Response: Requirement v. recommendation. The first sentence of the proposed rule indeed contemplated a requirement, i. e., that no container may be used for the storage of oil unless its material and construction are compatible with the material stored and the conditions of storage, such as pressure or temperature. The second sentence, which was clearly a recommendation, has been deleted from the rule because we have decided to remove all recommendations from the rule language. Rules are mandates, and we do not wish to confuse the regulated community as to what actions are 229 mandatory and what actions are discretionary. The Professional Engineer must, pursuant to §112.3( d)( 1)( iii), certify that he has considered applicable industry standards in the preparation of the Plan. While he must consider such standards, use of any particular standards are a matter of good engineering practice.

Additional industry standards. While we do not specify particular standards in the rule, we endorse the use of industry standards. We note that the discussion of many sections of the rule addresses particular industry standards.

Section 112.8( c)( 2). We will address issues relating to §112.8( c)( 2) under the discussion of that section.

XI  B( 2) Secondary containment for bulk storage containers at onshore facilities  §112.8( c)( 2)

Background: In 1991, we proposed to redesignated the §112.7( e)( 2)( ii) secondary containment requirements of the current rule as §112.8( c)( 2), and make some revisions. We gave notice in the preamble that "sufficient freeboard" to contain precipitation is freeboard sufficient to contain a 25 year storm event. We also proposed that diked areas be sufficiently impervious to contain spilled oil for at least 72 hours. The rationale for the 72 hour standard was to allow time for the discovery and removal of a discharge.

Electrical equipment. In the 1991 preamble, we noted that certain facilities may have equipment such as electrical transformers that contain significant quantities of oil for operations rather than for storage. For safety and other considerations, we determined that we should not require an owner or operator of such oil filled equipment to comply with §112.8( c) or §112.9( d) secondary containment requirements, because storage of oil in bulk is not the primary purpose of such equipment. Therefore, we stated that an owner or operator of a facility with equipment containing oil for ancillary purposes does not need to provide secondary containment for this equipment or implement the other provisions of proposed §112.8( c) (or §112.9( d). 56 FR 54623. However, an owner or operator of oil filled equipment must meet other applicable SPCC requirements including the requirements of §112.7( c), to provide appropriate containment and diversionary structures to prevent discharged oil from reaching navigable waters.

Comments: De minimis containers. "Request that some de minimis limit be set for requiring secondary containment. While in some cases secondary containment for the largest tank is acceptable, can manufacturers may have several smaller tanks, none of which should be considered large." (62)

Designations. "In extraordinary circumstances, EPA Solid Waste and Emergency Response should designate local fire regulatory authorities and/ or state and local EPA's to make decisions concerning `deemed equivalency' for secondary containment, as is done by the UST section of EPA." (65) 230 Double walled or vaulted tanks. We should allow an owner or operator to use prefabricated vaulted, or double walled tanks with secondary containment under §112.8( c). (65, 79, 140, 144, 179)

Facility size. "Recognizing EPA's limited funding and enforcement resources, EPA should consider allowing the state EPA's and the fire regulatory authorities to continue to regulate the small `throughput' vaulted tank industry which fire regulatory authorities have defined as 6,000 per tank and 18,000 gallons per site." (65, 79)

Fire codes. "Deem as equivalent for EPA purposes, the secondary containment of VAST technology which meets any of EPA recognized industry standards of the model fire codes of NFPA, BOCA, or UFC." (65)

Freeboard. Double walled steel tanks with integral secondary containment, and other factory fabricated tanks with secondary containment are designed so that precipitation does not collect within the secondary containment. (65, 140) Asks us to address the technical construction design of steel tanks with factoryfabricated secondary containment in the §112.8( c)( 2) freeboard requirements. (140) A double walled "F921 92" AST or its equivalent does not need freeboard because it is entirely enclosed; the outside tank is larger than the inside tank and will hold the entire contents of the primary tank. (179)

Impermeability. VASTs are impervious to oil for 72 hours. (65)

Outer steel wrap. The secondary containment provided by a factory fabricated, "integral outer steel wrap" is acceptable if the system has additional mechanisms to prevent overfill and provide containment. (140)

Regional opposition. "Working mostly with fire prevention personnel and codes, but with environmental protection of equal concern, several styles of tanks have been developed which will meet the intent of the proposed regulations for protection of the environment, but based on an interpretation from Region 10 have not ben allowed to be used." (108, 122)

Vandalism and fire. A VAST's concrete encasement provides protection against vandalism and fire. VASTs allow an owner or operator to dike the contents of every tank, rather than only the single largest tank. (65)

Editorial suggestions. Recommends that we move the proposed §112.8( c)( 2) on secondary containment requirements to the proposed §112.8( c)( 3) on drainage requirements. Asks that we change the phrase "all bulk storage tank installations" to "tanks" in the proposed §112.8( c)( 2) sentence, "All bulk storage tank installations should be constructed so that a secondary means of containment is provided for the entire contents of the largest single tank and sufficient freeboard to allow for precipitation." (121) 231 Electrical or other operating equipment. Support for proposal that an owner/ operator who has equipment containing oil for ancillary purposes need not have secondary containment nor comply with the §112.8( c) and §112.9( d) bulk storage container provisions. (66, 103, 125, 132, 134, 156, 164, L7, L20)

Fire, hazard, safety considerations. Installing secondary containment for electrical equipment may create electrical and fire hazards. (125) We should clarify what "safety and other considerations" make it appropriate to exclude electrical equipment from secondary containment requirements. (L17)

Leak detection. An owner or operator can immediately detect a leak from electrical equipment because a leak would trigger the alarm system. (66, 98, 138, L20) Electrical equipment is constructed with pressure relief devices and that a leak from one unit would not affect another unit. (L20)

Operating equipment. We should exclude from the secondary containment requirements: trash compactors and process or water pumps; lubricating oil used in engines, turbines, compressors, and expanders; oil circuit breakers and auto boosters; oil held temporarily in the internal or external storage compartment of an oil/ water separator; oil used in cranes, jacks, elevators, and forklifts; hydraulic lift systems; throughput type tanks; wastewater treatment tanks; and capacitors and oil based heaters. (62, 65, 66, 102, 107, 125, 132, L7)

Manifolded tanks. "The term `single largest tank' should be modified to include tanks which are manifolded together, or otherwise have overflow capabilities." (27)

Seventy two hour impermeability standard. See the discussion on §112.7( c) for the comments on this subject.

Secondary containment, in general.

Supports requirement. Secondary containment for storage containers, including mobile storage containers, should be adequate to contain the contents of the largest, single tank within the secondary containment with freeboard sufficient for precipitation from a 25 year storm event. The State of New Jersey has this requirement. (27, 147)

Opposes requirement. Requiring secondary containment for small ASTs is unduly burdensome and impractical, and would require owners or operators to staff and monitor otherwise unstaffed sites. (69) Asks us to consider promulgating a "more realistic" provision for secondary containment systems (71). We have no justification for requiring an owner or operator to provide secondary containment for the contents of the largest single tank, or for requiring an owner or operator to provide freeboard sufficient to allow for precipitation. The commenter cited our "Analysis of Implementing Permitting Activities for Stormwater Discharges Associated with Industrial Activity" document as evidence 232 of the minimal risk posed by secondary containment overflow (July 1991). (173) We should recognize that secondary containment installation is not possible for all tanks (e. g., indoor tanks). (175)

Contingency planning instead. Asks us to follow the Federal Aviation Administration's example, and allow an owner or operator of a facility with "small numbers of small capacity ASTs" to conduct contingency planning and training instead of installing secondary containment. We should use the fire prevention code to define the term "small numbers of small capacity ASTs" as "less than a total capacity of 6, 000 gallons per facility." (69)

Largest single tank. Not all facilities "have enough property to provide this volume of containment," which would result in an enormous operational burden for existing facilities. However, we should require secondary containment for existing tanks with a volume greater than 100,000 gallons. (90) "Impervious containment of a volume larger than the largest single tank may not be necessary for all tanks." (90,126)

Methods. "In other words, we recommend that the free choice of design offered to the facility by 112. 8( b)( 3) be preserved in 112. 8( c)( 2) and not be narrowed to allow only drainage trench enclosures in cases where diking is not used." (L26)

Oil/ water separators. Asks us to allow properly sized and operated oil/ water separators to meet the drainage control and secondary containment requirements. (98)

Phase in. We should phase in secondary containment requirements, and apply them to large facilities only. (116)

Underground cable systems. "Even if secondary containment systems could be installed, the costa are likely to be prohibitive. ... Electric utilities already have operational response plans to address leaks as part of their planning to prevent disruption of service." (125)

"Should to shall" cost. We reduced the impact of the proposal by failing to consider the cost of changing "should" to "shall," and cited the secondary containment requirement as an example. The proposed rule requires an owner or operator to equip all tank batteries with secondary containment, although many petroleum extraction industry tank batteries do not have secondary containment because of the cost or lack of need. (L27)

Snow and ice. "In the case of many Rocky Mountain fields, secondary containment in the form of dikes is worthless because of drifting snow which turns to ice filling the diked area." (L27)

Sufficient freeboard. 233 Alternatives to freeboard. "Also, the regulations should specify that maintaining any freeboard does not apply when rainguards are used to divert storm water and keep it from accumulating in the diked area." (88) "E& P operations should have the option to use portable/ permanent pumps or water hauler trucks for removal of any 25 year storm water event. KMS believes the more appropriate and applicable standard is the 10 year event." (114)

Clarification needed. We should clarify what we mean in §112.8( c)( 2) by "sufficient freeboard." (54, 154, 179, L18)

10 year storm event. It would be adequate to provide freeboard sufficient to contain precipitation from a 10 year storm event, or more specifically, a 10 year, 24 hour storm event. (48, 80, 87, 95, 102, 114, 133, L3, L12)

25 year storm event.

Opposes recommendation. "It will be difficult and would require meteorological studies over a period of time to determine what freeboard is sufficient to contain a 25 year storm event." (34, 53) "We should consider as sufficient, a tank's ability to contain 110 percent of the capacity of the largest tank, which is an accepted industry standard and consistent with good engineering practice. (34, 48, 54, 133, L7) "We feel that the 25 year storm containment recommendation is unduly stringent, and would impose considerable costs without any significant benefits." (80) We should allow flexibility for determining whether a facility has adequate freeboard. There is not enough space to retrofit the containment areas required to provide freeboard for a 25 year storm for all facilities. (88) "The chances of a secondary containment dike being full of oil at the same time that a 24 hour, 25 year storm event takes place is astronomically small. Freeboard capable of holding a 24 hour, 10 year storm event is sufficient." (102) The volume from a 25 year storm event should remain as a recommendation, but we should not specify the amount of precipitation accumulated from a 25 year storm event because it will vary depending on the location. States may require a specific freeboard capacity. (143) "The rubber industry is concerned that the 25 year freeboard `recommendation' will be interpreted as a `requirement'." (L3) "This `requirement' may be sufficient for new storage tanks. Secondary containment for previously installed tanks, however, may have been designed for 100% of the largest tank, 110% of the largest tank, 100% of the largest tank plus 0.5 inches of rain, or another viable measure. EPA should provide some variance to allow existing containment to meet the intent of the law, and thereby not requiring small additions to the containment structure with minimum resulting benefit." (L7)

Clarification needed. We should clarify what we meant by "sufficient to contain a 25 year storm event." (54) Asks clarification of the duration and the recurrence frequency of the 25 year storm event. (76, 87, 102, 114) 234 Response: De minimis containers. We have established a de minimis container size of less than 55 gallons. You do not have to provide secondary containment for containers of less than 55 gallons.

Designations. We disagree that we should designate State and local authorities to determine whether a tank meets the §112.8( c) secondary containment requirements. We have no authority under the Clean Water Act to delegate elements of the SPCC program to State or local governments. We likewise disagree that we should that we should designate Federal authorities, including our regional offices, to determine whether a container meets the §112.8( c) secondary containment requirements. Such a determination is in the first instance one for the owner or operator to make in consultation with his Professional Engineer. If the Regional Administrator disagrees with this determination, he may require the owner or operator to amend his Plan.

Double walled or vaulted tanks. 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. While double walled or vaulted tanks are subject to secondary containment requirements, shop fabricated double walled aboveground storage tanks equipped with adequate technical spill and leak prevention options might provide sufficient equivalent secondary containment as that required under §112.7( c). Such options include overfill alarms, flow shutoff or restrictor devices, and constant monitoring of product transfers. In the case of vaulted tanks, the Professional Engineer must determine whether the vault meets the requirements for secondary containment in §112.7( c). This determination should include an evaluation of drainage systems and of sumps or pumps which could cause a discharge of oil outside the vault. Industry standards for vaulted tanks often require the vaults to be liquid tight, which if sized correctly, may meet the secondary containment requirement.

There might also be other examples of such alternative systems. Larger, field erected tanks (generally over 12,000 gallons) should not be without more traditional forms of secondary containment as listed in §112.7( c) because of the higher risk of uncontrolled discharges from such tanks due to tank size, design, and pumping rates.

Editorial suggestions. We disagree that we move should §112.8( c)( 2) secondary containment requirements to §112.8( c)( 3) with drainage requirements. Drainage and secondary containment are discrete subjects which should be handled separately.

In the first sentence, "spill" becomes "discharge." Also in that sentence, "contents of the largest single tank" becomes "capacity of the largest single container." This is merely a clarification and has always been the intent of the rule. The contents of a container may vary from day to day, but the capacity remains the same. In discussing capacity, we noted in the 1991 preamble that "the oil storage capacity (emphasis added) of the equipment, however, must be included in determining the total storage capacity of the facility, which determines whether a facility is subject to the Oil Pollution Prevention regulation." 56 FR 54623. We discuss this capacity in the context of the general requirements for secondary containment. Thus, it is clear that we have always intended 235 capacity to be the determinative factor in both subjecting a facility to the rule and in determining the need for secondary containment.

We also deleted the phrase "but they may not always be appropriate" from the third sentence of the paragraph because it is confusing when compared to the text of §112.7( d). Under §112.7( d), if secondary containment is not practicable, you may provide a contingency plan in your SPCC Plan and otherwise comply with that section. In the last sentence, "plant" becomes "facility." Also in that sentence, the phrase "so that a spill could terminate...." becomes "so that any discharge will terminate...."

Electrical or other operating equipment. Because electrical, operating, manufacturing equipment are not bulk storage containers, the §112.8( c)( 2) secondary containment requirement is inapplicable to those devices or equipment. 56 FR 54623. However, the general secondary containment requirement at §112.7( c) is applicable. If it is not practicable from a matter of good engineering practice (for example, because of safety reasons or the danger of fire or explosion) to install secondary containment for oil filled equipment, the owner or operator must provide a contingency plan following part 109 and otherwise comply with §112.7( d).

Model fire codes. Compliance with a model fire code may be acceptable under §112.8( c) if the code meets the requirements of the section. We note that we meet with fire code officials from time to time.

Secondary containment, in general. A primary containment system is the container or equipment in which oil is stored or used. Secondary containment is a requirement for all bulk storage facilities, large or small, manned or unmanned; and for facilities that use oil filled equipment; whenever practicable. Such containment must at least provide for the capacity of the largest single tank with sufficient freeboard for precipitation. A discharge as described in §112. 1( b) from a small facility may be as environmentally harmful as such a discharge from a large facility, depending on the surrounding environment. Likewise, a discharge from a manned facility needs to be contained just as a discharge from an unmanned one. A phase in of these requirements is not appropriate because secondary containment is already required under current rules. When secondary containment is not practicable, the owner or operator of a facility may deviate from the requirement under §112.7( d), explain the rationale in the Plan, provide a contingency plan following the provisions of 40 CFR part 109, and otherwise comply with §112.7( d).

Because a pit used as a form of secondary containment may pose a threat to birds and wildlife, we encourage an owner or operator who uses a pit to take measures to mitigate the effect of the pit on birds and wildlife. Such measures may include netting, fences, or other means to keep birds or animals away. In some cases, pits may also cause a discharge as described in §112. 1( b). The discharge may occur when oil spills over the top of the pit or when oil seeps through the ground into groundwater, and thence to navigable waters or adjoining shorelines. Therefore, we recommend that an owner or operator not use pits in an area where such pit may prove a source of such discharges. 236 Should the oil reach navigable waters or adjoining shorelines, it is a reportable discharge under 40 CFR 110.6.

We disagree that the rule is duplicative of NPDES rules. Forseeable or chronic point source discharges that are permitted under CWA section 402, and that are either due to causes associated with the manufacturing or other commercial activities in which the discharger is engaged or due to the operation of treatment facilities required by the NPDES permit, are to be regulated under the NPDES program. "Classic spill" situations are subject to the requirements of CWA section 311. Such spills are governed by section 311 even where the discharger holds a valid and effective NPDES permit under section 402. 52 FR 10712, 10714. Therefore, the typical bulk storage facility with no permitted discharge or treatment facility would not be under the NPDES rules.

The secondary containment requirements of the rule apply to bulk storage containers and their purpose is to help prevent discharges as described in §112.1( b) by containing discharged oil. NPDES rules, on the other hand, may at times require secondary containment, but do not always. Furthermore, NPDES rules may not always apply to bulk storage facilities. Therefore, the rule is not always duplicative of NPDES rules. Where it is duplicative, an owner or operator of a facility subject to NPDES rules may use that portion of his Best Management Practice Plan as part of his SPCC Plan.

Alternatives. Oil/ water separators. The rule does not mandate the use of any specific means of secondary containment. Any system that achieves the purpose of the rule is acceptable. That purpose is to prevent discharges as described in §112.1( b).

Phase in. There is no need for a phase in of secondary containment requirements because they are already in effect and apply to all facilities, large and small.

Snow and ice. We disagree that secondary containment is unnecessary for facilities in which drifting snow turns to ice in the diked area. Such snow or ice may be contaminated with oil and cause harm to the environment if it escapes the facility.

Seventy two hour impermeability standard. As noted above, we have decided to withdraw the proposal for the 72 hour impermeability standard and retain the current standard that diked areas must be sufficiently impervious to contain oil. We take this step because we agree with commenters that the purpose of secondary containment is to contain oil from reaching waters of the United States. The rationale for the 72 hour standard was to allow time for the discovery and removal of an oil spill. We believe that an owner or operator of a facility should have flexibility in how to prevent discharges as described in §112.1( b), and that any method of containment that achieves that end is sufficient. Should such containment fail, an owner or operator must immediately clean up any discharged oil. Similarly, we intend that the purpose of the "sufficiently impervious" standard is to prevent discharges as described in §112.1( b) by ensuring 237 that diked areas can contain oil and are sufficiently impervious to prevent such discharges.

"Should to shall" cost. There is no cost in the "should to shall to must" change because the change is merely editorial.

Sufficient freeboard. An essential part of secondary containment is sufficient freeboard to contain precipitation. Whatever method you use to calculate the amount of freeboard that is "sufficient" must be documented in the Plan. We believe that the proper standard of "sufficient freeboard" to contain precipitation is that amount necessary to contain precipitation from a 25 year, 24 hour storm event. That standard allows flexibility for varying climatic conditions. It is also the standard required for certain tank systems storing or treating hazardous waste. See, for example, 40 CFR 265.1( e)( 1)( ii) and (e)( 2)( ii). While we believe that 25 year, 24 hour storm event standard is appropriate for most facilities and protective of the environment, we are not making it a rule standard because of the difficulty and expense for some facilities of securing recent information concerning such storm events at this time. Recent data does not exist for all areas of the United States. Furthermore, available data may be costly for small operators to secure. Should recent and inexpensive information concerning a 25 year, 24 hour storm event for any part of the United States become easily accessible, we will reconsider proposing such a standard.

XI  B( 3) Drainage of rainwater  §112.8( c)( 3)

Issues. In 1991, we also proposed several changes to §112.7( e)( 2) of the current rule on bulk storage tanks at onshore facilities (excluding production facilities). Specifically, we proposed to redesignated §112.7( e)( 2)( iii) as §112. 8( c)( 3). Proposed paragraph (c)( 3) addressed drainage from diked areas around bulk storage tank installations. It contains requirements for drainage of uncontaminated rainwater from a diked area into a storm drain or discharge of an effluent into an open watercourse, lake, or pond, bypassing the facility treatment system.

Comments: NPDES. Records of discharges that do not violate water quality standards are unnecessary. "It is more logical and less confusing to train operators to report by exception." (88) "To avoid unnecessarily duplicative and overlapping work, we request that the Agency clarify that records and testing normally required for a permitted outfall under the NPDES program are adequate to fulfill the requirements under this section." (92)

Methods. The proposed requirement in §112.8( c)( 3) to close and seal drains on dikes or equivalent measures at all times, except when rainwater is being drained, precludes engineering measures, such as standpipes, based on good engineering practice. Requiring the closing of standpipe valves defeats the purpose of installing the valves in the first place. (28, 101, 165, L15, L27) 238 Response: Methods. Acceptable measures might, depending on good engineering practice, include using structures such as standpipes designed to handle flow through conditions at certain oil production operations, where large volumes of water may be directed to oil storage tanks if water discharge lines on oil water separators become plugged.

NPDES. We are not adopting the NPDES rules for SPCC purposes, but are only offering an alternative for recordkeeping. The intent of the rule is that you may, if you choose, use the NPDES stormwater discharge records in lieu of records specifically created for SPCC purposes. We are not incorporating the NPDES requirements into our rules by reference.

This paragraph applies to discharges of rainwater from diked areas that may contain any type of oil, including animal fats and vegetable oils. The only purpose of this paragraph is to offer a recordkeeping option so that you do not have to create a duplicate set of records for SPCC purposes, when adequate records created for NPDES purposes already exist.

XI  B( 4) Completely buried tanks; corrosion protection  §112.8( c)( 4)

Background: In 1991, we redesignated and reproposed current §112.7( e)( 2)( iv) as §112.8( c)( 4), to require that an owner or operator protect new completely buried storage tanks installed on or after January 10, 1974, from corrosion by coatings, cathodic protection, or other effective methods compatible with local soil conditions.

In 1991, we also proposed changing the §112.7( e)( 2)( iv) requirement for regular pressure testing to a recommendation for regular leak testing of buried tanks. We specified leak testing rather than pressure testing to be consistent with many State rules. Because completely buried tanks currently subject to the technical requirements of 40 CFR parts 280 and 281, the underground storage tank (UST) regulations, are generally exempted from SPCC requirements under proposed §112.1( d)( 4), §112.8( c)( 4) applies only to tanks not subject to 40 CFR part 280 or 281.

Comments: Part 280 standards. We should avoid duplicative environmental requirements by expressly stating that metallic USTs must meet the "appropriate requirements of 40 CFR 280." (44, 67, 85, 111, 175, 180)

Corrosion protection.

Support for proposal. "We support the proposed requirement for protective coating and cathodic protection for new or replaced buried piping, regardless of soil conditions." (L17)

Opposition to proposal.

"Unenforceable." Proposal "is unenforceable." (121) 239 Monitoring effectiveness. "...( T) he regulation contains no discussion of cathodic protection for tank bottoms in contact with soil or fill materials. Also the regulation includes no requirements for monitoring the effectiveness of cathodic protection of buried tanks and piping." (16)

Leak testing.

Support for proposal. Support for our proposal for discretionary leak (or discharge) testing with some modifications. (48, 67, 85, 102) "ILMA agrees that making this a recommended, rather than mandatory, practice is consistent with the goal of using good engineering practice. This offers regulated facilities the flexibility to monitor these tanks with a frequency necessitated by site specific circumstances, such as the ages of the tanks or soil conditions." (48)

Opposition to proposal. "As to leak testing, there is no current requirement for integrity testing of buried piping at storage facilities. At very large facilities it may be practical to conduct the type of testing proposed. However, for small and medium facilities it is impractical and would be extremely costly to implement this recommended practice." (34)

Response: Corrosion protection. We agree in principle that all completely buried tanks should have some type of corrosion protection, but as proposed, we will only extend that requirement to new completely buried metallic storage tanks. Because corrosion protection is a feature of the current rule (see §112.7( e)( 2)( iv)), the requirement applies to completely buried metallic tanks installed on or after January 10, 1974. The requirement is enforceable because it is a procedure or method to prevent the discharge of oil. See section 311( j)( 1)( C) of the CWA. Most owners or operators of completely buried storage tanks will be exempted from part 112 under this rule because such tanks are subject to all of the technical requirements of 40 CFR part 280 or a State program approved under 40 CFR 281. Those tanks subject to 40 CFR part 280 or a State program approved under 40 CFR part 281 will follow the corrosion protection provisions of that rule, which provides comparable environmental protection. Those that remain subject to the SPCC regulation must comply with this paragraph.

The rule requires corrosion protection for completely buried metallic tanks by a method compatible with local soil conditions. Local soil conditions might include fill material. The method of such corrosion protection is a question of good engineering practice which will vary from facility to facility. You should monitor such corrosion protection for effectiveness, in order to be sure that the method of protection you choose remains protective. See §112.8( d)( 1) for a discussion of corrosion protection for buried piping.

UST standards. UST or other industry standards may satisfy SPCC requirements.

Leak testing. The current SPCC rule contains a provision calling for the "regular pressure testing" of buried metallic storage tanks. 40 CFR 112. 7( e)( 2)( iv). We 240 proposed in 1991 a recommendation that such buried tanks be subject to regular "leak testing." Proposed §112.8( c)( 4). Leak testing for purposes of this paragraph is testing to ensure liquid tightness of container and whether it may discharge oil. We specified leak testing in the proposal, instead of pressure testing, in order to be consistent with many State regulations and because the technology on such testing was rapidly evolving. 56 FR at 54623.

We are modifying the leak testing recommendation to make it a requirement. We agree with the commenter who argued that such testing should be mandatory because recommendations may not often be followed. Appropriate methods of testing should be selected based on good engineering practice. Whatever method and schedule for testing the PE selects must be described in the Plan. Testing under the standards set out in 40 CFR part 280 or a State program approved under 40 CFR part 281 is certainly acceptable (as we suggested in the proposed rule). "Regular testing" means testing in accordance with industry standards or at a frequency sufficient to prevent leaks.

XI  B( 5) Partially buried or bunkered tanks  §112.8( c)( 5)

Background: Under §112.7( e)( 2)( v) of the current rule, a partially buried metallic tank must be avoided unless the shell is coated, since damp earth can cause rapid corrosion of a buried tank, especially where air and soil contact. In 1991, we proposed in §112.8( c)( 5) to recommend against storing oil in partially buried or bunkered metallic tanks. However, if such tanks are used, we proposed to require that the owner or operator protect the buried or bunkered metallic tank from corrosion by using coatings, cathodic protection, or other methods compatible with local soil conditions.

Comments: Applicability. We should clarify that the proposed recommendation applies only to new partially buried tanks. (54)

Editorial suggestion. We could omit §112.8( c)( 5) by removing the term "partially buried tanks." (180)

Requirement v. recommendation. Recommends that we delete the first sentence of §112.8( c)( 5) because it is purely advisory. (121)

Response: Applicability. The requirement to avoid the use of such tanks, unless they are protected from corrosion, applies to all partially buried metallic tanks, installed at any time. This requirement is in the current rule and applies to tanks installed since the effective date of the rule in 1974.

Editorial suggestion. We disagree that we should remove the term "partially buried tanks" or delete §112.8( c)( 5). Such a deletion would remove partially buried tanks from the corrosion protection requirements of the rule.

Requirement v. recommendation. Due to the risk of discharge caused by corrosion, we decided to keep the current requirement to not use partially buried metallic tanks, unless 241 the buried section of such tanks are protected from corrosion. The requirement to not use such tanks, unless they are protected from corrosion, applies to all partially buried metallic tanks, installed at any time.

XI  B( 6) Integrity testing  §112.8( c)( 6)

Background: Current §112.7( e)( 2)( vi) requires an owner or operator to conduct periodic integrity testing of aboveground bulk storage tanks, taking into account tank design and using such techniques as hydrostatic testing, visual inspection, or a system of non destructive shell thickness testing. In 1991, we proposed to redesignated §112.7( e)( 2)( vi) as §112.8( c)( 6), and to require that an owner or operator of a facility with adequate secondary containment conduct integrity testing of aboveground bulk storage tanks every ten years and when there are material repairs to an aboveground tank. We also proposed to maintain the current requirement for keeping comparison records and for inspecting the tank's supports and foundations. Further, we proposed to maintain the current requirement for operating personnel to observe the outside of the tank frequently for signs of deterioration, leaks, or oil accumulation inside diked areas.

Comments: Support for proposal. "Ashland supports the agency's proposal to require integrity testing of bulk storage tanks once every ten years and when material repairs are performed." (83, 102, L35)

Opposition to proposal.

Air emissions, fatalities. The release of gas from testing would increase air emissions and the risk of fatalities. Tanks "in severe environments or service" may not have a ten year life expectancy. (67) . Cost, out of service tanks. Owners or operators would have to build replacement tanks for the 10 percent of tanks taken out of service every year for testing. (67)

Logistically difficult. Internally inspecting tanks is costly and logistically difficult. (L35)

Environmental threat. Integrity testing is unwarranted since many tanks are inspected daily, and tanks located inside buildings are less likely to pose an environmental threat than outside tanks. (71) The ten year testing requirement is costly and may not have an environmental benefit, since secondary containment contains the tank's contents if there is a failure. (90)

Residual oil. "A ten year testing cycle is simply not justified for residual oil tanks. Such relatively frequent forced outages will likely impact system reliability in the context of maintaining reserve capacity requirements if, for example, a particular generating unit is supplied from a specific fuel oil tank or an alternative fuel is unavailable. And perhaps more important, the compensating mechanism for avoiding station outages, i. e., to barge or truck in fuel in lieu of tank supplies, is 242 far more environmentally threatening. Consequently, Con Edison recommends that residual oil tanks be excluded from the testing frequency proposed in the revised section 112.8( c)( 6) or alternatively, that the testing of these tanks be tied to practical operational factors such as scheduled maintenance outages." (100, L35)

Unnecessary, hazardous waste. Integrity testing is unnecessary because "tanks that store oil have a lower rust potential" (71) and "cleaning would generate more hazardous waste" (67).

Applicability.

Airport fuel systems. "This recommendation does not mention airport fuel hydrant systems associated with above ground fuel storage facilities ...." (107)

Electrical equipment. Tank integrity testing requirement for electric equipment containing oil is burdensome and has no environmental benefit. Owners or operators would have to test such equipment while it was out of service, which is impractical. (92) "While the electric utilities generally believe that this is a reasonable proposal, we believe that two exclusions should be provided. First, ..., an exclusion should be provided for tanks used to store oils with a pour point greater than 60 degrees Fahrenheit. Such tanks pose little risk to navigable waters because the oil does not flow freely. ... A second exclusion should be provided for tanks that are capable of visible inspection on all sides and utilize secondary containment." (92, 125, L2)

Phase in.

10 years. Suggests testing be phased in over the "next ten years after enactment of the final rule." (92, 125)

UST model. "There should be a phase in period for testing of aboveground tanks subject to 112.8( c)( 6). This could be based on age of the tank and modeled after the UST program requirements for phase in of leak detection." (161)

Small facilities. We should differentiate between large and small facilities because the ten year testing requirement is inappropriate for small tanks at small facilities. (34) "GM also believes that mandatory testing of aboveground tanks every ten years at a minimum, is unnecessary for small volume tanks and at facilities that have incorporated secondary containment structures." (90) We should consider exempting tanks based on size and tanks with 100 percent containment. (191)

Suggested threshold levels. 243 Less than 2,000 gallons. We should exempt from the testing requirement, tanks contained within a building or with a maximum capacity of less than 2,000 gallons, tanks with all sides visible, and tanks and any associated piping and ancillary equipment that are visually inspected monthly. (71)

10,000 gallons or more. We should require an owner or operator to inspect aboveground tanks with a capacity of 10,000 gallons or more internally for structural soundness, tank bottom corrosion, and wall thinning. An owner or operator could conduct hydrostatic testing between ten year intervals, but not as a substitute for a thorough inspection. (111)

Type of oil stored. "The proposed amendment does not properly reflect the difference between groundwater and surface water impact potential of different petroleum products such as gasoline, # 2 fuel oil or # 6 fuel oil nor do the proposed changes differentiate or give consideration to petroleum storage facilities over groundwater deep recharge areas as opposed to those in less sensitive hydrogeologic zones." (100, L35)

Heavy oils. Re #5 and #6 fueloiltanks:" It is very expensive and timeconsuming to perform integrity tests on such tanks and because of the viscosity and pour point of these products, there is little likelihood that these products could flow and cause any substantial environmental damage." (54, L35) "In New York State, for example, the bulk storage regulations effectively exclude No. 6 fuel oil and other petroleum products for purposes of regulatory control." (100) "First, ..., an exclusion should be provided for tanks used to store oils with a pour point greater than 60 degrees Fahrenheit. Such tanks pose little risk to navigable waters because the oil does not flow freely. Moreover, the costs of cleaning and testing such tanks is extremely high because of the difficulty of removing oil from the tank." (125)

Residual oil. "A ten year testing cycle is simply not justified for residual oil tanks. Such relatively frequent forced outages will likely impact system reliability in the context of maintaining reserve capacity requirements if, for example, a particular generating unit is supplied from a specific fuel oil tank or an alternative fuel is unavailable." (100)

Clarification. "` Integrity testing' is not defined." (70)

Frequency of testing.

Construction material or usage. "The requirement of testing every ten years does not take into account construction materials, usage, or many other factors. It is suggested that more flexibility is warranted to address particular cases." (L30)

Industry standards. "Also, the integrity test interval of 10 years for tanks with containment seems to conflict with API guidance recommending ultrasound thickness measurements within 5 years after commissioning new tanks and at 5 244 year intervals for existing tanks where the corrosion rate is not know." (16) "API suggests that adherence to accepted industry operating and inspection standards should also e accepted in place of the proposed 10 year integrity testing interval. In some cases industry standards provide more specificity, and in others, more stringent requirements that the proposed wording." (67)

More frequent. The proposed rule "contains too long a period between AST integrity tests (10 years). EPA should develop an AST integrity testing schedule that provides for more frequent testing for older tanks with bottoms made of corrosive material." (44, 88)

More limited. We should limit the required integrity testing frequency. (71)

Material repairs. "However, to help clarify what constitute material repairs, §112.8( c)( 6) should be revised to indicate that such testing must be performed when the repairs involve the installation of a 12 inch or larger nozzle in the shell, a new steel bottom, a door sheet, tombstone replacement in the shell, or other similar repairs that could materially increase the potential for oil to be discharged from the tank." (83, 102)

Method of testing.

Other techniques. Between hydrostatic testing, we should allow owners or operators to use other inspection techniques while the tanks are in service. This approach would permit owners or operators to schedule tank outages while supporting supply and demand obligations. (25)

Rule list. "Guidelines or recommendations for inspections and testing procedures should be set forth here." (27) "Unless you are prepared to state what type of `integrity testing' is acceptable to EPA, and to what standards, this paragraph should be deleted." (121)

Visual inspection.

Internal and external. "The seriousness of certain conditions such as tank bottom settlement, bottom corrosion, or poor condition of roof supports may not be identified by this type of `integrity testing'. EPA should consider requiring that integrity testing procedures be complemented with a formal internal visual inspection when the tank is not in service." (16) "It should be clarified if the extent of a visual inspection would be expected to be both inside and out (that is, product and vapors removed)." (76)

Visual inspections adequate. "We support the need to review the integrity of tanks. We are not in favor of pressure testing and would be concerned with the amount of pressure applied. ... Visual inspection is much more economical and will be used as often as twice yearly where possible. Remote sites would be inspected at least yearly, with full time electronic monitoring used when possible." 245 (37) "A second exclusion should be provided for tanks that are capable of visible inspection on all sides and utilize secondary containment. In such a case, where the tank bottom as well as the sides can be adequately inspected, integrity testing is not necessary to maintain the safety of the tanks." (125) "The Company feels that visually inspecting aboveground tanks fully meets the intent of the testing requirement. During the aforementioned UST rulemaking in 1988, EPA totally exempted USTs which were in basements or vaults if the USTs were totally inspectable for leaks. EPA recognized that these tanks, although they were subterranean, did not require upgrading, release detection, etc., based upon the simple fact that they were inspectable and this was a reliable means of detecting leakage." (164)

Response: Support for proposal. We appreciate commenter support.

Applicability. Integrity testing is essential for all aboveground containers to help prevent discharges. Testing will show whether corrosion has reached a point where repairs or replacement of the container is needed. Prevention of discharges is preferable to cleaning them up afterwards. Therefore, it must apply to large and small containers, containers on and off the ground wherever located, and to containers storing any type of oil. From all of these containers there exists the possibility of discharge.

Air emissions, fatalities. An owner or operator who follows good engineering practice will minimize the possibility of air emissions or fatalities. In any event, an owner or operator must comply with applicable State and Federal clean air and safety requirements.

Ancillary equipment. We agree that integrity testing should include ancillary equipment in some circumstances, and require integrity and leak testing on a periodic basis for valves and piping when a facility lacks secondary containment. 40 CFR 112.7( d). Even with secondary containment, an owner or operator must examine all aboveground valves, piping, and appurtenances regularly to assess the general condition of certain items. 40 CFR 112.8( d)( 4). In addition, an owner or operator must conduct integrity and leak testing of buried piping at the time of installation, modification, construction, relocation, or replacement. 40 CFR 112.8( d)( 4)

Electrical equipment. Because electrical, operating, manufacturing equipment are not bulk storage containers, the requirement is inapplicable to those devices or equipment. 56 FR 54623. See also the definition of bulk storage container in §112.2. Furthermore, as noted by commenters, methods may not exist for integrity testing of such devices or equipment.

Hazardous waste. While it is possible that cleaning might generate more hazardous waste, that is not a reason to avoid integrity testing. The purpose of the testing is to prevent container failure leading to a discharge as described in §112.1( b). 246 Phase in. We disagree that there should be a phase in of the requirement because it is already in effect.

Rust. A container with any potential to rust may fail and discharge oil. Further, rust is not the only possible failure factor. For example, integrity testing may reveal an improper weld or inadequate shell thickness before the defect causes a container to fail.

Secondary containment. We disagree that secondary containment for the entire content of a container mitigates the need for integrity testing. Such testing helps prevent the discharge in the first place. Furthermore, oil may escape secondary containment and reach the environment.

Business records. You may use usual and customary business records, at your option, for purposes of integrity testing recordkeeping. Specifically, you may use records maintained under API Standards 653 and 2610 for purposes of this section, if you choose. Other usual and customary business records either existing or to be developed in the future may also suffice. Or, you may elect to keep separate records for SPCC purposes. This section requires you to keep comparison records. Section 112.7( e) requires retention of these records for three years. You should note, however, that certain industry standards (for example, API Standards 570 and 653) may specify that an owner or operator to maintain records for longer than three years.

Frequency of testing, industry standards, 10 year integrity testing. Integrity testing is a necessary component of any good prevention plan. A number of commenters supported a requirement for such testing. It will help to prevent discharges by testing the strength and imperviousness of the container. We agree with commenters that testing according to industry standards is preferable, and thus will maintain the current standard of regularly scheduled testing instead of prescribing a particular period for testing. Industry standards may at times be more specific and more stringent than our proposed rule. For example, API Standard 653 provides specific criteria for internal inspection frequencies based on the calculated corrosion rate, rather than an arbitrary time period. API Standard 653 allows the aboveground storage tank (AST) owner or operator the flexibility to implement a number of options to identify and prevent problems which ultimately lead to a loss of tank integrity. It establishes a minimum and maximum interval between internal inspections. It requires an internal AST inspection when the estimated corrosion rate indicates the bottom will have corroded to 0.1 inches. Certain prevention measures taken to prevent a discharge from the tank bottom may affect this action level (thickness). Once this point has been reached, the owner or operator has to make a decision, depending on the future service and operating environment of the tank, to either replace the whole tank, line the bottom, add cathodic protection, replace the tank bottom with a new bottom, add a release prevention barrier, or some combination of the above.

Another benefit from the use of industry standards is that they specify when and where specific tests may and may not be used. For example, API Standard 653 is very specific 247 as to when radiographic tests may be used and when a full hydrostatic test is required after shell repairs. Depending on shell material toughness and thickness a full hydrotest is required for certain shell repairs. Allowing a visual inspection in these cases risks a tank failure similar to the 1988 Floreffe, Pennsylvania event. Testing on a "regular schedule" means testing per industry standards or at a frequency sufficient to prevent discharges. Whatever schedule the PE selects must be documented in the Plan.

Integrity testing. "Integrity testing" is any means to measure the strength (structural soundness) of the container shell, bottom, and/ or floor to contain oil and may include leak testing to determine whether the container will discharge oil. It includes, but is not limited to, testing foundations and supports of containers. Its scope includes both the inside and outside of the container. It also includes frequent observation of the outside of the container for signs of deterioration, leaks, or accumulation of oil inside diked areas.

Material repairs. The rationale for testing at the time material repairs are conducted is that such repairs could materially increase the potential for oil to be discharged from the tank. Examples of such repairs include removing or replacing the annular plate ring; replacement of the container bottom; jacking of a container shell; installation of a 12 inch or larger nozzle in the shell; a door sheet, tombstone replacement in the shell, or other shell repair; or, such repairs that might materially change the potential for oil to be discharged from the container.

Method of testing. The rule requires visual testing in conjunction with another method of testing, because visual testing alone is normally insufficient to measure the integrity of a container. Visual testing alone might not detect problems which could lead to container failure. For example, studies of the 1988 Ashland oil spill suggest that the tank collapse resulted from a brittle fracture in the shell of the tank. Adequate fracture toughness of the base metal of existing tanks is an important consideration in discharge prevention, especially in cold weather. Although no definitive non destructive test exists for testing fracture toughness, had the tank been evaluated for brittle fracture, for example under API standard 653, and had the evaluation shown that the tank was at risk for brittle fracture, the owner or operator could have taken measures to repair or modify the tank's operation to prevent failure.

List of procedures. We disagree that we should state in the rule  not the preamble  what integrity testing procedures we consider adequate. We list examples in the rule of possible types of testing, but those are merely examples. While we suggest testing according to industry standards, we realize those standards will not be appropriate for every facility. Where industry standards are inappropriate for a particular facility, the Professional Engineer must devise a standard of testing that is appropriate. We note, however, that a visual inspection must be combined with some other technique.

Pressure testing. We note that we do not require pressure testing. 248 Routine inspections. We disagree that a routine inspection suffices for an integrity test. A routine inspection may be visual and may not test the tank sufficiently to meet the §112.8( c)( 6) integrity testing requirement. We also disagree that we should require integrity testing only when the inspector thinks there is a risk of discharge because such a standard is entirely subjective.

Visual inspection. For certain smaller shop built containers in which internal corrosion poses minimal risk of failure; which are inspected at least monthly; and, for which all sides are visible (i. e., the container has no contact with the ground), visual inspection alone might suffice, subject to good engineering practice. In such case the owner or operator must explain in the Plan why visual integrity testing alone is sufficient, and provide equivalent environmental protection. 40 CFR 112.7( a)( 2). However, containers which are in contact with the ground must be evaluated for integrity in accordance with industry standards and good engineering practice.

Internal and external. A visual inspection may be either solely external, or external and internal. The rule requires visual testing in conjunction with another method of testing, because visual testing alone is normally insufficient to measure the integrity of a container. Visual testing alone might not detect problems which could lead to container failure.

XI  B( 7) Leakage  internal heating coils  §112.8( c)( 7)

Background: In 1991, we proposed to redesignate §112.7( e)( 2)( vii) of the current rule as §112.8( c)( 7). The proposal would require the prevention of leakage through defective internal heating coils. In 1991, we also proposed a new recommendation that the retention systems be designed to hold the contents of an entire tank, be of sufficient size to contain a spill that may occur when the system is not being monitored or observed, or have fail safe oil leakage detectors.

Comments: External heating system recommendation. "It would seem that the cost to install insulation, upgrade boilers, and pay for the extra energy consumption would be outlandish." (76)

Internal heating coils, opposition to recommendation. "It is felt that aboveground piping can be easily inspected and maintained; and, with drainage at facilities routed to oily water separators or holding ponds, it is unnecessary to have leak proof galleys under aboveground piping. This would be redundant containment and encouraging this installation is economically unjustified." (25) "The recommendation that aboveground piping be placed into galleys that drain into the oil/ water separator is not necessary. Leaks in the aboveground piping can be mitigated through daily inspections and they are often placed within the secondary containment." (68) Instead of requiring a retention system, which would hold the entire contents of a tank, suggests, "A reasonable alternative would the installation of an oil/ water separator with a high product level indicator; or a flow stop valve which incorporates a valve that closes if a 249 liquid with a specific gravity of less than 1 is present (such as provided by Enquip of Tulsa)." (76)

Oil/ water separators. "In addition, not all facilities have oil/ water separators and the same ought not to be a requirement. ... The choice of what type of equipment and requirements an operating facility need should be left to the regulated unit and the qualified independent professional engineer." (162)

Response: Alternatives. The rule does not mandate the use of any specific separation or retention system. Any system that achieves the purpose of the rule is acceptable. That purpose is to prevent discharges as described in §112. 1( b) by controlling leakage.

Proposed recommendation. We deleted the proposed recommendation from the rule because we do not wish to confuse the regulated public as to what is mandatory and what is discretionary. We have included only requirements in the rule.

XI  B( 8) Good engineering practice  alarm systems  §112.8( c)( 8)

Background: In 1991, we proposed to redesignate §112.7( e)( 2)( viii) of the current rule as §112.8( c)( 8). The provision pertains to engineering requirements formerly labeled "fail safe."

Comments: Support for proposal. Supports proposed list of devices that we consider to be "fail safe" engineering. (143)

Terminology. Objects to the term "fail safe" engineering because nothing is ever failsafe Suggests using term "in accordance with good engineering practice" or "consistent with accepted industry practices" instead. (54, 92)

Applicability. "GM recommends that installation of fail safe equipment be required for storage tanks of volume greater than 100,000 gallons, and/ or for storage tanks that were the cause of a reportable spill within the past three years." (90) "If fail safe devices are appropriate for specific large tanks, the requirement should be phased in over a period of 2 to 5 years." (116)

Alternatives.

Procedures. Supports use of "procedures" as well as "devices" as good engineering practice measures. (54) Tanks filled "with an operator present should not require such devices." (116)

UST rules. "With respect to overfill requirements, existing Underground Storage Tank (UST) regulations ... merely require a five (5) gallon overfill bucket  a standard feature for vaulted tanks. Overfill requirements, as contemplated by the proposed revised regulations, should not exceed the EPA standards for USTs." (50) 250 Monitoring. "... the `fast response system' for overfill prevention does not provide the same level of protection as a high level alarm or high liquid level pump cutoff. If this alternative is to be considered further by EPA, the regulations should require that a person be present to monitor gauges and the overall filling of storage tanks." (111)

Response: Support for proposal. We appreciate commenter support.

Terminology. We agree with the commenter that "fail safe" engineering is inappropriate and have substituted "in accordance with good engineering practice." The change in terminology does not imply any substantive change in the level of environmental protection required, it is merely editorial.

Applicability. Alarm system devices are necessary for all facilities, large or small, to prevent discharges. Such systems alert the owner or operator to potential container overfills, which are a common cause of discharges. Because this is a requirement in the current rule, no phase in is necessary.

Alternatives. Under the deviation provision at §112.7( a)( 2), you may substitute "procedures" or other measures that provide equivalent environmental protection as any of the alarm systems mandated in the rule if you can explain your reasons for nonconformance. Such procedures might include conformance to UST rules if you can show that such conformance provides equivalent environmental protection to the SPCC requirement.

Monitoring. We agree with the commenter that a person must be present to monitor a fast response system to prevent overfills and have amended the rule accordingly. We disagree that the requirement for alarm devices should not apply when a person is present, because human error, negligence, on inattention may still occur in those cases, necessitating some kind of alarm device.

XI  B( 9) Removal of accumulated oil within 72 hours  §112.8( c)( 10)

Background: Section 112.7( e)( 2)( x) of the current rule requires an owner or operator of an onshore bulk storage facility to promptly correct visible oil leaks that result in a loss of oil from tank seams, gaskets, rivets, and bolts sufficiently large enough to cause the accumulation of oil in diked areas. In 1991, we reproposed this requirement in redesignated §112.8( c)( 10). We also proposed to require that an owner or operator completely remove accumulated oil or oil contaminated materials within 72 hours from the time the discharge occurred. We noted that this time frame was consistent with the requirement for diked areas in proposed §112.7( c), where we proposed to require that the entire containment system be impervious to oil for 72 hours.

Comments: Bioremediation. "... the 72 hour requirement would effectively limit the choice of cleanup technologies to those that emphasize speed. This would preclude the use of other proven technologies, such as in situ bioremediation, which cannot be completed in a 72 hour period." (42, 48, 67, 91, 99, 102, 133, 175, 187). 251 "Bioremediation techniques and other measures which may be used under existing laws are less expensive and create less waste than removal procedures. No materials are transported, which eliminates the risks inherent in hauling the `contaminated' dirt. In short, fixing the problem `on the spot' is often very good advice." (42)

72 hour cleanup standard.

Support for proposal. "As noted in the preamble, such containment would have to be impervious to spilled product for 72 hours." (L17)

Opposition to proposal. We should delete the requirement or change it to a recommendation. (72)

Expensive. "To require total cleanup of spilled oil and material within 72 hours in all cases would be impractical, costly, and impossible in some cases." (22, 37, 72, 90, 99, 170, 187) The 72 hour requirement is excessive and unnecessary because spill response procedures are described in the SPCC Plan. (25) The requirement would be particularly costly for remote facilities. (37)

Health or safety hazard. "Depending on site conditions," 72 hour cleanup "could jeopardize worker safety and health." (48, 67, 91, 102, 170, 175, 187)

Impractical or impossible. "To require total cleanup of spilled oil and material within 72 hours in all cases would be impractical, costly, and impossible in some cases." (22, 48, 57, 72, 83, 92, 98, 102, 107, 125, 143, 153, 170, 175, 184, 189, L2) Removal within 72 hours from the time of the spill would be difficult for unattended facilities. (72) Texas allows on site soil remediation or treatment. (99) "Frequently it is not technically feasible to remove contaminated soil due to structural concerns or volume considerations. State regulations often will not allow for treatment methods which are commonly employed until a permit has been issued, requiring considerably more time than 72 hours." (153) "The Company agrees that `accumulated oil' (i. e., free product) be cleaned out of a containment structure, however, `oil contaminated materials' should not be a concern. This could be construed to mean the walls and floor of a clay dike used for containment." (125,164)

Land disposal problems. "Also, to dispose of a waste sometimes takes as much as two months while waste samples are laboratory tested, arrangements are made with a disposal facility, and State approval is obtained to ship the wastes off site. In many cases, the ideal location to hold the waste until shipment offsite is within the secondary containment area of the tank which experienced the spill." (92, 125) "To disallow any other method than complete removal of oil contaminated soil from diked areas in these circumstances serves no useful purpose. Moreover, it compounds landfill disposal capacity problems and diverts funds that could be more effectively used to address other more pressing environmental problems." (99, 187) 252 Low risk, historic spills. "More importantly, at older facilities there may be historically contaminated soil from past spills within diked areas. These soils pose no threat of `escape to surface waters. The requirement to clean up in these instances would be prohibitively expensive and would yield no benefit." (72, 164)

Small spills. "... API believes clarification is needed with regard to cleanup of small discharges as opposed to larger discharges within the proposed 72 hour cleanup period." (67, 77, 91, 175, 187, L20)

Unnecessary. It is unnecessary to remove all spilled oil within 72 hours if the containment system is designed to be impervious to oil for a longer period of time. (57) Since regulated facilities have secondary containment, discharged oil and oil contaminated materials would be contained. Therefore, the 72 hour requirement is unnecessary. (107, 189)

Prevention  plastic film. Covering soil with plastic film may be an acceptable method to prevent stormwater contamination during remediation. (99)

Terms to clarify.

Accumulated oil, oil contaminated materials. We should clarify the terms accumulated oil and oil contaminated materials. (57, 62, 125, 153) Asks for clarification of accumulated oil, because a slow leak or drip may result in the accumulation of a small puddle of oil in a large containment area with limited access. In this situation, the risk to employees may be greater than the risk to the environment. (62)

Completely removed. We should clarify the term completely removed. (57)

Spill event. Our reference to a spill event in §112.8( c)( 10) is inconsistent with the definition in §112.2( s). (29)

Time calculations. "API notes that the time the spill occurred will not always be known. Therefore, any such requirement should be based on the time the spill is first discovered." (67, 72, 91, 92, 102, 153, 164, 175)

Clarification needed. Questions how 72 hour period will be calculated. (67, 79, 82, 85, 91, 92, 95, 102, 153, 164, 175)

Time cleanup alternatives.

Immediately. "Accumulated oil should be cleaned up immediately, and not within the 72 hours proposed." (27) 253 72 hours after observation. "GM recommends that accumulated oil of sufficient volume, i. e., greater than 50 gallons, in containment structures should be removed expediently but no longer than 72 hours after observation." (90, 153)

As soon as possible. We should require that the owner or operator complete clean up operations as soon as "possible" or "practicable," or "after the spill is discovered." ( 48, 67, 83, 91, 102, 133, 143)

Expeditiously. (48, 67, 85, 91, 95, 102, 117, 133, 143)

Initiation within 72 hours. We should amend the proposed requirement to state that clean up efforts must begin within 72 hours or within a period of time sufficient to permit the clean up of oil before the containment system begins to leak. (57) "As suggested above, this requirement should be changed to allow that within 72 hours and/ or as soon as feasible a spill will be responded to and cleanup initiated in order to ensure that navigable waters are not impacted." (66, 98, 125, 170, 184,189, L2, L20) We should require the "prompt removal of precipitation from containment areas" within 72 hours. We should require treatment of the accumulated precipitation from the containment areas, if necessary, within 72 hours after the precipitation had ended. (80)

So as to prevent further environmental impact. "EPA should clarify this requirement to state that `accumulated spills should be sufficiently removed within 72 hours so as to prevent further environmental impact." (107)

More than 72 hours. "If the spilled oil is contained or controlled or is being remediated, then there should be additional time given for the response measures in process, especially if there are difficulties encountered in the cleanup." (22) "Nor is it necessary to remove all spilled oil within seventy two hours if the containment system is designed to be impervious to oil for a much longer period of time." (57, 66, 98, 125, 170, 184, 189, L2)

96 hours. "A 96 hour time frame would still meet the general intent of the rule buy allowing unattended weekend operation, but still provide adequate response time once the event is discovered without putting the facility in jeopardy of not complying with the regulations." (87)

144 hours, at least. "Alyeska recommends that EPA at least double this time requirement." (77)

Response: Support for proposal. We appreciate commenter support.

Applicability. The requirement to clean up accumulations of oil is applicable to all facilities, large and small. The size of the accumulation is irrelevant, as any accumulation may migrate to navigable waters or adjoining shorelines. The damage to the environment may be the same, depending on the amount discharged. 254 72 hour cleanup standard. We have deleted the proposed 72 hour cleanup standard because it would preclude bioremediation. We also agree that under certain circumstances, such a time limit might jeopardize worker safety and health. Therefore, we have maintained the current standard that visible discharges must be promptly removed. Prompt removal means beginning the clean up immediately after discovery of the discharge, or immediately after taking any action to prevent fire and explosion or other threats to worker health and safety. However, actions to prevent threats of fire or explosions may not be used to unreasonably delay such efforts. The size of the accumulation is irrelevant, as any accumulation may migrate to navigable waters or adjoining shorelines.

Extent of and methods of cleanup. No matter what method of clean up method you use, you must completely remove the accumulated oil. Any effective method that complies with all other applicable laws and regulations is acceptable. Bioremediation may be one acceptable method of clean up. Acceptable methods will depend on the weather, other environmental conditions, and good engineering practice. If the clean up method chosen undermines the stability of a dike, the owner or operator must repair the dike to its previous condition.

Prevention  plastic film. We support all efforts to prevent contamination of navigable waters. An owner or operator may choose to spread plastic film over the diked area to prevent stormwater contamination, or use some other acceptable method. However, the owner or operator must dispose of the film properly if he chooses that method.

Terms to clarify.

Accumulated oil, oil contaminated materials. An "accumulation of oil" means a discharge that causes a film or sheen or a sludge or emulsion in a diked area. See 40 CFR 110.3( b). The term "oil contaminated materials" is not used in the final rule, because oil must accumulate on something such as materials or soil. Therefore, the term is redundant. Instead, in the final rule we use the term "accumulation of oil", which includes anything on which the oil gathers or amasses within the diked area. Such accumulation may include oil contaminated soil or any other oil contaminated material within the diked area that impairs (i. e., decreases the capacity of) the secondary containment system.

Completely removed. We no longer use the term "completely removed" in §112.8( c)( 10). The requirement to remove any accumulation of oil means cleanup of all such accumulations.

Spill event. We have removed the term "spill event" from the proposed paragraph and note that we agree with the commenter who noted that the reference to a "spill event," or a "discharge as described in §112.1( b)," within a diked area is inconsistent with that concept.

XI  B( 10) Mobile and portable containers  §112.8( c)( 11) 255 Background: Under §112.7( e)( 2)( xi) of the current rule, an owner or operator must locate mobile or portable containers so as to prevent spilled oil from reaching navigable waters. He must provide secondary containment for the largest single compartment or tank. He must locate his facility where it will not be subject to periodic flooding or washout. In 1991, we proposed to designate §112.7( e)( 2)( xi) of the current rule as §112.8( c)( 11), and to change the requirement for secondary containment to a recommendation. We also proposed to recommend, not require, that an owner or operator locate a mobile or portable oil storage container in an area not subject to periodic flooding or washout.

Comments: Floods. "... portable tanks are not the only tanks which should be kept out of the flood plain. The recommendation should be extended to all new equipment." ( 111)

Requirement or recommendation. "Tanks should be required to be located in areas not subject to flooding." (27) We should amend the rule to require locating mobile or portable containers to "prevent discharges from entering navigable waters." (67)

Secondary containment  requirement or recommendation.

Recommendation. We should place the secondary containment recommendation in another document. (121) "Secondary containment for mobile or portable tanks should be left as a recommendation. In addition, some basic security procedures and a contingency plan may be adequate for spill prevention and control from mobile and portable tanks. Further investigation into the spill history from these types of tanks should be conducted to assess the environmental threat from such tanks." (190)

Time limits. "Mobile and portable tanks should be defined more clearly. Ohio EPA recommends defining such a tank as one which is in place on a contiguous property for 10 days or less." (27)

Response: Floods. We deleted the proposed recommendation on siting of mobile containers in this rule because we do not wish to confuse the regulated public over what is mandatory and what is discretionary. These rules contain only mandatory requirements.

Requirement or recommendation. We agree that the purpose of the rule is to prevent discharges from becoming discharges as described in §112.1( b). Therefore, in response to comment, we have modified the proposed rule to require positioning or locating mobile or portable containers to prevent "a discharge as described in §112.1( b)," rather than "oil discharges." "A discharge as described in §112.1( b)" is a more inclusive term, tracking the expanded scope of the amended CWA.

Secondary containment. In response to comments, we have maintained the secondary containment requirement in the current rule because secondary containment is 256 necessary for mobile containers for the same reason that it is necessary for fixed containers; to prevent discharges from becoming discharges as described in §112.1( b). Secondary containment must also be designed so that there is ample freeboard for anticipated precipitation. We have therefore amended the rule on the suggestion of a commenter to provide for freeboard. We agree with the commenter that the amount of freeboard should be sufficient to contain a 25 year storm event, but are not adopting that standard because of the difficulty and expense for some facilities in securing recent information concerning 25 year, 24 hour storm events at this time. Should that situation change, we will reconsider proposing such a standard in rule text. Freeboard sufficient to contain precipitation is freeboard according to industry standards, or in an amount that will avert a discharge as described in §112.1( b). Should secondary containment not be practicable, you may be able to deviate from the requirement under §112.7( d).

We clarify that the secondary containment requirement relates to the capacity of the largest single compartment or container. Permanently manifolded tanks are tanks that are designed, installed, or operated in such a manner that the multiple containers function as a single storage unit. Containers that are permanently manifolded together may count as the "largest single compartment," as referenced in the rule.

Time limits. We decline to place a time limitation in a definition of mobile or portable containers. Mobile or portable containers may be in place for more than ten days and still be mobile. Mobile containers that are in place for less than 10 days may still experience a discharge as described in §112.1( b).

XI  C: Facility transfer operations, pumping, and facility process  §112.8( d)

XI  C( 1) Buried piping  protective coatings and cathodic protection

112.8( d)( 1)

Background: Section 112.7( e)( 3)( i) of the current rule requires an owner or operator to cathodically protect and provide protective wrapping and coating on all buried piping installations if soil conditions warrant. In 1991, we proposed to redesignate §112.7( e)( 3)( i) as §112.8( d)( 1). In that proposal we recommended that an owner or operator place all piping installations aboveground, where possible. We also proposed to require that an owner or operator cathodically protect and provide protective wrapping and coating on new or replaced buried piping, with an alternative option to comply with other corrosion protection standards for buried piping in 40 CFR part 280, the underground storage tank (UST) regulation.

We proposed to continue to require that an owner or operator carefully inspect buried pipeline for deterioration if a pipeline section is exposed for any reason. We proposed that if an owner or operator finds corrosion damage, he must inspect the damage and take corrective action as indicated by the magnitude of damage.

Finally, in the preamble, we encouraged owners or operators to place piping installations in leak proof galleys that feed into the facility's oil/ water separator. We 257 also proposed to recommend that buried piping installations comply to the extent applicable with all of the relevant part 280 provisions.

Comments: Aboveground piping recommendation.

Support for recommendation.

All piping. Owners or operators should place all piping aboveground to help detect piping system problems before there is a discharge. (L1)

New piping. We should revise §112.8( d)( 1) to recommend that owners or operators place all new piping aboveground, where appropriate. It would be "onerous, costly, and not necessarily protective of navigable waters" to move all existing buried lines aboveground. (67)

Editorial suggestion. "The first sentence in proposed 40 CFR 112.8( d)( 1) should be properly reworded (i. e., remove `shall' to read, `It is recommended that all piping be placed aboveground, where possible." (79, 102)

Opposition to recommendation. The recommendation is "a clear safety problem if followed as recommended by the agency. ... Above ground installations do not provide the requisite degree of worker safety, because of the tripping hazard, that Delhi seeks to attain." (34)

Buried piping recommendation  part 280.

Support for requirement. The rule should "require – rather than recommend, that buried piping comply with the corrosion protection provisions of 40 CFR part 280." (44, 121)

Recommendations not followed. "Also, practices for integrity testing and for installation of pipes pursuant to 40 CFR 280 should be changed from `recommended' practices to `required' practices. Our experience is that recommendations without standards are not usually followed." (111)

Corrosion protection.

Support for proposal. Applying protective coating and cathodic protection on buried piping provides sufficient leak protection. (34) We cannot enforce the current requirement for protecting buried piping installations "if soil conditions warrant." (121) "MDE strongly supports amendments to" §112.8( d)( 1). (135, L17)

Opposition to proposal. 258 Coating only. "New and replacement piping should include protective coating. Cathodic protection should be required only when soil conditions require it. Tests to determine the need for cathodic protection are very specific and should be used to identify those locations requiring the protection." (114)

Ineffective. "Protective coating and cathodic protection will not prevent a discharge of oil to the environment in the event of a pipe fracture, nor will such protection be able to detect a leak if one occurs. The practice of using double walled pipe or secondary containment and product sensitivity leak detection for new installations is currently required by NJDEPE." (147)

Keep current rule. An owner or operator should protect new buried piping "where soil conditions support the operation of a corrosion system and where there is a history of external buried piping corrosion that can be controlled by corrosion protection." (67, 85, 114, 143)

Repairs. "EPA should clarify that only the section of the line undergoing repair must be retrofitted with this corrosion protection." It would be very costly to retrofit the entire line. (83, 88, 102)

Coating only on replaced sections. "Placing cathodic protection on sections of replaced piping is unwieldy and not technically feasible because the cathodic protection requires considerable maintenance. Bethlehem endorses the use of cathodic protection when an entire pipeline is replaced and protective wrapping on all replaced sections of pipe." (88)

Leak proof galleys. Our recommendation for owners or operators to install leak proof galleys under aboveground piping is redundant and economically unjustifiable, because owners or operators easily can inspect and maintain aboveground piping, and because aboveground piping is often placed within secondary containment that drains to oil/ water separators. (25, 68)

Response: Support for proposal. We appreciate commenter support.

Aboveground piping recommendation. While we have deleted the proposed recommendation from the rule text because we do not wish to confuse the regulated public over what is mandatory and what is discretionary, we still believe that piping should be placed aboveground whenever possible because such placement makes it easier to detect discharges. The decision to place piping aboveground might include consideration of safety and traffic factors.

Buried piping recommendation  part 280. We have deleted the recommendation from the proposed rule that all buried piping installations comply to the extent practicable with 40 CFR part 280, because we are excluding recommendations from this rule to avoid confusion with what is mandatory and what is discretionary. Also, some buried piping 259 now subject to part 112 will be subject only to 40 CFR part 280 or a State program approved under 40 CFR part 281 under this rule. See §112.1( d)( 4).

Corrosion protection. Based on EPA experience, we believe that all soil conditions warrant protection of new and replaced buried piping. EPA's cause of release study indicates that the operational piping portion of an underground storage tank system is twice as likely as the tank portion to be the source of a discharge. Piping failures are caused equally by poor workmanship and corrosion. Metal areas made active by threading have a high propensity to corrode if not coated and cathodically protected. See 53 FR 37082, 37127, September 23, 1988; and "Causes of Release from US Systems," September 1987, EPA 510 R 92 702. If you decide to deviate from the requirement, for example, to provide an alternate means of protection other than coating or cathodic protection, you may do so, but must explain your reasons for nonconformance, and demonstrate that you are providing equivalent environmental protection. A deviation which seeks to avoid coating or cathodic protection, or some alternate means of buried piping protection, on the grounds that the soil is somehow incompatible with such measure( s), will not be acceptable to EPA.

A "new" or "replaced" buried piping installation is one that is installed 30 days or more after the date of publication of this rule in the Federal Register. We have deleted the words "new" and "replaced" from the proposed language and substituted this specific date so the effective date is clearer to the regulated community. Under the current rule, you have an obligation to provide buried piping installations with protective wrapping and coating only if soil conditions warrant such measures. Under the revised rule, you must provide such wrapping and coating for new or replaced buried piping installations regardless of soil conditions.

You should consult a corrosion professional before design, installation, or repair of any corrosion protection system. Any corrosion protection you provide should be installed according to relevant industry standards. When piping is replaced, you must protect from corrosion only the replaced section, although protection of the entire line whenever possible is preferable. Equipping only a small portion of piping with corrosion protection may accelerate corrosion rates on connected unprotected piping. While we agree that corrosion protection might not prevent all discharges from buried piping, it is an important measure because it will help to prevent most discharges.

We disagree that we should require only protective coating and not cathodic protection. Protective coating and wrapping and cathodic protection provide the maximum feasible leak prevention technology.

We note that no strategy can prevent all discharges from buried piping, but corrosion protection and coating will help prevent most discharges.

Double walled piping. Double walled piping or secondary containment or sensitive leak detection for buried piping may be acceptable as a deviation from the requirements of this paragraph under §112.7( a)( 2) if you explain your reasons for nonconformance with 260 the requirement and show that the means you selected provides equivalent environmental protection to the requirement. However, we will not require such measures because we did not propose them.

Leak proof galleys. We have not included such a recommendation in the final rule, because all final rule provisions are mandatory.

XI  C( 2) Terminal connections  §112.8( d)( 2)

Background: Section 112.7( e)( 3)( ii) of the current rule requires an owner or operator to cap or blank flange an oil pipeline terminal connection when it is not in service or is in standby service for an extended time. In 1991, we proposed to redesignate §112.7( e)( 3)( ii) as §112.8( d)( 2), and to clarify that "an extended time" is "six months or more."

Comments: Support for proposal. "Consistency for determining when loading/ unloading connections must be securely capped or blank flanged will be promoted by specifying what constitutes `an extended time', and NJDEPE supports the specified time period of six months." (147)

Opposition to proposal. The rule should be rewritten as follows: "When piping is not in service or is not in standby service...." "Typically piping that is in standby service is only needed in emergency situations or when there is an operational problem. ... It is not appropriate for this requirement to apply to standby piping, especially if the piping must be put into service quickly during an emergency to insure the safe operation of the facility." (67, 102)

Response: We appreciate commenter support. We have decided to keep the current standard of requiring capping or blank flanging terminal connections when such piping is not in service or is in standby for an extended time in order to maintain flexibility for variable facilities and engineering conditions. We define "an extended time" in reference to industry standards or at a frequency sufficient to prevent discharges. We disagree with commenters that the requirement should not apply to piping that is not in standby service because some discharges may be caused by loading or unloading oil through the wrong piping or turning the wrong valve when the piping in question was actually out of service. Typically, piping that is in standby service is only needed in emergency situations or when there is an operational problem. In the rare situations when such piping is needed immediately, the owner or operator may remove the cap or blank flange to return the piping to service.

XI  C( 3) Aboveground valves and piping; buried piping  §112.8( d)( 4).

XI  C( 3) 1 Inspection of aboveground valves, piping, and appurtenances Background: Under §112.7( e)( 3)( iv) of the current rule (redesignated in the final rule as §112.8( d)( 4)), an owner or operator must regularly inspect all aboveground valves 261 and pipelines. Operating personnel must assess the general conditions of items, such as flange joints, expansion joints, valve glands and bodies, catch pans, pipeline supports, locked valves, and metal surfaces. In 1991, we proposed that examinations of aboveground valves and piping must be monthly, and must include appurtenances.

In 1991, we recommended in §112.8( d)( 4) that all valves, pipes, and appurtenances conform to relevant industry codes, such as ASME standards.

Comments: Applicability.

Electrical equipment. "This requirement would impose an extremely heavy burden on the electric utility industry if maintained in the final rule. The utility industry has millions of pieces of equipment in tens of thousands of facilities that could be subject to the SPCC requirements, some in remote areas. It would be extremely time consuming and expensive to require that each of these be inspected monthly." (125)

Large facilities. We should exempt from the monthly examination requirement, piping systems associated with large tanks with a storage capacity greater than 100,000 gallons. (90)

Buried piping recommendation.

Support for recommendation. "ACMS agrees that all buried piping should be tested as proposed." (51, 87, 107, 168)

Requirement instead. "ATA believes that such testing is reasonable and in accordance with good engineering practices. In order to provide sufficient environmental protection and to minimize industry remediation costs, such testing should be required rather than recommended. Also, it should apply to all SPCCregulated facilities, not only large facilities (greater than 42, 000 gallons) as EPA has suggested." (87, 107, 168)

Editorial suggestion. "All aboveground valves, piping and appurtenances in oil service should be visually inspected regularly, monthly or more frequently if necessary, and they shall be subject to an annual examination where possible." (143)

Industry standards recommendation. "Similarly, proposed section 112.8( d)( 4) should require, rather than recommend, that all valves, pipes, and appurtenances conform to relevant industry codes." (44) "This is also the place to require that piping and fittings be manufactured and assembled to industry codes (which need to be listed) for all construction beginning after the effective date of this part." (121)

Methods of inspection. 262 Pressure testing. "We agree that monthly visual examinations of aboveground piping may be sufficient. However, a more sophisticated method of heating should be required every three or four years, such as pressure testing." (27)

Visual examinations. We should require periodic visual examinations "in accordance with accepted industry standards." (67, 83, 91, 102)

Monthly inspection.

Support for proposal. Support for the §112.8( d)( 4) proposed requirement for monthly examinations of aboveground valves, piping, and appurtenances. (27, 91)

Large and small facilities. Our proposed monthly examination should be a requirement for large facilities, but a recommendation for small facilities. (135)

Opposition to proposal.

Costly. Monthly examinations require large facilities to commit financial and personnel resources. (77) Monthly examinations are too restrictive (155). Unjustified and expensive. (L30)

Difficult. "GM believes that all aboveground valves, piping, and appurtenances should not be subject to mandatory monthly examinations .... GM believes that the owner should be provided the flexibility to periodically examine piping systems at a necessary frequency to insure leaks and failure conditions are not occurring. Failure of aboveground piping system are unlike underground systems where corrosion is the main cause. Aboveground piping and appurtenances failure are more often caused by accidental damage or vibrational fatigue." (90)

Recommendation instead. "The Agency has not shown that this requirement is necessary to reduce any risk of discharge to navigable waters, and therefore this provision should remain as a `should' to allow for the exercise of good engineering practice." (125, 136, 143, 155, 189) "We suggest that proposed §§ 112.8( d)( 4) and (d)( 5) be recommendations instead of requirements for facilities that store more than 42, 000 gallons." (39)

Unnecessary. We should delete the §112.8( d) requirements since they are unnecessary. They are unduly onerous, since discharges emanating during transfer operations would be properly contained according to the SPCC Plan for that facility. Monthly examinations are excessive, unnecessary, and expensive. (189, L30)

Alternatives to monthly testing. 263 Every six months. "A six month examination period combined with an obligation by the operator to be alert for spills that could result from failure of pipes and appurtenances is a more reasonable and economic approach." (77)

Owner/ operator discretion. The owner or operator should determine examination frequency. (90, 155)

Quarterly. Examinations should be performed quarterly  not monthly  for exploration and production facilities. (114) "Large facilities can have thousands of valves and miles of pipe, and even visual inspections would be very time consuming and costly. Further, there is some question as to whether monthly inspections are warranted; the condition of piping and valves rarely changes significantly in one month." (175)

System examinations. We should not require monthly examinations, but should require systems examinations with sufficient frequency to assure safe and proper maintenance and operations. (184)

Clarification needed. We did not explain what the monthly aboveground examination would require. (77)

Response: Support for proposal. We appreciate commenter support.

Applicability. Inspection of aboveground valves, piping, and appurtenances must be a requirement to help prevent discharges. Such valves, piping, and appurtenances often are located outside of secondary containment systems, and often do not have double wall protection or some form of secondary containment themselves. Therefore, any discharge from such valves, piping, and appurtenances is more likely to become a discharge as described in §112.1( b). Examination of discharge reports from the Emergency Response Notification System (ERNS) show that discharges from such valves, piping, and appurtenances are much more common than catastrophic tank failure or discharges from tanks.

Electrical equipment. The requirements of this paragraph do not apply to electrical utilities and other facilities with oil filled equipment because they are not bulk storage facilities.

Exploration and production facilities. Regarding the comment that we should require inspections less frequently for exploration and production facilities, the point is moot. Section 112.8 excludes production facilities from its scope.

Large facilities. The requirement must be applicable to large and small facilities covered by this section, because of the same threat of discharge.

Editorial suggestion. We agree with a commenter that the rule applies only to "oil handling" piping and valves, not all such piping and valves, which may be unrelated 264 to oil activities. However, no change in rule text is necessary because the entire rule applies only to procedures, methods, or equipment that are involved with the storage or use of oil.

Industry standards recommendation. We deleted from rule text the recommendation that all valves, pipes, and appurtenances conform to industry standards, because we do not wish to confuse the public with discretionary items in a mandatory rule, but we endorse its substance. However, we do endorse conforming with industry standards and codes because such conformance reflects the exercise of good engineering practice.

Monthly inspection. The final rule maintains the current standard of "regular" inspections, on the suggestion of commenters who noted that at some remote sites monthly inspections are impractical, especially in harsh weather conditions. Furthermore, we agree with commenters that "regular" inspections are inspections conducted "in accordance with accepted industry standards," rather than the monthly proposed standard. You must include appurtenances in the inspection. Inspections may be either visual or by other means, including pressure testing. However, we do not require pressure testing or any other specific method. We agree that, subject to good engineering practice, pressure testing every three or four years may be warranted in addition to regular inspection of aboveground valves, piping, and appurtenances. However, we believe that regular inspection is sufficient to help prevent discharges and will not impose any additional requirements at this time.

Aboveground leaks. In response to the comment that leaks from aboveground piping are discovered more quickly than from underground storage tanks, we note that leakage may occur from any piping. An owner or operator must inspect aboveground valves, piping, and appurtenances to prevent such leakage.

Integrity testing. In response to the comment that integrity testing is impractical for piping systems associated with storage tanks designed to operate as a gravity system, we note that we did not propose testing of aboveground piping. In response to the comment that accidental damage or vibrational fatigue most often causes aboveground system failure, we note that these conditions may become apparent when the owner or operator inspects the general conditions of aboveground valves, piping, and appurtenances.

Transfer operations. In response to the comment that changes emanating during transfer operations would be properly contained according to the SPCC Plan for that facility, we think this remark is unrelated to the utility of preventive testing and remediation. Proper containment is an effective control measure for an actual discharge.

Visual inspections. Inspections may be either visual or by other means, including pressure testing. However, we do not require pressure testing or any other specific method. We think the inspection method is best left to good engineering practice. 265 XI  C( 3) 2 Integrity and leak testing of buried piping  §112.8( d)( 4)

Background: Under current rule §112.7( e)( 3)( iv), an owner or operator must conduct periodic pressure testing for piping in areas where facility drainage is such that a failure might lead to a spill event. In 1991, we proposed to redesignate §112.7( e)( 3)( iv) as §112.8( d)( 4), and to delete the periodic pressure testing requirement from the rule. Instead, we proposed to recommend annual integrity and leak testing or monthly monitoring of buried piping following the requirements of 40 CFR part 280, the Underground Storage Tank (UST) regulations. We proposed to require that an owner or operator maintain testing or monitoring records for five years.

Comments: Applicability.

Double walled tanks and piping. The configuration of a vaulted tank is unsuitable for monthly examinations we proposed. "VAST (Vaulted aboveground storage tank) technology also requires that all fittings and pipes come out of the top of the tank, which eliminates the possibility of leaking from the valves, pipes, or fittings and significantly reduces the potential for corrosion." (65) Exterior tanks and piping systems in remote locations are secondarily contained and have low level alarms connected to an attended facility. (79) "An alternative would be to allow double walled underground piping or other means of secondary containment for the pipe itself to be exempt from annual testing requirements. This type of piping is one way of addressing providing secondary containment to meet RCRA standards." (87)

Manned facilities, aboveground facilities, cathodically protected facilities. "... discretion should be applied to and exceptions from periodic buried pipe testing should be established for manned facilities, aboveground facilities, and cathodically protected facilities." (192)

Support for recommendation. "This provides for maximum flexibility in the use of good engineering practices." (39, 48, 66, 72, 95, 102, 103, 116, 150, 161, 175, 188,192, L8, L29) Alternatives.

3 years. "Oxychem recommends integrity testing be required on underground piping every three years, unless failure data supports more frequent testing." (141)

3 4 years. "However, a more sophisticated method of heating should be required every three to four years, such as pressure testing. ... Frequency may be based on aquifer use." (27)

5 years. "The testing for underground piping should be conducted once every five years. This would be consistent with the requirements for aboveground piping systems." (L2, L20) 266 Owner/ operator discretion. "Integrity testing of buried tanks, piping and valves should be discretionary in all cases. Cites pollution risk of testing. (102, 136, 155, 175)

Periodic testing. We could make part 112 more cost effective by requiring "periodic testing of existing piping under a reasonable compliance schedule" to provide additional safeguards without the risks and difficulties the proposed recommendation presented. (L35)

Regular basis. We should require testing on a regular basis. (143)

Small facilities. We should allow owners or operators of small facilities with secondary containment to use good engineering practice to determine the testing frequency. (10) We should allow small facilities the discretion to determine testing frequency, but require owners or operators of large facilities to conduct the monthly monitoring. (116, 182)

When a line is exposed. "API believes that buried piping should be inspected for corrosion and necessary remedial action whenever a section of the line is exposed." (67, 91, L30)

Opposition to recommendation.

Costly. "It would be impractical and extremely costly for small facilities to implement the recommended integrity and leak testing." (34, 66, 115) Annual testing would interfere with essential facility operations. (77) The need to monitor buried piping systems monthly is costly and a significant administrative burden. (90, 188)

Drawbacks. "There are a variety of drawbacks with performing pressure testing of piping systems more frequently than site specific conditions indicate are necessary. Pressure testing of such systems often results in the generation of waste materials and air emissions that otherwise would not have resulted." (102) "Performing annual integrity testing of pipes and valves could be detrimental to the life expectancy of the piping. When a hydrostatic integrity test is performed, the piping is often subjected to 1. 5 times its design pressure. Annual testing will very likely cause undue stress on the piping and can potentially lead to premature failure, and consequently, releases to the environment." (141, 175)

Impractical for multiple sites. "However, monthly testing is not practical at the many sites we have, especially those sites which are not accessible in the winter. Our fuel piping is contained within a secondary enclosure. If a leak occurs, the product will be contained and drained into a containment area where it will be noticed. The tank system has been designed to prevent any contamination to the environment if a failure should occur." (37, 79) 267 Inaccurate predictor. "Additionally, all the test would show is that the piping is not leaking at that particular moment. It would not be an accurate predictor of the future integrity of the line." (34, 115)

Non operational pipelines. "Similarly, the pipeline integrity testing program would be too onerous to impose on historic, non operational buried pipelines, the location of which are not know." (35 )

Other leak prevention instrumentation. "Requiring annual tests on buried piping would severely limit the facility's ability to receive feedstocks and deliver finished products. It should not be necessary for these proposed requirements taking into consideration the other leak prevention instrumentation that would sound alarms, shut off pumps, and automatically close valves to isolate sections of piping." (25)

Piping age, size. "Integrity testing of underground pipes on an annual basis appears too stringent and should be scheduled to account for the age of the facility (as is the case of UST regulations.)" We should require "testing for buried piping on a schedule related to the age and size of the system, with greater frequencies for older and larger systems." (89, 95, 102, 197, L30) (L30)

Requirement instead. "Annual integrity and leak testing of buried piping will not be conducted unless it is made a requirements." (27, 44, 51, 87, 107, 111, 168) "Additionally, given the relatively higher frequency of piping leaks compared to tank leaks, it is essential that facility owners or operators be required to conduct `annual integrity and leak testing of buried piping or monitor buried piping on a monthly basis, ..., a requirement similar to that in 40 CFR part 280." (44) We should change the proposed §112.8( d)( 4) recommendation to a requirement or delete it. (121) "Proposed 112.8( d)( 4) should be a requirement since piping often runs outside of secondary containment systems. Examination of ERNS data will reveal that spills from piping are much more common than catastrophic tank failures or leaks from tanks. Buried piping is not capable of being visually inspected on a periodic basis, and many facilities do conduct integrity or leak testing of buried piping on a regular basis." (168) "Because secondary containment would not affect underground spill pathways, annual testing should be required of all underground piping systems." (L1)

Large facilities. "We agree with the SPCC Task Force that such provisions should be made mandatory for large facilities. Buried piping which is unprotected should be inspected annually regardless of facility size." (L17)

Too restrictive. The proposed testing provision is too restrictive. (155)

Coast Guard rules. The buried piping recommendation should be consistent with U. S. Coast Guard rules for testing piping. (143) 268 Length and nature of piping. It is impractical to conduct monthly monitoring of lengthy buried piping systems. (66) "UCC believes that this should not apply to piping less than ten feet or piping which conveys limited flow annually." (190)

Methods of testing.

Guidance needed. We did not provide guidance on the types of accepted integrity testing or define what constitutes a leak rate. (66, 80)

Hydrostatic testing. Hydrostatic testing should include testing with the product and gases to achieve the required pressure. (143)

Part 280. Part 280 test methods and monitoring techniques do not apply to all buried piping systems, such as large diameter piping, booster pumps, and valves and connections. (66) "Alyeska also is confused by the preamble's statement that integrity and leak testing follow 40 CFR part 280. However, there is no mention of 40 CFR part 280 in the proposed rule for integrity and leak testing." (77)

Visual or hydrostatic testing adequate. "A more reasonable requirement would be to require annual integrity testing of buried piping. Further, a requirement that such testing be anything other than visual or hydrostatic is financially burdensome, and also costly in terms of manpower." (188, L18, L30)

Oil handling piping. We should clarify that our proposed integrity and leak testing or monthly monitoring recommendation applies only to oil handling piping and equipment not all buried piping or other equipment unrelated to oil operations. (103)

Recordkeeping.

Opposes proposal. We should exempt ASTs from the recordkeeping requirement. (65) It is unreasonable to require a facility to keep records of a recommended practice (77). The recordkeeping requirement is costly and a significant administrative burden. (90) The five year recordkeeping requirement is overly burdensome and unnecessary. (189) The proposed requirement is unmanageable and we failed to show that it is necessary to reduce any reasonable risk of discharge to navigable waters. (125)

Supports proposal. Supports the proposed requirement that an owner or operator maintain testing and monitoring records for five years. (L1)

Separate document for recommendations. We should keep discretionary provisions in a separate guidance document. (27)

Response: Support for proposal. We appreciate commenter support. 269 Buried piping. We have deleted the text of the proposed recommendation to conduct annual integrity and leak testing of buried piping or monitor buried piping on a monthly basis from the rule because we do not wish to confuse the regulated public over what is mandatory and what is discretionary. This rule contains only mandatory requirements. However, we continue to endorse the recommendation as a discretionary action, and suggest that you conduct such testing according to industry standards.

We agree with a commenter that the proposed recommendation would apply only to oilhandling piping and valves, not all such piping and valves, which may be unrelated to oil activities. However, no change in rule text is necessary because the entire rule applies only to procedures, methods, or equipment that are involved with the storage or use of oil. In response to the commenter who urged that the proposed recommendation not apply to buried piping of less than 10 feet in length, we believe that any buried piping, regardless of length, may cause a discharge, and therefore should be tested. Double walled piping might be an acceptable alternative to integrity and leak testing or monthly monitoring. If you choose double walled piping as an alternative, you must explain your nonconformance with the rule requirements, and explain how double walled piping provides equivalent environmental protection. See 112.7( a)( 2).

On the suggestion of commenters, we have modified the proposed recommendation for annual testing or monthly monitoring of buried piping into a requirement that you must only conduct integrity and leak testing of such piping at the time of installation, modification, construction, relocation, or replacement. We believe that when piping is exposed for any reason, integrity and leak testing of such exposed piping according to industry standards is appropriate because piping is visible at that point, and testing is easier because the piping is more accessible. The same commenters also recommended that unprotected underground piping be subject to engineering evaluations every five years, but we recommend such evaluations be conducted in accordance with industry standards to preserve flexibility in case the time frame changes with changing technology.

Double walled or vaulted tanks. If you have vaulted containers, the requirement for integrity and leak testing of buried piping might be the subject of a deviation under §112.7( a)( 2) if those pipes, valves, and fittings come out of the top of the container and are not buried, or are encased in a double walled piping system and you thereby significantly reduce the potential for corrosion.

Feedstocks. We disagree that buried piping testing, whether annual or otherwise, would limit the facility's ability to receive feedstocks and deliver finished products. The facility may schedule testing so as not to interfere with receipt of products.

Large or small facilities. This requirement applies to facilities of any size because the risk of discharge is the same.

Manned facilities, aboveground facilities, cathodically protected facilities. The requirement for integrity and leak testing applies only to buried piping. Therefore, aboveground piping, whether manned or not, is exempted. Piping cathodically 270 protected is likewise not exempt, but may be the subject for a deviation if you explain your reasons for nonconformance, and show that cathodic protection provides equivalent environmental protection to the requirement to conduct integrity and leak testing of buried piping when it is installed, modified, constructed, relocated, or replaced.

Piping material or age. Good engineering practice would include consideration of these factors, as well as site conditions.

Coast Guard rules. We disagree that our rules should necessarily be consistent with Coast Guard rules on buried piping testing. We regulate non transportation related facilities. Comparing these facilities with transportation related facilities under Coast Guard programs is inappropriate because of the differences in the types of facilities that EPA regulates.

Cost. We disagree integrity and leak testing is burdensome or costly for small facilities, or that testing other than visual or hydrostatic testing is financially burdensome and costly in terms of manpower. We do not specify the method of such testing. You may use the least costly method that meets the requirements of the rule.

Method of testing. We do not require pressure testing or any other specific method. While testing pursuant to standards following part 280 or a state program approved under part 281 is certainly acceptable, it is not required. Generally we recommend testing according to industry standards.

Guidance. We suggest use of industry standards where appropriate.

Recordkeeping. We agree that a five year period for recordkeeping is more than necessary, and instead require that records be kept for a maximum of three years. See §112.7( e). We disagree that ASTs should be exempt from the recordkeeping requirement. There is no deviation for recordkeeping if a requirement to keep records is applicable. If the owner or operator of a vaulted tank deviates from the requirement to test buried piping at the specified intervals, he must explain his reasons for nonconformance, and provide equivalent environmental protection. If the equivalent environmental protection provided requires tests or inspections, records of those tests or inspections must be maintained for three years.

XI  C( 4) Vehicular traffic  §112.8( d)( 5)

Background: Section 112.7( e)( 3)( v) of the current rule requires warning verbally or by appropriate signs for vehicular traffic granted entry into the facility to be sure that the vehicle, because of its size, will not endanger aboveground piping. In 1991, we proposed to redesignate the provision as §112.8( d)( 5), adding a recommendation that the owner or operator post weight restrictions, as applicable, to prevent damage to underground piping. 271 Comments: Support for proposal. "It seems that good engineering practices would exclude heavy equipment from crossing buried piping which does not have adequate cover to protect the pipe." (39, 48, 51, 53, 72, 102, 143, 147, 161, 168, L8).

Alternatives.

Additional structural protection. "MDE recommends that if a buried pipe must be placed across a thoroughfare, it should be installed with additional structural protection. Proper installation is preventative and is a better alternative over a sign. The vehicle weight restriction signs are not always needed." (135)

Local building codes. "In virtually all cases, local building codes or other standards already address the issue of buried piping protection." (53)

Location and marking. "This could result in weight limits being set low at some sites that access would be denied to the very vehicles which need access to make the facility economically viable  and which have driven over the same piping for a dozen or more years. ... Location and marking of such piping so that it could be temporarily protected, or avoided, would appear to be an acceptable alternate. While it could be argued that providing such protection or rerouting emergency equipment is not practical, it is at least as practical as expecting such equipment to comply with weight restriction signs!" (76)

PE discretion. "This provision recommends the posting of vehicle weight restrictions. However, it would be preferable for EPA to require that a PE be involved in evaluating this question and that the PE's conclusions be documented and implemented." (43)

Requirement, not recommendation. The rule "should require, rather than recommend, that vehicular weight restrictions be posted to prevent damage to underground piping." (44, 52)

Rerouting. "Location and marking of such piping so that it could be temporarily protected, or avoided, would appear to be an acceptable alternate. While it could be argued that providing such protection or rerouting emergency equipment is not practical, it is at least as practical as expecting such equipment to comply with weight restriction signs!" (76)

Applicability.

Airports. The proposal is "unreasonable at airport facilities where some buried piping/ hydrant systems run under ramp surfaces. Posting of signs in such open areas would be impractical and impact operations." (107) 272 Large facilities. Recommendation should apply only "to large facilities because only large facilities will have the type of tanker trucks which would potentially damage underground piping." (34, 75, 182)

Railroads. "This recommendation is overly broad. Railroads have a large amount of piping under track that is built to withstand maximum loads from vehicular traffic. It is unnecessary to require signs for such pipes. Furthermore, it would be costly to post signs wherever there is underground piping on railroad property." (57)

Vaulted tanks. "Because VAST technology requires all openings and fittings to be placed at the top of the tank, and requires the dike in the form of a concrete vault to immediately encompass the secondary containment, the risk of damage from vehicular traffic has been significantly reduced, making the provisions in §112.8( d)( 5) unduly burdensome and costly to sites using VAST technology." (65)

Costs. We failed to recognize the substantial costs to owners or operators of determining accurate weight restrictions. (76)

Guidance. "...( U) nless further guidance is provided on the method of determining an acceptable weight limit, this item should be eliminated." (169)

Response: Support for proposal. We appreciate commenter support.

Applicability. The requirement to warn vehicular traffic so that no vehicle will endanger aboveground piping or other oil transfer operations applies to all facilities, large or small, because vehicular traffic may endanger aboveground piping or other transfer operations at all facilities. Warnings may include verbal warnings, signs, or marking and temporary protection of piping or equipment. No particular height restriction is incorporated into the rule. Rather, aboveground piping at any height must be protected from vehicular traffic unless the piping is so high that all vehicular traffic passes underneath the piping. In this case, or where the requirement is infeasible, you may be able to use the deviation provision in §112.7( a)( 2) if you explain your reasons for nonconformance and provide equivalent environmental protection. We have deleted the clause concerning the size of vehicles that may endanger piping or oil transfer operations because the owner or operator may not be able to determine precisely when the size or weight of a vehicle which would cause such endangerment.

In response to commenters who suggested that the posting of signs is impractical and might impact operations, or would be very costly, we note that you may deviate from the requirement under §112.7( a)( 2) if you explain your reasons for nonconformance and provide equivalent environmental protection.

Costs. Even though we did not include the recommendation in the final rule, we included the estimated costs of the proposal in our 1991 economic analysis. 273 New regulatory structure. We see no need for a new regulatory structure because buried piping is likely to be an appurtenance to a completely buried tank and as such, is likely to be regulated under 40 CFR part 280. If the piping is not of a completely buried tank, the appurtenance is likely covered by part 112 requirements. Therefore, a new regulatory structure is unnecessary.

Weight restriction posting. We deleted the proposed recommendation concerning weight restrictions as it relates to underground piping from rule text, but still support it when appropriate. We include only mandatory items in this rule because we do not wish to confuse the regulated public as to what is mandatory and what is discretionary. We decline to make the recommendation a requirement because we believe the appropriate posting of weight restrictions should be a matter of good engineering practice. 274 Category XII: Onshore production facility Plan requirements XII  A: Production facilities (general requirements)  §112.9( a)

Background: In 1991, we proposed to reorganize §112.7( e) of the current rule into four sections (§§ 112. 8, 112. 9, 112. 10, and 112. 11), based on facility type. We proposed §112.7( e)( 5) of the current rule as §112.9 in 1991.

Comments: Cost. Section §112.9 of the proposed rule would result in an increased economic burden on owners or operators of production facilities – particularly small facilities with "stripper" wells. "For these wells, any substantial capital expense or increase in operating costs will very likely result in premature closure." (42, 67, 91, 101)

Performance standards. "Arbitrary standards for onshore and offshore production facilities (40 CFR §§ 112. 9 and 112. 11) should be deleted and replaced by reasonable performance standards." (86)

Reorganization of rule. "The requirements for oil production facilities should be consolidated with similar requirements for on shore facilities. The few differences between the two types of facilities could be handled on a call out basis. As §§ 112.8 and 112.9 are now written, they are similar but not identical. There appears to be no justification for the difference." (111)

Response: Cost. EPA considered cost factors in finalizing the requirements in this rule. We believe that facilities in compliance with the current rule will incur minimal additional cost due to the revisions in this rule. Many of the provisions we proposed in 1991 that commenters believed were too costly were not finalized in the rule, In addition, in today's rule, we have provided flexibility in several ways. Furthermore, we are finalizing other provisions in this rule which will reduce burden in other ways and will exempt certain facilities from having to prepare a Plan. EPA has also prepared an assessment of the costs of rule compliance, which is discussed in part VI. F (Regulatory Flexibility Act) of today's preamble, and we have included the specific comments related to costs and our responses in relevant sections of this preamble.

We agree that we should require performance standards in this regulation rather than prescriptive standards. Throughout the rule we generally allow for the application of industry standards where the standards are both specific and objective, and their application may reduce the risk of discharges to and impacts to the environment. We also permit the owner or operator greater flexibility by allowing the use of deviations under either §112.7( a)( 2) or (d).

Performance standards. The final rule generally provides for use of performance standards rather than design standards. See §§ 112.7( a)( 2) and (d).

Reorganization of rule. We generally agree that the current rule is adequate and effective in preventing discharges. We have reorganized the rule into subparts and sections based 275 on the type of oil stored or used and the type of facility for clarity and ease of use. The reorganization is not a substantive change.

XII  B: Facility drainage  §112.9( b) (proposed as §112.9( c))

XII  B( 1) Diked storage area drainage  §112.9( b)( 1)

Comments: Applicability. Urges a small facility exemption from this requirement because the recordkeeping involved was too burdensome.

Editorial changes and clarifications. "The language in §112.9( c)( 1) stating `... where an accidental discharge of oil would have a reasonable possibility of reaching navigable waters.... ' does not agree with the wording in §112.1( b)( 1) stating `... which due to their location could reasonably be expected to discharge oil in quantities that may be harmful.... ' These sections should be made consistent." (154) "The requirement to have all drains closed on dikes around storage tanks might preclude engineering measures (stand pipes) designed to handle flow through conditions at water flood oil production operations, where large volumes of water may be directed to oil storage tanks if water discharge lines on oil water separators become plugged." (28, 31, 101, 165)