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Chapter 5: Oil/Water Separators
In separators used for oil production, the momentum of the fluid flow is absorbed at the inlet,
thereby reducing the fluid viscosity and allowing oil, gas, and water to separate out of solution. Gas
then rises and flows out at the top of the separator, while oil and water fall to the lower portion of the
vessel and coalesce in separate areas. With the appropriate settling time, the more dense free
water settles beneath the less dense oil. Liquid levels are maintained by float-actuated control
valves or dump valves. As the different pre-set liquid levels are reached, dump valves discharge
water and oil from the separator to appropriate storage areas:
Water is discharged from the bottom of the separator to a water tank;
Oil is discharged out at a higher level to a oil storage tank; and
• Gas flows continuously out at the top of the separator to sales, a meter run, a flare,
or a recovery system.
5.5.2 Applicability of the SPCC Rule to Oil/Water Separators Used in Oil Production
The SPCC rule's wastewater treatment exemption specifically states that the production of
oil is not wastewater treatment for the purposes of §112.1(d)(6). The focus of the separation
process in oil production is on removing water from oil, as opposed to removing oil from water.
Additionally, as stated in the preamble to the 2002 revised SPCC rule, production facilities
generally lack NPDES or state-equivalent permits or prevention requirements, and thus lack the
protections that such permits provide. Furthermore, Underground Injection Control (UIC) permits
do not have prevention requirements for production facilities. Production facilities are normally
unmanned and therefore lack constant human oversight and inspection. Produced water generated
in the production process normally contains saline water as a contaminant in the oil, which in
addition to the toxicrty of the oil might aggravate environmental conditions in the case of a discharge
(67 FR 47068). In some areas of the United States, produced water is fresh and may be
discharged under a NPDES permit for beneficial use (e.g., irrigation, water for livestock).
The goal of an oil production, oil recovery, or oil recycling facility is to maximize the
production or recovery of oil, while eliminating impurities in the oil, including water, whereas the
goal of a wastewater treatment facility is to purify water. Neither an oil production facility nor an oil
recovery or recycling facility treats water; instead, it treats oil. For purposes of the wastewater
treatment exemption, produced water is not considered wastewater, and treatment of produced
water is not considered wastewater treatment. Therefore, a facility that stores, treats, or otherwise
uses produced water remains subject to the rule. At oil drilling, oil production, oil recycling, or oil
recovery facilities, treatment units subject to the rule include open oil pits or ponds associated with
oil production operations, oil/water separators (e.g., gun barrels), and heater-treater units. Open oil
pits or ponds function as another form of bulk storage container and are not used for wastewater
treatment (67 FR 47068,9). Although the ratio of water to oil can be relatively high, the quantity of
oil involved can be still be substantial and pose a threat of a discharge to navigable waters and
adjoining shorelines.
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Oil/water separators used in the production of oil (e.g., heater-treaters and gun barrels) and
other separation and treatment facility installations, are subject to the specific secondary
containment requirements for oil production facility bulk storage containers in §112.9(c)(2).
Therefore, oil/water separators used in oil production are considered bulk storage containers and
are subject to the applicable SPCC requirements under §112.9(c):
* Oil/water separators used in onshore oil production are subject to the provisions of
§112.9(c). For example, oil/water separators used in onshore oil production must
have secondary containment designed to contain the capacity of the largest single
container and sufficient freeboard to contain precipitation (§112.9(c}(2)). If specific
secondary containment is determined to be impracticable for the equipment, the
SPCC Plan must document the reason for impracticability and comply with the
additional regulatory requirements in §112.7(d).
Oil/water separators used in offshore oil production are subject to the provisions of
§112.11 (b) and (d) to prevent a discharge of oil. However, if other provisions of the
rule (except secondary containment) can be met through alternative methods that
provide environmental equivalence for this equipment, then the Plan must include a
description in accordance with §112.7(a)(2)
* Vessels and equipment, such as glycol dehydrators and inline heaters, that treat only
gas and that do not separate, treat, or contain oil, are not subject to the SPCC rule.
Oil/water separators used in oil production count toward the total storage capacity of the
facility and must be considered when determining if a facility is regulated by the SPCC rule in
accordance with §112.1 (b) and (d)(2) and the definition of storage capacity in §112.2. In
determining applicability of any container for calculating the total facility storage capacity, the
preamble to the 2002 rule states:
The keys to the definition are the availability of the container for drilling, producing,
gathering, storing, processing, refining, transferring, distributing, using, or consuming oil,
and whether it is available for one of those uses or whether it is permanently closed.
Containers available for one of the above described uses count towards storage capacity,
those not used for these activities do not. Types of containers counted as storage capacity
would include some flow-through separators, tanks used for "emergency" storage,
transformers, and other oil-filled equipment. (67 FR 47081)
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Chapter 5: OH/Water Separators
5.6 Documentation Requirements and the Role of the EPA Inspector
5.6.1 Documentation by Owner/Operator
Oil/water separators used exclusively for wastewater treatment are exempt from all SPCC
requirements, and no documentation is required for this equipment in the SPCC Plan.
For oil/water separators used to meet SPCC secondary containment requirements, the
SPCC Plan should discuss the separator design capacity, configuration, maintenance, operation,
and other elements of the drainage systems that ensure proper functioning and containment of the
oil as required by §112.7(a)(3)(iii). Examples of elements that this discussion should include are:
The presence and configuration of valves to prevent the accidental release of oil;
• Routine visual inspection of the oil/water separator, its contents, and discharges of
effluent;
Preventive maintenance of facility equipment affecting discharge, including the
removal of settled pollutants and collected oil;
A drainage area that flows to the oil/water separator and corresponding anticipated
flow rate of the drainage system to the separator;
• Appropriate capacity of the oil/water separator for oil and for wastewater;
Provisions for adequate separate storage capacity (based on the containment sizing
required by the rule) to contain oil recovered in the oil/water separator; and
• Documentation associated with the maintenance and inspection of oil/water
separators.
A separate bulk storage container used to store oil following separation in any oil/water
separator (i.e., wastewater treatment, secondary containment, or oil production) is subject to all
applicable requirements of 40 CFR part 112, including §§112.8(c) or 112.9(c), as appropriate.
For oil/water separators used in oil production, the oil/water separators are considered bulk
storage containers to be included in the SPCC Plan. The location of these containers must be
indicated on the facility diagram and discussed in the general requirements in accordance with
§112.7(a)(3). For more information on facility diagrams, refer to Chapters of this document. The
facility owner/operator may determine that the sized secondary containment required for these
oil/water separators is impracticable, pursuant to §112.7(d). If impracticability is determined for
sized secondary containment, the SPCC Plan must clearly explain why secondary containment is
not practicable and provide an oil spill contingency plan following the provisions of 40 CFR part 109.
In addition, such facilities must conduct integrity and leak testing of bulk containers and associated
valves and piping, and provide a written commitment of manpower, equipment, and materials to
respond to oil discharges (§112.7(d)). For more information on impracticability, refer to Chapter 4
of this document.
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5.6.2 Role of the EPA Inspector
As with other aspects of the SPCC Plan, the certifying PE will review the use of and
applicable requirements for oil/water separators at a facility and ensure that they are consistent with
good engineering practice.
The EPA inspector will verify that any oil/water separators at a facility that are not addressed
in the SPCC Plan are in fact used exclusively for wastewater treatment and not to meet any
requirement of part 112. This review considers the intended and actual use of the separator. The
EPA inspector should consider the intended use of the separator at the facility (e.g., wastewater
treatment, secondary containment, oil production, recovery, or recycling), any flow diagrams
illustrating the use of the separator, and the design specifications of the unit in evaluating the
proper application of the wastewater exemption. The EPA inspector may also consider the flow-
through capacity of the separator, the emulsion of oil present within the separator, and the design
specifications of the unit in evaluating the use of the oil/water separator.
For oil/water separators used to meet SPCC secondary containment requirements, the EPA
inspector will verify that the Plan includes, for each oil/water separator used as secondary
containment, a discussion of the separator design capacity, configuration, maintenance, and
operation, as well as other elements of the drainage systems that ensure proper functioning and
containment of the oil in accordance with §112.7(a)(3)(iii). Inspectors should note the risk
associated with this form of containment and should evaluate the design, maintenance, operation,
and efficacy of oil/water separator systems used for containment very carefully. Generally, these
separators should be monitored on a routine schedule, and collected oil should be removed as
appropriate and in accordance with the drainage procedures in the Plan.
Oil/water separators used in the production of oil (e.g., heater-treaters and gun barrels) and
other separation and treatment facility installations, are subject to the specific secondary
containment requirements for oil production facility bulk storage containers in §112.9(c)(2). The
SPCC Plan must address this equipment and include the storage capacity of the equipment in the
storage capacity calculations (§112.1(b) and (d)(2) and the definition of storage capacity in §112.2.)
If sized secondary containment is determined to be impracticable for the equipment, the SPCC Plan
must document the reason for impracticability and comply with the additional regulatory
requirements in §112.7(d).
By certifying the SPCC Plan, a PE attests that the Plan has been prepared in accordance
with good engineering practice and with the requirements of 40 CFR part 112, and that the Plan is
adequate for the facility. Thus, if the wastewater treatment exemption is certified by the PE or if
other oil/water separator uses are properly documented, they most likely will be considered
acceptable by EPA inspectors. However, if the documented uses of the oil/water separators do not
meet the standards of common sense, appear to be incorrect, deviate from the use described in the
Plan, are not maintained or operated in accordance with the Plan, or simply do not operate
correctly, further follow-up action may be warranted. This may include a request for more
information or a Plan amendment in accordance with §112.4(d).
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Chapter 6: Facility Diagrams
FACILITY DIAGRAMS
6.1 Introduction
Section 112.7(a)(3) of the SPCC rule requires that facility owners and operators include in
the SPCC Plan a diagram of the facility that identifies the location and contents of oil containers,
connecting piping, and transfer stations. The diagram helps to ensure safe and efficient response
actions, effective spill prevention and emergency planning, ease of Plan review by an EPA
inspector, and proper implementation of the Plan by facility personnel. This chapter explains the
requirement for a facility diagram, provides guidelines on the necessary level of detail, and includes
several facility diagrams as examples.
6.1.1 Purpose
The facility diagram is an important component of an SPCC Plan because the diagram is
used for prevention, planning, inspection, management, and response considerations. EPA and
facility inspectors, responders, and facility personnel need to be aware of the location of all
containers, piping, and transfer areas subject to the SPCC rule. The facility diagram may also
assist response efforts by helping responders determine the flow pathway of discharged oil and
take more effective measures to control the flow of oil. This may avert damage to sensitive
environmental areas; may protect drinking water sources; and may help prevent discharges to other
conduits, to a treatment facility, or to navigable waters or adjoining shorelines. The diagram may
also serve to address the rule requirements by describing, pictorially, the capacity and type of oil in
each container, the associated discharge/drainage controls, and the flow path of a discharge
(§112.7(a)(3)(i) and (iii) and 112.7(b), respectively). Additionally, the diagram may be attached to a
facility inspection checklist to identify areas, containers, or equipment subject to inspection.
Diagrams may also help federal, state, or facility personnel avoid certain hazards and identify the
location of facility response equipment. Finally, by
informing responders of the location and content
of containers, a facility diagram helps to ensure
their safety in conducting response actions and to
protect property.
6.1.2 Requirements for a Facility Diagram
A description of the physical layout of a
facility, including a facility diagram, is one of the
general requirements for an SPCC Plan. The
2002 revisions to the SPCC rule added a new
specific requirement in §112.7(a)(3) for a facility
diagram to be included in the Plan. Section
§112.7(a)(3)
Describe in your Plan the physical layout of the
facility and include a facility diagram, which
must mark the location and contents of each
container. The facility diagram must include
completely buried tanks that are otherwise
exempted from the requirements of this part
under §112.1(d)(4). The facility diagram must
also include all transfer stations and
connecting pipes. ...
Note: The above text is an excerpt of the SPCC rule.
Refer to 40 C FR part 112 for the full text of the rule.
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112.7(a)(3) requires that the facility diagram include the location and contents of each container,
completely buried tanks (even if exempted from the SPCC requirements), transfer areas (i.e.,
stations), and connecting pipes. In addition to the requirement for a facility description and
diagram, §112.7(a)(3) lists additional items to be addressed in an SPCC Plan, including the type of
oil in each container and its capacity; discharge prevention measures; discharge or drainage
controls; countermeasures for discharge discovery, response, and cleanup; methods of disposal of
recovered materials; and specific contact information. Please see §112.7(a)(3) for these
requirements in their entirety.
6.2 Preparing a Facility Diagram
Facility diagrams provided as part of an SPCC Plan often illustrate the following information:
Required by §112.7(a)(3):1
Aboveground and underground storage tanks (including content and capacity);
Mobile portable containers (including content and capacity);
Hydraulic operating systems or manufacturing equipment;
• Oil-filled electrical transformers, circuit breakers, or other equipment (including
content and capacity);
Any other oil-filled equipment (including content and capacity);
* Oil pits or ponds (at production facilities);
Oil/water separators (e.g., at tank batteries, separation, and treating facility
installations associated with production facilities);
Fill ports and connecting piping (scale of drawing permitting);
• Oil transfer areas; and
Loading racks/unloading areas.
Recommended:
Secondary containment structures, including oil/water separators used for
containment;
Storm drain inlets and surface waters that could be affected by a discharge;
Direction of flow in the event of a discharge (which can serve to address the SPCC
requirement under §112.7(b));
Legend that indicates scale and identifies symbols used in the diagram;
Location of response kits and firefighting equipment;
Location of valves or drainage system control that could be used in the event of a
discharge to contain oil on the site;
Compass direction; and
1 Containers that have a capacity of less than 55 gallons, are permanently dosed, or are otherwise exempt
from the rule (with the exception of exempted underground storage tanks) are not required to be listed on the facility
diagram.
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Chapter 6: Facility Diagrams
Topographical information and area maps.
In addition, for purposes of emergency response, EPA recommends, but does not require, that an
owner/operator mark on a facility diagram containers that store Clean Water Act (CWA) hazardous
substances (listed in 40 CFR part 116, Designation of Hazardous Substances) and label the
contents of these containers (67 FR 47097).
While recognizing that SPCC Plans and their associated diagrams are facility-specific and
prepared with a certain amount of PE discretion, the following information is meant to facilitate a
common understanding of what EPA inspectors may expect to see in a facility diagram. The
remainder of this section provides guidelines for the recommended level of detail, how specific
containers and systems may be addressed, and the use of alternate facility diagrams for meeting
the requirements of §112.7{a)(3).
6,2.1 Level of Detail
The facility diagram should provide sufficient detail for the facility personnel to undertake
prevention activities, for EPA to perform an effective inspection, and for responders to take effective
measures. As with other aspects of the SPCC Plan, the facility diagram is to be prepared in
accordance with good engineering practice and reviewed by the PE as part of Plan certification.
Thus, the level of detail provided and the approach taken for preparing an adequate facility diagram
is primarily at the discretion of the certifying PE.
6.2.2. Facility Description
Section 112.7(a)(3) requires that the Plan include a description of the physical layout of the
facility. In addition to marking the location and contents of each oil storage container at the facility,
this description may include information on the facility location, type, size, and proximity to
navigable waters, as well as other relevant information. This general facility description is often
supplemented with a more specific description of containers subject to the SPCC rule to
complement what is required on the facility diagram (e.g., storage capacity and content).
6.2.3 Oil Containers
The facility diagram must include all containers (including oil-filled equipment) that store 55
gallons or more of oil and must include information indicating the contents of these containers
(§112.7(a)(3)). The 2002 revisions to the SPCC rule established a minimum container size of 55
gallons. Pursuant to §112.1(d)(5), the rule does not apply to containers of less than 55 gallons, and
therefore they do not need to be included on the facility diagram.
In situations where diagrams become complicated due to the presence of multiple oil
storage containers or complex piping/transfer areas at the facility, it may be difficult to indicate the
contents and capacity of the containers on the diagram itself. In order to simplify the diagram, the
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PE may choose to include that information on a separate log or sheet maintained in the Plan,
similar to the description outlined below for mobile/portable containers.
6.2.4 Mobile or Portable Containers
The owner/operator must state the contents and location of each container on the diagram
of the facility (§112.7(a){3)). For portable containers (e.g., drums and totes), the facility
owner/operator may note the general contents of each container and provide more detailed content
information on a separate sheet or log, as well as other information, such as container capacity, that
the PE determines to be appropriate to adequately describe the facility. If the contents of a
container change frequently, the contents may be recorded on a separate sheet or log, or on the
diagram (67 FR 47097). In this case, the diagram should note that contents vary. Additionally, the
PE may choose to identify an area on the facility diagram (e.g., a drum storage area) and include a
separate log that can be updated by facility personnel. The PE should develop a reasonable
estimate of the number of containers in the area and the capacity of the containers, and consider
routine movement of the containers for the Plan. This estimate can be used to determine
applicability of the rule thresholds and provide a general description of the mobile/portable
containers in the Plan. The PE should also include a procedure for maintaining the log, in order to
avoid PE certification of technical amendments of the Plan as the number of mobile/portable
containers changes at the facility.
Mobile containers should be marked on the facility diagram in their out-of-service or
designated storage area or where they are most frequently located, such as a warehouse drum
storage area. The facility owner/operator and certifying PE determine how best to represent
mobile/portable containers on the facility diagram, such as by developing a log or indicating primary
storage areas. If mobile containers are moved throughout the facility and do not immediately return
to a specified location easily identified on the facility diagram, the exact location could be addressed
on a separate sheet or log. This log would complement the facility diagram and the SPCC Plan by
providing further information on the specific location and contents of mobile and portable
containers. In addition, the diagram must identify the final location of mobile or portable containers
(as required in §112.7(a)(3)) that return to a specific designated area to comply with the specific
secondary containment requirements in §112.8(c)(11). (See Chapter 4 of this document for a
discussion of secondary containment requirements.)
6.2.5 Completely Buried Storage Tanks
A facility diagram must include the location and contents of all containers required to be
addressed in the SPCC Plan (67 FR 47097 and §112.7(a)(3)). This includes exempt underground
storage tanks (USTs) as well as USTs that are subject to SPCC requirements at the facility. The
rationale for this requirement is to help response personnel to easily identify dangers from either fire
or explosion, or from physical impediments during response activities. For example, exempted
tanks may include completely buried USTs and piping systems at a gasoline service station that are
subject to all technical requirements of either 40 CFR part 280 or an approved state UST program
under 40 CFR part 281.
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As discussed in Chapter 2 of this document, a facility may have USTs that are subject to
SPCC requirements because they are deferred from compliance with some or all of the technical
requirements of 40 CFR part 280 {e.g., UST systems with field constructed tanks, any UST system
that stores fuel solely for use by an emergency power generator, airport hydrant fuel distribution
systems). Any USTs at a facility that are subject to SPCC requirements must also be marked on
the facility diagram (§112.7{a)(3)). (See the preamble to the 1991 proposed rule, 56 FR 54612,
October 22,1991.)
6.2.6 Piping and Manufacturing Equipment
The facility diagram must also include all transfer stations (i.e., any location where oi! is
transferred) and connecting pipes (§112.7(a)(3)). Associated piping and manufacturing equipment
present at an SPCC-regulated facility may be difficult to represent on a facility diagram, due to their
relative location, complexity, or design. Recognizing this, EPA allows flexibility in the way the
facility diagram is drawn. An owner/operator may represent such systems in a less detailed manner
on the facility diagram in the SPCC Plan as long as more detailed diagrams of the systems are
maintained at the facility and referenced on the diagram. Examples of more detailed diagrams may
include blueprints, engineering diagrams, or diagrams developed to comply with other local, state,
or federal requirements.
The scale and level of detail of the facility diagram may make it difficult to show small
transfer lines within containment structures. Schematic representations that provide a general
overview of the piping service (e.g., supply/return) may provide sufficient information when
combined with a description of the piping in the Plan. Alternatively, overlay diagrams showing
different portions of the piping system may be used where the density and/or complexity of the
piping system would make a single diagram difficult to read.
Examples of ways that manufacturing equipment may be represented include a box that
identifies the equipment and its location, or a simplified process flow diagram. Figure 6-1, which is
an excerpt of a complete facility diagram (Figure 6-4) included later in Section 6.4, provides an
example showing how manufacturing equipment may be represented in a facility diagram. For
areas of complicated piping, which often include different types, numbers, and lengths of pipes, the
facility diagram may show a simplified box labeled "piping" or show a single line that identifies the
service (e.g., supply/return), as long as more detailed diagrams are available at the facility. Figure
6-2 provides an example showing how a complex piping area may be represented in a facility
diagram, and is also an excerpt of the example facility diagram presented in Figure 6-4.
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Figure 6-1. Example showing how manufacturing equipment
could be represented in a facility diagram. Note that more
detailed diagrams would need to be available at the facility.
Rtarn
f-'iptf s; /V
Accumulation Isf*
10.300 aalfon
Figure 6-2. Example showing how a complex piping area could be represented in a facility
diagram. Note that more detailed diagrams would need to be available at the facility.
Piping A--«f3
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Chapter 6: Facility Diagrams
6.2.7 Use of State and Federal Diagrams
Some state and federal regulations may require a diagram with similar or overlapping
requirements, whereas others do not. SPCC is a federal program that specifies minimum
requirements, which states may supplement with more stringent requirements. A facility diagram
prepared for a state or federal plan or for other purposes (construction permits, facility
modifications, or other pollution prevention requirements) may be used in an SPCC Plan if it meets
the requirements of the SPCC rule.
6.3 Facility Diagram Examples
This section includes example facility diagrams for three fictitious SPCC-regulated facilities.
These three examples illustrate how certain containers and equipment could be represented in a
facility diagram; the examples are provided for the purpose of illustration only. Preparation of a
facility diagram is a site-specific effort, and the diagram prepared for a given facility should reflect
the level of detail needed to adequately describe the facility configuration. The level of detail and/or
approach taken for the examples below may not necessarily be appropriate for a given facility.
It is important to note that facility diagrams, like the other elements of an SPCC Plan, must
be prepared in accordance with good engineering practice, and must be reviewed by the PE
certifying the Plan (§112.3(d)). Section 112.7(a)(3) requires the facility diagram to show, at a
minimum, the location and contents of oil containers; completely buried storage tanks, including
those that may otherwise be exempt from the rule; and transfer areas (i.e., stations) and connecting
pipes. The facility owner or operator may also include on the diagram additional structures and
equipment, and may use the diagram to illustrate other elements that may be relevant to the SPCC
Plan and to emergency response. For instance, a diagram may also show the discharge and
drainage controls that are described in the SPCC Plan, the predicted flow path for discharged oil
based on topography, areas on which to focus inspections, fire-fighting resources, spill response
kits, and/or evacuation routes.
Example facility diagrams are presented below for a bulk storage and distribution facility, a
manufacturing facility, and an oil production facility.
6.3,1 Example #1: Bulk Storage and Distribution Facility
Figure 6-3 is an example of a diagram for a bulk storage and distribution facility, which has a
tank farm, a loading rack and an unloading area, and other oil containers and oil-filled equipment.
This diagram corresponds to the model SPCC Plan for a bulk storage distribution facility that is
provided in Appendix D of this guidance document. Because it has fewer tanks and less complex
operations than a manufacturing facility, for example, this facility requires a less detailed facility
diagram than the example provided in Figure 6-4.
As required by §112.7(a)(3), this diagram includes all containers with an oil storage capacity
of 55 gallons or greater. In addition to listing the contents directly on the diagram, the diagram
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provides a reference to a supplementary table that contains the volume and content of the storage
tanks shown on the diagram (appended to the diagram as Table B-1). At the discretion of the PE
who reviewed and certified the Plan, the example facility diagram also depicts secondary
containment methods and includes a reference to calculations of containment capacity provided in
other parts of the SPCC Plan. Also, a separate log (Table B-2) identifies the contents of the drums
in the storage warehouse. Please refer to Section 6.2.3 of this document for more information.
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SPCC Guidance for Regional Inspectors
Table B-1. Volume and contents of tanks and containers identified on the facility diagram. Please
see facility diagram to identify the areas below.
Tank/Container
Area 1
Tankl
Tank 2
TankS
Tank 4
TankS
Tank 6
Volume (gallons)
25,
25,
25,
25,
30,
30,
Contents
000 | Product A - #2 fuel oil
000
000
000
000
000
Product A- #2 fuel oil
Product B - #6 fuel oil
Product B - #6 fuel oil
Product C - Kerosene
Product C - Kerosene
Main Office Building
TankH
2,000
Drum Storage Warehouse
Up to 30 drums
55
(each)
Heating oil
Various oil products
(lubricating oil, engine oil,
used oil, etc.)
Rev. 06/14/05
Table B-2. Drum storage warehouse log.
Date
6/14/05
6/14/05
6/14/05
Number and Type
of Container
Contents
Capacity
Location at
facility
15 drums
5 drums
10 drums
lubrication oil
engine oil
used oil
55x15 = 825
55 x 5 = 275
55x10 = 550
Drum storage
warehouse
Drum storage
warehouse
Drum storage
warehouse
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Chapter 6: Facility Diagrams
6.3.2 Example #2: Manufacturing Facility
Figure 6-4 is an example facility diagram for a large manufacturing facility with a variety of
containers and equipment, including piping, oil-filled equipment (i.e., manufacturing equipment and
transformers), and completely buried storage tanks. As required by §112.7(a)(3), this diagram
includes all containers with a storage capacity of 55 gallons or greater. In addition to listing the
contents directly on the diagram, it includes a reference to a crosswalk that contains the volume
and content of the storage containers shown on the diagram (appended to the diagram as Table
B-3). Also, while not required, the diagram marks the location of containers that store CWA
hazardous substances and labels those containers. EPA would further recommend that the specific
volume and specific contents of the 4,000-gallon solvent tank be included in the crosswalk.
Additionally, the diagram notes the location and content of completely buried storage tanks that,
although otherwise exempt from the SPCC rule because they meet all the technical requirements of
40 CFR part 280 or an approved state UST program under 40 CFR part 281, must still be included
in the diagram in accordance with §112.7(a)(3).
This diagram also includes an example of how manufacturing equipment and complex
piping may be represented on a facility diagram. The diagram references the more detailed
diagrams and plans of the piping and manufacturing equipment that are available separately at the
facility. For more information on ways to represent these systems, please see Section 6.2.6, Piping
and Manufacturing Equipment, above.
Finally, while not required to be included in the diagram, this example facility diagram also
includes a reference to the calculation of diked storage provided in other parts of the SPCC Plan
and depicts wastewater treatment systems, secondary containment, and oil/water separators.
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Chapter 6: Facility Diagrams
Table B-3. Volume and contents of tanks and containers identified on the facility diagram. Please
see facility diagram to identify the areas below.
Tank/Container Volume (gallons)
Contents
Area A - Raw Material Bulk Storage
Tankl
Tank 2
TankS
Tank 4
TankS
TankS
TankS
4,000
4,000
20,000
20,000
20,000
6,000
40,000
Product A- #2 fuel oil
Product A - #2 fuel oil
Product B- #6 fuel oil
Product B- #6 fuel oil
Product B - #6 fuel oil
Product C - Kerosene
Solvent - Toluene
Area B - Finished Product Bulk Storage
Tank 6
Tank?
Area C - Electrical Equipment
Transformer E1
Transformer E2
Area D
Liquid Product Accumulation
Tank
20,000
20,000
235
235
10,000
Product D - proprietary oil
Product D - proprietary oil
Silicon-based dielectric fluid
Silicon-based dielectric fluid
Product D - proprietary oil
Process Area
Primary Reactor
Distillation
Direct Contact Cooling
Stripping
Pump/Tank
Condenser Liquifier
Underground Storage Tanks
Tank 9 (otherwise exempt
from SPCC requirements)
Tank 1 0 (otherwise exempt
from SPCC requirements)
Tank 1 1
Rev. 04/21/05
500
500
500
500
300
500
8,000
8,000
2,000
intermediate oil product
intermediate oil product
intermediate oil product
intermediate oil product
intermediate oil product
intermediate oil product
gasoline
gasoline
heating oil
6.3.3 Example #3: Oil Production Facility
Figure 6-5 is an example facility diagram for a small oil production facility with two extraction
wells and a production tank battery. As required by §112.7(a)(3), this diagram includes all
containers with a storage capacity of 55 gallons or greater and transfer areas. Because the facility
has a relatively large footprint, the direction of flow is best displayed on a separate figure that shows
the general location of the site relative to receiving waterbodies (Figure 6-6).
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Figure 6-5. Example facility diagram for a production facility.
Clearwater Oil Company
Big Bear Lease No. 2 Production Facility
Facility Diagram
Rev. 11/12'02
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6.4 Review of a Facility Diagram
6.4.1 Documentation by Owner/Operator
By certifying an SPCC Plan, a PE attests that he/she is familiar with the requirements of 40
CFR part 112, that the Plan has been prepared in accordance with good engineering practice,
following the requirements of 40 CFR part 112, that the Plan is adequate for the facility, and that he
or his agent visited the facility. Thus, if an SPCC Plan is certified by a PE and the facility diagram is
consistent with the rule requirements, it will most likely be considered acceptable by regional
inspectors. However, if the diagram does not meet these standards of common sense, the facility
design has changed, the supporting drawings for a simplified diagram are not available at the
facility, or the diagram appears to be inadequate for the facility, appropriate follow-up action may be
warranted. This may include a request for more information or a Plan amendment in accordance
with§112.4(d).
6.4.2 Role of the EPA Inspector
The inspector should verify that the diagram accurately represents the facility layout and
provides sufficient detail as outlined in §112.7(a)(3), and use it as a guide for the containers and
piping inspected during the site visit.
The EPA inspector should verify that the diagram included in the Plan includes:
Location and contents of each container (except those below the 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.
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Chapter 7: Inspection, Evaluation, and Testing
INSPECTION, EVALUATION, AND TESTING
7.1 Introduction
Regularly scheduled inspections, evaluations, and testing by qualified personnel are critical
parts of discharge prevention. Their purpose is to prevent, predict, and readily detect discharges.
They are conducted not only on containers, but also on associated piping, valves, and
appurtenances, and on other equipment and components that could be a source or cause of an oil
release. Activities may involve one or more of the following: an external visual inspection of
containers, piping, valves, appurtenances, foundations, and supports; a non-destructive shell test to
evaluate integrity of certain containers; and additional evaluations, as needed, to assess the
equipment's fitness for continued service. The type of activity and its scope will depend on the
exercise of good engineering practice; not every action will necessarily be applicable to every
facility and container, and additional inspections may be required in some cases. An inspection,
evaluation, and testing program that complies with SPCC requirements should specify the
procedures, schedule/frequency, types of equipment covered, person(s) conducting the activities,
recordkeeping practices, and other elements as outlined in this chapter.
The remainder of this chapter is organized as follows:
• Section 7.2 provides an overview of the SPCC inspection, evaluation, and testing
requirements.
• Section 7.3 discusses specific cases, including the use of environmentally
equivalent measures.
Section 7.4 discusses the role of the EPA inspector in reviewing a facility's
compliance with the rule's inspection, evaluation, and testing requirements.
Section 7.5 summarizes industry standards, code requirements, and recommended
practices (RPs) that apply to different types of equipment.
7.2 Inspection, Evaluation, and Testing under the SPCC Rule
Various provisions of the SPCC rule relate to the inspection, evaluation, and testing of
containers, associated piping, and other oil-containing equipment. Different requirements apply to
different types of equipment and to different types of facilities. The requirements are generally
aimed at preventing discharges of oil caused by leaks, brittle fracture, or other forms of container
failure by ensuring that containers used to store oil have the necessary physical integrity for
continued oil storage. The requirements are also aimed at detecting container failures (such as
small pinhole leaks) before they can become significant and result in a discharge as described in
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7.2.1 Summary of Inspection and Integrity Testing Requirements
Table 7-1 summarizes the provisions that apply to different types of equipment and facilities.
Some inspection and testing provisions apply to bulk storage containers at onshore facilities (other
than production facilities). Inspection and/or testing requirements also apply to other components
of a facility that might cause a discharge (such as vehicle drains, foundations, or other equipment or
devices). Other inspection requirements also apply to oil production facilities. In addition,
inspection, evaluation, and testing requirements are required under certain circumstances, such as
when an aboveground field-constructed container undergoes repairs, alterations, or a change in
service that may affect its potential for a brittle fracture or other catastrophe, or in cases where
secondary containment for bulk storage containers is impracticable (§112.7(d), as described in
Chapter 4 of this document.) Facility owners and operators must also maintain corresponding
records to demonstrate compliance {§§112.8{c)(6), 112.8(d)(4), 112.9(b)(2), 112.9(c)(3), and
112.9{d)(1) and (2)) per §112.7(e).
Table 7-1. Summary of SPCC inspection, evaluation, testing, and maintenance program provisions.
Facility Component 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)
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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.
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Facility Component
Bulk storage
container supports
and foundation
Diked area
Steam return and
exhaust lines
Liquid level sensing
devices
Effluent treatment
facilities
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.
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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
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certifying an SPCC Plan, a PE is also certifying that the inspection program it describes is
appropriate for the facility and is consistent with good engineering practice. Section 112.3(d) also
states that the Plan must be prepared in accordance with good engineering practice, including
consideration of applicable industry standards, and with the requirements of 40 CFR part 112.
The preamble to the 2002 revised SPCC rule lists examples of industry standards and
recommended practices that may be relevant to determining what constitutes good engineering
practice for various rule provisions. These industry standards are summarized in Tables 7-2 and 7-
3 (Section 7.2.6) and further discussed in Section 7.5. It is important to note, however, that the
industry standards may be more specific and more stringent than the requirements in the SPCC
rule. For example, EPA does not prescribe a particular schedule for testing. This is because "good
engineering practice" and relevant industry standards change over time. In addition, site-specific
conditions at an SPCC-regulated facility play a significant role in the development of appropriate
inspections and tests and the associated schedule for these activities. For example, the American
Petroleum Institute (API) Standard 653, "Tank Inspection, Repair, Alteration, and Reconstruction,"
includes a cap on the maximum interval between external and internal inspections, and provides
specific criteria for alternative inspection intervals based on the calculated corrosion rate. API 653
also provides an internal inspection interval when the corrosion rates are not known. Similarly, the
Steel Tank Institute (STI) Standard SP-001, 3rd Edition, provides specific intervals for external and
internal inspection of shop-built containers based on container size and configuration.
Integrity testing requirements for the SPCC rule may be replaced by environmentally
equivalent measures as allowed under §112.7(a)(2) and reviewed by the PE who certifies the Plan.
Chapter 3 of this guidance provides a general discussion of environmental equivalence, while
Section 7.3 discusses its particular relevance to inspection, evaluation, and testing requirements.
7.2.2 Regularly Scheduled Integrity Testing
and Frequent Visual Inspection of
Aboveground Bulk Storage
Containers
Section 112.8(c)(6) of the SPCC rule
specifies the inspection and testing
requirements for aboveground bulk storage
containers at onshore facilities that store, use, or
process petroleum oils and non-petroleum oils
(except animal fats and vegetable oils). Section
112.12(c)(6) contains the same requirements for
facilities with animal fats and vegetable oils.
The provision sets two distinct
requirements for aboveground bulk storage
containers:
§§112.8(c}(6) and 112.12(c)(6)
Test each aboveground container for integrity on
a regular schedule, and whenever you make
material repairs. The frequency of and type of
testing must take into account container size and
design (such as floating roof, skid-mounted,
elevated, or partially buried). You must combine
visual inspection with another testing technique
such as hydrostatic testing, radiographic testing,
ultrasonic testing, acoustic emissions testing, or
another system of non-destructive shell testing.
You must keep comparison records and you
must also inspect the container's supports and
foundations. In addition, you must frequently
inspect the outside of the container for signs of
deterioration, discharges, or accumulation of oil
inside diked areas. Records of inspections and
tests kept under usual and customary business
practices will suffice for purposes of this
paragraph.
Note: The above text is only a brief excerpt of the rule. Refer
to 40 CFR part 112 for the full text of the rule.
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(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.
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secondary containment would be impracticable, §112.7(d) requires, among other measures,
periodic integrity testing of bulk storage containers. Given the higher potential of a discharge
reaching navigable waters or adjoining shorelines, however, the PE may decide, based on good
engineering practice, that more frequent integrity tests would be needed than for containers that
have adequate secondary containment. This approach of establishing an increased inspection
frequency for an aboveground container without secondary containment is used in the STI SP-001
standard.
Frequent visual inspection. There must be a frequent inspection of the outside of the
container for signs of deterioration, discharges, or accumulations of oil inside diked areas
(§112.8(c)(6)). This visual inspection is intended to be a routine walk-around. EPA expects that the
walk-around, which will occur on an ongoing routine basis, can generally be conducted by properly
trained facility personnel, as opposed to the more intensive but less frequent visual inspection
component of the non-destructive examination conducted by qualified testing/inspection personnel.
Qualifications of these personnel are outlined in tank inspection standards, such as API 653 and
STI SP-001. A facility owner or operator can, for example, visually inspect the outside of bulk
storage containers on a daily, weekly, and/or monthly 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,
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(2) on the first filling in cold weather, (3) after a change to lower temperature service, or (4) after a
repair/modification. Storage tanks with a maximum shell thickness of one-half inch or less are not
generally considered at risk for brittle fracture.6 Brittle fracture was most vividly illustrated by the
splitting and collapse of a 3.8 million gallon (120-foot diameter) tank in Floreffe, Pennsylvania,
which released approximately 750,000 gallons of oil into the Monongahela River in January 1988.
Section 112.7(i) of the SPCC rule
requires that field-constructed aboveground
containers that have undergone a repair or
change in service that might affect the risk of a
discharge due to brittle fracture or other
catastrophe, or have had a discharge associated
with brittle fracture or other catastrophe, be
evaluated to assess the risk of such a discharge.
Unless the original design shell thickness of the
tank is less than one-half inch (see API 653,
Section 5, and STI SP-001, Appendix B),
evidence of this evaluation should be
documented in the facility's SPCC Plan.
If a field-constructed aboveground container
undergoes a repair, alteration, reconstruction, or
a change in service that might affect the risk of a
discharge or failure due to brittle fracture or
other catastrophe, or has discharged oil or failed
due to brittle fracture failure or other
catastrophe, evaluate the container for risk of
discharge or failure due to brittle fracture or
other catastrophe, and as necessary, take
appropriate action.
Note: The above text is only a brief excerpt of the rule.
Refer to 40 CFR part 112 for the full text of the SPCC rule.
In summary, industry standards discuss methods for assessing the risk of brittle fracture
failure for a field-erected aboveground container and for performing a brittle fracture evaluation
including API 653, "Tank Inspection, Repair, Alteration, and Reconstruction," API RP 920
"Prevention of Brittle Fracture of Pressure Vessels," and API RP 579, "Fitness-for-Service." These
standards include a decision tree or flowchart for use by the owner/operator and PE in assessing
the risk of brittle fracture. STI SP-001 also addresses brittle fracture failures for smaller diameter
field-erected tanks with a wall thickness less than one-half inch.
7.2.4 Inspections of Piping
For onshore facilities, the SPCC rule specifies the following inspection and testing
requirements for piping. Buried piping at non-production facilities that has been installed or
replaced on or after August 16, 2002, must have a protective wrapping and coating and be
protected from corrosion cathodically or by other means, as per §§112.8(d)(1) and 112.12(d)(1).
Any exposed line must be inspected for deterioration, and, if corrosion damage is found, additional
inspection or corrective action must be taken as needed.
Aboveground piping, valves, and appurtenances at non-production facilities must be
regularly inspected, as per §§112.8(d)(4) and 112.12(d)(4) and in accordance with industry
6 Mclaughlin, James E. 1991. "Preventing Brittle Fracture of Aboveground Storage Tanks - Basis for the Approach
Incorporated into API 653." Case Studies: Sessions III and IV of the IIW Conference: Fitness for Purpose of Welded
Structures. October 23-24, 1991, Key Biscayne, Florida, USA. Cosponsored by the American Welding Society,
Welding Research Institute, Welding Institute of Canada, and International Institute of Welding. Published by the
American Welding Society, Miami, Florida. Pages 90-110.
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standards. Buried piping must be integrity and leak tested at the time of installation, modification,
construction, relocation, or replacement.
Aboveground valves and piping associated with transfer operations at production facilities
must be inspected periodically and on a regular schedule, as per §112.9(d)(1) and in accordance
with industry standards. A program of flowline maintenance is required by §112.9(d)(3) and is
described in the following section of this document.
For offshore facilities, §112.11 (n) specifies that all piping appurtenant to the facility must be
protected from corrosion, such as with protective coatings 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
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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
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The facility's SPCC Plan should describe how the flowlines are configured, monitored, and
maintained to prevent discharges. The program is to be implemented in the field, and facility
personnel responsible for the maintenance of the equipment should be aware of the flowline
locations and be familiar with maintenance procedures, including replacement of damaged and/or
leaking flowlines. Records of inspections and tests kept under usual and customary business
practices should be prepared and made available for review, as required by the rule (§112.7(e)).
If an impracticability determination is made for flowlines, the flowline maintenance program
should be shown to be adequate along with the contingency plan (67 FR 47078).
7.2.6 Role of Industry Standards and Recommended Practices in Meeting SPCC
Requirements
The SPCC rule does not require the use of a specific industry standard for conducting
inspections, evaluations, and integrity testing of bulk storage containers and other equipment at the
facility. Rather, the rule provides flexibility in the facility owner/operator's implementation of the
requirement, consistent with good engineering practice, as reviewed by the PE certifying the Plan.
To develop an appropriate inspection, evaluation, and testing program for an SPCC-
regulated facility, the PE must consider applicable industry standards (§112.3(d)(1)(iii)). If the
facility owner or operator uses a specific standard to comply with SPCC requirements, the standard
should be referenced in the Plan. Where no specific and general industry standard exists to inform
the determination of what constitutes good engineering practice for a particular inspection or testing
requirement, the PE should consider the manufacturer's specifications and instructions for the
proper use and maintenance of the equipment, appurtenance, or container. If neither a specific and
objective industry standard nor a specific and objective manufacturer's instruction apply, the PE
may also call upon his/her professional experience to develop site-specific inspection and testing
requirements for the facility or equipment as per §112.3(d)(1)(iv). The inspection and testing
program must be documented in the Plan (§112.7(e)). A checklist is provided as Table 7-5 at the
end of this chapter to assist inspectors in reviewing the relevant industry standards based on the
equipment observed at an SPCC-regulated facility.
In the preamble to the 2002 SPCC rule, EPA provides examples of industry standards that
may constitute good engineering practice for assessing the integrity of different types of containers
for oil storage (67 FR 47120). Compliance with other industry standards and federal requirements
may also meet SPCC inspection, evaluation, and testing requirements. The U.S. Department of
Transportation (DOT) regulates containers used to transport hazardous materials, including certain
oil products. For example, mobile/portable containers that leave a facility are subject to the DOT
construction and continuing qualification and maintenance requirements (49 CFR part 178 and
49 CFR part 180). These DOT requirements may be used by the facility owner and operator and by
the certifying PE as references of good engineering practice for assessing the fitness for service of
mobile/portable containers.
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Industry standards typically apply to containers built according to a specified design (API
653, for example, applies to tanks constructed in accordance with API 650 or API 12C); the
standards describe the scope, frequency, and methods for evaluating the suitability of the
containers for continued service. This assessment usually considers performance relative to
specified minimum criteria, such as ability to maintain pressure or remaining shell thickness. The
integrity testing is usually performed by inspectors licensed by the standard-setting organizations
(e.g., American Petroleum Institute, Steel Tank Institute).
Table 7-2 summarizes key elements of industry standards (and recommended practices)
commonly used for testing aboveground storage tanks (ASTs). Table 7-3 summarizes key
elements of standards (and recommended practices) used for testing piping and other equipment.
Section 7.5 of this chapter provides a more detailed description of the standards listed in the tables.
Other industry standards exist for specific equipment or purposes. Many of these are cross-
referenced in API 653, including publications and standards from other organizations such as the
American Society for Testing and Materials (ASTM), the American Society for Non-Destructive
Testing (ASNT), and the American Society of Mechanical Engineers (ASME). Other organizations,
such as the National Fire Protection Association (NFPA), the National Association of Corrosion
Engineers (NACE), and the Underwriters Laboratory (UL), also provide critical information on all
container types and appurtenances.
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Table 7-2. Summary of industry standards and recommended practices (RP) for ASTs.
Equipment
covered
Scope
Inspection
interval
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
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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.
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7.3 Specific Circumstances
Integrity testing (a combination of visual inspection and another testing technique) is
required for all aboveground bulk storage containers located at onshore facilities (except production
facilities), unless the facility owner/operator implements an environmentally equivalent method (as
described in Chapter 3 and in Section 7.3.4, below) and documents the deviation in the SPCC Plan.
Typically, visual inspection is combined with non-destructive shell testing in order to adequately
assess the container condition. EPA has indicated that visual inspection alone may provide
equivalent environmental protection in some cases, if certain conditions are met and if the
inspections are conducted at appropriate time intervals (see Section 7.3.4 of this document) in
accordance with good engineering practice. Therefore, if the Plan calls for visual inspection alone
in accordance with an industry standard, then the Plan must discuss the reason for the
nonconformance with §112.8(c){6) or §112.12(c)(6) and comply with the environmental equivalence
provision in §112.7(a)(2).
Some facilities may not have performed integrity testing of their tanks. In this case,
developing an appropriate integrity testing program will require assessing baseline conditions for
these tanks. This "baseline" will provide information on the condition of the tank shell, and the rate
of change in condition due to corrosion or other factors, in order to establish a regular inspection
schedule. Section 112.7 requires that if any facilities, procedures, methods, or equipment are not
yet fully operational, the SPCC Plan must explain the details of installation and operational start-up;
this applies to the inspection and testing programs required by the rule. For all types of facilities,
the PE is responsible for making the final determination on the scope and frequency of testing when
certifying that an SPCC Plan is consistent with good engineering practice and is appropriate for the
facility.
This section provides guidance on integrity testing for the following circumstances the
inspector may encounter at an SPCC-regulated facility:
Aboveground bulk storage containers for which the baseline condition is known;
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
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site-specific SPCC Plan) per §112.8(c)(6) or §112.12(c)(6). There is an advantage to knowing the
baseline condition of a tank, particularly if the remaining wall thickness and the corrosion rate are
known. Only when the baseline is known can an inspection and testing program be established on
a regular schedule. The inspection interval should be identified consistent with specific intervals
per industry standards or should be based on the corrosion rate and expected remaining life of the
container. This inspection interval must be documented in the Plan in accordance with §§112.3(d),
112.7(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
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alternative inspection schedule established by the PE in accordance with good engineering
practice.
When no baseline information is available for a container, the PE may schedule visual
inspection and another testing technique within the first five-year review cycle of the SPCC Plan in
order to establish a regular integrity testing schedule based on current container conditions. In this
example, the review cycle would begin on the revised rule implementation deadline of August 18,
2006, so the first (baseline) container inspection and integrity test would be completed by August
18,2011. In the case of a tank that is newly built, construction data (e.g., as-built drawings and/or
manufacturers cut-sheets) may typically be used as an initial datum point to establish wall
thicknesses and would be included in the established procedures for inspection and testing.
The implementation, particularly in establishing inspection priorities, of the testing program
should be in accordance with good engineering practice and include consideration of industry
standards (§112.3(d)), as discussed in this document. For instance, special consideration may be
discussed in the Plan for containers for which the age and existing condition is not known (no
baseline information exists). For example, older tanks or tanks in more demanding service may be
identified as high-priority tanks for inspection, versus tanks for which the baseline information is
Figure 7-1. Example baselining plan to determine the integrity testing and inspection schedule.
Scenario:
Facility has three aboveground atmospheric, mild-carbon steel tanks of different ages and conditions. Some have prior
inspection histories; others have never been inspected. Although there is limited history available for tank construction,
the tanks are presumed to be field-erected tanks and to each have 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.
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known.
An example baselining plan is presented in Figure 7-1. The example presents a simple
scenario and is only provided as an illustration of some of the factors that may be considered when
determining a schedule to initiate inspections of bulk storage containers.
7.3.3 Deviation from Integrity Testing Requirements Based on Environmental Equivalence
Chapter 3 of this document describes the flexibility provided in the SPCC rule through the
use of environmental equivalent measures, per §112.7(a)(2). The discussion below describes
examples of measures that facility owners and operators can use to deviate from inspection and
testing requirements, while providing equivalent environmental protection.
The SPCC rule provides flexibility regarding integrity testing requirements of bulk storage
containers, as long as the alternatives provide equivalent environmental protection per
§112.7(a)(2). Measures that may be considered environmentally equivalent to integrity testing for
shop-built containers are those that effectively minimize the risk of container failure and that allow
detection of leaks before they become significant. Alternative measures to integrity testing requiring
the combination of internal, external, and non-destructive evaluation may, for example, prevent
container failure by minimizing the container's exposure to conditions that promote corrosion (e.g.,
direct contact with soil), or they may enable facility personnel to detect 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
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not be measures already required to meet another part of the SPCC rule. A facility may not rely
solely on measures that are required by other sections of the rule (e.g., secondary containment) to
provide "equivalent environmental protection." Otherwise, the deviation provision would allow for
approaches that provide a lesser degree of protection overall. However, for certain tank sizes and
configurations of secondary containment, continuous release detection and frequent visual
inspection by the owner/operator may be the sole inspection requirement, provided that the
rationale is discussed in the Plan (STI SP-001). This rationale should include a discussion of good
engineering practice referencing appropriate industry standards.
7.3,4 Environmental Equivalence Scenarios for Shop-Built Containers
Scenario 1: Elevated Drums. As EPA has indicated in the 2002 Figure 7-2. Drums elevated
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
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engineering practice, including consideration of industry standards, as certified by the PE in
accordance with §112.3(d).
When the container is fully emptied and meets the definition of a permanently closed
container (§112.2) (including labeling), it is not subject to the SPCC requirements, including the
integrity testing requirements. In this case, the capacity of the container does not count toward the
facility threshold capacity. If the container is refilled on site, however, it is not considered a
single-use container, and is therefore subject to the integrity testing requirements of the rule.
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.
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the approach complies or deviates from industry inspection standards and how it will be
implemented in the field. For example, if the alternative approach involves the visual inspection of
the containers, the SPCC Plan should describe the key elements of this inspection, including the
inspection frequency and scope, the training and/or qualifications of individuals conducting the
inspections, and the records used to document the inspection. If the alternative measure relies on
engineered systems to mitigate corrosion (e.g., coatings, cathodic protection) or to facilitate early
detection of small leaks, the SPCC Plan should describe how such systems are maintained and
monitored to ensure their effectiveness. For instance, where the alternative measure relies on the
presence of a liner, the Plan should discuss how the liner is adequately designed, maintained, and
inspected. This discussion may consider such factors as life expectancy stated by the
manufacturer (from cut-sheets), as-built specifications, and inspection and maintenance
procedures.
As discussed above, the environmental equivalence provision applies to the inspection and
appropriate integrity testing of bulk storage containers at §§112.8(c)(6), 112.9{c)(3), and
112.12(c)(6). PEs have the flexibility to offer environmental equivalent integrity testing options for
all classes of tanks, including shop-built tanks above 30,000 gallon capacity and field-erected tanks,
if the rationale is provided referencing appropriate industry standards.
7.4 Documentation Requirements and Role of the EPA Inspector
The facility SPCC Plan must describe the scope and schedule of examinations to be
performed on bulk storage containers (as required in §§112.3(d)(1)(iv), 112.7(e), 112.8(c)(6),
112.9(c)(3), and 112.12(c)(6)), and should reference an applicable industry inspection standard or
describe an equivalent program developed by the PE, in accordance with good engineering
practice. If a PE specifies a hybrid inspection and testing program, then the EPA inspector should
verify that the testing program covers minimum elements for the inspections, the frequency of
inspections, and their scope (e.g., wall thickness, footings, tank supports). See Section 7.5 for a list
of suggested minimum standards.
A hybrid testing program may be appropriate for a facility where an industry inspection
standard does not yet contain enough specificity for a particular facility's universe of tanks and/or
configuration, or while modifications to an industry inspection standard are under consideration. For
example, a tank user may have made a request to the industry standard-setting organizations
recommending a change or modification to a standard. Both API and STI have mechanisms to
allow tank users (and the regulatory community) to request changes to their respective inspection
standards. In this case, the modification to a standard may be proposed, but not yet accepted by
the standard-setting organization. In the meantime, the facility is still subject to the SPCC
requirements to develop an inspection and testing program. In this scenario, a hybrid inspection
and testing program may be appropriate. When reviewing the scope and schedule of a hybrid
program, the inspector should review whether an industry inspection standard and appropriate good
engineering practices were used in the development of the hybrid program.
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The facility must maintain records of all visual inspections and integrity testing, as required
bytheSPCCrulein§§112.7(e), 112.8(c)(6), 112.9(c)(3), and 112.12(c)(6). Records do not need to
be specifically created for this purpose, and may follow the format of records kept under usual and
customary business practices. These records should include the frequent inspections performed by
facility personnel. Also, industry standards generally provide example guidelines for formal tank
inspections, as well as sample checklists. The EPA inspector should review the inspection
checklists used by the facility to verify that they cover at least the minimum elements and are in
accordance with the PE-certified inspection and testing program. The tank inspection checklist
from Appendix F of 40 CFR part 112, reproduced as Table 7-6 at the end of this chapter, provides
an example of the type of information that may be included on an owner/operator-performed
inspection checklist.
The EPA inspector should review records of frequent visual inspections by facility personnel
as well as regular integrity testing of the container. Comparison records maintained at the facility
will aid in determining a container's suitability for continued service. Both API 653 and STI SP-001
contain details on determining a container's suitability for continued service. Though §112.7(e)
requires retention of all records for a period of three years, industry standards usually recommend
retention of certified inspection and non-destructive examination reports for the life of the container.
In cases where the SPCC Plan has not identified a regularly scheduled inspection and
testing program, the inspector should request information on the anticipated schedule (e.g., when a
baseline has not been established). If the facility has not performed any integrity testing of bulk
storage containers so far, the EPA inspector should verify that the SPCC Plan describes: (1) the
strategy for implementing an inspection and testing program and collecting baseline conditions
within ten years of the installation date of the tank, or during the first five-year Plan cycle (or another
schedule as identified and certified by a PE); and (2) the ongoing testing program that will be
established once the baseline information has been collected. When the inspection program
establishes inspection priorities for multiple containers, the inspector should consider the rationale
for these priorities as described in the SPCC Plan and verify implementation.
The EPA inspector should review records of regular and periodic inspections and tests of
buried and aboveground piping, valves, and appurtenances. Such inspections may be visual or
conducted by other means.
The inspector reviewing a maintenance program, such as the flowline maintenance program
required under §112.9(d)(3) for oil production facilities, should verify that the 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.
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If an impracticability determination is made for secondary containment of flowlines, the EPA
inspector should extensively review the adequacy of the flowline maintenance program along with
the contingency plan (67 FR 47078).
In summary, the EPA inspector should verify that the owner or operator has inspection
reports that document the implementation of the testing, evaluation, or inspection criteria set forth in
the Plan. He/she may also verify whether the recommended actions that affect the potential for a
discharge have been taken to ensure the integrity of the container/piping until the next scheduled
inspection or replacement of the container/piping. When an inspection procedure is outlined in the
Plan that does not meet the requirement of §§112.8(c)(6) and 112.12(c){6) (e.g., a combination of
visual inspection and another testing technique), the inspector should verify that the Plan includes a
discussion of an environmentally equivalent measure in accordance with §112.7(a)(2).
Implementation of the SPCC Plan as certified by the PE is the responsibility of the facility
owner/operator (§112.3{d)(2)).
By certifying an SPCC Plan, the PE attests that the Plan has been prepared in accordance
with good engineering practice, that it meets the requirements of 40 CFR part 112, and that it is
adequate for the facility. Thus, if testing, evaluation, or inspection procedures have been reviewed
by the certifying PE and are properly documented, they should generally be considered acceptable
by the EPA inspector. However, if testing, evaluation, or inspection procedures do not meet the
standards of common sense, appear to be at odds with recognized industry standards, do not meet
the overall objective of oil spill response/prevention, or appear to be inadequate for the facility,
appropriate follow-up action may be warranted. In this case, the EPA inspector should clearly
document any concerns to assist review and 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
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good engineering practices, including the consideration of applicable industry standards. Use of a
particular standard is voluntary. If a standard (or parts of a standard) is incorporated into a facility's
SPCC Plan, then adherence to that standard is mandatory for implementation of the Plan.
Although these guidelines are often grouped together under the term "standards," several
other terms are used to differentiate among the types of guidelines:
• Standard (or code)—set of instructions or guidelines. Use of a particular standard
is voluntary. Some groups draw a distinction between a standard and a code. The
American Society of Mechanical Engineers (ASME), for example, stipulates that a
code is a standard that "has been adopted by one or more governmental bodies and
has the force of law..."
Recommended practice—advisory document often useful for a particular situation.
Specification—may be one element of a code or standard or may be used
interchangeably with these terms.
7.5.1 API Standard 653 - Tank Inspection, Repair, Alteration, and Reconstruction
API Standard 653 -Tank Inspection, Repair, Alteration, and Reconstruction {API 653)8
provides the minimum requirements for maintaining the integrity of carbon and alloy steel tanks built
to API Standard 650 (Welded Steel Tanks for Oil Storage) and its predecessor, API 12C (Welded
Oil Storage Tanks). API 653 may also be used for any steel tank constructed to a tank
specification.9
API 653 covers the maintenance, inspection, repair, alteration, relocation, and
reconstruction of welded or riveted, non-refrigerated, atmospheric pressure, aboveground,
field-fabricated, vertical storage tanks after they have been placed in service. The standard limits
its scope to the tank foundation, bottom, shell, structure, roof, attached appurtenances, and nozzles
to the face of the first flange, first threaded joint, or first welding-end connection. The standard is
intended for use by those facilities that utilize engineering and inspection personnel technically
trained and experienced in tank design, fabrication, repair, construction, and inspection. Section 1
of the standard introduces the standard and details its scope. Sections 2 and 3 of the standard list
the works cited and definitions used in the standard, respectively.
The standard requires that a tank evaluation be conducted when tank inspection results
reveal a change in a tank from its original physical condition. Sections 4 and 5 of the standard
describe procedures for evaluating an existing tank's suitability for continued operation or a change
of service; for making decisions about repairs or alterations; or when considering dismantling,
relocating, or reconstructing an existing tank. Section 4 of the standard details the procedures to
8 API Standard 653, "Tank Inspection, Repair, Alteration, and Reconstruction," Third Edition, Addendum 1, American
Petroleum Institute, September 2003.
9 See Section 1.1.3 of API Standard 653.
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follow in evaluating the roof, shell, bottom, and foundation of the tank. Section 5 of the standard
provides a decision tree to evaluate a tank's risk of brittle fracture.
Section 6 focuses on factors to consider when establishing inspection intervals and covers
detailed procedures for performing external and internal tank integrity inspections. Inspection
intervals are largely dependent upon a tank's service history. The standard establishes time
intervals for when routine in-service inspections of the tank exterior are to be conducted by the
owner/operator and when external visual inspections are to be conducted by an authorized
inspector. External ultrasonic thickness (UT) inspections may also be conducted periodically to
measure the thickness of the shell and are used to determine the rate of corrosion. Time intervals
for external UT inspections are also provided and are based on whether or not the corrosion rate is
known.
Internal inspections (Section 6.4 of the standard) primarily focus on measuring the thickness
of the tank bottom and assessing its integrity. Measured or anticipated corrosion rates of the tank
bottom can be used to establish internal inspection intervals; however, the inspection interval
cannot exceed 20 years using these criteria. Alternatively, risk-based inspection (RBI) procedures,
which focus attention specifically on the equipment and associated deterioration mechanisms
presenting the most risk to the facility (Section 6.4.3 of the standard), can be used to establish
internal inspection intervals; an RBI may increase or decrease the 20-year inspection interval. API
653 states that an RBI assessment shall be reviewed and approved by an authorized tank inspector
and a tank design/corrosion engineer. If a facility chooses to use RBI in the development of a tank
integrity testing program, the EPA inspector should verify that these parties conducted the initial
RBI assessment.
An external inspection (Section 6.5 of the standard) can be used in place of an internal
inspection to determine the bottom plate thickness in cases where the external tank bottom is
accessible due to construction, size, or other aspects. If chosen, this option should be documented
and included as part of the tank's permanent record. Owners/operators should maintain records
that detail construction, inspection history, and repair/alteration history for the tank (Section 6.8 of
the standard). Section 6.9 of the standard stipulates that detailed reports should be filed for every
inspection performed.
Sections 7 through 11 of API 653 do not address integrity testing, but instead focus on the
repair, alteration, and reconstruction of tanks. Section 12 provides specific criteria for examining
and testing repairs made to tanks. Section 13 addresses the specific requirements for recording
any evaluations, repairs, alterations, or reconstructions that have been performed on a tank in
accordance with this standard. Appendix A to API 653 provides background information on
previously published editions of API welded steel storage tank standards. Appendix B details the
approaches that are used to monitor and evaluate the settlement of a tank bottom.10 Appendix C
provides sample checklists that the owner/operator can use when developing inspection intervals
and specific procedures for internal and external inspections of both in-service and out-of-service
10 See Section 1.1.3 of API 653.
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tanks. The requirements for authorized inspector certification are the focus of Appendix D.
Certification of authorized tank inspectors, which is valid for three years from the date of issue,
requires the successful completion of an examination, as well as a combination of education and
experience. Technical inquiries related to the standard are the focus of Appendix E. Appendix F
summarizes the non-destructive examination (NDE) requirements for reconstructed and repaired
tanks. Technical inquiries regarding the use of the standard can be made through API's Web site
(www.api.org). Selected responses to technical inquiries are provided in the Technical Inquiry
appendices of the standard.
7.5.2 STI Standard SP-001 - Standard for the Inspection of Aboveground Storage Tanks
STI Standard SP-001 - Standard for the Inspection of Aboveground Storage Tanks
(SP-001)11 provides the minimum inspection requirements and evaluation criteria required to
determine the suitability for continued service of aboveground storage tanks until the next
scheduled inspection. Only aboveground tanks included in the scope of this standard are
applicable for inspection per this standard. Other standards, recommended practices, and other
equivalent engineering and best practices exist that provide alternative inspection requirements for
tanks defined within the scope of this standard and for tanks outside the scope of this standard.
For example, API Standard 653, "Tank Inspection, Repair, Alteration, and Reconstruction," provides
additional information pertaining to tanks built to API 650 and API 12C. API 12R1, "Recommended
Practice for Setting, Maintenance, Inspection, Operation, and Repair of Tanks in Production
Service," pertains to tanks employed in production service or other similar service.
SP-001 applies to the inspection of aboveground storage tanks, including shop-fabricated
tanks, field-erected tanks, and portable containers, as defined in this standard, as well as the
containment systems. The inspection and testing requirements for field-erected tanks are covered
separately in Appendix B of the standard. Specifically, the standard applies to ASTs storing stable,
flammable, and combustible liquids at atmospheric pressure with a specific gravity less than
approximately 1.0 and those storing liquids with operating temperatures between ambient
temperature and 200 degrees Fahrenheit (93.3'C). At a minimum, the following tank components
shall be inspected (as applicable): tank, supports, anchors, foundation, gauges and alarms,
insulation, appurtenances, vents, release prevention barriers, and spill control systems.
Section 3 addresses safety considerations, and Section 4 addresses AST inspector
qualifications.
Section 5 of the standard addresses the criteria, including AST type, size, type of
installation, corrosion rate, and previous inspection history, if any, that should be used to develop a
schedule of inspections for each AST. Table 5.5 (Table of Inspection Schedules) places tanks into
one of three categories and establishes different requirements regarding the type and frequency of
periodic inspection by tank owner/operators as well as 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.
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certified inspector. The factors used for categorizing tanks include tank size, whether or not the
tank is in contact with the ground, the presence or absence of secondary containment (or spill
control), and the presence or absence of a continuous release detection method (CRDM).
Section 6 provides guidelines for the periodic inspections conducted by the owner or his/her
designee. The owner's inspector is to complete an AST Record for each AST or tank site, as well
as a Monthly Inspection Checklist and an Annual Inspection Checklist. Monthly inspections should
monitor water accumulation to prevent Microbial Influenced Corrosion (MIC), and action should be
taken if MIC is found. Additional requirements for field-erected tanks are in Appendix B of SP-001.
Section 7 of SP-001 contains the minimum inspection requirements for formal external
inspections, which are to be performed by a certified inspector. Inspections should cover the AST
foundations, supports, secondary containment, drain valves, ancillary equipment, piping, vents,
gauges, grounding system (if any), stairways, and coatings on the AST. Original shell thickness
should be determined using one of several suggested methods. Ultrasonic Thickness Testing
(UTT) readings are to be taken at different locations of the AST depending upon whether the AST is
horizontal, vertical, rectangular, and/or insulated. The final report should include field data,
measurements, pictures, drawings, tables, and an inspection summary, and should specify the next
scheduled inspection.
Section 8 of the standard details the minimum inspection requirements for formal internal
inspections, which are to be performed by a certified inspector. A formal internal inspection
includes the requirements of an external inspection with some additional requirements for specific
situations that are outlined in the standard. Double-wall tanks and secondary containment tanks
may be inspected by checking the interstice for liquid or by other equivalent methods. For elevated
ASTs where all external surfaces are accessible, the internal inspection may be conducted by
examining the tank exterior using such methods as Ultrasonic Thickness Scans (UTS). For all
other situations, entry into the interior of the AST is necessary. Internal inspection guidelines are
detailed separately for horizontal ASTs and for vertical and rectangular ASTs in Sections 8.2 and
8.3, respectively. Additional requirements for field-erected tanks are in Appendix B. The final
report should contain elements similar to reports prepared for external inspections.
Section 9 addresses leak testing methods. For shop-fabricated ASTs, the standard
references the Steel Tank Institute Recommended Practice R912, "Installation Instructions for Shop
Fabricated Stationary Aboveground Storage Tanks for Flammable, Combustible Liquids." The
standard also references DOT regulations for portable containers:
49 CFR part 173.28, Reuse, reconditioning, and remanufacturing of packagings,
mainly for drums;
* 49 CFR part 178.803, Testing and certification of intermediate bulk containers
(IBCs); and
49 CFR part 180.605, or equivalent, for portable container testing and recertification.
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Section 10 addresses the suitability for continued service based on the results of formal
internal and/or external inspections. For ASTs that show signs of damage caused by MIC, the
criteria for assessing their suitability for continued service differ based on the category they fall into
(as per Section 5 of SP-001). Categories refer to the level of reduction of the shell thickness. For
other tank damage, an engineer experienced in AST design or a tank manufacturer should
determine if an inspection is required for any AST that was exposed to fire, natural disaster,
excessive settlement, overpressure, or damage from cracking.
Section 11 of the standard details recordkeeping requirements. Appendix A presents
supplemental technical information including terms commonly associated with ASTs, and Appendix
B presents information for the inspection of field-erected ASTs.
For more information on SP-001, please visit the Steel Tank Institute Web site,
http://www.steeltank.com.
7.5.3 API Recommended Practice 575 - Inspection of Atmospheric and Low-Pressure
Storage Tanks
API Recommended Practice 575 - Inspection of Atmospheric and Low-Pressure Storage
Tanks12 (API RP 575), which supplements API 653, covers the inspection of atmospheric tanks
(e.g., cone roof and floating roof tanks) and low-pressure storage tanks (i.e., those that have
cylindrical shells and cone or dome roofs) that have been designed to operate at pressures from
atmospheric to 15 pounds per square inch gauge (psig). (API RP 572 covers tanks operating
above 15 psig.) In addition to describing the types of storage tanks and standards for their
construction and maintenance, API RP 575 also covers the reasons for inspection, causes of
deterioration, frequency and methods of inspection, methods of repair, and the preparation of
records and reports. API RP 575 applies only to the inspection of atmospheric and low-pressure
storage tanks that have been in service. Section 1 of API RP 575 introduces the recommended
practice and details its scope. Section 2 lists the references that are cited in the recommended
practice.
Section 3 of API RP 575 describes selected methods for non-destructive examination of
tanks, including ultrasonic thickness measurement, ultrasonic corrosion testing, ultrasonic shear
wave testing, and magnetic flux testing. Section 4 describes the construction materials and design
standards, use, and specific types of atmospheric and low-pressure storage tanks. Section 5
covers the reasons for inspection and causes of deterioration of both steel and non-steel storage
tanks. Section 5 also covers the deterioration and failure of auxiliary equipment.
Section 6 of API RP 575 addresses inspection frequency; it mainly defers to the inspection
frequency requirements described in API 653. Section 7 covers the methods of inspection and
inspection scheduling. It addresses the external inspection of both in-service and out-of-service
12 API RP 575, "Inspection of Atmospheric and Low-Pressure Storage Tanks," 1sted., American Petroleum Institute,
November 1995.
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tanks and the internal inspection of out-of-service tanks. Section 7 provides some information
about scheduling tank inspections, but it mostly defers to API 653. Section 8 addresses the
methods for repairing tanks. Recordkeeping and inspection reports are the focus of Section 9,
which stresses the importance of keeping complete records. Appendix A of the recommended
practice provides a typical field record form and history card. Appendix B contains a typical tank
report form. Appendix C provides sample checklists for internal and external tank inspections.
7.5.4 API Recommended Practice 12R1 - Recommended Practice for Setting, Maintenance,
Inspection, Operation, and Repair of Tanks in Production Service
API Recommended Practice 12R1 - Recommended Practice for Setting, Maintenance,
Inspection, Operation, and Repair of Tanks in Production Service (API RP 12R1)13 provides
guidance on new tank installations and maintenance of existing production tanks. These tanks are
often referred to as "upstream" or "extraction and production (E&P) tanks." The recommended
practices are primarily intended for tanks fabricated to API Specifications 12B, D, F, and P that are
employed in on-land production service.14 This said, the basic principles in the recommended
practices can also be applied to other atmospheric tanks that are employed in similar oil and gas
production, treating, and processing services; however, they are not applicable to refineries,
marketing bulk stations, petrochemical plants, or pipeline storage facilities operated by carriers.
According to the recommended practice, tanks that are fabricated to API Standards 12C or 650
should be maintained in accordance with API 653, summarized above.
Sections 1, 2, and 3 of API RP 12R1 describe the scope of the standard, the 19 standards it
references, and the relevant definitions, respectively. The remaining four main sections describe
the recommended practices. Section 4 provides recommended practices for setting of new or
relocated tanks and connecting tanks. Section 5 recommends practices for safe operation and spill
prevention for tanks.15 Section 6 details the recommended practices for routine operational and
external and internal condition examinations, internal and external inspections, maintenance of
tanks, and recordkeeping. Table 1 of this recommended practice details the type of observations,
frequency, and associated personnel requirements for internal and external tank inspections.
Records from these inspections should be retained with permanent equipment records. Finally,
Section 7 provides guidance for the alteration or repair of various tank components. API RP 12R1
also contains nine appendices detailing the recommended requirements of qualified inspectors,
sample calculations for venting requirements, observations regarding shell corrosion and brittle
fracture, checklists for internal and external condition examinations and inspections, details
regarding the minimum thickness of tank elements, and various figures and diagrams.
13 API Recommended Practice 12R1, "Recommended Practice for Setting, Maintenance, Inspection, Operation, and
Repair of Tanks in Production Service," 5th edition. American Petroleum Institute. August 1997.
14 API Specifications 12B, 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."
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7.5.5 API 570 - Piping Inspection Code: Inspection, Repair, Alteration, and Rerating of
In-service Piping Systems
API 570 - Piping Inspection Code: Inspection, Repair, Alteration, and Rerating of In-service
Piping Systems (API 570)16 covers inspection, repair, alteration, and'rerating procedures for metallic
piping systems that have been in service. API 570 was developed for the petroleum refining and
chemical process industries. In-service piping systems covered by API 570 include those used for
process fluids, hydrocarbons, and similar flammable or toxic fluids. API states that this standard is
not a substitute for the original construction requirements governing a piping system before it is
placed in service. API 570 is intended for use by organizations that maintain or have access to an
authorized inspection agency; a repair organization; and technically qualified piping engineers,
inspectors, and examiners. The owner/operator is responsible for implementing a piping system
inspection program, controlling the inspection frequencies, and ensuring the maintenance of piping
systems in accordance with this standard.
Section 5, the first substantive section of the standard, addresses the specific inspection
and testing practices for in-service piping systems. Section 6 addresses the frequency and extent
of inspection of piping. Inspection intervals for piping are based largely on the likelihood and
consequence of failure (i.e., they are risk-based), which takes into account the corrosion rate and
remaining life calculations; piping service classification; applicable jurisdictional requirements; and
the judgement of the inspector, the piping engineer, the piping engineer supervisor, or a corrosion
specialist. Table 6-1 of API 570 provides maximum inspection intervals for piping based on piping
service classification (Class 1 poses the highest risk of an emergency if a leak were to occur; Class
2, which includes the majority of unit process piping, poses an intermediate risk; Class 3 poses the
lowest risk) and the corrosion measurement technique (i.e., thickness measurements or visual
external inspection) that is used. In general, the maximum inspection interval for in-service piping
should be between five years for Class 1 piping to ten years for Class 3 piping.
Section 7 of the standard addresses data evaluation, analysis, and recording. The
owner/operator should maintain permanent records for all piping systems covered by API 570.
Section 8 provides guidelines for repairing, altering, and rerating piping systems. Inspecting buried
process piping is different from inspecting other process piping because the inspection is hindered
by the inaccessibility of the affected areas of the piping; therefore, API 570 addresses the
inspection of buried piping separately in Section 9. Appendices A, B, C, and D of API 570 address
inspector certification, technical inquiries, examples of repairs, and the external inspection checklist
for process piping, respectively.
16 API 570, "Piping Inspection Code: Inspection, Repair, Alteration, and Rerating of In-service Piping Systems," 2nd
ed., American Petroleum Institute, October 1998.
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7.5.6 API Recommended Practice 574 - Inspection Practices for Piping System
Components
API Recommended Practice 574 - Inspection Practices for Piping System Components (API
RP 574)17 covers inspection practices for piping, tubing, valves (other than control valves), and
fittings used in petroleum refineries and chemical plants. API RP 574 is not specifically intended to
cover specialty items, such as control valves, level gauges, and instrument controls columns, but
many of the inspection methods are applicable to these items. API RP 574 provides more detailed
information about piping system components and inspection procedures than API 570. Section 1
introduces the recommended practice and details its scope. Sections 2 and 3, respectively, list the
references and definitions used throughout the recommended practice.
Section 4, which begins the substantive portion of the recommended practice, details the
types, material specifications, sizes, and other characteristics of the components of the piping
system, which include the piping, tubing, valves, and fittings. This section of the recommended
practice also addresses the common joining methods used to assemble piping components.
Section 5 of API RP 574 presents the rationale for inspecting the piping system: to maintain safety,
attain reliable and efficient operation, and meet regulatory requirements. The procedures for
monitoring the piping system components for corrosion and inspecting for deterioration are the
focus of Section 6. Section 7 provides guidelines for establishing the frequency and time (i.e., while
equipment is operating or while equipment is shut down) of inspection. Similar to API 570, this
recommended practice uses the following conditions to determine the frequency of inspection: the
consequences of a failure (piping classification, see summary of API 570 for a description), the
degree of risk, the amount of corrosion allowance remaining, the historical data available, and the
regulatory requirements.
Section 8 of API RP 574 outlines the safety precautions that should be taken and
preparatory work that should be performed prior to inspecting the piping system components. The
inspection tools commonly used to inspect piping are tabulated in Section 9 of this recommended
practice. Section 10 details the specific procedures that should be followed when inspecting the
components of the piping system. This section also covers the inspection of underground piping
(Section 10.3) and new construction (Section 10.4). Section 11 describes the procedures a piping
engineer should follow to determine the thickness at which piping and valves and flanged fittings
should be retired. Recordkeeping is the focus of Section 12. Appendix A of the recommended
practice provides an external inspection checklist for process piping.
17 API RP 574, "Inspection Practices for Piping System Components," 2nd ed., American Petroleum Institute, June
1998.
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7.5.7 API Recommended Practice 1110 - Pressure Testing of Liquid Petroleum Pipelines
API Recommended Practice 1110 - Pressure Testing of Liquid Petroleum Pipelines (API RP
1110)18 provides guidance regarding the procedures, equipment, and factors to consider when
pressure testing new and existing liquid petroleum pipelines. Pressure testing uses a liquid test
medium (typically water) to apply internal pressure to a segment of pipe above its normal or
maximum operating pressure for a fixed period of time under no-flow conditions to verify that the
"test segments have the requisite structural integrity to withstand normal and maximum operating
pressures19 and to verify that they are capable of liquid containment." This testing should be
performed by '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.
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A brittle fracture assessment may be warranted based on operating conditions and/or the
condition of the AST. API RP 579 provides separate brittle fracture assessment procedures for
continued service based on three levels. All three apply to pressure vessels, piping, and tankage,
although a separate assessment procedure is provided for tankage.
Level 1 assessments are used for equipment that meets toughness requirements in
a recognized code or standard (e.g., API 650).
Level 2 assessments exempt equipment from further assessment and qualify it for
continued service based on one of three methods. These methods are based on
operating pressure and temperature; performance of a hydrotest; or the materials of
construction, operating conditions, service environment, and past operating
experience.
* Level 3 assessments, which normally utilize a fracture mechanics methodology, are
used for tanks that do not meet the acceptance criteria for Levels 1 and 2.
A decision tree in API RP 579 (Figure 3.2, Brittle Fracture Assessment for Storage Tanks)
outlines this assessment procedure. The Level 1 and Level 2 brittle fracture assessment
procedures are nearly identical to those found in API 653, Section 5, with a few notable exceptions:
API 653 does not use the Level 1 and Level 2 designations; API 653 applies only to tanks that meet
API 650 (7th edition or later) construction standards, whereas API 579 applies to tanks that meet
toughness requirements in the "current construction code"; and the two standards set a different
limit on the maximum membrane stress (the stress forces that form within the shell as a result of the
pressure of the liquid inside the vessel). There is, however, one major difference between API 653
and API 579: API 653, Section 5, does not allow for an exemption of the hydrostatic test
requirement as API 579 does. API 579 allows for a probabilistic evaluation of the potential for brittle
fracture using engineering calculations (i.e., a Level 3 assessment) in lieu of the hydrostatic test.
7.5.9 API Standard 2610 - Design, Construction, Operation, Maintenance, and Inspection of
Terminal & Tank Facilities
The standard23 has short sections on petroleum terminals, pipeline tankage facilities,
refinery facilities, bulk plants, lube blending and packaging facilities, asphalt plants, and aviation
service facilities; these sections mainly serve to define what is meant by each type of facility. The
standard does not apply to installations covered by API Standard 2510 and API RP 12R1, as well
as a list of specific types of facilities and equipment Indicated in the standard. The standard lists
governmental requirements and reviews that should be conducted to ensure that facilities meet
applicable federal, state, or local requirements (Section 1.3); and has an extensive list of standards,
codes, and specifications to use (Section 2.1).
Section 4 of the standard covers the site selection and spacing requirements for the design
and construction of new terminal facilities. Section 5 addresses the methods of pollution prevention
23 API Recommended Practice 2610, "Design, Construction, Operation, Maintenance, and Inspection of Terminal and
Tank Facilities," 2nd edition, American Petroleum Institute, May 2005.
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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.
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be examined for leaks after being put into service. Options for leak testing include hydrostatic tests,
pneumatic tests, hydropneumatic tests, and alternative leak tests.
The standard requires that records detailing the examination personnel's qualifications and
examination procedures be kept for at least five years. Test records or the inspector's certification
that the piping has passed pressure testing are also required to be retained.
7.5.11 ASME Code for Pressure Piping B31.4-2002 - Pipeline Transportation Systems for
Liquid Hydrocarbons and Other Liquids
ASME Code for Pressure Piping B31.4-2002 - Pipeline Transportation Systems for
Liquid Hydrocarbons and Other Liquids26 describes "engineering requirements deemed necessary
for safe design and construction of pressure piping." These requirements are for the "design,
materials, construction, assembly, inspection, and testing of piping transporting liquids" such as
crude oil and liquid petroleum products between various facilities. Piping includes bolting, valves,
pipes, gaskets, flanges, fittings, relief devices, pressure-containing parts of other piping
components, hangers and supports, and any other equipment used to prevent the overstressing of
pressure-containing pipes. This code's primary purpose is to "establish requirements for safe
design, construction, inspection, testing, operation, and maintenance of liquid pipeline systems for
protection of the general public and operating company personnel."
The personnel inspecting the piping are deemed qualified based on their level of training
and experience and should be capable of performing various inspection services such as right-of-
way and grading, welding, coating, pressure testing, and pipe surface inspections. Inspections of
piping material and inspections during piping construction should include the visual evaluation of all
piping components. Once construction is complete, these piping components and the entire system
should be tested. Testing methods include hydrostatic testing of internal pressure piping; leak
testing; and qualification tests based on a visual examination, bending properties, determination of
wall thickness, determination of weld joint factor, weldability, determination of yield strength, and the
minimum yield strength value.
Records detailing the design, construction, and testing of the piping should be kept in the
files of the operating company for the life of the facility.
7.5.12 DOT 49 CFR 180.605 - Requirements for Periodic Testing, Inspection, and Repair of
Portable Tanks and Other Portable Containers
Section 180.60527 applies to any portable tank constructed to a DOT (e.g., 51, 56, 57,60, or
intermodal [IM]) or United Nations (UN) specification. According to these requirements, a portable
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.
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tank must be inspected prior to further use if it shows evidence of a condition that might render it
unsafe for use, has been damaged in an accident, has been out of service for more than a year,
has been modified, or is in an unsafe operating condition. All tanks must receive an initial
inspection prior to being placed into service and a periodic inspection or intermediate periodic
inspection every two to five years. The timeframe between inspections depends upon the tank's
specification.
Intermediate periodic inspections must include an internal and external examination of the
tank and fittings, a leak test, and a test of the service equipment. The periodic inspection and test
must include an external and internal inspection and a sustained air pressure leak test, unless
exempted. For tanks that show evidence of damage or corrosion, an exceptional inspection and
test is mandated. The extent of the inspection is dictated by the amount of damage or deterioration
of the portable tank. Specification-60 tanks are further tested by filling them with water.
Specification-IM or Specification-UN portable tanks must also be hydrostatically tested. Any tank
that fails a test may not return to service until it is repaired and retested. An approval agency must
witness the retest and certify the tank for return to service. The date of the last pressure test and
visual inspection must be clearly marked on each IM or UN portable tank. A written record of the
dates and results of the tests, including the name and address of the person performing the test, is
to be retained by the tank owner or authorized agent.
Requirements for retest and inspection of Intermediate Bulk Containers (IBCs) are specified
in 49 CFR 180.352. Requirements depend on the IBC shell material. For metal, rigid plastic, and
composite IBCs, they include a leakproof test and external visual inspection every 2.5 years from
the date of manufacture or repair. They also require an internal inspection every 5 years to ensure
that the IBC is free from damage and capable of withstanding the applicable conditions. Flexible,
fiberboard, or wooden IBCs must be visually inspected prior to first use and permitted reuse.
Records of each test must be kept until the next test, or for at least 2.5 years from the date of the
last test.
Design standards and specifications for initial qualification and reuse performance testing for
portable tanks, drums, and IBCs are contained in 49 CFR part 178, Specifications for Packaging.
See www.access.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.
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safe storage, handling, and dispensing of fuels used in aircraft on airports but not in terms of quality
control. Although airports that are not certificated under 14 CFR part 139 are not required to
develop fuel safety standards, the FAA recommends that they do so.
This AC is not intended to replace airport procedures developed to meet requirements
imposed because of the use of special equipment, nor to replace local regulations. For specific
provisions, the other standards that are referenced in this AC are:
* For fuel storage, handling and dispensing, the National Fire Prevention Association's
"Standard for Aircraft Fuel Servicing"
For refueling and quality control procedures, the National Air Transportation
Association's "Refueling and Quality Control Procedures for Airport Service and
Support Operations." This provides information about fuel safety, types of aviation
fuels, fueling vehicle safety, facility inspection procedures, fueling procedures, and
methods for handling fuel spills. API also publishes documents pertaining to
refueling and facility specifications.
The AC also requires fuel safety training for airports certificated under 14 CFR part 139.
(See http://www.faa.gov/arp/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.
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For example, a hybrid testing program may be developed in cases where no specific
industry inspection standard exists to date, as is the case for tanks that contain certain products
such as animal fats and vegetable oils, asphalt, or oils that have a specific gravity greater than 1.0.
Although there are no industry standards specific to integrity testing of bulk storage containers
containing vegetable oils at this time, some facilities with large animal fat and vegetable oil tanks
follow API 653. Additionally, the U.S. Food and Drug Administration (FDA) sets requirements for
food-grade oils, which would need to be followed in addition to EPA's integrity testing requirements.
The following provide recommendations of the minimum elements for a hybrid inspection
program.
For shop-built tanks:
Visually inspect exterior of tank;
Evaluate external pitting;
Evaluate "hoop stress and longitudinal stress risks" where corrosion of the shell is
present;
Evaluate condition and operation of appurtenances;
• Evaluate welds;
Establish corrosion rates and determine the inspection interval and suitability for
continued service;
Evaluate tank bottom where it is in contact with ground and no cathodic protection is
provided;
• Evaluate the structural integrity of the foundation;
Evaluate anchor bolts in areas where required; and
Evaluate the tank to determine it is hydraulically sound and not leaking.
For field-erected tanks:
Evaluate foundation;
Evaluate settlement;
Determine safe product fill height;
Determine shell corrosion rate and remaining life;
Determine bottom corrosion rate and remaining life;
Determine the inspection interval and suitability for continued service;
Evaluate all welds;
Evaluate coatings and linings;
Evaluate repairs for risk of brittle fracture; and
• Evaluate the tank to determine it is hydraulically sound and not leaking.
EPA suggests that an appropriately trained and qualified inspector conduct a hybrid
inspection and provide a detailed report of the findings. The qualifications of the tank inspector will
depend on the condition and circumstances of the tank (e.g., size, field-erected or shop-built), and
an inspector should only certify an inspection to the extent he/she is qualified to do so. A registered
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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.
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Table 7-5 summarizes the facility components covered by select industry standards and
recommended practices for tanks, valves, pipes, and appurtenances. Additional standards and/or
manufacturers' standards may also apply. The recommended standards for facility personnel to
use for inspecting and testing at a particular facility would be specified in the SPCC Plan by the PE
preparing the Plan. All actions (e.g., visual inspection or testing) performed by facility personnel
must be appropriately documented and maintained in permanent facility records as per§112.7(e).
Table 7-5. Checklist summary of industry standards for inspection, evaluation, and testing.
Facility 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
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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.
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CWA§§311(j)(l)(c)
Summary:
The President is authorized to issue regulations establishing procedures, methods,
equipment, and other requirements to prevent discharges of oil from vessels and facilities.
Rule Text:
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...
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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
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§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
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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
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§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
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Environmental Protection Agency
§112.2
currents within the area in which the
systems or equipment Is intended to
function.
Alteration means any work on a con-
tainer involving cutting, burning,
welding, or heating operations that
changes the physical dimensions or
configuration of the container.
Animal fat means a non-petroleum
oil. fat, or grease of animal, fish, or
marine mammal origin.
Breakout tank means a container used
to relieve surges in an oil pipeline sys-
tem or to receive and store oil trans-
ported by a pipeline for reinjection and
continued transportation by pipeline.
Bulk storage container means any con-
tainer used to store oil. These con-
tainers are used for purposes including,
but 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
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Environmental Protection Agency
§112.2
States, and any facility of any kind
that is subject to the jurisdiction of
the United States and is located in. on,
or under any other waters.
Oil means oil of any kind or in any
form, including, but not limited to;
fats, oils, or greases of animal, fish, or
marine mammal origin; vegetable oils,
including oils from seeds, nuts, fruits,
or kernels; and, other oils and greases,
including petroleum, fuel oil, sludge,
synthetic oils, mineral oils, oil refuse,
or oil mixed with wastes other than
dredged spoil.
Oil Spill Removal Organization means
an entity that provides oil spill re-
sponse resources, and includes any for
profit or not-for-profit contractor, co-
operative, or in-house response re-
sources that have been established in a
geographic area to provide required re
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
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§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
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Environmental Protection Agency
§112.4
(e) If you are the owner or operator
of a facility for which a Plan is re-
quired under this section, you must:
(1) Maintain a complete copy of the
Plan at the facility if the facility is
normally attended at least four hours
per day, or at the nearest field office if
the facility is not so attended, and
(2) Have the Plan available to the Re-
gional Administrator for on-site review
during normal working hours.
(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
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§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
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Environmental Protection Agency
§112.7
subject to this part; or, if your facility
was in operation on or before August
16, 2002, five years from the date your
last review was required under this
part. As a result of this review and
evaluation, you must amend your
SPCC Plan within six months of the re-
view to include more effective preven-
tion and control technology if the tech-
nology has been field-proven at the
time of the review and will signifi-
cantly reduce the likelihood of a dis-
charge as described in §112.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
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§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
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Environmental Protection Agency
§112.7
(e) Inspections, tests, and records. Con-
duct inspections and tests required by
this part. In accordance with written
procedures that you or the certifying
engineer develop for the facility. You
must keep these written procedures
and a record of the inspections and
tests, signed by the appropriate super-
visor or inspector, with the SPCC Plan
for a period of three years. Records of
inspections and tests kept under usual
and customary business practices will
suffice for purposes of this paragraph.
(f) Personnel, training, and discharge
prevention procedures. (1) At a min-
imum, train your oil-handling per-
sonnel in the operation and mainte-
nance of equipment to prevent dis-
charges; discharge procedure protocols;
applicable pollution control laws,
rules, and regulations; general facility
operations; and, the contents of the fa-
cility SPCC Plan.
(2) Designate a person at each appli-
cable facility who is accountable for
discharge prevention and who reports
to facility management.
(3) Schedule and conduct discharge
prevention briefings for your oil han-
dling personnel at least once a year to
assure adequate understanding of the
SPCC Plan for that facility. Such brief-
ings must highlight and describe
known discharges as described in
§112.1(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
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§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
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Environmental Protection Agency
§112.8
(iii) Open the bypass valve and reseal
it following drainage under responsible
supervision; and
(iv) Keep adequate records of such
events, for example, any records re-
quired under permits issued in accord-
ance with §§122.41(j)(2) and 122.41(m)(3)
of this chapter.
(4) Protect any completely buried
metallic storage tank installed on or
after January 10, 1974 from corrosion
by coatings or cathodic protection
compatible with local soil conditions.
You must regularly leak test such
completely buried metallic storage
tanks.
(5) Not use partially buried or
bunkered metallic tanks for the stor-
age of oil, unless you protect the bur-
ied section of the tank from corrosion.
You must protect partially buried and
bunkered tanks from corrosion by
coatings or cathodic protection com-
patible with local soil conditions.
(6) Test, each aboveground container
for integrity on a regular schedule, and
whenever you make material repairs.
The frequency of and type of testing
must take into account container size
and design (such as floating roof, skid-
mounted, elevated, or partially buried).
You must combine visual inspection
with another testing technique such as
hydrostatic testing, radiographic test-
ing, ultrasonic testing, acoustic emis-
sions testing, or another system of
non-destructive shell testing. You
must keep comparison records and you
must also inspect the container's sup-
ports and foundations. In addition, you
must frequently inspect the outside of
the container for signs of deteriora-
tion, discharges, or accumulation of oil
inside diked areas. Records of inspec-
tions and tests kept under usual and
customary business practices will suf-
fice for purposes of this paragraph.
(7) Control leakage through defective
internal heating coils by monitoring
the steam return and exhaust lines for
contamination from internal heating
coils that discharge into an open wa-
tercourse, or pass the steam return or
exhaust lines through a settling tank,
skimmer, or other separation or reten-
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
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§112.9
40 CFR Ch. I (7-1-05 Edition)
you must: undertake additional exam-
ination and corrective action as indi-
cated by the magnitude of the damage.
(2) Cap or blank-flange the terminal
connection at (.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
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Environmental Protection Agency
§112.11
following a sudden change in atmos-
pheric temperature, to detect possible
system upsets capable of causing a dis-
charge.
(3) Have a program of flowline main-
tenance to prevent discharges from
each flowline.
§112.10 Spill Prevention, Control, and
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
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§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
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Environmental Protection Agency
§112.12
catchment basins in areas subject to
periodic flooding.
(4) If facility drainage is not engi-
neered as in paragraph (b)(3) of this
section, equip the final discharge of all
ditches Inside the facility with a diver-
sion system that would, in the event of
an uncontrolled discharge, retain oil in
the facility.
(5) Where drainage waters are treated
in more than one treatment unit and
such treatment is continuous, and
pump transfer is needed, provide two
"lift" pumps and permanently install
at least one of the pumps. Whatever
techniques you use, you must engineer
facility drainage systems to prevent a
discharge as described in §112.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
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Environmental Protection Agency
§112.15
the storage of oil unless its material
and construction are compatible with
the material stored and the conditions
of storage.
(2) Provide all tank battery, separa-
tion, and treating facility installations
with a secondary means of contain-
ment for the entire capacity of the
largest single container and sufficient
freeboard to contain precipitation. You
must safely confine drainage from
undiked areas in a catchment basin or
holding pond.
(3) Periodically and upon a regular
schedule visually inspect each con
tainer of oil for deterioration and
maintenance needs, including the foun-
dation and support of each container
that is on or above the surface of the
ground.
(4) Engineer or update new and old
tank battery installations in accord-
ance with good engineering practice to
prevent, discharges. You must provide
at least one of the following:
(i) Container capacity adequate to as-
sure that a container will not overfill if
a pumper/gauger is delayed in making
regularly scheduled rounds.
(ii) Overflow equalizing lines between
containers so that a full container can
overflow to 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
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Environmental Protection Agency
§112.20
plan to the Regional Administrator,
according to the following provisions:
(1) For the owner or operator of a fa-
cility in operation on or before Feb-
ruary 18, 1993 who is required to pre-
pare and submit a response plan under
33 U.S.C. 1321(j)(5), the Oil Pollution
Act of 1990 (Pub. L. 101-380, 33 U.S.C.
2701 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
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§112.20
40 CFR Ch. I (7-1-05 Edition)
(4) Preparation and submission of re-
sponse plans—Animal fat and vegetable
oil facilities. The owner or operator of
any non-transportation-related facility
that handles, stores, or transports ani-
mal fats 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
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Environmental Protection Agency
§112.20
(2) Require amendments to any re-
sponse plan that does not meet the re-
quirements of this section:
(3) Approve any response plan that
meets the requirements of this section;
and
(4) Review each response plan peri-
odically thereafter on a schedule estab-
lished by the Regional Administrator
provided that the period between plan
reviews does not exceed five years.
(d)(l) The owner or operator of a fa-
cility for which a response plan is re-
quired under this part shall revise and
resubmit revised portions of the re-
sponse plan within 60 days of each fa-
cility change that materially may af
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
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§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
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Environmental Protection Agency
§112.20
plan periodically to reflect changes at
the facility.
(h) A response plan .shall follow the
format of the model facility-specific re-
sponse plan included in Appendix F to
this part, unless you have prepared an
equivalent response plan acceptable to
the Regional Administrator to meet
State or other Federal requirements. A
response plan that does not follow the
specified format in Appendix F to this
part shall have an emergency response
action plan as specified in paragraphs
(h)(l) of this section and 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
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§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
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Environmental Protection Agency
§112.21
(ii) A description of the equipment to
be used for each scenario;
(iii) Plans to dispose of contaminated
cleanup materials; and
(iv) Measures to provide adequate
containment and drainage of dis-
charged oil.
(8) Self-inspection, drills/exercises, and
response training. The response plan
shall include:
(i) A checklist and record of inspec-
tions for tanks, secondary contain
ment, and response equipment;
(ii) A description of the drill/exercise
program to be carried out under the re-
sponse plan as described in §112.21;
(iii) A description of the training pro-
gram to be carried out under the re
sponse plan as described in §112.21; 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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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.
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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
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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
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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.
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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
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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
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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
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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
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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
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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
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Environmental Protection Agency Pt. 112, App. E
TABLE 5 TO APPENDIX E—RESPONSE CAPABILITY CAPS BY OPERATING AREA—Continued
Rivers & Canals
February 18,1998:
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
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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
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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
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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
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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
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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
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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
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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
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Environmental Protection Agency
Pt. 112, App. F
Attachment K-2 Example (continued) --
Worksheet to Plan Volume of Response Resources
for Worst Can* Discharge - Animal Fats and Vegetable Oils (continued)
Part II On-Water OiL Recovery .Capacity (barrels/day)
Tier 2
Tier 1
30,000
50,000
Step (El) > step x
step <&1>
step (El) x step x step <
Tier 1
Tier 2
12,500
25,000
Tier 3
50.0CO
Pare v On-Wa_ter Amount Needed to be^Jdencified. but not Contracted for
in Advance (barrels/day)
Tier l
Tier 2
Tier 3
17,500
25,000
30,000
n Her t - step
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Pt. 112. App. F
1.7 Plan Implementation
1.7.1 Response Resources for Small. Me-
dium, and Worst Case Spills
1.7.2 Disposal Plans
1.7.3 Containment and Drainage Planning
1.8 Sclf-Inspertlan. Drills/Exercises, and Re
sponse Training
1.8.1 Facility Self-Inspection
1.8.1.1 Tank'Inspection
1.8.1.2 Response Equipment Inspection
1.8.1.3 Secondary Containment Inspection
1.8.2 Facility Drills/Exercises
1.8.2.1 Qualified Individual Notification
Drill Logs
1.8.2.2 Spill Management Team Tabletop
Exercise Logs
1.8.3 Response Tra i ni 11 g
1.8.3.1 Personnel Response Training Logs
1.8.3.2 Discharge Prevention Meeting Logs
1.9 Diagrams
1.10 Security
2.0 Response Plan Cover Sheet
3.0 Acronyms
4.0 References
1.0 Model Facility-Specific Response Plan
(A) Owners or operators of facilities regu-
lated under this part which pose a threat of
substantial harm to the environment by dis-
charging ail into or on navigable waters or
adjoining shorelines are required to prepare
and submit facility-specific response plans to
EPA in accordance with the provisions in
40 CFR Ch. I (7-1-05 Edition)
this appendix. This appendix further de-
scribes the required elements In §112.20(h),
(B) Response plans must be sent to the ap-
propriate EPA Regional office. Figure F-l of
this Appendix lists each EPA Regional office
and the address where owners or operators
must, submit their response plans. Those fa-
cilities deemed by the Regional Adminis-
trator (RA) to pose a threat of significant
and substantial harm to the environment
will have their plans reviewed and approved
by EPA. In certain cases, information re-
quired in the model response plan is similar
to information currently maintained in the
facility's Spill Prevention, Control, and
Countenneasures (SPCC) Plan as required by
40 CFR 112.3. In these cases, owners or opera-
tors may reproduce the Information and In-
clude a photocopy in the response plan.
(C) A complex may develop a single re-
sponse plan with a set of core elements for
all regulating agencies and separate sections
for the non-transportation related and trans-
portation-related components, as described
in § 112.20(h). Owners or operators of large fa-
cilities that handle, store, or transport oil at
more chan one geographically distinct loca-
tion (e.g., oil storage areas at opposite ends
of a single, continuous parcel of property)
shall, as appropriate, develop separate sec-
tions of the response plan for each storage
area.
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Environmental Protection Agency
Pt. 112, App. F
/. / Emergency Response Action Plan
Several sections of the response plan shall
he co'located for easy access by response per-
sonnel during an actual emergency or oil dis-
charge. This collection of sections shall be
called the Emergency Response Action Plan.
The Agency intends that the Action Plan
contain only as much information as is nec-
essary to comhar. the discharge and be ar-
ranged so response actions are not delayed.
The Action Plan may he arranged in a num-
ber of ways. For example, the sections of the
Emergency Response Action Plan may be
photocopies or condensed versions of the
87
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Pt. 112. App. F
forms Included in the associated sections of
the response plan. Each Emergency Response
Action Plan section may be tabbed for quick
reference. The Action Plan shall be main-
tained in tlie front of the same binder that
contains the complete response plan or it
shall be contained in a separate binder. In
the latter case, both binders shall be kept to-
gether so that the entire plan can be
accessed by the qualified individual and ap-
propriate spill response personnel. The
Emergency Response Action Plan shall be
made up of the following sections:
1. Qualified Individual Information (Section
l.Z) partial
2. Emergency Notification Phone List (Sec-
tion 1.3.1) partial
3. Spill Response Notification Form (Section
1.3.1) partial
4. Response Equipment List rind Location
(Section 1.3.2) complete
5. Response Equipment Testing and Deploy-
ment (Section 1.3.3) complete
6. Facility Response Team (Section 1.3.4)
partial
7. Evacuation Plan (Section 1.3.5) condensed
8. Immediate Actions (Section 1.7.1) com-
plete
9. Facility Diagram (Section l.S) complete
1.2 Facility Information
The facility information form is designed
to provide an overview of the sile and a de-
scription of past activities at the facility.
Much of the information required by this
section may be obtained from the facility's
existing SPCC Plan.
1.2.1 Facility name- and location: Enter fa-
cility name and street address. Enter the ad-
dress of corporate headquarters only if cor-
porate headquarters are physically located
at the facility. Include city, county, state,
zip code, and phone number.
1.2.2 Latitude and Longitude: Enter the
latitude and longitude of the facility. In-
clude degrees, minutes, and seconds of the
main entrance of the facility.
1.2.3 Wellhead Protection Arra: Indicate if
the facility is located in or drains into a
wellhead protection area as defined by the
Safe Drinking Water Act of 19B6 (SDWA).1
The response plan requirements in the Well-
head Protection Program are outlined by the
1A wellhead protection area Is defined as
the surface and subsurface area surrounding
a water well or wellfleld. supplying a public
water system, through which contaminants
are reasonably likely to move toward and
reach such water well or wellfield. For fur-
ther Information regarding Slate and terri-
tory protection programs, facility owners or
operators may contact the SDWA Hotline at
1-800-426-4791.
40 CFR Ch, I (7-1-05 Edition)
State or Territory in which the facility re-
sides.
1.2.4 Owner/oprrator: Write the name of
the company or person operating the facility
and the name of the person or company that
owns the facility, if the two are different.
List the address of the owner, if the two are
different.
1.2.5 Qualified Individual: Write the name
of the qualified individual for the entire fa-
cility. If more than one person is listed, each
individual indicated In this section shall
have full authority to implement the facility
response plan, For each individual, list:
name, position, home and work addresses
(street addresses, not P.O. boxes), emergency
phone number, and specific response training
experience.
1.2 6 Date of Oil Storage Start-up: Enter the
year which the present facility first started
storing oil.
1.2.7 Current Operation: Briefly describe
the facility's operations and include the
North American Industrial Classification
System (NAICS) code.
1.2.8 Dates and Type of Substantial Expan-
sion.' Include Information on expansions that
have occurred at the facility. Examples of
such expansions include, hut are not limited
to: Throughput expansion, addition of a
product line, change of a product line, and
installation of additional oil storage capac-
ity. The data provided shall include all facil-
ity historical information and detail the ex-
pansion of the facility. An example of sub-
stantial expansion is any material alteration
of the facility which causes the owner or op-
erator of the facility to re-evaluate and in-
crease the response equipment necessary to
adequately respond to a worst case discharge
from the facility.
Date of Last Update:
FACILITY INFORMATION FORM
Facility Name:
Location (Street Address):
City: State: Zip:
County: Phone Number: ( )
Latitude: Degrees Minutes
Seconds
Longitude: Degrees Minutes
Seconds
Wellhead Protection Area:
Owner:
Owner Location (Street Address):
(if different from Facility Address)
City: State: Zip:
County: Phone Number: ( )
Operator (if not Owner):
Qualified Individual(s): (attach additional
sheets if more than one)
Name:
Position: _ __^____ __
Work Address""2_i I
Home Address:
Emergency Phone Number: ( )
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Environmental Protection Agency
Date of Oil Storage Start-up:
Current Opera t Ions:
Date(s) and Type(s) of Substantial Expan
sion(s):
(Attach additional sheets if necessary)
1.3 Emergency Response Information
(A) The Information provided In this sec-
tion shall describe what will be needed in an
actual emergency involving the discharge of
oil or a combination of hazardous substances
and oil discharge. The Emergency Response
Information section of the plan must include
the following components:
(1) The information provided in the Kmer-
gency Notification Phone List in section
1.3.1 identifies and prioritizes the names arid
phone numbers of the organizations and per-
sonnel that need to be notified immediately
in the event of an emergency. This section
shall include all the appropriate phone num-
bers for tlie facility. These numhers must l>e
verified each time the plan is updated. The
contact list must be accessible to all facility
employees to ensure that, in case of a dis-
charge, any employee on site could imme-
diately notify the appropriate patties.
(2) The Spill Response Notification Form
in section 1.3.1 creates a checklist of Infor-
mation that shall he provided to the Na-
tional Response Center (NRC) and other re-
sponse personnel. All Information on this
checklist must he known at ttie time of noti-
fication, or be in the process of being col-
lected. This notification form is based on a
similar form used hy the NRC. Note: Do not
delay spill notification to collect the infor-
mation on the list.
(3) Section 1.3.2 provides a description of
the facility's list of emergency response
equipment and location of the response
equipment. When appropriate, the amount of
oil that emergency response equipment can
handle and any limitations (e.g., launching
sites) must be described.
(4) Section 1,3.3 provides information re-
garding response equipment tests and de-
ployment drills. Response equipment deploy-
ment exercises shall be conducted to ensure
that response equipment is operational and
the personnel who would operate the equip-
ment In a spill response are capable of de-
ploying and operating it. Only a represent.a-
t ive sample of each type of response equip-
ment needs to he deployed and operated, as
long as the remainder is properly main-
tained. If appropriate, testing of response
equipment may be conducted while it is
being deployed. Facilities without facility-
owned response equipment must ensure that
the oil spill removal organization that is
Identified in the response plan to provide
this response equipment certifies that the
deployment exercises have been met. Refer
Pt. 112, App. f
to the National Preparedness for Response
Exercise Program (PREP) Guidelines (see
Appendix E to this part, section 13, for avail-
ability), which satisfy Oil Pollution Act
(OPA) response exercise requirements.
(5) Section 1.3.4 lists the facility response
personnel, including those employed hy the
facility and those under contract to the fa-
cility for response activities, the amount of
time needed for personnel to respond, their
responsibility In the case of an emergency.
and their level of response training. Three
different forms are included in this section.
The Emergency Response Personnel List
shall be composed of all personnel employed
by the facility whose duties involve respond-
ing to emergencies, including oil discharges,
even when they are not physically present at
the site. An example of this type of person
would be the Building Engineer-in-Charge or
Plant Fire Chief. The second form is a list of
the Emergency Response Contractors (both
primary and secondary) retained by the fa-
cility. Any changes in contractor status
must be reflected in updates to the response
plan. Evidence of contracts witli response
contractors shall be included in this section
so that the availability of resources can lie
verified. The last form is the Facility Re-
sponse Team List, which shall be composed
of both emergency response personnel (ref-
erenced by Job title/position) and emergency
response contractors, included in one of the
two lists described above, that will respond
immediately upon discovery of ari oil dis
charge or other emergency (i.e., the first
people to respond). These are to be persons
normally on the facility premises or primary
response contractors. Examples of these per-
sonnel would he the Facility Hazardous Ma-
terials (HAZMAT) Spill Team 1, Facility
Fire Engine Company i, Production Super-
visor, or Transfer Supervisor. Company per-
sonnel must he able to respond Immediately
and adequately if contractor support Is not
available.
(6) Section 1.3.5 lists factors that must, as
appropriate, he considered when preparing an
evacuation plan.
(7) Section 1.3.6 references the responsibil-
ities of the qualified individual for the facil-
ity in the event of an emergency.
(B) The Information provided in the emer-
gency response section will aid in the assess-
ment of the facility's ability to respond to a
worst case discharge and will identify addi-
tional assistance that may be needed. In ad-
dition, the facility owner or operator may
want to produce a wallet-size card con-
taining a checklist of the immediate re-
sponse and notification steps to he taken in
the event of an oil discharge.
1.3.1 Notification
Date of Last Update:
89
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I
Pt. 112, App. F
EMERGENCY NOTIFICATION PHO^E LIST WHOM
To NOTIFY
Reporter's Name:
Date: '
Facility Name:
Owner Name:
Facility Identification Number:
Date and Time of Each NRC Notification:
Organization
Phone No.
1. National Response Center (NRC): 1-800-424-8802
2. Qualified Individual;
Evening Phone:
3. Company Response Team
Evening Phone:
4. Federal On-Soene Coordinator (OSC)
and/or Regional Response Center
(RBC):
Evening Phone(s);
Pager Numberfs):
5. Local Response Team (Fire Dept-/Co-
operatives):
6. fire Marshall:
Evening Phone:
7. State Emergency Response Commis-
sion (SERC):
Evening Phone:
6, State Police:
9. Local Emergency Planning Committee
(LEPC);
10. Local Water Simply System.
Evening Phone:
It. Weather Report:
12. Local Television/Radio Station tor
Evacuation Notification:
13. Hospitals:
40 CFR Ch, I (7-1-05 Edition)
SPILL RESPONSE NOTIFICATION FORM
Reporter's Last Name:
First: "
M.I.:
Position;
Phone Numbers:
Day ( )
Evening ( )
Company: ^
Organization Type: __
Address:
City:
State: : . .
Zip: ._
Were Materials Discharged? _ (Y/N) Con-
fldenf-ial? (Y/N)
Meeting Federal Obligations to Report?
(Y/N) Date Called:
Calling for Responsible Party? _ (Y/N)
Time Called:
Incident Description
Source and/or Cause of Incident:
Date of Incident:
Time of Incident:
AM/PM
Incident Address/Location:
Nearest City:__ State:
County: Zip:
Distance from City: Units of Measure:
Direction from City:
Section: Township: Range:
Borough:
Container Type: Tank Oil Storage Ca-
pacity: Units of Measure:
Facility Oil Storage Capacity; Units
of Measure:
Facility Latitude: _ Degrees Min
utes Seconds
Facility Longitude: Degrees
Minutes Seconds
Material
CHRIS Code
Discharged quan-
tity
Unit 01 measure
Material Dis-
charged in water
Quantity
Unit of measure
90
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Environmental Protection Agency
Pt. 112, App. F
CHRIS Code
Un*o, measure
Quantity
Unit of measure
Response Action
Actions Taken to Correct, Control or Miti-
gate Incident:
Impact
Number of Injuries: Number of Deaths:
Were There Evacuations? (Y/N) Nutn
her Evacuated:
Was there any Damage? (Y/N)
Damage in Dollars (approximate):
Medium Affected:
Description:
More Infcjrmation about Medium:
Caller Notifications
EPA? (Y/N) USCG? (Y/N) State?
(Y/N)
Other? (Y/N) Describe:
1.3.2 Response Equipment List
Date of Last Update:
FACILITY RESPONSE EQUIPMENT LIST
1. Skimmers/Pumps—Operational Status:
Type. Model, and Year:
Type Model Year
Number:
Capacity: gal. /mi n.
Daily Effective Recovery Rate:
Storage Location(s):
Date Fuel Last Changed:
Additional Information
Any information about the incident not re-
corded elsewhere in the report:
2. Boom—Operational Status: _^
Type. Model, and Year:
Type Model Year
Number:
Size (length):
ft.
Containment Area: sq. ft.
Storage Location:
EP
Type
A's NCP Product Schedule)
Amount
Date
purchased
Treatment
capacity
Storage
location
Were appropriate procedures used to re-
ceive approval for use of dlspcrsants in ac-
cordance with the NCP (40 CFR 300.910) and
the Area Contingency Plan (ACP), where ap-
plicable? (Y/N).
Name and State of On Scene Coordinator
(OSC) authorising use: .
Date Authorized: .
4. Dispersant Dispensing Equipment—Oper-
ational Status:
Type and year
Capacity
Storage
location
Response
time
(minutes)
91
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Pt. 112, App. F
40 CFR Ch. I (7-1-05 Edition)
5. Sorhents— Operational Stati
Type and Year Purchased:
Amount:
Absorption Capacity (gal.):
Storage Location (s):
6. Hand Tools— Operational St
Type and year
7. Conimunic
era ting freque
lular phone n
Type and year
Quantity
js:
—
dtus:
Storage
location
atlon Equipment (Include op-
ficy and channel and/or eel-
umbers}— Operational Status:
Quantity
Storage location/
number
8. Fire Fighting and Personnel Protective
Equipment -Operational Status:
Type and year
Quantity
Storage
krcation
Type and year
Quantity
9. Other (e.g.. Heavy Equipni
Motors)— Operational Status:
Type and year
Quantity
Storage
location
ent. Boats and
Storage
location
1.3.3 Response Equipment Testjng.'Deploynirnt
Date of Last Update:
Response Equipment Testing and
Deployment Drill Log
Last Inspection or Response Equipment Test
Date:
Last Deployment Drill Date:
Deployment Frequency:
Oil Spill Removal Organl/aticm Certification
(if applicable):
1.3.4 Perstinin-1
Date of Last Update:
EMERGENCY RESPONSE PERSONNEL
Company Personnel
Name
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
Phone'
Response time
Responsibility during re-
sponse action
Response training type/date
1 Phone number to be used when person is not an-srte,
92
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Environmental Protection Agency
Pt. 112, App. F
EMERGENCY RESPONSE CONTRACTORS
Date of Last Update:
Contractor
1.
2.
3.
4.
Phone
Response timo
Contract responsibility1
•Include evidence ot contracts/agreements with response contractors to ensure the availability of personnel and response
equipment.
FACILITY RESPONSE TEAM
Date of Last Update:
Team member
Qualified Individual:
Response time (minutes)
Phone or pager number (day/evening)
I
1
1
1
/
1
1
1
1
1
1
1
1
1
1
1
1
I
NOTE: ff the facility uses contracted help in an emergency response situation, the owner or operator must provide the contrac-
tors' names and review the contractors' capacities to provide adequate personnel and response equipment.
93
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Pt. 112, App. F
1.3.5 Evacuation Plans
1.3.5.1 Based on the analysis of the facil-
ity, as discussed elsewhere in the plan, a fa-
cility-wide evacuation plan shall be devel-
oped. In addition plans to evacuate parts of
the facility that are at a high risk of expo-
sure in the event of a discharge or other re-
lease must be developed. Evacuation routes
must be shown on a diagram of the facility
(see section 1.9 of this appendix). When de-
veloping evacuation plans, consideration
must be given to the following factors, as ap-
propriate:
(1) Location of stored materials;
(2) Hazard imposed hy discharged material;
(3) Discharge flow direction:
(4) Prevailing wind direction and speed;
(5) Water currents, tides, or wave condi-
tions (if applicable);
(6) Arrival route of emergency response
personnel and response equipment;
(7) Evacuation routes;
(8) Alternative routes of evacuation;
(9) Transportation of injured personnel to
nearest emergency medical facility;
(10) Location of alarm/notification sys-
tems;
(11) The need for a centralized check in
area for evacuation validation (roll call);
(12) Selection of a mitigation command
center; and
(13) Location of shelter at the facility as
an alternative to evacuation.
1.3.5.2 One resource that may be helpful
to owners or operators in preparing this sec-
tion of the response plan is The Handbook of
Chemical Hazard Analysis Procedures hy the
Federal Emergency Management Agency
(FEMA), Department of Transportation
(DOT), and EPA. The Handbook of Chemical
Hazard Analysis Procedures is available from:
FEMA , Publication Office, 500 C. Street,
S.W., Washington, DC 20472. (202) 646-3484.
1.3.5.3 As specified in 5 112.20(h)(l)(vi), the
facility owner or operator must reference ex-
isting community evacuation plans, as ap-
propriate,
;.3.S Qualified Individual's Duties
The duties of the designated qualified indi-
vidual are specified in S 112.20(h)(3)(lx). The
qualified Individual's duties must be de
scribed and be consistent with the minimum
requirements in S 112.20(h)(3)(ix). In addition,
the qualified individual must be identified
with the Facility Information in section 1.2
of the response plan.
1.4 Hazard Evaluation
This section requires the facility owner or
operator to examine the facility's operations
closely and to predict where discharges could
occur. Hazard evaluation is a widely used in-
dustry practice that allows facility owners
or operators to develop a complete under-
standing of potential hazards and the re-
40 CFR Ch. I (7-1-05 Edition)
sponse ar tions necessary to address these
hazards. The Handbook of Chemical Hazard
Analysis Procedures, prepared by the EPA,
DOT, and the FEMA and the Hazardous Mate-
rials Emergency Planning Guide (NRT-1). pre-
pared by the National Response Team are
good references for conducting a hazard anal-
ysis. Hazard identification and evaluation
will assist facility owners cr operators in
planning for potential discharges, thereby
reducing the severity of discharge impacts
that may occur In the future. The evaluation
also may help the operator identify and cor-
rect potential sources of discharges. In addi-
tion, special hazards to workers and emer-
gency response personnel's health and safety
shall be evaluated, as well as the facility's
oil spill history.
1.4.1 Hazard Identification
The Tank and Surface Impoundment (SI)
forms, or their equivalent, tliat are part of
this section must be completed according to
the directions helow. {"Surface Impound-
ment" means a facility or part of a facility
which Is a natural topographic depression,
man-made excavation, or diked area formed
primarily of earthen materials (although it
may be lined with man-made materials),
which is designed to hold an accumulation of
liquid wastes or wastes containing free liq-
uids, and which Is not an injection well or a
seepage facility.) Similar worksheets, or
their equix-alent, must be developed for any
other type of storage containers.
(1) List each tank at the facility with a
separate and distinct identifier. Begin above-
ground tank identifiers with an "A" and t)e-
lowground tank identifiers with a "B", or
submit multiple sheets with the aboveground
tanks and belowground tanks on separate
sheets.
(2) Use gallons for the maximum capacity
of a tank; and use square feet for the area.
(3) Using the appropriate Identifiers and
the following instructions, fill In the appro-
priate forms:
(a) Tank or SI number—Using the afore-
mentioned identifiers (A or B) or multiple
reporting sheets, idenl ify each tank or SI at
the facility that stores oil or hazardous ma-
terials.
(b) Substance Stored—For each tank or SI
identified, record the material that is stored
therein. If the tank or SI Is used to store
more than one material, list all of the stored
materials.
(c) Quantity Stored—For each material
stored in each tank or SI, report the average
volume of material stored on any given day.
(d) Tank Type or Surface Area/Year—For
each tank, report the type of tank (e.g..
floating top), and the year the tank was
originally Installed. If the tank has been re-
fabricated, the year that the latest refabrica
tion was completed must be recorded in pa-
rentheses next to the year Installed. For
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Environmental Protection Agency
each SI, record the surface area of the im-
poundment and the year it went into service.
(e) Maximum Capacity—Record the oper
ational maximum capacity for each tank and
SI. If the maximum capacity varies with the
season, record the upper and lower limits,
(0 Failure/Cause—Record the cause and
date of any tank or SI failure which has re-
sulted in a loss of tank or SI contents,
(4) Using the numbers from the tank and
SI forms, lahel a schematic drawing of the
facility. This drawing shall he identical to
any schematic drawings Included in the
SPCC Plan.
(5) Using knowledge of the facility and its
operations, descrihe the following in writing:
(a) The loading and unloading of trr-mspor
tation vehicles that risk the discharge of oil
or release of hazardous substances during
transport processes. These operations may
include loading and unloading of trucks,
railroad cars, or vessels. Estimate the vol-
ume of material involved in transfer oper-
HAZARD IDENTIFICATION TANKS'
Date ot Last Update;
Pt. 112, App. F
ations, if the exact volume cannot he deter-
mined.
(h) Day-to-day operations tliat may
present a risk of discharging oil or releasing
a hazardous substance. These activities in-
clude scheduled venting, piping repair or re-
placement, valve maintenance, transfer of
tank contents from one tank to another, etc.
(not Including transportation-related activi-
ties). Estimate the volume of material in-
volved In these operations, if the exact vol-
ume cannot be determined,
(c) The secondary containment volume as-
sociated with each tank and/or transfer point
at the facility. The numbering scheme devel-
oped on the tallies, or an equivalent system,
must be used to identify each containment
area. Capacities must be listed for each Indi-
vidual unit (tanks, slumps, drainage traps,
and ponds), as well as the facility total.
(d) Normal dally throughput for the facil-
ity and any effect on potential discharge vol-
umes that a negative or positive change in
that throughput may cause.
Tank No.
Sutoslance Stored
(Oil and Hazardous
Substance)
Quantity Stared
(gallons)
Tank Type/Year
Maximum Capacity
(gallons)
Failure/Cause
* Tank = any container that stores oil,
Attach as many sheets as necessary.
HAZARD iDEmiFicATiON SURFACE IMPOUNOMEI^TS (Sis)
Date of Last Update:
SI No.
Substance Stored
Quantity Stored
(gallons)
Surface Area/Year
Maximum Capacity
(Sailor*)
FaJ lure/Cause
95
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40 CFR Ch. I (7-1-05 Edition)
Pt. 112, App. F
HAZARD IDEMTIFICATION SURFACE IMPOUNDMEMTS (Sis)—Continued
Date of Last Update:
SINc.
Substance Stored
Quantity Stored
(gallons)
Surface Area/Year
Maximum Capacity
(gallons)
Failure/Cause
Attach as many sheets as necessary.
;. 4.2 Vulnerability Analysis
The vulnerability analysis shall address
the potential effects {I.e., to human health,
property, or the environment) of an oil dis-
charge. Attachment C-111 to Appendix C to
this part provides a method that owners or
operators shall use to determine appropriate
distances from the facility to fish and wild-
life and sensitive environments. Owners or
operators can use n comparable formula that
is considered acceptable by the KA. If a com-
parable formula is used, documentation of
the reliability arid analytical soundness of
the formula must be attached to the re-
sponse plan cover sheet. This analysis must
be prepared for each facility and, as appro-
priate, must discuss the vulnerability of:
(1) Water Intakes (drinking, cooling, or
other);
(2) Schools;
(3) Medical facilities;
(4) Residential areas;
(5) Businesses;
<6) Wetlands or other sensitive environ-
ments; 2
(7) Fish and wildlife;
(8) Lakes and streams;
(9) Endangered flora and fauna;
(10) Recreational areas;
(11) Transportation routes (air. land, and
water);
(12) Utilities; and
(13) Other areas of economic importance
(e.g.. beaches, marinas) including terrestri-
ally sensitive environments, aquatic envi-
ronments, and unique habitats.
1.4.3 Analysis of the Potential for an Oil
Discharge
Each owner or operator shall analyze the
probability of a discharge occurring at the
facility. This analysis shall Incorporate fac-
tors such as oil discharge history, horizontal
range of a potential discharge, arid vulner-
ability to natural disaster, and shall, as ap-
propriate, incorporate other factors such as
tank age. This analysis will provide Informa-
tion for developing discharge scenarios for a
worst case discharge and small arid medium
discharges and aid in the development of
techniques to reduce the size and frequency
of discharges. The owner or operator may
need to research the age of the tanks the oil
discharge history at the facility.
1.4.4 Facility Reportabk Oil Spill History
Briefly describe ihe facility's reportablc
oil spill3 history for the entire life of the fa-
cility to the extent that such information is
reasonably identifiable, Including:
(1) Date of dlscharge(s);
(2) List of discharge causes;
(3) Materlal(s) discharged;
(4) Amount discharged in gallons;
(5) Amount of discharge that reached navi-
gable waters, if applicable:
(6) Effectiveness and capacity of secondary
containment;
(7) Clean up actions taken;
(8) Steps taken to reduce possibility of re-
currence:
(9) Total oil storage capacity of the tank(s)
or impoundment(s) from which the material
discharged;
(10) Enforcement actions:
(11) Effectiveness of monitoring equip-
ment; arid
(12) Descriptlon(s) of how each oil dis-
charge was detected.
2 Refer to the DOC/NOAA "Guidance for
Facility and Vessel Response Plans: Fish arid
Wildlife and Sensitive Environments" (See
appendix E to this part, section 13, for avail
ability).
3As described in 4(1 CFR pan: 110, report-
able oil spills are those that: (a) violate ap
plicable water quality standards, or (b) cause
a fllm or sheen upon or discoloration of the
surface of the water or adjoining shorelines
or cause a sludge or emulsion to be deposited
beneath the surface of the water or upon ad-
joining shorelines.
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Environmental Protection Agency
The Information solicited in this sen Ion
may lie similar to requirements in 40 CFR
112.4(a). Any duplicate Information required
hy § 112.4{a) may he photocopied arid inserted.
1.5 Discharge Scenarios
In this section, the owner or operator is re-
quired to provide a description of the facili-
ty's worst case discharge, as well as a small
and medium discharge, as appropriate. A
multi level planning approach has been cho-
sen because the response actions to a dis-
charge (i.e.. necessary response equipment.
products, and personnel) are dependent on
the magnitude of the discharge. Planning for
lesser discharges is necessary because the
nature of the response rimy be qualitatively
different depending on the quantity of the
discharge. The facility owner or operator
shall discuss the potential direction of the
discharge pathway.
1.5.1 Small and Medium Discharges
1.5.1.1 To address multi-level planning re-
quirements, the owner or operator must con-
sider types of facility-specific discharge sce-
narios that may contribute to a small or me-
dium discharge. The scenarios shall account
for all the operations that take place at the
facility, including but not limited to:
(1) Loading and unloading of surface trans-
portation;
(2) Facility maintenance;
(3) Facility piping;
(4) Pumping stations and sumps;
(5) Oil storage tanks;
(6) Vehicle refueling; and
(7) Age and condition of facility and com-
ponents.
1.5.1.2 The scenarios shall also consider
factors that affect the response efforts re-
quired by the facility. These include but are
not limited to;
(1} Size of the discharge;
(2) Proximity to downgradlent wells, wa-
terways, and drinking water intakes;
(3) Proximity to fish and wildlife and sen-
sitive environments;
(4) Likelihood that the discharge will trav-
el offsite (i.e.. topography, drainage);
(5) Location of the material discharged
(i.e.. on a concrete pad or directly on the
soil);
(6) Material discharged;
(7) Weather or aquatic conditions (i.e..
river flow):
(8) Available remediation equipment;
(a) Probability of a chain reaction of fail
ures: and
(10) Direction of discharge pathway.
l.i.Z Worst Case Discharge
1.5.2.1 In this section, the owner or oper-
ator must identify the worst case discharge
volume at the facility. Worksheets for pro-
duel ion and non production facility owners
Pt. 112,App. f
or operators to use when calculating worst
case discharge are presented in Appendix D
to this part. When planning for the worst
case discharge response, all of the aforemen-
tioned factors listed In the small and me-
dium discharge section of the response plan
shall he addressed.
1.5.2.2 For onshore storage facilities and
production facilities, permanently
manifolded oil storage tanks are defined as
tanks that are designed, installed, and/or op-
erated in such a manner that the multiple
tanks function as one storage unit (i.e.. mul-
tiple tank volumes are equalized). In this
section of the response plan, owners or oper-
ators must provide evidence that oil storage
tanks with common piping or piping systems
are not operated as one unit. If such evidence
is provided and is acceptable to the RA, the
worst case discharge volume shall be based
on the combined oil storage capacity of all
manifold tanks or the oil storage capacity of
the largest single oil storage tank within the
secondary containment area, whichever is
greater. For permanently manifolded oil
storage tanks that function as one storage
unit, the worst case discharge shall be based
on the combined oil storage capacity of all
manifolded tanks or the oil storage capacity
of the largest single tank within a secondary
containment area, whichever is greater. For
purposes of the worst case discharge calcula-
tion, permanently manifolded oil storage
tanks that are separated by internal divi-
sions for each tank are considered to be sin-
gle tanks and individual manifolded tank
volumes are not combined.
1.6 Discharge Detection Systems
In this section, the facility owner or oper-
ator shall provide a detailed description of
the procedures and equipment used to detect
discharges. A section on discharge detection
by personnel and a discussion of automated
discharge detection, if applicable, shall be
included for both regular operations and
after hours operations. In addition, the facil-
ity owner or operator shall discuss how the
reliability of any automated system will be
checked and how frequently the system will
be inspected.
1.6.1 Discharge Detection by Personnel
In this section, facility owners or opera-
tor's shall describe the procedures and per-
sonnel that will detect any discharge of oil
or release of a hazardous substance. A thor-
ough discussion of facility inspections must
be included. In addition, a description of ini-
tial response actions shall he addressed. This
section shall reference section 1.3.1 of the re-
sponse plan for emergency response informa-
tion.
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Pt. 112, App. F
1,6.2 Automated Dlsrharge Detection
In this section, facility owners or opera-
tors must describe any automated discharge
detection equipment that the facility lias in
place. This section shall include a discussion
of overfill alarms, secondary containment
sensors, etc. A discussion of the plans to
verify an automated alarm and the actions
to be taken once verified must also he in-
cluded.
1.7 Flan Implementation
In this section, facility owners or opera-
tors must explain in detail how to Imple-
ment the facility's emergency response plan
by describing response actions to be carried
out under the plan to ensure the safety of
the facility and to mitigate or prevent dis-
charges described In section 1.5 of the re-
sponse plan. This section shall Include the
identification of response resources for
small, medium, and worst case discharges;
disposal plans; and containment and drain-
age planning. A list of those pe;n>onnel who
would he involved in the cleanup shall he
identified. Procedures that the facility will
use, where appropriate or necessary, to up-
date their plan after an oil discharge event
and the time frame to update the plan must
be described.
/. 7. / Response Resources far Small. Medium.
and Worst Case Discharages
1.7.1.1 Once the discharge scenarios have
been identified in section 1.5 of the response
plan, the facility owner or operator shall
identify and describe implementation of the
response actions. The facility owner or oper-
ator shall demonstrate accessibility to the
proper response personnel and equipment to
effectively respond to all of the identified
discharge scenarios. The determination and
demonstration of adequate response capa-
bility are presented in Appendix E to this
part. In addition, steps to expedite the clean-
up of oil discharges must he discussed. At a
minimum, the following Items must be ad-
dressed:
(1) Emergency plans for spill response;
(2) Additional response training;
{3} Additional contracted help;
(4) Access to additional response equip-
ment/experts: and
(5) Ability to implement the plan including
response training and practice drills.
1.7.1.2A recommended form detailing im-
mediate actions follows.
OIL SPILL RESPONSE—IMMEDIATE ACTIONS
1. Stop the product flow
Act quickly to secure
pumps, close valves,
etc.
40 CFR Ch. I (7-1-05 Edition)
OIL SPILL RESPONSE—IMMEDIATE ACTIONS—
Continued
2. Warn personnel
3. Shut off ignition
sources.
4. Initiate containment
5. Notify NRC
6. Notify OSC
7. Notify, as appropriate
Enforce safety and secu-
rity measures.
Motors, electrical circuits,
open flames, etc.
Around the tank and/or in
the water with oil
boom.
1-800-424-8802
Source: FOSS, Oil Sprll Response—Emergency Proce-
dures, Revised December 3, 1992.
1.7.2 Disposal Mans
1.7.2.1 Facility owners or operators must
describe how and where the facility intends
co recover, reuse, decontaminate, or dispose
of materials after a discharge has taken
place. The appropriate permits required to
transport or dispose of recovered materials
according to local. State, and Federal re-
quirements must be addressed. Materials
that must he accounted for in the disposal
plan, as appropriate. Include:
{1} Recovi.-red product:
(2) Contaminated soil;
(3) Contaminated equipment and mate-
rials, including drums, tank parts, valves,
and shovels;
(4) Personnel protective equipment;
(5) decontamination solutions:
(6) Adsorbents; and
(7) Spent chemicals.
1.7.2.2 These plans must he prepared in ac-
cordance with Federal (e.g., the Resource
Conservation and Recovery Act (RCRAJ),
State, and local regulations, where applica-
ble, A copy of the disposal plans from die fa-
cility's SPCC Plan may be Inserted with this
section, including any diagrams In those
plans.
Material
1.
2.
3
4.
Disposal fa-
cility
Location
RCRA per-
mit/manifest
1.7.3 Containment and Drainage Planning
A proper plan to contain and control a dis-
charge through drainage may limit the
threat of harm to human health and the en-
vironment. This section shall describe how
to contain and control a discharge through
drainage, including:
98
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Environmental Protection Agency
(1) The available volume of containment
(use the information presented in section
1.4.1 of the response plan);
(2) The route of drainage from oil storage
and transfer areas;
(3) The construction materials used in
drainage troughs;
(4) The type arid number of valves arid sep-
arators used in the drainage system;
(5) Sump pump capacities;
(6) The containment capacity of weirs and
booms that might he used and their location
(see section 1.3.2 of this appendix); and
(7) Other cleanup materials.
In addition, a facility owner or operator
must meet the inspection and monitoring re-
quirements for drainage contained in 40 CFR
part 112, subparts A through C. A copy of the
containment and drainage plans that are re-
quired in 40 CFR part 112. suhparts A
through C may he inserted in this section,
including any diagrams in those plans.
N'OTK: The general permit for stormwater
drainage may contain additional require-
ments.
l.S Seif-lnspecUan, Drills/Exercises, and
Response Training
The owner or operator must, develop pro-
grams for facility response training and for
drills/exercises according to the require-
ments of 40 Cf'R 112.21. Logs must he kept for
facility drills/exercises, personnel response
training, and spill prevention meetings.
Much of the recordkeeplng information re-
quired by this section Is also contained in
the SPCC Plan required hy 40 CFR 112.3.
These logs may be included in the facility re-
sponse plan or kept as an annex to the facil-
ity response plan.
1.8.1 Facility Self-lniptntion
Under 40 CFR H2.7(e), you must include
the written procedures and records of Inspec-
tions for each facility in the SPCC Plan. You
must include the Inspection records I'or e
-------
Pt. 112, App. F 40 CFR Ch. I (7-1-05 Edition)
TANK/SURFACE IMPOUNDMENT INSPECTION LOG—Continued
Tank or SI*
Dale
1.8,1,2 Response Equipment Inspection
Using the Emergency Response Equipment
List provided in section 1.3.2 of the response
plan, describe each type of response equip-
ment, checking for the following:
Response Equipment Checklist
1. Inventory (item and quantity);
2. Storage location;
3. Accessibility (time tc access and re-
spond);
4. Operational status/condition;
5. Actual use/testing (last test date and fre-
quency of testing); and
6. Sliflf life (present age, expected replace-
ment date).
Please note any discrepancies between this
list and the available response equipment.
RESPONSE EQUIPMENT INSPECTION LOG
'Use section 1.3.3 ot the response plan as a checklist]
Inspector
Comments
100
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Environmental Protection Agency
Pt. 112, App. F
RESPONSE EauiPMEr^rr INSPECTION LOG—Continued
[Use section 1.3.2 at (he response plan as a checklist]
Inspector
I.S.I.3 Secondary Containment Inspectinri
Inspect tlie secondary containment (as de
scribed in sections 1.4.1 and 1.7.2 of the re-
sponse plan), checking the following:
Secondary Containment Ch<:rklist
1. Dike or berm system.
A Level of precipitation in dike/available
capacity;
B. Operational status of drainage valves;
C. Dike or herm permeability;
U. Debris;
E. Erosion;
K. Permeability of the earthen floor of
diked area: and
C,. Location/status of pipes, inlets, drain-
age beneath tanks, etc.
2. Secondary containment
A. Cracks;
B. Discoloration;
C. Presence of spilled or leaked material
(standing liquid);
D. Corrosion; and
t. Valve conditions.
3. Retention and drainage ponds
A. Erosion;
B. Available capacity;
C. Presence of spilled or leaked material;
D. Debris: and
E. Stressed vegetation.
The tank inspection checklist presented
below has been Included as guidance during
inspections and monitoring. Similar require-
ments exist in 40 CFR part 112, subparts A
through C. Similar requirements exist in 40
CFR 112.7(e). Duplicate information from the
SPCC Plan may be photocopied and inserted
in this section.
1.11.2 F.-nility Drills/Exercises
(A) CWA section 311(j)(5). as amended by
OPA, requires the response plan to contain a
description of facility drills/exercises. Ac-
cording to 40 CFR 112.Zl(c). the facility
owner or operator shall develop a program of
facility response drills/exercises, including
evaluation procedures. Following the PREP
guidelines (see Appendix E to tills part, sec-
tion 13. for availability) would satisfy a fa-
cility's requirements for drills/exercises
under this part. Alternately, under §112.ZI(c).
a facility owner or operator may develop a
program that Is not based on the PREP
guidelines. Such a program is subject to ap-
proval by the Regional Administrator based
on the description of the program provided
in the response plan.
(B) The PREP Guidelines specify that the
facility conduct internal and external drills/
exercises. The internal exercises include:
qualified individual notification drills, spill
management team tahletop exercises, equip-
ment deployment exercises, and unan-
nounced exercises. External exercises in-
clude Area Exercises. Credit for an Area or
Facility-specific Exercise will he given to
the facility for an actual response to a dis-
charge in the area if the plan was utilized for
response to the discharge and the objectives
of the Exercise were met and were properly
evaluated, documented, and self-certified.
(C) Section 112.20(h)(8)(ii) requires the fa-
cility owner or operator to provide a descrip-
tion of the drill/exercise program to be car-
ried out under the response plan. Qualified
Individual Notification Drill and Spill Man-
agement Team Tabletop Drill logs shall he
provided In sections 1.8.2.1 and 1.8.2.2. respec-
tively. These logs may be included in the fa-
cility response plan or kept as an annex to
the facility response plan. See section 1.3.3 of
this appendix for Equipment Deployment
Drill Logs.
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Pt. 112, App. F
1.8.2.1 Qualified Iruiividual Notifiuition Drill
Log;.
Qualified Individual Notification Drill Log
Date:
Company:
Qualified Individual(s): ~I ^
Emergency Scenario:
Evaluation:
Changes to be Implemented:
Time Table for Implementation: ___
1.S.Z.2 SpillManagement Team Tabletop
Exercise Logs
Spill Management Team Tabletop Exercise
Log
Date:
Company: .
Qualified Individuals): ~__^
Emergency Scenario:
Evaluation:
40 CFR Ch. I (7-1-05 Edition)
Changes to be Implemented:
Time Table for Implementation:
1.8.3 Response Training
Section iU.21(a) requires facility owners or
operators to develop programs for facility re-
sponse training Facility owners or operators
are required by S 112.2(>(h)(8)(iii) to provide a
description of the response training program
to be carried out under the response plan. A
facility's training program can be based on
the USCG's Training Elements for Oil Spill
Response, to the extent applicable to facility
operations, or another response training pro-
gram acceptable to the RA. The training ele-
ments are available from the USCG Office of
Response (G-MOR) at (202) 267-0518 or fax
(202) 267-4085. Personnel response training
logs and discharge prevention meeting logs
shall be included in sections 1.8.3.1 and 1.8.3.2
tjf the response plan respectively. These logs
may he included in the facility response plan
or kept as an annex to the facility response
plan.
1.8.3.1 Personnel Response Training Logs
PERSONNEL RESPONSE TRAINING LOG
Name
Response training/date and numbei of
hours
PreventK>n training/data and number of
hours
l.S.3.2 Discharge Prevention Meetings Logs
DISCHARGE PREVENTION MEKTING Loc
Date: __,
Attendees:
102
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Environmental Protection Agency
Pt. 112, App. F
Subject/issue identified
Required action
Implementation date
1.9 Diagrams
The facility-specific; response plan shall In-
clude the following diagrams. Additional dia-
grams that would aid in the development of
response plan sections may also be included.
(I) The Site Plan Diagram shall, as appro-
priate, include and identify:
(A) the entire facility to scale;
(B) above and below ground hulk oil stor-
age tanks;
(C) the contents and capacities of hulk oil
storage tanks;
(D) the contents arid capacity of drum oil
storage areas;
(E) the contents and capacities of surface
impoundments;
(F) process buildings;
(G) transfer areas;
(H) secondary containment systems (loca-
tion and capacity);
(1) structures where hazardous materials
are stored or handled, including mate-
rials stored and capacity of storage;
(J) location of communication and emer-
gency response equipment;
(K) location of electrical equipment which
contains oil; and
(L) for complexes only, the Interface(s)
(i.e., valve or component) between the
portion of the facility regulated by EPA
and the portion (s) regulated by other
Agencies. In most cases, this interface is
defined as the last valve inside secondary
containment before piping leaves the sec-
ondary containment area to connect to
the transportation related portion of the
facility (i.e.. the structure used or in-
tended to he used to transfer oil to or
from a vessel or pipeline). In the absence
of secondary containment, this interface
Is the valve manifold adjacent to the
tank nearest the transfer structure as de-
scribed above. The interface may be de-
fined differently at a specific facility if
agreed to by the RA and the appropriate
Federal official.
(2) The Site Drainage Plan Diagram shall, as
appropriate, include:
(A) major sanitary and storm sewers, man-
holes, and drains;
(B) weirs and shut-off valves;
(C) surface water receiving streams;
(D) fire fighting water sources;
(E) other utilities;
(F) response personnel Ingress and egress;
(G) response equipment transportation
routes; and
{HJ direction of discharge flow from dis-
charge points.
(3) The Site Evacuation Plan Diagram shall,
as appropriate, include;
{A) site plan diagram with evacuation
rcmre(s); and
(B) location of evacuation regrouping
areas.
1.10 Security
According to 40 CFR 112.7(g) facilities are
required to maintain a certain level of secu-
rity, as appropriate. In this section, a de-
scription of the facility security shall be pro
vided and include, as appropriate:
(1) emergency cut-off locations (automatic
or manual valves);
(2) enclosures (e.g., fencing, etc.);
(3) guards and their duties, day and night;
(4) lighting;
(5) valve and pump locks; and
(6) pipeline connection caps.
The SPCC Plan contains similar informa-
tion. Duplicate information may he
photocopied and inserted in this section.
2.0 Response Plan Cover Sheet
A three-page form lias been developed to he-
completed and submitted to the RA by own-
ers or operators who are required to prepare
and submit a facility-specific response plan.
The cover sheet (Attachment F-l) must ac-
company the response plan to provide the
Agency with basic information concerning
the facility. This section will describe the
Response Plan Cover Sheet arid provide in-
structions for its completion.
2.1 General Information
Owner/Operator of Facility: Enter the name
of the owner of the facility (if the owner is
the operator). Knter the operator of the fa-
cility If otherwise. If the owner/operator of
103
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Pt. 112, App. F
the facility is a corporation, erittr the name
of the facility's principal corporate execu-
tive. Enter as much of the namo as will fit In
each section.
(1) Facility Name: Enter the proper name of
the facility.
(2) Facility Address: Enter the street ad-
dress, city, State, and zip code.
(3) Facility Phone Number: Enter the phone
number of the facility.
(4) Latitude and Longitude: Enter the facil-
ity latitude and longitude in degrees, min-
utes, arid seconds.
(5) Dun and Bradstreel Number: Enter the
facility's Dun and Bradstreet number if
available (this information may he obtained
from public library resources).
(6) North American industrial Classifica-
tion System (NAICS) Code: Enter the facili-
ty's NAICS code as determined by the Office
of Management and Budget (this information
may he obtained from public library re-
sources.)
(7) Largest Oil Storage Tank Capacity: Enter
the capacity in GALLONS of the largest
aboveground oil storage tank at: the facility.
(8) Maximum Oil Storage Capacity: Enter the
total maximum capacity in GALLONS of all
ahovegrounti oil storage tanks at the facil-
ity.
(9) Number of Oil Storage Tanks: Enter the
number of all aboveground oil storage tanks
at the facility.
(10) Wont Case Discharge Amount: Using in-
formation from the worksheets in Appendix
D, enter the amount, of the worst case dis-
charge in GALLONS.
(11) Facility Distance to Navigable Waters:
Mark the appropriate line for the nearest
distance between an opportunity for dis-
charge (i.e.. oil storage tank, piping, or
flowline) and a navigable water.
2,2 Applicability of Substantial Harm Criteria
Using the flowchart provided in Attach-
ment C-I to Appendix C to this part, mark
the appropriate answer to each question. Ex-
planations of referenced terms can be found
in Appendix C to this part. If .1 comparable
formula to the ones described In Attachment
C-III to Appendix C to this part Is used to
calculate the planning distance, documenta-
tion of the reliability and analytical sound-
ness of the formula must be attached to the
response plan cover sheet.
2.3 Certification
Complete this Mock after all other ques-
tions have been answered.
3.0 Acronyms
ACP; Area Contingency Plan
ASTM: American Society of Testing Mate-
rials
bbls: Barrels
hpd: Barrels per Day
40 CFR Ch. I (7-1-05 Edition)
bph: Barrels per Hour
CHRIS: Chemical Hazards Response Informs
tlciii System
CWA: Clean Water Act
DO1: Department of Interior
DOC: Department of Commerce
DOT: Department of Transportation
EPA: Environmental Protection Agency
FEMA: Federal Emergency Management
Agency
FR: Federal Register
gal: Gallons
gprn: Gallons per Minute
HAZMAT: Hazardous Materials
LEPC: Local Emergency Planning Com-
mittee
MMS: Minerals Management Service (part of
D01)
NAICS: North American Industrial Classi-
fication System
NCP: National Oil and Hazardous Substances
Pollution Contingency Plan
NOAA: National Oceanic and Atmospheric
Administration (part of DOC)
NRC: National Response Center
NRT: National Response Team
OPA: Oil Pollution Act of 1990
OSC: On-Scene Coordinator
PREP: National Preparedness for Response
Exercise Program
RA: Regional Administrator
RCRA: Resource Conservation arid Recovery
Act
RRC: Regional Response Centers
RRT: Regional Response Team
RSPA: Research and Special Programs Ad-
ministration
SARA: Superfutid Amendments and Reau-
thnrlzation Act
SERC: State Emergency Response Commis-
sion
SDWA: Safe Drinking Water Act of 1986
SI: Surface Impoundment.
SPCC: Spill Prevention, Control, and Coun-
termeasures
USCG: United States Coast Guard
4.0 References
CONCAWE, 1982. Methodologies for Hazard
Analysis and Risk Assessment In the Petro-
leum Refining and Storage Industry. Pre-
pared by CONCAWE's Risk Assessment Ad-
hoc Group.
U.S. Department of Housing arid Urban De-
velopment. 1987. Siting of HUD-Assisted
Projects Near Hazardous Facilities: Accept-
able Separation Distances from Explosive
and Flammable Hazards. Prepared by the Of-
fice of Environment and Energy, Environ-
mental Planning Division. Department of
Housing and Urban Development. Wash-
ington, DC.
U.S. DOT, FEMA and U.S. EPA. Handbook
of Chemical Hazard Analysis Procedures.
U.S. DOT, FEMA and U.S. EPA. Technical
Guidance lor Hazards Analysis: Emergency
104
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Environmental Protection Agency
Planning for Extremely Hazardous Sub
stances.
The National Response Team. 1S87. Ha/
ardous Materials Emergency Planning
Guide. Washington. DC.
The National Response Team. 1990. Oil
Spil! Contingency Planning, National Sta-
tus: A Report to the President. Washington.
DC. U.S. Government Printing Office.
Offshore Inspection arid Enforcement Divi-
sion. 1988. Minerals Management Service.
Offshore Inspection Program: National Po-
tential Incident of Noncomplianre (PJNC)
List. Reston. VA.
ATTACHMENTS TO APPENDIX f-
Attachment F-l—Response Plan Cover Sheet
This rover sheet will provide KPA with
basic information concerning the facility. It
must acxompany a submitted facility re
spouse plan. Explanations and detailed In
structions can he found in Appendix F.
Please type or write legibly in blue or black
ink. Public reporting burden for the coller-
tion of this Information is estimated to vary
from 1 hour to 270 hours per response in the
first year, with an average of 5 hours per re-
sponse. This estimate includes time for re
viewing Instructions, searching existing data
sources, gathering the data needed, and coin
pleting and reviewing the collection of infor-
mation. Send comments regarding the bur-
den estimate of this information, including
suggestions for reducing this burden to:
Chief, Information Policy Branch, Mail Code:
PM-2822, U.S. Environmental Protection
Agency, Ariel Rlos Building, 1200 Pennsyl
vania'Avenue, NW., Washington, DC 20461);
and to the Office of Information and Regu
latory Affairs, Office of Management and
Budget. Washington D.C. 20503.
GENERAL INFORMATION
Owner/Operator of Facility:
Facility Name:
Facility Address (street address or route):
City. State, and U.S. Zip Code:
Facility Phone No.:
Latitude (Degrees: North):
degrees, minutes, seconds
Dun & Bradstreet Number: '
Largest Aboveground Oil Storage Tank Ca
pacity (Gallons):
Pt. 112, App. F
Number of Abovegrounri Oil Storage Tanks:
Longitude (Degrees: West):
degrees, minutes, seconds
North American Industrial Classification
System (NAICS) Code: '
Maximum Oil Storage Capacity (Gallons):
Worst Case Oil Discharge Amount (Gallons):
Facility Distance to Navigable Water, Mark
the appropriate line,
0- V< mile Vt-Vi mile '/z-1 mile >1
mile
APPLICABILITY OF SUBSTANTIAL HARM
CRITERIA
Does the facility transfer oil over-water2
to or from vessels arid does the facility have
a total oil storage capacity greater than or
equal to 42,000 gallons?
Yes
No
Does the facility have a total oil storage
capacity greater than or equal to 1 million
gallons and. within any storage area, does
the facility lark secondary containment 2
that is sufficiently large to contain the ca-
pacity of the largest ahoveground oil storage
tank plus sufficient freeboard to allow for
precipitation?
Yes
No
Does the facility have a total oil storage
capacity greater than or equal to 1 million
gallons and is the facility located at a dis-
tance l (as calculated using the appropriate
formula in Appendix C or a comparable for-
mula) such that a discharge from the facility
could cause injury *o fish and wildlife and
sensitive environments?11
Yes .. .__.._
No
Does the facility have a total oil storage ca-
parity greater than or equal to 1 million
'These numbers may he obtained from pub
lie library resources.
2 Explanations of the above-referenced
terms can lie found in Appendix C to this
part. If a comparable formula to the ones
contained in Attachment C-II1 is used to es-
tablish the appropriate distance to fish and
wildlife and sensitive environments or public
drinking water intakes, documentation of
the reliability and analytical soundness of
the formula must be attached to this form.
3For further description offish and wildlife
and sensitive environments, see Appendices
I, II, and HI to DOC/NOAA's "Guidance for
Facility and Vessel Response Plans: Fish and
Wildlife and Sensitive Environments" (see
Appendix E to this part, section 13, for avail-
ability) and the applicable ACP.
105
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Pt. 113
gallons and is the facility located at a dis-
tance2 (as calculated using the appropriate
formula in Appendix C or a comparable for-
mula) such that a discharge from the facil
ity would shut down a public drinking
water Intake?2
Yes
No
Does the facility have a total oil storage
capacity greater than or equal to 1 million
gallons and has the facility experienced a re-
portable oil spill >' In an amount greater than
or equal to 10,000 gallons within the last 5
years?
Yes .
No
CERTIFICATION
1 certify under penalty of law that 1 have
personally examined and am familiar with
the information submitted in this document.
and that hased on my inquiry of those indi-
viduals responsible for obtaining informa-
tion, I believe that the submitted Informa-
tion is true, accurate, and complete.
Signature:
Name (Please type or prim.): ._
Title:
Date: ,
159 FR 34122, July 1, 1994; 59 FR 49006. Sept.
26. 1994. as amended at 65 FR 40816. June 30.
2000; 65 FR 43840, July 14, 2000; 66 FR 34561.
June 29. 2001; 67 FR 47152, July 17, 2002)
PART 113—LIABILITY LIMITS FOR
SMALL ONSHORE STORAGE
FACILITIES
Sec.
113.1
113.2
113.3
113.4
Subport A—Oil Storage Facilities
Purpose.
Applicability.
Definitions.
Size classes and associated liability
limits for fixer) onshore oil storage facili-
ties, l.GOO barrels or less capacity.
113.5 Exclusions.
113.8 Effect on other laws.
AUTHORITY: Sec. 311(0(2). 86 Stat. 867 (33
U.S.C. 1251 (1972))
SOURCE: 38 FR 25440. Sept. 13, 1973. unless
otherwise noted.
Subport A—Oil Storage Facilities
§ 113.1 Purpose.
This subpart establishes size classi-
fications and associated liability limits
40 CFR Ch. I (7-1-05 Edition)
for small onshore oil storage facilities
with fixed capacity of 1,000 barrels or
less.
§113.2 Applicability.
This subpart applies to all onshore
oil storage facilities with fixed capac-
ity of 1,000 barrels or less. When a dis-
charge to the waters of the United
States occurs from such facilities and
when removal of said discharge is per-
formed by the United States Govern-
ment pursuant to the provisions of sub-
section 311(c)(l) of the Act, the liability
of the owner or operator and the facil-
ity will be limited to the amounts spec-
ified in §113.4.
§113.3 Definitions.
As used in this subpart. the following
terms shall have the meanings indi-
cated below:
(a) Aboveground storage facility
means a tank or other container, the
bottom of which is on a plane not more
than 6 inches below the surrounding
surface.
(b) Act means the Federal Water Pol-
lution Control Act, as amended, 33
U.S.C. 1151, etseq.
(c) Barrel means 42 United States gal-
lons at 60 degrees Fahrenheit.
(d) Belowground storage facility
means a tank or other container lo-
cated other than as defined as "Above-
ground".
(e) Discharge includes, but is not lim-
ited to any spilling, leaking, pumping,
pouring, emitting, emptying or dump-
ing.
(f) Onshore Oil Storage Facility means
any facility (excluding motor vehicles
and rolling stock) of any kind located
in, on, or under, any land within the
United States, other than submerged
land.
(g) On-Scene Coordinator is the single
Federal representative designated pur-
suant to the National Oil and Haz-
ardous Substances Pollution Contin-
gency Plan arid identified in approved
Regional Oil and Hazardous Substances
Pollution Contingency Plans.
(h) Oil means oil of any kind or in
any form, including but not limited to,
petroleum, fuel oil. sludge, oil refuse,
and oil mixed with wastes other than
dredged spoil.
106
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Appendix C: Summary of Revised Rule Provisions
APPENDIX C: SUMMARY OF REVISED SPCC RULE PROVISIONS
Citation
New Threshold
Requirement
§112.1(d)(2)(i)
and (ii)
Underground
Storage Tanks
(USTs)
§112.1(d)(2)(i)and
112.1
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SPCC Guidance for Regional Inspectors
Citation
Oil-Filled Equipment
§112.2
Professional
Engineer (PE)
Certification
§112.3(d)
Plan Location
§112.3(e)(1)
Reportable
Discharge
Notification to EPA
Regional
Administrator (RA)
for SPCC facilities
§112.4
Five-Year Review
Documentation
§112.5(b)and
112.5(c)
Alternative Formats
§112.7
Revised Rule Provision
Oil-filled electrical, operating, and manufacturing equipment does not need to meet the
requirements for bulk storage containers (§112.8) as this equipment is excluded from
the definition of a "bulk storage container." However, this equipment does need to
meet other provisions of the rule, including secondary containment as described in
§112.7(C).
Change from 1974 rule: Clarification on the application of the rule to this type of
equipment.
In order for a facility to comply with the provisions of §1 12.3(d), a licensed Professional
Engineer (PE) must attest to the following:
i. The PE is familiar with 40 CFR part 112;
ii. The PE or his agent has visited and examined the facility;
iii. The Plan has been prepared in accordance with good engineering practice,
including consideration of industry standards and the requirements of the rule;
iv. Procedures for required inspections and testing have been established; and
v. The Plan is adequate for the facility.
Change from 1974 rule: The previous rule required a PE to attest that, through the
examination of the facility and familiarity with the provisions of the rule, the Plan was
prepared in accordance with good engineering practice.
The owner or operator must maintain a complete copy of the Plan at the facility if the
facility is normally attended at least four hours per day.
Change from 1974 rule: The rule previously required a Plan to be located at the
facility if it was attended for at least eight hours per day.
Whenever a facility has a discharge as described in §1 12.1 (b) that is greater than
1 ,000 gallons of oil or two discharges each of more than 42 gallons of oil occurring
within any 12-month period, the facility must submit certain information regarding the
spill to the RA. The SPCC Plan does not need to be submitted unless requested by the
RA.
Change from 1974 rule: Previously, the SPCC Plan was submitted to the RA as part
of the reporting requirement, and there was a different threshold for SPCC spill
reporting. Note: The basic oil discharge reporting requirements for 40 CFR 110 (spills
reportable to the National Response Center) did not change.
The period in which an owner or operator is required to review and evaluate the SPCC
Plan is now five years. The review and evaluation must be documented, and a
statement must be signed stating whether or not the Plan will be amended. Note: The
review and evaluation do not require a Professional Engineer (PE) certification.
However, any technical changes to the Plan do require a PE certification.
Change from 1974 rule: The review period was previously three years
The Plan must be in writing, and if the Plan does not follow the sequence specified in
the rule, an equivalent plan and a cross-reference must be provided. For example, the
owner/operator may use an Integrated Contingency Plan (ICP) or an equivalent state
plan that includes all applicable SPCC requirements with a cross-reference.
Change from 1974 rule: No direct counterpart for alternative plan formats in the 1 974
rule.
U.S. Environmental Protection Agency
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Appendix C: Summary of Revised Rule Provisions
Citation
Spill History
Previously
§112.7(a)
Environmental
Equivalence
§112.7(a)(2)
Facility Diagram
§112.7(8X3)
Information for Use
in a Discharge
§112.7(8X3)
Information for Use
in a Discharge
§112.7(a)(4)and
112.7(a)(5)
Secondary
Containment
§112.7(c)
Impracticability
Claim/Integrity
Testing
§112.7(d)
Revised Rule Provision
Spiil history does not need to be reported. Note: Facility Response Plans (FRPs) are
still required to include a spill history.
Change from 1974 rule: The previous rule required a spill history for reportable
discharges, including corrective actions and preventive measures for spills occurring
before the effective date of the 1 974 rule. This requirement has been eliminated in the
2002 rule.
Where a facility does not conform with SPCC provisions, the owner or operator must
state the reason for nonconformance and describe, in detail, alternate methods to
achieve equivalent environmental protection. Note: This weaver does not apply to any
secondary containment requirements.
Change from 1974 rule: No direct counterpart in the 1974 rule.
The facility is required to prepare a facility diagram that includes the location and
contents of containers, transfer stations, and connecting pipes. The facility diagram
must also include exempt USTs.
Change from 1974 rule: No direct counterpart in the 1974 rule.
The owner or operator must provide, in the Plan, information and procedures relating
to basic spill prevention, reporting (contact list with phone numbers), and response.
The specific information is listed in the rule text. Note: This subparagraph applies to all
facilities.
Change from 1974 rule: No direct counterpart in the 1974 rule.
Unless the facility has submitted a response plan under §112.20, the owner or operator
must provide, in the Plan, information and procedures to enable a person reporting a
discharge to relate the necessary information. The plan must have an organization that
will make it readily usable in an emergency. The necessary information is listed in the
rule text.
Change from 1974 rule: No direct counterpart in the 1974 rule.
The entire containment system must be able to contain oil and prevent a discharge
from a primary containment system from escaping the confines of the containment
system before cleanup occurs.
Change from 1974 rule: The new language clarifies the requirement in the previous
rule that containment and/or diversionary structures must "prevent discharged oil from
reaching a navigable water course."
When it is not practicable to install secondary containment, the owner/operator must
clearly explain why, and for bulk storage containers, conduct both periodic integrity
testing of the containers and periodic integrity and leak testing of the valves and piping.
Wore: Facilities must still prepare an oil spill contingency plan following 40 CFR part
109 and a have written commitment of resources to respond to and clean up a
discharge.
Change from 1974 rule: The previous rule did not require integrity testing or leak
testing if an impracticability claim was made for secondary containment for bulk
storage containers.
U.S. Environmental Protection Agency
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SPCC Guidance for Regional Inspectors
Citation
Business Records
§§112.7(e)and
112.8(c)(6)
Employee Training
§112.7(f)
Brittle Fracture
Evaluation
§112.7(i)
Secondary
Containment
Onshore facilities
§112.8(c)(2)
Onshore production
facilities
§112.9(0(2)
Integrity Testing per
Industry Standards
§112.8(c)(6)
Cathodlc Protection
§112.8(d)(1)
Reorganization/
Plain Language
Format
Revised Rule Provision
An owner or operator may use usual and customary business records to satisfy the
recordkeeping requirements for inspections and tests. Written procedures and a
record of inspections and tests must be maintained for three years.
Change from 1974 rule: Previously, the rule required maintenance of a record of
inspections and tests for three years but did not allow for the use of usual and
customary business records.
Training is required for oil-handling personnel, and the revised rule supplies additional
topics for this training. Discharge prevention briefings must be conducted at least once
a year.
Change from 1974 rule: The revised rule requires training only for oil-handling
personnel and not for all employees. It also clarifies that briefings must be conducted
once a year, instead of intervals "frequent enough to assure adequate understanding
of the SPCC Plan for that facility."
The rule requires evaluations for field-constructed aboveground storage containers
undergoing repair, alteration, reconstruction, or a change in service.
Change from 1974 rule: No direct counterpart in the 1974 rule.
Onshore facilities (including production facilities) must ensure that secondary
containment has sufficient freeboard to allow for precipitation. Whatever method used
must be documented in the Plan.
Change from 1974 rule: Onshore facilities were required to provide sufficient
freeboard to allow for precipitation, though the previous rule did not specify that an
allowance for precipitation was required for production facilities.
Facilities must test aboveground containers for integrity on a regular schedule, and
whenever material repairs are made. Testing must combine visual inspection with
another non-destructive shell thickness testing technique. A list of organizations that
may be helpful in the identification and explanation of industry standards is included In
the rule preamble.
Change from 1974 rule: Previously, the rule stated that integrity testing should occur
periodically and did not require the combination of a visual inspection with another non-
destructive shell thickness testing technique.
All buried piping that is installed or replaced on or after August 16, 2002, must have
protective wrapping and coating as well as cathodic protection, for all soil conditions.
Note: A facility can also satisfy the corrosion protection provisions through 40 CFR part
280 or a state program approved under 40 CFR part 281.
Change from 1974 rule: The previous rule required cathodic protection for buried
piping if soil conditions warranted such protection. It did not allow for satisfaction of the
provision through 40 CFR part 280 or a state program approved under 40 CFR part
281.
Included are new sections for different types of facilities and new subparts for different
types of oils in compliance with Edible Oil Regulatory Reform Act (EORRA.) The rule
has been written in a plain language format to make it clearer and easier to use.
Requirements for the SPCC Plan are included in §§112.1 through 112.15.
U.S. Environmental Protection Agency
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DISCLAIMER - APPENDIX D
The sample Spill Prevention, Control and Countermeasure (SPCC) Plan in Appendix D
is intended to provide examples and illustrations of how a bulk storage facility could address a
variety of scenarios in its SPCC Plan. The "facility" is not an actual facility, nor does it represent
any actual facility or company. Rather, EPA is providing illustrative examples of the type and
amount of information that is appropriate SPCC Plan language for these hypothetical situations.
Because the SPCC rule is designed to give each facility owner/operator the flexibility to
tailor the facility's SPCC Plan to the facility's circumstances, this sample SPCC Plan is not a
template to be adopted by a facility; doing so does not mean that the facility will be in
compliance with the SPCC rule requirements. Nor is the sample plan a template that must be
followed in order for the facility to be considered in compliance with the SPCC rule.
Version 1.0, 11/28/2005
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SPILL PREVENTION, CONTROL, AND COUNTERMEASURE PLAN
Unified Oil Company
123 A Street
Stonefield, Massachusetts 02000
May 12, 2003
Prepared by
Poppins & Associates, Inc.
Clearwater Falls, Massachusetts, 02210
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Unified Oil Company, Ltd.
SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
TABLE OF CONTENTS
Introduction
Part 1: Plan Administration
1.1 Management Approval and Designated Person
1.2 Professional Engineer Certification
1.3 Location of SPCC Plan
1.4 Plan Review
1.5 Facilities, Procedures, Methods, or Equipment Not Yet Fully Operational
1.6 Cross-Reference with SPCC Provisions
Part 2: General Facility Information
2.1 Facility Description
2.2 Evaluation of Discharge Potential
Part 3: Discharge Prevention - General SPCC Provisions
3.1 Compliance with Applicable Requirements
3.2 Facility Layout Diagram
3.3 Spill Reporting
3.4 Potential Discharge Volumes and Direction of Flow
3.5 Containment and Diversionary Structures
3.6 Practicability of Secondary Containment
3.7 Inspections, Tests, and Records
3.8 Personnel, Training, and Discharge Prevention Procedures
3,9 Security
3.10 Tank Truck Loading/Unloading Rack Requirements
3.11 Brittle Fracture Evaluation
3.12 Conformance with State and Local Applicable Requirements
Part 4: Discharge Prevention - SPCC Provisions for Onshore Facilities
(Excluding Production Facilities)
4.1 Facility Drainage
4.2 Bulk Storage Containers
4.3 Transfer Operations, Pumping, and In-Plant Processes
Page
1
3
3
4
4
5
5
8
11
12
12
12
13
14
16
16
18
19
19
22
22
23
23
29
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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
Part 5: Discharge Response
5.1 Response to a Minor Discharge 30
5.2 Response to a Major Discharge 31
5.3 Waste Disposal 32
5.4 Discharge Notification 32
5.5 Cleanup Contractors and Equipment Suppliers 33
List of Tables
Table 1-1: Plan Review Log 6
Table 1-2: SPCC Cross-Reference 7
Table 2-1: Oil Containers 9
Table 2-2: OH Discharge History 10
Table 3-1: Potential Discharge Volume and Direction of Flow 13
Table 3-2: Inspection and Testing Program 16
Table 3-3: Fuel Transfer Procedures 21
Table 4-1: List of Oil Containers 24
Table 4-2: Scope and Frequency of Bulk Storage Containers Inspections and Tests 27
Appendices
A: Site Plan and Facility Diagram
B: Substantial Harm Determination
C: Facility Inspection Checklists
D: Record of Containment Dike Drainage
E: Record of Discharge Prevention Briefings and Training
F: Calculation of Secondary Containment Capacity
G: Records of Tank Integrity and Pressure Tests
H: Emergency Contacts
I: Discharge Notification Form
J: Discharge Response Equipment Inventory
K: Agency Notification Standard Report
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Unified Oil Company, Ltd.
SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
LIST OF ACRONYMS AND ABBREVIATIONS
AST Aboveground Storage Tank
EPA U.S. Environmental Protection Agency
MADEP Massachusetts Department of Environmental Protection
NPDES National Pollutant Discharge Elimination System
PE Professional Engineer
POTW Publicly Owned Treatment Works
SPCC Spill Prevention, Control, and Countermeasure
STI Steel Tank Institute
UST Underground Storage Tank
-IV-
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Unified Oil Company, Ltd.
SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
INTRODUCTION
Purpose
The purpose of this Spill Prevention, Control, and Countermeasure {SPCC) Plan is to
describe measures implemented by Unified Oil to prevent oil discharges from occurring, and to
prepare Unified Oil to respond in a safe, effective, and timely manner to mitigate the impacts of
a discharge.
This Plan has been prepared to meet the requirements of Title 40, Code of Federal
Regulations, Part 112 (40 CFR part 112), and supercedes the earlier Plan developed to meet
provisions in effect since 1974.
In addition to fulfilling requirements of 40 CFR part 112, this SPCC Plan is used as a
reference for oil storage information and testing records, as a tool to communicate practices on
preventing and responding to discharges with employees, as a guide to facility inspections, and
as a resource during emergency response.
Unified Oil management has determined that this facility does not pose a risk of
substantial harm under 40 CFR part 112, as recorded in the "Substantial Harm Determination"
included in Appendix B of this Plan.
This Plan provides guidance on key actions that Unified Oil must perform to comply with
the SPCC rule:
Q Complete monthly and annual site inspections as outlined in the Inspection,
Tests, and Records section of this Plan (Section 3.7) using the inspection
checklists included in Appendix C.
Q Perform preventive maintenance of equipment, secondary containment systems,
and discharge prevention systems described in this Plan as needed to keep them
in proper operating conditions.
Q Conduct annual employee training as outlined in the Personnel, Training, and
Spill Prevention Procedures section of this Plan (Section 3.8) and document
them on the log included in Appendix E.
Q If either of the following occurs, submit the SPCC Plan to the EPA Region 1
Regional Administrator (RA) and the Massachusetts Department of
Environmental Protection (MADEP), along with other information as detailed in
Section 5.4 of this Plan:
Q The facility discharges more than 1,000 gallons of oil into or upon the
navigable waters of the U.S. or adjoining shorelines in a single spill event;
or
-1-
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Unified Oil Company, Ltd.
SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
Q The facility discharges oil in quantity greater than 42 gallons in each of
two spill events within any 12-month period.
Review the SPCC Plan at least once every five (5) years and amend it to include
more effective prevention and control technology, if such technology will
significantly reduce the likelihood of a spill event and has been proven effective
in the field at the time of the review. Plan amendments, other than administrative
changes discussed above, must be recertified by a Professional Engineer on the
certification page in Section 1.2 of this Plan.
Amend the SPCC Plan within six (6) months whenever where is a change in
facility design, construction, operation, or maintenance that materially affects the
facility's spill potential. The revised Plan must be recertified by a Professional
Engineer (PE).
Review the Plan on an annual basis. Update the Plan to reflect any
"administrative changes" that are applicable, such as personnel changes or
revisions to contact information, such as phone numbers. Administrative changes
must be documented in the Plan review log of Section 1.4 of this Plan, but do not
have to be certified by a PE.
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SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
Part 1: Plan Administration
1.1 Management Approval and Designated Person (40 CFR 112.7)
Unified Oil Company ("Unified Oil') is committed to preventing discharges of oil to navigable
waters and the environment, and to maintaining the highest standards for spill prevention
control and countermeasures through the implementation and regular review and amendment to
the Plan. This SPCC Plan has the full approval of Unified Oil management. Unified Oil has
committed the necessary resources to implement the measures described in this Plan.
The Facility Manager is the Designated Person Accountable for Oil Spill Prevention at the
facility and has the authority to commit the necessary resources to implement this Plan.
Authorized Facility Representative (facility response coordinator): Susan Blake
Signature: kuuvn, (BloL
Title: Facility Manager
Date: May 12, 2003
1.2 Professional Engineer Certification (40 CFR 112.3(d))
The undersigned Registered Professional Engineer is familiar with the requirements of Part 112
of Title 40 of the Code of Federal Regulations (40 CFR part 112) and has visited and examined
the facility, or has supervised examination of the facility by appropriately qualified personnel.
The undersigned Registered Professional Engineer attests that this Spill Prevention, Control,
and Countermeasure Plan has been prepared in accordance with good engineering practice,
including consideration of applicable industry standards and the requirements of 40 CFR part
112; that procedures for required inspections and testing have been established; and that this
Plan is adequate for the facility. [40 CFR 112.3(d)]
This certification in no way relieves the owner or operator of the facility of his/her duty to prepare
and fully implement this SPCC Plan in accordance with the requirements of 40 CFR part 112.
This Plan is valid only to the extent that the facility owner or operator maintains, tests, and
inspects equipment, containment, and other devices as prescribed in this Plan.
Signature
Julie Andrews
Name
Poppins and Associates
Company
90535055, Massachusetts
Professional Engineer Registration Number
Sr Process Engineer
Title
May 12, 2003
Date
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PE Seal
MA
Julie Andrews
#90535055
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SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
1.3 Location of SPCC Plan (40 CFR112.3(e))
In accordance with 40 CFR 112.3(e), a complete copy of this SPCC Plan is maintained at the
facility in the office building. The front office is attended whenever the facility is operating, i.e.,
7:00 AM to 5:00 PM, 6 days per week (closed on Sundays).
1.4 Plan Review (40 CFR 112.3 and 112.5)
1.4.1 Changes in Facility Configuration
In accordance with 40 CFR 112.5(a), Unified Oil periodically reviews and evaluates this SPCC
Plan for any change in the facility design, construction, operation, or maintenance that
materially affects the facility's potential for an oil discharge, including, but not limited to:
commissioning of containers;
» reconstruction, replacement, or installation of piping systems;
construction or demolition that might alter secondary containment structures; or
» changes of product or service, revisions to standard operation, modification of
testing/inspection procedures, and use of new or modified industry standards or
maintenance procedures.
Amendments to the Plan made to address changes of this nature are referred to as technical
amendments, and must be certified by a PE. Non-technical amendments can be done {and
must be documented in this section) by the facility owner and/or operator. Non-technical
amendments include the following:
change in the name or contact information {i.e., telephone numbers) of
individuals responsible for the implementation of this Plan; or
» change in the name or contact information of spill response or cleanup
contractors.
Unified Oil must make the needed revisions to the SPCC Plan as soon as possible, but no later
than six months after the change occurs. The Plan must be implemented as soon as possible
following any technical amendment, but no later than six months from the date of the
amendment. The Facility Manager is responsible for initiating and coordinating revisions to the
SPCC Plan.
1.4.2 Scheduled Plan Reviews
In accordance with 40 CFR 112.5(b), Unified Oil reviews this SPCC Plan at least once every
five years (in the past, such reviews were required every three years). Revisions to the Plan, if
needed, are made within six months of the five-year review. A registered Professional Engineer
certifies any technical amendment to the Plan, as described above, in accordance with 40 CFR
112.3(d). The last SPCC review occurred on May 13, 2001. This Plan is dated May 12, 2003.
The next plan review is therefore scheduled to take place on or prior to May 12, 2008.
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1.4.3 Record of Plan Reviews
Scheduled reviews and Plan amendments are recorded in the Plan Review Log (Table 1-1).
This log must be completed even if no amendment is made to the Plan as a result of the review.
Unless a technical or administrative change prompts an earlier review of the Plan, the next
scheduled review of this Plan must occur by May 12, 2008,
1.5 Facilities, Procedures, Methods, or Equipment Not Yet Fully
Operational (40 CFR 112.7)
Bulk storage containers at this facility have never been tested for integrity since their installation
in 1989. Section 4.2.6 of this Plan describes the inspection program to be implemented by the
facility following a regular schedule, including the dates by which each of the bulk storage
containers must be tested.
1.6 Cross-Reference with SPCC Provisions (40 CFR 112.7)
This SPCC Plan does not follow the exact order presented in 40 CFR part 112. Section
headings identify, where appropriate, the relevant section(s) of the SPCC rule. Table 1-2
presents a cross-reference of Plan sections relative to applicable parts of 40 CFR part 112.
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Table 1-1: Plan Review Log
;"f^:By:. .
Mike Davies
Mike Davies
Mike Davies
Susan Blake
Susan Blake
Susan Blake
Susan Blake
Date Activity
5/20/1989 Prepare Plan
Start of
Operations
5/18/1992 Scheduled
review
2/18/1994 Plan
amendment
5/15/1995 Scheduled
review
5/15/1998 Scheduled
review
5/13/2001 Scheduled
review
5/12/2003 Periodic review
due to physical
change
certification
required? Comments
Yes Initial SPCC Plan.
No No change.
Yes* Changes to inspection procedures,
addition of a new tank, full review not
conducted.
No Change in responsible individual
contact information.
No No change.
No No change.
Yes* Installation of oil/water separator
and
' Previous PE certifications of this Plan are summarized below.
-:xv :Bate. :
2/18/1994
5/12/2003
Scope
Addition of new tank and changes in
inspection procedures.
Installation of oil/water separator
PEName
Chris Ebert
Julie Andrews
Licensing State and
• Registration No.
MA, 90117823
MA, 905350055
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Table 1-2: SPCC Cross-Reference
provision
112.3(d)
112.3
112.8(c)(3)
112.8(c)(4)
112.8(c)(5)
112.8(c)(6)
112.8(c){7)
112.8(c)(8)
112.8(c)(9)
112.8(0(10)
112.8(0(11)
112.8(d)
112.20(6)
.: ••••':":-::;::-' •' • Plan Section . •.:-.'• '.\'\'\ •:'•::• :~
Professional Engineer Certification
Location o* SPCC Plan
Plan Review
Management Approval
Cross-Reference with SPCC Rule
Part 2: General Facility Information
Appendix A: Site Plan and Facility Diagram
5.4 Discharge Notification
Part 5: Discharge Response
3.4 Potential Discharge Volumes and Direction of Flow
3.5 Containment and Diversionary Structures
3.6 Practicability of Secondary Containment
3.7 Inspections, Tests, and Records
3.8 Personnel, Training and Discharge Prevention Procedures
3.9 Security
3.10 Tank Truck Loading/Unloading
3.11 Brittle Fracture Evaluation
3.12 Conformance with Applicable State and Local Requirements
4.1 Facility Drainage
4.2.1 Construction
4.2.2 Secondary Containment
4.2.3 Drainage of Diked Areas
4.2.4 Corrosion Protection
4.2.5 Partially Buried and Bunkered Storage Tanks
4.2.6 Inspection
Appendix B - Facility Inspection Checklists
4.2.7 Heating Coils
4.2.8 Overfill Prevention System
4.2.9 Effluent Treatment Facilities
4.2.10 Visible Discharges
4.2.11 Mobile and Portable Containers
4.3 Transfer Operations, Pumping and In-Plant Processes
Certification of Substantial Harm Determination
•: :: Pag*:—:
3
4
4
Table 1-1
3
Table 1-2
8
Appendix A
32
Appendix I
Appendix K
32
13
14
16
16
Appendix B
18
19
19
22
22
23
23
25
26
Appendix D
26
26
26
Appendix C
27
27
28
28
28
29
Appendix B
* Only selected excerpts of relevant rule text are provided. For a complete list of SPCC requirements, refer
to the full text of 40 CFR part 112.
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Part 2: General Facility Information
Name:
Address:
Type:
Date of Initial Operations:
Owner/Operator:
Primary contact:
Unified Oil Company
123 A Street
Stonefield, MA 02000
(781)555-5556
Bulk storage distribution facility
May 20, 1989
Blake and Daughters, Inc.
20 Fairview Road
Stonefield, MA 02000
Susan Blake, Facility Manager
Work: (781)555-5550
Cell (24 hours): (781) 555-5559
2.1 Facility Description (40 CFR112.7(a)(3))
2.1.1 Location and Activities
Unified Oil distributes a variety of petroleum products to primarily commercial customers. The
facility handles, stores, uses, and distributes petroleum products in the form of gasoline, diesel,
No. 2 fuel oil, No. 6 fuel oil, and motor oil. Unified Oil receives products by common carrier via
tanker truck. The products are stored in several aboveground storage tanks (ASTs) and in one
underground storage tank (UST). They are delivered to customers by Unified Oil trucks or by
independent contractors. The facility refuels its own two delivery trucks from an underground
diesel tank connected to a fueling pump.
Hours of operation are between 7:00 AM and 5:00 PM, 6 days per week. Personnel at the
facility include a facility manager, a plant operator, two truck drivers, an office administrator, and
three operations and maintenance personnel.
The Site Plan and Facility Diagram included in Appendix A of this Plan show the location and
layout of the facility. The Facility Diagram (Figure A-2) shows the location of oil containers,
buildings, loading/unloading and transfer areas, and critical spill control structures.
Unified Oil is located in a primarily commercial area at 123 A Street in Stonefield,
Massachusetts. The site is comprised of approximately 2 acres of land and is bordered to the
east by A Street, to the west by Silver Creek, and to the north by ABC Plating Co.
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The site includes an office building, a maintenance shop, a tanker truck loading rack and
unloading area, and product storage and handling areas. Petroleum products are stored within
the main bulk storage area, underground, and inside the maintenance building.
2.1.2 Oil Storage
Oil storage at the facility consists of seven tanks: four fixed ASTs, one portable tank, and two
metallic USTs. In addition, the facility stores a varying stock of oil drums inside the maintenance
building.
The capacities of oil containers present at the site are listed below and are also indicated on the
facility diagram in Figure A-2. All containers with capacity of 55 gallons or more are included.
The capacity of the oil/water separator is not included in the total storage capacity for the facility
since it is used to treat storm water and as a means of secondary containment for areas of the
facility with potential for an oil discharge outside dikes or berms.
Unified Oil owns two 2,000-gallon transport trucks that are used to deliver product to customers.
One of the two trucks is periodically parked overnight while full; the capacity of this truck is
therefore counted in the total storage capacity for this facility.
Table 2-1: Oil Containers
m
Fixed Storage
1 20,000 gallons
2 20,000 gallons
3 20,000 gallons
6 1,000 gallons
7 10,000 gallons
1,100 gallons
Portable storage
4 500 gallons
Vehicles
2,000 gallons
Diesel
Unleaded regular gasoline
Aboveground vertical tank
Aboveground horizontal tank elevated on
built-in saddles
Unleaded premium gasoline Aboveground horizontal tank elevated on
built-in saddles
No. 2 fuel oil
No. 6 fuel oil
Motor oil
Gasoline
Fuel oil
Underground horizontal tank
Field-constructed aboveground vertical tank
55-gallon storage drums (variable stock; up
to 20 drums on site at any time)
Double-walled aboveground horizontal tank
Delivery truck*
* Note: Unified Oil owns two delivery trucks. Both trucks are used in transportation-
related activities outside the confines of the facility and generally return to the facility
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empty for parking overnight. One of the two delivery trucks is periodically parked while
full. This truck is therefore counted in the storage capacity for this facility. The other truck
is dedicated to scheduled deliveries and returns to the facility empty (except for minor
residual). If the tanker truck returns to the facility with more than residual product, this
product will be returned to inventory via the unloading station. If the facility decides to
use this tanker for overnight storage, then this Plan must be modified to include the
capacity of the truck and ensure compliance with other rule requirements, including
secondary containment.
jTotal Oil Storage:
Other containers:
74,600 gallons
(1) 1,500-gallon oil/water separator
Note: The oil/water separator is used treat facility drainage (i.e.,
wastewater) prior to discharge into Silver Creek under state and federal
wastewater discharge permits. Discharge from the facility includes storm
water collected from the paved areas outside the loading rack/unloading
area containment berm and bulk storage containment dike. No external
oil tanks are associated with the oil/water separator. This equipment is
used to meet certain secondary containment requirements under 40 CFR
part 112, as described later in this Plan. Thus, the capacity of the
oil/water separator is not counted towards the facility total storage
capacity.
(1) 5,000-gallon underground horizontal tank (Diesel) - Tank #5
Note: This underground storage tank is subject to, and meets, all the
technical requirements of Massachusetts Underground Storage Tank
Program at 527 CMR 9, as approved under 40 CFR part 281, and is
therefore not counted in the storage capacity for this facility (exempted
under 40 CFR 112.1(d)(4). Its location is indicated on the Facility Diagram
in Appendix A. Note that the other underground storage tank (Tank #6)
which contains No. 2 fuel oil for heating consumption on the premises of
the facility is not subject to certain technical requirements under 40 CFR
part 280 or a program approved under part 281, in particular corrosion
protection, and is therefore included in the storage capacity for this facility
(and is SPCC-regulated), as described above.
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2.2 Evaluation of Discharge Potential
2.2.1 Distance to Navigable Waters and Adjoining Shorelines and Flow Paths
The facility is located on relatively level terrain. Drainage generally flows in the direction of Silver
Creek, which runs immediately along the southwest side of the site. Silver Creek flows north to
the Blackpool River approximately 1.5 miles from the facility. Spilt trajectories are indicated on
the facility diagram. Storm drains are located along A Street at the northeast end of the site.
They discharge to Silver Creek.
Approximately three-quarters of the facility's ground surface area is paved with asphalt. The
remainder consists of compacted gravel, grass, and low-lying vegetation.
2.2.2 Discharge History
Table 2-1 summarizes the facility's discharge history.
Table 2-2: Oil Discharge History
Description of Discharge
On 3/23/2003, a leaking valve
on a delivery truck discharged
50 gallons of diesel oil onto the
ground during a rain event,
allowing approximately 10
gallpnsjo enter Silver Creek.
Corrective Actions Taken
A boom was placed into Silver
Creek immediately upon
discovery. Approximately 35
gallons of oil were recovered
from Silver creek and the facility
ground.
Plan for Preventing
Recurrence
An oil/water separator was
installed and the facility
drainage was designed to flow
into the separator.
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PART 3: Discharge Prevention - General SPCC Provisions
The following measures are implemented to prevent oil discharges during the handling, use, or
transfer of oil products at the facility. Oil-handling employees have received training in the
proper implementation of these measures.
3.1 Compliance with Applicable Requirements (40 CFR 112.7(a)(2))
This facility uses an oil/water separator as part of its drainage system to contain oil discharged
in certain areas of the facility (i.e., overfills, and the loading/unloading area associated with Tank
#4). Because Tank #4 does not meet the specifications provided in EPA's memorandum
concerning its policy on double-walled tanks, general containment must be provided to address
overfills. The separator provides environmental protection equivalent to the requirements under
112.8(b)(3) to use ponds, lagoons, or catchment basins to retain oil at the facility in the event of
an uncontrolled discharge. As described in Section 3.5 of this Plan, the operational and
emergency oil storage capacity of the oil/water separator is sufficient to handle the quantity of
oil expected to be discharged in undiked areas from tank overfills or transfer operations.
Non-destructive integrity evaluation is not performed on Tank #4 (500-gallon portable storage
tank) or the 55-gallon storage drums. Tank #4 has a double-wall construction and is elevated off
the ground. The tank is inspected regularly and following a regular schedule in accordance with
the Steel Tank Institute (STI) SP-001 tank inspection standard as described in this Plan. Any
leakage from the primary container would be detected through monitoring of the interstitial
space performed on a monthly basis. Any leakage from the secondary shell would be detected
visually during scheduled visual inspections by facility personnel. Storage drums are elevated
on spill pallets and have all sides visible, and any leak would be readily detected by facility
personnel before they can cause a discharge to navigable waters or adjoining shorelines.
Corrosion poses minimal risk of failure since drums are single-use and remain on site for a
relatively short period of time (less than one year). The drum storage area is inspected monthly.
This is in accordance with accepted industry practice for drum storage and provides an effective
means of verifying container integrity, as noted by EPA in the preamble to the SPCC rule at
67 FR 47120.
3.2 Facility Layout Diagram (40 CFR 112.7(a)(3))
Figure A-1 in Appendix A shows the general location of the facility on a U.S. Geological Survey
topographic map. Figure A-2 in Appendix A presents a layout of the facility and the location of
storage tanks and drums. The diagram also shows the location of storm water drain inlets and
the direction of surface water runoff. As required under 40 CFR 112.7(a)(3), the facility diagram
indicates the location and content of ASTs, USTs, and transfer stations and connecting piping.
3.3 Spill Reporting (40 CFR 112.7(a)(4))
The discharge notification form included in Appendix I will be completed upon immediate
detection of a discharge and prior to reporting a spill to the proper notification contacts.
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3.4 Potential Discharge Volumes and Direction of Flow (40 CFR 112.7(b))
Table 3-1 presents expected volume, discharge rate, general direction of flow in the event of
equipment failure, and means of secondary containment for different parts of the facility where
oil is stored, used, or handled.
Table 3-1: Potential Discharge Volumes and Direction of Flow
Potential Event
r Maximum
volume
released
(gallons)
Maximum
discharge rate
Direction of Flow
Bulk Storage Area (Aboveground Storage Tanks #1 , 2, 3, or 7)
Failure of aboveground tank (collapse
sr puncture below product level)
Tank overfill
Pipe failure
Leaking pipe or valve packing
Leaking heating coil (Tank #7)
Loading Rack/Unloading Area
Tank truck leak or failure inside the
•ollover berm
Tank truck leak or failure outside the
rollover berm
Hose leak during truck loading
Fuel Dispensing Areas
Tank #4 and diesel dispenser hose/
connections leak
Maintenance Building
Leak or failure of drum
Other Areas
20,000
1 to 120
20,000
600
10,000
Gradual to
instantaneous
60 gal/mi n
SWto Silver Creek
SWto Silver Creek
240 gat/min ' SW to Silver Creek
1 gal/min ! SWto Silver Creek
1 gal/min SWto Silver Creek
Secondary
Containment
Concrete dike
Concrete dike
Concrete dike
Concrete dike
Concrete dike
1 to 2,000
1 to 2.000
1 to 300
Gradual to
instantaneous
Gradual to
SWto Silver Creek
SW to Silver Creek
instantaneous \
Rollover berm,
on to oil/water
separator
Rollover berm,
on to oil/water
separator
60 gal/min SW to Silver Creek : Rollover berm
1 to 150
30 gal/minute
SWto Silver Creek.
\
1 to 55
Gradual to
instantaneous
Land-based spill
response
capability (spill
kit) and oil/water
separator
SW to Silver Creek, i Spill pallets,
Complete failure of portable tank 500
(Tank #4)
Leaking portable tank or overfills
(Tank #4}
1 to 100
Gradual to I SW to Silver Creek.
instantaneous j
3 gal/min SW to Silver Creek.
oil/water
separator
Secondary shell,
oil/water
separator
Secondary shell,
oil/water
separator
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Potential Event
Leak during transfer to heating fuel
UST (Tank # 6)
Oil/water separator malfunction
Maximum
volume
released
(gallons)
1 to 120
1 to 300
Maximum
discharge rate
60 gal/min
1 gal/min
Direction of Flow
SW to Silver Creek.
SW to Silver Creek.
Secondary
Containment
Oil/water
separator
3.5 Containment and Diversionary Structures (40 CFR 112.7(c))
Methods of secondary containment at this facility include a combination of structures (e.g., dike,
berm, built-in secondary containment), drainage systems (e.g., oil/water separator), and land-
based spill response (e.g., drain covers, sorbents) to prevent oil from reaching navigable waters
and adjoining shorelines:
»• For bulk storage containers (refer to Section 4,2.2 of this Plan):
» Dike. A concrete dike enclosure is provided around fixed aboveground
storage tanks, as described in Section 4.2.2 of this Plan.
» Double-wall tank construction. Tank #6 (UST), and the 500-gallon
portable storage tank (Tank #4) both have double-wall design with a
secondary shell designed to contain 110 percent of the inner shell
capacity. The portable tank is generally located near the entrance to the
maintenance building; however, it may be used elsewhere on site. It is
used to refuel various small pieces of equipment (each less than 55-
gallon capacity) such as trucks and compressors, that may be deployed
at different areas on the site.
•• Spill pallets. Each spill pallet has a capacity of 75 gallons, which can
effectively contain the volume of any single 55-gallon drum. Drums are
also stored inside the maintenance building and are not exposed to
precipitation. The floor of the maintenance building and lower 24 inches of
the outside walls are constructed of poured concrete that would restrict
the flow of oil outside the building. The floor has two floor drains; the drain
closest to the drum storage area is located 18 feet away. Floor drains flow
into the oil/water separator, which is capable of containing any oil
discharged from a 55-gallon drum.
»• At the loading rack and unloading area (refer to Section 3.10 of this Plan):
- Rollover berm. The loading rack/unloading area is surrounded by a 4-
inch rollover berm that provides sufficient containment for the largest
compartment of the tank truck loading or unloading at the facility (2,000
gallons), and an additional 4 inches of freeboard for precipitation.
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In transfer areas and other parts of the facility where a discharge could occur:
•• Drip pans. Fill ports for all ASTs are equipped with drip pans to contain
small leaks from the piping/hose connections.
» Sorbent material. Spill cleanup kits that include absorbent material,
booms, and other portable barriers are located inside the maintenance
building near the drummed oil storage area and in an outside shed
located near the loading rack/unloading area, as shown on the Facility
Diagram in Appendix A. The spill kits are located within close proximity of
the oil product storage and handling areas for rapid deployment should a
spill occur. Sorbent material, booms, and other portable barriers are
stored in the shed next to the loading rack/unloading area to allow for
quick deployment in the event of a discharge during loading/unloading
activities or any other accidental discharge outside the dike or loading
rack/unloading area, such as from tank vehicles entering/leaving the
facility or spills associated with the fuel dispenser. The response
equipment inventory for the facility is listed in Appendix J of this Plan. The
inventory is checked monthly to ensure that used material is replenished.
> Drainage system. The facility surface drainage is engineered to direct oil
that may be discharged outside of engineered containment structures
such as dikes or berms into the oil/water separator.
Oil/water separator. The oil/water separator is designed to separate and
retain oil at the facility. The oil/water separator has a total capacity for
oil/water mixture of 1,500 gallons and a design flow rate of 150 gallons
per minute. The separator outlet valve can be closed in the event of a
large discharge (greater than 300 gallons) to provide additional
emergency containment of up to 1,200 gallons. The maximum amount of
oil potentially discharged outside the diked or bermed areas is estimated
at roughly 2,000 gallons (from the complete failure of an on-site tanker
truck). A spill of this volume outside the diked or bermed areas will be
primarily contained by deploying sorbent material and other portable spill
barriers upon discovery of the spill, and additional oil containment
capacity will be provided by the oil/water separator. The operating oil
storage capacity is 300 gallons. Best Management Practices are used to
minimize the amount of solids and oil that flow into the oil/water
separator. Facility personnel are instructed to avoid and address small
spills using sorbents to minimize runoff of oil into the oil/water separator.
The oil/water separator is inspected monthly as part of the scheduled
inspection to check the level of water within the separator and measure
the depth of bottom sludges and floating oils. Floating oil is removed by a
licensed waste collector when it reaches a thickness of 2 inches.
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3.6 Practicability of Secondary Containment (40 CFR 112.7(d))
Unified Oil management has determined that secondary containment is practicable at this
facility.
3.7 Inspections, Tests, and Records (40 CFR 112.7(e))
As required by the SPCC rule, Unified Oil performs the inspections, tests, and evaluations listed
in the following table. Table 3-2 summarizes the various types of inspections and tests
performed at the facility. The inspections and tests are described later in this section, and in the
respective sections that describe different parts of the facility (e.g., Section 4.2.6 for bulk
storage containers).
Table 3-2; Inspection and Testing Program ___
Facility
Component
Action
Frequency/Circumstances
Aboveground
container
Container supports
and foundation
Liquid level sensing
devices (overfill)
Diked area
Lowermost drain
and all outlets of
tank truck
Effluent treatment
facilities
AH aboveground
valves, piping, and
appurtenances
Test container integrity. Combine
visual inspection with another testing
technique (non-destructive shell
testing). Inspect outside of container
for signs of deterioration and
discharges.
Inspect container's supports and
foundations.
Test for proper operation.
Inspect for signs of deterioration,
discharges, or accumulation of oil
inside diked areas.
Visually inspect content for presence
of oil.
Visually inspect.
Detect possible system upsets that
could cause a discharge.
Assess general condition of items,
such as flange joints, expansion
joints, valve glands and bodies, catch
pans, pipeline supports, locking of
valves, and metal surfaces.
Following a regular schedule (monthly,
annual, and during scheduled inspections)
and whenever material repairs are made.
Following a regular schedule (monthly,
annual, and during scheduled inspections)
and whenever material repairs are made.
Monthly
Monthly
Prior to draining
Prior to filling and departure
Daily, monthly
Monthly
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Facility
Component
Action
Frequency/Circumstances
Buried metallic
storage tank
Buried piping
Leak test.
Inspect for deterioration.
Integrity and leak testing.
Annually
Whenever a section of buried line is
exposed for any reason.
At the time of installation, modification,
construction, relocation, or replacement.
3,7,1 Daily Inspection
A Unified Oil employee performs a complete walk-through of the facility each day. This daily
visual inspection involves: (1) looking for tank/piping damage or leakage, stained or discolored
soils, or excessive accumulation of water in diked and bermed areas; (2) observing the effluent
from the oil/water separator; and (3) verifying that the dike drain valve is securely closed.
3.7.2 Monthly Inspection
The checklist provided in Appendix C is used for monthly inspections by Unified Oil personnel.
The monthly inspections cover the following key elements:
Q Observing the exterior of aboveground storage tanks, pipes, and other
equipment for signs of deterioration, leaks, corrosion, and thinning.
Q Observing the exterior of portable containers for signs of deterioration or leaks.
Q Observing tank foundations and supports for signs of instability or excessive
settlement.
Q Observing the tank fill and discharge pipes for signs of poor connection that
could cause a discharge, and tank vent for obstructions and proper operation.
Q Verifying the proper functioning of overfill prevention systems.
Q Checking the inventory of discharge response equipment and restocking as
needed.
Q Observing the effluent and measuring the quantity of accumulated oil within the
oil/water separator.
All problems regarding tanks, piping, containment, or response equipment must immediately be
reported to the Facility Manager. Visible oil leaks from tank walls, piping, or other components
must be repaired as soon as possible to prevent a larger spill or a discharge to navigable waters
or adjoining shorelines. Pooled oil is removed immediately upon discovery.
Written monthly inspection records are signed by the Facility Manager and maintained with this
SPCC Plan for a period of three years.
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3,7.3 Annual Inspection
Facility personnel perform a more thorough inspection of facility equipment on an annual basis.
This annual inspection complements the monthly inspection described above and is performed
in June of each year using the checklist provided in Appendix C of this Plan.
The annual Inspection is preferably performed after a large storm event in order to verify the
imperviousness and/or proper functioning of drainage control systems such as the dike, rollover
berm, control valves, and the oil/water separator.
Written annual inspection records are signed by the Facility Manager and maintained with this
SPCC Plan for a period of three years.
3.7.4 Periodic Integrity Testing
In addition to the above monthly and annual inspections by facility personnel, Tanks #1,2, 3,4,
and 7 are periodically evaluated by an outside certified tank inspector following the Steel Tank
Institute (STI) Standard for the Inspection of Aboveground Storage Tanks, SP-001,2005
version, as described in Section 4.2.6 of this Plan.
3.8 Personnel, Training, and Discharge Prevention Procedures
(40CFR112.7(f))
The Facility Manager is the facility designee and is responsible for oil discharge prevention,
control, and response preparedness activities at this facility.
Unified Oil management has instructed oil-handling facility personnel in the operation and
maintenance of oil pollution prevention equipment, discharge procedure protocols, applicable
pollution control laws, rules and regulations, general facility operations, and the content of this
SPCC Plan. Any new facility personnel with oil-handling responsibilities are provided with this
same training prior to being involved in any oil operation.
Annual discharge prevention briefings are held by the Facility Manager for all facility personnel
involved in oil operations. The briefings are aimed at ensuring continued understanding and
adherence to the discharge prevention procedures presented in the SPCC Plan. The briefings
also highlight and describe known discharge events or failures, malfunctioning components, and
recently implemented precautionary measures and best practices. Facility operators and other
personnel will have the opportunity during the briefings to share recommendations concerning
health, safety, and environmental issues encountered during facility operations.
A simulation of an on-site vehicular discharge has been conducted, and future training
exercises will be periodically held to prepare for possible discharge responses.
Records of the briefings and discharge prevention training are kept on the form shown in
Appendix E and maintained with this SPCC Plan for a period of three years.
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3.9 Security (40 CFR 112.7(g)}
The facility is surrounded by 8-ft tal! steel security fencing. The fence encircles the entire
footprint of the facility. The single entrance gate is locked when the facility is unattended.
All drain valves for containment areas are locked in the closed position to prevent unauthorized
opening. Water draw valves on the 20,000-gallon storage tanks are maintained in the closed
position to prevent unauthorized opening via locks. Keys for all locked valves are kept in the
front office.
Two area lights illuminate the loading/unloading and storage areas. Additional motion-activated
lights are placed in other areas of the facility. The lights are placed to allow for the discovery of
discharges and to deter acts of vandalism.
The electrical starter controls for the oil pumps, including the fuel dispenser, are located in a
closet inside the maintenance shop. The closet is locked when the pumps are not in use. The
maintenance shop is locked when the facility is unattended.
The facility securely caps or blank-flanges the loading/unloading connections of facility piping
when not in service or when in standby service for an extended period of time, or when piping is
emptied of liquid content either by draining or by inert gas pressure.
3.10 Tank Truck Loading/Unloading Rack Requirements (40 CFR 112.7(h))
The potential for discharges during tank truck loading and unloading operations is of particular
concern at this facility. Unified Oil management is committed to ensuring the safe transfer of
material to and from storage tanks. The following measures are implemented to prevent oil
discharges during tank truck loading and unloading operations.
3.10.1 Secondary Containment (40 CFR 112.7(h)(1))
The facility has both a loading rack (for loading moderate capacity oil delivery tanker trucks) and
an unloading area (where product is unloaded from large capacity tanker truck to the facility
bulk storage tanks).
The loading rack and unloading area are co-located and are used by outside suppliers making
deliveries to the facility and to load Unified Oil delivery trucks.
The tank truck loading rack/unloading area is surrounded with a 4-inch rollover asphalt berm
that provides secondary containment in the event of a discharge during transfer operations. The
secondary containment berm is designed to address the more stringent rack containment
requirements of 40 CFR 112.7(h), which requires that the berm be sufficient to contain the
capacity of the largest compartment, plus freeboard for precipitation. The curbed area provides
a catchment capacity of 2,500 gallons, which is capable of containing the largest compartment
of the petroleum suppliers truck making deliveries at this facility (maximum 2,000 gallons), and
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SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
is also capable of containing the capacity of Unified Oil's delivery trucks, which each have a
total capacity of 2,000 gallons.
To minimize direct exposure to rain, and facilitate the cleanup of small spills that may occur
during loading/unloading operations, the area is partially covered by a roof.
The area is graded to direct the flow of oil or water away from the vehicle, and the low point of
the curbed area is fitted with a gate valve that is normally kept closed and locked. The key for
that lock is kept in the main office. The berm is drained by Unified personnel after verifying that
the retained water is free of oil. The accumulated water is released to the oil/water separator.
The drain valve is closed and locked following drainage.
Although delivery trucks are usually empty while at the site for extended periods of time, Unified
Oil periodically parks one of its two delivery trucks while full overnight. If a delivery truck is
parked overnight or for an extended period of time while it still contains fuel, it is parked inside
the loading rack/unloading area containment berm. As discussed above, the berm provides
sufficient containment capacity for the truck volume, plus sufficient freeboard for 4 inches of
precipitation.
3.10.2 Loading/Unloading Procedures (40 CFR 112.7(h)(2) and (3))
All suppliers must meet the minimum requirements and regulations for tank truck
loading/unloading established by the U.S. Department of Transportation. Unified Oil ensures
that the vendor understands the site layout, knows the protocol for entering the facility and
unloading product, and has the necessary equipment to respond to a discharge from the vehicle
or fuel delivery hose.
The Facility Manager or his/her designee supervises oil deliveries for all new suppliers, and
periodically observes deliveries for existing, approved suppliers.
All loading and unloading of tank vehicles takes place only in the designated loading
rack/unloading area.
Vehicle filling operations are performed by facility personnel trained in proper discharge
prevention procedures. The truck driver or facility personnel remain with the vehicle at all times
while fuel is being transferred. Transfer operations are performed according to the minimum
procedures outlined in Table 3-3. This table is also posted next to the loading/unloading point.
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Table 3-3; Fuel Transfer Procedures
tasks
Prior to
loading/
unloading
During
loading/
unloading
Q
Q
Q
J
LI
LI
LI
Q
Q
LI
U
LJ
G
Q
Q
U
y
After loading/ LJ
unloading Q
Q
Q
Q
LI
U
LI
Q
Visually check all hoses for leaks and wet spots.
Verify that sufficient volume (ullage) is available in the storage tank or truck.
Lock in the closed position all drainage valves of the secondary containment
structure.
Secure the tank vehicle with wheel chocks and interlocks.
Ensure that the vehicle's parking brakes are set.
Verify proper alignment of valves and proper functioning of the pumping
system.
If filling a tank truck, inspect the lowermost drain and all outlets.
Establish adequate bonding/grounding prior to connecting to the fuel transfer
point.
Turn off cell phone.
Driver must stay with the vehicle at all times during loading/unloading
activities.
Periodically inspect all systems, hoses and connections.
When loading, keep internal and external valves on the receiving tank open
along with the pressure relief valves.
When making a connection, shut off the vehicle engine. When transferring
Class 3 materials, shut off the vehicle engine unless it is used to operate a
pump.
Maintain communication with the pumping and receiving stations.
Monitor the liquid level in the receiving tank to prevent overflow.
Monitor flow meters to determine rate of flow
When topping off the tank, reduce flow rate to prevent overflow.
Make sure the transfer operation is completed.
Close all tank and loading valves before disconnecting.
Securely close all vehicle internal, external, and dome cover valves before
disconnecting.
Secure all hatches.
Disconnect grounding/bonding wires.
Make sure the hoses are drained to remove the remaining oil before moving
them away from the connection. Use a drip pan.
Cap the end of the hose and other connecting devices before moving them to
prevent uncontrolled leakage.
Remove wheel chocks and interlocks.
Inspect the lowermost drain and ail outlets on tank truck prior to departure. If
necessary, tighten, adjust, or replace caps, valves, or other equipment to
prevent oil leaking while in transit.
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3.11 Brittle Fracture Evaluation (40 CFR 112.7{i))
The only field-constructed tank at the facility is Tank #7. All other tanks were shop-built.
The shell thickness of Tank #7 is less than one-half inch. As discussed in the American
Petroleum Institute (API) Standard 653 Tank Inspection, Repair, Alteration, and Reconstruction
(API-653), brittle fracture is not a concern for tanks that have a shell thickness of less than one-
half inch. This is the extent of the brittle fracture evaluation for this tank.
Nonetheless, in the event that Tank #7 undergoes a repair, alteration, reconstruction, or change
in service that might affect the risk of a discharge or failure, the container will be evaluated for
risk of discharge or failure, following API-653 or an equivalent approach, and corrective action
will be taken as necessary.
3.12 Conformance with State and Local Applicable Requirements (40 CFR
112.70))
All bulk storage tanks at this facility are registered with the state and local authorities (Stonefield
Fire Department) and have current certificates of registration and special use permits required
by the local fire code.
Both USTs at the facility (Tanks #5 and 6) meet all requirements of Massachusetts UST
regulation, including cathodic protection, double-wall construction, and monitoring systems,
although Tank #6 is not subject to these requirements.
Treated storm water runoff is discharged to Silver Creek as permitted under NPDES permit
#MA0001990. The maximum allowable daily oil/grease concentration is 15 mg/L. Grab samples
are taken each quarter, following the monitoring requirements specified in the NPDES permit.
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SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
PART 4: Discharge Prevention - SPCC Provisions for
Onshore Facilities (Excluding Production Facilities)
4.1 Facility Drainage (40 CFR112.8(b))
Drainage from the concrete dike surrounding tanks 1, 2, and 3 is restrained by a manually-
operated gate valve to prevent a discharge from entering the facility drainage system. The gate
valve is normally sealed closed, except when draining the secondary containment structure. The
content of the secondary containment dike is inspected by facility personnel prior to draining to
ensure that only oil-free water is allowed to enter the facility storm water drainage system. The
bypass valve is opened and resealed under direct personnel supervision. Drainage events are
recorded in the log included in Appendix D to this SPCC Plan.
Any potential discharge from ASTs will be restrained by secondary containment structures.
Discharges occurring during loading/unloading operations will be restrained by the rollover
berm. The facility includes a drainage system and an oil/water separator, which are used to as
containment for spilt sources outside the main berm areas (fuel dispensing, overfills of 500-
gallon AST (Tank#4), and transfers associated with the heating oil tank). The facility is equipped
with an oil/water separator engineered to retain oil at the facility. This separator provides
environmental protection equivalent to ponds, tagoons, or catchments basins required under 40
CFR 112.8(b)(3) and (4), as allowed in 40 CFR 112.7(a)(2). Discharges outside the containment
areas, such as those occurring in the fuel dispensing area or while unloading heating oil, will
flow by gravity into the drainage collection area and into the oil/water separator where oil will be
retained until it can be pumped out.
4.2 Bulk Storage Containers (40 CFR 112.8(c))
Table 4-1 summarizes the construction, volume, and content of bulk storage containers at
Unified Oil facility.
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Table 4-1: List of Oil Containers
tank
#1
#2
#3
#4
#5
#6
#7
Location
Bulk Storage
Area
Bulk Storage
Area
Bulk Storage
Area
Varies
Fuel
Dispensing
Area
Outside
Office
Building
Bulk Storage
Area
Inside
Maintenance
Building
Type (Construction
Standard)
AST vertical (UL142)
AST horizontal (UL142)
AST horizontal (UL142)
AST dual wall, portable
tank(UL142)
UST dual wall (STI P3)
UST dual wall (STIP3)
AST vertical (field-
erected). Heated during
winter months (internal
coils)
Steel drums
Capacity Content
{gallons)
20,000 Diesel
20,000 Premium
unleaded
gasoline
20,000 Regular
unleaded
gasoline
500 Regular
unleaded
gasoline
5,000 Diesel
1,000 No. 2 Fuel Oil
10,000 No. 6 Fuel Oil
55 Motor oil and
used oil
Discharge :
Prevention 4
Containment
Concrete dike.
Liquid level
gauge.
Concrete dike.
Liquid level
gauge.
Concrete dike.
Liquid level
gauge.
Double-wall.
Liquid level gauge
and interstitial
monitoring
system.
Double-wall.
Liquid level
gauge, overfill
protection system,
and interstitial
monitoring.
Double-wall.
Liquid level
gauge, overfill
protection system,
and interstitial
monitoring.
Concrete dike.
Liquid level
gauge.
Spill pallets with
built-in
containment
capacity. Building
also serves as
containment since
floor drains flow
into oil/water
separator
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4.2.1 Construction (40 CFR 112.8(c)(1))
All oil tanks used at this facility are constructed of steel, in accordance with industry
specifications as described above. The design and construction of all bulk storage containers
are compatible with the characteristics of the oil product they contain, and with temperature and
pressure conditions.
Piping between fixed aboveground bulk storage tanks is made of steel and placed aboveground
on appropriate supports designed to minimize erosion and stress.
4.2.2 Secondary Containment (40 CFR 112.8(c)(2))
A dike is provided around Tanks #1, 2, 3, and 7. Tanks #1, 2, and 3 each have a 20,000-gallon
capacity. Tank #7 has a 10,000-gallon capacity. The dike has a total containment capacity of
27,316 gallons to allow sufficient volume for the largest tank and freeboard for precipitation.
The freeboard is sufficient to contain a 4-inch rainfall corresponding to a 25-year, 24-hour storm
event for this region of Massachusetts, as documented in Appendix F of this Plan. The floor and
walls of the containment dike are constructed of poured concrete reinforced with steel. The
concrete dike was built under the supervision of a structural engineer and in conformance with
his specifications to be impervious to oil for a period of 72 hours. The facility is unattended for a
maximum of 40 hours (Saturday evening through Monday morning) and therefore any spill into
the diked area would be detected before it could escape the diked area. The surface of the
concrete floor, the inside and outside of the walls, and the interface of the floor and walls, are
visually inspected during the monthly facility inspection to detect any crack, signs of heaving or
settlement, or other structural damage that could affect the ability of the dike to contain oil. Any
damage is promptly corrected to prevent migration of oil into the ground, or out of the dike.
The 500-gallon portable AST tank is of double-wall construction and provides intrinsic
secondary containment for 110 percent of the tank capacity. Since the secondary containment
is not open to precipitation, this volume is sufficient to fully contain the product in the event of a
teak from the primary container. The interstitial space between the primary and secondary
containers is inspected on a monthly basis to detect any teak of product from the primary
container. The container, however, is not equipped to prevent overfills as required by EPA
policy in its memorandum on double-walled tanks. Therefore, general containment is required
for potential tank overfills. This containment is accomplished through the facility drainage
system and the oil/water separator, which provide environmentally equivalent protection as
described in Section 3.1 of this Plan.
Both USTs are of double-wall construction and provide intrinsic secondary containment for
110 percent of the tank capacity. The interstitial space between the primary and secondary
containers is inspected on a monthly basis to detect any leak of product from the primary
container.
The 55-gallon drums are placed on spill pallets inside the maintenance shop. Each spill pallet
provides 75 gallons of containment capacity, which is more than the required 55 gallons for any
single drum since the drums are not exposed to precipitation. The floor of the maintenance shop
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is impervious and sloped to direct any discharge occurring in the building away from doorways
and towards the drainage system that leads to the facility oil/water separator.
4,2.3 Drainage of Diked Areas (40 CFR112.8(c)(3))
The concrete dikes are drained under direct supervision of facility personnel. The accumulated
water is observed for signs of oil prior to draining. The gate valves are normally kept in a closed
position and locked except when draining the dike. Dike drainage events are recorded on the
form Included in Appendix D of this Plan; records are maintained at the facility for at least three
years.
4.2.4 Corrosion Protection {40 CFR 112.8(c)(4))
Both metallic underground storage tanks, including Tank #6, which is subject to the
requirements of 40 CFR part 112, are coated and cathodically protected to prevent corrosion
and leakage into the ground. Pressure testing is performed on both buried storage tanks every
two years following the requirements of 40 CFR part 280. The cathodic protection system is
tested annually to verify its efficacy.
Cathodic protection is provided for both tanks in accordance with 40 CFR part 280 and meets
the requirements of 40 CFR part 112.
Records of pressure tests are kept for at least three years.
4.2.5 Partially Buried and Bunkered Storage Tanks (40 CFR 112.8(c)(5))
This section is not applicable since there are no partially buried or bunkered storage tanks at
this facility.
4.2.6 Inspections and Tests (40 CFR 112.8(c)(6)}
Visual inspections of ASTs by facility personnel are performed according to the procedure
described in this SPCC Plan. Leaks from tank seams, gaskets, rivets, and bolts are promptly
corrected. Records of inspections and tests are signed by the inspector and kept at the facility
for at least three years.
The scope and schedule of certified inspections and tests performed on the facility's ASTs are
specified in STI Standard SP-001. The external inspection includes ultrasonic testing of the
shell, as specified in the standard, or if recommended by the certified tank inspector to assess
the integrity of the tank for continued oil storage.
Records of certified tank inspections are kept at the facility for at least three years. Shell test
comparison records are retained for the life of the tanks.
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SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
Table 4-2 summarizes inspections and tests performed on bulk storage containers ("EE"
indicates that an environmentally equivalent measure is implemented in place of the
inspection/test, as discussed in Section 3.1 of this Plan).
Table 4-2: Scope and Frequency of Bulk Storage Containers Inspections and Tests
Inspection/Test
Visual inspection by facility
personnel (as per checklist of
Appendix C)
External inspection by certified
inspector (as per STI Standard
SP-001)
Internal Inspection by certified
inspector (as per STI Standard
SP-001)
Tank tightness test meeting
requirements of 40 CFR 280
#1
M
A
20 yr
t
#2
M
A
20 yr
t
Tank »D
#3 #4 #S
M M
A A
10 yr EE
20 yr* EE
2yr
#6 #7 Drums
M M
A A
10 yr EE
20 yr* EE
2yr
Legend: M: Monthly
A: Annual
EE: Inspection not required given use of environmentally equivalent measure (refer to
Section 3.1 of this Plan).
* Or earlier, as recommended by the certified inspector based on findings from an external
inspection.
f Internal inspection may be recommended by the certified inspector based on findings
from the external inspection.
The frequency above is based on implementation of a scheduled inspection/testing program. To
initiate the program, ASTs will be inspected by the following dates:
»• Tank #1: external inspection to be performed by December 31,2009
»• Tank #2: external inspection to be performed by December 31, 2009
«• Tank #3: external inspection to be performed by December 31, 2006
c Tank #7: external Inspection to be performed by December 31,2006
4.2.7 Heating Coils (40 CFR 112.8(c)(7))
Exhaust lines from internal heating coils for Tank #7 drain to the oil/water separator. The
exhaust lines are monitored for signs of leakage as part of the monthly inspection of the facility.
4.2.8 Overfill Prevention Systems (40 CFR 112.8(c)(8))
All tanks are equipped with a direct-reading level gauge. Additionally, all four fixed ASTs (Tanks
#1, 2, 3, and 7) are equipped with high level alarms set at 90 percent of the rated capacity. Tank
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#4 does not have an overfill prevention system. General secondary containment is provided in
the event of overfills, as described in this Plan.
Storage drums are not refilled, and therefore overfill prevention systems do not apply.
Tanks #5 and 6 are equipped with liquid level gauges and overfill protection systems. Liquid
level sensing devices are tested on a monthly basis during the monthly inspection of the facility,
following manufacturer recommendations. Venting capacity is suitable for the fill and withdrawal
rates.
Facility personnel are present throughout the filling operations to monitor the product level in the
tanks.
4.2.9 Effluent Treatment Facilities (40 CFR 112.8(c)(9))
The facility's storm water effluent discharged into Silver Creek is observed and records
maintained according to the frequency required by NPDES permit MA0000157 (at least once
per month) to detect possible upsets in the oil/water separator that could lead to a discharge.
4.2.10 Visible Discharges (40 CFR 112.8(c)(10))
Visible discharges from any container or appurtenance - including seams, gaskets, piping,
pumps, valves, rivets, and bolts - are quickly corrected upon discovery.
Oil is promptly removed from the diked area and disposed of according to the waste disposal
method described in Part 5 of this Plan.
4.2.11 Mobile and Portable Containers (40 CFR 112.8(c}(11))
Tank #4 is of double-wall design, which provides for adequate secondary containment in the
event of leaks in the primary container shell. The interstitial space is monitored monthly for
signs of leakage.
Small portable oil storage containers, such as 55-gallon drums, are stored inside the
maintenance shop where secondary containment is provided by spill pallets and the floor is
sloped to drain away from the floor drains and door. Any discharged material is quickly
contained and cleaned up using sorbent pads and appropriate cleaning products.
Unified Oil delivery trucks generally return to the facility empty or product is returned to
inventory. Whenever they remain at the facility while full for an extended period of time (such as
when parking overnight with an emergency load of product), they are positioned in the loading
rack/unloading area, which provides 2,500 gallons of secondary containment capacity (i.e.,
sufficient for the capacity of the delivery truck (2,000 gallons) and additional freeboard for 4
inches of precipitation).
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4.3 Transfer Operations, Pumping, and In-Plant Processes
(40CFR112.8(d))
Transfer operations at this facility include:
>• The transfer of oil from the underground fuel oil storage tank to the furnace
located in the basement of the office building. The oil is pumped from the oil
storage tank by means of buried steel fuel lines and a suction pump system.
* The filling of facility delivery trucks using the gasoline dispenser.
»• The transfer of oil into or from tanker trucks at the loading rack/unloading area.
All buried piping at this facility is cathodically protected against corrosion and is provided with a
protective wrapping and coating. When a section of buried line is exposed, it is carefully
examined for deterioration. If corrosion damage is found, additional examination and corrective
action must be taken as deemed appropriate considering the magnitude of the damage.
Additionally, Unified Oil conducts integrity and leak testing of buried piping at the time of
installation, modification, construction, relocation, or replacement. Records of all tests are kept
at the facility for at least three years.
Lines that are not in service or are on standby for an extended period of time are capped or
blank-flanged and marked as to their origin.
All pipe supports are designed to minimize abrasion and corrosion and to allow for expansion
and contraction. Pipe supports are visually inspected during the monthly inspection of the
facility.
All aboveground piping and valves are examined monthly to assess their condition. Inspection
includes aboveground valves, piping, appurtenances, expansion joints, valve glands and
bodies, catch pans, pipeline supports, locking of valves, and metal surfaces. Observations are
noted on the monthly inspection checklist provided in this Plan.
Warning signs are posted at appropriate locations throughout the facility to prevent vehicles
from damaging aboveground piping and appurtenances. Most of the aboveground piping is
located within areas that are not accessible to vehicular traffic (e.g., inside diked area). Brightly
painted bollards are placed where needed to prevent vehicular collisions with equipment.
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SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
Part 5: Discharge Response
This section describes the response and cleanup procedures in the event of an oil discharge.
The uncontrolled discharge of oil to groundwater, surface water, or soil is prohibited by state
and possibly federal laws. Immediate action must be taken to control, contain, and recover
discharged product.
In general, the following steps are taken:
«• Eliminate potential spark sources;
> If possible and safe to do so, identify and shut down source of the discharge to
stop the flow;
Contain the discharge with sorbents, berms, fences, trenches, sandbags, or
other material;
> Contact the Facility Manager or his/her alternate;
Contact regulatory authorities and the response organization; and
» Collect and dispose of recovered products according to regulation.
For the purpose of establishing appropriate response procedures, this SPCC Plan classifies
discharges as either "minor" or "major," depending on the volume and characteristics of the
material released.
A list of Emergency Contacts is provided in Appendix H. The list is also posted at prominent
locations throughout the facility. A list of discharge response material kept at the facility is
Included in Appendix J.
5.1 Response to a Minor Discharge
A "minor" discharge is defined as one that poses no significant harm (or threat) to human health
and safety or to the environment. Minor discharges are generally those where;
» The quantity of product discharged is small (e.g., may involve less than 10
gallons of oil);
Discharged material is easily stopped and controlled at the time of the discharge;
Discharge is localized near the source;
Discharged material is not likely to reach water;
There is little risk to human health or safety; and
There is little risk of fire or explosion.
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Minor discharges can usually be cleaned up by Unified Oil personnel. The following guidelines
apply:
•• Immediately notify the Facility Manager.
> Under the direction of the Facility Manager, contain the discharge with discharge
response materials and equipment. Place discharge debris in properly labeled
waste containers.
•• The Facility Manager will complete the discharge notification form (Appendix I)
and attach a copy to this SPCC Plan.
»• If the discharge involves more than 10 gallons of oil, the Facility Manager will call
the Massachusetts Department of Environmental Protection Incident Response
Division (617-556-1133).
5.2 Response to a Major Discharge
A "major" discharge is defined as one that cannot be safely controlled or cleaned up by facility
personnel, such as when:
The discharge is large enough to spread beyond the immediate discharge area;
The discharged material enters water;
The discharge requires special equipment or training to clean up;
The discharged material poses a hazard to human health or safety; or
There is a danger of fire or explosion.
In the event of a major discharge, the following guidelines apply:
•• All workers must immediately evacuate the discharge site via the designated exit
routes and move to the designated staging areas at a safe distance from the
discharge. Exit routes are included on the facility diagram and posted in the
maintenance building, in the office building, and on the outside wall of the outside
shed that contains the spill response equipment.
> If the Facility Manager is not present at the facility, the senior on-site person
notifies the Facility Manager of the discharge and has authority to initiate
notification and response. Certain notifications are dependent on the
circumstances and type of discharge. For example, if oil reaches a sanitary
sewer, the publicly owned treatment works (POTW) should be notified
immediately. A discharge that threatens Silver Creek may require immediate
notification to downstream users such as the town drinking water plant, which
has an intake located on Silver Creek.
» The Facility Manager (or senior on-site person) must call for medical assistance if
workers are injured.
* The Facility Manager (or senior on-site person) must notify the Fire Department
or Police Department.
»• The Facility Manager (or senior on-site person) must call the spill response and
cleanup contractors listed in the Emergency Contacts list in Appendix H.
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> The Facility Manager (or senior on-site person) must immediately contact the
Massachusetts Department of Environmental Protection Incident Response
Division (617-556-1133) and the National Response Center (888-424-8802).
•• The Facility Manager (or senior on-site person) must record the call on the
Discharge Notification form in Appendix I and attach a copy to this SPCC Plan.
» The Facility Manager (or senior on-site person) coordinates cleanup and obtains
assistance from a cleanup contractor or other response organization as
necessary.
If the Facility Manager is not available at the time of the discharge, then the next highest person
in seniority assumes responsibility for coordinating response activities.
5.3 Waste Disposal
Wastes resulting from a minor discharge response will be containerized in impervious bags,
drums, or buckets. The facility manager will characterize the waste for proper disposal and
ensure that it is removed from the facility by a licensed waste hauler within two weeks.
Wastes resulting from a major discharge response will be removed and disposed of by a
cleanup contractor.
5.4 Discharge Notification
Any size discharge (i.e., one that creates a sheen, emulsion, or sludge) that affects or threatens
to affect navigable waters or adjoining shorelines must be reported immediately to the National
Response Center (1-800-424-8802). The Center is staffed 24 hours a day.
A summary sheet is included in Appendix I to facilitate reporting. The person reporting the
discharge must provide the following information:
Q Name, location, organization, and telephone number
Q Name and address of the party responsible for the incident
Q Date and time of the incident
Q Location of the incident
Q Source and cause of the release or discharge
Q Types of material(s) released or discharged
Q Quantity of materials released or discharged
Q Danger or threat posed by the release or discharge
Q Number and types of injuries (if any)
Q Media affected or threatened by the discharge (i.e., water, land, air)
Q Weather conditions at the incident location
Q Any other information that may help emergency personnel respond to the
incident
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Contact information for reporting a discharge to the appropriate authorities is listed in Appendix
H and is also posted in prominent locations throughout the facility (e.g., in the office building, in
the maintenance building, and at the loading rack/unloading area).
In addition to the above reporting, 40 CFR 112.4 requires that information be submitted to the
United States Environmental Protection Agency (EPA) Regional Administrator and the
appropriate state agency in charge of oil pollution control activities (see contact information in
Appendix H) whenever the facility discharges (as defined in 40 CFR 112.1(b)) more than 1,000
gallons of oil in a single event, or discharges (as defined in 40 CFR 112.1(b)) more than 42
gallons of oil in each of two discharge incidents within a 12-month period. The following
information must be submitted to the EPA Regional Administrator and to MADEP within 60
days:
» Name of the facility;
> Name of the owner/operator;
* Location of the facility;
>• Maximum storage or handling capacity and normal daily throughput;
- Corrective action and countermeasures taken, including a description of
equipment repairs and replacements;
•> Description of facility, including maps, flow diagrams, and topographical maps;
- Cause of the discharge(s) to navigable waters and adjoining shorelines, including
a failure analysis of the system and subsystem in which the failure occurred;
- Additional preventive measures taken or contemplated to minimize possibility of
recurrence; and
» Other pertinent information requested by the Regional Administrator.
A standard report for submitting the information to the EPA Regional Administrator and to
MADEP is included in Appendix K of this Plan.
5.5 Cleanup Contractors and Equipment Suppliers
Contact information for specialized spill response and cleanup contractors are provided in
Appendix M. These contractors have the necessary equipment to respond to a discharge of oil
that affects Silver Creek or adjoining shorelines, including floating booms and oil skimmers.
Spill kits are located at the loading rack/unloading area and inside the maintenance building.
The inventory of response supplies and equipment is provided in Appendix J of this Plan. The
inventory is verified on a monthly basis. Additional supplies and equipment may be ordered from
the following sources:
AA Equipment Co.
Eastern Sorbent
(800) 555-5556
(800) 555-5557
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Appendix A
Site Plan and Facility Diagram
Figure A-1: Site Plan
1 STONEFIELD
Unified Oil
Company
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SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
Appendix B
Substantial Harm Determination
Facility Name:
Facility Address:
Unified Oil Company
123 A Street
Stonefield, MA 02000
1. Does the facility transfer oil over water to or from vessels and does the facility have a total oil
storage capacity greater than or equal to 42,000 gallons?
Yes D 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 aboveground oil storage tank plus sufficient freeboard to allow for precipitation within
any aboveground storage tank area?
Yes D No •
3. Does the facility have a total oil storage capacity greater than or equal to 1 million gallons and
is the facility located at a distance (as calculated using the appropriate formula in 40 CFR part
112 Appendix C, Attachment C-lll or a comparable formula) such that a discharge from the
facility could cause injury to fish and wildlife and sensitive environments?
Yes D 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 distance (as calculated using the appropriate formula in 40 CFR part
112 Appendix C, Attachment C-lll or a comparable formula) such that a discharge from the
facility would shut down a public drinking water intake?
Yes D 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 reportable oil spill in an amount greater than or equal to 10,000
gallons within the last 5 years?
Yes D No •
Certification
I certify under penalty of law that I have personally examined and am familiar with the
information submitted in this document, and that based on my inquiry of those individuals
responsible for obtaining this information, I believe that the submitted information is true,
accurate, and complete.
Facility Manager
Title
May 12, 2003
Date
Signature
Susan Blake
Name (type or print)
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SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
APPENDIX C
Facility Inspection Checklists
The following checklists are to be used for monthly and annual facility-conducted inspections.
Completed checklists must be signed by the inspector and maintained at the facility, with this
SPCC Plan, for at least three years.
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SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
Monthly Inspection Checklist
This inspection record must be completed each month except the month in which an annual
inspection is performed. Provide further description and comments, if necessary, on a separate
sheet of paper and attach to this sheet. *Any item that receives "yes" as an answer must be
described and addressed immediately.
Storage tanks
Tank surfaces show signs of leakage
Tanks are damaged, rusted or deteriorated
Bolts, rivets, or seams are damaged
Tank supports are deteriorated or buckled
Tank foundations have eroded or settled
Level gauges or alarms are inoperative
Vents are obstructed
Secondary containment is damaged or stained
Water/product in interstice of double-walled tank
Dike drainage valve is open or is not locked
Piping
Valve seals, gaskets, or other appurtenances are leaking
Pipelines or supports are damaged or deteriorated
Joints, valves and other appurtenances are leaking
Buried piping is exposed
Loading/unloading and transfer equipment
Loading/unloading rack is damaged or deteriorated
Connections are not capped or blank-flanged
Secondary containment is damaged or stained
Berm drainage valve is open or is not locked
Oil/water separator
Oil/water separator > 2 inches of accumulated oil
Oil/water separator effluent has a sheen
Security
Fencing, gates, or lighting is non-functional
Pumps and valves are locked if not in use
Response Equipment
Response equipment inventory is complete
V*:
N Description & Qpmitients ::;
Date:
Signature:
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SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
Annual Facility Inspection Checklist
This inspection record must be completed each year. If any response requires further
elaboration, provide comments in Description & Comments space provided. Further description
and comments, if necessary, must be provided on a separate sheet of paper and attached to
this sheet. *Any item that receives "yes" as an answer must be described and addressed
immediately.
Storage tanks
Tank #1
Tank surfaces show signs of leakage
Tank is damaged, rusted or deteriorated
Bolts, rivets or seams are damaged
Tank supports are deteriorated or buckled
Tank foundations have eroded or settled
Level gauges or alarms are inoperative
Vents are obstructed
Tank #2
Tank surfaces show signs of leakage
Tank is damaged, rusted, or deteriorated
Bolts, rivets, or seams are damaged
Tank supports are deteriorated or buckled
Tank foundations have eroded or settled
Level gauges or alarms are inoperative
Vents are obstructed
Tank #3
Tank surfaces show signs of leakage
Tank is damaged, rusted, or deteriorated
Bolts, rivets, or seams are damaged
Tank supports are deteriorated or buckled
Tank foundations have eroded or settled
Level gauges or alarms are inoperative
Vents are obstructed
Tank #4
Tank surfaces show signs of leakage
Tank is damaged, rusted or deteriorated
Bolts, rivets or seams are damaged
Tank supports are deteriorated or buckled
Tank foundations have eroded or settled
Level gauges or alarms are inoperative
x;:W:..:.:,:::De^ript(i3n::^;;^orrimierj^: :;;;>;:.; •.••f^l: :
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SAMPLE Spill Prevention, Control, and Counts/measure (SPCC) Plan
•'••••••' :.•••: - -• -. ; Y*
Vents are obstructed
Oil is present in the interstice
Tank #7
Tank surfaces show signs of leakage
Tank is damaged, rusted, or deteriorated
Bolts, rivets, or seams are damaged
Tank supports are deteriorated or buckled
Tank foundations have eroded or settled
Level gauges or alarms are inoperative
Leakage in exhaust from heating coils
Concrete dike
Secondary containment is stained
Dike drainage valve is open or is not locked
Dike walls or floors are cracked or are separating
Dike is not retaining water (following large rainfall)
Piping
Valve seals or gaskets are leaking
Pipelines or supports are damaged or deteriorated
Joints, valves and other appurtenances are leaking
Buried piping is exposed
Out-of-service pipes are not capped
Warning signs are missing or damaged
Loading/unloading and transfer equipment
Loading/unloading rack is damaged or deteriorated
Connections are not capped or blank-flanged
Rollover berm is damaged or stained
Berm drainage valve is open or is not locked
Drip pans have accumulated oil or are leaking
Oil/water separator
Oil/water separator > 2 inches of accumulated oil
Oil/water separator effluent has a sheen
Security
Fencing, gates, or lighting is non-functional
Pumps and valves are not locked (and not in use)
Response equipment
Response eciuipment inventory is incomplete
N Description & Comments
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Annual reminders:
>• Hold SPCC Briefing for all oil-handling personnel (and update briefing log in the Plan);
•• Check contact information for key employees and response/cleanup contractors and
update them in the Plan as needed;
Additional Remarks:
Date: Signature:
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SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
APPENDIX D
Record of Containment Dike Drainage
This record must be completed when rainwater from diked areas is drained into a storm drain or
into an open watercourse, lake, or pond, and bypasses the water treatment system. The bypass
valve must normally be sealed in closed position. It must be opened and resealed following
drainage under responsible supervision.
Date
06/05/2003
07/15/2003
Diked Area Presence of Time ; Time Signature
Area 1 No oil 08:00 10:00 Susan Blake
Area 1 No oil 08:20 10:30 Susan Blake
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SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
APPENDIX E
Record of Annual Discharge Prevention
Briefings and Training
Briefings will be scheduled and conducted by the facility owner or operator for operating
personnel at regular intervals to ensure adequate understanding of this SPCC Plan. The
briefings will also highlight and describe known discharge events or failures, malfunctioning
components, and recently implemented precautionary measures and best practices. Personnel
will also be instructed in operation and maintenance of equipment to prevent the discharge of
oil, and in applicable pollution laws, rules, and regulations. Facility operators and other
personnel will have an opportunity during the briefings to share recommendations concerning
health, safety, and environmental issues encountered during facility operations.
Date
Subjects Covered Employees in Attendance
Instructor(s)
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SAMPLE Spill Prevention. Control, and Countermeasure (SPCC) Plan
APPENDIX F
Calculation of Secondary Containment Capacity
The maximum 24-hour rainfall recorded in the last 25 years at this location is 3.75 inches.
Bulk Storage Dike
Capacity of Tanks within the Diked Area:
Tank 1 = 20,000 gallons (saddle-mounted tank, no significant displacement)
Tank 2 = 20,000 gallons (saddle-mounted tank, no significant displacement)
Tank 3 = 20,000 gallons (need to account for tank displacement)
Tank 7 = 10,000 gallons (on legs, no significant displacement)
Dike Dimensions:
Dike footprint = 50 feet x 60 feet
Dike height =15 inches = 1.25 feet
Dike volume = 50' x 60' x 1.25' = 3750 ft3 x 7.48 gal/ft3 = 28,050 gallons
Displacement Volume of Tank 3:
Tank diameter = 10 feet
3.1415 * (10 ft)2 / 4 * 1.25' = 98 ft3 x 7.48 gal/ft3 = 734 gallons
Available Freeboard for Precipitation:
28,050 gallons - (20,000 gallons + 734 gallons) = 7,316 gallons
7,316 gallons / 7.48 gallons/ft3 / (50 ft x 60 ft) = 0.33 ft = 4 inches
The dike therefore provides sufficient storage capacity for the largest bulk storage
container within the diked area, tank displacement, and precipitation. The
containment capacity is equivalent to 137% of the capacity of the largest container
((28,050 gallons - 734 gallons)/20,000 gallons).
Loading Rack/Unloading Area Rollover Berm
Capacity of Largest Tank Truck Compartment:
2,000 gallons
Berm Dimensions.
Berm footprint = 28 feet x 45 feet (50% of the berm surface area is covered by the roof)
Berm height = 4.5 inches = 0.375 feet
Berm volume = 28 ft x 45 ft x 0.375 ft = 473 ft3 x 7.48 gal/ft3 = 3,534 gallons
Available Freeboard for Precipitation:
Since 50% of the surface area of the berm is covered by a roof, the volume of
precipitation that enters the berm is reduced.
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Minimum freeboard required = 28 ft x 45 ft x 0.5 x 3.75/12 = 197 ft3 = 1,472 gallons
Actual freeboard = 3,534 gallons - 2,000 gallons = 1,534 gallons
The berm therefore provides sufficient storage capacity to contain both the largest
compartment of tank trucks loading/unloading at the facility, and the volume of
precipitation that enters the berm.
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SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
APPENDIX G
Records of Tank Integrity and Pressure Tests
Attach copies of official records of tank integrity and pressure tests.
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SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
APPENDIX H
Emergency Contacts
Designated person responsible for spill prevention: Susan Blake, Facility Manager
781-555-5550
EMERGENCY TELEPHONE NUMBERS:
Facility
Susan Blake, Facility Manager
Local Emergency Response
Stonefield Fire Department
St. Mary's Hospital
Response/Cleanup Contractors
EZ Clean
Stonefield Oil Removal
Notification
Massachusetts Department of Environmental Protection, incident
Response Division
National Response Center
United States Environmental Protection Agency, Region 1
781-555-5550
911 or
781-555-5551
781-555-5552
617-555-5554
781-555-5555
617-556-1133
800-424-8802
888-372-7341
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SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
APPENDIX I
Discharge Notification Form
Part A: Discharge Information
General information when reporting a spill to outside authorities:
Name:
Address:
Telephone:
Owner/Operator:
Primary Contact:
Type of oil:
Unified Oil Company
123 A Street
Stonefield, MA 02000
(781)555-5556
Blake and Daughters, Inc.
20 Fairview Road
Stonefield, MA 02000
Susan Blake, Facility Manager
Work: (781)555-5550
Cell(24hrs): (781)555-5559
Quantity released:
Quantity released to a waterbody:
Discharge Date and Time:
Discovery Date and Time:
Discharge Duration:
Location/Source:
Actions taken to stop, remove, and mitigate impacts of the discharge:
Affected media:
Oair
n water
Dsoil
Notification person:
D storm water sewer/POTW
D dike/berm/oil-water separator
D other:
Telephone contact:
Business:
24-hr:
Nature of discharges, environmental/health effects, and damages:
: Injuries, fatalities or evacuation required?
Part B: Notification Checklist
Date and time Name of person receiving call
Discharge in any amount
Susan Blake, Facility Manager and Response
Coordinator
(781) 555-5550 / (781) 555-5559
Discharge in amount exceeding 10 gallons and not affecting a waterbody or groundwater
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Local Fire Department
Fire Chief: D. Evans
(781) 555-1258 or 911
Massachusetts Department of Environmental
Protection
(888) 304-1133 or (617) 553-1133
Discharge in any amount and affecting (or threatening to affect) a water body
Local Fire Department
Fire Chief: D. Evans
(781) 555-1258 or 911
Massachusetts Department of Environmental
Protection
(888) 304-1133 or (617) 553-1133
National Response Center
(800) 424-8802
Town of Stonefield POTW
Plant Operator: K. Bromberg
(781)555-5453
Town of Stonefield Drinking Water Plant
Plant Operator: D. Lopez
(781)555-5450
EZ Clean
(617) 555-5554
* The POTW should be notified of a discharge only if oil has reached or threatens sewer drains that
connect to the POTW collection system.
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SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
APPENDIX J
Discharge Response Equipment inventory
The discharge response equipment inventory is verified during the monthly inspection and must
be replenished as needed.
Tank Truck Loading/Unloading Area
O Empty 55-gallons drums to hold contaminated material 4
D Loose absorbent material 200 pounds
D Absorbent pads 3 boxes
O Nitrite gloves 6 pairs
D Neoprene gloves 6 pairs
D Vinyl/PVC pull-on overboots 6 pairs
D Non-sparking shovels 3
D Brooms 3
D Drain seals or mats 2
D Sand bags 12
Maintenance Building
O Empty 55-gallons drums to hold contaminated material 1
D Loose absorbent material 50 pounds
D Absorbent pads 1 box
D Nitrite gloves 2 pairs
D Neoprene gloves 2 pairs
D Vinyl/PVC pull-on overboots 2 pairs
D Non-sparking shovels 1
D Brooms 1
D Drain seals or mats 1
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SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan
APPENDIX K
Agency Notification Standard Report
Information contained in this report, and any supporting documentation, must be submitted to
the EPA Region 1 Regional Administrator, and to MADEP, within 60 days of the qualifying
discharge incident.
Facility:
Owner/operator:
Name of person filing report:
Location:
Maximum storage capacity:
Daily throughput:
Nature of qualifying incident(s):
Unified Oil Company
Blake and Daughters
20 Fairview Road
Stonefield, MA 02000
i
123 A Street
Stonefield, MA 02000
74,600 gallons
8,000 gallons
D Discharge to navigable waters or adjoining shorelines exceeding 1,000 gallons
D Second discharge exceeding 42 gallons within a 12-month period.
Description of facility (attach maps, flow diagrams, and topographical maps):
Unified Oil distributes a variety of petroleum products to primarily commercial customers. The
facility handles, stores, uses, and distributes petroleum products in the form of gasoline,
diesel, No. 2 fuel oil, No. 6 fuel oil, and motor oil. Unified Oil receives products by common
carrier via tanker truck. The products are stored in five aboveground storage tanks (ASTs)
and in one underground storage tank (UST). They are delivered to customers by Unified Oil
trucks or by independent contractors. The facility refuels its own two delivery trucks from an
underground diesel tank connected to a fueling pump.
Unified Oil is located in a primarily commercial area at 123 A Street in Stonefield,
Massachusetts. The site is comprised of approximately 2 acres of land and is bordered to the
East by A Street, to the West by Silver Creek, and to the North by ABC Plating Co.
Site improvements include an office building, a maintenance shop, a tanker truck loading rack
and unloading area, and product storage and handling areas. Petroleum products are stored
in the bulk storage area, the maintenance building, and the office building.
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Agency Notification Standard Report (cont'd)
Cause of the discharge(s), including a failure analysis of the system and subsystems
in which the failure occurred:
Corrective actions and countermeasures taken, including a description of equipment
repairs and replacements:
Additional preventive measures taken or contemplated to minimize possibility of
recurrence:
Other pertinent information:
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Disclaimer - Appendix E
The sample Spill Prevention, Control and Countermeasure (SPCC) Plan in Appendix E
is intended to provide examples and illustrations of how a production facility could address a
variety of scenarios in its SPCC Plan. The "facility" is not an actual facility, nor does it represent
any actual facility or company. Rather, EPA is providing illustrative examples of the type and
amount of information that is appropriate SPCC Plan language for these hypothetical situations.
Because the SPCC rule is designed to give each facility owner/operator the flexibility to
tailor the facility's SPCC Plan to the facility's circumstances, this sample SPCC Plan is not a
template to be adopted by a facility; doing so does not mean that the facility will be in
compliance with the SPCC rule requirements. Nor is the sample plan a template that must be
followed in order for the facility to be considered in compliance with the SPCC rule.
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SPILL PREVENTION, CONTROL, AND COUNTERMEASURE PLAN
Clearwater Oil Company
Big Bear Lease No. 2 Production Facility
5800 Route 417
Madison, St. Anthony Parish, Louisiana 73506
Clearwater
Prepared by
Montgomery Engineering, Inc.
November 23, 2003
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Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan
Table of Contents
Page
Cross-Reference with SPCC Rule 4
Introduction 5
Management Approval 6
Professional Engineer Certification 6
Plan Review 7
Location of SPCC Plan 7
Certification of Substantial Harm Determination 8
Part I - General Facility Information
1.1 Company Information 9
1.2 Contact Information 9
1.3 Facility Layout Diagram 10
1.4 Facility Location and Operations 10
1.5 Oil Storage and Handling 11
1,6 Proximity to Navigable Waters 12
1,7 Conformance with Applicable State and Local Requirements 12
Part II - Spill Response and Reporting
2.1 Discharge Discovery and Reporting 13
2.2 Spill Response Materials 14
2.3 Spill Mitigation Procedures 15
2.4 Disposal Plan 16
Part III -Spill Prevention, Control, and Countermeasure Provisions
3.1 Potential Discharge Volume and Direction of Flow 18
3.2 Containment and Diversionary Structures 19
3.3 Other Spill Prevention Measures 22
3.4 Inspections, Tests, and Records 23
3.5 Personnel, Training, and Discharge Prevention Procedures 27
Appendix A - Facility Diagrams 30
Appendix B - Tank Truck Loading Procedure 32
Appendix C - Monthly Inspection Checklist 33
Appendix D - Record of Dike Drainage 34
Appendix E - Discharge Prevention Briefing Log 35
Appendix F - Discharge Notification Procedures 36
Appendix G - Equipment Shut-off Procedures 41
Appendix H - Written Commitment of Manpower, Equipment, and Materials 42
Appendix I - Oil Spill Contingency Plan 43
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Clearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
List of Tables
Table 0-1: Record of plan review and changes
Table 1-1: Facility contact information
Table 1-2: Characteristics of oil containers
Table 3-1: Potential discharge volume and direction of flow
Table 3-2: Berm capacity calculations
Table 3-3: Scope of daily examinations
Table 3-4: Scope of monthly inspections
Table 3-5: Schedule of periodic condition inspection of bulk storage containers
Table 3-6: Components of flowline maintenance program
Page
7
10
11
18
21
24
25
26
27
List of Figures
Figure A-1: Site plan.
Figure A-2: Production facility diagram.
30
31
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Clearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
Cross-Reference with SPCC Rule
Prbvtelon* :
112.3(d)
112.3(e>
112.5
112.7
112.7
112.7{a)(3)
11 2.4 and
112.7(a)(4>
112.7(a)(5)
112.7(b)
112.7(c)
112.7(d)
112.7(e)
112.7(f)
112.7(g)
112.7(h)
112.7(i)
112.70)
112.9(b)
112.9(c>(1)
112.9(c}(2)
112.9(c)(3)
112.9{c)(4)
112.9(3)
: - -rtaln Section ; p:; : : >? : • :y: • • ••'•';• • ;'- : . . ;;•..• vS: • • • v;;: • :. •;';.•' . c;::; . . :•:•'• :
Professional Engineer Certification
Location of SPCC Plan
Plan Review
Management Approval
Cross-Reference with SPCC Rule
Part I - General Information and Facility Diagram
Appendix A: Facility Diagrams
2.1 Discharge Discovery and Reporting
Appendix F: Discharge Notification
2.2 Spill Mitigation Procedures
Appendix 1: Oil Spill Contingency Plan
3.1 Potential Discharge Volume and Direction of Flow
3.2 Containment and Diversionary Structures
3.2.3 Practicability of Secondary Containment
Appendix H: Written Commitment of manpower, equipment, and materials
Appendix I: Oil Spill Contingency Plan
3.4 Inspections, Tests, and Records
Appendix C: Facility Inspection Checklists
3.5 Personnel, Training, and Discharge Prevention Procedures
Appendix E: Discharge Prevention Briefing Log
Security - N/A (does not apply to production facilities)
Loading/Unloading Rack - N/A (no rack present at this facility)
Brittle Fracture Evaluation - N/A (no fi eld-erected aboveground tank at this
facility)
1 .7 Conformance with Applicable State and Local Requirements
3.2.1 Oil Production Facility Drainage
Appendix D: Record of Dike Drainage
1.5.1 Production Equipment
3.2.2 Secondary Containment for Bulk Storage Containers
3.4 Inspections, Tests, and Records
Appendix C: Monthly Inspection Checklist
3.3.1 Bulk Storage Containers Overflow Prevention
3.3.2 Transfer Operations and Saltwater Disposal System
3.3.2 Transfer Operations and Saltwater Disposal System
3.4.5 Flowline Maintenance Program
Page(s)
6
7
7
6
4
9-12
Appendix A
13-15
Appendix F
15-16
Appendix I
18-19
19-21
21
Appendix H
Appendix I
23-26
Appendix C
27-29
Appendix E
N/A
N/A
26
12
20
Appendix D
11
19-21
23-26
Appendix C
22
22-23
22-23
26-27
* Only relevant rule provisions are indicated. For a complete list of SPCC requirements, refer to the
part 112.
full text of 40 CFR
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Clearwater Oil Company, Ltd.
Big Bear Lease Wo. 2 Production Facility
SAMPLE Spill Prevention. Control, and
Countermeasure (SPCC) Plan
Introduction
The purpose of this Spill Prevention Control and Countermeasure (SPCC) Plan is to describe
measures implemented by Clearwater to prevent oil discharges from occurring, and to prepare
Clearwater to respond in a safe, effective, and timely manner to mitigate the impacts of a
discharge from the Big Bear Lease No. 2 production facility. This SPCC Plan has been
prepared and implemented in accordance with the SPCC requirements contained in 40 CFR
part 112.
In addition to fulfilling requirements of 40 CFR part 112, this SPCC Plan is used as a reference
for oil storage information and testing records, as a tool to communicate practices on preventing
and responding to discharges with Clearwater employees and contractors, as a guide on facility
inspections, and as a resource during emergency response.
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Cteanvafer Oil Company, Ltd. SAMPLE Spill Prevention, Control, and
Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan
Management Approval
40CFR112.7
Clearwater Oil Company ("Clearwater") is committed to maintaining the highest standards for
preventing discharges of oil to navigable waters and the environment through the
implementation of this SPCC Plan. This SPCC Plan has the full approval of Clearwater
management. Clearwater's management has committed the necessary resources to implement
the measures described in this Plan.
Bill Laurier is the Designated Person Accountable for Oil Spill Prevention at this Clearwater
facility and has the authority to commit the necessary resources to implement the Plan as
described.
Authorized Facility Representative: Bill Laurier
Signature: (M &WWA,
Title: Field Operations Manager
Date: November 23, 2003
Professional Engineer Certification
40CFR112.3(d)
The undersigned Registered Professional Engineer is familiar with the requirements of Part 112
of Title 40 of the Code of Federal Regulations (40 CFR part 1 12) and has visited and examined
the facility, or has supervised examination of the facility by appropriately qualified personnel.
The undersigned Registered Professional Engineer attests that this Spill Prevention, Control,
and Countermeasure Plan has been prepared in accordance with good engineering practice,
including consideration of applicable industry standards and the requirements of 40 CFR part
112; that procedures for required inspections and testing have been established; and that this
Plan is adequate for the facility. [1 12.3(d)]
This certification in no way relieves the owner or operator of the facility of his/her duty to prepare
and fully implement this SPCC Plan in accordance with the requirements of 40 CFR part 1 12.
£. lwM*4*> November 23. 2003
Signature Date
Peter E. Trudeau. P.E.
Name of Professional Engineer
90535055 Louisiana
Registration Number Issuing State
Peter E. Trudeau
LA #90535055
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Clearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
Plan Review
40CFR112.5
In accordance with 40 CFR 112.5, Clearwater Oil periodically reviews and evaluates this SPCC
Plan for any change in the facility design, construction, operation, or maintenance that
materially affects the facility's potential for an oil discharge. Clearwater reviews this SPCC Plan
at least once every five years. Revisions to the Plan, if any are needed, are made within six
months of this five-year review. Clearwater will implement any amendment as soon as possible,
but not later than six months following preparation of any amendment. A registered PE certifies
any technical amendment to the Plan, as described above, in accordance with 40 CFR 112.3(d).
Scheduled five-year reviews and Plan amendments are recorded in Table 0-1. This log must be
completed even if no amendment is made to the Plan. Unless a technical or administrative
change prompts an earlier review, the next scheduled review of this Plan must occur by
November 23, 2008.
Table 0-1: Record of Plan Review and Changes
Dat*
Authorized
Individual
Review Type
PE
Certification
Summary of Changes
11/23/03 BillLaurier Initial Plan Yes
04/14/04 BillLaurier Off-cycle review No
N/A
Changed telephone number for Field
Operations Manager.
Corrected page numbers in Table of
Content.
Non-technical amendments, no PE
certification is needed.
Location of SPCC Plan
40 CFR 112.3(6)
In accordance with 40 CFR 112.3(e), and because the facility is normally unmanned, a
complete copy of this SPCC is maintained at the field office closest to the facility, which is
located approximately 25 miles from the facility at 2451 Mountain Drive, Ridgeview, LA.
Additional copies are available at the Clearwater Oil Company management office, located at
13000 Main Street, Suite 400, Houston, TX.
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Clearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
Certification of Substantial Harm Determination
40 CFR 112.20(e), 40 CFR 112.20(f)(1)
Facility Name:
Clearwater Oil Company, Big Bear Lease No. 2
1. Does the facility transfer oil over water to or from vessels and does the facility have a total oil
storage capacity greater than or equal to 42,000 gallons?
Yes D 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 aboveground oil storage tank plus sufficient freeboard to allow for precipitation within
any aboveground storage tank area?
Yes D No •
3. Does the facility have a total oil storage capacity greater than or equal to 1 million gallons and
is the facility located at a distance (as calculated using the appropriate formula) such that a
discharge from the facility could cause injury to fish and wildlife and sensitive environments?
Yes D 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 distance (as calculated using the appropriate formula) such that a
discharge from the facility would shut down a public drinking water intake?
Yes D 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 reportable oil spill in an amount greater than or equal to 10,000
gallons within the last 5 years?
Yes D No •
Certification
I certify under penalty of law that I have personally examined and am familiar with the
information submitted in this document, and that based on my inquiry of those individuals
responsible for obtaining this information, I believe that the submitted information is true,
accurate, and complete.
Signature
Bill Laurier
Name (type or print)
Field Operations Manager
Title
November 23, 2003
Date
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Clearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
PART I - GENERAL FACILITY INFORMATION
40CFR112.7(a)(3)
1.1 Company Information
Name of Facility:
Type
Date of Initial Operation
Location
Name and Address of Owner
Clearwater Oil Company
Big Bear Lease No. 2
Onshore oil production facility
2002
5800 Route 417
Madison, St. Anthony Parish, Louisiana 73506
Clearwater Oil Company
Regional Field Office
2451 Mountain Drive
Ridgeview, LA 70180
Corporate Headquarters
13000 Main Street, Suite 400
Houston, TX 77077
1.2 Contact Information
The designated person accountable for overall oil spill prevention and response at the facility,
also referred to as the facility's "Response Coordinator" (RC), is the Field Operations Manager,
Bill Laurier. 24-hour contact information is provided in Table 1-1.
Personnel from Avonlea Services Inc. ("Avonlea") provide operations (pumper/gauger) support
activities to Clearwater field personnel, including performing informal daily examinations of the
facility equipment, as described in Section 3.4 of this SPCC Plan. Avonlea personnel regularly
visit the facility to record production levels and perform other maintenance/inspection activities
as requested by the Clearwater Field Operations Manager. Key contacts for Avonlea are
included in Table 1-1,
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C/eanvafer 0/7 Company, Ltd.
Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
Table 1-1: Facility contact information
:::Name-:;:::;::-:" : : '-J:P':
Lester Pearson
Carol Campbell
Bill Laurier
Joe Clark
William Mackenzie
'• : Tii;rh • • : • • ' •
Vice-President of
Operations
Clearwater Oil Co.
Regional Director of
Operations
Clearwater Oil Co.
Field Operations
Manager
Clearwater Oil Co.
Field Supervisor
Avonlea Services, Inc.
Pumper
Avonlea Services, Inc.
Telephone
(555)-289-4500
(405) 83 1-6320 (office)
(405) 83 1-2262 (cell)
(405) 831 -6322 (office)
(405)829-4051 (cell)
(406) 545-2285 (office)
(406) 549-9087 (cell)
(406) 549-9087 (cell)
Address
13000 Main Street, Suite 400
Houston, TX 77077
2451 Mountain Drive
Ridgeview, LA 701 80
2451 Mountain Drive
Ridgeview, LA 701 80
786 Cherry Creek Road
Avonlea, LA 701 80
786 Cherry Creek Road
Avonlea, LA 70180
1.3 Facility Layout Diagram
Appendix A, at the end of this Plan, shows a general site plan for the facility. The site plan
shows the site topography and the location of the facility relative to waterways, roads, and
inhabited areas. Appendix A also includes a detailed facility diagram that shows the wells,
flowlines, tank battery, and transfer areas for the facility. The diagram shows the location,
capacity, and contents of all oil storage containers greater than 55 gallons in capacity.
1.4 Facility Location and Operations
Clearwater owns and operates the Big Bear Lease No. 2 production facility, which is located
approximately six miles north of Madison, St. Anthony Parish, Louisiana (see Figure A-1 in
Appendix A). The site is accessed through a private dirt/gravel road off Route 417.
As illustrated in Figure A-2 in Appendix A, the facility is comprised of five main areas: Well A,
Well B, the saltwater disposal well, flowlines, and a tank battery. The tank battery includes three
400-barrel (bbl) oil storage tanks, one 500-bbl produced water tank, one 500-bbl gun barrel, and
associated flowlines and piping.
The production facility is generally unmanned. Clearwater's field office is located 25 miles from
the site, at 2541 Mountain Drive, Ridgeview, Louisiana. Field operations personnel from
Clearwater, or pumpers acting as contractors to Clearwater visit the facility daily (2-4 hours each
day) to record production rates and ensure the proper functioning of wellhead equipment and
pumpjacks, storage tanks, flowlines, and separation vessels. This includes performing
equipment inspections and maintenance as needed.
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Clearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
The facility produces an average of 30 bbl (1,260 gallons) of crude oil (approximately 40 API
gravity) and 140 bbl (5,880 gallons) of produced water each day. The produced water tank
contains an oil/produced water mixture. It is subject to 40 CFR part 112 and is covered by this
SPCC Plan.
1.5 Oil Storage and Handling
1.5.1 Production Equipment
Oil storage at the facility consists of one (1) 500-bbl gun barrel, three (3) 400-bbl aboveground
storage tanks, one (1) 500-bbl produced water tank, and associated piping, as summarized in
Table 1-2. The total oil capacity at this facility is 2,200 bbl (92,400 gallons).
All oil storage tanks are shop-built and meet the American Petroleum Institute (API) tank
construction standard. Their design and construction are compatible with the oil they contain
and the temperature and pressure conditions of storage. Tanks storing crude or produced oil
(#1 through #4) are constructed of welded steel following API-12F Shop Welded Tanks for
Storage of Production Liquids specifications. Steel tanks are coated to minimize corrosion. Tank
holding produced water (#5) constructed of fiberglass following API-12P Fiberglass Reinforced
Plastic Tanks specifications.
Other production equipment present at the facility include the pumpjacks at each well and water
pumps for transfer of saltwater to the injection well. These store a minimal amount of lubricating
oil (less than 55 gallons). Lubricating oil and other substances, such as solvents and chemicals
for downhole treatment, are also stored at the facility, but in quantities below the 55-gallon
threshold for SPCC applicability. Table 1-2 lists all oil containers present at the facility with
capacity of 55 gallons or more.
Table 1-2: Characteristics of oil containers
ID
#1
#2
#3
#4
#5
Type
Gun barrel
AST
AST
AST
AST
Construct
ton
Steel
Steel
Steel
Steel
Fiberglass
Primary
Content
Oil
Oil
Oil
Oil
Produced water
and oil mixture
TOTAL
Capacity
(barrtrtij
500
400
400
400
500
2.200
Capacity
(gallons)
21,000
16,800
16,800
16,800
21 ,000
92,400
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Clearwater Oil Company, Ltd, SAMPLE Spill Prevention, Control, and
Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan
1.5.2 Transfer Activities
Wells A and B produce crude oil, produced water (saltwater), and small amounts of natural gas.
The oil and water are produced through the tubing, while the natural gas is produced through
the casing. Well liquids are then routed via 2-inch steel flowlines to the gun barrel tank for
separation, while the gas is sent to a flare. Produced saltwater is routed from the gun barrel to
the 500-bbl saltwater storage tank first, then is pumped through flowlines to the saltwater
disposal well where it is injected. The disposal well is located approximately 2,000 ft to the west
of the tank battery. The crude oil is sent to the three 400-bbt (16,800-gallon) oil storage tanks.
Crude oil from the lease is purchased by Clearwater's crude oil purchaser and transported from
the facility by the purchaser's tanker truck. Although daily well production rates may vary,
enough crude is produced and stored for approximately one 180-bbl (7,560-gallon) load of oil to
be picked up weekly by the transporter. The largest tanker truck visiting the facility has a total
capacity of 210 bbl {8,820 gallons). Tanker trucks come to the facility only to transfer crude oil
and do not remain at the facility. All transfer operations are attended by the trucker or by field
operations personnel and meet the minimum requirements of the U.S. Department of
Transportation Hazardous Materials Regulations. Appendix B to this Plan summarizes the Tank
Truck Loading Procedure at this facility.
Produced saltwater is pumped via transfer pumps from the saltwater tank to the saltwater
disposal well, located approximately 2,000 feet west of the facility, by 2-inch PVC flowlines
(FLSW). The disposal well meets all requirements of the Underground Injection Control (UIC)
program (40 CFR parts 144-148).
1.6 Proximity to Navigable Waters
The facility is located within the Mines River watershed, approximately half a mile to the west of
Big Bear Creek, and six miles North of the Mines River. The wells and tank battery are situated
on relatively level ground that slopes in a general southeastern direction. The site plan in Figure
A-1 in Appendix A shows the location of the facility relative to nearby waterways. The facility
diagram included in Figure A-2 in Appendix A indicates the general direction of drainage. In the
event of an uncontrolled discharge from the wells, flowlines, or the tank battery areas, oil would
follow the natural topography of the site and flow into Big Bear Creek. Big Bear Creek meets
with the Mines River to the south just before the town of Madison. The River then flows in a
general easterly direction following Route 101.
1.7 Conformance with Applicable State and Local Requirements [112.70)]
The SPCC regulation at 40 CFR part 112 is more stringent than requirements from the state of
Louisiana for this type of facility. This SPCC Plan was written to conform with 40 CFR part 112
requirements. The facility thereby conforms with general requirements for oil pollution facilities
in Louisiana. All discharge notifications are made in compliance with local, state, and federal
requirements.
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Clearwater Oil Company, Ltd
Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
PART II. SPILL RESPONSE AND REPORTING
40CFR112.7
2.1 Discharge Discovery and Reporting [112.7(a)(3)J
Several individuals and organizations must be contacted in the event of an oil discharge. The
Field Operations Manager is responsible for ensuring that all required discharge notifications
have been made. All discharges should be reported to the Field Operations Manager. The
summary table included in Appendix F to this SPCC Plan provides a list of agencies to be
contacted under different circumstances. Discharges would typically be discovered during the
inspections conducted at the facility in accordance with procedures set forth in Section 3.4.1 of
this SPCC Plan, Table 3-3 and Table 3-4, and on the checklist of Appendix C. The Form
included in Appendix F of this Plan summarizes the information that must be provided when
reporting a discharge, including contact lists and phone numbers.
2.1.1 Verbal Notification Requirements (Local, State, and Federal (40 CFR part 110))
Any unauthorized discharge into air, land or water must be reported immediately to the State
Police and the Emergency Planning Commission as soon as the discharge is detected.
For any discharge that reaches navigable waters, or threatens to reach navigable waters,
immediate notification must be made to the National Response Center Hotline (800-424-8802)
and to the Environmental Protection Agency.
In the event of a discharge that threatens to result in an emergency condition, facility field
personnel must verbally notify the Louisiana Emergency Hazardous Materials Hotline (225-
925-6595) immediately, and in no case later than within one (1) hour of the discovery of the
discharge. An emergency condition is any condition that could reasonably be expected to
endanger the health and safety of the public; cause significant adverse impact to the land,
water, or air environment; or cause severe damage to property. This notification must be made
regardless of the amount of the discharge.
In the event of a discharge that does not present an emergency situation, verbal notification
must be made to the Office of Environmental Compliance (by telephone at 225-763-3908 during
office hours or 225-342-1234 after hours, weekends, and holidays; or by e-mail utilizing the
Incident Report Form and procedures found at www.deq.state.la.us/surveillance) within twenty-
four (24) hours of the discovery of the discharge.
2.1.2 Written Notification Requirements (State and Federal (40 CFR part 112))
A written notification will be made to EPA for any single discharge of oil to a navigable waters or
adjoining shoreline waterway of more than 1,000 gallons, or for two discharges of 1 bbl (42
gallons) of oil to a waterway in any 12-month period. This written notification must be made
within 60 days of the qualifying discharge, and a copy will be sent to the Louisiana Department
of Environmental Quality (DEQ), which is the state agency in charge of oil pollution control
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C/earwafer OH Company. Ltd. SAMPLE Spill Prevention, Control, and
Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan
activities. This reporting requirement is separate and in addition to reporting under 40 CFR part
110 discussed above.
For any discharge reported verbally, a written notification must also be sent to the DEQ and to
the St. Anthony's Parish Local Emergency Planning Committee (LEPC), both within five (5)
days of the qualifying discharge.
A written notification to the State Emergency Response Commission or LEPC is required for a
discharge of 100 Ibs or more beyond the confines of the facility (equivalent to 2 mcf of natural
gas, or 13 gallons of oil) within five (5) days of the qualifying discharge.
2.1.3 Submission of SPCC Information
Whenever the facility experiences a discharge into navigable waters of more than 1,000 gallons,
or two discharges of 42 gallons or more within a 12-month period, Clearwater will provide
information in writing to the EPA Region 6 office within 60 days of a qualifying discharge as
described above. The required information is described in Appendix F of this SPCC Plan.
2.2 Spill Response Materials
Boom, sorbent, and other spill response materials are stored in the shed next to the loading
area and are accessible by Clearwater and Avonlea personnel. The response equipment
Inventory for the facility includes:
(4) Empty 55-galtons drums to hold contaminated material
(3) 50-ft absorbent socks
(4) 10-ft sections of hard skirted deployment boom
(2) 50-ft floating booms
(200 pounds) "Oil-dry" loose absorbent material
(4 boxes) 2 ft x 3 ft absorbent pads
(3 boxes) Nitrile gloves
(3 boxes) Neoprene gloves
(6 pairs) Vinyl/PVC pull-on overboots
(3) Non-sparking shovels
(3) Brooms
(20) Sand bags
(1) Combustible Gas Indicator with H2S detection capabilities
Additional equipment and material are also kept at the field office. The inventory is checked
monthly by Clearwater field operations personnel to ensure that used material is replenished.
Supplies and equipment may be ordered from:
(1) Rocky Mountain Equipment Co. (800) 959-3000
(2) Quick Sorbent (800) 857-4650.
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Ctearwater Oil Company, Ltd.
Big Bear Lease No, 2 Production Facility
SAMPLE Spill Prevention, Control, and
Counter/measure (SPCC) Plan
2.3 Spill Mitigation Procedures
The following is a summary of actions that must be
taken in the event of a discharge. It summarizes the
distribution of responsibilities among individuals and
describes procedures to follow in the event of a
discharge.
A complete outline of actions to be performed in the
event of a discharge from flowlines reaching or
threatening to reach navigable waters is included in
the facility Contingency Plan (see Appendix I of this
SPCC Plan).
Reminder: In the event of a discharge
originating from Flowline A or Flow/line B,
facility personnel must immediately
implement the Oil Spill Contingency Plan.
The Oil Spill Contingency Plan discusses
the additional procedures that must be
followed to respond to a discharge of oil to
navigable waters or adjoining shorelines.
In the event of a discharge, Clearwater or contractor field personnel and the Field Operations
Manager shall be responsible for the following:
2.3.1 Shut Off Ignition Sources
Field personnel must shut off all ignition sources, including motors, electrical circuits, and open
flames. See Appendix G for more information about shut-off procedures.
2.3.2 Stop Oil Flow
Field personnel should determine the source of the discharge, and if safe to do so, immediately
shut off the source of the discharge. Shut in the well(s) if necessary.
2.3.3 Stop the Spread of Oil and Call the Field Operations Manager
If safe to do so, field personnel must use resources available at the facility (see spill response
material and equipment listed in Section 2.2) to stop the spilled material from spreading.
Measures that may be implemented, depending on the location and size of the discharge,
include placing sorbent material or other barriers in the path of the discharge (e.g., sand bags),
or constructing earthen berms or trenches.
In the event of a significant discharge, field personnel must immediately contact the Field
Operations Manager, who may obtain assistance from authorized company contractors and
direct the response and cleanup activities. Should a discharge reach Big Bear Creek, only
physical response and countermeasures should be employed, such as the construction of
underflow dams, installation of hard boom and sorbent boom, use of sorbent pads, and use of
vacuum trucks to recover oil and oily water from the creek. If water flow is low in the creek,
construction of an underflow dam downstream and ahead of the spill flow may be
advantageous. Sorbent material and/or boom should be placed immediately downstream of the
dam to recover any sheen from the water. If water flow is normal in the creek, floating booms
and sorbent boom will be deployed. Vacuum trucks will then be utilized to remove oil and oily
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Clearwater Oil Company, Ltd. SAMPLE Spill Prevention. Control, and
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water at dams and other access points. Crews should remove oiled vegetation and debris from
the creek banks and place them in bags for later disposal. After removal of contaminated
vegetation, creek banks should be flushed with water to remove free oil and help it flow down to
dams and other access points where it can be recovered by vacuum truck. At no time shall any
surfactants, dispersants, or other chemicals be used to remove oil from the creek.
2.3.4 Gather Spill Information
The Field Operations Manager will ensure that the Discharge Notification Form is filled out and
that notifications have been made to the appropriate authorities. The Field Operations Manager
may ask for assistance in gathering the spill information on the Discharge Notification Form
(Appendix F) of this Plan:
Reporter's name
Exact location of the spill
Date and time of spill discovery
Material spilled (e.g., oil, produced water containing a reportable quantity of oil)
* Total volume spilled and total volume reaching or threatening navigable waters or
adjoining shorelines
Weather conditions
Source of spill
Actions being taken to stop, remove, and mitigate the effects of the discharge
• Whether an evacuation may be needed
Spill impacts (injuries; damage; environmental media, e.g., air, waterway,
groundwater)
Names of individuals and/or organizations who have also been contacted
2.3.5 Notify Agencies Verbally
Some notifications must be completed immediately upon discovering the discharge. It is
important to immediately contact the Field Operations Manager so that timely notifications can
be made. If the Field Operations Manager is not available, or the Field Operations Manager
requests it, field personnel must designate one person to begin notification. Section 2.1 of this
Plan describes the required notifications to government agencies. The Notification List is
included in Appendix F of this SPCC Plan. The Field Operations Manager must also ensure that
written notifications, if needed, are submitted to the appropriate agencies.
2.4 Disposal Plan
The cleanup contractor will handle the disposal of any recovered product, contaminated soil,
contaminated materials and equipment, decontamination solutions, sorbents, and spent
chemicals collected during a response to a discharge incident.
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Any recovered product that can be recycled will be placed into the gun barrel tank to be
separated and recycled. Any recovered product not deemed suitable for on-site recycling will be
disposed of with the rest of the waste collected during the response efforts.
If the facility responds to a discharge without involvement of a cleanup contractor, Clearwater
will contract a licensed transportation/disposal company to dispose of waste according to
regulatory requirements. The Field Operations Manager will characterize the waste and arrange
for the use of certified waste containers.
All facility personnel handling hazardous wastes must have received both the initial 40-hour
and annual 8-hour refresher training in the Hazardous Waste Operations and Emergency
Response Standard (HAZWOPER) of the Occupational Health and Safety Administration
(OSHA). This training is included as part of the initial training received by all field personnel.
Training records and certificates are kept at the field office.
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3.1
PART III. SPILL PREVENTION, CONTROL, AND
COUNTERMEASURE PROVISIONS
40 CFR 112.7 and 112.9
Potential Discharge Volume and Direction of Flow [112.7(b)] and
Containment [112.7(a)(3)(iii)]
Table 3-1, below, summarizes potential oil discharge scenarios. If unimpeded, oil would follow
the site topography and reach Big Bear Creek.
Table 3-1: Potential discharge volume and direction of flow
Source : 1 fy|ii of fajjfure "Maximum Maximum; 0i»iBti6n of FloVif
Volume Discharge
:.. • - - • - •',•':...• -.'••• ' • :': « :.:-,. . : . (gal) : .:•• : : : . Rate (gal/hr) . : ::;:.;-: : . : :-/:;:: : : • .:-.•;••:.: . .
: . • • • • . . •. : • • . • -. :• - • . ; . . . • *'" * •••.•••.• ...... '•• •::••* .••..••. ••:::: .
Tank Battery
Crude Oil Storage Tank
Gun barrel
Flowlines and Piping
Flowlines and Piping on
Storage Tanks and Gun
Barrel
Flowlines and Piping
associated with wells
Rupture due to 1 6,800
lightning strike,
seam failure
Leak at manway, 24
valves
Overflow (1 day's 1,260
production)
Rupture due to 21,000
lightning strike,
seam failure
Leak at manway, 42
valves
Overflow (1 day's 7,1 40
production)
Rupture/failure 3,570
due to corrosion
Pinhole leak, or 48
leak at
connection
Rupture/failure 3,570
due to corrosion
16,800 Southeast towards Big
Bear Creek.
1 Southeast towards Big
Bear Creek.
53 Southeast towards Big
Bear Creek.
21 ,000 Southeast towards Big
Bear Creek.
2 Southeast towards Big
Bear Creek.
298 Southeast towards Big
Bear Creek.
148 Southeast towards Big
Bear Creek.
2 Southeast towards Big
Bear Creek.
148 Southeast towards Big
Bear Creek.
Containment
Containment
berm
Containment
berm
Containment
berm
Containment
berm
None; See Oil
Spill
Contingency
Plan
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source
Wells
Polished rod stuffing box
valves, fittings, gauges
Saltwater Disposal
Piping/hoses, pumps,
valves
Transfers and Loading
Transport truck loading
hose
Offload line, connection
Tank truck
Transfer valve
Type of failure
Pinhole leak, or
leak at
connection
Leak
Leak
Operations
Rupture
Leak
Over-topping
while loading
Rupture, leak of
valve packing
Maximum Maximum Direction of Flow
Volume Discharge
(gal) Rate (gal/hr)
48 2 Southeast towards Big
Bear Creek.
24 1 Southeast towards Big
Bear Creek.
24 1 Southeast towards Big
Bear Creek.
84 84 Southeast towards Big
Bear Creek.
42 1 Southeast towards Big
Bear Creek.
1,680 1,680 Southeast towards Big
Bear Creek.
3 3 Southeast towards Big
Bear Creek.
Containment
None; See Oil
Spill
Contingency
Plan
Well pad
Containment
berm
Downslope
berm
Downslope
berm
Drainage ditch
Load line
container, curb
3.2 Containment and Diversionary Structures [112.7(c) and 112.7(a)(3)(iii)]
The facility is configured to minimize the likelihood of a discharge reaching navigable waters.
The following measures are provided:
Secondary containment for the oil storage tanks, saltwater tank (which may have
small amounts of oil), and gun barrel is provided by a 60 ft x 40 ft x 2.5 ft earthen
berm that provides a total containment volume of 867 barrels (36,423 gallons), as
described in Section 3.2.2 below. The berm is constructed of native soils and
heavy clay that have been compacted, then covered with gravel. A clay layer in
the shallow subsurface exists naturally and will stop any spilled oil from seeping
to deeper groundwater.
• The tank truck loading area is flat but gently slopes to the southeast, where a
crescent-shaped, open berm has been placed to catch any potential spills from
tanker transport trucks. The bermed area provides a catchment basin of 40
barrels (1,680 gallons), the maximum expected amount of a spill from the tanker
due to overtopping of the truck during loading. In addition, the end of the load line
is equipped with a load line drip bucket designed to prevent small discharges that
may occur when disconnecting the hose.
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• Booms, sorbents, shovels, and other discharge response materials are stored in
a shed located in close proximity to the loading area. This material is sufficient to
contain small discharges (up to approximately 200 gallons).
These measures are described in more details in the following sections.
3.2.1 Oil Production Facility Drainage [112.9(b)]
Facility drainage in the production/separation area but outside containment berms is designed
to flow into drainage ditches located on the eastern and southern boundaries of the site. These
ditches usually run dry. The ditches are visually examined by facility personnel on a daily basis
during routine facility rounds, during formal monthly inspections, and after rain events, to detect
any discoloration or staining that would indicate the presence of oil from small leaks within the
facility. Any accumulation of oil is promptly removed and disposed off site. Formal monthly
inspections are documented.
Discharges from ASTs are restrained by the secondary containment berm, as described in
Section 3.2.2 of this Plan. Discharges occurring during transfer operations will be contained at
each well by the rock pad or will flow into the drainage ditch located at the facility.
3.2.2 Secondary Containment for Bulk Storage Containers [112.9(c)(2)]
In order to further minimize the potential for a discharge to navigable waters, bulk storage
containers such as all tank battery, separation, and treating equipment are placed inside a 2.5-ft
tall earthen berm (fire wall). The berm capacity exceeds the SPCC and Louisiana requirements.
It provides secondary containment sufficient for the size of the largest tank, plus at least 1 ft of
freeboard to contain precipitation. This secondary containment capacity is equivalent to 173
percent of the capacity of the largest tank within the containment area (500 barrels) and
exceeds the 10 percent freeboard recommended by API for firewalls around production tanks
(AP1-12R1). The amount of freeboard also exceeds the amount of precipitation anticipated at
this facility, which is estimated to average 3.5 inches for a 24-hour, 25-year storm, based on
data from the nearby Ridgeview Regional Airport. Details of the berm capacity calculation are
provided in Table 3-2.
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Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
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Table 3-2: Berm capacity calculations
Berm Capacity
Berm height
Berm dimensions
Tank footprint
2.5ft
60 ft x 40 ft = 2,400 ft2
4 tanks @ 12 ft dia. each = 4 x (n 122/4) = 452 ft2
Net volume 2.5 ft x (2,400 - 452) = 4,869 ft3 = 36,423 gallons
Ratio to largest tank 36,423 / 21,000 = 173%
Corresponding Amount of Freeboard
100% of tank volume
Net area (minus tank footprint)
Minimum berm height for 100% of tank volume
Freeboard
21,000 gallons = 2,807 ft3
2,400 ft2-452 ft2 =1,948 ft2
2,807 fP / 1,948 fP= 1.44 ft
2.5 ft-1.44 ft = 1.06 ft
The floor and walls of the berm are constructed of compacted earth with a layer of clay that
ensures that the berm is able to contain the potential release of oil from the storage tanks until
the discharge can be detected and addressed by field operations personnel. Facility personnel
inspect the berm daily for the presence of oil. The sides of the berm are capped with gravel to
minimize erosion.
The berm is equipped with a manual valve of open-and-closed design. The valve is used to
drain the berm and is normally kept closed, except when draining water accumulation within the
berm. Drainage from the berm flows into the drainage ditch to the south of the production/
separation area. All water is closely inspected by field operations personnel (who are the
persons providing "responsible supervision") prior to draining water accumulation to ensure that
no free oil is present (i.e., there is no sheen or discoloration upon the surface, or a sludge or
emulsion deposit beneath the surface of the water). The bypass valve for the containment
structure is opened and reseated following drainage under the responsible supervision of field
operations personnel. Free oil is promptly removed and disposed of in accordance with waste
regulations. Drainage events are recorded on the form provided in Appendix D, including the
time, date, and name of the employee who performed the drainage. The records are maintained
with this SPCC Plan at the Ridgeview field office for a period of at least three years.
3.2.3 Practicability of Secondary Containment [112.7(d)]
Flowlines adjacent to the production equipment and storage tanks are located within the berm,
and therefore have secondary containment. Aboveground flowlines that go from the wells to the
production equipment and buried flowlines, however, lack adequate secondary containment.
The installation of double-wall piping, berms, or other permanent structures (e.g., remote
impoundment) are impracticable at this facility due to the long distances involved and physical
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and road/fenceline right-of-way constraints. Additionally, such permanent structures would
create land erosion and access problems for the landowner's farming operations and current
uses of the land (e.g., agricultural production, animal grazing).
Other measures listed under 40 CFR 112.7(c) such as the use of sorbents are also
impracticable as means of secondary containment since the volumes involved may exceed the
sorbent capacity and the facility is attended for only a few hours each day.
Because secondary containment for flowlines outside of the tank battery is impracticable,
Clearwater has provided with this Plan additional elements required under 40 CFR 112.7(d),
including:
A written commitment of manpower, equipment, and materials required to
expeditiously control and remove any quantity of oil discharged that may be
harmful (see Appendix H).
An Oil Spill Contingency Plan following the provisions of 40 CFR 109 (see
Appendix I).
3.3 Other Spill Prevention Measures
3.3.1 Bulk Storage Containers Overflow Prevention [112.9(c)(4)]
The tank battery is designed with a fail-safe system to prevent discharge, as follows:
The capacity of the oil storage tanks is sufficient to ensure that oil storage is
adequate in the event where facility personnel are unable to perform the daily
visit to unload the tanks or the pumper is delayed in stopping production. The
maximum capacity of the wells linked to the tank battery is approximately 600
barrels per day. The oil tanks are sized to provide sufficient storage for at least
two days.
The tanks are connected with overflow equalizing lines to ensure that a full tank
can overflow to an adjacent tank.
3.3.2 Transfer Operations and Saltwater Disposal System [112.9{d)]
All aboveground valves and piping associated with transfer operations are inspected daily by
the pumper and/or tank truck driver, as described in Section 3.4 of this Plan. The inspection
procedure includes observing flange joints, valve glands and bodies, drip pans, and pipe
supports. The conditions of the pumping well polish rod stuffing boxes, and bleeder and gauge
valves, are inspected monthly.
Components of the produced water disposal system are inspected on a monthly basis by field
operation personnel as described in Section 3.4 and following the checklist provided in
Appendix C of this SPCC Plan. This includes the pumps and motors for working condition and
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leaks, hoses, valves, flowlines, and the saltwater injection wellhead. Maintenance and operation
of the well itself and the downhole injection comply with EPA's and the state's Underground
Injection Control (UIC) rules and regulations (40 CFR parts 144-148).
3.4 Inspections, Tests, and Records [112.7(e)J
This Plan outlines procedures for inspecting the facility equipment in accordance with SPCC
requirements. Records of inspections performed as described in this Plan and signed by the
appropriate supervisor are a part of this Plan, and are maintained with this Plan at the
Ridgeview field office for a minimum of three years. The reports include a description of the
inspection procedure, the date of inspection, whether drainage of accumulated rainwater was
required, and the inspector's signature.
The program established in this SPCC Plan for regular inspection of all oil storage tanks and
related production and transfer equipment follows the American Petroleum Institute's
Recommended Practice for Setting Maintenance, Inspection, Operation, and Repair of Tanks in
Production Service (API RP 12R1, Fifth Edition, August 1997). Each container is inspected
monthly by field operation personnel as described in this Plan section and following the
checklist provided in Appendix C of this SPCC Plan. The monthly inspection is aimed at
identifying signs of deterioration and maintenance needs, including the foundation and support
of each container. Any leak from tank seams, gaskets, rivets, and bolts is promptly corrected.
This Plan also describes provisions for monitoring the integrity of flowlines through a
combination of monthly visual inspections and periodic pressure testing or through the use of an
alternate technology. The latter element is particularly important for this facility since flowlines
do not have adequate secondary containment.
The inspection program is comprised of informal daily examinations, monthly scheduled
inspections, and periodic condition inspections. Additional inspections and/or examinations are
performed whenever an operation alert, malfunction, shell or deck leak, or potential bottom leak
is reported following a scheduled examination. Written examination/inspection procedures and
monthly examination/inspection reports are signed by the field inspector and are maintained at
the field office for a period of at least three years.
3.4.1 Daily Examinations
The facility is visited daily by field operations personnel. The daily visual examination consists of
a walkthrough of the tank battery and around the wells. Field operations personnel check the
wells and production equipment for leaks and proper operation. They examine all aboveground
valves, polished rod stuffing boxes, wellheads, fittings, gauges, and flowline piping at the
wellhead. Personnel inspect pumps to verify proper function and check for damage and
leakage. They look for accumulation of water within the tank battery berms and verify the
condition and position of valves. The storage tanks are gauged every day. A daily production
report is maintained. All malfunctions, improper operation of equipment, evidence of leakage,
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stained or discolored soil, etc. are logged and communicated to the Clearwater Field Operations
Manager.
Table 3-3: Scope of daily examinations
Facility Area
item
Observations
Storage Tanks (Oil
and Produced water)
Leaks
Wells
SW Pumps
Foundation problems
Flowlines problems
Leak
Leaks
Tank liquid level gauged
Drip marks, leaks from weld seams, base of tank
Puddles containing spilled or leak material
Corrosion, especially at base (pitting, flaking)
Cracks in metal
Excessive soil or vegetation buildup against base
Cracks
Puddles containing spilled or leaked material
Settling
Gaps at base
Evidence of leaks, especially at connections/collars
Corrosion (pitting, flaking)
Settling
Evidence of stored material seepage from valves or
seals
Evidence of oil seepage from pumping rod stuffing
boxes, wellhead and wellhead flowlines, valves, gauges
Leaks at seals, flowlines, valves, hoses
Puddles containing spilled or leaked material
Corrosion
3.4.2 Monthly Inspections
Table 3-4 summarizes the scope of monthly inspections performed by field personnel.
The monthly inspection covers the wellheads, flowlines, and all processing equipment. It also
includes verifying the proper functioning of all detection devices, including high-level sensors on
oil storage tanks, heater treater, and separators. Storage tanks are inspected for signs of
deterioration, leaks, or accumulation of oil inside the containment area, or other signs that
maintenance or repairs are needed. The secondary containment area is checked for proper
drainage, general conditions, evidence of oil, or signs of leakage. The monthly inspection also
involves visually inspecting all aboveground valves and pipelines and noting the general
condition of items such as transfer hoses, flange joints, expansion joints, valve glands and
bodies, catch pans, pipeline supports, pumping well pumping rod stuffing boxes, bleeder and
gauge valves, locking of valves, and metal surfaces.
The checklist provided in Appendix C is used during monthly inspections. These inspections are
performed in accordance with written procedures such as API standards (e.g., API RP 12R1),
engineering specifications, and maintenance schedule developed by the equipment
manufacturers.
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All safety devices are tested quarterly by a third party inspector. The tests are recorded and the
results are maintained with this Plan at Clearwater's field office. Testing of the safety devices is
conducted in accordance with guidelines API RP-14C published by the American Petroleum
Institute, or in accordance with instructions from the device's manufacturer. Written test
procedures are kept at the offices of the third party testing company and are available upon
request.
Twice a year, facility personnel drive to the pre-established response staging areas located at
three different points along Big Bear Creek (see Oil Spill Contingency Plan in Appendix I) to
ensure that the dirt/gravel roads are accessible using field vehicles and that the Oil Spill
Contingency Plan can be implemented in the event of a discharge from fiowlines reaching the
Creek.
Table 3-4: Scope of monthly inspections
FaellftyArea
Equipment
Inspection Item
Tank Battery
Storage tanks
Area
Truck Loading
Wells (including
saltwater disposal
well)
Offload lines, drip pans,
valves, catchment berm
Production equipment
Area
Leakage, gaskets, hatches
Tank liquid level checked
Tank welds in good condition
Vacuum vents
Overflow lines
Piping, vafves, and bull plugs
Corrosion, paint condition
Pressure / level safety devices*
Emergency shut-down system(s)*
Pressure relief valves*
Berm and curbing
Presence of contaminated/stained soil
Excessive vegetation
Equipment protectors and signs
Engine drip pans and sumps
General housekeeping
Valve dosed and in good condition
Cap or bull plug at end of offload line/connection
Sign of oil or standing water in drip pan(s)
Sign of oil or standing water in catchment berm
Sign of oil in surrounding area
Gauges (pressure, temperature, and liquid level)
Pressure / level safety devices*
Emergency shut-down system(s)*
Pressure relief valves*
Spills and leaks (e.g., stuffing box)
Equipment protectors and signs
General housekeeping
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Faculty Area
Equipment
Inspection Item
Leasehold area
between wells and
Tank Battery
Flowlines
Other
Response staging
areas
Road and Field Ditches
Chemicals, Fuels and Lube
Oils
Area
Flowline between the well and tank battery/gun barrel
Exposed line of buried piping
Valves (condition of, whether locked or sealed)
Evidence of leaks and/or damage, especially at
connections/collars
Corrosion (pitting, flaking)
Pipe supports
Evidence/puddles of crude oil and/or produced water
Storage conditions
Road practicable by field vehicle
Area clear of excessive vegetation
* Tested quarterly by third party inspection company.
3.4.3 Periodic Condition Inspection of Bulk Storage Containers
A condition inspection of bulk storage containers is performed by a qualified inspector according
to the schedule and scope specified in API RP 12R1. The schedule is determined based on the
corrosion rate; with the first inspection performed no more than 15 years after the tank
construction, as detailed in Table 3-5.
Three bulk storage containers installed at this facility were moved from another facility
decommissioned by Clearwater. These bulk storage containers were leak tested after relocation
to the facility.
Table 3-5: Schedule of periodic condition inspection of bulk storage containers
Tank
#1
#2
#3
#4
#5
Year Built
1983
2002
1995
2002
1991
Last Inspection J
11/5/1998
None
None
None
None
. Next inspection by ;^:. :;• • .;s.... .•::-. . o.:., ...<:' . ..v
11/5/2008*
First inspection to be performed by 12/31/2017*
First inspection to be performed by 12/31/2010*
First inspection to be performed by 12/31/2017*
First inspection to be performed by 12/31/2006*
* Dates for subsequent external inspections must follow the recommendations of the certified inspector, not to exceed
three-quarters of the predicted shell/roof deck corrosion rate life, or maximum of 15 years.
3.4.4 Brittle Fracture Evaluation [112.7{i)]
At the present time, none of the bulk storage containers at this site was field-erected, and
therefore no brittle fracture evaluation is required.
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3.4.5 Flowline Maintenance Program [112.9(d)(3)]
Because the facility is relying on a contingency plan to address discharges, the flowline
maintenance program is specifically implemented to maintain the integrity of the primary
container (in this case piping) to minimize releases of oil from this part of the production facility.
The facility's gathering lines and flowlines are configured, inspected monthly for leaks at
connections and on each joint, corrosion (pitting, flaking), and maintained to minimize the
potential for a discharge as summarized in Table 3-6. Records of integrity inspections, leak
tests, and part replacements are kept at the facility for at least three years (integrity test results
are kept for ten years).
Table 3-6: Components of flowline maintenance program
Component
Measures/Activities
Configuration
Inspection
Maintenance
Well pumps are equipped with low-pressure shut-off systems that detect
pressure drops and minimize spill volume in the event of a flowline leak.
Flowlines are identified on facility maps and are marked in the field to facilitate
access and inspection by facility personnel. Flowline maps and field tags
indicate the location of shutdown devices and valves that may be used to
isolate portions of the flowline.
With the exception of a portion of Flowline B under an access road, the
flowlines and appurtenances (valves, flange joints, supports) can be visually
observed for signs of leakage, deterioration, or other damage.
Lines are visually inspected for leaks and corrosion as part of the monthly
rounds by field personnel, as discussed in Section 3.4 above.
The buried portions of Flowline B are coated/wrapped and visually observed
for damage or coating condition whenever they are repaired, replaced, or
otherwise exposed.
Every five years, flowlines are tested using ultrasonic techniques to determine
remaining wall thickness and mechanical integrity. Copies of test results are
maintained atthe facility for ten years to allow comparison of successive tests.
Any leak in the flowline or appurtenances is promptly addressed by isolating
the damaged portion and repairing or replacing the faulty piece of equipment
Clearwater does not accept pipe clamps and screw-in plugs as forms of repair.
Any portion of a flowline that fails the mechanical integrity test is repaired and
retested, or replaced.
3.5 Personnel, Training, and Discharge Prevention Procedures [112.7(f}]
The Field Operations Manager has been designated as the point of contact for all oil discharge
prevention and response at this facility.
All Clearwater field personnel receive training on proper handling of oil products and procedures
to respond to an oil discharge prior to entering any Clearwater production facility. The training
ensures that all facility personnel understand the procedures described in this SPCC Plan and
are informed of the requirements under applicable pollution control laws, rules and regulations.
The training also covers risks associated with potential exposure to hydrogen sulfide (H2S) gas.
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All Clearwater field personnel also receive an initial 40-hour HAZWOPER training (and 8-hour
annual refresher training) as per OSHA standard.
Clearwater ensures that all contractor personnel are familiar with the facility operations, safety
procedures, and spill prevention and control procedures described in this Plan prior to working
at the facility. All contractors working at the facility receive a copy of this SPCC Plan. Avonlea
personnel visiting the facility receive training similar to that provided to Clearwater oil handling
employees.
Clearwater management holds briefings with field operations personnel (including contractor
personnel as appropriate) at least once a year, as described below.
3.5.1 Spill Prevention Briefing
The Field Operations Manager conducts Spill Prevention Briefings annually to ensure adequate
understanding and effective implementation of this SPCC Plan. These briefings highlight and
describe known spill events or failures, malfunctioning components, and recently developed
precautionary measures. The briefings are conducted in conjunction with the company safety
meetings. Sign-in sheets, which include the topics of discussion at each meeting, are
maintained with this Plan at Clearwater's field office. A Discharge Prevention Briefing Log form
is provided in Appendix E to this Plan and is used to document the briefings. The scheduled
annual briefing includes a review of Clearwater policies and procedures relating to spill
prevention, control, cleanup, and reporting; procedures for routine handling of products (e.g.,
loading, unloading, transfers); SPCC inspections and spill prevention procedures; spill reporting
procedures; spill response; and recovery, disposal, and treatment of spilled material.
Personnel are instructed in operation and maintenance of equipment to prevent the discharge of
oil, and in applicable federal, state, and local pollution laws, rules, and regulations. Facility
operators and other personnel have an opportunity during the briefings to share
recommendations concerning health, safety, and environmental issues encountered during
facility operations.
The general outline of the briefings is as follows:
Responsibilities of personnel and Designated Person Accountable for Spill
Prevention;
• Spill prevention regulations and requirements;
Spill prevention procedures;
Spill reporting and cleanup procedures;
• History/cause of known spill events;
Equipment failures and operational issues;
• Recently developed measures/procedures;
Proper equipment operation and maintenance; and
• Procedures for draining rainwater from berms.
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3.5.2 Contractor Instructions
In order that there will be no misunderstanding on joint and respective duties and
responsibilities to perform work in a safe manner, contractor personnel also receive instructions
on the procedures outlined in this SPCC Plan. The instructions cover the contractor activities
such as servicing a well or equipment associated with the well, such as pressure vessels.
All contractual agreements between Clearwater and contractors specifically state:
Personnel must, at all times, act in a manner to preserve life and property, and prevent
pollution of the environment by proper use of the facility's prevention and containment
systems to prevent hydrocarbon and hazardous material spills. No pollutant, regardless of
the volume, is to be disposed of onto the ground or water, or allowed to drain into the
ground or water. Federal regulations impose substantial fines and/or imprisonment for
willful pollution of navigable waters. Failure to report accidental pollution at this facility, or
elsewhere, can be cause for equally severe penalties to be imposed by federal
regulations. To this end, all personnel must comply with every requirement of this SPCC
Plan, as well as taking necessary actions to preserve life, and property, and to prevent
pollution of the environment. It is the contractor's (or subcontractor's) responsibility to
maintain his equipment in good working order and in compliance with this SPCC Plan.
The contractor (or subcontractor) is also responsible for the familiarity and compliance of
his personnel with this SPCC Plan. Contractor and subcontractor personnel must secure
permission from Clearwater's Field Operations Manager before commencing any work on
any facility. They must immediately advise the Field Operations Manager of any
hazardous or abnormal condition so that the Field Operations Manager can take
corrective measures.
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Countermeasure (SPCC) Plan
APPENDIX A: Facility Diagrams
Figure A-1: Site plan.
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Clearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
BOX i. Saftwslw 0)^x»ti Wc-8 Ar«i>
f"".'«V.™*"l ; ^« (:-r:Tllijf
fKWD"5 [- Aj/Rrar
_~l.j : ?.!!
Clearwater OH Company
Big Bear Lease No. 2 Production Facility
Facility Diagram
R&v. 11/1 #02
Figure A-2: Production Facility Diagram.
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Clearwater Oil Company, Ltd. SAMPLE Spill Prevention, Control, and
Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan
APPENDIX B: Tank Truck Loading Procedures
Loading Tank Truck
Make sure the vehicle tank is properly vented before starting to load or unload. If you are not
certain that the trailer is properly vented, you must contact your supervisor and request
permission to open the trailer dome before starting to load or unload.
To Load from Storage Tank to Tank Truck
Attach ground cable or bonding clamp to trailer.
• Use wheel chocks or other similar barrier to prevent premature departure.
Hook up load hose and open all appropriate valves from storage tank to trailer
entry.
Disengage clutch and place pump in load position.
Release clutch slowly.
Adjust throttle to proper engine RPM.
When trailer is loaded to appropriate level, slow engine speed.
• Close valve to storage tank.
Loosen loading hose to allow enough air to drain loading hose dry.
Ensure that drips from the hose drain into the spill bucket at the loading area.
Disconnect loading hose completely, close load valve, plug and fasten securely.
Close belly valve on trailer.
Disconnect ground cable.
Promptly clean up any spilled oil.
Inspect lowermost drains and valves of the vehicle for discharges/leaks and
ensure that they are tightened, adjusted, or replaced as needed to prevent
discharges while vehicle is in transit.
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C/eanvafer Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
APPENDIX C: Monthly Inspection Checklist
Further description and comments, if needed, should be provided on a separate sheet of paper and attached to this
sheet. Any item answered "YES" needs to be promptly reported, repaired, or replaced, as it may result in non-
compliance with regulatory requirements. Records are maintained with the SPCC Plan at the Ridgeview field office.
Date:
Signature:.
Yes
Storage tanks and Separation Equipment
Tank surfaces show signs of leakage
Tanks show signs of damage, rust, or deterioration
Bolts, rivets or seams are damaged
Aboveground tank supports are deteriorated or buckled
Aboveground tank foundations have eroded or settled
Gaskets are leaking
Level gauges or alarms are inoperative
Vents are obstructed
Thief hatch and vent valve does not seal air tight
Containment berm shows discoloration or stains
Berm is breached or eroded or has vegetation
Berm drainage valves are open/broken
Tank area clear of trash and vegetation
Equipment protectors, labels or signs are missing
Piping/Flowlines and Related Equipment
Valve seals or gaskets are leaking.
Pipelines or supports are damaged or deteriorated.
Buried pipelines are exposed.
Transfer equipment
Loading/unloading lines are damaged or deteriorated.
Connections are not capped or blank-flanged
Secondary containment is damaged or stained
Response Kit Inventory
Discharge response material is missing or damaged or
needs replacement
No
Description & Comments
(Note tank/equipment ID)
Additional Remarks (attach sheet as needed):
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Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
APPENDIX D: Record of Dike Drainage
This record must be completed when rainwater from diked areas is drained into a storm drain or into an open
watercourse, lake, or pond, and bypasses the water treatment system. The bypass valve must normally be sealed in
closed position and opened and reseated following drainage under responsible supervision. Records are maintained
with the SPCC Plan at the Ridge view field office.
Date
12/5/2003
Area
Tank battery
Presence of
Oil
No oil
Time Time Signature
Started Finished
08:00 8:40 William Mackenzie
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Ctearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
APPENDIX E: Discharge Prevention Briefing Log
Date
12/5/2003
11/25/2004
Type of Briefing
Instructors)
L 1 1
Scheduled refresher. All field personnel. JHelena Berry, Optimal H&S Inc.
Scheduled refresher. Ail field personnel. [BillLaurjer
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Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
APPENDIX F: Discharge Notification Procedures
Circumstances, instructions, and phone numbers for reporting a discharge to the National
Response Center and other federal, state, and local agencies, and to other affected parties, are
provided below. They are also posted at the facility in the storage shed containing the discharge
response equipment. Note that any discharge to water must be reported immediately to the
National Response Center.
Field Operations Manager, Bill Laurier (24 hours)
Local Emergency (fire, explosion, or other hazards)
(405) 829-4051
911
: Agency /Organization
Federal Agencies
National Response
Center
EPA Region VI
(Hotline)
EPA Region VI
Regional Administrator
State Agencies
Office of State Police,
Transportation and
Environmental Safety
Section, Hazardous
Materials Hotline
Office of State Police,
Transportation and
Environmental Safety
Section, Hazardous
Materials Hotline
Louisiana Department
of Environmental
Quality, Office of
Environmental
Compliance
Agency Contact ;
1-800-424-8802
1-800-887-6063
First Interstate Bank
Tower at Fountain
Place
1445 Ross Avenue,
12lh floor, Suite 1200
Dallas TX 75202
225-925-6595
or
1-877-925-6595
225-925-6595
or
1-877-925-6595
225-763-3908
or 225-342-1 234
(after business
hours, weekends
and holidays)
Circumstances .:•;.;• \ ':.:. • . . ;:•; :;;.:.:
Discharge reaching navigable
waters.
Discharge 1 ,000 gallons or
more; or second discharge of 42
gallons or more over a 1 2-month
period.
1 ) Injury requiring hospitalization
or fatality.
2) Fire, explosion, or other
impact that could affect public
safety.
3) Release exceeding 24-hour
reportable quantity.
4) Impact to areas beyond the
facility's confines.
Discharges that pose
emergency conditions,
regardless of the volume
discharged.
Discharges that do not pose
emergency conditions.
When to NotHy
Immediately (verbal)
Immediately (verbal)
Written notification within
60 days (see Section 2.1 of
this Plan)
Immediately (verbal)
Written notification to be
made within 5 days.
Within 1 hour of discovery
(verbal).
Written notification within 7
working days.
Within 24 hours of
discovery (verbal).
Written notification within 7
working days.
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Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
Agency /Organization
Local Agencies
St. Anthony's Parish
Emergency Planning
Committee
Others
Response/cleanup
contractors
Howard Fleming Farm
(agricultural irrigation
intake)
Agency Contact
337-828-1960
EZ Clean
(800)521-3211
Armadillo Oil
Removal Co.
(214)566-5586
(405) 235-6893
• Circumstances ' : . :
Any discharge of 1 00 Ibs or
more that occur beyond the
boundaries of the facility,
including to the air.
Any discharge that exceeds the
capacity of facility personnel to
respond and cleanup.
Any discharge that threatens to
affect neighboring properties
and irrigation intakes.
When to Notify >
Immediately (verbal)
Written notification within 7
days.
As needed
As needed
The person reporting the discharge must provide the following information:
Name, location, organization, and telephone number;
Name and address of the owner/operator;
• Date and time of the incident;
Location of the incident;
Source and cause of discharge;
• Types of material(s) discharged;
Total quantity of materials discharged;
Quantity discharged in harmful quantity (to navigable waters or adjoining
shorelines);
Danger or threat posed by the release or discharge;
• Description of all affected media (e.g., water, soil);
Number and types of injuries (if any) and damaged caused;
Weather conditions;
• Actions used to stop, remove, and mitigate effects of the discharge;
Whether an evacuation is needed;
* Name of individuals and/or organizations contacted; and
Any other information that may help emergency personnel respond to the
incident.
Whenever the facility discharges more than 1,000 gallons of oil in a single event, or discharges
more than 42 gallons of oil in each of two discharge incidents within a 12-month period, the
Manager of Field Operations must provide the following information to the U.S. Environmental
Protection Agency's Regional Administrator within 60 days:
Name of the facility;
• Name of the owner or operator;
• Location of the facility;
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Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan
• Maximum storage or handling capacity and normal daily throughput;
• Corrective actions and countermeasures taken, including a description of
equipment repairs and replacements;
Description of facility, including maps, flow diagrams, and topographical maps;
• Cause of the discharge(s) to navigable waters, including a failure analysis of the
system and subsystems in which the failure occurred;
Additional preventive measures taken or contemplated to minimize possibility of
recurrence; and
• Other pertinent information requested by the Regional Administrator.
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Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
Discharge Notification Form
*** Notification must not be delayed if information or individuals are not available.
Facility: Clearwater Oil Company Big Bear Lease No. 2 Production Facility
5800 Route 417, Madison. Louisiana 73506
Description of Discharge • ..::..:. y : / : v;J/:.:: • ';•:•'•' ' • ' ::!••:•-.• •' .:'•;;•;•!• :.
Date/time
Reporting Individual
Location of discharge
Equipment source
Product
Appearance and
description
Environmental conditions
Release date:
Release time:
Duration:
Name:
Tel. #:
Latitude:
Longitude:
D piping
D flowline
Dwell
n unknown
D stock, flare
D crude oil
D saltwater
D other*
Wind direction:
Wind speed:
Discovery date:
Discovery time:
Description:
Description:
Equipment ID:
* Describe other:
Rainfall:
Current
• Impacts^ :' . • •::•!•:'!! !'••'•' ' '.:;:;.'. ';; : : ' : : ' : ;-:: i^ : ;':i'-: : •; :':-:::;:. : '. . i-:;:-;: y : :
Quantify
Receiving medium
Released:
D water"
D land
D other (describe):
Recovered:
D Release confined to company property.
Q Release outside company property.
** If water, indicate extent and body of water.
Describe circumstances
of the release
Assessment of impacts
and remedial actions
Disposal method for
recovered material
Action taken to prevent
incident from reoccurring
Safety issues
D Injuries
O Fatalities
D Evacuation
i
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Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
Notifications
Agency
Name
Date/time reported & Comments
Company Spill
Response Coordinator
National Response
Center
1-800-424-8802
State police
Parish Emergency
Response Commission
oil spill removal
organization/cleanup
contractor
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Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention, Control, and
Countermeasure (SPCC) Plan
APPENDIX G: Equipment Shut-off Procedures
Source
Action
Manifold, transfer
pumps or hose failure
Tank overflow
Tank failure
Flowline rupture
Flowline leak
Explosion or fire
Equipment failure
Shut in the well supplying oil to the tank battery if appropriate. Immediately close the
header/manifold or appropriate valve(s). Shut off transfer pumps.
Shut in the well supplying oil to the tank battery. Close header/manifold or appropriate
valve(s)
Shut in the well supplying oil to the tank battery. Close inlet valve to the storage tanks.
Shut in the well supplying oil to the flowline. Close nearest valve to the rupture site to
top the flow of oil.
Shut in the well supplying oil to the flowline. Immediately close the nearest valve to stop
the flow of oil to the leaking section.
Immediately evacuate personnel from the area until the danger is over. Immediately
shut in both wells if safe to do so. If possible, close all manifold valves. If the fire is
small enough such that it is safe to do so, attempt to extinguish with fire extinguishers
available on site.
Immediately close the nearest valve to stop the flow of oil into the leaking area.
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Big Bear Lease No. 2 Production Facility
SAMPLE Spill Prevention. Control, and
Counter-measure (SPCC) Plan
APPENDIX H: Written Commitment of Manpower,
Equipment, and Materials
In addition to implementing the preventive measures described in this Plan, Clearwater will also
specifically:
In the event of a discharge:
• Make available all trained field personnel (three employees) to perform response
actions
Obtain assistance from an additional three full-time employees from its main
operations contractor {Avonlea Services)
• Collaborate fully with local, state, and federal authorities on response and
cleanup operations
Maintain all on-site oil spill control equipment described in this Plan and in the attached
Oil Spill Contingency Plan. The equipment is estimated to contain oil spills of up to 500
gallons.
Maintain all communications equipment in operating condition at all times.
• Ensure that staging areas to be used in the event of a discharge to Big Bear Creek are
accessible by field vehicles.
Review the adequacy of on-site and third-party response capacity with pre-established
response/cleanup contractors on an annual basis and update response/cleanup
contractor list as necessary.
Maintain formal agreements/contracts with response and cleanup contractors who will
provide assistance in responding to an oil discharge and/or completing cleanup (see
contract agreements maintained separately at the Ridgeview field office and lists of
associated equipment and response contractor personnel capabilities).
Authorized Facility Representative:
Signature:
Title:
Bill Laurier
(nill iojj/wt/k
Field Operations Manager
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Ctearwater Oil Company, Ltd. SAMPLE Spill Prevention, Control, and
Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan
APPENDIX I: Oil Spill Contingency Plan
The oil spill contingency plan is maintained separately at the Ridgeview field office.
[Refer to the sample Contingency Plan also available from EPA for more information on the
content and format of that Plan]
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DISCLAIMER -APPENDIX F
The sample Contingency Plan in Appendix F is intended to provide examples of
contingency planning as a reference when a facility determines that the required secondary
containment is impracticable, pursuant to 40 CFR §112.7{d). The sample Contingency Plan
presents a variety of scenarios for purposes of illustration only. It is not a template to be
adopted by a facility; doing so does not mean that the facility will be in compliance with the
SPCC rule requirements for a contingency plan. Nor is the sample plan a template that must be
followed in order for the facility to be considered in compliance with the contingency plan
requirement.
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Clearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility
Oil Spill Contingency Plan
CLEARWATER OIL COMPANY
BIG BEAR LEASE No. 2 PRODUCTION FACILITY
OIL SPILL CONTINGENCY PLAN
NOTE: Throughout this document, shaded
boxes identify relevant sections of 40 CFR
part 109 and part 112.
1.1 Purpose and Scope
PARTI
Introduction
This Oil Spill Contingency Plan is prepared in accordance with 40 CFR 112.7{d) to
address areas of the facility where secondary containment is impracticable, as
documented in the facility Spill Prevention, Control, and Countermeasure (SPCC) Plan.
The purpose of this Oil Spill Contingency Plan ("Contingency Plan") is to define
procedures and tactics for responding to discharges of oil into navigable waters or
adjoining shorelines of the United States, originating more specifically from flowlines at
Clearwater Oil Company ("Clearwater") Big Bear Lease No. 2 Production Facility. The
Contingency Plan is implemented whenever a discharge of oil has reached, or threatens,
navigable waters or adjoining shorelines.
The objective of procedures described in this Contingency Plan is to protect the public,
Clearwater personnel, and other responders during oil discharges. In addition, the Plan
is intended to minimize damage to the environment, natural resources, and facility
installations from a discharge of oil. This Oil Spill Contingency Plan complements the
prevention and control measures presented in the facility's SPCC Plan by addressing
areas of the facility that have inadequate secondary containment and impacts that may
result from a discharge from these areas. The facility implements a detailed and
stringent flowline maintenance program to prevent leaks from the primary system (in this
case, piping). Areas lacking adequate containment at the Big Bear Lease No. 2
Production Facility include the flowlines that run between the extraction wells and the
tank battery area and between the tank battery area and the saltwater disposal area.
This Oil Spill Contingency Plan follows the content and organization of 40 CFR part 109
and describes the distribution of responsibilities and basic procedures for responding to
an oil discharge and performing cleanup operations.
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Clearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility
Oil Spill Contingency Plan
1.2 Resources at Risk
40 CFR 1Q9.5(b){1)
Clearwater's Big Bear Lease No. 2 Production Facility is located approximately 6 miles
North of Madison, LA, within the Mines River watershed (see Figure C-1 in Appendix C).
The waterways closest to the facility are Big Bear Creek, which flows approximately Yz
mile to the east of the facility, and the Mines River, which flows 6 miles to the south in a
west-to-east direction and receives water from Big Bear Creek. The facility diagram
included in Appendix C (Figure C-2) indicates the location of the oil extraction,
production, and storage areas. Ground cover at the facility consists of compacted soil,
gravel, and low lying vegetation. The natural topography of the land is graded in an east-
southeast direction, and all surface drainage from the facility therefore flows towards Big
Bear Creek. The slope is relatively mild: approximately 4 feet vertical per mile (5,280
feet) horizontal.
Three flowlines (which contain oil) at the facility lack adequate secondary containment
(see Figure C-2):
Rowline A. The flowline from Well A to the tank battery (FLA) is approximately
2,100 feet long. It runs aboveground in a north-south direction to the tank battery
area.
Flowline B. The flowline between Well B and the tank battery (FLB) is
approximately 3,400 feet long. It travels in a southwest direction to the tank
battery area. This flowline runs the closest to navigable waters. At the closest
point, the flowline is located Vz mile from Big Bear Creek.
• Flowline SWD. The flowline between the tank battery and the saltwater disposal
well is approximately 2,000 feet long. It runs in an east-west direction.
All three flowlines are aboveground, with the exception of a short portion of Flowline B
that is buried under the dirt/gravel access road. A drainage ditch runs along the access
road to the east of the tank battery and along Route 417. The ditch flows into Big Bear
Creek. Given the direction of surface drainage, a discharge from any of the three
flowlines could reach Big Bear Creek, either directly or via the drainage ditch, and from
there, flow southward to the Mines River.
Neither Big Bear Creek nor the Mines River is used as a public drinking water supply,
although animals grazing on the nearby land are often seen drinking from Big Bear
Creek and the Howard Fleming Farm has an agricultural irrigation intake on Big Bear
Creek (see the Notification Form later in this Plan for contact information). The two
waterways, however, provide habitat for a number of aquatic species and mammals and
are used by local residents for recreational purposes. The Mines River runs through the
center of Madison. Recreational and scenic areas are located on both banks of the river.
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Clearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility Oil Spill Contingency Plan
A public park is located approximately 1 mile east from the town center and 8 miles from
the facility. Recreational uses on the Mines River include picnic areas, walking trails,
canoeing, and nature watching.
There are no residences within the immediate vicinity of the facility. The closest
residence is located 1 mile to the north of the site, upstream on Big Bear Creek. The
closest residence downstream from the site is located 3 miles away. Both residences
have private drinking water wells. Clearwater will coordinate with the Madison fire and/or
police departments and with its residential neighbors to provide the appropriate warnings
in the event of a discharge that could affect public health and safety.
1.3 Risk Assessment
The facility is comprised of approximately 7,500 feet of 2-inch diameter flowlines. With
the exception of a short road crossing, the flowlines are located aboveground. The
flowlines do not have secondary containment, since such containment is impracticable at
this facility (see discussion on impracticability of secondary containment in the facility's
SPCC Plan),
The total daily production rate at the facility varies, but can reach as much as 1,260
gallons of crude oil and 5,880 gallons of produced water. The two wells have
approximately equal production rates (each 3,570 gallons per day). Flowline B, the
longest of the three flowlines and the one closest to navigable waters, contains up to
555 gallons of oil/water when charged. The facility is visited daily. For planning
purposes, the worst-case discharge is therefore the volume of oil within the flowline plus
24 hours of production, or 4,125 gallons.
A discharge of this quantity of oil could potentially reach Big Bear Creek. The velocity of
oil over land is estimated, based on past experience and a simple calculation of flow
over short grass pastureland, at approximately 0.2 feet/second.1 Considering the
distance between Flowline B and Big Bear Creek (Yz mile) and the 2-foot elevation
gradient, the oil, if unimpeded, could reach Big Bear Creek in as little as 4 hours. The
water current in Big Bear Creek averages approximately 0.3 feet/second during high
stages. Over a 24-hour period, the oil could travel approximately 5 miles downstream
from the release point. The Mines River, which is located only 6 miles downstream to the
south of the tank battery area, could therefore possibly be affected by a discharge.
1 Calculated using sheet flow transport equations.
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Clearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility
Oil Spill Contingency Plan
1.4 Response Strategy
Clearwater personnel and contractors are equipped and trained to respond to certain
"minor discharges" confined within the facility. Minor discharges can generally be
described as those where the quantity of product discharged is small, the discharged
material can be easily stopped and controlled, the discharge is localized, and the
product is not likely to seep into groundwater or reach surface water or adjoining
shorelines. Procedures for responding to these minor discharges are covered in the
SPCC Plan.
This Contingency Plan addresses all discharge incidents, including those that affect
navigable waters or during which the oil cannot be safely controlled by facility personnel
and confined within the boundaries of the facility. Response to such incidents may
necessitate the assistance of outside contractors or other responders to prevent
imminent impact to navigable waters.
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Clearwater Oil Company. Ltd.
Big Bear Lease No. 2 Production Facility
Oil Spill Contingency Plan
40CFR109.5(a)
40CFR109.5(d){2}
40CFR1Q9.5(b}(2)
PART II
Spill Discovery and Response
2.1 Distribution of Responsibilities
Clearwater has the primary responsibility for providing the initial response to oil
discharge incidents originating from its facility. To accomplish this, Clearwater has
designated the Field Operations Manager, Bill Laurier, as the qualified oil discharge
Response Coordinator (RC) in the event of an oil discharge.
The RC plays a central coordinating role in any emergency situation, as illustrated in the
emergency organization chart in Figure 2-1.
The RC has the authority to commit the necessary services and equipment to respond to
the discharge and to request assistance from Madison fire and/or police departments,
contractors, or other responders, as appropriate.
The RC will direct notifications and initial response actions in accordance with training
and capabilities. In the event of a fire or emergency situation that threatens the health
and safety of those present at the site, the RC will direct evacuations and contact the fire
and police departments.
In the event of an emergency involving outside response agencies, the RC's primary
responsibility is to provide information regarding the characteristics of the materials and
equipment involved and to provide access to Clearwater resources as requested. The
RC shall also take necessary measures to control the flow of people, emergency
equipment, and supplies and obtain the support of the Madison Police Department as
needed to maintain control of the site. These controls may be necessary to minimize
injuries and confusion.
Finally, the RC serves as the coordinator for radio communications by acquiring all
essential information and ensuring clear communication of information to emergency
response personnel. The RC has access to reference material at the field office either as
printed material or on computer files that can further assist the response activities.
Whenever circumstances permit, the RC transmits assessments and recommendations
to Clearwater Senior Management for direction. Senior Management is contacted in the
following order: (1) Regional Director of Operations; (2) Vice-President of Operations.
In the event that the Field Operations Manager is not available, the responsibility and
authority for initiating a response to a discharge rests with the most senior Clearwater
employee on site at the time the discharge is discovered (Crew Lead) or with the
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Clearwater OH Company, Ltd.
Big Bear Lease No. 2 Production Facility
Oil Spill Contingency Plan
contractor Field Supervisor (or next person in command) if contractor personnel are the
only personnel on site,
VPof Op
$11
Oi! !
!f?»«m j
%£ 1
jffS i
283 i
wt i
•C0_ i
1
c*>*
:;^r
lrn»rg«ncy
Fi*ltt
Coorofnatot
ons Wsna^er
f*85; «-
U,-:ai, S«»te at
P-srsonne!
«^C«*««
Cfesrwale: OB £ZC(asfi Af^J
Figure 2-1. Distribution of response authority and communication.
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Clearwater OH Company, Ltd.
Big Bear Lease No. 2 Production Facility
Oil Spill Contingency Plan
2.2 Response Activities
4QCFR109.5{d)
40CFR109,5(e)
In the event of a discharge, the first priority is to stop the product flow and to shut off alt
ignition sources, followed by the containment, control, and mitigation of the discharge.
This Contingency Plan breaks actions to be performed to respond to an oil discharge
into different phases, described in greater detail in the checklists below.
2.2.1 Discharge Discovery and Source Control
Minor Discharge. A minor discharge (i.e., small volume leak from flowlines or other
equipment) will be discovered by Clearwater facility personnel or by contractor personnel
during scheduled daily or monthly visits to the facility. Aboveground flowlines are visually
inspected formally once a month during the normal inspection rounds.
Major Discharge. A more severe and sudden discharge will trigger the automatic shut
down of the pumping units and will affect oil production. The impact will be detected
during the daily visit to the production area by Clearwater or contractor field personnel.
The maximum amount of time until a major discharge is detected can be up to 24 hours.
Notifications to the National Response Center, Louisiana authorities, and St. Anthony's
Parish Emergency Committee must occur immediately upon discovery of reportable
discharges.
Completed
Actions • :- .;.;; ;; .;':;.;.:; :•;• :.;:::.: .:;.: j' /: •( J.: .:-:::. .I:..;;;. ./...•;.. :::
Immediately report the discharge to the RC, providing the following
• Exact location;
Material involved;
• Quantity involved;
Topographic and environmental conditions;
• Circumstances that may hinder response; and
Injuries, if any.
information:
Turn off all sources of ignition.
Turn off lift pumps that charge or provide flow to the flowline.
Locate the flowline break.
If safe to do so, isolate the affected section of piping by closing off the closest
valves upstream and downstream from the break.
.7.
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Clearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility
Oil Spill Contingency Plan
2.2.2 Assessment and Notifications
Completed
Actions
Investigate the discharge to assess the actual or potential threat to human health
or the environment:
Location of the discharge relative to receiving waterbodies;
Quantity of spilled material;
• Ambient conditions (temperature, rain);
• Other contributing factors such as fire or explosion hazards; and
Sensitive receptors downstream.
Request outside assistance from local emergency responders, as needed.
Evaluate the need to evacuate facility and evacuate employees, as needed.
Notify the fire/police departments and St. Anthony's Parish Emergency Committee
to assess whether community evacuation is needed.
Notify immediately:
911
• National Response Center
Response contractor(s)
St. Anthony's Parish Emergency Planning Committee
State authorities
Communicate with neighboring property owners regarding the discharge and
actions taken to mitigate the damage.
If the oil reaches (or threatens to reach) the Mines River, notify the local fire/police
departments to limit access to the River by local residents until the oil has been
contained and recovered.
Additionally, notify downstream water users of the spill and of actions that will be
taken to protect these downstream receptors.
2.2.3 Control and Recovery
The RC directs the initial control of the oil flow by Clearwater, Avonlea Oil Services, and
other contractor personnel. The actions taken will depend on whether the oil has
reached water or is still on land. All effort will be made to prevent oil from reaching water.
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Big Bear Lease No. 2 Production Facility
Oil Spill Contingency Plan
If the oil has not yet reached water:
Completed
Actions
Deploy sand bags and absorbent socks downgradient from the oil, or erect
temporary barriers such as trenches or mounds to prevent the oil from flowing
towards Big Bear Creek.
Implement land based response actions (countermeasure) such as digging
temporary containment pits, ponds, or curbs to prevent the flow of oil into the
river.
Deploy absorbent sock and sorbent materiai along the shoreline to prevent oil
from entering waters.
if the oil has reached water:
Completed
Actions
Contact cleanup contractor(s).
Deploy floating booms immediately downstream from the release point. Big Bear
Creek is narrow and shallow. Floating boom deployment does not require the use
of a boat.
Control oil flow on the ground by placing absorbent socks and other sorbent
material or physical barriers (e.g., "kitty litter," sandbags, earthen berm, trenches)
across the oil flow path.
Deploy additional floating booms across the whole width of the Creek at the next
access point downstream from the release point. Access points and staging areas
along the shoreline are identified on Figure C-1 of this Contingency Plan.
Deploy protective booming measures for downstream receptors that may be
impacted by the spill.
2.2.4 Disposal of Recovered Product and Contaminated Response Material
The RC ensures that all contaminated materials classified as hazardous waste are
disposed of in accordance with all applicable solid and hazardous waste regulations.
Completed
Actions
Place any recovered product that can be recycled into the gun barrel tank to be
separated and recycled.
Dispose of recovered product not suitable for on-site recycling with the rest of the
waste collected during the response efforts.
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Oil Spill Contingency Plan
Collect alt debris in properly labeled waste containers (impervious bags, drums, or
buckets).
Dispose of contaminated material in accordance with all applicable solid and
hazardous waste regulations using a licensed waste hauler and disposal facility,
after appropriately characterizing the material for collection and disposal.
Dispose of all contaminated response material within 2 weeks of the discharge.
2.2.5 Termination
The RC ensures that cleanup has been completed and that the contaminated area has
been treated or mitigated according to the applicable regulations and state/federal
cleanup action levels. The RC collaborates with the local, state and federal authorities
regarding the assessment of damages.
Completed
Actions
Ensure that all repairs to the defective equipment orflowline section have been
completed.
Review circumstances that led to the discharge and take all necessary
precautions to prevent a recurrence.
Evaluate the effectiveness of the response activities and make adjustments as
necessary to response procedures and personnel training.
Carry out personnel and contractor debriefmgs as necessary to emphasize
prevention measures or to communicate changes in operations or response
procedures.
Submit any required follow-up reports to the authorities.
In the case where the discharge (as defined in 40 CFR 112.1 (b)) was greater than
1,000 gallons or was the second discharge (as defined in 40 CFR 112.1(b)) of 42
gallons or more within any 12-month period, the RC is responsible for submitting
the required information within 60 days to the EPA Regional Admnmtrator
following the procedures outlined in Appendix B.
Within 30 days of the discharge, the RC will convene an incident critique including
all appropriate persons that responded to the spill. The goal of the incident
critique is to discuss lessons learned, the efficacy of the Contingency Plan and its
implementation, and coordination of the plan/RC and other state and local plans.
Within 60 days of the critique, the Contingency Plan will be updated (as needed)
to incorporate the results, findings, and suggestions developed during the critique.
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Clearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility Oil Spill Contingency Plan
2.3 Discharge Notification
Instructions and phone numbers for reporting a discharge to the National Response
Center and other federal, state, and local authorities are provided in Appendix B to this
Plan. Any discharge to water must be reported immediately to the National Response
4Q CFR1Q9 SM2) I Center. The Response Coordinator must ensure that details of the discharge are
* recorded on the Discharge Notification Form provided in Appendix B.
If the discharge qualifies under 40 CFR part 112 (see Appendix B for conditions), the RC
is responsible for ensuring that all pertinent information is provided to the EPA Regional
Administrator.
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Clearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility
Oil Spill Contingency Plan
40CFR109.5(c)(1)
and(c)(2)
40 CFR 109.5(d)(3)
40 CFR 1Q9.5(d)(2)
PART III
Response Resources and Preparedness Activities
3.1 Equipment, Supplies, Services, and Manpower
Spill kits are provided in a storage shed at the production site that is accessible by both
Clearwater and Avonlea personnel (see Figure C-2 in Appendix C). Response
equipment and material present at the site include:
(4) Empty 55-gallons drums to hold contaminated material
(1) 50-fl absorbent socks
(2) 10-ft sections of hard skirted deployment boom
(2) 50-ft floating booms
(200 pounds) "Oil-dry" Loose absorbent material
(4 boxes) 2 ft x 3 ft absorbent pads
(3 boxes) Nitrite gloves
(3 boxes) Neoprene gloves
(6 pairs) Vinyl/PVC pull-on overboots
(3) Non-sparking shovels •
(3) Brooms
(20) Sand bags
(1) Combustible Gas Indicator with H2S detection capabilities
This material is sufficient to respond to most minor discharges occurring at the facility
and to initially contain a major discharge while waiting for additional material or support
from outside contractors. The inventory is verified on a monthly basis during the
scheduled facility inspection by designated personnel and is replenished as needed.
Additional material and equipment is kept at Clearwater's field office, located 25 miles
from the facility. This additional material includes empty storage drums, absorbent socks
and booms, containment booms, sand bags, personal protective gear, etc. It also
includes all necessary communication equipment to coordinate response activities (cell
phones, two-way radios). The Field Office serves as the response operation center
during a response.
Clearwater has three employees trained and available to respond to an oil discharge.
Clearwater personnel may be assisted by three additional employees from the facility's
main contractor, Avonlea Oil Services. All employees are familiar with the facility layout,
location of spill response equipment and staging areas, and response strategies, and
with the SPCC and Oil Spill Contingency Plans for this facility. All have received training
in the deployment of response material and handling of hazardous waste (HAZWOPER)
and have attended the required refresher courses.
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Clearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility
Oil Spill Contingency Plan
40 CFR 1Q9.5(c)(3)
To respond to larger discharges and ensure the removal and disposal of cleanup debris,
Clearwater has established agreements with two specialized cleanup contractors:
EZCIean and Armadillo Oil Removal, with EZCIean contacted first and acting as the
primary response/cleanup contractor and Armadillo Oil Removal acting as the alternate
or in a supporting role. Contact information is provided in Appendix A. These contractors
have immediate access to an assortment of equipment and materials, including
mechanical recovery equipment for use on water and on land, small boats, floating
booms, and large waste containers. Each contractor has sufficient response equipment
to contain and recover the maximum possible discharge of 4,125 gallons. EZCIean and
Armadillo Oil Removal are able to respond within 4 hours of receiving a verbal request
from the RC. Clearwater discusses response capacity needs on an annual basis with
each contractor to ensure that sufficient equipment and material are available to respond
to a potential 4,125-gallon discharge. The inventories of EZCIean and Armadillo Oil
Removal equipment are maintained with the response agreements and updated
annually.
3.2 Access to Receiving Waterbody
40 CFR 109.5(d)(5)
Big gear Creek would be the first waterbody affected
in the event of a discharge. From there, the oil would
flow into the Mines River. The response strategy
consists of: (1) deploying booms and other response
equipment at various points downstream from the oil
plume to prevent its migration; and (2) deploying
booms as a protective measure for an irrigation water
intake and other downstream sensitive receptors.
Vehicular access to Big Bear Creek is essential to
ensure that the response equipment can be effectively
deployed to contain oil at various points along the
waterway and prevent further migration of the oil
towards the Mines River.
Three access points have been established along Big
Bear Creek and are marked on the map in Figure C-1
(BB1, BB2, and BBS). These access points provide
sufficient cleared land for a staging area from which
Clearwater or contractor personnel can deploy
response equipment, and recover and store spilled oil.
Twice a year, as part of the monthly inspection of the
facility, Clearwater facility personnel drive to each
access point and make sure that it remains
accessible (e.g., vegetation is not overgrown and the
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Figure 3-2: Boom deployed
across Big Bear Creek.
Figure 3-3: Boom deployed at
Route 54 bridge crossing.
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Clearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility
Oil Spill Contingency Plan
dirt trail is not impassable for a field vehicle). The respective property owners have agreed to
allow access to Clean/water's personnel and contractors for response and maintenance
purposes. Although no further approval is needed prior to the deployment of response
equipment, the RC will contact the property owners as necessary to inform them of activities
being carried out.
If necessary, three access points are also available along the Mines River. One is
located in the center of Madison, at the bridge crossing for Route 101, the second is
located at the public park two miles downstream from the center, and the third one is
located at the bridge crossing for Route 54, four miles downstream from the center.
Coordination with the Madison police/fire departments is necessary to stage equipment
at these three access points.
3.3 Communications and Control
4QCFR109.5(b){3)
40CFR109.5((i)(3)
A central coordination center will be set up at the field office in the event of a discharge.
The field office is equipped with a variety of fixed and mobile communication equipment
(telephone, fax, cell phones, two-way radios, computers) to ensure continuous
communication with Clearwater management, responders, authorities, and other
interested parties.
Communications equipment includes:
Portable hand-held radios. Clearwater maintains a two-way base station and
four portable radio units. These radio units are kept at the field office as part of
the response equipment. Local emergency responders have been provided with
the response frequencies that will be used during an incident.
Cell phones. Each field vehicle and the RC are provided with a cell phone. The
RC and/or his alternate (Site Supervisor when the Field Operations Manager is
not "on calf) can be reached by cell phone 7 days a week, 24 hours a day.
Additional equipment. Additional equipment will be obtained from EZCIean
and/or Armadillo Oil Removal in the event that more communications equipment
is necessary.
The RC is responsible for communicating the status of the response operations and for
sharing relevant information with involved parties, including local, state, and federal
authorities.
In the event that local response agencies, Louisiana authorities, or a federal On Site
Coordinator (OSC) assumes Incident Command, the RC will function as the facility
representative in the Unified Command structure.
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Ctearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility Oil Spill Contingency Plan
3.4 Training Exercises and Updating Procedures
Clearwater has established and maintains an ongoing training program to ensure that
40 CFR iQ9.5(d){l) j Clearwater personnel responding to oil discharges are properly trained and that all
necessary equipment is available to them. The program includes on-the-job training on
the proper deployment of response equipment and periodic practice drills during which
Clearwater personnel are asked to deploy equipment and material in response to a
simulated discharge. The RC is responsible for implementing and evaluating employee
preparedness training.
Following a response to an oil discharge, the RC will evaluate the actions taken and
identify procedural areas where improvements are needed. The RC will conduct a
briefing with field personnel, contractors, and local emergency responders to discuss
lessons learned and will integrate the outcome of the discussion in subsequent SPCC
briefings and employee training seminars. As necessary, the RC will amend this
Contingency Plan or the SPCC Plan to reflect changes made to the facility equipment
and procedures. A Professional Engineer will certify any technical amendment to the
SPCC Plan.
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Ctearwater Oil Company, Ltd,
Big Bear Lease No. 2 Production Facility
Oil Spill Contingency Plan
40 CFR 109.5(b)(2)
APPENDIX A
EMERGENCY CONTACTS
Facility Operations
Name
Bill Laurier
Carol Campbell
Lester Pearson
Joe Clark
William Mackenzie
•':-:TWe: : : !':"!i:
Field Operations
Manager
Clearwater Oil Co.
Regional Director of
Operations
Clearwater Oil Co.
Vice-President of
Operations
Clearwater Oil Co.
Field Supervisor
Avonlea Services, Inc.
Pumper
Avonlea Services, Inc.
Telephone : : ^\^\ •;;:•:. ;
(405) 831 -6322 (office)
(405) 829-4051 (cell)
(405) 831 -6320 (office)
(405) 831 -2262 (cell)
(555)-289-4500
(406) 545-2285 (office)
(406) 549-9087 (cell)
(406) 549-9087 (cell)
• : Address •::- • . : • • •
2451 Mountain Drive
Ridgeview, LA 701 80
2451 Mountain Drive
Ridgeview, LA 701 80
13000 Main Street, Suite
400
Houston, TX 77077
786 Cherry Creek Road
Avonlea, LA 70180
786 Cherry Creek Road
Avonlea, LA 701 80
Local Emergency Responders
-/Name. • • • . .. ;j--.: .
Fire/Police Departments
Emerson Hospital
Telephone
911
(405) 830-2000
(405)831-9558
'.. Address • • :.-.;•;;.•:.;;.: : • • • :'• :.;.:•;/ •.•••. :
2451 Mountain Drive, Madison, LA 70180
13000 Main Street, Madison, LA 70180
Cleanup Contractors
Name •. '.' :'::^\'-
EZCIean
Armadillo Oil Removal
Telephone^ ; ;;
(800) 521 -321 1
(214)566-5588
:: 'Address : ;:;;:-:: •;•:;: ..•;•: •; ;- : ;'-- :::Q':.. :•;•':;• : :- -: '.
1200 Industry Park Drive, Gardner, LA 70180
25 B Street, Suite #6, Madison. LA 70180
Neighboring Property Owners
•flfiame : :'/••;
Maurice Richard
Jim Larouche
Peter Martin
Howard Fleming
; vH^yFetephone : :":••
(405)830-2186
(405) 832-2645
(405) 832-5527
(405) 235-6893
Address . .:: •. . • :': :: ::•.:-:-:':-::•-::.;:.:
5540 Route 417, Madison, LA 70180
6075 Greenfield Drive, Madison, LA 70180
1644 Oilfield Road, Madison, LA 70180
531 Horseshoe Road, Madison, LA 70180
Sv-'ilocirtion • • :
BB1
BB2
BB3
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C/eanvafer O/7 Company, Ltd.
Big Bear Lease No. 2 Production Facility
Oil Spill Contingency Plan
APPENDIX B
DISCHARGE NOTIFICATION PROCEDURES
Circumstances, instructions, and phone numbers for reporting a discharge to the National
Response Center and other federal, state, and local agencies, and to other affected parties, are
provided below. They are also posted at the facility in the storage shed containing the discharge
response equipment. Note that any discharge to water must be reported immediately to the
National Response Center.
Field Operations Manager, Bill Laurier (24 hours)
Local Emergency (fire, explosion, or other hazards)
(405) 829-4051
911
Agency / Organization
Federal Agencies
National Response
Center
EPA Region VI
(Hotline)
EPA Region VI
Regional Administrator
State Agencies
Office of State Police,
Transportation and
Environmental Safety
Section, Hazardous
Materials Hotline
Office of State Police,
Transportation and
Environmental Safety
Section, Hazardous
Materials Hotline
Agency Contact •
1 -800-424-8802
1-800-887-6063
First Interstate Bank
Tower at Fountain
Place
1 445 Ross Avenue,
12lh floor, Suite 1200
Da lias TX 75202
225-925-6595
or
1-877-925-6595
225-925-6595
or
1-877-925-6595
Circumstances
Discharge reaching navigable
waters.
Discharge 1 ,000 gallons or
more; or second discharge of 42
gallons or more over a 1 2-month
period.
1) Injury requiring hospitalization
or fatality.
2) Fire, explosion, or other
impact that could affect public
safety.
3) Release exceeding 24-hour
reportable quantity.
4) Impact to areas beyond the
facility's confines.
Discharges that pose
emergency conditions,
regardless of the volume
discharged.
When to Notify
Immediately (verbal)
Immediately (verbal)
Written notification within
60 days (see Section 2.1 of
this Plan)
Immediately (verbal)
Written notification to be
made within 5 days.
Within 1 hour of discovery
(verbal).
Written notification within 7
working days.
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A Clearwater Oil Company, Ltd.
til Big Bear Lease No. 2 Production Facility
Oil Spill Contingency Plan
Agency / Organization
Louisiana Department
of Environmental
Quality, Office of
Environmental
Compliance
Local Agencies
St. Anthony's Parish
Emergency Planning
Committee
Otters
Response/cleanup
contractors
Howard Fleming Farm
(agricultural irrigation
intake)
Maurice Richard
Jim Larouche
Peter Martin
Agency Contact
225-763-3908
or 225-342-1 234
(after business
hours, weekends
and holidays)
337-828-1960
EZCtean
(800)521-3211
Armadillo Oil
Removal Co.
(21 4) 566-5588
(405) 235-6893
405-830-2186
405-832-2645
405-832-5527
Circumstances' ; :
Discharges that do not pose
emergency conditions
Any discharge of 1 00 Ibs or
more that occurs beyond the
boundaries of the facility,
including to the air.
Any discharge that exceeds the
capacity of facility personnel to
respond and clean up.
Any discharge that threatens to
affect neighboring properties
and irrigation intakes.
When deploying response
equipment from Access Point
BB1 on Big Bear Creek.
When deploying response
equipment from Access Point
BB2 on Big Bear Creek.
When deploying response
equipment from Access Point
BBS on Big Bear Creek.
When to Notify o!
Within 24 hours of
discovery (verbal).
Written notification within 7
working days.
Immediately (verbal)
Written notification within 7
days.
As needed
As needed
As needed
As needed
As needed
The person reporting the discharge must provide the following information:
Name, location, organization, and telephone number
* Name and address of the owner/operator
Date and time of the incident
Location of the incident
Source and cause of discharge
Types of materials) discharged
Total quantity of materials discharged
Quantity discharged in harmful quantity (to navigable waters or adjoining
shorelines)
Danger or threat posed by the release or discharge
Description of all affected media (e.g., water, soil)
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Clearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility
Oil Spill Contingency Plan
• Number and types of injuries (if any) and damaged caused
Weather conditions
Actions used to stop, remove, and mitigate effects of the discharge
* Whether an evacuation is needed
Name of individuals and/or organizations contacted
• Any other information that may help emergency personnel respond to the
incident
Whenever the facility discharges more than 1,000 gallons of oil in a single event, or discharges
more than 42 gallons of oil in each of two discharge incidents within a 12-month period, the
Manager of Field Operations must provide the following information to the U.S. Environmental
Protection Agency's Regional Administrator within 60 days:
Name of the facility
Name of the owner or operator
Location of the facility
• Maximum storage or handling capacity and normal daily throughput
• Corrective actions and countermeasures taken, including a description of
equipment repairs and replacements
Description of facility, including maps, flow diagrams, and topographical maps
Cause of the discharge(s) to navigable waters, including a failure analysis of the
system and subsystems in which the failure occurred.
• Additional preventive measures taken or contemplated to minimize possibility of
recurrence
Other pertinent information requested by the Regional Administrator.
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C/earwafer O/7 Company, Ltd.
Big Bear Lease No. 2 Production Facility
Oil Spill Contingency Plan
Discharge Notification Form
*** Notification must not be delayed if information or individuals are not available. Additional pages may be attached to
supplement information contained in the form.
Facility: Clearwater Oil Company Big Bear Lease No. 2 Production Facility
5800 Route 417
Madison, Louisiana 73506
Description of Discharge
Date/time
Reporting Individual
Location of discharge
Equipment source
Product
Appearance and
description
Environmental conditions
Impacts ' ' •::;;' .^:-;- V^
Release date:
Release time:
Duration:
Name:
Latitude:
Longitude:
Q piping
D flowline
Dwell
D unknown
D stock, flare
D crude oil
D saltwater
D other*
Wind direction:
Wind speed:
Discovery date:
Discovery time:
Tel. #:
Description:
Description:
Equipment ID:
* Describe other:
Rainfall:
Current
Quantity
Released:
Recovered:
Receiving medium
Describe circumstances
of the release
D water"
IHIand
D other (describe):
D Release confined to company property.
D Release outside company property.
** If water, indicate extent and body of water:
Assessment of impacts
and remedial actions
Disposal method for
recovered material
Action taken to prevent
incident from reoccurring
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Clearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility
Oil Spill Contingency Plan
Safety issues
D Injuries
Q Fatalities
D Evacuation
Notifications
Agency
Name
Date/time reported & Comments
Company Spill
Response Coordinator
National Response
Center
1-800-424-8802
State police
Parish Emergency
Response Commission
OSRO/cleanup
contractor
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Clearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility
Oil Spill Contingency Plan
Appendix C
SITE PLAN AND FACILITY DIAGRAM
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r\ I *^
-------
Ctearwater Oil Company, Ltd.
Big Bear Lease No. 2 Production Facility
Oil Spill Contingency Plan
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Clearwater Oil Company
Big dear Lease No. 2 Production Facility
Facittty Diagram
Rev.'11/12/02
Figure C-2: Facility Diagram.
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U.S. ENVIRONMENTAL PROTECTION AGENCY
SPCC FIELD INSPECTION AND PLAN REVIEW CHECKLIST
FOR USE AT ONSHORE FACILITIES (EXCLUDING PRODUCTION)
Overview of the Checklist
This checklist is designed to assist EPA inspectors in conducting a thorough and consistent
inspection of a facility's compliance with the Spill Prevention, Control, and Countermeasure
(SPCC) rule at 40 CFR part 112. It is a tool to help federal inspectors (or their contractors)
record observations during the site visit and review of the SPCC Plan. While the checklist is
comprehensive, the inspector should always refer to the SPCC rule in its entirety, the SPCC
Regional Inspector Guidance Document, and other relevant guidance for evaluating
compliance. This checklist must be completed in order for an inspection to count toward an
agency measure (i.e., OEM/OECA inspection measures or GPRA).
The checklist is organized according to the SPCC rule. Each item in the checklist identifies the
relevant section and paragraph in 40 CFR part 112 where that requirement is stated.
Sections 112.1 through 112.5 specify the applicability of the rule and requirements for the
preparation, implementation, and amendment of SPCC Plans. For these sections, the checklist
includes data fields to be completed, as well as several questions with "yes" or "no" answers.
Sections 112.7 through 112.12 specify requirements for spill prevention, control, and
countermeasures. For these sections, the inspector needs to evaluate whether the requirement
is addressed adequately or inadequately in the SPCC Plan and whether it is implemented
adequately in the field (either by field observation or record review). For the SPCC Plan and
implementation in the field, if a requirement is addressed adequately, mark the "Yes" box in the
appropriate column. If a requirement is not addressed adequately, mark the "No" box. If a
requirement does not apply to the particular facility, mark the "NA" box. If a provision of the rule
applies only to the SPCC Plan, the "Field" column is shaded.
Space is provided in each section to record comments. Additional space is available on the
comments page at the end of the checklist. Comments should remain factual and support the
evaluation of compliance.
Appendix A is for recording information about containers and other locations at the facility that
require secondary containment.
Appendix B is a checklist for documentation of the tests and inspections the facility operator is
required to keep with the SPCC Plan.
Appendix C is a checklist for oil removal contingency plans. A contingency plan is required if a
facility determines that secondary containment is impracticable as provided in 40 CFR 112.7(d).
Onshore Facilities {Excluding Production)
Page 1 of 16
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U.S. ENVIROMMENTAL PROTECTION AGENCY
SPCC FIELD INSPECTION AND PLAN REVIEW CHECKLIST
FOR USE AT ONSHORE FACILITIES (EXCLUDING PRODUCTION)
FAOllJT* INFORMATION
FACILITY NAME:
ADDRESS:
LAT:
CITY:
TELEPHONE:
STATE: | ZIP:
FACILITY REPRESENTATIVE NAME:
COUNTY:
LONG:
OWNER NAME:
OWNER ADDRESS:
CITY:
TELEPHONE:
STATE:
ZIP:
OWNER CONTACT PERSON:
FACILITY OPERATOR NAME (IF DIFFERENT FROM OWNER - IF NOT, PRINT "SAME"):
OPERATOR ADDRESS:
STATE:
CITY:
TELEPHONE:
ZIP:
OPERATOR CONTACT PERSON:
FACILITY TYPE:
HOURS PER DAY FACILITY ATTENDED:
TYPE(S) OF OIL STORED:
NAICS CODE:
TOTAL FACILITY CAPACITY:
IS FACILITY LOCATED IN INDIAN COUNTRY? D YES D NO IF YES, RESERVATION NAME:
INSPECTION DATE:
LEAD INSPECTOR:
TIME:
INSPECTION NUMBER.
OTHER INSPECTOR(S):
INSPECTOR ACKNOWLEDGMENT
/ performed an SPCC inspection at the fscility specified above.
INSPECTOR SIGNATURE:
DATE:
Onshore Facilities (Excluding Production)
Page 2 of 16
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T&ClLff YfcESPONSE PLAN (FRP) APPLICABILITY
A non-transportation related onshore facility is required to prepare and implement an FRP as outlined in 40 CFR 112.20 if:
D The facility transfers oil over water to or from vessels and has a total oil storage capacity greater than or equal to 42,000 gallons,
OR
The facility has a total oil storage capacity of at least 1 million gallons, and at least one of the following is true:
D The facility does not have secondary containment sufficiently large to contain the capacity of the largest aboveground tank plus
sufficient freeboard for precipitation.
O The facility is located at a distance such that a discharge could cause injury to fish and wildlife and sensitive environments.
D The facility is located such that a discharge would shut down a public drinking water intake.
D The facility has had a reportable discharge greater than or equal to 10,000 gallons in the past 5 years.
Facility has FRP: D Yes D No D Not Required
FRP Number:
Facility has a completed and signed copy of Appendix C, Attachment C-ll, "Certification of the Applicability of the Substantial Harm
Criteria." D Yes D No
Comments:
GENERAL APPLICABILITY^*) CFR 112;1
IS THE FACILITY REGULATED UNDER 40 CFR part 112?
The completely buried oil storage capacity is over 42,000 gallons, OR the aggregate aboveground oil storage capacity is over 1,320
gallons Q Yes D No AND
The facility is a non-transportation-related facility engaged in drilling, producing, gathering, storing, processing, refining, transferring,
distributing, using, or consuming oil and oil products, which due to its location could reasonably be expected to discharge oil into or
upon the navigable waters of the United States (as defined in 40 CFR 110.1). D Yes D No
AFFECTED WATERWAY(S):
PATH:
DISTANCE:
Note: The following storage capacity is not considered in determining applicability ofSPCC requirements:
Completely buried tanks subject to all the technical requirements of 40 CFR part 280 or a state program approved under 40 CFR part 281.
Equipment subject to the authority of the U.S. Department of Transportation, U.S. Department of the Interior, or Minerals Management Service,
as defined in Memoranda of Understanding dated November 24, 1971, and November 8, 1993.
Any facility or part thereof used exclusively for o/astewater treatment (production, recovery or recycling of oil is not considered wastewater
treatment).
* Containers smaller man 55 gallons.
' Permanently closed containers.
Does the facility have an SPCC Plan?
Comments:
Q Yes DNo
REQUlREMeNTS F Oft PjtEPARAtidM AMD IMPLEMENTATION
112.3
Date facility began operations:
Date of initial SPCC Plan preparation:
Current plan version (date/number):
112.3(a)
For facilities in operation prior to August 16, 2002:
Plan amended by February 17, 2006
O Yes D No D NA
• Amended Plan implemented by August 18, 2006
For facilities beginning operation between August 17, 2002, and August 18,
2006, Plan prepared and fully implemented by August 18, 2006
D Yes D No D NA
D Yes D No D NA
Onshore Facilities (Excluding Production)
Page 3 of 16
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RE<&ftl^Efri Fi« f RlPAR/iTiQN MJb iMPiEMfeNf /itliJN & A SNc f L4N--4P; C|R
1 12.3(b) For facilities beginning operation after August 18, 2006, Plan prepared and fully
& (c) implemented before beginning operations
112.3
DYes DNo
DNA
112.3(d) Professional Engineer certification includes statement that the PE attests:
• PE is familiar with the requirements of 40 CFR part 112 D Yes D No
• PE or agent has visited and examined the facility D Yes D No
• Plan is prepared in accordance with good engineering practice including consideration of
applicable industry standards and the requirements of 40 CFR part 1 12 D Yes D No
• Procedures for required inspections and testing have been established D Yes D No
• Plan is adequate for tie facility D Yes D No
PE Name: I License No.: State: Date of certification:
1 1 2.3(e) Plan available onsite if facility is attended at least 4 hours/day
(If located at nearest field office, please note contact information below)
DYes DNo
DNA
Comments:
AMESII2pgJMT;O£Sp^^ -^ ;i '-ii' IU?H J:- -^ ;f :
1 12.4(a) Has the facility discharged a re portable quantity of oil in amounts considered harmful: more
than 1 ,000 gallons of oil ina single discharge or more than 42 gallons in each of two
discharges in any 12-month period (see 40 CFR part 1 10)?
• If yes. was information submitted to the RA as required in §1 1 2.4(a)?
• Date(s) of reportable dischargers):
• Were they reported to the NRC?
112.4(d), (e) Have changes required by the RA been implemented in the Plan and/or facility?
Comments:
DYes DNo
D Yes DNo
DYes D No
DYes DNo
D NA
DNA
DNA
Al|ENpttENT$F$PN ^ 5 ^
1 12.5(a) Has there been a change at the facility that materially affects the potential for a discharge?
• If so, was the Plan amended within six months of the change?
DYes DNo
D Yes DNo
112. 5(b) Review and evaluation of the Plan documented at least once every 5 years? D Yes D No
• Following Plan review, and if amendment was required, was Plan amended within six D Yes D No
months to include more effective prevention and control technology, if available?
112.5(c) Professional Engineer certification of any technical Plan amendments in accordance with D Yes O No
§112.3(d)
Name: License No.: ] State: Date of certification:
Reason for amendment:
Amendments implemented within six months of any Plan amendment
D Yes DNo
DNA
DNA
DNA
DNA
DNA
DNA
Comments:
Onshore Facilities (Excluding Production)
Page 4 of 16
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INDICATE IF ITEM IS ADDRESSED ADEQUATELY (Yes), INADEQUA TEL Y (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
REQUIREMENTS—40 CFR 112.7
PLAN FIELD
Management approval at a level of authority to commit the necessary resources to fully implement the Plan D Yes D No
Name:
Title:
Plan follows sequence of the rule or provides a cross-reference of requirements in the Plan and the rule
Date:
D Yes
[UNo
If Plan calls for facilities, procedures, methods, or equipment not yet fully operational, details of their installation
and start-up are discussed (Note: Relevant for inspection evaluation and testing baselines.)
I
112.7(a){2) ] If there are deviations from the requirements of the rule, the Plan states reasons for
' nonconformance
Alternative measures described in detail and provide equivalent environmental protection (Note:
Inspector should document if the environmental equivalence is implemented in the field)
OYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
Describe each deviation and reasons for nonconformance:
112.7(a)(3) Plan includes diagram with location and contents of all regulated containers (including completely
buried tanks otherwise exempt from the SPCC requirements), transfer stations, and connecting
pipes
112.7(a)(3) Plan addresses each of the following:
DYes
DNo
DNA
(i) For each container, type of oil and storage capacity (see Appendix A)
(ii) Discharge prevention measures, including procedures for routine handling of products
(iii) Discharge or drainage controls, such as secondary containment around containers, and other
structures, equipment, and procedures for the control of a discharge
(iv) Countermeasures for discharge discovery, response, and cleanup (both facility's and contractor's
resources)
(v) Methods of disposal of recovered materials in accordance with applicable legal requirements
(vi) Contact list and phone numbers for the facility response coordinator, National Response Center,
cleanup contractors contracted to respond to a discharge, and all Federal, State, and local agencies
who must be contacted in the case of a discharge as described in §112.1 (b)
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
UNA
DYes
DNo
DNA
D Yes
DNo
ONA
Comments:
DYes
DNo
DNA
OYes
DNo
DNA
D Yes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
Onshore Facilities (Excluding Production)
Page 5 of 16
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INDICATE IF ITEM IS ADDRESSED ADEQUA TEL Y (Yes). INADEQUA TEL Y (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
GENERAL SPCC REQUfREMENTS—40 CFR 112,7
PLAN FIELD
112.7(a)(4) Plan includes information and procedures that enable a person reporting a discharge as described
in §112.1 (b) to relate information on the exact address or location and phone number of the facility;
the date and time of the discharge: the type of material discharged: estimates of the total quantity
discharged; estimates of the quantity discharged as described in §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; actions being used to stop, remove, and mitigate the effects of the
discharge; whether an evacuation may be needed; and the names of individuals and/or
organizations who have also been contacted (Not required if a facility has an FRP)
112.7(a)(5) Plan organized so that portions describing procedures to be used when a discharge occurs will be
readily usable in an emergency (Not required if a facility has an FRP}
D Yes
DNo
DNA
DYes
DNo
DNA
112.7(b) Plan includes a prediction of the direction, rate of flow, and total quantity of oil that could be
discharged for each type of major equipment failure where experience indicates a reasonable
potential for equipment failure
DYes
DNo
DNA
112.7(c) Appropriate containment and/or diversionary structures provided to prevent a discharge as
described in §112.1 (b) before cleanup occurs. The entire containment system, including walls and
floors, are capable of containing oil and are constructed to prevent escape of a discharge from the
containment system before cleanup occurs. (1) For onshore facilities, one of the following or its
equivalent: (i) dikes, berms, or retaining walls sufficiently impervious to contain oil, (ii) curbing, (iii)
culverting, gutters or other drainage systems, (iv) weirs, booms or other barriers, (v) spill diversion
ponds, (vi) retention ponds, or (vii) sorbent materials (See Appendix A)
112.7(d) Determination(s) of impracticability of secondary containment
If YES, is the impracticability of secondary containment clearly demonstrated?
a Yes
a NO
DNA
DYes
QNo
DYes
DNo
DNA
Comments concerning impracticability determination(s) for secondary containment:
If impracticability determination is made, for bulk storage containers, periodic integrity testing of
containers and leak testing of the valves and piping associated with the container is conducted
If impracticability determination is made, unless facility has FRP:
(1) Contingency Plan following 40 CFR part 109 (see Appendix C checklist) is provided AND
(2) Written commitment of manpower, equipment, and materials required to control and remove
any quantity of oil discharged that may be harmful
112.7(e) Inspections and tests conducted in accordance with written procedures
Record of inspections or tests signed by supervisor or inspector and kept with Plan for at least 3
years (see Appendix B checklist)
Q Yes
a NO
DNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
Comments:
DYes
a NO
DNA
DYes
DNo
DNA
D Yes
D No
DNA
DYes
ONo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
Onshore Facilities (Excluding Production)
PageS of 16
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INDICATE IF ITEM IS ADDRESSED ADEQUATELY (Yes). INADEQUA TEL Y (No). OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
tScNtRAL SrCC KtQUJREMtNTS— 40 CFR 11 2.7: ^ : : •' ' : • ' •• '*. '•• i;^f- • . ....... •.-.?•:'••:". ; . : . .: :. :-...::.v.:. •:•"''
>M$-:.-:
FIELD
11 2.7(f) Personnel, training, and oil discharge prevention procedures
(1 ) Training of oil-handling personnel in operation and maintenance of equipment to prevent discharges;
discharge procedure protocols; applicable pollution control laws, rules and regulations; general facility
operations; and contents of SPCC Plan
(2) Person designated as accountable for discharge prevention at the facility
(3) Discharge prevention briefings conducted at least once a year for oil handling personnel
1 12.7(g) Security (excluding production facilities)
(1 ) Facility fully fenced and gates are locked and/or guarded when facility is unattended
(2) Master flow and drain valves and any other valves permitting direct outward flow of the container's
contents to the surface have adequate security measures so that they remain in the closed position when
in non-operating or non-standby status
(3) Pump starter controls locked in "off" position and accessible only to authorized personnel when in non-
opera ting/non-standby status
(4) Loading/unloading connections of oil pipelines or facility piping securely capped or blank-flanged when not
in service or when in standby service for an extended period of time, including piping that is emptied of
liquid content either by draining or by inert gas pressure
(5) Adequate facility lighting commensurate with the type and location of the facility that assists in the
discovery of discharges occurring during hours of darkness and to prevent discharges occurring through
acts of vandalism
1 12.7(h) Tank car and tank truck loading/unloading rack*
{1} Does loading/unloading area (the location adjacent to the loading or unloading rack) drainage flow to
catchment basin or treatment facility? D Yes n No
• If NO, quick drainage system used
Containment system holds capacity of the largest single compartment of a tank car/truck
loaded/unloaded at the facility
(2) Physical barriers, warning signs, wheel chocks, or vehicle brake interlock system in loading/unloading
areas (the location adjacent to the loading or unloading rack) to prevent vehicles from departing before
complete disconnection of flexible or fixed oil transfer lines
(3) Lower-most drains and all outlets on tank cars/trucks inspected prior to filling/departure, and, if necessary
ensure that they are tightened, adjusted, or replaced to prevent liquid discharge while in transit
DYes
ONo
DNA
O Yes
ONo
DNA
DYes
DNo
DNA
DYes
DNO
DMA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
QNo
DNA
DYes
GNo
ONA
DYes
DNo
DNA
DYes
DNo
UNA
DYes
Q No
DNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
D No
DNA
DYes
DNo
DNA
DYes
DNo
DNA
D Yes
DNo
DNA
D Yes
DNo
DNA
DYes
DNo
DNA
Q Yes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
O Yes
LiNo
UNA
D Yes
DNo
DNA
Comments:
* Note that a tank car/truck loading/unloading rack must be present for §1 12.7(h) to apply
Onshore Facilities (Excluding Production)
Page 7 of 16
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112.7
li iPUWAi «F»EOC
112,7(i) Brittle fracture evaluation of field-constructed aboveground containers
112.7(i) Brittle fracture evaluation is conducted after tank repair/alteration/change in service that might affect
the risk of a discharge or after a discharge/failure due to brittle fracture or other catastrophe, and
appropriate action taken as necessary (for field-constructed aboveground containers)
112.7(j) State rules, regulations and guidelines and conformance with applicable sections of 40 CFR part 112
DYes
O NO
ONA
112.7(j) Discussion of conformance with applicable more stringent State rules, regulations, and guidelines and
other effective discharge prevention and containment procedures listed in 40 CFR part 112
Comments:
DYes
DNo
DMA
DYes
DNo
DNA
QSNSHORJE ilpJTIES (i^LUOINS PRODUCTION}—112.8/112,12
PtAN
FIELD
112.8(b)/112.12(b) Facility Drainage
(1) Drainage from diked storage areas is restrained by valves, OR manually activated pumps or ejectors are
used and the condition of the accumulation is inspected prior to discharge to ensure no oil will be
discharged.
(2) Valves from diked storage areas are manual, open-and-closed design (not flapper-type drain valves)
If drainage is released directly to a watercourse and not into an onsrte waste water treatment plant, storm
water inspected per§112.8(c)(3)(ii), (iii), and (iv)or §112.12(c)(3)(ii), (iii), and (iv)
(3) Drainage from undiked areas with a potential for discharge designed to flow into ponds, lagoons, or
catchment basins to retain oil or return it to facility. Catchment basin located away from flood areas.*
(4) If facility drainage not engineered as in (b)(3), facility equipped with a diversion system to retain oil in the
facility in the event of a discharge*
DYes
DNo
DNA
D Yes
DNo
DNA
DYes
ONo
DNA
DYes
DNo
DNA
Q Yes
O No
DNA
(5) Are facility drainage waters continuously treated in more than one treatment unit and pump transfer is needed?
D Yes D No If YES:
Two "lift" pumps available and at least one permanently installed
Facility drainage systems engineered to prevent a discharge as described in §112.1 (b) in the case of
equipment failure or human error
DYes
DNo
DNA
DYes
ONo
DNA
Comments:
* These provisions apply only when a facility drainage system is used for containment.
DYes
DNo
DNA
D Yes
D No
DNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
Onshore Facilities (Excluding Production)
Page 8 of 16
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INDICA TE IF ITEM IS ADDRESSED ADEQUA TELY (Yes), INADEQUA TEL Y (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
112.8(c)/112.12(c) Bulk Storage Containers (See Appendix A of this checklist)
(1 ) Containers compatible with material stored and conditions of storage such as pressure and temperature
(2) Secondary containment to hold capacity of largest container and sufficient freeboard for precipitation
Diked areas sufficiently impervious to contain discharged oil
Alternatively, any discharge to a drainage trench system will be safely confined in a facility catchment
basin or holding pond
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNO
DNA
DYes
DNA
DYes
DNo
DNA
DYes
GNo
DNA
DYes
DNo
DNA
DYes
DNA
(3) Is there drainage of uncontaminated rainwater from diked areas into a storm drain or open watercourse?
D Yes D No If YES:
(i) Bypass valve normally sealed closed
(ii) Retained rainwater is inspected to ensure that its presence will not cause a discharge as described in
R1 1 ^ 1 fh\
S ( )
(iii) Bypass valve opened and resealed under responsible supervision
(iv) Adequate records of drainage are kept; for example, records required under permits issued in
accordance with 40 CFR 1 22.41 (j)(2) and (m>(3)
DYes
DNo
DNA
DYes
DNo
C1NA
n Yes
UNO
DNA
D Yes
UNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
UNA
QYes
UNA
(4) For completely buried metallic tanks installed on or after January 10, 1974 (if not exempt from SPCC regulation because subject
to all of the technical requirements of 40 CFR part 280 or 281):
• Corrosion protection with coatings or cathodic protection compatible with local soil conditions
• Regular leak testing conducted
(5) Partially buried or bunkered metallic tanks protected from corrosion with coatings or cathodic protection
compatible with local soil conditions
DYes
DNo
DNA
DYes
DNo
DNA
DYes
UNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNA
Comments:
Onshore Facilities (Excluding Production)
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INDICA TE IF ITEM IS ADDRESSED ADEQUA TEL Y (Yes), INADEQUA TEL Y (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
ONSHORE FACILITIES (EXGLUDINGPRODUCTtONy—112,8/112.12
112.8(c)/112.12(c) Bulk Storage Containers (continued)
(6)
Aboveground containers integrity tested by visual inspection and another technique such as hydrostatic
testing, radiographic testing, ultrasonic testing, acoustic emissions testing, or another system of non-
destructive shell testing on a regular schedule and whenever material repairs are made
Container supports and foundations regularly inspected
Outside of containers frequently inspected for signs of deterioration, discharges, or accumulation of oil
inside diked areas
Records of inspections and tests maintained
(7) Leakage through defective internal heating coils controlled:
• Steam returns and exhaust lines from internal heating coils that discharge into an open water source are
monitored for contamination, OR
• Steam returns and exhaust lines pass through a settling tank, skimmer, or other separation or retention
system
(8) Each container equipped with at least one of the following for liquid level sensing: (i) high liquid level alarms
with an audible or visual signal at a constantly attended operation or surveillance station, or audible air vent
in smaller facilities, (ii) high liquid level pump cutoff devices set to stop flow at a predetermined container
content level, (iii) direct audible or code signal communication between container ganger and pumping
station,
-------
INDICATE IF ITEM IS ADDRESSED ADEQUATELY (Yes), INADEQUA TEL Y (No). OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
ONSHORE FACILITIES (EXCiUJOiNG PRODOCftQNH112-1^^2.12
FIEtD
112.8(d)/112.12(d) Facility transfer operations, pumping, and facility process
(D
Buried piping installed or replaced on or after August 16, 2002 has protective wrapping or coating
Buried piping installed or replaced on or after August 16, 2002 is cathodically protected or otherwise
satisfies corrosion protection standards for piping in 40 CFR part 280 or 281
r~
Exposed buried piping is inspected for deterioration and corrosion damage is examined and corrected
i
(2) Piping terminal connection at the transfer point is marked as to origin and capped or blank-flanged when
not in service or in standby service for an extended time
(3) Pipe supports are properly designed to minimize abrasion and corrosion and allow for expansion and
contraction
(4)
Aboveground valves, piping, and appurtenances such as flange joints, expansion joints, valve glands
and bodies, catch pans, pipeline supports, locking of valves, and metal surfaces are inspected regularly
Integrity and leak testing conducted on buried piping at time of installation, modification, construction,
relocation, or replacement
(5) Vehicles warned so that no vehicle endangers aboveground piping and other oil transfer operations
DYes
DNo
DNA
DYes
DNo
DNA
QVes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DMA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
Comments:
DYes
DNo
DNA
DYes
DNo
DNA
DYes
ONo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
Onshore Facilities (Excluding Production)
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ADDITIONAL
Rule Provision
Comment
Onshore Facilities (Excluding Production)
Page 12 of 16
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:;: PHOTO DOCUMENTATtON LOG
Photo Number
Description (include date and location)
Onshore Facilities (Excluding Production)
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SPCC FIELD INSPECTION AND PLAN REVIEW TABLE
Appendix A: Documentation of Field Observations for Containers and Associated Requirements
Inspectors should use this table to document observations of containers as needed.
Containers and Piping
Check containers for leaks, specifically looking for: drip marks, discoloration of tanks, puddles containing spilled or leaked material,
corrosion, cracks, and localized dead vegetation, and standards/specifications of construction.
Check foundation for: cracks, discoloration, puddles containing spilled or leaked material, settling, gaps between container and
foundation, and damage caused by vegetation roots.
Check piping for: droplets of stored material, discoloration, corrosion, bowing of pipe between supports, evidence of stored material
seepage from valves or seals, and localized dead vegetation. (Document in comments section of §112.8(d) /§112.12(d).)
Secondary Containment (Active and Passive)
Check secondary containment for: containment system (including walls and floor) ability to contain oil such that oil will not escape the
containment system before cleanup occurs, proper sizing, cracks, discoloration presence of spilled or leaked material (standing liquid),
erosion, corrosion, and valve conditions
Check dike or berm systems for: level of precipitation in dike/available capacity, operational status of drainage valves (closed), dike
or berm impermeability, debris, erosion, impermeability of the earthen floor/walls of diked area, and location/status of pipes, inlets,
drainage around and beneath containers, presence of oil discharges within diked areas.
Check retention and drainage ponds for: erosion, available capacity, presence of spilled or leaked material, debris, and stressed
vegetation.
Check active measures (countermeasures) for: amount indicated in plan is available and appropriate; deployment procedures are
realistic; material is located so that they are readily available; efficacy of discharge detection; availability of personnel and training,
appropriateness of measures to prevent a discharge as described in §112.1(b).
Container IJW General Condition
Storage Capacity and
Type of OH
Type of Containment/
Drainage Control
Overfill Protection and
Testing & inspections
Onshore Facilities (Excluding Production)
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SPCC INSPECTION AND TESTING CHECKLIST
Appendix B: Required Documentation of Tests and Inspections
Records of inspections and tests required by 40 CFR part 112 signed by the appropriate supervisor or inspector must be kept with the
SPCC Plan for a period of three years. Records of inspections and tests conducted under usual and customary business practices will
suffice. Documentation of the following inspections and tests should be kept with the SPCC Plan.
Inspection or Test
Documentation
Present
Not
Present
Not
Applicable
112.7-General SPCC Requirements
(d) Integrity testing is conducted for bulk storage containers with no secondary
containment system and for which an impracticability determination has been
made
(d) Integrity and leak testing of valves and piping associated with bulk storage
containers with no secondary containment system and for which an
impracticability determination has been made
(i) Evaluate field-constructed aboveground containers for potential for brittle fracture
or other catastrophic failure when the container undergoes a repair, alteration,
reconstruction or change in service
112.8/112.12-Onshore facilities (excluding production)
(b)(2) Storm water released from facility drainage directly to a watercourse is
inspected and records of drainage are kept
(c)(3)(iv) Rainwater released directly from diked containment areas to a storm drain
or open watercourse is inspected and records of drainage are kept
Regular leak testing of completely buried metallic storage tanks
Aboveground containers, supports and foundations tested for integrity on a
regular schedule
Outside of containers frequently inspected for deterioration, discharges or
accumulations of oil inside diked areas
Liquid level sensing devices regularly tested to ensure proper operation
Effluent treatment facilities are observed frequently enough to detect
possible system upsets that could cause a discharge as described in
When buried piping is exposed, it is carefully inspected for deterioration and
corrosion damage is corrected
Aboveground valves, piping and appurtenances are regularly inspected and
the general condition of flange joints, expansion joints, valve glands and
bodies, catch pans, pipeline supports, locking of valves, and metal surfaces
are assessed
Integrity and leak testing of buried piping is conducted at time of installation,
modification, construction, relocation or replacement
Comments:
Onshore Facilities (Excluding Production)
Page 15 of 16
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SPCC CONTINGENCY PLAN REVIEW CHECKLIST
Appendix C: 40 CFR Part 109-Criteria for State, Local and Regional Oil
Removal Contingency Plans
If a facility makes an impracticability determination for secondary containment in accordance with §112.7(d), it is required to provide
an oil spill contingency plan following 40 CFR part 109.
109v5-De velopment and implementation criteria for State, local and regional oil removal contingency plans*
(a) Definition of the authorities, responsibilities and duties of all persons, organizations or agencies which are to be
involved in planning or directing oil removal operations.
(b) Establishment of notification procedures for the purpose of early detection and timely notification of an oil
discharge including:
(1) The identification of critical water use areas to facilitate the reporting of and response to oil discharges.
(2) A current list of names, telephone numbers and addresses of the responsible persons (with alternates) and
organizations to be notified when an oil discharge is discovered.
(3) Provisions for access to a reliable communications system for timely notification of an oil discharge, and
the capability of interconnection with the communications systems established under related oil removal
contingency plans, particularly State and National plans (e.g., NCP).
(4) An established, prearranged procedure for requesting assistance during a major disaster or when the
situation exceeds the response capability of the State, local or regional authority.
(c) Provisions to assure that full resource capability is known and can be committed during an oil discharge situation
including:
(1) The identification and inventory of applicable equipment, materials and supplies which are available locally
and regionally.
(2) An estimate of the equipment, materials and supplies which would be required to remove the maximum oil
discharge to be anticipated.
(3) Development of agreements and arrangements in advance of an oil discharge for the acquisition of
equipment, materials and supplies to be used in responding to such a discharge.
(d) Provisions for well defined and specific actions to be taken after discovery and notification of an oil discharge
including:
(1) Specification of an oil discharge response operating team consisting of trained, prepared and available
operating personnel.
(2} Predesignation of a properly qualified oil discharge response coordinator who is charged with the
responsibility and delegated commensurate authority for directing and coordinating response operations
and who knows how to request assistance from Federal authorities operating under existing national and
regional contingency plans.
(3) A preplanned location for an oil discharge response operations center and a reliable communications
system for directing the coordinated overall response operations.
(4) Provisions for varying degrees of response effort depending on the severity of the oil discharge.
(5) Specification of the order of priority in which the various water uses are to be protected where more than
one water use may be adversely affected as a result of an oil discharge and where response operations
may not be adequate to protect all uses.
(e) Specific and well defined procedures to facilitate recovery of damages and enforcement measures as provided
for by State and local statutes and ordinances.
I
"The contingency plan should be consistent with all applicable state and local plans, Area Contingency Plans, and the National
Contingency Plan (NCP).
Onshore Facilities (Excluding Production) Page 16 of 16 Version 1.0
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U.S. ENVIRONMENTAL PROTECTION AGENCY
SPCC FIELD INSPECTION AND PLAN REVIEW CHECKLIST
ONSHORE OIL PRODUCTION, DRILLING, AND WORKOVER FACILITIES
Overview of the Checklist
This checklist is designed to assist EPA inspectors in conducting a thorough and consistent
inspection of a facility's compliance with the Spill Prevention, Control, and Countermeasure
(SPCC) rule at 40 CFR part 112. It is a tool to help federal inspectors (or their contractors)
record observations during the site visit and review of the SPCC Plan. While the checklist is
comprehensive, the inspector should always refer to the SPCC rule in its entirety, the SPCC
Regional Inspector Guidance Document, and other relevant guidance for evaluating
compliance. This checklist must be completed in order for an inspection to count toward an
agency measure (i.e., OEM/OECA inspection measures or GPRA).
The checklist is organized according to the SPCC rule. Each item in the checklist identifies the
relevant section and paragraph in 40 CFR part 112 where that requirement is stated.
Sections 112.1 through 112.5 specify the applicability of the rule and requirements for the
preparation, implementation, and amendment of SPCC Plans. For these sections, the checklist
includes data fields to be completed, as well as several questions with "yes" or "no" answers.
Sections 112.7 through 112.11 specify requirements for spill prevention, control, and
countermeasures. For these sections, the inspector needs to evaluate whether the requirement
is addressed adequately or inadequately in the SPCC Plan and whether it is implemented
adequately in the field (either by field observation or record review). For the SPCC Plan and
implementation in the field, if a requirement is addressed adequately, mark the "Yes" box in the
appropriate column. If a requirement is not addressed adequately, mark the "No" box. If a
requirement does not apply to the particular facility, mark the "NA" box. If a provision of the rule
applies only to the SPCC Plan, the "Field" column is shaded.
Space is provided in each section to record comments. Additional space is available on the
comments page at the end of the checklist. Comments should remain factual and support the
evaluation of compliance.
Appendix A is for recording information about containers and other locations at the facility that
require secondary containment.
Appendix B is a checklist for documentation of the tests and inspections the facility operator is
required to keep with the SPCC Plan.
Appendix C is a checklist for oil removal contingency plans. A contingency plan is required if a
facility determines that secondary containment is impracticable as provided in 40 CFR 112.7(d).
Onshore Oil Production, Drilling, & Workover Facilities
Page 1 of 14
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U.S. ENVIRONMENTAL PROTECTION AGENCY
SPCC FIELD INSPECTION AND PLAN REVIEW CHECKLIST
ONSHORE OIL PRODUCTION, DRILLING, AND WORKOVER FACILITIES
FACILITY INRORMAfJON
FACILITY NAME:
ADDRESS:
CITY:
STATE:
j ZIP:
LAT:
COUNTY:
LONG:
TELEPHONE:
FACILITY REPRESENTATIVE NAME:
OWNER NAME:
OWNER ADDRESS:
CITY:
STATE:
ZIP:
TELEPHONE:
OWNER CONTACT PERSON:
FACILITY OPERATOR NAME (IF DIFFERENT FROM OWNER - IF NOT, PRINT "SAME"):
OPERATOR ADDRESS:
CITY:
STATE:
; ZIP:
TELEPHONE:
OPERATOR CONTACT PERSON:
FACILITY TYPE:
NAICS CODE:
TOTAL FACILITY CAPACITY:
HOURS PER DAY FACILITY ATTENDED:
TYPE(S) OF OIL STORED:
IS FACILITY LOCATED IN INDIAN COUNTRY? D YES D NO IF YES, RESERVATION NAME:
INSPECTION INFORMATION
INSPECTION DATE:
TIME:
INSPECTION NUMBER:
LEAD INSPECTOR:
OTHER INSPECTOR(S):
INSPECTOR ACKNOWLEDGMENT
/ performed an SPCC inspection at the facility specified above.
INSPECTOR SIGNATURE:
DATE:
Onshore Oil Production, Drilling, & Workover Facilities
Page 2 of 14
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FACILITY RESPONSE PUN (FRP) APPLICABILITY
A non-transportation related onshore facility is required to prepare and implement an FRP as outlined in 40 CFR 112.20 if:
D The facility transfers oil over water to or from vessels and has a total oil storage capacity greater than or equal to 42,000 gallons,
OR
The facility has a total oil storage capacity of at least 1 million gallons, and at least one of the following is true:
D The facility does not have secondary containment sufficiently large to contain the capacity of the largest aboveground tank plus
sufficient freeboard for precipitation.
D The facility is located at a distance such that a discharge could cause injury to fish and wildlife and sensitive environments.
D The facility is located such that a discharge would shut down a public drinking water intake.
D The facility has had a reportable discharge greater than or equal to 10,000 gallons in the past 5 years.
Facility has FRP: D Yes D No D Not Required j FRP Number:
Facility has a completed and signed copy of Appendix C, Attachment C-ll, "Certification of the Applicability of the Substantial Harm
Criteria" D Yes D No
Comments:
SPCGSENERAL APPLICABiLITY—40 CFR 112.1
IS THE FACILITY REGULATED UNDER 40 CFR part 112?
The completely buried oil storage capacity is over 42,000 gallons, OR the aggregate aboveground oil storage capacity is over 1,320
gallons D Yes D No AND
The facility is a non-transportation-related facility engaged in drilling, producing, gathering, storing, processing, refining, transferring,
distributing, using, or consuming oil and oil products, which due to its location could reasonably be expected to discharge oil into or
upon the navigable waters of the United States (as defined in 40 CFR 110.1). D Yes D No
AFFECTED WATERWAY(S):
PATH:
DISTANCE:
Note: The following storage capacity is not considered in determining applicability ofSPCC requirements:
Completely buried tanks subject to all the technical requirements of 40 CFR part 280 or a state program approved under 40 CFR part 281.
Equipment subject to the authority of the U.S. Department of Transportation, U.S. Department of the Interior, or Minerals Management Service,
as defined in Memoranda of Understanding dated November 24, 1971, and November 8, 1993.
• Any facility or part thereof used exclusively for wastewater treatment (production, recovery or recycling of oil is not considered wastewater
treatment).
• Containers smaller than 55 gallons.
• Permanently closed containers.
Does the facility have an SPCC Plan?
Comments:
D Yes D No
REQUIREMENTS FOR PREPARAf ION AND IMPLEMENTATION OF A SPCC ^
CFR 112.3
Date facility began operations:
Date of initial SPCC Plan preparation:
Current plan version (date/number):
112.3(a)
For facilities in operation prior to August 16, 2002:
Plan amended by February 17, 2006
• Amended Plan implemented by August 18, 2006
DYes DNo (UNA
D Yes D No D NA
For facilities beginning operation between August 17, 2002, and August 18,
2006, Plan prepared and fully implemented by August 18, 2006
Yes D No D NA
Onshore Oil Production, Drilling, & Workover Facilities
Page 3 of 14
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iiQUllliMENll FOR ! PREPiftiRATJQN ANGf IMPILf MENTATION OF A SPCC pl^N---|ij; CF
1 12.3(b) For facilities beginning operation after August 18, 2006, Plan prepared and fully
& (c) implemented before beginning operations
R 112.3 '"-::
D Yes D No
DNA
112.3(d) Professional Engineer certification includes statement that the PE attests:
• PE is familiar with the requirements of 40 CFR part 112 DYes DNo
• PE or agent has visited and examined the facility D Yes D No
• Plan is prepared in accordance with good engineering practice including consideration of
applicable industry standards and the requirements of 40 CFR part 1 12 DYes DNo
• Procedures for required inspections and testing have been established DYes DNo
* Plan is adequate for the facility D Yes D No
PE Name: j License No.: State: Date of certification:
1 1 2.3(e) Plan available onsite if facility is attended at least 4 hours/day
(If located at nearest field office, please note contact information below)
DYes DNo
DNA
Comments:
AMENDMENT OF SPGC P^
1 12.4(a) Has the facility discharged a reportable quantity of oil in amounts considered harmful more
than 1 ,000 gallons of oil in a single discharge or more than 42 gallons in each of two
discharges in any 1 2-month period {see 40 CFR part 1 10)?
• If yes, was information submitted to the RA as required in §1 12 4(a)?
• Date(s) of reportable discharge(s):
• Were they reported to the NRC?
1 12.4(d), (e) Have changes required by the RA been implemented in the Plan and/or facility?
DYes DNo
DYes DNo
DYes DNo
DYes DNo
DNA
DNA
DNA
DNA
Comments:
AMENDMENT OF SPCC PLAN BY THE OWNER OR OPERATOR— 40 CFR 112.5
112.5(a) Has there been a change at the facility that materially affects the potential fora discharge?
• If so, was the Plan amended within six months of Ihe change?
1 12,5(b) Review and evaluation of the Plan documented at least once every 5 years?
• Following Plan review, and if amendment was required, was Plan amended within six
months to include more effective prevention and control technology, if available?
1 12.5(c) Professional Engineer certification of any technical Plan amendments in accordance with
§112.3(d)
D Yes D No
DYes DNo
DYes DNo
DYes DNo
DYes DNo
DNA
DNA
DNA
DNA
D NA
Name: License No.: State: Date of certification:
Reason for amendment:
Amendments implemented within six months of any Plan amendment
Comments:
DYes DNo
DNA
Onshore Oil Production, Drilling, & Workover Facilities Page 4 of 14
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INDICATE IF ITEM IS ADDRESSED ADEQUATEL Y (Yes). INADEQUATELY (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
GENERAL SPCC REQUIRE MENTS-4Q CFR 1 12.7
PLAN
FIELD
Management approval at a level of authority to commit the necessary resources to fully implement the Plan O Yes D No
Name: Title: Date:
Plan follows sequence of the rule or provides a cross-reference of requirements in the Plan and the rule
If Plan calls for facilities, procedures, methods, or equipment not yet fully operational, details of their installation
and start-up are discussed (Note: Relevant for inspection evaluation and testing baselines.)
1 12.7{a)(2) If there are deviations from the requirements of the rule, the Plan states reasons for
nonoonformance
Alternative measures described in detail and provide equivalent environmental protection (Note:
Inspector should document if the environmental equivalence is implemented in the field)
D Yes
QNo
n Yes
DNO
GNA
D Yes
Q No
DNA
D Yes
CJNo
DNA
':
!
D Yes
QNo
DNA
Describe each deviation and reasons for nonconformance:
1 1 2.7(a)(3} Plan includes diagram with location and contents of all regulated containers (including completely
buried tanks otherwise exempt from the SPCC requirements), transfer stations, and connecting
prpes
1 1 2.7(a)(3) Plan addresses each of the following:
(i) For each container, type of oil and storage capacity (see Appendix A)
(ii) Discharge prevention measures, including procedures for routine handling of products
(iii) Discharge or drainage controls, such as secondary containment around containers, and other
structures, equipment, and procedures for the control of a discharge
(iv) Countermeasures for discharge discovery, response, and cleanup (both facility's and contractor's
resources)
(v) Methods of disposal of recovered materials in accordance with applicable legal requirements
(vi) Contact list and phone numbers for the facility response coordinator, National Response Center,
cleanup contractors contracted to respond to a discharge, and all Federal, State, and local
agencies who must be contacted in the case of a discharge as described in §112.1(b)
D Yes
UNo
DNA
HYes
DNo
DNA
D Yes
DNo
DNA
D Yes
DNo
DNA
D Yes
DNA
D Yes
DNo
DNA
O Yes
DNo
DNA
D Yes
DNo
DNA
G Yes
DNo
DNA
D Yes
DNo
DNA
DYes
DNo
DNA
GYes
DNA
Comments:
Onshore Oil Production, Drilling, & Workover Facilities
Page 5 of 14
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INDICATE IF ITEM IS ADDRESSED ADEQUA TEL Y (Yes), INADEQUA TEL Y (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
REQUIREMENT SMfl
PLAN FIELD
112.7(a)(4) Plan includes information and procedures that enable a person reporting a discharge as described
in§112.1(b)to relate information on the exact address or location and phone number of tie facility;
the date and time of the discharge; the type of material discharged; estimates of the total quantity
discharged; estimates of the quantity discharged as described in §112.1 (b); the source of the
discharge; a description of all affected media; the cause of the discharge; any damages or injuries
caused by the discharge; actions being used to stop, remove, and mitigate the effects of the
discharge; whether an evacuation may be needed; and the names of individuals and/or
organizations who have also been contacted (Not required if a facility has an FRP)
112.7(a)(5) Plan organized so that portions describing procedures to be used when a discharge occurs will be
readily usable in an emergency (Not required if a facility has an FRP)
D Yes
DNo
DMA
O Yes
D No
DMA
112.7{b) Plan includes a prediction of the direction, rate of flow, and total quantity of oil that could be
discharged for each type of major equipment failure where experience indicates a reasonable
potential for equipment failure
D Yes
DNo
DNA
112.7(c> Appropriate containment and/or diversionary structures provided to prevent a discharge as
described in §112.1(b) before cleanup occurs. The entire containment system, including walls and
floors, is capable of containing oil and is constructed to prevent escape of a discharge from the
containment system before cleanup occurs. (1) For onshore facilities, one of the following or its
equivalent: (i) dikes, berms, or retaining walls sufficiently impervious to contain oil, (ii) curbing, (iii)
culverting, gutters or other drainage systems, (iv) weirs, booms or other barriers, (v) spill diversion
ponds, (vi) retention ponds, or (vii) sorbent materials (See Appendix A)
112.7(d) Determination(s) of impracticability of secondary containment
If YES, is the impracticability of secondary containment clearly demonstrated?
D Yes
DNo
DNA
D Yes
DNo
DYes
DNo
DNA
Comments concerning impracticability determination(s) for secondary containment:
If impracticability determination is made, for bulk storage containers, periodic integrity testing of
containers and leak testing of the valves and piping (associated with the container) is conducted
If impracticability determination is made, unless facility has FRP:
(1) Contingency Plan following 40 CFR part 109 (see Appendix C) is provided AND
(2) Written commitment of manpower, equipment, and materials required to control and
remove any quantity of oil discharged that may be harmful
112.7(e) Inspections and tests conducted in accordance with written procedures
Record of inspections or tests signed by supervisor or inspector and kept with Plan for at least 3
years (see Appendix B checklist)
rj Yes
D No
DNA
DYes
DNo
DNA
DYes
O No
DNA
DYes
DNo
DNA
D Yes
DNo
DNA
Comments:
DYes
DNo
DNA
D Yes
a NO
DNA
DYes
a NO
DNA
DYes
DNo
DNA
D Yes
DNo
DNA
D Yes
D No
DNA
Onshore Oil Production, Drilling, & Workover Facilities
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INDICATE IF ITEM IS ADDRESSED ADEQUATELY (Yes), INADEQUA TELY(No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
G|NERALSPCCREQUIREMEMTS--WCmil2J ;
1 12.7{f) Personnel, training, and oil discharge prevention procedures
(1 ) Training of oil-handling personnel in operation and maintenance of equipment to prevent discharges;
discharge procedure protocols; applicable pollution control laws, rules and regulations; general facility
operations; and contents of SPCC Plan
(2) Person designated as accountable for discharge prevention at the facility
(3) Discharge prevention briefings conducted at least once a year for oil handling personnel
1 12.7(h) Tank car and tank truck loading/unloading rack*
(1) Does loading/unloading area (the location adjacent to the loading or unloading rack) drainage flow
to catchment basin or treatment facility? D Yes D No
• If NO, quick drainage system used
Containment system holds capacity of the largest single compartment of a tank car/truck
loaded/unloaded at the facility
(2) Physical barriers, warning signs, wheel chocks, or vehicle brake interlock system in loading/unloading
areas (the location adjacent to the loading or unloading rack) to prevent vehicles from departing before
complete disconnection of flexible or fixed oil transfer lines
(3) Lower-most drains and all outlets on tank cars/trucks inspected prior to filling/departure, and if necessary
ensure that they are tightened, adjusted, or replaced to prevent liquid discharge while in transit
112.7(i) Brittle fracture evaluation of field-constructed aboveground containers
1 12.7(i) Brittle fracture evaluation is conducted after tank repair/alteration/change in service that might affect
the risk of a discharge or after a discharge/failure due to brittle fracture or other catastrophe and
appropriate action taken as necessary (for field-constructed aboveground containers)
1 12.7(|) State rules, regulations and guidelines and conformance with applicable sections of 40 CFR part 112
1 12,7(j) Discussion of conformance with applicable more stringent State rules, regulations, and guidelines
and other effective discharge prevention and containment procedures listed in 40 CFR part 112
PLAN
FIELD
D Yes
a NO
C1NA
D Yes
DNo
DMA
DYes
a NO
DMA
D Yes
a NO
QNA
D Yes
Q No
DMA
D Yes •
DNo
DNA
DYes
D No
DNA
DYes
DNo
D NA
D Yes
DNo
DNA
D Yes
DNo
DNA
DYes
DNo
ONA
DYes
DNo
DNA
DYes
DNo
DNA
OYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
Comments:
*Note that a tank car/truck loading/unloading rack must be present for §112. 7(h) to apply. Though this requirement applies to all
facilities, loading and unloading rack equipment is often not present at typical production facilities.
Onshore Oil Production, Drilling, & Workover Facilities
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INDICA TE IF ITEM IS ADDRESSED ADEQUA TEL Y (Yes), INADEQUA TEL Y (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
HAN
112.9(b) Oil production facility drainage
(1) At tank batteries, separation and treating areas where there is a reasonable possibility of a discharge as
described in §112.1(b), drainage is closed and sealed except when draining uncontaminated rainwater.
Accumulated oil on the rainwater is returned to storage or disposed of in accordance with legally
approved methods
DYes
DNo
DNA
Prior to drainage, diked area inspected and action taken as provided in §112.8(c)(3)(ii), (iii).and (iv):
• 112.8(c)(3)(ii) Retained rainwater is inspected to ensure that its presence will not cause a discharge
as described in §112.1(b)
112.8(c)(3)(iii) Bypass valve opened and resealed under responsible supervision
112.8{c)(3){iv) Adequate records of drainage are kept; for example, records required under permits
issued in accordance with §122.41(j)(2) and (m)(3)
(2) Field drainage systems and oil traps, sumps, or skimmers inspected at regularly scheduled intervals for oil,
and accumulations of oil promptly removed
112.9(c) Oil production facility bulk storage containers
DYes
DNo
DNA
DYes
ONo
QNA
DYes
DNo
DNA
D Yes
DNo
DNA
(1) Containers used are compatible with material stored and conditions of storage
(2)
Secondary containment provided for all tank battery, separation and treating facilities with capacity to
hold the largest single container and sufficient freeboard for precipitation
Drainage from undiked areas safely confined in a catchment basin or holding pond
(3) Periodically and upon a regular schedule, visually inspect containers on or above the surface of the ground
for deterioration and maintenance needs, including foundations and supports
(4) New and old tank batteries engineered/updated in accordance with good engineering practices to prevent
discharges including at least one of the following: (i) adequate container capacity to prevent overfill if
regular pumping/gauging is delayed; (ii) overflow equalizing lines between containers so that a full
container can overflow to an adjacent container; (iii) vacuum protection to prevent container collapse; or
(iv) high level sensors to generate and transmit an alarm to the computer where the facility is subject to a
computer production control system
Comments:
DYes
DNo
ONA
DYes
DNo
DNA
DYes
DNa
DNA
DYes
DNO
DNA
DYes
DNo
DNA
a Yes
DNo
DNA
D Yes
DNo
DNA
DYes
DNo
UNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
Onshore Oil Production, Drilling, & Workover Facilities
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INDICATE IF ITEM IS ADDRESSED ADEQUATELY (Yes), INADEQUATELY (No), ORIS NOT APPLICABLE (NA) IN PLAN AND FIELD.
ONSHORE OIL PROpBCTION FAiEiLlTJES—112;9
PLAN
112.9(d) Facility transfer operations
(1) All aboveground valves and piping associated with transfer operations are inspected periodically and upon
a regular schedule. Include the general condition of flange joints, valve glands and bodies, drip pans, pipe
supports, pumping well palish rod stuffing boxes, bleeder and gauge valves, and other such items.
(2) Saltwater (oil field brine) disposal facilities inspected often to detect possible system upsets capable of
causing a discharge, particularly following a sudden change in atmospheric temperature
(3) Flowline maintenance program to prevent discharges from each flowline is established
DYes
DNo
TJNA
DYes
DNo
DNA
DYes
DNo
DNA
Comments:
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNO
DNA
ONSHORE OJL DRIlIlNG AND WORKOVER FACiLmES-~112,10
PLAN
FIELD
112.10(b) Mobile drilling or workover equipment is positioned or located to prevent a discharge as described in
112.10(c) Catchment basins or diversion structures are provided to intercept and contain discharges of fuel,
crude oil, or oily drilling fluids.
Blowout prevention (BOP) assembly and well control system installed before drilling below any
casing string or during workover operations
BOP assembly and well control system capable of controlling any well-head pressure that may be
encountered while on the well
Comments:
DYes
DNo
DNA
DYes
DNo
DNA
O Yes
DNo
QNA
DYes
DNo
GNA
DYes
DNo
DNA
DYes
DNo
ONA
O Yes
Q No
DNA
D No
ONA
Onshore Oil Production, Drilling, & Workover Facilities
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ADDITION AL COMMENTS
Rule Provision
Comment
Onshore Oil Production, Drilling, & Workover Facilities Page 10 of 14
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Photo Number
fo^rgjipcp*
Description (include date and location)
Onshore Oil Production, Drilling, & Workover Facilities Page 11 of 14
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SPCC FIELD INSPECTION AND PLAN REVIEW TABLE
Appendix A: Documentation of Field Observations of Containers and Associated Requirements
Inspectors should use this table to document observations of containers, as needed.
Containers and Piping
Check containers for leaks, specifically looking for: drip marks, discoloration of tanks, puddles containing spilled or leaked material,
corrosion, cracks, and localized dead vegetation, and standard/specifications of construction..
Check aboveground container foundation for: cracks, discoloration, puddles containing spilled or leaked material, settling, gaps
between container and foundation, and damage caused by vegetation roots.
Check all piping for: droplets of stored material, discoloration, corrosion, bowing of pipe between supports, evidence of stored material
seepage from valves or seals, evidence of leaks from flowlines, and localized dead vegetation. For all aboveground piping, include the
general condition of flange joints, valve glands and bodies, drip pans, pipe supports, pumping well polish rod stuffing boxes, bleeder and
gauge valves, and other such items. (Document in comments section of §112.9(d)).
Secondary Containment
Check secondary containment Tor: containment system (including walls and floor) ability to contain oil such that oil will not escape the
containment system before cleanup occurs, proper sizing, cracks, discoloration, presence of spilled or leaked material (standing liquid),
erosion, corrosion, penetrations in the containment system, and valve conditions.
Check dike or berm systems for: level of precipitation in dike/available capacity, operational status of drainage valves (closed), dike
or berm impermeability, debris, erosion, impermeability of the earthen floor/walls of diked area, and location/status of pipes, inlets,
drainage around and beneath containers, presence of oil discharges within diked areas.
Check drainage systems for: an accumulations of oil that may have resulted from any small discharge, including field drainage
systems (such as drainage ditches or road ditches), and oil traps, sumps, or skimmers. Ensure any accumulations of oil have been
promptly removed.
Check retention and drainage ponds for: erosion, available capacity, presence of spilled or leaked material, debris, and stressed
vegetation.
Container ID/ General Condition
Storage Capacity and
Type of OH
Type of Containment/
Drainage Control
Overfill Protection and
Testing & Inspections
Onshore Oil Production, Drilling, & Workover Facilities
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SPCC INSPECTION AND TESTING CHECKLIST
Appendix B: Required Documentation of Tests and Inspections
Records of inspections and tests required by 40 CFR part 112 signed by the appropriate supervisor or inspector must be kept with the
SPCC Plan for a period of three years. Records of inspections and tests conducted under usual and customary business practices will
suffice. Documentation of the following inspections and tests should be kept with the SPCC Plan.
Inspection or Test
Documentation
Present
Not
Present
Not
Applicable
112.7-General SPCC Requirements
(a) Integrity testing is conducted for bulk storage containers with no secondary
containment system and for which an impracticability determination has been
made
(d) Integrity and leak testing of valves and piping associated with bulk storage
containers with no secondary containment system and for which an
impracticability determination has been made
(i) Evaluate field-constructed aboveground containers for potential for brittle fracture
or other catastrophic failure when the container undergoes a repair, alteration,
reconstruction or change in service
112.9-Onshore oil production facilities
(b)(1) Rainwater released directly from diked containment areas to a storm drain or
open watercourse inspected and records of drainage kept
(b)(2) Field drainage systems, oil traps, sumps, and skimmers inspected regularly for
oil, and accumulations of oil promptly removed
(c)(3) Regular visual inspections of containers, foundations and supports for
deterioration and maintenance needs
(d)(1} All aboveground valves and piping associated with transfer operations are
regularly inspected
(d)(2) Saltwater disposal facilities inspected often to detect possible system upsets
capable of causing a discharge
(d)(3) Specific and individual inspection, testing, and/or evaluation requirements as
required by facility's fiowline maintenance program
Comments:
Onshore Oil Production, Drilling, & Workover Facilities
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SPCC CONTINGENCY PLAN REVIEW CHECKLIST
Appendix C: 40 CFR Part 109-Criteria for State, Local and Regional Oil
Removal Contingency Plans
If a facility makes an impracticability determination for secondary containment in accordance with §112.7(d), it is required to provide
an oil spill contingency plan following 40 CFR part 109.
i09.5-Development and ImplementaUoncrfterla for State, local and regional oil removal contingency plans* Yes
(a) Definition of the authorities, responsibilities and duties of all persons, organizations or agencies which are to be
involved in planning or directing oil removal operations.
(b) Establishment of notification procedures for the purpose of early detection and timely notification of an oil
discharge including:
(1) The identification of critical water use areas to facilitate the reporting of and response to oil discharges.
(2) A current list of names, telephone numbers and addresses of the responsible persons (with alternates) and
organizations to be notified when an oil discharge is discovered
(3) Provisions for access to a reliable communications system for timely notification of an oil discharge, and
the capability of interconnection with the communications systems established under related oil removal
contingency plans, particularly State and National plans (e.g., NCP).
(4) An established, prearranged procedure for requesting assistance during a major disaster or when the
situation exceeds the response capability of the State, local or regional authority.
(c) Provisions to assure that full resource capability is known and can be committed during an oil discharge situation
including:
(1) The identification and inventory of applicable equipment, materials and supplies which are available locally
and regionally.
(2) An estimate of the equipment, materials and supplies which would be required to remove the maximum oil
discharge to be anticipated.
(3) Development of agreements and arrangements in advance of an oil discharge for the acquisition of
equipment, materials and supplies to be used in responding to such a discharge.
(d) Provisions for well defined and specific actions to be taken after discovery and notification of an oil discharge
including:
(1) Specification of an oil discharge response operating team consisting of trained, prepared and available
operating personnel.
(2) Predesignation of a properly qualified oil discharge response coordinator who is charged with the
responsibility and delegated commensurate authority for directing and coordinating response operations
and who knows how to request assistance from Federal authorities operating under existing national and
regional contingency plans.
(3) A preplanned location for an oil discharge response operations center and a reliable communications
system for directing the coordinated overall response operations.
(4) Provisions for varying degrees of response effort depending on the severity of the oil discharge.
(5) Specification of the order of priority in which the various water uses are to be protected where more than
one water use may be adversely affected as a result of an oil discharge and where response operations
may not be adequate to protect all uses.
(e) Specific and well defined procedures to facilitate recovery of damages and enforcement measures as provided
for by State and local statutes and ordinances.
No
* The contingency plan should be consistent with all applicable state and local plans, Area Contingency Plans, and the National
Contingency Plan (NCP).
Onshore Oil Production, Drilling, & Workover Facilities Page 14 of 14
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U.S. ENVIRONMENTAL PROTECTION AGENCY
SPCC FIELD INSPECTION AND PLAN REVIEW CHECKLIST
FOR USE AT OFFSHORE DRILLING, PRODUCTION, AND WORKOVER FACILITIES
Overview of the Checklist
This checklist is designed to assist EPA inspectors in conducting a thorough and consistent
inspection of a facility's compliance with the Spill Prevention, Control, and Countermeasure
(SPCC) rule at 40 CFR part 112. It is a tool to help federal inspectors (or their contractors)
record observations during the site visit and review of the SPCC Plan. While the checklist is
comprehensive, the inspector should always refer to the SPCC rule in its entirety, the SPCC
Regional Inspector Guidance Document, and other relevant guidance for evaluating
compliance. This checklist must be completed in order for an inspection to count toward an
agency measure (i.e., OEM/OECA inspection measures or GPRA).
The checklist is organized according to the SPCC rule. Each item in the checklist identifies the
relevant section and paragraph in 40 CFR part 112 where that requirement is stated.
Sections 112.1 through 112.5 specify the applicability of the rule and requirements for the
preparation, implementation, and amendment of SPCC Plans. For these sections, the checklist
includes data fields to be completed, as well as several questions with "yes" or "no" answers.
Sections 112.7 through 112.11 specify requirements for spill prevention, control, and
countermeasures. For these sections, the inspector needs to evaluate whether the requirement
is addressed adequately or inadequately in the SPCC Plan and whether it is implemented
adequately in the field (either by field observation or record review). For the SPCC Plan and
implementation in the field, if a requirement is addressed adequately, mark the "Yes" box in the
appropriate column. If a requirement is not addressed adequately, mark the "No" box. If a
requirement does not apply to the particular facility, mark the "NA" box. If a provision of the rule
applies only to the SPCC Plan, the "Field" column is shaded.
Space is provided in each section to record comments. Additional space is available on the
comments page at the end of the checklist. Comments should remain factual and support the
evaluation of compliance.
Appendix A is for recording information about containers and other locations at the facility that
require secondary containment.
Appendix B is a checklist for documentation of the tests and inspections the facility operator is
required to keep with the SPCC Plan.
Appendix C is a checklist for oil removal contingency plans. A contingency plan is required if a
facility determines that secondary containment is impracticable as provided in 40 CFR 112.7(d).
OFFSHORE FACILITIES
Page 1 of 14
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U.S. ENVIRONMENTAL PROTECTION AGENCY
SPCC FIELD INSPECTION AND PLAN REVIEW CHECKLIST
FOR USE AT OFFSHORE DRILLING, PRODUCTION, AND WORKOVER FACILITIES
FACILITY NAME:
ADDRESS:
CITY:
STATE:
ZIP:
LAT:
COUNTY:
LONG:
TELEPHONE:
FACILITY REPRESENTATIVE NAME:
OWNER NAME:
OWNER ADDRESS:
CITY:
STATE:
ZIP:
TELEPHONE:
OWNER CONTACT PERSON:
FACILITY OPERATOR NAME (IF DIFFERENT FROM OWNER - IF NOT. PRINT "SAME"):
OPERATOR ADDRESS:
CITY:
TELEPHONE:
STATE:
ZIP:
OPERATOR CONTACT PERSON:
FACILITY TYPE:
HOURS PER DAY FACILITY ATTENDED:
NAICS CODE:
TOTAL FACILITY CAPACITY:
TYPE(S) OF OIL STORED:
IS FACILITY LOCATED IN INDIAN COUNTRY? Q YES D NO IF YES, RESERVATION NAME:
JNSPECTrON INFORMATION
INSPECTION DATE:
LEAD INSPECTOR:
TIME:
INSPECTION NUMBER:
OTHER INSPECTOR(S):
/ performed an SPCC inspection et the facility specified above.
INSPECTOR SIGNATURE:
DATE:
OFFSHORE FACILITIES
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IS THE FACILITY REGULATED UNDER 40 CFR part 112?
The completely buried oil storage capacity is over 42,000 gallons, OR the aggregate aboveground oil storage capacity is over 1,320
gallons D Yes O No AND
The facility is a non-transportation-related facility engaged in drilling, producing, gathering, storing, processing, refining, transferring,
distributing, using, or consuming oil and oil products, which due to its location could reasonably be expected to discharge oil into or
upon the navigable waters of the United States (as defined in 40 CFR 110.1), D Yes D No
AFFECTED WATERWAY(S):
PATH:
DISTANCE:
Note: The fallowing storage capacity is not considered in determining applicability of SPCC requirements:
• Completely buried tanks subject to all the technical requirements of 40 CFR part 280 or a state program approved under 40 CFR part 281.
• Equipment subject to the authority of the U.S. Department of Transportation, U.S. Department ofthe Interior, or Minerals Management Service,
as defined in Memoranda of Understanding dated November 24, 1971, and November 8, 1993.
' Any facility or part thereof used exclusively for wastewater treatment (production, recovery or recycling of oil is not considered wastewater
treatment).
Containers smaller than 55 gallons.
Permanently closed containers.
Does the facility have an SPCC Plan?
Comments:
QYes DNo
REQUIREMENTS FOR PREPARATION AND IMPLEMENTATION OF A SPGC PLAN-^40GFR 112.3
Date facility began operations:
Date of initial SPCC Plan preparation:
112.3(a) For facilities in operation prior to August 16, 2002:
Plan amended by February 17, 2006
Amended Plan implemented by August 18, 2006
Current plan version (date/number):
D Yes D No D NA
DYes DNo D NA
For facilities beginning operation between August 17, 2002, and August 18,
2006, Plan prepared and fully implemented by August 18, 2006
D Yes D No D NA
112.3(b)
&(c)
For facilities beginning operation after August 18, 2006, Plan prepared and fully
implemented before beginning operations
D Yes D No D NA
112.3(d) Professional Engineer certification includes statement that the PE attests:
• PE is familiar with the requirements of 40 CFR part 112
• PE or agent has visited and examined the facility
* Plan is prepared in accordance with good engineering practice including consideration of
applicable Industry standards and the requirements of 40 CFR part 112
• Procedures for required inspections and testing have been established
• Plan is adequate for the facility
PE Name:
License No.:
State:
DYes DNo
DYes DNo
DYes DNo
DYes DNo
DYes DNo
Date of certification:
112.3(e) Plan available onsite if facility is attended at least 4 hours/day
(If located at nearest field office, please note contact information below.)
D Yes D No D NA
Comments:
OFFSHORE FACILITIES
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1
112 4(a) Has the facility discharged a reportable quantity of oil in amounts considered harmful: more
than 1,000 gallons of oil in a single discharge or more than 42 gallons in each of two
discharges in any 12-month period (see 40 CFR part 110)7
DYes DNo
• If yes, was information submitted to the RA as required in §112.4(a)?
• Date(s) of reportable discharge(s):
• Were they reported to the NRC?
112.4(d), (e) Have changes required by the RA been implemented in the Plan and/or facility?
DYes DNo D NA
DYes DNo DMA
DYes DNo D NA
Comments:
BY THE OWNER 6R OPBRATQRMO SFR 112,5
112.5(a) Has there been a change at the facility that materially affects the potential for a discharge?
DYes DNo D NA
112.5(b)
• If so, was the Plan amended within six months of Ihe change?
Review and evaluation of the Plan documented at least once every 5 years?
D Yes D No D NA
DYes DNo D NA
Following Plan review, and if amendment was required, was Plan amended within six
months to include more effective prevention and control technology, if available?
DYes DNo D NA
112.5(c) Professional Engineer certification of any technical Plan amendments in accordance with
§112.3(d)
DYes D No DNA
Name:
I
License No.:
State:
Date of certification:
Reason for amendment:
Amendments implemented within six months of any Plan amendment
DYes DNo D NA
Comments:
OFFSHORE FACILITIES
Page 4 of 14
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INDICATE IF ITEM IS ADDRESSED ADEQUATEL Y (Yes), INADEQUA TEL Y (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
^|NER|kSPS£ RECiiREM|NTS^40 CFR 112.7
'•WMB
FIEtD
Management approval at a level of authority to commit the necessary resources to fully implement the Plan D Yes D No
Name: Titie:
Plan follows sequence of the rule or provides a cross-reference of requirements in the Plan and the rule
If Plan calls for facilities, procedures, methods, or equipment not yet fully operational, details of their installation
and start-up are discussed (Note: Relevant for inspection evaluation and testing baselines.)
1 1 2.7(a)(2) If there are deviations from the requirements of the rule, the Plan states reasons for
nonconformance
Alternative measures described in detail and provide equivalent environmental protection (Note:
Inspector should document if the environmental equivalence is implemented in the field.)
Date:
DYes
DNo
D Yes
DNo
DNA
D Yes
D No
DNA
DYes
DNo
DNA
-
DYes
UNO
DNA
Describe each deviation and reasons for nonconformance:
1 12,7(a)(3) Plan includes diagram with location and contents of all regulated containers (including completely
buried tanks otherwise exempt from the SPCC requirements), transfer stations, and connecting
pipes
1 12.7(a)(3) Plan addresses each of the following:
(i) For each container, type of oil and storage capacity (see Appendix A)
(ii) Discharge prevention measures, including procedures for routine handling of products
(iii) Discharge or drainage controls, such as secondary containment around containers, and other
structures, equipment, and procedures for the control of a discharge
(iv) Countermeasures for discharge discovery, response, and cleanup (both facility's and contractor's
resources)
(v) Methods of disposal of recovered materials in accordance with applicable legal requirements
(vi> Contact list and phone numbers for the facility response coordinator, National Response Center,
cleanup contractors contracted to respond to a discharge, and all Federal, State, and local agencies
who must be contacted in the case of a discharge as described in §11 2.1 (b)
D Yes
ONA
O Yes
ONo
ONA
D Yes
DNo
PNA
DYes
DNA
DYes
DNo
DNA
DYes
DNo
DNA
D Yes
DNo
DNA
DYes
DNA
DYes
DNo
DNA
U Yes
nNo
DNA
DYes
DNA
O Yes
DNA
Comments:
OFFSHORE FACILITIES
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INDICATE IF ITEM IS ADDRESSED ADEQUATELY (Yes), INADEQUATELY (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
SENEGAL
REQUIREMENTS— 40 CFR 1 12.7
PLAN FIELD
112.7(a)(4) Plan includes information and procedures that enable a person reporting a discharge as described
in §112.1(b)to relate information on the exact address or location and phone number of the facility;
the date and time of the discharge; the type of material discharged; estimates of the total quantity
discharged; estimates of the quantity discharged as described in §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; actions being used to stop, remove, and mitigate the effects of the
discharge; whether an evacuation may be needed; and the names of individuals and/or
organizations who have also been contacted
112.7(a)(5) Plan organized so that portions describing procedures to be used when a discharge occurs will be
readily usable in an emergency
D Yes
DNo
DMA
DYes
ONo
DNA
112.7(b) Plan includes a prediction of the direction, rate of flow, and total quantity of oil that could be
discharged for each type of major equipment failure where experience indicates a reasonable
potential for equipment failure
DYes
O No
ONA
112.7(c) Appropriate containment and/or diversionary structures provided to prevent a discharge as
described in §112.1 (b) before cleanup occurs. The entire containment system, including walls and
floors, is capable of containing oil and is constructed to prevent escape of a discharge from the
containment system before a cleanup occurs.... (2) For offshore facilities: (i) curbing or drip pans,
or (ii) sumps and collection systems (See Appendix A)
112.7(d) Determination(s) of impracticability of secondary containment
If YES, is the impracticability of secondary containment clearly demonstrated?
DYes
DNo
DNA
D Yes
DNo
D Yes
DNO
DNA
DYes
DNo
DNA
DYes
DNo
DNA
Comments concerning impracticability determination(s) for secondary containment:
If impracticability determination is made, for bulk storage containers, periodic integrity testing of
containers and leak testing of the valves and piping associated with the container is conducted
If impracticability determination is made:
(1) Contingency Plan following 40 CFR part 109 (see Appendix C) is provided AND
(2) Written commitment of manpower, equipment, and materials required to control and remove
any quantity of oil discharged that may be harmful
112.7(e) Inspections and tests conducted in accordance with written procedures
Record of inspections or tests signed by supervisor or inspector and kept with Plan for at least 3
years (see Appendix B checklist)
D Yes
DNo
DNA
DYes
DNO
DNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
GNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
OYes
DNo
DNA
Comments:
OFFSHORE FACILITIES
Page 6 of 14
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INDICATE IF ITEM IS ADDRESSED ADEQUA TELY(Yes), INADEQUA TEL Y (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
GENERAL SPCC REQUIREMENTS—40 CFR 112.7
PLAN
FIELD
112,7$) Personnel, training and oii discharge prevention procedures
(1) Training of oil-handling personnel in operation and maintenance of equipment to prevent discharges;
discharge procedure protocols; applicable pollution control laws, rules and regulations; general facility
operations; and contents of SPCC Plan
(2) Person designated as accountable for discharge prevention at the facility
(3) Discharge prevention briefings conducted at least once a year for oil handling personnel
DYes
DNo
DNA
QYes
O No
UNA
D Yes
DNo
DNA
112:7/{h) Tank car and :tenk truck Wading/unloading rack*
(D
Does loading/unloading area (the location adjacent to the loading or unloading rack) drainage flow to
catchment basin or treatment facility? D Yes D No
• If NO, quick drainage system used
Containment system holds capacity of the largest single compartment of a tank car/truck
loaded/unloaded at the facility
(2) Physical barriers, warning signs, wheel chocks, or vehicle brake interlock system in loading/unloading
areas (the location adjacent to the loading or unloading rack) to prevent vehicles from departing before
complete disconnection of flexible or fixed oil transfer lines
(3) Lower-most drains and all outlets on tank cars/trucks inspected prior to filling/departure, and if necessary
ensure that they are tightened, adjusted, or replaced to prevent liquid discharge while in transit
DYes
DNo
DNA
DYes
DNo
DNA
P Yes
DNo
DNA
OYes
UNO
DNA
DYes
a NO
DNA
DYes
DNo
DNA
DYes
Q No
ONA
DYes
DNo
DNA
DYes
DNa
DNA
DYes
a NO
DNA
DYes
DNo
DNA
::Brtftefracture:evaluati^^ : .-= - :
112.7{i) Brittle fracture evaluation is conducted after tank repair/a Iteration/change in service that might affect
the risk of a discharge or after a discharge/failure due to brittle fracture or other catastrophe, and
appropriate action taken as necessary (for field-constructed aboveground containers)
112:70) State rules, regulations and guidelines and eonformartce with applicable sections of 40 CFR part 112
112.7(j) Discussion of conformance with applicable more stringent State rules, regulations, and guidelines and
other effective discharge prevention and containment procedures listed in 40 CFR part 112
Comments:
DYes
DNo
QNA
DYes
DNo
DNA
DYes
DNo
DNA
* Note that a tank car/truck loading/unloading rack must be present for §112.7(h) to apply. Though this requirement applies to all
facilities, loading and unloading rack equipment is often not present at typical offshore production facilities.
OFFSHORE FACILITIES
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INDICATE IF ITEM IS ADDRESSED ADEQUA TEL Y (Yes). INADEQUA TEL Y (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
; ffiOpyCjlON, JPIR W0R1QYER FftCILITIES-H 12.11
112.11(b) Oil drainage collection equipment used to prevent and control small discharges around pumps,
glands, valves, flanges, expansion joints, hoses, drain lines, separators, treatsrs, tanks, and
associated equipment
Facility drains are controlled and directed toward a central collection sump to prevent a discharge
as described in §112.1(b); if drains and sumps not practicable, oil in collection equipment removed
as often as necessary to prevent overflow
112.11 (c) For facilities using a sump system, sump and drains adequately sized
For facilities using a sump system, spare pump available to remove liquids and assure that oil does
not escape
Regularly scheduled preventive maintenance inspection and testing program to assure reliable
operation of liquid removal system and pump start-up device
Redundant automatic sump pumps and control devices are installed if necessary
112.11{d) If separators and treaters are equipped with dump valves which predominantly fail in the closed
position and where pollution risk is high, facility equipped to prevent discharges by (1) extending the
flare line to a diked area if the separator is near shore, (2) equipping separator with high liquid level
sensor to automatically shut in wells producing to the separator, OR (3) installing parallel redundant
dump valves
112.11(e) Atmospheric storage or surge containers equipped with high liquid level sensing devices that activate
an alarm or control the flow, or otherwise prevent discharges
PLAN
D Yes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DMA
D Yes
DNo
DNA
O Yes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
OYes
DNo
UNA
Comments:
FIELD
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DMA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
ONA
OFFSHORE FACILITIES
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INDICATE IF ITEM IS ADDRESSED ADEQUATELY (Yes), INADEQUATELY (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD.
112.11(f)
112.1 1(g)
112.11(h)
112.11(i)
112.110)
112.11(k)
112.11(1)
112.1 1(m)
112.11(n)
112.11(o)
112.11(p)
Comments
poi|iDRi|uhi|,>ft$by^ : : 4!';.- :"if :': • • 3
Pressure containers equipped with high and low pressure sensing devices that activate an alarm or
control the flow
Containers equipped with suitable corrosion protection
Written procedures maintained in the SPCC plan for inspecting and testing pollution prevention
equipment and systems
Testing and inspection of pollution prevention equipment and systems conducted on a scheduled
periodic basis commensurate with the complexity, conditions, and circumstances of the facility and any
other applicable regulations. Simulated discharges are used for testing and inspecting human and
equipment pollution control and countermeasure systems
Detailed records are provided that describe surface and subsurface well shut-in valves and devices in
use at the facility for each well. Records are sufficient to determine the method of activation or control,
such as pressure differential, change in fluid or flow conditions, combination of pressure and flow, or
manual or remote control mechanisms
Blowout prevention (BOP) assembly and well control system installed before drilling below any
casing string and during workover operations
BOP assembly and well control system capable of controlling any well-head pressure that may be
encountered while on the well
Manifolds (headers) equipped with check valves on individual flowlines
If the shut-in well pressure is greater than the working pressure of the flowline and manifold valves up
to and including the header valves, flowlines are equipped with a high pressure sensing device and
shut-in valve at the wellhead, OR pressure relief system provided for flowlines
Piping appurtenant to the facility is protected from corrosion, such as with protective coatings or
cathodic protection
Sub-marine piping appurtenant to the facility is protected against environmental stresses and other
activities such as fishing operations
Sub-marine piping maintained in good operating condition at all times. Piping periodically inspected or
tested on a regular schedule for failures. Documentation of inspections or tests kept at facility.
:P|AN-
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
D Yes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
Q No
DNA
:|feL0;;
DYes
a NO
DNA
DYes
D No
DNA
.:•:.: :.; . • V ,
:;•;::?:.: ;:•' '.• '.•
SK K
DYes
QNo
DNA
D Yes
D No
DNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
DYes
DNo
DNA
D Yes
DNo
DNA
UYes
DNo
DNA
OFFSHORE FACILITIES
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I
ADDITIONAL. COMMENTS
Rule Provision
Comment
OFFSHORE FACILITIES
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PHOTO DOCUMENTATION LOG
Photo Number
Description (Include date and location}
OFFSHORE FACILITIES
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SPCC FIELD INSPECTION AND PLAN REVIEW TABLE
Appendix A: Documentation of Field Observations for Containers and Associated Requirements
Inspectors should use this table to document observations of containers, as needed.
Containers
Check containers tor the following: (1} atmospheric storage or surge containers are equipped with high liquid level sensing devices
that activate an alarm or control the flow or otherwise prevent discharges (2) pressure containers are equipped with high and low
pressure sensing devices that activate an alarm or control the flow (3) containers are equipped with suitable corrosion protection.
Check piping for: droplets of stored material, discoloration, corrosion, bowing of pipe between supports, evidence of stored material
seepage from valves or seals, and localized dead vegetation.
Secondary Containment
Check secondary containment for: containment system (including walls and floor) ability to contain oil such that oil will not escape the
containment system before cleanup occurs, cracks, discoloration, presence of spilled or leaked material (standing liquid), corrosion, and
valve conditions.
Container ID/General Condition Storage Capacity and
TypeofOJI
Type of Containment/ Overfill Protection and
Drainage Control Testing A taspactlons
OFFSHORE FACILITIES
Page12of 14
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SPCC INSPECTION AND TESTING CHECKLIST
Appendix B: Required Documentation of Tests and Inspections
Records of inspections and tests required by 40 CFR part 112 signed by the appropriate supervisor or inspector must be kept with the
SPCC Plan for a period of three years. Records of inspections and tests conducted under usual and customary business practices will
suffice. Documentation of the following inspections and tests should be kept with the SPCC Plan.
Inspection or Test
Documentation
Present
Not
Present
Not
Appiteabie
112.7-General SPCC Requirements
(d) Integrity testing is conducted for bulk storage containers with no secondary
containment system and for which an impracticability determination has been
made
(d) Integrity and leak testing of valves and piping associated with bulk storage
containers with no secondary containment system and for which an
impracticability determination has been made
(i) Evaluate field-constructed aboveground containers for potential for brittle fracture
or other catastrophic failure when the container undergoes a repair, alteration,
reconstruction or change in service
112.1 iHDffshore oil drilling; prc^<^oh:ahdwbrfa>ver facilities ; : ;; ;; •• ;; :;:;
(c) Regularly scheduled preventive maintenance inspection and testing program to
assure reliable operation of liquid removal system and pump start-up device
(i) Testing and inspection of pollution prevention equipment and systems performed
on a scheduled periodic basis. Simulated discharges are used for testing and
inspecting human and equipment pollution control and countermeasure systems
(p) Submarine piping periodically inspected or tested for failures.
Comments:
OFFSHORE FACILITIES
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SPCC CONTINGENCY PLAN REVIEW CHECKLIST
Appendix C: 40 CFR Part 109-Criteria for State, Local and Regional Oil
Removal Contingency Plans
If a facility makes an impracticability determination for secondary containment in accordance with §112.7(d), it is required to provide
an oil spill contingency plan following 40 CFR part 109.
109,4-Davelopm«nt and Implementation criteria for State, local and regional oil removal contingency plans* Yes
No
(a) Definition of the authorities, responsibilities and duties of all persons, organizations or agencies which are to be
involved in planning or directing oil removal operations.
(b) Establishment of notification procedures for the purpose of early detection and timely notification of an oil
discharge including:
(1) The identification of critical water use areas to facilitate the reporting of and response to oil discharges.
(2) A current list of names, telephone numbers and addresses of the responsible persons (with alternates) and
organizations to be notified when an oil discharge is discovered.
(3) Provisions for access to a reliable communications system for timely notification of an oil discharge, and
the capability of interconnection with the communications systems established under related oil removal
contingency plans, particularly State and National plans (e.g., NCP).
(4) An established, prearranged procedure for requesting assistance during a major disaster or when the
situation exceeds the response capability of the State, local or regional authority.
(c) Provisions to assure that full resource capability is known and can be committed during an oil discharge situation
including:
(1) The identification and inventory of applicable equipment, materials and supplies which are available locally
and regionally.
(2) An estimate of the equipment, materials and supplies which would be required to remove the maximum oil
discharge to be anticipated.
(3) Development of agreements and arrangements in advance of an oil discharge for the acquisition of
equipment, materials and supplies to be used in responding to such a discharge.
(d) Provisions for well defined and specific actions to be taken after discovery and notification of an oil discharge
including:
(1) Specification of an oil discharge response operating team consisting of trained, prepared and available
operating personnel.
(2) Predesignation of a properly qualified oil discharge response coordinator who is charged with the
responsibility and delegated commensurate authority for directing and coordinating response operations
and who knows how to request assistance from Federal authorities operating under existing national and
regional contingency plans.
(3) A preplanned location for an oil discharge response operations center and a reliable communications
system for directing the coordinated overall response operations.
(4) Provisions for varying degrees of response effort depending on the severity of the oil discharge.
(5) Specification of the order of priority in which the various water uses are to be protected where more than
one water use may be adversely affected as a result of an oil discharge and where response operations
may not be adequate to protect all uses.
(e) Specific and well defined procedures to facilitate recovery of damages and enforcement measures as provided
for by State and local statutes and ordinances.
'The contingency plan should be consistent with all applicable state and local plans, Area Contingency Plans, and the National
Contingency Plan (NCP).
Page 14 of 14 Version 1.0,11 /28/2005
OFFSHORE FACILITIES
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Melissa Young, Esq.
Government Affairs Counsel
Petroleum Marketers Association of America
1901 N. Fort Meyer Drive
Suite 1200
Arlington, Virginia 22209-1604
Dear Ms. Young:
Thank you for your letter to Administrator Whitman of February 5, 2001, which she
has referred to me for an answer.
You explained that a marketer was notified by an Environmental Protection Agency
(EPA) inspector that her facility, which is below the 42,000 gallon underground storage
tank threshold capacity, would need a Spill Prevention, Control, and Countermeasure
(SPCC) Plan, because she parks her 2,500 gallon cargo tank motor vehicle at the facility
in the evenings. You noted that it is used to deliver petroleum products in commerce, not
as a mobile fueling facility and that it is emptied before it is parked for the evening.
EPA presumes that a cargo tank motor vehicle that contains no oil, other than any
residual oil present in an emptied vehicle when it is parked at the facility in the evening, is
a highway vehicle used for the transport of oil in interstate or intrastate commerce, and is
therefore transportation-related, and not subject to SPCC jurisdiction. 40 CFR 112,
Appendix A, Section II(2)(D). You should be aware, however, if the vehicle were to be
used at any time in a fixed operating non-transportation mode, such as the storage or
transfer of oil in any amount, other than any residual oil present in an emptied vehicle at the
end of the day, then it would become subject to the SPCC rule if there were a reasonable
possibility of discharge from the vehicle to navigable waters or adjoining shorelines. See
40 CFR 112.3(c); and 40 CFR 112, Appendix A, Section 11(1 )(F).
To determine if a fixed operating non-transportation mode has begun, and therefore
EPA SPCC jurisdiction arises, an EPA inspector would will look at all the circumstances at
a particular facility. Here, such circumstances might include whether the vehicle is
functioning as a storage tank, supplementing storage capacity or transferring oil at the
facility. We believe the vehicle you described is operating in a transportation-related
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mode, and therefore, no EPA SPCC regulatory jurisdiction arises. We note that if the
vehicle itself were to be subject to the SPCC rule, it exceeds the SPCC regulatory
threshold regardless of any other storage or use of oil at the facility. We also note that if it
is used for the transport of oil exclusively within the confines of a facility and is not intended
to transport oil in interstate or intrastate commerce, it may be subject to the SPCC rule. 40
CFR 112, Appendix A, Section 11(1 ){J).
Again, thank you for your letter. Please do not hesitate to contact us again
if you have other questions concerning EPA's oil program. If you have any questions about
this letter, please contact Hugo Fleischman at 703-603-8769 or Mark Howard at 703-603-
8715.
Sincerely,
Stephen F. Heare, Acting Deputy Director,
Office of Emergency and Remedial Response
cc: Clifford J. Harvison, NTTC
James Malcolm, MC 2131
Susan Gorsky, DOT
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Daniel Gilligan, President
Petroleum Marketers Association of America
1901 N. Fort Myer Drive- Suite 500
Arlington, VA 22209-1604
Dear Mr. Gilligan:
This letter is in response to your request for the Agency's view regarding whether several
approaches under consideration by your members would satisfy 40 CFR § 112.7(a)(2)'s
"equivalent environmental protection" provision and for clarification of the scope of the
requirements in 40 CFR §112.7(h)(entitled "Facility tank car and tank truck loading/unloading
rack (excluding offshore facilities)"). We discuss each of your proposals and questions below.
Please note that the guidance provided in this letter is based on generalized assumptions and may
not be applicable in a particular case based on site-specific circumstances.
"Equivalent Environmental Protection"
Integrity Testing
The newly amended SPCC provisions regarding bulk storage container integrity require,
among other things, that each aboveground container be tested for integrity "on a regular
schedule." 40 CFR § 112.8(c)(6). These regulations further provide that "you must combine
visual inspection with another testing technique such as hydrostatic testing, radiographic testing,
ultrasonic testing, acoustic emissions testing, or another system of non-destructive shell testing."
As you know, however, the regulations also allow deviations from this requirement where "you
provide equivalent environmental protection by some other means of spill prevention, control, or
countermeasure." 40 CFR §112.7(a)(2). You have asked whether, for shop-built containers,
visual inspection plus certain actions to ensure that the containers are not in contact with the soil
would likely be considered to provide "equivalent environmental protection" to visual inspection
plus another form of testing.
It is our view that for well-designed shop-built containers with a shell capacity of 30,000
gallons or under, combining appropriate visual inspection with the measures described below
would generally provide environmental protection equivalent to that provided by visual
inspection plus another form of testing. Specifically, the Agency generally believes that visual
inspection plus elevation of a shop-built container in a manner that decreases corrosion potential
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(as compared to a container in contact with soil)1 and makes all sides of the container, including
the bottom, visible during inspection (e.g., where the containers are mounted on structural
supports, saddles, or some forms of grillage) would be considered "equivalent." In a similar
vein, we'd also generally believe an approach that combines visual inspection with placement of
a barrier between the container and the ground, designed and operated in a way that ensures that
any leaks are immediately detected, to be considered "equivalent." For example, we believe it
would generally provide equivalent environmental protection to place a shop-built container on
an adequately designed, maintained, and inspected synthetic liner.2 We believe these approaches
would generally provide equivalent environmental protection when used for shop-built
containers (which generally have a lower failure potential than field-erected containers), because
these approaches generally reduce corrosion potential and ensure detection of any container
failure before it becomes significant.
In determining the appropriate SPCC plan requirements for visual inspection of
containers managed as described above, we suggest that the professional engineer (PE) begin by
consulting appropriate industry standards, such as those listed in Steel Tank Institute Standard
SP001 and American Petroleum Institute Standard 653.3 Similarly, in assessing whether a shop-
built container is well designed, the PE may wish to consult industry standards such as
Underwriters Laboratory 142 or American Petroleum Institute Standard 650, Appendix J. Where
a facility is considering the use of the above approaches for containers that are currently resting
on the ground, or have otherwise been managed in a way that presents risks for corrosion or are
showing signs of corrosion, we recommend the facility first evaluate the condition of the
'Additionally, we recommend that special attention be paid to the characteristics of the
material used for the support structure to ensure that they do not actually accelerate corrosion.
2Note, however, that a facility may not rely solely on measures that are required by other
sections of the rule (e.g., secondary containment) to provide "equivalent environmental
protection." Otherwise, the deviation provision would allow for approaches that provide a lesser
degree of protection overall.
3Note that the Agency intends in the near future to develop guidance on appropriate visual
inspection of shop-built containers. In that guidance, we intend to address issues such as
inspection frequency, scope (e.g., internal and /or external), training and/or qualifications of
persons conducting the inspections, and other measures that may be appropriate at a given site
(e.g., measures to detect the presence of water in a container). We expect to use the referenced
industry standards in developing such guidance.
It is also important to note, however, that depending on site circumstances, the
appropriate requirements for visual inspection may exceed those normally conducted in
accordance with recognized industry standards.
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container in accordance with good engineering practices, including seeking expert advice, where
appropriate.
Security
The SPCC regulations state that you must "fully fence each facility handling, processing,
or storing oil, and lock and/or guard entrance gates when the facility is not in production or is
unattended." 40 CFR § 112.7(g)(l). You have asked whether two specific sets of circumstances
would likely be determined to provide "equivalent environmental protection" to this requirement.
The first is where the area of the facility directly involved in the handling, processing and storage
of oil is adequately fenced. The second is where the facility is equipped with a "pump house" or
"pump shack," which contains, among other appropriate things, a master disconnect switch from
which all power to pumps and containers is cut off when the facility is unattended.
With respect to your first scenario, it is our view that, as a general matter, adequately
fencing all discrete areas directly involved in the handling, processing and storage of oil would
provide equivalent environmental protection to fencing the entire footprint of the facility, since it
is potential for harm to this equipment that poses the risk addressed by the fencing requirement.
With respect to the second scenario, the approach you suggest would appear to generally
provide environmental protection equivalent to fencing for risks associated with the potential for
unauthorized access to pumping equipment. In other words, cutting off power in the manner you
suggest would likely provide the added layer of protection offered by a fence should the other
security measures offered by the rule, in this case 40 CFR § 112.7(g)(3)'s requirements for
securing pumps, fail. However, because cutting off power as suggested does not address risks to
containers, piping and appurtenances not associated with the pumps at the facility, it does not
appear to provide protection equivalent to fencing as it relates to risks to such equipment.
Conclusion
Please note that determinations of "equivalent environmental protection" must be
implemented and documented in accordance with 40 CFR § 112.7(a)(2). In addition, please be
aware that the conclusions drawn in this letter are only for the purposes of meeting the
"environmental equivalence" standard in the SPCC regulation. PE's might nevertheless decide
to recommend non-destructive shell testing and fencing of the entire footprint of the facility for
reasons other than compliance with the SPCC rule (e.g., to protect an owner's investment in
equipment or to meet other local, state or federal requirements).
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Finally, this letter is meant to provide guidance on the "equivalent environmental
protection" standard. It docs not, however, substitute for EPA's statutes or regulations, nor does
it itself constitute a regulation. Thus, it cannot impose legally-binding requirements on EPA,
States, or the regulated community, and its recommendations may not be appropriate at an
individual site based on site-specific circumstances.
Sincerely,
Marianne Larmont Horinko
Assistant Administrator
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UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, O.C. 20460
JUl | 4 2000
Mr. Chris Early
Safety-Kleen Corporation
1301 Gervais Street
Columbia, SC 29201
OFFICE OF
SOLID WASTE AND EMERGENCY
RESPONSE
Dear Mr. Early:
Thank you for your e-mail of May 31, 2000. Through this letter, we respond to
the questions you posed in your e-mail.
Your first set of questions concerned the meaning of the terms "transportation-
related" and "non-transportation-related" as they relate to SPCC facilities. You also
raised issues concerning transfers of oil in the first set of questions. You posed the fact
situation of "a rail car containing oil that enters my site by crossing site boundaries."
You added that the "rail car is one of many rail cars and is the only rail car containing
oil." We will repeat your questions, and answer them immediately below. We note that
we have coordinated our response with the U.S. Department of Transportation (DOT).
1. Question: "If the rail car is passing through my facility and the oil contained in this
rail car is not loaded or unloaded is it subject to the SPCC requirements including
SPCC Plan and containment system/diversionary structure or proof of impracticability
requirements? Or, is this rail car subject to DOT requirements because it is considered
as a transportation-related unit?"
Answer: As a general rule, we will presume that the rail car is Considered to be a
"transportation-related facility" under the 1971 Memorandum of Understanding (MOU)
between DOT and the U.S. Environmental Protection Agency (EPA) if it is consigned to
your property or is consigned elsewhere and is being stored incidental to transportation
in commerce. Storage incidental to transportation in commerce is storage between the
time the oil is offered for transportation to a carrier until the time that it reaches its
destination and is accepted by the consignee, assuming no circumstances marking an
end to the transportation process. EPA will consider all the circumstances concerning
the presence of the rail car at the facility before determining that there has been an end
to the transportation process and a beginning of non-transportation-related storage
subject to SPCC requirements. If non-transportation-related storage has begun, the rail
car will be subject to SPCC requirements if it contains above the regulatory threshold
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amount and there is a reasonable possibility of discharge from the rail car to navigable
waters or adjoining shorelines. If the rail car is consigned to the Safety-Kleen facility, as
indicated on shipping papers, bills of lading, or other shipping documentation, then
transportation of the rail car ends once it arrives at the facility, and the rail car is subject
to SPCC requirements. However, if the rail car is consigned to a different facility and is
merely passing through the Safety-Kleen facility on its way to its consigned destination
with no unreasonable delays, then the rail car is considered to be in storage incidental
to transportation in commerce and is not subject to SPCC requirements. Instead the
car is subject to applicable DOT requirements for the duration of such transportation.
2. Question: "If this rail car stops on my property for any period of time but the oil in
the rail car is never loaded or unloaded is it subject to SPCC requirements at any time
including SPCC Plan and containment system/diversionary structure or proof of
impracticability requirements?"
Answer: See the answer to Question 1 above.
3. Question: "If the rail car is loaded or unloaded at any time is it subject to SPCC
Plan and containment system/diversionary structure or proof of impracticability
requirements?"
Answer: The loading or unloading of the rail car may mark an end to the transportation
process and the beginning of non-transportation-related storage, triggering all SPCC
requirements, assuming that the rail car stores oil in an amount above the regulatory
threshold and that there is a reasonable possibility of discharge to navigable waters or
adjoining shorelines. In this case, the rail car itself may become the non-transportation-
related facility even if no other containers at the property would qualify the property as a
non-transportation-related facility.
4. Question: "If the rail car is loaded/unloaded intermittently (i.e., over a period of 14
days oil in the rail car is unloaded on two consecutive Mondays) is the rail car subject to
SPCC requirements only during the loading events including SPCC Plan and
containment system/diversionary structure or proof of impracticability requirements?"
Answer: The loading or unloading of the rail car, whether intermittent or not, may mark
an end to the transportation process and the beginning of non-transportation-related
storage, triggering all SPCC requirements, assuming that the rail car stores oil in an
amount above the regulatory threshold and that there is a reasonable possibility of
discharge to navigable waters or adjoining shorelines. In this case, the rail car itself
may become the non-transportation-related facility even if no other containers at the
property would qualify the property as a non-transportation-related facility.
5. Question: "If the rail car enters my site (1/3 crosses the facility boundaries), is any
portion of the rail car subject to SPCC Plan requirements including SPCC Plan and
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containment system/diversionary structure or proof of impracticability requirements?"
Answer: If by entry on the site, the rail car has reached its ultimate destination, then
the transportation process has ended and non-transportation-related storage has
begun, triggering all SPCC requirements, assuming that the rail car stores oil in an
amount above the regulatory threshold and that there is a reasonable possibility of
discharge to navigable waters or adjoining shorelines. In this case, the rail car itself
becomes the non-transportation-related facility even if no other containers at the
property would qualify the property as a non-transportation-related facility.
Your second set of questions posited the fact situation that you demonstrate in
your SPCC Plan that it is impracticable to provide containment systems/diversionary
structures and instead provide a strong oil contingency plan.
1. Question: "Does the word 'demonstrate' used here indicate that the SPCC Plan will
only require certification by a Registered Professional Engineer no matter the reason
used to determine impracticability?"
Answer The owner or operator of the facility must demonstrate impracticability if he
cannot provide secondary containment. The Professional Engineer must certify that
demonstration of impracticability. If the Regional Administrator disagrees with the
owner or operator's determination, he may require that the owner or operator amend his
Plan.
2. Question: "In developing a strong Oil Contingency Plan who determines if the plan
is 'strong' enough to respond and prevent released oil from reaching navigable water?"
Answer The owner or operator of the facility must determine that the Contingency
Plan is adequate to meet regulatory requirements. The Professional Engineer must
certify that determination. If the Regional Administrator disagrees with the owner or
operator's determination, he may require that the owner or operator amend his Plan.
Your third set of questions asked "at what point the following transportation-
related facility unite become non-transportation related and subject to SPCC
requirements."
a. Question: "Rail car"
Answer: A rail car may or may not be transportation-related, depending on the use to
which it is put. Seethe 1971 MOU,§ ll(1)
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U.S. Department
of Transportation
Research &
Special Programs
Administration
400 Seventh Street S.W.
Washington, D.C. 20S90
From:
FEB -4 2000
U.S. Environmental
Protection Agency
Office Solid Waste &
Emergency Response
401 M Street. SW, 5201G
Washington, DC 20460
To:
Subject:
I. Purpose
Stephen D. Luftig, Director, Office of Emergency and Remedial Respo
States Environmental Protection Agency
Department of Transportation, Office of Pipeline Safety Regional Directors
Director, Office of Site Remediation and Restoration EPA Region I
Director, Emergency and Remedial Response Division EPA Region II
Directors, Hazardous Waste Management Division EPA Regions
III and IX
Director, Waste Management Division EPA Regions IV, VIII
Directors, Superfund Division EPA Regions V, VI, VII
Director, Environmental Cleanup Office EPA Region X
Jurisdiction over Breakout Tanks/Bulk Oil Storage Tanks (Containers) at
Transportation-Related and Non-Transportation-Related Facilities
The purpose of mis agreement is to clarify jurisdictional issues and establish mutual goals
for the Office of Emergency and Remedial Response, Environmental Protection Agency (EPA)
and the Office of Pipeline Safety, Department of Transportation (DOT). This letter does not
amend the 1971 MOU between the EPA and DOT or redelegate any responsibilities agreed to
under that MOU or previously assigned to DOT or EPA under Executive Order 12777 or any
previous Executive Order.
n. Authority and History
Section 311 of the Clean Water Act (C WA) (33 U.S.C. 1321) gives the President
authority to issue regulations regarding prevention, preparedness, and response planning for
facilities. Executive Order 12777, signed on October 18,1991, delegates responsibilities under
CWA Section 311 to EPA to issue regulations regarding prevention, preparedness, and response
planning for non-transportation-related onshore facilities. EPA was also delegated responsibility
1
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to establish procedures, methods, and equipment and other requirements to prevent and contain-
discharges of oil and hazardous substances from non-transportation-related onshore facilities. -
Those regulations are found at 40 CFR 112. DOT was delegated authority to issue regulations-
regarding prevention, preparedness, and response planning at transportation-related onshore-
facilities. DOT was also delegated responsibility to establish procedures, methods, and-
equipment and other requirements to prevent and contain discharges of oil and hazardous-
substances from transportation-related onshore facilities. DOT issued response planning-
regulations for transportation-related onshore oil pipelines, found at 49 CFR 194.-
DOT also issued safety standards found at 49 CFR 195 for pipeline facilities under the-
Pipeline Safety Act of 1992 (49 U.S.C. 60101). DOT considers environmental factors when-
issuing pipeline safety standards. -
III. Current Status at Complex Facilities
A 1971 Memorandum of Understanding (MOU) between the EPA and DOT defines-
transportation and non-transportation-related activities. A facility with both transportation-
related and non-transportation-related activities is a "complex facility" and is subject to the dual-
jurisdiction of EPA and DOT. Both EPA and DOT have determined that the definition of a-
complex facility, as currently interpreted under both agencies programs, can include an entire-
facility or a single tank. Owners or operators of a complex facility must comply with all the-
regulatory requirements of both agencies when both agencies have jurisdiction. An example of-
dual jurisdiction is a bulk storage container serving as a tank storing oil while also serving as a-
breakout tank for a pipeline or other transportation purposes. Attachments 1-10 provide practical-
examples of complex facilities showing jurisdictional delineation to minimize potential-
confusion over regulatory responsibility. -
IV. Next Steps
To improve communications, both DOT and EPA have initiated talks at the Headquarters-
level. These talks will be expanded to include regional representatives. Better communications-
entails; (1) improving information sharing on pipeline and tank incidents resulting in discharges-
to navigable water, material failures, human errors and other activities resulting in a discharge;-
(2) improving information sharing relating to pollution prevention, preparedness, and response;-
(3) sharing critiques of response efforts by EPA On-Scene Coordinators (OSCs) with DOT to-
enhance response planning of the pipeline operator (DOT may also consider these critiques in-
revisions to its regulations); (4) including an EPA participant on the Technical Hazardous Liquid-
Pipeline Safety Standards Committee (THLPSSC); (5) including a DOT Office of Pipeline Safety-
Regional member on each Inland Area Committee who may advise the EPA OSC on issues-
related to pipelines and breakout tanks; (6) continuing the DOT practice of offering EPA OSCs-
the opportunity to review submitted response plans before DOT approval; and (7) continuing-
discussions to resolve the jurisdictional issues surrounding oil gathering lines and their associated-
tanks.-
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Cross training is also important. EPA will make space available for DOT representatives-
to attend Spill Prevention, Control, and Countermeasure and Facility Response Planning training-
courses. DOT will make space available for EPA representatives and OSCs to attend courses in-
pipeline safety and inspection. DOT and EPA personnel will establish the appropriate level of-
participation in these training opportunities over the next three years. The agencies will also-
explore other opportunities for cross training including the Freshwater Spill Symposium,-
Preparedness for Response Exercise Program (PREP), etc. -
DOT and EPA will establish procedures for the joint inspection of facilities subject to-
dual jurisdiction. A joint inspection will be considered the equivalent of a separate inspection by-
each agency. DOT and EPA will identify risk factors to consider when identifying high-
priority/high-risk facilities subject to joint inspections. These risk factors include, but are not-
limited to; proximity to densely populated areas, proximity to navigable waters or-
environmentally sensitive areas as defined in Area Contingency Plans or other appropriate-
documents, areas likely to be subject to natural disasters, facility spill history, and compliance-
history. DOT and EPA regional representatives will use the procedures to identify thosc-
facilities that will be jointly inspected by both agencies. Facilities should be offered the-
opportunity to elect to participate in joint inspections. A joint inspection does not abridge the-
ability of each agency to implement enforcement activities arising from those inspections, nor-
limit the right to conduct separate inspections of any facility subject to dual jurisdiction. DOT-
and EPA will endeavor to conduct six to ten joint inspections nationwide within one year of this-
memorandum. The agencies will assess the effectiveness of the joint inspection program at the-
completion of all of the joint inspections.-
V. Immediate Considerations and Long Term Goals
While DOT and EPA have different historical emphases, our respective goals are-
complementary. The mutual long term goals of EPA and DOT are: -
1. To ensure that all breakout tanks/bulk storage containers are appropriately regulated
under all applicable statutes, -
2. That the rules and enforcement practices of both agencies are substantially equivalent -
to the extent possible and, -
3. That as many facilities as possible are subject to single jurisdiction in the interest of
regulatory efficiency. -
DOT and EPA want to encourage the use of tank management programs which exemplify-
"best practices/good engineering and operational practices" in the industry. Our efforts to-
recognize excellence in performance will enable both agencies to runnel lessons back into our-
tank programs to ensure that they are dynamic and able to keep pace with developments in the-
filcd. Both agencies share the goal of improving the effectiveness of our tank inspection-
programs while focusing our limited resources on those facilities that pose the greatest risk to the-
environment-
3,
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Over a five-year period, DOT and EPA shall undertake joint efforts to measure the-
effectiveness of DOT and EPA regulatory programs in protecting the environment and-
contributing to the safety of the regulated industry. The agencies will determine and agree upon-
factors including, but not limited to regulations, implementation, enforcement, and additional-
exemplary protective measures. DOT and EPA may invite the Coast Guard to participate in or-
review these efforts. -
EPA and DOT are committed to working diligently towards achieving these goals. Until-
these long term goals are achieved, EPA and DOT shall respect the jurisdiction of its sister-
agency and encourage regulated facilities to fully comply with each agency's regulations.-
For more information contact David Lopez, Director, Office of Emergency and Remedial-
Response Oil Program Center at (703) 603-8707 and Stacey Gerard, Director, Office of Policy,-
Regulations, and Training (202) 366^595.-
Attachments-
cc: d Timothy Fields Jr, Assistant Administrator, OSWER-
Mike Shapiro, Deputy Assistant Administrator, OSWER-
Jim Makris, Director, CEPPO, OSWER-
Steve Herman, Assistant Administrator, OECA-
Eric Schaeffer, Director, Office of Regulatory Enforcement, OECA-
Earl Salo, Assistant General Counsel for Superfund, OGC-
Bob Cianciarulo, Superfund/Oil Program Lead Region Coordinator-
EPA Regional Removal Managers-
Elaine Joost, Acting Chief Counsel, RSPA-
Commandant, U.S. Coast Guard (G-MS, G-MO, G-MSO, G-MOC, G-MOR)-
r:\text\rspa\luffell6.wpd 4- Rev 02/03/00-
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Pt, 112, App. C 40 CFR Ch. I (7-1-03 Edition)
ATTACHMENTS TU APPENDIX C
Attachment CM
Flowchart of Criteria for Substantial Harm
1H«* the facility transfer oil over
water to *if from vessels anJ docs
the fjicUib, have a tinal oil
siora-jc capacity greater ilion or
CHM*) lu -12.000 gallons?
No
Yes
Submit Response Plan
Oocs the facility Imvc a toiaF oJI
.storage capacity givaier ihan or
equal to I million gallon*'1
W [thin any db»vcg[\wnt capacity of ihe lar^esi
jbovfjivwitl i>il su>rjige tank plus
pillnw for
Ii ihe Jaciliiy located ai a distance' such
lliai a discharge fiixn the facitii> con id
Cuu^t: m'tuiy to fish ;«i and v«sel reipoasc Plans: Fish and Wildiifis anj
Sensitive Environnwnts* (59 FR 14713. March 39. 1994) and the apphcablc Area Contingency
rijn.
' Public drinking water intakes are analogous lo pubJic uatcr ^yslctns as described at CFR
52
-------
Environmental Protection Agency
ATTACHMENT C- II -CERTIFICATION OF THK AP-
PLICAHIUTV 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,
-------
DISCLAIMER
This document provides guidance to EPA inspectors, as well as to owners and operators of
facilities that may be subject to the requirements of the Spill Prevention, Control, and
Countermeasure (SPCC) rule (40 CFR Part 112) and the general public on how EPA intends the
SPCC rule to be implemented. The guidance is designed to implement national policy on these
issues.
The statutory provisions and EPA regulations described in this guidance document contain
legally binding requirements. This guidance document does not substitute for those provisions or
regulations, nor is it a regulation itself. In the event of a conflict between the discussion in this
document and any statute or regulation, this document would not be controlling. Thus, it does not
impose legally binding requirements on EPA or the regulated community, and might not apply to a
particular situation based upon the circumstances. The word "should" as used in this Guide is
intended solely to recommend or suggest, in contrast to "must" or "shall" which are used when
restating regulatory requirements. Similarly, model SPCC Plans in Appendices D, E, and F, as well
as examples of SPCC Plan language in the guidance, are provided as suggestions and illustrations
only. While this guidance document indicates EPA's strongly preferred approach to assure
effective implementation of legal requirements, EPA decisionmakers retain the discretion to adopt
approaches on a case-by-case basis that differ from this guidance where appropriate. Any
decisions regarding a particular facility will be made based on the statute and regulations.
Interested parties are free to raise questions and objections about the substance of this
guidance and the appropriateness of the application of this guidance to a particular situation. This
guidance is a living document and may be revised periodically without public notice. This document
will be revised, as necessary, to reflect any relevant future regulatory amendments. EPA welcomes
public comments on this document at any time and will consider those comments in any future
revision of this guidance document.
U.S. Environmental Protection Agency vii Version 1.0,11/28/2005
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SPCC Guidance for Regional Inspectors
This page intentionally left blank.
U.S. Environmental Protection Agency viii
Version 1.0, 11/28/2005
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