 (74 FR 58784, November 13, 2009); both of these actions became effective on
January 14, 2010. Additionally, in response to legal challenges filed by members of the regulated community,
EPA announced the vacatur of the July 2002 definition of "navigable waters", restoring the 1973 definition of
"navigable waters" (73 FR 71941, November 26, 2008).
Finally, in April 2011, EPA published a final rule to exempt milk and milk product containers, associated
piping and appurtenances from the SPCC regulation (76 FR 21652, April 18, 2011). The specific amendments to
the SPCC rule are discussed in more detail in Section 1.3: Revised Rule Provisions, below, as well as in Appendix C
to this guidance, Summary of Revised SPCC Rule Provisions.
1.2.6 Compliance Date Amendments
The compliance date is the date by which the owner or operator must have a Plan that complies with
the revised rule requirements. On eight occasions following the 2002 final rule, EPA extended the compliance
dates in §112.3 for facilities to update (or for new facilities to prepare) and implement an SPCC Plan that
The Federal Register notice and letter to PMAA are available on the EPA Web site, at
http://www.epa.gov/emergencies/lawsregs.htmfffroppr and
http://www.epa.gov/emergencies/content/spcc/spccref.htmffletter, respectively.
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complies with the revised requirements. All of these extensions alleviated the need for individual extension
requests from owners and operators:
• On January 9, 2003 (68 FR 1348), EPA extended the compliance date by 60 days to allow time to
consider comments on a proposed one-year extension that was published concurrently in the
Federal Register.
• On April 17, 2003 (68 FR 18890), EPA extended the compliance dates by one year, to provide
sufficient time for the regulated community to undertake the actions necessary to update (or
prepare) their plans in accordance with the 2002 amendments.
• On August 11, 2004 (69 FR 48794), EPA extended the compliance dates by an additional 18
months, to provide members of the regulated community with sufficient time to understand
clarifications related to a partial settlement of litigation involving the July 2002 amendments,
and to be able to incorporate these clarifications, as appropriate, in preparing and updating
their SPCC Plans.
• On February 17, 2006 (71 FR 8462), EPA extended the compliance dates to allow the agency
time to take final action on the proposed amendments to the SPCC requirements before owners
and operators were required to prepare, amend, and implement their SPCC Plans (to allow
owners and operators to take advantage of any modifications that would be provided by a final
SPCC amendment rule); to allow the regulated community the opportunity to understand the
material presented in this guidance; and to provide time for facilities that might have difficulty
meeting the compliance dates because they were adversely affected by recent hurricanes.
Additionally, the 2006 SPCC rule amendments (71 FR 77266, December 26, 2006) specifically
extended the compliance dates for the owner or operator of a farm to prepare or amend and
implement the farm's SPCC Plan until the effective date of a rule addressing whether to provide
differentiated requirements for farms.
In this notice, EPA eliminated the six-month interim period in §112.3(a) between the compliance
dates for Plan amendment and implementation.
• On May 16, 2007 (72 FR 27443), EPA extended the compliance dates to allow the agency time to
promulgate further revisions to the SPCC rule before owners and operators are required to
prepare or amend, and implement their SPCC Plans.
• On June 19, 2009 (74 FR 29136), EPA extended the compliance dates to provide the owner or
operator of a facility the opportunity to fully understand all of the regulatory amendments
offered by revisions to the SPCC rule promulgated since July 2002 and to provide sufficient time
for the agency to review comments on the December 2008 amendments and to promulgate any
additional revisions that result from this review.
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These compliance date amendments established the same compliance date for farms as for all other
SPCC-regulated facilities.
• On October 14, 2010 (75 FR 63093), EPA extended the compliance date an additional year to
allow owners and operators sufficient time to amend and implement their SPCC Plans. The
extension applied to all facilities, except for oil drilling, production or workover facilities that are
offshore or that have an offshore component and onshore facilities required to have and submit
FRPs. The compliance date for these offshore facilities and FRP-subject facilities remained
November 10, 2010.
• On October 18, 2011 (76 FR 72120), EPA published a direct final rule that extended the
compliance date by an additional 18 months for the owners or operators of farms, who because
of their unique nature, were disproportionately affected by severe weather conditions in the
continental United States. The extension allowed additional time for owners and operators of
farms to prepare and implement SPCC Plans. The agency confirmed the compliance date
extension in a final rule published November 22, 2011 (76 FR 72120).
It should be noted that all compliance dates are in the past. If the owner or operator of a facility did not
comply with the SPCC rule and does not have an SPCC Plan, the owner or operator must develop a Plan
immediately in accordance with the amendments to the rule from 2002 forward.
The current compliance dates under §112.3(a) and (b) apply to all SPCC-regulated facilities, as follows:
A farm, starting operation...
On or before August 16, 2002
After August 16, 2002 through May 10, 2013
After May 10, 2013
Must...
Maintain its existing SPCC Plan
Amend and implement the amended
than May 10, 2013
Prepare and implement an SPCC Plan
10, 2013
Prepare and implement an SPCC Plan
operations
SPCC Plan no later
no later than May
before beginning
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An oil drilling, production or workover facility, including a
mobile or portable facility, located offshore or with an
offshore component; or an onshore facility that is required
to have and submit FRPs starting operation...
On or before August 16, 2002
After August 16, 2002 through November 10, 2010
After November 10, 2010 (excluding oil production
facilities)
After November 10, 2010 (oil production facilities)
Must...
Maintain its existing SPCC Plan
Amend and implement the amended
than November 10, 2010
Prepare and implement an SPCC Plan
November 10, 2010
Prepare and implement an SPCC Plan
operations
Prepare and implement an SPCC Plan
after beginning operations.
SPCC Plan no later
no later than
before beginning
within six months
The December 2008 rule amendments (73 FR 74236, December 5, 2008) allow new oil production
facilities a period of six months after the start of operations to prepare and implement an SPCC Plan. A "new" oil
production facility is one that becomes operational after the applicable compliance date, not an existing oil
production facility (in operation prior to the compliance date) that has changed name, owner, operator, or
equipment.
All other facilities starting operation...
On or before August 16, 2002
After August 16, 2002 through November 10, 2011
After November 10, 2011 (excluding oil production
facilities)
After November 10, 2011 (oil production facilities)
Must...
Maintain its existing SPCC Plan
Amend and implement the amended
than November 10, 2011
Prepare and implement an SPCC Plan
November 10, 2011
Prepare and implement an SPCC Plan
operations
Prepare and implement an SPCC Plan
after beginning operations.
SPCC Plan no later
no later than
before beginning
within six months
The compliance date amendments described above affected only requirements of the rule amendments
(67 FR 47042, July 17, 2002; 71 FR 77266, December 26, 2006; 73 FR 74236, December 5, 2008; and 74 FR
58784, November 13, 2009) that imposed new or more stringent compliance obligations than did the original
1973 SPCC rule. Provisions in these amendments that provide regulatory relief were not affected by these
compliance date amendments because they would not typically require amendments to existing Plans "to
ensure compliance" (see §112.3). Provisions in these amendments that provide regulatory relief to facilities
were applicable as of the effective date of the amendment.
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Furthermore, where certain dates appear as part of the rule text in provisions other than §112.3, as
listed below, these dates are not affected by, or replaced by, the compliance date:
• §112.5(b) requires the owner/operator to complete a review and evaluation of the SPCC Plan at
least once every five years from the date the facility becomes subject to this part; or, if your
facility was in operation on or before August 16, 2002, five years from the date your last review
was required under this part.
• §§112.8(d)(l) and 112.12(d)(l) require that buried piping that is installed or replaced on or after
August 16, 2002 have protective wrapping and coating and cathodic protection, or otherwise
satisfy the corrosion protection provisions for piping in 40 CFR part 280 or a State program
approved under 40 CFR part 281.
• §§112.8(c)(4) and 112.12(c)(4) require the owner/operator to protect any completely buried
metallic storage tank installed on or after January 10, 1974 from corrosion by coatings or
cathodic protection, and regularly leak test such tanks.
1.3 Revised Rule Provisions
The 2002 revision to the SPCC rule clarified the language and organization of the regulation, made
technical changes, and reduced regulatory burden in certain areas of the rule. The 2006 final rule amended the
SPCC rule to streamline the requirements for a subset of facilities. The 2008 final rule amended the SPCC rule to
provide increased clarity with respect to specific regulatory requirements, tailor requirements to particular
industry sectors, and streamline certain rule requirements. Finally, the 2009 amendments removed certain
provisions that were finalized in 2008, and provided minor technical corrections, as discussed in more detail
below. This section provides an overview of the current rule's organization and highlights some of the more
substantive changes made to the rule in 2002 through 2009.
For the inspector's reference, Appendix B of this guidance includes the Oil Pollution Prevention regulation, 40
CFR part 112, in its entirety and current as of the publication of this guidance. Since the regulation is subject to
change, the appendix is provided for informational purposes only. The Federal Register - the official daily
publication for rules, proposed rules, and notices of federal agencies and organizations - is available
electronically from the U.S. Government Printing Office Web site at http://www.gpoaccess.gov/fr/. General and
permanent rules published in the Federal Register are codified in the Code of Federal Regulations (CFR),
available electronically at http://www.gpoaccess.gov/cfr/. Each volume of the CFR is updated once each
calendar year and is issued on a quarterly basis. For a more frequently updated version of the CFR, refer to the
Electronic Code of Federal Regulations (e-CFR) at http://www.gpoaccess.gov/ecfr/. The e-CFR is updated daily
but is not an official legal edition of the CFR. Inspectors implementing the SPCC program should always consult
the aforementioned resources (or their equivalent) to obtain the current version of the SPCC rule.
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1.3.1 Rule Organization
The Oil Pollution Prevention regulation at 40 CFR part 112 is divided into four subparts. Subparts A, B,
and C address oil discharge prevention requirements and are commonly referred to as the "SPCC rule." Subpart
D, commonly referred to as the "FRP rule/' addresses facility response planning requirements in the event of an
oil discharge, and includes the FRP requirements and facility response training and drill requirements.
The regulation is organized as follows:
Subpart A Applicability, definitions, and general requirements for all facilities and all types of
oils
Subpart B Requirements for petroleum oils and non-petroleum oils, except those covered in
Subpart C
Subpart C Requirements for animal fats and oils and greases, and fish and marine mammal
oils; and for vegetable oils, including oils from seeds, nuts, fruits, and kernels
Subpart D Response requirements
Pertaining to all oil and facility types, subpart A contains the following key sections of the SPCC rule:
§112.1
§112.2
§112.3
General Applicability
Definitions
Requirement to Prepare and Implement an SPCC Plan
§112.4 Amendment of an SPCC Plan by Regional Administrator
§112.5 Amendment of an SPCC Plan by Owners or Operators
§112.6 Qualified Facilities
§112.7 General Requirements for SPCC Plans
Additional requirements for specific facility types are given in §§112.8 through 112.12,16 and are found
within subparts B and C. These facility types and their corresponding sections of the rule are as follows:
The 2002 SPCC rule included requirements within subpart C that are not applicable or are inappropriate for animal fats and
vegetable oils (§§112.13 through 112.15). These sections were promulgated because EPA had not proposed differentiated SPCC
requirements for public notice and comment, and were removed and reserved by rulemaking on December 26, 2006 (71 FR
77266).
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§112.8 Onshore Facilities (excluding oil production facilities)
§112.9 Oil Production Facilities (onshore)
§112.10 Oil Drilling and Workover Facilities (onshore)
§112.11 Oil Drilling, Production, or Workover Facilities (offshore)
§112.12 Onshore Facilities (requirements for AFVOs)
The Oil Pollution Prevention regulation also contains several appendices, including Memoranda of
Understanding, information referenced in the FRP rule (Substantial Harm Criteria, Determination of a Worst
Case Discharge Planning Volume, Determination and Evaluation of Required Response Resources for Facility
Response Plans, and a model Facility-Specific Response Plan) and an SPCC Plan template for certain qualified
facilities.
Appendix C to part 112 - Substantial Harm Criteria provides guidance for determining FRP applicability.
However, in accordance with Section 3.0 of Appendix C, an SPCC-regulated facility owner/operator must
complete and maintain a copy of Attachment C-ll "Certification of the Applicability of the Substantial Harm
Criteria" at the facility when the facility17 does not meet the substantial harm criteria listed in Attachment C-l
"Flowchart of Criteria for Substantial Harm." Copies of Attachment C-l and C-ll are included in Appendix C of 40
CFR 112 and in Appendix H of this Guidance.
Figure 1-2 illustrates the organization of 40 CFR part 112, highlighting sections that pertain to the SPCC
and FRP requirements. Note that all FRP-regulated facilities are also subject to the SPCC requirements and must
develop and implement an SPCC Plan.
Many facility owner/operators include a copy of Attachment C-ll "Certification of the Applicability of the Substantial Harm
Criteria as an appendix to the SPCC Plan.
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Figure 1-2: Graphical representation of 40 CFR part 112 sections.
Subpart Section(s)
112.1 General Applicability
A 112.2 Definitions
Regulations
B
D
0)
C
0)
Q.
Q.
112.3-112.7
112.8-112.11
112.12
112.20-112.21
- DOT/EPA MOU
B-DOI/DOT/EPAMOU
C - Sub. Harm Criteria
D - Worst Case Discharge
E - Response Resources
F-Model FRP
G -Tier I Template
Note that Section 3.0 of Appendix C requires an SPCC-regulated facility owner/operator
to complete and maintain a copy of Attachment C-ll at the facility when the facility does
not meet the substantial harm criteria outlined in Attachment C-l of the appendix.
1.3.2 Summary of Major 2002 Revisions
The 2002 amendments shifted the SPCC rule to a more performance-based regulation that allows
owners, operators, and the certifying Professional Engineer (PE) flexibility in meeting many of the prevention
requirements. The "environmental equivalence" provision, in particular, allows facilities to deviate from
specified substantive requirements of the SPCC rule (except secondary containment provisions and certain
administrative provisions) by implementing alternate measures, certified by a PE, that provide equivalent
environmental protection. Deviations are not allowed for the administrative provisions of the rule, §§112.1
through 112.5, and for certain additional requirements in §112.7, such as recordkeeping and training.
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Additionally, in situations where secondary containment is not practicable, the owner/operator must (1) clearly
explain the reason for the determination in the SPCC Plan; (2) for bulk storage containers, conduct periodic
integrity testing of containers and associated valves and piping; and (3) prepare an oil spill contingency plan and
a written commitment of manpower, equipment, and materials to expeditiously control and remove any
quantity of oil discharged that may be harmful (§112.7(d)).
The 2002 rule amendments also revised many other rule provisions, both to provide regulatory relief
and to make technical changes. Specifically, the amendments exempted many completely buried underground
storage tanks (USTs), containers that store less than 55 U.S. gallons, and certain wastewater treatment
operations/facilities. The amendments also increased the oil capacity threshold for the applicability of the rule,
and both reduced information required after a discharge and raised the regulatory trigger for its submission. In
addition, the rule amendments decreased the frequency of Plan review from every three years to every five
years.
Technical amendments to the rule include requiring brittle fracture evaluation for field-constructed
aboveground containers; strengthening the integrity testing requirements; finalizing additional general
requirements for spill planning, preparedness, and reporting; adding a requirement for a facility diagram;
clarifying the rule's applicability to the operational use of oil; and making the PE certification and associated
attestation more specific. Also, the rule allows alternative formats for SPCC Plans with a cross-reference and
mandates specific time frames for employee training.
The specific amendments to each section of the SPCC rule finalized in 2002 are highlighted in Appendix C
of this guidance, Summary of Revised SPCC Rule Provisions.
1.3.3 Summary of 2006 Revisions
In 2006, EPA amended the SPCC rule to streamline the regulatory requirements for a subset of facilities.
The revisions specifically addressed certain "qualified facilities," oil-filled operational equipment, motive power,
s, animal fats and vegetable oils, and farms. Each of these topics is discussed below. The specific amendments to
each section of the SPCC rule finalized in 2006 are also highlighted in Appendix C of this guidance, Summary of
Revised SPCC Rule Provisions.
Qualified Facilities
The 2006 amendments provided an option to allow the owner or operator of a facility that meets
qualifying criteria (a "qualified facility") to self-certify the facility's SPCC Plan in lieu of review and certification by
a licensed Professional Engineer (PE). The 2008 amendments further streamlined and tailored SPCC rule
requirements for a subset of qualified facilities (see Section 1.3.4). While this section briefly describes the
associated regulatory requirements, separate guidance is available for qualified facilities at
http://www.epa.gov/oem/content/spcc/spcc qf.htm.
To be eligible to take advantage of the qualified facility self-certification option, a facility must meet the
following criteria:
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1. In the three years before the SPCC Plan is certified, (or since becoming subject to the SPCC rule if the
facility has been in operation for less than three years), the facility has had no discharges to
navigable waters or adjoining shorelines as described below:
A single discharge greater than 1,000 U.S. gallons, or
Two discharges as each greater than 42 U.S. gallons within any 12-month period; and
2. The facility has an aggregate aboveground oil storage capacity of 10,000 U.S. gallons or less.
Facilities that meet these criteria were later designated as Tier II qualified facilities in the 2008
amendments (see Section 1.3.4). Discharges to navigable waters or adjoining shorelines (i.e., discharges as
described in §112.l(b)) that are the result of natural disasters, acts of war, or terrorism do not disqualify a
facility from using the self-certification option. When determining spill history, the U.S. gallon amount specified
in the criterion (either 1,000 or 42) refers to the amount of oil that actually reaches navigable waters or
adjoining shorelines and not the total amount of oil spilled. The entire volume of the discharge is considered to
be oil for the purpose of these reporting requirements.
Self-certified Tier II qualified facility Plans can include alternative methods that provide environmental
equivalence when each alternate method has been reviewed and certified in writing by a PE18 (§112.6(d)).
Because the flexibility offered by the use of environmental equivalence (discussed in detail in Chapter 3:
Environmental Equivalence) is not available for Plans without review and certification by a PE, the 2006 rule
provided streamlined requirements for security requirements and bulk storage container inspections. Similarly,
self-certified Tier II Plans may include a determination that secondary containment is impracticable and use
alternative provisions in lieu of secondary containment, when the determination and alternative provisions are
reviewed and certified in writing by a PE.
The self-certification is optional for qualified facilities. The owner or operator of an otherwise-qualified
facility may choose to prepare a Plan in accordance with the general Plan requirements (§112.7) and applicable
requirements in subparts B and C, and have the Plan certified by a PE as required under §112.3(d) rather than
self-certify the SPCC Plan.
Oil-Filled Operational Equipment
The 2006 final rule amended §112.7 to provide an alternative option for facilities with qualified oil-filled
operational equipment. Oil-filled operational equipment includes equipment with an oil storage container (or
multiple containers) in which the oil is present solely to support the function of the apparatus or the device.
A self-certified Plan with PE-certified portions is called a "hybrid Plan.'
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"Qualified" oil-filled operational equipment are those that have had no discharges to navigable waters
or adjoining shorelines in the three years prior to the SPCC Plan certification date (or since the facility became
subject to 40 CFR part 112 if it has been in operation for less than three years), as described below:19
• A single discharge greater than 1,000 U.S. gallons, or
• Two discharges as each greater than 42 U.S. gallons within any 12-month period;
In lieu of general secondary containment for qualified oil-filled operational equipment, facility owners or
operators may establish and document the facility procedures for inspections or a monitoring program to detect
equipment failure and/or a discharge, develop an oil spill contingency plan, and provide a written commitment
of manpower, equipment, and materials required to expeditiously control and remove any quantity of oil
discharged that may be harmful.
If an owner/operator submitted an FRP to EPA in accordance with the requirements in §§112.20 and
112.21, the owner/operator does not need to develop an oil spill contingency plan and provide a written
commitment of resources. Facilities do not have to make an impracticability determination for each piece of
qualified oil-filled operational equipment. Chapter 2: SPCC Rule Applicability provides more detail on the
definition of oil-filled operational equipment (see Section 2.10.4) and Chapter 4: Secondary Containment and
Impracticability (see Section 4.2.1) describes the alternative requirements for qualified oil-filled operational
equipment.
Motive Power
The 2006 amendments exempted motive power containers from the SPCC rule. Motive power
containers are onboard bulk storage containers used primarily to power the movement of a motor vehicle, or
ancillary onboard oil-filled operational equipment. The provision was included under the general applicability
section, §112.l(d). This exemption of motive power containers is discussed in more detail in Chapter 2: SPCC
Rule Applicability (see Section 2.8.6).
Mobile Refuelers
The 2006 amendments exempted mobile refuelers from the requirements of §§112.8(c)(2) and (11) and
112.12(c)(2) and (11). EPA defines a mobile refueler as "a bulk storage container, onboard a vehicle or towed,
that is designed or used solely to store and transport fuel for transfer into or from an aircraft, motor vehicle,
locomotive, vessel, ground service equipment, or other oil storage container." Mobile refuelers are discussed in
more detail in Chapter 2: SPCC Rule Applicability (see Section 2.5.1) and Chapter 4: Secondary Containment and
Impracticability (see Section 4.7.6). Additionally, in the 2008 amendments, this exemption from sized secondary
containment requirements was expanded to include similar tanker trucks not storing a fuel, as explained below
in Section 1.3.4 in the paragraph titled "General Secondary Containment for Non-Transportation-Related Tank
Trucks."
Unlike the qualified facility criteria there is no capacity criterion for oil-filled operational equipment.
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Animal Fats and Vegetable Oils (AFVOs)
The 2006 rule removed and reserved three sections of Subpart C of the regulation because they were
not appropriate for animal fats and vegetable oils (AVFOs). These sections included requirements for onshore oil
production facilities (§112.13), requirements for onshore oil drilling and workover facilities (§112.14), and
requirements for offshore oil drilling, production, or workover facilities (§112.15). This change has generated a
common misconception that AFVOs are no longer regulated under the SPCC requirements. This is incorrect;
AFVOs continue to be regulated under the SPCC rule and have specific requirements in §112.12.
Farms
A farm is defined as a facility on a tract of land devoted to the production of crops or raising of animals,
including fish, which produced and sold, or normally would have produced and sold, $1,000 or more of
agricultural products during a year (§112.2). In 2006, EPA extended the compliance date for farms until the
agency promulgated a rule specifically addressing how farms should be regulated under the SPCC rule. The 2006
compliance date extension was superseded by the 2009 rule that established November 10, 2010 as the
compliance date for farms (74 FR 29136, June 19, 2009). The compliance date was later extended to May 10,
2013 due to severe weather conditions in the continental United States that had a disproportionate effect on
the agricultural sector (76 FR 64245, October 18, 2011).
1.3.4 Summary of 2008 Revisions
On December 5, 2008, EPA amended the SPCC rule to address a number of issues and concerns raised
by the regulated community. The amendments were intended to increase clarity, streamline the requirements
to which facility owners and operators must adhere, and modify the requirements for specific industry sectors,
including farms and oil production facilities. Specific topics addressed by the 2008 rule revisions are discussed
below, and are also highlighted in Appendix C of this guidance, Summary of Revised SPCC Rule Provisions.
Hot-mix Asphalt (HMA)
The 2008 amendments exempted hot-mix asphalt (HMA) and HMA-containers from the rule
requirements by modifying §112.1(d)(2) and adding paragraph §112.1(d)(8). HMA is typically asphalt cement
(AC) mixed with aggregate. The capacity of HMA containers is not counted toward the facility's oil storage
capacity calculation because this material is unlikely to flow as a result of the entrained aggregate. Therefore,
there would be very few circumstances, if any, in which a discharge of HMA would have the potential to reach
navigable waters or adjoining shorelines. However, AC, asphalt emulsions, and cutbacks, that are not entrained
with aggregates and are thus not HMAs, continue to be subject to SPCC regulation. This exemption is discussed
further in Chapter 2: SPCC Rule Applicability (see Section 2.2.4).
Pesticide Application Equipment
The 2008 amendments exempted all pesticide application equipment and related mix containers
regardless of ownership or where used when crop oil or adjuvant oil is added to the pesticide formulation
(§112.1(d)(10)). EPA also modified §112.1(d)(2) so that the capacity of pesticide application equipment and
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Chapter 1: Introduction
related mix containers is not counted toward the facility's oil storage capacity calculation. This exemption is
discussed further in Chapter 2: SPCC Rule Applicability (see Section 2.8.9).
Residential Heating Oil Containers
The 2008 rule amended §112.l(d) and added paragraph §112.1(d)(9) to exempt from SPCC applicability
containers (both aboveground and completely buried) that are used to store oil for the sole purpose of heating
single-family residences (including at a farm). Furthermore, the capacity of such containers does not count
toward the facility aggregate oil storage capacity. This exemption is discussed further in Chapter 2: SPCC Rule
Applicability (see Section 2.8.8).
Definition of Facility
The 2008 amendments modified the definition of the term "facility" under §112.2 and clarified that this
definition alone governs the applicability of 40 CFR part 112. The amendments also clarified that the owner or
operator has the discretion to identify which contiguous or non-contiguous buildings, properties, parcels, leases,
structures, installations, pipes or pipelines make up the facility. The amendments also clarified that a facility
owner/operator may determine that s/he is no longer subject to the SPCC requirements. However, the revisions
note that owners and operators may not characterize a facility so as to simply avoid applicability of the rule. This
amendment is discussed in more detail in Chapter 2: SPCC Rule Applicability (see Section 2.4).
Facility Diagram
The 2008 final rule amended §112.7(a)(3) to clarify that the facility diagram must include all fixed
containers (that is, those that are not mobile or portable). For any mobile or portable containers (such as drums
or totes), a facility owner or operator must mark the storage area on the facility diagram for these containers.
The owner or operator may mark the number of containers, contents, and capacity of each container either on
the facility diagram or in a separate description in the SPCC Plan. Also, the amendment requires that certain
intra-facility piping (i.e., gathering lines) exempted from the SPCC requirements in the December 2008 action be
identified on the facility diagram and marked as "exempt." This amendment is discussed in more detail in
Chapter 6: Facility Diagram and Description (See Sections 6.4.5, 6.4.6 and 6.4.8).
Loading/Unloading Racks
The 2008 final rule defined the term "loading/unloading rack", which governs whether a facility's oil
transfer equipment and areas are subject to §112.7(h). Under §112.2, loading/unloading rack means "a fixed
structure (such as a platform, gangway) necessary for loading or unloading a tank truck or tank car, which is
located at a facility subject to the requirements of this part. A loading/unloading rack includes a loading or
unloading arm and may include any combination of the following: piping assemblages, valves, pumps, shut-off
devices, overfill sensors, or personnel safety devices." This definition and amendment is discussed in more detail
in Chapter 4: Secondary Containment and Impracticability (see Section 4.7.3).
The 2008 amendments excluded oil production facilities and farms from the loading/unloading rack
requirements at §112.7(h); however, this provision was removed in the 2009 final rule.
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Qualified Facilities
The 2008 amendments designated a subset of qualified facilities (Tier I qualified facilities) as those that
meet the current qualified facility eligibility criteria and that have no oil storage containers with an individual
aboveground storage capacity greater than 5,000 U.S. gallons. Under §112.6, the owner or operator of a Tier I
qualified facility has the option to complete and implement a self-certified SPCC Plan template (found in
Appendix G to 40 CFR part 112) in lieu of a full SPCC Plan to comply with the SPCC regulation. The template is
comprised of a set of streamlined SPCC rule requirements. The rule designated all other qualified facilities as
Tier II qualified facilities.
General Secondary Containment Requirements
The 2008 amendments modified the general secondary containment requirements under §112.7(c) by
clarifying that the scope of the general secondary containment requirements takes into consideration the typical
failure mode and most likely quantity of oil that would be discharged. The amendment clarified that general
secondary containment requirements allow for use of both active and passive secondary containment measures
and provided additional examples of prevention systems for onshore facilities. This amendment is discussed in
more detail in Chapter 4: Secondary Containment and Impracticability (see Section 4.2).
General Secondary Containment for Non-Transportation-Related Tank Trucks
The 2008 amendments extend the 2006 exemption from sized secondary containment requirements
provided to mobile refuelers to non-transportation-related tank trucks at facilities subject to the SPCC rule
(§§112.6(a)(3)(ii), 112.8(c)(2), 112.8(c)(ll), 112.12(c)(2), and 112.12(c)(ll)). The general secondary containment
requirements in §112.7(c) apply to non-transportation-related tank trucks. This amendment is discussed in more
detail in Chapter 4: Secondary Containment and Impracticability (see Section 4.7.6).
Facility Security Requirements
The 2008 rule amended the facility security requirements at §112.7(g) to be performance-based and
allow an owner or operator of a facility to tailor its security measures to suit the facility's characteristics and
location. The facility owner or operator is required to document in the SPCC Plan how these security measures
are implemented. This amendment is discussed in more detail in Chapter 3: Environmental Equivalence (see
Section 3.3.6).
Bulk Storage Container Integrity Testing Requirements
The 2008 final rule amended the requirements at §§112.8(c)(6) and 112.12(c)(6) to provide flexibility in
complying with the bulk storage container integrity testing requirements. The amendment allows an owner or
operator to consult and rely on industry standards to determine the appropriate qualifications for tank
inspectors/testing personnel, and the type and frequency of integrity testing required for a particular container
size, configuration, and design. These requirements are discussed in more detail in Chapter 7: Inspection,
Evaluation, and Testing.
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Integrity Testing Requirements for Animals Fats and Vegetable Oils
The 2008 SPCC rule amendments differentiate the integrity testing requirements at §112.12(c)(6) for an
owner or operator of a facility that handles Animal Fats and Vegetable Oils (AFVOs). Under this amendment, the
PE or the owner or operator self-certifying an SPCC Plan is provided the flexibility to use a visual inspection
program for integrity testing for containers that store AFVOs and that meet certain criteria identified in
§112.12(c)(6)(ii). This requirement is discussed in more detail in Chapter 7: Inspection, Evaluation, and Testing
(see Section 7.2.4).
Oil Production Facilities
The 2008 amendments tailored several requirements for oil production facilities which are discussed in
more detail in Chapter 2: SPCC Rule Applicability and Chapter 4: Secondary Containment and Impracticability,
including:
• Amending the definition of "production facility" in §112.2 to be consistent with the
amendments to the definition of "facility" (see Section 2.4.3);
• Providing new oil production facilities with additional time to prepare and implement their SPCC
Plans;
• Providing an alternative option for flow-through process vessels (such as separators and heater-
treaters) at oil production facilities to comply with the general secondary containment
requirement and additional oil spill prevention measures in lieu of sized secondary containment
(see Section 4.8.1);
• Exempting certain intra-facility gathering lines (see Section 2.8.10);
• Providing a compliance alternative for produced water containers to comply with the general
secondary containment requirement and additional oil spill prevention measures in lieu of sized
secondary containment (see Section 4.8.2);
• Establishing a minimum set of requirements for flowline and intra-facility gathering line
maintenance programs and providing a compliance alternative to secondary containment for
this piping (see Sections 3.3.5 and 4.2.2); and
• Clarifying the definition of "permanently closed" as it applies to oil production facilities and
containers present at an oil production facility (see Section 2.8.1).
The 2008 amendments also included several provisions that were removed from the rule in 2009,
including an exclusion for oil production facilities from the loading/unloading rack requirements at §112.7(h); an
exemption for certain produced water containers; and alternative qualified facilities eligibility criteria for oil
production facilities to be eligible to self-certify SPCC Plans.
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Chapter 1: Introduction
Man-made Structures
The 2008 amendments to the SPCC rule clarified that manmade features such as drainage control
structures and dikes cannot be used to conclude that there is no reasonable expectation that a discharge from a
facility will reach navigable waters or adjoining shorelines (§112.1(d)(l)(i)). However, it may be appropriate for a
facility owner or operator to consider man-made structures (for example, dikes, equipment, buildings,
basements or other containment structures) to determine how to comply with the SPCC rule secondary
containment and integrity testing requirements. This provision is addressed further in Chapter 4: Secondary
Containment and Impracticability (see Section 4.4.4).
Wind Turbines
The 2008 amendments clarified that wind turbines meet the definition of oil-filled operational
equipment adopted in the December 2006 rule amendments. Therefore, the alternative compliance option for
qualified oil-filled operational equipment in §112.7(k) may be available for SPCC-regulated wind turbines that
meet the qualifying criteria for oil-filled operational equipment.
Underground Emergency Diesel Generator Tanks at Nuclear Power Stations
The 2008 amendments exempted underground oil storage tanks deferred from regulation under 40 CFR
part 280, as originally promulgated, that supply emergency diesel generators at nuclear power generation
facilities licensed by Nuclear Regulatory Commission (NRC) and that meet the NRC design criteria and quality
assurance criteria. This exemption, under §§112.1(d)(2)(i) and 112.1(d)(4), includes both tanks that are
completely buried and certain tanks that are below-grade and vaulted. This exemption is discussed further in
Chapter 2: SPCC Rule Applicability (see Section 2.8.4).
1.3.5 Summary of Navigable Waters Ruling
On November 26, 2008 (73 FR 71941), the Federal Register published EPA's direct final rule to amend a
CWA section 311 regulation that defines the term "navigable waters." In this action, EPA announced the vacatur
of the July 17, 2002, revisions to the definition of "navigable waters" in accordance with an order, issued by the
United States District Court for the District of Columbia (D.D.C.) in American Petroleum Institute v. Johnson, 571
F.Supp.2d 165 (D.D.C. 2008), invalidating those revisions. The court decision also restored the regulatory
definition of "navigable waters" promulgated by EPA in 1973; consequently, EPA amended the definition of
"navigable waters" in part 112 to comply with that decision (see Section 2.6.4).
1.3.6 Summary of the 2009 Amendments to the 2008 Rule
On November 13, 2009, EPA promulgated revisions to the December 2008 amendments (74 FR 58784).
In this action, EPA removed the following provisions from the SPCC rule: the exclusion of farms and oil
production facilities from the loading/unloading rack requirements under §112.7(h), the exemption of certain
produced water containers at oil production facilities, and the alternative qualified facilities eligibility criteria for
oil production facilities. These amendments also retained or provided minor technical corrections to the
December 2008 provisions.
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1.3.7 Effective Date of the 2008 and 2009 Amendments
EPA twice delayed the effective date of the 2008 amendments. The effective date for the 2008
amendments was originally scheduled for February 3, 2009. However, on February 3, 2009 (74 FR 5900), the
effective date was delayed by 60 days, until April 4, 2009, in accordance with the January 20, 2009, White House
memorandum entitled "Regulatory Review" (74 FR 4435, January 26, 2009) and the memorandum from the
Office of Management and Budget entitled "Implementation of Memorandum Concerning Regulatory Review"
(M-09-08, January 21, 2009). EPA took that action to ensure that the final rule reflected proper consideration of
all relevant facts. In the February 3, 2009 notice, EPA requested public comment on the extension of the
effective date and its duration, and on the regulatory amendments contained in the final rule. As a result of
public comment, EPA further delayed the April 4, 2009 effective date until January 14, 2010 to allow sufficient
time to properly address public comments. These public comments were addressed in the November 2009 final
amendments to the SPCC rule (74 FR 58784, November 13, 2009), which also became effective on January 14,
2010. Modifications to the effective date did not affect the compliance date for preparing or updating an SPCC
Plan.
S? FYI - Effective date and compliance date
The effective date is the date that amendments in the rule document affect the current Code of Federal Regulations
(CFR). The current CFR consists of the rules published in the latest CFR volume and any effective amendments published
in the Federal Register since the revision date of the latest CFR volume. The effective date is not the same as the rule's
compliance date.
The compliance date is the date that the affected person (that is, the owner or operator) must comply with the revised
rule requirements.
1.3.8 Summary of the Milk and Milk Product Container Exemption
On January 15, 2009, the agency published a proposal to exempt from SPCC requirements milk
containers and associated piping and appurtenances provided they are constructed according to current
applicable 3-A Sanitary Standards, and are subject to the current applicable Grade "A" Pasteurized Milk
Ordinance (PMO) or a State dairy regulatory requirement equivalent to the current applicable PMO (74 FR
2463).
EPA modified the proposed rule language and exempted milk and milk product containers, associated
piping and appurtenances on April 18, 2011 (76 FR 21652). EPA believes that the combination of these specific
construction and sanitation standards address the prevention of oil discharges in quantities that may be
harmful.
The capacity of the exempt milk and milk product containers, piping and appurtenances is excluded
from the calculation of a facility's total oil storage capacity when determining if the facility is subject to the SPCC
rule. This exemption is addressed further in Chapter 2: SPCC Rule Applicability (see Section 2.8.11).
1.4 Using This Guidance
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Chapter 1: Introduction
SPCC Guidance for Regional Inspectors is intended to assist regional EPA inspectors in implementing the
revised SPCC rule, including environmental equivalence, impracticability, and integrity testing, as well as the role
of the inspector in the review of these provisions. It is also intended to establish a nationally consistent
understanding among regional EPA inspectors on how certain provisions of the rule may be applied. Finally, the
guidance also provides the regulated community, including PEs and qualified facility owner/operators, with
information that is valuable for the development and implementation of SPCC Plans. This guidance does not
address all aspects of the SPCC rule, nor is it a substitute for
the regulation itself. Additional guidance is available for
qualified facility owners/operators at
http://www.epa.gov/oem/content/spcc/spcc qf.htm.
Excerpts of the SPCC rule relevant to a particular
section of this guidance are provided in text
boxes. This information is provided for
informational purposes only. The reader should
always refer to the full text of the current 40 CFR
part 112 rule for the applicable regulatory
language, available from the Government
Printing Office Web site at
http://www.gpoaccess.gov/fr/.
Many of the terms used in this guidance have specific
regulatory definitions in 40 CFR 112.2; however, other
regulatory programs may define some of these terms
differently. Please refer to §112.2 of the rule and associated
preamble of the July 2002, December 2006, December 2008,
and November 2009 Federal Register publications for clarification of defined terms in the SPCC rule. An
acronyms list, provided at the beginning of this document, defines all acronyms used throughout the guidance.
This guidance is divided into seven main chapters and includes several appendices for the reader's
reference, as follows:
• Chapter 1: Introduction discusses the purpose and scope of 40 CFR part 112, the regulatory
history, and the 2002, 2006, 2008, 2009, and 2011 rule amendments.
• Chapter 2: SPCC Rule Applicability clarifies the facilities, activities, and equipment that are
subject to the SPCC rule through an in-depth discussion of the rule and relevant scenarios.
• Chapters: Environmental Equivalence discusses the use of the "environmental equivalence"
provision, which allows facilities to implement alternate measures based on site-specific
considerations, as long as the measures provide equivalent environmental protection, in
accordance with good engineering practice and as determined by a PE.
• Chapter 4: Secondary Containment and Impracticability discusses the secondary containment
requirements and explains when an impracticability determination can be made and how the
determination should be documented.
• Chapters: Oil/Water Separators addresses various scenarios involving oil/water separators
with respect to the SPCC rule requirements.
• Chapter 6: Facility Diagram and Description provides guidelines on the necessary level of detail
for facility diagrams included in SPCC Plans. This section also includes example facility diagrams
for different types of facilities.
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Chapter 1: Introduction
• Chapter 7: Inspection, Evaluation, and Testing explains the inspection, evaluation, and testing
requirements for facilities subject to the SPCC rule, as well as how "environmental equivalence"
may apply for the integrity testing requirements of the SPCC rule.
The appendices include a complete copy of the relevant sections of the statutory authority from the
Clean Water Act; the Oil Pollution Prevention regulation (40 CFR part 112); the Discharge of Oil regulation (40
CFR part 110); the Criteria for State, Local and Regional Oil Removal Contingency Plans (40 CFR part 109); a
summary of revised rule provisions; model SPCC Plans; a model contingency plan; inspector checklists; and a
collection of other SPCC policy documents.
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Chapter 2 SPCC Rule Applicability
2.1 Introduction
The SPCC rule establishes requirements to prepare and implement SPCC Plans. SPCC Plans complement
existing laws, regulations, rules, standards, policies, and procedures pertaining to safety, fire prevention, and oil
pollution prevention. The purpose of an SPCC Plan is to form a comprehensive oil spill prevention program that
minimizes the potential for discharges. The SPCC Plan must address all relevant spill prevention, control, and
countermeasures necessary at the specific facility.
The rule applies to the owners and operators of non-
transportation-related onshore and offshore facilities that
could reasonably be expected to discharge oil into navigable
waters of the United States or adjoining shorelines in
quantities that may be harmful. This chapter clarifies which
facilities, activities, and equipment are subject to the SPCC
rule. The facility owner/operator is responsible for
determining whether the facility is subject to the SPCC rule,
however, this determination is subject to review by the
Regional Administrator or his delegated representative.
2.1.1 Summary of General Applicability
Section 112.1 establishes the general applicability of
the SPCC rule. The SPCC rule applies to facilities that:
• Are non-transportation-related;
• Have an aboveground oil storage capacity of more than 1,320 U.S. gallons or a completely
buried oil storage capacity greater than 42,000 U.S; and
• Could reasonably be expected to discharge oil to navigable waters or adjoining shorelines in
quantities that may be harmful.
Facilities that are owned and operated by federal, state, local government or tribal entities are equally
subject to the regulation20 as any other facility (although the federal government is not subject to civil
penalties). Unlike some other federal environmental programs, the Clean Water Act does not authorize EPA to
delegate the SPCC program implementation or enforcement to State, local, or tribal representatives.
...this part applies to any owner or operator of a
non-transportation-related onshore or offshore
facility engaged in drilling, producing, gathering,
storing, processing, refining, transferring,
distributing, using, or consuming oil and oil
products, which due to its location, could
reasonably be expected to discharge oil in
quantities that may be harmful, as described in
part 110 of this chapter, into or upon the
navigable waters of the United States or
adjoining shorelines...
Note: The above text is an excerpt of the SPCC rule. Refer
to 40 CFR part 112 for the full text of the rule.
The SPCC rule requires an owner or operator to develop an SPCC Plan. Under the CWA the definition of owner or operator
includes "person" which includes federal, state and local government or tribal entities (33 USC 1362(4) (CWA Section 502(4))).
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^Applicability
Specifically, EPA exempts:
Any facility where the completely buried oil storage capacity is 42,000 U.S. gallons or less and the aggregate
aboveground oil storage capacity is 1,320 U.S. gallons or less;
Completely buried oil tanks and associated piping and equipment that are subject to all of the technical
requirements under 40 CFR part 280 or 281;
Underground oil storage tanks, including below-grade vaulted tanks that supply emergency diesel generators
at a nuclear power generation facility licensed by the Nuclear Regulatory Commission (NRC) and subject to any
NRC provision regarding design and quality criteria, including but not limited to 10 CFR part 50;
Permanently closed oil containers;
Any container with an oil storage capacity less than 55 U.S. gallons;
Any facility or part thereof used exclusively for wastewater treatment;
Motive power oil containers;
Hot-mix asphalt or any hot-mix asphalt container;
Containers storing heating oil used solely at a single-family residence;
Pesticide application equipment or related mix containers (with adjuvant oil);
Intra-facility oil gathering lines subject to the regulatory requirements of 49 CFR part 192 or 195; and
- Any milk and milk product container and associated piping and appurtenance.
Do not include exempt oil containers or oil equipment when calculating the total oil storage capacity of the facility, (see
Section 112.l(d) describes facilities subject to EPA jurisdiction (i.e., that are non-transportation-related)
and the activities and equipment that are exempt from the SPCC rule and from the facility total oil storage
capacity calculations. The section also describes the types of facilities that are outside EPA jurisdiction and
therefore not subject to the SPCC rule. Notwithstanding the exemptions provided in §112.l(d), under §112.l(f)
the Regional Administrator has discretion to require the owner or operator of any facility, subject to EPA's
jurisdiction under §311(j) of the Clean Water Act (CWA), to prepare and implement an SPCC Plan, or part of an
SPCC Plan.
This chapter further explains each of the applicability criteria listed in §112.1 and provides examples of
how these criteria are applied. The remainder of this chapter is organized as follows:
• Section 2.2 discusses the definition of "oil" and the regulated activities.
• Section 2.3 discusses activities involving oil.
• Section 2.4 explains what a "facility" is and provides examples of how a facility can be
determined.
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Chapter 2: Applicability
• Section 2.5 discusses the difference between "transportation-related" and "non-transportation-
related" facilities in determining jurisdiction of regulatory agencies.
• Section 2.6 discusses the criteria for a facility to have a "reasonable expectation of a discharge
to navigable waters in quantities that may be harmful."
• Section 2.7 addresses storage capacity thresholds and methods of calculating storage capacity.
• Section 2.8 addresses the exemptions to the SPCC rule.
• Section 2.9 discusses the process for a Regional Administrator to determine applicability,
outside of the exemptions listed in §112.l(d).
• Section 2.10 addresses the applicability of the rule requirements to different kinds of
containers.
• Section 2.11 discusses the applicability of Facility Response Plan (FRP) requirements.
• Section 2.12 describes the role of the EPA inspector.
2.2 Definition of Oil
The SPCC rule applies to the owners and operators of
facilities with the potential to discharge oil in quantities that
may be harmful to navigable waters or adjoining shorelines.
The SPCC rule's definition of oil derives from §311(a)(l) of
the Clean Water Act (CWA) which defines oil as "oil of any
kind or in any form, including, but not limited to, petroleum,
fuel oil, sludge, oil refuse, and oil mixed with wastes other
than dredged spoil."
OPA §1001 defined oil separately to exclude any
substance which is specifically listed or designated as a
hazardous substance under Comprehensive Environmental
Response, Compensation, and Liability Act (CERCLA) and
which is subject to provisions of that Act.21 Although oil is
defined separately under OPA, that definition did not amend the original CWA definition of oil in §311(a)(l) and
therefore was not incorporated into the definition of oil under 40 CFR part 112.2 that applies to both SPCC and
FRP regulatory requirements.
§112.2
Oil means oil of any kind or in any form,
including, but not limited to: fats, oils, or greases
of animal, fish, or marine mammal origin;
vegetable oils, including oils from seeds, nuts,
fruits, or kernels; and, other oils and greases,
including petroleum, fuel oil, sludge, synthetic
oils, mineral oils, oil refuse, or oil mixed with
wastes other than dredged spoil.
Note: The above text is an excerpt of the SPCC rule. Refer
to 40 CFR part 112 for the full text of the rule.
Under OPA, "oil" means "oil of any kind or in any form, including petroleum, fuel oil, sludge, oil refuse, and oil mixed with
wastes other than dredged spoil, but does not include any substance which is specifically listed or designated as a hazardous
substance under subparagraphs (A) through (F) of section 101(14) of the Comprehensive Environmental Response,
Compensation, and Liability Act (42 U.S.C. 9601) and which is subject to the provisions of that Act."
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Chapter 2: Applicability
In response to Edible Oil Regulatory Reform Act (EORRA) of 1995 (33 U.S.C. 2720) requirements, the oil
definition under §112.2 was revised to include the categories of oil in EORRA. Those categories are: (1)
petroleum oils, (2) animal fats and vegetable oils; and, (3) other non-petroleum oils and greases.22
Section 112.2 of the SPCC rule defines oil as "oil of any kind or in any form, including, but not limited to:
fats, oils, or greases of animal, fish, or marine mammal origin; vegetable oils, including oils from seeds, nuts,
fruits, or kernels; and, other oils and greases, including petroleum, fuel oil, sludge, synthetic oils, mineral oils, oil
refuse, or oil mixed with wastes other than dredged spoil."
The U.S. Coast Guard (USCG) maintains a separate list of substances it considers oil for its regulatory
purposes. The list is available on the USCG Web site and may be used as a guide when determining if a particular
substance is an oil.23 However, it is important to note that for purposes of EPA's regulations, the USCG list is not
comprehensive and does not include all oils that are subject to 40 CFR part 112. The sections below discuss
whether or not specific substances are considered oils for purposes of SPCC regulation.
2.2.1 Petroleum Oils and Non-Petroleum Oils
The SPCC rule applies to both petroleum oils and non-petroleum oils. Petroleum oils include, but are not
limited to, crude and refined petroleum products, asphalt, gasoline, fuel oils, mineral oils, naphtha, sludge, oil
refuse, and oil mixed with wastes other than dredged spoil. Nonpetroleum oils and greases include coal tar,
creosote, silicon fluids, pine oil, turpentine, and tall oils. (67 FR 47075, July 17, 2002).
Subpart B of 40 CFR part 112 covers both "petroleum oils and non-petroleum oils..." Petroleum oils and
non-petroleum oils, including synthetic oils, share common physical properties and produce similar
environmental effects. Petroleum and non-petroleum oils can enter all parts of an aquatic system and adjacent
shoreline, and similar methods of containment, removal and cleanup are used to reduce the harm created by
spills of both types of oils.
2.2.2 Synthetic Oils
Synthetic oils are used in a wide range of applications, including as heat transfer fluids, engine fluids,
hydraulic and transmission fluids, metalworking fluids, dielectric fluids, compressor lubricants, and turbine
lubricants. Synthetic oils are created by chemical synthesis rather than by refining petroleum crude or extracting
oil from plant seeds. Oils that are derived from plant material may be considered animal fats and vegetable oils
under subpart C of 40 CFR part 112.
EPA provided notice in 1975 that affirmed that animal fats and vegetable oils (AFVOs) were subject to the SPCC rule (40 FR
28849, July 9,1975). For more information see Chapter 1: Introduction.
See the "List of Petroleum and Non-Petroleum Oils" on the USCG Web site at http://www.uscg.mil/vrp/faq/oil.shtml under
"Additional References."
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Chapter 2: Applicability
2.2.3 Animal Fats and Vegetable Oils (AFVO)
Animal fats and vegetable oils are covered under the SPCC regulation. Animal fats include but are not
limited to fats, oils, and greases of animal origin (for example, lard and tallow), fish (for example, cod liver oil), or
marine mammal origin (for example, whale oil).
§112.2
Animal fat means a non-petroleum oil, fat, or
grease of animal, fish, or marine mammal origin.
Vegetable oil means a non-petroleum oil or fat of
vegetable origin, including but not limited to oils
and fats derived from plant seeds, nuts, fruits,
and kernels.
Note: The above text is an excerpt of the SPCC rule. Refer
to 40 CFR part 112 for the full text of the rule.
Vegetable oils include but are not limited to oils of
vegetable origin, including oils from seeds, nuts, fruits, and
kernels. Examples of vegetable oils include: corn oil,
rapeseed oil, coconut oil, palm oil, soy bean oil, sunflower
seed oil, cottonseed oil, and peanut oil. (67 FR 47075, July
17, 2002).
2.2.4 Asphalt
Asphalt is a thermoplastic material, composed of
unsaturated aliphatic and aromatic compounds, that
softens when heated and hardens upon cooling. Within a
certain temperature range, it exhibits viscoelastic properties with viscous flow behavior and elastic deformation.
All types of asphalt are petroleum oil products, and its composition depends on the source of the crude oil and
the process used to manufacture it.
The SPCC rule applies to asphalt cement (AC), as well as to asphalt derivatives such as cutbacks and
emulsions. Because of the operational conditions under which AC, cutbacks and emulsions are used and stored,
they do pose a risk of being discharged into navigable waters or adjoining shorelines. Although AC) is semi-solid
or solid at ambient temperature and pressure, it is generally stored at elevated temperatures. Hot AC is liquid-
similar to other semi-solid oils, such as paraffin wax and heavy bunker fuels—and therefore is capable of
flowing. Cutbacks and emulsions are liquid at ambient temperature, and because of their low viscosity, they may
flow when discharged onto the ground. All of these oils are regulated under the SPCC rule to prevent discharges
to navigable waters or adjoining shorelines.
However, hot-mix asphalt (HMA) and HMA containers are exempt from the SPCC rule. HMA is a blend of
AC and aggregate material, such as stone, ground tires, sand, or gravel, which is formed into final paving
products for use on roads and parking lots. HMA is unlikely to flow as a result of the entrained aggregate, such
that there would be very few circumstances, if any, in which a discharge of HMA would have the potential to
reach navigable waters or adjoining shorelines.
2.2.5 Natural Gas and Condensate
The SPCC rule does not apply to natural gas (including liquid natural gas and liquid petroleum gas). EPA
does not consider highly volatile liquids that volatilize on contact with air or water, such as liquid natural gas or
liquid petroleum gas, to be oil (67 FR 47076, July 17, 2002). Furthermore, EPA has stated that hydrocarbons in a
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gaseous phase under ambient pressure and temperature, such as natural gas, present at SPCC regulated
facilities are not regulated under the SPCC rule (73 FR 74271, December 5, 2008).
However, natural gas liquid condensate (often referred to as "natural gasoline" or "drip gas") is an oil
subject to the SPCC rule. Condensate can accumulate in tanks, containers, or other equipment. For the purposes
of determining SPCC applicability, containers with 55 gallons or more in capacity storing condensate must be
included in a natural gas facility's total oil storage capacity calculation.
More information on specific types of facilities handling both natural gas and oil and how they are
regulated under the SPCC rule can be found in Section 2.4.7.
2.2.6 Oil and Water Mixtures
Oil and water mixture containers are subject to the SPCC rule. A mixture of wastewater and oil is "oil"
under the statutory and regulatory definition of the term (33 U.S.C. 1321(a)(l) and 40 CFR 110.2 and 112.2). A
discharge of wastewater containing oil to navigable waters or adjoining shorelines in a "harmful quantity" (40
CFR part 110) is prohibited (see July 17, 2002, 67 FR 47069). One example of an oil and water mixture is
produced water.
2.2.7 Produced Water
§112.2
Produced water container means a storage
container at an oil production facility used to
store the produced water after initial oil/water
separation, and prior to reinjection, beneficial
reuse, discharge, or transfer for disposal.
Note: The above text is an excerpt of the SPCC rule. Refer
to 40 CFR part 112 for the full text of the rule.
The SPCC rule applies to produced water from an oil
well. Produced water is the oil and water mixture resulting
from the separation of crude oil or gas from the fluids or
gases extracted from the oil/gas reservoir, prior to disposal,
subsequent use (e.g., re-injection or beneficial reuse), or
further treatment. Produced water's chemical and physical
characteristics vary considerably depending on the geologic
formation, usually being commingled with oil and gas at the
wellhead, and changing in composition as the oil or natural
gas fraction is separated and sent to market.
Produced water is typically collected in produced water containers at the end of the oil and gas
treatment process, and often accumulates emulsified oil not captured in the separation process. Under normal
operating conditions, a layer of oil may be present on top of the fluids. The amount of oil by volume observed in
produced water storage containers varies, but based on EPA's assessment, is generally estimated to range from
less than one to ten percent by volume, and can be greater. Oil may be present not only in free phase, but also
in other forms, such as in a dissolved phase, emulsion or a sludge at the bottom of the produced water
container.
Oil discharges to navigable waters or adjoining shorelines from an oil/water mixture in a produced water
container may cause harm. Such mixtures24 are regulated as oil under the SPCC rule. Therefore, the capacity of
Refers to mixtures in the produced water container.
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produced water containers counts toward the facility aggregate oil storage capacity. Produced water containers
at oil production, oil recycling or oil recovery facilities are not eligible for the wastewater treatment exemption
2.2.8 Hazardous Substances and Hazardous Waste
The definition of "oil" in §112.2 includes but is not limited to "oil mixed with wastes other than dredged
spoil." Oils covered under the SPCC rule include certain hazardous substances or hazardous wastes that are oils,
as well as certain hazardous substances or hazardous wastes that are mixed with oils. Containers storing these
substances may also be covered by other regulations, such as the Resource Conservation and Recovery Act
(RCRA) or CERCLA (also known as Superfund). For example, the definition of oil under §112.2 includes "used oil"
because it is an oil mixed with wastes. "Used oil," as defined in EPA's Standards for the Management of Used Oil
at 40 CFR 279.1, means any oil that has been refined from crude oil, or any synthetic oil, that has been used and
as a result of such use is contaminated by physical or chemical impurities.
Inspectors should evaluate whether containers storing hazardous substances or mixtures of wastes
contain oil. Hazardous substances or hazardous wastes that are neither oils nor mixed with oils are not subject
to SPCC rule requirements. For purposes of 40 CFR part 112, the CWA §311(b)(2) hazardous substances as
identified under 40 CFR part 116 are not considered oils. However, an oil mixture that includes a CWA hazardous
substance is subject to 40 CFR part 112 when it meets the definition of oil in the regulation. For example,
benzene is a CWA hazardous substance and therefore does not meet the definition of oil in §112.2; however,
benzene is a constituent of gasoline which is a mixture that includes other oils. Gasoline is an oil as defined
under 40 CFR part 112.2.
Although the rule contains an exemption for completely buried tanks that are subject to all underground
storage tank (UST) technical requirements of 40 CFR part 280 and/or a state program approved under part 281
under §112.1(d)(2)(i) or (4), tanks containing RCRA hazardous wastes are not subject to the UST rules. Therefore,
when RCRA hazardous wastes tanks located at a facility subject to the SPCC rule also contain oil, they are subject
to the SPCC rule requirements.
2.2.9 Denatured Ethanol used in Renewable Fuels
Renewable fuels, such as E85 or "flex fuel" (15% unleaded gasoline and 85% ethanol) are produced in a
blending process.25 Ethanol used for fuel often contains a denaturing additive (typically gasoline, natural
gasoline, diesel fuel or other oil petroleum product) which is oil. Therefore, the final denatured ethanol is also
considered an oil, and facilities handling or storing denatured ethanol may be subject to the SPCC requirements.
An EPA letter dated November 7, 2006 details the Agency's position on denatured ethanol (see Appendix H).
For more information on ethanol renewable fuels see:
http://epa.gov/region07/priorities/agriculture/pdf/ethanol plants manual.pdf
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2.2.10 Biodiesel and Biodiesel Blends
Biodiesel and biodiesel blends are other types of renewable fuels that are often stored and handled at
facilities regulated under 40 CFR part 112.2S Biodiesel, designated B100, is a domestic, renewable fuel for diesel
engines derived from natural oils like soybean oil. Biodiesel is comprised of mono-alkyl esters of long chain fatty
acids derived from vegetable oils or animal fats.
Biodiesel can be used in any concentration with petroleum-based diesel fuel in existing diesel engines
with little or no modification. Biodiesel is not the same as raw vegetable oil. It is produced by a chemical process
which removes the glycerin from the oil. Biodiesel is typically produced by a reaction of a vegetable oil or animal
fat with an alcohol such as methanol or ethanol in the presence of a catalyst to yield mono-alkyl esters and
glycerin, which is removed.
Biodiesel blends are a blend of biodiesel fuel with petroleum-based diesel fuel, designated BXX, where
XX represents the volume percentage of biodiesel fuel in the
blend. Both biodiesel (B100) and biodiesel blends are
considered oil for the purposes of 40 CFR part 112.
2.3 Activities Involving Oil
Section 112.l(b) specifies the following oil-related
activities are regulated under the SPCC rule: "drilling,
producing, gathering, storing, processing, refining,
transferring, distributing, using, or consuming oil and oil
products." These activities are subject to SPCC provided the
facility meets the other applicability criteria in §112.1. Table
2-1 provides examples of these activities.
§112.l(b)
...this part applies to any owner or operator of a
non-transportation-related onshore or offshore
facility engaged in drilling, producing, gathering,
storing, processing, refining, transferring,
distributing, using, or consuming oil and oil
products....
Note: The above text is an excerpt of the SPCC rule. Refer
to 40 CFR part 112 for the full text of the rule. Emphasis
added.
For more information on biodiesel renewable fuels see:
http://epa.gov/region07/priorities/agriculture/pdf/biodiesel manual.pdf
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Table 2-1: Examples of some oil-related activities that may be regulated under 40 CFR part 112.2
Activity
Drilling
Producing
Gathering
Storing
Processing
Refining
Transferring
Distributing
Using
Consuming
Examples of Oil-related Regulated Activities
Drilling a well to extract crude oil or natural gas and associated products (such as wet natural gas) from
a subsurface field
Extracting product from a well and separating the crude oil and/or gas from other associated products
(e.g., water, sediment)
Collecting oil from numerous wells, tank batteries, or platforms and transporting it to a main storage
facility, processing plant, or shipping point
Storing oil in containers prior to use, while being used, or prior to further distribution in commerce
Treating oil using a series of processes to prepare the oil for commercial use, consumption, further
refining, manufacturing, or distribution
Separating crude oil into different types of hydrocarbons through distillation, cracking, reforming, and
other processes; separating animal fats and vegetable oils from free fatty acids and other impurities
Transferring oil between containers, such as between a railcar or tank truck and a bulk storage
container, or between stock tanks and manufacturing equipment
Selling or marketing oil for further commerce or moving oil using equipment such as highway vehicles,
railroad cars, or pipeline systems in the confines of a non-transportation-related facility. Note that
businesses commonly referred to as oil distributors and retailers are also "storing" oil, as described
above
Using oil for mechanical or operational purposes in a manner that does not significantly reduce the
quantity of oil, such as using oil to lubricate moving parts, provide insulation, or for other purposes in
electrical equipment, electrical transformers, and hydraulic equipment
Consuming oil in a manner that reduces the amount of oil, such as burning as fuel in a generator
2.4 Facilities
2.4.1 Definition of Facility
The definition of "facility" governs the overall applicability of 40 CFR part 112, and thus is used to
determine the scope of a facility's boundaries in order to determine if the facility is subject to the SPCC and/or
FRP requirements. The boundary or extent of a "facility" depends on site-specific circumstances. Factors that
may be considered relevant in delineating the boundaries of a facility under 40 CFR 112 may include, but are not
limited to:
• Ownership, management, and operation of the buildings, structures, equipment, installations,
pipes, or pipelines on the site;
• Similarity in functions, operational characteristics, and types of activities occurring at the site;
The examples listed in this table are not exhaustive and are for illustrative purposes only.
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Adjacency; or
Shared drainage pathways (e.g., same receiving water bodies).
The facility owner or operator, or a Professional Engineer (PE) on behalf of the facility owner/operator,
must make a judgment of what constitutes the "facility."
Once the owner or operator determines the facility
boundaries for purposes of the SPCC rule, then the same
boundaries apply for FRP applicability. Note that generally,
an SPCC-regulated facility excludes components that are not
subject to EPA's jurisdiction, but are instead subject solely to
the jurisdiction of other agencies, such as the Department of
Transportation (DOT) or the United States Coast Guard
(USCG).
Contiguous or non-contiguous buildings, properties,
parcels, leases, structures, installations, pipes, or pipelines
under the ownership or operation of the same person may
be considered separate facilities for SPCC purposes. For
example, a single facility may be composed of various oil-
containing areas spread over a relatively large campus, such
as multiple operational areas within a military base. Each
operational area may be considered a separate facility. The
military base may not necessarily include single-family
homes occupied by military personnel as part of the facility if
these are considered personal space similar to civilian single-
family residences. However, larger military barracks for
which a branch of the military controls, operates, and
maintains the space would be included as part of a facility.
While the facility owner/operator has some discretion in defining the parameters of the facility, the
boundaries of a facility may not be drawn to solely avoid regulation under 40 CFR part 112. For example, two
contiguous operational areas, each with 700 gallons in aboveground storage capacity, that have the same
owner, perform similar functions, are attended by the same personnel, and are in other ways indistinguishable
from each other, would reasonably be expected to represent a single facility under the SPCC rule, and would
therefore be required to have an SPCC Plan, since the capacity of this facility is above the 1,320-gallon
aboveground threshold. These two operational areas would not be defined as two separate facilities under the
definition of "facility" in §112.2. EPA reserves the right to make its own facility boundary determination after
reviewing the Plan or inspecting the facility.
The facility owner and operator is responsible for ensuring that an SPCC Plan is prepared. A single site
may have multiple owners and/or operators, and therefore may be divided into multiple facilities. Factors to
§112.2
Facility means any mobile or fixed, onshore or
offshore building, property, parcel, lease,
structure, installation, equipment, pipe, or
pipeline (other than a vessel or a public vessel)
used in oil well drilling operations, oil production,
oil refining, oil storage, oil gathering, oil
processing, oil transfer, oil distribution, and oil
waste treatment, or in which oil is used, as
described in appendix A to this part. The
boundaries of a facility depend on several site-
specific factors, including but not limited to, the
ownership or operation of buildings, structures,
and equipment on the same site and types of
activity at the site. Contiguous or non-contiguous
buildings, properties, parcels, leases, structures,
installations, pipes, or pipelines under the
ownership or operation of the same person may
be considered separate facilities. Only this
definition governs whether a facility is subject to
this part.
Note: The above text is an excerpt of the SPCC rule. Refer
to 40 CFR part 112 for the full text of the rule.
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consider in determining which owner or operator should prepare the Plan include who has control over day-to-
day operations of the facility or particular containers and equipment, who trains the employee(s) involved in oil
handling activities, who will conduct the required inspections and tests, and who will be responsible for
responding to and cleaning up any discharge of oil. EPA expects that the owners and operators will cooperate to
prepare one or more Plans, as appropriate, to be kept at each facility when attended more than four hours per
day.
SPCC facilities include not only permanent facilities with fixed storage and equipment, but also those
that have only standby, temporary, and seasonal storage as described under §112.1(b)(3), as well as
construction facilities. The owners and operators of mobile facilities (addressed in §112.3(a)) can create a
general Plan, instead of developing a new Plan each time the facility is moved to a new location. Types of
operations (mobile facilities) using a mobile plan include, but are not limited to, mobile fueling operations, road
construction projects, drilling operations, and workover operations.
Because the physical surroundings of mobile facilities are subject to change, §112.3(a)(2) of the SPCC
rule indicates that the owner or operator of a mobile facility may have a "general" Plan and need not prepare a
new Plan each time the mobile facility is moved to a new site. When a mobile facility is moved, it must be
located and installed using the spill prevention practices outlined in its Plan. In accordance with §112.3(a)(2), the
Plan is only required to be implemented "while the facility is in a fixed (non-transportation) operating mode"
(67 FR 47081, July 17, 2002).
2.4.2 Definitions of Onshore and Offshore Facility
EPA was delegated the authority to regulate non-transportation-related onshore and offshore facilities
that could reasonably be expected to discharge oil into navigable waters of the United States or adjoining
shorelines. Section 112.2 defines an "onshore facility" as "any facility of any kind located in, on, or under any
land within the United States, other than submerged lands." Requirements under Subparts B and C are divided
based on the location of the facility and the type of operations. Sections 112.8 and 112.12 apply to all onshore
facilities (excluding oil production facilities). Section 112.9
applies to all onshore oil production facilities and §112.10
applies to all onshore oil drilling and workover facilities.
"Offshore facility" means any facility of any kind
(other than a vessel or public vessel) located in, on, or under
any of the navigable waters of the United States, and any
facility of any kind that is subject to the jurisdiction of the
United States and is located in, on, or under any other
waters. Section 112.11 applies to all offshore oil drilling,
production, or workover facilities.
§112.2
Onshore facility means any facility of any kind
located in, on, or under any land within the
United States, other than submerged lands.
Offshore facility means any facility of any kind
(other than a vessel or public vessel) located in,
on, or under any of the navigable waters of the
United States, and any facility of any kind that is
subject to the jurisdiction of the United States
and is located in, on, or under any other waters.
Note: The above text is an excerpt of the SPCC rule. Refer
to 40 CFR part 112 for the full text of the rule.
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Some facilities may be comprised of both onshore and offshore components. In these instances,
facilities may be considered "hybrid" facilities and subject to more than one set of requirements under either
Subpart B or C of the rule. For example, an oil production facility located along a coastline that has a tank
battery located onshore and associated wellheads and flowlines that are located offshore may be subject to the
requirements of §112.9 (for onshore oil production facilities) and §112.11 (for offshore oil drilling, workover and
production facilities).
2.4.3 Definition of Production Facility
A "production facility" is a type of "facility" as defined
in §112.2. A "production facility" includes all the structures
(including but not limited to wells, platforms, or storage
facilities), piping (including but not limited to flowlines or
intra-facility gathering lines), or equipment (including but not
limited to workover equipment, separation equipment, or
auxiliary non-transportation-related equipment) used in the
production, extraction, recovery, lifting, stabilization,
separation or treatment of oil (including condensate) and
associated storage or measurement and is located in an oil or
gas field, at a facility.
The definition of "production facility" in §112.2 is
narrower than the definition of facility and is used to
determine which sections of the rule may apply at a particular
facility. This definition governs whether such structures,
piping, or equipment are subject to §112.9 of the rule. That is,
if a facility meets the definition of a production facility, the owner or operator must comply with §112.9, or
§112.11 (depending on the characteristics of the facility). Additionally, the sections for administrative and
general rule requirements under 40 CFR part 112 apply as well (except for the security requirements under
§H2.7(g)).
The definition of "production facility" is consistent with the definition of "facility" in emphasizing
flexibility in how a facility owner or operator can determine facility boundaries.
§112.2
Production facility means all structures (including
but not limited to wells, platforms, or storage
facilities), piping (including but not limited to
flowlines or intra-facility gathering lines), or
equipment (including but not limited to workover
equipment, separation equipment, or auxiliary
non-transportation-related equipment) used in
the production, extraction, recovery, lifting,
stabilization, separation or treating of oil
(including condensate) and associated storage or
measurement and is located in an oil or gas field,
at a facility. This definition governs whether such
structures, piping, or equipment are subject to a
specific section of this part.
Note: The above text is an excerpt of the SPCC rule. Refer
to 40 CFR part 112 for the full text of the rule.
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ip - Production facility
A production facility for purposes of 40 CFR part 112 is one that is involved with producing or extracting petroleum
crude oil from a reservoir and not any other type of oil production, such as animal fat and vegetable oil (AFVO)
production.
The definition of production facility addresses petroleum crude oil production, extraction, recovery, lifting,
stabilization, separation or treatment and associated storage or measurement.
The definition also includes terms associated with petroleum crude oil production, such as gathering lines and
flowlines which are exclusively associated with upstream petroleum crude oil/gas production, not AFVO
production or processing facilities. The term "oil or gas field" is used exclusively in upstream crude oil and gas
production, not in AFVO production.
2.4.4 Drilling and Workover Facilities
Under the SPCC rule, the term "production facility" can encompass drilling and workover activities, as
well as oil production operations. However, different specific provisions of the rule apply to these different
activities. Drilling activities typically involve the initial establishment of an oil well: drilling the borehole,
inserting, running, and cementing the casing, and completing the well to start the flow of well fluids to the
surface. Workover operations involve maintenance or remedial work that may be necessary to improve
productivity during the life of the well. Workover operations may also include activities associated with the
initial well completion process. Both drilling and workover activities tend to be temporary in nature and are
performed using mobile rigs and associated equipment. Thus a drilling and/or workover facility is considered a
mobile facility. Mobile facilities may use a general Plan so that a new Plan need not be prepared each time the
mobile facility is moved to a new site. For example, it is not necessary to amend the Plan for a drilling rig every
time the operator moves the rig to drill a well in a field containing multiple wells (see 67 FR 47084, July 17,
2002). The same approach for mobile facilities applies to workover operations and activities.
For drilling and workover operations, the owner or operator is required to develop an SPCC Plan under
§112.3(c) because a drilling or workover facility is considered a mobile facility. The administrative and general
requirements of the SPCC rule (§§112.1 through 112.7), as well as the specific requirements in §112.10 (for
onshore facilities) or §112.11 (for offshore facilities) apply to the facility.
Once the well is completed and the well fluids are flowing, the completion (workover) and/or drilling rig
is removed from the site and production equipment, such as a pump or valve assembly, is set up to extract or
control the flow of oil from the well. At this point, drilling and or workover activities have ceased and production
has begun; the facility is considered an oil production facility. The processes performed at a typical oil
production facility include extraction, separation and treatment, storage, and transfer. The owner or operator of
an oil production facility is subject to the administrative and general requirements of the SPCC rule (§§112.1
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through 112.7) as well as the specific requirements in §112.9 (for onshore facilities) or §112.11 (for offshore
facilities). Typically, a gas plant is not considered an oil production facility.28
During the life of an oil well, maintenance or remedial work may be necessary to improve productivity. A
specialized workover rig, equipment, and associated containers are brought on-site to perform maintenance or
remedial activities. Workover activities are a distinct operation and may be conducted by a separate owner or
operator, therefore, a workover operation may be considered a separate mobile facility and be described in a
different SPCC Plan, separate from the oil production facility. Although production activities may temporarily
cease during workover, if the production equipment and containers (such as those found in a tank battery)
remain operable then the oil production facility owner/operator must maintain his own SPCC Plan during
workover activities.
2.4.5 Definition of Farm
EPA defines "farm" in the SPCC rule in part by
adapting the definition used by the National Agricultural
Statistics Service (NASS) in its Census of Agriculture. NASS
defines a farm as any place from which $1,000 or more of
agricultural products were produced and sold, or normally
would have been sold, during the census year. Operations
receiving $1,000 or more in Federal government payments
are counted as farms, even if they have no sales and
otherwise lack the potential to have $1,000 or more in sales.
§112.2
Farm means a facility on a tract of land devoted
to the production of crops or raising of animals,
including fish, which produced and sold, or
normally would have produced and sold, $1,000
or more of agricultural products during a year.
Note: The above text is an excerpt of the SPCC rule. Refer
to 40 CFR part 112 for the full text of the rule.
EPA also considered the "farm tank" definition under
the Underground Storage Tank (UST) regulations at 40 CFR part 280. As defined in 40 CFR 280.12, a farm tank is
a tank located on a tract of land devoted to the production of crops or raising of animals, including fish.
The term "farm" includes fish hatcheries, rangeland, and nurseries with growing operations, but does
not include laboratories where animals are raised, land used to grow timber, and pesticide aviation operations.
This term also does not include retail stores or garden centers where the product of nursery farms is marketed,
but not produced, nor does the Agency interpret the term "farm" to include golf courses or other places
dedicated primarily to recreational, aesthetic, or other nonagricultural activities. Additionally, the definition of
farm does not include agribusinesses because these businesses, e.g., oil marketing and distribution to farmers,
are distinctly different from farms.
The definition of "farm" is narrower than the definition of "facility" and was originally promulgated to
identify a subset of SPCC facilities subject to a compliance date extension. The definition of "facility" governs the
overall applicability of 40 CFR part 112, and thus is used to determine whether the owner or operator (e.g., a
EPA addressed this issue in a letter from R. Craig Matthiessen, Office of Emergency Management, to Roger Claff of the
American Petroleum Institute (2010). See Appendix H.
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farmer) is subject to the SPCC and/or FRP requirements of the rule and to determine the scope of his or her
facility.
2.4.6 Examples of Aggregation or Separation
The following factors to determine the boundaries of a facility are not exclusive and simply serve as
examples:
• Ownership, management, and operation of the buildings, structures, equipment, installations,
pipes, or pipelines on the site;
• Similarity in functions, operational characteristics, and types of activities occurring at the site;
• Adjacency; or
• Shared drainage pathways (e.g., same receiving water bodies)
A lease may, at the owner or operator's discretion, constitute a facility, but does not necessarily create a
facility. According to the definition of facility, contiguous or noncontiguous buildings, properties, leases,
structures, installations, pipes, or pipelines under the ownership or operation of the same person may be
considered separate facilities. A facility may also consist of parcels that are smaller or larger than an individual
lease.
A facility may or may not be subject to the SPCC and FRP rule requirements depending on how the
facility owner or operator aggregates buildings, structures or equipment and associated storage or type of
activity. However, once the owner/operator determines the facility boundaries for SPCC applicability, then the
same boundaries apply for determining applicability of the FRP rule requirements. An owner or operator may
not characterize a facility so as to simply avoid applicability of the rule (for example, defining separate facilities
around oil storage containers that are located side-by-side or within close proximity, and are used for the same
purpose).
Following are six example scenarios of how a facility owner or operator may determine what is
considered a "facility" for the purposes of an SPCC Plan. Each of these scenarios is hypothetical and is not
intended to provide a policy interpretation for any specific existing facility.
• Scenario A. Separation of Tracts at a Farm
• Scenario B. Separation of Leases at an Oil Production Facility
• Scenario C. Aggregation of Equipment at an Oil Production Facility
• Scenario D. Separation of Areas at a Military Base (or Other Large Facility)
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• Scenario E. Separation of Functions at a Dual-Purpose Facility
• Scenario F. Separation of Equipment on Private Property
Scenario A. Separation of Tracts at a Farm
A farmer has one central fueling location and ten separate (either contiguous or non-contiguous) tracts
of land (inclusive of owned and leased tracts) where various types of crops are grown. The central fueling
location has several oil containers, with an aggregate storage capacity of 5,000 U.S. gallons of diesel fuel,
gasoline, and hydraulic/lubrication oils. Each tract has one 1,000-gallon aboveground container of diesel fuel,
used for fueling only the equipment operated on the tract. The tracts are located such that the containers are
each several miles from each other. Each tract produces various types of crops, and thus the equipment is
operated seasonally according to crop type and irrigation needs.
Figure 2-1: Separation of tracts at a farm.
1000 gal.
Diesel
Fuel
Aggregate
capacity of
• 5,000 gal.
1000 gal.
Diesel
Fuel
15 Miles
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Determination: Given the distance between containers, and the clear distinction between the
operations that they support, each tract and the central fueling location can be considered a separate facility for
the purposes of calculating oil storage capacity and determining the applicability of the SPCC rule. The fact that
the tracts may be contiguous would be only one factor in the facility determination, and may allow the
designation of the separate contiguous tracts as separate facilities, given the great distance and operational
differences. In this example, each tract does not individually meet the aboveground storage capacity threshold
for applicability of the SPCC rule (1,320 U.S. gallons). Therefore, no SPCC Plan is required for these containers.
However, the central fueling location exceeds the SPCC rule aboveground storage capacity threshold. Assuming
the farm is located such that a discharge of oil could reasonably pose a threat to navigable waters or adjoining
shorelines, the farmer must prepare and implement an SPCC Plan for the central fueling area.
Under Section 311 of the Clean Water Act, the farmer, as an owner or operator of each facility, may still
be liable for response costs and damages associated with any harmful quantities of oil discharged from the
containers on the separate tracts into navigable waters or adjoining shorelines, even if an SPCC Plan is not
required for these separate facilities.29
Alternative: To provide general protection and prevention measures against an oil discharge, the farmer
may instead choose to include the ten diesel containers on the separate tracts in his Plan. The farmer may also
choose to aggregate individual tracts of land that share similarities in operation and prepare SPCC Plans for
those separate facilities. For example, combine the tracts of land that are used to grow the same crop and
develop an SPCC Plan for each distinct facility.
Scenario B. Separation of Leases at an Oil Production Facility
An oil production facility operator leases the right to extract oil from three parcels of land separated by
large distances within one oil production field. The parcels may be contiguous or non-contiguous. Each of the
parcels (or lease) is subject to a distinct lease agreement, consistent with all applicable state and local oil and
gas laws and regulations. Each lease contains a tank battery storing more than 1,320 U.S. gallons of oil and one
or more wellheads. Well fluids are separated and oil is stored in containers at each tank battery. Gathering lines
from each tank battery flow to a central collection area that serves as a gathering station30 and is managed by
the same operator.
29
The owner/operator may also be subject to liability under OPA and other statutes or regulations.
This gathering station may also include an injection point to a transportation-related pipeline.
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Figure 2-2: Separation of parcels at an oil production facility.
Aggregate (
capacity of •
tank battery I
> 1,320 gal.
Aggregate
capacity of
tank battery
> 1,320 gal.
Aggregate .
capacity of \
tank battery •
> 1,320 gal. I
Central collection area
10 Miles
Determination: Given their geographic separation and the nature of the individual lease agreements,
each lease could be considered a separate facility. Each tank battery stores a total aboveground capacity of oil
greater than 1,320 U.S. gallons, so under such a scenario the operator must prepare and implement a separate
SPCC Plan for each tank battery and its associated wellheads, flowlines, and equipment, as individual facilities.
Any gathering lines that transport oil from these individual facilities into a centralized collection area involve the
transportation of oil between facilities ("inter-facility") and are therefore not within EPA jurisdiction. These
"inter-facility" gathering lines do not need to be included in the SPCC Plans. In this example, the central
collection area is a separate facility and may be subject to SPCC requirements. If the central collection area
facility meets the SPCC rule applicability criteria, then a separate SPCC Plan must be developed.
Alternative: Because the definition of facility is flexible, the operator could alternatively choose to
consider all three parcels and the central collection area as one facility, based on his common ownership or
operation of all of them. Under this approach, the operator would only need to prepare one SPCC Plan that
covers the components of all parcels. Any gathering lines connecting the tank batteries of each parcel are then
considered "intra-facility" gathering lines and must be included in the SPCC Plan.31 It is also important to note
Except when the intra-facility gathering lines are subject to the regulatory requirements of 49 CFR part 192 or 195. In that case,
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that if an owner/operator aggregates oil storage so as to develop one SPCC Plan, he must then determine the
facility boundaries the same way for the purposes of determining the applicability of the FRP rule requirements.
Also note that an oil production facility may consist of parcels that are smaller or larger than an individual lease.
Scenario C. Aggregation of Equipment at an Oil Production Facility
An oil production facility owner operates one wellhead. Oil is treated in a 10-barrel (bbl) capacity
heater-treater to separate the oil from produced water; the treated oil is then stored in several stock tanks that
separately or combined would be subject to SPCC requirements until it is sold and transported off-site. The
heater-treater separation equipment is located several feet away from the stock tanks, which hold both the oil
and produced water.
These two areas may be physically separate and are protected by separate secondary containment
berms, but the heater-treater is an integral component of an oil production facility, connected by piping, and
under the control of the same operator. The heater-treater is a component of a larger process that would be
incomplete without the ability to separate oil and produced water. Thus, all of these components should be
aggregated together to comprise the oil production facility. In this circumstance, the heater-treater should not
be considered a separate facility.
Similarly, an owner/operator could not separate a wellhead from the associated flowline or tank battery
to call them distinct facilities. For example, an oil production facility owner operates one wellhead connected to
the tank battery by a mile-long flowline. Despite the length of the flowline, the facility operator may not have a
reasonable basis for separating the wellhead, flowline, and tank battery as distinct facilities with individual SPCC
Plans. Similar to the heater-treater, the wellhead and tank battery are considered integral components of the
larger process, and an oil production facility would be incomplete without including these two components. The
flowline, whether several feet or several miles in length, is a necessary connection between the wellhead and
tank battery, and all of these components must be included in one SPCC Plan.
the intra-facility gathering lines are exempt from the SPCC rule; however, the location of the exempt intra-facility gathering
lines must be identified and marked as "exempt" on the facility diagram.
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Figure 2-3: Aggregation of equipment at an oil production facility.
lObbl
heater
treaterj
Wellhead
Hi
**-,
0
Secondary
containment
berm
Stock tanks of crude oil/produced water ,
Figure 2-4: Mile-long flowline at an oil production facility.
fYY
•v A A ;
YY
vv_A_A-y
N
)
it\
JL
WeHheod
Determination: An SPCC Plan must include all of the components that together comprise a typical oil
production facility. There may be no reasonable basis to determine that either of the facilities in these examples
could be divided into separate, smaller facilities. While a facility owner or operator has some discretion in
describing the parameters of his facility, he may not describe the boundaries of a facility unreasonably in an
attempt to avoid regulation. The processes performed at a typical oil production facility include extraction,
separation and treatment, storage, and transfer.
Scenario D. Separation of Areas at a Military Base (or Other Large Facility)
A military base is spread out over 10 square miles. Within the base, there are several areas where oil
containers are located: a tank farm associated with an aircraft fueling area, back-up fuel oil for a small power
generation plant, and a mess hall with several drums of cooking oil. Because different groups service, manage,
or maintain the various tank farms and oil storage areas, these operators have agreed to calculate the aggregate
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storage capacity of each of their operations separately to determine their SPCC rule applicability. The operations
vary across these oil container locations, each with unique or specific characteristics.
Figure 2-5: Separation of areas at a military base (or other large facility).
Aircraft fueling area
1,000 gal. each
Back-up fuel oil
Power
Generation
Plant
Mess Hall
oqpo
Cooking oil containers
55 gal. each
10 Miles
Determination: In this example, different groups service, manage, or maintain the various tank farms
and oil storage areas. The operations vary across these oil container locations, each with unique or specific
characteristics; therefore, the operators can choose to calculate the aggregate storage capacity of each of their
operations separately to determine SPCC rule applicability.
Alternative: However, the operators may also determine that it would be more efficient to prepare one
SPCC Plan for the entire base. This determination would also be appropriate.
The same principles apply at other large facilities such as universities or airports. While a facility owner
or operator has some discretion in describing the parameters of his facility, he may not unreasonably describe
the boundaries of a facility to avoid regulation.
Regardless of how the facility boundaries are defined, heating oil containers associated with single-
family residences within a military base (or other large-footprint facility) are exempt from the SPCC rule.
Scenario E. Separation of Functions at a Dual-Purpose Facility
The owner of a truck maintenance company operates his business from a site that also includes his
single-family residence. The business office is located in his residence. The entire building is heated with one
500-gallon heating oil container. In an adjacent garage, he has one 500-gallon gasoline container, one 250-gallon
waste oil container, and five 55-gallon drums of various automotive lubricants.
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Figure 2-6: Separation of functions at a dual-purpose facility.
Truck Maintenance
Single family
residence and
business office
55 gal. drums of
automotive
lubricants
.25 Mile
Determination: In considering whether the facility is subject to the SPCC rule, this business owner can
conclude that the heating oil container is exempt from the rule because it is associated with his home, and the
function of heating his home is necessary regardless of the presence of his business operations. Because the
total storage capacity of the remaining containers does not meet the aboveground storage capacity threshold
for applicability of the SPCC rule (1,320 U.S. gallons), the owner is not subject to the SPCC rule.
v* Tip - Containers owned or operated by someone else
One commonly asked question is how an owner/operator should address a container located at the facility that is
owned or operated by someone else.
The owner or operator of a facility that includes a container being used by another person that is not under his or her
operational control should coordinate with that person to determine who will prevent spills from that container.
For example, transformers, or other energized electrical equipment, that are located on an easement and are under
the operational control of the local electrical utility may be addressed separately by the utility. The owner/operator of
the facility would typically not be required to include these containers in the SPCC Plan or on the facility diagram. The
owner/operator should coordinate with the electric utility on how to address spill prevention procedures for this
equipment.
This determination by the plan holder must be based on site-specific factors.
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Scenario F. Separation of Equipment on Private Property
The owner of a vehicle repair shop maintains one 500-gallon gasoline container, one 250-gallon waste
oil container, ten 55-gallon drums of various automotive lubricants, and one 500-gallon completely buried
heating oil container for use at the facility. The local utility company has also sited a transformer, with a capacity
to hold 55 U.S. gallons of transformer oil, on the repair shop property.
Figure 2-7: Separation of equipment on private property.
Vehicle Repair Shop
Transformer sited
by local utility
company
55 gat drums of
automotive
lubricants
500 gal. ~
\_ heating oil.
.25 Mile
Determination: In calculating total facility oil storage capacity, the property owner is not required to
consider the volume of the transformer because it is owned and operated by another entity, and the
transformer may be covered under the utility company's Plan. However, because it is located on the repair shop
property, the facility owner/operator should coordinate with the utility company on how to address oil
discharges from the transformer. Under Section 311 of the Clean Water Act, the repair shop owner/operator, in
addition to the transformer owner/operator, may be liable for any harmful quantities of oil discharged from the
transformer when it is located on his property.
The total aboveground oil storage capacity of the repair shop is less than 1,320 U.S. gallons when the
transformer is not included in the calculation. The heating oil container counts separately toward the facility's
completely buried storage capacity because it is not used "solely at a single-family residence." However, the
facility aggregate completely buried capacity is less than the 42,000 gallons threshold. Therefore, the facility is
not subject to the SPCC rule.
2.4.7 Natural Gas Production/Treatment Facilities and Pipelines
As described in Section 2.2.5 above, EPA does not regulate natural gas under the SPCC rule. However,
natural gas condensate is considered an oil and is regulated under the SPCC rule. For the purposes of
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determining SPCC applicability, containers with 55 gallons or more in capacity storing condensate must be
included in a natural gas facility's total oil storage capacity calculation. Ancillary oil storage in other areas of the
facility, such as fuel or lubrication oil, and oil-filled equipment, is also counted. Natural gas production or
treatment facilities and pipeline systems commonly have associated oil storage, including oil-containing
equipment such as compressors, drip tanks, and separators that may store motor oil, lubricants, crude oil
impurities removed from the gas stream, and liquid condensate. Equipment that compresses or pumps the
natural gas is not regulated unless there is oil-filled operational equipment associated with it that meets the
applicability requirements of the rule.
The definition of "production facility" in §112.2 specifies that an oil production facility involves the
"...production, extraction, recovery, lifting, stabilization, separation or treating of oil." (emphasis added.)
Therefore, any natural gas treatment facility that does not produce oil or condensate is not regulated as a
production facility under the SPCC requirements, but may be regulated as a bulk oil storage facility because of
aboveground ancillary oil storage, including oil-filled equipment. For the following scenarios, the general and
administrative provisions of the rule (§§112.1 through 112.7) apply, as well as the more specific requirements
described.
Following are five example scenarios of facilities that are involved in producing or treating natural gas
and how the SPCC rule would apply for each. Each of these scenarios is hypothetical and is not intended to
provide a policy interpretation for any specific existing facility.
• Scenario A Oil and Gas Production Facility
• Scenario B "Wet Gas" Production Facility
• Scenario C "Dry Gas" Production Facility
• Scenario D Gas Processing/Treatment Facility/Plant
• Scenario E Facility Supporting a Gas Pipeline
Scenario A Oil and Gas Production Facility
The wellhead at this type of facility produces a mixture of oil, gas, and produced water. Because this
facility produces oil from the wellhead, it is considered an oil production facility according to the SPCC rule and
must comply with the requirements at §112.9.
Oil production facilities can include piping with both oil and gas phases. In this instance, such a facility's
dual-phase flowlines and intra-facility gathering lines (i.e., those carrying both gas and liquid phase hydrocarbon)
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are subject to the SPCC requirements32 because if the lines were to rupture or leak, they may discharge oil to
navigable waters or adjoining shorelines in quantities that may be harmful as defined in 40 CFR part 110.
Scenario B "Wet Gas" Production Facility
The wellhead at this type of facility produces a mixture of gas, produced water, and condensate.
Condensate that is liquid at atmospheric pressures and temperatures is considered an oil, and the facility could
be subject to the SPCC rule if it meets the SPCC rule applicability criteria. Because the facility produces oil, this
facility is considered an oil production facility and must comply with the requirements at §112.9 if subject to the
SPCC rule. The presence of any gas treatment at the facility prior to the point of custody transfer (e.g., meter)
into a gas pipeline would not affect the determination that this facility is an oil production facility.
Scenario C
"Dry Gas" Production Facility
The wellhead at this facility produces a mixture of gas and produced water only. A dry gas production
facility that produces natural gas from a well (or wells) but does not also produce condensate or crude oil that
can be drawn off the tanks, containers, or other production equipment at the facility is not subject to the SPCC
rule. EPA has clarified that a dry gas production facility does not meet the description of an "oil production, oil
recovery, or oil recycling facility." Therefore, a dry gas facility may be eligible for the wastewater treatment
exemption under §112.1(d)(6).33 See the excerpt "Notice concerning certain issues pertaining to the July 2002
Spill Prevention, Control, and Countermeasure (SPCC) rule" below.
However, if the aboveground ancillary storage of oil at a dry gas production facility is greater than 1,320
U.S. gallons, and the facility otherwise meets the applicability of the rule, the facility is regulated under the SPCC
rule and must comply with the requirements for onshore facilities at §112.8. Because the well does not produce
recoverable oil or condensate, the facility does not meet the definition for an oil production facility under the
SPCC rule.
Intra-facility gathering lines subject to DOT regulation under 49 CFR parts 192 or 195 are exempt from SPCC rule requirements
"Notice Concerning Certain Issues Pertaining to the July 2002 Spill Prevention, Control, and Countermeasure (SPCC) Rule," 69 FR
29728, May 25, 2004.
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Notice concerning certain issues pertaining to the July 2002 Spill Prevention, Control, and Countermeasure
(SPCC) rule
The Agency has been asked whether produced water tanks at dry gas facilities are eligible for the SPCC rule's wastewater
treatment exemption at 40 CFR 112.7(d)(6). A dry gas production facility is a facility that produces natural gas from a well
(or wells) from which it does not also produce condensate or crude oil that can be drawn off the tanks, containers or
other production equipment at the facility.
The SPCC rule's wastewater treatment exemption excludes from 40 CFR part 112 "any facility or part thereof used
exclusively for wastewater treatment and not used to satisfy any requirement of this part." However, for the purposes of
the exemption, the "production, recovery, or recycling of oil is not wastewater treatment." In interpreting this provision,
the preamble to the final rule states that the Agency does "not consider wastewater treatment facilities or parts thereof
at an oil production, oil recovery, or oil recycling facility to be wastewater treatment for purposes of this paragraph."
It is our view that a dry gas production facility (as described above) would not be excluded from the wastewater
treatment exemption based on the view that it constitutes an "oil production, oil recovery, or oil recycling facility." As
discussed in the preamble to the July 2002 rulemaking, "the goal of an oil production, oil recovery, or oil recycling facility
is to maximize the production or recovery of oil. * * *" 67 FR 47068. A dry gas facility does not meet this description.
(See 69 FR 29729, 29730, May 25, 2004.)
Scenario D Gas Processing/Treatment Facility/Plant
This type of facility receives gas after it is separated from oil and produced water. The gas typically
contains condensate, which is removed from the gas stream at this facility. Petroleum distillate that is produced
by natural gas wells and stored at atmospheric pressures and temperatures is considered an oil. If the total
aboveground storage capacity for condensate tanks and all other ancillary oil storage is greater than 1,320
gallons, and the facility otherwise meets the applicability of the rule, then this facility is considered a bulk
storage facility subject to the requirements under §112.8. EPA has addressed this issue in a letter34 to API, dated
December 10, 2010, that details the Agency's position on how SPCC requirements apply to gas
plants/compression stations.
However, when gas plant or compression activities are co-located at an SPCC-regulated oil production
facility with a tank battery, then the containers associated with gas separation that store or process oil (i.e.,
separation vessels containing oil/ liquid condensate) are typically considered part of the oil production facility
operations and therefore subject to the onshore oil production facility requirements under 40 CFR part 112.9 (or
§112.11 for offshore facilities).
Scenario E Facility Supporting a Gas Pipeline
At a facility supporting a gas pipeline, EPA regulates compressors or equipment containing oil (including
condensate when it turns into liquid at atmospheric temperatures and pressures), but not gas-filled portions of
See Appendix H for the letter from R. Craig Matthiessen, Office of Emergency Management, to Roger Claff of the American
Petroleum Institute (2010).
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equipment. If the aboveground oil storage capacity is greater than 1,320 gallons, and the facility otherwise
meets the applicability of the rule, the facility is considered a bulk storage facility under the SPCC rule subject to
the requirements under §112.8.
2.5 "Non-Transportation Related" - EPA/DOT Jurisdiction
Facilities regulated under 40 CFR part 112 are divided into three categories: transportation-related
facilities, non-transportation-related facilities, and complexes. The delineation between transportation-related
and non-transportation-related facilities has been established through a series of Executive Orders (EOs) and
Memoranda of Understanding (MOUs) as described below. Onshore and certain offshore non-transportation-
related facilities (and portions of a complex) are subject to the SPCC regulation, provided they meet the other
applicability criteria set forth in §112.1.
A 1971 MOD between EPA and DOT clarifies the types of facilities, activities, equipment, and vessels
that are meant by the terms "transportation-related onshore and offshore facilities" and "non-transportation-
related onshore and offshore facilities." DOT delegated authority over vessels and transportation-related
onshore and offshore facilities to the Commandant of the U.S. Coast Guard.35 Sections of the MOU between EPA
and DOT are included in Appendix A of 40 CFR part 112. Section 112.1(d)(l)(ii) specifically exempts from SPCC
applicability any equipment, vessels, or facilities subject to the authority and control of the DOT as defined in
this MOU.
A 1994 MOU among the Secretary of the Interior, the Secretary of Transportation, and the Administrator
of EPA establishes the jurisdictional responsibilities for offshore facilities, including pipelines. This MOU can be
found in Appendix B of 40 CFR part 112. Section 112.1(d)(l)(iii) specifically exempts from SPCC applicability any
equipment, vessels, or facilities subject to the authority of
the DOT or DOI as defined in this MOU.
Table 2-2 provides examples of transportation-
related and non-transportation-related facilities as the
concepts apply to the SPCC rule applicability. Some
equipment, such as loading arms and transfer hoses, may be
considered either transportation-related or non-
transportation-related depending on their use.
§112.2
Complex means a facility possessing a
combination of transportation-related and non-
transportation-related components that is
subject to the jurisdiction of more than one
Federal agency under section 311(j) of the CWA.
Note: The above text is an excerpt of the SPCC rule. Refer
to 40 CFR part 112 for the full text of the rule.
The USCG was reorganized under the Department of Homeland Security in March 2003.
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Table 2-2: Examples of transportation-related and non-transportation-related facilities from the 1971 DOT-
ERA MOU.
Transportation-related Facilities
(DOT Jurisdiction)
Non-Transportation-related Facilities
(EPA Jurisdiction)
- Onshore and offshore terminal facilities, including
transfer hoses, loading arms, and other equipment used
to transfer oil in bulk to or from a vessel, including
storage tanks and appurtenances for the reception of
oily ballast water or tank washings from vessels
Transfer hoses, loading arms, and other equipment
appurtenant to a non-transportation-related facility used
to transfer oil in bulk to or from a vessel
- Interstate and intrastate onshore and offshore pipeline
systems
- Highway vehicles and railroad cars that are used for the
transport of oil
Equipment used for the fueling of locomotive units, as
well as the rights-of-way on which they operate.
Fixed or mobile onshore and offshore oil drilling and oil
production facilities
Oil refining and storage facilities
Industrial, commercial, agricultural, and public facilities
that use and store oil
Waste oil treatment facilities
Loading racks, transfer hoses, loading arms, and other
equipment used to transfer oil in bulk to or from
highway vehicles or railroad cars
Highway vehicles, railroad cars, and pipelines used to
transport oil exclusively within the confines of non-
transportation-related facility
A facility with both transportation-related and non-transportation-related activities is a "complex" and is
subject to the dual jurisdiction of EPA and DOT or LJSCG. The jurisdiction over a component of a complex is
determined by the activity occurring at that component. An activity might at one time subject a facility to one
agency's jurisdiction, and a different activity at the same facility using the same structure or equipment might
subject the facility to the jurisdiction of another agency. The 1971 DOT-EPA MOU defines the activities that are
subject to either EPA or DOT jurisdiction. Appendix H includes drawings that show EPA's regulatory jurisdiction
at complexes.36
The sections below describe common scenarios that have raised jurisdictional questions regarding the
distinction between transportation-related and non-transportation-related containers or facilities for
applicability of SPCC requirements. EPA inspectors should evaluate the intended activity carefully because the
determination of jurisdiction is not always straightforward.
See EPA Jurisdiction at Complexes in Appendix H.
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^ FYI - EPA/DOT jurisdiction
Equipment, operations, and facilities are subject to DOT jurisdiction when they are engaged in activities subject to DOT
jurisdiction. If those same facilities are also engaged in activities subject to EPA jurisdiction (such facilities are
considered a "complex"), such activities would subject the equipment, operation, or facility to EPA jurisdiction, as well.
During the development of the FRP rule, EPA and other federal agencies with jurisdiction under the Oil Pollution Act
(OPA) and Executive Order 12777 (including DOT) met to create an implementation strategy that minimized duplication,
wherever practicable and recognized State oil pollution prevention and response programs. One of the critical
outgrowths of these efforts was the development of a definition for, and a consistent approach to regulate
"complexes."
The jurisdiction over a component of a complex is determined by the activity involving that component. An activity at
one time might subject a facility to one agency's jurisdiction, while a different activity at the same facility using the
same structure, container or equipment might subject the facility to the jurisdiction of another agency.
(see 74 FR 58804, November 13, 2009)
2.5.1 Tank Trucks
EPA regulates tank trucks (or mobile refuelers) as "mobile/portable containers" under the SPCC rule if
they operate exclusively within the confines of a non-transportation-related facility. For example, a tank truck
that moves within the confines of a facility and only leaves the facility to obtain more fuel (oil) would be
considered to distribute fuel exclusively at one facility. This tank truck would be subject to the SPCC rule if it, or
the facility, contained above the regulatory threshold amount (see Section 2.7) and there was a reasonable
expectation of discharge to navigable waters or adjoining shorelines. Similarly, a mobile refueler that fuels
exclusively at one site, such as at an airport or construction site, would be subject to the SPCC rule. However, if
the tank truck only distributed fuel to multiple off-site facilities and did not perform fueling activities at the
home base, the tank truck would be transportation-related, and regulated by DOT. Additionally, EPA regulates
containers which were formerly used for transportation, such as a truck or railroad car, and are now used to
store oil (i.e., no longer used for a transportation purpose) as a bulk storage container (see 67 FR 47075, July 17,
2002).
Tank trucks that are used in interstate or intrastate commerce can also be regulated if they are
operating in a fixed, non-transportation mode. For example, if a home heating oil truck makes its deliveries,
returns to the facility, and parks overnight with a partly filled fuel tank, it is subject to the SPCC rule if it, or the
facility has a capacity above the threshold amount (see Section 2.7), and there is a reasonable expectation of
discharge to navigable waters or adjoining shorelines.37 However, if the home heating oil truck's fuel tank
contains no oil when it is parked at the facility, other than any residual oil present in an emptied vehicle, it
would be regulated only by DOT.38 For more information on the secondary containment requirements for
In this case, the facility would include the truck storage capacity in its aggregate capacity determination in order to determine
whether it is above the 1,320 gallon aboveground threshold for SPCC applicability.
EPA addressed this scenario in a letter from Stephen Heare, Office of Emergency and Remedial Response, to Melissa Young of
Petroleum Marketers Association of America (2001). See Appendix H.
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mobile refuelers and other non-transportation-related tank trucks, refer to Chapter 4: Secondary Containment
and Impracticability.
2.5.2 Railroad Cars
DOT regulates railroad cars used for the transport of oil in interstate or intrastate commerce and the
related equipment and appurtenances. DOT jurisdiction includes railroad cars that are passing through a facility
or are temporarily stopped on a normal route. EPA regulates railroad cars under the SPCC rule if they are
operating exclusively within the confines of a non-transportation-related facility. EPA regulates both transfers to
or from railroad cars and when the railroad cars serve as non-transportation-related storage at an SPCC-
regulated facility.
When the railcar is serving as non-transportation-related storage, if the railroad car has a storage
capacity above the regulatory threshold amount of oil, and there is a reasonable expectation of discharge to
navigable waters or adjoining shorelines, the railroad car itself may become a non-transportation-related
facility, even if no other containers at the property would qualify it as an SPCC-regulated facility.39
2.5.3 Loading/Unloading Activities
DOT regulates equipment used for the fueling of locomotive units, as well as the rights-of-way on which
they operate. EPA regulates the activity of loading or unloading oil in bulk into storage containers (such as those
on tank trucks or railroad cars), as well as all equipment involved in this activity (e.g., a hose or loading arm
attached to a storage tank system). Different requirements apply to oil transfer areas and to loading/unloading
racks at a regulated facility. A transfer area is any area of a facility where oil is transferred between bulk storage
containers and tank trucks or railroad cars. These areas are subject to the general secondary containment
requirements in §112.7(c). If a "loading/unloading rack" (as defined in §112.2) is present, the requirements of
§112.7(h) apply to the loading/unloading rack area. For more information, refer to Chapter 4: Secondary
Containment and Impracticability which discusses secondary containment requirements for loading/unloading
areas and racks.
2.5.4 Marine Terminals
A marine terminal is an example of a "complex" subject to both U.S. Coast Guard (USCG) and EPA
jurisdiction. The jurisdictional boundary of a complex facility for both USCG and EPA is defined in 33 CFR part
154, Facilities Transferring Oil or Hazardous Material in Bulk under the definition of a marine transportation-
related facility (MTR facility) in §154.1020.The USCG regulates the pier structures, transfer hoses, hose-piping
connection, containment, controls, and transfer piping associated with the transfer of oil between a vessel and
an onshore facility. EPA regulates the tanks, internal piping, loading racks, and vehicle/rail operations that are
completely within the non-transportation portion of the facility. EPA jurisdiction begins at the first valve inside
secondary containment. If there is no secondary containment, EPA jurisdiction begins at the valve or manifold
EPA addressed the applicability of the SPCC rule to railroad cars by addressing specific scenarios in a letter to the Safety-Kleen
Corporation in July 2000. See Appendix H.
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adjacent to the storage tank. Appendix H includes drawings that show EPA's regulatory jurisdiction at
complexes, including an example of a marine terminal.40
2.5.5 Vessels (Ships/Barges)
The U.S. Coast Guard regulates the loading or unloading of oil in bulk from a vessel to an onshore
facility, as well as the oil-carrying vessel and the connecting piping (33 CFR part 155, Oil or Hazardous Material
Pollution Prevention Regulations for Vessels). In this scenario, a vessel is a ship or a barge. The oil passes from
the USCG's jurisdiction to that of the EPA when it passes the first valve inside the secondary containment for the
storage container at an otherwise regulated facility. If there is no secondary containment, EPA's jurisdiction
begins at the first valve or manifold closest to the storage container. Storage tanks and appurtenances for the
reception of oily ballast water or tank washings from vessels are under USCG jurisdiction.
Vessels themselves are specifically exempt from 40 CFR part 112 under §112.1(d)(l)(iii). EPA also
clarified that barges or other watercraft that store oil, and have been determined by the Coast Guard to be
permanently moored, are no longer vessels, but storage containers that are part of an offshore facility (67 FR
47075, July 17, 2002).
2.5.6 Breakout Tanks
Although breakout tanks can be used to relieve surges in an oil pipeline system or to receive and store
oil transported by a pipeline for reinjection and continued transportation by pipeline, they are sometimes used
for bulk storage (i.e., non-transportation-related storage). Thus, breakout tanks may be regulated by EPA, DOT,
or both depending on how the tank is used. Breakout tanks used solely to relieve surges in a pipeline, not used
for any non-transportation-related activity (i.e., pipeline-in and pipeline-out configuration, and with no transfer
to other equipment/mode of transportation such as a tank truck), are not subject to EPA jurisdiction. Bulk
storage containers used to store oil while also serving as a breakout tank for a pipeline or other transportation-
related purposes may be subject to both EPA and DOT jurisdiction.41 Determining agency jurisdiction can be
difficult and should be treated on a case-by-case basis. However, additional information can be found in
Appendix H which includes drawings that show EPA's regulatory jurisdiction at complexes.42
40
41
42
See EPA Jurisdiction at Complexes.
See the 1971 MOU between DOT and EPA (Appendix A of 40 CFR part 112).
See EPA Jurisdiction at Complexes for specific examples.
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§112.2
Motive power container means any onboard bulk
storage container used primarily to power the
movement of a motor vehicle, or ancillary
onboard oil-filled operational equipment. An
onboard bulk storage container which is used to
store or transfer oil for further distribution is not
a motive power container. The definition of
motive power container does not include oil
drilling or workover equipment, including rigs.
Note: The above text is an excerpt of the SPCC rule. Refer
to 40 CFR part 112 for the full text of the rule.
2.5.7 Motive Power
Motive power containers are located in or on a
motor vehicle and serve as an onboard bulk storage
container used primarily to power the movement of a motor
vehicle or ancillary onboard oil-filled operational equipment.
Motive power containers on vehicles used solely at non-
transportation-related facilities fall under EPA jurisdiction
but are exempt from the SPCC rule. See Section 2.8.6 for
more information.
2.5.8 Flowlines and Gathering Lines
Any pipeline or piping that transports oil between facilities or from a facility to a vessel is considered
transportation-related, and is therefore outside the jurisdiction of EPA and not subject to the SPCC rule. EPA
recognizes that gathering lines are often outside of the Agency's jurisdiction because they transport oil outside
of an oil production facility.
However, EPA has jurisdiction over non-transportation-related facilities, including pipelines that
transport oil within a facility. The definition of "facility" as it applies to the SPCC rule is flexible; depending upon
how an owner/operator defines his facility, an oil production facility may also include gathering lines. A typical
oil production facility includes a wellhead, a tank battery (including, but not limited to, separation equipment,
stock oil containers and produced water containers), and the flowlines that transfer the oil and well fluids from
the wellhead to the tank battery. A flowline may also connect a tank battery to an injection well. If multiple tank
batteries are included as part of the same facility for purposes of developing one SPCC Plan, then any gathering
lines that connect the tank batteries, or flow to a central collection or gathering area or centralized tank battery
within the facility boundaries, must also be included in the SPCC Plan. EPA considers any gathering lines within
the boundaries of a facility to be "intra-facility gathering lines" and within EPA's jurisdiction for the purposes of
SPCC rule applicability (72 FR 58406 to 58407, October 15, 2007). Appendix H includes drawings that show EPA's
regulatory jurisdiction at complexes, including an example of an oil production facility with gathering lines.43
The exemption of certain intra-facility gathering lines from SPCC rule requirements is discussed in
Section 2.8.10.
See EPA Jurisdiction at Complexes.
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v** FYI - Flowlines and gathering lines
Flowlines are the piping that transfer crude oil and well fluids from the wellhead to the tank battery where separation
and treatment equipment are typically located. A flowline may also connect a tank battery to an injection well.
Flowlines are relatively small diameter steel or fiberglass piping (generally less than four inches). Depending on the size
of the oil field, flowlines may run for hundreds of feet to a tank battery.
Gathering lines are the piping or pipelines that transfer the crude oil product between tank batteries, within or between
facilities. Gathering lines often originate from an oil production facility's lease automatic custody transfer (LACT) unit,
which transfers oil to other facilities involved in gathering, refining or pipeline transportation operations.
2.6 Reasonable Expectation of Discharge to Navigable Waters in Quantities
That May Be Harmful
2.6.1 Definition of "Discharge" and "Discharge as Described in §112.l(b)"
According to §112.l(b), the SPCC rule applies to certain facilities that could "reasonably be expected to
discharge oil in quantities that may be harmful, as described in part 110 of this chapter..." The Discharge of Oil
regulation at 40 CFR part 110 (also referred to as the "sheen rule") defines a discharge of oil into or upon the
navigable waters of the United States or adjoining shorelines in quantities that may be harmful under the CWA
as that which:
• Causes a sheen or discoloration on the surface of the water or adjoining shorelines;
• Causes a sludge or emulsion to be deposited beneath the surface of the water or upon adjoining
shorelines; or
• Violates an applicable water quality standard.44
A discharge meeting any of the above criteria triggers requirements to report to the National Response
Center (NRC). The failure to report such a discharge may result in criminal sanctions under the CWA. The
appearance of a "sheen" on the surface of the water is often used as a simple way to identify harmful
discharges of oil that should be reported. However, the presence of a sludge or emulsion or of another deposit
of oil beneath the water surface, or the violation of an applicable water quality standard also indicates a harmful
discharge regardless of whether there is a sheen on the water surface.
Section 311 of the CWA defines and prohibits certain "discharges" of oil. This definition is also codified
in 40 CFR part 112. A "discharge" as defined in §112.2 includes, but is not limited to, any spilling, leaking,
pumping, pouring, emitting, emptying, or dumping of any amount of oil no matter where it occurs. It excludes
certain discharges associated with §402 of the CWA and §13 of the River and Harbor Act of 1899. The primary
Water Quality Standards define the goals for a waterbody by designating its uses, setting criteria to protect those uses, and
establishing provisions such as antidegradation policies to protect waterbodies from pollutants. For more information on water
quality standards see http://water.epa.gov/scitech/swguidance/standards/upload/WQS basic factsheet.pdf
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distinction between the §112.2 and §112.l(b) definitions of discharge is that a discharge as described in
§112.l(b) is a violation of §311 of the Clean Water Act, whereas a §112.2 discharge includes discharges that do
not reach navigable waters or adjoining shorelines. For example, if a tank leaks a puddle of oil into a building's
basement, this would be considered a discharge of oil under §112.2, but is not necessarily a violation of the CWA
because the oil did not reach a navigable water or adjoining shoreline (and would not be a discharge as
described in §112.l(b)).
The SPCC regulation includes requirements for corrective action as well as additional reporting
requirements. For example, in §112.8(c)(10), the owner or operator of a facility is required to promptly correct
visible discharges that result in a loss of oil from a container. A discharge of any amount would need to be
cleaned up, but would not be considered a violation of the spill prohibition (a discharge as described in
§112.l(b)), unless it reaches a navigable water or adjoining shorelines. Additionally, if a facility discharged more
than 42 U.S. gallons of oil in each of two discharges as described in §112.l(b) over a 12-month period, the owner
or operator would be required to report each spill to the NRC, clean up the spill, and submit a report to the
Regional Administrator, and may be required to amend its Plan. The same is true if the facility has a single
discharge as described in §112.l(b) of more than 1,000 U.S.
gallons. For more information on these reporting
requirements, see §112.4 of the rule.45
2.6.2 Reasonable Expectation of Discharge
The SPCC rule applies only to facilities that, due to
their location, can reasonably be expected to discharge oil as
described in §112.l(b). The rule does not define the term
"reasonably be expected." The owner or operator of each
facility must determine the potential for a discharge from
his/her facility. According to §112.1(d)(l)(i), this
determination must be based solely upon consideration of
the geographical and locational aspects of the facility. An
owner or operator should consider the location of the facility
in relation to a stream, ditch, gully, or storm sewer; the
volume of material likely to be spilled; drainage patterns; and soil conditions. An owner or operator may not
consider constructed features, such as dikes, equipment, or other manmade structures that prevent, contain,
hinder, or restrain a discharge as described in §112.l(b), when making this determination.46
...this part applies to any owner or operator of a
non-transportation-related onshore or offshore
facility engaged in drilling, producing, gathering,
storing, processing, refining, transferring,
distributing, using, or consuming oil and oil
products, which due to its location, could
reasonably be expected to discharge oil in
quantities that may be harmful, as described in
part 110 of this chapter...
Note: The above text is an excerpt of the SPCC rule. Refer
to 40 CFR part 112 for the full text of the rule. Emphasis
added.
When determining the applicability of this SPCC reporting requirement, the gallon amount(s) specified (either 1,000 or 42)
refers to the amount of oil that actually reaches navigable waters or adjoining shorelines not the total amount of oil spilled. EPA
considers the entire volume of the discharge to be oil for the purposes of these reporting requirements.
Certain man-made features, such as building walls, basement structures, and drainage systems may be taken into consideration
in determining how to comply with the SPCC requirements.
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A facility owner or operator, however, should consider the presence of manmade structures that may
serve to transport discharged oil to navigable waters, such as sanitary or storm water drainage systems, even if
they lead to a publicly owned treatment work (POTW) prior to ultimate discharge into navigable waters. The
presence of a treatment system such as a POTW cannot be used to determine that the facility is not reasonably
expected to discharge to navigable waters or adjoining shorelines. POTWs can fail to contain oil. They are not
designed to handle oil discharges and are on occasion forced to bypass to receiving waterbodies during extreme
weather events or when upsets occur in the treatment system.
The following factors47 may be useful to consider in determining whether there is a reasonable
expectation of a discharge:
• Post discharges of oil from the facility or a neighboring facility that reached a navigable water or
adjoining shoreline may indicate that another could be reasonably expected;
• Facility location relative to navigable waters, a watercourse and/or intervening natural drainage
could cause a discharge to the navigable waters to be reasonably expected;
• On-site conduits and certain underground features, such as sewer lines, storm sewers, power
or cable lines, or groundwater could facilitate the transport of discharged oil off-site to
navigable waters;
• Unique geological or geographic features could facilitate the transport of discharged oil off-site
to navigable waters;
• Precipitation runoff could transport oil into navigable waters; and
• Quantity and nature of oil stored.
If an owner or operator makes a determination that, due to the location, the facility cannot reasonably
be expected to discharge oil as described in §112.l(b), he should be prepared to provide the rationale and any
supporting documentation to an EPA inspector that explains why the facility does not have an SPCC Plan.
v* FYI -Tools to determine reasonable expectation of discharge
While EPA does not endorse or recommend any particular modeling programs, the Agency recognizes that there are
software tools available to aid in making the reasonable expectation of discharge determination, which have been used
by various industry sectors. Such tools may combine data concerning the location of facilities with respect to navigable
waters, geographical features, type of oil stored, soil type, and other factors as described above, to make site-specific
estimations. The SPCC Plan preparer and/or certifying PE may determine whether any software tool is appropriate for
his or her specific circumstances, and should adequately document the input variables in the SPCC Plan.
These are examples of factors to provide guidance and are not mandatory. However, a facility owner/operator may wish to
take a conservative approach and consider all of these factors when determining reasonable expectation of a discharge from
the facility.
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2.6.3 Geographic Scope
EPA revised the geographic scope described in §112.l(b) of the SPCC regulation in 2002 to be more
consistent with the CWA. Formerly, the geographic scope of the rule extended to navigable waters of the United
States and adjoining shorelines. The current rule reflects the full geographic scope of EPA's authority to include a
discharge:
• Into or upon the waters of the contiguous zone;
• In connection with activities under the Outer Continental Shelf Lands Act or the Deepwater Port
Act of 1974; or
• That may affect natural resources belonging to, appertaining to, or under the exclusive
management authority of the United States (including resources under the Magnuson Fishery
Conservation and Management Act).
The rule's scope includes discharges harmful not only to the public health and welfare, but also to the
environment through the protection of natural resources. Such protection would apply to resources under the
Magnuson Fishery Conservation and Management Act, a statute that establishes exclusive U.S. management
authority over all fishing within the exclusive economic zone (inner boundary coterminous with the seaward
boundary of each coastal state), and all anadromous fish throughout their migratory range except when in a
foreign nation's waters, and all fish on the continental shelf.
2.6.4 Definition of "Navigable Waters"
Section 112.2 provides the SPCC rule's definition of "navigable waters." This definition has been revised
on several occasions, most recently in 2008. The current definition of navigable waters for the SPCC rule is the
definition promulgated by EPA in 1973 (73 FR 71941, November 26 2008).
EPA and the U.S. Army Corps of Engineers have issued guidance on implementing Supreme Court
decisions that affect CWA jurisdiction over navigable waters.48 4?
\r\Solid\NasteAgencyofNorthern Cook County v. United States Army Corps of Engineers, 531 U.S. 159 (2001) (referred to as
"SWANCC'J, the Supreme Court held that the agencies cannot assert CWA jurisdiction over intrastate non-navigable isolated
waters based solely on use or potential use by migratory birds, presence of habitat.
In the consolidated cases Rapanos v. United States and Carabell v. United States (referred to simply as "Rapanos") the Supreme
Court made two substantive decisions that indicated that a water is a "water of the US" either where the water is:
"relatively permanent, standing, or continuously flowing bodies of water" connected to traditional navigable waters,
and to "wetlands with a continuous surface connection to" such relatively permanent waters; or
"either alone or in combination with similarly situated lands in the region, significantly affect the chemical, physical
and biological integrity of other covered waters more readily understood as navigable' (i.e. whether there is a
significant nexus with navigable waters).
^ Guidance on SWANCC is available in a joint memorandum between EPA and the U.S. Army Corps of Engineers (Corps) (see
68 FR 1995, January 15, 2003). For more information on navigable waters, including previous statements on Waters of the US,
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Chapter 2: Applicability
§112.2
Storage capacity of a container means the shell
capacity of the container.
Note: The above text is an excerpt of the SPCC rule. See
40 CFR part 112 for the full text of the rule.
2.7 Storage Capacity Thresholds
The SPCC rule applies to certain facilities that have
more than 42,000 U.S. gallons of completely buried oil
storage capacity or more than 1,320 U.S. gallons of
aggregate aboveground oil storage capacity, provided it
meets the other applicable criteria set forth in §112.1.
Under §112.1(b)(l) through (4), the rule is applicable to eligible facilities that have oil in aboveground
containers; completely buried tanks; containers that are used for standby storage, for seasonal storage, or for
temporary storage, or are not otherwise "permanently closed;" and "bunkered tanks" or "partially buried tanks"
or containers in a vault. Containers include not only oil storage tanks, but also mobile or portable containers
such as drums and totes, and oil-filled equipment such as electrical equipment (e.g., transformers, circuit
breakers), manufacturing flow-through process equipment, and operational equipment. Under §112.1(d)(2) the
rule limits the applicability to facilities with oil capacity above specific threshold amounts.
Once a facility is subject to the rule, all aboveground containers and completely buried tanks are subject
to the rule requirements (unless these containers are otherwise exempt from the regulation). For example, a
facility could have 10,000 U.S. gallons of aggregate aboveground storage capacity in tanks and oil-filled
equipment of 55 U.S. gallons or more, and a completely buried tank of 10,000 U.S. gallons that is not subject to
all of the technical requirements of 40 CFR part 280 or a state program approved under part 281 (and therefore
not exempt). Since the aboveground storage capacity exceeds 1,320 U.S. gallons, all of the tanks and oil-filled
equipment, including the buried tank, are subject to the SPCC rule.
2.7.1 Storage Capacity Calculation
Sections 112.1(d)(2)(i) and (ii) clarify which containers are included and excluded when calculating total
storage capacity at a facility in determining whether it exceeds the volume limits in the rule. The container
capacities to count and not count are discussed below.
2.7.2 Definition of Storage Capacity
Under the SPCC rule, if a container has the requisite capacity, it does not matter whether the container
is actually filled to that capacity. The storage capacity of a container is defined as the shell capacity of the
container.
If a certain portion of a container is incapable of storing oil because of its integral design (e.g.,
mechanical equipment or other interior components take up space), then the shell capacity of the container is
reduced to the volume the container could hold (67 FR 47081, July 17, 2002). Generally, the shell capacity is the
rated design capacity rather than the working/operational capacity.
see http://water.epa.gov/lawsregs/guidance/wetlands/CWAwaters.cfm.
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Industry standards for certain field-erected and shop-fabricated aboveground vertical storage tanks
define the storage capacity of the tank as the physical capacity of the shell to contain liquid, and if present, the
capacity can be limited by overflow openings that restrict the liquid level so that the container cannot hold
liquid above that point. Thus, for tanks that have floating roofs or internal floating pans where overflow
openings or slots are present in the shell, the freeboard volume above the overflow openings or slots is not
included in the tank's shell capacity. However, if an existing tank with overflow ports or vents is modified by
covering the overflow ports or vents, the container storage capacity reverts to the original shell capacity (see
Tank Re-rating section below).
Any modification to the existing port or vent must be performed in accordance with applicable industry
standards. Additionally, this container alteration will require a technical amendment to the SPCC Plan certified
by a PE in accordance with §112.5. The PE will ensure that the alteration was performed in accordance with
applicable industry standards, original design specifications and good engineering practice. Note that many
aboveground field erected tanks have cone-down bottoms (the volume of the cone bottom can be significant for
larger tanks). This volume is included in the overall storage capacity of the tank.
Devices such as hydraulic overfill valves or high level alarms or procedures, such as operational controls,
are not a means of limiting the capacity of a storage container because these systems or procedures can fail or
an owner/operator can easily override or remove the controls, increasing the storage capacity of the container.
v* FYI - What capacities to count and not to count
Do count the following oil containers' capacities:
All containers of oil with a capacity of 55 U.S. gallons or greater (unless otherwise exempt).
Do not count the following exempt oil containers' capacities:
Permanently closed containers
Motive power containers
Hot-mix asphalt (HMA) or any HMA containers
Single-family residential heating oil containers
Pesticide application equipment and related mix containers
Milk and milk product containers and associated piping and appurtenances
Completely buried tanks that are subject to all of the technical requirements of 40 CFR part 280 or a State
program approved under 40 CFR part 281
Underground oil storage tanks including below-grade vaulted tanks, that supply emergency diesel generators
at nuclear power stations
Containers used exclusively for wastewater treatment
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2.7.3 Tank Re-rating
Shell capacity is used as the measure of storage capacity, unless physical changes are made to the
design shell capacity in a permanent, non-reversible, manner that reduces the capacity of the container to
contain liquid. An owner or operator may reduce the capacity of a tank by changing the shell dimensions (e.g.,
by removing shell plate sections, or installing a double bottom in accordance with applicable industry
standards). When the alteration is an action such as the installation of a double bottom or new floor to the
container, the integral design of the container has changed, and may result in a reduction in shell container
capacity.
EPA also considers overflow ports or vents installed in accordance with industry standards as an
acceptable method of reducing the shell capacity of container.49 These properly engineered alterations can be
considered permanent when the alteration to the container is performed in accordance with applicable industry
standards. However, even when a shell penetration is completed in accordance with industry standards, this
does not re-rate the storage capacity of the tank to a lower capacity if the owner or operator overrides the
alteration.
When an overflow nozzle is equipped with a pipe and a valve, and the valve is then closed, the
container's capacity reverts to the original shell capacity.50 If an overfill opening is closed at a later date, this
constitutes a change in service and as such, per API 653, the tank's suitability for service must be reevaluated
and the original capacity of the tank to the top of the shell becomes the measure of storage capacity. This and
similar actions that reverse or effectively override the prior alteration used to change the original shell capacity
of the container may change the shell capacity again and require an amendment to the SPCC Plan.
Any container alteration will require a technical amendment to the SPCC Plan certified by a PE in
accordance with §112.5. The PE will ensure that the alteration was performed in accordance with applicable
industry standards and in consideration of original design specifications. Relevant industry standards include
American Petroleum Institute (API) Standard 653 "Tank Inspection, Repairs, Alteration, and Reconstruction"
(API-653). This standard includes requirements for adding shell penetrations (which may be used to reduce
container capacity) such as shell penetration (i.e., nozzle) for overflow. Tank alterations which change the
original shell capacity may affect secondary containment capacity necessary to comply with SPCC requirements
and FRP applicability and requirements under 40 CFR part 112 subpart D. Thus, changes in container storage
capacity may affect FRP requirements for calculating the worst case discharge volume and the amount of
resources required to respond to a worst case discharge scenario to comply with the FRP requirements.
Simply drilling a hole in the container, so that the container cannot hold liquid above that point, may not
be an appropriate method to re-rate tank capacity when this alteration is not in accordance with applicable
industry standards. In this case the original capacity of the container has not changed and remains the measure
To be considered as overflow ports, the size and number of overflow ports shall be based on filling the tank (i.e., fill rate)
without increasing the liquid level above the bottom of the overflow port.
A valve is not recommended unless otherwise required by code.
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of storage capacity. Finally, devices (e.g. hydraulic overfill valves and high level alarms) and procedures (e.g.
administrative controls) may not be used to limit the capacity of a storage container. For more information on
how to evaluate a re-rated tank see Chapter 7: Inspection, Evaluation, and Testing (see Section 7.6.1).
2.8 Exemptions to the Requirements of
the SPCC Rule
§112.2
Permanently closed means any container or
facility for which (1) All liquid and sludge has
been removed from each container and
connecting line; and (2) All connecting lines and
piping have been disconnected from the
container and blanked off, all valves (except
ventilation valves) have been closed and locked,
and conspicuous signs have been posted on each
container stating that it is a permanently closed
container and noting the date of closure.
Note: The above text is an excerpt of the SPCC rule. Refer
to 40 CFR part 112 for the full text of the rule.
In addition to the criteria described above, §112.l(d)
describes certain types of additional equipment and facilities
that are exempt from SPCC rule requirements.
2.8.1 Permanently Closed Containers
Permanently closed containers are exempt from
SPCC regulation. Once permanently closed, a container no
longer counts toward the total facility storage capacity, nor is
it subject to the other requirements under the SPCC rule. The
SPCC rule does not require that permanently closed
containers be removed from a facility.
In addition, any container brought on to a facility that has never stored oil is not subject to the SPCC
rule, nor is it counted toward the facility capacity until it stores oil. Any other container that at one time stored
oil but no longer contains oil or sludge, which is brought on to a facility and meets the definition of permanently
closed, is not subject to the SPCC rule nor is it counted toward the facility capacity until it stores oil.
Permanent closure requirements under the SPCC rule are separate and distinct from the closure
requirements in regulations promulgated under Subtitle C of the Resource Conservation and Recovery Act
(RCRA).51 These regulations establish the requirements for owners and operators of facilities that use tank
systems for storing or treating hazardous waste, and include the requirements for tank system closure and post-
closure care (§§264.197 and 265.197). These requirements generally do not apply to an oil production facility.
According to the applicability provision in §264.1(b),52 "the standards in this part apply to owners and operators
of all facilities which treat, store, or dispose of hazardous waste, except as specifically provided otherwise in this
part or part 261 of this chapter." In addition, 40 CFR part 261 states that "Drilling fluids, produced waters, and
other wastes associated with the exploration, development, or production of crude oil, natural gas or
geothermal energy" are not hazardous waste (§261.4(b)(5)). Therefore, an oil production facility that does not
otherwise treat, store, or dispose of hazardous waste would not have to undergo the expense of permanent
See Standards for Owners and Operators of Hazardous Waste Treatment, Storage, and Disposal Facilities at 40 CFR part 264 and
Interim Status Standards for Owners and Operators of Hazardous Waste Treatment, Storage, and Disposal Facilities at 40 CFR
part 265.
The applicability provision under §265.l(b) includes similar language that excludes oil production facilities.
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closure under Part 264 or 265 of RCRA, based on the management of these wastes (i.e., drilling fluids, produced
waters, and other wastes associated with the exploration, development, or production of crude oil) which are
exempt from subtitle C regulations.
v* Permanently closed containers - Is it really permanent?
The SPCC rule does not include a provision to temporarily close containers to account for seasonal use of tanks or
variable economic conditions and production rates at oil production facilities. In order for a container to be exempt
from SPCC rule requirements, the container must meet the following criteria for a permanently closed container:
All liquid and sludge has been removed from each container and connecting line;
All connecting lines and piping have been disconnected from the container and blanked off,
All valves (except ventilation valves) have been closed and locked, and
Conspicuous signs have been posted on each container stating that it is a permanently closed container and
noting the date of closure.
A permanently closed container may remain at the facility. However, a facility owner or operator should review state
and local requirements, which may require removal of a container when it is taken out service. When a container is
removed from the facility, the SPCC Plan must be amended and the technical amendment must be certified.
In the event that a permanently closed container is brought back into use (e.g., to accommodate variations in
production rates), the SPCC Plan will need to be amended to reflect the capacity of the permanently closed container if
this capacity was previously excluded from the facility total capacity.
2.8.2 Offshore Oil Drilling, Production or Workover Facilities Subject to Minerals
Management Service Regulations
Section 112.1(d)(3) excludes offshore oil drilling, production, or workover facilities that are subject to
notices and regulations of the Minerals Management Service (MMS). The facilities are regulated by the
Department of Interior as specified in the 1994 DOI-DOT-EPA
MOD (40 CFR part 112, Appendix B).
The memorandum states that MMS has jurisdiction
over facilities, including pipelines, located seaward of the
coast line, except for deepwater ports and associated
seaward pipelines delegated by Executive Order 12777 to
DOT. EPA is responsible for non-transportation-related
offshore facilities located landward of the coast line. The
term "coast line" is defined as in the Submerged Lands Act
(43 U.S.C. 1301(c)) to mean "the line of ordinary low water
along that portion of the coast which is in direct contact with
Except as provided in paragraph (f) of this
section, this part does not apply to:...
(3) Any offshore oil drilling, production, or
workover facility that is subject to the notices
and regulations of the Minerals Management
Service, as specified in the Memorandum of
Understanding between the Secretary of
Transportation, the Secretary of the Interior, and
the Administrator of EPA, dated November 8,
1993 (Appendix B of this part).
Note: The above text is an excerpt of the SPCC rule. Refer
to 40 CFR part 112 for the full text of the rule.
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the open sea and the line marking the seaward limit of inland waters."
MMS has been replaced, most recently on October 1, 2011, by the Bureau of Ocean Energy
Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE) as part of a
reorganization. BOEM is responsible for managing environmentally and economically responsible development
of the nation's offshore resources. Its functions include offshore leasing, resource evaluation, review and
administration of oil and gas exploration and development plans, renewable energy development, National
Environmental Policy Act (NEPA) analysis and environmental studies.53 BSEE is responsible for safety and
environmental oversight of offshore oil and gas operations, including permitting and inspections, of offshore oil
and gas operations. Its functions include the development and enforcement of safety and environmental
regulations, permitting offshore exploration, development and production, inspections, offshore regulatory
programs, oil spill response and newly formed training and environmental compliance programs.54
2.8.3 Underground Storage Tanks
Under §112.1(d)(4), the SPCC rule exempts completely buried storage tanks, as well as connected
underground piping, underground ancillary equipment, and containment systems, when such tanks are subject
to all of the technical requirements of 40 CFR part 280 or a state program approved under 40 CFR part 281 (also
known as the Underground Storage Tank regulations55). Although these tanks are exempt from the SPCC
requirements, they must still be marked on the facility diagram if the facility is otherwise subject to the SPCC
rule (see §112.7(a)(3)).
The regulations at 40 CFR parts 280 and 281
comprise the Underground Storage Tank (UST) Program,
which requires owners and operators of new tanks and tanks
already in the ground to prevent, detect, and clean up
releases. The SPCC rule only recognizes a subset of tanks
covered by the UST Program regulations. Specifically, the
UST Program defines an underground storage tank as a tank
and any underground piping that has at least 10 percent of
its combined volume underground. However, under the
SPCC rule, only completely buried tanks subject to all of the
technical UST program requirements are exempt from the
rule. Any tanks that are not completely buried are
considered aboveground storage tanks and subject to the
SPCC rule.
§112.2
Completely buried tank means any container
completely below grade and covered with earth,
sand, gravel, asphalt, or other material.
Containers in vaults, bunkered tanks, or partially
buried tanks are considered aboveground
storage containers for purposes of this part.
Note: The above text is an excerpt of the SPCC rule. Refer
to 40 CFR part 112 for the full text of the rule.
53
54
55
See www.boem.gov
See www.bsee.gov
See Technical Standards and Corrective Action Requirements for Owners and Operators of Underground Storage Tanks (UST) at
40 CFR part 280 and Approval of State Underground Storage Tank Programs at 40 CFR part 281.
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The following completely buried tanks are either excluded from the definition of UST or are exempt
from the UST regulations at 40 CFR part 280 (and therefore may be subject to the SPCC rule if they contain oil):
• Tanks with a capacity of 110 U.S. gallons or less;
• Farm or residential tanks with a capacity of 1,100 U.S. gallons or less used for storing motor fuel
for non-commercial purposes;
• Tanks used for storing heating oil for consumptive use on the premises where stored;
• Tanks storing non-petroleum oils, such as animal fat or vegetable oil;
• Tanks on or above the floor of underground areas (e.g., basements or tunnels);
• Septic tanks and systems for collecting storm water and wastewater;
• Flow-through process tanks;
• Emergency spill and overfill tanks that are expeditiously emptied after use;
• Surface impoundments, pits, ponds, or lagoons;
• Any UST system holding RCRA hazardous waste;
• Any equipment or machinery that contains regulated substances for operational purposes such
as hydraulic lift tanks and electrical equipment tanks;
• Liquid trap or associated gathering lines directly related to oil or gas production or gathering
operations;
• Pipeline facilities regulated under the Natural Gas Pipeline Safety Act of 1968, the Hazardous
Liquid Pipeline Safety Act of 1979, or intrastate pipelines regulated under state laws comparable
to the provisions of above laws;56 and
• Any UST system that contains de minimis concentration of regulated substances.
The following are examples of deferrals from the UST regulations (and therefore may be subject to the
SPCC rule):
• Wastewater treatment tank systems;
Although exempt from UST regulations, pipeline facilities regulated under the Natural Gas Pipeline Safety Act of 1968, the
Hazardous Liquid Pipeline Safety Act of 1979, or intrastate pipelines regulated under state laws comparable to the provisions of
above laws do not generally come within EPA's jurisdiction and are not generally regulated under the SPCC rule. See
Section 2.5.
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• Any UST systems containing radioactive materials that are regulated under the Atomic Energy
Act of 1954;
• Airport hydrant fuel distribution systems; and
• UST systems with field-constructed tanks.
Note that, at an otherwise SPCC-regulated facility, any transfer to or from completely buried storage
tanks is regulated because it is a potential source of discharge of oil into navigable waters or adjoining
shorelines. Because a loading/unloading rack, or other transfer area, associated with a UST is not typically part
of the UST system, it is not subject to all of the technical requirements of 40 CFR part 280 or 281. Therefore,
such a loading/unloading rack is regulated under the SPCC regulations in the same manner as any other transfer
equipment or transfer activity located at an otherwise SPCC-regulated facility (73 FR 74250, December 5, 2008).
Additional and/or more stringent requirements may exist in a state-approved program under 40 CFR
part 281 and they may also impact SPCC applicability. For example, a state may choose to regulate a UST used
for storing heating oil for consumptive use on the premises where stored. Thus, under the state program the
UST is subject to all the technical requirements of a 40 CFR part 281 program and therefore exempt from the
SPCC rule. Inspectors should consider any state UST program approved under 40 CFR part 281 when addressing
applicability issues associated with completely buried tanks.
A list of states with approved 281 UST programs, and their respective Federal Register notices, is
available at http://www.epa.gov/oust/fsstates.htm.
2.8.4 Underground Emergency Diesel Generator Tanks at Nuclear Power Stations
Under §112.1(d)(4), the SPCC rule exempts underground oil storage tanks deferred under 40 CFR part
280, as originally promulgated, that supply emergency diesel generators at nuclear power generation facilities
licensed by Nuclear Regulatory Commission (NRC) and that meet the NRC design criteria and quality assurance
criteria.
This exemption includes both tanks that are completely buried and tanks that are below-grade and
vaulted. In order to be eligible for the exemption, the below-grade vaulted tank must meet the definition of an
underground storage tank in 40 CFR 280. An underground storage tank or UST is defined in 40 CFR part 280 as
"any one or combination of tanks... the volume of which is 10 percent or more beneath the surface of the
ground." A storage tank situated in an underground area (such as a basement, cellar, mineworking, drift, shaft,
or tunnel) is excluded from the definition when the storage tank is situated upon or above the surface of the
floor. Therefore, a below-grade vaulted tank located in a space that an inspector can routinely walk into and
view all sides of the tank would not be eligible for the exemption from SPCC requirements.
Under the NRC regulations, a nuclear power generation facility must meet certain design criteria to
ensure that the plant will be operated in a manner protective of the public's health and safety (such as 10 CFR
part 50, Appendix A). These NRC design criteria cover the design, fabrication, installation, testing and operation
of structures, systems, and components important to safety and are considered to be similar to the measures
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required under the SPCC regulation for completely buried tanks, which include corrosion protection of buried
tanks (§112.8(c)(4)) and of buried piping (§112.8(d)(l)), and inspection and testing of buried piping
Although these tanks are exempt from the SPCC requirements, they must still be marked on the facility
diagram if the facility is otherwise subject to the SPCC rule (§112.7(a)(3)).
2.8.5 Wastewater Treatment Facilities
The wastewater treatment exemption, outlined in §112.1(d)(6), excludes from the SPCC requirements
facilities or parts of facilities that are used exclusively for wastewater treatment, and are not used to meet 40
CFR part 112 requirements. Do not count the capacity of these exempt containers when calculating facility
aggregate capacity.
Many of the wastewater treatment facilities or parts thereof are subject to the National Pollutant
Discharge Elimination System (NPDES) or state-equivalent
permitting requirements that involve operating and
maintaining the facility to prevent discharges. The NPDES or
state-equivalent process ensures review and approval of the
facility's plans and specifications; operation/maintenance
manuals and procedures; and Storm Water Pollution
Prevention Plans, which may include Best Management
Practice (BMP) Plans (67 FR 47068, July 17, 2002).
§112.l(d)
Except as provided in paragraph (f) of this
section, this part does not apply to:...
(6) Any facility or part thereof used exclusively
for wastewater treatment and not used to satisfy
any requirement of this part. The production,
recovery, or recycling of oil is not wastewater
treatment for purposes of this paragraph.
Note: The above text is an excerpt of the SPCC rule. Refer
to 40 CFR part 112 for the full text of the rule.
For the purposes of the exemption, the production,
recovery, or recycling of oil is not considered wastewater
treatment. These activities generally lack NPDES or state-
equivalent permits and thus lack the protections that such
permits provide. The goal of an oil production, oil recovery,
or oil recycling facility is to maximize the production or recovery of oil, while eliminating impurities in the oil,
including water, whereas the goal of a wastewater treatment facility is to purify water (67 FR 47068-69, July 17,
2002). Additionally, produced water is not considered wastewater and is therefore not eligible for this
exemption. However, produced water containers used exclusively for wastewater treatment at dry gas
production facilities are eligible for the wastewater treatment exemption (see 69 FR 29728, May 25, 2004).
The exemption also does not apply to a wastewater treatment facility (or part of that facility) that is
used to store oil. In those instances, the oil storage capacity must be counted as part of the total facility storage
capacity (see 67 FR 47068, July 17, 2002). For example, if there is a 1,000-gallon storage container that contains
oil removed from an exempt oil/water separator and a 500-gallon storage container for an emergency
generator, the total aboveground storage capacity for the facility would be 1,500 U.S. gallons, and the facility
may potentially be regulated by the SPCC rule.
A wastewater treatment facility (or parts of that facility) used to meet a 40 CFR part 112 requirement,
including an oil/water separator used to meet any SPCC requirement, is not exempt. Oil/water separators used
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to meet SPCC requirements include those used to satisfy the secondary containment requirements of §112.7(c),
§112.7(h)(l), and/or §§112.8(c)(2) or 112.8(c)(ll). Although not exempt, oil/water separators used to satisfy
secondary containment requirements of the rule do not count toward storage capacity. For more information,
refer to Chapter 5: Oil/Water Separators, which clarifies how the SPCC rule applies to oil/water separators and
produced water at dry gas production facilities.
2.8.6 Motive Power
A motive power container is defined as any onboard bulk storage container used primarily to power the
movement of a motor vehicle, or ancillary onboard oil-filled operational equipment (§112.2). Section 112.1(d)(7)
exempts motive power containers from regulation under the SPCC rule. Section 112.1(d)(2)(ii) excludes the
capacity of these containers from facility capacity calculations. Motive power containers include the fuel tanks
that are used primarily to power a motor vehicle's
movement and the on-board hydraulic and lubrication
containers used for ancillary functions of the motor vehicle.
Bulk Storage Container Used for Propulsion
Containers on motor vehicles that provide the
vehicle with a means of propulsion are considered motive
power containers. Examples of motor vehicles which have
containers used to individually provide their own means of
propulsion from location to location within a facility or
between facilities include:
• Aircraft,
• Cherry pickers,
• Self-propelled cranes,
• Self-propelled aviation ground service
equipment vehicles,
• Self-propelled heavy vehicles (e.g., used in
forestry, agricultural, mining, excavation and
construction applications), and
• Locomotives.
Ancillary On-Board Equipment
Except as provided in paragraph (f) of this
section, this part does not apply to: ...
(7) Any "motive power container," as defined in
§112.2. The transfer of fuel or other oil into a
motive power container at an otherwise
regulated facility is not eligible for this
exemption.
Note: The above text is an excerpt of the SPCC rule. Refer
to 40 CFR part 112 for the full text of the rule.
§112.2
Motive power container means any onboard bulk
storage container used primarily to power the
movement of a motor vehicle, or ancillary
onboard oil-filled operational equipment. An
onboard bulk storage container which is used to
store or transfer oil for further distribution is not
a motive power container. The definition of
motive power container does not include oil
drilling or workover equipment, including rigs.
Note: The above text is an excerpt of the SPCC rule. Refer
to 40 CFR part 112 for the full text of the rule.
Ancillary on-board equipment includes hydraulic and lubrication operational oil-filled containers used
for other ancillary functions of a motor vehicle. It also includes motor vehicle bulk storage containers that serve
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a non-operational purpose in addition to the propulsion of the motor vehicle: for example, a bulk storage
container that supplies fuel to an engine that provides the propulsion for that motor vehicle, as well as its
auxiliary units and functions (i.e., heaters, air conditioning units, and electrical power generation, etc.).
Exclusions from the Motive Power Container Definition
The exemption does not include non-self-propelled stationary or towed equipment, such as towed
ground service equipment or any type of oil-powered generator (gensets; see Section 2.10.6). The following are
examples of equipment that are not motive power containers because they do not include containers used for
propulsion:
• Towed aviation ground service equipment,
• Non-self-propelled construction/cargo cranes,
• Non-self-propelled (forestry, agricultural, mining, excavation or construction) equipment,
• Oil-powered generators,
• Fire pumps, and
• Compressors.
An onboard bulk storage container used to store or transfer oil for further distribution is also not a
motive power container. An onboard bulk storage container that supplies oil for the movement of a vehicle or
operation of onboard equipment, and at the same time is used for the distribution or storage of this oil is not
eligible for the exemption. This situation includes, for example, a mobile refueler that has an onboard bulk
storage container used to distribute fuel to other vehicles on a site and which also draws its engine fuel (for
propulsion) from that bulk container.
Oil drilling and workover equipment (including rigs) are not eligible for the motive power container
exemption because they are specifically excluded from the definition of a motive power container. Although
drilling and workover rigs are not exempt, other types of motive power containers located at drilling or
workover facilities (i.e., trucks, automobiles, bulldozers, seismic exploration vehicles, or other earth-moving
equipment) are exempt.
Oil Transfers to Motive Power Containers
Regardless of the exemption for motive power containers, oil transfer activities occurring within an
SPCC-regulated facility are regulated. An example of such an activity would be the transfer of oil from an oil
storage container via a dispenser to a motive power container. This transfer activity is subject to the general
secondary containment requirements of §112.7(c). See Chapter 4: Secondary Containment and Impracticability
for more information on secondary containment requirements.
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2.8.7 Hot-mix Asphalt and Hot-mix Asphalt Containers
Hot-mix asphalt (HMA) is a blend of asphalt cement (AC) and aggregate material, such as stone, sand,
gravel or ground rubber tires, which is formed into final paving products for use on roads and parking lots.
Under §112.1(d)(8), the SPCC rule exempts HMA and HMA containers. Section 112.1(d)(2)(ii) excludes the
capacity of HMA and HMA containers from facility capacity calculations.
This exemption from SPCC regulation is based on the fact that HMA is unlikely to flow as a result of the
entrained aggregate, such that there would be very few circumstances, if any, in which a discharge of HMA
would have the potential to reach navigable waters or adjoining shorelines.
However, asphalt cement, as well as asphalt
derivatives such as asphalt cutbacks and emulsions remain
subject to the SPCC rule (see the discussion in Section
2.2.4).
2.8.8 Heating Oil Containers at Single-family
Residences
Except as provided in paragraph (f) of this
section, this part does not apply to:...
(8) Hot-mix asphalt, or any hot-mix asphalt
container.
Note: The above text is an excerpt of the SPCC rule. Refer
to 40 CFR part 112 for the full text of the rule.
Many regulated facilities, including farms, military
installations, colleges and universities, may include single
family residence heating oil tanks within the geographical
confines of the facility. Residential heating oil containers
used to store oil for the sole purpose of heating single-family residences (including a residence at a farm) are
exempt from the SPCC rule under §112.1(d)(9). They are also excluded from facility storage capacity calculations
in Section 112.1(d)(2). This exemption applies to aboveground as well as completely buried heating oil tanks at
single-family residences. Heating oil tanks used for on-site consumptive use of oil are also exempt from
underground storage tanks requirements under 40 CFR part 280.
A single-family residence is a household that has direct ownership of the oil stored in the heating oil
container. In addition, if a commercial facility (for example,
a university) includes a single-family residence on the
premises, then any heating oil container associated solely
with this residence is exempt from SPCC rule applicability.
However, the SPCC requirements apply to oil
containers used to heat other non-residential buildings
within a facility, because the exemption covers only
residential heating oil containers at single-family
residences. Owners and operators of commercial facilities,
such as a multi-family structure (e.g. condominiums and
Except as provided in paragraph (f) of this
section, this part does not apply to:...
(9) Any container for heating oil used solely at a
single-family residence.
Note: The above text is an excerpt of the SPCC rule. Refer
to 40 CFR part 112 for the full text of the rule.
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apartment complexes) remain subject to the SPCC rule. These facilities generally store much larger volumes of
oil, and if there is a reasonable expectation of an oil discharge to navigable waters or adjoining shorelines, then
oil spill prevention measures need to be addressed in an SPCC Plan.
2.8.9 Pesticide Application Equipment and Related Mix Containers
Pesticide formulations may include petroleum- or vegetable-based oils in concentrated formulations or
may contain crop oil or adjuvant oil in the mix formulations added just prior to application. Pesticide application
equipment and related mix containers are exempt from the SPCC rule, under §112.1(d)(10) and the facility
capacity calculations in §112.1(d)(2)(ii).
Pesticide application equipment includes ground boom applicators, airblast sprayers, and specialty
aircraft containers/equipment that are used to apply measured quantities of pesticides to crops and/or soil.
Related mix containers are those used to mix pesticides with water and, as needed, adjuvant oils, just prior to
loading into the application equipment.
Containers (55 U.S. gallons or greater in capacity)
storing oil prior to blending it with the pesticide, and
containers used to store any pesticides after they have been
mixed with oil, are considered bulk storage containers and
are regulated as such under the SPCC rule.
Except as provided in paragraph (f) of this
section, this part does not apply to:...
(10) Any pesticide application equipment or
related mix containers.
Note: The above text is an excerpt of the SPCC rule. Refer
to 40 CFR part 112 for the full text of the rule.
EPA adopted this exemption because this type of
pesticide use and related mix containers are already subject
to regulation under the Federal Insecticide, Fungicide, and
Rodenticide Act (FIFRA), as codified in Standards for
Pesticide Containment Structures in 40 CFR part 165, to
assure the safe use (including discharge), reuse, storage, and
disposal of pesticide containers.
2.8.10 Intra-Facility Gathering Lines Subject to Department of Transportation (DOT)
Requirements
Intra-facility gathering lines (i.e. gathering lines found within the confines of a non-transportation-
related facility) may be under the jurisdiction of both EPA and DOT as described in Section 2.5.8. However,
certain DOT requirements for pipelines are considered to be similar in scope to SPCC regulations. Therefore,
intra-facility gathering lines that are subject to DOT regulatory requirements at 49 CFR part 192 (Transportation
of Natural and Other Gas by Pipeline) or 195 (Transportation of Hazardous Liquids by Pipeline) are exempt from
the SPCC rule under §112.1(d)(ll). If intra-facility gathering lines are not subject to DOT regulatory
requirements (i.e., gathering lines that by statute are subject to DOT jurisdiction, yet are not subject to the DOT
regulations) they remain subject to 40 CFR part 112. Other equipment and piping at an oil production facility
(such as flowlines) remain subject to SPCC requirements. EPA considers intra-facility gathering lines subject to
EPA's jurisdiction if they are located within the boundaries of an otherwise regulated SPCC facility. Appendix H
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includes drawings that show EPA's regulatory jurisdiction at complexes, including an example of an oil
production facility with gathering lines.57
The exemption requires owners or operators of a facility to identify and mark as "exempt" the location
of exempt piping on the facility diagram. This requirement will assist both facility and EPA personnel in defining
the boundaries of EPA and DOT jurisdiction and provide
response personnel with information used to identify
hazards during a spill response activity. More information
about facility diagram requirements is provided in Chapter
6: Facility Diagram and Description.
Except as provided in paragraph (f) of this
section, this part does not apply to:...
(11) Intra-facility gathering lines subject to the
regulatory requirements of 49 CFR part 192 or
195, except that such a line's location must be
identified and marked as "exempt" on the facility
diagram as provided in §112.7(a)(3), if the facility
is otherwise subject to this part.
Note: The above text is an excerpt of the SPCC rule. Refer
to 40 CFR part 112 for the full text of the rule.
Issues related to intra-facility gathering lines and
their SPCC requirements are covered in detail in Chapter 3:
Environmental Equivalence (Section 3.3.5) and Chapter 4:
Secondary Containment and Impracticability (Section 4.2.2).
2.8.11 Milk and Milk Product Containers
Milk and milk product containers and associated
piping and appurtenances are exempt from the SPCC
requirements under §112.1(d)(12) and excluded from facility capacity calculations in §112.1(d)(2)(ii). Butter,
cheese, and dry milk containers are a few examples of milk product containers subject to the exemption.
All milk and/or milk product transfer and processing activities are included in the scope of this
exemption from the SPCC rule. For more information on the final rule exempting milk and milk product
containers see 76 FR 21652, April 18, 2011.
2.8.12 Summary of Exemptions
Table 2-3 provides a summary of containers and equipment, as described in the preceding sections,
which are exempt from the requirements of the SPCC rule and therefore excluded from a facility's oil storage
capacity calculation.
See EPA Jurisdiction at Complexes.
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Table 2-3: Summary of oil storage capacity calculation as described in §112.1(d)(2)(i) and (ii).58
Included
Capacity of containers (e.g.,
bulk storage containers, oil-
filled equipment,
mobile/portable containers)
with a capacity of 55 U.S.
gallons or greater (unless
otherwise exempt)
Excluded
Capacity of a container that is permanently closed
Capacity of a motive power container
Capacity of hot-mix asphalt or any hot-mix asphalt container
Capacity of a container for heating oil used solely at a single-family residence
Capacity of pesticide application equipment and related mix containers
Capacity of any milk and milk product container and associated piping and
appurtenances
Capacity of any completely buried tank and associated underground piping, ancillary
equipment, and containment systems subject to all technical requirements of 40 CFR
part 280 or a state-approved program under 40 CFR part 281
Capacity of any underground oil storage tanks including below-grade vaulted tanks, that
supply emergency diesel generators at a nuclear power generation facility licensed by
the Nuclear Regulatory Commission and subject to any Nuclear Regulatory Commission
provision regarding design and quality criteria, including, but not limited to, 10 CFR part
50
2.9 Determination of Applicability by the Regional Administrator
Section 112.l(f) allows the Regional Administrator (RA) to require the preparation and implementation
of an SPCC Plan or applicable part from the owner or operator of an otherwise exempted facility that is subject
to EPA jurisdiction under §311(j) of the CWA. This provision is designed to address gaps in other regulatory
regimes that may be remedied by requiring a facility to have an SPCC Plan. For example, a facility may be
exempt from the SPCC rule because its storage capacity is below the regulatory threshold, but the facility may
have been the cause of repeated discharges as described in §112.l(b).
Factors the RA may consider in making a determination to require that a facility prepare an SPCC Plan
include, but are not limited to, the physical characteristics of the facility; the presence of secondary
containment; the discharge history of the facility; and the proximity of the facility to sensitive environmental
areas such as wetlands, parks, or wildlife refuges. The RA might require either an entire Plan or a partial Plan
addressing a specific rule requirement like secondary containment, for example, to prevent future discharges.
Sections 112.1(f)(l) through (5) describe the process for an RA to determine applicability. The process
includes specific deadlines for both the RA and the facility owner or operator, as well as requirements for the
type of information and delivery method. Table 2-4 lists the deadlines and responsibilities of the RA and the
facility owner or operator to appeal the RA determination that requires preparing an SPCC Plan.
Also exclude the capacity of containers used exclusively for wastewater treatment as described in §112.1(d)(6)
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Table 2-4: Process for an RA determination of SPCC applicability and appeals.
Deadline
Responsibility
Determination
As needed.
Within 30 days of receipt of notice of a
potential need to prepare an SPCC Plan
(following preliminary determination)
Within 30 days of receipt of data
Within 6 months of final determination that
facility needs a Plan
Within 1 year of final determination that
facility needs a Plan
Regional Administrator (RA) makes a preliminary determination. RA must
provide a written notice to the owner/operator stating the reasons why an
SPCC Plan or applicable part of a Plan is needed. (§112.1(f)(l))
Owner/operator must provide information and data and may consult with
EPA about the need to prepare an SPCC Plan, or applicable part.
(§112.1(f)(2))
RA makes a final determination regarding whether the owner/operator is
required to prepare and implement an SPCC Plan, or applicable part.
(§112.1(f)(3))
Owner/operator must prepare the Plan, or applicable part. (§112.1(f)(4))
Owner/operator must implement the Plan, or applicable part.
(§112.1(f)(4))
Appeals
Within 30 days of receipt of final
determination that facility needs a Plan
Within 60 days of receiving the appeal or
additional information submitted by
owner/operator
Owner/operator may appeal final determination to the Administrator of
EPA (and send a copy to the RA). (§112.1(f)(5))
The Administrator renders a decision on the appeal. (§112.1(f)(5))
The EPA inspector plays an important role in assisting the RA in determining applicability. For example,
an inspector may initially alert the RA of the need for an otherwise exempt facility to have an SPCC Plan. This
may result from an inspection prompted by a citizen complaint or state referral, an oil spill, or awareness of
other conditions that warrant closer examination. Following an RA determination of the need for an SPCC Plan,
the EPA inspector may perform a targeted inspection of the
subject facility to verify compliance with SPCC
requirements.
2.10 SPCC Applicability for Different
Types of Containers
2.10.1 Bulk Storage Container
A bulk storage container, as defined in §112.2, with
a capacity of 55 U.S. gallons or greater, must follow specific
requirements, as described under §§112.8(c), 112.9(c), and
§112.2
Bulk storage container means any container used
to store oil. These containers are used for
purposes including, but not limited to, the
storage of oil prior to use, while being used, or
prior to further distribution in commerce. Oil-
filled electrical, operating, or manufacturing
equipment is not a bulk storage container.
Note: The above text is an excerpt of the SPCC rule. Refer
to 40 CFR part 112 for the full text of the rule. Emphasis
added.
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112.12(c) for onshore facilities. Examples of these requirements include, but are not limited to, secondary
containment and fail-safe engineering (such as high level alarms), inspections, and testing.
2.10.2 Double-walled or Vaulted Tanks or Containers
Double-walled tanks are essentially a tank within another tank, equipped with an interstitial (i.e.,
annular) space and constructed in accordance with industry standards. The inner tank serves as the primary oil
storage container while the outer tank serves as secondary containment. The outer tank of a double-walled tank
may provide adequate secondary containment for discharges resulting from leaks or ruptures of the entire
capacity of the inner storage tank.
The term "vaulted tank" has been used to describe both double-walled tanks (especially those with a
concrete outer shell) and tanks inside underground vaults, rooms, or crawl spaces. Both double-walled tanks
and vaulted tanks are bulk storage containers under the SPCC rule. For more information on how double-walled
tanks comply with the secondary containment and inspection requirements of the SPCC rule see Chapter 4:
Secondary Containment and Impracticability and Chapter 7: Inspection, Evaluation, and Testing.
2.10.3 Oil-filled Equipment
The definition of bulk storage container in §112.2 specifically excludes oil-filled electrical, operating, and
manufacturing equipment ("oil-filled equipment"). Therefore, oil-filled equipment is not subject to the bulk
storage container requirements in §§112.8(c), 112.9(c), and 112.12(c). However, oil-filled equipment must meet
the general requirements of §112.7. See generally 67 FR 47054-47055, July 17, 2002.
While the integrity testing requirements of §§112.8(c)(6) and 112.12(c)(6) are only applicable to bulk
storage containers, EPA believes it is good engineering practice to have some form of visual inspection or
monitoring for this oil-filled equipment to prevent discharges as described in §112.l(b). For example, it is a
challenge to comply with security requirements under §112.7(g) and countermeasures for discharge discovery
under §112.7(a)(3)(iv)) without some form of inspection or monitoring program. Additionally, inspection and/or
monitoring should be part of an effective contingency plan when secondary containment for this equipment is
impracticable.
2.10.4 Oil-filled Operational Equipment
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"Oil-filled operational equipment" is defined under §112.2 as equipment that includes an oil storage
container (or multiple containers) in which the oil is present solely to support the function of the apparatus or
the device. Oil-filled operational equipment is not considered a bulk storage container, and does not include oil-
filled manufacturing equipment (flow-through process).
Examples of oil-filled operational equipment include,
but are not limited to, hydraulic systems, lubricating systems
(e.g., those for pumps, compressors and other rotating
equipment, including pumpjack lubrication systems), gear
boxes, machining coolant systems, heat transfer systems,
transformers, circuit breakers, electrical switches, wind
turbines, and other systems containing oil solely to enable
the operation of the device (§112.2). When piping is intrinsic
to the oil-filled operational equipment in a closed loop
system, i.e., inherent to the equipment and used solely to
facilitate operation of the device (e.g., for lubrication), then
EPA considers the piping to be a component of the oil-filled
operational equipment. However, piping not intrinsic to the
operational equipment (e.g., flowlines, transfer piping or
piping associated with a process) is not considered to be part
of the oil-filled operational equipment.
§112.2
Oil-filled operational equipment means
equipment that includes an oil storage container
(or multiple containers) in which the oil is
present solely to support the function of the
apparatus or the device. Oil-filled operational
equipment is not considered a bulk storage
container, and does not include oil-filled
manufacturing equipment (flow-through
process). Examples of oil-filled operational
equipment include, but are not limited to,
hydraulic systems, lubricating systems (e.g.,
those for pumps, compressors and other rotating
equipment, including pumpjack lubrication
systems), gear boxes, machining coolant systems,
heat transfer systems, transformers, circuit
breakers, electrical switches, and other systems
containing oil solely to enable the operation of
the device.
Note: The above text is an excerpt of the SPCC rule. Refer
to 40 CFR part 112 for the full text of the rule.
Under §112.7(k), the owner or operator of a facility
with oil-filled operational equipment that meets specific
qualification criteria may choose to implement the alternate
requirements for qualified oil-filled operational equipment
in lieu of the general secondary containment required in
§112.7(c). Chapter 4: Secondary Containment and Impracticability (Section 4.2.1) provides more information
about this option.
2.10.5 Oil-filled Manufacturing Equipment
Oil-filled manufacturing equipment is distinct from bulk storage containers in its purpose. Oil-filled
manufacturing equipment stores oil only as an ancillary element of performing a mechanical or chemical
operation to create or modify an intermediate or finished product. Examples of oil-filled manufacturing
equipment may include reaction vessels, fermentors, high pressure vessels, mixing tanks, dryers, heat
exchangers, and distillation columns. Under the SPCC rule, flow-through process vessels are generally
considered oil-filled manufacturing equipment since they are not intended to store oil.59 Additionally, there may
The U.S. Occupational Safety and Health Administration (OSHA)'s Process Safety Management (PSM) regulation (29 CFR
1910.119) considers a single process "any group of vessels which are interconnected and separate vessels which are located
such that a highly hazardous chemical could be involved in a potential release." The PSM definition of process includes storage
tanks, while the SPCC rule considers storage tanks as bulk storage containers and not manufacturing equipment.
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be oil-filled operational equipment (e.g., a hydraulic unit) at this type of facility to support the manufacturing
equipment (see generally 67 FR 47080, July 17. 2002). The PE reviewing and certifying the SPCC Plan should be
familiar with processes taking place at the facility and should therefore determine whether a given process
vessel is considered a bulk storage container or oil-filled manufacturing equipment.
In cases where a container is used for the static storage of oil within a manufacturing or processing area,
the PE may determine that the container is in fact a bulk storage container. Examples of oil storage within
manufacturing areas include:
• Storing an intermediate product for an extended period of time in a continuous or batch
process;
• Storing a raw product prior to use in a continuous or batch process; and
• Storing a final product after a continuous or batch process.
Storage tanks and containers located at the beginning or end of a process and used to store feedstock or
finished products generally are considered bulk storage containers. In cases where oil storage is incidental to the
manufacturing activity or process (e.g., where it is being transformed in a flow-through process vessel) the Plan
preparer may determine that the container is part of the manufacturing equipment.
Oil-filled manufacturing equipment is inherently more complicated than oil-filled operational equipment
because it typically involves a flow-through process and is commonly interconnected through piping. Oil-filled
manufacturing equipment is subject to the general SPCC requirements under §112.7, including a demonstration
of impracticability under §112.7(d) if the SPCC Plan does not provide for general secondary containment as
required by §112.7(c). (71 FR 77266, December 26, 2006).
2.10.6 Oil-powered Generators ("Gen-sets")
Oil powered generators are commonly referred to as "gen-sets." Gen-sets are a combination of oil-filled
operational equipment and a bulk oil storage container. The oil that is consumed to generate electricity is not
inherent to the device and is stored in a bulk storage container, which requires transfers of oil because oil is
consumed in order to generate electricity. Therefore, although gen-sets include oil-filled operational equipment,
such as the lubrication oil reservoir, gen-sets, as a whole unit, do not meet the definition of oil-filled operational
equipment.
Newer designs of gen-sets provide for a double-walled tank for the bulk oil storage container. This type
of design may meet the sized and general containment requirements of the SPCC rule (112.8(c)(2), 112.8(c)(ll)
and 112.7(c)) for the bulk storage container, however, this does not address secondary containment for the oil-
filled operational equipment on the gen-set. To address the oil-filled operational equipment on these gen-sets,
the facility owner/operator can provide secondary containment for the typical failure mode and most likely
quantity of oil that would be discharged from the oil-filled operational equipment on the gen-set (in accordance
with §112.7(c)) or provide alternative measures as provided for qualified oil-filled operational equipment in
§112.7(k).
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When it is impracticable to provide appropriate secondary containment for gen-sets (for either the bulk
storage containers or oil-filled operational equipment of the gen-set), a PE can make a determination of
impracticability in accordance with §112.7(d); and can develop a contingency plan following the provisions of 40
CFR part 109 and provide a written commitment of manpower, equipment, and materials to expeditiously
control and remove any quantity of oil discharged that may be harmful.
2.10.7 Bulk Storage Containers at Tank Battery, Separation and Treating Areas
An oil production facility typically includes, at a minimum, a wellhead, a tank battery, and flowlines
connecting the wellhead to the tank battery and in some cases, the tank battery to an injection wellhead. The
tank battery includes separation and treating equipment, a crude oil or condensate container (oil stock tank),
drums of oil-based products and typically a produced water container, which receives both oil and produced
water from the separator. Bulk storage containers at oil production facilities must be:
• Compatible with the materials stored and condition of storage;
• Provided with secondary containment sized for the largest single container and sufficient
freeboard to contain precipitation for those containers at the tank battery, separation and
treating facility installations;
• Visually inspected periodically and upon a regular schedule for deterioration and maintenance
needs, including the foundation and support; and
• Engineered in accordance with good engineering practice to prevent discharges by:
1. Ensuring adequate container capacity to assure that a container will not overfill if a
pumper/gauger is delayed in making regularly scheduled rounds;
2. Providing overflow equalizing lines between containers so that a full container can overflow
to an adjacent container;
3. Providing adequate vacuum protection to prevent container collapse during a pipeline run
or other transfer of oil from the container; or
4. Providing high level sensors to generate and transmit an alarm signal to the computer
where the facility is subject to a computer production control system.
Alternative measures are provided for flow through process vessels and produced water containers in
lieu of the secondary containment and inspection requirements of §§112.9(c)(2) and (3) as described below.
Flow-through Process Vessels
Separation and treating installations at an oil production facility typically include equipment whose
primary purpose is to separate the well fluid into its marketable or waste fractions (e.g., oil, gas, produced
water, and solids), and to treat the crude oil as needed for further storage and shipping. Flow-through process
vessels, such as horizontal or vertical separation vessels (e.g., heater-treater, separator, gun barrel, free-water
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knockout, etc.), have the primary purpose of separating the oil from other fractions (water and/or gas) and
sending the fluid streams to the appropriate container.
Flow-through process vessels at separation and treatment installations are bulk storage containers and
count toward the facility aggregate oil storage capacity. They are also subject to general secondary containment
under §112.7(c) and the bulk storage container requirements of §112.9(c). The facility owner or operator must
either provide sized secondary containment for flow-through process vessels in accordance with §112.9(c)(2)
and inspect them following §112.9(c)(3) or comply with the general secondary containment under §112.7(c) and
alternative measures provided in §112.9(c)(5). More information about the secondary containment
requirements and the alternative compliance provision for flow-through process vessels can be found in Chapter
4: Secondary Containment and Impracticability (Section 4.8.1).
Produced Water Containers
Produced water containers are bulk storage containers typically located within the tank battery.
Produced water containers are part of the process that separates the oil from other fractions (water and/or gas).
Oil discharges to navigable waters or adjoining shorelines from an oil/water mixture in a produced water
container may cause harm. Such mixtures60 are regulated as oil under the SPCC rule. Therefore, the capacity of
produced water containers counts toward the facility aggregate oil storage capacity. Produced water containers
are subject to general secondary containment under §112.7(c) and the bulk storage container requirements in
§112.9(c). The facility owner or operator must either provide sized secondary containment for produced water
containers in accordance with §112.9(c)(2) and inspect them following §112.9(c)(3) or comply with general
secondary containment under §112.7(c) and alternative measures provided in §112.9(c)(6).
The alternative measures require that the facility owner or operator conduct visual inspections; perform
maintenance and corrective action; and remove, or stabilize
and remediate, oil discharges. Additionally a PE must
describe in the SPCC Plan and certify that a practice is
established that is designed to remove the amount of free-
phase oil from the produced water container on a scheduled
and routine basis. More information about the secondary
containment requirements and the alternative compliance
provision for produced water containers can be found in
Chapter 4: Secondary Containment and Impracticability
(Section 4.8.2).
§112.2
Produced water container means a storage
container at an oil production facility used to
store the produced water after initial oil/water
separation, and prior to reinjection, beneficial
reuse, discharge, or transfer for disposal.
Note: The above text is an excerpt of the SPCC rule. Refer
to 40 CFR part 112 for the full text of the rule.
Refers to mixtures in the produced water container.
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2.11 Determination of Applicability of Facility Response Plans
A portion of the SPCC-regulated community may also be required to prepare a Facility Response Plan
(FRP). According to §112.20, an owner or operator of a facility that has the potential to cause substantial harm
to the environment in the event of a discharge into or on navigable waters or adjoining shorelines must prepare
and submit an FRP. Owners or operators of SPCC facilities must document whether they meet the FRP
applicability criteria (40 CFR 112 Appendix CSection 3.0). Owners/operators may refer to the "Flowchart of
Criteria for Substantial Harm/' Attachment C-l to Appendix C of 40 CFR part 112, to determine whether they
need to prepare an FRP. The owner or operator must document his/her determination of whether the facility
has the potential to cause substantial harm by completing the Attachment C-ll form, "Certification of the
Applicability of the Substantial Harm Criteria/' and maintaining the certification at the facility. Attachments C-l
and C-ll are included in Appendix C of 40 CFR part 112 (also see Appendix H of this guidance).
2.12 Role of the EPA Inspector
The EPA inspector is responsible for gathering information and data to determine compliance with SPCC
requirements for those facilities that are regulated by the SPCC rule. During an SPCC inspection, EPA inspectors
will check that the measures described in the SPCC Plan are implemented at the facility and will fully document
all observations and other pertinent information. The EPA inspector will check that the Plan is kept at the facility
if it is attended more than four hours per day. The Summary of Applicability Flowchart and Applicability
Assessment Worksheet, provided as Figure 2-8 and Figure 2-9, are two quick references provided for
convenience to aid inspectors in assessing whether a facility is subject to the SPCC rule.
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Figure 2-8: Summary of applicability flowchart.
Is the facility, or part of the facility,
considered non-transportation-related?
NO
YES
T
Is the facility engaged in drilling, producing,
gathering, storing, processing, refining,
transferring, distributing, using, or
consuming oil?
I
YES
T
NO
Could the facility be expected to discharge
oil in quantities that may be harmful into
navigable waters or adjoining shorelines?
YES
T
NO
The facility IS NOT
subject to SPCC
Is the total aggregate capacity of
aboveground oil storage
containers greater than 1,320
gallons?
Do not include containers with a capacity less than
55 gallons, permanently closed containers, storage
containers used exclusively in wastewater
treatment, hot mix asphalt or hot-mix asphalt
containers, pesticide application equipment and
related mix containers, residential heating oil
containers, or milk and milk product containers.
OR
Is the total aggregate capacity of
completely buried storage tanks
greater than 42,000 gallons?
Do not include completely buried tanks subject to all
of the technical requirements of 40 CFR part 280 or
40 CFR part 281, underground oil storage tanks that
supply emergency diesel generators at a nuclear
power stations, permanently closed containers, and
single family residential heating oil containers.
NO
YES
f
The facility, or part of
the facility, IS subject
to SPCC
Definitions (40 CFR 112.2)
Completely buried tank: Any container completely below grade and covered with earth, sand, gravel, asphalt, or other material.
Containers in vaults, bunkered tanks, or partially buried tanks are considered aboveground storage containers for purposes of this
part,
Complex: A facility possessing a combination of transportation-related and non-transportation-related components that is subject
to the jurisdiction of more than one Federal agency under section 311(j) of the CWA.
Facility: Any mobile or fixed, onshore or offshore building, structure, installation, equipment, pipe or pipeline (other than a vessel
or a public vessel) used in oil well drilling operations, oil production, oil refining, oil storage, oil gathering, oil processing, oil
transfer, oil distribution, and oil waste treatment, or in which oil is used, as described in Appendix A to the SPCC rule. The
boundaries of a facility depend on several site-specific factors, including, but not limited to, the ownership or operation of
buildings, structures, and equipment on the same site and the types of activity at the site.
Permanently closed: Any container or facility for which: (1) All liquid and sludge has been removed from each container and
connecting line; and (2) All connecting lines and piping have been disconnected from the container and blanked off, all valves
(except for ventilation valves) have been closed and locked, and conspicuous signs have been posted on each container stating
that it is a permanently closed container and noting the date of closure.
Storage capacity: Shell capacity of the container.
The intent of this flowchart is to show the general principles of applicability. Inspectors should always consult the Code of Federal
Regulations and applicable MOUs.
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Figure 2-9: Applicability assessment worksheet.
1 Is the facility or part of the facility considered non-transportation-related and engaged in one of the following
activities? (Refer to Section 2.3 of this chapter.)
Drilling, producing, gathering, storing, processing, refining, transferring, distributing, using, or consuming oil.
D Yes. Go to question 2.
D No. The facility is not subject to the SPCC rule.
2 Could the facility reasonably be expected to discharge oil in quantities that may be harmful into navigable waters or
adjoining shorelines? (Refer to Section 2.6 of this chapter.)
Note: This determination must be based solely upon consideration of the geographical and location aspects of the facility (such as proximity to
navigable waters or adjoining shorelines, land contour, drainage, etc.) and must exclude consideration of manmade features such as dikes,
equipment or other structures, which may serve to restrain, hinder, contain, or otherwise prevent a discharge.
D Yes. Go to question 3a.
D No. The facility is not subject to the SPCC rule.
3a Is the total aggregate capacity of aboveground oil storage containers greater than 1,320 U.S. gallons? (Refer to
Sections 2.7 and 2.8 of this chapter.)
Note: Exclude containers less than 55 gallons, permanently closed containers, motive power containers, storage containers used exclusively in
wastewater treatment, hot-mix asphalt containers, pesticide application equipment and related mix containers, single-family residential heating oil
containers, milk and milk product containers, and underground storage tanks that supply emergency diesel generators at nuclear power stations.
D Yes. The facility is subject to the SPCC rule.
D No. Go to question 3b.
3b Is the total aggregate capacity of completely buried storage tanks greater than 42,000 U.S. gallons? (Refer to Sections
2.7 and 2.8 of this chapter.)
Note: Do not include completely buried tanks subject to all technical requirements of 40 CFR part 280 or 281, permanently closed containers, single-
family residential heating oil containers, or underground storage tanks that supply emergency diesel generators at nuclear power stations.
D Yes. The facility is subject to the SPCC rule.
D No. The facility is not subject to the SPCC rule.
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Chapters Environmental Equivalence
3.1 Introduction
The environmental equivalence provision, contained in §112.7(a)(2), allows for deviations from specific
requirements of the SPCC rule, as long as the alternative measures provide equivalent environmental
protection. The environmental equivalence provision is a key mechanism of the performance-based SPCC rule.
This flexibility enables owners and operators of facilities to achieve environmental protection in a manner that
fits the facility's unique circumstances. It also allows owners and operators to adopt more protective industry
practices and technologies for their facilities as they become available.
The facility owner or operator is responsible for the selection, documentation in the SPCC Plan, and
implementation in the field of SPCC measures, including any environmentally equivalent measures. However, a
Professional Engineer (PE), when certifying a Plan as per §112.3(d) or §112.6(b)(4), must verify that the Plan (and
any alternative methods) are in accordance with good engineering practice, including consideration of
applicable industry standards. These alternative methods must also provide environmental protection
equivalent to the provisions described in the SPCC rule. Because the expertise of a trained professional is
important in making site-specific equivalence determinations, owners or operators of qualified facilities (those
meeting the criteria in §112.3(g)) who choose to self-certify their SPCC Plans in lieu of PE-certification cannot
take advantage of the flexibility allowed by the environmental equivalence provision, unless the alternative
methods have been reviewed and certified in writing by a PE (§112.6(b)(3)(i)).61
In the SPCC context, equivalent environmental protection means an equal level of protection of
navigable waters and adjoining shorelines from oil pollution. This level of protection can be achieved in various
ways, but a facility may not rely solely on measures that are required by other sections of the rule (e.g.,
implementing secondary containment) to provide environmentally equivalent protection. While environmental
equivalence need not be a mathematical equivalence, it must achieve the same desired outcome, though not
necessarily through the same mode of operation (see 67 FR 47095, July 17, 2002).
The reason for deviating from a requirement of the SPCC rule, as well as a detailed description of the
alternate method and how equivalent environmental protection will be achieved, must be stated in the SPCC
Plan, as required in §112.7(a)(2). Possible rationales for a deviation include the owner or operator's ability to
show that the particular requirement is inappropriate for the facility because of good engineering practice
considerations or other reasons, and that the owner/operator can achieve equivalent environmental protection
in an alternate manner. Thus, a requirement that may be essential for a facility storing gasoline may be less
appropriate for a facility storing hot asphalt cement, due to differences in the properties and behavior of the
For each alternative measure allowed under §112.7(a)(2), a qualified facility's Plan must be accompanied by a written
statement that states the reason for nonconformance and describes the alternative method and how it provides equivalent
environmental protection in accordance with §112.7(a)(2) (see §112.6(b)(3)(i)).
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two products, and the facility owner or operator may be able to implement equivalent environmental protection
through an alternate technology (see 67 FR 47094, 47095, July 17, 2002).
As mentioned above, a PE must review the selection of environmentally equivalent measures and certify
them as being consistent with good engineering practice (§112.3(d) or §112.6(b)(4)). The selection of alternative
measures may be based on various considerations, such as safety, cost, geographical constraints, the
appropriateness of a particular requirement based on site-specific considerations, or other factors consistent
with engineering principles. See Section 3.4.1 for a discussion on considering costs when choosing
environmentally equivalent measures.
Alternative measures, however, cannot rely solely on measures that are already required by other parts
of the rule because this would allow for approaches that provide a lesser degree of protection overall. For
instance, as EPA noted in a May 2004 letter to the Petroleum Marketers Association of America (PMAA), the
presence of sized secondary containment for bulk storage containers, which is required under §112.8(c) and
other relevant parts of the SPCC rule, does not provide, by itself, an environmentally equivalent alternative to
performing integrity testing of bulk storage containers.62 Secondary containment reduces the risk of a discharge
from primary containment (the container or tank) to navigable waters or adjoining shorelines and can increase
the effectiveness of another prevention or control measure. However, it does not serve the purpose of integrity
testing, which is to identify potential leaks or failure of the container before a discharge occurs.
The remainder of this chapter is organized as follows:
• Section 3.2 summarizes substantive SPCC requirements subject to the environmental
equivalence provision.
• Section 3.3 clarifies certain policy areas and provides examples of deviations based on the
implementation of environmentally equivalent alternatives.
• Section 3.4 describes the role of the EPA inspector in reviewing deviations based on
environmental equivalence.
3.2 Substantive Requirements Subject to the Environmental Equivalence
Provision
Section 112.7(a)(2) of the SPCC rule allows deviations for most technical elements of the rule (§§112.7
through 112.12), with the exception of the secondary containment requirements of §§112.7(c) and 112.7(h)(l),
and in relevant paragraphs of §§112.8, 112.9, 112.10, and 112.12. Chapter 4: Secondary Containment and
Impracticability discusses these secondary containment requirements in detail.
See EPA letter to Daniel Gilligan of PMAA, available in Appendix H of this guidance.
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§112.7(a)(2)
Comply with all applicable requirements listed in this part. Except as provided in §112.6, your Plan may deviate from
the requirements in paragraphs (g), (h)(2) and (3), and (i) of this section and the requirements in subparts B and C of
this part, except the secondary containment requirements in paragraphs (c) and (h)(l) of this section, and
§§112.8(c)(2), 112.8(c)(ll), 112.9(c)(2), 112.9(d)(3), 112.10(c), 112.12(c)(2), and 112.12(c)(ll), where applicable to a
specific facility, if you provide equivalent environmental protection by some other means of spill prevention, control,
orcountermeasure. Where your Plan does not conform to the applicable requirements in paragraphs (g), (h)(2) and
(3), and (i) of this section, or the requirements of subparts B and C of this part, except the secondary containment
requirements in paragraphs (c) and (h)(l) of this section, and §§112.8(c)(2), 112.8(c)(ll), 112.9(c)(2), 112.10(c),
112.12(c)(2), and 112.12(c)(ll) you must state the reasons for nonconformance in your Plan and describe in detail
alternate methods and how you will achieve equivalent environmental protection. If the Regional Administrator
determines that the measures described in your Plan do not provide equivalent environmental protection, he may
require that you amend your Plan, following the procedures in §112.4(d) and (e).
Note: The above text is an excerpt of theSPCC rule. Refer to 40 CFR part 112 for the full text of the rule. Emphasis Added.
Along with secondary containment requirements, the SPCC Plan cannot deviate from:
• Administrative provisions of the rule, such as applicability thresholds, exemptions, definitions
and procedures for developing, reviewing and implementing a Plan (§§112.1 through 112.5);
• Rule requirements for Tier I qualified facilities (§112.6(a));
• Alternate measures for secondary containment based on impracticability (§112.7(d)) or for oil-
filled operational equipment that meet the criteria in §112.7(k);
• Recordkeeping requirements (§112.7(e))—the SPCC rule already provides flexibility for
recordkeeping that allows records of inspections and tests be kept under usual and customary
business practices;
• Personnel training (§112.7(f)); and
• A discussion of conformance with any applicable, more stringent state rules (§112.7(j)).
Table 3-1 through Table 3-3 list the SPCC requirements eligible for consideration for environmental
equivalence.
Table 3-1: Requirements eligible for environmental equivalence at all facilities.
Provision
Security
Loading and unloading racks
Brittle fracture evaluation
Section(s)
112.7(g)
112.7(h)(2)andll2.7(h)(3)
112.7(i)
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Table 3-2: Requirements eligible for environmental equivalence at onshore facilities (excluding oil
production).
Provision
Section introduction63
Facility drainage/undiked areas
Type of bulk storage container
Drainage of diked areas
Corrosion protection of buried storage tanks
Integrity testing and/or container inspection
Monitoring internal heating coils
Engineering of bulk container installation
(overfill prevention)
Monitoring effluent treatment facilities
Correction of discharges and removal of oil in
diked areas
Piping
Section(s)
Petroleum Oils and
Non-Petroleum Oils
112.8(a)
112.8(b)
112.8(c)(l)
112.8(c)(3)
112.8(c)(4) and 112.8(c)(5)
112.8(c)(6)
112.8(c)(7)
112.8(c)(8)
112.8(c)(9)
112.8(c)(10)
112.8(d)
Animal Fats and
Vegetable Oils
112.12(a)
112.12(b)
112.12(c)(l)
112.12(c)(3)
112.12(c)(4)andll2.12(c)(5)
112.12(c)(6)
112.12(c)(7)
112.12(c)(8)
112.12(c)(9)
112.12(c)(10)
112.12(d)
This is an administrative provision to indicate that both the general requirements of §112.7 and the requirements for onshore
facilities in either §§112.8 or 112.12 apply. When meeting the general requirements of §112.7, environmental equivalence
applies only to the §§112.7(g), (h)(2), (h)(3), and (i) provisions as described in §112.7(a)(2). The availability of environmental
equivalence for §112.8(a) and 112.12(a) does not change how environmental equivalence applies in §112.7.
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Table 3-3: Requirements eligible for environmental equivalence at onshore and offshore oil production,
drilling, and workover facilities.
Facility Type/Provision
Section(s)64
Onshore oil production facilities
Section introduction
Facility drainage
Type of bulk storage container
Container inspection
Engineering of bulk container installation (overfill prevention)
Alternative measures for flow-through process vessels
Alternative measures for produced water containers
Monitoring disposal facilities
Piping
112.9(a)
112.9(b)
112.9(c)(l)
112.9(c)(3)
112.9(c)(4)
112.9(c)(5)
112.9(c)(6)
112.9(d)(2)
112.9(d)(l) and 112.9(d)(4)
Onshore oil drilling and workover facilities
Section introduction
Facility drainage (rig position)
Blowout prevention and well control system
112.10(a)
112.10(b)
112.10(d)
Offshore oil drilling, production, or workover facilities
Drainage, container, blowout prevention, and piping requirements
112.11(a) through 112.11(p)
3.3 Policy Issues Addressed by Environmental Equivalence
This section provides additional guidance on environmentally equivalent measures for specific
requirements about which the regulated community has raised questions. The examples discussed below are
meant to clarify selected rule provisions and to illustrate how deviations based on environmentally equivalent
alternatives may be implemented; other circumstances not discussed here may also be addressed through the
use of environmentally equivalent measures. The examples in this section address environmental equivalence as
it relates to specific major rule provisions, including:
Sections 112.9(a), 112.10(a) and 112.11(a) are administrative provisions to indicate that both the general requirements of
§112.7 and the requirements for facilities in §112.9,112.10 or 112.11 apply. When meeting the general requirements of
§112.7, environmental equivalence applies only to the §§112.7(g), (h)(2), (h)(3), and (i) provisions as described in §112.7(a)(2).
The availability of environmental equivalence for §§112.9(a), 112.10(a) and 112.11(a) does not change how environmental
equivalence applies in §112.7.
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• Facility Drainage (Section 3.3.1);
• Corrosion Protection and Leak Testing of Completely Buried Metallic Storage Tanks (Section
3.3.2);
• Overfill Prevention (Section 3.3.3);
• Facility Transfer Operations, Pumping, and Facility Process Requirements (Section 3.3.4);
• Flowline/lntra-Facility Gathering Line Maintenance Program (Section 3.3.5);
• Security (Excluding Oil Production Facilities)(5ecfr'on 3.3.6);
• Integrity Testing and Inspection Requirements for Bulk Storage Containers at Onshore Facilities
(Section 3.3.7); and
• Alternative Measures for Containers at Oil Production Facilities (Section 3.3.8).
3.3.1 Facility Drainage
Section 112.8(b) describes facility drainage provisions for onshore facilities that handle petroleum oils
and non-petroleum oils other than animal fats and/or vegetable oils. Section 112.12(b) provides the
corresponding requirements for facilities that handle animal fats and/or vegetable oils. The description of the
design capacity of facility drainage systems is also addressed under §§112.7(a)(3) and 112.7(b).
The objective of these requirements is to provide design specifications for drainage systems used as a
means of secondary containment to prevent oil from escaping the facility and becoming a discharge as
described in §112.l(b). Note that the secondary containment requirements themselves are not subject to the
environmental equivalence provision as described in 112.7(a)(2); deviations from secondary containment
requirements must instead be based on an impracticability determination (see Chapter 4: Secondary
Containment and Impracticability).
Diked Storage Area Provisions
Sections 112.8(b)(l) and (b)(2) (and §112.12(b)(l) and (b)(2)) specify requirements for the design of
drainage systems for dikes used as a means of secondary containment. Under §112.8(b)(l) and (b)(2) (and
§112.12(b)(l) and (b)(2)), the SPCC regulation requires that when the facility owner/operator uses valves to
drain a dike or berm, the valves must be of manual, open-and-closed design and not a flapper design, unless the
facility drainage system is equipped to control oil discharges. The facility owner or operator, and the PE
certifying a Plan, may consider alternative technologies specifically engineered to prevent oil from escaping the
facility containment and drainage control system, while normally allowing drainage of uncontaminated water.
For example, certain valves are engineered to automatically shut off upon detecting oil. Material included within
the device expands upon contact with oil, effectively plugging the drainage system. The valve is not actuated per
se, but rather the device plugs the drainage system upon contact with oil. These types of systems have been
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installed at electrical substations, for example, to drain uncontaminated rainwater under normal conditions,
while also preventing oil from escaping the containment system in the event of a discharge from transformers or
other oil-filled electrical equipment. When implemented and maintained properly, such systems may provide
environmental protection equivalent to using a manually operated valve and visually monitoring discharge from
dikes.
To be most effective, however, EPA recommends that the systems have a fail-safe design to
automatically prevent any oil from escaping the containment area in the event of a system malfunction. The PE
certifying the Plan should verify the adequacy of the system to prevent oil discharges to navigable waters or
adjoining shorelines, considering factors such as the type of oil and its compatibility with the system selected,
the amount of precipitation, maintenance requirements, flow paths, and proximity to navigable waters. The
SPCC Plan should also describe procedures for maintaining these systems and verifying their effectiveness by
routine inspections and inspections following heavy rain events to ensure that they are operational. See Chapter
4: Secondary Containment and Impracticability for more details on secondary containment requirements.
Undiked Storage Area Provisions
Sections 112.8(b)(3) and (b)(4) (and §112.12(b)(3) and (b)(4)) specify performance requirements for
systems used to drain undiked areas with the potential for a discharge. These provisions apply only when the
facility owner/operator chooses to use a facility drainage system to meet general secondary containment
requirements under §112.7(c) or a more specific containment requirement under §§112.7(h)(l), 112.8(c)(2) or
112.12(c)(2). Where the facility drainage cannot be engineered as described in §112.8(b)(3), the SPCC rule
requires that the facility owner/operator equip the final discharge points of all ditches within the facility with a
diversion system that would, in the event of a discharge, retain the oil at the facility as described in §112.8(b)(4).
Requirements in §112.8(b)(5) pertain specifically to engineering multiple treatment units for these drainage
systems.
For parts of a facility that could be involved in a discharge and where secondary containment
requirements are met through the use of a drainage system rather than a dike or berm, the SPCC rule generally
requires facility drainage to flow into a system (e.g., a pond, lagoon, or catchment basin) designed to retain the
oil or return it to the facility. For example, an oil/water separator may be used as part of the containment
system; however, an environmental equivalent deviation for drainage controls for the separator must be
provided.
Other measures that are based on good engineering practice may be implemented to achieve the
drainage control objective, subject to PE review and certification. For example, directing undiked facility
drainage into an impoundment system located within a neighboring facility may be considered equivalent to
keeping it within the facility's confines (as required in §112.8(b)(4)) if the neighboring facility owner has agreed
to allow use of the impoundment and as long as the impoundment is designed and managed such that it is
capable of handling a potential discharge from both facilities before it becomes a discharge as described in
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Drainage at Oil Production Facilities65
Similar deviations from SPCC drainage control
requirements are possible for other types of facilities.
Section 112.9(b), for example, outlines drainage
requirements for tank batteries and separation and treating
areas at oil production facilities. They include sealing dike
drains or drains of equivalent measures required under
§112.7(c)(l) at all times except when draining
uncontaminated rainwater. The PE may specify alternative
measures (e.g., the technology used at electrical
substations as described above that expands upon contact
with oil and plugs the drainage system) that would provide
equivalent environmental protection by retaining oil within
the diked area in the event of a discharge.66 The Plan must
describe the measure in detail and discuss how it provides
environmentally equivalent protection when implemented
in the field, as required by §112.7(a)(2).
Wherever a facility owner or operator chooses to
deviate from the drainage control provisions by using an
alternative measure that provides equivalent
environmental protection, the SPCC Plan must state the
reasons for nonconformance and describe the alternative measure in detail, including how it achieves
equivalent environmental protection when implemented (§112.7(a)(2)).
3.3.2 Corrosion Protection and Leak Testing of Completely Buried Metallic Storage Tanks
Facility owners or operators must protect buried
metallic storage tanks (containers) installed on or after
January 10, 1974 from corrosion and regularly perform leak
test on the tanks. In order to comply with the corrosion
protection requirement of §§112.8(c)(4) and 112.12(c)(4),
owners and operators of completely buried metallic storage
tanks may want to consider the requirements of Subpart B
of 40 CFR 280. This regulation includes design, construction
and installation requirements for underground storage
§112.9 (b)
Oil production facility drainage.
(1) At tank batteries and separation and treating
areas where there is a reasonable possibility of a
discharge as described in §112.l(b), close and seal
at all times drains of dikes or drains of equivalent
measures required under §112.7(c)(l), except
when draining uncontaminated rainwater. Prior to
drainage, you must inspect the diked area and take
action as provided in §112.8(c)(3)(ii), (iii), and (iv).
You must remove accumulated oil on the
rainwater and return it to storage or dispose of it
in accordance with legally approved methods.
(2) Inspect at regularly scheduled intervals field
drainage systems (such as drainage ditches or road
ditches), and oil traps, sumps, or skimmers, for an
accumulation of oil that may have resulted from
any small discharge. You must promptly remove
any accumulations of oil.
Note: The above text is an excerpt of the SPCC rule. Refer to
40 CFR part 112 for the full text of the rule.
§§112.8(c)(4) and 112.12(c)(4)
Protect any completely buried metallic storage
tank installed on or after January 10,1974 from
corrosion by coatings or cathodic protection
compatible with local soil conditions. You must
regularly leak test such completely buried metallic
storage tanks.
Note: The above text is an excerpt of the SPCC rule. Refer to
40 CFR part 112 for the full text of the rule.
These requirements also apply to wet gas production facilities (where oil condensate is produced).
See the above discussion in Diked Storage Area Provisions.
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tanks (USTs) including corrosion protection methods for new (see §280.20) and existing (see §280.21) UST
systems.
To comply with the leak testing requirements of §§112.8(c)(4) and 112.12(c)(4), a facility
owner/operator may consider the requirements of 40 CFR 280.43 which specify release detection methods for
petroleum UST systems that include tank tightness testing. Additionally, the Petroleum Equipment Institute (PEI)
RP1200 publication "Recommended Practices for the Testing and Verification of Spill, Overfill, Leak Detection
and Secondary Containment Equipment at UST Facilities" provides general guidelines for the inspection and
testing of leak detection, release prevention and overfill prevention equipment at UST facilities. These methods
may be appropriate to meet the SPCC leak testing requirements for buried metallic storage tank.
Tank tightness testing may be accomplished by several methods:67
• Pressure testing with inert gas such as nitrogen and checking the tank for loss of pressure. Loss
of pressure indicates a leak in the tank.68 Consult with the tank manufacturer for the
recommended test pressure.
• Chemical inoculant testing. A chemical inoculant is added to the product in the tank and
sampling ports are installed in the soil around the tank to check for the presence of the chemical
(which would indicate a leak in the tank).
• Volumetric testing. Volumetric testing involves measuring very precisely (in milliliters or
thousandths of an inch) the change in product level in a tank over time.
• For double-walled tanks, pressure testing or vacuum testing the interstitial space.
• Some automatic tank gauging systems are capable of meeting the regulatory performance
requirements for tank tightness testing and can be considered as an equivalent method.
Rather than leak test the completely buried metallic tank, a PE may substitute elements required under
40 CFR part 280 or a state program approved under 40 CFR part 281 to detect a release from the completely
buried tank in accordance with the environmental equivalence provision in §112.7(a)(2). For example, a PE may
determine that use of a continuous leak detection system in combination with the use of an Automatic Tank
Gauge (ATG) is environmentally equivalent to the regular leak testing69 requirements in §§112.8(c)(4) and
112.12(c)(4).70
The tank must be isolated from piping connections when performing tank tightness tests. Check with state regulatory
authorities for state approved leak testing methods. For more information on tank tightness testing see
http://www.epa.gov/oust/ustsystm/inventor.htm.
CAUTION: Do not use compressed air to pressure test tanks that contain or contained flammable or combustible liquids unless
the tank is first purged and cleaned.
EPA stated that leak testing ensures the liquid tightness of a container and whether it may discharge oil (67 FR 47118, July 17.
2002).
A PE may want to design such an environmentally equivalent measure in accordance with 40 CFR part 280 or a state program
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v^ FYI - Cathodic protection of buried tanks
40 CFR 280.20 and 280.21 identify methods for cathodically protecting buried tanks. These methods may be
considered when developing corrosion and cathodic protection protocols for completely buried metallic storage tanks
subject to the SPCC rule. The following are some examples of codes and standards for protecting metallic tanks from
corrosion that may also be considered:
• Steel Tank Institute (STI) "Specification for STI-P3 System of External Corrosion Protection of Underground
Steel Storage Tanks"
• Underwriters Laboratories (UL) Standard 1746, "Corrosion Protection Systems for Underground Storage
Tanks"
• Underwriters Laboratories of Canada (ULC) CAN4-S603-M85, "Standard for Steel Underground Tanks for
Flammable and Combustible Liquids," CAN4-G03.1-M85, "Standard for Galvanic Corrosion Protection Systems
for Underground Tanks for Flammable and Combustible Liquids," and CAN4-S631-M84, "Isolating Bushings for
Steel Underground Tanks Protected with Coatings and Galvanic Systems"
• National Association of Corrosion Engineers (NACE) Standard RP-02-85, "Control of External Corrosion on
Metallic Buried, Partially Buried, or Submerged Liquid Storage Systems," and Underwriters Laboratories
Standard 58, "Standard for Steel Underground Tanks for Flammable and Combustible Liquids"
3.3.3 Overfill Prevention
Sections 112.8(c)(8) and 112.12(c)(8) require that each container installation is engineered to avoid
discharges during filling activities. The selection of an overfill prevention system should be based on good
engineering practice (see §112.7 introductory paragraph), considering methods that are appropriate for the
types of activities and circumstances. Regular tests of liquid level sensing devices to ensure proper operation
should be conducted on a routine basis.
approved under 40 CFR part 281, as a demonstration of good engineering practice.
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§112.8(c)(8) and 112.12(c)(8)
Engineer or update each container installation in accordance with good engineering practice to avoid discharges. You
must provide at least one of the following devices:
(i) High liquid level alarms with an audible or visual signal at a constantly attended operation or surveillance
station. In smaller facilities an audible air vent may suffice.
(ii) High liquid level pump cutoff devices set to stop flow at a predetermined container content level.
(iii) Direct audible or code signal communication between the container gauger and the pumping station.
(iv) A fast response system for determining the liquid level of each bulk storage container such as digital
computers, telepulse, or direct vision gauges. If you use this alternative, a person must be present to monitor
gauges and the overall filling of bulk storage containers.
(v) You must regularly test liquid level sensing devices to ensure proper operation.
Note: The above text is an excerpt of the SPCC rule. Refer to 40 CFR part 112 for the full text of the rule.
While an audible/visual alarm or fast-response system may be appropriate for a large, stationary storage
tank, a simpler overfill prevention procedure may be appropriate for a small container (e.g., relatively small
containers that can be readily monitored) when the filling procedure is documented in the SPCC Plan. A
procedure for smaller containers that ensures communication between the container gauger and the pumper, is
in accordance with §§112.8(c)(8)(iii) and 112.12(c)(8)(iii) and therefore does not require an environmental
equivalence determination.
The procedure must be adequate to prevent a discharge by ensuring communication between the
container gauger and the pumper. The development of this procedure should consider factors such as the
container size; inventory control procedures; filling rate; ability of the person performing the filling operation to
continuously monitor product level in the container; reaction time; capacity of the secondary containment
and/or catchment basin; and proximity of the tank to floor drains, sumps, and other means through which oil
could escape. Personnel should be able to demonstrate an understanding of the procedures and proper field
implementation. As part of the description, the Plan preparer may reference other facility documents in the
SPCC Plan that discuss relevant established Best Management Practices (BMPs), pollution prevention training,
and/or procedures in more detail, rather than restating this information in the SPCC Plan. Additional supporting
documentation should be on-site and available for review during an inspection.
For example, a filling procedure for a small container may involve:
• Verifying that the container has sufficient free capacity (i.e., ullage of the container) for the
transfer,
• Visually monitoring the product level throughout the transfer operation, and
• Posting the detailed written procedure described in the SPCC Plan next to the container/fill pipe.
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Many facilities have smaller storage containers such as 55-gallon drums, Intermediate Bulk Containers
(IBCs) and totes that are never filled at the facility. Since these containers are never filled, the overfill
requirements do not apply and there is no need to document environmental equivalence deviations for these
containers.
Where a facility owner or operator chooses to deviate from the overfill prevention provisions by using
an alternative measure that provides environmentally equivalent protection, the SPCC Plan must state the the
reasons for nonconformance and describe the alternative measure in detail, including how it achieves
equivalent environmental protection when implemented (§112.7(a)(2)).
v^ FYI - Preventing container overfills
In order to prevent container overfills consider the following:
1) Training individuals involved in the transfer operations;
2) Communicating facility oil transfer procedures to personnel;
3) Ensuring transfer operations are appropriately monitored;
4) Ensuring tank gages and overfill alarms are operational, calibrated and routinely tested;
5) Verifying that the container has sufficient available capacity;
6) Monitoring the product level throughout the operation; and
7) Providing response equipment that is easily accessible from the transfer location
3.3.4 Facility Transfer Operations, Pumping, and Facility Process Requirements
Requirements that apply to valves, appurtenances, piping, and transfer operations at onshore facilities
that handle petroleum oils are described in §112.8(d). Similar requirements are described in §112.12(d) for
piping at onshore facilities that handle animal fats and/or vegetable oils.
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§§112.8(d) and 112.12(d) - Facility-transfer operations, pumping, and facility process.
(1) Provide buried piping that is installed or replaced on or after August 16, 2002, with a protective wrapping and
coating. You must also cathodically protect such buried piping installations or otherwise satisfy the corrosion
protection standards for piping in part 280 of this chapter or a State program approved under part 281 of this
chapter. If a section of buried line is exposed for any reason, you must carefully inspect it for deterioration. If
you find corrosion damage, you must undertake additional examination and corrective action as indicated by
the magnitude of the damage.
(2) Cap or blank-flange the terminal connection at the transfer point and mark it as to origin when piping is not in
service or is in standby service for an extended time.
(3) Properly design pipe support to minimize abrasion and corrosion and allow for expansion and contraction.
(4) Regularly inspect all aboveground valves, piping, and appurtenances. During the inspection you must assess the
general condition of items, such as flange joints, expansion joints, valve glands and bodies, catch pans, pipeline
supports, locking of valves, and metal surfaces. You must also conduct integrity and leak testing of buried
piping at the time of installation, modification, construction, relocation, or replacement.
(5) Warn all vehicles entering the facility to be sure that no vehicle will endanger aboveground piping or other oil
transfer operations.
NOTE: The above text is an excerpt of the SPCC rule. Refer to 40 CFR part 112 for the full text of the rule.
These provisions of the SPCC rule require that owners and operators of facilities generally protect buried
piping against corrosion; cap or blank-flange the terminal connection of piping that is not in service; design pipe
supports to minimize abrasion and corrosion and allow for expansion and contraction; regularly inspect all
aboveground valves, piping, and appurtenances; and take corrective action when corrosion damage is found.
The rule also requires integrity and leak testing of buried piping at the time of installation, modification,
construction, relocation, or replacement. Finally, the rule requires warning all vehicles entering the facility to
ensure that they will not endanger aboveground piping (or other oil transfer operations). Types of facility piping
addressed by this provision include, but are not limited to:
• Transfer piping to and from bulk storage containers, both aboveground and buried;
• Transfer piping associated with manufacturing equipment, both aboveground and buried; and
• Piping associated with oil-filled operational and manufacturing equipment.
A 1987 EPA study into the causes of oil releases indicates that the operational piping portion of an
underground storage tank system is twice as likely as the tank portion to be the source of a discharge.71 Piping
failures are caused equally by poor workmanship, improper installation, corrosion, or other forms of
deterioration. The SPCC piping requirements aim to prevent oil discharges from aboveground or buried piping
due to corrosion, operational accidents, or collision. Accordingly, equivalent environmental protection may be
"Causes of Release from Underground Storage Tank Systems: Attachments," September 1987, EPA 510-R-92-702.
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achieved through alternative measures that reduce or eliminate the risks of corrosion to buried piping or the risk
of damage to aboveground piping.
The following sections discuss examples of environmentally equivalent deviations from piping
requirements.
Protecting Buried Piping from Corrosion Damage
A PE must certify that the Plan has been prepared in accordance with good engineering practices,
including consideration of applicable industry standards. Similarly, an owner/operator self-certifies that the Plan
has been prepared in accordance with accepted and sound industry practices. Therefore, the Plan preparer may
want to consult a qualified corrosion professional when evaluating the adequacy of cathodic protection and
corrosion prevention systems at the facility. If the Plan preparer determines that cathodic protection of buried
piping installed on or after August 16, 2002 is not appropriate considering site-specific conditions, facility
configuration, and other engineering factors (e.g., where the installation of a corrosion system would accelerate
corrosion of existing unprotected equipment), then a PE may specify other measures to assess and ensure the
continued fitness-for-service of piping. For example, the owner or operator of a facility could, instead of
cathodically protecting underground piping, use double-wall piping combined with an interstitial leak detection
system (67 FR 47123, July 17, 2002). Cathodic protection averts discharges by preventing container corrosion,
whereas the alternative method of installing a leak detection system and double-wall piping averts discharges by
detecting and containing leakage so it may be addressed before it can become a discharge as described in
§112.l(b). As with any environmentally equivalent measure, this portion of the Plan must be certified by a PE.
Alternatively, the facility owner or operator may implement a comprehensive monitoring, detection,
and preventive maintenance program for piping and appurtenances as an alternative for cathodic protection to
detect and address potential discharges. The PE who certifies the Plan or this portion of it, should develop
and/or review such a program, which may combine inspection, monitoring and leak testing elements with
preventive maintenance, contingency measures, and recordkeeping. Examples of these elements are outlined
for piping systems in API Standard 570,72 "Piping Inspection Code: In-Service Inspection, Rating, Repair, and
Alteration of Piping Systems." Table 3-4 summarizes key elements of an API-570 inspection program when
evaluating buried piping that is not cathodically protected (refer to Chapter 7: Inspection, Evaluation, and
Testing for an overview of API-570). Such a program provides a means of assessing the suitability of piping to
contain oil and/or identifying potential failures prior to their occurrence.
API 570 Third Edition 2009
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Table 3-4: Summary of inspection and leak testing elements of an API-570 program for unprotected buried
piping - additional inspection and testing requirements are specified in API 570 (refer to the full
text of API 570 for details).
73
Inspection and Leak Testing
Elements
Above-grade Visual
Surveillance
Pipe-to-Soil Potential Survey
Pipe Coating Holiday* Survey
Soil Corrosivity
Cathodic Protection
External and Internal
Inspection Intervals
Leak Testing Intervals
Summary
Inspect the surface of the ground covering the piping for discoloration of the soil,
softening of asphalt pavement, formation of pools, bubbling water puddles, and
noticeable odor. The inspection should be performed at approximately six month
intervals and may be performed by the owner/operator.
Conduct pipe-to-soil potential survey along the pipe route to assess corrosion potential.
Excavate sites where active corrosion cells are located to determine the extent of
corrosion damage.
Conduct pipe coating holiday survey based on results of other evaluations.
Perform soil corrosivity evaluation at a five-year interval for piping buried in lengths
greater than 100 feet that is not cathodically protected.
Monitor at intervals in accordance with Section 10 of NACE RP016974 or API RP65175
when piping cathodically protected.
Determine external condition of buried piping that is not cathodically protected by either
pigging or by excavating according to frequency indicated in Table 5 of API-570. Adjust
inspection of buried piping based on results of inspections of above-grade portion.
Alternatively, or in addition to inspection, perform leak testing with pressure at least 10
percent greater than maximum operating pressure at an interval half the length of
intervals in API 570 Table 5 for buried piping that is not cathodically protected.
Alternatively, perform temperature-corrected volumetric or pressure test methods, use
acoustic emission examination, or addition of tracer fluid.
"Holiday" means any discontinuity, bare, or thin spot in a painted area.
Where a piping inspection and testing program is used to provide environmental protection equivalent
to cathodic protection, a PE will develop and/or review the scope and frequency of the program considering
industry standards when available,76 before certifying that the Plan is in accordance with good engineering
practice. Certain elements of a piping inspection and testing program (e.g., frequent leak testing of buried
piping) may be emphasized over others based on site-specific factors such as length of piping at the facility or
proximity to navigable waters or adjoining shorelines. Chapter 7: Inspection, Evaluation, and Testing references
API 570 Third Edition 2009
NACE SP0169-2007 (formerly RP0169), "Control of External Corrosion on Underground or Submerged Metallic Piping Systems"
Edition 2007 www.nace.org
API RP 651, "Cathodic Protection of Aboveground Petroleum Storage Tanks", Third Edition, 2007.
See PE attestation in §112.3(d)
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industry standards that specifically discuss leak testing, including API Recommended Practice 1110 - Pressure
Testing of Steel Pipelines for the Transportation of Gas, Petroleum Gas, Hazardous Liquids, Highly Volatile
Liquids or Carbon Dioxide. However, since leak testing only detects existing leaks, rather than preventing them,
good engineering practice may suggest that testing occur at a greater frequency than when other prevention
systems, such as cathodic protection and coatings, are in place. Accordingly, the PE who certifies the Plan will
determine the appropriate frequency of leak tests for buried piping after considering the other prevention and
detection measures incorporated into the inspection program.
If alternative measures are used to meet the SPCC corrosion protection requirements for buried piping,
§112.7(a)(2) requires that the Plan state the reasons for nonconformance, describe in detail the alternative
measures and explain how the alternative measures provide environmental protection equivalent to coating and
cathodically protecting new piping. In order to be considered equivalent environmental protection to cathodic
protection, a comprehensive inspection and preventive maintenance program needs to be implemented to
effectively detect and address piping deterioration before it can result in a discharge as described in §112.l(b).
The EPA inspector should verify that the alternative method is described in detail in the SPCC Plan and that the
Plan specifies the scope and frequency of tests and inspections and/or refers to the relevant industry standards,
as applicable. The EPA inspector should also review records that document these tests and inspections.
Preventing Physical Damage to Aboveground Piping/Transfer Operations
Warnings to vehicles entering the facility may be verbal, posted on signs, or by other appropriate
means. The Plan must describe how the warnings will be communicated and should include locations of signs
and information provided on the signs. When relying on verbal warnings, the Plan should describe information
provided as part of the verbal warnings and the procedure for issuing those warnings including personnel
responsible for providing the warnings.
Alternatively, protecting the equipment from the possibility of a collision by installing fencing, barriers,
curbing or other physical obstacles may provide equivalent environmental protection. The SPCC Plan must
document the method implemented at the facility to prevent physical damage to aboveground piping and
transfer operations, and if an alternative method is used, then it must be documented in accordance with
§112.7(a)(2).
3.3.5 Flowline/Intra-Facility Gathering Line Maintenance Program
The SPCC rule requires a flowline or intra-facility gathering line maintenance program, according to
§112.9(d)(4). A flowline or intra-facility gathering line maintenance program aims to manage oil production
operations in a manner that reduces the potential for a discharge from these piping systems. Common causes of
such discharges include mechanical damage (e.g., impact, rupture) and corrosion.
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§112.9(d)(4)
Prepare and implement a written program of flowline/intra-facility gathering line maintenance. The maintenance
program must address your procedures to:
(i) Ensure that flowlines and intra-facility gathering lines and associated valves and equipment are compatible with the
type of production fluids, their potential corrosivity, volume, and pressure, and other conditions expected in the
operational environment.
(ii) Visually inspect and/or test flowlines and intra-facility gathering lines and associated appurtenances on a periodic and
regular schedule for leaks, oil discharges, corrosion, or other conditions that could lead to a discharge as described in
§112.l(b). For flowlines and intra-facility gathering lines that are not provided with secondary containment in
accordance with §112.7(c), the frequency and type of testing must allow for the implementation of a contingency
plan as described under part 109 of this chapter.
(iii) Take corrective action or make repairs to any flowlines and intra-facility gathering lines and associated
appurtenances as indicated by regularly scheduled visual inspections, tests, or evidence of a discharge.
(iv) Promptly remove or initiate actions to stabilize and remediate any accumulations of oil discharges associated with
flowlines, intra-facility gathering lines, and associated appurtenances.
Note: The above text is an excerpt of the SPCC rule. Refer to 40 CFR part 112 for the full text of the rule.
An effective flowline maintenance program is necessary to detect a discharge in a timely manner so that
the oil discharge response operations described in the contingency plan may be implemented effectively. The
rule specifically requires a written maintenance program which addresses procedures to:
• Ensure that flowlines and intra-facility gathering lines and associated valves and equipment
are compatible with the type of production fluids, their potential corrosivity, volume, and
pressure, and other conditions expected in the operational environment. This preventative
measure is intended to help preserve the integrity of the lines and reduce the potential effects
of corrosion or other factors that may lead to a discharge.
• Visually inspect and/or test flowlines and intra-facility gathering lines and associated
appurtenances on a periodic and regular schedule for leaks, oil discharges, corrosion, or other
conditions that could lead to a discharge as described in §112.l(b). This measure is intended to
ensure that any discharges, potential problems or conditions related to the flowline/intra-facility
gathering lines that could lead to a discharge will be promptly discovered. When flowlines and
intra-facility gathering lines have no secondary containment, then the frequency and type of
testing must allow for the implementation of a contingency plan as described under 40 CFR part
109. An oil spill contingency plan cannot be effective unless a discharge is discovered in a timely
manner so that the oil response operations can be implemented as described in the contingency
plan. (See Chapter 7: Inspection, Evaluation, and Testing for more information on this inspection
requirement.)
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• Take corrective action or make repairs to any flowlines and intra-facility gathering lines and
associated appurtenances as indicated by regularly scheduled visual inspections, tests, or
evidence of a discharge. The results of the inspections or tests (as described above) will inform
the owner/operator of any corrections or repairs that need to be made. Corrective action is
necessary in order to prevent a discharge from occurring, as well as in response to a discharge.
This measure is intended to prevent discharges as described in §112.l(b) by ensuring that
flowlines and intra-facility gathering lines are well maintained and ensuring prompt corrective
actions or repairs in response to conditions found during the inspection/testing of the flowlines
and intra-facility gathering lines.
• Promptly remove or initiate actions to stabilize and remediate any accumulations of oil
discharges associated with flowlines, intra-facility gathering lines, and associated
appurtenances. Removing oil-contaminated soil is one method to prevent a discharge from
reaching navigable waters or adjoining shorelines. Disposal of oil must be in accordance with
applicable Federal, State, and local requirements; under §112.7(a)(3)(v), a facility owner or
operator is required to describe the methods of disposal of recovered materials in accordance
with applicable legal requirements. For the purposes of this provision, removal of recoverable
oil may be combined with physical, chemical, and/or biological treatment methods to address
any residual oil. These treatment methods must be consistent with other Federal, state or local
requirements as applicable, and must be properly managed to prevent a discharge as described
in §112.l(b). "Promptly remove" indicates that the owner or operator of the facility has both the
responsibility and flexibility to outline an inspection program under §112.9(d)(4)(ii) which puts
the timeframe for "prompt removal" in the context of the inspection frequency (73 FR 74276,
Decembers, 2008).
The facility owner or operator may deviate from the flowline and intra-facility gathering line
maintenance program requirements if an environmentally equivalent alternative measure is implemented in
accordance with §112.7(a)(2). The Plan preparer certifying the Plan will typically establish the scope and
frequency of inspections, tests, and preventive maintenance based on industry standards, manufacturer's
recommendations, and other sources of good engineering practice. There is currently no published industry
standard for a flowline or intra-facility gathering line maintenance program, however, a standard may be
developed in the future. If a future industry standard is
developed that meets all of the requirements described
in §112.9(d)(4), then the Plan preparer may follow that
standard when developing a flowline/intra-facility
gathering line program for the facility. If a future
standard does not address all of the SPCC rule
requirements, then a PE may need to make an
environmental equivalence determination. Chapter 7:
Inspection, Evaluation, and Testing refers to selected
1 Tip - Intra-facility gathering lines
As described in §112.1(d)(ll), intra-facility gathering
lines that are subject to DOT regulatory requirements
at 49 CFR part 192 (Transportation of Natural and
Other Gas by Pipeline) or part 195 (Transportation of
Hazardous Liquids by Pipeline) are exempt from the
SPCC rule.
See Chapter 2: SPCC Rule Applicability for more information.
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relevant industry standards that describe methods used to test the integrity of piping, such as API 57077 and
ASME B31.4. While these are not specific to flowlines and intra-facility gathering lines, they may serve as
guidance.
A PE may determine that state requirements governing flowlines and gathering lines are
environmentally equivalent to one or more of the SPCC flowline/intra-facility gathering line maintenance
requirements. If alternative measures are used to meet the SPCC flowline/intra-facility gathering line
maintenance program requirements in §112.9(d)(4), EPA requires that the Plan state the reasons for
nonconformance and explain how the alternative measures provide environmental protection equivalent to the
outlined procedures.
3.3.6 Security (Excluding Oil Production Facilities)
Section 112.7(g) of the SPCC rule outlines
security requirements for facilities. These requirements
are intended to prevent discharges of oil to navigable
waters or adjoining shorelines that could result from
acts of vandalism or other unauthorized access to oil
containers or equipment. Unlike other provisions under
§112.7, the security provisions in paragraph (g) do not
apply to oil production facilities.
§112.7(g) - Security (excluding oil production
facilities).
Describe in your Plan how you secure and control
access to the oil handling, processing and storage
areas; secure master flow and drain valves; prevent
unauthorized access to starter controls on oil pumps;
secure out-of service and loading/unloading
connections of oil pipelines; and address the
appropriateness of security lighting to both prevent
acts of vandalism and assist in the discovery of oil
discharges.
Note: The above text is an excerpt of the SPCC rule. Refer to 40
CFR part 112 for the full text of the rule.
Prior to December 2008, the security provision
of the SPCC rule required that the facility owner or
operator install security systems such as fencing, locks
and lighting to prevent unauthorized access to oil-
handling operations and controls. However, EPA
amended the facility security requirements to be more
performance-based and allow an owner or operator of a facility to tailor security measures to the facility's
specific characteristics and location (73 FR 74236, December 5, 2008). The security requirements remain subject
to the environmental equivalence provision, but given the increased flexibility, there may be limited instances
where a PE would determine that a deviation is necessary. Below we provide examples of how the revised
security requirements can be met.
A facility owner or operator may achieve the rule's security objectives by providing a description of the
security measures and how they are implemented at the facility. This description may include a discussion of
how measures employed by the facility help deter vandals and prevent unauthorized access to containers and
equipment that could be involved in an oil discharge. Measures that may be used to meet the security
requirements include fencing and lighting, as appropriate for the facility.
API 570 Third Edition 2009
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Securing and Controlling Access to Oil Handling, Processing and Storage Areas
Fencing can serve to secure and control access to the oil handling, processing and storage areas and
prevent unauthorized access to starter controls on oil pumps. As part of facility security measures, an owner or
operator may fully fence the facility and/or guard gates when the facility is not in operation or attended.
Alternatively, for facilities where oil containers
and equipment are located within discrete areas, securing
only those parts of the facilities that could be involved in
an oil discharge may provide an effective level of
protection. This may be preferable for very large facilities
where controlling access for the entire footprint of the
facility would require installing and monitoring very long
lengths of fencing. In such cases, installing a fence around
the discrete areas of a facility where oil containers and
associated valves, pumps and piping are located (Figure
3-1), and around the equipment needed to operate
pumps and containers, may adequately deter vandals
and/or prevent access by unauthorized personnel.
Figure 3-1: Fencing around oil storage area.
Other measures may also adequately control access to the facility and equipment, depending on facility-
specific circumstances. One example may be a facility attended on a 24-hour basis by security or other facility
personnel with closed-circuit cameras to detect and investigate unauthorized access. Alternatively, a facility may
combine an alarm system that detects the presence of trespassers. The rule language no longer prescribes a
single method to secure and control access to oil handling, processing and storage areas and therefore allows
the facility owner or operator to determine the best method to secure these areas without explaining
environmental equivalence.
Appropriateness of Lighting
The SPCC Plan must describe how the facility owner or operator addresses the appropriateness of
security lighting to both prevent acts of vandalism and assist in the discovery of oil discharges. Facilities may be
equipped with lights to allow facility personnel to discover discharges that occur at night and as a way to
prevent acts of vandalism. Appropriate lighting may consist of motion-activated lights to ward off trespassers
and allow facility personnel to notice if a discharge occurs. Alternatively, portable lights available for facility
personnel to use as they perform regular rounds of the facility may be appropriate. For facilities located away
from populated areas (e.g., farms or rural facilities) then the location itself may serve as a deterrent to vandals
and, based on the judgment of the Plan certifier, be considered when determining whether lighting is an
appropriate security measure for the facility. Alternatively, an owner/operator of an unattended facility may
determine that lights at the facility would not be an effective deterrent for vandals and choose instead to fence
the facility to prevent vandalism.
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Another security measure that may be used to detect oil discharges (typically used at electrical
substations) is a Supervisory Control and Data Acquisition (SCADA) system that monitors the facility and detects
oil discharges remotely without a need for lighting to assist in visual detection.
No discussion of an environmentally equivalent alternative to security lighting is necessary because the
rule does not specifically require lighting. Instead, the facility owner or operator describes in the SPCC Plan how
they prevent vandalism and discover oil discharges and whether security lighting is appropriate.
3.3.7 Integrity Testing and Inspection Requirements for Bulk Storage Containers at
Onshore Facilities
Integrity testing in accordance with industry standards is required for all aboveground bulk storage
containers that store, use, or process petroleum and other non-petroleum oils. Requirements for bulk storage
containers located at onshore facilities (excluding oil production facilities) are addressed in §112.8(c)(6).
Integrity testing requirements for onshore facilities that store, use, or process animal fats and/or vegetable oils
are addressed in §112.12(c)(6). For a complete discussion of integrity testing requirements and how the
environmental equivalence provision applies, see Chapter 7: Inspection, Evaluation, and Testing.
3.3.8 Alternative Measures for Containers at Onshore Oil Production Facilities
The SPCC rule allows for alternative measures to substitute for sized secondary containment for both
flow-through process vessels and produced water containers at onshore oil production facilities. The owner or
operator of an oil production facility may choose to follow the alternative measures for flow-through process
vessels described in §112.9(c)(5) or the measures for produced water containers as described in §112.9(c)(6), or
may substitute environmentally equivalent measures in accordance with §112.7(a)(2).
The alternative measures for flow-through process vessels and produced water containers at oil
production facilities are discussed in more detail in Chapter 4: Secondary Containment and Impracticability. The
general secondary containment requirements in §112.7(c) still apply to these containers, and environmentally
equivalent measures cannot be used to substitute for general secondary containment.
3.4 Review of Environmental Equivalence
Whenever an alternative measure is substituted for a prevention and control measure required by the
rule, then the environmentally equivalent measure must be documented in the SPCC Plan, as required in
§112.7(a)(2). This documentation is reviewed by the EPA inspector during inspections to ensure that the facility
is in compliance with the regulatory requirements. The EPA inspector may refer to the list in Table 3-5 at the end
of this chapter to identify and review technical rule requirements that are eligible for deviation through the
environmental equivalence provision.
As noted earlier in this Chapter, facility owners and operators may not use environmentally equivalent
measures to meet general and specific secondary containment provisions of the SPCC rule. Instead, an
impracticability determination in accordance with §112.7(d) provides a separate means of deviating from
secondary containment requirements after a PE determines that secondary containment is not practicable.
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Environmentally equivalent deviations are also not available for the general recordkeeping and training
provisions in §112.7. The rule already provides flexibility in the manner of recordkeeping for inspections and
tests by allowing the use of records kept under usual and customary business practices. Personnel training
(§112.7(f)) and a discussion of conformance with any applicable, more stringent state rules (§112.7(j)) are
essential for all facilities, and environmental equivalence does not apply to the alternative provision for qualified
oil-filled operational equipment as described in §112.7(k).
^ FYI - Cost considerations
EPA clarified in a Federal Register notice that
under §112.7(a)(2), owners and operators of
facilities may choose environmentally
equivalent approaches (selected in
accordance with good engineering practices)
for any reason, including because they are
cheaper.
(see 69 FR 29728, May 25, 2004)
3.4.1 Consideration of Costs
A PE must review the selection and implementation of
environmentally equivalent measures and certify them as being
consistent with good engineering practice (§112.3(d) or
§112.6(b)(4)). The selection of alternative measures may be based
on various considerations, such as safety, cost, geographical
constraints, the appropriateness of a particular requirement based
on site-specific considerations, or other factors consistent with
engineering principles.
Unlike impracticability claims, where cost cannot be the sole consideration (69 FR 29729, May 25, 2004),
an owner or operator may consider cost as one of the factors in deciding whether to deviate from a particular
requirement, but the alternative provided must achieve environmental protection equivalent to the required
measure (67 FR 47095, July 17, 2002). Facilities have the opportunity to reduce costs by alternative methods if
they can maintain environmental protection (67 FR 47056, July 17, 2002).
3.4.2 SPCC Plan Documentation
For each environmentally equivalent measure, the SPCC Plan must state the reason for nonconformance
within the relevant section of the Plan, as required in §112.7(a)(2). The Plan must also describe the alternative
measure in detail and explain how the measure provides environmental protection equivalent to that provided
by the SPCC provision.
The facility owner or operator must ensure that alternative measures are adequate for the facility; that
equipment, devices, or materials are designed for the intended use; and that the equipment, devices, or
materials are properly implemented and maintained to provide effective environmental protection (§§112.3(d)
and 112.7). EPA emphasizes that the environmental equivalence provision is not intended to be used as a means
to avoid complying with the rule or simply as an excuse for not meeting requirements the owner or operator
believes are too costly. The alternative measure chosen, and certified by a PE, must represent good engineering
practice and must achieve environmental protection equivalent to the SPCC rule requirement as required in
§112.7(a)(2).
The PE who certifies the Plan reviews environmentally equivalent measures. If a qualified facility uses
environmentally equivalent measures to comply with rule requirements, a PE must specifically certify each
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environmentally equivalent measure described in the Plan, as required in §112.6(b)(3)(i), even if other parts of
the qualified facility Plan are self-certified by the owner/operator.
In cases where operational procedures are used as environmentally equivalent alternatives to SPCC
requirements, the Plan must state the reasons for nonconformance and describe in detail the alternative
methods and how the approach will achieve equivalent environmental protection (§112.7(a)(2)). The description
should provide the details of how the procedures are implemented at the facility, including specific information
on the steps involved in each activity, required equipment, personnel training, and records that need to be
maintained to document and verify implementation. Records kept as part of usual and customary business
practices are acceptable forms of documentation, but should be referenced in the Plan and available for an
inspector's review during an inspection. These records must be maintained at the facility for a period of three
years (§112.7(e)). Certain industry standards (for example, API Standards 570 and 653) may specify that records
be maintained for more than three years. If a Plan indicates conformance with a standard that requires longer
retention of inspection records, then the owner/operator should follow the longer recordkeeping requirement
of the standard.
The two examples in Figure 3-2 and Figure 3-3 illustrate documentation of environmentally equivalent
measures in hypothetical SPCC Plans. The first example in Figure 3-2 shows insufficient documentation,
illustrating a Plan description that simply notes the use of an alternative measure without supporting
descriptions. Specifically, the example in Figure 3-2 does not provide sufficient detail to ascertain whether the
approach provides environmentally equivalent protection - it does not describe how environmental equivalence
is achieved and what procedures are implemented to ensure that the measure performs as intended. The
second example in Figure 3-3 provides a sufficient level of detail to allow an EPA inspector to understand what
the facility is doing to meet the objectives of the SPCC rule with regard to the given provision, and to verify
implementation of the measure(s) in the field.
Figure 3-2: Example 1: Insufficient Documentation of Environmentally Equivalent Protection for Drainage of
Diked Areas (§112.8(b)(l) and §112.8(b)(2)).
Facility Drainage - 40 CFR 112.8(b)(l) and 40 CFR 112.8(b)(2)
The dike structure in Area A is equipped with a [TRADEMARK] drain shutoff system and therefore does not require
employee supervision during draining. This provides an environmentally equivalent method of compliance with the
drainage requirement.
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Figure 3-3: Example 2: Sufficient Documentation of Environmentally Equivalent Protection for Drainage of
Diked Areas (§112.8(b)(l) and §112.8(b)(2)).
78
Facility Drainage - 40 CFR 112.8(b)(l) and 40 CFR 112.8(b)(2)
The dike in Area A contains three transformers (see list of equipment and oil storage capacity in the Plan). The dike is
equipped with a [TRADEMARK] drain shutoff system specifically engineered to prevent any oil from escaping the
containment structure while allowing water to flow through the valve housing during normal conditions. The system
uses hydrophobic and oleophilic material to block the flow of all fluids once it detects the presence of oil. The oil type
stored in the containment area has been confirmed by the manufacturer to activate the oil-blocking mechanism and
the mechanism ensures that any discharge from the containment structure will not cause a discharge as described in
§112.l(b). Attached in an appendix to the Plan are efficacy testing results supplied by the manufacturer of
[TRADEMARK].
Further documentation of the performance of this system and the manufacturer's suggested replacement interval are
maintained as an appendix to this Plan. This method deviates from the rule requirement to drain dikes under direct
visual supervision using valves of manual, open-and-closed design. Employee supervision is not required under regular
operating conditions to drain uncontaminated rainwater that has accumulated in the dike, which will reduce
manpower and resources necessary to implement the SPCC Plan. Therefore, we are implementing this system which is
environmentally equivalent because it will only drain rainwater when oil is not present.
The manufacturer's maintenance and inspection requirements are maintained at the facility. In accordance with those
recommendations, the diked area is inspected monthly by facility personnel as part of the scheduled inspection of bulk
storage tanks, as per the checklist presented in Appendix A. This inspection includes looking for accumulation of water
and presence of oil within the diked area, and examining, and replacing, as warranted, the silt filter and [TRADEMARK]
elements. Facility personnel also examine the system, and replace components as needed, within 48 hours of any
rainfall greater than 3 inches. Replacement of the silt filter and/or other elements of the [TRADEMARK] system are
noted on the monthly inspection sheets, which are maintained at the facility for three years.
All maintenance is performed following the manufacturer's specifications. Maintenance requirements are covered in
the employee training program.
In the event that the filter clogs and storm water accumulates within the diked area, facility personnel will follow
required procedures for dike drainage as follows:
1) Inspect the retained rainwater to ensure that it does not contain oil (to avoid a discharge to [Insert Name of
Waterbody] or adjoining shorelines which is the nearest navigable water to the facility);
2) Open the bypass valve, allow drainage, and reseal the valve; and
3) Record event in log.
This is a hypothetical example for illustrative purposes only. The use of environmental equivalence is a site-specific
determination certified by a PE in accordance with good engineering practice. EPA does not endorse this specific example as a
means of environmental equivalence. If a system that uses hydrophobic and oleophilic material is used at a facility, the
inspector should pay close attention to manufacturers' data supporting the assertion the system is effective to prevent a
discharge as described in § 112.l(b) and PE's site-specific considerations for the use of this technology at the facility. Follow-up
action by the EPA inspector may include requesting additional information from the facility owner or operator on the
implementation of the equivalent measure.
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3.4.3 Role of the EPA Inspector
A PE must certify environmentally equivalent measures for a facility to ensure consistency with good
engineering practice (§112.3(d) or §112.6(b)(3)(i) and §112.7). For each case where an environmentally
equivalent measure is used, the EPA inspector should verify that the Plan includes
• The reasons for nonconformance;
• A detailed description of the alternative measure; and
• An explanation describing how the alternative measure provides protection that is
environmentally equivalent.
Additionally, the EPA inspector should verify implementation of the alternative measure in the field.
The explanation describing how an alternative measure achieves environmental equivalence does not
need to demonstrate "mathematical equivalency/' but the alternative measure does need to provide equivalent
protection to prevent a discharge to navigable waters or adjoining shorelines. The Plan should describe how the
alternative measure prevents, controls, or mitigates a discharge, as well as the procedures or equipment used to
implement the alternative measure and ensure its continued effectiveness, particularly in terms of the
measure's practical impacts on field operations, employee training, monitoring, and equipment maintenance.
By certifying an SPCC Plan (or portion of a Plan, in the case of a qualified facility), a PE attests that the
Plan has been prepared in accordance with good engineering practice, that it meets the requirements of 40 CFR
part 112, and that it is adequate for the facility. EPA encourages innovative techniques for preventing
discharges, but these techniques need to effectively prevent discharges as described in §112.l(b). EPA believes
that PEs will seek to protect themselves from liability by certifying only measures that provide equivalent
environmental protection (67 FR 47095, July 17, 2002). If alternative measures are certified by a PE as being
environmentally equivalent, are properly documented, and are appropriately implemented in the field, they
should generally be considered acceptable by EPA regional inspectors absent a reasonable basis to believe
otherwise.
The EPA inspector should note whether the alternative measures make sense and appear to agree with
recognized industry standards or, where such standards do not apply, are in accordance with good engineering
practice. An EPA inspector should also carefully review alternative approaches that purposely deviate from
applicable industry consensus standards. If a PE develops an alternative measure that does not follow an
applicable industry standard, then the Plan must describe why the applicable industry consensus standard is not
being used and how the alternative measure is environmentally equivalent to the industry standard. The EPA
inspector should assess implementation of the alternative measures, including whether they appear to have
been altered or differ from the measures described in the Plan and certified by the PE, have not been
implemented correctly, require maintenance that has not occurred, appear to be inadequate for the facility, or
otherwise do not meet the overall oil spill prevention objective of the SPCC rule. Finally, the EPA inspector
should ensure that the rule requirement for which the Plan is deviating is eligible for environmental equivalence
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(as identified in §112.7(a)(2)) and that the environmentally equivalent alternative is not an existing SPCC
requirement.
If the inspector questions the appropriateness of alternative measures, he/she should fully document all
field observations and other pertinent information. Follow-up action by the EPA inspector may include
requesting additional information from the facility owner or operator on the implementation of the equivalent
measure. The EPA Regional Administrator (RA) has the authority to require amendment of the Plan to correct
alternative measures. If the RA determines that the measures described in the SPCC Plan do not provide
equivalent environmental protection, then the procedures for requiring a Plan amendment under §112.4(d) and
(e) may be initiated. In cases of noncompliance, an enforcement action may follow, as deemed appropriate.
Test Your Knowledge
Can you identify all of the problems with the following environmental equivalence example?
Example: Rather than provide secondary containment for Tank 4 (10,000-gallon shop-built heating oil tank) we are
implementing an integrity testing program that follows STI SPOOL Implementation of this integrity testing program will
prevent discharges of oil from the container and thus this provides equivalent environmental protection to a secondary
containment dike.
What problems did you identify?
1) Deviates from Secondary Containment Requirements. The environmental equivalence provision in §112.7(a)(2)
specifies exactly which provisions are eligible for the rule and it excludes secondary containment provisions.
Instead, if the facility owner/operator in this example cannot provide adequate secondary containment for the
10,000-gallon tank, then the SPCC Plan must include an impracticability determination in accordance with
§112.7(d) and he must develop an oil spill contingency plan and provide a written commitment of manpower,
equipment, and materials to implement the contingency plan.
2) Alternative Measure is an Existing SPCC Requirement. Integrity testing is an SPCC rule requirement that applies
to bulk storage containers under §§112.8(c)(6) and 112.12(c)(6). The facility owner/operator cannot substitute
one SPCC rule requirement for another because this allows for a lesser degree of overall protection of
navigable waters or adjoining shorelines.
3) Inadequate Documentation. The SPCC Plan must document the reason for deviating from a rule requirement,
provide a detailed description of the alternative measure and explain how it is environmentally equivalent. The
above example includes a single sentence identifying the alternative measure but does not provide a detailed
description of the alternative or an explanation of why the owner/operator did not provide secondary
containment for the tank. For an example of adequate documentation of environmental equivalent alternative,
see Section 3.1.1 of this chapter.
Table 3-5 lists the SPCC provisions that may be met through environmentally equivalent measures, and
provides guidance on the kinds of questions an inspector should consider when reviewing environmentally
equivalent measures in an SPCC Plan and during a site inspection. The table provides a list of evaluation
questions for each section of the rule, means of verifying compliance during an on-site review, and elements
that should be considered in cases where the facility installation does not conform with the methods described
in the SPCC rule. The EPA inspector should use the part(s) of the table that are relevant to the facility being
inspected.
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Table 3-5: SPCC provisions subject to environmentally equivalent measures under §112.7(a)(2).
Rule Element and
Relevant Section(s)
Evaluation
Verification During
Inspection
Inspectors: Consider the following questions as you review the basis for environmental equivalence for each provision
below.
Does the Plan state the reason for nonconformance? Does the Plan describe the alternative measure in sufficient detail?
Is the alternative measure appropriate for the facility? Does the Plan describe how the alternative measure is
environmentally equivalent? Is the alternative measure being implemented as described? Is the proposed alternative
already a rule requirement?
ALL FACILITIES
Administrative
provisions
of the SPCC rule
112.1-112.5
No deviation allowed based on environmental equivalence.
Qualified Facilities
112.6
Deviations based on environmental equivalence are only allowed for Tier II qualified facilities.
Tier II Qualified Facility Plans can include environmentally equivalent measures when a PE
certifies the alternative measures in accordance with 112.6(b)(3)(l) and 112.6(b)(4).
Amendments to PE-certified sections of Tier II (or hybrid) Plans must be certified by a PE in
accordance with 112.6(b)(2)(i).
General requirements
for an SPCC Plan
including
facility description,
secondary containment,
recordkeeping, and
personnel training
112.7 introductory
paragraph and
No deviation allowed based on environmental equivalence.
Security (excluding oil
production facilities)
112.7(g)
Does the Plan describe:
- Measures to secure and control access to the oil handling,
processing and storage areas?
- Measures that ensure that master flow and drain valves are
secured?
- Measures that prevent unauthorized access to starter controls on
oil pumps?
- How the out-of-service and loading/unloading connections of oil
pipelines are secured?
- The appropriateness of security lighting to both prevent acts of
vandalism and assist in the discovery of oil discharges?
- Visual
- Plan review
Loading and
unloading racks
No deviation allowed based on environmental equivalence.
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Chapter 3: Environmental Equivalence
Rule Element and
Relevant Section(s)
Evaluation
Verification During
Inspection
Loading and
unloading racks
12.7(h)(2)
Are loading/unloading racks equipped with an interlocked warning
light or physical barrier system, warning signs, wheel chocks, or a
vehicle brake interlock system to prevent vehicles from departing
before complete disconnection of oil transfer lines?
Visual review of loading
operation
Plan review
Loading and
unloading racks
112.7(h)(3)
Are the lowermost drain and all outlets of tank car or tank truck
inspected for signs of discharge prior to filling and departure of the
vehicles?
Are the drain and outlets tightened, adjusted, or replaced as
necessary to prevent liquid discharges while in transit?
Visual review of loading
operation
Review of procedures
described in the Plan
Field-constructed
aboveground containers
112.7(1)
Has the facility conducted an evaluation of field-constructed
aboveground containers undergoing repair, alteration,
reconstruction, or change in service that might affect the risk of a
discharge or failure?
If a field-constructed aboveground container has discharged oil or
failed due to brittle fracture failure or other catastrophe, has the
container been evaluated and has appropriate corrective action
been taken?
Was repair/corrective action in accordance with an industry
standard?
Visual
Inspection and testing
records
Brittle fracture
evaluation records
Industry standard by
which the brittle
fracture evaluation is
conducted
Industry standard by
which repairs for
corrective action were
conducted
Conformance with state
requirements
112.70;
No deviation allowed based on environmental equivalence.
Qualified oil-filled
operational equipment
112.7(k)
No deviation allowed based on environmental equivalence.
ALL FACILITIES, EXCEPT OIL PRODUCTION
Facility Drainage
112.8(b)(l) and 112.8(b)(2)
OR112.12(b)(l)and
Diked areas
- Is the facility drainage system or effluent treatment system
designed to control oil discharges?
- If not, is drainage from diked storage areas restricted by valves?
- Are dikes equipped with manual valves of open-closed design?
- If pumps or ejectors are used to empty the dikes, are they manually
activated?
- Is accumulated rainwater inspected for the presence of oil prior to
draining?
Visual
Plan review
Records of drainage
events
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Chapter 3: Environmental Equivalence
Rule Element and
Relevant Section(s)
Evaluation
Verification During
Inspection
Facility Drainage
112.8(b)(3) and
112.8(b)(4) OR
112.12(b)(3) and
Undiked areas with potential for a discharge
- Does the facility have ponds, lagoons, or catchment basins designed
to capture water from other areas with a potential for a discharge?
- If so, are such systems designed to retain or return oil to the
facility?
- If not, are ditches throughout the facility designed to flow into a
diversion system that would retain oil in the facility in the event of a
discharge?
- If the facility has catchment basins, are they located outside areas
subject to periodic flooding?
Visual
Plan review
Facility Drainage
112.8(b)(5) OR
- If the facility uses more than one treatment unit to treat its drainage
water, and this treatment is continuous and requires pump transfer,
does the facility have at least two "lift" pumps?
- Are facility drainage systems engineered to prevent discharges to
navigable waters or adjoining shorelines?
Visual
Plan review
Bulk Storage Containers
112.8(c)(l) OR
Are the material and construction of oil storage containers compatible
with the product stored and conditions of storage (e.g., temperature,
pressure, and soil conditions)?
Visual
Plan review
Standards/
specifications of
construction (tank
label), construction
documents and as-built
specifications
Bulk Storage Containers
112.8(c)(2) OR
No deviation allowed based on environmental equivalence.
Bulk Storage Containers
112.8(c)(3) OR
Does the facility prevent unsupervised drainage of rainwater into a
storm drain or open watercourse, or bypassing the facility
treatment system?
If so, does the facility document procedures to normally:
Keep the bypass valve sealed closed;
Inspect retained rainwater to prevent a discharge to navigable
waters or adjoining shorelines;
Open the bypass valve and reseal it following supervised drainage;
and
Keep adequate records of dike drainage event?
Visual
Plan review
Records of drainage
events
Bulk Storage Containers
112.8(c)(4) OR
Does the facility have completely buried metallic storage tanks that
were installed after January 10,1974?
Are completely buried metallic storage tanks protected from
corrosion by coatings or cathodic protection?
Are leak tests performed regularly on these tanks?
Visual
Plan review
Installation records
Inspection and testing
records
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Chapter 3: Environmental Equivalence
Rule Element and
Relevant Section(s)
Evaluation
Verification During
Inspection
Bulk Storage Containers
112.8(c)(5) OR
- Does the facility store oil in partially buried or bunkered metallic
tanks?
- If so, are these tanks protected from corrosion by coatings or
cathodic protection?
Visual
Plan review
Records
Bulk Storage Containers
112.8(c)(6) OR
- Does the facility inspect or test each aboveground container
(including foundation and supports) for integrity on a regular
schedule, and whenever a container undergoes material repairs?
- Does the Plan identify an applicable industry standard used to
determine the appropriate qualifications for personnel performing
tests and inspections, the frequency and type of testing and
inspections?
- If no applicable industry standard exists, does the Plan describe an
inspection program that is in accordance with good engineering
practices?
- Does the facility frequently inspect the outside of each aboveground
container for signs of deterioration, discharges, or accumulation or
oil?
Plan review
Applicable industry
standard
Inspection program
described in the Plan
including the schedule
and scope of such
inspections
Inspection and testing
records
Bulk Storage Containers
112.8(c)(7) OR
- Does the facility have containers with internal heating coils?
- Does the facility monitor the steam return and exhaust lines for
contamination from internal heating coils?
- Does the facility pass the steam return or exhaust lines through a
settling tank, skimmer, or other separation or retention system?
Visual
Container
specifications
Review of procedures
described in the Plan
Bulk Storage Containers
112.8(c)(8) OR
- Are containers equipped with at least one of the following:
- High liquid level alarm with audible or visual signal connected to a
constantly attended station,
- High liquid pump cutoff device,
- Direct audible or code signal communication between container
gauger and pumping station, or
- A fast response system for determining the liquid level (computers,
telepulse, direct vision gauges) of each bulk storage container,
combined with the continuous presence of personnel to monitor
filling operations.
- If the SPCC Plan indicates that liquid sensing devises are tested, are
the devices regularly tested to ensure proper operation?
Visual
Review of test
procedures described
in the Plan
Test records
Bulk Storage Containers
112.8(c)(9) OR
Are effluent treatment facilities inspected frequently to detect
possible system upsets that could cause a discharge to navigable
waters or adjoining shorelines?
Inspection and testing
records
Review of inspection
program described in
the Plan
Bulk Storage Containers
112.8(c)(10) OR
- Are there visible discharges from containers, including seams,
gaskets, piping, pumps, valves, rivets, and bolts? If so, is the facility
promptly correcting such discharges?
- Is there accumulation of oil in diked areas? If so, is the facility
promptly removing such accumulations?
Visual
Plan review
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Chapter 3: Environmental Equivalence
Rule Element and
Relevant Section(s)
Evaluation
Verification During
Inspection
Bulk Storage Containers
112.8(c)(ll) OR
No deviation allowed based on environmental equivalence.
Piping
112.8(d)(l) OR
- Does the facility have buried piping installed after August 16, 2002?
If so, is this piping protected against corrosion by wrapping and
coating? Is this piping cathodically protected?
- Does the facility have any exposed buried piping?
If so, does the facility inspect it for deterioration and undertake
additional examination and corrective action as appropriate?
Visual
Plan review
Installation records
Piping
112.8(d)(2) OR
- Does the facility have piping that is not in service or is in standby
service for an extended period of time?
If so, is the terminal connection at the transfer point capped or
blank-flanged, and is it marked as to origin?
Visual
Plan review
Piping
112.8(d)(3) OR
Are pipe supports properly designed to minimize abrasion and
corrosion and to allow for expansion and contraction?
Visual
Plan review
Piping
112.8(d)(4) OR
- Are aboveground valves, piping, and appurtenances regularly
inspected?
- NOTE: Inspection program must address conditions of items such as
flange joints, expansion joints, valve glands and bodies, catch pans,
pipeline supports, locking of valves, and metal surfaces.
- Is buried piping tested for integrity and leaks when installed,
modified, constructed, relocated, or replaced?
- Inspection records
- Description of
inspection program
within the Plan
- Applicable industry
standard
Piping
112.8(d)(5) OR
Are all vehicles entering the facility appropriately warned to ensure
that they will not endanger aboveground piping or other oil transfer
operations?
Visual
ONSHORE OIL PRODUCTION FACILITIES
Drainage
- Are drains of dikes or other containment measures for tank
batteries and separation/treating areas closed and sealed at all
times, except when draining uncontaminated rainwater?
- Prior to draining uncontaminated rainwater, does the facility inspect
the diked area and take the following actions:
- Document procedures to normally keep the diked drains sealed
closed;
- Inspect retained rainwater to prevent a discharge to navigable
waters or adjoining shorelines;
- Open the bypass valve and reseal it following supervised drainage;
and
- Keep adequate records of dike drainage event?
- And is accumulated oil removed and either returned to storage or
disposed of properly?
- Visual
- Plan review
- Records of drainage
events
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Chapter 3: Environmental Equivalence
Rule Element and
Relevant Section(s)
Evaluation
Verification During
Inspection
Drainage
112.9(b)(2)
Are field drainage systems and oil traps, sumps, or skimmers
regularly inspected for accumulation of oil?
And is accumulated oil promptly removed?
Visual
Inspection records
Inspection program
described in the Plan,
including the schedule
and scope of such
inspections
Bulk Storage Containers
Are the material and construction of oil storage containers compatible
with the product stored and conditions of storage (e.g., temperature,
pressure, and soil conditions)?
Visual
Construction standards
(tank labels, as-build
specifications, etc.)
Visual indication of
incompatibility, (i.e.,
excessive corrosion)
Bulk Storage Containers
112.9(c)(2)
No deviation allowed based on environmental equivalence.
Bulk Storage Containers
112.9(c)(3)
Is each container visually inspected periodically and on a regular
schedule?
NOTE: Inspections must cover foundation and support of each
container that is on or above the ground surface.
Inspection records
Inspection program
described in the Plan,
including scope and
frequency of such
inspections
Bulk Storage Containers
112.9(c)(4)
- Are tank battery installations engineered to prevent discharges
using one of the following:
- Container capacity is adequate to prevent overfill if gauger/pumper
is delayed in making regularly schedule rounds
- Equipped with overflow equalizing lines between containers
- Adequate vacuum protection to prevent container collapse during
transfer of oil
- High level sensors to alert computer where the facility is subject to a
computer production control system
Visual
Plan review
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Chapter 3: Environmental Equivalence
Rule Element and
Relevant Section(s)
Evaluation
Verification During
Inspection
Bulk Storage Containers
- Flow-through Process
Vessels
112.9(c)(5)
Does the facility owner/operator comply with secondary
containment and inspection requirements of 112.9(c)(2) and (c)(3)
for flow-through process vessels?
If not, then does the facility comply with the secondary containment
requirements of 112.7(c) and implement the following alternative
compliance option for this equipment:
Visually inspect and/or test flow-through process vessels and
associated components periodically for leaks, corrosion, or other
conditions that could lead to a discharge to navigable waters or
adjoining shorelines;
Take corrective action or repair flow-through process vessels and
any associated components as necessary; and
Promptly remove or initiate actions to stabilize and remediate any
accumulations of oil discharges associated with flow-through
process vessels.
Has the facility discharged more than 1,000 U.S. gallons of oil in a
single discharge as described in §112.l(b), or discharges more than
42 U.S. gallons of oil in each of two discharges as described in
§112.l(b) within any twelve month period, from flow-through
process vessels (excluding discharges that are the result of natural
disasters, acts of war, or terrorism)?
If so, did the facility ensure that all flow-through process vessels
subject to this subpart comply with §112.9(c)(2) and (c)(3) within six
months from the discharge(s)?
Plan review
Visual
Inspection records
Spill history/spill
reports
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Chapter 3: Environmental Equivalence
Rule Element and
Relevant Section(s)
Evaluation
Verification During
Inspection
Bulk Storage Containers
- Produced Water
Containers
112.9(c)(6)
- Does the facility owner/operator comply with secondary
containment and inspection requirements of 112.9(c)(2) and (c)(3)
for produced water containers?
- If not, then does the facility comply with the secondary containment
requirements of 112.7(c) and implement the following alternative
compliance option for this equipment:
- Implement a procedure to separate the free-phase oil that
accumulates on the surface of the produced water, on a regular
schedule, for each produced water container;
- Does the Plan describe the procedures, frequency, amount of free-
phase oil expected to be maintained inside the container, and
include a PE certification in accordance with §112.3(d)(l)(vi);
- Maintain records of such events;
- Visually inspect and/or test the produced water container and
associated piping on a regular schedule, for leaks, corrosion, or
other conditions that could lead to a discharge to navigable waters
and adjoining shorelines;
- Take corrective action or repair produced water containers and any
associated piping as necessary; and
- Promptly remove or initiate actions to stabilize and remediate any
accumulations of oil discharges associated with the produced water
container.
- Has the facility discharged more than 1,000 U.S. gallons of oil in a
single discharge as described in §112.l(b), or discharges more than
42 U.S. gallons of oil in each of two discharges as described in
§112.l(b) within any twelve month period, from flow-through
process vessels (excluding discharges that are the result of natural
disasters, acts of war, or terrorism)?
- If so, did the facility ensure that all produced water containers
subject to this subpart comply with §112.9(c)(2) and (c)(3) within six
months from the discharge(s)?
Plan review
Visual
Inspection records
Spill history/spill
reports
Transfer operations
Are all aboveground valves and piping inspected periodically and upon
a regular schedule?
NOTE: Inspections must cover items such as flange joints, valve glands
and bodies, drip pans, pipe supports, pumping well polish rod stuffing
boxes, and bleeder and gauge valves.
Inspection and testing
records
Inspection program
described in the Plan,
including frequency
and scope of
inspections
Transfer operations
112.9(d)(2)
Are saltwater disposal facilities inspected, particularly following a
sudden change in atmospheric temperature?
Plan review
Inspection and testing
records
Transfer operations
112.9(d)(3)
No deviation allowed based on environmental equivalence.
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Chapter 3: Environmental Equivalence
Rule Element and
Relevant Section(s)
Transfer operations
112.9(d)(4)
Evaluation
- Did the facility prepare and implement a written program of
flowline/intra-facility gathering line maintenance that addresses the
following:
- Equipment is compatible with the type of production fluids, their
potential corrosivity, volume, and pressure, and other conditions
expected in the operational environment;
- Flowlines and intra-facility gathering lines and associated
appurtenances are visually inspected and/or tested on a periodic
and regular schedule;
- Frequency and type of testing allows for the implementation of a
contingency plan as described in 40 CFR 109 for those flowlines and
intra-facility gathering lines that are not provided with secondary
containment;
- Corrective action is taken or repairs are made for flowlines and
intra-facility gathering lines and associated appurtenances as
necessary; and
- Any accumulations of oil discharges associated with flowlines, intra-
facility gathering lines, and associated appurtenances are promptly
removed or actions initiated to stabilize and remediate.
Verification During
Inspection
- Inspection and
maintenance records.
- Program of flowline
maintenance described
in the Plan, including
the scope and
frequency of
maintenance
ONSHORE OIL DRILLING AND WORKOVER FACILITIES
Mobile drilling or
workover equipment
112.10(b)
Containment
112.10(c)
Blowout prevention
112.10(d)
Is the equipment located so as to prevent a discharge to navigable
waters or adjoining shorelines?
- Visual
- Plan review
No deviation allowed based on environmental equivalence.
- Are a blowout prevention (BOP) assembly and well control system
installed before drilling below any casing string or during workover
operations?
- Are the BOP assembly and well control system capable of
controlling well-head pressure?
- Visual
- Installation record
- Plan review
OFFSHORE OIL DRILLING, PRODUCTION AND WORKOVER FACILITIES
Drainage
112.11(b)
Drainage
112. ll(c)
- Is oil drainage collection equipment used to prevent and control
small discharges? Are facility drains directed toward a central
collection sump?
- If a sump is not practicable, is oil removed from collection
equipment as often as necessary to prevent overflow?
- If a sump system is employed, are the sizes of pump and sump
adequate? Is a spare pump available?
- If a sump system is employed, does the facility have in place a
regularly scheduled preventive maintenance inspection and testing
program to assure reliable operation?
- Are redundant automatic sump pump and control devices provided
(when necessary)?
- Visual
- Plan review
- Visual
- Plan review
- Preventive
maintenance
inspection and testing
program described in
the Plan
SPCC GUIDANCE FOR REGIONAL INSPECTORS
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Chapter 3: Environmental Equivalence
Rule Element and
Relevant Section(s)
Separators and Treaters
112.11(d)
Containers
112. ll(e)
Containers
112.11(f)
Containers
112.11(g)
Pollution prevention
equipment and systems
112.11(h)
Pollution prevention
equipment and systems
112.11(i)
Well shut-in valves
112.11(1)
Blowout Prevention
112.1Hk)
Flowlines
112.11(1)
Flowlines
112.11(m)
Evaluation
- Does the facility have areas where separators and treaters are
equipped with dump valves which predominantly fail in the closed
position and where the pollution risk is high? If so, is the facility
specially equipped to prevent the discharge of oil, including:
- Extending the flare line to a diked area if the separator is near
shore?
- Equipping the separator with a high liquid level sensor that will
automatically shut in wells producing to the separator, or
- Installing parallel redundant dump valves?
Are atmospheric storage or surge containers equipped with high liquid
level sensing devices that activate an alarm or control the flow, or
otherwise prevent discharges?
Are pressure containers equipped with high and low pressure sensing
devices that activate an alarm or control the flow?
Are containers equipped with suitable corrosion protection?
Does the Plan include a written procedure for inspecting and testing
pollution prevention equipment and systems?
- Are the pollution prevention equipment and systems tested and
inspected on a scheduled periodic basis?
- Is the facility testing and inspecting human and equipment pollution
control and countermeasure systems by using simulated
discharges?
Is the method of activation or control of well shut-in valves and
devices for each well described in sufficient details?
- Is a BOP assembly and well control system installed during workover
operations or before drilling below any casing string?
- Is the BOP assembly and well control system capable of controlling
well-head pressure that may be encountered?
Are manifolds (headers) equipped with check valves on individual
flowlines?
- When the shut-in well pressure is greater than the working pressure
of the flowline are flowlines equipped with a high pressure sensing
device and shut-in valve at the wellhead? and
- Are valves manifolded up to and including the header valves? If not,
is a pressure relief system provided for flowlines?
Verification During
Inspection
- Visual
- Description of
inspection and
maintenance of
separators and heater
treaters (including
dump valves) in the
Plan, including the
schedule and scope of
such inspections
- Visual
- Plan review
- Visual
- Plan review
- Visual
- Plan review
Plan review
- Inspection and testing
records
- Description of
inspection and testing
program in Plan,
including scope and
frequency
Plan review
- Visual
- Plan review
- Installation records
- Visual
- Plan review
- Visual
- Plan review
SPCC GUIDANCE FOR REGIONAL INSPECTORS
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Chapter 3: Environmental Equivalence
Rule Element and
Relevant Section(s)
Piping
112.11(n)
Piping
112.11(o)
Piping
112.11(p)
Evaluation
Is all piping appurtenant to the facility protected from corrosion, such
as with protective coating or cathodic protection?
Is sub-marine piping adequately protected against environmental
stresses and other activities such as fishing operations?
- Is sub-marine piping appurtenant to the facility maintained in good
operating condition at all times?
- Does the facility have a program to inspect or test sub-marine piping
for failures according to a regular schedule?
- Does the facility maintain a record of these inspections or tests?
Verification During
Inspection
- Visual
- Plan review
- Installation records
- Inspection and
maintenance program
described in Plan
- Installation records
- Inspection and testing
records
- Review of inspection or
testing program
described in Plan,
including scope and
frequency of
inspections or tests
SPCC GUIDANCE FOR REGIONAL INSPECTORS
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Chapter 4 Secondary Containment and
Impracticability
4.1 Introduction
The purpose of the SPCC rule is to prevent discharges of oil into navigable waters of the United States
and adjoining shorelines. One of the primary ways the rule sets out to accomplish this goal is by requiring
secondary containment. A secondary containment system provides an essential line of defense in the event of a
failure of the primary containment, such as a bulk storage container, a mobile or portable container, piping, or
oil-filled equipment. The system provides temporary containment of discharged oil until the appropriate actions
are taken to abate the source of the discharge and remove oil from areas where it has accumulated to prevent it
from reaching navigable waters or adjoining shorelines. The rule includes two categories of secondary
containment requirements:
• A general provision addresses the potential for oil discharges from all regulated parts of a
facility. The containment method, design, and capacity are determined by good engineering
practice to contain the most likely discharge of oil until cleanup occurs.
• Specific provisions address the potential of oil discharges from areas of a facility where oil is
stored or handled. The containment design, sizing, and freeboard requirements are specified by
the SPCC rule to address a major container failure.
The general secondary containment requirements are intended to address, in accordance with good
engineering practice, the most likely oil discharges from areas or containers such as mobile refuelers and other
non-transportation-related tank trucks; oil-filled operational or process equipment; (non-rack) transfer areas; or
piping. In determining the method, design, and capacity for general secondary containment, only the typical
failure mode needs to be considered.
The specific secondary containment requirements are intended to address a major container failure
(e.g., the entire contents of the container and/or compartment) associated with a bulk storage container; single
compartment of a tank car or tank truck at a loading/unloading rack; mobile/portable containers; and
production tank batteries, treatment, and separation installations (including flow-through process vessels and
produced water containers). These specific provisions (see Table 4-1 in Section 4.1.1) provide explicit
requirements for sizing, design, and freeboard.
The purpose of this chapter is to clarify the relationships among the various general and specific
secondary containment requirements of the SPCC rule, and to illustrate how these requirements apply. This
chapter also discusses the rule's impracticability determination provision, which may be used when a facility
owner/operator cannot install secondary containment by any reasonable method. The additional requirements
that accompany an impracticability determination, the documentation needed to support such a determination,
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Chapter 4: Secondary Containment and Impracticability Determination
and the role of the EPA inspector in reviewing secondary containment requirements and impracticability
determinations are also discussed.
The remainder of this chapter is organized as follows.
• Section 4.2 provides an overview of the SPCC rule's general secondary containment provisions,
including exceptions to the requirement to provide secondary containment.
• Section 4.3 discusses the specific secondary containment requirements and the meaning of
"sufficient freeboard."
• Section 4.4 discusses issues related to secondary containment, such as active versus passive
measures, the "sufficiently impervious" requirement, facility drainage, and man-made
structures.
• Section 4.5 describes the impracticability determination provision.
• Section 4.6 describes required measures when secondary containment is impracticable.
• Section 4.7discusses how the impracticability determination may be used in certain
circumstances.
• Section 4.8 discusses alternative measures in the rule in lieu of secondary containment at oil
production facilities.
4.1.1 Overview of Secondary Containment Provisions
The SPCC rule includes several secondary containment provisions intended to address the various
activities or locations at a facility where oil is handled. This section differentiates among these general and
specific secondary containment provisions.
Table 4-1 lists all the secondary containment provisions of the SPCC rule for different types of facilities.
SPCC GUIDANCE FOR REGIONAL INSPECTORS
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Chapter 4: Secondary Containment and Impracticability Determination
Table 4-1: Secondary containment provisions in 40 CFR part 112.
Type of Facility
All Facilities
Onshore Storage
Onshore Oil
Production
Onshore Oil Drilling
and Workover
Offshore Oil Drilling,
Production, and
Workover
Secondary Containment
General containment (areas with potential for discharge,
such as piping-including flowlines, bulk storage containers,
oil-filled operating and manufacturing equipment, and oil
equipment associated with transfer areas)
Mobile refuelers and other non-transportation-related tank
trucks.
Loading/unloading racks**
Qualified Oil-Filled Operational Equipment
Bulk storage containers (except mobile refuelers and other
non-transportation-related tank trucks)
Mobile or portable oil containers (except mobile refuelers
and other non-transportation-related tank trucks)
Bulk storage containers, including tank batteries,
separation, and treating facility installations (except for
flow-through process vessels and produced water
containers)
Flow-through process vessels
Flowlines and intra-facility gathering lines
Produced water containers
Mobile drilling or workover equipment
Oil drilling, production, or workover equipment
Rule Sect ion(s)
§112.7(c)
§112.7(c)
§112.7(h)(l)
§112. 7(c) or alternate measures
in §112.7(k)
§112.8(c)(2)or§112.12(c)(2)
§112.8(c)(ll) or §112.12(c)(ll)
§112.9(c)(2)
§112.9(c)(2)or
§112. 7(c) and alternate
measures in §112.9(c)(5)
§112. 7(c) or alternate measures
in §112.9(d)(3)
§112.9(c)(2)or
§112. 7(c) and alternate
measures in §112.9(c)(6)
§112.10(c)
§112.7(c)
** Although this requirement applies to all facilities, loading/unloading racks are generally not present at typical oil
production facilities or farms, as discussed in Section 4.7.3.
Figure 4-1 through Figure 4-4 illustrate the relationships between the secondary containment
requirements at various types of facilities. EPA inspectors should use the flowchart that corresponds to the type
of facility he or she is inspecting (see the figure description for each flowchart). The second row of each
flowchart identifies the types of containers, equipment, and activities or areas where oil is handled, with
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Chapter 4: Secondary Containment and Impracticability Determination
reference to the appropriate secondary containment rule provision. The flowcharts note the use of
impracticability determinations and additional design considerations for other areas with the potential for
discharge.
Figure 4-1: Secondary containment provisions in 40 CFR part 112 related to onshore storage facilities
(§§112.7 and 112.8 or 112.12).
Onshore Storage
Facility
if impracticable
§112.7(d) Impracticability
Determination
For bulk storage containers, conduct
both periodic integrity testing of the
containers and periodic integrity and
leak testing of the valves and piping
.
• Prepare a part 1 09 cont
• Provide a written comm
manpower, equipment,
1 J
Bulk Storage Containers
(except mobile refuelers
and non-transportation-
related tank trucks)
§112.8(c)(2)
§112.12(c)(2)
Loading/Unloading
Rack §112.7(h)(1)
Mobile/portable
Containers (except
mobile refuelers)
Qualified Oil-Filled
Operational
Equipment
§112.7{c) OR
§112.7(k)
Other areas** with
potential discharge
§112,7(c)
" Examples of areas with potential
for discharge may include: piping -
including flowtines, buik storage
containers, oil-filled operating and
manufacturing equipment, and oil
equipment associated with transfer
areas
When dikes/berms are used to
satisfy secondary containment
requirements
When facilities drainage controls
are used to satisfy secondary
containment requirements
Diked areas:
§112.8(b)(1)and§112.8(b)(2)
OR
§112.12(b)(1)and§112.12(b)<2)
Undiked areas:
§112.8(b)(3) and §112.8(b)(4)
OR
§112.12(b)(3)and§112.12(b)(4)
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Figure 4-2:
Chapter 4: Secondary Containment and Impracticability Determination
Secondary containment provisions in 40 CFR part 112 related to onshore oil production facilities
(§§112.7 and 112.9).
Onshore Oil
Production Facility
§112.7(c)
if impracticable^
Bulk Storage Containers
§112.9{c}(2)
Applies to containers in the
tank battery, separation,
and treating facility
installations
§112.7(d) Impracticability Determination
For bulk storage containers, conduct both
periodic integrity testing of the containers and
periodic integrity and leak testing of the valves
and piping
Prepare a part 109 contingency plan
Provide a written commitment of manpower,
equipment, and materials
Flow-Through Process
Vessels
§112.9(c)(2)OR
§112.7(c)and§112.9(c)(5)
T
Flowlines and Intra-
Facility Gathering Lines
§112.7(c)OR
§112.9(d)(3)
Loading/Unloading Rack
Qualified Oil-Filled
Operational Equipment
§112.7(c)OR
§112.7(k)
Produced Water
Containers
§112.9(c}(2)OR
§112.7(c)and§112.9(c)(6)
Other areas** with
potential for discharge
§112.7(c)only
** Examples of areas with potential for discharge may include: piping - including flowlines, Christmas trees, pumpjacks. bulk
storage containers (not part of a tank battery), oil-filled operating and manufacturing equipment, and oil equipment associated
with transfer areas.
Oil production facilities do not typically have loading/unloading racks as defined in §112.2, but when oil
is transferred through a loading/unloading rack, sized secondary containment in accordance with §112.7(h)(l)
applies. Oil transfers to trucks within oil production facilities normally occur at transfer areas that are subject to
general secondary containment in accordance with §112.7(c).
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Chapter 4: Secondary Containment and Impracticability Determination
Figure 4-3:
Secondary containment provisions in 40 CFR part 112 related to onshore oil drilling and
workover facilities (§§112.7 and 112.10).
Onshore Oil Drilling and
Workover Facility
if impracticable
§112.7(d) Impracticability
Determination
For bulk storage containers, conduct
both periodic integrity testing of the
containers and periodic integrity and
leak testing of the valves and piping
Prepare a part 109 contingency plan
Provide a written commitment of
manpower, equipment, and materials
Provide catchment basins
or divisionary structures
§112.10(c)
Qualified Oil-Filled
Operational Equipment
§112.7(c)OR
§112.7(k)
Other areas** with
potential for discharge
§112.7(c)only
** Examples of areas with potential for discharge may include: piping - including flowiines, bulk storage containers, additive tanks containing
oil, lubricant oil tanks, oil-filled operating and manufacturing equipment, and oil equipment associated with transfer areas.
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Figure 4-4:
Chapter 4: Secondary Containment and Impracticability Determination
Secondary containment provisions in 40 CFR part 112 related to offshore oil drilling, production,
and workover facilities (§§112.7 and 112.11).79
Offshore Oil Drilling Production
and Workover Facility
if impracticable
§112.7(d) Impracticability Determination
• For bulk storage containers, conduct
both periodic integrity testing of the
containers and periodic integrity and
leak testing of the valves and piping
• Prepare a part 109 contingency plan
• Provide a written commitment of
manpower, equipment, and materials
Qualified Oil-Filled
Operational Equipment
§1127{c)OR
§112.7(k)
Other areas** with potential
for discharge
§112.7(c)only
Use oil drainage collection
equipment around separators,
treaters, tanks and associated
equipment §112.11(b)
When sumps are used, provide
appropriate size (§112.11(c))
and a spare pump
** Examples of areas with potential for discharge may include: piping - including flowlines, wellheads, blowout preventers, stock
tanks, bulk storage containers, additive tanks containing oil, lubricant oil tanks, oil-filed operating and manufacturing equipment,
flow-through process vessels, oil tanks for drilling rigs, and oil equipment associated with transfer areas.
4.2 General Secondary Containment Requirements
At a regulated facility, all areas and equipment with the potential for a discharge are subject to the
general secondary containment provision, §112.7(c). These may include bulk storage containers;
mobile/portable containers; mobile refuelers and other non-transportation-related tank trucks; oil production
tank batteries, treatment, and separation installations; pieces of oil-filled operational or manufacturing
equipment; loading/unloading areas (also referred to as transfer areas); and piping; and may include other areas
of a facility where oil is present. For the areas where specific (sized) secondary containment is also required (as
described in Section 4.7), this sized secondary containment fulfills the general secondary containment
requirements. The general secondary containment provision requires that these areas be designed with
appropriate containment and/or diversionary structures to prevent a discharge in quantities that may be
harmful (i.e., a discharge as described in §112.l(b)). "Appropriate containment" must be designed to address
the most likely quantity of oil that would be discharged from the primary containment system (e.g., container,
Onshore components associated with offshore facilities may also be subject to §§112.8 or 112.9 requirements (as applicable).
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Chapter 4: Secondary Containment and Impracticability Determination
equipment), such that the discharge will not
escape secondary containment before
cleanup occurs. In determining the most likely
quantity, the facility owner/operator should
consider factors such as the typical failure
mode (e.g., overfill, fracture in container wall,
etc.), resulting oil flow rate, facility personnel
response time, and the duration of the
discharge. An example calculation for a
transfer area is included in Section 4.7.2. A
similar calculation can be applied for any area
or equipment subject to the general
secondary containment requirement (e.g., oil-
filled equipment such as transformers).
Calculations may be provided as part of the
documentation to support the adequacy of
secondary containment measures employed
at the facility, although they are not required.
Nevertheless, the Plan preparer must include
enough detail in the SPCC Plan to describe the
efficacy of the measures used to comply with
the general secondary containment
requirements in §112.7(c).
Section 112.7(c) lists several methods
of providing secondary containment, which
are described in Table 4-2. These methods are
examples only; other containment methods
may be used, consistent with good
engineering practice. For example, a facility
could use an oil/water separator, combined
with a drainage system, to collect and retain discharges of oil within the facility. PE certification (or self-
certification, in the case of qualified facilities) of the SPCC Plan includes verification that the selected secondary
containment methods for the facility are appropriate and follow good engineering practice.
§112.7(c)
Provide appropriate containment and/or diversionary structures
or equipment to prevent a discharge as described in §112.l(b)
except as provided in paragraph (k) of this section for qualified oil-
filled operational equipment, and except as provided in
§112.9(d)(3) for flowlines and intra-facility gathering lines at an oil
production facility. The entire containment system, including walls
and floor, must be capable of containing oil and must be
constructed so that any discharge from a primary containment
system, such as a tank or pipe, will not escape the containment
system before cleanup occurs. In determining the method, design,
and capacity for secondary containment, you need only to address
the typical failure mode, and the most likely quantity of oil that
would be discharged. Secondary containment may be either active
or passive in design. At a minimum, you must use one of the
following prevention systems or its equivalent:
(1) For onshore facilities:
(i) Dikes, berms, or retaining walls sufficiently impervious to
contain oil;
(ii)
(iii)
(iv)
(v)
(vi)
(vii)
(viii)
Curbing or drip pans;
Sumps and collection systems;
Culverting, gutters, or other drainage systems;
Weirs, booms, or other barriers;
Spill diversion ponds;
Retention ponds; or
Sorbent materials.
(2) For offshore facilities:
(i) Curbing or drip pans; or
(ii) Sumps and collection systems.
Note: The above text is an excerpt of the SPCC rule. Refer to 40 CFR part 112
for the full text of the rule.
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Chapter 4: Secondary Containment and Impracticability Determination
Discharge as described in §112.l(b) is a discharge in quantities that may be harmful, as described in part 110 of this
chapter [40 CFR part 110], into or upon the navigable waters of the United States or adjoining shorelines, or into or
upon the waters of the contiguous zone, or in connection with activities under the Outer Continental Shelf Lands Act or
the Deepwater Port Act of 1974, or that may affect natural resources belonging to, appertaining to, or under the
exclusive management authority of the United States (including resources under the Magnuson Fishery Conservation
and Management Act).
Note: The above text is an excerpt of theSPCC rule. Refer to 40 CFR part 112 for the full text of the rule.
Table 4-2: Example methods of secondary containment listed in §112.7(c).
Secondary
Containment Method
Description of Examples
Dikes, berms, or
retaining walls
sufficiently impervious
to contain oil
Types of permanent engineered barriers, such as raised earth embankments or concrete
containment walls, designed to hold oil. Normally used in areas with potential for large
discharges, such as single or multiple aboveground storage tanks and certain piping.
Temporary dikes and berms may be constructed after a discharge is discovered as an active
containment measure (or a countermeasure) so long as they can be implemented in time to
prevent the spilled oil from reaching surface waters. Please see Section 4.4.1, Passive versus
Active Measures of Secondary Containment.
Curbing
Typically consists of a permanent reinforced concrete or an asphalt apron surrounded by a
concrete curb. Can also be of a uniform, rectangular cross-section or combined with
mountable curb sections to allow access to loading/unloading vehicles and materials handling
equipment. Can be used where only small spills are expected and also used to direct spills to
drains or catchment areas. Temporary curbing may be constructed after a discharge is
discovered as an active containment measure (or a countermeasure) so long as it can be
implemented in time to prevent the spilled oil from reaching surface waters. Please see
Section 4.4.1, Passive versus Active Measures of Secondary Containment.
Culverting, gutters, or
other drainage systems
Types of permanent drainage systems designed to direct spills to remote containment or
treatment areas. Ideal for situations where spill containment structures cannot or should not
be located immediately adjacent to the potential spill source.
Weirs
Dam-like structures with a notch through which oil may flow to be collected. Generally used
in combination with skimmers to remove oil from the surface of water.
Booms
Form a continuous barrier placed as a precautionary measure to contain/collect oil. Typically
used for the containment, exclusion, or deflection of oil floating on water, and is usually
associated with an oil spill contingency or facility response plan to address oil spills that have
reached surface waters. Beach booms are designed to work in shallow or tidal areas.
Sorbent-filled booms can be used for land-based spills. There are very limited applications for
use of booms for land-based containment of discharged oil.
Barriers
Spill mats, storm drain covers, and dams used to block or prevent the flow of oil. Temporary
barriers may be put in place prior to a discharge or after a discharge is discovered. These are
all considered effective active containment measures (or countermeasures) as long as they
can be implemented in time to prevent the spilled oil from reaching navigable waters and
adjoining shorelines. Please see Section 4.4.1, Passive versus Active Measures of Secondary
Containment.
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Chapter 4: Secondary Containment and Impracticability Determination
Secondary
Containment Method
Description of Examples
Spill diversion ponds
and retention ponds
Designed for long-term or permanent containment of storm water, but also capable of
capturing and holding oil or runoff and preventing it from entering surface water bodies.
Temporary spill diversion ponds and retention ponds may be constructed after a discharge is
discovered as an active containment measure (or countermeasure) as long as they can be
implemented in time to prevent the spilled oil from reaching navigable waters and adjoining
shorelines. There are very limited applications for use of temporary spill diversion and
retention ponds for land-based containment of discharged oil due to the timely availability of
the appropriate excavation equipment required to rapidly construct the ponds. Please see
Section 4.4.1, Passive versus Active Measures of Secondary Containment.
Sorbent materials
Insoluble materials or mixtures of materials (packaged in forms such as spill pads, pillows,
socks, and mats) used to recover liquids through the mechanisms of absorption, adsorption,
or both. Materials include clay, vermiculite, diatomaceous earth, and man-made materials.
Used to isolate and contain small drips or leaks until the source of the leak is repaired.
Commonly used with material handling equipment, such as valves and pumps. Also used as
an active containment measure (or countermeasure) to contain and collect small-volume
discharges before they reach waterways. Proper use of these materials may require a
properly equipped and trained spill response team specifically trained to contain an oil
discharge prior to reaching navigable waters or adjoining shorelines Please see Section 4.4.1,
Passive versus Active Measures of Secondary Containment.
Drip pans
Used to isolate and contain small drips or leaks until the source of the leak is repaired. Drip
pans are commonly used with product dispensing containers (usually drums), when
uncoupling hoses during bulk transfer operations, and for pumps, valves, and fittings.
Sumps and collection
systems
A permanent pit or reservoir and its associated troughs/trenches that collect oil.
The general secondary containment provision applies to all areas of a facility that have a potential to
cause an oil discharge. However, the provision allows for alternative measures in the SPCC Plan for:
• Qualified oil-filled operational equipment; and
• Flowlines and intra-facility gathering lines
These alternative measures are further described below.
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Chapter 4: Secondary Containment and Impracticability Determination
4.2.1 Alternative Measures for General Secondary Containment Requirement: Qualified
Oil-Filled Operational Equipment
Providing adequate secondary containment
for oil-filled operational equipment is often
impracticable, therefore, the SPCC rule provides an
optional alternative to the general secondary
containment requirements for oil-filled operational
equipment that meets qualifying criterion in
§112.7(k) (commonly referred to as "qualified oil-
filled operational equipment").
Oil-filled operational equipment, as defined
in §112.2, is equipment that includes an oil storage
container (or multiple containers) in which the oil
present is used solely to support the function of the
apparatus or the device. For more information on oil-
filled equipment, refer to Chapter 2: SPCC Rule
Applicability.
§112.2
Oil-filled operational equipment means equipment that
includes an oil storage container (or multiple containers)
in which the oil is present solely to support the function
of the apparatus or the device. Oil-filled operational
equipment is not considered a bulk storage container,
and does not include oil-filled manufacturing equipment
(flow-through process). Examples of oil-filled operational
equipment include, but are not limited to, hydraulic
systems, lubricating systems (e.g., those for pumps,
compressors and other rotating equipment, including
pumpjack lubrication systems), gear boxes, machining
coolant systems, heat transfer systems, transformers,
circuit breakers, electrical switches, and other systems
containing oil solely to enable the operation of the
device.
Note: The above text is an excerpt of the SPCC rule. Refer to 40 CFR
part 112 for the full text of the rule.
§112.7(k)
Qualified Oil-filled Operational Equipment. The owner or operator of a facility with oil-filled operational equipment
that meets the qualification criteria in paragraph (k)(l) of this sub-section may choose to implement for this qualified
oil-filled operational equipment the alternate requirements as described in paragraph (k)(2) of this sub-section in lieu
of general secondary containment required in paragraph (c) of this section.
(1) Qualification Criteria—Reportable Discharge History: The owner or operator of a facility that has had no single
discharge as described in § 112.l(b) from any oil-filled operational equipment exceeding 1,000 U.S. gallons or no two
discharges as described in § 112.l(b) from any oil-filled operational equipment each exceeding 42 U.S. gallons within
any twelve month period in the three years prior to the SPCC Plan certification date, or since becoming subject to this
part if the facility has been in operation for less than three years (other than oil discharges as described in § 112. l(b)
that are the result of natural disasters, acts of war or terrorism)
(2) Alternative Requirements to General Secondary Containment. If secondary containment is not provided for qualified
oil-filled operational equipment pursuant to paragraph (c) of this section, the owner or operator of a facility with
qualified oil-filled operational equipment must:
(i) Establish and document the facility procedures for inspections or a monitoring program to detect equipment failure
and/or a discharge; and
(ii) Unless you have submitted a response plan under §112.20, provide in your Plan the following:
(A) An oil spill contingency plan following the provisions of part 109 of this chapter.
(B) A written commitment of manpower, equipment, and materials required to expeditiously control and
remove any quantity of oil discharged that may be harmful.
Note: The above text is an excerpt of the SPCC rule. Refer to 40 CFR part 112 for the full text of the rule.
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Chapter 4: Secondary Containment and Impracticability Determination
Determining Eligibility for Alternative Measures for Oil-Filled Operational Equipment
The facility owner/operator determines if he is eligible to use the alternative measures in §112.7(k) by
considering the reportable discharge history from any oil-filled operational equipment at the facility. Table 4-3
identifies the criterion for determining if the facility has qualified oil-filled operational equipment.
Table 4-3: Reportable discharge history criterion for oil-filled operational equipment.
You must answer no to the following to be eligible for alternative measures in §112. 7(k):
In the three years before the SPCC Plan is certified, has the facility had any discharges to navigable waters or adjoining
shorelines from oil-filled operational equipment as described below:
A single discharge of oil greater than 1,000 gallons?
Two discharges of oil each greater than 42 gallons within any 12-month period?
Yes or No
Yes or No
When considering the above questions, the owner/operator does not need to include discharges that
are the result of natural disasters, acts of war, or terrorism. Additionally, when determining the applicability of
this SPCC reporting requirement, the gallon amount(s) specified (either 1,000 or 42) refers to the amount of oil
that actually reaches navigable waters or adjoining shorelines, not the total amount of oil spilled. EPA considers
the entire volume of the discharge to be oil for the purposes of these reporting requirements.
Let's consider the following examples:
Example 1: A facility has one discharge from oil-filled operational equipment over the past three years in
which 1,500 gallons of oil discharged onto the ground but only 20 gallons reached navigable waters or adjoining
shorelines (causing a sheen and reportable to the NRC).
You must answer no to the following to be eligible for alternative measures in §112.7(k):
In the three years before the SPCC Plan is certified, has the facility had any discharges to navigable waters or adjoining
shorelines from oil-filled operational equipment as described below:
A single discharge of oil greater than 1,000 gallons? No
Two discharges of oil each greater than 42 gallons within any 12-month period? No
Does the facility have qualified oil-filled operational equipment? Yes. The facility has qualified oil-filled
operational equipment because there was only one reportable oil discharge from oil-filled operational
equipment and the amount discharged to navigable waters (20 gallons) was less than 1,000 gallons (i.e., they
met the reportable discharge history criterion).
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Chapter 4: Secondary Containment and Impracticability Determination
Example 2: A facility has one 1,500-gallon discharge from oil-filled operational equipment to navigable
waters.
You must answer no to the following to be eligible for alternative measures in §112.7(k):
In the three years before the SPCC Plan is certified, has the facility had any discharges to navigable waters or adjoining
shorelines from oil-filled operational equipment as described below:
A single discharge of oil greater than 1,000 gallons? Yes
Two discharges of oil each greater than 42 gallons within any 12-month period? No
Does the facility have qualified oil-filled operational equipment? No. In this example, the oil discharge to
navigable waters was larger than 1,000 gallons and therefore the facility does not qualify for alternative
measures.
Example 3: A 2,000-gallon oil discharge to navigable waters occurs while unloading a vehicle into a bulk
storage container.
You must answer no to the following to be eligible for alternative measures in §112.7(k):
In the three years before the SPCC Plan is certified, has the facility had any discharges to navigable waters or adjoining
shorelines from oil-filled operational equipment as described below:
A single discharge of oil greater than 1,000 gallons? No
Two discharges of oil each greater than 42 gallons within any 12-month period? No
Does the facility have qualified oil-filled operational equipment? Yes. The facility has qualified oil-filled
operational equipment because the oil discharge did not originate from oil-filled operational equipment and
therefore is not considered when determining eligibility of the facility to use alternative measures for qualified
oil-filled operational equipment.
Alternative Measures
If an owner or operator uses alternative measures in lieu of meeting the secondary containment
requirements for qualified oil-filled operational equipment., he or she is required to establish and document an
inspection or monitoring program for qualified oil-filled operational equipment to detect equipment failure
and/or a discharge. Additionally, the owner/operator must prepare an oil spill contingency plan and provide a
written commitment of manpower, equipment, and materials required to expeditiously control and remove any
quantity of oil discharged that may be harmful (unless the facility has submitted a Facility Response Plan.) The
advantage of the §112.7(k) alternative to the general secondary containment requirements is that the facility
owner/operator is not required to prepare an impracticability determination for the qualified oil-filled
operational equipment (impracticability determinations are discussed in Section 4.5 of this chapter). Note that
the use of alternative measures is optional for qualified oil-filled operational equipment; the owner/operator
can instead provide secondary containment or may prepare an impracticability determination.
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Chapter 4: Secondary Containment and Impracticability Determination
For facility owners and operators that rely on contingency planning for qualified oil-filled operational
equipment in lieu of secondary containment, the discovery of a discharge by inspection or monitoring is critical
for effective and timely implementation of the contingency plan. An inspection or monitoring program ensures
that facility personnel are alerted quickly of equipment failures and/or discharges. The SPCC Plan must describe
the inspection or monitoring program and the owner or operator must keep a record of inspections and tests,
signed by the appropriate supervisor or inspector, for a period of three years in accordance with §112.7(e).
Qualified Oil-Filled Operational Equipment and Qualified Facilities Overlap
Some facilities may meet the criteria for qualified facilities as provided in §112.3(g) and have qualified
oil-filled operational equipment on-site. Owners and operators of such facilities can use the alternative
measures for oil-filled operational equipment described in §112.7(k) and self-certify the SPCC Plan. The owner or
operator can choose to develop an oil spill contingency plan, provide a written commitment of manpower,
equipment and materials and implement an inspection or monitoring
program as an alternative to secondary containment for qualified oil-
filled operational equipment. Since no impracticability determination
is necessary for qualified oil-filled operational equipment, the owner
or operator can self-certify his/her SPCC Plan and is not required to
have a PE develop and certify the contingency plan for the qualified
oil-filled operational equipment. The responsibility of preparing a
contingency plan and identifying the necessary equipment, materials
and manpower to implement the contingency plan would fall on the
owner or operator of the qualified facility. For more information on
qualified facilities, visit the EPA website at
http://www.epa.gov/oem/content/spcc/spcc qf.htm.
S? Tip - Generator sets
One commonly asked question is
whether generator sets are considered
oil-filled operational equipment.
No. Generator sets (gen sets) are a
combination of oil-filled operational
equipment and a bulk storage
container. Lubrication systems on gen
sets may be oil-filled operational
equipment, but bulk storage tanks
providing fuel for the generator
typically are not oil-filled operational
equipment.
Oil-Filled Manufacturing Equipment is not Oil-Filled Operational Equipment
The definition of oil-filled operational equipment does not include oil-filled manufacturing equipment
(flow-through process). Oil-filled manufacturing equipment is inherently more complicated than oil-filled
operational equipment because it typically involves a flow-through process and is commonly interconnected
through piping. For example, oil-filled manufacturing equipment may receive a continuous supply of oil, in
contrast to the static capacity of other, non-flow-through oil-filled equipment. Examples of oil-filled
manufacturing equipment include, but are not limited to, process vessels, conveyances such as piping associated
with a process, and equipment used in the alteration, processing or refining of crude oil and other non-
petroleum oils, including animal fats and vegetable oils (71 FR 77276, December 26, 2006).
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4.2.2 Alternative Measures for General Secondary Containment Requirement: Flowlines
and Intra-facility Gathering Lines
"Flowlines" are typically found at oil production facilities. They are piping that transfer crude oil and
well fluids from the wellhead to the tank battery where separation and treatment equipment are typically
located. Flowlines may also connect a tank battery to an injection well. Depending on the size of the oil field,
flowlines may range in diameter and run from hundreds of
feet to miles between the wellheads and the tank
batteries or primary separation operations.
§112.9(d)(3)
For flowlines and intra-facility gathering lines that
are not provided with secondary containment in
accordance with §112.7(c), unless you have
submitted a response plan under §112.20, provide
in your Plan the following:
(i) An oil spill contingency plan following the
provisions of part 109 of this chapter.
(ii) A written commitment of manpower,
equipment, and materials required to expeditiously
control and remove any quantity of oil discharged
that might be harmful.
Note: The above text is an excerpt of the SPCC rule. Refer to
40 CFR part 112 for the full text of the rule.
The term "gathering lines" refers to piping or
pipelines that transfer crude oil product between tank
batteries, within or between facilities. Gathering lines
often originate from an oil production facility's lease
automatic custody transfer (LACT) unit, which transfers oil
to other facilities involved in gathering, refining or pipeline
transportation operations. EPA considers gathering lines
subject to EPA's jurisdiction if they are located within the
boundaries of an otherwise regulated SPCC/FRP facility
(that is, intra-facility gathering lines) (73 FR 74274,
December 5, 2008). See Section 2.5.8 for a more detailed
description of flowlines and intra-facility gathering lines,
and the SPCC rule's applicability to each; note that intra-facility gathering lines subject to DOT requirements at
49 CFR parts 192 or 195 are exempt from the SPCC rule entirely.
Secondary containment is, in many cases, impracticable for flowlines and intra-facility gathering lines.
For example, an oil production facility in a remote area may have many miles of flowlines and gathering lines,
around which it would not be practicable to build permanent containment structures. It may not be possible to
install secondary containment around flowlines running across a farmer's or rancher's fields since berms may
become severe erosional features and can impede access to the fields by farm/ranch tractors and other
equipment. Similarly, it may be impracticable to construct secondary containment around flowlines that run
along a fence or county road due to space limitations or intrusions into a county's property or right-of-way. At
unattended facilities, active secondary containment methods are not effective in meeting secondary
containment requirements because there is limited capability to detect a discharge and deploy active measures
in a timely fashion.
Therefore, §112.9(d)(3) provides an optional alternative to the general secondary containment
requirements for flowlines and intra-facility gathering lines that are subject to the SPCC rule. In lieu of secondary
containment, the facility owner or operator may implement an oil spill contingency plan in accordance with 40
CFR part 109 (Criteria for State, Local and Regional Oil Removal Contingency Plans) and have a written
commitment of manpower, equipment, and materials required to expeditiously control and remove any
quantity of oil discharged that may be harmful. These requirements are the same as those in §112.7(d) of the
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rule, however, the Plan does not need to include an impracticability determination for each flowline and intra-
facility gathering line.
The contingency plan required when secondary containment is not practicable for flowlines and intra-
facility gathering lines should rely on strong maintenance, corrosion protection, testing, recordkeeping, and
inspection procedures to prevent and quickly detect discharges from such lines. It should also ensure quick
availability and deployment of response equipment. An effective flowline maintenance program is necessary to
detect a discharge in a timely manner so that the oil discharge response operations described in the contingency
plan may be implemented effectively.
Additionally, eliminating the requirement for secondary containment means that more prescriptive
requirements are needed for discharge prevention to ensure the integrity of the primary containment of the
pipe itself. The SPCC rule requires a performance-based program of flowline and intra-facility gathering line
maintenance, in accordance with §112.9(d)(4), that addresses the facility owner or operator's procedures and
must be documented in their SPCC Plan. See Section 3.3.5 and Chapter 7: Inspection, Evaluation, and Testing
(Section 7.2.12) for more information.
The complexity or simplicity of a facility's contingency plan is subject to good engineering practice as
determined by the Plan certifier. EPA developed a model contingency plan (see Appendix F of this guidance).
This model contingency plan is intended as an example and inspectors should only use it for this purpose.
4.3 Specific (Sized) Secondary Containment Requirements
While all parts of a regulated facility with potential for a discharge are, at a minimum, subject to the
general secondary containment requirements of §112.7(c),80 areas where certain types of containers, activities,
or equipment are located may be subject to additional, more stringent containment requirements, including
specifications for minimum capacity (see Table 4-1.) The SPCC rule specifies a required minimum size for
secondary containment for the following areas:
• Loading/unloading racks;
• Bulk storage containers including mobile or portable containers (does not apply to mobile
refuelers or other non-transportation-related tank trucks); and
• Production facility bulk storage containers, including tank batteries, separation, and treating
equipment (e.g., produced water tanks).
The applicable requirements for each of these types of containers or equipment are discussed in more
detail in Section 4.7 of this chapter. In general, provisions for specific secondary containment require that the
Note that the rule includes alternative provisions for certain equipment, in lieu of the general secondary containment
requirements of §112.7(c).
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chosen containment method be sized to contain the largest single oil compartment or container plus "sufficient
freeboard" to contain precipitation,81 as discussed in Section 4.3.2 below.
EPA inspectors should note that the "largest single compartment" may consist of several containers that
are permanently manifolded together. Permanently manifolded tanks are tanks that are designed, installed, or
operated in such a manner that the multiple containers function as a single storage unit (67 FR 47122, July 17,
2002). Accordingly, the total capacity of manifolded containers is the design capacity standard for the sized
secondary containment provisions (plus freeboard in certain cases).
4.3.1 Role of the EPA Inspector in Evaluating Secondary Containment Methods
The EPA inspector should evaluate whether the secondary containment system is adequate for the
facility, and whether it is maintained to contain oil discharges to navigable waters or adjoining shorelines. This
evaluation may include reviewing inspection reports and maintenance records. Some items that the inspector
should look for include:
For a dike, berm, or other engineered secondary containment system:
• Presence of debris;
Capacity of the system to contain oil as
determined in accordance with good
engineering practice and the
requirements of the rule;
Cracks in containment system materials
(e.g., concrete, liners, coatings, earthen
materials);
Discoloration;
Presence of spilled or leaked material
(standing liquid);
Corrosion of the system;
Erosion of the system;
Operational status of drain valves or other
drainage controls;
Dike or berm permeability;
Level of precipitation in diked area and
available capacity versus design capacity;
Location/status of pipes, inlets, and
drainage around and beneath containers;
Excessive vegetation that may inhibit
visual inspection and assessment of berm
integrity;
Large-rooted plants (e.g., shrubs, cacti,
trees) that could affect the berm integrity;
Holes or penetrations to the containment
system created by burrowing animals; and
Drainage records for rainwater discharges
from containment areas.
Does not apply to the loading and unloading rack secondary containment requirements.
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For retention and drainage ponds:
• Capacity of the system to contain oil as
determined in accordance with good
engineering practice and the rule
requirements;
• Erosion of the system;
• Discoloration;
• Design capacity versus available capacity;
• Presence of spilled or leaked liquid;
Presence of debris;
Cracks in containment system materials
(e.g., concrete, liners, coatings, earthen
materials);
Stressed vegetation;
Evidence of water seeps from the system;
and
Operational status of drain valves or other
drainage controls.
While the rule does not require that secondary containment calculations be kept in the Plan, EPA
strongly recommends that the facility owner or operator maintain the calculations such that if questions arise
during an inspection, the calculations which serve as the basis for the capacity of the secondary containment
system will be readily available for review by the EPA inspector. Industry guidance also recommends that facility
owners or operators include any secondary containment capacity calculations and/ or design standards with the
Plan. API Bulletin D16, "Suggested Procedure for Development of a Spill Prevention Control and
Countermeasure Plan," contains example calculations to which inspectors may refer (see Exhibit E of
"Suggested Procedure for Development of Spill Prevention Control and Countermeasure Plans," API Bulletin
D16. Fifth Edition, April 2011).
Examples and blank worksheets are available in Appendix H of this guidance. These documents were
developed to help qualified facility owner/operators to calculate secondary containment volume.82 These
worksheets address four specific scenarios and may not be valid for every facility:
• Single Vertical Cylindrical Tank Inside a Rectangular or Square Dike or Berm
• Multiple Horizontal Cylindrical Tanks Inside a Rectangular or Square Dike or Berm
• Rectangular or Square Remote Impoundment Structure
• Constructing New Secondary Containment
Disclaimer: Please note that these are simplified calculations for qualified facilities that assume: 1) the secondary containment
is designed with a flat floor; 2) the wall height is equal for all four walls; and 3) the corners of the secondary containment
system are 90 degrees. Additionally, the calculations do not include displacement for support structures or foundations. For
Professional Engineer (PE) certified Plans, the PE may need to account for site-specific conditions associated with the secondary
containment structure which may require modifications to these sample calculations to ensure good engineering practice.
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4.3.2 Sufficient Freeboard
The SPCC rule does not specifically define the term "sufficient freeboard/' nor does it describe how to
calculate this volume. The 1991 proposed amendment to the SPCC rule recommended the use of industry
standards and data on 25-year storm events to determine the appropriate freeboard capacity. Numerous
commenters on the 1991 proposal questioned the 25-year storm event recommendation and suggested
alternatives, such as using 110 percent of storage tank capacity or using other characteristic storm events. EPA
addressed these comments in the preamble to the 2002 amendments to the rule:
We believe that the proper standard of "sufficient freeboard" to contain precipitation is that amount
necessary to contain precipitation from a 25-year, 24-hour storm event. That standard allows flexibility
for varying climatic conditions. It is also the standard required for certain tank systems storing or
treating hazardous waste. (67 FR 47117, July 17, 2002)
However, the SPCC rule did not set this standard as a requirement for freeboard capacity. Therefore, the
use of precipitation data from a 25-year, 24-hour storm event is not enforceable as a standard for containment
freeboard. In the 2002 preamble, EPA further stated:
While we believe that the 25-year, 24-hour storm event standard is appropriate for most facilities and
protective of the environment, we are not making it a rule standard because of the difficulty and expense
for some facilities of securing recent information concerning such storm events at this time. (67 FR
47117, July 17, 2002)
Ultimately, EPA determined that, for freeboard, "the proper method of secondary containment is a
matter of engineering practice so [EPA does] not prescribe here any particular method" (67 FR 47101, July 17,
2002). However, where data are available, the facility owner/operator (and/or certifying PE) may want to
consider the appropriateness of the 25-year, 24-hour storm event precipitation design criteria for containment
freeboard.
A "110 percent of storage tank capacity" rule of thumb may be an acceptable design criterion in many
situations, and aboveground storage tank regulations in many states require secondary containment to be sized
to contain at least 110 percent of the volume of the largest tank. However, in some situations, 110 percent of
storage tank capacity may not provide enough volume to contain precipitation from storm events. Some states
require that facilities consider storm events when designing secondary containment structures, and in certain
cases these requirements translate to more stringent sizing criteria than the 110 percent rule of thumb.
Other important factors may be considered in determining necessary secondary containment capacity.
According to practices recommended by industry groups such as the American Petroleum Institute (API), these
factors include:
• Local precipitation conditions (rainfall and/or snowfall);
• Height of the existing dike wall;
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• Size of tank/container;
• Safety considerations; and
• Frequency of dike drainage and inspection.
The following examples (Figure 4-5 and Figure 4-6) present secondary containment size calculations for
hypothetical oil storage areas. The certifying PE (or owner/operator, in the case of qualified facilities)
determines what volume constitutes sufficient freeboard for precipitation for secondary containment and
should document in the Plan how the determination was made.
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Figure 4-5: Sample calculation of containment size, using two design criteria.
The following example compares two different design criteria: one based on the volume of the tank and one based on precipitation.
Scenario:
A 20,000-gallon horizontal tank is placed within an engineered secondary containment structure, such as a concrete dike. The tank is
35 feet long by 10 feet in diameter. The secondary containment area provides a 5-foot buffer on all sides (i.e., dike dimensions are 45
feet x 20 feet.
Given the dike footprint, we want to determine the wall height necessary to provide sufficient freeboard for precipitation, based on
(1) the tank storage capacity; (2) actual precipitation data. Several storm events in the recent past caused precipitation in amounts
between 3.6 and 4.0 inches at this location, although greater amounts have also been reported in the past. Note: The factor for
converting cubic feet to gallons is 7.48 gallons/ft3.
1. Calculation of secondary containment capacity, based on a design criterion of 110% of tank storage capacity:
Containment surface area = 45 ft x 20 ft = 900 ft2
Tank volume, based on 100% of tank capacity = 20,000 gallons
Tank volume, in cubic feet = 20,000 gallons / 7.48 gallons/ft3 = 2,674 ft3
Wall height that would contain the tank' s volume = 2,674 ft3 / 900 ft2 = 2.97 ft
Containment capacity with freeboard, based on 110% of tank capacity = 22,000 gallons
Containment capacity, in cubic feet = 22,000 gallons / 7.48 gallons/ft3 = 2,941 ft3
Wall height equivalent to 110% of storage capacity = 2,941 ft3/ 900 ft2 = 3.27 feet
Height of freeboard = 3.27 ft - 2.97 ft = 0.3 ft = 3.6 inches
Therefore, a dike design based on a criterion of 110% of tank capacity provides a dike wall height of 3.27 feet.
2. Calculation of secondary containment capacity, based on rainfall criterion:
After a review of historical precipitation data for the vicinity of the facility, the PE determined that a 4.5 inch rain event is the most
reasonable design criterion for this diked area.
Containment surface area = 45 ft x 20 ft = 900 ft2
Tank volume, based on 100% of tank capacity = 20,000 gallons
Tank volume, in cubic feet = 20,000 gallons / 7.48 gallons/ft3 = 2,674 ft3
Wall height that would contain the tank's volume = 2,674 ft3 / 900 ft2 = 2.97 ft
The height of the dike would need to be 3.35 feet (2.97 ft + 4.5 in).
Therefore, a dike design based on a 4.5 inch rain event provides a dike wall height of 3.35 feet, or almost 1 inch higher than calculated
using the 110% criterion.
Conclusion:
As noted from the comparison of the two design criteria illustrated above, the dike heights are similar although not exactly the same.
The adequacy of the secondary containment freeboard is ultimately an engineering determination made by the PE and certified in the
Plan.
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Figure 4-6: Sample secondary containment calculations, for multiple tanks in a containment area.
The EPA inspector has questioned the adequacy of the secondary containment based on the following scenario and wants to verify
how much precipitation the dike area can hold and compare it to available precipitation data to determine if 112% is an adequate
design criterion for this facility.
Scenario:
A 60 ft x 36 ft concrete dike surrounds one 20,000-gallon horizontal tank (10 ft diameter and 35 ft length) and two 10,000-gallon
vertical tanks (each 10 ft diameter and 15 ft height). The dike walls are 18 inches (1.5 feet) tall. The SPCC Plan states that secondary
containment is designed to hold 112% of the volume of the largest container.
Notes:
• The factor for converting gallons to cubic feet is 7.48 gallons/ft3.
• The volume displaced by a cylindrical vertical tank is the tank volume within the containment structure and is equal to the
tank footprint multiplied by height of the concrete dike. The tank footprint is equal to n cf/4, where D is the tank diameter.
1. Calculate total dike capacity:
Total capacity of the concrete dike = length x width x height = 60 ft x 36 ft x 1.5 ft = 3,240 ft3 = 24,235 gallons
2. Calculate net dike capacity, considering displacement from other tanks within the dike:
The total capacity of the concrete dike is reduced by the volume displaced by other tanks inside the containment structure.
The displacement is:
= number of tanks x footprint x height of dike wall = 2 n(lO ft)2/4 x 1.5 ft = 235.6 ft3 = 1,762 gallons
The net dike capacity, i.e., the volume that would be available in the event of a failure of the largest tank within the dike, is:
= Total volume - tank displacement = 24,235 -1,762 = 22,473 gallons = 3,004 ft3
3. Calculate the amount of available freeboard provided by the dike, given the net dike capacity:
The available freeboard volume is:
= Net dike capacity - volume of largest tank within the dike
= 22,473 - 20,000 = 2,473 gallons = 331 ft3
This is equivalent, expressed in terms of the capacity of the largest tank, to:
= Net dike capacity/volume of largest tank within the dike
= 22,473/20,000 = 112%
This available freeboard volume provides a freeboard height:
= Available freeboard volume / dike surface area
= 331 ft3 / (60 ft x 36 ft) = 0.15 ft =1.8 in
Therefore, this dike provides sufficient freeboard for 1.8 inches of precipitation.
Conclusion:
The EPA inspector should review the Plan and/or inquire about the precipitation event considered in determining that sufficient
freeboard for precipitation is provided. The adequacy of the secondary containment freeboard is ultimately an engineering
determination made by the PE and is certified in the Plan. This example serves only as a guide on doing the calculations for certain
circumstances in which the inspector has concerns with the freeboard volume associated with the secondary containment design.
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4.3.3 Role of the EPA Inspector in Evaluating Sufficient Freeboard
When reviewing an SPCC Plan, the EPA inspector should evaluate whether the size of secondary
containment is adequate to meet the freeboard requirement. When examining the secondary containment
measures for bulk storage containers, mobile or portable oil containers, and oil production facility bulk storage
containers, the inspector should ensure that the Plan documents that the secondary containment can hold the
entire capacity of the largest single container, plus sufficient freeboard to contain precipitation. Whatever
method is used to calculate the amount of freeboard that is "sufficient" for the facility and container
configuration should be documented in the Plan.
To determine whether secondary containment is sufficient, the EPA inspector may:
• Verify that the Plan specifies the capacity of secondary containment along with supporting
documentation, such as calculations for comparing freeboard capacity to the volume of
precipitation in an expected storm event.
If calculations are not included with the Plan, and the inspector suspects the secondary
containment is inadequate, the inspector may request supporting documentation from
the owner/operator.83
If diked area calculations appear inadequate, review local precipitation data such as data
from airports or the National Weather Service,84 as needed.
• Review operating procedures, storage tank design, and/or system controls for preventing
inadvertent overfilling of oil storage tanks that could affect the available capacity of the
secondary containment structure.
• Confirm that the secondary containment capacity can reasonably handle the contents of the
largest tank on an ongoing basis (i.e., including during rain events).
• During the inspection, verify that the containment structures and equipment are maintained
and that the SPCC Plan is properly implemented.
4.4 Issues Related to Secondary Containment Requirements
The following sections describe issues related to all secondary containment requirements, general and
specific.
Industry guidance recommends that facility owners/operators include any secondary containment capacity calculations and/or
design standards with the Plan. API Bulletin D16, "Suggested Procedure for Development of Spill Prevention Control and
Countermeasure Plans," contains example calculations to which inspectors may refer.
National Weather Service, Hydrometeorological Design Studies Center, Current Precipitation Frequency Publications, available
at http://www.nws.noaa.gov/oh/hdsc/currentpf.htmffN2.
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4.4.1 Passive versus Active Measures of Secondary Containment
In some situations, permanent containment structures, such as dikes, may not be feasible (e.g., may
cause pooling of liquids around electrical equipment which may present a hazard). Section 112.7(c) specifically
allows for the use of active containment measures (countermeasures or spill response capability), which prevent
a discharge to navigable waters or adjoining shorelines. Active containment measures are those that require
deployment or other specific action by the owner or operator. These measures may be deployed either before
the start of an activity involving the handling of oil, or in reaction to a discharge, so long as the active measure is
designed to prevent an oil spill from reaching navigable water or adjoining shorelines. Passive measures are
permanent installations and do not require deployment or action by the owner/operator.
Active measures (countermeasures) include, but are not limited to:
• Placing a properly designed storm drain cover over a drain to contain a potential spill in an
area where a transfer occurs, prior to the transfer activity. Storm drains are normally kept
uncovered; deployment of the drain cover prior to the transfer activity may be an acceptable
active measure to prevent a discharge from reaching navigable waters or adjoining shorelines
through the drainage system.
• Placing a storm drain cover over a drain in reaction to a discharge, before the oil reaches the
drain. If deployment of a drain cover can reliably be achieved in time to prevent a discharge of
oil from reaching navigable waters or adjoining shorelines, this may be an acceptable active
measure. This method may be risky, however, and is subject to a good engineering judgment on
what is realistically and reliably achievable, particularly under adverse circumstances.
• Using spill kits in the event of an oil discharge. The use of spill kits, strategically located and
ready for deployment in the event of an oil discharge, may be an acceptable active measure, in
certain circumstances, to prevent a spill from reaching navigable waters or adjoining shorelines.
This method may be risky and is subject to good engineering judgment, considering the volume
most likely expected to be discharged and proximity to navigable waters or adjoining shorelines.
• Use of spill response capability (spill response teams) in the event of an oil discharge. This
method differs from activating an oil spill contingency plan (see §112.7(d)) because the
response actions are specifically designed to contain an oil discharge prior to reaching navigable
waters or adjoining shorelines. Such actions may include the emergency
construction/deployment of dikes, curbing, diversionary structures, ponds, and other temporary
containment methods (such as sorbent materials), so long as they can be implemented in time
to prevent the spilled oil from reaching navigable waters or adjoining shorelines. This method
may be risky and reliance on oil spill response capability for secondary containment is subject to
good engineering judgment.
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• Closing a gate valve that controls drainage from an undiked area prior to a discharge. If the
gate valve is normally kept open, closing it before an activity that may result in an oil discharge
may be an acceptable active measure to prevent a spill from reaching navigable waters or
adjoining shorelines. Note that the rule requires that bypass valves for diked areas be sealed
closed (§§112.8(c)(3)(i) and 112.12(c)(3)(i)).
Considerations in Selecting an Active Containment Measure
The use of active containment as a strategy to address discharges should be carefully evaluated. The
v> Tip - Active vs. passive
containment measures
Active: The containment measure involves
a certain action by facility personnel
before or after the discharge occurs.
These actions are also referred to as spill
countermeasures.
Passive: The containment measure
remains in place regardless of the facility
operations and therefore does not require
an action by facility personnel.
efficacy of active containment measures to prevent a discharge
depends on their technical effectiveness (e.g., mode of operation,
absorption rate), placement and quantity, and timely deployment
prior to or following a discharge. For discharges that occur only
during attended or observed activities, such as those occurring
during transfers, an active measure (e.g., sock, mat, other portable
barrier, or land-based response capability) may be appropriate,
provided that the measure is capable of containing the most likely
volume of an oil discharge from a typical failure mode, and is timely
and properly constructed/deployed. Ideally, in order to further
reduce the potential for an oil discharge to reach navigable waters
or adjoining shorelines, the active measure should be deployed prior
to initiating the activity with potential for a discharge.
For certain active measures, however, such as the use of "kitty litter" or other sorbent material, it may
be impractical to pre-deploy the measure. In such cases, the sorbent material should be readily available so that
it can be used immediately after a spill occurs but before it can spread. Portable tanks can be equipped with a
spill kit to be used in the event of a discharge during transfers. The spill kit should be sized, however, to
effectively contain the volume of oil that could be discharged. Most commercially available spill kits are
intended for relatively small volumes (up to approximately 150 gallons of oil).
Active containment measures can be used to satisfy the general secondary containment requirement
when they are capable of containing the most likely discharge volume identified in the SPCC Plan. Elements to
consider may include the capacity of the containment measure, effectiveness, timely implementation, and the
availability of facility personnel and equipment to implement the active measure effectively. For example, a
discharge of 600 gallons would require deploying more than 900 "high-capacity" sorbent pads (20 inches by 20
inches) since each pad absorbs less than 0.7 gallons of oil. The same spill volume would require nine sorbent
blankets, each measuring 38 inches by 144 feet and weighing approximately 40 pounds. The rapid deployment
of such response equipment and material would be difficult to achieve under most circumstances, particularly if
only a few individuals are present when the discharge occurs, or during adverse conditions (e.g., rainfall, fire).
Using an active measure to meet the specific secondary containment requirement for a bulk storage
container may be difficult because the containment system must be sized for the entire capacity of the bulk oil
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storage container. Therefore, the use of active measures for larger oil containers may not be appropriate or in
accordance with good engineering practice or sound industry standards.
In certain circumstances, sorbents, such as socks, booms, pads, or loose materials may be used to
complement passive measures. For example, where berms around transfer areas are open on one side for
access, and where the ground surface slopes away from the opening with no nearby drains, sorbent material
may be effective in preventing small quantities of oil from escaping the bermed area in the event of a discharge.
The secondary containment approach implemented at a facility need not be "one-size-fits-all." Different
approaches may be taken for the same activity at a given facility, depending on the material and location. For
example, the SPCC Plan may specify that drain covers and sorbent material be pre-deployed prior to transfers of
low viscosity oils in certain areas of a facility located in close proximity to drainage structures or navigable
waters. For other areas and/or other products (e.g., highly viscous oils), the Plan may specify that sufficient spill
response capability (spill response teams) are available for use in the event of a discharge, so long as personnel
and equipment are available at the facility and these measures can be effectively implemented in a timely
manner to prevent oil from reaching navigable waters or adjoining shorelines.
Evaluating the ability of active secondary containment measures deployed after a discharge to prevent
oil from reaching navigable waters or adjoining shorelines involves considering the time it would take to
discover the discharge, the time for the discharge to reach navigable waters or adjoining shorelines, and the
time necessary to deploy the active secondary containment measure. For some active containment measures
such as the use of sorbent materials, the amount of oil the secondary containment measure can effectively
contain, including the potential impact of precipitation on sorption capacity, is also a critical factor. Good
engineering practice would indicate that active secondary containment measures may be used to satisfy the
general secondary containment requirements of §112.7(c) only in certain circumstances.
The use of an active measure containment strategy can be risky if not properly designed, evaluated and
implemented. If an active measure fails to prevent an oil discharge from reaching navigable waters or adjoining
shorelines, the owner or operator is liable for the discharge and cleanup, and is responsible for properly
reporting it to the National Response Center. Furthermore, even when used to comply with §112.7(c), active
measures should be limited to those situations where a PE has determined that the typical failure mode involves
a small volume of oil. Generally, active containment measures are not appropriate for satisfying the specific
containment requirements for a major container failure. Inspectors should closely review the SPCC Plan and
evaluate the rationale, equipment and implementation of such a strategy, as in most cases, this would not be
considered good engineering practice.
Deployment of Active Measures
Active measures are not appropriate for all situations with the potential for an oil discharge. As noted
above, active measures often have limited absorption or containment capacity. Additionally, storage tanks,
piping, and other containers pose a risk of discharge during off-hour periods when facility personnel are
generally not on site or are too few in number to detect a discharge in a timely manner and deploy the
containment measure(s) in order to prevent a discharge of oil to navigable waters or adjoining shorelines. Pre-
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deployment of active measures in a "fixed" configuration may be problematic since sorbent materials or
portable barriers are typically not engineered for long-term deployment, and their performance may be affected
by precipitation, ultraviolet light degradation, or cold temperature. Moreover, in some cases, the deployment of
an active measure can interfere with other systems; for example, by impeding the proper operation of drainage
structures (e.g., drain cover). For these reasons, engineered structures (such as dikes and berms, curbing, spill
diversion ponds, or similar systems) remain the most effective means of spill control and containment for oil
storage containers.
The SPCC Plan must describe the procedures used to deploy the active measures, explain how the use of
active measures is appropriate to the situation, and explain the methods for discharge discovery that will be
used to determine when deployment of the active measures is appropriate (§112.7(a)(3)(iii) and (iv)). The Plan
should, for instance, discuss whether active measures will be put in place before a potential discharge event
(e.g., a boom placed around a vehicle before fueling activities begin) or whether the active measures will be
deployed quickly after a spill occurs as a countermeasure (e.g., sorbents on hand and readily available). The Plan
should describe the amount of materials available and the location where they are stored, and the manpower
required to adequately deploy the material in a timely manner. Both the amount and location of materials
should be determined based on good engineering practice, taking into consideration the potential volume of a
discharge and the time necessary to deploy the measure to prevent a discharge to navigable waters or adjoining
shorelines. Some of this information may already be described in other existing documents at the facility, in
which case, these documents should be referenced in the SPCC Plan and be available at the time of an
inspection.
Using Active Measures with Oil-Filled Operational Equipment
Oil-filled operational equipment (e.g., electrical transformers, capacitors, switches) poses unique
challenges; permanent (passive) containment structures, such as dikes, may not always be feasible. Oil-filled
operational equipment as defined in §112.2 is only subject to the general secondary containment provision, and
the owner/operator may use the flexibility of active containment measures as described above. However, active
containment measures may be risky because they require the ability to detect a discharge, and these measures
must be implemented effectively and in a timely manner to prevent oil from reaching navigable waters and
adjoining shorelines, as required by §112.7(a)(3)(iii) and (c). As provided in §112.7(k), owners and operators of
facilities with eligible oil-filled operational equipment have the option to prepare an oil spill contingency plan
and a written commitment of manpower, equipment, and materials to expeditiously control and remove any oil
discharged that may be harmful, in lieu of general secondary containment, without having to make an individual
impracticability determination as required in §112.7(d).
Role of the EPA Inspector in Evaluating the Use of Active Measures of Secondary Containment
Inspectors should carefully evaluate the use of active measures and determine if the equipment and
personnel are available for deployment of this secondary containment method. The EPA inspector should
inspect the facility to determine whether the active measures are appropriate for the facility - i.e., the inspector
should note whether material storage locations are reasonable given the time necessary to deploy measures,
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and whether the amount of available materials is sufficient to handle the anticipated discharge volume. In
addition, the inspector should document whether the owner/operator of the facility is keeping the necessary
records.
Upon EPA inspection, a facility owner/operator should be able to demonstrate that facility personnel are
able to carry out the deployment procedure as written. The EPA inspector should verify that the facility's SPCC
Plan contains the following items, and that items in the Plan are observed in the field and/or verified through
discussions with facility personnel. Questions for the EPA inspector to consider in evaluating the adequacy of
active measures are also provided below.
• Explanation showing why the use of active measures is appropriate.
What is the expected/most likely potential discharge volume, and is the active measure
appropriately sized to contain the spill?
What is the discharge detection method and is it appropriate?
How much time is required to deploy the selected active measure?
Given these factors, is the active measure a reasonable approach?
• Detailed description of deployment procedures.
Will active measures be put in place before or after a spill occurs?
If measures are to be activated after a spill occurs, does the Plan describe the method of
discharge detection?
Are the equipment and personnel available to deploy/implement the proposed active
containment measure in an effective and timely manner to prevent oil from reaching
navigable waters or adjoining shorelines?
Does the Plan identify drainage pathways and the appropriate deployment location(s) for
the active measures?
• Description of all necessary materials and the location where they are stored (i.e., location of
drain covers, spill kits, or other spill response equipment).
In cases where spill kits or sorbent materials are to be used, does the Plan describe the
amount of materials available?
Are inventory and/or maintenance logs provided to ensure that spill response
equipment/materials are currently in sufficient supply and in good working condition (i.e.,
not damaged, expired, or used up)?
Are the equipment/materials located such that personnel can realistically get to the
equipment and deploy it quickly enough to prevent a discharge to navigable waters or
adjoining shorelines? That is, are the material and equipment accessible (not locked, or a
key is available), and are they located close enough to the potential source of discharge?
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• Description of facility staff responsible for deploying active measures.
Are training records up to date?
Have the personnel involved in activities for which the active measures might be deployed
been trained (e.g., are they familiar with the location and use of spill response materials,
drainage conditions)?
Is there sufficiently trained facility staff present at all times to effectively deploy the
measures in the event of a discharge?
Furthermore, the EPA inspector may review records and documentation such as:
• Personnel training records
• Drill records
• Deployment logs
The EPA inspector does not need to require the facility personnel to actually deploy the active measure
(e.g., through a demonstration or drill) to show that the measure is adequate and can be deployed in a timely
manner. However, the inspector may ask a series of questions in order to determine if the procedures for
deploying an active measure are well understood.
4.4.2 "Sufficiently Impervious"
Section 112.7(c) states that the entire secondary containment system, "including walls and floor, must
be capable of containing oil and must be constructed so that any discharge from a primary containment system
... will not escape containment before cleanup occurs." With respect to bulk storage containers at onshore
facilities (except oil production facilities), §§112.8(c)(2) and 112.12(c)(2) state that diked areas must be
"sufficiently impervious to contain oil." The purpose of the secondary containment requirement is to prevent
discharges as described in §112.l(b); therefore, effective secondary containment methods must be able to
contain oil until the oil is cleaned up.
The rule does not specify permeability, hydraulic conductivity, or retention time performance criteria for
these provisions (i.e., "sufficiently impervious" does not necessarily mean indefinitely impervious). Instead, the
owner/operator and/or the certifying PE have the flexibility to determine how best to design the containment
system to prevent a discharge to navigable waters or adjoining shorelines. This determination is based on a good
engineering practice evaluation of the facility configuration, product properties, and other site-specific
conditions. For example, a sufficiently impervious retaining wall, dike, or berm, including the walls and floors,
must be constructed so that any discharge from a primary containment system will not escape the secondary
containment system before cleanup occurs and before the oil reaches navigable waters or adjoining shorelines
(§§112.7(c), 112.8(c)(2) and 112.12(c)(2)). In other words, secondary containment structures such as dikes,
berms and retaining walls can be considered sufficiently impervious as long as they allow for cleanup to occur in
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time to prevent a discharge to navigable waters or adjoining shorelines. Ultimately, the determination of
imperviousness should be verified by a PE and documented in the SPCC Plan.
The preamble to the 2002 SPCC rule amendments states that "a complete description of how secondary
containment is designed, implemented, and maintained to meet the standard of sufficiently impervious is
necessary" (67 FR 47102, July 17, 2002). Therefore, pursuant to §112.7(a)(3)(iii) and (c), the Plan should address
how the secondary containment is designed to effectively contain oil until it is cleaned up. Control and/or
removal of vegetation may be necessary to maintain the imperviousness of the secondary containment and to
allow for the visual detection of discharges. The owner or operator should monitor the conditions of the
secondary containment structure to ensure that it remains impervious to oil. Repairs of excavations or other
penetrations through secondary containment need to be conducted in accordance with good engineering
practice.
The earthen floor of a secondary containment system may be considered "capable of containing oil"
until cleanup occurs, or "sufficiently impervious" if there is no subsurface conduit to navigable waters allowing
the oil to reach navigable waters before it is cleaned up. Should oil reach navigable waters or adjoining
shorelines, it is a reportable discharge under 40 CFR part 110. The suitability of earthen material for secondary
containment systems may depend on the properties of both the product stored and the soil. For example,
compacted local soil may be suitable to contain a viscous product, such as liquid asphalt cement, but may not be
suitable to contain gasoline. Permeability through the wall (or wall-to-floor interface) of the structure may result
in a discharge to navigable waters or adjoining shorelines and must be carefully evaluated.
In certain geographic locations, the native soil (e.g., clay) may be determined as sufficiently impervious.
However, in many more instances good engineering practice would generally not allow the use of a facility's
native soil alone as secondary containment when the soil is not homogenous. In fact, certain state requirements
may restrict the use of soil as a means of secondary containment, and many state regulations explicitly forbid
the discharge of oil on soil. Pennsylvania's Storage Tank and Spill Prevention Act, for example, requires that
facilities take immediate steps to prevent injury from any discharge of a substance that has the potential to flow,
be washed or fall into waters, and endanger downstream users. Pennsylvania's law requires that residual
substances be removed within 15 days from the ground or affected waters. Discharges to soil and groundwater
may violate other federal regulations (and violate Section 311(b)(3) of the Clean Water Act if an oil discharge to
groundwater impacts a navigable water or adjoining shoreline). The EPA inspector should strongly urge facility
owners and operators to investigate and comply with all state and local requirements. An inspector who notices
potential violations of other statutes or regulations should contact the appropriate authorities for follow-up with
the facility.
In summary, the owner/operator must base determinations of sufficiently impervious secondary
containment design on good engineering practice and site-specific considerations and this must be documented
in the Plan.
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Role of the EPA Inspector in Evaluating "Sufficiently Impervious"
Like other technical aspects of the SPCC Plan, the determination that a facility's soil is sufficiently
impervious must be made on a case-by-case basis by the certifying PE (or owner/operator, in the case of
qualified facilities). The EPA inspector should determine whether the facility's secondary containment is
sufficiently impervious, based on a review of the SPCC Plan, inspection reports, maintenance records, and an
observation of site conditions. The EPA inspector may ask to see any calculations or engineering justifications (as
applicable) used in determining levels of imperviousness; this information should be maintained with the Plan to
facilitate the inspector's review. To evaluate whether secondary containment is sufficiently impervious, the EPA
inspector may consider the following:
• Whether the SPCC Plan describes how secondary containment is designed, implemented, and
maintained to be sufficiently impervious. The certification of the Plan's adequacy is the
responsibility of the PE (or the owner or operator of a qualified facility) and a determination of
sufficient imperviousness may be based strictly on geotechnical knowledge of soil classification
and best engineering judgment. The inspector may review records of hydraulic conductivity
tests, if such tests were conducted to ascertain the imperviousness of the secondary
containment structure. The inspector may also review drainage records that are required to be
kept by the facility owner/operator in accordance with §112.8(c)(3), §112.9(b)(l), or
§112.12(c)(3). If, for example, facility personnel never drain the outdoor containment, then the
inspector may pose follow-up questions to clarify how the facility removes precipitation after
heavy rainfall, since lack of rainfall accumulation could indicate that the water is escaping the
containment structure through the walls or floor.
• Procedures for how the owner/operator minimizes and evaluates the potential for corrosion of
the bottom/bases of bulk storage containers that cannot be visually inspected. Corrosion of
container bottom is addressed in part by integrity testing of bulk storage containers under
§112.8(c)(6) or §112.12(c)(6). If a facility owner/operator cannot certify that the material under
the container is sufficiently impervious (whether earthen or manmade), the inspector should
consider:
Whether the inspection and integrity testing program in the Plan includes an internal
inspection, in accordance with industry standards. The scope of this internal inspection
should include the bottom plate. Since the bottom plate cannot be examined from the
underside, the only inspection available is to assess the fitness of the bottom plate via an
internal inspection. (See Chapter 7: Inspection, Evaluation, and Testing for more
information on integrity testing.)
Whether the owner/operator of the facility has a system in place to detect oil discharges
from a container bottom in order to commence cleanup before a discharge escapes the
containment systems.
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• Evidence of stained soil or stressed vegetation outside the containment area as well as at
nearby outfalls or other areas affected by runoff from the secondary containment structure. For
example, at onshore oil production facilities, there may be oil stains or white areas and white
salt crystal deposits on the outside of berm walls and on the ground surface farther away from
the berm. These deposits may indicate that oil and produced water has flowed through the
secondary containment and that the structure may not be sufficiently impervious.
• How the secondary containment is constructed (materials and method of construction). The
inspector should consider the type of soil (if soil is used). Floor and walls constructed of sandy
material, for example, may not be appropriate to hold refined products such as gasoline. If
earthen material is used, then it should have a high clay content and be properly compacted,
not simply formed into a mound. Untreated cinder blocks used for containment should be
closely evaluated by an inspector due to their porous nature.
• If a facility considers the earthen floor of a secondary containment system to be sufficiently
impervious, the inspector should consider any underground pathway that could lead to
navigable waters.
4.4.3 Facility Drainage (Onshore Facilities)
The facility drainage requirements of §§112.8(b) and 112.12(b) are design standards for secondary
containment (not additional secondary containment requirements) and are therefore eligible for deviations that
provide equivalent environmental protection in compliance with §112.7(a)(2) and as determined appropriate by
a PE. Chapter 3: Environmental Equivalence discusses ways to evaluate whether facility drainage systems that
deviate from the specified design standards are "environmentally equivalent" and comply with §112.7(a)(2) (see
Section 3.3.1).
The following sections describe how the facility drainage provisions at §§112.8(b) and 112.12(b) relate
to each other and to the secondary containment requirements.
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Facility Drainage Control from Diked Areas
When a dike (the term as used here also includes
other barrier methods such as berms, retaining walls,
curbing, weirs, or booms) is used as the containment
method to satisfy either general or specific secondary
containment requirements, then facility drainage
requirements also apply. The requirements for diked
areas at onshore facilities (except oil production
facilities) are found in §112.8(b)(l), 112.8(b)(2) (or
§112.12(b)(l), and 112.12(b)(2)); for diked areas at
onshore oil production facilities they are found in
§112.9(b)(l). Drainage from diked storage areas can be
accomplished by several means such as valves, manually
activated pumps, or ejectors. If dikes are drained using
valves, they must be of manual design to prevent an
uncontrolled discharge outside of the dike, such as into a
facility drainage system or effluent treatment system,
except where facility systems are designed to control
such a discharge (§§112.8(b)(l) and 112.12(b)(l)).
Although not required by the rule, owners and operators
should strongly consider locking valves controlling dike
or remote impoundment areas, especially when they can
be accessed by non-facility personnel.
For diked areas serving as secondary
containment for bulk storage containers, §§112.8(c)(3)
and 112.12(c)(3) require that storm water accumulations
be inspected for the presence of oil and that records of
the drainage events be maintained. Prior to draining
these areas, accumulated oil on the rainwater must be
removed and returned to storage or disposed of in
accordance with legally approved methods.
Facility Drainage Control from Undiked Areas
When secondary containment requirements are
addressed through facility drainage controls, such as
culverting, gutters, ponds, or other drainage systems,
the requirements in §112.8(b)(3) and (4), or
§112.12(b)(3) and (4) apply. For example, a facility may
§§112.8(b) and 112.12(b) Facility drainage.
(1) Restrain drainage from diked storage areas by
valves to prevent a discharge into the drainage
system or facility effluent treatment system, except
where facility systems are designed to control such
discharge. You may empty diked areas by pumps or
ejectors; however, you must manually activate
these pumps or ejectors and must inspect the
condition of the accumulation before starting, to
ensure no oil will be discharged.
(2) Use valves of manual, open-and-closed design, for
the drainage of diked areas. You may not use
flapper-type drain valves to drain diked areas. If
your facility drainage drains directly into a
watercourse and not into an on-site wastewater
treatment plant, you must inspect and may drain
uncontaminated retained stormwater, as provided
in paragraphs (c)(3)(ii), (iii), and (iv) of this section.
Note: The above text is an excerpt of the SPCC rule. Refer to 40
CFR part 112forthefull text of the rule.
§§112.8(c)(3) and 112.12(c)(3)
Not allow drainage of uncontaminated rainwater from
the diked area into a storm drain or discharge of an
effluent into an open watercourse, lake, or pond,
bypassing the facility treatment system unless you:
(i) Normally keep the bypass valve sealed closed.
(ii) Inspect the retained rainwater to ensure that its
presence will not cause a discharge as described in
§ 112.1(b).
(iii) Open the bypass valve and reseal it following
drainage under responsible supervision; and
(iv) Keep adequate records of such events, for example,
any records required under permits issued in
accordance with §§ 122.41(j)(2) and 122.41(m)(3) of
this chapter.
Note: The above text is an excerpt of the SPCC rule. Refer to 40
CFR part 112 for the full text of the rule.
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choose to use the existing storm drainage system to meet secondary containment requirements by channeling
discharged oil to a remote containment area to prevent a discharge to navigable waters or adjoining shorelines.
The facility drainage system must be designed to flow into ponds, lagoons, or catchment basins designed to
retain oil or return it to the facility. Catchment basins must not be located in areas subject to periodic flooding
(§§112.8(b)(3) and 112.12(b)(3)).
Conversely, the owner or operator of a facility does not have to address the undiked area requirements
of §112.8(b)(3) and (4) or §112.12(b)(3) and (4) if the facility does not use drainage systems to meet one of the
secondary containment requirements in the SPCC rule. For example, if the SPCC Plan documents the use of an
active containment measure (such as a combination of sorbents and a spill mat) that is effective to prevent a
discharge to navigable waters or adjoining shorelines, then secondary containment has been provided and it is
not necessary to alter drainage systems at the facility. The facility drainage system design requirements in
§112.8(b)(3) and (4) or §112.12(b)(3) and (4) apply only when the facility uses these drainage systems to comply
with the secondary containment provisions of the rule.
The EPA inspector should determine if the facility's documentation in the Plan identifies whether the
final ponds, lagoons, or catchment basins are designed/sized to meet the appropriate general and/or specific
secondary containment requirements. The following examples help to illustrate how to determine the
appropriate size of the ponds, lagoons, or catchment basins:
• General Secondary Containment. A facility owner/operator may use a storm water drainage
system that flows to a containment pond to address the general secondary containment
requirements of §112.7(c) for a piece of operational equipment (including electrical oil-filled
equipment). The secondary containment system must be designed to address the typical failure
mode and to contain the volume of oil most likely to be discharged as determined according to
good engineering practice and documented in the SPCC Plan (not necessarily a complete/major
container failure).
• Specific Secondary Containment. If a facility owner/operator uses a storm water drainage
system that flows to a catchment basin to comply with the specific secondary containment
requirements for a bulk storage container, the secondary containment system must be designed
to contain the capacity of the largest bulk storage container located inside the containment
system (with appropriate freeboard for precipitation) as dictated by the rule's requirements in
§§112.8(c)(2) or 112.12(c)(2). The specific secondary containment requirement is based on a
worst case container failure in which the entire capacity of the container is discharged.
• General and Specific Secondary Containment. In a case where a drainage system to a final
catchment basin is used to meet multiple secondary containment needs for the facility,
including compliance with both general and specific secondary containment requirements, the
system's design will need to meet the most stringent rule requirement (typically sized for the
specific secondary containment requirement).
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Oil Production Facility Drainage
Owners and operators of oil production
facilities must close and seal drains on
secondary containment systems associated
with tank batteries and separation and treating
areas (both dikes and other equivalent
measures required under §112.7(c)(l)) at all
times, except when draining uncontaminated
rainwater (§112.9(b)(l)). Prior to drainage, the
owner/operator must inspect the diked area
and take action as provided in §112.8(c)(3)(ii),
(iii), and (iv). If oil is present, then the
owner/operator must remove accumulated oil
on the rainwater and return it to storage or
dispose of it in accordance with legally
approved methods.
§112.9(b) Oil production facility drainage.
(1) At tank batteries and separation and treating areas where
there is a reasonable possibility of a discharge as described in
§112. l(b), close and seal at all times drains of dikes or drains of
equivalent measures required under §112.7(c)(l), except when
draining uncontaminated rainwater. Prior to drainage, you
must inspect the diked area and take action as provided in
§ 112.8(c)(3)(ii), (iii), and (iv). You must remove accumulated oil
on the rainwater and return it to storage or dispose of it in
accordance with legally approved methods.
(2) Inspect at regularly scheduled intervals field drainage
systems (such as drainage ditches or road ditches), and oil
traps, sumps, or skimmers, for an accumulation of oil that may
have resulted from any small discharge. You must promptly
remove any accumulations of oil.
Note: The above text is an excerpt of the SPCC rule. Refer to 40 CFR part
112 for the full text of the rule.
Owners and operators of oil production facilities must also inspect field drainage systems (such as
drainage ditches or road ditches), and oil traps, sumps, or skimmers at regularly scheduled intervals for an
accumulation of oil that may have resulted from any small discharge and promptly remove any accumulations of
oil from these systems. EPA inspectors should evaluate facility records to verify compliance with the drainage
procedures described in §112.8(c)(3). Any storm water discharge records maintained at the facility in
accordance with the NPDES requirements in §122.41(j)(2) or 122.41(m)(3) are acceptable to satisfy the
recordkeeping requirements of §§112.8(c)(3)(iv) or 112.12(c)(3)(iv). Field observations may also shed light on
compliance with the drainage provisions of the rule.
Role of the EPA Inspector in Evaluating Onshore Facility Drainage
The EPA inspector should review the facility's SPCC Plan to ensure that the drainage procedures are
documented and records are maintained. The EPA inspector should also examine the facility to determine
whether the drainage procedures are implemented as described in the SPCC Plan and whether they are
appropriate for the facility. If a facility uses drainage systems to meet one or more secondary containment
requirements, the EPA inspector should evaluate whether the final ponds, lagoons, or catchment basins are
designed/sized in accordance with the appropriate general and/or specific secondary containment
requirements. The EPA inspector should also evaluate the facility records to verify compliance with the drainage
procedures described in §112.8(c)(3).
4.4.4 Man-made Structures
If an oil storage container at a regulated facility is located inside a building, the PE certifying the SPCC
Plan may take into consideration the ability of the building walls and/or drainage systems to serve as secondary
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containment. As described throughout this chapter, the SPCC regulation is performance-based and provides
flexibility to the facility owner or operator in terms of how to design and implement secondary containment to
provide adequate protection.
As described in Section 4.3, the regulation provides general design criteria for secondary containment of
bulk storage containers by requiring that the containment system be sized to contain the capacity of the largest
container, with freeboard for precipitation, as appropriate. The SPCC rule does not specify a volume amount to
account for precipitation (e.g., 110 percent of capacity); instead it allows the facility owner or operator, or the
PE certifying the Plan, to consider location-specific conditions, including the possibility that a bulk storage
container is located indoors where precipitation is not a factor. When secondary containment is provided inside
a building, freeboard calculations for precipitation are typically not applicable.
The SPCC rule also requires that the containment structure provided around bulk storage containers be
sufficiently impervious to oil. Any indoor drainage system that leads directly to a storm sewer (discharging into a
stream), a sanitary sewer (discharging into a Publicly Owned Treatment Works (POTW)), or otherwise directly
into a waterbody may serve as a conduit for a discharge to navigable waters or adjoining shorelines. Therefore,
the containment structure must not be equipped with open floor drains or an automated sump pump unless the
drainage system has been purposefully equipped to treat any discharge (e.g., by use of an adequately sized,
designed and maintained oil-water separator). Additionally, any doorways, windows, or other openings that
would permit a discharge to flow out of the building must also be taken into consideration.
To the extent that an existing building structure meets the SPCC performance criteria for secondary
containment, the owner/operator can consider such a building as an appropriate containment structure. In
cases where the building walls are used for secondary containment, the calculation of the capacity of the
secondary containment structure would need to consider the displacement by other containers, equipment, and
items sharing the containment structure.
Where applicable, containers may be subject to the National Fire Protection Association's Flammable
and Combustible Liquids Code (NFPA 30) in addition to the SPCC requirements. For containers located in
buildings, NFPA 30 prescribes specific requirements to control fire hazards involving flammable or combustible
liquids, particularly in the areas of design, construction, ventilation, and ultimately facility drainage. Specifically,
NFPA 30 requires that curbs, scuppers, drains or similar features prevent the flow of liquids to adjacent buildings
during emergencies, and includes provisions to handle water from fire protection systems. In the area of facility
drainage, NFPA 30 requires that a facility be designed and operated to prevent the discharge of liquids to public
waterways, public sewers, or adjoining property. Thus, if a facility is designed, constructed and maintained to
applicable fire codes, such as NFPA 30, the building may serve as secondary containment under the SPCC rule.
4.4.5 Double-walled or Vaulted Tanks or Containers
A double-walled tank is essentially a tank within another tank, equipped with an interstitial (i.e.,
annular) space and constructed in accordance with industry standards. The inner tank serves as the primary oil
storage container while the outer tank serves as secondary containment. The outer tank of a double-walled tank
may provide adequate secondary containment for discharges resulting from leaks or ruptures of the entire
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capacity of the inner storage tank. The term "vaulted tank" has been used to describe both double-walled tanks
(especially those with a concrete outer shell) and tanks inside underground vaults, rooms, or crawl spaces.
Double-walled or vaulted tanks are subject to secondary containment requirements.
In the case of vaulted tanks, the Plan preparer must determine whether the vault meets the
requirements for secondary containment in §112.7(c). This determination should include an evaluation of
drainage systems and of sumps or pumps which could cause a discharge of oil outside the vault. Industry
standards for vaulted tanks often require the vaults to be liquid tight, which if sized correctly, may meet the
secondary containment requirement. There might also be other examples of such alternative systems. (67 FR
47102, July 17, 2002).
EPA issued two memorandums to address how the secondary containment requirements of §112.7(c)
apply to double-walled tanks. In the first memo, issued April 29, 1992,85 EPA described that shop-fabricated
aboveground double-walled tanks that meet certain industry construction standards, with capacities less than
12,000 gallons, installed and operated with protective measures such as overfill alarms, flow shutoff or restrictor
devices, and constant monitoring of product transfers would generally comply with the secondary containment
requirements of §112.7(c). As an alternative to the overfill prevention measures to contain discharges from a
double-walled tank, active or passive measures of secondary containment may be used to contain overfills from
tank vents that may occur during transfer operations.
The 1992 memo was later amended on August 9, 200286 to remove the 12,000 gallon tank capacity
limitation and to discuss additional SPCC requirements that apply to double-walled tanks.
Shop-fabricated double-wall ASTs, regardless of size,
may generally satisfy not only the secondary containment
requirements of §112.7(c), but also the specific secondary
containment requirements for sizing secondary containment
for bulk storage containers found at §112.8(c)(2).87 Double-
walled tanks that store animal fats or vegetable oils may
generally satisfy the secondary containment requirements of
§112.12(c)(2).
However, please note that double-walled tanks with
fittings or openings (e.g. a manway) located below the liquid
x?
^ Tip - Transfers from double-walled
tanks
A double-walled tank may have adequate
containment for the bulk storage container;
however it does not provide adequate
secondary containment to address transfer-
related overfills from the tank vent. Active
secondary containment measures may be used
to contain overfills from vents associated with
transfer operations.
Memorandum, Use of Alternative Secondary Containment Measures at Facilities Regulated under the Oil Pollution Prevention
Regulation (40 CFR Part 112), OSWER 9360.8-37, Don R. Clay, OSWER Assistant Administrator, April 29,1992.
Memorandum, Use of Alternative Secondary Containment Measures at Facilities Regulated under the Oil Pollution Prevention
Regulation (40 CFR Part 112), OSWER 9360.8-38, Marianne Lament Horinko, OSWER Assistant Administrator, August 9, 2002.
Double-walled tanks typically do not require additional freeboard for precipitation when the interstice is not exposed to
precipitation.
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level of the container may require additional secondary containment to conform with industry standards and/or
local codes. For example, NFPA 30 (paragraph 22.11) requires that piping connections be above the liquid level
to conform to spill control requirements.
Summary of required elements from the double-walled tank memos:
The use of certain shop-built double-wall ASTs serve as an "equivalent" preventive system for purposes of the general
secondary containment requirements of §112.7(c) when they include the following elements:
1) Containers are shop fabricated;
2) The inner tank is an Underwriter Laboratories (UL)-listed steel tank;
3) The outer tank is constructed in accordance with nationally accepted industry standards (e.g., API, STI, the
American Concrete Institute);
4) Equipped with the following overfill prevention measures to contain overfills from tank vents:
a) Overfill alarm and
b) Automatic flow restrictor or flow shut-off; and
5) All product transfers are constantly monitored.
Alternative to Overfill Prevention Measures: As an alternative to the overfill prevention measure described in the fourth
bullet above, the container may be equipped with either active or passive secondary containment methods to address
the typical failure mode and the most likely quantity of oil that would be discharged from the tank's vents during during
transfer operations.
Inspection Requirements for Double-walled Tanks
Section 112.8(c)(6) requires the owner or operator to conduct integrity testing on a regular schedule and
whenever he makes repairs. The section also requires the owner or
operator to frequently inspect the outside of the container for signs of
deterioration, discharges, or accumulation of oil inside diked areas (for a
double-walled tank, this inspection requirement applies to the inner
tank). For more information on how to meet the inspection
requirements for double-walled-tanks see Chapter 7: Inspection,
Evaluation, and Testing.
Other Applicable Secondary Containment Requirements
While shop-fabricated double-wall ASTs may satisfy the
requirements of §112.7(c) and §112.8(c)(2), such tanks, associated
appurtenances/piping and transfer activities are also subject to other
applicable SPCC requirements. For example, the facility owner or operator must satisfy §112.7(h) requirements
for tank car and tank truck loading/unloading racks if he transfers oil in bulk to double-wall tanks from highway
vehicles or railroad cars. If such transfers occur, where loading/unloading area drainage does not flow into a
catchment basin or treatment facility designed to handle spills, a quick drainage system must be used. The
§112.2
Repair means any work necessary to
maintain or restore a container to a
condition suitable for safe operation,
other than that necessary for
ordinary, day-to-day maintenance to
maintain the functional integrity of
the container and that does not
weaken the container.
Note: The above text is an excerpt of the
SPCC rule. Refer to 40 CFR part 112 for the
full text of the rule.
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Chapter 4: Secondary Containment and Impracticability Determination
containment system must be designed to hold at least the maximum capacity of any single compartment of a
tank car of tank truck loaded or unloaded at the facility. Transfer areas (those not associated with a
loading/unloading rack) need to comply with the general secondary containment requirements in §112.7(c).
Additionally, any piping, equipment, or device not contained within a double-walled AST is subject to the
general secondary containment requirements of §112.7(c). If a facility drainage system will be used to comply
with secondary containment then the piping, equipment or device is also subject to requirements of §112.8(b)
or§112.12(b).
4.5 Overview of the Impracticability Determination Provision
Although secondary containment systems are preferred, they may not always be practicable. If a PE
determines that containment methods are "impracticable," alternative modes of protection to prevent and
contain oil discharges are available. The SPCC rule provision found in §112.7(d) allows facility owners/operators
to substitute other measures in place of
secondary containment.
If an impracticability determination is
made, the SPCC Plan must clearly describe
why secondary containment measures are
impracticable and how the alternative
measures are implemented (§112.7(d)). See
Section 4.6 of this chapter for more
information on the alternative measures.
The option of determining
impracticability assumes that it is feasible to
effectively and reliably implement an oil spill
contingency plan. EPA inspectors should be
aware that an impracticability determination
may affect the applicability to the facility of
the FRP requirements under 40 CFR part 112
subpart D. In addition, an impracticability
determination may affect the calculation of
the worst case discharge volume, which may
impact the amount of resources required to
respond to a worst case discharge scenario
to comply with the FRP requirements.
§112.7(d)
Provided your Plan is certified by a licensed Professional Engineer
under §112.3(d), or, in the case of a qualified facility that meets
the criteria in §112.3(g), the relevant sections of your Plan are
certified by a licensed Professional Engineer under §112.6(d), if
you determine that the installation of any of the structures or
pieces of equipment listed in paragraphs (c) and (h)(l) of this
section, and §§112.8(c)(2), 112.8(c)(ll), 112.9(c)(2), 112.10(c),
112.12(c)(2), and 112.12(c)(ll), to prevent a discharge as
described in 112.l(b) from any onshore or offshore facility is not
practicable, you must clearly explain in your Plan why such
measures are not practicable; for bulk storage containers, conduct
both periodic integrity testing of the containers and periodic
integrity and leak testing of the valves and piping; and, unless you
have submitted a response plan under §112.20, provide in your
Plan the following:
1) An oil spill contingency plan following the provisions of part
109 of this chapter.
2) A written commitment of manpower, equipment, and
materials required to expeditiously control and remove any
quantity of oil discharged that may be harmful.
Note: The above text is an excerpt of the SPCC rule. Refer to 40 CFR part 112
for the full text of the rule.
Only secondary containment requirements can be determined to be impracticable; for most other
technical requirements, the rule provides flexibility to facility owners or operators to implement alternative
measures that provide equivalent environmental protection (see Chapter 3: Environmental Equivalence for more
information on the environmental equivalence provision).
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Because the expertise of a trained professional is important in making site-specific impracticability
determinations, owners or operators of Tier II qualified facilities (as described in §112.3(g)) who choose to self-
certify their SPCC Plans in lieu of PE-certification cannot take advantage of the flexibility allowed by the
impracticability provision, unless such determinations are reviewed and certified in writing by a PE
(§112.6(b)(3)(ii) and 112.6(b)(4)). When secondary containment is determined to be impracticable in accordance
with §112.7(d), the Plan must clearly explain why secondary containment measures are not practicable at the
facility and provide the alternative measures required in §112.7(d) in lieu of secondary containment.
4.5.1 Meaning of "Impracticable"
The impracticability determination is intended to be used when a facility owner/operator cannot install
secondary containment by any reasonable method. Considerations include space and geographical limitations,
local zoning ordinances, fire codes, safety, or other good engineering practice reasons that would not allow for
secondary containment (67 FR 47104, July 17, 2002). EPA clarified in a Federal Register notice that economic
cost may be considered as one element in a decision on alternative methods, consistent with good engineering
practice for the facility, but may not be the only determining factor in claiming impracticability (see text box
"Notice concerning certain issues pertaining to the July 2002 Spill Prevention, Control, and Countermeasure
(SPCC) rule" below). Each impracticability determination is site-specific and EPA inspectors should carefully
evaluate the rationale for the impracticability determination described by the PE in the SPCC Plan.
Notice concerning certain issues pertaining to the July 2002 Spill Prevention, Control, and
Countermeasure (SPCC) rule
The Agency did not intend with [preamble language at 67 FR 47104] to opine broadly on the role of costs in
determinations of impracticability. Instead, the Agency intended to make the narrower point that secondary
containment may not be considered impracticable solely because a contingency plan is cheaper. (This was the
concern that was presented by the commenter to whom the Agency was responding.)
In addition, with respect to the emphasized language enumerating considerations for determinations of
impracticability, the Agency did not intend to foreclose the consideration of other pertinent factors. In fact, in the
response-to-comment document for the SPCC amendments rulemaking, the Agency stated that "... for certain
facilities, secondary containment may not be practicable because of geographic limitations, local zoning ordinances,
fire prevention standards, or other good engineering practice reasons."
The above text is an excerpt from 69 FR 29728 (May 25, 2004).
4.6 Required Measures when Secondary Containment is Impracticable
Pursuant to §112.7(d), if secondary containment is impracticable for any area where secondary
containment requirements apply, facility owners or operators must clearly explain in the SPCC Plan why such
secondary containment is impracticable and implement additional requirements. The additional requirements
are:
• Periodic integrity testing of bulk storage containers;
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Chapter 4: Secondary Containment and Impracticability Determination
• Periodic integrity testing and leak testing of the valves and piping associated with bulk storage
containers;
• An oil spill contingency plan prepared in accordance with the provisions of 40 CFR 109, unless
the facility has submitted a Facility Response Plan (FRP) under §112.20; and
• A written commitment of manpower, equipment, and materials required to expeditiously
control and remove any quantity of oil discharged that may be harmful.
This section describes these additional requirements.
4.6.1 Integrity Testing of Bulk Storage Containers
When a facility owner or operator shows that secondary containment around a bulk storage container is
impracticable, he or she must conduct periodic integrity testing of the container (§112.7(d)). Integrity testing is
any means to measure the strength (structural soundness) of the container shell, bottom, and/or floor to
contain oil. Integrity testing must be done in accordance with good engineering practice, and consider applicable
industry standards. For a thorough discussion of integrity testing, see Chapter 7: Inspection, Evaluation, and
Testing. Chapter 7 describes the scope and frequency of inspections and tests, considering industry standards
and the characteristics of the container. When there is no secondary containment around a container, good
engineering practice would suggest a more stringent integrity testing schedule than would be required for a
container if secondary containment were in place. Although the SPCC rule does not incorporate specific
inspection frequency, certain industry standards require more frequent and/or more intensive inspection of
containers when they do not have secondary containment.88
It should be noted that if an impracticability determination is made for bulk storage containers located
at an oil production facility, the containers are subject to integrity testing under §112.7(d) and integrity testing
should be in accordance with applicable industry standards and good engineering practice.
The EPA inspector should verify that the Plan describes the integrity testing of bulk storage containers,
in particular for those containers for which secondary containment is impracticable. The EPA inspector should
also review testing records to ensure that the inspection program is implemented as described.
4.6.2 Periodic Integrity and Leak Testing of the Valves and Piping
When the facility owner or operator determines that secondary containment for a bulk storage
container is impracticable, he/she must also perform periodic integrity and leak testing of valves and piping
associated with the container for which secondary containment is impracticable (§112.7(d)). As the PE
establishes the periodic integrity testing for the bulk storage container, he will also determine the minimal
For example, the Steel Tank Institute's "Standard for the Inspection of Aboveground Storage Tanks," SP001, 5th Edition, Steel
Tank Institute, September 2011 (summarized in Chapter 7: Inspection, Evaluation, and Testing) requires more frequent
inspections of tanks that do not have adequate secondary containment.
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elements of the integrity and leak testing program needed for the for the valves and piping and identify what
portion of piping to include in the program.
Leak testing determines the liquid tightness of valves and piping and whether they may discharge oil.
Leak testing should be performed in accordance with appropriate industry standards. Chapter 7: Inspection,
Evaluation, and Testing provides an overview of integrity and leak testing of valves and piping. As for integrity
testing, good engineering practice may suggest a more stringent leak testing schedule than would be required if
secondary containment were in place. The scope of this integrity and leak testing program is a matter of good
engineering practice and should be clearly described in the SPCC Plan.
x?
v^ Tip - Valves and piping
Valves and piping are subject to additional
periodic integrity testing and leak testing
requirements when a PE determines that
secondary containment is impracticable for an
associated bulk storage container.
The EPA inspector should verify that the Plan describes
the type and scope of integrity and leak testing for valves and
piping associated with bulk storage containers for which
secondary containment is impracticable. The inspector should
also review testing records to ensure that the testing program
is implemented as described and is in accordance with the
scope of the testing program described by the PE in the Plan.
4.6.3 Oil Spill Contingency Plan and Written Commitment of Resources
Unless he or she has submitted a Facility Response Plan under §112.20, an owner or operator who
determines that secondary containment is impracticable must include with the SPCC Plan an oil spill contingency
plan following the provisions of 40 CFR part 109 and a written commitment of manpower, equipment, and
materials required to expeditiously control and remove any quantity of oil that may be harmful (§112.7(d)).
The requirements for the content of contingency plans are given in 40 CFR part 109 (Criteria for State,
Local, and Regional Oil Removal Contingency Plans). The elements of the contingency plan are outlined in
§109.5, and include:
• Definition of the authorities, responsibilities, and duties of all persons, organizations, or
agencies that are to be involved or could be involved in planning or directing oil removal
operations;
• Establishment of notification procedures for the purpose of early detection and timely
notification of an oil discharge;
• Provisions to ensure that full resource capability is known and can be committed during an oil
discharge situation;
• Provisions for well-defined and specific actions to be taken after discovery and notification of an
oil discharge; and
• Specific and well-defined procedures to facilitate recovery of damages and enforcement
measures as provided for by state and local statutes and ordinances.
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Refer to the model contingency plan in Appendix F of this guidance for an example contingency plan
prepared in compliance with the SPCC rule and 40 CFR part 109.
A "written commitment" of manpower, equipment, and materials means either a written contract or
other written documentation showing that the owner/operator has made provision for items needed for
response purposes. According to 40 CFR 109.5, the commitment includes:
• Identification and inventory of applicable equipment, materials, and supplies that are available
locally and regionally;
• An estimate of the equipment, materials, and supplies that would be required to remove the
maximum oil discharge to be anticipated;
• Development of agreements and arrangements in advance of an oil discharge for the acquisition
of equipment, materials, and supplies to be used in responding to such a discharge;
• Provisions for well-defined and specific actions to be taken after discovery and notification of an
oil discharge, including specification of an oil discharge response operating team consisting of
trained, prepared, and available operating personnel;
• Pre-designation of a properly qualified oil discharge response coordinator who is charged with
the responsibility and delegated commensurate authority for directing and coordinating
response operations and who knows how to request assistance from federal authorities
operating under current national and regional contingency plans;
• A preplanned location for an oil discharge response operations center and a reliable
communications system for directing the coordinated overall response actions;
• Provisions for varying degrees of response effort depending on the severity of the oil discharge;
and
• Specification of the order of priority in which the various water uses are to be protected where
more than one water use may be adversely affected as a result of an oil discharge and where
response operations may not be adequate to protect all uses. (67 FR 47105, July 17, 2002).
Note that a facility owner/operator does not need to develop a separate contingency plan and written
commitment of manpower, equipment, and materials for each individual impracticability determination. A
single plan, describing how the elements apply to each area where secondary containment is impracticable, will
suffice. Additionally, the elements required under §112.7(d) may be integrated into other contingency plans that
already may be in place at the facility, such as those developed pursuant to other federal or state requirements.
For a contingency plan to satisfy the requirements of §112.7(d), the owner or operator of a facility must
be able to activate and implement the contingency plan immediately upon detection of a discharge. As part of
evaluating the adequacy of the contingency plan developed to satisfy requirements of §112.7(d), the EPA
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inspector should consider the time it takes facility personnel to detect and mitigate a discharge to navigable
waters or adjoining shorelines. For example, at an unmanned facility (or during periods of time when a facility is
unattended), effective implementation of the contingency plan may involve enhanced discharge detection
methods such as more frequent facility visits and inspections, or the use of spill detection equipment.
4.6.4 Difference between Contingency Plans and Active Containment Measures
Note that active containment measures are used to meet secondary containment requirements, and
contingency plans are used to meet the requirement in §112.7(d) when an impracticability determination is
made. There is a subtle but important difference between active containment measures (i.e., countermeasures,
including land-based response capability) and an oil spill contingency plan as described in §112.7(d). Active
containment measures (as opposed to passive containment measures - i.e., permanent structures) require
deployment or other action; they are put in place prior to or immediately upon discovery of an oil discharge. The
purpose of active containment measures is to contain an oil discharge before it reaches navigable waters or
adjoining shorelines. These measures should be designed to prevent discharges from leaving the facility
boundaries.
A contingency plan, for SPCC purposes, is a detailed oil spill response plan developed when any form of
secondary containment is determined to be impracticable. It addresses controlling, containing, and recovering
an oil discharge in quantities that may be harmful to
navigable waters or adjoining shorelines. The purpose
of a contingency plan should be both to outline
response capability or countermeasures to limit the
quantity of a discharge reaching navigable waters or
adjoining shorelines (if possible), and to address
response to a discharge of oil that has reached
navigable waters or adjoining shorelines. Thus, active
containment measures can be part of a contingency
plan and every effort should be made to control the oil
discharge before it reaches navigable waters or
adjoining shorelines.
Tip - Active containment measures vs.
Contingency Plans
Active containment measure is used to describe any
land-based response capability that is deployed or
implemented immediately upon discovery of a
discharge before the discharge reaches navigable
waters or adjoining shorelines.
Contingency Plan is used to describe measures for
controlling, containing, and recovering oil that has been
discharged into or upon navigable waters or adjoining
shorelines in such quantities as may be harmful.
4.6.5 FRP Implications for Impracticability Determinations
When a facility owner/operator determines that secondary containment is impracticable, he must also
determine how this affects applicability of the Facility Response Plan (FRP) rule requirements under 40 CFR part
112.20 and 112.21 for the facility. The facility owner/operator may need to either prepare an FRP or revise an
FRP to address how a lack of adequate secondary containment affects the worst case discharge planning volume
for the facility.
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Facility Not Previously Subject to FRP
If a facility is not subject to the FRP rule, then the owner or operator must determine if an
impracticability determination will cause the facility to meet the following FRP applicability criterion:
The facility's total oil storage capacity is greater than or equal to one million gallons and it does not have
secondary containment for each aboveground storage area sufficiently large to contain the capacity of
the largest aboveground oil storage tank within each storage area plus sufficient freeboard to allow for
precipitation (see §112.20(f)(l)(ii)(A)).
If so, then the facility could reasonably be expected to cause substantial harm to the environment by
discharging oil into or on navigable waters or adjoining shorelines and is now subject to the FRP requirements
under §§112.20 and 112.21. The owner or operator must prepare and submit an FRP to the EPA Regional
Administrator (RA) in accordance with §112.20(a)(2).
Even when the total facility capacity is less than one million gallons, the EPA RA may determine that a
facility is a "substantial harm" facility and require the owner or operator to prepare and submit an FRP. The RA
may consider a lack of secondary containment as a criterion to require an FRP for a facility in accordance with
§112.20(f)(2).
Once an FRP is received, the EPA RA will review the plan to determine whether a facility could, because
of its location, reasonably be expected to cause significant and substantial harm to the environment by
discharging oil into or on navigable waters or adjoining shorelines (§112.20(c)). The EPA RA will review the
"significant and substantial harm" facility FRP, require amendments (as applicable), and approve any response
plan that meets the FRP rule requirements.
Aboveground oil storage tanks without adequate secondary containment will also factor into the
calculation of the worst case discharge planning volume for the facility, which has implications for the quantity
of response resources (by contract or other means) required under the FRP rule (see Appendices D and E of 40
CFR112).
Facility Previously FRP-subject
If a facility was previously subject to the FRP requirements and then makes a determination of
impracticability, the owner or operator of the facility must consider the implications of that change on the FRP.
The owner or operator will need to recalculate the worst case discharge planning volume to address
aboveground oil storage tanks without adequate secondary containment as well as determine sufficient
response resources to respond to the worst case discharge in accordance with Appendix E.
The owner or operator must revise and resubmit portions of the FRP within 60 days of a facility change
that materially may affect the response to a worst case discharge and submit a revised FRP to the EPA RA
(§112.20(d)(l)). A lack of adequate secondary containment may also influence the RA to determine that the
facility could reasonably be expected to cause significant and substantial harm to the environment by
discharging oil into or on navigable waters or adjoining shorelines.
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Chapter 4: Secondary Containment and Impracticability Determination
4.6.6 Role of the EPA Inspector in Reviewing Impracticability Determinations
Determinations of impracticability must be reviewed by the PE certifying the Plan in accordance with
§112.3(d) or §112.6(b)(4) to ensure that they are consistent with good engineering practice. The EPA inspector
should verify that the Plan has been certified by a PE and that the additional measures specified in §112.7(d) are
documented in the Plan, as explained below.
By certifying a Plan, or a portion of a Plan, a PE attests that it has been prepared in accordance with
good engineering practice, that it meets the requirements of 40 CFR part 112, and that it is adequate for the
facility. Thus, if impracticability determinations and the corresponding alternative measures and contingency
plan have been reviewed by the certifying PE and are properly documented, they should generally be considered
acceptable by regional EPA inspectors.
However, if an impracticability determination and/or the additional required measures appear to be at
odds with recognized industry standards, do not meet the overall objective of oil spill response/prevention, or
appear to be inadequate for the facility, appropriate follow-up action may be warranted. In this case, the EPA
inspector should clearly document the concerns (including photographs and drawings of the facility
configuration, flow direction, and proximity to navigable waters) to assist RA review and follow-up. This may
include requesting additional information from the facility owner or operator to justify the impracticability
determination, the adequacy of the contingency plan, or determine compliance with other requirements of
§112.7(d). The EPA inspector should also assess how the lack of adequate secondary containment impacts FRP
applicability or worst case discharge planning for the facility (see Section 4.6.5).
A PE making an impracticability determination should have considered, to the extent possible, all
reasonably appropriate options for secondary containment. The documentation presented in support of the
impracticability determination should discuss the reasons why various secondary containment options are
impracticable. The documentation must demonstrate the reasoning used to determine why secondary
containment is impracticable, rather than provide an exhaustive evaluation of all potentially available types of
secondary containment.
The example below (see Figure 4-7) describes an inadequate impracticability determination. The
supporting discussion provided in the example does not provide a sufficient discussion of the reasons why a
concrete dike is not practicable. It also fails to address, even in general terms, whether means of secondary
containment other than a concrete dike may be practicable (e.g., remote impoundment, drainage systems, or
active measures). Finally, the discussion does not provide information on the measures that are provided in lieu
of secondary containment and how the facility intends to implement the contingency plan, commit manpower
and equipment to respond, and perform the required testing on the bulk storage containers and associated
piping and appurtenances. Refer to §112.7(c) and (d) for a list of available secondary containment options as
well as the alternative measures required in the SPCC Plan when an impracticability determination is made.
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Figure 4-7: Example of inadequate impracticability determination: Bulk Storage Containers
Bulk Storage Tanks - 40 CFR 112.8(c)(2)
XYZ Oil has determined that secondary containment is impracticable for the two bulk storage tanks located to
the east of the maintenance building. There is not sufficient space to build a concrete dike because of the
proximity to the property line. XYZ Oil is therefore implementing a contingency plan for this portion of the
facility.
For comparison, the following example (see Figure 4-8) provides an adequate impracticability
determination. The supporting discussion provided in the example clearly explains why various methods of
secondary containment measures are not practicable, and documents the measures that the facility has
implemented in lieu of secondary containment. Additionally, the PE explains the additional
equipment/procedures that will be implemented to compensate for the lack of adequate secondary
containment. These additional measures would typically provide an EPA inspector with assurance that a facility
will be able to address oil discharges using a contingency plan (and ensure its timely implementation).
Figure 4-8: Example of adequate impracticability determination: Bulk Storage Containers
Bulk Storage Tanks - 40 CFR 112.8(c)(2)
XYZ Oil has determined that secondary containment is impracticable for the two bulk storage tanks located to the east
of the maintenance building. There is not sufficient space to accommodate a dike or berm with the required
containment capacity due to minimum setbacks and maximum dike height. A dike or berm with the required capacity
would either encroach on the neighbor's property and/or exceed a 6-feet safe wall height (Occupational Safety and
Health Administration (OSHA) Flammable and combustible liquids regulation, 29 CFR 1910.106). The facility also lacks
the space necessary for remote impoundment. Other measures listed under §112.7(c) such as the use of sorbents
would not be a reliable and effective means of secondary containment since the volumes involved may exceed the
sorbent capacity.
The tanks are currently in good condition and do not need to be replaced. However, tanks of double-wall design may
be considered as potential replacement in the future. The existing tanks have been equipped with a leak detection
device to aid with the discovery of an oil discharge. The containers, due to a lack of containment, are going to be
subject to a more aggressive integrity testing program than required by the governing standard (see Section 2.7 of the
SPCC Plan, Integrity Testing, for details). Finally, the tanks are equipped with an overfill system and automatic
shutdown leak detection to prevent overfills.
Because secondary containment for these two bulk storage tanks is impracticable, XYZ Oil has provided in this SPCC
Plan the additional elements required under 40 CFR 112.7(d), namely:
• Periodic integrity testing of bulk storage containers, and periodic integrity and leak testing of valves and
piping (see Section 2.7 of the SPCC Plan).
• A written commitment of manpower, equipment, and materials required to expeditiously control and
remove any quantity of oil discharged that may be harmful (see Appendix F of the SPCC Plan).
• An Oil Spill Contingency Plan following the provisions of 40 CFR part 109 (see Appendix G of the SPCC
Plan).
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In addition to verifying that the SPCC Plan clearly describes the reason why secondary containment
measures are not practicable and documents the implementation of the additional measures required in
§112.7(d), the EPA inspector should verify that:
• The facility's contingency plan can be implemented as written;
• The equipment for response is available;
• The commitment of manpower, equipment, and materials is documented;
• The contingency plan describes the location of drainage systems, containment deployment
locations, and oil collection areas (including recovered oil storage capability);
• There is a process in place to detect a discharge and implement the contingency plan at an
unmanned facility;
• There are procedures for early detection of oil discharges that enables timely contingency plan
implementation;
• There is a defined set of response actions; and
• The contingency plan meets all the criteria of §109.5.
Figure 4-9 provides a checklist that an EPA inspector can review to verify that all the criteria of §109.5
are included in a facility's oil spill contingency plan. The EPA inspector may also refer to the checklist included in
Figure 4-13 at the end of this chapter when identifying and reviewing technical rule requirements that are
eligible for the impracticability provision.
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Figure 4-9:
Chapter 4: Secondary Containment and Impracticability Determination
Checklist of required components of state, local, and regional oil removal contingency plans.
Please refer to the complete text of 40 CFR §109.5.
109.5-Development and implementation criteria for state, local, and regional oil removal
contingency plans*
Yes
No
Definition of the authorities, responsibilities and duties of all persons, organizations or agencies which are to be
involved in planning or directing oil removal operations.
Establishment of notification procedures for the purpose of early detection and timely notification of an oil
discharge including:
(1) The identification of critical water use areas to facilitate the reporting of and response to oil discharges.
(2) A current list of names, telephone numbers and addresses of the responsible persons (with alternates)
and organizations to be notified when an oil discharge is discovered.
(3) Provisions for access to a reliable communications system for timely notification of an oil discharge, and
the capability of interconnection with the communications systems established under related oil
removal contingency plans, particularly State and National plans (e.g., NCR).
(4) An established, prearranged procedure for requesting assistance during a major disaster or when the
situation exceeds the response capability of the State, local or regional authority.
Provisions to assure that full resource capability is known and can be committed during an oil discharge situation
including:
(5) The identification and inventory of applicable equipment, materials and supplies which are available
locally and regionally.
(6) An estimate of the equipment, materials and supplies which would be required to remove the
maximum oil discharge to be anticipated.
(7) Development of agreements and arrangements in advance of an oil discharge for the acquisition of
equipment, materials and supplies to be used in responding to such a discharge.
Provisions for well-defined and specific actions to be taken after discovery and notification of an oil discharge
including:
(8) Specification of an oil discharge response operating team consisting of trained, prepared and available
operating personnel.
(9) Predesignation of a properly qualified oil discharge response coordinator who is charged with the
responsibility and delegated commensurate authority for directing and coordinating response
operations and who knows how to request assistance from Federal authorities operating under existing
national and regional contingency plans.
(10) A preplanned location for an oil discharge response operations center and a reliable communications
system for directing the coordinated overall response operations.
(11) Provisions for varying degrees of response effort depending on the severity of the oil discharge.
(12) Specification of the order of priority in which the various water uses are to be protected where more
than one water use may be adversely affected as a result of an oil discharge and where response
operations may not be adequate to protect all uses.
Specific and well defined procedures to facilitate recovery of damages and enforcement measures as provided for
by State and local statutes and ordinances.
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D D
D
D
D
D
D
D
D
D
D
D
D
D
* The contingency plan should be consistent with all applicable state and local plans, Area Contingency Plans, and the
National Contingency Plan (NCP).
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4.7
Chapter 4: Secondary Containment and Impracticability Determination
Selected Issues Related to Secondary Containment and Impracticability
Determinations
Section 112.7(d) lists the provisions of the SPCC rule for which facility owners or operators may
determine impracticability. Discussed below are commonly raised issues related to secondary containment
requirements for various types of equipment and areas at a facility, and the use of impracticability
determinations.
4.7.1 Piping (General Secondary Containment Requirement, §112.7(c))
Discharge reports from the Emergency Response Notification System (ERNS) suggest that discharges
from valves, piping, flowlines, and appurtenances are much more common than catastrophic tank failure or
discharges from tanks (67 FR 47124, July 17, 2002). To prevent a discharge to navigable waters or adjoining
shorelines, the SPCC rule requires that all piping (including buried piping) comply with the general secondary
containment requirements contained in §112.7(c).89
In many cases, secondary containment for piping will be possible. Nevertheless, §112.7(c) provides
flexibility in the method of secondary containment: active containment measures including land-based response
capability, sorbent materials, drainage systems, and other equipment are acceptable. Section 112.7(c) does not
prescribe a specific containment size for piping; however, the secondary containment must be designed to
address a typical failure mode for the piping and most likely quantity of oil discharged. The SPCC Plan should
describe the expected sources of a discharge from piping systems, maximum flow rate, duration of a discharge,
and discharge detection capability at the facility taking into consideration the specific features of the facility and
operation. Calculations for each piping system may not be practical at large facilities due to the large number
and complexity of the piping; instead, more general assumptions specific to the conditions at the individual
facility may be appropriate as long as they are well documented in the Plan. The EPA inspector should ensure
that the secondary containment method for piping is described in the SPCC Plan and that the PE has certified
that the method is appropriate for the facility according to good engineering practice. In the case of a qualified
facility, the owner or operator would certify that the method is appropriate for the facility in accordance with
accepted and sound industry practices and standards. If active containment measures are selected, the facility
personnel should be able to demonstrate that they can identify a discharge in a timely manner (e.g., a leak
detection method) and effectively deploy these measures to contain a potential spill before it reaches navigable
waters or adjoining shorelines.
Secondary containment may not always be practicable for piping. If secondary containment is not
practicable, then the facility owner/operator may make an impracticability determination and comply with the
alternative regulatory requirements described in §112.7(d), which includes developing an oil spill contingency
plan. In order for a contingency plan to be effective, discharges must be detected in a timely manner. For
The owner/operator of an oil production facility may either, comply with the general secondary containment requirements of
§112.7(c) for flowlines and intra-facility gathering lines or develop a contingency plan and a written commitment of manpower,
equipment and materials in accordance with §112.9(d)(3).
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Chapter 4: Secondary Containment and Impracticability Determination
example, good engineering practice may require that unattended facilities where secondary containment is
impracticable be inspected more frequently than would be required at a typical facility where secondary
containment is provided. The SPCC Plan may include other procedures, testing and or equipment to aid in the
timely implementation of a contingency plan and/or overall oil spill prevention. This may include, but is not
limited to, aggressive pipe integrity management/testing procedures, leak detection equipment and enhanced
corrosion protection. If it is not feasible to effectively and reliably implement a contingency plan and the facility
does not meet the applicability criteria under the Facility Response Plan (FRP) requirements in §112.20, then
owners/operators must determine how to comply with the applicable secondary containment requirements in
§112.7(c).
4.7.2 Loading or Unloading Area (or Transfer Area) (General Secondary Containment
Requirement, §112.7(c))
All areas with the potential for a discharge as described in §112.l(b) are subject to the general
secondary containment provision, §112.7(c). These areas may include loading/unloading areas (also referred to
as transfer areas), piping, mobile refuelers, and may include other areas of a facility where oil is present. A
transfer operation is one in which oil is moved from or into some form of transportation, storage, equipment, or
other device, into or from some other or similar form of transportation, such as a pipeline, truck, tank car, or
other storage, equipment, or device (67 FR 47130, July 17, 2002). Loading or unloading areas where oil is
transferred but no loading/unloading rack (as defined in §112.2) is present are subject to §112.7(c), and thus
appropriate secondary containment and/or diversionary structures to prevent a discharge to navigable waters
or adjoining shorelines are required. The SPCC rule does not require specifically sized containment for transfer
areas; however, containment capacity must be based on the typical failure mode and most likely quantity of oil
that would be discharged.
The general secondary containment requirement at §112.7(c) applies to both loading and unloading
areas. Examples of activities that occur within transfer areas include, but are not limited to:
• Unloading oil from a truck to a heating oil tank;
• Loading oil into a vehicle from a dispenser; and
• Transferring crude oil from an oil production tank battery into tank trucks.
Secondary containment may be either active or passive in design and take into consideration the specific
features of the facility and operation or activity. Specific features of different loading/unloading operations
include the hardware, procedures, and personnel who are able to take action to limit the volume of a discharge.
The determination of adequate general secondary containment volume must consider the typical failure mode
and the most likely quantity of oil that would discharge as a result of that failure:
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Chapter 4: Secondary Containment and Impracticability Determination
• Typical Failure Mode
Identify the source and the mechanism of failure. These could include a failed hose
connection; improper transfer equipment connection or disconnection; pump, valve,
flange or pipe fitting leak; or overfill of a container. Determining the typical failure mode
would be based on the type of transfer operation, equipment, and procedures, facility
experience and spill history, potential for human error, etc.
• Most Likely Quantity of Oil Discharged. This factor is based on the reasonably expected rate of
discharge and duration of the discharge.
The reasonably expected rate of discharge. This factor will depend on the typical mode of
failure. It may be equal to the maximum rate of transfer, e.g., when an improperly
connected transfer hose connection separates, or the expected leakage rate, e.g., from a
pump, pipe flange, pipe fitting, or hose valve.
The ability to detect and react to the discharge. This factor will depend on the availability
of monitoring instrumentation for prompt detection of a discharge and/or the proximity
of personnel to detect and respond to the discharge. The ability to detect a discharge is
critical for the implementation of active containment measures.
The reasonably expected duration of the discharge. This factor may depend on the
accessibility of manual or automatic shutdown mechanisms, the proximity of qualified
personnel to the operation, and other factors that may limit the duration of a discharge.
After identifying the typical failure mode for each transfer area and the most likely quantity of oil that
would be discharged, the facility owner/operator can determine the appropriate type of secondary containment
(i.e., active or passive). To determine if active containment measures are appropriate to address the most likely
discharge quantity, the owner/operator must determine the time it would take a discharge to impact navigable
waters or adjoining shorelines. This factor will depend on the proximity to waterways and storm drains, and the
slope of the ground surface between the loading area and the waterway or drain. The SPCC Plan must describe
the type of secondary containment and, for active containment measures, clearly outline the procedures,
equipment, and personnel necessary to implement this containment strategy.
Additionally, a number of other factors may also affect the appropriate volume for secondary
containment at loading and unloading areas, such as the variable rate of transfer; the ability to control a
discharge from a breached container, if such a breach is reasonably expected to occur; the availability of
personnel in close proximity to the operations and the necessary time to respond; the presence or absence of
monitoring instrumentation to detect a discharge; the type and location of valving that may affect the probable
time needed to stop the discharge; and the presence or absence of automatic valve actuators. These are a few
examples of the factors that a PE may want to consider when reviewing the adequacy of secondary containment
systems at a facility. The EPA inspector may consider the same factors when assessing the adequacy of
secondary containment.
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Chapter 4: Secondary Containment and Impracticability Determination
An example calculation for secondary containment capacity in accordance with §112.7(c), based on
these considerations, is provided in Figure 4-10. Note that the calculation of a most-likely discharge is often a
site-specific determination that must be in accordance with good engineering practice.
Figure 4-10: Sample calculation of appropriate general secondary containment capacity at a transfer area.
Scenario: A fuel truck is loading oil into a heating oil tank at a regulated facility, with an attendant present throughout
the operation.
Details:
• The truck is loading at a rate of 150 gallons per minute.
• The typical failure mode expected is a ruptured hose connection.
• A shutoff valve, present on the loading line, and the pump control are accessible to the attendant.
• An evaluation determines that the discharge will not impede the attendant's access to the shutoff valve and
pump control. The attendant can safely shut down the pump and close the valve within 10 seconds of the hose
connection rupture, based on past experience under similar circumstances; 15 seconds is assumed to be a
conservative estimate of the response time.
Calculations:
With a flow rate of 150 gal/min and a reaction time of 15 seconds, the most likely discharge is calculated to be 37.5
gallons:
[(150 gal/min) x (1 min/60 sec) x (15 sec)] = 37.5 gallons
Conclusion:
Secondary containment volume should be at least 37.5 gallons. A larger volume for secondary containment would be
needed if time required to safely close the shutoff valve takes longer than 15 seconds.
To determine if an active containment measure would be appropriate then the owner or operator also needs to
consider the time it would take the discharge to impact navigable waters or adjoining shorelines.
Secondary containment structures, such as dikes or berms, may not be appropriate in areas where
vehicles continuously need access; however, curbing, drainage systems, active containment measures, or a
combination of these systems can adequately fulfill the secondary containment requirements of §112.7(c). A
facility owner or operator may implement methods for secondary containment other than dikes or berms. For
example, a transfer truck loading area at an onshore oil production facility may be designed to drain discharges
away to a topographically lower area using a crescent or eyebrow-shaped berm. In certain situations, secondary
containment at transfer areas may be impracticable due to geographic limitations, fire codes, etc. In these cases,
owners/operators may determine that secondary containment is impracticable in accordance with §112.7(d),
and must clearly explain the reasons why secondary containment is not practicable and comply with the
alternative regulatory requirements.
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Chapter 4: Secondary Containment and Impracticability Determination
4.7.3 Loading/Unloading Rack (Specific
Secondary Containment Requirements,
§112.2
Loading/unloading rack means a fixed
structure (such as a platform, gangway)
necessary for loading or unloading a tank
truck or tank car, which is located at a facility
subject to the requirements of this part. A
loading/unloading rack includes a loading or
unloading arm, and may include any
combination of the following: piping
assemblages, valves, pumps, shut-off
devices, overfill sensors, or personnel safety
devices.
Note: The above text is an excerpt of the SPCC rule.
Refer to 40 CFR part 112 for the full text of the rule.
Section 112. 7(h) applies to areas at regulated
facilities where traditional loading/unloading racks for tank
cars and tank trucks are located. EPA inspectors should
evaluate compliance with the requirements of §112. 7(h) for
equipment that meets the definition of "loading/unloading
rack" as found in §112.2.
A loading/unloading arm is a critical component of a
loading/unloading rack. A loading/unloading arm is typically a
movable piping assembly that may include fixed piping or a
combination of fixed and flexible piping, typically with at least
one swivel joint (that is, at least two articulated parts that are connected in such a way that relative movement
is feasible to transfer product via top or bottom
loading/unloading to a tank truck or tank car). However,
certain loading/unloading arm configurations present at
loading racks may include a loading/unloading arm that is a
combination of flexible piping (hoses) and rigid piping without
a swivel joint. In this case, a swivel joint is not present on the
loading arm because flexible piping is attached directly to the
rigid piping of the loading arm and the flexible hose provides
the movement needed to conduct loading or unloading
operations in lieu of the swivel joint.
§112.7(h) - Facility tank car and tank
truck loading/unloading rack (excluding
offshore facilities).
(1) Where loading/unloading rack drainage
does not flow into a catchment basin or
treatment facility designed to handle
discharges, use a quick drainage system for
tank car or tank truck loading and unloading
racks. You must design any containment
system to hold at least the maximum
capacity of any single compartment of a tank
car or tank truck loaded or unloaded at the
facility.
Note: The above text is an excerpt of the SPCC rule.
Refer to 40 CFR part 112 for the full text of the rule.
In developing the definition in §112.2, EPA considered
existing definitions of the term "loading rack" and related
terms, as found in industry, federal, state, or international
references, and reviewed various types of equipment
considered components of loading racks (see 72 FR 58378,
October 15, 2007). This definition does not include simple loading or unloading configurations, but rather only
includes the associated equipment and structures associated with loading/unloading arms as part of a rack.
Equipment present at a loading/unloading area where a pipe stand connects to a tank car or tank truck via a
flexible hose is not a loading/unloading rack because there is no loading or unloading arm. Because some top
and bottom loading/unloading racks are made up of a combination of steel loading arms connected by flexible
hosing, the presence of flexible hoses on oil transfer equipment should not be used as an indicator of whether
the equipment meets the definition of loading/unloading rack.
Section 112.7(h)(l) requires a sized secondary containment system: the containment must hold at least
the maximum capacity of any single compartment of a tank car or tank truck loaded or unloaded at the facility.
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Chapter 4: Secondary Containment and Impracticability Determination
However, the SPCC rule does not require that secondary containment for loading/unloading racks be designed
to include freeboard for precipitation. When drainage from the areas surrounding a loading/unloading rack do
not flow into a catchment basin or treatment facility designed to handle discharges, facility owners and
operators must use a quick drainage system (§112.7(h)(l)). A "quick drainage system" is a device that drains oil
away from the loading/unloading area to some means of secondary containment or returns the oil to the
facility.
Loading and unloading activities that take place beyond the rack area are not subject to the
requirements of §112.7(h), but are subject, where applicable, to the general secondary containment
requirements of §112.7(c). Loading/unloading racks can be located at any type of facility; however,
loading/unloading racks are not typically found at farms or oil production facilities. Oil transfers to or from oil
storage containers at farms and oil production facilities where no loading rack is present are subject to the
general secondary containment requirement. For more information on these requirements, see Section 4.7.2,
Transfer Areas.
Figure 4-11 and Figure 4-12 illustrate how SPCC secondary containment requirements apply at two
facilities with loading/unloading areas and with equipment that meet the definition of loading/unloading rack. In
Figure 4-11, the facility has two separate and distinct areas for transfer activities. One is a tank truck unloading
area and the other includes a tank truck loading rack. The unloading area contains no rack structure, so the
secondary containment requirements of §112.7(c) apply. The requirements of §112.7(h) apply to the area
surrounding the loading rack. As highlighted by this example, the presence of a loading rack at one location of a
facility does not subject other loading or unloading areas in a separate part of the facility to the requirements of
§112.7(h).
In Figure 4-12, the tank truck loading rack and unloading area are co-located. In this situation, the more
stringent secondary containment provision applies; therefore, the area is subject to the sized secondary
containment requirements of §112.7(h)(l).
In certain situations, the sized secondary containment requirements of §112.7(h)(l) for
loading/unloading racks may be impracticable due to geographic limitations, fire codes, etc. In these cases, the
owner or operator may determine that secondary containment is impracticable as provided in §112.7(d). Under
that provision, the SPCC Plan must clearly explain the reasons why secondary containment is not practicable,
and comply with the alternative regulatory requirements.
Letter to Petroleum Marketers Association of America
"[T]he Agency does not interpret §112.7(h) to apply beyond activities and/or equipment associated with tank
car and tank truck loading/unloading racks. Therefore, loading and unloading activities that take place beyond the rack
area would not be subject to the requirements of 40 CFR §112.7(h) (but, of course, would be subject, where applicable,
to the general containment requirements of 40 CFR §112.7(c))."
The above text is an excerpt from a letter to Daniel Gilligan, President, Petroleum Marketers Association of America, from Marianne Lamont
Horinko, Assistant Administrator, EPA, May 25, 2004. Found at www.epa.gov/oilspill/pdfs/PMAAJetter.pdf.
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Chapter 4: Secondary Containment and Impracticability Determination
Figure 4-11: Facility with separate unloading area and loading rack. The tank unloading area is subject to
§112.7(c). The tank truck loading rack is subject to §112.7(h)(l).
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Chapter 4: Secondary Containment and Impracticability Determination
Figure 4-12: Facility with co-located unloading area and loading rack. This containment area is designed to
meet the more stringent §112.7(h)(l) provision.
PREVENTION STREET
*rn Predicted direction oFdrainage Fence DIAGRAM ISNOT TO SCALE
4.7.4 Onshore Bulk Storage Container (Specific Secondary Containment Requirements,
§112.8(c)(2) and §112.12(c)(2))
Under the SPCC rule, a bulk storage container is any container used to store oil with a capacity of 55
gallons or more (§§112.1(d)(5) and 112.2). Bulk storage containers are used for purposes including, but not
limited to, the storage of oil prior to use, while being used, or prior to further distribution in commerce. Oil-filled
pieces of electrical, operating, or manufacturing equipment are not considered bulk storage containers.
Bulk storage containers at a regulated facility (except mobile refuelers and other non-transportation-
related tank trucks) must comply with the specific (sized) secondary containment requirements of §112.8(c)(2).90
The specific secondary containment requirements for bulk storage containers do not apply to oil-filled equipment (though they
are subject to the general secondary containment requirements of §112.7(c). Certain oil-filled operational equipment may
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Chapter 4: Secondary Containment and Impracticability Determination
For bulk storage containers, secondary containment must be designed to hold the entire capacity of the largest
single container and sufficient freeboard91 to contain precipitation. Secondary containment is required for all
facilities with bulk storage containers, large or small, attended or
unattended.
Section 112.8(c)(2) considers the use of dikes,
containment curbs, and pits as secondary containment methods,
or allows an alternative system consisting of a drainage trench
enclosure that must be arranged so that any discharge will
terminate and be safely confined in a facility catchment basin or
holding pond. Dikes contain oil in the immediate vicinity of the
storage container, whereas remote impoundment drains
discharge to an area located away from the container. Examples of
design considerations and requirements for these types of
containment are set forth in the National Fire Protection
Association (NFPA) 30 Flammable and Combustible Liquids Code.92
Diked areas must be sufficiently impervious to contain
discharged oil. The purpose of the "sufficiently impervious"
standard is to prevent discharges as described in §112.l(b) by
ensuring that diked areas can contain oil and are sufficiently
impervious to prevent such discharges (67 FR 47117; July 17,
2002). For more information on sufficiently impervious secondary containment see Section 4.4.2.
An owner or operator may determine that secondary containment is impracticable under §112.7(d),
when he or the PE certifying the Plan, determines that it is not practicable to design a secondary containment
system that can hold the capacity of the largest single container plus sufficient freeboard. If secondary
containment is determined to be impracticable, the EPA inspector should verify that the SPCC Plan clearly
explains why secondary containment is not practicable, and that the facility is complying with the alternative
regulatory requirements, such as conducting both periodic integrity testing of the containers and periodic
integrity and leak testing of the valves and piping (§112.7(d)). For further information on the alternative
regulatory requirements in §112.7(d), see Section 4.6.
§§112.8(c)(2) and 112.12(c)(2)
Construct all bulk storage container
installations (except mobile refuelers and
other non-transportation-related tank
trucks) so that you provide a secondary
means of containment for the entire
capacity of the largest single container and
sufficient freeboard to contain
precipitation. You must ensure that diked
areas are sufficiently impervious to contain
discharged oil. Dikes, containment curbs,
and pits are commonly employed for this
purpose. You may also use an alternative
system consisting of a drainage trench
enclosure that must be arranged so that
any discharge will terminate and be safely
confined in a facility catchment basin or
holding pond.
Note: The above text is an excerpt of the SPCC rule.
Refer to 40 CFR part 112 for the full text of the rule.
qualify for alternative requirements in lieu of secondary containment in accordance with §112.7(k).
For more information on sufficient freeboard, see the discussion in Section 4.3.2 of this chapter.
For more information on NFPA, visit their website at www.nfpa.org.
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Chapter 4: Secondary Containment and Impracticability Determination
4.7.5 Mobile/Portable Containers (Except for Mobile Refuelers and Other Non-
Transportation-related Tank Trucks) (Specific Secondary Containment
Requirements, §§112.8(c)(ll) and 112.12(c)(11))
Mobile or portable oil storage containers with a capacity to store 55 gallons or more of oil and operating
exclusively within the confines of a non-transportation-related facility are regulated under the SPCC rule. With
the exception of mobile refuelers and other non-transportation related tank trucks, such containers must
comply with the secondary containment requirements of §112.8(c)(ll) (or §112.12(c)(ll) in the case of a facility
that stores or handles animal fats or vegetable oils).
§§112.8(c)(ll) and 112.12(c)(ll)
Position or locate mobile or portable oil
storage containers to prevent a
discharge as described in §112.l(b).
Except for Mobile facilitys and other
non-transportation-related tank trucks,
you must furnish a secondary means of
containment, such as a dike or
catchment basin, sufficient to contain
the capacity of the largest single
compartment or container with
sufficient freeboard to contain
precipitation.
Note: The above text is an excerpt of the SPCC
rule. Refer to 40 CFR part 112 for the full text of
the rule.
Examples of mobile portable containers include, but are not
limited to, 55-gallon drums, skid tanks, totes, and intermediate bulk
containers (IBCs).
According to §§112.8(c)(ll) and 112.12(c)(ll), mobile or
portable containers (excluding mobile refuelers and other non-
transportation-related tank trucks) must be positioned or located to
prevent a discharge as described in §112.l(b). The provision requires
that the secondary containment be sized to hold the capacity of the
largest single compartment or container with sufficient freeboard to
contain precipitation.
The appropriate containment methods for mobile containers
may vary depending on the activity in which the container is engaged
at a given time. Thus, secondary containment requirements may be
met differently depending upon the type of operation being performed, as described below.
When mobile containers, such as drums, skids, and totes, are in a stationary mode, the requirements of
§§112.8(c)(ll) and 112.12(c)(ll)93 may be met through the use of permanent secondary containment methods,
such as dikes, curbing, drainage systems, and catchment basins. In order to comply with this requirement, an
owner/operator may designate an area of the facility in which to locate mobile containers when not in use. This
area must be designed, following good engineering practices, to hold the capacity of the largest single
compartment or container with sufficient freeboard to contain precipitation. The area designated for mobile
portable containers must be identified on the facility diagram94 provided within the SPCC Plan (§112.7(a)(3)).
While in use, mobile containers, such as drums, skids, and totes, must also comply with the
requirements of §112.8(c)(ll) or §112.12(c)(ll) according to good engineering practice and the areas where the
containers are used must be marked on the facility diagram. For these types of containers, the EPA inspector
should verify that the secondary containment methods are appropriate to prevent a discharge to navigable
waters or adjoining shorelines. For example, an oil-filled drum positioned for use at a construction site must be
Mobile/portable containers at Tier I qualified facilities are subject to §112.6(a)(3)(ii) in lieu of §§112.8(c)(ll) and 112.12(c)(ll).
Tier I qualified facilities are not subject to the facility diagram requirement in §112.7(a)(3).
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equipped with secondary containment sized in accordance with §112.8(c)(ll). The facility owner or operator
may determine that it is impracticable to provide sized secondary containment in accordance with §112.8(c)(ll),
when the container is in use at the facility, or the general containment of §112.7(c), pursuant to §112.7(d). If so,
then the SPCC Plan must properly explain why secondary containment is impracticable, and document the
implementation of the alternative regulatory requirements of §112.7(d).
4.7.6 Mobile Refuelers and other Non-transportation-Related Tank Trucks (General
Secondary Containment Requirement, §112.7(c))
When mobile containers meet the definition of mobile refuelers, in §112.2, then they are excluded from
the sized secondary containment requirements for bulk storage containers. Providing sized secondary
containment for vehicles that move frequently within a non-transportation-related facility to perform refueling
operations can raise safety and security concerns (71 FR 77266, December 26, 2006). However, the general
secondary containment requirements at §112.7(c) still apply. Furthermore, since mobile refuelers are a subset
of bulk storage containers, the other provisions of §§112.8(c) and 112.12(c) also still apply.
§112.2
Mobile refueler means a bulk storage
container onboard a vehicle or towed,
that is designed or used solely to store
and transport fuel for transfer into or
from an aircraft, motor vehicle,
locomotive, vessel, ground service
equipment, or other oil storage
container.
Note: The above text is an excerpt of the SPCC
rule. Refer to 40 CFR part 112 for the full text of
the rule.
The definition of mobile refueler describes vehicles of various
sizes equipped with a bulk storage container such as a cargo tank or
tank truck that is used to fuel or defuel aircraft, motor vehicles,
locomotives, tanks, vessels or other oil storage containers, including
full trailers and tank semi-trailers. The definition also includes nurse
tanks, which are mobile vessels used at farms to store and transport
fuel for transfers to or from farm equipment, such as tractors and
combines, and to other bulk storage containers, such as containers
used to provide fuel to wellhead/relift pumps at rice farms. A nurse
tank is often mounted on a trailer for transport around the farm, and
this function is consistent with that of a mobile refueler.
The exemption from sized secondary containment for mobile
refuelers also applies to other non-transportation-related tank trucks.95 Other non-transportation-related tank
trucks may operate similarly to mobile refuelers, though not specifically transferring fuel. Instead, these tank
trucks may carry other oils such as transformer oils, lubrication oils, crude oil, condensate, or non-petroleum oils
such as AFVOs. Examples include a truck used to refill oil-filled equipment at an electrical substation and a pump
truck at an oil production facility. These tank trucks may have the same difficulty in complying with the sized
secondary containment requirements as mobile refuelers. Therefore, all non-transportation-related tank trucks
are excluded from the sized secondary containment requirements for bulk storage containers, however the
general secondary containment requirements at §112.7(c) apply (see 73 FR 74236, December 5, 2008).
Vehicles used to store oil, operating as on-site fueling vehicles within locations such as construction
sites, military, or civilian remote operations support sites, or rail sidings are generally considered non-
For more information on the jurisdiction of non-transportation-related tank trucks see Chapter 2: SPCC Rule Applicability.
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transportation-related. Indicators of when a vehicle is intended to be used as a storage tank (and therefore
considered non-transportation-related) include, but are not limited to:
• The vehicle is not licensed for on-road use;
• The vehicle is fueled on-site and never moves off-site; or
• The vehicle is parked on a home-base facility and is filled up off-site but then returns to the
home base to fuel other equipment located exclusively within the home-base facility, and only
leaves the site to obtain more fuel.
The exemption from sized secondary containment requirements does not apply to vehicles that are used
primarily to store oil in a stationary location, such as tanker trucks used to supplement storage and serving as a
fixed tank. An indicator that a vehicle is intended to store oil in a fixed location is that the vehicle is no longer
mobile (e.g., it is hard-piped or permanently parked, or that the tank car has been separated from the cab of the
truck).
^Tip- Non-transportation related vehicles and railroad cars
The 1971 Memorandum of Understanding between EPA and the Department of Transportation (DOT) states that
"highway vehicles and railroad cars which are used for the transport of oil exclusively within the confines of a non-
transportation-related facility and which are not intended to transport oil in interstate or intrastate commerce" are
considered non-transportation-related, and therefore fall under EPA's regulatory jurisdiction. For example, some oil
refinery tank trucks and fueling trucks dedicated to a particular facility (such as a construction site, military base, or
similar large facility) fall under this category.
4.7.7 Bulk Storage Containers at Oil Production
Facilities (Sized Secondary Containment
Requirements, §112.9(c)(2))
The secondary containment requirements of
§112.9(c)(2) apply to all tank battery, separation, and treating
facility installations at a regulated oil production facility, except
for flow-through process vessels that comply with the alternative
requirements under §112.9(c)(5), and produced water containers
that comply with the alternative requirements of §112.9(c)(6).
According to the 2002 rule preamble, the sized secondary
containment requirement at §112.9(c)(2) is not required for the
entire leased area, merely for the contents of the largest single
container in the tank battery, separation, and treating facility
installation, with sufficient freeboard to contain precipitation."
(67 FR 47128, July 17 2002) Thus, containers (e.g. drums storing
§112.9(c)(2)
Except as described in paragraph (c)(5) of
this section for flow-through process vessels
and paragraph (c)(6) of this section for
produced water containers and any
associated piping and appurtenances
downstream from the container, construct
all tank battery, separation, and treating
facility installations, so that you provide a
secondary means of containment for the
entire capacity of the largest single container
and sufficient freeboard to contain
precipitation. You must safely confine
drainage from undiked areas in a catchment
basin or holding pond.
Note: The above text is an excerpt of the SPCC rule.
Refer to 40 CFR part 112 for the full text of the rule.
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lubrication oil, which are not located within the tank battery are subject only to the general secondary
containment requirements of §112.7(c) and not subject to §112.9(c)(2).
Section 112.9(c)(2) specifies that secondary containment be designed so that it is able to contain the
entire capacity of the largest single container with sufficient freeboard to contain precipitation.96 Additionally,
pursuant to §112.9(c)(2), if facility drainage is used as a method of secondary containment for bulk storage
containers, drainage from undiked areas must be safely confined in a catchment basin or holding ponds.
Although the undiked drainage requirements of §112.9(c)(2) do not apply to other areas of the facility or lease,
such as truck transfer or wellhead or flowline areas because they are not bulk storage containers, the rule does
require that field drainage systems (such as drainage ditches or road ditches), and oil traps, sumps, or skimmers
be inspected at regularly scheduled intervals. Promptly remove any accumulations of oil in these drainage
systems that may have resulted from a small discharges (§112.9(b)(2)).
Section 112.7(c) also applies and requires the entire containment system, including walls and floor, must
be capable of containing oil and must be constructed so that any discharge from a primary containment system,
such as a tank, will not escape the containment system before cleanup occurs.97
The facility owner/operator may determine that it is impracticable to provide sized secondary
containment in accordance with §112.9(c)(2). Pursuant to §112.7(d), the SPCC Plan must then clearly explain
why secondary containment is not practicable, and document how the alternative regulatory requirements of
§112.7(d) are implemented. Owners or operators of unattended facilities need to determine how to identify
when an oil discharge occurs in order to effectively implement an oil spill contingency plan. This may involve
additional site inspections, or some other method as determined appropriate by a PE.
ip-Oil pits
Because a pit used as a form of secondary containment may pose a threat to birds and wildlife if oil is present in the pit,
EPA encourages owners or operators who use a pit to take measures to mitigate the effect of the pit on birds and
wildlife. Such measures may include netting, fences, or other means to keep birds or animals away. In some cases, pits
may also cause a discharge as described in §112.l(b). The discharge may occur when oil spills over the top of the pit or
when oil seeps through the ground into the groundwater, and then to navigable waters or adjoining shorelines.
Therefore, EPA recommends that an owner or operator not use pits in an area where such pit may prove a source of
such discharges. Should the oil reach navigable waters or adjoining shorelines, it is a reportable discharge under 40 CFR
110.6.
(67 FR 47116; July 17, 2002)
4.7.8 Onshore Drilling or Workover Equipment (Secondary Containment Requirements,
§112.10(c))
Section 112.10(c) applies to onshore oil drilling and workover facilities. Areas with drilling and workover
equipment are required to provide catchment basins or diversion structures to intercept and contain discharges
Refer to Section 4.3.2 of this chapter for more information on calculating sufficient freeboard.
Refer to Section 4.4.2 of this chapter for more information on sufficiently impervious secondary containment.
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Provide catchment basins or diversion
structures to intercept and contain
discharges of fuel, crude oil, or oily drilling
fluids.
Note: The above text is an excerpt of the SPCC rule.
See 40 CFR part 112 for the full text of the rule.
of fuel, crude oil, or oily drilling fluids. This provision contains no
specific sizing requirement, and no freeboard requirement; it is
essentially similar to the general secondary containment
requirement of §112.7(c).
The facility owner/operator may determine that it is
impracticable to provide secondary containment in accordance with §112.10(c). Pursuant to §112.7(d), the SPCC
Plan must then clearly explain why secondary containment is not practicable, and document how the alternative
regulatory requirements of §112.7(d) are implemented.
4.8 Alternative Measures in Lieu of Secondary Containment at Oil
Production Facilities
4.8.1 Flow-through Process Vessels at Oil Production Facilities (General Secondary
Containment Requirements, §112.7(c) and Alternative Requirements)
Flow-through process vessels at oil production facilities, such as horizontal or vertical separation vessels
(e.g., heater-treater, free-water knockout, and gun barrel) have the primary purpose of separating oil from other
fractions (water and/or gas) and sending the fluid streams to the appropriate container. These flow-through
process vessels are bulk storage containers and are subject to the bulk storage container requirements of
§112.9(c) including specific secondary containment requirements of §112.9(c)(2).
There is a potential fire-hazard if spilled oil collects around heater-treaters when dikes or berms are
used to comply with the sized secondary containment requirements of the SPCC rule. Therefore, as an
alternative to the sized secondary containment and inspection requirements for bulk storage containers at oil
production facilities, §§112.9(c)(2)98 and 112.9(c)(3), an oil production facility owner or operator may opt to
provide general secondary containment in accordance with §112.7(c), and comply with the following
requirements for flow-through process vessels at oil production facilities:
• Periodically and on a regular schedule, visually inspect and/or test flow-through process vessels
and associated components (such as dump valves) for leaks, corrosion, or other conditions that
could lead to a discharge as described in §112.l(b);
• Take corrective action or make repairs to flow-through process vessels and any associated
components as indicated by regularly scheduled visual inspections, tests, or evidence of an oil
discharge; and
• Promptly remove or initiate actions to stabilize and remediate any accumulations of oil
discharges.
See Section 4.7.7.
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The additional requirements are necessary because oil production facilities are generally unattended, so
there is a lower potential to immediately discover and correct a discharge than at other facilities that are
typically attended during hours of operation. These alternative measures are optional, i.e., the owner or
operator may still choose to comply with the sized secondary containment and inspection requirements of
§§112.9(c)(2) and 112.9(c)(3). The facility owner or operator can decide which option is best suited to the design
and operation of the facility. For more information on the alternate provisions for flow-through process vessels,
see Chapter 7: Inspection, Evaluation, and Testing, Section 7.2.9.
SPCC Plans that include the alternative measures in §112.9(c)(5) must address how flow-through process
vessels comply with general secondary containment requirements of §112.7(c). Flow-through process vessels
must be provided with secondary containment so that any discharge does not escape the containment system
before cleanup occurs. In determining how to provide appropriate general secondary containment for flow-
through process vessels, an oil production facility owner or operator may consider the typical failure mode and
most likely quantity of oil that would be discharged (see §112.7(c)). Based on site-specific conditions, the owner
or operator can determine what capacity of secondary containment is needed, and design the containment
method accordingly. The design for general secondary containment should address site-specific factors,
including, but not limited to, frequency of site visits, rate of flow of the wells, capacity of the containers, and
whether the facility is equipped with automatic shut-off devices to prevent an overflow (see 73 FR 74278,
Decembers, 2008).
The general secondary containment provision allows for the use of both active and passive containment
measures to prevent a discharge to navigable waters or adjoining shorelines. However, active containment
measures would generally have limited applicability at oil production facilities because these facilities are
typically not attended and owners or operators may not be able to detect a discharge in a timely manner to
successfully implement the active containment measures. In contrast, passive containment measures are
installations that do not require deployment or action by the owner or operator and may be more appropriate
for unattended oil production operations. Section 4.4.1 provides several examples of the use of active and
passive containment measures at an SPCC-regulated facility.
Owners or operators of oil production facilities that implement the alternative provisions for flow-
through process vessels in accordance with §112.9(c)(5) are not required to locate flow-through process vessels
within a secondary containment system sized for the entire capacity of the largest single container and sufficient
freeboard to contain precipitation. However, oil production facility owners and operators may want to provide
secondary containment (such as berms) around the entire tank battery, which is a typical design for many oil
production facilities. These batteries can include flow-through process vessels, such as separators, along with oil
stock tanks and other bulk storage containers. Such a facility design would provide the maximum environmental
protection (see 73 FR 74277, December 5, 2008).
Further, the owner/operator of the facility must install sized secondary containment and comply with
bulk storage container inspection requirements (§112.9(c)(2) and (c)(3)) for flow-through process vessels within
six months of a discharge(s) from flow-through process equipment as described below and a report must be
submitted to the RA in accordance with the requirements of §112.4:
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• More than 1,000 U.S. gallons of oil in a single discharge to navigable waters or adjoining
shorelines, or
• More than 42 U.S. gallons of oil in each of two discharges to navigable waters or adjoining
shorelines within any twelve month period.
This excludes discharges that are the result of natural disasters, acts of war, or terrorism. When
determining the applicability of this SPCC reporting requirement, the gallon amount(s) specified (either 1,000 or
42) refers to the amount of oil that actually reaches navigable waters or adjoining shorelines not the total
amount of oil spilled. EPA considers the entire volume of the discharge to be oil for the purposes of these
reporting requirements.
EPA inspectors should review inspection records to ensure that the Plan is being properly implemented
to comply with the alternative requirements. If, upon inspection, it is discovered that the owner or operator of
the facility is not implementing the alternative requirements included in the SPCC Plan, then the RA may require
the Plan be amended to include sized secondary containment for flow-through process vessels at the facility and
inspections in accordance with 112.9(c)(2) and (c)(3).
Finally, if the owner or operator of the facility determines that secondary containment is impracticable
and chooses not to implement the alternative requirements in §112.9(c)(5), then the facility owner or operator
may comply with §112.7(d). The SPCC Plan must then clearly explain why secondary containment is
impracticable; include with the SPCC Plan an oil contingency plan following the provisions of 40 CFR part 109
(unless he or she has submitted an FRP under §112.20); and provide a written commitment of manpower,
equipment, and materials required to expeditiously control and remove any quantity of oil that may be harmful
(§112.7(d)). Owners or operators of unattended facilities may need to determine how to quickly identify when
an oil discharge occurs in order to effectively implement an oil spill contingency plan. This may involve additional
site inspections, or some other method as determined appropriate by a PE.
4.8.2 Produced Water Containers at Oil Production Facilities (General Secondary
Containment Requirements, §112.7(c) and Alternative Requirements)
Produced water containers are defined in §112.2 and are typically located within a tank battery at an oil
production facility where they are used to store well fluids remaining after marketable crude oil is separated
from the fluids extracted from the reservoir and prior to disposal, re-injection, subsequent use (or beneficial
reuse), or further treatment. Under normal operating conditions, a layer of oil may be present on top of the
fluids in these produced water containers. These produced water containers are typically at the end of the oil
treatment process and often accumulate emulsified oil not captured in the separation process. The amount of
oil by volume observed in produced water containers varies, but is generally estimated to range from less than
one to up to ten percent, and can be greater.
Skimming operations for produced water containers that
remove or recover free phase oil on a regular basis may operate
similarly to separation operations for flow-through process
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§112.2
Produced water container means a
storage container at an oil production
facility used to store the produced water
after initial oil/water separation, and prior
to reinjection, beneficial reuse, discharge,
or transfer for disposal.
Note: The above text is an excerpt of the SPCC
rule. Refer to 40 CFR part 112 for the full text of
the rule.
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Chapter 4: Secondary Containment and Impracticability Determination
vessels. Therefore, the additional compliance measures for produced water containers described below is
consistent with alternative compliance options provided for other bulk storage containers (i.e., flow-through
process vessels) which separate oil and water mixtures.
For produced water containers, instead of complying with the sized secondary containment and
inspection requirements for bulk storage containers at oil production facilities, §§112.9(c)(2)99 and 112.9(c)(3),
an oil production facility owner or operator may opt to provide general secondary containment and comply with
the following additional requirements:
• Implement on a regular schedule a procedure to separate free-phase oil (or skimming program).
• Regularly scheduled visual inspection and/or testing of produced water containers and
associated piping and appurtenances for leaks, corrosion, or other conditions that could lead to
a discharge as described in §112.l(b).
• Corrective action or repairs to produced water containers and any associated piping as indicated
by regularly scheduled visual inspections, tests, or evidence of an oil discharge.
• Prompt removal or initiation of actions to stabilize and remediate any accumulations of oil
discharges associated with produced water containers.
The general secondary containment requirement at §112.7(c) calls for secondary containment to be
designed to hold the most likely quantity of oil potentially discharged in an event, rather than installation of
sized secondary containment designed to hold the contents of the largest container with sufficient freeboard.
Typically, the quantity of oil contained by general secondary containment is expected to be smaller than the
amount of oil that would need to be contained by sized secondary containment. Good general secondary
containment practices can be successfully implemented if such practices are designed by a PE in consideration of
the site specific factors and in combination with additional oil spill prevention practices including inspections,
procedures to minimize the amount of free-phase oil in the container and procedures to remove/ remediate
discharged oil.
See Section 4.7.7.
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§112.9(c)(6)
Produced water containers. For each produced water container, comply with §112.9(c)(l) and (c)(4); and §112.9(c)(2)
and (c)(3), or comply with the provisions of the following paragraphs (c)(6)(i) through (v):
(i) Implement, on a regular schedule, a procedure for each produced water container that is designed to separate
the free-phase oil that accumulates on the surface of the produced water. Include in the Plan a description
of the procedures, frequency, amount of free-phase oil expected to be maintained inside the container,
and a Professional Engineer certification in accordance with §112.3(d)(l)(vi). Maintain records of such
events in accordance with §112.7(e). Records kept under usual and customary business practices will
suffice for purposes of this paragraph. If this procedure is not implemented as described in the Plan or no
records are maintained, then you must comply with §112.9(c)(2) and (c)(3).
(ii) On a regular schedule, visually inspect and/or test the produced water container and associated piping for
leaks, corrosion, or other conditions that could lead to a discharge as described in §112.l(b) in accordance
with good engineering practice.
(iii) Take corrective action or make repairs to the produced water container and any associated piping as indicated
by regularly scheduled visual inspections, tests, or evidence of an oil discharge.
(iv) Promptly remove or initiate actions to stabilize and remediate any accumulations of oil discharges associated
with the produced water container.
(v) If your facility discharges more than 1,000 U.S. gallons of oil in a single discharge as described in §112.l(b), or
discharges more than 42 U.S. gallons of oil in each of two discharges as described in §112. l(b) within any
twelve month period from a produced water container subject to this subpart (excluding discharges that
are the result of natural disasters, acts of war, or terrorism) then you must, within six months from the
time the facility becomes subject to this paragraph, ensure that all produced water containers subject to
this subpart comply with §112.9(c)(2) and (c)(3).
Note: The above text is an excerpt of the SPCC rule. Refer to 40 CFR part 112 for the full text of the rule.
Produced water containers must be provided with secondary containment so that any discharge does
not escape the containment system before cleanup occurs. In determining how to provide appropriate general
secondary containment for produced water containers, a production facility owner or operator may consider the
typical failure mode and most likely quantity of oil that would be discharged (see §112.7(c)). Based on site-
specific conditions, the owner or operator can determine what capacity of secondary containment is needed,
and design the containment method accordingly. The design for general secondary containment should address
site-specific factors, including, but not limited to, frequency of site visits, rate of flow of the wells, frequency of
the free-phase oil separation and removal process or procedure, the amount of oil that typically accumulates on
the surface of the produced water container between skimming operations, capacity of the containers, and
whether the facility is equipped with automatic shut-off devices to prevent an overflow.
The general secondary containment provision allows for the use of both active and passive containment
measures to prevent a discharge to navigable waters or adjoining shorelines. However, active containment
measures would generally have limited applicability at oil production facilities because these facilities are
typically not attended and owners or operators may not be able to detect a discharge in a timely manner to
successfully implement the active measures. In contrast, passive containment measures are installations that do
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not require deployment or action by the owner or operator and may be more appropriate for unattended oil
production operations. See Section 4.4.1 of this guidance for several examples of the use of active and passive
containment measures at an SPCC-regulated facility.
The facility owner or operator must implement a process and/or procedure for the produced water
container (s) that is designed to remove the free-phase oil that accumulates on the surface of the produced
water container. This process or procedure must be implemented on a regular schedule so that the amount of
free phase oil that collects in produced water containers is within the amounts managed by the general
secondary containment system designed by the PE to address the typical failure mode, and the most likely
quantity of oil that would be discharged.
The SPCC Plan must include a description of the free-phase oil separation and removal process or
procedure, the frequency it is implemented or operated, the amount of free-phase oil expected to be
maintained inside the container, and a description of the adequacy of the general secondary containment
approach for the produced water container, including the anticipated typical failure mode and the method,
design, and capacity for general secondary containment. Additionally, the owner or operator must keep records
of the implementation of these procedures in accordance with §112.7(e) (see 73 FR 74287, December 5, 2008).
Section 112.3(d)(l)(vi) requires the PE to certify that an oil removal process or procedure for produced
water containers is designed according to good engineering practice to reduce the accumulation of free-phase
oil, and that the process or procedure and frequency for required inspections, maintenance, and testing have
been established. Oil production facility owners or operators that meet the criteria for Tier II qualified facilities
(as described in §112.3(g)) and choose to self-certify their SPCC Plans cannot take advantage of the flexibility
allowed in the alternative requirements for produced water containers, unless the procedures for skimming
produced water containers are reviewed and certified in writing by a PE (§112.6(b)(3)(iii) and 112.6(b)(4)).
If the facility experiences a discharge of more than 1,000 U.S. gallons of oil in a single discharge to
navigable waters or adjoining shorelines, or discharges more than 42 U.S. gallons of oil in each of two discharges
to navigable waters or adjoining shorelines, occurring within any twelve month period (excluding discharges that
are the result of natural disasters, acts of war, or terrorism)100 from any produced water container, then the
facility owner/operator may no longer take advantage of this alternative option and must comply with the sized
secondary containment requirements at §112.9(c)(2) and the inspection requirements at §112.9(c)(3) within six
months for all produced water containers at the facility. Additionally, in accordance with the requirements of
§112.4, the owner or operator must submit a report to the RA within 60 days of the discharge(s) and to the
appropriate state agency or agencies in charge of oil pollution control activities.
The facility owner/operator may determine that it is impracticable to provide sized secondary
containment for produced water containers in accordance with §112.9(c)(2) and choose not to implement the
alternative requirements for these containers as described in §112.9(c)(6). The SPCC Plan must then clearly
When determining the applicability of this SPCC reporting requirement, the gallon amount(s) specified (either 1,000 or 42)
refers to the amount of oil that actually reaches navigable waters or adjoining shorelines not the total amount of oil spilled. EPA
considers the entire volume of the discharge to be oil for the purposes of these reporting requirements.
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explain why secondary containment is not practicable; include with the SPCC Plan an oil spill contingency plan
following the provisions of 40 CFR part 109 (unless he or she has submitted an FRP under §112.20); and provide
a written commitment of manpower, equipment, and materials required to expeditiously control and remove
any quantity of oil that may be harmful (§112.7(d)). Owners or operators of unattended facilities may need to
determine how to quickly identify when an oil discharge occurs in order to effectively implement an oil spill
contingency plan. This may involve additional site inspections, or some other method as determined appropriate
byaPE.
Finally, these alternative measures are optional. The owner or operator may still choose to comply with
the sized secondary containment and inspection requirements of §§112.9(c)(2) and 112.9(c)(3) for produced
water containers. The facility owner or operator can decide which option is best suited to the design and
operation of the facility. For more information on the alternate provisions for produced water containers, see
Chapter 7: Inspection, Evaluation, and Testing, Section 7.2.10.
r&.
V? Tip - Discharge from flow-through process vessels or produced water containers
If flow-through process vessels or produced water containers at the facility cause a single discharge of oil to navigable
waters or adjoining shorelines exceeding 1,000 U.S. gallons, or two discharges of oil to navigable waters or adjoining
shorelines each exceeding 42 U.S. gallons within any 12-month period then:
Install sized secondary containment with sufficient freeboard for precipitation for the type of containers that
caused the discharge (i.e., either all flow-process vessels or all produced water containers at the facility)
within six months of such a discharge(s), and
Submit a report to the Regional Administrator (in accordance with the requirements of §112.4) within 60 days
of the discharge(s) and to the appropriate state agency or agencies in charge of oil pollution control activities.
The report must include the name of the facility; the name of the owner or operator; location of the facility; maximum
storage or handling capacity of the facility and normal daily throughput; corrective action and countermeasures taken,
including a description of equipment repairs and replacements; an adequate description of the facility, including maps,
flow diagrams, and topographical maps, as necessary; the cause of the discharge(s), including a failure analysis of the
system or subsystem in which the failure occurred; additional preventive measures taken or contemplated to minimize
the possibility of recurrence; and any other information as the Regional Administrator may reasonably require
pertinent to the Plan or discharge.
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Figure 4-13: List of SPCC requirements eligible for impracticability determinations.
Rule Element
Relevant
Section(s)
Evaluation
Verification
Nonconformance
ALL FACILITIES
General
Containment
112.7(c)
Are appropriate containment and/or diversionary
structures provided to prevent a discharge to navigable
waters of adjoining shorelines?
Is the containment system capable of containing oil and
constructed so that any discharge from the primary
containment system will not escape before cleanup
occurs?
Are active measures properly documented?
Is the most likely discharge volume documented?
Visual.
Does the Plan explain why secondary containment is
impracticable?
Is a Contingency Plan (or FRP) provided?
Does the Plan include a written commitment of manpower,
equipment, and materials?
Does the facility conduct periodic integrity testing of bulk
storage containers and integrity and leak testing of associated
valves and piping?
Does the facility implement alternative measures for qualified
oil-filled operational equipment (§112.7(k))?
Does an oil production facility implement alternative measures
for flowlines and intra-facility gathering lines as provided in
§112.9(d)(3)?
Loading/unloading
Racks
Does the loading/unloading rack area drainage flow
into a catchment basin or treatment facility?
If not, is a quick drainage system used?
Is the secondary containment system sized to contain the
maximum capacity of any single compartment of a tank
car or tank truck loaded there?
Visual.
Does the Plan explain why secondary containment is
impracticable?
Is a Contingency Plan (or FRP) provided?
Does the Plan include a written commitment of manpower,
equipment, and materials?
ALL ONSHORE FACILITIES, EXCEPT OIL PRODUCTION
Bulk Storage
Containers
112.8(c)(2)
OR
Is the secondary containment system (except when for
mobile refuelers and other non-transportation-related
tank trucks) sized to contain the entire capacity of the
largest single container and sufficient freeboard to
contain precipitation?
Are dikes sufficiently impervious to contain oil?
Visual.
Does the Plan explain why secondary containment is
impracticable?
Is a Contingency Plan (or FRP) provided?
Does the Plan include a written commitment of manpower,
equipment, and materials?
Does the facility conduct periodic integrity testing of bulk
storage containers and integrity and leak testing of associated
valves and piping?
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Chapter 4: Secondary Containment and Impracticability Determination
Rule Element
Relevant
Section(s)
Evaluation
Verification
Nonconformance
OR
Are mobile or portable oil containers (except mobile
refuelersand other non-transportation-related tank
trucks) located within a dike, catchment basin or other
means of secondary containment large enough to
contain the largest single container and sufficient
freeboard to contain precipitation?
Visual.
Does the Plan explain why secondary containment is
impracticable?
Is a Contingency Plan (or FRP) provided?
Does the Plan include a written commitment of manpower,
equipment, and materials?
Does the facility conduct periodic integrity testing of bulk
storage containers and integrity and leak testing of associated
valves and piping?
ONSHORE OIL PRODUCTION FACILITIES
Drainage
112.9(c)(2)
Is drainage from undiked areas safely confined in a
catchment basin or holding pond?
Visual.
Does the Plan explain why secondary containment is
impracticable?
Is a Contingency Plan (or FRP) provided?
Does the Plan include a written commitment of manpower,
equipment, and materials?
Does the facility conduct periodic integrity testing of bulk
storage containers and integrity and leak testing of associated
valves and piping?
Bulk Storage
Containers
112.9(c)(2)
Are all tank battery, separation, and treatment facility
installations provided with secondary containment that
can contain the largest single container and sufficient
freeboard to contain precipitation?
Visual.
Does the Plan explain why secondary containment is
impracticable?
Is a Contingency Plan (or FRP) provided?
Does the Plan include a written commitment of manpower,
equipment, and materials?
Does the facility conduct periodic integrity testing of bulk
storage containers and integrity and leak testing of associated
valves and piping?
Does the facility implement alternative measures for flow-
through process vessels in accordance with §112.9(c)(5)?
Does the facility implement alternative measures for produced
water tanks in accordance with §112.9(c)(6)?
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Chapter 4: Secondary Containment and Impracticability Determination
Rule Element
Relevant
Section(s)
Evaluation
Verification
Nonconformance
Flow-through
Process Vessels
112.9(c)(2)
Are all flow-through process vessels provided with
secondary containment that can contain the largest
single container and sufficient freeboard to contain
precipitation?
- or-
Are appropriate containment and/or diversionary
structures provided?
Is the containment system capable of containing oil and
constructed so that any discharge from the primary
containment system will not escape before cleanup
occurs?
Are flow-through process vessels and components
inspected or tested for leaks, corrosion or other
conditions that could lead to a discharge to navigable
waters or adjoining shorelines?
Are oil accumulations promptly removed or actions
initiated to stabilize and remediate them?
Was corrective action taken if a discharge occurred?
Visual.
Does the facility comply with §112.9(c)(2)?
- or-
Does the Plan explain why secondary containment is
impracticable?
Is a Contingency Plan (or FRP) provided?
Does the Plan include a written commitment of manpower,
equipment, and materials?
Does the facility conduct periodic integrity testing of bulk
storage containers and integrity and leak testing of associated
valves and piping?
- or-
Does the facility comply with alternative requirements in
§112.9(c)(5)?
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Chapter 4: Secondary Containment and Impracticability Determination
Rule Element
Produced Water
Containers
Relevant
Section(s)
112.9(c)(2)
Evaluation
Are all produced water containers provided with
secondary containment that can contain the largest
single container and sufficient freeboard to contain
precipitation?
- or -
Are appropriate containment and/or diversionary
structures provided?
Is the containment system capable of containing oil and
constructed so that any discharge from the primary
containment system will not escape before cleanup
occurs?
Is there a procedure to separate free-phase oil? Are
records maintained that document implementation of
the procedure?
Is periodic inspection and/or testing of produced water
containers and any associated piping and appurtenances
for leaks, corrosion, or other conditions that could lead
to a discharge to navigable waters or adjoining
shorelines, conducted?
Are corrective action or repairs to produced water
containers and any associated piping taken, as indicated
by regularly scheduled visual inspections, tests, or
evidence of an oil discharge?
Are oil accumulations promptly removed or actions
initiated to stabilize and remediate them?
Verification
Visual.
Nonconformance
Does the facility comply with §112.9(c)(2)?
- or-
Does the Plan explain why secondary containment is
impracticable?
Is a Contingency Plan (or FRP) provided?
Does the Plan include a written commitment of manpower,
equipment, and materials?
Does the facility conduct periodic integrity testing of bulk
storage containers and integrity and leak testing of associated
valves and piping?
- or-
Does the facility comply with alternative requirements in
§112.9(c)(6)?
ONSHORE OIL DRILLING AND WORKOVER FACILITIES
Drainage
112.10(c)
Are catchment basins or diversion structures provided to
intercept and contain discharges of fuel, crude oil, or oily
drilling fluids?
Visual.
Does the Plan explain why secondary containment is
impracticable?
Is a Contingency Plan (or FRP) provided?
Does the Plan include a written commitment of manpower,
equipment, and materials?
Does the facility conduct periodic integrity testing of bulk
storage containers and integrity and leak testing of associated
valves and piping?
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Chapters Oil/Water Separators
5.1 Introduction
The intended use of an oil/water separator(s) (OWS) determines whether the separator is subject to the
SPCC regulations and, if so, what provisions are applicable. This chapter explains the applicability of the SPCC
rule to OWS, and clarifies the exemption for certain uses, including equipment, vessels, and containers that are
not specifically called "OWS" but perform oil/water separation, such as water clarifiers at wastewater treatment
plants. This chapter also discusses the alternative compliance options for flow-through process vessels at oil
production facilities.
Table 5-1 below outlines the SPCC rule applicability for various uses of OWS. Only OWS used exclusively
to treat wastewater and not used to satisfy any requirement of 40 CFR part 112 are exempt from all SPCC
requirements. OWS used in oil production, recovery or recycling and to meet the secondary containment
requirements of the rule are not exempt.
Table 5-1: SPCC rule applicability for various uses of OWS.
Wastewater Treatment
Separators are exempt from
all SPCC requirements in
accordance with
§112.1(d)(6)anddonot
count toward facility
storage capacity.
Secondary Containment
Separators that are used as
part of a secondary
containment system and are
not intended for oil storage
or use do not themselves
require secondary
containment and do not
count toward facility
storage capacity. However,
they are subject to the
design specifications (e.g.,
capacity) for the secondary
containment requirements
with which they are
designed to comply.
Oil Production
Separators are bulk storage
containers and are not
exempt; they count toward
the facility storage capacity.
They are subject to the
provisions of §§112.7 and
§§112.9(c)orll2.11(b)and
(d).
Oil Recovery and/or
Recycling
Separators are not exempt
and count toward the
facility storage capacity.
Separators are oil-filled
manufacturing equipment
subject to the provisions of
§112.7 and §§112.8(b) and
(d)orl!2.12(b)and(d), as
applicable.101
The §§112.8(c) and 112.12(c) provisions for bulk storage containers do not apply because oil/water separators at these facilities
function as oil-filled manufacturing equipment and are not bulk storage containers.
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Chapter 5: Oil/Water Separators
The remainder of this chapter is organized as follows:
• Section 5.2 summarizes applicable SPCC rule provisions to the four uses of OWS identified
above.
• Section 5.3 discusses the exemption for the use of an OWS as wastewater treatment.
• Section 5.4 addresses applicable SPCC requirements for the use of an OWS as secondary
containment.
• Section 5.5 discusses applicable SPCC requirements for the use of an OWS at oil production
facilities.
• Section 5.6 discusses applicable SPCC requirements for the use of an OWS at oil recovery or
recycling facilities.
• Section 5.7 describes required documentation for OWS and the role of the EPA inspector in
reviewing facilities with OWS.
5.2 Overview of Provisions Applicable to OWS
The following paragraphs briefly summarize the four uses of OWS and identify the SPCC provisions
applicable to each. These requirements are discussed in greater detail in Sections 5.3 through 5.6.
5.2.1 Wastewater Treatment Facilities
Section 112.1(d)(6) of the SPCC rule addresses OWS used for wastewater treatment. Facilities or
equipment used exclusively for wastewater treatment, and which do not satisfy any requirements of the SPCC
rule, are exempt from the SPCC rule requirements. These OWS do not count toward facility storage capacity.
Whether a wastewater treatment facility or part thereof is used exclusively for wastewater treatment or used to
satisfy an SPCC requirement will often be a facility-specific determination based upon the activities carried out
at the facility and upon its configuration.
5.2.2 OWS Used for Secondary Containment
OWS used to meet the SPCC requirements for general secondary containment, sized secondary
containment, or facility drainage are subject to applicable rule requirements, but they do not count toward
storage capacity. These include OWS that are used to meet the secondary containment requirements of
§§112.7(c), 112.7(h)(l), 112.8(c)(2), 112.8(c)(ll), 112.12(c)(2), and/or 112.12(c)(ll). Drainage systems that
satisfy the secondary containment requirements may use OWS to recover oil and return it to the facility (see
Chapter 4: Secondary Containment and Impracticability for a description of secondary containment
requirements). Additionally, the drainage provisions in §§112.8(b) and 112.9(b) set forth design specifications
for secondary containment at a facility.
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Chapter 5: Oil/Water Separators
5.2.3 Oil Production Facilities
Production, recovery, and recycling of oil are not considered wastewater treatment and, thus, are not
eligible for the wastewater treatment exemption. For purposes of §112.1(d)(6), such activities also include
recovery and recycling of crude oil at facilities associated with, and/or downstream of, production facilities, such
as saltwater disposal (produced water) and injection facilities.
OWS associated with oil production activities are subject to §112.7 and applicable provisions of §112.9
for onshore oil production facilities or §112.11 for offshore oil production facilities. Examples of OWS associated
with oil production, separation, and treatment include free water knockouts, two- and three-phase separators,
and gun barrels.
5.2.4 Oil Recovery and/o r Recycling Facilities
Oil recycling and recovery activities that collect and consolidate production fluids from multiple oil
production facilities in an effort to further recover and treat oil prior to the disposal of production fluids are not
eligible for the wastewater treatment exemption because the operations focus on oil treatment rather than
wastewater treatment. These operations typically specialize in the treatment of production fluids and other oil
recovery activities, and may include disposal and injection of production fluids. Other oil recycling operations
include waste oil recyclers not associated with oil production operations (e.g., motor oil recyclers) and facilities
engaged in the recovery and/or recycling of animal fats and vegetable oils (AFVO).
Figure 5-1 to Figure 5-4 illustrate rule requirements or exemptions based upon the use of OWS at SPCC-
regulated facilities.
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Chapter 5: Oil/Water Separators
Figure 5-1: OWS subject to wastewater treatment exemption.
Are exempt from all SPCC
requirements in
accordance with
§112.1(d)(6)andnot
subject to the rule**
Do not count toward overall
storage capacity at the
facility**
"Any oil storage container that is
used to hold oil removed from the
separation process is considered
a bulk storage container and
must comply with applicable
SPCC requirements
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Chapter 5: Oil/Water Separators
Figure 5-2: OWS used to satisfy SPCC rule requirements.
OWS used exclusively to satisfy SPCC
rule requirements
OWS used to comply with
general secondary containment
requirements of 112.7(c)
OWS used to comply with
sized secondary requirements
for loading/unloading racks in
OWS used to comply with
sized secondary requirements
for bulk storage containers in
OWS used to comply with
facility drainage requirements
of 112.8(b), 112.9(b)or
OWS used at an Offshore
Drilling, Workover and
Production Facility
Secondary containment sized
to address the most likely oil
discharge from any part of the
facility
Must be sized to contain the
maximum capacity of any
single compartment of a tank
truck/car loaded or unloaded at
the facility
Must be sized to contain the
largest single bulk storage
container with sufficient
freeboard to contain
precipitation
OWS used as
secondary containment
to comply with 112.7(c)
OWS used as part of
the oil production
process are subject to
§112.7 (including
112.7(c)), 112.11(b)
and112.11(d)
(See Figure 5-3)
Are not bulk storage containers
and not subject to bulk storage
container requirements'*
> not count toward overall
storage capacity at the facility**
"Any oil storage container that is
used to hold oil removed from the
separation process is considered
a bulk storage container and
must comply with applicable
SPCC requirements
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Chapter 5: Oil/Water Separators
Figure 5-3: OWS at oil production facilities.
Production, Drilling or Workover
Facilities
Offshore Drilling, Workover
and Production Facility
OWS are flow-through process
vessels and are subject to
§112.7 and applicable
requirements of §112.9
Subject to specific
secondary containment
requirements of 112.9(c)(2)
and visual inspection
requirements of 112.9(c)(3)
Secondary containment
must be designed to
contain the capacity of
largest single container
and sufficient freeboard to
contain precipitation
Subject to general
secondary containment
requirements of 112.7(c)
and the alternative
requirements of 112.9(c)(5)
T
Facility owner/operator
must perform periodic
inspections, take corrective
actions, and promptly
remove or remediate any
accumulations of oil.
Secondary containment
sized to address the most
likely oil discharge from
any part of the facility
'
OWS used as part of the
oil production process are
subject to §112.7 (including
112.7(c)), 112.11(b) and
Secondary containment
sized to address the most
likely oil discharge from
any part of the facility
Count toward overall
storage capacity at
the facility
OWS used to comply with
112.7(c)
(See Figure 5-2)
"Any oil storage container that is
used to hold oil removed from the
separation process is considered
a bulk storage container and
must comply with applicable
SPCC requirements
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Chapter 5: Oil/Water Separators
Figure 5-4: OWS at oil recovery and/or recycling facilities.
Onshore Oil Recycling or Oil
Recovery Facilities
OWS are oil-filled
manufacturing equipment
and not bulk storage
containers
Subject to §112.7
requirements including
§112.7(c) general
secondary containment
Petroleum and Non-
petroleum Oil Facilities
(except AFVO)
Subject to requirements of
§112.8(b)§112.8(d)
AFVO Facilities
Subject to requirements of
§112.12(b)§112.12(d)
Count toward overall
storage capacity at the
facility
"Any oil storage container that is
used to hold oil removed from the
separation process is considered
a bulk storage container and
must comply with applicable
SPCC requirements
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Chapter 5: Oil/Water Separators
5.3 OWS Used for Wastewater Treatment
5.3.1 OWS Used for Wastewater Treatment
OWS used to pre-treat wastewater are typically standard gravity or enhanced gravity separators.102
Standard gravity separators, as illustrated in Figure 5-5 (separator designs may vary), are liquid containment
structures that provide sufficient hydraulic retention time to allow oil droplets to rise to the surface. The oil
forms a separate layer that can then be removed by skimmers, pumps, or other methods. The wastewater outlet
is located below the oil level so that water leaving the separator is free of the oil that accumulates at the top of
the unit. The inlet is often fitted with diffusion baffles to reduce turbulent flow that might prevent effective
separation of the oil and might re-suspend settled pollutants.
Figure 5-5: Standard gravity oil/water separator.
Wastewater
Separated Oil
Enhanced gravity separators allow the separation of smaller oil droplets within confined spaces. These
separators use a variety of coalescing media and small diameter cartridges that enhance laminar flow and
separation of smaller oil droplets that accumulate on the separator surface for removal. Figure 5-6 shows
coalescing plates in the middle compartment (separator designs may vary).
102
Other types of separators include vortex separators, which combine gravity with centrifugal forces.
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Chapter 5: Oil/Water Separators
Figure 5-6: Enhanced gravity oil/water separator.
Wastewater
Separated Oil
\7
Treated Water
OWS are flow-through equipment in which wastewater enters the separator and treated water exits the
separator typically on a continual basis. To be effective, the OWS is sized appropriately in order for the unit to
separate and contain the intended oil capacity, in addition to the flow-through wastewater quantity. Also, the
design flow rate of the OWS is carefully considered when specifying a wastewater treatment system, as a flow
rate above the maximum rate of the separator will cause the discharge of accumulated oil and/or untreated
wastewater. The specifications from OWS manufacturers typically outline these and other design factors and
considerations, along with operation and maintenance requirements, to ensure that the OWS is correctly
constructed and operated for its intended use.
5.3.2 Applicability of the SPCC Rule to OWS Used for Wastewater Treatment
Section 112.1(d)(6) exempts "any facility or part thereof" that is used exclusively for wastewater
treatment and is not used to meet any other requirement of the rule (excluding oil production, recovery, and
recycling facilities). There are components of wastewater treatment facilities, such as treatment systems at
publicly owned treatment works (POTWs) and industrial wastewater treatment facilities treating oily
wastewater, that likely meet the two criteria for this exemption. OWS used exclusively for wastewater
treatment are flow-through separators and are not engaged in a static process in an isolated container. For
example, the presence of a water sump in a bulk storage container does not constitute wastewater treatment.
POTWs and other wastewater treatment facilities may have bulk storage containers and oil-filled
equipment, as well as exempt OWS. The capacities of the bulk storage containers and oil-filled equipment are
counted to determine whether the facility is subject to the requirements of the SPCC rule. The presence of an
OWS at an otherwise regulated facility does not exempt the entire facility from the SPCC rule requirements.
Such OWS capacity does not count toward the overall storage capacity of the facility, and only that equipment
used for oil/water separation is not subject to any rule provisions. At wastewater treatment facilities, storage
capacities to be counted include bulk storage containers, hydraulic equipment associated with the treatment
process, containers used to store oil that feed an emergency generator associated with wastewater treatment,
and slop tanks or other containers used to store oil resulting from treatment. All separate containers used to
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Chapter 5: Oil/Water Separators
store oil recovered by the separation process and all other equipment or containers at a regulated facility that
do not qualify for the wastewater treatment exemption are required to meet the applicable SPCC requirements
(67 FR 47069, July 17, 2002).
Examples of wastewater treatment OWS that may be eligible for the exemption of §112.1(d)(6) include:
• OWS at a wastewater treatment facility;
• OWS at an active groundwater remediation site;
• Grease traps that intercept and congeal oil and grease from liquid waste; and
• OWS in landfill leachate collection systems.
A separate container storing oil removed from an exempt separator is considered a bulk storage
container and is subject to the SPCC rule requirements. Furthermore, OWS exempted from the SPCC rule may be
subject to other federal, state, and local regulations. For example, many exempted wastewater treatment OWS
are within wastewater treatment facilities or parts thereof subject to the National Pollutant Discharge
Elimination System (NPDES) requirements under section 402 of the Clean Water Act (CWA). NPDES (or an
approved state permit program) ensures review and approval of the facility's wastewater treatment plans and
specifications, as well as operation/maintenance manuals and procedures, and requires a Storm Water Pollution
Prevention Plan, which may include a Best Management Practice (BMP) Plan.103
Additionally, some facilities may be subject to pretreatment standards promulgated under §307(b) of
the CWA. Pretreatment standards apply to "indirect discharges" that go first to a POTW via a collection system
before being discharged to navigable waters. The General Pretreatment Regulations for Existing or New Sources
of Pollution, found at 40 CFR part 403, prohibits an indirect discharger from introducing into a POTW a pollutant
that passes through or interferes with treatment processes at the POTW, and also sets the framework for the
implementation of categorical pretreatment standards. Specifically, 40 CFR 403.5(b)(6) prohibits the
introduction into a POTW of "petroleum, oil, non-biodegradable cutting oil, or products of mineral oil origin in
amounts that will cause interference or pass through."
103
BMPs are operational conditions that may supplement or constitute effluent limitations in NPDES permits. Under §402(a)(2) of
CWA, BMPs may be imposed in addition to effluent limits when the EPA Administrator determines that such conditions are
necessary to carry out the provisions of the Act. See discussion of authority for NPDES and BMP provisions in the preamble to
the 2002 final SPCC rule, 67 FR 47068.
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Chapter 5: Oil/Water Separators
01 Example of SPCC Rule Applicability and Secondary Containment Requirements: Kitchen Grease Trap
A kitchen grease trap at a facility otherwise subject to the SPCC rule and that is used solely for the pretreatment of
wastewater is eligible for the wastewater treatment exemption. However, the transfer of oily wastewater and sludge
from this exempt grease trap, using a vacuum truck, is subject to the general containment requirements of §112.7(c) if
the transfer area does not meet the definition of a "loading/unloading rack." Sufficient secondary containment for a
grease trap unloading area may be provided by active containment measures deployed either prior to transfer (e.g.,
placement of a drain cover over a storm water drop inlet) or in reaction to a discharge as long as the certifying PE
determines that the active containment measures are sufficient and can be reliably deployed in time to prevent the
spilled material from reaching navigable waters or adjoining shorelines.
5.3.3 Wastewater Treatment Exemption Clarification for Dry Gas Production Facilities
^^^^W^^srnsrechmtW^aWtfty is a facility that produces natural gas from a well (or wells) from which it
does not also produce condensate or crude oil that can be drawn off the tanks, containers or other production
equipment at the facility. Since no oil is being "produced" at these dry gas facilities they may be eligible for the
wastewater treatment exemption because they are not "oil production, oil recovery, or oil recycling facilities."
Produced water containers used exclusively for wastewater treatment at dry gas production facilities are not
excluded from the wastewater treatment exemption (69 FR 29728, May 25, 2004). These produced water
containers are eligible for the wastewater treatment exemption and therefore do not count toward oil storage
capacity and are not subject to the rule's requirements.
It should be noted that in the 2008 amendments to the SPCC rule (73 FR 74236, December 5, 2008), EPA
added the term "condensate" to the definition of production facility. The purpose of this amendment was to
clarify that certain gas facilities (i.e., wet gas facilities) that produce oil in the form of condensate are oil
production facilities and may be subject to the SPCC rule. As oil production facilities, wet gas facilities are not
eligible for the waste water treatment exemption.
At 69 FR 29730, EPA stated that
"...[in] verifying that a particular gas facility is not an 'oil production, oil recovery, or oil recycling facility/
the Agency plans to consider, as appropriate, evidence at the facility pertaining to the presence or
absence of condensate or crude oil that can be drawn off the tanks, containers or other production
equipment at the facility, as well as pertinent facility test data and reports (e.g., flow tests, daily gauge
reports, royalty reports or other production reports required by state or federal regulatory bodies)."
5.4 OWS Used to Meet SPCC Secondary Containment Requirements
5.4.1 OWS Used to Meet SPCC Secondary Containment Requirements
Properly designed, maintained, and operated OWS may be used as part of a facility drainage system to
meet the secondary containment requirements of the rule in §§112. 7(c), 112.7(h)(l), 112.8(c)(2), 112.8(c)(ll),
112.12(c)(2), and/or 112.12(c)(ll). Additionally, §§112.8(b), 112.9(b), and 112.12(b) set forth design
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Chapter 5: Oil/Water Separators
specifications for drainage associated with secondary containment provisions at the facility. See Chapter 4:
Secondary Containment and Impracticability for a detailed discussion of secondary containment requirements.
Standard gravity and enhanced gravity separators (Figure 5-5 and Figure 5-6), or other types of OWS,
may be used to meet secondary containment requirements. In this application, the separators are expected to
have oil and water present in the system when there is an oil discharge or oil-contaminated precipitation runoff
within the drainage area. These separators should be monitored on a routine schedule and collected oil should
be removed as appropriate in accordance with procedures described in the SPCC Plan.
When designing OWS to be used as secondary containment, the SPCC Plan preparer should consider:
• The drainage area that flows to the separator;
• The corresponding anticipated flow rate of the drainage system to the separator; and
• The appropriate capacity of the OWS for oil and for wastewater.
Many OWS used for secondary containment are installed in areas where they may receive considerable
flow from precipitation. If the precipitation flow rate exceeds the maximum design rate of a separator, it may
discharge accumulated oil and/or untreated wastewater to navigable waters or adjoining shorelines. In this case,
the separator may be an inappropriate choice for secondary containment. The specifications from OWS
manufacturers outline these and other design factors as important items to consider when determining the use
of a given OWS for a given application. Additionally, the manufacturer specifies the maintenance requirements
to ensure proper operation of the separator.
When OWS are used to meet SPCC requirements, they must be properly operated and maintained to
ensure they will perform correctly and as intended under the potential discharge scenarios it is aimed to address
(e.g., §§112.7(c), 112.8(c)(2), and 112.12(c)(2)). Required OWS capacities should always be available (i.e., oil
should not continually accumulate in the separators over a period of time such that the required storage
capacities would not be available if an oil discharge were to occur within the drainage areas).
The use of OWS as a method of containment may be risky as they have limited drainage controls to
prevent a discharge of oil and their reliability rests heavily on proper maintenance. This is particularly true when
using a separator to meet the sized secondary containment requirements for large bulk storage containers, as
separators are not typically designed to accommodate a worst case discharge of oil. EPA inspectors noting this
containment configuration should closely inspect the device and review records associated with documenting
the design criteria of the equipment and the routine maintenance performed on such equipment.
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Chapter 5: Oil/Water Separators
v* FYI - Oil/water separators used for secondary containment
When oil/water separators are used for secondary containment:
• Oil contained in the separator does not count toward facility total oil storage capacity
• Do not require additional secondary containment (i.e. tertiary containment) for the separator
Remember to observe the effluent treatment systems associated with bulk storage containers to prevent discharges to
navigable waters or adjoining shorelines.
5.4.2 Applicability of the SPCC Rule to OWS Used to Meet Specific SPCC Secondary
Containment Requirements
Section 112.7(c) requires "appropriate containment and/or diversionary structures or equipment to
prevent a discharge as described in §112.l(b)." OWS may be used to satisfy this requirement for onshore or
offshore facilities. These separators must be constructed to contain oil and prevent an escape of oil from the
system prior to cleanup in order to comply with the secondary containment provision for which it is intended
(§112.7(c)). A description explaining how the OWS complies with secondary containment provisions, and how it
is operated and maintained, should be included in the SPCC Plan. BMPs or operation and maintenance (O&M)
manuals that detail operation and maintenance procedures for OWS used specifically for secondary
containment may be referenced in the SPCC Plan and maintained separately.
v> FYI - Location of oil/water separators
Separators used as secondary containment would typically be located in undiked areas, to supplement drainage
systems. The requirements for secondary containment systems described in Section 5.4 apply.
Separators associated with a diked area which are used exclusively for treating dike discharge effluent are subject to
the wastewater treatment exemption, as described in Section 5.3.
Section 112.7(h)(l) requires "a quick drainage system" for areas where a tank car or tank truck loading
or unloading rack is present. OWS may be used as part of a quick drainage system to meet this requirement. This
containment system must hold at least the maximum capacity of any single compartment of a tank car or tank
truck loaded or unloaded at the facility (§112.7(h)(l)).
Sections 112.8(b), 112.9(b), and 112.12(b) set forth design specifications for drainage systems
associated with secondary containment at onshore facilities. Environmentally equivalent measures can be used
to satisfy these requirements (see Chapter 3: Environmental Equivalence, Section 3.3.1). For example, facilities
might use ponds, lagoons, or catchment basins as part of the design of facility drainage systems. Alternatively,
OWS might serve as environmentally equivalent measures to the ponds, lagoons, or catchment basins required
by §§112.8(b)(3) and 112.12(b)(3). In this instance, EPA recommends that these separators be designed to
handle the expected flow rate and volume of oil and water generated by facility operations. When certifying a
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Chapter 5: Oil/Water Separators
facility's SPCC Plan, the PE must verify that OWS are adequately designed, maintained, and operated to provide
environmentally equivalent protection (in accordance with §112.7(a)(2)) under the potential discharge scenarios
they are aimed to address.
Sections 112.8(c)(2), 112.8(c)(ll), 112.12(c)(2), and 112.12(c)(ll) require that all bulk storage containers
be provided with secondary containment for "the entire capacity of the largest single container and sufficient
freeboard to contain precipitation." OWS may be used to meet these requirements, but must be appropriately
sized. These separators must be capable of handling the oil and precipitation from the general drainage area and
additional oil from any accidental discharge from the largest bulk storage container located within the drainage
area for which the separator provides secondary containment. Good engineering practice would suggest that
the use of OWS to meet the specific secondary containment provisions be on a very limited basis and typically
with smaller capacity container storage areas. See the example scenario in Figure 5-7 that calculates the
required capacity of an OWS used as secondary containment for a drum storage area.
Sections 112.8(c)(9) and 112.12(c)(9) require that the facility owner/operator observe effluent
treatment facilities frequently enough to detect possible system upsets that could cause a discharge as
described in §112.l(b). Separators should be monitored on a routine schedule, and collected oil should be
promptly removed, as appropriate, and in accordance with manufacturers' specifications and maintenance
instructions as described in the Plan, in order to ensure the proper operation and capacity of the equipment.
When OWS are used to meet secondary containment requirements, their capacities do not count
toward a facility's overall storage capacity. Any volume of oil that would flow into these separators would come
from another source within the drainage areas and are already counted in the facility storage capacity
determination. However, slop tanks or other containers used to store waste oil that is transferred out of these
separators do count toward the facility's total storage capacity. Furthermore, the SPCC rule does not require
redundant secondary containment around OWS used for secondary containment (i.e., tertiary containment is
not required).
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Chapter 5: Oil/Water Separators
Figure 5-7: Example calculation of secondary containment for a drum storage area using an oil/water
separator. X
The following example includes an oil/water separator used to provide secondary containment for a drum storage area:
Scenario: An automotive facility stores up to 10 55-gallon containers of lubricating oil in its outdoor drum storage area.
This undiked area drains to an oil/water separator. The total drainage area served by the oil/water separator is 70 feet x
100 feet.
Applicable secondary containment requirements: The 55-gallon containers are bulk storage containers, subject to the
sized secondary containment requirements of §112.8(c)(2). In this case, the facility is using the oil/water separator to
meet the secondary containment requirements. Therefore, the separator must be designed and sized to handle the
capacity of the largest container in the area, plus sufficient freeboard to contain precipitation.
Note that because the drum storage area is undiked, the requirements at §112.8(b)(3) and (4) also apply.
70 ft
-100ft-
Calculation of OWS capacity: After a review of historical precipitation data for the vicinity of the facility, the PE
determined that a peak rainfall intensity is 0.6 inch per hour is the most reasonable design criterion for this undiked
area, based on local conditions. The site is 100 percent impervious and therefore the full volume of precipitation that
falls on the drainage surface is expected to flow into the oil/water separator.
Volume of largest container in area = 55 gallons
Drainage surface area = 70 ft x 100 ft = 7,000 ft2
Precipitation volume (per hour) = 7,000 ft2 x (0.6 in /12 in=0.05 ft) = 350 ft3
Precipitation volume (per hour) in gallons = 350 ft3 x 7.48 gal/ft3 = 2,618 gallons
Total volume = 55 gal + 2,618 gal = 2,673 gallons
Flow rate = 2,673 gallons / 60 minutes/hour = 44.6 gallons/minute
The OWS must be capable of handling a flow-rate of 44.6 gallons per minute. Additionally, the OWS must have
sufficient oil storage capacity within the unit to provide storage for 55 gallons of oil plus a reasonable safety to account
for oil accumulated from the drainage area itself.
Conclusion: Based on these calculations, the facility has specified a cylindrical separator sized to handle a flow rate of
55 gallons per minute and providing a total volume of 550 gallons, including an oil storage capacity of 110 gallons prior
to the recommended pump out. The oil/water separator is maintained so as to preserve storage within the unit at all
times under normal operating conditions (pump out is scheduled for 35 gallons). For additional protection, the outlet of
the separator is equipped with an afterbay in which absorbent materials are placed.
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Chapter 5: Oil/Water Separators
5.5 OWS Used in Oil Production
5.5.1 OWS Used in Oil Production
OWS are used at both onshore and offshore oil production facilities. Separation and treating
installations at an oil production facility typically include equipment whose primary purpose is to separate the
well fluid into its marketable or waste fractions (e.g., oil, gas, wastewater, and solids), and to treat the crude oil
as needed for further storage and shipping. Separators and other separation equipment, such as heater-treaters
and gun barrels, are generally used for this purpose. These flow-through process vessels are considered bulk
storage containers and are subject to both the general provisions of §112.7 and applicable requirements of
§112.9 for onshore oil production facilities (including bulk storage container requirements of §112.9(c)) or
§112.11 for offshore oil drilling, production or workover facilities.
A variety of production equipment is used to separate and treat produced fluids. Some types of
equipment are operated under low pressure conditions, while others are operated at high pressure. A process
called "free-water knockout" (Figure 5-8) is generally used to separate large volumes of water from oil and gas
generated from the well. A two-phase separator separates the well fluids into a liquid (oil, emulsion,104 or water)
and a gas. The liquid exits the bottom of the separator and the gas exits the top (Figure 5-9). Gun barrels, also
called wash tanks, are generally found in older or marginal fields and are used to provide quiescent conditions
and retention time to allow produced water to settle out of the well fluids (Figure 5-10). Three-phase separators
separate well fluids into oil/emulsion, gas, and water. Gas exits from the top, oil/emulsion from the middle, and
water from the bottom of this type of vertical three-phase separator (Figure 5-11). Three-phase separators are
generally used when there is free water in the well fluids. If there is little or no free water, a two-phase
separator might be used instead. Another type of equipment used to separate produced fluids, especially fluid
emulsions, is termed a "heater-treater." Heater-treaters use heat, electricity, and/or chemicals to reduce the
emulsion viscosity and to separate out free oil, water, and gas in oil production. OWS designs may differ from
the examples provided.
^ FYI - Flow-through process vessels
Flow-through process vessels, such as horizontal or vertical separation vessels (e.g., heater-treater, free-water knockout,
gun barrel, etc.) primarily separate the oil from other fractions (water and/or gas) and send the fluid streams to the
appropriate container. The intended use of this equipment is what differentiates flow-through process vessels from
other bulk and end-use storage containers, such as produced water containers. Produced water containers store well
fluids (which may also contain various amounts of oil) after they have been separated and/or treated, prior to disposal
or reinjection. Produced water containers are not considered flow-through process vessels; they are considered bulk
storage containers when oil is present.
104
An emulsion is a colloidal suspension of a liquid within another liquid. In this case, small droplets of oil are dispersed through
water.
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Chapter 5: Oil/Water Separators
Figure 5-8: Low pressure free-water knockout.
Gas
Ouilel
Well Fluids
Inlet
Defleclo
\
IP
e
(
1 Gas
R_Wave_^P
^T 'Baffles tt
Oil
Water
Figure 5-9: Two-phase oil/water separator.
^muli
3utle
4
Oil/Emulsion
Outlet
°»
Ou"el
Water
Outlel
LJ
Spreader
Water
J|—»• Outlet
Figure 5-10: Gun barrel oil/water separator.
Figure 5-11: Three-phase oil/water separator.
Well Ruids_
Inlet
Spreader
In oil production separators, the momentum of the fluid flow is absorbed at the inlet, thereby reducing
the fluid viscosity and allowing oil, gas, and water to separate out of solution. Gas then rises and flows out at the
top of the separator, while oil and water fall to the lower portion of the vessel and coalesce in separate areas.
With the appropriate settling time, the more dense free water settles beneath the less dense oil. Liquid levels
are maintained by float-actuated control valves or dump valves. As the different pre-set liquid levels are
reached, dump valves discharge water and oil from the separator to appropriate storage areas:
• Water is discharged from the bottom of the separator to a water tank;
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• Oil is discharged out at a higher level to an oil storage tank; and
• Gas flows continuously out at the top of the separator to sales, a meter run, a flare, or a
recovery system.
5.5.2 Applicability of the SPCC Rule to OWS Used in Onshore Oil Production
OWS used in oil production count toward the total storage capacity of the facility and must be
considered when determining if a facility is regulated by the SPCC rule in accordance with §112.l(b) and (d)(2)
and the definition of storage capacity in §112.2. In determining applicability of any container for calculating the
total facility storage capacity, the preamble to the 2002 rule states:
The keys to the definition are the availability of the container for drilling, producing, gathering, storing,
processing, refining, transferring, distributing, using, or consuming oil, and whether it is available for one
of those uses or whether it is permanently closed. Containers available for one of the above described
uses count towards storage capacity; those not used for these activities do not. Types of containers
counted as storage capacity would include some flow-through separators, tanks used for "emergency"
storage, transformers, and other oil-filled equipment. (67 FR 47081, July 17, 2002)
Onshore oil production facilities with flow-through
process vessel OWS (e.g., heater-treater, free-water knockout,
and gun barrel) and other separation/treatment installations are
required to follow the specific sized secondary containment
requirements for bulk storage containers in §112.9(c)(2) and the
inspection requirements of §112.9(c)(3). However, as an
alternative to sized secondary containment, the facility owner
or operator may provide general secondary containment in
accordance with §112.7(c), and comply with the following
§112.9(c)(5) provisions for flow-through process vessels at oil
production facilities:
• Periodically and on a regular schedule, visually
inspect and/or test flow-through process vessels
and associated components (such as dump
valves) for leaks, corrosion, or other conditions
that could lead to a discharge, as described in
§112.9(c)(2)
Except as described in paragraph (c)(5) of
this section for flow-through process vessels
and paragraph (c)(6) of this section for
produced water containers and any
associated piping and appurtenances
downstream from the container, construct
all tank battery, separation, and treating
facility installations, so that you provide a
secondary means of containment for the
entire capacity of the largest single
container and sufficient freeboard to
contain precipitation. You must safely
confine drainage from undiked areas in a
catchment basin or holding pond.
Note: The above text is an excerpt of the SPCC rule.
Refer to the full text of 40 CFR part 112.
Take corrective action or make repairs to flow-through process vessels and any associated
components as indicated by regularly scheduled visual inspections, tests, or evidence of an oil
discharge; and
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• Promptly remove or initiate actions to stabilize and remediate any accumulations of oil
discharges.
It is important to note that the general secondary containment requirements under §112.7(c) still apply
to flow-through process vessel OWS in addition to the alternative requirements described above. The secondary
containment system must be designed to address the typical failure mode, and the most likely quantity of oil
that would be discharged, and can be either active or passive in design (see Chapter 4: Secondary Containment
and Impracticability, Section 4.8.1).
Furthermore, the owner/operator of the facility must install sized secondary containment and comply
with bulk storage container inspection requirements (§112.9(c)(2) and (c)(3)) for flow-through process vessels
within six months of a discharge(s) from flow-through process equipment as described below and a report must
be submitted to the RA in accordance with the requirements of §112.4:
• More than 1,000 U.S. gallons of oil in a single discharge to navigable waters or adjoining
shorelines, or
• More than 42 U.S. gallons of oil in each of two discharges to navigable waters or adjoining
shorelines within any twelve month period.
This excludes discharges that are the result of natural disasters, acts of war, or terrorism. When
determining the applicability of this SPCC reporting requirement, the gallon amount(s) specified (either 1,000 or
42) refers to the amount of oil that actually reaches navigable waters or adjoining shorelines not the total
amount of oil spilled. EPA considers the entire volume of the discharge to be oil for the purposes of these
reporting requirements.
_
^ FYI - Process equipment at non-production facilities
Similar flow-through process equipment at non-production facilities (i.e., oil-filled manufacturing equipment, such as
reaction vessels, fermentors, high pressure vessels, mixing tanks, dryers, heat exchangers, and distillation columns) are
not subject to the more stringent sized secondary containment and inspection requirements required for bulk storage
containers; only the general secondary containment requirements at §112.7(c) apply.
Process equipment at a facility other than an oil production facility, such as at a manufacturing facility, is typically
attended during hours of operation. Therefore, there is a greater potential to immediately discover and correct a
discharge at non-production facilities than at oil production facilities, which are generally unattended. For this reason,
EPA requires the inspection of flow-through process vessel components; prompt removal of any oil accumulations, and
corrective action should a discharge occur.
See 73 FR 74277, December 5, 2008
5.5.3 Applicability of the SPCC Rule to OWS Used in Offshore Oil Production
Offshore production facilities are subject to requirements under §112.11 of the SPCC rule, which are
tailored specifically for the offshore operating environment. Therefore, OWS used at off-shore oil production
facilities are not eligible for the alternate compliance option in §112.9(c)(5) as described in Section 5.5.2. Flow-
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Use oil drainage collection equipment to prevent and
control small oil discharges around pumps, glands,
valves, flanges, expansion joints, hoses, drain lines,
separators, treaters, tanks, and associated equipment.
You must control and direct facility drains toward a
central collection sump to prevent the facility from
having a discharge as described in §112. l(b). Where
drains and sumps are not practicable, you must
remove oil contained in collection equipment as often
as necessary to prevent overflow.
through process equipment at offshore facilities are
subject to the general requirements of the SPCC rule
under §112.7, including the secondary containment
requirement in §112.7(c).
OWS used in offshore oil production are also
subject to the provisions of §112.11(b) and (d) to prevent
a discharge of oil. However, if other provisions of the rule
(except secondary containment) can be met through
alternative methods that provide environmental
equivalence for this equipment, then the Plan must
include a description in accordance with §112.7(a)(2).
Vessels and equipment, such as glycol
dehydrators and inline heaters that treat only gas and
that do not separate, treat, or contain oil, are not subject
to the SPCC rule.
5.5.4 Wastewater Treatment Exemption and
Produced Water
At oil drilling and oil production facilities,
treatment units subject to the rule include produced
water containers, open oil pits or ponds associated with
oil production operations, OWS (e.g., gun barrels), and
heater-treater units. Open oil pits or ponds function as
another form of bulk storage container and are not used
for wastewater treatment (67 FR 47068, 47069, July 17, 2002). Therefore, as a type of oil treatment equipment,
oil water separators at production facilities are not eligible for the wastewater treatment exemption.
The SPCC rule's wastewater treatment exemption specifically states that the production of oil is not
wastewater treatment for the purposes of §112.1(d)(6). The goal of an oil production, oil recovery, or oil
recycling facility is to maximize the production or recovery of oil, while eliminating water and other impurities in
the oil, whereas the goal of a wastewater treatment facility is to purify
water. Neither an oil production facility nor an oil recovery or recycling
facility treats water; instead, it treats oil. Treatment of produced water
and oil mixtures is not considered wastewater treatment, and thus the
wastewater treatment exemption does not apply.
At facilities with areas where separators and treaters
are equipped with dump valves which predominantly
fail in the closed position and where pollution risk is
high, specially equip the facility to prevent the
discharge of oil. You must prevent the discharge of oil
by:
(1) Extending the flare line to a diked area if the
separator is near shore;
(2) Equipping the separator with a high liquid level
sensor that will automatically shut in wells producing
to the separator; or
(3) Installing parallel redundant dump valves.
Note: The above text is an excerpt of the SPCC rule. Refer to the
full text of 40 CFR part 112.
Additionally, oil production facilities generally lack NPDES or
state-equivalent permits or prevention requirements, and thus lack the
protections that such permits provide. Underground Injection Control
(UIC) permits do not have surface water prevention requirements for
§112.2
Produced water container means a
storage container at an oil production
facility used to store the produced
water after initial oil/water
separation, and prior to reinjection,
beneficial reuse, discharge, or transfer
for disposal.
Note: The above text is an excerpt of the
SPCC rule. Refer to 40 CFR part 112 for the
full text of the rule.
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production facilities. Production facilities are normally unattended and therefore lack constant human oversight
and inspection. Produced water generated in the production process normally contains saline water as a
contaminant in the oil, which in addition to the toxicity of the oil might aggravate environmental conditions in
the case of a discharge (67 FR 47068, July 17, 2002). In some areas of the United States, produced water is fresh
and may be discharged for beneficial use (e.g., irrigation or water for livestock) in accordance with federal and
state regulatory requirements.
Therefore, a facility that stores, treats, or otherwise uses produced water remains subject to the rule.
Produced water containers at onshore oil production facilities are bulk storage containers and are therefore
subject to the applicable requirements in §112.9(c), including the requirement for sized secondary containment.
The SPCC rule includes an alternative compliance option for produced water containers at onshore oil
production facilities in lieu of sized secondary containment.
For more information on the applicability of the SPCC rule as it relates to oil and water mixtures in
produced water or produced water containers, see Chapter 2: SPCC Rule Applicability, Sections 2.2.7 and 2.10.7.
For information on the secondary containment requirements that apply to produced water containers including
the alternative regulatory requirements, see Chapter 4: Secondary Containment and Impracticability, Section
4.8.2.
5.6 OWS Used in Oil Recovery or Recycling Facilities
Oil recycling and recovery activities that collect and consolidate production fluids from multiple oil
production facilities in an effort to further recover and treat oil prior to the disposal of production fluids are not
eligible for the wastewater treatment exemption because the operations focus on oil treatment rather than
wastewater treatment.
These include facilities that are typically discrete and not associated (co-located) with an oil production
facility. Operations typically specialize in the treatment of production fluids or other oil recovery activities, and
may include disposal, and injection of production fluids. A second type of oil recycling operation that is not
eligible for the wastewater treatment exemption includes waste oil recyclers and facilities engaged in the
recovery and/or recycling of motor oils, other petroleum oils, and AFVOs.
OWS located at oil recovery or recycling facilities are subject to the provisions of §112.7 and applicable
provisions of §112.8(b) and (d) for onshore petroleum and non-petroleum facilities or §112.12(b) and (d) for
onshore AFVO facilities. The §§112.8(c) and 112.12(c) provisions (such as sized containment, integrity testing
and overfill prevention) for bulk storage containers do not apply because OWS at these facilities function as oil-
filled manufacturing equipment and are not bulk storage containers. When OWS are part of a flow-through
process, such as that found during oil recovery or recycling activities, OWS are considered oil-filled
manufacturing equipment and are excluded from §§112.8(c) and 112.12(c) requirements because they are
excluded from the definition of a bulk storage container as defined in §112.2 of the rule. However, containers
used to store recovered or recycled oil collected from the OWS are bulk storage containers. These bulk storage
containers must comply with the §§112.8(c) and 112.12(c) provisions and other applicable requirements.
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For OWS used in oil recovery or recycling, the OWS are considered oil-filled manufacturing equipment
and are subject to the provisions of §112.7 and applicable provisions of §112.8(b) and (d) for onshore petroleum
and non-petroleum facilities or §112.12(b) and (d) for onshore AFVO facilities. The Plan must address the
general requirements under §112.7 for the OWS including a description of how the facility complies with the
secondary containment requirement under §112.7(c).
5.7 Documentation Requirements and the Role of the EPA Inspector
5.7.1 Documentation by Owner/Operator
OWS used exclusively for wastewater treatment are exempt from all SPCC requirements, and no
documentation is required for this equipment in the SPCC Plan.
For OWS used to meet SPCC secondary containment requirements, the SPCC Plan should discuss the
separator design capacity, configuration, maintenance, operation, and other elements of the drainage systems
that ensure proper functioning and containment of the oil as required by §112.7(a)(3)(iii). Examples of elements
that this discussion should include are:
• The presence and configuration of OWS outlets and the presence of other equipment to prevent
the accidental release of oil;
• Routine visual inspection of the oil/water separator, its contents, and discharges of effluent;
• Preventive maintenance of facility equipment affecting discharge, including the removal of
settled pollutants and collected oil;
• A drainage area that flows to the OWS and corresponding anticipated flow rate of the drainage
system to the separator;
• Appropriate capacity of the OWS for oil, wastewater, and, if appropriate, precipitation;
• Provisions for adequate separate storage capacity (based on the containment sizing required by
the rule) to contain oil recovered in the oil/water separator; and
• Documentation associated with the maintenance and inspection of OWS.
A separate bulk storage container used to store oil following separation in any OWS (i.e., wastewater
treatment, secondary containment, or oil production) is subject to all applicable requirements of 40 CFR part
112, including §§112.8(c), 112.9(c), or 112.12(c) as appropriate.
For OWS used in oil production, the OWS are bulk oil storage containers to be included in the SPCC Plan.
The location of these containers must be indicated on the facility diagram and discussed in the general
requirements in accordance with §112.7(a)(3). For more information on facility diagrams, refer to Chapter 6:
Facility Diagram and Description. The Plan must also include a discussion of sized secondary containment
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provided for OWS (§112.9(c)(2)), or, in the case where the owner/operator elects to comply instead with the
alternate requirements in §112.9(c)(5), include records to document implementation of the alternative
measures, including periodic inspection and/or testing for leaks, corrosion, or other conditions that could lead to
a discharge as described in §112.l(b); corrective action or repairs to flow-through process vessels and any
associated components as indicated by regularly scheduled visual inspections, tests, or evidence of an oil
discharge; and prompt removal or initiation of actions to stabilize and remediate any accumulations of oil
discharges associated with flow-through process vessels. The Plan must also address the general requirements
under §112.7 for OWS including a description of how the facility complies with the secondary containment
requirement under §112.7(c).
5.7.2 Role of the EPA Inspector
As with other aspects of the SPCC Plan, the certifying PE will review the use of and applicable
requirements for OWS at a facility and ensure that they are consistent with good engineering practice. In the
case of a qualified facility, the owner operator will make a similar certification and ensure that the Plan is in
accordance with accepted and sound industry practices and standards.
The EPA inspector will verify that any OWS at a facility that are not addressed in the SPCC Plan are in
fact used exclusively for wastewater treatment and not to meet any requirement of part 112. This review
considers how the OWS is being used at the facility. The EPA inspector should consider the intended use of the
separator at the facility (e.g., wastewater treatment, secondary containment, oil production, recovery, or
recycling), any flow diagrams illustrating the use of the separator, and the design specifications of the unit in
evaluating whether the OWS is eligible for the wastewater exemption. The EPA inspector may also consider the
flow-through capacity of the separator, the nature of the oil to be separated (e.g., whether it is an emulsion),
and the design specifications of the unit in evaluating the use of the oil/water separator.
For each OWS used to meet SPCC secondary containment requirements, the EPA inspector will verify
that the Plan includes a discussion of the separator design capacity, configuration, maintenance, and operation,
as well as other elements of the drainage systems that ensure proper functioning and containment of the oil in
accordance with §112.7(c), §112.8(c)(2), or §112.12(c)(2). Particularly large drainage areas served by an OWS to
meet secondary containment requirements may raise a "red flag" given the large volume of precipitation that
may need to be handled by the OWS concurrently with an oil discharge; the inspector should verify that the Plan
adequately addresses the ability of the OWS to handle the expected precipitation (considering expected rainfall
intensity) and discharge volume given the design treatment flow rate and OWS capacity.
EPA inspectors should note the risk associated with this form of containment and should review the
information provided in the Plan regarding the design, maintenance, operation, and efficacy of OWS systems
used for containment very carefully. These separators should be monitored on a routine schedule, and collected
oil should be promptly removed as appropriate and in accordance with manufactures specifications and
maintenance instructions as described in the Plan in order to ensure the proper operation and capacity of the
equipment.
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OWS (including those used in oil production) that are not eligible for the wastewater exemption must be
included in the oil storage capacity calculations for the facility (§112.l(b) and (d)(2) and the definition of storage
capacity in §112.2).
When an oil production facility Plan describes compliance with the alternative option for flow-through
process vessels in accordance with §112.9(c)(5), then the EPA inspector should verify that the requisite records
are included in the SPCC Plan (refer to Section 4.8.1 and 7.2.9 for a summary of the information to be provided
in the Plan).
If the owner or operator of the facility discharges into or upon a navigable water or adjoining shoreline
more than 1,000 U.S. gallons of oil in a single discharge, or more than 42 U.S. gallons of oil in each of two
discharges within a 12-month period from a flow-through process vessel, and is required to comply with
§112.9(c)(2) and 112.9(c)(3), the SPCC Plan must then describe the sized secondary containment and inspection
program provided for this equipment.
By certifying the SPCC Plan, a PE attests that the Plan has been prepared in accordance with good
engineering practice and with the requirements of 40 CFR part 112, and that the Plan is adequate for the facility.
Thus, if OWS uses are properly documented, they most likely will be considered acceptable by EPA inspectors.
However, if the documented uses of the OWS appear inappropriate to prevent spills from reaching navigable
waters or adjoining shorelines, appear to be incorrect, deviate from the use described in the Plan, are not
maintained or operated in accordance with the Plan, or the separator appears to be malfunctioning or out of
serviceA further follow-up action may be warranted. This may include requests for more information or for a Plan
amendment in accordance with §112.4(d).
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ChapterG Facility Diagram and
Description
6.1 Introduction
Section 112.7(a)(3) of the SPCC rule requires that facility owners/operators include in the SPCC Plan a
description of the facility, including a facility diagram that marks the location and contents of each fixed oil
storage container and the storage area where mobile or portable containers are located. The facility diagram
must also include all transfer stations and connecting pipes. The facility diagram is important because it is used
for effective prevention, planning, management (for example, inspections), and response considerations. The
diagram also will help the facility and emergency response personnel to plan for emergencies.
The rule also requires a description of the facility's oil storage containers, including their content and
capacity. Providing information on a container-specific basis helps the owner or operator of the facility to
prioritize inspections and maintenance of containers based on characteristics such as age, capacity, or location
and helps to formulate contingency planning, if such planning is necessary. This information also helps
inspectors to prioritize inspections of higher-risk containers at a facility and verify the facility capacity
calculation. This chapter explains these requirements, provides guidelines on the necessary level of detail,
discusses the discretion of the certifying PE or owner/operator in preparing the diagram, and includes several
facility diagrams as examples.
Additionally, the SPCC Plan must also address discharge prevention measures; discharge or drainage
controls; countermeasures for discharge discovery, response, and cleanup; methods of disposal of recovered
materials; and specific contact information (see Section 112.7(a)(3) for more information on these
requirements).
This chapter is organized as follows:
• Section 6.2 outlines requirements for providing a general facility description that includes the
physical layout, discharge prevention measures, drainage controls and countermeasures.
• Section 6.3 describes the type of information that is necessary to enable a person to report a
discharge to navigable waters or adjoining shorelines.
• Section 6.4 describes the requirements for the facility diagram and specific types of containers.
• Section 6.5 provides several examples of facility diagrams.
• Section 6.6 describes the EPA inspector's role in reviewing facility diagrams.
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Chapter 6: Facility Diagram and Description
6.2 General Facility Description
Section 112.7(a)(3) requires that the Plan include a description of the physical layout of the facility. This
description may include information on the facility's location, type, size, geographic and topographic
characteristics, and proximity to navigable waters, as well as other relevant information. This general facility
description is supplemented with a more specific description of containers subject to the SPCC rule to
complement what is illustrated on the facility diagram. This description must be included in the SPCC Plan
regardless of whether similar information is available in the FRP or other facility plans. If the SPCC Plan does not
follow the sequence of the rule, then a cross-reference is required.
6.2.1 Oil Types and Container Capacities
Section 112.7(a)(3)(i) requires that the Plan include the type of oil in each fixed container and its storage
capacity. For mobile or portable containers, EPA provides flexibility in allowing the Plan preparer to either
provide the type of oil and storage capacity for each container, or provide an estimate of the potential number
of mobile or portable containers, the types of oil, and
anticipated storage capacities.
The Plan preparer may identify an area on the
facility diagram (e.g., a drum storage area) and include
a separate description of the total number of
containers, capacities, and contents in the Plan or
reference facility inventories that can be updated by
facility personnel. The Plan should include an estimate
of the number of mobile or portable containers
expected to be stored in an area and the capacity of
each container. This estimate can be used to
determine the applicability of the rule thresholds and
provide a general description of the mobile/portable
containers in the Plan (72 FR 58389, October 15,
2007). This estimate may be represented as a capacity
range. For example, a facility with a 55-gallon drum
inventory that fluctuates between 10 and 100 drums
would represent a capacity range of 550 gallons to
5,500 gallons in the SPCC Plan.
6.2.2 Discharge Prevention Measures
The facility owner/operator must include in
the SPCC Plan a discussion of discharge prevention
measures including procedures for routine handling of
products (loading, unloading, and facility transfers,
§112.7(a)(3)
... You must also address in your Plan:
(i) The type of oil in each fixed container and its storage
capacity. For mobile or portable containers, either provide
the type of oil and storage capacity for each container or
provide an estimate of the potential number of mobile or
portable containers, the types of oil, and anticipated
storage capacities;
(ii) Discharge prevention measures including procedures
for routine handling of products (loading, unloading, and
facility transfers, etc.);
(iii) Discharge or drainage controls such as secondary
containment around containers and other structures,
equipment, and procedures for the control of a discharge;
(iv) Countermeasures for discharge discovery, response,
and cleanup (both the facility's capability and those that
might be required of a contractor);
(v) Methods of disposal of recovered materials in
accordance with applicable legal requirements; and
(vi) Contact list and phone numbers for the facility
response coordinator, National Response Center, cleanup
contractors with whom you have an agreement for
response, and all appropriate Federal, State, and local
agencies who must be contacted in case of a discharge as
described in §112.1(b).
Note: The above text is an excerpt of the SPCC rule. Refer to 40 CFR
part 112 for the full text of the rule.
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Chapter 6: Facility Diagram and Description
etc.). Including this information in the SPCC Plan will help to train new facility personnel on the discharge
prevention measures to be employed at the facility and be useful for refresher training during annual discharge
prevention briefings.
6.2.3 Drainage Controls
The Plan must also include a discussion of discharge or drainage controls such as secondary containment
around containers and other structures, equipment, and procedures for the control of a discharge.
The general secondary containment provision of §112.7(c) requires that secondary containment and/or
diversionary structures be appropriate to prevent a discharge to navigable waters or adjoining shorelines. The
owner/operator should discuss the method, design, and capacity for secondary containment that he chooses to
address the typical failure mode, and the most likely quantity of oil that would be discharged. The entire
containment system, including walls and floor, must be capable of containing oil and must be constructed so
that any discharge from a primary containment system, such as a tank, will not escape the containment system
before cleanup occurs. The discussion should also include whether the secondary containment is either active or
passive in design. If an active containment measure is employed, then the discussion should describe the
equipment, procedures and personnel that will be necessary to effectively employ the active containment
measure to prevent a discharge to navigable waters or adjoining shorelines.
Loading and unloading racks should have containment that flows to catchment basins or a treatment
facility designed to handle discharges. Otherwise, the facility can include a quick drainage system for tank car or
tank truck loading/unloading racks. Any containment system to address the loading/unloading rack must hold at
least the maximum capacity of any single compartment of a tank car or tank truck loaded or unloaded at the
facility.
Finally, the description for bulk storage containers should address whether the secondary containment
is sized to contain the capacity of the largest single container within the containment system with sufficient
freeboard for precipitation.
6.2.4 Countermeasures
Include in the SPCC Plan a discussion of the facility's countermeasures for discharge discovery, response,
and cleanup (both the facility's capability and those that might be required of a contractor). These
countermeasures may include procedures for responding to a discharge that is discovered before it reaches
navigable waters or adjoining shorelines (active containment measures used as part of a secondary containment
strategy) as well as additional procedures for responding after a discharge reaches navigable waters or adjoining
shorelines (contingency planning).
6.2.5 Disposal Methods
The SPCC rule requires that the owner/operator of the facility discuss the methods to be used to dispose
of recovered materials in the event of a discharge. By describing those methods in the Plan, the owner/operator
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demonstrates that the facility has done the appropriate planning to be able to dispose of recovered materials,
should a discharge occur.
Proper disposal of recovered materials helps prevent a discharge as described in §112.l(b) by ensuring
that the materials are managed in an environmentally sound manner. Proper disposal also assists response
efforts. If the owner or operator of a facility lacks adequate resources to dispose of recovered oil and oil-
contaminated material during a response, it limits how much and how quickly oil and oil-contaminated material
is recovered, thereby increasing the risk and damage to the environment.
6.2.6 Contact List
The SPCC Plan must include a contact list that includes phone numbers for the facility response
coordinator, National Response Center, cleanup contractors with whom the owner/operator has an agreement
for response, and all appropriate Federal, State, Tribal and local agencies who must be contacted in case of a
discharge to navigable waters or adjoining shorelines.
A contact list is necessary for both preparedness and response purposes because it enables the facility
personnel to begin mobilizing resources immediately upon the discovery of a discharge to navigable waters or
adjoining shorelines. The information included in the contact list should be reviewed periodically to ensure that
the information is current.
6.3 Notification Requirements
^ The SPCC rule identifies the type of information
to include in the SPCC Plan that is necessary to enable a
person to report a discharge to navigable waters or
adjoining shorelines. Additionally, in accordance with 40
CFR part 110.6, the owner/operator of the facility must
report discharges to navigable waters or adjoining
shorelines to the National Response Center (NRC) at 1-800-
424-8802 or for those without "800" access 1-202-267-
2675. The NRC is the federal government's centralized
reporting center, which is staffed 24 hours per day by U.S.
Coast Guard personnel (for more information see
http://www.nrc.uscg.mil/). If reporting directly to NRC is not
practicable, reports also can be made to the EPA regional
office or the U.S. Coast Guard Marine Safety Office (MSO) in
the area where the incident occurred.
§112.7(a)(4)
Unless you have submitted a response plan under
§112.20, provide information and procedures in
your Plan to enable a person reporting a discharge
as described in §112.l(b) to relate information on
the exact address or location and phone number of
the facility; the date and time of the discharge, the
type of material discharged; estimates of the total
quantity discharged; estimates of the quantity
discharged as described in §112.l(b); the source of
the discharge; a description of all affected media;
the cause of the discharge; any damages or injuries
caused by the discharge; actions being used to stop,
remove, and mitigate the effects of the discharge;
whether an evacuation may be needed; and, the
names of individuals and/or organizations who
have also been contacted.
Note: The above text is an excerpt of the SPCC rule. Refer to
40 CFR part 112 for the full text of the rule.
The following information will be requested by the
NRC:
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40 CFR 110.6 Notice X
Any person in charge of a vessel or of an onshore or offshore facility shall, as soon as he or she has knowledge of any
discharge of oil from such vessel or facility in violation of section 311(b)(3) of the Act, immediately notify the National
Response Center (NRC) (800-424- 8802; in the Washington, DC metropolitan area, 202-426-2675). If direct reporting to
the NRC is not practicable, reports may be made to the Coast Guard or EPA predesignated On-Scene Coordinator (OSC)
for the geographic area where the discharge occurs. All such reports shall be promptly relayed to the NRC. If it is not
possible to notify the NRC or the predesignated DCS immediately, reports may be made immediately to the nearest
Coast Guard unit, provided that the person in charge of the vessel or onshore or offshore facility notifies the NRC as soon
as possible. The reports shall be made in accordance with such procedures as the Secretary of Transportation may
prescribe. The procedures for such notice are set forth in U.S. Coast Guard regulations, 33 CFR part 153, subpart B and in
the National Oil and Hazardous Substances Pollution Contingency Plan, 40 CFR part 300, subpart E.
• The exact address or location and phone number of the facility;
• The date and time of the discharge, the type of material discharged;
• Estimates of the total quantity discharged;
• Estimates of the quantity discharged to navigable waters or adjoining shorelines;
• The source of the discharge;
• A description of all affected media;
• The cause of the discharge;
• Any damages or injuries caused by the discharge;
• Actions being used to stop, remove, and mitigate the effects of the discharge;
• Whether an evacuation may be needed; and
• The names of individuals and/or organizations who have also been contacted.
The same requirements for spill reporting are part of the FRP rule under 40 CFR 112.20; therefore, if a
facility has prepared and submitted an FRP to the EPA Regional Administrator, then the SPCC Plan does not need
to include a section on notifications.
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Chapter 6: Facility Diagram and Description
6.4 Preparing a Facility Diagram
6.4.1 Purpose
The facility diagram is an important component of an SPCC Plan. It is used for prevention, planning,
inspections, management, and response considerations. In most cases, the owner or operator of the facility will
work with the PE certifying the SPCC Plan to identify the
information to include on the facility diagram. The rule
requires that the diagram identify the location and contents
of each fixed oil storage container and location of mobile and
portable container storage areas (§112.7(a)(3)). Diagrams
may help responders avoid certain hazards by informing them
of the location and content of containers and of the response
equipment. The facility diagram may also assist responders in
determining the flow pathway of discharged oil and to take
more effective measures to control the flow of oil to
potentially avert damage to sensitive environmental areas;
protect drinking water sources; and prevent discharges to
other conduits, to a treatment facility, or to navigable waters
or adjoining shorelines. Federal and state facility inspectors
and facility personnel need to be aware of the location of all
containers, piping, and transfer areas subject to the SPCC
rule. The diagram may also be used to visually address other
rule requirements such as discharge/drainage controls and
the flow path of a discharge (§112.7(a)(3)(iii) and 112.7(b),
respectively). Additionally, the diagram may be attached to a facility inspection checklist to identify areas,
containers, or equipment subject to inspection.
§112.7(a)(3)
Describe in your Plan the physical layout of the
facility and include a facility diagram, which
must mark the location and contents of each
fixed oil storage container and the storage area
where mobile and portable containers are
located. The facility diagram must identify the
location of and mark as "exempt" underground
tanks that are otherwise exempted from the
requirements of this part under §112.1(d)(4).
The facility diagram must also include all
transfer stations and connecting pipes, including
intra-facility gathering lines that are otherwise
exempted from the requirements of this part
under §112.1(d)(ll).
Note: The above text is an excerpt of the SPCC rule.
Refer to 40 CFR part 112 for the full text of the rule.
6.4.2 Tier I Qualified Facility Exclusion
In 2008, EPA promulgated streamlined requirements for that exclude the requirement for a facility
diagram. This subset of qualified facilities (i.e., those with no individual container greater than 5,000 U.S. gallons
in capacity) is eligible to complete an SPCC Plan template that follows the format outlined in Appendix G of the
SPCC rule. EPA determined that a facility diagram is not necessary because this type of facility is typically small
and generally simple in configuration. A facility diagram is not needed to understand the facility layout and
locate areas of potential discharge at such facilities.
The facility diagram exclusion applies only for Tier I qualified facilities. The owner or operator of a Tier II
qualified facility is required to develop and certify an SPCC Plan that complies with all of the applicable
requirements of section §112.7 and subparts B and C of the rule. For more information on qualified facilities see
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the discussion in Chapter 1: Introduction, Sections 1.3.3 and 1.3.4. Additional guidance is also available for
qualified facility owners/operators at http://www.epa.gov/oem/content/spcc/spcc qf.htm
6.4.3 Requirements for a Facility Diagram
The facility diagram is one of the general requirements for an SPCC Plan. Facility diagrams provided as
part of an SPCC Plan illustrate a variety of information. The following items are required by §112.7(a)(3):
• Aboveground storage tanks (including location and contents);
• Underground storage tanks (including location and contents). This includes those that are
subject to the SPCC rule or those that are exempt (see Section 6.4.7);
• Storage area(s) where mobile or portable containers are located (see Section 6.4.6);
• Transfer stations such as oil transfer areas including loading/unloading racks and
loading/unloading areas;
• Oil-filled equipment such as hydraulic operating systems or manufacturing equipment (including
location and contents);
• Oil-filled electrical transformers, circuit breakers, or other equipment (including location and
contents);
• Connecting piping (if the scale of drawing permits, as discussed in Section 6.4.9);
• Oil pits or ponds (at oil production facilities);
• Oil production facility stock tanks, separation equipment and produced water containers;
• Any other bulk storage or oil-filled operational equipment at an oil production facility; and
• Flowlines and intra-facility gathering lines at a production facility (this includes those that are
subject to the SPCC rule and exempt intra-facility gathering lines subject to the requirements of
49 CFR part 192 or 195 as described in §112.1(d)(ll)).
Containers that have a capacity of less than 55 gallons, are permanently closed, or are otherwise exempt
from the rule (with the exception of exempt underground tanks and exempt intra-facility gathering lines) are not
required to be identified on the facility diagram.
In addition, EPA recommends (but does not require under the SPCC rule) that the following information
be included on the facility diagram to maximize its utility for facility personnel, emergency responders, and
inspectors:
• Aboveground storage tank capacities and/or tank identification numbers or letters;
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Chapter 6: Facility Diagram and Description
• Secondary containment structures, including oil/water separators used for containment;
• Storm drain inlets and surface waters that could be affected by a discharge;
• Direction of flow in the event of a discharge (which can serve to address the SPCC requirement
under §112.7(b));
• Legend that indicates scale and identifies symbols used in the diagram;
• Location of response kits or other equipment used to implement an active containment
strategy:
• Location of firefighting equipment and pipe stands for foam application;
• Location of valves or drainage system control that could be used in the event of a discharge to
contain oil on the site;
• The location of important piping appurtenances such as valves, checks or other piping-related
equipment (to aid in facility response and inspection efforts);
• Compass direction indicating north; and
• Topographical information and area maps.
For purposes of emergency response, EPA recommends, but does not require, that an owner/operator
mark on a facility diagram containers that store Clean Water Act (CWA) hazardous substances (listed in 40 CFR
part 116, Designation of Hazardous Substances) and label the contents of these containers (67 FR 47097, July 17,
2002).
While recognizing that SPCC Plans and their associated diagrams are facility-specific and prepared within
the discretion granted to the Plan preparer, the information provided in this chapter is meant to facilitate a
common understanding of what EPA inspectors may expect to see in a facility diagram. The remainder of this
section provides guidelines for the recommended level of detail, how specific containers and systems may be
addressed and the use of various approaches to develop facility diagrams that meet the requirements of
§112.7(a)(3).
6.4.4 Level of Detail
The facility diagram should provide sufficient detail for the facility personnel to undertake prevention
activities, for EPA to perform an effective inspection, and for responders to take effective measures. As with
other aspects of the SPCC Plan, the facility diagram is to be prepared in accordance with good engineering
practice. Thus, the level of detail provided and the approach taken for preparing an adequate facility diagram is
primarily at the discretion of the person certifying the SPCC Plan.
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Chapter 6: Facility Diagram and Description
The scale and level of detail shown on a facility diagram may vary according to the needs and complexity
of the facility (72 FR 58389, October 15, 2007). Owners or operators of a facility may represent complicated
areas of piping or oil-filled equipment in a less detailed manner on the facility diagram in the SPCC Plan, as long
as the information is contained in more detailed diagrams of the systems or is contained in some other form and
such information is maintained elsewhere at the facility and this location is referenced in the SPCC Plan (73 FR
74247, December 5, 2008). For example, a facility owner or operator may indicate in the diagram an area where
complicated oil-filled equipment (such as manufacturing equipment found in a refinery or other oil processing
facility) is located and provide a table in the Plan describing the type(s) of equipment and contents of the oil
storage containers.
The facility diagram must include all fixed and mobile/portable containers (including oil-filled
equipment) that store 55 gallons or more of oil and identify the contents of these containers (§112.7(a)(3)). (The
SPCC rule exempts containers with a capacity less than 55 gallons, and therefore they should not be included on
the facility diagram.) The following sections provide information on identifying mobile or portable containers,
completely buried storage tanks, and piping and manufacturing equipment on the facility diagram.
6.4.5 Fixed Storage Containers
In 2008, EPA amended the SPCC rule to clarify that the facility diagram must include the location of all
containers located in a fixed position (i.e., those that do not move around the facility). In situations where
diagrams become complicated due to the presence of multiple oil storage containers, it may be difficult to
indicate the contents of the containers on the diagram itself. In order to simplify the diagram, the owner or
operator may choose to include the contents of the containers separately in the SPCC Plan in an accompanying
table or key. See Section 6.2.1 for more information on the requirement to describe the facility's oil storage
containers, including contents and capacity
6.4.6 Mobile or Portable Containers
The owner/operator must mark the storage area of mobile or portable containers on the facility diagram
(§112.7(a)(3)). Mobile or portable containers should be marked on the facility diagram in their out-of-service or
designated storage area, primary storage areas, or areas where they are most frequently located (see 73 FR
74247, December 5, 2008). Thus, if containers are stored in one area and operated in another area, both "areas"
would be identified on the facility diagram. However, since the rule requires the identification of a "storage
area", these "areas" may be marked as general locations on the diagram rather than identify specific discrete
locations for each mobile or portable container. Regardless of where mobile or portable containers are located
at the facility, the owner/operator must comply with the
specific secondary containment requirements for these
containers as described in §§112.8(c)(ll) and
112.12(c)(ll). See Chapter 4: Secondary Containment and
Impracticability, Section 4.7.5 for a discussion of these
requirements.
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v* Tip - Mobile or portable containers
While the SPCC rule does not specifically define
"mobile" or "portable" containers, such containers
may include 55-gallon drums, skid tanks, totes,
Intermediate Bulk Containers (IBCs), and other small
containers put into place and later moved.
Mobile/portable maintenance tanks, and some oil
refinery tank trucks and fueling trucks dedicated to a
particular facility (such as a construction site, military
base, or similar large facility) may also fall under this
category.
(73 FR 74246-7, December 5, 2008)
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Chapter 6: Facility Diagram and Description
For mobile or portable containers (e.g., drums, IBCs and totes), the facility owner/operator may note the
general contents of each container and provide more detailed content information separately (such as on a
separate sheet, log, or electronic system). If the contents of a container change frequently, the contents may be
recorded separately, or on the diagram. If the information is provided separately, the diagram should note that
contents vary. See Section 6.2.1 for more information on the requirement to describe the facility's oil storage
containers, including contents and capacity.
6.4.7 Underground Storage Tanks
A facility diagram must include the location and contents of all containers addressed in the SPCC Plan
(67 FR 47097 and §112.7(a)(3)). This requirement includes both exempt underground storage tanks (USTs) and
USTs that are subject to SPCC requirements. Completely buried USTs and piping systems that are subject to all
technical requirements of either 40 CFR part 280 or an approved state UST program under 40 CFR part 281 are
exempt from SPCC requirements. However, USTs must be included in the facility diagram and marked "exempt"
if the facility is otherwise subject to the SPCC rule. Similarly, the SPCC rule exempts USTs including below-grade
vaulted tanks that supply emergency diesel generators at a nuclear power generation facility licensed by the
Nuclear Regulatory Commission (see Chapter 2: SPCC Rule Applicability, Section 2.8.4). Such emergency
generator tanks must be included in the facility diagram and marked "exempt" if the facility is otherwise subject
to the SPCC rule. This information will help response personnel to easily identify dangers from fire, explosion, or
physical impediments during response activities.
As discussed in Chapter 2: SPCC Rule Applicability, Section 2.8.3, a facility may have USTs that are subject
to SPCC requirements because they are deferred from compliance with some or all of the technical
requirements of 40 CFR part 280 (e.g., UST systems with field constructed tanks and airport hydrant fuel
distribution systems). USTs that are subject to SPCC requirements must be marked on the facility diagram
(§112.7(a)(3)). (See 56 FR 54612, October 22, 1991.)
6.4.8 Intra-facility Gathering Lines
The facility diagram must include all transfer stations (i.e., any location where oil is transferred) and
connecting pipes, including intra-facility gathering lines that are otherwise exempted from SPCC requirements
(§112.7(a)(3)). Although the SPCC rule exempts those intra-facility gathering lines that are subject to the
regulatory requirements of 49 CFR part 192 or 195, their location must be identified and marked as "exempt" on
the facility diagram (§112.1(d)(ll)). This will assist facility, EPA, and emergency personnel to review the facility's
SPCC Plan and identify hazards during a spill response activity.
6.4.9 Piping and Oil-filled Equipment
Oil-filled equipment (such as manufacturing equipment) and associated piping present at an SPCC-
regulated facility may be difficult to represent on a facility diagram, due to their relative location, complexity, or
design. Recognizing this, EPA allows flexibility in the way the facility diagram is drawn. An owner/operator may
represent such systems in a less detailed manner on the facility diagram as long as more detailed drawings are
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Chapter 6: Facility Diagram and Description
maintained at the facility and referenced in the SPCC Plan. More detailed drawings may include blueprints,
engineering diagrams, or diagrams developed to comply with other local, state, or federal requirements.
The scale and level of detail of the facility diagram may make it difficult to show small transfer lines or
piping within containment structures. Schematic representations that provide a general overview of the piping
service (e.g., supply/return) may provide sufficient information when combined with a description of the piping
in the Plan. Alternatively, overlay diagrams showing different portions of the piping system may be used where
the density and/or complexity of the piping system would make a single diagram difficult to read (73 FR 74248,
December 5, 2008). Although the SPCC rule requires that piping be included on the facility diagram, it is not
necessary to include appurtenances associated with the piping.
Figure 6-1 and Figure 6-2 demonstrate simplified examples of oil-filled equipment and piping as shown
in a complete facility diagram in Figure 6-4. Examples of ways that oil-filled manufacturing equipment may be
represented include a box that identifies the equipment and its location, or a simplified process flow diagram.
For areas of complicated piping, which often include different types, numbers, and lengths of pipes, the facility
diagram may show a simplified box labeled "piping" or show a single line that identifies the service (e.g.,
supply/return), as long as more detailed diagrams are available at the facility (73 FR 74248, December 5, 2008).
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-ter 6: Facility Diagram and Description
Figure 6-1: Example of a facility diagram showing how manufacturing equipment could be represented.
Note that more detailed diagrams would need to be available at the facility.
Finished
Consumer
Product
Concrete pad
'CONCRETE FLOOR
Liquid Product
Accumulation Tank
10,000 gallons
Area D
From
Piping Area
To water
treatment plant
Figure 6-2: Example showing how a complex piping area could be represented in a facility diagram. Note
that more detailed diagrams would need to be available at the facility.
From Area A
Raw Material Bulk Storage
Ahoveground oipiriQ
f
Raw Material Feed - Products & Solvent
To Process Area
Piping Area
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Chapter 6: Facility Diagram and Description
6.4.10 Use of Diagrams Created for Other Programs or Uses
EPA does not require that a facility diagram be developed exclusively for the SPCC Plan. Some state and
other federal regulations may require a diagram with similar or overlapping requirements. States may
supplement the SPCC minimum requirements with more stringent requirements. A facility diagram prepared for
a state or other federal plan (including the FRP requirements under §112.20) or for other purposes (e.g., as-built
plans, construction permits, facility modifications, and other pollution prevention requirements) may be used in
an SPCC Plan if it meets the requirements of the SPCC rule (e.g., it includes the contents of the containers,
transfer areas, and piping) (73 FR 74247, December 5, 2008). Similarly, facilities with oil-filled electrical
equipment may base their facility diagrams on existing electrical one-line diagrams, provided the drawings are
appended as necessary to include all of the containers, transfer areas, piping, and other information as required
to meet the requirements of §112.7(a)(3).
6.5 Facility Diagram Examples
This section includes example facility diagrams for three fictitious SPCC-regulated facilities. They
illustrate how certain containers and equipment could be represented on a facility diagram. Preparation of a
facility diagram is a site-specific effort, and the level of detail and/or approach taken to prepare it will vary based
on what is needed to adequately describe the configuration for any given facility. The examples provided are not
meant to indicate a specific amount of detail an EPA inspector will require for each SPCC-regulated facility. They
merely illustrate the concepts discussed in this chapter.
Facility diagrams, like the other elements of an SPCC Plan, must be prepared in accordance with good
engineering practice or in accordance with accepted and sound industry practices and standards. They must be
reviewed by the PE (or owner/operator, in the case of a Tier II qualified facility) certifying the Plan (§112.3(d) or
§112.6(b)). Section 112.7(a)(3) requires the facility diagram to show, at a minimum, the location and contents of
fixed oil containers; mobile/portable container storage area locations; completely buried storage tanks,
including those that may otherwise be exempt from the rule; and transfer stations (i.e., areas where oil is
transferred ) and connecting pipes, including exempt intra-facility gathering lines. The facility owner or operator
may also include on the diagram additional structures and equipment, and may use the diagram to illustrate
other elements that may be relevant to the SPCC Plan and to emergency response. For instance, a diagram may
also show the discharge and drainage controls that are described in the SPCC Plan, the predicted flow path for
discharged oil based on topography, areas on which to focus inspections, fire-fighting resources, spill response
kits or other equipment necessary to implement an active containment measure and/or evacuation routes. The
examples presented below are for a bulk storage and distribution facility, a manufacturing facility, and an oil
production facility.
6.5.1 Example #1: Bulk Storage and Distribution Facility
Figure 6-3 illustrates a diagram for a bulk storage and distribution facility, which has a tank farm, a
loading rack, an unloading area, and other oil containers and oil-filled equipment. This diagram corresponds to
the model SPCC Plan for a bulk storage distribution facility that is provided in Appendix D of this guidance.
SPCC GUIDANCE FOR REGIONAL INSPECTORS 6-13
November 15, 2013
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Chapter 6: Facility Diagram and Description
As required by §112.7(a)(3), this diagram includes all containers with an oil storage capacity of 55
gallons or greater. In addition to listing the contents directly on the diagram, the diagram provides a reference
to a supplementary table that contains the volume and content of the storage tanks shown on the diagram
(appended to the diagram as Table B-l). At the discretion of the Plan preparer who reviewed and certified the
Plan, the example facility diagram also depicts secondary containment methods and includes a reference to
calculations for secondary containment capacity provided in other parts of the SPCC Plan. Also, a separate log
(Table B-2) identifies the contents of the drums in the storage warehouse and estimates the maximum number
of containers.
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Chapter 6: Facility Diagram and Description
Figure 6-3: Example facility diagram, including a loading rack and a separate loading area.
PREVENTION STREET
( fence
u
Storm Drain
. (SW ftj° Ctearwoter Creek)_
X
Fence Gate
Concrete pad
Kerosene dispenser
36" concrete dike
(60,000 gallons capacity,
plus 4 inches of freeboard)
Roof
(covered
area)
4" asphalt
rollover term
Capacity: 1,150 gallons
NOTES
• Refer to Table B-1 of SPCC Plan for volume and content of
storage tanks and containers shown on this diagram.
• The calculation of the design capacities of diked area 1. loading
rack containment berm. and refueler parking area is detailed in
Appendix A of SPCC Plan.
• Refuelers used for emergency oil fill runs are positioned in the
refueler parking area since they are usually kept full
• Other refueters are positioned in other parts of the facility since
they are usually kept empty upon reluming to the facility.
• Facility drainage from diked areas terminates at the oil/water
separator.
Double-woiled AST
2,000 gallons with overfill
protection, heating oil
ASPHALT PAVED AR£A
to OWS or pickup
Boiler
D
Main Office Building
1
*" ^^
Supply line
Return line
55-gotton drums - Maximum 930 with
total capacity of 550 gallons
Roof (covered area)
Quick drainage system ana' rollover curb
Capacity: 2,000 gallons
6" asphalt rollover berm
(2,000 gallons capacity)
UD O0^9
Refueters Parking Area
Neverspill Oil & Products Corporation ^
SPCC Plan - Facility Diagram
Rev. 07/22/2013 )
LEGEND
G Fire extinguisher Valv8
• _ Catch basin Fence
Predicted Direction of Drainage
* N I
V
DIAGRAM IS NOT TO SCALE
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Chapter 6: Facility Diagram and Description
Table B-l: Volume and contents of containers identified on the facility diagram.
Tank/ Container
Volume (gallons)
Contents
Areal
Tankl
Tank 2
TankS
Tank 4
TankS
Tank 6
25,000
25,000
25,000
25,000
30,000
30,000
Product A- #2 fuel oil
Product A- #2 fuel oil
Product B- #6 fuel oil
Product B- #6 fuel oil
Product C- Kerosene
Product C- Kerosene
Main Office Building
TankH
2,000
Heating oil
Drum Storage Warehouse
Up to 10 drums
55 (each)
Various oil products (lubricating oil, engine oil, used oil, etc.)
Rev. 07/22/13
Table B-2: Drum storage warehouse log (maintained at the facility as part of inventory).
Date
Number and Type
of Container
Contents
Capacity
Location at facility
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Chapter 6: Facility Diagram and Description
6.5.2 Example #2: Manufacturing Facility
Figure 6-4 illustrates a large manufacturing facility with a variety of containers and equipment, including
piping, oil-filled equipment (i.e., manufacturing equipment and transformers), and completely buried storage
tanks. As required by §112.7(a)(3), this diagram includes all containers with a storage capacity of 55 gallons or
greater. In addition to listing the contents directly on the diagram, it includes a reference to a crosswalk that
contains the volume and content of the storage containers shown on the diagram (appended to the diagram as
Table B-3). While not an SPCC requirement, the diagram also marks the location of containers that store CWA
hazardous substances and labels those containers. Additionally, the diagram notes the location and contents of
completely buried storage tanks otherwise exempt from the SPCC rule because they meet all the technical
requirements of 40 CFR part 280 or an approved state UST program under 40 CFR part 281 (in accordance with
the requirements of §112.7(a)(3)).
This diagram also includes an example of how oil-filled manufacturing equipment and complex piping
may be represented on a facility diagram, at the discretion of the owner/operator or PE. The diagram references
the more detailed diagrams and plans of the piping and manufacturing equipment that are available separately
at the facility.
Finally, while not required in the diagram, this example also includes a reference to the calculation of
diked storage provided in other parts of the SPCC Plan and depicts wastewater treatment systems, secondary
containment, and oil/water separators.
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Chapter 6: Facility Diagram and Description
Figure 6-4: Example facility diagram, including oil-filled equipment, complex piping, and completely buried storage tanks.
PREVENTION STREET
Tank 12
Balding 1
Main Office
NOTES
• Refer to Table 8-1 of SPCC Plan (or volume and content of storage tanks and
containers shown on this diagram.
• The calculation of the design capacity of diked areas A, B, and C is detailed in
Appendix A of SPCC Plan.
• For more d&taiied diagrams and plans, including for piping and manufacturing
areas, refer to site drawings maintained at NROMC main office in Building 1,
* Facility drainage from diked areas terminates at the oil/water separator.
• O/Tfy some Yemeni's of the process are represented on this diagram. For more
detailed information on process equipment configuration, refer to site drawings
maintained in the main office.
Tank Truck Load ing
4"osprtolt
rollover term
I2.SOO gallons
capacity)
Tank 10
( Tank 11 4
Spill Control
Equipment
Aboveground piping
Raw Material Feed - Products & Solvent
Piping Area
Area B
Finished Product Bulk Storage
[ Tank? J (' Tanks }
36" concrete dike
(35,000 gallons capacity)
f 6"graveton
concrete finer —
ss s
Mac
Electrical Equipment
Finished
Consumer
Product
Liquid Product
Accumulation Tank
J* i
Concrete pad Area D
f | .
. CONCRETE FIOOR
1 — ..
1
| Stripping
1
1
Condenser
Uquffler
1
i
•J Pump /Tank
1
Direct
Contact
Cooling
i
i
t .
Primary
1 "— '
Distillation
i
' t '
1 1 Process Area
Building 2
£
t
I
To wot
Treatme
pto
No Release Oil & Manufacturing Corporation '
SPCC Plan - Facility Diagram
Rev. 07/22/2013 j
LEGEND
Fire extinguisher
Predicted Direction ol Drainage
: Valve
— Fence
• - Process area delineation
1"" Piping area delineation
Underground storage lank
DIAGRAM IS NOT TO SCALE
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Chapter 6: Facility Diagram and Description
Table B-3: Volume and contents of containers identified on the facility diagram.
Rev. 07/22/13
Tank/ Container
Volume (gallons)
Contents
Area A - Raw Material Bulk Storage
Tankl
Tank 2
TankS
Tank 4
TankS
TankS
Tank9
4,000
4,000
20,000
20,000
20,000
6,000
4,000
Product A- #2 fuel oil
Product A- #2 fuel oil
Product B- #6 fuel oil
Product B- #6 fuel oil
Product B- #6 fuel oil
Product C- Kerosene
Solvent -Toluene
Area B - Finished Product Bulk Storage
Tank 6
Tank?
20,000
20,000
Product D - proprietary oil
Product D - proprietary oil
Area C- Electrical Equipment
Transformer El
Transformer E2
235
235
Silicon-based dielectric fluid
Silicon-based dielectric fluid
Area D
Liquid Product Accumulation Tank
10,000
Product D - proprietary oil
Process Area
Primary Reactor
Distillation
Direct Contact Cooling
Stripping
Pump/Tank
Condenser Liquefier
500
500
500
500
300
500
intermediate oil product
intermediate oil product
intermediate oil product
intermediate oil product
intermediate oil product
intermediate oil product
Underground Storage Tanks
Tank 10 (otherwise exempt from SPCC
requirements)
Tank 11 (otherwise exempt from SPCC
requirements)
Tank 12
8,000
8,000
2,000
gasoline
gasoline
heating oil
6.5.3 Example #3: Oil Production Facility
Figure 6-5 illustrates a small oil production facility with two extraction wells and a production tank
battery. As required by §112.7(a)(3), this diagram includes all containers with a storage capacity of 55 gallons or
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Chapter 6: Facility Diagram and Description
greater and transfer areas. Because the facility has a relatively large footprint, the direction of flow is best
displayed on a separate figure that shows the general location of the site relative to receiving water bodies ().
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Chapter 6: Facility Diagram and Description
Figure 6-5: Example facility diagram for an oil production facility.
Buried segment
under dirt road
75 gallon gear o
reservoir
FIB
2 inch diameter steel
Approx. lengtti 2,100ft
FLA
2 inch diameter steel
Approx. lengtti 2,100ft
Curbed concrete pad
3'x6'x4-
75 gallon ge
reservoir
Curbed concrete pad
3'x6'x4-
•5
500 Bbl
Produced
Water
To Saltwater
disposalwel
Approx. lengtti
2,000ft
IseeBOXl)
Tank top-mounted
belt oil skimmer
Containment berm
15' x 15' x 4'
Containment berm
30' x 25' x 2'
•2
400 Bbl
Crude Oil
500 gal ton port able
skimmedoil
collection tank
Tanker truck loading,'
unloading area
containment
Load line
/container
Containment berm
60" x 401 x 2.5'
BOX 1. Saltwater Disposal Well Area
ClearwaterOil Company
Big Bear Lease No. 2 Production Facility
To production area
Approx. lengtti 2,000ft
Facility Diagram
Rev. 05/03/2010
DIAGRAM IS MOT TO SCALE
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Chapter 6: Facility Diagram and Description
Figure 6-6: Example general facility location diagram for an oil production facility.
6.6 Review of a Facility Diagram
6.6.1 Documentation by Owner/Operator
The person certifying the SPCC Plan attests familiarity with the requirements of 40 CFR part 112; that
the Plan has been prepared in accordance with good engineering practice (or for a Tier II qualified facility, in
accordance with accepted and sound industry practices and standards); follows the requirements of 40 CFR part
112; and that the Plan is adequate for the facility. Thus, if an SPCC Plan is certified, and the facility diagram is
consistent with the rule requirements, it will most likely be considered acceptable by regional EPA inspectors.
However, if the facility design has changed and is no longer accurately represented on the diagram, the
supporting drawings for a simplified diagram are not available at the facility, or the diagram appears to be
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Chapter 6: Facility Diagram and Description
inadequate for the facility, appropriate follow-up action may be warranted. This action may include a request for
more information or a Plan amendment in accordance with §112. 4(d).
Additionally, changes to the facility diagram are considered administrative in nature and do not require
PE certification. (72 FR 58389, October 15, 2007) The same is true for a Tier II qualified facility: the owner or
operator does not need to certify changes to a facility diagram in accordance with §112.6(b)(2) because these
changes are not considered technical amendments.
6.6.2 Role of the EPA Inspector
As part of the EPA inspection, the inspector will verify that the diagram accurately represents the facility
layout and provides sufficient detail as outlined in §112.7(a)(3), and use it as a guide for the containers and
piping inspected during the site visit.
The EPA inspector should verify that the diagram included in the Plan includes:
• Location and contents of each fixed container (except those below the de minimis container size
of 55 gallons as described in Section 6.4.3, above).
• Location of storage areas (which may also include operational or staging areas) for mobile or
portable containers.
• Completely buried tanks, including those that are otherwise exempt from the SPCC rule by
• All transfer stations (i.e., areas where oil is transferred) and connecting pipes including intra-
facility gathering lines that are otherwise exempt from the SPCC rule by §112.1(d)(ll).
Although EPA stated in both the preamble of the 2002 SPCC rule (67 FR 47097, July 17, 2002) and in
§112.7(a)(3) that all facility transfer stations and connecting pipes that handle oil must be included in the
diagram, the rule allows flexibility on the method of depicting concentrated areas of piping and oil-filled
manufacturing equipment on the facility diagram. These areas may be represented in a more simplified manner,
as long as more detailed diagrams (such as blueprints, engineering diagrams, or process charts) are available at
the facility and referenced in the SPCC Plan. The EPA inspector may ask to review more detailed diagrams of
piping and oil-filled manufacturing equipment if further information is needed during a site inspection
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Chapter 7 Inspection, Evaluation, and
Testing
7.1 Introduction
The inspection, evaluation and testing requirements of the SPCC rule are intended to prevent, predict
and detect potential integrity or structural issues before they cause a leak, spill or discharge of oil to navigable
waters or adjoining shorelines. Regularly scheduled inspections, evaluations, and testing by qualified personnel
are critical parts of oil discharge prevention. They are conducted not only on containers, but also on associated
piping, valves, and appurtenances, and on other equipment and components that could be a source or cause of
an oil discharge.
Activities may involve one or more of the following: an external visual inspection of containers, piping,
valves, appurtenances, foundations, and supports; a non-destructive testing (examination) to evaluate integrity
of certain containers; and additional evaluations, as needed, to assess the equipment's fitness for continued
service. The type of inspection program and its scope will depend on site-specific conditions and the application
of good engineering practices, adherence to applicable industry standards and/or manufacturer's requirements.
An inspection, evaluation, and testing program that complies with SPCC requirements should specify the
procedures, schedule/frequency, types of equipment covered, person(s) conducting the activities,
recordkeeping practices, and other elements as outlined in this chapter.
The remainder of this chapter is organized as follows:
• Section 7.2 provides an overview of the SPCC inspection, evaluation, and testing requirements.
• Section 7.3 discusses the role of industry standards and recommended practices in meeting
SPCC requirements.
• Section 7.4 discusses determining a baseline in order to establish a regular inspection schedule.
• Section 7.5 presents special circumstances, including the use of environmentally equivalent
measures. This section also includes suggested minimum requirements for a hybrid inspection
program.
• Section 7.6 discusses the role of the EPA inspector in reviewing a facility's compliance with the
rule's inspection, evaluation, and testing requirements.
• Section 7.7summarizes industry standards, code requirements, and recommended practices
(RPs) that apply to different types of equipment.
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Chapter 7: Inspection, Evaluation, and Testing
7.2 Inspection, Evaluation, and Testing under the SPCC Rule
Various provisions of the SPCC rule relate to the inspection, evaluation, and testing of containers,
associated piping, and other oil-containing equipment. Different requirements apply to different types of
equipment, oil, and facilities. The requirements are generally aimed at preventing discharges of oil caused by
leaks, corrosion, brittle fracture, overfill, or other forms of container or equipment failure by ensuring that
containers used to store oil have the necessary physical integrity for continued oil storage. The requirements are
also aimed at detecting container and equipment failures (such as pinhole leaks) before they can become
significant and result in a discharge as described in §112.l(b).
7.2.1 Summary of Inspection, Evaluation and Integrity Testing Requirements
Table 7-1 summarizes the provisions that apply to different types of equipment and facilities. As shown
in the table, applicable inspection and testing provisions vary depending on the type of equipment, facility, and
circumstances. For example, some inspection and testing provisions apply specifically to bulk storage containers
at onshore facilities (other than oil production facilities) while other inspection and/or testing requirements
apply to other components of a facility that might cause a discharge (such as vehicle drains, foundations, or
other equipment or devices). Animal fat and vegetable oil (AFVO) containers that meet certain criteria are
eligible for differentiated integrity testing requirements. Onshore oil production facilities have a distinct set of
inspection requirements including minimum expectations for a flowline maintenance program. The SPCC rule
also includes regulatory alternatives to sized secondary containment that include inspection and corrective
action requirements.
Finally, additional requirements apply under certain circumstances, such as when an aboveground field-
constructed container undergoes repairs, alterations, or a change in service that may affect its potential for a
brittle fracture or other catastrophic failure, or in cases where secondary containment for bulk storage
containers is impracticable (§112.7(d), as described in Chapter 4: Secondary Containment and Impracticability).
Facility owners and operators must maintain records to demonstrate compliance with the inspection,
evaluation, and integrity testing requirements per §112.7(e).
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Chapter 7: Inspection, Evaluation, and Testing
Table 7-1: Summary of SPCC inspection, evaluation, and integrity testing program provisions and
associated recordkeeping requirements.
Facility Component
Section(s)
Action
Method, Circumstance, and Required Action
(Text in italics indicates the frequency or circumstances for performing the activity, as specified in the SPCC rule.)
General Requirements Applicable to All Facilities
Bulk storage
containers with no
secondary
containment and for
which an
impracticability
determination has
been made
112.7(d)
Test
Integrity testing. Periodically.
Integrity testing is required for all bulk storage containers. In
cases where no secondary containment is present because it
is impracticable, good engineering practice may suggest more
frequent testing than would otherwise be scheduled.
Note that this includes bulk storage containers at oil
production, drilling and workover facilities that are not
typically subject to integrity testing requirements.
Valves and piping
associated with bulk
storage containers
with no secondary
containment and for
which an
impracticability
determination has
been made
112.7(d)
Test
Integrity and leak testing of valves and piping associated with
containers that have no secondary containment as described
in §112.7(c). Periodically.
Recordkeeping
requirement
112.7(e)
Record
Keep written procedures and a signed record of
inspections105 and tests for a period of three years.106
Records kept under usual and customary business practices
will suffice. For all actions.
Lowermost drain and
all outlets of tank car
or tank truck at
loading/unloading
racks
112.7(h)(3)
Inspect
Visually inspect. Prior to filling and departure of tank car or
tank truck from loading/unloading racks.
105
106
Inspections include evaluations (e.g. brittle fracture evaluation) required under the regulation.
Certain industry standards require recordkeeping beyond three years. Facility owners/operators should keep comparison
records of integrity inspections and tests as directed in the standard, but no less than three years in accordance with the SPCC
record retention requirement, in order to identify changing conditions of the oil storage container. EPA recommends that
formal testing and inspection records or reports be retained for the life of the container.
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Chapter 7: Inspection, Evaluation, and Testing
Facility Component
Field-constructed
aboveground
container
Section(s)
112.7(i)
Action
Evaluate
Corrective
Action
Method, Circumstance, and Required Action
Evaluate potential for brittle fracture or other catastrophic
failure. When the container undergoes a repair, alteration,
reconstruction or a change in service that might affect the risk
of a discharge or failure due to brittle fracture or other
catastrophe, or has discharged oil or failed due to brittle
fracture failure or other catastrophic failure.
Based on the results of this evaluation, take appropriate
action.
Onshore Facilities (Excluding Oil Production Facilities)107
Diked areas
Diked areas for bulk
storage containers
Bu ried metallic
storage tank installed
on or after January
10, 1974
Aboveground bulk
storage container
Aboveground bulk
storage container
Aboveground bulk
storage container
supports and
foundations
112.8(b)(l)&
112.8(b)(2)or
112.12(b)(l)&
H2.l2(b)(2)108
112.8(c)(3) &
112.8(c)(3)
112.8(c)(4) or
112.12(c)(4)
112.8(c)(6) or
112.12(c)(6)
112.8(c)(6) or
112.12(c)(6)
112.8(c)(6) or
112.12(c)(6)
Inspect
Record
Inspect
Record
Test
Test or
Inspect
Inspect
Inspect
Visually inspect content for presence of oil when draining into
a watercourse. Prior to draining.
Keep adequate records of such events.
Inspect retained rainwater to ensure that it will not cause a
discharge as described in §112. l(b) when draining to storm
sewer or open watercourse, lake or pond. Prior to draining.
Keep adequate records of such events.
Leak test. Regularly
Test or inspect each container for integrity. Following a
regular schedule and whenever material repairs are made.
Determine scope, frequency of testing and qualification of
personnel performing the test or inspection, in accordance
with industry standards. Tests include, but are not limited to,
visual inspection, hydrostatic testing or other non-destructive
testing.
Inspect outside of container for signs of deterioration and
discharges. Frequently.
Inspect container's supports and foundations. Following a
regular schedule and whenever material repairs are made.
Note that §112.8 provisions apply to facilities that store petroleum oils and non-petroleum oils (excluding AFVO). §112.12
provisions apply to facilities storing AFVO (i.e., animal fats and oils and greases, and fish and marine mammal oils; and for
vegetable oils, including oils from seeds, nuts, fruits, and kernels.) Also see alternative provisions in table under "Onshore
Facilities (Excluding Production) - Animal Fats and Vegetable Oils."
Sections 112.8(b)(2) and 112.12(b)(2) reference dike drainage procedures in §§112.8(c)(3)(ii)-(iv) and 112.12(c)(3)(ii)-(iv). These
dike drainage procedures apply to any facility drainage that drains directly to a watercourse.
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Chapter 7: Inspection, Evaluation, and Testing
Facility Component
Diked areas around
bulk containers
Steam return and
exhaust lines
Liquid level sensing
devices
Effluent treatment
facilities
Bulk storage
containers
Buried piping
All aboveground
valves, piping, and
appurtenances
Section(s)
112.8(c)(6) or
112.12(c)(6)
112.8(c)(7) or
112.12(c)(7)
112.8(c)(8)(v) or
112.12(c)(8)(v)
112.8(c)(9) or
112.12(c)(9)
112.8(c)(10)or
112.12(c)(10)
112.8(d)(l)or
112.12(d)(l)
112.8(d)(4)or
112.12(d)(4)
112.8(d)(4)or
112.12(d)(4)
Action
Inspect
Monitor
Test
Observe
Corrective
Action
Inspect
Corrective
Action
Test
Inspect
Method, Circumstance, and Required Action
Inspect for signs of deterioration, discharges, or accumulation
of oil inside diked areas. Frequently.
Monitor for leaks from defective internal heating coils. On an
ongoing or regular basis.
Test for proper operation. Regularly.
Detect possible system upsets that could cause a discharge.
Frequently.
Correct visible discharges which result in a loss of oil from the
container, including but not limited to seams, gaskets, piping,
pumps, valves, rivets, and bolts.
109
Remove any accumulations of oil in diked areas. Promptly.
Inspect for deterioration. Whenever a section of buried line is
exposed for any reason.
If corrosion damage is found, additional examination and
corrective action must be undertaken as indicated by the
magnitude of the damage.
Integrity and leak testing. At the time of installation,
modification, construction, relocation, or replacement.
During the inspection, assess general condition of items, such
as flange joints, expansion joints, valve glands and bodies,
catch pans, pipeline supports, locking of valves, and metal
surfaces. Regularly.
Onshore Oil Production Facilities (Excluding Drilling and Workover Facilities)
Diked areas
associated with tank
batteries and
separation and
treating areas
112.9(b)(l)
Inspect
Corrective
Action
Visually inspect contents of dike area and take action in
accordance with §112.8(c)(3)(ii), (iii), and (iv). Prior to
draining.
Remove accumulated oil on the rainwater and return it to
storage or dispose of it in accordance with legally approved
methods. Prior to draining.
"Prompt" removal means beginning the cleanup of any accumulation of oil immediately after discovery of the discharge, or
immediately after any actions to prevent fire or explosion or other threats to worker health and safety, but such actions may
not be used to unreasonably delay such efforts (67 FR 47122, July 17, 2002).
Any buried piping connected to an exempt completely buried storage tank regulated under 40 CFR part 280 or 281 is also
exempt from the SPCC rule.
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Chapter 7: Inspection, Evaluation, and Testing
Facility Component
Section(s)
Action
Method, Circumstance, and Required Action
Field drainage
systems (such as
drainage ditches or
road ditches), oil
traps, sumps, and
skimmers
112.9(b)(2)
Inspect
Corrective
Action
Inspect for an accumulation of oil that may have resulted
from any small discharge. Inspect at regularly scheduled
intervals.
Remove any accumulations of oil. Promptly.
Aboveground bulk
storage containers
112.9(c)(3)
Inspect
Visually inspect each container to assess deterioration and
maintenance needs. Periodically and on a regular schedule.
Foundation and
support of each
aboveground
container that is on
or above the surface
of the ground
112.9(c)(3)
Inspect
Visually inspect to assess deterioration and maintenance
needs. Periodically and on a regular schedule.
Flow-through
process vessels and
associated
components (such as
dump valves) without
sized secondary
containment
Inspect
and/or test
Visually inspect and/or test for leaks, corrosion, or other
conditions that could lead to a discharge as described in
112. l(b). Periodically and on a regular schedule.
Flow-through
process vessels and
associated
components without
sized secondary
containment
Corrective
Action
Take corrective action or make repairs. As indicated by
regularly scheduled visual inspections, tests, or evidence of an
oil discharge.
Flow-through
process vessels
without sized
secondary
containment
Corrective
Action
Remove or initiate actions to stabilize and remediate any
accumulations of oil discharges associated with flow-through
process vessels. Promptly.
Produced water
containers without
sized secondary
containment
Implement
Procedure
Record
Implement a procedure for each produced water container
that is designed to separate the free-phase oil that
accumulates on the surface of the produced water. On a
regular schedule.
Include in the Plan a description of the procedures,
frequency, amount of free-phase oil expected to be
maintained inside the container, and a Professional Engineer
(PE) certification in accordance with §112.3(d)(l)(vi).
Maintain records of such events in accordance with
§112.7(e).
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Facility Component
Section(s)
Action
Method, Circumstance, and Required Action
Produced water
containers and
associated piping
without sized
secondary
containment
Inspect
and/or test
Visually inspect and/or test for leaks, corrosion, or other
conditions that could lead to a discharge as described in
112. l(b) in accordance with good engineering practice. On a
regular schedule.
Produced water
containers and
associated piping
without sized
secondary
containment
Corrective
action
Take corrective action or make repairs. As indicated by
regularly scheduled visual inspections, tests, or evidence of
an oil discharge.
Produced water
containers and
associated piping
without sized
secondary
containment
Corrective
action
Remove or initiate actions to stabilize and remediate any
accumulations of oil discharges. Promptly.
All aboveground
valves and piping
associated with
transfer operations
Inspect
Inspect for the general condition of flange joints, valve glands
and bodies, drip pans, pipe supports, pumping well polish rod
stuffing boxes, bleeder and gauge valves, and other such
items. Periodically and upon a regular schedule.
Saltwater (oil field
brine) disposal
facilities
112.9(d)(2)
Inspect
Inspect to detect possible system upsets capable of causing a
discharge. Often, particularly following a sudden change in
atmospheric temperature.
Flowlinesand intra-
facility gathering
lines and associated
appurtenances
Inspect
and/or test
Visually inspect and/or test for leaks, oil discharges,
corrosion, or other conditions that could lead to a discharge
as described in 112. l(b). On a periodic and regular schedule.
For flowlines and intra-facility gathering lines that are not
provided with secondary containment in accordance with
§112. 7(c), inspect or test the lines such that the frequency
and type of testing allows for the implementation of a
contingency plan as described under 40 CFR part 109.
Flowlinesand intra-
facility gathering
lines and associated
appurtenances
Corrective
Action
Take corrective action or make repairs. As indicated by
regularly scheduled visual inspections, tests, or evidence of a
discharge.
Flowlinesand intra-
facility gathering
lines and associated
appurtenances
Corrective
Action
Remove or initiate actions to stabilize and remediate any
accumulations of oil discharges. Promptly.
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Facility Component
Section(s)
Action
Method, Circumstance, and Required Action
Offshore Oil Drilling, Production, and Workover Facilities
Oil drainage
collection
equipment, where
drains or sumps are
not practicable
Corrective
action
Remove oil contained in collection equipment as often as
necessary to prevent overflow.
Sump system (liquid
removal system and
pump start-up
device)
Inspect and
Test
Use preventive maintenance, inspection and testing program
to assure reliable operation. Regularly scheduled.
Pollution prevention
equipment and
systems
Inspect and
Test
Prepare and maintain a written procedure within the Plan for
inspecting and testing pollution prevention equipment and
systems. Conduct testing and inspection of the pollution
prevention equipment and systems commensurate with the
complexity, conditions, and circumstances of the facility and
any other appropriate regulations. Use simulated discharges
for testing and inspecting human and equipment pollution
control and countermeasure systems. On a scheduled
periodic basis.
Sub-marine piping
Inspect and
Test
Inspect and test for good operating conditions and for
failures. Periodically and according to a schedule.
Onshore Facilities (Excluding Oil Production) - Animal Fats and Vegetable Oils
111
Bulk storage
containers that are
subject to
21CFR part 110, are
elevated, constructed
of austenitic stainless
steel, have no
external insulation
and are shop-
fabricated; and
associated diked
areas
Inspect
Conduct formal visual inspection of bulk storage containers.
Following a regular schedule.
Inspect the outside of the container for signs of deterioration,
discharges, or accumulation of oil inside diked areas.
Frequently.
The SPCC rule is a performance-based regulation. Since each facility may present unique characteristics
and methods may evolve as new technologies are developed, the rule does not prescribe a specific frequency or
method to perform the required inspections, evaluations, and tests. Instead, it relies on the use of good
Note that additional inspection requirements applicable to AFVO facilities are described in the table above. See alternative
provisions in table under "Onshore Facilities (Excluding Production Facilities)."
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engineering practice, based on the professional judgment of the PE (for a PE-certified SPCC Plan), which includes
consideration of applicable industry standards. In addition, recommended practices, safety considerations, and
requirements of other federal, state, or local regulations may be considered in the development and
certification of the SPCC Plan. Section 112.3(d)(l) specifically states that the PE certifying a Plan attests that
"procedures for required inspections and testing have been established." Section 112.3(d)(l) also states that the
Plan must be prepared in accordance with good engineering practice, including consideration of applicable
industry standards, and with the requirements of 40 CFR part 112. Thus, when certifying an SPCC Plan, a PE is
also certifying that the inspection program described in the Plan is appropriate for the facility and is consistent
with good engineering practice.
Similarly, the owner/operator of a qualified facility112 who self-certifies the SPCC Plan must attest that
the SPCC Plan has been prepared in accordance with the SPCC rule113 and accepted and sound industry practices
and standards; that procedures for inspections and tests have been established for the facility; and that the Plan
will be implemented. While owners and operators of qualified facilities may choose not to have their SPCC Plans
certified by a PE, they are still required to comply with all of the SPCC requirements and to develop and
implement a spill prevention program in accordance with good engineering practices, and may do so by
following regulatory guidance and industry recommended practices, consulting with tank testing professionals,
and implementing standard design and operation protocols.
The preamble to the 2002 SPCC rule amendment (67 FR 47042, July 17, 2002) lists examples of industry
standards and recommended practices that may be relevant to determining what constitutes good engineering
practice for various rule provisions. These industry standards are summarized in Table 7-2 and Table 7-3 (Section
7.3) and further discussed in Section 7.7. Although EPA refers to the use of industry standards to determine
inspection and integrity testing practices, the Agency does not prescribe a particular standard or schedule for
testing. "Good engineering practice" and relevant industry standards change overtime. In addition, site-specific
conditions at an SPCC-regulated facility play a significant role in the development of appropriate inspections and
tests and the associated schedule for these activities. For example, the American Petroleum Institute (API)
Standard 653, "Tank Inspection, Repair, Alteration, and Reconstruction," includes a cap on the maximum time
interval between inspections, and provides specific criteria for alternative inspection intervals based on the
calculated corrosion rate or risk-based inspection assessment. API 653 also provides an internal inspection
interval when the corrosion rates are not known. Similarly, the Steel Tank Institute (STI) Standard SP001
provides specific intervals for external inspection of portable containers; and external and internal inspection of
shop-built containers and small field-erected containers based on container size and configuration. Site-specific
The self-certification option is designed for owners and operators of those facilities that store smaller amounts of oil. These
smaller amounts of oil generally translate to facilities with simpler, pre-engineered installations, such as restaurants, office
buildings, family farms, automotive repair shops, and rural electrical substations. For more information on qualified facilities,
see Chapter 1: Introduction.
Note that this provision applies to Tier II qualified facility Plans. The Tier I qualified facility self-certification provisions in
§112.6(a)(l) do not require the owner or operator to attest that the Plan was prepared in accordance with the SPCC rule
because the template in Appendix G of the rule, that serves as the SPCC Plan for these facilities, addresses applicable rule
requirements.
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conditions may therefore affect the exact schedule of inspections and tests conducted under either industry
standard.
Finally, environmentally equivalent measures may substitute for integrity testing requirements as
allowed under §112.7(a)(2) when reviewed and certified by a PE.114 Chapter 3: Environmental Equivalence
provides a general discussion of environmental equivalence, while Section 7.5 discusses its particular relevance
to bulk storage container integrity testing and inspection
requirements at onshore facilities and other special
circumstances.
FYI - Oil-filled equipment
Oil-filled equipment is not a bulk storage
container and, therefore, NOT subject to the
integrity testing requirements of the SPCC rule.
The remaining portions of Section 7.2 discuss various
requirements related to the inspection, testing, evaluation, and
maintenance of selected components of facilities (Sections 7.2.1
through 7.2.13). The section ends with a discussion of the general role of industry standards in meeting SPCC
requirements (Section 7.3).
7.2.2 Regularly Scheduled Integrity Testing and Inspection of Aboveground Bulk Storage
Containers (at Onshore Facilities Other than Oil Production Facilities)
Section 112.8(c)(6) of the SPCC rule specifies the inspection and testing requirements for aboveground
bulk storage containers at onshore facilities that store petroleum oils and non-petroleum oils (except AFVOs).
Section 112.12(c)(6) contains similar requirements for facilities with animal fats and vegetable oils.115 The SPCC
rule has two distinct inspection requirements for bulk storage containers:
• Test or inspect each container for integrity on a regular schedule and whenever material repairs
are made; and
• Frequently inspect the outside of the container for signs of deterioration, discharges, or
accumulation of oil inside diked areas. This visual inspection is intended to be a routine walk-
around and includes the container's supports and foundations.
Qualified facility owners or operators who choose to self-certify their SPCC Plan, as allowed under §112.3(g), may incorporate
environmentally equivalent alternatives in the Plan when each alternate method is reviewed and certified in writing by a PE.
See Section 7.5.2 for more information on deviating from the SPCC rule requirements based on environmental equivalence.
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§112.8(c)(6)
Test or inspect each aboveground container for integrity on a regular schedule and whenever you make material
repairs. You must determine, in accordance with industry standards, the appropriate qualifications for personnel
performing tests and inspections, the frequency and type of testing and inspections, which take into account container
size, configuration, and design (such as containers that are: shop-built, field-erected, skid-mounted, elevated, equipped
with a liner, double-walled, or partially buried). Examples of these integrity tests include, but are not limited to: visual
inspection, hydrostatic testing, radiographic testing, ultrasonic testing, acoustic emissions testing, or other systems of
non-destructive testing. You must keep comparison records and you must also inspect the container's supports and
foundations. In addition, you must frequently inspect the outside of the container for signs of deterioration, discharges,
or accumulation of oil inside diked areas. Records of inspections and tests kept under usual and customary business
practices satisfy the recordkeeping requirements of this paragraph.
Note: The above text is only a brief excerpt of the rule. Refer to 40 CFR part 112 for the full text of the rule.
Integrity testing is any means to measure the strength (structural soundness) of a container shell,
bottom, and/or floor to contain oil, and may include leak testing to determine whether the container will
discharge oil (67 FR 47120, July 17, 2002). The integrity testing and routine inspection requirements apply to
aboveground bulk storage containers with a capacity of 55 gallons116 or more, including:
Large (field-constructed or field-erected) and small (shop-built) aboveground containers;
117
• Containers located on, partially in (partially buried, bunkered, or vaulted tanks), and off the
ground wherever located; and
• Double-walled containers.
Regularly scheduled integrity tests or inspections
Integrity testing is a necessary component of any good oil discharge prevention plan. Integrity testing is
necessary to determine whether the bulk storage container (e.g., tank) is suitable for continued use until the
next formal inspection. It will help to prevent discharges by testing the integrity of containers, ensuring they are
suitable for continued service under current and anticipated operating conditions (e.g., product, temperature,
pressure). For example, testing may help facility owners/operators to determine whether corrosion has reached
a point where repairs are required or replacement of the container is necessary. Information obtained through
116
117
For information on inspecting mobile/portable containers, see Section 7.5.1.
STI SP001 makes the distinction between field-erected and shop-fabricated tanks. A field-erected aboveground storage tank
(AST) is a welded metal AST erected on the site where it will be used. For the purpose of the standard, ASTs are to be inspected
as field-erected ASTs if they are either: (a) an AST where the nameplate indicates that it is a field-erected AST, and limited to a
maximum shell height of 50 feet and maximum diameter of 30 feet; or (b) an AST without a nameplate that is more than 50,000
gallons and has a maximum shell height of 50 feet and a maximum diameter of 30 feet. A shop-fabricated AST is a welded metal
AST fabricated in a manufacturing facility or an AST not otherwise identified as field-erected with a volume less than or equal to
50,000 gallons. (STI SP001, "Standard for the Inspection of Aboveground Storage Tanks," 5th Edition September 2011)
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integrity testing also enables a facility owner/operator to budget and plan for routine maintenance and any
associated repairs and avoid unexpected disruptions to
facility operations.
^ FYI - Industry standard identified in SPCC
Plan
The industry standard identified in an SPCC Plan
outlines the specific inspection and integrity testing
protocol for the containers at the facility. These
protocols may vary depending on the size and
configuration of the facility's containers.
For example, portable containers (e.g., a drum)
have fewer inspection requirements than shop-built
and field-erected containers.
Industry standards describe procedures to identify
the condition of the container through formal internal and
external inspections conducted by certified personnel. For
internal inspections, the container must typically be taken
out of service, cleaned, and made ready for personnel to
enter the container.
Examples of integrity tests include, but are not
limited to:
• Visual inspection,
• Radiographic examination,
• Ultrasonic Testing (UT), including Ultrasonic Thickness Scan (UTS) and Ultrasonic Thickness
Testing (UTT),
• Magnetic Flux Leakage (MFL) scan,
• Helium leak testing,
• Magnetic particle examination,
• Liquid penetrant examination,
• Acoustic emissions testing,
• Hydrostatic testing,
• Inert gas leak testing, or
• Other methods of non-destructive examination.
Acoustic emissions testing and UT robotic measurement118 are non-destructive examination methods
that can be used while the tank is in service. Acoustic emissions testing is used to determine if there is a leak but
does not determine if there is corrosion or metal loss. Hydrostatic testing is typically performed on new tanks
and on existing tanks that have had major repairs or alterations. Industry standards may use one, or a
The PE should determine how to incorporate robotic inspections into an integrity testing program. Robotic inspections alone
may not constitute a comprehensive integrity testing evaluation of the container as specified by the appropriate industry
standards.
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combination, of these non-destructive examination methods or tests as part of an integrity testing program. If
there are containers at the facility that have never been inspected for integrity, then, depending on their size
and configuration, industry standards may require that the owner or operator first assess baseline conditions for
these containers in order to develop an inspection and testing protocol (see Section 7.4 of this chapter for
information on determining a baseline).
\? Integrity Testing and Secondary Containment
Impracticability
Periodic integrity testing is required as an additional
measure in §112.7(d) when it is impracticable to
provide adequate secondary containment for bulk
storage containers (among other measures). The Plan
preparer may decide, based on good engineering
practice, to increase the frequency of integrity tests for
containers that have inadequate secondary
containment because there is a higher potential of a
discharge reaching navigable waters or adjoining
shorelines.
This approach to establish an increased inspection
frequency for an aboveground container without
secondary containment is used in the STI SP001
standard.
According to §112.8(c)(6), the frequency and type
of testing and inspections as well as the qualifications for
personnel performing tests and inspections must be
determined in accordance with applicable industry
standards. While frequent external visual inspections can
often be completed by trained facility personnel, the
requirement to conduct regular integrity tests or
inspections may involve hiring specialized personnel (as
specified by the applicable industry standard). For
example, integrity testing of field-erected aboveground
storage tanks in accordance with API 653 involves formal
in-service external inspections and formal out-of-service
internal inspections conducted by an API 653 certified
inspector. A formal in-service external inspection involves
visual inspection (typically using a standard checklist) and
UT measurements of the tank shell. A formal out-of-
service internal inspection determines the condition of the tank's floor, welds, walls and structure, but should
also include the shell, roof (fixed or floating roof), nozzles, and tank appurtenances. The out-of-service
inspection typically includes non-destructive testing such as MFL scanning of the floor, vacuum box testing of
floor welds, helium leak testing, UT measurements, and tank bottom settlement measurements.
The SPCC rule requires that integrity testing of aboveground bulk storage containers be performed on a
regular schedule, as well as when material repairs120 are made, because such repairs might increase the
potential for oil discharges. Testing on a 'regular schedule' means testing per industry standards or at a
frequency sufficient to prevent discharges. (67 FR 47119, July 17, 2002).
Industry standards establish the scope and frequency for inspections, considering the particular
conditions of the aboveground container. These conditions may include the age, service history, original
construction specifications (e.g., shop-built vs. field-erected, welded steel vs. riveted steel), prior inspection
results, and the existing condition of the container. They may also consider the degree of risk of a discharge to
119
120
Note that in some circumstances, industry standards allow visual inspection alone for portable containers.
Examples of material repairs include removal or replacement of the annular plate ring; replacement of the container bottom;
jacking of a container shell; installation of a 12-inch or larger nozzle in the shell; replacement of a door sheet or tombstone in
the shell, or other shell repair; or such repairs that might materially change the potential for oil to be discharged from the
container.
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navigable waters and adjoining shorelines. For example, for containers that are located near saltwater, an
accelerated corrosion rate would be expected. The frequency of inspections is based on the changing conditions
of the container (e.g., corrosion rates, settling); the interval between inspections may therefore vary over the
lifetime of the container.
Once the Plan preparer selects an inspection schedule for aboveground containers (based on applicable
industry standards), it must be documented in the SPCC Plan and the owner or operator must conduct
inspections according to that schedule. The Plan should also include a description of the conditions of the
container at the time the Plan was certified that led to the specific inspection schedule identified.
Frequent Inspections-Visual
The rule requires frequent inspections of the outside of the container for signs of deterioration,
discharges, or accumulations of oil inside diked areas (§112.8(c)(6)). This visual inspection is intended to be a
routine walk-around and include the container's supports and foundations. The scope and frequency of the
inspection is determined by industry standards or according to a site-specific inspection program developed and
certified121 by the Plan preparer. Industry standards typically require monthly visual inspections, although some
facilities conduct daily or weekly visual inspections of their containers. EPA expects the visual inspection to occur
on an ongoing routine basis, to be conducted by qualified personnel, and to follow industry standards. The
necessary qualifications for personnel conducting the inspections are outlined in tank inspection standards such
as API 653 and STI SPOOL Records of visual inspections should be maintained and kept under usual and
customary business practices.
7.2.3 Removal of Oil Accumulations in Bulk Storage Container Diked Areas
The rule requires that the owner or operator promptly correct visible discharges which result in a loss of
oil from a bulk storage container, including but not limited to seams, gaskets, piping, pumps, valves, rivets, and
bolts and remove oil accumulations in diked areas. "Prompt" removal means beginning the cleanup of any
accumulation of oil immediately after discovery of the discharge, or immediately after any actions to prevent
fire or explosion or other threats to worker health and safety, but such actions may not be used to unreasonably
delay such efforts (67 FR 47122, July 17, 2002).
§112.8(c)(10) and §112.12(c)(10)
Promptly correct visible discharges which result in a loss of oil from the container, including but not limited to seams,
gaskets, piping, pumps, valves, rivets, and bolts. You must promptly remove any accumulations of oil in diked areas.
Note: The above text is only a brief excerpt of the rule. Refer to 40 CFR part 112 for the full text of the rule.
The Plan certification requires that procedures for inspection and testing have been established by either a PE (in accordance
with §112.3(d)(l)(iv)) or the owner or operator of a qualified facility (in accordance with either §112.6(a)(l)(iv) or
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7.2.4 Integrity Testing and Inspection for AFVO Bulk Storage Containers
The integrity testing requirements at §112.12(c)(6)(i), for animal fats and vegetable oil containers are
identical to those described above at §H2.8(c)(6).122 To address differences in the way certain AFVOs may be
stored and handled at a facility, the SPCC rule also provides differentiated, more flexible, alternative
requirements at §112.12(c)(6)(ii) for AFVO containers that meet certain criteria. Facility owners/operators with
AFVO containers that meet the specific criteria can conduct visual inspections of their containers on a regular
schedule in lieu of meeting the integrity testing requirements found at §112.12(c)(6)(i). According to
§112.12(c)(6)(ii), this flexibility applies to bulk storage containers that:
• Are subject to the Food and Drug Administration (FDA) regulations in 21 CFR part 110, Current
Good Manufacturing Practice in Manufacturing, Packing or Holding Human Food;
• Are elevated;
• Are made from austenitic stainless steel;
• Have no external insulation; and
• Are shop-built.
The owner or operator is required to document in the SPCC Plan the procedures for visual inspections of
AFVO bulk storage containers that are eligible for these differentiated requirements.
EPA developed this alternative to integrity testing based on the ways these oils are stored and handled
at a facility. Each of the five criteria for this approach is described below and addresses the design, construction,
and maintenance of bulk storage containers to minimize the potential for internal and external corrosion. Note
that formal visual inspections may be used in lieu of integrity testing only when all five criteria are met.
See Section 7.5.2 for more information on deviating from the SPCC rule requirements based on environmental equivalence.
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112.12(c)(6) Bulk storage container inspections.
(i) Except for containers that meet the criteria provided in paragraph (c)(6)(ii) of this section, test or inspect each
aboveground container for integrity on a regular schedule and whenever you make material repairs. You must
determine, in accordance with industry standards, the appropriate qualifications for personnel performing
tests and inspections, the frequency and type of testing and inspections, which take into account container
size, configuration, and design (such as containers that are: shop-built, field-erected, skid-mounted, elevated,
equipped with a liner, double-walled, or partially buried). Examples of these integrity tests include, but are not
limited to: Visual inspection, hydrostatic testing, radiographic testing, ultrasonic testing, acoustic emissions
testing, or other systems of nondestructive testing. You must keep comparison records and you must also
inspect the container's supports and foundations. In addition, you must frequently inspect the outside of the
container for signs of deterioration, discharges, or accumulation of oil inside diked areas. Records of
inspections and tests kept under usual and customary business practices satisfy the recordkeeping
requirements of this paragraph.
(ii) For bulk storage containers that are subject to 21 CFR part 110, are elevated, constructed of austenitic
stainless steel, have no external insulation, and are shop-fabricated, conduct formal visual inspection on a
regular schedule. In addition, you must frequently inspect the outside of the container for signs of
deterioration, discharges, or accumulation of oil inside diked areas. You must determine and document in the
Plan the appropriate qualifications for personnel performing tests and inspections. Records of inspections and
tests kept under usual and customary business practices satisfy the recordkeeping requirements of this
paragraph (c)(6).
Note: The above text is only a brief excerpt of the rule. Refer to 40 CFR part 112 for the full text of the rule.
FDA Regulation at 21 CFR Part 110
The regulation at 21 CFR part 110, Current Good Manufacturing Practice in Manufacturing, Packing or
Holding Human Food provides minimal elements for an integrity testing program, which address maintenance of
the container, its foundations, and support structures.
FDA requires that facilities be constructed in such a manner that the floor, walls, and ceilings be
adequately cleaned and kept clean and in good repair (21 CFR 110.20(b)(4)). Thus, the FDA requirements include
procedures and practices, such as frequent monitoring of the floor around a bulk storage container, to ensure
that cracks in the floor under and/or around the foundations of a bulk storage container do not accumulate food
particles, organic matter, pests, or other potentially unsanitary substances that could lead to food
contamination. These inspection requirements also address the SPCC rule requirement to inspect the
container's foundations for structural integrity.
Additionally, all plant equipment, including the container's structural supports, must be designed and
constructed to be adequately cleanable and properly maintained (21 CFR 110.40(a)). Periodic maintenance of
the structural supports of a bulk storage container is also an oil spill preventive measure, especially inside a
facility where mobile equipment (e.g., forklifts) can strike and damage the container and/or its structural
supports.
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FDA also requires that equipment (such as bulk storage containers) be designed, constructed, and used
in such a way as to prevent food contamination by metal fragments or other potential contaminants (21 CFR
110.40(a)). Food-contact surfaces must be corrosion-resistant when in contact with food. Monitoring AFVOs for
metal fragments as the oil exits the bulk storage container, either by sampling the oil itself for metal or by
monitoring the inclusion prevention device for metal fragment accumulation, is a reasonable alternative
approach to an internal inspection for corrosion. These regulatory requirements are likely to prevent the
corrosion of the internal contact surface in food grade AFVO bulk storage containers.
For some bulk storage container configurations, external corrosion can be the primary concern with
respect to their integrity. Significant corrosion of the exterior surface can occur from exposure to moisture and,
in some cases, may be enhanced if insulation is present. Significant corrosion can also occur from overfills of oil
and/or any associated substance(s) that have accumulated on the exterior surface, as well as from cleaning and
sanitizing agents. FDA requires equipment that is in the manufacturing or food-handling area but does not come
into contact with food to be constructed to be kept in a clean condition (21 CFR 110.40(c)). Since plant
equipment used in the manufacturing or food-handling area must be designed to be kept clean and withstand
the corrosive effects of cleaning agents, it is generally constructed of austenitic stainless steel.
In order to further address the potential for external corrosion and allow facility personnel to visually
identify leaks and discharges, EPA requires that bulk oil storage containers which will be subject to visual
inspections only be elevated, be made of austenitic stainless steel, have no external insulation and be shop
fabricated. The following sections provide the rationales for these additional criteria.
Elevated Bulk Storage Containers
FDA recommends, but does not require, that all plant equipment be installed and maintained to
facilitate its cleaning, including all adjacent spaces. According to 21 CFR 110.40(a), "all equipment should be so
installed and maintained as to facilitate cleaning of the equipment and of all adjacent spaces." In practice, an
owner or operator of a facility implementing this recommended practice is likely to have a bulk storage
container that is elevated off the floor.
Food equipment is generally designed to stand on legs, which elevates the plant equipment off the floor
so that the space between the plant equipment and the floor can be cleaned. An elevated bulk storage
container also facilitates complete drainage because the oil can be withdrawn from the lowest point in the
container, so that foreign substances or materials do not accumulate and contaminate the food oil.
For the purposes of oil spill prevention, elevated bulk storage containers allow visual inspections for oil
discharges all around the container. Additionally, self-draining containers that operate using gravity flow allow
complete drainage and prevent substances other than oil (e.g., water) from accumulating at the bottom of the
container, thus minimizing corrosion. The self-drainage design, in conjunction with the applicable regulatory
requirements, is likely to prevent the corrosion of the internal contact surface in food-grade AFVO bulk storage
containers.
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Containers Made From Austenitic Stainless Steel
EPA limits the alternative approach to AFVO bulk storage containers made of austenitic stainless steel to
ensure that containers are corrosion resistant and compatible with the materials stored. FDA requires that the
food-contact surface be corrosion resistant under 21 CFR part 110 but does not explicitly require that AFVOs be
stored in austenitic stainless steel bulk storage containers. For example, a carbon steel container with an
internal liner may provide a corrosion resistant food contact surface to meet the FDA requirements. Although
this meets the FDA regulatory requirements for food contact surfaces, the presence of a liner may also indicate
that the oil in the bulk storage container is incompatible with the construction material of the bulk storage
container.
In addition, non-homogenous container systems (e.g., containers with external insulation, external
coating, mild-carbon steel shell, internal liner) are more complex than homogenous container systems (e.g.,
containers constructed solely of austenitic stainless steel) and may require additional inspection measures to
ensure the integrity of the container. Finally, there is less chance of corrosion with austenitic stainless steel
containers because they are compatible with cleaning agents and acidic detergents used to clean food and non-
food contact surfaces.
Note that this limitation to austenitic stainless steel construction is only for an owner or operator who
chooses to take advantage of the alternative compliance option in §112.12(c)(6)(ii). An SPCC Plan may still be
certified with an environmental equivalence determination, in accordance with §112.7(a)(2) of the SPCC rule, for
other types of bulk storage containers that are similarly corrosion resistant but do not meet all of the criteria
described in §112.12(c)(6)(ii). Chapter 3: Environmental Equivalence discusses associated requirements.
Containers with No External Insulation
A minimum criterion for inspections is frequent monitoring of the exterior surface of a bulk storage
container for corrosion and/or other mechanisms that can threaten a container's integrity. External insulation
acts as a physical barrier to prevent effective visual examination of the exterior surface of the bulk storage
container. Additionally, insulating materials on a bulk storage container and/or any associated equipment and
piping can become damp when not properly sealed and cause significant corrosion, which may threaten the
integrity of the container. Therefore, EPA included only containers with no external insulation in the alternative
option for integrity testing.
Shop-Fabricated Containers
Shop-fabricated (i.e., shop-built) containers are containers that are shop-assembled in one piece before
transport to the installation site. Shop-fabricated containers generally have lower volume capacities, smaller
tank diameters, and a fewer number of welds than field-erected containers and are typically comprised of a
single type of material with a single wall thickness.
The Steel Tank Institute's (STI) SP001, Standard for the Inspection for Aboveground Storage Tanks,
establishes the scope and frequency for visual inspections of shop-fabricated containers. EPA limited the
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alternative integrity testing option to shop-fabricated containers because they are simpler in design and
construction (e.g., typically subject to less stress, and less likely to fail as a result of a brittle fracture) than field-
erected containers.
7.2.5 Regular Leak Testing of Completely Buried Tanks
Completely buried metallic storage tanks installed on or after January 10, 1974 must be regularly leak
tested. "Regular testing" means testing in accordance with industry standards or at a frequency sufficient to
prevent leaks. Appropriate methods of testing should be selected based on good engineering practice and tests
conducted in accordance with 40 CFR part 280.43 or
a State program approved under 40 CFR part 281 are
acceptable.
Leak testing is often referred to as "tank
tightness testing." Tank tightness tests include a
wide variety of methods. Other terms used for these
methods include "precision," "volumetric," and
"nonvolumetric" testing. The features of tank
tightness testing vary by method, as described in EPA
19*3
Guidance on meeting UST system requirements:
§§112.8(c)(4),
Protect any completely buried metallic storage tank
installed on or after January 10,1974 from corrosion by
coatings or cathodic protection compatible with local soil
conditions. You must regularly leak test such completely
buried metallic storage tanks.
Note: The above text is only a brief excerpt of the rule. Refer to 40
CFR part 112 for the full text of the SPCC rule.
Many tightness test methods are "volumetric" methods in which the change in product level in a
tank over several hours is measured very precisely (in milliliters or thousandths of an inch).
Other methods use acoustics or tracer chemicals to determine the presence of a hole in the
tank. With such methods, all of the factors in the following bullets may not apply.
For most methods, changes in product temperature also must be measured very precisely
(thousandths of a degree) at the same time as level measurements, because temperature
changes cause volume changes that interfere with finding a leak.
For most methods, a net decrease in product volume (subtracting out volume changes caused
by temperature) over the time of the test indicates a leak.
The testing equipment is temporarily installed in the tank, usually through the fill pipe.
The tank must be taken out of service for the test, generally for several hours, depending on the
method.
Many test methods require that the product in the tank be a certain level before testing, which
often requires adding product from another tank on-site or purchasing additional product.
For more information on tank tightness testing, see: http://www.epa.gov/oust/ustsystm/inventor.htm. For more information on
preventing and detecting underground storage tank system leaks, see http://www.epa.gov/oust/prevleak.htm.
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• Some tightness test methods require all of the measurements and calculations to be made by
hand by the tester.
• Other tightness test methods are highly automated. After the tester sets up the equipment, a
computer controls the measurements and analysis.
• A few methods measure properties of the product that are independent of temperature, such as
the mass of the product, and so do not need to measure product temperature.
• Some automatic tank gauging systems are capable of meeting the regulatory requirements for
tank tightness testing and can be considered as an equivalent method.
The SPCC Plan must describe the method and schedule for testing completely buried tanks.
7.2.6 Brittle Fracture Evaluation of Field-Constructed Aboveground Containers
Brittle fracture is a type of structural failure in aboveground steel tanks, characterized by rapid crack
formation that can cause sudden tank failure. This, along
with catastrophic failures such as those resulting from
lightning strikes, seismic activity, or other such events,
can cause the entire contents of a container to be
discharged to the environment. Brittle fracture was most
vividly illustrated by the splitting and collapse of a 3.8
million gallon (120-foot diameter) tank in Floreffe,
Pennsylvania, which released approximately 750,000
gallons of oil into the Monongahela River in January 1988.
A review of past failures due to brittle fracture shows that
they typically occur:
During an initial hydrotest,
On the first filling in cold weather,
If a field-constructed aboveground container
undergoes a repair, alteration, reconstruction, or a
change in service that might affect the risk of a
discharge or failure due to brittle fracture or other
catastrophe, or has discharged oil or failed due to
brittle fracture failure or other catastrophe,
evaluate the container for risk of discharge or
failure due to brittle fracture or other catastrophe,
and as necessary, take appropriate action.
Note: The above text is only a brief excerpt of the rule. Refer
to 40 CFR part 112 for the full text of the SPCC rule.
• After a change to lower temperature service, or
• After a repair/modification.
Storage tanks with a maximum shell thickness of one-half inch or less are not generally considered at
risk for brittle fracture.124'125
Mclaughlin, James E. 1991. "Preventing Brittle Fracture of Aboveground Storage Tanks- Basis for the Approach Incorporated
into API 653." Case Studies: Sessions III and IV of the IIW Conference: Fitness for Purpose of Welded Structures. October 23-24,
1991, Key Biscayne, Florida, USA. Cosponsored by the American Welding Society, Welding Research Institute, Welding Institute
of Canada, and International Institute of Welding. Published by the American Welding Society, Miami, Florida. Pages 90-110.
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Section 112.7(i) of the SPCC rule requires that field-constructed aboveground containers that have
undergone a repair or change in service that might affect the risk of a discharge due to brittle fracture or other
catastrophe, or have had a discharge associated with brittle fracture or other catastrophe, be evaluated to
assess the risk of such a discharge. Unless the original design shell thickness of the tank is less than one-half inch
(see API 653, Section 5, and STI SP001, Appendix B), evidence of this evaluation should be documented in the
facility's SPCC Plan.
Industry standards discuss methods for assessing the risk of brittle fracture failure for a field-erected
aboveground container and for performing a brittle fracture evaluation. These include API 653, "Tank Inspection,
Repair, Alteration, and Reconstruction," API RP 920 "Prevention of Brittle Fracture of Pressure Vessels," and API
RP 579-1/ASME FFS-1, "Fitness-for-Service." API 653 includes a decision tree or flowchart for use by the
owner/operator and PE in assessing the risk of brittle fracture.
7.2.7 Inspections of Piping at Onshore Facilities (Other than Oil Production Facilities)
Any piping installed prior to August 16, 2002 was subject to coating and cathodic protection if soil
conditions warranted. However, in 2002, the SPCC rule was revised to require that all piping installed or
replaced after August 16, 2002 be protectively wrapped and coated and also cathodically protected. The
preamble to the final rule explains:
"...we believe that all soil conditions warrant protection of buried piping. We did not propose to make the
requirement applicable to all existing piping because of the significant possibility that replacing all
unprotected buried piping might cause more discharges than it would prevent. If soil conditions warrant
such protection for existing piping, it is already required by the current rule." (67 FR 47123, July 17,
2002).
Additionally, the SPCC rule has required since its original promulgation in 1973, that if any portion of
buried piping at non-production facilities is exposed, the line must be inspected for deterioration, as per
§§112.8(d)(l) and 112.12(d)(l). If corrosion damage is found, additional inspection or corrective action must be
taken as needed.
Aboveground piping, valves, and appurtenances at non-production facilities must be regularly inspected,
as per §§112.8(d)(4) and 112.12(d)(4) and in accordance with industry standards. In addition, buried piping must
be integrity and leak tested at the time of installation, modification, construction, relocation, or replacement.
API 653 4th Edition April 2009 Addendum 2 January 2012 Section 5.3.5.
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§112.8(d) and 112.12(d)
(1) Provide buried piping that is installed or replaced on or after August 16, 2002, with a protective wrapping and
coating. You must also cathodically protect such buried piping installations or otherwise satisfy the corrosion protection
standards for piping in part 280 of this chapter or a State program approved under part 281 of this chapter. If a section
of buried line is exposed for any reason, you must carefully inspect it for deterioration. If you find corrosion damage,
you must undertake additional examination and corrective action as indicated by the magnitude of the damage.
(4) Regularly inspect all aboveground valves, piping, and appurtenances. During the inspection you must assess the
general condition of the items, such as flange joints, expansion joints, valve glands and bodies, catch pans, pipeline
supports, locking of valves, and metal surfaces. You must also conduct integrity and leak testing of buried piping at the
time of installation, modification, construction, relocation, or replacement.
Note: The above text is only a brief excerpt of the rule. Refer to 40 CFR part 112 for the full text of theSPCC rule. Emphasis added.
7.2.8 Inspection of Drainage Area and Bulk Storage Containers at Onshore Oil Production
Facilities
Drainage Areas at Oil Production Facilities
The rule contains provisions for inspecting drainage
from tank batteries or separation and treating areas. As per
§112.9(b)(l), dike drains associated with tank batteries and
separation and treating areas must be closed and sealed at
all times and drainage areas must be inspected prior to
draining in accordance with §112.8(c)(3)(ii), (iii), and (iv) as
follows:
• Inspect the retained rainwater to ensure
that its presence will not cause a discharge
as described in §112.1(b);
• Open the bypass valve and reseal it
following drainage under responsible
supervision; and
• Keep adequate records of such events, for
example, any records required under
permits issued in accordance with 40 CFR
122.41(j)(2) and 122.41(m)(3).
Field drainage systems, such as road ditches, and oil
traps, sumps or skimmers must be inspected at regular
§112.9(b)
(1) ...Prior to drainage, you must inspect the diked
area and take action as provided in §112.8(c)(3)(ii),
(iii), and (iv). You must remove accumulated oil on
the rainwater and return it to storage or dispose of
it in accordance with legally approved methods.
(2) Inspect at regularly scheduled intervals field
drainage systems (such as drainage ditches or road
ditches), and oil traps, sumps, or skimmers, for an
accumulation of oil that may have resulted from
any small discharge. You must promptly remove
any accumulations of oil.
§112.9(c)
(3) Except as described in paragraph (c)(5) of this
section for flow-through process vessels and
paragraph (c)(6) of this section for produced water
containers and any associated piping and
appurtenances downstream from the container,
periodically and upon a regular schedule visually
inspect each container of oil for deterioration and
maintenance needs, including the foundation and
support of each container that is on or above the
surface of the ground.
Note: The above text is only a brief excerpt of the rule.
Refer to 40 CFR part 112 for the full text of the SPCC rule.
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intervals (§112.9(b)(2)) for accumulations of oil which must be promptly removed.
Bulk Storage Containers at Oil Production Facilities
Each bulk storage container (e.g., oil stock tanks/26 flow-through process vessels, and produced water
containers) at an oil production facility must be inspected periodically and upon a regular schedule for signs of
deterioration and maintenance needs in accordance with §112.9(c)(3), including the foundation and support of
each container that is on or above the surface of the ground. This inspection is intended to be a routine walk-
around where the inspector looks at the container and supports and foundations for any evidence of damage,
corrosion, or leaks. The inspection procedures and schedule must be documented in the SPCC Plan and
inspections conducted in accordance with the Plan, good engineering practices, and any appropriate industry
standards or recommended practices identified in the Plan.
The inspection should occur on an ongoing routine basis and be conducted by qualified personnel.
Before the PE certifies the SPCC Plan in accordance with §112.3(d),127 he must consider applicable industry
standards and verify that appropriate procedures for inspections and tests have been established. API has
developed Recommended Practice 12R1 "Recommended Practice for Setting, Maintenance, Inspection,
Operation and Repair of Tanks in Production Service" that includes inspection procedures for tanks employed in
onshore oil production service and in certain circumstances includes non-destructive testing elements in
addition to visual inspection.
Additionally, the owner or operator of an onshore oil production facility must conduct integrity testing
for any bulk storage containers for which he determines secondary containment is impracticable. The Plan must
follow the provision of §112.7(d) and clearly explain why secondary containment measures are not practicable;
for bulk storage containers, conduct both periodic integrity testing of the containers and periodic integrity and
leak testing of the valves and piping; and, unless the facility owner or operator has submitted a response plan
under §112.20, provide the following in the Plan:
• An oil spill contingency plan following the provisions of 40 CFR part 109, and
• A written commitment of manpower, equipment, and materials required to expeditiously
control and remove any quantity of oil discharged that may be harmful.
7.2.9 Alternative Inspection requirements for Flow-through Process Vessels at Oil
Production Facilities
Flow-through process vessels at oil production facilities are bulk storage containers and are therefore
subject to the bulk storage container requirements of §112.9(c) including specific secondary containment
A stock tank is a storage tank for oil production after the oil has been treated (Schlumberger Oil Field Glossary
http://www.glossary.oilfield.slb.com/)
In the case of a qualified facility, the owner or operator would certify the SPCC Plan in accordance with either §112.6(a)(l) or
112.6(b)(l), as applicable.
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requirements of §112.9(c)(2). However, facility owners and operators have the option to implement alternative
requirements in accordance with §112.9(c)(5) in lieu of providing sized secondary containment.
As an alternative to the sized secondary containment and inspection requirements for bulk storage
containers at oil production facilities found at §§112.9(c)(2) and 112.9(c)(3), an oil production facility owner or
operator may opt to provide general secondary containment in accordance with §112.7(c), and comply with the
following requirements for flow-through process vessels at oil production facilities:
• Periodically and on a regular schedule visually inspect and/or test flow-through process
vessels and associated components (such as dump valves) for leaks, corrosion, or other
conditions that could lead to a discharge, as described in §112.l(b). Regular inspections are
necessary to ensure that any leak, or potential for a leak, is detected promptly enough to
prevent a discharge of the entire contents of the separation or treating equipment. This is
especially true for components that typically cause discharges, such as dump valves. These
requirements are consistent with the inspection requirements for bulk storage containers under
§112.9(c)(3). (73 FR 74279, December 5, 2008). Records of inspections or tests must be
maintained in accordance with §112.7(e). This requirement is necessary to increase the
likelihood that a discharge to navigable waters or
adjoining shorelines will be prevented or
r&
S? Tip -Oil discharge
Note that the SPCC rule defines discharge to
include any spilling, leaking, pumping,
pouring, emitting, emptying, or dumping of
oil... and not just a discharge as described in
§112.l(b) (i.e., a discharge to navigable
waters or adjoining shorelines.)
Therefore corrective action and removal
must be initiated before the discharge
reaches navigable waters or adjoining
shorelines.
detected promptly.
Take corrective action or make repairs to flow-
through process vessels and any associated
components as indicated by regularly scheduled
visual inspections, tests, or evidence of an oil
discharge. Corrective action/repairs ensure that
equipment is adequately maintained to prevent
discharges from flow-through process vessels and
associated components. Needed repairs that are
identified during regular inspections should be scheduled in a timely manner to prevent a
discharge.
Promptly remove or initiate actions to stabilize and remediate any accumulations of oil
discharges associated with flow-through process vessels. If a leak or spill is identified during an
inspection, corrective action is necessary to ensure that a discharge does not impact navigable
waters or adjoining shorelines. The owner or operator must remove, or stabilize and remediate,
oil accumulations from flow-through process vessels and any associated components in order to
prevent a discharge as described in §112.l(b). This may include removal of oil-contaminated
soil. Removal of recoverable oil may be combined with physical, chemical, and/or biological
treatment methods to address any residual oil. These treatment methods must be consistent
with other Federal, state or local requirements as applicable, and must be properly managed to
prevent a discharge as described in §112.l(b). Disposal of oil and/or oil-contaminated media
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must be in accordance with applicable Federal, state, and local requirements (see 73 FR 74279,
December 5, 2008). The SPCC Plan must describe the methods of disposal of recovered
materials in accordance with applicable legal requirements under §112.7(a)(3)(v).
These additional requirements are necessary because oil production facilities are generally unattended,
so there is a lower potential to immediately discover and correct a discharge than at a non-production facility,
which would typically be attended during hours of operation. The owner or operator of the facility may choose
to deviate from the measures described above by substituting environmentally equivalent alternatives. The
alternative measure chosen, and certified by a PE, must represent good engineering practice and must achieve
environmental protection equivalent to the SPCC rule requirement as required in §112.7(a)(2). For more
information on environmental equivalence, see Chapter 3: Environmental Equivalence, Section 3.3.8. For more
information on how to determine appropriate secondary containment capacity to comply with the general
secondary containment requirements of §112.7(c), see Chapter 4: Secondary Containment and Impracticability,
Section 4.8.1.
§112.9(c)(5)
Flow-through process vessels. The owner or operator of a facility with flow-through process vessels may choose to
implement the alternate requirements as described below in lieu of sized secondary containment required in
paragraphs (c)(2) and (c)(3) of this section.
(i) Periodically and on a regular schedule visually inspect and/or test flow-through process vessels and
associated components (such as dump valves) for leaks, corrosion, or other conditions that could lead
to a discharge as described in §112.l(b).
(ii) Take corrective action or make repairs to flow-through process vessels and any associated components as
indicated by regularly scheduled visual inspections, tests, or evidence of an oil discharge.
(iii) Promptly remove or initiate actions to stabilize and remediate any accumulations of oil discharges
associated with flow-through process vessels.
(iv) If your facility discharges more than 1,000 U.S. gallons of oil in a single discharge as described in
§112. l(b), or discharges more than 42 U.S. gallons of oil in each of two discharges as described in
§112.l(b) within any twelve month period, from flow-through process vessels (excluding discharges
that are the result of natural disasters, acts of war, or terrorism) then you must, within six months
from the time the facility becomes subject to this paragraph, ensure that all flow-through process
vessels subject to this subpart comply with §112.9(c)(2) and (c)(3).
Note: The above text is an excerpt of the SPCC rule. Refer to 40 CFR part 112 for the full text of the rule.
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v^ Tip - Discharges from flow-through process vessels
If flow-through process vessels at the facility cause a single discharge of oil to navigable waters or adjoining shorelines
exceeding 1,000 U.S. gallons, or two discharges of oil to navigable waters or adjoining shorelines each exceeding 42 U.S.
gallons within any 12-month period (excluding discharges that are the result of natural disasters, acts of war, or
terrorism), then the owner/operator must, within six months:
Install sized secondary containment with sufficient freeboard for precipitation for all flow-process vessels at
the facility,
Periodically and upon a regular schedule visually inspect each container of oil for deterioration and
maintenance needs, including the foundation and support of each container that is on or above the surface of
the ground, and
Submit a report to the Regional Administrator within 60 days of the discharge(s) and to the appropriate state
agency or agencies in charge of oil pollution control activities, as per Section 112.4(a).
The report must include the name of the facility; the name of the owner or operator; location of the facility; maximum
storage or handling capacity of the facility and normal daily throughput; corrective action and countermeasures taken,
including a description of equipment repairs and replacements; an adequate description of the facility, including maps,
flow diagrams, and topographical maps, as necessary; the cause of the discharge(s), including a failure analysis of the
system or subsystem in which the failure occurred; additional preventive measures taken or contemplated to minimize
the possibility of recurrence; and any other information as the Regional Administrator may reasonably require pertinent
to the Plan or discharge.
7.2.10 Alternative Inspection Requirements for Produced Water Containers at Oil
Production Facilities
Like flow-through process vessels, produced water containers are bulk storage containers and are
therefore subject to the bulk storage container requirements of §112.9(c) for oil production facilities, including
specific secondary containment requirements of §112.9(c)(2).
However, differentiated inspections and testing requirements apply in cases where the facility owner or
operator takes advantage of the option outlined in §112.9(c)(6) in lieu of providing sized secondary containment
for produced water containers.
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§112.9(c)
(6) For each produced water container, comply with §112.9(c)(l) and (c)(4); and §112.9(c)(2) and (c)(3), or comply
with the provisions of the following paragraphs (c)(6)(i) through (v):
(i) Implement, on a regular schedule, a procedure for each produced water container that is designed to separate
the free-phase oil that accumulates on the surface of the produced water. Include in the Plan a description of the
procedures, frequency, amount of free-phase oil expected to be maintained inside the container, and a Professional
Engineer certification in accordance with §112.3(d)(l)(vi). Maintain records of such events in accordance with
§112.7(e). Records kept under usual and customary business practices will suffice for purposes of this paragraph. If
this procedure is not implemented as described in the Plan or no records are maintained, then you must comply
with §112.9(c)(2) and (c)(3).
(ii) On a regular schedule, visually inspect and/or test the produced water container and associated piping for leaks,
corrosion, or other conditions that could lead to a discharge as described in §112.l(b) in accordance with good
engineering practice.
(iii) Take corrective action or make repairs to the produced water container and any associated piping as indicated
by regularly scheduled visual inspections, tests, or evidence of an oil discharge.
(iv) Promptly remove or initiate actions to stabilize and remediate any accumulations of oil discharges associated
with the produced water container.
(v) If your facility discharges more than 1,000 U.S. gallons of oil in a single discharge as described in §112. l(b), or
discharges more than 42 U.S. gallons of oil in each of two discharges as described in §112. l(b) within any twelve
month period from a produced water container subject to this subpart (excluding discharges that are the result of
natural disasters, acts of war, or terrorism) then you must, within six months from the time the facility becomes
subject to this paragraph, ensure that all produced water containers subject to this subpart comply with
§112.9(c)(2)and(c)(3).
Note: The above text is only a brief excerpt of the rule. Refer to 40 CFR part 112 for the full text of the SPCC rule.
As an alternative to the sized secondary containment requirements and inspection requirements for
bulk storage containers at oil production facilities found at §§112.9(c)(2) and 112.9(c)(3), an oil production
facility owner or operator may opt to provide general secondary containment in accordance with §112.7(c) for
produced water containers, and comply with the following additional requirements:
Implement on a regular schedule a procedure for each produced water container that is designed to
separate the free-phase oil that accumulates on the surface of the produced water (e.g., skimming
program).
• The facility owner or operator must implement a process and/or procedure for the produced
water container (s) that is designed to remove the free-phase oil that accumulates on the
surface of the produced water container. This process or procedure must be implemented on a
regular schedule so that the amount of free phase oil that collects in produced water containers
does not exceed the amounts that can be managed by the general secondary containment
system designed by the PE to address the typical failure mode, and the most likely quantity of oil
that would be discharged.
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The SPCC Plan must include a description of the free-phase oil separation and removal process
or procedure, the frequency at which the procedure is implemented or operated, the maximum
amount of free-phase oil expected to accumulate in the container, and a description of the
adequacy of the general secondary containment approach for the produced water container,
including the anticipated typical failure mode and the method, design, and capacity for general
secondary containment. Additionally, the owner or operator must keep records of the
implementation of these procedures in accordance with §112.7(e). (see 73 FR 74287, December
5, 2008).
Section 112.3(d)(l)(vi) requires the PE to certify that the oil removal process or procedure for
produced water containers is designed according to good engineering practice to reduce the
accumulation of free-phase oil, and that the process or procedure and frequency for required
inspections, maintenance, and testing have been established. When developing this procedure
and designing general secondary containment for produced water containers, the PE should
carefully consider the length of time the facility is unattended and the flow rate of produced
water into the container to ensure that the most likely discharge of the produced water
container is discovered before it escapes secondary containment.
<& Tip - Oil discharge
Note that the SPCC rule defines discharge
to include any spilling, leaking, pumping,
pouring, emitting, emptying, or dumping
of oil... and not just a discharge as
described in §112.l(b) (i.e., a discharge to
navigable waters or adjoining shorelines).
Therefore, corrective action and removal
must be initiated when the container is
leaking but before the discharge reaches
navigable waters or adjoining shorelines.
• Furthermore, this oil removal process or procedure
is essential for reducing the amount of free-phase oil
in the produced water container to ensure that the
secondary containment system is appropriate to
contain a discharge before cleanup can occur.
Therefore, EPA inspectors should review records of
the implementation of the process or procedure to
ensure that the Plan is being properly implemented.
If, upon inspection, it is discovered that the removal
process or procedure is not implemented, then the
Regional Administrator may require amendments to
the Plan that include providing sized secondary
containment for produced water containers at the facility (§112.4(d)).
On a regular schedule, visually inspect and/or test the produced water container and associated
piping for leaks, corrosion, or other conditions that could lead to a discharge as described in §112.1(b)
in accordance with good engineering practice.
• These inspections and/or tests are to be done in conjunction with procedures implemented on a
regular schedule to separate the free-phase oil that accumulates on the surface of the produced
water, and are meant to ensure that the produced water container will not cause a discharge as
described in §112.l(b) were its contents to be released. The inspections and tests may involve,
for example, frequently inspecting the content of the produced water container to assess the
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amount of oil that has accumulated. Records of inspections or tests must be maintained in
accordance with §112.7(e). This requirement is necessary to increase the likelihood that a
discharge to navigable waters or adjoining shorelines will be prevented or detected promptly
when general secondary containment measures are used instead of sized secondary
containment.
Take corrective action or make repairs to the produced water container and any associated piping as
indicated by regularly scheduled visual inspections, tests, or evidence of an oil discharge.
• Corrective action is necessary to prevent a discharge from occurring, as well as in response to a
discharge. This measure is intended to prevent discharges by ensuring that produced water
containers are adequately maintained.
Promptly remove or initiate actions to stabilize and remediate any accumulations of oil discharges
associated with the produced water container.
• This requirement is intended to ensure the removal of oil accumulations around the container
and any associated piping and appurtenances that may contribute to a discharge as described in
§112.l(b). This may include removal of oil-contaminated soil as a means of preventing oil from
becoming a discharge as described in §112.l(b). Disposal of oil and/or oil-contaminated media
must be in accordance with applicable Federal, state, and local requirements.
The owner or operator of the facility may choose to deviate from the measures described above by
substituting environmentally equivalent alternatives, but must still comply with the secondary containment
requirements in §112.7(c). The alternative measure chosen, and certified by a PE, must represent good
engineering practice and must achieve environmental protection equivalent to the SPCC rule requirement, as
required in §112.7(a)(2). For more information on environmental equivalence see Chapter 3: Environmental
Equivalence, Section 3.3.8. For more information on how to determine appropriate capacity for secondary
containment systems to comply with the general
secondary containment requirements of §112.7(c)
see Chapter 4: Secondary Containment and
Impracticability, Section 4.8.2.
7.2.11 Inspection of Facility Transfer
Operations at Onshore Oil
Production Facilities
All aboveground valves and piping at facility
transfer operations must be inspected on a regular
schedule to check the condition of all components
(§112.9(d)(l)and(2)).
§112.9(d)
(1) Periodically and upon a regular schedule inspect all
aboveground valves and piping associated with transfer
operations for the general condition of flange joints,
valve glands and bodies, drip pans, pipe supports,
pumping well polish rod stuffing boxes, bleeder and
gauge valves, and other such items.
(2) Inspect saltwater (oil field brine) disposal facilities
often, particularly following a sudden change in
atmospheric temperature, to detect possible system
upsets capable of causing a discharge.
Note: The above text is only a brief excerpt of the rule. Refer to 40
CFR part 112 for the full text of the SPCC rule.
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Inspections "upon a regular schedule" means in accordance with industry standards or at a frequency
sufficient to prevent discharges as described in §112.l(b). Whatever frequency of inspections is selected must
be documented in the Plan (67 FR 47130, July 17, 2002). The inspection requirement includes transfer
operations, including but not limited to all aboveground valves and piping, the general condition of flange joints,
valve glands and bodies, drip pans, pipe supports, pumping well polish rod stuffing boxes, bleeder and gauge
valves, and other such items. Saltwater or oil field brine disposal facilities also must be inspected often and
particularly following a sudden change in atmospheric temperature.
7.2.12 Maintenance of Flowlines and Intra-Facility Gathering Lines
The purpose of a flowline/intra-facility gathering line maintenance program is to help prevent oil
discharges from this piping. Common causes of such discharges include mechanical damage (e.g., impact or
rupture) and corrosion. The SPCC rule requires that the scope of a maintenance program include written
procedures and other measures to prevent corrosion or other conditions that could cause a discharge. An
effective flowline/intra-facility gathering line maintenance program is necessary to detect a discharge in a timely
manner so that the oil discharge response operations described in a contingency plan may be implemented
effectively.
§112.9(d)(4)
Prepare and implement a written program of flowline/intra-facility gathering line maintenance. The maintenance
program must address your procedures to:
(i) Ensure that flowlines and intra-facility gathering lines and associated valves and equipment are compatible
with the type of production fluids, their potential corrosivity, volume, and pressure, and other conditions
expected in the operational environment.
(ii) Visually inspect and/or test flowlines and intra-facility gathering lines and associated appurtenances on a
periodic and regular schedule for leaks, oil discharges, corrosion, or other conditions that could lead to a
discharge as described in §112.l(b). For flowlines and intra-facility gathering lines that are not provided with
secondary containment in accordance with §112.7(c), the frequency and type of testing must allow for the
implementation of a contingency plan as described under part 109 of this chapter.
(iii) Take corrective action or make repairs to any flowlines and intra-facility gathering lines and associated
appurtenances as indicated by regularly scheduled visual inspections, tests, or evidence of a discharge.
(iv) Promptly remove or initiate actions to stabilize and remediate any accumulations of oil discharges associated
with flowlines, intra-facility gathering lines, and associated appurtenances.
Note: The above text is an excerpt of the SPCC rule. Refer to 40 CFR part 112 for the full text of the rule.
The SPCC rule specifically requires a written maintenance program that addresses procedures to:
• Ensure that flowlines and intra-facility gathering lines and associated valves and equipment are
compatible with the type of production fluids, their potential corrosivity, volume, pressure, and
other operating conditions.
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• Visually inspect and/or test flowlines and intra-facility gathering lines and associated
appurtenances on a periodic and regular schedule for leaks, oil discharges, corrosion, or other
conditions that could lead to a discharge as described in §112.l(b). For flowlines and intra-
facility gathering lines that are not provided with secondary containment in accordance with
§112.7(c), the frequency and type of testing must allow for the implementation of a contingency
plan as described under 40 CFR part 109.
• Take corrective action or make repairs to any flowlines and intra-facility gathering lines and
associated appurtenances as indicated by regularly scheduled visual inspections, tests, or
evidence of a discharge. Note that the SPCC rule defines discharge to include any spilling,
leaking, pumping, pouring, emitting, emptying, or dumping of oil; not just a discharge as
described in §112.l(b) (i.e., a discharge to navigable waters or adjoining shorelines). Therefore,
corrective action and removal must be initiated before the discharge reaches navigable waters
or adjoining shorelines.
• Promptly remove or initiate actions to stabilize and remediate any accumulations of oil
discharges associated with flowlines, intra-facility gathering lines, and associated
appurtenances. The owner or operator of the facility has both the responsibility and flexibility to
outline an inspection program under §112.9(d)(4)(ii) that puts the timeframe for "prompt
removal" in the context of the inspection frequency (73 FR 74276, December 5, 2008).
Oil production facility owners or operators must either provide secondary containment for flowlines and
intra-facility gathering lines in accordance with §112.7(c) or comply with alternative measures for these lines
under §112.9(d)(3). Unless the facility owner/operator has submitted a response plan under §112.20, the
alternative measures include an oil spill contingency plan following the provisions of 40 CFR part 109 and a
written commitment of manpower, equipment, and materials required to expeditiously control and remove any
quantity of oil discharged that might be harmful.
The frequency and type of inspections and/or tests must allow for the implementation of the
contingency plan prepared in accordance with 40 CFR part 109 or the FRP. This measure is intended to ensure
that any discharges, potential problems or conditions related to the flowline/intra-facility gathering line that
could lead to a discharge will be promptly discovered. This is because an oil spill contingency plan cannot be
effective unless the discharge is discovered in a timely manner so that the response operations described in the
contingency plan can be implemented.
Additionally, the results of inspections or tests will inform the owner/operator of any corrections or
repairs that need to be made. Corrective action is necessary in order to prevent a discharge as described in
§112.l(b) by ensuring that flowlines and intra-facility gathering lines are well maintained and by ensuring
prompt corrective actions or repairs in response to conditions found during the inspection/testing of the flow
and intra-facility gathering lines.
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The Plan preparer certifying the Plan will typically establish the scope and frequency of inspections,
tests, and preventive maintenance based on industry standards, manufacturer's recommendations, and other
sources of good engineering practice. This guidance refers to selected relevant industry standards that describe
methods used to test the integrity of piping, such as API 570128 and ASME B31.4. While these standards are not
specific to flowlines and intra-facility gathering lines, they may serve as guidance. There is currently no published
industry standard for a flowline or intra-facility gathering line maintenance program; however, a standard may
be developed in the future. If an industry standard is developed that meets all of the requirements described in
§112.9(d)(4) then the PE may follow that standard when developing a flowline/intra-facility gathering line
program for the facility.
Due to changes in flowrates and corrosivity of production fluids over time in an oil field, the frequency
of inspection may need to change over the lifetime of the well in order to prevent discharges. For buried piping,
a facility owner or operator should develop an inspection program to identify evidence of leaks at the surface or
other conditions that may lead to a discharge to navigable waters or adjoining shorelines. The provisions for a
flowline/intra-facility gathering line maintenance program in §112.9(d)(4) are eligible for environmental
equivalence as discussed in more detail in Chapter 3:.... Equivalence, Section 3.3.5.
7.2.13 Inspection and Corrective Action Requirements at Offshore Facilities
For offshore facilities, the SPCC rule includes inspection requirements for oil collection equipment,
sumps, pollution prevention equipment, and piping.
Section 112.11(b) requires that the facility include oil collection equipment to prevent and control small
oil discharges and direct facility drains toward a central collection sump to prevent a discharge as described in
§112.l(b). When drains and sumps are not practicable, oil must be removed from collection equipment as often
as necessary to prevent an overflow. The facility owner/operator can use inspections as directed in §112.11(h)
and (i) to determine the frequency of oil removal activities to prevent overflows from this collection equipment.
Facilities employing a sump system must provide adequately sized sump and drains; make available a
spare pump to remove liquid from the sump and assure that oil does not escape; and employ a regularly
scheduled preventive maintenance inspection and testing program to assure reliable operation of the liquid
removal system and pump start-up device. Redundant automatic sump pumps and control devices may be
required on some installations (§112.11(c)). In accordance with §112.11(h), the offshore facility owner/operator
must prepare and maintain at the facility a written procedure within the Plan for inspecting and testing pollution
prevention equipment and systems and then implement that procedure as directed in §112.11(i). The rule
requires the owner or operator to conduct testing and inspection of the pollution prevention equipment and
systems at the facility on a scheduled periodic basis, commensurate with the complexity, conditions, and
circumstances of the facility and any other appropriate regulations and to use simulated discharges for testing
and inspecting human and equipment pollution control and countermeasure systems.
API 570 3th Edition November 2009
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Finally, the owner/operator must maintain sub-marine piping appurtenant to the facility in good
operating condition at all times and inspect or test such piping for failures periodically and according to a
schedule in accordance with §112.11(p).
§112.11 Relevant sections
(b) Use oil drainage collection equipment to prevent and control small oil discharges around pumps, glands, valves,
flanges, expansion joints, hoses, drain lines, separators, treaters, tanks, and associated equipment. You must control
and direct facility drains toward a central collection sump to prevent the facility from having a discharge as described in
§ 112.l(b). Where drains and sumps are not practicable, you must remove oil contained in collection equipment as
often as necessary to prevent overflow.
(c) For facilities employing a sump system, provide adequately sized sump and drains and make available a spare pump
to remove liquid from the sump and assure that oil does not escape. You must employ a regularly scheduled preventive
maintenance inspection and testing program to assure reliable operation of the liquid removal system and pump start-
up device. Redundant automatic sump pumps and control devices may be required on some installations.
(h) Prepare and maintain at the facility a written procedure within the Plan for inspecting and testing pollution
prevention equipment and systems.
(i) Conduct testing and inspection of the pollution prevention equipment and systems at the facility on a scheduled
periodic basis, commensurate with the complexity, conditions, and circumstances of the facility and any other
appropriate regulations. You must use simulated discharges for testing and inspecting human and equipment pollution
control and countermeasure systems.
(p) Maintain sub-marine piping appurtenant to the facility in good operating condition at all times. You must
periodically and according to a schedule inspect or test such piping for failures. You must document and keep a record
of such inspections or tests at the facility.
Note: The above text is only a brief excerpt of the rule. Refer to 40 CFR part 112 for the full text of theSPCC rule.
7.3 Role of Industry Standards and Recommended Practices in Meeting SPCC
Requirements
The SPCC rule does not require the use of a specific industry standard for conducting inspections,
evaluations, and integrity testing of bulk storage containers and other equipment at a facility. Rather, the rule
provides flexibility in a facility owner/operator's use of industry standards to comply with the requirements,
consistent with good engineering practice and as reviewed by the PE certifying the Plan.
To develop an appropriate inspection, evaluation, and testing program for an SPCC-regulated facility,
the PE must consider applicable industry standards (§112.3(d)(l)(iii)). If the facility owner or operator indicates
in the SPCC Plan that he intends to use a standard to comply with a particular rule requirement (e.g., integrity
testing), then it is mandatory to implement the relevant portions of the standard (i.e., those that address
integrity testing of the container). In this case, if the standard is more stringent than federal regulations (e.g., for
recordkeeping retention requirements), the standard would take precedent. A summary is provided in Table 7-5
later in this chapter to assist EPA inspectors in reviewing the relevance of particular industry standards to the
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equipment observed at an SPCC-regulated facility. The SPCC Plan
should clearly identify the standard used to comply with the SPCC
requirements. As required in §112. 5(b), facility owners/operators
must review their SPCC Plan at least once every five years to include
more effective prevention and control technology. This may provide
an opportunity to consider revisions to industry standards and
determine whether these revisions impact implementation of the
SPCC Plan.
ip for Qualified Facilities
The Plan preparer must ensure that the
Plan is prepared in accordance with
accepted and sound industry practices and
standards; and that procedures for required
inspections and testing are established in
accordance with industry inspection and
testing standards or recommended
Industry standards typically apply to containers built according to a specified design (API 653, for
example, applies to tanks constructed in accordance with API 650 or API 12C specifications); the standards129
describe the scope, frequency, and methods for evaluating the suitability of the containers for continued
service. This assessment usually considers performance relative to specified minimum criteria, such as remaining
shell thickness or ability to maintain pressure. The standards specify certain visual inspections, evaluations,
assessments, and tests that must be performed by inspectors certified by the standard-setting organizations
(e.g., American Petroleum Institute, Steel Tank Institute).
In the preamble to the 2002 SPCC rule amendments, EPA provided examples of industry standards that
may constitute good engineering practice for assessing the integrity of different types of containers for oil
storage (67 FR 47120, July 17, 2002). Compliance with other federal requirements and industry standards may
also meet SPCC inspection, evaluation, and testing requirements. For example, the U.S. Department of
Transportation (DOT) regulates containers used to transport hazardous materials, including certain oil products;
mobile/portable containers that leave a facility are subject to the DOT construction and continuing qualification
and maintenance requirements (49 CFR part 178 and 49 CFR part 180). Measures that comply with these DOT
requirements may be used by the facility owner and operator and by the certifying PE as references of good
engineering practice for assessing the fitness for service of mobile/portable containers.
Table 7-2 summarizes key elements of industry standards and recommended practices commonly used
for testing aboveground storage tanks (ASTs). Table 7-3 summarizes key elements of standards and
recommended practices used for testing piping and other equipment. Section 7.7 provides a more detailed
description of the standards listed in the tables. Other industry standards, beyond those detailed in this chapter,
exist for specific equipment or purposes. Many of these are cross-referenced in API 653, including publications
and standards from other organizations such as the American Society for Testing and Materials (ASTM), the
American Society for Non-Destructive Testing (ASNT), and the American Society of Mechanical Engineers
(ASME). Other organizations, such as the National Fire Protection Association (NFPA), the National Association of
Corrosion Engineers (NACE), and the Underwriters Laboratory (UL), also provide critical information on various
container types and appurtenances. Note that this Chapter reflects industry standards in effect at the time EPA
revised this Guidance; however, industry standards are subject to change.
See Section 7.7 of this chapter for more information on these publications.
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Table 7-2: Summary of industry standards and recommended practices (RP) for ASTs.
Equipment
covered
Scope
Inspection
interval
Inspection
performed by
Applicable
section of this
Guidance
API 653130
Field-fabricated,
welded, or riveted ASTs
operating at
atmospheric pressure
and built according to
API 650 and API 12C.
Inspection and design;
fitness for service;
repair and alterations;
risk.
Certified inspections:
Dependent on tank's
service history.
Intervals from 5 to 30
years.
Owner inspections:
monthly.
Authorized inspector,
tank owner.
Section 7.7.1
STI SP001131
ASTs including shop-
fabricated and field-
erected tanks and
portable containers and
containment systems
with contents at
atmospheric pressure
and upto200°F
(93.3-C).
Inspection and
evaluation of ASTs.
Certified inspections:
Inspection intervals and
scope based on tank
size and configuration.
Owner inspections:
monthly, quarterly, and
yearly.
Certified inspector
(either by API 653 with
STI adjunct certification
or STI) or owner's
inspector.
Section 7.7.2
API RP 575132
Atmospheric and low-
pressure ASTs that have
been in service.
Inspection and repair of
tanks.
Same as API 653 and
API RP 12R1.
Same as API 653.
Section 7.7.3
API RP 12R1133
Atmospheric ASTs
employed in oil and gas
production, treating,
and processing.
Setting, connecting,
maintaining, operating,
inspecting, and
repairing tanks.
Scheduled and
unscheduled internal
and external
inspections conducted
as per Table 1 and
Table 2 of the
Recommended
Practice, based on tank
conditions.
Competent person or
qualified inspector, as
defined in
recommended practice.
Section 7.7.5
130
131
132
133
API 653 4th Edition April 2009 Addendum 2 January 2012
STI SP001 5th Edition September 2011
API 575 2nd Edition May 2005
AP 12R1 5th Edition April 2008
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Table 7-3: Summary of industry standards and recommended practices (RP) for piping, valves, and
appurtenances.
Equipment
covered
Scope
Inspection
interval
Inspection
performed
by
Applicable
section of
this
Guidance
API 570134
In-service
aboveground and
buried metallic
piping
Inspection, repair,
alteration, and
rerating
procedures
Based on possible
forms of
degradation and
consequence of
failure, maximum
of 10 years
Authorized piping
inspector
Section 7.7.6
API RP 574135
Piping, tubing,
valves and fittings
in petroleum
refineries and
chemical plants
Inspection
practices, intervals
and records.
Based on five
factors including
consequences of a
failure as classified
by API 570
Authorized piping
inspector
Section 7.7.7
API RP 1110136
Steel pipelines for
the transportation
of gas, petroleum
gas, hazardous
liquids, highly
volatile liquids or
carbon dioxide
(pressure testing)
Planning,
implementation
and records and
drawings for
pressure testing
Not specified
Qualified by both
training and
experience,
considering six
factors
Section 7.7.8
ASME B31.3137
New process piping
for oil,
petrochemical,
chemical, and
other industries
Safety
requirements for
design,
construction and
testing
As part of quality
assurance function.
Differentiates
between
inspection and
examination
Qualified
Inspector, as
defined in standard
Section 7.7.11
ASME B31.4138
Pressure piping for
liquid
hydrocarbons and
other liquids
Safe design,
construction,
inspection, testing,
operation, and
maintenance
Not specified
Qualified
Inspector, as
defined in standard
Section 7.7.13
134
135
136
137
138
API 570 3rd Edition November 2009
API 574 3rd Edition November 2009
API 1110 5th Edition June 2007
ASME B31.3 3rd Edition 2008
ASME B31.4 2006
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7.4 Baselining
Industry standards, such as API 653 and STI SP001, contain minimum requirements to inspect
aboveground containers and criteria to assess each container's suitability for continued service. The baseline
and suitability evaluation provides information on the container's existing condition relative to the design metal
thickness and the rate of metal loss from corrosion as well as the anticipated remaining service. Some facilities
may not have yet performed integrity testing of their tanks. In this case, developing an appropriate integrity
testing program will require assessing baseline conditions for these tanks. This "baseline" will provide
information on the existing condition of the tank shell and tank bottom, or other factors, in order to establish a
regular inspection schedule.
Section 112.7 of the rule requires that if any facilities, procedures, methods, or equipment are not yet
fully operational, the SPCC Plan must explain the details of installation and operational start-up; this applies to
the inspection and testing programs required by the rule. If an owner or operator has yet to implement the
integrity testing program, the SPCC Plan should establish and document a schedule (in accordance with good
engineering practice and the introductory paragraph
of §112.7) that describes the projected
implementation of the integrity testing program for
the aboveground bulk storage containers at the
facility. The owner or operator must then
implement the inspection program in accordance
with the SPCC Plan. The PE is responsible for
determining the scope and frequency of testing
when certifying, in accordance with §112.3(d), that
the SPCC Plan is consistent with industry standards
and is appropriate for the facility.
Is a baseline necessary when the standard requires
only visual inspections?
No, if the industry standard only requires visual inspections
for the container (e.g., certain shop-built containers) then a
baseline is not necessary. The standard establishes a
frequency for visual inspections rather than basing the
interval on the container's corrosion rate. On the other hand,
a baseline is necessary for most non-destructive testing
protocols, because the container's corrosion rate impacts the
frequency/interval of future formal integrity testing
inspections.
Owners and operators need to refer to the particular industry
standard identified in the SPCC Plan to determine the scope
of inspection and testing requirements. For example, under
the STI SP001 standard, visual inspection is allowed for
portable containers such as drums and totes. A baseline
determination of metal thickness of a portable container is
not required prior to implementing the visual-only integrity
testing inspection protocol.
The implementation of the testing program
should be in accordance with industry standards and
establish appropriate inspection priorities among
multiple containers at a facility. For instance, special
consideration may be discussed in the Plan for
containers for which the age and existing condition
is not known (no baseline or only partial information
exists); older containers; or those in more
demanding service. These higher priority containers may be targeted for inspection in the schedule before other
aboveground containers where the baseline information is known.
This section provides guidance on integrity testing for circumstances the EPA inspector may encounter
at an SPCC-regulated facility, i.e., aboveground bulk storage containers for which the baseline condition is
known and aboveground bulk storage containers for which the baseline condition is not known.
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7.4.1 Aboveground Bulk Storage Container for Which the Baseline Condition Is Known
In the case of tanks for which the baseline condition is known (e.g., the shell thickness and bottom
thickness), the inspection, evaluation and testing schedule should occur at a scope and frequency based on
industry standards (or a hybrid inspection program developed by a PE, as described in Section 7.5.3) per
§112.8(c)(6) or §112.12(c)(6). There is an advantage to knowing the baseline condition of a tank, particularly the
remaining wall thickness and bottom thickness. Only when the baseline is known can an inspection and testing
program be established on a regular schedule. The inspection interval should be identified consistent with
intervals specified in industry standards or should be based on the corrosion rate and expected remaining life of
the container. This inspection interval must be documented in the Plan in accordance with §§112. 3(d), 112. 7(e),
112.8(c)(6), and 112.12(c)(6). API 653 is an example of an industry standard that directs the owner/operator to
consider the remaining wall thickness and bottom thickness, and the established corrosion rates to determine
an inspection interval for external and internal inspections and testing. In the case of a tank that is newly built,
construction data (e.g., as-built drawings and/or manufacturers cut-sheets) may typically be used as an initial
datum to establish wall and bottom thicknesses, and would be included in the established procedures for
inspection and testing.
Inspection and testing standards may require visual inspection of both the exterior and interior of the
container, and the use of another method of non-destructive evaluation depending on the type and
configuration of the container. EPA inspectors should note that the scope and frequency of inspections and tests
for shop-built tanks and field-erected tanks at an SPCC-regulated facility may vary due to the age of the tank, the
configuration, and the applicable industry standard used as the reference. For example, the Plan preparer may
choose to develop an inspection and testing program for the facility's shop-built containers in accordance with
STI SP001, and may elect to develop a program for the facility's field-erected containers in accordance with API
653. As an alternative example, the Plan preparer may elect to develop a program in accordance with STI SP001
for both the facility's shop-built and field-erected containers, after determining that the containers are within
the scope of the standard.
7.4.2 Aboveground Bulk Storage Container for Which the Baseline Condition Is Not Known
For a facility to comply with the requirement for integrity testing of containers on a regular schedule
(§§112.8(c)(6) and 112.12(c)(6)), a baseline condition for each container is necessary to establish inspection
intervals. However, for shop-built and field-erected containers for which construction history and wall and/or
bottom plate thickness baselines are not known, it is not possible to establish a regular integrity testing program
at the time the Plan is prepared. In this case, the Plan preparer must describe in the SPCC Plan an interim
schedule (in accordance with the introductory paragraph of §112.7) that allows the facility to gather the
baseline data to establish a regular schedule of integrity testing in accordance with §§112.8(c)(6) and
When a container has no prior inspection history or baseline information, the implementation of the
baseline inspection program is important in order to assess the container's "suitability for continued service."
Both API 653 and STI SP001 contain minimum requirements to inspect aboveground containers and criteria to
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assess a container's suitability for continued service. In some cases, where baseline information is not known,
the testing program may include two data collection periods, one to establish a baseline of the container's
existing shell and bottom plate thickness, and a second inspection to establish corrosion rates in order to
develop the next inspection interval. These inspection intervals establish the frequency of the 'regular schedule'
required for testing under the SPCC rule.
When no or only partial baseline information is available for a container at the facility, then the
owner/operator should schedule integrity testing in accordance with industry standards as soon as possible and
in accordance with both good engineering practice and the judgment of the certifying PE.139 Because the SPCC
Plan must be reviewed at the facility every five years in accordance with §112.5(b), the owner or operator of the
facility should consider to begin collecting inspection data during the next five year period. As an example, a
facility owner/operator is scheduling upcoming inspections for bulk storage containers at a facility he recently
purchased. The owner/operator has no records of inspections or information on the in-service date (i.e. original
construction date) for a 10,000-gallon aboveground storage container at the facility. The SPCC Plan was last
amended on November 10, 2011. Therefore, in order to establish a baseline for the 10,000-gallon AST, the
facility owner schedules the first (baseline) container inspection or integrity test by November 10, 2016.
Example baselining plans are presented in Figure 7-1 and Figure 7-2. The examples present simple
scenarios and are only provided as an illustration of some of the factors that may be considered when
determining a schedule to initiate inspections of bulk storage containers.
If the owner or operator of a Tier II qualified facility is not familiar with inspection standards, then he should consult with a tank
inspection professional or PE to establish an inspection schedule.
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Chapter 7: Inspection, Evaluation, and Testing
Figure 7-1: Example baselining plan to determine the integrity testing and inspection schedule
API 653.
using
Scenario: A facility has three aboveground atmospheric, mild-carbon steel tanks of different ages and conditions. One
has a prior inspection history; the others have never been inspected. Although there is limited history available
regarding tank construction, the tanks are presumed to be field-erected tanks and to each have 100,000 gallons in
storage capacity. The SPCC Plan was amended on November 10, 2011 and API 653 is the referenced inspection
standard. What is an appropriate inspection schedule for these tanks?
Additional information: API 653 recommends a formal visual inspection* every 5 years or % of corrosion rate,
whichever is less, and a non-destructive shell test (UT) within 15 years or % of corrosion rate, whichever is less. If
corrosion rates are not known, the maximum interval for a UT inspection is 5 years. For internal inspection, the interval
from initial service to the initial inspection shall not exceed 10 years, or longer if certain tank safeguards are in place.
Subsequent internal inspection intervals are based on corrosion rate shall not exceed 20 years for tanks without a
release prevention barrier and 30 years for tanks with a release prevention barrier or at an inspection interval
determined using risk-based inspection assessment. If the construction date and date of last inspection are unknown,
the compliance date of the regulation should determine the starting point for an integrity testing schedule. The first
inspection must occur within 5 years of the compliance date or a lesser period of time as determined by a PE in cases
where there is higher risk.
Determination of inspection schedule:
Tankl
Tank 2
Tanks
Construction Date
unknown
2008
1984
Last External and
Internal Inspection
none
none
Last External:
Inspections
conducted in
1999,2004, and
2009
Last Internal:
1999
Next Inspection (External)
formal visual and shell test
(external) before
November 10, 2016
2013 for both visual inspection
and non-destructive shell test**
201 4 for formal visual**
2014 non-destructive shell test.
Both intervals may be
decreased based on calculated
corrosion rates from the 1999
inspection.
Next Inspection (Internal)
formal (internal) bottom
inspection before
November 10, 2016
2018 or longer if cathodic
protection or other safeguards
are in place
2029 if the tank has a release
prevention barrier, 2019 if the
tank does not have a release
prevention barrier or sooner
based on corrosion rates from
the 1999 inspection or as
determined from risk-based
inspection assessment
* A formal visual inspection is one conducted by a certified inspector.
** Inspection should be conducted as soon as possible and in consultation with a PE.
Note: Actual inspection schedule is ultimately an engineering determination made by the PE, based on industry
standards, and is certified in the Plan. Other events or factors that occur during the life of the container could cause the
owner/operator to revise the inspection interval originally calculated.
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Chapter 7: Inspection, Evaluation, and Testing
Figure 7-2: Example baselining plan to determine the integrity testing and inspection schedule using
STI SPOOL
Scenario: A facility has four aboveground atmospheric, mild-carbon steel tanks of different ages and conditions. One
has a prior inspection history; the others have never been inspected. The tanks are shop-fabricated. Tanks 1, 2 and 3
have 40,000 gallons in storage capacity and Tank 4 has 10,000 gallons in capacity. The SPCC Plan was amended on
November 10, 2011 and STI SP001 is the referenced inspection standard. What is an appropriate inspection schedule for
these tanks?
Additional information: Tanks 1, 2 and 3 are in Category 3 of STI SP001 (i.e., do not have spill control or a continuous
release detection method, or CRDM). In addition to periodic inspections recommended by the standard for all tanks, for
tanks in Category 3 STI SP001 recommends that a formal external inspection,* as well as a leak test by owner be
conducted at a maximum of 5-year intervals, and that a formal internal inspection* be conducted at 10-year intervals.
Tank 4 is in Category 1 of STISP001 (i.e., has spill control and CRDM). For this tank, STI SP001 recommends that a formal
external inspection be conducted by a certified inspector at a maximum of 20-year intervals. No formal internal
inspection or leak test is required.
If the construction date and date of last inspection are unknown, the compliance date of the regulation should
determine the starting point for an integrity testing schedule. The first inspection must occur within 5 years of the
compliance date or a lesser period of time as determined by a PE in cases where there is higher risk.
Determination of inspection schedule:
Tankl
Tank 2
Tanks
Tank 4
Construction Date
(in service date)
unknown
2004
1984
2002
Last External and
Internal Inspection
none
none
2005
none
Next Inspection (External)
Formal external inspection and
leak testing before
November 10, 2016
2009 for formal external
inspection and leak testing**
2010 for formal external
inspection and leak testing**
2022 for formal external
inspection
Next Inspection (Internal)
Formal internal inspection
before November 10, 2016
2014 for formal internal
inspection
2015 for formal internal
inspection*
Not required
* A formal inspection is one conducted by a certified inspector.
**lnspection should be conducted as soon as possible and in consultation with a PE.
Note: Actual inspection schedule is ultimately an engineering determination made by the PE, based on industry
standards, and is certified in the Plan. Other events or factors that occur during the life of the container could cause the
owner/operator to revise the inspection interval originally calculated.
7.5 Specific Circumstances
Integrity testing in accordance with industry standards is required for all aboveground bulk storage
containers located at onshore facilities (except oil production facilities), unless the facility owner/operator
implements an environmentally equivalent method according to §112.7(a)(2) and documents the deviation in
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ik~—-•—-—
the SPCC Plan (see Chapter 3: Environmental Equivalence). This section provides guidance on integrity testing for
the following circumstances that an EPA inspector may encounter at an SPCC-regulated facility:
• Integrity testing scenarios for shop-built containers; and
• Using environmentally equivalent alternatives for integrity testing.
This is not a comprehensive list of circumstances. For these and other cases, a PE may recommend
alternative approaches.
7.5.1 Integrity Testing Scenarios for Shop-built Containers
Scenario 1: Mobile or Portable Bulk Storage Containers
Industry standards (such as STI SPOOl) refer to specific conditions
for which visual inspection alone is an appropriate method for verifying the
integrity of certain smaller shop-built containers (e.g., portable containers
such as drums and totes). These conditions include container type, size, and
configuration (such as whether the container is in contact with the ground
or has appropriate secondary containment). For example, according to STI
SPOOl, when portable containers have adequate secondary containment then visual inspection of these
containers is acceptable and will satisfy the integrity testing requirements of the rule at §112.8(c)(6).
Scenario 2: Single-Use Mobile or Portable Containers.
For containers that are single-use and for dispensing only (i.e., the container is not refilled), industry
standards such as STI SPOOl may require only visual examination by the owner/operator. Since these containers
are single-use, other types of integrity testing such as internal or comparative integrity testing for corrosion are
generally not appropriate because the containers are not maintained on-site for a long enough period of time
that degradation and deterioration of the container's integrity might occur. Single-use containers (e.g., 55-gallon
drums) typically are returned to the vendor, recycled, or disposed of in accordance with applicable regulations.
Good engineering practices for single-use containers should be identified in the Plan, and these practices should
follow industry standards and ensure that the conditions of storage or use of a container do not subject it to
potential corrosion or other conditions that may compromise its integrity in its single-use lifetime.
Scenario 3: Elevated large shop-built containers.
The SPCC rule requires that inspections be in accordance with industry standards. Under certain
circumstances the standards may stipulate that visual inspection alone will suffice. However, for tanks larger
than 5,000 gallons, most industry standards require more than a visual inspection by the owner or operator.
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The previous version of this Guidance140 published in 2005 described an example considered
environmentally equivalent to the integrity testing requirements of the SPCC rule at that time. The example
described visual inspection plus certain additional actions to ensure the containment and detection of leaks as
appropriate for bulk oil storage containers with a capacity up to 30,000 gallons. This example was based on a
policy that described the environmental equivalence flexibility available
to a PE with respect to integrity testing in a letter to the Petroleum
Marketers Association of America (PMAA).141
Figure 7-3:
Shop-built containers
elevated on saddles.
This example was established at a time when the rule specifically
required that integrity testing include more than just a visual inspection.
While the approach for the use of environmental equivalence described
in this letter is still valid, EPA revised the integrity testing provision in
2008 to allow inspection requirements outlined in industry standards to
be used without the need for environmental equivalence determinations
certified by a PE. After EPA wrote the letter to PMAA in 2004, a major industry standard for integrity testing (STI
SP001) was modified to outline "good engineering practice" for integrity testing of shop-built containers. This
may affect a PE's decision whether to certify an environmentally equivalent approach as described in the PMAA
letter, or to follow an applicable industry standard without having to certify the measures described in the
PMAA letter as an environmentally equivalent method of integrity testing.
If an owner or operator deviates from applicable industry standards to develop an integrity testing
program, then a PE must certify an environmentally equivalent alternative in the SPCC Plan. The Plan must
provide the reason for the deviation, describe the alternative approach, and explain how it achieves
environmental protection equivalent to the applicable industry standard.
Scenario 4: Shop-built containers placed on a liner.
Certain industry standards, such as STI SP001, also specify differentiated inspection practices for certain
shop-built containers that are placed on a barrier or liner and where this barrier is designed in a way that
ensures that any leaks are immediately detected. The size of the container and other site-specific factors
determine appropriate inspection or testing procedures and frequencies.
Scenario 5: Double-walled tanks or containers
A double-walled tank is essentially a tank within another tank, equipped with an interstitial (i.e.,
annular) space and constructed in accordance with industry standards. The inner tank serves as the primary oil
storage container while the outer tank serves as secondary containment. The outer tank of a double-walled tank
140
141
SPCC Guidance for Regional Inspectors, Version 1.0, November 28, 2005.
Letter to Daniel Gilligan, President, Petroleum Marketers Association of America, from Marianne Lamont Horinko, Assistant
Administrator, Office of Solid Waste and Emergency Response, EPA, May 25, 2004 (available in Appendix H of this document).
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may provide adequate secondary containment for discharges resulting from leaks or ruptures of the entire
capacity of the inner storage tank.
Section 112.8(c)(6) requires the owner or operator to conduct integrity testing on a regular schedule and
whenever he makes repairs. One possible advantage of a double-walled shop fabricated aboveground tank is
that industry standards (such as STI SP001142) may specify a less stringent program for integrity testing during
the life of the container. However, note that industry standards may specify more stringent integrity testing
requirements for double-walled tanks not equipped with an interstitial space (e.g., formal non-destructive
testing).
Section 112.8(c)(6) also requires that the owner or operator frequently inspect the outside of the
container for signs of deterioration, discharges, or accumulation of oil inside diked areas (for a double-walled
tank, this inspection requirement applies to the inner tank). To comply with the requirement to frequently
inspect the outside of the tank, an owner or operator must inspect the interstitial spaces of a shop-built double-
wall AST. Typically this is accomplished by an inspection port (which can be visually inspected or used in
conjunction with a dip stick, camera, or visual leak indicator), a drain plug, sensors or other equivalent means to
detect a discharge into the interstitial (annular) space from the inner primary container. EPA recommends the
use of automatic detection devices to detect discharges into the interstitial space. Once a discharge is
discovered in the interstice, corrective action is typically required by industry standards. After a discharge to the
interstitial space has occurred, the system is no longer operating as a double-walled tank (because the external
tank is serving as the primary container unless and until appropriate repairs are made in accordance with the
applicable industry standard).
Owners or operators should conduct integrity testing and inspections in accordance with industry
standards, when applicable. One industry standard to consider is "SP001, Standard for Inspection of In-Service
Shop-Fabricated Aboveground Tanks for Storage of Combustible and Flammable Liquids."
For more information on secondary containment requirements for double-walled tanks see Chapter 4:
Secondary Containment and Impracticability, Section 4.4.5.
7.5.2 Integrity Testing and Inspection Requirements for Bulk Storage Containers at
Onshore Facilities - Environmental Equivalence
In December 2008, EPA amended the requirements at §§112.8(c)(6) and 112.12(c)(6) to provide
flexibility in complying with the bulk storage container integrity testing requirements. EPA modified the
provision to allow an owner or operator to consult and rely on industry standards to determine the appropriate
qualifications for personnel performing tests and inspections, as well as the type and frequency of integrity
testing required for a particular container size and configuration.
The integrity testing requirements are subject to the environmental equivalence provision, but given the
increased flexibility, there may be few, if any, instances where a PE would determine that a deviation is
SPOOl Standard for the Inspection of Aboveground Storage Tanks, 5* Edition, Issued September 2011.
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appropriate. This is because the rule allows inspection requirements outlined in industry standards to be used
without the need for environmental equivalence determinations certified by a PE (see 73 FR 74265, December 5,
2008).
As with other requirements eligible for environmental equivalence provision, a facility owner or
operator may not rely solely on measures that are required by other sections of the rule (e.g., secondary
containment) to provide "equivalent environmental protection" for integrity testing required under §112.8(c)(6)
or §112.12(c)(6). Otherwise, the deviation provision would allow for approaches that provide a lesser degree of
protection overall.
In any case where the owner or operator of a facility uses an alternative means of meeting the integrity
testing requirement of §112.8(c)(6) or §112.12(c)(6), the SPCC Plan must provide the reason for the deviation,
describe the alternative approach, which is most likely to be a site-specific inspection program (i.e., hybrid
inspection program), and explain how it achieves equivalent environmental protection (§112.7(a)(2)), while
considering good engineering practice and industry standards. In cases where industry standards apply to a
container, the PE would need to explain how an inspection or test that deviates from an applicable industry
standard is environmentally equivalent to following established industry standards and how it will be
implemented in the field. This determination is site-specific and based on good engineering practice as
determined by the certifying PE. The hybrid inspection program should include the recommended minimal
elements described in Section 7.5.3 for a PE-developed site-specific integrity testing program. Figure 7-4
provides a summary of integrity testing and inspection program documentation for bulk storage containers at
onshore facilities, by type of SPCC Plan and standard applicability case.
The following sections describe situations in which a hybrid inspection program is developed to comply
with the bulk storage container inspection requirements of §§112.8(c)(6) and 112.12(c)(6).
Hybrid Inspection Program Rather than an Applicable Industry Standard
Although the rule requires that the Plan preparer consider industry standards when developing an
inspection program, the SPCC Plan can include an environmentally equivalent (i.e., hybrid) inspection program
when the owner or operator and the certifying PE determine that another inspection approach would be more
appropriate or cost effective, based on site-specific factors. The SPCC Plan must include the reason for deviating
from the rule requirements, and describe the alternative method in detail, including how it is environmentally
equivalent.
An environmentally equivalent approach to following the applicable industry standard verbatim may be
a hybrid inspection program that is based on elements designed to minimize the risk of container failure and
allow detection of leaks before they impact navigable waters or adjoining shorelines. These elements may be
based on a combination of various industry standards and good engineering practice and should include the
recommended minimal elements described in Section 7.5.3 for a PE-developed site-specific integrity testing
program (or hybrid inspection program). Alternative measures may, for example, prevent container failure by
minimizing the container's exposure to conditions that promote corrosion (e.g., direct contact with soil), or they
may enable facility personnel to detect leaks and other container integrity problems early so these problems can
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be addressed before more severe integrity failure occurs. The ability to use an environmentally equivalent
alternative to integrity testing in accordance with an applicable industry standard may be influenced by the tank
configuration and adequacy of secondary containment. The facility owner/operator may determine that
alternatives to inspection frequency and type of testing and inspections may be more appropriate according to
site-specific conditions.
If a Tier II qualified facility owner or operator chooses to develop an alternative inspection program
rather than follow an applicable industry standard, then he must have a PE certify the environmentally
equivalent measures as described in §112.6(b)(4). A Tier I qualified facility owner or operator cannot deviate
from applicable industry standards when following the requirements for Tier I qualified facilities in §112.6(a).
Hybrid Inspection Program that Deviates from a Portion of an Industry Standard
It may be appropriate to deviate from portions of an industry standard under certain circumstances.
Although the Plan preparer must determine, in accordance with industry standards, the appropriate
qualifications for personnel performing tests and inspections, and the frequency and type of testing and
inspections when developing the inspection and/or testing program, the inspection program can deviate from a
portion of a standard when another approach would be more appropriate or cost effective, based on site-
specific factors. The SPCC Plan must document the environmentally equivalent alternative, the reason for
deviating from the rule requirement, and describe the alternative method in detail, including how it is
environmentally equivalent.143 The PE should document in the Plan what industry standard applies, how the
hybrid inspection program deviates from the applicable industry standard, and how the inspection program
meets the minimal recommended elements described in Section 7.5.3.
If a Tier II qualified facility owner or operator chooses to deviate from a portion of an applicable industry
standard, then he must have a PE certify the environmentally equivalent measures as described in §112.6(b)(4).
A Tier I qualified facility owner or operator cannot deviate from applicable industry standards when following
the requirements for Tier I qualified facilities in §112.6(a).
No Applicable Industry Standard - Hybrid Inspection Program Established X
Industry standards are often developed to address a particular industry sector or type of container or
equipment. The scope of a standard may limit how it should be applied by specifying the type of containers or
equipment, their service conditions, the specific gravity of stored products, or other factors. Two commonly
used steel tank inspection standards are STI SP001144 and API 653.14S The scope of these two standards
addresses many of the steel storage tanks in service at SPCC-regulated facilities and it is likely that one of these
inspection standards can be applied. However, if in the judgment of a PE or qualified facility owner/operator, no
industry standard applies to a particular container, then the Plan preparer should consider the manufacturer's
143
144
145
See 73 FR 74264 (December 5, 2008)
STI Standard SP-001, "Standard for the Inspection of Aboveground Storage Tanks," 5* Edition September 2011.
API Standard 653, "Tank Inspection, Repair, Alteration, and Reconstruction," Fourth Edition, American Petroleum Institute, April
2009 Addendum 2 January 2012.
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specifications and instructions for the proper use and maintenance of the equipment, appurtenance, or
container. If no industry standards or manufacturer's instructions apply, the Plan preparer may also call upon
his/her professional experience and/or consult with tank inspection professionals to develop site-specific
inspection and testing requirements for the facility or equipment that are in accordance with good engineering
practice and document them in the Plan.
A customized, site-specific inspection program (i.e., hybrid inspection program) should be based on
relevant industry standards (in whole or in part) and other good engineering principles. The hybrid inspection
program should be designed to measure the structural soundness of a container shell, bottom, and/or floor to
contain oil, and may include leak testing to determine whether the container will discharge oil. API 653 and STI
SP001 provide the foundation for integrity testing and inspecting containers, and in many cases it may still be
appropriate to consider these standards when developing a hybrid inspection program.
A PE does not need to provide and certify an environmental equivalence justification for implementing
a hybrid inspection program when industry standards do not apply to a container or the container is outside the
Tip - AFVO containers and tanks operated
at elevated temperatures
Although existing industry standards are not specific
to integrity testing of AFVO bulk storage containers
or tanks operated at elevated temperatures (e.g.
asphalt), facilities with these storage containers can
follow API Standard 653, 'Tank Inspection, Repair,
Alteration, and Reconstruction" because the scope is
written broadly to include any steel tank constructed
in accordance with a tank specification.
scope of the standard. However, the PE attests in the Plan
certification that required inspections and testing have
been established and that the Plan has been prepared in
accordance with good engineering practice, including
applicable industry standards. The PE should document in
the Plan why current industry standards do not apply and
how the hybrid inspection program meets the minimal
recommended elements described in Section 7.5.3.
The Plan must describe the procedures for this
inspection program and the facility owner or operator
must keep a record of inspections and tests for three
years. Industry standards often advise that records for formal inspections and tests be maintained for the life of
the container. These records can be helpful to inform changes in the inspection program.
It is unlikely that qualified facility owner/operators will have bulk storage containers for which no
industry standard applies. However, if a qualified facility owner or operator determines that no industry
standard applies, then he should follow the procedures described above to develop an inspection program for
bulk storage containers. No environmental equivalence determination is necessary in this case and a PE does not
need to certify the hybrid inspection program. However, a qualified facility owner/ operator who develops a
hybrid inspection program should consider consulting with a tank inspection professional or a PE. The qualified
facility owner/operator should also clearly explain why current industry standards do not apply and how the
hybrid inspection program meets the minimal recommended elements described in Section 7.5.3.
AFVO Bulk Storage Containers
The inspection and/or testing requirements for AFVO at §112.12(c)(6)(i) are identical to those described
at §112.8(c)(6). The SPCC rule also provides differentiated, more flexible, alternative inspection requirements at
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§112.12(c)(6)(ii) for AFVO containers that meet certain criteria (see Section 7.2.4). A facility owner/operator with
AFVO bulk storage containers may follow an applicable industry standard, such as API 653, to conduct
inspections in accordance with the requirements of §112.12(c)(6)(i), follow the requirements of §112.12(c)(6)(ii)
(if applicable), or provide an environmentally equivalent measure in the SPCC Plan in accordance with
§112.7(a)(2) of the SPCC rule.
The facility owner or operator has flexibility to make an environmental equivalence determination, in
accordance with §112.7(a)(2), to address those bulk storage containers that have alternative configurations and
meet the intent of the criteria in §112.12(c)(6)(ii) to minimize internal and external corrosion of the container
and allow personnel to visually identify a discharge. For example, the criteria in §112.12(c)(6)(ii) requires that
bulk storage containers be subject to 21 CFR part 110. However, bulk storage containers that store food oil and
are built according to industry standards (such as 3-A Sanitary Standards) may have additional design features
to minimize internal and external corrosion of the container and allow for visual detection of a discharge that
provide equivalent environmental protection to 21 CFR part 110. Container configurations built according to 3-A
Sanitary Standards typically include "manholes" that facilitate complete access for examination of the entire
internal surface. These containers also typically have an outer shell (i.e., a double wall) that is sealed completely
such as with completely welded seams so that the container integrity is maintained because insulation is less
likely to be exposed to moisture.
If a hybrid inspection program is used to meet the integrity testing requirements in §112.12(c)(6), the
Plan must state the reasons for nonconformance and explain how the hybrid inspection program provides
equivalent environmental protection. The Plan should also address how the program effectively minimizes the
risk of container failure and allows detection of leaks before they become significant.
A PE must review and certify the environmental equivalence determination. If a PE develops a hybrid
inspection program for a facility, rather than uses an applicable industry standard, then the PE must describe
why the hybrid inspection program does not follow the applicable industry consensus standard and how the
hybrid inspection program is environmentally equivalent to the industry standard and meets the minimal
recommended elements described in Section 7.5.3.
7.5.3 Suggested Minimum Elements for a PE-Developed Site-Specific Integrity Testing
Program (Hybrid Inspection Program)
Although EPA requires inspection, evaluation, and testing in accordance with industry standards, it does
not require that inspections and tests be performed according to a specific standard. Consistent with the
environmental equivalence provision in §112.7(a)(2), the PE may use industry standards along with other good
engineering practices to develop a customized inspection and testing program for the facility (a "hybrid"
inspection program), considering the equipment type and condition, characteristics of products stored and
handled at the facility, and other site-specific factors. The PE may also develop a hybrid program in the rare
cases where industry standards do not apply to a container. The hybrid program should be designed to measure
the structural soundness of a container shell, bottom, and/or floor to contain oil, and may include leak testing to
determine whether the container will discharge oil. The components of a hybrid inspection program would likely
include frequent visual inspections by the owner as well as periodic formal inspections (plus integrity testing, as
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appropriate) by a certified inspector. Alternatively, the PE can recommend an inspection program following a
specific standard, even when the standard does not specifically identify the container in its scope, if he believes
that the inspection elements of that standard are appropriate for the container(s) at the facility and in
accordance with good engineering practices.
Any hybrid inspection program should include an evaluation of the principal elements that would cause
a tank to fail, and how the inspection program addresses finding such conditions, or prevents such conditions
from continuing to the point of failure. For example, internal and external corrosion conditions must be
considered, and a testing method developed to assure that the condition is identified and measured. Conditions
that may lead to a structural failure, for example a failing foundation, should be identified and evaluation
methods developed to identify the condition. In all cases, careful consideration should be given to discovering
such conditions that may not be identifiable from visual examination, such as the bottom of floor plates. Hybrid
programs should also include evaluation of container modifications made since last examination that may
degrade integrity or lead to failure.
The following is a partial list of items to consider regarding the elements of a hybrid inspection program.
1) For shop-built tanks:
• Visually inspect exterior of tank;
• Evaluate external pitting;
• Evaluate hoop stress and longitudinal stress risks where corrosion of the shell is present;
• Evaluate condition and operation of appurtenances;
• Evaluate welds;
• Establish corrosion rates and determine the inspection interval and suitability for continued
service;
• Evaluate tank bottom where it is in contact with ground and no cathodic protection is provided;
• Evaluate the structural integrity of the foundation;
• Evaluate anchor bolts in areas where required; and
• Evaluate the tank to determine whether it is hydraulically sound and not leaking.
2) For field-erected tanks:
• Evaluate foundation;
• Evaluate settlement;
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• Determine safe product fill height;
• Determine shell corrosion rate and remaining life;
• Determine bottom corrosion rate and remaining life;
• Determine the inspection interval and suitability for continued service;
• Evaluate welds;
• Evaluate coatings and linings;
• Evaluate repairs for risk of brittle fracture; and
• Evaluate the tank to determine whether it is hydraulically sound and not leaking.
EPA suggests that an appropriately trained and qualified inspector conduct a hybrid inspection and
provide a detailed report of the findings. The qualifications of the tank inspector will depend on the condition
and circumstances of the tank (e.g., size, field-erected or shop-built), and a tank inspector should only conduct
an inspection to the extent he/she is qualified to do so. A registered PE may be able to perform the hybrid
inspection or could have a certified tank inspector (e.g., STI or API) complete the inspection.146 Either way, the
hybrid inspection program should be reviewed and certified by a PE in accordance with §112.3(d) (or
§112.6(b)(4) for Tier II qualified facilities).
EPA inspectors may review checklists that are used by facility personnel to conduct the frequent
inspections. Table 7-4 provides an example of the type of information that may be included on an
owner/operator-performed inspection checklist.
Note that industry inspection standards require the inspector's certification number on these reports.
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Table 7-4: Owner/Operator tank inspection checklist (from Appendix F of 40 CFR part 112).
1.
II.
III.
Check tanks for leaks, specifically looking for:
A.
B.
C.
D.
E.
F.
Drip marks;
Discoloration of tanks;
Puddles containing spilled or leaked material;
Corrosion;
Cracks; and
Localized dead vegetation.
Check foundation for:
A.
B.
C.
D.
E.
F.
Cracks;
Discoloration;
Puddles containing spilled or leaked material;
Settling;
Gaps between tank and foundation; and
Damage caused by vegetation roots.
Check piping for:
A.
B.
C.
D.
E.
F.
Droplets of stored material;
Discoloration;
Corrosion;
Bowing of pipe between supports;
Evidence of stored material seepage from valves or seals; and
Localized dead vegetation.
7.6 Documentation Requirements and Role of the EPA Inspector
When evaluating the SPCC Plan the EPA inspector will need to review the scope of the inspection
program identified in the Plan and determine whether the facility owner/operator is implementing the program
as described. Additionally, if there have been any changes or alterations to bulk storage containers at the
facility, the EPA inspector will need to identify whether those alterations were performed in accordance with
industry standards and whether additional evaluations were conducted and documented.
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7.6.1 Evaluating Tank Re-Rating Alterations
Chapter 2: SPCC Rule Applicability, Section 2.7.3 describes how to calculate the storage capacity for bulk
storage containers and discusses appropriate methods for altering the capacity of a bulk storage container (i.e.,
tank re-rating). Re-rating a tank's storage capacity is permitted when the alteration is completed in accordance
with applicable industry standards and good engineering practice. As discussed in Chapter 2: SPCC Rule
Applicability, Section 2.7.3, any container alteration will require a technical amendment to the SPCC Plan
certified by a PE in accordance with §112.5. Additionally, tank alterations which change the original shell
capacity may affect secondary containment capacity necessary to comply with SPCC requirements and FRP
applicability and requirements under 40 CFR part 112 subpart D. Any subsequent changes to the shell capacity
(e.g., to increase capacity) will require a re-assessment of SPCC compliance and FRP applicability.
Since this type of alteration may have a significant impact on secondary containment capacity,
compliance with SPCC rule requirements, and FRP applicability, the EPA inspector must carefully review these
alterations. This review should consider relevant SPCC requirements and Plan documentation, industry
standards, records, and field observations as described below.
Relevant SPCC Requirements and Plan Documentation:
The EPA inspector should consider the following questions when evaluating whether the SPCC Plan
appropriately addresses tank alterations completed at the facility:
• Do all relevant sections of the SPCC Plan reflect the current container capacity and was the
technical amendment to the Plan documented and certified by a PE?
The certifying PE must sign an amendment to the SPCC Plan. As part of this certification,
the PE verifies that the modifications to the tank (e.g., installation of overflow ports or
new tank bottom) were done in accordance with industry standards and identifies the
standard used (e.g., API 653).
• Have operating procedures that may be affected by the alteration been updated in the Plan to
reflect the current tank capacity?
• If the alteration includes an overflow nozzle and the associated overflow pipe is equipped with a
valve,147 does the Plan clearly explain the purpose of the valve and identify the reasons the valve
may be closed, including any implications for 40 CFR part 112 requirements when the valve is
closed and the capacity of the tank reverts to a larger capacity? Each time the valve is closed,
was a technical amendment of the SPCC Plan completed to address:
Revised tank capacity;
Adequacy of secondary containment capacity; and
A valve is not recommended unless otherwise required by code.
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Updates to tank transfer procedures (to identify change in maximum capacity of the tank),
facility diagram, tank information and any other relevant SPCC requirements.
• Additionally, has the facility owner/operator determined FRP applicability based on tank
capacity when the valve is both open and closed? If the facility is FRP-subject when the valve is
closed then was an FRP submitted to the EPA regional office?
Relevant Industry Standards:
API Standard 650, Welded Tanks for Oil Storage,™s and API Standard 653, Tank Inspection, Repair,
Alteration, and Reconstruction,149 include specifications for tank construction and inspections (respectively) that
are relevant when re-rating a tank. When evaluating a tank that has been re-rated to a lower storage capacity,
the EPA inspector should verify that the documentation of the tank alterations describe conformance with
industry standards, which stipulate the following:150
API 650 Specifications:
• When emergency overflow slots are used, the overflow slots are covered with a corrosion-
resistant coarse-mesh screen and provided with weather shields (the closed area of the screen
must be deducted to determine the net open area).
• The overflow slots are sized to discharge at the pump-in rates for the tank. Overflow discharge
rates were determined by using the net open area (less screen) and using a product level (for
determining head pressure) not exceeding the top of the overflow opening.
• The floating-roof seal does not interfere with the operation of the emergency overflow
openings.
• Overflow slots are not placed over the stairway or nozzles unless restricted by tank
diameter/height or unless overflow piping, collection headers, or troughs are specified by the
Purchaser [e.g., facility owner/operator] to divert flow.
API 653 Specifications:
API 653 provides requirements on installing new penetrations (such as a nozzle) in existing tanks. The
standard requires:
API Standard 650, "Welded Tanks for Oil Storage," Eleventh Edition, American Petroleum Institute, June 2007 Addendum 3
August 2011, Errata, October 2011.
API Standard 653, "Tank Inspection, Repair, Alteration, and Reconstruction," Fourth Edition, American Petroleum Institute, April
2009 Addendum 2 January 2012.
Please note that these are summaries. EPA inspectors should refer to the full text of the relevant industry standards when
conducting an evaluation of a tank alteration.
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• All design, work execution, materials, welding procedures, examination, and testing methods be
approved by the authorized inspector or by an engineer experienced in storage tank design.
• New shell penetrations (i.e. nozzles) be in accordance with material, design, and stress relief
requirements of API 650, and in accordance with relevant portions of API 653.
• Proper spacing of welds.
• Examinations be performed in accordance with the standard:
Penetrations (i.e. nozzles) located on a shell joint must receive additional shell
radiography in accordance with API 650.
— Nozzle neck to shell welds and reinforcing plate to shell and nozzle neck welds must be
examined by magnetic particle or liquid penetrant examination.
• When penetrations are installed using insert plates as described in the standard, the completed
butt welds between the insert plate and the shell plate must be fully radiographed.
• If the shell course where the nozzle is installed is thicker than VT. inch and shell material does not
meet current API 650 and API 653 design metal temperature the overflow nozzle must be
installed with an insert plate.
Records:
When an EPA inspector is evaluating a tank that has been re-rated to a lower storage capacity, the EPA
inspector should request/review the following records:
• Documentation from a PE that the overflow port is sized based on filling the tank (i.e., fill rate)
without substantially increasing the liquid level above the bottom of the overflow opening and is
in accordance with API 653;
• Documentation in the owner/operator records on what modifications were made and when,
and the maximum liquid level;
• Records that the overflow was inspected by an API 653 certified inspector or reviewed by a tank
engineer;
• Documentation on materials, welding procedure, examinations, and testing methods; and
• Records required by the standards. API 653 requires that records of alterations be kept on file.
When a tank is evaluated, repaired, altered, or reconstructed the following documentation is
maintained in the owner/operators' tank records:
Calculations on the following:
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Chapter 7: Inspection, Evaluation, and Testing
- Evaluation of the component for integrity, including brittle fracture considerations;
- Re-rating (including liquid level); and
- Repair and alteration considerations.
Supporting Data (as applicable):
- Inspections;
- Material test report/certifications;
- Tests;
- Radiographs;
- Brittle fracture considerations; and
- Construction completion record.
EPA Inspector Field Observations:
When an EPA inspector is evaluating a tank in the field that has been re-rated to a lower storage
capacity, the EPA inspector should look for the following:
• Is the overflow port away from shell welds? When the shell plate, where the nozzle is located, is
less than or equal to VT. inch thick, the required spacing is 6 inches from vertical welds and
3 inches from horizontal welds. Other spacing is required for thicker shell plates.
• If the overflow port is a nozzle, the nozzle must have a reinforcing plate or be installed with a
thickened insert plate.
• If the overflow nozzle has an overflow pipe, check that it is supported from the shell.
• Check to see if the overflow port's circumference appears proportional to the circumference of
the piping supplying the tank with product.
• Does there appear to be a blank flange (skillet) installed between the nozzle and the overflow
pipe or any flange along the overflow pipe? This could be difficult to view from ground level, but
if a gap exists between the nozzle flange and the overflow pipe fitting or between two flanges
along the piping, ask the owner/operator if the alteration has been modified.
The tank may have a new nameplate indicating what modifications were made, the date, and the
maximum liquid level. NOTE: API 653 Section 13 covers requirements for nameplates for reconstructed tanks
and tanks without nameplates, but does not specifically require the owner/operator to install a new nameplate
for altered tanks.
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7.6.2 Evaluating Inspection, Evaluation and Testing Programs
The facility SPCC Plan must describe the scope and schedule of testing and examinations to be
performed on bulk storage containers (as required in §§112.3(d)(l)(iv), 112.7(e), 112.8(c)(6), 112.9(c)(3), and
112.12(c)(6)), and should reference an applicable industry inspection standard or describe an equivalent
program (i.e., hybrid inspection program) developed by the PE, in accordance with good engineering practice. If
an SPCC Plan specifies a hybrid inspection and testing program, then the EPA inspector should verify that the
testing program covers minimum recommended elements for the inspections, the frequency of inspections, and
their scope (e.g., wall thickness, footings, tank supports). In cases where the hybrid inspection and testing
program is used in lieu of applicable industry standards, the EPA inspector should verify that the Plan includes an
environmental equivalence determination, certified by a PE. See Section 7.5.3 for a list of recommended
minimum elements.
If an owner or operator has yet to implement the integrity testing program, the SPCC Plan should
establish and document a schedule (in accordance with good engineering practice and the introductory
paragraph of §112.7) that describes the projected implementation of the integrity testing program for the
aboveground bulk storage containers at the facility. The EPA inspector should pay close attention to the
scheduling of integrity testing to ensure that the facility is implementing any schedule associated with §112.7.
The EPA inspector should also review the rationale for any inspection schedule that extends beyond the
frequency identified in applicable inspection standards (particularly if no baseline exists for the tanks).
A hybrid testing program may be appropriate for a facility where an industry inspection standard does
not yet contain enough specificity for a facility's particular tank(s) and/or configuration, or while modifications
to an existing industry inspection standard are under consideration. For example, a tank user may have made a
request to the industry standard-setting organizations recommending a change or modification to a standard.
Both API and STI have mechanisms to allow tank users (and the regulatory community) to request changes to
their respective inspection standards. In this case, the modification to a standard may be proposed, but not yet
accepted by the standard-setting organization. In the meantime, the facility is still subject to the SPCC
requirements to develop an inspection and testing program in accordance with industry standards. In this
scenario, a hybrid inspection and testing program may be appropriate. When reviewing the scope and schedule
of a hybrid program, the EPA inspector should ensure that a PE has attested that the program has been
developed in accordance with good engineering practice and is being implemented at the facility.
The owner or operator of the facility must maintain records of all visual inspections and integrity testing,
as required by the SPCC rule in §112.7(e). The owner or operator must keep written procedures and a record of
the inspections and tests, signed by the appropriate supervisor or inspector, with the SPCC Plan for a period of
three years.151 Records do not need to be specifically created for this purpose, and may follow the format of
records kept under usual and customary business practices, including electronic records. For example, it may be
usual and customary to keep inspection records for a drum storage area rather than for each individual drum.
These records should cover the frequent inspections performed by facility personnel. Also, industry standards
Facility Response Plan holders are required to maintain inspection records for five years.
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generally provide example guidelines for formal tank inspections, as well as sample checklists. The EPA inspector
should review the inspection checklists used by the facility to verify that they are in accordance with the
inspection and testing program as certified in the SPCC Plan. The tank inspection checklist from Appendix F of 40
CFR part 112, reproduced as Table 7-4 in this chapter, provides an example of the type of information that may
be included on an owner/operator-performed inspection checklist. Industry standards, such as STI SP001, also
provide example inspection checklists.
The EPA inspector should review the description of the integrity testing/inspection program in the SPCC
Plan and determine whether it follows an industry standard; deviates from applicable standards; or indicates
that no industry standard applies to certain containers. If the program follows an industry standard, the EPA
inspector should review the program to verify that it follows the applicable elements of the standard. If an
inspection program deviates from industry standards, or the SPCC Plan indicates that no industry standard
applies to a particular container, the EPA inspector should review the rationale described in the SPCC Plan and
check that the alternative inspection program addresses the recommended minimal elements of a hybrid
inspection program described in Section 7.5.3.
If an SPCC Plan contains measures that deviate from an applicable industry standard, based on
environmental equivalence, then the EPA inspector should look for a clear rationale for the development of the
inspection and testing program, paying close attention to the referenced industry standard. The Plan should
address how the alternative approach complies or deviates from industry inspection standards and how it will
be implemented in the field.
Figure 7-4 summarizes the type of documentation the EPA inspector should look for when reviewing the
use of industry standards to meet SPCC integrity testing and inspection requirements for different types of SPCC
Plan and industry standard applicability cases.
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Figure 7-4: Summary of integrity testing and inspection program documentation for bulk storage containers
at onshore facilities, by type of SPCC Plan and standard applicability case. X
PE-Certified
Plan Facility
Tier II Qualified
Facility Plan
Tier I Qualified
Facility Plan
Industry standard
applies to containers
Industry standards do ,
not apply to containers i
(Expected to be
very rare
circumstances) i
Industry standard
applies to containers
Industry standards do ,
not apply to containers i
(Expected to be
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Industry standard
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comply with the SPCC requirements
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Plan describes the hybrid program
Plan provides justification for hybrid program
based on environmental equivalence (EE)
Plan describes how and why the program
deviates from applicable industry standards
PE certified the EE measures and Plan
i • Plan describes the hybrid program*
!• Plan discusses why no standard applies**
• (no EE justification required)
i» PE certified the Plan
• Plan provides reference to standard used to
comply with the SPCC requirement.
• Owner/operator certified the Plan
Plan describes the hybrid program
Plan provides justification for hybrid program
based on environmental equivalence (EE)
Plan describes how and why the program
deviates from applicable industry standards
Owner/operator certified the Plan
PE certified the EE measures
Plan describes the hybrid program*
Plan discusses why no standard applies**
(no EE justification required)
Owner/operator certified the Plan
• Plan provides reference to standard used to
comply with the SPCC requirements
• Owner/operator certified the Plan
* Plan describes how the hybrid inspection program meets the minimal recommended elements described in Section 7.5.3.
** EPA Inspector should review carefully to confirm that industry standards do not apply
The EPA inspector should also review records of frequent visual inspections by facility personnel as well
as records of regular integrity testing of the container. Both API 653 and STI SP001 contain details on
determining a container's suitability for continued service; the maintenance of comparison records at the facility
aid in making this determination. Though §112.7(e) requires retention of all records for a period of three years,
industry standards often advise that certified inspection and non-destructive examination reports be maintained
for the life of the container.
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In cases where the SPCC Plan has not identified a regularly scheduled inspection and testing program,
the EPA inspector should request information on the anticipated schedule (e.g., when a baseline has not been
established). If the facility has not performed any formal inspections or integrity testing of bulk storage
containers so far, the EPA inspector should verify that the SPCC Plan describes: (1) the strategy for implementing
an inspection and testing program and collecting baseline conditions within ten years of the installation date of
the tank, or during the first five-year Plan cycle (or another schedule as identified and certified by a PE); and (2)
the ongoing testing program that will be established once the baseline information has been collected (including
the applicable industry standard that serves as the basis for the program). When the inspection program
establishes inspection priorities for multiple containers, the EPA inspector should consider the rationale for
these priorities as described in the SPCC Plan and verify implementation.
The EPA inspector should review records of regular and periodic inspections and tests of buried and
aboveground piping, valves, and appurtenances. As described throughout this section, such inspections may be
visual or involve other methods.
At oil production facilities, the EPA inspector should review records for inspections of bulk storage
containers (including flow-through process vessels and produced water containers), piping associated with
transfer operations, and flowlines or intra-facility gathering lines. When reviewing a maintenance program, such
as the flowline maintenance program required under §112.9(d)(4) for oil production facilities, the EPA inspector
should verify that the Plan describes how the flowlines are configured, monitored, and maintained to prevent
discharges and whether the frequency and type of testing will allow for the implementation of a contingency
plan when secondary containment is not provided for these lines (in accordance with §112.9(d)(3)). The EPA
inspector should also verify that the program is implemented in the field; this can be done, for example, by
verifying that facility personnel responsible for the maintenance of the equipment are aware of the flowline
locations and are familiar with maintenance procedures, including replacement of damaged and/or leaking
flowlines.
In summary, the EPA inspector should verify that the owner or operator has reports that document the
implementation of the testing, evaluation, or inspection criteria set forth in the Plan. As applicable, the EPA
inspector should also verify that the recommended actions that affect the potential for a discharge have been
taken to ensure the integrity of the container/piping until the next scheduled inspection or replacement of the
container/piping. Specifically, if the tank integrity evaluation/testing report recommends and/or requires repairs
then the EPA inspector should request documentation that confirms that the repair was completed or identifies
the rationale why the particular repair was not performed. When an inspection procedure is outlined in the Plan
that does not meet the specific SPCC requirement, the EPA inspector should verify that the Plan includes a
discussion of an environmentally equivalent measure in accordance with §112.7(a)(2). Implementation of the
SPCC Plan as certified by the PE is the responsibility of the facility owner/operator (§112.3(d)(2)).
By certifying an SPCC Plan, the PE attests that the Plan has been prepared in accordance with good
engineering practice, that it meets the requirements of 40 CFR part 112, and that it is adequate for the facility.
Thus, if testing, evaluation, or inspection procedures have been reviewed by the certifying PE and are properly
documented, they should generally be considered acceptable by the EPA inspector. However, if testing,
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evaluation, or inspection procedures appear to be at odds with recognized industry standards with no rationale
provided, do not meet the overall objective of oil spill response/prevention, or appear to be inadequate for the
facility, appropriate follow-up action may be warranted. In this case, the EPA inspector should clearly document
any concerns to assist review and follow-up by the Regional Administrator, where necessary. The EPA inspector
may also request additional information from the facility owner or operator regarding the testing, evaluation, or
inspection procedures provided in the Plan.
7.7 Summary of Industry Standards
and Regulations
v> FYI - Industry standard scope
The scope of a standard will describe the type of
tanks that are subject to the standard.
For example, API Standard 653, 'Tank Inspection,
Repair, Alteration, and Reconstruction," applies to
tanks built to API 650 and API 12C specifications.
API 12R1, "Recommended Practice for Setting,
Maintenance, Inspection, Operation, and Repair of
Tanks in Production Service," pertains to tanks
employed in production service or other similar
service.
Industry standards are technical guidelines
created by experts in a particular industry for use
throughout that industry. These guidelines assist in
establishing common levels of safety and common
practices for manufacture, maintenance, and repair.
Standards-developing organizations use a consensus
process to establish the minimum accepted industry
practice. The SPCC rule (§112.3(d)(l)(iii)) requires that a PE
attest that the Plan is prepared in accordance with good
engineering practices, including the consideration of applicable industry standards. Similarly, §112.6(a)(l)(iii)
and §112.6(b)(l)(iii) require that the owner or operator of a qualified facility certify that the Plan is prepared in
accordance with accepted and sound industry practices and standards. Standards play a role in determining
good engineering practice when developing spill prevention procedures and an inspection program for an SPCC-
regulated facility.
Implementing the inspection program based on a particular industry standard is ultimately up to the
owner/operator. When an owner/operator indicates in the SPCC Plan that he intends to use a standard to
comply with a particular rule requirement (e.g., integrity testing), then it is mandatory to implement the
relevant portions of the standard (i.e., those that address integrity testing of the container). It is important to
note that the principles on which industry consensus standards are based may have broad application with
regard to meeting the SPCC rule's performance-based requirement for integrity testing bulk storage containers.
In the unlikely situation where the scope of available inspection standards does not include a particular tank, the
inspection protocols outlined in the standards may serve as a guide for developing a hybrid inspection program.
Although these guidelines are often grouped together under the term "standards," several other terms
are used to differentiate among the types of guidelines:
• Standard (or code)—set of instructions or guidelines. Use of a particular standard is voluntary.
Some groups draw a distinction between a standard and a code. The American Society of
Mechanical Engineers (ASME), for example, stipulates that a code is a standard that "has been
adopted by one or more governmental bodies and has the force of law..."
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• Recommended practice—advisory document often useful for a particular situation.
• Specification—may be one element of a code or standard or may be used interchangeably with
these terms.
This section provides an overview and description of the scope and key elements of pertinent industry
inspection standards, including references to relevant sections of the standards. In each case, the purpose is to
allow EPA inspectors to be familiar with the general scope and requirements. However, industry standards may
be developed or revised over time. For more detailed and complete information, EPA inspectors should review
the text of the actual standards. This Chapter reflects the content of the standards at the time EPA revised this
Guidance. When words such as "must," "required," and "necessary," or other such terms are used in this
section, they are used in describing what the various standards specify and are not considered requirements
imposed by EPA, unless otherwise stated in the regulations.
Table 7-5 summarizes the facility components covered by selected industry standards and
recommended practices for tanks, valves, pipes, and appurtenances that are discussed in this section. Additional
standards and/or equipment manufacturers' standards may also apply.
Table 7-5: Summary of facility components covered in industry standards for inspection, evaluation, and
testing.
Facility Component(s) Covered in Standard or
Recommended Practice
New equipment
Equipment that has been in service
Shop-built AST
Field-erected AST
Fiberglass Reinforced Plastic tanks
Container supports or foundation
Diked area
Aboveground valves, piping, and appurtenances
Underground piping
Offshore valves, piping, and appurtenances
Potentially Relevant Standards and Recommended Practices
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The standards that facility personnel must use for inspecting and testing at a particular facility would be
specified in the SPCC Plan by the Plan preparer. If the PE requires the use of a specific standard for
implementation of the Plan, the owner or operator must also reference that standard in the Plan (67 FR 47057,
July 17, 2002). All actions (e.g., visual inspection or testing) performed by facility personnel must be
appropriately documented and maintained in permanent facility records as per §112.7(e). Note, however, that
certain industry standards may specify that an owner or operator maintain records for longer than three years,
in which case the owner or operator should keep comparison records of integrity inspections and tests as
directed in the standard in order to identify changing conditions of the oil storage container. Records of
inspections and tests kept under usual and customary business practices satisfy the recordkeeping
requirements.
In a case where the PE determines that industry inspection standards may not be appropriate in their
entirety for a facility's particular tanks and configuration, this section discusses the minimum recommended
elements for a hybrid inspection program.
7.7.1 API Standard 653 - Tank Inspection, Repair, Alteration, and Reconstruction
API Standard 653 -Tank Inspection, Repair, Alteration, and Reconstruction (API 653)152 provides the
minimum requirements for maintaining the integrity of carbon and alloy steel tanks built to API Standard 650
(Welded Steel Tanks for Oil Storage) and its predecessor, API 12C (Welded Oil Storage Tanks). API 653 may also
be used for any steel tank constructed to a tank specification.153
API 653 covers the maintenance, inspection, repair, alteration, relocation, and reconstruction of welded
or riveted, non-refrigerated, atmospheric pressure, aboveground, field-fabricated, vertical storage tanks after
they have been placed in service. The standard limits its scope to the tank foundation, bottom, shell, structure,
roof, attached appurtenances, and nozzles to the face of the first flange, first threaded joint, or first welded-end
connection. The standard is intended for use by those facilities that utilize engineering and inspection personnel
technically trained and experienced in tank design, fabrication, repair, construction, and inspection. Section 1 of
the standard introduces the standard and details its scope. Sections 2 and 3 of the standard list the works cited
and definitions used in the standard, respectively.
The standard requires that a tank evaluation be conducted when tank inspection results reveal a change
in a tank from its original physical condition. Sections 4 and 5 of the standard describe procedures for evaluating
an existing tank's suitability for continued operation or a change of service; for making decisions about repairs
or alterations; or when considering dismantling, relocating, or reconstructing an existing tank. Section 4 of the
standard details the procedures to follow in evaluating the roof, shell, bottom, and foundation of the tank.
Section 5 of the standard provides a decision tree to evaluate a tank's risk of brittle fracture.
API Standard 653, "Tank Inspection, Repair, Alteration, and Reconstruction," Fourth Edition, American Petroleum Institute, April
2009 Addendum 2 January 2012.
See Section 1.1.3 of API Standard 653.
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Section 6 of the standard focuses on factors to consider when establishing inspection intervals and
covers detailed procedures for performing external and internal tank integrity inspections. Inspection intervals
are largely dependent upon a tank's service history. The standard establishes time intervals for when routine in-
service inspections of the tank exterior are to be conducted by the owner/operator and when external visual
inspections are to be conducted by an authorized inspector. External ultrasonic thickness (UT) inspections may
also be conducted periodically to measure the thickness of the shell and are used to determine the rate of
corrosion. Time intervals for external UT inspections are also provided and are based on whether the corrosion
rate is known.
Internal inspections (Section 6.4 of the standard) primarily focus on measuring the thickness of the tank
bottom and assessing its integrity. Measured or anticipated corrosion rates of the tank bottom can be used to
establish internal inspection intervals; however, the inspection interval cannot exceed 30 years using these
criteria if the tank has a release prevention barrier and 20 years if the tank does not have a release prevention
barrier. Alternatively, risk-based inspection (RBI) procedures, which focus attention specifically on the
equipment and associated deterioration mechanisms presenting the most risk to the facility (Section 6.4.2.4 of
the standard), can be used to establish internal inspection intervals; an RBI may increase or decrease the
inspection interval. API 653 states that an RBI assessment shall be reviewed and approved by an authorized tank
inspector and a tank design/corrosion engineer. If a facility chooses to use RBI in the development of a tank
integrity testing program, the EPA inspector should verify that these parties conducted the initial RBI
assessment.
An external inspection (Section 6.5 of the standard) can be used in place of an internal inspection to
determine the bottom plate thickness in cases where the external tank bottom is accessible due to construction,
size, or other aspects. If chosen, this option should be documented and included as part of the tank's permanent
record. Owners/operators should maintain records that detail construction, inspection history, and
repair/alteration history for the tank (Section 6.8 of the standard). Section 6.9 of the standard stipulates that
detailed reports should be filed for every inspection performed.
Sections 7 through 11 of API 653 do not address integrity testing, but instead focus on the repair,
alteration, and reconstruction of tanks. Section 12 provides specific criteria for examining and testing repairs
made to tanks. Section 13 addresses the specific requirements for recording any evaluations, repairs,
alterations, or reconstructions that have been performed on a tank in accordance with this standard.
Several annexes provide additional information:
• Annex A to API 653 provides background information on previously published editions of API
welded steel storage tank standards.
• Annex B details the approaches that are used to monitor and evaluate the settlement of a tank
bottom.
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• Annex C provides sample checklists that the owner/operator can use when developing
inspection intervals and specific procedures for internal and external inspections of both in-
service and out-of-service tanks.
• Annex D focuses on the requirements for authorized inspector certification. Certification of
authorized tank inspectors, which is valid for three years from the date of issue, requires the
successful completion of an examination, as well as a combination of education and experience.
• Annex E has been removed, and is purposefully left blank.
• Annex F summarizes the non-destructive examination (NDE) requirements for reconstructed
and repaired tanks.
• Annex G discusses the qualification of tank bottom examination procedures and personnel.
• Annex H provides guidance for performing a similar service assessment to establish inspection
intervals for tanks for which corrosion rates have not been directly measured.
• Annex S covers the requirements for austenitic stainless steel storage tanks, constructed in
accordance with API 650, Appendix S, that differ from the basic rules in the rest of API 653.
Technical inquiries regarding the use of the standard can be made through API's Web site
(www.api.org).
7.7.2 STI Standard SP001 - Standard for the Inspection of Aboveground Storage Tanks
STI Standard SP001 - Standard for the Inspection of Aboveground Storage Tanks (STI SP001)154 provides
inspection and evaluation criteria to determine the suitability for continued service of aboveground storage
tanks until the next scheduled inspection. STI SP001 applies to the inspection of aboveground storage tanks,
including shop-fabricated tanks, field-erected tanks, and portable containers, as defined in the standard, as well
as their containment systems. The inspection and testing requirements for field-erected tanks are covered
separately in Appendix B of the standard. Specifically, the standard applies to ASTs storing stable, flammable,
and combustible liquids at atmospheric pressure with a specific gravity less than approximately 1.0, and those
storing liquids with operating temperatures between ambient temperature and 200 degrees Fahrenheit
(93.3°C).155 At a minimum, the following tank components shall be inspected (as applicable): primary and
secondary tanks, supports, anchors, foundation and external supports, gauges and alarms, insulation,
appurtenances, normal and emergency vents, release prevention barriers, and spill control systems.
After providing general information and definitions, Section 3 of the standard addresses safety
considerations, and Section 4 addresses AST inspector qualifications.
STI Standard SP-001, "Standard for the Inspection of Aboveground Storage Tanks," 5 Edition September 2011.
Given this operating range, the standard may not apply to certain tanks such as those containing asphalt cement.
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Section 5 of the standard addresses the criteria, including AST type, size, type of installation, corrosion
rate, and previous inspection history, if any, that should be used to develop a schedule of inspections for each
AST.
A Table of Inspection Schedules (Table 5.5) places tanks into one of three categories and establishes
different requirements regarding the type and frequency of periodic inspection by tank owner/operators as well
as formal external and internal inspections by a certified inspector. The factors used for categorizing tanks
include:
• Tank size,
• Whether the tank is in contact with the ground,
• The presence or absence of secondary containment or spill control, and
• The presence or absence of a continuous release detection method (CRDM).
Section 6 of the standard provides guidelines for the periodic inspections conducted by the owner or
his/her designee. The owner's inspector is to complete an AST Record for each AST or tank site, as well as a
Monthly Inspection Checklist and an Annual Inspection Checklist. Monthly inspections should monitor water
accumulation to prevent Microbial Influenced Corrosion (MIC), and action should be taken if MIC is found.
Additional requirements for field-erected tanks are in Appendix B of STI SPOOL
Section 7 of the standard contains the minimum inspection requirements for formal external
inspections, which are to be performed by a certified inspector. Inspections should cover the AST foundations,
supports, secondary containment, drain valves, ancillary equipment, piping, vents, gauges, grounding system (if
any), stairways, and coatings on the AST. Original shell thickness should be determined using one of several
suggested methods. Ultrasonic Thickness Testing (UTT) readings are to be taken at different locations of the AST
depending upon whether the AST is horizontal, vertical, rectangular, and/or insulated. The final report should
include field data, measurements, pictures, drawings, tables, and an inspection summary, and should specify the
next scheduled inspection.
Section 8 of the standard details the minimum inspection requirements for formal internal inspections,
which are to be performed by a certified inspector. A formal internal inspection includes the requirements of an
external inspection with some additional requirements for specific situations that are outlined in the standard.
Double-wall tanks and secondary containment tanks may be inspected by checking the interstice for liquid or by
other equivalent methods. For elevated ASTs where all external surfaces are accessible, the internal inspection
may be conducted by examining the tank exterior using such methods as Ultrasonic Thickness Scans (UTS). For
all other situations, entry into the interior of the AST is necessary. Internal inspection guidelines are detailed
separately for horizontal ASTs and for vertical and rectangular ASTs in Sections 8.2 and 8.3 of the standard,
respectively. Additional requirements for field-erected tanks are in Appendix B. The final report should contain
elements similar to reports prepared for external inspections.
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Section 9 of the standard addresses leak testing methods. For shop-fabricated ASTs, the standard
references the Steel Tank Institute Recommended Practice R912, "Installation Instructions for Shop Fabricated
Stationary Aboveground Storage Tanks for Flammable, Combustible Liquids." The standard also references DOT
regulations for portable containers:
• 49 CFR part 173.28, Reuse, reconditioning, and remanufacturing of packaging, mainly for drums;
• 49 CFR part 178 - 49 CFR Subpart O, Testing and certification of intermediate bulk containers
(IBCs); and
• 49 CFR part 180.605, or equivalent, for portable container testing and recertification.
Section 10 of the standard addresses the suitability for continued service based on the results of formal
internal and/or external inspections performed by a certified inspector. For ASTs that show signs of damage
caused by MIC, the criteria for assessing their suitability for continued service differ based on categories
associated with the level of reduction of the shell thickness (as per Section 5 of STI SP001). For other tank
damage, an engineer experienced in AST design or a tank manufacturer should determine if an inspection is
required for any AST that was exposed to fire, natural disaster, excessive settlement, overpressure, or damage
from cracking.
Section 11 of the standard details recordkeeping requirements. Appendix A presents supplemental
technical information including terms commonly associated with ASTs, and Appendix B presents information for
the inspection of field-erected ASTs.
For more information on STI SP001, please visit the Steel Tank Institute Web site,
http://www.steeltank.com.
7.7.3 STI Standard SP031 - Standard for Repair of Shop Fabricated Aboveground Tanks for
Storage of Combustible & Flammable Liquids
STI Standard SP031 - Standard for Repair of Shop Fabricated Aboveground Tanks for Storage of
Combustible & Flammable Liquids156 covers the repair and modification of an atmospheric-type shop fabricated
carbon and stainless steel tanks. It applies to tanks storing flammable and combustible liquids at atmospheric
pressure with a specific gravity not greater than 1.0. STI SP031 is referenced in STI SP001 for repairs or
alterations to an AST.
STI SP031 Standard for Repair of Shop Fabricated Aboveground Tanks for Storage of Combustible & Flammable Liquids 4th
Edition November 2008, Revised November 2012
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7.7.4 API Recommended Practice 575 - Guidelines and Methods for Inspection of Existing
Atmospheric and Low-Pressure Storage Tanks
API Recommended Practice 575 - Guidelines and Methods for Inspection of Existing Atmospheric and
Low-Pressure Storage Tanks157 (API RP 575), which supplements API 653, covers the inspection of atmospheric
tanks (e.g., cone roof and floating roof tanks) and low-pressure storage tanks (i.e., those that have cylindrical
shells and cone or dome roofs) that have been designed to operate at pressures from atmospheric to 15 pounds
per square inch gauge (psig). (API RP 572158 covers vessels operating above 15 psig.) API RP 575 applies only to
the inspection of atmospheric and low-pressure storage tanks that have been in service. In addition to
describing the types of storage tanks and their construction and maintenance, API RP 575 also covers the
reasons for inspection, causes of deterioration, frequency and methods of inspection, methods of repair, and
the preparation of records and reports.
The recommended practice is organized as follows:
• Section 1 of API RP 575 introduces the recommended practice and details its scope.
• Section 2 lists codes, standards and related publications that are cited in the recommended
practice.
• Section 3 defines terms relevant to API RP 575.
• Section 4 describes specific types of atmospheric and low-pressure storage tanks including
construction materials and design standards and their use.
• Section 5 covers the reasons for inspection and causes of deterioration of both steel and non-
steel storage tanks. Section 5 also covers the deterioration and failure of auxiliary equipment as
well as a similar service methodology for establishing tank corrosion rates.
• Section 6 of API RP 575 addresses inspection frequency and scheduling; it mainly defers to the
inspection frequency requirements described in API 653 and API RP 12R1.
• Section 7 covers the methods of inspection including the external inspection of both in-service
and out-of-service tanks and the internal inspection of out-of-service tanks.
• Section 8 addresses leak testing and hydraulic integrity of tank bottoms.
• Section 9 focuses on the integrity of repairs and alterations, which stresses the importance of
inspecting repairs to ensure they have been properly done.
API RP 575, "Guidelines and Methods for Inspection of Existing Atmospheric and Low-Pressure Storage Tanks," 2nd ed.,
American Petroleum Institute, May, 2005
API 572 Inspection of Pressure Vessels, 3rd Edition, November, 2009
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• Section 10 addresses recordkeeping and inspection reports.
• Appendix A describes selected methods for non-destructive examination of tanks, including
ultrasonic thickness measurement, ultrasonic corrosion testing, ultrasonic shear wave testing,
magnetic flux testing and robotic inspection.
• Appendix B contains similar service evaluation tables for corrosion rates.
• Appendix C provides a selected bibliography.
7.7.5 API Recommended Practice 12R1 - Recommended Practice for Setting, Maintenance,
Inspection, Operation, and Repair of Tanks in Oil Production Service
API Recommended Practice 12R1 - Recommended Practice for Setting, Maintenance, Inspection,
Operation, and Repair of Tanks in Production Service (API RP 12R1)159 provides guidance on new tank
installations and maintenance of existing oil production tanks. These tanks are often referred to as "upstream"
or "extraction and production (E&P) tanks."
This recommended practice is primarily intended for tanks fabricated to API Specifications 12B, D, F, and
P that are employed in on-land production service.160 The basic principles in this recommended practice can also
be applied to other atmospheric tanks in similar oil and gas production, treating, and processing services;
however, they are not applicable to refineries, marketing bulk stations, petrochemical plants, or pipeline storage
facilities operated by carriers. According to the recommended practice, tanks that are fabricated to API
Standards 12C or 650 should be maintained in accordance with API 653, summarized above.
The recommended practice is organized as follows:
• Sections 1, 2, and 3 describe the scope of the standard, the 19 standards it references, and the
relevant definitions, respectively. The remaining four main sections describe the recommended
practices.
• Section 4 provides recommended practices for setting of new or relocated tanks and connecting
tanks.
Section 5 recommends practices for safe operation and spill prevention for tanks.
161
API Recommended Practice 12R1, "Recommended Practice for Setting, Maintenance, Inspection, Operation, and Repair of
Tanks in Production Service," 5th edition. American Petroleum Institute. August 1997, Reaffirmed April 2008.
API Specifications 12B, D, F, and P correspond to bolted tanks for storage of production liquids, field welded tanks for storage of
production liquids, shop welded tanks for storage of production liquids, and specification for fiberglass reinforced plastic tanks,
respectively.
The scope of API RP 12R1 states that "the spill prevention and examination/inspection provisions of this recommended practice
should be a companion to the spill prevention control and countermeasures (SPCC) to prevent environmental damage."
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• Section 6 details the recommended practices for routine operational and external and internal
condition examinations, internal and external inspections, maintenance of tanks, and
recordkeeping. Tables 1 and 2 detail the type of observations, frequency, and associated
personnel requirements for internal and external tank inspections. Records from these
inspections should be retained with permanent equipment records.
• Section 7 provides guidance for the alteration or repair of various tank components.
API RP 12R1 also contains nine appendices detailing the recommended requirements for qualified
inspectors, sample calculations for venting requirements, observations regarding shell corrosion and brittle
fracture, checklists for internal and external condition examinations and inspections, details regarding the
minimum thickness of tank elements, and various figures and diagrams.
7.7.6 API 570 - Piping Inspection Code: In-Service Inspection, Rating, Repair, and
Alteration, of Piping Systems
API 570 - Piping Inspection Code: In-Service Inspection, Rating, Repair, and Alteration, of Piping Systems
(API 570)162 covers procedures for metallic and fiberglass reinforced plastic piping systems and their associated
pressure relieving devices that have been in service. API 570 was developed for the petroleum refining and
chemical process industries but may be used, where practical, for any piping system. In-service piping systems
covered by API 570 include those used for process fluids, hydrocarbons, and similar flammable or toxic fluids.
API states that this standard is not a substitute for the original construction requirements governing a piping
system before it is placed in service. API 570 is intended for use by organizations that maintain or have access to
an authorized inspection agency; a repair organization; and technically qualified piping engineers, inspectors,
and examiners. The code is organized as follows:
• Section 4 outlines responsibilities and associated procedures and qualifications. The owner/user
of piping systems is responsible for the piping system inspection program, inspection
frequencies, and maintenance of piping systems in accordance with this standard. The
owner/user organization is also responsible for activities related to the rating, repair and
alteration of its piping systems.
• Section 5 addresses the specific inspection and pressure testing practices for in-service piping
systems.
• Section 6 addresses the frequency and extent of inspection of piping. Inspection intervals for
piping are based on the forms of degradation possible and consequence of failure. Risk-based
assessment may be used to determine inspection intervals or an interval can be established
which takes into account the corrosion rate and remaining life calculations; piping service
API 570, "Piping Inspection Code: In-Service Inspection, Rating, Repair, and Alteration of Piping Systems," 3rd ed., American
Petroleum Institute, November 2009.
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classification; applicable jurisdictional requirements; and the judgment of the inspector, the
piping engineer, the piping engineer supervisor, or a corrosion specialist.
Table 2 of API 570 provides maximum inspection intervals for piping based on piping service
classification:
Class 1 poses the highest potential of resulting in an immediate emergency if a leak were
to occur;
Class 2 is for services not included in other categories and includes the majority of piping;
Class 3 is for services that are flammable but do not significantly vaporize when they leak
and are not located in high-activity areas; and
Class 4 is for services that are essentially nonflammable and nontoxic.
The maximum inspection interval for in-service aboveground piping listed in Section 6 Table 2 is
as follows:
Class 1: Thickness measurements - 5 years, visual inspection - 5 years
Class 2: Thickness measurements - 10 years, visual inspection - 5 years
Class 3: Thickness measurements - 10 years, visual inspection - 10 years
Class 4: Thickness measurements - optional, visual inspection - optional
The inspection interval may be less depending on corrosion rates and remaining life. Thickness
measurements must be obtained at 1/£ the remaining life determined from corrosion rates or the
intervals listed in Table 2 whichever is less.
The type and frequency of inspections for buried piping is presented separately in Section 9 (see
below).
Section 7 addresses data evaluation, analysis, and recording. The owner/operator should
maintain permanent records for all piping systems covered by API 570.
Section 8 provides guidelines for repairing, altering, and rerating piping systems and refers to
ASME B31.3 for in-service repairs.
Section 9 addresses the inspection of buried piping. Inspecting buried process piping is different
from inspecting other process piping because the inspection is hindered by the inaccessibility of
the affected areas of the piping.
Annex A, B, and C address inspector certification, requests for interpretations, examples of
repairs, and the external inspection checklist for process piping, respectively.
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7.7.7 API Recommended Practice 574 - Inspection Practices for Piping System
Components
API Recommended Practice 574 - Inspection Practices for Piping System Components (API RP 574)163
covers inspection practices for piping, tubing, valves (other than control valves), and fittings used in petroleum
refineries and chemical plants. It addresses inspection planning processes, inspection intervals and techniques
and types of records. API RP 574 is intended to supplement API 570. It does not cover inspection of specialty
items, such as instrumentation and control valves. The recommended practice is organized as follows:
• Section 1 introduces the recommended practice and details its scope.
• Sections 2 and 3, respectively, list the references and definitions used throughout the
recommended practice.
• Section 4, which begins the substantive portion of the recommended practice, details the types,
material specifications, sizes, and other characteristics of the components of the piping system,
which include the piping, tubing, valves, fittings, flanges and joints.
• Section 5 details common joining methods, i.e., welding, threading and flanging.
• Section 6 presents the rationale for inspecting the piping system: to identify active deterioration
mechanisms and to specify repair, replacement, or future inspections for affected piping. It
suggests examining inspection history and points to API 570 as providing the basic requirements
for such an inspection program.
• Section 7 discusses the development of an inspection plan, including risk-based plans and
interval-based plans. It presents considerations for monitoring the piping system components
for corrosion and inspecting for damage.
• Section 8 provides guidelines for establishing the frequency and extent of inspection using the
following conditions to determine the frequency of inspection: the consequences of a failure
(piping classification, see summary of API 570 in Section 7.7.6 for a description) degree of risk,
amount of corrosion allowance remaining, historical data available, and regulatory
requirements. It also discusses inspections on piping that is operating and not in operation.
• Section 9 outlines the safety precautions and preparatory work to be performed prior to
inspecting the piping system components. The inspection tools commonly used to inspect piping
are listed in Section 9.2.2 of API RP 574.
• Section 10 details the specific procedures and practices to be followed when inspecting the
components of the piping system such as external and internal visual inspection, pressure tests,
API RP 574, "Inspection Practices for Piping System Components," 3rd ed., American Petroleum Institute, November 2009.
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and other methods. This section also covers the inspection of underground piping (Section
10.10) and new construction (Section 10.11).
• Section 11 refers to ASME B31.3 in describing the procedures a piping engineer should follow to
determine the thickness at which piping and valves and flanged fittings should be retired.
• Section 12 addresses recordkeeping.
• Appendix A of the recommended practice provides an external inspection checklist for process
piping.
7.7.8 API Recommended Practice 1110 - Pressure Testing of Steel Pipelines for the
Transportation of Gas, Petroleum Gas, Hazardous Liquids, Highly Volatile Liquids or
Carbon Dioxide
API Recommended Practice 1110 - Pressure Testing of Steel Pipelines for the Transportation of Gas,
Petroleum Gas, Hazardous Liquids, Highly Volatile Liquids or Carbon Dioxide (API RP 1110)164 provides guidance
regarding the procedures, equipment, and verification of pressure test results, as well as guidance for meeting
the requirements of Integrity Management set out in API Standard 1160 and ASME B31.8S. Pressure testing uses
a liquid test medium (typically water) to apply internal pressure to a segment of pipe above its normal or
maximum operating pressure for a fixed period of time.
The main sections of this standard are Pressure Test Planning, Pressure Test Implementation, and
Pressure Test Records and Drawings. Planning for a pressure test involves safety considerations, written test
procedures, pipeline operating considerations, selection of a test medium, equipment and materials, target test
pressures and durations, and other related issues. There are three basic types of pressure tests based on the
intended purpose:
• Spike test— a short duration, high amplitude (pressure ratio) test;
• Strength test— conducted to establish the operating pressure limit of a pipeline; and
• Leak test— used to determine if a pipeline is leaking, and can be used in combination with the
other test types
For implementation of pressure tests, personnel should follow site-specific test procedures including
appropriate test pressures and the duration of the pressure test. Other operational aspects of pressure test
implementation address the proper qualifications of personnel, pressurization, the test period, searching for
leaks, and disposal of the test medium. Lastly, adequate test records and drawings should be kept for the useful
API Recommended Practice 1110, "Pressure Testing of Liquid Petroleum Pipelines," 5th edition, American Petroleum Institute,
June 2007.
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life of the pipeline to document the operating pressure limit of a section of pipe or to demonstrate compliance
with integrity management requirements.
7.7.9 API Recommended Practice 579-1/ASME FFS-1, Fitness-for-Service, Part 3
This recommended practice165 addresses "Assessment of Existing Equipment for Brittle Fracture" and
provides guidelines for evaluating the resistance to brittle fracture of existing carbon and low alloy steel
pressure vessels, piping, and storage tanks. If the results of the fitness-for-service assessment indicate that the
AST is suitable for the current operating conditions, then the equipment can continue to be operated under the
same conditions provided that suitable monitoring/inspection programs are established. API RP 579-1/ASME
FFS-1 is intended to supplement and augment the requirements in API 653. That is, when API 653 does not
provide specific evaluation procedures or acceptance criteria for a specific type of degradation, or when API 653
explicitly allows the use of fitness-for-service criteria, API RP 579-1/ASME FFS-1 may be used to evaluate the
various types of degradation or test requirements addressed in API 653.
A brittle fracture assessment may be warranted based on operating conditions and/or the condition of
the AST. API RP 579-1/ASME FFS-1 provides separate brittle fracture assessment procedures for continued
service based on three levels. All three apply to pressure vessels, piping, and tankage, although a separate
assessment procedure is provided for tankage.
• Level 1 assessments are used for equipment that meets toughness requirements in a recognized
code or standard (e.g., API 650).
• Level 2 assessments exempt equipment from further assessment and qualify it for continued
service based on one of three methods that utilize operating pressure and temperature;
performance of a hydrotest; or the materials of construction, operating conditions, service
environment, and past operating experience.
• Level 3 assessments, which normally utilize a fracture mechanics methodology, are used for
tanks that do not meet the acceptance criteria for Levels 1 and 2.
A decision tree in API RP 579-1/ASME FFS-1 (Figure 3.3, Brittle Fracture Assessment for Storage Tanks)
outlines this assessment procedure. The Level 1 and Level 2 brittle fracture assessment procedures are nearly
identical to those found in API 653, Section 5, with a few notable exceptions: API 653 does not use the Level 1
and Level 2 designations; API 653 applies only to tanks that meet API 650 (7th edition or later) construction
standards, whereas API 579-1/ASME FFS-1 applies to tanks that meet toughness requirements in the "current
construction code;" and the two standards set a different limit on the maximum membrane stress (the stress
forces that form within the shell as a result of the pressure of the liquid inside the vessel). There is, however,
one major difference between API 653 and API 579-1/ASME FFS-1: API 653 Section 5 does not allow for an
exemption of the hydrostatic test requirement whereas API 579-1/ASME FFS-1 does. API 579-1/ASME FFS-1
API Recommended Practice 579, "Fitness for Service," 2nd Edition, American Petroleum Institute, June 2007.
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allows for a probabilistic evaluation of the potential for brittle fracture using engineering calculations (i.e., a
Level 3 assessment) in lieu of the hydrostatic test.
7.7.10 API Standard 2610 - Design, Construction, Operation, Maintenance, and Inspection
of Terminal and Tank Facilities
This standard166 has short sections on petroleum terminals, pipeline tankage facilities, refinery facilities,
bulk plants, lube blending and packaging facilities, asphalt plants, and aviation service facilities. These sections
mainly serve to define what is meant by each type of facility. The standard does not apply to installations
covered by API Standard 2510 and API RP 12R1, as well as specific types of facilities and equipment listed in the
standard. The standard lists governmental requirements and reviews that should be conducted to ensure that
facilities meet applicable federal, state, or local requirements (Section 1.3); and has an extensive list of
standards, codes, and specifications to use (Section 2.1) and definitions (Section 3). The standard is further
organized as follows:
• Section 4 covers the site selection and spacing requirements for the design and construction of
new terminal facilities.
• Section 5 addresses the methods of pollution prevention and waste management practices in
the design, maintenance, and operation of petroleum terminal and tank facilities.
• Section 6 covers the safe operation of terminals and tanks including hazard identification,
operating procedures, safe work practices, emergency response and control procedures,
training, and other provisions.
• Section 7 covers fire prevention and protection, including tank overfill protection and inspection
and maintenance programs. This section also covers considerations for special products.
• Section 8 covers aboveground petroleum storage tanks and appurtenances such as release
prevention, leak detection, and air emissions. This section covers operations, inspections,
maintenance, and repair for aboveground and underground tanks.
• Section 9 addresses dikes and berms.
• Section 10 covers pipe, valves, pumps, and piping systems.
• Section 11 covers loading, unloading, and product transfer facilities and activities including spill
prevention and containment.
• Section 12 addresses the procedures and practices for achieving effective corrosion control.
API Recommended Practice 2610, "Design, Construction, Operation, Maintenance, and Inspection of Terminal and Tank
Facilities," 2nd edition, American Petroleum Institute, May 2005.
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• Section 13 addresses structures, utilities, and yards.
• Section 14 covers removal or decommissioning of facilities.
All of these sections make extensive reference to the regulatory requirements and applicable industry
standards.
7.7.11 RP FTPI 2007-1 Recommended Practice for the In-service Inspections of Aboveground
Atmospheric Fiberglass Reinforced Plastic Tanks and Vessels
The Fiberglass Tank and Pipe Institute (FTPI) 2007-1 Recommended Practice includes recommended
inspector qualifications, periodic preventive maintenance inspections, certified external inspections, certified
integrity inspections, internal inspections and alternate non-intrusive inspection methods. It also includes report
forms for monthly, annual and periodic preventive maintenance and certified inspections and a section on
aboveground fiberglass tank fabrication information. RP FTPI 2007-1 may be used for the inspection of
aboveground fiberglass tanks or vessels.
The purpose of this Recommended Practice is to provide procedures for conducting periodic preventive
maintenance inspections and certified inspections of fiberglass reinforced plastic atmospheric tanks and vessels
in corrosive industrial and commercial service after a set period of time and when there is a change of service.
The procedures are intended to:
• Minimize maintenance costs;
• Ensure compliance with environmental and safety requirements;
• Minimize system failures; and
• Ensure that proper engineering, construction and maintenance practices are in place.
Recommended Practice FTPI 2007-1 specifies the requirements for external and internal inspections to
be performed by certified inspectors as follows:
Certified External Inspections
• Every 5 years for tanks or vessels in Hazardous Substance service;
• Every 10 years for tanks/vessels greater than 10,000 gallons capacity and in other service;
• If evidence of material stress appears;
• If tank or vessel leaks occur;
• Before there is a change in service to a dissimilar stored material; or
• If a tank or vessel is relocated.
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Certified Integrity Inspections
• Every 20 years for tanks/vessels in Hazardous Substance service;
• Every 20 years for tanks/vessels greater than 10,000 gallons capacity and in other service;
• If evidence of material stress appears;
• If tank or vessel leaks occur;
• Before there is a change in service to a dissimilar stored material; or
• If a tank or vessel is relocated.
7.7.12 ASME B31.3 - Process Piping
ASME B31.3 - Process Piping167 is the generally accepted standard of minimum safety requirements for
the oil, petrochemical, chemical, pharmaceutical, textile, paper, and semiconductor industries' process piping
design and construction (for process piping already in service, other standards should be used, such as API 570,
"Piping Inspection Code"). ASME B31.3 is written to be very broad in scope to cover a range of fluids,
temperatures, and pressures. This broad coverage leaves a great deal of responsibility with the owner to use
good engineering practices. The safety requirements for the design, examination, and testing of process piping
vary in stringency based on four different categories of fluid service. Categories include:
• Category D for a low hazard of fluid service,
• Category M for a high hazard of fluid service,
• High Pressure for piping designated by the owner as being in high pressure fluid service168, and
• Normal to indicate all remaining fluid services.
It is the owner's responsibility to select the appropriate fluid service category, which determines the
appropriate examination requirements.
ASME B31.3 distinguishes between inspection and examination. Inspection "applies to functions
performed for the owner by the owner's Inspector or the Inspector's delegates." The owner is responsible,
through the Inspector, for verifying that the required examinations and testing have been completed. The
examination of process piping is to be completed by an examiner who demonstrates sufficient qualifications to
perform the specified examination and who has training and experience records kept by his/her employer that
ASME Code for Pressure Piping, B31.3-2008, "Process Piping," The American Society of Mechanical Engineers, revision of ASME
31.3-2006, 2008.
High Pressure is considered in ASME B31.3 to be pressure in excess of that allowed by the ASME b!6.5 Class 2500 rating for the
specified design temperature and material group; however, there are not specified pressure limitations for ASME B31.3.
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can support these qualifications.169 Different types of examinations performed include visual, radiographic,
ultrasonic, in-process, liquid-penetrant, magnetic-particle, and hardness testing.
While these examinations are a part of the quality assurance procedures for new piping, leak testing
should also be performed to test the overall system. According to ASME B31.3, leak testing is required for all
new piping systems other than those classified as Category D, which can be examined for leaks after being put
into service. Options for leak testing include hydrostatic, pneumatic, hydro pneumatic, and alternative leak
tests.
The standard requires that records detailing the examination personnel's qualifications and examination
procedures be kept for at least five years. Test records or the inspector's certification that the piping has passed
pressure testing are also required to be retained.
7.7.13 ASME Code for Pressure Piping B31.4-2006 - Pipeline Transportation Systems for
Liquid Hydrocarbons and Other Liquids
ASME Code for Pressure Piping B31.4-2006 - Pipeline Transportation Systems for Liquid Hydrocarbons
and Other Liquids170 describes "engineering requirements deemed necessary for safe design and construction of
pressure piping." These requirements are for the "design, materials, construction, assembly, inspection, and
testing of piping transporting liquids" such as crude oil and liquid petroleum products between various facilities.
Piping includes bolting, valves, pipes, gaskets, flanges, fittings, relief devices, pressure-containing parts of other
piping components, hangers and supports, and any other equipment used to prevent the overstressing of
pressure-containing pipes. This code's primary purpose is to "establish requirements for safe design,
construction, inspection, testing, operation, and maintenance of liquid pipeline systems for protection of the
general public and operating company personnel."
The personnel inspecting the piping are deemed qualified based on their level of training and experience
and should be capable of performing various inspection services such as right-of-way and grading, welding,
coating, pressure testing, and pipe surface inspections. Inspections of piping material and inspections during
piping construction should include the visual evaluation of all piping components. Once construction is
complete, these piping components and the entire system should be tested. Testing methods include
hydrostatic testing of internal pressure piping; leak testing; and qualification tests based on a visual
examination, bending properties, determination of wall thickness, determination of weld joint factor,
weldability, determination of yield strength, and the minimum yield strength value.
Records detailing the design, construction, and testing of the piping should be kept in the files of the
operating company for the life of the facility.
ASME B31.3 does not have specific requirements for an examiner, but SNT-TC-1A, "Recommended Practice for Nondestructive
Testing Personnel Qualification and Certification," acts as an acceptable guide.
ASME Code for Pressure Piping, B31.4-2006, "Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids," The
American Society of Mechanical Engineers, revision of ASME B31.4-2002, 2006.
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Chapter 7: Inspection, Evaluation, and Testing
7.7.14 DOT 49 CFR part 180.605 - Requirements for Periodic Testing, Inspection, and
Repair of Portable Tanks and Other Portable Containers
Section 180.60S171 applies to any portable tank constructed to a DOT (e.g., 51, 56, 57, 60, or intermodal
[IM]) or United Nations (UN) specification. According to these requirements, a portable tank must be inspected
prior to further use if it shows evidence of a condition that might render it unsafe for use, has been damaged in
an accident, has been out of service for more than a year, has been modified, or is in an unsafe operating
condition. All tanks must receive an initial inspection prior to being placed into service and a periodic inspection
or intermediate periodic inspection every two to five years. The timeframe between inspections depends upon
the tank's specification.
Intermediate periodic inspections must include an internal and external examination of the tank and
fittings, a leak test, and a test of the service equipment. The periodic inspection and test must include an
external and internal inspection and a sustained air pressure leak test, unless exempted. For tanks that show
evidence of damage or corrosion, an exceptional inspection and test is mandated. The extent of the inspection is
dictated by the amount of damage or deterioration of the portable tank. Specification-60 tanks are further
tested by filling them with water. Specification-IM or Specification-UN portable tanks must also be
hydrostatically tested. Any tank that fails a test may not return to service until it is repaired and retested. An
approval agency must witness the retest and certify the tank for return to service. The date of the last pressure
test and visual inspection must be clearly marked on each portable tank. A written record of the dates and
results of the tests, including the name and address of the person performing the test, is to be retained by the
tank owner or authorized agent.
Requirements for retest and inspection of Intermediate Bulk Containers (IBCs) are specified in 49 CFR
180.352. Requirements depend on the IBC shell material. For metal, rigid plastic, and composite IBCs, they
include a leakproof test and external visual inspection every 2.5 years from the date of manufacture or repair.
They also require an internal inspection every 5 years to ensure that the IBC is free from damage and capable of
withstanding the applicable conditions. Flexible, fiberboard, or wooden IBCs must be visually inspected prior to
first use and permitted reuse. Records of each test must be kept until the next test, or for at least 2.5 years from
the date of the last test.
Design standards and specifications for initial qualification and reuse performance testing for portable
tanks, drums, and IBCs are contained in 49 CFR part 178, Specifications for Packaging. See
http://www.ecf r.gov/cgi-bin/text-idx?c=ecfr&tpl=%2Findex.tpl.
49 CFR part 180.605, "Requirements for Periodic Testing, Inspection, and Repair of Portable Tanks," Department of
Transportation, 64 FR 28052, May 24,1999, as amended at 67 FR 15744, April 3, 2002 and 68 FR 45042 revision.
SPCC GUIDANCE FOR REGIONAL INSPECTORS
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Chapter 7: Inspection, Evaluation, and Testing
7.7.15 FAA Advisory Circular 150/5230-4A - Aircraft Fuel Storage, Handling, and
Dispensing on Airports
FAA Advisory Circular 150/5230-4A - Aircraft Fuel Storage, Handling, and Dispensing on Airports172
identifies standards and procedures for storage, handling, and dispensing of aviation fuel on airports. The
Federal Aviation Administration (FAA) recommends the standards and procedures referenced in the Advisory
Circular (AC) for all airports. The FAA accepts these standards as one means of complying with 14 CFR Part 139,
Certification of Airports, as it pertains to fire safety in the safe storage, handling, and dispensing of fuels used in
aircraft on airports but not in terms of quality control. Although airports that are not certificated under 14 CFR
part 139 are not required to develop fuel safety standards, the FAA recommends that they do so.
This AC is not intended to replace airport procedures developed to meet requirements imposed because
of the use of special equipment, nor to replace local regulations. For specific provisions, the other standards that
are referenced in this AC are:
• For fuel storage, handling and dispensing, the National Fire Prevention Association's "Standard
for Aircraft Fuel Servicing."
• For refueling and quality control procedures, the National Air Transportation Association's
"Refueling and Quality Control Procedures for Airport Service and Support Operations." This
provides information about fuel safety, types of aviation fuels, fueling vehicle safety, facility
inspection procedures, fueling procedures, and methods for handling fuel spills. API also
publishes documents pertaining to refueling and facility specifications.
The AC also requires fuel safety training for airports certificated under 14 CFR part 139. (See
http://www.faa.gov/airports/resources/advisory circulars/index.cfm.)
7.7.16 FAA Advisory Circular 150/5210-20 - Ground Vehicle Operations on Airports
FAA Advisory Circular 150/5210-20 - Ground Vehicle Operations on Airports173 provides "guidance to
airport operators in developing training programs for safe ground vehicle operations and pedestrian control on
the airside of an airport." Specifically, this advisory circular provides recommended operating procedures for
ground vehicles. It also provides two appendices containing samples of the training curriculum and training
manual. The sample training manual in Appendix B provides airport operators with a template for developing
and implementing policies or procedures for controlling ground vehicles and equipment on an airport, for
example requirements for fuel trucks transporting oil. Airport operators would use the format but adapt the
requirements to specific conditions found on the airport.
(See http://www.faa.gov/airports/resources/advisory circulars/index.cfm.)
FAA Advisory Circular 150/5230-4A, "Aircraft Fuel Storage, Handling, and Dispensing on Airports," Federal Aviation
Administration, U.S. Department of Transportation, June 18, 2004.
FAA Advisory Circular 150/5210-20, "Ground Vehicle Operations on Airports," Federal Aviation Administration, U.S. Department
of Transportation, March 31, 2008.
SPCC GUIDANCE FOR REGIONAL INSPECTORS
November 15, 2013
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3A Sanitary Standards, 7-48
Aboveground piping
Inspection requirements, 7-21, 7-59, 7-70
Aboveground storage tank
(AST), 1-7, 4-19, 7-11
Accumulation of oil
Removal, 4-62, 7-14, 7-23
Active measures, secondary containment
Considerations in selecting, 4-25, 4-26
Definition, 4-24, 4-25
Deployment of, 4-26, 4-27
Oil-filled operational equipment, 4-27
Role of EPA Inspector, 4-27, 4-28, 4-29
Acts of war or terrorism, 1-19, 4-12, 4-65, 4-68, 5-13
Adjuvant oil, 1-21, 2-50
Airport, 1-10, 2-29, 6-10, 7-79
Alteration
Industry standard, 7-62, 7-63, 7-66, 7-67, 7-69
Storage capacity. See Storage capacity, Alteration
Amendment
SPCC Plan, 2-40, 3-26, 4-45, 5-18, 6-22, 7-28, 7-52
Animal fat, 1-5, 1-10, 1-18, 1-21, 1-24, 2-4, 2-5, 2-8, 2-44,
3-6, 3-12, 3-21, 4-14, 4-37, 4-59, 5-3, 7-2, 7-10, 7-15
Appendix G template
Qualified facility. See Qualified facility, Appendix G
template
Applicability
FRP, 1-2, 1-4, 1-5, 1-16, 2-10, 2-15, 2-19, 2-40, 2-59, 4-
39, 4-44, 4-45, 4.45, 4-51, 7-52, 7-53
Applicability, SPCC
Appeal process, 2-53
Description, 2-1, 2-2, 2-6, 2-8, 2-9, 2-54, 2-61
Flowchart, 2-60
OWS, 5-1, 5-3, 5-7, 5-12, 5-13
Approval of State Underground Storage Tank Programs
40 CFR part 281, 2-43
Asphalt
Asphalt cement, 1-21, 2-5
Cutback, 1-21, 2-5
Emulsions, 1-21, 2-5
Hot-mix asphalt, 1-21, 2-5
Austenitic stainless steel, 7-8, 7-15, 7-16, 7-17, 7-18, 7-64
Barrier
Secondary containment example, 4-8
Secondary containment examples, 4-9, 4-25, 4-27, 4-
33
Baseline
Inspections, 7-37, 7-38, 7-56, 7-59, See Integrity
testing, Baseline
Berm
Secondary containment example, 2-19, 3-6, 3-7, 4-8,
4-9, 4-15, 4-17, 4-18, 4-26, 4-27, 4-29, 4-32, 4-33, 4-
53, 4-63, 4-64, 7-74
Best Management Practice (BMP), 2-46, 3-11, 5-4
Biodiesel, 2-8
Blowout prevention (BOP) assembly, 3-5, 3-35, 3-36
Boom
Secondary containment example, 4-8, 4-9, 4-26, 4-27,
4-33
Breakout tank
Definition of, 2-31
Brittle fracture evaluation, 1-18, 3-3, 3-28, 7-2, 7-3, 7-20,
7-21, 7-20, 7-50, 7-55, 7-62, 7-69, 7-73, 7-74
Bulk storage container
Definition, 2-54, 2-56, 2-57, 2-58
SPCC GUIDANCE FOR REGIONAL INSPECTORS
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Integrity testing requirements, 1-23, 3-21
Bunkered tank, 2-37, 2-43
Buried metallic tank
Testing requirements, 3-9
Buried piping
Requirements, 3-13, 3-14, 3-15, 3-16, 3-31, 4-50, 7-5,
7-21, 7-22
Certification
SPCC Plan, 1-18, 1-19, 1-20, 3-1, 3-7, 3-34, 4-8, 4-31, 4-
40, 4-68, 5-17, 6-22, 7-9, 7-47, 7-52
Certification of the Applicability of the Substantial Harm
Criteria. See FRP substantial harm criteria:certification
of
Change in service, 2-40, 3-28, 7-2, 7-20, 7-21
Clean Water Act, 1-1,1-2,1-3,1-4,1-6,1-8,1-9,1-25, 2-
2, 2-3, 2-7, 2-33, 2-34, 2-36, 2-52, 5-4
Collection system
Secondary containment example, 4-8, 4-10
Completely buried tank
Applicability, 2-37, 2-45
Corrosion protection, 2-46
Diagram, 6-22
Exemption, 2-7, 2-37, 2-43
Leak testing, 7-19, 7-20
Release detection, 3-9
Complex, 2-27, 2-28, 2-29, 2-31, 2-32, 2-51
Definition, 2-27
Compliance date, 1-6,1-10,1-11,1-12,1-13,1-14,1-21,
1-26
Condensate, 2-6, 2-12, 2-24, 2-26, 2-57, 4-60, 5-5
Contact list, 6-4
Contiguous zone, 1-1,1-3,1-19, 2-36
Corrosion protection
Completely buried tank, 1-14, 2-46, 3-8, 3-9
Piping, 1-14, 2-46, 3-13, 3-14, 3-15, 3-16
Cost considerations
Environmental equivalence. See Environmental
Equivalence, Consideration of costs
Countermeasure, 2-55, 4-24, 4-27, 4-44, 6-1, 6-3, 7-32
Criteria for State, Local and Regional Oil Removal
Contingency Plans, 1-28, 4-15
Crop oil, 1-21, 2-50
Culverting
Secondary containment example, 4-9, 4-33
Curbing
Secondary containment example, 4-9, 4-24, 4-27, 4-33,
4-53, 4-58, 4-59
Current Good Manufacturing Practice in Manufacturing,
Packing or Holding Human Food, 7-15, 7-16
Denatured ethanol, 2-7
Department of Transportation, 1-2, 2-10, 2-27, 2-28, 2-
29, 2-30, 2-31, 2-42, 2-50, 7-34
Dike
Secondary containment example, 4-53, 4-58, 4-59, 4-
63, 7-74
Diked area
Accumulation of oil. See Visible discharge,promptly
correct
Discharge
Definition, 2-33
Disposal of recovered materials, 3-18, 6-1, 6-4, 7-24, 7-29
DOT. See Department of Transportation
Double-walled tank, 4-36, 4-37, 4-38, 7-43, 7-44
Drainage pond, 4-18
Drainage system
Secondary containment example, 3-6, 3-7, 4-8, 4-32,
4-33, 4-34, 4-35, 4-39, 4-46, 4-50, 4-53
Drilling
Activity, 2-9, 2-13, 2-48, 4-6, 4-7, 4-63
Drip gas, 2-6
Drip pan
Secondary containment example, 4-10
Dry gas, 2-24, 2-25, 2-26, 2-46, 2-47, 5-5
Edible Oil Regulatory Reform Act, 1-5,1-9, 2-4
SPCC GUIDANCE FOR REGIONAL INSPECTORS
November 15, 2013
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Effluent treatment
System or facility, 4-33, 5-8
Eligibility criteria
Qualified facility. See Qualified facility
Qualified oil-filled operational equipment. See
Qualified oil-filled operational equipment
Emergency generator, 2-47, 5-3, 6-9
Environmental Equivalence
Consideration of costs, 3-22
Description of, 3-1
Documentation, 3-22, 3-23
Integrity testing, 7-43, 7-44, 7-45, 7-46
Executive Order 12777,1-4, 2-29, 2-42
Facilities Transferring Oil or Hazardous Material in Bulk,
2-30
Facility Response Plan, 1-2,1-4,1-15,1-16, 2-59, 4-13, 4-
41, 4-42, 4-44, 4-51, 4-65, 4-69, 6-2, 6-5, 6-12, 7-53
Farm
Definition, 1-21, 2-14
Example scenarios, 2-16
Fiberglass reinforced plastic tanks, 7-75
Fitness for service, 3-14, 7-21, 7-34, 7-73
Flowline maintenance program, 3-17, 4-16, 7-2, 7-30, 7-
32, 7-59
Flow-through process vessel, 1-24, 2-55, 3-5, 4-1, 4-61, 4-
63, 4-64, 4-65, 4-66, 5-1, 5-10, 5-12, 5-13, 5-17, 5-18,
7-23, 7-24, 7-59
Alternative measures, 2-58, 3-21, 7-26
Oil production, 2-58
Freeboard. See Sufficient freeboard
Free-water knockout
OWS, 2-58, 4-63, 5-3, 5-10, 5-11, 5-12
FRP. See Facility Response Plan
FRP substantial harm criteria
certification of, 1-16, 2-59
Gas pipeline facility, 2-25, 2-26
Gas processing plant, 2-26
Gathering line, 2-32
Definition, 4-15
Intra-facility, 2-32, 2-50, 2-51, 3-16, 3-17, 3-18, 4-15,
4-16, 6-7, 6-10, 6-22, 7-30, 7-31, 7-59
Generator, 1-25, 2-9, 2-45, 4-14
Gun barrel
OWS, 2-58, 4-63, 5-3, 5-10, 5-11, 5-12, 5-14
Gutter
Secondary containment example, 4-9, 4-33
Harmful quantities of oil, 2-33
Hazardous substance, 1-3,1-4, 2-3, 2-7, 6-8, 6-16
Hazardous waste, 2-7, 2-41, 2-44, 4-19
Heater-treater
OWS, 1-24, 2-19, 2-58, 5-10, 5-12, 5-14
Hot-mix asphalt. See Asphalt:Hot-mix asphalt
Hybrid inspection program
Minimum components, 7-49
Industry standards, summary of
API 570, 7-69
API 653, 7-62, 7-63
API RP 1110, 7-72, 7-73
API RP 12R1, 7-68, 7-69
API RP 574, 7-71
API RP 575, 7-67
AS ME B31.3, 7-76, 7-77
ASME B31.4, 7-77
STI SP001, 7-64, 7-66
Integrity testing
Baseline, 7-37, 7-38, 7-40, 7-41
Schedule, 4-41, 5-12, 7-10, 7-13, 7-14, 7-37, 7-38, 7-
56, 7-59
Intermediate Bulk Container, 4-59, 7-66, 7-78
Interstice, 4-37, 7-44, 7-65
SPCC GUIDANCE FOR REGIONAL INSPECTORS
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Leak testing, 3-9, 3-10, 3-13, 3-14, 3-15, 3-16, 4-41, 7-11,
7-13, 7-19, 7-23, 7-47, 7-49, 7-66, 7-77
Lease, 1-22, 2-10, 2-15, 2-17, 2-18, 2-19, 4-15, 4-62
Liner, 1-4, 4-17, 4-18, 7-18, 7-43
Manifolded, permanently. See Permanently manifolded
Man-made structure, 1-25, 4-36
Marine terminal, 2-30, 2-31
Marine transportation-related facility. See Marine
Terminal
Milk exemption
3A Sanitary Standards, 1-26
Milk or milk product container, 1-11,1-26, 2-51
Mix container
Pesticide, 1-21, 2-50
Mobile facility, 2-11, 2-13, 2-14
Mobile or portable containers, 2-37, 4-59
Facility diagram, 1-22, 4-59, 6-2, 6-5, 6-8, 6-9
Inspection, 7-9, 7-34, 7-42, 7-64, 7-66
Single-use, 7-42
Tank trucks, 2-29
Mobile refueler, 1-10,1-18,1-20,1-23, 2-29, 2-30, 2-48,
4-1, 4-7, 4-16, 4-51, 4-57, 4-59, 4-60
Most likely quantity of oil that would be discharged, 4-
67, 4-68, 5-13, 6-3, See Secondary containment, most
like quantity discharged
Motive power, 1-10,1-18,1-20, 2-47, 2-48, 2-49
National Fire Protection Association, 4-36, 4-58, 7-34
National Pollutant Discharge Elimination System, 1-9, 2-
46, 4-35, 5-4, 5-14
National Response Center, xvii, xix, 2-33, 4-26, 6-4
Natural disaster, 1-19, 3-33, 3-34, 4-11, 4-12, 4-65, 4-68,
5-13, 7-66
Natural gas, 2-5, 2-6, 2-24, 2-25, 2-26, 2-41, 2-44, 5-5
Natural gasoline, 2-6, 2-7
Navigable waters
Definition, 1-1,1-10,1-11,1-25, 2-36
Reasonable expectation of a discharge, 1-21,1-25, 2-
33, 2-34, 2-35, 6-2, 7-14
Ruling, 1-25
NFPA. See National Fire Protection Association
Non-transportation-related facility, 2-27, 2-28, 2-30, 2-31
Non-Transportation-Related Tank Truck, 1-23, 4-1, 4-7, 4-
16, 4-57, 4-59, 4-60
Notification requirements, 1-9, 6-4, 6-5
NPDES. See National Pollutant Discharge Elimination
System
Nuclear Power Stations, 1-25, 2-45, 2-61
Offshore Facility
Definition, 2-11
Jurisdiction, 2-42
Requirements, 4-7, 5-3, 5-13
Oil
Definition, 2-3
USCG List of, 2-4
Oil Pollution Act of 1990,1-4,1-9, 2-3, 2-17
Oil Pollution Prevention
40 CFR part 112, 1-1, 1-9, 1-15, 1-16,1-28, 4-37
Oil production facility
Containers. See Tank battery
Flow-through process vessels. See Flow-through
process vessels
Produced water containers. See Produced water
Oil recovery
Facility, 2-7, 2-25, 2-26, 2-46, 5-1, 5-2, 5-3, 5-1, 5-5, 5-
14, 5-15
Oil recycling
Facility, 2-7, 2-25, 2-26, 2-46, 5-3, 5-5, 5-14
Oil spill contingency plan, 1-18,1-20, 3-17, 3-26,4-11, 4-
13, 4-14, 4-15, 4-24, 4-27, 4-39, 4-41, 4-42, 4-44, 4-47,
4-48, 4-50, 4-62, 4-65, 4-69, 7-23, 7-31
Oil-filled equipment, 2-24, 2-37, 4-1, 4-8, 4-11, 4-14, 4-
34, 4-57, 4-60, 5-3, 5-12, 6-8, 6-10, 6-12, 6-16
Applicability, 2-54
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Oil-filled manufacturing equipment, 2-55, 2-56, 4-14, 4-
57, 5-15, 6-8, 6-10
Flow-through process vessel. See Flow-through
process vessel
Oil-filled operational equipment
Definition, 2-55
Overfill prevention
Requirements, 3-4, 3-5, 3-6, 3-10, 3-11, 3-12, 4-37, 4-
38, 4-47, 4-54
Standards, 3-9
Overfill protection
Standards, 7-74
Partially buried
tank or container, 2-37, 2-43, 3-10, 7-11, 7-16
Passive measure
Secondary containment, 4-2, 4-24, 4-26, 4-37, 4-64, 4-
67, 4-68
Permanently closed, 1-24, 2-37, 2-40, 2-41, 5-12, 6-7
Permanently manifolded, 4-17
Personnel training, 3-3, 3-22, 3-23, 4-29, 6-3
Pesticide application equipment, 1-21,1-22, 2-50
Produced water
Alternative measures, 2-58, 3-21, 4-66, 4-67, 4-68, 7-
26, 7-27, 7-28
Applicability, 2-6, 2-24, 2-25, 2-26, 2-41, 2-46, 5-15
Container, 2-6, 2-7, 2-57, 2-58, 4-1, 4-61, 4-65, 5-5, 7-
59
Impracticability of secondary containment, 4-68
OWS, 5-10, 5-14
Wastewater treatment, 5-5, 5-14
Production facility
Definition, 2-12, 2-14, 2-24
Drainage system requirements, 4-35
Example scenarios, 2-17, 2-19, 2-24, 2-25, 6-18
Flowlines and gathering lines, 2-32
OWS, 5-10
Piping requirements, 4-15
Qualified facility
Appendix G template, 1-23, 4-47, 6-6, 7-9
Deviation from industry standard, 7-46, 7-47
Eligibility criteria, 1-19
Facility diagram, 6-6
Self-certification, 1-18,1-19, 3-1, 3-14, 3-23, 4-14, 4-
40, 7-9, 7-10
Tier 1,1-23, 6-6, 7-46
Tier II, 1-19, 6-6, 6-22, 7-46
Qualified oil-filled operational equipment
Alternative measures, 4-13
Eligibility criteria, 1-20, 4-12
Qualified facility, 4-14
Quick drainage system
Secondary containment example, 4-38, 4-54, 4-55, 5-7,
6-3
Rack
Loading/unloading, 1-10,1-22,1-23,1-24,1-25, 2-28,
2-30, 2-45, 3-3, 3-27, 3-28, 4-1, 4-3, 4-5, 4-16, 4-38,
4-39, 4-51, 4-54, 4-55, 4-56, 4-57, 4-1, 5-7, 6-3, 6-6,
6-12
Railroad car, 2-29, 2-30, 4-38, 4-61
RCRA. See Resource Conservation and Recovery Act
Reconstructed tank, 7-55
Remote impoundment
Secondary containment example, 4-33, 4-46, 4-58
Renewable fuel, 2-7, 2-8
Repair
Definition, 4-38
Reportable discharge history, 4-11, 4-12
Reporting requirement
Discharge, 4-26, 6-4
SPCC, 2-34, 4-12, 4-65, 5-13, 6-5
Re-rating
Tank. See Storage capacity, tank re-rating
Resource Conservation and Recovery Act, 2-7, 2-41, 2-44
Retaining wall
SPCC GUIDANCE FOR REGIONAL INSPECTORS
November 15, 2013
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Secondary containment example, 4-9, 4-33
Retention pond
Secondary containment example, 4-10
Saltwater disposal facility, 3-34, 5-3
Secondary containment
Calculation, 4-8, 4-18, 4-20, 4-21, 4-22, 4-23, 4-36, 4-
53, 6-13
Example method, 4-9
Most likely quantity discharged, 4-7, 4-8, 4-25, 4-28, 4-
50, 4-51, 4-64, 4-66
Security, 1-19, 1-23, 2-54, 3-19, 3-20, 3-21
Self-certified Plan. See Qualified facility, Self-certification
Sheen, 2-33
Ships and barges, 2-31, 2-32
Shop-built containers. See Shop-fabricated containers
Shop-fabricated containers, 7-18
Single-family residence, heating oil container
Exemption, 1-22, 2-10, 2-21, 2-23, 2-49
Sorbent
Secondary containment example, 4-10, 4-24, 4-25, 4-
26, 4-27, 4-28, 4-34, 4-50
SPCC Plan review, 1-9,1-18
Spill diversion pond
Secondary containment example, 4-10
Spill mat
Secondary containment example, 4-9, 4-34
Storage capacity, 2-39, 2-40, 7-53
Alteration, 2-38, 2-39, 2-40, 7-52, 7-53, 7-54, 7-55
Applicability, 1-2
Container, 2-37, 2-38, 2-39, 2-40, 7-52
Facility, 1-6, 1-19, 1-21, 1-22, 1-23, 1-27, 2-1, 2-2, 2-6,
2-7, 2-10, 2-16, 2-17, 2-21, 2-22, 2-23, 2-24, 2-26, 2-
27, 2-29, 2-30, 2-37, 2-40, 2-46, 2-49, 2-50, 2-51, 2-
52, 2-53, 2-58, 4-45, 5-2, 5-3, 5-5, 5-8, 5-12, 5-18, 6-
2
Tank re-rating, 2-39, 7-52
Sufficient freeboard, 2-57, 4-17, 4-19, 4-20, 4-21, 4-58, 4-
59, 4-61, 4-64, 4-66, 5-8, 6-3
Role of EPA Inspector, 4-23
Sufficiently impervious, 4-2, 4-29, 4-30, 4-36, 4-58
Role of EPA Inspector, 4-31
Sump
Secondary containment example, 7-32
Synthetic oil, 2-4, 2-7
Tank battery, 2-12, 2-14, 2-17, 2-18, 2-19, 2-26, 2-32, 2-
57, 2-58, 4-15, 4-51, 4-61, 4-62, 4-64, 4-65, 6-18
Tank tightness testing. See Leak testing
Technical Standards and Corrective Action Requirements
for Owners and Operators of Underground Storage
Tanks
40 CFR part 280, 2-43
Transformer, 2-9, 2-23, 2-37, 2-55, 3-7, 4-8, 4-27, 5-12, 6-
6, 6-16
Transportation of Hazardous Liquids by Pipeline
40 CFR part 195, 2-51
Transportation of Natural and Other Gas by Pipeline
49 CFR part 192, 2-51
Underground storage tank, 1-18, 2-7, 2-14, 2-43, 2-45, 2-
49, 3-9, 3-13, 6-6, 6-9
United States Coast Guard, 2-4, 2-10, 2-28, 2-30, 2-31
USCG. See United States Coast Guard
UST. See Underground storage tank
Valve
Flapper design, 3-6
Open-and-closed design, 3-6
Vandalism, 3-19, 3-20, 3-21
Vaulted tank, 2-45, 2-54, 4-36, 4-37, 6-9, 7-11
Vegetable oil, 1-5,1-10,1-18,1-21,1-24, 2-4, 2-5, 2-44,
3-6, 3-12, 3-21, 4-14, 4-37, 4-59, 5-3, 7-2, 7-10, 7-15
Vessel. See Ships and barges
Visible discharge
Promptly correct, 7-14
Wastewater treatment exemption, 5-14
SPCC GUIDANCE FOR REGIONAL INSPECTORS
November 15, 2013
-------
Weir
Secondary containment example, 4-9, 4-33
Wellhead, 2-6, 2-12, 2-17, 2-18, 2-19, 2-24, 2-25, 2-57, 4-
15, 4-62
Wet gas, 2-24, 2-25, 3-8, 5-5
Wind turbine, 1-25, 2-55
Workover
Activity, 2-13, 2-14, 2-42, 2-48, 4-6, 4-7, 4-63
Written commitment of manpower, equipment, and
materials, 1-18,1-20, 2-57, 4-13, 4-14,4-15,4-27,4-
41, 4-42, 4-43, 4-65, 4-69, 7-23, 7-31
SPCC GUIDANCE FOR REGIONAL INSPECTORS
November 15, 2013
-------
Appendix A: CWA 311(j)(l)(c)
SPCC GUIDANCE FOR REGIONAL INSPECTORS
November 15, 2013
-------
CWA§§311(j)(l)(c)
Summary:
The President is authorized to issue regulations establishing procedures, methods,
equipment, and other requirements to prevent discharges of oil from vessels and facilities.
Rule Text:
(j) National Response System
(1) In general
Consistent with the National Contingency Plan required by subsection
(c)(2) of this section, as soon as practicable after October 18, 1972, and
from time to time thereafter, the President shall issue regulations
consistent with maritime safety and with marine and navigation laws
(c)
establishing procedures, methods, and equipment and other
requirements for equipment to prevent discharges of oil and
hazardous substances from vessels and from onshore facilities and
off shore facilities, and to contain such discharges...
-------
Appendix B: Selected Regulations
• 40 CFR part 109: Criteria for State, Local and Regional Oil Removal Contingency Plans
• 40 CFR part 110: Discharge of Oil
• 40 CFR part 112: Oil Pollution Prevention
Copies of the regulations provided in this appendix are current as of the publication of this guidance. Since the
regulations are subject to change, the appendix is provided for informational purposes only.
The Federal Register-the official daily publication for rules, proposed rules, and notices of federal agencies and
organizations - is available electronically from the U.S. Government Printing Office Web site at
http://www.gpoaccess.gov/fr/.
General and permanent rules published in the Federal Register are codified in the Code of Federal Regulations (CFR),
available electronically at http://www.gpoaccess.gov/cfr/. Each volume of the CFR is updated once each calendar year
and is issued on a quarterly basis.
For a more frequently updated version of the CFR, refer to the Electronic Code of Federal Regulations (e-CFR) at
http://www.gpoaccess.gov/ecfr/. The e-CFR is updated daily but is not an official legal edition of the CFR.
Inspectors implementing the SPCC program should always consult the aforementioned resources (or their equivalent) to
obtain the current version of the regulations.
SPCC GUIDANCE FOR REGIONAL INSPECTORS
November 15, 2013
-------
Environmental Protection Agency
§109.2
Law Judge, on his own motion, or at
the request of any party, shall have the
power to hold prehearing conferences,
to issue subpoenas for the attendance
and testimony of witnesses and the
production of relevant papers, books,
and documents, and he may administer
oaths. The Regional Administrator,
and any party submitting a request
pursuant to §108.3 or §108.4, or counsel
or other representative of such party
or the Regional Administrator, may
appear and offer evidence at the hear-
ing.
§ 108.6 Recommendations.
At the conclusion of any hearing
under this part, the Administrative
Law Judge shall, based on the record,
issue tentative findings of fact and rec-
ommendations concerning the alleged
discrimination, and shall submit such
tentative findings and recommenda-
tions to the Administrator. The Ad-
ministrator shall adopt or modify the
findings and recommendations of the
Administrative Law Judge, and shall
make copies of such findings and rec-
ommendations available to the com-
plaining employee, the employer, and
the public.
§ 108.7 Hearing before Administrator.
At his option, the Administrator may
exercise any powers of an Administra-
tive Law Judge with respect to hear-
ings under this part.
PART 109—CRITERIA FOR STATE,
LOCAL AND REGIONAL OIL RE-
MOVAL CONTINGENCY PLANS
Sec.
109.1 Applicability.
109.2 Definitions.
109.3 Purpose and scope.
109.4 Relationship to Federal response ac-
tions.
109.5 Development and implementation cri-
teria for State, local and regional oil re-
moval contingency plans.
109.6 Coordination.
AUTHORITY: Sec. ll(j)(l)(B), 84 Stat. 96, 33
U.S.C. 1161(j)(l)(B).
SOURCE: 36 FR 22485, Nov. 25, 1971, unless
otherwise noted.
§ 109.1 Applicability.
The criteria in this part are provided
to assist State, local and regional
agencies in the development of oil re-
moval contingency plans for the inland
navigable waters of the United States
and all areas other than the high seas,
coastal and contiguous zone waters,
coastal and Great Lakes ports and har-
bors and such other areas as may be
agreed upon between the Environ-
mental Protection Agency and the De-
partment of Transportation in accord-
ance with section ll(j)(l)(B) of the Fed-
eral Act, Executive Order No. 11548
dated July 20, 1970 (35 FR 11677) and
§306.2 of the National Oil and Haz-
ardous Materials Pollution Contin-
gency Plan (35 FR 8511).
§ 109.2 Definitions.
As used in these guidelines, the fol-
lowing terms shall have the meaning
indicated below:
(a) Oil means oil of any kind or in
any form, including, but not limited to,
petroleum, fuel oil, sludge, oil refuse,
and oil mixed with wastes other than
dredged spoil.
(b) Discharge includes, but is not lim-
ited to, any spilling, leaking, pumping,
pouring, emitting, emptying, or dump-
ing.
(c) Remove or removal refers to the re-
moval of the oil from the water and
shorelines or the taking of such other
actions as may be necessary to mini-
mize or mitigate damage to the public
health or welfare, including, but not
limited to, fish, shellfish, wildlife, and
public and private property, shorelines,
and beaches.
(d) Major disaster means any hurri-
cane, tornado, storm, flood, high water,
wind-driven water, tidal wave, earth-
quake, drought, fire, or other catas-
trophe in any part of the United States
which, in the determination of the
President, is or threatens to become of
sufficient severity and magnitude to
warrant disaster assistance by the Fed-
eral Government to supplement the ef-
forts and available resources of States
and local governments and relief orga-
nizations in alleviating the damage,
loss, hardship, or suffering caused
thereby.
15
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§109.3
40 CFR Ch. I (7-1-13 Edition)
(e) United States means the States,
the District of Columbia, the Common-
wealth of Puerto Rico, the Canal Zone,
Guam, American Samoa, the Virgin Is-
lands, and the Trust Territory of the
Pacific Islands.
(f) Federal Act means the Federal
Water Pollution Control Act, as
amended, 33 U.S.C. 1151 et seg.
§ 109.3 Purpose and scope.
The guidelines in this part establish
minimum criteria for the development
and implementation of State, local,
and regional contingency plans by
State and local governments in con-
sultation with private interests to in-
sure timely, efficient, coordinated and
effective action to minimize damage
resulting from oil discharges. Such
plans will be directed toward the pro-
tection of the public health or welfare
of the United States, including, but not
limited to, fish, shellfish, wildlife, and
public and private property, shorelines,
and beaches. The development and im-
plementation of such plans shall be
consistent with the National Oil and
Hazardous Materials Pollution Contin-
gency Plan. State, local and regional
oil removal contingency plans shall
provide for the coordination of the
total response to an oil discharge so
that contingency organizations estab-
lished thereunder can function inde-
pendently, in conjunction with each
other, or in conjunction with the Na-
tional and Regional Response Teams
established by the National Oil and
Hazardous Materials Pollution Contin-
gency Plan.
§ 109.4 Relationship to Federal re-
sponse actions.
The National Oil and Hazardous Ma-
terials Pollution Contingency Plan
provides that the Federal on-scene
commander shall investigate all re-
ported spills. If such investigation
shows that appropriate action is being
taken by either the discharger or non-
Federal entities, the Federal on-scene
commander shall monitor and provide
advice or assistance, as required. If ap-
propriate containment or cleanup ac-
tion is not being taken by the dis-
charger or non-Federal entities, the
Federal on-scene commander will take
control of the response activity in ac-
cordance with section ll(c)(l) of the
Federal Act.
§ 109.5 Development and implementa-
tion criteria for State, local and re-
gional oil removal contingency
plans.
Criteria for the development and im-
plementation of State, local and re-
gional oil removal contingency plans
are:
(a) Definition of the authorities, re-
sponsibilities and duties of all persons,
organizations or agencies which are to
be involved or could be involved in
planning or directing oil removal oper-
ations, with particular care to clearly
define the authorities, responsibilities
and duties of State and local govern-
mental agencies to avoid unnecessary
duplication of contingency planning
activities and to minimize the poten-
tial for conflict and confusion that
could be generated in an emergency
situation as a result of such duplica-
tions.
(b) Establishment of notification pro-
cedures for the purpose of early detec-
tion and timely notification of an oil
discharge including:
(1) The identification of critical
water use areas to facilitate the report-
ing of and response to oil discharges.
(2) A current list of names, telephone
numbers and addresses of the respon-
sible persons and alternates on call to
receive notification of an oil discharge
as well as the names, telephone num-
bers and addresses of the organizations
and agencies to be notified when an oil
discharge is discovered.
(3) Provisions for access to a reliable
communications system for timely no-
tification of an oil discharge and incor-
poration in the communications sys-
tem of the capability for interconnec-
tion with the communications systems
established under related oil removal
contingency plans, particularly State
and National plans.
(4) An established, prearranged proce-
dure for requesting assistance during a
major disaster or when the situation
exceeds the response capability of the
State, local or regional authority.
(c) Provisions to assure that full re-
source capability is known and can be
committed during an oil discharge sit-
uation including:
16
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Environmental Protection Agency
§110.1
(1) The identification and inventory
of applicable equipment, materials and
supplies which are available locally
and regionally.
(2) An estimate of the equipment,
materials and supplies which would be
required to remove the maximum oil
discharge to be anticipated.
(3) Development of agreements and
arrangements in advance of an oil dis-
charge for the acquisition of equip-
ment, materials and supplies to be used
in responding to such a discharge.
(d) Provisions for well defined and
specific actions to be taken after dis-
covery and notification of an oil dis-
charge including:
(1) Specification of an oil discharge
response operating team consisting of
trained, prepared and available oper-
ating personnel.
(2) Predesignation of a properly
qualified oil discharge response coordi-
nator who is charged with the responsi-
bility and delegated commensurate au-
thority for directing and coordinating
response operations and who knows
how to request assistance from Federal
authorities operating under existing
national and regional contingency
plans.
(3) A preplanned location for an oil
discharge response operations center
and a reliable communications system
for directing the coordinated overall
response operations.
(4) Provisions for varying degrees of
response effort depending on the sever-
ity of the oil discharge.
(5) Specification of the order of pri-
ority in which the various water uses
are to be protected where more than
one water use may be adversely af-
fected as a result of an oil discharge
and where response operations may not
be adequate to protect all uses.
(e) Specific and well defined proce-
dures to facilitate recovery of damages
and enforcement measures as provided
for by State and local statutes and or-
dinances.
§ 109.6 Coordination.
For the purposes of coordination, the
contingency plans of State and local
governments should be developed and
implemented in consultation with pri-
vate interests. A copy of any oil re-
moval contingency plan developed by
State and local governments should be
forwarded to the Council on Environ-
mental Quality upon request to facili-
tate the coordination of these contin-
gency plans with the National Oil and
Hazardous Materials Pollution Contin-
gency Plan.
PART 110—DISCHARGE OF OIL
Sec.
110.1 Definitions.
110.2 Applicability.
110.3 Discharge of oil in such quantities as
"may be harmful" pursuant to section
311(b)(4) of the Act.
110.4 Dispersants.
110.5 Discharges of oil not determined "as
may be harmful" pursuant to section
311(b)(3) of the Act.
110.6 Notice.
AUTHORITY: 33 U.S.C. 1321(b)(3) and (b)(4)
and 1361(a); E.G. 11735, 38 FR 21243, 3 CFR
Parts 1971-1975 Comp., p. 793.
SOURCE: 52 FR 10719, Apr. 2, 1987, unless
otherwise noted.
§110.1 Definitions.
Terms not defined in this section
have the same meaning given by the
Section 311 of the Act. As used in this
part, the following terms shall have
the meaning indicated below:
Act means the Federal Water Pollu-
tion Control Act, as amended, 33 U.S.C.
1251 et seg., also known as the Clean
Water Act;
Administrator means the Adminis-
trator of the Environmental Protection
Agency (EPA);
Applicable water quality standards
means State water quality standards
adopted by the State pursuant to sec-
tion 303 of the Act or promulgated by
EPA pursuant to that section;
MARPOL 73/78 means the Inter-
national Convention for the Prevention
of Pollution from Ships, 1973, as modi-
fied by the Protocol of 1978 relating
thereto, Annex I, which regulates pol-
lution from oil and which entered into
force on October 2, 1983;
Navigable waters means the waters of
the United States, including the terri-
torial seas. The term includes:
(a) All waters that are currently
used, were used in the past, or may be
susceptible to use in interstate or for-
eign commerce, including all waters
17
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Environmental Protection Agency
§110.1
(1) The identification and inventory
of applicable equipment, materials and
supplies which are available locally
and regionally.
(2) An estimate of the equipment,
materials and supplies which would be
required to remove the maximum oil
discharge to be anticipated.
(3) Development of agreements and
arrangements in advance of an oil dis-
charge for the acquisition of equip-
ment, materials and supplies to be used
in responding to such a discharge.
(d) Provisions for well defined and
specific actions to be taken after dis-
covery and notification of an oil dis-
charge including:
(1) Specification of an oil discharge
response operating team consisting of
trained, prepared and available oper-
ating personnel.
(2) Predesignation of a properly
qualified oil discharge response coordi-
nator who is charged with the responsi-
bility and delegated commensurate au-
thority for directing and coordinating
response operations and who knows
how to request assistance from Federal
authorities operating under existing
national and regional contingency
plans.
(3) A preplanned location for an oil
discharge response operations center
and a reliable communications system
for directing the coordinated overall
response operations.
(4) Provisions for varying degrees of
response effort depending on the sever-
ity of the oil discharge.
(5) Specification of the order of pri-
ority in which the various water uses
are to be protected where more than
one water use may be adversely af-
fected as a result of an oil discharge
and where response operations may not
be adequate to protect all uses.
(e) Specific and well defined proce-
dures to facilitate recovery of damages
and enforcement measures as provided
for by State and local statutes and or-
dinances.
§ 109.6 Coordination.
For the purposes of coordination, the
contingency plans of State and local
governments should be developed and
implemented in consultation with pri-
vate interests. A copy of any oil re-
moval contingency plan developed by
State and local governments should be
forwarded to the Council on Environ-
mental Quality upon request to facili-
tate the coordination of these contin-
gency plans with the National Oil and
Hazardous Materials Pollution Contin-
gency Plan.
PART 110—DISCHARGE OF OIL
Sec.
110.1 Definitions.
110.2 Applicability.
110.3 Discharge of oil in such quantities as
"may be harmful" pursuant to section
311(b)(4) of the Act.
110.4 Dispersants.
110.5 Discharges of oil not determined "as
may be harmful" pursuant to section
311(b)(3) of the Act.
110.6 Notice.
AUTHORITY: 33 U.S.C. 1321(b)(3) and (b)(4)
and 1361(a); E.G. 11735, 38 FR 21243, 3 CFR
Parts 1971-1975 Comp., p. 793.
SOURCE: 52 FR 10719, Apr. 2, 1987, unless
otherwise noted.
§110.1 Definitions.
Terms not defined in this section
have the same meaning given by the
Section 311 of the Act. As used in this
part, the following terms shall have
the meaning indicated below:
Act means the Federal Water Pollu-
tion Control Act, as amended, 33 U.S.C.
1251 et seg., also known as the Clean
Water Act;
Administrator means the Adminis-
trator of the Environmental Protection
Agency (EPA);
Applicable water quality standards
means State water quality standards
adopted by the State pursuant to sec-
tion 303 of the Act or promulgated by
EPA pursuant to that section;
MARPOL 73/78 means the Inter-
national Convention for the Prevention
of Pollution from Ships, 1973, as modi-
fied by the Protocol of 1978 relating
thereto, Annex I, which regulates pol-
lution from oil and which entered into
force on October 2, 1983;
Navigable waters means the waters of
the United States, including the terri-
torial seas. The term includes:
(a) All waters that are currently
used, were used in the past, or may be
susceptible to use in interstate or for-
eign commerce, including all waters
17
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§110.2
40 CFR Ch. I (7-1-13 Edition)
that are subject to the ebb and flow of
the tide;
(b) Interstate waters, including inter-
state wetlands;
(c) All other waters such as intra-
state lakes, rivers, streams (including
intermittent streams), mudflats,
sandflats, and wetlands, the use, deg-
radation, or destruction of which would
affect or could affect interstate or for-
eign commerce including any such
waters:
(1) That are or could be used by inter-
state or foreign travelers for rec-
reational or other purposes;
(2) From which fish or shellfish are or
could be taken and sold in interstate or
foreign commerce;
(3) That are used or could be used for
industrial purposes by industries in
interstate commerce;
(d) All impoundments of waters oth-
erwise defined as navigable waters
under this section;
(e) Tributaries of waters identified in
paragraphs (a) through (d) of this sec-
tion, including adjacent wetlands; and
(f) Wetlands adjacent to waters iden-
tified in paragraphs (a) through (e) of
this section: Provided, That waste
treatment systems (other than cooling
ponds meeting the criteria of this para-
graph) are not waters of the United
States;
Navigable waters do not include prior
converted cropland. Notwithstanding
the determination of an area's status
as prior converted cropland by any
other federal agency, for the purposes
of the Clean Water Act, the final au-
thority regarding Clean Water Act ju-
risdiction remains with EPA.
NPDES means National Pollutant
Discharge Elimination System;
Sheen means an iridescent appear-
ance on the surface of water;
Sludge means an aggregate of oil or
oil and other matter of any kind in any
form other than dredged spoil having a
combined specific gravity equivalent to
or greater than water;
United States means the States, the
District of Columbia, the Common-
wealth of Puerto Rico, Guam, Amer-
ican Samoa, the Virgin Islands, and the
Trust Territory of the Pacific Islands;
Wetlands means those areas that are
inundated or saturated by surface or
ground water at a frequency or dura-
tion sufficient to support, and that
under normal circumstances do sup-
port, a prevalence of vegetation typi-
cally adapted for life in saturated soil
conditions. Wetlands generally include
playa lakes, swamps, marshes, bogs
and similar areas such as sloughs, prai-
rie potholes, wet meadows, prairie
river overflows, mudflats, and natural
ponds.
[52 FR 10719, Apr. 2, 1987, as amended at 58
FR 45039, Aug. 25, 1993; 61 FR 7421, Feb. 28,
1996]
§110.2 Applicability.
The regulations of this part apply to
the discharge of oil prohibited by sec-
tion 311(b)(3) of the Act.
[61 FR 7421, Feb. 28, 1996]
§110.3 Discharge of oil in such quan-
tities as "may be harmful" pursuant
to section 311(b)(4) of the Act.
For purposes of section 311(b)(4) of
the Act, discharges of oil in such quan-
tities that the Administrator has de-
termined may be harmful to the public
health or welfare or the environment of
the United States include discharges of
oil that:
(a) Violate applicable water quality
standards; or
(b) Cause a film or sheen upon or dis-
coloration of the surface of the water
or adjoining shorelines or cause a
sludge or emulsion to be deposited be-
neath the surface of the water or upon
adjoining shorelines.
[61 FR 7421, Feb. 28, 1996]
§110.4 Dispersants.
Addition of dispersants or emulsifiers
to oil to be discharged that would cir-
cumvent the provisions of this part is
prohibited.
[52 FR 10719, Apr. 2, 1987. Redesignated at 61
FR 7421, Feb. 28, 1996]
§110.5 Discharges of oil not deter-
mined "as may be harmful" pursu-
ant to Section 311(b)(3) of the Act.
Notwithstanding any other provi-
sions of this part, the Administrator
has not determined the following dis-
charges of oil "as may be harmful" for
purposes of section 311(b) of the Act:
(a) Discharges of oil from a properly
functioning vessel engine (including an
18
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Environmental Protection Agency
Pt. 112
engine on a public vessel) and any dis-
charges of such oil accumulated in the
bilges of a vessel discharged in compli-
ance with MARPOL 73/78, Annex I, as
provided in 33 CFR part 151, subpart A;
(b) Other discharges of oil permitted
under MARPOL 73/78, Annex I, as pro-
vided in 33 CFR part 151, subpart A; and
(c) Any discharge of oil explicitly
permitted by the Administrator in con-
nection with research, demonstration
projects, or studies relating to the pre-
vention, control, or abatement of oil
pollution.
[61 FR 7421, Feb. 28, 1996]
§110.6 Notice.
Any person in charge of a vessel or of
an onshore or offshore facility shall, as
soon as he or she has knowledge of any
discharge of oil from such vessel or fa-
cility in violation of section 311(b)(3) of
the Act, immediately notify the Na-
tional Response Center (NRC) (80CM24-
8802; in the Washington, DC metropoli-
tan area, 202-426-2675). If direct report-
ing to the NRC is not practicable, re-
ports may be made to the Coast Guard
or EPA predesignated On-Scene Coordi-
nator (OSC) for the geographic area
where the discharge occurs. All such
reports shall be promptly relayed to
the NRC. If it is not possible to notify
the NRC or the predesignated OCS im-
mediately, reports may be made imme-
diately to the nearest Coast Guard
unit, provided that the person in
charge of the vessel or onshore or off-
shore facility notifies the NRC as soon
as possible. The reports shall be made
in accordance with such procedures as
the Secretary of Transportation may
prescribe. The procedures for such no-
tice are set forth in U.S. Coast Guard
regulations, 33 CFR part 153, subpart B
and in the National Oil and Hazardous
Substances Pollution Contingency
Plan, 40 CFR part 300, subpart E.
(Approved by the Office of Management and
Budget under control number 2050-0046)
[52 FR 10719, Apr. 2, 1987. Redesignated and
amended at 61 FR 7421, Feb. 28, 1996; 61 FR
14032, Mar. 29, 1996]
PART 112—OIL POLLUTION
PREVENTION
Subpart A—Applicability, Definitions, and
General Requirements For All Facilities
and All Types of Oils
Sec.
112.1 General applicability.
112.2 Definitions.
112.3 Requirement to prepare and imple-
ment a Spill Prevention, Control, and
Countermeasure Plan.
112.4 Amendment of Spill Prevention, Con-
trol, and Countermeasure Plan by Re-
gional Administrator.
112.5 Amendment of Spill Prevention, Con-
trol, and Countermeasure Plan by owners
or operators.
112.6 Qualified Facility Plan Requirements.
112.7 General requirements for Spill Preven-
tion, Control, and Countermeasure
Plans.
Subpart B—Requirements for Petroleum
Oils and Non-Petroleum Oils, Except
Animal Fats and Oils and Greases,
and Fish and Marine Mammal Oils;
and Vegetable Oils (Including Oils
from Seeds, Nuts, Fruits, and Kernels)
112.8 Spill Prevention, Control, and Coun-
termeasure Plan requirements for on-
shore facilities (excluding production fa-
cilities).
112.9 Spill Prevention, Control, and Coun-
termeasure Plan Requirements for on-
shore oil production facilities (excluding
drilling and workover facilities).
112.10 Spill Prevention, Control, and Coun-
termeasure Plan requirements for on-
shore oil drilling and workover facilities.
112.11 Spill Prevention, Control, and Coun-
termeasure Plan requirements for off-
shore oil drilling, production, or
workover facilities.
Subpart C—Requirements for Animal Fats
and Oils and Greases, and Fish and
Marine Mammal Oils; and for Vege-
table Oils, Including Oils from Seeds,
Nuts, Fruits and Kernels
112.12 Spill Prevention, Control, and Coun-
termeasure Plan requirements.
112.13-112.15 [Reserved]
Subpart D—Response Requirements
112.20 Facility response plans.
112.21 Facility response training and drills/
exercises.
APPENDIX A TO PART 112—MEMORANDUM OF
UNDERSTANDING BETWEEN THE SECRETARY
19
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Environmental Protection Agency
Pt. 112
engine on a public vessel) and any dis-
charges of such oil accumulated in the
bilges of a vessel discharged in compli-
ance with MARPOL 73/78, Annex I, as
provided in 33 CFR part 151, subpart A;
(b) Other discharges of oil permitted
under MARPOL 73/78, Annex I, as pro-
vided in 33 CFR part 151, subpart A; and
(c) Any discharge of oil explicitly
permitted by the Administrator in con-
nection with research, demonstration
projects, or studies relating to the pre-
vention, control, or abatement of oil
pollution.
[61 FR 7421, Feb. 28, 1996]
§110.6 Notice.
Any person in charge of a vessel or of
an onshore or offshore facility shall, as
soon as he or she has knowledge of any
discharge of oil from such vessel or fa-
cility in violation of section 311(b)(3) of
the Act, immediately notify the Na-
tional Response Center (NRC) (80CM24-
8802; in the Washington, DC metropoli-
tan area, 202-426-2675). If direct report-
ing to the NRC is not practicable, re-
ports may be made to the Coast Guard
or EPA predesignated On-Scene Coordi-
nator (OSC) for the geographic area
where the discharge occurs. All such
reports shall be promptly relayed to
the NRC. If it is not possible to notify
the NRC or the predesignated OCS im-
mediately, reports may be made imme-
diately to the nearest Coast Guard
unit, provided that the person in
charge of the vessel or onshore or off-
shore facility notifies the NRC as soon
as possible. The reports shall be made
in accordance with such procedures as
the Secretary of Transportation may
prescribe. The procedures for such no-
tice are set forth in U.S. Coast Guard
regulations, 33 CFR part 153, subpart B
and in the National Oil and Hazardous
Substances Pollution Contingency
Plan, 40 CFR part 300, subpart E.
(Approved by the Office of Management and
Budget under control number 2050-0046)
[52 FR 10719, Apr. 2, 1987. Redesignated and
amended at 61 FR 7421, Feb. 28, 1996; 61 FR
14032, Mar. 29, 1996]
PART 112—OIL POLLUTION
PREVENTION
Subpart A—Applicability, Definitions, and
General Requirements For All Facilities
and All Types of Oils
Sec.
112.1 General applicability.
112.2 Definitions.
112.3 Requirement to prepare and imple-
ment a Spill Prevention, Control, and
Countermeasure Plan.
112.4 Amendment of Spill Prevention, Con-
trol, and Countermeasure Plan by Re-
gional Administrator.
112.5 Amendment of Spill Prevention, Con-
trol, and Countermeasure Plan by owners
or operators.
112.6 Qualified Facility Plan Requirements.
112.7 General requirements for Spill Preven-
tion, Control, and Countermeasure
Plans.
Subpart B—Requirements for Petroleum
Oils and Non-Petroleum Oils, Except
Animal Fats and Oils and Greases,
and Fish and Marine Mammal Oils;
and Vegetable Oils (Including Oils
from Seeds, Nuts, Fruits, and Kernels)
112.8 Spill Prevention, Control, and Coun-
termeasure Plan requirements for on-
shore facilities (excluding production fa-
cilities).
112.9 Spill Prevention, Control, and Coun-
termeasure Plan Requirements for on-
shore oil production facilities (excluding
drilling and workover facilities).
112.10 Spill Prevention, Control, and Coun-
termeasure Plan requirements for on-
shore oil drilling and workover facilities.
112.11 Spill Prevention, Control, and Coun-
termeasure Plan requirements for off-
shore oil drilling, production, or
workover facilities.
Subpart C—Requirements for Animal Fats
and Oils and Greases, and Fish and
Marine Mammal Oils; and for Vege-
table Oils, Including Oils from Seeds,
Nuts, Fruits and Kernels
112.12 Spill Prevention, Control, and Coun-
termeasure Plan requirements.
112.13-112.15 [Reserved]
Subpart D—Response Requirements
112.20 Facility response plans.
112.21 Facility response training and drills/
exercises.
APPENDIX A TO PART 112—MEMORANDUM OF
UNDERSTANDING BETWEEN THE SECRETARY
19
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§112.1
40 CFR Ch. I (7-1-13 Edition)
OF TRANSPORTATION AND THE ADMINIS-
TRATOR OF THE ENVIRONMENTAL PROTEC-
TION AGENCY
APPENDIX B TO PART 112—MEMORANDUM OF
UNDERSTANDING AMONG THE SECRETARY
OF THE INTERIOR, SECRETARY OF TRANS-
PORTATION, AND ADMINISTRATOR OF THE
ENVIRONMENTAL PROTECTION AGENCY
APPENDIX C TO PART 112—SUBSTANTIAL HARM
CRITERIA
APPENDIX D TO PART 112—DETERMINATION OF
A WORST CASE DISCHARGE PLANNING VOL-
UME
APPENDIX E TO PART 112—DETERMINATION
AND EVALUATION OF REQUIRED RESPONSE
RESOURCES FOR FACILITY RESPONSE
PLANS
APPENDIX F TO PART 112—FACILITY-SPECIFIC
RESPONSE PLAN
APPENDIX G TO PART 112—TIER I QUALIFIED
FACILITY SPCC PLAN
AUTHORITY: 33 U.S.C. 1251 et seg.; 33 U.S.C.
2720; E.G. 12777 (October 18, 1991), 3 CFR, 1991
Comp., p. 351.
SOURCE: 38 FR 34165, Dec. 11, 1973, unless
otherwise noted.
EDITORIAL NOTE: Nomenclature changes to
part 112 appear at 65 FR 40798, June 30, 2000.
Subpart A—Applicability, Defini-
tions, and General Require-
ments for All Facilities and All
Types of Oils
SOURCE: 67 FR 47140, July 17, 2002, unless
otherwise noted.
§ 112.1 General applicability.
(a)(l) This part establishes proce-
dures, methods, equipment, and other
requirements to prevent the discharge
of oil from non-transportation-related
onshore and offshore facilities into or
upon the navigable waters of the
United States or adjoining shorelines,
or into or upon the waters of the con-
tiguous zone, or in connection with ac-
tivities under the Outer Continental
Shelf Lands Act or the Deepwater Port
Act of 1974, or that may affect natural
resources belonging to, appertaining
to, or under the exclusive management
authority of the United States (includ-
ing resources under the Magnuson
Fishery Conservation and Management
Act).
(2) As used in this part, words in the
singular also include the plural and
words in the masculine gender also in-
clude the feminine and vice versa, as
the case may require.
(b) Except as provided in paragraph
(d) of this section, this part applies to
any owner or operator of a non-trans-
portation-related onshore or offshore
facility engaged in drilling, producing,
gathering, storing, processing, refining,
transferring, distributing, using, or
consuming oil and oil products, which
due to its location, could reasonably be
expected to discharge oil in quantities
that may be harmful, as described in
part 110 of this chapter, into or upon
the navigable waters of the United
States or adjoining shorelines, or into
or upon the waters of the contiguous
zone, or in connection with activities
under the Outer Continental Shelf
Lands Act or the Deepwater Port Act
of 1974, or that may affect natural re-
sources belonging to, appertaining to,
or under the exclusive management au-
thority of the United States (including
resources under the Magnuson Fishery
Conservation and Management Act)
that has oil in:
(1) Any aboveground container;
(2) Any completely buried tank as de-
fined in §112.2;
(3) Any container that is used for
standby storage, for seasonal storage,
or for temporary storage, or not other-
wise "permanently closed" as defined
in §112.2;
(4) Any "bunkered tank" or "par-
tially buried tank" as defined in §112.2,
or any container in a vault, each of
which is considered an aboveground
storage container for purposes of this
part.
(c) As provided in section 313 of the
Clean Water Act (CWA), departments,
agencies, and instrumentalities of the
Federal government are subject to this
part to the same extent as any person.
(d) Except as provided in paragraph
(f) of this section, this part does not
apply to:
(1) The owner or operator of any fa-
cility, equipment, or operation that is
not subject to the jurisdiction of the
Environmental Protection Agency
(EPA) under section 311(j)(l)(C) of the
CWA, as follows:
(i) Any onshore or offshore facility,
that due to its location, could not rea-
sonably be expected to have a dis-
charge as described in paragraph (b) of
20
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Environmental Protection Agency
§112.1
this section. This determination must
be based solely upon consideration of
the geographical and location aspects
of the facility (such as proximity to
navigable waters or adjoining shore-
lines, land contour, drainage, etc.) and
must exclude consideration of man-
made features such as dikes, equipment
or other structures, which may serve
to restrain, hinder, contain, or other-
wise prevent a discharge as described
in paragraph (b) of this section.
(ii) Any equipment, or operation of a
vessel or transportation-related on-
shore or offshore facility which is sub-
ject to the authority and control of the
U.S. Department of Transportation, as
defined in the Memorandum of Under-
standing between the Secretary of
Transportation and the Administrator
of EPA, dated November 24, 1971 (ap-
pendix A of this part).
(ill) Any equipment, or operation of a
vessel or onshore or offshore facility
which is subject to the authority and
control of the U.S. Department of
Transportation or the U.S. Department
of the Interior, as defined in the Memo-
randum of Understanding between the
Secretary of Transportation, the Sec-
retary of the Interior, and the Admin-
istrator of EPA, dated November 8, 1993
(appendix B of this part).
(2) Any facility which, although oth-
erwise subject to the jurisdiction of
EPA, meets both of the following re-
quirements:
(i) The completely buried storage ca-
pacity of the facility is 42,000 U.S. gal-
lons or less of oil. For purposes of this
exemption, the completely buried stor-
age capacity of a facility excludes the
capacity of a completely buried tank,
as defined in §112.2, and connected un-
derground piping, underground ancil-
lary equipment, and containment sys-
tems, that is currently subject to all of
the technical requirements of part 280
of this chapter or all of the technical
requirements of a State program ap-
proved under part 281 of this chapter,
or the capacity of any underground oil
storage tanks deferred under 40 CFR
part 280 that supply emergency diesel
generators at a nuclear power genera-
tion facility licensed by the Nuclear
Regulatory Commission and subject to
any Nuclear Regulatory Commission
provision regarding design and quality
criteria, including, but not limited to,
10 CFR part 50. The completely buried
storage capacity of a facility also ex-
cludes the capacity of a container that
is "permanently closed," as defined in
§112.2 and the capacity of intra-facility
gathering lines subject to the regu-
latory requirements of 49 CFR part 192
or 195.
(ii) The aggregate aboveground stor-
age capacity of the facility is 1,320 U.S.
gallons or less of oil. For the purposes
of this exemption, only containers with
a capacity of 55 U.S. gallons or greater
are counted. The aggregate above-
ground storage capacity of a facility
excludes:
(A) The capacity of a container that
is "permanently closed" as defined in
§112.2;
(B) The capacity of a "motive power
container" as defined in §112.2;
(C) The capacity of hot-mix asphalt
or any hot-mix asphalt container;
(D) The capacity of a container for
heating oil used solely at a single-fam-
ily residence;
(E) The capacity of pesticide applica-
tion equipment and related mix con-
tainers.
(F) The capacity of any milk and
milk product container and associated
piping and appurtenances.
(3) Any offshore oil drilling, produc-
tion, or workover facility that is sub-
ject to the notices and regulations of
the Minerals Management Service, as
specified in the Memorandum of Under-
standing between the Secretary of
Transportation, the Secretary of the
Interior, and the Administrator of
EPA, dated November 8, 1993 (appendix
B of this part).
(4) Any completely buried storage
tank, as defined in §112.2, and con-
nected underground piping, under-
ground ancillary equipment, and con-
tainment systems, at any facility, that
is subject to all of the technical re-
quirements of part 280 of this chapter
or a State program approved under
part 281 of this chapter, or any under-
ground oil storage tanks including
below-grade vaulted tanks, deferred
under 40 CFR part 280, as originally
promulgated, that supply emergency
diesel generators at a nuclear power
generation facility licensed by the Nu-
clear Regulatory Commission, provided
21
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§112.1
40 CFR Ch. I (7-1-13 Edition)
that such a tank is subject to any Nu-
clear Regulatory Commission provision
regarding design and quality criteria,
Including, but not limited to, 10 CFR
part 50. Such emergency generator
tanks must be marked on the facility
diagram as provided In §112.7(a)(3), If
the facility Is otherwise subject to this
part.
(5) Any container with a storage ca-
pacity of less than 55 gallons of oil.
(6) Any facility or part thereof used
exclusively for wastewater treatment
and not used to satisfy any require-
ment of this part. The production, re-
covery, or recycling of oil Is not waste-
water treatment for purposes of this
paragraph.
(7) Any "motive power container," as
defined In §112.2. The transfer of fuel or
other oil Into a motive power container
at an otherwise regulated facility Is
not eligible for this exemption.
(8) Hot-mix asphalt, or any hot-mix
asphalt container.
(9) Any container for heating oil used
solely at a single-family residence.
(10) Any pesticide application equip-
ment or related mix containers.
(11) Intra-faclllty gathering lines sub-
ject to the regulatory requirements of
49 CFR part 192 or 195, except that such
a line's location must be Identified and
marked as "exempt" on the facility
diagram as provided In §112.7(a)(3), If
the facility Is otherwise subject to this
part.
(12) Any milk and milk product con-
tainer and associated piping and appur-
tenances.
(e) This part establishes require-
ments for the preparation and Imple-
mentation of Spill Prevention, Control,
and Countermeasure (SPCC) Plans.
SPCC Plans are designed to com-
plement existing laws, regulations,
rules, standards, policies, and proce-
dures pertaining to safety standards,
fire prevention, and pollution preven-
tion rules. The purpose of an SPCC
Plan Is to form a comprehensive Fed-
eral/State spill prevention program
that minimizes the potential for dis-
charges. The SPCC Plan must address
all relevant spill prevention, control,
and countermeasures necessary at the
specific facility. Compliance with this
part does not In any way relieve the
owner or operator of an onshore or an
offshore facility from compliance with
other Federal, State, or local laws.
(f) Notwithstanding paragraph (d) of
this section, the Regional Adminis-
trator may require that the owner or
operator of any facility subject to the
jurisdiction of EPA under section 311(j)
of the CWA prepare and Implement an
SPCC Plan, or any applicable part, to
carry out the purposes of the CWA.
(1) Following a preliminary deter-
mination, the Regional Administrator
must provide a written notice to the
owner or operator stating the reasons
why he must prepare an SPCC Plan, or
applicable part. The Regional Adminis-
trator must send such notice to the
owner or operator by certified mall or
by personal delivery. If the owner or
operator Is a corporation, the Regional
Administrator must also mall a copy of
such notice to the registered agent, If
any and If known, of the corporation In
the State where the facility Is located.
(2) Within 30 days of receipt of such
written notice, the owner or operator
may provide Information and data and
may consult with the Agency about the
need to prepare an SPCC Plan, or appli-
cable part.
(3) Within 30 days following the time
under paragraph (b)(2) of this section
within which the owner or operator
may provide Information and data and
consult with the Agency about the
need to prepare an SPCC Plan, or appli-
cable part, the Regional Administrator
must make a final determination re-
garding whether the owner or operator
Is required to prepare and Implement
an SPCC Plan, or applicable part. The
Regional Administrator must send the
final determination to the owner or op-
erator by certified mall or by personal
delivery. If the owner or operator Is a
corporation, the Regional Adminis-
trator must also mall a copy of the
final determination to the registered
agent, If any and If known, of the cor-
poration In the State where the facility
Is located.
(4) If the Regional Administrator
makes a final determination that an
SPCC Plan, or applicable part, Is nec-
essary, the owner or operator must pre-
pare the Plan, or applicable part, with-
in six months of that final determina-
tion and Implement the Plan, or appli-
cable part, as soon as possible, but not
22
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Environmental Protection Agency
§112.2
later than one year after the Regional
Administrator has made a final deter-
mination.
(5) The owner or operator may appeal
a final determination made by the Re-
gional Administrator requiring prepa-
ration and Implementation of an SPCC
Plan, or applicable part, under this
paragraph. The owner or operator must
make the appeal to the Administrator
of EPA within 30 days of receipt of the
final determination under paragraph
(b)(3) of this section from the Regional
Administrator requiring preparation
and/or Implementation of an SPCC
Plan, or applicable part. The owner or
operator must send a complete copy of
the appeal to the Regional Adminis-
trator at the time he makes the appeal
to the Administrator. The appeal must
contain a clear and concise statement
of the Issues and points of fact In the
case. In the appeal, the owner or oper-
ator may also provide additional Infor-
mation. The additional Information
may be from any person. The Adminis-
trator may request additional Informa-
tion from the owner or operator. The
Administrator must render a decision
within 60 days of receiving the appeal
or additional Information submitted by
the owner or operator and must serve
the owner or operator with the decision
made In the appeal In the manner de-
scribed In paragraph (f)(l) of this sec-
tion.
[67 FR 47140, July 17, 2002, as amended at 71
FR 77290, Dec. 26, 2006; 73 FR 74300, Dec. 5,
2008; 74 FR 58809, Nov. 13, 2009; 76 FR 21660,
Apr. 18, 2011]
§112.2 Definitions.
For the purposes of this part:
Adverse weather means weather condi-
tions that make It difficult for re-
sponse equipment and personnel to
clean up or remove spilled oil, and that
must be considered when Identifying
response systems and equipment In a
response plan for the applicable oper-
ating environment. Factors to consider
Include significant wave height as
specified In appendix E to this part (as
appropriate), Ice conditions, tempera-
tures, weather-related visibility, and
currents within the area In which the
systems or equipment Is Intended to
function.
Alteration means any work on a con-
tainer Involving cutting, burning,
welding, or heating operations that
changes the physical dimensions or
configuration of the container.
Animal fat means a non-petroleum
oil, fat, or grease of animal, fish, or
marine mammal origin.
Breakout tank means a container used
to relieve surges In an oil pipeline sys-
tem or to receive and store oil trans-
ported by a pipeline for relnjectlon and
continued transportation by pipeline.
Bulk storage container means any con-
tainer used to store oil. These con-
tainers are used for purposes Including,
but not limited to, the storage of oil
prior to use, while being used, or prior
to further distribution In commerce.
Oil-filled electrical, operating, or man-
ufacturing equipment Is not a bulk
storage container.
Bunkered tank means a container
constructed or placed In the ground by
cutting the earth and re-covering the
container In a manner that breaks the
surrounding natural grade, or that lies
above grade, and Is covered with earth,
sand, gravel, asphalt, or other mate-
rial. A bunkered tank Is considered an
aboveground storage container for pur-
poses of this part.
Completely buried tank means any
container completely below grade and
covered with earth, sand, gravel, as-
phalt, or other material. Containers In
vaults, bunkered tanks, or partially
burled tanks are considered above-
ground storage containers for purposes
of this part.
Complex means a facility possessing a
combination of transportation-related
and non-transportation-related compo-
nents that Is subject to the jurisdiction
of more than one Federal agency under
section 311(j) of the CWA.
Contiguous zone means the zone es-
tablished by the United States under
Article 24 of the Convention of the Ter-
ritorial Sea and Contiguous Zone, that
Is contiguous to the territorial sea and
that extends nine miles seaward from
the outer limit of the territorial area.
Contract or other approved means
means:
(1) A written contractual agreement
with an oil spill removal organization
that Identifies and ensures the avail-
ability of the necessary personnel and
23
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§112.2
40 CFR Ch. I (7-1-13 Edition)
equipment within appropriate response
times; and/or
(2) A written certification by the
owner or operator that the necessary
personnel and equipment resources,
owned or operated by the facility
owner or operator, are available to re-
spond to a discharge within appro-
priate response times; and/or
(3) Active membership in a local or
regional oil spill removal organization
that has identified and ensures ade-
quate access through such membership
to necessary personnel and equipment
to respond to a discharge within appro-
priate response times in the specified
geographic area; and/or
(4) Any other specific arrangement
approved by the Regional Adminis-
trator upon request of the owner or op-
erator.
Discharge includes, but is not limited
to, any spilling, leaking, pumping,
pouring, emitting, emptying, or dump-
ing of oil, but excludes discharges in
compliance with a permit under sec-
tion 402 of the CWA; discharges result-
ing from circumstances identified, re-
viewed, and made a part of the public
record with respect to a permit issued
or modified under section 402 of the
CWA, and subject to a condition in
such permit; or continuous or antici-
pated intermittent discharges from a
point source, identified in a permit or
permit application under section 402 of
the CWA, that are caused by events oc-
curring within the scope of relevant op-
erating or treatment systems. For pur-
poses of this part, the term discharge
shall not include any discharge of oil
that is authorized by a permit issued
under section 13 of the River and Har-
bor Act of 1899 (33 U.S.C. 407).
Facility means any mobile or fixed,
onshore or offshore building, property,
parcel, lease, structure, installation,
equipment, pipe, or pipeline (other
than a vessel or a public vessel) used in
oil well drilling operations, oil produc-
tion, oil refining, oil storage, oil gath-
ering, oil processing, oil transfer, oil
distribution, and oil waste treatment,
or in which oil is used, as described in
appendix A to this part. The bound-
aries of a facility depend on several
site-specific factors, including but not
limited to, the ownership or operation
of buildings, structures, and equipment
on the same site and types of activity
at the site. Contiguous or non-contig-
uous buildings, properties, parcels,
leases, structures, installations, pipes,
or pipelines under the ownership or op-
eration of the same person may be con-
sidered separate facilities. Only this
definition governs whether a facility is
subject to this part.
Farm means a facility on a tract of
land devoted to the production of crops
or raising of animals, including fish,
which produced and sold, or normally
would have produced and sold, $1,000 or
more of agricultural products during a
year.
Fish and wildlife and sensitive environ-
ments means areas that may be identi-
fied by their legal designation or by
evaluations of Area Committees (for
planning) or members of the Federal
On-Scene Coordinator's spill response
structure (during responses). These
areas may include wetlands, National
and State parks, critical habitats for
endangered or threatened species, wil-
derness and natural resource areas,
marine sanctuaries and estuarine re-
serves, conservation areas, preserves,
wildlife areas, wildlife refuges, wild
and scenic rivers, recreational areas,
national forests, Federal and State
lands that are research national areas,
heritage program areas, land trust
areas, and historical and archae-
ological sites and parks. These areas
may also include unique habitats such
as aquaculture sites and agricultural
surface water intakes, bird nesting
areas, critical biological resource
areas, designated migratory routes,
and designated seasonal habitats.
Injury means a measurable adverse
change, either long- or short-term, in
the chemical or physical quality or the
viability of a natural resource result-
ing either directly or indirectly from
exposure to a discharge, or exposure to
a product of reactions resulting from a
discharge.
Loading/unloading rack means a fixed
structure (such as a platform, gang-
way) necessary for loading or unload-
ing a tank truck or tank car, which is
24
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Environmental Protection Agency
§112.2
located at a facility subject to the re-
quirements of this part. A loading/un-
loading rack includes a loading or un-
loading arm, and may include any com-
bination of the following: piping as-
semblages, valves, pumps, shut-off de-
vices, overfill sensors, or personnel
safety devices.
Maximum extent practicable means
within the limitations used to deter-
mine oil spill planning resources and
response times for on-water recovery,
shoreline protection, and cleanup for
worst case discharges from onshore
non-transportation-related facilities in
adverse weather. It includes the
planned capability to respond to a
worst case discharge in adverse weath-
er, as contained in a response plan that
meets the requirements in §112.20 or in
a specific plan approved by the Re-
gional Administrator.
Mobile refueler means a bulk storage
container onboard a vehicle or towed,
that is designed or used solely to store
and transport fuel for transfer into or
from an aircraft, motor vehicle, loco-
motive, vessel, ground service equip-
ment, or other oil storage container.
Motive power container means any on-
board bulk storage container used pri-
marily to power the movement of a
motor vehicle, or ancillary onboard oil-
filled operational equipment. An on-
board bulk storage container which is
used to store or transfer oil for further
distribution is not a motive power con-
tainer. The definition of motive power
container does not include oil drilling
or workover equipment, including rigs.
Navigable waters of the United States
means "navigable waters" as defined in
section 502(7) of the FWPCA, and in-
cludes:
(1) All navigable waters of the United
States, as defined in judicial decisions
prior to passage of the 1972 Amend-
ments to the FWPCA (Pub. L. 92-500),
and tributaries of such waters;
(2) Interstate waters;
(3) Intrastate lakes, rivers, and
streams which are utilized by inter-
state travelers for recreational or
other purposes; and
(4) Intrastate lakes, rivers, and
streams from which fish or shellfish
are taken and sold in interstate com-
merce.
Non-petroleum oil means oil of any
kind that is not petroleum-based, in-
cluding but not limited to: Fats, oils,
and greases of animal, fish, or marine
mammal origin; and vegetable oils, in-
cluding oils from seeds, nuts, fruits,
and kernels.
Offshore facility means any facility of
any kind (other than a vessel or public
vessel) located in, on, or under any of
the navigable waters of the United
States, and any facility of any kind
that is subject to the jurisdiction of
the United States and is located in, on,
or under any other waters.
Oil means oil of any kind or in any
form, including, but not limited to:
fats, oils, or greases of animal, fish, or
marine mammal origin; vegetable oils,
including oils from seeds, nuts, fruits,
or kernels; and, other oils and greases,
including petroleum, fuel oil, sludge,
synthetic oils, mineral oils, oil refuse,
or oil mixed with wastes other than
dredged spoil.
Oil-filled operational equipment means
equipment that includes an oil storage
container (or multiple containers) in
which the oil is present solely to sup-
port the function of the apparatus or
the device. Oil-filled operational equip-
ment is not considered a bulk storage
container, and does not include oil-
filled manufacturing equipment (flow-
through process). Examples of oil-filled
operational equipment include, but are
not limited to, hydraulic systems, lu-
bricating systems (e.g., those for
pumps, compressors and other rotating
equipment, including pumpjack lubri-
cation systems), gear boxes, machining
coolant systems, heat transfer sys-
tems, transformers, circuit breakers,
electrical switches, and other systems
containing oil solely to enable the op-
eration of the device.
Oil Spill Removal Organisation means
an entity that provides oil spill re-
sponse resources, and includes any for-
profit or not-for-profit contractor, co-
operative, or in-house response re-
sources that have been established in a
geographic area to provide required re-
sponse resources.
Onshore facility means any facility of
any kind located in, on, or under any
land within the United States, other
than submerged lands.
25
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§112.2
40 CFR Ch. I (7-1-13 Edition)
Owner or operator means any person
owning or operating an onshore facility
or an offshore facility, and in the case
of any abandoned offshore facility, the
person who owned or operated or main-
tained the facility immediately prior
to such abandonment.
Partially buried tank means a storage
container that is partially inserted or
constructed in the ground, but not en-
tirely below grade, and not completely
covered with earth, sand, gravel, as-
phalt, or other material. A partially
buried tank is considered an above-
ground storage container for purposes
of this part.
Permanently closed means any con-
tainer or facility for which:
(1) All liquid and sludge has been re-
moved from each container and con-
necting line; and
(2) All connecting lines and piping
have been disconnected from the con-
tainer and blanked off, all valves (ex-
cept for ventilation valves) have been
closed and locked, and conspicuous
signs have been posted on each con-
tainer stating that it is a permanently
closed container and noting the date of
closure.
Person includes an individual, firm,
corporation, association, or partner-
ship.
Petroleum oil means petroleum in any
form, including but not limited to
crude oil, fuel oil, mineral oil, sludge,
oil refuse, and refined products.
Produced water container means a
storage container at an oil production
facility used to store the produced
water after initial oil/water separation,
and prior to reinjection, beneficial
reuse, discharge, or transfer for dis-
posal.
Production facility means all struc-
tures (including but not limited to
wells, platforms, or storage facilities),
piping (including but not limited to
flowlines or intra-facility gathering
lines), or equipment (including but not
limited to workover equipment, sepa-
ration equipment, or auxiliary non-
transportation-related equipment) used
in the production, extraction, recovery,
lifting, stabilization, separation or
treating of oil (including condensate),
or associated storage or measurement,
and is located in an oil or gas field, at
a facility. This definition governs
whether such structures, piping, or
equipment are subject to a specific sec-
tion of this part.
Regional Administrator means the Re-
gional Administrator of the Environ-
mental Protection Agency, in and for
the Region in which the facility is lo-
cated.
Repair means any work necessary to
maintain or restore a container to a
condition suitable for safe operation,
other than that necessary for ordinary,
day-to-day maintenance to maintain
the functional integrity of the con-
tainer and that does not weaken the
container.
Spill Prevention, Control, and Counter-
measure Plan; SPCC Plan, or Plan means
the document required by §112.3 that
details the equipment, workforce, pro-
cedures, and steps to prevent, control,
and provide adequate countermeasures
to a discharge.
Storage capacity of a container means
the shell capacity of the container.
Transportation-related and non-trans-
portation-related, as applied to an on-
shore or offshore facility, are defined
in the Memorandum of Understanding
between the Secretary of Transpor-
tation and the Administrator of the
Environmental Protection Agency,
dated November 24, 1971, (appendix A of
this part).
United States means the States, the
District of Columbia, the Common-
wealth of Puerto Rico, the Common-
wealth of the Northern Mariana Is-
lands, Guam, American Samoa, the
U.S. Virgin Islands, and the Pacific Is-
land Governments.
Vegetable oil means a non-petroleum
oil or fat of vegetable origin, including
but not limited to oils and fats derived
from plant seeds, nuts, fruits, and ker-
nels.
Vessel means every description of
watercraft or other artificial contriv-
ance used, or capable of being used, as
a means of transportation on water,
other than a public vessel.
Wetlands means those areas that are
inundated or saturated by surface or
groundwater at a frequency or duration
sufficient to support, and that under
normal circumstances do support, a
prevalence of vegetation typically
adapted for life in saturated soil condi-
tions. Wetlands generally include playa
26
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Environmental Protection Agency
§112.3
lakes, swamps, marshes, bogs, and
similar areas such as sloughs, prairie
potholes, wet meadows, prairie river
overflows, mudflats, and natural ponds.
Worst case discharge for an onshore
non-transportation-related facility
means the largest foreseeable dis-
charge in adverse weather conditions
as determined using the worksheets in
appendix D to this part.
[67 FR 47140, July 17, 2002, as amended at 71
FR 77290, Dec. 26, 2006; 73 FR 71943, Nov. 26,
2008; 73 FR 74300, Dec. 5, 2008]
§112.3 Requirement to prepare and
implement a Spill Prevention, Con-
trol, and Countermeasure Plan.
The owner or operator or an onshore
or offshore facility subject to this sec-
tion must prepare in writing and im-
plement a Spill Prevention Control and
Countermeasure Plan (hereafter "SPCC
Plan" or "Plan")," in accordance with
§112.7 and any other applicable section
of this part.
(a)(l) Except as otherwise provided in
this section, if your facility, or mobile
or portable facility, was in operation
on or before August 16, 2002, you must
maintain your Plan, but must amend
it, if necessary to ensure compliance
with this part, and implement the
amended Plan no later than November
10, 2011. If such a facility becomes oper-
ational after August 16, 2002, through
November 10, 2011, and could reason-
ably be expected to have a discharge as
described in §112.1(b), you must prepare
and implement a Plan on or before No-
vember 10, 2011. If such a facility (ex-
cluding oil production facilities) be-
comes operational after November 10,
2011, and could reasonably be expected
to have a discharge as described in
§112.1(b), you must prepare and imple-
ment a Plan before you begin oper-
ations. You are not required to prepare
a new Plan each time you move a mo-
bile or portable facility to a new site;
the Plan may be general. When you
move the mobile or portable facility,
you must locate and install it using
the discharge prevention practices out-
lined in the Plan for the facility. The
Plan is applicable only while the mo-
bile or portable facility is in a fixed
(non-transportation) operating mode.
(2) If your drilling, production or
workover facility, including a mobile
or portable facility, is offshore or has
an offshore component; or your on-
shore facility is required to have and
submit a Facility Response Plan pursu-
ant to 40 CFR 112.20(a), and was in op-
eration on or before August 16, 2002,
you must maintain your Plan, but
must amend it, if necessary to ensure
compliance with this part, and imple-
ment the amended Plan no later than
November 10, 2010. If such a facility be-
comes operational after August 16,
2002, through November 10, 2010, and
could reasonably be expected to have a
discharge as described in §112.1(b), you
must prepare and implement a Plan on
or before November 10, 2010. If such a
facility (excluding oil production fa-
cilities) becomes operational after No-
vember 10, 2010, and could reasonably
be expected to have a discharge as de-
scribed in §112.1(b), you must prepare
and implement a Plan before you begin
operations. You are not required to
prepare a new Plan each time you
move a mobile or portable facility to a
new site; the Plan may be general.
When you move the mobile or portable
facility, you must locate and install it
using the discharge prevention prac-
tices outlined in the Plan for the facil-
ity. The Plan is applicable only while
the mobile or portable facility is in a
fixed (non-transportation) operating
mode.
(3) If your farm, as defined in §112.2,
was in operation on or before August
16, 2002, you must maintain your Plan,
but must amend it, if necessary to en-
sure compliance with this part, and im-
plement the amended Plan on or before
May 10, 2013. If your farm becomes
operational after August 16, 2002,
through May 10, 2013, and could reason-
ably be expected to have a discharge as
described in §112.1(b), you must prepare
and implement a Plan on or before May
10, 2013. If your farm becomes oper-
ational after May 10, 2013, and could
reasonably be expected to have a dis-
charge as described in §112.1(b), you
must prepare and implement a Plan be-
fore you begin operations.
(b) If your oil production facility as
described in paragraph (a)(l) of this
section becomes operational after No-
vember 10, 2011, or as described in para-
graph (a)(2) of this section becomes
operational after November 10, 2010,
27
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§112.3
40 CFR Ch. I (7-1-13 Edition)
and could reasonably be expected to
have a discharge as described In
§112.1(b), you must prepare and Imple-
ment a Plan within six months after
you begin operations.
(c) [Reserved]
(d) Except as provided In §112.6, a li-
censed Professional Engineer must re-
view and certify a Plan for It to be ef-
fective to satisfy the requirements of
this part.
(1) By means of this certification the
Professional Engineer attests:
(1) That he Is familiar with the re-
quirements of this part ;
(11) That he or his agent has visited
and examined the facility;
(111) That the Plan has been prepared
In accordance with good engineering
practice, Including consideration of ap-
plicable Industry standards, and with
the requirements of this part;
(Iv) That procedures for required In-
spections and testing have been estab-
lished; and
(v) That the Plan Is adequate for the
facility.
(vl) That, If applicable, for a pro-
duced water container subject to
§112.9(c)(6), any procedure to minimize
the amount of free-phase oil Is de-
signed to reduce the accumulation of
free-phase oil and the procedures and
frequency for required Inspections,
maintenance and testing have been es-
tablished and are described In the Plan.
(2) Such certification shall In no way
relieve the owner or operator of a facil-
ity of his duty to prepare and fully Im-
plement such Plan In accordance with
the requirements of this part.
(e) If you are the owner or operator
of a facility for which a Plan Is re-
quired under this section, you must:
(1) Maintain a complete copy of the
Plan at the facility If the facility Is
normally attended at least four hours
per day, or at the nearest field office If
the facility Is not so attended, and
(2) Have the Plan available to the Re-
gional Administrator for on-slte review
during normal working hours.
(f) Extension of time. (1) The Regional
Administrator may authorize an exten-
sion of time for the preparation and
full Implementation of a Plan, or any
amendment thereto, beyond the time
permitted for the preparation, Imple-
mentation, or amendment of a Plan
under this part, when he finds that the
owner or operator of a facility subject
to this section, cannot fully comply
with the requirements as a result of ei-
ther nonavailability of qualified per-
sonnel, or delays In construction or
equipment delivery beyond the control
and without the fault of such owner or
operator or his agents or employees.
(2) If you are an owner or operator
seeking an extension of time under
paragraph (f)(l) of this section, you
may submit a written extension re-
quest to the Regional Administrator.
Your request must Include:
(1) A full explanation of the cause for
any such delay and the specific aspects
of the Plan affected by the delay;
(11) A full discussion of actions being
taken or contemplated to minimize or
mitigate such delay; and
(111) A proposed time schedule for the
Implementation of any corrective ac-
tions being taken or contemplated, In-
cluding Interim dates for completion of
tests or studies, Installation and oper-
ation of any necessary equipment, or
other preventive measures. In addition
you may present additional oral or
written statements In support of your
extension request.
(3) The submission of a written ex-
tension request under paragraph (f)(2)
of this section does not relieve you of
your obligation to comply with the re-
quirements of this part. The Regional
Administrator may request a copy of
your Plan to evaluate the extension re-
quest. When the Regional Adminis-
trator authorizes an extension of time
for particular equipment or other spe-
cific aspects of the Plan, such exten-
sion does not affect your obligation to
comply with the requirements related
to other equipment or other specific as-
pects of the Plan for which the Re-
gional Administrator has not expressly
authorized an extension.
(g) Qualified Facilities. The owner or
operator of a qualified facility as de-
fined In this subparagraph may self-
certify his facility's Plan, as provided
In §112.6. A qualified facility Is one
that meets the following Tier I or Tier
II qualified facility criteria:
(1) A Tier I qualified facility meets
the qualification criteria In paragraph
-------
Environmental Protection Agency
§112.4
(g)(2) of this section and has no indi-
vidual aboveground oil storage con-
tainer with a capacity greater than
5,000 U.S. gallons.
(2) A Tier II qualified facility is one
that has had no single discharge as de-
scribed in §112.l(b) exceeding 1,000 U.S.
gallons or no two discharges as de-
scribed in §112.1(b) each exceeding 42
U.S. gallons within any twelve month
period in the three years prior to the
SPCC Plan self-certification date, or
since becoming subject to this part if
the facility has been in operation for
less than three years (other than dis-
charges as described in §112.1(b) that
are the result of natural disasters, acts
of war, or terrorism), and has an aggre-
gate aboveground oil storage capacity
of 10,000 U.S. gallons or less.
[67 FR 47140, July 17, 2002, as amended at 68
FR 1351, Jan. 9, 2003; 68 FR 18894, Apr. 17,
2003; 69 FR 48798, Aug. 11, 2004; 71 FR 8466,
Feb. 17, 2006; 71 FR 77290, Dec. 26, 2006; 72 FR
27447, May 16, 2007; 73 FR 74301, Dec. 5, 2008,
74 FR 29141, June 19, 2009; 74 FR 58809, Nov.
13, 2009; 75 FR 63102, Oct. 14, 2010; 76 FR 21660,
Apr. 18, 2011; 76 FR 64248, Oct. 18, 2011; 76 FR
72124, Nov. 22, 2011]
§112.4 Amendment of Spill Preven-
tion, Control, and Countermeasure
Plan by Regional Administrator.
If you are the owner or operator of a
facility subject to this part, you must:
(a) Notwithstanding compliance with
§112.3, whenever your facility has dis-
charged more than 1,000 U.S. gallons of
oil in a single discharge as described in
§112.1(b), or discharged more than 42
U.S. gallons of oil in each of two dis-
charges as described in §112.1(b), occur-
ring within any twelve month period,
submit the following information to
the Regional Administrator within 60
days from the time the facility be-
comes subject to this section:
(1) Name of the facility;
(2) Your name;
(3) Location of the facility;
(4) Maximum storage or handling ca-
pacity of the facility and normal daily
throughput;
(5) Corrective action and counter-
measures you have taken, including a
description of equipment repairs and
replacements;
(6) An adequate description of the fa-
cility, including maps, flow diagrams,
and topographical maps, as necessary;
(7) The cause of such discharge as de-
scribed in §112.1(b), including a failure
analysis of the system or subsystem in
which the failure occurred;
(8) Additional preventive measures
you have taken or contemplated to
minimize the possibility of recurrence;
and
(9) Such other information as the Re-
gional Administrator may reasonably
require pertinent to the Plan or dis-
charge.
(b) Take no action under this section
until it applies to your facility. This
section does not apply until the expira-
tion of the time permitted for the ini-
tial preparation and implementation of
the Plan under §112.3, but not including
any amendments to the Plan.
(c) Send to the appropriate agency or
agencies in charge of oil pollution con-
trol activities in the State in which the
facility is located a complete copy of
all information you provided to the Re-
gional Administrator under paragraph
(a) of this section. Upon receipt of the
information such State agency or agen-
cies may conduct a review and make
recommendations to the Regional Ad-
ministrator as to further procedures,
methods, equipment, and other require-
ments necessary to prevent and to con-
tain discharges from your facility.
(d) Amend your Plan, if after review
by the Regional Administrator of the
information you submit under para-
graph (a) of this section, or submission
of information to EPA by the State
agency under paragraph (c) of this sec-
tion, or after on-site review of your
Plan, the Regional Administrator re-
quires that you do so. The Regional
Administrator may require you to
amend your Plan if he finds that it
does not meet the requirements of this
part or that amendment is necessary to
prevent and contain discharges from
your facility.
(e) Act in accordance with this para-
graph when the Regional Adminis-
trator proposes by certified mail or by
personal delivery that you amend your
SPCC Plan. If the owner or operator is
a corporation, he must also notify by
mail the registered agent of such cor-
poration, if any and if known, in the
State in which the facility is located.
The Regional Administrator must
specify the terms of such proposed
29
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§112.5
40 CFR Ch. I (7-1-13 Edition)
amendment. Within 30 days from re-
ceipt of such notice, you may submit
written information, views, and argu-
ments on the proposed amendment.
After considering all relevant material
presented, the Regional Administrator
must either notify you of any amend-
ment required or rescind the notice.
You must amend your Plan as required
within 30 days after such notice, unless
the Regional Administrator, for good
cause, specifies another effective date.
You must implement the amended Plan
as soon as possible, but not later than
six months after you amend your Plan,
unless the Regional Administrator
specifies another date.
(f) If you appeal a decision made by
the Regional Administrator requiring
an amendment to an SPCC Plan, send
the appeal to the EPA Administrator
in writing within 30 days of receipt of
the notice from the Regional Adminis-
trator requiring the amendment under
paragraph (e) of this section. You must
send a complete copy of the appeal to
the Regional Administrator at the
time you make the appeal. The appeal
must contain a clear and concise state-
ment of the issues and points of fact in
the case. It may also contain addi-
tional information from you, or from
any other person. The EPA Adminis-
trator may request additional informa-
tion from you, or from any other per-
son. The EPA Administrator must
render a decision within 60 days of re-
ceiving the appeal and must notify you
of his decision.
§112.5 Amendment of Spill Preven-
tion, Control, and Countermeasure
Plan by owners or operators.
If you are the owner or operator of a
facility subject to this part, you must:
(a) Amend the SPCC Plan for your fa-
cility in accordance with the general
requirements in §112.7, and with any
specific section of this part applicable
to your facility, when there is a change
in the facility design, construction, op-
eration, or maintenance that materi-
ally affects its potential for a dis-
charge as described in §112.1(b). Exam-
ples of changes that may require
amendment of the Plan include, but
are not limited to: commissioning or
decommissioning containers; replace-
ment, reconstruction, or movement of
containers; reconstruction, replace-
ment, or installation of piping systems;
construction or demolition that might
alter secondary containment struc-
tures; changes of product or service; or
revision of standard operation or main-
tenance procedures at a facility. An
amendment made under this section
must be prepared within six months,
and implemented as soon as possible,
but not later than six months following
preparation of the amendment.
(b) Notwithstanding compliance with
paragraph (a) of this section, complete
a review and evaluation of the SPCC
Plan at least once every five years
from the date your facility becomes
subject to this part; or, if your facility
was in operation on or before August
16, 2002, five years from the date your
last review was required under this
part. As a result of this review and
evaluation, you must amend your
SPCC Plan within six months of the re-
view to include more effective preven-
tion and control technology if the tech-
nology has been field-proven at the
time of the review and will signifi-
cantly reduce the likelihood of a dis-
charge as described in §112.1(b) from
the facility. You must implement any
amendment as soon as possible, but not
later than six months following prepa-
ration of any amendment. You must
document your completion of the re-
view and evaluation, and must sign a
statement as to whether you will
amend the Plan, either at the begin-
ning or end of the Plan or in a log or an
appendix to the Plan. The following
words will suffice, "I have completed
review and evaluation of the SPCC
Plan for (name of facility) on (date),
and will (will not) amend the Plan as a
result."
(c) Except as provided in §112.6, have
a Professional Engineer certify any
technical amendments to your Plan in
accordance with §112.3(d).
[67 FR 47140, July 17, 2002, as amended at 71
FR 77291, Dec. 26, 2006; 73 FR 74301, Dec. 5,
2008; 74 FR 58809, Nov. 13, 2009]
§112.6 Qualified Facilities Plan Re-
quirements.
Qualified facilities meeting the Tier I
applicability criteria in §112.3(g)(l) are
30
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Environmental Protection Agency
§112.6
subject to the requirements in para-
graph (a) of this section. Qualified fa-
cilities meeting the Tier II applica-
bility criteria in §112.3(g)(2) are subject
to the requirements in paragraph (b) of
this section.
(a) Tier I Qualified Facilities—(1) Prep-
aration and Self-Certification of the Plan.
If you are an owner or operator of a fa-
cility that meets the Tier I qualified
facility criteria in §112.3(g)(l), you
must either: comply with the require-
ments of paragraph (a)(3) of this sec-
tion; or prepare and implement a Plan
meeting requirements of paragraph (b)
of this section; or prepare and imple-
ment a Plan meeting the general Plan
requirements in §112.7 and applicable
requirements in subparts B and C, in-
cluding having the Plan certified by a
Professional Engineer as required
under §112.3(d). If you do not follow the
appendix G template, you must prepare
an equivalent Plan that meets all of
the applicable requirements listed in
this part, and you must supplement it
with a section cross-referencing the lo-
cation of requirements listed in this
part and the equivalent requirements
in the other prevention plan. To com-
plete the template in appendix G, you
must certify that:
(i) You are familiar with the applica-
ble requirements of 40 CFR part 112;
(ii) You have visited and examined
the facility;
(ill) You prepared the Plan in accord-
ance with accepted and sound industry
practices and standards;
(iv) You have established procedures
for required inspections and testing in
accordance with industry inspection
and testing standards or recommended
practices;
(v) You will fully implement the
Plan;
(vi) The facility meets the qualifica-
tion criteria in §112.3(g)(l);
(vii) The Plan does not deviate from
any requirement of this part as allowed
by §112.7(a)(2) and 112.7(d) or include
measures pursuant to §112.9(c)(6) for
produced water containers and any as-
sociated piping; and
(viii) The Plan and individual(s) re-
sponsible for implementing this Plan
have the approval of management, and
the facility owner or operator has com-
mitted the necessary resources to fully
implement this Plan.
(2) Technical Amendments. You must
certify any technical amendments to
your Plan in accordance with para-
graph (a)(l) of this section when there
is a change in the facility design, con-
struction, operation, or maintenance
that affects its potential for a dis-
charge as described in §112.1(b). If the
facility change results in the facility
no longer meeting the Tier I qualifying
criteria in §112.3(g)(l) because an indi-
vidual oil storage container capacity
exceeds 5,000 U.S. gallons or the facil-
ity capacity exceeds 10,000 U.S. gallons
in aggregate aboveground storage ca-
pacity, within six months following
preparation of the amendment, you
must either:
(i) Prepare and implement a Plan in
accordance with §112.6(b) if you meet
the Tier II qualified facility criteria in
§112.3(g)(2); or
(ii) Prepare and implement a Plan in
accordance with the general Plan re-
quirements in §112.7, and applicable re-
quirements in subparts B and C, includ-
ing having the Plan certified by a Pro-
fessional Engineer as required under
§112.3(d).
(3) Plan Template and Applicable Re-
quirements. Prepare and implement an
SPCC Plan that meets the following re-
quirements under §112.7 and in sub-
parts B and C of this part: introductory
paragraph of §§112.7, 112.7(a)(3)(i),
112.7(a)(5), 112.7(c), 112. 7(e), 112. 7(f),
112. 7(g), 112. 7(k), 112.8(b)(l), 112.8(b)(2),
112.12(c)(6), 112.12(c)(10), and 112.12(d)(4).
The template in appendix G to this
part has been developed to meet the re-
quirements of 40 CFR part 112 and,
when completed and signed by the
owner or operator, may be used as the
SPCC Plan. Additionally, you must
meet the following requirements:
(i) Failure analysis, in lieu of the re-
quirements in §112.7(b). Where experi-
ence indicates a reasonable potential
31
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§112.6
40 CFR Ch. I (7-1-13 Edition)
for equipment failure (such as loading
or unloading equipment, tank overflow,
rupture, or leakage, or any other
equipment known to be a source of dis-
charge), include in your Plan a pre-
diction of the direction and total quan-
tity of oil which could be discharged
from the facility as a result of each
type of major equipment failure.
(ii) Bulk storage container secondary
containment, in lieu of the requirements
in §§112.8(c)(2) and (c)(ll) and
112.12(c)(2) and (c)(ll). Construct all
bulk storage container installations
(except mobile refuelers and other non-
transportation-related tank trucks),
including mobile or portable oil stor-
age containers, so that you provide a
secondary means of containment for
the entire capacity of the largest single
container plus additional capacity to
contain precipitation. Dikes, contain-
ment curbs, and pits are commonly em-
ployed for this purpose. You may also
use an alternative system consisting of
a drainage trench enclosure that must
be arranged so that any discharge will
terminate and be safely confined in a
catchment basin or holding pond. Posi-
tion or locate mobile or portable oil
storage containers to prevent a dis-
charge as described in §112.1(b).
(ill) Overfill prevention, in lieu of the
requirements in §§112.8(c)(8) and
112.12(c)(S). Ensure that each container
is provided with a system or docu-
mented procedure to prevent overfills
of the container, describe the system
or procedure in the SPCC Plan and reg-
ularly test to ensure proper operation
or efficacy.
(b) Tier II Qualified Facilities—(1)
Preparation and Self-Certification of
Plan. If you are the owner or operator
of a facility that meets the Tier II
qualified facility criteria in §112.3(g)(2),
you may choose to self-certify your
Plan. You must certify in the Plan
that:
(i) You are familiar with the require-
ments of this part;
(ii) You have visited and examined
the facility;
(ill) The Plan has been prepared in
accordance with accepted and sound in-
dustry practices and standards, and
with the requirements of this part;
(iv) Procedures for required inspec-
tions and testing have been estab-
lished;
(v) You will fully implement the
Plan;
(vi) The facility meets the qualifica-
tion criteria set forth under
§112.3(g)(2);
(vii) The Plan does not deviate from
any requirement of this part as allowed
by §112.7(a)(2) and 112.7(d) or include
measures pursuant to §112.9(c)(6) for
produced water containers and any as-
sociated piping, except as provided in
paragraph (b)(3) of this section; and
(viii) The Plan and individual(s) re-
sponsible for implementing the Plan
have the full approval of management
and the facility owner or operator has
committed the necessary resources to
fully implement the Plan.
(2) Technical Amendments. If you self-
certify your Plan pursuant to para-
graph (b)(l) of this section, you must
certify any technical amendments to
your Plan in accordance with para-
graph (b)(l) of this section when there
is a change in the facility design, con-
struction, operation, or maintenance
that affects its potential for a dis-
charge as described in §112.1(b), except:
(i) If a Professional Engineer cer-
tified a portion of your Plan in accord-
ance with paragraph (b)(4) of this sec-
tion, and the technical amendment af-
fects this portion of the Plan, you must
have the amended provisions of your
Plan certified by a Professional Engi-
neer in accordance with paragraph
(b)(4)(ii) of this section.
(ii) If the change is such that the fa-
cility no longer meets the Tier II quali-
fying criteria in §112.3(g)(2) because it
exceeds 10,000 U.S. gallons in aggregate
aboveground storage capacity you
must, within six months following the
change, prepare and implement a Plan
in accordance with the general Plan re-
quirements in §112.7 and the applicable
requirements in subparts B and C of
this part, including having the Plan
certified by a Professional Engineer as
required under §112.3(d).
(3) Applicable Requirements. Except as
provided in this paragraph, your self-
certified SPCC Plan must comply with
§112.7 and the applicable requirements
in subparts B and C of this part:
32
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Environmental Protection Agency
§112.7
(i) Environmental Equivalence. Your
Plan may not include alternate meth-
ods which provide environmental
equivalence pursuant to §112.7(a)(2),
unless each alternate method has been
reviewed and certified in writing by a
Professional Engineer, as provided in
paragraph (b)(4) of this section.
(ii) Impracticability. Your Plan may
not include any determinations that
secondary containment is impracti-
cable and provisions in lieu of sec-
ondary containment pursuant to
§112.7(d), unless each such determina-
tion and alternate measure has been
reviewed and certified in writing by a
Professional Engineer, as provided in
paragraph (b)(4) of this section.
(ill) Produced Water Containers. Your
Plan may not include any alternative
procedures for skimming produced
water containers in lieu of sized sec-
ondary containment pursuant to
§112.9(c)(6), unless they have been re-
viewed and certified in writing by a
Professional Engineer, as provided in
paragraph (b)(4) of this section.
(4) Professional Engineer Certification
of Portions of a Qualified Facility's Self-
Certified Plan.
(i) As described in paragraph (b)(3) of
this section, the facility owner or oper-
ator may not self-certify alternative
measures allowed under §112.7(a)(2) or
(d), that are included in the facility's
Plan. Such measures must be reviewed
and certified, in writing, by a licensed
Professional Engineer. For each alter-
native measure allowed under
§112.7(a)(2), the Plan must be accom-
panied by a written statement by a
Professional Engineer that states the
reason for nonconformance and de-
scribes the alternative method and how
it provides equivalent environmental
protection in accordance with
§112.7(a)(2). For each determination of
impracticability of secondary contain-
ment pursuant to §112.7(d), the Plan
must clearly explain why secondary
containment measures are not prac-
ticable at this facility and provide the
alternative measures required in
§112.7(d) in lieu of secondary contain-
ment. By certifying each measure al-
lowed under §112.7(a)(2) and (d), the
Professional Engineer attests:
(A) That he is familiar with the re-
quirements of this part;
(B) That he or his agent has visited
and examined the facility; and
(C) That the alternative method of
environmental equivalence in accord-
ance with §112.7(a)(2) or the determina-
tion of impracticability and alter-
native measures in accordance with
§112.7(d) is consistent with good engi-
neering practice, including consider-
ation of applicable industry standards,
and with the requirements of this part.
(ii) As described in paragraph (b)(3) of
this section, the facility owner or oper-
ator may not self-certify measures as
described in §112.9(c)(6) for produced
water containers and any associated
piping. Such measures must be re-
viewed and certified, in writing, by a li-
censed Professional Engineer, in ac-
cordance with §112.3(d)(l)(vi).
(ill) The review and certification by
the Professional Engineer under this
paragraph is limited to the alternative
method which achieves equivalent en-
vironmental protection pursuant to
§112.7(a)(2); to the impracticability de-
termination and measures in lieu of
secondary containment pursuant to
§112.7(d); or the measures pursuant to
§112.9(c)(6) for produced water con-
tainers and any associated piping and
appurtenances downstream from the
container.
[73 FR 74302, Dec. 5, 2008, as amended at 74
FR 58810, Nov. 13, 2009]
§112.7 General requirements for Spill
Prevention, Control, and Counter-
measure Plans.
If you are the owner or operator of a
facility subject to this part you must
prepare a Plan in accordance with good
engineering practices. The Plan must
have the full approval of management
at a level of authority to commit the
necessary resources to fully implement
the Plan. You must prepare the Plan in
writing. If you do not follow the se-
quence specified in this section for the
Plan, you must prepare an equivalent
Plan acceptable to the Regional Ad-
ministrator that meets all of the appli-
cable requirements listed in this part,
and you must supplement it with a sec-
tion cross-referencing the location of
requirements listed in this part and the
equivalent requirements in the other
prevention plan. If the Plan calls for
additional facilities or procedures,
33
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§112.7
40 CFR Ch. I (7-1-13 Edition)
methods, or equipment not yet fully
operational, you must discuss these
Items In separate paragraphs, and must
explain separately the details of Instal-
lation and operational start-up. As de-
tailed elsewhere In this section, you
must also:
(a)(l) Include a discussion of your fa-
cility's conformance with the require-
ments listed In this part.
(2) Comply with all applicable re-
quirements listed In this part. Except
as provided In §112.6, your Plan may
deviate from the requirements In para-
graphs (g), (h)(2) and (3), and (1) of this
section and the requirements In sub-
parts B and C of this part, except the
secondary containment requirements
In paragraphs (c) and (h)(l) of this sec-
tion, and §§112.8(c)(2), 112.8(c)(ll),
112.12(c)(2), and 112.12(c)(ll), where ap-
plicable to a specific facility, If you
provide equivalent environmental pro-
tection by some other means of spill
prevention, control, or counter-
measure. Where your Plan does not
conform to the applicable requirements
In paragraphs (g), (h)(2) and (3), and (1)
of this section, or the requirements of
subparts B and C of this part, except
the secondary containment require-
ments In paragraph (c) and (h)(l) of
this section, and §§112.8(c)(2),
112.12(c)(2), and 112.12(c)(ll), you must
state the reasons for nonconformance
In your Plan and describe In detail al-
ternate methods and how you will
achieve equivalent environmental pro-
tection. If the Regional Administrator
determines that the measures de-
scribed In your Plan do not provide
equivalent environmental protection,
he may require that you amend your
Plan, following the procedures In
§112.4(d) and (e).
(3) Describe In your Plan the physical
layout of the facility and Include a fa-
cility diagram, which must mark the
location and contents of each fixed oil
storage container and the storage area
where mobile or portable containers
are located. The facility diagram must
Identify the location of and mark as
"exempt" underground tanks that are
otherwise exempted from the require-
ments of this part under §112.1(d)(4).
The facility diagram must also Include
all transfer stations and connecting
pipes, Including Intra-faclllty gath-
ering lines that are otherwise exempt-
ed from the requirements of this part
under §112.1(d)(ll). You must also ad-
dress In your Plan:
(1) The type of oil In each fixed con-
tainer and Its storage capacity. For
mobile or portable containers, either
provide the type of oil and storage ca-
pacity for each container or provide an
estimate of the potential number of
mobile or portable containers, the
types of oil, and anticipated storage ca-
pacities;
(11) Discharge prevention measures
Including procedures for routine han-
dling of products (loading, unloading,
and facility transfers, etc.);
(Ill) Discharge or drainage controls
such as secondary containment around
containers and other structures, equip-
ment, and procedures for the control of
a discharge;
(Iv) Countermeasures for discharge
discovery, response, and cleanup (both
the facility's capability and those that
might be required of a contractor);
(v) Methods of disposal of recovered
materials In accordance with applica-
ble legal requirements; and
(vl) Contact list and phone numbers
for the facility response coordinator,
National Response Center, cleanup con-
tractors with whom you have an agree-
ment for response, and all appropriate
Federal, State, and local agencies who
must be contacted In case of a dis-
charge as described In §112.1(b).
(4) Unless you have submitted a re-
sponse plan under §112.20, provide In-
formation and procedures In your Plan
to enable a person reporting a dis-
charge as described In §112.1(b) to re-
late Information on the exact address
or location and phone number of the fa-
cility; the date and time of the dis-
charge, the type of material dis-
charged; estimates of the total quan-
tity discharged; estimates of the quan-
tity discharged as described In
§112.1(b); the source of the discharge; a
description of all affected media; the
cause of the discharge; any damages or
Injuries caused by the discharge; ac-
tions being used to stop, remove, and
mitigate the effects of the discharge;
whether an evacuation may be needed;
34
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Environmental Protection Agency
§112.7
and, the names of individuals and/or or-
ganizations who have also been con-
tacted.
(5) Unless you have submitted a re-
sponse plan under §112.20, organize por-
tions of the Plan describing procedures
you will use when a discharge occurs in
a way that will make them readily usa-
ble in an emergency, and include ap-
propriate supporting material as ap-
pendices.
(b) Where experience indicates a rea-
sonable potential for equipment failure
(such as loading or unloading equip-
ment, tank overflow, rupture, or leak-
age, or any other equipment known to
be a source of a discharge), include in
your Plan a prediction of the direction,
rate of flow, and total quantity of oil
which could be discharged from the fa-
cility as a result of each type of major
equipment failure.
(c) Provide appropriate containment
and/or diversionary structures or
equipment to prevent a discharge as
described in §112.1(b), except as pro-
vided in paragraph (k) of this section
for qualified oil-filled operational
equipment, and except as provided in
§112.9(d)(3) for flowlines and intra-facil-
ity gathering lines at an oil production
facility. The entire containment sys-
tem, including walls and floor, must be
capable of containing oil and must be
constructed so that any discharge from
a primary containment system, such as
a tank, will not escape the contain-
ment system before cleanup occurs. In
determining the method, design, and
capacity for secondary containment,
you need only to address the typical
failure mode, and the most likely quan-
tity of oil that would be discharged.
Secondary containment may be either
active or passive in design. At a min-
imum, you must use one of the fol-
lowing prevention systems or its equiv-
alent:
(1) For onshore facilities:
(i) Dikes, berms, or retaining walls
sufficiently impervious to contain oil;
(ii) Curbing or drip pans;
(ill) Sumps and collection systems;
(iv) Culverting, gutters, or other
drainage systems;
(v) Weirs, booms, or other barriers;
(vi) Spill diversion ponds;
(vii) Retention ponds; or
(viii) Sorbent materials.
(2) For offshore facilities:
(i) Curbing or drip pans; or
(ii) Sumps and collection systems.
(d) Provided your Plan is certified by
a licensed Professional Engineer under
§112.3(d), or, in the case of a qualified
facility that meets the criteria in
§112.3(g), the relevant sections of your
Plan are certified by a licensed Profes-
sional Engineer under §112.6(d), if you
determine that the installation of any
of the structures or pieces of equip-
ment listed in paragraphs (c) and (h)(l)
of this section, and §§112.8(c)(2),
112.12(c)(2), and 112.12(c)(ll) to prevent
a discharge as described in §112.1(b)
from any onshore or offshore facility is
not practicable, you must clearly ex-
plain in your Plan why such measures
are not practicable; for bulk storage
containers, conduct both periodic in-
tegrity testing of the containers and
periodic integrity and leak testing of
the valves and piping; and, unless you
have submitted a response plan under
§112.20, provide in your Plan the fol-
lowing:
(1) An oil spill contingency plan fol-
lowing the provisions of part 109 of this
chapter.
(2) A written commitment of man-
power, equipment, and materials re-
quired to expeditiously control and re-
move any quantity of oil discharged
that may be harmful.
(e) Inspections, tests, and records. Con-
duct inspections and tests required by
this part in accordance with written
procedures that you or the certifying
engineer develop for the facility. You
must keep these written procedures
and a record of the inspections and
tests, signed by the appropriate super-
visor or inspector, with the SPCC Plan
for a period of three years. Records of
inspections and tests kept under usual
and customary business practices will
suffice for purposes of this paragraph.
(f) Personnel, training, and discharge
prevention procedures. (1) At a min-
imum, train your oil-handling per-
sonnel in the operation and mainte-
nance of equipment to prevent dis-
charges; discharge procedure protocols;
applicable pollution control laws,
rules, and regulations; general facility
operations; and, the contents of the fa-
cility SPCC Plan.
35
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§112.7
40 CFR Ch. I (7-1-13 Edition)
(2) Designate a person at each appli-
cable facility who is accountable for
discharge prevention and who reports
to facility management.
(3) Schedule and conduct discharge
prevention briefings for your oil-han-
dling personnel at least once a year to
assure adequate understanding of the
SPCC Plan for that facility. Such brief-
ings must highlight and describe
known discharges as described in
§112.1(b) or failures, malfunctioning
components, and any recently devel-
oped precautionary measures.
(g) Security (excluding oil production
facilities). Describe in your Plan how
you secure and control access to the oil
handling, processing and storage areas;
secure master flow and drain valves;
prevent unauthorized access to starter
controls on oil pumps; secure out-of-
service and loading/unloading connec-
tions of oil pipelines; and address the
appropriateness of security lighting to
both prevent acts of vandalism and as-
sist in the discovery of oil discharges.
(h) Facility tank car and tank truck
loading/unloading rack (excluding off-
shore facilities).
(1) Where loading/unloading rack
drainage does not flow into a
catchment basin or treatment facility
designed to handle discharges, use a
quick drainage system for tank car or
tank truck loading/unloading racks.
You must design any containment sys-
tem to hold at least the maximum ca-
pacity of any single compartment of a
tank car or tank truck loaded or un-
loaded at the facility.
(2) Provide an interlocked warning
light or physical barrier system, warn-
ing signs, wheel chocks or vehicle
brake interlock system in the area ad-
jacent to a loading/unloading rack, to
prevent vehicles from departing before
complete disconnection of flexible or
fixed oil transfer lines.
(3) Prior to filling and departure of
any tank car or tank truck, closely in-
spect for discharges the lowermost
drain and all outlets of such vehicles,
and if necessary, ensure that they are
tightened, adjusted, or replaced to pre-
vent liquid discharge while in transit.
(i) If a field-constructed aboveground
container undergoes a repair, alter-
ation, reconstruction, or a change in
service that might affect the risk of a
discharge or failure due to brittle frac-
ture or other catastrophe, or has dis-
charged oil or failed due to brittle frac-
ture failure or other catastrophe,
evaluate the container for risk of dis-
charge or failure due to brittle fracture
or other catastrophe, and as necessary,
take appropriate action.
(j) In addition to the minimal preven-
tion standards listed under this sec-
tion, include in your Plan a complete
discussion of conformance with the ap-
plicable requirements and other effec-
tive discharge prevention and contain-
ment procedures listed in this part or
any applicable more stringent State
rules, regulations, and guidelines.
(k) Qualified Oil-filled Operational
Equipment. The owner or operator of a
facility with oil-filled operational
equipment that meets the qualification
criteria in paragraph (k)(l) of this sub-
section may choose to implement for
this qualified oil-filled operational
equipment the alternate requirements
as described in paragraph (k)(2) of this
sub-section in lieu of general secondary
containment required in paragraph (c)
of this section.
(1) Qualification Criteria—Reportable
Discharge History: The owner or oper-
ator of a facility that has had no single
discharge as described in §112.1(b) from
any oil-filled operational equipment
exceeding 1,000 U.S. gallons or no two
discharges as described in §112.1(b)
from any oil-filled operational equip-
ment each exceeding 42 U.S. gallons
within any twelve month period in the
three years prior to the SPCC Plan cer-
tification date, or since becoming sub-
ject to this part if the facility has been
in operation for less than three years
(other than oil discharges as described
in §112.1(b) that are the result of nat-
ural disasters, acts of war or ter-
rorism); and
(2) Alternative Requirements to General
Secondary Containment. If secondary
containment is not provided for quali-
fied oil-filled operational equipment
pursuant to paragraph (c) of this sec-
tion, the owner or operator of a facility
with qualified oil-filled operational
equipment must:
(i) Establish and document the facil-
ity procedures for inspections or a
monitoring program to detect equip-
ment failure and/or a discharge; and
36
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Environmental Protection Agency
§112.8
(ii) Unless you have submitted a re-
sponse plan under §112.20, provide In
your Plan the following:
(A) An oil spill contingency plan fol-
lowing the provisions of part 109 of this
chapter.
(B) A written commitment of man-
power, equipment, and materials re-
quired to expedltlously control and re-
move any quantity of oil discharged
that may be harmful.
[67 FR 47140, July 17, 2002, as amended at 71
FR 77292, Dec. 26, 2006; 73 FR 74303, Dec. 5,
2008; 74 FR 58810, Nov. 13, 2009]
Subpart B—Requirements for Pe-
troleum Oils and Non-Petro-
leum Oils, Except Animal Fats
and Oils and Greases, and
Fish and Marine Mammal Oils;
and Vegetable Oils (Including
Oils from Seeds, Nuts, Fruits,
and Kernels)
SOURCE: 67 FR 47146, July 17, 2002, unless
otherwise noted.
§112.8 Spill Prevention, Control, and
Counternieasure Plan requirements
for onshore facilities (excluding
production facilities).
If you are the owner or operator of an
onshore facility (excluding a produc-
tion facility), you must:
(a) Meet the general requirements for
the Plan listed under §112.7, and the
specific discharge prevention and con-
tainment procedures listed In this sec-
tion.
(b) Facility drainage. (1) Restrain
drainage from diked storage areas by
valves to prevent a discharge Into the
drainage system or facility effluent
treatment system, except where facil-
ity systems are designed to control
such discharge. You may empty diked
areas by pumps or ejectors; however,
you must manually activate these
pumps or ejectors and must Inspect the
condition of the accumulation before
starting, to ensure no oil will be dis-
charged.
(2) Use valves of manual, open-and-
closed design, for the drainage of diked
areas. You may not use flapper-type
drain valves to drain diked areas. If
your facility drainage drains directly
Into a watercourse and not Into an on-
slte wastewater treatment plant, you
must Inspect and may drain
uncontamlnated retained stormwater,
as provided In paragraphs (c)(3)(ll),
(111), and (Iv) of this section.
(3) Design facility drainage systems
from undlked areas with a potential for
a discharge (such as where piping Is lo-
cated outside containment walls or
where tank truck discharges may occur
outside the loading area) to flow Into
ponds, lagoons, or catchment basins de-
signed to retain oil or return It to the
facility. You must not locate
catchment basins In areas subject to
periodic flooding.
(4) If facility drainage Is not engi-
neered as In paragraph (b)(3) of this
section, equip the final discharge of all
ditches Inside the facility with a diver-
sion system that would, In the event of
an uncontrolled discharge, retain oil In
the facility.
(5) Where drainage waters are treated
In more than one treatment unit and
such treatment Is continuous, and
pump transfer Is needed, provide two
"lift" pumps and permanently Install
at least one of the pumps. Whatever
techniques you use, you must engineer
facility drainage systems to prevent a
discharge as described In §112.1(b) In
case there Is an equipment failure or
human error at the facility.
(c) Bulk storage containers. (1) Not use
a container for the storage of oil unless
Its material and construction are com-
patible with the material stored and
conditions of storage such as pressure
and temperature.
(2) Construct all bulk storage tank
Installations (except mobile refuelers
and other non-transportation-related
tank trucks) so that you provide a sec-
ondary means of containment for the
entire capacity of the largest single
container and sufficient freeboard to
contain precipitation. You must ensure
that diked areas are sufficiently Imper-
vious to contain discharged oil. Dikes,
containment curbs, and pits are com-
monly employed for this purpose. You
may also use an alternative system
consisting of a drainage trench enclo-
sure that must be arranged so that any
discharge will terminate and be safely
confined In a facility catchment basin
or holding pond.
37
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§112.8
40 CFR Ch. I (7-1-13 Edition)
(3) Not allow drainage of
uncontamlnated rainwater from the
diked area Into a storm drain or dis-
charge of an effluent Into an open wa-
tercourse, lake, or pond, bypassing the
facility treatment system unless you:
(1) Normally keep the bypass valve
sealed closed.
(11) Inspect the retained rainwater to
ensure that Its presence will not cause
a discharge as described In §112.1(b).
(Ill) Open the bypass valve and reseal
It following drainage under responsible
supervision; and
(Iv) Keep adequate records of such
events, for example, any records re-
quired under permits Issued In accord-
ance with §§122.41(j)(2) and 122.41(m)(3)
of this chapter.
(4) Protect any completely burled
metallic storage tank Installed on or
after January 10, 1974 from corrosion
by coatings or cathodlc protection
compatible with local soil conditions.
You must regularly leak test such
completely burled metallic storage
tanks.
(5) Not use partially burled or
bunkered metallic tanks for the stor-
age of oil, unless you protect the bur-
led section of the tank from corrosion.
You must protect partially burled and
bunkered tanks from corrosion by
coatings or cathodlc protection com-
patible with local soil conditions.
(6) Test or Inspect each aboveground
container for Integrity on a regular
schedule and whenever you make mate-
rial repairs. You must determine, In
accordance with Industry standards,
the appropriate qualifications for per-
sonnel performing tests and Inspec-
tions, the frequency and type of testing
and Inspections, which take Into ac-
count container size, configuration,
and design (such as containers that
are: shop-built, field-erected, skid-
mounted, elevated, equipped with a
liner, double-walled, or partially bur-
led). Examples of these Integrity tests
Include, but are not limited to: visual
Inspection, hydrostatic testing, radio-
graphic testing, ultrasonic testing,
acoustic emissions testing, or other
systems of non-destructive testing.
You must keep comparison records and
you must also Inspect the container's
supports and foundations. In addition,
you must frequently Inspect the out-
side of the container for signs of dete-
rioration, discharges, or accumulation
of oil Inside diked areas. Records of In-
spections and tests kept under usual
and customary business practices sat-
isfy the recordkeeplng requirements of
this paragraph.
(7) Control leakage through defective
Internal heating colls by monitoring
the steam return and exhaust lines for
contamination from Internal heating
colls that discharge Into an open wa-
tercourse, or pass the steam return or
exhaust lines through a settling tank,
skimmer, or other separation or reten-
tion system.
(8) Engineer or update each container
Installation In accordance with good
engineering practice to avoid dis-
charges. You must provide at least one
of the following devices:
(1) High liquid level alarms with an
audible or visual signal at a constantly
attended operation or surveillance sta-
tion. In smaller facilities an audible air
vent may suffice.
(11) High liquid level pump cutoff de-
vices set to stop flow at a predeter-
mined container content level.
(Ill) Direct audible or code signal
communication between the container
gauger and the pumping station.
(Iv) A fast response system for deter-
mining the liquid level of each bulk
storage container such as digital com-
puters, telepulse, or direct vision
gauges. If you use this alternative, a
person must be present to monitor
gauges and the overall filling of bulk
storage containers.
(v) You must regularly test liquid
level sensing devices to ensure proper
operation.
(9) Observe effluent treatment facili-
ties frequently enough to detect pos-
sible system upsets that could cause a
discharge as described In §112.1(b).
(10) Promptly correct visible dis-
charges which result In a loss of oil
from the container, Including but not
limited to seams, gaskets, piping,
pumps, valves, rivets, and bolts. You
must promptly remove any accumula-
tions of oil In diked areas.
(11) Position or locate mobile or port-
able oil storage containers to prevent a
discharge as described In §112.1(b). Ex-
cept for mobile refuelers and other
non-transportation-related tank
38
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Environmental Protection Agency
§112.9
trucks, you must furnish a secondary
means of containment, such as a dike
or catchment basin, sufficient to con-
tain the capacity of the largest single
compartment or container with suffi-
cient freeboard to contain precipita-
tion.
(d) Facility transfer operations, pump-
ing, and facility process. (1) Provide bur-
ied piping that is installed or replaced
on or after August 16, 2002, with a pro-
tective wrapping and coating. You
must also cathodically protect such
buried piping installations or otherwise
satisfy the corrosion protection stand-
ards for piping in part 280 of this chap-
ter or a State program approved under
part 281 of this chapter. If a section of
buried line is exposed for any reason,
you must carefully inspect it for dete-
rioration. If you find corrosion damage,
you must undertake additional exam-
ination and corrective action as indi-
cated by the magnitude of the damage.
(2) Cap or blank-flange the terminal
connection at the transfer point and
mark it as to origin when piping is not
in service or is in standby service for
an extended time.
(3) Properly design pipe supports to
minimize abrasion and corrosion and
allow for expansion and contraction.
(4) Regularly inspect all aboveground
valves, piping, and appurtenances. Dur-
ing the inspection you must assess the
general condition of items, such as
flange joints, expansion joints, valve
glands and bodies, catch pans, pipeline
supports, locking of valves, and metal
surfaces. You must also conduct integ-
rity and leak testing of buried piping
at the time of installation, modifica-
tion, construction, relocation, or re-
placement.
(5) Warn all vehicles entering the fa-
cility to be sure that no vehicle will
endanger aboveground piping or other
oil transfer operations.
[67 FR 47146, July 17, 2002, as amended at 71
FR 77293, Dec. 26, 2006; 73 FR 74304, Dec. 5,
2008]
§112.9 Spill Prevention, Control, and
Counternieasure Plan Require-
ments for onshore oil production fa-
cilities (excluding drilling and
workover facilities).
If you are the owner or operator of an
onshore oil production facility (exclud-
ing a drilling or workover facility), you
must:
(a) Meet the general requirements for
the Plan listed under §112.7, and the
specific discharge prevention and con-
tainment procedures listed under this
section.
(b) Oil production facility drainage. (1)
At tank batteries and separation and
treating areas where there is a reason-
able possibility of a discharge as de-
scribed in §112.1(b), close and seal at all
times drains of dikes or drains of
equivalent measures required under
§112.7(c)(l), except when draining
uncontaminated rainwater. Prior to
drainage, you must inspect the diked
area and take action as provided in
§112.8(c)(3)(ii), (ill), and (iv). You must
remove accumulated oil on the rain-
water and return it to storage or dis-
pose of it in accordance with legally
approved methods.
(2) Inspect at regularly scheduled in-
tervals field drainage systems (such as
drainage ditches or road ditches), and
oil traps, sumps, or skimmers, for an
accumulation of oil that may have re-
sulted from any small discharge. You
must promptly remove any accumula-
tions of oil.
(c) Oil production facility bulk storage
containers. (1) Not use a container for
the storage of oil unless its material
and construction are compatible with
the material stored and the conditions
of storage.
(2) Except as described in paragraph
(c)(5) of this section for flow-through
process vessels and paragraph (c)(6) of
this section for produced water con-
tainers and any associated piping and
appurtenances downstream from the
container, construct all tank battery,
separation, and treating facility instal-
lations, so that you provide a sec-
ondary means of containment for the
entire capacity of the largest single
container and sufficient freeboard to
contain precipitation. You must safely
confine drainage from undiked areas in
a catchment basin or holding pond.
(3) Except as described in paragraph
(c)(5) of this section for flow-through
process vessels and paragraph (c)(6) of
this section for produced water con-
tainers and any associated piping and
appurtenances downstream from the
39
-------
§112.9
40 CFR Ch. I (7-1-13 Edition)
container, periodically and upon a reg-
ular schedule visually inspect each
container of oil for deterioration and
maintenance needs, including the foun-
dation and support of each container
that is on or above the surface of the
ground.
(4) Engineer or update new and old
tank battery installations in accord-
ance with good engineering practice to
prevent discharges. You must provide
at least one of the following:
(i) Container capacity adequate to as-
sure that a container will not overfill if
a pumper/gauger is delayed in making
regularly scheduled rounds.
(ii) Overflow equalizing lines between
containers so that a full container can
overflow to an adjacent container.
(ill) Vacuum protection adequate to
prevent container collapse during a
pipeline run or other transfer of oil
from the container.
(iv) High level sensors to generate
and transmit an alarm signal to the
computer where the facility is subject
to a computer production control sys-
tem.
(5) Flow-through process vessels. The
owner or operator of a facility with
flow-through process vessels may
choose to implement the alternate re-
quirements as described below in lieu
of sized secondary containment re-
quired in paragraphs (c)(2) and (c)(3) of
this section.
(i) Periodically and on a regular
schedule visually inspect and/or test
flow-through process vessels and asso-
ciated components (such as dump
valves) for leaks, corrosion, or other
conditions that could lead to a dis-
charge as described in §112.1(b).
(ii) Take corrective action or make
repairs to flow-through process vessels
and any associated components as indi-
cated by regularly scheduled visual in-
spections, tests, or evidence of an oil
discharge.
(ill) Promptly remove or initiate ac-
tions to stabilize and remediate any ac-
cumulations of oil discharges associ-
ated with flow-through process vessels.
(iv) If your facility discharges more
than 1,000 U.S. gallons of oil in a single
discharge as described in §112.1(b), or
discharges more than 42 U.S. gallons of
oil in each of two discharges as de-
scribed in §112.1(b) within any twelve
month period, from flow-through proc-
ess vessels (excluding discharges that
are the result of natural disasters, acts
of war, or terrorism) then you must,
within six months from the time the
facility becomes subject to this para-
graph, ensure that all flow-through
process vessels subject to this subpart
comply with §112.9(c)(2) and (c)(3).
(6) Produced water containers. For
each produced water container, comply
with §112.9(c)(l) and (c)(4); and
§112.9(c)(2) and (c)(3), or comply with
the provisions of the following para-
graphs (c)(6)(i) through (v):
(i) Implement, on a regular schedule,
a procedure for each produced water
container that is designed to separate
the free-phase oil that accumulates on
the surface of the produced water. In-
clude in the Plan a description of the
procedures, frequency, amount of free-
phase oil expected to be maintained in-
side the container, and a Professional
Engineer certification in accordance
with §112.3(d)(l)(vi). Maintain records
of such events in accordance with
§112.7(e). Records kept under usual and
customary business practices will suf-
fice for purposes of this paragraph. If
this procedure is not implemented as
described in the Plan or no records are
maintained, then you must comply
with §112.9(c)(2) and (c)(3).
(ii) On a regular schedule, visually
inspect and/or test the produced water
container and associated piping for
leaks, corrosion, or other conditions
that could lead to a discharge as de-
scribed in §112.1(b) in accordance with
good engineering practice.
(ill) Take corrective action or make
repairs to the produced water con-
tainer and any associated piping as in-
dicated by regularly scheduled visual
inspections, tests, or evidence of an oil
discharge.
(iv) Promptly remove or initiate ac-
tions to stabilize and remediate any ac-
cumulations of oil discharges associ-
ated with the produced water con-
tainer.
(v) If your facility discharges more
than 1,000 U.S. gallons of oil in a single
discharge as described in §112.1(b), or
discharges more than 42 U.S. gallons of
oil in each of two discharges as de-
scribed in §112.1(b) within any twelve
month period from a produced water
40
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Environmental Protection Agency
§112.10
container subject to this subpart (ex-
cluding discharges that are the result
of natural disasters, acts of war, or ter-
rorism) then you must, within six
months from the time the facility be-
comes subject to this paragraph, en-
sure that all produced water containers
subject to this subpart comply with
§112.9(c)(2) and (c)(3).
(d) Facility transfer operations, oil pro-
duction facility. (1) Periodically and
upon a regular schedule inspect all
aboveground valves and piping associ-
ated with transfer operations for the
general condition of flange joints,
valve glands and bodies, drip pans, pipe
supports, pumping well polish rod
stuffing boxes, bleeder and gauge
valves, and other such items.
(2) Inspect saltwater (oil field brine)
disposal facilities often, particularly
following a sudden change in atmos-
pheric temperature, to detect possible
system upsets capable of causing a dis-
charge.
(3) For flowlines and intra-facility
gathering lines that are not provided
with secondary containment in accord-
ance with §112.7(c), unless you have
submitted a response plan under
§112.20, provide in your Plan the fol-
lowing:
(i) An oil spill contingency plan fol-
lowing the provisions of part 109 of this
chapter.
(ii) A written commitment of man-
power, equipment, and materials re-
quired to expeditiously control and re-
move any quantity of oil discharged
that might be harmful.
(4) Prepare and implement a written
program of flowline/intra-facility gath-
ering line maintenance. The mainte-
nance program must address your pro-
cedures to:
(i) Ensure that flowlines and intra-fa-
cility gathering lines and associated
valves and equipment are compatible
with the type of production fluids,
their potential corrosivity, volume,
and pressure, and other conditions ex-
pected in the operational environment.
(ii) Visually inspect and/or test
flowlines and intra-facility gathering
lines and associated appurtenances on
a periodic and regular schedule for
leaks, oil discharges, corrosion, or
other conditions that could lead to a
discharge as described in §112.1(b). For
flowlines and intra-facility gathering
lines that are not provided with sec-
ondary containment in accordance
with §112.7(c), the frequency and type
of testing must allow for the imple-
mentation of a contingency plan as de-
scribed under part 109 of this chapter.
(ill) Take corrective action or make
repairs to any flowlines and intra-facil-
ity gathering lines and associated ap-
purtenances as indicated by regularly
scheduled visual inspections, tests, or
evidence of a discharge.
(iv) Promptly remove or initiate ac-
tions to stabilize and remediate any ac-
cumulations of oil discharges associ-
ated with flowlines, intra-facility gath-
ering lines, and associated appur-
tenances.
[73 FR, 74304, Dec. 5, 2008, as amended at 74
FR 58810, Nov. 13, 2009]
§112.10 Spill Prevention, Control, and
Counternieasure Plan requirements
for onshore oil drilling and
workover facilities.
If you are the owner or operator of an
onshore oil drilling and workover facil-
ity, you must:
(a) Meet the general requirements
listed under §112.7, and also meet the
specific discharge prevention and con-
tainment procedures listed under this
section.
(b) Position or locate mobile drilling
or workover equipment so as to pre-
vent a discharge as described in
(c) Provide catchment basins or di-
version structures to intercept and
contain discharges of fuel, crude oil, or
oily drilling fluids.
(d) Install a blowout prevention
(BOP) assembly and well control sys-
tem before drilling below any casing
string or during workover operations.
The BOP assembly and well control
system must be capable of controlling
any well-head pressure that may be en-
countered while that BOP assembly
and well control system are on the
well.
41
-------
§112.11
40 CFR Ch. I (7-1-13 Edition)
§112.11 Spill Prevention, Control, and
Countermeasure Plan requirements
for offshore oil drilling, production,
or workover facilities.
If you are the owner or operator of an
offshore oil drilling, production, or
workover facility, you must:
(a) Meet the general requirements
listed under §112.7, and also meet the
specific discharge prevention and con-
tainment procedures listed under this
section.
(b) Use oil drainage collection equip-
ment to prevent and control small oil
discharges around pumps, glands,
valves, flanges, expansion joints, hoses,
drain lines, separators, treaters, tanks,
and associated equipment. You must
control and direct facility drains to-
ward a central collection sump to pre-
vent the facility from having a dis-
charge as described in §112.1(b). Where
drains and sumps are not practicable,
you must remove oil contained in col-
lection equipment as often as nec-
essary to prevent overflow.
(c) For facilities employing a sump
system, provide adequately sized sump
and drains and make available a spare
pump to remove liquid from the sump
and assure that oil does not escape.
You must employ a regularly scheduled
preventive maintenance inspection and
testing program to assure reliable op-
eration of the liquid removal system
and pump start-up device. Redundant
automatic sump pumps and control de-
vices may be required on some installa-
tions.
(d) At facilities with areas where sep-
arators and treaters are equipped with
dump valves which predominantly fail
in the closed position and where pollu-
tion risk is high, specially equip the fa-
cility to prevent the discharge of oil.
You must prevent the discharge of oil
by:
(1) Extending the flare line to a diked
area if the separator is near shore;
(2) Equipping the separator with a
high liquid level sensor that will auto-
matically shut in wells producing to
the separator; or
(3) Installing parallel redundant
dump valves.
(e) Equip atmospheric storage or
surge containers with high liquid level
sensing devices that activate an alarm
or control the flow, or otherwise pre-
vent discharges.
(f) Equip pressure containers with
high and low pressure sensing devices
that activate an alarm or control the
flow.
(g) Equip containers with suitable
corrosion protection.
(h) Prepare and maintain at the facil-
ity a written procedure within the Plan
for inspecting and testing pollution
prevention equipment and systems.
(i) Conduct testing and inspection of
the pollution prevention equipment
and systems at the facility on a sched-
uled periodic basis, commensurate with
the complexity, conditions, and cir-
cumstances of the facility and any
other appropriate regulations. You
must use simulated discharges for test-
ing and inspecting human and equip-
ment pollution control and counter-
measure systems.
(j) Describe in detailed records sur-
face and subsurface well shut-in valves
and devices in use at the facility for
each well sufficiently to determine
their method of activation or control,
such as pressure differential, change in
fluid or flow conditions, combination
of pressure and flow, manual or remote
control mechanisms.
(k) Install a BOP assembly and well
control system during workover oper-
ations and before drilling below any
casing string. The BOP assembly and
well control system must be capable of
controlling any well-head pressure that
may be encountered while the BOP as-
sembly and well control system are on
the well.
(1) Equip all manifolds (headers) with
check valves on individual flowlines.
(m) Equip the flowline with a high
pressure sensing device and shut-in
valve at the wellhead if the shut-in
well pressure is greater than the work-
ing pressure of the flowline and mani-
fold valves up to and including the
header valves. Alternatively you may
provide a pressure relief system for
flowlines.
(n) Protect all piping appurtenant to
the facility from corrosion, such as
with protective coatings or cathodic
protection.
(o) Adequately protect sub-marine
piping appurtenant to the facility
against environmental stresses and
42
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Environmental Protection Agency
§112.12
other activities such as fishing oper-
ations.
(p) Maintain sub-marine piping ap-
purtenant to the facility in good oper-
ating condition at all times. You must
periodically and according to a sched-
ule inspect or test such piping for fail-
ures. You must document and keep a
record of such inspections or tests at
the facility.
Subpart C—Requirements for Ani-
mal Fats and Oils and
Greases, and Fish and Marine
Mammal Oils; and for Vege-
table Oils, including Oils from
Seeds, Nuts, Fruits, and Ker-
nels
SOURCE: 67 FR 57149, July 17, 2002, unless
otherwise noted.
§112.12 Spill Prevention, Control, and
Counternieasure Plan require-
ments.
If you are the owner or operator of an
onshore facility, you must:
(a) Meet the general requirements for
the Plan listed under §112.7, and the
specific discharge prevention and con-
tainment procedures listed in this sec-
tion.
(b) Facility drainage. (1) Restrain
drainage from diked storage areas by
valves to prevent a discharge into the
drainage system or facility effluent
treatment system, except where facil-
ity systems are designed to control
such discharge. You may empty diked
areas by pumps or ejectors; however,
you must manually activate these
pumps or ejectors and must inspect the
condition of the accumulation before
starting, to ensure no oil will be dis-
charged.
(2) Use valves of manual, open-and-
closed design, for the drainage of diked
areas. You may not use flapper-type
drain valves to drain diked areas. If
your facility drainage drains directly
into a watercourse and not into an on-
site wastewater treatment plant, you
must inspect and may drain
uncontaminated retained stormwater,
subject to the requirements of para-
graphs (c)(3)(ii), (ill), and (iv) of this
section.
(3) Design facility drainage systems
from undiked areas with a potential for
a discharge (such as where piping is lo-
cated outside containment walls or
where tank truck discharges may occur
outside the loading area) to flow into
ponds, lagoons, or catchment basins de-
signed to retain oil or return it to the
facility. You must not locate
catchment basins in areas subject to
periodic flooding.
(4) If facility drainage is not engi-
neered as in paragraph (b)(3) of this
section, equip the final discharge of all
ditches inside the facility with a diver-
sion system that would, in the event of
an uncontrolled discharge, retain oil in
the facility.
(5) Where drainage waters are treated
in more than one treatment unit and
such treatment is continuous, and
pump transfer is needed, provide two
"lift" pumps and permanently install
at least one of the pumps. Whatever
techniques you use, you must engineer
facility drainage systems to prevent a
discharge as described in §112.1(b) in
case there is an equipment failure or
human error at the facility.
(c) Bulk storage containers. (1) Not use
a container for the storage of oil unless
its material and construction are com-
patible with the material stored and
conditions of storage such as pressure
and temperature.
(2) Construct all bulk storage tank
installations (except mobile refuelers
and other non-transportation-related
tank trucks) so that you provide a sec-
ondary means of containment for the
entire capacity of the largest single
container and sufficient freeboard to
contain precipitation. You must ensure
that diked areas are sufficiently imper-
vious to contain discharged oil. Dikes,
containment curbs, and pits are com-
monly employed for this purpose. You
may also use an alternative system
consisting of a drainage trench enclo-
sure that must be arranged so that any
discharge will terminate and be safely
confined in a facility catchment basin
or holding pond.
(3) Not allow drainage of
uncontaminated rainwater from the
diked area into a storm drain or dis-
charge of an effluent into an open wa-
tercourse, lake, or pond, bypassing the
facility treatment system unless you:
43
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§112.12
40 CFR Ch. I (7-1-13 Edition)
(i) Normally keep the bypass valve
sealed closed.
(11) Inspect the retained rainwater to
ensure that Its presence will not cause
a discharge as described In §112.1(b).
(Ill) Open the bypass valve and reseal
It following drainage under responsible
supervision; and
(Iv) Keep adequate records of such
events, for example, any records re-
quired under permits Issued In accord-
ance with §§122.41(j)(2) and 122.41(m)(3)
of this chapter.
(4) Protect any completely burled
metallic storage tank Installed on or
after January 10, 1974 from corrosion
by coatings or cathodlc protection
compatible with local soil conditions.
You must regularly leak test such
completely burled metallic storage
tanks.
(5) Not use partially burled or
bunkered metallic tanks for the stor-
age of oil, unless you protect the bur-
led section of the tank from corrosion.
You must protect partially burled and
bunkered tanks from corrosion by
coatings or cathodlc protection com-
patible with local soil conditions.
(6) Bulk storage container inspections.
(1) Except for containers that meet
the criteria provided In paragraph
(c)(6)(ll) of this section, test or Inspect
each aboveground container for Integ-
rity on a regular schedule and when-
ever you make material repairs. You
must determine, In accordance with In-
dustry standards, the appropriate
qualifications for personnel performing
tests and Inspections, the frequency
and type of testing and Inspections,
which take Into account container size,
configuration, and design (such as con-
tainers that are: shop-built, field-erect-
ed, skid-mounted, elevated, equipped
with a liner, double-walled, or partially
burled). Examples of these Integrity
tests Include, but are not limited to:
Visual Inspection, hydrostatic testing,
radlographlc testing, ultrasonic test-
Ing, acoustic emissions testing, or
other systems of non-destructive test-
Ing. You must keep comparison records
and you must also Inspect the con-
tainer's supports and foundations. In
addition, you must frequently Inspect
the outside of the container for signs of
deterioration, discharges, or accumula-
tion of oil Inside diked areas. Records
of Inspections and tests kept under
usual and customary business practices
satisfy the recordkeeplng requirements
of this paragraph.
(11) For bulk storage containers that
are subject to 21 CFR part 110, are ele-
vated, constructed of austenltlc stain-
less steel, have no external Insulation,
and are shop-fabricated, conduct for-
mal visual Inspection on a regular
schedule. In addition, you must fre-
quently Inspect the outside of the con-
tainer for signs of deterioration, dis-
charges, or accumulation of oil Inside
diked areas. You must determine and
document In the Plan the appropriate
qualifications for personnel performing
tests and Inspections. Records of In-
spections and tests kept under usual
and customary business practices sat-
isfy the recordkeeplng requirements of
this paragraph (c)(6).
(7) Control leakage through defective
Internal heating colls by monitoring
the steam return and exhaust lines for
contamination from Internal heating
colls that discharge Into an open wa-
tercourse, or pass the steam return or
exhaust lines through a settling tank,
skimmer, or other separation or reten-
tion system.
(8) Engineer or update each container
Installation In accordance with good
engineering practice to avoid dis-
charges. You must provide at least one
of the following devices:
(1) High liquid level alarms with an
audible or visual signal at a constantly
attended operation or surveillance sta-
tion. In smaller facilities an audible air
vent may suffice.
(11) High liquid level pump cutoff de-
vices set to stop flow at a predeter-
mined container content level.
(Ill) Direct audible or code signal
communication between the container
gauger and the pumping station.
(Iv) A fast response system for deter-
mining the liquid level of each bulk
storage container such as digital com-
puters, telepulse, or direct vision
gauges. If you use this alternative, a
person must be present to monitor
gauges and the overall filling of bulk
storage containers.
(v) You must regularly test liquid
level sensing devices to ensure proper
operation.
44
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Environmental Protection Agency
§112.20
(9) Observe effluent treatment facili-
ties frequently enough to detect pos-
sible system upsets that could cause a
discharge as described in §112.1(b).
(10) Promptly correct visible dis-
charges which result in a loss of oil
from the container, including but not
limited to seams, gaskets, piping,
pumps, valves, rivets, and bolts. You
must promptly remove any accumula-
tions of oil in diked areas.
(11) Position or locate mobile or port-
able oil storage containers to prevent a
discharge as described in §112.1(b). Ex-
cept for mobile refuelers and other
non-transportation-related tank
trucks, you must furnish a secondary
means of containment, such as a dike
or catchment basin, sufficient to con-
tain the capacity of the largest single
compartment or container with suffi-
cient freeboard to contain precipita-
tion.
(d) Facility transfer operations, pump-
ing, and facility process. (1) Provide bur-
ied piping that is installed or replaced
on or after August 16, 2002, with a pro-
tective wrapping and coating. You
must also cathodically protect such
buried piping installations or otherwise
satisfy the corrosion protection stand-
ards for piping in part 280 of this chap-
ter or a State program approved under
part 281 of this chapter. If a section of
buried line is exposed for any reason,
you must carefully inspect it for dete-
rioration. If you find corrosion damage,
you must undertake additional exam-
ination and corrective action as indi-
cated by the magnitude of the damage.
(2) Cap or blank-flange the terminal
connection at the transfer point and
mark it as to origin when piping is not
in service or is in standby service for
an extended time.
(3) Properly design pipe supports to
minimize abrasion and corrosion and
allow for expansion and contraction.
(4) Regularly inspect all aboveground
valves, piping, and appurtenances. Dur-
ing the inspection you must assess the
general condition of items, such as
flange joints, expansion joints, valve
glands and bodies, catch pans, pipeline
supports, locking of valves, and metal
surfaces. You must also conduct integ-
rity and leak testing of buried piping
at the time of installation, modifica-
tion, construction, relocation, or re-
placement.
(5) Warn all vehicles entering the fa-
cility to be sure that no vehicle will
endanger aboveground piping or other
oil transfer operations.
[67 FR 57149, July 17, 2002, as amended at 71
FR 77293, Dec. 26, 2006; 73 FR 74305, Dec. 5,
2008]
§§112.13-112.15 [Reserved]
Subpart D—Response
Requirements
§112.20 Facility response plans.
(a) The owner or operator of any non-
transportation-related onshore facility
that, because of its location, could rea-
sonably be expected to cause substan-
tial harm to the environment by dis-
charging oil into or on the navigable
waters or adjoining shorelines shall
prepare and submit a facility response
plan to the Regional Administrator,
according to the following provisions:
(1) For the owner or operator of a fa-
cility in operation on or before Feb-
ruary 18, 1993 who is required to pre-
pare and submit a response plan under
33 U.S.C. 1321(j)(5), the Oil Pollution
Act of 1990 (Pub. L. 101-380, 33 U.S.C.
2701 et seq.) requires the submission of
a response plan that satisfies the re-
quirements of 33 U.S.C. 1321(j)(5) no
later than February 18, 1993.
(i) The owner or operator of an exist-
ing facility that was in operation on or
before February 18, 1993 who submitted
a response plan by February 18, 1993
shall revise the response plan to satisfy
the requirements of this section and re-
submit the response plan or updated
portions of the response plan to the Re-
gional Administrator by February 18,
1995.
(ii) The owner or operator of an exist-
ing facility in operation on or before
February 18, 1993 who failed to submit
a response plan by February 18, 1993
shall prepare and submit a response
plan that satisfies the requirements of
this section to the Regional Adminis-
trator before August 30, 1994.
(2) The owner or operator of a facility
in operation on or after August 30, 1994
that satisfies the criteria in paragraph
(f)(l) of this section or that is notified
45
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§112.20
40 CFR Ch. I (7-1-13 Edition)
by the Regional Administrator pursu-
ant to paragraph (b) of this section
shall prepare and submit a facility re-
sponse plan that satisfies the require-
ments of this section to the Regional
Administrator.
(i) For a facility that commenced op-
erations after February 18, 1993 but
prior to August 30, 1994, and is required
to prepare and submit a response plan
based on the criteria in paragraph (f)(l)
of this section, the owner or operator
shall submit the response plan or up-
dated portions of the response plan,
along with a completed version of the
response plan cover sheet contained in
appendix F to this part, to the Re-
gional Administrator prior to August
30, 1994.
(11) For a newly constructed facility
that commences operation after Au-
gust 30, 1994, and is required to prepare
and submit a response plan based on
the criteria in paragraph (f)(l) of this
section, the owner or operator shall
submit the response plan, along with a
completed version of the response plan
cover sheet contained in appendix F to
this part, to the Regional Adminis-
trator prior to the start of operations
(adjustments to the response plan to
reflect changes that occur at the facil-
ity during the start-up phase of oper-
ations must be submitted to the Re-
gional Administrator after an oper-
ational trial period of 60 days).
(ill) For a facility required to prepare
and submit a response plan after Au-
gust 30, 1994, as a result of a planned
change in design, construction, oper-
ation, or maintenance that renders the
facility subject to the criteria in para-
graph (f)(l) of this section, the owner
or operator shall submit the response
plan, along with a completed version of
the response plan cover sheet con-
tained in appendix F to this part, to
the Regional Administrator before the
portion of the facility undergoing
change commences operations (adjust-
ments to the response plan to reflect
changes that occur at the facility dur-
ing the start-up phase of operations
must be submitted to the Regional Ad-
ministrator after an operational trial
period of 60 days).
(iv) For a facility required to prepare
and submit a response plan after Au-
gust 30, 1994, as a result of an un-
planned event or change in facility
characteristics that renders the facil-
ity subject to the criteria in paragraph
(f)(l) of this section, the owner or oper-
ator shall submit the response plan,
along with a completed version of the
response plan cover sheet contained in
appendix F to this part, to the Re-
gional Administrator within six
months of the unplanned event or
change.
(3) In the event the owner or operator
of a facility that is required to prepare
and submit a response plan uses an al-
ternative formula that is comparable
to one contained in appendix C to this
part to evaluate the criterion in para-
graph (f)(l)(ii)(B) or (f)(l)(ii)(C) of this
section, the owner or operator shall at-
tach documentation to the response
plan cover sheet contained in appendix
F to this part that demonstrates the
reliability and analytical soundness of
the alternative formula.
(4) Preparation and submission of re-
sponse plans—Animal fat and vegetable
oil facilities. The owner or operator of
any non-transportation-related facility
that handles, stores, or transports ani-
mal fats and vegetable oils must pre-
pare and submit a facility response
plan as follows:
(i) Facilities with approved plans. The
owner or operator of a facility with a
facility response plan that has been ap-
proved under paragraph (c) of this sec-
tion by July 31, 2000 need not prepare
or submit a revised plan except as oth-
erwise required by paragraphs (b), (c),
or (d) of this section.
(ii) Facilities with plans that have been
submitted to the Regional Administrator.
Except for facilities with approved
plans as provided in paragraph (a)(4)(i)
of this section, the owner or operator
of a facility that has submitted a re-
sponse plan to the Regional Adminis-
trator prior to July 31, 2000 must re-
view the plan to determine if it meets
or exceeds the applicable provisions of
this part. An owner or operator need
not prepare or submit a new plan if the
existing plan meets or exceeds the ap-
plicable provisions of this part. If the
plan does not meet or exceed the appli-
cable provisions of this part, the owner
or operator must prepare and submit a
new plan by September 28, 2000.
46
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Environmental Protection Agency
§112.20
(ill) Newly regulated facilities. The
owner or operator of a newly con-
structed facility that commences oper-
ation after July 31, 2000 must prepare
and submit a plan to the Regional Ad-
ministrator in accordance with para-
graph (a)(2)(ll) of this section. The plan
must meet or exceed the applicable
provisions of this part. The owner or
operator of an existing facility that
must prepare and submit a plan after
July 31, 2000 as a result of a planned or
unplanned change in facility character-
istics that causes the facility to be-
come regulated under paragraph (f)(l)
of this section, must prepare and sub-
mit a plan to the Regional Adminis-
trator in accordance with paragraph
(a)(2)(iii) or (iv) of this section, as ap-
propriate. The plan must meet or ex-
ceed the applicable provisions of this
part.
(iv) Facilities amending existing plans.
The owner or operator of a facility sub-
mitting an amended plan in accordance
with paragraph (d) of this section after
July 31, 2000, including plans that had
been previously approved, must also re-
view the plan to determine if it meets
or exceeds the applicable provisions of
this part. If the plan does not meet or
exceed the applicable provisions of this
part, the owner or operator must revise
and resubmit revised portions of an
amended plan to the Regional Adminis-
trator in accordance with paragraph (d)
of this section, as appropriate. The
plan must meet or exceed the applica-
ble provisions of this part.
(b)(l) The Regional Administrator
may at any time require the owner or
operator of any non-transportation-re-
lated onshore facility to prepare and
submit a facility response plan under
this section after considering the fac-
tors in paragraph (f)(2) of this section.
If such a determination is made, the
Regional Administrator shall notify
the facility owner or operator in writ-
ing and shall provide a basis for the de-
termination. If the Regional Adminis-
trator notifies the owner or operator in
writing of the requirement to prepare
and submit a response plan under this
section, the owner or operator of the
facility shall submit the response plan
to the Regional Administrator within
six months of receipt of such written
notification.
(2) The Regional Administrator shall
review plans submitted by such facili-
ties to determine whether the facility
could, because of its location, reason-
ably be expected to cause significant
and substantial harm to the environ-
ment by discharging oil into or on the
navigable waters or adjoining shore-
lines.
(c) The Regional Administrator shall
determine whether a facility could, be-
cause of its location, reasonably be ex-
pected to cause significant and sub-
stantial harm to the environment by
discharging oil into or on the navigable
waters or adjoining shorelines, based
on the factors in paragraph (f)(3) of this
section. If such a determination is
made, the Regional Administrator
shall notify the owner or operator of
the facility in writing and:
(1) Promptly review the facility re-
sponse plan;
(2) Require amendments to any re-
sponse plan that does not meet the re-
quirements of this section;
(3) Approve any response plan that
meets the requirements of this section;
and
(4) Review each response plan peri-
odically thereafter on a schedule estab-
lished by the Regional Administrator
provided that the period between plan
reviews does not exceed five years.
(d)(l) The owner or operator of a fa-
cility for which a response plan is re-
quired under this part shall revise and
resubmit revised portions of the re-
sponse plan within 60 days of each fa-
cility change that materially may af-
fect the response to a worst case dis-
charge, including:
(i) A change in the facility's configu-
ration that materially alters the infor-
mation included in the response plan;
(ii) A change in the type of oil han-
dled, stored, or transferred that mate-
rially alters the required response re-
sources;
(ill) A material change in capabilities
of the oil spill removal organization(s)
that provide equipment and personnel
to respond to discharges of oil de-
scribed in paragraph (h)(5) of this sec-
tion;
(iv) A material change in the facili-
ty's spill prevention and response
equipment or emergency response pro-
cedures; and
47
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§112.20
40 CFR Ch. I (7-1-13 Edition)
(v) Any other changes that materi-
ally affect the Implementation of the
response plan.
(2) Except as provided In paragraph
(d)(l) of this section, amendments to
personnel and telephone number lists
Included In the response plan and a
change In the oil spill removal organl-
zatlon(s) that does not result In a ma-
terial change In support capabilities do
not require approval by the Regional
Administrator. Facility owners or op-
erators shall provide a copy of such
changes to the Regional Administrator
as the revisions occur.
(3) The owner or operator of a facility
that submits changes to a response
plan as provided In paragraph (d)(l) or
(d)(2) of this section shall provide the
EPA-lssued facility Identification num-
ber (where one has been assigned) with
the changes.
(4) The Regional Administrator shall
review for approval changes to a re-
sponse plan submitted pursuant to
paragraph (d)(l) of this section for a fa-
cility determined pursuant to para-
graph (f)(3) of this section to have the
potential to cause significant and sub-
stantial harm to the environment.
(e) If the owner or operator of a facil-
ity determines pursuant to paragraph
(a)(2) of this section that the facility
could not, because of Its location, rea-
sonably be expected to cause substan-
tial harm to the environment by dis-
charging oil Into or on the navigable
waters or adjoining shorelines, the
owner or operator shall complete and
maintain at the facility the certifi-
cation form contained In appendix C to
this part and, In the event an alter-
native formula that Is comparable to
one contained In appendix C to this
part Is used to evaluate the criterion In
paragraph (f)(l)(ll)(B) or (f)(l)(ll)(C) of
this section, the owner or operator
shall attach documentation to the cer-
tification form that demonstrates the
reliability and analytical soundness of
the comparable formula and shall no-
tify the Regional Administrator In
writing that an alternative formula
was used.
(f)(l) A facility could, because of Its
location, reasonably be expected to
cause substantial harm to the environ-
ment by discharging oil Into or on the
navigable waters or adjoining shore-
lines pursuant to paragraph (a)(2) of
this section, If It meets any of the fol-
lowing criteria applied In accordance
with the flowchart contained In attach-
ment C-I to appendix C to this part:
(1) The facility transfers oil over
water to or from vessels and has a total
oil storage capacity greater than or
equal to 42,000 gallons; or
(11) The facility's total oil storage ca-
pacity Is greater than or equal to 1 mil-
lion gallons, and one of the following Is
true:
(A) The facility does not have sec-
ondary containment for each above-
ground storage area sufficiently large
to contain the capacity of the largest
aboveground oil storage tank within
each storage area plus sufficient
freeboard to allow for precipitation;
(B) The facility Is located at a dis-
tance (as calculated using the appro-
priate formula In appendix C to this
part or a comparable formula) such
that a discharge from the facility could
cause Injury to fish and wildlife and
sensitive environments. For further de-
scription of fish and wildlife and sen-
sitive environments, see Appendices I,
II, and III of the "Guidance for Facility
and Vessel Response Plans: Fish and
Wildlife and Sensitive Environments"
(see appendix E to this part, section 13,
for availability) and the applicable
Area Contingency Plan prepared pursu-
ant to section 311(j)(4) of the Clean
Water Act;
(C) The facility Is located at a dis-
tance (as calculated using the appro-
priate formula In appendix C to this
part or a comparable formula) such
that a discharge from the facility
would shut down a public drinking
water Intake; or
(D) The facility has had a reportable
oil discharge In an amount greater
than or equal to 10,000 gallons within
the last 5 years.
(2)(1) To determine whether a facility
could, because of Its location, reason-
ably be expected to cause substantial
harm to the environment by dis-
charging oil Into or on the navigable
waters or adjoining shorelines pursu-
ant to paragraph (b) of this section, the
Regional Administrator shall consider
the following:
(A) Type of transfer operation;
(B) Oil storage capacity;
48
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Environmental Protection Agency
§112.20
(C) Lack of secondary containment;
(D) Proximity to fish and wildlife and
sensitive environments and other areas
determined by the Regional Adminis-
trator to possess ecological value;
(E) Proximity to drinking water in-
takes;
(F) Spill history; and
(G) Other site-specific characteristics
and environmental factors that the Re-
gional Administrator determines to be
relevant to protecting the environment
from harm by discharges of oil into or
on navigable waters or adjoining shore-
lines.
(ii) Any person, including a member
of the public or any representative
from a Federal, State, or local agency
who believes that a facility subject to
this section could, because of its loca-
tion, reasonably be expected to cause
substantial harm to the environment
by discharging oil into or on the navi-
gable waters or adjoining shorelines
may petition the Regional Adminis-
trator to determine whether the facil-
ity meets the criteria in paragraph
(f)(2)(l) of this section. Such petition
shall include a discussion of how the
factors in paragraph (f)(2)(l) of this sec-
tion apply to the facility in question.
The RA shall consider such petitions
and respond in an appropriate amount
of time.
(3) To determine whether a facility
could, because of its location, reason-
ably be expected to cause significant
and substantial harm to the environ-
ment by discharging oil into or on the
navigable waters or adjoining shore-
lines, the Regional Administrator may
consider the factors in paragraph (f)(2)
of this section as well as the following:
(i) Frequency of past discharges;
(ii) Proximity to navigable waters;
(ill) Age of oil storage tanks; and
(iv) Other facility-specific and Re-
gion-specific information, including
local impacts on public health.
(g)(l) All facility response plans shall
be consistent with the requirements of
the National Oil and Hazardous Sub-
stance Pollution Contingency Plan (40
CFR part 300) and applicable Area Con-
tingency Plans prepared pursuant to
section 311(j)(4) of the Clean Water Act.
The facility response plan should be co-
ordinated with the local emergency re-
sponse plan developed by the local
emergency planning committee under
section 303 of Title III of the Superfund
Amendments and Reauthorization Act
of 1986 (42 U.S.C. 11001 et seq.). Upon re-
quest, the owner or operator should
provide a copy of the facility response
plan to the local emergency planning
committee or State emergency re-
sponse commission.
(2) The owner or operator shall re-
view relevant portions of the National
Oil and Hazardous Substances Pollu-
tion Contingency Plan and applicable
Area Contingency Plan annually and, if
necessary, revise the facility response
plan to ensure consistency with these
plans.
(3) The owner or operator shall re-
view and update the facility response
plan periodically to reflect changes at
the facility.
(h) A response plan shall follow the
format of the model facility-specific re-
sponse plan included in appendix F to
this part, unless you have prepared an
equivalent response plan acceptable to
the Regional Administrator to meet
State or other Federal requirements. A
response plan that does not follow the
specified format in appendix F to this
part shall have an emergency response
action plan as specified in paragraphs
(h)(l) of this section and be supple-
mented with a cross-reference section
to identify the location of the elements
listed in paragraphs (h)(2) through
(h)(10) of this section. To meet the re-
quirements of this part, a response
plan shall address the following ele-
ments, as further described in appendix
F to this part:
(1) Emergency response action plan.
The response plan shall include an
emergency response action plan in the
format specified in paragraphs (h)(l)(i)
through (viii) of this section that is
maintained in the front of the response
plan, or as a separate document accom-
panying the response plan, and that in-
cludes the following information:
(i) The identity and telephone num-
ber of a qualified individual having full
authority, including contracting au-
thority, to implement removal actions;
(ii) The identity of individuals or or-
ganizations to be contacted in the
event of a discharge so that immediate
communications between the qualified
individual identified in paragraph (h)(l)
49
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§112.20
40 CFR Ch. I (7-1-13 Edition)
of this section and the appropriate Fed-
eral officials and the persons providing
response personnel and equipment can
be ensured;
(ill) A description of information to
pass to response personnel in the event
of a reportable discharge;
(iv) A description of the facility's re-
sponse equipment and its location;
(v) A description of response per-
sonnel capabilities, including the du-
ties of persons at the facility during a
response action and their response
times and qualifications;
(vi) Plans for evacuation of the facil-
ity and a reference to community evac-
uation plans, as appropriate;
(vii) A description of immediate
measures to secure the source of the
discharge, and to provide adequate con-
tainment and drainage of discharged
oil; and
(viii) A diagram of the facility.
(2) Facility information. The response
plan shall identify and discuss the loca-
tion and type of the facility, the iden-
tity and tenure of the present owner
and operator, and the identity of the
qualified individual identified in para-
graph (h)(l) of this section.
(3) Information about emergency re-
sponse. The response plan shall include:
(i) The identity of private personnel
and equipment necessary to remove to
the maximum extent practicable a
worst case discharge and other dis-
charges of oil described in paragraph
(h)(5) of this section, and to mitigate or
prevent a substantial threat of a worst
case discharge (To identify response re-
sources to meet the facility response
plan requirements of this section, own-
ers or operators shall follow appendix E
to this part or, where not appropriate,
shall clearly demonstrate in the re-
sponse plan why use of appendix E of
this part is not appropriate at the fa-
cility and make comparable arrange-
ments for response resources);
(ii) Evidence of contracts or other ap-
proved means for ensuring the avail-
ability of such personnel and equip-
ment;
(ill) The identity and the telephone
number of individuals or organizations
to be contacted in the event of a dis-
charge so that immediate communica-
tions between the qualified individual
identified in paragraph (h)(l) of this
section and the appropriate Federal of-
ficial and the persons providing re-
sponse personnel and equipment can be
ensured;
(iv) A description of information to
pass to response personnel in the event
of a reportable discharge;
(v) A description of response per-
sonnel capabilities, including the du-
ties of persons at the facility during a
response action and their response
times and qualifications;
(vi) A description of the facility's re-
sponse equipment, the location of the
equipment, and equipment testing;
(vii) Plans for evacuation of the facil-
ity and a reference to community evac-
uation plans, as appropriate;
(viii) A diagram of evacuation routes;
and
(ix) A description of the duties of the
qualified individual identified in para-
graph (h)(l) of this section, that in-
clude:
(A) Activate internal alarms and haz-
ard communication systems to notify
all facility personnel;
(B) Notify all response personnel, as
needed;
(C) Identify the character, exact
source, amount, and extent of the re-
lease, as well as the other items needed
for notification;
(D) Notify and provide necessary in-
formation to the appropriate Federal,
State, and local authorities with des-
ignated response roles, including the
National Response Center, State Emer-
gency Response Commission, and Local
Emergency Planning Committee;
(E) Assess the interaction of the dis-
charged substance with water and/or
other substances stored at the facility
and notify response personnel at the
scene of that assessment;
(F) Assess the possible hazards to
human health and the environment due
to the release. This assessment must
consider both the direct and indirect
effects of the release (i.e., the effects of
any toxic, irritating, or asphyxiating
gases that may be generated, or the ef-
fects of any hazardous surface water
runoffs from water or chemical agents
used to control fire and heat-induced
explosion);
(G) Assess and implement prompt re-
moval actions to contain and remove
the substance released;
50
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Environmental Protection Agency
§112.20
(H) Coordinate rescue and response
actions as previously arranged with all
response personnel;
(I) Use authority to immediately ac-
cess company funding to initiate clean-
up activities; and
(J) Direct cleanup activities until
properly relieved of this responsibility.
(4) Hazard evaluation. The response
plan shall discuss the facility's known
or reasonably identifiable history of
discharges reportable under 40 CFR
part 110 for the entire life of the facil-
ity and shall identify areas within the
facility where discharges could occur
and what the potential effects of the
discharges would be on the affected en-
vironment. To assess the range of areas
potentially affected, owners or opera-
tors shall, where appropriate, consider
the distance calculated in paragraph
(f)(l)(ii) of this section to determine
whether a facility could, because of its
location, reasonably be expected to
cause substantial harm to the environ-
ment by discharging oil into or on the
navigable waters or adjoining shore-
lines.
(5) Response planning levels. The re-
sponse plan shall include discussion of
specific planning scenarios for:
(i) A worst case discharge, as cal-
culated using the appropriate work-
sheet in appendix D to this part. In
cases where the Regional Adminis-
trator determines that the worst case
discharge volume calculated by the fa-
cility is not appropriate, the Regional
Administrator may specify the worst
case discharge amount to be used for
response planning at the facility. For
complexes, the worst case planning
quantity shall be the larger of the
amounts calculated for each compo-
nent of the facility;
(ii) A discharge of 2,100 gallons or
less, provided that this amount is less
than the worst case discharge amount.
For complexes, this planning quantity
shall be the larger of the amounts cal-
culated for each component of the fa-
cility; and
(ill) A discharge greater than 2,100
gallons and less than or equal to 36,000
gallons or 10 percent of the capacity of
the largest tank at the facility, which-
ever is less, provided that this amount
is less than the worst case discharge
amount. For complexes, this planning
quantity shall be the larger of the
amounts calculated for each compo-
nent of the facility.
(6) Discharge detection systems. The re-
sponse plan shall describe the proce-
dures and equipment used to detect dis-
charges.
(7) Plan implementation. The response
plan shall describe:
(i) Response actions to be carried out
by facility personnel or contracted per-
sonnel under the response plan to en-
sure the safety of the facility and to
mitigate or prevent discharges de-
scribed in paragraph (h)(5) of this sec-
tion or the substantial threat of such
discharges;
(ii) A description of the equipment to
be used for each scenario;
(ill) Plans to dispose of contaminated
cleanup materials; and
(iv) Measures to provide adequate
containment and drainage of dis-
charged oil.
(8) Self-inspection, drills/exercises, and
response training. The response plan
shall include:
(i) A checklist and record of inspec-
tions for tanks, secondary contain-
ment, and response equipment;
(ii) A description of the drill/exercise
program to be carried out under the re-
sponse plan as described in §112.21;
(ill) A description of the training pro-
gram to be carried out under the re-
sponse plan as described in §112.21; and
(iv) Logs of discharge prevention
meetings, training sessions, and drills/
exercises. These logs may be main-
tained as an annex to the response
plan.
(9) Diagrams. The response plan shall
include site plan and drainage plan dia-
grams.
(10) Security systems. The response
plan shall include a description of fa-
cility security systems.
(11) Response plan cover sheet. The re-
sponse plan shall include a completed
response plan cover sheet provided in
section 2.0 of appendix F to this part.
(i)(l) In the event the owner or oper-
ator of a facility does not agree with
the Regional Administrator's deter-
mination that the facility could, be-
cause of its location, reasonably be ex-
pected to cause substantial harm or
significant and substantial harm to the
environment by discharging oil into or
51
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§112.21
40 CFR Ch. I (7-1-13 Edition)
on the navigable waters or adjoining
shorelines, or that amendments to the
facility response plan are necessary
prior to approval, such as changes to
the worst case discharge planning vol-
ume, the owner or operator may sub-
mit a request for reconsideration to
the Regional Administrator and pro-
vide additional information and data in
writing to support the request. The re-
quest and accompanying information
must be submitted to the Regional Ad-
ministrator within 60 days of receipt of
notice of the Regional Administrator's
original decision. The Regional Admin-
istrator shall consider the request and
render a decision as rapidly as prac-
ticable.
(2) In the event the owner or operator
of a facility believes a change in the fa-
cility's classification status is war-
ranted because of an unplanned event
or change in the facility's characteris-
tics (i.e., substantial harm or signifi-
cant and substantial harm), the owner
or operator may submit a request for
reconsideration to the Regional Ad-
ministrator and provide additional in-
formation and data in writing to sup-
port the request. The Regional Admin-
istrator shall consider the request and
render a decision as rapidly as prac-
ticable.
(3) After a request for reconsider-
ation under paragraph (i)(l) or (1)(2) of
this section has been denied by the Re-
gional Administrator, an owner or op-
erator may appeal a determination
made by the Regional Administrator.
The appeal shall be made to the EPA
Administrator and shall be made in
writing within 60 days of receipt of the
decision from the Regional Adminis-
trator that the request for reconsider-
ation was denied. A complete copy of
the appeal must be sent to the Re-
gional Administrator at the time the
appeal is made. The appeal shall con-
tain a clear and concise statement of
the issues and points of fact in the
case. It also may contain additional in-
formation from the owner or operator,
or from any other person. The EPA Ad-
ministrator may request additional in-
formation from the owner or operator,
or from any other person. The EPA Ad-
ministrator shall render a decision as
rapidly as practicable and shall notify
the owner or operator of the decision.
[59 FR 34098, July 1, 1994, as amended at 65
FR 40798, June 30, 2000; 66 FR 34560, June 29,
2001; 67 FR 47151, July 17, 2002]
§112.21 Facility response training and
drills/exercises.
(a) The owner or operator of any fa-
cility required to prepare a facility re-
sponse plan under §112.20 shall develop
and implement a facility response
training program and a drill/exercise
program that satisfy the requirements
of this section. The owner or operator
shall describe the programs in the re-
sponse plan as provided in §112.20(h)(8).
(b) The facility owner or operator
shall develop a facility response train-
ing program to train those personnel
involved in oil spill response activities.
It is recommended that the training
program be based on the USCG's Train-
ing Elements for Oil Spill Response, as
applicable to facility operations. An al-
ternative program can also be accept-
able subject to approval by the Re-
gional Administrator.
(1) The owner or operator shall be re-
sponsible for the proper instruction of
facility personnel in the procedures to
respond to discharges of oil and in ap-
plicable oil spill response laws, rules,
and regulations.
(2) Training shall be functional in na-
ture according to job tasks for both su-
pervisory and non-supervisory oper-
ational personnel.
(3) Trainers shall develop specific les-
son plans on subject areas relevant to
facility personnel involved in oil spill
response and cleanup.
(c) The facility owner or operator
shall develop a program of facility re-
sponse drills/exercises, including eval-
uation procedures. A program that fol-
lows the National Preparedness for Re-
sponse Exercise Program (PREP) (see
appendix E to this part, section 13, for
availability) will be deemed satisfac-
tory for purposes of this section. An al-
ternative program can also be accept-
able subject to approval by the Re-
gional Administrator.
[59 FR 34101, July 1, 1994, as amended at 65
FR 40798, June 30, 2000]
52
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Environmental Protection Agency
Pt. 112, App. A
APPENDIX A TO PART 112—MEMORANDUM
OF UNDERSTANDING BETWEEN THE
SECRETARY OF TRANSPORTATION AND
THE ADMINISTRATOR OF THE ENVI-
RONMENTAL PROTECTION AGENCY
SECTION II—DEFINITIONS
The Environmental Protection Agency and
the Department of Transportation agree that
for the purposes of Executive Order 11548, the
term:
(1) Non-transportation-related onshore and
offshore facilities means:
(A) Fixed onshore and offshore oil well
drilling facilities including all equipment
and appurtenances related thereto used in
drilling operations for exploratory or devel-
opment wells, but excluding any terminal fa-
cility, unit or process integrally associated
with the handling or transferring of oil in
bulk to or from a vessel.
(B) Mobile onshore and offshore oil well
drilling platforms, barges, trucks, or other
mobile facilities including all equipment and
appurtenances related thereto when such
mobile facilities are fixed in position for the
purpose of drilling operations for exploratory
or development wells, but excluding any ter-
minal facility, unit or process integrally as-
sociated with the handling or transferring of
oil in bulk to or from a vessel.
(C) Fixed onshore and offshore oil produc-
tion structures, platforms, derricks, and rigs
including all equipment and appurtenances
related thereto, as well as completed wells
and the wellhead separators, oil separators,
and storage facilities used in the production
of oil, but excluding any terminal facility,
unit or process integrally associated with
the handling or transferring of oil in bulk to
or from a vessel.
(D) Mobile onshore and offshore oil produc-
tion facilities including all equipment and
appurtenances related thereto as well as
completed wells and wellhead equipment,
piping from wellheads to oil separators, oil
separators, and storage facilities used in the
production of oil when such mobile facilities
are fixed in position for the purpose of oil
production operations, but excluding any
terminal facility, unit or process integrally
associated with the handling or transferring
of oil in bulk to or from a vessel.
(E) Oil refining facilities including all
equipment and appurtenances related there-
to as well as in-plant processing units, stor-
age units, piping, drainage systems and
waste treatment units used in the refining of
oil, but excluding any terminal facility, unit
or process integrally associated with the
handling or transferring of oil in bulk to or
from a vessel.
(F) Oil storage facilities including all
equipment and appurtenances related there-
to as well as fixed bulk plant storage, ter-
minal oil storage facilities, consumer stor-
age, pumps and drainage systems used in the
storage of oil, but excluding inline or break-
out storage tanks needed for the continuous
operation of a pipeline system and any ter-
minal facility, unit or process integrally as-
sociated with the handling or transferring of
oil in bulk to or from a vessel.
(G) Industrial, commercial, agricultural or
public facilities which use and store oil, but
excluding any terminal facility, unit or proc-
ess integrally associated with the handling
or transferring of oil in bulk to or from a
vessel.
(H) Waste treatment facilities including
in-plant pipelines, effluent discharge lines,
and storage tanks, but excluding waste
treatment facilities located on vessels and
terminal storage tanks and appurtenances
for the reception of oily ballast water or
tank washings from vessels and associated
systems used for off-loading vessels.
(I) Loading racks, transfer hoses, loading
arms and other equipment which are appur-
tenant to a nontransportation-related facil-
ity or terminal facility and which are used
to transfer oil in bulk to or from highway ve-
hicles or railroad cars.
(J) Highway vehicles and railroad cars
which are used for the transport of oil exclu-
sively within the confines of a nontrans-
portation-related facility and which are not
intended to transport oil in interstate or
intrastate commerce.
(K) Pipeline systems which are used for the
transport of oil exclusively within the con-
fines of a nontransportation-related facility
or terminal facility and which are not in-
tended to transport oil in interstate or intra-
state commerce, but excluding pipeline sys-
tems used to transfer oil in bulk to or from
a vessel.
(2) Transportation-related onshore and off-
shore facilities means:
(A) Onshore and offshore terminal facili-
ties including transfer hoses, loading arms
and other equipment and appurtenances used
for the purpose of handling or transferring
oil in bulk to or from a vessel as well as stor-
age tanks and appurtenances for the recep-
tion of oily ballast water or tank washings
from vessels, but excluding terminal waste
treatment facilities and terminal oil storage
facilities.
(B) Transfer hoses, loading arms and other
equipment appurtenant to a non-transpor-
tation-related facility which is used to trans-
fer oil in bulk to or from a vessel.
(C) Interstate and intrastate onshore and
offshore pipeline systems including pumps
and appurtenances related thereto as well as
in-line or breakout storage tanks needed for
the continuous operation of a pipeline sys-
tem, and pipelines from onshore and offshore
oil production facilities, but excluding on-
shore and offshore piping from wellheads to
oil separators and pipelines which are used
for the transport of oil exclusively within
53
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Pt. 112, App. B
40 CFR Ch. I (7-1-13 Edition)
the confines of a nontransportation-related
facility or terminal facility and which are
not intended to transport oil in interstate or
intrastate commerce or to transfer oil in
bulk to or from a vessel.
(D) Highway vehicles and railroad cars
which are used for the transport of oil in
interstate or intrastate commerce and the
equipment and appurtenances related there-
to, and equipment used for the fueling of lo-
comotive units, as well as the rights-of-way
on which they operate. Excluded are high-
way vehicles and railroad cars and motive
power used exclusively within the confines of
a nontransportation-related facility or ter-
minal facility and which are not intended for
use in interstate or intrastate commerce.
APPENDIX B TO PART 112—MEMORANDUM
OF UNDERSTANDING AMONG THE SEC-
RETARY OF THE INTERIOR, SEC-
RETARY OF TRANSPORTATION, AND
ADMINISTRATOR OF THE ENVIRON-
MENTAL PROTECTION AGENCY
PURPOSE
This Memorandum of Understanding
(MOU) establishes the jurisdictional respon-
sibilities for offshore facilities, including
pipelines, pursuant to section 311 (j)(l)(c),
(j)(5), and (j)(6)(A) of the Clean Water Act
(CWA), as amended by the Oil Pollution Act
of 1990 (Public Law 101-380). The Secretary of
the Department of the Interior (DOI), Sec-
retary of the Department of Transportation
(DOT), and Administrator of the Environ-
mental Protection Agency (EPA) agree to
the division of responsibilities set forth
below for spill prevention and control, re-
sponse planning, and equipment inspection
activities pursuant to those provisions.
BACKGROUND
Executive Order (E.O.) 12777 (56 PR 54757)
delegates to DOI, DOT, and EPA various re-
sponsibilities identified in section 311(j) of
the CWA. Sections 2(b)(3), 2(d)(3), and 2(e)(3)
of E.O. 12777 assigned to DOI spill prevention
and control, contingency planning, and
equipment inspection activities associated
with offshore facilities. Section 311(a)(ll) de-
fines the term "offshore facility" to include
facilities of any kind located in, on, or under
navigable waters of the United States. By
using this definition, the traditional DOI
role of regulating facilities on the Outer
Continental Shelf is expanded by E.O. 12777
to include inland lakes, rivers, streams, and
any other inland waters.
RESPONSIBILITIES
Pursuant to section 2(i) of E.O. 12777, DOI
redelegates, and EPA and DOT agree to as-
sume, the functions vested in DOI by sec-
tions 2(b)(3), 2(d)(3), and 2(e)(3) of E.O. 12777
as set forth below. For purposes of this MOU,
the term "coast line" shall be defined as in
the Submerged Lands Act (43 U.S.C. 1301(c))
to mean "the line of ordinary low water
along that portion of the coast which is in
direct contact with the open sea and the line
marking the seaward limit of inland
waters."
1. To EPA, DOI redelegates responsibility
for non-transportation-related offshore fa-
cilities located landward of the coast line.
2. To DOT, DOI redelegates responsibility
for transportation-related facilities, includ-
ing pipelines, located landward of the coast
line. The DOT retains jurisdiction for deep-
water ports and their associated seaward
pipelines, as delegated by E.O. 12777.
3. The DOI retains jurisdiction over facili-
ties, including pipelines, located seaward of
the coast line, except for deepwater ports
and associated seaward pipelines delegated
by E.O. 12777 to DOT.
EFFECTIVE DATE
This MOU is effective on the date of the
final execution by the indicated signatories.
LIMITATIONS
1. The DOI, DOT, and EPA may agree in
writing to exceptions to this MOU on a facil-
ity-specific basis. Affected parties will re-
ceive notification of the exceptions.
2. Nothing in this MOU is intended to re-
place, supersede, or modify any existing
agreements between or among DOI, DOT, or
EPA.
MODIFICATION AND TERMINATION
Any party to this agreement may propose
modifications by submitting them in writing
to the heads of the other agency/department.
No modification may be adopted except with
the consent of all parties. All parties shall
indicate their consent to or disagreement
with any proposed modification within 60
days of receipt. Upon the request of any
party, representatives of all parties shall
meet for the purpose of considering excep-
tions or modifications to this agreement.
This MOU may be terminated only with the
mutual consent of all parties.
Dated: November 8, 1993.
Bruce Babbitt,
Secretary of the Interior.
Dated: December 14, 1993.
Federico Pena,
Secretary of Transportation.
Dated: February 3, 1994.
Carol M. Browner,
Administrator, Environmental Protection
Agency.
[59 FR 34102, July 1, 1994]
54
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Environmental Protection Agency
Pt. 112, App. C
APPENDIX C TO PART 112—SUBSTANTIAL
HARM CRITERIA
1.0 INTRODUCTION
The flowchart provided in Attachment C-I
to this appendix shows the decision tree with
the criteria to identify whether a facility
"could reasonably be expected to cause sub-
stantial harm to the environment by dis-
charging into or on the navigable waters or
adjoining shorelines." In addition, the Re-
gional Administrator has the discretion to
identify facilities that must prepare and sub-
mit facility-specific response plans to EPA.
1.1 Definitions
1.1.1 Great Lakes means Lakes Superior,
Michigan, Huron, Brie, and Ontario, their
connecting and tributary waters, the Saint
Lawrence River as far as Saint Regis, and
adjacent port areas.
1.1.2 Higher Volume Port Areas include
(1) Boston, MA;
(2) New York, NY;
(3) Delaware Bay and River to Philadel-
phia, PA;
(4) St. Croix, VI;
(5) Pascagoula, MS;
(6) Mississippi River from Southwest Pass,
LA to Baton Rouge, LA;
(7) Louisiana Offshore Oil Port (LOOP),
LA;
(8) Lake Charles, LA;
(9) Sabine-Neches River, TX;
(10) Galveston Bay and Houston Ship Chan-
nel, TX;
(11) Corpus Christi, TX;
(12) Los Angeles/Long Beach Harbor, CA;
(13) San Francisco Bay, San Pablo Bay,
Carquinez Strait, and Suisun Bay to Anti-
och, CA;
(14) Straits of Juan de Fuca from Port An-
geles, WA to and including Puget Sound,
WA;
(15) Prince William Sound, AK; and
(16) Others as specified by the Regional Ad-
ministrator for any EPA Region.
1.1.3 Inland Area means the area shore-
ward of the boundary lines defined in 46 CFR
part 7, except in the Gulf of Mexico. In the
Gulf of Mexico, it means the area shoreward
of the lines of demarcation (COLRBG lines as
defined in 33 CFR 80.740-80.850). The inland
area does not include the Great Lakes.
1.1.4 Rivers and Canals means a body of
water confined within the inland area, in-
cluding the Intracoastal Waterways and
other waterways artificially created for
navigating that have project depths of 12 feet
or less.
2.0 DESCRIPTION OF SCREENING CRITERIA FOR
THE SUBSTANTIAL HARM FLOWCHART
A facility that has the potential to cause
substantial harm to the environment in the
event of a discharge must prepare and sub-
mit a facility-specific response plan to EPA
in accordance with appendix F to this part.
A description of the screening criteria for
the substantial harm flowchart is provided
below:
2.1 Non-Transportation-Related Facilities
With a Total Oil Storage Capacity Greater Than
or Equal to 42,000 Gallons Where Operations In-
clude Over-Water Transfers of Oil. A non-
transportation-related facility with a total
oil storage capacity greater than or equal to
42,000 gallons that transfers oil over water to
or from vessels must submit a response plan
to EPA. Daily oil transfer operations at
these types of facilities occur between barges
and vessels and onshore bulk storage tanks
over open water. These facilities are located
adjacent to navigable water.
2.2 Lack of Adequate Secondary Contain-
ment at Facilities With a Total Oil Storage Ca-
pacity Greater Than or Equal to 1 Million Gal-
lons. Any facility with a total oil storage ca-
pacity greater than or equal to 1 million gal-
lons without secondary containment suffi-
ciently large to contain the capacity of the
largest aboveground oil storage tank within
each area plus sufficient freeboard to allow
for precipitation must submit a response
plan to EPA. Secondary containment struc-
tures that meet the standard of good engi-
neering practice for the purposes of this part
include berms, dikes, retaining walls, curb-
ing, culverts, gutters, or other drainage sys-
tems.
2.3 Proximity to Fish and Wildlife and Sen-
sitive Environments at Facilities With a Total
Oil Storage Capacity Greater Than or Equal to
1 Million Gallons. A facility with a total oil
storage capacity greater than or equal to 1
million gallons must submit its response
plan if it is located at a distance such that
a discharge from the facility could cause in-
jury (as defined at 40 CFR 112.2) to fish and
wildlife and sensitive environments. For fur-
ther description of fish and wildlife and sen-
sitive environments, see Appendices I, II, and
III to DOC/NOAA's "Guidance for Facility
and Vessel Response Plans: Fish and Wildlife
and Sensitive Environments" (see appendix
E to this part, section 13, for availability)
and the applicable Area Contingency Plan.
Facility owners or operators must determine
the distance at which an oil discharge could
cause injury to fish and wildlife and sen-
sitive environments using the appropriate
formula presented in Attachment C-III to
this appendix or a comparable formula.
2.4 Proximity to Public Drinking Water In-
takes at Facilities with a Total Oil Storage Ca-
pacity Greater than or Equal to 1 Million Gal-
lons A facility with a total oil storage capac-
ity greater than or equal to 1 million gallons
must submit its response plan if it is located
at a distance such that a discharge from the
facility would shut down a public drinking
water intake, which is analogous to a public
water system as described at 40 CFR 143.2(c).
55
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Pt. 112, App. C
The distance at which an oil discharge from
an SPCC-regulated facility would shut down
a public drinking water intake shall be cal-
culated using the appropriate formula pre-
sented in Attachment C-III to this appendix
or a comparable formula.
2.5 Facilities That Have Experienced Report-
able Oil Discharges in an Amount Greater Than
or Equal to 10,000 Gallons Within the Past 5
Years and That Have a Total Oil Storage Ca-
pacity Greater Than or Equal to 1 Million Gal-
lons. A facility's oil spill history within the
past 5 years shall be considered in the eval-
uation for substantial harm. Any facility
with a total oil storage capacity greater
than or equal to 1 million gallons that has
experienced a reportable oil discharge in an
amount greater than or equal to 10,000 gal-
lons within the past 5 years must submit a
response plan to EPA.
3.0 CERTIFICATION FOR FACILITIES THAT Do
NOT POSE SUBSTANTIAL HARM
If the facility does not meet the substan-
tial harm criteria listed in Attachment C-I
40 CFR Ch. I (7-1-13 Edition)
to this appendix, the owner or operator shall
complete and maintain at the facility the
certification form contained in Attachment
C-II to this appendix. In the event an alter-
native formula that is comparable to the one
in this appendix is used to evaluate the sub-
stantial harm criteria, the owner or operator
shall attach documentation to the certifi-
cation form that demonstrates the reli-
ability and analytical soundness of the com-
parable formula and shall notify the Re-
gional Administrator in writing that an al-
ternative formula was used.
4.0 REFERENCES
Chow, V.T. 1959. Open Channel Hydraulics.
McGraw Hill.
USCG IFR (58 PR 7353, February 5, 1993).
This document is available through BPA's
rulemaking docket as noted in appendix B to
this part, section 13.
56
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Environmental Protection Agency
ATTACHMENTS TO APPENDIX C
Pt. 112, App. C
Attachment C-I
Flowchart of Criteria for Substantial Harm
Does the facility transfer oil over
water to or from vessels and does
the facility have a total oil
storage capacity greater than or
equal to 42,000 gallons?
Submit Response Plan
Does the facility have a total oil
storage capacity greater than or
equal to 1 million gallons?
Within any abovcground storage tank area,
does the facility lack secondary
containment that is sufficiently large to
contain the capacity of the largest
aboveground oil storage tank plus
sufficient freeboard to allow for
precipitation?
Is the facility located at a distance1 such
that a discharge from the facility could
cause injury to fish and wildlife and
sensitive environments2?
No
Is the facility located at a distance1 such
that a discharge from the facility would
shut down a public drinking water intake3"
Has the facility experienced a reportable oil
spill in an amount greater than or equal to
10,000 gallons within the last five years?
No Submittal of Response Plan
Except at RA Discretion
1 Calculated using the appropriate formula in Attachment C-III to this appendix or a comparable
formula.
2 For further description offish and wildlife and sensitive environments, see Appendices I,II, and
III to DOC/NOAA's "Guidance for Facility and vessel response Plans: Fish and Wildlife and
Sensitive Environments" (59 FR 14713, March 29, 1994) and the applicable Area Contingency
Plan.
3 Public drinking water intakes are analogous to public water systems as described at CFR
143.2(c).
57
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Pt. 112, App. C
40 CFR Ch. I (7-1-13 Edition)
ATTACHMENT C-II—CERTIFICATION OF THE AP-
PLICABILITY OF THE SUBSTANTIAL HARM CRI-
TERIA
Facility Name:
Facility Address:
1. Does the facility transfer oil over water
to or from vessels and does the facility have
a total oil storage capacity greater than or
equal to 42,000 gallons?
Yes No
2. Does the facility have a total oil storage
capacity greater than or equal to 1 million
gallons and does the facility lack secondary
containment that is sufficiently large to
contain the capacity of the largest above-
ground oil storage tank plus sufficient
freeboard to allow for precipitation within
any aboveground oil storage tank area?
Yes No
3. Does the facility have a total oil storage
capacity greater than or equal to 1 million
gallons and is the facility located at a dis-
tance (as calculated using the appropriate
formula in Attachment C-III to this appen-
dix or a comparable formula1) such that a
discharge from the facility could cause in-
jury to fish and wildlife and sensitive envi-
ronments? For further description of fish and
wildlife and sensitive environments, see Ap-
pendices I, II, and III to DOC/NOAA's "Guid-
ance for Facility and Vessel Response Plans:
Fish and Wildlife and Sensitive Environ-
ments" (see appendix B to this part, section
13, for availability) and the applicable Area
Contingency Plan.
Yes No
4. Does the facility have a total oil storage
capacity greater than or equal to 1 million
gallons and is the facility located at a dis-
tance (as calculated using the appropriate
formula in Attachment C-III to this appendix
or a comparable formula1) such that a dis-
charge from the facility would shut down a
public drinking water intake2?
Yes No
5. Does the facility have a total oil storage
capacity greater than or equal to 1 million
gallons and has the facility experienced a re-
portable oil discharge in an amount greater
than or equal to 10,000 gallons within the last
5 years?
Yes No
Certification
I certify under penalty of law that I have
personally examined and am familiar with
the information submitted in this document,
1lf a comparable formula is used, docu-
mentation of the reliability and analytical
soundness of the comparable formula must
be attached to this form.
2 For the purposes of 40 CFR part 112, pub-
lic drinking water intakes are analogous to
public water systems as described at 40 CFR
143.2(c).
and that based on my inquiry of those indi-
viduals responsible for obtaining this infor-
mation, I believe that the submitted infor-
mation is true, accurate, and complete.
Signature
Name (please type or print)
Title
Date
ATTACHMENT C-III—CALCULATION OF THE
PLANNING DISTANCE
1.0 Introduction
1.1 The facility owner or operator must
evaluate whether the facility is located at a
distance such that a discharge from the fa-
cility could cause injury to fish and wildlife
and sensitive environments or disrupt oper-
ations at a public drinking water intake. To
quantify that distance, EPA considered oil
transport mechanisms over land and on still,
tidal influence, and moving navigable
waters. EPA has determined that the pri-
mary concern for calculation of a planning
distance is the transport of oil in navigable
waters during adverse weather conditions.
Therefore, two formulas have been developed
to determine distances for planning purposes
from the point of discharge at the facility to
the potential site of impact on moving and
still waters, respectively. The formula for oil
transport on moving navigable water is
based on the velocity of the water body and
the time interval for arrival of response re-
sources. The still water formula accounts for
the spread of discharged oil over the surface
of the water. The method to determine oil
transport on tidal influence areas is based on
the type of oil discharged and the distance
down current during ebb tide and up current
during flood tide to the point of maximum
tidal influence.
1.2 EPA's formulas were designed to be
simple to use. However, facility owners or
operators may calculate planning distances
using more sophisticated formulas, which
take into account broader scientific or engi-
neering principles, or local conditions. Such
comparable formulas may result in different
planning distances than EPA's formulas. In
the event that an alternative formula that is
comparable to one contained in this appen-
dix is used to evaluate the criterion in 40
CFR 112.20(f)(l)(ii)(B) or (f)(l)(ii)(C), the
owner or operator shall attach documenta-
tion to the response plan cover sheet con-
tained in appendix F to this part that dem-
onstrates the reliability and analytical
soundness of the alternative formula and
shall notify the Regional Administrator in
58
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Environmental Protection Agency
Pt. 112, App. C
writing that an alternative formula was
used.1
1.3 A regulated facility may meet the cri-
teria for the potential to cause substantial
harm to the environment without having to
perform a planning distance calculation. For
facilities that meet the substantial harm cri-
teria because of inadequate secondary con-
tainment or oil spill history, as listed in the
flowchart in Attachment C-I to this appen-
dix, calculation of the planning distance is
unnecessary. For facilities that do not meet
the substantial harm criteria for secondary
containment or oil spill history as listed in
the flowchart, calculation of a planning dis-
tance for proximity to fish and wildlife and
sensitive environments and public drinking
water intakes is required, unless it is clear
without performing the calculation (e.g., the
facility is located in a wetland) that these
areas would be impacted.
1.4 A facility owner or operator who must
perform a planning distance calculation on
navigable water is only required to do so for
the type of navigable water conditions (i.e.,
moving water, still water, or tidal- influ-
enced water) applicable to the facility. If a
facility owner or operator determines that
more than one type of navigable water condi-
tion applies, then the facility owner or oper-
ator is required to perform a planning dis-
tance calculation for each navigable water
type to determine the greatest single dis-
tance that oil may be transported. As a re-
sult, the final planning distance for oil
transport on water shall be the greatest indi-
vidual distance rather than a summation of
each calculated planning distance.
1.5 The planning distance formula for
transport on moving waterways contains
three variables: the velocity of the navigable
water (v), the response time interval (t), and
a conversion factor (c). The velocity, v, is de-
termined by using the Chezy-Manning equa-
tion, which, in this case, models the flood
flow rate of water in open channels. The
Chezy-Manning equation contains three vari-
ables which must be determined by facility
owners or operators. Manning's Roughness
!For persistent oils or non-persistent oils,
a worst case trajectory model (i.e., an alter-
native formula) may be substituted for the
distance formulas described in still, moving,
and tidal waters, subject to Regional Admin-
istrator's review of the model. An example of
an alternative formula that is comparable to
the one contained in this appendix would be
a worst case trajectory calculation based on
credible adverse winds, currents, and/or river
stages, over a range of seasons, weather con-
ditions, and river stages. Based on historical
information or a spill trajectory model, the
Agency may require that additional fish and
wildlife and sensitive environments or public
drinking water intakes also be protected.
Coefficient (for flood flow rates), n, can be
determined from Table 1 of this attachment.
The hydraulic radius, r, can be estimated
using the average mid-channel depth from
charts provided by the sources listed in
Table 2 of this attachment. The average
slope of the river, s, can be determined using
topographic maps that can be ordered from
the U.S. Geological Survey, as listed in
Table 2 of this attachment.
1.6 Table 3 of this attachment contains
specified time intervals for estimating the
arrival of response resources at the scene of
a discharge. Assuming no prior planning, re-
sponse resources should be able to arrive at
the discharge site within 12 hours of the dis-
covery of any oil discharge in Higher Volume
Port Areas and within 24 hours in Great
Lakes and all other river, canal, inland, and
nearshore areas. The specified time intervals
in Table 3 of appendix C are to be used only
to aid in the identification of whether a fa-
cility could cause substantial harm to the
environment. Once it is determined that a
plan must be developed for the facility, the
owner or operator shall reference appendix B
to this part to determine appropriate re-
source levels and response times. The speci-
fied time intervals of this appendix include a
3-hour time period for deployment of boom
and other response equipment. The Regional
Administrator may identify additional areas
as appropriate.
2.0 Oil Transport on Moving Navigable Waters
2.1 The facility owner or operator must
use the following formula or a comparable
formula as described in §112.20(a)(3) to cal-
culate the planning distance for oil transport
on moving navigable water:
d=vxtxc; where
d: the distance downstream from a facility
within which fish and wildlife and sen-
sitive environments could be injured or a
public drinking water intake would be
shut down in the event of an oil dis-
charge (in miles);
v: the velocity of the river/navigable water of
concern (in ft/sec) as determined by
Chezy-Manning's equation (see below and
Tables 1 and 2 of this attachment);
t: the time interval specified in Table 3 based
upon the type of water body and location
(in hours); and
c: constant conversion factor 0.68 seco) mile/
hro) ft (3600 sec/hr •*• 5280 ft/mile).
2.2 Chezy-Manning's equation is used to de-
termine velocity:
v=1.5/nxr%xs1/2; where
v=the velocity of the river of concern (in ft/
sec);
n=Manning's Roughness Coefficient from
Table 1 of this attachment;
r=the hydraulic radius; the hydraulic radius
can be approximated for parabolic chan-
nels by multiplying the average mid-
59
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Pt. 112, App. C
40 CFR Ch. I (7-1-13 Edition)
channel depth of the river (in feet) by
0.667 (sources for obtaining the mid-chan-
nel depth are listed in Table 2 of this at-
tachment); and
s=the average slope of the river (unitless) ob-
tained from U.S. Geological Survey topo-
graphic maps at the address listed in
Table 2 of this attachment.
TABLE 1—MANNING'S ROUGHNESS COEFFICIENT
FOR NATURAL STREAMS
[NOTE: Coefficients are presented for high flow rates at or
near flood stage.]
Stream description
Minor Streams (Top Width <100 ft.)
Clean:
Straight
Winding
Sluggish (Weedy, deep pools):
No trees or brush
Major Streams (Top Width >100 ft.)
Regular section:
(No boulders/brush)
Irregular section:
(Brush)
Rough-
ness co-
efficient
(n)
003
0.04
0.06
0 10
0.035
0.05
TABLE 2—SOURCES OF R AND s FOR THE CHEZY-
MANNING EQUATION
All of the charts and related publications for
navigational waters may be ordered from:
Distribution Branch
(N/CG33)
National Ocean Service
Riverdale, Maryland 20737-1199
Phone: (301) 436-6990
There will be a charge for materials ordered
and a VISA or Mastercard will be accepted.
The mid-channel depth to be used in the cal-
culation of the hydraulic radius (r) can be
obtained directly from the following sources:
Charts of Canadian Coastal and Great Lakes
Waters:
Canadian Hydrographic Service
Department of Fisheries and Oceans Insti-
tute
P.O. Box 8080
1675 Russell Road
Ottawa, Ontario KIG 3H6
Canada
Phone: (613) 998^931
Charts and Maps of Lower Mississippi River
(Gulf of Mexico to Ohio River and St.
Francis, White, Big Sunflower,
Atchafalaya, and other rivers):
U.S. Army Corps of Engineers
Vicksburg District
P.O. Box 60
Vicksburg, Mississippi 39180
Phone: (601) 634-5000
Charts of Upper Mississippi River and Illi-
nois Waterway to Lake Michigan:
U.S. Army Corps of Engineers
Rock Island District
P.O. Box 2004
Rock Island, Illinois 61204
Phone: (309) 794-5552
Charts of Missouri River:
U.S. Army Corps of Engineers
Omaha District
6014 U.S. Post Office and Courthouse
Omaha, Nebraska 68102
Phone: (402) 221-3900
Charts of Ohio River:
U.S. Army Corps of Engineers
Ohio River Division
P.O. Box 1159
Cincinnati, Ohio 45201
Phone: (513) 684-3002
Charts of Tennessee Valley Authority Res-
ervoirs, Tennessee River and Tributaries:
Tennessee Valley Authority
Maps and Engineering Section
416 Union Avenue
Knoxville, Tennessee 37902
Phone: (615) 632-2921
Charts of Black Warrior River, Alabama
River, Tombigbee River, Apalachicola
River and Pearl River:
U.S. Army Corps of Engineers
Mobile District
P.O. Box 2288
Mobile, Alabama 36628-0001
Phone: (205) 690-2511
The average slope of the river (s) may be ob-
tained from topographic maps:
U.S. Geological Survey
Map Distribution
Federal Center
Bldg. 41
Box 25286
Denver, Colorado 80225
Additional information can be obtained from
the following sources:
1. The State's Department of Natural Re-
sources (DNR) or the State's Aids to Navi-
gation office;
2. A knowledgeable local marina operator; or
3. A knowledgeable local water authority
(e.g., State water commission)
2.3 The average slope of the river (s) can
be determined from the topographic maps
using the following steps:
(1) Locate the facility on the map.
(2) Find the Normal Pool Elevation at the
point of discharge from the facility into the
water (A).
(3) Find the Normal Pool Elevation of the
public drinking water intake or fish and
wildlife and sensitive environment located
downstream (B) (Note: The owner or oper-
ator should use a minimum of 20 miles down-
stream as a cutoff to obtain the average
slope if the location of a specific public
drinking water intake or fish and wildlife
and sensitive environment is unknown).
(4) If the Normal Pool Elevation is not
available, the elevation contours can be used
to find the slope. Determine elevation of the
water at the point of discharge from the fa-
cility (A). Determine the elevation of the
60
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Environmental Protection Agency
Pt. 112, App. C
water at the appropriate distance down-
stream (B). The formula presented below can
be used to calculate the slope.
(5) Determine the distance (in miles) be-
tween the facility and the public drinking
water intake or fish and wildlife and sen-
sitive environments (C).
(6) Use the following formula to find the
slope, which will be a unitless value: Average
Slope=[(A-B) (ft)/C (miles)] x [1 mile/5280
feet]
2.4 If it is not feasible to determine the
slope and mid-channel depth by the Chezy-
Manning equation, then the river velocity
can be approximated on- site. A specific
length, such as 100 feet, can be marked off
along the shoreline. A float can be dropped
into the stream above the mark, and the
time required for the float to travel the dis-
tance can be used to determine the velocity
in feet per second. However, this method will
not yield an average velocity for the length
of the stream, but a velocity only for the
specific location of measurement. In addi-
tion, the flow rate will vary depending on
weather conditions such as wind and rainfall.
It is recommended that facility owners or
operators repeat the measurement under a
variety of conditions to obtain the most ac-
curate estimate of the surface water velocity
under adverse weather conditions.
2.5 The planning distance calculations for
moving and still navigable waters are based
on worst case discharges of persistent oils.
Persistent oils are of concern because they
can remain in the water for significant peri-
ods of time and can potentially exist in large
quantities downstream. Owners or operators
of facilities that store persistent as well as
non-persistent oils may use a comparable
formula. The volume of oil discharged is not
included as part of the planning distance cal-
culation for moving navigable waters. Facili-
ties that will meet this substantial harm cri-
terion are those with facility capacities
greater than or equal to 1 million gallons. It
is assumed that these facilities are capable
of having an oil discharge of sufficient quan-
tity to cause injury to fish and wildlife and
sensitive environments or shut down a public
drinking water intake. While owners or oper-
ators of transfer facilities that store greater
than or equal to 42,000 gallons are not re-
quired to use a planning distance formula for
purposes of the substantial harm criteria,
they should use a planning distance calcula-
tion in the development of facility-specific
response plans.
TABLE 3—SPECIFIED TIME INTERVALS
TABLE 3—SPECIFIED TIME INTERVALS—
Continued
Operating
areas
Higher volume
port area.
Great Lakes ...
Substantial harm planning time (hrs)
Operating
areas
All other rivers
and canals,
inland, and
nearshore
areas.
Substantial
harm planning time (hrs)
24 hour arrival+3 hour deployment=27
hours.
12 hour arrival+3 hour deployments 5
hours.
24 hour arrival+3 hour deployment=27
hours.
2.6 Example of the Planning Distance Cal-
culation for Oil Transport on Moving Navigable
Waters. The following example provides a
sample calculation using the planning dis-
tance formula for a facility discharging oil
into the Monongahela River:
(1) Solve for v by evaluating n, r, and s for
the Chezy-Manning equation:
Find the roughness coefficient, n, on Table
1 of this attachment for a regular section of
a major stream with a top width greater
than 100 feet. The top width of the river can
be found from the topographic map.
n=0.035.
Find slope, s, where A=727 feet, B=710 feet,
and C=25 miles.
Solving:
s=[(727 ft-1710 ft)/25 miles]x[l mile/5280
feet]=l.3xlO-4
The average mid-channel depth is found by
averaging the mid-channel depth for each
mile along the length of the river between
the facility and the public drinking water in-
take or the fish or wildlife or sensitive envi-
ronment (or 20 miles downstream if applica-
ble). This value is multiplied by 0.667 to ob-
tain the hydraulic radius. The mid-channel
depth is found by obtaining values for r and
s from the sources shown in Table 2 for the
Monongahela River.
Solving:
r=0.667x20 feet=13.33 feet
Solve for v using:
v=1.5/nxr2/3xs172:
v=[1.5/0.035]x(13.33)™x(1.3xlO-4)i'2
v=2.73 feet/second
(2) Find t from Table 3 of this attachment.
The Monongahela River's resource response
time is 27 hours.
(3) Solve for planning distance, d:
d=vxtxc
d=(2.73 ft/sec)x(27 hours)x(0.68 seem mile/hro)
ft)
d=50 miles
Therefore, 50 miles downstream is the appro-
priate planning distance for this facility.
3.0 Oil Transport on Still Water
3.1 For bodies of water including lakes or
ponds that do not have a measurable veloc-
ity, the spreading of the oil over the surface
must be considered. Owners or operators of
facilities located next to still water bodies
may use a comparable means of calculating
61
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Pt. 112, App. C
40 CFR Ch. I (7-1-13 Edition)
the planning distance. If a comparable for-
mula is used, documentation of the reli-
ability and analytical soundness of the com-
parable calculation must be attached to the
response plan cover sheet.
3.2 Example of the Planning Distance Cal-
culation for Oil Transport on Still Water. To as-
sist those facilities which could potentially
discharge into a still body of water, the fol-
lowing analysis was performed to provide an
example of the type of formula that may be
used to calculate the planning distance. For
this example, a worst case discharge of
2,000,000 gallons is used.
(1) The surface area in square feet covered
by an oil discharge on still water, Al, can be
determined by the following formula,2 where
V is the volume of the discharge in gallons
and C is a constant conversion factor:
Ai=10BxV%xC
0=0.1643
Ai=106x(2,000,OOOgallons)3/4X(0.1643)
A1=8.74xl08 ft2
(2) The spreading formula is based on the
theoretical condition that the oil will spread
uniformly in all directions forming a circle.
In reality, the outfall of the discharge will
direct the oil to the surface of the water
where it intersects the shoreline. Although
the oil will not spread uniformly in all direc-
tions, it is assumed that the discharge will
spread from the shoreline into a semi-circle
(this assumption does not account for winds
or wave action).
(3) The area of a circle=t r2
(4) To account for the assumption that oil
will spread in a semi-circular shape, the area
of a circle is divided by 2 and is designated as
A2.
A2=(t r2)/2
Solving for the radius, r, using the relation-
ship Ai=A2: 8.74xl08 ft2=(t2)/2
Therefore, r=23,586 ft
r=23,586 ft*5,280 ft/mile=4.5 miles
Assuming a 20 knot wind under storm condi-
tions:
1 knot=1.15 miles/hour
20 knotsxl.15 miles/hour/knot=23 miles/hr
Assuming that the oil slick moves at 3 per-
cent of the wind's speed:3
23 miles/hourx0.03=0.69 miles/hour
(5) To estimate the distance that the oil
will travel, use the times required for re-
sponse resources to arrive at different geo-
graphic locations as shown in Table 3 of this
attachment.
For example:
2Huang, J.C. and Monastero, F.C., 1982. Re-
view of the State-of-the-Art of Oil Pollution
Models. Final report submitted to the Amer-
ican Petroleum Institute by Raytheon Ocean
Systems, Co., Bast Providence, Rhode Island.
3 Oil Spill Prevention & Control. National
Spill Control School, Corpus Christ! State
University, Thirteenth Edition, May 1990.
For Higher Volume Port Areas: 15 hrsxO.69
miles/hr=10.4 miles
For Great Lakes and all other areas: 27
hrsxO.69 miles/hr=18.6 miles
(6) The total distance that the oil will
travel from the point of discharge, including
the distance due to spreading, is calculated
as follows:
Higher Volume Port Areas: d=10.4+4.5 miles
or approximately 15 miles
Great Lakes and all other areas: d=18.6+4.5
miles or approximately 23 miles
4.0 Oil Transport on Tidal-Influence Areas
4.1 The planning distance method for
tidal influence navigable water is based on
worst case discharges of persistent and non-
persistent oils. Persistent oils are of primary
concern because they can potentially cause
harm over a greater distance. For persistent
oils discharged into tidal waters, the plan-
ning distance is 15 miles from the facility
down current during ebb tide and to the
point of maximum tidal influence or 15
miles, whichever is less, during flood tide.
4.2 For non-persistent oils discharged into
tidal waters, the planning distance is 5 miles
from the facility down current during ebb
tide and to the point of maximum tidal influ-
ence or 5 miles, whichever is less, during
flood tide.
4.3 Example of Determining the Planning
Distance for Two Types of Navigable Water
Conditions. Below is an example of how to de-
termine the proper planning distance when a
facility could impact two types of navigable
water conditions: moving water and tidal
water.
(1) Facility X stores persistent oil and is
located downstream from locks along a slow
moving river which is affected by tides. The
river velocity, v, is determined to be 0.5 feet/
second from the Chezy-Manning equation
used to calculate oil transport on moving
navigable waters. The specified time inter-
val, t, obtained from Table 3 of this attach-
ment for river areas is 27 hours. Therefore,
solving for the planning distance, d:
d=vxtxc
d=(0.5 ft/sec)x(27 hours)x(0.68 secmile/hrft)
d=9.18 miles.
(2) However, the planning distance for
maximum tidal influence down current dur-
ing ebb tide is 15 miles, which is greater than
the calculated 9.18 miles. Therefore, 15 miles
downstream is the appropriate planning dis-
tance for this facility.
5.0 Oil Transport Over Land
5.1 Facility owners or operators must
evaluate the potential for oil to be trans-
ported over land to navigable waters of the
United States. The owner or operator must
evaluate the likelihood that portions of a
worst case discharge would reach navigable
62
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Environmental Protection Agency
Pt. 112, App. C
waters via open channel flow or from sheet
flow across the land, or be prevented from
reaching navigable waters when trapped in
natural or man-made depressions excluding
secondary containment structures.
5.2 As discharged oil travels over land, it
may enter a storm drain or open concrete
channel intended for drainage. It is assumed
that once oil reaches such an inlet, it will
flow into the receiving navigable water. Dur-
ing a storm event, it is highly probable that
the oil will either flow into the drainage
structures or follow the natural contours of
the land and flow into the navigable water.
Expected minimum and maximum velocities
are provided as examples of open concrete
channel and pipe flow. The ranges listed
below reflect minimum and maximum ve-
locities used as design criteria.4 The calcula-
tion below demonstrates that the time re-
quired for oil to travel through a storm drain
or open concrete channel to navigable water
is negligible and can be considered instanta-
neous. The velocities are:
For open concrete channels:
maximum velocity=25 feet per second
minimum velocity=3 feet per second
For storm drains:
maximum velocity=25 feet per second
minimum velocity=2 feet per second
5.3 Assuming a length of 0.5 mile from the
point of discharge through an open concrete
channel or concrete storm drain to a navi-
gable water, the travel times (distance/veloc-
ity) are:
1.8 minutes at a velocity of 25 feet per second
14.7 minutes at a velocity of 3 feet per second
22.0 minutes for at a velocity of 2 feet per
second
5.4 The distances that shall be considered
to determine the planning distance are illus-
trated in Figure C-I of this attachment. The
relevant distances can be described as fol-
lows:
Dl=Distance from the nearest opportunity
for discharge, Xi, to a storm drain or an
open concrete channel leading to navi-
gable water.
D2=Distance through the storm drain or
open concrete channel to navigable
water.
D3=Distance downstream from the outfall
within which fish and wildlife and sen-
4 The design velocities were obtained from
Howard County, Maryland Department of
Public Works' Storm Drainage Design Man-
ual.
sitive environments could be injured or a
public drinking water intake would be
shut down as determined by the planning
distance formula.
D4=Distance from the nearest opportunity
for discharge, X2, to fish and wildlife and
sensitive environments not bordering
navigable water.
5.5 A facility owner or operator whose
nearest opportunity for discharge is located
within 0.5 mile of a navigable water must
complete the planning distance calculation
(D3) for the type of navigable water near the
facility or use a comparable formula.
5.6 A facility that is located at a distance
greater than 0.5 mile from a navigable water
must also calculate a planning distance (D3)
if it is in close proximity (i.e., Dl is less than
0.5 mile and other factors are conducive to
oil travel over land) to storm drains that
flow to navigable waters. Factors to be con-
sidered in assessing oil transport over land
to storm drains shall include the topography
of the surrounding area, drainage patterns,
man-made barriers (excluding secondary
containment structures), and soil distribu-
tion and porosity. Storm drains or concrete
drainage channels that are located in close
proximity to the facility can provide a direct
pathway to navigable waters, regardless of
the length of the drainage pipe. If Dl is less
than or equal to 0.5 mile, a discharge from
the facility could pose substantial harm be-
cause the time to travel the distance from
the storm drain to the navigable water (D2)
is virtually instantaneous.
5.7 A facility's proximity to fish and wild-
life and sensitive environments not bor-
dering a navigable water, as depicted as D4
in Figure C-I of this attachment, must also
be considered, regardless of the distance
from the facility to navigable waters. Fac-
tors to be considered in assessing oil trans-
port over land to fish and wildlife and sen-
sitive environments should include the to-
pography of the surrounding area, drainage
patterns, man-made barriers (excluding sec-
ondary containment structures), and soil dis-
tribution and porosity.
5.8 If a facility is not found to pose sub-
stantial harm to fish and wildlife and sen-
sitive environments not bordering navigable
waters via oil transport on land, then sup-
porting documentation should be maintained
at the facility. However, such documentation
should be submitted with the response plan
if a facility is found to pose substantial
harm.
63
-------
g
ss
p_
Sf
Figure G - I
CH
£
4T
Distances that Shall Be Considered to Determine the Planning Distance
Top. View
Fish and Wildlife and
Sensitive Environments
Nearest opportunity
for discharge
Storm Drain
Side View
X,
-
X,
Stc
Fish and Wildlife and
Sensitive Environments
Planning Distance
D3
Public Drinking
Water Intake
Flow
and Sensitive
Environments
JO
o
o
g
** Not to scale
o
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Environmental Protection Agency
Pt. 112, App. D
APPENDIX D TO PART 112—DETERMINA-
TION OF A WORST CASE DISCHARGE
PLANNING VOLUME
1.0 Instructions
1.1 An owner or operator is required to
complete this worksheet if the facility meets
the criteria, as presented in appendix C to
this part, or it is determined by the RA that
the facility could cause substantial harm to
the environment. The calculation of a worst
case discharge planning volume is used for
emergency planning purposes, and is re-
quired in 40 CFR 112.20 for facility owners or
operators who must prepare a response plan.
When planning for the amount of resources
and equipment necessary to respond to the
worst case discharge planning volume, ad-
verse weather conditions must be taken into
consideration. An owner or operator is re-
quired to determine the facility's worst case
discharge planning volume from either part
A of this appendix for an onshore storage fa-
cility, or part B of this appendix for an on-
shore production facility. The worksheet
considers the provision of adequate sec-
ondary containment at a facility.
1.2 For onshore storage facilities and pro-
duction facilities, permanently manifolded
oil storage tanks are defined as tanks that
are designed, installed, and/or operated in
such a manner that the multiple tanks func-
tion as one storage unit (i.e., multiple tank
volumes are equalized). In a worst case dis-
charge scenario, a single failure could cause
the discharge of the contents of more than
one tank. The owner or operator must pro-
vide evidence in the response plan that tanks
with common piping or piping systems are
not operated as one unit. If such evidence is
provided and is acceptable to the RA, the
worst case discharge planning volume would
be based on the capacity of the largest oil
storage tank within a common secondary
containment area or the largest oil storage
tank within a single secondary containment
area, whichever is greater. For permanently
manifolded tanks that function as one oil
storage unit, the worst case discharge plan-
ning volume would be based on the combined
oil storage capacity of all manifolded tanks
or the capacity of the largest single oil stor-
age tank within a secondary containment
area, whichever is greater. For purposes of
this rule, permanently manifolded tanks
that are separated by internal divisions for
each tank are considered to be single tanks
and individual manifolded tank volumes are
not combined.
1.3 For production facilities, the presence
of exploratory wells, production wells, and
oil storage tanks must be considered in the
calculation. Part B of this appendix takes
these additional factors into consideration
and provides steps for their inclusion in the
total worst case discharge planning volume.
Onshore oil production facilities may include
all wells, flowlines, separation equipment,
storage facilities, gathering lines, and auxil-
iary non-transportation-related equipment
and facilities in a single geographical oil or
gas field operated by a single operator. Al-
though a potential worst case discharge
planning volume is calculated within each
section of the worksheet, the final worst
case amount depends on the risk parameter
that results in the greatest volume.
1.4 Marine transportation-related transfer
facilities that contain fixed aboveground on-
shore structures used for bulk oil storage are
jointly regulated by EPA and the U.S. Coast
Guard (USCG), and are termed "complexes."
Because the USCG also requires response
plans from transportation-related facilities
to address a worst case discharge of oil, a
separate calculation for the worst case dis-
charge planning volume for USCG-related fa-
cilities is included in the USCG IFR (see ap-
pendix B to this part, section 13, for avail-
ability). All complexes that are jointly regu-
lated by EPA and the USCG must compare
both calculations for worst case discharge
planning volume derived by using the EPA
and USCG methodologies and plan for which-
ever volume is greater.
PART A: WORST CASE DISCHARGE PLAN-
NING VOLUME CALCULATION FOR ON-
SHORE STORAGE FACILITIES1
Part A of this worksheet is to be com-
pleted by the owner or operator of an SPCC-
regulated facility (excluding oil production
facilities) if the facility meets the criteria as
presented in appendix C to this part, or if it
is determined by the RA that the facility
could cause substantial harm to the environ-
ment. If you are the owner or operator of a
production facility, please proceed to part B
of this worksheet.
A.I SINGLE-TANK FACILITIES
For facilities containing only one above-
ground oil storage tank, the worst case dis-
charge planning volume equals the capacity
of the oil storage tank. If adequate sec-
ondary containment (sufficiently large to
contain the capacity of the aboveground oil
storage tank plus sufficient freeboard to
allow for precipitation) exists for the oil
storage tank, multiply the capacity of the
tank by 0.8.
(1) FINAL WORST CASE VOLUME:
GAL
(2) Do not proceed further.
1 "Storage facilities" represent all facili-
ties subject to this part, excluding oil pro-
duction facilities.
65
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Pt. 112, App. D
40 CFR Ch. I (7-1-13 Edition)
A.2 SECONDARY CONTAINMENT—
MULTIPLE-TANK FACILITIES
Are all aboveground oil storage tanks or
groups of aboveground oil storage tanks at
the facility without adequate secondary con-
tainment? 2
(Y/N)
A.2.1 If the answer is yes, the final worst
case discharge planning volume equals the
total aboveground oil storage capacity at the fa-
cility.
(1) FINAL WORST CASE VOLUME:
GAL
(2) Do not proceed further.
A.2.2 If the answer is no, calculate the
total aboveground oil storage capacity of
tanks without adequate secondary contain-
ment. If all aboveground oil storage tanks or
groups of aboveground oil storage tanks at
the facility have adequate secondary con-
tainment, ENTER "0" (zero).
GAL
A.2.3 Calculate the capacity of the largest
single aboveground oil storage tank within
an adequate secondary containment area or
the combined capacity of a group of above-
ground oil storage tanks permanently
manifolded together, whichever is greater,
PLUS THE VOLUME FROM QUESTION
A.2.2.
FINAL WORST CASE VOLUME:3
GAL
PART B: WORST CASE DISCHARGE PLAN-
NING VOLUME CALCULATION FOR ON-
SHORE PRODUCTION FACILITIES
Part B of this worksheet is to be completed
by the owner or operator of an SPCC-regu-
lated oil production facility if the facility
meets the criteria presented in appendix C to
this part, or if it is determined by the RA
that the facility could cause substantial
harm. A production facility consists of all
wells (producing and exploratory) and re-
lated equipment in a single geographical oil
or gas field operated by a single operator.
B.I SINGLE-TANK FACILITIES
B.I.I For facilities containing only one
aboveground oil storage tank, the worst case
discharge planning volume equals the capac-
ity of the aboveground oil storage tank plus
the production volume of the well with the
highest output at the facility. If adequate
2 Secondary containment is described in 40
CFR part 112, subparts A through C. Accept-
able methods and structures for containment
are also given in 40 CFR 112.7(c)(l).
3A11 complexes that are jointly regulated
by EPA and the USCG must also calculate
the worst case discharge planning volume for
the transportation-related portions of the fa-
cility and plan for whichever volume is
greater.
secondary containment (sufficiently large to
contain the capacity of the aboveground oil
storage tank plus sufficient freeboard to
allow for precipitation) exists for the storage
tank, multiply the capacity of the tank by
0.8.
B.I.2 For facilities with production wells
producing by pumping, if the rate of the well
with the highest output is known and the
number of days the facility is unattended
can be predicted, then the production volume
is equal to the pumping rate of the well mul-
tiplied by the greatest number of days the
facility is unattended.
B.I.3 If the pumping rate of the well with
the highest output is estimated or the max-
imum number of days the facility is unat-
tended is estimated, then the production vol-
ume is determined from the pumping rate of
the well multiplied by 1.5 times the greatest
number of days that the facility has been or
is expected to be unattended.
B.I.4 Attachment D-l to this appendix
provides methods for calculating the produc-
tion volume for exploratory wells and pro-
duction wells producing under pressure.
(1) FINAL WORST CASE VOLUME:
GAL
(2) Do not proceed further.
B.2 SECONDARY CONTAINMENT—
MULTIPLE-TANK FACILITIES
Are all aboveground oil storage tanks or
groups of aboveground oil storage tanks at
the facility without adequate secondary con-
tainment?
(Y/N)
B.2.1 If the answer is yes, the final worst
case volume equals the total aboveground oil
storage capacity without adequate secondary
containment plus the production volume of
the well with the highest output at the facil-
ity.
(1) For facilities with production wells pro-
ducing by pumping, if the rate of the well
with the highest output is known and the
number of days the facility is unattended
can be predicted, then the production volume
is equal to the pumping rate of the well mul-
tiplied by the greatest number of days the
facility is unattended.
(2) If the pumping rate of the well with the
highest output is estimated or the maximum
number of days the facility is unattended is
estimated, then the production volume is de-
termined from the pumping rate of the well
multiplied by 1.5 times the greatest number
of days that the facility has been or is ex-
pected to be unattended.
(3) Attachment D-l to this appendix pro-
vides methods for calculating the production
volumes for exploratory wells and produc-
tion wells producing under pressure.
(A) FINAL WORST CASE VOLUME:
GAL
(B) Do not proceed further.
66
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Environmental Protection Agency
Pt. 112, App. D
B.2.2 If the answer is no, calculate the
total aboveground oil storage capacity of
tanks without adequate secondary contain-
ment. If all aboveground oil storage tanks or
groups of aboveground oil storage tanks at
the facility have adequate secondary con-
tainment, ENTER "0" (zero).
GAL
B.2.3 Calculate the capacity of the largest
single aboveground oil storage tank within
an adequate secondary containment area or
the combined capacity of a group of above-
ground oil storage tanks permanently
manifolded together, whichever is greater,
plus the production volume of the well with
the highest output, PLUS THE VOLUME
FROM QUESTION B.2.2. Attachment D-l
provides methods for calculating the produc-
tion volumes for exploratory wells and pro-
duction wells producing under pressure.
(1) FINAL WORST CASE VOLUME:"
GAL
(2) Do not proceed further.
ATTACHMENTS TO APPENDIX D
ATTACHMENT D-I—METHODS To CALCULATE
PRODUCTION VOLUMES FOR PRODUCTION FA-
CILITIES WITH EXPLORATORY WELLS OR PRO-
DUCTION WELLS PRODUCING UNDER PRES-
SURE
1.0 Introduction
The owner or operator of a production fa-
cility with exploratory wells or production
wells producing under pressure shall com-
pare the well rate of the highest output well
(rate of well), in barrels per day, to the abil-
ity of response equipment and personnel to
recover the volume of oil that could be dis-
charged (rate of recovery), in barrels per day.
The result of this comparison will determine
the method used to calculate the production
volume for the production facility. This pro-
duction volume is to be used to calculate the
worst case discharge planning volume in part
B of this appendix.
2.0 Description of Methods
2.1 Method A
If the well rate would overwhelm the re-
sponse efforts (i.e., rate of well/rate of recov-
ery >1), then the production volume would be
the 30-day forecasted well rate for a well
10,000 feet deep or less, or the 45-day fore-
casted well rate for a well deeper than 10,000
feet.
(1) For wells 10,000 feet deep or less:
Production volume=30 days x rate of well.
4A11 complexes that are jointly regulated
by EPA and the USCG must also calculate
the worst case discharge planning volume for
the transportation-related portions of the fa-
cility and plan for whichever volume is
greater.
(2) For wells deeper than 10,000 feet:
Production volume=45 days x rate of well.
2.2 Method B
2.2.1 If the rate of recovery would be
greater than the well rate (i.e., rate of well/
rate of recovery <1), then the production vol-
ume would equal the sum of two terms:
Production volume=discharge volumei + dis-
charge volume2
2.2.2 The first term represents the volume
of the oil discharged from the well between
the time of the blowout and the time the re-
sponse resources are on scene and recovering
oil (discharge volumei).
Discharge volumei=(days unattended+days
to respond) x (rate of well)
2.2.3 The second term represents the vol-
ume of oil discharged from the well after the
response resources begin operating until the
discharge is stopped, adjusted for the recov-
ery rate of the response resources (discharge
volume2).
(1) For wells 10,000 feet deep or less:
Discharge volume2=[30 days-(days unat-
tended + days to respond)] x (rate of well)
x (rate of well/rate of recovery)
(2) For wells deeper than 10,000 feet:
Discharge volume2=[45 days-(days unat-
tended + days to respond)] x (rate of well)
x (rate of well/rate of recovery)
3.0 Example
3.1 A facility consists of two production
wells producing under pressure, which are
both less than 10,000 feet deep. The well rate
of well A is 5 barrels per day, and the well
rate of well B is 10 barrels per day. The facil-
ity is unattended for a maximum of 7 days.
The facility operator estimates that it will
take 2 days to have response equipment and
personnel on scene and responding to a blow-
out, and that the projected rate of recovery
will be 20 barrels per day.
(1) First, the facility operator determines
that the highest output well is well B. The
facility operator calculates the ratio of the
rate of well to the rate of recovery:
10 barrels per day/20 barrels per day=0.5 Be-
cause the ratio is less than one, the facil-
ity operator will use Method B to cal-
culate the production volume.
(2) The first term of the equation is:
Discharge volumei=(7 days + 2 days) x (10
barrels per day)=90 barrels
(3) The second term of the equation is:
Discharge volume2=[30 days—(7 days + 2
days)] x (10 barrels per day) x (0.5)=105
barrels
(4) Therefore, the production volume is:
Production volume=90 barrels + 105
barrels=195 barrels
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40 CFR Ch. I (7-1-13 Edition)
3.2 If the recovery rate was 5 barrels per
day, the ratio of rate of well to rate of recov-
ery would be 2, so the facility operator would
use Method A. The production volume would
have been:
30 days x 10 barrels per day=300 barrels
[59 FR 34110, July 1, 1994; 59 FR 49006, Sept.
26, 1994, as amended at 65 FR 40800, June 30,
2000; 67 FR 47152, July 17, 2002]
APPENDIX E TO PART 112—DETERMINA-
TION AND EVALUATION OF REQUIRED
RESPONSE RESOURCES FOR FACILITY
RESPONSE PLANS
1.0 Purpose and Definitions
1.1 The purpose of this appendix is to de-
scribe the procedures to identify response re-
sources to meet the requirements of §112.20.
To identify response resources to meet the
facility response plan requirements of 40
CFR 112.20(h), owners or operators shall fol-
low this appendix or, where not appropriate,
shall clearly demonstrate in the response
plan why use of this appendix is not appro-
priate at the facility and make comparable
arrangements for response resources.
1.2 Definitions.
1.2.1 Animal fat means a non-petroleum
oil, fat, or grease of animal, fish, or marine
mammal origin. Animal fats are further
classified based on specific gravity as fol-
lows:
(1) Group A—specific gravity less than 0.8.
(2) Group B—specific gravity equal to or
greater than 0.8 and less than 1.0.
(3) Group C—specific gravity equal to or
greater than 1.0.
1.2.2 Nearshore is an operating area de-
fined as extending seaward 12 miles from the
boundary lines defined in 46 CFR part 7, ex-
cept in the Gulf of Mexico. In the Gulf of
Mexico, it means the area extending 12 miles
from the line of demarcation (COLRBG lines)
defined in 49 CFR 80.740 and 80.850.
1.2.3 Non-persistent oils or Group 1 oils in-
clude:
(1) A petroleum-based oil that, at the time
of shipment, consists of hydrocarbon frac-
tions:
(A) At least 50 percent of which by volume,
distill at a temperature of 340 degrees C (645
degrees F); and
(B) At least 95 percent of which by volume,
distill at a temperature of 370 degrees C (700
degrees F); and
(2) A non-petroleum oil, other than an ani-
mal fat or vegetable oil, with a specific grav-
ity less than 0.8.
1.2.4 Non-petroleum oil means oil of any
kind that is not petroleum-based, including
but not limited to: fats, oils, and greases of
animal, fish, or marine mammal origin; and
vegetable oils, including oils from seeds,
nuts, fruits, and kernels.
1.2.5 Ocean means the nearshore area.
1.2.6 Operating area means Rivers and Ca-
nals, Inland, Nearshore, and Great Lakes ge-
ographic location(s) in which a facility is
handling, storing, or transporting oil.
1.2.7 Operating environment means Rivers
and Canals, Inland, Great Lakes, or Ocean.
These terms are used to define the condi-
tions in which response equipment is de-
signed to function.
1.2.8 Persistent oils include:
(1) A petroleum-based oil that does not
meet the distillation criteria for a non-per-
sistent oil. Persistent oils are further classi-
fied based on specific gravity as follows:
(A) Group 2—specific gravity less than 0.85;
(B) Group 3—specific gravity equal to or
greater than 0.85 and less than 0.95;
(C) Group 4—specific gravity equal to or
greater than 0.95 and less than 1.0; or
(D) Group 5—specific gravity equal to or
greater than 1.0.
(2) A non-petroleum oil, other than an ani-
mal fat or vegetable oil, with a specific grav-
ity of 0.8 or greater. These oils are further
classified based on specific gravity as fol-
lows:
(A) Group 2—specific gravity equal to or
greater than 0.8 and less than 0.85;
(B) Group 3—specific gravity equal to or
greater than 0.85 and less than 0.95;
(C) Group 4—specific gravity equal to or
greater than 0.95 and less than 1.0; or
(D) Group 5—specific gravity equal to or
greater than 1.0.
1.2.9 Vegetable oil means a non-petroleum
oil or fat of vegetable origin, including but
not limited to oils and fats derived from
plant seeds, nuts, fruits, and kernels. Vege-
table oils are further classified based on spe-
cific gravity as follows:
(1) Group A—specific gravity less than 0.8.
(2) Group B—specific gravity equal to or
greater than 0.8 and less than 1.0.
(3) Group C—specific gravity equal to or
greater than 1.0.
1.2.10 Other definitions are included in
§112.2, section 1.1 of appendix C, and section
3.0 of appendix F.
2.0 Equipment Operability and Readiness
2.1 All equipment identified in a response
plan must be designed to operate in the con-
ditions expected in the facility's geographic
area (i.e., operating environment). These
conditions vary widely based on location and
season. Therefore, it is difficult to identify a
single stockpile of response equipment that
will function effectively in each geographic
location (i.e., operating area).
2.2 Facilities handling, storing, or trans-
porting oil in more than one operating envi-
ronment as indicated in Table 1 of this ap-
pendix must identify equipment capable of
successfully functioning in each operating
environment.
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Environmental Protection Agency
Pt. 112, App. E
2.3 When identifying equipment for the
response plan (based on the use of this ap-
pendix), a facility owner or operator must
consider the inherent limitations of the
operability of equipment components and re-
sponse systems. The criteria in Table 1 of
this appendix shall be used to evaluate the
operability in a given environment. These
criteria reflect the general conditions in cer-
tain operating environments.
2.3.1 The Regional Administrator may re-
quire documentation that the boom identi-
fied in a facility response plan meets the cri-
teria in Table 1 of this appendix. Absent ac-
ceptable documentation, the Regional Ad-
ministrator may require that the boom be
tested to demonstrate that it meets the cri-
teria in Table 1 of this appendix. Testing
must be in accordance with ASTM F 715,
ASTM F 989, or other tests approved by EPA
as deemed appropriate (see appendix B to
this part, section 13, for general availability
of documents).
2.4 Table 1 of this appendix lists criteria
for oil recovery devices and boom. All other
equipment necessary to sustain or support
response operations in an operating environ-
ment must be designed to function in the
same conditions. For example, boats that de-
ploy or support skimmers or boom must be
capable of being safely operated in the sig-
nificant wave heights listed for the applica-
ble operating environment.
2.5 A facility owner or operator shall refer
to the applicable Area Contingency Plan
(ACP), where available, to determine if ice,
debris, and weather-related visibility are sig-
nificant factors to evaluate the operability
of equipment. The ACP may also identify the
average temperature ranges expected in the
facility's operating area. All equipment iden-
tified in a response plan must be designed to
operate within those conditions or ranges.
2.6 This appendix provides information on
response resource mobilization and response
times. The distance of the facility from the
storage location of the response resources
must be used to determine whether the re-
sources can arrive on-scene within the stated
time. A facility owner or operator shall in-
clude the time for notification, mobilization,
and travel of resources identified to meet the
medium and Tier 1 worst case discharge re-
quirements identified in sections 4.3 and 9.3
of this appendix (for medium discharges) and
section 5.3 of this appendix (for worst case
discharges). The facility owner or operator
must plan for notification and mobilization
of Tier 2 and 3 response resources as nec-
essary to meet the requirements for arrival
on-scene in accordance with section 5.3 of
this appendix. An on-water speed of 5 knots
and a land speed of 35 miles per hour is as-
sumed, unless the facility owner or operator
can demonstrate otherwise.
2.7 In identifying equipment, the facility
owner or operator shall list the storage loca-
tion, quantity, and manufacturer's make and
model. For oil recovery devices, the effective
daily recovery capacity, as determined using
section 6 of this appendix, must be included.
For boom, the overall boom height (draft and
freeboard) shall be included. A facility owner
or operator is responsible for ensuring that
the identified boom has compatible connec-
tors.
3.0 Determining Response Resources Required
for Small Discharges—Petroleum Oils and
Non-Petroleum Oils Other Than Animal Fats
and Vegetable Oils
3.1 A facility owner or operator shall
identify sufficient response resources avail-
able, by contract or other approved means as
described in §112.2, to respond to a small dis-
charge. A small discharge is defined as any
discharge volume less than or equal to 2,100
gallons, but not to exceed the calculated
worst case discharge. The equipment must be
designed to function in the operating envi-
ronment at the point of expected use.
3.2 Complexes that are regulated by EPA
and the United States Coast Guard (USCG)
must also consider planning quantities for
the transportation-related transfer portion
of the facility.
3.2.1 Petroleum oils. The USCG planning
level that corresponds to EPA's "small dis-
charge" is termed "the average most prob-
able discharge." A USCG rule found at 33
CFR 154.1020 defines "the average most prob-
able discharge" as the lesser of 50 barrels
(2,100 gallons) or 1 percent of the volume of
the worst case discharge. Owners or opera-
tors of complexes that handle, store, or
transport petroleum oils must compare oil
discharge volumes for a small discharge and
an average most probable discharge, and
plan for whichever quantity is greater.
3.2.2 Non-petroleum oils other than animal
fats and vegetable oils. Owners or operators of
complexes that handle, store, or transport
non-petroleum oils other than animal fats
and vegetable oils must plan for oil dis-
charge volumes for a small discharge. There
is no USCG planning level that directly cor-
responds to EPA's "small discharge." How-
ever, the USCG (at 33 CFR 154.545) has re-
quirements to identify equipment to contain
oil resulting from an operational discharge.
3.3 The response resources shall, as appro-
priate, include:
3.3.1 One thousand feet of containment
boom (or, for complexes with marine transfer
components, 1,000 feet of containment boom
or two times the length of the largest vessel
that regularly conducts oil transfers to or
from the facility, whichever is greater), and
a means of deploying it within 1 hour of the
discovery of a discharge;
3.3.2 Oil recovery devices with an effec-
tive daily recovery capacity equal to the
amount of oil discharged in a small dis-
charge or greater which is available at the
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Pt. 112, App. E
40 CFR Ch. I (7-1-13 Edition)
facility within 2 hours of the detection of an
oil discharge; and
3.3.3 Oil storage capacity for recovered
oily material indicated in section 12.2 of this
appendix.
4.0 Determining Response Resources Required
for Medium Discharges—Petroleum Oils and
Non-Petroleum Oils Other Than Animal Fats
and Vegetable Oils
4.1 A facility owner or operator shall
identify sufficient response resources avail-
able, by contract or other approved means as
described in §112.2, to respond to a medium
discharge of oil for that facility. This will re-
quire response resources capable of con-
taining and collecting up to 36,000 gallons of
oil or 10 percent of the worst case discharge,
whichever is less. All equipment identified
must be designed to operate in the applicable
operating environment specified in Table 1 of
this appendix.
4.2 Complexes that are regulated by EPA
and the USCG must also consider planning
quantities for the transportation-related
transfer portion of the facility.
4.2.1 Petroleum oils. The USCG planning
level that corresponds to BPA's "medium
discharge" is termed "the maximum most
probable discharge." The USCG rule found at
33 CFR part 154 defines "the maximum most
probable discharge" as a discharge of 1,200
barrels (50,400 gallons) or 10 percent of the
worst case discharge, whichever is less. Own-
ers or operators of complexes that handle,
store, or transport petroleum oils must com-
pare calculated discharge volumes for a me-
dium discharge and a maximum most prob-
able discharge, and plan for whichever quan-
tity is greater.
4.2.2 Non-petroleum oils other than animal
fats and vegetable oils. Owners or operators of
complexes that handle, store, or transport
non-petroleum oils other than animal fats
and vegetable oils must plan for oil dis-
charge volumes for a medium discharge. For
non-petroleum oils, there is no USCG plan-
ning level that directly corresponds to BPA's
"medium discharge."
4.3 Oil recovery devices identified to meet
the applicable medium discharge volume
planning criteria must be located such that
they are capable of arriving on-scene within
6 hours in higher volume port areas and the
Great Lakes and within 12 hours in all other
areas. Higher volume port areas and Great
Lakes areas are defined in section 1.1 of ap-
pendix C to this part.
4.4 Because rapid control, containment,
and removal of oil are critical to reduce dis-
charge impact, the owner or operator must
determine response resources using an effec-
tive daily recovery capacity for oil recovery
devices equal to 50 percent of the planning
volume applicable for the facility as deter-
mined in section 4.1 of this appendix. The ef-
fective daily recovery capacity for oil recov-
ery devices identified in the plan must be de-
termined using the criteria in section 6 of
this appendix.
4.5 In addition to oil recovery capacity,
the plan shall, as appropriate, identify suffi-
cient quantity of containment boom avail-
able, by contract or other approved means as
described in §112.2, to arrive within the re-
quired response times for oil collection and
containment and for protection of fish and
wildlife and sensitive environments. For fur-
ther description of fish and wildlife and sen-
sitive environments, see Appendices I, II, and
III to DOC/NOAA's "Guidance for Facility
and Vessel Response Plans: Fish and Wildlife
and Sensitive Environments" (see appendix
E to this part, section 13, for availability)
and the applicable ACP. Although 40 CFR
part 112 does not set required quantities of
boom for oil collection and containment, the
response plan shall identify and ensure, by
contract or other approved means as de-
scribed in §112.2, the availability of the
quantity of boom identified in the plan for
this purpose.
4.6 The plan must indicate the avail-
ability of temporary storage capacity to
meet section 12.2 of this appendix. If avail-
able storage capacity is insufficient to meet
this level, then the effective daily recovery
capacity must be derated (downgraded) to
the limits of the available storage capacity.
4.7 The following is an example of a me-
dium discharge volume planning calculation
for equipment identification in a higher vol-
ume port area: The facility's largest above-
ground storage tank volume is 840,000 gal-
lons. Ten percent of this capacity is 84,000
gallons. Because 10 percent of the facility's
largest tank, or 84,000 gallons, is greater
than 36,000 gallons, 36,000 gallons is used as
the planning volume. The effective daily re-
covery capacity is 50 percent of the planning
volume, or 18,000 gallons per day. The ability
of oil recovery devices to meet this capacity
must be calculated using the procedures in
section 6 of this appendix. Temporary stor-
age capacity available on-scene must equal
twice the daily recovery capacity as indi-
cated in section 12.2 of this appendix, or
36,000 gallons per day. This is the informa-
tion the facility owner or operator must use
to identify and ensure the availability of the
required response resources, by contract or
other approved means as described in §112.2.
The facility owner shall also identify how
much boom is available for use.
5.0 Determining Response Resources Required
for the Worst Case Discharge to the Maximum
Extent Practicable
5.1 A facility owner or operator shall
identify and ensure the availability of, by
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Environmental Protection Agency
Pt. 112, App. E
contract or other approved means as de-
scribed in §112.2, sufficient response re-
sources to respond to the worst case dis-
charge of oil to the maximum extent prac-
ticable. Sections 7 and 10 of this appendix de-
scribe the method to determine the nec-
essary response resources. Worksheets are
provided as Attachments B-l and E-2 at the
end of this appendix to simplify the proce-
dures involved in calculating the planning
volume for response resources for the worst
case discharge.
5.2 Complexes that are regulated by EPA
and the USCG must also consider planning
for the worst case discharge at the transpor-
tation-related portion of the facility. The
USCG requires that transportation-related
facility owners or operators use a different
calculation for the worst case discharge in
the revisions to 33 CFR part 154. Owners or
operators of complex facilities that are regu-
lated by EPA and the USCG must compare
both calculations of worst case discharge de-
rived by EPA and the USCG and plan for
whichever volume is greater.
5.3 Oil discharge response resources iden-
tified in the response plan and available, by
contract or other approved means as de-
scribed in §112.2, to meet the applicable
worst case discharge planning volume must
be located such that they are capable of ar-
riving at the scene of a discharge within the
times specified for the applicable response
tier listed as follows
Higher volume port areas
All other river and canal, inland, and nearshore areas
Tier 1
(in hours)
6
12
12
Tier 2
(in hours)
30
36
36
Tiers
(in hours)
54
60
60
The three levels of response tiers apply to
the amount of time in which facility owners
or operators must plan for response re-
sources to arrive at the scene of a discharge
to respond to the worst case discharge plan-
ning volume. For example, at a worst case
discharge in an inland area, the first tier of
response resources (i.e., that amount of on-
water and shoreline cleanup capacity nec-
essary to respond to the fraction of the worst
case discharge as indicated through the se-
ries of steps described in sections 7.2 and 7.3
or sections 10.2 and 10.3 of this appendix)
would arrive at the scene of the discharge
within 12 hours; the second tier of response
resources would arrive within 36 hours; and
the third tier of response resources would ar-
rive within 60 hours.
5.4 The effective daily recovery capacity
for oil recovery devices identified in the re-
sponse plan must be determined using the
criteria in section 6 of this appendix. A facil-
ity owner or operator shall identify the stor-
age locations of all response resources used
for each tier. The owner or operator of a fa-
cility whose required daily recovery capacity
exceeds the applicable contracting caps in
Table 5 of this appendix shall, as appro-
priate, identify sources of additional equip-
ment, their location, and the arrangements
made to obtain this equipment during a re-
sponse. The owner or operator of a facility
whose calculated planning volume exceeds
the applicable contracting caps in Table 5 of
this appendix shall, as appropriate, identify
sources of additional equipment equal to
twice the cap listed in Tier 3 or the amount
necessary to reach the calculated planning
volume, whichever is lower. The resources
identified above the cap shall be capable of
arriving on-scene not later than the Tier 3
response times in section 5.3 of this appen-
dix. No contract is required. While general
listings of available response equipment may
be used to identify additional sources (i.e.,
"public" resources vs. "private" resources),
the response plan shall identify the specific
sources, locations, and quantities of equip-
ment that a facility owner or operator has
considered in his or her planning. When list-
ing USCG-classified oil spill removal organi-
zation(s) that have sufficient removal capac-
ity to recover the volume above the response
capacity cap for the specific facility, as spec-
ified in Table 5 of this appendix, it is not
necessary to list specific quantities of equip-
ment.
5.5 A facility owner or operator shall
identify the availability of temporary stor-
age capacity to meet section 12.2 of this ap-
pendix. If available storage capacity is insuf-
ficient, then the effective daily recovery ca-
pacity must be derated (downgraded) to the
limits of the available storage capacity.
5.6 When selecting response resources nec-
essary to meet the response plan require-
ments, the facility owner or operator shall,
as appropriate, ensure that a portion of
those resources is capable of being used in
close-to-shore response activities in shallow
water. For any EPA-regulated facility that
is required to plan for response in shallow
water, at least 20 percent of the on-water re-
sponse equipment identified for the applica-
ble operating area shall, as appropriate, be
capable of operating in water of 6 feet or less
depth.
5.7 In addition to oil spill recovery de-
vices, a facility owner or operator shall iden-
tify sufficient quantities of boom that are
available, by contract or other approved
means as described in §112.2, to arrive on-
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40 CFR Ch. I (7-1-13 Edition)
scene within the specified response times for
oil containment and collection. The specific
quantity of boom required for collection and
containment will depend on the facility-spe-
cific information and response strategies em-
ployed. A facility owner or operator shall, as
appropriate, also identify sufficient quan-
tities of oil containment boom to protect
fish and wildlife and sensitive environments.
For further description of fish and wildlife
and sensitive environments, see Appendices
I, II, and III to DOC/NOAA's "Guidance for
Facility and Vessel Response Plans: Fish and
Wildlife and Sensitive Environments" (see
appendix B to this part, section 13, for avail-
ability), and the applicable ACP. Refer to
this guidance document for the number of
days and geographic areas (i.e., operating en-
vironments) specified in Table 2 and Table 6
of this appendix.
5.8 A facility owner or operator shall also
identify, by contract or other approved
means as described in §112.2, the availability
of an oil spill removal organization(s) (as de-
scribed in §112.2) capable of responding to a
shoreline cleanup operation involving the
calculated volume of oil and emulsified oil
that might impact the affected shoreline.
The volume of oil that shall, as appropriate,
be planned for is calculated through the ap-
plication of factors contained in Tables 2, 3,
6, and 7 of this appendix. The volume cal-
culated from these tables is intended to as-
sist the facility owner or operator to identify
an oil spill removal organization with suffi-
cient resources and expertise.
6.0 Determining Effective Daily Recovery
Capacity for Oil Recovery Devices
6.1 Oil recovery devices identified by a fa-
cility owner or operator must be identified
by the manufacturer, model, and effective
daily recovery capacity. These capacities
must be used to determine whether there is
sufficient capacity to meet the applicable
planning criteria for a small discharge, a me-
dium discharge, and a worst case discharge
to the maximum extent practicable.
6.2 To determine the effective daily recov-
ery capacity of oil recovery devices, the for-
mula listed in section 6.2.1 of this appendix
shall be used. This formula considers poten-
tial limitations due to available daylight,
weather, sea state, and percentage of
emulsified oil in the recovered material. The
RA may assign a lower efficiency factor to
equipment listed in a response plan if it is
determined that such a reduction is war-
ranted.
6.2.1 The following formula shall be used
to calculate the effective daily recovery ca-
pacity:
R = T x 24 hours x B
where:
R—Effective daily recovery capacity;
T—Throughput rate in barrels per hour
(nameplate capacity); and
B—20 percent efficiency factor (or lower fac-
tor as determined by the Regional Ad-
ministrator).
6.2.2 For those devices in which the pump
limits the throughput of liquid, throughput
rate shall be calculated using the pump ca-
pacity.
6.2.3 For belt or moptype devices, the
throughput rate shall be calculated using the
speed of the belt or mop through the device,
assumed thickness of oil adhering to or col-
lected by the device, and surface area of the
belt or mop. For purposes of this calculation,
the assumed thickness of oil will be % inch.
6.2.4 Facility owners or operators that in-
clude oil recovery devices whose throughput
is not measurable using a pump capacity or
belt/mop speed may provide information to
support an alternative method of calcula-
tion. This information must be submitted
following the procedures in section 6.3.2 of
this appendix.
6.3 As an alternative to section 6.2 of this
appendix, a facility owner or operator may
submit adequate evidence that a different ef-
fective daily recovery capacity should be ap-
plied for a specific oil recovery device. Ade-
quate evidence is actual verified perform-
ance data in discharge conditions or tests
using American Society of Testing and Mate-
rials (ASTM) Standard F 631-99, F 808-83
(1999), or an equivalent test approved by BPA
as deemed appropriate (see Appendix B to
this part, section 13, for general availability
of documents).
6.3.1 The following formula must be used
to calculate the effective daily recovery ca-
pacity under this alternative:
R = DxU
where:
R—Effective daily recovery capacity;
D—Average Oil Recovery Rate in barrels per
hour (Item 26 in F 808-83; Item 13.2.16 in
F 631-99; or actual performance data);
and
U—Hours per day that equipment can oper-
ate under discharge conditions. Ten
hours per day must be used unless a fa-
cility owner or operator can demonstrate
that the recovery operation can be sus-
tained for longer periods.
6.3.2 A facility owner or operator submit-
ting a response plan shall provide data that
supports the effective daily recovery capac-
ities for the oil recovery devices listed. The
following is an example of these calcula-
tions:
(1) A weir skimmer identified in a response
plan has a manufacturer's rated throughput
at the pump of 267 gallons per minute (gpm).
267 gpm=381 barrels per hour (bph)
R=381 bphx24 hr/dayx0.2=l,829 barrels per day
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(2) After testing using ASTM procedures,
the skimmer's oil recovery rate is deter-
mined to be 220 gpm. The facility owner or
operator identifies sufficient resources avail-
able to support operations for 12 hours per
day.
220 gpm=314 bph
R=314 bphx!2 hr/day=3,768 barrels per day
(3) The facility owner or operator will be
able to use the higher capacity if sufficient
temporary oil storage capacity is available.
Determination of alternative efficiency fac-
tors under section 6.2 of this appendix or the
acceptability of an alternative effective
daily recovery capacity under section 6.3 of
this appendix will be made by the Regional
Administrator as deemed appropriate.
7.0 Calculating Planning Volumes for a Worst
Case Discharge—Petroleum Oils and Non-Pe-
troleum Oils Other Than Animal Fats and
Vegetable Oils
7.1 A facility owner or operator shall plan
for a response to the facility's worst case dis-
charge. The planning for on-water oil recov-
ery must take into account a loss of some oil
to the environment due to evaporative and
natural dissipation, potential increases in
volume due to emulsification, and the poten-
tial for deposition of oil on the shoreline.
The procedures for non-petroleum oils other
than animal fats and vegetable oils are dis-
cussed in section 7.7 of this appendix.
7.2 The following procedures must be used
by a facility owner or operator in deter-
mining the required on-water oil recovery
capacity:
7.2.1 The following must be determined:
the worst case discharge volume of oil in the
facility; the appropriate group(s) for the
types of oil handled, stored, or transported
at the facility [persistent (Groups 2, 3, 4, 5)
or non-persistent (Group 1)]; and the facili-
ty's specific operating area. See sections 1.2.3
and 1.2.8 of this appendix for the definitions
of non-persistent and persistent oils, respec-
tively. Facilities that handle, store, or trans-
port oil from different oil groups must cal-
culate each group separately, unless the oil
group constitutes 10 percent or less by vol-
ume of the facility's total oil storage capac-
ity. This information is to be used with
Table 2 of this appendix to determine the
percentages of the total volume to be used
for removal capacity planning. Table 2 of
this appendix divides the volume into three
categories: oil lost to the environment; oil
deposited on the shoreline; and oil available
for on-water recovery.
7.2.2 The on-water oil recovery volume
shall, as appropriate, be adjusted using the
appropriate emulsification factor found in
Table 3 of this appendix. Facilities that han-
dle, store, or transport oil from different pe-
troleum groups must compare the on-water
recovery volume for each oil group (unless
the oil group constitutes 10 percent or less
by volume of the facility's total storage ca-
pacity) and use the calculation that results
in the largest on-water oil recovery volume
to plan for the amount of response resources
for a worst case discharge.
7.2.3 The adjusted volume is multiplied by
the on-water oil recovery resource mobiliza-
tion factor found in Table 4 of this appendix
from the appropriate operating area and re-
sponse tier to determine the total on-water
oil recovery capacity in barrels per day that
must be identified or contracted to arrive
on-scene within the applicable time for each
response tier. Three tiers are specified. For
higher volume port areas, the contracted
tiers of resources must be located such that
they are capable of arriving on-scene within
6 hours for Tier 1, 30 hours for Tier 2, and 54
hours for Tier 3 of the discovery of an oil dis-
charge. For all other rivers and canals, in-
land, nearshore areas, and the Great Lakes,
these tiers are 12, 36, and 60 hours.
7.2.4 The resulting on-water oil recovery
capacity in barrels per day for each tier is
used to identify response resources necessary
to sustain operations in the applicable oper-
ating area. The equipment shall be capable
of sustaining operations for the time period
specified in Table 2 of this appendix. The fa-
cility owner or operator shall identify and
ensure the availability, by contract or other
approved means as described in §112.2, of suf-
ficient oil spill recovery devices to provide
the effective daily oil recovery capacity re-
quired. If the required capacity exceeds the
applicable cap specified in Table 5 of this ap-
pendix, then a facility owner or operator
shall ensure, by contract or other approved
means as described in §112.2, only for the
quantity of resources required to meet the
cap, but shall identify sources of additional
resources as indicated in section 5.4 of this
appendix. The owner or operator of a facility
whose planning volume exceeded the cap in
1993 must make arrangements to identify
and ensure the availability, by contract or
other approved means as described in §112.2,
for additional capacity to be under contract
by 1998 or 2003, as appropriate. For a facility
that handles multiple groups of oil, the re-
quired effective daily recovery capacity for
each oil group is calculated before applying
the cap. The oil group calculation resulting
in the largest on-water recovery volume
must be used to plan for the amount of re-
sponse resources for a worst case discharge,
unless the oil group comprises 10 percent or
less by volume of the facility's total oil stor-
age capacity.
7.3 The procedures discussed in sections
7.3.1-7.3.3 of this appendix must be used to
calculate the planning volume for identi-
fying shoreline cleanup capacity (for Group 1
through Group 4 oils).
7.3.1 The following must be determined:
the worst case discharge volume of oil for
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40 CFR Ch. I (7-1-13 Edition)
the facility; the appropriate group(s) for the
types of oil handled, stored, or transported
at the facility [persistent (Groups 2, 3, or 4)
or non-persistent (Group 1)]; and the geo-
graphic area(s) in which the facility operates
(i.e., operating areas). For a facility han-
dling, storing, or transporting oil from dif-
ferent groups, each group must be calculated
separately. Using this information, Table 2
of this appendix must be used to determine
the percentages of the total volume to be
used for shoreline cleanup resource planning.
7.3.2 The shoreline cleanup planning vol-
ume must be adjusted to reflect an emulsi-
fication factor using the same procedure as
described in section 7.2.2 of this appendix.
7.3.3 The resulting volume shall be used
to identify an oil spill removal organization
with the appropriate shoreline cleanup capa-
bility.
7.4 A response plan must identify re-
sponse resources with fire fighting capa-
bility. The owner or operator of a facility
that handles, stores, or transports Group 1
through Group 4 oils that does not have ade-
quate fire fighting resources located at the
facility or that cannot rely on sufficient
local fire fighting resources must identify
adequate fire fighting resources. The facility
owner or operator shall ensure, by contract
or other approved means as described in
§112.2, the availability of these resources.
The response plan must also identify an indi-
vidual located at the facility to work with
the fire department for Group 1 through
Group 4 oil fires. This individual shall also
verify that sufficient well-trained fire fight-
ing resources are available within a reason-
able response time to a worst case scenario.
The individual may be the qualified indi-
vidual identified in the response plan or an-
other appropriate individual located at the
facility.
7.5 The following is an example of the pro-
cedure described above in sections 7.2 and 7.3
of this appendix: A facility with a 270,000 bar-
rel (11.3 million gallons) capacity for #6 oil
(specific gravity 0.96) is located in a higher
volume port area. The facility is on a penin-
sula and has docks on both the ocean and
bay sides. The facility has four aboveground
oil storage tanks with a combined total ca-
pacity of 80,000 barrels (3.36 million gallons)
and no secondary containment. The remain-
ing facility tanks are inside secondary con-
tainment structures. The largest above-
ground oil storage tank (90,000 barrels or 3.78
million gallons) has its own secondary con-
tainment. Two 50,000 barrel (2.1 million gal-
lon) tanks (that are not connected by a
manifold) are within a common secondary
containment tank area, which is capable of
holding 100,000 barrels (4.2 million gallons)
plus sufficient freeboard.
7.5.1 The worst case discharge for the fa-
cility is calculated by adding the capacity of
all aboveground oil storage tanks without
secondary containment (80,000 barrels) plus
the capacity of the largest aboveground oil
storage tank inside secondary containment.
The resulting worst case discharge volume is
170,000 barrels or 7.14 million gallons.
7.5.2 Because the requirements for Tiers 1,
2, and 3 for inland and nearshore exceed the
caps identified in Table 5 of this appendix,
the facility owner will contract for a re-
sponse to 10,000 barrels per day (bpd) for Tier
1, 20,000 bpd for Tier 2, and 40,000 bpd for Tier
3. Resources for the remaining 7,850 bpd for
Tier 1, 9,750 bpd for Tier 2, and 7,600 bpd for
Tier 3 shall be identified but need not be con-
tracted for in advance. The facility owner or
operator shall, as appropriate, also identify
or contract for quantities of boom identified
in their response plan for the protection of
fish and wildlife and sensitive environments
within the area potentially impacted by a
worst case discharge from the facility. For
further description of fish and wildlife and
sensitive environments, see Appendices I, II,
and III to DOC/NOAA's "Guidance for Facil-
ity and Vessel Response Plans: Fish and
Wildlife and Sensitive Environments," (see
appendix B to this part, section 13, for avail-
ability) and the applicable ACP. Attachment
C-III to Appendix C provides a method for
calculating a planning distance to fish and
wildlife and sensitive environments and pub-
lic drinking water intakes that may be im-
pacted in the event of a worst case discharge.
7.6 The procedures discussed in sections
7.6.1-7.6.3 of this appendix must be used to
determine appropriate response resources for
facilities with Group 5 oils.
7.6.1 The owner or operator of a facility
that handles, stores, or transports Group 5
oils shall, as appropriate, identify the re-
sponse resources available by contract or
other approved means, as described in §112.2.
The equipment identified in a response plan
shall, as appropriate, include:
(1) Sonar, sampling equipment, or other
methods for locating the oil on the bottom
or suspended in the water column;
(2) Containment boom, sorbent boom, silt
curtains, or other methods for containing
the oil that may remain floating on the sur-
face or to reduce spreading on the bottom;
(3) Dredges, pumps, or other equipment
necessary to recover oil from the bottom and
shoreline;
(4) Equipment necessary to assess the im-
pact of such discharges; and
(5) Other appropriate equipment necessary
to respond to a discharge involving the type
of oil handled, stored,, or transported.
7.6.2 Response resources identified in a re-
sponse plan for a facility that handles,
stores, or transports Group 5 oils under sec-
tion 7.6.1 of this appendix shall be capable of
being deployed (on site) within 24 hours of
discovery of a discharge to the area where
the facility is operating.
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Pt. 112, App. E
7.6.3 A response plan must identify re-
sponse resources with fire fighting capa-
bility. The owner or operator of a facility
that handles, stores, or transports Group 5
oils that does not have adequate fire fighting
resources located at the facility or that can-
not rely on sufficient local fire fighting re-
sources must identify adequate fire fighting
resources. The facility owner or operator
shall ensure, by contract or other approved
means as described in §112.2, the availability
of these resources. The response plan shall
also identify an individual located at the fa-
cility to work with the fire department for
Group 5 oil fires. This individual shall also
verify that sufficient well-trained fire fight-
ing resources are available within a reason-
able response time to respond to a worst case
discharge. The individual may be the quali-
fied individual identified in the response
plan or another appropriate individual lo-
cated at the facility.
7.7 Non-petroleum oils other than animal
fats and vegetable oils. The procedures de-
scribed in sections 7.7.1 through 7.7.5 of this
appendix must be used to determine appro-
priate response plan development and eval-
uation criteria for facilities that handle,
store, or transport non-petroleum oils other
than animal fats and vegetable oils. Refer to
section 11 of this appendix for information
on the limitations on the use of chemical
agents for inland and nearshore areas.
7.7.1 An owner or operator of a facility
that handles, stores, or transports non-petro-
leum oils other than animal fats and vege-
table oils must provide information in his or
her plan that identifies:
(1) Procedures and strategies for respond-
ing to a worst case discharge to the max-
imum extent practicable; and
(2) Sources of the equipment and supplies
necessary to locate, recover, and mitigate
such a discharge.
7.7.2 An owner or operator of a facility
that handles, stores, or transports non-petro-
leum oils other than animal fats and vege-
table oils must ensure that any equipment
identified in a response plan is capable of op-
erating in the conditions expected in the ge-
ographic area(s) (i.e., operating environ-
ments) in which the facility operates using
the criteria in Table 1 of this appendix. When
evaluating the operability of equipment, the
facility owner or operator must consider lim-
itations that are identified in the appro-
priate ACPs, including:
(1) Ice conditions;
(2) Debris;
(3) Temperature ranges; and
(4) Weather-related visibility.
7.7.3 The owner or operator of a facility
that handles, stores, or transports non-petro-
leum oils other than animal fats and vege-
table oils must identify the response re-
sources that are available by contract or
other approved means, as described in §112.2.
The equipment described in the response
plan shall, as appropriate, include:
(1) Containment boom, sorbent boom, or
other methods for containing oil floating on
the surface or to protect shorelines from im-
pact;
(2) Oil recovery devices appropriate for the
type of non-petroleum oil carried; and
(3) Other appropriate equipment necessary
to respond to a discharge involving the type
of oil carried.
7.7.4 Response resources identified in a re-
sponse plan according to section 7.7.3 of this
appendix must be capable of commencing an
effective on-scene response within the appli-
cable tier response times in section 5.3 of
this appendix.
7.7.5 A response plan must identify re-
sponse resources with fire fighting capa-
bility. The owner or operator of a facility
that handles, stores, or transports non-petro-
leum oils other than animal fats and vege-
table oils that does not have adequate fire
fighting resources located at the facility or
that cannot rely on sufficient local fire
fighting resources must identify adequate
fire fighting resources. The owner or oper-
ator shall ensure, by contract or other ap-
proved means as described in §112.2, the
availability of these resources. The response
plan must also identify an individual located
at the facility to work with the fire depart-
ment for fires of these oils. This individual
shall also verify that sufficient well-trained
fire fighting resources are available within a
reasonable response time to a worst case sce-
nario. The individual may be the qualified
individual identified in the response plan or
another appropriate individual located at
the facility.
8.0 Determining Response Resources Required
for Small Discharges—Animal Fats and Vege-
table Oils
8.1 A facility owner or operator shall
identify sufficient response resources avail-
able, by contract or other approved means as
described in §112.2, to respond to a small dis-
charge of animal fats or vegetable oils. A
small discharge is defined as any discharge
volume less than or equal to 2,100 gallons,
but not to exceed the calculated worst case
discharge. The equipment must be designed
to function in the operating environment at
the point of expected use.
8.2 Complexes that are regulated by EPA
and the USCG must also consider planning
quantities for the marine transportation-re-
lated portion of the facility.
8.2.1 The USCG planning level that cor-
responds to BPA's "small discharge" is
termed "the average most probable dis-
charge." A USCG rule found at 33 CFR
154.1020 defines "the average most probable
discharge" as the lesser of 50 barrels (2,100
gallons) or 1 percent of the volume of the
worst case discharge. Owners or operators of
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40 CFR Ch. I (7-1-13 Edition)
complexes that handle, store, or transport
animal fats and vegetable oils must compare
oil discharge volumes for a small discharge
and an average most probable discharge, and
plan for whichever quantity is greater.
8.3 The response resources shall, as appro-
priate, include:
8.3.1 One thousand feet of containment
boom (or, for complexes with marine transfer
components, 1,000 feet of containment boom
or two times the length of the largest vessel
that regularly conducts oil transfers to or
from the facility, whichever is greater), and
a means of deploying it within 1 hour of the
discovery of a discharge;
8.3.2 Oil recovery devices with an effec-
tive daily recovery capacity equal to the
amount of oil discharged in a small dis-
charge or greater which is available at the
facility within 2 hours of the detection of a
discharge; and
8.3.3 Oil storage capacity for recovered
oily material indicated in section 12.2 of this
appendix.
9.0 Determining Response Resources Required
for Medium Discharges—Animal Fats and
Vegetable Oils
9.1 A facility owner or operator shall
identify sufficient response resources avail-
able, by contract or other approved means as
described in §112.2, to respond to a medium
discharge of animal fats or vegetable oils for
that facility. This will require response re-
sources capable of containing and collecting
up to 36,000 gallons of oil or 10 percent of the
worst case discharge, whichever is less. All
equipment identified must be designed to op-
erate in the applicable operating environ-
ment specified in Table 1 of this appendix.
9.2 Complexes that are regulated by EPA
and the USCG must also consider planning
quantities for the transportation-related
transfer portion of the facility. Owners or
operators of complexes that handle, store, or
transport animal fats or vegetable oils must
plan for oil discharge volumes for a medium
discharge. For non-petroleum oils, there is
no USCG planning level that directly cor-
responds to BPA's "medium discharge." Al-
though the USCG does not have planning re-
quirements for medium discharges, they do
have requirements (at 33 CFR 154.545) to
identify equipment to contain oil resulting
from an operational discharge.
9.3 Oil recovery devices identified to meet
the applicable medium discharge volume
planning criteria must be located such that
they are capable of arriving on-scene within
6 hours in higher volume port areas and the
Great Lakes and within 12 hours in all other
areas. Higher volume port areas and Great
Lakes areas are defined in section 1.1 of ap-
pendix C to this part.
9.4 Because rapid control, containment,
and removal of oil are critical to reduce dis-
charge impact, the owner or operator must
determine response resources using an effec-
tive daily recovery capacity for oil recovery
devices equal to 50 percent of the planning
volume applicable for the facility as deter-
mined in section 9.1 of this appendix. The ef-
fective daily recovery capacity for oil recov-
ery devices identified in the plan must be de-
termined using the criteria in section 6 of
this appendix.
9.5 In addition to oil recovery capacity,
the plan shall, as appropriate, identify suffi-
cient quantity of containment boom avail-
able, by contract or other approved means as
described in §112.2, to arrive within the re-
quired response times for oil collection and
containment and for protection of fish and
wildlife and sensitive environments. For fur-
ther description of fish and wildlife and sen-
sitive environments, see Appendices I, II, and
III to DOC/NOAA's "Guidance for Facility
and Vessel Response Plans: Fish and Wildlife
and Sensitive Environments" (59 FR 14713-22,
March 29, 1994) and the applicable ACP. Al-
though 40 CFR part 112 does not set required
quantities of boom for oil collection and con-
tainment, the response plan shall identify
and ensure, by contract or other approved
means as described in §112.2, the availability
of the quantity of boom identified in the
plan for this purpose.
9.6 The plan must indicate the avail-
ability of temporary storage capacity to
meet section 12.2 of this appendix. If avail-
able storage capacity is insufficient to meet
this level, then the effective daily recovery
capacity must be derated (downgraded) to
the limits of the available storage capacity.
9.7 The following is an example of a me-
dium discharge volume planning calculation
for equipment identification in a higher vol-
ume port area:
The facility's largest aboveground storage
tank volume is 840,000 gallons. Ten percent
of this capacity is 84,000 gallons. Because 10
percent of the facility's largest tank, or
84,000 gallons, is greater than 36,000 gallons,
36,000 gallons is used as the planning volume.
The effective daily recovery capacity is 50
percent of the planning volume, or 18,000 gal-
lons per day. The ability of oil recovery de-
vices to meet this capacity must be cal-
culated using the procedures in section 6 of
this appendix. Temporary storage capacity
available on-scene must equal twice the
daily recovery capacity as indicated in sec-
tion 12.2 of this appendix, or 36,000 gallons
per day. This is the information the facility
owner or operator must use to identify and
ensure the availability of the required re-
sponse resources, by contract or other ap-
proved means as described in §112.2. The fa-
cility owner shall also identify how much
boom is available for use.
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10.0 Calculating Planning Volumes for a Worst
Case Discharge—Animal Fats and Vegetable
Oils.
10.1 A facility owner or operator shall
plan for a response to the facility's worst
case discharge. The planning for on-water oil
recovery must take into account a loss of
some oil to the environment due to physical,
chemical, and biological processes, potential
increases in volume due to emulsification,
and the potential for deposition of oil on the
shoreline or on sediments. The response
planning procedures for animal fats and veg-
etable oils are discussed in section 10.7 of
this appendix. You may use alternate re-
sponse planning procedures for animal fats
and vegetable oils if those procedures result
in environmental protection equivalent to
that provided by the procedures in section
10.7 of this appendix.
10.2 The following procedures must be
used by a facility owner or operator in deter-
mining the required on-water oil recovery
capacity:
10.2.1 The following must be determined:
the worst case discharge volume of oil in the
facility; the appropriate group(s) for the
types of oil handled, stored, or transported
at the facility (Groups A, B, C); and the fa-
cility's specific operating area. See sections
1.2.1 and 1.2.9 of this appendix for the defini-
tions of animal fats and vegetable oils and
groups thereof. Facilities that handle, store,
or transport oil from different oil groups
must calculate each group separately, unless
the oil group constitutes 10 percent or less
by volume of the facility's total oil storage
capacity. This information is to be used with
Table 6 of this appendix to determine the
percentages of the total volume to be used
for removal capacity planning. Table 6 of
this appendix divides the volume into three
categories: oil lost to the environment; oil
deposited on the shoreline; and oil available
for on-water recovery.
10.2.2 The on-water oil recovery volume
shall, as appropriate, be adjusted using the
appropriate emulsification factor found in
Table 7 of this appendix. Facilities that han-
dle, store, or transport oil from different
groups must compare the on-water recovery
volume for each oil group (unless the oil
group constitutes 10 percent or less by vol-
ume of the facility's total storage capacity)
and use the calculation that results in the
largest on-water oil recovery volume to plan
for the amount of response resources for a
worst case discharge.
10.2.3 The adjusted volume is multiplied
by the on-water oil recovery resource mobili-
zation factor found in Table 4 of this appen-
dix from the appropriate operating area and
response tier to determine the total on-water
oil recovery capacity in barrels per day that
must be identified or contracted to arrive
on-scene within the applicable time for each
response tier. Three tiers are specified. For
higher volume port areas, the contracted
tiers of resources must be located such that
they are capable of arriving on-scene within
6 hours for Tier 1, 30 hours for Tier 2, and 54
hours for Tier 3 of the discovery of a dis-
charge. For all other rivers and canals, in-
land, nearshore areas, and the Great Lakes,
these tiers are 12, 36, and 60 hours.
10.2.4 The resulting on-water oil recovery
capacity in barrels per day for each tier is
used to identify response resources necessary
to sustain operations in the applicable oper-
ating area. The equipment shall be capable
of sustaining operations for the time period
specified in Table 6 of this appendix. The fa-
cility owner or operator shall identify and
ensure, by contract or other approved means
as described in §112.2, the availability of suf-
ficient oil spill recovery devices to provide
the effective daily oil recovery capacity re-
quired. If the required capacity exceeds the
applicable cap specified in Table 5 of this ap-
pendix, then a facility owner or operator
shall ensure, by contract or other approved
means as described in §112.2, only for the
quantity of resources required to meet the
cap, but shall identify sources of additional
resources as indicated in section 5.4 of this
appendix. The owner or operator of a facility
whose planning volume exceeded the cap in
1998 must make arrangements to identify
and ensure, by contract or other approved
means as described in §112.2, the availability
of additional capacity to be under contract
by 2003, as appropriate. For a facility that
handles multiple groups of oil, the required
effective daily recovery capacity for each oil
group is calculated before applying the cap.
The oil group calculation resulting in the
largest on-water recovery volume must be
used to plan for the amount of response re-
sources for a worst case discharge, unless the
oil group comprises 10 percent or less by vol-
ume of the facility's oil storage capacity.
10.3 The procedures discussed in sections
10.3.1 through 10.3.3 of this appendix must be
used to calculate the planning volume for
identifying shoreline cleanup capacity (for
Groups A and B oils).
10.3.1 The following must be determined:
the worst case discharge volume of oil for
the facility; the appropriate group(s) for the
types of oil handled, stored, or transported
at the facility (Groups A or B); and the geo-
graphic area(s) in which the facility operates
(i.e., operating areas). For a facility han-
dling, storing, or transporting oil from dif-
ferent groups, each group must be calculated
separately. Using this information, Table 6
of this appendix must be used to determine
the percentages of the total volume to be
used for shoreline cleanup resource planning.
10.3.2 The shoreline cleanup planning vol-
ume must be adjusted to reflect an emulsi-
fication factor using the same procedure as
described in section 10.2.2 of this appendix.
77
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Pt. 112, App. E
40 CFR Ch. I (7-1-13 Edition)
10.3.3 The resulting volume shall be used
to identify an oil spill removal organization
with the appropriate shoreline cleanup capa-
bility.
10.4 A response plan must identify re-
sponse resources with fire fighting capability
appropriate for the risk of fire and explosion
at the facility from the discharge or threat
of discharge of oil. The owner or operator of
a facility that handles, stores, or transports
Group A or B oils that does not have ade-
quate fire fighting resources located at the
facility or that cannot rely on sufficient
local fire fighting resources must identify
adequate fire fighting resources. The facility
owner or operator shall ensure, by contract
or other approved means as described in
§112.2, the availability of these resources.
The response plan must also identify an indi-
vidual to work with the fire department for
Group A or B oil fires. This individual shall
also verify that sufficient well-trained fire
fighting resources are available within a rea-
sonable response time to a worst case sce-
nario. The individual may be the qualified
individual identified in the response plan or
another appropriate individual located at
the facility.
10.5 The following is an example of the
procedure described in sections 10.2 and 10.3
of this appendix. A facility with a 37.04 mil-
lion gallon (881,904 barrel) capacity of several
types of vegetable oils is located in the In-
land Operating Area. The vegetable oil with
the highest specific gravity stored at the fa-
cility is soybean oil (specific gravity 0.922,
Group B vegetable oil). The facility has ten
aboveground oil storage tanks with a com-
bined total capacity of 18 million gallons
(428,571 barrels) and without secondary con-
tainment. The remaining facility tanks are
inside secondary containment structures.
The largest aboveground oil storage tank (3
million gallons or 71,428 barrels) has its own
secondary containment. Two 2.1 million gal-
lon (50,000 barrel) tanks (that are not con-
nected by a manifold) are within a common
secondary containment tank area, which is
capable of holding 4.2 million gallons (100,000
barrels) plus sufficient freeboard.
10.5.1 The worst case discharge for the fa-
cility is calculated by adding the capacity of
all aboveground vegetable oil storage tanks
without secondary containment (18.0 million
gallons) plus the capacity of the largest
aboveground storage tank inside secondary
containment (3.0 million gallons). The re-
sulting worst case discharge is 21 million
gallons or 500,000 barrels.
10.5.2 With a specific worst case discharge
identified, the planning volume for on-water
recovery can be identified as follows:
Worst case discharge: 21 million gallons
(500,000 barrels) of Group B vegetable oil
Operating Area: Inland
Planned percent recovered floating vegetable
oil (from Table 6, column Nearshore/Inland/
Great Lakes): Inland, Group B is 20%
Emulsion factor (from Table 7): 2.0
Planning volumes for on-water recovery:
21,000,000 gallons x 0.2 x 2.0 = 8,400,000 gal-
lons or 200,000 barrels.
Determine required resources for on-water
recovery for each of the three tiers using
mobilization factors (from Table 4, column
Inland/Nearshore/Great Lakes)
Inland Operating Area
Estimated Daily Recovery Capacity (bbls)
Tier 1
15
30,000
Tier 2
25
50,000
Tiers
40
80,000
10.5.3 Because the requirements for On-
Water Recovery Resources for Tiers 1, 2, and
3 for Inland Operating Area exceed the caps
identified in Table 5 of this appendix, the fa-
cility owner will contract for a response of
12,500 barrels per day (bpd) for Tier 1, 25,000
bpd for Tier 2, and 50,000 bpd for Tier 3. Re-
sources for the remaining 17,500 bpd for Tier
1, 25,000 bpd for Tier 2, and 30,000 bpd for Tier
3 shall be identified but need not be con-
tracted for in advance.
10.5.4 With the specific worst case dis-
charge identified, the planning volume of on-
shore recovery can be identified as follows:
Worst case discharge: 21 million gallons
(500,000 barrels) of Group B vegetable oil
Operating Area: Inland
Planned percent recovered floating vegetable
oil from onshore (from Table 6, column
Nearshore/Inland/Great Lakes): Inland,
Group B is 65%
Emulsion factor (from Table 7): 2.0
Planning volumes for shoreline recovery:
21,000,000 gallons x 0.65 x 2.0 = 27,300,000 gal-
lons or 650,000 barrels
10.5.5 The facility owner or operator shall,
as appropriate, also identify or contract for
quantities of boom identified in the response
plan for the protection of fish and wildlife
and sensitive environments within the area
potentially impacted by a worst case dis-
charge from the facility. For further descrip-
tion of fish and wildlife and sensitive envi-
ronments, see Appendices I, II, and III to
DOC/NOAA's "Guidance for Facility and Ves-
sel Response Plans: Fish and Wildlife and
Sensitive Environments," (see Appendix E to
this part, section 13, for availability) and the
applicable ACP. Attachment C-III to Appen-
dix C provides a method for calculating a
planning distance to fish and wildlife and
sensitive environments and public drinking
78
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Environmental Protection Agency
Pt. 112, App. E
water intakes that may be adversely affected
in the event of a worst case discharge.
10.6 The procedures discussed in sections
10.6.1 through 10.6.3 of this appendix must be
used to determine appropriate response re-
sources for facilities with Group C oils.
10.6.1 The owner or operator of a facility
that handles, stores, or transports Group C
oils shall, as appropriate, identify the re-
sponse resources available by contract or
other approved means, as described in §112.2.
The equipment identified in a response plan
shall, as appropriate, include:
(1) Sonar, sampling equipment, or other
methods for locating the oil on the bottom
or suspended in the water column;
(2) Containment boom, sorbent boom, silt
curtains, or other methods for containing
the oil that may remain floating on the sur-
face or to reduce spreading on the bottom;
(3) Dredges, pumps, or other equipment
necessary to recover oil from the bottom and
shoreline;
(4) Equipment necessary to assess the im-
pact of such discharges; and
(5) Other appropriate equipment necessary
to respond to a discharge involving the type
of oil handled, stored, or transported.
10.6.2 Response resources identified in a
response plan for a facility that handles,
stores, or transports Group C oils under sec-
tion 10.6.1 of this appendix shall be capable of
being deployed on scene within 24 hours of
discovery of a discharge.
10.6.3 A response plan must identify re-
sponse resources with fire fighting capa-
bility. The owner or operator of a facility
that handles, stores, or transports Group C
oils that does not have adequate fire fighting
resources located at the facility or that can-
not rely on sufficient local fire fighting re-
sources must identify adequate fire fighting
resources. The owner or operator shall en-
sure, by contract or other approved means as
described in §112.2, the availability of these
resources. The response plan shall also iden-
tify an individual located at the facility to
work with the fire department for Group C
oil fires. This individual shall also verify
that sufficient well-trained fire fighting re-
sources are available within a reasonable re-
sponse time to respond to a worst case dis-
charge. The individual may be the qualified
individual identified in the response plan or
another appropriate individual located at
the facility.
10.7 The procedures described in sections
10.7.1 through 10.7.5 of this appendix must be
used to determine appropriate response plan
development and evaluation criteria for fa-
cilities that handle, store, or transport ani-
mal fats and vegetable oils. Refer to section
11 of this appendix for information on the
limitations on the use of chemical agents for
inland and nearshore areas.
10.7.1 An owner or operator of a facility
that handles, stores, or transports animal
fats and vegetable oils must provide infor-
mation in the response plan that identifies:
(1) Procedures and strategies for respond-
ing to a worst case discharge of animal fats
and vegetable oils to the maximum extent
practicable; and
(2) Sources of the equipment and supplies
necessary to locate, recover, and mitigate
such a discharge.
10.7.2 An owner or operator of a facility
that handles, stores, or transports animal
fats and vegetable oils must ensure that any
equipment identified in a response plan is ca-
pable of operating in the geographic area(s)
(i.e., operating environments) in which the
facility operates using the criteria in Table 1
of this appendix. When evaluating the oper-
ability of equipment, the facility owner or
operator must consider limitations that are
identified in the appropriate ACPs, includ-
ing:
(1) Ice conditions;
(2) Debris;
(3) Temperature ranges; and
(4) Weather-related visibility.
10.7.3. The owner or operator of a facility
that handles, stores, or transports animal
fats and vegetable oils must identify the re-
sponse resources that are available by con-
tract or other approved means, as described
in §112.2. The equipment described in the re-
sponse plan shall, as appropriate, include:
(1) Containment boom, sorbent boom, or
other methods for containing oil floating on
the surface or to protect shorelines from im-
pact;
(2) Oil recovery devices appropriate for the
type of animal fat or vegetable oil carried;
and
(3) Other appropriate equipment necessary
to respond to a discharge involving the type
of oil carried.
10.7.4 Response resources identified in a
response plan according to section 10.7.3 of
this appendix must be capable of com-
mencing an effective on-scene response with-
in the applicable tier response times in sec-
tion 5.3 of this appendix.
10.7.5 A response plan must identify re-
sponse resources with fire fighting capa-
bility. The owner or operator of a facility
that handles, stores, or transports animal
fats and vegetable oils that does not have
adequate fire fighting resources located at
the facility or that cannot rely on sufficient
local fire fighting resources must identify
adequate fire fighting resources. The owner
or operator shall ensure, by contract or
other approved means as described in §112.2,
the availability of these resources. The re-
sponse plan shall also identify an individual
located at the facility to work with the fire
department for animal fat and vegetable oil
fires. This individual shall also verify that
sufficient well-trained fire fighting resources
are available within a reasonable response
time to respond to a worst case discharge.
79
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Pt. 112, App. E
40 CFR Ch. I (7-1-13 Edition)
The individual may be the qualified indi-
vidual identified in the response plan or an-
other appropriate individual located at the
facility.
11.0 Determining the Availability of
Alternative Response Methods
11.1 For chemical agents to be identified
in a response plan, they must be on the NCP
Product Schedule that is maintained by
EPA. (Some States have a list of approved
dispersants for use within State waters. Not
all of these State-approved dispersants are
listed on the NCP Product Schedule.)
11.2 Identification of chemical agents in
the plan does not imply that their use will be
authorized. Actual authorization will be gov-
erned by the provisions of the NCP and the
applicable ACP.
12.0
Additional Equipment Necessary to
Sustain Response Operations
12.1 A facility owner or operator shall
identify sufficient response resources avail-
able, by contract or other approved means as
described in §112.2, to respond to a medium
discharge of animal fats or vegetables oils
for that facility. This will require response
resources capable of containing and col-
lecting up to 36,000 gallons of oil or 10 per-
cent of the worst case discharge, whichever
is less. All equipment identified must be de-
signed to operate in the applicable operating
environment specified in Table 1 of this ap-
pendix.
12.2 A facility owner or operator shall
evaluate the availability of adequate tem-
porary storage capacity to sustain the effec-
tive daily recovery capacities from equip-
ment identified in the plan. Because of the
inefficiencies of oil spill recovery devices, re-
sponse plans must identify daily storage ca-
pacity equivalent to twice the effective daily
recovery capacity required on-scene. This
temporary storage capacity may be reduced
if a facility owner or operator can dem-
onstrate by waste stream analysis that the
efficiencies of the oil recovery devices, abil-
ity to decant waste, or the availability of al-
ternative temporary storage or disposal loca-
tions will reduce the overall volume of oily
material storage.
12.3 A facility owner or operator shall en-
sure that response planning includes the ca-
pability to arrange for disposal of recovered
oil products. Specific disposal procedures
will be addressed in the applicable ACP.
13.0 References and Availability
13.1 All materials listed in this section
are part of BPA's rulemaking docket and are
located in the Superfund Docket, 1235 Jeffer-
son Davis Highway, Crystal Gateway 1, Ar-
lington, Virginia 22202, Suite 105 (Docket
Numbers SPCC-2P, SPCC-3P, and SPCC-9P).
The docket is available for inspection be-
tween 9 a.m. and 4 p.m., Monday through
Friday, excluding Federal holidays.
Appointments to review the docket can be
made by calling 703-603-9232. Docket hours
are subject to change. As provided in 40 CFR
part 2, a reasonable fee may be charged for
copying services.
13.2 The docket will mail copies of mate-
rials to requestors who are outside the Wash-
ington, DC metropolitan area. Materials may
be available from other sources, as noted in
this section. As provided in 40 CFR part 2, a
reasonable fee may be charged for copying
services. The RCRA/Superfund Hotline at
800^24-9346 may also provide additional in-
formation on where to obtain documents. To
contact the RCRA/Superfund Hotline in the
Washington, DC metropolitan area, dial 703-
412-9810. The Telecommunications Device for
the Deaf (TDD) Hotline number is 800-553-
7672, or, in the Washington, DC metropolitan
area, 703-412-3323.
13.3 Documents
(1) National Preparedness for Response Ex-
ercise Program (PREP). The PREP draft
guidelines are available from United States
Coast Guard Headquarters (G-MEP-4), 2100
Second Street, SW., Washington, DC 20593.
(See 58 FR 53990-91, October 19, 1993, Notice
of Availability of PREP Guidelines).
(2) "Guidance for Facility and Vessel Re-
sponse Plans: Fish and Wildlife and Sensitive
Environments (published in the FEDERAL
REGISTER by DOC/NOAA at 59 FR 14713-22,
March 29, 1994.). The guidance is available in
the Superfund Docket (see sections 13.1 and
13.2 of this appendix).
(3) ASTM Standards. ASTM F 715, ASTM F
989, ASTM F 631-99, ASTM F 808-83 (1999).
The ASTM standards are available from the
American Society for Testing and Materials,
100 Barr Harbor Drive, West Conshohocken,
PA 19428-2959.
(4) Response Plans for Marine Transpor-
tation-Related Facilities, Interim Final
Rule. Published by USCG, DOT at 58 FR 7330-
76, February 5, 1993.
TABLE 1 TO APPENDIX E—RESPONSE RESOURCE OPERATING CRITERIA
Inland
Oil Recovery Devices
Operating environment
Significant wave 0 + +
height 1 Sea state
< 1 foot 1
<3feet 2
80
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Environmental Protection Agency Pt. 112, App. E
TABLE 1 TO APPENDIX E—RESPONSE RESOURCE OPERATING CRITERIA—Continued
Great Lakes
Ocean
Oil Recovery Devices
Operating environment
Significant wave Sea s(ate
<4feet 2-3
<6feet 3-4
Boom
Boom property
Significant Wave Height1
Sea State
Reserve Buoyancy to Weight Ratio
Skirt Fabric Tear Strength— pounds
Rivers and
canals
< 1
1
6 18
2:1
4500
200
100
Us
Inland
<3
2
18-42
2:1
1 5 000-
20,000.
300
100
e
Great Lakes
<4
2-3
18-42
2:1
15000-
20,000.
300
100
Ocean
<6
3-4
>42
3:1 to 4:1
>20 000
500
125
1 Oil recovery devices and boom shall be at least capable of operating in wave heights up to and including the values listed i
Table 1 for each operating environment.
TABLE 2 TO APPENDIX E—REMOVAL CAPACITY PLANNING TABLE FOR PETROLEUM OILS
Spill location
Sustainability of on-water oil recovery
Oil group1
1 — Non-persistent oils
3 — Medium crudes and fuels
4— Heavy crudes and fuels
Rivers and canals
3 days
Percent nat-
ural dissipa-
tion
80
40
20
5
Percent re-
covered
floating oil
10
15
15
20
Percent oil
onshore
10
45
65
75
Nearshore/lnland/Great Lakes
4 days
Percent nat-
ural dissipa-
tion
80
50
30
10
Percent re-
covered
floating oil
20
50
50
50
Percent oil
onshore
10
30
50
70
1 The response resource considerations for non-petroleum oils other than animal fats and vegetable oils are outlined in section
7.7 of this appendix.
NOTE: Group 5 oils are defined in section 1.2.8 of this appendix; the response resource considerations are outlined in section
7.6 of this appendix.
TABLE 3 TO APPENDIX E—EMULSIFICATION FACTORS FOR PETROLEUM OIL GROUPS 1
Non-Persistent Oil:
i 1
Group 1
Persistent Oil:
Group 2
Group 3 .
Group 4
Group 5 oils are defined in section 1.2.7 of this appendix; the response resource considerations are outlined in section
7.6 of this appendix.
1 See sections 1.2.2 and 1.2.7 of this appendix for group designations for non-persistent and persistent oils, respectively.
TABLE 4 TO APPENDIX E—ON-WATER OIL RECOVERY RESOURCE MOBILIZATION FACTORS
1.0
1.8
2.0
Operating area
Rivers and Canals
Inland/Nearshore Great Lakes
Tier 1
0.30
0.15
Tier 2
0.40
0.25
Tiers
0.60
0.40
Note: These mobilization factors are for total resources mobilized, not incremental response resources.
TABLE 5 TO APPENDIX E—RESPONSE CAPABILITY CAPS BY OPERATING AREA
February 18, 1993:
Great Lakes
Rivers & Canals
Tier 1
1 0K bbls/day
5K bbls/day
1.5K bbls/dav
Tier 2
20K bbls/day
1 0K bbls/day
3.0K bbls/dav
Tiers
40K bbls/day
20K bbls/day.
6.0K bbls/dav.
81
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Pt. 112, App. E 40 CFR Ch. I (7-1-13 Edition)
TABLE 5 TO APPENDIX E—RESPONSE CAPABILITY CAPS BY OPERATING AREA—Continued
February 18, 1998:
All except Rivers & Canals, Great Lakes
Great Lakes
February 18, 2003:
Rivers & Canals
Tier 1
12.5K bbls/day
6.35K bbls/day
1 875K bbls/
day
TBD
TBD
TBD
Tier 2
25K bbls/day
12.3K bbls/day
3 75K bbls/day
TBD
TBD
TBD
Tiers
50K bbls/day.
25K bbls/day.
7 5K bbls/day
TBD
TBD
TBD.
Note: The caps show cumulative overall effective daily recovery capacity, not incremental increases.
TBD=To Be Determined.
TABLE 6 TO APPENDIX E—REMOVAL CAPACITY PLANNING TABLE FOR ANIMAL FATS AND VEGETABLE
OILS
Spill location
Sustainability of on-water oil recovery
Oil group1
Group B
Rivers and canals
3 days
Percent nat-
ural loss
40
20
Percent re-
covered
floating oil
15
15
Percent re-
covered oil
from on-
shore
45
65
Nearshore/lnland/Great Lakes
4 days
Percent nat-
ural loss
50
30
Percent re-
covered
floating oil
20
20
Percent re-
covered oil
from on-
shore
30
50
1 Substances with a specific gravity greater than 1.0 generally sink below the surface of the water. Response resource consid-
erations are outlined in section 10.6 of this appendix. The owner or operator of the facility is responsible for determining appro-
priate response resources for Group C oils including locating oil on the bottom or suspended in the water column; containment
boom or other appropriate methods for containing oil that may remain floating on the surface; and dredges, pumps, or other
equipment to recover animal fats or vegetable oils from the bottom and shoreline.
NOTE: Group C oils are defined in sections 1.2.1 and 1.2.9 of this appendix; the response resource procedures are discussed
in section 10.6 of this appendix.
TABLE 7 TO APPENDIX E—EMULSIFICATION FACTORS FOR ANIMAL FATS AND VEGETABLE OILS
Oil Group1:
Group A ,
Group B ,
1.0
2.0
1 Substances with a specific gravity greater than 1.0 generally sink below the surface of the water. Response resource consid-
erations are outlined in section 10.6 of this appendix. The owner or operator of the facility is responsible for determining appro-
priate response resources for Group C oils including locating oil on the bottom or suspended in the water column; containment
boom or other appropriate methods for containing oil that may remain floating on the surface; and dredges, pumps, or other
equipment to recover animal fats or vegetable oils from the bottom and shoreline.
NOTE: Group C oils are defined in sections 1.2.1 and 1.2.9 of this appendix; the response resource procedures are discussed
in section 10.6 of this appendix.
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Environmental Protection Agency
ATTACHMENTS TO APPENDIX E
Pt. 112, App. E
Attachment E-l --
Worksheet to Plan Volume of Response Resources
for Worst Case Discharge - Petroleum Oils
Part I Background Information
Step (A) Calculate Worst Case Discharge in barrels {Appendix D)
Step (B) Oil Group1 (Table 3 and section 1.2 of this appendix)
Step (C) Operating Area (choose one} ....
Near
shore/Inla
nd Great
Lakes
Step (D) Percentages of Oil (Table 2 of this appendix)
Percent Lost to
Natural Dissipation
Percent Recovered
Floating Oil
Percent
Oil Onshore
Step (El) On-Water Oil Recovery Step (D2) x Step(A)
100
Step (E2) Shoreline Recovery Step (D3) x Step (A)
100
Step (F) Emulsification Factor
(Table 3 of this appendix)
Step (G) On-Water Oil Recovery Resource Mobilization Factor
(Table 4 of this appendix)
83
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Pt. 112, App. E
40 CFR Ch. I (7-1-13 Edition)
Attachment E-l (continued) --
Worksheet to Plan Volume of Response Resources
for Worst Case Discharge - Petroleum Oils
Part II On-Water Oil Recovery Capacity (barrels/day)
Tier 2
Tier 1
Step (ED x Step (F> x
Step (G1)
Step (ED x Step (F) x
Step (G2>
Tier 3
Step (ED x Step (F) x
Step (G3>
Part III S ho re1ine CIeanup Volume (barrels) ....
Part IV On-Water Response; Capacity By Operating Area
(Table 5 of this appendix)
(Amount needed to be contracted for in barrels/day)
Tier 1
Tier 2
Step (E2) x Step (F)
(JD CJ2)
Part v On-Hater Amount Needed to be Identified, but not Contracted for ir
Tier 2
Tier 3
Part II Tier 1 - Step (JD
Part I! Tier 2 - Step (J2)
Part II Tier 3 - Step (J3)
NOTE: To convert from barrels/day to gallons/day, multiply the quantities in
Parts II through V by 42 gallons/barrel.
84
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Environmental Protection Agency
Pt. 112, App. E
Attachment E-l Example --
Worksheet to Plan Volume of Response Resources
for Worst Case Discharge - Petroleum Oils
Part I Background Infgrrnation
Step (A) Calculate Worst Case Discharge in barrels (Appendix D)
Step (B) Oil Group1 (Table 3 and section 1.2 of this appendix)
Step (C) Operating Area (choose one)
Near
shore/Inla
nd Great
Lakes
Step (D) Percentages of Oil (Table 2 of this appendix)
or
Rivers
and
Canals
Percent Lost to
Natural Dissipation
Percent Recovered
Floating Oil
Percent Oil Onshore
Step (El) On-Water Oil Recovery Step (D2) x Step (Al
100
Step (E2) Shoreline Recovery Step (DS^x^Step (A)
100
Step (F) Emulsification Factor
(Table 3 of this appendix)
Step (G) On-Water Oil Recovery Resource Mobilization Factor
(Table 4 of this appendix)
1 A facility that handles, stores, or transports multiple groups of oil must do separate calculations for each
oil group on site except for those oil groups that constitute 10 percent or less by volume of the total oil
storage capacity at the facility. For purposes of this calculation, the volumes of all products in an oil
group must be summed to determine the percentage of the facility's total oil storage capacity.
85
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Pt. 112, App. E
40 CFR Ch. I (7-1-13 Edition)
Attachment E-l Example (continued) --
Worksheet to Plan Volume of Response Resources
for Worst Case Discharge - Petroleum Oils
Part II On-Water Oil Recovery Capacity (barrels/day)
Tier 1
Tier 2
17,850
29,750
Step (ED x Step (F) x
Step (CD
Step (ED x Step (F) x
Step (02)
Tier 3
47,600
Step (ED x Step (F) x
Step (G3>
Part III Shoreline Cleanup Volume (barrels) ....
Part IV On-Water Response Capacity By Operating Area
(Table 5 of this appendix)
(Amount needed to be contracted for in barrels/day)
166,600
Step (E2) x Step (F)
Tier 1
Tier 2
10,000
20,000
(JD
(J2>
40,000
(J3>
Part V On-Water Amount Needed to be Identified, but not Contracted for in
Advance (barrels/day)
Tier 1
Tier 2
Tier 3
7, 850
9,750
7,600
Part II Tier 1 - Step (JD
Part II Tier 2 - Step (J2)
Part II Tier 3 - Step (J3>
NOTE: To convert from barrels/day to gallons/day, multiply the quantities in
Parts II through V by 42 gallons/barrel.
86
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Environmental Protection Agency
Pt. 112, App. E
Attachment E-2 --
Worksheet to Plan Volume of Response Resources
for Worst Case Discharge - Animal Fats and Vegetable Oils
Part I Backer round Information
Step (A) Calculate Worst Case Discharge in barrels (Appendix D)
Step (B) Oil Group1 (Table 7 and section 1.2 of this appendix)
Step (C) Operating Area (choose one) ....
Near
shore/Inla
nd Great
Lakes
Step (D) Percentages of Oil (Table 6 of this appendix)
Percent Lost to
Natural Dissipation
Percent Recovered
Floating Oil
Percent
Oil Onshore
Step (El) On-Water Oil Recovery Step (D2) x Step (A).
100
Step (E2) Shoreline Recovery Step (D3) x Step (Al . . .
100
Step (F) Emulsification Factor
(Table 7 of this appendix)
Step (G) On-Water Oil Recovery Resource Mobilization Factor
(Table 4 of this appendix)
87
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Pt. 112, App. E 40 CFR Ch. I (7-1-13 Edition)
Attachment E-2 (continued) --
Worksheet to Plan Volume of Response Resources
for Worst Case Discharge - Animal Fats and Vegetable Oils
Part II On-Water Oil Recovery Capacity (barrels/day)
Tier 1 Tier 2 Tier 3
Step (ED x Step (F> x Step x Step (F) x Step (ED x Step (F) x
Step (GD Step (G2> Step
Part III Shoreline Cleanup Volume (barrels) ....
step (E2> x step (F)
Part IV On-Water Response Capacity By Operating Area
(Table S of this appendix)
(Amount needed to be contracted for in barrels/day)
Tier 1 Tier 2 Tier 3
(J1> (J2> (J3>
Part V On-Water Amount Needed to be Identified, but not Contracted for
in Advance (barrels/day)
Tier 1 Tier 2 Tier 3
Part II Tier 1 - Step (JD Part II Tier I - Step (J2) Part II Tier 3 - Step (J3>
NOTE: To convert from barrels/day to gallons/day, multiply the
quantities in Parts II through V by 42 gallons/barrel.
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Environmental Protection Agency
Pt. 112, App. E
Attachment E-2 Example --
Worksheet to Plan Volume of Response Resources
for Worst Case Discharge - Animal Fats and Vegetable Oils
Part I Background Information
Step (A) Calculate Worst Case Discharge in barrels
(Appendix D)
500,
000
Step (B) Oil Group1 (Table 7 and section 1.2 of this
appendix)
Step (C) Operating Area (choose
one)
Near
shore/Inl
and Great
Lakes
Step (D) Percentages of Oil (Table 6 of this appendix)
or
Rivers
and
Canals
Percent Lost to
Natural
Dissipation
30
Percent Recovered
Floating Oil
20
(D2)
Step (El) On-Water Oil Recovery Step (D2) x Step (A)
100
Percent Oil
Onshore
50
100,000
Step (E2) Shoreline Recovery Step (D3) x Step (A)
100
250,000
Step (F) Etnulsification Factor
(Table 7 of this appendix)
2.0
Step (G) On-Water Oil Recovery Resource Mobilization Factor
(Table 4 of this appendix)
Tier 1
Tier 2
Tier 3
0
15
0
25
0
40
(G2)
1 A facility that handles, stores, or transports multiple groups of oil must do separate calculations for each
oil group on site except for those oil groups that constitute 10 percent or less by volume of the total oil
storage capacity at the facility. For purposes of this calculation, the volumes of all products in an oil
group must be summed to determine the percentage of the facility's total oil storage capacity.
89
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Pt. 112, App. F
40 CFR Ch. I (7-1-13 Edition)
Attachment E-2 Example (continued) --
Worksheet to Plan Volume of Response Resources
for Worst Case Discharge - Animal Fats and Vegetable Oils (continued)
Part II On-Water Oil Recovery Capacity (barrels/day)
Tier 1 Tier 2
30,000
50,000
Step (E1) x Step (F) x
Step (01)
Step (E1) x Step (F) x
Step
Tier 3
80,000
Step
Part V On-Water Amount Needed to be Identified, but not Contracted for
in Advance (barrels/day)
Tier 1
Tier 2
Tier 3
17,500
25,000
30,000
Part II Tier 1 - Step
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Environmental Protection Agency
1.7 Plan Implementation
1.7.1 Response Resources for Small, Me-
dium, and Worst Case Spills
1.7.2 Disposal Plans
1.7.3 Containment and Drainage Planning
1.8 Self-Inspection, Drills/Exercises, and Re-
sponse Training
1.8.1 Facility Self-Inspection
1.8.1.1 Tank Inspection
1.8.1.2 Response Equipment Inspection
1.8.1.3 Secondary Containment Inspection
1.8.2 Facility Drills/Exercises
1.8.2.1 Qualified Individual Notification
Drill Logs
1.8.2.2 Spill Management Team Tabletop
Exercise Logs
1.8.3 Response Training
1.8.3.1 Personnel Response Training Logs
1.8.3.2 Discharge Prevention Meeting Logs
1.9 Diagrams
1.10 Security
2.0 Response Plan Cover Sheet
3.0 Acronyms
4.0 References
1.0 Model Facility-Specific Response Plan
(A) Owners or operators of facilities regu-
lated under this part which pose a threat of
substantial harm to the environment by dis-
charging oil into or on navigable waters or
adjoining shorelines are required to prepare
and submit facility-specific response plans to
EPA in accordance with the provisions in
Pt. 112, App. F
this appendix. This appendix further de-
scribes the required elements in §112.20(h).
(B) Response plans must be sent to the ap-
propriate EPA Regional office. Figure F-l of
this Appendix lists each EPA Regional office
and the address where owners or operators
must submit their response plans. Those fa-
cilities deemed by the Regional Adminis-
trator (RA) to pose a threat of significant
and substantial harm to the environment
will have their plans reviewed and approved
by EPA. In certain cases, information re-
quired in the model response plan is similar
to information currently maintained in the
facility's Spill Prevention, Control, and
Countermeasures (SPCC) Plan as required by
40 CFR 112.3. In these cases, owners or opera-
tors may reproduce the information and in-
clude a photocopy in the response plan.
(C) A complex may develop a single re-
sponse plan with a set of core elements for
all regulating agencies and separate sections
for the non-transportation-related and trans-
portation-related components, as described
in §112.20(h). Owners or operators of large fa-
cilities that handle, store, or transport oil at
more than one geographically distinct loca-
tion (e.g., oil storage areas at opposite ends
of a single, continuous parcel of property)
shall, as appropriate, develop separate sec-
tions of the response plan for each storage
area.
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Pt. 112, App. F
40 CFR Ch. I (7-1-13 Edition)
1.1 Emergency Response Action Plan
Several sections of the response plan shall
be co-located for easy access by response per-
sonnel during an actual emergency or oil dis-
charge. This collection of sections shall be
called the Emergency Response Action Plan.
The Agency intends that the Action Plan
contain only as much information as is nec-
essary to combat the discharge and be ar-
ranged so response actions are not delayed.
The Action Plan may be arranged in a num-
ber of ways. For example, the sections of the
Emergency Response Action Plan may be
photocopies or condensed versions of the
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Environmental Protection Agency
Pt. 112, App. F
forms included in the associated sections of
the response plan. Bach Emergency Response
Action Plan section may be tabbed for quick
reference. The Action Plan shall be main-
tained in the front of the same binder that
contains the complete response plan or it
shall be contained in a separate binder. In
the latter case, both binders shall be kept to-
gether so that the entire plan can be
accessed by the qualified individual and ap-
propriate spill response personnel. The
Emergency Response Action Plan shall be
made up of the following sections:
1. Qualified Individual Information (Section
1.2) partial
2. Emergency Notification Phone List (Sec-
tion 1.3.1) partial
3. Spill Response Notification Form (Section
1.3.1) partial
4. Response Equipment List and Location
(Section 1.3.2) complete
5. Response Equipment Testing and Deploy-
ment (Section 1.3.3) complete
6. Facility Response Team (Section 1.3.4)
partial
7. Evacuation Plan (Section 1.3.5) condensed
8. Immediate Actions (Section 1.7.1) com-
plete
9. Facility Diagram (Section 1.9) complete
1.2 Facility Information
The facility information form is designed
to provide an overview of the site and a de-
scription of past activities at the facility.
Much of the information required by this
section may be obtained from the facility's
existing SPCC Plan.
1.2.1 Facility name and location: Enter fa-
cility name and street address. Enter the ad-
dress of corporate headquarters only if cor-
porate headquarters are physically located
at the facility. Include city, county, state,
zip code, and phone number.
1.2.2 Latitude and Longitude: Enter the
latitude and longitude of the facility. In-
clude degrees, minutes, and seconds of the
main entrance of the facility.
1.2.3 Wellhead Protection Area: Indicate if
the facility is located in or drains into a
wellhead protection area as defined by the
Safe Drinking Water Act of 1986 (SDWA).1
The response plan requirements in the Well-
head Protection Program are outlined by the
1A wellhead protection area is defined as
the surface and subsurface area surrounding
a water well or wellfield, supplying a public
water system, through which contaminants
are reasonably likely to move toward and
reach such water well or wellfield. For fur-
ther information regarding State and terri-
tory protection programs, facility owners or
operators may contact the SDWA Hotline at
1-800^26-4791.
State or Territory in which the facility re-
sides.
1.2.4 Owner/operator: Write the name of
the company or person operating the facility
and the name of the person or company that
owns the facility, if the two are different.
List the address of the owner, if the two are
different.
1.2.5 Qualified Individual: Write the name
of the qualified individual for the entire fa-
cility. If more than one person is listed, each
individual indicated in this section shall
have full authority to implement the facility
response plan. For each individual, list:
name, position, home and work addresses
(street addresses, not P.O. boxes), emergency
phone number, and specific response training
experience.
1.2.6 Date of Oil Storage Start-up: Enter the
year which the present facility first started
storing oil.
1.2.7 Current Operation: Briefly describe
the facility's operations and include the
North American Industrial Classification
System (NAICS) code.
1.2.8 Dates and Type of Substantial Expan-
sion: Include information on expansions that
have occurred at the facility. Examples of
such expansions include, but are not limited
to: Throughput expansion, addition of a
product line, change of a product line, and
installation of additional oil storage capac-
ity. The data provided shall include all facil-
ity historical information and detail the ex-
pansion of the facility. An example of sub-
stantial expansion is any material alteration
of the facility which causes the owner or op-
erator of the facility to re-evaluate and in-
crease the response equipment necessary to
adequately respond to a worst case discharge
from the facility.
Date of Last Update:
FACILITY INFORMATION FORM
Facility Name:
Location (Street Address):
City: State: Zip:
County: _
Latitude:
Phone Number: ( )
Degrees Minutes
Seconds
Longitude:
Degrees
Minutes
Seconds
Wellhead Protection Area:
Owner:
Owner Location (Street Address):
(if different from Facility Address)
City: State: Zip:
County: Phone Number: ( )
Operator (if not Owner):
Qualified Individual(s): (attach additional
sheets if more than one)
Name:
Position:
Work Address:
Home Address:
Emergency Phone Number: ( )
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Pt. 112, App. F
40 CFR Ch. I (7-1-13 Edition)
Date of Oil Storage Start-up:
Current Operations:
Date(s) and Type(s) of Substantial Expan-
sion(s):
(Attach additional sheets if necessary)
1.3 Emergency Response Information
(A) The information provided in this sec-
tion shall describe what will be needed in an
actual emergency involving the discharge of
oil or a combination of hazardous substances
and oil discharge. The Emergency Response
Information section of the plan must include
the following components:
(1) The information provided in the Emer-
gency Notification Phone List in section
1.3.1 identifies and prioritizes the names and
phone numbers of the organizations and per-
sonnel that need to be notified immediately
in the event of an emergency. This section
shall include all the appropriate phone num-
bers for the facility. These numbers must be
verified each time the plan is updated. The
contact list must be accessible to all facility
employees to ensure that, in case of a dis-
charge, any employee on site could imme-
diately notify the appropriate parties.
(2) The Spill Response Notification Form
in section 1.3.1 creates a checklist of infor-
mation that shall be provided to the Na-
tional Response Center (NRC) and other re-
sponse personnel. All information on this
checklist must be known at the time of noti-
fication, or be in the process of being col-
lected. This notification form is based on a
similar form used by the NRC. Note: Do not
delay spill notification to collect the infor-
mation on the list.
(3) Section 1.3.2 provides a description of
the facility's list of emergency response
equipment and location of the response
equipment. When appropriate, the amount of
oil that emergency response equipment can
handle and any limitations (e.g., launching
sites) must be described.
(4) Section 1.3.3 provides information re-
garding response equipment tests and de-
ployment drills. Response equipment deploy-
ment exercises shall be conducted to ensure
that response equipment is operational and
the personnel who would operate the equip-
ment in a spill response are capable of de-
ploying and operating it. Only a representa-
tive sample of each type of response equip-
ment needs to be deployed and operated, as
long as the remainder is properly main-
tained. If appropriate, testing of response
equipment may be conducted while it is
being deployed. Facilities without facility-
owned response equipment must ensure that
the oil spill removal organization that is
identified in the response plan to provide
this response equipment certifies that the
deployment exercises have been met. Refer
to the National Preparedness for Response
Exercise Program (PREP) Guidelines (see ap-
pendix E to this part, section 13, for avail-
ability), which satisfy Oil Pollution Act
(OPA) response exercise requirements.
(5) Section 1.3.4 lists the facility response
personnel, including those employed by the
facility and those under contract to the fa-
cility for response activities, the amount of
time needed for personnel to respond, their
responsibility in the case of an emergency,
and their level of response training. Three
different forms are included in this section.
The Emergency Response Personnel List
shall be composed of all personnel employed
by the facility whose duties involve respond-
ing to emergencies, including oil discharges,
even when they are not physically present at
the site. An example of this type of person
would be the Building Engineer-in-Charge or
Plant Fire Chief. The second form is a list of
the Emergency Response Contractors (both
primary and secondary) retained by the fa-
cility. Any changes in contractor status
must be reflected in updates to the response
plan. Evidence of contracts with response
contractors shall be included in this section
so that the availability of resources can be
verified. The last form is the Facility Re-
sponse Team List, which shall be composed
of both emergency response personnel (ref-
erenced by job title/position) and emergency
response contractors, included in one of the
two lists described above, that will respond
immediately upon discovery of an oil dis-
charge or other emergency (i.e., the first
people to respond). These are to be persons
normally on the facility premises or primary
response contractors. Examples of these per-
sonnel would be the Facility Hazardous Ma-
terials (HAZMAT) Spill Team 1, Facility
Fire Engine Company 1, Production Super-
visor, or Transfer Supervisor. Company per-
sonnel must be able to respond immediately
and adequately if contractor support is not
available.
(6) Section 1.3.5 lists factors that must, as
appropriate, be considered when preparing an
evacuation plan.
(7) Section 1.3.6 references the responsibil-
ities of the qualified individual for the facil-
ity in the event of an emergency.
(B) The information provided in the emer-
gency response section will aid in the assess-
ment of the facility's ability to respond to a
worst case discharge and will identify addi-
tional assistance that may be needed. In ad-
dition, the facility owner or operator may
want to produce a wallet-size card con-
taining a checklist of the immediate re-
sponse and notification steps to be taken in
the event of an oil discharge.
1.3.1 Notification
Date of Last Update:
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Environmental Protection Agency
EMERGENCY NOTIFICATION PHONE LIST WHOM
To NOTIFY
Reporter's Name:
Date:
Facility Name:
Owner Name:
Facility Identification Number:
Date and Time of Bach NRC Notification:
Organization
Phone No.
1. National Response Center (NRC):
2. Qualified Individual:
Evening Phone:
3. Company Response Team:
Evening Phone:
4. Federal On-Scene Coordinator (OSC)
and/or Regional Response Center
(RRC):
Evening Phone(s):
Pager Number(s):
5. Local Response Team (Fire Dept./Co-
operatives):
6. Fire Marshall:
Evening Phone:
7. State Emergency Response Commis-
sion (SERC):
Evening Phone:
8. State Police:
9. Local Emergency Planning Committee
(LEPC):
10. Local Water Supply System:
Evening Phone:
11. Weather Report:
12. Local Television/Radio Station for
Evacuation Notification:
13. Hospitals:
1-800^24-8802
Pt. 112, App. F
SPILL RESPONSE NOTIFICATION FORM
Reporter's Last Name:
First:
M.I.:
Position:
Phone Numbers:
Day ( )
Evening ( )
Company:
Organization Type:
Address:
City:
State:
Zip:
Were Materials Discharged? (Y/N) Con-
fidential? (Y/N)
Meeting Federal Obligations to Report?
(Y/N) Date Called:
Calling for Responsible Party? (Y/N)
Time Called:
Incident Description
Source and/or Cause of Incident:
Date of Incident:
Time of Incident:
AM/PM
Incident Address/Location:
Nearest City:_
County:
State:
Zip:
Distance from City:
Units of Measure:
Direction from City:
Section: Township:
Borough:
Range:
Tank Oil Storage Ca-
Container Type: _
pacity: Units of Measure:
Facility Oil Storage Capacity:
of Measure:
Facility Latitude: Degrees
utes Seconds
Facility Longitude: Degrees
Minutes Seconds
Material
Units
Min-
CHRIS Code
Discharged quan- Uni, Qf measure
Material Dis-
charged in water
Quantity
Unit of measure
95
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Pt. 112, App. F
40 CFR Ch. I (7-1-13 Edition)
Response Action
Actions Taken to Correct, Control or Miti-
gate Incident:
Impact
Number of Injuries: Number of Deaths:
Were there Evacuations?
ber Evacuated:
Was there any Damage?
(Y/N) Num-
_ (Y/N)
Damage in Dollars (approximate):
Medium Affected:
Description:
More Information about Medium:
Additional Information
Any information about the incident not re-
corded elsewhere in the report:
Caller Notifications
EPA? (Y/N) USCG? (Y/N) State?
(Y/N)
Other? (Y/N) Describe:
1.3.2 Response Equipment List
Date of Last Update:
FACILITY RESPONSE EQUIPMENT LIST
1. Skimmers/Pumps—Operational Status:
Type, Model, and Year:
Model
Year
Type
Number:
Capacity:
Daily Effective Recovery Rate:
Storage Location(s):
gal./min.
Date Fuel Last Changed: _
2. Boom—Operational Status:
Type, Model, and Year:
Type Model Year
Number:
Size (length):
Containment Area:
Storage Location:
ft.
sq. ft.
3. Chemicals Stored (Dispersants listed on
EPA's NCP Product Schedule)
Type
Amount
Date
purchased
Treatment
capacity
Storage
location
Were appropriate procedures used to re-
ceive approval for use of dispersants in ac-
cordance with the NCP (40 CFR 300.910) and
the Area Contingency Plan (ACP), where ap-
plicable? (Y/N).
Name and State of On-Scene Coordinator
(OSC) authorizing use: .
Date Authorized: .
4. Dispersant Dispensing Equipment—Oper-
ational Status:
Type and year
Capacity
Storage
location
Response
time
(minutes)
5. Sorbents—Operational Status:
Type and Year Purchased:
Amount:
Absorption Capacity (gal.):
Storage Location(s):
6. Hand Tools—Operational Status:
Type and year
Quantity
Storage
location
96
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Environmental Protection Agency
Pt. 112, App. F
Type and year
7. Communic
erating freque
lular phone n
Type and year
Quantity
Storage
location
ation Equipment (include op-
ncy and channel and/or eel-
umbers) — Operational Status:
Quantity
8. Fire Fighting and Person
Equipment — Operational StatL
Type and year
Quantity
Storage location/
number
nel Protective
s:
Storage
location
9. Other (e.g., Heavy Equipment, Boats and
Motors)—Operational Status:
Type and year
Quantity
Storage
location
1.3.3 Response Equipment Testing/Deployment
Date of Last Update:
Response Equipment Testing and
Deployment Drill Log
Last Inspection or Response Equipment Test
Date:
Inspection Frequency:
Last Deployment Drill Date:
Deployment Frequency:
Oil Spill Removal Organization Certification
(if applicable):
1.3.4 Personnel
Date of Last Update:
EMERGENCY RESPONSE PERSONNEL
Company Personnel
Name
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
Phone1
Response time
Responsibility during re-
sponse action
Response training type/date
1 Phone number to be used when person is not on-site.
EMERGENCY RESPONSE CONTRACTORS
Date of Last Update:
Contractor
1.
Phone
Response time
Contract responsibility1
97
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Pt. 112, App. F
40 CFR Ch. I (7-1-13 Edition)
EMERGENCY RESPONSE CONTRACTORS—Continued
Date of Last Update:
Contractor
2.
3.
4.
Phone
Response time
Contract responsibility1
11nclude evidence of contracts/agreements with response contractors to ensure the availability of personnel and response
equipment.
FACILITY RESPONSE TEAM
Date of Last Update:
Team member
Qualified Individual:
Response time (minutes)
Phone or pager number (day/evening)
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
NOTE: If the facility uses contracted help in an emergency response situation, the owner or operator must provide the contrac-
tors' names and review the contractors' capacities to provide adequate personnel and response equipment.
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Environmental Protection Agency
Pt. 112, App. F
1.3.5 Evacuation Plans
1.3.5.1 Based on the analysis of the facil-
ity, as discussed elsewhere in the plan, a fa-
cility-wide evacuation plan shall be devel-
oped. In addition, plans to evacuate parts of
the facility that are at a high risk of expo-
sure in the event of a discharge or other re-
lease must be developed. Evacuation routes
must be shown on a diagram of the facility
(see section 1.9 of this appendix). When de-
veloping evacuation plans, consideration
must be given to the following factors, as ap-
propriate:
(1) Location of stored materials;
(2) Hazard imposed by discharged material;
(3) Discharge flow direction;
(4) Prevailing wind direction and speed;
(5) Water currents, tides, or wave condi-
tions (if applicable);
(6) Arrival route of emergency response
personnel and response equipment;
(7) Evacuation routes;
(8) Alternative routes of evacuation;
(9) Transportation of injured personnel to
nearest emergency medical facility;
(10) Location of alarm/notification sys-
tems;
(11) The need for a centralized check-in
area for evacuation validation (roll call);
(12) Selection of a mitigation command
center; and
(13) Location of shelter at the facility as
an alternative to evacuation.
1.3.5.2 One resource that may be helpful
to owners or operators in preparing this sec-
tion of the response plan is The Handbook of
Chemical Hazard Analysis Procedures by the
Federal Emergency Management Agency
(FEMA), Department of Transportation
(DOT), and EPA. The Handbook of Chemical
Hazard Analysis Procedures is available from:
FEMA , Publication Office, 500 C. Street,
S.W., Washington, DC 20472, (202) 646-3484.
1.3.5.3 As specified in §112.20(h)(l)(vi), the
facility owner or operator must reference ex-
isting community evacuation plans, as ap-
propriate.
1.3.6 Qualified Individual's Duties
The duties of the designated qualified indi-
vidual are specified in §112.20(h)(3)(ix). The
qualified individual's duties must be de-
scribed and be consistent with the minimum
requirements in §112.20(h)(3)(ix). In addition,
the qualified individual must be identified
with the Facility Information in section 1.2
of the response plan.
1.4 Hazard Evaluation
This section requires the facility owner or
operator to examine the facility's operations
closely and to predict where discharges could
occur. Hazard evaluation is a widely used in-
dustry practice that allows facility owners
or operators to develop a complete under-
standing of potential hazards and the re-
sponse actions necessary to address these
hazards. The Handbook of Chemical Hazard
Analysis Procedures, prepared by the EPA,
DOT, and the FEMA and the Hazardous Mate-
rials Emergency Planning Guide (NRT-1), pre-
pared by the National Response Team are
good references for conducting a hazard anal-
ysis. Hazard identification and evaluation
will assist facility owners or operators in
planning for potential discharges, thereby
reducing the severity of discharge impacts
that may occur in the future. The evaluation
also may help the operator identify and cor-
rect potential sources of discharges. In addi-
tion, special hazards to workers and emer-
gency response personnel's health and safety
shall be evaluated, as well as the facility's
oil spill history.
1.4.1 Hazard Identification
The Tank and Surface Impoundment (SI)
forms, or their equivalent, that are part of
this section must be completed according to
the directions below. ("Surface Impound-
ment" means a facility or part of a facility
which is a natural topographic depression,
man-made excavation, or diked area formed
primarily of earthen materials (although it
may be lined with man-made materials),
which is designed to hold an accumulation of
liquid wastes or wastes containing free liq-
uids, and which is not an injection well or a
seepage facility.) Similar worksheets, or
their equivalent, must be developed for any
other type of storage containers.
(1) List each tank at the facility with a
separate and distinct identifier. Begin above-
ground tank identifiers with an "A" and be-
lowground tank identifiers with a "B", or
submit multiple sheets with the aboveground
tanks and belowground tanks on separate
sheets.
(2) Use gallons for the maximum capacity
of a tank; and use square feet for the area.
(3) Using the appropriate identifiers and
the following instructions, fill in the appro-
priate forms:
(a) Tank or SI number—Using the afore-
mentioned identifiers (A or B) or multiple
reporting sheets, identify each tank or SI at
the facility that stores oil or hazardous ma-
terials.
(b) Substance Stored—For each tank or SI
identified, record the material that is stored
therein. If the tank or SI is used to store
more than one material, list all of the stored
materials.
(c) Quantity Stored—For each material
stored in each tank or SI, report the average
volume of material stored on any given day.
(d) Tank Type or Surface Area/Year—For
each tank, report the type of tank (e.g.,
floating top), and the year the tank was
originally installed. If the tank has been re-
fabricated, the year that the latest refabrica-
tion was completed must be recorded in pa-
rentheses next to the year installed. For
99
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Pt. 112, App. F
40 CFR Ch. I (7-1-13 Edition)
each SI, record the surface area of the im-
poundment and the year it went into service.
(e) Maximum Capacity—Record the oper-
ational maximum capacity for each tank and
SI. If the maximum capacity varies with the
season, record the upper and lower limits.
(f) Failure/Cause—Record the cause and
date of any tank or SI failure which has re-
sulted in a loss of tank or SI contents.
(4) Using the numbers from the tank and
SI forms, label a schematic drawing of the
facility. This drawing shall be identical to
any schematic drawings included in the
SPCC Plan.
(5) Using knowledge of the facility and its
operations, describe the following in writing:
(a) The loading and unloading of transpor-
tation vehicles that risk the discharge of oil
or release of hazardous substances during
transport processes. These operations may
include loading and unloading of trucks,
railroad cars, or vessels. Estimate the vol-
ume of material involved in transfer oper-
ations, if the exact volume cannot be deter-
mined.
(b) Day-to-day operations that may
present a risk of discharging oil or releasing
a hazardous substance. These activities in-
clude scheduled venting, piping repair or re-
placement, valve maintenance, transfer of
tank contents from one tank to another, etc.
(not including transportation-related activi-
ties). Estimate the volume of material in-
volved in these operations, if the exact vol-
ume cannot be determined.
(c) The secondary containment volume as-
sociated with each tank and/or transfer point
at the facility. The numbering scheme devel-
oped on the tables, or an equivalent system,
must be used to identify each containment
area. Capacities must be listed for each indi-
vidual unit (tanks, slumps, drainage traps,
and ponds), as well as the facility total.
(d) Normal daily throughput for the facil-
ity and any effect on potential discharge vol-
umes that a negative or positive change in
that throughput may cause.
HAZARD IDENTIFICATION TANKS 1
Date of Last Update:
Tank No.
Substance Stored
(Oil and Hazardous
Substance)
Quantity Stored
(gallons)
Tank Type/Year
Maximum Capacity
(gallons)
Failure/Cause
1 Tank = any container that stores oil.
Attach as many sheets as necessary.
HAZARD IDENTIFICATION SURFACE IMPOUNDMENTS (Sis)
Date of Last Update:
SI No.
Substance Stored
Quantity Stored
(gallons)
Surface Area/Year
Maximum Capacity
(gallons)
Failure/Cause
100
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Pt. 112, App. F
HAZARD IDENTIFICATION SURFACE IMPOUNDMENTS (Sis)—Continued
Date of Last Update:
SI No.
Substance Stored
Quantity Stored
(gallons)
Surface Area/Year
Maximum Capacity
(gallons)
Failure/Cause
Attach as many sheets as necessary.
1.4.2 Vulnerability Analysis
The vulnerability analysis shall address
the potential effects (i.e., to human health,
property, or the environment) of an oil dis-
charge. Attachment C-III to Appendix C to
this part provides a method that owners or
operators shall use to determine appropriate
distances from the facility to fish and wild-
life and sensitive environments. Owners or
operators can use a comparable formula that
is considered acceptable by the RA. If a com-
parable formula is used, documentation of
the reliability and analytical soundness of
the formula must be attached to the re-
sponse plan cover sheet. This analysis must
be prepared for each facility and, as appro-
priate, must discuss the vulnerability of:
(1) Water intakes (drinking, cooling, or
other);
(2) Schools;
(3) Medical facilities;
(4) Residential areas;
(5) Businesses;
(6) Wetlands or other sensitive environ-
ments;2
(7) Fish and wildlife;
(8) Lakes and streams;
(9) Endangered flora and fauna;
(10) Recreational areas;
(11) Transportation routes (air, land, and
water);
(12) Utilities; and
(13) Other areas of economic importance
(e.g., beaches, marinas) including terrestri-
ally sensitive environments, aquatic envi-
ronments, and unique habitats.
1.4.3 Analysis of the Potential for an Oil
Discharge
Bach owner or operator shall analyze the
probability of a discharge occurring at the
facility. This analysis shall incorporate fac-
tors such as oil discharge history, horizontal
range of a potential discharge, and vulner-
ability to natural disaster, and shall, as ap-
propriate, incorporate other factors such as
tank age. This analysis will provide informa-
tion for developing discharge scenarios for a
worst case discharge and small and medium
discharges and aid in the development of
techniques to reduce the size and frequency
of discharges. The owner or operator may
need to research the age of the tanks the oil
discharge history at the facility.
1.4.4 Facility Reportable Oil Spill History
Briefly describe the facility's reportable
oil spill3 history for the entire life of the fa-
cility to the extent that such information is
reasonably identifiable, including:
(1) Date of discharge(s);
(2) List of discharge causes;
(3) Material(s) discharged;
(4) Amount discharged in gallons;
(5) Amount of discharge that reached navi-
gable waters, if applicable;
(6) Effectiveness and capacity of secondary
containment;
(7) Clean-up actions taken;
(8) Steps taken to reduce possibility of re-
currence;
(9) Total oil storage capacity of the tank(s)
or impoundment(s) from which the material
discharged;
(10) Enforcement actions;
(11) Effectiveness of monitoring equip-
ment; and
(12) Description(s) of how each oil dis-
charge was detected.
2Refer to the DOC/NOAA "Guidance for
Facility and Vessel Response Plans: Fish and
Wildlife and Sensitive Environments" (See
appendix E to this part, section 13, for avail-
ability).
3 As described in 40 CFR part 110, report-
able oil spills are those that: (a) violate ap-
plicable water quality standards, or (b) cause
a film or sheen upon or discoloration of the
surface of the water or adjoining shorelines
or cause a sludge or emulsion to be deposited
beneath the surface of the water or upon ad-
joining shorelines.
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40 CFR Ch. I (7-1-13 Edition)
The information solicited in this section
may be similar to requirements in 40 CFR
112.4(a). Any duplicate information required
by §112.4(a) may be photocopied and inserted.
1.5 Discharge Scenarios
In this section, the owner or operator is re-
quired to provide a description of the facili-
ty's worst case discharge, as well as a small
and medium discharge, as appropriate. A
multi-level planning approach has been cho-
sen because the response actions to a dis-
charge (i.e., necessary response equipment,
products, and personnel) are dependent on
the magnitude of the discharge. Planning for
lesser discharges is necessary because the
nature of the response may be qualitatively
different depending on the quantity of the
discharge. The facility owner or operator
shall discuss the potential direction of the
discharge pathway.
1.5.1 Small and Medium Discharges
1.5.1.1 To address multi-level planning re-
quirements, the owner or operator must con-
sider types of facility-specific discharge sce-
narios that may contribute to a small or me-
dium discharge. The scenarios shall account
for all the operations that take place at the
facility, including but not limited to:
(1) Loading and unloading of surface trans-
portation;
(2) Facility maintenance;
(3) Facility piping;
(4) Pumping stations and sumps;
(5) Oil storage tanks;
(6) Vehicle refueling; and
(7) Age and condition of facility and com-
ponents.
1.5.1.2 The scenarios shall also consider
factors that affect the response efforts re-
quired by the facility. These include but are
not limited to:
(1) Size of the discharge;
(2) Proximity to downgradient wells, wa-
terways, and drinking water intakes;
(3) Proximity to fish and wildlife and sen-
sitive environments;
(4) Likelihood that the discharge will trav-
el offsite (i.e., topography, drainage);
(5) Location of the material discharged
(i.e., on a concrete pad or directly on the
soil);
(6) Material discharged;
(7) Weather or aquatic conditions (i.e.,
river flow);
(8) Available remediation equipment;
(9) Probability of a chain reaction of fail-
ures; and
(10) Direction of discharge pathway.
1.5.2 Worst Case Discharge
1.5.2.1 In this section, the owner or oper-
ator must identify the worst case discharge
volume at the facility. Worksheets for pro-
duction and non-production facility owners
or operators to use when calculating worst
case discharge are presented in appendix D
to this part. When planning for the worst
case discharge response, all of the aforemen-
tioned factors listed in the small and me-
dium discharge section of the response plan
shall be addressed.
1.5.2.2 For onshore storage facilities and
production facilities, permanently
manifolded oil storage tanks are defined as
tanks that are designed, installed, and/or op-
erated in such a manner that the multiple
tanks function as one storage unit (i.e., mul-
tiple tank volumes are equalized). In this
section of the response plan, owners or oper-
ators must provide evidence that oil storage
tanks with common piping or piping systems
are not operated as one unit. If such evidence
is provided and is acceptable to the RA, the
worst case discharge volume shall be based
on the combined oil storage capacity of all
manifold tanks or the oil storage capacity of
the largest single oil storage tank within the
secondary containment area, whichever is
greater. For permanently manifolded oil
storage tanks that function as one storage
unit, the worst case discharge shall be based
on the combined oil storage capacity of all
manifolded tanks or the oil storage capacity
of the largest single tank within a secondary
containment area, whichever is greater. For
purposes of the worst case discharge calcula-
tion, permanently manifolded oil storage
tanks that are separated by internal divi-
sions for each tank are considered to be sin-
gle tanks and individual manifolded tank
volumes are not combined.
1.6 Discharge Detection Systems
In this section, the facility owner or oper-
ator shall provide a detailed description of
the procedures and equipment used to detect
discharges. A section on discharge detection
by personnel and a discussion of automated
discharge detection, if applicable, shall be
included for both regular operations and
after hours operations. In addition, the facil-
ity owner or operator shall discuss how the
reliability of any automated system will be
checked and how frequently the system will
be inspected.
1.6.1 Discharge Detection by Personnel
In this section, facility owners or opera-
tors shall describe the procedures and per-
sonnel that will detect any discharge of oil
or release of a hazardous substance. A thor-
ough discussion of facility inspections must
be included. In addition, a description of ini-
tial response actions shall be addressed. This
section shall reference section 1.3.1 of the re-
sponse plan for emergency response informa-
tion.
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Pt. 112, App. F
1.6.2 Automated Discharge Detection
In this section, facility owners or opera-
tors must describe any automated discharge
detection equipment that the facility has in
place. This section shall include a discussion
of overfill alarms, secondary containment
sensors, etc. A discussion of the plans to
verify an automated alarm and the actions
to be taken once verified must also be in-
cluded.
1.7 Plan Implementation
In this section, facility owners or opera-
tors must explain in detail how to imple-
ment the facility's emergency response plan
by describing response actions to be carried
out under the plan to ensure the safety of
the facility and to mitigate or prevent dis-
charges described in section 1.5 of the re-
sponse plan. This section shall include the
identification of response resources for
small, medium, and worst case discharges;
disposal plans; and containment and drain-
age planning. A list of those personnel who
would be involved in the cleanup shall be
identified. Procedures that the facility will
use, where appropriate or necessary, to up-
date their plan after an oil discharge event
and the time frame to update the plan must
be described.
1.7.1 Response Resources for Small, Medium,
and Worst Case Discharages
1.7.1.1 Once the discharge scenarios have
been identified in section 1.5 of the response
plan, the facility owner or operator shall
identify and describe implementation of the
response actions. The facility owner or oper-
ator shall demonstrate accessibility to the
proper response personnel and equipment to
effectively respond to all of the identified
discharge scenarios. The determination and
demonstration of adequate response capa-
bility are presented in appendix B to this
part. In addition, steps to expedite the clean-
up of oil discharges must be discussed. At a
minimum, the following items must be ad-
dressed:
(1) Emergency plans for spill response;
(2) Additional response training;
(3) Additional contracted help;
(4) Access to additional response equip-
ment/experts; and
(5) Ability to implement the plan including
response training and practice drills.
1.7.1.2A recommended form detailing im-
mediate actions follows.
OIL SPILL RESPONSE—IMMEDIATE ACTIONS
OIL SPILL RESPONSE—IMMEDIATE ACTIONS—
Continued
1. Stop the product flow
2. Warn personnel
3. Shut off ignition
sources.
4. Initiate containment ...
5. Notify NRC
6. Notify OSC
7. Notify, as appropriate
Enforce safety and secu-
rity measures.
Motors, electrical circuits,
open flames, etc.
Around the tank and/or in
the water with oil
boom.
1-800-424-8802
Source: FOSS, Oil Spill Response—Emergency Proce-
dures, Revised December 3, 1992.
1.7.2 Disposal Plans
1.7.2.1 Facility owners or operators must
describe how and where the facility intends
to recover, reuse, decontaminate, or dispose
of materials after a discharge has taken
place. The appropriate permits required to
transport or dispose of recovered materials
according to local, State, and Federal re-
quirements must be addressed. Materials
that must be accounted for in the disposal
plan, as appropriate, include:
(1) Recovered product;
(2) Contaminated soil;
(3) Contaminated equipment and mate-
rials, including drums, tank parts, valves,
and shovels;
(4) Personnel protective equipment;
(5) Decontamination solutions;
(6) Adsorbents; and
(7) Spent chemicals.
1.7.2.2 These plans must be prepared in ac-
cordance with Federal (e.g., the Resource
Conservation and Recovery Act [RCRA]),
State, and local regulations, where applica-
ble. A copy of the disposal plans from the fa-
cility's SPCC Plan may be inserted with this
section, including any diagrams in those
plans.
Material
1.
2.
3.
4.
Disposal fa-
cility
Location
RCRA per-
mit/manifest
Act quickly to secure
pumps, close valves,
etc.
1.7.3 Containment and Drainage Planning
A proper plan to contain and control a dis-
charge through drainage may limit the
threat of harm to human health and the en-
vironment. This section shall describe how
to contain and control a discharge through
drainage, including:
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Pt. 112, App. F
40 CFR Ch. I (7-1-13 Edition)
(1) The available volume of containment
(use the information presented in section
1.4.1 of the response plan);
(2) The route of drainage from oil storage
and transfer areas;
(3) The construction materials used in
drainage troughs;
(4) The type and number of valves and sep-
arators used in the drainage system;
(5) Sump pump capacities;
(6) The containment capacity of weirs and
booms that might be used and their location
(see section 1.3.2 of this appendix); and
(7) Other cleanup materials.
In addition, a facility owner or operator
must meet the inspection and monitoring re-
quirements for drainage contained in 40 CFR
part 112, subparts A through C. A copy of the
containment and drainage plans that are re-
quired in 40 CFR part 112, subparts A
through C may be inserted in this section,
including any diagrams in those plans.
NOTE: The general permit for stormwater
drainage may contain additional require-
ments.
1.8 Self-Inspection, Drills/Exercises, and
Response Training
The owner or operator must develop pro-
grams for facility response training and for
drills/exercises according to the require-
ments of 40 CFR 112.21. Logs must be kept for
facility drills/exercises, personnel response
training, and spill prevention meetings.
Much of the recordkeeping information re-
quired by this section is also contained in
the SPCC Plan required by 40 CFR 112.3.
These logs may be included in the facility re-
sponse plan or kept as an annex to the facil-
ity response plan.
1.8.1 Facility Self-Inspection
Under 40 CFR 112.7(e), you must include
the written procedures and records of inspec-
tions for each facility in the SPCC Plan. You
must include the inspection records for each
container, secondary containment, and item
of response equipment at the facility. You
must cross-reference the records of inspec-
tions of each container and secondary con-
tainment required by 40 CFR 112.7(e) in the
facility response plan. The inspection record
of response equipment is a new requirement
in this plan. Facility self-inspection requires
two-steps: (1) a checklist of things to in-
spect; and (2) a method of recording the ac-
tual inspection and its findings. You must
note the date of each inspection. You must
keep facility response plan records for five
years. You must keep SPCC records for three
years.
1.8.1.1. Tank Inspection
The tank inspection checklist presented
below has been included as guidance during
inspections and monitoring. Similar require-
ments exist in 40 CFR part 112, subparts A
through C. Duplicate information from the
SPCC Plan may be photocopied and inserted
in this section. The inspection checklist con-
sists of the following items:
TANK INSPECTION CHECKLIST
1. Check tanks for leaks, specifically looking
for:
A. drip marks;
B. discoloration of tanks;
C. puddles containing spilled or leaked ma-
terial;
D. corrosion;
B. cracks; and
F. localized dead vegetation.
2. Check foundation for:
A. cracks;
B. discoloration;
C. puddles containing spilled or leaked ma-
terial;
D. settling;
B. gaps between tank and foundation; and
F. damage caused by vegetation roots.
3. Check piping for:
A. droplets of stored material;
B. discoloration;
C. corrosion;
D. bowing of pipe between supports;
B. evidence of stored material seepage
from valves or seals; and
F. localized dead vegetation.
TANK/SURFACE IMPOUNDMENT INSPECTION LOG
Inspector
Tank or Sl#
Date
Comments
104
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Environmental Protection Agency
TANK/SURFACE IMPOUNDMENT INSPECTION LOG—Continued
Pt. 112, App. F
Inspector
Tank or Sl#
Date
Comments
1.8.1.2 Response Equipment Inspection
Using the Emergency Response Equipment
List provided in section 1.3.2 of the response
plan, describe each type of response equip-
ment, checking for the following:
Response Equipment Checklist
1. Inventory (item and quantity);
2. Storage location;
3. Accessibility (time to access and re-
spond);
4. Operational status/condition;
5. Actual use/testing (last test date and fre-
quency of testing); and
6. Shelf life (present age, expected replace-
ment date).
Please note any discrepancies between this
list and the available response equipment.
RESPONSE EQUIPMENT INSPECTION LOG
[Use section 1.3.2 of the response plan as a checklist]
Inspector
Date
Comments
105
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Pt. 112, App. F
40 CFR Ch. I (7-1-13 Edition)
RESPONSE EQUIPMENT INSPECTION LOG—Continued
[Use section 1.3.2 of the response plan as a checklist]
Inspector
Date
Comments
1.8.1.3 Secondary Containment Inspection
Inspect the secondary containment (as de-
scribed in sections 1.4.1 and 1.7.2 of the re-
sponse plan), checking the following:
Secondary Containment Checklist
1. Dike or berm system.
A. Level of precipitation in dike/available
capacity;
B. Operational status of drainage valves;
C. Dike or berm permeability;
D. Debris;
E. Erosion;
F. Permeability of the earthen floor of
diked area; and
G. Location/status of pipes, inlets, drain-
age beneath tanks, etc.
2. Secondary containment
A. Cracks;
B. Discoloration;
C. Presence of spilled or leaked material
(standing liquid);
D. Corrosion; and
E. Valve conditions.
3. Retention and drainage ponds
A. Erosion;
B. Available capacity;
C. Presence of spilled or leaked material;
D. Debris; and
E. Stressed vegetation.
The tank inspection checklist presented
below has been included as guidance during
inspections and monitoring. Similar require-
ments exist in 40 CFR part 112, subparts A
through C. Similar requirements exist in 40
CFR 112.7(e). Duplicate information from the
SPCC Plan may be photocopied and inserted
in this section.
1.8.2 Facility Drills/Exercises
(A) CWA section 311(j)(5), as amended by
OPA, requires the response plan to contain a
description of facility drills/exercises. Ac-
cording to 40 CFR 112.21(c), the facility
owner or operator shall develop a program of
facility response drills/exercises, including
evaluation procedures. Following the PREP
guidelines (see appendix B to this part, sec-
tion 13, for availability) would satisfy a fa-
cility's requirements for drills/exercises
under this part. Alternately, under §112.21(c),
a facility owner or operator may develop a
program that is not based on the PREP
guidelines. Such a program is subject to ap-
proval by the Regional Administrator based
on the description of the program provided
in the response plan.
(B) The PREP Guidelines specify that the
facility conduct internal and external drills/
exercises. The internal exercises include:
qualified individual notification drills, spill
management team tabletop exercises, equip-
ment deployment exercises, and unan-
nounced exercises. External exercises in-
clude Area Exercises. Credit for an Area or
Facility-specific Exercise will be given to
the facility for an actual response to a dis-
charge in the area if the plan was utilized for
response to the discharge and the objectives
of the Exercise were met and were properly
evaluated, documented, and self-certified.
(C) Section 112.20(h)(8)(ii) requires the fa-
cility owner or operator to provide a descrip-
tion of the drill/exercise program to be car-
ried out under the response plan. Qualified
Individual Notification Drill and Spill Man-
agement Team Tabletop Drill logs shall be
provided in sections 1.8.2.1 and 1.8.2.2, respec-
tively. These logs may be included in the fa-
cility response plan or kept as an annex to
the facility response plan. See section 1.3.3 of
this appendix for Equipment Deployment
Drill Logs.
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Pt. 112, App. F
1.8.2.1 Qualified Individual Notification Drill
Logs
Qualified Individual Notification Drill Log
Date:
Company:
Qualified Individual(s):
Emergency Scenario:
Changes to be Implemented:
Evaluation:
Changes to be Implemented:
Time Table for Implementation:
1.8.2.2 Spill Management Team Tabletop
Exercise Logs
Spill Management Team Tabletop Exercise
Log
Date:
Company:
Qualified Individual(s):
Emergency Scenario:
Evaluation:
Time Table for Implementation:
1.8.3 Response Training
Section 112.21(a) requires facility owners or
operators to develop programs for facility re-
sponse training. Facility owners or operators
are required by §112.20(h)(8)(iii) to provide a
description of the response training program
to be carried out under the response plan. A
facility's training program can be based on
the USCG's Training Elements for Oil Spill
Response, to the extent applicable to facility
operations, or another response training pro-
gram acceptable to the RA. The training ele-
ments are available from the USCG Office of
Response (G-MOR) at (202) 267-0518 or fax
(202) 267-4085. Personnel response training
logs and discharge prevention meeting logs
shall be included in sections 1.8.3.1 and 1.8.3.2
of the response plan respectively. These logs
may be included in the facility response plan
or kept as an annex to the facility response
plan.
1.8.3.1 Personnel Response Training Logs
PERSONNEL RESPONSE TRAINING LOG
Name
Response training/date and number of
hours
Prevention training/date and number of
hours
1.8.3.2 Discharge Prevention Meetings Logs
DISCHARGE PREVENTION MEETING LOG
Date:
Attendees:
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40 CFR Ch. I (7-1-13 Edition)
Subject/issue identified
Required action
Implementation date
1.9 Diagrams
The facility-specific response plan shall in-
clude the following diagrams. Additional dia-
grams that would aid in the development of
response plan sections may also be included.
(1) The Site Plan Diagram shall, as appro-
priate, include and identify:
(A) the entire facility to scale;
(B) above and below ground bulk oil stor-
age tanks;
(C) the contents and capacities of bulk oil
storage tanks;
(D) the contents and capacity of drum oil
storage areas;
(B) the contents and capacities of surface
impoundments;
(F) process buildings;
(G) transfer areas;
(H) secondary containment systems (loca-
tion and capacity);
(I) structures where hazardous materials
are stored or handled, including mate-
rials stored and capacity of storage;
(J) location of communication and emer-
gency response equipment;
(K) location of electrical equipment which
contains oil; and
(L) for complexes only, the interface(s)
(i.e., valve or component) between the
portion of the facility regulated by EPA
and the portion(s) regulated by other
Agencies. In most cases, this interface is
defined as the last valve inside secondary
containment before piping leaves the sec-
ondary containment area to connect to
the transportation-related portion of the
facility (i.e., the structure used or in-
tended to be used to transfer oil to or
from a vessel or pipeline). In the absence
of secondary containment, this interface
is the valve manifold adjacent to the
tank nearest the transfer structure as de-
scribed above. The interface may be de-
fined differently at a specific facility if
agreed to by the RA and the appropriate
Federal official.
(2) The Site Drainage Plan Diagram shall, as
appropriate, include:
(A) major sanitary and storm sewers, man-
holes, and drains;
(B) weirs and shut-off valves;
(C) surface water receiving streams;
(D) fire fighting water sources;
(B) other utilities;
(F) response personnel ingress and egress;
(G) response equipment transportation
routes; and
(H) direction of discharge flow from dis-
charge points.
(3) The Site Evacuation Plan Diagram shall,
as appropriate, include:
(A) site plan diagram with evacuation
route(s); and
(B) location of evacuation regrouping
areas.
1.10 Security
According to 40 CFR 112.7(g) facilities are
required to maintain a certain level of secu-
rity, as appropriate. In this section, a de-
scription of the facility security shall be pro-
vided and include, as appropriate:
(1) emergency cut-off locations (automatic
or manual valves);
(2) enclosures (e.g., fencing, etc.);
(3) guards and their duties, day and night;
(4) lighting;
(5) valve and pump locks; and
(6) pipeline connection caps.
The SPCC Plan contains similar informa-
tion. Duplicate information may be
photocopied and inserted in this section.
2.0 Response Plan Cover Sheet
A three-page form has been developed to be
completed and submitted to the RA by own-
ers or operators who are required to prepare
and submit a facility-specific response plan.
The cover sheet (Attachment F-l) must ac-
company the response plan to provide the
Agency with basic information concerning
the facility. This section will describe the
Response Plan Cover Sheet and provide in-
structions for its completion.
2.1 General Information
Owner/Operator of Facility: Enter the name
of the owner of the facility (if the owner is
the operator). Enter the operator of the fa-
cility if otherwise. If the owner/operator of
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Environmental Protection Agency
Pt. 112, App. F
the facility is a corporation, enter the name
of the facility's principal corporate execu-
tive. Enter as much of the name as will fit in
each section.
(1) Facility Name: Enter the proper name of
the facility.
(2) Facility Address: Enter the street ad-
dress, city, State, and zip code.
(3) Facility Phone Number: Enter the phone
number of the facility.
(4) Latitude and Longitude: Enter the facil-
ity latitude and longitude in degrees, min-
utes, and seconds.
(5) Dun and Bradstreet Number: Enter the
facility's Dun and Bradstreet number if
available (this information may be obtained
from public library resources).
(6) North American Industrial Classifica-
tion System (NAICS) Code: Enter the facili-
ty's NAICS code as determined by the Office
of Management and Budget (this information
may be obtained from public library re-
sources.)
(7) Largest Oil Storage Tank Capacity: Enter
the capacity in GALLONS of the largest
aboveground oil storage tank at the facility.
(8) Maximum Oil Storage Capacity: Enter the
total maximum capacity in GALLONS of all
aboveground oil storage tanks at the facil-
ity.
(9) Number of Oil Storage Tanks: Enter the
number of all aboveground oil storage tanks
at the facility.
(10) Worst Case Discharge Amount: Using in-
formation from the worksheets in appendix
D, enter the amount of the worst case dis-
charge in GALLONS.
(11) Facility Distance to Navigable Waters:
Mark the appropriate line for the nearest
distance between an opportunity for dis-
charge (i.e., oil storage tank, piping, or
flowline) and a navigable water.
2.2 Applicability of Substantial Harm Criteria
Using the flowchart provided in Attach-
ment C-I to appendix C to this part, mark
the appropriate answer to each question. Ex-
planations of referenced terms can be found
in Appendix C to this part. If a comparable
formula to the ones described in Attachment
C-III to appendix C to this part is used to
calculate the planning distance, documenta-
tion of the reliability and analytical sound-
ness of the formula must be attached to the
response plan cover sheet.
2.3 Certification
Complete this block after all other ques-
tions have been answered.
3.0 Acronyms
ACP: Area Contingency Plan
ASTM: American Society of Testing Mate-
rials
bbls: Barrels
bpd: Barrels per Day
bph: Barrels per Hour
CHRIS: Chemical Hazards Response Informa-
tion System
CWA: Clean Water Act
DOI: Department of Interior
DOC: Department of Commerce
DOT: Department of Transportation
EPA: Environmental Protection Agency
FEMA: Federal Emergency Management
Agency
FR: Federal Register
gal: Gallons
gpm: Gallons per Minute
HAZMAT: Hazardous Materials
LEPC: Local Emergency Planning Com-
mittee
MMS: Minerals Management Service (part of
DOI)
NAICS: North American Industrial Classi-
fication System
NCP: National Oil and Hazardous Substances
Pollution Contingency Plan
NOAA: National Oceanic and Atmospheric
Administration (part of DOC)
NRC: National Response Center
NRT: National Response Team
OPA: Oil Pollution Act of 1990
OSC: On-Scene Coordinator
PREP: National Preparedness for Response
Exercise Program
RA: Regional Administrator
RCRA: Resource Conservation and Recovery
Act
RRC: Regional Response Centers
RRT: Regional Response Team
RSPA: Research and Special Programs Ad-
ministration
SARA: Superfund Amendments and Reau-
thorization Act
SERC: State Emergency Response Commis-
sion
SDWA: Safe Drinking Water Act of 1986
SI: Surface Impoundment
SPCC: Spill Prevention, Control, and Coun-
termeasures
USCG: United States Coast Guard
4.0 References
CONCAWE. 1982. Methodologies for Hazard
Analysis and Risk Assessment in the Petro-
leum Refining and Storage Industry. Pre-
pared by CONCAWE's Risk Assessment Ad-
hoc Group.
U.S. Department of Housing and Urban De-
velopment. 1987. Siting of HUD-Assisted
Projects Near Hazardous Facilities: Accept-
able Separation Distances from Explosive
and Flammable Hazards. Prepared by the Of-
fice of Environment and Energy, Environ-
mental Planning Division, Department of
Housing and Urban Development. Wash-
ington, DC.
U.S. DOT, FEMA and U.S. EPA. Handbook
of Chemical Hazard Analysis Procedures.
U.S. DOT, FEMA and U.S. EPA. Technical
Guidance for Hazards Analysis: Emergency
109
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Pt. 112, App. F
40 CFR Ch. I (7-1-13 Edition)
Planning for Extremely Hazardous Sub-
stances.
The National Response Team. 1987. Haz-
ardous Materials Emergency Planning
Guide. Washington, DC.
The National Response Team. 1990. Oil
Spill Contingency Planning, National Sta-
tus: A Report to the President. Washington,
DC. U.S. Government Printing Office.
Offshore Inspection and Enforcement Divi-
sion. 1988. Minerals Management Service,
Offshore Inspection Program: National Po-
tential Incident of Noncompliance (PINC)
List. Reston, VA.
ATTACHMENTS TO APPENDIX F
Attachment F-l—Response Plan Cover Sheet
This cover sheet will provide EPA with
basic information concerning the facility. It
must accompany a submitted facility re-
sponse plan. Explanations and detailed in-
structions can be found in appendix F. Please
type or write legibly in blue or black ink.
Public reporting burden for the collection of
this information is estimated to vary from 1
hour to 270 hours per response in the first
year, with an average of 5 hours per re-
sponse. This estimate includes time for re-
viewing instructions, searching existing data
sources, gathering the data needed, and com-
pleting and reviewing the collection of infor-
mation. Send comments regarding the bur-
den estimate of this information, including
suggestions for reducing this burden to:
Chief, Information Policy Branch, Mail Code:
PM-2822, U.S. Environmental Protection
Agency, Ariel Rios Building, 1200 Pennsyl-
vania Avenue, NW., Washington, DC 20460;
and to the Office of Information and Regu-
latory Affairs, Office of Management and
Budget, Washington D.C. 20503.
GENERAL INFORMATION
Owner/Operator of Facility:
Facility Name:
North American Industrial Classification
System (NAICS) Code:1
Facility Address (street address or route):
City, State, and U.S. Zip Code:
Facility Phone No.:
Latitude (Degrees: North):
degrees, minutes, seconds
Dun & Bradstreet Number:1
Largest Aboveground Oil Storage Tank Ca-
pacity (Gallons):
Number of Aboveground Oil Storage Tanks:
Longitude (Degrees: West):
degrees, minutes, seconds
Maximum Oil Storage Capacity (Gallons):
Worst Case Oil Discharge Amount (Gallons):
Facility Distance to Navigable Water. Mark
the appropriate line.
0—V4 mile V*-¥i mile %-l mile >1
mile
APPLICABILITY OF SUBSTANTIAL HARM
CRITERIA
Does the facility transfer oil over-water2
to or from vessels and does the facility have
a total oil storage capacity greater than or
equal to 42,000 gallons?
Yes
No
Does the facility have a total oil storage
capacity greater than or equal to 1 million
gallons and, within any storage area, does
the facility lack secondary containment2
that is sufficiently large to contain the ca-
pacity of the largest aboveground oil storage
tank plus sufficient freeboard to allow for
precipitation?
Yes
No
Does the facility have a total oil storage
capacity greater than or equal to 1 million
gallons and is the facility located at a dis-
tance2 (as calculated using the appropriate
formula in appendix C or a comparable for-
mula) such that a discharge from the facility
could cause injury to fish and wildlife and
sensitive environments?3
Yes
No
Does the facility have a total oil storage ca-
pacity greater than or equal to 1 million
gallons and is the facility located at a dis-
tance2 (as calculated using the appropriate
formula in appendix C or a comparable for-
mula) such that a discharge from the facil-
ity would shut down a public drinking
water intake?2
Yes
1 These numbers may be obtained from pub-
lic library resources.
2 Explanations of the above-referenced
terms can be found in appendix C to this
part. If a comparable formula to the ones
contained in Attachment C-III is used to es-
tablish the appropriate distance to fish and
wildlife and sensitive environments or public
drinking water intakes, documentation of
the reliability and analytical soundness of
the formula must be attached to this form.
3 For further description of fish and wildlife
and sensitive environments, see Appendices
I, II, and III to DOC/NOAA's "Guidance for
Facility and Vessel Response Plans: Fish and
Wildlife and Sensitive Environments" (see
appendix E to this part, section 13, for avail-
ability) and the applicable ACP.
110
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Environmental Protection Agency Pt. 112, App. G
No viduals responsible for obtaining informa-
Does the facility have a total oil storage tion, I believe that the submitted informa-
capacity greater than or equal to 1 million tion is true. accurate, and complete.
gallons and has the facility experienced a re- Signature:
portable oil spill 2 in an amount greater than Name (Please type or print).
or equal to 10,000 gallons within the last 5
years? Title:
Yes Date:
No [59 FR 34122, July 1, 1994; 59 FR 49006, Sept.
26, 1994, as amended at 65 FR 40816, June 30,
CERTIFICATION 2000; 65 FR 43840j July 14j 2000; 66 FR 34561j
I certify under penalty of law that I have June 29, 2001; 67 FR 47152, July 17, 2002]
personally examined and am familiar with
the information submitted in this document, APPENDIX G TO PART 112—TIER I
and that based on my inquiry of those indi- QUALIFIED FACILITY SPCC PLAN
111
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Pt. 112, App. G 40 CFR Ch. I (7-1-13 Edition)
Tier I Qualified Facility SPCC Plan
This template constitutes the SPCC Plan for the facility, when completed and signed by the owner or
operator of a facility that meets the applicability criteria in §112.3(g)(1). This template addresses the
requirements of 40 CFR part 112. Maintain a complete copy of the Plan at the facility if the facility is
normally attended at least four hours per day, or for a facility attended fewer than four hours per day, at
the nearest field office. When making operational changes at a facility that are necessary to comply with
the rule requirements, the owner/operator should follow state and local requirements (such as for
permitting, design and construction) and obtain professional assistance, as appropriate.
Facility Description
Facility Name
Facility Address
City State ZIP
County Tel. Number ( ) -
Owner or operator Name
Owner or operator
Address
City State ZIP
County Tel. Number ( ) -
I. Self-Certification Statement (§112.6(a)(1))
The owner or operator of a facility certifies that each of the following is true in order to utilize this
template to comply with the SPCC requirements:
I , certify that the following is accurate:
1. I am familiar with the applicable requirements of 40 CFR part 112;
2. I have visited and examined the facility;
3. This Plan was prepared in accordance with accepted and sound industry practices and
standards;
4. Procedures for required inspections and testing have been established in accordance
with industry inspection and testing standards or recommended practices;
5. I will fully implement the Plan;
6. This facility meets the following qualification criteria (under §112.3(g)(1)):
a. The aggregate aboveground oil storage capacity of the facility is 10,000 U.S.
gallons or less; and
b. The facility has had no single discharge as described in §112.1(b) exceeding
1,000 U.S. gallons and no two discharges as described in §112.1(b) each
exceeding 42 U.S. gallons within any twelve month period in the three years
prior to the SPCC Plan self-certification date, or since becoming subject to 40
CFR part 112 if the facility has been in operation for less than three years (not
including oil discharges as described in §112.1(b) that are the result of natural
disasters, acts of war, or terrorism); and
112
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Environmental Protection Agency Pt. 112, App. G
c. There is no individual oil storage container at the facility with an aboveground
capacity greater than 5,000 U.S. gallons.
7. This Plan does not deviate from any requirement of 40 CFR part 112 as allowed by
§112.7(a)(2) (environmental equivalence) and §112.7(d) (impracticability of secondary
containment) or include an measures pursuant to §112.9(c)(6) for produced water
containers and any associated piping;
8. This Plan and individual(s) responsible for implementing this Plan have the full approval
of management and I have committed the necessary resources to fully implement this
Plan.
I also understand my other obligations relating to the storage of oil at this facility, including, among others:
1. To report any oil discharge to navigable waters or adjoining shorelines to the
appropriate authorities. Notification information is included in this Plan.
2. To review and amend this Plan whenever there is a material change at the facility that
affects the potential for an oil discharge, and at least once every five years. Reviews
and amendments are recorded in an attached log [See Five Year Review Log and
Technical Amendment Log in Attachments 1.1 and 1.2.]
3. Optional use of a contingency plan. A contingency plan:
a. May be used in lieu of secondary containment for qualified oil-filled operational
equipment, in accordance with the requirements under §112.7(k), and;
b. Must be prepared for flowlines and/or intra-facility gathering lines which do not
have secondary containment at an oil production facility, and;
c. Must include an established and documented inspection or monitoring
program; must follow the provisions of 40 CFR part 109; and must include a
written commitment of manpower, equipment and materials to expeditiously
remove any quantity of oil discharged that may be harmful. If applicable, a
copy of the contingency plan and any additional documentation will be attached
to this Plan as Attachment 2.
I certify that I have satisfied the requirement to prepare and implement a Plan under §112.3 and all of the
requirements under §112.6(a). I certify that the information contained in this Plan is true.
Signature Title:
Name Date: / /20
II. Record of Plan Review and Amendments
Five Year Review (§112.5(b)):
Complete a review and evaluation of this SPCC Plan at least once every five years. As a result of the
review, amend this Plan within six months to include more effective prevention and control measures for
the facility, if applicable. Implement any SPCC Plan amendment as soon as possible, but no later than six
months following Plan amendment. Document completion of the review and evaluation, and complete the
Five Year Review Log in Attachment 1.1. If the facility no longer meets Tier I qualified facility eligibility, the
owner or operator must revise the Plan to meet Tier II qualified facility requirements, or complete a full PE
certified Plan.
Table G-1 Technical Amendments (§§112.5(a), (c) and 112.6(a)(2))
This SPCC Plan will be amended when there is a change in the facility design, construction,
operation, or maintenance that materially affects the potential for a discharge to navigable waters
or adjoining shorelines. Examples include adding or removing containers, reconstruction,
replacement, or installation of piping systems, changes to secondary containment systems,
changes in product stored at this facility, or revisions to standard operating procedures.
D
Any technical amendments to this Plan will be re-certified in accordance with Section I of this
Plan template. [§112.6(a)(2)][See Technical Amendment Log in Attachment 1.2]
113
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Pt. 112, App. G
40 CFR Ch. I (7-1-13 Edition)
III. Plan Requirements
1. Oil Storage Containers (§112.7(aX3)(i)):
Table G-2 Oil Storage Containers and Capacities
This table includes a complete list of all oil storage containers (aboveground containers3 and Q
completely buried tanks") with capacity of 55 U.S. gallons or more, unless otherwise exempt
from the rule. For mobile/portable containers, an estimate number of containers, types of oil, and
anticipated capacities are provided.
Oil Storage Container (indicate whether
aboveground (A) or completely buried (B))
Type of Oil
Shell Capacity
(gallons)
_ gallons
_ gallons
_ gallons
Total Aboveground Storage
Capacity °
Total Completely Buried
Storage Capacity
Facility Total Oil Storage
Capacity
a Aboveground storage containers that must be included when calculating total facility oil storage capacity include:
tanks and mobile or portable containers; oil-filled operational equipment (e.g. transformers); other oil-filled equipment,
such as flow-through process equipment. Exempt containers that are not included in the capacity calculation include:
any container with a storage capacity of less than 55 gallons of oil; containers used exclusively for wastewater
treatment; permanently closed containers; motive power containers; hot-mix asphalt containers; heating oil containers
used solely at a single-family residence; and pesticide application equipment or related mix containers.
6 Although the criteria to determine eligibility for qualified facilities focuses on the aboveground oil storage containers
at the facility, the completely buried tanks at a qualified facility are still subject to the rule requirements and must be
addressed in the template; however, they are not counted toward the qualified facility applicability threshold.
c Counts toward qualified facility applicability threshold.
114
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Environmental Protection Agency
Pt. 112, App. G
2. Secondary Containment and Oil Spill Control (§§112.6(a)(3)(i) and (ii), 112.7(c) and 112.9(c)(2)):
Table G-3 Secondary Containment and Oil Spill Control
Appropriate secondary containment and/or diversionary structures or equipment is provided for
all oil handling containers, equipment, and transfer areas to prevent a discharge to navigable
waters or adjoining shorelines. The entire secondary containment system, including walls and
floor, is capable of containing oil and is constructed so that any discharge from a primary
containment system, such as a tank or pipe, will not escape the containment system before
cleanup occurs.
Use one of the following methods of secondary containment or its equivalent: (1) Dikes, berms, or retaining waits
sufficiently impervious to contain oil; (2) Curbing; (3) Culverting, gutters, or other drainage systems; (4) Weirs, booms,
or other barriers; (5) Spill diversion ponds; (6) Retention ponds; or (7) Sorbent materials.
115
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Table G-4 below identifies the tanks and containers at the facility with the potential for an oil discharge; the mode of failure; the flow direction and
potential quantity of the discharge; and the secondary containment method and containment capacity that is provided.
Table G-4 Containers with Potential for an Oil Discharge
Area
Type of failure (discharge
scenario)
Potential
discharge
volume
(gallons)
Direction of
flow for
unconiained
discharge
Secondary
containment method3
Secondary
containment
capacity
(gallons)
Bulk Storage Containers and Mobile/Portable Containers0
Oil-filled Operational Equipment (e.g., hydraulic equipment, transformers)0
Piping, Valves, etc.
Product Transfer Areas (location where oil is loaded to or from a container, pipe or other piece of equipment.)
Other Oil-Handling Areas or Oil-Filled Equipment (e.g. flow-through process vessels at an oil production facility)
JO
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Environmental Protection Agency Pt. 112, App. G
3. Inspections, Testing, Recordkeeping and Personnel Training (§§112.7(e) and (f),
112.8(c)(6) and (d)(4), 112.9(c)(3), 112.12(cX6) and (d)(4)):
Table G-5 Inspections, Testing, Recordkeeping and Personnel Training
An inspection and/or testing program is implemented for all aboveground bulk storage
containers and piping at this facility. [§§112.8(c)(6) and (d)(4), 112.9(c)(3), 112.12(c)(6) and
D
The following is a description of the inspection and/or testing program (e.g. reference to industry
standard utilized, scope, frequency, method of inspection or test, and person conducting the
inspection) for all aboveground bulk storage containers and piping at this facility:
Inspections, tests, and records are conducted in accordance with written procedures developed
for the facility. Records of inspections and tests kept under usual and customary business
practices will suffice for purposes of this paragraph. [§112.7(e)]
D
A record of the inspections and tests are kept at the facility or with the SPCC Plan for a period
of three years. [§112,7(e)][See Inspection Log and Schedule in Attachment 3.1]
Inspections and tests are signed by the appropriate supervisor or inspector. [§112.7(e)]
n
Personnel, training, and discharge prevention procedures [§112.7(f)]
Oil-handling personnel are trained in the operation and maintenance of equipment to prevent
discharges; discharge procedure protocols; applicable pollution control laws, rules, and
regulations; general facility operations; and, the contents of the facility SPCC Plan. [§ 112.7(1)]
A person who reports to facility management is designated and accountable for discharge
prevention. [§112.7(f)]
Name/Title:
Discharge prevention briefings are conducted for oil-handling personnel annually to assure
adequate understanding of the SPCC Plan for that facility. Such briefings highlight and describe
past reportable discharges or failures, malfunctioning components, and any recently developed
precautionary measures. [§112.7(f)]
[See Oil-handling Personnel Training and Briefing Log in Attachment 3.4]
D
117
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Pt. 112, App. G 40 CFR Ch. I (7-1-13 Edition)
4. Security (excluding oil production facilities) §112.7(g):
Table G-6 Implementation and Description of Security Measures
Security measures are implemented at this facility to prevent unauthorized access to oil
handling, processing, and storage area.
The following is a description of how you secure and control access to the oil handling,
processing and storage areas; secure master flow and drain valves; prevent unauthorized
access to starter controls on oil pumps; secure out-of-service and loading/unloading
connections of oil pipelines; address the appropriateness of security lighting to both prevent acts
of vandalism and assist in the discovery of oil discharges:
5, Emergency Procedures and Notifications (§112.7(a)(3)(iv) and 112.7(a)(5)):
Table G-7 Description of Emergency Procedures and Notifications
The following is a description of the immediate actions to be taken by facility personnel in the
event of a discharge to navigable waters or adjoining shorelines [§112.7(a)(3)(iv) and
112.7(a)(5ff.
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Environmental Protection Agency
6. Contact List (§112.7{a)(3)(vi)):
Pt. 112, App. G
Table G-8 Contact List
Contact Organization / Person
National Response Center (NRC)
Cleanup Contractor(s)
Telephone Number
1-800-424-8802
Key Facility Personnel
Designated Person Accountable for Discharge
Prevention:
State Oil Pollution Control Agencies
Other State, Federal, and Local Agencies
Local Fire Department
Local Police Department
Hospital
Other Contact References (e.g., downstream water
intakes or neighboring facilities)
Office:
Emergency:
Office:
Emergency:
Office:
Emergency:
Office:
Emergency:
119
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Pt. 112, App. G 40 CFR Ch. I (7-1-13 Edition)
7. NRC Notification Procedure (§112.7(a)(4) and (aX5)):
Table G-9 NRC Notification Procedure
In the event of a discharge of oil to navigable waters or adjoining shorelines, the following
information identified in Attachment 4 will be provided to the National Response Center
immediately following identification of a discharge to navigable waters or adjoining shorelines
[See Discharge Notification Form in Attachment 4]: [§112.7(a)(4)]
The exact address or location and phone • Description of all affected media;
number of the facility; . Cause of the discharge;
Date and time of the discharge; • Any damages or injuries caused by the
Type of material discharged; discharge;
Estimate of the total quantity discharged; • Actions being used to stop, remove, and
Estimate of the quantity discharged to mitigate the effects of the discharge;
navigable waters; • Whether an evacuation may be needed; and
Source of the discharge; • Names of individuals and/or organizations
who have also been contacted.
8. SPCC Spill Reporting Requirements (Report within 60 days) (§112.4):
Submit information to the EPA Regional Administrator (RA) and the appropriate agency or agencies in
charge of oil pollution control activities in the State in which the facility is located within 60 days from one
of the following discharge events:
• A single discharge of more than 1,000 U.S. gallons of oil to navigable waters or adjoining
shorelines or
• Two discharges to navigable waters or adjoining shorelines each more than 42 U.S. gallons
of oil occurring within any twelve month period
You must submit the following information to the RA:
(1) Name of the facility;
(2) Your name;
(3) Location of the facility;
(4) Maximum storage or handling capacity of the facility and normal daily throughput;
(5) Corrective action and countermeasures you have taken, including a description of
equipment repairs and replacements;
(6) An adequate description of the facility, including maps, flow diagrams, and
topographical maps, as necessary;
(7) The cause of the reportable discharge, including a failure analysis of the system or
subsystem in which the failure occurred; and
(8) Additional preventive measures you have taken or contemplated to minimize the
possibility of recurrence
(9) Such other information as the Regional Administrator may reasonably require
pertinent to the Plan or discharge
NOTE: Complete one of the following sections (A, B or C)
as appropriate for the facility type.
120
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Environmental Protection Agency Pt. 112, App. G
A. Onshore Facilities (excluding production) (§§112.8(b) through (d), 112.12(b) through
(d)):
The owner or operator must meet the general rule requirements as well as requirements under this
section. Note that not all provisions may be applicable to all owners/operators. For example, a facility may
not maintain completely buried metallic storage tanks installed after January 10,1974, and thus would not
have to abide by requirements in §§112.8(c)(4) and 112.12(c)(4), listed beiow. in cases where a provision
is not applicable, write "N/A".
Table G-10 General Rule Requirements for Onshore Facilities
Drainage from diked storage areas is restrained by valves to prevent a discharge into the ,-,
drainage system or facility effluent treatment system, except where facility systems are
designed to control such discharge. Diked areas may be emptied by pumps or ejectors that
must be manually activated after inspecting the condition of the accumulation to ensure no oil
will be discharged. [§§112.8(b)(1) and 112.12(b)(1)]
Valves of manual, open-and-closed design are used for the drainage of diked areas.
[§§112.8(b)(2) and 112.12(b)(2)J
D
The containers at the facility are compatible with materials stored and conditions of storage
such as pressure and temperature. [§§ 112.8(c)(1) and 112.12(c)(1)]
D
Secondary containment for the bulk storage containers (including mobile/portable oil storage
containers) holds the capacity of the largest container plus additional capacity to contain
precipitation. Mobile or portable oil storage containers are positioned to prevent a discharge as
described in §112.1(b). [§112.6(a)(3)(ii)]
If uncontaminated rainwater from diked areas drains into a storm drain or open watercourse the
following procedures will be implemented at the facility: [§§112.8(c)(3) and 112.12(c)(3)]
• Bypass valve is normally sealed closed
• Retained rainwater is inspected to ensure that its presence will not cause a discharge to
navigable waters or adjoining shorelines
• Bypass valve is opened and resealed under responsible supervision
• Adequate records of drainage are kept [See Dike Drainage Log in Attachment 3.3]
D
D
D
n
For completely buried metallic tanks installed on or after January 10,1974 at this facility
[§§ 112.8(c)(4) and 112.12(c)(4)f.
• Tanks have corrosion protection with coatings or cathodic protection compatible with
local soil conditions.
• Regular leak testing is conducted.
D
D
For partially buried or bunkered metallic tanks [§112.8(c)(5) and §112.12(c)(5)f.
• Tanks have corrosion protection with coatings or cathodic protection compatible with
local soil conditions.
D
Each aboveground bulk container is tested or inspected for integrity on a regular schedule and
whenever material repairs are made. Scope and frequency of the inspections and inspector
qualifications are in accordance with industry standards. Container supports and foundations
are regularly inspected.
[See Inspection Log and Schedule and Bulk Storage Container Inspection Schedule in
Attachments 3.1 and 3.2] [§112.8(c)<6) and §112.12(c)(6)(i)]
Outsides of bulk storage containers are frequently inspected for signs of deterioration,
discharges, or accumulation of oil inside diked areas. [See Inspection Log and Schedule in
Attachment 3.1] [§§112.8(c)(6) and 112.12(c)(6)]
D
For bulk storage containers that are subject to 21 CFR part 110 which are shop-fabricated,
constructed of austenitic stainless steel, elevated and have no external insulation, formal visual
inspection is conducted on a regular schedule. Appropriate qualifications for personnel
performing tests and inspections are documented. [See Inspection Log and Schedule and Bulk
121
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Pt. 112, App. G 40 CFR Ch. I (7-1-13 Edition)
Table G-10 General Rule Requirements for Onshore Facilities
Storage Container Inspection Schedule in Attachments 3.1 and 3.2] [§112.12(c)(6)(ii)]
Each container is provided with a system or documented procedure to prevent overfills for the
container. Describe:
Liquid level sensing devices are regularly tested to ensure proper operation [See Inspection Log
and Schedule in Attachment 3.1]. [§112.6(a)(3)(iii)]
D
Visible discharges which result in a loss of oil from the container, including but not limited to ,-,
seams, gaskets, piping, pumps, valves, rivets, and bolts are promptly corrected and oil in diked
areas is promptly removed. [§§112.8(c)(10) and 112.12(c)(10)]
Aboveground valves, piping, and appurtenances such as flange joints, expansion joints, valve ,-,
glands and bodies, catch pans, pipeline supports, locking of valves, and metal surfaces are
inspected regularly. [See Inspection Log and Schedule in Attachment 3.1] [§§112.8(d)(4) and
112.12(d)(4)]
Integrity and leak testing are conducted on buried piping at the time of installation, modification, ,-,
construction, relocation, or replacement. [See Inspection Log and Schedule in Attachment 3.1]
[§§112.8(d)(4) and 112.12(d)(4)]
122
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Environmental Protection Agency Pt. 112, App. G
B. Onshore Oil Production Facilities (excluding drilling and workover facilities)
(§112.9(b),(c),and(d)):
The owner or operator must meet the general rule requirements as well as the requirements under this
section. Note that not all provisions may be applicable to all owners/operators. In cases where a provision
is not applicable, write "N/A".
Table G-11 General Rule Requirements for Onshore Oil Production Facilities
At tank batteries, separation and treating areas, drainage is closed and sealed except when
draining uncontaminated rainwater. Accumulated oil on the rainwater is returned to storage or
disposed of in accordance with legally approved methods. [§112.9(b)(1)]
Q
Prior to drainage, diked areas are inspected and [§112.9(b)(1)]:
• Retained rainwater is inspected to ensure that its presence will not cause a discharge to
navigable waters
• Bypass valve is opened and resealed under responsible supervision
• Adequate records of drainage are kept [See Dike Drainage Log in Attachment 3.3]
D
a
n
Field drainage systems and oil traps, sumps, or skimmers are inspected at regularly scheduled ,-,
intervals for oil, and accumulations of oil are promptly removed [See Inspection Log and
Schedule in Attachment 3.1] [§112.9(b)(2)J
The containers used at this facility are compatible with materials stored and conditions of
storage. [§112.9(c)(1)J
All tank battery, separation, and treating facility installations (except for flow-through process
vessels) are constructed with a capacity to hold the largest single container plus additional
capacity to contain rainfall. Drainage from undiked areas is safely confined in a catchment basin
or holding pond. [§112.9(c)(2)]
D
Except for flow-through process vessels, containers that are on or above the surface of the
ground, including foundations and supports, are visually inspected for deterioration and
maintenance needs on a regular schedule. [See Inspection Log and Schedule in Attachment
n
New and old tank batteries at this facility are engineered/updated in accordance with good
engineering practices to prevent discharges including at least one of the following: (i) adequate
container capacity to prevent overfill if regular pumping/gauging is delayed; (ii) overflow
equalizing lines between containers so that a full container can overflow to an adjacent
container; (iii) vacuum protection to prevent container collapse; or (iv) high level sensors to
generate and transmit an alarm to the computer where the facility is subject to a computer
production control system. [§112.9(c)(4)]
D
Flow-through process vessels and associated components are:
• Are constructed with a capacity to hold the largest single container plus additional
capacity to contain rainfall. Drainage from undiked areas is safely confined in a
catchment basin or holding pond; [§112.9(c)(2)]and
• That are on or above the surface of the ground, including foundations and supports, are
visually inspected for deterioration and maintenance needs on a regular schedule. [See
Inspection Log and Schedule in Attachment 3.1] [§112.9(c)(3)]
Or
• Visually inspected and/or tested periodically and on a regular schedule for leaks,
corrosion, or other conditions that could lead to a discharge to navigable waters; and
• Corrective action or repairs are applied to flow-through process vessels and any
associated components as indicated by regularly scheduled visual inspections, tests, or
evidence of an oil discharge; and
• Any accumulations of oil discharges associated with flow-through process vessels are
promptly removed; and
D
n
D
n
123
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Pt. 112, App. G 40 CFR Ch. I (7-1-13 Edition)
Table G-11 General Rule Requirements for Onshore Oil Production Facilities
Flow-through process vessels are provided with a secondary means of containment for
the entire capacity of the largest single container and sufficient freeboard to contain
precipitation within six months of a discharge from flow-through process vessels of more
than 1,000 U.S. gallons of oil in a single discharge as described in §112.1(b), or a
discharge more than 42 U.S. gallons of oil in each of two discharges as described in
§112.1(b) within any twelve month period. [§112.9(c)(5)J
(Leave blank until such time that this provision is applicable.)
All aboveground valves and piping associated with transfer operations are inspected periodically
and upon a regular schedule. The general condition of flange joints, valve glands and bodies,
drip pans, pipe supports, pumping well polish rod stuffing boxes, bleeder and gauge valves, and
other such items are included in the inspection. [See Inspection Log and Schedule in
Attachment 3.1] [§112.9(d)(1>]
D
D
An oil spill contingency plan and written commitment of resources are provided for flowlines and
infra-facility gathering lines [See Oil Spill Contingency Plan and Checklist in Attachment 2 and
Inspection Log and Schedule in Attachment 3.1] [§112.9(d)(3)J
or
Appropriate secondary containment and/or diversionary structures or equipment is provided for '-'
flowlines and intra-facility gathering lines to prevent a discharge to navigable waters or adjoining
shorelines. The entire secondary containment system, including walls and floor, is capable of
containing oil and is constructed so that any discharge from the pipe, will not escape the
containment system before cleanup occurs.
A flowline/intra-facility gathering line maintenance program to prevent discharges from each .-,
flowline has been established at this facility. The maintenance program addresses each of the
following:
• Flowlines and intra-facility gathering lines and associated valves and equipment are
compatible with the type of production fluids, their potential corrosivity, volume, and
pressure, and other conditions expected in the operational environment;
Flowlines, intra-facility gathering lines and associated appurtenances are visually
inspected and/or tested on a periodic and regular schedule for leaks, oil discharges,
corrosion, or other conditions that could lead to a discharge as described in §112.1(b).
The frequency and type of testing allows for the implementation of a contingency plan
as described under part 109 of this chapter.
Corrective action and repairs to any flowlines and intra-facility gathering lines and
associated appurtenances as indicated by regularly scheduled visual inspections, tests,
or evidence of a discharge.
Accumulations of oil discharges associated with flowlines, intra-facility gathering lines,
and associated appurtenances are promptly removed. [§112.9(d)(4)]
n
The following is a description of the flowline/intra-facility gathering line maintenance program
implemented at this facility:
124
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Environmental Protection Agency Pt. 112, App. G
C. Onshore Oil Drilling and Workover Facilities (§112.10(b), (c) and (d)):
The owner or operator must meet the general rule requirements as well as the requirements under this
section.
Table G-12 General Rule Requirements for Onshore Oil Drilling and Workover Facilities
Mobile drilling or worker equipment is positioned or located to prevent discharge as described in
D
Catchment basins or diversion structures are provided to intercept and contain discharges of
fuel, crude oil, or oily drilling fluids. [§112.10(c)]
D
A blowout prevention (BOP) assembly and well control system was installed before drilling
below any casing string or during workover operations. [§112.10(d)]
D
The BOP assembly and well control system is capable of controlling any well-head pressure
that may be encountered while the BOP assembly and well control system are on the well.
[§112.10(0)]
n
ATTACHMENT 1 - Five Year Review and Technical Amendment Logs
ATTACHMENT 1.1 - Five Year Review Log
I have completed a review and evaluation of the SPCC Plan for this facility, and will/will not amend this
Plan as a result.
Table G-13 Review and Evaluation of SPCC Plan for Facility
Review Date
Plan Amendment
Will Amend
D
D
n
D
n
n
n
n
Will Not Amend
D
D
D
D
D
D
n
n
Name and signature of person authorized to review
this Plan
125
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Pt. 112, App. G
40 CFR Ch. I (7-1-13 Edition)
ATTACHMENT 1.2 - Technical Amendment Log
Any technical amendments to this Plan will be re-certified in accordance with Section I ot this Plan
template.
Table G-14 Description and Certification of Technical Amendments
Review
Date
Description of Technical Amendment
Name and signature of person certifying this
technical amendment
126
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Environmental Protection Agency Pt. 112, App. G
ATTACHMENT 2 - Oil Spill Contingency Plan and Checklist
An oil spill contingency plan and written commitment of resources is required for:
• Flow/lines and infra-facility gathering lines at oil production facilities and
• Qualified oil-filled operational equipment which has no secondary containment.
An oil spill contingency plan meeting the provisions of 40 CFR part 109, as described below, and a
written commitment of manpower, equipment and materials required to expeditiously control and
remove any quantity of oil discharged that may be harmful is attached to this Plan.
Complete the checklist below to verify that the necessary operations outlined in 40 CFR part 109 - Criteria
for State, Local and Regional Oil Removal Contingency Plans - have been included.
Table G-15 Checklist of Development and Implementation Criteria for State, Local and Regional Oil
Removal Contingency Plans (§109.5)a
(a) Definition of the authorities, responsibilities and duties of all persons, organizations or agencies
which are to be involved in planning or directing oil removal operations.
(b) Establishment of notification procedures for the purpose of early detection and timely notification of an
oil discharge including:
(1) The identification of critical water use areas to facilitate the reporting of and response to oil
discharges.
(2) A current list of names, telephone numbers and addresses of the responsible persons (with
alternates) and organizations to be notified when an oil discharge is discovered.
(3) Provisions for access to a reliable communications system for timely notification of an oil
discharge, and the capability of interconnection with the communications systems established
under related oil removal contingency plans, particularly State and National plans (e.g., NCP).
(4) An established, prearranged procedure for requesting assistance during a major disaster or
when the situation exceeds the response capability of the State, local or regional authority.
(c) Provisions to assure that full resource capability is known and can be committed during an oil discharge
situation including:
(1) The identification and inventory of applicable equipment, materials and supplies which are
available locally and regionally.
(2) An estimate of the equipment, materials and supplies which would be required to remove the
maximum oil discharge to be anticipated.
(3) Development of agreements and arrangements in advance of an oil discharge for the
acquisition of equipment, materials and supplies to be used in responding to such a
discharge.
(d) Provisions for well defined and specific actions to be taken after discovery and notification of an oil
discharge including:
(1) Specification of an oil discharge response operating team consisting of trained, prepared and
available operating personnel.
(2) Predesignation of a properly qualified oil discharge response coordinator who is charged with
the responsibility and delegated commensurate authority for directing and coordinating
response operations and who knows how to request assistance from Federal authorities
operating under existing national and regional contingency plans.
127
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Pt. 112, App. G 40 CFR Ch. I (7-1-13 Edition)
Table G-15 Checklist of Development and Implementation Criteria for State, Local and Regional Oil
Removal Contingency Plans (§109.5)"
(3) A preplanned location for an oil discharge response operations center and a reliable
communications system for directing the coordinated overall response operations.
(4) Provisions for varying degrees of response effort depending on the severity of the oil
discharge.
(5) Specification of the order of priority in which the various water uses are to be protected where
more than one water use may be adversely affected as a result of an oil discharge and where
response operations may not be adequate to protect all uses.
(6) Specific and well defined procedures to facilitate recovery of damages and enforcement
measures as provided for by State and local statutes and ordinances.
n
The contingency plan must be consistent with all applicable state and local plans, Area Contingency
Plans, and the National Contingency Plan (NCP).
128
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ATTACHMENT 3 - Inspections, Dike Drainage and Personnel Training Logs
ATTACHMENT 3.1 - Inspection Log and Schedule
Table G-16 Inspection Log and Schedule
This log is intended to document compliance with §§1 1 2.6(a)(3)(iii), 1 1 2.8(c}(6), 1 1 2.8(d)(4), 1 1 2.9(b)(2), 1 1 2.9(c)(3), 1 1 2.9(d)(1 ),
112.9(d)(4), 112.12.(c)(6), and 112.12(d)(4), as applicable.
Date of
Inspection
Container /
Piping /
Equipment
Describe Scope
(or cite Industry
Standard)
Observations
Name/ Signature of Inspector
Records
maintained
separately3
a
D
a
a
o
<
o
(D
o
I
6
(D
O
JO
•a
p
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Pt. 112, App. G
40 CFR Ch. I (7-1-13 Edition)
ATTACHMENT 3.2 - Bulk Storage Container Inspection Schedule - onshore facilities
(excluding production):
To comply with integrity inspection requirement for bulk storage containers, inspect/test each shop-built
aboveground bulk storage container on a regular schedule in accordance with a recognized container
inspection standard based on the minimum requirements in the following table.
Table G-17 Bulk Storage Container Inspection Schedule
Container Size and Design Specification
Portable containers (including drums, totes, and
intermodal bulk containers (IBC))
55 to 1 , 1 00 gallons with sized secondary containment
1,101 to 5,000 gallons with sized secondary
containment and a means of leak detection"
1,101 to 5,000 gallons with sized secondary
containment and no method of leak detection3
Inspection requirement
Visually inspect monthly for signs of
deterioration, discharges or accumulation of
oil inside diked areas
Visually inspect monthly for signs of
deterioration, discharges or accumulation of
oil inside diked areas plus any annual
inspection elements per industry inspection
standards
Visually inspect monthly for signs of
deterioration, discharges or accumulation of
oil inside diked areas, plus any annual
inspection elements and other specific
integrity tests that may be required per
industry inspection standards
1 Examples of leak detection include, but are not limited to, double-walled tanks and elevated containers where a leak can
be visually identified.
130
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ATTACHMENT 3.3 - Dike Drainage Log
CO
Table G-18 Dike Drainage Log
Date
Bypass
valve
sealed
closed
D
D
D
D
D
D
D
D
Rainwater
inspected to
be sure no oil
(or sheen) is
visible
D
D
D
D
a
a
D
a
Open
bypass
valve and
reseal it
following
drainage
D
D
D
D
n
n
D
D
Drainage
activity
supervised
D
n
D
n
n
D
D
a
Observations
Signature of Inspector
<
o
(D
o
I
6
(D
O
JO
•a
p
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Pt. 112, App. G 40 CFR Ch. I (7-1-13 Edition)
ATTACHMENT 3.4 - Oil-handling Personnel Training and Briefing Log
Table G-19 Oil-Handling Personnel Training and Briefing Log
Date
Description / Scope
Attendees
132
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Environmental Protection Agency
§113.2
ATTACHMENT 4 - Discharge Notification Form
In the event of a discharge of oil to navigable waters or adjoining shorelines, the following information will
be provided to the National Response Center [also see the notification information provided in Section 7
of the Plan]:
Table G-20 Information provided to the National Response Center in the Event of a Discharge
Discharge/Discovery Date
Facility Name
Facility Location (Address/Lat-
Long/Section Township Range)
Name of reporting individual
Type of material discharged
Source of the discharge
Actions taken
Damage or injuries
Organizations and individuals
contacted
1 Time
Telephone #
Estimated total
quantity discharged
Media affected
Gallons/Barrels
DSoil
D Water (specify)
D Other (specify)
D No D Yes
(specify)
Evacuation needed?
D National Response Center 800-424-8802 Tirr
D No D Yes (specify)
e
D Cleanup contractor (Specify) Time
D Facility personnel (Specify) Time
D State Agency (Specify) Time
D Other (Specify) Time
[74 FR 58811, Nov. 13, 2009]
PART 113—LIABILITY LIMITS FOR
SMALL ONSHORE STORAGE FA-
CILITIES
Subpart A—Oil Storage Facilities
Sec.
113.1
113.2
113.3
113.4
Purpose.
Applicability.
Definitions.
Size classes and associated liability
limits for fixed onshore oil storage facili-
ties, 1,000 barrels or less capacity.
113.5 Exclusions.
113.6 Effect on other laws.
AUTHORITY: Sec. 311(f)(2), 86 Stat. 867 (33
U.S.C. 1251 (1972)).
SOURCE: 38 FR 25440, Sept. 13, 1973, unless
otherwise noted.
Subpart A—Oil Storage Facilities
§113.1 Purpose.
This subpart establishes size classi-
fications and associated liability limits
for small onshore oil storage facilities
with fixed capacity of 1,000 barrels or
less.
§113.2 Applicability.
This subpart applies to all onshore
oil storage facilities with fixed capac-
ity of 1,000 barrels or less. When a dis-
charge to the waters of the United
States occurs from such facilities and
when removal of said discharge is per-
formed by the United States Govern-
ment pursuant to the provisions of sub-
section 311(c)(l) of the Act, the liability
133
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Appendix C: Summary of Revised Rule Provisions
The chart below summarizes rule amendments (beginning in 2002) to the SPCC regulation that was first
promulgated in December 1973 and effective January 10, 1974. Each year that a rule citation was revised is
marked with an "X". For specific details on amendments, please refer to preamble text and relevant sections of
this guidance. In the table:
• 2002 refers to the amendments published at 67 FR 47042, July 17, 2002
• 2006 refers to the amendments published at 71 FR 77266, December 26, 2006
• 2008 refers to the amendments published at 73 FR 74236, December 5, 2008
• 2009 refers to the amendments published at 74 FR 58784, November 13, 2009
• 2011 EPA exempted milk and milk product containers-published at 76 FR 21652, April 18, 2011
SPCC GUIDANCE FOR REGIONAL INSPECTORS
November 15, 2013
-------
Rule Provision
Preamble
Clarifications
§112.1(b)
§112.1(d)(2)(i),
§112.1(d)(2)(ii)
§112.1(d)(2)(i),
§112.1(d)(4)
§112.1(d)(2)(i),
§112.1(d)(ll)
§112.1(d)(2)(ii),
§112.1(d)(7)
Description
Clarified that the definition of "mobile refueler" includes nurse tanks
Clarified definition of "permanently closed"
Clarified §112.8 versus §112.9 applicability
Clarified drilling and workover activities are not subject to §112.9
Clarified applicability of the rule to wind turbines
Clarified how manmade structures can affect rule applicability and how they can be considered to comply
with rule requirements
Clarified applicability of loading/unloading requirements to transfers to/from exempt USTs
Clarified jurisdiction between EPA and the Department of Transportation (DOT)
Amended geographic scope of the rule
Amended threshold requirements
Exempted completely buried underground storage tanks (USTs) in 2002.
Exempted underground emergency diesel generator tanks at nuclear power stations exempted in 2008.
Amended exemption for underground emergency diesel generator tanks at nuclear power stations in 2009.
Exempted certain intra-facility gathering lines
Exempted motive power containers
2002
X
X
X
2006
X
2008
X
X
X
X
X
X
X
X
X
2009
X
X
SPCC GUIDANCE FOR REGIONAL INSPECTORS
C-l
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Rule Provision
§112.1(d)(2)(ii),
§112.1(d)(8)
§112.1(d)(2)(ii),
§112.1(d)(9)
§112.1(d)(2)(ii),
§112.1(d)(10)
§112.1(d)(2)(ii),
§112.1(d)(12)
§112.1(d)(5)
§112.1(d)(6)
§112.1(f)
Description
Exempted hot-mix asphalt (HMA)
Exempted residential heating oil containers
Exempted pesticide application equipment and related mix containers
Exempted milk and milk product container and associated piping and appurtenances
Established minimum container size
Exempted facilities or parts thereof used exclusively for wastewater treatment
Established RA authority to determine applicability
2002
2006
2008
X
X
X
2009
2011
X
X
X
SPCC GUIDANCE FOR REGIONAL INSPECTORS
C-2
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Rule Provision
$112.2
Description
Defined:
Alteration
Breakout tank
Bulk storage container
Bunkered tank
Completely buried tank
Contiguous zone
Facility
Partially buried tank
Permanently closed
Production facility
Repair
SPCC Plan
Storage capacity
Wetlands
Defined:
Farm
Mobile refueler
Motive power container
Oil-filled operational equipment
Defined:
Loading/unloading rack
Produced water container
Amended definition of "facility"
2002
X
2006
X
2008
X
X
2009
SPCC GUIDANCE FOR REGIONAL INSPECTORS
C-3
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Rule Provision
§112.3(b)(2)
§112.3(d)
§112.3(e)(l)
§H2.3(g)(l)
§H2.3(g)(2)
§112.4
§112.5(b),
§112.5(c)
§112.6(a)
§112.6(b)
§112.7
§112.7(a)
§112.7(a)(2)
§112.7(a)(3)
Description
Amended definition of "production facility"
Amended timeframe for new production facilities to prepare and implement a plan
Amended Professional Engineer (PE) certification requirements
Amended plan location requirements
Established Tier 1 qualified facilities eligibility criteria
Established Tier II qualified facilities eligibility criteria
Amended reportable discharge notification to EPA Regional Administrator (RA) requirements for SPCC
facilities
Amended period of review of SPCC Plan and documentation requirements
Established Tier 1 qualified facility requirements. Amended requirements in 2009.
Established Tier II qualified facility requirements. Amended requirements in 2008.
Established alternative SPCC Plan formats
Eliminated spill history reporting requirements
Established environmental equivalence
Established facility diagram requirements in 2002. Amended requirements in 2008.
2002
X
X
X
X
X
X
X
X
2006
X
X
X
2008
X
X
X
X
X
X
X
2009
X
X
X
SPCC GUIDANCE FOR REGIONAL INSPECTORS
C-4
-------
Rule Provision
§112.7(a)(3),
§112.7(a)(4),
§112.7(a)(5),
§112.7(c)
§112.7(d)
§112.7(e),
§112.8(c)(6)/
§112.12(c)(6)
§112.7(f)
§112.7(g)
§112.7(h)
§112.7(1)
§112.7(k)
§112.8(c)(2),
§112.8(c)(ll),
§112.12(c)(2),
§112.12(c)(ll)
§112.8(c)(6),
§112.12(c)(6)
Description
Established inclusion of information for use in a discharge requirements
Amended general secondary containment requirements
Established integrity testing requirements for impracticability claims
Amended recordkeeping requirements for inspections and tests
Amended personnel training requirements
Amended facility security requirements
Amended loading/unloading rack requirements
Established brittle fracture evaluation requirements
Established alternative to secondary containment requirements for qualified oil-filled operational equipment
Exempted mobile refuelers from sized secondary containment requirements in 2006. Sized secondary
containment exemption extended to other non-transportation-related tank trucks in 2008.
Amended integrity testing requirements
2002
X
X
X
X
X
X
X
2006
X
X
X
2008
X
X
X
X
X
2009
SPCC GUIDANCE FOR REGIONAL INSPECTORS
C-5
-------
Rule Provision
§112.8(d)(l),
§112.12(d)(l)
§112.9(c)(2)
§112.9(c)(5)
§112.9(c)(6)
§112.9(d)(3)
§112.9(d)(4)
[formerly
§112.9(d)(3)]
§112.12(c)(6)
Description
Amended buried piping requirements
Amended secondary containment requirements for onshore production facilities
Established alternative to secondary containment requirements for flow-through process vessels
Established alternative to secondary containment requirements for produced water containers
Established alternative to secondary containment requirements for flowlines and intra-facility gathering lines
Amended flowline and intra-facility gathering line maintenance program requirements
Established specific integrity testing requirements for Animal Fats and Vegetable Oils (AFVOs)
2002
X
X
X
2006
2008
X
X
X
X
X
2009
SPCC GUIDANCE FOR REGIONAL INSPECTORS
C-6
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Appendix D: Sample Bulk Storage Facility Plan
SPCC GUIDANCE FOR REGIONAL INSPECTORS
November 15, 2013
D
-------
DISCLAIMER - APPENDIX D
The sample Spill Prevention, Control and Countermeasure (SPCC) Plan in Appendix D
is intended to provide examples and illustrations of how a bulk storage facility could address a
variety of scenarios in its SPCC Plan. The "facility" is not an actual facility, nor does it represent
any actual facility or company. Rather, EPA is providing illustrative examples of the type and
amount of information that is appropriate SPCC Plan language for these hypothetical situations.
Because the SPCC rule is designed to give each facility owner/operator the flexibility to
tailor the facility's SPCC Plan to the facility's circumstances, this sample SPCC Plan is not a
template to be adopted by a facility; doing so does not mean that the facility will be in
compliance with the SPCC rule requirements. Nor is the sample plan a template that must be
followed in order for the facility to be considered in compliance with the SPCC rule.
Version 1.0, 11/28/2005
-------
SPILL PREVENTION, CONTROL, AND COUNTERMEASURE PLAN
Unified Oil Company
123 A Street
Stonefield, Massachusetts 02000
May 12, 2003
Prepared by
Poppins & Associates, Inc.
Clearwater Falls, Massachusetts, 02210
Version 1.0, 11/28/2005
-------
Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
TABLE OF CONTENTS
Page
Introduction 1
Part 1: Plan Administration
1.1 Management Approval and Designated Person 3
1.2 Professional Engineer Certification 3
1.3 Location of SPCC Plan 4
1.4 Plan Review 4
1.5 Facilities, Procedures, Methods, or Equipment Not Yet Fully Operational 5
1.6 Cross-Reference with SPCC Provisions 5
Part 2: General Facility Information
2.1 Facility Description 8
2.2 Evaluation of Discharge Potential 11
Part 3: Discharge Prevention - General SPCC Provisions
3.1 Compliance with Applicable Requirements 12
3.2 Facility Layout Diagram 12
3.3 Spill Reporting 12
3.4 Potential Discharge Volumes and Direction of Flow 13
3.5 Containment and Diversionary Structures 14
3.6 Practicability of Secondary Containment 16
3.7 Inspections, Tests, and Records 16
3.8 Personnel, Training, and Discharge Prevention Procedures 18
3.9 Security 19
3.10 Tank Truck Loading/Unloading Rack Requirements 19
3.11 Brittle Fracture Evaluation 22
3.12 Conformance with State and Local Applicable Requirements 22
Part 4: Discharge Prevention - SPCC Provisions for Onshore Facilities
(Excluding Production Facilities)
4.1 Facility Drainage 23
4.2 Bulk Storage Containers 23
4.3 Transfer Operations, Pumping, and In-Plant Processes 29
-ii- Version 1.0, 11/28/2005
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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
Part 5: Discharge Response
5.1 Response to a Minor Discharge 30
5.2 Response to a Major Discharge 31
5.3 Waste Disposal 32
5.4 Discharge Notification 32
5.5 Cleanup Contractors and Equipment Suppliers 33
List of Tables
Table 1-1: Plan Review Log 6
Table 1-2: SPCC Cross-Reference 7
Table 2-1: Oil Containers 9
Table 2-2: Oil Discharge History 10
Table 3-1: Potential Discharge Volume and Direction of Flow 13
Table 3-2: Inspection and Testing Program 16
Table 3-3: Fuel Transfer Procedures 21
Table 4-1: List of Oil Containers 24
Table 4-2: Scope and Frequency of Bulk Storage Containers Inspections and Tests 27
Appendices
A: Site Plan and Facility Diagram
B: Substantial Harm Determination
C: Facility Inspection Checklists
D: Record of Containment Dike Drainage
E: Record of Discharge Prevention Briefings and Training
F: Calculation of Secondary Containment Capacity
G: Records of Tank Integrity and Pressure Tests
H: Emergency Contacts
I: Discharge Notification Form
J: Discharge Response Equipment Inventory
K: Agency Notification Standard Report
Version 1.0, 11/28/2005
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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
LIST OF ACRONYMS AND ABBREVIATIONS
AST Aboveground Storage Tank
EPA U.S. Environmental Protection Agency
MADEP Massachusetts Department of Environmental Protection
NPDES National Pollutant Discharge Elimination System
PE Professional Engineer
POTW Publicly Owned Treatment Works
SPCC Spill Prevention, Control, and Countermeasure
STI Steel Tank Institute
LIST Underground Storage Tank
-IV- Version 1.0, 11/28/2005
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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
INTRODUCTION
Purpose
The purpose of this Spill Prevention, Control, and Countermeasure (SPCC) Plan is to
describe measures implemented by Unified Oil to prevent oil discharges from occurring, and to
prepare Unified Oil to respond in a safe, effective, and timely manner to mitigate the impacts of
a discharge.
This Plan has been prepared to meet the requirements of Title 40, Code of Federal
Regulations, Part 112 (40 CFR part 112), and supercedes the earlier Plan developed to meet
provisions in effect since 1974.
In addition to fulfilling requirements of 40 CFR part 112, this SPCC Plan is used as a
reference for oil storage information and testing records, as a tool to communicate practices on
preventing and responding to discharges with employees, as a guide to facility inspections, and
as a resource during emergency response.
Unified Oil management has determined that this facility does not pose a risk of
substantial harm under 40 CFR part 112, as recorded in the "Substantial Harm Determination"
included in Appendix B of this Plan.
This Plan provides guidance on key actions that Unified Oil must perform to comply with
the SPCC rule:
Q Complete monthly and annual site inspections as outlined in the Inspection,
Tests, and Records section of this Plan (Section 3.7) using the inspection
checklists included in Appendix C.
Q Perform preventive maintenance of equipment, secondary containment systems,
and discharge prevention systems described in this Plan as needed to keep them
in proper operating conditions.
Q Conduct annual employee training as outlined in the Personnel, Training, and
Spill Prevention Procedures section of this Plan (Section 3.8) and document
them on the log included in Appendix E.
Q If either of the following occurs, submit the SPCC Plan to the EPA Region 1
Regional Administrator (RA) and the Massachusetts Department of
Environmental Protection (MADEP), along with other information as detailed in
Section 5.4 of this Plan:
Q The facility discharges more than 1,000 gallons of oil into or upon the
navigable waters of the U.S. or adjoining shorelines in a single spill event;
or
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Q The facility discharges oil in quantity greater than 42 gallons in each of
two spill events within any 12-month period.
Q Review the SPCC Plan at least once every five (5) years and amend it to include
more effective prevention and control technology, if such technology will
significantly reduce the likelihood of a spill event and has been proven effective
in the field at the time of the review. Plan amendments, other than administrative
changes discussed above, must be recertified by a Professional Engineer on the
certification page in Section 1.2 of this Plan.
Q Amend the SPCC Plan within six (6) months whenever where is a change in
facility design, construction, operation, or maintenance that materially affects the
facility's spill potential. The revised Plan must be recertified by a Professional
Engineer (PE).
Q Review the Plan on an annual basis. Update the Plan to reflect any
"administrative changes" that are applicable, such as personnel changes or
revisions to contact information, such as phone numbers. Administrative changes
must be documented in the Plan review log of Section 1.4 of this Plan, but do not
have to be certified by a PE.
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Part 1: Plan Administration
1.1 Management Approval and Designated Person (40 CFR 112.7)
Unified Oil Company ("Unified Oil') is committed to preventing discharges of oil to navigable
waters and the environment, and to maintaining the highest standards for spill prevention
control and countermeasures through the implementation and regular review and amendment to
the Plan. This SPCC Plan has the full approval of Unified Oil management. Unified Oil has
committed the necessary resources to implement the measures described in this Plan.
The Facility Manager is the Designated Person Accountable for Oil Spill Prevention at the
facility and has the authority to commit the necessary resources to implement this Plan.
Authorized Facility Representative (facility response coordinator): Susan Blake
Signature: kuAon, (EUL
Title: Facility Manager
Date: May 12, 2003
1 .2 Professional Engineer Certification (40 CFR 1 12.3(d))
The undersigned Registered Professional Engineer is familiar with the requirements of Part 112
of Title 40 of the Code of Federal Regulations (40 CFR part 112) and has visited and examined
the facility, or has supervised examination of the facility by appropriately qualified personnel.
The undersigned Registered Professional Engineer attests that this Spill Prevention, Control,
and Countermeasure Plan has been prepared in accordance with good engineering practice,
including consideration of applicable industry standards and the requirements of 40 CFR part
112; that procedures for required inspections and testing have been established; and that this
Plan is adequate for the facility. [40 CFR 1 12.3(d)]
This certification in no way relieves the owner or operator of the facility of his/her duty to prepare
and fully implement this SPCC Plan in accordance with the requirements of 40 CFR part 112.
This Plan is valid only to the extent that the facility owner or operator maintains, tests, and
inspects equipment, containment, and other devices as prescribed in this Plan.
90535055, Massachusetts
Signature Professional Engineer Registration Number
Julie Andrews Sr. Process Engineer
Name Title ^ ~~-\
Poppins and Associates May 12,2003 / PE Seal \
Company Date ( MA
Julie Andrews
#90535055
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1.3 Location of SPCC Plan (40 CFR 112.3(e))
In accordance with 40 CFR 112.3(e), a complete copy of this SPCC Plan is maintained at the
facility in the office building. The front office is attended whenever the facility is operating, i.e.,
7:00 AM to 5:00 PM, 6 days per week (closed on Sundays).
1.4 Plan Review (40 CFR 112.3 and 112.5)
1.4.1 Changes in Facility Configuration
In accordance with 40 CFR 112.5(a), Unified Oil periodically reviews and evaluates this SPCC
Plan for any change in the facility design, construction, operation, or maintenance that
materially affects the facility's potential for an oil discharge, including, but not limited to:
* commissioning of containers;
•> reconstruction, replacement, or installation of piping systems;
•> construction or demolition that might alter secondary containment structures; or
* changes of product or service, revisions to standard operation, modification of
testing/inspection procedures, and use of new or modified industry standards or
maintenance procedures.
Amendments to the Plan made to address changes of this nature are referred to as technical
amendments, and must be certified by a PE. Non-technical amendments can be done (and
must be documented in this section) by the facility owner and/or operator. Non-technical
amendments include the following:
* change in the name or contact information (i.e., telephone numbers) of
individuals responsible for the implementation of this Plan; or
•> change in the name or contact information of spill response or cleanup
contractors.
Unified Oil must make the needed revisions to the SPCC Plan as soon as possible, but no later
than six months after the change occurs. The Plan must be implemented as soon as possible
following any technical amendment, but no later than six months from the date of the
amendment. The Facility Manager is responsible for initiating and coordinating revisions to the
SPCC Plan.
1.4.2 Scheduled Plan Reviews
In accordance with 40 CFR 112.5(b), Unified Oil reviews this SPCC Plan at least once every
five years (in the past, such reviews were required every three years). Revisions to the Plan, if
needed, are made within six months of the five-year review. A registered Professional Engineer
certifies any technical amendment to the Plan, as described above, in accordance with 40 CFR
112.3(d). The last SPCC review occurred on May 13, 2001. This Plan is dated May 12, 2003.
The next plan review is therefore scheduled to take place on or prior to May 12, 2008.
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1.4.3 Record of Plan Reviews
Scheduled reviews and Plan amendments are recorded in the Plan Review Log (Table 1-1).
This log must be completed even if no amendment is made to the Plan as a result of the review.
Unless a technical or administrative change prompts an earlier review of the Plan, the next
scheduled review of this Plan must occur by May 12, 2008.
1.5 Facilities, Procedures, Methods, or Equipment Not Yet Fully
Operational (40 CFR 112.7)
Bulk storage containers at this facility have never been tested for integrity since their installation
in 1989. Section 4.2.6 of this Plan describes the inspection program to be implemented by the
facility following a regular schedule, including the dates by which each of the bulk storage
containers must be tested.
1.6 Cross-Reference with SPCC Provisions (40 CFR 112.7)
This SPCC Plan does not follow the exact order presented in 40 CFR part 112. Section
headings identify, where appropriate, the relevant section(s) of the SPCC rule. Table 1-2
presents a cross-reference of Plan sections relative to applicable parts of 40 CFR part 112.
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Table 1-1: Plan Review Log
By
Mike Davies
Mike Davies
Mike Davies
Susan Blake
Susan Blake
Susan Blake
Susan Blake
Date Activity
5/20/1 989 Prepare Plan
Start of
Operations
5/18/1992 Scheduled
review
2/18/1994 Plan
amendment
5/15/1995 Scheduled
review
5/15/1998 Scheduled
review
5/13/2001 Scheduled
review
5/12/2003 Periodic review
due to physical
change
PE
certification
required? Comments
Yes Initial SPCC Plan.
No No change.
Yes* Changes to inspection procedures,
addition of a new tank, full review not
conducted.
No Change in responsible individual and
contact information.
No No change.
No No change.
Yes* Installation of oil/water separator
* Previous PE certifications of this Plan are summarized below.
Date
2/18/1994
5/12/2003
Scope
Addition of new tank and changes in
inspection procedures.
Installation of oil/water separator
PE Name
Chris Ebert
Julie Andrews
Licensing State and
Registration No.
MA, 90117823
MA, 905350055
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Table 1-2: SPCC Cross-Reference
Provision
112.3(d)
112.3(e)
112.5
112.7
112.7
112.7(a)(3)
112.7(a)(4)
112.7(a)(5)
112.7(b)
112.7(c)
112.7(d)
112.7(e)
112.7(f)
112.7(g)
112.7(h)
112.7(i)
112.7(j)
112.8(b)
112.8(c)(1)
112.8(c)(2)
112.8(c)(3)
112.8(c)(4)
112.8(c)(5)
112.8(c)(6)
112.8(c)(7)
112.8(c)(8)
112.8(c)(9)
112.8(c)(10)
112.8(c)(11)
112.8(d)
112.20(e)
Plan Section
Professional Engineer Certification
Location of SPCC Plan
Plan Review
Management Approval
Cross-Reference with SPCC Rule
Part 2: General Facility Information
Appendix A: Site Plan and Facility Diagram
5.4 Discharge Notification
Part 5: Discharge Response
3.4 Potential Discharge Volumes and Direction of Flow
3.5 Containment and Diversionary Structures
3.6 Practicability of Secondary Containment
3.7 Inspections, Tests, and Records
3.8 Personnel, Training and Discharge Prevention Procedures
3.9 Security
3.10 Tank Truck Loading/Unloading
3.11 Brittle Fracture Evaluation
3.12 Conformance with Applicable State and Local Requirements
4.1 Facility Drainage
4.2.1 Construction
4.2.2 Secondary Containment
4.2.3 Drainage of Diked Areas
4.2.4 Corrosion Protection
4.2.5 Partially Buried and Bunkered Storage Tanks
4.2.6 Inspection
Appendix B - Facility Inspection Checklists
4.2.7 Heating Coils
4.2.8 Overfill Prevention System
4.2.9 Effluent Treatment Facilities
4.2.10 Visible Discharges
4.2.1 1 Mobile and Portable Containers
4.3 Transfer Operations, Pumping and In-Plant Processes
Certification of Substantial Harm Determination
Page
3
4
4
Table 1-1
3
Table 1-2
8
Appendix A
32
Appendix I
Appendix K
32
13
14
16
16
Appendix B
18
19
19
22
22
23
23
25
26
Appendix D
26
26
26
Appendix C
27
27
28
28
28
29
Appendix B
* Only selected excerpts of relevant rule text are provided. For a complete list of SPCC requirements, refer
to the full text of 40 CFR part 112.
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Part 2: General Facility Information
Name: Unified Oil Company
Address: 123 A Street
Stonefield, MA 02000
(781) 555-5556
Type: Bulk storage distribution facility
Date of Initial Operations: May 20, 1989
Owner/Operator: Blake and Daughters, Inc.
20 Fairview Road
Stonefield, MA 02000
Primary contact: Susan Blake, Facility Manager
Work: (781) 555-5550
Cell (24 hours): (781) 555-5559
2.1 Facility Description (40 CFR 112.7(a)(3))
2.1.1 Location and Activities
Unified Oil distributes a variety of petroleum products to primarily commercial customers. The
facility handles, stores, uses, and distributes petroleum products in the form of gasoline, diesel,
No. 2 fuel oil, No. 6 fuel oil, and motor oil. Unified Oil receives products by common carrier via
tanker truck. The products are stored in several aboveground storage tanks (ASTs) and in one
underground storage tank (UST). They are delivered to customers by Unified Oil trucks or by
independent contractors. The facility refuels its own two delivery trucks from an underground
diesel tank connected to a fueling pump.
Hours of operation are between 7:00 AM and 5:00 PM, 6 days per week. Personnel at the
facility include a facility manager, a plant operator, two truck drivers, an office administrator, and
three operations and maintenance personnel.
The Site Plan and Facility Diagram included in Appendix A of this Plan show the location and
layout of the facility. The Facility Diagram (Figure A-2) shows the location of oil containers,
buildings, loading/unloading and transfer areas, and critical spill control structures.
Unified Oil is located in a primarily commercial area at 123 A Street in Stonefield,
Massachusetts. The site is comprised of approximately 2 acres of land and is bordered to the
east by A Street, to the west by Silver Creek, and to the north by ABC Plating Co.
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The site includes an office building, a maintenance shop, a tanker truck loading rack and
unloading area, and product storage and handling areas. Petroleum products are stored within
the main bulk storage area, underground, and inside the maintenance building.
2.1.2 Oil Storage
Oil storage at the facility consists of seven tanks: four fixed ASTs, one portable tank, and two
metallic USTs. In addition, the facility stores a varying stock of oil drums inside the maintenance
building.
The capacities of oil containers present at the site are listed below and are also indicated on the
facility diagram in Figure A-2. All containers with capacity of 55 gallons or more are included.
The capacity of the oil/water separator is not included in the total storage capacity for the facility
since it is used to treat storm water and as a means of secondary containment for areas of the
facility with potential for an oil discharge outside dikes or berms.
Unified Oil owns two 2,000-gallon transport trucks that are used to deliver product to customers.
One of the two trucks is periodically parked overnight while full; the capacity of this truck is
therefore counted in the total storage capacity for this facility.
Table 2-1: Oil Containers
ID Storage capacity
Content
Description
Fixed Storage
1 20,000 gallons
2 20,000 gallons
3 20,000 gallons
6 1,000 gallons
7 10,000 gallons
1,100 gallons
Portable storage
4 500 gallons
Vehicles
2,000 gallons
Diesel
Aboveground vertical tank
Unleaded regular gasoline Aboveground horizontal tank elevated on
built-in saddles
Unleaded premium gasoline Aboveground horizontal tank elevated on
built-in saddles
No. 2 fuel oil
No. 6 fuel oil
Motor oil
Gasoline
Fuel oil
Underground horizontal tank
Field-constructed aboveground vertical tank
55-gallon storage drums (variable stock; up
to 20 drums on site at any time)
Double-walled aboveground horizontal tank
Delivery truck*
* Note: Unified Oil owns two delivery trucks. Both trucks are used in transportation-
related activities outside the confines of the facility and generally return to the facility
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empty for parking overnight. One of the two delivery trucks is periodically parked while
full. This truck is therefore counted in the storage capacity for this facility. The other truck
is dedicated to scheduled deliveries and returns to the facility empty (except for minor
residual). If the tanker truck returns to the facility with more than residual product, this
product will be returned to inventory via the unloading station. If the facility decides to
use this tanker for overnight storage, then this Plan must be modified to include the
capacity of the truck and ensure compliance with other rule requirements, including
secondary containment.
Total Oil Storage: 74,600 gallons
Other containers: (1) 1,500-gallon oil/water separator
Note: The oil/water separator is used treat facility drainage (i.e.,
wastewater) prior to discharge into Silver Creek under state and federal
wastewater discharge permits. Discharge from the facility includes storm
water collected from the paved areas outside the loading rack/unloading
area containment term and bulk storage containment dike. No external
oil tanks are associated with the oil/water separator. This equipment is
used to meet certain secondary containment requirements under 40 CFR
part 112, as described later in this Plan. Thus, the capacity of the
oil/water separator is not counted towards the facility total storage
capacity.
(1) 5,000-gallon underground horizontal tank (Diesel) -Tank#5
Note: This underground storage tank is subject to, and meets, all the
technical requirements of Massachusetts Underground Storage Tank
Program at 527 CMR 9, as approved under 40 CFR part 281, and is
therefore not counted in the storage capacity for this facility (exempted
under 40 CFR 112.1(d)(4). Its location is indicated on the Facility Diagram
in Appendix A. Note that the other underground storage tank (Tank #6)
which contains No. 2 fuel oil for heating consumption on the premises of
the facility is not subject to certain technical requirements under 40 CFR
part 280 or a program approved under part 281, in particular corrosion
protection, and is therefore included in the storage capacity for this facility
(and is SPCC-regulated), as described above.
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2.2 Evaluation of Discharge Potential
2.2.1 Distance to Navigable Waters and Adjoining Shorelines and Flow Paths
The facility is located on relatively level terrain. Drainage generally flows in the direction of Silver
Creek, which runs immediately along the southwest side of the site. Silver Creek flows north to
the Blackpool River approximately 1.5 miles from the facility. Spill trajectories are indicated on
the facility diagram. Storm drains are located along A Street at the northeast end of the site.
They discharge to Silver Creek.
Approximately three-quarters of the facility's ground surface area is paved with asphalt. The
remainder consists of compacted gravel, grass, and low-lying vegetation.
2.2.2 Discharge History
Table 2-1 summarizes the facility's discharge history.
Table 2-2: Oil Discharge History
Description of Discharge
Corrective Actions Taken
Plan for Preventing
Recurrence
On 3/23/2003, a leaking valve
on a delivery truck discharged
50 gallons of diesel oil onto the
ground during a rain event,
allowing approximately 10
gallons to enter Silver Creek.
A boom was placed into Silver
Creek immediately upon
discovery. Approximately 35
gallons of oil were recovered
from Silver creek and the facility
ground.
An oil/water separator was
installed and the facility
drainage was designed to flow
into the separator.
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PART 3: Discharge Prevention - General SPCC Provisions
The following measures are implemented to prevent oil discharges during the handling, use, or
transfer of oil products at the facility. Oil-handling employees have received training in the
proper implementation of these measures.
3.1 Compliance with Applicable Requirements (40 CFR 112.7(a)(2))
This facility uses an oil/water separator as part of its drainage system to contain oil discharged
in certain areas of the facility (i.e., overfills, and the loading/unloading area associated with Tank
#4). Because Tank #4 does not meet the specifications provided in EPA's memorandum
concerning its policy on double-walled tanks, general containment must be provided to address
overfills. The separator provides environmental protection equivalent to the requirements under
112.8(b)(3) to use ponds, lagoons, or catchment basins to retain oil at the facility in the event of
an uncontrolled discharge. As described in Section 3.5 of this Plan, the operational and
emergency oil storage capacity of the oil/water separator is sufficient to handle the quantity of
oil expected to be discharged in undiked areas from tank overfills or transfer operations.
Non-destructive integrity evaluation is not performed on Tank #4 (500-gallon portable storage
tank) or the 55-gallon storage drums. Tank #4 has a double-wall construction and is elevated off
the ground. The tank is inspected regularly and following a regular schedule in accordance with
the Steel Tank Institute (STI) SP-001 tank inspection standard as described in this Plan. Any
leakage from the primary container would be detected through monitoring of the interstitial
space performed on a monthly basis. Any leakage from the secondary shell would be detected
visually during scheduled visual inspections by facility personnel. Storage drums are elevated
on spill pallets and have all sides visible, and any leak would be readily detected by facility
personnel before they can cause a discharge to navigable waters or adjoining shorelines.
Corrosion poses minimal risk of failure since drums are single-use and remain on site for a
relatively short period of time (less than one year). The drum storage area is inspected monthly.
This is in accordance with accepted industry practice for drum storage and provides an effective
means of verifying container integrity, as noted by EPA in the preamble to the SPCC rule at
67 FR 47120.
3.2 Facility Layout Diagram (40 CFR 112.7(a)(3))
Figure A-1 in Appendix A shows the general location of the facility on a U.S. Geological Survey
topographic map. Figure A-2 in Appendix A presents a layout of the facility and the location of
storage tanks and drums. The diagram also shows the location of storm water drain inlets and
the direction of surface water runoff. As required under 40 CFR 112.7(a)(3), the facility diagram
indicates the location and content of ASTs, USTs, and transfer stations and connecting piping.
3.3 Spill Reporting (40 CFR 112.7(a)(4))
The discharge notification form included in Appendix I will be completed upon immediate
detection of a discharge and prior to reporting a spill to the proper notification contacts.
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3.4 Potential Discharge Volumes and Direction of Flow (40 CFR 112.7(b))
Table 3-1 presents expected volume, discharge rate, general direction of flow in the event of
equipment failure, and means of secondary containment for different parts of the facility where
oil is stored, used, or handled.
Table 3-1: Potential Discharge Volumes and Direction of Flow
Potential Event
Maximum
volume
released
(gallons)
Maximum
discharge rate
Direction of Flow
Bulk Storage Area (Aboveground Storage Tanks #1 , 2, 3, or 7)
Failure of aboveground tank (collapse
or puncture below product level)
Tank overfill
Pipe failure
_eaking pipe or valve packing
Leaking heating coil (Tank #7)
20,000
1 to 120
20,000
600
10,000
Gradual to
instantaneous
60 gal/min
240 gal/min
1 gal/min
1 gal/min
SWto Silver Creek
SWto Silver Creek
SWto Silver Creek
SWto Silver Creek
SWto Silver Creek
Loading Rack/Unloading Area
Tank truck leak or failure inside the
rollover berm
Tank truck leak or failure outside the
rollover berm
Hose leak during truck loading
1 to 2,000
1 to 2,000
1 to 300
Gradual to
instantaneous
Gradual to
instantaneous
60 gal/min
SWto Silver Creek
SWto Silver Creek
SWto Silver Creek
Fuel Dispensing Areas
Tank #4 and diesel dispenser hose/
connections leak
1 to 1 50
30 gal/minute
SWto Silver Creek.
Maintenance Building
Leak or failure of drum
1 to 55
Gradual to
instantaneous
SWto Silver Creek.
Other Areas
Complete failure of portable tank
(Tank #4)
Leaking portable tank or overfills
(Tank #4)
500
1 to 100
Gradual to
instantaneous
3 gal/min
SWto Silver Creek.
SWto Silver Creek.
Secondary
Containment
Concrete dike
Concrete dike
Concrete dike
Concrete dike
Concrete dike
Rollover berm,
on to oil/water
separator
Rollover berm,
on to oil/water
separator
Rollover berm
Land-based spill
response
capability (spill
kit) and oil/water
separator
Spill pallets,
oil/water
separator
Secondary shell,
oil/water
separator
Secondary shell,
oil/water
separator
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Potential Event
_eak during transfer to heating fuel
UST(Tank#6)
Oil/water separator malfunction
Maximum
volume
released
(gallons)
1 to 120
1 to 300
Maximum
discharge rate
60 gal/min
1 gal/min
Direction of Flow
SWto Silver Creek.
SWto Silver Creek.
Secondary
Containment
Oil/water
separator
3.5 Containment and Diversionary Structures (40 CFR 112.7(c))
Methods of secondary containment at this facility include a combination of structures (e.g., dike,
berm, built-in secondary containment), drainage systems (e.g., oil/water separator), and land-
based spill response (e.g., drain covers, sorbents) to prevent oil from reaching navigable waters
and adjoining shorelines:
* For bulk storage containers (refer to Section 4.2.2 of this Plan):
> Dike. A concrete dike enclosure is provided around fixed aboveground
storage tanks, as described in Section 4.2.2 of this Plan.
•> Double-wall tank construction. Tank #6 (LIST), and the 500-gallon
portable storage tank (Tank #4) both have double-wall design with a
secondary shell designed to contain 110 percent of the inner shell
capacity. The portable tank is generally located near the entrance to the
maintenance building; however, it may be used elsewhere on site. It is
used to refuel various small pieces of equipment (each less than 55-
gallon capacity) such as trucks and compressors, that may be deployed
at different areas on the site.
•> Spill pallets. Each spill pallet has a capacity of 75 gallons, which can
effectively contain the volume of any single 55-gallon drum. Drums are
also stored inside the maintenance building and are not exposed to
precipitation. The floor of the maintenance building and lower 24 inches of
the outside walls are constructed of poured concrete that would restrict
the flow of oil outside the building. The floor has two floor drains; the drain
closest to the drum storage area is located 18 feet away. Floor drains flow
into the oil/water separator, which is capable of containing any oil
discharged from a 55-gallon drum.
* At the loading rack and unloading area (refer to Section 3.10 of this Plan):
•> Rollover berm. The loading rack/unloading area is surrounded by a 4-
inch rollover berm that provides sufficient containment for the largest
compartment of the tank truck loading or unloading at the facility (2,000
gallons), and an additional 4 inches of freeboard for precipitation.
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In transfer areas and other parts of the facility where a discharge could occur:
•> Drip pans. Fill ports for all ASTs are equipped with drip pans to contain
small leaks from the piping/hose connections.
* Sorbent material. Spill cleanup kits that include absorbent material,
booms, and other portable barriers are located inside the maintenance
building near the drummed oil storage area and in an outside shed
located near the loading rack/unloading area, as shown on the Facility
Diagram in Appendix A. The spill kits are located within close proximity of
the oil product storage and handling areas for rapid deployment should a
spill occur. Sorbent material, booms, and other portable barriers are
stored in the shed next to the loading rack/unloading area to allow for
quick deployment in the event of a discharge during loading/unloading
activities or any other accidental discharge outside the dike or loading
rack/unloading area, such as from tank vehicles entering/leaving the
facility or spills associated with the fuel dispenser. The response
equipment inventory for the facility is listed in Appendix J of this Plan. The
inventory is checked monthly to ensure that used material is replenished.
•> Drainage system. The facility surface drainage is engineered to direct oil
that may be discharged outside of engineered containment structures
such as dikes or berms into the oil/water separator.
* Oil/water separator. The oil/water separator is designed to separate and
retain oil at the facility. The oil/water separator has a total capacity for
oil/water mixture of 1,500 gallons and a design flow rate of 150 gallons
per minute. The separator outlet valve can be closed in the event of a
large discharge (greater than 300 gallons) to provide additional
emergency containment of up to 1,200 gallons. The maximum amount of
oil potentially discharged outside the diked or bermed areas is estimated
at roughly 2,000 gallons (from the complete failure of an on-site tanker
truck). A spill of this volume outside the diked or bermed areas will be
primarily contained by deploying sorbent material and other portable spill
barriers upon discovery of the spill, and additional oil containment
capacity will be provided by the oil/water separator. The operating oil
storage capacity is 300 gallons. Best Management Practices are used to
minimize the amount of solids and oil that flow into the oil/water
separator. Facility personnel are instructed to avoid and address small
spills using sorbents to minimize runoff of oil into the oil/water separator.
The oil/water separator is inspected monthly as part of the scheduled
inspection to check the level of water within the separator and measure
the depth of bottom sludges and floating oils. Floating oil is removed by a
licensed waste collector when it reaches a thickness of 2 inches.
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3.6 Practicability of Secondary Containment (40 CFR 112.7(d))
Unified Oil management has determined that secondary containment is practicable at this
facility.
3.7 Inspections, Tests, and Records (40 CFR 112.7(e))
As required by the SPCC rule, Unified Oil performs the inspections, tests, and evaluations listed
in the following table. Table 3-2 summarizes the various types of inspections and tests
performed at the facility. The inspections and tests are described later in this section, and in the
respective sections that describe different parts of the facility (e.g., Section 4.2.6 for bulk
storage containers).
Table 3-2: Inspection and Testing Program
Facility
Component
Action
Frequency/Circumstances
Aboveg round
container
Container supports
and foundation
Liquid level sensing
devices (overfill)
Diked area
Lowermost drain
and all outlets of
tank truck
Effluent treatment
facilities
All aboveground
valves, piping, and
appurtenances
Test container integrity. Combine
visual inspection with another testing
technique (non-destructive shell
testing). Inspect outside of container
for signs of deterioration and
discharges.
Inspect container's supports and
foundations.
Test for proper operation.
Inspect for signs of deterioration,
discharges, or accumulation of oil
inside diked areas.
Following a regular schedule (monthly,
annual, and during scheduled inspections)
and whenever material repairs are made.
Following a regular schedule (monthly,
annual, and during scheduled inspections)
and whenever material repairs are made.
Monthly
Monthly
Visually inspect content for presence Prior to draining
of oil.
Visually inspect.
Detect possible system upsets that
could cause a discharge.
Assess general condition of items,
such as flange joints, expansion
joints, valve glands and bodies, catch
pans, pipeline supports, locking of
valves, and metal surfaces.
Prior to filling and departure
Daily, monthly
Monthly
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Facility
Component
Action
Frequency/Circumstances
Buried metallic
storage tank
Buried piping
Leak test.
Inspect for deterioration.
Integrity and leak testing.
Annually
Whenever a section of buried line is
exposed for any reason.
At the time of installation, modification,
construction, relocation, or replacement.
3.7.1 Daily Inspection
A Unified Oil employee performs a complete walk-through of the facility each day. This daily
visual inspection involves: (1) looking for tank/piping damage or leakage, stained or discolored
soils, or excessive accumulation of water in diked and bermed areas; (2) observing the effluent
from the oil/water separator; and (3) verifying that the dike drain valve is securely closed.
3.7.2 Monthly Inspection
The checklist provided in Appendix C is used for monthly inspections by Unified Oil personnel.
The monthly inspections cover the following key elements:
Q Observing the exterior of aboveground storage tanks, pipes, and other
equipment for signs of deterioration, leaks, corrosion, and thinning.
Q Observing the exterior of portable containers for signs of deterioration or leaks.
Q Observing tank foundations and supports for signs of instability or excessive
settlement.
Q Observing the tank fill and discharge pipes for signs of poor connection that
could cause a discharge, and tank vent for obstructions and proper operation.
Q Verifying the proper functioning of overfill prevention systems.
Q Checking the inventory of discharge response equipment and restocking as
needed.
Q Observing the effluent and measuring the quantity of accumulated oil within the
oil/water separator.
All problems regarding tanks, piping, containment, or response equipment must immediately be
reported to the Facility Manager. Visible oil leaks from tank walls, piping, or other components
must be repaired as soon as possible to prevent a larger spill or a discharge to navigable waters
or adjoining shorelines. Pooled oil is removed immediately upon discovery.
Written monthly inspection records are signed by the Facility Manager and maintained with this
SPCC Plan for a period of three years.
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3.7.3 Annual Inspection
Facility personnel perform a more thorough inspection of facility equipment on an annual basis.
This annual inspection complements the monthly inspection described above and is performed
in June of each year using the checklist provided in Appendix C of this Plan.
The annual inspection is preferably performed after a large storm event in order to verify the
imperviousness and/or proper functioning of drainage control systems such as the dike, rollover
berm, control valves, and the oil/water separator.
Written annual inspection records are signed by the Facility Manager and maintained with this
SPCC Plan for a period of three years.
3.7.4 Periodic Integrity Testing
In addition to the above monthly and annual inspections by facility personnel, Tanks #1, 2, 3, 4,
and 7 are periodically evaluated by an outside certified tank inspector following the Steel Tank
Institute (STI) Standard for the Inspection ofAboveground Storage Tanks, SP-001, 2005
version, as described in Section 4.2.6 of this Plan.
3.8 Personnel, Training, and Discharge Prevention Procedures
(40CFR112.7(f))
The Facility Manager is the facility designee and is responsible for oil discharge prevention,
control, and response preparedness activities at this facility.
Unified Oil management has instructed oil-handling facility personnel in the operation and
maintenance of oil pollution prevention equipment, discharge procedure protocols, applicable
pollution control laws, rules and regulations, general facility operations, and the content of this
SPCC Plan. Any new facility personnel with oil-handling responsibilities are provided with this
same training prior to being involved in any oil operation.
Annual discharge prevention briefings are held by the Facility Manager for all facility personnel
involved in oil operations. The briefings are aimed at ensuring continued understanding and
adherence to the discharge prevention procedures presented in the SPCC Plan. The briefings
also highlight and describe known discharge events or failures, malfunctioning components, and
recently implemented precautionary measures and best practices. Facility operators and other
personnel will have the opportunity during the briefings to share recommendations concerning
health, safety, and environmental issues encountered during facility operations.
A simulation of an on-site vehicular discharge has been conducted, and future training
exercises will be periodically held to prepare for possible discharge responses.
Records of the briefings and discharge prevention training are kept on the form shown in
Appendix E and maintained with this SPCC Plan for a period of three years.
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3.9 Security (40 CFR 112.7(g))
The facility is surrounded by 8-ft tall steel security fencing. The fence encircles the entire
footprint of the facility. The single entrance gate is locked when the facility is unattended.
All drain valves for containment areas are locked in the closed position to prevent unauthorized
opening. Water draw valves on the 20,000-gallon storage tanks are maintained in the closed
position to prevent unauthorized opening via locks. Keys for all locked valves are kept in the
front office.
Two area lights illuminate the loading/unloading and storage areas. Additional motion-activated
lights are placed in other areas of the facility. The lights are placed to allow for the discovery of
discharges and to deter acts of vandalism.
The electrical starter controls for the oil pumps, including the fuel dispenser, are located in a
closet inside the maintenance shop. The closet is locked when the pumps are not in use. The
maintenance shop is locked when the facility is unattended.
The facility securely caps or blank-flanges the loading/unloading connections of facility piping
when not in service or when in standby service for an extended period of time, or when piping is
emptied of liquid content either by draining or by inert gas pressure.
3.10 Tank Truck Loading/Unloading Rack Requirements (40 CFR 112.7(h))
The potential for discharges during tank truck loading and unloading operations is of particular
concern at this facility. Unified Oil management is committed to ensuring the safe transfer of
material to and from storage tanks. The following measures are implemented to prevent oil
discharges during tank truck loading and unloading operations.
3.10.1 Secondary Containment (40 CFR 112.7(h)(1))
The facility has both a loading rack (for loading moderate capacity oil delivery tanker trucks) and
an unloading area (where product is unloaded from large capacity tanker truck to the facility
bulk storage tanks).
The loading rack and unloading area are co-located and are used by outside suppliers making
deliveries to the facility and to load Unified Oil delivery trucks.
The tank truck loading rack/unloading area is surrounded with a 4-inch rollover asphalt berm
that provides secondary containment in the event of a discharge during transfer operations. The
secondary containment berm is designed to address the more stringent rack containment
requirements of 40 CFR 112.7(h), which requires that the berm be sufficient to contain the
capacity of the largest compartment, plus freeboard for precipitation. The curbed area provides
a catchment capacity of 2,500 gallons, which is capable of containing the largest compartment
of the petroleum suppliers truck making deliveries at this facility (maximum 2,000 gallons), and
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is also capable of containing the capacity of Unified Oil's delivery trucks, which each have a
total capacity of 2,000 gallons.
To minimize direct exposure to rain, and facilitate the cleanup of small spills that may occur
during loading/unloading operations, the area is partially covered by a roof.
The area is graded to direct the flow of oil or water away from the vehicle, and the low point of
the curbed area is fitted with a gate valve that is normally kept closed and locked. The key for
that lock is kept in the main office. The berm is drained by Unified personnel after verifying that
the retained water is free of oil. The accumulated water is released to the oil/water separator.
The drain valve is closed and locked following drainage.
Although delivery trucks are usually empty while at the site for extended periods of time, Unified
Oil periodically parks one of its two delivery trucks while full overnight. If a delivery truck is
parked overnight or for an extended period of time while it still contains fuel, it is parked inside
the loading rack/unloading area containment berm. As discussed above, the berm provides
sufficient containment capacity for the truck volume, plus sufficient freeboard for 4 inches of
precipitation.
3.10.2 Loading/Unloading Procedures (40 CFR 112.7(h)(2) and (3))
All suppliers must meet the minimum requirements and regulations for tank truck
loading/unloading established by the U.S. Department of Transportation. Unified Oil ensures
that the vendor understands the site layout, knows the protocol for entering the facility and
unloading product, and has the necessary equipment to respond to a discharge from the vehicle
or fuel delivery hose.
The Facility Manager or his/her designee supervises oil deliveries for all new suppliers, and
periodically observes deliveries for existing, approved suppliers.
All loading and unloading of tank vehicles takes place only in the designated loading
rack/unloading area.
Vehicle filling operations are performed by facility personnel trained in proper discharge
prevention procedures. The truck driver or facility personnel remain with the vehicle at all times
while fuel is being transferred. Transfer operations are performed according to the minimum
procedures outlined in Table 3-3. This table is also posted next to the loading/unloading point.
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Table 3-3: Fuel Transfer Procedures
Stage
Tasks
Prior to
loading/
unloading
Q
Q
Q
During Q
loading/
unloading Q
After loading/ Q
unloading Q
Visually check all hoses for leaks and wet spots.
Verify that sufficient volume (ullage) is available in the storage tank or truck.
Lock in the closed position all drainage valves of the secondary containment
structure.
Secure the tank vehicle with wheel chocks and interlocks.
Ensure that the vehicle's parking brakes are set.
Verify proper alignment of valves and proper functioning of the pumping
system.
If filling a tank truck, inspect the lowermost drain and all outlets.
Establish adequate bonding/grounding prior to connecting to the fuel transfer
point.
Turn off cell phone.
Driver must stay with the vehicle at all times during loading/unloading
activities.
Periodically inspect all systems, hoses and connections.
When loading, keep internal and external valves on the receiving tank open
along with the pressure relief valves.
When making a connection, shut off the vehicle engine. When transferring
Class 3 materials, shut off the vehicle engine unless it is used to operate a
pump.
Maintain communication with the pumping and receiving stations.
Monitor the liquid level in the receiving tank to prevent overflow.
Monitor flow meters to determine rate of flow.
When topping off the tank, reduce flow rate to prevent overflow.
Make sure the transfer operation is completed.
Close all tank and loading valves before disconnecting.
Securely close all vehicle internal, external, and dome cover valves before
disconnecting.
Secure all hatches.
Disconnect grounding/bonding wires.
Make sure the hoses are drained to remove the remaining oil before moving
them away from the connection. Use a drip pan.
Cap the end of the hose and other connecting devices before moving them to
prevent uncontrolled leakage.
Remove wheel chocks and interlocks.
Inspect the lowermost drain and all outlets on tank truck prior to departure. If
necessary, tighten, adjust, or replace caps, valves, or other equipment to
prevent oil leaking while in transit. _
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3.11 Brittle Fracture Evaluation (40 CFR 112.7(i))
The only field-constructed tank at the facility is Tank #7. All other tanks were shop-built.
The shell thickness of Tank #7 is less than one-half inch. As discussed in the American
Petroleum Institute (API) Standard 653 Tank Inspection, Repair, Alteration, and Reconstruction
(API-653), brittle fracture is not a concern for tanks that have a shell thickness of less than one-
half inch. This is the extent of the brittle fracture evaluation for this tank.
Nonetheless, in the event that Tank #7 undergoes a repair, alteration, reconstruction, or change
in service that might affect the risk of a discharge or failure, the container will be evaluated for
risk of discharge or failure, following API-653 or an equivalent approach, and corrective action
will be taken as necessary.
3.12 Conformance with State and Local Applicable Requirements (40 CFR
112.70))
All bulk storage tanks at this facility are registered with the state and local authorities (Stonefield
Fire Department) and have current certificates of registration and special use permits required
by the local fire code.
Both USTs at the facility (Tanks #5 and 6) meet all requirements of Massachusetts LIST
regulation, including cathodic protection, double-wall construction, and monitoring systems,
although Tank #6 is not subject to these requirements.
Treated storm water runoff is discharged to Silver Creek as permitted under NPDES permit
#MA0001990. The maximum allowable daily oil/grease concentration is 15 mg/L. Grab samples
are taken each quarter, following the monitoring requirements specified in the NPDES permit.
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PART 4: Discharge Prevention - SPCC Provisions for
Onshore Facilities (Excluding Production Facilities)
4.1 Facility Drainage (40 CFR 112.8(b))
Drainage from the concrete dike surrounding tanks 1, 2, and 3 is restrained by a manually-
operated gate valve to prevent a discharge from entering the facility drainage system. The gate
valve is normally sealed closed, except when draining the secondary containment structure. The
content of the secondary containment dike is inspected by facility personnel prior to draining to
ensure that only oil-free water is allowed to enter the facility storm water drainage system. The
bypass valve is opened and resealed under direct personnel supervision. Drainage events are
recorded in the log included in Appendix D to this SPCC Plan.
Any potential discharge from ASTs will be restrained by secondary containment structures.
Discharges occurring during loading/unloading operations will be restrained by the rollover
berm. The facility includes a drainage system and an oil/water separator, which are used to as
containment for spill sources outside the main berm areas (fuel dispensing, overfills of 500-
gallon AST (Tank#4), and transfers associated with the heating oil tank). The facility is equipped
with an oil/water separator engineered to retain oil at the facility. This separator provides
environmental protection equivalent to ponds, lagoons, or catchments basins required under 40
CFR 112.8(b)(3) and (4), as allowed in 40 CFR 112.7(a)(2). Discharges outside the containment
areas, such as those occurring in the fuel dispensing area or while unloading heating oil, will
flow by gravity into the drainage collection area and into the oil/water separator where oil will be
retained until it can be pumped out.
4.2 Bulk Storage Containers (40 CFR 112.8(c))
Table 4-1 summarizes the construction, volume, and content of bulk storage containers at
Unified Oil facility.
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Table 4-1: List of Oil Containers
Tank
#1
#2
#3
#4
#5
#6
#7
Location
Bulk Storage
Area
Bulk Storage
Area
Bulk Storage
Area
Varies
Fuel
Dispensing
Area
Outside
Office
Building
Bulk Storage
Area
Inside
Maintenance
Building
Type (Construction
Standard)
AST vertical (UL1 42)
AST horizontal (UL1 42)
AST horizontal (UL1 42)
AST dual wall, portable
tank(UL142)
UST dual wall (STIP3)
UST dual wall (STIP3)
AST vertical (field-
erected). Heated during
winter months (internal
coils)
Steel drums
Capacity Content
(gallons)
20,000 Diesel
20,000 Premium
unleaded
gasoline
20,000 Regular
unleaded
gasoline
500 Regular
unleaded
gasoline
5,000 Diesel
1,000 No. 2 Fuel Oil
10,000 No. 6 Fuel Oil
55 Motor oil and
used oil
Discharge
Prevention &
Containment
Concrete dike.
Liquid level
gauge.
Concrete dike.
Liquid level
gauge.
Concrete dike.
Liquid level
gauge.
Double-wall.
Liquid level gauge
and interstitial
monitoring
system.
Double-wall.
Liquid level
gauge, overfill
protection system,
and interstitial
monitoring.
Double-wall.
Liquid level
gauge, overfill
protection system,
and interstitial
monitoring.
Concrete dike.
Liquid level
gauge.
Spill pallets with
built-in
containment
capacity. Building
also serves as
containment since
floor drains flow
into oil/water
separator
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4.2.1 Construction (40 CFR 112.8(c)(1))
All oil tanks used at this facility are constructed of steel, in accordance with industry
specifications as described above. The design and construction of all bulk storage containers
are compatible with the characteristics of the oil product they contain, and with temperature and
pressure conditions.
Piping between fixed aboveground bulk storage tanks is made of steel and placed aboveground
on appropriate supports designed to minimize erosion and stress.
4.2.2 Secondary Containment (40 CFR 112.8(c)(2))
A dike is provided around Tanks #1, 2, 3, and 7. Tanks #1, 2, and 3 each have a 20,000-gallon
capacity. Tank #7 has a 10,000-gallon capacity. The dike has a total containment capacity of
27,316 gallons to allow sufficient volume for the largest tank and freeboard for precipitation.
The freeboard is sufficient to contain a 4-inch rainfall corresponding to a 25-year, 24-hour storm
event for this region of Massachusetts, as documented in Appendix F of this Plan. The floor and
walls of the containment dike are constructed of poured concrete reinforced with steel. The
concrete dike was built under the supervision of a structural engineer and in conformance with
his specifications to be impervious to oil for a period of 72 hours. The facility is unattended for a
maximum of 40 hours (Saturday evening through Monday morning) and therefore any spill into
the diked area would be detected before it could escape the diked area. The surface of the
concrete floor, the inside and outside of the walls, and the interface of the floor and walls, are
visually inspected during the monthly facility inspection to detect any crack, signs of heaving or
settlement, or other structural damage that could affect the ability of the dike to contain oil. Any
damage is promptly corrected to prevent migration of oil into the ground, or out of the dike.
The 500-gallon portable AST tank is of double-wall construction and provides intrinsic
secondary containment for 110 percent of the tank capacity. Since the secondary containment
is not open to precipitation, this volume is sufficient to fully contain the product in the event of a
leak from the primary container. The interstitial space between the primary and secondary
containers is inspected on a monthly basis to detect any leak of product from the primary
container. The container, however, is not equipped to prevent overfills as required by EPA
policy in its memorandum on double-walled tanks. Therefore, general containment is required
for potential tank overfills. This containment is accomplished through the facility drainage
system and the oil/water separator, which provide environmentally equivalent protection as
described in Section 3.1 of this Plan.
Both USTs are of double-wall construction and provide intrinsic secondary containment for
110 percent of the tank capacity. The interstitial space between the primary and secondary
containers is inspected on a monthly basis to detect any leak of product from the primary
container.
The 55-gallon drums are placed on spill pallets inside the maintenance shop. Each spill pallet
provides 75 gallons of containment capacity, which is more than the required 55 gallons for any
single drum since the drums are not exposed to precipitation. The floor of the maintenance shop
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is impervious and sloped to direct any discharge occurring in the building away from doorways
and towards the drainage system that leads to the facility oil/water separator.
4.2.3 Drainage of Diked Areas (40 CFR 112.8(c)(3))
The concrete dikes are drained under direct supervision of facility personnel. The accumulated
water is observed for signs of oil prior to draining. The gate valves are normally kept in a closed
position and locked except when draining the dike. Dike drainage events are recorded on the
form included in Appendix D of this Plan; records are maintained at the facility for at least three
years.
4.2.4 Corrosion Protection (40 CFR 112.8(c)(4))
Both metallic underground storage tanks, including Tank #6, which is subject to the
requirements of 40 CFR part 112, are coated and cathodically protected to prevent corrosion
and leakage into the ground. Pressure testing is performed on both buried storage tanks every
two years following the requirements of 40 CFR part 280. The cathodic protection system is
tested annually to verify its efficacy.
Cathodic protection is provided for both tanks in accordance with 40 CFR part 280 and meets
the requirements of 40 CFR part 112.
Records of pressure tests are kept for at least three years.
4.2.5 Partially Buried and Bunkered Storage Tanks (40 CFR 112.8(c)(5))
This section is not applicable since there are no partially buried or bunkered storage tanks at
this facility.
4.2.6 Inspections and Tests (40 CFR 112.8(c)(6))
Visual inspections of ASTs by facility personnel are performed according to the procedure
described in this SPCC Plan. Leaks from tank seams, gaskets, rivets, and bolts are promptly
corrected. Records of inspections and tests are signed by the inspector and kept at the facility
for at least three years.
The scope and schedule of certified inspections and tests performed on the facility's ASTs are
specified in STI Standard SP-001. The external inspection includes ultrasonic testing of the
shell, as specified in the standard, or if recommended by the certified tank inspector to assess
the integrity of the tank for continued oil storage.
Records of certified tank inspections are kept at the facility for at least three years. Shell test
comparison records are retained for the life of the tanks.
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Table 4-2 summarizes inspections and tests performed on bulk storage containers ("EE"
indicates that an environmentally equivalent measure is implemented in place of the
inspection/test, as discussed in Section 3.1 of this Plan).
Table 4-2: Scope and Frequency of Bulk Storage Containers Inspections and Tests
Tank ID
Inspection/Test #1 #2 #3 #4 #5
Visual inspection by facility M M M M
personnel (as per checklist of A A A A
Appendix C)
External inspection by certified 20 yr 20 yr 10yr EE
inspector (as per STI Standard
SP-001)
Internal inspection by certified t t 20 yr* EE
inspector (as per STI Standard
SP-001)
Tank tightness test meeting 2 yr
requirements of 40 CFR 280
#6 #7 Drums
M M
A A
10 yr EE
20 yr* EE
2yr
Legend: M: Monthly
A: Annual
EE: Inspection not required given use of environmentally equivalent measure (refer to
Section 3.1 of this Plan).
* Or earlier, as recommended by the certified inspector based on findings from an external
inspection.
t Internal inspection may be recommended by the certified inspector based on findings
from the external inspection.
The frequency above is based on implementation of a scheduled inspection/testing program. To
initiate the program, ASTs will be inspected by the following dates:
* Tank #1: external inspection to be performed by December 31, 2009
•> Tank #2: external inspection to be performed by December 31, 2009
•> Tank #3: external inspection to be performed by December 31, 2006
* Tank #7: external Inspection to be performed by December 31, 2006
4.2.7 Heating Coils (40 CFR 112.8(c)(7))
Exhaust lines from internal heating coils for Tank #7 drain to the oil/water separator. The
exhaust lines are monitored for signs of leakage as part of the monthly inspection of the facility.
4.2.8 Overfill Prevention Systems (40 CFR 112.8(c)(8))
All tanks are equipped with a direct-reading level gauge. Additionally, all four fixed ASTs (Tanks
#1, 2, 3, and 7) are equipped with high level alarms set at 90 percent of the rated capacity. Tank
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#4 does not have an overfill prevention system. General secondary containment is provided in
the event of overfills, as described in this Plan.
Storage drums are not refilled, and therefore overfill prevention systems do not apply.
Tanks #5 and 6 are equipped with liquid level gauges and overfill protection systems. Liquid
level sensing devices are tested on a monthly basis during the monthly inspection of the facility,
following manufacturer recommendations. Venting capacity is suitable for the fill and withdrawal
rates.
Facility personnel are present throughout the filling operations to monitor the product level in the
tanks.
4.2.9 Effluent Treatment Facilities (40 CFR 112.8(c)(9))
The facility's storm water effluent discharged into Silver Creek is observed and records
maintained according to the frequency required by NPDES permit MA0000157 (at least once
per month) to detect possible upsets in the oil/water separator that could lead to a discharge.
4.2.10 Visible Discharges (40 CFR 112.8(c)(10))
Visible discharges from any container or appurtenance - including seams, gaskets, piping,
pumps, valves, rivets, and bolts - are quickly corrected upon discovery.
Oil is promptly removed from the diked area and disposed of according to the waste disposal
method described in Part 5 of this Plan.
4.2.11 Mobile and Portable Containers (40 CFR 112.8(c)(11))
Tank #4 is of double-wall design, which provides for adequate secondary containment in the
event of leaks in the primary container shell. The interstitial space is monitored monthly for
signs of leakage.
Small portable oil storage containers, such as 55-gallon drums, are stored inside the
maintenance shop where secondary containment is provided by spill pallets and the floor is
sloped to drain away from the floor drains and door. Any discharged material is quickly
contained and cleaned up using sorbent pads and appropriate cleaning products.
Unified Oil delivery trucks generally return to the facility empty or product is returned to
inventory. Whenever they remain at the facility while full for an extended period of time (such as
when parking overnight with an emergency load of product), they are positioned in the loading
rack/unloading area, which provides 2,500 gallons of secondary containment capacity (i.e.,
sufficient for the capacity of the delivery truck (2,000 gallons) and additional freeboard for 4
inches of precipitation).
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4.3 Transfer Operations, Pumping, and In-Plant Processes
(40CFR112.8(d))
Transfer operations at this facility include:
•> The transfer of oil from the underground fuel oil storage tank to the furnace
located in the basement of the office building. The oil is pumped from the oil
storage tank by means of buried steel fuel lines and a suction pump system.
* The filling of facility delivery trucks using the gasoline dispenser.
•> The transfer of oil into or from tanker trucks at the loading rack/unloading area.
All buried piping at this facility is cathodically protected against corrosion and is provided with a
protective wrapping and coating. When a section of buried line is exposed, it is carefully
examined for deterioration. If corrosion damage is found, additional examination and corrective
action must be taken as deemed appropriate considering the magnitude of the damage.
Additionally, Unified Oil conducts integrity and leak testing of buried piping at the time of
installation, modification, construction, relocation, or replacement. Records of all tests are kept
at the facility for at least three years.
Lines that are not in service or are on standby for an extended period of time are capped or
blank-flanged and marked as to their origin.
All pipe supports are designed to minimize abrasion and corrosion and to allow for expansion
and contraction. Pipe supports are visually inspected during the monthly inspection of the
facility.
All aboveground piping and valves are examined monthly to assess their condition. Inspection
includes aboveground valves, piping, appurtenances, expansion joints, valve glands and
bodies, catch pans, pipeline supports, locking of valves, and metal surfaces. Observations are
noted on the monthly inspection checklist provided in this Plan.
Warning signs are posted at appropriate locations throughout the facility to prevent vehicles
from damaging aboveground piping and appurtenances. Most of the aboveground piping is
located within areas that are not accessible to vehicular traffic (e.g., inside diked area). Brightly
painted bollards are placed where needed to prevent vehicular collisions with equipment.
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Part 5: Discharge Response
This section describes the response and cleanup procedures in the event of an oil discharge.
The uncontrolled discharge of oil to groundwater, surface water, or soil is prohibited by state
and possibly federal laws. Immediate action must be taken to control, contain, and recover
discharged product.
In general, the following steps are taken:
•> Eliminate potential spark sources;
* If possible and safe to do so, identify and shut down source of the discharge to
stop the flow;
•> Contain the discharge with sorbents, berms, fences, trenches, sandbags, or
other material;
* Contact the Facility Manager or his/her alternate;
* Contact regulatory authorities and the response organization; and
•> Collect and dispose of recovered products according to regulation.
For the purpose of establishing appropriate response procedures, this SPCC Plan classifies
discharges as either "minor" or "major," depending on the volume and characteristics of the
material released.
A list of Emergency Contacts is provided in Appendix H. The list is also posted at prominent
locations throughout the facility. A list of discharge response material kept at the facility is
included in Appendix J.
5.1 Response to a Minor Discharge
A "minor" discharge is defined as one that poses no significant harm (or threat) to human health
and safety or to the environment. Minor discharges are generally those where:
* The quantity of product discharged is small (e.g., may involve less than 10
gallons of oil);
•> Discharged material is easily stopped and controlled at the time of the discharge;
* Discharge is localized near the source;
* Discharged material is not likely to reach water;
•> There is little risk to human health or safety; and
•> There is little risk of fire or explosion.
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Minor discharges can usually be cleaned up by Unified Oil personnel. The following guidelines
apply:
* Immediately notify the Facility Manager.
* Under the direction of the Facility Manager, contain the discharge with discharge
response materials and equipment. Place discharge debris in properly labeled
waste containers.
* The Facility Manager will complete the discharge notification form (Appendix I)
and attach a copy to this SPCC Plan.
•> If the discharge involves more than 10 gallons of oil, the Facility Manager will call
the Massachusetts Department of Environmental Protection Incident Response
Division (617-556-1133).
5.2 Response to a Major Discharge
A "major" discharge is defined as one that cannot be safely controlled or cleaned up by facility
personnel, such as when:
•> The discharge is large enough to spread beyond the immediate discharge area;
* The discharged material enters water;
* The discharge requires special equipment or training to clean up;
•> The discharged material poses a hazard to human health or safety; or
•> There is a danger of fire or explosion.
In the event of a major discharge, the following guidelines apply:
•> All workers must immediately evacuate the discharge site via the designated exit
routes and move to the designated staging areas at a safe distance from the
discharge. Exit routes are included on the facility diagram and posted in the
maintenance building, in the office building, and on the outside wall of the outside
shed that contains the spill response equipment.
* If the Facility Manager is not present at the facility, the senior on-site person
notifies the Facility Manager of the discharge and has authority to initiate
notification and response. Certain notifications are dependent on the
circumstances and type of discharge. For example, if oil reaches a sanitary
sewer, the publicly owned treatment works (POTW) should be notified
immediately. A discharge that threatens Silver Creek may require immediate
notification to downstream users such as the town drinking water plant, which
has an intake located on Silver Creek.
* The Facility Manager (or senior on-site person) must call for medical assistance if
workers are injured.
•> The Facility Manager (or senior on-site person) must notify the Fire Department
or Police Department.
* The Facility Manager (or senior on-site person) must call the spill response and
cleanup contractors listed in the Emergency Contacts list in Appendix H.
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* The Facility Manager (or senior on-site person) must immediately contact the
Massachusetts Department of Environmental Protection Incident Response
Division (617-556-1133) and the National Response Center (888-424-8802).
* The Facility Manager (or senior on-site person) must record the call on the
Discharge Notification form in Appendix I and attach a copy to this SPCC Plan.
•> The Facility Manager (or senior on-site person) coordinates cleanup and obtains
assistance from a cleanup contractor or other response organization as
necessary.
If the Facility Manager is not available at the time of the discharge, then the next highest person
in seniority assumes responsibility for coordinating response activities.
5.3 Waste Disposal
Wastes resulting from a minor discharge response will be containerized in impervious bags,
drums, or buckets. The facility manager will characterize the waste for proper disposal and
ensure that it is removed from the facility by a licensed waste hauler within two weeks.
Wastes resulting from a major discharge response will be removed and disposed of by a
cleanup contractor.
5.4 Discharge Notification
Any size discharge (i.e., one that creates a sheen, emulsion, or sludge) that affects or threatens
to affect navigable waters or adjoining shorelines must be reported immediately to the National
Response Center (1-800-424-8802). The Center is staffed 24 hours a day.
A summary sheet is included in Appendix I to facilitate reporting. The person reporting the
discharge must provide the following information:
Q Name, location, organization, and telephone number
Q Name and address of the party responsible for the incident
Q Date and time of the incident
Q Location of the incident
Q Source and cause of the release or discharge
Q Types of material(s) released or discharged
Q Quantity of materials released or discharged
Q Danger or threat posed by the release or discharge
Q Number and types of injuries (if any)
Q Media affected or threatened by the discharge (i.e., water, land, air)
Q Weather conditions at the incident location
Q Any other information that may help emergency personnel respond to the
incident
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Contact information for reporting a discharge to the appropriate authorities is listed in Appendix
H and is also posted in prominent locations throughout the facility (e.g., in the office building, in
the maintenance building, and at the loading rack/unloading area).
In addition to the above reporting, 40 CFR 112.4 requires that information be submitted to the
United States Environmental Protection Agency (EPA) Regional Administrator and the
appropriate state agency in charge of oil pollution control activities (see contact information in
Appendix H) whenever the facility discharges (as defined in 40 CFR 112.1(b)) more than 1,000
gallons of oil in a single event, or discharges (as defined in 40 CFR 112.1(b)) more than 42
gallons of oil in each of two discharge incidents within a 12-month period. The following
information must be submitted to the EPA Regional Administrator and to MADEP within 60
days:
•> Name of the facility;
•> Name of the owner/operator;
* Location of the facility;
* Maximum storage or handling capacity and normal daily throughput;
•> Corrective action and countermeasures taken, including a description of
equipment repairs and replacements;
* Description of facility, including maps, flow diagrams, and topographical maps;
* Cause of the discharge(s) to navigable waters and adjoining shorelines, including
a failure analysis of the system and subsystem in which the failure occurred;
•> Additional preventive measures taken or contemplated to minimize possibility of
recurrence; and
* Other pertinent information requested by the Regional Administrator.
A standard report for submitting the information to the EPA Regional Administrator and to
MADEP is included in Appendix K of this Plan.
5.5 Cleanup Contractors and Equipment Suppliers
Contact information for specialized spill response and cleanup contractors are provided in
Appendix H. These contractors have the necessary equipment to respond to a discharge of oil
that affects Silver Creek or adjoining shorelines, including floating booms and oil skimmers.
Spill kits are located at the loading rack/unloading area and inside the maintenance building.
The inventory of response supplies and equipment is provided in Appendix J of this Plan. The
inventory is verified on a monthly basis. Additional supplies and equipment may be ordered from
the following sources:
AA Equipment Co. (800) 555-5556
Eastern Sorbent (800) 555-5557
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Appendix A
Site Plan and Facility Diagram
Figure A-1: Site Plan.
STONEFIELD
Unified Oil
Company
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Figure A-2: Facility Diagram.
^^-
1 j 1
Stofm Dra/n
Feno
A STREET
Stofm Drain
Fence Gate
/
ASPHALT PAVED AREA
('50' x 601)
Tank 4
/ Tank 1 \
I 20:300 Gal HX! 1
\ Dteses /
Tank 2
20.000 Sai. -{X! —
Premium UNractw Gamine
Abovoground piping
Tank 3
2D (SOD rial "4> 3 — '
Reqylar LlnJe*ad«d Grassofne
/Tank 7 \
I 10, COD Gal J
\ Nfj 6 fURi /
Bulk Storage Area
\
ows • «a'«
1.500 Gal.
, Sp'ffW
S '
j£ 4"aspft^[rcrffoi«rttemi 500 Gal. Gasoline /
pi - (parking area for nafifctes PORTABLE IAWK ' ^[ 1
Tank TrutJ? Loading Rack /
Unloading Area
A*
,.. .''
Protective Bollards ,
\ Roof (covered area) Underground pipint
Fuel p^
Dispensing o -P-
Area J-J
FijEi/ disp0tis®r arid ^^^
— (SateVa/ve UST fill port o
000
X^ 10-2O x 55 Gal.
~~| A*#tw O(7
•- Sf»* A*
Maintenance Building
3 ^--~~^
/ Tank 5 \
-i KIIXI G.ul J
regirAremer?fs/
.••'""•-,. USTfaport,
, •'' / \
Vafo& v- / ^ ^ ^- O)V furnace
'••._ < ' Tank 6 ^ (in basement)
S^FU«OI_X» \jS
Undergroufid piping / — Main Offioa Bui»n3
To Silvw Creek
_ ^C=r»
T&
C
ABC
reek
(250 Yards)
(250 Yards)
NOT TO SCALE
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Appendix B
Substantial Harm Determination
Facility Name: Unified Oil Company
Facility Address: 123 A Street
Stonefield, MA 02000
1 . Does the facility transfer oil over water to or from vessels and does the facility have a total oil
storage capacity greater than or equal to 42,000 gallons?
Yes DD No ID
2. Does the facility have a total oil storage capacity greater than or equal to 1 million gallons and
does the facility lack secondary containment that is sufficiently large to contain the capacity of
the largest aboveground oil storage tank plus sufficient freeboard to allow for precipitation within
any aboveground storage tank area?
Yes DD No ID
3. Does the facility have a total oil storage capacity greater than or equal to 1 million gallons and
is the facility located at a distance (as calculated using the appropriate formula in 40 CFR part
112 Appendix C, Attachment C-lll or a comparable formula) such that a discharge from the
facility could cause injury to fish and wildlife and sensitive environments?
Yes DD No ID
4. Does the facility have a total oil storage capacity greater than or equal to 1 million gallons and
is the facility located at a distance (as calculated using the appropriate formula in 40 CFR part
112 Appendix C, Attachment C-lll or a comparable formula) such that a discharge from the
facility would shut down a public drinking water intake?
Yes DD No ID
5. Does the facility have a total oil storage capacity greater than or equal to 1 million gallons and
has the facility experienced a reportable oil spill in an amount greater than or equal to 10,000
gallons within the last 5 years?
Yes DD No ID
Certification
I certify under penalty of law that I have personally examined and am familiar with the
information submitted in this document, and that based on my inquiry of those individuals
responsible for obtaining this information, I believe that the submitted information is true,
accurate, and complete.
Facility Manager
Signature Title
Susan Blake May 12, 2003
Name (type or print) Date
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APPENDIX C
Facility Inspection Checklists
The following checklists are to be used for monthly and annual facility-conducted inspections.
Completed checklists must be signed by the inspector and maintained at the facility, with this
SPCC Plan, for at least three years.
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Monthly Inspection Checklist
This inspection record must be completed each month except the month in which an annual
inspection is performed. Provide further description and comments, if necessary, on a separate
sheet of paper and attach to this sheet. *Any item that receives "yes" as an answer must be
described and addressed immediately.
Y*
N
Description & Comments
Storage tanks
Tank surfaces show signs of leakage
Tanks are damaged, rusted or deteriorated
Bolts, rivets, or seams are damaged
Tank supports are deteriorated or buckled
Tank foundations have eroded or settled
Level gauges or alarms are inoperative
Vents are obstructed
Secondary containment is damaged or stained
Water/product in interstice of double-walled tank
Dike drainage valve is open or is not locked
Piping
Valve seals, gaskets, or other appurtenances are leaking
Pipelines or supports are damaged or deteriorated
Joints, valves and other appurtenances are leaking
Buried piping is exposed
Loading/unloading and transfer equipment
Loading/unloading rack is damaged or deteriorated
Connections are not capped or blank-flanged
Secondary containment is damaged or stained
Berm drainage valve is open or is not locked
Oil/water separator
Oil/water separator > 2 inches of accumulated oil
Oil/water separator effluent has a sheen
Security
Fencing, gates, or lighting is non-functional
Pumps and valves are locked if not in use
Response Equipment
Response equipment inventory is complete
Date:
Signature:
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Annual Facility Inspection Checklist
This inspection record must be completed each year. If any response requires further
elaboration, provide comments in Description & Comments space provided. Further description
and comments, if necessary, must be provided on a separate sheet of paper and attached to
this sheet. *Any item that receives "yes" as an answer must be described and addressed
immediately.
Y*
N
Description & Comments
Storage tanks
Tank #1
Tank surfaces show signs of leakage
Tank is damaged, rusted or deteriorated
Bolts, rivets or seams are damaged
Tank supports are deteriorated or buckled
Tank foundations have eroded or settled
Level gauges or alarms are inoperative
Vents are obstructed
Tank #2
Tank surfaces show signs of leakage
Tank is damaged, rusted, or deteriorated
Bolts, rivets, or seams are damaged
Tank supports are deteriorated or buckled
Tank foundations have eroded or settled
Level gauges or alarms are inoperative
Vents are obstructed
Tank #3
Tank surfaces show signs of leakage
Tank is damaged, rusted, or deteriorated
Bolts, rivets, or seams are damaged
Tank supports are deteriorated or buckled
Tank foundations have eroded or settled
Level gauges or alarms are inoperative
Vents are obstructed
Tank #4
Tank surfaces show signs of leakage
Tank is damaged, rusted or deteriorated
Bolts, rivets or seams are damaged
Tank supports are deteriorated or buckled
Tank foundations have eroded or settled
Level gauges or alarms are inoperative
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Vents are obstructed
Oil is present in the interstice
Tank #7
Tank surfaces show signs of leakage
Tank is damaged, rusted, or deteriorated
Bolts, rivets, or seams are damaged
Tank supports are deteriorated or buckled
Tank foundations have eroded or settled
Level gauges or alarms are inoperative
Leakage in exhaust from heating coils
Concrete dike
Secondary containment is stained
Dike drainage valve is open or is not locked
Dike walls or floors are cracked or are separating
Dike is not retaining water (following large rainfall)
Y*
N
Description & Comments
Piping
Valve seals or gaskets are leaking
Pipelines or supports are damaged or deteriorated
Joints, valves and other appurtenances are leaking
Buried piping is exposed
Out-of-service pipes are not capped
Warning signs are missing or damaged
Loading/unloading and transfer equipment
Loading/unloading rack is damaged or deteriorated
Connections are not capped or blank-flanged
Rollover berm is damaged or stained
Berm drainage valve is open or is not locked
Drip pans have accumulated oil or are leaking
Oil/water separator
Oil/water separator > 2 inches of accumulated oil
Oil/water separator effluent has a sheen
Security
Fencing, gates, or lighting is non-functional
Pumps and valves are not locked (and not in use)
Response equipment
Response equipment inventory is incomplete
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Annual reminders:
* Hold SPCC Briefing for all oil-handling personnel (and update briefing log in the Plan);
•> Check contact information for key employees and response/cleanup contractors and
update them in the Plan as needed;
Additional Remarks:
Date: Signature:
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APPENDIX D
Record of Containment Dike Drainage
This record must be completed when rainwater from diked areas is drained into a storm drain or
into an open watercourse, lake, or pond, and bypasses the water treatment system. The bypass
valve must normally be sealed in closed position. It must be opened and resealed following
drainage under responsible supervision.
Date
06/05/2003
07/15/2003
Diked Area
Area 1
Area 1
Presence of
No oil
No oil
Time
08:00
08:20
Time
10:00
10:30
Signature
Susan Blake
Susan Blake
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APPENDIX E
Record of Annual Discharge Prevention
Briefings and Training
Briefings will be scheduled and conducted by the facility owner or operator for operating
personnel at regular intervals to ensure adequate understanding of this SPCC Plan. The
briefings will also highlight and describe known discharge events or failures, malfunctioning
components, and recently implemented precautionary measures and best practices. Personnel
will also be instructed in operation and maintenance of equipment to prevent the discharge of
oil, and in applicable pollution laws, rules, and regulations. Facility operators and other
personnel will have an opportunity during the briefings to share recommendations concerning
health, safety, and environmental issues encountered during facility operations.
Date
Subjects Covered
Employees in Attendance
Instructor(s)
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APPENDIX F
Calculation of Secondary Containment Capacity
The maximum 24-hour rainfall recorded in the last 25 years at this location is 3.75 inches.
Bulk Storage Dike
Capacity of Tanks within the Diked Area:
Tank 1 = 20,000 gallons (saddle-mounted tank, no significant displacement)
Tank 2 = 20,000 gallons (saddle-mounted tank, no significant displacement)
Tank 3 = 20,000 gallons (need to account for tank displacement)
Tank 7 = 10,000 gallons (on legs, no significant displacement)
Dike Dimensions:
Dike footprint = 50 feet x 60 feet
Dike height =15 inches = 1.25 feet
Dike volume = 50' x 60' x 1.25' = 3750 ft3 x 7.48 gal/ft3 = 28,050 gallons
Displacement Volume of Tank 3:
Tank diameter = 10 feet
3.1415 * (10 ft)2 / 4 * 1.25' = 98 ft3 x 7.48 gal/ft3 = 734 gallons
Available Freeboard for Precipitation:
28,050 gallons - (20,000 gallons + 734 gallons) = 7,316 gallons
7,316 gallons / 7.48 gallons/ft3 / (50 ft x 60 ft) = 0.33 ft = 4 inches
The dike therefore provides sufficient storage capacity for the largest bulk storage
container within the diked area, tank displacement, and precipitation. The
containment capacity is equivalent to 137% of the capacity of the largest container
((28,050 gallons - 734 gallons)/20,000 gallons).
Loading Rack/Unloading Area Rollover Berm
Capacity of Largest Tank Truck Compartment:
2,000 gallons
Berm Dimensions:
Berm footprint = 28 feet x 45 feet (50% of the berm surface area is covered by the roof)
Berm height = 4.5 inches = 0.375 feet
Berm volume = 28 ft x 45 ft x 0.375 ft = 473 ft3 x 7.48 gal/ft3 = 3,534 gallons
Available Freeboard for Precipitation:
Since 50% of the surface area of the berm is covered by a roof, the volume of
precipitation that enters the berm is reduced.
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Minimum freeboard required = 28 ft x 45 ft x 0.5 x 3.75/12 = 197 ft3 = 1,472 gallons
Actual freeboard = 3,534 gallons - 2,000 gallons = 1,534 gallons
The berm therefore provides sufficient storage capacity to contain both the largest
compartment of tank trucks loading/unloading at the facility, and the volume of
precipitation that enters the berm.
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APPENDIX G
Records of Tank Integrity and Pressure Tests
Attach copies of official records of tank integrity and pressure tests.
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APPENDIX H
Emergency Contacts
Designated person responsible for spill prevention: Susan Blake, Facility Manager
781-555-5550
EMERGENCY TELEPHONE NUMBERS:
Facility
Susan Blake, Facility Manager 781-555-5550
Local Emergency Response
Stonefield Fire Department 911 or
781-555-5551
St. Mary's Hospital 781-555-5552
Response/Cleanup Contractors
EZ Clean 617-555-5554
Stonefield Oil Removal 781-555-5555
Notification
Massachusetts Department of Environmental Protection, Incident 617-556-1133
Response Division
National Response Center 800-424-8802
United States Environmental Protection Agency, Region 1 888-372-7341
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APPENDIX I
Discharge Notification Form
Part A: Discharge Information
General information when reporting a spill to outside authorities:
Name:
Address:
Telephone:
Owner/Operator:
Primary Contact:
Unified Oil Company
123 A Street
Stonefield, MA 02000
(781) 555-5556
Blake and Daughters, Inc.
20 Fairview Road
Stonefield, MA 02000
Susan Blake, Facility Manager
Work: (781)555-5550
Cell (24 hrs): (781)555-5559
Type of oil:
Discharge Date and Time:
Quantity released:
Discovery Date and Time:
Quantity released to a waterbody:
Discharge Duration:
Location/Source:
Actions taken to stop, remove, and mitigate impacts of the discharge:
Affected media:
Dair
D water
Dsoil
D storm water sewer/POTW
D dike/berm/oil-water separator
D other:
Notification person:
Telephone contact:
Business:
24-hr:
Nature of discharges, environmental/health effects, and damages:
Injuries, fatalities or evacuation required?
Part B: Notification Checklist
Date and time
Name of person receiving call
Discharge in any amount
Susan Blake, Facility Manager and Response
Coordinator
(781) 555-5550 / (781) 555-5559
Discharge in amount exceeding 10 gallons and not affecting a waterbody or groundwater
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Local Fire Department
Fire Chief: D. Evans
(781) 555-1258 or 911
Massachusetts Department of Environmental
Protection
(888) 304-1 1 33 or (61 7) 553-1 1 33
Discharge in any amount and affecting (or threatening to affect) a waterbody
Local Fire Department
Fire Chief: D. Evans
(781) 555-1258 or 911
Massachusetts Department of Environmental
Protection
(888) 304-1 1 33 or (61 7) 553-1 1 33
National Response Center
(800) 424-8802
Town of Stonefield POTW
Plant Operator: K. Bromberg
(781) 555-5453
Town of Stonefield Drinking Water Plant
Plant Operator: D. Lopez
(781) 555-5450
EZ Clean
(617)555-5554
* The POTW should be notified of a discharge only if oil has reached or threatens sewer drains that
connect to the POTW collection system.
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APPENDIX J
Discharge Response Equipment Inventory
The discharge response equipment inventory is verified during the monthly inspection and must
be replenished as needed.
Tank Truck Loading/Unloading Area
DD Empty 55-gallons drums to hold contaminated material 4
DD Loose absorbent material 200 pounds
DD Absorbent pads 3 boxes
DD Nitrile gloves 6 pairs
DD Neoprene gloves 6 pairs
DD Vinyl/PVC pull-on overboots 6 pairs
D Non-sparking shovels 3
D Brooms 3
DD Drain seals or mats 2
D Sand bags 12
Maintenance Building
DD Empty 55-gallons drums to hold contaminated material 1
DD Loose absorbent material 50 pounds
DD Absorbent pads 1 box
DD Nitrile gloves 2 pairs
DD Neoprene gloves 2 pairs
DD Vinyl/PVC pull-on overboots 2 pairs
D Non-sparking shovels 1
D Brooms 1
DD Drain seals or mats 1
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APPENDIX K
Agency Notification Standard Report
Information contained in this report, and any supporting documentation, must be submitted to
the EPA Region 1 Regional Administrator, and to MADEP, within 60 days of the qualifying
discharge incident.
Facility:
Owner/operator:
Name of person filing report:
Location:
Maximum storage capacity:
Daily throughput:
Unified Oil Company
Blake and Daughters
20 Fairview Road
Stonefield, MA 02000
123 A Street
Stonefield, MA 02000
74,600 gallons
8, 000 gallons
Nature of qualifying incident(s):
D Discharge to navigable waters or adjoining shorelines exceeding 1,000 gallons
D Second discharge exceeding 42 gallons within a 12-month period.
Description of facility (attach maps, flow diagrams, and topographical maps):
Unified Oil distributes a variety of petroleum products to primarily commercial customers. The
facility handles, stores, uses, and distributes petroleum products in the form of gasoline,
diesel, No. 2 fuel oil, No. 6 fuel oil, and motor oil. Unified Oil receives products by common
carrier via tanker truck. The products are stored in five aboveground storage tanks (ASTs)
and in one underground storage tank (UST). They are delivered to customers by Unified Oil
trucks or by independent contractors. The facility refuels its own two delivery trucks from an
underground diesel tank connected to a fueling pump.
Unified Oil is located in a primarily commercial area at 123 A Street in Stonefield,
Massachusetts. The site is comprised of approximately 2 acres of land and is bordered to the
East by A Street, to the West by Silver Creek, and to the North by ABC Plating Co.
Site improvements include an office building, a maintenance shop, a tanker truck loading rack
and unloading area, and product storage and handling areas. Petroleum products are stored
in the bulk storage area, the maintenance building, and the office building.
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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
Agency Notification Standard Report (cont'd)
Cause of the discharge(s), including a failure analysis of the system and subsystems
in which the failure occurred:
Corrective actions and countermeasures taken, including a description of equipment
repairs and replacements:
Additional preventive measures taken or contemplated to minimize possibility of
recurrence:
Other pertinent information:
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Appendix E: Sample Production Facility Plan
SPCC GUIDANCE FOR REGIONAL INSPECTORS
November 15, 2013
-------
Disclaimer - Appendix E
The sample Spill Prevention, Control and Countermeasure (SPCC) Plan in Appendix E
is intended to provide examples and illustrations of how a production facility could address a
variety of scenarios in its SPCC Plan. The "facility" is not an actual facility, nor does it represent
any actual facility or company. Rather, EPA is providing illustrative examples of the type and
amount of information that is appropriate SPCC Plan language for these hypothetical situations.
Because the SPCC rule is designed to give each facility owner/operator the flexibility to
tailor the facility's SPCC Plan to the facility's circumstances, this sample SPCC Plan is not a
template to be adopted by a facility; doing so does not mean that the facility will be in
compliance with the SPCC rule requirements. Nor is the sample plan a template that must be
followed in order for the facility to be considered in compliance with the SPCC rule.
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SPILL PREVENTION, CONTROL, AND COUNTERMEASURE PLAN
Clearwater Oil Company
Big Bear Lease No. 2 Production Facility
5800 Route 417
Madison, St. Anthony Parish, Louisiana 73506
Clearwater
Prepared by
Montgomery Engineering, Inc.
November 23, 2003
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Clearwater Oil Company, Ltd. SAMPLE Spill Prevention, Control, and
Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan
Table of Contents
Page
Cross-Reference with SPCC Rule 4
Introduction 5
Management Approval 6
Professional Engineer Certification 6
Plan Review 7
Location of SPCC Plan 7
Certification of Substantial Harm Determination 8
Part I - General Facility Information
1.1 Company Information 9
1.2 Contact Information 9
1.3 Facility Layout Diagram 10
1.4 Facility Location and Operations 10
1.5 Oil Storage and Handling 11
1.6 Proximity to Navigable Waters 12
1.7 Conformance with Applicable State and Local Requirements 12
Part II - Spill Response and Reporting
2.1 Discharge Discovery and Reporting 13
2.2 Spill Response Materials 14
2.3 Spill Mitigation Procedures 15
2.4 Disposal Plan 16
Part III - Spill Prevention, Control, and Countermeasure Provisions
3.1 Potential Discharge Volume and Direction of Flow 18
3.2 Containment and Diversionary Structures 19
3.3 Other Spill Prevention Measures 22
3.4 Inspections, Tests, and Records 23
3.5 Personnel, Training, and Discharge Prevention Procedures 27
Appendix A - Facility Diagrams 30
Appendix B - Tank Truck Loading Procedure 32
Appendix C - Monthly Inspection Checklist 33
Appendix D - Record of Dike Drainage 34
Appendix E - Discharge Prevention Briefing Log 35
Appendix F - Discharge Notification Procedures 36
Appendix G - Equipment Shut-off Procedures 41
Appendix H - Written Commitment of Manpower, Equipment, and Materials 42
Appendix I - Oil Spill Contingency Plan 43
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Clearwater Oil Company, Ltd. SAMPLE Spill Prevention, Control, and
Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan
Page
List of Tables
Table 0-1: Record of plan review and changes 7
Table 1-1: Facility contact information 10
Table 1-2: Characteristics of oil containers 11
Table 3-1: Potential discharge volume and direction of flow 18
Table 3-2: Berm capacity calculations 21
Table 3-3: Scope of daily examinations 24
Table 3-4: Scope of monthly inspections 25
Table 3-5: Schedule of periodic condition inspection of bulk storage containers 26
Table 3-6: Components of flowline maintenance program 27
List of Figures
Figure A-1: Site plan. 30
Figure A-2: Production facility diagram. 31
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Clearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
Cross-Reference with SPCC Rule
Provision*
112.3(d)
112.3(e)
112.5
112.7
112.7
112.7(a)(3)
112.4 and
112.7(a)(4)
112.7(a)(5)
112.7(b)
112.7(c)
112.7(d)
112.7(e)
112.7(f)
112.7(g)
112.7(h)
112.7(i)
112.70)
112.9(b)
112.9(c)(1)
112.9(c)(2)
112.9(c)(3)
112.9(c)(4)
112.9(d)(1)
112.9(d)(2)
112.9(d)(3)
Plan Section
Professional Engineer Certification
Location of SPCC Plan
Plan Review
Management Approval
Cross-Reference with SPCC Rule
Part I - General Information and Facility Diagram
Appendix A: Facility Diagrams
2.1 Discharge Discovery and Reporting
Appendix F: Discharge Notification
2.2 Spill Mitigation Procedures
Appendix I: Oil Spill Contingency Plan
3.1 Potential Discharge Volume and Direction of Flow
3.2 Containment and Diversionary Structures
3.2.3 Practicability of Secondary Containment
Appendix H: Written Commitment of manpower, equipment, and materials
Appendix I: Oil Spill Contingency Plan
3.4 Inspections, Tests, and Records
Appendix C: Facility Inspection Checklists
3.5 Personnel, Training, and Discharge Prevention Procedures
Appendix E: Discharge Prevention Briefing Log
Security - N/A (does not apply to production facilities)
Loading/Unloading Rack - N/A (no rack present at this facility)
Brittle Fracture Evaluation - N/A (no field-erected aboveground tank at this
facility)
1.7 Conformance with Applicable State and Local Requirements
3.2.1 Oil Production Facility Drainage
Appendix D: Record of Dike Drainage
1.5.1 Production Equipment
3.2.2 Secondary Containment for Bulk Storage Containers
3.4 Inspections, Tests, and Records
Appendix C: Monthly Inspection Checklist
3.3.1 Bulk Storage Containers Overflow Prevention
3.3.2 Transfer Operations and Saltwater Disposal System
3.3.2 Transfer Operations and Saltwater Disposal System
3.4.5 Flowline Maintenance Program
Page(s)
6
7
7
6
4
9-12
Appendix A
13-15
Appendix F
15-16
Appendix I
18-19
19-21
21
Appendix H
Appendix I
23-26
Appendix C
27-29
Appendix E
N/A
N/A
26
12
20
Appendix D
11
19-21
23-26
Appendix C
22
22-23
22-23
26-27
* Only relevant rule provisions are indicated. For a complete list of SPCC requirements, refer to the full text of 40 CFR
part 112.
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Clearwater Oil Company, Ltd. SAMPLE Spill Prevention, Control, and
Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan
Introduction
The purpose of this Spill Prevention Control and Countermeasure (SPCC) Plan is to describe
measures implemented by Clearwater to prevent oil discharges from occurring, and to prepare
Clearwater to respond in a safe, effective, and timely manner to mitigate the impacts of a
discharge from the Big Bear Lease No. 2 production facility. This SPCC Plan has been
prepared and implemented in accordance with the SPCC requirements contained in 40 CFR
part 112.
In addition to fulfilling requirements of 40 CFR part 112, this SPCC Plan is used as a reference
for oil storage information and testing records, as a tool to communicate practices on preventing
and responding to discharges with Clearwater employees and contractors, as a guide on facility
inspections, and as a resource during emergency response.
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Clearwater Oil Company, Ltd. SAMPLE Spill Prevention, Control, and
Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan
Management Approval
40 CFR 112.7
Clearwater Oil Company ("Clearwater") is committed to maintaining the highest standards for
preventing discharges of oil to navigable waters and the environment through the
implementation of this SPCC Plan. This SPCC Plan has the full approval of Clearwater
management. Clearwater's management has committed the necessary resources to implement
the measures described in this Plan.
Bill Laurier is the Designated Person Accountable for Oil Spill Prevention at this Clearwater
facility and has the authority to commit the necessary resources to implement the Plan as
described.
Authorized Facility Representative: Bill Laurier
Signature: (Sill Au/ue/i,
Title: Field Operations Manager
Date: November 23, 2003
Professional Engineer Certification
40CFR112.3(d)
The undersigned Registered Professional Engineer is familiar with the requirements of Part 112
of Title 40 of the Code of Federal Regulations (40 CFR part 112) and has visited and examined
the facility, or has supervised examination of the facility by appropriately qualified personnel.
The undersigned Registered Professional Engineer attests that this Spill Prevention, Control,
and Countermeasure Plan has been prepared in accordance with good engineering practice,
including consideration of applicable industry standards and the requirements of 40 CFR part
112; that procedures for required inspections and testing have been established; and that this
Plan is adequate for the facility. [112.3(d)]
This certification in no way relieves the owner or operator of the facility of his/her duty to prepare
and fully implement this SPCC Plan in accordance with the requirements of 40 CFR part 112.
P-efc^ £. J/tA*jU4U* November 23, 2003
Signature Date /"""^ ^""\
Peter E. Trudeau. P.E. / PESeal \
Name of Professional Engineer
Peter E. Trudeau
90535055 Louisiana \ LA #90535055 /
Registration Number Issuing State \. /
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Clearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
Plan Review
40CFR112.5
In accordance with 40 CFR 112.5, Clearwater Oil periodically reviews and evaluates this SPCC
Plan for any change in the facility design, construction, operation, or maintenance that
materially affects the facility's potential for an oil discharge. Clearwater reviews this SPCC Plan
at least once every five years. Revisions to the Plan, if any are needed, are made within six
months of this five-year review. Clearwater will implement any amendment as soon as possible,
but not later than six months following preparation of any amendment. A registered PE certifies
any technical amendment to the Plan, as described above, in accordance with 40 CFR 112.3(d).
Scheduled five-year reviews and Plan amendments are recorded in Table 0-1. This log must be
completed even if no amendment is made to the Plan. Unless a technical or administrative
change prompts an earlier review, the next scheduled review of this Plan must occur by
November 23, 2008.
Table 0-1: Record of Plan Review and Changes
Date
Authorized
Individual
Review Type
PE
Certification
Summary of Changes
11/23/03
04/14/04
Bill Laurier
Bill Laurier
Initial Plan
Off-cycle review
Yes
No
N/A
Changed telephone number for Field
Operations Manager.
Corrected page numbers in Table of
Content.
Non-technical amendments, no PE
certification is needed.
Location of SPCC Plan
40 CFR 112.3(e)
In accordance with 40 CFR 112.3(e), and because the facility is normally unmanned, a
complete copy of this SPCC is maintained at the field office closest to the facility, which is
located approximately 25 miles from the facility at 2451 Mountain Drive, Ridgeview, LA.
Additional copies are available at the Clearwater Oil Company management office, located at
13000 Main Street, Suite 400, Houston, TX.
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Clearwater Oil Company, Ltd. SAMPLE Spill Prevention, Control, and
Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan
Certification of Substantial Harm Determination
40 CFR 112.20(e), 40 CFR 112.20(f)(1)
Facility Name: Clearwater Oil Company, Big Bear Lease No. 2
1. Does the facility transfer oil over water to or from vessels and does the facility have a total oil
storage capacity greater than or equal to 42,000 gallons?
Yes DD No ID
2. Does the facility have a total oil storage capacity greater than or equal to 1 million gallons and
does the facility lack secondary containment that is sufficiently large to contain the capacity of
the largest aboveground oil storage tank plus sufficient freeboard to allow for precipitation within
any aboveground storage tank area?
Yes DD No ID
3. Does the facility have a total oil storage capacity greater than or equal to 1 million gallons and
is the facility located at a distance (as calculated using the appropriate formula) such that a
discharge from the facility could cause injury to fish and wildlife and sensitive environments?
Yes DD No ID
4. Does the facility have a total oil storage capacity greater than or equal to 1 million gallons and
is the facility located at a distance (as calculated using the appropriate formula) such that a
discharge from the facility would shut down a public drinking water intake?
Yes DD No ID
5. Does the facility have a total oil storage capacity greater than or equal to 1 million gallons and
has the facility experienced a reportable oil spill in an amount greater than or equal to 10,000
gallons within the last 5 years?
Yes DD No ID
Certification
I certify under penalty of law that I have personally examined and am familiar with the
information submitted in this document, and that based on my inquiry of those individuals
responsible for obtaining this information, I believe that the submitted information is true,
accurate, and complete.
Field Operations Manager
Signature Title
Bill Laurier November 23, 2003
Name (type or print) Date
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Clearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
PART I - GENERAL FACILITY INFORMATION
40CFR112.7(a)(3)
1.1 Company Information
Name of Facility:
Type
Date of Initial Operation
Location
Name and Address of Owner
Clearwater Oil Company
Big Bear Lease No. 2
Onshore oil production facility
2002
5800 Route 417
Madison, St. Anthony Parish, Louisiana 73506
Clearwater Oil Company
Regional Field Office
2451 Mountain Drive
Ridgeview, LA 70180
Corporate Headquarters
13000 Main Street, Suite 400
Houston, TX 77077
1.2 Contact Information
The designated person accountable for overall oil spill prevention and response at the facility,
also referred to as the facility's "Response Coordinator" (RC), is the Field Operations Manager,
Bill Laurier. 24-hour contact information is provided in Table 1-1.
Personnel from Avonlea Services Inc. ("Avonlea") provide operations (pumper/gauger) support
activities to Clearwater field personnel, including performing informal daily examinations of the
facility equipment, as described in Section 3.4 of this SPCC Plan. Avonlea personnel regularly
visit the facility to record production levels and perform other maintenance/inspection activities
as requested by the Clearwater Field Operations Manager. Key contacts for Avonlea are
included in Table 1-1.
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Clearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
Table 1-1: Facility contact information
Name
Lester Pearson
Carol Campbell
Bill Laurier
Joe Clark
William Mackenzie
Title
Vice-President of
Operations
Clearwater Oil Co.
Regional Director of
Operations
Clearwater Oil Co.
Field Operations
Manager
Clearwater Oil Co.
Field Supervisor
Avonlea Services, Inc.
Pumper
Avonlea Services, Inc.
Telephone
(555)-289-4500
(405) 831-6320 (office)
(405) 831-2262 (cell)
(405) 831-6322 (office)
(405) 829-4051 (cell)
(406) 545-2285 (office)
(406) 549-9087 (cell)
(406) 549-9087 (cell)
Address
13000 Main Street, Suite 400
Houston, TX 77077
2451 Mountain Drive
Ridgeview, LA 701 80
2451 Mountain Drive
Ridgeview, LA 701 80
786 Cherry Creek Road
Avonlea, LA 701 80
786 Cherry Creek Road
Avonlea, LA 701 80
1.3 Facility Layout Diagram
Appendix A, at the end of this Plan, shows a general site plan for the facility. The site plan
shows the site topography and the location of the facility relative to waterways, roads, and
inhabited areas. Appendix A also includes a detailed facility diagram that shows the wells,
flowlines, tank battery, and transfer areas for the facility. The diagram shows the location,
capacity, and contents of all oil storage containers greater than 55 gallons in capacity.
1.4 Facility Location and Operations
Clearwater owns and operates the Big Bear Lease No. 2 production facility, which is located
approximately six miles north of Madison, St. Anthony Parish, Louisiana (see Figure A-1 in
Appendix A). The site is accessed through a private dirt/gravel road off Route 417.
As illustrated in Figure A-2 in Appendix A, the facility is comprised of five main areas: Well A,
Well B, the saltwater disposal well, flowlines, and a tank battery. The tank battery includes three
400-barrel (bbl) oil storage tanks, one 500-bbl produced water tank, one 500-bbl gun barrel, and
associated flowlines and piping.
The production facility is generally unmanned. Clearwater's field office is located 25 miles from
the site, at 2541 Mountain Drive, Ridgeview, Louisiana. Field operations personnel from
Clearwater, or pumpers acting as contractors to Clearwater visit the facility daily (2-4 hours each
day) to record production rates and ensure the proper functioning of wellhead equipment and
pumpjacks, storage tanks, flowlines, and separation vessels. This includes performing
equipment inspections and maintenance as needed.
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Clearwater Oil Company, Ltd. SAMPLE Spill Prevention, Control, and
Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan
The facility produces an average of 30 bbl (1,260 gallons) of crude oil (approximately 40 API
gravity) and 140 bbl (5,880 gallons) of produced water each day. The produced water tank
contains an oil/produced water mixture. It is subject to 40 CFR part 112 and is covered by this
SPCC Plan.
1.5 Oil Storage and Handling
1.5.1 Production Equipment
Oil storage at the facility consists of one (1) 500-bbl gun barrel, three (3) 400-bbl aboveground
storage tanks, one (1) 500-bbl produced water tank, and associated piping, as summarized in
Table 1-2. The total oil capacity at this facility is 2,200 bbl (92,400 gallons).
All oil storage tanks are shop-built and meet the American Petroleum Institute (API) tank
construction standard. Their design and construction are compatible with the oil they contain
and the temperature and pressure conditions of storage. Tanks storing crude or produced oil
(#1 through #4) are constructed of welded steel following API-12F Shop Welded Tanks for
Storage of Production Liquids specifications. Steel tanks are coated to minimize corrosion. Tank
holding produced water (#5) constructed of fiberglass following API-12P Fiberglass Reinforced
Plastic Tanks specifications.
Other production equipment present at the facility include the pumpjacks at each well and water
pumps for transfer of saltwater to the injection well. These store a minimal amount of lubricating
oil (less than 55 gallons). Lubricating oil and other substances, such as solvents and chemicals
for downhole treatment, are also stored at the facility, but in quantities below the 55-gallon
threshold for SPCC applicability. Table 1-2 lists all oil containers present at the facility with
capacity of 55 gallons or more.
Table 1-2: Characteristics of oil containers
ID
#1
#2
#3
#4
#5
Type
Gun barrel
AST
AST
AST
AST
Construct
ion
Steel
Steel
Steel
Steel
Fiberglass
Primary
Content
Oil
Oil
Oil
Oil
Produced water
and oil mixture
TOTAL
Capacity
(barrels)
500
400
400
400
500
2,200
Capacity
(gallons)
21,000
16,800
16,800
16,800
21,000
92,400
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Clearwater Oil Company, Ltd. SAMPLE Spill Prevention, Control, and
Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan
1.5.2 Transfer Activities
Wells A and B produce crude oil, produced water (saltwater), and small amounts of natural gas.
The oil and water are produced through the tubing, while the natural gas is produced through
the casing. Well liquids are then routed via 2-inch steel flowlines to the gun barrel tank for
separation, while the gas is sent to a flare. Produced saltwater is routed from the gun barrel to
the 500-bbl saltwater storage tank first, then is pumped through flowlines to the saltwater
disposal well where it is injected. The disposal well is located approximately 2,000 ft to the west
of the tank battery. The crude oil is sent to the three 400-bbl (16,800-gallon) oil storage tanks.
Crude oil from the lease is purchased by Clearwater's crude oil purchaser and transported from
the facility by the purchaser's tanker truck. Although daily well production rates may vary,
enough crude is produced and stored for approximately one 180-bbl (7,560-gallon) load of oil to
be picked up weekly by the transporter. The largest tanker truck visiting the facility has a total
capacity of 210 bbl (8,820 gallons). Tanker trucks come to the facility only to transfer crude oil
and do not remain at the facility. All transfer operations are attended by the trucker or by field
operations personnel and meet the minimum requirements of the U.S. Department of
Transportation Hazardous Materials Regulations. Appendix B to this Plan summarizes the Tank
Truck Loading Procedure at this facility.
Produced saltwater is pumped via transfer pumps from the saltwater tank to the saltwater
disposal well, located approximately 2,000 feet west of the facility, by 2-inch PVC flowlines
(FLSW). The disposal well meets all requirements of the Underground Injection Control (UIC)
program (40 CFR parts 144-148).
1.6 Proximity to Navigable Waters
The facility is located within the Mines River watershed, approximately half a mile to the west of
Big Bear Creek, and six miles North of the Mines River. The wells and tank battery are situated
on relatively level ground that slopes in a general southeastern direction. The site plan in Figure
A-1 in Appendix A shows the location of the facility relative to nearby waterways. The facility
diagram included in Figure A-2 in Appendix A indicates the general direction of drainage. In the
event of an uncontrolled discharge from the wells, flowlines, or the tank battery areas, oil would
follow the natural topography of the site and flow into Big Bear Creek. Big Bear Creek meets
with the Mines River to the south just before the town of Madison. The River then flows in a
general easterly direction following Route 101.
1.7 Conformance with Applicable State and Local Requirements [112.7(j)]
The SPCC regulation at 40 CFR part 112 is more stringent than requirements from the state of
Louisiana for this type of facility. This SPCC Plan was written to conform with 40 CFR part 112
requirements. The facility thereby conforms with general requirements for oil pollution facilities
in Louisiana. All discharge notifications are made in compliance with local, state, and federal
requirements.
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Clearwater Oil Company, Ltd. SAMPLE Spill Prevention, Control, and
Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan
PART II. SPILL RESPONSE AND REPORTING
40CFR112.7
2.1 Discharge Discovery and Reporting [112.7(a)(3)]
Several individuals and organizations must be contacted in the event of an oil discharge. The
Field Operations Manager is responsible for ensuring that all required discharge notifications
have been made. All discharges should be reported to the Field Operations Manager. The
summary table included in Appendix F to this SPCC Plan provides a list of agencies to be
contacted under different circumstances. Discharges would typically be discovered during the
inspections conducted at the facility in accordance with procedures set forth in Section 3.4.1 of
this SPCC Plan, Table 3-3 and Table 3-4, and on the checklist of Appendix C. The Form
included in Appendix F of this Plan summarizes the information that must be provided when
reporting a discharge, including contact lists and phone numbers.
2.1.1 Verbal Notification Requirements (Local, State, and Federal (40 CFR part 110))
Any unauthorized discharge into air, land or water must be reported immediately to the State
Police and the Emergency Planning Commission as soon as the discharge is detected.
For any discharge that reaches navigable waters, or threatens to reach navigable waters,
immediate notification must be made to the National Response Center Hotline (800-424-8802)
and to the Environmental Protection Agency.
In the event of a discharge that threatens to result in an emergency condition, facility field
personnel must verbally notify the Louisiana Emergency Hazardous Materials Hotline (225-
925-6595) immediately, and in no case later than within one (1) hour of the discovery of the
discharge. An emergency condition is any condition that could reasonably be expected to
endanger the health and safety of the public; cause significant adverse impact to the land,
water, or air environment; or cause severe damage to property. This notification must be made
regardless of the amount of the discharge.
In the event of a discharge that does not present an emergency situation, verbal notification
must be made to the Office of Environmental Compliance (by telephone at 225-763-3908 during
office hours or 225-342-1234 after hours, weekends, and holidays; or by e-mail utilizing the
Incident Report Form and procedures found at www.deq.state.la.us/surveillance) within twenty-
four (24) hours of the discovery of the discharge.
2.1.2 Written Notification Requirements (State and Federal (40 CFR part 112))
A written notification will be made to EPA for any single discharge of oil to a navigable waters or
adjoining shoreline waterway of more than 1,000 gallons, or for two discharges of 1 bbl (42
gallons) of oil to a waterway in any 12-month period. This written notification must be made
within 60 days of the qualifying discharge, and a copy will be sent to the Louisiana Department
of Environmental Quality (DEQ), which is the state agency in charge of oil pollution control
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Clearwater Oil Company, Ltd. SAMPLE Spill Prevention, Control, and
Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan
activities. This reporting requirement is separate and in addition to reporting under 40 CFR part
110 discussed above.
For any discharge reported verbally, a written notification must also be sent to the DEQ and to
the St. Anthony's Parish Local Emergency Planning Committee (LEPC), both within five (5)
days of the qualifying discharge.
A written notification to the State Emergency Response Commission or LEPC is required for a
discharge of 100 Ibs or more beyond the confines of the facility (equivalent to 2 mcf of natural
gas, or 13 gallons of oil) within five (5) days of the qualifying discharge.
2.1.3 Submission of SPCC Information
Whenever the facility experiences a discharge into navigable waters of more than 1,000 gallons,
or two discharges of 42 gallons or more within a 12-month period, Clearwater will provide
information in writing to the EPA Region 6 office within 60 days of a qualifying discharge as
described above. The required information is described in Appendix F of this SPCC Plan.
2.2 Spill Response Materials
Boom, sorbent, and other spill response materials are stored in the shed next to the loading
area and are accessible by Clearwater and Avonlea personnel. The response equipment
inventory for the facility includes:
(4) Empty 55-gallons drums to hold contaminated material
(3) 50-ft absorbent socks
(4) 10-ft sections of hard skirted deployment boom
(2) 50-ft floating booms
(200 pounds) "Oil-dry" loose absorbent material
(4 boxes) 2 ft x 3 ft absorbent pads
(3 boxes) Nitrile gloves
(3 boxes) Neoprene gloves
(6 pairs) Vinyl/PVC pull-on overboots
(3) Non-sparking shovels
(3) Brooms
(20) Sand bags
(1) Combustible Gas Indicator with H2S detection capabilities
Additional equipment and material are also kept at the field office. The inventory is checked
monthly by Clearwater field operations personnel to ensure that used material is replenished.
Supplies and equipment may be ordered from:
(1) Rocky Mountain Equipment Co. (800) 959-3000
(2) Quick Sorbent (800) 857-4650.
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Clearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
Reminder: In the event of a discharge
originating from Flowline A or Flowline B,
facility personnel must immediately
implement the Oil Spill Contingency Plan.
The Oil Spill Contingency Plan discusses
the additional procedures that must be
followed to respond to a discharge of oil to
navigable waters or adjoining shorelines.
2.3 Spill Mitigation Procedures
The following is a summary of actions that must be
taken in the event of a discharge. It summarizes the
distribution of responsibilities among individuals and
describes procedures to follow in the event of a
discharge.
A complete outline of actions to be performed in the
event of a discharge from flowlines reaching or
threatening to reach navigable waters is included in
the facility Contingency Plan (see Appendix I of this
SPCC Plan).
In the event of a discharge, Clearwater or contractor field personnel and the Field Operations
Manager shall be responsible for the following:
2.3.1 Shut Off Ignition Sources
Field personnel must shut off all ignition sources, including motors, electrical circuits, and open
flames. See Appendix G for more information about shut-off procedures.
2.3.2 Stop Oil Flow
Field personnel should determine the source of the discharge, and if safe to do so, immediately
shut off the source of the discharge. Shut in the well(s) if necessary.
2.3.3 Stop the Spread of Oil and Call the Field Operations Manager
If safe to do so, field personnel must use resources available at the facility (see spill response
material and equipment listed in Section 2.2) to stop the spilled material from spreading.
Measures that may be implemented, depending on the location and size of the discharge,
include placing sorbent material or other barriers in the path of the discharge (e.g., sand bags),
or constructing earthen berms or trenches.
In the event of a significant discharge, field personnel must immediately contact the Field
Operations Manager, who may obtain assistance from authorized company contractors and
direct the response and cleanup activities. Should a discharge reach Big Bear Creek, only
physical response and countermeasures should be employed, such as the construction of
underflow dams, installation of hard boom and sorbent boom, use of sorbent pads, and use of
vacuum trucks to recover oil and oily water from the creek. If water flow is low in the creek,
construction of an underflow dam downstream and ahead of the spill flow may be
advantageous. Sorbent material and/or boom should be placed immediately downstream of the
dam to recover any sheen from the water. If water flow is normal in the creek, floating booms
and sorbent boom will be deployed. Vacuum trucks will then be utilized to remove oil and oily
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water at dams and other access points. Crews should remove oiled vegetation and debris from
the creek banks and place them in bags for later disposal. After removal of contaminated
vegetation, creek banks should be flushed with water to remove free oil and help it flow down to
dams and other access points where it can be recovered by vacuum truck. At no time shall any
surfactants, dispersants, or other chemicals be used to remove oil from the creek.
2.3.4 Gather Spill Information
The Field Operations Manager will ensure that the Discharge Notification Form is filled out and
that notifications have been made to the appropriate authorities. The Field Operations Manager
may ask for assistance in gathering the spill information on the Discharge Notification Form
(Appendix F) of this Plan:
Reporter's name
Exact location of the spill
Date and time of spill discovery
Material spilled (e.g., oil, produced water containing a reportable quantity of oil)
Total volume spilled and total volume reaching or threatening navigable waters or
adjoining shorelines
Weather conditions
Source of spill
Actions being taken to stop, remove, and mitigate the effects of the discharge
Whether an evacuation may be needed
Spill impacts (injuries; damage; environmental media, e.g., air, waterway,
groundwater)
Names of individuals and/or organizations who have also been contacted
2.3.5 Notify Agencies Verbally
Some notifications must be completed immediately upon discovering the discharge. It is
important to immediately contact the Field Operations Manager so that timely notifications can
be made. If the Field Operations Manager is not available, or the Field Operations Manager
requests it, field personnel must designate one person to begin notification. Section 2.1 of this
Plan describes the required notifications to government agencies. The Notification List is
included in Appendix F of this SPCC Plan. The Field Operations Manager must also ensure that
written notifications, if needed, are submitted to the appropriate agencies.
2.4 Disposal Plan
The cleanup contractor will handle the disposal of any recovered product, contaminated soil,
contaminated materials and equipment, decontamination solutions, sorbents, and spent
chemicals collected during a response to a discharge incident.
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Any recovered product that can be recycled will be placed into the gun barrel tank to be
separated and recycled. Any recovered product not deemed suitable for on-site recycling will be
disposed of with the rest of the waste collected during the response efforts.
If the facility responds to a discharge without involvement of a cleanup contractor, Clearwater
will contract a licensed transportation/disposal company to dispose of waste according to
regulatory requirements. The Field Operations Manager will characterize the waste and arrange
for the use of certified waste containers.
All facility personnel handling hazardous wastes must have received both the initial 40-hour
and annual 8-hour refresher training in the Hazardous Waste Operations and Emergency
Response Standard (HAZWOPER) of the Occupational Health and Safety Administration
(OSHA). This training is included as part of the initial training received by all field personnel.
Training records and certificates are kept at the field office.
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PART III. SPILL PREVENTION, CONTROL, AND
COUNTERMEASURE PROVISIONS
40 CFR 112.7 and 112.9
3.1 Potential Discharge Volume and Direction of Flow [112.7(b)] and
Containment [112.7(a)(3)(iii)]
Table 3-1, below, summarizes potential oil discharge scenarios. If unimpeded, oil would follow
the site topography and reach Big Bear Creek.
Table 3-1: Potential discharge volume and direction of flow
Source
Tank Battery
Crude Oil Storage Tank
Gun barrel
Flowlines and Piping
Flow/lines and Piping on
Storage Tanks and Gun
Barrel
Flowlines and Piping
associated with wells
Type of failure
Rupture due to
lightning strike,
seam failure
Leak at manway,
valves
Overflow (1 day's
production)
Rupture due to
lightning strike,
seam failure
Leak at manway,
valves
Overflow (1 day's
production)
Rupture/failure
due to corrosion
Pinhole leak, or
leak at
connection
Rupture/failure
due to corrosion
Maximum Maximum
Volume Discharge
(gal) Rate (gal/hr)
16,800 16,800
24 1
1,260 53
21,000 21,000
42 2
7,140 298
3,570 148
48 2
3,570 148
Direction of Flow
Southeast towards Big
Bear Creek.
Southeast towards Big
Bear Creek.
Southeast towards Big
Bear Creek.
Southeast towards Big
Bear Creek.
Southeast towards Big
Bear Creek.
Southeast towards Big
Bear Creek.
Southeast towards Big
Bear Creek.
Southeast towards Big
Bear Creek.
Southeast towards Big
Bear Creek.
Containment
Containment
berm
Containment
berm
Containment
berm
Containment
berm
None; See Oil
Spill
Contingency
Plan
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Source
Wells
Polished rod stuffing box
valves, fittings, gauges
Saltwater Disposal
Piping/hoses, pumps,
valves
Transfers and Loading
Transport truck loading
hose
Offload line, connection
Tank truck
Transfer valve
Type of failure
Pinhole leak, or
leak at
connection
Leak
Leak
Operations
Rupture
Leak
Over-topping
while loading
Rupture, leak of
valve packing
Maximum Maximum Direction of Flow
Volume Discharge
(gal) Rate (gal/hr)
48 2 Southeast towards Big
Bear Creek.
24 1 Southeast towards Big
Bear Creek.
24 1 Southeast towards Big
Bear Creek.
84 84 Southeast towards Big
Bear Creek.
42 1 Southeast towards Big
Bear Creek.
1,680 1,680 Southeast towards Big
Bear Creek.
3 3 Southeast towards Big
Bear Creek.
Containment
None; See Oil
Spill
Contingency
Plan
Well pad
Containment
berm
Downslope
berm
Downslope
berm
Drainage ditch
Load line
container, curb
3.2 Containment and Diversionary Structures [112.7(c) and 112.7(a)(3)(iii)]
The facility is configured to minimize the likelihood of a discharge reaching navigable waters.
The following measures are provided:
Secondary containment for the oil storage tanks, saltwater tank (which may have
small amounts of oil), and gun barrel is provided by a 60 ft x 40 ft x 2.5 ft earthen
berm that provides a total containment volume of 867 barrels (36,423 gallons), as
described in Section 3.2.2 below. The berm is constructed of native soils and
heavy clay that have been compacted, then covered with gravel. A clay layer in
the shallow subsurface exists naturally and will stop any spilled oil from seeping
to deeper groundwater.
The tank truck loading area is flat but gently slopes to the southeast, where a
crescent-shaped, open berm has been placed to catch any potential spills from
tanker transport trucks. The bermed area provides a catchment basin of 40
barrels (1,680 gallons), the maximum expected amount of a spill from the tanker
due to overtopping of the truck during loading. In addition, the end of the load line
is equipped with a load line drip bucket designed to prevent small discharges that
may occur when disconnecting the hose.
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Booms, sorbents, shovels, and other discharge response materials are stored in
a shed located in close proximity to the loading area. This material is sufficient to
contain small discharges (up to approximately 200 gallons).
These measures are described in more details in the following sections.
3.2.1 Oil Production Facility Drainage [112.9(b)]
Facility drainage in the production/separation area but outside containment berms is designed
to flow into drainage ditches located on the eastern and southern boundaries of the site. These
ditches usually run dry. The ditches are visually examined by facility personnel on a daily basis
during routine facility rounds, during formal monthly inspections, and after rain events, to detect
any discoloration or staining that would indicate the presence of oil from small leaks within the
facility. Any accumulation of oil is promptly removed and disposed off site. Formal monthly
inspections are documented.
Discharges from ASTs are restrained by the secondary containment berm, as described in
Section 3.2.2 of this Plan. Discharges occurring during transfer operations will be contained at
each well by the rock pad or will flow into the drainage ditch located at the facility.
3.2.2 Secondary Containment for Bulk Storage Containers [112.9(c)(2)]
In order to further minimize the potential for a discharge to navigable waters, bulk storage
containers such as all tank battery, separation, and treating equipment are placed inside a 2.5-ft
tall earthen berm (fire wall). The berm capacity exceeds the SPCC and Louisiana requirements.
It provides secondary containment sufficient for the size of the largest tank, plus at least 1 ft of
freeboard to contain precipitation. This secondary containment capacity is equivalent to 173
percent of the capacity of the largest tank within the containment area (500 barrels) and
exceeds the 10 percent freeboard recommended by API for firewalls around production tanks
(API-12R1). The amount of freeboard also exceeds the amount of precipitation anticipated at
this facility, which is estimated to average 3.5 inches for a 24-hour, 25-year storm, based on
data from the nearby Ridgeview Regional Airport. Details of the berm capacity calculation are
provided in Table 3-2.
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Table 3-2: Berm capacity calculations
Berm Capacity
Berm height 2.5 ft
Berm dimensions 60 ft x 40 ft = 2,400 ft2
Tank footprint 4 tanks @ 12 ft dia. each = 4 x (n 122/4) = 452 ft2
Net volume 2.5 ft x (2,400 - 452) = 4,869 ft3 = 36,423 gallons
Ratio to largest tank 36,423/21,000= 173%
Corresponding Amount of Freeboard
100% of tank volume 21,000 gallons = 2,807 ft3
Net area (minus tank footprint) 2,400 ft2 - 452 ft2 = 1,948 ft2
Minimum berm height for 100% of tank volume 2,807 ft3/ 1,948ft2 = 1.44ft
Freeboard 2.5 ft-1.44 ft = 1.06 ft
The floor and walls of the berm are constructed of compacted earth with a layer of clay that
ensures that the berm is able to contain the potential release of oil from the storage tanks until
the discharge can be detected and addressed by field operations personnel. Facility personnel
inspect the berm daily for the presence of oil. The sides of the berm are capped with gravel to
minimize erosion.
The berm is equipped with a manual valve of open-and-closed design. The valve is used to
drain the berm and is normally kept closed, except when draining water accumulation within the
berm. Drainage from the berm flows into the drainage ditch to the south of the production/
separation area. All water is closely inspected by field operations personnel (who are the
persons providing "responsible supervision") prior to draining water accumulation to ensure that
no free oil is present (i.e., there is no sheen or discoloration upon the surface, or a sludge or
emulsion deposit beneath the surface of the water). The bypass valve for the containment
structure is opened and resealed following drainage under the responsible supervision of field
operations personnel. Free oil is promptly removed and disposed of in accordance with waste
regulations. Drainage events are recorded on the form provided in Appendix D, including the
time, date, and name of the employee who performed the drainage. The records are maintained
with this SPCC Plan at the Ridgeview field office for a period of at least three years.
3.2.3 Practicability of Secondary Containment [112.7(d)]
Flowlines adjacent to the production equipment and storage tanks are located within the berm,
and therefore have secondary containment. Aboveground flowlines that go from the wells to the
production equipment and buried flowlines, however, lack adequate secondary containment.
The installation of double-wall piping, berms, or other permanent structures (e.g., remote
impoundment) are impracticable at this facility due to the long distances involved and physical
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and road/fenceline right-of-way constraints. Additionally, such permanent structures would
create land erosion and access problems for the landowner's farming operations and current
uses of the land (e.g., agricultural production, animal grazing).
Other measures listed under 40 CFR 112.7(c) such as the use of sorbents are also
impracticable as means of secondary containment since the volumes involved may exceed the
sorbent capacity and the facility is attended for only a few hours each day.
Because secondary containment for flowlines outside of the tank battery is impracticable,
Clearwater has provided with this Plan additional elements required under 40 CFR 112.7(d),
including:
A written commitment of manpower, equipment, and materials required to
expeditiously control and remove any quantity of oil discharged that may be
harmful (see Appendix H).
An Oil Spill Contingency Plan following the provisions of 40 CFR 109 (see
Appendix I).
3.3 Other Spill Prevention Measures
3.3.1 Bulk Storage Containers Overflow Prevention [112.9(c)(4)]
The tank battery is designed with a fail-safe system to prevent discharge, as follows:
The capacity of the oil storage tanks is sufficient to ensure that oil storage is
adequate in the event where facility personnel are unable to perform the daily
visit to unload the tanks or the pumper is delayed in stopping production. The
maximum capacity of the wells linked to the tank battery is approximately 600
barrels per day. The oil tanks are sized to provide sufficient storage for at least
two days.
The tanks are connected with overflow equalizing lines to ensure that a full tank
can overflow to an adjacent tank.
3.3.2 Transfer Operations and Saltwater Disposal System [112.9(d)]
All aboveground valves and piping associated with transfer operations are inspected daily by
the pumper and/or tank truck driver, as described in Section 3.4 of this Plan. The inspection
procedure includes observing flange joints, valve glands and bodies, drip pans, and pipe
supports. The conditions of the pumping well polish rod stuffing boxes, and bleeder and gauge
valves, are inspected monthly.
Components of the produced water disposal system are inspected on a monthly basis by field
operation personnel as described in Section 3.4 and following the checklist provided in
Appendix C of this SPCC Plan. This includes the pumps and motors for working condition and
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leaks, hoses, valves, flowlines, and the saltwater injection wellhead. Maintenance and operation
of the well itself and the downhole injection comply with EPA's and the state's Underground
Injection Control (UIC) rules and regulations (40 CFR parts 144-148).
3.4 Inspections, Tests, and Records [112.7(e)]
This Plan outlines procedures for inspecting the facility equipment in accordance with SPCC
requirements. Records of inspections performed as described in this Plan and signed by the
appropriate supervisor are a part of this Plan, and are maintained with this Plan at the
Ridgeview field office for a minimum of three years. The reports include a description of the
inspection procedure, the date of inspection, whether drainage of accumulated rainwater was
required, and the inspector's signature.
The program established in this SPCC Plan for regular inspection of all oil storage tanks and
related production and transfer equipment follows the American Petroleum Institute's
Recommended Practice for Setting Maintenance, Inspection, Operation, and Repair of Tanks in
Production Service (API RP 12R1, Fifth Edition, August 1997). Each container is inspected
monthly by field operation personnel as described in this Plan section and following the
checklist provided in Appendix C of this SPCC Plan. The monthly inspection is aimed at
identifying signs of deterioration and maintenance needs, including the foundation and support
of each container. Any leak from tank seams, gaskets, rivets, and bolts is promptly corrected.
This Plan also describes provisions for monitoring the integrity of flowlines through a
combination of monthly visual inspections and periodic pressure testing or through the use of an
alternate technology. The latter element is particularly important for this facility since flowlines
do not have adequate secondary containment.
The inspection program is comprised of informal daily examinations, monthly scheduled
inspections, and periodic condition inspections. Additional inspections and/or examinations are
performed whenever an operation alert, malfunction, shell or deck leak, or potential bottom leak
is reported following a scheduled examination. Written examination/inspection procedures and
monthly examination/inspection reports are signed by the field inspector and are maintained at
the field office for a period of at least three years.
3.4.1 Daily Examinations
The facility is visited daily by field operations personnel. The daily visual examination consists of
a walk through of the tank battery and around the wells. Field operations personnel check the
wells and production equipment for leaks and proper operation. They examine all aboveground
valves, polished rod stuffing boxes, wellheads, fittings, gauges, and flowline piping at the
wellhead. Personnel inspect pumps to verify proper function and check for damage and
leakage. They look for accumulation of water within the tank battery berms and verify the
condition and position of valves. The storage tanks are gauged every day. A daily production
report is maintained. All malfunctions, improper operation of equipment, evidence of leakage,
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stained or discolored soil, etc. are logged and communicated to the Clearwater Field Operations
Manager.
Table 3-3: Scope of daily examinations
Facility Area
Item
Observations
Storage Tanks (Oil
and Produced water)
Leaks
Wells
SW Pumps
Foundation problems
Flow/lines problems
Leak
Leaks
Tank liquid level gauged
Drip marks, leaks from weld seams, base of tank
Puddles containing spilled or leak material
Corrosion, especially at base (pitting, flaking)
Cracks in metal
Excessive soil or vegetation buildup against base
Cracks
Puddles containing spilled or leaked material
Settling
Gaps at base
Evidence of leaks, especially at connections/collars
Corrosion (pitting, flaking)
Settling
Evidence of stored material seepage from valves or
seals
Evidence of oil seepage from pumping rod stuffing
boxes, wellhead and wellhead flowlines, valves, gauges
Leaks at seals, flowlines, valves, hoses
Puddles containing spilled or leaked material
Corrosion
3.4.2 Monthly Inspections
Table 3-4 summarizes the scope of monthly inspections performed by field personnel.
The monthly inspection covers the wellheads, flowlines, and all processing equipment. It also
includes verifying the proper functioning of all detection devices, including high-level sensors on
oil storage tanks, heater treater, and separators. Storage tanks are inspected for signs of
deterioration, leaks, or accumulation of oil inside the containment area, or other signs that
maintenance or repairs are needed. The secondary containment area is checked for proper
drainage, general conditions, evidence of oil, or signs of leakage. The monthly inspection also
involves visually inspecting all aboveground valves and pipelines and noting the general
condition of items such as transfer hoses, flange joints, expansion joints, valve glands and
bodies, catch pans, pipeline supports, pumping well pumping rod stuffing boxes, bleeder and
gauge valves, locking of valves, and metal surfaces.
The checklist provided in Appendix C is used during monthly inspections. These inspections are
performed in accordance with written procedures such as API standards (e.g., API RP 12R1),
engineering specifications, and maintenance schedule developed by the equipment
manufacturers.
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All safety devices are tested quarterly by a third party inspector. The tests are recorded and the
results are maintained with this Plan at Clearwater's field office. Testing of the safety devices is
conducted in accordance with guidelines API RP-14C published by the American Petroleum
Institute, or in accordance with instructions from the device's manufacturer. Written test
procedures are kept at the offices of the third party testing company and are available upon
request.
Twice a year, facility personnel drive to the pre-established response staging areas located at
three different points along Big Bear Creek (see Oil Spill Contingency Plan in Appendix I) to
ensure that the dirt/gravel roads are accessible using field vehicles and that the Oil Spill
Contingency Plan can be implemented in the event of a discharge from flowlines reaching the
Creek.
Table 3-4: Scope of monthly inspections
Facility Area
Equipment
Inspection Item
Tank Battery
Storage tanks
Area
Truck Loading
Wells (including
saltwater disposal
well)
Offload lines, drip pans,
valves, catchment berm
Production equipment
Area
Leakage, gaskets, hatches
Tank liquid level checked
Tank welds in good condition
Vacuum vents
Overflow lines
Piping, valves, and bull plugs
Corrosion, paint condition
Pressure / level safety devices*
Emergency shut-down system(s)*
Pressure relief valves*
Berm and curbing
Presence of contaminated/stained soil
Excessive vegetation
Equipment protectors and signs
Engine drip pans and sumps
General housekeeping
Valve closed and in good condition
Cap or bull plug at end of offload line/connection
Sign of oil or standing water in drip pan(s)
Sign of oil or standing water in catchment berm
Sign of oil in surrounding area
Gauges (pressure, temperature, and liquid level)
Pressure / level safety devices*
Emergency shut-down system(s)*
Pressure relief valves*
Spills and leaks (e.g., stuffing box)
Equipment protectors and signs
General housekeeping
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Facility Area
Equipment
Inspection Item
Leasehold area
between wells and
Tank Battery
Flowlines
Other
Response staging
areas
Road and Field Ditches
Chemicals, Fuels and Lube
Oils
Area
Flowline between the well and tank battery/gun barrel
Exposed line of buried piping
Valves (condition of, whether locked or sealed)
Evidence of leaks and/or damage, especially at
connections/collars
Corrosion (pitting, flaking)
Pipe supports
Evidence/puddles of crude oil and/or produced water
Storage conditions
Road practicable by field vehicle
Area clear of excessive vegetation
' Tested quarterly by third party inspection company.
3.4.3 Periodic Condition Inspection of Bulk Storage Containers
A condition inspection of bulk storage containers is performed by a qualified inspector according
to the schedule and scope specified in API RP 12R1. The schedule is determined based on the
corrosion rate; with the first inspection performed no more than 15 years after the tank
construction, as detailed in Table 3-5.
Three bulk storage containers installed at this facility were moved from another facility
decommissioned by Clearwater. These bulk storage containers were leak tested after relocation
to the facility.
Table 3-5: Schedule of periodic condition inspection of bulk storage containers
Tank
#1
#2
#3
#4
#5
Year Built
1983
2002
1995
2002
1991
Last Inspection
11/5/1998
None
None
None
None
Next inspection by
11/5/2008*
First inspection to be performed by 12/31/2017*
First inspection to be performed by 12/31/2010*
First inspection to be performed by 12/31/2017*
First inspection to be performed by 12/31/2006*
* Dates for subsequent external inspections must follow the recommendations of the certified inspector, not to exceed
three-quarters of the predicted shell/roof deck corrosion rate life, or maximum of 15 years.
3.4.4 Brittle Fracture Evaluation [112.7(i)]
At the present time, none of the bulk storage containers at this site was field-erected, and
therefore no brittle fracture evaluation is required.
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3.4.5 Flowline Maintenance Program [112.9(d)(3)]
Because the facility is relying on a contingency plan to address discharges, the flowline
maintenance program is specifically implemented to maintain the integrity of the primary
container (in this case piping) to minimize releases of oil from this part of the production facility.
The facility's gathering lines and flowlines are configured, inspected monthly for leaks at
connections and on each joint, corrosion (pitting, flaking), and maintained to minimize the
potential for a discharge as summarized in Table 3-6. Records of integrity inspections, leak
tests, and part replacements are kept at the facility for at least three years (integrity test results
are kept for ten years).
Table 3-6: Components of flowline maintenance program
Component Measures/Activities
Configuration • Well pumps are equipped with low-pressure shut-off systems that detect
pressure drops and minimize spill volume in the event of a flowline leak.
Flowlines are identified on facility maps and are marked in the field to facilitate
access and inspection by facility personnel. Flowline maps and field tags
indicate the location of shutdown devices and valves that may be used to
isolate portions of the flowline.
With the exception of a portion of Flowline B under an access road, the
flowlines and appurtenances (valves, flange joints, supports) can be visually
observed for signs of leakage, deterioration, or other damage.
Inspection • Lines are visually inspected for leaks and corrosion as part of the monthly
rounds by field personnel, as discussed in Section 3.4 above.
The buried portions of Flowline B are coated/wrapped and visually observed
for damage or coating condition whenever they are repaired, replaced, or
otherwise exposed.
Every five years, flowlines are tested using ultrasonic techniques to determine
remaining wall thickness and mechanical integrity. Copies of test results are
maintained at the facility for ten years to allow comparison of successive tests.
Maintenance • Any leak in the flowline or appurtenances is promptly addressed by isolating
the damaged portion and repairing or replacing the faulty piece of equipment.
Clearwater does not accept pipe clamps and screw-in plugs as forms of repair.
Any portion of a flowline that fails the mechanical integrity test is repaired and
retested, or replaced.
3.5 Personnel, Training, and Discharge Prevention Procedures [112.7(f)]
The Field Operations Manager has been designated as the point of contact for all oil discharge
prevention and response at this facility.
All Clearwater field personnel receive training on proper handling of oil products and procedures
to respond to an oil discharge prior to entering any Clearwater production facility. The training
ensures that all facility personnel understand the procedures described in this SPCC Plan and
are informed of the requirements under applicable pollution control laws, rules and regulations.
The training also covers risks associated with potential exposure to hydrogen sulfide (H2S) gas.
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All Clearwater field personnel also receive an initial 40-hour HAZWOPER training (and 8-hour
annual refresher training) as per OSHA standard.
Clearwater ensures that all contractor personnel are familiar with the facility operations, safety
procedures, and spill prevention and control procedures described in this Plan prior to working
at the facility. All contractors working at the facility receive a copy of this SPCC Plan. Avonlea
personnel visiting the facility receive training similar to that provided to Clearwater oil handling
employees.
Clearwater management holds briefings with field operations personnel (including contractor
personnel as appropriate) at least once a year, as described below.
3.5.1 Spill Prevention Briefing
The Field Operations Manager conducts Spill Prevention Briefings annually to ensure adequate
understanding and effective implementation of this SPCC Plan. These briefings highlight and
describe known spill events or failures, malfunctioning components, and recently developed
precautionary measures. The briefings are conducted in conjunction with the company safety
meetings. Sign-in sheets, which include the topics of discussion at each meeting, are
maintained with this Plan at Clearwater's field office. A Discharge Prevention Briefing Log form
is provided in Appendix E to this Plan and is used to document the briefings. The scheduled
annual briefing includes a review of Clearwater policies and procedures relating to spill
prevention, control, cleanup, and reporting; procedures for routine handling of products (e.g.,
loading, unloading, transfers); SPCC inspections and spill prevention procedures; spill reporting
procedures; spill response; and recovery, disposal, and treatment of spilled material.
Personnel are instructed in operation and maintenance of equipment to prevent the discharge of
oil, and in applicable federal, state, and local pollution laws, rules, and regulations. Facility
operators and other personnel have an opportunity during the briefings to share
recommendations concerning health, safety, and environmental issues encountered during
facility operations.
The general outline of the briefings is as follows:
Responsibilities of personnel and Designated Person Accountable for Spill
Prevention;
Spill prevention regulations and requirements;
Spill prevention procedures;
Spill reporting and cleanup procedures;
History/cause of known spill events;
Equipment failures and operational issues;
Recently developed measures/procedures;
Proper equipment operation and maintenance; and
Procedures for draining rainwater from berms.
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Clearwater Oil Company, Ltd. SAMPLE Spill Prevention, Control, and
Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan
3.5.2 Contractor Instructions
In order that there will be no misunderstanding on joint and respective duties and
responsibilities to perform work in a safe manner, contractor personnel also receive instructions
on the procedures outlined in this SPCC Plan. The instructions cover the contractor activities
such as servicing a well or equipment associated with the well, such as pressure vessels.
All contractual agreements between Clearwater and contractors specifically state:
Personnel must, at all times, act in a manner to preserve life and property, and prevent
pollution of the environment by proper use of the facility's prevention and containment
systems to prevent hydrocarbon and hazardous material spills. No pollutant, regardless of
the volume, is to be disposed of onto the ground or water, or allowed to drain into the
ground or water. Federal regulations impose substantial fines and/or imprisonment for
willful pollution of navigable waters. Failure to report accidental pollution at this facility, or
elsewhere, can be cause for equally severe penalties to be imposed by federal
regulations. To this end, all personnel must comply with every requirement of this SPCC
Plan, as well as taking necessary actions to preserve life, and property, and to prevent
pollution of the environment. It is the contractor's (or subcontractor's) responsibility to
maintain his equipment in good working order and in compliance with this SPCC Plan.
The contractor (or subcontractor) is also responsible for the familiarity and compliance of
his personnel with this SPCC Plan. Contractor and subcontractor personnel must secure
permission from Clearwater's Field Operations Manager before commencing any work on
any facility. They must immediately advise the Field Operations Manager of any
hazardous or abnormal condition so that the Field Operations Manager can take
corrective measures.
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Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
APPENDIX A: Facility Diagrams
JO.
Figure A-1: Site plan.
n
Big
Beai* |
Big Bear Lease
ctioij
"Facility \! Vi
'111
Staging
\2
St Samuel '.II -~ \
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Clearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
FLA
2 inch diameter steei
Approx length 2,100 ft
FLB
2 inch diameter steel
Approx length 3,400ft
BOX 1. Saltwater Disposal Well Area
To production area
- — Approx. length
2,000 ft
Clearwater Oil Company
Big Bear Lease No. 2 Production Facility
Facility Diagram
Rev. 11/12/02
Drawing
not to
seals
Figure A-2: Production Facility Diagram.
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Clearwater Oil Company, Ltd. SAMPLE Spill Prevention, Control, and
Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan
APPENDIX B: Tank Truck Loading Procedures
Loading Tank Truck
Make sure the vehicle tank is properly vented before starting to load or unload. If you are not
certain that the trailer is properly vented, you must contact your supervisor and request
permission to open the trailer dome before starting to load or unload.
To Load from Storage Tank to Tank Truck
Attach ground cable or bonding clamp to trailer.
Use wheel chocks or other similar barrier to prevent premature departure.
Hook up load hose and open all appropriate valves from storage tank to trailer
entry.
Disengage clutch and place pump in load position.
Release clutch slowly.
Adjust throttle to proper engine RPM.
When trailer is loaded to appropriate level, slow engine speed.
Close valve to storage tank.
Loosen loading hose to allow enough air to drain loading hose dry.
Ensure that drips from the hose drain into the spill bucket at the loading area.
Disconnect loading hose completely, close load valve, plug and fasten securely.
Close belly valve on trailer.
Disconnect ground cable.
Promptly clean up any spilled oil.
Inspect lowermost drains and valves of the vehicle for discharges/leaks and
ensure that they are tightened, adjusted, or replaced as needed to prevent
discharges while vehicle is in transit.
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Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
APPENDIX C: Monthly Inspection Checklist
Further description and comments, if needed, should be provided on a separate sheet of paper and attached to this
sheet. Any item answered "YES" needs to be promptly reported, repaired, or replaced, as it may result in non-
compliance with regulatory requirements. Records are maintained with the SPCC Plan at the Ridgeview field office.
Date:
Signature:
Yes
No
Description & Comments
(Note tank/equipment ID)
Storage tanks and Separation Equipment
Tank surfaces show signs of leakage
Tanks show signs of damage, rust, or deterioration
Bolts, rivets or seams are damaged
Aboveground tank supports are deteriorated or buckled
Aboveground tank foundations have eroded or settled
Gaskets are leaking
Level gauges or alarms are inoperative
Vents are obstructed
Thief hatch and vent valve does not seal air tight
Containment berm shows discoloration or stains
Berm is breached or eroded or has vegetation
Berm drainage valves are open/broken
Tank area clear of trash and vegetation
Equipment protectors, labels, or signs are missing
Piping/Flowlines and Related Equipment
Valve seals or gaskets are leaking.
Pipelines or supports are damaged or deteriorated.
Buried pipelines are exposed.
Transfer equipment
Loading/unloading lines are damaged or deteriorated.
Connections are not capped or blank-flanged
Secondary containment is damaged or stained
Response Kit Inventory
Discharge response material is missing or damaged or
needs replacement
Additional Remarks (attach sheet as needed):
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Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
APPENDIX D: Record of Dike Drainage
This record must be completed when rainwater from diked areas is drained into a storm drain or into an open
watercourse, lake, or pond, and bypasses the water treatment system. The bypass valve must normally be sealed in
closed position and opened and resealed following drainage under responsible supervision. Records are maintained
with the SPCC Plan at the Ridgeview field office.
Date
12/5/2003
Area
Tank battery
Presence of
Oil
No oil
Time
Started
08:00
Time
Finished
8:40
Signature
William Mackenzie
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Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
APPENDIX E: Discharge Prevention Briefing Log
Date
12/5/2003
11/25/2004
Type of Briefing
Scheduled refresher. All field personnel.
Scheduled refresher. All field personnel.
Instructors)
Helena Berry, Optimal H&S Inc.
Bill Laurier
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Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
APPENDIX F: Discharge Notification Procedures
Circumstances, instructions, and phone numbers for reporting a discharge to the National
Response Center and other federal, state, and local agencies, and to other affected parties, are
provided below. They are also posted at the facility in the storage shed containing the discharge
response equipment. Note that any discharge to water must be reported immediately to the
National Response Center.
Field Operations Manager, Bill Laurier (24 hours)
Local Emergency (fire, explosion, or other hazards)
(405) 829-4051
911
Agency / Organization
Federal Agencies
National Response
Center
EPA Region VI
(Hotline)
EPA Region VI
Regional Administrator
Sfafe Agencies
Office of State Police,
Transportation and
Environmental Safety
Section, Hazardous
Materials Hotline
Office of State Police,
Transportation and
Environmental Safety
Section, Hazardous
Materials Hotline
Louisiana Department
of Environmental
Quality, Office of
Environmental
Compliance
Agency Contact
1-800-424-8802
1-800-887-6063
First Interstate Bank
Tower at Fountain
Place
1445 Ross Avenue,
12th floor, Suite 1200
Dallas TX 75202
225-925-6595
or
1-877-925-6595
225-925-6595
or
1-877-925-6595
225-763-3908
or 225-342-1 234
(after business
hours, weekends
and holidays)
Circumstances
Discharge reaching navigable
waters.
Discharge 1,000 gallons or
more; or second discharge of 42
gallons or more over a 12-month
period.
1) Injury requiring hospitalization
or fatality.
2) Fire, explosion, or other
impact that could affect public
safety.
3) Release exceeding 24-hour
reportable quantity.
4) Impact to areas beyond the
facility's confines.
Discharges that pose
emergency conditions,
regardless of the volume
discharged.
Discharges that do not pose
emergency conditions.
When to Notify
Immediately (verbal)
Immediately (verbal)
Written notification within
60 days (see Section 2.1 of
this Plan)
Immediately (verbal)
Written notification to be
made within 5 days.
Within 1 hour of discovery
(verbal).
Written notification within 7
working days.
Within 24 hours of
discovery (verbal).
Written notification within 7
working days.
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Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
Agency / Organization
Local Agencies
St. Anthony's Parish
Emergency Planning
Committee
Offers
Response/cleanup
contractors
Howard Fleming Farm
(agricultural irrigation
intake)
Agency Contact
337-828-1960
EZ Clean
(800)521-3211
Armadillo Oil
Removal Co.
(214)566-5588
(405) 235-6893
Circumstances
Any discharge of 100 Ibs or
more that occur beyond the
boundaries of the facility,
including to the air.
Any discharge that exceeds the
capacity of facility personnel to
respond and cleanup.
Any discharge that threatens to
affect neighboring properties
and irrigation intakes.
When to Notify
Immediately (verbal)
Written notification within 7
days.
As needed
As needed
The person reporting the discharge must provide the following information:
Name, location, organization, and telephone number;
Name and address of the owner/operator;
Date and time of the incident;
Location of the incident;
Source and cause of discharge;
Types of material(s) discharged;
Total quantity of materials discharged;
Quantity discharged in harmful quantity (to navigable waters or adjoining
shorelines);
Danger or threat posed by the release or discharge;
Description of all affected media (e.g., water, soil);
Number and types of injuries (if any) and damaged caused;
Weather conditions;
Actions used to stop, remove, and mitigate effects of the discharge;
Whether an evacuation is needed;
Name of individuals and/or organizations contacted; and
Any other information that may help emergency personnel respond to the
incident.
Whenever the facility discharges more than 1,000 gallons of oil in a single event, or discharges
more than 42 gallons of oil in each of two discharge incidents within a 12-month period, the
Manager of Field Operations must provide the following information to the U.S. Environmental
Protection Agency's Regional Administrator within 60 days:
Name of the facility;
Name of the owner or operator;
Location of the facility;
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Maximum storage or handling capacity and normal daily throughput;
Corrective actions and countermeasures taken, including a description of
equipment repairs and replacements;
Description of facility, including maps, flow diagrams, and topographical maps;
Cause of the discharge(s) to navigable waters, including a failure analysis of the
system and subsystems in which the failure occurred;
Additional preventive measures taken or contemplated to minimize possibility of
recurrence; and
Other pertinent information requested by the Regional Administrator.
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Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
Discharge Notification Form
*** Notification must not be delayed if information or individuals are not available.
Facility: Clearwater Oil Company Big Bear Lease No. 2 Production Facility
5800 Route 417, Madison, Louisiana 73506
Description of Discharge
Date/time
Reporting Individual
Location of discharge
Equipment source
Product
Appearance and
description
Environmental conditions
Release date:
Release time:
Duration:
Name:
Tel. #:
Latitude:
Longitude:
D piping
D flow/line
Dwell
D unknown
D stock, flare
D crude oil
D saltwater
D other*
Discovery date:
Discovery time:
Description:
Description:
Equipment ID:
* Describe other:
Wind direction:
Wind speed:
Rainfall:
Current:
Impacts
Quantity
Receiving medium
Describe circumstances
of the release
Assessment of impacts
and remedial actions
Disposal method for
recovered material
Action taken to prevent
incident from reoccurring
Safety issues
Released:
D water**
D land
D other (describe):
Recovered:
D Release confined to company property.
D Release outside company property.
** If water, indicate extent and body of water:
D Injuries
D Fatalities
D Evacuation
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Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
Notifications
Agency
Company Spill
Response Coordinator
National Response
Center
1-800-424-8802
State police
Parish Emergency
Response Commission
oil spill removal
organization/cleanup
contractor
Name
Date/time reported & Comments
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Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
APPENDIX G: Equipment Shut-off Procedures
Source
Action
Manifold, transfer
pumps or hose failure
Tank overflow
Tank failure
Flow/line rupture
Flow/line leak
Explosion or fire
Equipment failure
Shut in the well supplying oil to the tank battery if appropriate. Immediately close the
header/manifold or appropriate valve(s). Shut off transfer pumps.
Shut in the well supplying oil to the tank battery. Close header/manifold or appropriate
valve(s)
Shut in the well supplying oil to the tank battery. Close inlet valve to the storage tanks.
Shut in the well supplying oil to the flowline. Close nearest valve to the rupture site to
top the flow of oil.
Shut in the well supplying oil to the flowline. Immediately close the nearest valve to stop
the flow of oil to the leaking section.
Immediately evacuate personnel from the area until the danger is over. Immediately
shut in both wells if safe to do so. If possible, close all manifold valves. If the fire is
small enough such that it is safe to do so, attempt to extinguish with fire extinguishers
available on site.
Immediately close the nearest valve to stop the flow of oil into the leaking area.
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Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan
APPENDIX H: Written Commitment of Manpower,
Equipment, and Materials
In addition to implementing the preventive measures described in this Plan, Clearwater will also
specifically:
In the event of a discharge:
Make available all trained field personnel (three employees) to perform response
actions
Obtain assistance from an additional three full-time employees from its main
operations contractor (Avonlea Services)
Collaborate fully with local, state, and federal authorities on response and
cleanup operations
Maintain all on-site oil spill control equipment described in this Plan and in the attached
Oil Spill Contingency Plan. The equipment is estimated to contain oil spills of up to 500
gallons.
Maintain all communications equipment in operating condition at all times.
Ensure that staging areas to be used in the event of a discharge to Big Bear Creek are
accessible by field vehicles.
Review the adequacy of on-site and third-party response capacity with pre-established
response/cleanup contractors on an annual basis and update response/cleanup
contractor list as necessary.
Maintain formal agreements/contracts with response and cleanup contractors who will
provide assistance in responding to an oil discharge and/or completing cleanup (see
contract agreements maintained separately at the Ridgeview field office and lists of
associated equipment and response contractor personnel capabilities).
Authorized Facility Representative: Bill Laurier
Signature: (Sill <£au/wi/
Title: Field Operations Manager
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Clearwater Oil Company, Ltd. SAMPLE Spill Prevention, Control, and
Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan
APPENDIX I: Oil Spill Contingency Plan
The oil spill contingency plan is maintained separately at the Ridgeview field office.
[Refer to the sample Contingency Plan also available from EPA for more information on the
content and format of that Plan]
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Appendix F: Sample Contingency Plan
SPCC GUIDANCE FOR REGIONAL INSPECTORS
November 15, 2013
-------
DISCLAIMER - APPENDIX F
The sample Contingency Plan in Appendix F is intended to provide examples of
contingency planning as a reference when a facility determines that the required secondary
containment is impracticable, pursuant to 40 CFR §112.7(d). The sample Contingency Plan
presents a variety of scenarios for purposes of illustration only. It is not a template to be
adopted by a facility; doing so does not mean that the facility will be in compliance with the
SPCC rule requirements for a contingency plan. Nor is the sample plan a template that must be
followed in order for the facility to be considered in compliance with the contingency plan
requirement.
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A Clearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility
Oil Spill Contingency Plan
CLEARWATER OIL COMPANY
BIG BEAR LEASE No. 2 PRODUCTION FACILITY
OIL SPILL CONTINGENCY PLAN
NOTE: Throughout this document, shaded
boxes identify relevant sections of 40 CFR
part 109 and part 11 2.
PARTI
Introduction
1.1 Purpose and Scope
This Oil Spill Contingency Plan is prepared in accordance with 40 CFR 112.7(d) to
address areas of the facility where secondary containment is impracticable, as
documented in the facility Spill Prevention, Control, and Countermeasure (SPCC) Plan.
The purpose of this Oil Spill Contingency Plan ("Contingency Plan") is to define
procedures and tactics for responding to discharges of oil into navigable waters or
adjoining shorelines of the United States, originating more specifically from flowlines at
Clearwater Oil Company ("Clearwater") Big Bear Lease No. 2 Production Facility. The
Contingency Plan is implemented whenever a discharge of oil has reached, or threatens,
navigable waters or adjoining shorelines.
The objective of procedures described in this Contingency Plan is to protect the public,
Clearwater personnel, and other responders during oil discharges. In addition, the Plan
is intended to minimize damage to the environment, natural resources, and facility
installations from a discharge of oil. This Oil Spill Contingency Plan complements the
prevention and control measures presented in the facility's SPCC Plan by addressing
areas of the facility that have inadequate secondary containment and impacts that may
result from a discharge from these areas. The facility implements a detailed and
stringent flowline maintenance program to prevent leaks from the primary system (in this
case, piping). Areas lacking adequate containment at the Big Bear Lease No. 2
Production Facility include the flowlines that run between the extraction wells and the
tank battery area and between the tank battery area and the saltwater disposal area.
This Oil Spill Contingency Plan follows the content and organization of 40 CFR part 109
and describes the distribution of responsibilities and basic procedures for responding to
an oil discharge and performing cleanup operations.
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Clearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility
Oil Spill Contingency Plan
1.2 Resources at Risk
40CFR109.5(b)(1)
Clearwater's Big Bear Lease No. 2 Production Facility is located approximately 6 miles
North of Madison, LA, within the Mines River watershed (see Figure C-1 in Appendix C).
The waterways closest to the facility are Big Bear Creek, which flows approximately 1/4
mile to the east of the facility, and the Mines River, which flows 6 miles to the south in a
west-to-east direction and receives water from Big Bear Creek. The facility diagram
included in Appendix C (Figure C-2) indicates the location of the oil extraction,
production, and storage areas. Ground cover at the facility consists of compacted soil,
gravel, and low lying vegetation. The natural topography of the land is graded in an east-
southeast direction, and all surface drainage from the facility therefore flows towards Big
Bear Creek. The slope is relatively mild: approximately 4 feet vertical per mile (5,280
feet) horizontal.
Three flowlines (which contain oil) at the facility lack adequate secondary containment
(see Figure C-2):
Flowline A. The flowline from Well A to the tank battery (FLA) is approximately
2,100 feet long. It runs aboveground in a north-south direction to the tank battery
area.
Flowline B. The flowline between Well B and the tank battery (FLB) is
approximately 3,400 feet long. It travels in a southwest direction to the tank
battery area. This flowline runs the closest to navigable waters. At the closest
point, the flowline is located 1/4 mile from Big Bear Creek.
Flowline SWD. The flowline between the tank battery and the saltwater disposal
well is approximately 2,000 feet long. It runs in an east-west direction.
All three flowlines are aboveground, with the exception of a short portion of Flowline B
that is buried under the dirt/gravel access road. A drainage ditch runs along the access
road to the east of the tank battery and along Route 417. The ditch flows into Big Bear
Creek. Given the direction of surface drainage, a discharge from any of the three
flowlines could reach Big Bear Creek, either directly or via the drainage ditch, and from
there, flow southward to the Mines River.
Neither Big Bear Creek nor the Mines River is used as a public drinking water supply,
although animals grazing on the nearby land are often seen drinking from Big Bear
Creek and the Howard Fleming Farm has an agricultural irrigation intake on Big Bear
Creek (see the Notification Form later in this Plan for contact information). The two
waterways, however, provide habitat for a number of aquatic species and mammals and
are used by local residents for recreational purposes. The Mines River runs through the
center of Madison. Recreational and scenic areas are located on both banks of the river.
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Big Bear Lease No. 2 Production Facility
Oil Spill Contingency Plan
A public park is located approximately 1 mile east from the town center and 8 miles from
the facility. Recreational uses on the Mines River include picnic areas, walking trails,
canoeing, and nature watching.
There are no residences within the immediate vicinity of the facility. The closest
residence is located 1 mile to the north of the site, upstream on Big Bear Creek. The
closest residence downstream from the site is located 3 miles away. Both residences
have private drinking water wells. Clearwater will coordinate with the Madison fire and/or
police departments and with its residential neighbors to provide the appropriate warnings
in the event of a discharge that could affect public health and safety.
1.3 Risk Assessment
The facility is comprised of approximately 7,500 feet of 2-inch diameter flowlines. With
the exception of a short road crossing, the flowlines are located aboveground. The
flowlines do not have secondary containment, since such containment is impracticable at
this facility (see discussion on impracticability of secondary containment in the facility's
SPCC Plan).
40 CFR 109.5(c)(2)
The total daily production rate at the facility varies, but can reach as much as 1,260
gallons of crude oil and 5,880 gallons of produced water. The two wells have
approximately equal production rates (each 3,570 gallons per day). Flowline B, the
longest of the three flowlines and the one closest to navigable waters, contains up to
555 gallons of oil/water when charged. The facility is visited daily. For planning
purposes, the worst-case discharge is therefore the volume of oil within the flowline plus
24 hours of production, or 4,125 gallons.
A discharge of this quantity of oil could potentially reach Big Bear Creek. The velocity of
oil over land is estimated, based on past experience and a simple calculation of flow
over short grass pastureland, at approximately 0.2 feet/second.1 Considering the
distance between Flowline B and Big Bear Creek (1/4 mile) and the 2-foot elevation
gradient, the oil, if unimpeded, could reach Big Bear Creek in as little as 4 hours. The
water current in Big Bear Creek averages approximately 0.3 feet/second during high
stages. Over a 24-hour period, the oil could travel approximately 5 miles downstream
from the release point. The Mines River, which is located only 6 miles downstream to the
south of the tank battery area, could therefore possibly be affected by a discharge.
1 Calculated using sheet flow transport equations.
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Big Bear Lease No. 2 Production Facility Oil Spill Contingency Plan
1.4 Response Strategy
Clearwater personnel and contractors are equipped and trained to respond to certain
"minor discharges" confined within the facility. Minor discharges can generally be
described as those where the quantity of product discharged is small, the discharged
material can be easily stopped and controlled, the discharge is localized, and the
product is not likely to seep into groundwater or reach surface water or adjoining
shorelines. Procedures for responding to these minor discharges are covered in the
SPCC Plan.
This Contingency Plan addresses all discharge incidents, including those that affect
navigable waters or during which the oil cannot be safely controlled by facility personnel
and confined within the boundaries of the facility. Response to such incidents may
necessitate the assistance of outside contractors or other responders to prevent
imminent impact to navigable waters.
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Big Bear Lease No. 2 Production Facility
Oil Spill Contingency Plan
40 CFR 109.5(a)
40 CFR 109.5(d)(2)
PART 11
Spill Discovery and Response
2.1 Distribution of Responsibilities
Clearwater has the primary responsibility for providing the initial response to oil
discharge incidents originating from its facility. To accomplish this, Clearwater has
designated the Field Operations Manager, Bill Laurier, as the qualified oil discharge
Response Coordinator (RC) in the event of an oil discharge.
The RC plays a central coordinating role in any emergency situation, as illustrated in the
emergency organization chart in Figure 2-1.
The RC has the authority to commit the necessary services and equipment to respond to
the discharge and to request assistance from Madison fire and/or police departments,
contractors, or other responders, as appropriate.
The RC will direct notifications and initial response actions in accordance with training
and capabilities. In the event of a fire or emergency situation that threatens the health
and safety of those present at the site, the RC will direct evacuations and contact the fire
and police departments.
In the event of an emergency involving outside response agencies, the RC's primary
responsibility is to provide information regarding the characteristics of the materials and
equipment involved and to provide access to Clearwater resources as requested. The
RC shall also take necessary measures to control the flow of people, emergency
equipment, and supplies and obtain the support of the Madison Police Department as
needed to maintain control of the site. These controls may be necessary to minimize
injuries and confusion.
Finally, the RC serves as the coordinator for radio communications by acquiring all
essential information and ensuring clear communication of information to emergency
response personnel. The RC has access to reference material at the field office either as
printed material or on computer files that can further assist the response activities.
Whenever circumstances permit, the RC transmits assessments and recommendations
to Clearwater Senior Management for direction. Senior Management is contacted in the
following order: (1) Regional Director of Operations; (2) Vice-President of Operations.
In the event that the Field Operations Manager is not available, the responsibility and
authority for initiating a response to a discharge rests with the most senior Clearwater
employee on site at the time the discharge is discovered (Crew Lead) or with the
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Big Bear Lease No. 2 Production Facility
Oil Spill Contingency Plan
contractor Field Supervisor (or next person in command) if contractor personnel are the
only personnel on site.
Regional Director
Carol Campbell
(405) 831-2262
VP of Operations
Lester Pearson
(555) 289-4500
Emergency Coordinator
Field Operations Manager
Bill Laurler
(405) 829-4051
Madison Fire/Police
Department
911
Local, State and
Federal Agency
Personnel
Figure 2-1. Distribution of response authority and communication.
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Big Bear Lease No. 2 Production Facility
Oil Spill Contingency Plan
2.2 Response Activities
40 CFR 109.5(d)
40 CFR 109.5(e)
In the event of a discharge, the first priority is to stop the product flow and to shut off all
ignition sources, followed by the containment, control, and mitigation of the discharge.
This Contingency Plan breaks actions to be performed to respond to an oil discharge
into different phases, described in greater detail in the checklists below.
2.2.1 Discharge Discovery and Source Control
Minor Discharge. A minor discharge (i.e., small volume leak from flowlines or other
equipment) will be discovered by Clearwater facility personnel or by contractor personnel
during scheduled daily or monthly visits to the facility. Aboveground flowlines are visually
inspected formally once a month during the normal inspection rounds.
Major Discharge. A more severe and sudden discharge will trigger the automatic shut
down of the pumping units and will affect oil production. The impact will be detected
during the daily visit to the production area by Clearwater or contractor field personnel.
The maximum amount of time until a major discharge is detected can be up to 24 hours.
Notifications to the National Response Center, Louisiana authorities, and St. Anthony's
Parish Emergency Committee must occur immediately upon discovery of reportable
discharges.
Completed
Actions
Immediately report the discharge to the RC, providing the following
Exact location;
Material involved;
Quantity involved;
Topographic and environmental conditions;
Circumstances that may hinder response; and
Injuries, if any.
information:
Turn off all sources of ignition.
Turn off lift pumps that charge or provide flow to the flowline.
Locate the flowline break.
If safe to do so, isolate the affected section of piping by closing off the closest
valves upstream and downstream from the break.
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2.2.2 Assessment and Notifications
Completed
Actions
Investigate the discharge to assess the actual or potential threat to human health
or the environment:
Location of the discharge relative to receiving waterbodies;
Quantity of spilled material;
Ambient conditions (temperature, rain);
Other contributing factors such as fire or explosion hazards; and
Sensitive receptors downstream.
Request outside assistance from local emergency responders, as needed.
Evaluate the need to evacuate facility and evacuate employees, as needed.
Notify the fire/police departments and St. Anthony's Parish Emergency Committee
to assess whether community evacuation is needed.
Notify immediately:
911
National Response Center
Response contractor(s)
St. Anthony's Parish Emergency Planning Committee
State authorities
Communicate with neighboring property owners regarding the discharge and
actions taken to mitigate the damage.
If the oil reaches (or threatens to reach) the Mines River, notify the local fire/police
departments to limit access to the River by local residents until the oil has been
contained and recovered.
Additionally, notify downstream water users of the spill and of actions that will be
taken to protect these downstream receptors.
2.2.3 Control and Recovery
The RC directs the initial control of the oil flow by Clearwater, Avonlea Oil Services, and
other contractor personnel. The actions taken will depend on whether the oil has
reached water or is still on land. All effort will be made to prevent oil from reaching water.
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If the oil has not yet reached water:
Completed
Actions
Deploy sand bags and absorbent socks downgradient from the oil, or erect
temporary barriers such as trenches or mounds to prevent the oil from flowing
towards Big Bear Creek.
Implement land based response actions (countermeasure) such as digging
temporary containment pits, ponds, or curbs to prevent the flow of oil into the
river.
Deploy absorbent sock and sorbent material along the shoreline to prevent oil
from entering waters.
If the oil has reached water:
Completed
Actions
Contact cleanup contractor(s).
Deploy floating booms immediately downstream from the release point. Big Bear
Creek is narrow and shallow. Floating boom deployment does not require the use
of a boat.
Control oil flow on the ground by placing absorbent socks and other sorbent
material or physical barriers (e.g., "kitty litter," sandbags, earthen berm, trenches)
across the oil flow path.
Deploy additional floating booms across the whole width of the Creek at the next
access point downstream from the release point. Access points and staging areas
along the shoreline are identified on Figure C-1 of this Contingency Plan.
Deploy protective booming measures for downstream receptors that may be
impacted by the spill.
2.2.4 Disposal of Recovered Product and Contaminated Response Material
The RC ensures that all contaminated materials classified as hazardous waste are
disposed of in accordance with all applicable solid and hazardous waste regulations.
Completed
Actions
Place any recovered product that can be recycled into the gun barrel tank to be
separated and recycled.
Dispose of recovered product not suitable for on-site recycling with the rest of the
waste collected during the response efforts.
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Collect all debris in properly labeled waste containers (impervious bags, drums, or
buckets).
Dispose of contaminated material in accordance with all applicable solid and
hazardous waste regulations using a licensed waste hauler and disposal facility,
after appropriately characterizing the material for collection and disposal.
Dispose of all contaminated response material within 2 weeks of the discharge.
2.2.5 Termination
The RC ensures that cleanup has been completed and that the contaminated area has
been treated or mitigated according to the applicable regulations and state/federal
cleanup action levels. The RC collaborates with the local, state and federal authorities
regarding the assessment of damages.
Completed
Actions
Ensure that all repairs to the defective equipment or flowline section have been
completed.
Review circumstances that led to the discharge and take all necessary
precautions to prevent a recurrence.
Evaluate the effectiveness of the response activities and make adjustments as
necessary to response procedures and personnel training.
Carry out personnel and contractor debriefings as necessary to emphasize
prevention measures or to communicate changes in operations or response
procedures.
Submit any required follow-up reports to the authorities.
In the case where the discharge (as defined in 40 CFR 112.1(b)) was greater than
1,000 gallons or was the second discharge (as defined in 40 CFR 112.1(b)) of 42
gallons or more within any 12-month period, the RC is responsible for submitting
the required information within 60 days to the EPA Regional Administrator
following the procedures outlined in Appendix B.
Within 30 days of the discharge, the RC will convene an
all appropriate persons that responded to the spill. The goal of the incident
critique is to discuss lessons learned, the efficacy of the Contingency Plan and its
implementation, and coordination of the plan/RC and other state and local plans.
Within 60 days of the critique, the Contingency Plan will be updated (as needed)
to incorporate the results, findings, and suggestions developed during the critique.
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Big Bear Lease No. 2 Production Facility
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2.3 Discharge Notification
Instructions and phone numbers for reporting a discharge to the National Response
Center and other federal, state, and local authorities are provided in Appendix B to this
Plan. Any discharge to water must be reported immediately to the National Response
Center. The Response Coordinator must ensure that details of the discharge are
recorded on the Discharge Notification Form provided in Appendix B.
If the discharge qualifies under 40 CFR part 112 (see Appendix B for conditions), the RC
is responsible for ensuring that all pertinent information is provided to the EPA Regional
Administrator.
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Big Bear Lease No. 2 Production Facility
Oil Spill Contingency Plan
PART III
Response Resources and Preparedness Activities
3.1 Equipment, Supplies, Services, and Manpower
40 CFR 109.5(c)(1)
and(c)(2)
40 CFR 109.5(d)(3)
Spill kits are provided in a storage shed at the production site that is accessible by both
Clearwater and Avonlea personnel (see Figure C-2 in Appendix C). Response
equipment and material present at the site include:
(4) Empty 55-gallons drums to hold contaminated material
(1) 50-ft absorbent socks
(2) 10-ft sections of hard skirted deployment boom
(2) 50-ft floating booms
(200 pounds) "Oil-dry" Loose absorbent material
(4 boxes) 2 ft x 3 ft absorbent pads
(3 boxes) Nitrile gloves
(3 boxes) Neoprene gloves
(6 pairs) Vinyl/PVC pull-on overboots
(3) Non-sparking shovels
(3) Brooms
(20) Sand bags
(1) Combustible Gas Indicator with H2S detection capabilities
This material is sufficient to respond to most minor discharges occurring at the facility
and to initially contain a major discharge while waiting for additional material or support
from outside contractors. The inventory is verified on a monthly basis during the
scheduled facility inspection by designated personnel and is replenished as needed.
Additional material and equipment is kept at Clearwater's field office, located 25 miles
from the facility. This additional material includes empty storage drums, absorbent socks
and booms, containment booms, sand bags, personal protective gear, etc. It also
includes all necessary communication equipment to coordinate response activities (cell
phones, two-way radios). The Field Office serves as the response operation center
during a response.
Clearwater has three employees trained and available to respond to an oil discharge.
Clearwater personnel may be assisted by three additional employees from the facility's
main contractor, Avonlea Oil Services. All employees are familiar with the facility layout,
location of spill response equipment and staging areas, and response strategies, and
with the SPCC and Oil Spill Contingency Plans for this facility. All have received training
in the deployment of response material and handling of hazardous waste (HAZWOPER)
and have attended the required refresher courses.
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Big Bear Lease No. 2 Production Facility
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40 CFR 109.5(c)(3)
To respond to larger discharges and ensure the removal and disposal of cleanup debris,
Clearwater has established agreements with two specialized cleanup contractors:
EZCIean and Armadillo Oil Removal, with EZCIean contacted first and acting as the
primary response/cleanup contractor and Armadillo Oil Removal acting as the alternate
or in a supporting role. Contact information is provided in Appendix A. These contractors
have immediate access to an assortment of equipment and materials, including
mechanical recovery equipment for use on water and on land, small boats, floating
booms, and large waste containers. Each contractor has sufficient response equipment
to contain and recover the maximum possible discharge of 4,125 gallons. EZCIean and
Armadillo Oil Removal are able to respond within 4 hours of receiving a verbal request
from the RC. Clearwater discusses response capacity needs on an annual basis with
each contractor to ensure that sufficient equipment and material are available to respond
to a potential 4,125-gallon discharge. The inventories of EZCIean and Armadillo Oil
Removal equipment are maintained with the response agreements and updated
annually.
3.2 Access to Receiving Waterbody
Big Bear Creek would be the first waterbody affected
in the event of a discharge. From there, the oil would
flow into the Mines River. The response strategy
consists of: (1) deploying booms and other response
equipment at various points downstream from the oil
plume to prevent its migration; and (2) deploying
booms as a protective measure for an irrigation water
intake and other downstream sensitive receptors.
Vehicular access to Big Bear Creek is essential to
ensure that the response equipment can be effectively
deployed to contain oil at various points along the
waterway and prevent further migration of the oil
towards the Mines River.
Three access points have been established along Big
Bear Creek and are marked on the map in Figure C-1
(BB1, BB2, and BBS). These access points provide
sufficient cleared land for a staging area from which
Clearwater or contractor personnel can deploy
response equipment, and recover and store spilled oil.
Twice a year, as part of the monthly inspection of the
facility, Clearwater facility personnel drive to each
access point and make sure that it remains
accessible (e.g., vegetation is not overgrown and the
Figure 3-2: Boom deployed
across Big Bear Creek.
Figure 3-3: Boom deployed at
Route 54 bridge crossing.
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dirt trail is not impassable for a field vehicle). The respective property owners have agreed to
allow access to Clearwater's personnel and contractors for response and maintenance
purposes. Although no further approval is needed prior to the deployment of response
equipment, the RC will contact the property owners as necessary to inform them of activities
being carried out.
If necessary, three access points are also available along the Mines River. One is
located in the center of Madison, at the bridge crossing for Route 101, the second is
located at the public park two miles downstream from the center, and the third one is
located at the bridge crossing for Route 54, four miles downstream from the center.
Coordination with the Madison police/fire departments is necessary to stage equipment
at these three access points.
3.3 Communications and Control
40 CFR 109.5(b)(3)
40 CFR 109.5(d)(3)
A central coordination center will be set up at the field office in the event of a discharge.
The field office is equipped with a variety of fixed and mobile communication equipment
(telephone, fax, cell phones, two-way radios, computers) to ensure continuous
communication with Clearwater management, responders, authorities, and other
interested parties.
Communications equipment includes:
Portable hand-held radios. Clearwater maintains a two-way base station and
four portable radio units. These radio units are kept at the field office as part of
the response equipment. Local emergency responders have been provided with
the response frequencies that will be used during an incident.
Cell phones. Each field vehicle and the RC are provided with a cell phone. The
RC and/or his alternate (Site Supervisor when the Field Operations Manager is
not "on call") can be reached by cell phone 7 days a week, 24 hours a day.
Additional equipment. Additional equipment will be obtained from EZCIean
and/or Armadillo Oil Removal in the event that more communications equipment
is necessary.
The RC is responsible for communicating the status of the response operations and for
sharing relevant information with involved parties, including local, state, and federal
authorities.
In the event that local response agencies, Louisiana authorities, or a federal On Site
Coordinator (OSC) assumes Incident Command, the RC will function as the facility
representative in the Unified Command structure.
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Big Bear Lease No. 2 Production Facility
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3.4 Training Exercises and Updating Procedures
40 CFR 109.5(d)(1)
Clearwater has established and maintains an ongoing training program to ensure that
Clearwater personnel responding to oil discharges are properly trained and that all
necessary equipment is available to them. The program includes on-the-job training on
the proper deployment of response equipment and periodic practice drills during which
Clearwater personnel are asked to deploy equipment and material in response to a
simulated discharge. The RC is responsible for implementing and evaluating employee
preparedness training.
Following a response to an oil discharge, the RC will evaluate the actions taken and
identify procedural areas where improvements are needed. The RC will conduct a
briefing with field personnel, contractors, and local emergency responders to discuss
lessons learned and will integrate the outcome of the discussion in subsequent SPCC
briefings and employee training seminars. As necessary, the RC will amend this
Contingency Plan or the SPCC Plan to reflect changes made to the facility equipment
and procedures. A Professional Engineer will certify any technical amendment to the
SPCC Plan.
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Big Bear Lease No. 2 Production Facility
Oil Spill Contingency Plan
40 CFR 109.5(b)(2)
APPENDIX A
EMERGENCY CONTACTS
Facility Operations
Name
Bill Laurier
Carol Campbell
Lester Pearson
Joe Clark
William Mackenzie
Title
Field Operations
Manager
Clearwater Oil Co.
Regional Director of
Operations
Clearwater Oil Co.
Vice-President of
Operations
Clearwater Oil Co.
Field Supervisor
Avonlea Services, Inc.
Pumper
Avonlea Services, Inc.
Telephone
(405) 831-6322 (office)
(405) 829-4051 (cell)
(405) 831-6320 (office)
(405) 831-2262 (cell)
(555)-289-4500
(406) 545-2285 (office)
(406) 549-9087 (cell)
(406) 549-9087 (cell)
Address
2451 Mountain Drive
Ridgeview, LA 701 80
2451 Mountain Drive
Ridgeview, LA 701 80
13000 Main Street, Suite
400
Houston, TX 77077
786 Cherry Creek Road
Avonlea, LA 70180
786 Cherry Creek Road
Avonlea, LA 701 80
Local Emergency Responders
Name
Fire/Police Departments
Emerson Hospital
Telephone
911
(405) 830-2000
(405)831-9558
Address
2451 Mountain Drive, Madison, LA 70180
13000 Main Street, Madison, LA 70180
Cleanup Contractors
Name
EZCIean
Armadillo Oil Removal
Telephone
(800)521-3211
(214)566-5588
Address
1200 Industry Park Drive, Gardner, LA 70180
25 B Street, Suite #6, Madison, LA 70180
Neighboring Property Owners
Name
Maurice Richard
Jim Larouche
Peter Martin
Howard Fleming
Telephone
(405)830-2186
(405) 832-2645
(405) 832-5527
(405) 235-6893
Address
5540 Route 417, Madison, LA 70180
6075 Greenfield Drive, Madison, LA 70180
1644 Oilfield Road, Madison, LA 70180
531 Horseshoe Road, Madison, LA 70180
Location
BB1
BB2
BBS
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Big Bear Lease No. 2 Production Facility
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APPENDIX B
DISCHARGE NOTIFICATION PROCEDURES
Circumstances, instructions, and phone numbers for reporting a discharge to the National
Response Center and other federal, state, and local agencies, and to other affected parties, are
provided below. They are also posted at the facility in the storage shed containing the discharge
response equipment. Note that any discharge to water must be reported immediately to the
National Response Center.
Field Operations Manager, Bill Laurier (24 hours)
Local Emergency (fire, explosion, or other hazards)
(405) 829-4051
911
Agency / Organization
Federal Agencies
National Response
Center
EPA Region VI
(Hotline)
EPA Region VI
Regional Administrator
Sfafe Agencies
Office of State Police,
Transportation and
Environmental Safety
Section, Hazardous
Materials Hotline
Office of State Police,
Transportation and
Environmental Safety
Section, Hazardous
Materials Hotline
Agency Contact
1-800-424-8802
1-800-887-6063
First Interstate Bank
Tower at Fountain
Place
1445 Ross Avenue,
12th floor, Suite 1200
Dallas TX 75202
225-925-6595
or
1-877-925-6595
225-925-6595
or
1-877-925-6595
Circumstances
Discharge reaching navigable
waters.
Discharge 1,000 gallons or
more; or second discharge of 42
gallons or more over a 12-month
period.
1) Injury requiring hospitalization
or fatality.
2) Fire, explosion, or other
impact that could affect public
safety.
3) Release exceeding 24-hour
reportable quantity.
4) Impact to areas beyond the
facility's confines.
Discharges that pose
emergency conditions,
regardless of the volume
discharged.
When to Notify
Immediately (verbal)
Immediately (verbal)
Written notification within
60 days (see Section 2.1 of
this Plan)
Immediately (verbal)
Written notification to be
made within 5 days.
Within 1 hour of discovery
(verbal).
Written notification within 7
working days.
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Agency / Organization
Louisiana Department
of Environmental
Quality, Office of
Environmental
Compliance
Local Agencies
St. Anthony's Parish
Emergency Planning
Committee
Offers
Response/cleanup
contractors
Howard Fleming Farm
(agricultural irrigation
intake)
Maurice Richard
Jim Larouche
Peter Martin
Agency Contact
225-763-3908
or 225-342-1 234
(after business
hours, weekends
and holidays)
337-828-1960
EZCIean
(800)521-3211
Armadillo Oil
Removal Co.
(214)566-5588
(405) 235-6893
405-830-2186
405-832-2645
405-832-5527
Circumstances
Discharges that do not pose
emergency conditions
Any discharge of 100 Ibs or
more that occurs beyond the
boundaries of the facility,
including to the air.
Any discharge that exceeds the
capacity of facility personnel to
respond and clean up.
Any discharge that threatens to
affect neighboring properties
and irrigation intakes.
When deploying response
equipment from Access Point
BB1 on Big Bear Creek.
When deploying response
equipment from Access Point
BB2 on Big Bear Creek.
When deploying response
equipment from Access Point
BBS on Big Bear Creek.
When to Notify
Within 24 hours of
discovery (verbal).
Written notification within 7
working days.
Immediately (verbal)
Written notification within 7
days.
As needed
As needed
As needed
As needed
As needed
The person reporting the discharge must provide the following information:
Name, location, organization, and telephone number
Name and address of the owner/operator
Date and time of the incident
Location of the incident
Source and cause of discharge
Types of material(s) discharged
Total quantity of materials discharged
Quantity discharged in harmful quantity (to navigable waters or adjoining
shorelines)
Danger or threat posed by the release or discharge
Description of all affected media (e.g., water, soil)
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Number and types of injuries (if any) and damaged caused
Weather conditions
Actions used to stop, remove, and mitigate effects of the discharge
Whether an evacuation is needed
Name of individuals and/or organizations contacted
Any other information that may help emergency personnel respond to the
incident
Whenever the facility discharges more than 1,000 gallons of oil in a single event, or discharges
more than 42 gallons of oil in each of two discharge incidents within a 12-month period, the
Manager of Field Operations must provide the following information to the U.S. Environmental
Protection Agency's Regional Administrator within 60 days:
Name of the facility
Name of the owner or operator
Location of the facility
Maximum storage or handling capacity and normal daily throughput
Corrective actions and countermeasures taken, including a description of
equipment repairs and replacements
Description of facility, including maps, flow diagrams, and topographical maps
Cause of the discharge(s) to navigable waters, including a failure analysis of the
system and subsystems in which the failure occurred.
Additional preventive measures taken or contemplated to minimize possibility of
recurrence
Other pertinent information requested by the Regional Administrator.
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Discharge Notification Form
*** Notification must not be delayed if information or individuals are not available. Additional pages may be attached to
supplement information contained in the form.
Facility: Clearwater Oil Company Big Bear Lease No. 2 Production Facility
5800 Route 417
Madison, Louisiana 73506
Description of Discharge
Date/time
Reporting Individual
Location of discharge
Equipment source
Product
Appearance and
description
Environmental conditions
Release date:
Release time:
Duration:
Name:
Latitude:
Longitude:
D piping
D flow/line
Dwell
D unknown
D stock, flare
D crude oil
D saltwater
D other*
Discovery date:
Discovery time:
Tel. #:
Description:
Description:
Equipment ID:
* Describe other:
Wind direction:
Wind speed:
Rainfall:
Current:
Impacts
Quantity
Receiving medium
Describe circumstances
of the release
Assessment of impacts
and remedial actions
Disposal method for
recovered material
Action taken to prevent
incident from reoccurring
Released:
D water**
D land
D other (describe):
Recovered:
D Release confined to company property.
D Release outside company property.
** If water, indicate extent and body of water:
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Safety issues
D Injuries
D Fatalities
D Evacuation
Notifications
Agency
Company Spill
Response Coordinator
National Response
Center
1-800-424-8802
State police
Parish Emergency
Response Commission
OSRO/cleanup
contractor
Name
Date/time reported & Comments
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Appendix C
SITE PLAN AND FACILITY DIAGRAM
I .•& IV I
Figure C-1: Site Plan (pre-designated staging areas are indicated).
Staging area
BB1
BB2
BBS
Location
5540 Route 417, Madison, LA (access from path to the
right of the storage shed).
6075 Greenfield Drive, Madison, LA.
1644 Oilfield Road, Madison, LA
Contact Information
Maurice Richard; 405-830-2186
Jim Larouche; 405-832-2645
Peter Martin; 405-832-5527
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BOX 1. Saltwater Disposal Well Area
To production area
Approx. tengln
2,000 ft
Clearwater Oil Company
Big Bear Lease No. 2 Production Facility
Facility Diagram
Rev. 11/12/02
Figure C-2: Facility Diagram.
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Appendix G: SPCC Inspection Checklists
Onshore Facilities (excluding production)
Onshore Oil Production, Drilling, and Workover Facilities
Offshore Oil Production, Drilling, and Workover
Tier I Qualified Facility Checklist
SPCC GUIDANCE FOR REGIONAL INSPECTORS
November 15, 2013
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Appendix G: SPCC Inspection Checklists
U.S. ENVIRONMENTAL PROTECTION AGENCY
SPCC FIELD INSPECTION AND PLAN REVIEW CHECKLIST
ONSHORE FACILITIES (EXCLUDING OIL DRILLING, PRODUCTION AND WORKOVER)
Overview of the Checklist
This checklist is designed to assist EPA inspectors in conducting a thorough and nationally consistent inspection of a
facility's compliance with the Spill Prevention, Control, and Countermeasure (SPCC) rule at 40 CFR part 112. It is a
required tool to help federal inspectors (or their contractors) record observations for the site inspection and review of the
SPCC Plan. While the checklist is meant to be comprehensive, the inspector should always refer to the SPCC rule in its
entirety, the SPCC Regional Inspector Guidance Document, and other relevant guidance for evaluating compliance. This
checklist must be completed in order for an inspection to count toward an agency measure (i.e., OEM inspection
measures or GPRA). The completed checklist and supporting documentation (i.e. photo logs or additional notes) serve as
the inspection report.
This checklist addresses requirements for onshore facilities including Tier II Qualified Facilities (excluding facilities
involved in oil drilling, production and workover activities) that meet the eligibility criteria set forth in §112.3(g)(2).
Separate standalone checklists address requirements for:
Onshore oil drilling, production, and workover facilities including Tier II Qualified Facilities as defined in §112.3(g)(2);
Offshore drilling, production and workover facilities; and
Tier I Qualified Facilities (for facilities that meet the eligibility criteria defined in §112.3(g)(1))
Qualified facilities must meet the rule requirements in §112.6 and other applicable sections specified in §112.6, except for
deviations that provide environmental equivalence and secondary containment impracticability determinations as allowed
under§112.6.
The checklist is organized according to the SPCC rule. Each item in the checklist identifies the relevant section and
paragraph in 40 CFR part 112 where that requirement is stated.
• Sections 112.1 through 112.5 specify the applicability of the rule and requirements for the preparation,
implementation, and amendment of SPCC Plans. For these sections, the checklist includes data fields to be
completed, as well as several questions with "yes," "no" or "NA" answers.
• Section 112.6 includes requirements for qualified facilities. These provisions are addressed in Attachment D.
• Section 112.7 includes general requirements that apply to all facilities (unless otherwise excluded).
• Sections 112.8 and 112.12 specify requirements for spill prevention, control, and countermeasures for
onshore facilities (excluding production facilities).
The inspector needs to evaluate whether the requirement is addressed adequately or inadequately in the SPCC Plan and
whether it is implemented adequately in the field (either by field observation or record review). For the SPCC Plan and
implementation in the field, if a requirement is addressed adequately, mark the "Yes" box in the appropriate column. If a
requirement is not addressed adequately, mark the "No" box. If a requirement does not apply to the particular facility or
the question asked is not appropriate for the facility, mark as "NA". Discrepancies or descriptions of inspector
interpretation of "No" vs. "NA" may be documented in the comments box subsequent to each section. If a provision of the
rule applies only to the SPCC Plan, the "Field" column is shaded.
Space is provided throughout the checklist to record comments. Additional space is available as Attachment E at the end
of the checklist. Comments should remain factual and support the evaluation of compliance.
Attachments
• Attachment A is for recording information about containers and other locations at the facility that require
secondary containment.
• Attachment B is a checklist for documentation of the tests and inspections the facility operator is required to
keep with the SPCC Plan.
• Attachment C is a checklist for oil spill contingency plans following 40 CFR 109. Unless a facility has
submitted a Facility Response Plan (FRP) under 40 CFR 112.20, a contingency plan following 40 CFR 109 is
required if a facility determines that secondary containment is impracticable as provided in 40 CFR 112.7(d).
The same requirement for an oil spill contingency plan applies to the owner or operator of a facility with
qualified oil-filled operational equipment that chooses to implement alternative requirements instead of
general secondary containment requirements as provided in 40 CFR 112.7(k).
• Attachment D is a checklist for Tier II Qualified Facilities.
• Attachment E is for recording additional comments or notes.
• Attachment F is for recording information about photos.
SPCC GUIDANCE FOR REGIONAL INSPECTORS G-1
Onshore Facilities (Excluding Oil Production) Page 1 of 14 December 2012 (12-10-12)
-------
Appendix G: SPCC Inspection Checklists
FACILITY INFORMATION
FACILITY NAME:
LATITUDE:
LONGITUDE:
GPS DATUM:
Section/Township/Range:
FRS#/OIL DATABASE ID:
ICIS#:
ADDRESS:
CITY:
STATE:
ZIP:
COUNTY:
MAILING ADDRESS (IF DIFFERENT FROM FACILITY ADDRESS - IF NOT, PRINT -SAME-):
CITY:
STATE:
ZIP:
COUNTY:
TELEPHONE:
FACILITY CONTACT NAME/TITLE:
OWNER NAME:
OWNER ADDRESS:
CITY:
STATE:
ZIP:
COUNTY:
TELEPHONE:
FAX:
EMAIL:
FACILITY OPERATOR NAME (IF DIFFERENT FROM OWNER-IF NOT, PRINT -SAME-):
OPERATOR ADDRESS:
CITY:
STATE:
ZIP:
COUNTY:
TELEPHONE:
OPERATOR CONTACT NAME/TITLE:
FACILITY TYPE:
NAICS CODE:
HOURS PER DAY FACILITY ATTENDED:
TOTAL FACILITY CAPACITY:
TYPE(S) OF OIL STORED:
LOCATED IN INDIAN COUNTRY? YES D NO RESERVATION NAME:
INSPECTION/PLAN REVIEW INFORMATION
PLAN REVIEW DATE:
REVIEWER NAME:
INSPECTION DATE:
TIME:
ACTIVITY ID NO:
LEAD INSPECTOR:
OTHER INSPECTOR(S):
INSPECTION ACKNOWLEDGMENT
/ performed an SPCC inspection at the facility specified above.
INSPECTOR SIGNATURE:
DATE:
SUPERVISOR REVIEW/SIGNATURE:
DATE:
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Onshore Facilities (Excluding Oil Production)
Page 2 of 14
December 2012(12-10-12)
-------
Appendix G: SPCC Inspection Checklists
SPCC GENERAL APPLICABILITY—40 CFR 112.1
IS THE FACILITY REGULATED UNDER 40 CFR part 112?
The completely buried oil storage capacity is over 42,000 U.S. gallons, OR the aggregate aboveground
oil storage capacity is over 1,320 U.S. gallons AND
The facility is a non-transportation-related facility engaged in drilling, producing, gathering, storing,
processing, refining, transferring, distributing, using, or consuming oil and oil products, which due to its
location could reasonably be expected to discharge oil into or upon the navigable waters of the United
States
jYes
lYes
| No
I No
AFFECTED WATERWAY(S):
DISTANCE:
FLOW PATH TO WATERWAY:
Note: The following storage capacity is not considered in determining applicability of SPCC requirements:
Equipment subject to the authority of the U.S. Department of
Transportation, U.S. Department of the Interior, or Minerals
Management Service, as defined in Memoranda of Understanding dated
November 24, 1971, and November 8, 1993; Tank trucks that return to
an otherwise regulated facility that contain only residual amounts of oil
(EPA Policy letter)
Completely buried tanks subject to all the technical requirements of 40
CFR part 280 or a state program approved under 40 CFR part 281;
Underground oil storage tanks deferred under 40 CFR part 280 that
supply emergency diesel generators at a nuclear power generation
facility licensed by the Nuclear Regulatory Commission (NRC) and
subject to any NRC provision regarding design and quality criteria,
including but not limited to CFR part 50;
Any facility or part thereof used exclusively for wastewater treatment
(production, recovery or recycling of oil is not considered wastewater
treatment); (This does not include other oil containers located at a
wastewater treatment facility, such as generator tanks or transformers)
Containers smaller than 55 U.S. gallons;
Permanently closed containers (as defined in §112.2);
Motive power containers(as defined in §112.2);
Hot-mix asphalt or any hot-mix asphalt containers;
Heating oil containers used solely at a single-family residence;
Pesticide application equipment and related mix containers;
Any milk and milk product container and associated piping and
appurtenances; and
Intra-facility gathering lines subject to the regulatory requirements
of 49 CFR part 192 or 195.
Does the facility have an SPCC Plan?
Yes
No
FACILITY RESPONSE PLAN (FRP) APPLICABILITY—40 CFR 112.20(f)
A non-transportation related onshore facility is required to prepare and implement an FRP as outlined in 40 CFR 112.20 if:
LjThe facility transfers oil over water to or from vessels and has a total oil storage capacity greater than or equal to
42,000 U.S. gallons, OR
|_|The facility has a total oil storage capacity of at least 1 million U.S. gallons, AND at least one of the following is true:
[__|The facility does not have secondary containment sufficiently large to contain the capacity of the largest aboveground
tank plus sufficient freeboard for precipitation.
LjThe facility is located at a distance such that a discharge could cause injury to fish and wildlife and sensitive
environments.
|_|The facility is located such that a discharge would shut down a public drinking water intake.
[_|The facility has had a reportable discharge greater than or equal to 10,000 U.S. gallons in the past 5 years.
Facility has FRP: I lYes
No
NA
FRP Number:
Facility has a completed and signed copy of Appendix C, Attachment C-ll,
"Certification of the Applicability of the Substantial Harm Criteria."
Yes
No
Comments:
GUIDANCE FOR REGIONAL INSPECTORS
Onshore Facilities (Excluding Oil Production)
Page 3 of 14
December 2012 (12-10-12)
-------
Appendix G: SPCC Inspection Checklists
SPCC TIER II QUALIFIED FACILITY APPLICABILITY^^ CFR 112.3(g)(2)
The aggregate aboveground oil storage capacity is 10,000 U.S. gallons or less AND
In the three years prior to the SPCC Plan self-certification date, or since becoming subject to the rule (if the
facility has been in operation for less than three years), the facility has NOT had:
• A single discharge as described in §1 1 2.1 (b) exceeding 1 ,000 U.S. gallons, OR
• Two discharges as described in §112.1(b) each exceeding 42 U.S. gallons within any twelve-month period1
QYes DNO
Qves DNO
QVes ONO
IFyESTOAL^THEAB^
REQUIREMENTS FOR PREPARATION AND IMPLEMENTATION OF A SPCC PLAN— 40 CFR 112.3
Date facility began operations:
Date of initial SPCC Plan preparation: Current Plan version (date/number):
112.3(a)
112.3(d)
For facilities (except farms), including mobile or portable facilities:
• In operation on or prior to November 1 0, 201 1 : Plan prepared and/or amended and fully
implemented by November 10, 2011
• Beginning operations after November 10, 201 1 , Plan prepared and fully implemented
before beginning operations
For farms (as defined in §112.2):
• In operation on or prior to August 1 6, 2002: Plan maintained, amended and
implemented by May 10, 2013
• Beginning operations after August 1 6, 2002 through May 1 0, 201 3: Plan prepared and
fully implemented by May 10, 2013
• Beginning operations after May 10, 2013: Plan prepared and fully implemented before
beginning operations
Plan is certified by a registered Professional Engineer (PE) and includes statements that the
PE attests:
• PE is familiar with the requirements of 40 CFR part 1 1 2
• PE or agent has visited and examined the facility
• Plan is prepared in accordance with good engineering practice including consideration
of applicable industry standards and the requirements of 40 CFR part 1 12
• Procedures for required inspections and testing have been established
• Plan is adequate for the facility
DYes DNO DNA
E^Yes [UNO DNA
DYes DNO DNA
Qves DNO DNA
EJYes Qixio QNA
HHYes ONO ONA
nYes nN° DNA
HHYes ONO C|NA
DYes DNO DNA
HHYes d|No CUNA
PE Name: License No.: State: Date of certification:
112.3(e)(1)
Plan is available onsite if attended at least 4 hours per day. If facility is unattended, Plan is
available at the nearest field office.
(Please note nearest field office contact information in comments section below.)
^Yes nN° DNA
Comments:
1 Oil discharges that result from natural disasters, acts of war, or terrorism are not included in this determination. The gallon amount(s) specified (either
1,000 or 42) refers to the amount of oil that actually reaches navigable waters or adjoining shorelines not the total amount of oil spilled. The entire
volume of the discharge is oil for this determination.
2 An owner/operator who self-certifies a Tier II SPCC Plan may include environmentally equivalent alternatives and/or secondary containment
impracticagp^^^^^e^^ie^an^c^ij^^ a PE. G_4
Onshore Facilities (Excluding Oil Production) Page 4 of 14 December 2012 (12-10-12)
-------
Appendix G: SPCC Inspection Checklists
AMENDMENT OF SPCC PLAN BY REGIONAL ADMINISTRATOR (RA)—40 CFR 112.4
If YES
Has the facility discharged more than 1,000 U.S. gallons of oil in a single reportable discharge
or more than 42 U.S. gallons in each of two reportable discharges in any 12-month period?3
• Was information submitted to the RA as required in §112.4(a)?4
• Was information submitted to the appropriate agency or agencies in charge of oil
pollution control activities in the State in which the facility is located§112.4(c)
• Date(s) and volume(s) of reportable discharges(s) under this section:
• Were the discharges reported to the NRCb?
jYes |_|No
JYes QNO
lYes HMO
|NA
INA
JYes
No
Have changes required by the RA been implemented in the Plan and/or facility?
lYes
iNo LJNA
Comments:
AMENDMENT OF SPCC PLAN BY THE OWNER OR OPERATOR—40 CFR 112.5
112.5(a)
If YES
Has there been a change at the facility that materially affects the potential for a discharge
described in §112.1 (b)?
• Was the Plan amended within six months of the change?
• Were amendments implemented within six months of any Plan amendment?
JYes
JYes
JYes
No
No
No
112.5(b)
Review and evaluation of the Plan completed at least once every 5 years?
Following Plan review, was Plan amended within six months to include more effective
prevention and control technology that has been field-proven to significantly reduce the
likelihood of a discharge described in §112.1 (b)?
Amendments implemented within six months of any Plan amendment?
Five year Plan review and evaluation documented?
JYes
]Yes
]Yes
JYes
jNo
JNo
]No
JNo
JNA
]NA
]NA
JNA
112.5(c)
Professional Engineer certification of any technical Plan amendments in accordance with all
applicable requirements of §112.3(d) [Except for self-certified Plans]
JYes
JNo MNA
Name:
License No.:
State:
Date of certification:
Reason for amendment:
Comments:
3 A reportable discharge is a discharge as described in §112.1(b)(see 40 CFR part 110). The gallon amount(s) specified (either 1,000 or 42) refers to the
amount of oil that actually reaches navigable waters or adjoining shorelines not the total amount of oil spilled. The entire volume of the discharge is oil
for this determination.
4 Triggering this threshold may disqualify the facility from meeting the Qualified Facility criteria if it occurred in the three years prior to self certification
to NRC
Onshore Facilities (Excluding Oil Production)
Page 5 of 14
c-5
December 20 12 (12- 1 0- 12)
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Appendix G: SPCC Inspection Checklists
GENERAL SPCC REQUIREMENTS—40 CFR 112.7
PLAN
FIELD
Management approval at a level of authority to commit the necessary resources to
fully implement the Plan6
Yes
iNo
Plan follows sequence of the rule or is an equivalent Plan meeting all applicable rule
requirements and includes a cross-reference of provisions
lYes MNo LJNA
If Plan calls for facilities, procedures, methods, or equipment not yet fully operational,
details of their installation and start-up are discussed (Note: Relevant for inspection
evaluation and testing baselines.)
lYes MNo MNA
112.7(a)(2)
If YES
The Plan includes deviations from the requirements of §§112.7(g),
(h)(2) and (3), and (i) and applicable subparts B and C of the rule,
except the secondary containment requirements in §§112.7(c) and
(h)(1), 112.8(c)(2),112.8(c)(11), 112.12(c)(2), and 112.12(c)(11)
• The Plan states reasons for nonconformance
• Alternative measures described in detail and provide equivalent
environmental protection (Note: Inspector should document if
the environmental equivalence is implemented in the field, in
accordance with the Plan's description)
jYes |_|No |_|NA
]Yes EH No CHlSIA
MO HNA
lYes MNo
NA
Describe each deviation and reasons for nonconformance:
Onshore Facilities (Excluding Oil Production)
Page 6 of 14
December 2012(12-10-12)
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Appendix G: SPCC Inspection Checklists
PLAN
FIELD
112.7(a)(3)
IV
(v)
VI
Plan describes physical layout of facility and includes a diagram7
that identifies:
• Location and contents of all regulated fixed oil storage containers
• Storage areas where mobile or portable containers are located
• Completely buried tanks otherwise exempt from the SPCC requirements
(marked as "exempt")
• Transfer stations
• Connecting pipes, including intra-facility gathering lines that are
otherwise exempt from the requirements of this part under §112.1 (d)(11)
lYes
No
Yes MNo
Plan addresses each of the following:
For each fixed container, type of oil and storage capacity (see
Attachment A of this checklist). For mobile or portable containers,
type of oil and storage capacity for each container or an estimate of
the potential number of mobile or portable containers, the types of
oil, and anticipated storage capacities
Discharge prevention measures, including procedures for routine
handling of products (loading, unloading, and facility transfers, etc.)
Discharge or drainage controls, such as secondary containment
around containers, and other structures, equipment, and procedures
for the control of a discharge
Countermeasures for discharge discovery, response, and cleanup
(both facility's and contractor's resources)
Methods of disposal of recovered materials in accordance with
applicable legal requirements
Contact list and phone numbers for the facility response coordinator,
National Response Center, cleanup contractors with an agreement
for response, and all Federal, State, and local agencies who must
be contacted in the case of a discharge as described in §112.1 (b)
lYes MNo
jYes
]Yes
]Yes
]Yes
I Yes
jNo
]NO
]NO
]NO
]NO
JYes LJNo
]Yes DNO
JYes C|No
lYes DNO
112.7(a)(4)
Does not apply if the facility has submitted an FRP under §112.20: [_
Plan includes information and procedures that enable a person reporting
an oil discharge as described in §112.1(b) to relate information on the:
lYes
NO FNA
Exact address or location and phone
number of the facility;
Date and time of the discharge;
Type of material discharged;
Estimates of the total quantity discharged;
Estimates of the quantity discharged as
described in §112.1(b);
Source of the discharge;
Description of all affected media;
Cause of the discharge;
Damages or injuries caused by the discharge;
Actions being used to stop, remove, and
mitigate the effects of the discharge;
Whether an evacuation may be needed; and
Names of individuals and/or organizations who
have also been contacted.
112.7(a)(5)
Does not apply if the facility has submitted a FRP under § 112.20:
Plan organized so that portions describing procedures to be used
when a discharge occurs will be readily usable in an emergency
lYes
No
NA
112.7(b)
Plan includes a prediction of the direction, rate of flow, and total
quantity of oil that could be discharged for each type of major
equipment failure where experience indicates a reasonable potential
for equipment failure
lYes
No MNA
Comments:
Note in _
Onshore Facilities (Excluding Oil Production)
fegram, the description of the physical layout of facility, and what is observed io4h£ field
Page 7 of 14 December 2012~(12-10-12)
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Appendix G: SPCC Inspection Checklists
112.7(c)
112.7(d)
If YES
PLAN FIELD
Appropriate containment and/or diversionary structures or equipment are provided to prevent a discharge as described
in §112.1(b), except as provided in §112.7(k) of this section for certain qualified operational equipment. The
entire containment system, including walls and floors, are capable of containing oil and are constructed to prevent
escape of a discharge from the containment system before cleanup occurs. The method, design, and capacity for
secondary containment address the typical failure mode and the most likely quantity of oil that would be discharged.
See Attachment A of this checklist.
For onshore facilities, one of the following or its equivalent:
• Dikes, berms, or retaining walls sufficiently • Weirs, booms or other barriers;
impervious to contain oil; . Spi|| diversion pond;
* Curbing or drip pans; . Retention ponds; or
• Sumps and collection systems; . Sorbent materials.
• Culverting, gutters or other drainage systems;
Identify which of the following are present at the facility and if appropric
equipment are provided as described above:
I \ Bulk storage containers
I ^Mobile/portable containers
I loil-filled operational equipment (as defined in 1 1 2.2)
I lother oil-filled equipment (i.e., manufacturing equipment)
LJ Piping and related appurtenances
LJ Mobile refuelers or non-transportation-related tank cars
1 (Transfer areas, equipment and activities
L_| Identify any other equipment or activities that are not listed
above:
Secondary containment for one (or more) of the following provisions
is determined to be impracticable:
| [General secondary containment | JBulk storage containers
§112.7(c) §§112.8(c)(2)/112.12(c)(2)
[ Loading/unloading rack | | Mobile/portable
§1 12.7(h)(1) containers§§1 12.8(c)(1 1)/
112.12(c)(11)
• The impracticability of secondary containment is clearly
demonstrated and described in the Plan
• For bulk storage containers,8 periodic integrity testing of
containers and integrity and leak testing of the associated valves
and piping is conducted
(Does not apply if the facility has submitted a FRP under §1 12.20):
• Contingency Plan following the provisions of 40 CFR part 109 is
provided (see Attachment C of this checklist) AND
• Written commitment of manpower, equipment, and materials
required to expeditiously control and remove any quantity of oil
discharged that may be harmful
ate containment and/or diversionary structures or
Cves CNO CNA Cvesdxio CNA
Cves DNO CNA
dves DNO CNA
Dves DNO DNA
Elves DNO DMA
Dves CNO CNA
Cves DNO CNA
Dves DNO CNA
Qves DNO
Dves EH NO QXIA
CUves DNO ONA
Dves C|NO DMA
CvesDNo DMA
CvesdNo DMA
DYesDNo DMA
CvesCNo DNA
nvesDNo DNA
CvesCNo DMA
CvesCNo CNA
nYesQixio DNA
Qves C|NO DNA
HHveslZlNo DMA
Comments:
8 These ^BWWftfP ^8«ibt
Onshore Facilities (Excluding Oil Production)
itainers, when an impracticability determination has been made by the PE
Page 8 of 14
G-8
December 2012 (12-10-12)
-------
Appendix G: SPCC Inspection Checklists
PLAN
FIELD
112.7(e)
Inspections and tests conducted in accordance with written
procedures
Record of inspections or tests signed by supervisor or inspector
Kept with Plan for at least 3 years (see Attachment B of this
checklist)9
jYes
JYes
I Yes
jNo
]NO
I No
| Yes |_| No
YesNo
112.7(f)
(D
(2)
(3)
Personnel, training, and oil discharge prevention procedures
Training of oil-handling personnel in operation and maintenance of
equipment to prevent discharges; discharge procedure protocols;
applicable pollution control laws, rules, and regulations; general
facility operations; and contents of SPCC Plan
Person designated as accountable for discharge prevention at the
facility and reports to facility management
Discharge prevention briefings conducted at least once a year for oil
handling personnel to assure adequate understanding of the Plan.
Briefings highlight and describe known discharges as described in
§112.1 (b) or failures, malfunctioning components, and any recently
developed precautionary measures
JYes LjNo LJNA
Yes
]Yes
NA
NA
jYesLJNo |_|NA
NA
112.7(g)
Plan describes how to:
• Secure and control access to the oil handling, processing and
storage areas;
• Secure master flow and drain valves;
• Prevent unauthorized access to starter controls on oil pumps;
• Secure out-of-service and loading/unloading connections of oil
pipelines; and
• Address the appropriateness of security lighting to both prevent
acts of vandalism and assist in the discovery of oil discharges.
JYes
JNo IINA
JYesII No
NA
112.7(h)
If YES (1)
Tank car and tank truck loading/unloading rack is present at the facility | |Yes | | No
Loading/unloading rack means a fixed structure (such as a platform, gangway) necessary for loading or unloading a tank truck or tank
car, which is located at a facility subject to the requirements of this part. A loading/unloading rack includes a loading or unloading arm,
and may include any combination of the following: piping assemblages, valves, pumps, shut-off devices, overfill sensors, or personnel
safety devices.
Does loading/unloading rack drainage flow to catchment basin or
treatment facility designed to handle discharges or use a quick
drainage system?
Containment system holds at least the maximum capacity of the
largest single compartment of a tank car/truck loaded/unloaded at
the facility
(2)
(3)
An interlocked warning light or physical barriers, warning signs,
wheel chocks, or vehicle brake interlock system in the area adjacent
to the loading or unloading rack to prevent vehicles from departing
before complete disconnection of flexible or fixed oil transfer lines
Lower-most drains and all outlets on tank cars/trucks inspected prior
to filling/departure, and, if necessary ensure that they are tightened,
adjusted, or replaced to prevent liquid discharge while in transit
Yes MNo MNA
Yes MNo MNA
Yes MNo MNA
Yes MNo MNA
lYesMNo MNA
YesMNo LJNA
YesMNo MNA
DNA
Comments:
9 Records of inspections and tests kept under usual and customary business practices will suffice
10 Note th^c^fflE&yf<^°^ for §112-7(h) to apply
Onshore Facilities (Excluding Oil Production) Page 9 of 14
December 2012(12-10-12)
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Appendix G: SPCC Inspection Checklists
PLAN
FIELD
Brittle fracture evaluation of field-constructed aboveground
containers is conducted after tank repair, alteration, reconstruction,
or change in service that might affect the risk of a discharge or after
a discharge/failure due to brittle fracture or other catastrophe, and
appropriate action taken as necessary (applies to only field-
constructed aboveground containers)
lYes
iNo MNA
Yes
No MNA
Discussion of conformance with applicable more stringent State
rules, regulations, and guidelines and other effective discharge
prevention and containment procedures listed in 40 CFR part 112
lYes
INO MNA
112.7(k)
If YES
Qualified oil-filled operational equipment is present at the facility |_|Yes I I No
Oil-filled operational equipment means equipment that includes an oil storage container (or multiple containers) in which the oil is
present solely to support the function of the apparatus or the device. Oil-filled operational equipment is not considered a bulk storage
container, and does not include oil-filled manufacturing equipment (flow-through process). Examples of oil-filled operational
equipment include, but are not limited to, hydraulic systems, lubricating systems (e.g. , those for pumps, compressors and other
rotating equipment, including pumpjack lubrication systems), gear boxes, machining coolant systems, heat transfer systems,
transformers, circuit breakers, electrical switches, and other systems containing oil solely to enable the operation of the device.
Check which apply:
Secondary Containment provided in accordance with 112.7(c) I I
Alternative measure described below (confirm eligibility) | |
112.7(k)
Qualified Oil-Filled Operational Equipment
• Has a single reportable discharge as described in §1 12.1 (b) from any oil-filled |_|Yes
operational equipment exceeding 1 ,000 U.S. gallons occurred within the three years
prior to Plan certification date?
• Have two reportable discharges as described in §1 12.1 (b) from any oil-filled QYes
operational equipment each exceeding 42 U.S. gallons occurred within any 12-month
period within the three years prior to Plan certification date?12
If YES for either, secondary containment in accordance with §112.7(c) is required
• Facility procedure for inspections or monitoring program to
detect equipment failure and/or a discharge is established and
documented
Does not apply if the facility has submitted a FRP under §112.20:
• Contingency plan following 40 CFR part 109 (see Attachment C
of this checklist) is provided in Plan AND
• Written commitment of manpower, equipment, and materials
required to expeditiously control and remove any quantity of oil
discharged that may be harmful is provided in Plan
No NA
NO NA
Comments:
" This provision does not apply to oil-filled manufacturing equipment (flow-through process)
12 Oil discharges that result from natural disasters, acts of war, or terrorism are not included in this determination. The gallon amount(s) specified (either
1,000 or 42) refers to the amount of oil that actually reaches navigable waters or adjoining shorelines not the total amount of oil spilled. The entire
Onshore Facilities (Excluding Oil Production) Page 10 of 14 December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ONSHORE FACILITIES (EXCLUDING PRODUCTION)
40 CFR 112.8/112.12
PLAN
FIELD
112.8(b)/112.12(b) Facility Drainage
Diked Areas
(D
(2)
Drainage from diked storage areas is:
• Restrained by valves, except where facility systems are
designed to control such discharge, OR
• Manually activated pumps or ejectors are used and the condition
of the accumulation is inspected prior to draining dike to ensure
no oil will be discharged
Diked storage area drain valves are manual, open-and-closed
design (not flapper-type drain valves)
If drainage is released directly to a watercourse and not into an
onsite wastewater treatment plant, retained storm water is inspected
and discharged per §§112.8(c)(3)(ii), (iii), and (iv) or
§§112.12(c)(3)(ii), (iii), and(iv).
Yes llNo LJNA
jYes
|No
MO
|NA
MA
Yes llNo
NA
JYes LJNo
]Yes HMO
INA
INA
Undiked Areas
(3)
(4)
(5)
If YES
Drainage from undiked areas with a potential for discharge designed
to flow into ponds, lagoons, or catchment basins to retain oil or
return it to facility. Catchment basin located away from flood areas.13
Yes
No MIMA
Yes
NO MNA
If facility drainage not engineered as in (b)(3) (i.e., drainage flows
into ponds, lagoons, or catchment basins) then the facility is
equipped with a diversion system to retain oil in the facility in the
event of an uncontrolled discharge.14
Yes
|No II NA
Yes
NO MNA
Are facility drainage waters continuously treated in more than one
treatment unit and pump transfer is needed?
• Two "lift" pumps available and at least one permanently installed
• Facility drainage systems engineered to prevent a discharge as
described in §112.1(b) in the case of equipment failure or
human error
JYes |_|No
JYes DNO
JYes HNO
|NA
NA
NA
JYes LJNo
JYes DNO
JYes |~~|No
JNA
]NA
INA
Comments:
112.8(c)/112.12(c) Bulk Storage Containers |_|NA
Bulk storage container means any container used to store oil. These containers are used for purposes including, but not limited to, the storage of oil
prior to use, while being used, or prior to further distribution in commerce. Oil-filled electrical, operating, or manufacturing equipment is not a bulk
storage container.
If bulk storage containers are not present, mark this section Not Applicable (NA). If present, complete this section and Attachment A of this checklist.
(D
Containers materials and construction are compatible with material
stored and conditions of storage such as pressure and temperature
Yes MNo MNA
Yes |_|No MNA
(2)
Except for mobile refuelers and other non-transportation-related tank
trucks, construct all bulk storage tank installations with secondary
containment to hold capacity of largest container and sufficient
freeboard for precipitation
Diked areas sufficiently impervious to contain discharged oil OR
Alternatively, any discharge to a drainage trench system will be
safely confined in a facility catchment basin or holding pond
Yes MNo MNA
Yes MNo MNA
| Yes
I Yes
JNo
I No
JNA
]NA
I Yes
JYes
I No
]NO
INA
INA
13 Oil discharges that result from natural disasters, acts of war, or terrorism are not included in this determination. The gallon amount(s) specified (either
1,000 or 42) refers to the amount of oil that actually reaches navigable waters or adjoining shorelines not the total amount of oil spilled. The entire
volume of the discharge is oil for this determination.
14 These
Onshore Facilities (Excluding Oil Production)
is used for containment; otherwise mark NA
Page 11 of 14
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
PLAN
FIELD
(3)
If YES
Is there drainage of uncontaminated rainwater from diked areas into
a storm drain or open watercourse?
lYes
No LJNA
Yes
No MNA
Bypass valve normally sealed closed
Retained rainwater is inspected to ensure that its presence will
not cause a discharge as described in §112.1 (b)
Bypass valve opened and resealed under responsible
supervision
Adequate records of drainage are kept; for example, records
required under permits issued in accordance with 40 CFR
§§122.41 (j)(2) and (m)(3)
jYes
]Yes
JYes
JYes
jNo
]NO
]NO
I No
JNA
]NA
]NA
INA
|Yes
| Yes
JYes
lYes
| No
]NO
]NO
I No
INA
]NA
]NA
INA
(4)
For completely buried metallic tanks installed on or after January 10,
1974 (if not exempt from SPCC regulation because subject to all of
the technical requirements of 40 CFR part 280 or 281):
• Provide corrosion protection with coatings or cathodic
protection compatible with local soil conditions
• Regular leak testing conducted
Yes UNo UNA
Yes IjNo
NA
JYes LJNo
Yes IjNo
INA
INA
(5)
(6)
The buried section of partially buried or bunkered metallic tanks
protected from corrosion with coatings or cathodic protection
compatible with local soil conditions
JYes |_|No
NA
Yes IjNo
NA
Test or inspect each aboveground container for integrity on a
regular schedule and whenever you make material repairs.
Techniques include, but are not limited to: visual inspection,
hydrostatic testing, radiographic testing, ultrasonic testing,
acoustic emissions testing, or other system of non-destructive
testing
Appropriate qualifications for personnel performing tests and
inspections are identified in the Plan and have been assessed
in accordance with industry standards
The frequency and type of testing and inspections are
documented, are in accordance with industry standards and
take into account the container size, configuration and design
Comparison records of aboveground container integrity testing
are maintained
Container supports and foundations regularly inspected
Outside of containers frequently inspected for signs of
deterioration, discharges, or accumulation of oil inside diked
areas
Records of all inspections and tests maintained15
Yes MNo MNA
Yes MNo
NA
Yes
NA
NA
Yes NO NA
Yes UNO
Yes
Yes
NA
NO NA
Yes NO
JYes CNO
]Yes DNO
I Yes HNo
NA
NA
NA
NA
NA
Integrity Testing Standard identified in the Plan:
112.12
(Applies to
AFVO Facilities
only)
Conduct formal visual inspection on a regular schedule for bulk
storage containers that meet all of the following conditions:
• Have no external insulation; and
• Shop-fabricated.
• Subject to 21 CFR part 110;
• Elevated;
• Constructed of austenitic stainless
steel;
In addition, you must frequently inspect the outside of the container
for signs of deterioration, discharges, or accumulation of oil inside
diked areas.
You must determine and document in the Plan the appropriate
qualifications for personnel performing tests and inspections.16
Yes UNO MNA
Yes UNO UNA
Yes UNO UNA
I Yes UNO UNA
I Yes UNO MNA
I Yes UNO UNA
Onshore Facilities (Excluding Oil Production)
business practices wi" suffice
Page 12 of 14
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
(7)
(8)
(9)
(10)
(11)
Leakage through defective internal heating coils controlled:
• Steam returns and exhaust lines from internal heating coils
that discharge into an open watercourse are monitored for
contamination, OR
• Steam returns and exhaust lines pass through a settling
tank, skimmer, or other separation or retention system
PLAN
DYSS Cho C|NA
Dves DNO DMA
FIELD
dYesEHNo DMA
nvesDNo DMA
Each container is equipped with at least one of the following for CHves I [NO E^NA Q]Yes | |NO EH NA
liquid level sensing:
• High liquid level alarms with an audible or visual • Direct audible or code signal communication between container gauger
signal at a constantly attended operation or and pumping station;
surveillance station, or audible air vent in smaller . Fast response system for determining liquid level (such as digital
facilities; computers, telepulse, or direct vision gauges) and a person present to
• High liquid level pump cutoff devices set to stop monitor gauges and overall filling of bulk containers; or
flow at a predetermined container content level; . Regu|ar|y test liquid level sensing devices to ensure proper operation.
Effluent treatment facilities observed frequently enough to detect
possible system upsets that could cause a discharge as described in
§112.1(b)
Visible discharges which result in a loss of oil from the container,
including but not limited to seams, gaskets, piping, pumps, valves,
rivets, and bolts are promptly corrected and oil in diked areas is
promptly removed
Mobile or portable containers positioned to prevent a discharge as
described in §112.1(b).
Mobile or portable containers (excluding mobile refuelers and other
non-transportation-related tank trucks) have secondary containment
with sufficient capacity to contain the largest single compartment or
container and sufficient freeboard to contain precipitation
Dves DNO DNA
Dves DNO DMA
Dves DNO DNA
Dves DNO DNA
Qves DNO DNA
Dves D NO DMA
Qves D NO DMA
Qves QNO DNA
1 1 2.8(d)/1 1 2.1 2(d)Facility transfer operations, pumping, and facility process
(D
(2)
(3)
(4)
(5)
Buried piping installed or replaced on or after August 16, 2002 has
protective wrapping or coating
Buried piping installed or replaced on or after August 16, 2002 is
also cathodically protected or otherwise satisfies corrosion protection
standards for piping in 40 CFR part 280 or 281
Buried piping exposed for any reason is inspected for deterioration;
corrosion damage is examined; and corrective action is taken
Piping terminal connection at the transfer point is marked as to origin
and capped or blank-flanged when not in service or in standby
service for an extended time
Pipe supports are properly designed to minimize abrasion and
corrosion and allow for expansion and contraction
Aboveground valves, piping, and appurtenances such as flange
joints, expansion joints, valve glands and bodies, catch pans,
pipeline supports, locking of valves, and metal surfaces are
inspected regularly to assess their general condition
Integrity and leak testing conducted on buried piping at time of
installation, modification, construction, relocation, or replacement
Vehicles warned so that no vehicle endangers aboveground piping
and other oil transfer operations
Dves D NO DMA
dves CNO CNA
CHves C|NO C|NA
Dves DNO DMA
ClYes CNO CNA
Dves DNO DMA
Cves CNO E]NA
Dves DNO DNA
Dves DNO DMA
Cves CNO DNA
CUves CH NO DMA
Dves DNO DMA
ClYes CHisio CNA
Dves D NO DMA
HHYes d NO DMA
Dves DNO DNA
Comments:
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Onshore Facilities (Excluding Oil Production)
Page 13 of 14
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
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SPCC GUIDANCE FOR REGIONAL INSPECTORS G-14
Onshore Facilities (Excluding Oil Production) Page 14 of 14 December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT A: SPCC FIELD INSPECTION AND PLAN REVIEW TABLE
Documentation of Field Observations for Containers and Associated Requirements
Inspectors should use this table to document observations of containers as needed.
Containers and Piping
Check containers for leaks, specifically looking for: drip marks, discoloration of tanks, puddles containing spilled or leaked material,
corrosion, cracks, and localized dead vegetation, and standards/specifications of construction.
Check aboveground container foundation for: cracks, discoloration, and puddles containing spilled or leaked material, settling, gaps
between container and foundation, and damage caused by vegetation roots.
Check all piping for: droplets of stored material, discoloration, corrosion, bowing of pipe between supports, evidence of stored
material seepage from valves or seals, evidence of leaks, and localized dead vegetation. For all aboveground piping, include the
general condition of flange joints, valve glands and bodies, drip pans, pipe supports, bleeder and gauge valves, and other such items
(Document in comments section of §112.8(d) or 112.12(d).)
Secondary Containment (Active and Passive)
Check secondary containment for: containment system (including walls and floor) ability to contain oil such that oil will not escape
the containment system before cleanup occurs, proper sizing, cracks, discoloration, presence of spilled or leaked material (standing
liquid), erosion, corrosion, penetrations in the containment system, and valve conditions.
Check dike or berm systems for: level of precipitation in dike/available capacity, operational status of drainage valves (closed), dike
or berm impermeability, debris, erosion, impermeability of the earthen floor/walls of diked area, and location/status of pipes, inlets,
drainage around and beneath containers, presence of oil discharges within diked areas.
Check drainage systems for: an accumulation of oil that may have resulted from any small discharge, including field drainage
systems (such as drainage ditches or road ditches), and oil traps, sumps, or skimmers. Ensure any accumulations of oil have been
promptly removed.
Check retention and drainage ponds for: erosion, available capacity, presence of spilled or leaked material, debris, and stressed
vegetation.
Check active measures (countermeasures) for: amount indicated in plan is available and appropriate; deployment procedures are
realistic; material is located so that they are readily available; efficacy of discharge detection; availability of personnel and training,
appropriateness of measures to prevent a discharge as described in §112.1 (b).
Container ID/ General
Condition16
Aboveground or Buried Tank
Storage Capacity and Type
of Oil
Type of Containment/
Drainage Control
Overfill Protection and
Testing & Inspections
16 ldentify .
Onshore Facilities (Excluding Oil Production)
B for comp|ete|y buried
Page A-1of2
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT A: SPCC FIELD INSPECTION AND PLAN REVIEW TABLE (CONT.)
Documentation of Field Observations for Containers and Associated Requirements
Container ID/ General
Condition17
Aboveground or Buried Tank
Storage Capacity and Type
of Oil
Type of Containment/
Drainage Control
Overfill Protection and
Testing & Inspections
Identify each tank with either an A to indicate aboveground or B for completely buried
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Onshore Facilities (Excluding Oil Production)
PageA-2of2
G-16
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT B: SPCC INSPECTION AND TESTING CHECKLIST
Required Documentation of Tests and Inspections
Records of inspections and tests required by 40 CFR part 112 signed by the appropriate supervisor or inspector must be kept by all
facilities with the SPCC Plan for a period of three years. Records of inspections and tests conducted under usual and customary
business practices will suffice. Documentation of the following inspections and tests should be kept with the SPCC Plan.
Inspection or Test
Documentation
Present
Not
Present
Not
Applicable
112.7-General SPCC Requirements
(d)
(d)
(h)(3)
(i)
k(2)(i)
Integrity testing for bulk storage containers with no secondary containment system
and for which an impracticability determination has been made
Integrity and leak testing of valves and piping associated with bulk storage
containers with no secondary containment system and for which an impracticability
determination has been made
Inspection of lowermost drain and all outlets of tank car or tank truck prior to filling
and departure from loading/unloading rack
Evaluation of field-constructed aboveground containers for potential for brittle
fracture or other catastrophic failure when the container undergoes a repair,
alteration, reconstruction or change in service or has discharged oil or failed due to
brittle fracture failure or other catastrophe
Inspection or monitoring of qualified oil-filled operational equipment when the
equipment meets the qualification criteria in §1 1 2.7(k)(1 ) and facility
owner/operator chooses to implement the alternative requirements in §112.7(k)(2)
that include an inspection or monitoring program to detect oil-filled operational
equipment failure and discharges
D
n
D
n
n
D
n
D
n
•
D
D
D
n
°
11 2.8/11 2.1 2-Onshore Facilities (excluding oil production facilities)
(b)(D, (b)(2)
(c)(3)
(c)(4)
(c)(6)
(c)(6),
(c)(10)
(c)(6)
(c)(8)(v)
(c)(9)
(d)(D
(d)(4)
(d)(4)
Inspection of storm water released from diked areas into facility drainage directly to
a watercourse
Inspection of rainwater released directly from diked containment areas to a storm
drain or open watercourse before release, open and release bypass valve under
supervision, and records of drainage events
Regular leak testing of completely buried metallic storage tanks installed on or after
January 1 0, 1 974 and regulated under 40 CFR 1 1 2
Regular integrity testing of aboveground containers and integrity testing after
material repairs, including comparison records
Regular visual inspections of the outsides of aboveground containers, supports
and foundations
Frequent inspections of diked areas for accumulations of oil
Regular testing of liquid level sensing devices to ensure proper operation
Frequent observations of effluent treatment facilities to detect possible system
upsets that could cause a discharge as described in §1 1 2.1 (b)
Inspection of buried piping for damage when piping is exposed and additional
examination of corrosion damage and corrective action, if present
Regular inspections of aboveground valves, piping and appurtenances and
assessments of the general condition of flange joints, expansion joints, valve
glands and bodies, catch pans, pipeline supports, locking of valves, and metal
surfaces
Integrity and leak testing of buried piping at time of installation, modification,
construction, relocation or replacement
D
D
D
D
D
n
n
n
n
n
n
n
D
n
n
n
Q
n
n
n
D
n
n
n
n
n
n
G
n
n
n
n
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Onshore Facilities (Excluding Oil Production)
Page B-1 of 2
G-17
December 2012 (12-10-12)
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SPCC GUIDANCE FOR REGIONAL INSPECTORS G-18
Onshore Facilities (Excluding Oil Production) Page B-2 of 2 December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT C: SPCC CONTINGENCY PLAN REVIEW CHECKLIST dNA
40 CFR Part 109-Criteria for State, Local and Regional Oil Removal Contingency Plans
If SPCC Plan includes an impracticability determination for secondary containment in accordance with §112.7(d), the facility
owner/operator is required to provide an oil spill contingency plan following 40 CFR part 109, unless he or she has submitted a FRP
under §112.20. An oil spill contingency plan may also be developed, unless the facility owner/operator has submitted a FRP under
§112.20 as one of the required alternatives to general secondary containment for qualified oil filled operational equipment in
accordance with §112.7(k).
109.5-Development and implementation criteria for State, local and regional oil removal contingency plans18
(a)
(b)
(D
(2)
(3)
(4)
(c)
(D
(2)
(3)
(d)
(D
(2)
(3)
(4)
(5)
(e)
Definition of the authorities, responsibilities and duties of all persons, organizations or agencies which are to
be involved in planning or directing oil removal operations.
Establishment of notification procedures for the purpose of early detection and timely notification of an oil
discharge including:
The identification of critical water use areas to facilitate the reporting of and response to oil discharges.
A current list of names, telephone numbers and addresses of the responsible persons (with alternates) and
organizations to be notified when an oil discharge is discovered.
Provisions for access to a reliable communications system for timely notification of an oil discharge, and the
capability of interconnection with the communications systems established under related oil removal
contingency plans, particularly State and National plans (e.g., National Contingency Plan (NCP)).
An established, prearranged procedure for requesting assistance during a major disaster or when the
situation exceeds the response capability of the State, local or regional authority.
Provisions to assure that full resource capability is known and can be committed during an oil discharge
situation including:
The identification and inventory of applicable equipment, materials and supplies which are available locally
and regionally.
An estimate of the equipment, materials and supplies that would be required to remove the maximum oil
discharge to be anticipated.
Development of agreements and arrangements in advance of an oil discharge for the acquisition of
equipment, materials and supplies to be used in responding to such a discharge.
Provisions for well-defined and specific actions to be taken after discovery and notification of an oil discharge
including:
Specification of an oil discharge response operating team consisting of trained, prepared and available
operating personnel.
Pre-designation of a properly qualified oil discharge response coordinator who is charged with the
responsibility and delegated commensurate authority for directing and coordinating response operations and
who knows how to request assistance from Federal authorities operating under existing national and regional
contingency plans.
A preplanned location for an oil discharge response operations center and a reliable communications system
for directing the coordinated overall response operations.
Provisions for varying degrees of response effort depending on the severity of the oil discharge.
Specification of the order of priority in which the various water uses are to be protected where more than one
water use may be adversely affected as a result of an oil discharge and where response operations may not
be adequate to protect all uses.
Specific and well defined procedures to facilitate recovery of damages and enforcement measures as
provided for by State and local statutes and ordinances.
Yes
D
n
rj
n
n
n
n
n
n
n
n
n
n
n
rj
n
n
No
D
n
rj
n
D
n
n
n
n
n
n
n
a
n
rj
D
D
8 The contingency plan should be consistent with all applicable state and local plans, Area Contingency Plans, and the NCP.
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Onshore Facilities (Excluding Oil Production)
Page C-1 of 2
G-19
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
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SPCC GUIDANCE FOR REGIONAL INSPECTORS G-20
Onshore Facilities (Excluding Oil Production) Page C-2 of 2 December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT D: TIER II QUALIFIED FACILITY CHECKLIST
NA
TIER II QUALIFIED FACILITY PLAN REQUIREMENTS —40 CFR 112.6(b)
(iii)
(iv)
Plan Certification: Owner/operator certified in the Plan that:
He or she is familiar with the requirements of 40 CFR part 112
He or she has visited and examined the facility19
The Plan has been prepared in accordance with accepted and sound industry practices and
standards and with the requirements of this part
Procedures for required inspections and testing have been established
He or she will fully implement the Plan
The facility meets the qualification criteria set forth under §112.3(g)(2)
The Plan does not deviate from any requirements as allowed by §§112.7(a)(2) and 112.7(d),
except as described under §112.6(b)(3)(i) or (ii)
The Plan and individual(s) responsible for implementing the Plan have the full approval of
management and the facility owner or operator has committed the necessary resources to
fully implement the Plan.
JYes
]Yes
]Yes
JYes
]Yes
JYes
]Yes
JYes
lYes
jNo
JNo
]NO
| No
]NO
I No
]NO
No
JNA
JNA
JNA
]NA
JNA
]NA
]NA
No MNA
112.6(b)(2)
If YES
(i)
If YES
Technical Amendments: The owner/operator self-certified the Plan's technical amendments
for a change in facility design, construction, operation, or maintenance that affected potential
for a §112.1 (b) discharge
• Certification of technical amendments is in accordance with the self-certification
provisions of §112.6(b)(1).
lYes
Yes
No MNA
No MNA
A PE certified a portion of the Plan (i.e., Plan is informally referred to as a hybrid Plan)
• The PE also certified technical amendments that affect the PE certified portion of the
Plan as required under §112.6(b)(4)(ii)
JYes
JYes
JNo
No
The aggregate aboveground oil storage capacity increased to more than 10,000 U.S. gallons
as a result of the change
lYes
If YES
The facility no longer meets the Tier II qualifying criteria in §112,3(g)(2) because
it exceeds 10,000 U.S. gallons in aggregate aboveground storage capacity.
The owner/operator prepared and implemented a Plan within 6 months following the change
and had it certified by a PE under §112.3(d)
JNA
JNA
NO MNA
I Yes MNo MNA
112.6(b)(3)
If YES
Plan Deviations: Does the Plan include environmentally equivalent alternative methods or
impracticability determinations for secondary containment?
Identify the alternatives in the hybrid Plan:
• Environmental equivalent alternative method(s) allowed under §112.7(a)(2);
• Impracticability determination under §112.7(d)
Yes MNo MNA
JYes
Yes
I No LJNA
I NO DNA
112.6(b)(4)
(i)
(A)
(B)
(C)
• For each environmentally equivalent measure, the Plan is accompanied by a written
statement by the PE that describes: the reason for nonconformance, the alternative
measure, and how it offers equivalent environmental protection in accordance with
§112.7(a)(2);
• For each secondary containment impracticability determination, the Plan explains the
reason for the impracticability determination and provides the alternative measures to
secondary containment required in §112.7(d)
AND
PE certifies in the Plan that:
He/she is familiar with the requirements of 40 CFR Part 112
He/she or a representative agent has visited and examined the facility
The alternative method of environmental equivalence in accordance with §112.7(a)(2) or the
determination of impracticability and alternative measures in accordance with §112.7(d) is
consistent with good engineering practice, including consideration of applicable industry
standards, and with the requirements of 40 CFR Part 112.
Yes
Yes
No NA
No MNA
JYes
JYes
Yes
| No
| No
No
JNA
JNA
JNA
Comments:
Note that only the person certifying the Plan can make the site visit
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Onshore Facilities (Excluding Oil Production)
Page D-1 of 2
G-21
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
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SPCC GUIDANCE FOR REGIONAL INSPECTORS G-22
Onshore Facilities (Excluding Oil Production) Page D-2 of 2 December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT E: ADDITIONAL COMMENTS
SPCC GUIDANCE FOR REGIONAL INSPECTORS G-23
Onshore Facilities (Excluding Oil Production) Page E-1of2 December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT E: ADDITIONAL COMMENTS (CONT.)
SPCC GUIDANCE FOR REGIONAL INSPECTORS G-24
Onshore Facilities (Excluding Oil Production) Page E-2 of 2 December 2012 (12-10-12)
-------
Appendix G: SPCC Inspection Checklists
ATTACHMENT F: PHOTO DOCUMENTATION NOTES
Photo#
Photographer
Name
Time of
Photo Taken
Compass
Direction
Description
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Onshore Facilities (Excluding Oil Production)
Page F-1 of 2
G-25
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT F: PHOTO DOCUMENTATION NOTES (CONT.)
Photo#
Photographer
Name
Time of
Photo Taken
Compass
Direction
Description
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Onshore Facilities (Excluding Oil Production)
PageF-2of2
G-26
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
U.S. ENVIRONMENTAL PROTECTION AGENCY
SPCC FIELD INSPECTION AND PLAN REVIEW CHECKLIST
ONSHORE OIL DRILLING, PRODUCTION AND WORKOVER FACILITIES
Overview of the Checklist
This checklist is designed to assist EPA inspectors in conducting a thorough and nationally consistent inspection of a
facility's compliance with the Spill Prevention, Control, and Countermeasure (SPCC) rule at 40 CFR part 112. It is a
required tool to help federal inspectors (or their contractors) record observations for the site inspection and review of the
SPCC Plan. While the checklist is meant to be comprehensive, the inspector should always refer to the SPCC rule in its
entirety, the SPCC Regional Inspector Guidance Document, and other relevant guidance for evaluating compliance. This
checklist must be completed in order for an inspection to count toward an agency measure (i.e., OEM inspection
measures or GPRA). The completed checklist and supporting documentation (i.e. photo logs or additional notes) serve as
the inspection report.
This checklist addresses requirements for onshore oil drilling, production and workover facilities (including Tier II Qualified
Facilities that meet the eligibility criteria set forth in §112.3(g)(2)). Qualified facilities must meet the rule requirements in
§112.6 and other applicable sections specified in §112.6, except for deviations that provide environmental equivalence
and secondary containment impracticability determinations as allowed under §112.6.
Separate and standalone checklists address the requirements for:
All other onshore facilities including Tier II Qualified Facilities (i.e., those facilities not involved in oil drilling,
production and workover activities);
Offshore oil drilling, production and workover facilities; and
Tier I Qualified Facilities (for facilities that meet the eligibility criteria defined in §112.3(g)(1)).
The checklist is organized according to the SPCC rule. Each item in the checklist identifies the relevant section and
paragraph in 40 CFR part 112 where that requirement is stated.
• Sections 112.1 through 112.5 specify the applicability of the rule and requirements for the preparation,
implementation, and amendment of SPCC Plans. For these sections, the checklist includes data fields to be
completed, as well as several questions with "yes," "no" "NA" answers.
• Section 1 12.6 includes requirements for qualified facilities. These provisions are addressed in Attachment D.
• Section 1 12.7 includes general requirements that apply to all facilities (unless otherwise excluded).
• Section 1 12.9 specifies spill prevention, control, and countermeasures requirements for onshore oil drilling,
production and workover facilities
• Section 112.10 specifies spill prevention, control, and countermeasures requirements for onshore oil drilling,
production and workover facilities.
The inspector needs to evaluate whether the requirement is addressed adequately or inadequately in the SPCC Plan and
whether it is implemented adequately in the field (either by field observation or record review). For the SPCC Plan and
implementation in the field, if a requirement is addressed adequately, mark the "Yes" box in the appropriate column. If a
requirement is not addressed adequately, mark the "No" box. If a requirement does not apply to the particular facility or
the question asked is not appropriate for the facility, mark as "NA". Discrepancies or descriptions of inspector
interpretation of "No" vs. "NA" may be documented in the comments box subsequent to each section. If a provision of the
rule applies only to the SPCC Plan, the "Field" column is shaded.
Space is provided throughout the checklist to record comments. Additional space is available as Attachment E at the end
of the checklist. Comments should remain factual and support the evaluation of compliance.
Attachments
• Attachment A is for recording information about containers and other locations at the facility that require secondary
containment.
• Attachment B is a checklist for documentation of the tests and inspections the facility operator is required to keep
with the SPCC Plan.
• Attachment C is a checklist for oil spill contingency plans following 40 CFR 109. Unless a facility has submitted a
Facility Response Plan (FRP) under 40 CFR 112.20, a contingency plan following 40 CFR 109 is required if a facility
determines that secondary containment is impracticable as provided in 40 CFR 1 12.7(d). The same requirement for
an oil spill contingency plan applies to the owner or operator of a facility with qualified oil-filled operational equipment
that chooses to implement alternative requirements instead of general secondary containment requirements as
provided in 40 CFR 112.7(k).
• Attachment D is a checklist for Tier II Qualified Facilities.
• Attachment E is for recording additional comments or notes.
photos. G_27
Onshore Oil Drilling, Production and Workover Facilities Page 1 of 14 December 2012 (12-10-12)
-------
Appendix G: SPCC Inspection Checklists
FACILITY INFORMATION
FACILITY NAME:
LATITUDE:
LONGITUDE:
GPS DATUM:
Section/Township/Range:
FRS#/OIL DATABASE ID:
ICIS#:
ADDRESS:
CITY:
STATE:
ZIP:
COUNTY:
MAILING ADDRESS (IF DIFFERENT FROM FACILITY ADDRESS-IF NOT, PRINT "SAME"):
CITY:
STATE:
ZIP:
COUNTY:
TELEPHONE:
FACILITY CONTACT NAME/TITLE:
OWNER NAME:
OWNER ADDRESS:
CITY:
STATE:
ZIP:
COUNTY:
TELEPHONE:
FAX:
EMAIL:
FACILITY OPERATOR NAME (IF DIFFERENT FROM OWNER-IF NOT, PRINT "SAME"):
OPERATOR ADDRESS:
CITY:
STATE:
ZIP:
COUNTY:
TELEPHONE:
OPERATOR CONTACT NAME/TITLE:
FACILITY TYPE:
NAICS CODE:
HOURS PER DAY FACILITY ATTENDED:
TOTAL FACILITY CAPACITY:
TYPE(S) OF OIL STORED:
LOCATED IN INDIAN COUNTRY? MYES
NO RESERVATION NAME:
INSPECTION/PLAN REVIEW INFORMATION
PLAN REVIEW DATE:
REVIEWER NAME:
INSPECTION DATE:
TIME:
ACTIVITY ID NO:
LEAD INSPECTOR:
OTHER INSPECTOR(S):
INSPECTOR ACKNOWLEDGMENT
/ performed an SPCC inspection at the facility specified above.
INSPECTOR SIGNATURE:
DATE:
SUPERVISOR REVIEW/SIGNATURE:
DATE:
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Onshore Oil Drilling, Production and Workover Facilities
Page 2 of 14
G-28
December 2012 (12-10-12)
-------
Appendix G: SPCC Inspection Checklists
SPCC GENERAL APPLICABILITY—40 CFR 112.1
IS THE FACILITY REGULATED UNDER 40 CFR part 112?
The completely buried oil storage capacity is over 42,000 U.S. gallons, OR the aggregate aboveground oil
storage capacity is over 1,320 U.S. gallons AND
The facility is a non-transportation-related facility engaged in drilling, producing, gathering, storing,
processing, refining, transferring, distributing, using, or consuming oil and oil products, which due to its
location could reasonably be expected to discharge oil into or upon the navigable waters of the United
States
jYes
lYes
jNo
]NO
AFFECTED WATERWAY(S):
DISTANCE:
FLOW PATH TO WATERWAY:
Note: The following storage capacity is not considered in determining applicability of SPCC requirements:
Equipment subject to the authority of the U.S. Department of
Transportation, U.S. Department of the Interior, or Minerals Management
Service, as defined in Memoranda of Understanding dated November
24, 1971, and November 8, 1993; Tank trucks that return to an otherwise
regulated facility that contain only residual amounts of oil (EPA Policy
letter)
Completely buried tanks subject to all the technical requirements of 40
CFR part 280 or a state program approved under 40 CFR part 281;
Underground oil storage tanks deferred under 40 CFR part 280 that
supply emergency diesel generators at a nuclear power generation
facility licensed by the Nuclear Regulatory Commission (NRC) and
subject to any NRC provision regarding design and quality criteria,
including but not limited to CFR part 50;
Any facility or part thereof used exclusively for wastewater treatment
(production, recovery or recycling of oil is not considered wastewater
treatment); (This does not include other oil containers located at a
wastewater treatment facility, such as generator tanks or transformers)
• Containers smaller than 55 U.S. gallons;
• Permanently closed containers (as defined in §112.2);
• Motive power containers (as defined in §112.2);
• Hot-mix asphalt or any hot-mix asphalt containers;
• Heating oil containers used solely at a single-family residence;
• Pesticide application equipment and related mix containers;
• Any milk and milk product container and associated piping and
appurtenances; and
• Intra-facility gathering lines subject to the regulatory requirements
of 49 CFR part 192 or 195.
Does the facility have an SPCC Plan?
lYes
JNo
FACILITY RESPONSE PLAN (FRP) APPLICABILITY—40 CFR 112.20(f)
A non-transportation related onshore facility is required to prepare and implement an FRP as outlined in 40 CFR 112.20 if:
|_|The facility transfers oil over water to or from vessels and has a total oil storage capacity greater than or equal to
42,000 U.S. gallons, OR
L_|The facility has a total oil storage capacity of at least 1 million U.S. gallons, AND at least one of the following is true:
tjThe facility does not have secondary containment sufficiently large to contain the capacity of the largest aboveground tank
plus sufficient freeboard for precipitation.
| |The facility is located at a distance such that a discharge could cause injury to fish and wildlife and sensitive environments.
CjThe facility is located such that a discharge would shut down a public drinking water intake.
[_]The facility has had a reportable discharge greater than or equal to 10,000 U.S. gallons in the past 5 years.
Facility has FRP: LJYes
No
NA
FRP Number:
Facility has a completed and signed copy of Appendix C, Attachment C-ll,
"Certification of the Applicability of the Substantial Harm Criteria."
lYes
JNo
Comments:
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Onshore Oil Drilling, Production and Workover Facilities
Page 3 of 14
G-29
December 2012 (12-10-12)
-------
Appendix G: SPCC Inspection Checklists
SPCC TIER II QUALIFIED FACILITY APPLICABILITY— 40 CFR 112.3(g)(2)
The aggregate aboveground oil storage capacity is 10,000 U.S. gallons or less AND
In the three years prior to the SPCC Plan self-certification date, or since becoming subject to the rule (if the
facility has been in operation for less than three years), the facility has NOT had:
. A single discharge as described in §112. 1(b) exceeding 1,000 U.S. gallons, OR
• Two discharges as described in §112.1(b) each exceeding 42 U.S. gallons within any twelve-month period1
H:;H:
REQUIREMENTS FOR PREPARATION AND IMPLEMENTATION OF A SPCC PLAN— 40 CFR 112.3
Date facility began operations:
Date of initial SPCC Plan preparation: Current Plan version (date/number):
112.3(a)
112.3(d)
For drilling, production or workover facilities, including mobile or portable facilities, that are
offshore or have an offshore component; or facilities required to have and submit a FRP:
. In operation on or prior to November 1 0, 201 0: Plan prepared and/or amended and fully
implemented by November 10, 2010
. Facilities beginning operation after November 10, 2010:
o Plan prepared and fully implemented before drilling and workover facilities begin
operations; or
o Plan prepared and fully implemented within six months after oil production facilities
begin operations
For all other drilling, production or workover facilities, including mobile or portable facilities:
. In operation on or prior to November 1 0, 201 1 : Plan prepared and/or amended and fully
implemented by November 10, 2011
. Facilities beginning operation after November 1 0, 201 1 :
o Plan prepared and fully implemented before drilling and workover facilities begin
operations; or
o Plan prepared and fully implemented within six months after oil production facilities
begin operations
Plan is certified by a registered Professional Engineer (PE) and includes statements that the
PE attests:
. PE is familiar with the requirements of 40 CFR part 112
• PE or agent has visited and examined the facility
. Plan is prepared in accordance with good engineering practice including consideration
of applicable industry standards and the requirements of 40 CFR part 112
• Procedures for required inspections and testing have been established
. Plan is adequate for the facility
• For produced water containers subject to 1 12.9(c)(6), any procedure to minimize the
amount of free-phase oil is designed to reduce the accumulation of free-phase oil and
the procedures and frequency for required inspections, maintenance and testing have
been established and are described in the Plan, if applicable
dves CNO CNA
SI:
dves dNo dNA
PE Name: License No.: State: Date of certification:
112-3(6X1)
Plan is available onsite if attended at least 4 hours per day. If facility is unattended, Plan is
available at the nearest field office. (Please note nearest field office contact information in
comments section below.)
|>es DNO GNA
Comments:
1 Oil discharges that result from natural disasters, acts of war, or terrorism are not included in this determination. The gallon amount(s) specified (either
1,000 or 42) refers to the amount of oil that actually reaches navigable waters or adjoining shorelines not the total amount of oil spilled. The entire
volume of the discharge is oil for this determination.
2 An owner/operator who self-certifies a Tier II SPCC Plan may not include any environmentally equivalent alternatives or secondary containment
iaPE. G-30
December 2012 (12-10-12)
Onshore Oil Drilling, Production and Workover Facilities Page 4 of 14
-------
Appendix G: SPCC Inspection Checklists
AMENDMENT OF SPCC PLAN BY REGIONAL ADMINISTRATOR (RA)^40 CFR 112.4
If YES
,3
Has the facility discharged more than 1,000 U.S. gallons of oil in a single reportable discharge
or more than 42 U.S. gallons in each of two reportable discharges in any 12-month period?
• Was information submitted to the RA as required in §112.4(a)?4
. Was information submitted to the appropriate agency or agencies in charge of oil
pollution control activities in the State in which the facility is located§112.4(c)
• Date(s) and volume(s) of reportable discharges(s) under this section:
. Were the discharges reported to the NRC5?
jYes
JYes |
lYes I
Yes
jNo
]NO [
]NO [
No
|NA
]NA
Have changes required by the RA been implemented in the Plan and/or facility?
Yes
No IINA
Comments:
AMENDMENT OF SPCC PLAN BY THE OWNER OR OPERATOR—40 CFR 112.5
112.5(a)
If YES
Has there been a change at the facility that materially affects the potential for a discharge
described in§112.1(b)?
. Was the Plan amended within six months of the change?
. Were amendments implemented within six months of any Plan amendment?
Yes
NO
DNQ
112.5(b)
Review and evaluation of the Plan completed at least once every 5 years?
Following Plan review, was Plan amended within six months to include more effective
prevention and control technology that has been field-proven to significantly reduce the
likelihood of a discharge described in §112.1(b)?
Amendments implemented within six months of any Plan amendment?
Five year Plan review and evaluation documented?
JYes
JYes
JYes
lYes
| No
]NO
]NO
I No
JNA
JNA
]NA
INA
112.5(c)
Professional Engineer certification of any technical Plan amendments in accordance with all
applicable requirements of §112.3(d) [Except for self-certified Plans]
Yes
No NA
Name:
License No.:
State:
Date of certification:
Reason for amendment:
Comments:
3 A reportable discharge is a discharge as described in §112.1(b)(see 40 CFR part 110). The gallon amount(s) specified (either 1,000 or 42) refers to the
amount of oil that actually reaches navigable waters or adjoining shorelines not the total amount of oil spilled. The entire volume of the discharge is oil
for this determination
4 Triggering this threshold may disqualify the facility from meeting the Qualified Facility criteria if it occurred in the three years prior to self-certification
G-31
December 2012 (12-10-12)
to NRC
Onshore Oil Drilling, Production and Workover Facilities Page 5 of 14
-------
Appendix G: SPCC Inspection Checklists
GENERAL SPCC REQUIREMENTS^40 CFR 112.7
PLAN
FIELD
Management approval at a level of authority to commit the necessary resources to
fully implement the Plan6
I Yes
No
Plan follows sequence of the rule or is an equivalent Plan meeting all applicable rule
requirements and includes a cross-reference of provisions
lYes
No LJNA
If Plan calls for facilities, procedures, methods, or equipment not yet fully operational,
details of their installation and start-up are discussed (Note: Relevant for inspection
evaluation and testing baselines.)
lYes
iNo MNA
112.7(a)(2)
If YES
The Plan includes deviations from the requirements of §§112.7(g),
(h)(2) and (3), and (i) and applicable subparts B and C of the rule,
except the secondary containment requirements in §§112.7(c) and
(h)(1), 112.9(c)(2), 112.9(d)(3), and 112.10(c)
• The Plan states reasons for nonconformance
. Alternative measures described in detail and provide equivalent
environmental protection (Note: Inspector should document if
the environmental equivalence is implemented in the field, in
accordance with the Plan's description)
I Yes
INo MNA
jYes |_|No |_|NA
JYes DNO CUNA LJYes MNo
JNA
Describe each deviation and reasons for nonconformance:
May be
Onshore Oil Drilling, Production and Workover Facilities
Page 6 of 14
G-32
December 2012 (12-10-12)
-------
Appendix G: SPCC Inspection Checklists
PLAN
FIELD
112.7(a)(3)
(iv)
(v)
(vi)
Plan describes physical layout of facility and includes a diagram7
that identifies:
• Location and contents of all regulated fixed oil storage containers
• Storage areas where mobile or portable containers are located
• Completely buried tanks otherwise exempt from the SPCC
requirements (marked as "exempt")
• Transfer stations
• Connecting pipes, including intra-facility gathering lines that are
otherwise exempt from the requirements of this part under
Yes
No
Yes
No
Plan addresses each of the following:
For each fixed container, type of oil and storage capacity (see
Attachment A of this checklist). For mobile or portable containers,
type of oil and storage capacity for each container or an estimate of
the potential number of mobile or portable containers, the types of
oil, and anticipated storage capacities
Discharge prevention measures, including procedures for routine
handling of products (loading, unloading, and facility transfers, etc.)
Discharge or drainage controls, such as secondary containment
around containers, and other structures, equipment, and
procedures for the control of a discharge
Countermeasures for discharge discovery, response, and cleanup
(both facility's and contractor's resources)
Methods of disposal of recovered materials in accordance with
applicable legal requirements
Contact list and phone numbers for the facility response
coordinator, National Response Center, cleanup contractors with an
agreement for response , and all Federal, State, and local agencies
who must be contacted in the case of a discharge as described in
lYes MNo
jYes
]Yes
JYes
JYes
JYes
jNo
]NO
]NO
]NO
]NO
JYes |_|No
]Yes CHlMo
]Yes ONO
lYes HNO
112.7(a)(4)
lYes
Does not apply if the facility has submitted an FRP under §112.20:
Plan includes information and procedures that enable a person
reporting an oil discharge as described in §112.1 (b) to relate information on the:
No |_|NA
Exact address or location and phone
number of the facility;
Date and time of the discharge;
Type of material discharged;
Estimates of the total quantity discharged;
Estimates of the quantity discharged as
described in §112.1 (b);
Source of the discharge;
Description of all affected media;
Cause of the discharge;
Damages or injuries caused by the
discharge;
Actions being used to stop, remove, and
mitigate the effects of the discharge;
Whether an evacuation may be needed; and
Names of individuals and/or organizations
who have also been contacted.
112.7(a)(5)
Does not apply if the facility has submitted a FRP under §112.20:
Plan organized so that portions describing procedures to be used
when a discharge occurs will be readily usable in an emergency
Yes
I No MNA
112.7(b)
Plan includes a prediction of the direction, rate of flow, and total
quantity of oil that could be discharged for each type of major
equipment failure where experience indicates a reasonable
potential for equipment failure
I Yes
No MNA
Comments:
7 Note in
Onshore Oil Drilling, Production and Workover Facilities
, the description of the physical layout of facility, and what is observed iS-fl® field
Page 7 of 14 December 2012 (12-10-12)
-------
Appendix G: SPCC Inspection Checklists
PLAN
FIELD
112.7(c)
112.7(d)
If YES
Appropriate containment and/or diversionary structures or equipment are provided to prevent a discharge as
described in §112.1(b), except as provided in §112.7(k) of this section for certain qualified operational
equipment and §112.9(d)(3) for certain flowlines and intra-facility gathering lines at an oil production facility.
The entire containment system, including walls and floors, are capable of containing oil and are constructed to
prevent escape of a discharge from the containment system before cleanup occurs. The method, design, and
capacity for secondary containment address the typical failure mode and the most likely quantity of oil that would be
discharged. See Attachment A of this checklist.
For onshore facilities, one of the following or its equivalent:
• Dikes, berms, or retaining walls sufficiently • Weirs, booms or other barriers,
impervious to contain oil, . Spj|| diversion ponds,
. Curbing or drip pans, . Retention ponds, or
. Sumps and collection systems, . Sorbent materials.
• Culverting, gutters or other drainage systems,
Identify which of the following are present at the facility and if appropriate containment and/or diversionary structures
or equipment are provided as described above:
I Bulk storage containers
I Mobile/portable containers
I loil-filled operational equipment (as defined in 112.2)
Jother oil-filled equipment (i.e., manufacturing equipment)
I JPiping and related appurtenances
jMobile refuelers of non-transportation-related tank cars
jTransfer areas, equipment and activities
I lldentifv any other equipment or activities that are not listed
above:
Secondary containment for one (or more) of the following provisions
is determined to be impracticable:
| (General secondary containment
§112.7(c)
| | Loading/unloading rack
[ |Bulk storage containers
§§112.8(c)(2)/112.12(c)(2)
| | Mobile/portable
containers§§112.8(c)(11 )/112.12
• The impracticability of secondary containment is clearly
demonstrated and described in the Plan
. For bulk storage containers,8 periodic integrity testing of
containers and integrity and leak testing of the associated
valves and piping is conducted
(Does not apply if the facility has submitted a FRP under §112.20):
• Contingency Plan following the provisions of 40 CFR part 109 is
provided (see Attachment C of this checklist) AND
. Written commitment of manpower, equipment, and materials
required to expeditiously control and remove any quantity of oil
discharged that may be harmful
lYes
NO NA
I Yes
No LIMA
Yes
No NA
I Yes
No LJNA
I Yes
jNo LJNA
I Yes
JNo LJNA
lYes
JNo LJNA
I Yes
JNo MNA
Yes
MO
lYes
JNo MNA
Yes
No I NA
Yes
No MNA
Yes
No MNA
Yes
No MNA
lYes
JNo MNA
lYes
JNO MNA
lYesII No
|Yes |_|No |_|NA
]YBS DNO GNA
NA
jYes |_|No |_|NA
JYes |~~|No r~|NA
lYes IjNo MNA
Comments:
These
Onshore Oil Drilling, Production and Workover Facilities
, when an impracticability determination has been made by the PE G-34
Page 8 of 14 December 2012 (12-10-12)
-------
Appendix G: SPCC Inspection Checklists
PLAN
FIELD
112.7(e)
Inspections and tests conducted in accordance with written
procedures
Record of inspections or tests signed by supervisor or inspector
Kept with Plan for at least 3 years (see Attachment B of this
checklist)9
jYes
]Yes
I Yes
jNo
]NO
]NO
JYes
]Yes
Ives
JNo
]NO
]NO
112.7(f)
(1)
(2)
(3)
Personnel, training, and oil discharge prevention procedures
Training of oil-handling personnel in operation and maintenance of
equipment to prevent discharges; discharge procedure protocols;
applicable pollution control laws, rules, and regulations; general
facility operations; and contents of SPCC Plan
Person designated as accountable for discharge prevention at the
facility and reports to facility management
Discharge prevention briefings conducted at least once a year for
oil handling personnel to assure adequate understanding of the
Plan. Briefings highlight and describe known discharges as
described in §112.1(b) or failures, malfunctioning components, and
any recently developed precautionary measures
JYes |_|No |_|NA
JYes [UNO DMA
]Yes HMO r~|NA
JYes |_|No |_|NA
]Yes QNO ONA
lYes dlMo HNA
112.7(h)
Tank car and tank truck loading/unloading rack is present at the facility | |Yes | |No
Loading/unloading rack means a fixed structure (such as a platform, gangway) necessary for loading or unloading a tank truck or
tank car, which is located at a facility subject to the requirements of this part. A loading/unloading rack includes a loading or
unloading arm, and may include any combination of the following: piping assemblages, valves, pumps, shut-off devices, overfill
sensors, or personnel safety devices.
If YES (1)
(2)
(3)
Does loading/unloading rack drainage flow to catchment basin or
treatment facility designed to handle discharges or use a quick
drainage system?
Containment system holds at least the maximum capacity of the
largest single compartment of a tank car/truck loaded/unloaded at
the facility
An interlocked warning light or physical barriers, warning signs,
wheel chocks, or vehicle brake interlock system in the area
adjacent to the loading or unloading rack to prevent vehicles from
departing before complete disconnection of flexible or fixed oil
transfer lines
Lower-most drains and all outlets on tank cars/trucks inspected
prior to filling/departure, and, if necessary ensure that they are
tightened, adjusted, or replaced to prevent liquid discharge while in
transit
lYes llNo LJNA
JYes IjNo LJNA
JYes IjNo
CNA
lYes MNo LJNA
lYes MNo LJNA
lYes MNo LJNA
lYes MNo LJNA
lYes MNo MNA
Comments:
9 Records of inspections and tests kept under usual and customary business practices will suffice
10 Note thaJ|a(t^lscj}[7Jtow*&PdJretetel^ for §112.7(h) to apply
Onshore Oil Drilling, Production and Workover Facilities Page 9 of 14
G-35
December 2012 (12-10-12)
-------
Appendix G: SPCC Inspection Checklists
PLAN
FIELD
Brittle fracture evaluation of field-constructed aboveground
containers is conducted after tank repair, alteration, reconstruction,
or change in service that might affect the risk of a discharge or after
a discharge/failure due to brittle fracture or other catastrophe, and
appropriate action taken as necessary (applies to only field-
constructed aboveground containers in production service, drilling,
and workover service)
Yes
No UNA
Yes
No LJNA
Discussion of conformance with applicable more stringent State
rules, regulations, and guidelines and other effective discharge
prevention and containment procedures listed in 40 CFR part 112
Yes
iNo LJNA
112.7(k)
If YES
Qualified oil-filled operational equipment is present at the facility | JYes | JNo
Oil-filled operational equipment means equipment that includes an oil storage container (or multiple containers) in which the oil is
present solely to support the function of the apparatus or the device. Oil-filled operational equipment is not considered a bulk
storage container, and does not include oil-filled manufacturing equipment (flow-through process). Examples of oil-filled operational
equipment include, but are not limited to, hydraulic systems, lubricating systems (e.g. , those for pumps, compressors and other
rotating equipment, including pumpjack lubrication systems), gear boxes, machining coolant systems, heat transfer systems,
transformers, circuit breakers, electrical switches, and other systems containing oil solely to enable the operation of the device.
Check which apply:
Secondary Containment provided in accordance with 112.7(c) I I
Alternative measure described below (confirm eligibility) I I
112.7(k)
Qualified Oil-Filled Operational Equipment
• Has a single reportable discharge as described in §112.1(b) from any oil-filled
operational equipment exceeding 1,000 U.S. gallons occurred within the three years
prior to Plan certification date?
• Have two reportable discharges as described in §112.1(b) from any oil-filled operational
equipment each exceeding 42 U.S. gallons occurred within any 12-month period within
the three years prior to Plan certification date?12
JYes
lYes
No MNA
No UNA
. Facility procedure for inspections or monitoring program to
detect equipment failure and/or a discharge is established and
documented
Does not apply if the facility has submitted a FRP under
§112.20:
• Contingency plan following 40 CFR part 109 (see Attachment
C of this checklist) is provided in Plan AND
. Written commitment of manpower, equipment, and materials
required to expeditiously control and remove any quantity of oil
discharged that may be harmful is provided in Plan
JYes
JYes
JNo
]NO
JNA
INA
_L
Comments:
This provision does not apply to oil-filled manufacturing equipment (flow-through process)
12 Oil discharges that result from natural disasters, acts of war, or terrorism are not included in this determination. The gallon amount(s) specified (either
1,000 or 42) refers to the amount of oil that actually reaches navigable waters or adjoining shorelines not the total amount of oil spilled. The entire
volume of SiecaiS<3taMgAli*affl RfflRiBSeKWMalHSPECTORS G-36
Onshore Oil Drilling, Production and Workover Facilities Page 10 of 14
December 2012 (12-10-12)
-------
Appendix G: SPCC Inspection Checklists
ONSHORE OIL PRODUCTION FACILITIES—40 CFR 112.9
NA
PLAN
FIELD
(Drilling and workover facilities are excluded from the requirements of §112.9)
Production facility means all structures (including but not limited to wells, platforms, or storage facilities), piping (including but not limited to flowlines or
intra-facility gathering lines), or equipment (including but not limited to workover equipment, separation equipment, or auxiliary non-transportation-
related equipment) used in the production, extraction, recovery, lifting, stabilization, separation or treating of oil (including condensate), or associated
storage or measurement, and is located in an oil or gas field, at a facility. This definition governs whether such structures, piping, or equipment are
subject to a specific section of this part.
112.9(b) Oil Production Facility Drainage
(1)
At tank batteries, separation and treating areas where there is a
reasonable possibility of a discharge as described in §112.1(b),
drains for dikes or equivalent measures are closed and sealed
except when draining uncontaminated rainwater. Accumulated oil
on the rainwater is removed and then returned to storage or
disposed of in accordance with legally approved methods
Prior to drainage, diked area inspected and action taken as
provided below:
• 1 12.8(c)(3)(ii) - Retained rainwater is inspected to ensure that
its presence will not cause a discharge as described in
1 12.8(c)(3)(iii) - Bypass valve opened and resealed under
responsible supervision
1 12.8(c)(3)(iv) - Adequate records of drainage are kept; for
example, records required under permits issued in accordance
with §122.41Q)(2) and (m)(3)
Yes
No LJNA
jYes
]ves
Ives
|No |_|NA
NO ONA
MO |~~|NA
Yes
No LJNA
JYes
]YBS
lYes
|No |_|NA
NA
(2)
Field drainage systems (e.g., drainage ditches or road ditches) and
oil traps, sumps, or skimmers inspected at regularly scheduled
intervals for oil, and accumulations of oil promptly removed
Yes
No llNA
JYes
iNo LJNA
112.9(c) Oil Production Facility Bulk Storage Containers
Bulk storage container means any container used to store oil. These containers are used for purposes including, but not limited to, the storage of oil
prior to use, while being used, or prior to further distribution in commerce. Oil-filled electrical, operating, or manufacturing equipment is not a bulk
storage container.
(1)
(2)
(3)
(4)
Containers materials and construction are compatible with material
stored and conditions of storage such as pressure and
temperature
Except as allowed for flow-through process vessels in §112.9(c)(5)
and produced water containers in §112.9(c)(6), secondary
containment provided for all tank battery, separation and treating
facilities sized to hold the capacity of largest single container and
sufficient freeboard for precipitation.
Drainage from undiked area safely confined in a catchment basin
or holding pond.
Except as allowed for flow-through process vessels in §112.9(c)(5)
and produced water containers in §112.9(c)(6), periodically and
upon a regular schedule, visually inspect containers for
deterioration and maintenance needs, including foundation and
supports of each container on or above the surface of the ground
Yes
No |_|NA
MO NA
JYes
Yes
Yes
NA
No NA
New and old tank batteries engineered/updated in accordance
with good engineering practices to prevent discharges including at
least one of the following:
• Adequate container capacity to prevent overfill if a
pumper/gauger is delayed in making regularly scheduled
rounds;
• Overflow equalizing lines between containers so that a
full container can overflow to an adjacent container;
lYes
INo llNA
lYes
INo MNA
Adequate vacuum protection to prevent container collapse; or
High level sensors to generate and transmit an alarm to the
computer where the facility is subject to a computer production
control system
Comments:
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Onshore Oil Drilling, Production and Workover Facilities Page 11 of 14
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
(5)
0)
(ii)
(Hi)
(iv)
(6)
0)
(ii)
(iii)
(iv)
(v)
PLAN
FIELD
Flow-through Process Vessels. Alternate requirements in lieu of sized secondary containment required in (c)(2)
and requirements in (c)(3) above for facilities with flow-through process vessels:
Flow-through process vessels and associated components (e.g.
dump valves) are periodically and on a regular schedule visually
inspected and/or tested for leaks, corrosion, or other conditions
that could lead to a discharge as described in §1 12.1(b)
Corrective actions or repairs have been made to flow-through
process vessels and any associated components as indicated by
regularly scheduled visual inspections, tests, or evidence of an oil
discharge
Oil removed or other actions initiated to promptly stabilize and
remediate any accumulation of oil discharges associated with the
produced water container
All flow-through process vessels comply with §§1 12.9(c)(2) and
(c)(3) within six months of any flow-through process vessel
discharge of more than 1 ,000 U.S. gallons of oil in a single
discharge as described in §1 12.1(b) or discharges of more than 42
U.S. gallons of oil in each of two discharges as described in
§1 12.1(b) within any twelve month period.13
CHYes DNO ONA
Ores DNO DNA
HHves C|NO DMA
Cves CNO DMA
HHves C|NO DMA
dves CH No CH NA
dves CNO CNA
EHves ONO DNA
Produced Water Containers. Alternate requirements in lieu of sized secondary containment required in (c)(2) and
requirements in (c)(3) above for facilities with produced water containers:
A procedure is implemented on a regular schedule for each
produced water container that is designed to separate the free-
phase oil that accumulates on the surface of the produced water.
. A description is included in the Plan of the procedures,
frequency, and amount of free-phase oil expected to be
maintained inside the container;
. PE certifies in accordance with §112.3(d)(1)(vi);
. Records of such events are maintained in accordance with
§112.7(e).
Qves QNO C|NA
dves C|NO DMA
dves ni\io C|NA
dves QNO DMA
E^Yes CHlMo CHlMA
If this procedure is not implemented as described in the Plan or no records are maintained, then
facility owner/operator must comply with §1 12.9(c)(2) and (c)(3).
Each produced water container and associated piping is visually
inspected, on a regular basis, for leaks, corrosion, or other
conditions that could lead to a discharge as described in §112. 1(b)
in accordance with good engineering practice.
Corrective action or necessary repairs were made to any produced
water container and associated piping as indicated by regularly
scheduled visual inspections, tests, or evidence of an oil
discharge.
Oil removed or other actions initiated to promptly stabilize and
remediate any accumulation of oil discharges associated with the
produced water container.
All produced water containers comply with §§1 12.9(c)(2) and
(c)(3) within six months of any produced water container discharge
of more than 1 ,000 U.S. gallons of oil in a single discharge as
described in §112.1(b) or discharges of more than 42 U.S. gallons
of oil in each of two discharges as described in §112.1(b) within
any twelve month period.13
Cves CNO ONA
CHYes QNO ONA
HHves C|NO DMA
dves CH NO DMA
CHYes C|NO DNA
dves CH NO DMA
HHves ONO DMA
d|Yes CHlMo CHlMA
Comments:
Oil discharges that result from natural disasters, acts of war, or terrorism are not included in this determination. The gallon amount(s) specified (either
1,000 or 42) refers to the amount of oil that actually reaches navigable waters or adjoining shorelines not the total amount of oil spilled. The entire
volume of SiecaiS<3taMgAli*affl RfflRiBSeKWMalHSPECTORS G-38
Onshore Oil Drilling, Production and Workover Facilities Page 12 of 14
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
PLAN
FIELD
112.9(d) Facility transfer operations, pumping, and facility process
(1)
(2)
(3)
0)
(ii)
(4)
0)
(ii)
(Hi)
(iv)
All aboveground valves and piping associated with transfer
operations are inspected periodically and upon a regular schedule
to determine their general condition. Include the general condition
of flange joints, valve glands and bodies, drip pans, pipe supports,
pumping well polish rod stuffing boxes, bleeder and gauge valves,
and other such items
Saltwater (oil field brine) disposal facilities inspected often to
detect possible system upsets capable of causing a discharge,
particularly following a sudden change in atmospheric temperature
If flowlines and intra-facility gathering lines are not provided with
secondary containment in accordance with §1 12.7(c) and the
facility is not required to submit an FRP under §1 12.20, then the
SPCC Plan includes:
• An oil spill contingency plan following the provisions of 40 CFR
part10914
• A written commitment of manpower, equipment, and materials
required to expeditiously control and remove any quantity of oil
discharged that might be harmful
A flowline/intra-facility gathering line maintenance program to
prevent discharges is prepared and implemented and includes the
following procedures:
Flowlines and intra-facility gathering lines and associated valves
and equipment are compatible with the type of production fluids,
their potential corrosivity, volume, and pressure, and other
conditions expected in the operational environment
Flowlines and intra-facility gathering lines and associated
appurtenances are visually inspected and/or tested on a periodic
and regular schedule for leaks, oil discharges, corrosion, or other
conditions that could lead to a discharge as described in
§112.1(b).
If flowlines and intra-facility gathering lines are not provided with
secondary containment in accordance with §1 12.7(c), the
frequency and type of testing allows for the implementation of a
contingency plan as described under 40 CFR 1 09 or an FRP
submitted under §112. 20
Repairs or other corrective actions are made to any flowlines and
intra-facility gathering lines and associated appurtenances as
indicated by regularly scheduled visual inspections, tests, or
evidence of a discharge
Oil removed or other actions initiated to promptly stabilize and
remediate any accumulations of oil discharges associated with the
flowlines, intra-facility gathering lines, and associated
appurtenances
ElYes QNO CINA
ClYes C|NO C|NA
Elves DNO DMA
CYBS CNO DNA
CYBS DNO DNA
dves C|NO DMA
ElYes CD NO DMA
ClYes ONO C|NA
Cves CNO DMA
ClYes DNO C|NA
ClYes ClNo CiNA
C|Yes DNO DMA
ElYes D\io CNA
ClYes CJNo CHlMA
Clves C|NO C|NA
dves C|NO C|NA
CH Yes DNO L"HNA
Clves [UNO DMA
ONSHORE OIL DRILLING AND WORKOVER FACILITIES— 40 CFR 112.10 Q NA
112.10(b)
112.10(c)
112.10(d)
Mobile drilling or workover equipment is positioned or located to
prevent a discharge as described in §112.1(b)
Catchment basins or diversion structures are provided to intercept
and contain discharges of fuel, crude oil, or oily drilling fluids
Blowout prevention (BOP) assembly and well control system
installed before drilling below any casing string or during workover
operations
BOP assembly and well control system is capable of controlling
any well-head pressure that may be encountered while on the well
ClYesClNo CHlMA
Cves CNO DMA
Clves dlMo CHlMA
ClYes DNO C|NA
Clves CNO CNA
ClYes C|NO C|NA
ClYes C|NO C|NA
Comments:
14 Note thaSWSOn(i^rMt^toRORaREX3®R/^rtMOT5Il3irQR)Ss not require a PE impracticability determination for this specific requiremenG-39
Onshore Oil Drilling, Production and Workover Facilities Page 13 of 14 December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
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SPCC GUIDANCE FOR REGIONAL INSPECTORS G-40
Onshore Oil Drilling, Production and Workover Facilities Page 14 of 14 December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT A: SPCC FIELD INSPECTION AND PLAN REVIEW TABLE
Documentation of Field Observations for Containers and Associated Requirements
Inspectors should use this table to document observations of containers as needed.
Containers and Piping
Check containers for leaks, specifically looking for: drip marks, discoloration of tanks, puddles containing spilled or leaked material,
corrosion, cracks, and localized dead vegetation, and standards/specifications of construction.
Check aboveground container foundation for: cracks, discoloration, and puddles containing spilled or leaked material, settling, gaps
between container and foundation, and damage caused by vegetation roots.
Check all piping for: droplets of stored material, discoloration, corrosion, bowing of pipe between supports, evidence of stored
material seepage from valves or seals, evidence of leaks, and localized dead vegetation. For all aboveground piping, include the
general condition of flange joints, valve glands and bodies, drip pans, pipe supports, bleeder and gauge valves, and other such items
(Document in comments section of §112.9(d).)
Secondary Containment (Active and Passive)
Check secondary containment for: containment system (including walls and floor) ability to contain oil such that oil will not escape
the containment system before cleanup occurs, proper sizing, cracks, discoloration, presence of spilled or leaked material (standing
liquid), erosion, corrosion, penetrations in the containment system, and valve conditions.
Check dike or berm systems for: level of precipitation in dike/available capacity, operational status of drainage valves (closed), dike
or berm impermeability, debris, erosion, impermeability of the earthen floor/walls of diked area, and location/status of pipes, inlets,
drainage around and beneath containers, presence of oil discharges within diked areas.
Check drainage systems for: an accumulation of oil that may have resulted from any small discharge, including field drainage
systems (such as drainage ditches or road ditches), and oil traps, sumps, or skimmers. Ensure any accumulations of oil have been
promptly removed.
Check retention and drainage ponds for: erosion, available capacity, presence of spilled or leaked material, debris, and stressed
vegetation.
Check active measures (countermeasures) for: amount indicated in plan is available and appropriate; deployment procedures are
realistic; material is located so that they are readily available; efficacy of discharge detection; availability of personnel and training,
appropriateness of measures to prevent a discharge as described in §112.1 (b). Note that appropriate evaluation and consideration
must be given to the any use of active measures at an unmanned oil production facility.
Container ID/ General
Condition15
Aboveground or Buried Tank
Storage Capacity and Type
of Oil
Type of Containment/
Drainage Control
Overfill Protection and
Testing & Inspections
15 Identify SWftOaBkluatfchWlSeFQR/RBQittaiaaJle HMSResraomiar B for completely buried
Onshore Oil Drilling, Production and Workover Facilities Page A-1 of 2
G-41
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT A: SPCC FIELD INSPECTION AND PLAN REVIEW TABLE (CONT.)
Documentation of Field Observations for Containers and Associated Requirements
Container ID/ General
Condition16
Aboveground or Buried Tank
Storage Capacity and Type
of Oil
Type of Containment/
Drainage Control
Overfill Protection and
Testing & Inspections
16 Identify SWftOaBkluatfchWlSeFQR/RBQiltaiaaJle HMSResraomiar B for completely buried
Onshore Oil Drilling, Production and Workover Facilities Page A-2 of 2
G-42
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT B: SPCC INSPECTION AND TESTING CHECKLIST
Required Documentation of Tests and Inspections
Records of inspections and tests required by 40 CFR part 112 signed by the appropriate supervisor or inspector must be kept by all
facilities with the SPCC Plan for a period of three years. Records of inspections and tests conducted under usual and customary
business practices will suffice. Documentation of the following inspections and tests should be kept with the SPCC Plan.
Inspection or Test
Documentation
Present
Not
Present
Not
Applicable
112.7-General SPCC Requirements
(d)
(d)
(h)(3)
(i)
k(2)(i)
Integrity testing for bulk storage containers with no secondary containment system
and for which an impracticability determination has been made
Integrity and leak testing of valves and piping associated with bulk storage
containers with no secondary containment system and for which an impracticability
determination has been made
Inspection of lowermost drain and all outlets of tank car or tank truck prior to filling
and departure from loading/unloading rack
Evaluation of field-constructed aboveground containers for potential for brittle
fracture or other catastrophic failure when the container undergoes a repair,
alteration, reconstruction or change in service or has discharged oil or failed due to
brittle fracture failure or other catastrophe
Inspection or monitoring of qualified oil-filled operational equipment when the
equipment meets the qualification criteria in §112.7(k)(1) and facility
owner/operator chooses to implement the alternative requirements in §1 12.7(k)(2)
that include an inspection or monitoring program to detect oil-filled operational
equipment failure and discharges
D
D
n
a
n
a
n
a
n
*
a
a
a
n
°
112.9-Onshore Oil Production Facilities (excluding drilling and workover facilities) I JNA
(b)(1)
(b)(2)
(c)(3)
(c)(5)(i)
(c)(6)(ii)
(d)(1)
(d)(2)
(d)(4)(ii)
Rainwater released directly from diked containment areas inspected following
§§112.8(c)(3)(ii), (iii) and (iv), including records of drainage kept
Field drainage systems, oil traps, sumps, and skimmers inspected regularly for oil,
and accumulations of oil promptly removed
Containers, foundations and supports inspected visually for deterioration and
maintenance needs
In lieu of having sized secondary containment, flow-through process vessels and
associated components visually inspected and/or tested periodically and on a
regular schedule for conditions that could result in a discharge as described in
§112.1(b)
In lieu of having sized secondary containment, produced water containers and
associated piping are visually inspected and/or tested for leaks, corrosion, or other
conditions that could lead to a discharge as described in §1 12.1(b) in accordance
with good engineering practice
All aboveground valves and piping associated with transfer operations are regularly
inspected
Saltwater disposal facilities inspected often to detect possible system upsets
capable of causing a discharge
For flowlines and intra-facility gathering lines without secondary containment, in
accordance with §112.7(c), lines are visually inspected and/or tested periodically
and on a regular schedule to allow implementing the part 109 contingency plan or
the FRP submitted under §112. 20
a
a
n
°
n
a
a
n
a
n
a
n
n
a
n
°
a
n
a
°
n
a
a
D
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Onshore Oil Drilling, Production and Workover Facilities
Page B-1 of 2
G-43
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
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SPCC GUIDANCE FOR REGIONAL INSPECTORS G-44
Onshore Oil Drilling, Production and Workover Facilities Page 6-2 of 2 December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT C: SPCC CONTINGENCY PLAN REVIEW CHECKLIST DMA
40 CFR Part 109-Criteria for State, Local and Regional Oil Removal Contingency Plans
If SPCC Plan includes an impracticability determination for secondary containment in accordance with §112.7(d), the facility
owner/operator is required to provide an oil spill contingency plan following 40 CFR part 109, unless he or she has submitted a FRP
under §112.20. An oil spill contingency plan may also be developed, unless the facility owner/operator has submitted a FRP under
§112.20 as one of the required alternatives to general secondary containment for qualified oil filled operational equipment in
accordance with §112.7(k).
109.5-Development and implementation criteria for State, local and regional oil removal contingency plans17
(a)
(b)
(1)
(2)
(3)
(4)
(c)
(1)
(2)
(3)
(d)
(1)
(2)
(3)
(4)
(5)
(e)
Definition of the authorities, responsibilities and duties of all persons, organizations or agencies which are to
be involved in planning or directing oil removal operations.
Establishment of notification procedures for the purpose of early detection and timely notification of an oil
discharge including:
The identification of critical water use areas to facilitate the reporting of and response to oil discharges.
A current list of names, telephone numbers and addresses of the responsible persons (with alternates) and
organizations to be notified when an oil discharge is discovered.
Provisions for access to a reliable communications system for timely notification of an oil discharge, and the
capability of interconnection with the communications systems established under related oil removal
contingency plans, particularly State and National plans (e.g., National Contingency Plan (NCP)).
An established, prearranged procedure for requesting assistance during a major disaster or when the
situation exceeds the response capability of the State, local or regional authority.
Provisions to assure that full resource capability is known and can be committed during an oil discharge
situation including:
The identification and inventory of applicable equipment, materials and supplies which are available locally
and regionally.
An estimate of the equipment, materials and supplies that would be required to remove the maximum oil
discharge to be anticipated.
Development of agreements and arrangements in advance of an oil discharge for the acquisition of
equipment, materials and supplies to be used in responding to such a discharge.
Provisions for well defined and specific actions to be taken after discovery and notification of an oil discharge
including:
Specification of an oil discharge response operating team consisting of trained, prepared and available
operating personnel.
Pre-designation of a properly qualified oil discharge response coordinator who is charged with the
responsibility and delegated commensurate authority for directing and coordinating response operations and
who knows how to request assistance from Federal authorities operating under existing national and regional
contingency plans.
A preplanned location for an oil discharge response operations center and a reliable communications system
for directing the coordinated overall response operations.
Provisions for varying degrees of response effort depending on the severity of the oil discharge.
Specification of the order of priority in which the various water uses are to be protected where more than one
water use may be adversely affected as a result of an oil discharge and where response operations may not
be adequate to protect all uses.
Specific and well defined procedures to facilitate recovery of damages and enforcement measures as
provided for by State and local statutes and ordinances.
Yes
D
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
No
D
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
17 The conSfigMla^lplaUyt&SBtBgiRffiSBl^toiltlNaPlppiagBe state and local plans, Area Contingency Plans, and the NCP. G-45
Onshore Oil Drilling, Production and Workover Facilities Page C-1 of 2 December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
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SPCC GUIDANCE FOR REGIONAL INSPECTORS G-46
Onshore Oil Drilling, Production and Workover Facilities Page C-2 of 2 December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT D: TIER II QUALIFIED FACILITY CHECKLIST
JNA
TIER II QUALIFIED FACILITY PLAN REQUIREMENTS —40 CFR 112.6(b)
dves
Dves
(viii)
Plan Certification: Owner/operator certified in the Plan that:
He or she is familiar with the requirements of 40 CFR part 112
He or she has visited and examined the facility18
The Plan has been prepared in accordance with accepted and sound industry practices and
standards and with the requirements of this part
Procedures for required inspections and testing have been established
He or she will fully implement the Plan
The facility meets the qualification criteria set forth under §112.3(g)(2)
The Plan does not deviate from any requirements as allowed by §§112.7(a)(2) and 112.7(d),
except as described under §112.6(b)(3)(i) or (ii)
The Plan and individual(s) responsible for implementing the Plan have the full approval of
management and the facility owner or operator has committed the necessary resources to
fully implement the Plan.
JYes
]Yes
JYes
]Yes
]Yes
lYes
DN
JNo
JNo
]NO
]NO
JNA
]NA
]NA
]NA
JNA
]NA
]NA
No MNA
112.6(b)(2)
If YES
0)
If YES
Technical Amendments: The owner/operator self-certified the Plan's technical amendments
for a change in facility design, construction, operation, or maintenance that affected potential
fora§112.1(b) discharge
. Certification of technical amendments is in accordance with the self-certification
provisions of §112.6(b)(1).
JYes
JYes
A PE certified a portion of the Plan (i.e., Plan is informally referred to as a hybrid Plan)
. The PE also certified technical amendments that affect the PE certified portion of the
Plan as required under §112.6(b)(4)(ii)
JYes
lYes
The aggregate aboveground oil storage capacity increased to more than 10,000 U.S. gallons
as a result of the chanqe
JYes
If YES
The facility no longer meets the Tier II qualifying criteria in §112.3(g)(2) because
it exceeds 10,000 U.S. gallons in aggregate aboveground storage capacity.
The owner/operator prepared and implemented a Plan within 6 months following the change
and had it certified by a PE under §112.3(d)
JNO MNA
NO MNA
JNo
]NO
JNA
INA
JNo NA
Yes MNo MNA
112.6(b)(3)
If YES
Plan Deviations: Does the Plan include environmentally equivalent alternative methods or
impracticability determinations for secondary containment?
Identify the alternatives in the hybrid Plan:
. Environmental equivalent alternative method(s) allowed under §112.7(a)(2);
• Impracticability determination under §112.7(d)
YBS
DMA
JYes |_|No |_|NA
112.6(b)(4)
0)
(A)
(B)
(C)
• For each environmentally equivalent measure, the Plan is accompanied by a written
statement by the PE that describes: the reason for nonconformance, the alternative
measure, and how it offers equivalent environmental protection in accordance with
§112.7(a)(2);
. For each secondary containment impracticability determination, the Plan explains the
reason for the impracticability determination and provides the alternative measures to
secondary containment required in §112.7(d)
AND
PE certifies in the Plan that:
He/she is familiar with the requirements of 40 CFR Part 112
He/she or a representative agent has visited and examined the facility
The alternative method of environmental equivalence in accordance with §112.7(a)(2) or the
determination of impracticability and alternative measures in accordance with §112.7(d) is
consistent with good engineering practice, including consideration of applicable industry
standards, and with the requirements of 40 CFR Part 112.
Yes MNo MNA
Yes MNo MNA
JYes |_|No |_|NA
lYes HNO UNA
Comments:
18 Note thcSBfflgtmjfiafWiOEWJIgiri^mcRIWlcliWSiPiEEETtEigSite visit
Onshore Oil Drilling, Production and Workover Facilities Page D-1 of 2
G-47
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
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SPCC GUIDANCE FOR REGIONAL INSPECTORS G-48
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Appendix G: SPCC Inspection Checklists
ATTACHMENT E: ADDITIONAL COMMENTS
Onshore Oil Drilling, Production and Workover Facilities Page E-1 of 2 December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT E: ADDITIONAL COMMENTS (CONT.)
Onshore Oil Drilling, Production and Workover Facilities Page E-2 of 2 December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT F: PHOTO DOCUMENTATION NOTES
Photo*
Photographer
Name
Time of Compass
Photo Taken Direction
Description
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Onshore Oil Drilling, Production and Workover Facilities
Page F-1 of 2
G-51
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT F: PHOTO DOCUMENTATION NOTES (CONT.)
Photo*
Photographer
Name
Time of Compass
Photo Taken Direction
Description
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Onshore Oil Drilling, Production and Workover Facilities
Page F-2of2
G-52
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ENVIRONMENTAL PROTECTION AGENCY
SPCC FIELD INSPECTION AND PLAN REVIEW CHECKLIST
OFFSHORE OIL DRILLING, PRODUCTION AND WORKOVER FACILITIES
Overview of the Checklist
This checklist is designed to assist EPA inspectors in conducting a thorough and nationally consistent inspection of a
facility's compliance with the Spill Prevention, Control, and Countermeasure (SPCC) rule at 40 CFR part 112. It is a
required tool to help federal inspectors (or their contractors) record observations for the site inspection and review of the
SPCC Plan. While the checklist is meant to be comprehensive, the inspector should always refer to the SPCC rule in its
entirety, the SPCC Regional Inspector Guidance Document, and other relevant guidance for evaluating compliance. This
checklist must be completed in order for an inspection to count toward an agency measure (i.e., OEM inspection
measures or GPRA). The completed checklist and supporting documentation (i.e. photo logs or additional notes) serve as
the inspection report.
This checklist addresses requirements for offshore oil production, drilling, and workover facilities.
Separate and standalone checklists address the requirements for:
Onshore facilities including Tier II Qualified Facilities (excluding oil drilling, production and workover facilities);
Onshore oil drilling, production and workover facilities including Tier II Qualified Facilities as defined in §112.3(g)(2);
and
Tier I Qualified Facilities (for facilities that meet the eligibility criteria defined in §112.3(g)(1)).
Qualified facilities must meet the rule requirements in §1 12.6 and other applicable sections specified in §1 12.6, except for
deviations that provide environmental equivalence and secondary containment impracticability determinations as allowed
under §112.6.
The checklist is organized according to the SPCC rule. Each item in the checklist identifies the relevant section and
paragraph in 40 CFR part 112 where that requirement is stated.
• Sections 112.1 through 112.5 specify the applicability of the rule and requirements for the preparation,
implementation, and amendment of SPCC Plans. For these sections, the checklist includes data fields to be
completed, as well as several questions with "yes," "no" or "NA" answers.
• Section 1 12.7 includes general requirements that apply to all facilities (unless otherwise excluded).
• Section 112.11 specifies spill prevention, control, and countermeasures requirements for offshore oil drilling,
production and workover facilities.
The inspector needs to evaluate whether the requirement is addressed adequately or inadequately in the SPCC Plan and
whether it is implemented adequately in the field (either by field observation or record review). For the SPCC Plan and
implementation in the field, if a requirement is addressed adequately, mark the "Yes" box in the appropriate column. If a
requirement is not addressed adequately, mark the "No" box. If a requirement does not apply to the particular facility or
the question asked is not appropriate for the facility, mark as "NA". Discrepancies or descriptions of inspector
interpretation of "No" vs. "NA" may be documented in the comments box subsequent to each section. If a provision of the
rule applies only to the SPCC Plan, the "Field" column is shaded.
Space is provided throughout the checklist to record comments. Additional space is available as Attachment D at the end
of the checklist. Comments should remain factual and support the evaluation of compliance.
Attachments (Attachments A and B are included for hybrid facilities which have both offshore and onshore components)
• Attachment A is a checklist for Sections 112.8 and 112.12. This checklist specifies requirements for spill prevention,
control, and countermeasures for onshore facilities (excluding oil production facilities).
• Attachment B is a checklist that specifies requirements for spill prevention, control, and countermeasures for
onshore oil production facilities (112.9 provisions) and onshore drilling and workover facilities (112.10 provisions)
• Attachment C is for recording information about containers and other locations at the facility that require secondary
containment.
• Attachment D is a checklist for documentation of the tests and inspections the facility operator is required to keep
with the SPCC Plan.
• Attachment E is a checklist for oil spill contingency plans following 40 CFR 109. Unless a facility has submitted a
Facility Response Plan (FRP) under 40 CFR 112.20, a contingency plan following 40 CFR 109 is required if a
facility determines that secondary containment is impracticable as provided in 40 CFR 1 12.7(d). The same
requirement for an oil spill contingency plan applies to the owner or operator of a facility with qualified oil-filled
operational equipment that chooses to implement alternative requirements instead of general secondary
containment requirements as provided in 40 CFR 112.7(k).
• Attachment F is for recording additional comments or notes.
• Attachment G is for recording information about photos.
Offshore ^P8rffiM$^$££ffiiP!i?^&h<^^lftMi Page 1 of 10 December 20?f^2- 10-12)
-------
Appendix G: SPCC Inspection Checklists
FACILITY INFORMATION
FACILITY NAME:
LATITUDE:
LONGITUDE:
GPS DATUM:
Section/Township/Range:
FRS#/OIL DATABASE ID:
ICIS#:
ADDRESS:
CITY:
STATE:
ZIP:
COUNTY:
MAILING ADDRESS (IF DIFFERENT FROM FACILITY ADDRESS-IF NOT, PRINT "SAME"):
CITY:
STATE:
ZIP:
COUNTY:
TELEPHONE:
FACILITY CONTACT NAME/TITLE:
OWNER NAME:
OWNER ADDRESS:
CITY:
STATE:
ZIP:
COUNTY:
TELEPHONE:
FAX:
EMAIL:
FACILITY OPERATOR NAME (IF DIFFERENT FROM OWNER-IF NOT, PRINT "SAME"):
OPERATOR ADDRESS:
CITY:
STATE:
ZIP:
COUNTY:
TELEPHONE:
OPERATOR CONTACT NAME/TITLE:
FACILITY TYPE:
NAICS CODE:
HOURS PER DAY FACILITY ATTENDED:
TOTAL FACILITY CAPACITY:
TYPE(S) OF OIL STORED:
LOCATED IN INDIAN COUNTRY? YES NO RESERVATION NAME:
INSPECTION/PLAN REVIEW INFORMATION
PLAN REVIEW DATE:
REVIEWER NAME:
INSPECTION DATE:
TIME:
ACTIVITY ID NO:
LEAD INSPECTOR:
OTHER INSPECTOR(S):
INSPECTION ACKNOWLEDGMENT
/ performed an SPCC inspection at the facility specified above.
INSPECTOR SIGNATURE:
DATE:
SUPERVISOR REVIEW/SIGNATURE:
DATE:
Offshore
Page 2 of 10
December 20
-------
Appendix G: SPCC Inspection Checklists
SPCC GENERAL APPLICABILITY—40 CFR 112.1
IS THE FACILITY REGULATED UNDER 40 CFR part 112?
The completely buried oil storage capacity is over 42,000 U.S. gallons, OR the aggregate aboveground
oil storage capacity is over 1,320 U.S. gallons AND
The facility is a non-transportation-related facility engaged in drilling, producing, gathering, storing,
processing, refining, transferring, distributing, using, or consuming oil and oil products, which due to its
location could reasonably be expected to discharge oil into or upon the navigable waters of the United
States
jYes
]ves
JNo
]NO
AFFECTED WATERWAY(S):
DISTANCE:
FLOW PATH TO WATERWAY:
Note: The following storage capacity is not considered in determining applicability of SPCC requirements:
Equipment subject to the authority of the U.S. Department of
Transportation, U.S. Department of the Interior, or Minerals Management
Service, as defined in Memoranda of Understanding dated November
24, 1971, and November 8, 1993; Tank trucks that return to an otherwise
regulated facility that contain only residual amounts of oil (EPA Policy
letter)
Completely buried tanks subject to all the technical requirements of 40
CFR part 280 or a state program approved under 40 CFR part 281;
Underground oil storage tanks deferred under 40 CFR part 280 that
supply emergency diesel generators at a nuclear power generation
facility licensed by the Nuclear Regulatory Commission (NRC) and
subject to any NRC provision regarding design and quality criteria,
including but not limited to CFR part 50;
Any facility or part thereof used exclusively for wastewater treatment
(production, recovery or recycling of oil is not considered wastewater
treatment); (This does not include other oil containers located at a
wastewater treatment facility, such as generator tanks or transformers)
• Containers smaller than 55 U.S. gallons;
• Permanently closed containers (as defined in §112.2);
• Motive power containers (as defined in §112.2);
• Hot-mix asphalt or any hot-mix asphalt containers;
• Heating oil containers used solely at a single-family residence;
• Pesticide application equipment and related mix containers;
• Any milk and milk product container and associated piping and
appurtenances; and
• Intra-facility gathering lines subject to the regulatory requirements
of 49 CFR part 192 or 195.
Does the facility have an SPCC Plan?
Yes
No
FACILITY RESPONSE PLAN (FRP) APPLICABILITY —40 CFR 112.20(f)
A non-transportation related onshore facility is required to prepare and implement an FRP as outlined in 40 CFR 112.20 if:
L_| The facility transfers oil over water to or from vessels and has a total oil storage capacity greater than or equal to
42,000 U.S. gallons, OR
| | The facility has a total oil storage capacity of at least 1 million U.S. gallons, AND at least one of the following is true:
| JThe facility does not have secondary containment sufficiently large to contain the capacity of the largest aboveground tank
plus sufficient freeboard for precipitation.
I | The facility is located at a distance such that a discharge could cause injury to fish and wildlife and sensitive environments.
O"rhe facility is located such that a discharge would shut down a public drinking water intake.
I I The facility has had a reportable discharge greater than or equal to 10,000 U.S. gallons in the past 5 years.
Facility has FRP: |_|Yes
No
NA
FRP Number:
Facility has a completed and signed copy of Appendix C, Attachment C-ll,
"Certification of the Applicability of the Substantial Harm Criteria."
lYes
No
Comments:
Offshore
Page 3 on 0
December 20
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Appendix G: SPCC Inspection Checklists
REQUIREMENTS FOR PREPARATION AND IMPLEMENTATION OF A SPCC PLAN— 40 CFR 112.3
Date facility began operations:
Date of initial SPCC Plan preparation: Current Plan version (date/number):
112.3(a)
112.3(d)
For drilling, production or workover facilities, including mobile or portable facilities,
that are offshore or have an offshore component; or facilities required to have and
submit a FRP:
. In operation on or prior to November 1 0, 201 0: Plan prepared and/or amended and fully
implemented by November 10, 2010
. Facilities beginning operation after November 10, 2010:
o Plan prepared and fully implemented before drilling and workover facilities begin
operations; or
o Plan prepared and fully implemented within six months after oil production
facilities begin operations
Plan is certified by a registered Professional Engineer (PE) and includes statements that the
PE attests:
• PE is familiar with the requirements of 40 CFR part 112
• PE or agent has visited and examined the facil ty
. Plan is prepared in accordance with good engineering practice including consideration
of applicable industry standards and the requirements of 40 CFR part 112
. Procedures for required inspections and testing have been established
• Plan is adequate for the facility
. For produced water containers subject to 1 12.9(c)(6), any procedure to minimize the
amount of free-phase oil is designed to reduce the accumulation of free-phase oil and
the procedures and frequency for required inspections, maintenance and testing have
been established and are described in the Plan, if applicable
HHYes C|NO DNA
Cves CNO CNA
dives DNO DNA
dves Cho DNA
dves Cho C|NA
Clves Cho QNA
Clves Cho DNA
Clves Cho C|NA
ClYes DNO DNA
Clves Cho C|NA
PE Name: License No.: State: Date of certification:
112.3(e)(1)
Plan is available onsite if attended at least 4 hours per day. If facility is unattended, Plan is
available at the nearest field office. (Please note nearest field office contact information in
comments section below.)
Clves CH NO QNA
AMENDMENT OF SPCC PLAN BY REGIONAL ADMINISTRATOR (RA)— 40 CFR 1 1 2.4
112.4(a),(c)
If YES
112.4(d),(e)
Has the facility discharged more than 1 ,000 U.S. gallons of oil in a single reportable
discharge or more than 42 U.S. gallons in each of two reportable discharges in any 12-
month period?1
• Was information submitted to the RA as required in §1 12.4(a)?2
• Was information submitted to the appropriate agency or agencies in charge of oil
pollution control activities in the State in which the facility is located§1 12.4(c)
. Date(s) and volume(s) of reportable discharges(s) under this section:
• Were the discharges reported to the NRC3?
Have changes required by the RA been implemented in the Plan and/or facility?
ClYes Cho
Ckes Cho DNA
Clves Cho C|NA
Clves Cho
ClYes Cho QNA
Comments:
1 A reportable discharge is a discharge as described in §112.1(b)(see 40 CFR part 110). The gallon amount(s) specified (either 1,000 or 42) refers to the
amount of oil that actually reaches navigable waters or adjoining shorelines not the total amount of oil spilled. The entire volume of the discharge is oil
for this determination.
2 Triggering this threshold may disqualify the facility from meeting the Qualified Facility criteria if it occurred in the three years prior to self certification
3 Inspector Note-Confirm any spills identified above were reported to NRC
Offshore &iP6SMWm$8PaWWohmm'cms Page 4 of 10
December 20
-------
Appendix G: SPCC Inspection Checklists
AMENDMENT OF SPCC PLAN BY THE OWNER OR OPERATOR—40 CFR 112.5
112.5(a)
If YES
112.5(b)
Has there been a change at the facility that materially affects the potential for a discharge
described in§112.1(b)?
. Was the Plan amended within six months of the change?
. Were amendments implemented within six months of any Plan amendment?
Review and evaluation of the Plan completed at least once every 5 years?
Following Plan review, was Plan amended within six months to include more effective
prevention and control technology that has been field-proven to significantly reduce the
likelihood of a discharge described in §112.1(b)?
Amendments implemented within six months of any Plan amendment?
Five year Plan review and evaluation documented?
Yes
Dv
es
jYes
]Yes
JYes
]Yes
jNo
] No
]NO
]NO |
]NO |
]NO I
]NO I
JNA
]NA
]NA
]NA
112.5(c)
Professional Engineer certification of any technical Plan amendments in accordance with all
applicable requirements of §112.3(d) [Except for self-certified Plans]
JYes
No LJNA
Name:
License No.:
State:
Date of certification:
Reason for amendment:
Comments:
GENERAL SPCC REQUIREMENTS—40 CFR 112.7
PLAN
FIELD
Management approval at a level of authority to commit the necessary resources to
fully implement the Plan4
JYes
I No
Plan follows sequence of the rule or is an equivalent Plan meeting all applicable
rule requirements and includes a cross-reference of provisions
Yes
No LJNA
If Plan calls for facilities, procedures, methods, or equipment not yet fully
operational, details of their installation and start-up are discussed (Note: Relevant
for inspection evaluation and testing baselines.)
Yes
iNo LJNA
112.7(a)(2)
If YES
The Plan includes deviations from the requirements of §§112.7(g),
(h)(2) and (3), and (i) and applicable subparts B and C of the rule,
except the secondary containment requirements in §§112.7(c) and
(h)(1), 112.9(c)(2), 112.9(d)(3), and 112.10(c)
• The Plan states reasons for nonconformance
. Alternative measures described in detail and provide
equivalent environmental protection (Note: Inspector should
document if the environmental equivalence is implemented in
the field, in accordance with the Plan's description)
I Yes
JYes
I Yes
No LJNA
JNo
iNo
JNA
INA
Yes
No LJNA
Describe each deviation and reasons for nonconformance:
4 May be part of the Plan or demonstrated elsewhere.
Page 5 of 10
December 20^12-10-12)
-------
Appendix G: SPCC Inspection Checklists
PLAN
FIELD
112.7(a)(3)
(ii)
(iii)
(iv)
(v)
(vi)
Plan describes physical layout of facility and includes a diagram
that identifies:
• Location and contents of all regulated fixed oil storage containers
• Storage areas where mobile or portable containers are located
• Completely buried tanks otherwise exempt from the SPCC
requirements (marked as "exempt")
• Transfer stations
• Connecting pipes, including intra-facility gathering lines that are
otherwise exempt from the requirements of this part under
Yes
No
Yes
No
Plan addresses each of the following:
For each fixed container, type of oil and storage capacity (see
Attachment A of this checklist). For mobile or portable containers,
type of oil and storage capacity for each container or an estimate
of the potential number of mobile or portable containers, the types
of oil, and anticipated storage capacities
Discharge prevention measures, including procedures for routine
handling of products (loading, unloading, and facility transfers,
etc.)
Discharge or drainage controls, such as secondary containment
around containers, and other structures, equipment, and
procedures for the control of a discharge
Countermeasures for discharge discovery, response, and cleanup
(both facility's and contractor's resources)
Methods of disposal of recovered materials in accordance with
applicable legal requirements
Contact list and phone numbers for the facility response
coordinator, National Response Center, cleanup contractors with
an agreement for response, and all Federal, State, and local
agencies who must be contacted in the case of a discharge as
described in §112.1(b)
jYes |_|No
JYes
JYes
Kes
]Yes
I Yes
jNo
I No
]NO
]NO
]NO
JYes MNo
Yes MNo
JYes MNo
JYes LJNo
112.7(a)(4)
JYes
Does not apply if the facility has submitted an FRP under §112.20:
Plan includes information and procedures that enable a person
reporting an oil discharge as described in §112.1(b)to relate information on the:
No MNA
Exact address or location and phone
number of the facility;
Date and time of the discharge;
Type of material discharged;
Estimates of the total quantity discharged;
Estimates of the quantity discharged as
described in §112.1(b);
Source of the discharge;
Description of all affected media;
Cause of the discharge;
Damages or injuries caused by the
discharge;
Actions being used to stop, remove, and
mitigate the effects of the discharge;
Whether an evacuation may be needed;
and
Names of individuals and/or organizations
who have also been contacted
112.7(a)(5)
Does not apply if the facility has submitted a FRP under §112.20:
Plan organized so that portions describing procedures to be used
when a discharge occurs will be readily usable in an emergency
Yes
No LJNA
112.7(b)
Plan includes a prediction of the direction, rate of flow, and total
quantity of oil that could be discharged for each type of major
equipment failure where experience indicates a reasonable
potential for equipment failure
I Yes
iNo LJNA
Comments:
5 Note in comments any discrepancies between the facility diagram, the description of the physical layout of facility, and what is observed in the field
Offshore ^iPSrfi^^M^r^aW^o^l^^a'c^s Page 6 of 10 December 20^2-10-12)
-------
Appendix G: SPCC Inspection Checklists
PLAN FIELD
112.7(c)
112.7(d)
If YES
Appropriate containment and/or diversionary structures or equipment are provided to prevent a discharge as
described in §112.1(b), except as provided in §112.7(k) of this section for certain qualified operational
equipment and §112.9(d)(3) for certain flowlines and intra-facility gathering lines at an oil production facility.
The entire containment system, including walls and floors, are capable of containing oil and are constructed to
prevent escape of a discharge from the containment system before cleanup occurs. The method, design, and
capacity for secondary containment address the typical failure mode and the most likely quantity of oil that would be
discharged. See Attachment A of this checklist.
For offshore facilities, one of the following or its equivalent:
• Curbing or drip pans;
• Sumps and collection systems;
For onshore facilities, one of the following or its equivalent:
• Dikes, berms, or retaining walls sufficiently • Weirs, booms or other barriers;
impervious to contain oil; . Spi|| diversion ponds;
. Curbing or drip pans; . Retention ponds; or
. Sumps and collection systems; . Sorbent materials.
• Culverting, gutters or other drainage systems;
Identify which of the following are present at the facility and if appro|
or equipment are provided as described above:
I I Bulk storage containers
EH Mobile/portable containers
I loil-filled operational equipment (as defined in 1 12.2)
1 1 Other oil-filled equipment (i.e., manufacturing equipment)
EH Piping and related appurtenances
|J Mobile refuelers or non-transportation-related tank cars
LjTransfer areas, equipment and activities
In Identify any other equipment or activities that are not listed
above:
Secondary containment for one (or more) of the following
provisions is determined to be impracticable:
1 1 General secondary containment | | Bulk storage containers
§1 1 2.7(c) §§1 1 2.8(c)(2)/1 1 2. 1 2(c)(2)
| [Loading/unloading rack | [Mobile/portable
§1 1 2.7(h)(1 ) containers§§1 1 2.8(c)(1 1 )/1 1 2.1 2
(c)(11)
• The impracticability of secondary containment is clearly
demonstrated and described in the Plan
. For bulk storage containers,6 periodic integrity testing of
containers and integrity and leak testing of the associated
valves and piping is conducted
(Does not apply if the facility has submitted a FRP under §112.20):
• Contingency Plan following the provisions of 40 CFR part 109
is provided (see Attachment C of this checklist) AND
. Written commitment of manpower, equipment, and materials
required to expeditiously control and remove any quantity of
oil discharged that may be harmful
>riate containment and/or
Cves CNO CNA
Cves DNO CNA
Cves DNO DMA
Cves CNO CNA
Dves DNO DMA
Cves CNO CNA
Cves CNO CNA
Cves DNO CNA
dves ClNo
HHYes C|NO C|NA
Dves CNO CNA
LjYes GNO CNA
Cves CNO DMA
diversionary structures
Cves CNO CNA
Cves CNO CNA
Cves CNO CNA
Cves CNO CNA
Dves CNO CNA
Cves CNO CNA
Cves CNO CNA
Cves CNO CNA
dves C|NO C|NA
CH Yes dlMo CHNA
CI Yes CH No DMA
Comments:
These additional requirements apply only to bulk storage containers, when an impracticability determination has been made by the PE
PageTofW December 20
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Appendix G: SPCC Inspection Checklists
PLAN
FIELD
112.7(e)
Inspections and tests conducted in accordance with written
procedures
Record of inspections or tests signed by supervisor or inspector
Kept with Plan for at least 3 years (see Attachment B of this
checklist)7
jYes
]Yes
I Yes
JNo
]NO
]NO
JYes
]Yes
JYes
JNo
]NO
]NO
112.7(f)
(1)
(2)
(3)
Personnel, training, and oil discharge prevention procedures
Training of oil-handling personnel in operation and maintenance of
equipment to prevent discharges; discharge procedure protocols;
applicable pollution control laws, rules, and regulations; general
facility operations; and contents of SPCC Plan
Person designated as accountable for discharge prevention at the
facility and reports to facility management
Discharge prevention briefings conducted at least once a year for
oil handling personnel to assure adequate understanding of the
Plan. Briefings highlight and describe known discharges as
described in §112.1(b) or failures, malfunctioning components,
and any recently developed precautionary measures
JYes |_|No |_|NA
]ves DNO CNA
Ives HMO HNA
JYes LJNo |_|NA
]ves CNO CNA
Ives HMO HNA
112.7(h)
If YES (1)
Tank car and tank truck loading/unloading rack is present at the facility
JYes
JNo
Loading/unloading rack means a fixed structure (such as a platform, gangway) necessary for loading or unloading a tank truck or
tank car, which is located at a facility subject to the requirements of this part. A loading/unloading rack includes a loading or
unloading arm, and may include any combination of the following: piping assemblages, valves, pumps, shut-off devices, overfill
sensors, or personnel safety devices.
Does loading/unloading rack drainage flow to catchment basin or
treatment facility designed to handle discharges or use a quick
drainage system?
Containment system holds at least the maximum capacity of the
largest single compartment of a tank car/truck loaded/unloaded at
the facility
(2)
(3)
An interlocked warning light or physical barriers, warning signs,
wheel chocks, or vehicle brake interlock system in the area
adjacent to the loading or unloading rack to prevent vehicles
from departing before complete disconnection of flexible or fixed
oil transfer lines
Lower-most drains and all outlets on tank cars/trucks inspected
prior to filling/departure, and, if necessary ensure that they are
tightened, adjusted, or replaced to prevent liquid discharge while
in transit
Brittle fracture evaluation of field-constructed aboveground
containers is conducted after tank repair, alteration,
reconstruction, or change in service that might affect the risk of a
discharge or after a discharge/failure due to brittle fracture or other
catastrophe, and appropriate action taken as necessary (applies
to only field-constructed aboveground containers in production
service, drilling, and workover service)
JYes
Yes
DNC
NA
JYes
JNo llNA
JYes MNo MNA
Yes
JYes
NO
lNoMNA
JYes
JNo MNA
Yes
JNA
112.70)
Discussion of conformance with applicable more stringent State
rules, regulations, and guidelines and other effective discharge
prevention and containment procedures listed in 40 CFR part 112
JYes MNo MNA
Comments:
7 Records of inspections and tests kept under usual and customary business practices will suffice
8 Note that a tank car/truck loading/unloading rack must be present for §112.7(h) to apply. Though this requirement applies to all facilities, loading and
unloading rack equipment is often not present at typical offshore production facilities.
Offshore
Page SoflO
December 20
-------
Appendix G: SPCC Inspection Checklists
112.7(k)
If YES
112.7(k)
PLAN
FIELD
Qualified oil-filled operational equipment is present at the facility9 C_|Yes I ll\lo
Oil-filled operational equipment means equipment that includes an oil storage container (or multiple containers) in which the oil is
present solely to support the function of the apparatus or the device. Oil-filled operational equipment is not considered a bulk
storage container, and does not include oil-filled manufacturing equipment (flow-through process). Examples of oil-filled operational
equipment include, but are not limited to, hydraulic systems, lubricating systems (e.g. , those for pumps, compressors and other
rotating equipment, including pumpjack lubrication systems), gear boxes, machining coolant systems, heat transfer systems,
transformers, circuit breakers, electrical switches, and other systems containing oil solely to enable the operation of the device.
Check which apply:
Secondary Containment provided in accordance with 1 12.7(c) I I
Alternative measure described below (confirm eligibility) | |
Qualified Oil-Filled Operational Equipment
. Has a single reportable discharge as described in §112.1(b) from any oil-filled PHves L~!NO I INA
operational equipment exceeding 1 ,000 U.S. gallons occurred within the three years
prior to Plan certification date?
• Have two reportable discharges as described in §112.1(b) from any oil-filled PHves I ||\in | INA
operational equipment each exceeding 42 U.S. gallons occurred within any 12-month
period within the three years prior to Plan certification date?10
If YES for either, secondary containment in accordance with §112.7(c) is required
. Facility procedure for inspections or monitoring program to
detect equipment failure and/or a discharge is established and
documented
Does not apply if the facility has submitted a FRP under
§112.20:
• Contingency plan following 40 CFR part 109 (see Attachment
C of this checklist) is provided in Plan AND
. Written commitment of manpower, equipment, and materials
required to expeditiously control and remove any quantity of
oil discharged that may be harmful is provided in Plan
OFFSHORE OIL DRILLING, PRODUCTION OR WORKOVER
FACILITIES— 40 CFR 112.11
112.11(b)
112.11(c)
Oil drainage collection equipment used to prevent and control
small discharges around pumps, glands, valves, flanges,
expansion joints, hoses, drain lines, separators, treaters, tanks,
and associated equipment
Facility drains are controlled and directed toward a central
collection sump to prevent a discharge as described in §112.1(b);
if drains and sumps not practicable, oil in collection equipment
removed as often as necessary to prevent overflow
For facilities using a sump system, sump and drains adequately
sized
For facilities using a sump system, spare pump available to
remove liquids and assure that oil does not escape
Regularly scheduled preventive maintenance inspection and
testing program to assure reliable operation of liquid removal
system and pump start-up device
Redundant automatic sump pumps and control devices are
installed if necessary
d|Yes Cho ONA
EHves DNO DMA
Cves C NO DMA
PLAN
d|Yes CUNo ONA
Cves diMo DMA
Cves C]NO DMA
Cves DNO CNA
Cves C]NO DMA
dves CHisio DMA
dves CUNo ONA
FIELD
DYSS CUNo ONA
Eves DNO DMA
dves CUNo DMA
Cves CNO CNA
Oves CUNo dlMA
CH Yes CUNo DMA
Comments:
9 This provision does not apply to oil-filled manufacturing equipment (flow-through process)
10 A reportable discharge is a discharge as described in §112.1(b)(see 40 CFR part 110). Oil discharges that result from natural disasters, acts of war, or
terrorism are not included in this determination. The gallon amount(s) specified (either 1,000 or 42) refers to the amount of oil that actually reaches
navigable waters or adjoining shorelines not the total amount of oil spilled. The entire volume of the discharge is oil for this determination.
Offshore ?SPMM^W9&JcB§^^yW^i^^J^s Page 9 of 10 December 20^2-10-12)
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Appendix G: SPCC Inspection Checklists
112.11(d)
112.11(e)
112.11(f)
112.11(g)
112.11(h)
112.11(i)
112.11(j)
112.11(k)
112.11(1)
112.11(m)
112.11(n)
112.11(o)
112.11(p)
If separators and treaters are equipped with dump valves which
predominantly fail in the closed position and where pollution risk is
high, facility equipped to prevent discharges by:
• Extending the flare line to a diked area if the separator is near
shore;
• Equipping separator with high liquid level sensor to
automatically shut in wells producing to the separator; or
• Installing parallel redundant dump valves.
Atmospheric storage or surge containers equipped with high liquid
level sensing devices that activate an alarm or control the flow, or
otherwise prevent discharges
Pressure containers equipped with high and low pressure sensing
devices that activate an alarm or control the flow
Containers equipped with suitable corrosion protection
Written procedures maintained in the SPCC Plan for inspecting
and testing pollution prevention equipment and systems
Testing and inspection of pollution prevention equipment and
systems conducted on a scheduled periodic basis commensurate
with the complexity, conditions, and circumstances of the facility
and any other applicable regulations.
Simulated discharges are used for testing and inspecting human
and equipment pollution control and countermeasure systems
Detailed records are provided that describe surface and
subsurface well shut-in valves and devices in use at the facility for
each well.
Records are sufficient to determine the method of activation or
control, such as pressure differential, change in fluid or flow
conditions, combination of pressure and flow, or manual or remote
control mechanisms
Blowout prevention (BOP) assembly and well control system
installed before drilling below any casing string and during
workover operations
BOP assembly and well control system capable of controlling any
well-head pressure that may be encountered while on the well
Manifolds (headers) equipped with check valves on individual
flowlines
If the shut-in well pressure is greater than the working pressure of
the flowline and manifold valves up to and including the header
valves, flowlines are equipped with a high pressure sensing
device and shut-in valve at the wellhead, OR pressure relief
system provided for flowlines
Piping appurtenant to the facility is protected from corrosion, such
as with protective coatings or cathodic protection
Sub-marine piping appurtenant to the facility is protected against
environmental stresses and other activities such as fishing
operations
Sub-marine piping maintained in good operating condition at all
times. Piping periodically inspected or tested on a regular
schedule for failures. Documentation of inspections or tests kept
at facility.
PLAN
Cves CHlMo C|NA
dves C|NO ONA
dves dlMo CHlMA
dves CHlMo CHlMA
dves C|NO DNA
Cves C|NO DMA
HHves ONO ONA
Cves Cho DMA
Ores DNO ONA
dves CHlMo CHlMA
C^Yes E|NO CNA
dves QNO C|NA
dves C|NO ONA
d|Yes CH NO ONA
dives C|NO DMA
dves DNO DMA
FIELD
dves d NO DMA
dves Cho DMA
Dves Cho DMA
dves CH NO DMA
dves C|NO DMA
dves C|NO C|NA
Cves CNO DMA
nvesDNoDNA
dves C|NO DMA
Qves C|NO DNA
HIlYes CH NO C|NA
Elves CNO CNA
Dves Cho C|NA
dlYes Cl No CH NA
Qves CI NO DMA
CI Yes C|NO DNA
Comments:
Offshore
Page WofW
December 20
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Appendix G: SPCC Inspection Checklists
ATTACHMENT A
ONSHORE FACILITIES (EXCLUDING PRODUCTION) 40 CFR
112.8/112.12
NA
PLAN
FIELD
112.8(b)/ 112.12(b) Facility Drainage
Diked Areas
(1)
Drainage from diked storage areas is:
• Restrained by valves, except where facility systems are
designed to control such discharge, OR
• Manually activated pumps or ejectors are used and the
condition of the accumulation is inspected prior to draining
dike to ensure no oil will be discharged
Yes IjNo IJNA
Yes IjNo IJNA
Comments:
112.8(c)/112.12(c) Bulk Storage Containers |_|NA
Bulk storage container means any container used to store oil. These containers are used for purposes including, but not limited to, the storage of oil
prior to use, while being used, or prior to further distribution in commerce. Oil-filled electrical, operating, or manufacturing equipment is not a bulk
storage container.
If bulk storage containers are not present, mark this section Not Applicable (NA). If present, complete this section and Attachment C of this checklist.
(1)
Containers materials and construction are compatible with
material stored and conditions of storage such as pressure and
temperature
Yes
iNo IJNA
I Yes ONO DMA
(3)
If YES
Is there drainage of uncontaminated rainwater from diked areas
into a storm drain or open watercourse?
Yes
No MNA
Yes
INo MNA
Bypass valve normally sealed closed
• Retained rainwater is inspected to ensure that its presence
will not cause a discharge as described in §112.1(b)
. Bypass valve opened and resealed under responsible
supervision
• Adequate records of drainage are kept; for example, records
required under permits issued in accordance with 40 CFR
§§122.41(j)(2)and(m)(3)
| Yes
| Yes
| Yes
I Yes
jNo
]NO
]NO
]NO
JNA
]NA
]NA
]NA
| Yes
| Yes
| Yes
I Yes
JNo
]NO
]NO
]NO
JNA
]NA
]NA
INA
(4)
For completely buried metallic tanks installed on or after January
10, 1974 (if not exempt from SPCC regulation because subject to
all of the technical requirements of 40 CFR part 280 or 281):
. Provide corrosion protection with coatings or cathodic
protection compatible with local soil conditions
• Regular leak testing conducted
Yes MNo MNA
Yes MNo MNA
Yes MNo MNA
Yes MNo MNA
(5)
The buried section of partially buried or bunkered metallic tanks
protected from corrosion with coatings or cathodic protection
compatible with local soil conditions
Yes MNo LJNA
Yes MNo MNA
Comments:
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Offshore Oil Drilling, Production and Workover Facilities
Page A-1 of 2
G-63
December 2012 (12-10-12)
-------
Appendix G: SPCC Inspection Checklists
ATTACHMENT A
PLAN
FIELD
(6)
Test or inspect each aboveground container for integrity on a
regular schedule and whenever you make material repairs.
Techniques include, but are not limited to: visual inspection,
hydrostatic testing, radiographic testing, ultrasonic testing,
acoustic emissions testing, or other system of non-
destructive testing
Appropriate qualifications for personnel performing tests and
inspections are identified in the Plan and have been
assessed in accordance with industry standards
. The frequency and type of testing and inspections are
documented, are in accordance with industry standards and
take into account the container size, configuration and design
. Comparison records of aboveground container integrity
testing are maintained
• Container supports and foundations regularly inspected
. Outside of containers frequently inspected for signs of
deterioration, discharges, or accumulation of oil inside diked
areas
. Records of all inspections and tests maintained11
Yes llNo llNA
Yes IjNo MNA
jYes |_|No |_|NA
]YBS [UNO DMA
] Yes CNO CNA
]Yes CHNO [UNA
]Yes [UNO DMA
I Yes [~|NO niNA
Yes |_|No |_|NA
YBS
Yes
Yes
NA
NA
NA
NA
Yes NO NA
Integrity Testing Standard identified in the Plan:
112.12
(Applies to
AFVO
Facilities only)
Conduct formal visual inspection on a regular schedule for bulk
storage containers that meet all of the following conditions:
• Subject to 21 CFR part 110; • Have no external insulation; and
• Elevated; • Shop-fabricated.
• Constructed of austenitic
stainless steel;
In addition, you must frequently inspect the outside of the container
for signs of deterioration, discharges, or accumulation of oil inside
diked areas.
You must determine and document in the Plan the appropriate
qualifications for personnel performing tests and inspections.11
Yes II No IINA MYes MNo MNA
Yes MNo MNA
Yes MNo MNA
Yes MNo MNA
Yes MNo MNA
(10)
Visible discharges which result in a loss of oil from the container,
including but not limited to seams, gaskets, piping, pumps, valves,
rivets, and bolts are promptly corrected and oil in diked areas is
promptly removed
Yes MNo |_|NA
Yes MNo MNA
112.8(d)/112.12(d)Facility transfer operations, pumping, and facility process
(4)
Aboveground valves, piping, and appurtenances such as flange
joints, expansion joints, valve glands and bodies, catch pans,
pipeline supports, locking of valves, and metal surfaces are
inspected regularly to assess their general condition
Integrity and leak testing conducted on buried piping at time of
installation, modification, construction, relocation, or replacement
Yes MNo MNA
Yes MNo MNA
Yes MNo MNA
Yes MNo MNA
Comments:
Offshore Oil Drilling, Production and Workover Facilities
business practices will suffice
Page A-2 of 2
G-64
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT B
ONSHORE OIL PRODUCTION FACILITIES—40 CFR 112.9
NA
PLAN
FIELD
(Drilling and workover facilities are excluded from the requirements of §112.9)
Production facility means all structures (including but not limited to wells, platforms, or storage facilities), piping (including but not limited to flowlines or
intra-facility gathering lines), or equipment (including but not limited to workover equipment, separation equipment, or auxiliary non-transportation-
related equipment) used in the production, extraction, recovery, lifting, stabilization, separation or treating of oil (including condensate), or associated
storage or measurement, and is located in an oil or gas field, at a facility. This definition governs whether such structures, piping, or equipment are
subject to a specific section of this part.
112.9(b) Oil Production Facility Drainage
(1)
At tank batteries, separation and treating areas where there is a
reasonable possibility of a discharge as described in §1 12.1(b),
drains for dikes or equivalent measures are closed and sealed
except when draining uncontaminated rainwater. Accumulated oil
on the rainwater is removed and then returned to storage or
disposed of in accordance with legally approved methods
Prior to drainage, diked area inspected and action taken as
provided below:
. 1 12.8(c)(3)(ii) - Retained rainwater is inspected to ensure that
its presence will not cause a discharge as described in
1 12.8(c)(3)(iii) - Bypass valve opened and resealed under
responsible supervision
112.8(c)(3)(iv) -Adequate records of drainage are kept; for
example, records required under permits issued in
accordance with §122.41(j)(2) and (m)(3)
I Yes
|No |_|NA
| Yes
|No |_|NA
Yes NO NA
I Yes [~|NO r~|NA
I Yes
|No MNA
| Yes
|No |_|NA
Yes NO MA
I Yes HMO r~|NA
(2)
Field drainage systems (e.g., drainage ditches or road ditches) and
oil traps, sumps, or skimmers inspected at regularly scheduled
intervals for oil, and accumulations of oil promptly removed
Yes
No MNA
Yes
No I NA
112.9(c) Oil Production Facility Bulk Storage Containers
Bulk storage container means any container used to store oil. These containers are used for purposes including, but not limited to, the storage of oil
prior to use, while being used, or prior to further distribution in commerce. Oil-filled electrical, operating, or manufacturing equipment is not a bulk
storage container.
(1)
(2)
(3)
(4)
Containers materials and construction are compatible with material
stored and conditions of storage such as pressure and temperature
Except as allowed for flow-through process vessels in §112.9(c)(5)
and produced water containers in §112.9(c)(6), secondary
containment provided for all tank battery, separation and treating
facilities sized to hold the capacity of largest single container and
sufficient freeboard for precipitation.
Drainage from undiked area safely confined in a catchment basin
or holding pond.
Except as allowed for flow-through process vessels in §112.9(c)(5)
and produced water containers in §112.9(c)(6), periodically and
upon a regular schedule, visually inspect containers for
deterioration and maintenance needs, including foundation and
supports of each container on or above the surface of the ground
Yes MNo MNA
Yes MNo MNA
Yes MNo MNA
Yes MNo MNA
Yes MNo MNA
Yes MNo MNA
Yes MNo MNA
Yes MNo LJNA
New and old tank batteries engineered/updated in accordance with
good engineering practices to prevent discharges including at least
one of the following:
• Adequate container capacity to prevent overfill if a
pumper/gauger is delayed in making regularly scheduled
rounds;
Yes
jNo |_|NA
I Yes
JNo |_|NA
Overflow equalizing lines between containers so that a
full container can overflow to an adjacent container;
Adequate vacuum protection to prevent container collapse; or
High level sensors to generate and transmit an alarm to the
computer where the facility is subject to a computer production
control system
Comments:
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Offshore Oil Drilling, Production and Workover Facilities
Page B-1 of 4
G-65
December 2012 (12-10-12)
-------
Appendix G: SPCC Inspection Checklists
ATTACHMENT B
PLAN
FIELD
(5)
(iv)
Flow-through Process Vessels. Alternate requirements in lieu of sized secondary containment required in (c)(2) and
requirements in (c)(3) above for facilities with flow-through process vessels:
Flow-through process vessels and associated components (e.g.
dump valves) are periodically and on a regular schedule visually
inspected and/or tested for leaks, corrosion, or other conditions
that could lead to a discharge as described in §112.1(b)
Corrective actions or repairs have been made to flow-through
process vessels and any associated components as indicated by
regularly scheduled visual inspections, tests, or evidence of an oil
discharge
Oil removed or other actions initiated to promptly stabilize and
remediate any accumulation of oil discharges associated with the
produced water container
All flow-through process vessels comply with §§112.9(c)(2) and
(c)(3) within six months of any flow-through process vessel
discharge of more than 1,000 U.S. gallons of oil in a single
discharge as described in §112.1(b) or discharges of more than 42
U.S. gallons of oil in each of two discharges as described in
§112.1(b) within any twelve month period.
12
Yes IjNo MNA
Yes No NA
Yes llNo MNA
Yes MNo MNA
Yes MNO MNA
Yes No MNA
Yes MNO MNA
Yes MNO MNA
112.9(d) Facility transfer operations, pumping, and facility process
(1)
(3)
All aboveground valves and piping associated with transfer
operations are inspected periodically and upon a regular schedule
to determine their general condition. Include the general condition
of flange joints, valve glands and bodies, drip pans, pipe supports,
pumping well polish rod stuffing boxes, bleeder and gauge valves,
and other such items
If flowlines and intra-facility gathering lines are not provided with
secondary containment in accordance with §112.7(c) and the
facility is not required to submit an FRP under §112.20, then the
SPCC Plan includes:
• An oil spill contingency plan following the provisions of 40 CFR
part10913
• A written commitment of manpower, equipment, and materials
required to expeditiously control and remove any quantity of oil
discharged that might be harmful
Yes MNO MNA M Yes MNO MNA
I Yes |_|No |_|NA
I Yes r~|No flNA
JYes |_|No |_|NA
I Yes [~]NO IZlNA
Comments:
12 Oil discharges that result from natural disasters, acts of war, or terrorism are not included in this determination. The gallon amount(s) specified (either
1,000 or 42) refers to the amount of oil that actually reaches navigable waters or adjoining shorelines not the total amount of oil spilled. The entire
volume of the discharge is oil for this determination.
13 Note that the implementation of a 40 CFR part 109 plan does not require a PE impracticability determination for this specific requirement
SPCC GUIDANCE FOR REGIONAL INSPECTORS G-66
Offshore Oil Drilling, Production and Workover Facilities Page 6-2 of 4
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT B
PLAN
FIELD
(4)
(iv)
Aflowline/intra-facility gathering line maintenance program to
prevent discharges is prepared and implemented and includes the
following procedures:
Flow/lines and intra-facility gathering lines and associated valves
and equipment are compatible with the type of production fluids,
their potential corrosivity, volume, and pressure, and other
conditions expected in the operational environment
Flowlines and intra-facility gathering lines and associated
appurtenances are visually inspected and/or tested on a periodic
and regular schedule for leaks, oil discharges, corrosion, or other
conditions that could lead to a discharge as described in §112.1(b).
If flowlines and intra-facility gathering lines are not provided with
secondary containment in accordance with §112.7(c), the
frequency and type of testing allows for the implementation of a
contingency plan as described under 40 CFR 109 or an FRP
submitted under §112.20
Repairs or other corrective actions are made to any flowlines and
intra-facility gathering lines and associated appurtenances as
indicated by regularly scheduled visual inspections, tests, or
evidence of a discharge
Oil removed or other actions initiated to promptly stabilize and
remediate any accumulation of oil discharges associated with the
produced water containers
Yes MNo MNA
Yes |_|No MNA
Yes MNo MNA
Yes MNo MNA
Yes MNo MNA
Yes MNo NA
Yes |_|No MNA
Yes MNo MNA
Yes MNo MNA
Yes MNO MNA
ATTACHMENTS |_|NA
ONSHORE OIL DRILLING AND WORKOVER FACILITIES—40 CFR
112.10
PLAN
FIELD
Mobile drilling or workover equipment is positioned or located to
prevent a discharge as described in §112.1(b)
Yes MNo MNA
Yes MNO MNA
Catchment basins or diversion structures are provided to intercept
and contain discharges of fuel, crude oil, or oily drilling fluids
Yes MNO MNA
Yes MNO MNA
Blowout prevention (BOP) assembly and well control system
installed before drilling below any casing string or during workover
operations
BOP assembly and well control system is capable of controlling
any well-head pressure that may be encountered while on the well
Yes MNo MNA
Yes MNO MNA
Yes MNo MNA
Yes MNO MNA
Comments:
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Offshore Oil Drilling, Production and Workover Facilities
Page 6-3 of 4
G-67
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
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SPCC GUIDANCE FOR REGIONAL INSPECTORS G-68
Offshore Oil Drilling, Production and Workover Facilities Page B-4 of 4 December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT C: SPCC FIELD INSPECTION AND PLAN REVIEW TABLE
Documentation of Field Observations for Containers and Associated Requirements
Inspectors should use this table to document observations of containers as needed.
Containers and Piping
Check containers for leaks, specifically looking for: drip marks, discoloration of tanks, puddles containing spilled or leaked
material, corrosion, cracks, and localized dead vegetation, and standards/specifications of construction.
Check aboveground container foundation for: cracks, discoloration, and puddles containing spilled or leaked material, settling,
gaps between container and foundation, and damage caused by vegetation roots.
Check all piping for: droplets of stored material, discoloration, corrosion, bowing of pipe between supports, evidence of stored
material seepage from valves or seals, evidence of leaks, and localized dead vegetation. For all aboveground piping, include the
general condition of flange joints, valve glands and bodies, drip pans, pipe supports, bleeder and gauge valves, and other such items
(Document in comments section of §112.11.)
Secondary Containment (Active and Passive)
Check secondary containment for: containment system (including walls and floor) ability to contain oil such that oil will not escape
the containment system before cleanup occurs, proper sizing, cracks, discoloration, presence of spilled or leaked material (standing
liquid), erosion, corrosion, penetrations in the containment system, and valve conditions.
Check dike or berm systems for: level of precipitation in dike/available capacity, operational status of drainage valves (closed), dike
or berm impermeability, debris, erosion, impermeability of the earthen floor/walls of diked area, and location/status of pipes, inlets,
drainage around and beneath containers, presence of oil discharges within diked areas.
Check drainage systems for: an accumulation of oil that may have resulted from any small discharge, including field drainage
systems (such as drainage ditches or road ditches), and oil traps, sumps, or skimmers. Ensure any accumulations of oil have been
promptly removed.
Check retention and drainage ponds for: erosion, available capacity, presence of spilled or leaked material, debris, and stressed
vegetation.
Check active measures (countermeasures) for: amount indicated in plan is available and appropriate; deployment procedures are
realistic; material is located so that they are readily available; efficacy of discharge detection; availability of personnel and training,
appropriateness of measures to prevent a discharge as described in §112.1 (b). Note that appropriate evaluation and consideration
must be given to any use of active measures at an unmanned production facility.
Container ID/ General
Condition14
Aboveground or Buried Tank
Storage Capacity and Type
of Oil
Type of Containment/
Drainage Control
Overfill Protection and
Testing & Inspections
Identify each tank with either an A to indicate aboveground or B for completely buried
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Offshore Oil Drilling, Production and Workover Facilities Page C-1 of 2
G-69
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT C: SPCC FIELD INSPECTION AND PLAN REVIEW TABLE (CONT.)
Documentation of Field Observations for Containers and Associated Requirements
Container ID/ General
Condition15
Aboveground or Buried Tank
Storage Capacity and Type
of Oil
Type of Containment/
Drainage Control
Overfill Protection and
Testing & Inspections
Identify each tank with either an A to indicate aboveground or B for completely buried
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Offshore Oil Drilling, Production and Workover Facilities Page C-2 of 2
G-70
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT D: SPCC INSPECTION AND TESTING CHECKLIST
Required Documentation of Tests and Inspections
Records of inspections and tests required by 40 CFR part 112 signed by the appropriate supervisor or inspector must be kept by all
facilities with the SPCC Plan for a period of three years. Records of inspections and tests conducted under usual and customary
business practices will suffice. Documentation of the following inspections and tests should be kept with the SPCC Plan.
Inspection or Test
Documentation
Present
Not
Present
Not
Applicable
112.7-General SPCC Requirements
(d)
(d)
(h)(3)
(i)
k(2)(i)
Integrity testing for bulk storage containers with no secondary containment system
and for which an impracticability determination has been made
Integrity and leak testing of valves and piping associated with bulk storage
containers with no secondary containment system and for which an impracticability
determination has been made
Inspection of lowermost drain and all outlets of tank car or tank truck prior to filling
and departure from loading/unloading rack
Evaluation of field-constructed aboveground containers for potential for brittle
fracture or other catastrophic failure when the container undergoes a repair,
alteration, reconstruction or change in service or has discharged oil or failed due to
brittle fracture failure or other catastrophe
Inspection or monitoring of qualified oil-filled operational equipment when the
equipment meets the qualification criteria in §112.7(k)(1) and facility
owner/operator chooses to implement the alternative requirements in §1 12.7(k)(2)
that include an inspection or monitoring program to detect oil-filled operational
equipment failure and discharges
D
D
D
D
o
n
D
D
n
n
D
D
G
D
o
1 12. 11-Offshore oil drilling, production and workover facilities
(c)
(i)
(P)
Regularly scheduled preventive maintenance inspection and testing program to
assure reliable operation of liquid removal system and pump start-up device
Testing and inspection of pollution prevention equipment and systems performed
on a scheduled periodic basis. Simulated discharges are used for testing and
inspecting human and equipment pollution control and countermeasure systems
Submarine piping periodically inspected or tested for failures
D
D
n
n
n
n
n
n
n
112.8/112.12-Onshore Facilities (excluding oil production facilities) I JNA
(b)(1), (b)(2)
(c)(3)
(c)(4)
(c)(6)
(c)(6),
(c)(10)
(c)(6)
(d)(4)
(d)(4)
Inspection of storm water released from diked areas into facility drainage directly to
a watercourse
Inspection of rainwater released directly from diked containment areas to a storm
drain or open watercourse before release, open and release bypass valve under
supervision, and records of drainage events
Regular leak testing of completely buried metallic storage tanks installed on or after
January 10, 1974 and regulated under 40 CFR 112
Regular integrity testing of aboveground containers and integrity testing after
material repairs, including comparison records
Regular visual inspections of the outsides of aboveground containers, supports
and foundations
Frequent inspections of diked areas for accumulations of oil
Regular inspections of aboveground valves, piping and appurtenances and
assessments of the general condition of flange joints, expansion joints, valve
glands and bodies, catch pans, pipeline supports, locking of valves, and metal
surfaces
Integrity and leak testing of buried piping at time of installation, modification,
construction, relocation or replacement
n
n
n
n
n
n
D
n
n
n
n
n
n
n
n
D
n
n
o
D
n
n
n
n
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Offshore Oil Drilling, Production and Workover Facilities
Page D-1 of 2
G-71
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
112.9-Onshore Oil Production Facilities (excluding drilling and workover facilities)
NA
Rainwater released directly from diked containment areas inspected following
§§112.8(c)(3)(ii), (iii) and (iv), including records of drainage kept
Field drainage systems, oil traps, sumps, and skimmers inspected regularly for oil,
and accumulations of oil promptly removed
Containers, foundations and supports inspected visually for deterioration and
maintenance needs
In lieu of having sized secondary containment, flow-through process vessels and
associated components visually inspected and/or tested periodically and on a
regular schedule for conditions that could result in a discharge as described in
All aboveground valves and piping associated with transfers are regularly
inspected
For flowlines and intra-facility gathering lines without secondary containment, in
accordance with §112.7(c), lines are visually inspected and/or tested periodically
and on a regular schedule to allow implementing the part 109 contingency plan or
the FRP submitted under §112.20
Comments:
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Offshore Oil Drilling, Production and Workover Facilities
Page D-2of2
G-72
December 2012 (12-10-12)
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Apppnrliy fV RPf.r. Insppntinn
ATTACHMENT E: SPCC CONTINGENCY PLAN REVIEW CHECKLIST UNA
40 CFR Part 109-Criteria for State, Local and Regional Oil Removal Contingency Plans
If SPCC Plan includes an impracticability determination for secondary containment in accordance with §112.7(d), the facility
owner/operator is required to provide an oil spill contingency plan following 40 CFR part 109, unless he or she has submitted
under §112.20. An oil spill contingency plan may also be developed, unless the facility owner/operator has submitted a FRP
§112.20 as one of the required alternatives to general secondary containment for qualified oil filled operational equipment in
accordance with §112.7(k).
a FRP
under
109.5-Development and implementation criteria for State, local and regional oil removal contingency plans16
(a)
(b)
(1)
(2)
(3)
(4)
(c)
(1)
(2)
(3)
(d)
(1)
(2)
(3)
(4)
(5)
(e)
Definition of the authorities, responsibilities and duties of all persons, organizations or agencies which are to
be involved in planning or directing oil removal operations.
Establishment of notification procedures for the purpose of early detection and timely notification of an oil
discharge including:
The identification of critical water use areas to facilitate the reporting of and response to oil discharges.
A current list of names, telephone numbers and addresses of the responsible persons (with alternates) and
organizations to be notified when an oil discharge is discovered.
Provisions for access to a reliable communications system for timely notification of an oil discharge, and the
capability of interconnection with the communications systems established under related oil removal
contingency plans, particularly State and National plans (e.g., National Contingency Plan (NCR)).
An established, prearranged procedure for requesting assistance during a major disaster or when the
situation exceeds the response capability of the State, local or regional authority.
Provisions to assure that full resource capability is known and can be committed during an oil discharge
situation including:
The identification and inventory of applicable equipment, materials and supplies which are available locally
and regionally.
An estimate of the equipment, materials and supplies that would be required to remove the maximum oil
discharge to be anticipated.
Development of agreements and arrangements in advance of an oil discharge for the acquisition of
equipment, materials and supplies to be used in responding to such a discharge.
Provisions for well-defined and specific actions to be taken after discovery and notification of an oil discharge
including:
Specification of an oil discharge response operating team consisting of trained, prepared and available
operating personnel.
Pre-designation of a properly qualified oil discharge response coordinator who is charged with the
responsibility and delegated commensurate authority for directing and coordinating response operations and
who knows how to request assistance from Federal authorities operating under existing national and regional
contingency plans.
A preplanned location for an oil discharge response operations center and a reliable communications system
for directing the coordinated overall response operations.
Provisions for varying degrees of response effort depending on the severity of the oil discharge.
Specification of the order of priority in which the various water uses are to be protected where more than one
water use may be adversely affected as a result of an oil discharge and where response operations may not
be adequate to protect all uses.
Specific and well defined procedures to facilitate recovery of damages and enforcement measures as
provided for by State and local statutes and ordinances.
Yes
D
n
D
D
°
D
n
D
D
D
n
D
°
D
n
n
D
No
D
D
D
D
°
n
D
D
D
n
D
D
n
D
D
°
D
' The contingency plan should be consistent with all applicable state and local plans, Area Contingency Plans, and the NCR.
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Offshore Oil Drilling, Production and Workover Facilities Page E-1 of 2
G-73
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
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SPCC GUIDANCE FOR REGIONAL INSPECTORS G-74
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Appendix G: SPCC Inspection Checklists
ATTACHMENT F: ADDITIONAL COMMENTS
SPCC GUIDANCE FOR REGIONAL INSPECTORS G-75
Offshore Oil Drilling, Production and Workover Facilities Page F-1 of 2 December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT F: ADDITIONAL COMMENTS (CONT.)
C UUILJANCh I-OK KhUIONAL INSPhC I OKS U-/S
Offshore Oil Drilling, Production and Workover Facilities Page F-2 of 2 December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT G: PHOTO DOCUMENTATION NOTES
Photo*
Photographer
Name
Time of
Photo Taken
Compass
Direction
Description
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Offshore Oil Drilling, Production and Workover Facilities
Page G-1of2
G-77
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT G: PHOTO DOCUMENTATION NOTES (CONT.)
Photo*
Photographer
Name
Time of
Photo Taken
Compass
Direction
Description
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Offshore Oil Drilling, Production and Workover Facilities
Page G-2of2
G-78
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
U.S. ENVIRONMENTAL PROTECTION AGENCY
SPCC FIELD INSPECTION AND PLAN REVIEW CHECKLIST
TIER I QUALIFIED FACILITIES
Overview of the Checklist
This checklist is designed to assist EPA inspectors in conducting a thorough and nationally consistent inspection of a
facility's compliance with the Spill Prevention, Control, and Countermeasure (SPCC) rule at 40 CFR part 112. It is a
required tool to help federal inspectors (or their contractors) record observations for the site inspection and review of the
SPCC Plan. While the checklist is meant to be comprehensive, the inspector should always refer to the SPCC rule in its
entirety, the SPCC Regional Inspector Guidance Document, and other relevant guidance for evaluating compliance. This
checklist must be completed in order for an inspection to count toward an agency measure (i.e., OEM inspection
measures or GPRA). The completed checklist and supporting documentation (i.e. photo logs or additional notes) serve as
the inspection report.
This checklist addresses requirements for Tier I Qualified Facilities that meet the eligibility criteria set forth in §112.3(g)(1).
Separate and standalone checklists
Onshore
Onshore
and
Offshore
facilities including Tier
address the requirements for:
II Qualified Facilities (excluding
oil drilling, production and workover facilities including
drilling, production and
workover facilities
oil drilling,
Tierl
production and workover
1 Qualified
Facilities as defined
facilities);
in§112.3(g)(2);
Tier I Qualified Facilities must meet the rule requirements in §112.6 and other applicable sections specified in §112.6. The
checklist is organized according to the SPCC rule. Each item in the checklist identifies the relevant section and paragraph
in 40 CFR part 112 where that requirement is stated.
. Sections 112.1 through 112.5 specify the applicability of the rule and requirements for the preparation,
implementation, and amendment of SPCC Plans. For these sections, the checklist includes data fields to be
completed, as well as several questions with "yes," "no" or "NA" answers.
. Section 112.6 includes requirements for Tier I qualified facilities.
. Section 112.7 includes general requirements that apply to all facilities (unless otherwise excluded).
Attachments
. Attachment A is a checklist for Sections 112.8 and 112.12. This checklist specifies requirements for spill
prevention, control, and countermeasures for onshore facilities (excluding oil production facilities).
. Attachment B is a checklist that specifies requirements for spill prevention, control, and countermeasures for
onshore oil production facilities (112.9 provisions) and onshore drilling and workover facilities (112.10 provisions)
. Attachment C is for recording information about containers and other locations at the facility that require
secondary containment.
. Attachment D is a checklist for documenting the tests and inspections the facility operator is required to keep with
the SPCC Plan.
. Attachment E is a checklist for oil spill contingency plans following 40 CFR 109. Unless a facility has submitted a
Facility Response Plan (FRP) under 40 CFR 112.20, a contingency plan following 40 CFR 109 is required if a
facility the owner or operator of a facility with qualified oil-filled operational equipment chooses to implement
alternative requirements instead of general secondary containment requirements as provided in 40 CFR 112.7(k).
. Attachment F is for recording additional comments or notes.
. Attachment G is for recording information about photos.
The inspector needs to evaluate whether the requirements in the checklist are addressed adequately or inadequately in
the SPCC Plan and whether it is implemented adequately in the field (either by field observation or record review). For
the SPCC Plan and implementation in the field, if a requirement is addressed adequately, mark the "Yes" box in the
appropriate column. If a requirement is not addressed adequately, mark the "No" box. If a requirement does not apply to
the particular facility or the question asked is not appropriate for the facility, mark as "NA". Discrepancies or descriptions
of inspector interpretation of "No" vs. "NA" may be documented in the comments box subsequent to each section. If a
provision of the rule applies only to the SPCC Plan, the "Field" column is shaded.
Space is provided throughout the checklist to record comments. Additional space is available as Attachment F at the end
of the checklist. Comments should remain factual and support the evaluation of compliance.
SPCC GUIDANCE FOR REGIONAL INSPECTORS G-79
Tier I Qualified Facilities Page 1 of 8 December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
FACILITY INFORMATION
FACILITY NAME:
LATITUDE:
LONGITUDE:
GPS DATUM:
Section/Township/Range:
FRS#/OIL DATABASE ID:
ICIS#:
ADDRESS:
CITY:
STATE:
ZIP:
COUNTY:
MAILING ADDRESS (IF DIFFERENT FROM FACILITY ADDRESS-IF NOT, PRINT-SAME-):
CITY:
STATE:
ZIP:
COUNTY:
TELEPHONE:
FACILITY CONTACT NAME/TITLE:
OWNER NAME:
OWNER ADDRESS:
CITY:
STATE:
ZIP:
COUNTY:
TELEPHONE:
FAX:
EMAIL:
FACILITY OPERATOR NAME (IF DIFFERENT FROM OWNER-IF NOT, PRINT "SAME"):
OPERATOR ADDRESS:
CITY:
STATE:
ZIP:
COUNTY:
TELEPHONE:
OPERATOR CONTACT NAME/TITLE:
FACILITY TYPE:
NAICS CODE:
HOURS PER DAY FACILITY ATTENDED:
TOTAL FACILITY CAPACITY:
TYPE(S) OF OIL STORED:
LOCATED IN INDIAN COUNTRY? IJYES
NO RESERVATION NAME:
INSPECTION/PLAN REVIEW INFORMATION
PLAN REVIEW DATE:
REVIEWER NAME:
INSPECTION DATE:
TIME:
ACTIVITY ID NO:
LEAD INSPECTOR:
OTHER INSPECTOR(S):
INSPECTION ACKNOWLEDGMENT
/ performed an SPCC inspection at the facility specified above.
INSPECTOR SIGNATURE:
DATE:
SUPERVISOR REVIEW/SIGNATURE:
DATE:
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Tier I Qualified Facilities
Page 2 of 8
G-80
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
SPCC GENERAL APPLICABILITY—40 CFR 112.1
IS THE FACILITY REGULATED UNDER 40 CFR part 112?
The completely buried oil storage capacity is over 42,000 U.S. gallons, OR the aggregate aboveground
oil storage capacity is over 1,320 U.S. gallons AND
The facility is a non-transportation-related facility engaged in drilling, producing, gathering, storing,
processing, refining, transferring, distributing, using, or consuming oil and oil products, which due to its
location could reasonably be expected to discharge oil into or upon the navigable waters of the United
States
jYes
]ves
jNo
]NO
AFFECTED WATERWAY(S):
DISTANCE:
FLOW PATH TO WATERWAY:
Note: The following storage capacity is not considered in determining applicability of SPCC requirements:
Equipment subject to the authority of the U.S. Department of
Transportation, U.S. Department of the Interior, or Minerals
Management Service, as defined in Memoranda of Understanding
dated November 24, 1971, and November 8, 1993; Tank trucks that
return to an otherwise regulated facility that contain only residual
amounts of oil (EPA Policy letter)
Completely buried tanks subject to all the technical requirements of 40
CFR part 280 or a state program approved under 40 CFR part 281;
Underground oil storage tanks deferred under 40 CFR part 280 that
supply emergency diesel generators at a nuclear power generation
facility licensed by the Nuclear Regulatory Commission (NRC) and
subject to any NRC provision regarding design and quality criteria,
including but not limited to CFR part 50;
Any facility or part thereof used exclusively for wastewater treatment
(production, recovery or recycling of oil is not considered wastewater
treatment); (This does not include other oil containers located at a
wastewater treatment facility, such as generator tanks or transformers)
Containers smaller than 55 U.S. gallons;
Permanently closed containers (as defined in §112.2);
Motive power containers (as defined in §112.2);
Hot-mix asphalt or any hot-mix asphalt containers;
Heating oil containers used solely at a single-family residence;
Pesticide application equipment and related mix containers;
Any milk and milk product container and associated piping and
appurtenances; and
Intra-facility gathering lines subject to the regulatory requirements
of 49 CFR part 192 or 195.
Does the facility have an SPCC Plan?
Yes
No
SPCC TIER I QUALIFIED FACILITY APPLICABILITY—40 CFR 112.3(g)(1),(2)
The aggregate aboveground oil storage capacity is 10,000 U.S. gallons or less AND
The capacity of each individual aboveground oil storage container is 5,000 U.S. gallons or less AND
In the three years prior to the SPCC Plan self-certification date, or since becoming subject to the rule
(if the facility has been in operation for less than three years), the facility has NOT had:
• A single discharge as described in §112.1(b) exceeding 1,000 U.S. gallons, OR
• Two discharges as described in §112.1(b) each exceeding 42 U.S. gallons within any twelve-month
period1
JYes
Kes
JYes
lYes
JNo
]NO
JNo
]NO
"ES TO ALL OF THE ABOVE, THEN THE FACILITY IS CONSIDERED A TIER I QUALIFIED FACILITY.
Comments:
:
1 Oil discharges that result from natural disasters, acts of war, or terrorism are not included in this determination. The gallon amount(s) specified (either
1,000 or 42) refers to the amount of oil that actually reaches navigable waters or adjoining shorelines not the total amount of oil spilled. The entire
volume of the discharge is oil for this determination.
2 An owner/operator who self-certifies a Tier I SPCC Plan may not include any environmentally equivalent alternatives or secondary containment
impractica^fetdejej^^e^^iRgg^KLaOJSPECTORS G-81
Tier I Qualified Facilities Page 3 of 8 December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
REQUIREMENTS FOR PREPARATION AND IMPLEMENTATION OF A SPCC PLAN— 40 CFR 112.3
Date facility began operations:
Date of initial SPCC Plan preparation: Current Plan version (date/number):
112.3(a)
112.3(e)(1)
For facilities (except farms), including mobile or portable facilities:
• In operation on or prior to November 1 0, 201 1 : Plan prepared and/or amended and fully
implemented by November 10, 2011
• Facilities beginning operation after November 10, 201 1:
o Oil production facilities - Plan prepared and fully implemented within six months
after beginning operations; or
o All other facilities - Plan prepared and fully implemented before operations begin
For farms (as defined in §112.2):
• In operation on or prior to August 16, 2002: Plan maintained, amended and
implemented by May 10, 2013
• Beginning operations after August 16, 2002 through May 10, 2013: Plan prepared and
fully implemented by May 10, 2013
• Beginning operations after May 10, 2013: Plan prepared and fully implemented before
beginning operations
Plan is available onsite if attended at least 4 hours per day. If facility is unattended, Plan is
available at the nearest field office. (Please note nearest field office contact information in
comments section below.)
Comments:
AMENDMENT OF SPCC PLAN BY REGIONAL ADMINISTRATOR (RA)— 40 CFR 1 1 2.4
112.4(a),(c)
If YES
112.4(d),(e)
Has the facility discharged more than 1 ,000 U.S. gallons of oil in a single reportable
discharge or more than 42 U.S. gallons in each of two reportable discharges in any 12-month
period?
• Was information submitted to the RA as required in §1 12.4(a)?4
• Was information submitted to the appropriate agency or agencies in charge of oil
pollution control activities in the State in which the facility is located§1 12.4(c)
• Date(s) and volume(s) of reportable discharges(s) under this section:
. Were the discharges reported to the NRC5?
Have changes required by the RA been implemented in the Plan and/or facility?
dves C|NO C|NA
dves QNO DNA
HHYes DNO DNA
dves DNO DNA
Cves CNO DNA
nYes C|NO ONA
HHYes CUNo
QJYes CUNo L~HNA
CH Yes C|NO DNA
dves CUNo
QYes Q|NO nNA
Comments:
A reportable discharge is a discharge as described in §112.1(b)(see 40 CFR part 110). The gallon amount(s) specified (either 1,000 or 42) refers to the
amount of oil that actually reaches navigable waters or adjoining shorelines not the total amount of oil spilled. The entire volume of the discharge is oil
for this determination
4 Triggering this threshold may disqualify the facility from meeting the Qualified Facility criteria if it occurred in the three years prior to self-certification
Tier I Qualified Facilities Page 4 of 8 December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
AMENDMENT OF SPCC PLAN BY THE OWNER OR OPERATOR—40 CFR 112.5
112.5(a)
If YES
112.5(b)
Has there been a change at the facility that materially affects the potential for a discharge
described in§112.1(b)?
. Was the Plan amended within six months of the change?
. Were amendments implemented within six months of any Plan amendment?
Review and evaluation of the Plan completed at least once every 5 years?
Following Plan review, was Plan amended within six months to include more effective
prevention and control technology that has been field-proven to significantly reduce the
likelihood of a discharge described in §112.1(b)?
Amendments implemented within six months of any Plan amendment?
Five year Plan review and evaluation documented?
|Yes
Fiv
es
| Yes I
| Yes
Yes
Yes
jNo
] No
] No
]NO
]NO |
]NO
]NO I
JNA
INA
]NA
INA
112.5(c)
Professional Engineer certification of any technical Plan amendments in accordance with all
applicable requirements of §112.3(d) [Except for self-certified Plans]
Yes
JNo LJNA
Name:
License No.:
State:
Date of certification:
Reason for amendment:
TIER I QUALIFIED FACILITY PLAN REQUIREMENTS —40 CFR 112.6(a)
VIM
Plan Certification: Plan prepared to comply with the requirements of §112.6(a)(3) using the
Appendix G template
He or she is familiar with the requirements of 40 CFR part 112
He or she has visited and examined the facility6
The Plan has been prepared in accordance with accepted and sound industry practices and
standards
Procedures for required inspections and testing have been established
He or she will fully implement the Plan
The facility meets the qualification criteria in §112.3(g)(1)
The Plan does not deviate from any requirements as allowed by §§112.7(a)(2) and 112.7(d),
or include measures pursuant to §112.9(c)(6) for produced water containers and any
associated piping
The Plan and individual(s) responsible for implementing the Plan have the full approval of
management and the facility owner or operator has committed the necessary resources to
fully implement the Plan.
Yes
I Yes
j Yes
| Yes
I Yes
I Yes
I Yes
Yes
Yes
JNo
]NO
No
JNA
INA
]NA
]NA
]NA
JNA
NA
No \ NA
NO MNA
112.6(a)(2)
If YES
Technical Amendments: The owner/operator self-certified the Plan's technical amendments
for a change in facility design, construction, operation, or maintenance that affected potential
fora§112.1(b) discharge
. Certification of technical amendments is in accordance with the self-certification
provisions of §112.6(a)(1).
|Yes |_|No LJNA
I Yes r~|No r~|NA
An individual oil storage container capacity exceeds 5,000 U.S. gallons or the aggregate
aboveground oil storage capacity increased to more than 10,000 U.S. gallons as a result of
the chanqe
Yes MNo |_|NA
If YES
The facility no longer meets the Tier I qualifying criteria in §112.3(g)(1) because an individual oil storage container
capacity exceeds 5,000 U.S. gallons or the facility aboveground storage capacity exceeds 10,000 U.S. gallons
The following has been or will be completed within six months following the amendment:
• Plan prepared and implemented in accordance with the requirements for a Tier II
Qualified Facility (§112.6(b)) if the facility meets the eligibility criteria OR
• Plan prepared and implemented in accordance with the general Plan requirements in
§112.7 and applicable requirements in subparts B and C and certified by a PE as
required under §112.3(d)
Yes
Yes
No NA
No \ NA
visit
Tier I Qualified Facilities
Page 5 of 8
G-83
December 2012 (12-10-12)
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Appendix G: SPCC Ins
112.6(a)(3)(i)
(ii)
(iii)
Plan includes a prediction of the direction and total quantity of oil which could be discharged
from the facility as a result of each type of major equipment failure if there is a reasonable
potential for equipment failure (such as loading or unloading equipment, tank overflow,
rupture, or leakage, or any other equipment known to be a source of discharge)
Bulk storage container installations (except mobile refuelers and other non-transportation-
related tank trucks), including mobile or portable oil storage containers, are constructed to
provide secondary containment for the entire capacity of the largest single container plus
additional capacity to contain precipitation, and
Mobile or portable oil storage containers positioned or located to prevent a §112.1(b)
discharge
Plan describes a system or documented procedure to prevent overfills for each container
and is regularly tested to ensure proper operation or efficacy
oection Checklists
CYBS CNO CNA
CYBS CNO CNA
CYBS CNO CNA
CYBS CNO CNA
Comments:
GENERAL SPCC REQUIREMENTS— 40 CFR 112.7
Management approval at a level of authority to commit the necessary resources to
fully implement the Plan7
Plan follows sequence of the rule or is an equivalent Plan meeting all applicable
rule requirements and includes a cross-reference of provisions
If Plan calls for facilities, procedures, methods, or equipment not yet fully
operational, details of their installation and start-up are discussed (Note: Relevant
for inspection evaluation and testing baselines.)
112.7(a)(3)
(i)
(iv)
(vi)
112.7(a)(4)
112.7(a)(5)
PLAN
CYes CNO
CYBS CNO CNA
FIELD
CYBS CNO DMA
Plan addresses each of the following:
For each fixed container, type of oil and storage capacity (see
Attachment C of this checklist). For mobile or portable containers,
type of oil and storage capacity for each container or an estimate
of the potential number of mobile or portable containers, the types
of oil, and anticipated storage capacities
Countermeasures for discharge discovery, response, and cleanup
(both facility's and contractor's resources)
Contact list and phone numbers for the facility response
coordinator, National Response Center, cleanup contractors with
an agreement for response, and all Federal, State, and local
agencies who must be contacted in the case of a discharge as
described in §112.1(b)
CYes CNO
CYes CNO
C Yes CNO
Plan includes information and procedures that enable a person | |Yes | |lMo I llMA
reporting an oil discharge as described in §112.1(b) to relate
information on the:
• Exact address or location and phone • A description of all affected media;
number of the facility; . Cause of the discharge;
. Date and time of the discharge; . Damages or injuries caused by the
• Type of material discharged; discharge;
• Estimates of the total quantity discharged; • Actions being used to stop, remove, and
. Estimates of the quantity discharged as mitigate the effects of the discharge;
described in §11 2.1 (b); • Whether an evacuation may be needed;
• Source of the discharge; • Names of individuals and/or organizations
who have also been contacted
Plan organized so that portions describing procedures to be used
when a discharge occurs will be readily usable in an emergency
CYes CNO
CYes CNO
CYBS CNO CNA I
I
Comments:
7 May be
Tier I Qualified Facilities
Page 6 of 8
G-84
December 2012 (12-10-12)
-------
Appendix G: SPCC Inspection Checklists
112.7(c)
112.7(e)
112.7(f)
(1)
(2)
(3)
PLAN | FIELD
Appropriate containment and/or diversionary structures or equipment are provided to prevent a discharge as
described in §112.1(b), except as provided in §112.7(k) of this section for certain qualified operational
equipment and §112.9(d)(3) for certain flowlines and intra-facility gathering lines at an oil production facility.
The entire containment system, including walls and floors, are capable of containing oil and are constructed to prevent
escape of a discharge from the containment system before cleanup occurs. The method, design, and capacity for
secondary containment address the typical failure mode and the most likely quantity of oil that would be discharged.
See Attachment C of this checklist.
For onshore facilities, one of the following or its equivalent:
• Dikes, berms, or retaining walls sufficiently • Weirs, booms or other barriers,
impervious to contain oil, . Spi|| diversion ponds,
. Curbing or drip pans, . Retention ponds, or
. Sumps and collection systems, . sorbent materials
• Culverting, gutters or other drainage systems,
Identify which of the following are present at the facility and if appropriate containment and/or diversionary structures
or equipment are provided as described above:
n Bulk storage containers DYesDNoDNA DYesDNoDNA
I I Mobile/portable containers
Doil-filled operational equipment (as defined in 112.2)
LJ Other oil-filled equipment (i.e., manufacturing equipment)
I Ipiping and related appurtenances
1 (Mobile refuelers or non-transportation-related tank cars
CJTransfer areas, equipment and activities
1 1 Identify anv other equipment or activities that are not listed
above:
Inspections and tests conducted in accordance with written
procedures
Record of inspections or tests signed by supervisor or inspector
Kept with Plan for at least 3 years (see Attachment D of this
checklist)8
Cves DNO DNA
DYBS DNO DNA
D Yes DNO DNA
E| Yes DNO DNA
DYBS DNO DNA
DYBS DNO DNA
C Yes DNO DMA
DYBS DNO
DYes DNO
DYBS DNO DNA
DYBS DNO DMA
DYBS DNO DNA
DYBS DNO DNA
DYBS DNO DNA
D Yes DNO DNA
DYBS DNO DNA
CHYes DNO
Personnel, training, and oil discharge prevention procedures
Training of oil-handling personnel in operation and maintenance of
equipment to prevent discharges; discharge procedure protocols;
applicable pollution control laws, rules, and regulations; general
facility operations; and contents of SPCC Plan
Person designated as accountable for discharge prevention at the
facility and reports to facility management
Discharge prevention briefings conducted at least once a year for
oil handling personnel to assure adequate understanding of the
Plan. Briefings highlight and describe known discharges as
described in §1 12.1(b) or failures, malfunctioning components,
and any recently developed precautionary measures
C Yes DNO ONA
d|Yes CHlMo CHlMA
CHYes C|NO DNA
HHYes HH NO DMA
DYBS ONO DNA
QYes DNO DNA
Comments:
Tier I Qualified Facilities
business practices will suffice
Page 7 of 8
G-85
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
PLAN
FIELD
112.7(g)
Plan describes how to:
. Secure and control access to the oil handling, processing and
storage areas;
. Secure master flow and drain valves;
• Prevent unauthorized access to starter controls on oil pumps;
. Secure out-of-service and loading/unloading connections of
oil pipelines; and
. Address the appropriateness of security lighting to both
prevent acts of vandalism and assist in the discovery of oil
discharges
Yes
iNo MNA
Yes
INo MNA
For Oil Production Facilities:
Select NA
112.7(k)
If YES
Qualified oil-filled operational equipment is present at the facility | | Yes | |lMo
Oil-filled operational equipment means equipment that includes an oil storage container (or multiple containers) in which the oil is
present solely to support the function of the apparatus or the device. Oil-filled operational equipment is not considered a bulk storage
container, and does not include oil-filled manufacturing equipment (flow-through process). Examples of oil-filled operational
equipment include, but are not limited to, hydraulic systems, lubricating systems ( e.g. , those for pumps, compressors and other
rotating equipment, including pumpjack lubrication systems), gear boxes, machining coolant systems, heat transfer systems,
transformers, circuit breakers, electrical switches, and other systems containing oil solely to enable the operation of the device.
Check which apply:
Secondary Containment provided in accordance with 112.7(c) I I
Alternative measure described below (confirm eligibility) \ |
112.7(k)
Qualified Oil-Filled Operational Equipment
• Has a single reportable discharge as described in §112.1(b) from any oil-filled
operational equipment exceeding 1,000 U.S. gallons occurred within the three years
prior to Plan certification date?
• Have two reportable discharges as described in §112.1(b) from any oil-filled operational
equipment each exceeding 42 U.S. gallons occurred within any 12-month period within
Yes
Yes
INo I NA
JNO MNA
the three years prior to Plan certification date?
10
secondary containment in accordance with §112.7(c) is required
• Facility procedure for inspections or monitoring program to
detect equipment failure and/or a discharge is established and
documented
Does not apply if the facility has submitted a FRP under
§112.20:
• Contingency plan following 40 CFR part 109 (see Attachment
E of this checklist) is provided in Plan AND
• Written commitment of manpower, equipment, and materials
required to expeditiously control and remove any quantity of
oil discharged that may be harmful is provided in Plan
Yes MNo MNA
| Yes |_|No |_|NA
I Yes r~|No HNA
Yes MNO MNA
L
Comments:
Inspector Note- Complete, as applicable, either Attachment A or B which include additional
requirements based on the type of facility.
This provision does not apply to oil-filled manufacturing equipment (flow-through process)
10 Oil discharges that result from natural disasters, acts of war, or terrorism are not included in this determination. The gallon amount(s) specified (either
1,000 or 42) refers to the amount of oil that actually reaches navigable waters or adjoining shorelines not the total amount of oil spilled. The entire
volume of thficdjs^rsftiis^ fRBRiR^RJWALalNBPECTORS G-86
Tier I Qualified Facilities Page 8 of 8 December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT A
ONSHORE FACILITIES (EXCLUDING PRODUCTION) 40 CFR
112.8/112.12
NA
PLAN
FIELD
112.8(b)/ 112.12(b) Facility Drainage
Diked Areas
(1)
Drainage from diked storage areas is:
• Restrained by valves, except where facility systems are
designed to control such discharge, OR
. Manually activated pumps or ejectors are used and the
condition of the accumulation is inspected prior to draining
dike to ensure no oil will be discharged
Yes No MNA
Yes MNo MNA
Comments:
112.8(c)/112.12(c) Bulk Storage Containers |_|NA
Bulk storage container means any container used to store oil. These containers are used for purposes including, but not limited to, the storage of oil
prior to use, while being used, or prior to further distribution in commerce. Oil-filled electrical, operating, or manufacturing equipment is not a bulk
storage container.
If bulk storage containers are not present, mark this section Not Applicable (NA). If present, complete this section and Attachment C of this checklist.
(1)
Containers materials and construction are compatible with
material stored and conditions of storage such as pressure and
temperature
Yes
iNo NA
Yes
No MNA
(3)
If YES
Is there drainage of uncontaminated rainwater from diked areas
into a storm drain or open watercourse?
Yes
No MNA
Yes
INO MNA
Bypass valve normally sealed closed
• Retained rainwater is inspected to ensure that its presence
will not cause a discharge as described in §112.1(b)
. Bypass valve opened and resealed under responsible
supervision
. Adequate records of drainage are kept; for example, records
required under permits issued in accordance with 40 CFR
§§122.41(j)(2)and(m)(3)
| Yes
| Yes
JYes
Yes
jNo
]NO
]NO
]NO
INA
INA
]NA
INA
| Yes
| Yes
]Yes
I Yes
JNo
]NO
]NO
]NO
|NA
]NA
]NA
INA
(4)
For completely buried metallic tanks installed on or after January
10, 1974 (if not exempt from SPCC regulation because subject to
all of the technical requirements of 40 CFR part 280 or 281):
• Provide corrosion protection with coatings or cathodic
protection compatible with local soil conditions
• Regular leak testing conducted
Yes LjNo MNA
Yes LJNo MNA
Yes MNo MNA
I Yes MNo MNA
(5)
The buried section of partially buried or bunkered metallic tanks
protected from corrosion with coatings or cathodic protection
compatible with local soil conditions
Yes MNo MNA
Yes MNo MNA
Comments:
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Tier I Qualified Facilities
PageA-1 of 2
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT A
PLAN
FIELD
(6)
Test or inspect each aboveground container for integrity on a
regular schedule and whenever you make material repairs.
Techniques include, but are not limited to: visual inspection,
hydrostatic testing, radiographic testing, ultrasonic testing,
acoustic emissions testing, or other system of non-
destructive testing
Appropriate qualifications for personnel performing tests and
inspections are identified in the Plan and have been
assessed in accordance with industry standards
. The frequency and type of testing and inspections are
documented, are in accordance with industry standards and
take into account the container size, configuration and design
. Comparison records of aboveground container integrity
testing are maintained
• Container supports and foundations regularly inspected
. Outside of containers frequently inspected for signs of
deterioration, discharges, or accumulation of oil inside diked
areas
. Records of all inspections and tests maintained11
Yes llNo LJNA
Yes IjNo MNA
Yes II No LJNA
I Yes
Yes |_|No |_|NA
Yes C|NO C|NA
Yes NO C|NA
NO NA
I Yes MNo LJNA
I Yes |_|No
DMA
JYes |_|No |_|NA
]Yes C|NO DMA
]Yes DNO C|NA
I Yes HMO riNA
Integrity Testing Standard identified in the Plan:
112.12
(Applies to
AFVO
Facilities only)
Conduct formal visual inspection on a regular schedule for bulk
storage containers that meet all of the following conditions:
• Subject to 21 CFR part 110; • Have no external insulation; and
• Elevated; • Shop-fabricated.
• Constructed of austenitic
stainless steel;
In addition, you must frequently inspect the outside of the container
for signs of deterioration, discharges, or accumulation of oil inside
diked areas.
You must determine and document in the Plan the appropriate
qualifications for personnel performing tests and inspections.11
Yes II No MNA M YesLJNo MNA
Yes MNo MNA
I Yes MNO MNA
Yes MNO MNA
Yes MNO MNA
(10)
Visible discharges which result in a loss of oil from the container,
including but not limited to seams, gaskets, piping, pumps, valves,
rivets, and bolts are promptly corrected and oil in diked areas is
promptly removed
Yes II No MNA
JYes MNo |_|NA
112.8(d)/112.12(d)Facility transfer operations, pumping, and facility process
(4)
Aboveground valves, piping, and appurtenances such as flange
joints, expansion joints, valve glands and bodies, catch pans,
pipeline supports, locking of valves, and metal surfaces are
inspected regularly to assess their general condition
Integrity and leak testing conducted on buried piping at time of
installation, modification, construction, relocation, or replacement
Yes LjNo LJNA
Yes MNo MNA
I Yes MNo MNA
Yes MNO MNA
Comments:
Tier I Qualified Facilities
business practices will suffice
Page A-2 of 2
G-88
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT B
ONSHORE OIL PRODUCTION FACILITIES^40 CFR 112.9
NA
PLAN
FIELD
(Drilling and workover facilities are excluded from the requirements of §112.9)
Production facility means all structures (including but not limited to wells, platforms, or storage facilities), piping (including but not limited to flowlines or
intra-facility gathering lines), or equipment (including but not limited to workover equipment, separation equipment, or auxiliary non-transportation-
related equipment) used in the production, extraction, recovery, lifting, stabilization, separation or treating of oil (including condensate), or associated
storage or measurement, and is located in an oil or gas field, at a facility. This definition governs whether such structures, piping, or equipment are
subject to a specific section of this part.
112.9(b) Oil Production Facility Drainage
(1)
At tank batteries, separation and treating areas where there is a
reasonable possibility of a discharge as described in §1 12.1(b),
drains for dikes or equivalent measures are closed and sealed
except when draining uncontaminated rainwater. Accumulated oil
on the rainwater is removed and then returned to storage or
disposed of in accordance with legally approved methods
Prior to drainage, diked area inspected and action taken as
provided below:
• 1 12.8(c)(3)(ii) - Retained rainwater is inspected to ensure that
its presence will not cause a discharge as described in
1 12.8(c)(3)(iii) - Bypass valve opened and resealed under
responsible supervision
112.8(c)(3)(iv) -Adequate records of drainage are kept; for
example, records required under permits issued in
accordance with §122.41(j)(2) and (m)(3)
Yes
lNo LJNA
| Yes
|No |_|NA
Yes NO MA
I Yes [~|NO HNA
Yes
No |_|NA
| Yes
|No |_|NA
Yes lMo lMA
I Yes HMO HNA
(2)
Field drainage systems (e.g., drainage ditches or road ditches) and
oil traps, sumps, or skimmers inspected at regularly scheduled
intervals for oil, and accumulations of oil promptly removed
Yes
iNo LJNA
Yes
INo LJNA
112.9(c) Oil Production Facility Bulk Storage Containers
Bulk storage container means any container used to store oil. These containers are used for purposes including, but not limited to, the storage of oil
prior to use, while being used, or prior to further distribution in commerce. Oil-filled electrical, operating, or manufacturing equipment is not a bulk
storage container.
(1)
(2)
(3)
(4)
Containers materials and construction are compatible with material
stored and conditions of storage such as pressure and temperature
Except as allowed for flow-through process vessels in §112.9(c)(5)
and produced water containers in §112.9(c)(6), secondary
containment provided for all tank battery, separation and treating
facilities sized to hold the capacity of largest single container and
sufficient freeboard for precipitation.
Drainage from undiked area safely confined in a catchment basin
or holding pond.
Except as allowed for flow-through process vessels in §112.9(c)(5)
and produced water containers in §112.9(c)(6), periodically and
upon a regular schedule, visually inspect containers for
deterioration and maintenance needs, including foundation and
supports of each container on or above the surface of the ground
Yes MNo |_|NA
Yes MNo LJNA
Yes MNo llNA
Yes MNo MNA
lYes |_|No |_|NA
Yes MNo llNA
Yes MNo LJNA
Yes MNo MNA
New and old tank batteries engineered/updated in accordance with
good engineering practices to prevent discharges including at least
one of the following:
• Adequate container capacity to prevent overfill if a
pumper/gauger is delayed in making regularly scheduled
rounds;
Yes
No MNA
Yes
INO MNA
Overflow equalizing lines between containers so that a
full container can overflow to an adjacent container;
Adequate vacuum protection to prevent container collapse; or
High level sensors to generate and transmit an alarm to the
computer where the facility is subject to a computer production
control system
Comments:
Tier I Qualified Facilities
Page B-1 of 4
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT B
PLAN
FIELD
(5)
(iv)
Flow-through Process Vessels. Alternate requirements in lieu of sized secondary containment required in (c)(2) and
requirements in (c)(3) above for facilities with flow-through process vessels:
Flow-through process vessels and associated components (e.g.
dump valves) are periodically and on a regular schedule visually
inspected and/or tested for leaks, corrosion, or other conditions
that could lead to a discharge as described in §112.1(b)
Corrective actions or repairs have been made to flow-through
process vessels and any associated components as indicated by
regularly scheduled visual inspections, tests, or evidence of an oil
discharge
Oil removed or other actions initiated to promptly stabilize and
remediate any accumulation of oil discharges associated with the
produced water container
All flow-through process vessels comply with §§112.9(c)(2) and
(c)(3) within six months of any flow-through process vessel
discharge of more than 1,000 U.S. gallons of oil in a single
discharge as described in §112.1(b) or discharges of more than 42
U.S. gallons of oil in each of two discharges as described in
§112.1(b) within any twelve month period.
12
Yes MNo LjNA
Yes MNo MNA
Yes MNo MNA
Yes MNo MNA
Yes MNo MNA
Yes MNo MNA
Yes MNo |_|NA
Yes MNo MNA
112.9(d) Facility transfer operations, pumping, and facility process
(1)
(3)
All aboveground valves and piping associated with transfer
operations are inspected periodically and upon a regular schedule
to determine their general condition. Include the general condition
of flange joints, valve glands and bodies, drip pans, pipe supports,
pumping well polish rod stuffing boxes, bleeder and gauge valves,
and other such items
If flowlines and intra-facility gathering lines are not provided with
secondary containment in accordance with §112.7(c) and the
facility is not required to submit an FRP under §112.20, then the
SPCC Plan includes:
• An oil spill contingency plan following the provisions of 40 CFR
part10913
• A written commitment of manpower, equipment, and materials
required to expeditiously control and remove any quantity of oil
discharged that might be harmful
Yes MNo MNA MYes MNo MNA
| Yes |_|No LJNA
I Yes HNO |~~|NA
I Yes |_|No |_|NA
I Yes |~~|NO HNA
Comments:
Oil discharges that result from natural disasters, acts of war, or terrorism are not included in this determination. The gallon amount(s) specified (either
1 ,000 or 42) refers to the amount of oil that actually reaches navigable waters or adjoining shorelines not the total amount of oil spilled. The entire
volume of the discharge is oil for this determination.
13 Note tha^^^nj^r^iqitg^pig^ap^^^^ijy^g^aifo^gs not require a PE impracticability determination for this specific requiremen^.gg
Tier I Qualified Facilities PageB-2of4
December 2012 (12-10-12)
-------
Appendix G: SPCC Inspection Checklists
ATTACHMENT B
PLAN
FIELD
(4)
(iv)
Aflowline/intra-facility gathering line maintenance program to
prevent discharges is prepared and implemented and includes the
following procedures:
Flow/lines and intra-facility gathering lines and associated valves
and equipment are compatible with the type of production fluids,
their potential corrosivity, volume, and pressure, and other
conditions expected in the operational environment
Flowlines and intra-facility gathering lines and associated
appurtenances are visually inspected and/or tested on a periodic
and regular schedule for leaks, oil discharges, corrosion, or other
conditions that could lead to a discharge as described in §112.1(b).
If flowlines and intra-facility gathering lines are not provided with
secondary containment in accordance with §112.7(c), the
frequency and type of testing allows for the implementation of a
contingency plan as described under 40 CFR 109 or an FRP
submitted under §112.20
Repairs or other corrective actions are made to any flowlines and
intra-facility gathering lines and associated appurtenances as
indicated by regularly scheduled visual inspections, tests, or
evidence of a discharge
Oil removed or other actions initiated to promptly stabilize and
remediate any accumulation of oil discharges associated with the
produced water containers
Yes LjNo MNA
Yes MNo MNA
Yes MNo MNA
Yes MNo MNA
Yes MNo LJNA
Yes MNo MNA
Yes MNo MNA
Yes II No MNA
Yes MNo MNA
Yes MNo MNA
ATTACHMENTS |_|NA
ONSHORE OIL DRILLING AND WORKOVER FACILITIES—40 CFR
112.10
PLAN
FIELD
Mobile drilling or workover equipment is positioned or located to
prevent a discharge as described in §112.1(b)
I Yes |_|No UNA
Yes |_|No MNA
Catchment basins or diversion structures are provided to intercept
and contain discharges of fuel, crude oil, or oily drilling fluids
Yes MNo MNA
Yes MNo MNA
Blowout prevention (BOP) assembly and well control system
installed before drilling below any casing string or during workover
operations
BOP assembly and well control system is capable of controlling
any well-head pressure that may be encountered while on the well
Yes MNo MNA
Yes MNo MNA
Yes MNo MNA
Yes MNo MNA
Comments:
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Tier I Qualified Facilities
Page 6-3 of 4
G-91
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Appendix G: SPCC Inspection Checklists
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SPCC GUIDANCE FOR REGIONAL INSPECTORS G-92
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Appendix G: SPCC Inspection Checklists
ATTACHMENT C: SPCC FIELD INSPECTION AND PLAN REVIEW TABLE
Documentation of Field Observations for Containers and Associated Requirements
Inspectors should use this table to document observations of containers as needed.
Containers and Piping
Check containers for leaks, specifically looking for: drip marks, discoloration of tanks, puddles containing spilled or leaked material,
corrosion, cracks, and localized dead vegetation, and standards/specifications of construction.
Check aboveground container foundation for: cracks, discoloration, and puddles containing spilled or leaked material, settling, gaps
between container and foundation, and damage caused by vegetation roots.
Check all piping for: droplets of stored material, discoloration, corrosion, bowing of pipe between supports, evidence of stored
material seepage from valves or seals, evidence of leaks, and localized dead vegetation. For all aboveground piping, include the
general condition of flange joints, valve glands and bodies, drip pans, pipe supports, bleeder and gauge valves, and other such items
(Document in comments section of §112.8(d) or 112.12(d).)
Secondary Containment (Active and Passive)
Check secondary containment for: containment system (including walls and floor) ability to contain oil such that oil will not escape
the containment system before cleanup occurs, proper sizing, cracks, discoloration, presence of spilled or leaked material (standing
liquid), erosion, corrosion, penetrations in the containment system, and valve conditions.
Check dike or berm systems for: level of precipitation in dike/available capacity, operational status of drainage valves (closed), dike
or berm impermeability, debris, erosion, impermeability of the earthen floor/walls of diked area, and location/status of pipes, inlets,
drainage around and beneath containers, presence of oil discharges within diked areas.
Check drainage systems for: an accumulation of oil that may have resulted from any small discharge, including field drainage
systems (such as drainage ditches or road ditches), and oil traps, sumps, or skimmers. Ensure any accumulations of oil have been
promptly removed.
Check retention and drainage ponds for: erosion, available capacity, presence of spilled or leaked material, debris, and stressed
vegetation.
Check active measures (countermeasures) for: amount indicated in plan is available and appropriate; deployment procedures are
realistic; material is located so that they are readily available; efficacy of discharge detection; availability of personnel and training,
appropriateness of measures to prevent a discharge as described in §112.1 (b). Note that appropriate evaluation and consideration
must be given to the any use of active measures at an unmanned production facility.
Container ID/ General
Condition14
Aboveground or Buried Tank
Storage Capacity and Type
of Oil
Type of Containment
Drainage Control
Overfill Protection and
Testing & Inspections
14 Identify
Tier I Qualified Facilities
B for completely buried
Page C-1 of 2
G-93
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT C: SPCC FIELD INSPECTION AND PLAN REVIEW TABLE (CONT.)
Documentation of Field Observations for Containers and Associated Requirements
Container ID/ General
Condition15
Aboveground or Buried Tank
Storage Capacity and Type
of Oil
Type of Containment/
Drainage Control
Overfill Protection and
Testing & Inspections
15 Identify
Tier I Qualified Facilities
B for completely buried
Page C-2 of 2
G-94
December 2012 (12-10-12)
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Apppnrliy Pi- SPf.r. Ingppntinn
ATTACHMENT D: SPCC INSPECTION AND TESTING CHECKLIST
Required Documentation of Tests and Inspections
Records of inspections and tests required by 40 CFR part 112 signed by the appropriate supervisor or inspector must be kept by all
facilities with the SPCC Plan for a period of three years. Records of inspections and tests conducted under usual and customary
business practices will suffice. Documentation of the following inspections and tests should be kept with the SPCC Plan.
Inspection or Test
Documentation
Present
Not
Present
Not
Applicable
112.6— Tier I Qualified Facilities
(a)(3)(iii)
Regular testing of system or documented procedures used instead of liquid level sensing
devices specified in §§1 12.8(c)(8) and 1 12.12(c)(8) to prevent container overfills
D
n
n
112.7-General SPCC Requirements
k(2)(i)
Inspection or monitoring of qualified oil-filled operational equipment when the equipment
meets the qualification criteria in §1 12.7(k)(1) and facility owner/operator chooses to
implement the alternative requirements in §112.7(k)(2) that include an inspection or
monitoring program to detect oil-filled operational equipment failure and discharges
n
n
n
112.8/112.12-Onshore Facilities (excluding oil production facilities) I JNA
(b)(1),
(b)(2)
(c)(3)
(c)(4)
(c)(6)
(c)(6),
(c)(10)
(c)(6)
(d)(4)
(d)(4)
Inspection of storm water released from diked areas into facility drainage directly to a
watercourse
Inspection of rainwater released directly from diked containment areas to a storm drain
or open watercourse before release, open and release bypass valve under supervision,
and records of drainage events
Regular leak testing of completely buried metallic storage tanks installed on or after
January 10, 1974 and regulated under 40 CFR 112
Regular integrity testing of aboveground containers and integrity testing after material
repairs, including comparison records
Regular visual inspections of the outsides of aboveground containers, supports and
foundations
Frequent inspections of diked areas for accumulations of oil
Regular inspections of aboveground valves, piping and appurtenances and assessments
of the general condition of flange joints, expansion joints, valve glands and bodies, catch
pans, pipeline supports, locking of valves, and metal surfaces
Integrity and leak testing of buried piping at time of installation, modification,
construction, relocation or replacement
n
D
D
D
D
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
112.9-Onshore Oil Production Facilities (excluding drilling and workover facilities) I JNA
(b)(1)
(b)(2)
(c)(3)
(c)(5)(i)
(d)(1)
(d)(4)(ii)
Rainwater released directly from diked containment areas inspected following
§§112.8(c)(3)(ii), (iii) and (iv), including records of drainage kept
Field drainage systems, oil traps, sumps, and skimmers inspected regularly for oil, and
accumulations of oil promptly removed
Containers, foundations and supports inspected visually for deterioration and
maintenance needs
In lieu of having sized secondary containment, flow-through process vessels and
associated components visually inspected and/or tested periodically and on a regular
schedule for conditions that could result in a discharge as described in §112.1(b)
All aboveground valves and piping associated with transfers are regularly inspected
For flowlines and intra-facility gathering lines without secondary containment, in
accordance with §112.7(c), lines are visually inspected and/or tested periodically and on
a regular schedule to allow implementing the part 1 09 contingency plan or the FRP
submitted under §112. 20
n
n
n
n
n
n
n
n
n
n
n
D
n
n
n
n
n
D
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Tier I Qualified Facilities
Page D-1 of 2
G-95
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SPCC GUIDANCE FOR REGIONAL INSPECTORS G-96
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Appendix G: SPCC Inspection Checklists
ATTACHMENT E: SPCC CONTINGENCY PLAN REVIEW CHECKLIST
40 CFR Part 109-Criteria for State, Local and Regional Oil Removal Contingency Plans
NA
If SPCC Plan includes an impracticability determination for secondary containment in accordance with §112.7(d), the facility
owner/operator is required to provide an oil spill contingency plan following 40 CFR part 109, unless he or she has submitted a FRP
under §112.20. An oil spill contingency plan may also be developed, unless the facility owner/operator has submitted a FRP under
§112.20 as one of the required alternatives to general secondary containment for qualified oil filled operational equipment in
accordance with §112.7(k).
109.5-Development and implementation criteria for State, local and regional oil removal contingency plans16
(a)
(b)
(1)
(2)
(3)
(4)
(c)
(1)
(2)
(3)
(d)
(1)
(2)
(3)
(4)
(5)
(e)
Definition of the authorities, responsibilities and duties of all persons, organizations or agencies which are to
be involved in planning or directing oil removal operations.
Establishment of notification procedures for the purpose of early detection and timely notification of an oil
discharge including:
The identification of critical water use areas to facilitate the reporting of and response to oil discharges.
A current list of names, telephone numbers and addresses of the responsible persons (with alternates) and
organizations to be notified when an oil discharge is discovered.
Provisions for access to a reliable communications system for timely notification of an oil discharge, and the
capability of interconnection with the communications systems established under related oil removal
contingency plans, particularly State and National plans (e.g., National Contingency Plan (NCR)).
An established, prearranged procedure for requesting assistance during a major disaster or when the
situation exceeds the response capability of the State, local or regional authority.
Provisions to assure that full resource capability is known and can be committed during an oil discharge
situation including:
The identification and inventory of applicable equipment, materials and supplies which are available locally
and regionally.
An estimate of the equipment, materials and supplies that would be required to remove the maximum oil
discharge to be anticipated.
Development of agreements and arrangements in advance of an oil discharge for the acquisition of
equipment, materials and supplies to be used in responding to such a discharge.
Provisions for well-defined and specific actions to be taken after discovery and notification of an oil discharge
including:
Specification of an oil discharge response operating team consisting of trained, prepared and available
operating personnel.
Pre-designation of a properly qualified oil discharge response coordinator who is charged with the
responsibility and delegated commensurate authority for directing and coordinating response operations and
who knows how to request assistance from Federal authorities operating under existing national and regional
contingency plans.
A preplanned location for an oil discharge response operations center and a reliable communications system
for directing the coordinated overall response operations.
Provisions for varying degrees of response effort depending on the severity of the oil discharge.
Specification of the order of priority in which the various water uses are to be protected where more than one
water use may be adversely affected as a result of an oil discharge and where response operations may not
be adequate to protect all uses.
Specific and well defined procedures to facilitate recovery of damages and enforcement measures as
provided for by State and local statutes and ordinances.
Yes
n
D
D
D
°
D
D
D
D
D
n
D
1=1
D
D
°
D
No
n
D
D
D
°
D
D
D
D
D
n
D
1=1
D
n
n
D
16 The c
Tier I Qualified Facilities
state and local plans, Area Contingency Plans, and the NCR.
Page E-1 of 2
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Appendix G: SPCC Inspection Checklists
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SPCC GUIDANCE FOR REGIONAL INSPECTORS G-98
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Appendix G: SPCC Inspection Checklists
ATTACHMENT F: ADDITIONAL COMMENTS
SPCC GUIDANCE FOR REGIONAL INSPECTORS G-99
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Appendix G: SPCC Inspection Checklists
ATTACHMENT F: ADDITIONAL COMMENTS (CONT.)
SPCC GUIDANCE FOR REGIONAL INSPECTORS G-100
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Appendix G: SPCC Inspection Checklists
ATTACHMENT G: PHOTO DOCUMENTATION NOTES
Photo*
Photographer
Name
Time of
Photo Taken
Compass
Direction
Description
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Tier I Qualified Facilities
Page G-1of2
G-101
December 2012 (12-10-12)
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Appendix G: SPCC Inspection Checklists
ATTACHMENT G: PHOTO DOCUMENTATION NOTES (CONT.)
Photo*
Photographer
Name
Time of
Photo Taken
Compass
Direction
Description
SPCC GUIDANCE FOR REGIONAL INSPECTORS
Tier I Qualified Facilities
Page G-2of2
G-102
December 2012 (12-10-12)
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Appendix H: Other Policy Documents
Memorandum, Use of Alternative Secondary Containment Measures at Facilities Regulated
under the Oil Pollution Prevention Regulation (40 CFR Part 112), OSWER 9360.8-37, Don R. Clay,
OSWER Assistant Administrator, April 29, 1992.
EPA Liner Study: Report to Congress, Section 4113(a) of the Oil Pollution Act of 1990. May 1996.
David Lopez, Letter to Mr. Chris Early of Safety-Kleen Corporation, July 14, 2000.
Stephen F. Heare, Letter to Melissa Young of Petroleum Marketers Association of America,
2001.
Memorandum, Use of Alternative Secondary Containment Measures at Facilities Regulated
under the Oil Pollution Prevention Regulation (40 CFR Part 112), OSWER 9360.8-38, Marianne
Lament Horinko, OSWER Assistant Administrator, August 9, 2002.
Advance Notice of Proposed Rulemaking on the Clean Water Act Regulatory Definition of
"Waters of the United States", 68 FR 1991, January 15, 2003.
Marianne Horinko, Letter to Daniel Gilligan of Petroleum Marketers Association of America, May
25, 2004.
Susan Parker Bodine, Letter to Brian Jennings of American Coalition for Ethanol, November 7,
2006.
R. Craig Matthiessen, Letter to Roger Claff, December 10, 2010.
EPA Jurisdiction at Complexes, August 2013.
FRP Rule Attachment C-l: Flowchart of Criteria for Substantial Harm, 40 CFR Ch. I, Pt. 112, App.
C.
FRP Rule Attachment C-ll: Calculation of the Planning Distance, 40 CFR Ch. I, Pt. 112, App. C.
Example: Spill Prevention Control and Countermeasure (SPCC) Plan - Construct New Secondary
Containment, July 2011
Example: Spill Prevention Control and Countermeasure (SPCC) Plan - Multiple Horizontal
Cylindrical Tanks Inside a Rectangular or Square Dike or Berm, July 2011
SPCC GUIDANCE FOR REGIONAL INSPECTORS
November 15, 2013
-------
Appendix H
Example: Spill Prevention Control and Countermeasure (SPCC) Plan - Rectangular or Square
Remote Impoundment Structure, July 2011
Example: Spill Prevention Control and Countermeasure (SPCC) Plan - Single Vertical Cylindrical
Tank Inside a Rectangular or Square Dike or Berm, July 2011
Worksheet: Spill Prevention Control and Countermeasure (SPCC) Plan - Construct New
Secondary Containment, July 2011
Worksheet: Spill Prevention Control and Countermeasure (SPCC) Plan - Multiple Horizontal
Cylindrical Tanks Inside a Rectangular or Square Dike or Berm, July 2011
Worksheet: Spill Prevention Control and Countermeasure (SPCC) Plan - Rectangular or Square
Remote Impoundment Structure, July 2011
Worksheet: Spill Prevention Control and Countermeasure (SPCC) Plan - Single Vertical Cylindrical
Tank Inside a Rectangular or Square Dike or Berm, July 2011
SPCC GUIDANCE FOR REGIONAL INSPECTORS
H-2
-------
"Appendix H: Other Policy Documents
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
APR 29 :=32
Q<
SOLID WASTE AND EMERGENCY RESPONSE
KBMORAMDDK
SUBJECT: Use of Alternative Secondary Containment Measures at
Facilities Regulated under the Oil Pollution Prevention
Regulation (4JL CFR Part 113)
FROM: Don R. cis
Assistant Administr
TOi Director, Environmental Services Division.
Regions I, VI, VII
Director, Emergency and Remedial Response Division
Region II
Director, Hazardous Haste Management Division
Regions III, IX
Director, Haste Management Division
Regions IV, V, VIII
Director, Hazardous Haste Division
Region.X
PtmPOflB
This memorandum addresses the U.S. Environmental Protection
Agency's (EPA) interpretation of the term "secondary containment"
as it is used in section 112.7(c) of the Oil Pollution Prevention
regulation (40 CFR Part 112), also known as the Spill Prevention,
Control and Countermeasures (SPCC) regulation. It also addresses
technologies that may be used to provide secondary containment
for smaller, shop-fabricated aboveground storage tanks (ASTs)
consistent with 40 CFR Part 112.7(c).
BACKGROOMP
Since 1973, the SPCC regulation has included the following
provision addressing secondary containment and the allowance for
equivalent preventive systems. Section 112.7(c) states:
Appropriate containment and/or diversionary structures or
equipment to prevent discharged oil from reaching a
navigable water course should be provided. One of the
following .preventive systems or its equivalent should be
SPCC GUIDANCE FOR REGIONAL INSPECTORS H-3
-------
Appendix H: Other Policy Documents
- 2 -
used as a minimum: (1) Onshore facilities: (i) Dikes,
berms or retaining walls sufficiently impervious to contain
spilled oil; (ii) Curbing; (iii) Culverting, gutters or
other drainage systems; (iv) weirs, booms or other barriers;
(v) Spill diversion ponds; (vi) Retention ponds; (vii)
Sorbent materials.
The SPCC regulation implements section 311{j)(1)(C) of the
Clean Water Act (CWA) for non-transportation-related facilities.
In 1988, the Agency published regulations at 40 CFR Part 280 for
underground storage tanks (uSTs) implementing the requirements of
Subtitle I of the Resource Conservation and Recovery Act. An
apparent result of the implementation of the UST
regulation is a trend of facilities replacing USTs with ASTs.
In response to this trend, tank manufacturers have developed
various new designs for shop-fabricated AST systems. Alternative
AST systems for which we have information generally do not exceed
12,000 gallons capacity. Some of these new designs include a
steel or reinforced concrete secondary shell fully encasing a
storage tank; others include an attached, shop-fabricated
containment dike. Many other system designs may also be
available. Typically, these alternative AST system designs
provide containment for the entire capacity of the inner tank for
spills resulting from leaks or ruptures of the inner tank.
In 1988, EPA noted in its oil SPCC Program Task Force Report
that the Agency has limited inspection resources to implement the
SPCC program. Less than 1,'OQO of the estimated half million
SPCC-regulated facilities.are inspected by EPA annually.
Moreover, section 311 of the CWA does not permit EPA to delegate
this program to the states. The Task Force, therefore,
recommended that EPA attempt to target these very limited
resources to inspecting the highest-risk facilities. In general,
we believe that facilities using smaller-volume AST systems
generally pose less risk than larger field-erected tanks and tank
farms of large uncontrolled spills reaching navigable waters,
especially if these facilities are not located near sensitive
ecosystems or water supply intakes.
The traditional method of providing secondary containment
for ASTs has been to construct dikes, bcrms, retaining walls
and/or diversion ponds to collect oil once it spills. Based on
the experience of EPA Regional personnel implementing the SPCC
regulation since 1973, those traditional means of secondary
containment are very effective and reliable methods of protecting
the surface waters from oil spills from ASTs. However, the SPCC
regulation is a performance-based regulation that permits
facility owners or operators to substitute alternative forms of
spill containment if they provide protection against discharges
to navigable waters substantially equivalent to that provided by
the systems listed in section 112.7(c).
SPCC GUIDANCE FOR REGIONAL INSPECTORS H-4
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Appendix H: Other Policy Documents
Consistent with section 112.l(e) of the SPCC regulation,
this memorandum does not supersede the authority of "existing
lavs, regulations, rules, standards, policies and procedures
pertaining to safety standards, fire prevention and pollution
rules," including fire codes or other standards for good
engineering practice that may apply to alternative AST systems*
On October 22, 1991, EPA proposed revisions to the SPCC
regulation. The proposed revisions do not affect the provisions
of section 112.7 (c) that describe alternative systems that are
substantially equivalent to those specifically listed in
paragraphs (c)(1)(i) through (c)(1)(vii).
QBJBCTIVB
This memorandum should allow EPA Regional personnel to
provide consistent interpretation of the secondary containment
provisions of section 112.7(c) of the SPCC regulation to
facilities with generally smaller shop-fabricated ASTs.
Alternative AST systems, including equipment and procedures to
prevent reasonably expected discharges, should satisfy the
secondary containment provisions of the SPCC regulation under
most.site-specific conditions.
PIBCDflfllON
As smaller shop-fabricated ASTs are increasingly appearing
in the market, we have observed a number of innovative
technologies to reduce the risks of both leaks and spills.
Moreover, these smaller shop-fabricated tanks do not pose the
same risk of large uncontrolled oil spills to navigable waters as
the larger field-erected tanks. Therefore, we believe that there
should be many situations in which protection of navigable waters
substantially equivalent to that provided by the secondary
containment systems listed in section 112.7(c) could be provided
by alternative AST systems that have capacities generally less
than 12,000 gallons and are installed and operated with
protective measures other than secondary containment dikes. For
example, some state programs provide an exemption from State
spill prevention requirements for ASTs with similar capacities.
However, in certain situations, these alternative AST systems
might appropriately not be presumed to comply with the provisions
of section 112.7(c). An example of this type of situation is
facilities containing four or more ASTs or ASTs with combined
capacity greater than 40,000 gallons, where a number of larger
tanks are connected by manifolds or other piping arrangements
SPCC GUIDANCE FOR REGIONAL INSPECTORS H-5
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Appendix H: Other Policy Documents
- 4 -
that would permit a volume of oil greater than the capacity of
one tank to be spilled as a result of a single system failure.1
The owner or operator of any facility subject to the SPCC
regulation, including facilities using alternative AST systems,
must adhere to all applicable provisions of the SPCC regulation.
The owner or operator of each regulated facility must develop a
site-specific SPCC Plan that must be certified by a Registered
Professional Engineer as required by section 112.3 of the
regulation. Pursuant to the requirement of section 112.7 that
the SPCC Plan shall "include a discussion of the facility's
conformance with the appropriate guidelines listed," a complete
SPCC Plan for any facility using alternative AST systems should
include a discussion of why the facility is considered to be in
conformance with section 112.7(c).
in evaluating these shop-fabricated AST systems, EPA's
Office of Solid Waste and Emergency Response (OSWER) has looked
at requirements the Agency has established for tanks .in
situations where traditional secondary containment systems cannot
be provided (e.g., USTs covered by 40 CFR Part 280).
Additionally, OSWER has evaluated relevant state and local
government requirements. OSWER also has considered factors
related to alternative AST systems, including tank size, typical
pumping rates used to fill and empty them, and the lower risk of
large, uncontrolled oil spills from facilities using such AST
systems, based on tank size, design, and pumping rates. We
believe that for these smaller shop-fabricated ASTs some
alternative AST systems that include adequate technical spill and
leak prevention options such as overfill alarms, flow shutoff or
restrictor devices, and constant monitoring of product transfers
generally would allow owners and operators of facilities to
provide protection of navigable waters substantially equivalent
to that provided by secondary containment as defined in 40 CFR
Part 112.7(c). For example, small double walled ASTs, when used
with equipment and procedures described in this guidance,
generally would provide substantially equivalent protection of
navigable waters under section 112.7(c) of the SPCC regulation
when the inner "tank is an Underwriters' Laboratory-listed steel
tank, the outer wall is constructed in accordance with nationally
accepted industry standards (e.g., those codified by the American
Petroleum institute, the Steel Tank Institute, and American
Concrete Institute), the tank has overfill prevention measures
that include an overfill alarm and an automatic flow restrictor.
1 This £9 based on similar capacities in proposed National Fire
Protection Association standards and consideration of the risks to public
health or welfare or the environment of spills of potentially larger size.
SPCC GUIDANCE FOR REGIONAL INSPECTORS H-6
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Appendix H: Other Policy Documents
- 5 -
or flow shut-off,2 and all product transfers are constantly
monitored.9
When the only significant source of potential oil spills to
navigable waters of the United States from a facility is from
alternative ASTs as described in this memorandum, an SPCC Plan
that is certified by a Registered Professional Engineer and that
requires equipment and operating practices in accordance with
good engineering practice and the principle of substantial
equivalence as described above should be presumed to achieve the
protection of navigable waters substantially equivalent to that
provided by the preventive systems specified in 40 CFR Part
112. 7(c).
cc: Bowdoin Train
Henry Longest
Bruce Diamond
Deborah Dietrich
Walter Kovalick
James Makris
Charles Openchowski
David Ziegele
Wendy Butler
Removal Managers, Regions I-X
2 Consistent with the performance standards for these devices as
described In section 280.20(c) of EPA regulations for USTs at 40 CFR Part
280 and in an August 5, 1991, amendment, an automatic flow shut-off will
shut off flow so that none of the fittings located on top of the tank are
exposed to product as a result of overfilling, an automatic flow restrictor
will restrict flow 30 minutes prior to overfill or when the tank is no more
than 90 percent full, and a high level alarm will alert the operator one
minute before overfilling or when the tank is no more than 90 percent full.
3 Consistent with the performance standard for overfill control as
described in section 280.30(a) of EPA regulations for USTs at 40 CFR Part
280. an owner/operator of the facility will ensure .that the transfer
operation is monitored constantly to prevent overfilling and spilling.
TOTflL P.06
SPCC GUIDANCE FOR REGIONAL INSPECTORS H-7
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Appendix H: Other Policy Documents
OSWER 9380.0-24
EPA 540/R95/041
PB95-963538
United States Environmental Protection Agency
EPA LINER STUDY
Report to Congress
Section 4113(a) of the Oil Pollution Act of 1990
May 1996
SPCC GUIDANCE FOR REGIONAL INSPECTORS .' • . H-8
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Appendix H: Other Policy Documents
TABLE OF CONTENTS
• '• •'' ''• ' • " .-.' ' '"• :: • •, - ' Page
ACRONYMS'. ..:.....,.'—.,-. .-........>.%. v.. .............;.,.. y
* - . >, -
EXECUTIVE SUMMARY '.".'............ . .......... vii
PURPOSE ... ...... ........ '. vii
SCOPE OF THE STUDY , .. .. , .. ,... vii
SUMMARY OF FINDINGS ........'.......... . . .-...-,..- , .•.:I. yiii
Universe of Facilities ...-.; viii
Evidence of Spills ...........;........ ix
.Technical Feasibility . x
RECOMMENDATIONS ..:'.,........,. ........ , ................ xii
i. INTRODUCTION ...... ...,.... .. .........'. .... ...... 1
• 1.1 PURPOSE ......... "... ;..•.;..•..-_..,_.'.:..:...;.. 1
1.2 BACKGROUND ..;.V..,^,.,.....,..,.,.,..-.....; ... 1
. 1.3 STUDY APPROACH ...........;...,.................;... 2
1,4 ORGANIZATION OF REPORT ...... f.......... .. 3
2. BACKGROUND ON ASTs '..;........... .... 5
2.1 PROFILE OF AST FACILITIES AND ASTs , 5
2.1.1 Proffle of AST Facilities . 5
2.1.2 .Profile of .ASTs .',............,.-.....................; 9
- ' "• ,,.'*"'"• . " " "^
2.2 OIL DISCHARGES FROM ASTs . .. . 11
2.3 STATUS OF ASTs NATIONWIDE ... . ..... 15
2.3.1 Federal Reportipg Requirements ....... 17
',. 2.3.2 Discharges from ASTs .. ~....'...- V...-:. .......... . ..... 18
2.3.3 Age Profile of ASTs . .. .-'.-• . ..,..'.'. ..,... ,. .. . 19
SPCC GUIDANCE FOR REGIONAL INSPECTORS ' ' • -- . H-9
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Appendix H: Other Policy Documents,
«•
TABLE OF CONTENTS (Continued)
3. EXISTING REGULATIONS AND INDUSTRY PRACTICES FOR LINER
SYSTEMS '., .. . ......'. ......... . . 25
/ ' I - '- ' .
3.1 REVIEW OF FEDERAL AND STATE AST REGULATIONS ...... 25
3.1.1 Federal Regulations . . . .;. .... ... .1 ....:...... . 25
3.1.2 State Regulations ..........'.:.. 26
3.2 / INDUSTRY PRACTICES AND STANDARDS ................ 33
3.3 ESTIMATE OF THE NUMBER OF FACILITIES ALREADY
USING LINERS OR RELATED SYSTEMS ..34
4. TECHNICAL FEASIBILITY AND UNIT COST OF LINERS AND
RELATED SYSTEMS ......,...........:.......,..,.- ,. 37
4.1 OVERVIEW. .............:.;..:..........,........ 37
4,2 DESCRIPTiON OF MODEL FACILITIES . . . . . ,. . . . . . . .... . . . 37
4.3 LINER SYSTEM DESIGNS AND PRACTICES ............. ... 48
4.3.1 Liner Materials Currently in Use .'....... ...... . . . ... ... 50
,. 4.3.2 dostofLiners ........,.....;. ....,,.......-..;. 50
4.3.3 Liner Use Practices , > — ..-,.......................... 50
4.3.4 Liner Effectiveness .,.... .,. . .,. .. . .... ............. 51
4.3.5 iLiner Designs Used in this Study . . .... . ;,.'. ...... 52
4.4 LINER FEASIBILITY EVALUATION ....... . . ... ....... 59
4.4.1- Protection of the Environment and Construction Ease 61
4.4.2 Estimated Facility Costs . ....... ... . . . ., 62
4.5 LEAK DETECTION METHODS . . .. . . . : 67
5. RECOMMENDATIONS ...... .'.'. . ...... .... . . . . 69
REFERENCES . ............. .-/; . . ; . . . ., i V. ................ . . . . 73
APPENDIX A: STATE REGULATIONS ................. :..... 75
APPENDIX B: MODEL FACILITIES ..._..........: , ..... 79
- / ^ • • ••.-•. ^ .. -.11' '/ •:,.'. , ' • • • _
Spec GUIDANCE FOR REGIONAL INSPECTORS , \^.. ' , H-10
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Appendix H: Other Policy Documents
LIST OF EXHIBITS
Title
Exhibit 2-1:
Exhibit 2-2:
- Exhibit 2-3:
Exhibit 2-4:
Exhibit 2-5:
Exhibit 2-6:
Exhibit 2-7:
Exhibit 3-1:
Exhibit 3-2:
Exhibit 4-1:
Exhibit 4-2::
Exhibit 4-3:
Exhibit 4-4:
Exhibit 4-5:
Exhibit 4-6:
Exhibit 4-7:
Exhibit 4-8:
Page
Estimated Number of Facilities Meeting the
SPCC Storage Capacity Thresholds ......
Distribution of ASTs by Age Category '. 12
Distribution of ASTs by Storage Capacity Tier 13
Distribution of ASTs by Storage Capacity by Data Source .... 14
' ' > ' ( ' , - •'• ' '' - '•
Case Studies . 15
'* -,'.,,-. ^_
Percentage of ASTs by Age Category .....,,........;... 20
Percent Corrosion Failure in Each Age Group.......'..,;...... 22
Summary of State Regulatory Review for the Nine States .... 27
Estimated Number of Facilities Not Currently
Required to Install Liners ..... . . , ....., . .......... . . . 35
Model Facility 1: Small End User - Supply . 39
Model Facility 2: Small End User - Storage/Motor Fuel ..... 40
Model Facility 3: Small Bulk Storage - Distribution . ^... . . .. 41
Model Facility 4: Medium Bulk Storage - Distribution 42
Model Facility 5: Large Bulk Storage - Distribution 43
Model Facility 6: Large Oil Terminal - Distribution ........ 44
Summary of Characteristics of Model Facilities . 45
Categorization of Facilities Not Currently Required
to Install Liners ...... . ..../..;........ ...... 47
m
.INSPECTORS.. „_
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Appendix H: Other Policy Documents
IJST OF EXHIBITS (Continued)
Title
Exhibit 4-9:
Exhibit 4-10:
Exhibit 4-11:
Exhibit 4-12:
Exhibit 4-13:
Exhibit 4-14:
•*-.,
Exhibit 4-15:
Exhibit 4-16:
Exhibit 4-17:
Exhibit 4-18:
Exhibit A-l:
Exhibit B-l:
Exhibit B-2:
page
General Schematic: Aboveground Storage Facility . . . . ..... 53
Details: Containment Dike and Liner ...... ..... . . . ..... 54
Details: Liner at Base of Vertical Tank .... . ........ . . . . , 55
Details: Foundation Penetration ................. ...... 56
Details: Access Road .....'....., ______ . . . . _______ ...... 57
Details: Undertank Containment System . ..... . ... . . : , .... 58
' ' '
Comparative Analysis of Liners for Environmental
Protection and Construction Ease ....... .
60
Comparative Cost Analysis of Liner Materials by
Model Facility '.._.. . ______ ..'.;...:':.. s ..'......:." ____ .... 63
Annual Operation and Maintenance Costs . . . ...... . . ...... 64
Bstimated Liner Capital ^^ Cost Per Gallon of
Storage Capacity .. ;:'..-. ....................... ;'-. ..'..,. 66
State Regulations . . . . . ............. .....:....;... , . . . 76
Typical Storage Capacities for Facilities from
Previous EPA Analysis \. .... . . . . .....:.,.............. 79
Categorization of Facflities Not Currently
Required to Install Liners , ... ..... . .
80
IV
SPCC GUIDANCE FOR REGIONAL INSPECTORS
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Appendix H: Other Policy Documents
ACRONYMS
API American Petroleum Institute
AST Aboveground Storage Tank
CERCLA Comprehensive Environmental Response, Compensation,
and Liability Act
CFR Code of Federal Regulations
CWA Clean Water Act ,,
DQT Department of Transportation
EPA '. ' Environmental Protection Agency
ERNS Emergency Response Notification System
GCS Ground Water Characterization Study
HOPE '•)'. High Density Polyethylene
•HMTA Hazardous Materials Transportation Act
HWST Federal Hazardous Waste Storage Tank
MMS Minerals Management Service
NFPA . National Fire Protection Association's Flammable and
Combustible Liquids.Code
NRC National Response Center
ODCP Oil Discharge Contingency Plan
OP A Oil Pollution Act '
OSC On-Scene Coordinator
PVC Polyvinyl chloride
RCRA Resource Conservation and Recovery Act
SPCC 'Spill Prevention, Control, and Countermeasures
SIC Standard Industrial Classification •
UST Underground Storage Tank
VADEQ Virginia Department of Environmental Quality
_SPbC.GyjDANCE FOR REGIONAL,JNSPECTOBS,
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Appendix H: Other Policy Documents
EXECUTIVE SUMMARY
PURPOSE
Section 4113(a) of the Oil Pollution Act of 1990 (OPA) requires that: "The
President shall conduct a study to determine whether liners or other secondary means of
containment should be used to prevent leaking or to aid in leak detection at onshore
facilities used for the bulk storage of oil and located near navigable waters." In . >
Executive Order 12777, the President delegated authority to the U.S. Environmental
Protection Agency (EPA) to conduct this study.
EPA investigated the nature and magnitude of leaking oil at onshore facilities with
aboveground storage tanks (ASTs)-that are used for the bulk storage of oil and that are
located near navigable waters. The Agency also assessed the technical feasibility of using
liners and related systems to detect leaking oil and to prevent leaking oil from
contaminating soil and, by way of ground-water pathways, navigable waters. This report
to Congress, which presents the findings and recommendations of EPA's study, fulfills the*
'requirements of Section 4113(a) of the OP A.
-SCOPE OF THE STUDY;-- . . " . ; , - /•;• , ' ' •-.-..
After the OPA became law, EPA staff from the Offices of Emergency and
'. Remedial Response and Congressional Liaison met with Congressional staff to discuss
the scope of the study to be conducted under OPA Section 41l3(a). Based on these
discussions, the Agency decided that the study would focus on the feasibility of using
liners and related systems to addressoil leaking from ASTs to secondary containment
structures (e.g., berms, dikes) and to soil underneath ASTs. An assessment of the •
feasibility of using liners to address oil leaking from other parts of AST facilities, such as
tank truck transfer racks and underground piping, was not specifically addressed during
the study. However, because underground piping was identified as a significant potential
source of leaking oil at AST facilities, the Agency's recommendations also address this
source of contamination.
For this study, EPA defined a liner as an engineered system that makes secondary
containment structures more impervious. EPA assessed the technical feasibility of
installing liners made from synthetic materials as well as earthen materials within
secondary containment structures and under ASTs (i.e., undertank liners). EPA also
assessed the feasibility of installing double bottoms on vertical ASTs as "other secondary
means of containment," which could be used in place of undertank liners. The Agency
also examined other technologies to aid in leak detection and looked at available data on
liner costs. • ,
vn
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Appendix H: Other Policy Documents
EPA evaluated the effectiveness of liners and double bottoms in reducing the
potential for leaking oil to reach soil and navigable .waters (i.e., surface waters) via
ground-water pathways. Oil discharges to unlined secondary containment systems, such
as episodic spills, and continuous leaks from the bottoms of ASTs may contaminate soil
and have the potential to be transported downward to ground water. Because ground
water often is hydrologically connected to surface water, a ground-water oil plume has
the poteptial to migrate and contaminate surface water. Furthermore, oil that repeatedly
contaminates soil as a result of frequent spills may form oil-saturated soil zones, which
have the potential to contaminate surface water when precipitation migrates through soil
to surface-water bodies. Based on these considerations, EPA assessed the suitability of
using liner systems to protect ground water and, in turn, navigable waters by evaluating
the effectiveness of these systems in preventing discharged oil from contaminating soil
and ground water. :
SUMMARY OF FINDINGS
Universe of Facilities
EPA estimates that 502,000 onshore facilities have ASTs and store significant
quantities of oil in bulk. Approximately 435,000 of these facilities are required by EPA's
Oil Pollution Prevention regulation (40 GFR Part 112) to develop written plans to
prevent and control oil discharges and install secondary containment systems for ASTs.1
EPA estimates that the number of ASTs located at these 502,000 onshore facilities is
about 1.8 million. A separate study conducted for the American Petroleum Institute
(API) estimates that about 700,000 ASTs are used at facilities in the production, refining,
transportation, and marketing sectors of the petroleum industry.2
In general, there are two categories of ASTs: (1) vertical ASTs, which are
mounted such that the tank bottom rests' on a foundation at ground level; and (2)
horizontal ASTs, which are supported in saddles such that the tank is suspended above
the ground or floor of a secondary containment structure. The storage capacity of
horizontal ASTs typically ranges from a few hundred gallons up to 20,000 gallons, while
the storage capacity of vertical ASTs typically ranges from several thousand gallons to
1 The Oil Pollution Prevention regulation (40 CER Part 112) was initially promulgated on December
11, 1973. After passage of the OP A, two sets of revisions to the regulation were developed. The first set
of revisions was proposed on October 22, 1991 (56 FR 54612) in order to clarify the applicability of the
regulation. The second set of revisions was promulgated on July 1,1994 (59 FR 34070) to establish
requirements for the development of facility response plans (FRPs). The requirements to develop SPCC
plans and to install secondary containment, as referenced in this document, are included in the original
regulation. For information on state regulations for liners, see Chapter 3 and Appendix A of this
document.
? American Petroleum Institute (API), "Aboveground Storage Tank Survey," prepared by Entropy
Limited, April 1989. This study did not include ASTs at end-user facilities.
van
SPCC GUIDANCE FOR REGIONAL INSPECTORS
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Appendix H: Other Policy Documents
over 10 million gallons! All ASTs have the potential to leak oil, presenting the threat of
environmental contamination.
Evidence of Spills
EPA searched for existing data to estimate the number of leaking ASTs, volume
discharged, and resulting environmental damage. The Agency found that comprehensive
data do not exist to adequately quantify the extent to which the nation's AST inventory is
leaking. Existing Federal regulations require facility owners and operators to report oil
discharges only if they trigger the reporting thresholds of Clean Water Act (CWA)
regulations. Consequently, some leaking oil that contaminates soil and ground water may
not be reported to Federal authorities and, therefore, may not be recorded in national
spill data bases, such as EPA's Emergency Response Notification System (ERNS).
Existing sources of information evaluated by EPA, however, do indicate that a
significant number of ASTs may be leaking or spilling oil. For example, analysis of
ERNS data indicate that about 30 percent of all reported oil discharges from onshore
facilities, or approximately 1,700 spills annually, are to secondary containment areas,
many of which are believed to be unlined. The results of a recent API survey indicate
that 85 percent of refineries, £8 percent of marketing facilities, and 10 percent of
transportation facilities have known .ground-water contamination near their facilities.3
Some of these facilities store millions of .gallons of oil in ASTs. A preliminary report
issued by the Virginia Department of Environmental Quality containing statistics on 88
facilities that have 1 million gallons or more of abbveground storage capacity indicates
that 88 percent of these facilities reported ground-water contamination/ It is not clear
from these data whether this oil contamination js caused by past practices or is
continuing to occur at these facilities. For example, the results of the API survey
referenced above indicate that changes in operation practices, upgraded standards, and
improved equipment have significantly reduced reported petroleum spills and accidental
releases from ASTs. Spill data also do not allow EPA to determine the extent of oil
contamination caused by different sizes or types of'facilities. Furthermore, the data are
not sufficiently detailed to determine whether the contamination is caused by oil
discharging from ASTs or from other areas of the facility. EPA found during the course
of this study that underground" piping located at onshore facilities also is a potentially
significant source, of leaking oil. As one indicator of the number of ASTs that could be
leaking oil and the corresponding volume discharged, EPA obtained data on AST age
and examined the potential relationship between AST age and corrosion rates to
estimate the likelihood that ASTs will develop leaks as^a function of tank age.
3 American Petroleum Institute (API), "A Survey of API Members' Aboveground Storage Tank
Facilities," prepared by API Health and Environmental Affairs Department, July 1994.
' A ' ' ' ' ' ' • ' ' ' "• • " ' ' ' ' ' ' ' '
* Virginia Department of Environmental Quality (VADEQ)j "The Virginia DEQ Aboveground
Storage Tank Regulations,'1 April 4, 1994. . • .
IX
^ee Gtno AN crro R -R EGIO
3.
H-16
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Appendix H: Other Policy Documents
Technical Feasibility
EPA investigated the technical feasibility of liner systems, including double
bottoms, by examining the effectiveness of different liner materials and designs for
protecting the environment from oil discharges and evaluating the construction feasibility
of liner systems. The technical feasibility and unit-cost analysis are based on alternative
liner designs for six "model" facilities used to represent the diverse universe of facilities
potentially benefitting from liner system installation. These model facilities ranged from
small end-user facilities with one horizontally mounted 2,000-gallon AST to a large
petroleum bulk terminal with several vertical ASTs with a combined storage capacity of
about 50 million gallons. For these model facilities,'the alternative designs considered
and evaluations of their effectiveness were based largely on discussions with EPA On-
Scene Coordinators and owners and operators of facilities using, handling, and storing oil
and petroleum products. ,
For the model facilities with vertical ASTs, EPA developed several technically
feasible approaches for installing liners and double bottoms. These approaches include:
• Retrofitting the bottom of an AST with a second steel plate (i.e., installing
"a double bottom), an interstitial geosynthetic'liner, on .top of the original
bottom, and a leak detection system (e.g., a tell-tale drain);
' •, <• Installing a.liner within the secondary containment system around the AST;
« Installing a liner, within the secondary containment system around the AST
and retrofitting the bottom of the AST with a second steel plate, an
interstitial geosynthetic liner, and leak detection system; and
« Installing aliner within the secondarycontainment system and installing an *
undertank liner with a leak detection system during construction of a new
, ' .AST. ; • ,;..:-. , . '" -. •...: . "' .• : - "- - "'..'-.,. , •"
For horizontally mounted tanks, the only option considered was the installation of a liner
throughout the entire secondary containment system. During development of these
options, EPA considered a range of AST sizes and secondary containment systems, such
as structures with pipe penetrations through side walls and those built to accommodate
vehicle access. "
EPA evaluated four types of liner materials — soil (e.g., clay), concrete,
geomembranes, and steel — that could be integrated into secondary containment
structures. All four liner materials provide roughly equivalent protection provided that
they are properly installed and maintained. The cost of liners for secondary containment
areas faround ASTs varies significantly by material. Although steel and coated concrete
liners were found to provide excellent protection and durability, these systems generally
are considerably more expensive than soil or geomembrahe liners.
• '' ,- ' . • L.
SPCC GUIDANCE rOR-REOIONAL'I'NOPE'DTORO ' •'"'• ' — "" ' ""- " •"" '•• ... n.|f
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Appendix H: Other Policy Documents
Based on the technical feasibility and unit-cost analysis of different liner designs at
model facilities, EPA determined that for large facilities it may be less expensive to
install a complete liner system at a new facility than to retrofit an existing facility.
Depending on the liner type, the cost to install a complete liner system at a new large
bulk terminal can be 30 to 50 percent less than the cost to retrofit liners and double
bottoms at an existing facility. For example, at a new large bulk petroleum terminal
(with about 50 million gallons of storage capacity), a complete liner system is estimated
to cost between $.03 and $.08 per gallon of storage capacity, or roughly between $1.5
million and $4 million.5 In contrast, the cost to retrofit an existing large bulk terminal
with a complete liner system is estimated to cost between $.07 to $.11 per gallon, or
approximately $3.5 million to $5.5 million. However*,, for small end-user facilities,^ the
retrofit costs at existing facilities may not be significantly different from installation costs
at new facilities. For example, depending on the liner type, the estimated cost to install'a
liner system at an existing small end-user facility (with one horizontally mounted 2,000-
gallon tank) ranges from $2.00 to $4.50 per gallon of storage capacity, or $4,000 to $9,000
on a facility basis, while the estimated liner costs for a new small end-user facility range
from $1.50 to $4.00 per gallon of storage capacity, or $3,000 to $8,000.
The approaches presented above for installing liners and double bottoms at AST
facilities essentially provide two types of protection in preventing leaking oil from
reaching unprotected soil and ground water: protection underneath an AST and
protection within the secondary containment area around the AST. For example,
installing^ liner only within the secondary containment area around the AST will prevent
oil discharged from the tank into the secondary containment area (e.g., a leak from the
side of the tank) from contaminating soil. However, this system will not detect
discharged oil nor prevent oil from leaking through a corroded AST bottom and reaching
soil, ground water, or surface water. Alternatively, installing a double bottom'or
undertank liner with a leak detection system beneath an AST will detect leaking oil and
prevent oil from reaching soil, but will not prevent discharged oil that fills up an unlined
secondary containment system from contaminating soil and possibly ground water. A key
issue related to the effectiveness of liner systems is the extent to which liners are
properly maintained. The relationship between liner effectiveness and maintenance, and
the costs of that maintenance,"can vary greatly depending on the purpose and nature of
the liners and the inspection and maintenance requirements. Many AST facility owners
and EPA personnel expressed concern that although certain types of liners require
periodic maintenance to, perform effectively, some facility owners may not currently
allocate sufficient resources to liner maintenance activities.
In general, the cost to install liner systems at facilities would be better represented in dollars per
gallon of throughput rather than dollars per gallon of storage capacity since throughput is a more accurate
measure of the economic value of the AST; however, EPA lacks sufficient data on average throughput to
present costs on this basis. ••:'..
SPCC GUIDANCE FOB R£@!PMAkl-N-§,pJ£IQ[i§ ,.,„»,„„„,„,.,,.„..„,„,„,„-.,„ „,_:„,_ ,„„ ..„.,.', • HJr
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Appendix H: Other Policy Documents
RECOMMENDATIONS
The recommendation of this Report to Congress is based primarily on the results
of EPA's study of liners as well as insights the Agency has gained over the past 20 years
.into the problems posed by onshore AST facilities. As a first step toward addressing the
potential risks to public health and the environment as a result of contamination from
AST facilities located near navigable waters,'the Agency recommends initiating, through
a Federal Register notice or stakeholder workgroups, a process involving broad public
participation to develop a voluntary program. This process would give stakeholders the
opportunity to share new or additional data and information- to characterize the sources,
causes, and extent of soil and ground-water contamination and efforts underway to
address contamination at AST facilities nationwide. Such data are critical to determining
the most appropriate and effective means to reduce contamination.
As envisioned by EPA, the "voluntary program would be designed to encourage
facility owners or operators, through incentives such as technical assistance, cost sayings,
and public recognition, to identify and report contamination, take actions to prevent leaks
and spills, and remediate soil and ground-water contamination. This program would
complement the Agency's efforts to develop cleaner, cheaper, and smarter approaches to
environmental problems through innovative solutions that depart from the traditional
regulatory approach. The Agency favors a voluntary^ rather than regulatory, approach at
this time in order to provide greater flexibility in addressing contamination at the vast
range of oil storage facility types, sizes, and locations. A voluntary program could focus
more directly on facilities that may pose the greatest hazard to public health and the
environment. For example, the program may Initially focus on larger, older facilities, and
facilities located near waters, sensitive areas, or populations. In addition, a voluntary
approach could allow implementation of the most appropriate prevention and cleanup .
activities for each facility. The program would look for incentives for industry to
implement reasonable and cost-effective measures to address existing problems and help
prevent future ones. ;-'.,.-'
EPA views such a program as a cooperative effort among EPA, State
governments, industry, and environmental groups. Based on this study's findings, EPA
believes the program should include commitments from facilities to:
- -*. Address known contamination and to assure that existing contamination will
, not be allowed to migrate offsite;
• Report to appropriate government agencies the status of facility
contamination and actions underway to address any problems;
* Adopt the most protective appropriate prevention standards and upgrade
; equipment as.necessary^ and .
mi
SPCC GUIDANCE FOR REGIONAL INSPECTORS ' H-19
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Appendix H: Other Policy Documents
.'.'» Monitor and/or implement leak detection to ensure that new leaks are
addressed. '
Provided stakeholders commit to the voluntary,approach, a successful program will entail
the identification of specific actions for participating facilities to undertake and include
means for objectively measuring results.
EPA has evaluated the feasibility of conducting a voluntary program to address
the problem of AST releases arid concluded that a voluntary program is worth pursuing.
Factors that support development of a voluntary program include: (1) the universe of
large AST facilities is easily defined and represented by several large trade associations;
(2) the voluntary program is consistent with the Agency's goal of developing and
promoting innovative approaches to achieve environmental goals; (3) clear, achievable
overall goals are apparent (i.e., to clean up contamination and prevent future releases);
(4) flexible approaches are available to address the problem, thus allowing participants to
implement the program in a tailored manner appropriate to their circumstances; (5) EPA
is committed to providing technical assistance as well as other incentives; and (6) there
are'established industry and state practices and standards that can be used as a basis for
constructing a comprehensive program.
In keeping with the Agency's initiatives to develop innovative, common-sense
approaches to environmental problems, EPA supports a voluntary prevention and •
cleanup program as a first step in addressing the environmental problem presented by
contamination from AST facilities. Industry representatives have expressed their support
for such a program as a more cost-effectivej flexible alternative than traditional
. regulation. EPA fully supports such an attempt, arid believes it will be successful,
provided that it has the full commitment of those involved. .The Agency believes it is
essential, that stakeholders have the opportunity to participate in the development and
execution of this voluntary program and will establish an open process for public input
into the program's design and implementation.
xni
S£aaGUiDAN,CEFQBREe_QI\|ALJ,^SP,ECJpRS •_..__ „„„,„;„_ „„...„,„,.„, -.__._ „;„.„... „„' H-20
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Appendix H: Other Policy Documents
1. INTRODUCTION
1.1 PURPOSE
Section 4113(a) of the Oil Pollution Act of 1990 (OPA) requires that: "The
President shall conduct a study to determine whether liners or other secondary means of
containment should be used to prevent leaking or to aid in leak detection at onshore
facilities used for the. bulk storage of oil and located near navigable waters." In
Executive Order 12777, the President delegated authority to the U.S. Environmental
Protection Agency (EPA) to conduct this study.
-. t • • i • . _ ...
This report to Congress presents EPA's study to assess the extent to which liner
systems should be used with ASTs at onshore facilities to detect leaks and/or prevent
leaks from reaching soil, ground water, and surface water.1 As part of this study, EPA
investigated the nature and magnitude of leaking oil at onshore facilities with ASTs that
are used for the bulk storage of oil. The Agency also assessed the technical feasibility of
using liners and related systems to detect leaking oil, and to prevent leaking oil from
contaminating soil and, by way of ground-water pathways, navigable waters. This report
to Congress, which provides .recommendations based on EPA's findings, fulfills Section
4113(a)ofOPA.
1.2 BACKGROUND
Concerns about the environmental hazards posed by onshore oil-storage facilities
have grown in recent years as a result of several widely publicized oil discharges from .
such facilities, including significant discharges from tank farms in Fairfax, Virginia, in
1990, and in-Sparks, Nevada, in 1989. Such incidents have the potential to cause
widespread damage, including contamination of soil, ground-water and surface-water
supplies, loss of property, and risks to human health. Because several hundred thousand
onshore facilities with ASTs are located throughout the U.S., many near sensitive
environments (including ground water and surface water), discharges from ASTs
represent a potentially significant environmental hazard.
Oil discharges may originate from many parts of an onshore AST facility, including
tanks, loading/unloading areas where oil'transfers are conducted between tank trucks or
vessels and ASTs, and when oil is transported in underground and abovegrpund piping.
Although liner systems could be installed at certain types of loading/unloading areas and
, other locations at a facility, EPA decided to focus on the feasibility of using liners and
related systems to address oil leaking from ASTs to secondary containment systems and
to soil underneath ASTs. This decision was made after consultations with Congressional
1 For purposes of this study, "surface water" and "navigable water" are used interchangeably.
SPCC GUIDANCE FOR REGIONAL INSPECTORS ' • • • .H-21
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Appendix H: Other Policy Documents
staff about the intent of OPA Section 4113(a.). Although the problems posed by oil
discharges at other parts of the facility (including leaks from underground piping) were
not directly investigated during this study, EPA gained valuable insights into the nature of
these problems. ' . •-. ,
- . , ** "•",'.'"--.„ " '
For this study, EPA defined a liner as an engineered system that makes secondary
containment structures more impervious, EPA assessed the feasibility of installing liners
.within secondary containment structures and under ASTs (i.e., undertank liners). EPA
also assessed the feasibility of installing double bottoms on vertical ASTs as "other
secondary means of containment," which could be used in place of undertank liners!
Secondary containment liners used in conjunction with double, bottoms or undertank
liners are capable of addressing oil discharges from ASTs into secondary containment
areas and to soil underneath vertical ASTs.
, . JEPA evaluated Hae effectiveness of liner systems, including double bottoms, in
reducing the potential for leaking oil to reach soil and surface waters via ground-water
pathways. .Oil discharges to unlined secondary containment systems, such as episodic
spills, and continuous leaks from the bottom of ASTs may contaminate soil and have the
potential to migrate downward to ground water. Because ground water often is
hydrologically connected to surface water, a ground-water oil plume has the potential to
migrate and contaminate surface water. Furthermore, oil that repeatedly contaminates
soil as a result of frequent spills may form subsurface oil plumes, which have the
potential to contaminate surface water when precipitation migrates through soil to
surface-water bodies. Based on these Considerations, EPA assessed the suitability of
using liner systems to protect navigable waters by evaluating the effectiveness of these
systems in preventing discharged oil from contaminating soil and ground water.
For purposes";of evaluating the technical feasibilityof liner systems at onshore
facilities, EPA included as a basis for this study flie approximately 500,000 onshore
facilities that meet the oil storage capacity threshold of the Oil Pollution Prevention
regulation. These facilities have oil storage capacities ranging between several hundred
gallons to several million gallons and are found in the majority of industry sectors. As a
.resultf these facilities constitute a diverse and comprehensive group from which to
evaluate the technical feasibility of installing liner systems.
\ ' ' ' \'j,'. " -, " .„ . •, . •
13 STUDY APPROACH
EPA conducted two principal tasks in preparing tHis study:
Task 1: Gathered'a range of data and information on, leaks and spills from
ASTs, types of liner systems, and their costs; and
," 2 Throughout this study, "liner system" includes both secondary containment liners, undertank liners,
and double bottoms. . . •
SPCC GUIDANCE FOR REGIONAL INSPECTORS
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PeHfeyEteetHTiefits
Task 2: % Conducted a technical feasibility analysis of liner systems for a range
of typical onshore, facilities with ASTs.
EPA gathered data on the number and type of onshore facilities storing oil in
bulk, number and type of ASTs facilities and ASTs, and the number and volume of oil
discharges from ASTs. EPA conducted interviews with facility owners and operators,
manufacturers of liner systems, and Federal and State government personnel about the
characteristics of liners systems, including their cost and effectiveness, as well as
operation and maintenance requirements. This information was used to support the
technical feasibility analysis. •
~* i • ** *
EPA conducted a technical feasibility analysis of liner systems by examining the
effectiveness of different liner materials and designs for protecting the environment from
oil discharges and evaluating the construction feasibility of liner systems. The technical
feasibility and unit-cost analysis is based on alternative liner designs for six "model"
facilities used to represent the diverse universe of facilities that meet the oil storage
capacity threshold of the Oil Pollution Prevention regulation. These model facilities
ranged from small end-user facilities with one horizontally mounted 2,000-gallon AST to
a large petroleum bulk terminal with a mix of horizontal and vertical ASTs with a
combined storage capacity of about 50 million gallons. For these model facilities, the
alternative designs considered and evaluations of their effectiveness "were based largely
on discussions with facility owner/operators, liner manufacturers, and government
personnel. . -_ ' .. -- '. •.. • ; ''.'.-._•••.'.'; ' . • /•-.'.
, Based on--the results of these two tasks, EPA developed recommendations for
minimizang the potential damage to the environment as a result of-oil leaking from the
nation's AST inventory. /
1.4 ORGANIZATION OF REPORT
The remainder of this report is organized as follows: _
* .Qiapterjg provides background information on AST facilities nationwide
and the general characteristics of ASTs, including oil discharges.
« Chapters reviews Federal and State AST regulations .and industry
practices and standards, and provides estimates of the number of facilities
already using liner systems.
' Chapter 4 describes the technical feasibility analysis of alternative liner
system designs, and presents unit costs for facilities to install these liner
systems. - . '
* Chapter 5 presents EPA's recommendations.
SPeG©UhOANCB-FOR«E6l€)NA|-H'NSPEeTORS--- „,„.„_„,,,,,., ,_„ H-23
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Appendix H: Other Policy Documents
In additionj appendices are included that provide supporting documentation for the
various analyses discussed in the report.
SPCC GUIDANCE FOR REGIONAL INSPECTORS
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Appendix H: Other Policy Documents
2. BACKGROUND ON ASTs
This chapter provides information on AST facilities and ASTs and describes the
potential environmental problems they pose. Specifically, Section 2.1 presents
information on the number and type of U.S. facilities with ASTs and the general
characteristics of ASTs nationwide. Section 2.2 describes the types of oil discharges from
ASTs and the potential impacts on soil, ground water, and surface water. Section 2.3
presents information on the status of the U.S. AST inventory and the extent to which
which oil discharges may be occurring at these ASTs:
2.1 PROFILE OF AST PACILITIES AND ASTs
EPA reviewed existing Agency reports, State information, and industry studies to
develop a profile of f the number .and type of onshore facilities storing oil in bulk, and the
number and type of ASTs. This information was used to:
» Analyze the types and characteristics of facilities with ASTs; and
• . Develop representative facilities, or model facilities, to serve as the basis
1 for developing technically feasible options for using liner systems with
ASTs^ and determining the corresponding facility costs.
This section provides information on the number and type of AST facilities and the
number and general characteristics of ASTs.
.2.1.1 Profile of AST Facilities
Section 4113(a) of OPA did not provide EPA with:specific direction on the types
of "onshore facilities used for/the bulk storage of oil" that should be examined or the
distance that qualifies a facility as being "located near navigable waters." As a result,
EPA adopted a broad interpretation of this statutory language when preparing this report
to avoid underestimating the number of ASTs that potentially benefit from using liners
systems. Specifically, EPA used the storage capacity thresholds of the Oil Pollution
Prevention regulation as the criteria to define the universe of facilities and ASTs that
would be analyzed in the study because: (1) this regulation affects a diverse population
of facilities from many industry sectors; and (2) the Agency previously conducted a study
that provides estimates of the number and type of these facilities. These findings are
discussed below.
f4AL
H-25
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Appendix H: Other Policy Documents
EPA's "Spill Prevention, Control, and Countermeasures Facilities Study" (hereafter
referred to as the Facilities Study)3 provides estimates of the number of facilities that
meet the storage capacity threshold of the Oil Pollution Prevention regulation because
they have: (1) oil storage capacity greater than 42,000 gallons underground; (2)
combined oil storage capacity greater than 1,320 gallons aboyeground; or (3) greater than
660 gallons in a single tank aboveground. Exhibit 2-1 presents estimates of these
facilities by Standard Industrial Classification (SIC) code category and three storage
capacity tiers: 1,320 to 42,000 gallons; 42,001 to 1 million gallons; and greater than 1
million gallons. For purposes of this report, these facility storage capacity categories are
referred to as small, medium, and large, respectively. EPA estimates that there are
approximately 505,000 facilities that meet the storage capacity threshold of the Oil
Pollution Prevention regulation. About 81 percent of these facilities are small, 18
percent are medium, and 1 percent are large. ', '
This 505,000 estimate overstates the number of onshore facilities where AST liners
systems could be installed because approximately 3,000 of these facilities are offshore oil
production platforms that are currently regulated by the Department of the Interior's
Minerals Management Service (MMS). Furthermore, not all of the remaining facilities
are necessarily located near navigable waters; Specifically, EPA estimates that 435,000 of
the 502,000 facilities (505,000 facilities minus. 3,000 offshore production facilities) have
the potential to discharge oil in harmful quantities into or upon the navigable waters of .
the U.S. or adjoining shorelines. Nevertheless, EPA elected to include facilities not •
.located near navigable waters in this study because many of these facilities have the
potential to contaminate surface water if they discharge oil to soil and ground water,
which could be hydrologically connected to surface water.
As shown in Exhibit 2-1, facilities that meet the storage capacity threshold of the
Oil Pollution Prevention regulation span many SIC code categories, and include facilities
as diverse as farms, manufacturing facilities, and transportation facilities. Despite this
industry diversity, these facilities may be grouped into three broad categories
corresponding to how oil is used at these facilities. Specifically, oil is consumed or used
as a raw material or end-use product (storage/consumption); marketed, refined, and
distributed as a wholesale or retail good (storage/distribution); or pumped from the
ground as part of oil exploration or production activities (production). Facilities in these
three use categories have different characteristics in terms of basic physical and operating
characteristics, such as the number and type of ASTs, throughput, and number and type
of transfer points. For example, farms that use oil and diesel to heat buildings and
power machinery are likely to have fewer ASTs and ancillary equipment and Jess product
turnover than fuel oil dealers and bulk terminal facilities, which distribute petroleum
3 U.S. EPA, JSmergency Response Division, "Spill Prevention, Control, and Countermeasures Facilities
Study," January 1991. .
SPCC GUIDANCE FOR REGIONAUNSEE£IQRS_
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EXHIBIT2-1
ESTIMATED NUMBER OF FACILITIES MEETING THE SPCC STORAGE CAPACITY THRESHOLDS
Oil Storage Capacity
Facility Category
Farms
Coal Mining/Nonmetallic Minerals
Mining , .
Oil Production*
Contract Construction
Manufacturing:
Food and Kindred Products
Chemicals and Allied Products
Petroleum Refining
Stone, Clay, Glass, and Concrete
Primary Metal Industries
Other Manufacturing^'
Railroad Fueling
Bus Transportation
Trucking and Warehousing/
Water Transportation Services
Air Transportation
Pipeline's
Electric Utility Plants
Petroleum Bulk Stations
and Terminals
SIC (wfiere
applicable)
01/02
12/14
131 ~
15/16/17
20
28
29
32
33
20 - 39
401
411/413/414/417
42/446'
458
46 :
491;
5171
,
1,321 -42,000
gallons (above
ground only)
137,iOO - 138,400
2,500-4,500
118,000-233,000
2,000-3,600
3,000-3,500
3,000-5,500
1,000- 1,200
1,000 - 8,500
1,000 - 2,000
4,000 - 8,000
0
1,200-1,600
3,200 - 3,600
0
0.- 400
3,700
1,400
42,001 - 1,000,000
gallons
.. neg.- 1,300 ••.-'
500-900
41,000-82,000
500-900
600-700
600 - 1,100
800 - 900
200 - 1,700
200-400
800 - 1,600
100-600
300-400
800-900
500 - 600
neg. - 300
600
8,800
7
-
N
> 1,000,000
cations
o
neg. - 200
neg.
0
100
neg. - 100
300-400
neg. - 100
-' neg. - 400
100 '•
.neg.- 100
0
100
neg.
200-300
500
2,200
Total
137,100 - 139,700
3,000-5,600
159,000-315,000
2,500-4,500
3,700-4,300
3,600-6,700
2,100-2,500
1,200-10,300
1,200 - 2,800
4,900 - 9,700
• .
100-700
1,500-2,000
4,100 - 4,600
500 - 600
200 - 1,000
4,800
12,400
'•...,• ;-
.• , .
"Best
Estimate"
138,400
4,300
237,000
3,500
4,000)5;
5,150<:
2,30Qy :i
5,750 /
2,000^
7,300 :
~ ' V~
400
1,750
4,350
550
600 .
4,800
12,400
1
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w » ' • ; . - - . •
-D . ' -
0 , • - • ,
O '. *>. •-" • - - - - • -
c ' ' ' - . :- ' ; ' - '""•''.-
a . •..'•;• -
| EXHIBIT 2-1
3 ESTIMATED NUMBER OF FACILITIES MEETING
70 . •"'-. ' . • . '. . -. '
m • ' • - ' - .- • . . •
CD .,,.'" • -
o . - - • ; • ' ' •
i •• :- . •• • •' . - ."- '- • • .
"Z. . • . - ' • • "
CO
-D ' " ... '
o Facility Category
H . - • . .7
70 • ' '
w ' ' Gasoline Service Stations
Fuel Oil Dealers
~ Vehicle Rental
Commercial and Institutional:
Health Care^
Education-
Military Installations .
Other Commercial and Institutional
TOTAL
"BEST ESTIMATE"
Note: N/A means not applicable and neg.
i ..'•-'.' , . •_. . .... .
SIC (where .
applicable)
554 '
5983
751
N/A
N/A
N/A
N/A ;
means negligible (i.e.,
1,321 - 42,000
gallons (above
ground only)
o •
2,500-5,500 •
''0 . '-, • "'•/; ;
1,700-1,900
•4,900 - 5,000
100-200
46.600 - 46',800
337,900-478,300
. 408,100
less than 50). The "best
"- ( .
(continued) ^
THE SPCC STORAGE CAPACITY THRESHOLDS
'Oil Storage Capacity •
42,001 - 1,000,000
eallons
4,200 - 11,100
100 - 2,800
neg. - 300
' •• /v
300. -1,400
100,800
300
1.000 - 1.800
62,300 r 122,200
92,250
estimate" is the midpoint
> 1,000,000
eallons
neg. - 100
neg. -300
0
neg. -• 200
'neg. -100
100-200
neg. T 200
3,600-5,700
4,650 ,/•'"'
of the range.
Total
. 4,200 - 11,200
2,600 - 8,600
neg. -300
2,000 - 3,500
5,000 -.5,900 '
500-700
47,600-48,800
403,800 ? 606,200 ,
': • v
"Best
Estimate1;
7,700
5,600
150
- ^
2,750 . .
5,450
600
48.200
505,000
-' This includes the 3,000 offshore facilities currently regulated by the Departmept of the Interior's Minerals Management Service (MMS).
$ Other, industrial manufacturing establishments in SICs 20 through 39, except SICs 20, 28, 29,32, and 33- . ;
- For the. medium and large capacity tiers, data were available only for hospitals (SIC 806), which are included in the Health Care subcategory.
- For the medium and large capacity tiers> data were available only for colleges (SIC 822), which are included in the Education subcategory.
Source: U.S. Environmental Protection Agency, "Spill Prevention, Control, and Countermeasures Facilities Study," January 1991. .
T3
I?
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8
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-3
. a
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Appendix H: Othei" R0licy Documents
products to end-users. This characterization is .important for developing model facilities,
which provide the basis for developing technically feasible options for installing liners at
these facilities. •
The typical storage capacity of these facilities varies significantly, from several
thousand gallons for farms and small industrial manufacturers to tens-of-millions gallons
for petroleum bulk terminals. Similarly, the number of ASTs at these facilities varies
considerably from one or two per facility to over 100 per facility. The model facilities
discussed in Chapter 4 were developed to represent the range in storage capacity and '.
number of ASTs at these facilities.
2.1.2 Profile of ASTs
In general, there are two categories of ASTs: vertical ASTs and horizontal ASTs.
The storage capacity of horizontal ASTs typically ranges from a few hundred gallons up
to 20,000 gallons, while the storage capacity of vertical ASTs typically ranges from several
thousand gallons to over 10 million gallons. Vertical ASTs are mounted such that the
tank bottom rests on a ground-level foundation, such as a concrete pad or ring wall.
Small vertical tanks (e.g., less than 42,000 gallons), which are commonly used in the oil
production industry, often are installed on a concrete pad, which, in addition to the tank
bottom, may serve as a secondary barrier to prevent leaked oil from reaching soil and to.
aid in leak detection by channeling oil to the side of the tank where it may be visually
detected.4 ,
As the volume and the tank diameter of vertical ASTs increase, ring-wall
foundations become more economical than concrete pads. Ring walls, normally made of
reinforced concrete, provide a foundation or footing upon which the AST wall rests. The
AST bottom plate typically rests on hard-packed 'Soil, sand, or other fill material. Based
on engineering experience, as ASTs reach 40,000 to 50,000 gallons of storage capacity,
the combination of size and weight considerations are such that ring-wall foundations
become more economical than concrete pads.5 Unlike vertical tanks with concrete
pads, leaks from the bottom side of vertical ASTs with ring walls have the-potential to go
undetected for extended periods of time before oil seeps to the edge of the AST, is
detected during ground-water monitoring operations, or creates a sheen in a nearby
stream or river. .
Horizontal ASTs typically are supported in saddles that are bolted to secondary
containment structures, such that tank is suspended above the ground or floor of a
4 Concrete pads used with small ASTs often are manufactured with radial groves that aid in leak
detection by channeling discharge oil to the side of the tank.
5 An analysis of data provided by the Entropy Study (see footnote #9) generally confirms this
.experience. Specifically, for the oil production sector, approximately 88 percent of all ASTs with a storage
capacity of less than 42,000 gallons are set on concrete pads.
SPCC GUIDANCE FOR REGIONAL INSPECTORS ,' v H-29
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Appendix H: Other Policy Documents
secondary Containment structure. Leaks from horizontal ASTs are generally easy to
detect because facility personnel can readily see the underside of the tank.
The overwhelming majority of existing ASTs are fabricated using carbon steel,
although stainless steel, reinforced concrete, and fiberglass materials also have been used
for certain AST applications. The wall thickness of vertical ASTs may vary significantly,
from 0.1875 inches for a 10,000-gallon AST to 1.135 inches for a 10 million-gallon tank.
Similarly, the thickness of the annular bottom ring of a vertical AST may vary
significantly; The bqttom plates of a vertical AST must be constructed with a minimum
thickness of 0.25 inches,6 exclusive of any corrosion allowance specified by the
purchaser, while the annular ring supporting the bottom-to-shell weld may be as thick as
0.75 inches for the larger ASTs. The thickness of the bottom is a critical factor in
determining the potential for an AST to develop corrosion-related leaks (as discussed in
Section 2.3.3). ASTs are either erected at the site (i,e;, field erected) or are shop-
fabricated by a manufacturer and then transported to the site. Virtually all ASTs with
storage capacity greater than 50,000 gallons are field erected because of transportation
. constraints and construction considerations. Because the vast majority of ASTs are
constructed with steel materials and, therefore, are susceptible to corrosion, these ASTs
have the potential to leak oil.
EPA estimates that the number'of ASTs at the 502,000 onshore facilities that
meet the storage capacity threshold of the Oil Pollution Prevention regulation is about
1.8 million.7'8 Based on the 1989 API"Aboyeground Storage .Tank Survey"9
(hereafter referred to as the Entropy Study}^ about 700,000 ASTs are used at facilities in
the production, refining, transportation and marketing sectors of the petroleum industry.
These two estimates differ because the number of .ASTs at all facilities that meet the
storage capacity threshold of the Oil Pollution prevention include ASTs outside the
petroleum industry, such as ASTs at end-user facilities (e.g.j farms).
6 When specified by'the purchaser, a minimum nominal thickness of 6 millimeters for all bottom
plates is acceptable. "
7 U.S. EPA, Emergency Response Division, "Estimate of the Number of Aboveground Storage Tanks
at Onshore Facilities," October 1994.
8 An alternative order-of-magnitude estimate was developed by-multiplying the number of small,
medium, and large facilities that meet the storage capacity threshold of the Oil Pollution Prevention
regulation (presented in: Exhibit 2-1) by the number of ASTs typically found at each of these facility size
categories: two ASTs, seven ASTs and 17 ASTs for small, medium, and large facility categories,
respectively. The estimates of the typical number of tanks was developed based on analysis conducted in
support of revisions to the Oil Pollution Prevention regulation. Based on this approach, the number of
ASTs are estimated to be about 1.5 million..
9 American Petroleum Institute, "Aboveground Storage Tank Survey/ prepared by Entropy Limited,
April1989 (hereafter referred to as' the Entropy Study). .
10
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Appendix H: Other Policy Documents
Exhibits 2r2 and 2-3 present data on the percentage distribution of ASTs by age
and storage capacity, respectively. Exhibit 2-2 presents the distribution of ASTs by age
for 700,000 tanks, which was obtained from the Entropy Study. About 32 percent of these
ASTs are between 0 to 10 years old, while nearly 27 percent of these ASTs are between
11 to 20 years old. AST age may be a critical factor for determining the likelihood that
leaks will develop as a result of corrosion (as discussed in Section 2.3.3).
Exhibit 2-3 shows the estimated distribution of ASTs by storage capacity (gallons)
based on data provided by New York.10 As shown in the exhibit, the largest
. proportion of ASTs have a storage capacity of between 1,000 and 10,000 gallons. This
distribution is similar to the distribution of ASTs by storage capacity in the petroleum
industry. Specifically, in Exhibit 2-4, AST distribution by storage capacity based on the
. New York State data is compared to similar data provided by the Entropy Study. As
shown in the exhibit, both sources of data indicate that most ASTs are less than 21,000
gallons. This comparison suggests that the distribution of ASTs within the petroleum
industry by storage capacity is similar to the overall distribution of ASTs by storage
. capacity — because the New York State data include ASTs from many industry sectors.
2.2 OIL DISCHARGES FROM ASTs
In general, AST oil discharges may be classified into two broad groups/categories:
leaks and spills. These categories are useful for understanding how oil discharged from
ASTs affects the environment and how different types of liner systems could aid in
detecting discharges or preventing oil from contaminating surface water by way of
tributary ground water. . "
Leaks typically originate from the bottom of vertical ASTs as a result of'
perforations in the bottom plates, which are often caused by corrosion. Leaks also may
originate from the sidewalls of vertical ASTs, as well as any point on the surface of a
horizontal AST. However, such leaks can be detected visually as part of a periodic tank
inspection program and, therefore, may be addressed before significant contamination
occurs. Although the amount of oil discharged per hour (or day) from ASTs as a result
of leaks can be relatively small compared to spills (e.g., a leak rate of one gallon per
hour versus a spill of hundreds or thousands of gallons), substantial volumes of oil may
be discharged to soil underneath an AST over time because leaks may continue
undetected for years. Leaked oil is commonly carried through the soil layer by
precipitation and migrates downward to ground water. In addition, leaked oil may
migrate horizontally to the edge of the AST bottom where it can be visually detected.
10 Under New York State's Environmental Conservation Law, both existing and new facilities with a
combined aboveground and underground storage capacity exceeding 1,100 gallons are required to register
with the State in order to operate. Facilities fire required to provide general facility information and
detailed tank-specific information, including the storage capacity of ASTs, to the New York State
Department of Environmental Conservation (NYDEC) by filling out an application form..- This
information is entered into a computer data base, which is maintained by the NYDEC.
11
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EXHIBIT2-2
IMSTRIBUtiON OP ASTS BY AGE CATEGORY
20.0%
7,6%
;6.9%
6.8%
32.1%
Age Category
0 to 10 years
11 to 20 years
21-to 30 years
31 to 40 years
41 + years
Unknown
26.6%
12
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to
EXHIBIT 2-3
DISTRIBUTION OF ASTs BY
STORAGE CAPACITY TIER
19.0%
4.1%
2.4%
58.9%
Storage Capacity Tier (gallons)
15.6%
Less than/Equal to 1,000
1,001 to-10,000;
10,001 to 100,000
BJ 100,001 to 1,000,000
(
H Greater than 1,000,000
T3
"8
13
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-Appendix H: Other Policy Documents
EXHIBIT2-4
DISTRIBUTION OF ASTs BY STORAGE CAPACITY BY DATA SOURCE
1 • " •
SOURCE OF DATA
New York State
API/Entropy Study
AST STORAGE
less than or
equal to 21,000
90.7%
82.8%
21,001 to
42,000
2.1%-
. 6.4%.
CAPACITY TIER (Gallons)
42,001 to
420,000
3.1%
6.0%
420,001 to
4,200,000.
3.6%
.4.2%
greater than
4,200,000
-0.5%
0.6%
Spills are episodic events, whereby potentially significant quantities of oil may be
discharged rapidly into secondary containment areas and beyond. Spills from ASTs may
occur as a result of operator error, for example, during loading operations (e.g., vessel or
tank truck - AST transfer operation), or as a result of structural failure (e.g., brittle ,
fracture) because of inadequate maintenance of the AST. Oil discharged from spills may
fill up secondary containment structures (e.g., diked areas) that surround ASTs and, if
the secondary containment system is unlined, migrate through soil and ground water to
surface water. A range of secondary containment liner systems to address the potential
problems posed by oil spilled into secondary containment.areas is discussed in Chapter 4.
Oil discharged from ASTs as a result of either spills or leaks has the potential to
contaminate the environment. Oil spills from ASTs may adversely affect soil, ground
water, surface water, ecosystems, and organisms. Spilled oil can move' over the ground or
through the soil and can be carried along by precipitation. Precipitation that falls on the
land surface enters into a number of different pathways of the hydrologic cycle. Sonic of
the water will drain across the land directly into a stream channel, while some will seep
through the soil and become ground waten, Ground water flows through the rock and
soil.layers of the earth until it too discharges as a spring or as a seepage into a stream,
lake, or ocean. Soil contamination (e.g., oil spilled onto the ground from an AST) may
therefore be carried down into the ground water by precipitation, and this contamination
may then be discharged into surface water. Such a scenario is specifically contemplated
in EPA's underground storage tank (UST) technical requirements at 40 CFR part 280.
Under the UST regulation, a suspected tank leak must be reported if released petroleum
is discovered at the site or in,the surrounding area (such as the presence of free product
or vapors in soils, basements, sewer and utility piping, and nearby surface water).
A great deal of research has already been conducted on the effects of oil on,the
environment. Spilled and leaked oil can damage farmland and adversely affect water
supplies by polluting wells or water intakes on-surface streams. Soil contamination also
may threaten aquatic or terrestrial wildlife and may contribute to pollution in lakes,
. rivers, .freshwater wetlands, estuaries^ beaches, and ocean waters (where runoff is a major
14
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Appendix H: Other Policy Documents
source of oil pollution). Oil in sewers, pipeline trenches, or foundation fills can increase-'
the risk of fire and explosion. In addition, lethal effects of oil on organisms may include
bird mortality caused by oiled feathers, fish mortality, and egg or larval stage losses.
Sublethal effects of AST oil spills on aquatic .organisms could include stress-related
. disease and disruption in behavior patterns or reproduction.
Various technologies are available to remediate oil-contaminated soil, although
use of these technologies can present site-specific difficulties. For example, incineration
has been demonstrated to achieve remediation cleanup goals, but is relatively costly and
may not be acceptable to the public. Surface-enhanced bioremediation, on the other
hand, is not feasible at all sites; the hydrogeology of the site must not allow for rapid
transport of the contaminants to the ground water, and the soil must be compatible with
the introduction of nutrients.
Similarly, there are various remediation options to handle'oil-contaminated ground
water. Most of these options are either containment technologies (e.g., slurry walls) or
some variation of the traditional "pump-and-treat" approach. Ground-water pump-and-
treat systems can be very costly, and treatment goals may take 30 years or longer to
achieve. It should also be noted that for certain stratigraphies (e.g., fractured bedrock or
karst topographies), restoration of contaminated aquifers may not be achievable or
feasible with existing technologies.
Exhibit 2-5 highlights three case studies illustrating the problems posed by AST
facilities and concerns regarding the potential for oil to contaminate soil, ground water,
and surface water.
23 STATUS OF ASTs NATIONWIDE
' , ' ' • V , * '
EPA conducted an extensive data collection effort to estimate the number of
leaking ASTs. Specifically, the Agency investigated Federal government data bases, such
as the Emergency Response Notification System (ERNS), and contacted several States
about data on AST leaks. The Agency found that comprehensive data do not exist to
quantify adequately the extent to which the nation's AST inventory is leaking. Existing
Federal regulations require facility owners and operators to report oil discharges that
reach navigable waters and thereby trigger the reporting thresholds of Clean Water Act
(CWA) regulations. Consequently, AST oil discharges that affect only soil and ground
water and that do not initially reach surface water are generally not reported. Despite
these limitations, existing data sources evaluated by EPA suggest that a significant
number of ASTs may be leaking or spilling oil.
Section 2.3.1 discusses EPA's review of Federal reporting requirements related to
oil discharges. Section 2.3.2 describes the available information on the extent to which
ASTs are leaking oil. Section 2.3.3 provides an age profile of the AST universe and
examines the potential relationship between leak probability and tank age.
15
s|pCCGUIDANCEFOR,REGIQNA,L,!NSEECIQRS,,,'.,i .._,„„_„»,„ .„..:-. . . •- H-35
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Appendix H: Other Policy Documents
EXHIBIT 2-5
CASE STUDIES
Case Study #1:
COLDBRQOK ENERGY FACILITY
On April 17,1993, about 35,000 gallons of gasoline spilled from a 6-inch :crack invan AST at the
ColdbrookEnergy Facility in Hampden, Maine. The tank was surrounded by an uhlined
containment dike that contained the spilled material. Remediation measures employed at the
i site included recovery wells and trenches dug into the contaminated soil. Response crews also
deployed sofbent boom along the banks of the nearby Penobscot River as a precautionary
measure.. Fortunately, only small amounts leached into the river during periods of low tide,
producing'a light sheen ("World Spill Briefs,"Golub's Oil Pollution Bulletin, Vol. 5 No. 12, May
1993, p. 7).
Case Study #2:
STAR TANK FARM
At the Star Enterprise Inc. tank farm in Fairfax, Virginia, more than 150,000 gallons of. oil is
sitting oh ground .water beneath the Star site arid a neighboring.community. The site was first
•investigated in September 1990, after migration! of the underground plume produced a light
sheen on a nearby creek. Officials at Star Enterprise acknowledge that a missing overflow
container at the loading area of the tank farm could have allowed thousands of gallons of oil to
seep into the soil and ground water undetected; it is not clear whether this is the only source of
petroleum discharges at the site, and investigations are continuing.
Case Study #3:
SPARKS BULK FUEL TANK FARM
An example of a larger petroleum spill to land affecting soil and, subsequently, ground water
occurred at a bulk fuel tank farm in Sparks, Nevada. In 1989, a 3-to 5-million-gallon
petroleum plume was discovered extending a mile east of the facility into a gravel pit. The oil
from the plume appeared to be seeping through the gravel pit walls and collecting into a water
pool in the bottom of the pit. The gravel company that owned the gravel pit pumped the
solution out of .the pit and into containment ponds for treatment. The pumping action drew
the area ground water down to the pit bottom, divertuig it from its natural flow south into the
Truckee River. Regulators said that if the pumping were to stop, the contaminated ground
water would continue downstream and end up in the, river.
16
SPCC GUIDANCE FOR REGIONAL INSPECTORS
H-36
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"Kppencllx'hfTotheir PoIicy~Documents
2.3.1 Federal Reporting Requirements
The Hazardous Materials Transportation Act (HMTA), as amended, the CWA,
the Comprehensive Environmental Response, Compensation, and Liability Act
(CERCLA), and the Resource Conservation and Recovery Act (RCRA) all contain
requirements for reporting releases of hazardous materials to the environment under
certain conditions. For oil discharges, however, these reporting requirements are not
inclusive because releases from ASTs to land that do not directly affect surface water or
that are not related to transportation are generally not covered.
The U.S. Department of Transportation (DOT) maintains several systems for
reporting transportation-related hazardous material. Under the HMTA, as amended,
'DOT collects information on releases of hazardous materials, including: oil products,
during transport by highway, rail, pipeline, water, or air. In some circumstances,
information regarding spills from ASTs may be .included in DOT's systems (e.g^ an oil
release from a tank connected to a pipeline). Many AST discharges, however, are not
transportation-related. . v
The oil discharge regulations promulgated at 40 CFR part 110 and 33 CFR part
153 under the CWA require that an oil discharge to U.S: waters or adjoining shorelines,
or in ocean waters out to approximately 200 miles from the shore, must be reported
immediately to the National Response Center (NRC) if it meets one of the following
three conditions:
. • , ^ .•'.''•.• '"•.-•'•'
.• Causes a sheen to appear on the surface of the water;
* Violates applicable water quality standards; or
« Causes a sludge or emulsion to be deposited beneath the surface of the
water or upon the adjoining shorelines.
Traditionally, the CWA reporting requirements have not been interpreted to encompass
oil discharges to soil that reach ground water, but do not migrate to surface water.
In contrast, CERCLA does require that releases of hazardous substances to land
and ground water be reported to the NRC. However, CERCLA's list of regulated
substances excludes petroleum products unless they are specifically listed. In general,
crude oil and refined petroleum products are not listed under CERCLA. Both CWA
discharges and CERCLA releases reported to the NRC or EPA are contained in ERNS:
Finally, the RCRA Subtitle I requirements cover petroleum releases to land, but
only if they originate from an UST system. The Federal UST regulations (at 40 CFR,"
part 280) implement Subtitle I. Such underground stdrage systems are broadly defined to
include tanks (together with underground piping) that have a volume that is 10 percent
or more beneath the ground surface. UST owners and operators must report suspected
17
H-37
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Appendix H: Other Policy Documents
releases of any volume of petroleum to the environment, as well as spills or Overfills that
exceed 25 gallons (or other amount specified by the implementing agency). ASTs would
be covered only if they fit within the U$T definitioni and release reports would be
maintained by the implementing agency (usually a State agency). .
Based on these considerations, EPA believes that shortcomings exist with regard
to requirements for the reporting of discharges of oil from ASTs that initially only affect
soil and ground water, and that further action may be warranted to address this issue.
23.2 Discharges from ASTs
EPA analyzed ERNS data to estimate the number of reported oil discharges that
occur from ASTs annually. The ERNS^data base is the Federal government's central
source of data on reported discharges of oil and hazardous substances. The oil spill data
contained in ERNS include information collected primarily from initial release
notifications received by the NRC, U.S. Coast Guard, and EPA. ERNS data indicate
that roughly 30 percent of reported oil discharges from facilities are to secondary
containment areas. This discharged oil could be addressed by liner systems installed
within secondary containment systems.
Of the States that EPA contacted, only Virginia provided detailed information on
oil discharges from AST facilities. The Virginia Department of Environmental Quality
(VADEQ) recently implemented a regulatory program that requires certain AST facilities
to:•'-(!) register all applicable, ASTs with VADEQ; (2) ^satisfy financial responsibility
requirements; (3) submit an Oil Discharge Contingency Plan (ODCP); and (4) participate
in the AST pollution prevention program. In particular, under the ODCP requirements,-
facilities with an aggregate oil storage capacity pif greater than 1 million gallons must
submit a Ground Water Characterization Study (GCS).11 This study requires facilities
to monitor ground water for signs of oil contamination. Based on GCSs submitted by 88
facilities to VADEQ as of April 4, 1994, about 88 percent ;of facilities (77 facilities) :
reported ground-water contamination, ;The. data were not- sufficient to determine
whether this contamination is the result of past practices or is continuing to occur at
these facilities; ,
API conducted a survey in 1994 to determine the extent to which member
facilities in the refining, marketing, and transportation sectors of the petroleum industry
have ground-water contamination. 2 '"About 30Q facilities, or 85 percent, of 350 API
member facilities completed the survey. The results of the survey indicate that 85
11 Virginia Regulation 680-14-12: Facility and AST Registration Requirements, effective September
22.J993. ' - ' - . . ' ,'•; •;. . " . . ^ '- ". ' . •
12 American Petroleum Institute, "A Survey of API Members' Aboveground Storage Tank Facilities,"
prepared by API Health and Environmental Affairs Department, July J994.
18
SPCC GUIDANCE FOR REGIONAL INSPECTORS-
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Appendix H: Other Policy Documents
percent of refineries, 68 percent of marketing facilities, and 10 percent of transportation
facilities have known ground-water contamination near their facilities. Furthermore, the
majority of these facilities are remediating the contaminated ground water. According to
API, the results of this survey may be extrapolated to all API member facilities. Again, it
is not clear from these data whether this contamination is continuing to occur at these
facilities. However, API reports that improved equipment arid operating practices over
the last 5 years have reduced reported petroleum spills and accidental releases. These
improvements include:
• In 1991, API published standard 653 as guidance for establishing inspection '
intervals for AST bottoms. This standard also "incorporates an AST
inspector certification program that establishes minimum education and
experience qualifications and provides for the testing of candidates."
* Guidance on the development of an overfill prevention program is
provided in API Recommended Practice 2350.
•' '! . ,-'-.".
• Systems and operating procedures to remove, recover, or properly handle
tank water-bottoms have been or are being implemented at storage
facilities.
• . Survey results indicate the use. of cathodic protection for buried AST-
associated piping has increased. ','•.'
233 Age Profile of ASTs
EPA obtained data on.AST age arid examined the potentialrelationship between
AST age and corrosion rates to estimate the likelihood that ASTs will develop leaks as a
function of tank age.
The most comprehensive data currently available on the age of ASTk are provided
by the Entropy Study. This study provides estimates of the number of ASTs by several
age categories for each industry sector. These data are shown in Exhibit 2-6. As shown
in the exhibit, the distribution of ASTs by age category is roughly similar for the
marketing, refining, and transportation sectors, in that the majority of ASTs within each
of these sectors are over 40 years old. However, in the oil production sector, most ASTs „
are less than or equal to 10 years of age. Because the number of ASTs in the production
sector is significantly greater than the number of ASTs in the other sectors, the overall
age distribution for ASTs in thepetroleum industry is similar to the age distribution for
ASTs in the production sector.
13 Specifically, the number of tanks An the production, marketing, refining, transportation, sectors is
estimated by the Entropy Study to be 572,620, 88,529, 29,727, and 9,197, respectively, for a totalof 700,073.
About 82 percent of all ASTs are in the production sector. ,
19
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EXHIBIT2-6
PERCENTAGE OF ASTS BY AGE CATEGORY
w
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O
70
M
50% i
40%-
30%-
20% 1
0 to 10 years
11 to 20 years
21 to 30 years
31 to 40 years
40+ years
42.1%
Marketing
Refining
Transportation
Production
Total
Source: Entropy Study
20
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Appendix H: Other Policy Documents
EPA investigated the potential relationship between the age of ASTs and failure
rates based on data provided in a study conducted by the Suffolk County Department of
Health Services in 1988 entitled, "Final Report, Tank Corrosion Study" (hereafter
referred to as the Suffolk County^Study). During the 1980s, Suffolk County, New York, •
enacted legislation that required all unprotected bare steel USTs to be replaced with
protected storage tanks by 1990 — whether or not there was evidence that the USTs
were leaking oil. As a result, this program provided a valuable sample of data to
estimate leak probabilities as a function of age because leaking USTs were included in
the sample along with perfectly functional USTs.
, Hundreds of USTs were inspected as part of this program/to determine the extent
to which corrosion caused leaks. A relationship between UST tank age and the
probability that USTs will develop a leak caused by corrosion was identified,1*
Specifically, the original design wall thickness appears to be a key factor influencing the
amount of time a bare steel tank will remain free of perforations. USTs with thicker
walls normally will take longer to develop a perforation due to corrosion than USTs with
thinner walls> all other factors being equal (e.g., the acidity of the soil). Because the rate
at which tank walls fail due to corrosion is related to tank age, the age of the tank may
be used as an indicator to predict the likelihood that tank walls will develop perforations.
'Exhibit 2-7 presents the percentage of USTs that would fail due to corrosion by age
category, based on estimates from the results of the Suffolk County Study.
In extrapolating the results of the Suffolk County Study to ASTs, EPA modified
some of the assumptions regarding the relationship between the tank age and the
probability of leaks because of the differences between the nominal wall thickness of
USTs and the nominal thickness, of AST bottoms. Specifically, ASTs are generally
constructed using thicker bottoms than are USTs wails as a result of structural
considerations and industry standards. Based on these considerations, EPA assumed
that, on average, ASTs fail as a result of corrosion 10 years later than USTs. This 10-
year estimate was based on the added nominal bottom thickness for ASTs as specified in
current industry standards. Exhibit 2-7 presents EPA's estimates of the percentage of
ASTs that fail due to corrosion by age category.
As shown in the exhibit, ASTs less than 1CI years old are assumed not to fail as a
result of corrosion. AST failure due to bottom corrosion is generally greatest for tanks
older than 40 years. Specifically, the likelihood of a corrosion-relateji failure of the tank
bottom for ASTs in this age category is estimated to be about 22 percent.
14 Other factors that may affect the likelihood of corrosion-related tank failure include: (1) acidity of
the soils; (2) height of the water table; and (3) the presence of tank design features such as baffles or
'deflection plates. • '
21
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EXHIBIT 2-7
PERCENT CORROSION FAILURE IN EACH AGE GROUP
25% -
20%-
15%-
10%-
ro -
0%
OtofO
11 to 20
21 to 30
31 to 40
40+
Source: Entropy Study
AGE CATEGORIES (YEARS)
O
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Appendix H: Other Policy Documents
The probability rates for corrosion-related failure of ASTs estimated here do not
consider the effects of using cathodic protection systems to retard/corrosion of the
bottom plate of vertical ASTs. Specifically, cathodic protection systems have the
potential to reduce the rate at which the bottoms of ASTs corrode if these systems are
properly maintained, = EPA did not adjust the probability estimates as a result of cathodic
protection because data on the use of cathodic protection systems with ASTs are
incomplete and cathodic protection is effective only if it is properly maintained.
23
SiRGGGUIDANGE-FOR REGIONAL4WSf3fi6T.©RS -~ - ~,™««OT«.,^™,™,,.. J- -J— _.„, : ' ' ' H-43
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Appendix H: Other Policy Documents
[SUNG REGULATIONS AND INDUSTRY
PRACTICES FOR LINER SYSTEMS
EPA reviewed Federal and State regulations and industry practices to gather
information on the specifications of liner systems and to estimate the number of AST
facilities currently required to use liners. Section 3.1 discusses the results1 of EPA's
review of Federal and State AST regulations. Section 3.2 summarizes recommended
industry practices related to AST liners and double bottoms. Section 3.3 presents EPA's
estimate of the number and type of facilities required to use liner systems as a result of
State regulations.
3.1 REVIEW OF FEDERAL ANDSTATE: AST REGULATIONS
3.1.1 Federal Regulations
In general, existing Federal regulations affecting AST facilities do not explicitly
require the use of liners or double bottoms with ASTs. However, section Il2.7(c) of the
Oil Pollution Prevention regulation, which is the primary Federal regulation addressing
• oil discharge control and response equipment and procedures for AST facilities, requires
that "appropriate containment and/or diversionary structures or equipment to prevent
discharged oil from reaching a navigable water course should be provided" and that such
containment be "...sufficiently impervious to contain spilled oil." This regulatory •
requirement could be met by constructing a'secondary containment system, siich as a
dike, with materials that have a low permeability (i.e., resist the penetration of-oil
through the material) or by .adding a liner to the secondary containment system to
provide this protection. However, this requirement does not specify a permeability
standard, such as how far oil may move through the material per unit time (e.g., 1
millionth of a centimeter per second). Although EPA does not have comprehensive data
on the quality of secondary containment structures at AST facilities nationwide,
information provided by EPA field personnel indicates that the quality of secondary
containment systems (e.g., the permeability of the materials) varies considerably.
The Federal UST regulation under RCRA Subtitle I (at 40 CFR part 280) and
the Federal Hazardous Waste Storage Tank (HWST) regulation under RCRA Subtitle G
(at 40 CFR part 264) require that facility owners and operators consider the installation
of liners as a protective option for USTs and HWSTs. Although the Federal UST and
HWST, regulations do not specify liner materials or designs, these regulations establish
performance criteria for containment materials and structures. For example, the UST
regulation mandates a permeability for liners of 1 x 10"6 centimeters per second (cm/sec).
The HWST regulation requires that external liner systems be capable of preventing
lateral and vertical migration of the waste if a release from the tank(s) should occur.
25
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Appendix H: Other Policy Documents
Leak .detection practices or devices are required by the UST and HWST
regulations. The UST regulation specifies that leak detection equipment must be able to
detect a 0.2 galloh-per-hour leak and that tanks must be inspected monthly. The HWST •
regulation requires that leak detection systems be in continuous Operation and be capable
of detecting a release within 24 hours or .at the earliest practicable time.
In general, ASTs (and associated piping) that have less than 10 percent of their
volume below the ground surface are not subject to the Federal UST regulations. The
HWST regulations affect only ASTs that contain hazardous wastes. Thus, Federal
regulations do not require facilities with ASTs containing oil' to have liner systems within
secondary containment systems. '*
3.1.2 State Regulations
EPA conducted a review of current and proposed AST regulations for the 50
States to gather information on liner requirements and specifications and to determine
quantitatively the extent to which States require facilities to have liner systems. The
results of this review of regulations for each State is briefly summarized in Appendix A.
EPA identified nine States that have promulgated or have proposed regulations
that specify the use of "impermeable" secondary containment systems, liners, or other
diversionary structures -and systems to prevent discharges of oil from reaching soil,
ground watery or surface water: Alaska, Connecticut, Florida, Maryland, New Jersey,
New York, Rhode Island, South Dakota, and Wisconsin.13 For each of these States,
the following information is provided below and summarized in Exhibit 3-1:
» \ The applicability of the requirementst6 different sizes and/or types of
; .facilities;, arid ;
• Specifications that address secondary containment (including liner
specifications) and leak detection procedures and/or equipment. " _ ' •
Alaska (18 ACC 75): Alaska requires that all new and existing crude oil storage
facilities with a total storage capacity of more than 5,000 barrels (and non-crude facilities
with a storage capacity of more than 10,000 barrels') locate their tanks within a
"sufficiently impermeable" secondary containment area. Secondary containment wider
tanks at new installations must include "impermeable" liners or double bottoms. Liner
and permeability specifications apply to new facilities and new secondary containment
areas only:
13 Connecticut's regulations were proposed at the time of this review.
"-•'...'. • - ''' '•'"••' " ' 26 ' '" >
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Appendix H: Other Policy Documents
EXHIBIT 3-1
SUMMARY OF STATE REGULATORY REVIEW FOR THE NINE; STATES
REGULATION
Alaska
'Connecticut
(proposed)
Florida
Maryland
New Jersey
New York
Rhode Island
South Dakota
Wisconsin.
SECONDARY
CONTAINMENT
LINERS
•/•'
J
. • S - '- '
s
f .
'•/.'•'
s
J
/
UNDERTANK
LINERS
V
. ;N/A
s •
N/A.
/
_ / - •
/
V
• /
LINER
MATERIALS
- sb .
* N/A
/
N/A
/
/
/
/
-. V. -
PERMEABILITY
RATE (CM/SEC)
1.x lO'7*'
1 x 10'5
IxlO-7
1 x HT4 '
1 X lO'l
IxlCT*
1x10*
Ix 10*
•N/A • '
LEAK
DETECTION
WITH LINERS^
;/ .
y • ;
' ' ' -
-
"-"
• . • / •
' - -
• s
.. • • N/A.
Notes: -"••-." - . • ' ' •'•.-.• *
y Regulations require these specific provisions •
N/A Not applicable; the» provisions are not.part of the regulation .
' - . . States indicated by a "-" require visual detection." States indicated by/ also require additional measures
such as inventory control or automatic leak detection equipment ,
^ flew facilities are required to have a liner tot has a permeability of 1 x 10"7 cm^sec (layer of manufactured
materialin the area under the tank) or 1 x 10* cm/sec (layer of natural or manufactured material) for new
secondary containment structures, excludicig iindertank applications •
• "Sufficiently impermeable" for new installations consists of/a "layer of
natural or manufactured material of sufficient thickness, density, and
composition to produce a maximum permeability for the substance being
: contained of 1 x l(f6 cm/see,"
•*,_. 'Impermeable11 liners for new installations consist of a "layer of
manufactured material of sufficient thickness, density, and composition to
produce a maximum permeability for the substance being contained Of 1 x
10"7 cm/sec." . ,
Alaska requires that each tank at new and existing installations must be equipped with a
leak detection system that, can be used externally to "detect leaks in the bottom of the
27
S Pee- SWI BAN-ee«F©R"R£GtONM." fN S P ECTO RS"
H-46
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Appendix H: Other Policy Documents
tank, such as secondary catchment under the. tank bottom with a leak detection sump, a
sensitive gauging system, or another leak detection system approved by the department."
The owner or operator must check for the presence of leaks or spills daily at a staffed
facility and at least once a month at an unstaffed facility.
Connecticut (RSCA proposed 22a 449): The proposed regulations would require
facilities with aggregate storage of more than 1,320 gallons, or that have a single tank of
more than 660 gallons,-to have secondary containment in the form of "impermeable...
dikes" around all tanks. These volume specifications are consistent with .the Federal Oil
Pollution Prevention regulation. These regulations would apply equally to both new and
existing facilities. '
• • Dike permeability must be less than 1 x 10 cm/sec. The dikes may be
either above or below grade, but the depth of a dike may not exceed 10
feet below the outside finished grade. The diked area must contain at least
100 percent of the volume of the largest enclosed tank.
Proposed leak detection specifications, like those for most of the eight other States, will
require regular visual inspections around tanks and transfer piping. Connecticut also
proposes to mandate weekly inventory measurement/record reconciliation procedures to
detect slow leaks that have the potential to escape visual checks.
Florida (FAC 17-762): Florida law specifies "impervious secondary containment"
systems. The regulations apply to all new facilities with a storage capacity of greater than
550 gallons. All existing facilities with a storage capacity of greater than 550 gallons must
comply with the regulations by the year 2000, except for certain shop-fabricated tank
systems.
liner systems may be synthetic, concrete, or clay-based, and they must
be capable of containing 110 percent of the largest tank enclosed by the'
secondary containment area, unless that tank is itself enplosedvin a concrete
vault, or is double walled.
The definition of "impervious" varies :depending on the liner material used.
For synthetic systems,,it is 1 x 10~7 cm/sec. Concrete liners must only be
"product tight." Clay-based liner systems must be individually approved by
the Florida Department of Environmental Protection.
-14 Vehicular fuel-storing shop-fabricated systems that store or use 1,000 gallons or less per month or
10,000 gallons or less per year also must comply with these regulations by the year 20QO. Other
abbveground shop-fabricated tanks may be retrofitted with double bottoms rather than an undertank
impermeable liner All alterations must be installed to regulatory specifications by the year 2000.
. 28
SPCC GUIDANCE FOR RFP;inMAi iM.gpFrjnps .. ,• , . II 17
-------
Appendix H: Other Policy Documents
Specified leak detection measures consist of visual inspections or other appropriate
measures. Inspections should be conducted aroiind "tanks and integral piping," and must
be conducted at least once per month-
Maryland (CMR 26:12): Maryland law specifies that secondary containment must
be "capable of effectively holding the total volume of the largest storage container
located within the area enclosed by the dike or wall." The regulations apply to new and
existing facilities with a total storage capacity of greater than or equal to 10,000 gallons.
Facilities with a storage capacity of less than 10,000 gallons, if judged to be a reasonable
threat to State waters, also are subject to the regulations. The regulations prohibit the
construction of tanks, dikes, or walls in wetlands or 100-year floodplains, unless a permit
is obtained. ,
« Liner materials are not .specified, nor are any designs except that the
system must consist of continuous dikes or walls. •
• The permeability of the system must be 1 x 10 cm/sec or less, for an
unspecified liquid. Provisions for storm water collection/release are not
specified.
Maryland requires visual inspections for leak detection. Areas to be included in each
. inspection are "seams, rivets, nozzle connections, valves, pumps, and pipelines directly
connected to abovegf ound storage tanks." Inspections must be conducted at least once
per month. .
New Jersey (NJAC 7 1E-2): New Jersey requires that "any leak must be .
prevented from becoming a discharge." The regulations apply to new-and existing "major
facilities" — facilities with a storage capacity of greater than or equal to 200,000 gallons. •
However, existing facilities are exempt from the secondary containment liner requirement
if the following conditions are met: (l) the containment system (with a containment
volume at least as large'as the largest tank) can protect ground water for the period of
time needed to clean up and repair or stop the leak; (2) the containment system allows
visual inspection for'leaks; and (3) the containment system is inspected daily.
• All secondary containment systems must have a permeability of 1 i 10"?
cm/sec or less.
« Dikes j berms, walls, curbing, gutters, ponds, lagoons, and basins are all
listed as acceptable secondary containment designs. The system must be
capable of containing 100 percent of the volume of the largest enclosed
tank, plus have a means for accommodating 6 inches of rainwater.
Leak detection is required in the form of visual inspections. Areas that must be
protected include the secondary containment: areas and systems, storage tanks,
aboveground pipes, and valves. Secondary containment/storage tank areas must be
29
H-48
-------
Appendix H: Other Policy Documents
inspected al-least once per week; secondary'containment systems that are not
-impermeable (at existing facilities only) must be inspected daily. .
New York (^6NYCRR612-6i4): New York requires a "secondary containment.
system" around all ASTs with a storage capacity of greater than or equal to 10,000
gallons,' or any tank that could reasonably be expected to discharge oil to the waters of
the; State. The regulations for new facilities are more stringent than the regulations for
existing facilities. For example, owners of new facilities with new stationary tanks must:
(1) install double bottoms on tanks; or (2) install an "impervious barrier" underneath the
'tanks.' - • •,- •• '• • • I- .'••'•-'•" ; .' ' , • ':.•'..•-- . <
• The secondary containment system may consist of a "combination of dikes,
liners, pads, ponds, impoundments, curbs, ditches, sumps, receiving tanks,
and other equipment capable of containing the product stored."
• The system must perform such that "spills of petroleum and chemical
components of petroleum will not penrieate, drain, infiltrate, or otherwise
escape to the ground waters or surface waters of the State. If the
secondary containment system is constructed of earthen material, a release
may only result m a^'minimal; amount of soil contamination." For diked
, systems, the regulation specifies the use of the performance design
standard? hi Section 2-2.3.3 of the National Fire Protection Association's
Flammable and (Combustible Liquids Code (NFPA 30).
• Although the volume of the diked area need only be 100 percent of the
largest tank volume (i.e., no precipitation allowance is stipulated), storm
water collection must be controlled with either a manually operated sump
or siphon, or a storm drain with manually controlled valves. •
« For new facilities, the imperviousness of the double bottom or lindertarik
barrier must be Ix 10'^ cm/sec or better.
Visualinspection and inventory records reconciliation are required. The visual
inspections must concentrate on the exterior surfaces (e.g., valves, pipes, etc.) and leak
detection instruments (e.g., gauges or alarms). Visual inspections must be conducted
monthly, and reconciliation of daily inventory records "must be kept current."
Rhode Island (OPCR 10-11): Rhode Island requires that a secondary
containment system be in place around all oil-storing facilities that have a total storage
capacity of greater than 500 gallons. New (or substantially modified) facilities are
15 New York State provides a guidance document for inspectors and facility owners to aid in
understanding the regulations. This document lists some permeability criteria for certain substances, even
'> though no permeability rates are specified in the regulation. •
30
SPCC GUIDANCE-FOP! REGIONAL INOPES'TORO' ' "• —'• '•• • '••m..i ••• '• • ' -" ' 11-49
-------
Appendix H: Other Policy Documents
regulated more stringently in that their secondary containment systems must consist of an.
"impermeable barrier" underneath all aboveground tanks. Rhode Island's regulations are
similar to New York State's regulations; in many cases, the language is identical,
• Secondary containment may consist of a combination of dikes, liners, pads,
impoundments, curbs, ditches, sumps, receiving tanks, or other equipment.
'.••'. The secondary containment system must be constructed so that petroleum
spills "will riot permeate, drain, infiltrate, or otherwise escape to the ground
water or surface water before clean up can occur." Also, if earthen
materials are used for the secondary containment structure, a spill should
only be able to cause "a minimum amount of soil contamination."
• Dike construction must be in accordance with the standards are specified.
by Section 2-2.3.3 of NFPA 30, except that the capacity of the secondary
containment area imlst be 110 percent of the largest tank volume.
',."•• For new or substantially modified facilities, "impermeable" is defined as a
permeability rate for water of 1 x lO"6 cm/sec or less. The barrier must not
degrade in an underground environment or in the presence of oil. In
addition, the entire secondary containment area (not just the undertank
'-„ area) for new facilities must be constructed with a permeability rate for
water of 1 x 10"6 cm/sec or less.
Regular facility inspections are required to detect potential leaks. The inspections must
focus on all exterior surfaces of tanks, pipes, valves, and other equipment such as gauges,
cathodic protection monitoring equipment,; or other warning systems. The inspections
must be conducted so that any potentially severe structural imperfections are identified,
such as cracks, excessive settlement, or corrosion. These inspections must be performed
at least monthly.
South Dakota (SCAG 74:03:30): The regulations are applied differently to new
and existing facilities and to different sized facilities — new, large facilities are regulated
the most stringently. "Small" facilities are those that have a total storage capacity of less
than or equal to 250,000 gallons, and "large" facilities are those that have a total storage
capacity of greater than 250,000 gallons.
• The containment system for new, "large" facilities may consist of double-
walled and/or double-bottomed tanks, dikes, liners, pads, impoundments,
curbs, ditches, sumps, receiving tanks, or other equipment capable of
holding the material stored. For all containment designs except double-
walled tanks, the containment volume must be 110 percent of the largest
single enclosed tank. For "new" facilities, the containment structures may
be built with native soils, clays, bentoriite, or synthetic materials; however,
31
sfecCGUIDANCEFQRREGJQNAUNSfiECIORS.,,.,,^ '.- .,,-,.,,„.„«„»„-„„,_ - . - H-50
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Appendix H: Other Policy Documents
. the peniieability of liquid through the finished floors and walls of the
containment structure must be 1 xlO"6 cm/sec or less.
• "Small" new and existing facilities must comply with eithejr: (1) the
secondary containment requirements, as described in the bullet above- (2)
the release detection requirements, as described below; or (3) certain tank
performance standards, as outlined in the regulation.
• "Large" existing facilities must build a containment structure around all
tanks that is capable of storing 110 percent of the volume of the largest
tank. No permeability standard is provided. "Impermeable" barriers
(defined as a permeability of 1 x 10~6 cm/sec or less for an unspecified
. liquid) must be built underneath all aboveground piping, and all piping
must be cathodically protected.
"Large" (new and existing) facilities must perform specified leak detection measures;
"small" (new and existing) facilities are provided with options for implementing leak
detection standards, as described above. Facilities are required to use automatic leak
detection equipment, and, workers at the facilities also must conduct regular facility
inspections. Monthly reconciliations of inventory records shall be made with daily
measurements of product storage. Inspections of exterior surfaces of tanks, overfill
devices, release detection devices, valves, gauges, and cathodic protection equipment
must be conducted. Automatic detection systems shall be continuously engaged.
Inspections of equipment must be conducted at least twice per calendar year, not to
exceed 15 months between inspections in consecutive years.
Wisconsin (ILHR AR 10): Wisconsin requires lined secondary containment
systems, which must perform as "impervious barriers" to the product stored for all
aboveground, oil-storing tanks with a storage capacity greater than or equal to 110
gallons at new facilities.16 Existing facilities are given a choice among various
secondary containment options; in addition, existing facilities with a combined storage
capacity of less than or equal to 5,000 gallons are completely exempt. .
• The term "impervious" is not defined in the regulations, and permeabilities
for the floors and walls of the secondary containment area are not
specified. *
« For new facilities, construction guidelines for dikes are specific: "Dike walls
or floors made of earthen or other permeable materials shall be lined with
asphalt, concrete, a synthetic or manufactured liner, or prefabricated basin."
Dike design must be in accordance with Section 2-2.3.3 of NFPA 30, with
the following additions: (1) the volume of the contained area must be 125
' 16 For farms, this minimum storage tank capacity is increased to 1,100 gallons.
32
SPCC GUIDANCE FOR REGIONAL INSPECTORS
-------
Appendix H: Other Policy Documents
. , percent of the largest single tank volume, as opposed to 100 percent as •
specified by NFPA 30; (2) the walls and floors of the contained area must
be impeivious to the material stored; and (3). provisions must be made for
the removal of collected rainwater. .
• Existing facilities must comply with one or more of the following by May 1,
2001: (i) a^ of the secondary containment rules as described above, except
that the containment volume may be either (a) 125 percent;of the largest
single enclosed tank volume, or (b) 100 percent of the largest single
enclosed tank volume, with provisions for removal of rainwater (with valves
or a sump); (2) leak detection, in the-form of inventory
control/reconciliation, tank-gauging, tightness testing^ vapor monitoring, or
some other approved method; (3) installation of a double bottom on tanks;
or (4) lining of the tank interior with a suitable product (the lining must
cover the tank's bottom and extend a minimum of two feet up from the
exterior grade, along the inside of the tank and the lining must th,en pass a
series of inspections).
Leak detection is not a requirement for new facilities and is contained in the State.
• regulations only as an option for compliance for existuig AST systems.
3.2 INDUSTRY PRACTICES AND STANDARDS
EPA conducted a review of industry practices and standards related to liner
systems to gather additional information on the technical aspects of these systems and
when these systems are recommended; EPA found that although many industry
associations have developed detailed standards related to the construction and operation
of ASTs, few industry standards or practices explicitly recommend the use of secondary'
containment liners and/or double bottoms. However, at the time this review was being
conducted^ several industry associations, including Underwriters Laboratory and the
International Fire Code Institute, were revising their recommended practices related to
ASTs. API and NFPA recently completed their revisions, arid the standards relating to
liner systems are briefly summarized below.
In the July 1993 version of the API's Standard 650, "Welded Steel Tanks for Oil
Storage," API adopted a policy recommending the use of release prevention barriers .in
new AST construction. API encourages owners or operators planning to construct new
ASTs to consult this document Double bottoms and undertank liners are both discussed
as possible release prevention options. In addition, API states that if the tank owner
decides the undertank area is to be constructed for leak detection, then the permeability
of the leak detection barrier shall not exceed 1 x 10"7 cm/sec.
NFPA 30, "Flammable and Combustible Liquids Code" (1993 edition) states that
"Facilities shall be provided so that any accidental discharge...will be prevented from
endangering important facilities, or reaching waterways.11 Specifically, NFPA requires
33
SPGG-GUIDANCE FOR.REGIQNAL INSPECTORS - - ,,_.„,,.,,„,„,„„„,,,.„, .,- . •-.. — ' H-52
-------
Appendix H: Other Policy Documents
that discharge prevention measures be used with aboveground secondary cohtainment-
type tanks if they meet any of the following criteria: (1) tank capacity is greater than or
equal to 12,000 gallons; (2) piping connections to the tank are below the normal
maximum liquid level; (3) prevention systems for liquid released from the tank by siphon
flow are not provided; (4) means are not provided for determining the level of liquid in
the tank; (5) an alarm (triggered when the liquid in the tank reaches 90 percent of
capacity) is not provided; (6) a system which automatically shuts off delivery when the
liquid level reaches 95 percent of capacity is not provided; (7) spacing between adjacent
tanks is less than 3 feet; (8) the tank is not capable of resisting damage form the impact
of a motor vehicle, or does not have suitable collision barriers in place; or (9) emergency
venting is not provided between any enclosed interstitial space.
EPA's review of industry standards regarding liner systems indicated that these
standards primarily consist of recommended/suggested practices;, and not requirements.
EPA does not have information on the number of facilities that have installed liner
systems due to voluntary compliance with these industry standards.
33 ESTIMATE OF THE NUMBER OF FACILITIES ALREADY USING LINERS
OR RELATED SYSTEMS
The total number of facilities that could benefit from using liners, presented in •
Chapter 2, was adjusted to account for facilities located in States that already require
liner systems. Specifically, facilities in six States currently must use liner systems that are
comparable to liner systems considered in Chapter 4.17 EPA estimated the number of
facilities in these six States that meet the storage capacity threshold of the Oil Pollution
Prevention regulation and that are required to comply with State liner requirements.
This estimate was developed for each storage capacity tier and by SIC code, and .was
subtracted from the total number of facilities that meet the storage capacity threshold of
the Oil Pollution Prevention regulation to estimate the number of facilities that currently
do not to use liner systems. The results of this analysis are presented in Exhibit 3-2. The
total number of facilities subject to the six States' liner requirements is estimated to be
83,723. This estimate includes approximately £6,000 "small" facilities, 17,000 "medium"
facilities, and 723 "large" facilities. Therefore, the estimated number of facilities not
using liner systems currently is about 421,000.
17 These six states are: Alaska, Florida, New Jersey, New York, Rhode Island, and South Dakota.
34
SPCC GUIDANCE FOR REGIONAL INSPECTORS
-------
, EXHIBIT 3-2
ESTIMATED NUMBER OF FACILITIES
NOT CURRENTLY REQUIRED TO INSTALL LINERS
Facility Type
Farms •
Coal Mining/Nonmetal Minerals
Oil Production -
Contract Construction
Manufacturing:
Food and Kindred Products
.Chemicals and Allied Products
Petroleum Refining '
Stone, Clay, Glass, Concrete
Primary Metal Industries .
. Other Manufacturing .
Railroad Fueling ~ . "
Bus Transportation
Trucking/Warehousing/Water
Transportation Services
Air Transportation
Pipelines ' ' ~
Electric Utility Plants
Petroleum Bulk Stations and
Terminals
Gasoline Service Stations
Fuel Oil Dealers '
Vehicle Rental .
Commercial and Institutional1' -
SIC Code
01/02
12/14
131
15/16/17
20
28
29
32
:33
20-39
401
411/413/
414/417
42/446
458
46 .''
491
5171
554
5983
751
N/A
Estimated Number Facilities in each of Three Storage
, Capacity Tiers
1321-42,000
gallons
121,261
3,084
138,950
2,670
2,682
3,526 '
893
.. 3,932
1,215
4,795
0
1*079 >,
2,870
0
183
3,339
1,217
0
3,154
0
, 47,183
TOTAL 1 342,033
42,001-1 mill.
gallons
572
616
49,743
668
537
668
690
785
244
959
..'" 350
269
717
458
136
-542
7,547
1 5,967
1,031
.. 119
2,635
,. 75,253
> 1 million
gallons
0
87
0
0
82
38
273
40.
155
76
50
• o
82.
o
227
441
1,887
39
107
o
343
• - 3,927
Totals
121,833
3,787
188,693
3,338
3,301
4,232
1,856
" 4,757
1,614
5,830
400
1,348
3,669
458
546
4,322
. 10,651
6,006
4,292
119
50,161
421,213
^Includes military installations, health care, education, and other commercial and institutional facilities.
35
SP,G.eJ3UJ,DAMCE FOR
H-54
-------
4. TECHNICAL FEASIBILITY AND UNIT COST OF
LINERS AND RELATED SYSTEMS
4.1 OVERVIEW
This chapter presents EPA's evaluation of the technical feasibility of alternative
liner systems and estimates of the unit costs to install secondary containment liners and
tank double bottoms. EPA investigated the technical feasibility of liner systems by
examining the effectiveness of different liner materials and designs for protecting the
environment from oil discharges and evaluating the construction feasibility of liner
systems. The technical feasibility and unit-cost analysis is based on alternative liner
designs for six "model" facilities used to represent the diverse universe of facilities
potentially benefitting fromlhe installation of secondary containment liners and double
bottoms. The alternative designs examined in this analysis and evaluations of their
effectiveness were based largely on discussions with EPA On-Scene Coordinators (OSCs)
and owners and operators of facilities using; handling, and storing oil and petroleum
products. . .
The characteristics of the model facilities also were used to develop unit-cost
estimates. The estimated costs of installing liners at .new facilities and retrofitting liner
systems to existing facilities were based on material, installation, and engineering cost
information provided by liner manufacturers and installers, and are presented in this
chapter in terms of dollars-per-gallbn of storage capacity.
The remainder of this chapter is organized as follows. Section 4.2 discusses the six
model facilities used to represent AST facilities that currently do not use liners. Section
4.3 presents an overview of liner materials, costs, and effectiveness; current liner
practices; and the conceptual designs for the liner systems analyzed in this study.
Evaluation of these designs is presented in Section 4.4. Section 4.5 addresses the use of
leak detection methods at ASTs.
4.2 DESCRIPTION OF MODEL FACILITIES
The technical feasibility and estimated cost of liner systems were based on the
characteristics of six. "model" facilities intended to represent the universe of facilities
potentially benefiting from the use of liners.18 The "model facility" approach was
selected because the technical feasibility and cost to install and maintain liner systems
varies significantly depending on the specific characteristics of a facility (e.g., the number,
18
The estimated number of facilities not currently using liner systems, is presented in Chapter 3.
37
SPeG-Qt)-IC)ANeE'F©R-RE©tON-A-|.'INSPECTORS •-- - - .„.,<—.-,™-,.,, - .<- . ~ H-55
-------
Appendix H: Other Policy Documents
size, type, and arrangement of tanks). The model facility approach also is necessary :
because the diverse nature of facilities potentially benefitting from liners precludes
developing facility characteristics for each of the 16 industrial categories of facilities with
ASTs. Development of the six model facilities, shown in Exhibits 4-1 through 4-6,
reflects information previously collected about facilities storing, handling, and using oil.
The six model facilities and their principal characteristics that affect liner
installation costs are described below. All of the model facilities are assumed to have V
secondary containment dikes around their tanks although other forms of secondary
containment, such as directed drainage to collection ponds or sumps, also are possible.
Model Facility .1: Small End User -Heating Oil Supply (Exhibit 4-1) consists of a
one horizontal 2,000-gallon heating oil tank used to supply fuel to a boiler or
furnace for industrial or commercial purposes (e.g., school, hospital, or small
manufacturer).19 The tanks are filled by fuel delivery trucks, and the oil is used
on site.
• Model Facility 2: Small End User - Motor Fuel Storage (Exhibit 4-2) is a motor
fueling operation with a total storage capacity of 24,000 gallons (in three 8,o60-
gallon horizontal tanks). The tanks are filled by fuel delivery trucks and unloaded
to motor vehicles. ",'
••'-,- ^ • '""'',
Model Facility 3: Type 1 Bulk Storage - Distribution (Exhibit 4-3) is a small bulk
plant with a combined storage capacity of 45,000 gallons in three 15,000-gallon
shop-febricated, vertical tanks storing motor fuel and possibly heating oil.-°
Fuel delivery trucks are loaded and unloaded from a loading rack at the facility.
. Model Facility 4: Type 2 Bulk Storage - Distribution (Exhibit 4-4) has a •
combined storage capacity of 104,000 gallons in six horizontal tanks (three of
10,000-gallon capacity and three of 8,000-gallon capacity) and two shop-fabricated,
vertical tanks (each of 25,OOOTgallon capacity). It also has a loading rack area.
19 Horizontal tanks are cylindrically shaped tanks positioned so that the long axis of the tank is
parallel to the ground. Because of this orientation, horizontal tanks are usually supported off the ground
by concrete or metal "saddles" conformed to the rounded tank bottom. Horizontal tanks are typically less
than 42,000 gallons and are shop-fabricated (Lie., assembled entirely at the place of manufacture).
20 Vertical tanks are cylindrically shaped tanks whose main axis is perpendicular to the ground.
Vertical tanks typically range in size from less than several hundred gallons to over 1 million gallons.
Vertical' tanks niay be shop-fabricated if small, or field-erected (i.e., assembled on-site).
38
SPCC GUIDANCE FOR REGIONAL INSPECT
-------
06-
ti
O
O
o
©
EXHIBIT 4-1
MODEL FACILITY is. SMALL END USER - SUPPLY
39
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"8
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0>
-------
o
D.
O
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8.
CL
EXHIBIT 4-2
MODEL FACILITY 2: SMALL END USER . STORAGE/MOTOR FUEL
40
-------
f-
©
0
EXHIBIT 4-3
MODEL FACILITY 3: SMALL BULK STORAGE - DISTRIBUTION
t
03
13
cn
41
T3
T3
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p;
2
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Tl
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EXHIBIT 4-4
MODEL FACILITY 4: MEDIUM BULK STORAGE - DISTRIBUTION
8.
CL
42
o
o
LU
a:
ce
O
LJ_
LU
O
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EXHIBIT 4-5
MODEL FACILITY 5: LARGE BULK STORAGE - DISTRIBUTION
a
o •
T3
"8
43
o^
o'
•<
a
o
o
a>
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-------
Appendix H: Other Policy Documents
Model Facility 5t Type 3 Bulk Storage - Distribution (Exhibit 4-5) has a total
storage capacity of 325,000 gallons, including three 25,000-gallon shop-fabricated,
vertical tanks and a 250,000-gallon field-erected vertical tank located on a ring-
wall foundation. Loading rack areas for loading and unloading are also present at
this type of facility. .
Model Facility 6: Large Oil Terminal - Distribution (Exhibit 4-6) has a mixture
of nine large-diameter, field-erected, vertical tanks with a combined storage
capacity of 50.5 million gallons. The tanks consist of: four 10-million-gallon tanks
(200-foot diameter); three 3-million-gallon tanks (120-foot diameter); and two
750,000-gallon tanks (80-foot diameter). Product is transferred to the tanks from
barges and/or tankers at off-loading piers and loaded into distribution trucks at
loading racks* ^
The characteristics of the six model facilities are summarized in Exhibit 4-7.
EXHIBIT 4-7
SUMMARY OF CHARACTERISTICS OF MODEL FACILITIES
Total Capacity
(gallons)
No. of Tanks
Facility Type
Size
MODEL 1
2,000
1 .
End user
Small
MODEL 2
24,000 .
•" '3 '<'• •
End user
Small
MODEL 3
45,000
, 3
Distribution
Medium
MODEL 4
104,000
8'
Distribution
Medium.
MODELS
325,000
4
i
Distribution
Medium
MODEL 6
50,500,000
9
Distribution
Large
Note: Facility size categories are defined as small being 1,321 to 42,000 gallons; medium being 42,001 to 1
million gallons; and large being greater than 1 million gallons.
EPA then estimated the number of AST facilities represented by each model
facility. For this report, EPA categorized by "size"-and "use" the types of facilities in the
16 industrial sectors identified in Chapter 3 as not currently required to install liners
(presented in Exhibit 3-2). The "size" categories are small, medium, or large, and the
"use" categories (based on how the oil or. petroleum products are used at facilities in that
industrial sector) are:
• Production, which includes all facilities in SIC code 131 (Oil Production);
• Storage/Distribution, which includes all facilities in SIC code 46 (Pipelines),
.SIC code 5171 (Petroleum Bulk Stations/Terminals), SIC code 554
(Gasoline Service Stations), and SIC code 5983 (Fuel Oil Dealers); and
45
SPC'C'GUIDAN'CFFaR'REGI'ONSL INSPECTOR'S
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Appendix' H: Other Policy Documents
- * Storage/Consumption, which includes facilities in all other industrial
sectors.21 •
Exhibit 4-8 shows the results of this categorization by size and use; for example, 138,950.
AST facilities are small production facilities (i.e., have a total storage capacity of between
l,320;and 42,000 gallons).
Next, one or more of the model facilities developed for this report was assigned to
represent all facilities in each size and use category (e.g., small storage/distribution
facilities). This assignment was based on previous analyses conducted by EPA (described
in Appendix B) which developed typical storage capacities for facilities in each size and
use category. For example, a typical small storage/consumption facility is estimated to
have a storage capacity of approximately 2,000 gallons, which is the same as the assumed
storage, capacity of Model Facility 1. Consequently, all 198,529 small storage/
consumption faculties that currently are not required to have liners are represented by
Model Facility 1. The results of assigning facilities to the model facilities developed for
this report also are presented in Exhibit 4-8.
Several of this report's model facilities represent facilities from more than one size
and use category. In addition, because the size categories are broad, certain size and use
categories are best represented by mbre than one model facility. In these cases* the
difference between the typical storage capacity of the facilities in that size and use
category and the storage capacity of the model facilities in this analysis provided the basis
for allocating among two model facilities.22 For example, small storage/distribution
facilities are estimated to typically have a total storage capacity of approximately 10,000
gallons (see Appendix B for a detailed description); for which no single model facility in
this report corresponds closely. Therefore, small storage/distribution facilities are best
represented by a mix of Model Facilities 1 and 2, which are assumed to have 2,000 and
24,000 gallons of storage capacity, respectively. As the "typical" small storage/distribution
facility (10,000 gallons) is closer in storage capacity to that of Model Facility 1 (2,000 .
gallons) than Model FaciUty 2 (24,000 gallons), a larger percentage of facilities were
allocated to Model Facility 1, Of the estimated 4,554 small storage/distribution facilities,
2,898 facilities are estimated to be best represented by Model Facility 1, -and the
remaining 1,656 facilities are estimated to be best represented by Model Facility 2.
21 These size and use categories were originally developed by EPA for use in estimating the costs of
implementing the requirements of the Oil Pollution Act of 1990 (U.S. EPA, Emergency Response
Division, "Regulatory Impact Analysis of Revisions to the Oil Pollution Prevention Regulation (40 CFR
112) to Implement the Facility Response Planning Requirements of the Oil Pollution Act of 1990", June
1994). See Appendix B of this report for additional information comparing that analysis to the estimates
presented here.
. 22 An alternative .allocation formula was used for medium storage/distribution facilities, as described in
Appendix B. .,
46
SPCC GUIDANCE TOR REGIONAL I
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8-
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EXHIBIT 4-8
CATEGORIZATION OF FACILITIES NOT CURRENTLY REQUIRED TO INSTALL LINERS
FACILITY SIZE
AND USE
CATEGORY
Small
Medium
Large
Total
PRODUCTION
138,950 facilities
Model Facilities 2 and 3
49,743 facilities
Model Facility 4
• '•'-' •'
Negligible
Not Applicable
188,693
STORAGE/
DISTRIBUTION
4,554 facilities
Model Facilities 1 and 2
14,681 facilities
Model Facilities 3 and 5
2,221 facilities
Model Facility 6
21,456
STORAGE/
CONSUMPTION
198,529 facilities
Model Facility 1
10,829 facilities
Model Facilities 4 and 5
1,706 facilities
Model Facility 6
211,064
TOTAL
342,033
.75,253
3,927
421,213
Note: Size categories are defined as small being 1,321 to 42,000, gallons; medium being 42,001 to 1 million gallons; and large
being greater than; I million gallons.
T3
I?
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Appendix H: Other Policy Documents
The estimated total number of facilities represented by each model facility is as
follows: ^ .
• "Model Facility!: 201^427 :;
• Model Facility 2: 49,296 .
• Model Facility 3: 97,277 .
Model Facility 4: 55,623
• Model Facility 5; 13,663
• -. Model Facility 6: 3.927
Total # Fadlities . 421,213 ' .
43 LINER SYSTEM DESIGNS AND PRACTICES
Liners are engineered systems that enhance the imperviousness of secondary
containment structures that surround ASTs.23 Secondary containment structures vary
greatly depending on the size of the tanks and the physical characteristics of the facility
. and may be constructed of compacted native soil (e.g.; clay), concrete, or other synthetic
material.24 Secondary containment structures are typically designed to hold the entire
contents of the tank or tank battery within the structure and serve to contain any spilled
Oil or product in the event of a leak or sudden discharge. Liners may be installed within
secondary containment structures in several ways. Liners may be placed to cover the
entire interior area of a secondary containment system, including the area beneath any
tanks (i.e., undertank liners). Alternatively, especially for facilities with existing vertical
tanks in direct contact with the ground, liners may be installed throughout the interior
area of the secondary containment except underneath existing vertical tanks. Although it
is technically feasible to move an existing AST temporarily in order to install an
undertank liner beneath its normal resting area, it is usually considerably more expensive
than installing a double bottom, which serves the same purpose of protecting against
leaks from failing tank bottoms. _ ..
Double bottoms protect against leaking or failing tank bottoms in vertical tanks.
When in direct contact with the ground, the tank bottom is susceptible to corrosion
(rusting of the metal), which eventually reduces the thickness of the tank bottom,
resulting in the development of perforations (e;g., pinpoint holes) and, if left unrepaired,
rips and tears. In contrast, horizontally mounted tanks are smaller and are much less
susceptible to corrosion because they are typically supported off the ground by concrete
or metal saddles or other platforms. Double-bottom tanks have a second steel surface
above the outer tank bottom or tank foundation to provide additional protection against
23 Secondary containment is a general term that includes all structures designed to channel and contain
a spill or leak from an AST or storage facility. Secondary containment structures may include graded
surfaces leading to a collections pond, diked or bermed areas around tanks, or sumps.
^ Some of these materials 'also may be used as Imers to secondary containment structures made of
more permeable materials.
'
48
SPCC GUIDANCE FOR REGIONAL INSPECTORS'
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:GtheTPoTTcyTTocuments
leaks in the event of cpirosion-induced failure of the bottom Surface. Generally, the
interstitial space between the two steel bottoms of the tank includes a geosynthetic liner
and a leak detection system. Although, the choice of a second steel bottom may provide
additional opportunity for corrosion, the interstitial leak detection system would alert the
.facility operator to any failure of the system, and the geosynthetic liner would prevent oil
from discharging to the environment until repairs could be made. The space around the
interstitial liner and leak detection system also is filled with concrete or sand to provide
additional structural support to the inner tank bottom. For purposes of this report, EPA
analyzed double bottoms as "other means of secondary containment," which could be
used in place of undertank liners. '
EPA analyzed other alternatives to double bottpms, but did not find these options
to be as usable as double bottoms. For example, one of the options considered was the
use of electronic fluid flow indicators in horizontal wells placed beneath ASTs to detect
leaking petroleum products. Although this technology is relatively inexpensive, it detects
a leak only after oil has contaminated the underlying soil. For purposes of this study,
double bottoms are preferred over this option because double bottoms would aid in
detecting a leak before soil contamination could occur.
Another option considered was the installation of a gebmembrane liner along the
inside walls and bottom of an AST. .Although this option is not a form of leak detection,
it is a viable method for preventing oil from leaking into the underlying soil provided that
the product stored in the AST is compatible with the liner material. If it is not,
degradation Of the liner could occur. The use of double bottoms, however, would
provide greater flexibility in the type of product that could be stored in the AST.
To gather information on current industry practice relating to liners, EPA
surveyed OSCs (EPA technical staff directly implementing the current SPCC Program),
facility owners and operators, liner manufacturers and installers, and State officials
responsible for AST regulatory programs.25 These interviews were meant to provide a
general assessment of the advantages and disadvantages of various liner designs and
materials from a broad representation of knowledgeable sources. The interviews were
intended to gather background information rather than be a rigorous, scientifically valid
survey. The following section summarizes the information obtained from the interviews
on five topics: the types of liner materials in use, the costs of using liners, liner use
practices, opinions on liner effectiveness, and leak detection practices.
25 OSCs from each of the 10 EPA Regions, 13 facility owners/operators in 10 States, 15 liner
manufacturers, 7 installers, 2 manufacturers of spray-on coatings, and State environmental agency staff in
all 50 States were contacted. Three representatives of the insurance industry were, also contacted regarding
the availability of data, on the probabilities and. sizes of discharges from ASTs. However, these insurance
industry contacts were not able to provide any new information beyond that already identified from other .
sources. ' • , s '. •
49
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Appendix H: Other Policy Documents
43.1 Xiner Materials Currently in Use
Impervious soils26 (clay* soil-bentonite mixtures), concrete, bituminous concrete,
geomembranes (polymeric sheets and bentonite mats), and steel liner systems are all
used by industry. Spray-on liner systems also are available and tend to be used in
conjunction with concrete secondary containment structures, although some
manufacturers have developed spray-on systems that work with earthen berms (the
material adheres to and seals the surface of the dike wall or berm, preventing product
from permeating through cracks or other imperfections).
Facility owners and operators reported that nipst secondary containment
structures are made from earthen materials. Five out of 13 facility owners/operator
respondents further indicated that impervious soil was the preferred -liner material. In
contrast, manufacturers and installers reported that synthetics were the most common
materials used for secondary containment liners. The synthetic materials most often cited
by the manufacturer and installer respondents were high density polyethylene (HDPE),
polyvinyl chloride (PVC), XR-5®, Hypalon®, and Hytrel®,
43.2 Cost *f Liners
Opinions varied on the cost to install, operate, and maintain liner systems.
Several owners and operators mentioned that, in their experience, maintaining '.
geomembrane systems is expensive. However, several liner manufacturers asserted that
geomembrane liner systems have low operation and maintenance (O&M) costs following
ihe initial installation; most of the ;liner manufacturers and installers interviewed
suggested that the only routine maintenance necessary is .a periodic inspection, and repair
if damage is found.
Installed h'ner cost quotes from different companies varied significantly, even for
identical liner materials. In addition, recommended liner thicknesses also varied
significantly for identical liner materials and applications.
433 Liner Use Practices
In general, liners are not consistently used throughout the industry. Five of the
13 owners/operators-who were contacted said that liners were not used at their facilities.
Four facilities had incorporated liners into new designs and on some retrofitted tanks and
secondary containment structures. OSCs and owners/operators agreed that liner systems
are used primarily at large facilities (i.e., with total storage capacity greater than 1 million
gallons) and that small facilities (i.e., less than 42,000 gallons) usually use liners only
when mandated by State regulations.
^6 For purposes of this report, the term "impervious soil" means a naturally occurring or adapted soil
that has a hydraulic conductivity of 1 x 10"6 cm/s or less.
50
SPCC GUIDANCE FOR REGIONAL INSPECTORS
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Appendix H: Other Policy Documents
The liner-manufacturer and installer respondents stated that, while some existing
facilities are being retrofitted with new tank bottoms (double bottoms) and liners in
secondary containment areas, it is mostly new facilities that are protected with these
systems. Most respondents agreed that, in general, few existing facilities appear to be
retrofitted with liner systems, except in the States that mandate liners. .
State regulation of ASTs, including the required use of liners, varies. Twenty-
seven States have adopted, in varying degrees, the National Fire Protection Association
(NFPA) standards or other fire codes related to ASTs. Fifteen States have specific AST
requirements in their regulations; seven States require liners at AST facilities?7 Of the
seven States that require liners, six specify maximum'.permeability liners. Two additional
States are proposing liner regulations with specific permeability requirements. Four .
States specify that AST facilities must adhere to the Oil Pollution Prevention regulation,'
while another four States delegate the regulation of ASTs to local agencies. Four States
that currently do not regulate ASTs have proposed or will be proposing AST regulations.
4.3.4 Liner Effectiveness ,
Liner manufacturers and installers report that the design life of a liner is between
15 and 30 years, except for spray-on liners whose design life is between 8 and 15 years.
These numbers are conservative estimates of the life span of a liner based on the
manufacturer's warranty, which is derived from accelerated tests performed to evaluate .
liner effectiveness and longevity.
Although OSCs have limited experience .with liners, those interviewed agree that
with proper installation and maintenance, liners are effective in preventing ground-water
contamination and in detecting leaks from AST bottoms.28 However, facility
owner/operator respondents stated that liner maintenance is not always a high priority,
and poor maintenance can significantly reduce the effectiveness of certain types of liners.
Each type of liner has different requirements with regard to proper maintenance
and repairs, as briefly described below.
• Impervious Soil. Some silty clay liners require constant or periodic
hydratioh using a sprinkler or irrigation system. Facilities also sometimes
apply controls to prevent liner penetration from anmial activity or
undesirable vegetation, and regularly inspect the liner for damage from
heavy precipitation, erosion, and settling. If the original soil liner is
damaged, it may need to be completely replaced.
27 See Chapter 3 for a discussion of State regulations and industry practices related to liner systems.
28 OSCs also noted that most spills occur outside of the tank secondary containment areas, such as at
loading racks during product transfer operations. Such spills would not be addressed by liners in tank
secondary containment areas.
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Appendix H: Other Policy Documents
• Coated or Uncoated Concrete. Some concrete liners may require '•?
evaluation of the expansion/contraction joints. Such an evaluation could
include periodically confirming wall-to-floor integrity, and checking for
cracking. Facilities also typically evaluate the integrity of concrete coatings.
« Geomembranes. Routine maintenance of geomembrane liners typically
includes visual inspection of liner integrity and, in some cases, testing of the
seams. Facilities may also use controls to prevent liner penetration from
animals or vegetation.
43.5 Liner Designs Used in this Study . .
For this study, EPA developed representative liner system designs that could be
used at the six model facilities as a basis to evaluate liner system technical feasibility and
installation costs. To provide a visual description of how different types of liner system
designs can be applied at a facility, Exhibit 4-9 shows a general schematic of a. generic
AST facility, consisting of a single, large, vertically-mounted AST; a smaller, horizontally
mounted AST;, an aboveground piping system; and a lined, diked containment area with
an access road within it. . . ,
Exhibit 4-9 also indicates the areas of the generic facility that are presented in
. detail in Exhibits 4-10 through 4-14,:as described below. Some designs may be more
suitable than others for various liner applications.
* Exhibit 4^10 presents ^cross-section details of liner installations in a1
containment area using four alternative types of tiner materials: an
:f impervious soil liner, a concrete liner, a geomembrane liner, and a /
; bentonite mat liner. Although the designs depicted are typical examples,
• variousdesigns andinstallation methods exist for these liiier materials.
' • ' ", ' '.','.- - ' • 1 ' '- - ' - v • • '. " • ' x
* Exhibit 4-11 shows details of the liner system at the interface of the vertical
tank (i.e., where the tank base meets the liner material) for the same four
liner materials; as shown in Exhibit 4-10. These drawings show that liner
systems do not protect against discharges froin tank bottoms.
* Exhibit 4-12 details methods for securing liners to tank foundations and
foundations for above-ground piping supports that penetrate the floor of
the secondary containment area.
• ; Exhibit 4-13 presents designs for installing liners where access roads are
entirely within the secondary containment area. .
52
SPCC GUIDANCE FOR REGIONAL INSPECTORS
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p
EXHIBIT 4-9
GENERAL SCHEMATIC: ABOVEGROUND STORAGE FACILITY
ACCESS ROAD
-(EXHIBIT 4-12)
FOUNDATION PENETRATIONS
(EXHIBIT 4-11)-
HORIZONTAL
AST
CONTAINMENT DIKE
AND LINER
(EXHIBIT 4-9)
VERTICAL
AST
UNDERTANK CONTAINMENT AND LEAK
DETECTION SYSTEMS (EXHIBIT 4-13)
LINER AT BASE OF
VERTICAL TANK
(EXHIBIT 4-10)
T3
"8
NOT TO SCALE
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EXHIBIT 440
DETAILS: CONTAINMENT DIKE AND LINER
VEGETATED OR GRANULAR
- SOIL COVER - 6 INCHES
IMPERVIOUS SOIL
LINER-6 INCHES
A. IMPERVIOUS SOIL LINER
ANCHOR TRENCH USE BACKFILL AND
DEADMAN (OPTIONAL) •
GEOMEMBRANE LINER
SAND BASE -6 INCHES (2 INCHES FOR SPRAY-ON LINER)
C. GEOMEMBRANE LINER
REINFORCEMENT
MESH
EXPANSION
JOINT WITH
SEALANT
REINFORCEMENT BARN
EXPANSION JOINT WITH SEALANTv
CONCRETE HOOn • 4 MCHE8 N
REINFORCEMENT!
CONCRETE
LINER-4 INCHES
B. CONCRETE LINER
ANCHOR TRENCH USE BACKFILL AND
DEADMAN (OPTIONAL)
VEGETATED OR GRANULAR
SOIL COVER-6 INCHES-
BENTONITE MAT LINER
GEOFABRIC
(DIKE ONLY)
• SAND BASE-6 INCHES
D. BENTONITE MAT LINER
NOT TO SCALE
54
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EXHIBIT 4-11
DETAILS: LINER AT BASE OF VERTICAL TANK
VERTICAL
TANK BOTTOM
VEGETATED OR GRANULAR
SOIL COVER-6 INCHES
RINGWALL
FOUNDATION
IMPERVIOUS SOIL
LINER-6 INCHES
A. IMPERVIOUS SOIL LINER
BATTEN STRIP WITH
ANCHOR BOLTS
GEOMEMBRANE LINER
GASKET ,
RINGWALL
FOUNDATION
OEOMEMBHANEUNEH
LINER CEMENT
C. GEOMEMBRANE LINER
NOT TO SCALE
VERTICAL
TANK BOTTOM
SEALANT
EXPANSION JOINT
RINGWALL
FOUNDATION
CONCRETE LINER
4-• 4 INCHES
REINFORCEMENT
MESH
B. CONCRETE LINER
VERTICAL
TANK BOTTOM
SEALANT
VEGETATED OR GRANULAR
SOIL COVER-6 INCHES
RINGWALL
FOUNDATION
BENTONITE
MAT LINER
BENTONITE SEAL
D. BENTONITE MAT LINER
55
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EXHIBIT 4-12
DETAILS: FOUNDATION PENETRATION
FOUNDATION
PENETRATION
IMPERVIOUS
SOIL LINER -
6 INCHES
VEGETATED OR GRANULAR
SOIL COVER-6 INCHES
A. IMPERVIOUS SOIL LINER
GASKET
GEOMEMBRANE
LINER
FOUNDATION
PENETRATION
BATTEN STRIP WITH
ANCHOR BOLTS
VEGETATED OR GRANULAR
SOIL COVER-6 INCHES
Wtvwwwwt ®*ND BASE •
mmmf/m « INCHES
EXPANSION JOINT
WITH SEALANT
REINFORCEMENT
MESH
FOUNDATION
PENETRATION
CONCRETE LINER •
4 INCHES
B. CONCRETE LINER
BENTONITE MAT WRAPPED
AROUND FOUNDATION
VEGETATED OR GRANULAR
SOIL COVER • 0 INCHES
FOUNDATION
PENETRATION
BENTONITE
SEAL
BENTONITE
MAT
LINER
assss
C. GEOMEMBRANE LINER
D. BENTONITE MAT LINER
NOT TO SCALE
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EXHIBIT 4-13
DETAILS: ACCESS ROAD
IMPERVIOUS S6lL OR BENTONITE MAT LINER
A. IMPERVIOUS SOIL OR BENTONITE MAT I IMFP
VEGETATED OR GRANULA
SOIL COVER -6 INCHES
8"CONCRETE ROADBED
B. CONCRETE LINER
GEOGRID
SAND BASE-6 INCHES
C. GEOMEMBRANE LINER
GEOMEMBRANE LINER
NOT TO SCALE
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EXHIBIT 444
DETAILS: UNDERTAW CONTAINMENT SYSTEM
OPTION A
VERTICAL
I-TANK
OPTIONS
LINER LOCK EMBEDDED
-INTO CONCRETE
•EXTRUSION WELD
TANK BOTTOM
SAND BACKFILL
ANODE GRID
- GEOMEMBRANE LINER
-flING WALL FOUNDATION
LEAK DETECTION PIPE
A. GEOMEMBRANE LINER (NEW)
VERTICAL TANK WALL
LEAK DETECTION
CHANNEL CUT INTO CONCRETE
REINFORCEMENT PAR
EXISTING
TANK BOTTOM
REINFORCED CONCRETE
FOUNDATION PAD
C. CONCRETE LINER (NEW)
'VERTICAL TANK WALL
-NEWTANK BOTTOM
GASKET
SAND BACKFILL
ANODE GRID
GEOMEMBRANE
LINER
EXISTING TANK BOTTOM
BATTEN STRIP WITH
ANCHOR BOLTS
RING WALL FOUNDATION
LEAK DETECTION PIPE ; • •" •'. -••>', Y •<"'..'
B. GEOMEMBRANE LINER (RETROFIT)
LEAK DETECTION
CHANNEL CUT INTO
.' CONCRETE
GASKET
GEOMEMBRANE
LINER
(OPTIONAL)
RING WALL
FOUNDATION
-*r VERTICAL TANK BOTTOM
NEW TANK BOTTOM
CONCRETE
EXISTING
TANK BOTTOM
BATTEN STRIP WITH
ANCHOR BOLTS
D. CONCRETE LINER (RETROFIT)
NOT TO SCALE
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Appendix H: Other Policy Documents
* .•'•.: Exhibit 4-14 presents four possible designs for addressing leaks from tank
bottoms of vertical ASTs, which may not be controlled by a secondary
containment liner system.29 Two designs are for undertank liner systems
installed with new tanks, while the other two are for retrofitting existing
tanks with double bottoms and leak detection systems.
4.4 UNER FEASIBILITY EVALUATION
EPA assessed the technical feasibility of liner systems based, on: the degree of
environniental protection afforded, ease of construction, and cost, as described below.30
• Environmental Protection. Environmental protection-constitutes protecting
ground water, aiding in leak detection, and preventing oil spills from
reaching surface waters. The degree of environmental protection provided
by a liner system depends on its permeability, which is influenced by among
other factors: workmanship in installation; quality and regularity of
upkeep; chemical resistivity; resistance to weathering caused by .ultraviolet
• exposure, freeze/thaw cycles, erosion, and wet/dry cycles; and resistance to
other damage caused by vandalism, animal activity, and undesirable
vegetation.
• Ease of Construction. Factors that complicate construction include
cpnstrained site conditions, adverse climatic conditions, material availability,
and the skill of the installers.
• Cost. Cost includes capital costs for materials and installation, annual
operating costs (e.g., animal and vegetation controlj security, and'hydration
of clay-based material) and maintenance costs, such as liner system repairs.
Exhibit 4-15 summarizesthe feasibility of using liners at oil-storing AST facilities
for environmental protection and shows the constructibility of liner systems. Liner
systems are rated relative to each other on a scale from 1 to 5, where 1 is distinctively
inferior to other ratings and 5 is distinctively superior. ,
29 Undertank leaks are often very difficult to detect. The potential damage to the environment from
an undertank leak is decreased greatly when an undertank liner is in place. EPA found that a number of
potential designs are available for undertank containment and leak detection and evaluated two commonly
used designs shown in Exhibit 4-14. Both designs include leak detection, which should be an integral part
of every undertank containment design. J
30 Information in this section is intended to provide a general comparison of liner materials and their
relative advantages and disadvantages. This information should not be construed as constituting
governmental approval of any1 specific design or product; EPA does not endorse or recommend specific
' liner products or materials.
59
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COMPARATIVE ANALYSIS OF LINERS FOR ENVIRONMENTAL PROTECTION AND CONSTRUCTION EASE
FEASIBILITY CRITERIA
' . *-'
ENVIRONMENTAL PROTECTION ,
1. Inherent Permeability
2. Workmanship Requirements
3. Chemical Resistivity
4. Resistance to Weathering
Caused by: - - .'
• • ultraviolet exposure
• freeze/thaw action
• erosion ,
wet/dry cycles
5. Resistance to Other Damage
Caused by:
vandalism . ,,
animal activity '
•. 'undesirable vegetation
CONSTRUCTION EASE
1. Adverse Site Conditions^
. - 2. Adverse Climatic Conditions^
3. Material Availability
4. Availability of Skilled Labor
ALTERNATIVE SYSTEMS
IMPERVIOUS SOIL
NATIVE
. SILTY
' CLAY
- "."3." •;/.'./
•<• .High
- •'. 5 .-..
'
. NA
.. • 2 : -.-.
' •' . " '2;,
•"•2" • "'
' 5 • • ,
..' .2
- r ,2 '-; :~'.'
' High
. High
' . 2 •
2 •
MODIFIED
SOIL
.'••-.• . '3 '--•';
High ;
' ' 5 -• '
.-;_;.• HA._;"'
_- :' ' 2 '"• ,
':•'..• 2 ' i •
.'... --I'" •-'-.•
: 5 '
2
- 2 .- '
Low
Moderate
3
-5 ' -
CONCRETE
UNCOAfED
->, ^ " • : ' . s-
2
lytoderate
':... .'-'"5 •' •. -
' "-' ; •; '- /'
. -'-4 •
"' ' 2 ' -'
'' '-r ' '.'4' .
: _'.- .' 4 ../, - . _
" • • ' " '. '
.• 5 • :- •
'.-"- .5' :
3
High
Moderate
.'3
" , -4-
COATED
4
Moderate
4
'* ' '"
-" 3
; - " • -3 ' ' "
.4
^ L ,4, . .
-"3 " •
4
. ,, • 5
High
Low
3
.'3
GEOMEMBRANES
POLYMERIC
SHEETS
4.
Moderate
2 to 4
-- ./ 3 .
5 - '
,.• 5
-' 5 '
2
... 3 ;
5
Low . .
High
.-' 5
3 to 4
BENTON1TE
MAT
4
Low
5
.. -
NA "
3
' ' .3 .-.'.'
1
• - »* '
5
-•' . 2 .
•2 i.
Moderate
High
' . ' , 5 - '
- 4 "..
POLYSULFIDE
SPRAY-ON
.5
Moderate
• ; 4
' - 3 ':
• ' 5-
•' 5 ,
5
'•3 '
- • .- 3 '
5" IT
. '
:' ' 5
• '5 . -
. :• .'5 .• .
. - s ••;..
• ' 4 "
5
• , S ;
''"''
•/ Moderate
Moderate
. 4
2 .
NOTES:
-' "High" indicates that construction of. the liner would be difficult under the conditions listed 'under the Feasibility Criteria, "Moderate" indicates that, construction of
liner would be moderately difficult, and "Low" indicates that construction of the liner would be relatively easy under the conditions listed under the Feasibility Criteria.
NA = Not Applicable ' - . .
Alternatives are rated relative to each other on a scale from 1 tp 5 (inferior to superior). / .'.',,' .•
. . "''•' .- : ' ' '.'.-'... •' ' "'- 60 . "..:'- - • .' -.'.''..'-•
T3
"8
Tl
O
a
O
O
, C
a>
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Appendix H: Other Policy Documents
4.4.1 Protection .of the Environment and Construction Ease
Impervious soil. Impervious soils (see footnote #26). include native silty clay and
soils mixed with bentonite. The inherent permeability of these soils is rated in the mid-
range among the liner materials that were evaluated; however, oil resistivity is high.
Impervious soil liners are susceptible to degradation from-weathering, animal activity, and
vegetation. Construction of liners from impervious soils is relatively simple at new
facilities, but generally more difficult at existing facilities.
Concrete. Concrete is widely used for secondary containment, especially at
smaller facilities. The ability of concrete containment structures to protect the
environment varies depending on the condition of the concrete surface^ particularly its
degree of cracking. Uncoated concrete is more permeable than coated concrete, whose
permeability is similar to that of geomembranes, and both coated and uncoated concrete
are highly resistant to oil. Both'coated and uncoated concrete are relatively resistant to
weathering except that uncoated concrete is susceptible to damage from freezing and
thawing especially if the concrete is cracked. Concrete systems are generally easy to
construct in new applications and more difficult for retrofit applications of existing
obstructions such as pumps and pipes.
Geomembranes. A wide range of geomembrahe liner materials are available,
including polymeric sheets, bentonite mats, and spray-on coatings compounded with
polysulfide. The inherent impermeability of liners made from these materials is high, and
oil resistivity is generally good. These protective qualities can be degraded, by weathering
caused by exposure to the sun and, in the case of bentonite mats, cracking caused by
wet/dry cycles., Exposed geomembranes and polysulfide coatings may be susceptible to
damage from vandalism or animal activity. Animal activity and undesirable vegetation
are also of concern with bentonite mats. Repairs to geomembrane liners may be costly
, and must be made promptly upon discovery. The ease of installing geomembrane liners
varies depending largely on the stiffness of the material. Geomembrane liner systems
can be installed in either hew or existing facilities.
Steel. Steel liner systems are not widely used, although they are well suited for
small horizontal tanks (up to approximately 20,000-gallon capacity) and when space
limitations require erection of a high vertical: wall. Because steel resists all oil products
and is essentially impermeable, it is highly protective of the environment. Compared to
other liner systems, steel liner systems offer the greatest resistance to weathering and
other damage. Construction of steel liners requires extensive design and planning prior
to installation, and steel liner systems ar£ generally more difficult to install in existing
facilities than in new facilities because of existing obstructions such as pipes and pumps.
Retrofitting existing containment areas may pose safety problems because welding may
be required close to flammable products; as a result, tank contents may have to be
removed and the tank cleaned before the installation can begin. Compared to other
liner systems, steel is not economical for most facilities. . •.
61
FOR REGIONAL INSPECTORS— - •*• • ..~~^-...,.,.,,.^.,--.--. -~~ — H-79
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Appendix H>Other Policy Documents
4A.2 Estimated .Facility Costs
The estimated capital unit costs for, both retrofitting existing facilities and for
installing liner systems at new facilities are shown in Exhibit 4-16. O&M costs are
addressed qualitatively in Exhibit 4-17. The cost estimates presented in the exhibits are
meant to be representative estimates based on the characteristics of the model facilities
rather than definitive estimates applicable to a specific type of facility. Capital costs for
existing facilities are based on installing a secondary containment liner system (except
underneath tanks) and installing double bottoms on all vertical ASTs.31 For new
facilities, costs are estimated assuming that undertank liners would be installed along with
the secondary containment liner.
The exhibits do not include steel liners because their cost is prohibitive except in
special circumstances. Costs are presented in 1991 dollars, corresponding to when most
of the information on installation and O&M costs was collected. The cost estimates
presented in the exhibits were developed based on information in the 1991 Means
. construction cost data estimating guide, which presents average costs for 30 major
cities. In addition, the cost estimates reflect the following assumptions:
• • Grubbing, soil excavation, and grading costs are not included in the cost
•estimates for new facilities, but are:included in the estimates for installation
at existing facilities. .
• Concrete liners are 4 inches thick.
• , Liners comprising polymeric sheets are placed on top of a layer of sand 6
inches deep..
« Liners comprising bentonite mats are covered with 6 inches of soil that is
seeded with grass, fertilized, and mulched. '•'-••
: - ' . - ' ,
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TJ
O
CD
09
3 '
I
EXHIBIT 4-16
COMPARATIVE COST ANALYSIS OF LINER MATERIALS BY MODEL FACILITY3/
T,
MODEL
FACILITY*'
#1 New Facility
Existing Facility
#2 New Facility
Existing Facility
\ ,
#3 New Facility
Existing Facility-'
#4 New Facility
. Existing Facility-'
#5 New Facility
Existing Facility-61
#6 New Facility
Existing Facility8'
ESTIMATED LINER CAPITAL COSTS PER MODEL FACILITY*'
IMPERVIOUS SOIL
Native SJlty Clay
$5,000
$6,000
$11,000
$15,000
$18,000
$38,000
$28,000
,$50,000
_ $63,000
$117,000
,$1,606,000
$3,404,000
Modified Soil
$5,000
$5,000
$9,000
.$11,000
$16,000
$36,000 :
$24,000
$43,000
$64,000
$116,000
$1.568,000
$3,283,000
CONCRETE
Uncoated
. $3,000
$4,000
• $£,000
$11,000
$17,000
$36,000
$25,000
$43,000'
'$84,000
$134,000
$2,304,000
$3,930,000
. Coated
• $8,000
$9,000
$22,000
$24,000 s
$28,000
~ $56,000
$47,000
$66,000
$141,000 ';
• $191,000
$4,140,000
$5,767,000
GEOMEMBRANES
Polymeric Sheets
$4,000
$7,000
$13,000
$is,ooo
$20,000
$42,000
$33,000
$56,dOO
$95,000
$150,000
$2,103,000
$3,807,000
Benlonite Mat
$4,000
$4,000
$9,000
$12,000
$17,000
$36,000
$25,000
$43,000
$70,000
$121,000
$1,894,000
$3,569,000
Pblysuiflde Spray On
$5,000
- $5,000
$12,000
$14,000
$19,000
$39,000
$31,000
: $48,000
$97,000.
$147,000
$2,575,000
$4,186,000
S' In 1991 dollars. *
-' The six "model" facilities are summarized in Exhibit'4-7. ; , . "•
. S' 30-percent contingency included. '' ^ . -..'._ s -
^ $27,000 of tost is for double bottom tank retrofit for three 10-foot diameter tanks.
- $23,000 of cost is for double bottom tank retrofit for two 12-foot diameter tanks. .V
• $81,600 of cost is for double; bottom tank retrofit for three 12-foot diameter tanks and double bottom tank retrofit for one 40-foot diameter tank.
^ $2.534,000 of cost is for double bottom tank retrofit for two 80-foot diameter, three 120-foot diameter, and four 200-foot diameter tanks. . ,
Note: The retrofit costs for Model Facilities 1 and 2 do not include double bottom retrofit costs because the tanks at these model facilities are horizontal,' saddle-mounted tanks (see Exhibits
4-1 and 4-2).. . , . '
. '•"• . 63 - '• '..''-"•.':•
o^
-3
o
o
o
o>
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Appendix H: Other Policy Documents
EXHIBIT 4-17
ANNUAL OPERATIONS AND MAINTENANCE COSTS
TYPE
Operational
Liner System
' Repair
IMPERVIOUS SOIL
Native
Silty
Clay
Low
Low
Modified
Soil
Low
Low
CONCRETE
Uncoated
Moderate
Moderate
Coated
Low
High
GEOMEMBRANES
Polytfteric
Sheers
Low
High
Bentonite
Mat
Low to High
Moderate
Polysulfide
Spray On
Low
High
• Retrofitting of double bottoms: occurs during a routine inspection and
maintenance period when the tank has been drained, cleaned, and
temporarily taken out of service.
' • Soils with high permeability can be modified to produce an impervious soil
. liner by applying 3 pounds of bentonite to each square foot of soil. The
liner is covered with 6 inches of soil that is seeded with grass, fertilized, and
; mulched.
• Tank foundation liners are installed at new, large and medium sized
: facilities. This involves installation of aHOPE liner, a 2-inch sand layer,
cathodic protection, and an additional. 2-inch sand layer. At existing
facilities, additional equipment such as cranes and temporary tank pads are
required for retrofitting undertank liners.
* Large facilities have roads within secondary containment structures.
Crushed stone roads-are constructed over a liner system consisting of a
geomembrane and impervious soil layers. In the case of concrete liners, •
the concrete is thickened along the course of the road.
As indicated in Exhibit 4-16, for all liner systems, the cost to retrofit liners is
higher than installing liners at new facilities because of the added difficulty and cost
associated with working around existing tanks and appurtenances (e.g., piping). In
addition, certain general conclusions are apparent from the table:
- • Coated concrete was the most expensive alternative for all model facilities.
• Uncoated concrete, impervious modified soil, bentonite mat, and
polysulfide spray-on liner systems were the least costly for retrofitting of
existing facilities with total storage capacities of less than approximately
100,000 gallons. ,
64
ICE TOR REGIONAL I
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Appendix H: Other Policy Documents
• : For a large facility (e.g., total storage capacity of greater than or equal to 1
' million gallons), native soil -and bentonite mat liner systems were the least
costly alternatives. '
V For all model facilities, the bentonite mat liner system was consistently one
> ' . of the least expensive alternatives. .
• For all model facilities, the costs for polymeric sheet liner systems were
similar to the costs of other options; however, polymeric sheets were never
the least expensive alternative.
.A range of costs (expressed in dollars per,gallon of storage capacity) to install new
and retrofitted liners at the six model facilities is presented in Exhibit 4-18. These ranges
are based on the least and most expensive liner cost estimates presented in Exhibit 4-16.
Generally, the larger the facility, the lower the price per gallon of capacity to construct a
liner system because, for most secondary containment structures of typical proportions,
the volume of the secondary containment structure increases at a faster rate than its
area. Because secondary containment structures are designed to hold the entire contents
of the largest tank or aggregate volume of tanks permanently manifolded together within
the structure, the volume of the structure is typically roughly equivalent to the storage
capacity of the tank or tanks within-that structure. Because the increase in surface area
results in costs roughly equivalent to the incremental material and installation cost of .
liners (which cover the surface area of the secondary containment) and the increase in
volume corresponds with the additional amount of available storage capacity, the ratio of
available storage volume to surface area increases with tank size. This, in turn, translates
into declining cost per gallon of storage capacity. For example, if two facilities have
secondary containment areas of 50,000 square feet, and one has a dike height 6 inches
higher than the other, the difference in height would add very little to the cost of
installing a liner (the increase in lined surface area would be approximately 45 to 50
square yards), but the facility could store as much as 180,000 more gallons of oil
As shown in Exhibit 4-18, the cost for installing a liner system at an AST with a .
nominal capacity at a small end-user facility (Model Facility 1) is estimated to range from
$1.50 to $4.50 per gallon of storage capacity. A liner system at a large oil terminal
facility (Model Facility 6) is estimated to cost approximately $0.03 to $0.11 per gallon of
capacity. In general, the costs to install liner systems at facilities would be better
represented in dollars per gallon qf throughput rather than dollars per gallon of storage
capacity since throughput is a better representation of the economical value of the tank;
however, EPA lacks sufficient data on average throughput to present costs in this
manner.
Existing ASTs are assumed to be retrofitted with double bottoms to prevent
i undertank discharges. The cost of retrofitting ASTs with double bottoms is proportional
to the area of the tank bottom. These retrofits were found to vary from $15 to $115 per
65
-REi3t©N-Ab'l NSPEGTORS " - - - — •—•• •"• -—'""- ••-- •- - - ~" —" ——— - ' H-83
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Appendix H: Other Policy Documents
EXHIBIT4-18
ESTIMATED LINER CAPITAL COST PER GALLON OF STORAGE CAPACITY
MODEL
FACILITY
1 :. '..
2
•3
"" . , 4 " (\
•5
- x 6 •''.'' •
COST FOR RETROFIT
INSTALLATION
(DOLLARS/GALLON)
Low
$2.00 v
$0.46
'$0.80
$0.41
$0.36
$0.07
High
$4.50 •
$1.00
; ".'.;• $1.24.
$0.63
: $0.59 .
$0,11
COST FOR NEW
INSTALLATION
(DOLLARS/GALLON)
Low
$1.50
$0.38
$0,36
$0.23
$0.19
$0.03
High
$4.00
$0.92 ..
$0,62
. $d.45
$0.43 .
$0.08
square foot, depending on the tank size, with the higher cost per square foot associated
with smaller tanks. New installations of undertank liners can be completed for
approximately $4 to $34 per square foot, depending on tank size.
Annual P&M costs were examined qualitatively in the; analysis..They are
generally low for impervious soils and geomembrane liners (except for bentonite mats,
which must be hyd'rated regularly). Operational costs for coated concrete are lower than
uncoated concrete; however, the costs to repair cracks, deteriorated expansion jointsv and
sealants for coated concrete systems are greater. Although liner manufacturers rated
operational costs for bentonite mats as low, facility owners and operators who had
installed these types of liners stated that the operating costs were high. Exposed
geomembrane liners are susceptible to damage from vandalism and accidents, and any
needed repairs may be costly.
EPA determined that there is not sufficient information to quantify the number,
size, and costs associated with releases that liner usage may prevent. However, initial
research does indicate that the cost of remediating oil releases will vary greatly
depending on the characteristics of the oil (e!g., viscosity), characteristics of the soil and
ground-water (e.g., depth to ground water, velocity of flow, depth of saturation, and
effects from nearby pumping), external factors such as weather, and remediation
technique used. Preliminary analysis suggest that remediation costs can range up to
greater than $100 per gallon of oil released.
66
SPCC GUIDANCE FOR REGIONAL I
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4,5 LEAK DETECTION METBODS .
Current technology has produced a variety of leak detection systems including
alarms, inventory control, acoustic emissions testing, volumetric measurement, and
interstitial space monitoring, and industry is aggressively developing technology to make
leak detection more reliable. EPA has found that leak detection systems are part of an
effective liner system for ASTs, serving to bring a leak or spill to the owner's or
operator's attention while the liner prevents leaks and spills from reaching soil or ground
water.
Leak detection methods are typically classified as either continuous or periodic
systems, although many current technologies may be configured to provide either type of
operation. Continuous leak detection provides uninterrupted monitoring and,
consequently, instant notification of tank failure or an oil discharge. Examples of
continuous systems are overfill alarms, overfill sumps, tell-tale drains, interstitial space
monitors, and horizontal wells with electronic fluid-flow indicators. These systems are
most effective in preventing adverse environmental impacts of discharges when integrated
with leak containment systems because leak detection systems by themselves only alert
facility operators to the existence of the discharge. For example, when used in
conjunction with double tank bottoms, interstitial space monitoring may consist of a
hydrocarbon sensitive tape lying between a tank's external bottom and its internal double
bottom. Use of tell-tale drains on ASTs also is common at facilities that have installed
double bottom retrofits. Tell-tale drains are used to check the integrity of the double
bottom by providing a drain path for any liquid that has accumulated in the space
between the two bottoms. While overfill alarms and sumps are a form of leak defection,
they db not provide notification of tank bottom failure.
Periodic leak detection involves checks or tests at regular intervals to determine
the occurrence of oil discharges or tank bottom'failure. The type of system used
generally depends on the type and size of the tank being monitored. Periodic system's
include: internal/external visual inspections; pressure/vacuum testing of tanks and piping;
volumetric precision testing of the tank; inventory record and measurement
reconciliation; acoustic emissions testing; and chemical gas detection methods. OSCs
agreed that visual inspection is the most common form of leak detection at AST facilities.
When visual leak detection is used, daily records need to be maintained, interpreted, and
reviewed to provide the most sensitive leak detection threshold possible. The most
significant drawback to visually inspecting vertically mounted tanks is the inability to
examine the tank bottom while the tank is in service.
Periodic leak detection systems are generally required in States that regulate
ASTs; however, these methods are not adequate in certain situations. For example,
visual inspections cannot be conducted for the bottom or internal area of vertical ASTs
without the removal of stored product: In such circumstances, other non-invasive
periodic methods (i.e., those that do not require tank entry) such as acoustic emissions
67
']'-.- , .
Sf|c,,C,QUIDANtC,ElE,OR REGLQNA)- INSPECTORS ..!_ ,„. -.. , ™«^_««^.^ , --. - H-85
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Appendix H: Other Policy Documents
testing and precision volumetric detection, must be used. These methods can have
detection thresholds as low as one gallon of leaking product per hour.
Intrusive methods of leak detection have an extremely high detectability rate
because areas that are suspected to have failed can J?e examined by other means.of
integrity testing .(i.e., ultrasonic, radipgraphic, dye penetrant, magnetic particle, and
vacuum box testing). Internal inspections can be expensive and result in significant tank
down-time; consequently, intervals between tests have, historically been as long as 20
years. Internal inspections alone may not be adequate to identify tank bottom failures
because of the long time between bottom failure and leak discovery given the average
time between tests. !'
. ' Other non-invasive methods of leak detection such as inventory reconciliation can
be useful at detecting large leaks; however, inventory checks may not detect slow,
continuous leaks because of the normal margin of error in making measurements and the
effects of temperature-related expansion of product volume in the tank. Although the
types of systems described in the paragraphs above are effective for detection of smaller
leaks, their expense can be significant.
68
SPCC GUIDANCE FOR REGIONAL INSPECTORS '. H-8fi
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f:" OTier"FoIicyT35cuments
5. RECOMMENDATIONS
This chapter presents the Agent's recommendations. The recommendation of
this Report to Congress is based primarily on the results of EPA's study of liners as well
as insights the Agency has gained over the past 20 years into the problems posed by
onshore AST facilities. As a first step toward addressing the potential risks to public
health and the environment as a result of contamination from AST facilities located near
navigable waters, the Agency recommends initiating, through a Federal Register, notice or
stakeholder workgroups, a process involving broad public participation to develop a
voluntary program. This process would give stakeholders the opportunity to share new
or additional data and information to characterize the sources, causes^ and extent of soil
and ground-water contamination and efforts underway to address contamination at AST
facilities nationwide. Such data are critical to determining the niost appropriate and
effective means to reduce contamination.
• As envisioned by EPA, the voluntary program would be designed to encourage
.facility owners or operators, through incentives such as technical assistance, cost savings,
and public recognition, to identify and report contamination, take actions to prevent leaks
and spills, and remediate soil and ground-water contamination. This program would
complement the Agency's efforts to develop cleaner, cheaper, and smarter approaches to
environmental problems through innovative solutions that depart from the traditional
regulatory approach. The Agency favors a voluntary, rather than regulatory, approach at
'this time in order to provide greater flexibility in addressing contamination at the vast
range of oil storage facility types, sizes, arid locations. A voluntary program could focus
more directly on facilities that may pose the greatest hazard to public health and the
environment. For example^ the program may initially focus on larger, older facilities, and
facilities located near waters, sensitive areas, or populations. In addition, a voluntary
approach could allow implementation of the most appropriate prevention and cleanup
activities for each facility. The program would look for incentives for industry to
implement reasonable and cost-effective measures to address existing problems and help
prevent future ones. '
EPA views such a program as a cooperative effort among EPA, State
governments, industry, and environmental groups. Based on this study's findings, EPA
believes the program should include commitments from facilities to:
• Address known contamination and to assure that existing contamination will
not be allowed to migrate offsite;
• Report to appropriate government agencies the status of facility
contamination and actions underway to address any problems;
69
PC-G-€btDANGEFOR'REe+ONM:-.|"NSPEO-TORS •- •—.«-—,-,—.•—..,...,.-.— -.--.. ... ... .-^, ' ' H-87
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Appendix H: Other Policy Documents
• = Adopt the most protective appropriate prevention standards and upgrade ;
equipment as necessary; ancl
* Monitor and/or implement leak detection to ensure that new leaks are .
addressed.
Provided stakeholders commit to the voluntary approach, a successful program will entail
the identification .of specific actions for participating facilities to undertake, and include
means for objectively measuring results.
EPA has evaluated the feasibility of conducting a voluntary program to address
the problem of AST releases and concluded that a voluntary program is worth pursuing
for the following reasons:
'<*•'. The universe of large AST facilities is relatively easy to define and is
represented by several large trade associations,.
• The program is consistent with the Agency's goal of developing and
promoting innovative approaches to achieve environmental goals.
• Clear, achievable goals are apparent (e.g., to mitigate the spread of existing
. contamination and to prevent future releases).
• Elexible approaches (i.e., numerous technological options arid management
practices) are available to address the problem, thus allowing participants
Ito implement the program in a tailored manner appropriate to their
•-,. ' ' ; circumstances. -:•;':'.-'.-'.- - ";*V^.-.'.- /:,..','-• " ;-. " -' • •
'••-.; EPAis committed to prbviduig technical assistance as well as other
- ; "V- : •. ' ..incentives.'.-.--.' ••.;-. :. ; . ;.'"•;•'•','. •" "; • . . -." ' •/' .
• There are established industry .and state practices and standards that can
be used as a basis for constructing a comprehensive program.
EPA identified several characteristics shared by successful voluntary programs.
These include:
• The program must have goals that are clearly defined up front — This
assures that participants are working toward the same objectives and
provides a framework that increases efficiency.
• The program must have achievable goals — The goals of the program must
be realistic in order to ensure widespread participation and avoid wasting
resources. .1
70
SPCC GUIDANCE TOH! REGIONAL I
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• The program must offer useful incentives — Successful voluntary programs ;
offer benefits to attract and maintain the interest of participants. Such
incentives have included:
Cost savings/long-term profits/more efficient operations (release
prevention reduces product loss);
Publicity (newsletters, press releases, etc.);
- Recognition (certificates of participation and achieverhent);
- Technical assistance (advice and sources of information); ;
- Reducing or eliminating the heed for regulations; and
- Other types of assistance, such as assistance in identifying -
Federal/State/private financial options (i.e., information on insurance
programs, State grant programs, etc.).
EPA will vigorously pursue other incentives, and will work with interested
parties over the coming months to help identify them.
• The program must have a structure in place to work with all potentially
affected and interested parties and promote continued participation — We .
believe it is imperative that a voluntary program ensure broad participation
and be structured so that all involved can affect the decision-making
process.
• The program must effectively track progress and disseminate success stories
— Project tracking enables the Agency to determine whether the program .
is successful, identify areas where adjustments are needed, resolve issues,
and plan future goals. Success stories help foster new involvement.
• The program must have the support of the lead agency, the public, and
participants — For a program to be successful, it needs a real and strong
commitment of those involved. .
In keeping with the Agency's initiatives to develop innovative, common-sense
approaches to environmental problems, EPA supports a voluntary prevention and
cleanup program as a first step in addressing the environmental problem presented by
contamination from AST facilities. Industry representatives have expressed their support
for such a program as a more cost-effective, flexible alternative than traditional
regulation. EPA fully supports such an attempt, and believes it will be successful,
provided that it has the full commitment of those involved. The Agency believes it is
essential that stakeholders have the opportunity to participate in the development and
execution of this voluntary program and will establish an open process for public input
into the program's design and implementation.
71
Slpe-e-GUIE>ANG€"FOR-REOf©NAt-INSPECTORS- : - -™:—-,™,«;,m „-..„,-;,„_,,—„„,._„,„ ' „„ , _„ H_89
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REFERENCES
American Petroleum Institute (API), "Aboveground Storage Tank Survey," prepared by
Entropy Limited, April 1989.
American Petroleum Institute (API), "A Survey of API Members' Aboveground Storage
Tank Facilities," prepared by API Health and Environmental Affairs Department,
July 1994.
American Petroleum Institute (API), "Welded Steel tanks for Oil Storage," API Standard
; 650, July 1993.
Means Site Work and Landscape Cost Data, llth Edition, R.S, Means Co., 1991.
National Fire Protection Association (NFPA), Flammable and Combustible Liquids Code
•'• (NFPA 30) Section 2-2.3.3, 1993 edition.
New York State Department of Environmental Conservation, (NYDEC Database).
Office of Management and Budget Circular No. A-94 (57 FR 53519).
Suffolk County Department-of Health Services, "Final Report: Tank Corrosion Study,"
1988. ' ,'< ," . . .
U.S. Coast Guard and U.S. Department of Transportation, "Control of Pollution by Oil
and Hazardous Substances, Discharge Removal," 33 CFR part 153, 7-1-93 edition.
• ' ' '' " 1 .,' ' ' -
U.S. Environmental Protection Agency, "Discharge of "Oil," 40 CFR part 153, 7-1-93
edition.
U.S. Environmental Protection Agency, Emergency Response Division, "Estimate of the
Number of Aboveground Storage Tanks at Onshore Facilities," October 1994.
"''*,- - > , • ,
U.S. Environmental Protection Agency, Emergency Response Division, "Investigating the
Risk Posed by Different Sizes of Facilities Potentially Regulated by the Oil
Pollution Prevention Regulation," May 1993. ..
U.S. Environmental Protection Agency, Emergency Response Division, "Regulatory
Impact Analysis of Revisions to the Oil Pollution Prevention Regulation," Draft
Report, 1991.
73
SPCC'GtliaANCETOR'RE'GtDN^II'rNSPECTORS"
H-90
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Appendix H: Other Policy Documents
U.S. Environmental Protection Agency, Emergency "Response Division, "Regulatory
Impact Analysis of Revisions to the Oil Pollution Prevention Regulation (40 CFR
llij to Implement the Facility Response Planning Requirements of the Oil
Pollution Act of 1990," June 1994.
U.S. Environmental Protection Agency, Emergency Response Division, "Spill Prevention,
Control, and Countermeasures Facilities Study," January 1991. ' ;
U.S. Environmental Protection Agency; Emergency Response Notification System,
(ERNS Database).
U.S. Environmental Protection Agency, "Oil Pollution Prevention," 40 CFR part 112, 7-1-
93 edition. '
\v ' ^ ' " - ^ ' •> .' ,,
U.S. Environmental Protection Agency, "Oil Pollution Prevention; Non-Transportation-
Related Onshore Facilities," 58 FR8824, February 17, 1993.
U.S. Environmental Protection Agency, "Standards for Owners and Operators of
Hazardous Waste Treatment, Storage, and Disposal Facilities," 40 CFR part 264,
7-1-93 edition;
U.S.Environmental Protection Agency, "Technical Standards and Corrective Action
Requirements for Owners arid Operators of Underground Storage Tanks (USTs),"
40 CFR part 280, 7-1^93 edition.
Virginia Department of Environmental Quality {VADEQ),^The Virginia DEQ
Abovegrourid Storage Tank Regulations," April 4, ,1994.
Virginia Regulation 680-14-12: Facility and AST 'Registration Requirements, effective
^September 22, 1993. . '' ,'
"World Spm Briefs," Golub's OilPollution Bulletin, Vol. 5 No. 12, May 1993, p. 7.
74
SPCC GUIDANCE FOR REGIONAL IN*
-------
. ApperTOixFroifierPolicy Documents
APPENDIX A: STATE REGULATIONS
EPA reviewed current and proposed AST regulations for the 50 States to gather
information on liner systems and to estimate the number of facilities currently required to
use liners as a result of State regulation. Exhibit A-1 summarizes the results of this
review. The following components of AST regulatory programs were examined:
• Status of AST requirements (i.e., full AST regulations, NFPA or other fire
codes only, proposed AST regulations with NFPA or other fire codes, or
proposed AST regulations only);
• Status of liner requirements (current, proposed, or none);
. • Status of spill data collection (full AST regulations, some spill data
collection, AST data basfe started but is not extensive or easy to access, or
spill data collected but not required by regulation); and .
-''•..';. Whether a cost/benefit data analysis was performed.
Section 3.1.2 provides a more detailed 'discussion of the nine States (AK, CO, FL, MO,
NJ, NY, RI, SD, and WI) that have promulgated or-proposed regulations specifying the
use of "impermeable" secondary containment systems, liners, or other diversionary
structures and systems. v .
75
H-92
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Appendix H: Other Policy Documents
EXHIBIT A-l
STATE REGULATIONS33
STATE
Alabama
Alaska
Arizona
Arkansas
California
Colorado
(Connecticut
Delaware
Florida
1 Georgia
Hawaii
Idaho
Illinois
Indiana >
Iowa
Kansas
Kentucky
Louisiana
BASIS FOR
AST
REQUIRE-
MENTS
1
;, .. ' *
1
X
X
• 1
1 - • ' • 1 '
1
X
1
1
1 • :,
1
1
" .' 1
1
''1 '-
J
LINER
REQUIREMENT
Current
X
••
. >
X
"-.'•
', -"• '•
Proposed
;
X
Spill Data
Collected
Some
'. • ' * ••
* '
, . * •'
Some
'- . x
Some
' - •
. . '• •-..'-•
••..'•I -
'•'.••*
•--*
Cost/B-nefit
•Dftga
V..
• X
; Comments
Guidelines available
Liners required at new facilities
•only
• '. . •'. ,. , • ' -.
Working on draft regulations
Proposed AST regulations
Proposed AST regulations
•
Began data base in '92; no
regulations; local control
33 Information as of April 1994.
LEGEND
X
*
o
AST regulation „
NFPA or other fire codes
data base started, but not extensive nor easy to access
spill data is collected, but not required by regulation
proposed AST regulation
76
SPCC GUIDANCE FOR-RCCIONAL I
h9S
-------
STATE
Maine '
Maryland
Massachusetts
Michigan
. Minnesota .
Mississippi
Missouri
Montana
Nebraska
Nevada
New
Hampshire
New Jersey
New Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
BASIS FOR
' '• -.AST - ' ,
REQUIRE-
MENTS
' 1
X
X
1
;.x- . •;
1 .
1
1
1
1
•' '. 1
X '
', ' ' . I
X
1
i
.1
i
i
X
LINER
REQUIREMENT
Current
X
.
X
x
-
•\ -
'' -
Proposed
.
. '• '
Spill Data
Collected
o .
•
X
X
* •
X
1 - • •*•
X
.X
o ''•'•'
M 0
O
' -, o
1 * '
Cost/Benefit
Data
-, • . '.
X
X
-
X
Comments
Some oil terminal regulations;
proposed AST regulations
currently under development
Regulations only cover tanks >
10,000 gallons
No regulations; local control ,
Cost/benefit data from the failed
liner requirement available
Requires liners on a case by case
basis
No regulations; local control
Proposed regulations currently
under development; no
provisions available
New and retrofit must meet API
standards • ,
LEGEND
x
i
AST regulation
NFPA. or other fire codes
data base started, but not extensive nor easy to access
spill data is collected, hut not required by regulation
proposed AST regulation . ,
77
srecrGtJlDANCEFDR'-REGlONA'pTWSPECTORS"
H-94
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Appendix H: Other Policy Documents
STATE
Rhode Island
South Carolina
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia
.•
Washington
West Virginia
Wisconsin
Wyoming
BASIS FOR
AST
REQUIRE-
MENTS
X
1
X
1
X
1 •
.• ' 1
•;"
X
X
••' , -i1 ;':
X
- -r ;-t - .
LINER.
REQUIREMENT
Current '
X
X
'
' ; r
x
Proposed
• '' ;
Spill Data
Collected
X
o
'•
.
-• •
. -
-•*'''•;
'.,
Cost/Benefit
Data
' , • • '
i
Comments
. . •
No regulations; local control
<
f ',
•
Regulation applies to facilities '
with AST capacity in excess of
25,000 gallons of oil. Requires
installation of release prevention
barriers either under or in the
bottom of new or retrofitted
tanks. '
Only covers marine terminals
LEGEND
X =
1
•* ' =
o =
AST regulation /
"NFPA or other fire codes - ;
data base started, but not extensive nor easy to access
spill data is collected, but not required by regulation
proposed AST regulation
78
SPCC GUIDANCE FOR REGIONAL INSPECTORS"
=T-95
-------
APPENDIX B: MODEL FACILITIES
This appendix describes how EPA used previous analyses to determine how the
model facilities developed for this analysis would represent the diversity of facilities with
ASTs that do not have liner systems in place.
B.I Allocation of AST Facilities into Size and Use Categories , - .
As described in Chapter 2, the universe of AST facilities that currently is
estimated not to have liners was divided into size categories based on their storage
capacity and use categories (see .Exhibit 2-6). This classification scheme has been used in
a previous EPA analysis supporting revisions to the Oil Pollution Prevention
regulation.34 EPA's earlier analysis .also estimated the storage capacity for typical (i.e.,
representative) facilities in eight of the nine size and use categories. (Because only a
negligible number of large facilities were estimated to exist, no typical storage capacity
was estimated for this category.) The results of. the analysis are presented in Exhibit B-l.
EXHIBIT B-l
TYPICAL STORAGE CAPACITIES FOR FACILITIES
FROM PREVIOUS EPA ANALYSIS
Size and Use
Category
Small
Medium
Large
Production
37,800 gallons
96,600 gallons
Not Applicable
Storage/Distribution
10,000 gallons
250,000 gallons
21,400,000 gallons
Storage/Consumption
2,000 gallons
205,000 gallons
4,028,000 gallons
To ensure consistency in its analyses, EPA used the typical storage capacities from
this earlier analysis to determine which model facilities .developed in this analysis best
represented each size and use-category. Specifically, EPA compared the typical storage
capacities used in the previous analysis (and presented in Exhibit B-l) with the assumed
storage capacities of the model facilities developed for this report. If a single model
facility from this report closely agreed with the storage capacity from the earlier analysis,
then that model facility was assumed to represent all of the AST facilities that currently
do not have liners in that size and use category (as presented in Exhibit 2-6). For
34 U.S. EPA, Emergency Response Division, "Regulatory Impact Analysis of Revisions to the Oil
Pollution Prevention Regulation (40 CFR 112) to Implement the Facility Response Planning
Requirements of the Oil Pollution Act of 1990", June 1994.
79
FO"R"REGTOiTOl|: INSPECTORS""
H-96
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Appendix H: Other Policy Documents
example, Model Facility 1 has an assumed storage capacity of 2,000 gallons, which equals-.
the typical storage capacity of small storage/consumption facilities from EISA's earlier
analysis. Consequently, all 198,529 small storage/consumption facilities are considered to
be represented by Model Facility 1, .
Where the typical storage capacity of facilities in a size and use category did not
closely agree with a single model facility fromMhis report, two model facilities were used
to represent that^size and use category. The allocation of facilities between the two
model facilities generally was based on the difference between the typical storage
category, as presented in Exhibit B-l, and the assumed storage capacities of the model
facilities. For example, small storage/distribution facilities are estimated to typically have
a total storage capacity of approximately 10,000 gallons, for which no single model facility
in this report corresponds closely. Therefore, small storage/distribution facilities are best
represented by amix of Model Facilities 1 and 2, which are assumed to have 2,000 and
24,000 .gallons of storage capacity, respectively, As the "typical" small storage/distribution
facility (10,000 gallons) is closer in storage capacity to that of Model Facility 1 (2,000
gallons) than Model Facility 2 (24,000 gallons), facilities were allocated disproportionately
to Model Facility 1. Of the estimated 4,554 small storage/distribution facilities, 2,898
-facilities ate estimated to be best represented by Model Facility 1, and the. remaining
1,656 facilities are estimated to be best represented by Model Facility 2. The model
facilities selected to represent each size and use category and the allocation ratios are
presented in Exhibit B-2.
' .''. x: ' " -" ., -:. .. :' EXfflBITB-2 , • .-'••;'.:.;- ' / • '•
CATEGORIZATION OF FACILITIES NOT CURRENTLY REQUIRED
. •'. '"' -', - '--. Vy:/>;/Y: TO INSTALL LINERS '' • -;.- \V-V- '
Size and
•.-.•Use", ;
Category
Small
Medium
Large
^Production '•
Model Facility 2 (34%)
Model Facility 3 (66%)
Model Facility 4
(100%)
Not Applicable
Storage/Distribution
Model Facility 1 (64%)
Model Facility 2 (36%)
Model Facility 3 (41%)
Model Facility 5 (59%)
Storage/Consumption
Model Facility 1
(ibo%)
Model Facility 4 (54%)
Model Facility 5 (46%)
Model Facility 6 (100%) ,
In the case of medium storage/distribution facilities, however, an alternative
formula,was used. The medium storage/distribution category of facilities includes
gasoline service stations with ASTs. Historically, most gasoline service stations stored
product in USTs; however, where land limitations require or building codes allow, ASTs
80
SPCC GUIDANCE FOR REGIONAL INSPECTORS
TT-97
-------
Appendix H: Other Policy Documents
are used at these facilities for product storage. Model 3, with a storage capacity of
45,000 gallons, is an effective representation, of such medium-sized gasoline service
stations. As shown in Exhibit 3-2, there are aft estimated 5,967 medium-sized gasoline
service stations. Therefore, 5,967 of the 14,681 medium storage/distribution facilities are
represented by Model 3, and the remaining 8,714 are represented by Model 5, whose
assumed Storage capacity of 325,000 gallons is closest to the typical storage capacity of
facilities in this size and use category (i.e., 250,000 gallons).
To determine the total number of facilities that each model facility represents, the
percentages in Exhibit B-2 were multiplied by the estimated number of AST facilities i:
the corresponding size and use category in Exhibit 2-6 and the amounts were summed
in
model facility:
* iiiuiuput/u uy me caimmiGu iiuiiiuci ui fw i laiamics ill
category in Exhibit 2-6 and the amounts were summed by
• Model Facility 1: 201,427
• Model Facility 2: 49,296
• Model Facility 3: 97,277
• Model Facility 4: 55,623
• Model Facility 5: 13,663
2,898 small storage/distribution facilities .
All- small storage/consumption facilities
1,656 small storage/distribution facilities
47,640 small production facilities
91,310 small production facilities
5,967 medium storage/distribution facilities
All medium production facilities
5,880 medium storage/consumption facilities
Model Facility 6: 3,927
8,714 medium storage/distribution facilities
4,949 medium storage/consumption facilities
All large storage/consumption facilities
421,213 facilities
81
'SPCC GUTDA*NCE FOR'REGtOWAriNSFECTORS-
H-98
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Appendix H: Other Policy Documents
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
JUL I 4 2000 OFFKEOF
SOLID WASTE AND EMERGENCY
Mr. Chris Early RESPONSE
Safety-Kleen Corporation
1301 Gervais Street
Columbia, SC 29201
Dear Mr. Early:
Thank you for your e-mail of May 31, 2000. Through this letter, we respond to
the questions you posed in your e-mail.
Your first set of questions concerned the meaning of the terms "transportation-
related" and "non-transportation-related" as they relate to SPCC facilities. You also
raised issues concerning transfers of oil in the first set of questions. You posed the fact
situation of "a rail car containing oil that enters my site by crossing site boundaries."
You added that the "rail car is one of many rail cars and is the only rail car containing
oil." We will repeat your questions, and answer them immediately below. We note that
we have coordinated our response with the U.S. Department of Transportation (DOT).
1. Question: "If the rail car is passing through my facility and the oil contained in this
rail car is not loaded or unloaded is it subject to the SPCC requirements including
SPCC Plan and containment system/diversionary structure or proof of impracticability
requirements? Or, is this rail car subject to DOT requirements because it is considered
as a transportation-related unit?"
Answer: As a general rule, we will presume that the rail car is Considered to be a
"transportation-related facility" under the 1971 Memorandum of Understanding (MOU)
between DOT and the U.S. Environmental Protection Agency (EPA) if it is consigned to
your property or is consigned elsewhere and is being stored incidental to transportation
in commerce. Storage incidental to transportation in commerce is storage between the
time the oil is offered for transportation to a carrier until the time that it reaches its
destination and is accepted by the consignee, assuming no circumstances marking an
end to the transportation process. EPA will consider all the circumstances concerning
the presence of the rail car at the facility before determining that there has been an end
to the transportation process and a beginning of non-transpbrtation-related storage
subject to SPCC requirements. If non-transportation-related storage has begun, the rail
car will be subject to SPCC requirements if it contains above the regulatory threshold
Recycled/Recyclable
Printed with Soy/Canola Ink on paper that
contains at least 50% recycled fiber
SPCC GUIDANCE FOR REGIONAL INSPECTORS H-99
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Appendix H: Other Policy Documents .-
amount and there is a reasonable possibility of discharge from the rail car to navigable
waters or adjoining shorelines. If the rail car is consigned to the Safety-Kleen facility, as
indicated on shipping papers, bills of lading, or other shipping documentation, then
transportation of the rail car ends once it arrives at the facility, and the rail car is subject
to SPCC requirements. However, if the rail car is consigned to a different facility and is
merely passing through the Safety-Kleen facility on its way to its consigned destination
with no unreasonable delays, then the rail car is considered to be in storage incidental
to transportation in commerce and is not subject to SPCC requirements. Instead the
car is subject to applicable DOT requirements for the duration of such transportation.
2. Question: "If this rail car stops on my property for any period of time but the oil in
the rail car is never loaded or unloaded is it subject to SPCC requirements at any time
including SPCC Plan and containment system/diversionary structure or proof of
impracticability requirements?"
Answer: See the answer to Question 1 above.
3. Question: "If the rail car is loaded or unloaded at any time is it subject to SPCC
Plan and containment system/diversionary structure or proof of impracticability
requirements?"
Answer: The loading or unloading of the rail car may mark an end to the transportation
process and the beginning of non-transportation-related storage, triggering all SPCC
requirements, assuming that the rail car stores oil in an amount above the regulatory
threshold and that there is a reasonable possibility of discharge to navigable waters or
adjoining shorelines. In this case, the rail car itself may become the non-transportation-
related facility even if no other containers at the property would qualify the property as a
non-transportation-related facility.
4. Question: "If the rail car is loaded/unloaded intermittently (i.e., over a period of 14
days oil in the rail car is unloaded on two consecutive Mondays) is the rail car subject to
SPCC requirements only during the loading events including SPCC Plan and
containment system/diversionary structure or proof of impracticability requirements?"
Answer: The loading or unloading of the rail car, whether intermittent or not, may mark
an end to the transportation process and the beginning of non-transportation-related
storage, triggering all SPCC requirements, assuming that the rail car stores oil in an
amount above the regulatory threshold and that there is a reasonable possibility of
discharge to navigable waters or adjoining shorelines. In this case, the rail car itself
may become the non-transportation-related facility even if no other containers at the
property would qualify the property as a non-transportation-related facility.
5. Question: "If the rail car enters my site (1/3 crosses the facility boundaries), is any
portion of the rail car subject to SPCC Plan requirements including SPCC Plan and
SPCC GUIDANCE FOR REGIONAL INSPECTORS H-100
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Appendix H: Other Policy Documents
containment system/diversionary structure or proof of impracticability requirements?"
Answer: If by entry on the site, the rail car has reached its ultimate destination, then
the transportation process has ended and non-transportation-related storage has
begun, triggering all SPCC requirements, assuming that the rail car stores oil in an
amount above the regulatory threshold and that there is a reasonable possibility of
discharge to navigable waters or adjoining shorelines. In this case, the rail car itself
becomes the non-transportation-related facility even if no other containers at the
property would qualify the property as a non-transportation-related facility.
Your second set of questions posited the fact situation that you demonstrate in
your SPCC Plan that it is impracticable to provide containment systems/diversionary
structures and instead provide a strong oil contingency plan.
1. Question: "Does the word 'demonstrate' used here indicate that the SPCC Plan will
only require certification by a Registered Professional Engineer no matter the reason
used to determine impracticability?"
Answer: The owner or operator of the facility must demonstrate impracticability if he
cannot provide secondary containment. The Professional Engineer must certify that
demonstration of impracticability. If the Regional Administrator disagrees with the
owner or operator's determination, he may require that the owner or operator amend his
Plan.
2. Question: "In developing a strong Oil Contingency Plan who determines if the plan
is 'strong' enough to respond and prevent released oil from reaching navigable water?"
Answer: The owner or operator of the facility must determine that the Contingency
Plan is adequate to meet regulatory requirements. The Professional Engineer must
certify that determination. If the Regional Administrator disagrees with the owner or
operator's determination, he may require that the owner or operator amend his Plan.
Your third set of questions asked "at what point the following transportation-
related facility units become non-transportation related and subject to SPCC
requirements."
a. Question: "Rail car"
Answer: A rail car may or may not be transportation-related, depending on the use to
which it is put. See the 1971 MOU, § II(1)(F), (1)(J), and (2)(D).
b. Question: "Any vehicle with oil capacity of 660 gallons."
Answer: A vehicle may or may not be transportation-related, depending on the use to
SPCC GUIDANCE FOR REGIONAL INSPECTORS H-101
-------
" "Appendix"fl; 6ther Policy Documents^-
which ft is fH&
cc: Susan Goreky, DOT
SJ^C GUIDANCE FOR
H-102
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Appendix H: Other Policy Documents
Melissa Young, Esq.
Government Affairs Counsel
Petroleum Marketers Association of America
1901 N. Fort Meyer Drive
Suite 1200
Arlington, Virginia 22209-1604
Dear Ms. Young:
Thank you for your letter to Administrator Whitman of February 5, 2001, which she
has referred to me for an answer.
You explained that a marketer was notified by an Environmental Protection Agency
(EPA) inspector that her facility, which is below the 42,000 gallon underground storage
tank threshold capacity, would need a Spill Prevention, Control, and Countermeasure
(SPCC) Plan, because she parks her 2,500 gallon cargo tank motor vehicle at the facility
in the evenings. You noted that it is used to deliver petroleum products in commerce, not
as a mobile fueling facility and that it is emptied before it is parked for the evening.
EPA presumes that a cargo tank motor vehicle that contains no oil, other than any
residual oil present in an emptied vehicle when it is parked at the facility in the evening, is
a highway vehicle used for the transport of oil in interstate or intrastate commerce, and is
therefore transportation-related, and not subject to SPCC jurisdiction. 40 CFR 112,
Appendix A, Section II(2)(D). You should be aware, however, if the vehicle were to be
used at any time in a fixed operating non-transportation mode, such as the storage or
transfer of oil in any amount, other than any residual oil present in an emptied vehicle at the
end of the day, then it would become subject to the SPCC rule if there were a reasonable
possibility of discharge from the vehicle to navigable waters or adjoining shorelines. See
40 CFR 112.3(c); and 40 CFR 112, Appendix A, Section 11(1 )(F).
To determine if a fixed operating non-transportation mode has begun, and therefore
EPA SPCC jurisdiction arises, an EPA inspector would will look at all the circumstances at
a particular facility. Here, such circumstances might include whether the vehicle is
functioning as a storage tank, supplementing storage capacity or transferring oil at the
facility. We believe the vehicle you described is operating in a transportation-related
SPCC GUIDANCE FOR REGIONAL INSPECTORS H-103
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Appendix H: Other Policy Documents
mode, and therefore, no EPA SPCC regulatory jurisdiction arises. We note that if the
vehicle itself were to be subject to the SPCC rule, it exceeds the SPCC regulatory
threshold regardless of any other storage or use of oil at the facility. We also note that if it
is used for the transport of oil exclusively within the confines of a facility and is not intended
to transport oil in interstate or intrastate commerce, it may be subject to the SPCC rule. 40
CFR 112, Appendix A, Section 11(1 )(J).
Again, thank you for your letter. Please do not hesitate to contact us again
if you have other questions concerning EPA's oil program. If you have any questions about
this letter, please contact Hugo Fleischman at 703-603-8769 or Mark Howard at 703-603-
8715.
Sincerely,
Stephen F. Heare, Acting Deputy Director,
Office of Emergency and Remedial Response
cc: Clifford J. Harvison, NTTC
James Malcolm, MC 2131
Susan Gorsky, DOT
SPCC GUIDANCE FOR REGIONAL INSPECTORS H-104
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Appendix H: Other Policy Documents
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
OFFICE OF
SOLID WASTE AND EMERGENCY
RESPONSE
OSWER 9360.8-38
MEMORANDUM
SUBJECT: Use of Alternative Secondary Containment Measures at Facilities
Regulated under the Oil Pollution Prevention Regulation (40 CFR Part
112)
FROM: Marianne Lamont Horinko
Assistant Administrator
TO: Oil National Policy Managers, Regions 1-10
PURPOSE
This memorandum amends the guidance issued on April 29, 1992 (i.e., Use of
Alternative Secondary Containment Measures at Facilities Regulated under the Oil
Pollution Regulation (40 CFR Part 112), (OSWER 9360.8-37) concerning the potential
use of certain double-wall aboveground storage tanks (ASTs) for secondary
containment purposes. A copy is attached for your reference. This guidance also
clarifies when shop-built double-walled ASTs satisfy the applicable secondary
containment requirements in the Spill Prevention, Control, and Countermeasure
(SPCC) rule, found at 40 CFR part 112. We take this step because larger shop-built
ASTs that use the protective measures described in the 1992 guidance are generally
protective of the environment under certain circumstances.
BACKGROUND
On April 29, 1992, EPA issued guidance on how certain shop-built double-wall
ASTs may comply with the secondary containment requirements of §1 12.7(c). The
guidance discussed compliance with §112.7(c) only, and did not discuss compliance
with other applicable SPCC provisions. We said at the time that "there should be many
situations in which protection of navigable waters substantially equivalent to that
provided by the secondary containment systems listed in section 1 12.7(c) could be
provided by alternative AST systems that have capacities generally less than 12,000
gallons and are installed and operated with protective measures other than secondary
containment dikes."
Internet Address (URL) • http://www.epa.gov
Recycled/Racyciabla . Printed with Vegetable Oil Based Inks on Recycled Paper (Minimum 30% Postconsumer)
SPCC GUIDANCE FOR REGIONAL INSPECTORS H-105
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Appendix H: Other Policy Documents
OSWER 9360.8-38
DISCUSSION
SPCC secondary containment requirements. Section 112.7(c) requires that
the owner or operator:
"Provide appropriate containment and/or diversionary structures or equipment to
prevent a discharge as described in §112.1 (b). The entire containment system,
including walls and floor, must be capable of containing oil and must be
constructed so that any discharge from a primary containment system, such as a
tank or pipe, will not escape the containment system before cleanup occurs. At
a minimum, you must use one of the following preventive systems or its
equivalent:
(1) For onshore facilities:
(i) Dikes, berms or retaining walls sufficiently impervious to contain
oil;
(ii) Curbing;
(iii) Culverting, gutters or other drainage systems;
(iv) Weirs, booms or other barriers;
(v) Spill diversion ponds;
(vi) Retention ponds; or
(vii) Sorbent materials.
(2) For offshore facilities:
(i) Curbing, drip pans; or
(ii) Sumps and collection systems."
After nearly a decade of evaluation of the construction, performance, and use of certain
shop-built double-wall ASTs, we believe that they may serve as an "equivalent"
preventive system for purposes of §112.7(c).
In 1992, we recognized that a shop-built double-wall AST with a capacity
"generally less than 12,000 gallons" that was installed and operated with protective
measures other than a secondary containment dike might meet the secondary
containment requirements of §112.7(c). We described those protective measures as
"when the inner tank is an Underwriters' Laboratory-listed steel tank, the outer wall is
constructed in accordance with nationally accepted industry standards (e.g., those
codified by the American Petroleum Institute, the Steel Tank Institute, and the American
Concrete Institute), the tank has overfill prevention measures that include an overfill
alarm and an automatic flow restrictor or flow-shutoff, and all product transfers are
constantly monitored."
Today, after nearly a decade of experience in which we have seen the
construction, performance, and use of shop-built double-wall ASTs, we note a low
SPCC GUIDANCE FOR REGIONAL INSPECTORS H-106
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Appendix H: Other Policy Documents
OSWER 9360.8-38
occurrence of discharges from such tanks, including tanks with a capacity of 12,000
gallons or more. In some cases, such tanks provide secondary containment where
none existed before, or superior environmental protection to alternative containment
systems previously used. We believe that a 12,000 gallon limitation on the use of
certain shop-built double-wall ASTs is therefore no longer necessary, and believe that
shop-built double-wall ASTs that use the protective measures described in 1992
generally satisfy the secondary containment requirements found in §112.7(c).
Bulk storage secondary containment requirements (§112,8(c)(2));
inspection requirements (§112.8(c)(6)). For the same reasons outlined above, we
also believe that shop-fabricated double-wall AST, regardless of size, may generally
satisfy not only the secondary containment requirements of §112.7(c), but also the bulk
storage secondary containment requirements found at §112.8(c)(2). Section
112.8(c)(6) requires the owner or operator to conduct integrity testing on a regular
schedule and whenever he makes repairs. The owner or operator must also frequently
inspect the outside of the container for signs of deterioration, discharges, or
accumulation of oil inside diked areas. To comply with the requirement to frequently
inspect the outside of the tank, an owner or operator must inspect the inner wall and
interstitial spaces of a shop-built double-wall AST. We recommend the use of
automatic detection devices to detect discharges into the interstitial space. Owners or
operators should conduct this integrity testing and inspection in accordance with
industry standards, when practicable. One industry standard presently available is
"SP001-00, Standard for Inspection of In-Service Shop-Fabricated Aboveground Tanks
for Storage of Combustible and Flammable Liquids." Other applicable standards may
be developed in the future.
Other applicable SPCC requirements. While shop-fabricated double-wall
ASTs may satisfy the requirements of §112.7(c) and §112.8(c)(2), such tanks must also
continue to satisfy all other applicable SPCC requirements. For example, the facility
owner or operator must satisfy §112.7(h) requirements for tank car and tank truck
loading/unloading racks if he transfers oil in bulk to those tanks from highway vehicles
or railroad cars. If such transfers occur, where loading/unloading area drainage does
not flow into a catchment basin or treatment facility designed to handle spills, a quick
drainage system must be used. The containment system must be designed to hold at
least the maximum capacity of any single compartment of a tank car of tank truck
loaded or unloaded at the facility.
Additionally, any piping, equipment, or device not contained within a double-wall
AST is subject to the requirements of §112.8(b)(3) and (4), if such piping, equipment, or
device is in an undiked area.
CONCLUSION/IMPLEMENTATION Should you have any questions concerning this
memorandum, please contact Hugo Fleischman, of my staff, at 703-603-8769.
SPCC GUIDANCE FOR REGIONAL INSPECTORS H-107
-------
Appendix H: Other Policy Documents
OSWER 9360.8-38
Attachment
cc: Michael B. Cook
Elaine Davies
Andrew Gordon
David Dreiich
Oil Removal Managers
OERR Records Manager, IMC 5202G
OERR Documents Coordinator, HOSC 5202G
Jeff Josephson, Superfund Lead Region Coordinator, USEPA Region 2
NARPM Co-Chairs
Doug Kodama, Oil Lead Region Coordinator, USEPA Region 2
SPCC GUIDANCE FOR REGIONAL INSPECTORS H-108
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Federal Register/Vol. 68, No. 10/Wednesday, January 15, 2003/Proposed Rules
1991
§ 1794.51 Preparation for scoping.
(a) As soon as practicable after RUS
and the applicant have developed a
schedule for the environmental review
process, RUS shall have its notice of
intent to prepare an EA or EIS and
schedule scoping meetings (§ 1794.13)
published in the Federal Register (see
40 CFR 1508.22). The applicant shall
have published, in a timely manner, a
notice similar to RUS' notice.
A A A A A
14. Section 1794.52(d) is amended by
removing the last sentence and adding
a new sentence at the end of the
paragraph to read as follows:
§ 1794.52 Scoping meetings.
A A A A A
(d) * * * The applicant or its
consultant shall prepare a record of the
scoping meeting. The record shall
consist of a transcript when a traditional
meeting format is used or a summary
report when an open house format is
used.
A A A A A
15. Section 1794.53 is revised to read
as follows:
§ 1794.53 Environmental report.
(a) After scoping procedures have
been completed, RUS shall require the
applicant to develop and submit an ER.
The ER shall be prepared under the
supervision and guidance of RUS staff
and RUS shall evaluate and be
responsible for the accuracy of all
information contained therein.
(b) The applicant's ER will normally
serve as the RUS EA. After RUS has
reviewed and found the ER to be
satisfactory, the applicant shall provide
RUS with a sufficient number of copies
of the ER to satisfy the RUS distribution
plan.
(c) The ER shall include a summary
of the construction and operation
monitoring and mitigation measures for
the proposed action. These measures
may be revised as appropriate in
response to comments and other
information, and shall be incorporated
by summary or reference into the
FONSI.
16. Section 1794.54 is revised to read
as follows:
§ 1794.54 Agency determination.
Following the scoping process and the
development of a satisfactory ER by the
applicant or its consultant that will
serve as the agency's EA, RUS shall
determine whether the proposed action
is a major Federal action significantly
affecting the quality of the human
environment. If RUS determines the
action is significant, RUS will continue
with the procedures in subpart G of this
part. If RUS determines the action is not
significant, RUS will proceed in
accordance with §§ 1794.42 through
1794.44, except that RUS shall have a
notice published in the Federal Register
that announces the availability of the
EA and FONSI.
§1794.61 [Amended]
17. Section 1794.61 is amended by:
A. Removing paragraph (b).
B. Redesignating paragraph (a) as the
introductory text; paragraph (a)(l) as (a);
paragraph (a)(2) as (b); and paragraph
(a)(3) as (c).
Dated: December 24, 2002.
Elaine D. Stockton,
Acting Administrator, Rural Utilities Service.
[FR Doc. 03-713 Filed 1-14-03; 8:45 am]
BILLING CODE 3410-15-P
DEPARTMENT OF DEFENSE
Department of the Army, Corps of
Engineers
33 CFR Part 328
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Parts 110, 112, 116, 117,122,
230, 232, 300, and 401
[FRL-7439-8]
RIN 2040-AB74
Advance Notice of Proposed
Rulemaking on the Clean Water Act
Regulatory Definition of "Waters of the
United States"
AGENCIES: U.S. Army Corps of
Engineers, Department of the Army,
DOD; and Environmental Protection
Agency.
ACTION: Advance notice of proposed
rulemaking.
SUMMARY: The U.S. Army Corps of
Engineers (Corps) and the
Environmental Protection Agency (EPA)
are today issuing an advance notice of
proposed rulemaking (ANPRM) in order
to obtain early comment on issues
associated with the scope of waters that
are subject to the Clean Water Act
(CWA), in light of the U.S. Supreme
Court decision in Solid Waste Agency of
Northern Cook County v. U.S. Army
Corps of Engineers, 531 U.S. 159 (2001)
(SWANCC).
Today's ANPRM requests public
input on issues associated with the
definition of "waters of the United
States" and also solicits information or
data from the general public, the
scientific community, and Federal and
State resource agencies on the
implications of the SWANCC decision
for jurisdictional decisions under the
CWA. The goal of the agencies is to
develop proposed regulations that will
further the public interest by clarifying
what waters are subject to CWA
jurisdiction and affording full protection
to these waters through an appropriate
focus of Federal and State resources
consistent with the CWA. The input
received from the public in response to
today's ANPRM will be used by the
agencies to determine the issues to be
addressed and the substantive approach
for a future proposed rulemaking
addressing the scope of CWA
jurisdiction.
Pending this rulemaking, should
questions arise, the regulated
community should seek assistance from
the Corps and EPA, in accordance with
the joint memorandum attached as
Appendix A.
DATES: In order to be considered,
comments or information in response to
this ANPRM must be postmarked or e-
mailed on or before March 3, 2003.
ADDRESSES: Comments may be
submitted electronically, by mail, or
through hand delivery/courier. Mail
comments to: Water Docket,
Environmental Protection Agency,
Mailcode 4101T, 1200 Pennsylvania
Ave., NW., Washington, DC 20460,
Attention Docket ID No. OW-2002-
0050.
FOR FURTHER INFORMATION CONTACT: For
information on this ANPRM, contact
either Donna Downing, U.S.
Environmental Protection Agency,
Office of Wetlands, Oceans and
Watersheds (4502T), 1200 Pennsylvania
Avenue N.W., Washington, DC 20460,
phone: (202) 566-1366, e-mail:
CWAwaters@epa.gov, or Ted Rugiel,
U.S. Army Corps of Engineers, ATTN
CECW-OR, 441 G Street NW.,
Washington, DC 20314-1000, phone:
(202) 761-4595, e-mail:
Thaddeus./.Rugiel®
HQ02.USACE.ARMY.MIL.
SUPPLEMENTARY INFORMATION:
I. General Information
A. Potentially Regulated Entities
Persons or entities that discharge
pollutants (including dredged or fill
material) to "waters of the U.S." could
be regulated by a rulemaking based on
this ANPRM. The CWA generally
prohibits the discharge of pollutants
into "waters of the U.S." without a
permit issued by EPA or a State or Tribe
approved by EPA under section 402 of
the Act, or, in the case of dredged or fill
material, by the Corps or an approved
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1992
Federal Register/Vol. 68, No. 10/Wednesday, January 15, 2003/Proposed Rules
State or Tribe under section 404 of the
Act. In addition, under the CWA, States
or approved Tribes establish water
quality standards for "waters of the
U.S.", and also may assume
responsibility for issuance of CWA
permits for discharges into waters and
wetlands subject to the Act. Today's
ANPRM seeks public input on what, if
any, revisions in light of SWANCC
might be appropriate to the regulations
that define "waters of the U.S.", and
today's ANPRM thus would be of
interest to all entities discharging to, or
regulating, such waters. In addition,
because the Oil Pollution Act (OPA) is
applicable to waters and wetlands
subject to the CWA, today's ANPRM
may have implications for persons or
entities subject to the OPA. Examples of
entities potentially regulated include:
Category
State/Tribal govern-
ments or instru-
mentalities.
Local governments or
instrumentalities.
Federal government
agencies or instru-
mentalities.
Industrial, commer-
cial, or agricultural
entities.
Land developers and
landowners.
Examples of
potentially regulated
entities
State/Tribal agencies
or instrumentalities
that discharge or
spill pollutants into
waters of the U.S.
Local governments or
instrumentalities
that discharge or
spill pollutants into
waters of the U.S.
Federal government
agencies or instru-
mentalities that dis-
charge or spill pol-
lutants into waters
of the U.S.
Industrial, commer-
cial, or agricultural
entities that dis-
charge or spill pol-
lutants into waters
of the U.S.
Land developers and
landowners that
discharge or spill
pollutants into wa-
ters of the U.S.
This table is not intended to be
exhaustive, but rather provides a guide
for readers regarding entities that are
likely to be regulated by a rulemaking
based on this ANPRM. This table lists
the types of entities that we are now
aware of that could potentially be
regulated. Other types of entities not
listed in the table could also be
regulated. To determine whether your
organization or its activities could be
regulated, you should carefully examine
the discussion in this ANPRM. If you
have questions regarding the
applicability of this action to a
particular entity, consult one of the
persons listed in the preceding FOR
FURTHER INFORMATION CONTACT section.
B. How Can I Get Copies of This
Document and Other Related
Information?
1. Docket. The agencies have
established an official public docket for
this action under Docket ID No. OW—
2002-0050. The official public docket
consists of the documents specifically
referenced in this ANPRM, any public
comments received, and other
information related to this ANPRM.
Although a part of the official docket,
the public docket does not include
Confidential Business Information (CBI)
or other information whose disclosure is
restricted by statute. The official public
docket is the collection of materials that
is available for public viewing at the
Water Docket in the EPA Docket Center,
(EPA/DC) EPA West, Room B102, 1301
Constitution Ave., NW., Washington,
DC. The EPA Docket Center Public
Reading Room is open from 8:30 a.m. to
4:30 p.m., Monday through Friday,
excluding legal holidays. The telephone
number for the Public Reading Room is
(202) 566-1744, and the telephone
number for the Water Docket is (202)
566-2426. You may have to pay a
reasonable fee for copying.
2. Electronic Access. You may access
this Federal Register document
electronically through the EPA Internet
under the Federal Register listings at
http://www.epa.gov/fedrgstr/.
An electronic version of the public
docket is available through EPA's
electronic public docket and comment
system, EPA Dockets. You may use EPA
Dockets at http://www.epa.gov/edocket
to submit or view public comments,
access the index listing of the contents
of the official public docket, and to
access those documents in the public
docket that are available electronically.
Once in the system, select search, then
key in the appropriate docket
identification number.
Certain types of information will not
be placed in the EPA Dockets.
Information claimed as CBI and other
information whose disclosure is
restricted by statute, which is not
included in the official public docket,
will not be available for public viewing
in EPA's electronic public docket. EPA's
policy is that copyrighted material will
not be placed in EPA's electronic public
docket but will be available only in
printed, paper form in the official public
docket. Although not all docket
materials may be available
electronically, you may still access any
of the publicly available docket
materials through the docket facility
identified in I.B.I.
For those who submit public
comments, it is important to note that
EPA's policy is that public comments,
whether submitted electronically or in
paper, will be made available for public
viewing in EPA's electronic public
docket as EPA receives them and
without change, unless the comment
contains copyrighted material, CBI, or
other information whose disclosure is
restricted by statute. When EPA
identifies a comment containing
copyrighted material, EPA will provide
a reference to that material in the
version of the comment that is placed in
EPA's electronic public docket. The
entire printed comment, including the
copyrighted material, will be available
in the public docket.
Public comments submitted on
computer disks that are mailed or
delivered to the docket will be
transferred to EPA's electronic public
docket. Public comments that are
mailed or delivered to the Docket will
be scanned and placed in EPA's
electronic public docket. Where
practical, physical objects will be
photographed, and the photograph will
be placed in EPA's electronic public
docket along with a brief description
written by the docket staff.
C. How and To Whom Do I Submit
Comments?
You may submit comments
electronically, by mail, or through hand
delivery/courier. To ensure proper
receipt by EPA, identify the appropriate
docket identification number (OW-
2002-0050) in the subject line on the
first page of your comment. Please
ensure that your comments are
submitted within the specified comment
period. Comments received after the
close of the comment period will be
marked late. The agencies are not
required to consider these late
comments.
1. Electronically. If you submit an
electronic comment as prescribed
below, EPA recommends that you
include your name, mailing address,
and an e-mail address or other contact
information in the body of your
comment. Also include this contact
information on the outside of any disk
or CD ROM you submit, and in any
cover letter accompanying the disk or
CD ROM. This ensures that you can be
identified as the submitter of the
comment and allows EPA to contact you
in case EPA cannot read your comment
due to technical difficulties or needs
further information on the substance of
your comment. EPA's policy is that EPA
will not edit your comment, and any
identifying or contact information
provided in the body of a comment will
be included as part of the comment that
is placed in the official public docket,
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Federal Register/Vol. 68, No. 10/Wednesday, January 15, 2003/Proposed Rules
1993
and made available in EPA's electronic
public docket. If EPA cannot read your
comment due to technical difficulties
and cannot contact you for clarification,
the agencies may not be able to consider
your comment.
i. EPA Dockets. Your use of EPA's
electronic public docket to submit
comments to EPA electronically is
EPA's preferred method for receiving
comments. Go directly to EPA Dockets
at http://www.epa.gov/edocket, and
follow the online instructions for
submitting comments. Once in the
system, select search, and then key in
Docket ID No. OW-2002-0050. The
system is an anonymous access system,
which means EPA will not know your
identity, e-mail address, or other contact
information unless you provide it in the
body of your comment.
ii. E-mail. Comments may be sent by
electronic mail (e-mail) to
CWAwaters@epa.gov, Attention Docket
ID No. OW-2002-0050. In contrast to
EPA's electronic public docket, EPA's e-
mail system is not an anonymous access
system. If you send an e-mail comment
directly to the Docket without going
through EPA's electronic public docket,
EPA's e-mail system automatically
captures your e-mail address. E-mail
addresses that are automatically
captured by EPA's e-mail system are
included as part of the comment that is
placed in the official public docket, and
made available in EPA's electronic
public docket.
iii. Disk or CD ROM. You may submit
comments on a disk or CD ROM that
you mail to the mailing address
identified in I.C.2. These electronic
submissions will be accepted in
WordPerfect or ASCII file format. Avoid
the use of special characters and any
form of encryption.
2. By Mail. Send four copies of your
comments to: Water Docket,
Environmental Protection Agency,
Mailcode 4101T, 1200 Pennsylvania
Ave., NW, Washington, DC 20460,
Attention Docket ID No. OW-2002-
0050.
3. By Hand Delivery or Courier.
Deliver your comments to: Water
Docket, EPA Docket Center, EPA West,
Room B102, 1301 Constitution Avenue,
NW, Washington, DC, Attention Docket
ID No. OW-2002-0050. Such deliveries
are only accepted during the Docket's
normal hours of operation as identified
in I.B.I.
D. What Should I Consider as I Prepare
My Comments?
You may find the following
suggestions helpful for preparing your
comments:
a. Explain your views as clearly as
possible.
b. Describe any assumptions that you
used.
c. Provide any technical information
and/or data on which you based your
views.
d. If you estimate potential burden or
costs, explain how you arrived at your
estimate.
e. Provide specific examples to
illustrate your concerns.
f. Offer alternatives.
g. Make sure to submit your
comments by the comment period
deadline identified.
h. To ensure proper receipt by EPA,
identify the appropriate docket
identification number in the subject line
on the first page of your response. It
would also be helpful if you provided
the name, date, and Federal Register
citation related to your comments.
II. The Importance of Updating the
Regulations
The agencies have not engaged in a
review? of the regulations with the
public concerning CWA jurisdiction for
some time. This ANPRM will help
ensure that the regulations are
consistent with the CWA and the public
understands what waters are subject to
CWA jurisdiction. The goal of the
agencies is to develop proposed
regulations that will further the public
interest by clarifying what waters are
subject to CWA jurisdiction and
affording full protection to these waters
through an appropriate focus of Federal
and State resources consistent with the
CWA. It is appropriate to review the
regulations to ensure that they are
consistent with the SWANCC decision.
SWANCC eliminates CWA jurisdiction
over isolated waters that are intrastate
and non-navigable, where the sole basis
for asserting CWA jurisdiction is the
actual or potential use of the waters as
habitat for migratory birds that cross
State lines in their migrations. SWANCC
also calls into question whether CWA
jurisdiction over isolated, intrastate,
non-navigable waters could now be
predicated on the other factors listed in
the "Migratory Bird Rule" or the other
rationales of 33 CFR 328.3(a)(3)(i)-(iii).
Although the SWANCC case itself
specifically involves section 404 of the
CWA, the Court's decision may also
affect the scope of regulatory
jurisdiction under other provisions of
the CWA, including programs under
sections 303, 311, 401, and 402. Under
each of these sections, the relevant
agencies have jurisdiction over "waters
of the United States." The agencies will
consider the potential implications of
the rulemaking for these other sections.
• Section 404 dredged and fill
material permit program. This program
establishes a permitting system to
regulate discharges of dredged or fill
material into waters of the United
States.
• Section 303 water quality standards
program. Under this program, States
and authorized Indian Tribes establish
water quality standards for navigable
waters to "protect the public health or
welfare" and "enhance the quality of
water", "taking into consideration their
use and value for public water supplies,
propagation of fish and wildlife,
recreational purposes, and agriculture,
industrial, and other purposes, and also
taking into consideration their use and
value for navigation."
• Section 311 spill program and the
Oil Pollution Act (OPA). Section 311 of
the CWA addresses pollution from both
oil and hazardous substance releases.
Together with the Oil Pollution Act, it
provides EPA and the U.S. Coast Guard
with the authority to establish a
program for preventing, preparing for,
and responding to spills that occur in
navigable waters of the United States.
• Section 401 State water-quality
certification program. Section 401
provides that no Federal permit or
license for activities that might result in
a discharge to navigable waters may be
issued unless a section 401 water-
quality certification is obtained from or
waived by States or authorized Tribes.
• Section 402 National Pollutant
Discharge Elimination System (NPDES)
permitting program. This program
establishes a permitting system to
regulate point source discharges of
pollutants (other than dredged or fill
material) into waters of the United
States.
III. Legislative and Regulatory Context
The Federal Water Pollution Control
Act Amendments, now known as the
Clean Water Act (CWA), was enacted in
1972. In the years since its enactment,
the scope of waters regulated under the
CWA has been discussed in regulations,
legislation, and judicial decisions.
The CWA was intended to "restore
and maintain the chemical, physical,
and biological integrity of the Nation's
waters." 33 U.S.C. 1251(a). Its specific
provisions were designed to improve
upon the protection of the Nation's
waters provided under earlier statutory
schemes such as the Rivers and Harbors
Act of 1899 ("RHA") (33 U.S.C. 403,
407, 411) and the Federal Water
Pollution Control Act of 1948 (62 Stat.
1155) and its subsequent amendments
through 1970. In doing so, Congress
recognized "the primary responsibilities
and rights of States to prevent, reduce,
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1994
Federal Register/Vol. 68, No. 10/Wednesday, January 15, 2003/Proposed Rules
and eliminate pollution, to plan the
development and use (including
restoration, preservation, and
enhancement) of land and water
resources * * *" 33 U.S.C. 1251(b).
The jurisdictional scope of the CWA
is "navigable waters," defined in the
statute as "waters of the United States,
including the territorial seas." CWA
section 502(7), 33 U.S.C. 1362(7). The
existing CWA section 404 regulations
define "waters of the United States" as
follows:
(l) All waters which are currently
used, or were used in the past, or may
be susceptible to use in interstate or
foreign commerce, including all waters
which are subject to ebb and flow of the
tide;
(2) All interstate waters including
interstate wetlands;
(3) All other waters such as intrastate
lakes, rivers, streams (including
intermittent streams), mudflats,
sandflats, wetlands, sloughs, prairie
potholes, wet meadows, playa lakes, or
natural ponds, the use, degradation or
destruction of which could affect
interstate or foreign commerce
including any such waters:
(i) which are or could be used by
interstate or foreign travelers for
recreational or other purposes; or
(ii) from which fish or shellfish are or
could be taken and sold in interstate or
foreign commerce; or
(iii) which are used or could be used
for industrial purposes by industries in
interstate commerce.
(4) All impoundments of waters
otherwise defined as waters of the
United States under the definition;
(5) Tributaries of waters identified in
paragraphs (a)(l)-(4) of this section;
(6) The territorial seas;
(7) Wetlands adjacent to waters (other
than waters that are themselves
wetlands) identified in paragraphs
(a)(l)-(6) of this section.
(8) Waters of the United States do not
include prior converted cropland ...
Waste treatment systems, including
treatment ponds or lagoons designed to
meet the requirements of CWA (other
than cooling ponds ...) are not waters of
the United States. 40 CFR.230.3(s); 33
CFR 328.3(a).
Counterpart and substantively similar
regulatory definitions appear at 40 CFR
110.1, 112.2, 116.3, 117.1, 122.2, 232.2,
300.5, part 300 App. E, 302.3 and 401.11
(hereafter referred to as "the counterpart
definitions").
In regulatory preambles, both the
Corps and EPA provided examples of
additional types of links to interstate
commerce which might serve as a basis
under 40 CFR 230.3(a)(3) and 33 CFR
328.3(a)(3) for establishing CWA
jurisdiction over intrastate waters which
were not part of the tributary system or
their adjacent wetlands. These included
use of waters (1) as habitat by birds
protected by Migratory Bird Treaties or
which cross State lines, (2) as habitat for
endangered species, or (3) to irrigate
crops sold in commerce. 51 FR 41217
(November 13, 1986), 53 FR 20765 (June
6, 1988). These examples became
known as the "Migratory Bird Rule,"
even though the examples were neither
a rule nor entirely about birds. The
Migratory Bird Rule later became the
focus of the SWANCC case.
IV. Potential Natural Resource
Implications
To date, some quantitative studies
and anecdotal data provide early
estimates of potential resource
implications of the SWANCC decision.
One of the purposes of the ANPRM is
to solicit additional information, data,
or studies addressing the extent of
resource impacts to isolated, intrastate,
non-navigable waters.
Non-navigable intrastate isolated
waters occur throughout the country.
Their extent depends on a variety of
factors including topography, climate,
and hydrologic forces. Preliminary
assessments of potential resource
impacts vary widely depending on the
scenarios considered. See, e.g., Ducks
Unlimited, "The SWANCC Decision:
Implications for Wetlands and
Waterfowl" (September 2001) (available
at http://www.ducks.org/conservation/
404_report.asp); ASWM, "SWANCC
Decision and the State Regulation of
Wetlands," (June 2001) (available at
http://www.aswm.org).
There is an extensive body of
knowledge about the functions and
values of wetlands, which include flood
risk reduction, water quality
improvement, fish and wildlife habitat,
and maintenance of the hydrologic
integrity of aquatic ecosystems. The
ANPRM seeks information regarding the
functions and values of wetlands and
other waters that may be affected by the
issues discussed in this ANPRM.
V. Solicitation of Comments
The agencies are seeking comment on
issues related to the jurisdictional status
of isolated waters under the CWA which
the public wishes to call to our
attention. To assist the public in
considering these issues, the following
discussion and specific questions are
presented. The agencies will carefully
consider the responses received to this
ANPRM in determining what regulatory
changes may be appropriate and the
issues to be addressed in a proposed
rulemaking to clarify CWA jurisdiction.
The SWANCC holding eliminates
CWA jurisdiction over isolated,
intrastate, non-navigable waters where
the sole basis for asserting CWA
jurisdiction is the actual or potential use
of the waters as habitat for migratory
birds that cross State lines in their
migrations. 531 U.S. at 174 ("We hold
that 33 CFR 328.3(a)(3) (1999), as
clarified and applied to petitioner's
balefill site pursuant to the "Migratory
Bird Rule," 51 FR 41217 (1986), exceeds
the authority granted to respondents
under section 404(a) of the CWA."). The
agencies seek comment on the use of the
factors in 33 CFR 328.3(a)(3)(i)-(iii) or
the counterpart regulations in
determining CWA jurisdiction over
isolated, intrastate, non-navigable
waters.
The agencies solicit comment from
the public on the following issues:
(l) Whether, and, if so, under what
circumstances, the factors listed in 33
CFR 328.3(a)(3)(i)-(iii) (i.e., use of the
water by interstate or foreign travelers
for recreational or other purposes, the
presence of fish or shellfish that could
be taken and sold in interstate
commerce, the use of the water for
industrial purposes by industries in
interstate commerce) or any other
factors provide a basis for determining
CWA jurisdiction over isolated,
intrastate, non-navigable waters?
(2) Whether the regulations should
define "isolated waters," and if so, what
factors should be considered in
determining whether a water is or is not
isolated for jurisdictional purposes?
Solicitation of Information
In answering the questions set forth
above, please provide, as appropriate,
any information (e.g., scientific and
technical studies and data, analysis of
environmental impacts, effects on
interstate commerce, other impacts, etc.)
supporting your views, and specific
recommendations on how to implement
such views. Additionally, we invite
your views as to whether any other
revisions are needed to the existing
regulations on which waters are
jurisdictional under the CWA. As noted
elsewhere in this document, the
agencies are also soliciting data and
information on the availability and
effectiveness of other Federal or State
programs for the protection of aquatic
resources, and on the functions and
values of wetlands and other waters that
may be affected by the issues discussed
in this ANPRM.
VI. Related Federal and State
Authorities
The SWANCC decision addresses
CWA jurisdiction, and other Federal or
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1995
State laws and programs may still
protect a water and related ecosystem
even if that water is no longer
jurisdictional under the CWA following
SWANCC. The Federal government
remains committed to wetlands
protection through the Food Security
Act's Swampbuster requirements and
Federal agricultural program benefits
and restoration through such Federal
programs as the Wetlands Reserve
Program (administered by the U.S.
Department of Agriculture), grant
making programs such as Partners in
Wildlife (administered by the Fish and
Wildlife Service), the Coastal Wetlands
Restoration Program (administered by
the National Marine Fisheries Service),
the State Grant, Five Star Restoration,
and National Estuary Programs
(administered by EPA), and the
Migratory Bird Conservation
Commission (composed of the
Secretaries of Interior and Agriculture,
the Administrator of EPA and Members
of Congress).
The SWANCC decision also highlights
the role of States in protecting waters
not addressed by Federal law. Prior to
SWANCC, fifteen States had programs
that addressed isolated wetlands. Since
SWANCC, additional States have
considered, and two have adopted,
legislation to protect isolated waters.
The Federal agencies have a number of
initiatives to assist States in these efforts
to protect wetlands. For example, EPA's
Wetland Program Development Grants
are available to assist States, Tribes, and
local governments for building their
wetland program capacities. In addition,
the U.S. Department of Justice and other
Federal agencies co-sponsored a
national wetlands conference with the
National Governors Association Center
for Best Practices, National Conference
of State Legislatures, the Association of
State Wetlands Managers, and the
National Association of Attorneys
General. This conference and the
dialogue that has ensued will promote
close collaboration between Federal
agencies and States in developing,
implementing, and enforcing wetlands
protection programs. EPA also is
providing funding to the National
Governors Association Center for Best
Practices to assist States in developing
appropriate policies and actions to
protect intrastate isolated waters.
In light of this, the agencies solicit
information and data from the general
public, the scientific community, and
Federal and State resource agencies on
the availability and effectiveness of
other Federal or State programs for the
protection of aquatic resources and
practical experience with their
implementation. The agencies are also
interested in data and comments from
State and local agencies on the effect of
no longer asserting jurisdiction over
some of the waters (and discharges to
those waters) in a watershed on the
implementation of Total Maximum
Daily Loads (TMDLs) and attainment of
water quality standards.
VII. Statutory and Executive Order
Reviews
A. Executive Order 12866
Under Executive Order 12866 (58 FR
51735, October 4, 1993), EPA and the
Corps must determine whether the
regulatory action is "significant" and
therefore subject to review? by the Office
of Management and Budget (OMB) and
the requirements of the Executive Order.
The Order defines "significant
regulatory action" as one that is likely
to result in a rule that may:
(1) Have an annual effect on the
economy of $100 million or more or
adversely affect in a material way the
economy, a sector of the economy,
productivity, competition, jobs, the
environment, public health or safety, or
State, local, or Tribal governments or
communities;
(2) Create a serious inconsistency or
otherwise interfere with an action taken
or planned by another agency;
(3) Materially alter the budgetary
impact of entitlements, grants, user fees,
or loan programs or the rights and
obligations of recipients thereof; or
(4) Raise novel legal or policy issues
arising out of legal mandates, the
President's priorities, or the principles
set forth in the Executive Order.
Pursuant to the terms of Executive
Order 12866, it has been determined
that this Advanced Notice of Proposed
Rulemaking is a "significant regulatory
action" in light of the provisions of
paragraph (4) above as it raises novel
legal or policy issues. As such, this
action was submitted to OMB for
review?. Changes made in response to
OMB suggestions or recommendations
will be documented in the public
record.
B. National Environmental Policy Act
As required by the National
Environmental Policy Act (NEPA), the
Corps prepares appropriate
environmental documentation for its
activities affecting the quality of the
human environment. The Corps has
determined that today's Advance Notice
of Proposed Rulemaking merely solicits
early comment on issues associated
with the scope of waters that are
properly subject to the CWA, and
information or data from the general
public, the scientific community, and
Federal and State resource agencies on
the implications of the SWANCC
decision for the protection of aquatic
resources. In light of this, the Corps has
determined that today's ANPRM does
not constitute a major Federal action
significantly affecting the quality of the
human environment, and thus does not
require the preparation of an
Environmental Impact Statement (EIS).
Dated: January 10, 2003.
Christine Todd Whitman,
Administrator, Environmental Protection
Agency.
Dated: January 10, 2003.
R.L. Brownlee,
Acting Assistan t Secretary of the Army, (Civil
Works), Department of the Army.
Note: The following guidance document
will not appear in the Code of Federal
Regulations.
Appendix A
Joint Memorandum
Introduction
This document provides clarifying
guidance regarding the Supreme Court's
decision in Solid Waste Agency of Northern
Cook County v. United States Army Corps of
Engineers, 531 U.S. 159 (2001) ("SWANCC")
and addresses several legal issues concerning
Clean Water Act ("CWA") jurisdiction that
have arisen since SWANCC in various factual
scenarios involving federal regulation of
"navigable waters." Because the case law
interpreting SWANCC has developed over
the last two years, the Agencies are issuing
this updated guidance, which supersedes
prior guidance on this issue. The Corps and
EPA are also initiating a rulemaking process
to collect information and to consider
jurisdictional issues as set forth in the
attached ANPRM. Jurisdictional decisions
will be based on Supreme Court cases
including United States v. Riverside Bayview
Homes, 474 U.S. 121 (1985) and SWANCC,
regulations, and applicable case law in each
jurisdiction.
Background
In SWANCC, the Supreme Court held that
the Army Corps of Engineers had exceeded
its authority in asserting CWA jurisdiction
pursuant to section 404(a) over isolated,
intrastate, non-navigable waters under 33
C.F.R. 328.3(a)(3), based on their use as
habitat for migratory birds pursuant to
preamble language commonly referred to as
the "Migratory Bird Rule," 51 FR 41217
(1986). "Navigable waters" are defined in
section 502 of the CWA to mean "waters of
the United States, including the territorial
seas." In SWANCC, the Court determined
that the term "navigable" had significance in
indicating the authority Congress intended to
exercise in asserting CWA jurisdiction. 531
U.S. at 172. After reviewing the jurisdictional
scope of the statutory definition of
"navigable waters" in section 502, the Court
concluded that neither the text of the statute
nor its legislative history supported the
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Corps' assertion of jurisdiction over the
waters involved in SWANCC. Id. at 170-171.
In SWANCC, the Supreme Court
recognized that "Congress passed the CWA
for the stated purpose of 'restoring and
maintaining the chemical, physical, and
biological integrity of the Nation's waters'"
and also noted that "Congress chose to
'recognize, preserve, and protect the primary
responsibilities and rights of States to
prevent, reduce, and eliminate pollution, to
plan the development and use (including
restoration, preservation, and enhancement)
of land and water resources. '"Id. at 166-67
(citing 33 U.S.C. 1251(a) and (b)). However,
expressing "serious constitutional and
federalism questions" raised by the Corps'
interpretation of the CWA, the Court stated
that "where an administrative interpretation
of a statute invokes the outer limits of
Congress' power, we expect a clear indication
that Congress intended that result." Id. at
174, 172. Finding "nothing approaching a
clear statement from Congress that it
intended section 404(a) to reach an
abandoned sand and gravel pit" (id. at 174),
the Court held that the Migratory Bird Rule,
as applied to petitioners' property, exceeded
the agencies' authority under section 404(a).
Id. at 174.
The Scope of CWA Jurisdiction After
SWANCC
Because SWANCC limited use of 33 CFR
§ 328.3(a)(3) as a basis of jurisdiction over
certain isolated waters, it has focused greater
attention on CWA jurisdiction generally, and
specifically over tributaries to jurisdictional
waters and over wetlands that are "adjacent
wetlands" for CWA purposes.
As indicated, section 502 of the CWA
defines the term navigable waters to mean
"waters of the United States, including the
territorial seas." The Supreme Court has
recognized that this definition clearly
includes those waters that are considered
traditional navigable waters. In SWANCC, the
Court noted that while "the word 'navigable'
in the statute was of 'limited import' "
(quoting Riverside, 474 U.S. 121 (1985)), "the
term 'navigable' has at least the import of
showing us what Congress had in mind as its
authority for enacting the CWA: traditional
jurisdiction over waters that were or had
been navigable in fact or which could
reasonably be so made." 531 U.S. at 172. In
addition, the Court reiterated in SWANCC
that Congress evidenced its intent to regulate
"at least some waters that would not be
deemed 'navigable' under the classical
understanding of that term." SWANCC at 171
(quoting Riverside, 474 U.S. at 133). Relying
on that intent, for many years, EPA and the
Corps have interpreted their regulations to
assert CWA jurisdiction over non-navigable
tributaries of navigable waters and their
adjacent wetlands. Courts have upheld the
view that traditional navigable waters and,
generally speaking, their tributary systems
(and their adjacent wetlands) remain subject
to CWA jurisdiction.
Several federal district and appellate courts
have addressed the effect of SWANCC on
CWA jurisdiction, and the case law on the
precise scope of federal CWA jurisdiction in
light of SWANCC is still developing. While
a majority of cases hold that SWANCC
applies only to waters that are isolated,
intrastate and non-navigable, several courts
have interpreted SWANCC's reasoning to
apply to waters other than the isolated waters
at issue in that case. This memorandum
attempts to add greater clarity concerning
federal CWA jurisdiction following SWANCC
by identifying specific categories of waters,
explaining which categories of waters are
jurisdictional or non-jurisdictional, and
pointing out where more refined factual and
legal analysis will be required to make a
jurisdictional determination.
Although the SWANCC case itself
specifically involved Section 404 of the
CWA, the Court's decision may affect the
scope of regulatory jurisdiction under other
provisions of the CWA as well, including the
Section 402 NPDES program, the Section 311
oil spill program, water quality standards
under Section 303, and Section 401 water
quality certification. Under each of these
sections, the relevant agencies have
jurisdiction over "waters of the United
States." CWA section 502(7).
This memorandum does not discuss the
exact factual predicates that are necessary to
establish jurisdiction in individual cases. We
recognize that the field staff and the public
could benefit from additional guidance on
how to apply the applicable legal principles
to individual cases.1 Should questions arise
concerning CWA jurisdiction, the regulated
community should seek assistance from the
Corps and EPA.
A. Isolated, Intrastate Waters That are Non-
Navigable
SWANCC squarely eliminates CWA
jurisdiction over isolated waters that are
intrastate and non-navigable, where the sole
basis for asserting CWA jurisdiction is the
actual or potential use of the waters as
habitat for migratory birds that cross state
lines in their migrations. 531 U.S. at 174
("We hold that 33 CFR § 328.3(a)(3) (1999),
as clarified and applied to petitioner's balefill
site pursuant to the 'Migratory Bird Rule,' 51
FR 41217 (1986), exceeds the authority
granted to respondents under § 404(a) of the
CWA."). The EPA and the Corps are now
precluded from asserting CWA jurisdiction in
such situations, including over waters such
as isolated, non-navigable, intrastate vernal
pools, playa lakes and pocosins. SWANCC
also calls into question whether CWA
jurisdiction over isolated, intrastate, non-
navigable waters could now be predicated on
the other factors listed in the Migratory Bird
1 The CWA provisions and regulations described
in this document contain legally binding
requirements. This document does not substitute
for those provisions or regulations, nor is it a
regulation itself. It does not impose legally binding
requirements on EPA, the Corps, or the regulated
community, and may not apply to a particular
situation depending on the circumstances. Any
decisions regarding a particular water will be based
on the applicable statutes, regulations, and case
law. Therefore, interested person are free to raise
questions and objections about the appropriateness
of the application of this guidance to a particular
situation, and EPA and/or the Corps will consider
whether or not the recommendations or
interpretations of this guidance are appropriate in
that situation based on the law and regulations.
Rule, 51 FR 41217 (i.e., use of the water as
habitat for birds protected by Migratory Bird
Treaties; use of the water as habitat for
Federally protected endangered or threatened
species; or use of the water to irrigate crops
sold in interstate commerce).
By the same token, in light of SWANCC, it
is uncertain whether there remains any basis
for jurisdiction under the other rationales of
§ 328.3(a)(3)(i)-(iii) over isolated, non-
navigable, intrastate waters (i.e., use of the
water by interstate or foreign travelers for
recreational or other purposes; the presence
of fish or shellfish that could be taken and
sold in interstate commerce; use of the water
for industrial purposes by industries in
interstate commerce). Furthermore, within
the states comprising the Fourth Circuit,
CWA jurisdiction under 33 CFR § 328.3(a)(3)
in its entirety has been precluded since 1997
by the Fourth Circuit's ruling in United
States v. Wilson, 133 F. 3d 251, 257 (4th Cir.
1997) (invalidating 33 CFR § 328.3(a)(3)).
In view of SWANCC, neither agency will
assert CWA jurisdiction over isolated waters
that are both intrastate and non-navigable,
where the sole basis available for asserting
CWA jurisdiction rests on any of the factors
listed in the "Migratory Bird Rule." In
addition, in view of the uncertainties after
SWANCC concerning jurisdiction over
isolated waters that are both intrastate and
non-navigable based on other grounds listed
in 33 CFR § 328.3(a)(3)(i)-(iii), field staff
should seek formal project-specific
Headquarters approval prior to asserting
jurisdiction over such waters, including
permitting and enforcement actions.
B. Traditional Navigable Waters
As noted, traditional navigable waters are
jurisdictional. Traditional navigable waters
are waters that are subject to the ebb and flow
of the tide, or waters that are presently used,
or have been used in the past, or may be
susceptible for use to transport interstate or
foreign commerce. 33 CFR § 328.3(a)(l);
United States v. Appalachian Elec. Power
Co., 311 U.S. 377, 407-408 (1940) (water
considered navigable, although not navigable
at present but could be made navigable with
reasonable improvements); Economy Light &
Power Co. v. United States, 256 U.S. 113
(1911) (dams and other structures do not
eliminate navigability); SWANCC, 531 U.S. at
172 (referring to traditional jurisdiction over
waters that were or had been navigable in
fact or which could reasonably be so made).2
In accord with the analysis in SWANCC,
waters that fall within the definition of
traditional navigable waters remain
jurisdictional under the CWA. Thus, isolated,
intrastate waters that are capable of
supporting navigation by watercraft remain
subject to CWA jurisdiction after SWANCC if
they are traditional navigable waters, i.e., if
they meet any of the tests for being navigable-
in-fact. See, e.g., Colvin v. United States 181
F. Supp. 2d 1050 (C.D. Cal. 2001) (isolated
2 These traditional navigable waters are not
limited to those regulated under Section 10 of the
Rivers and Harbors Act of 1899; traditional
navigable waters include waters which, although
used, susceptibale to use, or historically used, to
transport goods or people in commerce, do not form
part of a continuous wateborne highway.
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1997
man-made water body capable of boating
found to be "water of the United States").
C. Adjacent Wetlands
(1) Wetlands Adjacent to Traditional
Navigable Waters
CWA jurisdiction also extends to wetlands
that are adjacent to traditional navigable
waters. The Supreme Court did not disturb
its earlier holding in Riverside when it
rendered its decision in SWANCC. Riverside
dealt with a wetland adjacent to Black Creek,
a traditional navigable water. 474 U.S. 121
(1985); see also SWANCC, 531 U.S. at 167
("[i]n Riverside, we held that the Corps had
section 404(a) jurisdiction over wetlands that
actually abutted on a navigable waterway").
The Court in Riverside found that "Congress";
concern for the protection of water quality
and aquatic ecosystems indicated its intent to
regulate wetlands 'inseparably bound up
with' " jurisdictional waters. 474 U.S. at 134.
Thus, wetlands adjacent to traditional
navigable waters clearly remain jurisdictional
after SWANCC. The Corps and EPA currently
define 'adjacent' as "bordering, contiguous,
or neighboring. Wetlands separated from
other waters of the United States by man-
made dikes or barriers, natural river berms,
beach dunes, and the like are 'adjacent
wetlands.'" 33 CFR §328.3(b); 40 CFR
§ 230.3(b). The Supreme Court has not itself
defined the term "adjacent," nor stated
whether the basis for adjacency is geographic
proximity or hydrology.
(2) Wetlands Adjacent to Non-Navigable
Waters
The reasoning in Riverside, as followed by
a number of post-SWANCC courts, supports
jurisdiction over wetlands adjacent to non-
navigable waters that are tributaries to
navigable waters. Since SWANCC, some
courts have expressed the view that
SWANCC raised questions about adjacency
jurisdiction, so that wetlands are
jurisdictional only if they are adjacent to
navigable waters. See, e.g., Rice v. Harken,
discussed infra.
D. Tributaries
A number of court decisions have held that
SWANCC does not change the principle that
CWA jurisdiction extends to tributaries of
navigable waters. See, e.g., Headwaters v.
Talent Irrigation Dist, 243 F.3d 526, 534 (9th
Cir. 2001) ("Even tributaries that flow
intermittently are 'waters of the United
States' "); United States v. Interstate Gen. Co,
No. 01-4513, slip op. at 7, 2002 WL 1421411
(4th Cir. July 2, 2002), off ing 152 F. Supp.
2d 843 (D. Md. 2001) (refusing to grant writ
of coram nobis; rejecting argument that
SWANCC eliminated jurisdiction over
wetlands adjacent to non-navigable
tributaries); United States v. Krilich, 393F.3d
784 (7th Cir. 2002) (rejecting motion to vacate
consent decree, finding that SWANCC did
not alter regulations interpreting "waters of
the U.S." other than 33 C.F.R. § 328.3(a)(3));
Community Ass. for Restoration oftheEnv't
v. Henry Bosma Dairy, 305 F.3d 953 (9th Cir.
2002) (drain that flowed into a canal that
flows into a river is jurisdictional); Idaho
Rural Council v. Bosma, 143 F. Supp. 2d
1169, 1178 (D. Idaho 2001) ("waters of the
United States include waters that are
tributary to navigable waters"); Aiello v.
Town of Brookhaven, 136 F. Supp. 2d 81, 118
(E.D. N.Y. 2001) (non-navigable pond and
creek determined to be tributaries of
navigable waters, and therefore "waters of
the United States under the CWA").
Jurisdiction has been recognized even when
the tributaries in question flow for a
significant distance before reaching a
navigable water or are several times removed
from the navigable waters (i.e., "tributaries of
tributaries"). See, e.g., United States v.
Lamplight Equestrian Ctr., No. 00 C 6486,
2002 WL 360652, at *8 (ND. 111. Mar. 8, 2002)
("Even where the distance from the tributary
to the navigable water is significant, the
quality of the tributary is still vital to the
quality of navigable waters"); United States
v. Buday, 138 F. Supp. 2d 1282, 1291-92 (D.
Mont. 2001) ("water quality of tributaries
* * * distant though the tributaries may be
from navigable streams, is vital to the quality
of navigable waters"); United States v. Rueth
Dev. Co., No. 2:96CV540, 2001 WL 17580078
(N.D. Ind. Sept. 26, 2001) (refusing to reopen
a consent decree in a CWA case and
determining that jurisdiction remained over
wetlands adjacent to a non-navigable (man-
made) waterway that flows into a navigable
water).
Some courts have interpreted the reasoning
in SWANCC to potentially circumscribe
CWA jurisdiction over tributaries by finding
CWA jurisdiction attaches only where
navigable waters and waters immediately
adjacent to navigable waters are involved.
Rice v. Harken is the leading case taking the
narrowest view of CWA jurisdiction after
SWANCC. 250 F.3d 264 (5th Cir. 2001)
(rehearing denied). Harken interpreted the
scope of "navigable waters" under the Oil
Pollution Act (OPA). The Fifth Circuit relied
on SWANCC to conclude "it appears that a
body of water is subject to regulation under
the CWA if the body of water is actually
navigable or is adjacent to an open body of
navigable water." 250 F.3d at 269. The
analysis in Harken implies that the Fifth
Circuit might limit CWA jurisdiction to only
those tributaries that are traditionally
navigable or immediately adjacent to a
navigable water.
A few post-SWANCC district court
opinions have relied on Harken or reasoning
similar to that employed by the Harken court
to limit jurisdiction. See, e.g., United States
v. Rapanos, 190 F. Supp. 2d 1011(E.D. Mich.
2002) (government appeal pending) ("the
Court finds as a matter of law that the
wetlands on Defendant's property were not
directly adjacent to navigable waters, and
therefore, the government cannot regulate
Defendant's property."); United States v.
Needham, No. 6:01-CV-01897, 2002 WL
1162790 (W.D. La. Jan. 23, 2002) (government
appeal pending) (district court affirmed
finding of no liability by bankruptcy court for
debtors under OPA for discharge of oil since
drainage ditch into which oil was discharged
was found to be neither a navigable water nor
adjacent to an open body of navigable water).
See alsoUnited States v. Newdunn, 195 F.
Supp. 2d 751 (E.D. Va. 2002) (government
appeal pending) (wetlands and tributaries not
contiguous or adjacent to navigable waters
are outside CWA jurisdiction); United States
v. RGM Corp., 222 F. Supp. 2d 780 (E.D. Va.
2002) (government appeal pending)
(wetlands on property not contiguous to
navigable river and, thus, jurisdiction not
established based upon adjacency to
navigable water).
Another question that has arisen is
whether CWA jurisdiction is affected when a
surface tributary to jurisdictional waters
flows for some of its length through ditches,
culverts, pipes, storm sewers, or similar
manmade conveyances. A number of courts
have held that waters with manmade features
are jurisdictional. For example, in
Headwaters Inc. v. Talent Irrigation District,
the Ninth Circuit held that manmade
irrigation canals that diverted water from one
set of natural streams and lakes to other
streams and creeks were connected as
tributaries to waters of the United States, and
consequently fell within the purview of CWA
jurisdiction. 243 F.3d at 533-34. However,
some courts have taken a different view of
the circumstances under which man-made
conveyances satisfy the requirements for
CWA jurisdiction. See, e.g., Newdunn, 195 F.
Supp. 2d at 765 (government appeal pending)
(court determined that Corps had failed to
carry its burden of establishing CWA
jurisdiction over wetlands from which
surface water had to pass through a spur
ditch, a series of man-made ditches and
culverts as well as non-navigable portions of
a creek before finally reaching navigable
waters).
A number of courts have held that waters
connected to traditional navigable waters
only intermittently or ephemerally are
subject to CWA jurisdiction. The language
and reasoning in the Ninth Circuit's decision
in Headwaters Inc. v. Talent Irrigation
District indicates that the intermittent flow of
waters does not affect CWA jurisdiction. 243
F.3d at 534 ("Even tributaries that flow
intermittently are 'waters of the United
States.' "). Other cases, however, have
suggested that SWANCC eliminated from
CWA jurisdiction some waters that flow only
intermittently. See, e.g., Newdunn, 195 F.
Supp. 2d at 764, 767-68 (government appeal
pending) (ditches and culverts with
intermittent flow not jurisdictional).
A factor in determining jurisdiction over
waters with intermittent flows is the
presence or absence of an ordinary high
water mark (OHWM). Corps regulations
provide that, in the absence of adjacent
wetlands, the lateral limits of non-tidal
waters extend to the OHWM (33 CFR
328.4(c)(l)). One court has interpreted this
regulation to require the presence of a
continuous OHWM. United States v. RGM,
222 F. Supp. 2d 780 (E.D. Va. 2002)
(government appeal pending).
Conclusion
In light of SWANCC, field staff should not
assert CWA jurisdiction over isolated waters
that are both intrastate and non-navigable,
where the sole basis available for asserting
CWA jurisdiction rests on any of the factors
listed in the "Migratory Bird Rule." In
addition, field staff should seek formal
project-specific HQ approval prior to
asserting jurisdiction over waters based on
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other factors listed in 33 CFR 328.3(a)(3)(i)-
(iii).
Field staff should continue to assert
jurisdiction over traditional navigable waters
(and adjacent wetlands) and, generally
speaking, their tributary systems (and
adjacent wetlands). Field staff should make
jurisdictional and permitting decisions on a
case-by-case basis considering this guidance,
applicable regulations, and any additional
relevant court decisions. Where questions
remain, the regulated community should
seek assistance from the agencies on
questions of jurisdiction.
Robert E. Fabricant,
General Counsel, Environmental Protection
Agency.
Steven J. Morello,
General Counsel, Department of the Army.
[FR Doc. 03-960 Filed 1-14-03; 8:45 am]
BILLING CODE 6560-50-P
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 52
[IN140-1b; FRL-7433-6]
Approval and Promulgation of
Implementation Plans; Indiana
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Proposed rule.
SUMMARY: The EPA is proposing to
conditionally approve rules submitted
by the State of Indiana as revisions to its
State Implementation Plan(SIP) for
prevention of significant deterioration
(PSD) provisions for attainment areas for
the Indiana Department of
Environmental Management.
In the "Rules and Regulations"
section of this Federal Register, EPA is
approving the State's request as a direct
final rule without prior proposal
because EPA views this action as
noncontroversial and anticipates no
adverse comments. The rationale for
approval is set forth in the direct final
rule. If EPA receives no written adverse
comments, EPA will take no further
action on this proposed rule. If EPA
receives written adverse comment, we
will publish a timely withdrawal of the
direct final rule in the Federal Register
and inform the public that the rule will
not take effect. In that event, EPA will
address all relevant public comments in
a subsequent final rule based on this
proposed rule. In either event, EPA will
not institute a second comment period
on this action. Any parties interested in
commenting must do so at this time.
DATES: Comments on this action must be
received by February 14, 2003.
ADDRESSES: Written comments should
be sent to: Pamela Blakley, Chief,
Permits and Grants Section (IL/IN/OH),
Air Programs Branch (AR-18J), U.S.
Environmental Protection Agency,
Region 5, 77 West Jackson Boulevard,
Chicago, Illinois 60604.
A copy of the State's request is
available for inspection at the above
address.
FOR FURTHER INFORMATION CONTACT: Julie
Capasso, Environmental Scientist,
Permits and Grants Section (IL/IN/OH),
Air Programs Branch, (AR-18J), U.S.
Environmental Protection Agency,
Region 5, 77 West Jackson Boulevard,
Chicago, Illinois 60604, telephone (312)
886-1426.
SUPPLEMENTARY INFORMATION:
Throughout this document whenever
"we," "us," or "our" are used we mean
the EPA.
I. What action is EPA taking today?
II. Where can I find more information about
this proposal and corresponding direct
final rule?
I. What Action Is EPA Taking Today?
The EPA is proposing to conditionally
approve rules submitted by the State of
Indiana as revisions to its State
Implementation Plan (SIP) for
prevention of significant deterioration
(PSD) provisions for attainment areas for
the Indiana Department of
Environmental Management.
II. Where Can I Find More Information
About This Proposal and
Corresponding Direct Final Rule?
For additional information see the
direct final rule published in the rules
and regulations section of this Federal
Register.
Authority: 42 U.S.C. 4201 et seq.
Dated: December 18, 2002.
Bharat Mathur,
Acting Regional Administrator, Region 5.
[FR Doc. 03-617 Filed 1-14-03; 8:45 am]
BILLING CODE 6560-50-P
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 52
[MD137-3090b; FRL-7420-9]
Approval and Promulgation of Air
Quality Implementation Plans;
Maryland; Revision to the Control of
Volatile Organic Compound Emissions
From Screen Printing and Digital
Imaging
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Proposed rule.
SUMMARY: EPA proposes to approve the
State Implementation Plan (SIP)
revision submitted by the State of
Maryland establishing reasonable
available control technology (RACT) to
limit volatile organic compound (VOC)
emissions from an overprint varnish
that is used in the cosmetic industry.
This action also proposes to add new
definitions and amend certain existing
definitions for terms used in the
regulations. In the Final Rules section of
this Federal Register, EPA is approving
the State's SIP submittal as a direct final
rule without prior proposal because the
Agency views this as a noncontroversial
submittal and anticipates no adverse
comments. A more detailed description
of the state submittal and EPA's
evaluation are included in a Technical
Support Document (TSD) prepared in
support of this rulemaking action. A
copy of the TSD is available, upon
request, from the EPA Regional Office
listed in the ADDRESSES section of this
document. If no adverse comments are
received in response to this action, no
further activity is contemplated. If EPA
receives adverse comments, the direct
final rule will be withdrawn and all
public comments received will be
addressed in a subsequent final rule
based on this proposed rule. EPA will
not institute a second comment period.
Any parties interested in commenting
on this action should do so at this time.
DATES: Comments must be received in
writing by February 14, 2003.
ADDRESSES: Written comments should
be addressed to Walter Wilkie, Acting
Branch Chief, Air Quality Planning and
Information Services Branch, Mailcode
3AP21, U.S. Environmental Protection
Agency, Region III, 1650 Arch Street,
Philadelphia, Pennsylvania 19103.
Copies of the documents relevant to this
action are available for public
inspection during normal business
hours at the Air Protection Division,
U.S. Environmental Protection Agency,
Region III, 1650 Arch Street,
Philadelphia, Pennsylvania 19103; and
the Maryland Department of the
Environment, 1800 Washington
Boulevard, Suite 705, Baltimore,
Maryland 21230.
FOR FURTHER INFORMATION CONTACT:
Ellen Wentworth, (215) 814-2034, at the
EPA Region III address above, or by e-
mail at wentworth.ellen@epa.gov. Please
note that while questions may be posed
via telephone and e-mail, formal
comments must be submitted in writing,
as indicated in the ADDRESSES section of
this document.
-------
Appendix H: Other Policy Documents
Daniel Gilligan, President
Petroleum Marketers Association of America
1901 N. Fort Myer Drive- Suite 500
Arlington, VA 22209-1604
Dear Mr. Gilligan:
This letter is in response to your request for the Agency's view regarding whether several
approaches under consideration by your members would satisfy 40 CFR § 112.7(a)(2)'s
"equivalent environmental protection" provision and for clarification of the scope of the
requirements in 40 CFR § 112.7(h)(entitled "Facility tank car and tank truck loading/unloading
rack (excluding offshore facilities)"). We discuss each of your proposals and questions below.
Please note that the guidance provided in this letter is based on generalized assumptions and may
not be applicable in a particular case based on site-specific circumstances.
"Equivalent Environmental Protection"
Integrity Testing
The newly amended SPCC provisions regarding bulk storage container integrity require,
among other things, that each aboveground container be tested for integrity "on a regular
schedule." 40 CFR § 112.8(c)(6). These regulations further provide that "you must combine
visual inspection with another testing technique such as hydrostatic testing, radiographic testing,
ultrasonic testing, acoustic emissions testing, or another system of non-destructive shell testing."
As you know, however, the regulations also allow deviations from this requirement where "you
provide equivalent environmental protection by some other means of spill prevention, control, or
countermeasure." 40 CFR §112.7(a)(2). You have asked whether, for shop-built containers,
visual inspection plus certain actions to ensure that the containers are not in contact with the soil
would likely be considered to provide "equivalent environmental protection" to visual inspection
plus another form of testing.
It is our view that for well-designed shop-built containers with a shell capacity of 30,000
gallons or under, combining appropriate visual inspection with the measures described below
would generally provide environmental protection equivalent to that provided by visual
inspection plus another form of testing. Specifically, the Agency generally believes that visual
inspection plus elevation of a shop-built container in a manner that decreases corrosion potential
SPCC GUIDANCE FOR REGIONAL INSPECTORS H-117
-------
Appendix H: Other Policy Documents
(as compared to a container in contact with soil)1 and makes all sides of the container, including
the bottom, visible during inspection (e.g., where the containers are mounted on structural
supports, saddles, or some forms of grillage) would be considered "equivalent." In a similar
vein, we'd also generally believe an approach that combines visual inspection with placement of
a barrier between the container and the ground, designed and operated in a way that ensures that
any leaks are immediately detected, to be considered "equivalent." For example, we believe it
would generally provide equivalent environmental protection to place a shop-built container on
an adequately designed, maintained, and inspected synthetic liner.2 We believe these approaches
would generally provide equivalent environmental protection when used for shop-built
containers (which generally have a lower failure potential than field-erected containers), because
these approaches generally reduce corrosion potential and ensure detection of any container
failure before it becomes significant.
In determining the appropriate SPCC plan requirements for visual inspection of
containers managed as described above, we suggest that the professional engineer (PE) begin by
consulting appropriate industry standards, such as those listed in Steel Tank Institute Standard
SP001 and American Petroleum Institute Standard 653.3 Similarly, in assessing whether a shop-
built container is well designed, the PE may wish to consult industry standards such as
Underwriters Laboratory 142 or American Petroleum Institute Standard 650, Appendix J. Where
a facility is considering the use of the above approaches for containers that are currently resting
on the ground, or have otherwise been managed in a way that presents risks for corrosion or are
showing signs of corrosion, we recommend the facility first evaluate the condition of the
1 Additionally, we recommend that special attention be paid to the characteristics of the
material used for the support structure to ensure that they do not actually accelerate corrosion.
2Note, however, that a facility may not rely solely on measures that are required by other
sections of the rule (e.g., secondary containment) to provide "equivalent environmental
protection." Otherwise, the deviation provision would allow for approaches that provide a lesser
degree of protection overall.
3Note that the Agency intends in the near future to develop guidance on appropriate visual
inspection of shop-built containers. In that guidance, we intend to address issues such as
inspection frequency, scope (e.g., internal and /or external), training and/or qualifications of
persons conducting the inspections, and other measures that maybe appropriate at a given site
(e.g., measures to detect the presence of water in a container). We expect to use the referenced
industry standards in developing such guidance.
It is also important to note, however, that depending on site circumstances, the
appropriate requirements for visual inspection may exceed those normally conducted in
accordance with recognized industry standards.
SPCC GUIDANCE FOR REGIONAL INSPECTORS H-118
-------
Appendix H: Other Policy Documents
container in accordance with good engineering practices, including seeking expert advice, where
appropriate.
Security
The SPCC regulations state that you must "fully fence each facility handling, processing,
or storing oil, and lock and/or guard entrance gates when the facility is not in production or is
unattended." 40 CFR §112.7(g)(l). You have asked whether two specific sets of circumstances
would likely be determined to provide "equivalent environmental protection" to this requirement.
The first is where the area of the facility directly involved in the handling, processing and storage
of oil is adequately fenced. The second is where the facility is equipped with a "pump house" or
"pump shack," which contains, among other appropriate things, a master disconnect switch from
which all power to pumps and containers is cut off when the facility is unattended.
With respect to your first scenario, it is our view that, as a general matter, adequately
fencing all discrete areas directly involved in the handling, processing and storage of oil would
provide equivalent environmental protection to fencing the entire footprint of the facility, since it
is potential for harm to this equipment that poses the risk addressed by the fencing requirement.
With respect to the second scenario, the approach you suggest would appear to generally
provide environmental protection equivalent to fencing for risks associated with the potential for
unauthorized access to pumping equipment. In other words, cutting off power in the manner you
suggest would likely provide the added layer of protection offered by a fence should the other
security measures offered by the rule, in this case 40 CFR § 112.7(g)(3)'s requirements for
securing pumps, fail. However, because cutting off power as suggested does not address risks to
containers, piping and appurtenances not associated with the pumps at the facility, it does not
appear to provide protection equivalent to fencing as it relates to risks to such equipment.
Conclusion
Please note that determinations of "equivalent environmental protection" must be
implemented and documented in accordance with 40 CFR § 112.7(a)(2). In addition, please be
aware that the conclusions drawn in this letter are only for the purposes of meeting the
"environmental equivalence" standard in the SPCC regulation. PE's might nevertheless decide
to recommend non-destructive shell testing and fencing of the entire footprint of the facility for
reasons other than compliance with the SPCC rule (e.g., to protect an owner's investment in
equipment or to meet other local, state or federal requirements).
SPCC GUIDANCE FOR REGIONAL INSPECTORS H-119
-------
Appendix H: Other Policy Documents
Finally, this letter is meant to provide guidance on the "equivalent environmental
protection" standard. It does not, however, substitute for EPA's statutes or regulations, nor does
it itself constitute a regulation. Thus, it cannot impose legally-binding requirements on EPA,
States, or the regulated community, and its recommendations may not be appropriate at an
individual site based on site-specific circumstances.
Sincerely,
Marianne Larmont Horinko
Assistant Administrator
SPCC GUIDANCE FOR REGIONAL INSPECTORS H-120
-------
Appendix H: Other Policy Documents
.
> m \ UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
\f]^ % WASHINGTON, D.C. 20460
NOV 7 2006
OFFICE OF
,,„. T . _, • ,r- -^ • •, SOLID WASTE AND
Mr. Brian Jennings, Executive Vice President EMERGENCY RESPONSE
American Coalition for Ethanol
2500 S. Minnesota Ave, #200
Sioux Falls, SD 57 105
Dear Mr. Jennings:
The purpose of this letter is to respond to your September 26 correspondence concerning
the applicability of the U.S. EPA's Facility Response Plan (FRP) regulations to ethanol
production and storage facilities and whether denatured ethanol is an "oil." We appreciate your
concerns for prevention of oil spills to the environment and trust that this response will clarify
EPA's position. Please note that although EPA works closely with the U.S. Department of
Transportation (DOT) and the U.S. Coast Guard (USCG) in oil spill prevention, preparedness,
and response, we can only address those facilities and regulations under our jurisdiction in
response to your concerns.
As you indicated, EPA 40 CFR Parts 1 12.20 and 1 12.21 require facilities that exceed
certain oil storage capacity thresholds and that because of their location could reasonably be
expected to cause substantial harm to the environment by discharging into or on navigable waters,
adjoining shorelines, or the exclusive economic zone, to prepare and submit an FRP. Inspectors
from EPA's Region 8 recently visited five ethanol production facilities and found that four require
an FRP because their total oil storage capacity exceeds the one million gallon threshold and they
meet one or more of the substantial harm criteria at 40 CFR Part 1 12.20(f)(l). Two of the four
have already submitted FRPs to the Region. The remaining two facilities elected to modify their
process operations such that each facility's total oil storage capacity would fall below the
applicable threshold, and thus, would no longer be subject to the FRP requirements.
One of the key factors driving FRP applicability is total oil storage capacity. You
requested that EPA clarify that storage tanks containing denatured ethanol are not to be included
when determining whether a facility exceeds the FRP total oil storage capacity threshold.
However, this depends on the denaturant and whether it is an oil. If a facility uses gasoline as the
denaturant, which is defined as a "petroleum oil" in 40 CFR Part 1 12.2, then the "storage capacity"
defined in Part 1 12.2 is "the shell capacity of the container." Therefore, any containers used to
store oil or fluids that include oil would need to be considered when determining whether a
facility's overall oil storage capacity exceeds the FRP applicability threshold. Although the DOT
regulations at 49 CFR 130.2(c)(l) provide for an oil concentration threshold of 10% for
containment and response planning requirements applicable to transportation of oil by motor
vehicles and rolling stock, there is no de minimis oil concentration in EPA's definition of oil for
facilities in its jurisdiction, other than the determination that the oil could reasonably be expected
Internet Address (URL) • http://www.epa.gov
Recycled/Recyclable • Printed with Vegetable Oil Based Inks on 100% Postconsumer, Process Chlorine Free Recycled Paper
SPCC GUIDANCE FOR REGIONAL INSPECTORS H-121
-------
Appendix H: Other Policy Documents
to be discharged to navigable waters in quantities that may be harmful, as described in 40 CFR
1 10.3 (violates water quality standards or causes a sheen).
In summary, once the determination is made that oil at a facility could reasonably be
expected to be discharged to navigable water in quantities that may be harmful then, because
gasoline is an oil, tanks storing ethanol denatured with 5% gasoline are oil tanks and the shell
capacity of such tanks must be included in the facility's total oil storage capacity when
determining applicability under 40 CFR Part 1 12, including the FRP requirements.
If you have any further questions on this issue, please contact Craig Matthiessen, Director
of the Regulation and Policy Development Division in the Office of Emergency Management at
202-564-8016.
Sincerely,
-
Parker Bodine
Assistant Administrator
SPCC GUIDANCE FOR REGIONAL INSPECTORS ' H-122
-------
Appendix H: Other Policy Documents
WASHINGTON, D.C, 20460
December 10, 2010
American Petroleum Institute
ATTN: Roger Claff, P.E.
Sr. Scientific Advisor
1220 L Street, Northwest
Washington, DC 20005-4070
(SENT VIA EMAIL)
RE: SPCC concerns related to gas plants
Dear Roger,
Thank you and the members of the API upstream SPCC committee for taking the time to meet
with my staff on November 10, 2010 to discuss concerns raised in your June 28, 2010 letter. I
also appreciate your willingness to provide my staff additional time to address your letter and
concerns in light of the unprecedented resource impacts the Deep Water Horizon incident had on
our office. The meeting was timely; as it provides a year until the compliance date arrives to
further clarify any applicability concerns for facility specific SPCC provisions regarding gas
plants/compression stations.
As discussed in the meeting and in comments my staff provided to the API Bulletin D-16
document submitted April 28, 2010, gas plants are generally not considered oil production
facilities under the SPCC rule and are therefore subject to the facility specific requirements under
40 CFR part 112.8 rather than 112.9. Although not specifically addressed in your letter, you also
raised concerns regarding gas compression stations and the applicability of the facility specific
SPCC requirements. As with gas plants, gas compression stations are not generally considered
oil production facilities under the SPCC rule and are therefore subject to the facility specific
requirements under 40 CFR part 112.8 rather than 112.9.
We share your concerns about providing a consistent interpretation of the rule with regard to the
applicability of facility specific SPCC requirements at gas plants. We have discussed the
application of the facility specific requirements to gas plant and compression stations with
regional office personnel, and are confident inspection personnel are consistently interpreting the
SPCC GUIDANCE FOR REGIONAL INSPECTORS H-136
-------
Appendix H: Other Policy Documents
-2-
regulation as described above. With almost a year to work collaboratively on guidance on this
issue, we look forward to working with you on text and examples that address site specific issues
which may be incorporated into the API Bulletin D-16 document and/or future EPA guidance.
Again, thank you for bringing your concern to our attention. Please call Mark W. Howard at
202-564-1964 with any questions.
R. Craig Matthiessen, PE, FAIChE
Director
Regulation and Policy Development Division
CC: Regional Oil Program Managers
James Bove, OGC
David Drelich, OECA
SPCC GUIDANCE FOR REGIONAL INSPECTORS H-137
-------
Appendix H: Other Policy Documents
EPA JURISDICTION AT COMPLEXES
8/23/20/3
SPCC GUIDANCE FOR REGIONAL INSPECTORS H-138
-------
BREAKOUT TANKAGE
Appendix H: Other Policy Documents
Fence
Legend
Pump
Valve
Meter
• EPA jurisdiction1
> May be regulated by other agencies
J
\
M)
i
I
t
J--I.
*
\
Product t
Tank t
(Breakout) i
i
Mom Line
Note that EPA does not have jurisdiction in this example.
EPA Jurisdiction at Complexes
SPCC GUIDANCE FOR REGIONAL INSPECTORS
08/23/2013, Page 1
H-139
-------
STORAGE TANKAGE
Appendix H: Other Policy Documents
Fence
Product
Tank
(Storage)
Product
Tank
(Storage)
a
en
a
Q
Legend
* Pump
*• Valve
M Meter
Isolation
Flange
i EPA jurisdiction*
• May be regulated by
other agencies*
A/lain Line
* This diagram does not identify the precise location where the change in jurisdiction may occur between EPA and any other agencies for the purpose of
the Clean Water Act, Section 311 (j) (33 USC 1321 (j)). When the pipeline operator and the storage or breakout tank operator remain the same, the change
in jurisdiction occurs at the first meter, valve, or isolation flange at or inside the facility property line. When the pipeline operator and the storage or
breakout tank operator are not the same, the change in jurisdiction occurs at the change in operational responsibility or at the first meter, valve, or isolation
flange at or inside the facility property line. In either of the above situations, the location of the property line should not solely be used to determine
jurisdiction when operational activities (loading/offloading) extend beyond the property line.
EPA Jurisdiction at Complexes
SPCC GUIDANCE FOR REGIONAL INSPECTORS
08/23/2013, Page 2
H-140
-------
Appendix H: Other Policy Documents
Fence
STORAGE TANKAGE
Legend
Pump
Valve
Meter
1 EPA jurisdiction*
• May be regulated by other agencies*
• EPA jurisdiction and may also be
regulated by other agencies*
Processing
Plant
Product
Tank
(Storage)
•
Main Line
* This diagram does not identify the precise location where the change in jurisdiction may occur between EPA and any other agencies for the purpose of
the Clean Water Act, Section 311 (j) (33 USC 1321 (j)). When the pipeline operator and the storage or breakout tank operator remain the same, the change
in jurisdiction occurs at the first meter, valve, or isolation flange at or inside the facility property line. When the pipeline operator and the storage or
breakout tank operator are not the same, the change in jurisdiction occurs at the change in operational responsibility or at the first meter, valve, or isolation
flange at or inside the facility property line. In either of the above situations, the location of the property line should not solely be used to determine
jurisdiction when operational activities (loading/offloading) extend beyond the property line.
EPA Jurisdiction at Complexes
SPCC GUIDANCE FOR REGIONAL INSPECTORS
08/23/2013, PageS
H-141
-------
Appendix H: Other Policy Documents
BREAKOUT AND STORAGE TANKAGE - EPA and Other Agencies Jurisdiction
(A)
Fence
(B)
Fence
i
•
•
&
•
i
i
t Product
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(Breakout)
\ (Storage)
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ixr
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1 EPA jurisdiction*
• May be regulated by other agencies*
• EPA jurisdiction and may also be regulated by other agencies*
* This diagram does not identify the precise location where the change in jurisdiction may occur between EPA and any other agencies for the purpose of
the Clean Water Act, Section 311 (j) (33 USC 1321 (j)). When the pipeline operator and the storage or breakout tank operator remain the same, the change
in jurisdiction occurs at the first meter, valve, or isolation flange at or inside the facility property line. When the pipeline operator and the storage or
breakout tank operator are not the same, the change in jurisdiction occurs at the change in operational responsibility or at the first meter, valve, or isolation
flange at or inside the facility property line. In either of the above situations, the location of the property line should not solely be used to determine
jurisdiction when operational activities (loading/offloading) extend beyond the property line.
EPA Jurisdiction at Complexes
SPCC GUIDANCE FOR REGIONAL INSPECTORS
08/23/2013, Page 4
H-142
-------
Appendix H: Other Policy Documents
BREAKOUT AND STORAGE TANKAGE - EPA and Other Agencies Jurisdiction
Fence
1
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^™ ^™ ^™ ™ agencies*
^ . . ^_ ... EPA jurisdiction and may also be
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1
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Main Line
* This diagram does not identify the precise location where the change in jurisdiction may occur between EPA and any other agencies for the purpose of
the Clean Water Act, Section 311 (j) (33 USC 1321 (j)). When the pipeline operator and the storage or breakout tank operator remain the same, the change
in jurisdiction occurs at the first meter, valve, or isolation flange at or inside the facility property line. When the pipeline operator and the storage or
breakout tank operator are not the same, the change in jurisdiction occurs at the change in operational responsibility or at the first meter, valve, or isolation
flange at or inside the facility property line. In either of the above situations, the location of the property line should not solely be used to determine
jurisdiction when operational activities (loading/offloading) extend beyond the property line.
EPA Jurisdiction at Complexes
SPCC GUIDANCE FOR REGIONAL INSPECTORS
08/23/2013, PageS
H-143
-------
STORAGE TANKAGE
Appendix H: Other Policy Documents
Fence
Legend
Pump
Valve
Meter
Isolation
Flange
• EPA jurisdiction*
. May be regulated by
other agencies*
Product
Tank
(Storage)
Product
Tank
(Storage)
Product
Tank
(Storage)
Product
Tank
(Storage)
Main Line
* This diagram does not identify the precise location where the change in jurisdiction may occur between EPA and any other agencies for the purpose of
the Clean Water Act, Section 311 (j) (33 USC 1321 (j)). When the pipeline operator and the storage or breakout tank operator remain the same, the change
in jurisdiction occurs at the first meter, valve, or isolation flange at or inside the facility property line. When the pipeline operator and the storage or
breakout tank operator are not the same, the change in jurisdiction occurs at the change in operational responsibility or at the first meter, valve, or isolation
flange at or inside the facility property line. In either of the above situations, the location of the property line should not solely be used to determine
jurisdiction when operational activities (loading/offloading) extend beyond the property line.
EPA Jurisdiction at Complexes
SPCC GUIDANCE FOR REGIONAL INSPECTORS
08/23/2013, Page 6
H-144
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Appendix H: Other Policy Documents
BREAKOUT AND STORAGE TANKAGE - EPA and Other Agencies Jurisdiction
Fence
/ Mix \
f Tank \
i (Breakout) }
& '
M
Legend
Pump
Valve
Meter
1 EPA jurisdiction*
t May be regulated
by other agencies*
EPA jurisdiction
and may also be
regulated by other
agencies*
Mix
/ Tank
« (Breakout) •
\ & '
\ (Storage}
»
Product
Tank
(Storage)
Product
Tank
(Storage)
•••••••• •• i^m m m mm^p • i^m • • m&fammmi ••••••• mm
P
f
i™.z±q[zqjzr~:zr!~~z:zi
i
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(Breakout
& /
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m ^•B" •n^" • • ™C" • ^^ • •!•• • i
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V &
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• i^n trnmm •• •
-+••
^
r^-
i
t
i
T
w
•
—\
:>
-------
Appendix H: Other Policy Documents
STORAGE TANKAGE ASSOCIATED WITH PRODUCTION/GATHERING LINES
Legend
* Pump
•* Valve
M Meter
Production/Gathering
Product \ Flowline
Tank
(Storage)
Oil Field*
1 EPA jurisdiction*
1 May be regulated by other agencies
• EPA jurisdiction for intra-facility
gathering lines and may also be
regulated by other agencies*
Q
3"
r—
3" ,,
CD A
X
a>
c
a
O
Individual Well Heads
may include Storage Tanks
Product
Tank
(Storage)
Truck transferring
from Oil Field*
I
1
I
•
•
L _
I
•
Gathering Line"
*ln 40 CFR 112.1, 112.7 and 112.9 EPA regulates onshore oil production facilities as defined in 112.2 including wells, flowlines, separation equipment, storage
facilities, intra-facility gathering lines and auxiliary non-transportation-related equipment and facilities.
** EPA jurisdiction applies to all gathering lines located within an SPCC-regulated facility (i.e., intra-facility gathering lines). However, EPA exempts intra-facility
gathering lines subject to the regulatory requirements of 49 CFR part 192 or 195, except that such lines must be identified and marked as exempt on the facility
diagram.
EPA Jurisdiction at Complexes 08/23/2013, Page 8
SPCC GUIDANCE FOR REGIONAL INSPECTORS H-146
-------
BREAKOUT AND
STORAGE TANKAGE -
EPA and Ofher
Agencies Jurisdiction
Appendix H: Other Policy Documents
Fence
Legend
• Pump
•• Valve
M Meter
1 EPA jurisdiction*
1 May be regulated by other agencies*
EPA jurisdiction and may also be
regulated by other agencies*
T
*
•
($$)
Refinery
X X
/ Product
Tank
I (Storage)
&
\ (Breakout)
Product
Tank
(Storage)
i
i
*
i
jxr
IXI
Main Line
* This diagram does not identify the precise location where the change in jurisdiction may occur between EPA and any other agencies for the purpose of
the Clean Water Act, Section 311 (j) (33 USC 1321 (j)). When the pipeline operator and the storage or breakout tank operator remain the same, the change
in jurisdiction occurs at the first meter, valve, or isolation flange at or inside the facility property line. When the pipeline operator and the storage or
breakout tank operator are not the same, the change in jurisdiction occurs at the change in operational responsibility or at the first meter, valve, or isolation
flange at or inside the facility property line. In either of the above situations, the location of the property line should not solely be used to determine
jurisdiction when operational activities (loading/offloading) extend beyond the property line.
EPA Jurisdiction at Complexes
SPCC GUIDANCE FOR REGIONAL INSPECTORS
08/23/2013, Page 9
H-147
-------
Appendix H: Other Policy Documents
EPA, COAST GUARD, AND O7HER AGENCIES JURISDICTION AT COMPLEX FACILITY
segment of a complex is under CG
jurisdiction for the purpose of CWA
Section 311 (i).
1
ed Facility
t. 1020. This
erCG
CWA
• •••••••••••••••i m-m
*-
• ••• • ••••, ••••
I 1
• 1
• •
• _
i A
• X
* * T
t^x .,
/' x
Product
/ Tank2
j (Storage)
M
\
A t
&
(Breakout)
», ^*
\
I
•
f
§
*l
*
*
m
m
i
i
*
*
"^
2 The tank depicted is used for storage
associated with the MTR facility and is
under EPA jurisdiction. If the tank is
also used as a breakout tank, it may
be subject to both EPA and another
Agency jurisdiction.
! » - — ..-.--
MARINE LOADING DOCK'
Ct i
' '-'1 I , 1
Legend
§ Pump
90 Valve
CD
.C
03
May be regulated by other agencies*
EPA jurisdiction and may also be regulated by
other agencies*
* This diagram does not identify the precise location where the change in jurisdiction may occur between EPA and any other agencies for the purpose of
the Clean Water Act, Section 311 (j) (33 USC 1321 (j)). When the pipeline operator and the storage or breakout tank operator remain the same, the change
in jurisdiction occurs at the first meter, valve, or isolation flange at or inside the facility property line. When the pipeline operator and the storage or
breakout tank operator are not the same, the change in jurisdiction occurs at the change in operational responsibility or at the first meter, valve, or isolation
flange at or inside the facility property line. In either of the above situations, the location of the property line should not solely be used to determine
jurisdiction when operational activities (loading/offloading) extend beyond the property line.
EPA Jurisdiction at Complexes
SPCC GUIDANCE FOR REGIONAL INSPECTORS
08/23/2013, Page 10
H-148
-------
Appendix H: Other Policy Documents
Environmental Protection Agency
ATTACHMENTS TO APPENDIX C
Pt. 112, App. C
Attachment C-I
Flowchart of Criteria for Substantial Harm
Does the facility transfer oil over
water to or from vessels and does
the facility have a total oil
storage capacity greater than or
equal to 42,000 gallons?
Submit Response Plan
Does the facility have a total oil
storage capacity greater than or
equal to 1 million gallons?
Within any abovcground storage tank area,
does the facility lack secondary
containment that is sufficiently large to
contain the capacity of the largest
aboveground oil storage tank plus
sufficient freeboard to allow for
precipitation?
Is the facility located at a distance1 such
that a discharge from the facility could
cause injury to fish and wildlife and
sensitive environments2?
No
Is the facility located at a distance1 such
that a discharge from the facility would
shut down a public drinking water intake3"
Has the facility experienced a reportable oil
spill in an amount greater than or equal to
10,000 gallons within the last five years?
No Submittal of Response Plan
Except at RA Discretion
1 Calculated using the appropriate formula in Attachment C-III to this appendix or a comparable
formula.
2 For further description offish and wildlife and sensitive environments, see Appendices I,II, and
III to DOC/NOAA's "Guidance for Facility and vessel response Plans: Fish and Wildlife and
Sensitive Environments" (59 FR 14713, March 29, 1994) and the applicable Area Contingency
Plan.
3 Public drinking water intakes are analogous to public water systems as described at CFR
143.2(c).
57
SPCC GUIDANCE FOR REGIONAL INSPECTORS
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Appendix H: Other Policy Documents
Pt. 112, App. C
ATTACHMENT C-II—CERTIFICATION OF THE AP-
PLICABILITY OF THE SUBSTANTIAL HARM CRI-
TERIA
Facility Name:
Facility Address:
1. Does the facility transfer oil over water
to or from vessels and does the facility have
a total oil storage capacity greater than or
equal to 42,000 gallons?
Yes No
2. Does the facility have a total oil storage
capacity greater than or equal to 1 million
gallons and does the facility lack secondary
containment that is sufficiently large to
contain the capacity of the largest above-
ground oil storage tank plus sufficient
freeboard to allow for precipitation within
any aboveground oil storage tank area?
Yes No
3. Does the facility have a total oil storage
capacity greater than or equal to 1 million
gallons and is the facility located at a dis-
tance (as calculated using the appropriate
formula in Attachment C-III to this appen-
dix or a comparable formula1) such that a
discharge from the facility could cause in-
jury to fish and wildlife and sensitive envi-
ronments? For further description of fish and
wildlife and sensitive environments, see Ap-
pendices I, II, and III to DOC/NOAA's "Guid-
ance for Facility and Vessel Response Plans:
Fish and Wildlife and Sensitive Environ-
ments" (see appendix B to this part, section
13, for availability) and the applicable Area
Contingency Plan.
Yes No
4. Does the facility have a total oil storage
capacity greater than or equal to 1 million
gallons and is the facility located at a dis-
tance (as calculated using the appropriate
formula in Attachment C-III to this appendix
or a comparable formula1) such that a dis-
charge from the facility would shut down a
public drinking water intake2?
Yes No
5. Does the facility have a total oil storage
capacity greater than or equal to 1 million
gallons and has the facility experienced a re-
portable oil discharge in an amount greater
than or equal to 10,000 gallons within the last
5 years?
Yes No
Certification
I certify under penalty of law that I have
personally examined and am familiar with
the information submitted in this document,
1lf a comparable formula is used, docu-
mentation of the reliability and analytical
soundness of the comparable formula must
be attached to this form.
2 For the purposes of 40 CFR part 112, pub-
lic drinking water intakes are analogous to
public water systems as described at 40 CFR
143.2(c).
40 CFR Ch. I (7-1-13 Edition)
and that based on my inquiry of those indi-
viduals responsible for obtaining this infor-
mation, I believe that the submitted infor-
mation is true, accurate, and complete.
Signature
Name (please type or print)
Title
Date
ATTACHMENT C-III—CALCULATION OF THE
PLANNING DISTANCE
1.0 Introduction
1.1 The facility owner or operator must
evaluate whether the facility is located at a
distance such that a discharge from the fa-
cility could cause injury to fish and wildlife
and sensitive environments or disrupt oper-
ations at a public drinking water intake. To
quantify that distance, EPA considered oil
transport mechanisms over land and on still,
tidal influence, and moving navigable
waters. EPA has determined that the pri-
mary concern for calculation of a planning
distance is the transport of oil in navigable
waters during adverse weather conditions.
Therefore, two formulas have been developed
to determine distances for planning purposes
from the point of discharge at the facility to
the potential site of impact on moving and
still waters, respectively. The formula for oil
transport on moving navigable water is
based on the velocity of the water body and
the time interval for arrival of response re-
sources. The still water formula accounts for
the spread of discharged oil over the surface
of the water. The method to determine oil
transport on tidal influence areas is based on
the type of oil discharged and the distance
down current during ebb tide and up current
during flood tide to the point of maximum
tidal influence.
1.2 EPA's formulas were designed to be
simple to use. However, facility owners or
operators may calculate planning distances
using more sophisticated formulas, which
take into account broader scientific or engi-
neering principles, or local conditions. Such
comparable formulas may result in different
planning distances than EPA's formulas. In
the event that an alternative formula that is
comparable to one contained in this appen-
dix is used to evaluate the criterion in 40
CFR 112.20(f)(l)(ii)(B) or (f)(l)(ii)(C), the
owner or operator shall attach documenta-
tion to the response plan cover sheet con-
tained in appendix F to this part that dem-
onstrates the reliability and analytical
soundness of the alternative formula and
shall notify the Regional Administrator in
58
SPCC GUIDANCE FOR REGIONAL INSPECTORS
H-150
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Construct New Secondary Containment
EXAMPLE
This worksheet determines the possible dimensions for a rectangular or square dike or berm to meet the
secondary containment requirement for aboveground bulk storage containers.
Steps:
A. Determining required dike or berm dimensions for largest single tank
1. Calculate the volume of the tank
2. Specify the containment wall height and one containment lateral dimension D1 to calculate
lateral dimension D2
3. Calculate the volume of rain, VRain to be collected in the secondary containment with area ASc
for the specified rain event
4. Calculate the required secondary containment volume, VscReq to account for the additional
volume of rain, VRain
B. Accounting for the displacements from other vertical cylindrical tanks to be located in dike
or berm with the largest tank
C. Accounting for the displacements from other horizontal cylindrical tanks to be located In
dike or berm with the largest tank
1. For SCHeight (ft), calculate the displacement from additional horizontal cylindrical tanks, Tank 2,
3, 4, etc., to be located with the largest tank in the dike or berm
2. Calculate the total displacement volume from the additional horizontal cylindrical tanks in the
dike or berm
D. Accounting for the displacements from other rectangular tanks to be located in dike or berm
with the largest tank
1. For SCHeight (ft), calculate the displacement from additional rectangular tanks, Tank 2, 3, 4, etc.,
to be located with the largest tank in the dike or berm
2. Calculate the total displacement volume from the additional rectangular tanks in the dike or berm
Disclaimer: Please note that these are simplified calculations for qualified facilities that assume: 1) the
secondary containment is designed with a flat floor; 2) the wall height is equal for all four walls; and 3) the
corners of the secondary containment system are 90 degrees. Additionally, the calculations do not include
displacement for support structures or foundations. For Professional Engineer (PE) certified Plans, the PE
may need to account for site-specific conditions associated with the secondary containment structure which
may require modifications to these sample calculations to ensure good engineering practice.
SPCC GUIDANCE FOR REGIONAL INSPECTORS
July 2011-Page 1 of 9
H-151
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Construct New Secondary Containment
EXAMPLE
Information needed to use this worksheet:
• Tank shell capacity, diameter, length, and height
See diagram for dimensions
• Secondary containment wall height
Cannot exceed 6 feet per local fire code
• Rainfall amount
Rainfall can collect in the secondary containment; the selected rain event for
the location is 6 inches.
• Other considerations
With a proposed containment wall height of 5 ft. and one lateral containment
dimension of 10 ft., the height of Tank B below the top of the wall is 4 ft.
8.5ft
A
4,000 gal
10ft
B
2,140 gal
4ft
SPCC GUIDANCE FOR REGIONAL INSPECTORS
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Construct New Secondary Containment
EXAMPLE
A. Determining required dike or berm dimensions for largest single tank
1. Calculate the volume of the tank
Largest Tank Shell Capacity (gal) =
Largest Tank Volume (ft3) =
ftd
Note that state and local fire and safety codes may prescribe limits on the height of containment walls, minimum
separation distances between tanks, and setback distances. For instance, Occupational Safety and Health
Administration (OSHA) flammable and combustible liquids standards in 29 CFR 1910.106 prescribe separation
distances between adjacent tanks. Such requirements may present constraints on the location, dimensions, and
configuration of the secondary containment structure. The footprint of the tank or tanks and arrangement of the
tanks when there is to be more than a single tank within secondary containment may also present constraints on
the containment dimensions.
2. Specify the containment wall height and one containment lateral dimension D1 to calculate
lateral dimension D2
r
Height of Containment Wall, SCHeight (ft) =
Height of Containment Wall, SCHeight (in) =
=
D1(ft) =
b is the volume of the largest ^.^ ,,.<.
tank calculated in Step 1. U£ (Jl) -
^
5
c
5
c(ft)
60
d
10
e
535
b (ft3)
ft
x 12
in/ft
in
ft
4- 10 10.7 ft
c (ft) e (ft) f
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Construct New Secondary Containment
EXAMPLE
3. Calculate the volume of rain, VRain to be collected in the secondary containment with area ASc
for the specified rain event
Selected Rainfall Event:
24— H r 25— Yr Rainfall (in) =
f is lateral dimension D2 „
calculated in Step 2. A$c (ft) =
VRain (ft3) =
=
v
6
g
10
e(ft)
6
g(in)
53.5
i
">
in
x 10.7 = 107 ft2
f (ft) h
•• 12 x 107
in/ft h (ft2)
ft3
J
4. Calculate the required secondary containment volume, VScReq to account for the additional
volume of rain, VRain
b is the volume of the largest • / ,,x ,
tank calculated in Step 1. VSCReq ( n) -
^
535
b (ft3)
+
53.5
i (ft3)
=
588.5
J
ft3
j
Vary the secondary containment height and lateral dimensions, or footprint, in Step 2 to meet any space or
dimension constraints or requirements and the required containment volume, VSCReq by using VSCReq in place of the
volume of the largest shell capacity tank, b in Step 2.
2. (Repeated with a required containment capacity of 588.5 ft3) Specify the containment wall
height and one containment lateral dimension D1 to calculate lateral dimension D2
>^""
' Height of Containment Wall, SCHe/g« (ft) =
Height of Containment Wall, SCHeight (in) =
=
D1 (ft) =
b is the volume of the largest tank
calculated in Step 1.
588.5 ff was used for this
calculation. D2 (ft) =
\^
5
c
5
c(ft)
60
d
10
e
588.5
b (ft3)
x 12
in/ft
in
ft
4- 5 4- 10 • 11.8 ft
c(ft) e(n) f y
For the same containment wall height and lateral dimension D1, D2 has to increase to 11.8 ft for the secondary
containment capacity to be adequate.
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Construct New Secondary Containment
EXAMPLE
IF APPLICABLE: When other tanks or containers are also to be located within the secondary containment along
with the largest tank, calculate the displacement volumes from these other tanks or containers using Parts B, C and
D as applicable. Add the total displacement volume from the other tanks or containers to the volume of rain, VRain
and the largest tank volume, b, in Step 1, to obtain a net secondary containment volume, VNetsc:
V/VefSC (ft3) =
j is the required secondary containment
volume calculated in Step 4.
Total Displacement
Volume (ft3)
Note: In this example, the total displacement of 331 ft3 result from the displacement of 203 ft3 from the horizontal
cylindrical tank calculated in Part C and 128 ft3 from the rectangular tank calculated in Part D.
Vary the secondary containment height and lateral dimensions, or footprint, in Step 2 to meet any space or
dimension constraints or requirements and the net required containment volume, VNetSc by using VNetSc in place of
the volume of the largest shell capacity tank, b.
2. (Repeated with a required containment capacity of 919.5 ft3) Specify the containment wall
height and one containment lateral dimension D1 to calculate lateral dimension D2
^^^
Height of Containment Wall, SCHeight (ft) =
Height of Containment Wall, SCHeiqht (in) =
=
D1(ft) =
b is the volume of the largest tank
calculated in Step 1.
919.5ft3 was used for this
calculation. D2 (ft) =
^
6
c
6
c(ft)
72
d
10
e
919.5
b (ft3)
ft
x 12
in/ft
in
ft
-6-10 • 15.3 ft
c(ft) e(ft) f
Increasing the containment wall height from 5 ft. to the limit of 6 ft. with the same D1 lateral dimension of 10 ft.
increases D2 to 15.3 ft. for the secondary containment capacity to be adequate and account for the other tank
displacements. Changing the containment wall height will require reviewing and recalculating displacement
volumes if necessary as the tank heights below the top of the wall may change. Also, as the containment area or
footprint increase, recalculations of the corresponding increase in the volume of rain, VRain, that can collect in the
containment using Step 3 and reassessment of containment capacity will be necessary.
B. Accounting for the displacements from other vertical cylindrical tanks to be located in dike or
berm with the largest tank
The single vertical cylindrical tank is the largest shell capacity tank; there are no other vertical cylindrical tanks
within the same secondary containment.
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Construct New Secondary Containment
EXAMPLE
C. Accounting for the displacements from other horizontal cylindrical tanks to be located in dike
or berm with the largest tank
1. For SCHeight (ft), calculate the displacement from additional horizontal cylindrical tanks, Tank 2,
3, 4, etc., to be located with the largest tank in the dike or berm
The easiest way to determine the displacement volume in a horizontal cylindrical tank is to use the tank
manufacturer's liquid height to gallons conversion chart for the tank in Method 1 calculation. If this information is not
available, use Method 2 calculation to obtain the displacement volumes.
METHOD 1
Height of Tank B Below Containment Wall (in) =
Displacement (gal) From Tank Conversion Chart =
Displacement (fr) =
x 0.1337 =
ft3/gal
Repeat to calculate the displacement of each additional horizontal cylindrical tank located with the
largest tank in the dike or berm.
Total Displacement Volume (ft3) =
METHOD 2
Height of Tank B Below =
Containment Wall (in)
Tank B Diameter (in) =
Height to Diameter =
Ratio for Tank B
Tank B Volume Fraction for =
Height to Diameter Ratio (Table)
If the tank shell capacity in gallons is known:
Tank Volume VTankB (ft3) =
t(in)
in
6
Diameter
(ft)
48
x 12
in/ft
72
72
u
0.67
u(in)
Shell Capacity
(gal)
0.1337
ft3/gal
in
SPCC GUIDANCE FOR REGIONAL INSPECTORS
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Construct New Secondary Containment
EXAMPLE
METHOD 2 (CONT)
Or, if the tank shell capacity in gallons is not known:
Tank B radius (ft) =
VTmkB(ft3)= 3.14
Radius Tank Length
Displacement, VTankB (ft3) = 286
xory
(ft3)
Repeat to calculate the displacement volume of each additional horizontal cylindrical tank to be located
with the largest tank in the dike or berm.
2. Calculate the total displacement volume from the additional horizontal cylindrical tanks in the
dike or berm
f
Tnfzil /"J/cn/^jr^An^nf \/nliim& (u) —
z is the displacement volume
calculated in Step 1, Method 2 of C.
=
L
203
z (ft3)
203
aa
+ 0
z1 (ft3)
ft3
h 0
z2 (ft3)
^
+
J
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Construct New Secondary Containment
EXAMPLE
D. Accounting for the displacements from other rectangular tanks to be located in dike or berm
with the largest tank
1. Calculate the total displacement volume from the additional horizontal cylindrical tanks in the
dike or berm
Height of Tank C Below Containment Wall (ft) =
Length of Tank C (ft) =
Width of 'Tank 2 (ft) =
Displacement Area, DATankC(ff) =
Displacement Volume, DVTankC (ft3) =
Repeat Step 1 to calculate the displacement are
^located with the largest tank in the dike or berm.
4
ab
8
ac
4
ad
8
ft
x 4 = 32 ft2
ac (ft) ad (ft) ae
32
ae (ft2)
128
x 4
ab (ft)
ft3
af
a and volume of each additional rectangular tank to be
J
2. Calculate the total displacement volume from the additional horizontal cylindrical tanks in the
dike or berm
0
Total Displacement Volume (ff) = \ 203 | +
af is the displacement volume of/ft3\ of1 /ft3\
calculated in Step 1 of D. aT (n > aT ' ^n >
0
af2 (ft3)
ft3
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Construct New Secondary Containment
EXAMPLE
Calculated acceptable dike dimensions
The preceding calculations produced the following dimensions shown in the diagram for one possible
dike configuration that would meet the required secondary capacity to conform to the SPCC regulation
and the local fire code's 6 ft dike height limit.
10
15.3ft
SPCC GUIDANCE FOR REGIONAL INSPECTORS
July 2011-Page 9 of 9
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Multiple Horizontal Cylindrical Tanks Inside a Rectangular or Square Dike or Berm
EXAMPLE
This worksheet calculates the secondary containment volume of a rectangular or square dike or berm for
three horizontal cylindrical tanks. In this example, displacements of the tanks except for the largest tank
in the berm must be accounted for when determining the required secondary containment volume.
2b.
3.
4.
5.
15ft
Determine the volume of the secondary containment, VSc
Determine the volume of the tank when the tank shell
capacity is unknown, VTank
Determine the volume of the tank when shell capacity is
known, VTank
Determine the unavailable (displacement) areas and
volumes in the containment due to other tanks within the
containment and the net containment volume remaining
for the largest tank
Determine the percentage of the net secondary
containment volume, VscNetto the largest tank volume,
Vjank
Determine whether the secondary containment can
contain the entire tank shell capacity with additional
capacity to contain rain.
Diameter- 4 ft
Length=5 5 ft
Height Below Top of Containment Wall= 2ft
Information needed to use this
worksheet:
• Tank shell capacity
Tanks A (off-road diesel) and B
(on-road diesel) each has a shell
capacity of 2,500 gallons while
Tank C (gasoline) has a shell
capacity of 500 gallons. Diameters
and lengths of the tanks are as
shown.
• Secondary containment length,
width, and height
See diagram for dimensions.
• Height of each tank below top of
containment wall (except largest
tank)
See diagram for dimensions
• Rainfall amount
Rainfall can collect in the
secondary containment; the
selected rain event for the location
is 7 inches.
Diameter= 6.5 ft
• Length=lOft
Height Below Top of Containment \
or Berm
2ft
20ft
Largest Tank Shell Capacity (gal) = | 2,500
a
Disclaimer: Please note that these are simplified calculations for qualified facilities that assume: 1) the
secondary containment is designed with a flat floor; 2) the wall height is equal for all four walls; and 3) the
corners of the secondary containment system are 90 degrees. Additionally, the calculations do not include
displacement for support structures or foundations. For Professional Engineer (PE) certified Plans, the PE
may need to account for site-specific conditions associated with the secondary containment structure
which may require modifications to these sample calculations to ensure good engineering practice.
July 2011-Page 1 of 7
SPCC GUIDANCE FOR REGIONAL INSPECTORS
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Ij Multiple Horizontal Cylindrical Tanks Inside a Rectangular or Square Dike or Berm
EXAMPLE
1. Determine the volume of the secondary containment, VSc
^"^
v Secondary Containment Area, Asc =
=
Vsc (ff) =
V
20
Length
(ft)
300
b
300
b
(ft2)
x 15
Width
(ft)
ft2
x 3
Height
(ft)
^^^
>
900 ft3
c
J
2a. Determine the volume of the tank when the tank shell capacity is unknown, \/^nk
Tank radius (ft) =
Diameter
(ft)
VTank(f13)= 3.14
Radius2
(ft)2
Tank
Length
(ft)
2b. Determine the volume of the tank when shell capacity is known, \/^nk
a is the tank shell capacity ]/ /ff) _
from page 1.
a (gal)
x 0.1337 =
ft3/gal
3. Determine the unavailable (displacement) areas and volumes in the containment due to other
tanks within the containment and the net containment volume remaining for the largest tank
The easiest way to determine the displacement volume in a horizontal cylindrical tank is to use the tank
manufacturer's liquid height to gallons conversion chart for the tank in Method 1 calculation. If this information is not
available, use Method 2 calculation to obtain the displacement volumes.
July 2011-Page 2 of 7
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Ij Multiple Horizontal Cylindrical Tanks Inside a Rectangular or Square Dike or Berm
EXAMPLE
METHOD 1
Height of Tank B Below Containment Wall (in) =
Displacement (gal) From Tank Conversion Chart =
VTankB Displacement (ft3) =
in
gal
x 0.1337 =
ft3/gal
Calculate the displacement of each additional horizontal cylindrical tank within the same secondary
containment:
Total Displacement Volume (ft3) =
ft3
g2 (ft3)
i
METHOD 2
Height of Tank B Below =
Containment Wall (in)
Tank B Diameter (in) =
Height to Diameter =
Ratio for Tank B
Tank B Volume Fraction for =
Height to Diameter Ratio (Table) •
If the tank shell capacity in gallons is known:
Tank Volume VTankB (ft3) =
in
Shell Capacity
(gal)
12
in/ft
0.1337
ft3/gal
SPCC GUIDANCE FOR REGIONAL INSPECTORS
July 2011-Page 3 of 7
H-162
-------
Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Multiple Horizontal Cylindrical Tanks Inside a Rectangular or Square Dike or Berm
EXAMPLE
/"METHOD 2 (CONT) 'X
Or, if the tank shell capacity in aallons is not known:
Tank B radius (ft) =
D
VTankB(ft3) =
Displacement, VTankB (ft3) =
m is the tank volume (Tank B).
1 is the Tank B volume fraction for H/D ratio (table).
Calculate the displacement of each additional r
4- 2 ft
iameter (ft)
3.14
334
x ( )2 x = ft3
Radius Tank Length n
(ft) (ft)
x 0.263 = 88 ft3
m (ft3) I o
horizontal cylindrical tank within the same secondary
containment:
Height of Tank C Below =
Containment Wall (in)
Tank C Diameter (in) =
Height to Diameter =
Ratio for Tank C
Tank C Volume Fraction for =
Height to Diameter Ratio (Table)
Tank Volume VTankC (ff) =
S
Displacement, VTankc (ft3) =
Total Displacement Volume (ft3) =
Net Secondary Containment Volume:
Net Containment Volume, VSCNet (ff) =
c is the secondary contianment
, volume.
24
i
4
in
x 12 = 48 in
Diameter in/ft j
(ft)
24
i(in)
0.5
I
500
4- 48 0.50
• j(in) k
x 0.1337 = 67 ft3
nell Capac ty ff/gal m
(gal)
67
x 0.5 = 34 ft3
m (ft3) 1 01
88
o (ft3)
122
P
900
+ 34
01 (ft3)
ft3
— 122 = 778 ft3
c (ft') p (Method 2)
-------
Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Multiple Horizontal Cylindrical Tanks Inside a Rectangular or Square Dike or Berm
EXAMPLE
4. Determine the percentage of the net secondary containment volume, VscNet to the largest tank
volume, Vjank1 (to determine whether the volume of the containment is sufficient to contain the largest tank's
entire shell capacity).
r~
VsCNe/Vrank =
q is the net secondary contianment volume.
e is the tank volume calculated
in Step 2b of this worksheet.
^
% =
778
A
2.33
r
- 334
e (ff)
x 100
2.33
r
233
s
The percentage, s, is 233% which is greater than 100%. The secondary containment volume is sufficient to contain
the shell capacity of the largest tank after accounting for the displacements. However, we must also account for
rain that can collect in the dike or berm. See step 5.
5. Determine whether the secondary containment can contain the entire tank shell capacity with
additional capacity to contain rain.
If rain can collect in a dike or berm, the SPCC rule requires that secondary containment for bulk storage containers
have additional capacity to contain rainfall or freeboard. The rule does not specify a method to determine the
additional capacity required to contain rain or the size of the rain event for designing secondary containment.
However, industry practice often considers a rule of thumb of 110% of the tank capacity to account for rainfall. A
dike with a 110% capacity of the tank may be acceptable depending on, the shell size of the tank, local precipitation
patterns and frequency of containment inspections. In a different geographic area, a dike or berm designed to hold
110% for the same size tank may not have enough additional containment capacity to account for a typical rain
event in that area. The 110% standard may also not suffice for larger storm events. If you want to determine a
conservative capacity for a rain event, you may want to consider a 24-hour 25-year storm event. It is the
responsibility of the owner or operator2 to determine the additional containment capacity necessary to contain rain.
A typical rain event may exceed the amount determined by using a 110% "rule of thumb" so it is important to
consider the amount of a typical rain event when designing or assessing your secondary containment capacity.
Rainfall data may be available from various sources such as local water authorities, local airports, and the National
Oceanic and Atmospheric Administration (NOAA).
1 Steps 4 and 5 in the worksheet determines whether the net volume of the secondary containment is sufficient to contain the
largest tank's entire shell capacity and rainfall (freeboard for precipitation) as required by the SPCC rule. Step 4 primarily
determines whether the net volume of the secondary containment is sufficient to contain the entire shell capacity of the largest
tank. Step 5 is necessary to determine whether the secondary containment can also contain the expected volume of rainfall
(both the volume of rain that falls into the containment plus the rain from the tank storage site).
The SPCC rule does not require you to show the secondary containment calculations in your Plan. However, you should
maintain documentation of secondary containment calculations to demonstrate compliance to an EPA inspector.
July 2011-Page 5 of 7
SPCC GUIDANCE FOR REGIONAL INSPECTORS
H-164
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Multiple Horizontal Cylindrical Tanks Inside a Rectangular or Square Dike or Berm
EXAMPLE
( Selected Rainfall Event:
24— Hr 25— Yr
Rainfall (in) =
Volume of Rain to be Contained, VRain (ft) = 0.6
Total Containment Capacity Required (ft) =
ff
The net secondary containment volume after accounting for displacements in q is 778 ft , which is equal to or
greater than the required containment capacity in w, which is 514 ft3. Therefore, the secondary containment is
sufficient to contain the shell capacity of the largest tank and has sufficient additional capacity to contain a typical
rainfall amount.
The percentage of the net secondary containment volume to the largest tank shell capacity volume is 233% (s in
Step 4). This percentage, which is greater than 100%, indicates that additional secondary containment capacity is
available to contain rain as the containment is exposed to rain. Subtracting the largest tank shell capacity volume
VTank of 334 ft3 (e in Step 4) from the net containment volume VSCNet of 778 ft3 (q in Step 4) yields 444 ft3 of
additional containment capacity for rain. VRain, the volume of rain falling into the secondary containment in a 24-hour
25-year rainfall event that produces 7 inches of rain, is 180 ft3 (v in Step 5). VRain is less than the 444 ft3 of
additional containment capacity by 264 ft3; consequently, the additional secondary containment capacity is
sufficient to also contain the rain from the selected rainfall event. As concluded at the end of Step 5 in this example,
the net secondary containment volume is sufficient to contain the shell capacity of the largest tank and the selected
typical rainfall amount.
July 2011-Page 6 of 7
SPCC GUIDANCE FOR REGIONAL INSPECTORS
H-165
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Multiple Horizontal Cylindrical Tanks Inside a Rectangular or Square Dike or Berm
EXAMPLE
Table of H/D Ratios and Corresponding Percent of Tank Volume
"H" is the tank height below the top of the containment wall. "D" is the tank diameter.
H/D Ratio
0
0.01
0.02
0.03
0.04
0.05
0.06
0.07
0.08
0.09
0.10
0.11
0.12
0.13
0.14
0.15
0.16
0.17
0.18
0.19
0.20
0.21
0.22
0.23
0.24
0.25
0.26
0.27
0.28
0.29
0.30
0.31
0.32
0.33
Percent of
Tank Vol
0
0.002
0.003
0.009
0.013
0.020
0.025
0.030
0.038
0.045
0.053
0.058
0.068
0.075
0.085
0.094
0.102
0.112
0.121
0.131
0.142
0.152
0.163
0.175
0.184
0.195
0.208
0.217
0.230
0.240
0.253
0.263
0.276
0.287
H/D ratio
0.34
0.35
0.36
0.37
0.38
0.39
0.40
0.41
0.42
0.43
0.44
0.45
0.46
0.47
0.48
0.49
0.50
0.51
0.52
0.53
0.54
0.55
0.56
0.57
0.58
0.59
0.60
0.61
0.62
0.63
0.64
0.65
0.66
0.67
Percent of
Tank Vol
0.301
0.312
0.323
0.337
0.348
0.362
0.374
0.385
0.400
0.411
0.423
0.435
0.450
0.461
0.473
0.488
0.500
0.512
0.527
0.539
0.550
0.565
0.577
0.589
0.600
0.615
0.626
0.638
0.652
0.663
0.677
0.688
0.699
0.713
H/D ratio
0.68
0.69
0.70
0.71
0.72
0.73
0.74
0.75
0.76
0.77
0.78
0.79
0.80
0.81
0.82
0.83
0.84
0.85
0.86
0.87
0.88
0.89
0.90
0.91
0.92
0.93
0.94
0.95
0.96
0.97
0.98
0.99
1.00
Percent of
Tank Vol
0.724
0.737
0.747
0.760
0.770
0.783
0.792
0.805
0.816
0.825
0.837
0.848
0.858
0.869
0.879
0.888
0.898
0.906
0.915
0.925
0.932
0.942
0.947
0.955
0.962
0.970
0.975
0.980
0.987
0.991
0.997
0.998
1.000
SPCC GUIDANCE FOR REGIONAL INSPECTORS
July 2011-Page 7 of 7
H-166
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Rectangular or Square Remote Impoundment Structure
EXAMPLE
This worksheet calculates the containment volume of a rectangular or square remote impoundment1
structure providing secondary containment for an aboveground tank storage facility.
1. Determine the volume of the secondary containment
impoundment, VSc
2a. Determine the volume of the largest tank when shell
capacity is unknown, VTank
2b. Determine the volume of the largest tank when shell
capacity is known, VTank
3. Determine the percentage of the secondary containment
volume, Vsc to the largest tank volume, VTank
4. Determine whether the secondary containment
impoundment can contain the entire tank shell capacity of
the largest tank with additional capacity to contain rain.
14 ft x 13 ft x 4 ft
Solid Mansonry Dik<
500-Gal AST.
^Drainage area contributing
ram runoff into the remote
impoundment is 525 ft2
.Three 3 QOO-Gal ASTs
For al least 50 ft or 40 ft to the dike ba
whichever is less slope V40 is 0 025
2 5% which is greater than the required
1*
' Information needed to use this ^
worksheet:
• Tank shell capacity
See diagram for capacities.
• Remote impoundment
length, width, and height
See diagram for dimensions.
• Rainfall amount
Rain can fall into the
impoundment and the area
draining into the
impoundment. The selected
rain event for the location is 7
inches. See the diagram to
obtain the surface drainage
area in square feet.
Largest Tank Shell Capacity (gal) = | 3,000
a
Disclaimer: Please note that these are simplified calculations for qualified facilities that assume: 1) the
secondary containment is designed with a flat floor; 2) the wall height is equal for all four walls; and 3) the
corners of the secondary containment system are 90 degrees. Additionally, the calculations do not include
displacement for support structures or foundations. For Professional Engineer (PE) certified Plans, the PE
may need to account for site-specific conditions associated with the secondary containment structure which
may require modifications to these sample calculations to ensure good engineering practice.
1 Remote impounding is an acceptable secondary containment method under NFPA 30 because the code primarily focuses on
fire safety and emphasizes the importance of moving leaked or spilled flammable liquids away from the tank by adequate
draining. A remote impoundment must be able to contain the contents of the largest tank. However, when this is not possible,
partial impounding can be used in combination with diking to meet the largest-tank criterion.
For tank fields contained by diking, NFPA 30 requires that a slope of not less than one percent away from the tank shall be
provided for at least 50 feet or to the dike base, whichever is less. This ensures that small spills will not accumulate against the
wall of the tank. Also, if remote impounding is used, the drainage path to the impoundment should be designed so that if the
drainage path is ignited, the flames will not pose serious risk to tanks or adjoining property.
July 2011-Page 1 of 4
SPCC GUIDANCE FOR REGIONAL INSPECTORS
H-167
-------
Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Ij Rectangular or Square Remote Impoundment Structure
EXAMPLE
1. Determine the volume of the secondary containment impoundment, VSc
Impoundment Containment Area, ASc =
Vsc(ft3) =
ft3
Height
(ft)
2a. Determine the volume of the largest tank when the shell capacity is unknown, VTank
Tank radius (ft) =
ft
VTtmk(fl3)= 3.14 x
Radius^
(ft)2
Tank
Height
(ft)
2b. Determine the volume of the largest tank when shell capacity is known, V
Tank
a is the tank shell capacity
from page 1.
\f
x 0.1337 =
a (gal) ft3/gal
July 2011-Page 2 of 4
SPCC GUIDANCE FOR REGIONAL INSPECTORS
H-168
-------
Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Rectangular or Square Remote Impoundment Structure
EXAMPLE
3. Determine the percentage of the secondary containment volume, VSc to the largest tank
volume, VTank2(to determine whether the volume of the containment is sufficient to contain the largest tank's entire
shell capacity).
^^^
VscA/Tank =
728
4- 401
c is the secondary contianment volume. ,
d/e is the tank volume calculated „ 3
in Step 2 of this worksheet. (ft) (ft)
% =
1.82
1.82
^^
f
x 100
182
f g
Percentage, g, is 182%, which is greater than 100%.The capacity of the impoundment containment is sufficient to
contain the shell capacity of the largest tank. However, we must also account for rain that can collect in the
impoundment. See Step 4.
4. Determine whether the secondary containment impoundment can contain the entire tank shell
capacity with additional capacity to contain rain.
If rain can collect in a remote impoundment structure, the SPCC rule requires that secondary containment for bulk
storage containers have additional capacity to contain rainfall or freeboard. The rule does not specify a method to
determine the additional capacity required to contain rain or the size of the rain event for designing secondary
containment. However, industry practice often considers a rule of thumb of 110% of the tank capacity to account for
rainfall. Secondary containment with a 110% capacity of the tank may be acceptable depending on, the shell size of
the tank, local precipitation patterns and frequency of containment inspections. In a different geographic area,
secondary containment designed to hold 110% for the same size tank may not have enough additional containment
capacity to account for a typical rain event in that area. The 110% standard may also not suffice for larger storm
events. If you want to determine a conservative capacity for a rain event, you may want to consider a 24-hour 25-
year storm event. It is the responsibility of the owner or operator3 to determine the additional containment capacity
necessary to contain rain. A typical rain event may exceed the amount determined by using a 110% "rule of thumb"
so it is important to consider the amount of a typical rain event when designing or assessing your secondary
containment capacity.
Rainfall data may be available from various sources such as local water authorities, local airports, and the National
Oceanic and Atmospheric Administration (NOAA).
Steps 3 and 4 in the worksheet determines whether the volume of the impoundment containment is sufficient to contain the
largest tank's entire shell capacity and rainfall (freeboard for precipitation) as required by the SPCC rule. Step 3 primarily
determines whether the volume of the impoundment containment is sufficient to contain the entire shell capacity of the largest
tank. Step 4 is necessary to determine whether the impoundment containment can also contain the expected volume of rainfall
(both the volume of rain that falls into the impoundment plus the rain from the drainage area contributing runoff into the
impoundment).
3 The SPCC rule does not require you to show the secondary containment calculations in your Plan. However, you should
maintain documentation of secondary containment calculations to demonstrate compliance to an EPA inspector.
July 2011-Page 3 of 4
SPCC GUIDANCE FOR REGIONAL INSPECTORS
H-169
-------
Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Rectangular or Square Remote Impoundment Structure
EXAMPLE
r Selected Rainfall Event:
Rainfall (in) =
Rainfall (ft) =
Volume of rain, Vpainimnniincl that can fall directly into
VRainlmpound ('' / =
b is the area of secondary containment
calculated in Step 1 of this worksheet
Volume of rain contributed from the Impoundment
impoundment: (The drainage surface area, ADrainageArea
impoundment in ft2 is required to determine VDrainageArea-
built plans for the design and construction of the impoun
Area of Drainage, ADrainageArea (ff) =
VDrainageArea ('' / =
Total Volume of Rain Collected in Impoundment, VT
VjotalRainlmpound (") =
Total Containment Capacity Required (ff) =
e is the tank volume calculated
in Step 2 of this worksheet
\.
7
h
7
h(in)
0.6
^^^
in
- 12
in/ft
ft
the impoundment:
0.6
x 182 = 109 ft3
i (ft) b (ft2) j
Drainaae Area, Vn™™™^^ ,to the remote
contributing rain runoff into the remote dike
This information can be obtained from the as-
dment).
525
k
0.6
ft2
x 525 = 315 ft3
i k ^
(ft) (ft2)
otaiRainlmpound •
109
j (ft3)
424
m (ft3)
825
n
+ 315 = 424 ft3
I (ft3) m
+ 401
e (ft3)
ft3
^
The volume of the impoundment containment in c is 728 ft , which is less than the required containment capacity in
n (825 ft3). Therefore, the impoundment containment is not sufficient to contain the shell capacity of the largest tank
and the typical rainfall amount.
The percentage of the impoundment containment volume to the largest tank shell capacity volume is 182% (g in
Step 3). This percentage, which is greater than 100%, indicates that additional impoundment containment capacity
is available to contain rain as the containment is exposed to rain. Subtracting the largest tank shell capacity volume
Vjank of 401 ft3 (d or e in Step 3) from the impoundment containment volume VSc of 728 ft3 (c in Step 3) yields 327
ft3 of additional containment capacity for rain. VTotaiRamimpound, the total volume of rain collected in the impoundment
containment in a 24-hour 25-year rainfall event that produces 7 inches of rain, is 424 ft3 (m in Step 4). VTota|Rainimpound
is more than the 327 ft3 of additional containment capacity by 97 ft3; consequently, the additional impoundment
containment capacity is not sufficient to also contain the rain from the selected rainfall event.
As concluded at the end of Step 4 in this example, the impoundment containment is not sufficient to contain the
shell capacity of the largest tank and the selected typical rainfall amount.
July 2011-Page 4 of 4
SPCC GUIDANCE FOR REGIONAL INSPECTORS
H-170
-------
Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Single Vertical Cylindrical Tank Inside a Rectangular or Square Dike or Berm
EXAMPLE
This worksheet calculates the secondary containment volume of a rectangular or square dike or berm for
a single vertical cylindrical tank. In this example, there are no other objects or structures within the dike
or berm that will displace the volume of the secondary containment.
Steps:
1. Determine the volume of the secondary containment, VSc
2a. Determine the volume of the tank when the tank shell
capacity is unknown, VTank
2b. Determine the volume of the tank when shell capacity is
known, VTank
3. Determine the percentage of the secondary containment
volume, Vsc to the tank volume, VTank
4. Determine whether the secondary containment can
contain the entire tank shell capacity with additional
capacity to contain rain.
Information needed to use this
worksheet:
• Tank shell capacity
In this example the tank is 1,200
gallons, the tank diameter is 5 ft,
and tank height is 8ft.
• Secondary containment
length, width, and height
See diagram for dimensions.
• Rainfall amount
Rainfall can collect in the
secondary containment; the
selected rain event for the
location is 7 inches.
Diameter-5 ft
12.5 ft
Height=8 ft
Dike or Berm
15ft
Tank A Shell Capacity (gal) = | 1,200
Disclaimer: Please note that these are simplified calculations for qualified facilities that assume: 1) the
secondary containment is designed with a flat floor; 2) the wall height is equal for all four walls; and 3) the
corners of the secondary containment system are 90 degrees. Additionally, the calculations do not include
displacement for support structures or foundations. For Professional Engineer (PE) certified Plans, the PE
may need to account for site-specific conditions associated with the secondary containment structure which
may require modifications to these sample calculations to ensure good engineering practice.
July 2011-Page 1 of 4
SPCC GUIDANCE FOR REGIONAL INSPECTORS
H-171
-------
Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
f j Single Vertical Cylindrical Tank Inside a Rectangular or Square Dike or Berm
EXAMPLE
1. Determine the volume of the secondary containment, VSc
^^
' Secondary Containment Area, Asc =
=
Vsc(ff) =
\
15
Length
(ft)
187.5
b
187.5
b
(ft2)
x 12.5
Width
(ft)
ft2
x 1.5
Height
(ft)
^x
\
281 .3 ft3
c
2a. Determine the volume of the tank when the tank shell capacity is unknown, VTank
(In this example we know the tank capacity so we skip this step.)
Tank radius (ft) =
Diameter
(ft)
3.14
Radius2
(ft)2
Tank
Height
2b. Determine the volume of the tank when shell capacity is known, VTank
I^^ge1. v^(f?) =
1,200
a (gal)
x 0.1337 =
ft3/gal
160.4
e
ft3
July 2011-Page 2 of 4
SPCC GUIDANCE FOR REGIONAL INSPECTORS
H-172
-------
Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Ij Single Vertical Cylindrical Tank Inside a Rectangular or Square Dike or Berm
EXAMPLE
3. Determine the percentage of the secondary containment volume, VSc to the tank volume, VTank1
(to determine whether the volume of the containment is sufficient to contain the tank's entire shell capacity).
^^^
c is the secondary contianment volume.
d/e is the tank volume calculated
in Step 2 of this worksheet.
% =
^
281.3
(f?3)
1.75
f
- 160.4
d ore
(ft3)
x 100
=
1.75
f
175
g
^^
^
Percentage, g, is 175% which is greater than 100%. The capacity of the secondary containment is sufficient to
contain the shell capacity of the tank. However, we must also account for rain that can collect in the dike or berm.
See Step 4.
4. Determine whether the secondary containment can contain the entire tank shell capacity with
additional capacity to contain rain.
If rain can collect in a dike or berm, the SPCC rule requires that secondary containment for bulk storage containers
have additional capacity to contain rainfall or freeboard. The rule does not specify a method to determine the
additional capacity required to contain rain or the size of the rain event for designing secondary containment.
However, industry practice often considers a rule of thumb of 110% of the tank capacity to account for rainfall. A
dike with a 110% capacity of the tank may be acceptable depending on, the shell size of the tank, local precipitation
patterns and frequency of containment inspections. In a different geographic area, a dike or berm designed to hold
110% for the same size tank may not have enough additional containment capacity to account for a typical rain
event in that area. The 110% standard may also not suffice for larger storm events. If you want to determine a
conservative capacity for a rain event, you may want to consider a 24-hour 25-year storm event. It is the
responsibility of the owner or operator2 to determine the additional containment capacity necessary to contain rain.
A typical rain event may exceed the amount determined by using a 110% "rule of thumb" so it is important to
consider the amount of a typical rain event when designing or assessing your secondary containment capacity.
Rainfall data may be available from various sources such as local water authorities, local airports, and the National
Oceanic and Atmospheric Administration (NOAA).
1 Steps 3 and 4 in the worksheet determines whether the volume of the secondary containment is sufficient to contain the tank's
entire shell capacity and rainfall (freeboard for precipitation) as required by the SPCC rule. Step 3 primarily determines whether
the volume of the secondary containment is sufficient to contain the entire shell capacity of the tank. Step 4 is necessary to
determine whether the secondary containment can also contain the expected volume of rainfall (both the volume of rain that falls
into the containment plus the rain from the tank storage site).
2 The SPCC rule does not require you to show the secondary containment calculations in your Plan. However, you should
maintain documentation of secondary containment calculations to demonstrate compliance to an EPA inspector.
July 2011-Page 3 of 4
SPCC GUIDANCE FOR REGIONAL INSPECTORS
H-173
-------
Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Single Vertical Cylindrical Tank Inside a Rectangular or Square Dike or Berm
EXAMPLE
Selected Rainfall Event:
24— Hr 25— Yr
Rainfall (in) =
Total Containment Capacity Required (ft3) = 112.5
Volume of Rain to be Contained, VRain (ftj) =
b is the area of secondary containment
calculated in Step 1 of this worksheet
d/e is the tank volume calculated
in Step 2 of this worksheet
The volume of the secondary containment in c is 281.3 ft3, which is greater than the required containment capacity
in k (272.9 ft3). Therefore, the secondary containment is sufficient to contain the shell capacity of the tank and has
sufficient additional capacity to contain a typical rainfall amount.
The percentage of the secondary containment volume to the tank shell capacity volume is 175% (g in Step 3). This
percentage, which is greater than 100%, indicates that additional secondary containment capacity is available to
contain rain as the containment is exposed to rain. Subtracting the tank shell capacity volume VTank of 160.4 ft3 (d or
e in Step 3) from the containment volume VSc of 281.3 ft3 (c in Step 3) yields 120.9 ft3 of additional containment
capacity for rain. VRain, the volume of rain falling into the secondary containment in a 24-hour 25-year rainfall event
that produces 7 inches of rain, is 112.5 ft3 (j in Step 4). VRain is less than the 120.9 ft3 of additional containment
capacity by 8.4 ft3; consequently, the additional secondary containment capacity is sufficient to also contain the rain
from the selected rainfall event. As concluded at the end of Step 4 in this example, the secondary containment is
sufficient to contain the shell capacity of the tank and the selected typical rainfall amount.
July 2011-Page 4 of 4
SPCC GUIDANCE FOR REGIONAL INSPECTORS
H-174
-------
Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Construct New Secondary Containment
WORKSHEET
This worksheet can be used to determine the possible dimensions for a rectangular or square dike or
berm to meet the secondary containment requirement for aboveground bulk storage containers.
Information needed to use this worksheet:
• Tank shell capacity, diameter, length, and height
• Secondary containment length, width, and/or height limitations
• If rain can collect in secondary containment; the amount of rain, inches or
feet, for the location
Steps:
A. Determining required dike or berm dimensions for largest single tank
1. Calculate the volume of the tank
2. Specify the containment wall height and one containment lateral dimension D1 to calculate
lateral dimension D2
3. Calculate the volume of rain, VRain, to be collected in the secondary containment with area ASc
for the specified rain event
4. Calculate the required secondary containment volume, VscReq, to account for the additional
volume of rain, VRain
B. Accounting for the displacements from other vertical cylindrical tanks to be located in dike
or berm with the largest tank
1. For SCHeight (ft), calculate the displacement from additional vertical cylindrical tanks, Tank 2, 3,
4, etc., to be located with the largest tank in the dike or berm
2. Calculate the total displacement volume from the additional vertical cylindrical tanks in the dike
or berm
C. Accounting for the displacements from other horizontal cylindrical tanks to be located In
dike or berm with the largest tank
1. For SCHeight (ft), calculate the displacement from additional horizontal cylindrical tanks, Tank 2,
3, 4, etc., to be located with the largest tank in the dike or berm
2. Calculate the total displacement volume from the additional horizontal cylindrical tanks in the
dike or berm
D. Accounting for the displacements from other rectangular tanks to be located in dike or berm
with the largest tank
1. For SCheight (ft), calculate the displacement from additional rectangular tanks, Tank 2, 3, 4, etc.,
to be located with the largest tank in the dike or berm
2. Calculate the total displacement volume from the additional rectangular tanks in the dike or berm
Disclaimer: Please note that these are simplified calculations for qualified facilities that assume: 1) the
secondary containment is designed with a flat floor; 2) the wall height is equal for all four walls; and 3) the
corners of the secondary containment system are 90 degrees. Additionally, the calculations do not include
displacement for support structures or foundations. For Professional Engineer (PE) certified Plans, the PE
may need to account for site-specific conditions associated with the secondary containment structure which
may require modifications to these sample calculations to ensure good engineering practice.
SPCC GUIDANCE FOR REGIONAL INSPECTORS
July 2011-Page 1 of 8
H-175
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Construct New Secondary Containment
WORKSHEET
A. Determining required dike or berm dimensions for largest single tank
1. Calculate the volume of the tank
Largest Tank Shell Capacity (gal) =
Largest Tank Volume (ft3) =
Note that state and local fire and safety codes may prescribe limits on the height of containment walls, minimum
separation distances between tanks, and setback distances. For instance, Occupational Safety and Health
Administration (OSHA) flammable and combustible liquids standards in 29 CFR 1910.106 prescribe separation
distances between adjacent tanks. Such requirements may present constraints on the location, dimensions, and
configuration of the secondary containment structure. The footprint of the tank or tanks and arrangement of the
tanks when there is to be more than a single tank within secondary containment may also present constraints on
the containment dimensions.
2. Specify the containment wall height and one containment lateral dimension D1 to calculate
lateral dimension D2
Note: NaN = Not A Number. Once values b, c, and e are inputted, NaN will be replaced with the correct value for f.
Height of Containment Wall, SCHeight (ft) =
Height of Containment Wall,
(in) =
b is the volume of the largest tank
calculated in Step 1.
D1(ft)
D2 (ft)
c(ft)
e(ft)
SPCC GUIDANCE FOR REGIONAL INSPECTORS
July 2011-Page 2 of 8
H-176
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Construct New Secondary Containment
WORKSHEET
3. Calculate the volume of rain, VRain to be collected in the secondary containment with area Asc
for the specified rain event
f
Selected Rainfall Event: Rainfall (in) =
f is lateral dimension D2 calculated „
in Step 2. Asc (ff) =
VRain (ff) =
=
\^
g
e(ft)
g(in)
0
i
^v
in
x o ft2
f (ft) h
^B 12 x
in/ft h (ft2)
ft3
J
4. Calculate the required secondary containment volume, VScReq to account for the additional
volume of rain, VRain
b is the volume of the largest
tank calculated in Step 1.
i is the volume of rain calculated in Step 3.
V,
SCReq
(ff) =
Vary the secondary containment height and lateral dimensions, or footprint, in Step 2 to meet any space or
dimension constraints or requirements and the required containment volume, VSCReq, by using VSCReq in place of the
volume of the largest shell capacity tank, b in Step 2.
IF APPLICABLE: When other tanks or containers are also to be located within the secondary containment along
with the largest tank, calculate the displacement volumes from these other tanks or containers using Parts B, C and
D as applicable. Add the total displacement volume from the other tanks or containers to the volume of rain, VRain,
and the largest tank volume, b, in Step 1, to obtain a net secondary containment volume, VNetSc:
VNe,sc (ft3) =
Total
Displacement
Volume (ft3)
Vary the secondary containment height and lateral dimensions, or footprint, in Step 2 to meet any space or
dimension constraints or requirements and the net required containment volume, VNetSc, by using VNetSc in place of
the volume of the largest shell capacity tank, b.
SPCC GUIDANCE FOR REGIONAL INSPECTORS
July 2011-Page 3 of 8
H-177
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Construct New Secondary Containment
WORKSHEET
B. Accounting for the displacements from other vertical cylindrical tanks to be located in dike or
berm with the largest tank
1. For SCHeight (ft), calculate the displacement from additional vertical cylindrical tanks, Tank 2, 3,
4, etc., to be located with the largest tank in the dike or berm
Diameter of Tank 2 (ft) =
Radius of Tank 2 (ft) =
Displacement Area, DAjank 2 (ft2) = 3'14 x
Displacement Volume, DVTank2 (ft) =
c is the containment wall
height used in Step 2 of A.
Repeat to calculate the displacement of each additional horizontal cylindrical tank located with the
largest tank in the dike or berm.
2. Calculate the total displacement volume from the additional vertical cylindrical tanks in the
dike or berm
^™
Total Displacement Volume (ft3) =
o is the displacement volume of
Tank 2 calculated in Step 1 of B.
=
L.
o (ft3)
0
p
"">
+ + + ...
o1 (ft3) o2 (ft3)
J
SPCC GUIDANCE FOR REGIONAL INSPECTORS
July 2011-Page 4 of 8
H-178
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Construct New Secondary Containment
WORKSHEET
C. Accounting for the displacements from other horizontal cylindrical tanks to be located in dike
or berm with the largest tank
1. For SCHeight (ft), calculate the displacement from additional horizontal cylindrical tanks, Tank
2, 3, 4, etc., to be located with the largest tank in the dike or berm
The easiest way to determine the displacement volume for a horizontal cylindrical tank is to use the tank
manufacturer's liquid height to gallons conversion chart for the tank in Method 1 calculation. If this information is
not available, use Method 2 calculation to obtain the displacement volumes.
METHOD 1
Height of Tank 2 Below Containment Wall (in) =
VTank2 Displacement (gal) From Tank Conversion Chart =
METHOD 2
Height of Tank 2 Below =
Containment Wall (in)
Tank 2 Diameter (in) =
Height to Diameter:
Ratio for Tank 2
Tank 2 Volume Fraction for ••
Height to Diameter Ratio (Table)
If the tank shell capacity in gallons is known:
t(in)
u(in)
ft3
VTank2 Displacement (fr) =
x 0.1337 =
ft3/gal
Repeat to calculate the displacement of each additional horizontal cylindrical tank located with the
largest tank in the dike or berm.
Total Displacement Volume (ft3) =
x 12
0
Diameter in/ft u
(ft)
=
NaN
in
Tank Volume
h-
V Tank 2 (f
Sh
x
ell Capacity
(gal)
0.
ft
1337 ^m
3/gai
0
X
ft3
--
SPCC GUIDANCE FOR REGIONAL INSPECTORS
July 2011-Page 5 of 8
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Construct New Secondary Containment
WORKSHEET
METHOD 2 (CONT)
Or, if the tank shell capacity in gallons is not known:
Tank 2 radius (ft) =
Displacement, VTank2 (ft3) =
VTank2(ft3)= 3.14 x ( )
Radius Tank Length
fta
x ory
(ft3)
Repeat to calculate the displacement volume of each additional horizontal cylindrical tank to be located
with the largest tank in the dike or berm.
2. Calculate the total displacement volume from the additional horizontal cylindrical tanks in the
dike or berm
Total Displacement Volume (ft3) =
2. is the displacement volume
calculated in Step 1, Method
2ofC.
Z2 (ft3)
SPCC GUIDANCE FOR REGIONAL INSPECTORS
July 2011-Page 6 of 8
H-180
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Construct New Secondary Containment
WORKSHEET
D. Accounting for the displacements from other rectangular tanks to be located in dike or berm
with the largest tank
1. For SCHeight (ft), calculate the displacement from additional rectangular tanks, Tank 2, 3, 4,
etc., to be located with the largest tank in the dike or berm
Height of Tank 2 Below Containment Wall (ft) =
Length of Tank 2 (ft) =
Width of Tank 2 (ft) =
Displacement Area, DATank2(ff) =
Displacement Volume, DVTank2 (ft3) =
ft
ab (ft)
ft
Repeat to calculate the displacement area and volume of each additional rectangular tank to be located
with the largest tank in the dike or berm.
2. Calculate the total displacement volume from the additional rectangular tanks in the dike or
berm
X"
Total Displacement Volume (ft3) =
afis the displacement volume
calculated in Step 1 of D.
k
"V
af (ft3)
0
ag
+ + +
af1 (ft3) af2 (ft3)
ft3
^
SPCC GUIDANCE FOR REGIONAL INSPECTORS
July 2011-Page 7 of 8
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Construct New Secondary Containment
WORKSHEET
Please use the space below to sketch tanks and wall dimensions to assist with calculations.
SPCC GUIDANCE FOR REGIONAL INSPECTORS UV " a§e 8 ° 8 H.182
-------
Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Multiple Horizontal Cylindrical Tanks Inside a Rectangular or Square Dike or Berm
WORKSHEET
This worksheet can be used to calculate the containment volume of a rectangular or square dike or berm
for multiple horizontal cylindrical tanks. When there are other objects or structures such as tanks along
with the largest tank within the dike or berm, their respective displacement volumes must be accounted
for when determining secondary containment.
Steps:
1. Determine the volume of the secondary containment, VSc
2a. Determine the volume of the tank when the tank shell
capacity is unknown, VTank
2b. Determine the volume of the tank when shell capacity is
known, VTank
3. Determine the unavailable (displacement) areas and
volumes in the containment due to other tanks within the
containment and the net containment volume remaining
for the largest tank
4. Determine the percentage of the net secondary
containment volume, VSCNet, to the largest tank volume,
Vjank
5. Determine whether the secondary containment can
contain the entire tank shell capacity with additional
capacity to contain rain.
Information needed to use this
worksheet:
• Tank shell capacity in gallons or
tank diameter and length of the
largest tank in feet
• Secondary containment length,
width, and height in feet
• Shell capacity in gallons or
length and diameter of each of
the other tanks in feet within the
secondary containment
• Height in feet of each tank
below top of containment wall
• If rain can collect in secondary
containment: amount of rain,
i inches or feet, for the location j
Largest Tank Shell Capacity (gal) =
Disclaimer: Please note that these are simplified calculations for qualified facilities that assume: 1) the
secondary containment is designed with a flat floor; 2) the wall height is equal for all four walls; and 3) the
corners of the secondary containment system are 90 degrees. Additionally, the calculations do not include
displacement for support structures or foundations. For Professional Engineer (PE) certified Plans, the PE
may need to account for site-specific conditions associated with the secondary containment structure
which may require modifications to these sample calculations to ensure good engineering practice.
July 2011-Page 1 of 7
SPCC GUIDANCE FOR REGIONAL INSPECTORS
H-183
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Multiple Horizontal Cylindrical Tanks Inside a Rectangular or Square Dike or Berm
WORKSHEET
1. Determine the volume of the secondary containment, VSc
2a. Determine th
2b. Determine tl
^
f Secondary Containment Area, ASc = >
Length
(ft)
0 ft
b
Vsc (ft3) = >
b
(ft2)
•
Width
(ft)
2
Height
(ft)
N
0 ft3
c
J
le volume of the tank when the tank shell capacity is unknown, VTank
/"
Tank radius (ft) = ±2.
Diameter
(ft)
VTank(ff)= 3.14 x ( )2
Radius2
(ft)2
o ft
x | = |
Tank
Length
(ft)
\
0 ft3
d
J
le volume of the tank when shell capacity is known, VTank
^^
a is the tank shell capacity \f /ff) _
from page 1.
a (gal)
k.
x 0.1337 =
ft3/gal
•>
0 ft3
e
j
3. Determine the unavailable (displacement) areas and volumes in the containment due to other
tanks within the containment and the net containment volume remaining for the largest tank
The easiest way to determine the displacement volume for a horizontal cylindrical tank is to use the tank
manufacturer's liquid height to gallons conversion chart for the tank in Method 1 calculation. If this information is not
available, use Method 2 calculation to obtain the displacement volumes.
July 2011-Page 2 of 7
SPCC GUIDANCE FOR REGIONAL INSPECTORS
H-184
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
* Mult'Ple Horizontal Cylindrical Tanks Inside a Rectangular or Square Dike or Berm
WORKSHEET
METHOD 1
in
Height of Tank B Below Containment Wall (in) =
Displacement (gal) From Tank Conversion Chart =
VTankB Displacement (ft3) =
Calculate the displacement of each additional horizontal cylindrical tank within the same secondary
containment:
x 0.1337 =
ft3/gal
Total Displacement Volume (ft3) =
g2 (ft3)
METHOD 2
Height of Tank B Below =
Containment Wall (in)
Tank B Diameter (in) =
Height to Diameter =
Ratio for Tank B
in
Tank B Volume Fraction for =
Height to Diameter Ratio (Table) •
If the tank shell capacity in gallons is known:
Tank Volume VTankB (ft3) =
12
in/ft
Shell Capacity
(gal)
0.1337
ft3/gal
SPCC GUIDANCE FOR REGIONAL INSPECTORS
July 2011-Page 3 of 7
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Multiple Horizontal Cylindrical Tanks Inside a Rectangular or Square Dike or Berm
WORKSHEET
r METHOD 2 (CONT)
Or, if the tank shell capacity in aallons is not known:
Tank B radius (ft) =
C
VTankB(ft3) =
Displacement, VTankB (ft3) =
m is the tank volume.
1 is the Tank B volume fractionfor H/D ratio (table).
Calculate the displacement of each additional I
containment:
Total Displacement Volume (ft3) =
Net Secondary Containment Volume:
Net Containment Volume, VScNet (ft3) =
c is the secondary contianment volume
calculated in Step 1.
h/p is the total displacement volume.
\^
iameter (ft)
3.14
I
- 2 0 ft
x ( )2 x
Radius Tank Length
(ft) (ft)
x 0 ft
"N
0 ft3
n
3
m (ft3) I o
lorizontal cylindrical tank within the same secondary
o (ft3)
0 f
p
c (fta)
+ + 4
01 (ft3) 02 (ft3)
0 ft
h (Method 1) or q
p (Method 2)
(ft3)
3
J
SPCC GUIDANCE FOR REGIONAL INSPECTORS
July 2011-Page 4 of 7
H-186
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Multiple Horizontal Cylindrical Tanks Inside a Rectangular or Square Dike or Berm
WORKSHEET
4. Determine the percentage of the net secondary containment volume, VscNet to the largest tank
volume, Vjank1 (to determine whether the volume of the containment is sufficient to contain the largest tank's
entire shell capacity).
Note: NaN = Not A Number. Once values q and e are inputted, NaN will be replaced with the correct value for r.
VsCNe/Vrank =
q is the net secondary contianment volume calculated in Q
Step 3, Method 2. ,,Tb,
e is the tank volume calculated \" I
in Step 2.
% =
X
\^ r
e (fta)
100
=
NaN
^
r
=
0
s
If percentage, s, is 100% or greater, the capacity of the secondary containment is sufficient to contain the shell
capacity of the tank. If rain can collect in the dike or berm, continue to step 4. If percentage, s, is less than 100%,
the capacity of the secondary containment is not sufficient to contain the shell capacity of the tank.
5. Determine whether the secondary containment can contain the entire tank shell capacity with
additional capacity to contain rain.
If rain can collect in a dike or berm, the SPCC rule requires that secondary containment for bulk storage containers
have additional capacity to contain rainfall or freeboard. The rule does not specify a method to determine the
additional capacity required to contain rain or the size of the rain event for designing secondary containment.
However, industry practice often considers a rule of thumb of 110% of the tank capacity to account for rainfall. A
dike with a 110% capacity of the tank may be acceptable depending on, the shell size of the tank, local precipitation
patterns and frequency of containment inspections. In a different geographic area, a dike or berm designed to hold
110% for the same size tank may not have enough additional containment capacity to account for a typical rain
event in that area. The 110% standard may also not suffice for larger storm events. If you want to determine a
conservative capacity for a rain event, you may want to consider a 24-hour 25-year storm event. It is the
responsibility of the owner or operator2 to determine the additional containment capacity necessary to contain rain.
A typical rain event may exceed the amount determined by using a 110% "rule of thumb" so it is important to
consider the amount of a typical rain event when designing or assessing your secondary containment capacity.
Rainfall data may be available from various sources such as local water authorities, local airports, and the National
Oceanic and Atmospheric Administration (NOAA).
1 Steps 4 and 5 in the worksheet determines whether the net volume of the secondary containment is sufficient to contain the
largest tank's entire shell capacity and rainfall (freeboard for precipitation) as required by the SPCC rule. Step 4 primarily
determines whether the net volume of the secondary containment is sufficient to contain the entire shell capacity of the largest
tank. Step 5 is necessary to determine whether the secondary containment can also contain the expected volume of rainfall
(both the volume of rain that falls into the containment plus the rain from the tank storage site).
The SPCC rule does not require you to show the secondary containment calculations in your Plan. However, you should
maintain documentation of secondary containment calculations to demonstrate compliance to an EPA inspector.
July 2011-Page 5 of 7
SPCC GUIDANCE FOR REGIONAL INSPECTORS
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Multiple Horizontal Cylindrical Tanks Inside a Rectangular or Square Dike or Berm
WORKSHEET
Selected Rainfall Event:
Rainfall (in) =
Rainfall (ft) =
Volume of Rain to be Contained, VRain (ft3) =
b is the area of secondary containment
calculated in Step 1.
Total Containment Capacity Required (ft3) =
e is the tank volume calculated
in Step 2.
ft
If the net secondary containment volume after accounting for displacements, q, is equal to or greater than the
required containment capacity, w, the secondary containment is sufficient to contain the shell capacity of the largest
tank with sufficient additional capacity to contain a typical rainfall amount. If the net secondary containment volume
after accounting for displacements, q, is less than the required containment capacity, w, the secondary
containment is not sufficient to contain the shell capacity of the largest tank and a typical rainfall amount.
July 2011-Page 6 of 7
SPCC GUIDANCE FOR REGIONAL INSPECTORS
H-188
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Multiple Horizontal Cylindrical Tanks Inside a Rectangular or Square Dike or Berm
WORKSHEET
Table of H/D Ratios and Corresponding Percent of Tank Volume
"H" is the tank height below the top of the containment wall. "D" is the tank diameter.
H/D Ratio
0
0.01
0.02
0.03
0.04
0.05
0.06
0.07
0.08
0.09
0.10
0.11
0.12
0.13
0.14
0.15
0.16
0.17
0.18
0.19
0.20
0.21
0.22
0.23
0.24
0.25
0.26
0.27
0.28
0.29
0.30
0.31
0.32
0.33
Percent of
Tank Vol
0
0.002
0.003
0.009
0.013
0.020
0.025
0.030
0.038
0.045
0.053
0.058
0.068
0.075
0.085
0.094
0.102
0.112
0.121
0.131
0.142
0.152
0.163
0.175
0.184
0.195
0.208
0.217
0.230
0.240
0.253
0.263
0.276
0.287
H/D ratio
0.34
0.35
0.36
0.37
0.38
0.39
0.40
0.41
0.42
0.43
0.44
0.45
0.46
0.47
0.48
0.49
0.50
0.51
0.52
0.53
0.54
0.55
0.56
0.57
0.58
0.59
0.60
0.61
0.62
0.63
0.64
0.65
0.66
0.67
Percent of
Tank Vol
0.301
0.312
0.323
0.337
0.348
0.362
0.374
0.385
0.400
0.411
0.423
0.435
0.450
0.461
0.473
0.488
0.500
0.512
0.527
0.539
0.550
0.565
0.577
0.589
0.600
0.615
0.626
0.638
0.652
0.663
0.677
0.688
0.699
0.713
H/D ratio
0.68
0.69
0.70
0.71
0.72
0.73
0.74
0.75
0.76
0.77
0.78
0.79
0.80
0.81
0.82
0.83
0.84
0.85
0.86
0.87
0.88
0.89
0.90
0.91
0.92
0.93
0.94
0.95
0.96
0.97
0.98
0.99
1.00
Percent of
Tank Vol
0.724
0.737
0.747
0.760
0.770
0.783
0.792
0.805
0.816
0.825
0.837
0.848
0.858
0.869
0.879
0.888
0.898
0.906
0.915
0.925
0.932
0.942
0.947
0.955
0.962
0.970
0.975
0.980
0.987
0.991
0.997
0.998
1.000
SPCC GUIDANCE FOR REGIONAL INSPECTORS
July 2011-Page 7 of 7
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Rectangular or Square Remote Impoundment Structure
WORKSHEET
This worksheet can be used to calculate the containment volume of a rectangular or square remote
impoundment1 structure providing secondary containment for an aboveground tank storage facility.
1. Determine the volume of the secondary containment
impoundment, VSc
2a. Determine the volume of the largest tank when shell
capacity is unknown, VTank
2b. Determine the volume of the largest tank when shell
capacity is known, VTank
3. Determine the percentage of the secondary containment
volume, VSc, to the largest tank volume, VTank
4. Determine whether the secondary containment
impoundment can contain the entire tank shell capacity of
the largest tank with additional capacity to contain rain.
Information needed to use this
worksheet:
• Tank shell capacity in gallons
or tank diameter and length or
height in feet of the largest
tank
• Remote impoundment length,
width, and height in feet
• If rain can collect in
impoundment: amount of rain,
inches or feet
• If rain can collect in drainage
area with runoff in the area
flowing into the impoundment,
this amount must also be
considered in the additional
impoundment capacity to
contain rain. The surface
drainage area in square feet is
required.
xft
For at least 50 ft or x ft to the dike base.
whichever is less, slope, y/x. is to be not
less than 0.01 or 1%.
Largest Tank Shell Capacity (gal) =
Disclaimer: Please note that these are simplified calculations for qualified facilities that assume: 1) the
secondary containment is designed with a flat floor; 2) the wall height is equal for all four walls; and 3) the
corners of the secondary containment system are 90 degrees. Additionally, the calculations do not include
displacement for support structures or foundations. For Professional Engineer (PE) certified Plans, the PE
may need to account for site-specific conditions associated with the secondary containment structure which
may require modifications to these sample calculations to ensure good engineering practice.
1 Remote impounding is an acceptable secondary containment method under NFPA 30 because the code primarily focuses on
fire safety and emphasizes the importance of moving leaked or spilled flammable liquids away from the tank by adequate
draining. A remote impoundment must be able to contain the contents of the largest tank. However, when this is not possible,
partial impounding can be used in combination with diking to meet the largest-tank criterion.
For tank fields contained by diking, NFPA 30 requires that a slope of not less than one percent away from the tank shall be
provided for at least 50 feet or to the dike base, whichever is less. This ensures that small spills will not accumulate against the
wall of the tank. Also, if remote impounding is used, the drainage path to the impoundment should be designed so that if the
drainage path is ignited, the flames will not pose serious risk to tanks or adjoining property.
July 2011-Page 1 of 4
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Rectangular or Square Remote Impoundment Structure
WORKSHEET
1. Determine the volume of the secondary containment impoundment, VSc
Impoundment Containment Area, Asc =
Vsc(fl3) =
ft3
Height
(ft)
2a. Determine the volume of the largest tank when the shell capacity is unknown, VTank
Tank radius (ft) =
ft
VTank(ft3)= 3.14 X
Radius^
(ft)2
Tank
Height
(ft)
2b. Determine the volume of the largest tank when shell capacity is known, V
Tank
a is the tank shell capacity
from page 1.
T ,
fff3) _
a (gal)
x 0.1337 =
ft3/gal
ft3
July 2011-Page 2 of 4
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Rectangular or Square Remote Impoundment Structure
WORKSHEET
3. Determine the percentage of the secondary containment volume, VSc, to the largest tank
volume, VTank2(to determine whether the volume of the containment is sufficient to contain the largest tank's entire
shell capacity).
Note: NaN = Not A Number. Once values c and d/e are inputted, NaN will be replaced with the correct value for f.
^^
c is the secondary containment volume
calculated in Step 1.
VscA/Tank =
0
c
(ft3)
=
d ore
(ft3)
^^^^
f
d/e is the tank volume calculated
in Step 2.
% =
fc-
0
f
x 100
0
g
^
If the percentage, g, is 100% or greater, the capacity of the impoundment containment is sufficient to contain the
shell capacity of the largest tank. If rain can collect in the impoundment, continue to step 4. If the percentage, g, is
less than 100%, the capacity of the impoundment containment is not sufficient to contain the shell capacity of the
largest tank.
4. Determine whether the secondary containment impoundment can contain the entire tank shell
capacity with additional capacity to contain rain.
If rain can collect in a remote impoundment structure, the SPCC rule requires that secondary containment for bulk
storage containers have additional capacity to contain rainfall or freeboard. The rule does not specify a method to
determine the additional capacity required to contain rain or the size of the rain event for designing secondary
containment. However, industry practice often considers a rule of thumb of 110% of the tank capacity to account for
rainfall. A dike with a 110% capacity of the tank may be acceptable depending on, the shell size of the tank, local
precipitation patterns and frequency of containment inspections. In a different geographic area, a dike or berm
designed to hold 110% for the same size tank may not have enough additional containment capacity to account for
a typical rain event in that area. The 110% standard may also not suffice for larger storm events. If you want to
determine a conservative capacity for a rain event, you may want to consider a 24-hour 25-year storm event. It is
the responsibility of the owner or operator3 to determine the additional containment capacity necessary to contain
rain. A typical rain event may exceed the amount determined by using a 110% "rule of thumb" so it is important to
consider the amount of a typical rain event when designing or assessing your secondary containment capacity.
Rainfall data may be available from various sources such as local water authorities, local airports, and the National
Oceanic and Atmospheric Administration (NOAA).
Steps 3 and 4 in the worksheet determines whether the volume of the impoundment containment is sufficient to contain the
largest tank's entire shell capacity and rainfall (freeboard for precipitation) as required by the SPCC rule. Step 3 primarily
determines whether the volume of the impoundment containment is sufficient to contain the entire shell capacity of the largest
tank. Step 4 is necessary to determine whether the impoundment containment can also contain the expected volume of rainfall
(both the volume of rain that falls into the impoundment plus the rain from the drainage area contributing runoff into the
impoundment).
3 The SPCC rule does not require you to show the secondary containment calculations in your Plan. However, you should
maintain documentation of secondary containment calculations to demonstrate compliance to an EPA inspector.
July 2011-Page 3 of 4
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Rectangular or Square Remote Impoundment Structure
WORKSHEET
Selected Rainfall Event:
Rainfall (in) =
Rainfall (ft) =
Volume of rain, VaaMmmimri that can fall directly into
VRainlmpound (ft) =
b is the area of secondary containment
calculated in Step 1.
Volume of rain contributed from the Impoundment
impoundment: (The drainage surface area, ADrainageArea
impoundment in ft2 is required to determine VDrainageArea.
built plans for the design and construction of the impoun
Area of Drainage, ADrainageArea (ft2) =
VDrainageArea ('' / =
Total Volume of Rain Collected in Impoundment, VT
VrotalRainlmpound ( '' / =
Total Containment Capacity Required (ft3) =
e is the tank volume calculated
in Step 2.
\.
h
h(in)
>i
in
- 12
in/ft
ft
the impoundment:
x o ft3
i (ft) b (ft2) j
Drainaae Area, Vnraina^Ama ,to the remote
contributing rain runoff into the remote dike
This information can be obtained from the as-
dment).
k
ft2
x = ft3
i k ^
(ft) (ft2)
otalRainlmpound •
j (ft3)
m (ft3)
NaN
n
+ 0 = ft3
I (ft3) m
+
e (ft3)
ft3
J
If the volume of the impoundment containment, c, is equal to or greater than the required containment capacity, n,
the impoundment is sufficient to contain the shell capacity of the largest tank with sufficient additional capacity to
contain a typical rainfall amount. If the volume of the impoundment containment, c, is less than the required
containment capacity, n, the impoundment containment is not sufficient to contain the shell capacity of the largest
tank and a typical rainfall amount.
July 2011-Page 4 of 4
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Single Vertical Cylindrical Tank Inside a Rectangular or Square Dike or Berm
WORKSHEET
This worksheet can be used to calculate the secondary containment volume of a rectangular or square
dike or berm for a single vertical cylindrical tank. This worksheet assumes that there are no other objects
or structures within the dike or berm that will displace the volume of the secondary containment.
Steps:
1. Determine the volume of the secondary containment, VSc x" ^
2a. Determine the volume of the tank when the tank shell
capacity is unknown, VTank
2b. Determine the volume of the tank when shell capacity is
known, VTank
3. Determine the percentage of the secondary containment
volume, VSc, to the tank volume, VTank
4. Determine whether the secondary containment can
contain the entire tank shell capacity with additional
capacity to contain rain.
Information needed to use this
worksheet:
• Tank shell capacity in gallons or
tank diameter and height in feet
• Secondary containment length,
width, and height in feet
• If rain can collect in secondary
containment: amount of rain in
inches or feet
Tank A Shell Capacity (gal) =
Disclaimer: Please note that these are simplified calculations for qualified facilities that assume: 1) the
secondary containment is designed with a flat floor; 2) the wall height is equal for all four walls; and 3) the
corners of the secondary containment system are 90 degrees. Additionally, the calculations do not include
displacement for support structures or foundations. For Professional Engineer (PE) certified Plans, the PE
may need to account for site-specific conditions associated with the secondary containment structure which
may require modifications to these sample calculations to ensure good engineering practice.
July 2011-Page 1 of 4
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
|j Single Vertical Cylindrical Tank Inside a Rectangular or Square Dike or Berm
WORKSHEET
1. Determine the volume of the secondary containment, VSc
Secondary Containment Area, Asc =
Vsc(ff) =
Height
(ft)
2a. Determine the volume of the tank when the tank shell capacity is unknown, V
Tank
Tank radius (ft) =
Diameter
(ft)
VTmk(ff)= 3.14 x
Radius^
(ft)2
ft
Tank
Height
(ft)
2b. Determine the volume of the tank when shell capacity is known, V
Tank
a is the tank shell
capacity from page 1.
V
rank
a (gal)
0.1337 =
ft3/gal
ft3
ft3
ft3
July 2011-Page 2 of 4
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Single Vertical Cylindrical Tank Inside a Rectangular or Square Dike or Berm
WORKSHEET
3. Determine the percentage of the secondary containment volume, VSc, to the tank volume,
Viank1(to determine whether the volume of the containment is sufficient to contain the tank's entire shell capacity).
Note: NaN = Not A Number. Once values c and d/e are inputted, NaN will be replaced with the correct value for f.
VscA/Tank =
c is the secondary containment volume
calculated in Step 1.
d/e is the tank volume calculated
in Step 2.
% =
If percentage, g, is 100% or greater, the capacity of the secondary containment is sufficient to contain the shell
capacity of the tank. If rain can collect in the dike or berm, continue to step 4. If percentage, g, is less than 100%,
the capacity of the secondary containment is not sufficient to contain the shell capacity of the tank.
4. Determine whether the secondary containment can contain the entire tank shell capacity with
additional capacity to contain rain.
If rain can collect in a dike or berm, the SPCC rule requires that secondary containment for bulk storage containers
have additional capacity to contain rainfall or freeboard. The rule does not specify a method to determine the
additional capacity required to contain rain or the size of the rain event for designing secondary containment.
However, industry practice often considers a rule of thumb of 110% of the tank capacity to account for rainfall. A
dike with a 110% capacity of the tank may be acceptable depending on, the shell size of the tank, local precipitation
patterns and frequency of containment inspections. In a different geographic area, a dike or berm designed to hold
110% for the same size tank may not have enough additional containment capacity to account for a typical rain
event in that area. The 110% standard may also not suffice for larger storm events. If you want to determine a
conservative capacity for a rain event, you may want to consider a 24-hour 25-year storm event. It is the
responsibility of the owner or operator2 to determine the additional containment capacity necessary to contain rain.
A typical rain event may exceed the amount determined by using a 110% "rule of thumb" so it is important to
consider the amount of a typical rain event when designing or assessing your secondary containment capacity.
Rainfall data may be available from various sources such as local water authorities, local airports, and the National
Oceanic and Atmospheric Administration (NOAA).
1Steps 3 and 4 in the worksheet determine whether the volume of the secondary containment is sufficient to contain the tank's
entire shell capacity and rainfall (freeboard for precipitation) as required by the SPCC rule. Step 3 primarily determines whether
the volume of the secondary containment is sufficient to contain the entire shell capacity of the tank. Step 4 is necessary to
determine whether the secondary containment can also contain the expected volume of rainfall (both the volume of rain that falls
into the containment plus the rain from the tank storage site).
2 The SPCC rule does not require you to show the secondary containment calculations in your Plan. However, you should
maintain documentation of secondary containment calculations to demonstrate compliance to an EPA inspector.
July 2011-Page 3 of 4
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Appendix H: Other Policy Documents
Spill Prevention Control and Countermeasure (SPCC) Plan
Single Vertical Cylindrical Tank Inside a Rectangular or Square Dike or Berm
WORKSHEET
Selected Rainfall Event:
Rainfall (in) =
Rainfall (ft) =
ft
Volume of Rain to be Contained, VRain (ft3) =
b is the area of secondary containment
calculated in Step 1.
Total Containment Capacity Required (ft3) =
d/e is the tank volume calculated
in Step 2.
X
i (ft) b (ft2)
(ft3)
k
+ NaN
d ore
(ft3)
ft3
= 0 | ft
j
A
If the volume of the secondary containment, c, is equal to or greater than the required containment capacity, k, the
secondary containment is sufficient to contain the shell capacity of the tank with sufficient additional capacity to
contain a typical rainfall amount. If the volume of the secondary containment, c, is less than the required
containment capacity, k, the secondary containment is not sufficient to contain the shell capacity of the tank and a
typical rainfall amount.
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