Oil Pollution Prevention and Response; Non-Transportation-Related Onshore and Offshore Facilities
[Federal Register: July 17, 2002 (Volume 67, Number 137)]
[Rules and Regulations]
[Page 47091-47140]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr17jy02-30]
[[pp. 47091-47140]]
Oil Pollution Prevention and Response; Non-Transportation-Related
Onshore and Offshore Facilities
[[Continued from page 47090]]
[[Page 47091]]
amended at fixed time points such as before a design is physically
implemented, before startup of operations, after modifications, before
new or modified equipment is in operation, or when changes are made.
One commenter said that rule language should be clarified to note that
the RA may specify a time period longer than six months to implement an
amendment.
Response to comments. When amendment is necessary. We agree with
the commenter who suggested that we maintain the current standard for
amendments, i.e., when there is a change that materially affects the
facility's potential to discharge oil. This position accords with our
stance on when Plans should be prepared and implemented. See
Sec. 112.3. The other suggested standards too narrowly limit the
changes which would trigger Plan amendment. We believe that an
amendment is necessary when a facility change results in a decrease in
the volume stored or a decrease in the potential for an oil spill
because EPA needs this information to determine compliance with the
rule. For example, the amount of secondary containment required depends
on the storage capacity of a container. Decreases might also affect the
way a facility plans emergency response measures and training
procedures. A lesser capacity might require different response measures
than a larger capacity. The training of employees might be affected
because the operation and maintenance of the facility might be affected
by a lesser storage capacity.
Likewise, a standard requiring amendment ``when there are indicia
of problems'' is too vague and leaves problems unaddressed which may
result in a discharge as described in Sec. 112.1(b). A standard
requiring an amendment only when the change would cause the spill
potential to exceed the Plan's capabilities (because day-to-day changes
do not affect the worst case spill) would have the effect of leaving no
documentation of amendments which might affect discharges which do not
reach the standard of ``worst case spill.'' While we encourage
facilities to incorporate new procedures into Plans which would help to
prevent discharges, amendments are still necessary when material
changes are made to document those new procedures, and thus facilitate
the enforcement of the rule's requirements. We disagree that a small
facility should be exempt from making amendments for material changes.
Amendments may be necessary at large or small facilities alike to
prevent discharges after material changes.
Material changes. A material change is one that may either increase
or decrease the potential for a discharge. We agree with the commenter
that the rule should be worded to indicate that the examples are for
illustration only, because the items in the list may not always trigger
amendments, and because the list is not exclusive. Only changes which
materially affect operations trigger the amendment requirement.
Ordinary maintenance or non-material changes which do not affect the
potential for the discharge of oil do not.
We disagree that decommissioning of a container that results in
permanent closure of that container is not a material amendment.
Decommissioning a container could materially decrease the potential for
a discharge and require Plan amendment, unless such decommissioning
brings the facility below the regulatory threshold, making the
preparation and implementation of a Plan no longer a requirement. We
also believe that the oversight of a Professional Engineer is necessary
to ensure that the container is in fact properly closed.
We agree that replacement of tanks, containers, or equipment may
not be a material change if the replacements are identical in quality,
capacity, and number. However, a replacement of one tank with more than
one identical tank resulting in greater storage capacity is a material
change because the storage capacity of the facility, and its consequent
discharge potential, have increased.
Changes of product. We have added to the list of examples, on a
commenter's suggestion, ``changes of product.'' We added ``changes of
product'' because such change may materially affect facility operations
and therefore be a material change. An example of a change of product
that would be a material change would be a change from storage of
asphalt to storage of gasoline. Storage of gasoline instead of asphalt
presents an increased fire and explosion hazard. A switch from storage
of gasoline to storage of asphalt might result in increased stress on
the container leading to its failure. Changes of product involving
different grades of gasoline might not be a material change and thus
not require amendment of the Plan if the differing grades of gasoline
do not substantially change the conditions of storage and potential for
discharge.
A change in service may also be a material change if it affects the
potential for a discharge. A ``change in service'' is a change from
previous operating conditions involving different properties of the
stored product such as specific gravity or corrosivity and/or different
service conditions of temperature and/or pressure. Therefore, we have
amended the rule to add ``or service'' after the phrase ``changes of
product.''
Documenting no change or certain activities. We agree that a log
book may be used to document non-material, routine activities. However,
this is not an appropriate substitute for amendment when you make
material changes at the facility.
EPA approval. We agree with the commenter's suggestion that EPA
approval of an amendment is not required. However, if the RA is not
satisfied that your amendment satisfies the requirements of these
rules, he may require further amendment of your Plan.
Time line for amendment implementation. We agree with commenters
that we should not require Plan amendment before material changes are
made. Therefore, we have revised the proposed rule to provide a maximum
of six months for Plan amendment, and a maximum of six more months for
amendment implementation. This is the current standard. We note that
Sec. 112.3(f) allows the RA to authorize an extension of time to
prepare and implement an amendment under certain circumstances.
Editorial changes and clarifications. The phrase in the first
sentence which read, ``potential to discharge oil as described in
Sec. 112.1(b) of this part,'' becomes ``potential for a discharge as
described in Sec. 112.1(b). ``Tanks'' becomes ``containers.''
``Commission or decommission'' becomes ``commissioning or
decommissioning.''
Section 112.5(b)--Periodic Review of Plans
Background. In 1991, we reproposed the current rule, which requires
that the owner or operator review the Plan at least every three years,
and amend it if more effective control and prevention technology would
significantly reduce the likelihood of a spill, and if the technology
had been field-proven at the time of the review.
In 1997, we withdrew the 1991 proposal, and instead proposed a
five-year review time frame, with the same technological conditions. In
1997, we also proposed that the owner or operator certify that he had
performed the review.
Comments. Five-year review. Most commenters favored the change from
three-to five-year review. Some
[[Page 47092]]
commenters noted that a five-year review period would make it easier to
coordinate reviews of related plans, such as facility response plans
required by part 112. A few opposed it, preferring the current three-
year review period. They believed that five-year review might lead to
reduced maintenance and consequent environmental harm, especially in
the absence of any requirements for a facility to ensure that personnel
are familiar with planning goals and proposed response actions,
including personnel who are rotated. One commenter suggested that the
longevity of a tank warranty should be the determining factor in the
length of review time. Another suggested that there should be no
particular time period prescribed because the requirement for an
amendment whenever a material change is made is sufficient.
Completion of review. Commenters split almost evenly on the
proposed requirement for certification of completion of the review.
Opponents of the certification proposal believed generally that it is
unnecessary paperwork that will not benefit the environment. One
commenter suggested that instead of documenting completion of review, a
facility might instead date the Plan to show review and date each
amendment. One commenter thought that the certifications should have to
be forwarded to the Regional Administrator. Others asked whether the
certification could be documented in a log book, instead of in the
Plan. Another commenter asked at what management level certification
should be required. One commenter believed that Plans amended due to
five-year reviews should not require owner or operator certification
because any amendments to the Plan have to be reviewed and certified by
a PE. Another commenter noted that no specific language was provided
for the certification. One commenter urged that the PE should be
allowed to document that no change is necessary after reviewing planned
changes, or that further study is required, or that an amendment is
necessary.
Response to comments. Five-year review. We agree that a five-year
review period will make coordination of review of related plans, such
as facility response plans required by part 112, easier. We disagree
that a five-year review period will lead to reduced maintenance or
increased environmental harm. Amendment of a Plan will still be
necessary when a material change is made affecting the facility's
potential to discharge oil, perhaps after certain discharges as
required by the RA under Sec. 112.4(a), and perhaps after on-site
review of a Plan (see Sec. 112.4(d)). Plus the Plan must be implemented
at all times. These opportunities ensure that Plans will be current. We
also disagree that the length of the tank warranty should be the
determining factor for a technological review. Technology changes
enough within a five-year period to warrant required review within such
time period whether or not other changes occur. Amendments other than
the five-year review amendments may not be based on the need to learn
of improved technology. Those amendments might result from deficiencies
in the Plan, on the need to make repairs, or to remedy the cause of a
discharge.
Calculation of time between reviews. The change in the rule from
three-year to five-year reviews requires some explanation as to when a
review must be conducted. For example, a facility became subject to the
rule on January 1, 1990. The first three-year review should have been
conducted by January 1, 1993, the second by January 1, 1996, and the
third by January 1, 1999. The next review must be conducted by January
1, 2004, due to the rule change. In other words, an existing facility
must complete the review within 5 years of the date the last review
must have been completed. A facility becoming operable on or after the
effective date of the rule will begin a five-year cycle at the date it
becomes subject to part 112.
Completion of review. We disagree that documentation of completion
of review has no environmental benefit. Its benefit lies in the fact
that it shows that someone reviewed the Plan to determine if better
technology would benefit the facility and the Plan is current.
Documentation of completion of review is necessary whether or not any
amendments are necessary in order to clearly show that the review was
done. Mere dating of the Plan or of an amendment does not show that you
performed the required review. Documentation of completion of review is
a function of the owner or operator, whereas certification of any
resulting technical amendment is a function of the PE. We disagree that
documentation of completion should be forwarded to the Regional
Administrator because it would increase the information collection
burden without an environmental benefit. It is sufficient that the
review be done. When the Regional Administrator wishes to verify
completion of review, he may do so during an on-site inspection.
How to document completion of review. You must add documentation of
completion of review either at the beginning or the end of the Plan, or
maintain such documentation in a log book appended to the Plan or other
appendix to the Plan. You may document completion in one of two ways.
If amendment of the Plan is necessary, then you must state as much, and
that review is complete. This statement is necessary because Plan
amendments may result either from five-year review or from material
changes at the facility affecting its potential for discharge, or from
on-site review of the Plan. There is no way to know which circumstance
causes the amendment without some explanation. If no amendments are
necessary, you must document completion of review by merely signing a
statement that you have completed the review and no amendments are
necessary. You may use the words suggested in the rule to document
completion, or make any similar statement to the same effect.
Who documents review. The owner or operator of the facility, or a
person at a management level with sufficient authority to commit the
necessary resources, must document completion of review.
Time line for amendment implementation. We agree with commenters
(see comments on proposed Sec. 112.5(a)) that the preparation and
implementation of Plan amendments require more time than proposed. The
same rationale applies to the preparation and implementation of
amendments required due to five-year reviews. Therefore, we will
require adherence to the time lines laid down in Sec. 112.5(b) for
amendments. Currently, Sec. 112.5(b) requires that Plan amendments be
prepared within six months. It is silent as to time lines for
implementation. Therefore, we have revised the rule to clarify that
amendments must be implemented as soon as possible, but within the next
six months. This is the current standard for implementation of certain
other amendments. See, for example, Secs. 112.3(a) and 112.4(e). We
note that Sec. 112.3(f) allows you to request an extension of time to
prepare and implement an amendment.
Editorial changes and clarifications. We have changed the word
``certification'' to a requirement to document completion of the review
to avoid the legal effect a certification may have. The intent of the
certification proposal was merely to show that an owner or operator
performed a review of the Plan every five years. 62 FR 63814, December
2, 1997. A false documentation of completion of review of the Plan is a
deficiency in the Plan and may be cited as a violation of these
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rules. ``Spill event,'' in the second sentence, becomes ``discharge as
described in Sec. 112.1(b).
Section 112.5(c)--PE Certification of Technical Amendments
Background. In 1991, we proposed that all amendments to the Plan
must be certified by a PE with the exception of changes to the contact
list. The current rule requires certification of all amendments.
Comments. A few commenters suggested that the value of PE
certification for amendments does not justify the cost. Another
commenter questioned when recertification of the entire Plan was
required, rather than just the amendment in question. Several
commenters suggested that the recertification requirement be limited to
those changes that materially affect the facility's potential to
discharge oil.
Response to comments. It is the responsibility of the owner or
operator to document completion of review, but completion of review and
Plan amendment are two different processes. PE certification is not
necessary unless the Plan is amended.
We believe that PE certification is necessary for any technical
amendment that requires the application of good engineering practice.
We believe that the value of such certification justifies the cost, in
that good engineering practice is essential to help prevent discharges.
Therefore, we have amended the rule to require PE certification for
technical changes only. Non-technical changes not requiring the
exercise of good engineering practice do not require PE certification.
Such non-technical changes include but are not limited to such items
as: changes to the contact list; more stringent requirements for
stormwater discharges to comply with NPDES rules; phone numbers;
product changes if the new product is compatible with conditions in the
existing tank and secondary containment; and, any other changes which
do not materially affect the facility's potential to discharge oil. If
the owner or operator is not sure whether the change is technical or
non-technical, he should have it certified.
Former Section 112.7(a)(1)--Certain pre-1974 Discharges
Background. In 1991, we proposed to delete Sec. 112.7(a), which
required a description of certain discharges to navigable waters or
adjoining shorelines which occurred prior to the effective date of the
rule in 1974, because that information was no longer relevant. 56 FR
54620. We received several comments supporting the proposed deletion of
this provision, and have deleted it.
Section 112.7 Introduction and (a)(1)--General Eequirements
Background. In 1991, we reproposed the introduction to Sec. 112.7
to clarify that the rule requires mandatory action, and that it is not
just a guideline. In 1997, we reproposed a definition of SPCC Plan that
included some substantive requirements. As noted above (see the ``SPCC
Plan'' definition in Sec. 112.2), those substantive requirements have
been transferred from the definition of ``SPCC Plan'' in Sec. 112.2 to
this section.
Section 112.7(a)(1) requires a discussion of the facility's
conformance with the listed requirements in the rule.
Comments. For a discussion of the ``should to shall to must''
comments and response to those comments, see the discussion above under
that topic in section IV.C of this preamble.
Cross-referencing. Several commenters criticized the requirement
for sequential cross-referencing set forth in the 1997 proposed
definition of ``SPCC Plan,'' alleging that it is confusing and provides
no benefit. Another commenter asked how detailed the cross-referencing
must be.
Written Plans. Another commenter proposed that a ``written'' Plan
might also include texts, graphs, charts, maps, photos, and tables, on
whatever media, including floppy disk, CD, hard drive, and tape storage
that allows the document to be easily accessed, comprehended,
distributed, viewed, updated, and printed.
Response to comments. Cross-referencing. We agree that the term
``sequential'' cross-referencing may be confusing, and have therefore
deleted it in favor of a requirement to provide cross-referencing. We
disagree that cross-referencing provides no benefit. With the wide
variation now allowed in differing formats, we need cross-referencing
so that an inspector can tell whether the Plan meets Federal
requirements, and whether it is complete. In addition, in order for an
owner or operator to do his own check to ensure that his facility meets
all SPCC requirements, he must go through the exercise of comparing his
Plan to each SPCC requirement. Cross-referencing in the context of the
rule means indicating the relationship of a requirement in the new
format to an SPCC requirement. The cross-referencing must identify the
Federal section and paragraph for each section of the new format it
fulfills, for example, Sec. 112.8(c)(3). Note the cross-referencing
table we have provided for your convenience in section II.A of this
preamble.
Written Plans. We agree that a ``written'' Plan might also include
texts, graphs, charts, maps, photos, and tables, on whatever media,
including floppy disk, CD, hard drive, and tape storage, that allows
the document to be easily accessed, comprehended, distributed, viewed,
updated, and printed. Whatever medium you use, however, must be readily
accessible to response personnel in an emergency. If it is produced in
a medium that is not readily accessible in an emergency, it must be
also available in a medium that is. For example, a Plan might be
electronically produced, but computers fail and may not be operable in
an emergency. For an electronic Plan or Plan produced in some other
medium, therefore, a backup copy must be readily available on paper. At
least one version of the Plan should be written in English so that it
will be readily understood by an EPA inspector.
Editorial changes and clarifications. We have transferred all of
the proposed substantive requirements in the 1997 proposed definition
of ``SPCC Plan'' to the introduction of this section. We did this
because we agree with commenters (see the comments on the definition of
``SPCC Plan'' in Sec. 112.2) that definitions should not contain
substantive requirements.
We have revised the introduction to Sec. 112.7 to facilitate use of
the active voice and to clearly note that the owner or operator, except
as specifically noted, is responsible for implementing the rule.
We also deleted language requiring a ``carefully thought-out'' SPCC
Plan. Such language is unnecessary because the Plan must be prepared in
accordance with good engineering practices. Another editorial revision
in the introduction is the change from ``level with authority'' in the
last sentence of proposed Sec. 112.7(a) to ``level of authority.'' A
third revision is a change from ``format'' to ``sequence.'' We have
transferred the part of the sentence proposed in 1991 dealing with the
sequence of the Plan in Sec. 112.7(a)(1) to the introduction of
Sec. 112.7.
For consistency with response plan language in Sec. 112.20(h), the
language in the introduction referring to alternative SPCC formats has
been revised to read ``equivalent Plan acceptable to the Regional
Administrator.'' The response plan language in Sec. 112.20(h) on
``equivalent response plans'' has also been revised to include the
``acceptable to the Regional Administrator'' language included in the
introduction to Sec. 112.7. For a discussion of possible SPCC formats,
see the discussion under the definition of ``SPCC Plan,'' above.
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We deleted the term ``sequentially cross-referenced'' because we
agree that it may be misunderstood, and instead use the term ``cross-
referencing'' in the revised rule. As noted above, cross-referencing
means identifying the requirement in the new format to the section and
paragraph of the SPCC requirement. We have also substituted the word
``part'' for ``section'' where ``cross-referencing'' and meeting
``equivalent requirements'' are mentioned. We make this change because
the rule requires compliance with any applicable provision in the part,
not merely Sec. 112.7. We also clarify that the discussion of your
facility's conformance with the requirements listed (see
Sec. 112.7(a)(1)) means the requirements listed in part 112, not merely
the requirements listed in Sec. 112.7.
We also note that if the Plan calls for additional facilities or
procedures, methods, or equipment not yet fully operational, you must
discuss these items in separate paragraphs, and must explain separately
the details of installation and operational start-up. The discussion
must include a schedule for the installation and start-up of these
items.
Section 112.7(a)(2)--Deviations from Plan Requirements
Background. In 1991, we proposed to allow deviations from the
requirements listed in Sec. 112.7(c) and in Secs. 112.8, 112.9, 112.10,
and 112.11, as long as the owner or operator explained the reason for
nonconformance and provided equivalent environmental protection by
another means. The proposal was intended to implement the requirement
for ``good engineering practice'' which is a cornerstone of the rule,
and to provide flexibility in meeting the rule's requirements. We
clearly noted in the rule that the Regional Administrator would have
the authority to overrule any deviation.
In 1993, we reproposed the section, eliminating language referring
to the Regional Administrator's (RA's) authority to overrule
deviations. Instead, we proposed that whenever you proposed a
deviation, you would have to submit the entire Plan to the RA with a
letter explaining how your Plan contained equivalent environmental
protection measures in lieu of those explicitly required in the rule.
The RA would have authority under the 1993 proposal to require
amendment of the Plan if he determined that the measures described in
the deviation did not provide equivalent protection.
Comments. Some commenters supported the 1991 proposal. But others
had concerns.
Applicability--1991. Some commenters suggested that the Agency
should add language to the rule making clear that a facility may
deviate from the express requirements of the rule and may substitute
alternatives based on good engineering practice. The commenters added
that we should make clear that the equivalency provision in
Sec. 112.7(a)(2) does not require mathematical equivalency of every
requirement, but merely the achievement of substantially the same level
of overall protection from the risk of discharge at the facility as the
specific requirement seeks to achieve. Another commenter was concerned
that proving the equivalence of measures to the satisfaction of
Regional officials may be difficult. One commenter urged us to
expressly state that PEs may substitute alternatives based on good
engineering practice.
RA oversight--1991. One commenter opposed the provision allowing
the RA to overrule waivers/equivalent measures. As noted above, we
withdrew the proposal to allow the RA to explicitly overrule waivers.
Instead we substituted a proposed procedure whereby the RA could
require you to amend your Plan. One commenter feared that PEs would be
reluctant to certify alternate technologies due to the threat of
potential liability.
Deviation submission. One commenter opposed the proposed
requirement to submit a Plan deviation and urged its deletion to make
it consistent with the rest of the SPCC rule. The commenter argued that
the deviation and Plan have already been certified by a PE, and there
is no reason for EPA to be asked to second guess that certification in
every case. The commenter also asserted that it is unduly burdensome to
require regulated facilities to prepare a justification and submit a
Plan to EPA for every waiver of the technical requirements. Another
commenter questioned why the entire Plan should be submitted to the RA
for review. The commenter suggested that only the portion or portions
of the Plan that do not conform to the standard requirements should be
submitted, adding that this step would help EPA to minimize the
resources needed to review such waivers. One commenter suggested that
the choice of preventive systems in the design and implementation of
spill prevention measures should be left to the facility owner or
operator. The commenter opposed giving the RA authority to require
equivalent protection because he questioned how the RA will determine
if the deviation will cause harm to the environment, and therefore lack
equivalency. If such a provision is included, the commenter asked for
an appeals process similar to the one suggested in Sec. 112.20(c).
RA oversight--1993. One commenter favored the 1993 proposal.
Opposing commenters believed that submission of deviations to the RA is
unnecessary because PE certification ensures the application of good
engineering practice.
Secondary containment. Several commenters suggested that we
explicitly say that equivalent protection should be defined to allow a
compacted earthen floor and compacted earthen dike to provide secondary
containment. The rationale for the comment was that other methods of
secondary containment may be prohibitively expensive and unnecessary to
protect against spills in primarily rural areas. One commenter
suggested that we should clarify that the language of Sec. 112.7(c)
applies only to oil storage areas.
Response to comments. Applicability. We generally agree with the
commenter that an owner or operator should have flexibility to
substitute alternate measures providing equivalent environmental
protection in place of express requirements. Therefore, we have
expanded the proposal to allow deviations from the requirements in
Sec. 112.7(g), (h)(2) and (3), or (i), as well as subparts B, and C,
except for the listed secondary containment provisions in Sec. 112.7
and subparts B and C. The proposed rule already included possible
deviations for any of the requirements listed in Secs. 112.7(c), 112.8,
112.9, 112.10, and 112.11. We have expanded this possibility of
deviation to include the new subparts we have added for various classes
of oils. We take this step because we believe that the application of
good engineering practice requires the flexibility to use alternative
measures when such measures offer equivalent environmental protection.
This provision may be especially important in differentiating between
requirements for facilities storing, processing, or otherwise using
various types of oil.
A deviation may be used whenever an owner or operator can explain
his reasons for nonconformance, and provide equivalent environmental
protection. Possible rationales for a deviation include when the owner
or operator can show that the particular requirement is inappropriate
for the facility because of good engineering practice considerations or
other reasons, and that he can achieve equivalent
[[Page 47095]]
environmental protection in an alternate manner. For example, a
requirement that may be essential for a facility storing gasoline may
be inappropriate for a facility storing asphalt; or, the owner or
operator may be able to implement equivalent environmental protection
through an alternate technology. An owner or operator may consider cost
as one of the factors in deciding whether to deviate from a particular
requirement, but the alternate provided must achieve environmental
protection equivalent to the required measure. The owner or operator
must ensure that the design of any alternate device used as a deviation
is adequate for the facility, and that the alternate device is
adequately maintained. In all cases, the owner or operator must explain
in the Plan his reason for nonconformance. We wish to be clear that we
do not intend this deviation provision to be used as a means to avoid
compliance with the rule or simply as an excuse for not meeting
requirements the owner or operator believes are too costly. The
alternate measure chosen must represent good engineering practice and
must achieve environmental protection equivalent to the rule
requirement. Technical deviations, like other substantive technical
portions of the Plan requiring the application of engineering judgment,
are subject to PE certification.
In the preamble to the 1991 proposal (at 56 FR 54614), we noted
that ``* * * aboveground storage tanks without secondary containment
pose a particularly significant threat to the environment. The Phase
One modifications would retain the current requirement for facility
owners or operators who are unable to provide certain structures or
equipment for oil spill prevention, including secondary containment, to
prepare facility-specific oil spill contingency plans in lieu of the
prevention systems.'' In keeping with this position, we have deleted
the proposed deviation in Sec. 112.7(a)(2) for the secondary
containment requirements in Secs. 112.7(c) and (h)(1); and for proposed
Secs. 112.8(c)(2), 112.8(c)(11), 112.9(c)(2), 112.10(c); as well as for
the new sections which are the counterparts of the proposed sections,
i.e., Secs. 112.12(c)(2), 112.12(c)(11), 112.13(c)(2), and 112.14(c),
because a more appropriate deviation provision already exists in
Sec. 112.7(d). Section Sec. 112.7(d) contains the measures which a
facility owner or operator must undertake when the secondary
containment required by Sec. 112.7(c) or (h)(1), or the secondary
containment provisions in the rule found at Secs. 112.8(c)(2),
112.8(c)(11), 112.9(c)(2), 112.10(c), 112.12(c)(2), 112.12(c)(11),
112.13(c)(2), and 112.14(c), are not practicable. Those measures are
expressly tailored to address the lack of secondary containment at a
facility. They include requirements to: explain why secondary
containment is not practicable; conduct periodic integrity testing of
bulk storage containers; conduct periodic integrity and leak testing of
valves and piping; provide in the Plan a contingency plan following the
provisions of 40 CFR part 109; and, provide a written commitment of
manpower, equipment, and materials to expeditiously control and remove
any quantity of oil discharged that may be harmful. Therefore, when an
owner or operator seeks to deviate from secondary containment
requirements, Sec. 112.7(d) will be the applicable ``deviation''
provision, not Sec. 112.7(a)(2).
Deviation submission. We agree with the commenter that submission
of a deviation to the Regional Administrator is not necessary and have
deleted the proposed requirement. We take this step because we believe
that the requirement for good engineering practice and current
inspection and reporting procedures (for example, Sec. 112.4(a)),
followed by the possibility of required amendments, are adequate to
review Plans and to detect the flaws in them. Upon submission of
required information, or upon on-site review of a Plan, if the RA
decides that any portion of a Plan is inadequate, he may require an
amendment. See Sec. 112.4(d). If you disagree with his determination
regarding an amendment, you may appeal. See Sec. 112.4(e).
RA oversight. Once an RA becomes aware of a facility's SPCC Plan as
a result of an on-site inspection or the submission of required
information, he is to follow the principles of good engineering
practice and not overrule a deviation unless it is clear that such
deviation fails to afford equivalent environmental protection. This
does not mean that the deviation must achieve ``mathematical
equivalency,'' as one commenter pointed out. But it does mean
equivalent protection of the environment. We encourage innovative
techniques, but such techniques must also protect the environment. We
also believe that in general PEs will seek to protect themselves from
liability by only certifying measures that do provide equivalent
environmental protection. But the RA must still retain the authority to
require amendments for deviations, as he can with other parts of the
Plan certified by a PE.
Not covered under the deviation rule. Deviations under
Sec. 112.7(a)(2) are not allowed for the general and specific secondary
containment provisions listed above because Sec. 112.7(d) contains the
necessary requirements when you find that secondary containment is not
practicable. We have amended both this paragraph and Sec. 112.7(d) to
clarify this. Instead, the contingency planning and other requirements
in Sec. 112.7(d) apply. Deviations are also not available for the
general recordkeeping and training provisions in Sec. 112.7, as these
requirements are meant to apply to all facilities, or for the
provisions of Sec. 112.7(f) and (j). We already provide flexibility in
the manner of recordkeeping by allowing the use of ordinary and
customary business records. Training and a discussion of compliance
with more stringent State rules are essential for all facilities.
Therefore, we do not allow deviations for these measures.
Secondary containment. Regarding the secondary containment
requirements, the requirement in Sec. 112.7(c) applies not only to oil
storage areas, but also to operational areas of the facility where a
discharge may occur. Section 112.7(c) may apply to any area of the
facility where a discharge is possible. Other secondary containment
provisions in this part have more particular applicability, e.g.,
Secs. 112.7(h)(1), 112.8(c)(2), 112.8(c)(11), 112.9(c)(2),112.10(c),
and their counterparts in subpart C. We decline to specify that a
compacted earthen floor and compacted earthen dike will always satisfy
the secondary containment requirements. Those methods may, however, be
acceptable if there is no potential for oil to migrate through the
compacted earthen floor or dike through groundwater to cause a
discharge as described in Sec. 112.1(b).
Editorial changes and clarifications. ``Equivalent protection''
becomes ``equivalent environmental protection'' throughout the
paragraph.
Section 112.7(a)(3)--Facility Characteristics That Must be Described in
the Plan
Background. In 1991, we proposed a new section that would require
you to describe the essential characteristics of your facility in the
Plan. Those characteristics are discussed below. In the description,
you would also be required to provide a facility diagram that included
the location and contents of all tanks, regardless of whether the tanks
are subject to all the provisions of 40 CFR part 280 or a State program
approved under 40 CFR part 281, or otherwise subject to part 112. The
rationale for the diagram was that it would assist in response actions.
[[Page 47096]]
Responders would have a means to know where all containers are, to help
ensure their safety in conducting a response action and aid in the
protection of life and property.
Comments. General description of characteristics. Two commenters
asked that the requirements proposed for Plan characteristics be listed
on a facility basis rather than a tank basis because otherwise the
proposal would be too resource intensive. The commenters did not
provide cost estimates.
Facility diagram. Two commenters supported the proposal. Opposing
commenters asserted that the diagram would be too costly and add little
to the Plan. One commenter said that the requirement was redundant
because many States require the same thing. Two commenters opposed
marking the contents of the tanks because those contents may change
frequently, requiring Plan amendment each time. One commenter suggested
that instead the facility maintain a separate list of tank contents
when changes occur frequently over a short span of time to eliminate
the need to constantly amend the diagram. Other commenters requested a
de minimis exemption for small containers for the diagram, suggesting
levels of 660 gallons or less. Some of these commenters suggested that
the diagram be discretionary for storage volumes of less than 10-15,000
gallons. Other commenters asked whether exempt materials would have to
be marked as to content, for example, products which are not oil. Some
believed that the inclusion of otherwise exempt containers in the
diagram was unreasonable. One commenter suggested the diagram should
include transfer stations and connecting pipes. Another commenter asked
for clarification that underground tanks, whether subject to SPCC or
not, need to be included in the diagram.
Unit-by-unit storage capacity. Several commenters asked for
clarification of the meaning of the term ``unit-by-unit storage
capacity.'' Many commenters asked for specification of a minimum size,
and some suggested sizes, ranging from 660 gallons to 10,000 gallons.
Type and quantity of oil stored. We received one comment on this
item. The commenter opposed the information requirement because ``the
way a tank is used changes often and the adequacy of response to an
accidental discharge does not depend on the type of oil stored.''
Estimates of quantity of oils potentially discharged. The few
comments we received opposed this information requirement. One
commenter argued that the item requests a ``prediction'' of future
events. Another asserted that it would not be possible to give
estimates of oil potentially discharged from flowlines or gathering
systems. One commenter argued that mobile facilities should be exempt
from this requirement because the exact site information changes with
the movement of equipment.
Possible spill pathways. Two commenters wrote that the proposed
requirement ``could be an infinite number and serves no useful
purpose.'' One commenter asked that the requirement be replaced by a
requirement to describe the most likely spill pathways to navigable
water.
Spill prevention measures (including loading areas and transfers).
One commenter suggested that the beginning of the paragraph be revised
to read, ``Secondary containment'' instead of ``Spill prevention
measures. . . .'' See also the discussion on loading areas under
Sec. 112.7(h).
Spill controls and secondary containment. One commenter thought
that this paragraph should refer to ``other drainage control features
and the equipment they protect.''
Spill countermeasures. One commenter suggested that this paragraph
be revised to read, ``Prevention, control, or countermeasure features,
other than secondary containment and drainage control, and the
equipment which they protect.'' Another commenter argued that mobile
drilling and workover rigs either on or off shore should be exempt from
this requirement because supplying site specific spill and clean-up
information for a mobile source that will move from one site to another
is not feasible. One commenter suggested that the contingency planning
requirements in this paragraph, as well as in Sec. 112.7(b) and (d)(1),
seem unnecessarily complex because the same basic information seems to
be required in several different places in the proposed regulation. The
commenter went on to suggest that EPA consolidate these requirements.
Another commenter suggested that this paragraph should be deleted and
removed to a response plan section which he suggested, because the
information called for requires response information.
Disposal of recovered materials. Two commenters supported the
proposal in general, but one suggested that it is not feasible nor
useful to discuss particular alternatives. One of the favorable
commenters suggested that we should encourage recycling of spilled oil
rather than mere disposal. Another commenter argued that mobile
drilling and workover rigs either on or off shore should be exempt from
this requirement because supplying site specific spill and clean-up
information for a mobile source that will move from one site to another
is not feasible.
Some opposing commenters believed that the proposal would preclude
bioremediation. Others believed that it was too costly. One commenter
suggested that the ``costs associated with off-site disposal of oil-
saturated soil from a typical secondary containment facility after a
contained spill event will cost an operator as much as $4,700,
calculated at the cost of $90 per ton of removed soil for
transportation and disposal fees and the associated leachate and waste
analysis but excluding the internal costs associated with the actual
excavation work.'' Other commenters believed that we have no authority
to ask the question because the subject matter is regulated either by
State law or another Federal program, such as the solid waste program.
One commenter asked for an exemption for mobile facilities from this
requirement.
Contact list. Several commenters favored the proposal. One
commenter suggested that the list name the cleanup contractor with whom
the facility has a relationship, not merely the name of any cleanup
contractor.
One commenter favored the inclusion of local emergency planning
contacts in the required information. Another opposed it as duplicative
of information in the HAZWOPER Plan. A commenter requested an exemption
for mobile facilities. Another commenter believed we lack authority to
request the information. One commenter suggested that the list be
restricted to Federal or State agencies that must be notified in case
of the accidental discharge of oil. Another commenter argued that
mobile drilling and workover rigs either on or off shore should be
exempt from this requirement because supplying site specific spill and
clean-up information for a mobile source that will move from one site
to another is not feasible. One commenter suggested that this paragraph
should be deleted and removed to a response plan section which he
suggested, because the information called for requires response
information.
Downstream water suppliers. Several commenters suggested that the
proposed requirement to include information on downstream water
suppliers who must be contacted in case of a discharge to navigable
waters should be limited to those ``who might reasonably be affected by
a discharge.'' Others asked that the downstream distance be specified.
They added that private wells should be excluded from the notice.
Several
[[Page 47097]]
commenters asked how they might identify such suppliers. Yet others
believed that such notification was the responsibility of local
emergency response agencies.
Response to comments. General description of characteristics. The
following characteristics must be described on a per container basis:
the storage capacity of the container, type of oil in each container,
and secondary containment for each container. The other characteristics
may be described on a facility basis. We disagree that these
requirements are too resource intensive. The major new requirement in
Sec. 112.7(a)(3) is the facility diagram. Based on site inspections and
professional judgment, we estimate unit costs for compliance with this
section to be $33 for a small facility, $39 for a medium facility, and
$5 for a large facility. Large facilities are assumed to already have a
diagram that may be attached to the SPCC Plan. The other items
mentioned in Sec. 112.7(a)(3)--storage capacity of each container,
prevention measures, discharge controls, countermeasures, disposal
methods, and the contact list--are already required under the current
rule or required by good engineering practice. As described in the
Information Collection Request for this rule, the cost of Plan
preparation includes these items, e.g., field investigations to
understand the facility design and to predict flow paths and potential
harm, regulatory review, and spill prevention and control practices.
Providing information on a container-specific basis helps the
facility to prioritize inspections and maintenance of containers based
on characteristics such as age, capacity, or location. It also helps
inspectors to prioritize inspections of higher-risk containers at a
facility. Container-specific information helps an inspector verify the
capacity calculation to determine whether a Plan is needed; and, helps
to formulate contingency planning if such planning is necessary.
Facility diagram. The facility diagram is important because it is
used for effective prevention, planning, management (for example,
inspections), and response considerations and we therefore believe that
it must be part of the Plan. The diagram will help the facility and
emergency response personnel to plan for emergencies. For example, the
identification of the type of oil in each container may help such
personnel determine the risks when conducting a response action. Some
oils present a higher risk of fire and explosion than other less
flammable oils.
Inspectors and personnel new to the facility need to know the
location of all containers subject to the rule. The facility diagram
may also help first responders to determine the pathway of the flow of
discharged oil. If responders know possible pathways, they may be able
to take measures to control the flow of oil. Such control may avert
damage to sensitive environmental areas; may protect drinking water
sources; and may help responders to prevent discharges to other
conduits leading to a treatment facility or navigable waters. Diagrams
may assist Federal, State, or facility personnel to avoid certain
hazards and to respond differently to others.
The facility diagram is necessary for all facilities, large or
small, because the rationale is the same for both. While some States
may require a diagram, others do not. SPCC is a Federal program
specifying minimum requirements, which the States may supplement with
their own more stringent requirements. We note that State plans may be
used as SPCC Plans if they meet all Federal requirements, thus avoiding
any duplication of effort if the State facility diagram meets the
requirements of the Federal one.
Facility diagram--container contents. The facility diagram must
include all fixed (i.e., not mobile or portable) containers which store
55 gallons or more of oil and must include information marking the
contents of those containers. If you store mobile containers in a
certain area, you must mark that area on the diagram. You may mark the
contents of each container either on the diagram of the facility, or on
a separate sheet or log if those contents change on a frequent basis.
Marking containers makes for more effective prevention, planning,
management, and response. For example, a responder may take one type of
emergency measure for one type of oil, and another measure for another
type. As noted above, oils differ in their risk of fire and explosion.
Gasoline is highly flammable and volatile. It presents the risk of fire
and inhalation of vapors when discharged. On the other hand, motor oil
is not highly flammable, and there is no inhalation of vapors hazard
associated with its discharge.
In an emergency, the responder may not have container content
information unless it is clearly marked on a diagram, log, or sheet.
For emergency response purposes, we also encourage, but do not require
you to mark on the facility diagram containers that store CWA hazardous
substances and to label the contents of those containers. When the
contents of an oil container change, this may or may not be a material
change. See the discussion on Sec. 112.5(a).
Facility diagram--De minimis containers. We have established a de
minimis container size of less than 55 gallons. You do not have to
include containers less than 55 gallons on the facility diagram.
Facility diagram--Transfer stations, connecting pipes, and USTs. We
agree that all facility transfer stations and connecting pipes that
handle oil must be included in the diagram, and have amended the rule
to that effect. This inclusion will help facilitate response by
informing responders of the location of this equipment. The location of
all containers and connecting pipes that store oil (other than de
minimis containers) must be marked, including USTs and other containers
not subject to SPCC rules which are present at SPCC facilities. Again,
this is necessary to facilitate response by informing responders of the
location of these containers.
Unit-by-unit storage capacity. For clarity, we have changed the
term in Sec. 112.7(a)(3)(i), ``unit-by-unit'' storage capacity, to
``type of oil in each container and its storage capacity.'' As noted
earlier, this requirement applies only to containers of 55 gallons or
greater.
Type and quantity of oil stored. We have eliminated proposed
Sec. 112.7(a)(3)(ii) because it repeats information requested in
revised Sec. 112.7(a)(3)(i). We ask for information concerning storage
capacity and type of oil stored in each container in that paragraph.
Estimates of quantity of oils potentially discharged. We have
eliminated proposed Sec. 112.7(a)(3)(iii) because it repeats
information sought in Sec. 112.7(b) regarding ``a prediction of the
direction, rate of flow, and total quantity of oil which could be
discharged* * * .'' We will address the substantive comments under the
discussion of that paragraph.
Possible spill pathways. We have eliminated proposed
Sec. 112.7(a)(3)(iv) because the proposal repeats information sought in
Sec. 112.7(b) regarding ``a prediction of the direction, rate of flow,
and total quantity of oil which could be discharged.* * *'' Again, we
will address the substantive comments under the discussion of that
paragraph.
Spill prevention measures. We have revised this paragraph to read
``discharge prevention measures.'' We disagree with the commenter that
the paragraph should be labeled ``secondary containment.'' The term
``discharge prevention measures'' is better because
[[Page 47098]]
it encompasses both secondary containment and other discharge
prevention measures.
Spill controls and secondary containment. We have revised this
paragraph to refer to ``discharge'' controls. In response to a
commenter, we have also included a reference to drainage controls in
the paragraph because drainage systems or diversionary ponds might be
an alternative means of secondary containment. See
Sec. 112.7(c)(1)(iii) and (v).
Spill countermeasures. We disagree that the paragraph should be
revised to read, ``Prevention, control, or countermeasure features,
other than secondary containment and drainage control, and the
equipment which they protect,'' because we believe that the language we
proposed, as revised, better captures the information we are seeking.
Our revised language refers to discovery, response, and cleanup, which
are features that are absent from the commenter's suggestion, and for
which a discussion in the Plan is necessary in order to be prepared for
any discharges.
We disagree that either onshore or offshore mobile drilling and
workover rigs should be exempted from this requirement because the
information necessary to this requirement is not always site specific,
and may be included in a general plan for a mobile facility.
We also disagree that the information required in this paragraph is
redundant of information required in Secs. 112.7(b) and 112.7(d)(1).
Each of the sections mentioned requires discrete and different
information. Section 112.7(a)(3)(iv) requires information concerning a
facility's and a contractor's capabilities for discharge discovery,
response, and cleanup. Section 112.7(b) requires information concerning
the potential consequences of equipment failure. Section 112.7(d)(1)
requires a contingency plan following the provisions of part 109, which
includes coordination requirements with governmental oil spill response
organizations.
We disagree that the information should be placed in a response
section, because most SPCC facilities are not required to have response
plans, and the information is necessary to prepare for discharge
discovery, response, and cleanup.
Disposal of recovered materials. This provision applies to all
facilities, including mobile facilities, because proper disposal of
recovered materials helps prevent a discharge as described in
Sec. 112.1(b) by ensuring that the materials are managed in an
environmentally sound manner. Proper disposal also assists response
efforts. If a facility lacks adequate resources to dispose of recovered
oil and oil-contaminated material during a response, it limits how much
and how quickly oil and oil-contaminated material is recovered, thereby
increasing the risk and damage to the environment.
We disagree that this paragraph would preclude bioremediation
efforts, as some commenters suggested. Bioremediation may be a method
of proper disposal. The paragraph merely requires that you discuss the
methods employed to dispose of recovered materials; it does not require
that materials recovered be ``disposed'' of in any particular manner
nor is it an independent requirement to properly dispose of materials.
Thus, there is no infringement on or duplication of any other State or
Federal program or regulatory authority. Because it does nothing more
than require that you explain the method of disposal of recovered
materials, we also disagree that this provision is too costly. Also, we
assume that good engineering practice will in many cases include a
discussion of such disposal already. By describing those methods in the
Plan, you help ensure that the facility has done the appropriate
planning to be able to dispose of recovered materials, should a
discharge occur. We support the recycling of spilled oil to the extent
possible, rather than its disposal. For purposes of this rule, disposal
of recovered materials includes recycling of those materials.
We disagree that either onshore or offshore mobile drilling and
workover rigs should be exempted from this requirement because the
information necessary to this requirement is not always site specific,
and may be included in a general plan for a mobile facility.
Contact list. In response to a comment, we have amended the rule to
require that the cleanup contractor listed must be the one with whom
the facility has an agreement for response that ensures the
availability of the necessary personnel and equipment within
appropriate response times. An agreement to respond may include a
contract or some less formal relationship with a cleanup contractor. No
formal written agreement to respond is required by the SPCC rule, but
if you do have one, you must discuss it in the Plan.
We have ample authority to ask for information concerning emergency
contacts under the CWA because it is relevant to the statute's
prevention, preparedness, and response purposes. Furthermore, it is an
appropriate question for all facilities, including mobile facilities,
because it is necessary to prepare for discharges and to aid in prompt
cleanup when they occur. Having a Plan which contains a contact list of
response organizations is a procedure and method to contain a discharge
of oil as specified in CWA section 311(j)(1)(C). However, we have
eliminated references to specific State and local agencies in the event
of discharges in favor of a reference to ``all appropriate State and
local agencies.'' ``Appropriate'' means those State and local agencies
that must be contacted due to Federal or State requirements, or
pursuant to good engineering practice. You may not always be required
to notify fire departments, local emergency planning committees
(LEPCs), and State emergency response commissions (SERCs), nor as an
engineering practice do they always need to receive direct notice from
the facility in the event of a discharge as described in Sec. 112.1(b).
At times they might, but they might also receive notice from other
sources, such as the National Response Center. Other State and local
agencies might also need notice from you.
We have added the word ``Federal'' to the list of all appropriate
contact agencies because there are times when you must notify EPA of
certain discharges. See Sec. 112.4(a). There might also be requirements
under Federal statutes other than the CWA, for notice in such
emergencies.
We disagree that either onshore or offshore mobile drilling and
workover rigs should be exempted from this requirement because the
information necessary to this requirement is not always site specific,
and may be included in a general plan for a mobile facility.
We disagree that the information should be placed in a response
section, because most SPCC facilities are not required to have response
plans, and the information is necessary to prepare for response to an
emergency.
Downstream water suppliers. We have deleted the reference to
``downstream water suppliers'' (i.e., intakes for drinking and other
waters) because facilities may have no way to identify such suppliers.
We agree with commenters that identifying such suppliers is more a
function of State and local emergency response agencies. We note,
however, that facilities that must prepare response plans under
Sec. 112.20 must discuss in those plans the vulnerability of water
intakes (drinking, cooling, or other).
[[Page 47099]]
Editorial changes and clarifications. In the introduction to
paragraph (a)(3), ``physical plant'' becomes ``physical layout.''
``Tanks'' becomes ``containers.'' In proposed paragraph (a)(3)(vi),
redesignated as paragraph (a)(3)(iii), ``spill controls'' becomes
``discharge or drainage controls.'' In proposed paragraph (a)(3)(vii),
redesignated as paragraph (a)(3)(iv), ``spill countermeasures for spill
discovery'' becomes ``countermeasures for discharge discovery.'' In
proposed paragraph (a)(3)(ix), redesignated as paragraph (a)(3)(vi),
``discharge to navigable waters'' becomes ``discharge as described in
Sec. 112.1(b).''
Section 112.7(a)(4)--Spill Reporting Information in the Plan
Background. In 1991, we proposed that documentation in this
paragraph be sufficient to enable a person reporting a spill to provide
essential information to organizations on the contact list.
Comments. Several commenters had editorial comments, suggesting the
rule refer to ``information'' rather than ``documentation'' on the
theory that documentation refers to a past event, whereas the rule
contemplates a future event. One commenter suggested that the section
be qualified to indicate that a form for collecting spill report
information be included in the Plan, or for ``small size facilities''
in the HAZWOPER reporting matrix. Another commenter suggested that a
properly prepared SPCC Plan would assist the person reporting the spill
to provide the requested information. One commenter asserted the
proposed rule was duplicative of State requirements. Several commenters
suggested that not all of the information will be available or
applicable for a person reporting a discharge. One commenter suggested
that this paragraph should be deleted and removed to a response plan
section which he suggested, because the information called for requires
response information.
Response to comments. Documentation. We agree with commenters that
the word ``documentation'' is inappropriate because it refers to a past
event. Accordingly, as suggested by commenters, we have revised the
rule to provide for ``information and procedures'' that would assist
the reporting of discharges as described in Sec. 112.1(b).
``Information'' refers to the facts which you must report, and
``procedures'' refers to the method of reporting those facts. Such
procedures must address whom the person relating the information should
call, in what order the caller should call potential responders and
others, and any other instructions necessary to facilitate notification
of a discharge as described in Sec. 112.1(b). If properly noted, the
information and procedures in the Plan should enable a person reporting
a discharge to accurately describe information concerning that
occurrence to the proper persons in an emergency. Any information or
procedure not applicable will not have to be used. Available
information on a discharge must be reported. Applicable procedures must
be followed. And of course, any information that is not available
cannot be reported.
State requirements. While it is possible that this information may
be duplicative of State requirements, the duplication is eliminated to
the extent that you use your State SPCC Plan for Federal SPCC purposes.
Where there is no State requirement, there is no duplication.
Response plan exemption. We disagree that this paragraph should be
placed in a response section, because most SPCC facilities are not
required to have response plans, and the information is necessary to
prepare for response to an emergency. However, if your facility has
prepared and submitted a response plan to us under Sec. 112.20, there
is no need to document this information in your SPCC Plan, because it
is already contained in the response plan. See Sec. 112.20(h)(1)(i)-
(viii). Therefore, we have amended the rule to exempt those facilities
with response plans from the requirements of this paragraph.
Editorial changes and clarifications. We changed ``address'' to
``address or location'' because some facilities do not have an exact
address. ``Spill'' and ``spilled'' becomes ``discharge as described in
Sec. 112.1(b)'' or ``discharged'' as appropriate in the context,
``discharge'' being a defined term. ``Spill'' or ``spilled'' are not
defined terms. ``The affected medium'' becomes ``all affected media.''
Section 112.7(a)(5)--Emergency Procedures
Background. In 1991, we proposed this paragraph to ensure that
portions of the Plan describing procedures to be used in emergency
circumstances are organized in a manner to make them readily usable in
an emergency.
Comments. One commenter suggested that this paragraph should be
deleted and removed to a response plan section which he suggested,
because the information called for requires response information.
Response to comments. We disagree this paragraph should be deleted
because most SPCC facilities are not required to have a response plan,
and the procedures to be used when a discharge occurs are necessary to
prepare for an emergency. Because this information would repeat
information contained in a response plan submitted under Sec. 112.20,
we have excluded from the requirements of this paragraph those
facilities which have submitted response plans. See
Sec. 112.20(h)(3)(i)-(ix).
Section 112.7(b)--Fault Analysis
Background. In 1991, we proposed only editorial changes to this
paragraph dealing with fault analysis. The proposal would require an
analysis of the major types of failures possible in a facility,
including a prediction of the direction, rate of flow, and total
quantity of oil that could be discharged as a result of each such
failure.
Comments. Applicability. One commenter wrote that the language in
the first sentence of the proposed rule is less clear than current
regulations. The commenter asserted that the proposed revision, perhaps
inadvertently, does not specify the sections to which the certain
``situations'' apply. The commenter suggested that current language is
clearer and specifically focuses limited resources on situations for
which there is a reasonable potential for discharge. The commenter
argued that limited resources should not be consumed in developing flow
rate, direction and quantity predictions in the SPCC Plan for
situations without a reasonable potential for discharge to navigable
waters.
Several commenters asserted that the fault analysis required by
this paragraph is ``too involved for small operators.'' They suggested
that only development of responses to obvious scenarios, such as tank
rupture, should be required. Commenters from the utility industry
suggested that electrical equipment facilities should be exempt from
the requirements in this paragraph. One commenter believed that mobile
facilities should be exempt from the requirements in the paragraph
because the exact site information changes with the movement of
equipment.
Failure factors. One commenter suggested that the rule should also
focus on small discharges, not just ``major'' discharges. Another
commenter asked for clarification as to what is a ``major failure'' and
to what degree of sophistication the pathway prediction must be made.
Another commenter suggested that the rule should adequately describe
how detailed the analysis of potential spill pathways
[[Page 47100]]
should be. Another suggested that it would be impossible to give
estimates of oil potentially discharged from flowlines or gathering
systems.
Response to comments. Applicability. We agree with the commenter
that current language is clearer and will retain it. We therefore
modified the first sentence contained in the proposed rule. We agree
that the Plan must only discuss potential failure situations that might
result in a discharge from the facility, not any failure situation. The
rule requires that when experience indicates a reasonable potential for
failure of equipment, the Plan must contain certain information
relevant to those failures. ``Experience'' includes the experience of
the facility and the industry in general.
We disagree that the requirement is too difficult for owners or
operators of small or mobile facilities, or of flowlines or gathering
lines, or of electrical equipment facilities, or other users of oil. We
believe that a Professional Engineer may evaluate the potential risk of
failure for the aforementioned facilities and equipment and predict
with a certain degree of accuracy the result of a failure from each. We
note that since we have raised the regulatory threshold, this
requirement will not be applicable to many smaller facilities.
Failure factors. To comply with this section, you need only address
``major equipment'' failures. A major equipment failure is one which
could cause a discharge as described in Sec. 112.1(b), not a minor
failure possibility. To help clarify the type of equipment failures the
rule contemplates, we have added examples of other types of failures
that would trigger the requirements of this paragraph. Such other
equipment failures include failures of loading/unloading equipment, or
of any other equipment known to be a source of a discharge. The
analysis required will depend on the experience of the facility and how
sophisticated the facility equipment is. If your facility has simpler
equipment, you will have less to detail. If you have more sophisticated
equipment, you will have to conduct a more detailed analysis. If your
facility's experience or industry experience in general indicates a
higher risk of failure associated with the use of that equipment, your
analysis will also have to be more detailed. This rationale and
analytic detail are also applicable to electrical equipment facilities
and other facilities that do not store oil, but contain it for
operational use. Again, the required explanation will be tailored to
the type of equipment used and the experience with that equipment.
Spill pathways. The level of analysis concerning spill pathways
will depend on the geographic characteristics of the facility's site
and the possibility of a discharge as described in Sec. 112.1(b) that
equipment failure might cause. However, the Professional Engineer
should focus on the most obvious spill pathways.
Because this information is facility specific, the owner or
operator of a mobile facility will not be able to detail spill pathways
in the general Plan for the facility each time the facility moves.
However, the owner or operator must provide management practices in the
general Plan that provide for containment of discharges in spill
pathways in a variety of geographic conditions likely to be
encountered. In case of a discharge at a particular facility, the owner
or operator would then take appropriate action to contain or remove the
discharge. For example, the Plan may provide that a rig must be
positioned to minimize or prevent discharges as described in
Sec. 112.1(b); or it may provide for the use of spill pans, drip trays,
excavations, or trenching to augment discharge prevention.
Editorial changes and clarifications. We made minor editorial
changes in the proposal's second sentence that reflect a plain language
format. We revised the phrase in the proposed second sentence of the
paragraph from ``each major type of failure'' to ``each type of major
equipment failure.''
Section 112.7(c)--Secondary Containment.
Background. The SPCC Task force concluded that aboveground storage
tanks without secondary containment could pose a particularly
significant threat to the environment. We noted in the 1991 preamble
that the proposed rule modifications would ``retain the current
requirement for facility owners or operators who are unable to provide
certain structures or equipment for oil spill prevention, including
secondary containment, to prepare facility-specific contingency plans
in lieu of prevention systems.'' 56 FR 54614.
In 1991, we proposed to modify the current standard that dikes,
berms, or retaining walls must be ``sufficiently impervious.'' We
proposed that the current ``sufficiently impervious'' standard for
secondary containment be replaced with a standard requiring that the
entire containment system, including walls and floor, must be
impervious to oil for 72 hours. The rationale was that a containment
system that is impervious to oil for 72 hours would allow time for
discovery and removal of an oil discharge in most cases.
We also noted that for some facilities such as electrical
substations, compliance with this section might not be practicable. We
said that since their purpose was not the storage of oil in bulk, they
did not need to comply with the secondary containment requirements
designed for bulk storage tanks in Secs. 112.8(c) and 112.9(d), but
only the secondary containment requirements in Sec. 112.7(c), and that
the Sec. 112.7(c) requirement for secondary containment might be
satisfied by various means including drainage systems, spill diversion
ponds, etc. We added that the alternative requirements contained in
proposed Sec. 112.7(d) would fulfill the intent of the CWA when a
facility could not provide secondary containment due to the
impracticability of installation. 56 FR 54621.
Comments. Editorial changes and clarifications. Several commenters
suggested that the reference to prevention of discharges to ``surface
waters'' be changed to prevention of discharges to ``navigable
waters.''
Contingency planning. One commenter suggested revising the rules to
allow the use of the contingency plan contemplated in Sec. 112.7(d)
instead of secondary containment measures. Another commenter asserted
that a contingency plan is not an acceptable substitute for secondary
containment and advocated that all facilities be required to have
secondary containment.
Applicability of requirement. Numerous electric utility commenters
suggested that secondary containment was impractical for their
facilities because it might cause a safety hazard. Instead, they argued
for the use of contingency planning. One commenter asserted that
secondary containment at sites used for the maintenance and operation
of the air traffic control system was also impracticable because those
sites are often very small, isolated, unmanned, and visited only on a
quarterly basis. Another commenter asked that wastewater treatment
tanks be exempted from the secondary containment requirement because
their use is not to store oil, but to treat water. Other containers not
used for storage, but other purposes might include stormwater surge
tanks, activated sludge aeration tanks, equalization basins, dissolved
and inducted air floatation tanks, oil/water separators, sludge
digesters, etc. Another commenter urged that all oil-filled equipment
located in a 25-year floodplain be required to have secondary
containment.
[[Page 47101]]
One commenter asked that we clarify that the secondary containment
requirement in this section does not apply to the following equipment
at onshore production facilities: flowlines because of the prohibitive
cost of construction for miles of lines; fired vessels because of the
danger of pooling spilled oil around an ignition source; and,
pressurized vessels because a leak from such vessel might be sprayed
beyond the area that a reasonable dike might enclose. One commenter
suggested that all in-use hydraulic equipment such as cranes, jacks,
elevators, forklifts, etc., be exempted from the secondary containment
requirement because it would be impractical to provide structures for
such equipment. Others suggested that mobile facilities should be
exempt from the secondary containment requirement because it would be
infeasible to provide it. Similarly, one commenter suggested that the
requirement was infeasible for production facilities due to their
sometimes remote locations or difficult terrain and soil conditions.
Yet another commenter wanted us to clarify that underground piping is
not subject to the rule's secondary containment provisions.
One commenter asserted that mining sites should be exempted from
the secondary containment requirement because the containment
requirements would be ``excessive'' for such sites and result in
``little resultant net environmental benefit.'' A commenter
representing various small facilities asked for exemption from the
requirement on the basis that the risk is lower for those facilities.
Methods of secondary containment. As to methods of secondary
containment, several commenters urged that the existence of ``natural''
structures and/or drainage could meet this requirement. Other
commenters suggested that vaulted tanks or double-walled tanks in
themselves meet the secondary containment requirement. One commenter
suggested that we remove sorbent materials or booms from the list of
acceptable secondary containment structures because they are not a
substitute for impervious dikes and impoundment floors.
72-hour impermeability standard. We received numerous comments on
the proposed 72-hour impermeability standard. Several commenters
favored the standard. Many were opposed. Of the opponents, some favored
the current standard that the dikes, berms or retaining walls be
``sufficiently impervious'' to contain spilled oil. Other commenters
thought that the proposed requirement to prevent escape of oil to
surface waters should be replaced with a standard of preventing the
escape of oil to ``the environment'' or to ``navigable waters.'' Others
asked for clarification of the term ``impervious,'' asserting that it
is a qualitative term that requires definition by engineering
standards. One commenter requested that if an impervious containment
system cannot be provided, that facilities be required to assure that
conduits that may cause substantial migration of free products are
appropriately monitored for discharges. Another commenter asked us to
specify acceptable liner materials, in lieu of a total imperviousness
requirement.
Costs. One commenter suggested that our industry cost estimate for
the proposed 1991 regulations--of $441 million in the first year and
$71.8 million each subsequent year--was erroneously low, but did not
provide his own cost estimates. The commenter came to this conclusion
by calculating compliance cost estimates for the following
requirements: 72-hour impermeability for secondary containment and
diked areas, and installation of containment systems at all truck
loading locations. The commenter estimated the cost of the effects of
two proposed items for New York oil and gas producers, not all us
producers, at in excess of $78 million; he estimated the cost of the
proposed 72 hour oil impermeability requirement at $48 million, and if
earthen dikes and diked areas cannot meet the secondary containment
standards at truck loading areas, at least $30 million.
Alternate impermeability standards. Commenters suggested a number
of alternate impermeability standards. One commenter suggested a
standard that the containment system be impervious to oil and water for
72 hours. Another commenter suggested that the standard apply only in
environmentally sensitive areas. Some suggested that the standard
should be inapplicable at facilities that are staffed around the clock,
seven days a week. One commenter suggested a phase-in of the
requirement. Some thought that the impermeability standard should not
apply to heavier oils, particularly number 5 and 6 oils.
Alternate time frames. Others suggested differing time standards in
lieu of 72 hours such as 24 hours at manned facilities, 36 hours or
increased inspections, ``as soon as practicable,'' ``for the duration
of the response,'' or no time limit at all. One commenter asked when
the 72 hours begins to run, whether it begins at the time of the
discovery of the discharge or the time of occurrence.
Containment or impermeability. Other commenters asserted that the
rule should address containment rather than impermeability because they
assert that the point of a containment structure is ``to keep the
discharge from reaching the waters of the United States.'' In the same
vein, two commenters asked EPA to clarify that the leaching of small
amounts of oil that does not reach the water table or surface waters
meets the impermeability requirement, while a third asked that we
clarify that we are concerned only with horizontal rather than vertical
discharges of oil.
Sufficient freeboard. See the comments to Sec. 112.8(c)(2) under
this topic.
Response to comments. Contingency planning. A contingency plan
should not be used routinely as a substitute for secondary containment
because we believe it is normally environmentally better to contain oil
than to clean it up after it has been discharged. Secondary containment
is intended to contain discharged oil so that it does not leave the
facility and contaminate the environment. The proper method of
secondary containment is a matter of good engineering practice, and so
we do not prescribe here any particular method. Under part 112, where
secondary containment is not practicable, you may deviate from the
requirement, provide a contingency plan following the provisions of 40
CFR part 109, and comply with the other requirements of Sec. 112.7(d).
For bulk storage containers, those requirements include both periodic
integrity testing of the containers and periodic integrity and leak
testing of the valves and piping. You must also provide a written
commitment of manpower, equipment, and materials to expeditiously
control and remove any quantity of oil discharged that may be harmful.
Applicability of requirement. Secondary containment is best for
most facilities storing or using oil because it is the most effective
method to stop oil from migrating beyond that containment. We believe
that secondary containment is preferable to a contingency plan at
manned and unmanned facilities because it prevents discharges as
described in Sec. 112.1(b). At unmanned facilities, it may be even more
important because of the lag in time before a discharge may be
discovered. Notwithstanding what may be difficult terrain, we believe
that some form of secondary containment is practicable at most
facilities, including remote production facilities. In fact, it may
often be more feasible in remote or rural areas because there are fewer
space limitations in such areas. For example,
[[Page 47102]]
at some remote mobile or production facilities, owners or operators dig
trenches and line them for containment or retention of drilling fluids.
Technologies used at offshore facilities to catch or contain oil may
also sometimes be used onshore.
While some types of secondary containment (for example, dikes or
berms) may not be appropriate at certain facilities, other types (for
example, diversionary systems or remote impounding) might. However, we
recognize and repeat, as we noted in the 1991 preamble, that some or
perhaps all types of secondary containment for certain facilities with
equipment that contain oil, such as electrical equipment, may be
contrary to safety factors or other good engineering practice
considerations. There might be other equipment, like fired or
pressurized vessels, for which safety considerations also preclude some
or all types of secondary containment.
Some facilities or equipment that use but do not store oil may or
may not, as a matter of good engineering practice, employ secondary
containment. Such facilities might include wastewater treatment
facilities, whose purpose is not to store oil, but to treat water.
Other facilities that may not find the requirement practicable are
those that use oil in equipment such as hydraulic equipment. Similarly,
flowlines must have a program of maintenance to prevent discharges. See
Sec. 112.9(d)(3). The maintenance program may or may not include
secondary containment. Owners or operators of underground piping must
have some form of corrosion protection, but do not necessarily have to
use secondary containment for that purpose.
As stated above, for a facility where secondary containment is not
practicable, the owner or operator is not exempt from the requirement,
but may instead provide a contingency plan and take other measures
required under Sec. 112.7(d). For most facilities, however, including
small facilities, mobile facilities, production facilities, mining
sites, and any other facilities that store or use oil, we believe that
secondary containment is generally necessary and appropriate to prevent
a discharge as described in Sec. 112.1(b). Without secondary
containment, discharges from containers would often reach navigable
waters or adjoining shorelines, or affect natural resources.
Methods of secondary containment. The appropriate method of
secondary containment is an engineering question. Earthen or natural
structures may be acceptable if they contain and prevent discharges as
described in Sec. 112.1(b), including containment that prevents
discharge of oil to groundwater that is connected to navigable water.
What is practical for one facility, however, might not work for
another. If secondary containment is not practicable, then the facility
must provide a contingency plan following the provisions of 40 CFR part
109, and otherwise comply with Sec. 112.7(d).
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 Sec. 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 Sec. 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.
Completely buried tanks. Completely buried tanks, other than those
exempted from this rule because they are subject to all technical
Federal or State UST requirements, are subject to the secondary
containment requirement. We realize that the concept of freeboard for
precipitation is inapplicable to secondary containment for completely
buried tanks. The requirement for secondary containment may be
satisfied in any of the ways listed in the rule or their equivalent.
72-hour impermeability standard. We are withdrawing the proposal
for the 72-hour impermeability standard and will retain the current
standard that dikes, berms, or retaining walls must be sufficiently
impervious to contain oil. We agree with commenters that the purpose of
secondary containment is to contain oil from escaping the facility and
reaching the environment. The rationale for the 72-hour standard was to
allow time for the discovery and removal of an oil spill. An owner or
operator of a facility should have flexibility in how he prevents a
discharge as described in Sec. 112.1(b), and any method of containment
that achieves that end is sufficient. Should such containment fail, the
owner or operator must immediately clean up any discharged oil.
Similarly, because the purpose of the ``sufficiently impervious''
standard is to prevent discharges as described in Sec. 112.1(b), dikes,
berms, or retaining walls must be capable of containing oil and
preventing such discharges. Discharges as described in Sec. 112.1(b)
may result from direct discharges from containers, or from discharges
from containers to groundwater that travel through the groundwater to
navigable waters. Effective containment means that the dike, berm, or
retaining wall must be capable of containing oil and sufficiently
impervious to prevent discharges from the containment system until it
is cleaned up. The same holds true for container floors or bottoms;
they must be able to contain oil to prevent a discharge as described in
Sec. 112.1(b). However, ``effective containment'' does not mean that
liners are required for secondary containment areas. Liners are an
option for meeting the secondary containment requirements, but are not
required by the rule.
If you are the owner or operator of a facility subject to this
part, you must prepare a Plan in accordance with good engineering
practice. A complete description of how secondary containment is
designed, implemented, and maintained to meet the standard of
sufficiently impervious is necessary. In order to document that
secondary containment is sufficiently impervious and sufficiently
strong to contain oil until it is cleaned up, the Plan must describe
how the secondary containment is designed to meet that standard. A
written description of the sufficiently impervious standard is not only
necessary for design and implementation, but will aid owners or
operators of facilities in determining which practices will be
necessary to maintain the standard of sufficiently impervious. Control
and/or removal of vegetation may be necessary to maintain the
impervious integrity of the secondary containment. Repairs of
excavations or other penetrations through secondary containment will
need to be conducted in accordance with good engineering practices in
order to maintain the standard of sufficiently impervious. The owner or
operator should monitor such imperviousness for effectiveness, in order
to be sure that the method chosen remains impervious to contain oil.
[[Page 47103]]
Costs. We note that we have withdrawn the proposed 72 hour
standard, and afford various secondary containment options, including
earthen dikes and diked areas, if they contain and prevent discharges
as described in Sec. 112.1(b). Therefore, there are no new costs. We
disagree with the commenters who asserted that we underestimated the
cost to comply with the secondary containment and truck loading and
unloading area requirements. The revised rule, like the current rule,
does not require a specific impermeability for dikes and does not
require a specific method of secondary containment at loading and
unloading areas, and this flexibility is reflected in our cost
estimates. We noted in our 1991 Supplemental Cost/Benefit Analysis that
secondary containment for bulk storage tanks is estimated to cost
$1,000 for small facilities; $6,400 for medium facilities; and $63,000
for large facilities. Unit cost estimates were developed for a broad
mix of facilities (e.g., farms, bulk petroleum terminals) in each size
category by experienced engineers with firsthand knowledge of the Oil
Pollution Prevention Regulation and the operations of onshore SPCC-
regulated facilities. Because our cost estimates must be representative
of the many types of facilities that are regulated, they will
underestimate the costs for some facility types and overestimate the
costs for others. Facilities were assumed to construct secondary
containment systems of impervious soil capable of holding 110 percent
of the largest tank. In that analysis, we estimated that 78 percent and
88 percent of the regulated community were already in compliance with
these requirements, respectively, and would not be affected by the
proposed rule change.
Since we last performed these analyses, API has issued several
industry standards, including API 653 and 2610, which address many of
the provisions in the SPCC rule. As a result, the final rule relies on
current industry standards and practices, where feasible. In the final
rule, we withdrew the proposed 72-hour impermeability standard for
secondary containment and maintained the current requirement that
dikes, berms, and oil retaining walls must be sufficiently impervious
to contain oil. As a result, the final rule reflects current industry
standards and we assume poses no additional requirements on industry.
Sufficient freeboard. See the Response to Comments in
Sec. 112.8(c)(2) for a discussion of this topic.
Industry standards. Industry standards that may assist an owner or
operator with secondary containment include: (1) NFPA 30; (2) BOCA,
National Fire Prevention Code; and, (3) API Standard 2610, ``Design,
Construction, Operation, Maintenance, and Inspection of Terminal and
Tank Facilities.''
Editorial changes and clarifications. In the introduction to
paragraph (c), ``structures or equipment to prevent discharged oil from
reaching a navigable water course'' becomes ``structures or equipment
to prevent a discharge as described in Sec. 112.1(b).'' This wording
change reflects the expanded scope of the CWA as reflected in
Sec. 112.1(b) and is clearer than the proposed language. In the second
sentence of the paragraph, we deleted the words ``permeate, drain,
infiltrate, or otherwise'' from the sentence because they were
unnecessary. The word ``escape'' in that sentence is sufficient. Also
in that sentence, the reference to ``escape to surface waters'' becomes
``escape from the containment system.'' This language more clearly
reflects the intent of the rule that secondary containment should keep
oil from escaping from the facility and reaching navigable waters or
adjoining shorelines. In paragraph (c)(2)(i), ``curbing, drip pans''
becomes ``curbing or drip pans.''
In response to the commenter's question, we note that a primary
containment system is the container or equipment which holds oil or in
which oil is used.
Section 112.7(d)--Contingency Planning
Background. 1991 proposal. In 1991, we proposed to add several new
requirements to the contingency planning requirement in Sec. 112.7(d).
First, we proposed that a facility without secondary containment be
required to test a tank for integrity every five years. In contrast,
our 1991 proposal for Sec. 112.8(c)(6) provided for testing at least
every 10 years for a tank with secondary containment. In addition, we
proposed to require a facility without secondary containment to conduct
integrity and leak testing of valves and piping at least annually. We
also proposed that the contingency plan be submitted to the Regional
Administrator for approval.
Instead of referring to 40 CFR part 109 for contingency plan
requirements as the current rule does, the 1991 proposal added specific
requirements including a description of response plans; personnel
needs; methods of mechanical containment; removal of spilled oil; and,
access to and availability of sorbents, booms, and other equipment.
Additionally, the proposal would have required that the Plan not rely
on dispersants and other chemicals for response to oil spills without
approval by the Regional Administrator. The owner or operator of a
facility would also have been required to provide a written commitment
of manpower, equipment, and materials required to quickly control and
remove any quantity of oil that may be discharged.
1993 proposal. In 1993, we modified the 1991 proposal for a
facility that lacks secondary containment to require a facility
response plan as described in Sec. 112.20, instead of the specific
requirements proposed in 1991. The response plan would not be submitted
to the Regional Administrator for his review, unless otherwise
required, but would be maintained at the facility with the SPCC Plan.
Comments. 1991 comments. Many commenters supported the 1991
proposal. Opposing commenters suggested that such planning should be
discretionary because not all facilities need such planning, or that
facilities be allowed to use contingency plans prepared for other
purposes. Others thought the proposal was premature as we had not at
the time finalized response planning requirements in Sec. 112.20. One
commenter argued that we should delete all of the contingency planning
requirements in Sec. 112.7(d) at the point when we require an owner or
operator to prepare a response plan. Some said that contingency
planning was not practicable because the costs are too high, but
commenters did not provide cost estimates. Several commenters
criticized the proposed requirement that the contingency plan be
submitted to the Regional Administrator, calling it duplicative, time-
consuming, and unnecessary. Two commenters suggested that the
Contingency Plan prepared under RCRA rules would suffice.
Representatives of small facilities asked for a small facility
exemption. Others asked for clarification of what a ``written
commitment'' of manpower, equipment, and materials meant. Several
commenters asked if PE certification of the contingency plan was
necessary. One commenter opposed any requirement to provide contingency
planning for buried tanks, piping, or valves for which secondary
containment cannot be provided.
Integrity and leak testing. Several commenters supported the
proposed integrity and leak testing requirements. Others opposed them,
some on the basis that facilities already inspect their tanks
regularly. Various commenters suggested exemptions for small containers
or containers that are entirely within buildings. Electrical utilities
argued that the requirement was
[[Page 47104]]
inapplicable for them because they do not store oil and that such
testing would cause disruption in electrical service. Mining interests
likewise asked for an exemption on the basis that they only store small
amounts of oil and the requirements would be very expensive, but did
not provide specific cost estimates. Various commenters asked for
clarification of the term ``integrity testing,'' and its applicability.
Others asked for clarification as to methods of testing. Some argued
that testing of valves and gathering lines would be expensive and
result in shut-downs of operations. None of these commenters provided
specific cost estimates.
1993 proposal. One commenter argued that the response plan proposal
was beyond our statutory authority. Others argued that the proposal was
expensive and lacking in environmental benefit. One commenter said that
the installation of structures or measures achieving equivalent
protection should be sufficient to avert the need for a response plan.
Another suggested that the current rule, which specifies use of a
strong oil spill contingency plan following 40 CFR part 109, is
adequate. One commenter asked for an exemption for facilities in areas
historically not subject to natural disasters. Electrical utility
commenters asked for an exemption because they argued that a response
plan was unnecessary for facilities that use, but do not store, oil.
Response to comments. Planning requirements. We note that we did
not finalize the 1991 or 1993 contingency planning proposals. Thus
there are no new costs for such planning.
Under the current rule, contingency planning is necessary whenever
you determine that a secondary containment system for any part of the
facility that might be the cause of a discharge as described in
Sec. 112.1(b) is not practicable. This requirement applies whether the
facility is manned or unmanned, urban or rural, and for large and small
facilities. In response to comment, we have revised the rule to exempt
from the contingency planning requirement any facility which has
submitted a response plan under Sec. 112.20 because such a response
plan is more comprehensive than a contingency plan following part 109.
We believe that it may be appropriate for an owner or operator to
consider costs or economic impacts in determining whether he can meet a
specific requirement that falls within the general deviation provision
of Sec. 112.7(a)(2). We believe so because under this section, the
owner or operator will still have to utilize good engineering practices
and come up with an alternative that provides ``equivalent
environmental protection.'' However, we believe that the secondary
containment requirement in Sec. 112.7(d) is an important component in
preventing discharges as described in Sec. 112.1(b) and is
environmentally preferable to a contingency plan prepared under 40 CFR
part 109. Thus, we do not believe it is appropriate to allow an owner
or operator to consider costs or economic impacts in any determination
as to whether he can satisfy the secondary containment requirement.
Instead, the owner or operator may only provide a contingency Plan in
his SPCC Plan and otherwise comply with Sec. 112.7(d). Therefore, the
purpose of a determination of impracticability is to examine whether
space or other geographic limitations of the facility would accommodate
secondary containment; or, if local zoning ordinances or fire
prevention standards or safety considerations would not allow secondary
containment; or, if installing secondary containment would defeat the
overall goal of the regulation to prevent discharges as described in
Sec. 112.1(b).
We disagree that facility response planning is beyond our statutory
authority, it is a procedure or method to remove discharged oil. See
section 311(j)(1)(A) of the CWA. However, while we disagree that such
planning is expensive and lacking in environmental benefit, we agree
that the current contingency plan arrangements which reference 40 CFR
part 109 should be sufficient to protect the environment, and that a
facility response plan as described in Sec. 112.20 is therefore
unnecessary for a facility that is not otherwise subject to
Sec. 112.20. We agree with the commenter that structures or equipment
might achieve the same or equivalent protection as response planning
for some SPCC facilities. Therefore, we are withdrawing that part of
the 1993 proposal related to response planning in proposed
Sec. 112.7(d)(1), but are retaining the current contingency planning
provisions, which require a contingency plan following the provisions
of 40 CFR part 109. We also believe that response plans should be
reserved for higher risk facilities, as provided in Sec. 112.20.
In following the provisions of part 109, you must address the oil
removal contingency planning criteria listed in 40 CFR 109.5 and ensure
that all response actions are coordinated with governmental oil spill
response organizations. The absence of secondary containment will place
extreme importance on the early detection of an oil discharge and rapid
response by the facility to prevent that discharge. Part 109 was
originally promulgated to assist State and local government oil spill
response agencies to prepare oil removal contingency plans in the
inland response zone, where EPA provides the On-Scene Coordinator. The
basic criteria for contingency planning listed in Sec. 109.5 apply to
any SPCC regulated facility that has adequately justified the
impracticability of installing secondary containment, irrespective of
whether it is a government agency or the facility is located in the
coastal (U.S. Coast Guard) or inland (EPA) response zone. Because the
contingency plan involves good engineering practice and is technically
a material part of the Plan, PE certification is required.
A contingency plan prepared under RCRA rules might suffice for
purposes of the rule if the plan fulfills the requirements of part 109,
and the PE certifies that such plan is adequate for the facility. If
the RCRA contingency plan satisfies some but not all SPCC requirements,
you must supplement it so that it does.
We note that the preamble to the 1993 proposed rule (at 58 FR 8841)
suggested that response plans would not have to be submitted to the
Regional Administrator unless ``otherwise required by the rest of
today's proposed rule.'' However, proposed Sec. 112.7(a)(2) would have
required that the owner or operator submit to the Regional
Administrator any Plan containing a proposed deviation, including a
deviation for the general secondary containment requirements in
Sec. 112.7(c). In any case, we agree with commenters that the
contingency plan (or any other deviation) should not have to be
submitted to the Regional Administrator for his review and approval
because we believe that it is sufficient that the contingency plan (or
other deviation) be available for on-site inspection. We have therefore
withdrawn that part of the proposal. See also the discussion on
Sec. 112.7(a)(2).
Integrity and leak testing. In response to a commenter who asked
for a clarification of 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. Facility
components that might cause a discharge as described in Sec. 112.1(b)
include containers, piping, valves, or other equipment or devices.
Integrity testing includes, but is not limited to, testing foundations
and supports of containers. Its scope includes both the
[[Page 47105]]
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. Such testing is also
applicable to valves and piping. See API Standard 653 for further
information on this term.
Leak testing for purposes of the rule is testing to determine the
liquid tightness of valves and piping and whether they may discharge
oil. Facilities that store oil, whether they are mines or other
businesses, are required to employ integrity testing for their bulk
storage containers, and integrity and leak testing for their valves and
piping, to help prevent discharges. Containers that do not store oil,
but merely use oil, are not subject to the requirement.
We reaffirm the applicability of integrity and leak testing to both
large and small facilities, because we believe such testing
requirements help prevent discharges as described in Sec. 112.1(b) at
those facilities. However, we have modified our proposal in response to
comments to only require such testing on a periodic basis instead of at
a prescribed frequency. Integrity and leak testing requirements are
also applicable for containers and valves and piping that are entirely
within buildings, or within mines, because in either case, such
containers, or valves and piping may become the source of a discharge
as described in Sec. 112.1(b). We have revised the rule to reflect that
the requirement applies only to onshore and offshore bulk storage
facilities. Therefore, a facility with only oil-filled electrical,
operating, or manufacturing equipment need not conduct such testing nor
incur any costs for such testing. For other types of facilities, we
disagree that testing of valves and gathering lines would be
prohibitively costly. In 1991, we estimated tank integrity testing and
leak testing costs of buried piping. We estimated the costs as $465 per
tank, $155 for equipment, and $310 for installation. Small facilities
were assumed to have no buried piping. Medium sized facilities were
assumed to bear first year costs for tank installation and testing of
$4,704 and subsequent year costs of $1,449. Large facilities were
assumed to incur a first year cost of $11,313, and subsequent year
costs of $3,519. We assume that this provision represents a negligible
additional burden because most facilities are already testing such
valves and gathering lines according to industry standards as a matter
of good engineering practice. We believe that if such testing is done
in accordance with industry standards, costs will be minimized.
We have eliminated the proposed frequency of the testing, both for
containers and for valves and piping, in favor of testing according to
industry standards. Instead, we require ``periodic'' integrity testing
of containers, and ``periodic'' integrity and leak testing of valves
and piping. ``Periodic'' testing means testing according to a regular
schedule consistent with accepted industry standards. We believe that
use of industry standards, which change over time, will prove more
feasible than providing a specific and unchanging regulatory
requirement. As required by Sec. 112.8(c)(6), integrity testing of
containers must be accomplished by a combination of visual testing and
some other technique.
Written commitment. A ``written commitment'' of manpower,
equipment, and materials means either a written contract or other
written documentation showing that you have made provision for those
items for response purposes. Such commitment must be shown by: the
identification and inventory of applicable equipment, materials, and
supplies which are available locally and regionally; an estimate of the
equipment, materials, and supplies which would be required to remove
the maximum oil discharge to be anticipated; and, development of
agreements and arrangements in advance of an oil discharge for the
acquisition of equipment, materials, and supplies to be used in
responding to such a discharge. 40 CFR 109.5(c).
The commitment also involves making provisions for well defined and
specific actions to be taken after discovery and notification of an oil
discharge including: specification of an oil discharge response
operating team consisting of trained, prepared, and available operating
personnel; predesignation of a properly qualified oil discharge
response coordinator who is charged with the responsibility and
delegated commensurate authority for directing and coordinating
response operations and who knows how to request assistance from
Federal authorities operating under current national and regional
contingency plans; a preplanned location for an oil discharge response
operations center and a reliable communications system for directing
the coordinated overall response actions; provisions for varying
degrees of response effort depending on the severity of the oil
discharge; and, specification of the order of priority in which the
various water uses are to be protected where more than one water use
may be adversely affected as a result of an oil discharge and where
response operations may not be adequate to protect all uses. 40 CFR
109.5(d).
Industry standards. Industry standards that may assist an owner or
operator with the integrity testing of containers, and the integrity
and leak testing of piping and valves include: (1) API Standard 653,
``Tank Inspection, Repair, Alteration, and Reconstruction''; (2) API
Recommended Practice 575, ``Inspection of Atmospheric and Low-Pressure
Tanks''; (3) API Standard 570, ``Piping Inspection Code (Inspection,
Repair, Alteration, and Rerating of In-Service Piping Systems)''; (4)
American Society of Mechanical Engineers (ASME) B31.3, ``Process
Piping''; (5) ASME 31.4, ``Liquid Transportation Systems for
Hydrocarbons, Liquid Petroleum Gas, Anhydrous Ammonia, and Alcohols'';
(6) Steel Tank Institute Standard SP001-00, ``Standard for Inspection
of In-Service Shop Fabricated Aboveground Tanks for Storage of
Combustible and Flammable Liquids''; and, (7) Underwriters Laboratory
(UL) Standard 142, ``Steel Aboveground Tanks for Flammable and
Combustible Liquids.''
Editorial changes and clarifications. In the introductory
paragraph, ``tanks'' becomes ``containers.'' We revised the first
sentence of the introduction which now reads, ``When it is determined *
* *,'' to read, ``If you determine * * *.'' Later in that sentence we
change the words ``demonstrate such impracticability'' to ``explain why
such measures are not practicable,'' in referencing the
impracticability of secondary containment. Also, in the first sentence
of the introduction, we clarify that the requirement for contingency
planning and other measures is applicable when secondary containment is
not practicable under Secs. 112.8(c)(2), 112.8(c)(11), 112.9(c)(2),
112.10(c), 112.12(c)(2), 112.12(c)(11), 112.13(c)(2), and 112.14(c), as
well as Sec. 112.7(c) and (h)(1). Additionally in that sentence, the
reference to ``prevent discharged oil from reaching navigable waters''
becomes ``to prevent a discharge as described in Sec. 112.1(b),''
conforming the geographic scope of the rule to the CWA. At the end of
the paragraph we clarify that when secondary containment is not
practicable, the contingency plan and written commitment must be
provided in the Plan, rather than to the Regional Administrator. We
also clarify that if you have submitted a facility response plan under
Sec. 112.20 for a facility, you need not provide for that facility
either a contingency plan following the provisions of part 109, nor a
written commitment of manpower, equipment, and materials required to
expeditiously
[[Page 47106]]
control and remove any quantity of oil discharged that may be harmful.
In paragraph (d)(1), ``A strong oil spill contingency plan
following the provision of 40 CFR part 109 * * *.'' becomes ``An oil
spill contingency plan following the provisions of part 109 * * *.''
The word ``strong'' is unnecessary because in any case the contingency
plan must follow the provisions of part 109.
In paragraph (d)(2), we did not finalize the proposed
recommendation for the operator to consider financial capability in
making his written commitment of manpower, equipment, and materials
because we do not wish to confuse the regulated community with
discretionary requirements in a mandatory rule. Finally, we changed the
reference in paragraph (d)(2) from ``to expeditiously control and
remove any harmful quantity of oil discharged'' to read ``to
expeditiously control and remove any quantity of oil discharged that
may be harmful.'' We made this change to refer to the statutory
standard referring to a quantity of oil ``that may be harmful.''
Section 112.7(e)--Inspections, Tests, and Records
Background. In 1991, we proposed that records and inspections and
test results be kept for a period of five years. Current rules require
record, inspection, and test results be maintained for three years. We
also proposed that such records might be maintained with the Plan,
instead of being part of the Plan.
In 1997, we returned to the three-year record maintenance period in
our new proposal. In 1997, we also proposed that usual and customary
business records, such as records maintained under API Standards 653
and 2610, would suffice to meet the requirements of this section.
Finally we proposed that such records be made a part of the Plan.
Comments. 1991 comments. Maintenance with Plan. Most commenters
favored the proposal that records might be maintained with the Plan,
rather than as part of it. Two commenters thought the requirements
should apply generally only to large facilities.
Form of records. One commenter urged use of electronic records.
Records required. Still another asked that we list all inspections
and tests required by part 112. One commenter asked for a requirement
to keep records and tests of all major repairs and of employee
training.
Time period. Most commenters favored retaining the current three-
year time period to maintain records, believing it is adequate. Some
commenters objected to the cost of a five-year record retention
requirement. One commenter favored a two-year record maintenance
period. Several favored a phase-in period if five years were to be
required so that three-year records could be brought into compliance
with the rule. One commenter favored a requirement that records be
maintained in accordance with other State and Federal agency
requirements to avoid additional and unnecessary costs.
1997 comments. Maintenance with Plan. A number of commenters
criticized the proposal that records must be maintained as part of the
Plan, rather than maintained with the Plan, considering that proposal
burdensome and providing no benefit to the environment.
Form of records. Several commenters asked that we clarify that use
of records maintained under the API standards cited is not required.
Another commenter noted that many smaller companies do not use API
standards, and that use of such records should be allowed ``when
available.'' Several commenters urged that we state that records kept
under the NPDES program might suffice for the SPCC program. Other
commenters asked whether records in other formats might be acceptable,
such as under a facility's QS-9000 or ISO-14000 system, or under
standards promulgated by the Underwriters' Laboratories. Other
commenters discussed use of NPDES stormwater bypass records. We will
talk about those records under the discussion of Sec. 112.8(c)(3)(iv).
Time period. Most commenters favored the proposal to retain the
current three-year time period for maintenance of records.
Response to comments. Maintenance with Plan. We agree with
commenters that it is not necessary to maintain records as part of the
Plan. Therefore, today's rule allows ``keeping'' of the records
``with'' the Plan, but not as part of it. In the current rule, such
records ``should be made part of the SPCC Plan * * *.'' 40 CFR
112.7(e)(8). Because you continually update these records, this change
will eliminate the need to amend your Plan each time you remove old
records and add new ones. You still retain the option of making these
records a part of the Plan if you choose.
Records required. The rule permits use of usual and customary
business records, and covers all of the inspections and tests required
by this part as well as any ancillary records. ``Inspections and
tests'' include not only inspections and tests, but schedules,
evaluations, examinations, descriptions, and similar activities
required by this part. After publication of this rule, we will list all
of the inspections and tests required by part 112 on our website
(www.epa.gov/oilspill). The applicability of each inspection and test
will depend on the exercise of good engineering practice, because not
every one will be applicable to every facility.
Form of records. Records of inspections and tests required by this
rule may be maintained in electronic or any other format which is
readily accessible to the facility and to EPA personnel. Usual and
customary business records may be those ordinarily used in the
industry, including those made under API standards, Underwriters'
Laboratories standards, NPDES permits, a facility's QS-9000 or ISO-
14000 system, or any other format acceptable to the Regional
Administrator. If you choose to use records associated with compliance
with industry standards, such as Underwriters' Laboratories standards,
you must closely review the inspection, testing, and recordkeeping
requirements of this rule to ensure that any records kept in accordance
with industry standards meets the intent of the rule. Some standards
have limited recordkeeping requirements and may only address a
particular aspect of container fabrication, installation, inspection,
and operation and maintenance. The intent of the rule is that you will
not have to maintain duplicate sets of records when one set has already
been prepared under industry or regulatory purposes that also fully
suffices for SPCC purposes. The use of these alternative record formats
is optional; you are not required to use them, but you may use them.
Time period. We agree with commenters that maintenance of records
for three years is sufficient for SPCC purposes, since that period will
allow for meaningful comparisons of inspections and tests taken.
Therefore, there will be no new costs. We note, however, that certain
industry standards, for example API Standards 570 and 653, may specify
record maintenance for more than three years.
Editorial changes and clarifications. As proposed in 1991, we
affirm that the certifying engineer, as well as the owner or operator,
may be a person who develops inspection procedures. We also affirm that
the provision applies to both ``inspections'' and ``tests'' undertaken.
The tests are usually integral parts of the inspections.
[[Page 47107]]
Section 112.7(f)--Employee Training and Discharge Prevention Procedures
Background. In 1991, we proposed that you conduct training
exercises and that you train new employees within their first week of
work. The rationale for these provisions was that a high percentage of
discharges are caused by operator error; therefore, training and
briefings might help prevent many discharges and promote a safer
facility. This rationale was based on program experience and studies
EPA undertook. The 1995 SPCC Survey found that operator error was the
most common spill cause for facilities in 9 of the 19 industry
categories that reported having spills. Also, the August 1994 draft
report of the EPA Aboveground Oil Storage Facilities Workgroup called
``Soil and Ground Water Contamination from Aboveground Oil Storage
Facilities: A Strategic Study'' presented data on causes of discharges
from two studies. Both studies showed that error during product
transfer activities is one of the biggest known causes of discharges at
AST facilities. Two other studies also support our contention: Carter,
W.J., ``How API Viewed the Needs for Aboveground Storage Tanks,'' Tank
Talk, Vol. 7, July/August 1992, p.2.; and U.S. EPA, ``The Technical
Background Document to Support the Implementation of OPA Response Plan
Requirements,'' Emergency Response Division, Office of Solid Waste and
Emergency Response, February 1993, p.4-19.
In 1993, we proposed to qualify the applicability of the training
requirements to only those facilities that transfer or receive greater
than or equal to 10,000 gallons of oil in a single operation more than
twice per month on average, or greater than or equal to 50,000 gallons
in a single operation more than once a month on the average. We further
proposed that you require that employees involved in ``oil-handling
activities,'' such as the operation or maintenance of oil storage tanks
or the operation of equipment related to storage tanks, receive eight
hours of facility specific training within one year of the effective
date of the rule or at the date that your facility becomes subject to
the requirement. In subsequent years, each employee would be required
to undergo four hours of refresher training.
Our 1993 proposal would require training for new employees within
one week of employment. We also proposed to specify the areas in which
you would be required to train employees to include: training in
correct equipment operation and maintenance, general facility
operations, discharge prevention laws and regulations, and the contents
of the facility's SPCC Plan. Finally, the proposal would require that
you conduct unannounced drills, at least annually, in which oil-
handling personnel would participate.
Comments. 1991 comments. Applicability of training requirements.
Numerous commenters suggested that the training requirements should
apply only to personnel involved in the operation or maintenance of
equipment. They argued that the training requirements need not apply to
clerks, secretaries, and similar employees who are not involved in the
physical operations of the facility. They also argued that we failed to
sufficiently account for training costs in our economic analysis.
Another commenter asked for a small facility exemption from training
requirements.
Another commenter asked that facilities be allowed to incorporate
SPCC training requirements into already existing training programs
required by other Federal or State law. One commenter suggested that
the rule include a requirement that owners or operators document each
training session and spill response drill conducted, and to maintain
those records for five years.
Timing of employee training. Some commenters favored the proposed
provision for yearly training exercises and suggested that the training
be coordinated with local oil spill response organizations or Local
Emergency Planning Committees (LEPCs) whenever possible. One commenter
cautioned that the annual training should not be considered a full
scale SPCC drill.
Opposing commenters suggested no time period for such exercises, or
alternative periods, such as every two or three years.
Likewise, many commenters opposed the provision relating to the
training of new employees within one week of employment. Opposing
commenters argued generally that such a recommendation is impractical,
and called for employer discretion in scheduling training. Others
suggested varying time periods in lieu of one week. Those suggestions
ranged from one month to one year, with alternatives suggested such as
``as soon as practical,'' ``prior to operation but before one year,''
``within one week of job assignment,'' ``a more reasonable time
period,'' ``after training,'' and ``until the next annual training for
all employees.'' One commenter asked that we define the term ``new
employee.''
Discharge prevention briefings. Many commenters criticized the
proposal for annual spill prevention briefings, as opposed to the
current requirement to hold such briefings ``at intervals frequent
enough to assure adequate understanding of the SPCC Plan.'' They argued
that the current standard is adequate. Some commenters suggested that
we require additional training in these briefings such as emergency
response training, or training concerning Plan changes.
1993 comments. Applicability of training requirements. In 1993,
many commenters asked for clarification of what ``oil-handling''
personnel meant. Some thought the requirements for training should be
limited to those employees engaged in response activities. Others
questioned what ``on average'' meant in determining the threshold
applicability of the rule. Still others asked what ``a single
operation'' meant. Some asked that the requirements be limited to
facilities with potential to cause ``substantial harm'' to the
environment. Others asked that the requirements be relaxed for
facilities with equipment that reduce the potential for discharges.
Some suggested differing gallon thresholds for the applicability of the
training requirements. One commenter suggested that training be limited
to those employees involved in emergency response or countermeasure
activities. One commenter asked for an exemption from this requirement
for small facilities. Another commenter asked for an exemption for
extraction facilities, because, he argued, they have few spills.
Another commenter suggested that the 1991 proposal was adequate.
Timing of employee training. Some commenters favored the proposed
requirement for eight-hour annual training, with four-hour refresher
training in subsequent years. Others opposed it, arguing that employer
discretion in this matter will ensure a better result.
Likewise many commenters opposed the requirement that new employees
be trained within one week of employment, arguing instead for employer
discretion. Some commenters suggested alternate frequencies other than
one week, ranging from ``prior to assuming duties'' to up to six months
after hiring.
Content of training. A few commenters supported the specification
of training subjects. Some commenters suggested that we require
training in the proper operation and maintenance of facility equipment
and knowledge of spill procedure protocols. A utility commenter
objected to the proposal that its employees be trained in maintenance
of oil storage tanks, because its
[[Page 47108]]
maintenance activities do not involve the transfer or handling of oil
and therefore fall outside the scope of the rule. Alternatively, the
commenter suggested, those employees should be given a lower level of
``awareness'' training. One commenter suggested inclusion of response
training.
Unannounced drills. Some commenters favored the proposal and
suggested that actual discharge experience should be given credit as a
drill. One commenter suggested a frequency schedule for various types
of drills.
Some commenters criticized the proposal for at least yearly
unannounced drills. One commenter suggested that the frequency of the
drills should be at the operator's discretion. Commenters argued that,
if required at all, drills should only be applicable to operational or
response personnel. Two commenters said that a requirement for
unannounced drills for all employees would require them to conduct at
least eight or more drills a year. Another commenter suggested training
instead of drills, because of the potential for drills to cause
expensive shutdowns.
Response to comments. Applicability of training requirements. We
believe that training requirements should apply to all facilities,
large or small, including all those that store or use oil, regardless
of the amount of oil transferred in any particular time. Training may
help avert human error, which is a principal cause of oil discharges.
``Spills from ASTs may occur as a result of operator error, for
example, during loading operations (e.g., vessel or tank truck--AST
transfer operation), or as a result of structural failure (e.g.,
brittle fracture) because of inadequate maintenance of the AST.'' EPA
Liner Study, at 14. The 1995 SPCC Survey found that operator error was
the most common spill cause for facilities in 9 of the 19 industry
categories that reported having spills. Also, the August 1994 draft
report of the EPA Aboveground Oil Storage Facilities Workgroup called
``Soil and Ground Water Contamination from Aboveground Oil Storage
Facilities: A Strategic Study'' presented data on causes of discharges
from two studies. Both studies showed that error during product
transfer activities is one of the biggest known causes of discharges at
AST facilities. Two other studies also support our contention: Carter,
W.J., ``How API Viewed the Needs for Aboveground Storage Tanks,'' Tank
Talk, Vol. 7, July/August 1992, p.2.; and U.S. EPA, ``The Technical
Background Document to Support the Implementation of OPA Response Plan
Requirements,'' Emergency Response Division, Office of Solid Waste and
Emergency Response, February 1993, p.4-19. We have therefore retained
the applicability of training to all facilities. The 1993 proposal
would have limited training requirements to only certain facilities
which received or transferred over the proposed amount of oil.
Facilities which receive or transfer less than the proposed amount
might also have discharges which could have been averted through
required training. Also the proposed rule would have exempted many
facilities that use rather than store oil from its scope. Therefore, we
have provided in the rule that all facilities, whether bulk storage
facilities or facilities that merely use oil, must train oil-handling
employees because all facilities have the potential for a discharge as
described in Sec. 112.1(b), and training is necessary to avert such a
discharge.
We agree with the commenter that training is only necessary for
personnel who will use it to carry out the requirements of this rule.
Therefore revised paragraph (f)(1) provides that only oil-handling
personnel are subject to training requirements, as we proposed in 1993.
Thus there are no new training costs because we have always required
such training of oil-handling personnel. ``Oil-handling personnel'' is
to be interpreted according to industry standards, but includes
employees engaged in the operation and maintenance of oil storage
containers or the operation of equipment related to storage containers
and emergency response personnel. We do not interpret the term to
include secretaries, clerks, and other personnel who are never involved
in operation or maintenance activities related to oil storage or
equipment, oil transfer operations, emergency response, countermeasure
functions, or similar activities.
You may incorporate SPCC training requirements into already
existing training programs required by other Federal or State law at
your option or may conduct SPCC training separately.
You must document that you have conducted required training
courses. Such documentation must be maintained with the Plan for three
years.
Timing of employee training. We agree with commenters who thought
it desirable to leave the timing and number of hours of training of
oil-handling employees, including new employees, to the employer's
discretion. ``Proper instruction'' of oil-handling employees, as
required in the rule, means in accordance with industry standards or at
a frequency sufficient to prevent a discharge as described in
Sec. 112.1(b). This standard will allow facilities more flexibility to
develop training programs better suited to the particular facility.
While the rule requires annual discharge prevention briefings, we also
agree that the annual briefings required are not drills. In any case,
the SPCC rules do not require drills, as explained below.
For purposes of the rule, it is not necessary to define a ``new
employee'' because all oil-handling personnel are subject to training
requirements, whether new or not. You do, however, have discretion as
to the timing of that training, so long as the timing meets the
requirements of good engineering practice.
Discharge prevention briefings. Annual discharge prevention
briefings are necessary, but there should be more frequent briefings
where appropriate. Such briefings are necessary to refresh employees'
memories on facility Plan provisions and to update employees on the
latest prevention and response techniques. Training must include the
contents of the facility Plan. Although it is desirable, we disagree
that we should require SPCC briefings to include emergency response
training. That training is already required for those facilities which
must prepare response plans.
Content of training. Specifying a minimum list of training subjects
is necessary to ensure that facility employees are aware of discharge
prevention procedures and regulations. As suggested by a commenter, we
have added knowledge of discharge procedure protocols to the list of
training subjects because such training will help avert discharges.
Therefore, we have specified that training must include, at a minimum:
the operation and maintenance of equipment to prevent the discharge of
oil; discharge procedure protocols; applicable pollution control laws,
rules, and regulations; general facility operations; and, the contents
of the facility Plan. As noted above, we require response training for
facilities that must submit response plans, but such training is not
necessary for all SPCC facilities.
In response to the utility commenter who asserted that utility
employees do not need to be trained in the maintenance of oil storage
tanks because such maintenance does not involve the transfer and
handling of oil, we note that training must address relevant
maintenance activities at the facility. If there is no transfer and
handling of oil, such topic need not be covered in training.
[[Page 47109]]
Unannounced drills. The proposed yearly frequency for unannounced
drills is also unnecessary because such drills are already required at
FRP facilities, which are higher risk facilities. We do not believe
that the risk at all SPCC facilities approaches the same level as at
FRP facilities. Therefore, we are not finalizing this proposal, and
there are no new costs.
Editorial changes and clarifications. We changed the title from
``Personnel, training, and spill prevention procedures,'' to
``Personnel, training, and discharge prevention procedures.'' In
paragraph (f)(1), ``discharges of oil'' becomes ``discharges.'' In
paragraph (f)(2), ``line management'' becomes ``facility management,''
and ``oil spill prevention'' becomes ``discharge prevention.'' In
paragraph (f)(3), ``spill prevention briefings'' becomes ``discharge
prevention briefings.'' Also in paragraph (f)(3); ``operating
personnel'' becomes ``oil-handling'' personnel,'' to be consistent with
language in paragraph (f)(1); and, ``spill events'' becomes
``discharges as described in Sec. 112.1(b).''
Section 112.7(g)--Security (Excluding oil Production Facilities)
Background. In 1991, we proposed to turn into a recommendation the
current requirement that a facility should be fully fenced, and gates
locked and/or guarded when the facility is not in production or is
unattended. We proposed to require that the master flow and drain
valves (or other valves that will permit direct outward flow of the
tanks' contents) have adequate security to ensure that they remain in a
closed position when in non-operating or non-standby status. Thus, the
proposal would allow more flexibility in the method of securing the
valves than the current rule, which requires that such valves be
``securely locked.''
The current rule requires that loading/unloading connections be
securely capped or blank-flanged when not in service or standby-service
``for an extended time.'' We proposed in 1991 to clarify that ``an
extended time'' means six months or more, based on our Regional
experience.
Comments. Editorial changes and clarifications. One commenter asked
for the meaning of ``plant'' as used in proposed Sec. 112.7(g)(1).
Applicability of requirement. One commenter urged an exemption from
all security provisions for mobile facilities, because such facilities
are manned 24 hours a day while in operation.
Fences. One commenter argued that fences should not be required for
all facilities, because it is not practicable in some places. Another
argued that fences should be topped with barbed wire, or otherwise
designed to deter vandalism.
Starter controls on pumps. Several commenters argued that the
requirements to lock starter controls on all pumps and to locate them
at a site accessible only to authorized personnel are duplicative and
do not deter vandals or other unauthorized personnel. Another commenter
urged us to exclude large facilities from the locking requirement
because the potential for losing keys or having the locks become
inoperative due to freezing conditions is great. A third commenter
suggested that the requirement should apply to facilities, and not to
pumps.
Loading/unloading connections. One commenter urged that the blank-
flanging requirement apply to facilities that are not in service for
six months or more, rather than to connections of oil piping. The
rationale was that larger facilities have seasonal or contractual
variations in use of lines, pumps, racks, and connections. Therefore,
it would be costly and impractical to blank off lines only to reopen
them in the seventh month. Accordingly, the rule should, per the
commenter, recognize normal operating procedures at such facilities and
allow flexibility. Another commenter requested that ``quick
disconnect'' fittings qualify as a method of secure capping.
Response to comments. Applicability of requirements. We asked in
the 1991 preamble (at 56 FR 54616) for comments as to whether
provisions proposed as discretionary measures or recommendations should
be made requirements. We were concerned whether these proposed measures
represented good engineering practice for all facilities. Specific
comments are discussed below. In the case of proposed Sec. 112.7(g)(1)
and (5) as requirements, we have decided to retain the requirements as
requirements rather than convert those paragraphs into recommendations
as proposed. We have done this because we believe that fencing,
facility lighting, and the other measures prescribed in the rule to
prevent vandalism are elements of good engineering practice in most
facilities, including mobile facilities. Where they are not a part of
good engineering practice, we have amended the proposed provision
allowing deviations, Sec. 112.7(a)(2), to include the provisions in
Sec. 112.7(g).
Fences. Fencing helps to deter vandals and thus prevent the
discharges that they might cause. In response to the commenter who
argued that fences should be topped with barbed wire, or otherwise
designed to deter vandalism, we agree. When you use a fence to protect
a facility, the design of the fence should deter vandalism. Methods of
deterring vandals might include barbed wire or other devices. If any
type of fence is impractical, you may, under Sec. 112.7(a)(2), explain
your reasons for nonconformance and provide equivalent environmental
protection by some other means.
Valves. Revised Sec. 112.7(g)(2) requires you to ensure that the
master flow and drain valves and other valves permitting outward flow
of the container's contents have adequate security measures. The
current rule requires that such valves be securely locked in the closed
position when in non-operating or non-standby status. Today's revised
rule allows security measures other than locking drain valves or other
valves permitting outflow to the surface. Manual locks may be
preferable for valves that are not electronically or automatically
controlled. Such locks may be the only practical way to ensure that
valves stay in the closed position. For electronically controlled or
automated systems, no manual lock may be necessary. The rule gives you
discretion in the method of securing valves. We believe that this
flexibility is necessary due to changes in technology and in the use of
manual and electronic valving.
Starter controls on pumps. We disagree that the requirements to
have the starter control locked in the off position and be accessible
only to authorized personnel are redundant. Restricting access to such
pumps prevents unauthorized personnel from accidentally opening the
starter control. These measures are necessary to prevent discharges at
small as well as large facilities because the threat of discharge is
the same regardless of the size of the container, and a small discharge
may be harmful to the environment. If the potential for losing keys,
weather conditions such as frequent freezing, or other engineering
factors render such a measure infeasible, you may use the deviation
provisions in Sec. 112.7(a)(2) if you can explain your reasons for
nonconformance and provide equivalent environmental protection by some
other means.
Loading/unloading connections. In response to comment, we have
decided to retain the current time line in Sec. 112.7(g)(4), i.e., ``an
extended time,'' instead of specifying a six-month time line, due to
the need for operational flexibility at facilities. We define ``an
extended time'' in reference to industry standards or, in the absence
of such standards, at a frequency sufficient to prevent any discharge.
The appropriate method of securing or blank flanging of
[[Page 47110]]
these connections is a matter of good engineering practice, and might
include ``quick disconnect fittings'' as a possible deviation under
Sec. 112.7(a)(2). In any case, a secure cap is one equipped with some
kind of lock or secure closure device to prevent vandalism. We disagree
that the requirements of this paragraph should apply to the owner or
operator of a facility instead of the owner or operator of the piping
because a facility might place only some piping out of service for a
period of time, and let other piping remain in service. Therefore, the
owners or operators of some piping might escape the requirements of the
rule and be more likely to discharge oil.
Industry standards. Industry standards that may assist an owner or
operator with security purposes include: (1) API Standard 2610, Design,
Construction, Operation, Maintenance, and Inspection of Terminal and
Tank Facilities; and, (2) NFPA 30A, Automotive and Marine Service
Station Code, Flammable and Combustible Liquids Code.
Editorial changes and clarifications. We agree that the term
``plant'' has no clear meaning. Therefore, in paragraph (g)(1), we have
substituted the term ``facility'' in its place, which is a defined term
in these rules. Also in that paragraph, the phrase ``handling,
processing and storing oil'' becomes ``handling, processing or storing
oil.'' In paragraph (g)(2), ``tank'' becomes ``container.'' In
paragraph (g)(3), ``pumps'' becomes ``pump.'' In paragraph (g)(5), the
phrase ``Consideration should be given to:'' is deleted. We revise the
sentence to read, ``Provide facility lighting commensurate with the
type and location of the facility that will assist in the: * * *''
Section 112.7(h)--Loading/Unloading (Excluding Offshore Facilities)
Background. In 1991, we reproposed the current discharge prevention
requirements for loading/unloading racks.
Comments. In general. Several commenters opposed the proposal on
the basis that a requirement for a strong contingency plan would be a
preferable and more effective alternative. Another commenter asked that
we clarify that only facilities routinely used for loading or unloading
of tanker trucks from or into aboveground bulk storage tanks are
subject to this provision. One commenter believed that the proposed
rule regulates items which ``should be covered'' by DOT rules governing
loading, unloading, and vehicle inspection.
Editorial changes and clarifications. One commenter asked for a
clarification of the term ``quick drainage system.''
Another commenter recommended that instead of mandatory containment
requirements, a facility be allowed to show that procedures are in
place to ensure that personnel are present at all times to supervise
tank truck loading and unloading. Additionally, that commenter
recommended that all new or renovated loading/unloading areas provide,
at a minimum, curbing, sloped concrete, trenching, tanks, or basins
which could contain at least five percent by volume of the largest
compartment of the tank car or truck. For existing facilities, that
commenter suggested that containment might contain a lesser volume,
provided that the entire area is constructed of impervious material, no
reported releases have occurred, and that loading/unloading activities
are supervised.
Alarm or warning systems. One commenter asked whether the
requirement to provide a warning light or physical barrier system, or
warning signs, applied to tank batteries or just plants. Another
suggested that a vehicle brake interlock system or similar system might
work just as well. Still another suggested the use of wheel chocks
during tank truck transfers.
Vehicle drain closure. Two commenters opposed the proposed
requirement that vehicle drains and outlets be examined for leakage and
if necessary repaired to prevent liquid leaks during transit. They
argued that the facility owner had little or no control over trucks
that were owned by others which loaded or unloaded at a facility and
could not ensure their compliance with the rules.
Response to comments. In general. This section is applicable to any
non-transportation-related or terminal facility where oil is loaded or
unloaded from or to a tank car or tank truck. It applies to containers
which are aboveground (including partially buried tanks, bunkered
tanks, or vaulted tanks) or completely buried (except those exempted by
this rule), and to all facilities, large or small. All of these
facilities have a risk of discharge from transfers. Our Survey of Oil
Storage Facilities (published in July 1996) showed that as annual
throughput increases, so does the propensity to discharge, the severity
of the discharge, and, to a lesser extent, the costs of the cleanup.
Throughput increases are often associated with transfers of oil.
The requirements contained in this section, including those for
secondary containment, warning systems, and inspection of trucks or
cars for discharges are necessary to help prevent discharges. If you
can justify a deviation for secondary containment requirement in
paragraph (h)(1) on the basis that it is not practicable from an
engineering standpoint, you must provide a contingency plan and take
other actions to comply with Sec. 112.7(d). If you seek to deviate from
any of the requirements in paragraphs (h)(2) or (3), you must explain
your reasons for nonconformance, as provided in Sec. 112.7(a)(2), and
provide measures affording equivalent environmental protection.
We disagree that a contingency plan (whether labeled ``strong'' or
otherwise) is a preferable alternative to secondary containment.
Secondary containment is preferable because it may prevent a discharge
that may be harmful as described in Sec. 112.1(b). A contingency plan
is a plan for action when such discharge has already occurred. However,
as noted earlier, if secondary containment is not practicable, you must
provide a contingency plan and take other actions as required by
Sec. 112.7(d). EPA will continue to evaluate the issue of whether the
provisions for secondary containment found in Sec. 112.7(h)(1) should
be modified or revised. We intend to publish a notice asking for
additional data and comment on this issue.
We disagree that the section regulates activities already under the
purview of the U.S. Department of Transportation. We regulate the
environmental aspects of loading/unloading transfers at non-
transportation-related facilities, which are legitimately part of a
prevention plan. DOT regulates other aspects of those transfers, such
as safety measures.
Other State or Federal law. We have withdrawn, as unnecessary,
proposed Sec. 112.7(h)(1), which would have required that facilities
meet the minimum requirements of Federal and State law. Those
requirements apply whether they are mentioned or not.
Secondary containment. As noted above, the requirement for
secondary containment applies to all facilities, whether with
aboveground or completely buried containers. This includes production
facilities and small facilities. The method of secondary containment
must be one of those listed in the rule (see Sec. 112.7(c)), or some
similar system that provides equivalent environmental protection. The
choice of method is one of good engineering practice. However, in
response to comments, we note that sumps and drip pans are a listed
method of secondary containment for offshore facilities. A catchment
basin might be an acceptable
[[Page 47111]]
form of retention pond for an onshore facility. Whatever method is
implemented, it must be capable of containing the maximum capacity of
any single compartment of a tank car or tank truck loaded or unloaded
in the facility. A discharge from the maximum capacity of any single
compartment of a tank car or tank truck includes a discharge from the
tank car or tank truck piping and hoses. This is the largest amount
likely to be discharged from the oil storage vehicle. A requirement
that secondary containment be able to hold only five percent of a
potential discharge when procedures are in place to prevent discharges
fails to protect the environment if there is human error in one of
those procedures. In case of discharge, the secondary containment
system must be capable of preventing a discharge from that maximum
capacity compartment to the environment. As mentioned above, if
secondary containment is not practicable, you may be able to deviate
from the requirement if you provide a contingency plan and otherwise
comply with Sec. 112.7(d).
Alarm or warning systems. The requirement to provide a warning
light or other physical barrier system applies to the loading/unloading
areas of facilities. We have amended the rule on the suggestion of a
commenter to include ``vehicle brake interlock system'' and ``wheel
chocks.'' The examples listed in the rule of potential warning systems
are merely illustrative. Any other alarm or warning system which serves
the same purpose and performs effectively will also suffice to meet
this requirement.
Vehicle drain closure. We believe that the requirement to check
vehicles for discharge is important to help prevent discharges. If the
check were not done, the entire contents of the vehicle might be
discharged. We further believe that the responsibility for compliance
with proposed Sec. 112.7(h)(3), as well as with all provisions of the
rule, continues to rest with the owner or operator of the facility when
those vehicles are loading or unloading oil at the facility.
Industry standards. Industry standards that may assist an owner or
operator with loading and unloading areas include: (1) NFPA 30,
``Flammable and Combustible Liquids Code''; and, (2) API Standard 2610,
``Design, Construction, Operation, Maintenance, and Inspection of
Terminal and Tank Facilities.''
Editorial changes and clarifications. In paragraph (h)(1), for
clarity, ``plant'' is changed to ``facility.'' The phrase ``to handle
spills'' becomes ``to handle discharges.'' A ``quick drainage system''
is a device which drains oil away from the loading/unloading area to
some means of secondary containment or returns the oil to the facility.
For Sec. 112.7(h)(1), if secondary containment is not practicable, you
must provide a contingency plan following the provisions of 40 CFR part
109, and otherwise comply with Sec. 112.7(d). Also, in paragraph
(h)(1), ``tank truck'' becomes ``tank car or tank truck.'' In paragraph
(h)(2), ``prevent vehicular departure,'' becomes ``prevent vehicles
from departing.'' In paragraph (h)(3), ``leakage'' becomes
``discharge.'' ``Discharge'' is a broader term, of which ``leakage'' is
a subset. Also in that paragraph, ``examine'' becomes ``inspect.''
Section 112.7(i)--Brittle Fracture Evaluation
Background. In 1993, we proposed to require that you evaluate your
field-constructed tanks for brittle fracture if those tanks undergo
repair, alteration, or a change in service. You would have been
required to evaluate those tanks by adherence to industry standards
contained in American Petroleum Institute (API) Standard 653, entitled
``Tank Inspection, Repair, Alteration, and Reconstruction.'' The
rationale was to help prevent the failure of field-constructed tanks
due to brittle fracture, such as the four million gallon aboveground
Ashland Oil tank failure which occurred in January 1988.
Comments. Applicability. Several commenters favored the proposal.
One suggested that we incorporate API Standard 653 into our rules to
accommodate the possibility of tank failures other than through brittle
fracture. One commenter opposed the proposal on the basis that the
evaluation was unnecessary for small volume tanks and tanks with
secondary containment. Other commenters argued that such testing was
unnecessary for steel-bolted tanks because such tanks are too thin to
be subject to brittle fracture since material properties are uniform
through the thickness. One commenter asked that small facilities be
exempted from the proposed requirement.
Editorial changes and clarifications. Two commenters asked what the
term ``change in service'' means. Others asked for clarification of the
term ``field-erected tank.'' Another asked for clarification of the
term ``repair,'' so that it would exclude ordinary day-to-day
maintenance activities which are conducted to maintain the functional
integrity of the tank and do not weaken the tank.
Alternatives to brittle fracture evaluation. One commenter
suggested that we allow testing by acoustic emission testing.
Response to comments. Applicability. The requirement to evaluate
field-constructed tanks for brittle fracture whenever a field-
constructed aboveground container undergoes repair, alteration,
reconstruction, or change in service is necessary because brittle
fracture may cause sudden and catastrophic tank failure, resulting in
potentially serious damage to the environment and loss of oil. The
requirement must be applicable to large and small facilities alike,
because all the field-constructed aboveground containers have a risk of
failure. The presence or absence of secondary containment does not
eliminate the need for brittle fracture evaluation because the intent
of the rule is to prevent a discharge whether or not it will be
contained. While the requirement applies to all field-constructed
aboveground containers, if you can show that the evaluation is
unnecessary for your steel-bolted tanks, you may deviate from the
requirement under Sec. 112.7(a)(2) if you can explain your reasons for
nonconformance and provide equivalent environmental protection. We note
that portions of steel-bolted tanks, such as the bottom or roof, may be
welded, and therefore subject to brittle fracture.
The requirement for evaluation of a field-constructed aboveground
container must be undertaken when the container undergoes a repair,
alteration, reconstruction, or change in service that might affect the
risk of a discharge or failure due to brittle fracture, or when a
discharge or failure has already occurred due to brittle fracture or
other catastrophe. Catastrophic failures are failures which may result
from events such as lightning strikes, dangerous seismic activity, etc.
As a result of a catastrophic failure, the entire contents of a
container may be discharged to the environment in the same way as if
brittle fracture had occurred.
``Repair'' means any work necessary to maintain or restore a
container to a condition suitable for safe operation. Typical examples
include the removal and replacement of material (such as roof, shell,
or bottom material, including weld metal) to maintain container
integrity; the re-leveling or jacking of a container shell, bottom, or
roof; the addition of reinforcing plates to existing shell
penetrations; and the repair of flaws, such as tears or gouges, by
grinding or gouging followed by welding. We understand that some
repairs (such as repair of tank seals), alterations, or changes in
service will not cause a risk of failure due to brittle
[[Page 47112]]
fracture; therefore, we have amended the rule to refer to those
repairs, alterations, reconstruction, or changes in service that affect
the risk of a discharge or failure due to brittle fracture.
``Alteration'' means any work on a container involving cutting,
burning, welding, or heating operations that changes the physical
dimensions or configurations of the container. Typical examples include
the addition of manways and nozzles greater than 12-inch nominal pipe
size and an increase or decrease in tank shell height.
Alternatives to brittle fracture evaluation. We have eliminated the
incorporation by reference to API Standard 653 from the rule. We have
also therefore withdrawn proposed Appendix H, the API Standard 653
brittle fracture flowchart. We believe that API Standard 653 is an
acceptable standard to test for brittle fracture. However, an
incorporation by reference of any standard might cause the rule to be
instantly obsolete should that standard change or should a newer,
better method emerge. A potential standard might also apply only to a
certain subset of facilities or equipment. Therefore, as with most
other requirements in this part, if you explain your reasons for
nonconformance, alternative methods which afford equivalent
environmental protection may be acceptable under Sec. 112.7(a)(2). If
acoustic emission testing provides equivalent environmental protection
it may be acceptable as an alternative. That decision, in the first
instance, is one for the Professional Engineer and owner or operator.
Industry standards. Industry standards that may assist an owner or
operator with brittle fracture evaluation include: (1) API Standard
653, ``Tank Inspection, Repair, Alteration, and Reconstruction''; and,
(2) API Recommended Practice 920, ``Prevention of Brittle Fracture of
Pressure Vessels.''
Editorial changes and clarifications. A ``field-constructed
aboveground container'' is one that is assembled or reassembled outside
the factory at the location of its intended use. A ``change in
service'' is a change from previous operating conditions involving
different properties of the stored product such as specific gravity or
corrosivity and/or different service conditions of temperature and/or
pressure. The word ``reconstruction'' was added in the first sentence
to conform with the text in API Standard 653. The words ``discharge
or'' were added prior to ``failure'' and ``brittle fracture failure''
to make clear that evaluation is necessary when there has been a
discharge from the container, whether or not there has been a complete
failure of the container due to brittle fracture or catastrophe. When a
container has failed completely and will be replaced, no brittle
fracture or catastrophe evaluation is necessary. The evaluation is only
applicable when the original container remains, but the physical
condition of the container has changed due to repair, alteration, or
change in service.
Section 112.7(j)--State Rules
Background. In the introduction to Sec. 112.7(e) of the current
rule, an owner or operator is required to discuss in the Plan his
conformance with Sec. 112.7(c), plus other applicable parts of
Sec. 112.7, other effective spill prevention and containment procedures
or, if more stringent, with State rules, regulations, and guidelines.
In our 1991 proposal, we limited the required discussion of ``other
effective spill prevention and containment procedures'' to those listed
in Secs. 112.8, 112.9, 112.10, and 112.11, or if more stringent, with
State rules, regulations, and guidelines.
Comments. Cross-referencing of requirements. One commenter argued
that the proposed requirements should be more clearly limited to those
sections which are applicable to the facility in question. For example,
the commenter asserted, ``requirements in Sec. 112.8 `* * *onshore
facilities (excluding production facilities)' should not (by the
requirement in Sec. 112.7(i)) be applied to any portion of any
production facility.''
Consistency in rules. Two States urged that our rules be as
consistent as possible with rules in the States. Another State urged
that we grant reciprocity to State-approved Plans which have been
reviewed under equal or greater adequacy criteria. One commenter
complained that EPA rules are in some cases more stringent than some
State rules.
Federal and State regulation. Two commenters argued against any
State regulation in the SPCC area to avoid duplication. Conversely,
another commenter argued against any Federal regulation because the
States are better qualified to regulate in the SPCC arena.
Preemption. Another State requested that EPA strive to have similar
programs as the States, or at the least not to preempt the States in
the regulation of SPCC matters.
Response to comments. Cross-referencing of requirements. In
response to the commenter who believed that proposed Sec. 112.7(i)
(redesignated in today's rule as Sec. 112.7(j)) might require him to
discuss inapplicable requirements, we note that you must address all
SPCC requirements in your Plan. You must include in your Plan a
complete discussion of conformance with the applicable requirements and
other effective discharge prevention and containment procedures listed
in part 112 or any applicable more stringent State rule, regulation, or
guideline. If a requirement is not applicable to a particular type of
facility, we believe that it is important for an owner or operator to
explain why.
Consistency in rules. As noted above, you may now use a State plan
as a substitute for an SPCC Plan when the State plan meets all Federal
requirements and is cross-referenced. When you use a State plan that
does not meet all Federal requirements, it must be supplemented by
sections that do meet all Federal requirements. At times EPA will have
rules that are more stringent than States rules, and some States may
have rules that are more stringent than those of EPA. If you follow
more stringent State rules in your Plan, you must explain that is what
you are doing.
Federal and State regulation. Both the States and EPA have
authority to regulate containers storing or using oil. We believe State
authority to regulate in this area and establish spill prevention
programs is supported by section 311(o) of the CWA. Some States have
exercised their authority to regulate while others have not. We believe
that State SPCC programs are a valuable supplement to our SPCC program.
Preemption. We do not preempt State rules, and defer to State
rules, regulations, and guidelines that are more stringent than part
112.
Editorial changes and clarifications. To simplify the rule
language, we have amended the proposed rule to state that you must
discuss all applicable requirements in the Plan instead of listing all
of the sections individually. The phrase ``sections of the Plan shall
include* * *'' becomes ``include in your Plan* * * .'' ``Spill''
becomes ``discharge.''
Subpart B--Requirements for Petroleum Oils or Other Non-petroleum Oils,
Except Animal Fats and Vegetable Oils
Background. As noted above, we have reformatted the rule to
differentiate between various classes of oil as mandated by EORRA.
Subpart B prescribes particular requirements for an owner or operator
of a facility that stores or uses petroleum oils or non-petroleum oils,
except for animal fats and vegetable oils.
[[Page 47113]]
Introduction to Section 112.8
Background. We have inserted an introduction to Sec. 112.8 so that
we could list the requirements of that section in the active voice.
Those requirements, except as specifically noted, apply to the owner or
operator of an onshore facility (except a production facility). The
introduction does not result in any substantive change in requirements.
Section 112.8(a)--General Requirements--Onshore Facilities (Excluding
Production Facilities)
Background. This is a new provision that merely references the
general requirements which all facilities subject to this part must
meet and the specific requirements that facilities subject to this
section must meet. It does not result in any change to substantive
requirements.
Editorial changes and clarifications. ``Spill prevention'' in the
1991 proposal becomes ``discharge prevention.'' We also deleted from
the titles of each paragraph the words ``onshore'' and ``excluding
production facilities'' because the entire section applies to onshore
facilities and excludes production facilities from its scope. Finally,
the proposed requirement to ``address'' general and specific
requirements and procedures becomes ``meet'' those requirements and
procedures.
Section 112.8(b)(1)--Diked Storage Area Drainage
Background. In 1991, we reproposed the current rule
(Sec. 112.7(e)(1)(i)) on facility drainage from diked areas.
Comments. Applicability. One commenter asked that we limit the
scope of this section to facilities having areas with the potential to
receive discharges greater than 660 gallons or areas with tanks
regulated under these rules. Another commenter said that for facilities
with site-wide containment, or that have substantial stormwater
draining onto and across the site, the requirement is not practical and
may justify reliance on contingency plans instead of containment. That
commenter, and another, suggested that certain devices may reduce the
potential of a significant spill of floating or other products that can
be separated by gravity, such as oil/water separators, underflow
uncontrolled discharge devices, and other apparatus.
De minimis amounts of oil. One commenter thought it would be
impossible to ensure no oil would be discharged into water from diked
areas. The rationale was that oil can be present in water in an amount
below the perception threshold of the human eye.
Response to comments. Applicability. We disagree that we should
limit the scope of this section to facilities having areas with the
potential to receive discharges greater than 660 gallons or areas with
tanks regulated under these rules. Small discharges (that is, of 660
gallons or less) as described in Sec. 112.1(b) from diked storage areas
can cause great environmental harm. See section IV. F of this preamble
for a discussion of the effects of small discharges. We disagree that
this section should apply only to areas with tanks regulated under
these rules because this rule applies to regulated facilities, not
merely areas with regulated tanks or other containers. A facility may
contain operating equipment within a diked storage area which could
cause a discharge as described in Sec. 112.1(b).
We disagree that the requirement is not practical for facilities
with site-wide containment, or that have substantial stormwater
draining onto and across the site. Where oil/water separators,
underflow uncontrolled discharge devices, or other positive means
provide equivalent environmental protection as the discharge restraints
required by this section, you may use them, if you explain your reasons
for nonconformance. See Sec. 112.7(a)(2). However, you must still
ensure that no oil will be discharged when using alternate devices.
De minimis amounts of oil. This rule is concerned with a discharge
of oil that would become a discharge as described in Sec. 112.1(b).
When oil is present in water in an amount that cannot be perceived by
the human eye, the discharge might not meet the description provided in
40 CFR 110.3. Therefore, such a discharge might not be a discharge in a
quantity that may be harmful, and therefore not a reportable discharge
under part 110. However, a discharge which is invisible to the human
eye might also contain components (for example, dissolved petroleum
components) which would violate applicable water quality standards,
making it a reportable discharge. Therefore, we are keeping the
language as proposed, other than making some editorial changes.
Industry standards. Industry standards that may assist an owner or
operator with facility drainage include: (1) NFPA 30, ``Flammable and
Combustible Liquids Code''; and (2), API Standard 2610, ``Design,
Construction, Operation, Maintenance, and Inspection of Terminal and
Tank Facilities.''
Editorial changes and clarifications. ``Spill or other excessive
leakage of oil'' and ``leakage'' become ``discharge.'' The phrase
``handle such leakage'' becomes ``control such discharge.'' We deleted
the phrase ``or other positive means,'' because it is confusing when
compared with the text of Sec. 112.7(a)(2). Under Sec. 112.7(a)(2), you
have the flexibility to use alternate measures ensuring equivalent
environmental protection. The word ``examine'' becomes ``inspect.''
Section 112.8(b)(2)--Diked Storage Areas--Valves Used; Inspection of
Retained Stormwater
Background. In 1991, we reproposed the current rule on the type of
valves that must be used to drain diked storage areas. The rule also
addresses inspection of retained stormwater.
Comments. Innovative devices. Two commenters believed that the rule
would apparently preclude the use of innovative containment devices to
control discharges from containment dikes, such as imbiber beads. These
beads are inside a small cylinder that filters releases from a
containment area. The beads are inserted where a valve would be placed
and allow water to pass, but prevent release of oil by closing on
contact. Another commenter asked that the rule allow oil-water gravity
separation systems instead of valves.
PE certification. One commenter suggested that a section should be
added to the rule requiring that Professional Engineers be required to
certify the design and construction of the stormwater drainage system
and the sanitary sewer system, because the Professional Engineer is in
the best position to prepare the spill containment parts of the SPCC
Plan.
Response to comments. Innovative devices. This rule does not
preclude innovative devices that achieve the same environmental
protection as manual open-and-closed design valves. If you do not use
such valves, you must explain why. The provision for deviations in
Sec. 112.7(a)(2) allows alternatives if the owner or operator states
his reasons for nonconformance, and if he can provide equivalent
environmental protection by some other means. However, you may not use
flapper-type drain valves to drain diked areas. And if you use
alternate devices to substitute for manual, open-and-closed design
valves, you must inspect and may drain retained stormwater, as provided
in Sec. 112.8(c)(3)(ii), (iii), and (iv), if your facility drainage
drains directly into a watercourse, lake, or pond bypassing the
facility treatment system.
PE certification. PE certification is already required for the
design of
[[Page 47114]]
stormwater drainage and sanitary sewer systems by current rules because
those systems are a technical element of the Plan. Therefore, we are
keeping the language as proposed.
Editorial changes and clarifications. In the first sentence, we
deleted the phrase ``as far as practical'' because it is confusing when
compared to the text of Sec. 112.7(a)(2). Under Sec. 112.7(a)(2), if
the requirement is not practical, you have the flexibility to use
measures ensuring equivalent environmental protection. In the second
sentence, we clarify that the wastewater treatment plant mentioned
therein is an ``on-site wastewater treatment plant.'' Also in that
sentence, we clarify that you must inspect and ``may drain'' retained
stormwater, as provided in Sec. 112.8(c)(3)(ii), (iii), and (iv).
Finally, in the last sentence, we clarify that drained retained
stormwater must be ``uncontaminated.''
Section 112.8(b)(3)--Drainage Into Secondary Containment; Areas Subject
to Flooding
Background. In 1991, we proposed to clarify that only undiked areas
that are located such that they have a reasonable potential to be
contaminated by an oil discharge are required to drain into a pond,
lagoon, or catchment basin. We explained that a good Plan should seek
to separate reasonably foreseeable sources of contamination and non-
contamination.
We also proposed to make a recommendation of the current
requirement that catchment basins not be located in areas subject to
periodic flooding.
Comments. One commenter supported the proposal.
Editorial changes and clarifications. One commenter suggested that
the rule should be worded to refer to systems ``with a potential for
discharge,'' rather than with a ``potential for contamination.''
Applicability. Two commenters argued that the secondary containment
provisions of this paragraph should ``remain a recommendation as
opposed to a regulation,'' because a requirement is impracticable for
drainage systems from pipelines that move product throughout the
facility.
Alternatives. One commenter said that the rule should not be
limited to drainage trenches, and that the owners and operators of
facilities should have a free choice of design. Another commenter
suggested that if areas under aboveground piping and loading/unloading
areas are regulated under this section, the operation should have the
option of providing spill control by committing to the regular
inspection of, and immediate clean-up of spills within such areas.
Another commenter urged that we clarify that oil/water separators meet
the requirement for drainage control and secondary containment because
such units, when properly sized and operated, meet the requirements of
good engineering practice for preventing discharges of oil. One
commenter suggested that in rural areas where electrical equipment is
widely spaced, it may be more practical to provide for individual
secondary containment rather than site-wide diversion facilities. Other
commenters suggested that the drainage requirements in urban areas
would be impossible to meet for transformers located in vaults in large
office and apartment buildings, and underneath urban streets because
there is no space at such sites to construct the sort of drainage
control structures required by the rule.
Areas subject to periodic flooding. One commenter argued that the
proposed recommendation should be retained as a requirement because it
is highly unlikely that catchment basins would operate effectively
during a flood event, and that these facilities could cause significant
harm to the environment. Another commenter suggested that drainage
systems for existing facilities be engineered (even if it requires
pumping of contaminated water to a higher level for storage prior to
treatment) so that minimal amounts of contaminated water are retained
in areas subject to periodic flooding.
Response to comments. Applicability. We disagree that the rule
language should become a recommendation because we believe that it is
important to control the potential discharges the rule addresses. Where
a drainage system is infeasible, if you explain your reasons for
nonconformance, you may provide equivalent environmental protection by
an alternate means.
In response to the commenter who questioned the applicability of
this paragraph to areas under aboveground piping and loading/unloading
areas, we note that both areas are subject to the rule's requirements
if they are undiked.
Alternatives. The rule does not limit you to the use of drainage
trenches for undiked areas. Other forms of secondary containment may be
acceptable. The rule only prescribes requirements for the drainage of
diked areas, but does not mandate the use of diked areas. However, if
you do use diked areas, the rule prescribes minimum requirements for
drainage of those areas. Also, if the requirement is not practical, you
may explain your reasons for nonconformance and provide equivalent
environmental protection under Sec. 112.7(a)(2).
Areas subject to periodic flooding. We agree with the commenter
that the current requirement should remain a requirement and not be
converted into a recommendation. We are convinced by the argument that
catchment basins will not work during flood events and may cause
significant environmental damage. We also agree with the commenter that
any drainage system should be engineered so that minimal amounts of
contaminated water are retained in areas subject to periodic flooding.
Therefore, we have retained the current requirement. We also recommend,
but do not require that ponds, lagoons, or other facility drainage
systems with the potential for discharge not be located in areas
subject to periodic flooding.
Editorial changes and clarifications. We agree that the wording
``potential for discharge'' meets the intent of the rule better than
``potential for contamination'' and have made that change.
Section 112.8(b)(4)--Diversion Systems
Background. In 1991, we proposed that diversion systems must retain
oil in the facility, rather than return it to the facility after it has
been discharged.
Comments. One commenter asked for a clarification that oil
``retained'' in a facility does not leave the facility boundaries. A
second commenter suggested that oil be either retained within the
facility or returned to the facility, whichever is applicable. The
commenter further suggested that the diversion system apply only to the
petroleum areas of the facility such as tanks, pipes, racks, and diked
areas because drainage from the rest of the facility should not be
contaminated and thus should not have to be diverted.
Response to comments. The rule accomplishes the aim of retaining
within the facility minimal amounts of contaminated water in undiked
areas subject to periodic flooding. It is better that a diversion
system retain rather than allow oil to leave the facility, thus
enhancing the prevention goals of the rule. Furthermore, it should be
easier to retain discharged oil rather than retrieve oil that has been
discharged from the facility. Therefore, we agree with the commenter
that ``retained'' oil is oil that never leaves the facility. We also
agree that the rule applies only to drainage from the ``petroleum'' (or
other oil) areas of the facility such as tanks, pipes, racks, and diked
areas, because the purpose of the SPCC rule is to prevent discharges of
oil, not of all runoff contaminants. Amendment of the rule
[[Page 47115]]
language is unnecessary because all of the rule applies only to
``petroleum'' or ``oil'' areas of the facility. Therefore, we have
promulgated the rule language as proposed with a minor editorial
change.
Editorial changes and clarifications. We clarify that the reference
to the engineering of facility drainage is a reference to paragraph
(b)(3).
Section 112.8(b)(5)--Natural Hydraulic Flow, Pumps
Background. In 1991, we reproposed substantively the current rule
(see Sec. 112.7(e)(1)(v)) concerning hydraulic flow and pump transfer
for drainage waters.
Comments. We received one editorial comment regarding a grammatical
error in the proposal. The commenter suggested that the second sentence
of the proposal read, ``If pump transfer is needed, two ``lift'' pumps
shall be provided, and at least one of the pumps shall be permanently
installed when such treatment is continuous.'' We received no
substantive comments.
Editorial changes and clarifications. We deleted the first sentence
from the proposed rule because it is a recommendation. We are not
including recommendations in this rule so as to avoid confusion in the
regulated community as to what is required and what is not. We agree
with the commenter's editorial suggestion regarding the second
sentence, and have amended the rule accordingly. In the last sentence
of the proposal, the phrase ``oil will be prevented from reaching
navigable waters of the United States, adjoining shorelines, or other
waters that would be affected by discharging oil as described in
Sec. 112.1(b)(1) of this part'' becomes `` to prevent a discharge as
described in Sec. 112.1(b). * * *''
Response to comments. We have corrected the grammatical error.
Proposed Section 112.8(b)(6)--Additional Requirements for Events that
Occur During a Period of Flooding
Background. In 1991, we proposed a new recommendation that
facilities should address the need to comply with Federal, State, and
local governmental requirements in areas subject to flooding. We noted
that this recommendation was consistent with Federal Emergency
Management Agency (FEMA) rules found at 44 CFR part 60 for aboveground
storage tanks located in flood hazard areas.
Comments. One commenter suggested that exploration and production
tanks located in flood plain areas should be adequately secured through
proper mechanical or engineering methods to reduce the chance of loss
of product. Another commenter argued that the proposed rule should be
eliminated because it is duplicative of stormwater regulations. One
commenter urged that the rule require that no facilities for oil or
hazardous substances be sited in floodplains. Another commenter
requested that the rule require that: (1) A facility should identify
whether it is in a floodplain in the SPCC Plan; (2) if it is in a
floodplain, the Plan should address minimum FEMA standards; and, (3) if
a facility does not meet minimum FEMA standards, the Plan should
address appropriate precautionary and mitigation measures for potential
flood-related discharges. The commenter also suggested that we consider
requiring facilities in areas subject to 500-year events to address
minimum FEMA standards. A second commenter supported a requirement for
special considerations in the Plan for facilities in areas subject to
flooding. That commenter also suggested that we define ``areas subject
to flooding,'' and noted that other Federal rules (i.e., RCRA) define
this as the 25-year floodplain. Another commenter thought the term
``areas subject to flooding'' should be explained in terms of a 100-
year flood event. A final comment noted that the preamble spoke to a
recommendation that facilities address precautionary measures if they
are located in areas subject to flooding, while the recommendation text
spoke to requirements for events that occur during a period of
flooding. The commenter urged reconciliation of the differing language.
Response to comments. We deleted this recommendation because it is
more appropriately addressed in FEMA rules and guidance, including the
definitions the commenters referenced. We disagree that the proposed
recommendation should be made a requirement because flood control plans
and design capabilities for discharge systems are provided for under
the stormwater regulations, and further Federal regulations would be
duplicative.
Other Federal rules also apply, making further SPCC rules
unnecessary. Oil storage facilities are considered structures under the
National Flood Insurance Program (NFIP), and therefore such structures
are subject to the Regulations for Floodplain Management at 44 CFR
60.3. Some of the specific NFIP standards that may apply for
aboveground storage tanks include the following: (1) tanks must be
designed so that they are elevated to or above the base flood level
(100-year flood) or be designed so that the portion of the tank below
the base flood level is watertight with walls substantially impermeable
to the passage of water, with structural components having the
capability of resisting hydrostatic and hydrodynamic loads, and with
the capability to resist effects of buoyancy (44 CFR 60.3(a)(3)); (2)
tanks must be adequately anchored to prevent flotation, collapse or
lateral movement of the structure resulting from hydrodynamic and
hydrostatic loads and the effects of buoyancy (40 CFR 60.3(c)(3)); for
structures that are intended to be made watertight below the base flood
level, a Registered Professional Engineer must develop and/or review
the structural design, specifications, and plans for construction, and
certify that they have been prepared in accordance with accepted
standards and practice (40 CFR 60.3(c)(4)); and, tanks must not
encroach within the adopted regulatory floodway unless it has been
demonstrated that the proposed encroachment would not result in any
increase in flood levels within the community during the occurrence of
the base flood discharge (40 CFR 60.3(d)). Additionally, the NFIP has
specific standards for coastal high hazard areas. See 40 CFR
60.3(e)(4).
Section 112.8(c)(1)--Construction of and Materials Used for Containers
Background. In 1991, we reproposed without substantive change
current Sec. 112.7(e)(2)(i), which requires that no tank 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
and temperature. The only changes we proposed were editorial. We also
proposed a new recommendation that the construction, materials,
installation, and use of tanks conform with relevant industry standards
such as API, NFPA, UL, or ASME standards, which are required in the
application of good engineering practice for the construction and
operation of the tank.
Comments. Several commenters asked that the proposal be recast as a
recommendation rather than a rule, arguing that the words of the
proposal, when taken in conjunction with Sec. 112.7(a) language
requiring the use of good engineering practice in the preparation of
Plans, were contradictory. A commenter noted that Sec. 112.8(c)(1)
recommends that materials, construction, and installation of tanks
adhere to industry standards ``which are required in the application of
good engineering practice for the construction and operation of the
tank.'' The commenter asserted that since it is clear in the preamble
that the Agency's intent is to make the use of industry standards a
recommendation rather than a
[[Page 47116]]
requirement, the rule should be modified to reflect that. Another
commenter supported the proposal as a requirement on the theory that
all tanks should be required to meet industry standards. A third
commenter asked for clarification as to whether we intended a
recommendation or a requirement.
One commenter asked that we specifically reference steel storage
tank systems standards in the rule.
Response to comments. 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 mandatory and what actions
are discretionary. The Professional Engineer must, pursuant to
Sec. 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 is a matter of
good engineering practice.
Industry standards. Industry standards that may assist an owner or
operator with the material and construction of containers include: (1)
API Standard 620, ``Design and Construction of Large Welded Low-
Pressure Storage Tanks''; (2) API Standard 650, ``Welded Steel Tanks
for Oil Storage''; (3) Steel Tank Institute (STI) F911, ``Standard for
Diked Aboveground Steel Tanks''; (4) STI Publication R931, ``Double
Wall Aboveground Storage Tank Installation and Testing Instruction'';
(5) UL Standard 58, ``Standard for Steel Underground Tanks for
Flammable and Combustible Liquids''; (6) UL Standard 142, ``Steel
Aboveground Tanks for Flammable and Combustible Liquids''; (7) UL
Standard 1316, ``Standard for Glass-Fiber-Reinforced Plastic
Underground Storage Tanks for Petroleum Products''; and, (8) Petroleum
Equipment Institute (PEI) Recommended Practice 200, ``Recommended
Practices for Installation of Aboveground Storage Systems for Motor
Vehicle Fueling.''
Editorial changes and clarifications. ``Bulk storage tanks''
becomes ``bulk storage containers.'' We deleted the abbreviation
``etc.'' from the end of the paragraph because it is unnecessary. The
use of the phrase ``such as pressure and temperature'' already
indicates that these are only some examples of such conditions.
Section 112.8(c)(2)--Secondary Containment--Bulk Storage Containers
Background. In 1991, we reproposed current secondary containment
requirements with several significant additions. We gave notice in the
preamble (at 56 FR 54622-23) that ``sufficient freeboard'' is freeboard
sufficient to contain precipitation from a 25-year storm event. We also
proposed in rule language that diked areas must be sufficiently
impervious to contain spilled oil for at least 72 hours. The current
standard is that such diked areas must be ``sufficiently impervious''
to contain spilled oil.
Comments. Secondary containment, in general. One commenter asked
for clarification of what ``primary containment system'' means. One
commenter opposed the requirement for secondary containment on the
grounds that impervious containment of a volume greater than the
largest single tank may not be necessary for all tanks, and that
existing facilities may find it difficult to retrofit. In this vein,
another commenter asked for a phase-in of the requirements, and a third
asked for variance provisions so that a facility would not have to make
small additions to its secondary containment for minimum environmental
benefit. Another commenter argued that the requirement should be
applied to large facilities only. One commenter believed that the
proposal duplicates NPDES stormwater rules. Two commenters believed the
requirement should apply only to unmanned facilities. See also the
comments and response to comments concerning secondary containment in
the discussion of Sec. 112.7(c), above.
Sufficient freeboard. Several commenters said that the standard of
a 25-year storm event might be difficult to determine without extensive
meteorological studies. Other commenters asked for clarification of the
terms ``sufficient'' and ``freeboard,'' or of the phrase ``sufficient
freeboard.'' Likewise, several commenters asked for clarification of
the Agency's position that sufficient freeboard would be that which
would withstand a 25-year storm event. Two commenters suggested a
standard of 110% of tank capacity. Other commenters suggested
alternatives for the 25-year storm event, such as a 24-hour, 10 year
rain; or a 24-hour, 25-year storm. Another commenter suggested the
adequacy of freeboard should be left flexible on a facility-specific
basis.
Seventy-two-hour impermeability standard. Similar to the comments
directed toward the proposed requirements for secondary containment in
Sec. 112.7(c), some commenters objected to the proposed 72-hour
impermeability standard. See the comments and response to comments for
Sec. 112.7(c) above.
Response to comments. 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
Sec. 112.1(b) from a small facility may be as environmentally
devastating 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 Sec. 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 Sec. 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 Sec. 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.
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
[[Page 47117]]
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 Sec. 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.
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.
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 Sec. 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 Sec. 112.1(b) by ensuring that
diked areas can contain oil and are sufficiently impervious to prevent
such discharges.
Industry standards. Industry standards that may assist an owner or
operator with secondary containment for bulk storage containers
include: (1) NFPA 30, ``Flammable and Combustible Liquids Code''; (2)
BOCA, National Fire Prevention Code; (3) API Standard 2610, ``Design
Construction, Operation, Maintenance, and Inspection of Terminal and
Tank Facilities''; and, (4) Petroleum Equipment Institute Recommended
Practice 200, ``Recommended Practices for Installation of Aboveground
Storage Systems for Motor Vehicle Fueling.''
Editorial changes and clarifications. 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 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 Sec. 112.7(d). Under
Sec. 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.* * *''
Section 112.8(c)(3)--Drainage of Rainwater
Background. In 1991, we reproposed the current rule on drainage of
rainwater, incorporating the CWA standard, i.e., ``that may be
harmful,'' into the proposal.
In 1997, we proposed that records required under NPDES
Secs. 122.41(j)(2) and 122.41(m)(3) would suffice for purposes of this
section, so that you would not have to prepare duplicate records
specifically for SPCC purposes. The proposed change would also apply to
records maintained regarding inspection of diked areas in onshore oil
production facilities prior to drainage. See 112.9(b)(1).
Comments. 1991 comments. One commenter in 1991 suggested that we
allow use of NPDES records for purposes of this section. Another
commenter suggested that records of discharges that do not violate
water quality standards are unnecessary.
1997 comments. Many commenters favored the 1997 proposal. One
commenter opposed the proposal if the records were not to be required
by NPDES. Specifically, the commenter sought an exemption for
discharges of rainwater containing animal fats and vegetable oils if
such discharges are not regulated under NPDES rules. The commenter
believed that an exception should be created for reporting and
recording dike bypasses of Sec. 112.7(e)(2)(iii)(D) relating to animal
fats and vegetable oil storage, only requiring such reporting and
recording if required by an NPDES stormwater permit, because in all
cases discharge of contaminated stormwater is not permitted. Asking why
EPA should regulate stormwater bypass events if the stormwater is not
contaminated, the commenter argued that if stormwater permits do not
require reporting and recording of dike bypass events, then EPA should
not require an added tier of regulation under SPCC Plans. Other
commenters thought that EPA was adopting by reference the NPDES rules
and sought clarification on the issue.
Response to comments. We agree with the first 1991 commenter
mentioned above and proposed that change in 1997. We disagree with the
second 1991 commenter that records of discharges
[[Page 47118]]
that do not violate water quality standards are unnecessary. Such
records show that the facility has complied with the rule.
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.
Editorial changes and clarifications. In the introduction to the
paragraph (c)(3), ``drainage of rainwater'' becomes ``drainage of
uncontaminated rainwater.'' In paragraph (c)(3)(ii), which read, ``* *
* run-off rainwater ensures compliance with applicable water quality
standards and will not cause a discharge as described in 40 CFR part
110'' becomes ``* * * retained rainwater to ensure that its presence
will not cause a discharge as described in Sec. 112.1(b).'' Also in
that paragraph, we deleted the phrase ``applicable water quality
standards'' because such standards are encompassed within the phrase
``a discharge as described in Sec. 112.1(b).''
Section 112.8(c)(4)--Completely Buried Tanks; Corrosion Protection
Background. In 1991, we reproposed the current rule requiring that
new completely buried metallic storage tank installations (i.e.,
installed on or after January 10, 1974) must be protected from
corrosion by coatings, cathodic protection, or effective methods
compatible with local soil conditions. We recommended that such buried
tanks be subjected to regular leak testing. The rationale for the
recommendation was that testing technology was rapidly advancing and we
wanted more information on such technology before making the
recommendation a requirement. We also stated a desire to be consistent
with many State rules.
Comments. Corrosion protection. One commenter supported the
proposal for corrosion protection. Another thought a requirement for
corrosion protection ``if soil conditions warrant'' would be
unenforceable. A third commenter complained that the proposal included
no discussion of cathodic protection for tank bottoms in contact with
soil or fill materials. Others thought facilities with underground
tanks subject to part 112 should be required to develop a corrosion
protection plan consistent with 40 CFR part 280, the rules for the
Underground Storage Tanks Program.
Leak testing. Several commenters opposed the proposed
recommendation for leak testing, arguing that owner/operator discretion
should be retained. One commenter suggested that practices for annual
integrity testing and for the installation of pipes under 40 CFR part
280 should be changed from recommended practices to required practices
because recommendations with standards are not usually followed.
Response to comments. 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 Sec. 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 part 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 Sec. 112.8(d)(1) for a
discussion of corrosion protection for buried piping.
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 proposed in 1991 a recommendation that such
buried tanks be subject to regular ``leak testing.'' Proposed
Sec. 112.8(c)(4). Leak testing for purposes of this paragraph is
testing to ensure liquid tightness of a 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.
Editorial changes and clarifications. The first sentence of the
proposed rule was deleted because it was surplus, and contained no
mandatory requirements. It merely noted that completely buried metallic
storage tanks represent a potential for undetected spills. ``Buried
installation'' becomes ``completely buried metallic storage tank,'' to
accord with the definition in Sec. 112.2. We clarify that a ``new''
installation is one installed on or after January 10, 1974, the
effective date of the SPCC rule, by deleting the word ``new'' and
substituting the date. We deleted the phrase ``or other effective
methods,'' because it is confusing when compared to the text of
Sec. 112.7(a)(2). Under Sec. 112.7(a)(2), if you explain your reasons
for nonconformance, you may use alternate methods providing equivalent
environmental protection.
Section 112.8(c)(5)--Partially Buried or Bunkered Tanks; Corrosion
Protection
Background. In 1991, we proposed changing the current requirement
to avoid using partially buried metallic tanks into a recommendation.
We proposed that if you do use such tanks, that you must protect them
from corrosion.
Comments. One commenter argued that the rule should only apply to
new tanks.
Response to comments. Requirement v. recommendation. Due to the
risk of discharge caused by corrosion, we
[[Page 47119]]
decided to keep the current requirement to not use partially buried
metallic tanks, unless 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.
Editorial changes and clarifications. Bunkered tanks are a subset
of partially buried tanks, and are included within the rule to clarify
that it applies to all partially buried tanks. We did not finalize the
proposed phrase ``or other effective methods,'' because it is confusing
when compared to the text of Sec. 112.7(a)(2). Under Sec. 112.7(a)(2),
if you explain your reasons for nonconformance, you may use alternate
methods providing equivalent environmental protection. The proposed
recommendation that ``partially buried or bunkered metallic tanks be
avoided, since partial burial at the earth can cause rapid corrosion of
metallic surfaces, especially at the earth/air interface'' becomes a
requirement to ``not use partially buried or bunkered metallic tanks
for the storage of oil unless you protect the buried section of the
tank from corrosion.''
Section 112.8(c)(6)--Integrity Testing
Background. In 1991, we proposed that integrity testing for bulk
storage tanks be conducted at least every ten years and when material
repairs are conducted. We gave several examples of ``material repairs''
in the preamble. The current requirement for such testing is that it be
``periodic.'' We also proposed that visual inspection, as a method of
testing, must be combined with some other method, because visual
testing alone is insufficient for an integrity test. 56 FR at 54623.
In 1997, we added a proposed sentence to the rule which would allow
the use of usual and customary business records for integrity testing.
We suggested that records maintained under API Standards 653 and 2610
would suffice for this purpose.
Comments. 10-year integrity testing in general. One commenter asked
for a clarification of the term ``integrity testing.'' Several
commenters favored the proposal for ten-year integrity testing. Other
commenters opposed the requirement or favored turning it into a
recommendation. Several commenters proposed testing according to
accepted industry standards, such as American Petroleum Institute
(API), National Fire Protection Association (NFPA), Underwriters
Laboratory (UL), or American Society of Mechanical Engineers (ASME).
Applicability of integrity testing. Some asked for an exemption for
tanks inside buildings. Others asked for an exemption for number 5 and
6 fuel oils, and asphalt, because such oils are heavy and would not
flow very far. Some commenters believed the requirement should not
apply to small facilities because it is ``not standard industry
practice'' to conduct these tests at small facilities. Another
commenter stated that while most large corporations perform testing at
some frequency, most smaller businesses do not. The commenter suggested
that exemptions because of size or quantity of oil stored should not be
granted because the smaller facilities generally are more in need of
testing.
Several commenters suggested that integrity testing should be
waived for tanks which can be visually inspected on the bottom and all
sides, such as tanks located off the ground on crates, and which have
secondary containment. One commenter asked that the requirement apply
only when the tank is used to store corrosive materials or where the
tank has failed within the last five years. Other commenters asked for
a phase-in of the requirement. Utilities asked that the requirement not
apply to electrical equipment because no methods exist for integrity
testing of such equipment, and because the primary reason for failure
of such equipment is not corrosion, but mechanical failure.
Material repairs. Several commenters asked for clarification as to
the meaning of ``material repairs.''
Method of testing. Some commenters favored visual inspection only
because it might be used more frequently than any other method of
testing. Another commenter asked for clarification if visual inspection
meant inspection of both the interior and exterior of a tank. Another
commenter suggested that we augment integrity testing procedures with
procedures to test the tank bottom for settlement and corrosion, and to
test roof supports.
Business records. Most commenters favored the proposal to allow use
of usual and customary business records for integrity testing and other
purposes. Some commenters argued that the suggested API Standards were
unfamiliar to many owners and operators.
Response to comments. 10-year integrity testing in general.
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 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.
Applicability of integrity testing. 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. Because electrical,
operating, and manufacturing
[[Page 47120]]
equipment are not bulk storage containers, the requirement is
inapplicable to those devices or equipment. 56 FR 54623. Also, as noted
by commenters, methods may not exist for integrity testing of such
devices or equipment.
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.
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.
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
maintain records for longer than three years.
Industry standards. Industry standards that may assist an owner or
operator with integrity testing include: (1) API Standard 653, ``Tank
Inspection, Repair, Alteration, and Reconstruction''; (2) API
Recommended Practice 575, ``Inspection of Atmospheric and Low-Pressure
Tanks;'' and, (3) Steel Tank Institute Standard SP001-00, ``Standard
for Inspection of In-Service Shop Fabricated Aboveground Tanks for
Storage of Combustible and Flammable Liquids.''
Editorial changes and clarifications. In the first sentence,
``Aboveground tanks shall be subject to integrity testing * * *''
becomes ``Test each container for integrity * * *'' Also in that
sentence, the phrase ``or a system of non-destructive shell testing''
becomes ``or another system of non-destructive shell testing.'' The
last sentence which read, ``* * * the outside of the container must be
frequently observed by operating personnel for signs of deterioration,
leaks, * * *'' becomes ``* * * you must frequently inspect the outside
of the container for signs of deterioration, leaks, * * *'' We made
that change because the requirements of this paragraph are the
responsibility of the owner or operator, not of ``operating
personnel.''
``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.
Section 112.8(c)(7)--Leakage; Internal Heating Coils
Background. In 1991, we proposed that the current rule on
controlling leakage through defective internal heating coils should be
modified to include a recommendation that retention systems be designed
to hold the contents of an entire tank. We also proposed to change the
current requirement to consider the feasibility of installing external
heating systems into a recommendation.
Comments. One commenter proposed that instead of requiring a
retention system which would hold the entire contents of a tank, that
an oil/water separator might work just as well. Another commenter
opposed requiring the use of oil/water separators. As to the proposed
recommendation to consider use of external heating systems, one
commenter objected to the cost which might be incurred. One commenter
opposed the proposed recommendation due to the belief that leaks in the
aboveground piping can be mitigated through daily inspections and they
are often placed within secondary containment. Another commenter
asserted that with drainage routed to oil/water separators or holding
ponds, leak proof galleys under aboveground piping were redundant and
economically unjustified.
Response to comments. 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 Sec. 112.1(b) by controlling leakage.
Editorial changes and clarifications. We deleted the proposed
recommendations 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.
Section 112.8(c)(8)--Good Engineering Practice--Alarm Systems
Background. In 1991, we reproposed the current rule on ``fail-
safe'' engineering. We added a proposal to allow alternate
technologies. We recommended that sensing devices be tested in
accordance with industry standards.
Comments. Editorial changes and clarifications. Several commenters
objected to the term ``fail-safe'' engineering because they believe
that nothing is ever fail-safe. They suggested using the term ``in
accordance with good engineering practice,'' or ``consistent with
accepted industry practices'' instead.
Applicability. One commenter thought the proposed requirement
should apply to large facilities only or facilities that were the cause
of a reportable spill within the preceding three years. One commenter
suggested a phase-in of the requirement.
[[Page 47121]]
Monitoring. One commenter suggested that a person must be present
to monitor gauges when a fast response system is used to prevent
container overfilling. Another suggested that the requirement for alarm
devices not apply to containers where an operator is present.
Alternatives. One commenter suggested that certain ``procedures''
might suffice instead of alarm devices. Another commenter suggested
that we need to be specific as to methods of testing.
Response to comments. 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.
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.
Alternatives. Under the deviation rule at Sec. 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.
Industry standards. Industry standards that may assist an owner or
operator with alarm systems, discharge prevention systems, and
inventory control include: (1) NFPA 30, ``Flammable and Combustible
Liquids Code''; (2) API Recommended Practice 2350, ``Overfill
Protection for Storage Tanks in Petroleum Facilities''; and, (3) API,
``Manual of Petroleum Measurement Standards.''
Editorial changes and clarifications. Throughout, ``tank'' becomes
``container.'' In the introductory paragraph, we deleted the words ``as
far as practical'' from the rule text because they are confusing when
compared with the text of Sec. 112.7(a)(2). Under Sec. 112.7(a)(2), you
may deviate from a requirement if you explain your reasons for
nonconformance and provide equivalent environmental protection.
``Spills'' becomes ``discharges.'' 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. Finally, in the
introductory paragraph the phrase ``one or more of the following
devices'' becomes ``at least one of the following.'' Not all of the
items listed under this paragraph are devices. For example, regular
testing of liquid sensing devices is a procedure. Therefore, the word
``devices'' was incomplete. In paragraph (i), ``manned operation''
becomes ``attended operation,'' and ``plants'' becomes ``facilities.''
In paragraph (iv), the phrase ``or their equivalent,'' was deleted
because it is confusing when compared with the text of
Sec. 112.7(a)(2). Under Sec. 112.7(a)(2), you may deviate from a
requirement if you explain your reasons for nonconformance, and provide
equivalent environmental protection. Proposed paragraph (v), relating
to alternative technologies, was deleted because alternative devices
are allowed under Sec. 112.7(a)(2).
Section 112.8(c)(9)--Effluent Disposal Facilities
Background. In 1991, we reproposed the current rule on observation
of effluent disposal facilities.
Comments. We received only one comment which asked us to clarify
that ``effluents'' mean oil-contaminated water collected within
secondary containment areas, and that ``disposal facilities'' means
``treatment facilities.''
Editorial changes and clarifications. ``Oil spill event'' becomes
``discharge as described in Sec. 112.1(b).'' ``System upset'' refers to
an event involving a discharge of oil-contaminated water. ``Effluent''
means oil-contaminated water. ``Disposal facilities'' becomes
``effluent treatment facilities.''
Section 112.8(c)(10)--Visible Oil Leaks
Background. In 1991, we reproposed the current requirement that
visible oil leaks must be promptly corrected. Additionally, we proposed
that accumulated oil or oil-contaminated materials must be removed
within 72 hours. The 72-hour proposal in this paragraph was consistent
with the proposal in Sec. 112.7(c). The rationale was that a 72-hour
time period would allow time for discovery and removal of an oil
discharge in most cases. We suggested in the preamble to the 1991
proposal that most facilities are attended at some time within a 72-
hour time period. 56 FR 54621.
Comments. Editorial changes and clarifications. One commenter asked
for clarification of the meaning of ``accumulation'' of oil. Others
asked for clarification of the meaning of ``oil contaminated
materials.'' Another commenter noted that reference to a spill event
within a diked area is inconsistent with its definition.
Applicability. Some commenters thought the requirement should not
apply to small facilities because of the likelihood that the discharge
would be smaller.
Extent and methods of cleanup. One commenter suggested that
covering soil with plastic film may be an acceptable method to prevent
stormwater contamination during remediation. Some commenters suggested
that where a spill creates a risk of fire or explosion, the first
priority should be to eliminate such threats before undertaking
cleanup. Several commenters asked whether removal of accumulations of
oil means complete removal. Some commenters feared that a requirement
to remove oil-contaminated materials would be interpreted to mean that
cleanup of portions of the dike that are oil-stained is required. The
commenters were concerned that such a cleanup would undermine the
stability of the dike and would be unnecessary. One commenter argued
that complete removal would compound landfill disposal problems.
Another commenter asked whether the rule contemplates cleanup of soil
contaminated by past practices. Some commenters argued that the 72-hour
requirement would preclude bioremediation.
72-hour cleanup standard. Some commenters asked how a 72-hour time
limit would be calculated. Those commenters suggested that the clock
begin to run from the time of the discharge itself, or of its
discovery. Others suggested different time periods from
``immediately,'' ``as soon as possible,'' ``within 72 hours,'' ``within
96 hours,'' or ``expeditiously.'' One commenter suggested no time
limit. Some commenters noted that a containment system might be
designed to contain oil for more than 72 hours before it begins to
leak.
One commenter suggested that, depending on site conditions, a 72-
hour time limit might jeopardize worker health and safety. Another
sought clarification on the need to clean up small discharges as
opposed to larger ones within the proposed time limit.
Numerous commenters opposed this requirement because it might
preclude bioremediation. Some thought it would be impossible to meet.
Response to comments. Applicability. The requirement to clean up an
accumulation of oil is applicable to all facilities, large and small.
The damage to the environment may be the same, depending on the amount
discharged.
[[Page 47122]]
Extent of and methods of cleanup. Prevention of contamination is
always the preferred alternative. If you choose, you may spread plastic
film over the diked area if it will prevent the occurrence of an
accumulation of oil. Of course, you must then dispose of the film
properly. We agree with commenters that where a discharge creates a
risk of fire or explosion, the first priority should be to eliminate
such threat before undertaking cleanup. But once that threat is
removed, correction of the source of the discharge and cleanup must
begin promptly.
No matter what method of cleanup you choose, you must completely
remove the accumulation of oil. Any method that works and complies with
all other applicable laws and regulations is acceptable. Bioremediation
may be one acceptable method of cleanup. Acceptable methods will depend
on weather and other environmental conditions. We do not mean to limit
cleanup methods, which will depend on good engineering practice. If the
cleanup method you choose would undermine the stability of the dike,
you must repair the dike to its previous condition.
72-hour cleanup standard. We have deleted the 72-hour cleanup
standard because it would preclude bioremediation. We also agree that
under certain circumstances, such a limit might jeopardize worker
health and safety. Therefore, we have maintained the current standard
that visible discharges must be promptly removed. ``Prompt'' removal
means beginning the cleanup of any accumulation of oil immediately
after discovery of the discharge, or immediately after any actions to
prevent fire or explosion or other threats to worker health and safety,
but such actions 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.
Editorial changes and clarifications. ``Leaks'' becomes
``discharges.'' ``Tank'' becomes ``container.'' ``Accumulation of oil''
means a discharge that causes a ``film or sheen'' in a diked area, or
causes a sludge or emulsion there. See 40 CFR 110.3(b). The reference
to violation of applicable water quality standards in 40 CFR 110.3(b)
does not apply here because the rule assumes that the oil will not have
reached any waters of the United States or adjoining shorelines, but
stays entirely within the diked area of the facility. The term ``oil-
contaminated materials'' is not used in the rule. We eliminate the term
``oil-contaminated materials'' that was used in the proposed rule
because oil must accumulate on something such as materials or soil.
Therefore, the term is redundant. Instead we refer to an 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
impairing the secondary containment system. See also the discussion of
``accumulation of oil'' included with the response to comments of
Sec. 112.9(b)(2). We have removed the term ``spill event'' from the
proposed paragraph and note that we agree with the commenter who noted
that reference to a ``spill event,'' or ``a discharge as described in
Sec. 112.1(b),'' within a diked area is inconsistent with that concept.
Section 112.8(c)(11)--Mobile Containers
Background. In 1991, we proposed to require that mobile tanks be
positioned or located to prevent oil discharges. We recommended
secondary containment for the largest single compartment or tank of any
mobile container. We also recommended that these containers not be
located where they will be subject to periodic flooding or washout.
Comments. Scope of discharge prevention. One commenter asked that
the rule be amended to refer to discharges to navigable waters, instead
of discharges.
Time limits. One commenter asked that a mobile or portable
container be defined as a container which is in place on a contiguous
property for 10 days or less.
Secondary containment. Two commenters supported the secondary
containment proposals, but favored making them requirements instead of
recommendations. One commenter asked that the secondary containment
recommendation for the largest single compartment or container be
modified to include tanks which are manifolded together or otherwise
have overflow capabilities. Another commenter suggested that secondary
containment provide freeboard sufficient to contain precipitation from
a 25-year storm event.
Floods. Other commenters asked for a requirement that mobile tanks
not be located in areas subject to flooding.
Response to comments. Scope of discharge prevention. We agree that
the purpose of the rule is to prevent discharges from becoming
discharges as described in Sec. 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 Sec. 112.1(b),'' rather than ``oil discharges.'' ``A
discharge as described in Sec. 112.1(b)'' is a more inclusive term,
tracking the expanded scope of the amended CWA.
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 Sec. 112.1(b).
Secondary containment. In response to comments, we have maintained
the secondary containment requirement in the current rule because
secondary containment is necessary for mobile containers for the same
reason that it is necessary for fixed containers; to prevent discharges
from becoming discharges as described in Sec. 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 Sec. 112.1(b). Should secondary
containment not be practicable, you may be able to deviate from the
requirement under Sec. 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.
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.
Industry standards. Industry standards that may assist an owner or
operator with secondary containment for mobile containers include: (1)
NFPA 30, ``Flammable and Combustible
[[Page 47123]]
Liquids Code'; and, (2) BOCA, ``National Fire Prevention Code.''
Editorial changes and clarifications. ``Spill event'' becomes ``a
discharge as described in Sec. 112.1(b).'' ``Tank'' becomes
``container.'' We deleted the word ``onshore'' because the whole
section applies only to onshore facilities.
Section 112.8(d)(1)--Buried Piping--Facility Transfer Operations,
Pumping, and Facility Process (Onshore) (Excluding Production
Facilities)
Background. In 1991, we proposed a new recommendation that all
piping installations should be placed aboveground wherever possible. We
added a new proposed requirement that would require protective coating
and cathodic protection for new or replaced buried piping. The current
rule requires such coating and cathodic protection only if soil
conditions warrant. We explained in the preamble that we believe that
all soil conditions warrant protection of buried piping. We did not
propose to make the requirement applicable to all existing piping
because of the significant possibility that replacing all unprotected
buried piping might cause more discharges than it would prevent. If
soil conditions warrant such protection for existing piping, it is
already required by the current rule. We also proposed a new
recommendation that buried piping installation comply to the extent
possible with all the relevant provisions of 40 CFR part 280.
Comments. Aboveground piping recommendation. Two commenters favored
the recommendation. Others requested that it be modified to have all
piping be aboveground only when appropriate, on the theory that some
aboveground piping may become an obstacle to motorized traffic within a
facility, or may be a hazard to worker safety because of the
possibility of tripping over it.
Corrosion protection. Several commenters supported the proposal to
require corrosion protection for all new or replaced buried piping. One
commenter believed that corrosion protection should be required, as in
the current rule, only where soil conditions warrant. One commenter
asked for clarification that the requirement for replaced piping only
applies to the section replaced, not necessarily to the entire line of
piping. Another commenter believed that corrosion protection was
inadequate to protect from discharges, and urged a requirement for
double-walled piping or secondary containment and product sensitive
leak detection for new facilities. One commenter believed that the
recommendation for buried piping installation to comply with 40 CFR
part 280 should be a requirement, not a recommendation.
Response to comments. 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.
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.
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 Sec. 112.7(a)(2) if you explain
your reasons for nonconformance with 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.
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 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 Sec. 112.1(d)(4).
Industry standards. Industry standards that may assist an owner or
operator with corrosion protection for buried piping installations
include: (1) National Association of Corrosion Engineers (NACE)
Recommended Practice-0169, ``Control of External Corrosion on
Underground or Submerged Metallic Piping Systems''; and, (2) STI
Recommended Practice 892, ``Recommended Practice for Corrosion
Protection of Underground Piping Networks Associated with Liquid
Storage and Dispensing Systems.''
Editorial changes and clarifications. In the second sentence of
paragraph (d)(1), we included a reference to ``a State program approved
under part 281 of this chapter.'' In the third sentence, ``examine''
and ``examination'' become ``inspect'' and ``inspection.''
[[Page 47124]]
Section 112.8(d)(2)--Terminal Connections
Background. In 1991, we proposed that when piping is not in service
or is in standby service for 6 months or more, the terminal connection
at the transfer point must be capped or blank-flanged and marked as to
origin. The current rule requires such capping or blank-flanging when
the piping is not in service or is in standby service ``for an extended
time.''
Comments. One commenter supported the six-month clarification of an
``extended time.'' Several commenters opposed the requirement to cap or
blank-flange piping in standby service because such piping may be
needed to be put into service quickly during an emergency to ensure
safe operations at the facility. The commenter suggested that the rule
be reworded to say ``When piping is not in service or is not in standby
service.''
Response to comments. 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.
Editorial changes and clarifications. ``Examine'' becomes
``inspect.''
Section 112.8(d)(3)--Pipe Supports
Background. In 1991, we reproposed without substantive change the
current rule concerning pipe supports.
Comments. We received no comments on this proposal. Therefore, we
have promulgated the provision as proposed.
Section 112.8(d)(4)--Inspection of Aboveground Valves and Piping
Background. In 1991, we proposed that you examine all aboveground
valves, piping, and appurtenances on at least a monthly basis. This
contrasts with the current requirement of ``regular'' examinations. We
also recommended that you conduct annual integrity and leak testing of
buried piping, or that you monitor it on a monthly basis. Finally, we
recommended that all valves, pipes, and appurtenances conform to
relevant industry codes, such as ASME standards. We proposed deletion
from the rule of the current requirement for periodic pressure testing
for piping where facility drainage is such that a failure might lead to
a spill event.
Comments. Monthly examination of aboveground valves, piping, and
appurtenances. One commenter supported the visual monthly examination
proposal, but suggested that we require a more sophisticated method of
testing every three to four years, such as pressure testing. Most other
commenters opposed monthly examinations, on grounds of impracticality.
Most opposing commenters urged testing on a quarterly or semiannual
basis, or per industry standards. Some thought the requirement should
be a recommendation, both for large and small facilities. Electrical
utility commenters asserted that the monthly testing of millions of
pieces of equipment would be extremely burdensome. Several commenters
urged that the examination requirement be limited to visual examination
because of the cost of other methods.
Buried piping. Several commenters favored the proposed
recommendation for annual integrity and leak testing of buried piping
or monitoring of such piping on a monthly basis. One commenter was
concerned that the recommendation made no concession for piping
construction material, length of time in the ground, etc. Several
commenters believed that the recommendation should be a requirement
because piping often runs outside of secondary containment; buried
piping cannot be inspected visually; discharges are common from this
piping; and few owners or operators conduct integrity or leak testing
of such piping. Some thought it should be a requirement for all
facilities, others just for large facilities. One commenter thought
that the requirement to inspect buried piping only when exposed is
inadequate. The commenter suggested that the piping should be subject
to pressure testing. The frequency of the testing would be based on
aquifer use.
Opposing commenters believed annual testing or monthly monitoring
was unnecessary, generally citing cost and practicability reasons. Some
suggested differing time periods for testing, such as every three
years, or every ten years. One commenter believed that the
recommendation should not apply to piping of less than ten feet. Others
asked for clarification as to the type of testing contemplated. One
commenter suggested that the recommendation be clarified to refer only
to oil-handling piping and equipment, and not include buried piping
unrelated to oil operations. Several commenters suggested that we add a
requirement to the rule to conduct integrity and leak testing of
protected piping at the time of installation, modification,
construction, relocation, or replacement, and to conduct an engineering
evaluation of in-service unprotected underground piping every five
years. Another commenter suggested double-walled piping as an
alternative. One commenter suggested that the recommendation was
inappropriate for vaulted tanks because of the configuration of the
tanks.
Response to comments. Monthly inspection of aboveground valves,
piping, and appurtenances. 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 Sec. 112.1(b). Examination
of discharge reports from the Emergency Response Notification System
(ERNS) shows that discharges from such valves, piping, and
appurtenances are much more common than catastrophic tank failure or
discharges from tanks. The requirement must be applicable to large and
small facilities covered by this section that store oil, because of the
same threat of discharge.
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.
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
[[Page 47125]]
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.
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 ``oil-handling'' 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.
If you have vaulted containers, the requirement for integrity and
leak testing of buried piping might be the subject of a deviation under
Sec. 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.
Likewise, we have deleted from rule text the recommendation that
all valves, pipes, and appurtenances conform to industry standards, but
we endorse its substance.
Industry standards. Industry standards that may assist an owner or
operator with inspection and testing of valves, piping, and
appurtenances include: (1) API Standard 570, ``Piping Inspection Code
(Inspection, Repair, Alteration, and Rerating of In-Service Piping
Systems''; (2) API Recommended Practice 574, ``Inspection Practices for
Piping System Components''; (3) American Society of Mechanical
Engineers (ASME) B31.3, ``Process Piping''; and, (4) ASME B31.4,
``Liquid Transportation Systems for Hydrocarbons, Liquid Petroleum Gas,
Anhydrous Ammonia, and Alcohols.''
Editorial changes and clarifications. ``Examine'' and
``examination'' become ``inspect'' and ``inspection.'' We have deleted
the reference to ``operating personnel'' in the first sentence because
all of the requirements of this rule, except when specifically noted
otherwise, are the responsibility of the owner or operator.
Section 112.8(d)(5)--Vehicular Traffic
Background. In 1991, we reproposed the current rule concerning
warnings to vehicular traffic, because of vehicle size, to avoid
endangering aboveground piping. We proposed to amend the rule to
include avoidance of endangering ``other transfer operations'' within
the scope of the warning. We added a recommendation that weight
restrictions should be posted, as applicable, to prevent damage to
underground piping.
Comments. Vehicular warnings. Several commenters supported the
current requirement to warn vehicular traffic to avoid endangering
aboveground piping or other transfer operations because of vehicle
size. Others believed that any size or weight restrictions would
unnecessarily burden facility operations. See the comments below on
weight restrictions. Some believed the proposed requirement should be a
recommendation based on good engineering practices. One thought it made
no difference. One commenter proposed as an alternative, marking such
piping so it could be temporarily protected or avoided. One commenter
suggested that it would be more prudent to require signs where piping
is lower than 14 feet and located such that vehicles can traverse, and
recommended that, in addition to signs, verbal warnings be provided.
Weight restriction posting. Several commenters supported making
this recommendation a requirement because good engineering practice
will exclude heavy equipment from crossing buried piping which does not
have adequate cover to protect the pipe.
Others opposed it on the grounds it would restrict access to
vehicles which ``have driven over the same piping for a dozen or more
years.'' One commenter thought the recommendation was unnecessary
because local building codes or other standards already address the
issue of buried piping protection. Some thought the recommendation
should be a matter of PE discretion. Several commenters thought that
the recommendation should apply to large facilities only because only
large facilities will have the type of tanker trucks on site which
would potentially damage underground piping. One commenter thought that
small facilities should be exempt from the recommendation.
Another commenter believed that the recommendation should be
restricted to situations where it is not certain that the underground
piping can withstand all anticipated vehicular traffic. Another
commenter suggested that if buried piping is placed across a
thoroughfare, it should be installed with additional structural
protection. The commenter asserted that proper installation is a
preventative and is a better alternative than a sign because signs are
not always heeded.
One commenter suggested that posting of weight restrictions at
airports in open areas would be impractical and impact operations. The
commenter argued that the proposal was unreasonable where some buried
piping/hydrant systems run under ramp surfaces. A railroad commenter
argued that the recommendation is overly broad because railroads have a
large amount of piping under track that is built to withstand maximum
loads from vehicular traffic, making the posting of signs unnecessary
and costly. One commenter argued that the requirement was inapplicable
to vaulted tanks
[[Page 47126]]
because the concrete vault reduced the risk of vehicular damage.
Response to comments. Vehicular warnings. 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 Sec. 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
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 Sec. 112.7(a)(2)
if you explain your reasons for nonconformance and provide equivalent
environmental protection.
Weight restriction posting. We deleted the proposed recommendation
concerning weight restrictions as they relate 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.
Editorial changes and clarifications. We deleted the references to
verbal warning or appropriate signs in the rule. Instead, the rule
contains an obligation to warn entering vehicular traffic. Warnings may
be verbal, by signs, or by other appropriate methods.
Introduction to Section 112.9
Background. We have added an introduction to help rewrite the
section in the active voice. Since the owner or operator is the person
with responsibility to implement a Plan, the mandates of the rule are
properly addressed to him, except as specifically noted.
Section 112.9(a)--General Requirements--Onshore Oil Production
Facilities
Background. This is a new provision that merely references the
general requirements which all facilities must meet as well as the
specific requirements that you must meet if you are an owner or
operator of a facility in the category of onshore oil production
facilities.
Editorial changes and clarifications. The obligation to ``address''
general SPCC requirements becomes the obligation to ``meet'' those
requirements. ``Spill prevention'' becomes ``discharge prevention.'' We
also deleted the word ``onshore'' from the titles of the paragraphs of
this section because the entire section applies only to onshore
production facilities.
Proposed Section 112.9(b)--Definition--Onshore Oil Production
Facilities
Background. This proposed section was merely a reference to the old
definition of onshore oil production facility (see current
Sec. 112.7(e)(5)(i)), which is today incorporated within the new
definition of production facility. Therefore, the section is no longer
necessary and we have deleted it.
Section 112.9(b)(1), Proposed as Sec. 112.9(c)(1)--Dike Drains and
Drainage
Background. In 1991, we reproposed the current rule concerning
drainage of diked areas.
Comments. Editorial changes and clarifications. One commenter
suggested an editorial change from discharges to ``navigable waters,''
to a discharge as referenced in Sec. 112.1(b)(1).
Applicability. Another commenter urged a small facility exemption
from this requirement because the recordkeeping involved was too
burdensome.
Engineering methods. One commenter believed that the requirement to
have all drains closed on dikes around storage containers might
preclude engineering methods 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.
Response to comments. Applicability. We believe that this
requirement must be applicable to both large and small facilities to
help prevent discharges as described in Sec. 112.1(b). The risk of such
a discharge and the accompanying environmental damage may be
devastating whether it comes from a large or small facility. We
disagree that the recordkeeping is burdensome. If you are an NPDES
permittee, you may use the stormwater drainage records required
pursuant to 40 CFR 122.41(j)(2) and 122.41(m)(3) for SPCC purposes,
thereby reducing the recordkeeping burden.
Engineering methods. ``Equivalent'' measures referenced in the rule
might, depending on good engineering practice, include using structures
such as 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. Any alternate measures must provide
environmental protection equivalent to the rule requirement.
Industry standards. Industry standards that may assist an owner or
operator with facility drainage include API Recommended Practice 51,
``Onshore Oil and Gas Production Practices for Protection of the
Environment.''
Editorial changes and clarifications. In response to the
commenter's suggestion, the reference to ``navigable waters'' becomes a
reference to ``a discharge as described in Sec. 112.1(b).'' ``Central
treating stations'' becomes ``separation and treating areas.'' Such
areas might be centrally located or located elsewhere at the facility
and might include both separation and treatment devices and equipment.
The reference to ``rainwater is being drained'' becomes ``draining
uncontaminated rainwater.'' We clarify that accumulated oil on
rainwater must be disposed of in accord with ``legally approved
methods,'' not ``approved methods.''
Section 112.9(b)(2)--Proposed as Sec. 112.9(c)(2)--Drainage Ditches,
Accumulations of Oil
Background. In 1991, we sought to clarify that oil as well as oil-
contaminated soil must be removed from field drainage ditches, road
ditches, and the like. The current rule only requires removal of an
``accumulation of oil.'' We also proposed that such accumulations be
removed within 72 hours at the most.
Comments. Applicability. One commenter asserted that this section
does not apply to crude oil transfers from production fields into tank
trucks because any discharges in the transfer process would be caught
in a small
[[Page 47127]]
sump or catchment basin. Another commenter asked if this section
applied to cleanup of oil and oil-contaminated soil from diked areas.
Inspection schedule. Another commenter suggested that we require
inspections of field drainage ditches, etc., at monthly intervals and
within 24 hours of a 25-year storm event.
Accumulations of oil and oil-contaminated soil. Two commenters
argued that EPA lacks authority to require cleanup of contaminated
soil. Others asked for clarifications of the terms ``accumulation'' and
``oil-contaminated soil.'' Another asked what cleanup standard EPA
contemplated under this rule. The commenter elaborated, ``is
accumulated oil and contaminated soil to be removed from diked areas
under this provision?''
72-hour cleanup standard. Several commenters argued that the 72-
hour standard for cleanup would preclude bioremediation or other
cleanup techniques allowed by State and local law. Several commenters
suggested other time periods, including ``as soon as practical,''
``within a timely manner.'' Some suggested no time standard is
appropriate. Those commenters generally thought that a 72-hour period
might be unrealistic in certain cases.
Response to comments. Applicability. Crude oil transfers from
production fields into tank trucks or cars are covered by the general
requirements contained in Sec. 112.7(c) and (h), both of which require
some form of secondary containment. Cleanup of oil, oil-contaminated
soil, and oil-contaminated materials from field drainage ditches, road
ditches, or other field drainage system is covered by this paragraph.
In response to comment, we note that cleanup of oil from diked areas at
onshore production facilities is not specifically covered by the rules.
However, the presence of oil in diked areas may impair the quality of
the dike or the capacity for secondary containment, and if so, the oil
must be removed.
Inspection schedule. We have retained the ``regularly scheduled
intervals'' standard for inspections. This standard means regular
inspections according to industry standards or on a schedule sufficient
to prevent a discharge as described in Sec. 112.1(b). Whatever schedule
for inspections is selected must be documented in the Plan. We decline
to specify a specific interval because such an interval might become
obsolete with changing technology.
Accumulations of oil and oil-contaminated soil. We have adequate
authority to require cleanup of an accumulation of oil, including on
soil and other materials, because section 311(j)(1)(C) of the CWA
provides EPA with the authority to establish procedures, methods, and
equipment and other requirements for equipment to prevent discharges of
oil. The broad definition of ``oil'' in CWA section 311(a)(1) covers
``oil refuse'' and ``oil mixed with wastes other than dredged spoil.''
If field drainage systems allow the accumulation of oil on the soil or
other materials at the onshore facility and that oil threatens
navigable water or adjoining shorelines, then EPA has authority to
establish a method or procedure, i.e., the removal of oil contaminated
soil, to prevent that oil from becoming a discharge as described in
Sec. 112.1(b). The cleanup standard under this paragraph requires the
complete removal of the contaminated oil, soil, or other materials,
either by removal, or by bioremediation, or in any other effective,
environmentally sound manner.
72-hour cleanup standard. We agree that the 72-hour cleanup
standard might preclude bioremediation and have therefore deleted it.
Instead we establish a standard of ``prompt cleanup.'' ``Prompt''
cleanup means beginning the cleanup immediately after discovery of the
discharge or immediately after any actions necessary to prevent fire or
explosion or other imminent threats to worker health and safety.
Editorial changes and clarifications. ``Escaped from small leaks''
becomes ``resulted from any small discharge.'' We eliminate the term
``oil-contaminated soil'' because oil must accumulate on something,
such as materials or soil. We retain the term ``accumulation of oil,''
but elaborate on its meaning. ``Accumulation of oil'' means a discharge
that causes a ``film or sheen'' within the field drainage system, or
causes a sludge or emulsion there (see 40 CFR 110.3(b)). An
accumulation of oil includes anything on which the oil gathers or
amasses within the field drainage system. An accumulation of oil may
include oil-contaminated soil or any other oil-contaminated material
within the field drainage system. See also the discussion of
``accumulation of oil'' included with the response to comments of
Sec. 112.8(c)(10).
Proposed Section 112.9(c)(3)--Additional Requirements for Flood Events
Background. In 1991, we proposed a new recommendation for oil
production facilities in areas subject to flooding. We recommended that
the Plan address additional precautionary measures related to flooding.
In the discussion of the proposal, we referenced FEMA requirements.
Comments. One commenter thought this provision should be a
requirement rather than a recommendation. Another commenter suggested
that exploration and production facilities located in flood plain areas
should be adequately secured through proper mechanical/engineering
methods to reduce the chance of loss of product. A third commenter
suggested the following specific measures to be implemented: (1)
Identify whether the facility is located in a floodplain in the Plan;
(2) if the facility is located in a floodplain, the Plan should address
to what extent it meets the minimum requirements of the National Flood
Insurance Program (NFIP); and (3) if a facility does not meet the
minimum requirements of the NFIP, the Plan should address appropriate
precautionary and mitigation measures for potential flood-related
discharges.
Response to comments. We have deleted the recommendation because we
do not wish to confuse the regulated public over what is mandatory and
what is discretionary. These rules contain only mandatory requirements.
However, we support the substance of the recommendation, and suggest
that a facility in an area prone to flooding either follow the
requirements of the NFIP or employ other methods based on good
engineering practice to minimize damage to the facility from a flood.
Section 112.9(c)(1)--Proposed as Sec. 112.9(d)(1)--Materials and
Construction--Bulk Storage Containers
Background. In 1991, we reproposed the section on materials and
construction of bulk storage containers with an added recommendation
that containers conform to relevant industry standards.
Comments. One commenter thought that the recommendation for use of
industry standards should be a requirement. The commenter asked that at
a date certain, all existing tanks must be upgraded to current
standards, and that all new and reconstructed tanks must be subject to
applicable codes. Another commenter suggested that the recommendation
should not apply to crude oil storage tanks because local industry
standards are more appropriate.
Response to comments. Recommendation v. requirement. We are
retaining the mandatory requirement to use no container for the storage
of oil unless its material and construction are compatible with the
material stored and the conditions of storage, as proposed. We have
deleted the recommendation that materials, installation, and use of
[[Page 47128]]
new tanks conform with relevant portions of industry standards because
we do not wish to confuse the regulated public over what is mandatory
and what is discretionary. However, we endorse its substance. In most
cases good engineering practice and liability concerns will prompt the
use of industry standards. See Sec. 112.3(d)(1)(iii). In addition, a
requirement is not necessary or desirable because local governmental
standards on construction, materials, and installation sometimes
control industry standards on these matters.
Industry standards. Industry standards that may assist an owner or
operator with materials for and construction of onshore bulk storage
production facilities include: (1) API Specification 12B, ``Bolted
Tanks for Storage of Production Liquids'; (2) API Specification 12D,
``Field Welded Tanks for Storage of Production Liquids'; (3) API
Specification 12F, ``Shop Welded Tanks for Storage of Production
Liquids'; (4) API Specification 12J, ``Oil Gas Separators'; (5) API
Specification 12K, ``Indirect-Type Oil Field Heaters'; and, (6) API
Specification 12L, ``Vertical and Horizontal Emulsion Treaters.''
Editorial changes and clarifications. ``Tank'' becomes
``container.''
Section 112.9(c)(2)--Proposed as Sec. 112.9(d)(2)--Secondary
Containment, Drainage
Background. The SPCC Task force concluded that aboveground storage
tanks without secondary containment pose a particularly significant
threat to the environment. We noted that the proposed rule
modifications would ``retain the current requirement for facility
owners or operators who are unable to provide certain structures or
equipment for oil spill prevention, including secondary containment, to
prepare facility-specific contingency plans in lieu of prevention
systems.'' 56 FR 54614. In 1991, we therefore reproposed the secondary
containment requirements for onshore oil production facilities with a
clarification. We clarified that secondary containment must include
sufficient freeboard to allow for precipitation. The current rule
requires that drainage from undiked areas must be safely confined in a
catchment basin or holding pond. The proposed rule had modified this
requirement to apply only to drainage from undiked areas ``showing a
potential for contamination.''
Comments. Secondary containment. See the discussion under
Sec. 112.7(c) of secondary containment in general. One commenter
suggested that the requirement was too vague and comprehensive to be
applied to oil leases, which might cover hundreds of acres. Another
asked how we would determine what is sufficient freeboard.
Drainage. One commenter thought the drainage requirement was
duplicative of NPDES requirements.
Response to comments. Secondary containment. The requirement
applies to oil leases of any size. Secondary containment is not
required for the entire leased area, merely for the contents of the
largest single container in the tank battery, separation, and treating
facility installation, with sufficient freeboard to contain
precipitation. In response to the comment as to how an owner or
operator might determine how much freeboard is sufficient, we have
revised the rule to provide that freeboard sufficient to contain
precipitation is the standard. Freeboard sufficient to contain
precipitation is freeboard installed according to industry standards,
or in an amount sufficient to avert a discharge as described in
Sec. 112.1(b). This standard is consistent with the amount of freeboard
required in Sec. 112.8(c)(2).
Drainage. We deleted the proposed reference to undiked areas
``showing a potential for contamination'' because drainage from any
undiked area poses a threat of contamination. When drainage from such
areas is covered by stormwater discharge permits, that part of the BMP
might be usable for SPCC purposes. There is no redundancy in
recordkeeping requirements, because you can use your NPDES records for
SPCC purposes.
Industry standards. Industry standards that may assist an owner or
operator with secondary containment at onshore production facilities
include: (1) API Recommended Practice 51, ``Onshore Oil and Gas
Production Practices for Protection of the Environment'; (2) NFPA 30,
``Flammable and Combustible Liquids Code'; and, (3) BOCA, ``National
Fire Prevention Code.''
Editorial changes and clarifications. ``Tank battery and central
treating plant installations'' becomes ``tank battery, separation, and
treating facility installations.'' ``Contents of the largest single
tank'' becomes ``capacity of the largest single container.'' With this
change, this paragraph agrees with general secondary containment
requirements found in Sec. 112.7(c). The reference to tanks ``in use''
was deleted because it is redundant. Containment for tanks or
containers that are not permanently closed is already required. We
deleted the phrase ``if feasible, or alternate systems, such as those
outlined in Sec. 112.7(c)(1),'' because it is confusing when compared
to the text of Sec. 112.7(d). Under Sec. 112.7(d), if secondary
containment is not practicable, you must provide a contingency plan
following the provisions of 40 CFR part 109, and otherwise comply with
the requirements of Sec. 112.7(d). Furthermore, you are also free to
provide alternate systems of secondary containment. We do not prescribe
the method.
Section 112.9(c)(3)--Proposed as Sec. 112.9(d)(3)--Container Inspection
Background. In 1991, we proposed that you must visually examine all
containers of oil at onshore production facilities at least once a
year. The current requirement is that you examine these containers ``on
a scheduled periodic basis.'' We also proposed that you would be
required to maintain the schedule and records of those examinations for
a period of five years, irrespective of changes in ownership.
Comments. Frequency of inspection. One commenter favored the
proposal. One commenter suggested quarterly rather than annual
inspections. Two commenters suggested triennial inspections. Other
commenters suggested a frequency in accordance with API recommended
standards.
Extent of inspection. Several commenters thought that the
inspections should be external only, and should not necessarily include
the foundations and supports (as proposed) because of the number of
containers that would be taken out of service with that requirement.
Another commenter asserted that inspection of foundations and supports
might not be possible due to foundation settlement or lack of space to
perform the inspection.
Response to comments. Frequency of inspection. We have maintained
the current standard for frequency of inspection because we agree that
inspections in accordance with industry standards are necessary. Those
standards may change with changing technology, therefore, a frequency
of ``periodically and upon a regular schedule'' preserves maximum
flexibility and upholds statutory intent.
Extent of inspection. We disagree that the inspection of containers
should be limited to external inspection. Internal inspection is also
necessary to detect possible flaws that could cause a discharge. The
inspection must also include foundations and supports that are on or
above the surface of the ground. If for some reason it is not
practicable to inspect the foundations and supports, you may deviate
from the requirement under Sec. 112.7(a)(2), if you explain your
rationale for
[[Page 47129]]
nonconformance and provide equivalent environmental protection.
Record maintenance. We have deleted the proposed requirement to
maintain records of these inspections for five years, irrespective of
ownership, because it is redundant with the general requirement in
Sec. 112.7(e) to maintain Plan records. Section 112.7(e) requires
record maintenance for three years. However, you should note that
certain industry standards (for example, API Standard 653 or API
Recommended Practice 12R1) may specify that an owner or operator
maintain records for longer than three years.
Industry standards. Industry standards that may assist an owner or
operator with inspection of containers at onshore production facilities
include: (1) API Recommended Practice 12R1, ``Recommended Practice for
Setting, Maintenance, Inspection, Operation, and Repair of Tanks in
Production Service''; and, (2) ``API Standard 653, ``Tank Inspection,
Repair, Alteration, and Reconstruction.''
Editorial changes and clarifications. ``Visually examine'' becomes
``Visually inspect.'' ``All tanks'' becomes ``each container.''
``Foundation and supports of tanks above the ground surface'' becomes
``Foundation and support of each container that is on or above the
surface of the ground.''
Section 112.9(c)(4)--Proposed as Sec. 112.9(d)(4)--Good Engineering
Practice
Background. In 1991, we proposed to convert the current requirement
for ``fail-safe'' engineering (which includes vacuum protection and
other measures) of new and old tank battery installations into a
recommendation. We also proposed that you reference appropriate
industry standards.
Comments. One commenter asserted that we should retain the original
requirement to avoid confusion among the regulated community, help
improve spill prevention, and because we proposed a similar requirement
for bulk storage containers. Another commenter opposed the proposed
recommendation because he believed the cost of such engineering would
be prohibitive. Two commenters sought an exemption for small facilities
on the same rationale. Similarly, some commenters opposed the proposed
recommendation on vacuum protection because of the potential cost. None
of the commenters provided their own cost estimates. Some commenters
opposed the proposed recommendation relating to vacuum protection
because of the potential cost, which they estimated as ``in excess of
$100 per tank.''
Response to comments. Good engineering practice. We agree with the
commenter that we should retain this section as a requirement both to
improve spill prevention and to avoid confusion among the regulated
community because of the similar requirement for bulk storage
containers at facilities other than production facilities. Therefore,
there are no new costs. Nevertheless, you have flexibility as to which
measures you use, and may choose the least expensive alternative listed
in Sec. 112.9(c)(4). For example, should vacuum protection be too
costly, you are free to use another alternative. Furthermore, you may
also deviate from the requirement under Sec. 112.7(a)(2) if you can
explain nonconformance and provide equivalent environmental protection
by some other means. We revised the paragraph on vacuum protection to
clarify that the rule addresses any type of transfer from the tank, not
merely a pipeline run.
Industry standards. Industry standards that may assist an owner or
operator with alarm systems include: (1) API, ``Manual of Petroleum
Measurement Standards''; (2) API Recommended Practice 51, ``Onshore Oil
and Gas Production Practices for Protection of the Environment''; (3)
API Recommended Practice 2350, ``Overfill Protection for Storage Tanks
in Petroleum Facilities''; and, (4) NFPA 30, ``Flammable and
Combustible Liquids Code.''
Editorial changes and clarifications. ``Fail-safe'' engineering
becomes ``good engineering practice,'' because fail-safe engineering is
a misnomer. The change in terminology does not imply any substantive
change in the level of environmental protection required, it is merely
editorial. See the comments, and the discussion under ``Editorial
changes and clarification,'' Sec. 112.8(c)(8). The same reasoning
applies to this paragraph. We deleted the phrase ``as far as is
practical,'' because it is confusing when compared to the text of
Sec. 112.7(a)(2). Under Sec. 112.7(a)(2), you may explain your reasons
for nonconformance, and provide equivalent environmental protection by
some other means. We deleted the recommendation to reference
appropriate industry standards because it was unnecessary. You must
discuss actual standards used in the Plan. Section 112.3(d)(1)(iii)
also requires the Professional Engineer to certify that he has
considered applicable industry standards in the preparation of the
Plan. Also in the introductory paragraph, the phrase ``Consideration
shall be given to providing.* * *'' becomes, ``You must provide.* * *''
This change makes the language consistent with a companion paragraph
dealing with good engineering design, i.e., Sec. 112.8(c)(8). In
paragraph (c)(4)(i), ``regular rounds'' becomes ``regularly scheduled
rounds.'' ``Spills'' becomes ``discharges.'' In paragraph (c)(4)(iv),
the phrase ``where facilities are'' becomes ``where the facility is.''
Elsewhere ``tank'' becomes ``container.''
Section 112.9(d)(1)--Proposed as Sec. 112.9(e)(1)--Inspection of
Aboveground Valves and Piping
Background. In 1991, we proposed that you inspect monthly all
aboveground valves and pipelines, and that you maintain records of such
inspections for five years. The current requirement is that you examine
such valves and pipelines ``periodically on a scheduled basis,'' and
maintain the records of such inspections for three years.
Comments. Editorial changes and clarifications. One commenter asked
for clarifying language that the rule only applied to valves and piping
associated with transfer operations.
Applicability. Two commenters asked for an exemption from the
requirements of this paragraph for small facilities.
Frequency of inspections. Several commenters suggested alternate
inspection intervals, such as every six months, or every year. Another
commenter suggested that monthly inspections are meaningless because
some unscrupulous operators might fill out inspection reports on dates
when no problems are to be found. Other commenters suggested that we
require a performance standard instead of a prescribed monthly
inspection. One commenter suggested the proposed inspections standards
for Sec. 112.9(e) were excessive for many small facilities. The
commenter suggested that a standard defined by the licensed
Professional Engineer who certifies the SPCC Plan could reflect the
differing requirements that may apply under different equipment
configurations as well as differing geographical and meteorological
conditions. The commenter added that a generalized performance standard
should be included that includes a minimum inspection interval, such as
annual inspection, which could be altered to meet specific facility
conditions.
Recordkeeping. One commenter thought a five-year record retention
period is excessive. Another commenter asked that we clarify that PE
certification of these regular inspections and records is not required.
Response to comments. Applicability. The rule must apply equally to
large and
[[Page 47130]]
small facilities because failure to inspect piping and valves at any
facility might lead to a discharge as described in Sec. 112.1(b).
Frequency of inspections. We have retained the current inspection
frequency of periodic inspections, but editorially changed it to ``upon
a regular schedule.'' Our decision accords with the comment which
sought a performance standard instead of a prescribed monthly
inspection. The standard of inspections ``upon a regular schedule''
means in accordance with industry standards or at a frequency
sufficient to prevent discharges as described in Sec. 112.1(b).
Whatever frequency of inspections is selected must be documented in the
Plan.
Recordkeeping. We agree that a five-year record retention period is
longer than necessary and have deleted the proposed requirement in
favor of the general requirement in Sec. 112.7(e) to maintain records
for three years. However, comparison records for compliance with
certain industry standards may require an owner or operator to maintain
records for longer than three years. PE certification of these
inspections and records is not required.
Editorial changes and clarifications. ``Examine'' becomes
``inspect.'' We agree with the commenter who asked for clarification
that the rule applies only to inspections related to transfer
operations and have amended the rule to reflect that. A transfer
operation is one in which oil is moved from or into some form of
transportation, storage, equipment, or other device, into or from some
other or similar form of transportation, such as a pipeline, truck,
tank car, or other storage, equipment, or device.
Section 112.9(d)(2)--Proposed as Sec. 112.9(e)(2)--Salt Water Disposal
Facilities
Background. In 1991, we reproposed without change the current
requirements on the examination of salt water (oil field brine)
disposal facilities. The current requirement is that you examine these
facilities ``often.'' However, we have recommended weekly examination
as an appropriate engineering standard for most facilities. 56 FR
54624. We noted that low temperature conditions, sudden temperature
changes, or periods of low flow rates may require more frequent
inspections.
Comments. Applicability. One commenter suggested that the
requirement to examine these facilities should not apply to storage
facilities with de minimis amounts of oil.
Sudden change in temperature. Another commenter asked for
clarification of what ``a sudden change in temperature'' means. The
commenter assumed that it meant a sudden drop that could cause system
upsets.
Response to comments. Applicability. The rule applies to any
regulated facility with salt water disposal if the potential exists to
discharge oil in amounts that may be harmful, as defined in 40 CFR
110.3. This standard is necessary to protect the environment.
Sudden change in temperature. A sudden change in temperature means
any abrupt change in temperature, either up or down, which could cause
system upsets.
Frequency of inspections. Inspections of these facilities must be
conducted ``often.'' ``Often'' means in accordance with industry
standards, or more frequently, if as noted, conditions warrant.
Whatever frequency of inspections is chosen must be documented in the
Plan.
Editorial changes and clarifications. ``Examine'' becomes
``inspect.'' ``Oil discharge'' becomes ``discharge,'' because the term
``oil'' is redundant in the definition of ``discharge.''
Section 112.9(d)(3)--Proposed as Sec. 112.9(e)(3)--Flowline Maintenance
Background. In 1991, we reproposed the current requirements for
flowline maintenance. We proposed a recommendation, rather than a
requirement, that the program include certain specifics, because of
differences in the circumstances of locations, staffing, and design for
production facilities. We suggested that monthly examinations are
appropriate for most facilities.
Comments. Applicability. Two commenters asked for a small facility
exemption for this recommendation.
Frequency of inspections. Several commenters suggested that the
recommendation refer to periodic instead of monthly examinations.
Others suggested annual or quarterly inspections. One commenter said
that monthly inspection of gathering lines buried in the colder parts
of the Appalachian basin is impossible.
Corrosion protection. Several commenters asserted that the
provision for corrosion protection for the bare steel pipe used for
gathering line systems in the Appalachians is impossible because the
cost of coated lines and cathodic protection is prohibitive. None of
the commenters provided their own cost estimates.
Transfer operation. One commenter asked for clarification of the
term ``oil production facility transfer operation.'' The commenter
suggested that a definition of the term would improve compliance.
Response to comments. Applicability. A program of flowline
maintenance is necessary to prevent discharges both at large and small
facilities. However, we have deleted the proposed recommendation
regarding the specifics of the program from the rule. We took this
action because we are not including recommendations in the rule in
order not to confuse the public over what is mandatory and what is
discretionary. This rule contains only mandatory requirements.
Frequency of inspections. In the proposed recommendation we
suggested that you conduct monthly inspections for a flowline
maintenance program. We now recommend that you conduct inspections
either according to industry standards or at a frequency sufficient to
prevent a discharge as described in Sec. 112.1(b). Under
Sec. 112.3(d)(1)(iii), the Professional Engineer must certify that the
Plan has been prepared in accordance with good engineering practice,
including consideration of applicable industry standards.
Corrosion protection, flowline replacement. While we have deleted
the recommendation from rule text due to reasons explained above and
therefore, the rule imposes no new costs, we recommend corrosion
protection, we recommend corrosion protection, and flowline replacement
when necessary, because those measures help to prevent discharges as
described in Sec. 112.1(b).
Transfer operation. A transfer operation is one in which oil is
moved from or into some form of transportation, storage, equipment, or
other device, into or from some other or similar form of
transportation, such as a pipeline, truck, tank car, or other storage,
equipment, or device.
Editorial changes and clarifications. ``Spills'' becomes
``discharges.'' The phrase ``from this source'' becomes ``from each
flowline.''
Section 112.10--Introduction--Onshore Oil Drilling and Workover
Facilities
Background. This paragraph is a new one, not proposed in 1991, but
editorially added to allow us to rewrite the section in the active
voice. Since the owner or operator is the person with responsibility to
implement a Plan, the mandates of the rule are properly addressed to
him, except as specifically noted.
Section 112.10(a)--General and Specific Requirements
Background. This is a new paragraph that merely references the
general
[[Page 47131]]
requirements which all facilities must meet as well as the specific
requirements that facilities in this category must meet.
Comments. One commenter asked for a definition of ``onshore
drilling and workover facilities.''
Editorial changes and clarifications. The new definition for
``production facility'' in Sec. 112.2 includes the procedures, methods,
and equipment referenced in this section, making a definition of
``onshore drilling and workover facilities'' unnecessary. ``Spill
prevention'' becomes ``discharge prevention.'' To ``address''
requirements becomes to ``meet'' requirements.
Section 112.10(b)--Mobile Facilities
Background. In 1991, we reproposed the current rule on the location
of mobile facilities without substantive change.
Comments. Editorial changes and clarifications. One commenter asked
that the requirement be limited to discharges to navigable waters.
Site location. One commenter opposed the requirement on the
location of mobile facilities because the facility contractor has
absolutely no control over the location of the rig unit. The commenter
added that the contractor is instructed by the site owner/operator
where to place the rig unit generally, and the sites are where oil and
gas are expected to be located. The physical location of the well site
is constructed by and maintained by the owner/operator of the lease.
The contractor has no input as to site design nor responsibility for
its maintenance.
Response to comments. Site location. We agree with the commenter
that the contractor is not normally responsible for site location, nor
site design or maintenance. Such decisions are the responsibility of
the facility owner or operator. The owner or operator of the facility
has the responsibility to locate equipment so as to prevent discharges
as described in Sec. 112.1(b).
Editorial changes and clarifications. The applicable limitation on
discharges in the rule tracks the statute. The commenters requested
that discharges be limited to discharges to ``navigable waters.''
However, the correct scope of discharge prevention is not merely
navigable waters, but the entire range of protected resources described
in Sec. 112.1(b). We therefore use the phrase ``a discharge as
described in Sec. 112.1(b).''
Section 112.10(c)--Secondary Containment--Catchment Basins or Diversion
Structures
Background. In 1991, we reproposed without substantive change the
current requirements for secondary containment. We received no comments
on the proposal. Therefore, we have promulgated it as proposed, with
minor editorial changes.
Industry standards. Industry standards that may assist an owner or
operator with secondary containment at onshore oil drilling and
workover facilities include: (1) API Recommended Practice 52, ``Land
Drilling Practices for Protection of the Environment''; (2) NFPA 30,
``Flammable and Combustible Liquids Code''; and, (3) BOCA, ``National
Fire Prevention Code.''
Editorial changes and clarifications. ``Spills'' becomes
``discharges.'' The words ``depending on the location'' were deleted
because they were confusing when compared with the text of
Sec. 112.7(d). If a catchment basin or diversion structure or other
form of secondary containment is not practicable from the standpoint of
good engineering practice, under Sec. 112.7(d) you must provide a
contingency plan following the provisions of 40 CFR part 109, and
otherwise comply with Sec. 112.7(d).
Section 112.10(d)--Blowout Prevention (BOP)
Background. In 1991, we proposed that blowout prevention (BOP)
assembly would only be required ``when necessary.'' The rationale was
that a BOP assembly is not necessary where pressure is not great enough
to cause a blowout (gauge negative) and is not required in all cases.
We noted that the necessity of BOP assembly hinges on the ``history of
the pressures encountered when drilling on the oil reservoir.'' When
that history is unknown, BOP assembly is required.
Comments. Several commenters urged modification of the rule to
exclude well service jobs that may not need BOP assembly, such as the
installation of a rod pumping unit, or the batch treatment of a well
with corrosion inhibitor.
Response to comments. Service jobs. Where BOP assembly is not
necessary, as for certain routine service jobs, such as the
installation of a rod pumping unit, or the batch treatment of a well
with corrosion inhibitor, you may deviate from the requirement under
Sec. 112.7(a)(2), and explain its absence in the Plan. When BOP
assembly is unnecessary because pressures are not great enough to cause
a blowout, it is likewise unnecessary to provide equivalent
environmental protection.
Industry standards. Industry standards that may assist an owner or
operator with blowout prevention assembly include: (1) API Recommended
Practice 16E, ``Design of Control Systems for Drilling Well Control
Equipment''; (2) API Recommended Practice 53, ``Blowout Prevention
Equipment Systems for Drilling Operations''; (3) API Specification 16A,
``Drill Through Equipment''; and, (4) API Specification 16D, ``Control
Systems for Drilling Well Control Equipment.''
Editorial changes and clarifications. We deleted the phrase ``as
necessary'' from the requirement, because it is confusing when compared
to the text of Sec. 112.7(a)(2). When BOP assembly is unnecessary and
therefore no alternate measure is required, you may deviate from the
requirement under Sec. 112.7(a)(2) if you explain your reasons for
nonconformance. We have deleted as surplus the last sentence of the
rule requiring that casing and BOP installations must be in accordance
with State regulatory requirements. Adherence to State regulatory
requirements is mandatory under State law in any case. The phrase ``is
expected to be encountered'' becomes ``may be encountered.''
Section 112.11--Introduction--Offshore Oil Drilling, Production, or
Workover Facilities
Background. We added an introduction as an editorial device to
allow us to rewrite the section in the active voice. Because the owner
or operator is the person with responsibility to implement a Plan, the
mandates of the rule are properly addressed to him, except as
specifically noted.
Section 112.11(a)--General and Specific Requirements--Offshore Oil
Drilling, Production, or Workover Facilities
Background. This is a new paragraph that merely references the
general requirements which all facilities must meet as well as the
specific requirements that facilities in this category must meet.
Comments. State rules. One commenter thought Sec. 112.11 should be
deleted because current State rules provide adequate spill protection
in inland water areas such as lakes, rivers, and wetlands.
Response to comments. State rules. We disagree with the commenter
that these rules are unnecessary because not every State has rules to
protect offshore drilling, production, and workover facilities. While
some States may have rules, some State rules may not be as stringent as
the Federal rules. In any case, Congress has intended us to establish a
nationwide Federal program to protect the environment from the
[[Page 47132]]
dangers of discharges as described in Sec. 112.1(b) posed by this class
of facilities. Therefore, we have retained the section, as modified. We
note, however, that if you have a State SPCC plan or other regulatory
document acceptable to the Regional Administrator that meets all
Federal SPCC requirements, you may use it as an SPCC Plan if you cross
reference the State or other requirements to the Federal requirement.
If it meets only some, but not all Federal SPCC requirements, you must
supplement it so that it meets all of the SPCC requirements.
Editorial changes and clarifications. ``Spill prevention'' becomes
``discharge prevention.'' The obligation to ``address'' requirements
and procedures becomes the obligation to ``meet'' them.
Proposed Section 112.11(b)--Definition Reference; MMS Jurisdiction
Background. The proposed 1991 section referenced the definition of
``offshore oil drilling, production, and workover facility,'' which is
now encompassed within the definition of ``production facility'' in
Sec. 112.2. A new sentence would have referenced the exemption of
facilities subject to Minerals Management Service (MMS) Operating
Orders, notices, and regulations from the SPCC rule. MMS jurisdiction
is outlined in Appendix B to part 112.
Comments. One commenter suggested that we delete the reference to
the proposed definition and to the applicability section.
Response to comments. We agree. Since none of the proposed language
is mandatory, we have deleted it because we have included only mandates
in this rule so as not to confuse the regulated public over what is
required and what is discretionary.
Section 112.11(b)--Proposed as Sec. 112.11(c)--Facility Drainage
Background. In 1991, we reproposed the current section on facility
drainage with the modification to require removal of collected material
at least once a year. The rationale was to prevent a buildup of
accumulated oils. We noted that a protracted removal period could lead
to an accidental excess buildup and resultant overflow.
Comments. Two commenters recommended deletion of the proposed
requirement to remove collected oil as often as necessary, but at least
once a year, because the current requirement is sufficient.
Response to comments. Removal of collected oil. EPA agrees with the
commenter's suggestion that the current rule is sufficient to prevent
discharges as described in Sec. 112.1(b), and therefore we have deleted
the ``at least once a year'' standard. You must remove collected oil as
often as is necessary to prevent such discharges.
Editorial changes and clarifications. ``Discharging oil as
described in Sec. 112.1(b)(1)'' becomes ``having a discharge as
described in Sec. 112.1(b).'' In the second sentence, we deleted the
phrase ``or equivalent collection system sufficient,'' because it is
confusing when compared to the text of Sec. 112.7(a)(2). You may
deviate from a requirement under Sec. 112.7(a)(2) if you explain your
reasons for nonconformance, and provide equivalent environmental
protection.
Section 112.11(c)--Proposed as Sec. 112.11(d)--Sump Systems
Background. In 1991, we proposed to clarify language in current
rule that a regularly scheduled maintenance program is a monthly
preventive maintenance program.
Comments. Frequency of inspections. One commenter recommended that
a semi-annual inspection and testing program of the liquid removal
system, instead of monthly inspection and testing would be preferable.
Response to comments. Frequency of inspections. We have retained
the current rule language requiring a ``regularly scheduled''
preventive maintenance program because we believe that the frequency of
maintenance should be in accordance with industry standards or
frequently enough to prevent a discharge as described in Sec. 112.1(b).
Whatever schedule is chosen must be documented in the Plan.
Editorial changes and clarifications. We deleted the phrase ``or
equivalent method'' from the first sentence because it is confusing
when compared to the text of Sec. 112.7(a)(2). You may deviate from a
requirement under Sec. 112.7(a)(2) if you explain your reasons for
nonconformance and provide equivalent environmental protection.
Section 112.11(d)--Proposed as Sec. 112.11(e)--Discharge Prevention
Systems for Separators and Treaters
Background. In 1991, we reproposed without substantive change the
current rule on discharge prevention systems for separators and
treaters. We received no comments.
Editorial changes and clarifications. ``Escape'' of oil becomes
``discharge'' of oil. ``Oil discharges'' becomes ``discharge of oil.''
We deleted the phrase from the last sentence which allows ``using other
feasible alternatives to prevent oil discharges,'' because it is
confusing when compared to the text of Sec. 112.7(a)(2). You may
deviate from a requirement under Sec. 112.7(a)(2) if you explain your
reasons for nonconformance and provide equivalent environmental
protection.
Section 112.11(e)--Proposed as Sec. 112.11(f)--Atmospheric Storage or
Surge Containers; Alarms
Background. In 1991, we reproposed without substantive change the
current paragraph on alarm systems for atmospheric storage or surge
containers. We received no comments. Therefore, we have promulgated the
rule as proposed, with only minor editorial changes.
Editorial changes and clarifications. ``Oil discharges'' becomes
``discharges.'' We added the words ``that activate an alarm or control
the flow'' to clarify that these activities, along with ``otherwise''
controlling discharges, are the purpose of the sensing devices we
reference in the paragraph. The phrase ``to activate'' becomes ``that
activate,'' and we add the word ``otherwise'' before ``prevent
discharges.'' We deleted the phrase ``or other acceptable
alternatives,'' because it is confusing when compared to the text of
Sec. 112.7(a)(2). You may deviate from a requirement under
Sec. 112.7(a)(2) if you explain your reasons for nonconformance and
provide equivalent environmental protection.
Section 112.11(f)--Proposed as Sec. 112.11(g)--Pressure Containers;
Alarm Systems
Background. In 1991, we reproposed the current rule concerning
pressure tanks without substantive change. We received no comments.
Therefore, we have promulgated the rule as proposed, with minor
editorial changes.
Editorial changes and clarifications. ``Tanks'' becomes
``containers.'' ``Oil discharges'' becomes ``discharges.'' We deleted
the phrase ``or with other acceptable alternatives to prevent
discharges,'' because it is confusing when compared to the text of
Sec. 112.7(a)(2). You may deviate from a requirement under
Sec. 112.7(a)(2) if you explain your reasons for nonconformance and
provide equivalent environmental protection.
Section 112.11(g)--Proposed as Sec. 112.11(h)--Corrosion Protection
Background. In 1991, we reproposed the current paragraph requiring
corrosion protection for containers at facilities subject to this
section. We added a recommendation that you follow National Association
of
[[Page 47133]]
Corrosion Engineers standards for corrosion protection.
Comments. Industry standards. One commenter suggested that we
remove the last sentence, which is advisory, and addresses industry
standards of the National Association of Corrosion Engineers, or make
it a requirement (at least for new construction). Another commenter
suggested that the rule be modified to incorporate other industry
recommended practices relative to corrosion control, such as those of
STI and API. The commenter specifically recommended STI Recommended
Practice R892-89, ``Recommended Practice for Corrosion Protection of
Underground Steel Piping Associated with Underground Storage and
Dispensing Systems,'' and STI Recommended Practice 893-89,
``Recommended Practice for External Corrosion of Shop Fabricated
Aboveground Steel Storage Tank Floors.''
Response to comments. Industry standards. In response to the
comment, we have deleted the recommendation because we do not wish to
confuse the regulated community over what is mandatory and what is
discretionary. These rules contain only mandatory requirements. We
expect that facilities will follow industry standards for corrosion
protection as well as other matters (see Sec. 112.3(d)(iii)), but
decline to prescribe particular standards in the rule text because
those standards are subject to change, and we will not incorporate a
potentially obsolescent standard into the rules.
Industry standards. Industry standards suggested by a commenter
that may assist an owner or operator with corrosion include: (1)
National Association of Corrosion Engineer standards; (2) STI
Recommended Practice R892, ``Recommended Practice for Corrosion
Protection of Underground Steel Piping Associated with Underground
Storage and Dispensing Systems,'' and, (3) STI Recommended Practice
893, ``Recommended Practice for External Corrosion of Shop Fabricated
Aboveground Steel Storage Tank Floors.''
Editorial changes and clarifications. ``Tanks'' becomes
``containers.''
Section 112.11(h)--Proposed as Sec. 112.11(i)--Pollution Prevention
System Procedures
Background. In 1991, we reproposed without substantive change the
current requirements concerning written procedures for inspecting and
testing pollution prevention equipment and systems. We received no
substantive comments. Therefore, we have promulgated the rule as
proposed with minor editorial changes.
Editorial changes and clarifications. ``As part of the SPCC Plan''
becomes ``within the Plan.''
Section 112.11(i)--Proposed as Sec. 112.11(j)--Pollution Prevention
Systems; Testing and Inspection
Background. In 1991, we reproposed the current rule on testing and
inspection of pollution prevention systems. Additionally, we proposed
that simulated spill testing must be the preferred method to test and
inspect oil spill prevention equipment and systems. We also proposed
that pollution prevention systems must be tested at least monthly. The
current standard calls for testing and inspection ``on a scheduled
periodic basis.''
Comments. Some commenters suggested that simulation testing on a
monthly basis is excessive. Commenters suggested instead testing on a
semi-annual or annual basis.
Response to comments. Frequency of testing. We have retained the
current requirement for testing on a ``scheduled periodic basis''
commensurate with conditions at the facility because we believe that
testing should follow industry standards or be conducted at a frequency
sufficient enough to prevent a discharge as described in Sec. 112.1(b)
rather than any prescribed time frame. Whatever frequency is chosen
must be documented in the Plan.
Editorial changes and clarifications. In the first sentence, ``or
other appropriate regulations'' becomes ``and any other appropriate
regulations.'' In the second sentence, ``spill testing'' becomes
``simulated discharges for testing.'' We have deleted from the last
sentence the phrase ``unless the owner or operator demonstrates that
another method provides equivalent alternative protection'' because it
is confusing when compared to the text of Sec. 112.7(a)(2). You may
deviate from a requirement under Sec. 112.7(a)(2) if you explain your
reasons for nonconformance and provide equivalent environmental
protection.
Section 112.11(j)--Proposed as Sec. 112.11(k)--Surface and Subsurface
Well Shut-in Valves and Devices
Background. In 1991, we reproposed the current section concerning
surface and subsurface well shut-in valves and devices. We proposed an
additional requirement that records for each well must be kept for five
years. We received no substantive comments. Therefore, we have
promulgated the rule as proposed, with minor editorial changes.
Editorial changes and clarifications. In today's rule, we kept the
recordkeeping requirement, but deleted language requiring maintenance
of those records for five years. The effect of the deletion is that
records become subject to the general three-year recordkeeping
requirement. See Sec. 112.7(e). You may keep the records as part of the
Plan or may keep them with the Plan.
Section 112.11(k)--Proposed as Sec. 112.11(l)--Blowout Prevention
Background. In 1991, we reproposed the current rule concerning
blowout prevention without substantive change.
Comments. One commenter suggested that there are occasions when
blowout prevention is not warranted or impractical to implement and
that there should be an exception for drilling below conductor casing.
Response to comments. Alternatives. The question of whether blowout
prevention is warranted or impractical or not for drilling below
conductor casing is one of good engineering practice. Acceptable
alternatives may be permissible under the rule permitting deviations
(Sec. 112.7(a)(2)) when the owner or operator states the reasons for
nonconformance and provides equivalent environmental protection.
Industry standards. Industry standards that may assist an owner or
operator with offshore blowout prevention assembly and well control
systems include: (1) API Recommended Practice 16E, ``Design of Control
Systems for Drilling Well Control Equipment''; (2) API Recommended
Practice 53, ``Blowout Prevention Equipment Systems for Drilling
Operations''; (3) API Specification 16A, ``Drill Through Equipment'';
(4) API Specification 16C, ``Choke and Kill Systems''; and, (5) API
Specification 16D, ``Control Systems for Drilling Well Control
Equipment.''
Editorial changes and clarifications. ``BOP preventor assembly''
becomes ``BOP assembly.'' We deleted the last sentence of the paragraph
referring to adherence to State rules because we are not incorporating
State rules into the SPCC rule and adherence to State rules is required
under State law whether we state it or not. The phrase ``expected to be
encountered'' becomes ``may be encountered.''
Proposed Sec. 112.11(m)--Extraordinary Well Control Measures
Background. In 1991, we proposed to change the current requirements
on extraordinary well control measures for emergency conditions to
recommendations. The rationale was
[[Page 47134]]
that we would review these measures in the context of response
planning.
Comments. One commenter suggested that the paragraph should be
deleted because it is advisory, or made a requirement.
Response to comments. In response to comment, we have deleted the
text of the recommendations from the rules because we do not wish to
confuse the regulated community over what is mandatory and what is
discretionary. However, we endorse its substance. This rule contains
only mandatory requirements.
Section 112.11(l)--Proposed as Sec. 112.11(n)--Manifolds
Background. In 1991, we reproposed the current requirements
concerning manifolds without substantive change. We received no
comments on the proposal. Therefore, we have promulgated the rule as
proposed.
Section 112.11(m)--Proposed as Sec. 112.11(o)--Flowlines, Pressure
Sensing Devices
Background. In 1991, we reproposed the current requirements
concerning pressure sensing devices and shut-in valves for flowlines
without substantive change. We received no comments on the proposal.
Therefore, we have promulgated the rule as proposed.
Section 112.11(n)--Proposed as Sec. 112.11(p)--Piping; Corrosion
Protection
Background. In 1991, we reproposed the current requirements
concerning corrosion protection for piping appurtenant to the facility
without substantive change. We also proposed to change into a
recommendation the current requirement that the method used, such as
protective coatings or cathodic protection, be discussed.
Comments. One commenter suggested that we remove the second
sentence, which is advisory.
Response to comments. In response to comment, we have deleted the
recommendation to discuss the method of corrosion protection, because
it is surplus. In your SPCC Plan, you must discuss the method of
corrosion protection you use. See 112.7(a)(1).
Section 112.11(o)--Proposed as Sec. 112.11(q)--Sub-Marine Piping;
Environmental Stresses
Background. In 1991, we reproposed the current requirements
concerning environmental stress against sub-marine piping appurtenant
to facilities without substantive change. We received no comments.
Therefore, we have promulgated the rule as proposed, with minor
editorial changes.
Editorial changes and clarifications. We have rewritten the rule in
the active voice. We also deleted the proposed recommendation because
this rule contains only mandatory items, and because the recommendation
is redundant. Whatever manner of protection is chosen to protect sub-
marine piping must be discussed in the Plan.
Section 112.11(p)--Proposed as Sec. 112.11(r)--Inspections of Sub-
Marine Piping
Background. In 1991, we reproposed the current requirements
concerning the inspection of sub-marine piping appurtenant to
facilities without substantive change. We received no comments.
Therefore, we have promulgated the rule as proposed, with minor
editorial changes.
Editorial changes and clarifications. The proposal to require
maintenance of records for five years was deleted because under
Sec. 112.7(e) of today's rule, all records must be kept for three
years. We clarify that you must inspect or test the piping. Because
visual inspection of sub-marine piping may not always be possible, we
allow testing as an alternative. We encourage inspection or testing
pursuant to industry standards or at a frequency sufficient to prevent
a discharge as described in Sec. 112.1(b). Whatever inspection schedule
you select must be documented in the Plan.
Proposed Sec. 112.11(s)--Written Instructions for Contractors
Background. In 1991, we proposed to change into a recommendation
the current requirement that you prepare written instructions for
contractors and subcontractors whenever contract activities involve
servicing a well, or systems appurtenant to a well or pressure vessel.
The current rule requires that you keep the instructions at the
facility. We note in the proposed rule that under certain
circumstances, you may require the presence of your representative at
the facility to intervene when necessary to prevent a discharge as
described in Sec. 112.1(b).
Comments. One commenter wrote that the proposal creates two serious
problems. First, that since the contractor is hired to perform special
services, he is able to do his work more safely if he is allowed to
direct his own activities. Second, operators might expose themselves to
various types of liability by virtue of the degree of control exercised
over contractors. A second commenter suggested editorial revisions to
the recommendation, and subsequent sentences.
Response to comments. We have decided to delete the proposed
recommendation because we do not wish to confuse the regulated
community over what is mandatory and what is discretionary. This rule
contains only mandatory requirements.
Subparts C and D
Background. In 1995, Congress enacted the Edible Oil Regulatory
Reform Act (EORRA), 33 U.S.C. 2720. That statute mandates that most
Federal agencies differentiate between and establish separate classes
for various types of oils, specifically: animal fats and oils and
greases, fish and marine mammal oils; oils of vegetable origin; and,
other oils and greases, including petroleum and other non-petroleum
oils. In differentiating between these classes of oils, Federal
agencies are directed to consider differences in the physical,
chemical, biological, and other properties, and in the environmental
effects, of the classes.
In 1991, EPA proposed to reorganize the SPCC rule based on facility
type. The rationale for that reorganization is to clarify SPCC Plan
requirements for different types of facilities. While we have
reorganized the rule to provide requirements for different types of
facilities, we also provide requirements for different types of oil in
this rulemaking. To make this change, we have divided the rule into
subparts. Subpart A consists of an applicability section, definitions,
and general requirements for all facilities. Subparts B and C outline
the requirements for different types of oils. Subpart B is for
petroleum oils and non-petroleum oils, except for animal fats and
vegetable oils. Subpart C is for animal fats and oils and greases, and
fish and marine mammal oils; and for vegetable oils, including oils
from seeds, nuts, fruits, and kernels. Subpart D is for response.
Subparts B and C are divided into sections to reflect the differing
types of facilities for each type of oil. Subpart D is for response
requirements.
Therefore, as noted above, we have divided the requirements of the
rule by subparts for the various classes of oils listed in EORRA.
Because at the present time EPA has not proposed differentiated
requirements for public notice and comment, the requirements for
facilities storing or using all classes of oil will remain the same.
However, we have published an advance notice of proposed rulemaking
seeking comments on how we might differentiate requirements for
facilities storing or using the various classes of oil. 64 FR
[[Page 47135]]
17227, April 8, 1999. After considering these comments, if there is
adequate justification for differentiation, we will propose a rule.
Proposed Sec. 112.20(f)(4)--Capacity of Facilities Storing Process
Water/Wastewater for Response Plan Purposes
Background. In 1997, we proposed to add a new paragraph to
Sec. 112.20(f) to provide a method for facility response plan purposes
to calculate the oil storage capacity of storage containers storing a
mixture of process water/wastewater with 10% or less of oil. This
proposal for certain systems that treat process water/wastewater would
be applicable at certain facilities required to prepare a facility
response plan. It would have no effect on facilities required to
prepare response plans because they transfer oil over water and have a
total oil storage capacity greater than or equal to 42,000 gallons.
Likewise, the proposal would have no effect on the method of
calculating capacity for purposes of SPCC Plans. Under the proposal, we
would not count the entire capacity of process water/wastewater
containers with 10% or less of oil in the capacity calculation to
determine whether a facility must prepare a facility response plan. We
only would count the oil portion of that process water/wastewater
contained in Sec. 112.20(f)(2), and therefore response planning is not
necessary.
Today, we are withdrawing the proposal because it is no longer
necessary. It is unnecessary because we have exempted from part 112 any
facility or part thereof (except at oil production, oil recovery, and
oil recycling facilities) used exclusively for wastewater treatment and
not to satisfy any requirement of part 112. See the discussion under
Sec. 112.1(d)(6). The exemption in Sec. 112.1(d)(6) applies to the
types of facilities treating wastewater that would have been allowed to
calculate a reduced storage capacity if the percentage of oil in the
mixture were 10 percent or less.
Section 112.20(h)--Facility Response Plan Format
Background. In 1997, we proposed to amend the requirements for
formatting of a facility response plan to clarify that an Integrated
Contingency Plan (ICP) or other plan format acceptable to the Regional
Administrator is allowable to serve as a facility response plan if it
meets all facility response plan requirements. Our intent was to track
language in the SPCC rule allowing the Regional Administrator similar
authority to accept differing formats for SPCC Plans. However, the
Regional Administrator already has the authority to accept differing
formats for response plans, and the existing facility response plan
requirements already provide for cross-referencing. See Sec. 112.20(h).
Therefore, new rule language was unnecessary, and the proposal tracked
current language. Today, we have made only a minor editorial change in
rule language.
Comments. Acceptable formats. Most commenters favored the proposal.
One commenter suggested that the rule should specifically mention the
ICP. Another requested that State FRP equivalents be accepted. Several
commenters criticized the proposal; one calling the ICP concept ``over-
rated.'' One commenter thought that the rule makes the ICP mandatory.
Another commenter noted that the proposed rule is identical to the
current rule.
Partially acceptable formats. One commenter asked if an operator
would have to integrate all parts of an ICP with a response plan or if
he would have the option to integrate parts of the ICP with the SPCC
Plan.
PE certification. One commenter asked how an ICP would work, i.e.,
whether the PE would be certifying the SPCC portion, the FRP portion,
or both.
Response to comments. Acceptable formats. It is not necessary for
the rule to mention the ICP or any other format specifically because
the rule already allows the Regional Administrator flexibility to
accept any format that meets all Federal requirements. See
Sec. 112.20(h). You may use the ICP, a State response plan, or other
format acceptable to the Regional Administrator, at your option. We do
not require use of any alternative format, but merely give you the
option to do so.
The commenter is correct that the proposed rule is identical to the
current rule. The current rule allows the submission of an ``equivalent
response plan that has been prepared to meet State or other Federal
requirements.''
Partially acceptable formats. You have the option to integrate any
or all parts of an ICP with your response plan. This gives you
flexibility in formatting. Similar to SPCC Plans, the Regional
Administrator may accept partial use of alternative formats.
PE certification. PE certification is only required for the SPCC
portion of any ICP.
Editorial changes and clarifications. We added the words
``acceptable to the Regional Administrator'' in the first sentence
after the words ``response plan.''
Appendix C--Substantial Harm Criteria
Background. In 1997, we proposed changes to Appendix C which would
track proposed amendments to Sec. 112.20(f)(4) regarding calculating
the oil storage capacity of aboveground storage containers storing a
mixture of process water/wastewater within 10% or less of oil. Because
we have withdrawn the proposed changes to Sec. 112.20(f)(4), the
proposed changes to Appendix C are also unnecessary. Therefore, we have
withdrawn the proposed changes to Appendix C, and it remains unchanged.
Appendix C--Section 2.1--Non-Transportation-Related Facilities With a
Total Oil Storage Capacity Greater Than or Equal to 42,000 Gallons
Where Operations Include Over-Water Transfer of Oil
Background. We have corrected the text of the first sentence in the
section to correspond with the title, so that it reads ``A non-
transportation-related facility with a total oil storage capacity
greater than or equal to 42,000 gallons that transfers oil over water
to or from vessels must submit a response plan to EPA. We added the
words ``or equal to'' to track rule language found at
Sec. 112.20(f)(1)(i).
Appendix C--Section 2.4--Proximity to Public Drinking Water Intakes at
Facilities With a Total Oil Storage Capacity Greater Than or Equal to 1
Million Gallons
Background. We have revised the title of this section by reversing
the order of the words ``Storage'' and ``Oil'' in the heading. We have
also added the word ``oil'' to the first sentence so that it reads, ``A
facility with a total oil storage capacity greater than * * *.''
Appendix D--Part A--Section A.2 (Footnote 2)
Background. We have revised footnote 2 to section A.2 of Part A,
Appendix D, to reflect the new citation to the SPCC rule's secondary
containment requirements.
Appendix F--Section 1.2.7--NAICS Codes
Background. We have revised section 1.2.7 to delete the reference
to Standard Industry Classification (SIC) codes, and replace it with a
reference to North American Industry Classification System (NAICS)
codes. The NAICS was adopted by the United States, Canada, and Mexico
on January 1, 1997 to replace the SIC codes.
[[Page 47136]]
Appendix F--Section 1.4.3 Analysis of the Potential for an Oil
Discharge
Background. We have revised the second and last sentences of this
section by replacing the word ``spill'' with ``discharge.''
Appendix F--Section 1.7.3 (7)--Containment and Drainage Planning
Background. We have revised paragraph (7) of section 1.7.3 of
Appendix F to use the new citation to the SPCC rule's inspection and
monitoring requirements for drainage.
Appendix F--Section 1.8.1 Facility Self-Inspection
Background. We have revised section 1.8.1 of Appendix F to use the
new citation to the SPCC rule's recordkeeping requirements. The
revision also reflects the three-year record maintenance periods for
SPCC records and keeps the current five-year period for FRP records.
Editorial changes and clarifications. ``Tanks'' becomes ``each
container.''
Appendix F--Section 1.8.1.1--Tank Inspection
Background. We have revised section 1.8.1.1 of Appendix F to use
the new citation to the SPCC rule's tank inspection requirements.
Appendix F--Section 1.8.1.3 Secondary Containment Inspection
Background. We have revised section 1.8.1.1.4 of Appendix F to use
the new citation to the SPCC rule's secondary containment inspection
requirements.
Appendix F--Section 1.10 Security
Background. We have revised section 1.10 of Appendix F to use the
new citation to the SPCC rule's security requirements.
Appendix F--Section 2.1(6) General Information
Background. We have revised paragraph 2.1(6) to refer to NAICS
codes in place of SIC codes.
Appendix F--Section 3.0 Acronyms
Background. We have deleted the acronym for SIC and substituted the
acronym for NAICS.
Appendix F-Attachment F-1 Response Plan Cover Sheet
Background. We have deleted the reference to SIC and substituted a
reference to NAICS.
VI. Summary of Supporting Analyses
A. Executive Order 12866--OMB Review
Under Executive Order 12866, (58 FR 51735, October 4, 1993), the
Agency must determine whether a regulatory action is ``significant''
and therefore subject to Office of Management and Budget (OMB) review
and the requirements of the Executive Order. The order defines
``significant regulatory action'' as one that is likely to result in a
rule that may:
(1) Have an annual effect on the economy of $100 million or more or
adversely affect in a material way the economy, a sector of the
economy, productivity, competition, jobs, the environment, public
health or safety, or State, local, or tribal governments or
communities;
(2) create a serious inconsistency or otherwise interfere with an
action taken or planned by another agency;
(3) materially alter the budgetary impact of entitlements, grants,
user fees, or loan programs or the rights and obligations of recipients
thereof; or
(4) raise novel legal or policy issues arising out of legal
mandates, the President's priorities, or the principles set forth in
the Executive Order.
Under the terms of Executive Order 12866, it has been determined
that this rule is a ``significant regulatory action'' because it raises
novel legal or policy issues. Such issues include proposed measures
which would relieve facilities of regulatory mandates and could change
the manner in which facilities comply with remaining mandates.
Therefore, this action was submitted to OMB for review. Changes made in
response to OMB suggestions or recommendations will be documented in
the public record.
The reduction in size of the regulated community due to final rule
revisions will lead to a capital cost savings of approximately $29.47
million per year. During the first year, regulated facilities will
experience an increase in total paperwork cost burden of $21.93 million
due primarily to the need to read the rule. In addition, certain
facilities will recalculate their storage capacity to exclude
applicable wastewater treatment systems and, therefore, must amend and
certify their plans if the storage capacity threshold is still met. In
certain cases, however, the wastewater treatment system provision in
section 112.1(b)(6) will result in a facility no longer being subject
to the any Part 112 requirements. However, during the second year,
total paperwork cost burden will decrease by about $60.21 million and
beginning in the third year following the rulemaking, the total
paperwork cost burden to all regulated facilities will decrease by
about $45.03 million. The result is an aggregate cost savings of about
$7.56 million during the first year, $89.69 million during the second
year, and $74.51 million during subsequent years.
B. Executive Order 12898--Environmental Justice
Executive Order 12898 requires that each Federal agency make
achieving environmental justice part of its mission by identifying and
addressing, as appropriate, disproportionately high and adverse human
health or environmental effects of its programs, policies, and
activities on minorities and low-income populations. EPA has determined
that the regulatory changes in this rule will not have a
disproportionate impact on minorities and low-income populations.
C. Executive Order 13045--Children's Health
Executive Order 13045, ``Protection of Children from Environmental
Health Risks and Safety Risks'' (62 FR 19885, April 23, 1997), applies
to any rule that: (1) is determined to be ``economically significant''
as defined under Executive Order 12866; and, (2) concerns an
environmental health or safety risk that EPA has reason to believe may
have a disproportionate effect on children. If the regulatory action
meets both criteria, the Agency must evaluate the environmental health
or safety effects of the planned rule on children, and explain why the
planned regulation is preferable to other potentially effective and
reasonably feasible alternatives considered by the Agency. EPA
interprets Executive Order 13045 as applying only to those regulatory
actions that are based on health or safety risks, such that the
analysis required under Section 5-501 of the Order has the potential to
influence the regulation. This final rule is not subject to Executive
Order 13045 because it is not economically significant as defined in
Executive Order 12866, and because the Agency does not have reason to
believe the environmental health or safety risks addressed by this
action present a disproportionate risk to children. The Agency has no
data that indicate that the types of risks resulting from oil
discharges have a disproportionate effect on children, and does not
have reason to believe that they do so.
D. Executive Order 13175--Consultation and Coordination with Indian
Tribal Governments
On November 6, 2000, the President issued Executive Order 13175
(65 FR 67249) entitled, ``Consultation and Coordination with Indian Tribal
Governments.'' Executive Order 13175 took effect on January 6, 2001,
and revokes Executive Order 13084 (Tribal
[[Page 47137]]
Consultation) as of that date. EPA developed this final rule, however,
under the period when EO 13084 was in effect; thus, EPA addressed
tribal considerations under EO 13084.
Today's rule does not significantly or uniquely affect communities
of Indian tribal governments. Overall, the rule significantly reduces
the regulatory burden, and the few burden increases in the rule do not
uniquely affect Indian tribal governments.
Nevertheless, we consulted with a representative organization of
tribal groups, the Tribal Association on Solid Waste and Emergency
Response. That organization did not provide us with any comments.
E. Executive Order 13132--Federalism
Executive Order 13132, entitled ``Federalism'' (64 FR 43255, August
10, 1999), requires EPA to develop an accountable process to ensure
``meaningful and timely input by State and local officials in the
development of regulatory policies that have federalism implications.''
``Policies that have federalism implications'' is defined in the
Executive Order to include regulations that have ``substantial direct
effects on the States, on the relationship between the national
government and the States, or on the distribution of power and
responsibilities among the various levels of government.''
This final rule does not have federalism implications. It will not
have substantial direct effects on the States, on the relationship
between the national government and the States, or on the distribution
of power and responsibilities among the various levels of government,
as specified in Executive Order 13132. Under CWA section 311(o), EPA
believes that States are free to impose additional requirements,
including more stringent requirements, relating to the prevention of
oil discharges to navigable waters. In proposing modifications to the
SPCC rule, EPA encouraged States to supplement the federal SPCC program
and recognized that some States have more stringent requirements. 56 FR
54612 (Oct. 22, 1991). This rule does not preempt state law or
regulations. Thus, Executive Order 13132 does not apply to this rule.
F. Executive Order 13211--Energy Effects
This rule is not a ``significant energy action'' as defined in
Executive Order 13211, ``Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use''
(66 FR 28355, May 22, 2001) because it is not likely to have a significant
adverse effect on the supply, distribution, or use of energy. The
overall effect of the rule is to decrease the regulatory burden on
facility owners or operators subject to its provisions.
G. Regulatory Flexibility Act (R.F.A.) as amended by the Small Business
Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5 U.S.C. 601 et
seq.
The R.F.A. generally requires an agency to prepare a regulatory
flexibility analysis of any rule subject to notice and comment
rulemaking requirements under the Administrative Procedure Act or any
other statute unless the agency certifies that the rule will not have a
significant economic impact on a substantial number of small entities.
Small entities include small businesses, small organizations, and small
governmental jurisdictions.
For purposes of assessing the impacts of today's rule on small
entities, small entity is defined as: (1) A small business as defined
in the Small Business Administration's (SBA) regulations at 13 CFR
121.201--the SBA defines small businesses by category of business using
North American Industry Classification System (NAICS) codes, and in the
case of farms and production facilities, which constitute a large
percentage of the facilities affected by this rule, generally defines
small businesses as having less than $500,000 in revenues or 500
employees, respectively; (2) a small governmental jurisdiction that is
a government of a city, county, town, school district or special
district with a population of less than 50,000; and (3) a small
organization that is any not-for-profit enterprise which is
independently owned and operated and is not dominant in its field.
In determining whether a rule has a significant economic impact on
a substantial number of small entities, the impact of concern is any
significant adverse economic impact on small entities, since the
primary purpose of the regulatory flexibility analyses is to identify
and address regulatory alternatives ``which minimize any significant
economic impact of the proposed rule on small entities.'' 5 U.S.C. 603
and 604. Thus, an agency may certify that a rule will not have a
significant economic impact on a substantial number of small entities
if the rule relieves regulatory burden, or otherwise has a positive
economic effect on all of the small entities subject to the rule. This
rule will significantly reduce regulatory burden on all facilities,
particularly small facilities. For example, the rule exempts
approximately 55,000 facilities from its scope. Approximately 41,300 of
those facilities are small facilities, and of those, nearly 27,700 are
small farms. This rulemaking will increase information collection
burden for most facilities in the first year by approximately 0.75
million hours due principally to the estimated burden each facility
will incur to read and understand the changes that we are making to the
rule. However, the rule will also reduce the overall annual information
collection burden by nearly 1.59 million hours a year in the second
year and over 1.18 million hours a year in the third year of the
information collection request, much of that for the small facilities
that make up the large majority of our regulated universe. Further, the
rule will reduce costs for both existing and new facilities.
Information collection and other provisions in the final rule that
affect capital costs are expected to yield cost savings of about $7.56
million during the first year, $89.69 million during the second year
and $74.51 million during subsequent years. The rule also gives all
facilities greater flexibility in recordkeeping and other paperwork
requirements. Finally, Sec. 112.7(a)(2) of the rule gives small
businesses and all other facilities the flexibility to use alternative
methods to comply with the requirements of the rule if the facility
explains its rationale for nonconformance and provides equivalent
environmental protection. We have therefore concluded that today's
final rule will relieve regulatory burden for all small entities.
After considering the economic impacts of today's final rule on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities.
H. Unfunded Mandates Reform Act
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Pub.
L. 104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under section 202 of UMRA, EPA
generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final rules with ``Federal mandates'' that
may result in expenditures to State, local, and tribal governments, in
the aggregate, or to the private sector, of $100 million or more in any
one year. Before promulgating an EPA rule for which a written statement
is needed, section 205 of UMRA generally requires EPA to identify and
consider a reasonable number of regulatory alternatives and adopt the
least costly, most cost-effective or least burdensome alternative
[[Page 47138]]
that achieves the objectives of the rule. The provisions of section 205
do not apply when they are inconsistent with applicable law. Moreover,
section 205 allows EPA to adopt an alternative other than the least
costly, most-effective or least burdensome alternative if the
Administrator publishes with the final rule an explanation why that
alternative was not adopted.
Before EPA establishes any regulatory requirements that may
significantly or uniquely affect small governments, including tribal
governments, it must have developed under section 203 of UMRA a small
government agency plan. The plan must provide for notifying potentially
affected small governments, enabling officials of affected small
governments to have meaningful and timely input in the development of
EPA regulatory proposals with significant Federal intergovernmental
mandates, and informing, educating, and advising small governments on
compliance with the regulatory requirements.
EPA has determined that this rule does not contain a Federal
mandate that may result in expenditures of $100 million or more for
State, local, and tribal governments, in the aggregate, or the private
sector in any one year. Overall, the rule reduces burden and costs on
all facilities. After the first and second year, the rule is expected
to reduce the information collection burden by over 1.3 million hours
annually.
Approximately 55,000 facilities will no longer be subject to the
SPCC rule. Of these facilities, EPA estimates that approximately 3,500
existing facilities will no longer be required to maintain SPCC plans,
due to the exemption for certain wastewater treatment systems. Other
revisions are expected to exempt approximately 51,400 additional
facilities 39,623 small facilities (including 27,700 small farms). The
exemption for completely buried containers will result in approximately
14,000 facilities no longer subject to the rule, and 37,000 more
facilities with some partial information collection reduction. Further,
EPA estimates Information collection and capital costs are expected to
decrease by over $74.25 million a year in the third year of the SPCC
information collection request. In addition to these SPCC-related
impacts, this rulemaking is estimated to result in cost savings for as
many as 35 facilities that are expected to no longer require facility
response plans due to the wastewater treatment system exemption. The
result of the changes to the scope of the FRP information collection
requirements is a cost savings of approximately $0.23 million per year.
The rule also gives all facilities greater flexibility in recordkeeping
and other paperwork requirements. Finally, Sec. 112.7(a)(2) of the rule
gives small businesses and all other facilities the flexibility to use
alternate methods to comply with the requirements of the rule if the
facility explains its rationale for nonconformance and describes its
method of equivalent environmental protection. Thus, today's rule is
not subject to the requirements of sections 202 and 205 of the UMRA.
In developing this rule, EPA nevertheless consulted with
representative organizations of State, local, and tribal governments.
The representative organizations were the Environmental Council of the
States, the National Association of Counties, and the Tribal
Association on Solid Waste and Emergency Response. None of those
organizations provided us with any comments. However, numerous States
and local governments did comment on the rule proposals in all three
proposed rulemakings. Those commenters submitted a wide variety of
comments. EPA responses to those comments may be found in this document
and in the Comment Response Documents.
EPA has determined that this rule contains no regulatory
requirements that might significantly or uniquely affect small
governments. As explained above, the overall effect of the rule will be
to reduce burden and costs for regulated facilities, including small
governments that are subject to the rule.
I. Paperwork Reduction Act
The Office of Management and Budget (OMB) has approved the
information collection requirements contained in this rule under the
provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and
has assigned OMB control number 2050-0021.
EPA does not collect the information required by SPCC regulation on
a routine basis. SPCC Plans ordinarily need not be submitted to EPA,
but must generally be maintained at the facility. Preparation,
implementation, and maintenance of an SPCC Plan by the facility helps
prevent oil discharges, and mitigates the environmental damage caused
by such discharges. Therefore, the primary user of the data is the
facility. While EPA may, from time to time, request information under
these regulations, such requests are not routine.
Although the facility is the primary data user, EPA also uses the
data in certain situations. EPA primarily uses SPCC Plan data to ensure
that facilities comply with the regulation. This includes design and
operation specifications, and inspection requirements. EPA reviews SPCC
Plans: (1) when it requests a facility to submit a Plan after certain
oil discharges or to evaluate an extension request; and, (2) as part of
EPA's inspection program. Note that the final rule eliminates the
previous requirement to submit the entire Plan after certain
discharges, and merely retains the requirement that it be maintained at
the facility unless EPA requests a copy. State and local governments
also use the data, which are not necessarily available elsewhere and
can greatly assist local emergency preparedness efforts. Preparation of
the information for affected facilities is required under section
311(j)(1) of the Act as implemented by 40 CFR part 112.
In the absence of this final rulemaking, EPA estimates that 469,274
facilities would have been subject to the rule in the first year and
would have already prepared SPCC Plans. In addition, EPA estimates that
approximately 4,700 new facilities would have become subject to the
requirements of the rule annually. EPA also estimates that, in the
absence of this rulemaking, the average annual public reporting and
recordkeeping burden for this collection of information for existing
and newly regulated facilities would have ranged between 4.9 to 13.8
hours and 39.4 to 100.4 hours, respectively, depending on facility
characteristics (e.g., storage capacity).
Through this rulemaking, we expect to reduce both the number of
regulated facilities, as well as the average annual burden for
facilities that remain regulated. The number of regulated facilities
will be reduced by approximately 55,000. The average annual public
reporting for facilities already regulated by the Oil Pollution
Prevention regulation is estimated to range between 8.6 and 12.2 hours,
while the burden for newly regulated facilities is estimated to range
between 35.1 and 65.2 hours as a result of this rulemaking. These
average annual burden estimates take into account the varied
frequencies of response for individual facilities according to
characteristics specific to those facilities, including the frequency
of oil discharges and facility modification, but exclude the
anticipated burden facilities may incur in the first year to read and
understand the changes we are making to the rule.
Under the final rule, an estimated 419,033 existing and newly
regulated facilities will be subject to the SPCC information collection
requirements of this rule during the first year of the information
collection period. The net annualized capital and start-up costs for
[[Page 47139]]
the SPCC information collection portion of the rule average $740,000
and net annualized labor and operation and maintenance costs are
estimated to be $93.00 million for all of these facilities combined.
The information collection burden of the SPCC rule prior to this
rulemaking averaged 2,828,150 hours per year. Under this final rule,
the annual average burden over the next three-year ICR period is
estimated to be 2,208,701 hours, resulting in a 22 percent average
reduction. This rulemaking will increase burden for most facilities in
the first year (totaling approximately 3.6 million hours) due
principally to the estimated burden each facility will incur to read
and understand the changes that we are making to the rule. The first-
year burden also includes the additional need for certain facilities to
amend and certify their SPCC plans to exclude wastewater treatment
volumes from their oil storage capacity. Second year burden is expected
to total approximately 1.3 million hours. In subsequent years, we
estimate that the overall burden will be approximately 1.7 million
hours annually, representing a nearly 40 percent reduction versus the
average annual burden from the previous information collection period.
Burden means the total time, effort, or financial resources expended by
persons to generate, maintain, retain, or disclose or provide
information to or for a Federal agency. This includes the time needed
to review instructions; develop, acquire, install, and utilize
technology and systems for the purposes of collecting, validating, and
verifying information, processing and maintaining information, and
disclosing and providing information; adjust the existing ways to
comply with any previously applicable instructions and requirements;
train personnel to be able to respond to a collection of information;
search data sources; complete and review the collection of information;
and transmit or otherwise disclose the information.
In addition to reducing the information collection burden of SPCC
facilities, this final rule also affects the number of facilities that
require an FRP. The FRP rule (40 CFR 112.20-21) requires that owners or
operators of facilities that could cause ``substantial harm'' to the
environment by discharging oil into navigable waters or adjoining
shorelines prepare plans for responding, to the maximum extent
practicable, to a worst case discharge of oil, to a substantial threat
of such a discharge, and, as appropriate, to discharges smaller than
worst case discharges. All facilities subject to this requirement must
submit their plans to EPA. In turn, we review and approve plans
submitted by facilities identified as ``significant and substantial
harm'' to the environment from oil discharges. Other facilities are not
required to prepare FRPs but are required to document their
determination that they do not meet the ``substantial harm'' criteria.
Prior to this rulemaking, EPA estimated that it requires between 99
and 132 hours for facility personnel in a large facility (i.e., total
storage capacity greater than 1 million gallons) and between 26 and 46
hours for personnel in a medium facility (i.e., total storage capacity
greater than 42,000 gallons and less than or equal to 1 million
gallons) to comply with the annual, subsequent-year reporting and
recordkeeping requirements of the FRP rule. We have also estimated that
prior to this rulemaking newly regulated large and medium facilities
will require between 253 and 293 hours and 109 and 142 hours,
respectively, to prepare a plan in the first year. In the absence of
this rulemaking, EPA estimates that the total number FRP facilities
affected in the first year would have been 6,000 existing and 70 new
facilities. Through this rulemaking the estimated number of facilities
required to maintain FRPs is reduced to 5,965 and the number of new
facilities that will be required to prepare and submit FRP plans is
reduced to 64 facilities. This reduction in the number of facilities
required to prepare, submit, and/or maintain an FRP would result in an
average annual information collection burden reduction of 8,513 hours a
year (624,252 to 615,739 hours).
An Agency may not conduct or sponsor, and a person is not required
to respond to a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations are listed in 40 CFR part 9 and 48 CFR Chapter 15. EPA is
amending the table in 40 CFR part 9 of currently approved ICR control
numbers issued by OMB for various regulations to list the information
requirements contained in this final rule.
J. National Technology Transfer and Advancement Act
As noted in the December 7, 1997, proposed rule, section 12(d) of
the National Technology Transfer and Advancement Act of 1995
(``NTTAA''). Pub. L. 104-113, section 12(d) (15 U.S.C. 272 note)
directs EPA to use voluntary consensus standards in its regulatory
activities unless to do so would be inconsistent with applicable law or
otherwise impractical. Voluntary consensus standards are technical
standards such as materials specifications, test methods, sampling
procedures, and business practices that are developed or adopted by
voluntary consensus standards bodies. The NTTAA directs EPA to provide
Congress, through OMB, explanations when the Agency decides not to use
available and applicable voluntary consensus standards.
This rulemaking involves technical standards. Throughout today's
preamble, EPA has emphasized that owners or operators of facilities
should use applicable industry standards in performing tests,
inspections, and in monitoring. Section 112.3(d) provides that a
Professional Engineer must certify that the SPCC Plan has been prepared
in accordance with good engineering practice, including consideration
of applicable industry standards. We are providing examples of specific
standards in today's preamble. However, due to the wide variety of
facilities the rule involves, few standards would be applicable to all
regulated facilities. Also, those standards change over time.
Therefore, we are not incorporating those standards into rule text.
K. Congressional Review Act
The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996, generally
provides that before a rule may take effect, the agency promulgating
the rule must submit a rule report, which includes a copy of the rule,
to each House of Congress and to the Comptroller General of the United
States. EPA has submitted a report containing this rule and other
required information to the U.S. Senate, the U.S. House of
Representatives, and the Comptroller General of the United States prior
to publication of the rule in the Federal Register. This action is not
a ``major rule'' as defined by 5 U.S.C. 804(2). This rule will be
effective August 16, 2002.
List of Subjects in 40 CFR Part 112
Environmental protection, Fire prevention, Flammable materials,
Materials handling and storage, Oil pollution, Oil spill prevention,
Oil spill response, Penalties, Petroleum, Reporting and recordkeeping
requirements, Tanks, Water pollution control, Water resources.
Dated: June 28, 2002.
Christine Todd Whitman,
Administrator.
For the reasons set out in the preamble, title 40 CFR, chapter I,
part
[[Page 47140]]
112 of the Code of Federal Regulations, is amended as follows:
PART 112--OIL POLLUTION PREVENTION
1. The authority for part 112 continues to read as follows:
Authority: 33 U.S.C. 1251 et seq.; 33 U.S.C 2720; E.O. 12777
(October 18, 1991), 3 CFR, 1991 Comp., p. 351.
2. Part 112 is amended by designating Secs. 112.1 through 112.7 as
subpart A, adding a subpart heading and revising newly designated
subpart A to read as follows:
Subpart A--Applicability, Definitions, and General Requirements For All
Facilities and All Types of Oils
Sec.
112.1 General applicability.
112.2 Definitions.
112.3 Requirement to prepare and implement a Spill Prevention,
Control, and Countermeasure Plan.
112.4 Amendment of Spill Prevention, Control, and Countermeasure
Plan by Regional Administrator.
112.5 Amendment of Spill Prevention, Control, and Countermeasure
Plan by owners or operators.
112.6 [Reserved].
112.7 General requirements for Spill Prevention, Control, and
Countermeasure Plans.
Subpart A--Applicability, Definitions, and General Requirements for
All Facilities and All Types of Oils
Sec. 112.1 General applicability.
(a)(1) This part establishes procedures, methods, equipment, and
other requirements to prevent the discharge of oil from non-
transportation-related onshore and offshore facilities into or upon the
navigable waters of the United States or adjoining shorelines, or into
or upon the waters of the contiguous zone, or in connection with
activities under the Outer Continental Shelf Lands Act or the Deepwater
Port Act of 1974, or that may affect natural resources belonging to,
appertaining to, or under the exclusive management authority of the
United States (including resources under the Magnuson Fishery
Conservation and Management Act).
(2) As used in this part, words in the singular also include the
plural and words in the masculine gender also include the feminine and
vice versa, as the case may require.
(b) Except as provided in paragraph (d) of this section, this part
applies to any owner or operator of a non-transportation-related
onshore or offshore facility engaged in drilling, producing, gathering,
storing, processing, refining, transferring, distributing, using, or
consuming oil and oil products, which due to its location, could
reasonably be expected to discharge oil in quantities that may be
harmful, as described in part 110 of this chapter, into or upon the
navigable waters of the United States or adjoining shorelines, or into
or upon the waters of the contiguous zone, or in connection with
activities under the Outer Continental Shelf Lands Act or the Deepwater
Port Act of 1974, or that may affect natural resources belonging to,
appertaining to, or under the exclusive management authority of the
United States (including resources under the Magnuson Fishery
Conservation and Management Act) that has oil in:
(1) Any aboveground container;
(2) Any completely buried tank as defined in Sec. 112.2;
(3) Any container that is used for standby storage, for seasonal
storage, or for temporary storage, or not otherwise ``permanently
closed'' as defined in Sec. 112.2;
(4) Any ``bunkered tank'' or ``partially buried tank'' as defined
in Sec. 112.2, or any container in a vault, each of which is considered
an aboveground storage container for purposes of this part.
(c) As provided in section 313 of the Clean Water Act (CWA),
departments, agencies, and instrumentalities of the Federal government
are subject to this part to the same extent as any person.
(d) Except as provided in paragraph (f) of this section, this part
does not apply to:
(1) The owner or operator of any facility, equipment, or operation
that is not subject to the jurisdiction of the Environmental Protection
Agency (EPA) under section 311(j)(1)(C) of the CWA, as follows:
(i) Any onshore or offshore facility, that due to its location,
could not reasonably be expected to have a discharge as described in
paragraph (b) of this section. This determination must be based solely
upon consideration of the geographical and location aspects of the
facility (such as proximity to navigable waters or adjoining
shorelines, land contour, drainage, etc.) and must exclude
consideration of manmade features such as dikes, equipment or other
structures, which may serve to restrain, hinder, contain, or otherwise
prevent a discharge as described in paragraph (b) of this section.
(ii) Any equipment, or operation of a vessel or transportation-
related onshore or offshore facility which is subject to the authority
and control of the U.S. Department of Transportation, as defined in the
Memorandum of Understanding between the Secretary of Transportation and
the Administrator of EPA, dated November 24, 1971 (Appendix A of this
part).
(iii) Any equipment, or operation of a vessel or onshore or
offshore facility which is subject to the authority and control of the
U.S. Department of Transportation or the U.S. Department of the
Interior, as defined in the Memorandum of Understanding between the
Secretary of Transportation, the Secretary of the Interior, and the
Administrator of EPA, dated November 8, 1993 (Appendix B of this part).
(2) Any facility which, although otherwise subject to the
jurisdiction of EPA, meets both of the following requirements:
(i) The completely buried storage capacity of the facility is
42,000 gallons or less of oil. For purposes of this exemption, the
completely buried storage capacity of a facility excludes the capacity
of a completely buried tank, as defined in Sec. 112.2, and connected
underground piping, underground ancillary equipment, and containment
systems, that is currently subject to all of the technical requirements
of part 280 of this chapter or all of the technical requirements of a
State program approved under part 281 of this chapter. The completely
buried storage capacity of a facility also excludes the capacity of a
container that is ``permanently closed,'' as defined in Sec. 112.2.
(ii) The aggregate aboveground storage capacity of the facility is
1,320 gallons or less of oil. For purposes of this exemption, only
containers of oil with a capacity of 55 gallons or greater are counted.
The aggregate aboveground storage capacity of a facility excludes the
capacity of a container that is ``permanently closed,'' as defined in
Sec. 112.2.
(3) Any offshore oil drilling, production, or workover facility
that is subject to the notices and regulations of the Minerals
Management Service, as specified in the Memorandum of Understanding
between the Secretary of Transportation, the Secretary of the Interior,
and the Administrator of EPA, dated November 8, 1993 (Appendix B of
this part).
(4) Any completely buried storage tank, as defined in Sec. 112.2,
and connected underground piping, underground ancillary equipment, and
containment systems, at any facility, that is subject to all of the
technical requirements of part 280 of this chapter or a State program
approved under part 281 of this chapter, except that such a tank must
be marked on the facility diagram as provided in Sec. 112.7(a)(3), if
[[Continued on page 47141]]
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