-------
Chapter 6: Facility Diagrams
-------
SPCC Guidance for Regional Inspectors
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 de 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
ruleby§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.
U.S. Environmental Protection Agency
6-16
Version 1.0, 11/28/2005
-------
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
U.S. Environmental Protection Agency
7-1
Version 1.0, 11/28/2005
-------
SPCC Guidance for Regional Inspectors
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 I Section(s)
Action
Method, Circumstance, and Required Action
General Requirements Applicable to All Facilities
Bulk storage with no ; 112.7(d)
secondary
containment and for
which an
impracticability
determination has
been made
Valves and piping
associated with bulk
storage containers
with no secondary
containment and for
which an
impracticability
determination has
been made
Test
112.7(d)
Test
I ntegrity testing.1 Periodically.
However, because there is no secondary containment,
good engineering practice may suggest more frequent
testing than would otherwise be scheduled.
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)
US. Environmental Protection Agency
7-2
Version 1.0, 11/28/2005
-------
Chapter 7: Inspection, Evaluation, and Testing
Facility Component
Recordkeeping
requirement
Section(s) j Action
112.7(e)
Record
Method, Circumstance, and Required Action
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 112.7(h)(3)
all outlets of tank car
or tank truck
Field-constructed
aboveground
container
Inspect
Evaluate
Visually inspect. Prior to filling and departure of tank
car or tank truck.
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
Diked areas
Onshore Facilities (Excluding Production)
Inspect
112.8(b)(2)or
&
112.8{c)(10)or
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
Aboveground bulk
storage container
Aboveground bulk
storage container
112.8(c)(6}or
Test
112.8(c)(6)or : Inspect
Leak test. Regularly.
&
112.8{c)(10)or
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.
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.
2 Certain industry standards require recordkeeping beyond three years.
US. Environmental Protection Agency
7-3
Version 1.0, 11/28/2005
-------
SPCC Guidance for Regional Inspectors
Facility Component
Bulk storage
container supports
and foundation
Diked area
Steam return and
exhaust lines
Liquid level sensing
devices
Effluent treatment
facilities
Section(s)
112.8(c){6)or
112.8(c)(6)or
&
112.8(c)(10) or
Action
Inspect
Method, Circumstance, and Required Action
!
Inspect container's supports and foundations.
Following a regular schedule and whenever material
repairs are made.
Inspect
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.
112.8(c)(7)or i Monitor
112.8(c)(8)(v) | Test
or
112.8(c)(9)or
Buried piping
Observe
112.8{d)(1)or : Inspect
Buried piping
All aboveground
valves, piping, and
appurtenances
112.8(d)(4)or i Test
112.8(d)(4)or
Inspect
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 sect/on 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)(2)
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.
112.9{c}(3)
Inspect
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.
U.S. Environmental Protection Agency
7-4
Version 1.0,11/28/2005
-------
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
Section(s)
112.9(c)(3)
112.9(d)(1)
associated with
transfer operations
Action Method, Circumstance, and Required Action
Inspect Visually inspect to assess deterioration and
maintenance needs. Periodically and on a regular
schedule.
Inspect
Saltwater disposal
112.9(d)(2)
facilities
j
Inspect
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
112.9(d)(3)
112.11(c)
Inspect
Inspect
removal system and ; ! and Test
pump start-up device)
Pollution prevention
equipment and
systems
Sub-marine piping
112.11(h)&(i)
112.11(p)
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
Inspect
and Test
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
U.S. Environmental Protection Agency
7-5
Version 1.0, 11/28/2005
-------
SPCC Guidance for Regional Inspectors
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.
U.S. Environmental Protection Agency
7-6
Version 1.0,11/28/2005
-------
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;"
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.
U.S. Environmental Protection Agency
7-7
Version 1.0, 11/28/2005
-------
SPCC Guidance for Regional Inspectors
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 basts, 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,
U.S. Environmental Protection Agency 7-8 Version 1.0,11/28/2005
-------
Chapter 7: Inspection, Evaluation, and Testing
(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.
U.S. Environmental Protection Agency
7-9
Version 1.0,11/28/2005
-------
SPCC Guidance for Regional Inspectors
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 or cathodic 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 Flowiine 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
U.S. Environmental Protection Agency 7-10 Version 1.0,11/28/2005
-------
Chapter 7: Inspection, Evaluation, and Testing
flowlines for secondary containment required by §112.7(c), EPA inspectors should extensively
review the adequacy of the flow/line 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
U.S. Environmental Protection Agency
7-11
Version 1.0, 11/28/2005
-------
SPCC Guidance for Regional Inspectors
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.
U. S. Environmental Protection Agency 7-12 Version 1.0.11 /28/2005
-------
Chapter 7: Inspection, Evaluation, and Testing
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.
U.S. Environmental Protection Agency
7-13
Version 1.0, 11/28/2005
-------
SPCC Guidance for Regional Inspectors
Table 7-2. Summary of industry standards and recommended practices (RP) for ASTs.
Equipment
covered
Scope
Inspection
interval
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.
I
Inspection i Certified inspector,
performed by
Applicable
section of this
document
tank owner.
Section 7. 5.1
STI SP-001 API RP 575
ASTs including Atmospheric and
shop-fabricated low-pressure ASTs.
and field-erected
tanks and portable
containers and
containment
systems.
Determined by the Inspection and
type of material repair of tanks.
stored within the
tank and the
operating
temperature.
Inspection of tanks
by the owner/
operator and
certified inspectors.
API RP 12R1
Atmospheric ASTs
employed in oil and
gas production,
treating, and
processing.
Setting, connecting,
maintaining,
operating, inspecting,
and repairing tanks.
Certified Same as API 653. j Scheduled and
inspections:
Inspection intervals
and scope based
on tank size and
configuration.
Owner inspections:
unscheduled internal
and external
inspections
conducted as per
Table 1 of the
Recommended
Practice.
monthly, quarterly, i
and yearly.
Certified inspector, Same as API 653
either by API or
STI.
Section 7.5.2 Section 7.5.3
Competent person or
qualified inspector, as
defined in
recommended
practice.
Section 7.5.4
US. Environmental Protection Agency
7-14
Version 1.0, 11/28/2005
-------
Chapter 7: Inspection, Evaluation, and Testing
Table 7-3. Summary of industry standards and recommended practices (RP) for piping, valves,
and appurtenances.
API 570
Equip-
ment
covered
Scope
Inspection
interval
Inspection
performed
by
Applicable
section of
this
document
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
10 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.
U.S. Environmental Protection Agency
7-15
Version 1.0,11/28/2005
-------
SPCC Guidance for Regional Inspectors
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;
Aboveg round bulk storage containers for which the baseline condition is nor 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
L/.S. Environmental Protection Agency 7-16 Version 1.0,11/28/2005
-------
Chapter 7: Inspection, Evaluation, and Testing
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(6), 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
U.S. Environmental Protection Agency
7-17
Version 1.0, 11/28/2005
-------
SPCC Guidance for Regional Inspectors
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 1 00,000 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 1 5 years or Vi of corrosion rate, whichever is less. If corrosion rates are not known, the
maximum interval is 5 years. An internal inspection of the floor 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
Tank 3
Construction Date
unknown
2001
1984
Last Inspection
none
none
1994
Next Inspection (External)
formal visual and shell test
within first five-year Plan review
cycle
2006 for both visual inspection
and non-destructive shell test
1 999 & 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)
external 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.
U.S. Environmental Protection Agency
7-18
Version 1.0, 11/28/2005
-------
Chapter 7: Inspection, Evaluation, and Testing
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 teaks 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
US. Environmental Protection Agency
7-19
Version 1.0, 11/28/2005
-------
SPCC Guidance for Regional Inspectors
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
preamble to the revised SPCC rule, certain smaller shop-built containers are^to^bjectto 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,
certain industry standards also reference these conditions as good
engineering practice. For example, elevating storage drums on an
appropriately designed storage rack (as shown in Figure 7-2) such that all
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
U.S. Environmental Protection Agency 7-20 Version 1.0,11/28/2005
-------
Chapter 7: Inspection, Evaluation, and Testing
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.
Figure 7-3. Shop-built containers elevated
on saddles.
Scenario 3: Elevated shop-built containers. For
certain shop-built containers with a shell capacity of 30,000
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).
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://vvww.epa.gov/oilspill/pdfs/PMAAJetter.pdf.
U.S. Environmental Protection Agency
7-21
Version 1.0,11/28/2005
-------
SPCC Guidance for Regional Inspectors
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.
U.S. Environmental Protection Agency 7-22 Version 1.0,11/28/2005
-------
Chapter 7: Inspection, Evaluation, and Testing
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 Ran 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.
U.S. Environmental Protection Agency
7-23
Version 1.0,11/28/2005
-------
SPCC Guidance for Regional Inspectors
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 foltow-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
U.S. Environmental Protection Agency 7-24 Version 1.0, 11/28/2005
-------
Chapter 7: Inspection, Evaluation, and Testing
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.
U.S. Environmental Protection Agency 7-25 Version 1.0,11/28/2005
-------
SPCC Guidance for Regional Inspectors
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
10 See Section 1.1.3 of API 653.
U.S. Environmental Protection Agency 7-26 Version 1.0, 11/28/2005
-------
Chapter 7: Inspection, Evaluation, and Testing
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 format 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.
U.S. Environmental Protection Agency
7-27
Version 1.0, 11/28/2005
-------
SPCC Guidance for Regional Inspectors
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.
U.S. Environmental Protection Agency 7-28 Version 1.0, 11/28/2005
-------
Chapter 7; Inspection, Evaluation, and Testing
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," 1sted., American Petroleum Institute,
November 1995.
U.S. Environmental Protection Agency 7-29 Version 1.0, 11/28/2005
-------
SPCC Guidance for Regional Inspectors
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, 0, 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.
18 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 countemeasures (SPCC) to
prevent environmental damage."
U.S. Environmental Protection Agency 7-30 Version 1.0, 11/28/2005
-------
Chapter 7: Inspection, Evaluation, and Testing
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.
U.S. Environmental Protection Agency 7-31 Version 1.0,11/28/2005
-------
SPCC Guidance for Regional Inspectors
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.
U.S. Environmental Protection Agency 7-32 Version 1.0,11/28/2005
-------
Chapter 7: Inspection, Evaluation, and Testing
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 'lest personnel" in accordance with ASME B31.4 20 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," 1s'Edition, American Petroleum Institute, January 2000.
US. Environmental Protection Agency
7-33
Version 1.0,11/28/2005
-------
SPCC Guidance for Regional Inspectors
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.
U.S. Environmental Protection Agency
7-34
Version 1.0,11/28/2005
-------
Chapter 7: Inspection, Evaluation, and Testing
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, 2"" edition, 2004.
25 ASME B31.3 does not have specific requirements for an examiner, but SNT-TC-1 A, "Recommended Practice for
Nondestructive Testing Personnel Qualification and Certification," acts as an acceptable guide.
U.S. Environmental Protection Agency
7-35
Version 1.0, 11/28/2005
-------
SPCC Guidance for Regional inspectors
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
28 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 831.4-1998, 2002.
2r 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.
US. Environmental Protection Agency 7-36 Version 1.0,11/28/2005
-------
Chapter 7: Inspection, Evaluation, and Testing
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.qpo.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.
U.S. Environmental Protection Agency 7-37 Version 1.0, 11/28/2005
-------
SPCC Guidance for Regional Inspectors
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/pubiications/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.oov/arp/ACs/5210-20.pdn
7.5.15 Suggested Minimum Requirements for a 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.
U.S. Environmental Protection Agency 7-38 Version 1.0,11/28/2005
-------
Chapter 7: Inspection, Evaluation, and Testing
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
U.S. Environmental Protection Agency 7-39 Version 1.0,11/28/2005
-------
SPCC Guidance for Regional Inspectors
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 property; 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.
U.S. Environmental Protection Agency
7-40
Version 1.0, 11/28/2005
-------
Chapter 7: Inspection, Evaluation, and Testing
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 Components) 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
CO
If)
CD
1
•
•
•
•
_8
1- Q.
W W
•
•
•
•
•
•
o
r-
m
1
•
•
•
in
r-~
in
CL
cr
5
•
•
•
•
•
•t
i-~
in
CL
C£
I
•
•
•
K
>r*
1
•
•
•
•
•
o
t—
E
<
•
•
•
ro
ro
CD
111
1
•
•
TJ-
ro
CD
UJ
1
•
•
•
•
* Recommended practice.
U.S. Environmental Protection Agency
7-41
Version 1.0, 11/28/2005
-------
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).
1.
II.
III.
Check tanks for leaks, specifically looking for:
A.
B.
C.
D.
E.
F.
Drip marks;
Discoloration of tanks;
Puddles containing spilled or leaked material;
Corrosion;
Cracks; and
Localized dead vegetation.
Check foundation for:
A.
B.
C.
D.
E.
F.
Cracks;
Discoloration;
Puddles containing spilled or leaked material;
Settling;
Gaps between tank and foundation; and
Damage caused by vegetation roots.
Check piping for:
A.
B.
C.
D.
E.
F.
Droplets of stored material;
Discoloration;
Corrosion;
Bowing of pipe between supports;
Evidence of stored material seepage from valves or seals; and
Localized dead vegetation.
US. Environmental Protection Agency
7-42
Version 1.0,11/28/2005
-------
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:
0) 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
offshore facilities, and to contain such discharges...
-------
-------
Environmental Protection Agency
Pr. 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 1, 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-Scetie Coordi
nator (OSC) for the geographic area
where the discharge occurs. All such
reports shall be promptly relayed to
the NRC. If it is not possible to notify
the NRC or the predesignated OCS im-
mediately, reports may be made imme
diately to the nearest Coast Guard
unit, provided that the person in
charge of the vessel or onshore or off-
shore facility notifies the NRC as soon
as possible. The reports shall be made
in accordance with such procedures as
the Secretary of Transportation may
prescribe. The procedures for such no-
tice are set forth in U.S. Coast Guard
regulations, 33 CFR part 153, subpart B
and in the National Oil and Hazardous
Substances Pollution Contingency
Plan, 40 CFR part 300, subpart E.
(Approved by the Office of Management ami
Budget under control number 2050-0046)
|52 FR 10719, Apr. 2. 1987. Redesignated and
amended at 61 FR 7421. Feb. 2». 19%; 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-
lermeasure Plan requirements for on-
shore oil production facilities.
112,10 Spill Prevention, Control, and Cciun-
termeasure Plan requirements for on-
shore oil drilling and workover facilities.
112.11 Spill Prevention, Control, and Cciun
terrneasure Plan requirements for off
share 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 Cciun-
tenneasure Plan requirements for on-
shore oil production facilities,
112.14 Spill Prevention, Control, and Coun-
tenneasure Plan requirements for on-
shore oil drilling and workover facilities.
19
-------
§112.1
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 THK 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 HZ—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 *«j.; 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 47HO. July 17, 2002, unless
otherwise noted.
1112.1 General applicability.
(a)(l) This part establishes proce-
dures, methods, equipment, and other
requirements to pi-event 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 affrct natural
resources belonging to, appertaining
40 CFR Ch. I (7-1-05 Edition)
to, or under the exclusive management
authority of the United States (includ-
ing resources under the Magnuson
Fishery Conservation aiid 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-
portal ion 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 Stales (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
-------
Environmental Protection Agency
§112.1
not subject to the jurisdiction of the
Environmental Protection Agency
(EPA) under section 3110)(D(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.) arid
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 huried 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
§H2.7(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.
(B) 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.
(c) 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
-------
§112.2
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 3t!(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)(Z) 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.
40 CFR Ch. I (7-1-05 Edition)
(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
-------
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 riot 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 '/.one, 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-
lion 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
(he CWA, that are caused by events oc
cuiTing within the scope of relevant op
crating or treatment systems. Hor 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 011
23
-------
§112.2
several site specific factors, including,
but not limited l.o. 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
arid 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 arid 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 arc currently used,
were used in the past, or may be sus-
40 CFR Ch. I (7-1-05 Edition)
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 vvaters:
(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 (I) 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-petroleurn 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
-------
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
sponsc 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 riot 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,
arid 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, arid the Pacific Is
land Governments.
Vegetable oil means a non-petroleum
oil or fat of vegetable origin, including
25
-------
§112.3
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, arid
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 Counter-measure 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
§112.1(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
40 CFR Ch. I (7-1-05 Edition)
to have a discharge as described in
§li;M(b). you must prepare and imple-
ment a Plan before you begin oper-
ations.
(c) If you are tho 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;
(ili) 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) Thai; 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 accoi'dance with
the requirements of this part.
26
-------
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.
(1) Extension of time. (I) 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 lime
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 (0(0 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
(in) 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 (0(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, 2B03; 68 FR 18*94, A[>r. 17.
2003; 69 FR 48798, Aug. 1!. 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.l(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
-------
§112.5
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 (he 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.
40 CFR Ch. I (7-1-05 Edition)
(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 §HZ.l(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
preparat ion of the amendment.
(D) 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
-------
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.l(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, "1 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 arid 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 §§U2.8(c)(2),
12.13(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 burled tanks that are
otherwise exempted from the require-
ments of this part under § I12.1(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
-------
§112.7
(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
(vt) 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.l(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
40 CFR Ch. I (7-1-05 Edition)
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. !(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) Ret€>ntion 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), m.8
112.13(c)(2), and 112.14(c) to prevent a
discharge as described in §ll2.I(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
-------
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
§112.1(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
-------
§112.8
discussion of coiiformiince 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
Countermeasure 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 ami 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-
40 CFR Ch. I (7-1-05 Edition)
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 §H2.1(b) in
case there is an equipment failure or
human error at the facility.
(c) Bulk storage containers. (I) 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 § U2.1(b).
32
-------
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-
t ion 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
ganger 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.l(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.
(II) Position or locate mobile or port-
able oil storage containers to prevent a
discharge as described in §M2.1(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, [lump-
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
-------
§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 (.he 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 arid
allow for expansion and contraction.
(4) Regularly inspect, all abovegrourid
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 abovegrourid piping or other
oil transfer operations.
§112.9 Spill Prevention, Control, and
Counter-measure 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. (I)
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
uncontamlnated 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 balk 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
-------
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
Co unterineasure Plan requirements
for onshore oil drilling and
workover facilities.
If you are the owner or operator of an
onshore oil drilling and workover facil-
ity, you must:
(a) Meet the general requirements
listed under §112.7, and also meet the
specific discharge prevention and con-
tainment procedures listed under this
section.
(b) Position or locate mobile drilling
or workover equipment so as to pre-
vent a discharge as described in
(c) Provide catchment basins or di
version structures to intercept and
contain discharges of fuel, crude oil, or
oily drilling fluids.
(d) Install a blowout prevention
(BOP) assembly and well control sys-
tem before drilling below any casing
string or during workover operations.
The BOP assembly and well control
system must be capable of controlling
any well-head pressure that may be en
countered while that BOP assembly
and well control system are on the
well.
§ 112.11 Spill Prevention, Control, and
Countermeasure Plan requirements
for offshore oil drilling, production,
or workover facilities.
If you are the owner or operator of an
offshore oil drilling, production, or
workover facility, you mvist:
(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.l(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:
(I) 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) Kquip 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
-------
§112.12
must use simulated discharges for test-
ing arid inspecting human and equip-
ment pollution control and counter-
measure systems.
(]) 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 How 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.
40 CFR Ch. I (7-1-05 Edition)
Subpait 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.
8 112.12 Spill Prevention, Control, and
Countermeasure 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 arc designed to control
such discharge. You may empty diked
areas by pumps or ejectors; however,
you must manually activate these
pumps or t-jectors 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 arid 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 uiidiked 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
facilitv. You must not locate
36
-------
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.I(b) in
case there is an equipment failure or
human error at the facility.
(c) Bulk storage containers. (I) 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).
(ill) Open the bypass valve find 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 I22.41(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-
mourited, 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
uudible or visual signal at a constantly
37
-------
§112.13
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.
(ill) Direct audible or code signal
communication between the container
gauger and the pumping station.
(iv) A fast response system for deter-
mining the liquid level of each bulk
storage container such as digital com-
puters, telepulse. or direct vision
gauges. If you use this alternative, a
person must be present to monitor
gauges and the overall filling of bulk
storage containers.
(v) You must regularly test liquid
level sensing devices to ensure proper
operation.
(9) Observe effluent treatment: facili-
ties frequently enough to detect pos-
sible system upsets that could cause a
discharge as described in § 112.1 (b).
(10) Promptly correct visible dis-
charges which result in a loss of oil
from the container, including but not
limited to seams, gaskets, piping,
pumps, valves, rivets, and bolts. You
must promptly remove any accumula-
tions of oil in diked areas.
(11) Position or locate mobile or port-
able oil storage containers to prevent a
discharge as described in § 112.1 (b). 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
40 CFR Ch. I (7-1-05 Edition)
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
Counter-measure 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 &112.1(b), close and seal at all
times drains of dikes or drains of
equivalent measures required under
§112.7(c)(l), except when draining
uncontaminated rainwater. Prior to
drainage, you must inspect the diked
area and Hake action as provided in
§112.12{<:)(3)(ii), (ill), and (iv). You must
remove accumulated oil on the rain-
water and return it to storage or dis-
pose of it In accordance with legally
approved methods.
(2) Inspect at regularly scheduled in-
tervals field drainage systems (such as
drainage ditches or road ditches), and
oil traps, sumps, or skimmers, for an
accumulation of oil that may have re-
sulted from any small discharge. You
must promptly remove any accumula-
tions of oil.
(c) Oil production facility bulk storage
containers. (I) Not use a container for
38
-------
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 ail 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-
tern.
(d) Facility transfer operations, nil 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 flowllne main-
tenance to prevent discharges from
each flowline.
§112.14 Spill Prevention, Control, and
Countenneasure 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
Counter-measure 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.l(b). Where
drains and sumps are not practicable,
39
-------
§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 arid inspection of
the pollution prevent ion 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 submarine 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
-------
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 ct sag.) 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.
(i) The owner or operator of a facility
in operation on or after August 30, 1991
that satisfies the criteria in paragraph
(f)(l) of this section or that is notified
by the Regional Administrator pursu
aril 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) (1)
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 (0(1) 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 opcr
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 (0(1) 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 H 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).
(lv) 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
(0(1) 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 (0(l)(ii)(B) or (f)(l)(ll)(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
-------
§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 arid 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 mtiets 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)(li) 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) (1)
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 (0(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
-------
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
feet 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(s) that does not result in a ma-
terial change in support capabilities do
not require approval by the Regional
Administrator. Facility owners or op-
erators shall provide a copy of such
changes to the Regional Administrator
as the revisions occur.
(3) The owner or operator of a facility
that submits changes to a response
plan as provided in paragraph (d)(l) or
(d)(2) of this section shall provide the
F,PA-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)(l) of this section for a fa-
cility determined pursuant to para-
graph (f)(3) of this section to have the
potential to Cause significant and sub-
stantial harm to the environment.
(e) If the owner or operator of a facil-
ity determines pursuant to paragraph
(a)(2) of this section that the facility
could not, because of its location, rea-
sonably be expected to cause substan-
tial harm to the environment by dis-
charging oil into or on the navigable
waters or adjoining shorelines, the
owner or operator shall complete and
maintain at the facility the certifi-
cation form contained in Appendix C to
this part and, in the event an alter-
native formula that is comparable to
one contained in Appendix C to this
part is used to evaluate the criterion in
paragraph (f)(l)(ii)(B) or (f)(l)(ii)(C) of
this section, the owner or operator
shall attach documentation to the cer-
tification fonn 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.
(0(1) 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
-------
§112.20
40 CFR Ch. I (7-1-05 Edition)
(B) The facilit.y 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, sec 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)(0 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; arid
(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 thi; 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 arid update the facility response
44
-------
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 he 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:
(1) 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;
(lii) 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 arid qualifications;
(vl) 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 lo community evac-
uation plans, as appropriate;
45
-------
§112.20
(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 commimicat ion 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
40 CFR Ch. I (7-1-05 Edition)
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
-------
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; anil
(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 dla
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 riot 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 fid 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.
|5S FR 340S8. July 1, 19»4, as amended nt 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
arid 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 § H2.20(h)(8).
47
-------
Pt. 112, App. A
(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 (PRKP) (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 4079H, June 30. 2000J
APPENDIX A TO PART 112—MEMORANDUM
OF UNDERSTANUIMG 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
hulk to or from a vessel.
40 CFR Ch. I (7-1-05 Edition)
(B) Mobile onshore arid offshore oil well
drilling platforms, barges, trucks, or other
mohile 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 w< 11 head 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 facilit les 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 mohile facilities
are fixed in position for the purpose of oil
production operations, hut 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, hut 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 transfer: ing of oil in bulk to or from a
vessel.
(H) Waste treatment facilities including
in-plant pipelines, effluent discharge lines,
and storage tanks, hut excluding waste
treatment facilities located on vessels and
terminal storage tanks and appurtenances
fur the reception of oily ballast water or
tank washings from vessels and associated
systems used for off-loading vessels.
48
-------
Environmental Protection Agency
(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 hulk 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 ("or the
transport of oil exclusively within the con-
fines of a riontransportatiori 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 hulk to or from
a vessel.
(2) Transportation-related nnshorr 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 reeep
tlon 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, hut 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 rars and motive
power used exclusively within the confines of
a nontransportation-related facility or ter
mirial facility and which are not intended for
use in interstate or Intrnstate commerce.
Pt. 112, App. B
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 jurlsdictional respon-
sibilities for offshore facilities, including
pipelines, pursuant to section 311 (j)(l)(c),
0)(5), and (j)(6)(A) of the Clean Water Act
(CWA), as amended hy 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.G.) 12777 (56 FR 54757)
delegates to DOI, DOT. and EPA various re-
sponslhilitles 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)(11) de-
fines the term "offshore facility" to include
facilities of any kind located in, on, or under
navigable waters of the United States. By
using this definition, the traditional DOI
role of regulating facilities on the Outer
Continental Shelf Is expanded by E.O. 12777
to include inland lakes, rivers, streams, and
any other Inland waters.
RESPONSIBILITIES
Pursuant to section 2(i) of E.O. 12777, DOI
redelegatos, and EPA and DOT agree to as
sume, the functions vested in DOI by sec-
tions Z(b)(3), 2(d)(3). arid 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. 13lll(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 rion transportation-related offshore fa-
cilities located landward of the coast line.
>. To DOT, DOI redelegates responsibility
lor 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
-------
Pf. 112, App. C
3. The DO! 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 effect ive on the date of the
final execution hy the indicated signatories.
LIMITATION'S
1. The DO1, DOT, and KPA may agree In
writing to exceptions Co this MOU on a facil-
ity-specific hasis. Affected parties wilt re-
ceive notification of the exceptions.
2. Nothing in this MOU is intended to re-
place, supersede, or modify any existing
agreements hetween 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 he 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 i-onsldering excep-
tions or modifications to this agreement.
This MOU may he terminated only with the
mutual consent of all parties.
Dated: November 8. 1993.
Bruce Babbitt,
Secretary of the Interior.
Dated: December 14, 1993.
Federico Peiia,
Secretary of Transportation.
Dated: February 3, 1994.
Carol M. Browner,
Administrator, Environmental Protection
Agency.
(59 FR 34102, July I, 19941
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 hy dis-
charging into or on the navigable waters or
adjoining shorelines." In addition, the Re-
gional Administrator has the disi.-retlon to
identify facilities that must prepare and sub-
mit facility-specific response plans to EPA.
A / Definitions
1.1.1 Great Lakes means Lakes Superior,
Michigan, Huron, Erie, and Ontario, their
connecting and tributary waters, the Saint
40 CFR Ch. I (7-1-05 Edition)
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 arid Rivet to Philadel-
phia. PA;
(4) St. Crolx. VI;
(5) Pascagoula, MS;
(6) Mississippi River from Southwest Pass.
LA to Baton Rouge. LA:
(7) Louisiana Offshore Oil Port (LOOP),
LA;
(«} Lake Charles, LA;
(9) Sahine 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-
orh. CA:
(14) Straits of Juan de Fuca from Port An
geles, WA t:o 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 Ares 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 Iritracoastal Waterways and
other waterways artificially created for
navigating that have project depths of 12 feet
or less.
2.0 DESCRIPTION OF SCRKENING 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 Kqual to 42.000 Gallons Where Ofierations 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
-------
Environmental Protection Agency
2.2 Lack of Adequate Secondary Contain-
ment at Facilities With a Total Oil Storage Ca-
pacity Greater Than or Equal to I Million Gal
Ions. 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 eng!
neerlng practice for the purposes of this part
include herms, 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
I Million Gallons. A facility with a total oil
storage capacity greater than or equal to 1
million gallons must suhmit 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 offish and wildlife and sen-
sitive environments, see Appendices I. II, and
111 to DOC/NOAA's "Guidance for Facility
arid 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 tu 1 Million Gal-
Ions A facility with a total oil storage capac-
ity greater than or equal to 1 million gallons
must suhmit 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
Pt. 112, App. C
water system as described at 40 CFR U3.2(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 I 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-1I 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.
McGrawHill.
USCG IFR (58 FR 7353, February 5, 1993).
This document is available through EPA's
rultmaking docket as noted In Appendix E to
this part, section 13.
51
-------
ft. 112, App. C 40 CFR Ch. I (7-1-05 Edition)
ATTACHMENTS TO APPENDIX C
Attachment C-I
Flowchart of Criteria for Substantial Harm
I*** th;: facility transfer Oi3 over
water 10 ur from vessels anJ Uocs
the tacilft> han; a total oil
»u>ragc capacity gnrtier thoii »»
equal to J 2.000 gallons'*
N<.
Yes
r:
"I Submit Response Plan
IXics ihc faviEitv have- a tout- ui!
J>turagc capacity jjivalerlHan or
ctjoal lo I million italicm***
Within w>y 4buv of the larccsi
dhov^i-oimd nil storage tank pEus
!»ii01ciff]it froclxwd 10 alinw for
h iftc lacilhs' located at a distance1 such
thai i di$chAr^c from the f*cilij> could
cuust: iitjuiy lu Ti-il and wildlife iirtJ
h ihc facility lufit'ed ut u distance'
Ihjl a ili^^Mr^c tr.ml rh« (At'itrt> v.o
3.iiui down a put-li* drbikiny waicr in
'No
H.t> llie facili;y c^f-crrwuitx) a rcfOn.ihic oil
iptll m an ;«nc.uttt [Jfcafer lliaii iir pqual fo
I O.UOU pilous within flic lt tiveycaf'j?
No Sub initial of Response Plan
Except at RA Discretion
Yes
: Calculated using ihc appropriate formula in Auachment C'-ITI lu this appendix or a c*nnparahlc
formula.
3 For fttrther description offish and wildlife and sensitive environments sec Appendices fJJ. and
HI U» DOC/NOAA's "Guidance fw Facility and vessel response Plans- fish and Wildhlc and
Sensitive Environments" (5£ V R 14? 13. March 2V> \ 994) and Ihc applicable Area Contingency
PUn.
? Public drinking wuici' intakes aix% analogiius to public water systems as described at CFR
52
-------
Environmental Protection Agency
ATTACHMENT C-ll—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
freehoard 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 locatE;d at a dis-
tance (as calculated using the appropriate
formula if) Attachment C-III to this appen-
dix or a comparable formula') such that a
discharge from the facility could cause in-
jury to fish and wildlife and sensitive envi-
ronments? For further description offish and
wildlife and sensitive environments, see Ap-
pendices I, 11, 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
Corn ingency 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-
tant e (as calculated using the appropriate
formula in Attachment C-III to this appendix
or a comparable formula1) such that a dis-
charge from the facility would shut clown 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 1 have
personally examined and am familiar with
the information submitted in this document,
!lf 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
Pt. 112, App. 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 puhlic 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 ehh ride 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 41)
CFR 112.20(0 (l)(ii)(B) or (f)(l)(ii)(C). the
owner or operator shall attach documenta-
tion to the response plan cover sheet con-
tained in Appendix F to this part that dem-
onstrates the reliability and analytical
soundness of the alternative formula and
shall notify the Regional Administrator in
53
-------
Pt. 112, App. C
writing that an alternative formula was
used,'
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
talriment or oil spill history, as listed in the
flowchart In Attachment C-l 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.
1A A facility owner or operat or who must
perform a planning distance calculation an
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 Ite 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 hy 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 hy 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 rive;r
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.
40 CFR Ch. I (7-1-05 Edition)
Coefficient (for flood flow rates), n, fan be
determined from Table 1 of this attachment.
The hydraulic radius, r. can l>e estimated
using the average mid-clinnnel depth from
charts provided hy 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.
l.fi Table 3 of Oils 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 hcurs 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 tfiis 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 §H2.20(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-
Mannirig's equation (see below and Tables I
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 secw mile/
hrffl ft (3600 sec/hr * 5280 ft/mile).
2.2 Chezy-Manning's equation is used to de-
termine velocity:
v=l.S/nxr%xs'/z; where
vthe velocity of tin- river of concern (in ft/
sec);
n-Mann!iig'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
-------
Environmental Protection Agency
(sources for obtaining the mid-fhannel
depth are listed in Table 2 of this attach-
ment); and
s=the average slope of the river (unit less) 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 lor 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 r|.)
Regular section:
Irregular section:
(Brush)
Rough-
ness co-
efficient
(n)
0 03
0 G4
0 06
0 10
0 035
0 05
TABLE 2—SOURCES OF R AND s FOR THL CHLZY-
M ANN INC EQUATION
All of the charts and related publications fnr
navigational waters may be ordered from:
Distribution Branch
(N/CG33)
National Ocean Service
Riverdale, Maryland 20737-1199
Phone: (301) 136-6990
There will be a charge for materials ordered
and a VISA or Mastercard will he arcepted.
The mid-channel depth to he 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 Hydrographlc Service
Department of Fisheries and Oceans Insti-
tute
P.O. Box 8080
1675 Russell Road
Ottawa. Ontario K1G 3H6
Canada
Phone: (613) 998-4931
Chares 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
Vicksbutg District
P.O. Box 60
Vicksburg, Mississippi 39180
Phone: (601) 634-50(10
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
Pt. 112, App. C
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) 221-39(10
Charts of Ohki River:
U.S. Army Corps of Engineers
Ohio River Division
P.O. Box 1159
Cincinnati. Ohio 45201
Phone: (513) 6S4-3002
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, Tornbighee River. Apalachicola
River and Pearl River:
U.S. Army Corps of Engineers
Mobile District
P.O. Box 2288
Mobile, Alabama 36628-0001
Phone: (205) 6»0-2511
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 1 lie average slope of the river (s) can
he 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 dowrr
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 ihe Normal Pool Elevation is not
available, the elevation contours can be used
to lind the slope. Determine elevation of the
water at the point of discharge from the fa
cillty (A). Determine the elevation of the
55
-------
Pt. 112, App. C
water at. the appropriate? distance down-
stream (B). The formula presented below can
be used to calculate the slope.
(5) Determine the distance (In miles) be-
tween the facility anri 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 lie a unitless value: Average
Slope-i(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- sitf. A specific
length, such as 100 feet, ran be marked off
along the shoreline. A float can be dropped
into the stream .ibove 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 fcir the length
of the stream, but a velocity only for the
specific location (if 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 art of concern Tiecause they
can remain iti 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 (if 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—SPECIRED TIME INTERVALS
Operating
areas
Higher volume
port area.
Great Lakes ...
Substantial harm planning time (hrs)
12 hour arnvakS hour deployment-is
hours.
24 hour arrival+3 hour deployment-??
hours.
40 CFR Ch. I (7-1-05 Edition)
TABLE 3— SPECIFIED TIME INTERVALS—
Continued
Operating
areas
All other rivers
and canals,
inland, and
nearshore
areas.
Substantial harm planning time (hrs)
24 hour
hours,
arrivals hour deptoyment-27
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 Chfizy-Manning equation:
Find the roughness coefficient, n, on Table
I of this attachment fcir a regular section of
a major stream with a top width greater
than 100 feet. The top width of the river can
he found from the topographic map.
n=0.035.
Find slope, s. where A=727 feet, B=710 feet.
and C-2S miles.
Solving:
s-|(727 ft-1710 ft)/25 miles]xjl rnile/5280
feet|-1.3xlO-«
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 hy 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^l.S/nxr2"**"2:
v.|1.5/O.II35)x(13.33)2»x(1.3xlO-«)1/;:
v=2.73 fret/second
(2) Find t from Table 3 of this attachment.
The Monongahela River's resource response
time is 27 hours.
(3) Solve fnr planning distance, d:
d=vxtxc
d=(2.73 ft/ser)x(27 hours)x(l).68 sects mile/hra
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
-------
Environmental Protection Agency
the planning distance. If a comparable for-
mula is used, documentation of the reli-
ability and analytical soundness of the com-
parable calculation must he attached to the
response plan cover sheet.
3.2 Example of the Planning Distance Cal-
culation for Oi/ 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:
C=0.1643
Al-10'x(2,000.0«0gallons)y»x(0.1643)
A, -8.74x10" ft'
(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
when- it intellects 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 assumpi ion 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 r>}/2
Solving for the radius, r, using the relation-
ship Ai=Az: 8.74xlO« ft-'=(t!V2
Therefore, r-23,586 ft
r-23,586 ft»S.280 ft/mileH.5 miles
Assuming a 20 knot wind under storm condi-
tions:
1 knot=1.15 miles/hour
20knotsxl.l5 mlles/hour/knot=23 miles/hi
Assuming that the oil slick moves at 3 per-
cent of the wind's speed:3
23 miles/hourxfl. 03=0.69 miles/hour
(5) To estimate the distance that the oil
will travel, use the times required tor re-
sponse resources to arrive at different, geo-
graphic locations as shown In Table 3 of this
attachment.
For example:
ZHuang, J.C. and Monastcrti. K.C.. 1982. Re-
view of the State-oi-the-Art of Oil Pollution
Models. Final report submitted to the Amer-
ican Petroleum Institute by Raytheon Ocean
Systems, Co.. East Providence. Rhode Island.
JO;; Spill Prevention & Control. National
Spill Control School, Corpus Christi State
University, Thirteenth Edition. May 1990.
Pf. 112, App. C
For Higher Volume Port Areas: 15 hrsxO.69
rniles/hr^lO.4 miles
For Great Lakes and all other areas: '11
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=10.4f4.5 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 hecause 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 ehh 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
tiiial waters, the planning distance Is 5 miles
from the facility down current during ehh
tide and to the point of maximum tidal influ-
ence or 5 miles, whichever is less, during
Hood tide.
4.3 Example of Determining the Planning
Distance for Two Types of Navigable Water
Conditions. Below is an example of how to de
tcrmine the proper planning distance when a
facility could impact two types of navigahle
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 he 0.5 feet/
second from the Chezy-Manning equation
used to calculate oil transport on moving
navigahle waters. The specified time inter-
val, t, obtained from Table 3 of this attach-
mcnt for river areas is 27 hours. Therefore,
solving for the planning distance, d:
ri=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 t.lde 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 ail 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
-------
Pt. 112, App. C
waters via open channel flow or from sheet
flow across the land, or be prevented from
reaching navigable waters when trapped in
natural or man-made depressions excluding
secondary containment structures.
5.2 As discharged oil travels over land, it
may enter a storm drain or open concrete
channel intended for drainage. It is assumed
that once oil reaches such an inlet, it will
flow into the receiving navigable water. Dur-
ing a storm event, it is highly probable that
the oil will either flow into the drainage
structures or follow the natural contours of
the land and flow into the navigable water.
Expected minimum and maximum velocities
are provided as examples of open concrete
channel and pipe flow. The ranges listed
below reflect minimum and maximum ve-
locities used as design criteria.' 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 arid can be considered instanta-
neous. The velocities are:
For open concrete channels:
maximum velocity=25 feet per second
minimum veloclty-3 feet per second
For storm drains:
maximum velocity-25 feet per second
minimum velocity-2 feet per second
S.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 fei-t 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-l of this attachment. The
relevant distances can he described as fol-
lows:
Dl=Distance from the nearest opportunity
for discharge. X i, to u 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=Dlstance downstream from the outfall
within which fish and wildlife arid sensitive
4The design velocities were obtained from
Howard County, Maryland Department of
Public Works' Storm Drainage Design Man-
ual.
40 CFR Ch. I (7-1-05 Edition)
environments could be injured or a public
drinking water intake would he shut down
as determined hy the planning distance
formula.
U4 "Distance from the nearest opportunity
for discharge, X2, to fish and wildlife and
sensitive environments riot bordering navi-
gable waver.
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
(1.5 mile and other factors are conducive to
oil travel over land) to storm drains thac
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
I he facility could pose substantial harm be-
cause the 1 ime 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 hind 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 riot bordering navigable
waters via oil transport on land, then sup-
porting documentation should be maintained
at the facility. However, such documentation
should he submitted with the response plan
if a facility is found to pose substantial
harm.
58
-------
Environmental Protection Agency
Pt. 112, App. C
D
[59 FR 34102. July 1. 1994, as amended at 65 FR 40798, June 30. 2000; 67 FR 4715Z. July 17. 20021
59
-------
Pt. 112, App. D
APPENDIX D TO PART IIZ—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 he 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
arid provides steps for their inclusion in the
total worst case discharge planning volume.
40 CFR Ch. I <7-1-05 Edition)
Onshore oil production facilities may include
all wells, flowllnes, separation equipment,
storage facilities, gathering lines, and auxil-
iary nori-transportation-relatud 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
erase 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). Alt 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
N1NG VOLUME CALCULATION FOR ON-
SHORE STORAGE FACILITIES'
Part A of this worksheet is to be com
pleted by the owner ur operator of an SPCC-
rfegulated 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
-------
Environmental Protection Agency
A.Z SECONDARY CONTAINMENT -
MUL T1PLE-TANK FACILITIES
Are all aboveground oil storage tanks or
groups of aboveground oil storage tanks at
the facility without adequate secondary con-
tainment?2
(Y/N)
A.2,1 If the answer Is yes, the final worst
case discharge planning volume equals the
total abovegrotmti 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 ahoveground oil storage capacity of
tanks without adequate secondary contain-
ment. If all aboveground oil storage tanks or
groups of ahoveground. oil storage tanks at.
the facility have adequate secondary con
talnment, ENTER "0" (zero).
GAL
A.2.3 Calculate the capacity of the largest
single ahoveground 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:1
GAL
PART B: WORST CASE DISCHARGE PLAN-
NING VOLUME CALCULATION FOR ON
SHORE PRODUCTION FACILITIES
Part B of this worksheet is to lie 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 arid exploratory) and re-
lated equipment in a single geographical oil
or gas field operated by a single operator.
B. I SINGLE TANK FACILITIES
B. 1.1 For facilities containing only one
ahoveground 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).
3All 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.
Pr. 112, App, D
secondary containment (sufficiently large lo
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. 1.2 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 he 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 hy 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.i SECONDARY CONTAINMENT-
MULTIPLE- TANK FACILITIES
Are all aboveground oil storage tanks or
groups of aboveground oil storage tanks at
the facility without adequate secondary con-
tainment?
(Y/N)
B.2.1 If the answer is yes, the final worst
case volume equals the total aboveground oil
storage capacity without adequate secondary1
containment plus the production volume of
the well with the highest output at the facil
ity.
(1) For facilities with production wells pro
due ing by pumping, if the rate of lire 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 dc;-
tennined 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 1.0 be unattended.
(i!) 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
-------
Pt. 112, App. D
B.2.2 If the answer is no, calculate the
total aboveground oil storage rapacity of
tanks without adequate secondary contain-
ment. If all aboveground oil storage tanks or
groups of abovegrounri 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 WILLS OR PRO-
DUCTION WELLS PRODUCING UNDER PRES-
SURE
l.O 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 he 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
spouse 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 luss:
Production volume-30 days x rate of well.
4 All complexes that are jointly regulated
by EPA arid 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.
40 CFR Ch. I (7-1-05 Edition)
(2) For wells deeper than 10,000 feet:
Production volume-45 days x rate of well.
12 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 volurne=di!icharge vcilumet -t- dis-
charge volume;
2.2.2 The first term represents the volume
of the oil discharger! from the well between
the time of the blowout and the time the re-
sponse resources are on scene and recovering
oil (discharge volume:).
Discharge volume |-(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 hegin operating until the
discharge Is stopped, adjusted for the recov-
ery rate of the response resources (discharge
volume J.
(1) For wells 10,000 feet deep or less:
Discharge volumQ-|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 volum§-|45 days—(days unat-
tended -f days to respond)! x (rate of well)
x (rate cif 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 i:o 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 z~[30 (lays—(7 days + ;
days)] x (10 barrels per day) x (fl.5)=105 bar-
rels
(4) Therefore, the production volume is:
Production volume-90 barrels «• 105
barrels~195 barrels
62
-------
Environmental Protection Agency
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. 20021
APPENDIX E TO PART 112—DETERMINA-
TION AND EVALUATION OF REQUIRED
RESPONSE RESOURCES FOR FACILITY
RESPONSE PLANS
l.O 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 112.2Q(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 origiit. 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 80.741) and 80.851).
1.2.3 Non-persistent oils or Croup 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 (S45
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 vegetahle oil, with a specific grav-
ity less than 0.8.
1.2.4 Non-pt-'truleum ti/7 means oil of any
kind that is not petroleum-based, including
but not limited to: fats, oils, and greasers of
animal, fish, or marine mammal origin: and
vegetahle oils, including oils from seeds,
nuts, fruits, and kernels.
Pt. 112, App. E
1.2.5 Ocean means the nearshore area.
1.2.6 Operating ana means Rivers and Ca-
nals, Inland, Nearshore, and Great Lakes ge-
ographic locatlon(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
nial fat or vegetahle 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 vegetahle origin, including but
not. limited to oils and fats derived from
plant seeds, nuts, fruits, arid kernels. Vege-
tahle 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 arid 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.
63
-------
Pt. 112. App. E
2.3 When identifying equipment for the
response plan (based on the use of this ap-
pendix), a facility owner or operator must
consider the inherent limitations of the
operabllity of equipment components and re-
sponse systems. The criteria in Table 1 of
this appendix shall be used to evaluate the
operabllity 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 lr 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-wat«T speed of 5 knots
arid 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-
40 CFR Ch. I (7-1-05 Edition)
tiori, 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 he 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-Petmlrum Oilf 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 rase 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 sliall, as appro-
priate, include:
3.3.! 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 rapacityequal to the
amount of oil discharged in a small dis-
charge or greater which is available at the
64
-------
Environmental Protection Agency
facility within 2 hours uf the detection of an
oil discharge: and
3.3.3 Oil storage capacity for recovered
oily material indicated In section 12.1 of this
appendix.
4.0 Determining Response Resources Required
for Medium Discharges— Petroleum Oik 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 3B,1K)0 gallons of
oil or 10 percent of the worst case discharge,
whichever is less. All equipment identified
must he 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.Z.I Petroleum oils. The USCG planning
level that corresponds to KPA'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 rase 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 ft>r a medium discharge. For
ijon*petroleum oils, there is no USCG plan-
ning level that directly corresponds to F.PA'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
fi 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
live 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. E*'or 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 ul" 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 tills appendix. Temporary stor-
age capacity available on-scene must equal
twice the dally 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
65
-------
Ft. 112, App. E
contract or other approved means as de-
scribed in §112.2, sufficient response re-
sources to respond to the worst: case dis-
charge of oil to the maximum extent prac-
ticable. Sections 7 and 10 of this appendix de-
scribe the method to determine the nec-
essary response resources. Worksheets are
provided as Attachments 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 5H2.2. 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
40 CFR Ch. I (7-1-05 Edition)
volume for response: resources for the worst
case discharge.
5.2 Complexes chat are regulated by EPA
and the USCG muse also consider planning
for the woist case discharge at the transpor-
tation-relaced 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 arid the USCG must compare
both calculations of worst cast 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. lo 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
Tien
(in hours)
g
12
12
Tier 2
(in hours)
30
36
36
Tier 3
(in hours)
54
60
80
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 res|jonse resources would ar-
rive within 60 hours,
5.4 The effective daily recovery capacity
for oil recovery devices identified iti 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
Oils 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 lias
considered in his or her planning. When list-
Ing USCG-classified oil spill removal organi-
zation(s) that have sufficient removal capac-
ity to recover the volume above the response
capacity cap for the specific facility, as spec-
ified in Table 5 of this appendix, it Is not
necessary to list specific quantities of equip-
ment.
5.5 A facility owner or operator shall
identify the availability of temporary stor-
age capacity to meet section 12.2 of tills 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
66
-------
Environmental Protection Agency
Pt. 112, App. E
those resources is capable of being used in
close-co-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 ori-water re-
sponse equipment identified for the applica-
ble operating area shall, as appropriate, he
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 hoorn that are
available, by contract or cither 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 ta this part, section 13, for av«til
ability), arid 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^) (as de-
scribed in §112.2) capable of responding to a
shoreline cleanup operation involving the
calculated volume of oil and emulsified oil
thai, 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 'i. 3,
6, and 7 of this appendix. The volume cal-
culated from these tables is intended t.ci as-
sist the facility owner or operator to identify
an nil spill removal organization with suffi-
cient resources and expertise.
g.O Determining Effective Daily Kecovtry
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 effertive
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.
fi.2.1 The following formula shall be used
to calculate the effective dally 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 V4 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 he 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 he used
to calculate the effective daily recovery ca-
pacity under this alternative:
R - D x U
where:
R—Effective daily recovery capacity.
D—Average Oil Recovery Rate in barrels pnr
hour (Item 26 In F 808-83; Item 13.2.16 in F
631-9(1; or actual performance data); and
U- Hours per day that, equipment can oper-
ate under discharge conditions. Ten hours
per day must, he used unless a facility
owner or operator can demonstrate that
the recovery operation can be sustained for
longer periods.
67
-------
Pt. 112, App. E
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 aii 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=1.82S 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.
220gpm=314 bph
R=314 bphx!2 hr/day=3,76g 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 he 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 emulsificatlon, and the poten-
tial for deposition of oil on the shoreline.
The procedures for non-petroleum oils other
than animal fats and vegetable oili are dis-
cussed in section 7.7 of this appendix.
7.2 The fallowing 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)1; and the facili-
ty's specific operating area. See sections 1.Z.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
40 CFR Ch. I <7-l-05 Edition)
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 art-water oil recovery volume
shall, as appropriate, be adjusted using the
appropriate emulsificatfon 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 iti 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
tin-scene within the applicable time for each
response tier. Three tiers are specified. For
higher volume port areas, the contracted
tiers of resources must he 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 tin-water oil recovery
capacity In barrels per day for each tier is
used to identify response resources necessary
to sustain operations ill the applicable oper-
ating area. The equipment shall be capable
of sustaining operations for the time period
specified in Table 2 tif 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 5112.2. only for the
quantity of resources requited 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 5112.2.
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
68
-------
Environmental Protection Agency
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) fur the
types of oil handled, stored, or transported
at the facility [persistent (Groups 2, 3. or 4)
or non-persistent (Group 1)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 io be
used for shoreline cleanup resource planning.
7.3.2 The shoreline cleanup planning vol-
ume must be adjusted to reflect an emulsi-
ficatlon factor using the same procedure as
described in section 7.2.2 of this appendix.
7.3.3 The resulting volume shall b«; vised
to identify an oil spill removal organisation
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 he 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 an 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-
Pt. 112, App. E
talnment 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 (chat 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-
i-ility is calculated hy adding the capacity of
all aboveground oil storage tanks without
secondary containment (80,000 barrels) plus
the capacity of the largest ahoveground 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
raps identified in Table 5 of this appendix,
the facility owner will contract for a re-
sponse to in,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 hpd 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, 11,
and 111 to DOC/NOAA's "Guidance for Facil-
ity and Vessel Response Plans: Fish and
Wildlife arid Sensitive Environments." (see
Appendix E to this part, section 13, for avail-
ability) and the applicable ACP. Attachment
C-1II to Appendix C provides a method for
calculating a planning distance to fish and
wildlife arid sensitive environments and pub-
lic drinking water Intakes that may he im-
pacted in the event of a worst case discharge.
7.6 The procedures discussed in sections
7.8.1-7.6.3 of this appendix must tie 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 hy contract or
other approved means, as described in SI 12.2.
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, sorhent 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;
69
-------
Pt. 112, App. E
(4) Equipment necessary to assess the im-
pact of such discharges: and
(5) Other appropriate equipment necessary
to respond t.o 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
Croup 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 he the quali-
fied individual identified In the response
plan or another appropriate Individual lo-
cated at the facility.
7.7 Nan petroleum nils atJiw than animal
fats and vegetable wl'/s. The procedures de-
scribed 111 sections 7.7.1 through 7.7.5 of this
appendix must be used to determine appro-
priate response pliin development and eval-
uation criteria for facilities that handle,
store, or transport, nori-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 arid 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-
40 CFR Ch. I (7-1-05 Edition)
itations that are Identified in the appro-
priate ACPs. including!
(1) Ice conditions;
(2) Dubris:
(3) Temperature ranges; and
(4) Weather-related visibility.
7.7.3 The owner or operator of a facility
(hat 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
cither 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 docs 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 resourc-es. The owner or oper-
ator shall ensure, by contract or other ap-
proved means as described In §112.2, Un-
availability of these resourc-es. 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 he 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 discliarge is defined as any discharge
volume less than or equal to 2,100 gallons,
hut 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.
70
-------
Environmental Protection Agency
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 Dischargrs-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 arc regulated by KPA
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 rio
have requirements (at. 33 CFR 154.545) to
identify equipment to contain oil resulting
from an operational discharge.
Pt. 112. App. E
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
111 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 arid 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 tri 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 abovegrouiid storage
tank volume is 841).WO 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 IB.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
71
-------
Pt. 112, App. E
daily recovery rapacity as indicated in sec-
tion 12.2 of this appendix, or :(6.000 gallons
per day. This is tlie information die 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
hoom 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 till
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 eniulsificatiori,
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 1:0
that provided by the procedures in section
10.7 of this appendix.
10.2 The following procedures must tie
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 till storage
capacity. This information is to be used with
Table B of this appendix to determine the
percentages of the total volume to be used
for removal capacity planning. Table 6 (if
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, he 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
40 CFR Ch. I (7-1-05 Edition)
for (he 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 ori-water
oil recovery capacity In barrels per day that
must he identified or contracted to arrive
on-scene within the applicable time for each
response tier. Three i iers 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, arid GO 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 rap specified in Table 5 of this ap.
pendix, thc-n a facility owner or operator
shall ensure, by contract or other approved
means as described in §112.2, only for the
quantity of resourci-s 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 tn be under contract
by 2003, as appropriate. For a facility that
handles multiple groups of oil, the required
effective dally 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 Thi: following must IK; 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
72
-------
Environmental Protection Agency
(i.e., operating areas). For a facility han-
dling, storing, or transporting oil from dif-
ferent groups, each group must he 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 he 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, hy contract
or other approved means as described in
5112,2. the availability of these resources.
The response plan must also identify an indi-
vidual to work with the fire department for
Croup 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 he the qualified
individual identified in the response plan or
another appropriate individual located al.
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-
Pt. 112, App. E
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
ahoveground 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 15, column Nearshore/InlandV
Great Lakes): Inland. Group B is 20%
Kmulsion factor (from Table 7): 2.0
Planning volumes for on-water recovery:
21,000,000 gallons x 0.2 x 2.0 = 8,400,000 gal-
lons or 200,000 barrels.
Determine required resources for on-water
recovery for each of the three tiers using
mobilization factors (from Table 4, column
Inland/Nearshore/Great Lakes)
Inland Operating Area
Estimated Daily Recovery Capacity (bbls) ..„„..,„„..„,..,
Tiert
15
30000
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 (hpd) for Tier 1. 25,000
bpd for Tier 2. and 50.001) bpd for Tier 3. Re-
sources for the remaining 17.500 hpd for Tier
1, 25,000 bpd for Tier 2, and 30,000 bpd for Tier
3 shall be Identified hut need not be con-
tracted for in advance.
10.5.4 With the specific worst (rase dis-
charge Identified, the planning volume of on-
shore recovery can IK identified as follows:
Worst case discharge: 21 million gallons
(51X1,000 barrels) of Group B vegetable oil
Operating Area: Inland
Planned percent recovered floating vegetable
oil from onshore (from Table 6, column
Nearshore/lnland/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
-------
Pt. 112, App. E
and sensitive environments wlt.hin the area
potentially Impacted by a warst case dis-
charge from the facility. For further descrip-
tion of fish arid wildlife and sensitive envi-
ronments, see Appendices I. II, and 111 to
DOC/NOAA's "Guidance lor 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 he
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 Si 12.2.
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 discliarge Involving the tyi>e
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
40 CFR Ch. I (7-1-05 Edition)
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 strategitrs far 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 vising the criteria in Table 1
tif 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
tliat handles, stores, or transports animal
fats and vegetable oils must identify the re-
sponse reso'-irces that are available by con-
tract or other approved means, as described
in 5112.2. The equipment described in the re-
sponse plan shall, as appropriate, include:
(1) Containment boom, scirhent 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 he capable of com-
mencing an effective on scene response with-
in the applicable tier response times in sec
t Ion 5.3 of this appendix.
10.7.5 A response plan must identify re-
sponse resources wir.h 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
-------
Environmental Protection Agency
the facility or that, cannot rely on sufficient
local fire fighting resources must identify
adequate fire fighting resources. The owner
or operator shall ensure, hy corn ract or
other approved means as described in §112.2,
the availability of these resources. The re
spouse 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 thai
sufficient well-trained fire lighting 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 A variability of
Alternative Ki-sponse Methods
11.1 For chemical agents to be identified
in a response plan, they must be on the NCP
Product Schedule that is maintained hy
EPA. (Some States have a list of approved
dispersants for use within Slate waters. Nor
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 tie
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 Ofjerations
12.1 A facility owner or operator shall
identify sufficient response resources avail-
able, by contract or other approved means a.s
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 ceil-
leciing up 10 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 cif 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 SCCMIB. This
temporary storage rapacity may be reduced
if a facility owner or operator can dem-
onstrate hy waste stream analysis that the
efficiencies of the oil recovery devices, abil
ity to decant waste, or OIL- availability of al-
ternative temporary storage or disposal loca
Ft, 112, App. E
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 he addressed in the applicable ACP.
13.0 References and Availability
13.1 All materials listed in this section
are part of EPA's rulemaking docket arid 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 he
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 l>e 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 hy 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 K
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 Consliohocken,
PA 19428-2959.
(4) Response Plans for Marine Transpor
tation-Related Facilities, Interim Final
Rule. Published by USCG. DOT at 5» FR 7330-
76. February 5. 1993.
75
-------
Pf. 112, App. E 40 CFR Ch. I (7-1-05 Edition)
TABLE 1 TO APPENDIX E—RESPONSE RESOURCE OPERATING CRITERIA
Oil Recovery Devices
Operating environment
Significant wave
height '
< i loot , ,
< 3 teet
< 4 teet ,
< 8 teet
Sea state
1
2
2-3
3-4
Boom
Boom property
Significant wave Height ' . ........
Reserve Buoyancy to Weigh! Ratio
Skirt Fabric Tensile Strength— pounds
Skirt Fabric Tear Strength — pounds
Rivers and
canals
s 1
1
6-1 B
2;1
4.500
200
100
Us
Inland
< 3 ...
2
18-42
2:1
15,000-
20.000.
300
100
e
Great Lakes
<4
2-3
18—42
2:1
15,000-
20,000
300
100
Ocean
<6
3-4
>42
3:1 to 4:1
>aoooo
500
125
'0il recovery devices and boom snail be at least capable o< operating In wave heights up to and including the values listed In
Table 1 lor each operating environment.
TABLE 2 TO APPENDIX E—REMOVAL CAPACITY PLANNING TABLE FOR PETROLEUM OILS
Spill location
Sustainability of en-water oil recovery
Oil group'
4 — Heavy crudes and iuete .................
Rivers and canals
3 days
Percent nat-
ural dissipa-
tion
80
40
20
5
Percent re-
covered
floating oil
10
IS
15
20
Percent cil
onshore
10
45
65
75
Nearshore/lnlano/Great Lakes
4 days
Percent nat-
ural disspa-
tior,
BO
50
30
10
Percent re-
covered
floating oil
20
50
50
SO
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—EMULSIFICATON FACTORS FOR PETROLEUM OIL GROUPS '
Non-Persistent Oil:
Group 1
Persistent Oil:
Group 2
Group 3
Group 4
Group 5 oils are defined in section 1.2.7 of this appendix; the response resource considerations are outlined in section
7.6 ot this appendix.
< See sections 1 £.2 and 1.2.7 of this appendix for group designations lor non-persistent and persistent oils, respectively.
TABLE 4 TO APPENDIX E—ON-WATER OIL RECOVERY RESOURCE MOBILIZATION FACTORS
1.6
2.0
Operating area
IntanoYNearshore Great Lakes
Tien
030
0.16
Tier 2
0.40
0.25
TierS
0.60
0.40
Note: These mobilization factors are for total resources mobilized, not incremental response resources,
TABLE 5 TO APPENDIX E—RESPONSE CAPABILITY CAPS BY OPERATING AREA
February 18, 1993:
All exccot Rivers & Canals. Great Lakes
Tier 1
1 0K bbls/dav
Tier 2
20K bbls/dav
Tiers
40K bbls/dav.
76
-------
Environmental Protection Agency Pt. 112, App. E
TABLE 5 TO APPENDIX E—RESPONSE CAPABILITY CAPS BY OPERATING AREA—Continued
Rivers & Canals
February 18,1998:
February 18, 2003:
Rivers & Canals
Tierl
SK bbls/day
1.5K bbls/day
12 5K bbls/day
6 35K bbls/day
1 675K bbls/
day
TBO
TBD
TBD
Tiers
10K bbls/day
3 OK bbls/day
25K bbls/day
1 2 3K bbls/day
3 75K bbls/day
TBD
TBO
TBO
Tiers
20K bbls/day
6.0K bbls/day.
SQK bbls/day
JSK bbls/day
7 SK bbls/day
TBD
TBD
TBO.
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 group *
Group B
Rivers and canals
3 days
Percent nat-
ural loss
40
20
Percent re-
covered
floating oil
15
15
Percent re-
covered oil
from on-
shore
45
65
Nearshore/lnland/Great Lakes
4 days
Percent nat-
ural loss
SO
30
Percent re-
covered
floating oil
20
20
Percent re-
covered oil
tram on-
shore
30
50
'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 ot the facility is responsible for determining appro-
priate response resources tor 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 ot this appendix. The owner or operator of the facility is responsible (or 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 tor 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 t.2.1 and 1.2,9 ot this appendix; the response resource procedures are discussed
in section 10.6 of this appendix.
77
-------
Pt. 112, App, E 40 CFR Ch. I (7-1-05 Edition)
ATTACHMENTS TO APPENDIX E
Att*ChlMDt 1-1 --
Vork»h*ct to Plan Volume o£ Reaponae x««ourc*i
for Mont Cacft Discharge - P*trol«um Oil*
Part I Background. ta£o_rgfltion
Step (A) Calculate Horat Case Discharge in barrels {Appendix D", |
Step \S> GL1 Group1 [Table- 3 and section 1-2 o£ ^Kia appendix)
step (C) Operating Area (choose one]
r:d Great
Lak«B
Step (C) Percentages of Oil (Table 2 of this appendix!
Percent Lost, t j
a t u r a 1 Disci pat.: or.
Percent Recovered
Floating Oil
or Rivers
and
Canals
Oil Onshore
Step (Eli Or.-Hater Oil Recejvery Step i~ voiw^c -at 1!^.* tt,LAl oil sto'*je c«p«cicy it ttvc f*CilUy- F^i piirpftiita ;if thia c»li
78
-------
Environmental Protection Agency
Pt. 112, App. E
g-1 (cootinu»d) --
to Plan Volum of R«pou* RMOurcis
for Wor»t €••• Diccliargo - Petroleum Oils
Part II On-Mater Oil Recovery Capacity (barreld/day)
Tie/: I Tier 2
st«p « ST«p tF>
Step (CD
Step <£!> X St«p IF) It
5t«p (62)
Tier 3
Stop (E1J x Step (F) «
Step
Part III Shor^yine Cleanup yolume (barrels) . .
Part IV On-Watg;jy Pegponse Capacity By Operating Area
(Table 5 of this appendix)
(Amount needed to be contracted for in barrels/day)
step (E2) > sttp (
Tier 3
U!) (J3)
Part V On-Water Amount Needed to be Ldttntj.fied. but not Contracted Cor in
fidvanca (barrels/day)
Tier 1 Tier 2 ' Tier 3
II Il«r 1 - Step (JD
P.rt II Titr 2 - tttp (JS)
II Her 3 - step
NOTE: To convert from barrels/day to gallons/day, multiply the quantities in
Parts II through V by 42 gallons/barrel.
79
-------
Pt. 112, App. E
40 CFR Ch. I (7-1-05 Edition)
Morttah««t to Plan Voluaw of R»pon** R«aourc
Cor Nor*t C*l* Diacktr?* - P«trol*ura Olli
Part I Background _lo format ion
Step [Ai Calculate Worst Ca.ee Discharge In barrels :Appendtx p- I 170,000
Step (BJ Oil Group1 {Table 3 and flection X-2 of this appendix)
Step fC) Operating Area Ichoose one; . .
shore,' Inla
(£} Percentages of Cil (Table 2 of this appendix)
Percent Lost to
Natural DiesiF»tit>
Floating Oil
50
Percent Oil Onshore
Step (Ell Gn-Water Oil Recovery Step (DZi x StCB tAl
100
(S21 Shoreline Recovery Step (D3l x Step (A.'
Seep (Ft Emuisi f.ica*ion Factcr
(Table '3 o:' this appendix) . .
Step tw hrmd to d*^r«rn« the p^rcsntiie of tht fkeitrty'i totil oft ttor««« capacity.
80
-------
Environmental Protection Agency
Pt. 112, App. E
Attachment Z-l Bx«mpl*. (continued) --
Worksheet to Plan volume of xe. x
Stic (G1>
Step
Tier
40,000
Part U Tier J - Step tJ2)
Purt II Tier 3 - step UJ>
HOT6: To convert from barrels/day to gallons/day, multiply cue quantities ii
Parts II through V by 42 gallons/barrel,
81
-------
Pt. 112, App. E
40 CFR Ch. I (7-1-05 Edition)
Attachment 1-2 - •
Nerkaheat to Flan volun* o* R«*pon«* Resource*
for lfor»t Caaa Discharge - Animal r«t> and V«g*eabl* dim
Part I Background **fo.rTriaJLi.QJi
Step iA? Calculate Karat Ca.ee Discharge in bartele (Appendix D)
Step {BJ Oil Group1 {Table ^ and section 1.3 of this appendix) .
Step 1C) Cperacin<3 Area (choose one; , , , .
nd Great
Step (D) Pej-cfcntagee of Oii tTable f> of this appendix)
Percent Lost to
Natural Dissipation
I
Flottlng Oil
Step (El) OR-water oil Recovery
Step !E2I Shoreline Recovery SCCP tP3} x SEeo lAI
Percent
i3 Ofiahote
Step (P) Enulaification Factor
(Tabla 7 of this appendix)
Step JGJ On-Water Oil Recovery Resource Hobilization Factor
{Table 4 c.f this appendix)
82
-------
Environmental Protection Agency
Pt 112, App. E
S-2 (continued) --
ttor)t«)ift*t to Plan Volun« oE Ra«pon«* R»«ottrc*«
for Hor.t Caa« DiiehAre* - Aniaal Jut* Mid V«g«tabl« Oil*
Part It On~Ma^ar Oil Recovery Capacity (barrela/day)
Tier 1 Tier 2
St«p (ED R Stfp (F) X
st>p ton
(tip (CD * Sttp (» «
Sttp (12)
Sttp (El) II St«f> (F) I
Part III Shoreline Cleanup Volume (barrels) . . .
Part IV On-Water Reapenae Capacity 8v Operating Area
(Table S of this appendix)
(Amount needed co be contracted for in barrels/day)
Tier 1
Tier 2
$«»> (J!) (J2>
P.rt II Tier > • Iltp
NOTE: To convert from barrels/day to gallons/day, multiply the
quantities in Parts IX through V by 42 gallons/barrel.
83
-------
Pt. 112, App. E
40 CFR Ch. I (7-1-05 Edition)
Attachtt»nt E-2 Bxutpl* --
to Plan Volume of R*spons« R**ourc«m
for Hoc-it Ca»« Discharge - Animal Pat* and Vegetable Oil*
Pare I Background Information
Step (A) Calculate Worst Case Discharge in barrels
(Appendix D)
soo,
000
Step !B) Oil Group- (Table 7 and section 1.2 of this
appendix)
Step 1C) Operating Area (choose
one)
Near
shore/Inl
and Great
Lakes
Step (D) Percentages of Oil (Table fi of this appendix)
or
Rivers
and
Canals
Percent Lost to
Natural
Dissipation
30
Percent Recovered
Floating Oil
20
Percent Oil
Onshore
SO
Step (Ell On -Water Oil Recovery £l;ep JD2) x steP
100
100,000
Step (E2) Shoreline Recovery Step (D3I x Step (taj
' A faculty that handla«, atorat, ar tranaporti lultlpla group* of all mitt do leparata calculation far ai
oil group on ifta aicept far thaaa oil groupo that conatitlRa 10 pareant ar laa> by valuM af tha tatal all
itaraga capacity at tha facility. For purpoaoa af thU calculation, tha voluna* af all praducta In an ail
group auft b* niaMiJ to datenalna tha pareantaga of tha facflfty'f tatal atl starag* capacity.
84