Rivers and Harbors Act

The Rivers and Harbors Act of 1899 was intended to protect the navigability of commercial waters.

Federal Water Pollution Control Act

• The FWPCA provided the first funds for constructing the public works that treat municipal wastewater before it is discharged into the environment. It was later amended to create the first Clean Water Act.

The Federal Water Pollution Control Act (FWPCA) was enacted in 1948 and provided the first funds for constructing publicly owned treatment works (POTWs) that treat municipal wastewater prior to its discharge into the environment.

The FWPCA was amended on April 3, 1970, by the Water Quality Improvement Act (WQIA) of 1970 (under Public Law 91-224). The WQIA amended the prohibitions on discharges of oil to allow such discharges only when consistent with regulations to be issued by the President and where permitted by Article IV of the 1954 International Convention for the Prevention of Pollution of the Sea by Oil (see 33 U.S.C. 1321).

In issuing regulations, the President was authorized to determine quantities of oil which would be harmful to the public health or welfare of the U.S., including, but not limited to, fish, shellfish, and wildlife, as well as public and private property, shorelines, and beaches.

Water Quality Act

The Water Quality Act of 1965 established interstate water quality standards, requiring that each water body achieve or maintain specific water quality standards.

Clean Water Act

• The Clean Water Act is the principal federal statute that protects navigable waters and adjoining shorelines from pollution.

When water is so polluted it can catch fire, the public and national news media will notice. The overwhelming public response to a Cuyahoga River fire in Cleveland in June 1969 prompted Congress to enact the Federal Water Pollution Control Act (FWPCA) of 1972, as amended.

The law became better known as the Clean Water Act (CWA), and the CWA is the principal federal statute for protecting navigable waters, adjoining shorelines, and the waters of the contiguous zone from pollution, including oil spills. It established a technology-based approach to maintaining water quality.

The Act prohibits discharges without a permit and allows permitted discharges to release only limited amounts of chemicals into navigable waters. As a result of the CWA, most point source discharges were successfully controlled, and the quality of the nation’s waters generally remained stable or improved slightly. The CWA sets the framework for a comprehensive program for water pollution control. The major objectives of the CWA include eliminating pollutant discharges to navigable waters, attaining water quality standards that provide for the protection of fish, shellfish, and wildlife, and providing federal financial assistance for the construction of publicly owned treatment works (POTW) facilities.

Section 311 of the CWA addresses the control of oil and hazardous substance discharges and provides the authority for promulgation of a regulation to prevent, prepare for, and respond to such discharges. Specifically, section 311(j)(1)(C) mandates regulations establishing procedures, methods, equipment, and other requirements to prevent discharges of oil from vessels and facilities and to contain such discharges.

Through an executive order, the President delegated the authority to regulate non-transportation-related onshore and offshore facilities to the Environmental Protection Agency (EPA), and the authority to regulate transportation-related onshore and offshore facilities to the U.S. Coast Guard (USCG), which currently operates under the authority of the U.S. Department of Homeland Security (DHS).

Both EPA and the USCG have consistently interpreted and administered section 311 as applicable to spills of non-petroleum-based oils (particularly because of the common physical and chemical properties of animal fats and vegetable oils) and petroleum oils, as well as their common potential for adverse environmental impact when discharged into water.

Oil Pollution Act

• The Oil Pollution Act of 1990 streamlined the EPA’s ability to prepare for and respond to catastrophic oil spills.

In response to a devastating oil discharge into Alaska’s Prince William Sound in 1989 from an ocean vessel, as well as other major oil spills, Congress enacted the Oil Pollution Act of 1990 (OPA). OPA streamlined and strengthened the Environmental Protection Agency’s (EPA’s) ability to prepare for and respond to catastrophic oil discharges.

Specifically, OPA expanded prevention and preparedness activities, improved response capabilities, ensured that shippers and owners or operators of facilities that handle oil pay the costs associated with discharges that do occur, expanded research and development programs, and established an Oil Spill Liability Trust Fund.

OPA section 4202(a)(6) amended Clean Water Act (CWA) section 311(j) to require promulgation of regulations to require owners or operators of certain vessels and facilities to prepare and submit facility response plans (FRPs) for responding to a worst-case discharge of oil and to a substantial threat of such a discharge.

OPA defined oil under section 1001 differently than the CWA section 311(a)(1) definition. Under OPA, “oil” means “oil of any kind or in any form, including petroleum, fuel oil, sludge, oil refuse, and oil mixed with wastes other than dredged spoil, but does not include any substance which is specifically listed or designated as a hazardous substance under subparagraphs (A) through (F) of section 101(14) of the Comprehensive Environmental Response, Compensation, and Liability Act (42 U.S.C. 9601) and which is subject to the provisions of that Act.”

The OPA definition did not amend the original CWA definition of oil and, therefore, was not incorporated into the regulation Part 112, the EPA Oil Pollution Prevention Standard.

OPA section 4113(a) required that the President conduct a study to determine whether liners or other secondary means of containment should be used to prevent leaking or aid in leak detection at onshore facilities used for the bulk storage of oil located near navigable waters. Executive Order 12777 tasked EPA with conducting this study.

The study resulted in EPA’s recommendation to initiate a voluntary program to prevent leaks and spills, rather than a regulatory amendment. The agency clarified that it is not necessary for facility owners and operators to install liners in order to comply with the Oil Pollution Prevention Standard. The agency said: “’Effective containment’ does not mean that liners are required for secondary containment areas. Liners are an option for meeting the secondary containment requirements, but are not required.”

Edible Oil Regulatory Reform Act

• EORRA required the federal government to establish separate classes for edible fats and oils from mammals, fish, and vegetables and led to the EPA declaring that non-petroleum oils pose similar environmental hazards to petroleum-based oils.

In 1995, Congress enacted the Edible Oil Regulatory Reform Act (EORRA). The statute mandates that most federal agencies must differentiate among, and establish separate classes for, various types of oils, specifically, animal fats and oils and greases, fish and marine mammal oils, oils of vegetable origin, and other oils and greases (including petroleum).

In differentiating among these classes of oils, EORRA directed the agencies to consider differences in these oils’ physical, chemical, biological, and other properties, and in their environmental effects.

As a result, the Environmental Protection Agency (EPA) clarified that animal fats and vegetable oils do not markedly differ from petroleum oils in properties or environmental effects, and the agency published a rulemaking establishing regulatory language to address non-petroleum oils more specifically.

Related regulation 40 CFR 109

• The guidelines in Part 109 establish the minimum criteria for the development of state and local contingency plans for responding to and minimizing damage from oil discharges.

Part 109 is called “Criteria for State, Local and Regional Oil Removal Contingency Plans.” The criteria in this regulation are provided to assist state, local, and regional agencies in the development of oil removal contingency plans for the inland navigable waters of the U.S. and all areas other than the high seas, coastal and contiguous zone waters, coastal and Great Lakes ports and harbors and such other areas as may be agreed upon between the Environmental Protection Agency (EPA) and the Department of Transportation (DOT).

The guidelines in this part establish minimum criteria for the development and implementation of state, local, and regional contingency plans by state and local governments in consultation with private interests to ensure timely, efficient, coordinated, and effective action to minimize damage resulting from oil discharges. Such plans are directed toward the protection of the public health or welfare of the U.S., including, but not limited to, fish, shellfish, wildlife, and public and private property, shorelines, and beaches. The development and implementation of such plans shall be consistent with the National Oil and Hazardous Materials Pollution Contingency Plan (also known as the National Contingency Plan).

State, local, and regional oil removal contingency plans must provide for the coordination of the total response to an oil discharge so that contingency organizations established thereunder can function independently, in conjunction with each other, or in conjunction with the National and Regional Response Teams established by the National Contingency Plan.

Related regulation 40 CFR 110

• Part 110, the so-called “sheen rule,” helps define what is a reportable discharge of oil on waterways and adjoining shorelines.

Part 110 is called “Discharge of Oil” but is also known as the “sheen rule.” These regulations apply to the discharge of oil prohibited by section 311(b)(3) of the Federal Water Pollution Control Act (FWPCA), as amended, 33 U.S.C. 1251 et seq., also known as the Clean Water Act (CWA).

Part 110 defines a discharge of oil into or upon the navigable waters of the U.S. or adjoining shorelines in quantities that may be harmful under the CWA as that which:

• Causes a sheen or discoloration on the surface of the water or adjoining shorelines;
• Causes a sludge or emulsion to be deposited beneath the surface of the water or upon adjoining shorelines; or
• Violates an applicable water quality standard.

A discharge meeting any of the above criteria triggers requirements to report to the National Response Center (NRC). The failure to report such a discharge may result in criminal sanctions under the CWA.

The appearance of a “sheen” on the surface of the water is often used as a simple way to identify harmful discharges of oil that should be reported. However, the presence of either of the other two criteria also indicates a harmful discharge regardless of whether there is a sheen on the water surface.

Related regulation 40 CFR 112

• Part 112 is the primary regulation that the EPA uses to establish requirements for oil-producing facilities to help prevent harmful discharges of oil and to respond quickly and appropriately to protect waterways if spills do happen.

Promulgated on December 11, 1973, Part 112 is called “Oil Pollution Prevention.” The regulation was mandated by the Federal Water Pollution Control Act (FWPCA) of 1972 (also called the Clean Water Act (CWA)) for the prevention of oil spills into navigable waters and adjoining shorelines of the U.S. Unlike some other federal environmental programs, the CWA does not authorize the Environmental Protection Agency (EPA) to delegate the Oil Pollution Prevention Program implementation or enforcement to state, local, or tribal representatives. Therefore, it is entirely implemented and enforced by federal EPA.

SPCC rule

Subparts A through C of Part 112 are often referred to as the spill prevention, control, and countermeasure regulations, or simply the “SPCC rule.” Focusing primarily on facility-related oil spill prevention, preparedness, and response, the SPCC rule is designed to protect public health, public welfare, and the environment from potential harmful effects of oil discharges to navigable waters or adjoining shorelines. The rule requires certain facilities (that could reasonably be expected to discharge oil in quantities that may be harmful into navigable waters of the U.S. or adjoining shorelines) to develop and implement SPCC Plans. The written plans ensure that these facilities put in place containment, controls, and countermeasures that will prevent oil discharges. The requirements to develop, implement, and revise the SPCC Plan, as well as train employees to carry it out, allow facility owners and operators to achieve the goal of preventing, preparing for, and responding to oil discharges that threaten navigable waters and adjoining shorelines.

Facility response plans

Part 112 also includes requirements for facility response plans (FRPs) that address oil discharge preparedness requirements for a subset of SPCC-regulated facilities. These requirements define who must prepare and submit an FRP and what must be included in the plan. The regulations, often referred to as the “FRP rule,” are found in Subpart D of Part 112 (and related appendices). The FRP rule applies to a subset of SPCC facilities, which are those that:

• Have 42,000 gallons or more of oil storage capacity and transfer oil over water to or from vessels; or
• The facility has a total oil storage capacity of one million gallons (or more) and one the following is true:
  • There is not sufficient secondary containment for each aboveground storage area;
  • The facility is located such that a discharge of oil could harm fish, wildlife, and sensitive environments;
  • The facility is located such that discharge of oil would shut down a public drinking water intake; or
  • The facility has had a reportable oil discharge within the last five years in an amount greater than or equal to 10,000 gallons.

Related regulation 40 CFR 113

• The regulation limits the liability for oil spills that occur at small oil storage facilities (fixed capacity of 1,000 barrels or less).

Part 113 is called “Liability Limits for Small Onshore Storage Facilities.” This regulation establishes size classifications and associated liability limits for small onshore oil storage facilities with a fixed capacity of 1,000 barrels or less. In fact, Part 113 applies to all onshore oil storage facilities with fixed capacity of 1,000 barrels or less.

When a discharge to the waters of the U.S. occurs from such facilities and when removal of said discharge is performed by the U.S. government pursuant to the provisions of subsection 311(c)(1) of the Federal Water Pollution Control Act (FWPCA), as amended, 33 U.S.C. 1151, et seq., the liability of the owner or operator and the facility will be limited to the amounts specified in section 113.4.

Part 113 does not apply to:

• Those facilities whose average daily oil throughout is more than their fixed oil storage capacity, and
• Vehicles and rolling stock.

Related regulation 40 CFR 120

• Part 120 helps to define the scope of “waters of the U.S.”

Part 120 is called “Definition of Waters of the United States.” The Clean Water Act (CWA) generally prohibits the discharge of pollutants (including oil) into ‘‘waters of the U.S.,” also known as WOTUS, without a permit issued by the Environmental Protection Agency (EPA) or a state or Tribe approved by EPA under section 402 of the Act, or, in the case of dredged or fill material, by the Army Corps of Engineers or an approved state or Tribe under section 404 of the Act.

EPA has struggled to nail down the meaning of “waters of the United States,” since a 2001 U.S. Supreme Court decision, Solid Waste Agency of Northern Cook County v. U.S. Army Corps of Engineers, and later decisions. Each EPA administration after that date has attempted to set the scope of waters that are subject to the CWA, and each final rule has faced lawsuits.

The definition of WOTUS at Part 120.2 has been revised several times. What’s more, the agency intends to propose and finalize yet another iteration in the years to come. For the current definition, facilities will want to review the latest Part 120.

Related regulation 40 CFR 300

• Part 300, also known as the National Contingency Plan or NCP, provides the federal government’s blueprint for responding to oil spills and other hazardous substance releases that require a national response.

Part 300 is called “National Oil and Hazardous Substances Pollution Contingency Plan.” The plan, more commonly called the National Contingency Plan or NCP, is essentially the federal government's blueprint for responding to both oil spills and hazardous substance releases that require a national response. The NCP provides the framework for our National Response System and the way in which the different levels of responding organizations coordinate their efforts.

The latest NCP, laid out by Part 300, is structured as follows:

• Subpart A — Introduction
• Subpart B — Responsibility and organization for response
• Subpart C — Planning and preparedness
• Subpart D — Operational response phases for oil removal
• Subpart E — Hazardous substance response
• Subpart F — State involvement in hazardous substance response
• Subpart G — Trustees for natural resources
• Subpart H — Participation by other persons
• Subpart I — Administrative record for selection of response action
• Subpart J — Use of dispersants and other chemicals
• Subpart K — Federal facilities [reserved]
• Subpart L — National oil and hazardous substances pollution contingency plan; Involuntary acquisition of property by the government
• Appendix A — The hazard ranking system
• Appendix B — National priorities list
• Appendix C — Swirling flask dispersant effectiveness test, revised standard dispersant toxicity test, and bioremediation agent effectiveness test
• Appendix D — Appropriate actions and methods of remedying releases

For more information, refer to:

• Discharges of Oil 
• CERCLA: National Contingency Plan

Part 110 applicability determination

• Notification is required whenever a harmful quantity of oil is discharged, and when that oil reaches navigable waters or adjoining shorelines in the U.S.

The Environmental Protection Agency (EPA) strives to limit the damage done by oil spills through regulations at Part 110 requiring the immediate notification of a discharge of a harmful quantity of oil.

Section 311(b)(3) of the Clean Water Act (CWA) stipulates notification is required when two criteria are met:

• A “harmful quantity” of oil is discharged; and
• That oil discharge is into the navigable waters or adjoining shorelines of the U.S.

Pursuant to CWA section 311(b)(3), release notification regulations for discharges of oil were codified in Part 110 on April 2, 1987. Section 110.3 clarifies that a discharge of a harmful quantity of oil is one that:

• Causes a film or sheen upon or discoloration of the surface of the navigable water or adjoining shorelines,
• Causes sludge or emulsion to be deposited beneath the surface of the navigable water or upon the adjoining shorelines, or
• Violates applicable water quality standards.

The appearance of a “sheen” on the surface of the water is often used as a simple way to identify harmful discharges of oil that must be reported. However, the presence of a sludge or emulsion or of another deposit of oil beneath the water surface, or the violation of an applicable water quality standard, also indicates a harmful discharge regardless of whether there is a sheen on the water surface.

Sludge means an aggregate of oil or oil and other matter of any kind in any form other than dredged spoil having a combined specific gravity equivalent to or greater than water. Water quality standards define the goals for a water body by designating its uses, setting criteria to protect those uses, and establishing provisions such as antidegradation policies to protect water bodies from pollutants.

Addition of dispersants or emulsifiers to oil to be discharged that would circumvent the provisions of Part 110 are prohibited.

Part 112 applicability determination

• A facility is covered by the Oil Pollution Prevention Standard (Part 112) if the facility is non-transportation-related; is engaged in certain oil-related activities; could discharge oil in harmful quantities; and has a certain oil storage capacity.

The Environmental Protection Agency (EPA)’s Oil Pollution Prevention Standard strives to limit damage done by oil spills through regulations designed to address a facility's preparedness and its ability to prevent and respond to an oil discharge.

General applicability criteria

The Oil Pollution Prevention Standard at Part 112 applies to facility owners or operators if:

• The facility or part of the facility is considered non-transportation-related; and
• The facility is engaged in drilling, producing, gathering, storing, processing, refining, transferring, distributing, using, or consuming oil or oil products; and
• The facility could reasonably be expected to discharge oil in quantities that may be harmful, and the discharge is to U.S. navigable waters or adjoining shorelines; and
• The facility meets at least one of the following capacity thresholds:
  • Aboveground oil storage capacity greater than 1,320 U.S. gallons, or
  • Completely buried oil storage capacity greater than 42,000 U.S. gallons.

Below is a flowchart with all four criteria:

Facilities that are owned and operated by federal, state, or local government or tribal entities are equally subject to the regulation as any other facility (although the federal government is not subject to civil penalties).

Terms related to exemptions under Part 112

• Several exemptions exist for Part 112.

The quickest way for a facility to avoid having to comply with the Part 112 exemptions are discussed here.

What is oil?

• EPA section 112.2 defines what substances are considered oils, based in part on the description included in the Clean Water Act.
• Any substance which is designated as a hazardous substance under CERCLA is not an oil.

To understand the oil-related regulations and their applicability, facilities must first understand the term “oil.”

The Environmental Protection Agency (EPA) Part 112.2 defines oil as “oil of any kind or in any form, including, but not limited to: fats, oils, or greases of animal, fish, or marine mammal origin; vegetable oils, including oils from seeds, nuts, fruits, or kernels; and, other oils and greases, including petroleum, fuel oil, sludge, synthetic oils, mineral oils, oil refuse, or oil mixed with wastes other than dredged spoil.”

Part 112 applies to the owners and operators of facilities with the potential to discharge oil in quantities that may be harmful to navigable waters or adjoining shorelines. The Part 112 definition of oil derives from section 311(a)(1) of the Clean Water Act (CWA).

Oil Pollution Act (OPA) section 1001 defined oil separately to exclude any substance which is specifically listed or designated as a hazardous substance under the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) and which is subject to provisions of that Act. Although oil is defined separately under OPA, that definition did not amend the original CWA definition of oil in section 311(a)(1) and, therefore, was not incorporated into the definition of oil under section 112.2 that applies to both spill prevention, control, and countermeasure (SPCC) and facility response plan (FRP) regulatory requirements. In response to Edible Oil Regulatory Reform Act (EORRA) of 1995 (33 U.S.C. 2720) requirements, the oil definition under section 112.2 was revised to include the categories of oil in EORRA. Those categories are: (1) petroleum oils, (2) animal fats and vegetable oils; and (3) other non-petroleum oils and greases.

The U.S. Coast Guard (USCG) maintains a separate list of substances it considers oil for its regulatory purposes. The list is available on the USCG website and may be used as a guide when determining if a particular substance is an oil. However, for purposes of EPA’s regulations, the USCG list is not comprehensive and does not include all oils that are subject to Part 112.

What is a facility?

• Facility means any mobile or fixed onshore or offshore building, property, parcel, lease, structure, installation, equipment, pipe, or pipeline (other than a vessel or a public vessel) used in oil well drilling operations, oil production, oil refining, oil storage, oil gathering, oil processing, oil transfer, oil distribution, and oil waste treatment, or in which oil is used.
• While a facility owner/operator has some discretion in defining the parameters of the facility, the boundaries of a facility may not be drawn to solely avoid regulation under Part 112.

It is important to know the meaning of the term facility and its various types in order to determine the applicability of Part 112 as a whole and to determine which sections come into play.

Facility means any mobile or fixed onshore or offshore building, property, parcel, lease, structure, installation, equipment, pipe, or pipeline (other than a vessel or a public vessel) used in oil well drilling operations, oil production, oil refining, oil storage, oil gathering, oil processing, oil transfer, oil distribution, and oil waste treatment, or in which oil is used, as described in Appendix A to Part 112.

The boundaries of a facility depend on several site-specific factors, including but not limited to the ownership or operation of buildings, structures, and equipment on the same site and types of activity at the site. Contiguous or non-contiguous buildings, properties, parcels, leases, structures, installations, pipes, or pipelines under the ownership or operation of the same person may be considered separate facilities.

The definition of facility governs the overall applicability of Part 112, and thus is used to determine the scope of a facility’s boundaries in order to determine if the facility is subject to the spill prevention, control, and countermeasure (SPCC) and/or facility response plan (FRP) requirements. The boundary or extent of a “facility” depends on site-specific circumstances. Factors that may be considered relevant in delineating the boundaries of a facility under Part 112 may include, but are not limited to:

• Ownership, management, and operation of the buildings, structures, equipment, installations, pipes, or pipelines on the site;
• Similarity in functions, operational characteristics, and types of activities occurring at the site;
• Adjacency; or
• Shared drainage pathways (e.g., same receiving water bodies).

The facility owner or operator, or a professional engineer (PE) on behalf of the facility owner/operator, must make a judgment of what constitutes the “facility.” Once the owner or operator determines the facility boundaries for purposes of the SPCC rule (Part 112 Subparts A to C), then the same boundaries apply for FRP applicability under sections 112.20 and 112.21. Note that generally, an SPCC-regulated facility excludes components that are not subject to the Environmental Protection Agency’s (EPA’s) jurisdiction but are instead subject solely to the jurisdiction of other agencies, such as the Department of Transportation (DOT) or the U.S. Coast Guard (USCG).

Contiguous or non-contiguous buildings, properties, parcels, leases, structures, installations, pipes, or pipelines under the ownership or operation of the same person may be considered separate facilities for SPCC purposes. For example, a single facility may be composed of various oil-containing areas spread over a relatively large campus, such as multiple operational areas within a military base. Each operational area may be considered a separate facility. The military base may not necessarily include single-family homes occupied by military personnel as part of the facility if these are considered personal space similar to civilian single-family residences. However, larger military barracks for which a branch of the military controls, operates, and maintains the space would be included as part of a facility.

While the facility owner/operator has some discretion in defining the parameters of the facility, the boundaries of a facility may not be drawn to solely avoid regulation under Part 112. For example, two contiguous operational areas, each with 700 gallons in aboveground storage capacity, that have the same owner, perform similar functions, are attended by the same personnel, and are in other ways indistinguishable from each other, would reasonably be expected to represent a single facility under the SPCC rule, and would therefore be required to have an SPCC Plan, since the capacity of this facility is above the 1,320-gallon aboveground threshold. These two operational areas would not be defined as two separate facilities under the definition of “facility” in section 112.2. EPA reserves the right to make its own facility boundary determination after reviewing the plan or inspecting the facility.

The facility owner or operator is responsible for ensuring that an SPCC Plan is prepared. A single site may have multiple owners and/or operators, and therefore may be divided into multiple facilities. Factors to consider in determining which owner or operator should prepare the plan include who has control over day-to-day operations of the facility or particular containers and equipment, who trains the employee(s) involved in oil handling activities, who will conduct the required inspections and tests, and who will be responsible for responding to and cleaning up any discharge of oil. EPA expects that the owners and operators will cooperate to prepare one or more plans, as appropriate, to be kept at each facility when attended more than four hours per day.

SPCC facilities include not only permanent facilities with fixed storage and equipment, but also those that have only standby, temporary, and seasonal storage as described under subparagraph 112.1(b)(3), as well as construction facilities. The owners and operators of mobile facilities (addressed in paragraph 112.3(a)) can create a general SPCC Plan, instead of developing a new plan each time the facility is moved to a new location. When a mobile facility is moved, it must be located and installed using the spill prevention practices outlined in its plan. In accordance with subparagraph 112.3(a)(2), the plan is only required to be implemented “while the facility is in a fixed (non-transportation) operating mode.” Types of operations (mobile facilities) using a mobile plan include, but are not limited to, mobile fueling operations, road construction projects, drilling operations, and workover operations.

What is an owner or operator?

• Owner or operator means any person owning or operating an onshore facility or an offshore facility.

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 maintained the facility immediately prior to such abandonment.

One commonly asked question about owners and operators is how a facility owner or operator should address a container located at the facility when the container is owned or operated by someone else. According to the Environmental Protection Agency (EPA), the owner or operator facility that includes a container being used by another person that is not under his or her operational control should coordinate with that person to determine who will prevent spills from that container

For example, transformers, or other energized electrical equipment, that are located on an easement and are under the operational control of the local electrical utility may be addressed separately by the utility. The facility owner or operator would typically not be required to include these containers in the Spill Prevention, Control, and Countermeasure (SPCC) Plan or on the facility diagram. The facility owner or operator should coordinate with the electric utility on how to address spill prevention procedures for this equipment. This determination by the plan holder must be based on site-specific factors.

What is non-transportation-related?

• The EPA does not have jurisdiction over transportation-related facilities; those are regulated by the Department of Transportation.
• Non-transportation-related facilities are regulated by the EPA.

Because the Environmental Protection Agency (EPA) does not have jurisdiction over “transportation-related” facilities, it makes the phrase “non-transportation-related” a critical term to understand.

Facilities discussed under Part 112 are divided into three categories: transportation-related facilities, non-transportation-related facilities, and complexes. The delineation between transportation-related and non-transportation-related facilities has been established through a series of Executive Orders (EOs) and Memoranda of Understanding (MOUs) as described below. Onshore and certain offshore non-transportation-related facilities (and portions of a complex) are subject to Part 112, provided they meet the other applicability criteria set forth in section 112.1.

A 1971 MOU between EPA and the Department of Transportation (DOT) clarifies the types of facilities, activities, equipment, and vessels that are meant by the terms “transportation-related onshore and offshore facilities” and “non-transportation-related onshore and offshore facilities.” DOT delegated authority over vessels and transportation-related onshore and offshore facilities to the Commandant of the U.S. Coast Guard. Sections of the MOU between EPA and DOT are included in Appendix A of Part 112. Subparagraph 112.1(d)(1)(ii) specifically exempts from Part 112 applicability any equipment, vessels, or facilities subject to the authority and control of the DOT as defined in this MOU.

A 1994 MOU among the Secretary of the Interior, the Secretary of Transportation, and the Administrator of EPA establishes the jurisdictional responsibilities for offshore facilities, including pipelines. This MOU can be found in Appendix B of Part 112. Section 112.1(d)(1)(iii) specifically exempts from spill prevention, control, and countermeasure (SPCC) applicability any equipment, vessels, or facilities subject to the authority of the DOT or the Department of the Interior (DOI) as defined in this MOU.

The table below provides examples of transportation-related and non-transportation-related facilities as the concepts apply to Part 112 applicability. Some equipment, such as loading arms and transfer hoses, may be considered either transportation-related or non-transportation-related depending on their use.

Examples of transportation-related and non-transportation-related facilities from the 1971 DOT-EPA MOU

A facility with both transportation-related and non-transportation-related activities is a “complex” and is subject to the dual jurisdiction of EPA and DOT or USCG. The jurisdiction over a component of a complex is determined by the activity occurring at that component. An activity might at one time subject a facility to one agency’s jurisdiction, and a different activity at the same facility using the same structure or equipment might subject the facility to the jurisdiction of another agency. The 1971 DOT-EPA MOU defines the activities that are subject to either EPA or DOT jurisdiction.

Note on EPA/DOT jurisdiction

Equipment, operations, and facilities are subject to DOT jurisdiction when they are engaged in activities subject to DOT jurisdiction. If those same facilities are also engaged in activities subject to EPA jurisdiction (such facilities are considered a “complex”), such activities would subject the equipment, operation, or facility to EPA jurisdiction, as well.

During the development of the Facility Response Plan (FRP) rule, EPA and other federal agencies with jurisdiction under the Oil Pollution Act (OPA) and Executive Order 12777 (including DOT) met to create an implementation strategy that minimized duplication, wherever practicable, and recognized state oil pollution prevention and response programs. One of the critical outgrowths of these efforts was the development of a definition for, and a consistent approach to, regulate “complexes.

The jurisdiction over a component of a complex is determined by the activity involving that component. An activity at one time might subject a facility to one agency’s jurisdiction, while a different activity at the same facility using the same structure, container or equipment might subject the facility to the jurisdiction of another agency.

What is the expectation to discharge?

• A discharge includes, but is not limited to, any spilling, leaking, pumping, pouring, emitting, emptying, or dumping of any amount of oil no matter where it occurs.
• Not all discharges violate the Clean Water Act, if not sufficient in quantity of if they do not reach navigable waters or adjoining shorelines.

According to Part 112.1(b), Part 112 applies to certain facilities that could “reasonably be expected to discharge oil in quantities that may be harmful, as described in [Part] 110.”

Discharge

A “discharge” as defined in section 112.2 includes, but is not limited to, any spilling, leaking, pumping, pouring, emitting, emptying, or dumping of any amount of oil no matter where it occurs. It excludes certain discharges associated with section 402 of the Clean Water Act (CWA) and section 13 of the River and Harbor Act of 1899. The primary distinction between the section 112.2 and paragraph 112.1(b) definitions of discharge is that a discharge as described in paragraph 112.1(b) is a violation of section 311 of the CWA, whereas a section 112.2 discharge includes discharges that do not reach navigable waters or adjoining shorelines. For example, if a tank leaks a puddle of oil into a building’s basement, this would be considered a discharge of oil under section 112.2 but is not necessarily a violation of the CWA because the oil did not reach a navigable water or adjoining shoreline (and would not be a discharge as described in paragraph 112.1(b)).

Part 112 includes requirements for corrective action as well as additional reporting requirements. For example, in subparagraph 112.8(c)(10), the owner or operator of a facility is required to promptly correct visible discharges that result in a loss of oil from a container. A discharge of any amount would need to be cleaned up but would not be considered a violation of the spill prohibition (a discharge as described in paragraph 112.1(b)) unless it reaches a navigable water or adjoining shorelines.

Additionally, if a facility discharged more than 42 U.S. gallons of oil in each of two discharges as described in paragraph 112.1(b) over a 12-month period, the owner or operator would be required to report each spill to the National Response Center (NRC), clean up the spill, and submit a report to the Environmental Protection Agency (EPA) Regional Administrator (RA), and may be required to amend its Spill Prevention, Control, and Countermeasure (SPCC) Plan. The same is true if the facility has a single discharge as described in paragraph 112.1(b) of more than 1,000 U.S. gallons. For more information on these reporting requirements, see section 112.4.

What container types are covered?

• Container types are defined in this section.

Which container type a facility has onsite makes a difference in whether it is covered or exempt, as well as which particular sections of Part 112 apply.

What is storage capacity?

• Storage capacity of a container means the shell capacity of the container, whether or not the container is actually filled to that capacity.
• Shell capacity is used as the measure of storage capacity, unless physical changes are made to the design shell capacity in a permanent, non-reversible, manner that reduces the capacity of the container.

Storage capacity of a container means the shell capacity of the container. It does not matter whether the container is actually filled to that capacity.

If a certain portion of a container is incapable of storing oil because of its integral design (e.g., mechanical equipment or other interior components take up space), then the shell capacity of the container is reduced to the volume the container could hold. Generally, the shell capacity is the rated design capacity rather than the working/operational capacity.

Industry standards for certain field-erected and shop-fabricated aboveground vertical storage tanks define the storage capacity of the tank as the physical capacity of the shell to contain liquid, and if present, the capacity can be limited by overflow openings that restrict the liquid level so that the container cannot hold liquid above that point. Thus, for tanks that have floating roofs or internal floating pans where overflow openings or slots are present in the shell, the freeboard volume above the overflow openings or slots is not included in the tank’s shell capacity. However, if an existing tank with overflow ports or vents is modified by covering the overflow ports or vents, the container storage capacity reverts to the original shell capacity (see Tank Re-rating section below).

Any modification to the existing port or vent must be performed in accordance with applicable industry standards. Additionally, this container alteration will require a technical amendment to the Spill Prevention, Control, and Countermeasure (SPCC) Plan certified by a professional engineer (PE) in accordance with Part 112.5. The PE will ensure that the alteration was performed in accordance with applicable industry standards, original design specifications and good engineering practice. Note that many aboveground field erected tanks have cone-down bottoms (the volume of the cone bottom can be significant for larger tanks). This volume is included in the overall storage capacity of the tank.

Devices such as hydraulic overfill valves or high-level alarms or procedures, such as operational controls, are not a means of limiting the capacity of a storage container because these systems or procedures can fail or an owner/operator can easily override or remove the controls, increasing the storage capacity of the container.

Tank re-rating

Shell capacity is used as the measure of storage capacity, unless physical changes are made to the design shell capacity in a permanent, non-reversible, manner that reduces the capacity of the container to contain liquid. An owner or operator may reduce the capacity of a tank by changing the shell dimensions (e.g., by removing shell plate sections, or installing a double bottom in accordance with applicable industry standards). When the alteration is an action such as the installation of a double bottom or new floor to the container, the integral design of the container has changed, and may result in a reduction in shell container capacity.

The Environmental Protection Agency (EPA) also considers overflow ports or vents installed in accordance with industry standards as an acceptable method of reducing the shell capacity of container. These properly engineered alterations can be considered permanent when the alteration to the container is performed in accordance with applicable industry standards. However, even when a shell penetration is completed in accordance with industry standards, this does not re-rate the storage capacity of the tank to a lower capacity if the owner or operator overrides the alteration.

When an overflow nozzle is equipped with a pipe and a valve, and the valve is then closed, the container’s capacity reverts to the original shell capacity. Let’s say your facility closes an overfill opening at some point. That would be what American Petroleum Institute (API) 653, “Tank Inspection, Repairs, Alteration, and Reconstruction,” would consider to be a “change in service.” In that case, you would need to reevaluate your tank to see if it's suitable, and the storage capacity would change. These changes in shell capacity require an amendment to the SPCC Plan.

Any container alteration will require a technical amendment to the SPCC Plan certified by a PE in accordance with 112.5. The PE will ensure that the alteration was performed in accordance with applicable industry standards and in consideration of original design specifications. Relevant industry standards include API-653.

Tank alterations which change the original shell capacity may affect secondary containment capacity necessary to comply with SPCC requirements and Facility Response Plan (FRP) applicability/requirements under Part 112 subpart D. Thus, changes in container storage capacity may affect FRP requirements for calculating the worst-case discharge volume and the amount of resources required to respond to a worst-case discharge scenario to comply with the FRP requirements.

Simply drilling a hole in the container, so that the container cannot hold liquid above that point, may not be an appropriate method to re-rate tank capacity when this alteration is not in accordance with applicable industry standards. In this case the original capacity of the container has not changed and remains the measure of storage capacity. Finally, devices (e.g., hydraulic overfill valves and high-level alarms) and procedures (e.g., administrative controls) may not be used to limit the capacity of a storage container.

SPCC Plan

• A facility that meets the applicability criteria of Part 112 must develop and implement a written Spill Prevention, Control, and Countermeasure (SPCC) Plan.

A facility that meets the applicability criteria of Part 112 must develop and implement a Spill Prevention, Control, and Countermeasure (SPCC) Plan.

However, notwithstanding the exemptions provided in paragraph 112.1(d), under paragraph 112.1(f) the Environmental Protection Agency (EPA) has discretion to require the owner or operator of any facility, subject to EPA’s jurisdiction under section 311(j) of the Clean Water Act (CWA), to prepare and implement an SPCC Plan, or part of an SPCC Plan.

The SPCC Plan elements are listed at Part 112.3 and 112.7.

Facility response plan

• An FRP is a plan for responding, to the maximum extent practicable, to a worse-case discharge, and to a substantial threat of such a discharge, of oil.

According to the Clean Water Act (CWA), as amended by the Oil Pollution Act (OPA), certain facilities that store and use oil are required to prepare and submit plans to respond to a worst-case discharge of oil and to a substantial threat of such a discharge. The Environmental Protection Agency (EPA) has established regulations that define who must prepare and submit a Facility Response Plan (FRP) and what must be included in the plan. An FRP is a plan for responding, to the maximum extent practicable, to a worse-case discharge, and to a substantial threat of such a discharge, of oil. The plan also includes responding to small and medium discharges as appropriate.

Oil spill contingency plan and written commitment of resources

• If an FRP is not submitted, and secondary containment is impracticable, an Oil Spill Contingency Plan must be included with the SPCC Plan.
• For a contingency plan to satisfy the requirements, the owner or operator of a facility must be able to activate and implement the contingency plan immediately upon detection of a discharge.

Unless a Facility Response Plan has been submitted under Part 112.20, an owner or operator who determines that secondary containment is impracticable must include with the Spill Prevention, Control, and Countermeasure (SPCC) Plan an Oil Spill Contingency Plan following the provisions of Part 109, and a written commitment of manpower, equipment, and materials required to expeditiously control and remove any quantity of oil that may be harmful (paragraph 112.7(d)).

The requirements for the content of contingency plans are given in Part 109 (Criteria for State, Local, and Regional Oil Removal Contingency Plans). The elements of the contingency plan are outlined in 109.5, and include:

• Definition of the authorities, responsibilities, and duties of all persons, organizations, or agencies that are to be involved or could be involved in planning or directing oil removal operations;
• Establishment of notification procedures for the purpose of early detection and timely notification of an oil discharge;
• Provisions to ensure that full resource capability is known and can be committed during an oil discharge situation;
• Provisions for well-defined and specific actions to be taken after discovery and notification of an oil discharge; and
• Specific and well-defined procedures to facilitate recovery of damages and enforcement measures as provided for by state and local statutes and ordinances.

A ‘‘written commitment’’ of manpower, equipment, and materials means either a written contract or other written documentation showing that the owner/operator has made provisions for items needed for response purposes. According to section 109.5, the commitment includes:

• Identification and inventory of applicable equipment, materials, and supplies that are available locally and regionally;
• An estimate of the equipment, materials, and supplies that would be required to remove the maximum oil discharge to be anticipated;
• Development of agreements and arrangements in advance of an oil discharge for the acquisition of equipment, materials, and supplies to be used in responding to such a discharge;
• Provisions for well-defined and specific actions to be taken after discovery and notification of an oil discharge, including specification of an oil discharge response operating team consisting of trained, prepared, and available operating personnel;
• Pre-designation of a properly qualified oil discharge response coordinator who is charged with the responsibility and delegated commensurate authority for directing and coordinating response operations and who knows how to request assistance from federal authorities operating under current national and regional contingency plans;
• A preplanned location for an oil discharge response operations center and a reliable communications system for directing the coordinated overall response actions;
• Provisions for varying degrees of response effort depending on the severity of the oil discharge; and
• Specification of the order of priority in which the various water uses are to be protected where more than one water use may be adversely affected as a result of an oil discharge and where response operations may not be adequate to protect all uses.

Note that a facility owner or operator does not need to develop a separate contingency plan and written commitment of manpower, equipment, and materials for each individual impracticability determination. A single plan, describing how the elements apply to each area where secondary containment is impracticable, will suffice. Additionally, the elements required under 112.7(d) may be integrated into other contingency plans that already may be in place at the facility, such as those developed pursuant to other federal or state requirements.

For a contingency plan to satisfy the requirements of 112.7(d), the owner or operator of a facility must be able to activate and implement the contingency plan immediately upon detection of a discharge. As part of evaluating the adequacy of the contingency plan, the Environmental Protection Agency (EPA) inspector should consider the time it takes facility personnel to detect and mitigate a discharge to navigable waters or adjoining shorelines. For example, at an unmanned facility (or during periods of time when a facility is unattended), effective implementation of the contingency plan may involve enhanced discharge detection methods such as more frequent facility visits and inspections, or the use of spill detection equipment.

Bulk storage containers

• Bulk storage container is defined in section 112.2. Bulk containers must be made of material compatible with what is stored in it and must have a secondary means of containment.
• Other examples of bulk storage container requirements include corrosion protection, overfill prevention, and inspections and testing.

A bulk storage container, as defined in Part 112.2, with a capacity of 55 U.S. gallons or greater, including mobile and portable bulk storage tanks, must follow specific requirements, as described under 112.8(c), 112.9(c), and 112.12(c) for onshore facilities.

It’s common sense, but a bulk container must be constructed of material compatible with what’s stored in it and with the pressure and temperature conditions.

The Environmental Protection Agency (EPA) requires that all bulk storage tanks (except mobile refuelers and other non-transportation-related tank trucks) have a secondary means of containment for the entire capacity of the largest single container and sufficient freeboard to contain precipitation. Dikes and berms are mentioned in the regulation. Similarly, catchment basins or holding ponds for undiked areas are also mentioned.

If a dike or berm is used, it must be “sufficiently impervious.” In other words, it has to have enough integrity to hold the discharge. If animals are boring holes into secondary containment, it’s not impervious. If sandy soil makes up the secondary containment floor and walls, it’s likely not going to work.

Also, certain drainage requirements apply for dikes and berms. When rainwater drains from a containment area, the owner/operator should inspect the rainwater to determine if it’s contaminated with oil, follow drainage procedures, and keep logs. A facility should not install an automatic sump pump for facility drainage. A sump pump that’s automatic will pump out not just the water but any oil too.

More information is available at 112.9(c)(4) to (6), for requirements on tank battery installations, flow-through process vessels, and produced water containers. Also see the Storage Containers at Tank Battery, Separation, and Treating Areas discussion.

Other examples of bulk storage container requirements include, but are not limited to:

• Corrosion protection,
• Overfill prevention, and
• Inspections and testing.

EPA does not prescribe what container to select or where to locate it. Those important decisions are related to oil spill prevention but come down to best practices, good engineering practices, industry standards, and perhaps state and local requirements. A professional engineer may be able to assist a facility owner or operator with these decisions. However, a few things an owner or operator should know about aboveground storage tanks include:

• If the tank will be used outdoors, it should be designated for outdoor use.
• For outdoor situations, double-wall tanks may be preferred because there’s no accumulated rainwater to remove from secondary containment with each rainstorm.
• The tank should be located so that it is accessible yet away from buildings, power lines, property lines, public roadways, and ignition sources.
• A tank should not be located near water bodies, ditches, storm drains, or wells.
• The tank should rest on a secure base on flat ground. A poor wood base, for example, may rot over time, and a hill encourages a spill to flow downhill, possibly toward water bodies.
• The tank should be placed several inches off the ground to allow for inspection and maintenance and prevent corrosion.
• Tanks should be properly labeled in accordance with Part 1910.1200, Hazard Communication.
• Barriers should be used to protect the tank from vehicle collision.
• The tank should be grounded to prevent sparks from igniting flammable vapors.

Oil-filled equipment

• Oil-filled equipment is not subject to the bulk storage container requirements but must meet the general requirements at section 112.7.

The definition of bulk storage container in Part 112.2 specifically excludes oil-filled electrical, operating, and manufacturing equipment (“oil-filled equipment”). Therefore, oil-filled equipment is not subject to the bulk storage container requirements in 112.8(c), 112.9(c), and 112.12(c). However, oil-filled equipment must meet the general requirements of 112.7.

While the integrity testing requirements of 112.8(c)(6) and 112.12(c)(6) are only applicable to bulk storage containers, the Environmental Protection Agency (EPA) believes it is good engineering practice to have some form of visual inspection or monitoring for oil-filled equipment to prevent discharges as described in 112.1(b). For example, it is a challenge to comply with security requirements under 112.7(g) and countermeasures for discharge discovery under 112.7(a)(3)(iv) without some form of inspection or monitoring program. Additionally, inspection and monitoring should be part of an effective contingency plan when secondary containment for this equipment is impracticable.

Oil-filled operational equipment

Oil-filled operational equipment is defined at 112.2. Under 112.7(k), the owner or operator of a facility with oil-filled operational equipment that meets specific qualification criteria may choose to implement the alternate requirements for qualified oil-filled operational equipment in lieu of the general secondary containment required in 112.7(c). More information is available in the Alternative measures related to qualified oil-filled operational equipment discussion.

Oil-filled manufacturing equipment

Oil-filled manufacturing equipment is subject to the general spill prevention, control, and countermeasure (SPCC) requirements under 112.7, including a demonstration of impracticability under 112.7(d) if the SPCC Plan does not provide for general secondary containment as required by 112.7(c). Oil-filled manufacturing equipment is defined in the What container types are covered discussion.

Oil-powered generators

• Newer designs of gen-sets may have a double-walled tank for the bulk oil storage container, but secondary containment must still be provided for the oil-filled operational equipment as part of the set.

Newer designs of oil-powered generators, or gen-sets, provide for a double-walled tank for the bulk oil storage container. This type of design may meet the size and general containment requirements of the spill prevention, control, and countermeasure (SPCC) rule (Part 112.8(c)(2), 112.8(c)(11) and 112.7(c), respectively) for the bulk storage container; however, this does not address secondary containment for the oil-filled operational equipment on the gen-set. (Oil-powered generators are defined in the What container types are covered discussion.)

To address the oil-filled operational equipment on these gen-sets, the facility owner or operator can provide secondary containment for the typical failure mode and most likely quantity of oil that would be discharged from the oil-filled operational equipment on the gen-set (in accordance with 112.7(c)) or provide alternative measures as provided for qualified oil-filled operational equipment in 112.7(k).

When it is impracticable to provide appropriate secondary containment for gen-sets (for either the bulk storage containers or oil-filled operational equipment of the gen-set), a professional engineer (PE) can make a determination of impracticability in accordance with 112.7(d), and can develop a contingency plan following the provisions of Part 109 and provide a written commitment of manpower, equipment, and materials to expeditiously control and remove any quantity of oil discharged that may be harmful.

Storage containers at tank battery, separation, and treating areas

• Bulk storage containers at oil production facilities must be compatible with the materials stored and condition of storage; provided with appropriate secondary containment; undergo regular inspection; and more.

An oil production facility typically includes, at a minimum, a wellhead, a tank battery, and flowlines connecting the wellhead to the tank battery and in some cases, the tank battery to an injection wellhead. The tank battery includes separation and treating equipment, a crude oil or condensate container (oil stock tank), drums of oil-based products and typically a produced water container, which receives both oil and produced water from the separator. Bulk storage containers at oil production facilities must be:

• Compatible with the materials stored and condition of storage;
• Provided with secondary containment sized for the largest single container and sufficient freeboard to contain precipitation for those containers at the tank battery, separation, and treating facility installations;
• Visually inspected periodically and upon a regular schedule for deterioration and maintenance needs, including the foundation and support; and
• Engineered in accordance with good engineering practice to prevent discharges by:
  • Ensuring adequate container capacity to assure that a container will not overfill if a pumper/gauger is delayed in making regularly scheduled rounds;
  • Providing overflow equalizing lines between containers so that a full container can overflow to an adjacent container;
  • Providing adequate vacuum protection to prevent container collapse during a pipeline run or other transfer of oil from the container; or
  • Providing high level sensors to generate and transmit an alarm signal to the computer where the facility is subject to a computer production control system.

Alternative measures are provided for flow-through process vessels and produced water containers in lieu of the secondary containment and inspection requirements of Part 112.9(c)(2) and (3) as described below.

Flow-through process vessels

Separation and treating installations at an oil production facility typically include equipment whose primary purpose is to separate the well fluid into its marketable or waste fractions (e.g., oil, gas, produced water, and solids), and to treat the crude oil as needed for further storage and shipping. Flow-through process vessels, such as horizontal or vertical separation vessels (e.g., heater-treater, separator, gun barrel, free-water knockout, etc.), have the primary purpose of separating the oil from other fractions (water and/or gas) and sending the fluid streams to the appropriate container.

Flow-through process vessels at separation and treatment installations are bulk storage containers and count toward the facility aggregate oil storage capacity. They are also subject to general secondary containment under 112.7(c) and the bulk storage container requirements of 112.9(c). The facility owner or operator must either provide sized secondary containment for flow-through process vessels in accordance with 112.9(c)(2) and inspect them following 112.9(c)(3) or comply with the general secondary containment under 112.7(c) and alternative measures provided in 112.9(c)(5).

Produced water containers

Produced water containers are bulk storage containers typically located within the tank battery. Produced water containers are part of the process that separates the oil from other fractions (water and/or gas).

Oil discharges to navigable waters or adjoining shorelines from an oil/water mixture in a produced water container may cause harm. Such mixtures are regulated as oil under Part 112. Therefore, the capacity of produced water containers counts toward the facility aggregate oil storage capacity. Produced water containers are subject to general secondary containment under 112.7(c) and the bulk storage container requirements in 112.9(c). The facility owner or operator must either provide sized secondary containment for produced water containers in accordance with 112.9(c)(2) and inspect them following 112.9(c)(3) or comply with general secondary containment under 112.7(c) and alternative measures provided in 112.9(c)(6).

The alternative measures require that the facility owner or operator conduct visual inspections; perform maintenance and corrective action; and remove, or stabilize and remediate, oil discharges. Additionally, a professional engineer (PE) must describe in the Spill Prevention, Control, and Countermeasure (SPCC) Plan and certify that a practice is established that is designed to remove the amount of free-phase oil from the produced water container on a scheduled and routine basis.

Protecting buried piping from corrosion damage

• An SPCC Plan preparer may want to consult with a qualified corrosion professional to ensure adequate corrosion protection of oil facility piping.
• Regular testing and inspection of buried piping will be required.

Unless a Spill Prevention, Control, and Countermeasure (SPCC) Plan can be self-certified, a professional engineer (PE) must certify that the plan has been prepared in accordance with good engineering practices, including consideration of applicable industry standards. Similarly, an owner/operator that self-certifies will certify that the plan has been prepared in accordance with accepted and sound industry practices.

Therefore, the SPCC Plan preparer may want to consult a qualified corrosion professional when evaluating the adequacy of cathodic protection and corrosion prevention systems at the facility. If the plan preparer determines that cathodic protection of buried piping installed on or after August 16, 2002, is not appropriate considering site-specific conditions, facility configuration, and other engineering factors (e.g., where the installation of a corrosion system would accelerate corrosion of existing unprotected equipment), then a PE may specify other measures to assess and ensure the continued fitness-for-service of piping.

For example, the owner or operator of a facility could, instead of cathodically protecting underground piping, use double-wall piping combined with an interstitial leak detection system. Cathodic protection averts discharges by preventing container corrosion; the alternative method of installing a leak detection system and double-wall piping averts discharges by detecting and containing leakage so it may be addressed before it can become a discharge as described in Part 112.1(b). As with any environmentally equivalent measure, this portion of the SPCC Plan must be certified by a PE.

Alternatively, the facility owner or operator may implement a comprehensive monitoring, detection, and preventive maintenance program for piping and appurtenances as an alternative for cathodic protection to detect and address potential discharges. The PE who certifies the SPCC Plan (or this portion of it) should develop and/or review such a program, which may combine inspection, monitoring, and leak testing elements with preventive maintenance, contingency measures, and recordkeeping. The Environmental Protection Agency (EPA) says that examples of these elements are outlined for piping systems in API Standard 570 (Third Edition 2009), “Piping Inspection Code: In-Service Inspection, Rating, Repair, and Alteration of Piping Systems.”

Where a piping inspection and testing program is used to provide environmental protection equivalent to cathodic protection, a PE will develop and/or review the scope and frequency of the program considering industry standards when available, before certifying that the SPCC Plan is in accordance with good engineering practice. Certain elements of a piping inspection and testing program (e.g., frequent leak testing of buried piping) may be emphasized over others based on site-specific factors such as length of piping at the facility or proximity to navigable waters or adjoining shorelines.

However, since leak testing only detects existing leaks, rather than preventing them, good engineering practice may suggest that testing occur at a greater frequency than when other prevention systems, such as cathodic protection and coatings, are in place. Accordingly, the PE who certifies the plan will determine the appropriate frequency of leak tests for buried piping after considering the other prevention and detection measures incorporated into the inspection program.

If alternative measures are used to meet the SPCC corrosion protection requirements for buried piping, 112.7(a)(2) requires that the plan state the reasons for nonconformance, describe in detail the alternative measures and explain how the alternative measures provide environmental protection equivalent to coating and cathodically protecting new piping. In order to be considered equivalent environmental protection to cathodic protection, a comprehensive inspection and preventive maintenance program needs to be implemented to effectively detect and address piping deterioration before it can result in a discharge as described in 112.1(b).

The EPA inspector may verify that the alternative method is described in detail in the SPCC Plan and that the plan specifies the scope and frequency of tests and inspections and/or refers to the relevant industry standards, as applicable. The EPA inspector may also review records that document these tests and inspections.

Preventing physical damage to aboveground piping/transfer operations

• When piping is aboveground, warnings to vehicles (either verbal or through signage) should be provided to protect against accidental damage.

Warnings to vehicles entering a facility may be verbal, posted on signs, or made by other appropriate means. The Spill Prevention, Control, and Countermeasure (SPCC) Plan must describe how the warnings will be communicated and should include locations of signs and information provided on the signs. When relying on verbal warnings, the plan should describe information provided as part of the verbal warnings and the procedure for issuing those warnings, including personnel responsible for providing the warnings.

Alternatively, protecting the equipment from the possibility of a collision by installing fencing, barriers, bollards, curbing or other physical obstacles may provide equivalent environmental protection. The SPCC Plan must document the method implemented at the facility to prevent physical damage to aboveground piping and transfer operations, and if an alternative method is used, then it must be documented in accordance with Part 112.7(a)(2).

Overview

• Secondary containment provisions will vary depending on the activities and location of the facility where oil is handled.

The spill prevention, control, and countermeasure (SPCC) rule includes several secondary containment provisions intended to address the various activities or locations at a facility where oil is handled. The table lists all the secondary containment provisions of the SPCC rule for different types of facilities:

General secondary containment

• General secondary containment requirements are intended to contain or hold the most likely oil discharges from an area or container.

The general secondary containment requirements are intended to address, in accordance with good engineering practice, the most likely oil discharges from areas or containers such as mobile refuelers and other non-transportation-related tank trucks; oil-filled operational or process equipment; (non-rack) transfer areas; or piping. The containment method, design, and capacity are determined by good engineering practice to contain or hold the most likely discharge of oil until cleanup occurs. The general secondary containment provision is found at Part 112.7(c).

Specific (sized) secondary containment

• Certain types of containers, activities, or equipment that have potential for oil discharge may be subject to more stringent requirements.

While all parts of a regulated facility with potential for a discharge are, at a minimum, subject to the general secondary containment requirements of 112.7(c), areas where certain types of containers, activities, or equipment are located may be subject to additional, more stringent containment requirements, including specifications for minimum capacity.

Specific secondary containment addresses the potential of oil discharges from areas of a facility where oil is stored or handled. Specific secondary containment is often called “sized” secondary containment because the containment is sized to hold the quantity from the largest single container plus sufficient freeboard (for precipitation).

The containment design, sizing, and freeboard requirements are specified by Part 112 to address a major container failure (e.g., the entire contents of the container and/or compartment) from a bulk storage container; single compartment of a tank car or tank truck at a loading/unloading rack; mobile/portable containers; and production tank batteries, treatment, and separation installations (including flow-through process vessels and produced water containers).

Other issues

Several other issues are related to all secondary containment, whether general or specific (sized).

Impracticality determination

• If a professional engineer (PE) determines that containment methods are “impracticable,” alternative modes of protection to prevent and contain oil discharges are available.
• If an impracticability determination is made, the SPCC Plan must clearly describe why secondary containment measures are impracticable and how the alternative measures are implemented.

Although secondary containment systems are preferred, they may not always be practicable. If a professional engineer (PE) determines that containment methods are “impracticable,” alternative modes of protection to prevent and contain oil discharges are available. The spill prevention, control, and countermeasure (SPCC) provision found at Part 112.7(d) allows facility owners or operators to substitute other measures in place of secondary containment.

If an impracticability determination is made, the SPCC Plan must clearly describe why secondary containment measures are impracticable and how the alternative measures are implemented (112.7(d)).

The option of determining impracticability assumes that it is feasible to effectively and reliably implement an Oil Spill Contingency Plan. An impracticability determination may affect the applicability to the facility of the Facility Response Plan (FRP) requirements under Part 112 Subpart D. In addition, an impracticability determination may affect the calculation of the worst-case discharge volume, which may impact the amount of resources required to respond to a worst-case discharge scenario to comply with the FRP requirements.

Only secondary containment requirements can be determined to be impracticable; for most other technical requirements, the SPCC rule (Part 112 Subparts A to C) provides flexibility to facility owners or operators to implement alternative measures that provide equivalent environmental protection.

Because the expertise of a trained professional is important in making site-specific impracticability determinations, owners or operators of Tier II qualified facilities (as described in 112.3(g)) who choose to self-certify their SPCC Plans in lieu of PE-certification cannot take advantage of the flexibility allowed by the impracticability provision, unless such determinations are reviewed and certified in writing by a PE (112.6(b)(3)(ii) and 112.6(b)(4)). When secondary containment is determined to be impracticable in accordance with 112.7(d), the plan must clearly explain why secondary containment measures are not practicable at the facility and provide the alternative measures required in 112.7(d) in lieu of secondary containment.

The impracticability determination is intended to be used when a facility owner or operator cannot install secondary containment by any reasonable method. Considerations include space and geographical limitations, local zoning ordinances, fire codes, safety, or other good engineering practice reasons that would not allow for secondary containment. The Environmental Protection Agency (EPA) clarified in a Federal Register notice that economic cost may be considered as one element in a decision on alternative methods, consistent with good engineering practice for the facility, but cost may not be the only determining factor in claiming impracticability. Each impracticability determination is site-specific, and EPA inspectors may evaluate the rationale for the impracticability determination described by the PE in the SPCC Plan.

Introduction

• Regularly scheduled inspections, evaluations, and testing of containers and equipment by qualified personnel are critical parts of oil discharge prevention.

The inspection, evaluation, and testing requirements of the spill prevention, control, and countermeasure (SPCC) rule are intended to prevent, predict, and detect potential integrity or structural issues before they cause a leak, spill, or discharge of oil to navigable waters or adjoining shorelines.

Regularly scheduled inspections, evaluations, and testing by qualified personnel are critical parts of oil discharge prevention. They are conducted not only on containers but also on associated piping, valves, and appurtenances and on other equipment and components that could be a source or cause of an oil discharge.

Inspection, testing, and evaluation activities may involve one or more of the following: an external visual inspection of containers, piping, valves, appurtenances, foundations, and supports; a non-destructive testing (examination) to evaluate integrity of certain containers; and additional evaluations, as needed, to assess the equipment’s fitness for continued service.

The type of inspection, testing, and evaluation program and its scope will depend on site-specific conditions and the application of good engineering practices and adherence to applicable industry standards and manufacturer’s requirements. In addition, the Environmental Protection Agency (EPA) says owners/operators should follow recommended practices, safety considerations, and other federal, state, or local regulations.

Any compliant inspection, testing, and evaluation program should specify the procedures, schedule or frequency, types of equipment covered, qualified person(s) conducting the activities, recordkeeping practices, and other elements.

Summary of requirements

• Applicable inspection and testing provisions vary depending on the type of equipment, facility, and circumstances.
• The SPCC rule is performance-based; because each facility may present unique characteristics and methods may evolve as new technologies are developed, the rule does not prescribe a specific frequency or method to perform the required inspections, evaluations, and tests.

See Table 7-1 on pages 7-3 to 7-8 in the SPCC Guidance for Regional Inspectors, which summarizes the inspection, evaluation, and integrity testing provisions that apply to different types of equipment and facilities. As shown in the table, applicable inspection and testing provisions vary depending on the type of equipment, facility, and circumstances. For example, some inspection and testing provisions apply specifically to bulk storage containers at onshore facilities (other than oil production facilities) while other inspection and/or testing requirements apply to other components of a facility that might cause a discharge (such as vehicle drains, foundations, or other equipment or devices). Animal fat and vegetable oil (AFVO) containers that meet certain criteria are eligible for differentiated integrity testing requirements. Onshore oil production facilities have a distinct set of inspection requirements including minimum expectations for a flowline maintenance program. The spill prevention, control, and countermeasure (SPCC) rule also includes regulatory alternatives to sized secondary containment that include inspection and corrective action requirements.

Finally, additional requirements apply under certain circumstances, such as when an aboveground field-constructed container undergoes repairs, alterations, or a change in service that may affect its potential for a brittle fracture or other catastrophic failure, or in cases where secondary containment for bulk storage containers is impracticable (Part 112.7(d)). Facility owners and operators must maintain records to demonstrate compliance with the inspection, evaluation, and integrity testing requirements per 112.7(e).

The SPCC rule is a performance-based regulation. Since each facility may present unique characteristics and methods may evolve as new technologies are developed, the rule does not prescribe a specific frequency or method to perform the required inspections, evaluations, and tests. Instead, a professional-engineer-certified SPCC Plan relies on the use of good engineering practice, based on the professional judgment of the professional engineer (PE), which includes consideration of applicable industry standards and the requirements of Part 112. In addition, recommended practices, safety considerations, and requirements of other federal, state, or local regulations must be considered. Thus, when certifying an SPCC Plan, a PE is also certifying that the inspection program described in the plan is appropriate for the facility and is consistent with good engineering practice.

Similarly, the owner or operator of a qualified facility who self-certifies the SPCC Plan must attest that the SPCC Plan has been prepared in accordance with the SPCC rule and accepted and sound industry practices and standards; that procedures for inspections and tests have been established for the facility; and that the plan will be implemented. While owners and operators of qualified facilities may choose not to have their SPCC Plans certified by a PE, they are still required to comply with all of the SPCC requirements and to develop and implement a spill prevention program in accordance with good engineering practices, and may do so by following regulatory guidance and industry recommended practices, consulting with tank testing professionals, and implementing standard design and operation protocols.

The preamble to the 2002 SPCC rule amendment lists examples of industry standards and recommended practices that may be relevant to determining what constitutes good engineering practice for various rule provisions.

Although the Environmental Protection Agency (EPA) refers to the use of industry standards to determine inspection and integrity testing practices, the agency does not prescribe a particular standard or schedule for testing. “Good engineering practice” and relevant industry standards change 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, industry standards may prescribe inspection intervals based on corrosion rates, risk assessments, and container size/configuration. Site-specific conditions may therefore affect the exact schedule of inspections and tests conducted under these industry standards.

Finally, environmentally equivalent measures may substitute for integrity testing requirements as allowed under 112.7(a)(2) when reviewed and certified by a PE.

Integrity testing

• Integrity testing is necessary to determine whether a bulk storage container is suitable for continued use until the next formal inspection. It measures the strength of a container and may also include leak testing.

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. Examples of integrity tests include, but are not limited to:

• Visual inspection (inspection of the outside of the container for signs of deterioration, discharges, or accumulations of oil inside diked areas. Includes visual inspection of the container’s supports and foundations);
• Radiographic examination;
• Ultrasonic Testing (UT), including ultrasonic thickness scan (UTS) and ultrasonic thickness testing (UTT);
• Magnetic flux leakage (MFL) scan;
• Helium leak testing;
• Magnetic particle examination;
• Liquid penetrant examination;
• Acoustic emissions testing;
• Hydrostatic testing;
• Inert gas leak testing; or
• Other methods of non-destructive examination.

Integrity testing is a necessary component of any good oil discharge prevention plan. Integrity testing is necessary to determine whether the bulk storage container (e.g., tank) is suitable for continued use until the next formal inspection. It will help to prevent discharges by testing the integrity of containers, ensuring they are suitable for continued service under current and anticipated operating conditions (e.g., product, temperature, and pressure). For example, testing may help facility owners or operators to determine whether corrosion has reached a point where repairs are required or replacement of the container is necessary.

Information obtained through integrity testing also enables a facility owner/operator to budget and plan for routine maintenance and any associated repairs and avoid unexpected disruptions to facility operations.

Leak testing

• Leak testing, or “tank tightness testing,” must be performed regularly on buried metallic storage tanks.

Completely buried metallic storage tanks installed on or after January 10, 1974, must be regularly leak tested. “Regular testing” means testing in accordance with industry standards or at a frequency sufficient to prevent leaks. Appropriate methods of testing should be selected based on good engineering practice, and tests conducted in accordance with Part 280.43 or a state program approved under Part 281 are acceptable.

Leak testing is often referred to as “tank tightness testing.” Tank tightness tests include a wide variety of methods. Other terms used for these methods include precision, volumetric, and nonvolumetric testing. The features of tank tightness testing vary by method, as described in the Environmental Protection Agency (EPA) Guidance^[1] on meeting UST system requirements:

• Many tightness test methods are volumetric methods in which the change in product level in a tank over several hours is measured very precisely (in milliliters or thousandths of an inch).
• Other methods use acoustics or tracer chemicals to determine the presence of a hole in the tank. With such methods, all of the factors in the following bullets may not apply.
• For most methods, changes in product temperature also must be measured very precisely (thousandths of a degree) at the same time as level measurements, because temperature changes cause volume changes that interfere with finding a leak.
• For most methods, a net decrease in product volume (subtracting out volume changes caused by temperature) over the time of the test indicates a leak.
• The testing equipment is temporarily installed in the tank, usually through the fill pipe.
• The tank must be taken out of service for the test, generally for several hours, depending on the method.
• Many test methods require that the product in the tank be a certain level before testing, which often requires adding product from another tank onsite or purchasing additional product.
• Some tightness test methods require all of the measurements and calculations to be made by hand by the tester.
• Other tightness test methods are highly automated. After the tester sets up the equipment, a computer controls the measurements and analysis.
• A few methods measure properties of the product that are independent of temperature, such as the mass of the product, and so do not need to measure product temperature.
• Some automatic tank gauging systems are capable of meeting the regulatory requirements for tank tightness testing and can be considered as an equivalent method.

The Spill Prevention, Control, and Countermeasure (SPCC) Plan must describe the method and schedule for testing completely buried tanks.

^{[1] For more information on tank tightness testing, see http://www.epa.gov/oust/ustsystm/inventor.htm. For more information on preventing and detecting underground storage tank system leaks, see http://www.epa.gov/oust/prevleak.htm.}

Piping inspection

• All piping installed or replaced after August 16, 2002, must be both protectively wrapped and cathodically protected.

Any piping installed prior to August 16, 2002, was subject to coating and cathodic protection if soil conditions warranted. However, in 2002, the spill prevention, control, and countermeasure (SPCC) rule (Part 112 Subparts A to C) was revised to require that all piping installed or replaced on or after August 16, 2002, be protectively wrapped and coated and also cathodically protected. The preamble to the final rule explains:

• “We believe that all soil conditions warrant protection of buried piping. We did not propose to make the requirement applicable to all existing piping because of the significant possibility that replacing all unprotected buried piping might cause more discharges than it would prevent. If soil conditions warrant such protection for existing piping, it is already required by the current rule.” (67 FR 47123, July 17, 2002).

Additionally, the SPCC rule has required since its original promulgation in 1973, that if any portion of buried piping at non-production facilities is exposed, the line must be inspected for deterioration, as per subparagraphs 112.8(d)(1) and 112.12(d)(1). If corrosion damage is found, additional inspection or corrective action must be taken as needed. Aboveground piping, valves, and appurtenances at non-production facilities must be regularly inspected, as per 112.8(d)(4) and 112.12(d)(4) and in accordance with industry standards. In addition, buried piping must be integrity and leak tested at the time of installation, modification, construction, relocation, or replacement.

Brittle fracture evaluation

• Brittle fracture is characterized by rapid crack formation that can cause sudden tank failure. These catastrophic failures can cause the entire contents of a container to be discharged into the environment.

Brittle fracture is a type of structural failure in aboveground steel tanks, characterized by rapid crack formation that can cause sudden tank failure. This, along with catastrophic failures such as those resulting from lightning strikes, seismic activity, or other such events, can cause the entire contents of a container to be discharged to the environment. Brittle fracture was most vividly illustrated by the splitting and collapse of a 3.8-million-gallon (120-foot diameter) tank in Floreffe, Pennsylvania, which released approximately 750,000 gallons of oil into the Monongahela River in January 1988.

A review of past failures due to brittle fracture shows that they typically occur:

• During an initial hydrotest,
• On the first filling in cold weather,
• After a change to lower temperature service, or
• After a repair/modification.

Storage tanks with a maximum shell thickness of one-half inch or less are not generally considered at risk for brittle fracture. Part 112.7(i) 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 the American Petroleum Institute API 653, Section 5, and the Steel Tank Institute STI SP001, Appendix B), evidence of this evaluation should be documented in the facility’s Spill Prevention, Control, and Countermeasure (SPCC) plan.

Industry standards discuss methods for assessing the risk of brittle fracture failure for a field-erected aboveground container and for performing a brittle fracture evaluation. These include API 653, “Tank Inspection, Repair, Alteration, and Reconstruction,” API RP 920 “Prevention of Brittle Fracture of Pressure Vessels,” and API RP 579-1/ASME FFS-1, “Fitness-for-Service.” API 653 includes a decision tree or flowchart for use by the owner or operator and professional engineer in assessing the risk of brittle fracture.

Industry standards

• Industry standards play a role in determining good engineering practice when developing an inspection program.

Industry standards are technical guidelines created by experts and stakeholders in a particular industry. They are the minimum accepted industry practice. Part 112 requires that a Spill Prevention, Control, and Countermeasure (SPCC) Plan be prepared in accordance with good engineering practice. Industry standards also play a role in determining good engineering practice when developing an inspection program. When a facility indicates in its SPCC Plan that the facility intends to use an industry standard to comply with a particular requirement (like integrity testing), then it is mandatory to implement the relevant portions of the industry standard (such as those that address integrity testing of the container).

Part 112 does not require the use of a specific industry standard for conducting inspections, evaluations, and integrity testing of bulk storage containers and other equipment at a facility. Rather, the rule provides flexibility in a facility owner or operator’s use of industry standards to comply with the requirements, consistent with good engineering practice and as reviewed by the professional engineer (PE) certifying the SPCC 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 indicates in the SPCC Plan the intent to use a standard to comply with a particular rule requirement (e.g., integrity testing), then it is mandatory to implement the relevant portions of the standard (i.e., those that address integrity testing of the container). In this case, if the industry standard is more stringent than federal regulations (e.g., for recordkeeping retention requirements), the industry standard would take precedent.

The SPCC Plan should clearly identify the standard used to comply with the SPCC requirements (Part 112 Subparts A to C). As required in 112.5(b), facility owners or operators must review their SPCC Plan at least once every five years to include more effective prevention and control technology. This may provide an opportunity to consider revisions to industry standards and determine whether these revisions impact implementation of the SPCC Plan.

Industry standards typically apply to containers built according to a specified design (American Petroleum Institute API 653, for example, applies to tanks constructed in accordance with API 650 or API 12C specifications); 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 remaining shell thickness or ability to maintain pressure. The standards specify certain visual inspections, evaluations, assessments, and tests that must be performed by inspectors certified by the standard-setting organizations (e.g., American Petroleum Institute and Steel Tank Institute).

In the preamble to a July 17, 2002, SPCC final rule, the Environmental Protection Agency (EPA) provided examples of industry standards that may constitute good engineering practice for assessing the integrity of different types of containers for oil storage. Compliance with other federal requirements and industry standards may also meet SPCC inspection, evaluation, and testing requirements. For example, the U.S. Department of Transportation (DOT) regulates containers used to transport hazardous materials, including certain oil products; mobile/portable containers that leave a facility are subject to the DOT construction and continuing qualification and maintenance requirements (49 CFR 178 and 180). Measures that comply with these DOT requirements may be used by the facility owner and operator and by the certifying PE as references of good engineering practice for assessing the fitness for service of mobile/portable containers.

Other industry standards, beyond those detailed in the tables, exist for specific equipment or purposes. Many of these are cross-referenced in API 653, including publications and standards from other organizations such as the American Society for Testing and Materials (ASTM), the American Society for Non-Destructive Testing (ASNT), and the American Society of Mechanical Engineers (ASME). Other organizations, such as the National Fire Protection Association (NFPA), the National Association of Corrosion Engineers (NACE), and the Underwriters Laboratory (UL), also provide critical information on various container types and appurtenances.

Schedule/Frequency

• Industry standards establish the scope and frequency for inspections, tests, and evaluations that considers the particular conditions of the container. These conditions may include the age, service history, original construction specifications, prior inspection results, and the existing condition of the container.

Where a specific point in time, schedule, or frequency of inspection, testing, or evaluation is specified in the regulation, the facility must adhere to it. However, in many cases the regulation calls for a periodic, regular, and/or frequent schedule or frequency. In these cases, the inspection, testing, or evaluation frequency must follow industry standards or be sufficient to prevent discharges.

Industry standards establish the scope and frequency for inspections, tests, and evaluations that considers the particular conditions of the container. These conditions may include the age, service history, original construction specifications (e.g., shop-built vs. field-erected, welded steel vs. riveted steel), prior inspection results, and the existing condition of the container. They may also consider the degree of risk of a discharge to navigable waters or adjoining shorelines (e.g., containers that are located near saltwater where an accelerated corrosion rate would be expected). The frequency of inspections is based on changing conditions of the container (e.g., corrosion rates, settling, etc.) and the interval between inspections may vary over the lifetime of the container.

Once a facility determines an inspection, testing, or evaluation schedule for its containers (based on applicable industry standards), it must document the schedule in its Spill Prevention, Control, and Countermeasure (SPCC) Plan and follow that schedule. It’s also a good idea to include a description of the conditions of the container that led to the specific schedule identified in the plan.

Qualified persons

• All inspections, tests, and evaluations should be conducted by qualified persons.

All inspections, tests, and evaluations should be conducted by qualified persons. However, only Part 112.8(c)(6) and 112.12(c)(6) specifically call for integrity tests or inspections of aboveground containers to be conducted by personnel with the appropriate qualifications.

At the same time, if the inspection, test, or evaluation is following an industry standard that mandates a person with certain qualifications, then the facility must also ensure those qualifications are met. The Spill Prevention, Control, and Countermeasure (SPCC) Plan itself, too, adhering to good engineering practices and perhaps certified by a professional engineer, may require a qualified person.

Records

• A facility must keep written procedures and a signed record of all required inspections, tests, and evaluations with the written SPCC Plan for at least three years.

A facility must keep written procedures and a signed record of all required inspections, tests, and evaluations with the written Spill Prevention, Control, and Countermeasure (SPCC) Plan for at least three years. Facilities may follow the format of records kept under their usual and customary business practices, including electronic records. For example, it may be usual and customary to keep inspection records for a drum storage area rather than for each individual drum. However a facility chooses to keep records, these records should cover the inspections, tests, and evaluations performed by personnel.

Also, industry standards often provide inspection guidelines and sample checklists. The tank inspection checklist from Appendix F of Part 112 is yet another example of the type of information that may be included on an owner- or operator-performed inspection checklist.

Overview

• The environmental equivalence provision offers flexibility to allow a facility to achieve environmental protection in a manner that fits the facility’s unique circumstances. A professional engineer must verify that any alternative measures provide equivalent protection.

The environmental equivalence provision, contained in Part 112.7(a)(2), allows for deviations from specific requirements of the spill prevention, control, and countermeasure (SPCC) rule (Part 112 Subparts A to C), as long as the alternative measures provide equivalent environmental protection. The environmental equivalence provision is a key mechanism of the performance-based SPCC rule. This flexibility enables owners and operators of facilities to achieve environmental protection in a manner that fits the facility’s unique circumstances. It also allows owners and operators to adopt more protective industry practices and technologies for their facilities as they become available.

The facility owner or operator is responsible for the selection, documentation in the SPCC Plan, and implementation in the field of SPCC measures, including any environmentally equivalent measures. However, a professional engineer (PE), when certifying a plan as per 112.3(d) or 112.6(b)(4), must verify that the plan (and any alternative methods) is in accordance with good engineering practice, including consideration of applicable industry standards. These alternative methods must also provide environmental protection equivalent to the provisions described in the SPCC rule.

Because the expertise of a trained professional is important in making site-specific equivalence determinations, owners or operators of qualified facilities (those meeting the criteria in 112.3(g)) who choose to self-certify their SPCC Plans in lieu of PE certification cannot take advantage of the flexibility allowed by the environmental equivalence provision, unless the alternative methods have been reviewed and certified in writing by a PE (112.6(b)(3)(i)).

In the SPCC context, equivalent environmental protection means an equal level of protection of navigable waters and adjoining shorelines from oil pollution. This level of protection can be achieved in various ways, but a facility may not rely solely on measures that are required by other sections of the SPCC rule (e.g., implementing secondary containment) to provide environmentally equivalent protection. While environmental equivalence need not be a mathematical equivalence, it must achieve the same desired outcome, though not necessarily through the same mode of operation.

The reason for deviating from a requirement of the SPCC rule, as well as a detailed description of the alternate method and how equivalent environmental protection will be achieved, must be stated in the SPCC Plan, as required in 112.7(a)(2). Possible rationales for a deviation include the owner or operator’s ability to show that the particular requirement is inappropriate for the facility because of good engineering practice considerations or other reasons, and that the owner or operator can achieve equivalent environmental protection in an alternate manner. Thus, a requirement that may be essential for a facility storing gasoline may be less appropriate for a facility storing hot asphalt cement, due to differences in the properties and behavior of the two products, and the facility owner or operator may be able to implement equivalent environmental protection through an alternate technology.

As mentioned above, a PE must review the selection of environmentally equivalent measures and certify them as being consistent with good engineering practice (112.3(d) or 112.6(b)(4)). The selection of alternative measures may be based on various considerations, such as safety, cost, geographical constraints, the appropriateness of a particular requirement based on site-specific considerations, or other factors consistent with engineering principles.

Alternative measures, however, cannot rely solely on measures that are already required by other parts of the SPCC rule because this would allow for approaches that provide a lesser degree of protection overall. For instance, as the Environmental Protection Agency (EPA) noted in a May 2004 letter to the Petroleum Marketers Association of America (PMAA), the presence of sized secondary containment for bulk storage containers, which is required under 112.8(c) and other relevant parts of the SPCC rule, does not provide, by itself, an environmentally equivalent alternative to performing integrity testing of bulk storage containers. Secondary containment reduces the risk of a discharge from primary containment (the container or tank) to navigable waters or adjoining shorelines and can increase the effectiveness of another prevention or control measure. However, it does not serve the purpose of integrity testing, which is to identify potential leaks or failure of the container before a discharge occurs.

Requirements eligible for environmental equivalence

Part 112.7(a)(2) allows deviations for most technical elements (112.7 through 112.12) of the spill prevention, control, and countermeasure (SPCC) rule, with the exception of the secondary containment requirements of 112.7(c) and 112.7(h)(1), and in relevant paragraphs of 112.8, 112.9, 112.10, and 112.12. Requirements eligible for environmental equivalence at all facilities include the following:

Requirements eligible for environmental equivalence at onshore facilities (excluding oil production) include the following:

Requirements eligible for environmental equivalence at onshore and offshore oil production, drilling, and workover facilities include the following:

Behavior and effects of oil discharges

• The severity of impact that an oil spill may have depends on natural conditions such as water temperature and weather, as well as characteristics of the oil itself.

Each type of oil has distinct physical and chemical properties. The severity of the impact of an oil spill depends on a variety of factors, including characteristics of the oil itself. Natural conditions, such as water temperature and weather, also influence the behavior of oil in aquatic environments.

Spilled oil immediately begins to move and weather, breaking down and changing its physical and chemical properties. As these processes occur, the oil threatens surface resources and a wide range of subsurface aquatic organisms linked in a complex food chain.

Many different types of aquatic habitats exist, with varied sensitivities to the harmful effects of oil contamination and different abilities to recuperate from oil spills. In some areas, habitats and populations can recover quickly. In other environments, however, recovery from persistent or stranded oil may take years. These detrimental effects are caused by both petroleum and non-petroleum oil.

Facility plans

• There are three primary plans that a facility might have to help it contain an oil spill: a Facility Response Plan (FRP), a Spill Prevention, Control and Countermeasure (SPCC) Plan, and an Oil Spill Contingency Plan.

Spills can happen on land or in water, at any time of day or night, and in any weather condition. Preventing oil spills is the best strategy for avoiding potential damage to human health and the environment. However, once a spill occurs, the best approach for containing and controlling the spill is to respond immediately and in a well-organized manner. A response will be quick and organized if response measures have been planned ahead of time. From a federal Environmental Protection Agency (EPA) standpoint, three primary plans come to mind:

Facility Response Plan (FRP) — If covered by Part 112.20 and 112.21, the Facility Response Plan (FRP) approved by the EPA Regional Office will be available consistent with the requirements of the National Contingency Plan (NCP), applicable Area Contingency Plans, and local emergency plans developed by local emergency planning committees (LEPCs) under Emergency Planning and Community Right-to-Know Act (EPCRA) section 303 (see 112.20(g)(1)). Appendix F to Part 112 offers a model FRP.

Spill Prevention, Control, and Countermeasure (SPCC) Plan — If covered by Part 112, the Spill Prevention, Control, and Countermeasure (SPCC) Plan will include countermeasures for discharge discovery, response, and cleanup (both the facility’s capability and those that might be required of a contractor); methods of disposal of recovered materials in accordance with applicable legal requirements; and a contact list and phone numbers for the facility response coordinator, National Response Center (NRC), cleanup contractors with whom the facility has an agreement for response, and all appropriate federal, state, and local agencies who must be contacted in case of a discharge as described in paragraph 112.1(b).

Oil Spill Contingency Plan — Unless an FRP has been submitted under 112.20, an owner or operator who determines that secondary containment is impracticable must include with the SPCC Plan an Oil Spill Contingency Plan following the provisions of Part 109 (Criteria for State, Local, and Regional Oil Removal Contingency Plans) and a written commitment of manpower, equipment, and materials required to expeditiously control and remove any quantity of oil that may be harmful (112.7(d)). The requirements for the content of these contingency plans are given in Part 109.

Other response plans at the facility level may be required under other federal, state, or local requirements.

Area Contingency Plan

• An ACP is a reference document that helps all agencies respond to environmental emergencies within a defined geographic area.

An Area Contingency Plan (or ACP) is a reference document prepared for the use of all agencies engaged in responding to environmental emergencies within a defined geographic area. An ACP may also contain sub-area and geographic response plans, which may have more limited scope than the ACP itself.

An ACP is a mechanism to ensure that all responders have access to essential area-specific information and promotes inter-agency coordination to improve the effectiveness of responses. Among other elements, the ACP will include a description of the responsibilities of owners, operators, and federal, state, and local agencies in removing a discharge.

Also to be included are descriptions on how to mitigate or prevent a substantial threat of discharge to ensure optimum communication and coordination during a response.

National Contingency Plan

• The NCP ensures that resources and expertise of the federal government are available for the type of very serious oil spills and hazardous substance releases that require a national response.

The federal government has designed a spill response plan, called the National Oil and Hazardous Substances Pollution Contingency Plan, also called the National Contingency Plan or NCP.

The NCP ensures that the resources and expertise of the federal government would be available for those relatively rare, but very serious, oil spills that require a national response. This plan was designed primarily to assist with coordinating the various federal agencies that are responsible for dealing with oil spill emergencies.

Oil discharge reporting

• Any discharge of oil in a harmful quantity that reaches a navigable waterway or adjoining shoreline must be reported according to federal reporting requirements.

Whether an oil discharge originates from a vessel, offshore facility, or onshore facility, it is reportable under Part 110 if a harmful quantity is discharged. See Covered Facilities to learn more about the applicability criteria and exemptions under Part 110. A subset of these oil discharges is also reportable under Part 112. Also, 300.300 includes discovery and notification regulations for discharges of oil.

Reporting under Part 110

If a facility or vessel discharges oil to navigable waters or adjoining shorelines, the facility is required to follow certain federal reporting requirements. Section 311(b)(3) of the Clean Water Act (CWA) stipulates notification is required when a “harmful quantity” of oil is discharged into the navigable waters or adjoining shorelines of the U.S. Pursuant to CWA 311(b)(3), release notification regulations for discharges of oil are codified in Part 110 of the Environmental Protection Agency (EPA) regulations.

Section 110.3 clarifies that a discharge of a harmful quantity of oil is one that violates applicable water quality standards, causes a film or sheen upon or discoloration of the surface of the navigable water or adjoining shorelines, or causes sludge or emulsion to be deposited beneath the surface of the navigable water or upon the adjoining shorelines. A few exemptions are listed at section 110.5.

According to section 110.6, persons in charge of a facility or vessel must immediately notify the National Response Center (NRC) as soon as they have knowledge of a non-exempt discharge of oil from that facility or vessel in a harmful quantity amount.

The contact number for the NRC is (800) 424-8802 or (202) 267-2675. The NRC is the federal government's centralized reporting center, which is staffed 24 hours a day by U.S. Coast Guard personnel.

If reporting directly to NRC is not practicable, reports also can be made to the EPA regional office or the USCG Marine Safety Office (MSO) in the area where the incident occurred.

The following information will be requested by the NRC (or EPA regional office):

• The exact address or location and phone number of the facility;
• The date and time of the discharge, the type of material discharged;
• Estimates of the total quantity discharged;
• Estimates of the quantity discharged to navigable waters or adjoining shorelines;
• The source of the discharge;
• A description of all affected media;
• The cause of the discharge;
• Any damages or injuries caused by the discharge;
• Actions being used to stop, remove, and mitigate the effects of the discharge;
• Whether an evacuation may be needed; and
• The names of individuals and/or organizations who have also been contacted.

Reporting under Part 112

Any owner or operator of a non-transportation-related facility regulated by the spill prevention, control, and countermeasure (SPCC) rule (Part 112 Subparts A to C) must submit a report to the Environmental Protection Agency (EPA) Regional Administrator within 60 days when:

• More than 1,000 U.S. gallons of oil is discharged to navigable waters or adjoining shorelines in a single event; or
• More than 42 U.S. gallons of oil in each of two discharges to navigable waters or adjoining shorelines occurs within any 12-month period.

Note that the gallon amount(s) specified (either 1,000 or 42) refers to the amount of oil that actually reaches navigable waters or adjoining shorelines, not the total amount of oil spilled. EPA considers the entire volume of the discharge to be oil for the purposes of these reporting requirements.

The written report to the EPA Regional Administrator must include the following:

• Name and location of the facility;
• Owner or operator name;
• Maximum storage or handling capacity of the facility and normal daily throughput;
• Corrective actions and countermeasures taken, including descriptions of equipment repairs and replacements;
• Adequate description of the facility, including maps, flow diagrams, and topographical maps, as necessary;
• Cause of the discharge to navigable waters, including a failure analysis;
• Failure analysis of the system where the discharge occurred;
• Additional preventive measures taken or planned to take to minimize discharge reoccurrence.

The facility must send a copy of the above information to the agency or agencies in charge of oil pollution control activities in the state in which the SPCC-regulated facility is located.

After reviewing the information, the EPA Regional Administrator may require additional information and/or an amendment to the SPCC Plan. If a facility wishes to appeal a decision made by the Regional Administrator requiring an amendment to an SPCC Plan, the facility should follow the requirements at 112.4(f).

Reporting under Part 300.300

In September 1994, EPA codified revisions to the National Contingency Plan (NCP) at Part 300.300 that included discovery and notification regulations for discharges of oil. These revisions clarify that a discharge of oil may be discovered by a report from the person in charge of a vessel or facility, a deliberate search by patrols, a random or incidental observation by government agencies or the public, or other sources. The notification provisions of this section require any person, upon the discovery of a discharge of oil, to notify the National Response Center (NRC). The NRC must then promptly notify the federal On-Scene Coordinator (OSC), who must notify the appropriate state agency of any states that may be affected by the discharge. The OSC shall then proceed with the following phases as outlined in the RCP and ACP.

Discharge response and cleanup

• Response to an oil spill will depend on the type of oil discharged, the location of the spill and its proximity to sensitive environments, and other factors.
• Containment equipment is used to contain a spill, while chemical and biological methods can help with removal and dispersal of the oil.

Response to oil spills requires the combined efforts of the owner or operator of the facility or vessel that spilled the oil, the federal On-Scene Coordinator (OSC), and/or state and local government officials. The specific steps taken to respond to a spill depend not only on the response plans that were prepared before the spill but also on the type of oil discharged, the location of the discharge, the proximity of the spill to sensitive environments, and other environmental factors.

When an oil spill occurs on water, it is critical to contain the spill as quickly as possible in order to minimize danger and potential damage to people, property, and natural resources. Containment equipment is used to restrict the spread of oil and to allow for its recovery, removal, or dispersal. The most common type of equipment used to control the spread of oil is the floating barrier, called a boom.

Chemical and biological methods can be used in conjunction with mechanical means for containing and cleaning up oil spills. Dispersants are most useful in helping to keep oil from reaching shorelines and other sensitive habitats. Biological agents have the potential to assist recovery in sensitive areas such as shorelines, marshes, and wetlands. In-situ burning has shown the potential to be an effective cleanup method under certain circumstances. Research into these technologies continues in the hope that future oil spills can be contained and cleaned up more efficiently and effectively.

Despite the best efforts of response teams to contain spilled oil, some of it may contaminate shorelines of oceans and lakes, banks of rivers and streams, and other ecologically sensitive habitats along the water’s edge. To help protect these resources from damage and to preserve them for public enjoyment and for the survival of numerous species, cleaning up shorelines following oil spills has become an important part of oil spill response.

Factors that affect the type of cleanup method used include the type of oil spilled, the geology of the shoreline and rate of water flow, and the type and sensitivity of biological communities in the area. Natural processes, such as evaporation, oxidation, and biodegradation help to clean the shoreline. Physical methods, such as wiping with sorbent materials, pressure washing, and raking and bulldozing can be used to assist these natural processes.

Cleanup from an oil spill is not considered complete until all waste materials are disposed of properly. The cleanup of an oiled shoreline can create different types of waste materials, including liquid oil, oil mixed with sand, and tar balls. Oil can sometimes be recovered and reused, disposed of by incineration, or placed in a landfill. States and the federal government strictly regulate the disposal of oil.

Oil collected during cleanup activities must be reused or disposed of properly, using such methods as incineration or landfilling. Choosing the most effective yet potentially least damaging cleaning methods helps to ensure that the natural systems of shorelines and the recreational benefits they offer will be preserved and protected for future generations.

Cleanup liability and funding

• When an oil spill occurs, the EPA has the authority to require a responsible party to pay for the cleanup and to compensate for lost or damaged natural resources.

The Clean Water Act (CWA) liability provisions, as amended by the Oil Pollution Act (OPA), provide the Environmental Protection Agency (EPA) the authority to require a responsible party (RP) to pay for cleanup and compensate for lost or damaged natural resources. Since EPA has limited funding for the cleanup of oil, it is important that EPA receive compensation and recovery of funds they use when responding to oil discharge events.

OPA section 1002 specifically outlines the costs for which an RP can be held liable, including removal costs and the costs of other actions taken to mitigate damage to public health and welfare. Additionally, an RP can be held liable for damages such as real or personal property damages, the costs of assessing natural resource damages, loss of profits or earning capacity, and the net cost of additional public services provided during or after removal actions.

Similar to liability under the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), OPA liability is judicially interpreted as both strict and joint and several. Strict liability is the assessment of legal responsibility without regard to fault or diligence. Joint and several liability means that any entity considered an RP can be held liable for the entire cleanup, regardless of his or her contribution to the discharge.

Financial responsibility

In preparation for an oil spill, section 2716 of the Oil Pollution Act (OPA) specifies financial responsibility requirements for offshore facilities. Financial responsibility is the ability to pay for cleanup or third-party liability compensation that results from an oil discharge. Financial responsibility ensures the timely completion of corrective action and third-party compensation and thus reduces the risk to human health and the environment posed by oil discharges. It also may provide an incentive for operating practices that can prevent leaks, overfills, and spills.

Under OPA, the owner or operator of a facility from which oil is discharged (responsible party) is liable for the costs associated with the:

• Containment
• Cleanup
• Damages resulting from the spill

Oil Spill Liability Trust Fund

In the event of an oil discharge, EPA prefers to have RPs finance the cleanup of their own oil discharges. When the RP is unknown or refuses to pay, the Oil Spill Liability Trust Fund (the Fund) can cover removal costs and/or damages that are not recovered from that RP. The emergency response portion of the Fund is administered by the U.S. Coast Guard's National Pollution Funds Center (NPFC).

The Fund can provide up to $1 billion for any one oil pollution incident, including up to $500 million for the initiation of natural resource damage assessments and claims in connection with any single incident (Internal Revenue Code, as amended by the OPA; 26 USC 9509). OPA section 1012 delineates the allowable uses of the Fund, including:

• Payment of costs assumed by states for removal actions conducted in a manner consistent with the National Contingency Plan (NCP);
• Payments to federal, state and Native American tribe trustees to carry out natural resource damage assessments and restorations in a manner consistent with the NCP;
• Payment of claims for uncompensated removal costs and damages; and
• Research and development and other specific appropriations.

The primary source of revenue for the Fund was a five-cents-per-barrel tax on imported and domestic oil. This tax expired on December 31, 1994. Several new laws since then have reinstated the tax and/or raised the tax to eight cents per barrel, but these taxes have since expired also. Current revenue sources for the Fund include interest on the Fund, cost recovery from the parties responsible for discharges, and fines or civil penalties collected from RPs.

Exemptions

• Exemptions to reporting requirements exist when oil spills to do not reach navigable waters or adjoining shorelines; when oil is released from a properly functioning vessel engine; for certain approved research and demonstration purposes; and a few others.

Several types of oil spills do not need to be reported.

Discharges that did not reach navigable waters or adjoining shorelines

If a discharge has not reached navigable waters or adjoining shorelines, it is not reportable. For example, if a tank leaks a puddle of oil into a building’s basement, this would be considered a discharge of oil, but it is not reportable if the oil did not reach a navigable water or adjoining shoreline. However, groundwater may be a conduit to navigable water or an adjoining shoreline.

Properly functioning vessel engines

Discharges of oil from a properly functioning vessel engine are not deemed to be harmful; therefore, they do not need to be reported under the Discharge of Oil Standard. However, oil accumulated in a vessel's bilge is not exempt.

Research and development releases

The Environmental Protection Agency (EPA) may permit the discharge of oil on a case-by-case basis in connection with:

• Research,
• Demonstration projects, or
• Studies relating to the prevention, control, or abatement of oil pollution.

However, the Discharge of Oil Standard specifically forbids the use of dispersants or emulsifiers to circumvent the standard.

NPDES-permitted releases

Three types of discharges subject to the National Pollutant Discharge Elimination System (NPDES) are exempt from oil spill reporting:

1. Discharges in compliance with a permit under section 402 of the Clean Water Act (CWA), when the permit contains either an effluent limitation:
   • Specifically applicable to oil, or
   • Applicable to another parameter that has been designated as an indicator of oil.
2. Discharges resulting from circumstances identified and reviewed and made 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. This exclusion addresses situations where the source, nature, and amount of a potential oil discharge was identified, and a treatment system capable of preventing that discharge was made a permit requirement.
   
   For example, if a discharger has a drainage system that will route spilled oil from a broken hose connection to a holding tank for subsequent treatment and discharge, the treatment system must be sufficient to handle the maximum potential spill from that source. Spills larger than those contemplated in the public record are not exempted.
3. Continuous or anticipated intermittent discharges from a point source, identified in a permit or permit application under section 402 of the CWA, which are caused by events occurring within the scope of relevant operating or treatment systems. This exclusion applies to chronic or anticipated intermittent discharges originating in the manufacturing or treatment systems of a facility or vessel, including those caused by periodic system failures. Discharges caused by spills or episodic events that release oil to the manufacturing or treatment systems are not exempt from reporting.

Discharges permitted under MARPOL

Certain discharges beyond the territorial seas (defined as extending three miles seaward from the coast) are allowed if they are permitted under international law. The International Convention for the Prevention of Pollution from Ships (MARPOL), as amended, prohibits the discharge of oily mixtures (defined as mixtures with any oil content) from a tanker except when all of the following conditions are met:

• The tanker is proceeding en route,
• The tanker is more than 50 miles from the nearest land,
• The instantaneous rate of discharge does not exceed 60 liters per mile, and
• The total quantity of oil discharged in any ballast voyage does not exceed 1/15,000 of the total cargo carrying capacity.

In addition, MARPOL allows discharges in quantities verified by a monitoring system to be less than or equal to 15 parts per million, regardless of whether the discharge causes a sheen. Therefore, discharges permitted under MARPOL into waters seaward of the territorial sea are exempt from U.S. oil spill notification requirements. Such discharges may include the operational discharge of limited quantities of oil-water mixtures from ships.

Activities involving oil

• Some activities that are considered to be oil-related activities include: drilling, producing, gathering, storing, processing, refining, transferring, distributing, or consuming oil or oil products.

Paragraph (b) to Part 112.1 specifies the following oil-related activities are regulated: drilling, producing, gathering, storing, processing, refining, transferring, distributing, using, or consuming oil and oil products. That means these activities are subject to the Oil Pollution Prevention Standard provided the facility meets the other applicability criteria in section 112.1. The table provides examples of these activities.

Container types

• Facilities are subject to Part 112 if they have oil in aboveground containers; buried tanks; containers used for seasonal or temporary storage; or tanks that are partially buried or contained in a vault.

Under subparagraphs 112.1(b)(1) through (4), the Oil Pollution Prevention Standard is applicable to eligible facilities that have oil in:

• Aboveground containers;
• Completely buried tanks;
• Containers that are used for standby storage, for seasonal storage, or for temporary storage, or are not otherwise “permanently closed;” and
• “Bunkered tanks” or “partially buried tanks” or containers in a vault.

Containers include not only oil storage tanks, but also mobile or portable containers such as drums and totes, and oil-filled equipment such as electrical equipment (e.g., transformers and circuit breakers), manufacturing flow-through process equipment, and operational equipment.

Storage capacity thresholds

• Part 112 applies to facilities with oil capacity of more than 42,000 gallons stored underground, or more than 1,320 gallons stored aboveground.

Subparagraph 112.1(d)(2) of the Oil Pollution Prevention Standard limits the applicability to facilities with oil capacity above certain threshold amounts. Specifically, Part 112 applies to a facility that has more than 42,000 U.S. gallons of completely buried oil storage capacity or more than 1,320 U.S. gallons of aggregate aboveground oil storage capacity, provided the facility meets the other applicable criteria set forth in 112.1.

Once a facility is subject to the regulation, all aboveground containers and completely buried tanks are subject to the requirements (unless these containers are otherwise exempt from the regulation). For example, a facility could have 10,000 U.S. gallons of aggregate aboveground storage capacity in tanks and oil-filled equipment of 55 U.S. gallons or more, and a completely buried tank of 10,000 U.S. gallons that is not subject to all of the technical requirements of Part 280 or a state program approved under Part 281 (and therefore not exempt). Since the aboveground storage capacity exceeds 1,320 U.S. gallons, all of the tanks and oil-filled equipment, including the buried tank, are subject to the Spill Prevention, Control, and Countermeasure (SPCC) rule.

Subparagraphs 112.1(d)(2)(i) and (ii) clarify which containers are included and excluded when calculating total storage capacity at a facility in determining whether it exceeds the volume limits in the regulation.

Under the Oil Pollution Prevention Standard, if a container has the requisite capacity, it does not matter whether the container is actually filled to that capacity. The storage capacity of a container is defined as the shell capacity of the container.

Facility boundaries

• Part 112 helps to define what constitutes a facility for the purposes of SPCC and FRP requirements. An owner or operator may not characterize a facility for the purpose of avoiding SPCC and FRP requirements.

A facility may or may not be subject to the Spill Prevention, Control, and Countermeasure (SPCC) and Facility Response Plan (FRP) rule requirements depending on how the facility owner or operator aggregates buildings, structures or equipment and associated storage or type of activity. However, once the owner/operator determines the facility boundaries for SPCC applicability, then the same boundaries apply for determining applicability of the FRP rule requirements. An owner or operator may not characterize a facility so as to simply avoid applicability of the rule (for example, defining separate facilities around oil storage containers that are located side-by-side or within close proximity, and are used for the same purpose).

A lease may, at the owner or operator’s discretion, constitute a facility but does not necessarily create a facility. According to the definition of facility, contiguous or noncontiguous buildings, properties, leases, structures, installations, pipes, or pipelines under the ownership or operation of the same person may be considered separate facilities. A facility may also consist of parcels that are smaller or larger than an individual lease.

The following factors to determine the boundaries of a facility are not exclusive and simply serve as examples:

• Ownership, management, and operation of the buildings, structures, equipment, installations, pipes, or pipelines on the site;
• Similarity in functions, operational characteristics, and types of activities occurring at the site;
• Adjacency; or
• Shared drainage pathways (e.g., same receiving water bodies).

Farm-specific applicability

• The WRRDA of 2014 changes the way the SPCC rule is applied to farms.
• New rules, when adopted by the EPA, will likely bring more farms under the SPCC rule.

Under the Spill Prevention, Control, and Countermeasure (SPCC) rule (Part 112 Subparts A to C), a farm is “a facility on a tract of land devoted to the production of crops or raising of animals, including fish, which produced and sold, or normally would have produced and sold, $1,000 or more of agricultural products during a year.”

Section 1049 of the Water Resources Reform and Development Act (WRRDA) of 2014 impacts the SPCC rule for farms. Specifically, the law changes certain applicability provisions of the SPCC rule for farms and modifies the criteria under which a farmer may self-certify an SPCC Plan. Details may be found at the following:

• The Environmental Protection Agency’s (EPA’s) fact sheet called “Oil Spill Prevention, Control, and Countermeasures (SPCC Program): Farms and the Water Resources Reform and Development Act (WRRDA),” April 24, 2015.
• EPA’s publication called “Oil Storage on U.S. Farms: Risks and Opportunities for Protecting Surface Waters,” EPA-530-R-15-002, June 30, 2015.

The changes are not yet in the regulations at Part 112. EPA expects to promulgate a rule amending the SPCC requirements associated with the applicability thresholds and other WRRDA amendments. However, please note that EPA has said it intends to lower the greater-than-6,000-gallon threshold to greater than 2,500 gallons. Lowering the threshold will bring more farms under the SPCC rule.

Exemptions

• EPA lists several exemptions from Part 112, most related to facility or equipment location, size, capacity, and more.

The Environmental Protection Agency (EPA) exempts the following from Part 112:

• Any facility, equipment, or operation that is not subject to the jurisdiction of EPA under section 311(j)(1)(C) of the Clean Water Act (CWA), as follows:
  • Any onshore or offshore facility, that due to its location, could not reasonably be expected to have a discharge as described in 112.1(b). This determination must be based solely upon consideration of the geographical and location aspects of the facility (such as proximity to navigable waters or adjoining shorelines, land contour, drainage, etc.) and must exclude consideration of man-made features such as dikes, equipment, or other structures, which may serve to restrain, hinder, contain, or otherwise prevent a discharge as described in 112.1(b).
  • Any equipment, or operation of a vessel or transportation-related onshore or offshore facility subject to the authority and control of the Department of Transportation (DOT), as defined in the memorandum of understanding found at Appendix A to Part 112.
  • Any equipment, or operation of a vessel or onshore or offshore facility which is subject to the authority and control of the DOT or the Department of the Interior, as defined in the memorandum of understanding found at Appendix B to Part 112.
• Any facility where the completely buried oil storage capacity is 42,000 U.S. gallons or less AND the aggregate aboveground oil storage capacity is 1,320 U.S. gallons or less.
• Completely buried oil tanks and associated piping and equipment that are subject to all of the technical requirements under Part 280 or 281.
• Underground oil storage tanks, including below-grade vaulted tanks that supply emergency diesel generators at a nuclear power generation facility licensed by the Nuclear Regulatory Commission (NRC) and subject to any NRC provision regarding design and quality criteria, including, but not limited to, 10 CFR 50.
• Permanently closed oil containers.
• Any container with an oil storage capacity less than 55 U.S. gallons.
• Any facility or part thereof used exclusively for wastewater treatment and not used to satisfy Part 112 (the production, recovery, or recycling of oil is not wastewater treatment for the purposes of this exemption).
• Motive power oil containers (the transfer of fuel or other oil into a motive power container at an otherwise regulated facility is not eligible for this exemption).
• Hot-mix asphalt or any hot-mix asphalt container.
• Containers storing heating oil used solely at a single-family residence.
• Pesticide application equipment or related mix containers (with adjuvant oil).
• Intra-facility oil gathering lines subject to the regulatory requirements of 49 CFR 192 or 195, except that such a line’s location must be identified and marked as ‘‘exempt’’ on the facility diagram as provided in subparagraph 112.7(a)(3), if the facility is otherwise subject to Part 112.
• Any milk and milk product container and associated piping and appurtenance.
• Any offshore oil drilling, production, or workover facility that is subject to the notices and regulations of the Minerals Management Service (MMS), as specified in the Memorandum of Understanding found in Appendix B to Part 112. Note that MMS was replaced in 2011 by the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE).

Facilities are not required to include exempt oil containers or oil equipment when calculating the total oil storage capacity of the facility.

Permanently closed

• If they meet the proper definition, permanently closed containers are exempt from Part 112 and no longer count toward a facility’s total oil storage capacity.

Permanently closed containers are exempt from Part 112. Once permanently closed, a container no longer counts toward the total facility storage capacity, nor is it subject to the other requirements under Part 112. Part 112 does not require that permanently closed containers be removed from a facility.

In addition, any container brought on to a facility that has never stored oil is not subject to Part 112, nor is it counted toward the facility capacity until it stores oil. Any other container that at one time stored oil but no longer contains oil or sludge, which is brought onto a facility and meets the definition of permanently closed, is not subject to Part 112 nor is it counted toward the facility capacity until it stores oil.

Permanent closure requirements under Part 112 are separate and distinct from the closure requirements in hazardous waste regulations promulgated under Subtitle C of the Resource Conservation and Recovery Act (RCRA), such as Part 264.197 and 265.197.

Is it really permanently closed?

Part 112 does not include a provision to temporarily close containers to account for seasonal use of tanks or variable economic conditions and production rates at oil production facilities. In order for a container to be exempt from Part 112 requirements, the container must meet the following criteria for a permanently closed container:

• All liquid and sludge have been removed from each container and connecting line;
• All connecting lines and piping have been disconnected from the container and blanked off;
• All valves (except ventilation valves) have been closed and locked; and
• Conspicuous signs have been posted on each container stating that it is a permanently closed container and noting the date of closure.

A permanently closed container may remain at the facility. However, a facility owner or operator should review state and local requirements, which may require removal of a container when it is taken out of service. When a container is removed from the facility, the Spill Prevention, Control, and Countermeasure (SPCC) Plan must be amended and the technical amendment must be certified.

In the event that a permanently closed container is brought back into use (e.g., to accommodate variations in production rates), the SPCC Plan will need to be amended to reflect the capacity of the permanently closed container if this capacity was previously excluded from the facility total capacity.

Underground storage tank

• Underground storage tanks are exempt from Part 112 but are subject to other regulations (such as Parts 280 and 281) that require a facility to prevent, detect, and clean up oil spills from such tanks.

Under subparagraph 112.1(d)(4), the Oil Pollution Prevention Standard exempts completely buried storage tanks, as well as connected underground piping, underground ancillary equipment, and containment systems, when such tanks are subject to all of the technical requirements of Part 280 or a state program approved under Part 281 (also known as the Underground Storage Tank (UST) regulations). Although these tanks are exempt from the requirements of Part 112, they must still be marked on the facility diagram if the facility is otherwise subject to the Spill Prevention, Control, and Countermeasure (SPCC) rule (see subparagraph 112.7(a)(3)).

The regulations at Part 280 and Part 281 comprise the UST Program, which requires owners and operators of new tanks and tanks already in the ground to prevent, detect, and clean up releases. Part 112 only recognizes a subset of tanks covered by the UST Program regulations. Specifically, the UST Program defines a UST as a tank and any underground piping that has at least 10 percent of its combined volume underground. However, under Part 112, only completely buried tanks subject to all of the technical UST program requirements are exempt from Part 112. Any tanks that are not completely buried are considered aboveground storage tanks and subject to Part 112.

The following completely buried tanks are either excluded from the definition of UST or are exempt from the UST regulations at Part 280 (and therefore may be subject to Part 112 if they contain oil):

• Tanks with a capacity of 110 U.S. gallons or less;
• Farm or residential tanks with a capacity of 1,100 U.S. gallons or less used for storing motor fuel for non-commercial purposes;
• Tanks used for storing heating oil for consumptive use on the premises where stored;
• Tanks storing non-petroleum oils, such as animal fat or vegetable oil;
• Tanks on or above the floor of underground areas (e.g., basements or tunnels);
• Septic tanks and systems for collecting stormwater and wastewater; •
• Flow-through process tanks;
• Emergency spill and overfill tanks that are expeditiously emptied after use;
• Surface impoundments, pits, ponds, or lagoons;
• Any UST system holding Resource Conservation and Recovery Act (RCRA) hazardous waste;
• Any equipment or machinery that contains regulated substances for operational purposes such as hydraulic lift tanks and electrical equipment tanks;
• Liquid trap or associated gathering lines directly related to oil or gas production or gathering operations;
• Pipeline facilities regulated under the Natural Gas Pipeline Safety Act of 1968, the Hazardous Liquid Pipeline Safety Act of 1979, or intrastate pipelines regulated under state laws comparable to the provisions of above laws; and
• Any UST system that contains de minimis concentration of regulated substances.

The following are examples of deferrals from the UST regulations (and therefore may be subject to Part 112):

• Wastewater treatment tank systems;
• Any UST systems containing radioactive materials that are regulated under the Atomic Energy Act of 1954;
• Airport hydrant fuel distribution systems; and
• UST systems with field-constructed tanks.

Note that, at an otherwise Part-112-regulated facility, any transfer to or from completely buried storage tanks is regulated because it is a potential source of discharge of oil into navigable waters or adjoining shorelines. Because a loading/unloading rack, or other transfer area, associated with a UST is not typically part of the UST system, it is not subject to all of the technical requirements of Part 280 or Part 281. Therefore, such a loading/unloading rack is regulated under the Part 112 regulations in the same manner as any other transfer equipment or transfer activity located at an otherwise Part-112-regulated facility.

Additional and/or more stringent requirements may exist in a state-approved program under Part 281, and they may also impact Part 112 applicability. For example, a state may choose to regulate a UST used for storing heating oil for consumptive use on the premises where stored. Thus, under the state program the UST is subject to all the technical requirements of a Part 281 program and therefore exempt from Part 112.

Wastewater treatment facilities

• The wastewater treatment exemption excludes from Part 112 those facilities or parts of facilities that are used exclusively for wastewater treatment.

The wastewater treatment exemption, outlined at Part 112.1(d)(6), excludes from the Part 112 requirements those facilities or parts of facilities that are used exclusively for wastewater treatment, and are not used to meet Part 112 requirements. Do not count the capacity of these exempt containers when calculating facility aggregate capacity.

Many of the wastewater treatment facilities or parts thereof are subject to the National Pollutant Discharge Elimination System (NPDES) or state-equivalent permitting requirements that involve operating and maintaining the facility to prevent discharges. The NPDES or state-equivalent process ensures review and approval of the facility’s plans and specifications; operation/maintenance manuals and procedures; and stormwater pollution prevention plans (SWPPPs), which may include best management practice (BMP) plans.

For the purposes of the exemption, the production, recovery, or recycling of oil is not considered wastewater treatment. These activities generally lack NPDES or state-equivalent permits and thus lack the protections that such permits provide. The goal of an oil production, oil recovery, or oil recycling facility is to maximize the production or recovery of oil, while eliminating impurities in the oil, including water, whereas the goal of a wastewater treatment facility is to purify water. Additionally, produced water is not considered wastewater and is therefore not eligible for this exemption. However, produced water containers used exclusively for wastewater treatment at dry gas production facilities are eligible for the wastewater treatment exemption.

The exemption also does not apply to a wastewater treatment facility (or part of that facility) that is used to store oil. In those instances, the oil storage capacity must be counted as part of the total facility storage capacity. For example, if there is a 1,000-gallon storage container that contains oil removed from an exempt oil/water separator and a 500-gallon storage container for an emergency generator, the total aboveground storage capacity for the facility would be 1,500 U.S. gallons, and the facility may potentially be regulated by Part 112.

A wastewater treatment facility (or parts of that facility) used to meet a Part 112 requirement, including an oil/water separator used to meet any spill prevention, control, and countermeasure (SPCC) requirement, is not exempt. Oil/water separators used to meet SPCC requirements include those used to satisfy the secondary containment requirements of subparagraphs 112.7(c), 112.7(h)(1), and/or 112.8(c)(2) or 112.8(c)(11). Although not exempt, oil/water separators used to satisfy secondary containment requirements of Part 112 do not count toward storage capacity.

Motive power

• A motive power container is defined as any onboard bulk storage container used primarily to power the movement of a motor vehicle, or ancillary onboard oil-filled operational equipment.

Motive power container means any onboard bulk storage container used primarily to power the movement of a motor vehicle, or ancillary onboard oil-filled operational equipment (Part 112.2). An onboard bulk storage container which is used to store or transfer oil for further distribution is not a motive power container. The definition of motive power container does not include oil drilling or workover equipment, including rigs.

Motive power containers on vehicles used solely at non-transportation-related facilities fall under the Environmental Protection Agency (EPA) jurisdiction but are exempt from Part 112. Section 112.1(d)(2)(ii) excludes the capacity of these containers from facility capacity calculations.

Bulk storage container used for propulsion

Containers on motor vehicles that provide the vehicle with a means of propulsion are considered motive power containers. Examples of motor vehicles which have containers used to individually provide their own means of propulsion from location to location within a facility or between facilities include:

• Aircraft,
• Cherry pickers,
• Self-propelled cranes,
• Self-propelled aviation ground service equipment vehicles,
• Self-propelled heavy vehicles (e.g., used in forestry, agricultural, mining, excavation and construction applications), and
• Locomotives.

Ancillary on-board equipment

Ancillary on-board equipment includes hydraulic and lubrication operational oil-filled containers used for other ancillary functions of a motor vehicle. It also includes motor vehicle bulk storage containers that serve a non-operational purpose in addition to the propulsion of the motor vehicle; for example, a bulk storage container that supplies fuel to an engine that provides the propulsion for that motor vehicle, as well as its auxiliary units and functions (e.g., heaters, air conditioning units, and electrical power generation, etc.).

Exclusions from the motive power container definition

The exemption does not include non-self-propelled stationary or towed equipment, such as towed ground service equipment or any type of oil-powered generator (gensets). The following are examples of equipment that are not motive power containers because they do not include containers used for propulsion: •

• Towed aviation ground service equipment,
• Non-self-propelled construction/cargo cranes,
• Non-self-propelled (forestry, agricultural, mining, excavation or construction) equipment,
• Oil-powered generators,
• Fire pumps, and
• Compressors.

An onboard bulk storage container used to store or transfer oil for further distribution is also not a motive power container. An onboard bulk storage container that supplies oil for the movement of a vehicle or operation of onboard equipment, and at the same time is used for the distribution or storage of this oil is not eligible for the exemption. This situation includes, for example, a mobile refueler that has an onboard bulk storage container used to distribute fuel to other vehicles on a site and which also draws its engine fuel (for propulsion) from that bulk container.

Oil drilling and workover equipment (including rigs) are not eligible for the motive power container exemption because they are specifically excluded from the definition of a motive power container. Although drilling and workover rigs are not exempt, other types of motive power containers located at drilling or workover facilities (e.g., trucks, automobiles, bulldozers, seismic exploration vehicles, or other earth-moving equipment) are exempt.

Oil transfers to motive power containers

Regardless of the exemption for motive power containers, oil transfer activities occurring within a Part-112-regulated facility are regulated. An example of such an activity would be the transfer of oil from an oil storage container via a dispenser to a motive power container. This transfer activity is subject to the general secondary containment requirements of 112.7(c).

Intra-facility gathering lines

• Intra-facility gathering lines may fall under the jurisdiction of the EPA and DOT.

Intra-facility gathering lines (i.e., gathering lines found within the confines of a non-transportation-related facility) may be under the jurisdiction of both the Environmental Protection Agency (EPA) and the Department of Transportation (DOT). However, certain DOT requirements for pipelines are considered to be similar in scope to Part 112 regulations. Therefore, intra-facility gathering lines that are subject to DOT regulatory requirements at Part 192 (Transportation of Natural and Other Gas by Pipeline) or Part 195 (Transportation of Hazardous Liquids by Pipeline) are exempt from Part 112 under 112.1(d)(11).

If intra-facility gathering lines are not subject to DOT regulatory requirements (i.e., gathering lines that by statute are subject to DOT jurisdiction, yet are not subject to the DOT regulations), they remain subject to Part 112. Other equipment and piping at an oil production facility (such as flowlines) remain subject to Part 112 requirements. EPA considers intra-facility gathering lines to be subject to EPA’s jurisdiction if they are located within the boundaries of an otherwise regulated Part-112-covered facility.

The exemption requires owners or operators of a facility to identify and mark as “exempt” the location of exempt piping on the facility diagram. This requirement will assist both facility and EPA personnel in defining the boundaries of EPA and DOT jurisdiction and provide response personnel with information used to identify hazards during a spill response activity. More information about facility diagram requirements is provided at Written plans.

Milk and milk product containers

• Milk and milk product containers are exempt from Part 112. Butter, cheese, and dry milk containers are a few examples.

Milk and milk product containers and associated piping and appurtenances are exempt from the Part 112 under subparagraph 112.1(d)(12) and excluded from facility capacity calculations in subparagraph 112.1(d)(2)(ii). Butter, cheese, and dry milk containers are a few examples of milk product containers subject to the exemption.

All milk and/or milk product transfer and processing activities are included in the scope of this exemption from Part 112. For more information on exempted milk and milk product containers, see the final rule in the Federal Register dated April 18, 2011.

Petroleum and non-petroleum oil

• Petroleum oil is petroleum in any form. Non-petroleum oil includes, but is not limited to, fats, oils and greases derived from animal, fish, or vegetable sources.

Petroleum oil means petroleum in any form, including but not limited to crude oil, fuel oil, mineral oil, sludge, oil refuse, and refined products.

Non-petroleum oil means oil of any kind that is not petroleum-based, including but not limited to: fats, oils, and greases of animal, fish, or marine mammal origin; and vegetable oils, including oils from seeds, nuts, fruits, and kernels.

Part 112 applies to both petroleum oils and non-petroleum oils. Petroleum oils include, but are not limited to, crude and refined petroleum products, asphalt, gasoline, fuel oils, mineral oils, naphtha, sludge, oil refuse, and oil mixed with wastes other than dredged spoil. Non-petroleum oils and greases include coal tar, creosote, silicon fluids, pine oil, turpentine, and tall oils.

Subpart B of Part 112 covers both “petroleum oils and non-petroleum oils.” Petroleum oils and non-petroleum oils, including synthetic oils, share common physical properties and produce similar environmental effects. Petroleum and non-petroleum oils can enter all parts of an aquatic system and adjacent shoreline, and similar methods of containment, removal, and cleanup are used to reduce the harm created by spills of both types of oils.

Synthetic oil

• Synthetic oils are created by chemical synthesis rather than by refining petroleum or extracting from animal or plant materials.

Synthetic oils are used in a wide range of applications, including as heat transfer fluids, engine fluids, hydraulic and transmission fluids, metalworking fluids, dielectric fluids, compressor lubricants, and turbine lubricants. Synthetic oils are created by chemical synthesis rather than by refining petroleum crude or extracting oil from plant seeds. Oils that are derived from plant material may be considered animal fats and vegetable oils under Subpart C of Part 112.

Animal fats and vegetable oils (AFVOs)

• Animal fat means a non-petroleum oil, fat, or grease of animal, fish, or marine mammal origin. Vegetable oil means a non-petroleum oil or fat of vegetable origin.

Animal fats and vegetable oils are covered under Part 112.

Animal fat means a non-petroleum oil, fat, or grease of animal, fish, or marine mammal origin. Animal fats include, but are not limited to, fats, oils, and greases of animal origin (for example, lard and tallow), fish (for example, cod liver oil), or marine mammal origin (for example, whale oil).

Vegetable oil means a non-petroleum oil or fat of vegetable origin, including but not limited to oils and fats derived from plant seeds, nuts, fruits, and kernels. Examples of vegetable oils include corn oil, rapeseed oil, coconut oil, palm oil, soybean oil, sunflower seed oil, cottonseed oil, and peanut oil.

Produced water

• Produced water is the oil and water mixture that results from the separation of crude oil or gas from the fluids or gases extracted from the oil/gas reservoir.
• Because it can cause harm if discharged, produced water is regulated as oil under Part 112.

Part 112 applies to produced water from an oil well. Produced water is the oil and water mixture resulting from the separation of crude oil or gas from the fluids or gases extracted from the oil/gas reservoir, prior to disposal, subsequent use (e.g., re-injection or beneficial reuse), or further treatment. Produced water’s chemical and physical characteristics vary considerably depending on the geologic formation, usually being commingled with oil and gas at the wellhead, and changing in composition as the oil or natural gas fraction is separated and sent to market.

Produced water is typically collected in produced water containers at the end of the oil and gas treatment process, and often accumulates emulsified oil not captured in the separation process. Under normal operating conditions, a layer of oil may be present on top of the fluids. The amount of oil by volume observed in produced water storage containers varies, but based on the Environmental Protection Agency (EPA)’s assessment, is generally estimated to range from less than one to 10 percent by volume and can be greater. Oil may be present not only in free phase, but also in other forms, such as in a dissolved phase, emulsion or a sludge at the bottom of the produced water container.

Oil discharges to navigable waters or adjoining shorelines from an oil/water mixture in a produced water container may cause harm. Such mixtures in the produced water container are regulated as oil under Part 112. Therefore, the capacity of produced water containers counts toward the facility aggregate oil storage capacity. Produced water containers at oil production, oil recycling, or oil recovery facilities are not eligible for the wastewater treatment exemption in subparagraph 112.1(d)(6).

Other substances

• Certain other substances may be regulated as oil, including but not limited to some forms of asphalt, natural gas condensate, oil and water mixtures, denatured ethanol, and biodiesel fuel.

Other substances may pose a challenge to facilities attempting to determine if they have an oil onsite.

Asphalt

Asphalt is a thermoplastic material, composed of unsaturated aliphatic and aromatic compounds, that softens when heated and hardens upon cooling. Within a certain temperature range, it exhibits viscoelastic properties with viscous flow behavior and elastic deformation. All types of asphalt are petroleum oil products, and its composition depends on the source of the crude oil and the process used to manufacture it.

The Environmental Protection Agency (EPA) regulation Part 112 applies to asphalt cement (AC), as well as to asphalt derivatives such as cutbacks and emulsions. Because of the operational conditions under which AC, cutbacks and emulsions are used and stored, they do pose a risk of being discharged into navigable waters or adjoining shorelines. Although AC is semi-solid or solid at ambient temperature and pressure, it is generally stored at elevated temperatures. Hot AC is liquid — similar to other semi-solid oils, such as paraffin wax and heavy bunker fuels — and therefore is capable of flowing. Cutbacks and emulsions are liquid at ambient temperature, and, because of their low viscosity, they may flow when discharged onto the ground. All of these oils are regulated under Part 112 to prevent discharges to navigable waters or adjoining shorelines.

However, hot-mix asphalt (HMA) and HMA containers are exempt from Part 112. HMA is a blend of AC and aggregate material, such as stone, ground tires, sand, or gravel, which is formed into final paving products for use on roads and parking lots. HMA is unlikely to flow as a result of the entrained aggregate, such that there would be very few circumstances, if any, in which a discharge of HMA would have the potential to reach navigable waters or adjoining shorelines.

Natural gas and condensate

Part 112 does not apply to natural gas (including liquid natural gas and liquid petroleum gas). EPA does not consider highly volatile liquids that volatilize on contact with air or water, such as liquid natural gas or liquid petroleum gas, to be oil. Furthermore, the agency has stated that hydrocarbons in a gaseous phase under ambient pressure and temperature, such as natural gas, present at Part 112-regulated facilities are exempt.

However, natural gas liquid condensate (often referred to as “natural gasoline” or “drip gas”) is an oil subject to Part 112. Condensate can accumulate in tanks, containers, or other equipment. For the purposes of determining applicability, containers with 55 gallons or more in capacity storing condensate must be included in a natural gas facility’s total oil storage capacity calculation.

Oil and water mixtures

Oil and water mixture containers are subject to Part 112. A mixture of wastewater and oil is “oil” under the statutory and regulatory definition of the term (33 U.S.C. 1321(a)(1) and Part 110.2 and 112.2). A discharge of “wastewater containing oil” to navigable waters or adjoining shorelines in a ‘‘harmful quantity’’ (as defined at Part 110) is prohibited. One example of an oil and water mixture is produced water.

Hazardous substances and hazardous waste

The definition of “oil” in section 112.2 includes, but is not limited to, “oil mixed with wastes other than dredged spoil.” Oils covered under Part 112 include certain hazardous substances or hazardous wastes that are oils, as well as certain hazardous substances or hazardous wastes that are mixed with oils. Containers storing these substances may also be covered by other regulations, such as those prompted by the Resource Conservation and Recovery Act (RCRA) or Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA, also known as Superfund). For example, the definition of oil under section 112.2 includes “used oil” because it is an oil mixed with wastes. “Used oil,” as defined in EPA’s Standards for the Management of Used Oil at Part 279.1, means any oil that has been refined from crude oil, or any synthetic oil, that has been used and as a result of such use is contaminated by physical or chemical impurities.

EPA inspectors may evaluate whether containers storing hazardous substances or mixtures of wastes contain oil. Hazardous substances or hazardous wastes that are neither oils nor mixed with oils are not subject to Part 112 requirements. For purposes of Part 112, the Clean Water Act (CWA) section 311(b)(2) hazardous substances as identified under Part 116 are not considered oils. However, an oil mixture that includes a CWA hazardous substance is subject to Part 112 when it meets the definition of oil in the regulation. For example, benzene is a CWA hazardous substance and therefore does not meet the definition of oil in section 112.2; however, benzene is a constituent of gasoline which is a mixture that includes other oils. Gasoline is an oil as defined under Part 112.2.

Although the rule contains an exemption for completely buried tanks that are subject to all underground storage tank (UST) technical requirements of Part 280 and/or a state program approved under Part 281 under subparagraph 112.1(d)(2)(i) or (d)(4), tanks containing RCRA hazardous wastes are not subject to the UST rules. Therefore, when RCRA hazardous waste tanks located at a facility subject to Part 112 also contain oil, they too are subject to the Part 112 requirements.

Denatured ethanol used in renewable fuels

Renewable fuels, such as E85 or “flex fuel” (15 percent unleaded gasoline and 85 percent ethanol), are produced in a blending process. Ethanol used for fuel often contains a denaturing additive (typically gasoline, natural gasoline, diesel fuel, or other oil petroleum product) which is oil. Therefore, the final denatured ethanol is also considered an oil, and facilities handling or storing denatured ethanol may be subject to the Part 112 requirements. An EPA letter dated November 7, 2006, details the agency’s position on denatured ethanol.

Biodiesel and biodiesel blends

Biodiesel and biodiesel blends are other types of renewable fuels that are often stored and handled at facilities regulated under Part 112. Biodiesel, designated B100, is a domestic, renewable fuel for diesel engines derived from natural oils like soybean oil. Biodiesel is comprised of mono-alkyl esters of long chain fatty acids derived from vegetable oils or animal fats.

Biodiesel can be used in any concentration with petroleum-based diesel fuel in existing diesel engines with little or no modification. Biodiesel is not the same as raw vegetable oil. It is produced by a chemical process which removes the glycerin from the oil. Biodiesel is typically produced by a reaction of a vegetable oil or animal fat with an alcohol such as methanol or ethanol in the presence of a catalyst to yield mono-alkyl esters and glycerin, which is removed.

Biodiesel blends are a blend of biodiesel fuel with petroleum-based diesel fuel, designated BXX, where XX represents the volume percentage of biodiesel fuel in the blend. Both biodiesel (B100) and biodiesel blends are considered oil for the purposes of Part 112.

Onshore facility and offshore facility

• For the purposes of the EPA, an onshore facility is any facility of any kind located in, on, or under any land within the United States, other than submerged lands.
• An offshore facility is any facility of any kind (other than a vessel or public vessel) located in, on, or under any of the navigable waters of the United States, and any facility of any kind that is subject to the jurisdiction of the United States and is located in, on, or under any other waters.

The Environmental Protection Agency (EPA) has the authority to regulate non-transportation-related onshore and offshore facilities that could reasonably be expected to discharge oil into navigable waters of the U.S. or adjoining shorelines. Section 112.2 defines an “onshore facility” as “any facility of any kind located in, on, or under any land within the United States, other than submerged lands.” Requirements under Subparts B and C are divided based on the location of the facility and the type of operations. Sections 112.8 and 112.12 apply to all onshore facilities (excluding oil production facilities). Section 112.9 applies to all onshore oil production facilities, and section 112.10 applies to all onshore oil drilling and workover facilities. Finally, sections 112.20 and 112.21 apply to any non-transportation-related onshore facilities that, because of their location, could reasonably be expected to cause substantial harm to the environment by discharging oil into or on the navigable waters or adjoining shorelines.

“Offshore facility” means any facility of any kind (other than a vessel or public vessel) located in, on, or under any of the navigable waters of the United States, and any facility of any kind that is subject to the jurisdiction of the United States and is located in, on, or under any other waters. Section 112.11 applies to all offshore oil drilling, production, or workover facilities.

Some facilities may include both onshore and offshore components. In these instances, facilities may be considered “hybrid” facilities and subject to more than one set of requirements under Part 112. For example, an oil production facility located along a coastline that has a tank battery located onshore and associated wellheads and flowlines located offshore may be subject to the requirements of section 112.9 (for onshore oil production facilities) and section 112.11 (for offshore oil drilling, workover and production facilities).

Production facility

• A production facility includes all the structures, piping, and equipment used in the production, extraction, recovery, lifting, stabilization, separation or treatment of oil.

A production facility is a type of facility as defined in Part 112.2. A production facility includes all the structures (including but not limited to wells, platforms, or storage facilities), piping (including but not limited to flowlines or intra-facility gathering lines), or equipment (including but not limited to workover equipment, separation equipment, or auxiliary non-transportation-related equipment) used in the production, extraction, recovery, lifting, stabilization, separation or treatment of oil (including condensate) and associated storage or measurement and is located in an oil or gas field, at a facility.

The definition of “production facility” in section 112.2 is narrower than the definition of facility and is used to determine which sections of the rule may apply at a particular facility. This definition governs whether such structures, piping, or equipment are subject to section 112.9. That is, if a facility meets the definition of a production facility, the owner or operator must comply with section 112.9 or section 112.11 (depending on the characteristics of the facility). Additionally, the sections for administrative and general requirements under Part 112 apply as well (except for the security requirements under paragraph 112.7(g)).

The definition of “production facility” is consistent with the definition of “facility” in emphasizing flexibility in how a facility owner or operator can determine facility boundaries.

A production facility for purposes of Part 112 is one that is involved with producing or extracting petroleum crude oil from a reservoir and not any other type of oil production, such as animal fat and vegetable oil (AFVO) production. In fact,

• The definition of production facility addresses petroleum crude oil production, extraction, recovery, lifting, stabilization, separation or treatment and associated storage or measurement.
• The definition also includes terms associated with petroleum crude oil production, such as gathering lines and flowlines which are exclusively associated with upstream petroleum crude oil/gas production, not AFVO production or processing facilities. The term “oil or gas field” is used exclusively in upstream crude oil and gas production, not in AFVO production.

Drilling and workover facility

• Drilling and workover activities are part of oil production facility operations, and regulated as such; however, different provisions of the SPCC rule apply to these different activities.

Under the spill prevention, control, and countermeasure (SPCC) rule (Part 112 Subparts A to C), the term “production facility” can encompass drilling and workover activities, as well as oil production operations. However, different specific provisions of the rule apply to these different activities.

Drilling activities typically involve the initial establishment of an oil well: drilling the borehole, inserting, running, and cementing the casing, and completing the well to start the flow of well fluids to the surface.

Workover operations involve maintenance or remedial work that may be necessary to improve productivity during the life of the well. Workover operations may also include activities associated with the initial well completion process.

Both drilling and workover activities tend to be temporary in nature and are performed using mobile rigs and associated equipment. Thus a drilling and/or workover facility is considered a mobile facility. Mobile facilities may use a general SPCC Plan so that a new plan need not be prepared each time the mobile facility is moved to a new site. For example, it is not necessary to amend the plan for a drilling rig every time the operator moves the rig to drill a well in a field containing multiple wells. The same approach for mobile facilities applies to workover operations and activities.

For drilling and workover operations, the owner or operator is required to develop an SPCC Plan under paragraph 112.3(c) because a drilling or workover facility is considered a mobile facility. The administrative and general requirements of the SPCC rule (sections 112.1 through 112.7), as well as the specific requirements in section 112.10 (for onshore facilities) or section 112.11 (for offshore facilities) apply to the facility.

Once the well is completed and the well fluids are flowing, the completion (workover) and/or drilling rig is removed from the site and production equipment, such as a pump or valve assembly, is set up to extract or control the flow of oil from the well. At this point, drilling and or workover activities have ceased and production has begun; the facility is considered an oil production facility. The processes performed at a typical oil production facility include extraction, separation and treatment, storage, and transfer. The owner or operator of an oil production facility is subject to the administrative and general requirements of the SPCC rule (sections 112.1 through 112.7) as well as the specific requirements in section 112.9 (for onshore facilities) or section 112.11 (for offshore facilities). Typically, a gas plant is not considered an oil production facility.

During the life of an oil well, maintenance or remedial work may be necessary to improve productivity. A specialized workover rig, equipment, and associated containers are brought onsite to perform maintenance or remedial activities. Workover activities are a distinct operation and may be conducted by a separate owner or operator; therefore, a workover operation may be considered a separate mobile facility and be described in a different SPCC Plan, separate from the oil production facility. Although production activities may temporarily cease during workover, if the production equipment and containers (such as those found in a tank battery) remain operable, then the oil production facility owner/operator must maintain his or her own SPCC Plan during workover activities.

Farm

• Though the definition of farm is narrower than the definition of facility, if a farm meets the criteria, it may be subject to SPCC and/or FRP requirements.

The Environmental Protection Agency (EPA) defines “farm” in Part 112 by adapting the definition used by the National Agricultural Statistics Service (NASS) in its Census of Agriculture. NASS defines a farm as any place from which $1,000 or more of agricultural products were produced and sold, or normally would have been sold, during the census year. Operations receiving $1,000 or more in federal government payments are counted as farms, even if they have no sales and otherwise lack the potential to have $1,000 or more in sales.

EPA also considered the “farm tank” definition under the underground storage tank (UST) regulations at Part 280. As defined in section 280.12, a farm tank is a tank located on a tract of land devoted to the production of crops or raising of animals, including fish.

The term “farm” includes fish hatcheries, rangeland, and nurseries with growing operations, but does not include laboratories where animals are raised, land used to grow timber, and pesticide aviation operations. This term also does not include retail stores or garden centers where the product of nursery farms is marketed, but not produced, nor does the agency interpret the term “farm” to include golf courses or other places dedicated primarily to recreational, aesthetic, or other nonagricultural activities. Additionally, the definition of farm does not include agribusinesses because these businesses (e.g., oil marketing and distribution to farmers) are distinctly different from farms.

The definition of “farm” is narrower than the definition of “facility.” The definition of “facility” governs the overall applicability of Part 112, and thus is used to determine whether the owner or operator (e.g., a farmer) is subject to the spill prevention, control, and countermeasure (SPCC) and/or facility response plan (FRP) requirements and to determine the scope of his or her facility.

Natural gas production/treatment facilities and pipelines

• Because natural gas condensate is considered an oil, facilities that produce or store it may be regulated under Part 112 if the other criteria are met.
• Five scenarios are outlined in which facilities that produce or treat natural gas may be subject to SPCC rules.

The Environmental Protection Agency (EPA) does not regulate natural gas under Part 112. However, natural gas condensate is considered an oil and is regulated. For the purposes of determining Part 112 applicability, containers with 55 gallons or more in capacity storing condensate must be included in a natural gas facility’s total oil storage capacity calculation. Ancillary oil storage in other areas of the facility, such as fuel or lubrication oil, and oil-filled equipment, is also counted. Natural gas production or treatment facilities and pipeline systems commonly have associated oil storage, including oil-containing equipment such as compressors, drip tanks, and separators that may store motor oil, lubricants, crude oil impurities removed from the gas stream, and liquid condensate. Equipment that compresses or pumps the natural gas is not regulated unless there is oil-filled operational equipment associated with it that meets the applicability requirements of the rule.

The definition of “production facility” in section 112.2 specifies that an oil production facility involves the “production, extraction, recovery, lifting, stabilization, separation or treating of oil.” Therefore, under Part 112, any natural gas treatment facility that does not produce oil or condensate is not regulated as a production facility but may be regulated as a bulk oil storage facility because of aboveground ancillary oil storage, including oil-filled equipment. For the following scenarios, the general and administrative provisions of the rule (sections 112.1 through 112.7) apply, as well as the more specific requirements described.

Following are five example scenarios of facilities that are involved in producing or treating natural gas and how the spill prevention, control, and countermeasure (SPCC) rule (Part 112 Subparts A to C) would apply for each. Each of these scenarios is hypothetical and is not intended to provide a policy interpretation for any specific existing facility.

• Scenario A: Oil and gas production facility
• Scenario B: “Wet gas” production facility
• Scenario C: “Dry gas” production facility
• Scenario D: Gas processing/Treatment facility/Plant
• Scenario E: Facility supporting a gas pipeline

Scenario A: Oil and gas production facility

The wellhead at this type of facility produces a mixture of oil, gas, and produced water. Because this facility produces oil from the wellhead, it is considered an oil production facility according to the SPCC rule and must comply with the requirements at section 112.9.

Oil production facilities can include piping with both oil and gas phases. In this instance, such a facility’s dual-phase flowlines and intra-facility gathering lines (i.e., those carrying both gas and liquid phase hydrocarbon) are subject to the SPCC requirements because if the lines were to rupture or leak, they may discharge oil to navigable waters or adjoining shorelines in quantities that may be harmful as defined in Part 110.

Scenario B: “Wet gas” production facility

The wellhead at this type of facility produces a mixture of gas, produced water, and condensate. Condensate that is liquid at atmospheric pressures and temperatures is considered an oil, and the facility could be subject to the SPCC rule if it meets the SPCC rule applicability criteria. Because the facility produces oil, this facility is considered an oil production facility and must comply with the requirements at section 112.9 if subject to the SPCC rule. The presence of any gas treatment at the facility prior to the point of custody transfer (e.g., meter) into a gas pipeline would not affect the determination that this facility is an oil production facility.

Scenario C: “Dry gas” production facility

The wellhead at this facility produces a mixture of gas and produced water only. A dry gas production facility that produces natural gas from a well (or wells) but does not also produce condensate or crude oil that can be drawn off the tanks, containers, or other production equipment at the facility is not subject to the SPCC rule. EPA has clarified that a dry gas production facility does not meet the description of an “oil production, oil recovery, or oil recycling facility.” Therefore, a dry gas facility may be eligible for the wastewater treatment exemption under subparagraph 112.1(d)(6). However, if the aboveground ancillary storage of oil at a dry gas production facility is greater than 1,320 U.S. gallons, and the facility otherwise meets the applicability of the rule, the facility is regulated under the SPCC rule and must comply with the requirements for onshore facilities at section 112.8. Because the well does not produce recoverable oil or condensate, the facility does not meet the definition for an oil production facility under the SPCC rule.

Scenario D: Gas processing/Treatment facility/Plant

This type of facility receives gas after it is separated from oil and produced water. The gas typically contains condensate, which is removed from the gas stream at this facility. Petroleum distillate that is produced by natural gas wells and stored at atmospheric pressures and temperatures is considered an oil. If the total aboveground storage capacity for condensate tanks and all other ancillary oil storage is greater than 1,320 gallons, and the facility otherwise meets the applicability of the rule, then this facility is considered a bulk storage facility subject to the requirements under section 112.8. EPA has addressed this issue in a letter to the American Petroleum Institute, dated December 10, 2010, that details the agency’s position on how SPCC requirements apply to gas plants/compression stations.

However, when gas plant or compression activities are co-located at an SPCC-regulated oil production facility with a tank battery, then the containers associated with gas separation that store or process oil (i.e., separation vessels containing oil/ liquid condensate) are typically considered part of the oil production facility operations and therefore subject to the onshore oil production facility requirements under section 112.9 (or section 112.11 for offshore facilities).

Scenario E: Facility supporting a gas pipeline

At a facility supporting a gas pipeline, EPA regulates compressors or equipment containing oil (including condensate when it turns into liquid at atmospheric temperatures and pressures), but not gas-filled portions of equipment. If the aboveground oil storage capacity is greater than 1,320 gallons, and the facility otherwise meets the applicability of the rule, the facility is considered a bulk storage facility under the SPCC rule subject to the requirements under section 112.8.

Tank trucks

• Tank trucks are regulated by the EPA if they operate exclusively within the confines of a non-transportation-related facility.

The Environmental Protection Agency (EPA) regulates tank trucks (or mobile refuelers) as “mobile/portable containers” under Part 112 if they operate exclusively within the confines of a non-transportation-related facility. For example, a tank truck that moves within the confines of a facility and only leaves the facility to obtain more fuel (oil) would be considered to distribute fuel exclusively at one facility. This tank truck would be subject to Part 112 if it, or the facility, contained above the regulatory threshold amount and there was a reasonable expectation of discharge to navigable waters or adjoining shorelines. Similarly, a mobile refueler that fuels exclusively at one site, such as at an airport or construction site, would be subject to Part 112. However, if the tank truck only distributed fuel to multiple off-site facilities and did not perform fueling activities at the home base, the tank truck would be transportation-related, and regulated by the Department of Transportation (DOT).

Additionally, EPA regulates containers which were formerly used for transportation, such as a truck or railroad car, and are now used to store oil (i.e., no longer used for a transportation purpose) as a bulk storage container.

Tank trucks that are used in interstate or intrastate commerce can also be regulated if they are operating in a fixed, non-transportation mode. For example, if a home heating oil truck makes its deliveries, returns to the facility, and parks overnight with a partly filled fuel tank, it is subject to Part 112 if it or the facility has a capacity above the threshold amount, and there is a reasonable expectation of discharge to navigable waters or adjoining shorelines. However, if the home heating oil truck’s fuel tank contains no oil when it is parked at the facility, other than any residual oil present in an emptied vehicle, it would be regulated only by DOT.

Railroad cars

• EPA regulates railroad cars under Part 112 if they operate exclusively within the confines of a non-transportation-related facility.

The Department of Transportation (DOT) regulates railroad cars used for the transport of oil in interstate or intrastate commerce and the related equipment and appurtenances. DOT jurisdiction includes railroad cars that are passing through a facility or are temporarily stopped on a normal route. The Environmental Protection Agency (EPA) regulates railroad cars under Part 112 if they are operating exclusively within the confines of a non-transportation-related facility. EPA regulates both transfers to or from railroad cars and when the railroad cars serve as non-transportation-related storage at a Part-112-regulated facility.

When the railcar is serving as non-transportation-related storage, if the railroad car has a storage capacity above the regulatory threshold amount of oil, and there is a reasonable expectation of discharge to navigable waters or adjoining shorelines, the railroad car itself may become a non-transportation-related facility, even if no other containers at the property would qualify it as a Part-112-regulated facility.

Loading/Unloading activities

• EPA regulates the activity of loading or unloading oil in bulk into storage containers (such as those on tank trucks or railroad cars), as well as all equipment involved in this activity (e.g., a hose or loading arm attached to a storage tank system).

Loading/unloading rack means a fixed structure (such as a platform or gangway) necessary for loading or unloading a tank truck or tank car, which is located at a facility subject to the requirements of Part 112. A loading/unloading rack includes a loading or unloading arm, and may include any combination of the following: piping assemblages, valves, pumps, shut-off devices, overfill sensors, or personnel safety devices.

The Department of Transportation (DOT) regulates equipment used for the fueling of locomotive units, as well as the rights-of-way on which they operate. The Environmental Protection Agency (EPA) regulates the activity of loading or unloading oil in bulk into storage containers (such as those on tank trucks or railroad cars), as well as all equipment involved in this activity (e.g., a hose or loading arm attached to a storage tank system).

Different requirements apply to oil transfer areas and to loading/unloading racks at a regulated facility. A transfer area is any area of a facility where oil is transferred between bulk storage containers and tank trucks or railroad cars. These areas are subject to the general secondary containment requirements in paragraph 112.7(c). If a “loading/unloading rack” (as defined in section 112.2) is present, the requirements of paragraph 112.7(h) apply to the loading/unloading rack area.

Marine terminals

• Marine terminals are regulated under both the U.S. Coast Guard and the EPA.

A marine terminal is an example of a “complex” subject to both U.S. Coast Guard (USCG) and the Environmental Protection Agency (EPA) jurisdiction. The jurisdictional boundary of a complex facility for both USCG and EPA is defined in 33 CFR 154, Facilities Transferring Oil or Hazardous Material in Bulk, under the definition of a marine transportation-related facility (MTR facility) in section 154.1020.

The USCG regulates the pier structures, transfer hoses, hose-piping connection, containment, controls, and transfer piping associated with the transfer of oil between a vessel and an onshore facility. EPA regulates the tanks, internal piping, loading racks, and vehicle/rail operations that are completely within the non-transportation portion of the facility.

EPA jurisdiction begins at the first valve inside secondary containment. If there is no secondary containment, EPA jurisdiction begins at the valve or manifold adjacent to the storage tank.

Vessels (Ships/Barges)

• A vessel is a watercraft or other artificial contrivance used, or capable of being used, as a means of transportation on water, other than a public vessel. The loading or unloading of oil from a vessel is regulated by the U.S. Coast Guard.

Vessel means every description of watercraft or other artificial contrivance used, or capable of being used, as a means of transportation on water, other than a public vessel.

The U.S. Coast Guard regulates the loading or unloading of oil in bulk from a vessel to an onshore facility, as well as the oil-carrying vessel and the connecting piping (33 CFR 155, Oil or Hazardous Material Pollution Prevention Regulations for Vessels). In this scenario, a vessel is a ship or a barge. The oil passes from the USCG’s jurisdiction to that of the Environmental Protection Agency (EPA) when it passes the first valve inside the secondary containment for the storage container at an otherwise regulated facility. If there is no secondary containment, EPA’s jurisdiction begins at the first valve or manifold closest to the storage container. Storage tanks and appurtenances for the reception of oily ballast water or tank washings from vessels are under USCG jurisdiction.

Vessels themselves are specifically exempt from Part 112 under subparagraph 112.1(d)(1)(iii). EPA also clarified that barges or other watercraft that store oil, and have been determined by the USCG to be permanently moored, are no longer vessels, but storage containers that are part of an offshore facility.

Breakout tanks

• Breakout tanks may be regulated by the EPA, the DOT, or both, depending on how the tank is used.

Although breakout tanks can be used to relieve surges in an oil pipeline system or to receive and store oil transported by a pipeline for reinjection and continued transportation by pipeline, they are sometimes used for bulk storage (i.e., non-transportation-related storage). Thus, breakout tanks may be regulated by the Environmental Protection Agency (EPA), the Department of Transportation (DOT), or both depending on how the tank is used.

Breakout tanks used solely to relieve surges in a pipeline, not used for any non-transportation-related activity (i.e., pipeline-in and pipeline-out configuration, and with no transfer to other equipment/mode of transportation such as a tank truck), are not subject to EPA jurisdiction. Bulk storage containers used to store oil while also serving as a breakout tank for a pipeline or other transportation-related purposes may be subject to both EPA and DOT jurisdiction. Determining agency jurisdiction can be difficult and should be treated on a case-by-case basis.

Flowlines and gathering lines

• Any pipeline or piping that transports oil between facilities or from a facility to a vessel is considered transportation-related and is therefore outside the jurisdiction of the EPA.
• EPA has jurisdiction over non-transportation-related facilities, including pipelines that transport oil within a facility.

Flowlines are the piping that transfers crude oil and well fluids from the wellhead to the tank battery where separation and treatment equipment are typically located. A flowline may also connect a tank battery to an injection well. Flowlines are relatively small diameter steel or fiberglass piping (generally less than four inches). Depending on the size of the oil field, flowlines may run for hundreds of feet to a tank battery.

Gathering lines are the piping or pipelines that transfer the crude oil product between tank batteries, within or between facilities. Gathering lines often originate from an oil production facility’s lease automatic custody transfer (LACT) unit, which transfers oil to other facilities involved in gathering, refining, or pipeline transportation operations.

Any pipeline or piping that transports oil between facilities or from a facility to a vessel is considered transportation-related and is therefore outside the jurisdiction of the Environmental Protection Agency (EPA) and not subject to Part 112. EPA recognizes that gathering lines are often outside of the agency’s jurisdiction because they transport oil outside of an oil production facility.

However, EPA has jurisdiction over non-transportation-related facilities, including pipelines that transport oil within a facility. The definition of “facility” as it applies to Part 112 is flexible; depending upon how an owner/operator defines his or her facility, an oil production facility may also include gathering lines.

A typical oil production facility includes a wellhead, a tank battery (including, but not limited to, separation equipment, stock oil containers and produced water containers), and the flowlines that transfer the oil and well fluids from the wellhead to the tank battery. A flowline may also connect a tank battery to an injection well. If multiple tank batteries are included as part of the same facility for purposes of developing one Spill Prevention, Control, and Countermeasure (SPCC) Plan, then any gathering lines that connect the tank batteries, or flow to a central collection or gathering area or centralized tank battery within the facility boundaries, must also be included in the SPCC Plan. EPA considers any gathering lines within the boundaries of a facility to be “intra-facility gathering lines” and within EPA’s jurisdiction for the purposes of Part 112 applicability.

Quantity of discharge that may be harmful

• Any discharge of oil that meets the “sheen rule” may be harmful and must be reported to the National Response Center.

The Discharge of Oil Standard at Part 110 (also referred to as the “sheen rule”) defines a discharge of oil into or upon the navigable waters of the U.S. or adjoining shorelines in quantities that may be harmful under the Clean Water Act (CWA) as that which:

• Causes a sheen or discoloration on the surface of the water or adjoining shorelines;
• Causes a sludge or emulsion to be deposited beneath the surface of the water or upon adjoining shorelines; or
• Violates an applicable water quality standard.

A discharge meeting any of the above criteria triggers requirements to report to the National Response Center (NRC). The failure to report such a discharge may result in criminal sanctions under the CWA. The appearance of a “sheen” on the surface of the water is often used as a simple way to identify harmful discharges of oil that should be reported. However, the presence of a sludge or emulsion or of another deposit of oil beneath the water surface, or the violation of an applicable water quality standard also indicates a harmful discharge regardless of whether there is a sheen on the water surface.

Section 311 of the CWA defines and prohibits certain “discharges” of oil.

Reasonable expectation to discharge

• Facility owners/operators determine whether a discharge from their facilities can be reasonably expected, based in part on location, proximity to waterways, history of oil discharge, and other considerations.
• An owner/operator whose facility is not expected to discharge oil should be prepared to provide the rationale and any supporting documentation to an EPA inspector that explains why the facility does not need an SPCC Plan.

The Oil Pollution Prevention Standard at Part 112 applies only to facilities that, due to their location, can reasonably be expected to discharge oil as described in paragraph 112.1(b). The rule does not define the term “reasonably be expected.” The owner or operator of each facility must determine the potential for a discharge from that facility. According to subparagraph 112.1(d)(1)(i), this determination must be based solely upon consideration of the geographical and locational aspects of the facility. An owner or operator should consider the location of the facility in relation to a stream, ditch, gully, or storm sewer; the volume of material likely to be spilled; drainage patterns; and soil conditions. An owner or operator may not consider constructed features, such as dikes, equipment, or other man-made structures that prevent, contain, hinder, or restrain a discharge as described in paragraph 112.1(b), when making this determination.

A facility owner or operator, however, should consider the presence of man-made structures that may serve to transport discharged oil to navigable waters, such as sanitary or stormwater drainage systems, even if they lead to a publicly owned treatment work (POTW) facility prior to ultimate discharge into navigable waters. The presence of a treatment system such as a POTW cannot be used to determine that the facility is not reasonably expected to discharge to navigable waters or adjoining shorelines. POTWs can fail to contain oil. They are not designed to handle oil discharges and are on occasion forced to bypass to receiving water bodies during extreme weather events or when upsets occur in the treatment system.

The following factors may be useful to consider in determining whether there is a reasonable expectation of a discharge:

• Past discharges of oil from the facility or a neighboring facility that reached a navigable water or adjoining shoreline may indicate that another could be reasonably expected;
• Facility location relative to navigable waters, a watercourse and/or intervening natural drainage could cause a discharge to the navigable waters to be reasonably expected;
• Onsite conduits and certain underground features, such as sewer lines, storm sewers, power or cable lines, or groundwater could facilitate the transport of discharged oil off-site to navigable waters;
• Unique geological or geographic features could facilitate the transport of discharged oil off-site to navigable waters;
• Precipitation runoff could transport oil into navigable waters; and
• Quantity and nature of oil stored.

If an owner or operator determines that, due to the location, the facility cannot reasonably be expected to discharge oil as described in 112.1(b), the owner/operator should be prepared to provide the rationale and any supporting documentation to an Environmental Protection Agency (EPA) inspector that explains why the facility does not have a Spill Prevention, Control, and Countermeasure (SPCC) Plan.

Tools to determine reasonable expectation of discharge

While EPA does not endorse or recommend any particular modeling programs, the agency recognizes that there are software tools available to aid in making the reasonable expectation of discharge determination, which have been used by various industry sectors. Such tools may combine data concerning the location of facilities with respect to navigable waters, geographical features, type of oil stored, soil type, and other factors as described above, to make site-specific estimations. The SPCC Plan preparer and/or certifying professional engineer may determine whether any software tool is appropriate for the specific circumstances and should adequately document the input variables in the SPCC Plan.

Geographic scope

• Revisions in 2002 expanded the geographic scope of EPA’s Part 112 to make it more consistent with the Clean Water Act.

The Environmental Protection Agency (EPA) revised the geographic scope described in paragraph 112.1(b) in 2002 to be more consistent with the Clean Water Act (CWA). Formerly, the geographic scope of Part 112 extended to navigable waters of the U.S. and adjoining shorelines. The current rule reflects the full geographic scope of EPA’s authority to include a discharge:

• Into or upon navigable waters of the U.S. and adjoining shorelines;
• Into or upon the waters of the contiguous zone;
• In connection with activities under the Outer Continental Shelf Lands Act or the Deepwater Port Act of 1974; or
• That may affect natural resources belonging to, appertaining to, or under the exclusive management authority of the United States (including resources under the Magnuson Fishery Conservation and Management Act).

The scope includes discharges harmful not only to the public health and welfare but also to the environment through the protection of natural resources. Such protection would apply to resources under the Magnuson Fishery Conservation and Management Act, a statute that establishes exclusive U.S. management authority over all fishing within the exclusive economic zone (inner boundary coterminous with the seaward boundary of each coastal state), and all anadromous fish throughout their migratory range except when in a foreign nation’s waters, and all fish on the continental shelf.

Navigable waters

• Navigable waters are waters of the United States, including the territorial seas; however, since 2001, the definition of “waters of the United States” has come into question following decisions of the U.S. Supreme Court.

Part 112.2 provides a definition of “navigable waters,” referring to the definition of the same term found at section 120.2. Section 120.2, in turn, states, “Navigable waters means waters of the United States, including the territorial seas.” That sounds simple, but the Environmental Protection Agency (EPA) has had a difficult time nailing down the meaning of “waters of the United States,” also known as WOTUS, since a 2001 U.S. Supreme Court decision, Solid Waste Agency of Northern Cook County v. U.S. Army Corps of Engineers, and later court decisions.

Each EPA administration has attempted to set the scope of waters that are subject to the Clean Water Act, and each attempt has faced lawsuits. The definition of WOTUS has been revised several times. What’s more, the agency intends to propose and finalize yet another iteration in the years to come.

For the current definition, facility owners/operators will want to review the latest 112.2 and 112.20.

Bulk storage container

• Bulk storage container means any container with a capacity of 55 gallons or more that is used to store oil.

Bulk storage container means any container used to store oil. These containers are used for purposes including, but not limited to, the storage of oil prior to use, while being used, or prior to further distribution in commerce. Oil-filled electrical, operating, or manufacturing equipment is not a bulk storage container.

Although the term uses the word bulk, facilities must not confuse the term with bulk containers under the Department of Transportation (DOT). Any oil storage container with a capacity of 55 gallons or greater is considered a bulk storage container, for the purposes of Part 112.

Double-walled tank

• A double-walled tank is basically a tank within a tank, and is a type of bulk storage container.

Double-walled tanks are essentially a tank within another tank, equipped with an interstitial (i.e., annular) space and constructed in accordance with industry standards. The inner tank serves as the primary oil storage container while the outer tank serves as secondary containment. The outer tank of a double-walled tank may provide adequate secondary containment for discharges resulting from leaks or ruptures of the entire capacity of the inner storage tank.

A double-walled tank is a type of bulk storage container under Part 112.

Vaulted tank

• Vaulted tank can mean a double-walled tank or a tank inside an underground vault, room or crawl space. It is another type of bulk storage container.

The term “vaulted tank” has been used to describe both double-walled tanks (especially those with a concrete outer shell) and tanks inside underground vaults, rooms, or crawl spaces. A vaulted tank is a type of bulk storage container under Part 112.

Aboveground storage tank

• Aboveground storage tanks can include containers such a 55-gallon drum that are completely above the ground or can be partially but not completely buried underground.

Aboveground oil storage containers include the following container types:

• An aboveground container of oil, such as a 55-gallon drum or a large tote.
• A bunkered tank, which is 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 material.
• A partially buried tank, which is a storage container that is partially inserted or constructed in the ground, but not entirely below grade, and not completely covered with earth, sand, gravel, asphalt, or other material.

Completely buried tank

• Completely buried tank means any container completely below grade and covered with earth, sand, gravel, asphalt, or other material.

Completely buried tank means any container completely below grade and covered with earth, sand, gravel, asphalt, or other material. Containers in vaults, bunkered tanks, or partially buried tanks are not considered completely buried tanks, but rather aboveground storage containers for purposes of Part 112.

Also, a completely buried tank is not the same as an underground storage tank (UST), which is defined at Part 280. A UST is a tank and any underground piping that has at least 10 percent of its combined volume underground. In fact, if a UST is not completely buried, it is considered an aboveground storage tank under Part 112.

See the Terms related to exemptions under Part 112 for more discussion about underground storage tanks.

Oil-filled operational equipment

• Oil-filled operational equipment means equipment that includes an oil storage container (or multiple containers) in which the oil is present solely to support the function of the apparatus or the device.

Oil-filled operational equipment means equipment that includes an oil storage container (or multiple containers) in which the oil is present solely to support the function of the apparatus or the device. Oil-filled operational equipment is not considered a bulk storage container and does not include oil-filled manufacturing equipment (flowthrough process). Examples of oil-filled operational equipment include, but are not limited to, hydraulic systems, lubricating systems (e.g., those for pumps, compressors and other rotating equipment, including pumpjack lubrication systems), gear boxes, machining coolant systems, heat transfer systems, transformers, circuit breakers, electrical switches, and other systems containing oil solely to enable the operation of the device.

When piping is intrinsic to the oil-filled operational equipment in a closed loop system, i.e., inherent to the equipment and used solely to facilitate operation of the device (e.g., for lubrication), then the Environmental Protection Agency (EPA) considers the piping to be a component of the oil-filled operational equipment. However, piping not intrinsic to the operational equipment (e.g., flowlines, transfer piping or piping associated with a process) is not considered to be part of the oil-filled operational equipment.

Oil-filled manufacturing equipment

• Oil-filled manufacturing equipment stores oil only as an ancillary element of performing a mechanical or chemical operation to create or modify an intermediate or finished product.

Oil-filled manufacturing equipment is distinct from bulk storage containers in its purpose. Oil-filled manufacturing equipment stores oil only as an ancillary element of performing a mechanical or chemical operation to create or modify an intermediate or finished product. Examples of oil-filled manufacturing equipment may include reaction vessels, fermenters, high pressure vessels, mixing tanks, dryers, heat exchangers, and distillation columns.

Under Part 112, flow-through process vessels are generally considered oil-filled manufacturing equipment since they are not intended to store oil. Additionally, there may be oil-filled operational equipment (e.g., a hydraulic unit) at this type of facility to support the manufacturing equipment. The professional engineer (PE) reviewing and certifying a Spill Prevention, Control, and Countermeasure (SPCC) Plan should be familiar with processes taking place at the facility and should therefore determine whether a given process vessel is considered a bulk storage container or oil-filled manufacturing equipment.

In cases where a container is used for the static storage of oil within a manufacturing or processing area, the PE may determine that the container is in fact a bulk storage container. Examples of oil storage within manufacturing areas include:

• Storing an intermediate product for an extended period of time in a continuous or batch process;
• Storing a raw product prior to use in a continuous or batch process; and
• Storing a final product after a continuous or batch process.

Storage tanks and containers located at the beginning or end of a process and used to store feedstock or finished products generally are considered bulk storage containers. In cases where oil storage is incidental to the manufacturing activity or process (e.g., where it is being transformed in a flow-through process vessel), the facility may determine that the container is part of the manufacturing equipment.

Oil-filled manufacturing equipment is inherently more complicated than oil-filled operational equipment because it typically involves a flow-through process and is commonly interconnected through piping.

Oil-powered generators

• Oil-powered generators, or gen-sets, are a combination of oil-filled operational equipment and a bulk oil storage container.

Oil-powered generators are commonly referred to as “gen-sets.” Gen-sets are a combination of oil-filled operational equipment and a bulk oil storage container. The oil that is consumed to generate electricity is not inherent to the device and is stored in a bulk storage container, which requires transfers of oil because oil is consumed in order to generate electricity. Therefore, although gen-sets include oil-filled operational equipment, such as the lubrication oil reservoir, gen-sets, as a whole unit, do not meet the definition of oil-filled operational equipment.

Newer designs of gen-sets provide for a double-walled tank for the bulk oil storage container.

Other containers

• Other containers that may be regulated under Part 112 include partially-buried tanks, portable and mobile containers, motive power containers, and produced water containers.

Partially buried tank

Partially buried tank means a storage container that is partially inserted or constructed in the ground, but not entirely below grade, and not completely covered with earth, sand, gravel, asphalt, or other material. A partially buried tank is considered an aboveground storage container for purposes of Part 112.

Portable and mobile containers

Portable oil storage containers are those containers that store 55 gallons or more, such as 55-gallon drums, skid tanks, totes, and intermediate bulk containers (IBCs). Mobile oil storage containers are containers on wheels operated within the confines of the non-transportation-related facility.

A mobile refueler is a type of mobile container. Specifically, a mobile refueler means a bulk storage container onboard a vehicle or towed, that is designed or used solely to store and transport fuel for transfer into or from an aircraft, motor vehicle, locomotive, vessel, ground service equipment, or other oil storage container.

Motive power containers

Motive power container means any onboard bulk storage container used primarily to power the movement of a motor vehicle, or ancillary onboard oil-filled operational equipment. An onboard bulk storage container which is used to store or transfer oil for further distribution is not a motive power container. The definition of motive power container does not include oil drilling or workover equipment, including rigs.

Produced water containers

Produced water container means a storage container at an oil production facility used to store the produced water after initial oil/water separation, and prior to reinjection, beneficial reuse, discharge, or transfer for disposal.