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SECTION 8
REGULATORY AND ENVIRONMENTAL ISSUES RELATED TO PRODUCED WATER
Much of the following information was taken from the
Environmental Handbook produced cooperatively by the Oklahoma
Midcontinent Oil and Gas Association and the Oklahoma Corporation
Commission. Also, the General Rules and Regulations of the Arkansas Oil
and Gas Commission were reviewed to include information pertaining to
Arkansas.
Oklahoma and Arkansas have assumed primary
responsibility for enforcing Environmental Protection Agency (EPA)
regulations pertaining to the construction, operation and closure of
Class II injection wells within their respective states.
Injection
and Disposal Wells. General
requirements. Approval and permits
must be obtained from the Oklahoma Corporation Commission (OCC) or the
Arkansas Oil and Gas Commission (AOGC) for any new injection or disposal
well.
A Mechanical Integrity Test (MIT) must be performed at
least once every five years and initially before a well is used. In
Oklahoma the initial test must be witnessed by an authorized
representative of the Oil and Gas Division and results submitted on Form
1075 within 30 days by the operator. In Arkansas, within fifteen (15)
days after the completion of the well, a completion report, well logs,
and injectivity test performed on the well must be filed with the Oil
and Gas Commission. The AOGC must be notified in writing before the
beginning of injection to allow inspection of the well and conduct the
initial mechanical integrity testing.
Minimum standards for injection and disposal wells
are:
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Oklahoma.
Injection must be through adequate tubing and packer.
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Arkansas.
All injection wells must have tubing and packer “or other
installation” to protect the casing.
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A
1/4 inch female fitting in Oklahoma (1/2 inch in Arkansas) with
cut-off valve to the tubing is required to be installed so injection
pressure may be checked.
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Oklahoma.
The packer must be set within 20 feet of the packer setting depth as
described in the permit to inject.
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Arkansas.
The packer can be set no higher than 100 feet above the injection
interval.
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Minimum
cement height circulated above the injection zone in the annulus
between the casing and the borehole must be 250 feet.
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Oklahoma.
The packer must be set at least 50 feet below the depth of the top
of cement behind the production casing.
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Oklahoma.
Surface casing must be set at least 50 feet below the base of
treatable water or 90 feet below the surface (whichever is greater)
if a stage collar is set or the production casing is cemented to the
surface (unless otherwise authorized),
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Arkansas.
New disposal wells require surface casing to be set 250 feet below
the lowermost Underground
Sources of Drinking Water (USDW).
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Oklahoma.
Surface casing must be set at least 200 feet below the base of
treatable water for annular injection of drilling fluids.
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Arkansas. A
sign must be maintained at the well site to indicate operator, well
name, well number and location description.
Oklahoma. Any
newly drilled or converted injection or disposal well within ˝
mile of any active or reserve municipal water supply well will not be
approved without notice and hearing and the operator must prove that the
water well will not be impacted. Applications for newly drilled or
converted injection or disposal wells need to be filed with the
Underground Injection Control Department on Form 1015. Applications must
be accompanied by a plat showing the location and total depth of all
wells within 1/4 mile of the injection or disposal well, and all surface
owners and operators of producing leases. A copy
of the application must be delivered to the surface owner of the land on
which the well will be located and to each operator of a producing lease
within ˝ mile of the well. A notice also has to be published in an
Oklahoma City newspaper and a newspaper in the county where the well
will be located. If a written objection is filed within 15 days, a
hearing will be set at the OCC.
Arkansas.
Applications
are filed with the Oil and Gas Commission on a form titled
“Application to Inject Salt Water/ Enhanced Recovery Fluid”.
Arkansas requires a plat indicating the
location of the proposed injection well with distances to the nearest
lease lines, including all wells of public record and fresh water wells
of public record within ˝ mile radius from the proposed injection well.
Arkansas also requires a separate list
of all wells which have penetrated the injection zone that indicates: 1)
exact legal location, 2) current operator, 3) lease name, 4) name of
zone currently completed, 5) perforated intervals, 6) total depth, 7)
drilling date, 8) cementing records, 9) record of completion/plugging,
and 10) current status. Information
on this list MUST agree with AOGC records. You are required to attach a
notarized copy of the proof of publication of the application as it ran
in one publication in a legal newspaper having a general circulation in
the county or in each county, if there shall be more than one, in which
the lands embraced within the application are situated, and by mailing
or delivering a copy of the application to each operator of producing or
drilling wells within one-half (1/2) mile radius of the injection well.
Such notice shall be published, mailed
or delivered at least ten days, but no more than 30 days, prior to the
date on which the application is mailed or filed with the Commission.
Monitoring and reporting. Oklahoma.
Operators
must monitor and record the injection rate and surface injection
pressure monthly. For each calendar year, the operator is required to
report the results of monthly monitoring on Form 1012A by April 1 of the
next year. Operators must submit Form 1072 (Notice of Commencement or
Termination) within 30 days after injecting or disposing into a well.
When a mechanical failure or downhole problem occurs, the operator must
notify the OCC Field Inspector within 24 hours after discovery. A
written repair plan must be submitted within 5 days.
Arkansas.
Operators
must monitor and submit a saltwater disposal report monthly on AOGC Form
14. The report must be filed no later than the 15th of the
month following the month covered by the report. Required monthly
injection data includes barrels of water injected, barrels of cumulative
water injected, injection pressure on the tubing and annulus and
injection zone.
Oil and Produced Water Spills.
General requirements for Oklahoma.
The first critical activity is to safely contain and control
the spill to protect human safety and minimize damage to the
environment. Notify proper authorities, including the appropriate OCC
district office before cleanup (see below under reporting requirements).
Attempt to recover and remove oil if possible. Cleanup contaminated
soil, vegetation, and/or water as per acting authority requirements.
Saltwater or oil soaked soil may require sampling before remediation can
take place.
Reporting requirements for Oklahoma.
Report spills to the following Oklahoma Corporation Commission
District Offices:
Report verbally to the Commission District Office or
Field Inspector within 24 hours of discovery of a reportable quantity
spill. Failure to report may result in a $500 fine. File a written or
oral report with the District Office within 10 working days. For spills that impact surface waters of the state
(rivers, streams, lakes) also report the spill to:
Spills
that pose an imminent danger to fish or wildlife should be reported to
the Oklahoma Department of Wildlife Conservation.
Record keeping for Oklahoma.
Maintain adequate records of each non-permitted discharge reflecting the
information, time and manner of reporting. Produce such documents upon
demand by an authorized representative of the Commission. Records of all
reportable spills should be kept on file in the nearest company office.
Document all cleanups and notifications.
Reporting
requirements for Arkansas.
Operators should immediately report to the Arkansas Oil and
Gas Commission any breaks or leaks in or from tanks or other receptacles
and pipelines from which oil or gas is escaping or has escaped. The
report must contain the location of the well, tank, receptacle, or line
break by Section, Township, Range, and property, so that the exact
location can be readily located on the ground. The report shall also
specify what steps have been taken or are in progress to remedy the
situation reported and shall detail the quantity (estimated, if no
accurate measurement can be obtained, in which case the report shall
show the same is an estimate) of the oil or gas lost, destroyed, or
permitted to escape. In case any tank or receptacle is permitted to run
over, the escape thus occurring shall be reported as in the case of a
leak. The report as to oil losses is necessary only in case such oil
loss exceeds twenty-five (25) barrels in the aggregate.
Spill Prevention,
Control and Countermeasure (SPCC) Regulation.
(At the time of
publication of this handbook, due to industry pressure, EPA has
indicated its intent to extend the February 17, 2003 compliance date and
the August 2003 compliance date for SPCC Plan revisions. EPA indicated
it would simultaneously issue a direct final rule and a proposed rule to
extend the compliance deadlines for one year with a mechanism to extend
beyond that time. Following action on the deadline extension, EPA
indicated it will initiate efforts to assess the problems with the new
regulations and determine methods to resolve them through additional
rule making, guidance, or interpretation. Keep in touch with your trade
associations for future updates regarding these new regulations.)
On
July 17, 2002, the EPA amended the Oil Pollution Prevention regulations
promulgated under the authority of the Clean Water Act. This includes
new requirements for SPCC Plans and for Facility Response Plans (FRPs).
The rule became effective August 16, 2002. The revised rule is difficult
to read and understand. The following paragraphs attempt to summarize
requirements for onshore oil operators.
It has been determined
that many oil drilling and production facilities are subject to the SPCC
regulation. EPA’s SPCC regulation (40 CFR 112.1 through 112.7) applies
to nontransportation-related facilities that could reasonably be
expected to discharge oil into or upon the navigable waters of the
United States or adjoining shorelines, and that have 1) any single
container or group of containers each greater than 55 gallons having a
total capacity of greater than 1320 gallons, or 2) a total underground
buried storage capacity of more than 42,000 gallons.
The SPCC regulation
requires the facility owner/operator to prepare an SPCC Plan for their
facility. All existing SPCC Plans prepared before August 16, 2002 must
be revised on or before February 17, 2003 to comply with the new rules
and implemented by August 18, 2003. If a facility becomes operational
after August 18, 2002, but before August 19, 2003, an SPCC Plan must be
prepared and implemented by August 18, 2003. If a facility becomes
operational on or after August 19, 2003, a plan must be prepared and
implemented before the facility goes on stream. There is a provision to
apply for an extension for the plan preparation time.
Additionally, a
Professional Engineer must certify the SPCC Plan and attest:
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The
Professional Engineer is familiar with the SPCC rule.
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The
Professional Engineer or agent has visited and examined the
facility.
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The
SPCC Plan has been prepared in accordance with good engineering
practices and the SPCC rules.
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Rules
specifying procedures for inspecting and testing are included.
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The
SPCC Plan is adequate for the facility.
The revised plan must be retained at the facility, if
the facility is attended at least four hours per day on a regular basis.
General
requirements.
The SPCC Plan must include:
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a
physical layout of the facility, including location of each tank,
separator, heater treater, transfer piping and pumps;
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type
of oil in and the capacity of each tank and vessel;
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discharge
prevention measures appropriate for routine loading, unloading and
transferring oil within the facility;
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discharge
and drainage controls such as secondary containment, catchment
basins, retention basins and control procedures;
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estimated
direction, rate and total quantity of release flow;
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a
method planned for discovery, response, and cleanup by company and
contractor; disposal methods for recovered
oil;
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a
list of contractors with phone numbers for company response
coordinator, National Response Center, cleanup contractors with whom
the company has a response agreement; and
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a
list of Federal, State and local agencies.
The owner/operator of onshore production facilities must
have at least one of the following means of secondary containment for
tanks, treating vessels, piping, and pumps:
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dikes, berms,
retaining walls
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curbing
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culverts,
gutters or drainage systems
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weirs,
booms or other barriers
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diversion
ponds
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retention
ponds
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sorbent
materials
For tank truck or tank car loading/unloading area racks
(frames), use catchment basins or treatment systems designed to handle
discharge from the largest single truck compartment or use a quick
drainage system. Provide secondary containment for tank batteries,
separators, heater treaters, transfer pumps and interconnecting piping.
The secondary containment must hold the capacity of the single largest
tank and anticipated precipitation. Newly installed or repaired buried
pipes must be coated and wrapped. Provide secondary containment for
flowlines, e.g., double-walled pipe, berms, catchment basins, and booms.
If the installation of secondary containment as discussed above is not
practical and the facility does not have a Response Plan, the
owner/operator must include in the SPCC Plan:
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an
explanation why the controls are not practical
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periodic,
scheduled integrity testing of facility containers, valves, piping
(including flowlines)
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a
Contingency Plan
Additionally, the SPCC Plan must include:
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a
written commitment of manpower, equipment and materials to control
and remove released liquid hydrocarbon.
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a written
inspection and testing procedures for tanks, separators, heater
treaters and piping. The procedures and record of inspections and
tests must be signed by the appropriate foreman and retained with
the SPCC Plan for three years.
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a
written commitment to train all oil-handling company personnel
regarding
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maintenance
and operation of equipment to prevent oil releases,
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release
reporting and control,
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pollution
control statutes, rules and regulations,
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general
facility operations,
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SPCC
contents.
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a provision
to schedule and conduct annual release prevention briefings for
oil-handling personnel. Include and describe known releases,
equipment failures or malfunctions and recently developed
precautionary measures to prevent releases.
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a
designated employee who is responsible for oil release and who
reports to the facility management.
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a
requirement to seal all tank and vessel valves when not in use and
the facility is operating.
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a lockout in
the off position for all shipping and transfer pump electric start
controls when not in use.
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a
way to cap, plug or flange all open-ended liquid hydrocarbon pipes
and/or valves when not in use or when in extended standby service.
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provision
for facility lighting, if practical.
Specific
requirements.
An onshore producing facility reasonably expected to release
liquid hydrocarbons that could enter waters of the United States, must
prepare an SPCC Plan in accordance with the General Requirements for the
SPCC Plan plus the following provisions:
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Dikes
and drains must be closed and locked when not in use. Oil-free
rainwater may be drained to the ground, but the owner/operator must
inspect the rainwater for oil before discharging the rainwater. If
oil is present, the oil must be removed and returned to the oil
treating system or disposed of.
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Written
inspection and testing procedures for tanks, separators, heater
treaters and piping must be maintained. The procedures and record of
inspections and tests, signed by the appropriate foreman, must be
retained with the SPCC Plan for three years.
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Provide
secondary containment for all tanks, separators, heater treaters and
transfer or shipping pumps. The containment must be capable of
retaining the capacity of the largest single tank and anticipated
precipitation. The owner/operator may use catchment basins in lieu
of berms.
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The
owner/operator must maintain written regularly scheduled drainage
system (borrow ditches, stream, ravines) inspection instructions.
Oil must be removed, if discovered.
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Design
new and update old tank batteries in accordance with good
engineering practice to prevent releases. At a minimum:
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tank
size must be adequate to assure no overfill if lease operator is
delayed
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equalizer
lines between tanks must be present
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vacuum
protection to prevent tank collapse must be present
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high
level sensor alarms must be present for computerized facilities.
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The
owner/operator must maintain written regularly scheduled inspection
procedures for above-ground tanks, piping, valving, pumps, drip
pans, polish rod, stuffing boxes.
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Written
inspection records of produced water disposal facilities must be
maintained, particularly after a sudden change in atmospheric
temperature.
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Written
flowline maintenance program must be prepared.
As mentioned previously, the above is an attempt to
summarize the new rules for onshore oil operators. There are also new
rules for onshore drilling and well servicing, as well as offshore
drilling, producing and well servicing. No matter who ends up preparing
an SPCC Plan, remember that ultimately it is the owner/operator who is
responsible for complying with the regulation. A copy of the regulation
is available by calling or writing your nearest EPA office. For Oklahoma
and Arkansas:
SPCC/FRP Coordinator
U.S. EPA-Region VI (6SF-RP)
1445 Ross Avenue
Dallas, TX 75202-2733
(214) 665-6489
Cleanup
Guidelines.
Follow the most recent "Oklahoma Corporation Commission
Guidelines For Responding To and Remediating Spills". Current
guidelines are as follows:
Crude oil spill to soil.
Use temporary dikes and emergency pits to confine the spill to
the smallest possible area. All accumulated oil should be collected and
recycled. Absorbent materials may be used to collect free oil.
Contaminated soil may be removed and replaced with compatible soil and
the contaminated soil land applied in accordance with OCC-OAC Rule
165:10-7-26.
If on-site bioremediation of the contaminated soil is
the preferred option, then the soil brought to the surface should be
disked to a depth of six inches and fertilized by applying 160 pounds of
nitrogen, 40 pounds of phosphorus and 40 pounds of potassium per acre,
unless soil testing reveals that an alternative ratio of these nutrients
would be superior for the purposes sought. If weather and soil
conditions do not permit immediate disking, it may be necessary to burn
the material following Department of Environmental Quality (DEQ)
approval. Disking and fertilizing should be done as soon as weather
conditions permit.
All affected areas must be restored as near as
practicable to the level of land productivity that existed before the
spill occurred and may require additional disking, fertilizing and/or
revegetation. Any alternative reclamation plan must be submitted to the
OCC District Office for approval before implementation. If remediation
cells or piles are to be utilized, remediation should be coordinated
with the OCC Field Operations Department.
Waste management practices that can be utilized during
the cleanup of crude oil spills include reclamation and/or recycling;
road applications by County Commissioners; application to lease roads,
well locations, and production sites; and disposal of waste oil by
transfer or sale to a reclaimer/transporter/County Commissioner. Some of
these practices require permits. (See OCC-OAC Rule 165:10-7-24).
Salt water spill to soil.
Because of the variable conditions that can be associated with
saltwater spills to soil, it is difficult to provide absolute guidance
as to the proper actions to take as a response to all spills. However,
general actions that should be taken in all cases are as follows: 1)
initiate actions to prevent further discharge or release; 2) utilize an
appropriate containment system to minimize the surface area impacted by
the spill. Such a system could consist of temporary diking, emergency
pits, or leak proof tanks; and 3) remove free fluids from the spill
surface as soon as practicable. The use of a vacuum removal system is
one way such removal can be facilitated. In some cases, particularly
where there is standing water or wet soils, flushing the spill areas
with fresh water may be an appropriate method to facilitate the removal
of saltwater from the soil surface. In any case, saltwater fluids
recovered should be properly disposed. Permitted Class II disposal or
injection wells are the only types of disposal that are appropriate.
After considering and weighing the relative conditions
and importance of each of the remediation factors, it may be determined
that it is appropriate to obtain soil samples to determine whether soil
removal or other remedial measures may be needed. If soil samples are to
be taken, a background soil sample from outside the spill area should be
collected for the purpose of comparison. If the affected area is large,
two or three soil samples should be collected towards the edge of the
spill, followed by two or three soil samples near the center of the
spill. Reduced sampling may be done for smaller areas.
Generally, quick response actions should limit the
infiltration of such spilled fluids. In such cases, surficial samples
(within one foot of the surface) may suffice for sampling purposes. If
more than one week has passed since the time of the initial release,
substantial rainfall has been received, or if plowed or sandy soils are
present, soil samples should be collected to a depth of three to five
feet or to bedrock if it is shallower. Such samples should be collected
at one-foot depth intervals.
All soil samples should be placed in suitable containers
for transportation, chain-of-custody records completed and the samples
sent to a qualified laboratory. Once received, the samples should be
analyzed for Total Dissolved Solids (TDS) or Total Soluble Salts (TSS).
Sample analysis exceeding 2500 ppm for TDS (or TSS) indicates a need for
remediation in place or removal of the soils in the area that such
samples were obtained from.
If the option of remediation by leaching is selected,
one can expect remediation to take from one year to several years,
depending upon site conditions. Clay soils, in particular, do not leach
well, so removal is normally recommended. For leaching, the affected
area should be treated with 20 to 30 tons per acre of organic matter
(either vegetable or animal) and an appropriate amount of calcium
sulfate (gypsum) or calcium nitrate. To determine the appropriate
amount, refer to the recommendations of the soils laboratory or a
consultant. If more than five tons are recommended, the recommended rate
should be split into separate applications three to six months apart. It
is not unusual to have to repeat treatments in order to get good
results.
If the removal option is selected, the area adversely
impacted by the spill should be excavated to a depth sufficient to
remove all soils that indicate a TDS (or TSS) level of 2500 ppm or
greater. Excavated material may then be disposed of in a manner
consistent with Corporation Commission Rule OAC 165:10-7-26 or
165:10-9-1. Following excavation, the area must be restored to its
original use by backfilling with compatible replacement soil and
establishing suitable vegetation as soon as possible.
Saltwater spill to surface water.
If possible, confine the spill to the smallest area possible
by using temporary dikes and emergency pits. Collect as much of the
affected water as possible and transport to an authorized disposal
facility. Cleanup procedures can be discontinued when the affected water
is restored to the previous beneficial use for the stream or body of
water. All saltwater spills to navigable waters of the state should be
reported to EPA Region VI, OCC, and the DEQ.
Crude oil spill to surface water.
Use temporary dikes, emergency pits, artificial barriers or
floating booms to confine the spill to the smallest possible area.
Containment barriers should be located for easy access and removal of
oil. Floating oil should be immediately removed from the surface of the
water by pumping or skimming. Removal must continue until there is no
visible sheen on the surface of the water. Removal may require
absorption of the oil with absorbent materials including straw or
commercial absorbents.
Stream or impoundment banks and affected vegetation may
be cleaned by washing or burning (following DEQ approval) to remove
excess oil and staining if erosion can be prevented. After all of the
oil has been removed from the surface of the water, containment
structures should be left in place for capture of any residual product.
These structures may be removed after there is no evidence of additional
product accumulation. Sufficient time must be allowed for all oil to
flush from the original spill area and there should be no residual sheen
on the water.
Following removal of the containment structures, an
effort should be made to restore the area to pre-spill conditions. All
contaminated materials should be disposed of in a manner approved by OCC
Field Operations. If the surface water is designated as a source of
public water supply under Oklahoma Water Quality Standards, cleanup
procedures must continue until all assigned beneficial uses for the
stream or body of water are restored. All oil spills to navigable waters
of the state should be reported to the National Response Center, OCC,
and the DEQ. |