&EPA
Office of Emergency Management
EPA 550-B-05-001
United States
Environmental Protection
Agency
SPCC Guidance
for Regional Inspectors
Version 1.0
November 28, 2005
U.S. Environmental Protection Agency
Office of Emergency Management
Regulation and Policy Development Division
The Oil Pollution Prevention regulation includes requirements for
facilities to prepare, amend, and implement Spill Prevention, Control,
and Countermeasure (SPCC) Plans to prevent discharges of oil to
navigable waters and adjoining shorelines. The regulation allows
flexibility in meeting some of the requirements. This document is
designed to assist regional inspectors in implementing the SPCC
program and in understanding its applicability.
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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 and Patricia Fleming.
EPA engineering review was conducted by Troy Swackhammer. Technical research, writing,
and editing was provided under EPA Contract No. 68-W-03-020.
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-05-001
www.epa.gov
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Table of Contents
TABLE OF CONTENTS
DISCLAIMER vii
OIL PROGRAM CONTACTS ix
ACRONYMS LIST xiii
INTRODUCTION 1-1
1.1 SPCC Background 1-1
1.1.1 Purpose and Scope 1-1
1.1.2 Statutory Framework 1-2
1.2 Regulatory History 1-4
1.2.1 Initial Promulgation 1-4
1.2.2 SPCC Task Force and GAO Recommendations 1-5
1.2.3 Proposed Revisions 1-7
1.2.4 Final Rule Revision 1-8
1.2.5 Compliance Date Amendments 1-9
1.3 Revised Rule Provisions 1-9
1.3.1 Rule Organization 1-10
1.3.2 Summary of Major Revisions 1-11
1.4 Using This Guidance 1-12
APPLICABILITY OF THE SPCC RULE 2-1
2.1 Introduction 2-1
2.1.1 Summary of General Applicability 2-1
2.2 Definition of Oil and Activities Involving Oil 2-3
2.2.1 Animal Fats and Vegetable Oils 2-3
2.2.2 Synthetic Oils 2-3
2.2.3 Determination of "Oil" for Natural Gas and Hazardous Substances 2-4
2.2.4 Activities Involving Oil 2-5
2.3 "Non-transportation-related" Facilities - EPA/DOT Jurisdiction 2-6
2.3.1 Definition of Facility 2-6
2.3.2 Determination of Transportation-related and Non-transportation-related
Facilities 2-8
2.3.3 EPA/DOT Jurisdiction Scenarios 2-9
2.4 Reasonable Expectation of Discharge to Navigable Waters in Quantities That
May Be Harmful 2-12
2.4.1 Definition of "Discharge" and "Discharge as Described in §112.1(b)" . . . 2-12
2.4.2 Reasonable Expectation of Discharge 2-13
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2.4.3 Geographic Scope 2-14
2.4.4 Definition of "Navigable Waters" 2-15
2.5 Storage Capacity 2-16
2.5.1 Capacity Thresholds 2-16
2.5.2 Storage Capacity Calculation 2-16
2.5.3 Definition of Storage Capacity 2-17
2.5.4 Tank Re-rating 2-18
2.6 Exemptions to the Requirements of the SPCC Rule 2-18
2.6.1 Facilities Subject to Minerals Management Service Regulations 2-18
2.6.2 Underground Storage Tanks 2-19
2.6.3 Wastewater Treatment Facilities 2-20
2.7 Determination of Applicability by the Regional Administrator 2-21
2.8 SPCC Applicability for Different Types of Containers 2-23
2.8.1 Bulk Storage Container 2-23
2.8.2 Oil-filled Equipment 2-23
2.9 Determination of Applicability of Facility Response Plans 2-24
2.10 Role of the EPA Inspector 2-25
ENVIRONMENTAL EQUIVALENCE 3-1
3.1 Introduction 3-1
3.2 Substantive Requirements Subject to the Environmental Equivalence
Provision 3-3
3.3 Policy Issues Addressed by Environmental Equivalence 3-4
3.3.1 Security 3-5
3.3.2 Facility Drainage 3-7
3.3.3 Corrosion Protection and Leak Testing of Completely Buried Metallic Storage
Tanks 3-10
3.3.4 Overfill Prevention 3-11
3.3.5 Piping 3-12
3.3.6 Evaluation, Inspection, and Testing 3-15
3.4 Review of Environmental Equivalence 3-16
3.4.1 SPCC Plan Documentation 3-16
3.4.2 Role of the EPA Inspector 3-19
SECONDARY CONTAINMENT AND IMPRACTICABILITY DETERMINATIONS 4-1
4.1 Introduction 4-1
4.2 Overview of Secondary Containment Provisions 4-2
4.2.1 General Secondary Containment Requirement 4-8
4.2.2 Specific Secondary Containment Requirements 4-10
4.2.3 Role of the EPA Inspector in Evaluating Secondary Containment
Methods 4-11
4.2.4 Sufficient Freeboard 4-12
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4.2.5 Role of the EPA Inspector in Evaluating Sufficient Freeboard 4-16
4.2.6 Passive versus Active Measures of Secondary Containment 4-16
4.2.7 Role of the EPA Inspector in Evaluating the Use of Active Measures of
Secondary Containment 4-20
4.2.8 "Sufficiently Impervious" 4-22
4.2.9 Role of the EPA Inspector in Evaluating "Sufficiently Impervious" 4-23
4.2.10 Facility Drainage (Onshore Facilities) 4-25
4.2.11 Role of the EPA Inspector in Evaluating Onshore Facility Drainage .... 4-27
4.3 Overview of the Impracticability Determination Provision 4-27
4.3.1 Meaning of "Impracticable" 4-28
4.4 Selected Issues Related to Secondary Containment and Impracticability
Determinations 4-28
4.4.1 General Secondary Containment Requirements, §112.7(c) 4-29
4.4.2 Secondary Containment Requirements for Loading/Unloading Racks,
§112.7(h)(1) 4-33
4.4.3 Secondary Containment Requirements for Onshore Bulk Storage
Containers, §112.8(c)(2) 4-38
4.4.4 Secondary Containment Requirements for Mobile/Portable Containers,
§112.8(c)(11) 4-39
4.4.5 Secondary Containment Requirements for Bulk Storage Containers at
Production Facilities, §112.9(c)(2) 4-40
4.4.6 Secondary Containment Requirements for Onshore Drilling or Workover
Equipment, §112.10(c) 4-41
4.5 Measures Required in Place of Secondary Containment 4-42
4.5.1 Integrity Testing of Bulk Storage Containers 4-42
4.5.2 Periodic Integrity and Leak Testing of the Valves and Piping 4-43
4.5.3 Oil Spill Contingency Plan and Written Commitment of Resources .... 4-43
4.5.4 Role of the EPA Inspector in Reviewing Impracticability Determinations 4-45
OIL/WATER SEPARATORS 5-1
5.1 Introduction 5-1
5.2 Overview of Provisions Applicable to Oil/Water Separators 5-2
5.3 Oil/Water Separators Used in Wastewater Treatment 5-5
5.3.1 Description of Oil/Water Separator Use in Wastewater Treatment 5-5
5.3.2 Applicability of the SPCC Rule to Oil/Water Separators Used for Wastewater
Treatment 5-6
5.3.3 Wastewater Treatment Exemption Clarification for Dry Gas Production
Facilities 5-8
5.4 Oil/Water Separators Used To Meet SPCC Secondary Containment
Requirements 5-8
5.4.1 Description of Oil/Water Separators Used to Meet SPCC Secondary
Containment Requirements 5-8
5.4.2 Applicability of the SPCC Rule to Oil/Water Separators Used to Meet Specific
SPCC Secondary Containment Requirements 5-9
5.5 Oil/Water Separators Used in Oil Production 5-11
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5.5.1 Description of Oil/Water Separators Used in Oil Production 5-11
5.5.2 Applicability of the SPCC Rule to Oil/Water Separators Used in Oil
Production 5-13
5.6 Documentation Requirements and the Role of the EPA Inspector 5-15
5.6.1 Documentation by Owner/Operator 5-15
5.6.2 Role of the EPA Inspector 5-16
FACILITY DIAGRAMS 6-1
6.1 Introduction 6-1
6.1.1 Purpose 6-1
6.1.2 Requirements for a Facility Diagram 6-1
6.2 Preparing a Facility Diagram 6-2
6.2.1 Level of Detail 6-3
6.2.2. Facility Description 6-3
6.2.3 Oil Containers 6-3
6.2.4 Mobile or Portable Containers 6-4
6.2.5 Completely Buried Storage Tanks 6-4
6.2.6 Piping and Manufacturing Equipment 6-5
6.2.7 Use of State and Federal Diagrams 6-7
6.3 Facility Diagram Examples 6-7
6.3.1 Example #1: Bulk Storage and Distribution Facility 6-7
6.3.2 Example #2: Manufacturing Facility 6-11
6.3.3 Example #3: Oil Production Facility 6-13
6.4 Review of a Facility Diagram 6-16
6.4.1 Documentation by Owner/Operator 6-16
6.4.2 Role of the EPA Inspector 6-16
INSPECTION, EVALUATION, AND TESTING 7-1
7.1 Introduction 7-1
7.2 Inspection, Evaluation, and Testing Under the SPCC Rule 7-1
7.2.1 Summary of Inspection and Integrity Testing Requirements 7-2
7.2.2 Regularly Scheduled Integrity Testing and Frequent Visual Inspection
of Aboveground Bulk Storage Containers 7-6
7.2.3 Brittle Fracture Evaluation of Field-Constructed Aboveground Containers 7-8
7.2.4 Inspections of Piping 7-9
7.2.5 Flowline Maintenance 7-10
7.2.6 Role of Industry Standards and Recommended Practices in Meeting SPCC
Requirements 7-12
7.3 Specific Circumstances 7-16
7.3.1 Aboveground Bulk Storage Container for Which the Baseline Condition Is
Known 7-16
7.3.2 Aboveground Bulk Storage Container for Which the Baseline Condition Is Not
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Known 7-17
7.3.3 Deviation from Integrity Testing Requirements Based on Environmental
Equivalence 7-19
7.3.4 Environmental Equivalence Scenarios for Shop-Built Containers 7-20
7.4 Documentation Requirements and Role of the EPA Inspector 7-22
7.5 Summary of Industry Standards and Regulations 7-24
7.5.1 API Standard 653 - Tank Inspection, Repair, Alteration, and Reconstruction
7-25
7.5.2 STI Standard SP-001 - Standard for the Inspection of Aboveground Storage
Tanks 7-27
7.5.3 API Recommended Practice 575 - Inspection of Atmospheric and Low-
Pressure Storage Tanks 7-29
7.5.4 API Recommended Practice 12R1 - Recommended Practice for Setting,
Maintenance, Inspection, Operation, and Repair of Tanks in Production
Service 7-30
7.5.5 API 570 - Piping Inspection Code: Inspection, Repair, Alteration, and
Rerating of In-service Piping Systems 7-31
7.5.6 API Recommended Practice 574 - Inspection Practices for Piping System
Components 7-32
7.5.7 API Recommended Practice 1110 - Pressure Testing of Liquid Petroleum
Pipelines 7-33
7.5.8 API Recommended Practice 579, Fitness-For-Service, Section 3 7-33
7.5.9 API Standard 2610 - Design, Construction, Operation, Maintenance, and
Inspection of Terminal & Tank Facilities 7-34
7.5.10 ASME B31.3- Process Piping 7-35
7.5.11 ASME Code for Pressure Piping B31.4-2002 - Pipeline Transportation
Systems for Liquid Hydrocarbons and Other Liquids 7-36
7.5.12 DOT 49 CFR 180.605 - Requirements for Periodic Testing, Inspection, and
Repair of Portable Tanks and Other Portable Containers 7-37
7.5.13 FAA Advisory Circular 150/5230-4A -Aircraft Fuel Storage, Handling, and
Dispensing on Airports 7-38
7.5.14 FAA Advisory Circular 150/5210-20 - Ground Vehicle Operations on Airports
7-38
7.5.15 Suggested Minimum Requirements for PE-Developed Site-Specific Integrity
Testing Program (Hybrid Testing Program) 7-39
APPENDICES
Appendix A Text of CWA 311 (j)(1 )(c)
Appendix B Select Regulations - 40 CFR part 109,110, and 112
Appendix C Summary of Revised Rule Provisions
Appendix D Sample Bulk Storage Facility SPCC Plan
Appendix E Sample Production Facility SPCC Plan
Appendix F Sample Contingency Plan
Appendix G SPCC Inspection Checklists
Appendix H Other Policy Documents
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DISCLAIMER
This document provides guidance to EPA inspectors, as well as 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 the general public on how EPA intends the
SPCC rule to be implemented. The guidance is designed to implement national policy on these
issues.
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. Thus, it 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 Guide 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 strongly preferred approach to assure
effective implementation of legal requirements, EPA decisionmakers retain 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.
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. 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. 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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DRAFT MATERIALS Acronyms
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 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.
Superfund, 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 9:00 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/resources/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)
Ariel Rios Building - Mail Code 5104A
1200 Pennsylvania Avenue
Washington, DC 20460
www.epa.gov/oilspill
oilinfo@epa.gov
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Acronyms
U.S. EPA Regional Offices
The Oil Program is administered through EPA headquarters and the ten EPA regions, each of
which is responsible for the execution of EPA programs within several states or territories. Contact
information for each of the Regional Oil Programs follows.
Region 1 - CT, ME, MA, NH, Rl, VT
One Congress Street, Suite 1100
Boston, MA 02114-2023
Main Number: (617)918-1111
Region 7- I A, KS, MO, NE
Storage Tanks & Oil Pollution Branch
901 North 5th Street
Kansas City, KS 66101
EPA Region 7 Operations Center (913) 551-7050
SPCC Coordinator: (913) 551-76477 (913) 551-7960
Region 2 - NJ, NY, PR, US VI
2890 Woodbridge Avenue
Building 209 (MS211)
Edison, NJ 08837-3679
Main Number: (732) 321-6654
SPCC Coordinator: (732) 321-6654
Region 3 - DE, DC, MD, PA, VA, WV
1650 Arch Street (3HS32)
Philadelphia, PA 19103-2029
Region 3 SPCC/FRP Hotline: 215-814-3452
Region 8 - CO, MT, ND, SD, UT, WY
999 18th Street, Suite 300 (8EPR-SA)
Denver, CO 80202-2466
Main Number: (800) 227-8917
SPCC Coordinator: (303) 312-6496
Region 9 - AZ, CA, HI, NV, AS, GU
75 Hawthorne Street (SFD9-2)
San Francisco, CA 94105
Main Number: (800) 231-3075
SPCC Coordinator: (415) 947-8000
Region 4 - AL, FL, GA, KY, MS, NC, SC, TN
61 Forsyth Street
Atlanta, GA 30365-3415
Main Number: (404) 562-9900
SPCC Coordinator: (404) 562-8705
Region 10- AK, ID, OR, WA
1200 6th Avenue (ECL-116)
Seattle, WA 98101
Main Number: (800) 424-4372
SPCC Coordinator: (206) 553-1671
Region 5 - IL, IN, Ml, MN, OH, Wl
77 West Jackson Boulevard (SE-5J)
Chicago, IL 60604-3590
Main Number: (312) 353-2000
SPCC Coordinator: (312) 886-7187
Alaska
U.S. EPA Alaska Operations Office
222 West 7th Ave. #19
Anchorage, AK 99513-7588
SPCC Coordinator: (907) 271-5083
Region 6 - AR, LA, NM, OK, TX
1445 Ross Avenue (6SF-RO)
Dallas, TX 75202-2733
Main Number: (214) 665-6444
SPCC Coordinators: (214) 665-6489, (214)665-2785
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DRAFT MATERIALS Acronyms
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 (G-OPF) - Room 2611
2100 2nd Street, SW
Washington, DC 20593-0001
(800) 424-8802
(202) 267-2675
Fax: 202-267-1322
TDD: 202-267-4477
http://www.nrc.uscg.mil
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Acronyms
ACRONYMS LIST
AC Advisory Circular
AFVO Animal Fat and/or Vegetable Oil
API American Petroleum Institute
ASME American Society of Mechanical Engineers
ASNT American Society for Non-Destructive Testing
AST Aboveground Storage Tank
ASTM American Society for Testing and Materials
BMP Best Management Practice
BOP Blowout Preventer
CERCLA Comprehensive Environmental Response, Compensation, and Liability Act
C F R Code of Federal Regulations
CRDM Continuous Release Detection Method
CWA Clean Water Act of 1972 (Federal Water Pollution Control Act)
DOI U.S. Department of Interior
DOT U.S. Department of Transportation
EO Executive Order
EORRA Edible Oil Regulatory Reform Act
E&P Exploration and Production
EPA U.S. Environmental Protection Agency
ERNS Emergency Response Notification System
FDA Food and Drug Administration
FAA Federal Aviation Administration
FR Federal Register
FRP Facility Response Plan
GAO General Accounting Office
GPR General Pretreatment Regulations
IBC Intermodal Bulk Container
ICP Integrated Contingency Plan
IM Intermodal
MIC Microbial Influenced Corrosion
MMS Minerals Management Service
MOU Memorandum of Understanding
NACE National Association of Corrosion Engineers
NCP National Contingency Plan
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Acronyms
NDE Non-Destructive Examination
NFPA National Fire Protection Association
NRC National Response Center
NPDES National Pollutant Discharge Elimination System
OPA Oil Pollution Act of 1990
OSHA U.S. Occupational Safety and Health Administration
PE Professional Engineer
PMAA Petroleum Marketers Association of America
POTW Publicly Owned Treatment Work
PSM Process Safety Management
RA Regional Administrator
RBI Risk-Based Inspection
RP Recommended Practice
RCRA Resource Conservation and Recovery Act
RMS Release Management Systems
SCADA Supervisory Control and Data Acquisition
SPCC Spill Prevention, Control, and Countermeasure
STI Steel Tank Institute
SWANCC Solid Waste Agency of Northern Cook County
UIC Underground Injection Control
UL Underwriters Laboratory
USCG U.S. Coast Guard
UST Underground Storage Tank
UT Ultrasonic Thickness
UTS Ultrasonic Thickness Scans
UTT Ultrasonic Thickness Testing
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Chapter 1: Introduction
INTRODUCTION
In 2002, the U.S. Environmental Protection Agency (EPA) amended the Oil Pollution
Prevention regulation (40 CFR part 112), which includes requirements for specific facilities to
prepare, amend, and implement Spill Prevention, Control, and Countermeasure (SPCC) Plans.
The regulation is largely performance-based (as requested in comments from the regulated
community), which allows flexibility in meeting the rule requirements to prevent discharges of oil to
navigable waters and adjoining shorelines. EPA developed this guidance document 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.
1.1 SPCC Background
§112.2
Sp;7/ 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.
The Oil Pollution Prevention regulation,
promulgated under the authority of §311 of the 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 and 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.
1.1.1 Purpose and Scope
Subparts A through C of part 112 are often referred to as the "SPCC rule." Focusing on 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 and adjoining shorelines. The rule requires facilities that could reasonably be expected to
discharge oil in quantities that may be harmful into navigable waters of the United States and
adjoining shorelines to develop and implement SPCC Plans. The Plans ensure that these facilities
put in place containment and countermeasures that will prevent oil discharges. The requirement to
develop, implement, and revise the SPCC Plan, as well as train employees to carry it out, will allow
owners and operators to achieve the goal of preventing, preparing for, and responding to oil
discharges that threaten navigable waters and adjoining shorelines.
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Part 112 also includes requirements for Facility Response Plans (FRPs). EPA has
established requirements that define who must prepare and submit an FRP and what must be
included in the Plan. These requirements are found in Subpart D of 40 CFR part 112, which is
often referred to as the "FRP rule."1 Although the SPCC and FRP rules are related, and certain
SPCC-regulated facilities must also comply with FRP requirements, this guidance document
concerns the prevention requirements of the SPCC rule (40 CFR part 112, subparts A, B, and C).
The SPCC rule carries out EPA's authority under CWA §311. 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
superceded by Executive Orders 11735 and 12777, respectively (38 FR 21243, August 7, 1973; 56
FR 54757, October 22, 1991). The U.S. Department of Transportation (DOT) was delegated
authority 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 significant 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.)
1.1.2 Statutory Framework
The Federal Water Pollution Control Act of 1972, as amended, or Clean Water Act, is the
principal federal statute for protecting navigable waters, adjoining shorelines, and the waters of the
contiguous zone from pollution. Section 311 of the CWA addresses the control of oil and
hazardous substance discharges, and provides the authority for a program to prevent, prepare for,
and respond to such discharges. Specifically, §311(j)(1)(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 document for the
textofCWA§311(j)(1)(C).)
The FRP rule applies to a subset of SPCC facilities: 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 112.20.
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Chapter 1: Introduction
Under CWA §311(a)(1), "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 confirmed that
all facilities processing and storing non-petroleum oils
in the quantities and under circumstances set out in
40 CFR part 112 are required to prepare and
. . oooo 01 • _i -iu iu i sludge, synthetic oils, mineral oils, oil
implement an SPCC Plan in accordance with that refusy^ oryoj| mjxed wjlh wgstes Qther thgn
§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,
dredged spoil.
Note: The above text is an excerpt of the SPCC rule.
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
. . ., , , , , , ., .. Refer to 40 CFR part 112 for the full text of the rule.
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 Guard2
consistently interpreted and administered §311 as applicable to spills of non-petroleum-based oils,
particularly because of the common physical and chemical properties of animal and vegetable oils
and petroleum oils, and their common potential for adverse environmental impact when discharged
into water.
The Oil Pollution Act of 1990 (OPA) streamlined and strengthened EPA's ability to prevent,
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 of 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 regulations to be promulgated that 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."
In 1995, Congress enacted the Edible Oil Regulatory Reform Act (EORRA). The statute
mandates that most federal agencies differentiate between 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
between these classes of oils, EORAA directed federal agencies to consider differences in these
oils' physical, chemical, biological, and other properties, and in their environmental effects. By an
August 12, 1994, letter submitted on behalf of several agricultural organizations, EPA received a
Petition for Reconsideration of the FRP rule as it applies to facilities that handle, store, or transport
DOT delegated authority over transportation-related facilities and vessels to the U.S. Coast Guard. In March 2003, the
Coast Guard formally transferred from 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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animal fats or vegetable oils.3 On October 20, 1997, EPA denied the petition to amend the FRP
rule (62 FR 54508) because it did not substantiate the petitioner's claims that animal fats and
vegetable oils differ from petroleum oils in properties and effects and 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 animal fats and vegetable
oils 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 the June 30, 2000, amendments to the FRP rule, 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
provided new subparts to facilitate differentiation between categories of oil listed in EORRA;
however, the requirements in each of the subparts are identical.
1.2 Regulatory History
The SPCC rule was initially promulgated in 1973, with modifications to the SPCC
requirements proposed for public comment on several occasions in the 1990s. Incorporating many
aspects of the earlier proposals, final revisions to the rule were published in the Federal Register
(FR) in July 2002. However, EPA extended the compliance dates in the SPCC rule for amending
existing SPCC Plans and for implementing amended or new Plans developed under revised 40
CFR part 112. EPA extended the dates to give owners and operators of affected facilities more
time to understand the revised requirements, to amend and implement their SPCC Plans that
comply with the revised requirements, and to understand the SPCC rule clarifications developed
during settlement proceedings in response to legal challenges filed by the regulated community
(see 69 FR 29728, May 25, 2004).
1.2.1 Initial Promulgation
The original SPCC rule proposal was published in the Federal Register on July 19, 1973
(38 FR 19334). The original SPCC final rule was published in the Federal Register on December
11, 1973, with an effective date of 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 gallons
"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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(or greater than 660 gallons aboveground in a single tank) or a buried underground oil storage
capacity greater than 42,000 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 12567),
primarily to clarify the criteria for determining whether or not a facility is subject to the regulation.
This rulemaking also clarified that SPCC Plans must be in a written form (§112.7, introductory
paragraph) and specified procedures for developing SPCC Plans for mobile facilities.4
1.2.2 SPCC Task Force and GAO Recommendations
In January 1988, a four-million gallon
aboveground storage tank in Floreffe, Pennsylvania,
experienced a brittle fracture of the tank shell, which
then split apart, collapsed, and released approximately
3.8 million gallons of diesel fuel. Of this amount,
approximately 750,000 gallons were discharged into the
Monongahela River. The spill temporarily 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 SPCC Task Force was formed to
examine federal regulations governing discharges from
aboveground storage tanks. The Task Force,
consisting of representatives from EPA headquarters
and regions, other federal agencies, and the states,
issued its findings and recommendations in May 1988.
The findings focused on the prevention of catastrophic
discharges and recommended changes to the SPCC
program (EPA, "The Oil Spill Prevention, Control, and
Countermeasures Program Task Force Report," Interim
Final Report, May 13, 1988).5
Figure 1-1. Aboveground storage tank in
Floreffe, Pennsylvania
Mobile facilities include onshore drilling or workover rigs, barge-mounted offshore drilling or workover rigs, and portable
fueling facilities.
5 Available in EPA docket OPA-1991 -0001.
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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 oil spill at an oil refinery in
Martinez, California, in April 1988, the General Accounting Office (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).6 To amend the SPCC regulation, GAO made
recommendations to the EPA Administrator 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
Storm water 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.
6 Available in EPA docket OPA-1991 -0001.
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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 requiring that facilities obtain certification from independent engineers
that facilities are in compliance with the regulations. Finally, the report also 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
to EPA that it consider re-establishing the oil spill research and development program.
1.2.3 Proposed Revisions
Following the Monongahela River spill 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 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
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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 Final Rule Revision
On July 17, 2002, EPA issued a final rule amending the Oil Pollution Prevention regulation,
primarily with respect to the SPCC subparts of part 112 (67 FR 47042). The final rule became
effective on August 16, 2002, and modified many aspects of the proposals described above. As a
performance-based regulation, the rule provides 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 includes new
subparts outlining the requirements for various classes of oil (pursuant to EORRA), revises the
applicability of the regulation, amends the requirements for completing SPCC Plans, and makes
other modifications. The final rule also contains a number of provisions designed to decrease
regulatory burden on facility owners and operators subject to the rule, while preserving
environmental protection.
In response to the final SPCC amendments, several members of the regulated community
filed legal challenges to certain aspects of the rule.7 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 that it developed in the course of settlement. The Federal Register notice
clarified statements regarding loading/unloading racks and impracticability that were challenged by
the plaintiffs. In addition, EPA clarified aspects of the wastewater treatment exemption and
specified which definition of "facility" applies to §112.20(f)(1). EPA also announced the availability
of a letter from EPA to the Petroleum Marketers Association of America (PMAA), which provides
additional guidance on equivalent environmental protection with respect to requirements for
integrity testing, security, and loading racks.8
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, Summary of Revised SPCC Rule
Provisions.
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.
Q
The Federal Register Notice and letter to PMAA are available on the Oil Program Web site, http://www.epa.gov/oilspill.
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1.2.5 Compliance Date Amendments
Following the 2002 final rule, on four occasions EPA extended the compliance dates for
facilities to update (or for new facilities to prepare) and implement an SPCC Plan that complies
with the revised requirements. The extensions provided additional time for the regulated
community to understand the SPCC amendments and the implications of the settlement
clarifications, and alleviated the need for individual extension requests.
EPA issued final rules in 2003, 2004, and 2006 (68 FR 1348, January 9, 2003; 68 FR
18890, April 17, 2003; 69 FR 48794, August 11, 2004; and 71 FR 8462, February 17, 2006) that
each extended the compliance dates in §112.3(a) and (b). The 2004 and 2006 final rules also
amended the compliance dates for onshore and offshore mobile facilities (§112.3(c)). The current
compliance dates in §112.3(a) and (b) for facilities are as follows:
A facility starting operation...
On or before August 16, 2002
After August 16, 2002,
through October 31 , 2007
After October 31 , 2007
Must...
Maintain the facility's existing SPCC Plan.
Amend and implement the SPCC Plan no later than
October 31, 2007.
Prepare and implement an SPCC Plan no later than
October 31, 2007.
Prepare and implement an SPCC Plan before beginning
operations.
Mobile facilities must prepare, implement, and maintain a Plan as required by the SPCC rule. They
must amend and implement the Plan, if necessary to ensure compliance with the revised SPCC
rule, on or before October 31, 2007. Mobile facilities that become operational after October 31,
2007, must prepare and implement a Plan before starting operations (§112.3(c)).
1.3 Revised Rule Provisions
The 2002 revision to the SPCC rule clarifies the language and organization of the
regulation, makes technical changes, and reduces regulatory burden. This section provides an
overview of the rule's organization and highlights some of the more substantive changes made to
the rule.
For the inspector's reference, Appendix B of this document includes the Oil Pollution
Prevention regulation, 40 CFR part 112, in its entirety and current as of the publication of this
document. Since the regulation is subject to change, this 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 Government
Printing Office Web site at http://www.gpoaccess.gov/fr/. General and permanent rules published
in the Federal Register are also codified in the Code of Federal Regulations (CFR), available
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electronically at http://www.gpoaccess.gov/cfr/. Inspectors implementing the SPCC program
should always consult the aforementioned resources (or their equivalent) to obtain the current
version of the SPCC rule.
1.3.1 Rule Organization
Part 112 is divided into four subparts, according to the oil and facility type. 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 part is organized as follows:
Subpart A Applicability, definitions, and general requirements for all facilities and all
types of oil
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 key sections of the SPCC rule,
including:
§112.1 General Applicability
§112.2 Definitions
§112.3 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
§112.7 General Requirements for SPCC Plans
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Additional requirements for specific facility types are given in §§112.8 through 112.12,9 and
are found within subparts B and C. These facility types and their corresponding sections of the rule
are:
Onshore Facilities (excluding production facilities) §§112.8 and 112.12
Oil Production Facilities (onshore) §112.9
Oil Drilling and Workover Facilities (onshore) §112.10
Oil Drilling, Production, or Workover Facilities (offshore) §112.11
The Oil Pollution Prevention regulation also contains several appendices, including
Memoranda of Understanding and appendices 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).
1.3.2 Summary of Major Revisions
The 2002 final SPCC rule is a performance-based regulation that allows owners, operators,
and the certifying Professional Engineer (PE) flexibility in meeting many of the prevention
requirements. Assisting inspectors in the evaluation of the proper use of environmental
equivalence and impracticability is one of the primary objectives of this guidance document. The
"environmental equivalence" provision allows facilities to deviate from specified substantive
requirements of the SPCC rule (except secondary containment 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 provisions. Additionally, in
situations where secondary containment is not practicable, the owner/operator must clearly explain
the reason for the determination in the SPCC Plan; for bulk storage containers, conduct periodic
integrity testing of containers and associated valves and piping; and 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 final rule revised many of the rule provisions, both to provide regulatory relief and
to make technical changes. The rule exempts many completely buried tanks, containers storing
less than 55 gallons, and certain wastewater treatment operations/facilities; raises the regulatory
threshold; and both reduces information required after a discharge and raises the regulatory trigger
for its submission. In addition, the rule decreased the frequency of Plan review from every three
years to every five years.
9
The 2002 SPCC rule includes requirements within subpart C that are not applicable or are inappropriate for animal fats and
vegetable oils. As a result, §§112.13 through 112.15 are not included here. These sections were promulgated because EPA had not
proposed differentiated SPCC requirements for public notice and comment.
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Technical changes 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 are highlighted in Appendix C
of this document, Summary of Revised SPCC Rule Provisions. Also, Chapter 2 of this document
discusses in greater detail the applicability of the revised SPCC rule, including facilities, activities,
and equipment subject to SPCC requirements.
1.4 Using This Guidance
SPCC Guidance for Regional Inspectors is
intended to assist EPA regional 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. This guidance does not
address all aspects of the SPCC rule. It is intended to
establish a consistent understanding among regional
EPA inspectors on how certain provisions of the rule
may be applied. It is not, however, a substitute for the
regulation itself.
Throughout the document, excerpts of the
SPCC rule that are relevant to a particular
section of this document 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 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 document 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 Federal Register
publication 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 document 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 the 40 CFR part 112, the
regulatory history, and the July 2002 amendments.
Chapter 2: Applicability of the SPCC Rule clarifies the facilities, activities, and equipment
that are subject to the SPCC rule through an in-depth discussion of the rule and relevant
scenarios.
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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 Determinations discusses the
secondary containment requirements and explains when an impracticability determination
can be made and how the determination should be documented.
Chapter 5: Oil/Water Separators addresses various scenarios involving oil/water
separators with respect to the SPCC rule requirements.
Chapters: Facility Diagrams 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.
Chapter 7: Inspections, 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; inspector checklists; model SPCC
Plans; and a model contingency plan.
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APPLICABILITY OF THE SPCC RULE
2.1 Introduction
The SPCC rule regulates 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. This chapter clarifies the facilities, activities, and equipment that are subject
to the SPCC rule. It is the responsibility of the facility owner/operator to make the determination
whether the facility is subject to the requirements of the SPCC rule. This determination is subject to
review by the Regional Administrator or his delegated representative.
2.1.1 Summary of General Applicability
...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.
Emphasis added. Refer to 40 CFR part 112 for the
full text of the rule.
Section 112.1 establishes the general
applicability of the SPCC rule by describing both the
facilities, activities, and equipment that are subject to
the rule and those that are excluded. In general,
SPCC-regulated facilities are non-transportation-
related, have aboveground oil storage capacity of
more than 1,320 gallons on site, and could reasonably
be expected to discharge oil to navigable waters or
adjoining shorelines in quantities that may be harmful.
Facilities owned and operated by federal government
agencies are subject to the regulation to the same
extent as any other facility (although the federal
government is not subject to civil penalties). Likewise,
facilities owned and operated by state and local
governments are subject to the regulation. Section
112.1(d) describes the facilities, activities, and equipment excluded from the rule based on
jurisdiction or through exemptions or exclusions from storage capacity calculations. Exemptions
pertain to whether a facility or part thereof is included in the SPCC-regulated universe, and
exclusions from storage capacity determine which containers count when determining a facility's
total oil storage capacity. In addition to facilities that are excluded from the SPCC rule because
they are not subject to EPA's jurisdiction, §112.1(d) exempts:
Any facility where the storage capacity of completely buried storage tanks and
associated piping and equipment does not exceed 42,000 gallons and the aggregate
aboveground storage capacity does not exceed 1,320 gallons;
Any container with a storage capacity less than 55 gallons at a facility, whether or
not subject to the requirements of the SPCC rule; and
Any facility or part thereof used exclusively for wastewater treatment.
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Exclusions from storage capacity calculations include:
Containers with a storage capacity of less than 55 gallons;
Storage containers used exclusively in wastewater treatment;
Completely buried tanks and associated piping and equipment that are subject to all
of the technical requirements under 40 CFR part 280 or 281; and
The capacity of any "permanently closed" aboveground storage container.
Notwithstanding the exemptions and exclusions provided in §112.1(d), under §112.1(f) the
Regional Administrator has discretion to require the owner or operator of any facility, subject to
EPA's jurisdiction under §311(j) Clean Water Act (CWA), to submit an SPCC Plan, or part of an
SPCC Plan, in order to carry out the purposes of the CWA.
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 the difference between "transportation-related" and "non-
transportation-related" facilities in determining jurisdiction of regulatory agencies.
Section 2.4 discusses the term "reasonable expectation of discharge to navigable
waters in quantities that may be harmful."
Section 2.5 addresses the storage capacity thresholds and the methods of
calculating storage capacity.
Section 2.6 addresses the exemptions to the SPCC rule.
Section 2.7 discusses the process for a Regional Administrator to determine
applicability, outside of §112.1 (d) requirements.
Section 2.8 addresses the applicability of the rule requirements to oil-filled
equipment (including manufacturing or process equipment), in contrast to bulk
storage containers.
Section 2.9 discusses the applicability of Facility Response Plans (FRPs).
Section 2.10 describes the role of the EPA inspector.
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2.2 Definition of Oil and Activities Involving Oil
The SPCC rule applies to facilities with the
potential to discharge "oil" in quantities that may be
harmful to navigable waters and adjoining shorelines.
The SPCC rule's definition of oil originated from the
Clean Water Act (CWA). Section 311 (a)(1) of the
CWA 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." Petroleum oils include crude
and refined petroleum products, asphalt, gasoline,
fuel oils, mineral oils, naphtha, sludge, oil refuse, and
oil mixed with wastes other than dredged spoil (67 FR
47075).
§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.
The U.S. Coast Guard (USCG) compiled a list of substances it considers oil, based on the
CWA definition. The list is available on the USCG Web site.1 Note, however, that the USCG list is
not comprehensive and does not define "oil" for purposes of 40 CFR part 112. EPA may determine
that a substance, chemical, material, or mixture is an oil even if it is not on the USCG list.
2.2.1 Animal Fats and Vegetable Oils
Oil covered under the SPCC regulation is further described in 40 CFR 112.2 as including
"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
includes animal fats and vegetable oils.
2.2.2 Synthetic Oils
The SPCC rule applies to 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 from plant
seeds. The base materials from which synthetic oils are synthesized include glycols, esters,
polyalphaolefins, aromatics, silicone fluids, Group III base oils, and others. Because of their origin,
synthetic oils are generally covered under subpart B of 40 CFR 112, which covers "petroleum oils
and non-petroleum oils..." Certain oils are synthesized from plant material, and thus may be
considered with animal fats and vegetable oils under subpart C of 40 CFR part 112, which, as
See the "List of Petroleum and Non-Petroleum Oils" on the USCG Web site at
http://vwwv.uscg.mil/vrp/faq/oil.shtml.
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discussed below, applies to "animal fats and oils and greases, and fish and marine mammal oils;
and...vegetable oils, including oils from seeds, nuts, fruits, and kernels."
2.2.3 Determination of "Oil" for Natural Gas and Hazardous Substances
Natural Gas
Natural gas (including liquid natural gas and liquid petroleum gas) is not considered an oil.
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). Petroleum distillate or oil that is
produced by natural gas wells and stored at atmospheric pressure and temperature (commonly
referred to as condensate or drip gas), however, is considered an oil.
Dry gas production facilities are not subject to the SPCC rule. A dry gas production facility
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. EPA has
clarified that a dry gas production facility does not meet the description of an "oil production, oil
recovery, or oil recycling facility" for which the wastewater treatment exemption would apply under
§112.1(d)(6).2 See excerpt below:
Notice Concerning Certain Issues Pertaining to the July 2002 Spill Prevention, Control,
and Countermeasure (SPCC) Rule, (May 25, 2004)
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.
Wet gas production facilities are subject to the SPCC rule. In addition to natural gas, wet
gas production facilities produce condensate or crude oil that can be drawn off the tanks,
2 "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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containers, or other production equipment at the facility. Since wet gas production facilities produce
and store condensate, which is considered an oil, they are regulated under the SPCC rule.
Hazardous Substances and Hazardous Waste
The definition of "oil" in §112.2 includes "oil mixed with wastes other than dredged spoil."
Oils covered under the SPCC rule therefore include certain hazardous substances or hazardous
wastes that are mixed with oil, as well as certain hazardous substances or hazardous wastes that
are themselves oils. Containers storing these substances may also be covered by other
regulations, such as the Resource Conservation and Recovery Act (RCRA), or the Comprehensive
Environmental Response, Compensation, and Liability Act (CERCLA), also known as Superfund.
Inspectors should evaluate whether containers storing hazardous substances or mixtures of wastes
contain oil. Although the rule contains an exemption for completely buried tanks that are subject to
all underground storage tank (LIST) technical requirements of 40 CFR part 280 and/or a state
program approved under part 281, tanks containing RCRA hazardous wastes are not subject to the
LIST rules, and therefore are not exempt under §112.1(d)(2)(i) or (4) if they contain oil.
Hazardous substances that are neither oils nor mixed with oils are not subject to SPCC rule
requirements.
2.2.4 Activities Involving Oil
Section 112.1(b) specifies that the owners or
operators of facilities involved in one or more of the
following oil-related activities are regulated under the
SPCC rule, provided they meet the other applicability
criteria in §112.1: "drilling, producing, gathering,
storing, processing, refining, transferring, distributing,
using, or consuming oil and oil products." Table 2-1
provides examples of these activities.
...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.
Emphasis added. Refer to 40 CFR part 112 for the
full text of the rule.
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Table 2-1. Examples of oil-related activities that may be regulated under 40 CFR part 112.
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. Note that businesses commonly
referred to as oil distributors and retailers commonly 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.
2.3 "Non-transportation-related" Facilities - EPA/DOT Jurisdiction
2.3.1 Definition of Facility
The extent of a "facility" under SPCC depends on site-specific circumstances. Factors that
may be considered relevant in delineating the boundaries of a facility for SPCC purposes 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;
Adjacency; or
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§112.2
Facility means 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 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 the types
of activity at the site.
Note: The above text is an excerpt of the SPCC rule.
Refer to 40 CFR part 112 for the full text of the rule.
Shared drainage pathways (e.g., same
receiving waterbodies).
The facility owner or operator, or a
Professional Engineer (PE) on behalf of the facility
owner/operator, determines what constitutes the
"facility." Note that the facility determination for
purposes of the SPCC rule should be the same as
that used to determine FRP applicability.
While the facility owner/operator has some
discretion in defining the parameters of the facility,
the boundaries of a facility should not be drawn to
purposely 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.
Alternatively, a single facility may be composed of various oil-containing areas spread over
a relatively large campus. For instance, different operational areas within a military base may be
considered a single 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, the facility may include larger military barracks for
which a branch of the military controls, operates, and maintains the space.
If a facility is regulated under the SPCC rule, it is the responsibility of the facility owner and
operator to ensure that an SPCC Plan is prepared. A site may have multiple owners and/or
operators, and therefore can have several facilities. Factors to 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.
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. Mobile facilities are addressed in §112.3(c), which
allows such facilities to create a general Plan, instead of developing a new Plan each time the
facility is moved to a new location.
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2.3.2 Determination of Transportation-related and Non-transportation-related Facilities
Facilities are divided into three categories: transportation-related facilities,
non-transportation-related facilities, and complexes. The determination of 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 facility with both transportation-related and non-transportation-related activities is
a "complex" and is subject to the dual jurisdiction of EPA and DOT. 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. Which activity would be subject to EPA jurisdiction and which activity would be subject to
DOT jurisdiction is defined by the 1971 DOT-EPA MOU.
A 1971 MOU 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.3 Sections of the MOU between EPA and DOT are included in Appendix A of 40 CFR part
112. Section 112.1(d)(1)(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)(1)(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.
3 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 Memorandum of Understanding.
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
Fixed or mobile onshore and offshore oil drilling
and production facilities
Oil refining and storage facilities
Industrial, commercial, agricultural, and public
facilities that use and store oil
Waste 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 within confines of non-
transportation-related facility
2.3.3 EPA/DOT Jurisdiction Scenarios
This section describes common scenarios that have raised jurisdictional questions regarding
the distinction between transportation-related and non-transportation-related facilities for
applicability of SPCC requirements. Inspectors should evaluate the intended activity carefully
because the determination of jurisdiction is not always straightforward.
Tank Trucks
EPA regulates tank trucks 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 around within the 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 2.5 of
this document) and there was a reasonable expectation of discharge to navigable waters or
adjoining shorelines. Similarly, an airport refueler or construction refueler that fuels exclusively at
one site would be subject to the SPCC rule. However, if the tank truck distributed fuel to multiple
off-site facilities, the tank truck would be transportation-related, and regulated by DOT.
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 2.5 of this
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document), and there is a reasonable expectation of discharge to navigable waters or shorelines.4
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.5 For
more information, refer to Chapter 4 of this document (Secondary Containment and Impracticability
Determinations), which discusses secondary containment requirements.
Railroad Cars
DOT regulates railroad cars from 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. DOT jurisdiction includes
railroad cars that are passing through a facility or are temporarily stopped on a normal route. EPA
regulates railroad cars after the transportation process ends; that is, when the railroad cars are
serving as non-transportation-related storage at an SPCC-regulated facility. EPA jurisdiction
includes railroad cars that are at their final destination, and/or if loading or unloading has begun. If
loading/unloading has begun, the railroad car itself may become the non-transportation-related
facility even if no other containers at the property would qualify the property. To be considered a
non-transportation-related facility, the railroad car must store oil in an amount above the regulatory
threshold, and there must be a reasonable expectation of discharge to navigable waters
EPA regulates railroad cars under the SPCC rule if they are operating exclusively within the
confines of a non-transportation facility. A railroad car would be subject to the SPCC rule if it, or the
facility, had a capacity above the regulatory threshold amount of oil, and there was a reasonable
expectation of discharge to navigable waters or adjoining shorelines.
Any Loading/Unloading Activities
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). A "loading/unloading 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 §1 12.7(c). If a
"loading/unloading rack" is present, the requirements of §1 12.7(h) apply to the loading/unloading
rack area. For more information, refer to Chapter 4 of this document (Secondary Containment and
Impracticability Determinations), which includes a discussion of secondary containment
requirements for loading/unloading areas.
4 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.
5 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.
6 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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Marine Terminals
A marine terminal is an example of a "complex" that is subject to U.S. Coast Guard (USCG)
and EPA jurisdiction. 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 (33
CFR part 154, Facilities Transferring Oil or Hazardous Material in Bulk). EPA jurisdiction begins at
the first valve inside secondary containment. If there is no secondary containment, EPA jurisdiction
begins at the valve or manifold adjacent to the storage tank (33 CFR 154.1020).
Vessels (Ships/Barges)
The U.S. Coast Guard regulates the loading or unloading of oil from a vessel to an onshore
facility, as well as the oil-carrying ship 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 of the secondary containment for the storage container. 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.
Motive Power
Motive power containers are located in or on a motor vehicle, such as on-board bulk oil
storage containers used solely to power the movement of a motor vehicle, or ancillary on-board, oil-
filled operational equipment used solely to facilitate its operation. A motive power container can be
considered non-transportation-related and subject to the SPCC rule. However, EPA does not
believe that the intent of the SPCC rule was to regulate motive power containers, including oil-filled
tanks used to fuel the propulsion of vehicles, such as buses, sport utility vehicles, construction
vehicles, and farm equipment.
Breakout Tanks
Breakout tanks are usually 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
also sometimes used for bulk storage. A breakout tank may be regulated by EPA, DOT, or both
depending on how the tank is used. For example, breakout tanks that are used solely to relieve
surges in a pipeline and are not used for any non-transportation-related activity (i.e., pipeline-in and
pipeline-out configuration, with no transfer to other equipment/mode of transportation such as a
tank truck), would be subject to DOT jurisdiction. A bulk storage container used to store oil while
also serving as a breakout tank for a pipeline or other transportation-related purpose would be
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subject to both DOT and EPA jurisdiction.7 For more information, see the EPA and DOT joint
memorandum dated February 4, 2000, which clarifies regulatory jurisdiction over breakout tanks.8
2.4 Reasonable Expectation of Discharge to Navigable Waters in
Quantities That May Be Harmful
2.4.1 Definition of "Discharge" and "Discharge as Described in §112.1(b)"
According to §112.1(b), the SPCC rule applies to 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.
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. The appearance of a sheen,
however, is not a necessary factor; 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.
Section 311 of the CWA defines and prohibits certain discharges of oil. These requirements
are also codified in 40 CFR part 112. As defined in §112.2, a "discharge" 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 distinction between the §112.2 and §112.1(b)
definitions of discharge is that a discharge as described in §112.1(b) is a violation of §311 of the
Clean Water Act, whereas a §112.2 discharge (i.e., one that does not impact a navigable water or
adjoining shoreline) is not a violation. For example, if a tank leaks a puddle of oil into a facility's
basement, this would be considered a discharge of oil, 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 §112.1(b)).
7 See also the 1971 MOU between DOT and EPA (Appendix A of 40 CFR part 112), and EPA/DOT memo
"Jurisdiction over Breakout Tanks/Bulk Oil Storage Tanks (Containers) at Transportation-Related and Non-
Transportation-Related Facilities" for specific examples of dual jurisdiction. See Appendices A and H.
8 See Appendix H.
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The SPCC regulation includes requirements for corrective action as well as additional
reporting requirements. For example, in §112.8(c)(10), 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 §112.1(b)), unless it impacts a navigable water or adjoining shoreline. Additionally,
if a facility discharged more than 42 gallons of oil in each of two discharges as described in
§112.1(b) overa 12-month period, the facility 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 §112.1(b) of more
than 1,000 gallons. For more information on these reporting requirements, see §112.4 of the rule.
2.4.2 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 §112.1(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)(1)(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
discharge as described in §112.1(b), when making this
...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.
Emphasis added. Refer to 40 CFR part 112 for the
full text of the rule.
prevent, contain, hinder, or restrain a
decision.
A facility owner or operator, however, should consider the presence of manmade structures
that may serve to convey 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.
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The following factors may prove useful to consider in determining whether there is a
reasonable expectation of discharge:
Whether a past discharge of oil reached a navigable water or adjoining shoreline,
which indicates that another could be reasonably expected;
Whether the facility is adjacent to navigable waters and a discharge to the navigable
waters could be reasonably expected;
Whether on-site conduits, such as sewer lines, storm sewers, and certain
underground features (e.g., power or cable lines, or groundwater), could facilitate the
transport of discharged oil off-site to navigable waters;
Whether a unique geological or geographic feature would facilitate the transport of
discharged oil off-site to navigable waters;
Whether the facility is near a watercourse and intervening natural drainage;
Whether precipitation runoff could transport oil into navigable waters; and
The quantity and nature of oil stored.
2.4.3 Geographic Scope
EPA revised the geographic scope 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 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.
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2.4.4 Definition of "Navigable Waters"
Section 112.2 provides the SPCC rule's definition of "navigable waters." See the text box
below.
§112.2
Navigable waters means the waters of the United States, including the territorial seas.
(1) The term includes:
(i) All waters that are currently used, were used in the past, or may be susceptible to use in interstate
or foreign commerce, including all waters subject to the ebb and flow of the tide;
(ii) All interstate waters, including interstate wetlands;
(iii) 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:
(A) That are or could be used by interstate or foreign travelers for recreational or other purposes; or
(B) From which fish or shellfish are or could be taken and sold in interstate or foreign commerce; or,
(C) That are or could be used for industrial purposes by industries in interstate commerce;
(iv) All impoundments of waters otherwise defined as waters of the United States under this section;
(v) Tributaries of waters identified in paragraphs (1)(i) through (iv) of this definition;
(vi) The territorial sea; and
(vii) Wetlands adjacent to waters (other than waters that are themselves wetlands) identified in
paragraph (1) of this definition.
(2) Waste treatment systems, including treatment ponds or lagoons designed to meet the
requirements of the CWA (other than cooling ponds which also meet the criteria of this definition) 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 CWA, the final authority regarding CWA jurisdiction remains with EPA.
Note: The above text is an excerpt of the SPCC rule. Referto 40 CFR part 112 forthe full text of the rule.
See "Joint Memorandum of U.S. Army Corps of Engineers and EPA providing clarifying
guidance regarding the Supreme Court's decision in So//cf Waste Agency of Northern Cook County
v. United States Army Corps of Engineers, 531 U.S. 159 (2001) (SWANCC)),"9 68 FR 1995,
January 15, 2003.
9 There is currently pending a petition for review challenging the definition of "navigable waters" in 40 CFR
112.2., American Petroleum Institute v. Leavitt, No. 1:102CV02247 PLF and consolidated cases (D.D.C. filed Nov. 14,
2002).
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Except as provided in paragraph (f) of this
section, this part does not apply to: ...
(2) Any facility which, although otherwise
subject to the jurisdiction of EPA, meets
both of the following requirements:
(i) The completely buried storage capacity
of the facility is 42,000 gallons or less of
oil. ...
(ii) The aggregate aboveground storage
capacity of the facility is 1,320 gallons or
less 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.
2.5 Storage Capacity
2.5.1 Capacity Thresholds
The SPCC rule applies to a facility that has
more than 42,000 gallons of completely buried oil
storage capacity or more than 1,320 gallons of
aggregate aboveground oil storage capacity, provided
it meets the other applicable criteria set forth in
§112.1.
According to §112.1(b)(1) 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. However,
§112.1(d)(2) 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, as is the case for containers smaller than
55 gallons). For example, a facility could have 10,000
gallons of aggregate aboveground storage capacity in
tanks and oil-filled equipment of 55 gallons or more,
and a completely buried tank of 10,000 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
gallons, all of the tanks and oil-filled equipment,
including the buried tank, are 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.
2.5.2 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. These containers are discussed below and summarized in Table 2-3.
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What to Count
All containers of oil with a capacity of 55 gallons or greater are to be counted (unless
listed below) when calculating total oil storage capacity at a facility.
What Not to Count
Permanently closed containers are not counted when calculating total oil storage
capacity. "Permanently closed," as defined in §112.2, refers to containers "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."
Completely buried tanks, as defined in §112.2, and connected underground piping,
underground ancillary equipment, and containment systems that are currently
subject to all of the technical requirements of 40 CFR part 280 or all of the technical
requirements of a state program approved under 40 CFR part 281 are not counted.
Such tanks must still be marked on the facility diagram as provided in §112.7(a)(3).
"Completely buried tank" as defined in §112.2 refers to "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."
Table 2-3. Summary of storage capacity calculation as described in §112.1(d)(2)(i) and (ii).
Included
Capacity of containers (e.g., bulk
storage containers, oil-filled
equipment, mobile/portable
containers) with a capacity of 55
gallons or greater
Excluded
Capacity of 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 containers that are permanently closed
2.5.3 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
§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.
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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 might hold (67 FR 47081).
Generally, the shell capacity is the rated design capacity rather than the working/operational
capacity.
2.5.4 Tank Re-rating
Shell capacity should be used as the measure of storage capacity, unless changes are
made to the design shell capacity in a permanent, non-reversible manner. For example, when the
integral design of a container has been altered by actions such as drilling a hole in the side of the
container so that it cannot hold oil above that point, shell capacity remains the measure of storage
capacity because such alteration can be altered again at will to restore the former storage capacity.
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
capacity.
An addition or modification to a field-erected storage tank should be performed in
accordance with industry standards and the original design specifications. Relevant industry
standards include American Petroleum Institute (API) Standard 653 "Tank Inspection, Repairs,
Alteration, and Reconstruction" (API-653). This standard includes additions or modifications to shell
penetrations such as overfill diverters. However, even where such modifications are done in
accordance with standards, the tank may not be considered re-rated to a lower capacity; the
capacity remains equal to the original rated shell capacity. An owner or operator may reduce the
capacity of a tank only by changing the shell dimensions (i.e., by removing shell plate sections).
Since SPCC requirements are based on shell capacity, modifying a vent, overflow, or other tank
appurtenances that reduce the working fill capacity does not affect SPCC requirements, including
facility capacity determination and secondary containment requirements.
2.6 Exemptions to the Requirements of the SPCC Rule
In addition to the criteria described
above, §112.1(d) describes certain types of
additional equipment and facilities that are
exempted from SPCC rule requirements.
2.6.1 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). MMS
regulations require adequate spill prevention,
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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control, and countermeasures that are directed more specifically to the facilities subject to the
regulations. The facilities are regulated by the Department of Interior as specified in the DOI-DOT-
EPA MOU (40 CFR part 112, Appendix B).
2.6.2 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 regulations).
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)).
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 UST
program defines USTs differently than the SPCC
rule does. The UST Program considers an
underground storage tank to be 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.
Except as provided in paragraph (f) of this
section, this part does not apply to: ...
(4) Any completely buried storage tank, as
defined in §112.2, and connected
underground piping, underground ancillary
equipment, and containment systems, at
any facility, that is subject to all of the
technical requirements of part 280 of this
chapter or a State program approved under
part 281 of this chapter, except that such a
tank must be marked 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.
The following 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 the completely
buried tanks contain oil):
Tanks with a capacity of 110 gallons or less;
Farm or residential tanks with a capacity of 1,100 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;
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Any LIST system holding RCRA hazardous waste;
Any equipment or machinery that contains regulated substances for operational
purposes;
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;10 and
Any LIST system that contains de minimis concentration of regulated substances.
The following are examples of deferrals from the LIST regulations (and therefore may be subject to
the SPCC rule):
Wastewater treatment tank systems;
Any LIST systems containing radioactive materials that are regulated under the
Atomic Energy Act of 1954;
LIST systems that are part of emergency generator systems at nuclear power
generation facilities;
Airport hydrant fuel distribution systems; and
LIST systems with field-constructed tanks.
Note that additional and/or more stringent requirements may exist in a state-approved
program under 40 CFR part 281 and that they may also impact SPCC applicability. For example, a
state may choose to regulate a LIST used for storing heating oil for consumptive use on the
premises where stored. Thus, under the state program the LIST is subject to all the technical
requirements of a 40 CFR part 281 program and not regulated by the SPCC rule. Inspectors
should consider any state LIST program approved
under 40 CFR part 281 when addressing applicability
issues associated with completely buried tanks.
2.6.3 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.
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.
Many of the wastewater treatment facilities or
parts thereof are subject to the National Pollutant Discharge Elimination System (NPDES) or state-
10 Although exempt from LIST 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 2.3.2 of this document.
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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).
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. Additionally, 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).
The exemption does not apply to a wastewater treatment facility or part thereof that is used
to store oil; in that instance, the oil storage capacity must be counted as part of the total facility
storage capacity (see 67 FR 47068). For example, if there is a 600-gallon storage container that
contains oil removed from an exempt oil/water separator and a 1,000-gallon storage container on
site, the total aboveground storage capacity for the facility would be 1,600 gallons, and the facility
may potentially be regulated by the SPCC rule.
In addition, the exemption does not apply to a wastewater treatment facility or parts thereof
used to meet a 40 CFR part 112 requirement, including an oil/water separator used to meet any
SPCC requirement. Examples of oil/water separators that are used to meet SPCC requirements
include oil/water separators used to satisfy the secondary containment requirements of §112.7(c),
§112.7(h)(1), and/or §112.8(c)(2). 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 of this document (Oil/Water Separators), which clarifies how the SPCC rule applies to
oil/water separators.
2.7 Determination of Applicability by the Regional Administrator
Section 112.1(f) allows the Regional
Administrator (RA) to require preparation of an SPCC
Plan or applicable part by the owner or operator of an
otherwise exempted facility that is subject to EPA
jurisdiction under CWA §311Q) of the CWA. This
provision is designed to address gaps in other
regulatory regimes that might best be remedied by
requiring a facility to have an SPCC Plan. For
example, a facility may be exempted 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 §112.1(b).
Notwithstanding paragraph (d) of this
section, the Regional Administrator may
require that the owner or operator of any
facility subject 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.
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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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
an entire Plan, or might require only a partial Plan addressing secondary containment, for example,
to prevent future discharges.
Sections 112.1(f)(1) through (5) describe the process for an RA to determine applicability.
The process includes specific time 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
he/she must prepare an SPCC Plan.
Table 2-4. Process for an RA determination of SPCC applicability and appeals.
Deadline
Responsibility
Determination
N/A
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(0(1))
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(0(2))
Regional Administrator (RA) must make 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). (§1 12.1 (0(5))
The Administrator must render a decision on the appeal.
(§112.1(0(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
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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.
2.8 SPCC Applicability for Different Types of Containers
2.8.1 Bulk Storage Container
A bulk storage container, as defined in
§112.2, must follow specific requirements, as
described under §§112.8(c), 112.9(c), and
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.
2.8.2 Oil-filled Equipment
§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.
Emphasis added. Refer to 40 CFR part 112 for the full
text of the rule.
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.
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 §112.1(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 a PE determines that secondary containment for this equipment is
impracticable.
Oil-filled Operational Equipment
Oil-filled operational equipment 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 does not include manufacturing equipment.
Examples of oil-filled operational equipment include hydraulic systems, lubricating systems
(including lubricating systems for pumps, compressors, and other rotating equipment), gear boxes,
machining coolant systems, heat transfer systems, transformers, other electrical equipment, and
other systems containing oil to enable operation.
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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.11 Additionally, there may 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). 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 PE may determine that the container is part of the manufacturing
equipment.
2.9 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, a facility that has the potential to cause substantial
harm to the environment in the event of a discharge must prepare and submit an FRP. SPCC
facilities must document whether they meet the FRP applicability criteria (40 CFR 112 Appendix C
Section 3.0). Facilities 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
11 The U.S. Occupational Safety and Health Administration'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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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-
are provided in Appendix H of this document.
2.10 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 Summary of Applicability Flowchart and Applicability Assessment Worksheet,
provided as Figures 2-1 and 2-2, 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 2-1. Summary of applicability flowchart.
Is the facility or part of the facility (e.g. complex)
considered non-transportation-related?
No
Yes
Is the facility engaged in drilling, producing,
gathering, storing, processing, refining,
transferring, distributing, using, or consuming oil?
No
Yes
Could the facility reasonably be expected to
discharge oil in quantities that may be harmful into
navigable waters or adjoining shorelines?
Yes
Is the total aggregate capacity of
aboveground oil storage containers
greater than 1,320 gallons of oil?
(Do not include containers less than 55
gallons, permanently closed containers,
or storage containers used exclusively
for wastewater treatment)
Is the total aggregate capacity of
or completely buried storage tanks
greater than 42,000 gallons of oil?
(Do not include completely buried tanks
subject to all technical requirements of
40 CFR 280/281, containers less than
55 gallons, permanently closed
containers, or storage containers used
exclusively for wastewater treatment)
Yes
The facility IS
subject to SPCC.
The facility IS NOT
subject to SPCC.
No
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.
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 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.
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Figure 2-2. 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 Sections 2.2.4 and 2.3 of this chapter.)
Drilling, producing, gathering, storing, processing, refining, transferring, distributing,
using, or consuming oil.
Yes. Go to question 2.
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 2.4 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.
Yes. Go to question 3.
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
gallons? (Refer to Sections 2.5 and 2.6 of this chapter.)
Note: Exclude containers less than 55 gallons, permanently closed containers, and storage containers
used exclusively in wastewater treatment.
Yes. The facility is subject to the SPCC rule.
No. Go to question 3b.
3b Is the total aggregate capacity of completely buried storage tanks greater than 42,000
gallons? (Refer to Sections 2.5 and 2.6 of this chapter.)
Note: Do not include completely buried tanks subject to all technical requirements of 40 CFR part 280
or 281, containers less than 55 gallons, permanently closed containers, or storage containers used
exclusively in wastewater treatment.
Yes. The facility is subject to the SPCC rule.
No. The facility is not subject to the SPCC rule.
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Chapter 3: Environmental Equivalence
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 facilities to achieve environmental
protection in a manner that fits their unique circumstances. It also allows facilities to adopt more
protective industry practices and technologies as they become available. The preamble to the 2002
SPCC regulation refers to certain industry standards that may be useful and can be considered in
implementing the required spill prevention measures.
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), must
verify that these alternative methods are in accordance with good engineering practice, including
consideration of industry standards, and provide environmental protection equivalent to the
measures described in the SPCC rule.
In the SPCC context, equivalent environmental protection means an equal level of
protection of navigable waters and adjoining shorelines from oil pollution. This 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).
The reason for deviating from a requirement of the SPCC rule, as well as a detailed
description of 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 he/she 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 two products, and the facility owner or operator
may be able to implement equivalent environmental protection through an alternate technology (67
FR 47094, 47095).
As mentioned above and as is the case for other technical elements of the SPCC Plan, the
PE must review the selection and implementation of environmentally equivalent measures and
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certify them as being consistent with good engineering practice (§112.3(d)). 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.
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.1 Although secondary containment reduces the risk of a discharge from primary
containment (the container or tank) to navigable waters and adjoining shorelines and can increase
the effectiveness of another prevention or control measure, it does not serve the purpose of
integrity testing, which is to identify potential leaks or failure of primary containment before a
discharge occurs.
EPA has indicated, however, that for certain shop-built containers - drums and small bulk
storage containers, for example - for which internal corrosion poses minimal risk of failure, which
are inspected at least monthly, and for which all sides are visible, visual inspection alone may
suffice to meet the integrity testing requirements under§112.8(c)(6) or§112.12(c)(6) (67 FR
47120). These are only examples; alternative measures that provide equivalent environmental
protection may also be appropriate for other site-specific circumstances. See Chapter 7,
Inspection, Evaluation, and Testing, for a discussion of "environmentally equivalent" integrity
testing.
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.
1 See EPA letter to Daniel Gilligan of PMAA, available in Appendix H of this guidance, or at
http://www.epa. gov/oilspill/pdfs/PMAAJetter.pdf.
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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)(1), as well as in relevant paragraphs of §§112.8, 112.9, 112.10, and
112.12. Chapter 4 of this document discusses these secondary containment requirements in detail.
§112.7(a)(2)
Comply with all applicable requirements listed in this part. 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)(1) of this section, and §§112.8(c)(2), 112.8(c)(11), 112.9(c)(2),
112.10(c), 112.12(c)(2), 112.12(c)(11), ... where applicable to a specific facility, if you provide equivalent
environmental protection by some other means of spill prevention, control, or countermeasure. 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)(1) of this section, and §§112.8(c)(2), 112.8(c)(11), 112.9(c)(2), 112.10(c), 112.12(c)(2), 112.12(c)(11), ... 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 the SPCC rule. Emphasis added. Refer to 40 CFR part 112 for the full text of the rule.
In addition to secondary containment requirements, deviations are not allowed for certain
provisions of §112.7, including the general recordkeeping and training provisions. Additionally,
deviations are not allowed for the administrative provisions of the rule, §§112.1 through 112.5. The
SPCC rule already provides flexibility for the format of records that need to be maintained at the
facility by allowing the use of ordinary and customary business records. 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.
Table 3-1 presents a list of the SPCC requirements eligible for consideration for
environmental equivalence.
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Table 3-1. Requirements eligible for environmental equivalence, by facility type.
Facility Type/Provision
Section(s)
Petroleum Oils and
Non-Petroleum Oils
Animal Fats and
Vegetable Oils
All regulated facilities
Security
Loading and unloading racks
Brittle fracture evaluation
112.7(g)
112.7(h)(2)and112.7(h)(3)
112.7(i)
Onshore facilities
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 treatment/disposal facilities
Removal of oil in diked areas and
production facility drainage
Piping
112.8(b), 112.9(b), 112.10(b)
and 112.11 (b)
112.8(c)(1)and 112.9(c)(1)
112.8(c)(3)
112.8(c)(4)and 112.8(c)(5)
112.8(c)(6)and112.9(c)(3)
112.8(c)(7)
112.8(c)(8)and 112.9(c)(4)
112.8(c)(9)and 112.9(d)(2)
112.8(c)(10)
112.8(d), 112.9(d)(1), and
112.9(d)(3)
112.12(b)
112.12(c)(1)
112.12(c)(3)
112.12(c)(4)and
112.12(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)
Oil drilling and workover facilities
Facility drainage/undiked areas (rig position)
Blowout prevention and well control system
112.10(b)
112.10(d)
N/A
N/A
Offshore facilities
Offshore oil drilling and workover facilities
1 1 2. 11(b) through 112.11(p)
N/A
3.3 Policy Issues Addressed by Environmental Equivalence
This section provides additional guidance on environmentally equivalent measures for
specific requirements on 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:
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Section 3.3.1 Security
Section 3.3.2 Facility Drainage
Section 3.3.3 Corrosion Protection and Leak Testing of Completely Buried Metallic
Storage Tanks
Section 3.3.4 Overfill Prevention
Section 3.3.5 Piping
Section 3.3.6 Evaluation, Inspection, and Testing
Although briefly discussed in Section 3.3.6, deviations from inspection and testing
requirements based on environmental equivalence are discussed in greater detail in Chapter 7 of
this guidance document.
3.3.1 Security
Section 112.7(g) of the SPCC rule outlines security requirements for facilities, including
fencing and lighting, and the use of control equipment and procedures. The security requirements
are meant to prevent discharges of oil, as defined in §112.1(b), that could result from acts of
vandalism or other unauthorized access to oil-filled containers or equipment. Note that unlike other
provisions under §112.7, the security provisions in paragraph (g) do not apply to oil production
facilities.
A facility owner or operator may
achieve the security objective through
alternative measures, as appropriate for
the facility, if these measures provide
environmental protection equivalent to the
measures described in the SPCC rule.
As described in §112.7(a)(2), if
alternative security measures are used,
the Plan must state the reasons for
nonconformance, and provide a
description of the alternative measures,
how they are implemented, and how they
will achieve environmentally equivalent
protection to prevent a discharge as
described in §112.1(b). This description
may include a discussion of how these
measures help deter vandals, prevent
unauthorized access to containers and
equipment that could be involved in an oil
discharge, or are otherwise equivalent to
the SPCC security requirements.
§112.7(9)
Security (excluding oil production facilities).
(1) 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.
(2) Ensure that the master flow and drain valves and any
other valves permitting direct outward flow of the container's
contents to the surface have adequate security measures so
that they remain in the closed position when in non-operating
or non-standby status.
(3) Lock the starter control on each oil pump in the "off"
position and locate it at a site accessible only to authorized
personnel when the pump is in a non-operating or non-
standby status.
(4) Securely cap or blank-flange the loading/unloading
connections of oil pipelines or facility piping when not in
service or when in standby service for an extended time. This
security practice also applies to piping that is emptied of
liquid content either by draining or by inert gas pressure.
(5) Provide facility lighting commensurate with the type and
location of the facility that will assist in the:
(i) Discovery of discharges occurring during hours of
darkness, both by operating personnel, if present, and by
non-operating personnel (the general public, local police,
etc.); and
(ii) Prevention of discharge occurring through acts of
vandalism.
Note: The above text is an excerpt of the SPCC rule. Refer to 40
CFRpart 112 for the full text of the rule.
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Fencing. Section 112.7(g)(1) requires that owners or operators fully fence the facility and/or
guard gates when the facility is not in production or attended. Two examples of scenarios
discussed in a letter to PMAA2 regarding environmentally equivalent alternatives to fencing the
entire footprint of a facility are discussed below.
Case #1 - Fencing areas directly
involved in oil handling, processing, and
storage. [Demonstrates environmental
equivalence.] For certain facilities where oil-filled
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
alternative may be preferable for very large
facilities where fencing the entire footprint of the
facility would require installing and monitoring very Figure 3-1. Fencing around storage area.
long lengths of fencing. In such cases, installing a
fence around the discrete areas of a facility where oil containers are located (Figure 3-1), or around
the equipment needed to operate such containers (Figure 3-2), may adequately deter vandals or
prevent access by unauthorized personnel, and thus may provide environmental protection
equivalent to the §112.7(g)(1) requirement to fully fence the facility to prevent a discharge as
described in §112.1(b) from these containers. Note that in the second case (i.e., where a fence is
placed only around the equipment used to operate containers), security measures may also be
required around the containers themselves, or other equipment and appurtenances connected to
the containers.
Case #2 - Placing master disconnect
panel controlling power to all pumps,
appurtenances (which could result in a
discharge such as from a bottom water drain),
and containers within an enclosed "pump
house." [Does not demonstrate environmental
equivalence.] Certain facilities may equip an
enclosed pump house with a master disconnect
switch that cuts off electrical power to the pumps
when the facility is unattended. Such disconnect
may provide equivalent protection for the pumps
and associated equipment that require power to Rgure 3.2 Fencjng ground g djspenser pump
operate and would meet the §112.7(g)(3)
requirement to lock starter controls on oil pumps in the "off" position and restrict access to
Available on EPA's Web site at http://www.epa.gov/oilspill/pdfs/PMAA letter.pdf or in Appendix
H of this guidance.
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authorized personnel only. However, if containers, piping, or appurtenances are also present, the
disconnect would not restrict access to equipment that can be operated without electrical power.
Therefore, it would not provide environmental protection equivalent to fencing. Additional security
measures would therefore be required for equipment that can be operated without electrical power.
Lighting. Section 112.7(g)(5) states that facilities must provide lighting to assist in the
discovery of discharges occurring during hours of darkness and help prevent discharges caused by
acts of vandalism. Note that the rule requires lighting that is "commensurate with the type and
location of the facility." Thus, for unattended facilities that are located away from inhabited areas
(for example, farm fields or certain isolated facilities) appropriate lighting may consist of lights that
are turned on intermittently. For example, lighting that uses motion-activated detectors may be an
appropriate means of meeting the lighting requirements, while avoiding undue attention to the
presence of oil containers. Alternatively, an environmentally equivalent approach may combine an
alarm system that detects the presence of trespassers, with portable lights used to perform regular
rounds of the facility. Whatever approach the owner or operator implements, the SPCC Plan
should discuss how lighting provided at the facility is adequate for the type and location of the
facility, or how the facility is achieving environmentally equivalent protection through other means.
The security requirements may also be met through other means, depending on facility-
specific circumstances. For example, a facility that is attended by a security guard on a 24-hour
basis may use closed-circuit cameras to detect and investigate unauthorized access to unfenced
portions of the facility. In another example, a facility such as an electrical substation that is
remotely located with limited access and monitored through use of a Supervisory Control and Data
Acquisition (SCADA) system, may provide environmentally equivalent security by its configuration
since the site's inaccessibility may be considered a powerful deterrent to unauthorized access and
the SCADA system serves to detect oil discharges remotely without requiring lighting to assist
visual detection.
3.3.2 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).
Diked Storage Area Provisions
The objective of the drainage requirements is to provide design specifications for the
secondary containment systems employed at the facility to prevent oil-contaminated water from
escaping the facility and becoming a discharge as described in §112.1(b).
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Sections 112.8(b)(1) and 112.8(b)(2)
specify requirements for the design of drainage
systems for dikes used as a means of
secondary containment. (See Chapter 4 for a
more detailed discussion of secondary
containment requirements.)
Under §112.8(b)(1) and 112.8(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, 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. When implemented
and maintained properly, such systems may
provide environmental protection equivalent to
using a manually operated valve and visually
monitoring discharge from dikes. Certain
valves will automatically shut off upon detecting
oil. These types of systems have been
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. The material
expands upon contact with oil, effectively plugging the drainage system. The valve is not actuated,
but rather the drainage system becomes plugged upon contact with the oil, thus providing an
equivalent measure of environmental protection.
§§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
(3) Design facility drainage systems from undiked
areas with a potential for a discharge (such as where
piping is located outside containment walls or where
tank truck discharges may occur outside the loading
area) to flow into ponds, lagoons, or catchment basins
designed 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 engineered as in paragraph
(b)(3) of this section, equip the final discharge of all
ditches inside the facility with a diversion 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.
Note: The above text is an excerpt of the SPCC rule.
Emphasis added. Refer to 40 CFR part 112 for the full text of
the rule.
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 and 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
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procedures for maintaining these systems and checking their effectiveness by routine inspections
and inspections following heavy rain events to ensure that they are operational.
Undiked Storage Area Provisions
Sections 112.8(b)(3) and 112.8(b)(4) specify performance requirements for systems used to
drain undiked areas with the potential for a discharge. These two provisions apply only when the
facility chooses to use a facility drainage system to meet general secondary containment
requirements under §112.7(c) or a more specific requirement under §112.8(c), §112.9(c),
§112.10(c) or§112.12(c). Where the facility drainage cannot be engineered as described in
§112.8(b)(3), the SPCC rule requires that the facility 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). Additional requirements in §112.8(b)(5) pertain more
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, such as a pond, lagoon, or
catchment basin, designed to retain the oil or return it to the facility. Other measures may be
implemented to achieve the drainage control objective, based on good engineering practice and
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 §112.1(b).
Alternatively, a facility owner or operator may engineer the facility drainage system intended
to meet general secondary containment requirements of §112.7(c) to flow into an oil/water
separator designed to remove oil resulting from facility operations. Chapter 5 of this guidance
document describes the requirements, depending on their function, that apply to oil/water
separators at SPCC-regulated facilities. The SPCC Plan should discuss how the oil/water
separator provides environmental equivalence, and any procedures necessary to maintain proper
operating conditions and the effectiveness of the system (such as maintenance of the filtration
systems). Note that the oil/water separator should be designed to handle the anticipated flow rate
and volumes of oil and water. Furthermore, the oil/water separator should be inspected or checked
periodically (including after heavy rain events) to ensure that it is working effectively and that it is
not holding significant quantities of oil for extended periods of time. For the oil/water separator to
provide equivalent environmental protection under §112.8(b)(3) and (b)(4), the PE must verify that
the oil/water separator is adequately designed and operated to effectively retain any discharge as
described in §112.1(b).
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Drainage at Production Facilities
Similar deviations from SPCC drainage
control requirements are possible for other types of
facilities. Section 112.9(b), for example, outlines
drainage requirements for production facilities. They
include sealing dike drains or drains of equivalent
measures required under§112.7(c)(1) for tank
batteries and separation and treating areas at all
times except when draining uncontaminated
rainwater. The PE may specify alternative
measures, such as the technologies described
above for electrical substations, that would provide
equivalent environmental protection by retaining oil
within the diked area in the event of a discharge.
(See the above discussion in Section 3.3.2, Diked
Storage Area Provisions.) Here also, the Plan must
describe the measure in detail and 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
§112.9(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 §112.1(b), close and
seal at all times drains of dikes or drains of
equivalent measures required under
§112.7(c)(1), 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.
3.3.3 Corrosion Protection and Leak Testing of Completely Buried Metallic Storage Tanks
Section 112.8(c) describes requirements
that apply to bulk storage containers at facilities
that store, use, or process petroleum and other
non-petroleum oils. Similar provisions are included
in §112.12(c) for facilities that store, use, or
process animal fats and/or vegetable oils. The
various subparagraphs under these sections
address requirements that apply to different types
of bulk storage containers, appurtenances, and
related activities.
§§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.
Subparagraph (c)(4) requires that facility owners or operators protect buried metallic storage
tanks from corrosion and regularly perform leak test on the tanks. Completely buried storage tanks
are exempted from SPCC requirements, as provided in §112.1(d)(2)(i), when the tanks are subject
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to all of the technical requirements of 40 CFR part 280 or a state program approved under 40 CFR
part 281. Tanks subject to 40 CFR part 280 or a state program approved under 40 CFR part 281
must follow those requirements. Completely buried tanks that are subject to SPCC requirements
must meet the provisions outlined in §112.8(c)(4) or §112.12(c)(4).
Completely buried tanks subject to the SPCC rule include, but are not limited to, tanks with
capacity of 110 gallons or less, heating oil tanks, and tanks located inside basements or tunnels.
Corrosion protection and leak detection for completely buried tanks that meet the corresponding
(corrosion protection and leak detection) testing requirements of 40 CFR part 280 or 40 CFR part
281 are considered environmentally equivalent to §§112.8(c)(4) and 112.12(c)(4). See Chapter 2
for more information on the applicability of the SPCC rule to completely buried storage tanks.
3.3.4 Overfill Prevention
Sections 112.8(c)(8) and 112.12(c)(8)
require that each container installation be
engineered to avoid discharges during filling
activities. At least one of the following systems is
required:
High level alarm with audible or
visual signal;
High liquid level pump cutoff
device;
Direct audible or code signal
communication between container
gauger and pumping station;
Fast response system for
determining the liquid level, such
as digital computer, telepulse, or
direct vision gauge, provided that
someone is present to monitor
gauges and the overall filling
operation; and
Regular tests of liquid level sensing
§§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 on excerpt of the SPCC rule.
Refer to 40 CFR part 112 for the full text of the rule.
devices to ensure proper operation.
The selection of an overfill prevention system should be based on good engineering practice
(§112.7 introductory paragraph), considering methods that are appropriate for the types of activities
and circumstances. While an audible/visual alarm or fast response system may be appropriate for
a large, stationary storage tank, a simpler overfill prevention system may be appropriate for a small
tank. In certain cases (e.g., for relatively small containers that can be readily monitored), a filling
procedure can be established in place of physical overfill prevention devices, which could be
considered environmentally equivalent. The procedure must be adequate to prevent a discharge
(as required under §112.8(c)(8)) when considering factors such as the container size; filling rate;
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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. For
example, a filling procedure for a small container may involve placing a drain cover on any floor
drain, ensuring that valves used to control drainage from the secondary containment are closed or
that sorbent material has been deployed around the container area, verifying that the container that
will receive the product has sufficient free capacity, and visually monitoring the product level
throughout the transfer operation.
In cases where a facility owner or operator uses an overfill prevention approach other than
the systems described in the SPCC rule, the Plan must describe the approach and how it provides
environmentally equivalent protection (§112.7(a)(2)). Where the alternative approach relies on
procedures instead of, or in addition to, a physical device, the Plan should clearly describe the
procedures and facility personnel involved in filling operations should be able to demonstrate an
understanding of the procedures and proper field implementation. As part of the description of the
environmentally equivalent measure required under §112.7(a)(2), the PE may reference other
facility documents in the SPCC Plan which 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.
3.3.5 Piping
Requirements that apply to piping at
onshore facilities that handle petroleum oils
are described in §112.8(d). Similar
requirements are described in §112.12(d) for
piping at facilities that handle animal fats
and/or vegetable oils.
These provisions of the SPCC rule
require that 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 regularly inspect
all aboveground valves, piping, and
appurtenances. The rule also requires
integrity and leak testing of all piping at the
time of installation, modification, construction,
relocation, or replacement. Finally, the rule
§§112.8(d)and 11
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.
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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 operational equipment.
An 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.3 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 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 deviations from prevention requirements related
to corrosion and other types of piping damage.
Protecting Buried Piping from Corrosion Damage
EPA recommends that a PE certifying an SPCC Plan consult appropriate industry standards
(consulting a qualified corrosion professional may also be appropriate) when evaluating the
adequacy of cathodic protection and corrosion prevention systems at the facility. Where the PE
determines that cathodic protection of new piping 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), the 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). The SPCC requirement (cathodic protection) averts discharges by preventing container
corrosion, while the alternative method (leak detection system and double-wall piping) detects and
contains leakage so it may be addressed before it can become a discharge as described in
Alternatively, the facility owner or operator may implement a comprehensive monitoring,
detection, and preventive maintenance program for piping and appurtenances where effective
cathodic protection is not reasonably achievable to detect and address potential discharges. The
3 "Causes of Release from Underground Storage Tank Systems: Attachments," September 1987,
EPA510-R-92-702.
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PE that certifies the Plan 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, "Piping Inspection Code: Inspection, Repair, Alteration, and Rerating of In-Service
Piping Systems,"
Table 3-2 summarizes key elements of an API-570 inspection program as they relate to the
evaluation of buried piping that is not cathodically protected (refer to Chapter 7 of this document for
an overview of API-570). Such a program provides a means of assessing the suitability of piping to
contain oil and to predict potential failures prior to their occurrence.
Table 3-2. Summary of inspection and leak testing elements of an API-570 program as they apply
to unprotected buried piping (refer to the full text of API 570 for details).
Inspection and Leak Testing
Elements
Summary
Pipe-to-Soil Potential Survey
Conduct pipe-to-soil potential survey along the pipe route to assess
corrosion potential at a five-year interval. Excavate sites where active
corrosion cells are located to determine the extent of corrosion damage.
Pipe Coating Holiday* Survey
Conduct pipe coating holiday survey as needed based on results of other
evaluations.
Soil Corrosivity
Perform soil corrosivity evaluation at a five-year interval for piping buried
in lengths greater than 100 feet.
External and Internal
Inspection Intervals
Determine external condition of buried piping that is not cathodically
protected by pigging or by excavating according to frequency indicated in
API-570 standard table. Adjust inspection of internal corrosion of buried
piping based on results of internal inspections of aboveground portion.
Leak Testing Intervals
Alternatively, or in addition to inspection, perform leak testing with
pressure at least 10 percent greater than maximum operating pressure at
an interval half that of inspections indicated in the standard for buried
piping that is not cathodically protected. Alternatively, perform
temperature-corrected volumetric or pressure test methods, or use
acoustic emission examination and 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, its scope and frequency should be developed and/or reviewed by
the PE certifying the Plan to be in accordance with good engineering practice, considering industry
standards. For facilities with shorter lengths of piping or where the distance to receiving waters or
adjoining shorelines is greater, the program may emphasize certain elements over others, such as
frequent leak testing of buried piping. Chapter 7 provides references to industry standards that
specifically discuss leak testing, including API Recommended Practice 1110, "Pressure Testing of
Liquid Petroleum Pipelines." However, since leak testing only detects leaks, rather than predicting
them, good engineering practice would suggest that testing should occur at a greater frequency
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than would otherwise be required if other prevention systems, such as cathodic protection and
coatings, were in place.
If alternative measures are used to meet the SPCC corrosion protection requirements,
§112.7(a)(2) requires that the Plan state the reasons for nonconformance 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, EPA suggests that 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 §112.1(b). The inspector should verify that the alternative method is
described in detail in the Plan, and that the Plan specifies the scope and frequency of tests and
inspections and/or refers to the relevant industry standards. The EPA inspector should also review
records maintained under normal business practice that document the tests and inspections.
Preventing Physical Damage to Aboveground Piping
Warnings to vehicles entering the facility may be given verbally, posted on signs, or other
appropriate means. Alternatively, protecting the equipment from the possibility of a collision by
installing fencing, barriers, curbing or other physical obstacles may be considered to provide
equivalent environmental protection. Whatever method is implemented at the facility, it must be
properly documented in the SPCC Plan in accordance with §112.7(a)(2).
3.3.6 Evaluation, Inspection, and Testing
The SPCC rule sets requirements for the evaluation, inspection, and testing of various parts
of a facility that could be involved in a discharge. The requirements are described in Chapter 7 of
this guidance document.
The evaluation, inspection, and testing requirements are aimed at detecting oil leaks, spills,
or other potential integrity problems before they can result in a discharge as described in §112.1(b).
The rule provides flexibility in the manner in which the evaluations, inspections, and tests are
performed by allowing the use of methods consistent with good engineering practice, as determined
by the PE certifying the Plan, considering industry standards.
While the rule describes the general nature and expected scope for evaluations,
inspections, and tests, the requirements are eligible for the environmental equivalence provisions
under §112.7(a)(2), and a facility owner or operator can therefore implement alternative measures if
he/she states in the Plan the reason for nonconformance and describes in detail the alternative
measures and how the alternative measures provide environmental protection equivalent to that
provided by the required evaluation, inspection, or test.
The use of environmental equivalence for evaluation, inspection, and testing requirements is
discussed in Chapter 7 of this guidance document, along with the background information on
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relevant regulatory requirements, industry standards, and recommended practices, which is
necessary for discussing alternatives to these provisions.
3.4 Review of Environmental Equivalence
Any substitution of a prevention and control measure required by the rule with an
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 3-3 at the end of this chapter to identify and
review technical rule requirements that are eligible for deviation through the environmental
equivalence provision.
Environmentally equivalent measures are not available for the general and specific
secondary containment provisions of the SPCC rule. Instead, §1 12.7(d) provides a separate
means of deviating from secondary containment requirements through a determination of
impracticability when secondary containment is not practicable. Environmentally equivalent
deviations are also not available for the general recordkeeping and training provisions in §1 12.7.
The rule already provides flexibility in the manner of recordkeeping by allowing the use of ordinary
and customary business records. The rule also does not specify how the training of oil-handling
personnel is conducted, or whom to designate as a person accountable for oil discharge prevention
3.4.1 SPCC Plan Documentation
For each environmental equivalent measure, the SPCC Plan must state the reason for
nonconformance within the relevant section of the Plan, as required in §1 12.7(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 (§§1 12.3(d) and 1 12.7). 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 must represent good engineering practice and must achieve
environmental protection equivalent to the SPCC rule requirement as required in §112.7(a)(2).
Technical deviations, like other substantive technical portions of the Plan requiring the application
of engineering judgement, are subject to PE certification (67 FR 47095).
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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 alternate methods and how this 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 detailing the steps involved in each activity, required equipment, personnel training, and
records that need to be maintained to document and verify implementation. Records that would be
kept as part of usual and customary business practices are generally considered 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 with the Plan for a period of three years
(§112.7(e)). Certain industry standards, for example API Standards 570 and 653, may specify that
records are to be maintained for more than three years.
The two examples below illustrate documentation of environmentally equivalent measures
that may be provided in a hypothetical SPCC Plan.
Example #1: Documentation of Environmentally Equivalent Protection for Integrity Testing
(§112.8(c)(6)) - Tank Elevated off the Ground
Bulk Storage Tanks - 40 CFR 112.8(c)(6)
ABC Oil is deviating from the integrity testing provision of §112.8(c)(6) for storage tank #3; based on good
engineering practice after considering the tank installation and alternative measures, the requirements of Steel
Tank Institute (STI) Standard SP-001, and alternative measures implemented by the facility. Tank #3 is a
4,500-gallon UL142 aboveground horizontal tank elevated on built-in saddles, and all sides of the tank are
visible. Tank #3 is not insulated, and the outside surface of the tank shell can therefore be observed on an
ongoing basis. The tank is located over a concrete floor, which functions as a release prevention barrier and
has properly sized containment in accordance with §112.8(c)(2). Under SP-001, the tank is considered a
Category 1 tank (aboveground storage tank with spill control and with continuous release detection method)
and therefore requires periodic inspection of the tank. The personnel performing these inspections are
knowledgeable of storage facility operations, characteristics of the liquid stored, the type of aboveground
storage tank and its associated components. Facility personnel perform monthly and annual inspections, as
described in Section 3.4 of the Plan and in accordance with the provisions and the checklists presented in SP-
001 . The scope of inspections and procedures is covered in the training provided to employees involved in
handling oil at the facility. The routine inspections focus specifically on detecting any change in conditions or
signs of product leakage from the tank, piping system, and appurtenances.
In accordance with inspection procedures outlined in this Plan, if signs of leakage or deterioration from the
tank are observed by facility personnel, the tank is to be inspected by a tank inspector certified by the
American Petroleum Institute or STI to assess its suitability for continued service, according to SP-001.
Facility personnel who conduct inspections are qualified in accordance with SP-001. The tank's physical
configuration, combined with monthly and annual inspections, ensures that any small leak that could develop
in the tank shell will be detected before it can become significant, escape secondary containment, and reach
the environment. This approach provides environmental protection equivalent to the non-destructive shell
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evaluation component of integrity testing required under §112.8(c)(6) since it provides an appropriate and
effective means of assessing the condition of the tank and its suitability for continued service.
Example #2: Documentation of Environmentally Equivalent Protection for Drainage of Diked
Areas (§112.8(b)(1) and §112.8(b)(2))
Facility Drainage - 40 CFR 112.8(b)(1) and 40 CFR 112.8(b)(2)
The dike structure in Area A contains three oil-filled 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 oil from escaping the containment structure while allowing water to flow through during normal
conditions. The system uses hydrophobic and oleofilic material to block the flow of water upon reacting to the
presence of oil. Documentation of the performance of this system and the manufacturer's suggested
replacement interval are maintained as an appendix to this Plan.
Employee supervision is not required under regular operating conditions to drain uncontaminated rainwater
that has accumulated in the dike. This method deviates from the rule requirements, which generally require
that a dike be drained under direct visual supervision using valves of manual, open-and-closed design.
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 (it will not cause 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.
3) Record event in log.
The above examples provide a sufficient level of detail to allow the EPA inspector to
understand what the facility is doing to meet the objectives of the SPCC rule with regard to the
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given provision, and to verify implementation of the measure(s) in the field. A Plan that simply
notes the use of an alternative measure without supporting descriptions would not be considered
sufficient. An example of insufficient documentation is given below.
Example #3: Insufficient Documentation of Environmentally Equivalent Protection for
Integrity Testing (§112.8(c)(6))
Bulk Storage Tanks - 40 CFR 112.8(c)(6)
No integrity testing is needed on tank 3A as this is an elevated shop-built storage tank and all sides are visible.
The outside of the tank is to be inspected on a regular schedule.
In contrast to the two previous examples, Example #3 does not provide sufficient detail to
ascertain whether the approach provides environmentally equivalent protection. In particular, it
does not describe how environmental equivalence is achieved, who performs the inspection, what
is inspected, and at what frequency.
3.4.2 Role of the EPA Inspector
Like other technical aspects of the SPCC Plan, the selection and implementation of
environmentally equivalent measures must be reviewed by the certifying PE for consistency with
good engineering practice (§112.3(d)). 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 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 of the environment against a discharge as described in
§112.1(b). 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, 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
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these techniques need to effectively protect the environment. EPA believes that, in general, PEs
will seek to protect themselves from liability by certifying only measures that do provide equivalent
environmental protection (67 FR 47095). 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.
The inspector should note whether the alternative measures meet the standards of common
sense, and appear to agree with recognized industry standards or, where such standards are not
used, are in accordance with good engineering practice. The 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.
If the inspector questions the appropriateness of alternative measures, he/she should fully
document all observations and other pertinent information for further review by the regional staff.
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 retains the authority to require amendment for deviations, as he/she can for any other
part of a Plan. If the Regional Administrator 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) and/or an enforcement action may be initiated as deemed
appropriate.
Table 3-3 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 3-3. SPCC requirements for environmentally equivalent measures under §112.7(a)(2).
Rule Element
Relevant
Section(s)
Evaluation
Verification
During Site Visit
Basis for Environmental Equivalence
ALL FACILITIES
Security
Loading and
unloading racks
112.7(g)(1)
112.7(g)(2)
112.7(g)(3)
112.7(g)(4)
112.7(g)(5)
112.7(h)(1)
112.7(h)(2)
Is the facility fully fenced?
Are entrance gates locked and/or
guarded when the facility is not in
production or is unattended?
Are adequate measures provided to
ensure that master flow and drain
valves and other valves that permit
direct outward flow of the
container's contents to the surface
remain in closed position when in
non-operating or non-standby
status?
Is the starter control for each oil
pump accessible only to authorized
personnel, and kept locked in "off1
position, when the pump is in non-
operating or non-standby status?
Are the loading/unloading
connections of oil pipelines or
facility piping securely capped or
blank-flanged when not in service,
or when in standby for an extended
period?
Is facility lighting appropriate,
considering the facility type and
location, to assist in the discovery of
discharges occurring in hours of
darkness and to discourage acts of
vandalism?
A/o deviation allowed based on
environmental equivalence.
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
Plan review
Visual
Plan review
Visual
Plan review
Visual
Plan review
Visual
Plan review
Visual
Plan review
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
U.S. Environmental Protection Agency
3-21
Version 1.0, 11/28/2005
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SPCC Guidance for Regional Inspectors
Rule Element
Field-constructed
aboveground
containers
Relevant
Section(s)
112.7(h)(3)
112.7(1)
Evaluation
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?
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 action been taken?
Verification
During Site Visit
Visual
Review of procedures
described in the Plan
Visual
Inspection and testing
records
Brittle fracture
evaluation records
Plan description of
standard by which the
brittle fracture
evaluation is
conducted
Basis for Environmental Equivalence
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
U.S. Environmental Protection Agency
3-22
Version 1.0, 11/28/2005
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Chapter 3: Environmental Equivalence
Rule Element
Relevant
Section(s)
Evaluation
Verification
During Site Visit
Basis for Environmental Equivalence
ALL FACILITIES, EXCEPT OIL PRODUCTION
Facility Drainage
Bulk Storage
Containers
112.8(b)(1)
and
112.8(b)(2)
OR
112.12(b)(1)
and
112.12(b)(2)
112.8(b)(3)
and
112.8(b)(4)
OR
112.12(b)(3)
and
112.12(b)(4)
112.8(b)(5)
OR
112.12(b)(5)
112.8(c)(1)
OR
112.12(c)(1)
112.8(c)(2)
OR
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?
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?
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 the material and construction of
containers used for the storage of
oil compatible with the product
stored and conditions of storage
(temperature, pressure, and soil
conditions)?
A/o deviation allowed based on
environmental equivalence.
Visual
Plan review
Records of drainage
events
Visual
Plan review
Visual
Plan review
Visual
Plan review
Standards of
construction (tank
label), construction
documents and as-
built specifications
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
U.S. Environmental Protection Agency
3-23
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SPCC Guidance for Regional Inspectors
Rule Element
Relevant
Section(s)
112.8(c)(3)
OR
112.12(c)(3)
112.8(c)(4)
OR
112.12(c)(4)
112.8(c)(4)
OR
112.12(c)(4)
112.8(c)(5)
OR
112.12(c)(5)
112.8(c)(6)
OR
112.12(c)(6)
112.8(c)(7)
OR
112.12(c)(7)
Evaluation
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 keep adequate
records of dike drainage event?
Does the facility have completely
buried metallic storage tanks that
were installed after January 10,
1974? If so, are these tanks
protected from corrosion by
coatings or cathodic protection?
Does the facility have completely
buried metallic storage tanks that
were installed after January 10,
1974? Are leak tests performed
regularly on these tanks?
Does the facility have partially
buried or bunkered metallic tanks
used for the storage of oil? If so,
are these tanks protected from
corrosion by coatings or cathodic
protection?
Does the facility test each
aboveground container (including
foundation and supports) for
integrity on a regular schedule, and
whenever a container undergoes
material repairs? Do the tests
combine visual inspection with
another non-destructive shell
testing technique? Does the facility
frequently inspect the outside of
each aboveground container for
signs of deterioration, discharges,
or accumulation or oil?
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?
Verification
During Site Visit
Visual
Plan review
Records of drainage
events
Visual
Plan review
Installation records
Visual
Plan review
Inspection and testing
records
Visual
Plan review
Records
Plan review
Inspection and testing
records
Visual
Container
specifications
Review of procedures
described in the Plan
Basis for Environmental Equivalence
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
U.S. Environmental Protection Agency
3-24
Version 1.0, 11/28/2005
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Chapter 3: Environmental Equivalence
Rule Element
Piping
Relevant
Section(s)
112.8(c)(8)
OR
112.12(c)(8)
112.8(c)(9)
OR
112.12(c)(9)
112.8(c)(10)
OR
112.12(c)(10)
112.8(c)(11)
OR
112.8,d,,1,
OR
112.12(d)(1)
Evaluation
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.
- In the case of bulk storage
containers, a fast response system
for determining the liquid level
(computers, telepulse, direct vision
gauges), combined with the
continuous presence of personnel
to monitor filling operations.
Are liquid level sensing devices
regularly tested to ensure proper
operation?
Are effluent treatment facilities
inspected frequently to detect
possible system upsets?
Are there visible discharges from
containers, including seams,
gaskets, piping, pumps, valves,
rivets, and bolts? If so, is the facility
promptly addressing such
discharges?
Is there accumulation of oil in diked
areas? If so, is the facility promptly
removing such accumulations?
A/o deviation allowed based on
environmental equivalence.
Does the facility have buried piping
installed after August 16, 2002? If
so, is this piping protected against
corrosion by wrapping and coating?
If 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?
Verification
During Site Visit
Visual
Review of test
procedures described
in the Plan
Test records
Inspection and testing
records
Review of inspection
program described in
Plan
Visual
Plan review
Visual
Plan review
Installation records
Basis for Environmental Equivalence
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
U.S. Environmental Protection Agency
3-25
Version 1.0, 11/28/2005
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SPCC Guidance for Regional Inspectors
Rule Element
Relevant
Section(s)
112.8(d)(2)
OR
112.12(d)(2)
112.8(d)(3)
OR
112.12(d)(3)
112.8(d)(4)
OR
112.12(d)(4)
112.8(d)(5)
OR
112.12(d)(5)
Evaluation
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?
Are pipe supports properly
designed to minimize abrasion and
corrosion and to allow for expansion
and contraction?
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,
constructed, relocated, or replaced?
Are all vehicles entering the facility
appropriately warned to ensure that
they will not endanger aboveground
piping and other oil transfer
operations?
Verification
During Site Visit
Visual
Plan review
Visual
Plan review
Inspection records
Description of
inspection program
within the Plan, or
reference to industry
standard.
Visual
Basis for Environmental Equivalence
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
U.S. Environmental Protection Agency
3-26
Version 1.0, 11/28/2005
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Chapter 3: Environmental Equivalence
Rule Element
Relevant
Section(s)
Evaluation
Verification
During Site Visit
Basis for Environmental Equivalence
ONSHORE OIL PRODUCTION FACILITIES
Drainage
Bulk Storage
Containers
112.9(b)(1)
112.9(b)(1)
112.9(b)(2)
112.9(c)(1)
112.9(c)(2)
112.9(c)(3)
112.9(c)(4)
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?
Is accumulated water inspected
prior to drainage? And is
accumulated oil removed and either
returned to storage or disposed of
properly?
Are field drainage systems and oil
traps, sumps, or skimmers regularly
inspected for accumulation of oil?
Are the material and construction of
containers used for the storage of
oil compatible with the product
stored and conditions of storage
(temperature, pressure, and soil
conditions)?
Wo deviation allowed based on
environmental equivalence.
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.
Are tank battery installations
engineered to prevent discharges?
- Container capacity is adequate to
prevent overfill if the gauger/pumper
is delayed in making a schedule
round
- Equipped with overflow equalizing
lines between containers
- Adequate vacuum protection to
prevent container collapse during
transfer of oil
- High level sensors if the facility is
subject to a computer production
control system
Visual
Plan review
Records of drainage
events
Plan review
Records of drainage
events
Visual
Inspection records
Inspection program
described in the Plan,
including the
schedule and scope
of such inspections
Visual
Construction
standards (tank
labels, as-build
specifications, etc.)
Visual indication of
incompatibility, i.e.,
excessive corrosion
Inspection and testing
records
Inspection program
described in the Plan,
including scope and
frequency of such
inspections
Visual
Plan review
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
U.S. Environmental Protection Agency
3-27
Version 1.0, 11/28/2005
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SPCC Guidance for Regional Inspectors
Rule Element
Transfer
operations
Relevant
Section(s)
112.9(d)(1)
112.9(d)(2)
112.9(d)(3)
Evaluation
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.
Are saltwater disposal facilities
inspected, particularly following a
sudden change in atmospheric
temperature?
Does the facility have a program of
flowline maintenance?
Verification
During Site Visit
Inspection and testing
records
Inspection program
described in the Plan,
including frequency
and scope of
inspections
Plan review
Inspection and testing
records
Inspection and
maintenance records.
Program of flowline
maintenance
described in the Plan,
including the scope
and frequency of
maintenance
Basis for Environmental Equivalence
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
U.S. Environmental Protection Agency
3-28
Version 1.0, 11/28/2005
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Chapter 3: Environmental Equivalence
Rule Element
Relevant
Section(s)
Evaluation
Verification
During Site Visit
Basis for Environmental Equivalence
ONSHORE OIL DRILLING AND WORKOVER FACILITIES
Mobile drilling or
workover
equipment
Containment
Blowout
prevention
112.10(b)
112.10(c)
112.10(d)
Is the equipment located so as to
prevent a discharge?
A/o deviation allowed based on
environmental equivalence.
If drilling below any casing string, or
during workover operations, are a
blowout prevention assembly and
well control system installed?
Are the blowout assembly and well
control system capable of
controlling well-head pressure?
Visual
Plan review
Visual
Installation record
Plan review
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
OFFSHORE OIL DRILLING, PRODUCTION AND WORKOVER FACILITIES
Drainage
112.11(b)
112.11(b)
112.11(c)
112.11(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?
If required by the conditions, are a
redundant automatic sump pump
and control devices provided?
Visual
Plan review
Visual
Oil removal
procedures described
in the Plan
Visual
Plan review
Visual
Preventive
maintenance
inspection and testing
program described in
the Plan
See below for cases where a sump is not practicable.
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
U.S. Environmental Protection Agency
3-29
Version 1.0, 11/28/2005
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SPCC Guidance for Regional Inspectors
Rule Element
Separators and
Treaters
Containers
Pollution
prevention
equipment and
systems
Relevant
Section(s)
112.11(d)
112.11(e)
112.11(f)
112.11(g)
112.11(h)
112.11(i)
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?
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 contain a written
procedure for inspecting and testing
pollution control equipment and
systems?
Are the pollution prevention
equipment and systems tested and
inspected on a scheduled periodic
basis?
Are the procedures documented in
the Plan?
Verification
During Site Visit
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
Basis for Environmental Equivalence
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
U.S. Environmental Protection Agency
3-30
Version 1.0, 11/28/2005
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Chapter 3: Environmental Equivalence
Rule Element
Well shut-in
valves
Blowout
Prevention
Flowlines
Piping
Relevant
Section(s)
112.11(j)
112.11(1)
Evaluation
Is the facility using simulated
discharges for testing and
inspecting human and equipment
pollution control and
countermeasure systems?
Is the method of activation or
control of well shut-in valves and
devices described in sufficient
details?
If drilling below any casing string or
during workover assembly, is a
blowout preventer (BOP) assembly
and well control system installed? If
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?
Are all flowlines equipped with a
high pressure sensing device and
shut-in valve at the wellhead? If
not, is a pressure relief system
provided for flowlines?
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?
Verification
During Site Visit
Description of testing
program in Plan
Plan review
Visual
Plan review
Installation records
Visual
Plan review
Visual
Plan review
Visual
Plan review
Installation records
Inspection and
maintenance program
described in Plan
Installation records
Basis for Environmental Equivalence
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
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Rule Element
Relevant
Section(s)
112.11(p)
Evaluation
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 Site Visit
Inspection and testing
records
Review of inspection
or testing prog ram
described in Plan,
including scope and
frequency of
inspections or tests
Basis for Environmental Equivalence
Does the Plan state the reason for nonconformance?
Does the Plan describe in sufficient detail an alternative
measure?
Is the alternative measure appropriate for the facility?
Does it provide equivalent environmental protection?
Is the alternative measure being implemented as
described?
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Chapter 4: Secondary Containment and Impracticability
SECONDARY CONTAINMENT AND IMPRACTICABILITY
DETERMINATIONS
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 through which the rule sets out to
do this is the secondary containment requirements. A secondary containment system provides an
essential line of defense in the event of a failure of an oil container (primary containment), such as a
bulk storage container, a mobile or portable container, pipes or flowlines, or other oil-filled
operational equipment. The system provides temporary containment of spilled oil until the
appropriate response actions are taken to abate the source of the discharge and remove oil from
areas where it has accumulated before the oil reaches navigable waters and adjoining shorelines.
The secondary containment requirements are divided into two categories:
General provisions address the potential for oil discharges from all regulated parts
of a facility. Containment method, design, and capacity are determined by good
engineering practice to contain an oil discharge until cleanup occurs.
Specific provisions address the potential of oil discharges from specific parts 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 the most likely oil
discharge from bulk storage containers; mobile/portable containers; production tank battery,
treatment, and separation installations; a particular piece of oil-filled operational or process
equipment; (non-rack) transfer activity; or piping in accordance with good engineering practice. The
specific secondary containment requirements are intended to address a major container failure (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. These specific
provisions (see Table 4.1 in Section 4.2) explicitly provide requirements for sizing, design, and
freeboard that need to be addressed in the SPCC Plan.
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 demonstrate how these
requirements apply. This chapter also discusses the rule's impracticability determination provision,
which may be used when a facility owner/operator is incapable of installing secondary containment
by any reasonable method. The additional requirements that accompany an impracticability
determination, the documentation needed to support such a determination, and the role of the EPA
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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 secondary containment
provisions, both general and specific. It also discusses related issues, such as
active versus passive measures, the "sufficiently impervious" requirement, and
facility drainage. The role of the EPA inspector in evaluating compliance with the
rule provisions is discussed for each of these subjects.
Section 4.3 describes the impracticability determination provision.
Section 4.4 discusses how the impracticability determination may be used in certain
circumstances.
Section 4.5 describes required measures when secondary containment is
impracticable.
Section 4.6 describes the role of the EPA inspector in reviewing impracticability
determinations.
4.2 Overview of Secondary Containment Provisions
The SPCC rule includes several different secondary containment provisions intended to
address the various activities or locations at a facility in which oil is handled. This section
differentiates among the general and specific secondary containment provisions.
Table 4-1 lists all the secondary containment provisions of the SPCC rule for different types
of facilities.
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Chapter 4: Secondary Containment and Impracticability
Table 4-1. Secondary containment provisions in 40 CFR part 112.
Type of Facility
All Facilities
Onshore Storage
Onshore Production
Onshore Oil Drilling and
Workover
Offshore Oil Drilling,
Production, and
Workover
Secondary Containment
General containment (areas with potential for
discharge, e.g., piping, oil-filled operating and
manufacturing equipment, and non-rack
related transfer areas)
Loading/unloading racks*,**
Bulk storage containers*
Mobile or portable oil containers*
Bulk storage containers, including tank
batteries, separation, and treating facility
installations*
Mobile drilling or workover equipment
Oil drilling, production, or workover equipment
Rule Section(s)
112.7(c)
112.7(h)(1)
112.8(c)(2)or112.12(c)(2)
112.8(c)(11)or112.12(c)(11)
112.9(c)(2)
112.10(c)
112.7(c)
* Sized secondary containment requirement, as discussed in Section 4.2.2.
** Although this requirement applies to all facilities, loading and unloading rack equipment is often not present at typical
production facilities, as discussed in Section 4.4.2.
Figures 4-1 through 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 visiting (see the uppermost box in each flowchart).
Types of containers, equipment, and activities or areas where oil is handled are identified in the
second row of the flowchart, with 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.
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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
§112.7(c)
- If frnpracfrcsb/e -
§112J(d) Impracticability Determination
- For bulk storage containers, conduct both periodic
integrity testing of the containers and periodic
integrity and teaK testing of the valves and piping
- Prepare a pad 109 contingency plan.
- Provide a written commitment of manpower,
equipment, and materials.
When dikes/berms
are used to satisfy
When facility drainage
controls are used to
1B E'xatTiptes of ures5 w)fti potenfe/ for f^frcterg^ may rnc/fxie;
piping and fitawltas. oil-filled electrical or operates} equipment, and
loadingfuntoading areas
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Figure 4-2. Secondary containment provisions in 40 CFR part 112 related to onshore production
facilities (§§112.7 and 112.9).
Onshore Production Facility
§112.7(c)
Bulk storage containers
§112.9(c)(2)
Includes tank batten/,
separation, and treating
facility installations.
Other areas** with
potential for discharge
§112.7(c)only
I
§112.7(d) Impracticability Determination
^ar bU< storage conlainers, conduct both periodic
irteyr ly les'ng erf the containers and periodic
irteguty aH leak testing of Die valves and piping.
- Proparo s. part 109 contingency plan.
- Provide a wr.tten comnitmsnt of manpower,
equipmerit, and materials.
" Examples of areas with potentol for discharge may include"
piping and fiowlSnes, oil-filled electrical or operating equipment,
and loading/unloading areas
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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
§112.7(c)
Provide catchment
basins or diversionary
structures
§112.10(c)
Other areas** with
potential for
discharge
§112.7{c)only
I
If Impracticable
1
§112>7(d) Impracticability Determination
• For bulk storage containers, conduct both periodic.
integrity testing of the containers an-d periodic
integrity and teak testing of the valves and piping.
- Prepare a part 109 contingency plan.
- Provide a written commitment of manpower.
equipment, and materials.
" Examples of areas with potential for discharge irmy include'
piping and ftowHn&s, oil-fitted electrical or aperafeif aqiitpnmnt, and
loading/unloading areas
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Chapter 4: Secondary Containment and Impracticability
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).
Offshore Oil Drilling, Production
and Workover Facility
§112.7(c)
Areas" with potential
for discharge
§112.7(c) only
Use oil drainage
collection 'equipment
around separators,
treatons, tanks and
associated equipment
— // Impracticable
§112.7(d) impracticability Determination
- For bulk storage containers, conduct both periodic
integrity' testing of the containers and paiiodlc
integrity and leak testing of the valves and piping.
- Prepare a part 109 contingency plan.
• Provide a written commitment of manpower,
equipment, and materials.
When sumps are used,
provide appropriate size
(§112 life)) aw:?a
spare pump
" Examples o/areas with potential for discharge may include:
piping sntl ftowtines. srtd oil-fitted electrical or operating ecftiipment
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4.2.1 General Secondary Containment Requirement
At a regulated facility, all areas with
the potential for a discharge are subject to
the general secondary containment
provision, §112.7(c). These areas may have
bulk storage containers; mobile/portable
containers; production tank batteries,
treatment, and separation installations;
pieces of oil-filled operational or
manufacturing equipment; loading/unloading
areas (also referred to as transfer areas);
piping; and may include other areas of a
facility where oil is present. The general
secondary containment provision requires
that these areas be designed with
appropriate containment and/or diversionary
structures to prevent a discharge that may
be harmful (a discharge as described in
§112.1(b)). "Appropriate containment"
should be designed to address the most
likely discharge from the primary
containment system such that the discharge will
§112.7(c)
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
prevention systems or its equivalent:
(1) For onshore facilities:
(i) Dikes, berms, or retaining walls sufficiently impervious to
contain oil;
(ii) Curbing;
(Hi) 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 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.
not escape containment before cleanup occurs.
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. Certification of the SPCC Plan verifies that whatever secondary containment methods are
selected are appropriate for the facility and that they follow good engineering practice.
Discharge as described in §112.1(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 the SPCC rule. Refer to 40 CFR part 112 for the full text of the rule.
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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 4.2.6, 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 4.2.6, 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 both 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 4.2.6, Passive Versus Active Measures of Secondary
Containment.
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Secondary
Containment Method
Description of Examples
Spill diversion ponds
and retention ponds
Designed for long-term or permanent containment of storm water capable to
capture and hold oil or runoff and prevent 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 4.2.6, 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. Please see Section 4.2.6,
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), uncoupling of hoses during bulk transfer operations, and for
pumps, valves, and fittings.
Sumps and collection
systems
A permanent pit or reservoir and the troughs/trenches connected to it that
collect oil.
4.2.2 Specific 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), 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:
Bulk storage containers;
Loading/unloading racks;
Mobile or portable bulk storage containers; and
Production facility bulk storage containers, including tank batteries, separation, and
treating vessels/equipment.
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The applicable requirements for each of these types of containers or equipment are
discussed in more detail in Section 4.4 of this chapter. In general, provisions for sized secondary
containment require that the chosen containment method be sized to contain the largest single oil
compartment or container plus "sufficient freeboard" to contain precipitation, as discussed in
Section 4.2.4 below. Specific freeboard sizing requirements apply to all of the areas listed above
except loading/unloading racks.
EPA inspectors should note that the "largest single compartment" may consist of 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). Accordingly, the total capacity of manifolded containers is the design
capacity standard for the sized secondary containment provisions (plus freeboard in certain cases).
4.2.3 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 any oil discharges to navigable waters and
adjoining shorelines. Some items that the inspector should look for include:
For a dike, berm, or other engineered secondary containment system:
Capacity of the system to contain oil as determined by the Professional Engineer
(PE) 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;
Level of precipitation in diked area and available capacity versus design capacity;
Dike or berm permeability;
Presence of debris;
Operational status of drain valves or other drainage controls;
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 plant systems (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.
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For retention and drainage ponds:
Capacity of the system to contain oil as determined by the PE in accordance with
good engineering practice and the requirements of the rule;
Erosion of the system;
Cracks in containment system materials (e.g., concrete, liners, coatings, earthen
materials);
Discoloration;
Design capacity versus available capacity;
Presence of spilled or leaked liquid;
Presence of debris;
Stressed vegetation;
Evidence of water seeps from the system; and
Operational status of drain valves or other drainage controls.
Some of the items listed above are discussed in more detail in later sections of this
guidance document.
4.2.4 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 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)
However, EPA 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 preamble, EPA 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.
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). However, where data are available, the facility owner/operator (and
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certifying PE) should consider the appropriateness of the 25-year, 24-hour storm event precipitation
level as a matter of good engineering practice.
EPA recognizes that a "110 percent of storage tank capacity" rule of thumb may be a
potentially acceptable design criterion in many situations, and that aboveground storage tank
regulations in many states require that secondary containment be sized to contain at least 110
percent of the volume of the largest tank. However, in some areas, 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;
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 determines what is sufficient
freeboard for precipitation for secondary containment and should document how the determination
was made along with supporting calculations in the SPCC Plan.
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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:
A20,000-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).
i Height:?
/) 1 I I //
20ft .
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.D
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).
4.5 inches /12 inches = .375 ft + 2.97 ft = 3.35 ft
Therefore, a dike design based on a 4.5 inch rain event provides a dike wall height of 3.35, or 0.9 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.
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.
1.5ft
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 nD2/4, 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 x n(10 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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4.2.5 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
production facility bulk storage containers, the inspector should ensure that the Plan documents
that the secondary containment capacity 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.1
- If diked area calculations appear inadequate, review local precipitation data
such as data from airports or the National Weather Service,2 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.
4.2.6 Passive Versus Active Measures of Secondary Containment
In some situations, permanent containment structures, such as dikes, may not be feasible
(i.e., for certain electrical equipment). Section 112.7(c) allows for the use of certain types 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 an activity involving the handling of oil starts, 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
1 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.
2 National Weather Service, Hydrometeorological Design Studies Center, Current Precipitation Frequency
Publications, available at http://www.nws.noaa.gov/oh/hdsc/currentpf.htmSN2.
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Chapter 4: Secondary Containment and Impracticability
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, priorto 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
judgement on what is realistically and reliably ^^^^^^^^^^^^^^
achievable, even under adverse circumstances. ^ Tip
... , . ,. , , Active -The containment
Using spill kits in the event of an oil discharge. measure involves a certain
The use of spill kits, strategically located and ready action by facility personnel
for deployment in the event of an oil discharge, may ^ .^S^dtonsaT
be an acceptable active measure, in certain also referred to as spill
circumstances, to prevent a spill from reaching countermeasures.
navigable waters or adjoining shorelines. This Passive - The containment
method may be risky and is subject to good measure remains in place
regardless of the facility
engineering judgement, considering the volume most operations and therefore
likely expected to be discharged and proximity to does not require facility
personnel to act.
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 (such as
required in §112.7(d)) because the response actions are specifically designed to
contain an oil discharge priorto reaching navigable waters or adjoining shorelines.
This 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 is subject to good engineering judgement.
Closing a gate valve that controls drainage from an 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.
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The 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 manned
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 oil discharge volume and rate, and is timely and properly
constructed/deployed. Ideally, in order to further reduce the potential for a discharge to reach
navigable waters or adjoining shorelines, the active
measure should be deployed prior to initiating the ^^^^^^^^^^^^^^^^^^^^^
activity with potential for a discharge. "* Tip
Land-Based Response Capability is used to
describe any active measure that is deployed/
For certain active measures, however, SUCh as implemented immediately upon discovery of a
discharge before the discharge reaches
the use Of "kitty litter" or Other loose sorbent material, it navigable waters or adjoining shorelines.
may be impractical to pre-deploy the measure. In such
.. . . . ... .. . . Contingency Plan is used to describe
cases, the sorbent material should be readily available mea Jes f£r controlling, containing, and
SO that it can immediately be used before the spill can recovering oil that has been discharged into or
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). EPA generally
believes that active containment measures can be used to satisfy the general secondary
containment requirement when they are capable of containing the most likely discharge volume.
Elements to consider may include the capacity of the containment measure, effectiveness, and
timely implementation, and the availability of personnel and equipment to implement the active
measure effectively at the facility. For example, a most likely 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).
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 navigable waters or drainage structures. 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 and adjoining shorelines.
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Additionally, oil-filled operational equipment (e.g., electrical transformers, capacitors,
switches) poses unique challenges, and permanent (passive) containment structures, such as
dikes, may not always be feasible. This type of oil-filled operational equipment 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, this method of containment may be risky
because it requires 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). The owner/operator may determine that these
methods prove impracticable for a facility with oil-filled operational equipment (e.g., because of
timeliness of a response). When secondary containment is impracticable, the certified SPCC Plan
must document the reasons for impracticability; use a contingency plan in lieu of secondary
containment; and provide 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)).
In certain circumstances, sorbents, such as socks, booms, pads, or loose materials, may be
used to complement passive measures. Where berms around transfer areas are open on one side
for access, and where the ground surface slopes away from the opening and from drains, for
example, sorbent material may be effective in preventing small quantities of oil from escaping the
bermed area in the event of a discharge.
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). Pre-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, EPA generally
believes that dikes/berms, curbing, spill diversion ponds, or other similarly fixed, engineered
structures 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)). It 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 to contain a spill should one occur). EPA also
recommends that the Plan 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 fashion. Both
the amount and location of materials should be determined based on good engineering practice,
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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 (i.e., BMPs) in
which case, these documents should be referenced in the SPCC Plan and available at the time of
an inspection.
There is a subtle but important difference between active containment measures
(countermeasures, including land-based response capability) and an oil spill contingency plan as
described in §112.7(d). Active secondary containment (as opposed to permanent or passive
containment structures) requires a deployment action; it is put in place prior to or immediately upon
discovery of an oil discharge. The purpose of these measures is to contain an oil discharge before
it reaches navigable waters or adjoining shorelines; alternatively, 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. A contingency plan 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.
Evaluating the ability of active secondary containment measures deployed after a discharge
to prevent oil from reaching navigable waters and 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 a critical factor. EPA would expect good engineering practice
to indicate that active secondary containment measures may be used to satisfy the general
secondary containment requirements of §112.7(c). Generally, active containment measures may
not be appropriate for satisfying the specific containment requirements for a major container failure.
Furthermore, even when used to comply with §112.7(c), EPA recommends that active measures be
limited to those situations where the PE has determined that the mostly likely discharge is a small
volume.
4.2.7 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, and whether the amount of available materials is
sufficient to handle the anticipated discharge volume. In addition, the inspector should document
whether the facility is keeping the necessary records.
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Upon 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 determining the adequacy of active measures are also provided below.
Explanation showing why the use of active measures is appropriate.
-D What is the PE-determined expected/most likely potential discharge volume,
and is the active measure appropriately sized to contain the spill?
-D What is the discharge detection method and is it appropriate?
-D How much time is required to deploy the selected active measure?
-D Given these factors, is the active measure a reasonable approach?
Detailed description of deployment procedures.
-D Will active measures be put in place before a potential discharge event or
after a spill occurs?
-D 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/timely manner to prevent oil from
reaching navigable waters or adjoining shorelines?
Does the Plan identify drainage pathways and the appropriate deployment
location 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).
-D 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 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, key is available), and are they located
close enough to the potential source of discharge?
Description of facility staff responsible for deploying active measures.
-D Are training records up to date?
-D Have the personnel involved in activities for which the active measures might
be deployed been trained (i.e., in location of materials, drainage conditions)?
-D Is there sufficiently trained facility staff present at all times to effectively
deploy the measures in the event of a discharge?
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4.2.8 "Sufficiently Impervious"
Section 1 12.7(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 production facilities), §§1 12.8(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. 1(b);
therefore, effective secondary containment methods must be able to contain oil until the oil is
cleaned up. EPA does not specify permeability or retention time performance criteria for these
provisions. Instead, EPA gives the owner/operator and the certifying PE flexibility in determining
how best to design the containment system to prevent a discharge as described in §112.1(b). This
determination is based on a good engineering practice evaluation of the facility configuration,
product properties, and other site-specific conditions. For example, EPA believes that a sufficiently
impervious retaining wall, or dike/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 discharge reaches navigable waters and adjoining
shorelines (§§112.7(c), 112.8(c)(2) and 112.12(c)(2)). Ultimately, the determination of
imperviousness should be verified by the certifying PE.
The preamble to the 2002 SPCC rule 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). Therefore, pursuant to §1 12.7(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" under §§1 12. 7(c), 112.8(c)(2), and
112.12(c)(2), respectively, 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 an immediate discharge as described in
In certain geographic locations the native soil (e.g., clay) may be determined as sufficiently
impervious by the PE. However, there are many more instances where good engineering practice
would generally not allow the use of a facility's native soil alone as secondary containment because
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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. The Act requires that residual
substances be removed, within 15 days, from the ground or affected waters. Discharges to soil and
groundwater may also violate other federal regulations. In addition, 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 under other statutes or regulations
should contact the appropriate authorities for follow-up with the facility.
In summary, any of the owner/operator's determinations specifying whether secondary
containment structures are capable of containing oil until it is cleaned up ("sufficiently impervious")
should be made based on good engineering practice and may consider site-specific factors.
4.2.9 Role of the EPA Inspector in Evaluating "Sufficiently Impervious"
The EPA inspector should determine whether the facility's secondary containment is
sufficiently impervious, based on a review of the SPCC Plan and on an observation of site
conditions. The EPA inspector may ask to see any calculations/engineering justifications used in
determining levels of imperviousness; this information, including calculations, should be maintained
with the Plan to facilitate the inspector's review. To determine whether secondary containment is
sufficiently impervious, the inspector may consider the following:
Whether the SPCC Plan describes how secondary containment is designed,
implemented, and maintained. The certification of the Plan's adequacy is the
responsibility of the PE and a determination of sufficient imperviousness may be
based strictly on geotechnical knowledge of soil classification and best engineering
judgment. The inspector may also 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)(1), 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.
For bulk storage facilities (excluding production) subject to §112.8 or §112.12,
procedures on how the facility minimizes and evaluates the potential for corrosion of
container bottoms/bases 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
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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 the scope of the container integrity testing program in
accordance with industry standards. 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 of this document for more
information on integrity testing.)
- Whether the facility has the ability to detect oil discharges from a container
bottom in order to commence cleanup before a discharge escapes the
containment systems.
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 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 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). Look for 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, EPA recommends that it 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.
4.2.10 Facility Drainage (Onshore Facilities)
Control of Drainage from Dikes and Berms
When containment methods such as dikes and berms are used to satisfy the secondary
containment requirements of the rule such as §§112.7(c) and 112.8(c)(2), the specific facility
drainage requirements also apply. The specific requirements for diked areas at onshore facilities
(except production) are found in §§112.8(b)(1), 112.8(b)(2), 112.12(b)(1), and 112.12(b)(2); for
diked areas at onshore production facilities they are found in §112.9(b)(1). 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
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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)(1) and 112.12(b)(1)). At oil production facilities, drains on secondary containment
systems (both dikes and other equivalent measures required under §112.7(c)(1)) must be closed
and sealed at all times, except when draining uncontaminated rainwater (§112.9(b)(1)). 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 records
of the drainage events must be
maintained. Section 112. 9(b)(1)
requires that oil production facilities
comply with the same drainage
procedures for diked areas as other
types of onshore facilities under
§112.8(c)(3)(ii) through (iv). 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 rules in §122.41(j)(2) or
122.41(m)(3) are acceptable under
§§112.8(c)(3)(iv)and
§§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.
(3) Design facility drainage systems from undiked areas with a
potential for a discharge (such as where piping is located outside
containment walls or where tank truck discharges may occur outside
the loading area) to flow into ponds, lagoons, or catchment basins
designed 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 engineered as in paragraph (b)(3) of this
section, equip the final discharge of all ditches inside the facility with
a diversion 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.
Note: The above text is an excerpt of the SPCC rule. Refer to 40 CFR part
112 for the full text of the rule.
Facility Drainage Control
When secondary containment requirements are addressed through facility drainage
controls, the requirements in §112.8(b)(3) and (4), or §112.12(b)(3) and (4) apply. For example, a
facility may 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 as
described in §112.1(b). 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)).
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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), which is
effective to prevent a discharge as described in §112.1(b), 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 such as §§112.7(c) and 112.8(c)(2).
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 containment
requirements of §112.7(c) for a piece of operational equipment (including electrical oil-filled
equipment). The pond/drainage system should be designed to contain the volume of oil
likely to be discharged as determined according to good engineering practice and
documented in the SPCC Plan. The capacity of the secondary containment required is that
which is necessary to meet the general containment requirement based on a likely
discharge (not necessarily a 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 containment
requirements of §112.8(c)(2) for a bulk storage container, the pond/drainage system must
be designed to contain the capacity of the largest bulk storage container (with appropriate
freeboard for precipitation) as dictated by the rule's requirements. The specific containment
requirement is based on a major 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 containment requirements, the system's
design will need to meet the most stringent rule requirement (typically the specific secondary
containment requirement).
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 of this guidance document,
Environmental Equivalence, includes a further discussion on ways to evaluate whether facility
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Chapter 4: Secondary Containment and Impracticability
drainage systems that deviate from the specified design standards are "environmentally equivalent"
and comply with §112.7(a)(2).
4.2.11 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 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 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 inspector should also evaluate the
facility records to verify compliance with the drainage procedures described in §112.8(c)(3).
4.3 Overview of the Impracticability Determination Provision
EPA recognizes that, although engineered
passive containment systems (such as dikes and
drainage systems) or active secondary
containment approaches are preferable, they may
not always be practicable. If a facility
owner/operator finds that containment methods
are "impracticable," alternative modes of
protection to prevent and contain oil discharges
are available. The impracticability provision found
in §112.7(d) allows facility owners/operators to
substitute a combination of other measures in
place of secondary containment: (1) periodic
integrity testing of bulk storage containers and
periodic integrity testing and leak testing of the
valves and piping associated with the containers;
(2) unless they have submitted a Facility
Response Plan (FRP) under §112.20, an oil spill
contingency plan; and (3) a written commitment of
manpower, equipment, and materials required to
control and remove any quantity of oil discharged that
§112.7(d)
If you determine that the installation of any of the
structures or pieces of equipment listed in
paragraphs (c) and (h)(1) of this section, and
§§112.8(c)(2), 112.8(c)(11), 112.9(c)(2), 112.10(c),
112.12(c)(2), 112.12(c)(11), 112.13(c)(2), and
112.14(c) to prevent a discharge as described in
§112.1(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.
may be harmful.
If an impracticability determination is made, the SPCC Plan must clearly describe why
secondary containment measures are impracticable and how the specified additional measures are
implemented (§112.7(d)). See Section 4.5 of this chapter for more information on the additional
measures. The option of determining impracticability assumes that it is feasible to effectively and
reliably implement a contingency plan. Facilities should be aware that an impracticability
determination may affect the applicability of the FRP requirements under 40 CFR part 112 subpart
D. In addition, an impracticability determination may affect the calculation of the worst case
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discharge volume, which may impact the amount of resources required to respond to a worst case
discharge scenario.
4.3.1 Meaning of "Impracticable"
The impracticability determination is intended to be used when a facility owner/operator is
incapable of installing 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). 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 below).
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).
4.4 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. Issues related to the use of impracticability determinations for
selected secondary containment requirements are discussed below. Requirements under each
provision are summarized below, along with a discussion of selected issues. 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 of this guidance
document for more information on the environmental equivalence provision).
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4.4.1 General Secondary Containment Requirements, §112.7(c)
The secondary containment requirements found in §112.7(c) apply to any area within a
regulated facility where a discharge may occur. Piping, flowlines, non-bulk containers such as oil-
filled operational equipment and manufacturing equipment, and non-rack transfer areas are subject
to the general secondary containment requirements. A discussion of issues related to secondary
containment for piping and flowlines, transfer areas, and certain oil-filled equipment follows.
Piping and Flowlines
Examination of discharge reports from the Emergency Response Notification System
(ERNS) shows that discharges from valves, piping, flowlines, and appurtenances are much more
common than catastrophic tank failure or discharges from tanks (67 FR 47124). To prevent a
discharge as described in §112.1(b), all piping, including buried piping and flowlines, at regulated
facilities must comply with the general secondary containment requirements contained in §112.7(c).
In certain cases, secondary containment for piping will be possible. Section 112.7(c)
provides flexibility in the method of secondary containment: active 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 and flowlines; however,
good engineering practice prescribes that containment size should be based on the magnitude of a
reasonable discharge scenario, taking into consideration the specific features of the facility and
operation. A determination of adequate secondary containment should consider the reasonably
expected sources, maximum flow rate, duration of a discharge, and detection capability. The EPA
inspector should ensure that the secondary containment method for piping and flowlines is
documented in the SPCC Plan and that the PE has certified that the method is appropriate for the
facility according to good engineering practice. If active methods of containment are selected, the
facility personnel should be able to demonstrate that they can effectively deploy these measures to
contain a potential spill before it reaches navigable waters or adjoining shorelines.
EPA acknowledges that in many cases, secondary containment may not be practicable for
flowlines and gathering lines. For example, a 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. For instance, 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 of the fields 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 line or county road due to space limitations or intrusion into a county's
property or right-of-way. At unmanned facilities, the use of active secondary containment methods
is not possible because there is limited capability to detect a discharge and deploy active measures
in a timely fashion. If secondary containment is not practicable, facility owners/operators may make
an impracticability determination and comply with the additional regulatory requirements described
in§112.7(d).
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The preamble of the 2002 SPCC rule (67 FR 47078) states that the contingency plan
required when secondary containment is not practicable for flowlines and 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. The integrity testing program for piping and valves should also
be developed in accordance with good engineering practice, in order to prevent a discharge as
described in §112.1(b). A flowline maintenance program is required for production facilities under
§112.9(d)(3). (See Chapter 7 of this document for a summary of the recommended key elements of
a flowline maintenance program.) It is especially important that facility owners or operators who
determine that secondary containment is impracticable implement a comprehensive flowline
maintenance program. If an impracticability determination is made for flowlines or gathering lines,
EPA inspectors should extensively and carefully review the adequacy of the flowline maintenance
program. According to practices recommended by industry groups such as API, a comprehensive
piping program should include the following elements:
Prevention measures that avert the discharge of fluids from primary containment;
Detection measures that identify a discharge or potential for a discharge;
Protection measures that minimize the impact of a discharge; and
Remediation measures that mitigate discharge impacts by relying on limited or
expedited cleanup.
In order for a contingency plan to be effective, it is essential for discharges to be detected in
a timely manner. Good engineering practice may require that unmanned facilities where secondary
containment is impracticable be inspected more frequently than would be required at a typical
unmanned facility where secondary containment is provided. For facilities that do not have a
Facility Response Plan (FRP) pursuant to §112.20, if it is not feasible to effectively and reliably
implement a contingency plan, owners/operators must determine how to comply with the applicable
secondary containment requirements in §112.7(c). A contingency plan or FRP is required when a
determination of impracticability is made, pursuant to §112.7(d).
Transfer Areas
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). Areas where
oil is transferred but no loading or unloading rack is present are subject to §112.7(c), and thus
appropriate containment and/or diversionary structures are required. EPA does not require
specifically sized containment for transfer areas; however, containment size must be based on
good engineering practice (§112.3(d)).
The containment requirement at §112.7(c) applies to both loading and unloading areas.
Examples of activities that occur within transfer areas include:
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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 size should be based on the magnitude of a most likely discharge,
taking into consideration the specific features of the facility and operation. 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. EPA recommends that a determination of
adequate secondary containment consider:
The reasonably expected sources and causes of a discharge. This could be a
failed hose connection; failed valve; overfill of a container, tank truck, or railroad tank
car; or breach of a container. Determination would be based on the type of transfer
operation, facility experience and spill history, potential for human error, etc.
The reasonably expected maximum rate of discharge. This will be dependent on
the mode of failure. It may be equal to the maximum rate of transfer or the leakage
rate from a breached container.
The ability to detect and react to the discharge. This will be dependent 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 reasonably expected duration of the discharge. This will be dependent on
the availability of manual or automatic isolation valves, the proximity of qualified
personnel to the operation, and other factors that may limit the volume of a
discharge.
The time it would take a discharge to impact navigable waters or adjoining
shorelines. This could 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.
An example calculation of secondary containment size, based on these considerations, is
provided in Figure 4-7.
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Figure 4-7. Sample calculation of appropriate 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 reasonably expected source and cause of a discharge is a ruptured hose connection.
A shutoff valve is present on the loading line and is accessible to the attendant.
An evaluation determines that the discharge will not impede the attendant's access to the shutoff
valve and that he can safely 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:
The maximum reasonably expected discharge would be calculated to be 150 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 10 seconds.
A number of other factors may also affect the appropriate volume for secondary containment
at loading and unloading areas. These factors include a 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
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.
Secondary containment structures, such as dikes or berms, may not be appropriate in areas
where vehicles continuously need access; however, curbing, drainage systems, active 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. EPA acknowledges that 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 under §112.7(d), and
must clearly explain the reasons why secondary containment is not practicable and comply with the
additional regulatory requirements.
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Oil-Filled Equipment
Secondary containment may be impracticable for oil-filled equipment (e.g., vaulted
transformers, hydraulic units associated with an elevators/lifts, pad-mounted transformers at
customer sites, and oil-filled cable systems) that are not readily accessible or cross properties
belonging to different owners. In these cases, the SPCC Plan must clearly explain the reasons why
secondary containment is not practicable and comply with the additional regulatory requirements
under §112.7(d). For more information on oil-filled operational equipment, refer to Section 2.8.2 of
this guidance document.
4.4.2 Secondary Containment Requirements for Loading/Unloading Racks, §112.7(h)(1)
Section 112.7(h) applies to areas at regulated
facilities where traditional loading/unloading racks for
tank cars and tank trucks are located. Loading and
unloading racks are subject to the specific secondary
containment requirements in §112.7(h)(1).
EPA inspectors should evaluate compliance
with the requirements of §112.7(h) for equipment
traditionally considered to be "loading racks." While
the SPCC rule does not provide a definition for the
term "rack," the type of equipment for which these
requirements would typically apply has the following
characteristics:
§112.7(h)
Facility tank car and tank truck
loading/unloading rack (excluding
offshore facilities).
(1) Where loading/unloading area
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 areas. 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.
The equipment is a permanent structure
for loading or unloading a tank truck or tank car that is located at a regulated facility.
The equipment may be comprised of piping assemblages, valves, loading arms,
pumps, or a similar combination of devices.
The system is necessary to load or unload tank trucks or tank cars.
The system may also include shut-off devices and overfill sensors.
EPA clarified that the provisions of §112.7(h) apply only in instances where a rack structure
is present. (See text box below.)
Loading racks can be located at any type of facility; however, the loading areas associated
with a production tank battery generally do not have the equipment described above, which is often
associated with a "loading rack." Loading/unloading areas utilizing a single hose and connection or
standpipe are not considered "racks."
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Notice Concerning Certain Issues Pertaining to the July 2002 Spill Prevention, Control,
and Countermeasure (SPCC) Rule
"[W]e interpret §112.7(h) only to apply to loading and unloading 'racks.' Under this interpretation,
if a facility does not have a loading or unloading 'rack,' §112.7(h) does not apply. Thus, in stating that
section 112.7(h) applies to 'all facilities, including production facilities,' the Agency only meant that the
provision applies if a 'facility' happens to have a loading or unloading rack present. The Agency did not
mean to imply that any particular category of facilities, such as production facilities, are likely to have
loading or unloading racks present."
The above text is an excerpt from 69 FR 29728 (May 25, 2004).
Where drainage from the areas surrounding a loading/unloading rack does 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)(1)). 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. Section 112.7(h)(1) 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.
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 containment
requirements of §112.7(c). For more information on these requirements, see Section 4.4.1,
Transfer Areas.
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/PMAA_letter.pdf.
Figures 4-8 and 4-9 illustrate how SPCC secondary containment requirements apply at two
facilities with loading/unloading areas and with equipment that may be considered
loading/unloading racks. In Figure 4-8, the facility has two separate and distinct areas for transfer
activities. One is a tank truck unloading area and the other contains 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)(1) apply to the area surrounding the loading rack. It should
be noted that 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).
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Chapter 4: Secondary Containment and Impracticability
In Figure 4-9, the tank truck loading rack and unloading area are co-located. In this
situation, the more stringent provision applies; the area is subject to the sized secondary
containment requirements of §112.7(h)(1).
EPA acknowledges that in certain situations, the sized secondary containment requirements
of §112.7(h)(1) at 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 additional
regulatory requirements.
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SPCC Guidance for Regional Inspectors
Figure 4-8. Facility with separate unloading area and loading rack. The tank truck unloading area is
subject to §112.7(c). The tank truck loading rack is subject to §112.7(h)(1).
PREVENT ION STREET
Slwn drum
' (500 ft to Clearxaler Creek)
y
36" concrete cff'te
$60,000 gallons c&p&city, plus ,
4 incft&s of ff&Gboard) \
ASPHAL T PA VED AREA
^
__ _ (600 ft to Ctearwater Creek) _
NOTES
* Ro/or to Ta&te B-1 of SPCC Pton for votifrm and content of
stofags- tanks and Gontaioors shown a1! this diagram.
• TTie calculation of the design capacities of diked Area 1.
loading reirM awfeittnm&nt henn aiKi r&fu&fer pfirkirtg fif^n is
derated tn Appendix A of SPCC Plan
• Refusers us&d for &m&rgQncy oil fill runs are posttioneti in
the refueterparking area sinc.e they are usuatfy kept ML
* Other refuefers are posilionod in other parts of the facility
since they are urn tally kepi ernpfy i ipon feUtming to the
fadtily
* Facility dramags from ctikBd amas t&rminatQS at the oil/water
ProS&ctod doub!®-wall®t3 AST
2,000 ga/tera. Heating oil \
Main Office Building
Quick drainage syst&rt and foflovsf curb.
Capacity: 2.QQO gaHorts plus 4 incfo&s of
6" asp^atf roJ/ov&r term
{2.000 gallons capacity
plus 4 inches of fa
Maximum 30 xr 55 gallons drums
Lubricating ov,'. engine oil. used cv^.
EKW? on sprf/ pas-fits insKi*? fcyv/riif ig.
D/arf
^-r-
Refiielers Pa
va/vo
*Vj
•iking Area
"* fool
|oo|
Drum
Storage
Neverspill Oil & Products Corporation \
SPCC Plan - Facility Diagram
Rev, 6/14/05 ,
LEGEND
I Fire extinguisher X! Valve
.-', Predicted Direction of Drainage Fence
DIAGRAM IS NOT TO SCALE
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Chapter 4: Secondary Containment and Impracticability
Figure 4-9. Facility with co-located unloading area and loading rack. This containment area is
designed to meet the more stringent §112.7(h)(1) provision.
PREVENTION STREET
ASPHAL T PA VtNG AREA
Ma
n Office Budding
Sp$ Contra!
Equipm&n!
Quick dra/nage system and ratover curb
Capacity 2,000 g&SSons pins 4 inches of
ABC
ABC Oil, Inc. ^\
SPCC Plan - Facility Diagram
Rev. 6/14/05 J
LEGEND
• Fire extinguisher
K- Predicted director of drainage
DIAGRAM IS NOT TO SCALE
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4.4.3 Secondary Containment Requirements for Onshore Bulk Storage Containers,
§112.8(c)(2)
§§112.8(c)(2)and112.12(c)(2)
Construct all bulk storage container
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
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.
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
must comply with the specific secondary containment
requirements of §112.8(c)(2). For bulk storage
containers, secondary containment must hold the entire
capacity of the largest single container and sufficient
freeboard to contain precipitation. (For more
information on sufficient freeboard, see the discussion
in Section 4.2.4 of this chapter.) Secondary containment is required for all facilities with bulk
storage containers, large or small, manned or unmanned, and for facilities with bulk storage
containers that also have oil-filled equipment (specific secondary containment requirements do not
apply to oil-filled equipment).
Section 112.8(c)(2) considers the use of dikes, containment curbs, and pits as secondary
containment methods, or 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. 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.
The owner or operator may determine that secondary containment is impracticable under
§112.7(d), when he/she, 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. 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 additional
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 additional regulatory requirements, see Section 4.5 of this guidance.
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4.4.4 Secondary Containment Requirements for Mobile/Portable Containers, §112.8(c)(11)
Mobile or portable oil storage containers operating
exclusively within the confines of a non-transportation-related
facility with a capacity to store 55 gallons or more of oil are
regulated under the SPCC rule and must comply with the
secondary containment requirements of §112.8(c)(11) (or
§112.12(c)(11) in the case of a facility that stores or handles
animal fats or vegetable oils).
sufficient freeboard to contain
precipitation.
The 1971 Memorandum of Understanding between
§§112.8(c)(11)and 112.12
Position or locate mobile or portable
oil storage containers to prevent a
discharge as described in §112.1(b).
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
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 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. Other examples of mobile portable containers include, but are
not limited to, 55 gallon drums, skid tanks, totes, and intermodal bulk containers.
Vehicles used to store oil, operating as on-site fueling vehicles at locations such as
construction sites, military, or civilian remote operations support sites, or rail sidings are generally
considered non-transportation-related. Indicators describing 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 no longer mobile (i.e., hard-piped or permanently parked);
The vehicle is fueled on-site and never moves off-site; and
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.
According to §§112.8(c)(11) and 112.12(c)(11), mobile or portable containers must be
positioned or located to prevent a discharge to navigable waters as described in §112.1(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 in the examples below.
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When mobile containers are in a stationary, unattended mode and not under the direct
oversight or control of facility personnel, the requirements of §§112.8(c)(11) and 112.12(c)(11) 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 equipment must be identified on the facility diagram provided within the
SPCC Plan (§112.7(a)(3)).
When mobile containers are involved in activities such as normal fuel transfer, on-site
movement, or preparation for such activities in "stand-by" mode, the requirements of §112.8(c)(11)
do not apply because the container is not "positioned" and therefore the less stringent requirements
of §112.7(c) apply. This requirement may be satisfied through the use of drainage systems that
could ultimately control spilled oil. Alternatively, other measures listed in the general secondary
containment provision under §112.7(c) may be used, including active measures such as sorbents,
booms, or response actions that prevent an oil discharge from reaching navigable waters and
adjoining shorelines. In these cases, a member of the facility personnel should (as determined by
good engineering practice) be in physical control and attending to the mobile or portable storage
container. When the mobile refueler is not engaged in one of the activities listed above, it must be
positioned to prevent a discharge and provided with secondary containment large enough for the
single compartment or container with sufficient freeboard for precipitation (§112.8(c)(11)).
Mobile containers, such as drums, skids, and totes, must also comply with the requirements
of §112.8(c)(11) or§112.12(c)(11) according to good engineering practice. For these types of
containers, the EPA inspector should verify that the secondary containment methods are
appropriate. For example, an oil-filled drum positioned for use at a construction site must be
equipped with secondary containment sized in accordance with §112.8(c)(11). The facility owner or
operator may determine that it is impracticable to provide sized secondary containment in
accordance with §112.8(c)(11), when the container is in stationary or unattended mode, or the
general containment of §112.7(c), pursuant to §112.7(d). The SPCC Plan must properly explain
why secondary containment is impracticable, and document the implementation of the additional
regulatory requirements of §112.7(d).
4.4.5 Secondary Containment Requirements for Bulk
Storage Containers at Production Facilities,
§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 production facility. This
specific secondary containment requirement does not apply
to the entire lease area, but only to tanks, vessels, and
§112.9(c)(2)
Provide all tank battery, separation,
and treating facility installations with 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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containers in the tank battery, separation, and treatment areas.
Section 112.9(c)(2) is a specific secondary containment requirement; the containment
structure or measure must be able to contain the entire capacity of the largest single container and
sufficient freeboard to contain precipitation. (Refer to Section 4.2.4 of this chapter for more
information on calculating sufficient freeboard.) 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. Secondary
containment should be sufficiently impervious to contain oil; refer to Section 4.2.8 of this chapter for
more information. 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. According to the 2002 rule preamble, "the [secondary containment]
requirement applies to oil leases of any size. Secondary containment 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).
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 clearly
explain why secondary containment is not practicable, and document how the additional regulatory
requirements of §112.7(d) are implemented. Owners or operators of unmanned facilities may need
to determine how to effectively implement a contingency plan. This may involve additional site
inspections, or some other method as determined appropriate by a Professional Engineer.
isf Tip
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 §112.1(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)
4.4.6 Secondary Containment Requirements for Onshore Drilling or Workover Equipment,
§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 of fuel, crude oil, or oily drilling
fluids. This provision contains no specific sizing requirement, and
no freeboard requirement; it is essentially very similar to the
general containment requirement of §112.7(c). 112 for the fun text of the rule.
§112.10(c)
Provide catchment basins or
crude oil, or oily drilling fluids.
Note: The above text is an excerpt of
the SPCC rule. See 40 CFR part
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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 clearly
explain why secondary containment is not practicable, and document how the additional regulatory
requirements of §112.7(d) are implemented.
4.5 Measures Required in Place of Secondary Containment
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. This section describes these additional requirements.
4.5.1 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 should be done in accordance
with good engineering practice, considering applicable industry standards. For a thorough
discussion of integrity testing, see Chapter 7 of this document. 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, however, good
engineering practice should indicate a more stringent integrity testing schedule than would be
required for a container if secondary containment were in place. Although the 2002 revised 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.3
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
inspector should also review testing records to ensure that the inspection program is implemented
as described.
4.5.2 Periodic Integrity and Leak Testing of the Valves and Piping
When the facility owner or operator determines that secondary containment for bulk storage
containers is impracticable, he/she must also perform periodic integrity and leak testing of valves
and piping associated with the containers for which secondary containment is impracticable
(§112.7(d)). 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
3 The Steel Tank Institute's "Standard for the Inspection of Aboveground Storage Tanks," SP001, 3rd
Edition, Steel Tank Institute, July 2005 (summarized in Chapter 7 of this document) requires more frequent
inspections of tanks that do not have adequate secondary containment.
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standards. Chapter 7 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 PE certifies that the extent of this
testing is in accordance with good engineering practice, including consideration of applicable
industry standards (§112.3(d)).
The EPA inspector should verify that the Plan describes the integrity and leak testing of
valves and piping associated with containers for which secondary containment is impracticable.
The inspector should also review testing records to ensure that the testing program is implemented
as described.
4.5.3 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 claims 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.
Specific and well-defined procedures to facilitate recovery of damages and
enforcement measures as provided for by state and local statutes and ordinances.
Please refer to the model contingency plan found in Appendix F of this document for an
example contingency plan prepared in compliance with the SPCC rule and 40 CFR part 109.
As described in 67 FR 47105, 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:
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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;
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 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)
For a contingency plan to satisfy the requirements of §112.7(d), facilities must be able to
implement the contingency plan. Activation of the contingency plan is contingent upon the
discharge of oil being detected. As part of evaluating the adequacy of the contingency plan
developed to satisfy requirements of §112.7(d), the EPA inspector should consider the time it takes
facility personnel to detect and mitigate a discharge to navigable waters and adjoining shorelines.
For example, at an unmanned facility, 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.
4.5.4 Role of the EPA Inspector in Reviewing Impracticability Determinations
Like other technical aspects of the SPCC Plan, determinations of impracticability must be
reviewed by the PE certifying the Plan in accordance with §112.3(d) to ensure that they are
consistent with good engineering practice. The inspector should verify that the Plan has been
certified by the PE and that the additional measures specified in §112.7(d) are documented in the
Plan, as explained below.
By certifying a Plan, 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. Thus, if impracticability determinations and the corresponding alternative measures and
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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 do not meet the standards of
common sense, 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.
An owner/operator making a determination of impracticability should have considered all
appropriate options for secondary containment, and the documentation presented in support of the
impracticability determination should include a discussion of the reasons why the various
reasonable options are impracticable.
The example below provides an example of an inadequate impracticability determination.
The supporting discussion provided in the example does not provide a sufficient discussion of the
reasons why the 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 additional measures required in the SPCC Plan when a determination of impracticability
is made.
Bad Example: 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 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.
Good Example: Bulk Storage Containers
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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 (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.
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).
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 are procedures for early detection of oil discharges; and
There is a defined set of response actions.
Figure 4-10 provides a checklist 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 4-11 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 4-10. 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*
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.
(1 0) A preplanned location for an oil discharge response operations center and a reliable communications
system for directing the coordinated overall response operations.
(1 1 ) Provisions for varying degrees of response effort depending on the severity of the oil discharge.
(1 2) 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
No
* The contingency plan should be consistent with all applicable state and local plans, Area Contingency Plans, and
National Contingency Plan (NCP).
the
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Figure 4-11. Checklist of SPCC requirements eligible for impracticability determinations.
Rule Element
Relevant
Section(s)
Evaluation
Verification
Nonconformance
ALL FACILITIES
General
Containment
Loading/unloading
Racks
112.7(c)
112.7(h)(1)
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?
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.
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 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 FACILITIES, EXCEPT OIL PRODUCTION
Bulk Storage
Containers
112.8(c)(2)
OR
112.12(c)(2)
112.8(c)(11)
OR
112.12(c)(11)
Is the secondary containment system sized to contain
the entire capacity of the largest single container and
sufficient freeboard to contain precipitation?
Are dikes sufficiently impervious to contain oil?
Are mobile or portable oil containers 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.
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 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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Rule Element
Relevant
Section(s)
Evaluation
Verification
Nonconformance
ONSHORE OIL PRODUCTION FACILITIES
Drainage
Bulk Storage
Containers
112.9(c)(2)
1 1 2.9(c)(2)
Is drainage from undiked areas safely confined in a
catchment basin or holding pond?
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.
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 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 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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Chapter 5: Oil/Water Separators
OIL/WATER SEPARATORS
5.1 Introduction
The wastewater treatment exemption in §112.1(d)(6) excludes from SPCC requirements
facilities or parts of facilities that are used exclusively for wastewater treatment, as long as they are
not used to meet other requirements of 40 CFR part 112. This chapter clarifies the applicability of
this exemption to oil/water separators (including equipment, vessels, and containers that are not
specifically called "oil/water separators" but
perform oil/water separation, such as water
clarifiers at wastewater treatment plants).
The intended use of an oil/water
separator determines whether the separator is
subject to the SPCC regulations and, if so, what
provisions are applicable. As outlined in Table
5-1 below, oil/water separators may be used for
several different purposes: to treat wastewater,
to meet secondary containment requirements of
40 CFR part 112, or as part of the oil production
process. Only oil/water separators used exclusively to treat wastewater and not used to satisfy any
requirement of part 112 are exempt from all SPCC requirements. Oil/water separators used in oil
production and to meet the secondary containment requirements of the rule are not exempt.
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 the full text of 40 CFR part 112.
Table 5-1. SPCC rule applicability for various uses of oil/water separators.
Wastewater Treatment
Secondary Containment
Oil Production
Separators are exempt from all
SPCC requirements in
accordance with §112.1(d)(6) and
do not count toward facility
storage capacity.
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.
Separators that are bulk storage
containers, subject to the
provisions of §§112.9(c) or
112.11 (b) and (d), are not exempt
and count toward the facility
storage capacity.
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The remainder of this chapter is organized as follows:
Section 5.2 summarizes the provisions of the SPCC rule that apply to the three uses
of oil/water separators identified above.
Section 5.3 discusses the use of an oil/water separator for wastewater treatment
and the exemption for this use.
Section 5.4 addresses the use of an oil/water separator as secondary containment
and the applicable SPCC requirements.
Section 5.5 discusses the use of an oil/water separator in oil production and the
applicable SPCC requirements.
Section 5.6 describes required documentation for oil/water separators and the role
of the EPA inspector in reviewing facilities with oil/water separators.
5.2 Overview of Provisions Applicable to Oil/Water Separators
Section 112.1(d)(6) addresses oil/water separators 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 oil/water
separators 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.
Drainage systems that satisfy the secondary containment requirements of the SPCC rule
may use oil/water separators to recover oil and return it to the facility (see Chapter 4 of this
document for a description of secondary containment requirements). Examples of oil/water
separators that are used to meet SPCC requirements include oil/water separators used to satisfy
the secondary containment requirements of §§112.7(c), 112.7(h)(1), 112.8(c)(2), 112.8(c)(11),
112.12(c)(2), and/or 112.12(c)(11). Additionally, the drainage provisions in §§112.8(b) and 112.9(b)
set forth design specifications for secondary containment at a facility. Oil/water separators may be
used as part of a facility drainage system to meet the secondary containment requirements of the
rule. Oil/water separators used to satisfy these rule requirements are subject to applicable
secondary containment requirements, but they do not count toward storage capacity.
As stated in §112.1(d)(6), 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), this means recovery
and recycling of crude oil at facilities associated
with, and downstream of, production facilities,
such as saltwater disposal and injection
§112.9(c)(2)
Provide all tank battery, separation, and
treating facility installations with 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.
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Chapter 5: Oil/Water Separators
facilities. Section 112.9(c)(2) includes
requirements for oil/water separators (e.g., gun
barrels, heater-treaters) used at onshore oil
production facilities. This provision specifically
identifies the secondary containment and
drainage requirements for all tank battery,
separation, and treating facility installations,
including oil/water separators. Examples of
oil/water separators associated with oil
production, separation, and treatment include
free water knock-outs, two- and three-phase
separators, and gun barrels.
Sections 112.11(b) and (d) include the
applicable provisions for oil/water separators
located at offshore oil production facilities.
Figure 5-1 helps determine the use of an
oil/water separator at SPCC-regulated facilities
and identifies the corresponding rule
requirements or exemptions based upon each
use.
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 §112.1(b). Where drains and
sumps are not practicable, you must remove
oil contained in collection equipment as often
as necessary to prevent overflow.
Note: The above text is an excerpt of the SPCC rule.
Refer to the full text of 40 CFR part 112.
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.
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Figure 5-1. Applicable requirements for an oil/water separator.
The OWS is used
exclusively tor
wastewater treatment
The OWS is used to
requirements of
t»SF*CCnule
Is the OWS used to meet tie requirements for general secondary
coniainffwnt, saeofwJary oomtainm*Bt, oriaellty drainage?
Separators are exempt
from ail SPCC
requirements in
accordance witti
General Secondary
Containmont
I
OWS used to meet tie
general containment
requirements of §112.7(c)
Separators are not subject
to the rule**
Separators are not bulk
storage containers"
Separators do riot count
toward the overall storaqe
capacity at the facility
Separators do not count
toward the overall storage
capacity at the facility
Sized Socondary
Containment
Facility Drainage
OWS used to meet the
specific containment
requirements of
§H2,7(h)(1) for loading
and unloading racks
OR
OWS used to meet the
specific eantammBrt
requirements of
§§1128(0X2),
112.8(cK11). 112:i2(cX2).
and 112.12(c)(11)forbulh
storage containers
OWS used to meet the
general facility drainage
requirements of
|§112'.8(b)or112.9(b)
Separators are not bulk
storage containers**
Separators must be sized
to contain Ehe maximum
capacity of any single
compartment of a tank
truck/car loaded or
unloaded at the rack OR
the largest single bulk
container and sufficient
freeboard
Separators do not count
toward the overall storage
capacity at the facility
Separators are not bulk
storage containers**
Separators do not count
toward tie overall storage
capacity at the facility*
The OWS Is used in the
production, recycling, of
recovery of oil
IB tie OWS ysed at an onshore or
offshore facility?
Onshore
Offshore
Separators are talk
storage containers and
are subject to the
provisions of §112,9(c)
Separators may be subject
to the provisions of
§112.11(b)or§112.11(d)
Separators count toward
the overall storage
capacity at the facility
Separators count toward
She overall storage
capacity at the facility
Secondary containment
must be deslgn&d to
contain the capacity of the
largest single container
and sufficient freeboard to
contain precipitation
"Arty oil storage that is used to hold the 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 Oil/Water Separators Used in Wastewater Treatment
5.3.1 Description of Oil/Water Separator Use in Wastewater Treatment
Oil/water separators used to pre-treat wastewater are usually of two kinds: standard gravity
separators or enhanced gravity separators.1 Standard gravity separators, as illustrated in Figure 5-
2 (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 5-2. Standard gravity oil/water separator.
Wastewater
Separated Oil
Treated Water
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 5-3 shows coalescing plates in the middle compartment (separator designs may
vary).
forces.
1 Other types of separators include vortex separators, which combine gravity with centrifugal
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Figure 5-3. Enhanced gravity oil/water separator.
Wastewater
Separated Oil
Treated Water
Oil/water separators are flow-through equipment in which wastewater enters the separator
and treated water exits the separator on a continual basis. To be effective, the oil/water separator
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 oil/water
separator 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 oil/water separator manufacturers typically outline
these and other design factors to consider, along with operation and maintenance requirements, to
ensure that the oil/water separator is correctly constructed and operated for its intended use.
5.3.2 Applicability of the SPCC Rule to Oil/Water Separators 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). Certain components of wastewater treatment
facilities, such as treatment systems at publicly owned treatment works (POTWs) and industrial
wastewater treatment facilities treating oily wastewater, likely meet the two criteria for this
exemption.
POTWs and other wastewater treatment facilities may have bulk storage containers and oil-
filled equipment, as well as exempt oil/water separators. The capacity of the bulk storage
containers and oil-filled equipment is counted to determine whether the facility is subject to the
requirements of the SPCC rule. Only the oil/water separator capacity does not count toward the
overall storage capacity of the facility. Thus, the presence of an oil/water separator at an otherwise
regulated facility does not exempt the entire facility from the SPCC rule requirements. At
wastewater treatment facilities, storage capacity to be counted includes 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. Any separate container used to store oil recovered by the
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separation process or any other equipment or containers at a regulated facility that do not qualify for
the wastewater treatment exemption are required to meet all applicable SPCC requirements (67 FR
47069).
Oil/water separators used exclusively for wastewater treatment are flow-through separators
and are not engaged in a static process in an isolated container. For example, a bulk storage
container containing an oil and water mixture, and from which water is drawn from the bottom, does
not constitute wastewater treatment.
Examples of oil/water separators that may be considered wastewater treatment and may be
eligible for the exemption of §112.1 (d)(6) include:
Oil/water separators at a wastewater treatment facility;
Oil/water separators at an active groundwater remediation site;
Grease traps that intercept and congeal oil and grease from liquid waste; and
Oil/water separators in landfill leachate collection systems.
Oil/water separators exempted from the SPCC rule may, however, be subject to other
federal, state, and local regulations. In addition, a separate container storing oil removed from an
exempt separator is considered a bulk storage container and is subject to the SPCC rule
requirements.
Many of these exempted wastewater treatment oil/water separators 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, operation/maintenance manuals and procedures, and requires a Storm Water
Pollution Prevention Plan, which may include a Best Management Practice (BMP) Plan.
BMPs are additional conditions that may supplement effluent limitations in NPDES permits.
In addition, other affected facilities need a BMP Plan for storm water runoff control under an
NPDES permit. Under §402(a)(1) of CWA, BMPs may be imposed when the Administrator
determines that such conditions are necessary to carry out the provisions of the Act.2
Additionally, some facilities may be subject to pretreatment standards promulgated under
§307(b) of CWA. Pretreatment standards apply to "indirect discharges" that go first to a POTW via
a collection system before being discharged to navigable waters, and they concern pollutants that
pass through POTWs untreated or interfere with the operation of POTWs. 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
2 See discussion of authority for NPDES and BMP provisions in the preamble to the 2002 revised
SPCC rule, 67 FR 47068.
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implementation of categorical pretreatment standards. Specifically, 40 CFR 403.5(b)(6) prohibits
the introduction into a POTWof "petroleum, oil, nonbiodegradable cutting oil, or products of mineral
oil origin in amounts that will cause interference or pass through."
5.3.3 Wastewater Treatment Exemption Clarification for Dry Gas Production Facilities
As EPA stated in a Federal Register notice (69 FR 29728), produced water tanks at dry gas
facilities are eligible for the wastewater treatment exemption. Gas facilities that do not produce
condensate or crude oil (i.e., dry gas facilities) do not meet the description of "oil production, oil
recovery, or oil recycling facilities." Therefore, produced water tanks used exclusively for
wastewater treatment at such facilities are eligible for the exemption. Tanks that are eligible for the
exemption do not count toward storage capacity.
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 Oil/Water Separators Used to Meet SPCC Secondary Containment
Requirements
5.4.1 Description of Oil/Water Separators Used to Meet SPCC Secondary Containment
Requirements
Oil/water separators can be used to meet the SPCC requirements for secondary
containment in §§112.7(c), 112.7(h)(1), 112.8(c)(2), 112.8(c)(11), 112.12(c)(2), and/or
112.12(c)(11). Additionally, §§112.8(b), 112.9(b), and 112.12(b) set forth design specifications for
drainage associated with secondary containment provisions at the facility. Properly designed,
maintained, and operated oil/water separators may be used as part of a facility drainage system to
meet the secondary containment requirements of the rule.
Standard gravity and enhanced gravity separators (Figures 5-2 and 5-3), or other types of
oil/water separators (separator designs may vary), 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. Generally, these separators should be monitored on a routine schedule and collected oil
should be removed as appropriate in accordance with procedures in the SPCC Plan.
When designing oil/water separators to be used as secondary containment (see Chapter 4
for a discussion of secondary containment requirements), good engineering practice would normally
indicate that a Professional Engineer (PE) would consider:
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Chapter 5: Oil/Water Separators
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 oil/water separator for oil and for wastewater.
Many oil/water separators used for secondary containment are installed in areas where they
may receive considerable flow from precipitation. If the flow rate exceeds the maximum design rate
of the separator, the separator may discharge accumulated oil and/or untreated wastewater;
therefore, it may be an inappropriate choice for secondary containment and may result in a
discharge to navigable waters and adjoining shorelines. The specifications from the oil/water
separator manufacturer outline these and other design factors as important items to consider when
specifying the use of a given oil/water separator for a given application. Additionally, the
manufacturer specifies the maintenance requirements for these separators that would ensure
proper operation of these devices.
When oil/water separators are used to meet SPCC requirements they must be properly
operated and maintained to ensure that the unit 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)). The required oil/water separator capacity should always be available (i.e., oil should
not continually accumulate in the separator over a period of time such that the required storage
capacity would not be available if an oil release were to occur within the drainage area). The use of
oil/water separators as a method of containment may be risky as they have limited drainage
controls to prevent a discharge of oil and rely heavily on proper maintenance.
5.4.2 Applicability of the SPCC Rule to Oil/Water Separators 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 §112.1(b)." An oil/water separator may be used
to satisfy this requirement for onshore or offshore facilities. This separator 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
an oil/water separator complies with secondary containment provisions, and how it is operated and
maintained, should be included in the SPCC Plan. BMPs or O&M manuals which detail operation
and maintenance procedures for oil/water separators used specifically for secondary containment
may be referenced in the SPCC Plan and maintained separately.
Section 112.7(h)(1) requires "a quick drainage system" for areas where a tank car or tank
truck loading or unloading rack is present. An oil/water separator 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)(1)).
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
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measures can be used to satisfy these requirements (see Chapter 3 for a discussion of the
environmental equivalence provision). In order to comply with secondary containment
requirements, facilities might use ponds, lagoons, or catchment basins as part of the design criteria
for facility drainage systems. However, an oil/water separator might serve as an environmentally
equivalent measure to the ponds, lagoons, or catchment basins required by §§112.8(b)(3) and
112.12(b)(3). In this instance, EPA recommends that the oil/water separator be designed to handle
the flow rate and volume of oil and water expected to be generated by facility operations. When
certifying a facility's SPCC Plan, the PE must verify that the oil/water separator is adequately
designed, maintained, and operated to provide environmentally equivalent protection (in
accordance with §112.7(a)(2)) under the potential discharge scenarios it is aimed to address, in
order to comply with the corresponding secondary containment provision.
Sections 112.8(c)(2), 112.8(c)(11), 112.12(c)(2), and 112.12(c)(11) 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." An oil/water separator may be
used for this purpose, but it must be appropriately sized to meet the requirements of the rule
provision for which it is intended to comply. The oil/water separator must be capable of handling
both the oil and precipitation that come into the separator from the general drainage area, and from
any accidental discharge from the largest bulk storage container located within the drainage area
for which the separator provides secondary containment (§112.8(c)(2), 112.8(c)(11), 112.12(c)(2),
and 112.12(c)(11)). Good engineering practice would suggest that the use of oil/water separators
for the specific secondary containment provisions be on a very limited basis and typically with
smaller capacity container storage areas (e.g., drum storage area). For more information on
specific secondary containment requirements for bulk storage containers, see Chapter 4 of this
document.
The capacity of an oil/water separator used to meet secondary containment requirements
does not count toward a facility's overall storage capacity. Any volume of oil that would flow into the
oil/water separator would come from another source within the drainage area that is already
generally counted in the facility storage capacity determination. Containers used to store recovered
oil after oil/water separation, however, represent additional oil storage and count toward a facility's
total storage capacity. These include slop tanks or other containers used to store waste oil.
The SPCC rule does not require redundant secondary containment around oil/water
separators used for secondary containment (i.e., tertiary containment is not required).
5.5 Oil/Water Separators Used in Oil Production
5.5.1 Description of Oil/Water Separators Used in Oil Production
Oil production oil/water separators are used at both onshore and offshore facilities.
Separators and other separation equipment, such as heater-treaters and gun barrels, are used
during oil production to separate the well stream into individual well fluids after they are extracted
from the production well. Different processes and equipment may be used to separate the mixture
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into oil/emulsion, water, and gas fractions. All such equipment is considered a bulk storage
container needing specific secondary containment. For purposes of this guidance, this chapter
focuses on those pieces of equipment that separate water from oil and the equipment through
which these fluids flow.
There is quite a variety of production equipment used to separate and treat produced fluids.
Some are operated under low pressure conditions, while others are operated at high pressure. A
process called "free-water knockout," illustrated in Figure 5-4, is generally used to separate large
volumes of water from oil and gas generated from the well. Gun barrels, also called wash tanks,
are generally found in older or marginal fields and are used to provide quiet retention time for the
water to settle out of the produced well fluids (see Figure 5-5). A two-phase separator separates
the well fluids into a liquid (oil, emulsion,3 or water) and a gas. The liquid exits the bottom of the
separator and the gas exits the top, as shown in Figure 5-6. 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 5-7). 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. The designs of oil/water separators may differ from the examples provided.
Figure 5-4. Low pressure free-water knockout.
Gas
Outlet
Deflector
\
Well Fluids_
Inlet
h77 ^
Gas
rp • Wave, r? •
U Baffles U
Oil
un
Outlet
U
TJ
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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Figure 5-5. Gun barrel oil/water
separator.
—ftl Water
—1|]^ Outlet
Figure 5-6. Two-phase oil/water
separator.
Oil/Emulsion
Outlet
Spreader
Well
Fluids
Inlet
Water
Outlet
Figure 5-7. Three-phase oil/water
separator.
Well Fluids_
Inlet
Oil/Emulsion
Outlet
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In separators used for oil production, 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;
Oil is discharged out at a higher level to a 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 Oil/Water Separators Used in Oil Production
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 focus of the separation
process in oil production is on removing water from oil, as opposed to removing oil from water.
Additionally, as stated in the preamble to the 2002 revised SPCC rule, production facilities
generally lack NPDES or state-equivalent permits or prevention requirements, and thus lack the
protections that such permits provide. Furthermore, Underground Injection Control (UIC) permits
do not have prevention requirements for production facilities. Production facilities are normally
unmanned 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). In some areas of the United States, produced water is fresh and may be
discharged under a NPDES permit for beneficial use (e.g., irrigation, water for livestock).
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. Neither an oil production facility nor an oil
recovery or recycling facility treats water; instead, it treats oil. For purposes of the wastewater
treatment exemption, produced water is not considered wastewater, and treatment of produced
water is not considered wastewater treatment. Therefore, a facility that stores, treats, or otherwise
uses produced water remains subject to the rule. At oil drilling, oil production, oil recycling, or oil
recovery facilities, treatment units subject to the rule include open oil pits or ponds associated with
oil production operations, oil/water separators (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 47068,9). Although the ratio of water to oil can be relatively high, the quantity of
oil involved can be still be substantial and pose a threat of a discharge to navigable waters and
adjoining shorelines.
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Oil/water separators used in the production of oil (e.g., heater-treaters and gun barrels) and
other separation and treatment facility installations, are subject to the specific secondary
containment requirements for oil production facility bulk storage containers in §112.9(c)(2).
Therefore, oil/water separators used in oil production are considered bulk storage containers and
are subject to the applicable SPCC requirements under §112.9(c):
Oil/water separators used in onshore oil production are subject to the provisions of
§112.9(c). For example, oil/water separators used in onshore oil production must
have secondary containment designed to contain the capacity of the largest single
container and sufficient freeboard to contain precipitation (§112.9(c)(2)). If specific
secondary containment is determined to be impracticable for the equipment, the
SPCC Plan must document the reason for impracticability and comply with the
additional regulatory requirements in §112.7(d).
Oil/water separators used in offshore oil production are 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.
Oil/water separators 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 §112.1(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)
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Chapter 5: Oil/Water Separators
5.6 Documentation Requirements and the Role of the EPA Inspector
5.6.1 Documentation by Owner/Operator
Oil/water separators used exclusively for wastewater treatment are exempt from all SPCC
requirements, and no documentation is required for this equipment in the SPCC Plan.
For oil/water separators 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 valves 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 oil/water separator and corresponding anticipated
flow rate of the drainage system to the separator;
Appropriate capacity of the oil/water separator for oil and for wastewater;
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 oil/water
separators.
A separate bulk storage container used to store oil following separation in any oil/water
separator (i.e., wastewater treatment, secondary containment, or oil production) is subject to all
applicable requirements of 40 CFR part 112, including §§112.8(c) or 112.9(c), as appropriate.
For oil/water separators used in oil production, the oil/water separators are considered bulk
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 of this document. The
facility owner/operator may determine that the sized secondary containment required for these
oil/water separators is impracticable, pursuant to §112.7(d). If impracticability is determined for
sized secondary containment, the SPCC Plan must clearly explain why secondary containment is
not practicable and provide an oil spill contingency plan following the provisions of 40 CFR part 109.
In addition, such facilities must conduct integrity and leak testing of bulk containers and associated
valves and piping, and provide a written commitment of manpower, equipment, and materials to
respond to oil discharges (§112.7(d)). For more information on impracticability, refer to Chapter 4
of this document.
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5.6.2 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 oil/water separators at a facility and ensure that they are consistent with
good engineering practice.
The EPA inspector will verify that any oil/water separators 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 the intended and actual use of the separator. 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 the
proper application of the wastewater exemption. The EPA inspector may also consider the flow-
through capacity of the separator, the emulsion of oil present within the separator, and the design
specifications of the unit in evaluating the use of the oil/water separator.
For oil/water separators used to meet SPCC secondary containment requirements, the EPA
inspector will verify that the Plan includes, for each oil/water separator used as secondary
containment, 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(a)(3)(iii). Inspectors should note the risk
associated with this form of containment and should evaluate the design, maintenance, operation,
and efficacy of oil/water separator systems used for containment very carefully. Generally, these
separators should be monitored on a routine schedule, and collected oil should be removed as
appropriate and in accordance with the drainage procedures in the Plan.
Oil/water separators used in the production of oil (e.g., heater-treaters and gun barrels) and
other separation and treatment facility installations, are subject to the specific secondary
containment requirements for oil production facility bulk storage containers in §112.9(c)(2). The
SPCC Plan must address this equipment and include the storage capacity of the equipment in the
storage capacity calculations (§112.1(b) and (d)(2) and the definition of storage capacity in §112.2.)
If sized secondary containment is determined to be impracticable for the equipment, the SPCC Plan
must document the reason for impracticability and comply with the additional regulatory
requirements in §112.7(d).
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 the wastewater treatment exemption is certified by the PE or if
other oil/water separator uses are properly documented, they most likely will be considered
acceptable by EPA inspectors. However, if the documented uses of the oil/water separators do not
meet the standards of common sense, appear to be incorrect, deviate from the use described in the
Plan, are not maintained or operated in accordance with the Plan, or simply do not operate
correctly, further follow-up action may be warranted. This may include a request for more
information or a Plan amendment in accordance with §112.4(d).
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Chapter 6: Facility Diagrams
FACILITY DIAGRAMS
6.1 Introduction
Section 112.7(a)(3) of the SPCC rule requires that facility owners and operators include in
the SPCC Plan a diagram of the facility that identifies the location and contents of oil containers,
connecting piping, and transfer stations. The diagram helps to ensure safe and efficient response
actions, effective spill prevention and emergency planning, ease of Plan review by an EPA
inspector, and proper implementation of the Plan by facility personnel. This chapter explains the
requirement for a facility diagram, provides guidelines on the necessary level of detail, and includes
several facility diagrams as examples.
6.1.1 Purpose
The facility diagram is an important component of an SPCC Plan because the diagram is
used for prevention, planning, inspection, management, and response considerations. EPA and
facility inspectors, responders, and facility personnel need to be aware of the location of all
containers, piping, and transfer areas subject to the SPCC rule. The facility diagram may also
assist response efforts by helping responders determine the flow pathway of discharged oil and
take more effective measures to control the flow of oil. This may avert damage to sensitive
environmental areas; may protect drinking water sources; and may help prevent discharges to other
conduits, to a treatment facility, or to navigable waters or adjoining shorelines. The diagram may
also serve to address the rule requirements by describing, pictorially, the capacity and type of oil in
each container, the associated discharge/drainage controls, and the flow path of a discharge
(§112.7(a)(3)(i) and (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.
Diagrams may also help federal, state, or facility personnel avoid certain hazards and identify the
location of facility response equipment. Finally, by
informing responders of the location and content
of containers, a facility diagram helps to ensure
their safety in conducting response actions and to ?e^ribe in your Plan the physical layout of the
3 » i- facility and include a facility diagram, which
protect property.
6.1.2 Requirements fora Facility Diagram
A description of the physical layout of a
§112.7(a)(3)
must mark the location and contents of each
container. The facility diagram must include
completely buried 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
Note: The above text is an excerpt of the SPCC rule.
Refer to 40 CFR part 112 for the full text of the rule.
facility, including a facility diagram, is one of the connecting pipes....
general requirements for an SPCC Plan. The
2002 revisions to the SPCC rule added a new
specific requirement in §112.7(a)(3) for a facility
diagram to be included in the Plan. Section
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112.7(a)(3) requires that the facility diagram include the location and contents of each container,
completely buried tanks (even if exempted from the SPCC requirements), transfer areas (i.e.,
stations), and connecting pipes. In addition to the requirement for a facility description and
diagram, §112.7(a)(3) lists additional items to be addressed in an SPCC Plan, including the type of
oil in each container and its capacity; discharge prevention measures; discharge or drainage
controls; countermeasures for discharge discovery, response, and cleanup; methods of disposal of
recovered materials; and specific contact information. Please see §112.7(a)(3) for these
requirements in their entirety.
6.2 Preparing a Facility Diagram
Facility diagrams provided as part of an SPCC Plan often illustrate the following information:
Required by §112.7(a)(3):1
Aboveground and underground storage tanks (including content and capacity);
Mobile portable containers (including content and capacity);
Hydraulic operating systems or manufacturing equipment;
Oil-filled electrical transformers, circuit breakers, or other equipment (including
content and capacity);
Any other oil-filled equipment (including content and capacity);
Oil pits or ponds (at production facilities);
Oil/water separators (e.g., at tank batteries, separation, and treating facility
installations associated with production facilities);
Fill ports and connecting piping (scale of drawing permitting);
Oil transfer areas; and
Loading racks/unloading areas.
Recommended:
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 and firefighting equipment;
Location of valves or drainage system control that could be used in the event of a
discharge to contain oil on the site;
Compass direction; and
1 Containers that have a capacity of less than 55 gallons, are permanently closed, or are otherwise exempt
from the rule (with the exception of exempted underground storage tanks) are not required to be listed on the facility
diagram.
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Chapter 6: Facility Diagrams
Topographical information and area maps.
In addition, 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).
While recognizing that SPCC Plans and their associated diagrams are facility-specific and
prepared with a certain amount of PE discretion, the following information 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 alternate facility diagrams for meeting
the requirements of §112.7(a)(3).
6.2.1 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 and reviewed by the PE as part of Plan certification.
Thus, the level of detail provided and the approach taken for preparing an adequate facility diagram
is primarily at the discretion of the certifying PE.
6.2.2. Facility Description
Section 112.7(a)(3) requires that the Plan include a description of the physical layout of the
facility. In addition to marking the location and contents of each oil storage container at the facility,
this description may include information on the facility location, type, size, and proximity to
navigable waters, as well as other relevant information. This general facility description is often
supplemented with a more specific description of containers subject to the SPCC rule to
complement what is required on the facility diagram (e.g., storage capacity and content).
6.2.3 Oil Containers
The facility diagram must include all containers (including oil-filled equipment) that store 55
gallons or more of oil and must include information indicating the contents of these containers
(§112.7(a)(3)). The 2002 revisions to the SPCC rule established a minimum container size of 55
gallons. Pursuant to §112.1(d)(5), the rule does not apply to containers of less than 55 gallons, and
therefore they do not need to be included on the facility diagram.
In situations where diagrams become complicated due to the presence of multiple oil
storage containers or complex piping/transfer areas at the facility, it may be difficult to indicate the
contents and capacity of the containers on the diagram itself. In order to simplify the diagram, the
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PE may choose to include that information on a separate log or sheet maintained in the Plan,
similar to the description outlined below for mobile/portable containers.
6.2.4 Mobile or Portable Containers
The owner/operator must state the contents and location of each container on the diagram
of the facility (§112.7(a)(3)). For portable containers (e.g., drums and totes), the facility
owner/operator may note the general contents of each container and provide more detailed content
information on a separate sheet or log, as well as other information, such as container capacity, that
the PE determines to be appropriate to adequately describe the facility. If the contents of a
container change frequently, the contents may be recorded on a separate sheet or log, or on the
diagram (67 FR 47097). In this case, the diagram should note that contents vary. Additionally, the
PE may choose to identify an area on the facility diagram (e.g., a drum storage area) and include a
separate log that can be updated by facility personnel. The PE should develop a reasonable
estimate of the number of containers in the area and the capacity of the containers, and consider
routine movement of the containers for the Plan. This estimate can be used to determine
applicability of the rule thresholds and provide a general description of the mobile/portable
containers in the Plan. The PE should also include a procedure for maintaining the log, in order to
avoid PE certification of technical amendments of the Plan as the number of mobile/portable
containers changes at the facility.
Mobile containers should be marked on the facility diagram in their out-of-service or
designated storage area or where they are most frequently located, such as a warehouse drum
storage area. The facility owner/operator and certifying PE determine how best to represent
mobile/portable containers on the facility diagram, such as by developing a log or indicating primary
storage areas. If mobile containers are moved throughout the facility and do not immediately return
to a specified location easily identified on the facility diagram, the exact location could be addressed
on a separate sheet or log. This log would complement the facility diagram and the SPCC Plan by
providing further information on the specific location and contents of mobile and portable
containers. In addition, the diagram must identify the final location of mobile or portable containers
(as required in §112.7(a)(3)) that return to a specific designated area to comply with the specific
secondary containment requirements in §112.8(c)(11). (See Chapter 4 of this document for a
discussion of secondary containment requirements.)
6.2.5 Completely Buried Storage Tanks
A facility diagram must include the location and contents of all containers required to be
addressed in the SPCC Plan (67 FR 47097 and §112.7(a)(3)). This includes exempt underground
storage tanks (USTs) as well as USTs that are subject to SPCC requirements at the facility. The
rationale for this requirement is to help response personnel to easily identify dangers from either fire
or explosion, or from physical impediments during response activities. For example, exempted
tanks may include completely buried USTs and piping systems at a gasoline service station that are
subject to all technical requirements of either 40 CFR part 280 or an approved state LIST program
under 40 CFR part 281.
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As discussed in Chapter 2 of this document, 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., LIST systems with field constructed tanks, any LIST system
that stores fuel solely for use by an emergency power generator, airport hydrant fuel distribution
systems). Any USTs at a facility that are subject to SPCC requirements must also be marked on
the facility diagram (§112.7(a)(3)). (See the preamble to the 1991 proposed rule, 56 FR 54612,
October 22, 1991.)
6.2.6 Piping and Manufacturing Equipment
The facility diagram must also include all transfer stations (i.e., any location where oil is
transferred) and connecting pipes (§112.7(a)(3)). Associated piping and manufacturing equipment
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 in the SPCC Plan as long as more detailed diagrams of the systems are
maintained at the facility and referenced on the diagram. Examples of more detailed diagrams 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 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.
Examples of ways that manufacturing equipment may be represented include a box that
identifies the equipment and its location, or a simplified process flow diagram. Figure 6-1, which is
an excerpt of a complete facility diagram (Figure 6-4) included later in Section 6.4, provides an
example showing how manufacturing equipment may be represented in a facility 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. Figure
6-2 provides an example showing how a complex piping area may be represented in a facility
diagram, and is also an excerpt of the example facility diagram presented in Figure 6-4.
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Figure 6-1. Example showing how manufacturing equipment
could be represented in a facility diagram. Note that more
detailed diagrams would need to be available at the facility.
From
Piping Area
Finished
• Consumer-
Product
Concrete pad
"CONCRETE FLOOR
liquid Product
Accumulation Tank
10,000 gal Ions
' To wafer
treatment plant
Pree»3s
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 Aiaa A
Raw Material Bulk Storagt
, Abovsground piping
• Raw Material Feed - Products & Solvent
To Process Area
Piping
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Chapter 6: Facility Diagrams
6.2.7 Use of State and Federal Diagrams
Some state and federal regulations may require a diagram with similar or overlapping
requirements, whereas others do not. SPCC is a federal program that specifies minimum
requirements, which states may supplement with more stringent requirements. A facility diagram
prepared for a state or federal plan or for other purposes (construction permits, facility
modifications, or other pollution prevention requirements) may be used in an SPCC Plan if it meets
the requirements of the SPCC rule.
6.3 Facility Diagram Examples
This section includes example facility diagrams for three fictitious SPCC-regulated facilities.
These three examples illustrate how certain containers and equipment could be represented in a
facility diagram; the examples are provided for the purpose of illustration only. Preparation of a
facility diagram is a site-specific effort, and the diagram prepared for a given facility should reflect
the level of detail needed to adequately describe the facility configuration. The level of detail and/or
approach taken for the examples below may not necessarily be appropriate for a given facility.
It is important to note that facility diagrams, like the other elements of an SPCC Plan, must
be prepared in accordance with good engineering practice, and must be reviewed by the PE
certifying the Plan (§112.3(d)). Section 112.7(a)(3) requires the facility diagram to show, at a
minimum, the location and contents of oil containers; completely buried storage tanks, including
those that may otherwise be exempt from the rule; and transfer areas (i.e., stations) and connecting
pipes. 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, and/or evacuation routes.
Example facility diagrams are presented below for a bulk storage and distribution facility, a
manufacturing facility, and an oil production facility.
6.3.1 Example #1: Bulk Storage and Distribution Facility
Figure 6-3 is an example of a diagram for a bulk storage and distribution facility, which has a
tank farm, a loading rack and 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 document. Because it has fewer tanks and less complex
operations than a manufacturing facility, for example, this facility requires a less detailed facility
diagram than the example provided in Figure 6-4.
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
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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-1). At the discretion of the PE
who reviewed and certified the Plan, the example facility diagram also depicts secondary
containment methods and includes a reference to calculations of 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. Please refer to Section 6.2.3 of this document for more information.
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Figure 6-3. Example facility diagram, including loading and unloading areas.
PREVENTION STREET
Storm Drain
(500 fl to Clsarwater Crmk)
Fenca Gale
36" concrefe dike
(60,000 gallons capacity, plus
4 inches of freeboard}
Drain valve
4" asphalt
rollover berm
Drain valve
ranks 5 ami 6
manifolded
ogether
Storm Drain
_ (600 ft to Clearwator Creek)
NOTES
' Refer to Table B-1 of SPCC Plan for volume and content of
storage tanks and containers shown on this diagram
• Th® calculation of the design capecrfes of cSted A?&® 1,
loading rscfc containment term, anrf reheler parting ares is
detailed In Appendix A of SPCC Plan.
* Refueters ussd tor emergency oi! fil! runs are positioned in
the refueter parking area since they are usually kept full.
• Other refueters are positioned in other parts of the facility
since limy am usually kapt empty upon reluming to the
facility.
* Facility drainage from diked areas terminates at the oil/water
separator
ASPHALT PA VED AREA
Protected double-walled AST
2,000 gallons. Heating oil
Main Office Building
Maximum 30 x 55 gallons drums
Lubricating oil. engine oil. used o*^
Placed on spill pallets inside hviMing,
Drain valve
Roof (coverdd area)
Quick drainage system and rollover curb.
Capacity: 2,000 gallons plus 4 Inches of
freeboard.
6* asphalt rollover betm
(2.000 gallons capacity
plus 4 inches of fmeboai?})
Refueters Parking Area
Neverspill Oil & Products Corporation "N
SPCC Plan - Facility Diagram
Rev, 6/14/05 ;
LEGEND
• Fire extinguisher C*^ Valve
-/*•' Predicted Direction of Drainage Fence
DIAGRAM IS NOT TO SCALE
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SPCC Guidance for Regional Inspectors
Table B-1. Volume and contents of tanks and containers identified on the facility diagram. Please
see facility diagram to identify the areas below.
Tank/Container
Volume (gallons)
Contents
Area 1
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 30 drums
55 (each)
Various oil products
(lubricating oil, engine oil,
used oil, etc.)
Rev. 06/14/05
Table B-2. Drum storage warehouse log.
Date
6/14/05
6/14/05
6/14/05
Number and Type
of Container
15 drums
5 drums
10 drums
Contents
lubrication oil
engine oil
used oil
Capacity
55x15 = 825
55 x 5 = 275
55x10 = 550
Location at
facility
Drum storage
warehouse
Drum storage
warehouse
Drum storage
warehouse
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Chapter 6: Facility Diagrams
6.3.2 Example #2: Manufacturing Facility
Figure 6-4 is an example facility diagram for 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). Also, while not required, the diagram marks the location of containers that store CWA
hazardous substances and labels those containers. EPA would further recommend that the specific
volume and specific contents of the 4,000-gallon solvent tank be included in the crosswalk.
Additionally, the diagram notes the location and content of completely buried storage tanks that,
although otherwise exempt from the SPCC rule because they meet all the technical requirements of
40 CFR part 280 or an approved state LIST program under 40 CFR part 281, must still be included
in the diagram in accordance with §112.7(a)(3).
This diagram also includes an example of how manufacturing equipment and complex
piping may be represented on a facility diagram. The diagram references the more detailed
diagrams and plans of the piping and manufacturing equipment that are available separately at the
facility. For more information on ways to represent these systems, please see Section 6.2.6, Piping
and Manufacturing Equipment, above.
Finally, while not required to be included in the diagram, this example facility diagram 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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Figure 6-4. Example facility diagram, including manufacturing equipment, complex piping, and completely buried storage tanks.
PREVENTION STREET
Fence
TankT r -
2.1XK! '->3l
EJuilding 1
Main Office
Fsnce Gate
Safe Valve
Gafe
Table 8-1 of SPCC Pfen for volume and cc*)fen( ofsiorage tanks and
confawiere shown oti Shis diagram.
The calculation of the design capacity of diked areas A. B. and C is detailed in
Appendix A of SPCC Ban,
For mots cteteutal diagrams and plans, including for piping and' manufacturing
areas, refer to site drawings maintained at NRQtJC main office in Building 1.
Facility drainage from diked areas terminates at the oil/water separator,
Only some elements of ihe process are represented on this diagram. For more
{fete^ed irtformafoon on process equipment configuration, refer to siie drawings
maintained in the main office-
Area A
Raw Material Bulk Storage
Gate Valve
asphalt
24" concrete dike
(35,000 gallons capacity)
Piping Area
/
AreaB ^
" Finished Product Bulk Storage
I fc a" 1 '
/ Tank 7 \ / Tank 6 \
Tank Truck Loading J \ ™-™™ ) ( ^ f' J
Rat* • V/' UL / \ '" """ /
k «|
\
\ 4" asphalt
\ rollover bem
(ZSOO gallons
:.f , capacity)
Gate Vaivs i
e t,
£
Fuel Island
I i a. ooo GS ) \ — i
em? """""ir^r"'
( S.fllMGal j Tp
SpHt Control /
Equipment
- Products & Solvent
it ,
36" co
(35.00
CO
icrete dike
} gallons capacity)
"" gram! on
ncrete finer L
__, .__, [ Sump |
[El][E2 1
AreaC
El^ctrica Equiprrienl
Finished
Product rf
Liquid Product
ccumulation Tank
10, COO gallons
Concrete pad x' Area p
'CONCRETE FLOOR
I
\
I
1
I
i
' Primary
. Reactor
1
• — •
Cond
Liqi
— • — • — . — .
1
snser
ifier i
i
I
Direct I
Contact
Cooling I
f I
Distillation I
i
5 Area
Building 2
1
rreafrr
J
c
"^
To
®nt
No Release Oil & Manufacturing Corporation
SPCC Plan - Facility Diagram
Rev, 04/21/05 j
LEGEND
• Fife extinguisher
FW/ Predicted Dlrecfon of Drainage
[X| Value
Fence
- - - Process area delineation
Piping area delineation
Underground storage tank
DIAGRAM IS NOT TO SCALE
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Chapter 6: Facility Diagrams
Table B-3. Volume and contents of tanks and containers identified on the facility diagram. Please
see facility diagram to identify the areas below.
Tank/Container
Volume (gallons)
Contents
Area A - Raw Material Bulk Storage
Tankl
Tank 2
TankS
Tank 4
TankS
TankS
Tank 9
4,000
4,000
20,000
20,000
20,000
6,000
40,000
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 E1
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 Liquifier
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 9 (otherwise exempt
from SPCC requirements)
Tank 10 (otherwise exempt
from SPCC requirements)
Tank 11
8,000
8,000
2,000
gasoline
gasoline
heating oil
Rev. 04/21/05
6.3.3 Example #3: Oil Production Facility
Figure 6-5 is an example facility diagram for 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 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 waterbodies (Figure 6-6).
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Figure 6-5. Example facility diagram for a production facility.
Well A
P2
Well B
FLA
2 inch diameter steel
Appro* length 2.100 ft
Birned segment
under dirt road
FLB
2 inch diameter steel
Approx length 3.400H
To Saltwater
disposal we
Approx. length
2,000 ft
(see BOX 1')
Tanker truck loading*'
unloading area
contain men!
BOX 1. Saltwater Disposal Well Area
To production afea
— Approx. fengtti
2,000 ft
Clearwater Oil Company
Big Bear Lease No. 2 Production Facility
Facility Diagram Drawing
Rev. 11/12/02
noc to
scale
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Chapter 6: Facility Diagrams
B|ig Beai/Le^e
Ifo 2JPrt>dtfctio
facility
Figure 6-6. Example general facility location diagram for a production facility.
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6.4 Review of a Facility Diagram
6.4.1 Documentation by Owner/Operator
By certifying an SPCC Plan, a PE attests that he/she is familiar with the requirements of 40
CFR part 112, that the Plan has been prepared in accordance with good engineering practice,
following the requirements of 40 CFR part 112, that the Plan is adequate for the facility, and that he
or his agent visited the facility. Thus, if an SPCC Plan is certified by a PE and the facility diagram is
consistent with the rule requirements, it will most likely be considered acceptable by regional
inspectors. However, if the diagram does not meet these standards of common sense, the facility
design has changed, the supporting drawings for a simplified diagram are not available at the
facility, or the diagram appears to be inadequate for the facility, appropriate follow-up action may be
warranted. This may include a request for more information or a Plan amendment in accordance
with§112.4(d).
6.4.2 Role of the EPA Inspector
The inspector should 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 container (except those below the cfe minimis
container size of 55 gallons as described in Section 6.2.3, above).
Completely buried tanks, including those that are otherwise exempt from the SPCC
rule by §112.1 (d)(4).
All transfer stations and connecting pipes (allowing the flexibility as described in
Section 6.2.6, above).
Although EPA generally stated in both the preamble of the 2002 SPCC rule (67 FR 47097)
and in §112.7(a)(3) that all facility transfer stations and connecting pipes that handle oil must be
included in the diagram, it is reasonable to allow flexibility on the method of depicting concentrated
areas of piping and 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. The inspector may ask to
review more detailed diagrams of piping and manufacturing equipment if further information is
needed during a site inspection.
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Chapter 7: Inspection, Evaluation, and Testing
INSPECTION, EVALUATION, AND TESTING
7.1 Introduction
Regularly scheduled inspections, evaluations, and testing by qualified personnel are critical
parts of discharge prevention. Their purpose is to prevent, predict, and readily detect discharges.
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
release. Activities may involve one or more of the following: an external visual inspection of
containers, piping, valves, appurtenances, foundations, and supports; a non-destructive shell test to
evaluate integrity of certain containers; and additional evaluations, as needed, to assess the
equipment's fitness for continued service. The type of activity and its scope will depend on the
exercise of good engineering practice; not every action will necessarily be applicable to every
facility and container, and additional inspections may be required in some cases. 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 specific cases, including the use of environmentally
equivalent measures.
Section 7.4 discusses the role of the EPA inspector in reviewing a facility's
compliance with the rule's inspection, evaluation, and testing requirements.
Section 7.5 summarizes industry standards, code requirements, and recommended
practices (RPs) that apply to different types of equipment.
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 and to different types of facilities. The requirements are generally
aimed at preventing discharges of oil caused by leaks, brittle fracture, or other forms of container
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 failures (such as
small pinhole leaks) before they can become significant and result in a discharge as described in
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7.2.1 Summary of Inspection and Integrity Testing Requirements
Table 7-1 summarizes the provisions that apply to different types of equipment and facilities.
Some inspection and testing provisions apply to bulk storage containers at onshore facilities (other
than production facilities). Inspection and/or testing requirements also apply to other components
of a facility that might cause a discharge (such as vehicle drains, foundations, or other equipment or
devices). Other inspection requirements also apply to oil production facilities. In addition,
inspection, evaluation, and testing requirements are required 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 catastrophe, or in cases where
secondary containment for bulk storage containers is impracticable (§112.7(d), as described in
Chapter 4 of this document.) Facility owners and operators must also maintain corresponding
records to demonstrate compliance (§§112.8(c)(6), 112.8(d)(4), 112.9(b)(2), 112.9(c)(3), and
112.9(d)(1) and (2)) per §112.7(e).
Table 7-1. Summary of SPCC inspection, evaluation, testing, and maintenance program provisions.
Facility Component
Section(s)
Action
Method, Circumstance, and Required Action
General Requirements Applicable to All Facilities
Bulk storage with no
secondary
containment and for
which an
impracticability
determination has
been made
112.7(d)
Test
Integrity testing.1 Periodically.
However, because there is no secondary containment,
good engineering practice may suggest more frequent
testing than would otherwise be scheduled.
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.
1 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. Integrity testing
is a necessary component of any good oil discharge prevention plan. It will help to prevent discharges by testing the
strength and imperviousness of containers, ensuring they are suitable for continued service under current and
anticipated operating conditions (e.g., product, temperature, pressure). Testing may also help facilities determine
whether corrosion has reached a point where repairs or replacement of the container is needed, and thus avoid
unplanned interruptions in facility operations. (67 FR 47120)
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Chapter 7: Inspection, Evaluation, and Testing
Facility Component
Section(s)
Action
Method, Circumstance, and Required Action
Recordkeeping
requirement
112.7(e)
Record
Keep written procedures and a signed record of
inspections and tests for a period of three years.2
Records kept under usual and customary business
practices will suffice. For all actions.
Lowermost drain and
all outlets of tank car
or tank truck
112.7(h)(3)
Inspect
Visually inspect. Prior to filling and departure of tank
car or tank truck.
Field-constructed
aboveground
container
Evaluate
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 catastrophe. Based on the results of this
evaluation, take appropriate action.
Subpart B: Onshore Facilities - Petroleum and Other Non-Petroleum Oils
Subpart C: Onshore Facilities (Excluding Production Facilities) -Animal Fats and Vegetable Oils
Onshore Facilities (Excluding Production)
Diked areas
112.8(b)(2)or
&
112.8(c)(10)or
Inspect
Visually inspect content for presence of oil. Prior to
draining. You must promptly remove any
accumulations of oil in diked areas.
Buried metallic
storage tank
installed on or after
January 10, 1974
112.8(c)(4)or
Test
Leak test. Regularly.
Aboveground bulk
storage container
112.8(c)(6)or
Test
Test container integrity. Combine visual inspection
with another testing technique (such as non-
destructive shell testing). Following a regular
schedule and whenever material repairs are made.
Aboveground bulk
storage container
112.8(c)(6)or
Inspect
&
112.8(c)(10)or
Inspect outside of container for signs of deterioration
and discharges. Frequently. 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.
Certain industry standards require recordkeeping beyond three years.
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Facility Component
Bulk storage
container supports
and foundation
Diked area
Steam return and
exhaust lines
Liquid level sensing
devices
Effluent treatment
facilities
Buried piping
Buried piping
All aboveground
valves, piping, and
appurtenances
Section(s)
112.8(c)(6)or
112.12(c)(6)
112.8(c)(6)or
112.12(c)(6)
&
112.8(c)(10)or
112.12(c)(10)
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(d)(1)or
112.12(d)(1)
112.8(d)(4)or
112.12(d)(4)
112.8(d)(4)or
112.12(d)(4)
Action
Inspect
Inspect
Monitor
Test
Observe
Inspect
Test
Inspect
Method, Circumstance, and Required Action
Inspect container's supports and foundations.
Following a regular schedule and whenever material
repairs are made.
Inspect for signs of deterioration, discharges, or
accumulation of oil inside diked areas. Frequently.
You must promptly remove any accumulations of oil in
diked areas.
Monitor for contamination from internal heating coils.
On an ongoing basis.
Test for proper operation. Regularly.
Detect possible system upsets that could cause a
discharge. Frequently.
Inspect for deterioration. Whenever a section of
buried line is exposed for any reason. If you find
corrosion damage, you must undertake additional
examination and corrective action 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 Production Facilities
Diked area
Field drainage
systems, oil traps,
sumps, and
skimmers
Aboveground
containers
112.9(b)(1)
112.9(b)(2)
112.9(c)(3)
Inspect
Inspect
Inspect
Visually inspect content. Prior to draining. You must
remove accumulated oil on the rainwater and return it
to storage or dispose of it in accordance with legally
approved methods.
Detect accumulation of oil that may have resulted from
any small discharge. Inspect at regularly scheduled
intervals. You must promptly remove any
accumulations of oil.
Visually inspect to assess deterioration and
maintenance needs. Periodically and on a regular
schedule.
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Chapter 7: Inspection, Evaluation, and Testing
Facility Component
Foundations or
supports of each
container that is on or
above the surface of
the ground
All aboveground
valves and piping
associated with
transfer operations
Saltwater disposal
facilities
Section(s)
112.9(c)(3)
112.9(d)(1)
112.9(d)(2)
Action
Inspect
Inspect
Inspect
Method, Circumstance, and Required Action
Visually inspect to assess deterioration and
maintenance needs. Periodically and on a regular
schedule.
During the inspection, assess 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 on a regular schedule.
Inspect to detect possible system upsets capable of
causing a discharge. Often, particularly following a
sudden change in atmospheric temperature.
Offshore Oil Drilling, Production, and Workover Facilities
Flowlines
Sump system (liquid
removal system and
pump start-up device)
Pollution prevention
equipment and
systems
Sub-marine piping
112.9(d)(3)
112.11(c)
112.11(h)&(i)
112.11(p)
Inspect
Inspect
and Test
Inspect
and Test
Inspect
and Test
Have a program of flowline maintenance to prevent
discharges from each flowline. Each program may
have its own specific and individual inspection, testing,
and/or evaluation requirements and frequencies as
determined by the PE.
Use preventive maintenance inspection and testing
program to ensure reliable operation. Regularly
scheduled.
Prepare, maintain, and 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. You must use simulated discharges for
testing and inspecting human and equipment pollution
control and countermeasure systems. On a schedulec
periodic basis.
Inspect and test for good operating conditions and for
failures. Periodically and according to a schedule.
The SPCC rule is a performance-based regulation. Since each facility may present unique
characteristics and since methodologies may evolve as new technologies are developed, the rule
does not prescribe a specific frequency or methodology to perform the required inspections,
evaluations, and tests. Instead, it relies on the use of good engineering practice, based on the
professional judgement of the Professional Engineer (PE) who certifies the SPCC Plan considering
industry standards. In addition, recommended practices, safety considerations, and requirements
of other federal, state, or local regulations may be considered in the development and PE
certification of the SPCC Plan. Section 112.3(d) specifically states that the PE certification of a
Plan attests that "procedures for required inspections and testing have been established." Thus, in
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certifying an SPCC Plan, a PE is also certifying that the inspection program it describes is
appropriate for the facility and is consistent with good engineering practice. Section 112.3(d) 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.
The preamble to the 2002 revised SPCC rule 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 Tables 7-2 and 7-
3 (Section 7.2.6) and further discussed in Section 7.5. It is important to note, however, that the
industry standards may be more specific and more stringent than the requirements in the SPCC
rule. For example, EPA does not prescribe a particular schedule for testing. This is because "good
engineering practice" and relevant industry standards change over time. 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 interval between external and internal inspections, and provides
specific criteria for alternative inspection intervals based on the calculated corrosion rate. API 653
also provides an internal inspection interval when the corrosion rates are not known. Similarly, the
Steel Tank Institute (STI) Standard SP-001, 3rd Edition, provides specific intervals for external and
internal inspection of shop-built containers based on container size and configuration.
Integrity testing requirements for the SPCC rule may be replaced by environmentally
equivalent measures as allowed under §112.7(a)(2) and reviewed by the PE who certifies the Plan.
Chapter 3 of this guidance provides a general discussion of environmental equivalence, while
Section 7.3 discusses its particular relevance to inspection, evaluation, and testing requirements.
7.2.2 Regularly Scheduled Integrity Testing
and Frequent Visual Inspection of
Aboveground Bulk Storage
Containers
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, use, or
process petroleum oils and non-petroleum oils
(except animal fats and vegetable oils). Section
112.12(c)(6) contains the same requirements for
facilities with animal fats and vegetable oils.
The provision sets two distinct
requirements for aboveground bulk storage
containers:
§§112.8(c)(6) and 112.12(c)(6)
Test each aboveground container for integrity on
a regular schedule, and whenever you make
material repairs. The frequency of and type of
testing must take into account container size and
design (such as floating roof, skid-mounted,
elevated, or partially buried). 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.
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 will suffice for purposes 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.
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Chapter 7: Inspection, Evaluation, and Testing
(1) Regularly scheduled integrity testing; and
(2) Frequent visual inspection of the outside of the container.
Regularly scheduled integrity testing. The integrity testing requirements are distinct from,
and are in addition to, the requirement to frequently inspect the outside of an aboveground storage
container ("visual inspection," see below). The integrity testing requirement applies to large (field-
constructed or field-erected) and small (shop-built)3 aboveground containers; aboveground
containers on, partially in (partially buried, bunkered, or vaulted tanks), and off the ground wherever
located; and to aboveground containers storing any type of oil.
Generally, visual inspection alone is not sufficient to test the integrity of the container as
stated in §§112.8(c)(6) and 112.12(c)(6); it must be combined with another testing technique and
must include the container's supports and foundations. Testing techniques include but are not
limited to:
Hydrostatic testing;4
Radiographic testing;
Ultrasonic testing;
Acoustic emissions testing; and
Another system of non-destructive shell testing.
The SPCC rule requires that integrity testing of aboveground bulk storage containers be
performed on a regular schedule, as well as when material repairs5 are made, because such repairs
might increase the potential for oil discharges. As stated in the preamble to the final 2002 rule,
"Testing on a 'regular schedule' means testing per industry standards or at a frequency sufficient to
prevent discharges. Whatever schedule the PE selects must be documented in the Plan" (67 FR
47119). The frequency of integrity tests should reflect the particular conditions of the container,
such as the age, service history, original construction specifications, prior inspection results, and
the existing condition of the container. It may also consider the degree of risk of a discharge to
navigable waters and adjoining shorelines. For example, where secondary containment is
inadequate (none provided, insufficient capacity or insufficiently impervious) and adequate
3 According to STI SP-001, 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 SP-001, "Standard for the Inspection of Aboveground Storage Tanks," July 2005)
4 Hydrostatic testing is allowed per §112.8(c)(6); however, hydrotesting the container may actually result in container
failure during the test and should be performed in accordance with industry standards and using the appropriate test
media.
5 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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secondary containment would be impracticable, §112.7(d) requires, among other measures,
periodic integrity testing of bulk storage containers. Given the higher potential of a discharge
reaching navigable waters or adjoining shorelines, however, the PE may decide, based on good
engineering practice, that more frequent integrity tests would be needed than for containers that
have adequate secondary containment. This approach of establishing an increased inspection
frequency for an aboveground container without secondary containment is used in the STI SP-001
standard.
Frequent visual inspection. There must be a frequent inspection 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. EPA expects that the
walk-around, which will occur on an ongoing routine basis, can generally be conducted by properly
trained facility personnel, as opposed to the more intensive but less frequent visual inspection
component of the non-destructive examination conducted by qualified testing/inspection personnel.
Qualifications of these personnel are outlined in tank inspection standards, such as API 653 and
STI SP-001. A facility owner or operator can, for example, visually inspect the outside of bulk
storage containers on a daily, weekly, and/or monthly basis, and supplement this inspection with
integrity testing (see above) performed by a certified inspector, with the scope and frequency
determined by industry standards or according to a site-specific inspection program developed by
the PE.
Oil-filled electrical, operating, and manufacturing devices or equipment are not considered
bulk storage containers; therefore, the integrity testing requirements in §§112.8(c)(6) and
112.12(c)(6) do not apply to those devices or equipment. However, EPA recommends that even
where not specifically required by the rule, it is good engineering practice to frequently inspect the
outside of oil-filled operational, electrical, and manufacturing equipment to determine whether it
could cause a discharge. For example, in a food manufacturing process, certain containers that
contain edible oil (such as reactors, fermentors, or mixing tanks) are considered oil-filled
manufacturing equipment and are not required to undergo integrity testing. Since a discharge as
described in §112.1(b) can occur from manufacturing, discharge discovery and thus visual
inspection procedures outlined in an SPCC Plan should include this equipment as well as other oil-
filled equipment to prevent such a discharge as part of the facility's countermeasures per
§112.7(a)(3)(iv) for discharge discovery. Although oil-filled equipment is not subject to the integrity
testing requirements under §112.8(c)(6) or§112.12(c)(6), EPA recommends routine inspections at
least visually to detect discharges as part of the facility's countermeasures per §112.7(a)(3)(iv) for
discharge discovery.
7.2.3 Brittle Fracture Evaluation of Field-Constructed Aboveground Containers
Brittle fracture is a type of structural failure in larger field-constructed 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. A review
of past failures due to brittle fracture shows that they typically occur (1) during an initial hydrotest,
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(2) on the first filling in cold weather, (3) after a change to lower temperature service, or (4) 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.6 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.
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 SP-001, Appendix B),
evidence of this evaluation should be
documented in the facility's SPCC Plan.
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.
In summary, 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
including API 653, "Tank Inspection, Repair, Alteration, and Reconstruction," API RP 920
"Prevention of Brittle Fracture of Pressure Vessels," and API RP 579, "Fitness-for-Service." These
standards include a decision tree or flowchart for use by the owner/operator and PE in assessing
the risk of brittle fracture. STI SP-001 also addresses brittle fracture failures for smaller diameter
field-erected tanks with a wall thickness less than one-half inch.
7.2.4 Inspections of Piping
For onshore facilities, the SPCC rule specifies the following inspection and testing
requirements for piping. Buried piping at non-production facilities that has been installed or
replaced on or after August 16, 2002, must have a protective wrapping and coating and be
protected from corrosion cathodically or by other means, as per§§112.8(d)(1) and 112.12(d)(1).
Any exposed line must be inspected for deterioration, and, 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
6 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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standards. Buried piping must be integrity and leak tested at the time of installation, modification,
construction, relocation, or replacement.
Aboveground valves and piping associated with transfer operations at production facilities
must be inspected periodically and on a regular schedule, as per §112.9(d)(1) and in accordance
with industry standards. A program of flowline maintenance is required by §112.9(d)(3) and is
described in the following section of this document.
For offshore facilities, §112.11(n) specifies that all piping appurtenant to the facility must be
protected from corrosion, such as with protective coatings orcathodic protection. Section 112.11(p)
requires that sub-marine piping appurtenant to the facility be maintained in good operating condition
at all times, and that such piping be inspected or tested for failures periodically and according to a
schedule.
In addition, if the owner/operator determines that these required measures are not
practicable, periodic integrity and leak testing of valves and piping must be conducted, as per
§112.7(d).
7.2.5 Flowline Maintenance
The objective of the SPCC flowline maintenance program requirement (§112.9(d)(3)) is to
help prevent oil discharges from production flowlines, e.g., the piping that extends from the
pump/well head to the production tank battery. Common causes of such discharges include
mechanical damage (i.e., impact, rupture) and corrosion. A flowline maintenance program aims to
manage the oil production operations in a manner that reduces the potential for a discharge. It
usually combines careful configuration, inspection, and ongoing maintenance of flowlines and
associated equipment to prevent and mitigate a potential discharge. EPA recommends that the
scope of a flowline maintenance program include periodic examinations, corrosion protection,
flowline replacement, and adequate records, as appropriate. EPA suggests that facility
owner/operators conduct inspections either according to industry standards or at a frequency
sufficient to prevent a discharge as described in §112.1(b). EPA is aware that API attempted to
develop an industry standard for flowline maintenance, but the standard has not been finalized.
However, according to practices recommended by industry groups, such as API, a comprehensive
piping (flowline) program should include the following elements:
Prevention measures that avert the discharge of fluids from primary containment;
Detection measures that identify a discharge or potential for a discharge;
Protection measures that minimize the impact of a discharge; and
Remediation measures that mitigate discharge impacts by relying on limited or
expedited cleanup.
If a standard for flowline maintenance is developed, inspectors are encouraged to review this
standard. At present, the details below serve to guide the inspector in reviewing the scope of a
flowline maintenance program. If an impracticability determination under §112.7(d) is made for
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flowlines for secondary containment required by §112.7(c), EPA inspectors should extensively
review the adequacy of the flowline maintenance program along with the contingency plan (67 FR
47078).
A flowline maintenance program should ensure that flowlines, associated equipment, and
safety devices are kept in good condition and would operate as designed in the event of a
discharge. The PE 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 such sources of good engineering practice.
General Spill Prevention
The maintenance program should ensure that the equipment is configured and operated to
prevent discharges. Adequate supports and signage should be maintained to help prevent
mechanical damage to aboveground flowlines. Finally, the maintenance program should ensure
the proper operation of safety devices such as low-pressure sensors and safety shut-down valves
to mitigate the extent of a spill in the event of a flowline rupture.
Corrosion Protection
Internal corrosion may be prevented through the use of compatible materials (PVC,
fiberglass, coatings) or by the addition of corrosion inhibitors. External corrosion may be prevented
through the use of compatible materials, coatings/wrappings, and/or cathodic protection.
Periodic Examination
Visual observation of the flowlines by facility personnel should be included as part of any
flowline maintenance program and is of paramount importance for those facilities with flowlines that
have no secondary containment and rely on rapid spill detection to implement a contingency plan in
a timely manner. Facility personnel may "walk the flowlines" or perform aerial fly-overs, if they are
located aboveground, to detect any evidence of leakage. The visual inspection should cover the
piping, flange joints, valves, drip pans, and supports, and look for signs of corrosion, deterioration,
leakage, malfunction, and other problems that could lead to a discharge. The frequency of
inspections can vary according to their scope, the presence of secondary containment, and the
detection capability needed to ensure prompt implementation of a contingency plan (if no
containment is present), and may include daily, monthly, quarterly, or annual inspections. Regular
visual inspection may be supplemented by periodic integrity testing using non-destructive
evaluation methods, such as ultrasonic or other techniques to determine remaining wall thickness,
or hydrostatic testing at a pressure above normal operating pressure. This guidance document
refers to some relevant industry standards that describe methods used to test the integrity of piping,
such as API 570 and ASME B31.4.
Flowline Replacement and Recordkeeping
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The facility's SPCC Plan should describe how the flowlines are configured, monitored, and
maintained to prevent discharges. The program is to be implemented in the field, and facility
personnel responsible for the maintenance of the equipment should be aware of the flowline
locations and be familiar with maintenance procedures, including replacement of damaged and/or
leaking flowlines. Records of inspections and tests kept under usual and customary business
practices should be prepared and made available for review, as required by the rule (§112.7(e)).
If an impracticability determination is made for flowlines, the flowline maintenance program
should be shown to be adequate along with the contingency plan (67 FR 47078).
7.2.6 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 the
facility. Rather, the rule provides flexibility in the facility owner/operator's implementation of the
requirement, consistent with good engineering practice, 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)(1)(iii)). If the
facility owner or operator uses a specific standard to comply with SPCC requirements, the standard
should be referenced in the Plan. Where no specific and general industry standard exists to inform
the determination of what constitutes good engineering practice for a particular inspection or testing
requirement, the PE should consider the manufacturer's specifications and instructions for the
proper use and maintenance of the equipment, appurtenance, or container. If neither a specific and
objective industry standard nor a specific and objective manufacturer's instruction apply, the PE
may also call upon his/her professional experience to develop site-specific inspection and testing
requirements for the facility or equipment as per §112.3(d)(1)(iv). The inspection and testing
program must be documented in the Plan (§112.7(e)). A checklist is provided as Table 7-5 at the
end of this chapter to assist inspectors in reviewing the relevant industry standards based on the
equipment observed at an SPCC-regulated facility.
In the preamble to the 2002 SPCC rule, EPA provides 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). Compliance with other industry standards and federal requirements
may also meet SPCC inspection, evaluation, and testing requirements. The U.S. Department of
Transportation (DOT) regulates containers used to transport hazardous materials, including certain
oil products. For example, 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). 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.
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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); the
standards 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 ability to maintain pressure or remaining shell thickness. The
integrity testing is usually performed by inspectors licensed by the standard-setting organizations
(e.g., American Petroleum Institute, Steel Tank Institute).
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 7.5 of this chapter provides a more detailed description of the standards listed in the tables.
Other industry standards 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 all
container types and appurtenances.
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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
document
API 653
Field-fabricated,
welded, or riveted
ASTs operating at
atmospheric
pressure and built
according to API
650.
Inspection and
design; fitness for
service; risk.
Certified
inspections:
Dependent on
tank's service
history. Intervals
from 5 to 20 years.
Owner inspections:
monthly.
Certified inspector,
tank owner.
Section 7.5.1
STI SP-001
ASTs including
shop-fabricated
and field-erected
tanks and portable
containers and
containment
systems.
Determined by the
type of material
stored within the
tank and the
operating
temperature.
Inspection of tanks
by the owner/
operator and
certified inspectors.
Certified
inspections:
Inspection intervals
and scope based
on tank size and
configuration.
Owner inspections:
monthly, quarterly,
and yearly.
Certified inspector,
either by API or
STI.
Section 7.5.2
API RP 575
Atmospheric and
low-pressure ASTs.
Inspection and
repair of tanks.
Same as API 653.
Same as API 653.
Section 7.5.3
APIRP12R1
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 of the
Recommended
Practice.
Competent person or
qualified inspector, as
defined in
recommended
practice.
Section 7.5.4
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Table 7-3. Summary of industry standards and recommended practices (RP) for piping, valves,
and appurtenances.
Equip-
ment
covered
Scope
Inspection
interval
Inspection
performed
by
Applicable
section of
this
document
API 570
In-service
aboveg round
and buried
metallic piping
Inspection,
repair,
alteration, and
rerating
procedures
Based on
likelihood and
consequence
of failure ("risk-
based"),
maximum of
1 0 years
Certified piping
inspector
Section 7.5.5
API RP 574
Piping, tubing,
valves and
fittings in
petroleum
refineries and
chemical plants
Inspection
practices
Based on five
factors
Authorized
piping inspector
Section 7.5.6
API RP 1110
Liquid
petroleum
pipelines
(pressure
testing)
Procedures,
equipment, and
factors to
consider during
pressure testing
-
-
Section 7.5.7
ASMEB31.3
Process piping
for oil,
petrochemical,
and chemical
processes
Minimum safety
requirements
for design,
examination,
and testing
As part of
quality control
function
Qualified
Inspector, as
defined in
standard
Section 7.5.10
ASMEB31.4
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 7.5.11
"-" means that the standard provides no specific information for the element listed.
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7.3 Specific Circumstances
Integrity testing (a combination of visual inspection and another testing technique) is
required for all aboveground bulk storage containers located at onshore facilities (except production
facilities), unless the facility owner/operator implements an environmentally equivalent method (as
described in Chapter 3 and in Section 7.3.4, below) and documents the deviation in the SPCC Plan.
Typically, visual inspection is combined with non-destructive shell testing in order to adequately
assess the container condition. EPA has indicated that visual inspection alone may provide
equivalent environmental protection in some cases, if certain conditions are met and if the
inspections are conducted at appropriate time intervals (see Section 7.3.4 of this document) in
accordance with good engineering practice. Therefore, if the Plan calls for visual inspection alone
in accordance with an industry standard, then the Plan must discuss the reason for the
nonconformance with §112.8(c)(6) or §112.12(c)(6) and comply with the environmental equivalence
provision in §112.7(a)(2).
Some facilities may not have 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 condition of the tank shell, and the rate
of change in condition due to corrosion or other factors, in order to establish a regular inspection
schedule. Section 112.7 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. For all types of facilities,
the PE is responsible for making the final determination on the scope and frequency of testing when
certifying that an SPCC Plan is consistent with good engineering practice and is appropriate for the
facility.
This section provides guidance on integrity testing for the following circumstances the
inspector may encounter at an SPCC-regulated facility:
Aboveground bulk storage containers for which the baseline condition is known;
Aboveground bulk storage containers for which the baseline condition is not known;
Deviation from integrity testing requirements based on environmental equivalence;
and
Environmental equivalence scenarios for shop-built containers.
This is not a comprehensive list of circumstances. For these and other cases, the PE may
recommend alternative approaches.
7.3.1 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
corrosion rates are known), the inspection and testing schedule should typically occur at a scope
and frequency based on industry standards (or the equivalent developed by a PE for the
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site-specific SPCC Plan) per §112.8(c)(6) or §112.12(c)(6). There is an advantage to knowing the
baseline condition of a tank, particularly if the remaining wall thickness and the corrosion rate are
known. 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 specific intervals
per 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 the established corrosion rate to
determine an inspection interval for external and internal inspections 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. 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 PE may choose to develop an inspection and testing program for the
facility's shop-built tanks in accordance with STI SP-001, and may elect to develop the program for
the facility's field-erected tanks in accordance with API 653. As an alternative example, the PE may
elect to develop a program in accordance with STI SP-001 for the facility's shop-built tanks and for
its field-erected tanks of a certain capacity and size. For containers at facilities storing animal fats
and vegetable oils, the PE may elect to develop a hybrid testing program building upon elements of
both API 653 and STI SP-001 or only one of the standards.
7.3.2 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. The PE must attest that procedures for required inspections and
testing have been established (§112.3(d)(1)(iv)). However, for shop-built and field-erected
containers for which construction history and wall and/or bottom plate thickness baselines are not
known, a regular integrity testing program cannot be established. Instead, the PE 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 112.12(c)(6). It should be noted that the introductory paragraph
of §112.7 of the SPCC rule allows for the Plan to describe procedures, methods, or equipment that
are not yet operational, and include a discussion of the details.
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 SP-001 include details on how to 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 to establish a baseline of shell thickness
and corrosion rate in order to develop the next inspection interval (or "regular" schedule), or an
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alternative inspection schedule established by the PE in accordance with good engineering
practice.
When no baseline information is available for a container, the PE may schedule visual
inspection and another testing technique within the first five-year review cycle of the SPCC Plan in
order to establish a regular integrity testing schedule based on current container conditions. In this
example, the review cycle would begin on the revised rule implementation deadline of August 18,
2006, so the first (baseline) container inspection and integrity test would be completed by August
18, 2011. 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 point to establish wall
thicknesses and would be included in the established procedures for inspection and testing.
The implementation, particularly in establishing inspection priorities, of the testing program
should be in accordance with good engineering practice and include consideration of industry
standards (§112.3(d)), as discussed in this document. For instance, special consideration may be
discussed in the Plan for containers for which the age and existing condition is not known (no
baseline information exists). For example, older tanks or tanks in more demanding service may be
identified as high-priority tanks for inspection, versus tanks for which the baseline information is
Figure 7-1. Example baselining plan to determine the integrity testing and inspection schedule.
Scenario:
Facility has three aboveground atmospheric, mild-carbon steel tanks of different ages and conditions. Some have prior
inspection histories; others have never been inspected. Although there is limited history available for tank construction,
the tanks are presumed to be field-erected tanks and to each have 100,000 gallons in storage capacity. What is an
appropriate inspection schedule for these tanks? API 653 is the referenced inspection standard.
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 1/4 of corrosion rate, whichever is less. If corrosion rates are not known, the
maximum interval is 5 years. An internal inspection of the bottom of the tank is to be done based on corrosion rates. If the
corrosion rate is known, the interval cannot exceed 20 years. If the corrosion rate is unknown, the interval cannot exceed 10
years.
Determination of inspection schedule:
Tankl
Tank 2
Tank3
Construction Date
unknown
2001
1984
Last Inspection
none
none
1994
Next Inspection (External)
formal visual and shell test
(external) within first five-year
Plan review cycle
2006 for both visual inspection
and non-destructive shell test
1999 & 2004 formal visual
2009 non-destructive shell test
both intervals may be
decreased based on calculated
corrosion rates from the 1994
inspection.
Next Inspection (Internal)
formal (internal) bottom
inspection within first five-year
Plan review cycle
2011 (i.e., not to exceed 10
years when corrosion rate of
tank bottom is not known)
2014 or less based on
calculated corrosion rates
from the 1994 inspection
Note: Actual inspection schedule is ultimately an engineering determination made by the PE, based on industry standards,
and is certified in the Plan.
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known.
An example baselining plan is presented in Figure 7-1. The example presents a simple
scenario and is 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.
7.3.3 Deviation from Integrity Testing Requirements Based on Environmental Equivalence
Chapter 3 of this document describes the flexibility provided in the SPCC rule through the
use of environmental equivalent measures, per §112.7(a)(2). The discussion below describes
examples of measures that facility owners and operators can use to deviate from inspection and
testing requirements, while providing equivalent environmental protection.
The SPCC rule provides flexibility regarding integrity testing requirements of bulk storage
containers, as long as the alternatives provide equivalent environmental protection per
§112.7(a)(2). Measures that may be considered environmentally equivalent to integrity testing for
shop-built containers are those that effectively minimize the risk of container failure and that allow
detection of leaks before they become significant. Alternative measures to integrity testing requiring
the combination of internal, external, and non-destructive evaluation 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 they can be addressed before more severe integrity failure occurs. The
ability to use an environmentally equivalent alternative to integrity testing will often hinge on the
degree of protection provided by the tank configuration and secondary containment. EPA believes
that larger tanks (including larger shop-built tanks) may require inspection by a professional
inspector, in addition to the visual inspection by the tank owner/operator during the tank's life. EPA
defers to applicable industry standards and to the certifying PE as to the type and scope of
inspections required in each case. However, the inspector should look for a clear rationale for the
development of the inspection and testing program, paying close attention to the referenced
industry standard.
EPA believes that environmental equivalence may be appropriate in other situations. For
example, facilities that store edible oils as part of a food manufacturing process may adhere to very
strict housekeeping and maintenance procedures that involve ongoing visual inspection and routine
cleaning of the exterior and interior of the containers (which are elevated so all sides are visible or
sit on a barrier that allows for rapid detect of a leak) by facility personnel. As part of these routine
inspections, small leaks can be detected before they can cause a discharge as defined in
§112.1(b). The PE certifying the facility's SPCC Plan may determine, upon considering applicable
food-related regulations, industry standards, and site-specific conditions, that such inspections and
housekeeping procedures provide environmental protection equivalent to performing an integrity
test on these containers.
As with other requirements eligible for environmental equivalence provision, the measures
implemented as alternatives to integrity testing required under §112.8(c)(6) or §112.12(c)(6) may
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not be measures already required to meet another part of the SPCC rule. 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. However, for certain tank sizes and
configurations of secondary containment, continuous release detection and frequent visual
inspection by the owner/operator may be the sole inspection requirement, provided that the
rationale is discussed in the Plan (STI SP-001). This rationale should include a discussion of good
engineering practice referencing appropriate industry standards.
7.3.4 Environmental Equivalence Scenarios for Shop-Built Containers
Scenario 1: Elevated Drums. As EPA has indicated in the 2002 Figure 7-2. Drums elevated
., . .. . . 01-,^^ i ^ • M i- i- -ix L • on a storage rack. Drums
preamble to the revised SPCC rule, certain smaller shop-built containers are a|SO subject to secondary
(e.g., 55-gallon drums) for which internal corrosion poses minimal risk of containment requirements for
failure, which are inspected at least monthly, and for which all sides are bulk storage in §112.8(C)(2).
visible (i.e., the container has no contact with the ground), visual
inspection alone might be considered to provide equivalent environmental . ,
protection, subject to good engineering practice (67 FR 47120). In fact, \~*s ,',, ,.'.. >.% r
-*—
certain industry standards also reference these conditions as good * "~\ ~"Y' •/""
engineering practice. For example, elevating storage drums on an H •.:...-.- •,, -....-, - ,
appropriately designed storage rack (as shown in Figure 7-2) such that all t
sides are visible allows the effective visual inspection of containers for
early signs of deterioration and leakage, and is therefore considered
environmentally equivalent to the requirement for integrity testing beyond
visual inspection for these smaller bulk storage containers. Note that the
drums, even if elevated, remain subject to the bulk storage secondary containment requirements in
§112.8(c)(2) or§112.12(c)(2). Determination of environmental equivalence is subject to good
engineering practice, including consideration of industry standards, as certified by the PE in
accordance with §112.3(d).
Scenario 2: Single-Use Bulk Storage Containers. For containers that are single-use and
for dispensing only (i.e., the container is not refilled), EPA recognizes that industry standards
typically require only visual examination by the owner/operator. Since these containers are
single-use, internal or comparative integrity testing for corrosion is 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 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. Typically, good engineering practice recommends that these containers be elevated
(usually on pallets or other support structures) to minimize bottom corrosion and to facilitate a visual
inspection of all sides of the container to detect any leaks during the regular owner/operator
inspections outlined in the Plan. Determination of environmental equivalence is subject to good
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engineering practice, including consideration of industry standards, as certified by the PE in
accordance with §112.3(d).
When the container is fully emptied and meets the definition of a permanently closed
container (§112.2) (including labeling), it is not subject to the SPCC requirements, including the
integrity testing requirements. In this case, the capacity of the container does not count toward the
facility threshold capacity. If the container is refilled on site, however, it is not considered a
single-use container, and is therefore subject to the integrity testing requirements of the rule.
Scenario 3: Elevated shop-built containers. For Rgure 7^ Shop.built containers elevated
certain shop-built containers with a shell capacity of 30,000 on saddles.
gallons or under, EPA considers that visual inspection
provides equivalent environmental protection when
accompanied by certain additional actions to ensure that the
containers are not in contact with the soil. These actions
include elevating the container in a manner that decreases
corrosion potential and makes all sides of the container,
including the bottom, visible during inspection. Examples of
adequate measures include elevating shop-built containers
on properly designed tank saddles as illustrated in Figure 7-3
and described in EPA's letter to PMAA.7 Determination of environmental equivalence is subject to
good engineering practice, including consideration of industry standards, as certified by the PE in
accordance with §112.3(d).
V
Scenario 4: Shop-built containers placed on a liner. For certain shop-built containers
with a shell capacity of 30,000 gallons or under, visual inspection, plus certain additional actions to
ensure the containment and detection of leaks, is also considered by EPA to provide equivalent
environmental protection. Actions may include placing the containers onto a barrier between the
container and the ground, designed and operated in a way that ensures that any leaks are
immediately detected. For example, placing a shop-built container on an adequately designed,
maintained, and inspected synthetic liner would generally provide equivalent environmental
protection. Determination of environmental equivalence is subject to good engineering practice,
including consideration of industry standards, as certified by the PE in accordance with §112.3(d).
Other Situations. Although the scenarios discussed above primarily address shop-built
tanks, environmental equivalence may be used for other types of bulk storage containers, subject to
good engineering practice. 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, and explain how it
achieves equivalent environmental protection (§112.7(a)(2)), while considering good engineering
practice and industry standards. The description of the alternative approach should address how
7 For more information, refer to EPA's letter to the Petroleum Marketers Association of America, available on EPA's
Web site at http://vwvw.epa.gov/oilspill/pdfs/PMAA_letter.pdf.
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the approach complies or deviates from industry inspection standards and how it will be
implemented in the field. For example, if the alternative approach involves the visual inspection of
the containers, the SPCC Plan should describe the key elements of this inspection, including the
inspection frequency and scope, the training and/or qualifications of individuals conducting the
inspections, and the records used to document the inspection. If the alternative measure relies on
engineered systems to mitigate corrosion (e.g., coatings, cathodic protection) or to facilitate early
detection of small leaks, the SPCC Plan should describe how such systems are maintained and
monitored to ensure their effectiveness. For instance, where the alternative measure relies on the
presence of a liner, the Plan should discuss how the liner is adequately designed, maintained, and
inspected. This discussion may consider such factors as life expectancy stated by the
manufacturer (from cut-sheets), as-built specifications, and inspection and maintenance
procedures.
As discussed above, the environmental equivalence provision applies to the inspection and
appropriate integrity testing of bulk storage containers at §§112.8(c)(6), 112.9(c)(3), and
112.12(c)(6). PEs have the flexibility to offer environmental equivalent integrity testing options for
all classes of tanks, including shop-built tanks above 30,000 gallon capacity and field-erected tanks,
if the rationale is provided referencing appropriate industry standards.
7.4 Documentation Requirements and Role of the EPA Inspector
The facility SPCC Plan must describe the scope and schedule of examinations to be
performed on bulk storage containers (as required in §§112.3(d)(1)(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 developed by the PE, in accordance with good engineering
practice. If a PE specifies a hybrid inspection and testing program, then the EPA inspector should
verify that the testing program covers minimum elements for the inspections, the frequency of
inspections, and their scope (e.g., wall thickness, footings, tank supports). See Section 7.5 for a list
of suggested minimum standards.
A hybrid testing program may be appropriate for a facility where an industry inspection
standard does not yet contain enough specificity for a particular facility's universe of tanks and/or
configuration, or while modifications to an 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 this scenario, a hybrid inspection
and testing program may be appropriate. When reviewing the scope and schedule of a hybrid
program, the inspector should review whether an industry inspection standard and appropriate good
engineering practices were used in the development of the hybrid program.
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The facility must maintain records of all visual inspections and integrity testing, as required
bytheSPCCrulein§§112.7(e), 112.8(c)(6), 112.9(c)(3), and 112.12(c)(6). 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. These records should include the frequent inspections performed by
facility personnel. Also, industry standards 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 cover at least the minimum elements and are in
accordance with the PE-certified inspection and testing program. The tank inspection checklist
from Appendix F of 40 CFR part 112, reproduced as Table 7-6 at the end of this chapter, provides
an example of the type of information that may be included on an owner/operator-performed
inspection checklist.
The EPA inspector should review records of frequent visual inspections by facility personnel
as well as regular integrity testing of the container. Comparison records maintained at the facility
will aid in determining a container's suitability for continued service. Both API 653 and STI SP-001
contain details on determining a container's suitability for continued service. Though §112.7(e)
requires retention of all records for a period of three years, industry standards usually recommend
retention of certified inspection and non-destructive examination reports for the life of the container.
In cases where the SPCC Plan has not identified a regularly scheduled inspection and
testing program, the inspector should request information on the anticipated schedule (e.g., when a
baseline has not been established). If the facility has not performed any 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. When the inspection program
establishes inspection priorities for multiple containers, the 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. Such inspections may be visual or
conducted by other means.
The inspector reviewing a maintenance program, such as the flowline maintenance program
required under §112.9(d)(3) for oil production facilities, should verify that the Plan describes how
the flowlines are configured, monitored, and maintained to prevent discharges. The inspector
should also verify that the program is implemented in the field; 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.
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If an impracticability determination is made for secondary containment of flowlines, the EPA
inspector should extensively review the adequacy of the flowline maintenance program along with
the contingency plan (67 FR 47078).
In summary, the EPA inspector should verify that the owner or operator has inspection
reports that document the implementation of the testing, evaluation, or inspection criteria set forth in
the Plan. He/she may also verify whether 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. When an inspection procedure is outlined in the
Plan that does not meet the requirement of §§112.8(c)(6) and 112.12(c)(6) (e.g., a combination of
visual inspection and another testing technique), the 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, evaluation, or inspection procedures do not meet the
standards of common sense, 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 any concerns to assist review and follow-up by the Regional Administrator. 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.
7.5 Summary of Industry Standards and Regulations
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.
Additionally, the section discusses the minimum elements for a so-called "hybrid" inspection
program for unique circumstances for which industry inspections standards do not contain enough
specificity for a given facility's tank universe and configuration, or for which the PE chooses to
deviate from the industry standards based on professional judgement. 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 state and are not considered requirements imposed by EPA,
unless otherwise stated in the regulations.
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. Created by standard-setting
organizations using a consensus process, the standards establish the minimum accepted industry
practice. The SPCC rule (§112.3(d)(1)(iii)) requires that the Plan be prepared in accordance with
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good engineering practices, including the consideration of applicable industry standards. Use of a
particular standard is voluntary. If a standard (or parts of a standard) is incorporated into a facility's
SPCC Plan, then adherence to that standard is mandatory for implementation of the Plan.
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..."
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.
7.5.1 API Standard 653 - Tank Inspection, Repair, Alteration, and Reconstruction
API Standard 653-Tank Inspection, Repair, Alteration, and Reconstruction (API 653)8
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.9
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 welding-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
8 API Standard 653, "Tank Inspection, Repair, Alteration, and Reconstruction," Third Edition, Addendum 1, American
Petroleum Institute, September 2003.
9 See Section 1.1.3 of API Standard 653.
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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.
Section 6 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 or not 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 20 years using these criteria. 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 6.4.3 of the standard), can be used to establish
internal inspection intervals; an RBI may increase or decrease the 20-year 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. Appendix A to API 653 provides background information on
previously published editions of API welded steel storage tank standards. Appendix B details the
approaches that are used to monitor and evaluate the settlement of a tank bottom.10 Appendix 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
1 See Section 1.1.3 of API 653.
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tanks. The requirements for authorized inspector certification are the focus of Appendix D.
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. Technical inquiries related to the standard are the focus of Appendix E. Appendix F
summarizes the non-destructive examination (NDE) requirements for reconstructed and repaired
tanks. Technical inquiries regarding the use of the standard can be made through API's Web site
(www.api.org). Selected responses to technical inquiries are provided in the Technical Inquiry
appendices of the standard.
7.5.2 STI Standard SP-001 - Standard for the Inspection of Aboveground Storage Tanks
STI Standard SP-001 - Standard for the Inspection of Aboveground Storage Tanks
(SP-001)11 provides the minimum inspection requirements and evaluation criteria required to
determine the suitability for continued service of aboveground storage tanks until the next
scheduled inspection. Only aboveground tanks included in the scope of this standard are
applicable for inspection per this standard. Other standards, recommended practices, and other
equivalent engineering and best practices exist that provide alternative inspection requirements for
tanks defined within the scope of this standard and for tanks outside the scope of this standard.
For example, API Standard 653, "Tank Inspection, Repair, Alteration, and Reconstruction," provides
additional information pertaining to tanks built to API 650 and API 12C. 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.
SP-001 applies to the inspection of aboveground storage tanks, including shop-fabricated
tanks, field-erected tanks, and portable containers, as defined in this standard, as well as the
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). At a minimum, the following tank components
shall be inspected (as applicable): tank, supports, anchors, foundation, gauges and alarms,
insulation, appurtenances, vents, release prevention barriers, and spill control systems.
Section 3 addresses safety considerations, and Section 4 addresses AST inspector
qualifications.
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. Table 5.5 (Table of Inspection Schedules) 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
11 STI Standard SP-001, "Standard for the Inspection of Aboveground Storage Tanks," 3rd Edition, Steel Tank
Institute, July 2005.
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certified inspector. The factors used for categorizing tanks include tank size, whether or not 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 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 SP-001.
Section 7 of SP-001 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, respectively. Additional requirements for field-erected tanks are in Appendix B. The final
report should contain elements similar to reports prepared for external inspections.
Section 9 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 packagings,
mainly for drums;
49 CFR part 178.803, Testing and certification of intermediate bulk containers
(IBCs); and
49 CFR part 180.605, or equivalent, for portable container testing and recertification.
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Section 10 addresses the suitability for continued service based on the results of formal
internal and/or external inspections. For ASTs that show signs of damage caused by MIC, the
criteria for assessing their suitability for continued service differ based on the category they fall into
(as per Section 5 of SP-001). Categories refer to the level of reduction of the shell thickness. 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 SP-001, please visit the Steel Tank Institute Web site,
http://www.steeltank.com.
7.5.3 API Recommended Practice 575 - Inspection of Atmospheric and Low-Pressure
Storage Tanks
API Recommended Practice 575 - Inspection of Atmospheric and Low-Pressure Storage
Tanks12 (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 572 covers tanks operating
above 15 psig.) In addition to describing the types of storage tanks and standards for 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. API RP 575 applies only to the inspection of atmospheric and low-pressure
storage tanks that have been in service. Section 1 of API RP 575 introduces the recommended
practice and details its scope. Section 2 lists the references that are cited in the recommended
practice.
Section 3 of API RP 575 describes selected methods for non-destructive examination of
tanks, including ultrasonic thickness measurement, ultrasonic corrosion testing, ultrasonic shear
wave testing, and magnetic flux testing. Section 4 describes the construction materials and design
standards, use, and specific types of atmospheric and low-pressure storage tanks. 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.
Section 6 of API RP 575 addresses inspection frequency; it mainly defers to the inspection
frequency requirements described in API 653. Section 7 covers the methods of inspection and
inspection scheduling. It addresses the external inspection of both in-service and out-of-service
12 API RP 575, "Inspection of Atmospheric and Low-Pressure Storage Tanks," 1st ed., American Petroleum Institute,
November 1995.
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tanks and the internal inspection of out-of-service tanks. Section 7 provides some information
about scheduling tank inspections, but it mostly defers to API 653. Section 8 addresses the
methods for repairing tanks. Recordkeeping and inspection reports are the focus of Section 9,
which stresses the importance of keeping complete records. Appendix A of the recommended
practice provides a typical field record form and history card. Appendix B contains a typical tank
report form. Appendix C provides sample checklists for internal and external tank inspections.
7.5.4 API Recommended Practice 12R1 - Recommended Practice for Setting, Maintenance,
Inspection, Operation, and Repair of Tanks in Production Service
API Recommended Practice 12R1 -Recommended Practice for Setting, Maintenance,
Inspection, Operation, and Repair of Tanks in Production Service (API RP 12R1)13 provides
guidance on new tank installations and maintenance of existing production tanks. These tanks are
often referred to as "upstream" or "extraction and production (E&P) tanks." The recommended
practices are primarily intended for tanks fabricated to API Specifications 12B, D, F, and P that are
employed in on-land production service.14 This said, the basic principles in the recommended
practices can also be applied to other atmospheric tanks that are employed 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.
Sections 1, 2, and 3 of API RP 12R1 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.15 Section 6 details the recommended practices for routine operational and
external and internal condition examinations, internal and external inspections, maintenance of
tanks, and recordkeeping. Table 1 of this recommended practice details 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. Finally,
Section 7 provides guidance for the alteration or repair of various tank components. API RP 12R1
also contains nine appendices detailing the recommended requirements of 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.
13 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.
14 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.
15 Section 7 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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7.5.5 API 570 - Piping Inspection Code: Inspection, Repair, Alteration, and Rerating of
In-service Piping Systems
API 570 - Piping Inspection Code: Inspection, Repair, Alteration, and Rerating of In-service
Piping Systems (API 570)16 covers inspection, repair, alteration, and rerating procedures for metallic
piping systems that have been in service. API 570 was developed for the petroleum refining and
chemical process industries. 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 owner/operator is responsible for implementing a piping system
inspection program, controlling the inspection frequencies, and ensuring the maintenance of piping
systems in accordance with this standard.
Section 5, the first substantive section of the standard, addresses the specific inspection
and testing practices for in-service piping systems. Section 6 addresses the frequency and extent
of inspection of piping. Inspection intervals for piping are based largely on the likelihood and
consequence of failure (i.e., they are risk-based), which takes into account the corrosion rate and
remaining life calculations; piping service classification; applicable jurisdictional requirements; and
the judgement of the inspector, the piping engineer, the piping engineer supervisor, or a corrosion
specialist. Table 6-1 of API 570 provides maximum inspection intervals for piping based on piping
service classification (Class 1 poses the highest risk of an emergency if a leak were to occur; Class
2, which includes the majority of unit process piping, poses an intermediate risk; Class 3 poses the
lowest risk) and the corrosion measurement technique (i.e., thickness measurements or visual
external inspection) that is used. In general, the maximum inspection interval for in-service piping
should be between five years for Class 1 piping to ten years for Class 3 piping.
Section 7 of the standard 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. 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; therefore, API 570 addresses the
inspection of buried piping separately in Section 9. Appendices A, B, C, and D of API 570 address
inspector certification, technical inquiries, examples of repairs, and the external inspection checklist
for process piping, respectively.
16 API 570, "Piping Inspection Code: Inspection, Repair, Alteration, and Rerating of In-service Piping Systems," 2nd
ed., American Petroleum Institute, October 1998.
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7.5.6 API Recommended Practice 574 - Inspection Practices for Piping System
Components
API Recommended Practice 574 - Inspection Practices for Piping System Components (API
RP 574)17 covers inspection practices for piping, tubing, valves (other than control valves), and
fittings used in petroleum refineries and chemical plants. API RP 574 is not specifically intended to
cover specialty items, such as control valves, level gauges, and instrument controls columns, but
many of the inspection methods are applicable to these items. API RP 574 provides more detailed
information about piping system components and inspection procedures than API 570. 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, and fittings. This section of the recommended
practice also addresses the common joining methods used to assemble piping components.
Section 5 of API RP 574 presents the rationale for inspecting the piping system: to maintain safety,
attain reliable and efficient operation, and meet regulatory requirements. The procedures for
monitoring the piping system components for corrosion and inspecting for deterioration are the
focus of Section 6. Section 7 provides guidelines for establishing the frequency and time (i.e., while
equipment is operating or while equipment is shut down) of inspection. Similar to API 570, this
recommended practice uses the following conditions to determine the frequency of inspection: the
consequences of a failure (piping classification, see summary of API 570 for a description), the
degree of risk, the amount of corrosion allowance remaining, the historical data available, and the
regulatory requirements.
Section 8 of API RP 574 outlines the safety precautions that should be taken and
preparatory work that should be performed prior to inspecting the piping system components. The
inspection tools commonly used to inspect piping are tabulated in Section 9 of this recommended
practice. Section 10 details the specific procedures that should be followed when inspecting the
components of the piping system. This section also covers the inspection of underground piping
(Section 10.3) and new construction (Section 10.4). Section 11 describes the procedures a piping
engineer should follow to determine the thickness at which piping and valves and flanged fittings
should be retired. Recordkeeping is the focus of Section 12. Appendix A of the recommended
practice provides an external inspection checklist for process piping.
17 API RP 574, "Inspection Practices for Piping System Components," 2nd ed., American Petroleum Institute, June
1998.
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7.5.7 API Recommended Practice 1110 - Pressure Testing of Liquid Petroleum Pipelines
API Recommended Practice 1110 - Pressure Testing of Liquid Petroleum Pipelines (API RP
1110)18 provides guidance regarding the procedures, equipment, and factors to consider when
pressure testing new and existing liquid petroleum pipelines. 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 under no-flow conditions to verify that the
"test segments have the requisite structural integrity to withstand normal and maximum operating
pressures19 and to verify that they are capable of liquid containment." This testing should be
performed by "test personnel" in accordance with ASME B31.420 and 49 CFR part 195.21
Sections 1 and 2 of API RP 1110 describe the scope of the standard and publications it
references, respectively. Section 3 explains how the pressure testing, performed one segment of
pipe at a time, should be executed. Generally this is done by filling a section of pipe with the testing
medium and increasing the pressure from its static pressure level at a controlled rate. Pipe
connections are tested for leaks during the pressurization and after the test pressure has been
reached.
Complete records of the testing should be kept, including information on any failures, the
places they occurred, and the methods of repair they require in order to comply with ASME B31.4,
49 CFR part 195, and any other applicable regulations. The final part of API RP 1110 is Appendix
A, which provides samples of various test record forms.
7.5.8 API Recommended Practice 579, Fitness-for-Service, Section 3
This recommended practice22 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 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 may be used to evaluate the various types
of degradation or test requirements addressed in API 653.
18 API Recommended Practice 1110, "Pressure Testing of Liquid Petroleum Pipelines," 4th edition, American
Petroleum Institute, March 1997.
19 This does not include low-pressure pneumatic testing.
20 ASME B31.4, "Liquid Transportation Systems for Hydrocarbons, Liquid Petroleum Gas, Anhydrous Ammonia, and
Alcohols."
21 U.S. Department of Transportation. Research and Special Programs Administration (49 CFR part 195).
22 API Recommended Practice 579, "Fitness for Service," I^Edition, American Petroleum Institute, January 2000.
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A brittle fracture assessment may be warranted based on operating conditions and/or the
condition of the AST. API RP 579 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. These methods are based on
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 (Figure 3.2, 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 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: API 653, Section 5, does not allow for an exemption of the hydrostatic test
requirement as API 579 does. API 579 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.
7.5.9 API Standard 2610 - Design, Construction, Operation, Maintenance, and Inspection of
Terminal & Tank Facilities
The standard23 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 a list of specific types of facilities and equipment indicated 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).
Section 4 of the standard covers the site selection and spacing requirements for the design
and construction of new terminal facilities. Section 5 addresses the methods of pollution prevention
23 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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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 such as 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. Section 13 addresses structures, utilities, and yards. Section 14 covers
removal or decommissioning of facilities. All of these sections extensively reference the regulatory
requirements and applicable industry standards.
7.5.10 ASME B31.3-Process Piping
ASME B31.3 - Process Piping24 is the generally accepted standard of minimum safety
requirements for the oil, petrochemical, and chemical 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 three 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, with all remaining fluid services that are not in Category D or Category
M being "Normal." It is the owner's responsibility to select the appropriate fluid service category,
which determines the appropriate examination requirements.
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 can support these qualifications.25 Different types of
examinations performed include visual examinations, radiographic examinations, ultrasonic
examinations, in-process examinations, liquid-penetrant examinations, magnetic-particle
examinations, 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
24 ASME B31.3, "Process Piping: The Complete Guide to ASME B31.3," Charles Becht IV, The American Society of
Mechanical Engineers, 2nd edition, 2004.
25 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.
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be examined for leaks after being put into service. Options for leak testing include hydrostatic tests,
pneumatic tests, hydropneumatic tests, 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.
7.5.11 ASME Code for Pressure Piping B31.4-2002 - Pipeline Transportation Systems for
Liquid Hydrocarbons and Other Liquids
ASME Code for Pressure Piping B31.4-2002 - Pipeline Transportation Systems for
Liquid Hydrocarbons and Other Liquids26 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.
7.5.12 DOT 49 CFR 180.605 - Requirements for Periodic Testing, Inspection, and Repair of
Portable Tanks and Other Portable Containers
Section 180.60527 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
26 ASME Code for Pressure Piping, B31.4-2002, "Pipeline Transportation Systems for Liquid Hydrocarbons and Other
Liquids," The American Society of Mechanical Engineers, revision of ASME B31.4-1998, 2002.
27 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.
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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 IM or UN 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 www.access.gpo.gov/cfr.
7.5.13 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
Airports28 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
28 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.
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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/arp/publications/acs/5230-4A.pdf.)
7.5.14 FAA Advisory Circular 150/5210-20 - Ground Vehicle Operations on Airports
FAA Advisory Circular 150/5210-20 - Ground Vehicle Operations on Airports29 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 accompanied by two appendices containing samples of the
training curriculum and training manual. With regard to the transportation and storage of oil, the
vehicle operator requirements on the airside of an airport require that "no fuel truck shall be brought
into, stored, or parked within 50 feet of a building. Fuel trucks must not be parked within 10 feet
from other vehicles." (See http://www.faa.gov/arp/ACs/5210-20.pdf.)
7.5.15 Suggested Minimum Requirements fora PE-Developed Site-Specific Integrity Testing
Program (Hybrid Testing Program)
Although EPA refers to certain industry standards for inspection and testing, it does not
require that inspections and tests be performed according to a specific standard. The PE may use
industry standards along with other good engineering principles 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.
29 FAA Advisory Circular 150/5210-20, "Ground Vehicle Operations on Airports," Federal Aviation Administration, U.S.
Department of Transportation, June 21, 2002.
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For example, a hybrid testing program may be developed in cases where no specific
industry inspection standard exists to date, as is the case for tanks that contain certain products
such as animal fats and vegetable oils, asphalt, or oils that have a specific gravity greater than 1.0.
Although there are no industry standards specific to integrity testing of bulk storage containers
containing vegetable oils at this time, some facilities with large animal fat and vegetable oil tanks
follow API 653. Additionally, the U.S. Food and Drug Administration (FDA) sets requirements for
food-grade oils, which would need to be followed in addition to EPA's integrity testing requirements.
The following provide recommendations of the minimum elements for a hybrid inspection
program.
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 it is hydraulically sound and not leaking.
For field-erected tanks:
Evaluate foundation;
Evaluate settlement;
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 all welds;
Evaluate coatings and linings;
Evaluate repairs for risk of brittle fracture; and
Evaluate the tank to determine 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
an inspector should only certify an inspection to the extent he/she is qualified to do so. A registered
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PE may be able to perform the hybrid inspection, but could also have a certified inspector (e.g., STI
or API) complete the inspection. Either way, the hybrid inspection should be reviewed and certified
by a PE in accordance with §112.3(d). Note that industry inspection standards require the
inspector's certification number on these reports.
EPA also recommends that the hybrid inspection program include frequent (e.g., monthly),
visual examinations of the tank by the tank owner. Such an examination may include the following
elements:
Foundation: Structurally sound and there is adequate drainage away from tank
(yes/no)
Tank bottom: Shows visible signs of leakage (yes/no)
Tank shell: Shows distortions, visible leaks, seepage at seam, external corrosion
(yes/no)
Condition of coatings and insulation (satisfactory/unsatisfactory)
Roof: Hatches securely closed, roof distortions, visible signs of holes, external
corrosion, adequate drainage (yes/no)
Condition of coatings and insulation (satisfactory/unsatisfactory)
Appurtenances: Thief hatch seals properly; thief hatch operational; vent valve
operational; drain and sample valves do not leak; piping properly supported off tank;
stairways, ladders, and walkways sound (yes/no)
Miscellaneous: Cathodic protection and automatic tank gauging is operational, tank
area is clean of trash and vegetation (yes/no)
The inspector may review checklists used by facility personnel to conduct the frequent (e.g.,
monthly) inspections.
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Table 7-5 summarizes the facility components covered by select industry standards and
recommended practices for tanks, valves, pipes, and appurtenances. Additional standards and/or
manufacturers' standards may also apply. The recommended standards for facility personnel to
use for inspecting and testing at a particular facility would be specified in the SPCC Plan by the PE
preparing the Plan. 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).
Table 7-5. Checklist summary of 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
Plastic tanks
Container supports or foundation
Buried metallic storage tank
Tank car or tank truck
Diked area
Aboveground valves, piping, and appurtenances
Underground piping
Offshore valves, piping, and appurtenances
Steam return and exhaust lines
Field drainage systems, oil traps, sumps, and/or
skimmers
Potentially Relevant Standards and
Recommended Practices
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SPCC Guidance for Regional Inspectors
Table 7-6, tank inspection checklist, provides an example of the type of information that may be
included on an owner/operator-performed inspection checklist.
Table 7-6. Tank inspection checklist (from Appendix F of 40 CFR part 112).
I.
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.
U.S. Environmental Protection Agency
7-42
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Appendix A
APPENDIX A: TEXT OF CWA 311 (j)(1 )(c)
U.S. Environmental Protection Agency Version 1.0, 11/28/2005
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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...
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Appendix B
APPENDIX B: SELECT REGULATIONS
40 CFR part 109
40 CFR part 110
40 CFR part 112
U.S. Environmental Protection Agency Version 1.0, 11/28/2005
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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
actions.
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 (7-1-05 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, 33U.S.C. 1151 et seq.
§ 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
regional 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.O. 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 seq., 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 (7-1-05 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 wa-
ters:
(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) (800-424-
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 DCS 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
Sec.
Subpart A—Applicability, Definitions, and
General Requirements For All Facilities
and All Types of Oils
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 [Reserved]
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.
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 for on-
shore facilities (excluding production fa-
cilities).
112.13 Spill Prevention, Control, and Coun-
termeasure Plan requirements for on-
shore oil production facilities.
112.14 Spill Prevention, Control, and Coun-
termeasure Plan requirements for on-
shore oil drilling and workover facilities.
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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) (800-424-
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 DCS 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
Sec.
Subpart A—Applicability, Definitions, and
General Requirements For All Facilities
and All Types of Oils
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 [Reserved]
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.
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 for on-
shore facilities (excluding production fa-
cilities).
112.13 Spill Prevention, Control, and Coun-
termeasure Plan requirements for on-
shore oil production facilities.
112.14 Spill Prevention, Control, and Coun-
termeasure Plan requirements for on-
shore oil drilling and workover facilities.
19
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§112.1
40 CFR Ch. I (7-1-05 Edition)
112.15 Spill Prevention, Control, and Coun-
termeasure Plan requirements for off-
shore oil drilling, production, or
workover facilities.
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
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
AUTHORITY: 33 U.S.C. 1251 et seq.; 33 U.S.C.
2720; E.O. 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
20
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Environmental Protection Agency
§112.1
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
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).
(iii) 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 gallons or
less of oil. For purposes of this exemp-
tion, the completely buried storage ca-
pacity of a facility excludes the capac-
ity of a completely buried tank, as de-
fined in §112.2, and connected under-
ground piping, underground ancillary
equipment, and containment systems,
that is currently subject to all of the
technical requirements of part 280 of
this chapter or all of the technical re-
quirements of a State program ap-
proved under part 281 of this chapter.
The completely buried storage capac-
ity of a facility also excludes the ca-
pacity of a container that is "perma-
nently closed," as defined in § 112.2.
(ii) The aggregate aboveground stor-
age capacity of the facility is 1,320 gal-
lons or less of oil. For purposes of this
exemption, only containers of oil with
a capacity of 55 gallons or greater are
counted. The aggregate aboveground
storage capacity of a facility excludes
the capacity of a container that is
"permanently closed," as defined in
§112.2.
(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, except that
such a tank must be marked on the fa-
cility 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.
(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
21
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§112.2
40 CFR Ch. I (7-1-05 Edition)
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 mail or
by personal delivery. If the owner or
operator is a corporation, the Regional
Administrator must also mail 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 mail or by personal
delivery. If the owner or operator is a
corporation, the Regional Adminis-
trator must also mail 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
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.
§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
22
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Environmental Protection Agency
§112.2
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 reinjection 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
buried 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
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, structure,
installation, equipment, pipe, or pipe-
line (other than a vessel or a public
vessel) used in oil well drilling oper-
ations, oil production, oil refining, oil
storage, oil gathering, oil processing,
oil transfer, oil distribution, and waste
treatment, or in which oil is used, as
described in Appendix A to this part.
The boundaries of a facility depend on
23
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§112.2
40 CFR Ch. I (7-1-05 Edition)
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.
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.
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.
Navigable waters means the waters of
the United States, including the terri-
torial seas.
(1) The term includes:
(i) All waters that are currently used,
were used in the past, or may be sus-
ceptible to use in interstate or foreign
commerce, including all waters subject
to the ebb and flow of the tide;
(ii) All interstate waters, including
interstate wetlands;
(iii) All other waters such as intra-
state 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 inter-
state or foreign commerce including
any such waters:
(A) That are or could be used by
interstate or foreign travelers for rec-
reational or other purposes; or
(B) From which fish or shellfish are
or could be taken and sold in interstate
or foreign commerce; or,
(C) That are or could be used for in-
dustrial purposes by industries in
interstate commerce;
(iv) All impoundments of waters oth-
erwise defined as waters of the United
States under this section;
(v) Tributaries of waters identified in
paragraphs (l)(i) through (iv) of this
definition;
(vi) The territorial sea; and
(vii) Wetlands adjacent to waters
(other than waters that are themselves
wetlands) identified in paragraph (1) of
this definition.
(2) Waste treatment systems, includ-
ing treatment ponds or lagoons de-
signed to meet the requirements of the
CWA (other than cooling ponds which
also meet the criteria of this defini-
tion) are not waters of the United
States. Navigable waters do not in-
clude prior converted cropland. Not-
withstanding the determination of an
area's status as prior converted crop-
land by any other Federal agency, for
the purposes of the CWA, the final au-
thority regarding CWA jurisdiction re-
mains with EPA.
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
24
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Environmental Protection Agency
§112.2
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 Spill Removal Organization 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.
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.
Production facility means all struc-
tures (including but not limited to
wells, platforms, or storage facilities),
piping (including but not limited to
flowlines or gathering lines), or equip-
ment (including but not limited to
workover equipment, separation equip-
ment, or auxiliary non-transportation-
related equipment) used in the produc-
tion, extraction, recovery, lifting, sta-
bilization, separation or treating of oil,
or associated storage or measurement,
and located in a single geographical oil
or gas field operated by a single oper-
ator.
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
25
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§112.3
40 CFR Ch. I (7-1-05 Edition)
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
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.
§112.3 Requirement to prepare and
implement a Spill Prevention, Con-
trol, and Countermeasure Plan.
The owner or operator of an onshore
or offshore facility subject to this sec-
tion must prepare a Spill Prevention,
Control, and Countermeasure Plan
(hereafter "SPCC Plan" or "Plan)," in
writing, and in accordance with §112.7,
and any other applicable section of this
part.
(a) If your onshore or offshore facil-
ity was in operation on or before Au-
gust 16, 2002, you must maintain your
Plan, but must amend it, if necessary
to ensure compliance with this part, on
or before February 17, 2006, and must
implement the amended Plan as soon
as possible, but not later than August
18, 2006. If your onshore or offshore fa-
cility becomes operational after Au-
gust 16, 2002, through August 18, 2006,
and could reasonably be expected to
have a discharge as described in
§112.l(b), you must prepare a Plan on
or before August 18, 2006, and fully im-
plement it as soon as possible, but not
later than August 18, 2006.
(b) If you are the owner or operator
of an onshore or offshore facility that
becomes operational after August 18,
2006, 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.
(c) If you are the owner or operator
of an onshore or offshore mobile facil-
ity, such as an onshore drilling or
workover rig, barge mounted offshore
drilling or workover rig, or portable
fueling facility, you must prepare, im-
plement, and maintain a facility Plan
as required by this section. You must
maintain your Plan, but must amend
and implement it, if necessary to en-
sure compliance with this part, on or
before August 18, 2006. If your onshore
or offshore mobile facility becomes
operational after August 18, 2006, and
could reasonably be expected to have a
discharge as described in §112.1(b), you
must prepare and implement a Plan be-
fore you begin operations. This provi-
sion does not require that you prepare
a new Plan each time you move the fa-
cility to a new site. The Plan may be a
general Plan. When you move the mo-
bile or portable facility, you must lo-
cate and install it using the discharge
prevention practices outlined in the
Plan for the facility. The Plan is appli-
cable only while the facility is in a
fixed (non-transportation) operating
mode.
(d) A licensed Professional Engineer
must review and certify a Plan for it to
be effective to satisfy the requirements
of this part.
(1) By means of this certification the
Professional Engineer attests:
(i) That he is familiar with the re-
quirements of this part ;
(ii) That he or his agent has visited
and examined the facility;
(iii) 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.
(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.
26
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Environmental Protection Agency
§112.4
(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-site 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:
(i) A full explanation of the cause for
any such delay and the specific aspects
of the Plan affected by the delay;
(ii) A full discussion of actions being
taken or contemplated to minimize or
mitigate such delay; and
(iii) 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.
[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]
§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
27
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§112.5
40 CFR Ch. I (7-1-05 Edition)
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
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
28
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Environmental Protection Agency
§112.7
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) Have a Professional Engineer cer-
tify any technical amendment to your
Plan in accordance with § 112.3(d).
§112.6 [Reserved]
§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,
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. Your
Plan may deviate from the require-
ments in paragraphs (g) , (h) (2) and (3) ,
and (i) of this section and the require-
ments in subparts B and C of this part,
except the secondary containment re-
quirements in paragraphs (c) and (h)(l)
of this section, and
112.12(c)(ll),112.13(c)(2), and 112.14(c),
where applicable to a specific facility,
if you provide equivalent environ-
mental protection by some other
means of spill prevention, control, or
countermeasure. Where your Plan does
not conform to the applicable require-
ments in paragraphs (g), (h)(2) and (3),
and (i) of this section, or the require-
ments of subparts B and C of this part,
except the secondary containment re-
quirements in paragraphs (c) and (h)(l)
of this section, and §§ 112.8(c)(2),
112.12(c)(2), 112.12(c)(ll), 112.13(c)(2), and
112.14(c), you must state the reasons for
nonconformance in your Plan and de-
scribe in detail alternate methods and
how you will achieve equivalent envi-
ronmental protection. If the Regional
Administrator determines that the
measures described in your Plan do not
provide equivalent environmental pro-
tection, he may require that you
amend your Plan, following the proce-
dures 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 con-
tainer. The facility diagram must in-
clude completely buried 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. You must also address in your
Plan:
(i) The type of oil in each container
and its storage capacity;
29
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§112.7
40 CFR Ch. I (7-1-05 Edition)
(ii) Discharge prevention measures
including procedures for routine han-
dling of products (loading, unloading,
and facility transfers, etc.);
(iii) 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
(vi) 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;
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). The entire con-
tainment 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 preven-
tion 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 or drip pans; or
(ii) Sumps and collection systems.
(d) If you determine that the instal-
lation 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
112.13(c)(2), and 112.14(c) to prevent a
discharge as described in §112.1(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 con-
tainers, conduct both periodic integ-
rity testing of the containers and peri-
odic 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.
30
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Environmental Protection Agency
§112.7
(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.
(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.l(b) or failures, malfunctioning
components, and any recently devel-
oped precautionary measures.
(g) Security (excluding oil production
facilities). (1) 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.
(2) Ensure that the master flow and
drain valves and any other valves per-
mitting direct outward flow of the con-
tainer's contents to the surface have
adequate security measures so that
they remain in the closed position
when in non-operating or non-standby
status.
(3) Lock the starter control on each
oil pump in the "off" position and lo-
cate it at a site accessible only to au-
thorized personnel when the pump is in
a non-operating or non-standby status.
(4) Securely cap or blank-flange the
loading/unloading connections of oil
pipelines or facility piping when not in
service or when in standby service for
an extended time. This security prac-
tice also applies to piping that is
emptied of liquid content either by
draining or by inert gas pressure.
(5) Provide facility lighting commen-
surate with the type and location of
the facility that will assist in the:
(i) Discovery of discharges occurring
during hours of darkness, both by oper-
ating personnel, if present, and by non-
operating personnel (the general pub-
lic, local police, etc.); and
(ii) Prevention of discharges occur-
ring through acts of vandalism.
(h) Facility tank car and tank truck
loading/unloading rack (excluding off-
shore facilities). (1) Where loading/un-
loading area 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 unload-
ing areas. You must design any con-
tainment system to hold at least the
maximum capacity of any single com-
partment of a tank car or tank truck
loaded or unloaded at the facility.
(2) Provide an interlocked warning
light or physical barrier system, warn-
ing signs, wheel chocks, or vehicle
break interlock system in loading/un-
loading areas to prevent vehicles from
departing before complete disconnec-
tion 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
31
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§112.8
40 CFR Ch. I (7-1-05 Edition)
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.
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-
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.
(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 con-
tainer 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 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:
(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).
32
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Environmental Protection Agency
§112.8
(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 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 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.
(5) Not use partially buried or
bunkered metallic tanks for the stor-
age of oil, unless you protect the bur-
ied section of the tank from corrosion.
You must protect partially buried and
bunkered tanks from corrosion by
coatings or cathodic protection com-
patible with local soil conditions.
(6) Test each aboveground container
for integrity on a regular schedule, and
whenever you make material repairs.
The frequency of and type of testing
must take into account container size
and design (such as floating roof, skid-
mounted, elevated, or partially buried).
You must combine visual inspection
with another testing technique such as
hydrostatic testing, radiographic test-
ing, ultrasonic testing, acoustic emis-
sions testing, or another system of
non-destructive shell testing. You
must keep comparison records and you
must also inspect the container's sup-
ports and foundations. In addition, you
must frequently inspect the outside of
the container for signs of deteriora-
tion, discharges, or accumulation of oil
inside diked areas. Records of inspec-
tions and tests kept under usual and
customary business practices will suf-
fice for purposes of this paragraph.
(7) Control leakage through defective
internal heating coils by monitoring
the steam return and exhaust lines for
contamination from internal heating
coils 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:
(i) 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.
(ii) High liquid level pump cutoff de-
vices set to stop flow at a predeter-
mined container content level.
(iii) 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). You
must furnish a secondary means of con-
tainment, such as a dike or catchment
basin, sufficient to contain the capac-
ity of the largest single compartment
or container with sufficient freeboard
to contain precipitation.
(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,
33
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§112.9
40 CFR Ch. I (7-1-05 Edition)
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.
§112.9 Spill Prevention, Control, and
Counternieasure Plan requirements
for onshore oil production facilities.
If you are the owner or operator of an
onshore production 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.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 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) Provide all tank battery, separa-
tion, and treating facility installations
with a secondary means of contain-
ment 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) Periodically and upon a regular
schedule visually inspect each con-
tainer 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.
(iii) 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.
(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
34
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Environmental Protection Agency
§112.11
following a sudden change in atmos-
pheric temperature, to detect possible
system upsets capable of causing a dis-
charge.
(3) Have a program of flowline main-
tenance to prevent discharges from
each flowline.
§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
§112.l(b).
(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.
§112.11 Spill Prevention, Control, and
Counternieasure 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
35
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§112.12
40 CFR Ch. I (7-1-05 Edition)
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
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 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-
site wastewater treatment plant, you
must inspect and may drain
uncontaminated retained stormwater,
subject to the requirements of para-
graphs (c)(3)(ii), (iii), 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
36
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Environmental Protection Agency
§112.12
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 con-
tainer 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 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:
(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 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 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.
(5) Not use partially buried or
bunkered metallic tanks for the stor-
age of oil, unless you protect the bur-
ied section of the tank from corrosion.
You must protect partially buried and
bunkered tanks from corrosion by
coatings or cathodic protection com-
patible with local soil conditions.
(6) Test each aboveground container
for integrity on a regular schedule, and
whenever you make material repairs.
The frequency of and type of testing
must take into account container size
and design (such as floating roof, skid-
mounted, elevated, or partially buried).
You must combine visual inspection
with another testing technique such as
hydrostatic testing, radiographic test-
ing, ultrasonic testing, acoustic emis-
sions testing, or another system of
non-destructive shell testing. You
must keep comparison records and you
must also inspect the container's sup-
ports and foundations. In addition, you
must frequently inspect the outside of
the container for signs of deteriora-
tion, discharges, or accumulation of oil
inside diked areas. Records of inspec-
tions and tests kept under usual and
customary business practices will suf-
fice for purposes of this paragraph.
(7) Control leakage through defective
internal heating coils by monitoring
the steam return and exhaust lines for
contamination from internal heating
coils 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:
(i) High liquid level alarms with an
audible or visual signal at a constantly
37
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§112.13
40 CFR Ch. I (7-1-05 Edition)
attended operation or surveillance sta-
tion. In smaller facilities an audible air
vent may suffice.
(ii) High liquid level pump cutoff de-
vices set to stop flow at a predeter-
mined container content level.
(iii) 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). You
must furnish a secondary means of con-
tainment, such as a dike or catchment
basin, sufficient to contain the capac-
ity of the largest single compartment
or container with sufficient freeboard
to contain precipitation.
(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.
§112.13 Spill Prevention, Control, and
Counternieasure Plan requirements
for onshore oil production facilities.
If you are the owner or operator of an
onshore production 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.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
§112.12(c)(3)(ii), (iii), 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
38
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Environmental Protection Agency
§112.15
the storage of oil unless its material
and construction are compatible with
the material stored and the conditions
of storage.
(2) Provide all tank battery, separa-
tion, and treating facility installations
with a secondary means of contain-
ment 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) Periodically and upon a regular
schedule visually inspect each con-
tainer 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.
(iii) 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.
(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) Have a program of flowline main-
tenance to prevent discharges from
each flowline.
§112.14 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
§112.l(b).
(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.
§112.15 Spill Prevention, Control, and
Counternieasure 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,
39
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§112.20
40 CFR Ch. I (7-1-05 Edition)
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 that 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
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 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
40
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Environmental Protection Agency
§112.20
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
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.
(ii) 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).
(iii) 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) (1) (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.
41
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§112.20
40 CFR Ch. I (7-1-05 Edition)
(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.
(iii) 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)(ii) 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;
42
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Environmental Protection Agency
§112.20
(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;
(iii) 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
(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 organi-
zation^) 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-issued 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) (1) 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)(ii)(B) or (f) (1) (ii) (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 At-
tachment C-I to Appendix C to this
part:
(i) 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
(ii) 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;
43
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§112.20
40 CFR Ch. I (7-1-05 Edition)
(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)(i) 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;
(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)(i) of this section. Such petition
shall include a discussion of how the
factors in paragraph (f) (2) (i) 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;
(iii) 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
44
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Environmental Protection Agency
§112.20
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 Appen-
dix 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)
of this section and the appropriate Fed-
eral officials and the persons providing
response personnel and equipment can
be ensured;
(iii) 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 appro-
priate, shall clearly demonstrate in the
response 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;
(iii) 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;
45
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§112.20
40 CFR Ch. I (7-1-05 Edition)
(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;
(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
(iii) 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;
46
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Environmental Protection Agency
§112.21
(ii) A description of the equipment to
be used for each scenario;
(iii) 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;
(iii) 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
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 (i)(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).
47
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Pt. 112, App. A
40 CFR Ch. I (7-1-05 Edition)
(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]
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.
48
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Environmental Protection Agency
Pt. 112, App. B
(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
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 FR 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(1) 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 wa-
ters."
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.
49
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Pt. 112, App. C
40 CFR Ch. I (7-1-05 Edition)
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]
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, Erie, 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 Christ!, 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 (COLREG 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.
50
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Environmental Protection Agency
Pt. 112, App. C
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).
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
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 FR 7353, February 5, 1993).
This document is available through EPA's
rulemaking docket as noted in Appendix E to
this part, section 13.
51
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Pt. 112, App. C 40 CFR Ch. I (7-1-05 Edition)
ATTACHMENTS TO APPENDIX 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).
52
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Environmental Protection Agency
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 formulal) 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 E 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 formula!) 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,
1 If 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 wa-
ters. EPA has determined that the primary
concern for calculation of a planning dis-
tance is the transport of oil in navigable wa-
ters 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) (1) (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
53
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Pt. 112, App. C
40 CFR Ch. I (7-1-05 Edition)
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
1 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 E
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 sensitive
environments could be injured or a public
drinking water intake would be shut down
in the event of an oil discharge (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 seem 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%xsV2; 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-chan-
nel depth of the river (in feet) by 0.667
54
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Environmental Protection Agency
Pt. 112, App. C
(sources for obtaining the mid-channel
depth are listed in Table 2 of this attach-
ment); 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):
Major Streams (Top Width >100 ft.)
Regular section:
(No boulders/brush)
Irregular section:
(Brush)
Rough-
ness co-
efficient
(n)
0.03
0.04
006
0 10
0.035
005
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) 998-4931
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
55
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Pt. 112, App. C
40 CFR Ch. I (7-1-05 Edition)
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/nxr2/3xs1/2:
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
56
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Environmental Protection Agency
Pt. 112, App. C
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=105xV3/4xC
C=0.1643
Ai=105x(2,000,000gallons)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., East Providence, Rhode Island.
3 Oil Spill Prevention & Control. National
Spill Control School, Corpus Christi 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
57
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Pt. 112, App. C
40 CFR Ch. I (7-1-05 Edition)
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, X i, to a storm drain or an
open concrete channel leading to navigable
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 sensitive
4 The design velocities were obtained from
Howard County, Maryland Department of
Public Works' Storm Drainage Design Man-
ual.
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 navi-
gable 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.
58
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Environmental Protection Agency
Pt. 112, App. C
[59 FR 34102, July 1, 1994, as amended at 65 FR 40798, June 30, 2000; 67 FR 47152, July 17, 2002]
59
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Pt. 112, App. D
40 CFR Ch. I (7-1-05 Edition)
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 E 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 FACILITIES '
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.
'"Storage facilities" represent all facili-
ties subject to this part, excluding oil pro-
duction facilities.
60
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Environmental Protection Agency
Pt. 112, App. D
A.2 SECONDARY CONTAINMENT—
MUL TIPLE- TANK FA CILITIES
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).
3 All 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—
MUL TIPLE- TANK FA CILITIES
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.
61
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Pt. 112, App. D
40 CFR Ch. I (7-1-05 Edition)
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.
4 All 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
volume 2).
(1) For wells 10,000 feet deep or less:
Discharge volume^ [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 volume^ [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 calculate
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 volume 2=[30 days—(7 days + 2
days)] x (10 barrels per day) x (0.5)=105 bar-
rels
(4) Therefore, the production volume is:
Production volume=90 barrels + 105
barrels=195 barrels
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Pt. 112, App. E
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 (COLREG 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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40 CFR Ch. I (7-1-05 Edition)
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 E 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 capacityequal to the
amount of oil discharged in a small dis-
charge or greater which is available at the
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Environmental Protection Agency
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 EPA'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 EPA'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-
Pt. 112, App. E
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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Pt. 112, App. E
40 CFR Ch. I (7-1-05 Edition)
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 E-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.
5.1 A facility owner or operator shall
identify and ensure the availability of, by
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 E-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
Great Lakes
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^) 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
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Environmental Protection Agency
Pt. 112, App. E
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-
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 E 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 E
where:
R—Effective daily recovery capacity;
T—Throughput rate in barrels per hour
(nameplate capacity); and
E—20 percent efficiency factor (or lower fac-
tor as determined by the Regional Admin-
istrator) .
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 ¥4 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 EPA
as deemed appropriate (see Appendix E 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 facility
owner or operator can demonstrate that
the recovery operation can be sustained for
longer periods.
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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
(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
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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
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 E 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;
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40 CFR Ch. I (7-1-05 Edition)
(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.
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.
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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 EPA'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
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 EPA'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
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40 CFR Ch. I (7-1-05 Edition)
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.
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
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Pt. 112, App. E
(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.
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
Mobilization factor by which you multiply planning volume
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
73
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Pt. 112, App. E
40 CFR Ch. I (7-1-05 Edition)
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
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
74
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Environmental Protection Agency
Pt. 112, App. E
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.
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 A vailability
13.1 All materials listed in this section
are part of EPA'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
800-424-9346 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 Reg-
ister 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.
75
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Pt. 112, App. E 40 CFR Ch. I (7-1-05 Edition)
TABLE 1 TO APPENDIX E—RESPONSE RESOURCE OPERATING CRITERIA
Inland
Oil Recovery Devices
Operating environment
Significant wave Sea s(ate
< 1 foot 1
<3feet 2
< 4 feet 2-3
< 6 feet 3-4
Boom
Boom property
Significant Wave Height1
Sea State
Reserve Buoyancy to Weight Ratio
Skirt Fabric Tear Strenath — oounds
Rivers and
canals
< 1
1
6-18
2:1
4500
200
100
Us
Inland
<3
2
18^2
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 in
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
2 — Light crudes
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:
Group
up 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
1.8
2.0
1.4
Inland/Nearshore Great
Operating area
Lakes
Tier 1
030
0.15
Tier 2
040
0.25
Tiers
060
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:
All except Rivers & Canals. Great Lakes
Tier 1
10K bbls/dav
Tier 2
20K bbls/dav
Tiers
40K bbls/dav.
76
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Environmental Protection Agency Pt. 112, App. E
TABLE 5 TO APPENDIX E—RESPONSE CAPABILITY CAPS BY OPERATING AREA—Continued
Rivers & Canals
February 18, 1998:
Rivers & Canals
February 18, 2003:
All except Rivers & Canals, Great Lakes
Great Lakes
Rivers & Canals
Tier 1
5K bbls/day
1.5K bbls/day
1 2 5K bbls/day
6 35K bbls/day
1.875K bbls/
day
TBD
TBD
TBD
Tier 2
1 0K bbls/day
3. OK bbls/day
25K bbls/day
1 2 3K bbls/day
3.75K bbls/day
TBD
TBD
TBD
Tiers
20K bbls/day
6. OK bbls/day.
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 A
Groub 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.
77
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Pt. 112, App. E
40 CFR Ch. I (7-1-05 Edition)
ATTACHMENTS TO APPENDIX 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)
78
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Environmental Protection Agency
Pt. 112, App. E
Attachment B-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 (El) x Step (F> x
Step (G1)
Step (El) x Step (F) x
Step (G2>
Tier 3
Step (El) 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 (J1>
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.
79
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Pt. 112, App. E
40 CFR Ch. I (7-1-05 Edition)
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.
80
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Environmental Protection Agency
Pt. 112, App. E
Attachment E-1 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
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.
81
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Pt. 112, App. E
40 CFR Ch. I (7-1-05 Edition)
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)
82
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Environmental Protection Agency Pt. 112, App. E
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.
83
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Pt. 112, App. E
40 CFR Ch. I (7-1-05 Edition)
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.
84
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Environmental Protection Agency
Pt. 112, App. F
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
Tier 3
80
000
Step (E1) x Step (F) x
Step (01)
Step (E1) x Step (F) x
Step
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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Pt. 112, App. F
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
40 CFR Ch. I (7-1-05 Edition)
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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Environmental Protection Agency
Pt. 112, App. F
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
87
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Pt. 112, App. F
40 CFR Ch. I (7-1-05 Edition)
forms included in the associated sections of
the response plan. Each 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 (SOWA).1
The response plan requirements in the Well-
head Protection Program are outlined by the
!A 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
1-800-426-4791.
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: Phone Number: ( )
Latitude: Degrees Minutes
Seconds
Longitude: Degrees
Seconds
Wellhead Protection Area:
Owner:
Minutes
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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Environmental Protection Agency
Pt. 112, App. F
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
Appendix 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:
89
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Pt. 112, App. F
EMERGENCY NOTIFICATION PHONE LIST WHOM
To NOTIFY
Reporter's Name:
Date:
Facility Name:
Owner Name:
Facility Identification Number:
Date and Time of Each 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
40 CFR Ch. I (7-1-05 Edition)
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: State:
County: Zip:
Distance from City: Units of Measure:
Direction from City:
Section: Township:
Borough:
Range:
Container Type: Tank Oil Storage Ca-
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
90
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Environmental Protection Agency
Pt. 112, App. F
CHRIS Code Discharged quan- unit of mpasurp Material Dis-
GHHIfa oode tjty unit ot measure cnarged in water
Quantity
Unit of measure
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:
EPA?
Caller Notifications
(Y/N) USCG? _
(Y/N)
Other? (Y/N) Describe:
(Y/N) State?
1.3.2 Response Equipment List
Date of Last Update:
FACILITY RESPONSE EQUIPMENT LIST
1. Skimmers/Pumps—Operational Status:
Type, Model, and Year:
Type Model Year
Number:
Capacity: gal./min.
Daily Effective Recovery Rate:
Storage Location(s):
Date Fuel Last Changed:
2. Boom—Operational Status:
Type, Model, and Year:
Type Model Year
Number:
Size (length): ft.
Containment Area:
Storage Location:
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)
91
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Pt. 112, App. F
40 CFR Ch. I (7-1-05 Edition)
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
7. Communication Equipment (include op-
erating frequency and channel and/or cel-
lular phone numbers)—Operational Status:
Type and year
9. Other (e.g.
Motors) — Oper<
Type and year
Quantity
Storage
location
Heavy Equipment, Boats and
ational Status:
Quantity
Storage
location
Type and year
Quantity
Storage location/
number
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:
8. Fire Fighting and Personnel Protective Inspection Frequency
Equipment-Operational Status: Last Deployment Drill Date:
Deployment Frequency:
Type and year
Quantity
Storage
location
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.
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Environmental Protection Agency
Pt. 112, App. F
EMERGENCY RESPONSE CONTRACTORS
Date of Last Update:
Contractor
1.
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.
93
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Pt. 112, App. F
40 CFR Ch. I (7-1-05 Edition)
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 Iden tifica tion
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
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Environmental Protection Agency
Pt. 112, App. F
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
95
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Pt. 112, App. F
40 CFR Ch. I (7-1-05 Edition)
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
Each 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) Materialfs) 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) .
3As 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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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 E 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
1. Stop the product flow
40 CFR Ch. I (7-1-05 Edition)
OIL SPILL RESPONSE—IMMEDIATE ACTIONS—
Continued
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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Environmental Protection Agency
Pt. 112, App. F
(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;
E. cracks; and
F. localized dead vegetation.
2. Check foundation for:
A. cracks;
B. discoloration;
C. puddles containing spilled or leaked ma-
terial;
D. settling;
E. 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;
E. 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
99
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Pt. 112, App. F
40 CFR Ch. I (7-1-05 Edition)
TANK/SURFACE IMPOUNDMENT INSPECTION LOG—Continued
Inspector
Tank or Sl#
Date
Comments
1.8.1.2 Response Equipment Inspection
Using the Emergency Response Equipment sPon >•
List provided in section 1.3.2 of the response
plan, describe each type of response equip-
ment, checking for the following:
3. Accessibility (time to access and re-
Response Equipment Checklist
1. Inventory (item and quantity);
2. Storage location;
RESPONSE EQUIPMENT INSPECTION LOG
[Use section 1.3.2 of the response plan as a checklist]
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.
Inspector
Date
Comments
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Environmental Protection Agency
Pt. 112, App. F
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 E 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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40 CFR Ch. I (7-1-05 Edition)
1.8.2.1 Qualified Individual Notification Drill
Logs
Qualified Individual Notification Drill Log
Date:
Company:
Qualified Individuals):
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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Pt. 112, App. F
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;
(E) 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 adj acent 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;
(E) 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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Pt. 112, App. F
40 CFR Ch. I (7-1-05 Edition)
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
104
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Environmental Protection Agency
Pt. 112, App. F
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 collec-
tion 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:
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:
Largest Aboveground Oil Storage Tank Ca-
pacity (Gallons):
Number of Aboveground Oil Storage Tanks:
Longitude (Degrees: West):
degrees, minutes, seconds
North American Industrial Classification
System (NAICS) Code: 1
Maximum Oil Storage Capacity (Gallons):
Worst Case Oil Discharge Amount (Gallons):
Facility Distance to Navigable Water. Marl*
the appropriate line.
0- Vi mile Vi-Vz mile Vz-l mile
mile
>1
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 containment 2
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-
tance 2 (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
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.
105
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Pt. 113
40 CFR Ch. I (7-1-05 Edition)
gallons and is the facility located at a dis-
tance 2 (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
No
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 spill 2 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,
and that based on my inquiry of those indi-
viduals responsible for obtaining informa-
tion, I believe that the submitted informa-
tion is true, accurate, and complete.
Signature:
Name (Please type or print):
Title:
Date:
[59 FR 34122, July 1, 1994; 59 FR 49006, Sept.
26, 1994, as amended at 65 FR 40816, June 30,
2000; 65 FR 43840, July 14, 2000; 66 FR 34561,
June 29, 2001; 67 FR 47152, July 17, 2002]
PART 113—LIABILITY LIMITS FOR
SMALL ONSHORE STORAGE
FACILITIES
Subpart A—Oil Storage Facilities
Sec.
113.1 Purpose.
113.2 Applicability.
113.3 Definitions.
113.4 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
of the owner or operator and the facil-
ity will be limited to the amounts spec-
ified in §113.4.
§113.3 Definitions.
As used in this subpart, the following
terms shall have the meanings indi-
cated below:
(a) Aboveground storage facility
means a tank or other container, the
bottom of which is on a plane not more
than 6 inches below the surrounding
surface.
(b) Act means the Federal Water Pol-
lution Control Act, as amended, 33
U.S.C. 1151, etseq.
(c) Barrel means 42 United States gal-
lons at 60 degrees Fahrenheit.
(d) Belowground storage facility
means a tank or other container lo-
cated other than as defined as "Above-
ground".
(e) Discharge includes, but is not lim-
ited to any spilling, leaking, pumping,
pouring, emitting, emptying or dump-
ing.
(f) Onshore Oil Storage Facility means
any facility (excluding motor vehicles
and rolling stock) of any kind located
in, on, or under, any land within the
United States, other than submerged
land.
(g) On-Scene Coordinator is the single
Federal representative designated pur-
suant to the National Oil and Haz-
ardous Substances Pollution Contin-
gency Plan and identified in approved
Regional Oil and Hazardous Substances
Pollution Contingency Plans.
(h) 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.
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Appendix C: Summary of Revised Rule Provisions
APPENDIX C: SUMMARY OF REVISED SPCC RULE PROVISIONS
Citation
New Threshold
Requirement
§112.1(d)(2)(i)
and (ii)
Underground
Storage Tanks
(USTs)
§112.1(d)(2)(i)and
112.1(d)(4)
Minimum Container
Size
§112.1(d)(5)
Wastewater
Treatment
§112.1(d)(6)
SPCC Plan
Preparation
§112.1(f)
New Definitions
§112.2
Revised Rule Provision
An owner or operator of a facility that stores more than 1 ,320 gallons in aboveground
containers or 42,000 gallons in completely buried tanks must prepare a Plan. Note:
Completely buried USTs subject to all to the technical requirements of 40 CFR parts
280 or 281 are exempt from the threshold calculation.
Change from 1974 rule: The single container capacity of 660 gallons for the previous
threshold requirement has been eliminated.
Completely buried storage tanks subject to all of the technical requirements under
40 CFR parts 280 or 281 and permanently closed USTs are not required to comply
with SPCC provisions. Note: The facility diagram must include completely buried tanks
that are exempt from § 1 12. 1(d)(4).
Change from 1974 rule: Previously, all USTs were subject to the SPCC provisions
once the facility met any of the SPCC threshold requirements.
A de minimis container capacity of 55 gallons or more has been established to
determine aboveground storage capacity. All containers with a capacity of less than
55 gallons are exempt from the rule.
Change from 1974 rule: Previously all containers, regardless of size, were considered
to be subject to SPCC provisions.
A facility or part thereof, if used exclusively for wastewater treatment, is exempt from
the rule. Note: The production, recovery, or recycling of oil is not considered
wastewater treatment.
Change from 1974 rule: No direct counterpart in the 1974 rule.
The Regional Administrator (RA) has the authority to require a facility, regardless of
exemptions, to prepare an SPCC Plan. This authority will be exercised on a case-by-
case basis.
Change from 1974 rule: No direct counterpart in the 1974 rule.
Definitions for the terms "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," and "wetlands" were added.
Change from 1974 rule: The definition for "spill event" was removed but is now
described as a discharge as described in 1 12.1 (b) Note: A "harmful discharge" is
described in 40 CFR part 110.
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SPCC Guidance for Regional Inspectors
Citation
Oil-Filled Equipment
§112.2
Professional
Engineer (PE)
Certification
§112.3(d)
Plan Location
§112.3(e)(1)
Reportable
Discharge
Notification to EPA
Regional
Administrator (RA)
for SPCC facilities
§112.4
Five-Year Review
Documentation
§112.5(b)and
112.5(c)
Alternative Formats
§112.7
Revised Rule Provision
Oil-filled electrical, operating, and manufacturing equipment does not need to meet the
requirements for bulk storage containers (§1 12.8) as this equipment is excluded from
the definition of a "bulk storage container." However, this equipment does need to
meet other provisions of the rule, including secondary containment as described in
§112.7(c).
Change from 1974 rule: Clarification on the application of the rule to this type of
equipment.
In order for a facility to comply with the provisions of §1 12.3(d), a licensed Professional
Engineer (PE) must attest to the following:
i. The PE is familiar with 40 CFR part 112;
ii. The PE or his agent has visited and examined the facility;
iii. The Plan has been prepared in accordance with good engineering practice,
including consideration of industry standards and the requirements of the rule;
iv. Procedures for required inspections and testing have been established; and
v. The Plan is adequate for the facility.
Change from 1974 rule: The previous rule required a PE to attest that, through the
examination of the facility and familiarity with the provisions of the rule, the Plan was
prepared in accordance with good engineering practice.
The owner or operator must maintain a complete copy of the Plan at the facility if the
facility is normally attended at least four hours per day.
Change from 1974 rule: The rule previously required a Plan to be located at the
facility if it was attended for at least eight hours per day.
Whenever a facility has a discharge as described in §112.1(b) that is greater than
1 ,000 gallons of oil or two discharges each of more than 42 gallons of oil occurring
within any 12-month period, the facility must submit certain information regarding the
spill to the RA. The SPCC Plan does not need to be submitted unless requested by the
RA.
Change from 1974 rule: Previously, the SPCC Plan was submitted to the RA as part
of the reporting requirement, and there was a different threshold for SPCC spill
reporting. Note: The basic oil discharge reporting requirements for 40 CFR 110 (spills
reportable to the National Response Center) did not change.
The period in which an owner or operator is required to review and evaluate the SPCC
Plan is now five years. The review and evaluation must be documented, and a
statement must be signed stating whether or not the Plan will be amended. Note: The
review and evaluation do not require a Professional Engineer (PE) certification.
However, any technical changes to the Plan do require a PE certification.
Change from 1974 rule: The review period was previously three years.
The Plan must be in writing, and if the Plan does not follow the sequence specified in
the rule, an equivalent plan and a cross-reference must be provided. For example, the
owner/operator may use an Integrated Contingency Plan (ICP) or an equivalent state
plan that includes all applicable SPCC requirements with a cross-reference.
Change from 1974 rule: No direct counterpart for alternative plan formats in the 1974
rule.
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Appendix C: Summary of Revised Rule Provisions
Citation
Spill History
Previously
§112.7(a)
Environmental
Equivalence
§112.7(a)(2)
Facility Diagram
§112.7(a)(3)
Information for Use
in a Discharge
§112.7(a)(3)
Information for Use
in a Discharge
§112.7(a)(4)and
112.7(a)(5)
Secondary
Containment
§112.7(c)
Impracticability
Claim/Integrity
Testing
§112.7(d)
Revised Rule Provision
Spill history does not need to be reported. Note: Facility Response Plans (FRPs) are
still required to include a spill history.
Change from 1974 rule: The previous rule required a spill history for reportable
discharges, including corrective actions and preventive measures for spills occurring
before the effective date of the 1974 rule. This requirement has been eliminated in the
2002 rule.
Where a facility does not conform with SPCC provisions, the owner or operator must
state the reason for nonconformance and describe, in detail, alternate methods to
achieve equivalent environmental protection. Note: This waiver does not apply to any
secondary containment requirements.
Change from 1974 rule: No direct counterpart in the 1974 rule.
The facility is required to prepare a facility diagram that includes the location and
contents of containers, transfer stations, and connecting pipes. The facility diagram
must also include exempt USTs.
Change from 1974 rule: No direct counterpart in the 1974 rule.
The owner or operator must provide, in the Plan, information and procedures relating
to basic spill prevention, reporting (contact list with phone numbers), and response.
The specific information is listed in the rule text. Note: This subparagraph applies to all
facilities.
Change from 1974 rule: No direct counterpart in the 1974 rule.
Unless the facility has submitted a response plan under §1 12.20, the owner or operator
must provide, in the Plan, information and procedures to enable a person reporting a
discharge to relate the necessary information. The plan must have an organization that
will make it readily usable in an emergency. The necessary information is listed in the
rule text.
Change from 1974 rule: No direct counterpart in the 1974 rule.
The entire containment system must be able to contain oil and prevent a discharge
from a primary containment system from escaping the confines of the containment
system before cleanup occurs.
Change from 1974 rule: The new language clarifies the requirement in the previous
rule that containment and/or diversionary structures must "prevent discharged oil from
reaching a navigable water course."
When it is not practicable to install secondary containment, the owner/operator must
clearly explain why, and for bulk storage containers, conduct both periodic integrity
testing of the containers and periodic integrity and leak testing of the valves and piping.
Note: Facilities must still prepare an oil spill contingency plan following 40 CFR part
109 and a have written commitment of resources to respond to and clean up a
discharge.
Change from 1974 rule: The previous rule did not require integrity testing or leak
testing if an impracticability claim was made for secondary containment for bulk
storage containers.
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SPCC Guidance for Regional Inspectors
Citation
Business Records
§§112.7(e)and
112.8(c)(6)
Employee Training
§112.7(1)
Brittle Fracture
Evaluation
§112.70)
Secondary
Containment
Onshore facilities
§112.8(c)(2)
Onshore production
facilities
§112.9(c)(2)
Integrity Testing per
Industry Standards
§112.8(c)(6)
Cathodic Protection
§112.8(d)(1)
Reorganization/
Plain Language
Format
Revised Rule Provision
An owner or operator may use usual and customary business records to satisfy the
recordkeeping requirements for inspections and tests. Written procedures and a
record of inspections and tests must be maintained for three years.
Change from 1974 rule: Previously, the rule required maintenance of a record of
inspections and tests for three years but did not allow for the use of usual and
customary business records.
Training is required for oil-handling personnel, and the revised rule supplies additional
topics for this training. Discharge prevention briefings must be conducted at least once
a year.
Change from 1974 rule: The revised rule requires training only for oil-handling
personnel and not for all employees. It also clarifies that briefings must be conducted
once a year, instead of intervals "frequent enough to assure adequate understanding
of the SPCC Plan for that facility."
The rule requires evaluations for field-constructed aboveground storage containers
undergoing repair, alteration, reconstruction, or a change in service.
Change from 1974 rule: No direct counterpart in the 1974 rule.
Onshore facilities (including production facilities) must ensure that secondary
containment has sufficient freeboard to allow for precipitation. Whatever method used
must be documented in the Plan.
Change from 1974 rule: Onshore facilities were required to provide sufficient
freeboard to allow for precipitation, though the previous rule did not specify that an
allowance for precipitation was required for production facilities.
Facilities must test aboveground containers for integrity on a regular schedule, and
whenever material repairs are made. Testing must combine visual inspection with
another non-destructive shell thickness testing technique. A list of organizations that
may be helpful in the identification and explanation of industry standards is included in
the rule preamble.
Change from 1974 rule: Previously, the rule stated that integrity testing should occur
periodically and did not require the combination of a visual inspection with another non-
destructive shell thickness testing technique.
All buried piping that is installed or replaced on or after August 16, 2002, must have
protective wrapping and coating as well as cathodic protection, for all soil conditions.
Note: A facility can also satisfy the corrosion protection provisions through 40 CFR part
280 or a state program approved under 40 CFR part 281.
Change from 1974 rule: The previous rule required cathodic protection for buried
piping if soil conditions warranted such protection. It did not allow for satisfaction of the
provision through 40 CFR part 280 or a state program approved under 40 CFR part
281.
Included are new sections for different types of facilities and new subparts for different
types of oils in compliance with Edible Oil Regulatory Reform Act (EORRA.) The rule
has been written in a plain language format to make it clearer and easier to use.
Requirements for the SPCC Plan are included in §§112.1 through 112.15.
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Appendix D
APPENDIX D: SAMPLE BULK STORAGE FACILITY SPCC PLAN
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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.
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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
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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
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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
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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
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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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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
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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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
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
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.
Corrective Actions Taken
A boom was placed into Silver
Creek immediately upon
discovery. Approximately 35
gallons of oil were recovered
from Silver creek and the facility
ground.
Plan for Preventing
Recurrence
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
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Figure A-2: Facility Diagram.
Storm Drain
I Fence
15" concrete dike
(50' x BO1)
Tank 2
20,000 Gal.
PBiTiiLjn Urteadfld Ua
•some
-tx—
Tank 3
ZO. 000 Gal.
Regula- UNeade
Bulk Storage Area
A STREET
Storm Drain
Fence Gate
6
Spill kit
ASPHAL T PA VED AREA
4n asphalt rollover borm
• (parking area for vehicles
left full wernight)
Tank Truck Loading Rack/
Unloading Area
1
AREA
J Tank 4 |
s PORTABLE TANK ^j j
J^W W
ooo
ooo
X, 10-20x55 Gal.
Motor Oil
Protective Bollards
• Roof (covered area)
Ga/e Valve
V
rv
Spttitit
Maintenance Building
Underground piping ^-~~~~
Fuel |—|i / Tank5 \
Dispensing O |\ MiYm.-n j
Area J—I s Dlwel __, ^
Fue/ Denser and f IBteovi from
USTWport o
{Exempt from SPCC
requirements]
Gate Valve
UST fill port
/ Tank 6
I 1 .MM Gal. Nn.
\ 2 Fuel Ol
Underground piping '
Oflfumacs
fin basement)
Main Office Building
To Silver Creek
[250 Yards)
To Silver Creek
(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.
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
Y*
N
Description & Comments
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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SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
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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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
APPENDIX E: SAMPLE PRODUCTION FACILITY SPCC PLAN
U.S. Environmental Protection Agency Version 1.0, 11/28/2005
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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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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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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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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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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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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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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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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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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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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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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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SAMPLE Spill Prevention, Control, and
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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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Big Bear Lease No. 2 Production Facility
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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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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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APPENDIX A: Facility Diagrams
Figure A-1: Site plan.
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2 inch diameter steel
Appro* length 2,100 ft
FLB
2 inch diameter steel
Appro* length 3,400 ft
Containment
berm
SO1 x 40' x 2.5'
To Saltwater
disposal well
Appro*., length
2,000 ft
(sea BOX 1)
BOX 1, Saltwater Disposal Well Araa
To production area
Apprax. length
2.000ft
Clearwater Oil Company
Big Bear Lease No. 2 Production Facility
Facility Diagram Drawing
Rev. 11/12/02
not to
scale
Figure A-2: Production Facility Diagram.
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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
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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&lowline
Dwell
Dlinknown
D stock, flare
D crude oil
Dftaltwater
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:
DQ/vater**
D land
D other (describe):
Recovered:
DtRelease confined to company property.
DtRelease 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
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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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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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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
APPENDIX F: SAMPLE CONTINGENCY PLAN
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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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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 D A o T I
part 109 and part 112. KART I
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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Big Bear Lease No. 2 Production Facility Oil Spill Contingency Plan
1.2 Resources at Risk
Clearwater's Big Bear Lease No. 2 Production Facility is located approximately 6 miles
40CFR 109.5(b)(1) 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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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).
The total daily production rate at the facility varies, but can reach as much as 1,260
40 CFR 109.5(c)(2) 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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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
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
40 CFR 109.5(b)(2) ; 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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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
Emergency Coordinator
Field Operations Manager
Bill Laurler
(405) 829-4051
VP of Operations
Lester Pearson
(555) 289-4500
Madison Fire/Pofice
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
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2.2 Response Activities
40CFR109.5(d)
40CFR109.5(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. £ AHCFR 11? Af
Within 30 days of the discharge, the RC will convene an incident critique including
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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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
40 CFR109 5(b)(2) 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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PART III
Response Resources and Preparedness Activities
3.1 Equipment, Supplies, Services, and Manpower
40CFR109.5(c)(1)
and(c)(2)
40CFR109.5(d)(2)
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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40CFR109.5(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
40CFR109.5(d)(5)
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
A central coordination center will be set up at the field office in the event of a discharge.
40 CFR 109.5(b)(3) j^e fje|d office is equipped with a variety of fixed and mobile communication equipment
40CFR 109.5(d)(3) (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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3.4 Training Exercises and Updating Procedures
Clearwater has established and maintains an ongoing training program to ensure that
40 CFR 109.5(d)(1) 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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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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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
DJIowline
Dwell
nlinknown
D stock, flare
D crude oil
Dftaltwater
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:
DQ/vater**
D land
D other (describe):
Recovered:
DtRelease confined to company property.
DtRelease 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
Appro*, length
2.000ft
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
APPENDIX G: SPCC INSPECTION CHECKLISTS
Onshore Facilities (excluding production)
Onshore Oil Production, Drilling, and Workover Facilities
Offshore Oil Production, Drilling, and Workover Facilities
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U.S. ENVIRONMENTAL PROTECTION AGENCY
SPCC FIELD INSPECTION AND PLAN REVIEW CHECKLIST
FOR USE AT ONSHORE FACILITIES (EXCLUDING PRODUCTION)
Overview of the Checklist
This checklist is designed to assist EPA inspectors in conducting a thorough and consistent
inspection of a facility's compliance with the Spill Prevention, Control, and Countermeasure
(SPCC) rule at 40 CFR part 112. It is a tool to help federal inspectors (or their contractors)
record observations during the site visit and review of the SPCC Plan. While the checklist is
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/OECA inspection measures or GPRA).
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" or "no" answers.
Sections 112.7 through 112.12 specify requirements for spill prevention, control, and
countermeasures. For these sections, 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, mark the "NA" box. If a provision of the rule
applies only to the SPCC Plan, the "Field" column is shaded.
Space is provided in each section to record comments. Additional space is available on the
comments page at the end of the checklist. Comments should remain factual and support the
evaluation of compliance.
Appendix A is for recording information about containers and other locations at the facility that
require secondary containment.
Appendix B is a checklist for documentation of the tests and inspections the facility operator is
required to keep with the SPCC Plan.
Appendix C is a checklist for oil removal contingency plans. A contingency plan is required if a
facility determines that secondary containment is impracticable as provided in 40 CFR 112.7(d).
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U.S. ENVIRONMENTAL PROTECTION AGENCY
SPCC FIELD INSPECTION AND PLAN REVIEW CHECKLIST
FOR USE AT ONSHORE FACILITIES (EXCLUDING PRODUCTION)
FACILITY INFORMATION
FACILITY NAME:
ADDRESS:
LAT:
LONG:
CITY:
STATE:
ZIP:
COUNTY:
TELEPHONE:
FACILITY REPRESENTATIVE NAME:
OWNER NAME:
OWNER ADDRESS:
CITY:
STATE:
ZIP:
TELEPHONE:
OWNER CONTACT PERSON:
FACILITY OPERATOR NAME (IF DIFFERENT FROM OWNER - IF NOT, PRINT "SAME"):
OPERATOR ADDRESS:
CITY:
STATE:
ZIP:
TELEPHONE:
OPERATOR CONTACT PERSON:
FACILITY TYPE:
NAICS CODE:
HOURS PER DAY FACILITY ATTENDED:
TOTAL FACILITY CAPACITY:
TYPE(S) OF OIL STORED:
IS FACILITY LOCATED IN INDIAN COUNTRY? DYES D NO IF YES, RESERVATION NAME:
INSPECTION INFORMATION
INSPECTION DATE:
TIME:
INSPECTION NUMBER:
LEAD INSPECTOR:
OTHER INSPECTOR(S):
INSPECTOR ACKNOWLEDGMENT
/ performed an SPCC inspection at the facility specified above.
INSPECTOR SIGNATURE:
DATE:
Onshore Facilities (Excluding Production)
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FACILITY RESPONSE PLAN (FRP) APPLICABILITY
A non-transportation related onshore facility is required to prepare and implement an FRP as outlined in 40 CFR 112.20 if:
D 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
The facility has a total oil storage capacity of at least 1 million gallons, and at least one of the following is true:
DD The facility does not have secondary containment sufficiently large to contain the capacity of the largest aboveground tank plus
sufficient freeboard for precipitation.
DD The facility is located at a distance such that a discharge could cause injury to fish and wildlife and sensitive environments.
DD The facility is located such that a discharge would shut down a public drinking water intake.
DD The facility has had a reportable discharge greater than or equal to 10,000 gallons in the past 5 years.
Facility has FRP: D Yes D No DQMot Required
FRP Number:
Facility has a completed and signed copy of Appendix C, Attachment C-ll, "Certification of the Applicability of the Substantial Harm
Criteria." D Yes D No
Comments:
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 gallons, OR the aggregate aboveground oil storage capacity is over 1,320
gallons D Yes D No 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 (as defined in 40 CFR 110.1). D Yes D No
AFFECTED WATERWAY(S):
DISTANCE:
PATH:
Note: The following storage capacity is not considered in determining applicability of SPCC requirements:
Completely buried tanks subject to all the technical requirements of 40 CFR part 280 or a state program approved under 40 CFR part 281.
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.
Any facility or part thereof used exclusively for wastewater treatment (production, recovery or recycling of oil is not considered wastewater
treatment).
Containers smaller than 55 gallons.
Permanently closed containers.
Does the facility have an SPCC Plan?
D Yes D No
Comments:
REQUIREMENTS FOR PREPARATION AND IMPLEMENTATION OF A SPCC PLAN—40 CFR 112.3
Date facility began operations:
Date of initial SPCC Plan preparation:
112.3(a)
For facilities in operation prior to August 16, 2002:
Plan amended by February 17, 2006
Amended Plan implemented by August 18, 2006
Current plan version (date/number):
D Yes D No D NA
D Yes D No D NA
For facilities beginning operation between August 17, 2002, and August 18,
2006, Plan prepared and fully implemented by August 18, 2006 D Yes D No D NA
Onshore Facilities (Excluding Production)
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REQUIREMENTS FOR PREPARATION AND IMPLEMENTATION OF A SPCC PLAN— 40 CFR 112.3
112.3(b) For facilities beginning operation after August 18, 2006, Plan prepared and fully D Yes D No DMA
& (c) implemented before beginning operations
1 12.3(d) Professional Engineer certification includes statement that the PE attests:
• PE is familiar with the requirements of 40 CFR part 112 D Yes D No
• PE or agent has visited and examined the facility D Yes D No
• Plan is prepared in accordance with good engineering practice including consideration of
applicable industry standards and the requirements of 40 CFR part 112 D Yes D No
• Procedures for required inspections and testing have been established D Yes D No
• Plan is adequate for the facility D Yes D No
PE Name: License No.: State:
112.3(e) Plan available onsite if facility is attended at least 4 hours/day
(If located at nearest field office, please note contact information below)
Date of certification:
D Yes D No D NA
Comments:
AMENDMENT OF SPCC PLAN BY REGIONAL ADMINISTRATOR (RA)— 40 CFR 1 1 2.4
1 12.4(a) Has the facility discharged a reportable quantity of oil in amounts considered harmful: more D Yes D No
than 1,000 gallons of oil in a single discharge or more than 42 gallons in each of two
discharges in any 12-month period (see 40 CFR part 110)?
• If yes, was information submitted to the RA as required in §1 12.4(a)?
• Date(s) of reportable discharges(s):
• Were they reported to the NRC?
D Yes D No D NA
D Yes D No D NA
112.4(d), (e) Have changes required by the RA been implemented in the Plan and/or facility? D Yes D No D NA
Comments:
AMENDMENT OF SPCC PLAN BY THE OWNER OR OPERATOR— 40 CFR 112.5
112.5(a) Has there been a change at the facility that materially affects the potential for a discharge? D Yes D No D NA
• If so, was the Plan amended within six months of the change?
D Yes D No D NA
112. 5(b) Review and evaluation of the Plan documented at least once every 5 years? D Yes D No D NA
• Following Plan review, and if amendment was required, was Plan amended within six D Yes D No D NA
months to include more effective prevention and control technology, if available?
112. 5(c) Professional Engineer certification of any technical Plan amendments in accordance with D Yes D No D NA
§112. 3(d)
Name: License No.: State:
Date of certification:
Reason for amendment:
Amendments implemented within six months of any Plan amendment
D Yes D No D NA
Comments:
Onshore Facilities (Excluding Production)
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INDICA TE IF ITEM IS ADDRESSED ADEQUA TELY (Yes), INADEQUA TELY(No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
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 Plan D Yes D No
Name: Title:
Plan follows sequence of the rule or provides a cross-reference of requirements in the Plan and the rule
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.)
1 12.7(a)(2) If there are deviations from the requirements of the rule, 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)
Date:
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Describe each deviation and reasons for nonconformance:
1 12.7(a)(3) Plan includes diagram with location and contents of all regulated containers (including completely
buried tanks otherwise exempt from the SPCC requirements), transfer stations, and connecting
pipes
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DNo
DMA
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DNo
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112.7(a)(3) Plan addresses each of the following:
(i) For each container, type of oil and storage capacity (see Appendix A)
(ii) Discharge prevention measures, including procedures for routine handling of products
(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 facility's and contractor's
resources)
(v) Methods of disposal of recovered materials in accordance with applicable legal requirements
(vi) Contact list and phone numbers for the facility response coordinator, National Response Center,
cleanup contractors contracted to respond to a discharge, and all Federal, State, and local agencies
who must be contacted in the case of a discharge as described in §112.1(b)
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Comments:
Onshore Facilities (Excluding Production)
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INDICA TE IF ITEM IS ADDRESSED ADEQUA TELY (Yes), INADEQUA TELY(No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
GENERAL SPCC REQUIREMENTS— 40 CFR 112.7
1 12.7(a)(4) Plan includes information and procedures that enable a person reporting a discharge as described
in §112.1(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 §1 12.1(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; 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 (Not required if a facility has an FRP)
1 12.7(a)(5) Plan organized so that portions describing procedures to be used when a discharge occurs will be
readily usable in an emergency (Not required if a facility has an FRP)
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
1 12.7(c) Appropriate containment and/or diversionary structures provided to prevent a discharge as
described in §112.1(b) before cleanup occurs. 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. (1) For onshore facilities, one of the following or its
equivalent: (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 (See Appendix A)
112.7(d)
112.7(e)
Determination(s) of impracticability of secondary containment
If YES, is the impracticability of secondary containment clearly demonstrated?
PLAN
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FIELD
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Comments concerning impracticability determination(s) for secondary containment:
If impracticability determination is made, for bulk storage containers, periodic integrity testing of
containers and leak testing of the valves and piping associated with the container is conducted
If impracticability determination is made, unless facility has FRP:
(1) Contingency Plan following 40 CFR part 109 (see Appendix C checklist) is provided AND
(2) Written commitment of manpower, equipment, and materials required to control and remove
any quantity of oil discharged that may be harmful
Inspections and tests conducted in accordance with written procedures
Record of inspections or tests signed by supervisor or inspector and kept with Plan for at least 3
years (see Appendix B checklist)
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Comments:
Onshore Facilities (Excluding Production)
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INDICA TE IF ITEM IS ADDRESSED ADEQUA TELY (Yes), INADEQUA TELY(No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
GENERAL SPCC REQUIREMENTS— 40 CFR 112.7
PLAN
FIELD
112.7(f) Personnel, training, and oil discharge prevention procedures
(1 ) 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
(2) Person designated as accountable for discharge prevention at the facility
(3) Discharge prevention briefings conducted at least once a year for oil handling personnel
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112.7(g) Security (excluding production facilities)
(1 ) Facility fully fenced and gates are locked and/or guarded when facility is unattended
(2) Master flow and drain valves and any other valves permitting direct outward flow of the container's
contents to the surface have adequate security measures so that they remain in the closed position when
in non-operating or non-standby status
(3) Pump starter controls locked in "off" position and accessible only to authorized personnel when in non-
operating/non-standby status
(4) Loading/unloading connections of oil pipelines or facility piping securely capped or blank-flanged when not
in service or when in standby service for an extended period of time, including piping that is emptied of
liquid content either by draining or by inert gas pressure
(5) Adequate facility lighting commensurate with the type and location of the facility that assists in the
discovery of discharges occurring during hours of darkness and to prevent discharges occurring through
acts of vandalism
112.7(h) Tank car and tank truck loading/unloading rack*
(1 ) Does loading/unloading area (the location adjacent to the loading or unloading rack) drainage flow to
catchment basin or treatment facility? D Yes D No
• If NO, quick drainage system used
Containment system holds capacity of the largest single compartment of a tank car/truck
loaded/unloaded at the facility
(2) Physical barriers, warning signs, wheel chocks, or vehicle brake interlock system in loading/unloading
areas (the location adjacent to the loading or unloading rack) to prevent vehicles from departing before
complete disconnection of flexible or fixed oil transfer lines
(3) 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
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DNo
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Comments:
* Note that a tank car/truck loading/unloading rack must be present for §112.7(h) to apply
Onshore Facilities (Excluding Production)
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NEEMBRAt/SBBlS REOEHKEMENTS— 40 CFR 1 1 2.7 //
JPUWAI
istiBBc.
112.7(i) Brittle fracture evaluation of field-constructed aboveground containers
112.7(i) Brittle fracture evaluation is conducted after tank repair/alteration/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 (for field-constructed aboveground containers)
DBfes
DNo
DMA
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DNo
DMA
112.7(j) State rules, regulations and guidelines and conformance with applicable sections of 40 CFR part 112
112.7(j) 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
DBfes
DNo
DMA
Comments:
ONSHORE FACILITIES (EXCLUDING PRODUCTION)— 112.8/112.12
1 12.8(b)/1 12. 12(b) Facility Drainage
(1 ) Drainage from diked storage areas is restrained by valves, OR manually activated pumps or ejectors are
used and the condition of the accumulation is inspected prior to discharge to ensure no oil will be
discharged.
(2)
(3)
Valves from diked storage areas 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, storm
water inspected per§112.8(c)(3)(ii), (iii), and (iv) or§112.12(c)(3)(ii), (iii), and (iv)
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.*
(4) If facility drainage not engineered as in (b)(3), facility equipped with a diversion system to retain oil in the
facility in the event of a discharge*
PLAN
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FIELD
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(5) Are facility drainage waters continuously treated in more than one treatment unit and pump transfer is needed?
D Yes D No If YES:
• 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
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Comments:
* These provisions apply only when a facility drainage system is used for containment.
Onshore Facilities (Excluding Production)
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INDICA TE IF ITEM IS ADDRESSED ADEQUA TELY (Yes), INADEQUA TELY(No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
ONSHORE FACILITIES (EXCLUDING PRODUCTION)— 112.8/112.12
PLAN
FIELD
112.8(c)/112.12(c) Bulk Storage Containers (See Appendix A of this checklist)
(1)
(2)
Containers compatible with material stored and conditions of storage such as pressure and temperature
Secondary containment to hold capacity of largest container and sufficient freeboard for precipitation
Diked areas sufficiently impervious to contain discharged oil
Alternatively, any discharge to a drainage trench system will be safely confined in a facility catchment
basin or holding pond
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(3) Is there drainage of uncontaminated rainwater from diked areas into a storm drain or open watercourse?
D Yes D No If YES:
(i) Bypass valve normally sealed closed
(ii) Retained rainwater is inspected to ensure that its presence will not cause a discharge as described in
§112.1(b)
(iii) Bypass valve opened and resealed under responsible supervision
(iv) Adequate records of drainage are kept; for example, records required under permits issued in
accordance with 40 CFR 1 22.41 (j)(2) and (m)(3)
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(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 ):
• Corrosion protection with coatings or cathodic protection compatible with local soil conditions
Regular leak testing conducted
(5) Partially buried or bunkered metallic tanks protected from corrosion with coatings or cathodic protection
compatible with local soil conditions
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Comments:
Onshore Facilities (Excluding Production)
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INDICA TE IF ITEM IS ADDRESSED ADEQUA TELY (Yes), INADEQUA TELY(No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
ONSHORE FACILITIES (EXCLUDING PRODUCTION)— 112.8/112.12
PLAN
FIELD
112.8(c)/112.12(c) Bulk Storage Containers (continued)
(6)
Aboveground containers integrity tested by visual inspection and another technique such as hydrostatic
testing, radiographic testing, ultrasonic testing, acoustic emissions testing, or another system of non-
destructive shell testing on a regular schedule and whenever material repairs are made
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 inspections and tests maintained
(7) Leakage through defective internal heating coils controlled:
• Steam returns and exhaust lines from internal heating coils that discharge into an open water source are
monitored for contamination, OR
• Steam returns and exhaust lines pass through a settling tank, skimmer, or other separation or retention
system
(8) Each container equipped with at least one of the following for liquid level sensing: (i) high liquid level alarms
with an audible or visual signal at a constantly attended operation or surveillance station, or audible air vent
in smaller facilities, (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 container gauger and pumping
station, (iv) fast response system (such as digital computers, telepulse, or direct vision gauges) and a
person is present to monitor gauges and the overall filling of bulk storage containers, (v) liquid level sensing
devices regularly tested to ensure proper operation
(9) Effluent treatment facilities observed frequently enough to detect possible system upsets that could cause a
discharge as described in §112.1(b)
(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
(11)
Mobile or portable containers positioned to prevent a discharge to prevent a discharge as described in
§112.1(b).
Mobile or portable containers have secondary containment with sufficient capacity to contain the largest
single compartment or container and sufficient freeboard for precipitation
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Comments:
Onshore Facilities (Excluding Production)
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INDICA TE IF ITEM IS ADDRESSED ADEQUA TELY (Yes), INADEQUA TELY(No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
ONSHORE FACILITIES (EXCLUDING PRODUCTION)— 112.8/112.12
PLAN
FIELD
112.8(d)/112.12(d) Facility transfer operations, pumping, and facility process
(1)
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 cathodically protected or otherwise
satisfies corrosion protection standards for piping in 40 CFR part 280 or 281
Exposed buried piping is inspected for deterioration and corrosion damage is examined and corrected
(2) 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
(3) Pipe supports are properly designed to minimize abrasion and corrosion and allow for expansion and
contraction
(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
Integrity and leak testing conducted on buried piping at time of installation, modification, construction,
relocation, or replacement
(5) Vehicles warned so that no vehicle endangers aboveground piping and other oil transfer operations
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Comments:
Onshore Facilities (Excluding Production)
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Rule Provision
ADDITIONAL COMMENTS
Comment
Onshore Facilities (Excluding Production)
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Photo Number
PHOTO DOCUMENTATION LOG
Description (include date and location)
Onshore Facilities (Excluding Production)
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SPCC FIELD INSPECTION AND PLAN REVIEW TABLE
Appendix A: 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 foundation for: cracks, discoloration, puddles containing spilled or leaked material, settling, gaps between container and
foundation, and damage caused by vegetation roots.
Check piping for: droplets of stored material, discoloration, corrosion, bowing of pipe between supports, evidence of stored material
seepage from valves or seals, and localized dead vegetation. (Document in comments section of §112.8(d)/§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, 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 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 Condition
Storage Capacity and
Type of Oil
Type of Containment/
Drainage Control
Overfill Protection and
Testing & Inspections
Onshore Facilities (Excluding Production)
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SPCC INSPECTION AND TESTING CHECKLIST
Appendix B: 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 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) Integrity testing is conducted for bulk storage containers with no secondary
containment system and for which an impracticability determination has been
made
(d) 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
(i) Evaluate 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
112.8/1 12. 12-Onshore facilities (excluding production)
(b)(2) Storm water released from facility drainage directly to a watercourse is
inspected and records of drainage are kept
(c)(3)(iv) Rainwater released directly from diked containment areas to a storm drain
or open watercourse is inspected and records of drainage are kept
(c)(4) Regular leak testing of completely buried metallic storage tanks
(c)(6) Aboveground containers, supports and foundations tested for integrity on a
regular schedule
(c)(6) Outside of containers frequently inspected for deterioration, discharges or
accumulations of oil inside diked areas
(c)(8)(v) Liquid level sensing devices regularly tested to ensure proper operation
(c)(9) Effluent treatment facilities are observed frequently enough to detect
possible system upsets that could cause a discharge as described in
§112.1(b)
(d)(1) When buried piping is exposed, it is carefully inspected for deterioration and
corrosion damage is corrected
(d)(4) Aboveground valves, piping and appurtenances are regularly inspected and
the general condition of flange joints, expansion joints, valve glands and
bodies, catch pans, pipeline supports, locking of valves, and metal surfaces
are assessed
(d)(4) Integrity and leak testing of buried piping is conducted at time of installation,
modification, construction, relocation or replacement
Comments:
Onshore Facilities (Excluding Production)
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SPCC CONTINGENCY PLAN REVIEW CHECKLIST
Appendix C: 40 CFR Part 109-Criteria for State, Local and Regional Oil
Removal Contingency Plans
If a facility makes an impracticability determination for secondary containment in accordance with §112.7(d), it is required to provide
an oil spill contingency plan following 40 CFR part 109.
109.5-Development and implementation criteria for State, local and regional oil removal contingency plans*
(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., 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.
(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.
(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.
(e) Specific and well defined procedures to facilitate recovery of damages and enforcement measures as provided
for by State and local statutes and ordinances.
Yes
No
* The contingency plan should be consistent with all applicable state and local plans, Area Contingency Plans, and the National
Contingency Plan (NCP).
Onshore Facilities (Excluding Production) Page 16 of 16 Version 1.0
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U.S. ENVIRONMENTAL PROTECTION AGENCY
SPCC FIELD INSPECTION AND PLAN REVIEW CHECKLIST
ONSHORE OIL PRODUCTION, DRILLING, AND WORKOVER FACILITIES
Overview of the Checklist
This checklist is designed to assist EPA inspectors in conducting a thorough and consistent
inspection of a facility's compliance with the Spill Prevention, Control, and Countermeasure
(SPCC) rule at 40 CFR part 112. It is a tool to help federal inspectors (or their contractors)
record observations during the site visit and review of the SPCC Plan. While the checklist is
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/OECA inspection measures or GPRA).
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" or "no" answers.
Sections 112.7 through 112.11 specify requirements for spill prevention, control, and
countermeasures. For these sections, 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, mark the "NA" box. If a provision of the rule
applies only to the SPCC Plan, the "Field" column is shaded.
Space is provided in each section to record comments. Additional space is available on the
comments page at the end of the checklist. Comments should remain factual and support the
evaluation of compliance.
Appendix A is for recording information about containers and other locations at the facility that
require secondary containment.
Appendix B is a checklist for documentation of the tests and inspections the facility operator is
required to keep with the SPCC Plan.
Appendix C is a checklist for oil removal contingency plans. A contingency plan is required if a
facility determines that secondary containment is impracticable as provided in 40 CFR 112.7(d).
Onshore Oil Production, Drilling, & Workover Facilities Page 1 of 14 Version 1.0, 11/28/2005
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U.S. ENVIRONMENTAL PROTECTION AGENCY
SPCC FIELD INSPECTION AND PLAN REVIEW CHECKLIST
ONSHORE OIL PRODUCTION, DRILLING, AND WORKOVER FACILITIES
FACILITY INFORMATION
FACILITY NAME:
ADDRESS:
LAT:
LONG:
CITY:
STATE:
ZIP:
COUNTY:
TELEPHONE:
FACILITY REPRESENTATIVE NAME:
OWNER NAME:
OWNER ADDRESS:
CITY:
STATE:
ZIP:
TELEPHONE:
OWNER CONTACT PERSON:
FACILITY OPERATOR NAME (IF DIFFERENT FROM OWNER - IF NOT, PRINT "SAME"):
OPERATOR ADDRESS:
CITY:
STATE:
ZIP:
TELEPHONE:
OPERATOR CONTACT PERSON:
FACILITY TYPE:
NAICS CODE:
HOURS PER DAY FACILITY ATTENDED:
TOTAL FACILITY CAPACITY:
TYPE(S) OF OIL STORED:
IS FACILITY LOCATED IN INDIAN COUNTRY? DYES D NO IF YES, RESERVATION NAME:
INSPECTION INFORMATION
INSPECTION DATE:
TIME:
INSPECTION NUMBER:
LEAD INSPECTOR:
OTHER INSPECTOR(S):
INSPECTOR ACKNOWLEDGMENT
/ performed an SPCC inspection at the facility specified above.
INSPECTOR SIGNATURE:
DATE:
Onshore Oil Production, Drilling, & Workover Facilities
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FACILITY RESPONSE PLAN (FRP) APPLICABILITY
A non-transportation related onshore facility is required to prepare and implement an FRP as outlined in 40 CFR 112.20 if:
D 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
The facility has a total oil storage capacity of at least 1 million gallons, and at least one of the following is true:
DD The facility does not have secondary containment sufficiently large to contain the capacity of the largest aboveground tank plus
sufficient freeboard for precipitation.
DD The facility is located at a distance such that a discharge could cause injury to fish and wildlife and sensitive environments.
DD The facility is located such that a discharge would shut down a public drinking water intake.
DD The facility has had a reportable discharge greater than or equal to 10,000 gallons in the past 5 years.
Facility has FRP: D Yes D No DQslot Required
FRP Number:
Facility has a completed and signed copy of Appendix C, Attachment C-ll, "Certification of the Applicability of the Substantial Harm
Criteria" D Yes D No
Comments:
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 gallons, OR the aggregate aboveground oil storage capacity is over 1,320
gallons D Yes D No 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 (as defined in 40 CFR 110.1). D Yes D No
AFFECTED WATERWAY(S):
DISTANCE:
PATH:
Note: The following storage capacity is not considered in determining applicability of SPCC requirements:
Completely buried tanks subject to all the technical requirements of 40 CFR part 280 or a state program approved under 40 CFR part 281.
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.
Any facility or part thereof used exclusively for wastewater treatment (production, recovery or recycling of oil is not considered wastewater
treatment).
Containers smaller than 55 gallons.
Permanently closed containers.
Does the facility have an SPCC Plan?
D Yes D No
Comments:
REQUIREMENTS FOR PREPARATION AND IMPLEMENTATION OF A SPCC PLAN—40 CFR 112.3
Date facility began operations:
Date of initial SPCC Plan preparation:
112.3(a)
For facilities in operation prior to August 16, 2002:
Plan amended by February 17, 2006
Amended Plan implemented by August 18, 2006
Current plan version (date/number):
D Yes D No D NA
D Yes D No D NA
For facilities beginning operation between August 17, 2002, and August 18,
2006, Plan prepared and fully implemented by August 18, 2006 D Yes D No D NA
Onshore Oil Production, Drilling, & Workover Facilities
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REQUIREMENTS FOR PREPARATION AND IMPLEMENTATION OF A SPCC PLAN— 40 CFR 112.3
112.3(b) For facilities beginning operation after August 18, 2006, Plan prepared and fully D Yes D No DMA
& (c) implemented before beginning operations
1 12.3(d) Professional Engineer certification includes statement that the PE attests:
• PE is familiar with the requirements of 40 CFR part 112 D Yes D No
• PE or agent has visited and examined the facility D Yes D No
• Plan is prepared in accordance with good engineering practice including consideration of
applicable industry standards and the requirements of 40 CFR part 112 D Yes D No
• Procedures for required inspections and testing have been established D Yes D No
• Plan is adequate for the facility D Yes D No
PE Name: License No.: State:
112.3(e) Plan available onsite if facility is attended at least 4 hours/day
(If located at nearest field office, please note contact information below)
Date of certification:
D Yes D No D NA
Comments:
AMENDMENT OF SPCC PLAN BY REGIONAL ADMINISTRATOR (RA)— 40 CFR 1 1 2.4
112.4(a) Has the facility discharged a reportable quantity of oil in amounts considered harmful more D Yes D No D NA
than 1,000 gallons of oil in a single discharge or more than 42 gallons in each of two
discharges in any 12-month period (see 40 CFR part 110)?
If yes, was information submitted to the RA as required in §1 12.4(a)?
• Date(s) of reportable discharge(s):
• Were they reported to the NRC?
D Yes D No D NA
D Yes D No D NA
112.4(d), (e) Have changes required by the RA been implemented in the Plan and/or facility? D Yes D No D NA
Comments:
AMENDMENT OF SPCC PLAN BY THE OWNER OR OPERATOR— 40 CFR 112.5
112.5(a) Has there been a change at the facility that materially affects the potential for a discharge? D Yes D No D NA
• If so, was the Plan amended within six months of the change?
D Yes D No D NA
112.5(b) Review and evaluation of the Plan documented at least once every 5 years? D Yes D No D NA
• Following Plan review, and if amendment was required, was Plan amended within six D Yes D No D NA
months to include more effective prevention and control technology, if available?
112.5(c) Professional Engineer certification of any technical Plan amendments in accordance with D Yes D No D NA
§112.3(d)
Name: License No.: State:
Reason for amendment:
Amendments implemented within six months of any Plan amendment
Date of certification:
D Yes D No D NA
Comments:
Onshore Oil Production, Drilling, & Workover Facilities
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INDICA TE IF ITEM IS ADDRESSED ADEQUA TELY (Yes), INADEQUA TELY(No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
GENERAL SPCC REQUIREMENTS— 40 CFR 112.7
Management approval at a level of authority to commit the necessary resources to fully
Name:
PLAN
FIELD
implement the Plan D Yes D No
Title:
Plan follows sequence of the rule or provides a cross-reference of requirements in the Plan and the rule
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)(2)
If there are deviations from the requirements of the rule, the Plan states
nonconformance
reasons for
Alternative measures described in detail and provide equivalent environmental protection (Note:
Inspector should document if the environmental equivalence is implemented in the field)
Date:
DBfes
DNo
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
Describe each deviation and reasons for nonconformance:
112.7(a)(3)
112.7(a)(3)
Plan includes diagram with location and contents of all regulated containers (including completely
buried tanks otherwise exempt from the SPCC requirements), transfer stations, and connecting
pipes
Dlan addresses each of the following:
DBfes
DNo
DMA
DBfes
DNo
DMA
(i) For each container, type of oil and storage capacity (see Appendix A)
(ii) Discharge prevention measures, including procedures for routine handling of products
(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 facility's and contractor's
resources)
(v) Methods of disposal of recovered materials in accordance with applicable legal requirements
(vi) Contact list and phone numbers for the facility response coordinator, National Response Center,
cleanup contractors contracted to respond to a discharge, and all Federal, State, and local
agencies who must be contacted in the case of a discharge as described in §1 12.1(b)
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
Comments:
Onshore Oil Production, Drilling, & Workover Facilities
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INDICA TE IF ITEM IS ADDRESSED ADEQUA TELY (Yes), INADEQUA TELY(No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
GENERAL SPCC REQUIREMENTS— 40 CFR 112.7
1 12.7(a)(4) Plan includes information and procedures that enable a person reporting a discharge as described
in §112.1(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 §1 12.1(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; 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 (Not required if a facility has an FRP)
1 12.7(a)(5) Plan organized so that portions describing procedures to be used when a discharge occurs will be
readily usable in an emergency (Not required if a facility has an FRP)
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
1 12.7(c) Appropriate containment and/or diversionary structures provided to prevent a discharge as
described in §112.1(b) before cleanup occurs. The entire containment system, including walls and
floors, is capable of containing oil and is constructed to prevent escape of a discharge from the
containment system before cleanup occurs. (1) For onshore facilities, one of the following or its
equivalent: (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 (See Appendix A)
112.7(d)
112.7(e)
Determination(s) of impracticability of secondary containment
If YES, is the impracticability of secondary containment clearly demonstrated?
PLAN
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DBfes
DlMo
DMA
FIELD
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
Comments concerning impracticability determination(s) for secondary containment:
If impracticability determination is made, for bulk storage containers, periodic integrity testing of
containers and leak testing of the valves and piping (associated with the container) is conducted
If impracticability determination is made, unless facility has FRP:
(1) Contingency Plan following 40 CFR part 109 (see Appendix C) is provided AND
(2) Written commitment of manpower, equipment, and materials required to control and
remove any quantity of oil discharged that may be harmful
Inspections and tests conducted in accordance with written procedures
Record of inspections or tests signed by supervisor or inspector and kept with Plan for at least 3
years (see Appendix B checklist)
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
Comments:
Onshore Oil Production, Drilling, & Workover Facilities
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INDICA TE IF ITEM IS ADDRESSED ADEQUA TELY (Yes), INADEQUA TELY(No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
GENERAL SPCC REQUIREMENTS— 40 CFR 112.7
PLAN
FIELD
112.7(f) Personnel, training, and oil discharge prevention procedures
(1 ) 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
(2) Person designated as accountable for discharge prevention at the facility
(3) Discharge prevention briefings conducted at least once a year for oil handling personnel
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
112.7(h) Tank car and tank truck loading/unloading rack*
(1 ) Does loading/unloading area (the location adjacent to the loading or unloading rack) drainage flow
to catchment basin or treatment facility? D Yes D No
• If NO, quick drainage system used
Containment system holds capacity of the largest single compartment of a tank car/truck
loaded/unloaded at the facility
(2) Physical barriers, warning signs, wheel chocks, or vehicle brake interlock system in loading/unloading
areas (the location adjacent to the loading or unloading rack) to prevent vehicles from departing before
complete disconnection of flexible or fixed oil transfer lines
(3) 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
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
112.7(i) Brittle fracture evaluation of field-constructed aboveground containers
112.7(i) Brittle fracture evaluation is conducted after tank repair/alteration/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 (for field-constructed aboveground containers)
DBfes
DNo
DMA
DBfes
DNo
DMA
112.7Q) State rules, regulations and guidelines and conformance with applicable sections of 40 CFR part 112
112.7Q) 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 1 12
DBfes
DNo
DMA
Comments:
* Note that a tank car/truck loading/unloading rack must be present for §1 12.7(h) to apply. Though this requirement applies to all
facilities, loading and unloading rack equipment is often not present at typical production facilities.
Onshore Oil Production, Drilling, & Workover Facilities
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INDICA TE IF ITEM IS ADDRESSED ADEQUA TELY (Yes), INADEQUA TELY(No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
ONSHORE OIL PRODUCTION FACILITIES— 112.9
PLAN
FIELD
1 12.9(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), 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
DBfes
DlMo
DMA
DBfes
DlMo
DMA
Prior to drainage, diked area inspected and action taken as provided in §112.8(c)(3)(ii), (iii), and (iv):
• 1 12.8(c)(3)(ii) Retained rainwater is inspected to ensure that its presence will not cause a discharge
as described in §112.1(b)
• 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 §122.41(j)(2) and (m)(3)
(2) Field drainage systems and oil traps, sumps, or skimmers inspected at regularly scheduled intervals for oil,
and accumulations of oil promptly removed
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
1 12.9(c) Oil production facility bulk storage containers
(1 ) Containers used are compatible with material stored and conditions of storage
(2)
Secondary containment provided for all tank battery, separation and treating facilities with capacity to
hold the largest single container and sufficient freeboard for precipitation
Drainage from undiked areas safely confined in a catchment basin or holding pond
(3) Periodically and upon a regular schedule, visually inspect containers on or above the surface of the ground
for deterioration and maintenance needs, including foundations and supports
(4) New and old tank batteries 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
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
Comments:
Onshore Oil Production, Drilling, & Workover Facilities
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INDICA TE IF ITEM IS ADDRESSED ADEQUA TELY (Yes), INADEQUA TELY(No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
ONSHORE OIL PRODUCTION FACILITIES—112.9
PLAN FIELD
112.9(d) Facility transfer operations
(1) All aboveground valves and piping associated with transfer operations are inspected periodically and upon
a regular schedule. 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.
DBfes
DlMo
DMA
DBfes
DlMo
DMA
(2) 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
DBfes
DlMo
DMA
DBfes
DlMo
DMA
(3) Flowline maintenance program to prevent discharges from each flowline is established
DBfes
DlMo
DMA
DBfes
DlMo
DMA
Comments:
ONSHORE OIL DRILLING AND WORKOVER FACILITIES—112.10
PLAN
FIELD
112.10(b) Mobile drilling or workover equipment is positioned or located to prevent a discharge as described in
DBfes
DlMo
DMA
DBfes
DlMo
DMA
112.10(c) Catchment basins or diversion structures are provided to intercept and contain discharges of fuel,
crude oil, or oily drilling fluids.
DBfes
DlMo
DMA
DBfes
DlMo
DMA
Blowout prevention (BOP) assembly and well control system installed before drilling below any
casing string or during workover operations
DBfes
DlMo
DMA
DBfes
DlMo
DMA
BOP assembly and well control system capable of controlling any well-head pressure that may be
encountered while on the well
DBfes
DlMo
DMA
DBfes
DlMo
DMA
Comments:
Onshore Oil Production, Drilling, & Workover Facilities
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Rule Provision
ADDITIONAL COMMENTS
Comment
Onshore Oil Production, Drilling, & Workover Facilities
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Photo Number
PHOTO DOCUMENTATION LOG
Description (include date and location)
Onshore Oil Production, Drilling, & Workover Facilities
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SPCC FIELD INSPECTION AND PLAN REVIEW TABLE
Appendix A: Documentation of Field Observations of 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 standard/specifications of construction..
Check aboveground container foundation for: cracks, discoloration, 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 from flowlines, and localized dead vegetation. For all aboveground piping, 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. (Document in comments section of §112.9(d)).
Secondary Containment
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 accumulations 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.
Container ID/ General Condition
Storage Capacity and
Type of Oil
Type of Containment/
Drainage Control
Overfill Protection and
Testing & Inspections
Onshore Oil Production, Drilling, & Workover Facilities
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SPCC INSPECTION AND TESTING CHECKLIST
Appendix B: 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 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
(a) Integrity testing is conducted for bulk storage containers with no secondary
containment system and for which an impracticability determination has been
made
(d) 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
(i) Evaluate 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
112.9-Onshore oil production facilities
(b)(1) Rainwater released directly from diked containment areas to a storm drain or
open watercourse inspected and records of drainage kept
(b)(2) Field drainage systems, oil traps, sumps, and skimmers inspected regularly for
oil, and accumulations of oil promptly removed
(c)(3) Regular visual inspections of containers, foundations and supports for
deterioration and maintenance needs
(d)(1) All aboveground valves and piping associated with transfer operations are
regularly inspected
(d)(2) Saltwater disposal facilities inspected often to detect possible system upsets
capable of causing a discharge
(d)(3) Specific and individual inspection, testing, and/or evaluation requirements as
required by facility's flowline maintenance program
Comments:
Onshore Oil Production, Drilling, & Workover Facilities
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SPCC CONTINGENCY PLAN REVIEW CHECKLIST
Appendix C: 40 CFR Part 109-Criteria for State, Local and Regional Oil
Removal Contingency Plans
If a facility makes an impracticability determination for secondary containment in accordance with §112.7(d), it is required to provide
an oil spill contingency plan following 40 CFR part 109.
109.5-Development and implementation criteria for State, local and regional oil removal contingency plans*
(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., 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.
(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.
(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.
(e) Specific and well defined procedures to facilitate recovery of damages and enforcement measures as provided
for by State and local statutes and ordinances.
Yes
No
* The contingency plan should be consistent with all applicable state and local plans, Area Contingency Plans, and the National
Contingency Plan (NCP).
Onshore Oil Production, Drilling, & Workover Facilities Page 14 of 14
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SPCC Guidance for Regional Inspectors
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U.S. Environmental Protection Agency Version 1.0, 11/28/2005
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U.S. ENVIRONMENTAL PROTECTION AGENCY
SPCC FIELD INSPECTION AND PLAN REVIEW CHECKLIST
FOR USE AT OFFSHORE DRILLING, PRODUCTION, AND WORKOVER FACILITIES
Overview of the Checklist
This checklist is designed to assist EPA inspectors in conducting a thorough and consistent
inspection of a facility's compliance with the Spill Prevention, Control, and Countermeasure
(SPCC) rule at 40 CFR part 112. It is a tool to help federal inspectors (or their contractors)
record observations during the site visit and review of the SPCC Plan. While the checklist is
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/OECA inspection measures or GPRA).
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" or "no" answers.
Sections 112.7 through 112.11 specify requirements for spill prevention, control, and
countermeasures. For these sections, 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, mark the "NA" box. If a provision of the rule
applies only to the SPCC Plan, the "Field" column is shaded.
Space is provided in each section to record comments. Additional space is available on the
comments page at the end of the checklist. Comments should remain factual and support the
evaluation of compliance.
Appendix A is for recording information about containers and other locations at the facility that
require secondary containment.
Appendix B is a checklist for documentation of the tests and inspections the facility operator is
required to keep with the SPCC Plan.
Appendix C is a checklist for oil removal contingency plans. A contingency plan is required if a
facility determines that secondary containment is impracticable as provided in 40 CFR 112.7(d).
OFFSHORE FACILITIES Page 1 of 14 Version 1.0, 11/28/2005
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U.S. ENVIRONMENTAL PROTECTION AGENCY
SPCC FIELD INSPECTION AND PLAN REVIEW CHECKLIST
FOR USE AT OFFSHORE DRILLING, PRODUCTION, AND WORKOVER FACILITIES
FACILITY INFORMATION
FACILITY NAME:
ADDRESS:
LAT:
LONG:
CITY:
STATE:
ZIP:
COUNTY:
TELEPHONE:
FACILITY REPRESENTATIVE NAME:
OWNER NAME:
OWNER ADDRESS:
CITY:
STATE:
ZIP:
TELEPHONE:
OWNER CONTACT PERSON:
FACILITY OPERATOR NAME (IF DIFFERENT FROM OWNER - IF NOT, PRINT "SAME"):
OPERATOR ADDRESS:
CITY:
STATE:
ZIP:
TELEPHONE:
OPERATOR CONTACT PERSON:
FACILITY TYPE:
NAICS CODE:
HOURS PER DAY FACILITY ATTENDED:
TOTAL FACILITY CAPACITY:
TYPE(S) OF OIL STORED:
IS FACILITY LOCATED IN INDIAN COUNTRY? DYES D NO IF YES, RESERVATION NAME:
INSPECTION INFORMATION
INSPECTION DATE:
TIME:
INSPECTION NUMBER:
LEAD INSPECTOR:
OTHER INSPECTOR(S):
INSPECTOR ACKNOWLEDGMENT
/ performed an SPCC inspection at the facility specified above.
INSPECTOR SIGNATURE:
DATE:
OFFSHORE FACILITIES
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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 gallons, OR the aggregate aboveground oil storage capacity is over 1,320
gallons D Yes D No 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 (as defined in 40 CFR 110.1). D Yes D No
AFFECTED WATERWAY(S):
DISTANCE:
PATH:
Note: The following storage capacity is not considered in determining applicability of SPCC requirements:
Completely buried tanks subject to all the technical requirements of 40 CFR part 280 or a state program approved under 40 CFR part 281.
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.
Any facility or part thereof used exclusively for wastewater treatment (production, recovery or recycling of oil is not considered wastewater
treatment).
Containers smaller than 55 gallons.
Permanently closed containers.
Does the facility have an SPCC Plan?
D Yes D No
Comments:
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)
For facilities in operation prior to August 16, 2002:
Plan amended by February 17, 2006
D Yes D No D NA
Amended Plan implemented by August 18, 2006
D Yes D No D NA
For facilities beginning operation between August 17, 2002, and August 18,
2006, Plan prepared and fully implemented by August 18, 2006
D Yes D No D NA
112.3(b) For facilities beginning operation after August 18, 2006, Plan prepared and fully
& (c) implemented before beginning operations
D Yes D No D NA
112.3(d) Professional Engineer certification includes statement that the PE attests:
• PE is familiar with the requirements of 40 CFR part 112 D Yes D No
• PE or agent has visited and examined the facility D Yes D No
• Plan is prepared in accordance with good engineering practice including consideration of
applicable industry standards and the requirements of 40 CFR part 112 D Yes D No
• Procedures for required inspections and testing have been established D Yes D No
• Plan is adequate for the facility D Yes D No
PE Name:
License No.:
State:
Date of certification:
112.3(e) Plan available onsite if facility is attended at least 4 hours/day
(If located at nearest field office, please note contact information below.)
D Yes D No D NA
Comments:
OFFSHORE FACILITIES
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AMENDMENT OF SPCC PLAN BY REGIONAL ADMINISTRATOR (RA)— 40 CFR 1 1 2.4
1 12.4(a) Has the facility discharged a reportable quantity of oil in amounts considered harmful: more D Yes D No
than 1,000 gallons of oil in a single discharge or more than 42 gallons in each of two
discharges in any 12-month period (see 40 CFR part 110)?
• If yes, was information submitted to the RA as required in §1 12.4(a)?
• Date(s) of reportable discharge(s):
• Were they reported to the NRC?
D Yes D No D NA
D Yes D No D NA
112.4(d), (e) Have changes required by the RA been implemented in the Plan and/or facility? D Yes D No D NA
Comments:
AMENDMENT OF SPCC PLAN BY THE OWNER OR OPERATOR^40 CFR 112.5
112.5(a) Has there been a change at the facility that materially affects the potential for a discharge? D Yes D No D NA
• If so, was the Plan amended within six months of the change?
D Yes D No D NA
112. 5(b) Review and evaluation of the Plan documented at least once every 5 years? D Yes D No D NA
• Following Plan review, and if amendment was required, was Plan amended within six D Yes D No D NA
months to include more effective prevention and control technology, if available?
112.5(c) Professional Engineer certification of any technical Plan amendments in accordance with D Yes D No D NA
§112. 3(d)
Name: License No.: State:
Date of certification:
Reason for amendment:
Amendments implemented within six months of any Plan amendment
D Yes D No D NA
Comments:
OFFSHORE FACILITIES
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INDICA TE IF ITEM IS ADDRESSED ADEQUA TELY (Yes), INADEQUA TELY(No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
GENERAL SPCC REQUIREMENTS— 40 CFR 112.7
Management approval at a level of authority to commit the necessary resources to fully
Name:
PLAN
FIELD
implement the Plan D Yes D No
Title:
Plan follows sequence of the rule or provides a cross-reference of requirements in the Plan and the rule
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)(2)
If there are deviations from the requirements of the rule, the Plan states
nonconformance
reasons for
Alternative measures described in detail and provide equivalent environmental protection (Note:
Inspector should document if the environmental equivalence is implemented in the field.)
Date:
DBfes
DNo
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
Describe each deviation and reasons for nonconformance:
112.7(a)(3)
112.7(a)(3)
Plan includes diagram with location and contents of all regulated containers (including completely
buried tanks otherwise exempt from the SPCC requirements), transfer stations, and connecting
pipes
Dlan addresses each of the following:
DBfes
DNo
DMA
DBfes
DNo
DMA
(i) For each container, type of oil and storage capacity (see Appendix A)
(ii) Discharge prevention measures, including procedures for routine handling of products
(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 facility's and contractor's
resources)
(v) Methods of disposal of recovered materials in accordance with applicable legal requirements
(vi) Contact list and phone numbers for the facility response coordinator, National Response Center,
cleanup contractors contracted to respond to a discharge, and all Federal, State, and local agencies
who must be contacted in the case of a discharge as described in §112.1(b)
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
Comments:
OFFSHORE FACILITIES
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INDICATE IF ITEM IS ADDRESSED ADEQUATELY (Yes), INADEQUATELY (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
GENERAL SPCC REQUIREMENTS— 40 CFR 112.7
1 12.7(a)(4) Plan includes information and procedures that enable a person reporting a discharge as described
in §112.1(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 §1 12.1(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; 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
1 12.7(a)(5) Plan organized so that portions describing procedures to be used when a discharge occurs will be
readily usable in an emergency
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
1 12.7(c) Appropriate containment and/or diversionary structures provided to prevent a discharge as
described in §112.1(b) before cleanup occurs. The entire containment system, including walls and
floors, is capable of containing oil and is constructed to prevent escape of a discharge from the
containment system before a cleanup occurs. ... (2) For offshore facilities: (i) curbing or drip pans,
or (ii) sumps and collection systems (See Appendix A)
112.7(d)
112.7(e)
Determination(s) of impracticability of secondary containment
If YES, is the impracticability of secondary containment clearly demonstrated?
PLAN
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DBfes
DlMo
DMA
FIELD
DBfes
DlMo
DMA
DBfes
DlMo
DMA
Comments concerning impracticability determination(s) for secondary containment:
If impracticability determination is made, for bulk storage containers, periodic integrity testing of
containers and leak testing of the valves and piping associated with the container is conducted
If impracticability determination is made:
(1) Contingency Plan following 40 CFR part 109 (see Appendix C) is provided AND
(2) Written commitment of manpower, equipment, and materials required to control and remove
any quantity of oil discharged that may be harmful
Inspections and tests conducted in accordance with written procedures
Record of inspections or tests signed by supervisor or inspector and kept with Plan for at least 3
years (see Appendix B checklist)
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
Comments:
OFFSHORE FACILITIES
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INDICATE IF ITEM IS ADDRESSED ADEQUATELY (Yes), INADEQUATELY (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
GENERAL SPCC REQUIREMENTS^" CFR 112.7
PLAN
FIELD
112.7(f) Personnel, training, and oil discharge prevention procedures
(1 ) 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
(2) Person designated as accountable for discharge prevention at the facility
(3) Discharge prevention briefings conducted at least once a year for oil handling personnel
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
112.7(h) Tank car and tank truck loading/unloading rack*
(1 ) Does loading/unloading area (the location adjacent to the loading or unloading rack) drainage flow to
catchment basin or treatment facility? D Yes D No
• If NO, quick drainage system used
Containment system holds capacity of the largest single compartment of a tank car/truck
loaded/unloaded at the facility
(2) Physical barriers, warning signs, wheel chocks, or vehicle brake interlock system in loading/unloading
areas (the location adjacent to the loading or unloading rack) to prevent vehicles from departing before
complete disconnection of flexible or fixed oil transfer lines
(3) 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
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
DBfes
DNo
DMA
112.7(i) Brittle fracture evaluation of field-constructed aboveground containers
112.7(i) Brittle fracture evaluation is conducted after tank repair/alteration/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 (for field-constructed aboveground containers)
DBfes
DNo
DMA
DBfes
DNo
DMA
112.7(j) State rules, regulations and guidelines and conformance with applicable sections of 40 CFR part 112
112.7Q) 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
DBfes
DNo
DMA
Comments:
* Note that a tank car/truck loading/unloading rack must be present for §1 12.7(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 FACILITIES
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INDICATE IF ITEM IS ADDRESSED ADEQUATELY (Yes), INADEQUATELY (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
OFFSHORE OIL DRILLING, PRODUCTION, OR WORKOVER FACILITIES— 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
112.11(d) 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 (1) extending the
flare line to a diked area if the separator is near shore, (2) equipping separator with high liquid level
sensor to automatically shut in wells producing to the separator, OR (3) installing parallel redundant
dump valves
112.11(e) Atmospheric storage or surge containers equipped with high liquid level sensing devices that activate
an alarm or control the flow, or otherwise prevent discharges
PLAN
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DDslo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
FIELD
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DDslo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
Comments:
OFFSHORE FACILITIES
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INDICA TE IF ITEM IS ADDRESSED ADEQUA TELY (Yes), INADEQUA TELY(No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
OFFSHORE OIL DRILLING, PRODUCTION, OR WORKOVER FACILITIES— 112.11
112.11(f) Pressure containers equipped with high and low pressure sensing devices that activate an alarm or
control the flow
112.11(g) Containers equipped with suitable corrosion protection
112.11(h) Written procedures maintained in the SPCC plan for inspecting and testing pollution prevention
equipment and systems
112.11(i) 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
112.11(j) 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
112.11(k) 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
112.11(1) Manifolds (headers) equipped with check valves on individual flowlines
112.11(m) 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
112.11(n) Piping appurtenant to the facility is protected from corrosion, such as with protective coatings or
cathodic protection
112.11(o) Sub-marine piping appurtenant to the facility is protected against environmental stresses and other
activities such as fishing operations
112.11(p) 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
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
FIELD
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
DBfes
DlMo
DMA
Comments:
OFFSHORE FACILITIES
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Rule Provision
ADDITIONAL COMMENTS
Comment
OFFSHORE FACILITIES
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Photo Number
PHOTO DOCUMENTATION LOG
Description (include date and location)
OFFSHORE FACILITIES
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SPCC FIELD INSPECTION AND PLAN REVIEW TABLE
Appendix A: Documentation of Field Observations for Containers and Associated Requirements
Inspectors should use this table to document observations of containers, as needed.
Containers
Check containers for the following: (1) atmospheric storage or surge containers are equipped with high liquid level sensing devices
that activate an alarm or control the flow, or otherwise prevent discharges (2) pressure containers are equipped with high and low
pressure sensing devices that activate an alarm or control the flow (3) containers are equipped with suitable corrosion protection.
Check piping for: droplets of stored material, discoloration, corrosion, bowing of pipe between supports, evidence of stored material
seepage from valves or seals, and localized dead vegetation.
Secondary Containment
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, cracks, discoloration, presence of spilled or leaked material (standing liquid), corrosion, and
valve conditions.
Container ID/General Condition
Storage Capacity and
Type of Oil
Type of Containment/
Drainage Control
Overfill Protection and
Testing & Inspections
OFFSHORE FACILITIES
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SPCC INSPECTION AND TESTING CHECKLIST
Appendix B: 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 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) Integrity testing is conducted for bulk storage containers with no secondary
containment system and for which an impracticability determination has been
made
(d) 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
(i) Evaluate 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
112.11-Offshore oil drilling, production and workover facilities
(c) Regularly scheduled preventive maintenance inspection and testing program to
assure reliable operation of liquid removal system and pump start-up device
(i) 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
(p) Submarine piping periodically inspected or tested for failures.
Comments:
OFFSHORE FACILITIES
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SPCC CONTINGENCY PLAN REVIEW CHECKLIST
Appendix C: 40 CFR Part 109-Criteria for State, Local and Regional Oil
Removal Contingency Plans
If a facility makes an impracticability determination for secondary containment in accordance with §112.7(d), it is required to provide
an oil spill contingency plan following 40 CFR part 109.
109.5-Development and implementation criteria for State, local and regional oil removal contingency plans*
(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., 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.
(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.
(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.
(e) Specific and well defined procedures to facilitate recovery of damages and enforcement measures as provided
for by State and local statutes and ordinances.
Yes
No
* The contingency plan should be consistent with all applicable state and local plans, Area Contingency Plans, and the National
Contingency Plan (NCP).
OFFSHORE FACILITIES Page 14 of 14 Version 1.0, 11/28/2005
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Appendix H
APPENDIX H: OTHER POLICY DOCUMENTS
Letter to Melissa Young of Petroleum Marketers Association of America (2001)
Letter to Daniel Gilligan of Petroleum Marketers Association of America (May 25, 2004)
Letter to Mr. Chris Early of Safety-Kleen Corporation (July 14, 2004)
DOT/EPA Memo "Jurisdiction over Breakout Tanks/Bulk Oil Storage Tanks (Containers) at
Transportation-Related and Non-Transportation-Related Facilities" (February 4, 2000)
FRP rule attachments C-l and C-ll
U.S. Environmental Protection Agency Version 1.0, 11/28/2005
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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
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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
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SPCC Guidance for Regional Inspectors
This page intentionally left blank.
U.S. Environmental Protection Agency Version 1.0, 11/28/2005
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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
-------
(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.
-------
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).
-------
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
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UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
JUL | 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/Canota Ink on paper that
contains at least 50% recycled fiber
-------
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
-------
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
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which ft isfH&.
cc: Susan Goreky, DOT
-------
U.S. Department
of Transportation
Research &
Special Programs
Administration
400 Seventh Street S.W.
Washington, D.C. 20590
From:
FEB -4 2000
Assoei aicAdmi ni s
U.S. Environmental
Protection Agency
Office Solid Waste &
Emergency Response
401 M Street, SW, 5201G
Washington, DC 20460
Stephen D. Luftig, Director, Office of Emergency and Remedial Response, United
States Environmental Protection Agency
V
To:
Subject:
I. Purpose
Department of Transportation, Office of Pipeline Safety Regional Directors
Director, Office of Site Remediation and Restoration EPA Region I
Director, Emergency and Remedial Response Division EPA Region II
Directors, Hazardous Waste Management Division EPA Regions
III and IX
Director, Waste Management Division EPA Regions IV, VIII
Directors, Superfund Division EPA Regions V, VI, VII
Director, Environmental Cleanup Office EPA Region X
Jurisdiction over Breakout Tanks/Bulk Oil Storage Tanks (Containers) at
Transportation-Related and Non-Transportation-Related Facilities
The purpose of this agreement is to clarify jurisdictional issues and establish mutual goals
for the Office of Emergency and Remedial Response, Environmental Protection Agency (EPA)
and the Office of Pipeline Safety, Department of Transportation (DOT). This letter does not
amend the 1971 MOU between the EPA and DOT or redelegate any responsibilities agreed to
under that MOU or previously assigned to DOT or EPA under Executive Order 12777 or any
previous Executive Order.
II. Authority and History
Section 311 of the Clean Water Act (CWA) (33 U.S.C. 1321) gives the President
authority to issue regulations regarding prevention, preparedness, and response planning for
facilities. Executive Order 12777, signed on October 18,1991, delegates responsibilities under
CWA Section 311 to EPA to issue regulations regarding prevention, preparedness, and response
planning for non-transportation-related onshore facilities. EPA was also delegated responsibility
1
-------
to establish procedures, methods, and equipment and other requirements to prevent and contain-
discharges of oil and hazardous substances from non-transportation-related onshore facilities. -
Those regulations are found at 40 CFR 112. DOT was delegated authority to issue regulations-
regarding prevention, preparedness, and response planning at transportation-related onshore-
facilities. DOT was also delegated responsibility to establish procedures, methods, and-
equipment and other requirements to prevent and contain discharges of oil and hazardous-
substances from transportation-related onshore facilities. DOT issued response planning-
regulations for transportation-related onshore oil pipelines, found at 49 CFR 194.-
DOT also issued safety standards found at 49 CFR 195 for pipeline facilities under the-
Pipeline Safety Act of 1992 (49 U.S.C. 60101). DOT considers environmental factors when-
issuing pipeline safety standards. -
III. Current Status at Complex Facilities
A 1971 Memorandum of Understanding (MOU) between the EPA and DOT defines-
transportation and non-transportation-related activities. A facility with both transportation-
related and non-transportation-related activities is a "complex facility" and is subject to the dual-
jurisdiction of EPA and DOT. Both EPA and DOT have determined that the definition of a-
complex facility, as currently interpreted under both agencies programs, can include an entire-
facility or a single tank. Owners or operators of a complex facility must comply with all the-
regulatory requirements of both agencies when both agencies have jurisdiction. An example of-
dual jurisdiction is a bulk storage container serving as a tank storing oil while also serving as a-
breakout tank for a pipeline or other transportation purposes. Attachments 1-10 provide practical-
examples of complex facilities showing jurisdictional delineation to minimize potential-
confusion over regulatory responsibility. -
IV. Next Steps
To improve communications, both DOT and EPA have initiated talks at the Headquarters-
level. These talks will be expanded to include regional representatives. Better communications-
entails; (1) improving information sharing on pipeline and tank incidents resulting in discharges-
to navigable water, material failures, human errors and other activities resulting in a discharge;-
(2) improving information sharing relating to pollution prevention, preparedness, and response;-
(3) sharing critiques of response efforts by EPA On-Scene Coordinators (OSCs) with DOT to-
enhance response planning of the pipeline operator (DOT may also consider these critiques in-
revisions to its regulations); (4) including an EPA participant on the Technical Hazardous Liquid-
Pipeline Safety Standards Committee (THLPSSC); (5) including a DOT Office of Pipeline Safety-
Regional member on each Inland Area Committee who may advise the EPA OSC on issues-
related to pipelines and breakout tanks; (6) continuing the DOT practice of offering EPA OSCs-
the opportunity to review submitted response plans before DOT approval; and (7) continuing-
discussions to resolve the jurisdictional issues surrounding oil gathering lines and their associated-
tanks.-
2,-,-
-------
Cross training is also important. EPA will make space available for DOT representatives-
to attend Spill Prevention, Control, and Countermeasure and Facility Response Planning training-
courses. DOT will make space available for EPA representatives and OSCs to attend courses in-
pipeline safety and inspection. DOT and EPA personnel will establish the appropriate level of-
participation in these training opportunities over the next three years. The agencies will also-
explore other opportunities for cross training including the Freshwater Spill Symposium,-
Preparedness for Response Exercise Program (PREP), etc. -
DOT and EPA will establish procedures for the joint inspection of facilities subject to-
dual jurisdiction. A joint inspection will be considered the equivalent of a separate inspection by-
each agency. DOT and EPA will identify risk factors to consider when identifying high-
priority/high-risk facilities subject to joint inspections. These risk factors include, but are not-
limited to; proximity to densely populated areas, proximity to navigable waters or-
environmentally sensitive areas as defined in Area Contingency Plans or other appropriate-
documents, areas likely to be subject to natural disasters, facility spill history, and compliance-
history. DOT and EPA regional representatives will use the procedures to identify those-
facilities that will be jointly inspected by both agencies. Facilities should be offered the-
opportunity to elect to participate in joint inspections. A joint inspection does not abridge the-
ability of each agency to implement enforcement activities arising from those inspections, nor-
limit the right to conduct separate inspections of any facility subject to dual jurisdiction. DOT-
and EPA will endeavor to conduct six to ten joint inspections nationwide within one year of this-
memorandum. The agencies will assess the effectiveness of the joint inspection program at the-
completion of all of the joint inspections.-
V. Immediate Considerations and Long Term Goals
While DOT and EPA have different historical emphases, our respective goals are-
complementary. The mutual long term goals of EPA and DOT are: -
1. To ensure that all breakout tanks/bulk storage containers are appropriately regulated
under all applicable statutes, -
2. That the rules and enforcement practices of both agencies are substantially equivalent -
to the extent possible and, -
3. That as many facilities as possible are subject to single jurisdiction in the interest of
regulatory efficiency.-
DOT and EPA want to encourage the use of tank management programs which exemplify-
"best practices/good engineering and operational practices" in the industry. Our efforts to-
recognize excellence in performance will enable both agencies to funnel lessons back into our-
tank programs to ensure that they are dynamic and able to keep pace with developments in the-
filed. Both agencies share the goal of improving the effectiveness of our tank inspection-
programs while focusing our limited resources on those facilities that pose the greatest risk to the-
environment-
3,-r
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Over a five-year period, DOT and EPA shall undertake joint efforts to measure the-
effectiveness of DOT and EPA regulatory programs in protecting the environment and-
contributing to the safety of the regulated industry. The agencies will determine and agree upon-
factors including, but not limited to regulations, implementation, enforcement, and additional-
exemplary protective measures. DOT and EPA may invite the Coast Guard to participate in or-
review these efforts.-
EPA and DOT are committed to working diligently towards achieving these goals. Until-
these long term goals are achieved, EPA and DOT shall respect the jurisdiction of its sister-
agency and encourage regulated facilities to fully comply with each agency's regulations.-
For more information contact David Lopez, Director, Office of Emergency and Remedial-
Response Oil Program Center at (703) 603-8707 and Stacey Gerard, Director, Office of Policy,-
Regulations, and Training (202) 366-4595.-
Attachments-
cc: d-d-Timothy Fields Jr, Assistant Administrator, OSWER-
Mike Shapiro, Deputy Assistant Administrator, OSWER-
Jim Makris, Director, CEPPO, OSWER-
Steve Herman, Assistant Administrator, OECA-
Eric Schaeffer, Director, Office of Regulatory Enforcement, OECA-
Earl Salo, Assistant General Counsel for Superfund, OGC-
Bob Cianciarulo, Superfund/Oil Program Lead Region Coordinator-
EPA Regional Removal Managers-
Elaine Joost, Acting Chief Counsel, RSPA-
Commandant, U.S. Coast Guard (G-MS, G-MO, G-MSO, G-MOC, G-MOR)-
r:\text\rspa\luffell6.wpd 4- Rev 02/03/00-
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BREAKOUT TANKAGE
Fence
Pump
Valve
@) Meter
IXI
§
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J
- -
1
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T 1
1 <
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/ \
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i) ' Tank i J
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IXI IXI
f
\
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\
Main Line
\XL
OPS Jurisdiction*
•EPA Jurisdiction*
SOURCE: US EPA REV: 11/09/99
ATTACHMENT
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STORAGE TAN/CAGE
Fence
Pump
Valve
Meter
Isolation
Flange
Product
Tank
(Storage)
I
A
*
a
O)
c
"T3
a
o
Product
Tank
(Storage)
OPS Jurisdiction*
•EPA Jurisdiction*
JXL
A/lain Line
* This diagram does not identify the precise location where the change in jurisdiction occurs between EPA and OPS for the purpose of the Clean Water Act, Section
311 (j) (33 DSC 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.
SOURCE: US EPA REV: 11/09/99 "' lALHMbN I 2.
-------
STORAGE TANKAGE
Pump
Valve
@) Meter
(M)
Product
Tank
(Storage)
I
•
•
!
•
•
<$)
•
•
•i-
i
OPS jurisdiction extends to
pressure influencing device
which effects operating pressure
of the main pipeline.
OPS Jurisdiction'
• EPA Jurisdiction*
Joint EPA-
OPS Jurisdiction
3XL
nxr
3XE
nxr
Main Line
* This diagram does not identify the precise location where the change in jurisdiction occurs between EPA and OPS for the purpose of the Clean Water Act,
Section 311 (j) (33 DSC 1321 (j)). When the pipeline operator and the storage or breakout tank operator remain the same, the change in jurisdiction occurs
at the first and last pressure influencing device, 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 and last pressure
influencing device, valve, or isolation flange, at or inside the facility property ine. 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.
SOURCE: US EPA REV: 11/09/99 ATTACHMENTS
-------
BREAKOUT AND STORAGE TANKAGE - JOINT EPA - OPS JURISDICTION
(A)
Fence
(B)
Fence
• •
• •
i i '
1 1 1
i x"-
J t
j / Product \ !
: ." Tank \ \
^^^^^H
D
S"~
! t
'! *
•4. ?
| /* Product \ j
i i
4 ! (Breakout) | A m '
V \ & / ® JIL — i
i \JStorage) \ t \ i
• *^" " 1 T i r 1
J ! 1 ruck transferring
| j to Facility 1
__ f
(M)
T \
Tank • :
^^^^^H
D
-------
STORAGE AND BREAKOUT TANKAGE - JOINT EPA - OPS JURISDICTION
Fence
• Pump
•• Valve w w
W. -Hill — -I""* *«-- -»<•»
M' Meter
_ Isolation
™ Flange >
i
I
4-
/ Proc
.* Tar
! (Stor
\ «
\ (Brea
; „ L
1 «f i V w 1
D
CD
05
C
"T3
0
• I i * "X ®^ Jurisdiction extends to
., , • ,^m— *t J^ i II pressure influencing device
**A j.** **\ j | which effects operating
uct *\ / Product \ • ^ I pressure of the main p peline.
ik ; • Tank ; ^ A
\ 1 i /c, % 1 (p M)
age) : «. (Storage) : T y
c / \ oc / • j ^^^^ vJro Jurist
$ «. * • 1
k<~>nt) / V (Br^nk^nt) / j Jl pp,A |Uri-H
.^**X *v-*...— »*X j : _.._.. -Joint EPA
* ! OPS Juris*
diction*
iction*
diction
I I
JXL
I
A/lain Line
* This diagram does not identify the precise ocation where the change in jurisdiction occurs between EPA and OPS 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 and last pressure influencing device, 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 and last pressure
influencing device, 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.
SOURCE: US EPA REV: 11/09/99
ATTACHMENT 5
-------
Fence
STORAGE TANKAGE
Mix
Tank
(Storage)
Product
Tank
(Storage)
Pump
Valve
Meter
Isolation
Flange
Product
Tank
(Storage)
Product
Tank
(Storage)
OPS Jurisdiction*
EPA Jurisdiction*
Main Line
* This diagram does not identify the precise location where the change in jurisdiction occurs between EPA and OPS 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 so ely be used to determine jurisdiction when operational activities
(loadinq/offloadinq) extend beyond the property line. ATTAr-ux/icMT /
SOURCE: US E?A REV: 11/09/99 AMAL.n!VltlN I O
-------
STORAGE & BREAKOUT TANKAGE - JOINT EPA - OPS JURISDICTION
Product
Tank
(Storage)
Product
Tank
(Storage)
• Pump
Valve
(Mi Meter
/ Mix \
/ Tank \
I (Breakout) J
& I
^ (Storage) y
^^l |L_ B B n||| B|y B B n|||| B B nnnnn||||n||| B B |nnnnn||||n|
._.._| . J
f|P ^^a m m ^^m m m ^^m m m ^^m m m iiiiiiiiiiiiiHiiiiiii B ^BH B B iiiiiiiiiiinlM|ii B IBBB B m BBBB
B ^Hn^nnnnn
m ssj
.4.™.j. ...
|>-*"^
•7 Product \
._!..
t
I
i
I
B ^BBB B S BBBB S • Hi
/ Tank
»
I (Breakout
« g I
\ /
\ Storage) /*
•W
D
0
D)
c
15
D
O
OPS Jurisdiction*
EPA Jurisdiction*
Joint EPA-OPS Jurisdiction
JXL
nxx
Main Line
* This diagram does not identify the precise location where the change in jurisdiction occurs between EPA and OPS for the purpose of the Clean Water Act, Section
311 (j) (33 DSC 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. ATTACHMENT 7
-------
STORAGE TANKAGE ASSOCIATED WITH
PRODUCTION/GATHERING
LINES
_ _ _ _ _ Geographical Oil Field* _
Q
3"
r—
3"
CD
Pump
Valve
@ Meter
X
The gathering line between
points A and B is the subject
of continuing jurisdictional
discussions.
Gathering Line
**
Product
Tank
(Storage)
Production/Gathering
Flowline
CD
C
CD
Oil Production Facility:
-* *-^:'
-4-r*
•*-
•*-
Individual Well Heads
may include Storage Tanks I
Product
Tank
(Storage)
O)
c
^5
D
o
Truck transferring
from Oil Field*
OPS Jurisdiction
EPA Jurisdiction
*ln 40 CFR 112.1 and 112.7 EPA regulates onshore oi production facilities including wells, flowlines, separation equipment, storage facilities,
gathering ines and auxiliary non-transportation-related equipment and facilities in a single geographical oil or gas field operated by a single operator.
**ln 49 CFR 1 95 OPS does not regulate gathering lines (8 5/8 inch or less nomina outside diameter) that transports petroleum from a production facil
in rural areas. See 49 CFR 1 95.1 and 1 95.2. The gathering line is subject to OPS response planning requirements in 49 CFR 1 94.
SOURCE: US EPA REV: 12/06/99
ATTACHMENT 8
-------
BREAKOUT AND
STORAGE TANKAGE -
JOINT EPA - OPS
JURISDICTION
Pump
Valve
@) Meter
i
I
Refinery
/ Product
Tank
I (Storage)
&
\ (Breakout) /
Product
Tank
(Storage)
I I
I
ixr
OPS Jurisdiction*
EPA Jurisdiction*
Joint EPA-OPS Jurisdiction
I
I
3XL
JXL
Main Line
* This diagram does not identify the precise location where the change in jurisdiction occurs between EPA and OPS for the purpose of the Clean Water Act,
Section 311 (j) (33 DSC 1321 (j)). When the pipeline operator and the storage or breakout tank operator remain the same, the change in jurisdiction occurs
at the first and last pressure influencing device, 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 and last pressure
influencing device, valve, or isolation flange, at or inside the facility property ine. 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.
ATTACHMENT?
SOURCE: US EPA REV: 11/09/99
-------
EPA, OPS, AND COAST GUARD JURISDICTION
ATA COMPLEX FACILITY
OPS jurisdiction extends to
pressure influencing device
which effects operating
pressure of the main pipeline
• Pump
•• Valve
Marine Transportation— Related
Facility (MTR) is defined in 33
CFR 154.1020. This segment
of a complex is under CG
jurisdiction for the purposes of
CWA Section 31 1(j).
i
Y
• I
t
1
\ !
• •
i !
**.i
•* v :
/ Product i
/ Tank2 \
1 (Storage) \
\ & /
\ (Breakout) y
^
MARINE LOADING DOCK
The tank depicted is used for
storage associated with the
MTR facility and is under EPA
jurisdiction. If tank is also used
as a breakout tank it is subject
to both OPS and EPA jurisdiction.
CD
.C
Ci
.c
CG Jurisdiction
OPS Jurisdiction3
EPA Jurisdiction3
Joint EPA-OPS Jurisdiction3
This diagram does not identify the precise location where the change in jurisdiction occurs between EPA and OPS 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 and last pressure influencing device, 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 and last pressure
influencing device, 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.
SOURCE: US EPA REV: 12/13/99
ATTACHMENT 10
-------
Pt. 112, App. C 40 CFR Ch. I (7-1-03 Edition)
ATTACHMENTS TO APPENDIX 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 aboveground 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 intake5"
Yes
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 1,11, 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).
52
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Environmental Protection Agency
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 formulal) 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 E 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 formula!) 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,
1 If 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 wa-
ters. EPA has determined that the primary
concern for calculation of a planning dis-
tance is the transport of oil in navigable wa-
ters 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) (1) (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
53
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