PROTECTION
906R87107
CHAPTER 7
SUMMARY OF STATE AND FEDERAL REGULATIONS
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Alabama
Introduction
Alabama produced 8,486,000 barrels of oil, and 11,392.000 barrels of
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condensate, 137 x 10 cubic feet of gas in 1984. Production was from
760 oil wells, 509 conventional gas wells, and 184 coalbed methane wells.
Thirteen percent of conventional oil and gas wells are strippers; 52
percent of coalbed methane wells are strippers.
Alabama began limited regulation of oil and gas activities in 1946.
Regulations for disposal of drilling wastes were adopted in 1973.
Regulations and/or administrative codes have continued to be revised
during the forty years of regulation.
Regulatory Agencies
Four agencies regulate oil and gas activity in Alabama:
- Alabama State Oil and Gas Board
- Alabama Department of Environmental Management
- U.S. Bureau of Land Management
- U.S. Corps of Engineers
The Alabama State Oil and Gas Board is "charged with preventing the
waste of Alabama's oil and gas resources and protecting the correlative
rights of owners." In carrying out its mandate, the Board regulates all
oil and gas operations for the issuance of drilling permits through the
production phase. The Oil and Gas Board has authority to issue permits
for UIC Class II wells. The various permitting requirements and
conditions of the Oil and Gas Board are detailed in the Board's
Administrative Code.
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The Alabama Department of Environmental Management (ADEM) has the
authority to issue permits for all UIC wells other than Class II. The
Department of Environmental Management also has NPDES authority. The Oil
and Gas Board and Department of Environmental Management operate under a
1979 Memorandum of Agreement which requires the Board to forward
information regarding actual or proposed discharges to the Department of
Environmental Management.
The U. S. Bureau of Land Management authority and regulations for
Federally-held mineral rights are discussed separately under Federal
Agencies. The U.S. Forest Service retains surface rights (and usually
coordinates stipulations with the Bureau of Land Management) in Federal
forests and grasslands.
State Rules and Regulations
Drilling
Drilling pits are permitted by the Oil and Gas Board. The Board
has certain construction requirements to ensure the integrity of the
pit. Pits are closed by dewatering (see below), then backfilling,
leveling, and compacting.
No pits are permitted in Alabama's coastal wetlands. The Department
of Environmental Management prohibits the use of pits in wetlands in
order to insure the protection of surface or groundwater resources. Many
of the wetlands area in Alabama fall within the jurisdiction of the
Alabama Coastal Area Management Program, which is an enforcement
responsibility of ADEM. The Certificate of Consistency which must be
issued by ADEM before a permit can be issued by the Board requires use of
portable above-ground tanksfor any well drilled in the coastal area.
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Drilling muds and pit fluids may be disposed in one of three ways.
They may be injected into a formation below underground sources of
drinking water. They may be transported to a drilling mud treatment
(recycling) facility. In non-wetland areas, the fluids may be applied to
the land surface or into an approved landfill if:
- The chloride concentration is less than 500 mg/L
- The Oil and Gas Board is properly notified
- The landowner provides written approval
- It is a one-time-only application
- There will be no discharge to surface body of water
These activities are permitted by the Oil and Gas Board prior to
allowing disposal of fluids.
Production Waters
Class II injection wells are used for the disposal of brines
produced in association with oil and/or natural gas, for the disposal of
non-hazardous waste waters that may be generated during the operation of
a gas plant, for the enhanced recovery of oil or natural gas, or for the
storage of hydrocarbons which are liquid at standard temperature and
pressure. Currently, all of Alabama's 250 Class II injection wells are
used for disposal purposes, or for the enhancement of oil or natural gas
production.
Rule 400-1-5-.04 requires that "Immediately following the initiation
of production in any field or pool, all salt water shall be disposed of
into an approved underground formation or otherwise disposed of as
approved by the Supervisor where such salt water cannot damage or pollute
underground sources of drinking water, oil, gas or other minerals." The
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permitting of Class II injection wells- in Alabama is a two-step process.
Step 1 is approval to drill or convert a well for injection purposes and
includes: a review of all well constructions within a one-quarter mile
radius of the proposed injection well; and the submission of data
concerning the construction of the proposed injection well, analyses and
estimated volumes of fluids to be injected, anticipated injection
pressures, known or calculated fracture pressure of the proposed
injection interval, and the lowermost depth of fresh water. All
injections shall be through tubing anchored by a packer unless otherwise
approved by the Oil and Gas Supervisor. In addition, the operator must
provide proof that the injection casing is adequately cemented in order
to prevent vertical fluid migration and must test the injection casing at
a pressure equal to 2/10th the depth of the mid-point of the injection
interval, but not to exceed 1,500 psi.
Following completion of the Board's Step 1 requirements, the
applicant may receive approval to begin injection. Once injection begins
the operator must submit monthly reports on injection volumes, injection
pressures, and tubing-casing annulus pressures. The injection pressure
and casing-tubing annulus pressure must be recorded on a daily basis, or
computed on a daily average basis from weekly measurements. Also,
chemical analyses of injected fluids are to be submitted on an annual
basis and a pressure test must be performed at least once every five
years.
Produced waters from coalbed methane wells are an exception to the
injection requirement. EPA has advised Alabama that coalbed methane
production is not covered under the Federal onshore oil and gas
regulations. Produced waters from coalbed methane wells may be allowed to
accumulate in pits, settle, and then may be discharged directly into live
streams. The Department of Environmental Management requires operators to
obtain permits for such discharges, and requires such discharges to meet
a 600 mg/1 in-stream limit.
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Plugging/Abandonment
Plugging is required after six months, but wells may be approved for
temporary abandonment if future utility can be shown. Thereafter, well
status must be reported every six months.
When plugging, cement plugs of not less than 100 feet should be
placed above any producing formation, from 50 feet below to 50 feet above
the base of fresh water strata, and from 50 feet below to 50 feet above
the base of the surface casing. A 25 foot plug should be near the
surface, and a steel plate over the casing stub. Intervals between the
plugs must be filled with mud-laden fluid.
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References
State Oil and Gas Board of Alabama, Submittal to EPA Regarding Onshore
Oil and Gas Subcategory, March 1985.
State Oil and Gas Board of Alabama Administrative Code, general order
prescribing rules and regulations governing the conservation of oil
and gas in Alabama nd oil and gas laws of Alabama with Oil and Gas
Board forms, Oil and Gas Report 1, 1983.
Alabama Meeting Report. 1985. Proceedings of the Onshore Oil and Gas
Workshop. U.S. EPA, Washington, D.C. (March 26-27 in Atlanta, GA).
Personal Communication:
Treena Pizner, Alabama Department of Environmental Management
(205) 271-7850.
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Alaska
Introduction
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Alaska produced 681,309,821 barrels of oil and 316 x 10 cubic
feet of gas in 1986. During 1986, 608,225.599 barrels of water and 1,066
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x 10 cubic feet of ga:
enhanced oil recovery.
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x 10 cubic feet of gas were injected into producing formations for
Alaska ranked second in U.S. oil production, but twenty-third in the
number of production wells (1,191 wells) in 1986. It ranked eighth in
U.S. gas production and twenty-fourth in the number of producing gas
wells (104 wells)
In 1986 Alaska produced from two oil and gas development regions,
the South Central region (including Cook Inlet and the Kenai Peninsula)
and the North Slope region. The state contains other prospective
regions; but to date no discoveries in these regions have been made.
Approximately 663,738,428 barrels of oil and 123 x 109 cubic feet of
gas were produced from the North Slope in 1986 from two fields (Kuparuk
and Prudhoe). The Duck Island unit (Endicott Field) will commence
production in early 1988. Production at Milue Point unit is currently
suspended for economic reasons.
The Kenai Peninsula produced mostly gas with little associated
produced water. In 1986, fields in the South Central region produced
17,571,393 barrels of oil and 193 x 109 cubic feet of gas.
Regulatory Agencies
Eight agencies regulate oil and gas activities in Alaska:
- Alaska Oil and Gas Conservation Commission
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- Alaska Department of Environmental Conservation
- U.S. Bureau of Land Management
- Alaska Department of Natural Resources
- Alaska Department of Fish and Game
- U.S. Army Corps of Engineers
- U. S. EPA - Region X
- U.S. Fish and Wildlife Service
Alaska Oil and Gas Conservation Commission regulates the production
and conservation of oil and gas in Alaska, and is responsible for issuing
permits for drilling. The Commission checks well casings to prevent
contamination of water, and has primacy for the Class II injection wells.
Under Title 31 of the Alaska Statutes, the Commission has the status of
an independent quasi-judicial agency. Its three commissioners, appointed
by the Governor, must include an expert in petroleum engineering and an
expert in petroleum geology.
The Alaska Department of Environmental Conservation is the primary
pollution control agency within the State government. The department
regulates and permits solid waste disposal, wastewater discharges, and
air contaminant emissions. It issues state discharge permits for oil and
gas drilling and production operations. The Department also regulates
hazardous wastes, oil spill control, and the subsurface disposal of non-
hazardous oil and gas wastes (which are not regulated as Class II
wastes). Since Alaska does not have responsibility for the NPDES
program, DEC coordinates with EPA-Region X, which administers the NPDES
program in Alaska.
The U.S.Bureau of Land Management is responsible for all oil and gas
activity on Federal and Indian lands (under 43 CFR 3160). There are 370
million acres of land in Alaska, of which more than half are under
Federal ownership. There are 150 producing oil and gas wells on Federal
leases. Regulatory processes for oil and gas operations are covered in
Onshore Oil and Gas Order No.l. More information on BLM regulations can
be found in the section on Federal programs.
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The Alaska Department of Natural Resources issues surface and
subsurface oil and gas leases on State land. Leasing stipulations
address environmental concerns, such as requiring that reserve pits be
rendered impermeable, at lease award. The Department also approves plans
of operations for all oil and gas activity on State lands. The approval
letter contains site-specific stipulations developed through inter-agency
review. The Department also conducts field inspections of operations and
abandonments.
Under the Section 404 program of the Clean Water Act, the U.S. Army
Corps of Engineers is responsible for issuing permits for dredge and fill
activities on wetlands defined as part of the waters of the United
States, and U.S. EPA has review responsibility for such permits. Several
other State and Federal agencies also have comment and/or concurrence
responsibilities on the Federal permits. Since much of Alaska's drilling
and production activity, including that on the North Slope, takes place
on wetlands, all pads, roads and facilities have 404 permits. The Corps
of Engineers requires all reserve pits to be rendered impermeable.
The U.S. Fish and Wildlife Service, in addition to having comment
responsibility on 404 permits, has been conducting research related to
the permitted discharge of drilling fluids to the tundra wetlands. The
research project currently in progress is designed to determine the
deleterious effect of the discharge on wildlife in the wetlands,
especially to waterfowl.
State Rules and Regulations
Current regulations for handling of drilling and production wastes
in Alaska may be subject to modification. A final draft of proposed
amendments to regulations for Solid Waste Management (18 AAC 60) was
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published by the Department of Environmental Conservation on October 31,
1986. These amendments would impose more stringent requirements on the
management of reserve pits and drilling wastes. As of April, 1987,
however, these amendments had not yet been adopted. However, the final
revisions were expected to be completed and distributed in April. DEC
projects adoption of the proposals by July, 1987.
Reserve Pits
The management and disposal of "drilling wastes" primarily involves
the proper operation and closure of the reserve pit utilized during
drilling operations. The reserve pit often provides the permanent
disposal site for solids or solidified wastes from the drilling
operation. Although in exploratory drilling, reserve pits may often be
used and closed in a single season, on the North Slope many are in
continual use, due to the directional drilling of multiple wells from a
single pad. There are however, a variety of ways in which drilling
wastes are ultimately disposed, such as subsurface injection. (In
proposed regulations (18 AAC 60), "drilling wastes" are defined as
including "drilling muds, cuttings, hydrocarbons, brine, acid, sand, and
emulsions of mixtures of fluids produced from and unique to the operation
or maintenance of a well").
State statutes require permits for solid waste disposal facilities.
However, prior to 1982, few solid waste permits were issued for reserve
pits. As early as 1982, it became policy to require permits for all
currently active and new pits in the Cook Inlet area. The same policy
was applied on the North Slope beginning in 1985.
Under 20 AAC 25.047, administered by the AOGCC, reserve pits are
required "for the reception and confinement of drilling fluids and
cuttings, to facilitate the safety of the drilling operation, and to
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prevent contamination of groundwater and damage to the surface
environment." The general construction requirement is that the pits must
be rendered "impervious." There is no specific requirement for lining.
The proposed DEC regulations would impose specific construction and
performance requirements for reserve pits. The particular requirements
would depend on factors such as the proximity of surface water or
groundwater which is used for drinking water, the proximity of an
existing or developing population, and whether the pit were being built
in an area of continuous permafrost. For example, a reserve pit being
constructed in a non-permafrost region within 100 feet of a surface water
body used for drinking water would require double liner, leachate
collection (if no fluid management plan), site inspection and monitoring.
A reserve pit in a permafrost region not adjacent to water supplies or
population would require a containment structure (possibly lined)
designed to prevent the escape of wastes from the reserve pit, site
inspection, a fluid management plan, and monitoring.
Under 20 AAC 25.047, administered by the AOGCC, upon termination of
operations related to a particular reserve pit, "the operator shall
proceed with diligence to dispose of and solidify in place all pumpable
fluids, and shall leave the reserve pit in a condition that does not
constitute a hazard to ground water." Under 18 AAC 60 and 18 AAC 72,
administered by the DEC, solid waste permits are required for closure
and wastewater permits for all discharges.
Disposal from Reserve Pits
Reserve pit fluids on the North Slope may be disposed of through
injection in dedicated wells. In the Kenai area there have been several
permits for centralized disposal of oil field wastes. One of these
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permitted disposal facilities was operated by an independent
concessionaire on Kenai Borough owned land, but DEC cancelled the permit
because of contaminants found in monitoring wells.
DEC has issued general permits for discharges to the tundra, for
annular injection of reserve pit fluids, and for dedicated injection
wells that are not Class II wells, and issues occasional specific permits
for road application. Injection into dedicated Class II wells is
permitted by the Oil and Gas Conservation Commission. Annular injection
is allowed under the permit-to-drill issued by AOGCC.
Surface Discharge to Tundra:
DEC issued a seasonal general permit on May 12, 1986 (expired
September 30, 1986) for discharges onto the tundra from reserve pits
containing "produced waters, drilling fluids and cuttings, boiler
blowdown, rig washing fluids, workover fluids, completion fluids, excess
fluids from blowouts and drill pad runoff." Only those pits were eligible
which had received no discharges or placements of any materials into
thepit since August 1, 1985 (that is, pits which had gone through a one
year freeze-thaw cycle to precipitate contaminants). Further, pits must
have no visible sheen on the surface. Operators must notify DEC two
weeks prior to any discharge, and include information on volumes and
analyses for salinity, settleable solids, arsenic and chromium. Written
approval must be received from DEC prior to the discharge.The permit
applies only to discharges of the clarified supernatant from the pits.
The maximum drawdown is 18 inches from pit bottom at point of withdrawal,
to prevent solids carry-over. Other management practices, such as
injection, must be used for further drawdown. Effluents must be monitored
during discharge. The effluent limitations for 1986 were:
COD 200 mg/1
pH 6.0 - 8.5(or
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within 0.5 of
receiving water)
Salinity Sparts/thousands
Settleable solids 1 mg/1
Oil and grease 15mg/l
Aromatic hydrocarbons 10ug/l
Arsenic .05mg/l
Barium 1 mg/1
Cadmium .01 mg/1
Chromium .05 mg/1
Lead .05 mg/1
Mercury .002 mg/1
These limitations will be reevaluated prior to issuance of the 1987
general permit. Limitations are also being evaluated for copper, zinc,
aluminum, and boron. The process of reevaluation after 1985 led to the
elimination of an effluent limitation for manganese in the 1986 general
permit. DEC figures in the information sheet with the 1986 general permit
indicate approximately 36 million gallons of liquid were discharged from
43 reserve pits in 1985, 35 of which exceeded limitations. But 16 of these
pits exceeded only the limitation for manganese, which is found at
naturally high levels in waters on the slope.
Surface Discharge to Roads:
Permits for road applications of reserve pit fluids, used for dust
control during the summer, are issued to individual applicants. Two
permits issued to facilities of one company for 1986 were valid from May
15th to December 31st, but specified that discharges must be between June
1st and August 31st unless DEC determined sufficient thaw existed to
prevent puddling or runoff.
Unlike discharges to the tundra, road application permits do not
require that the reserve pit fluids go through a one) year freeze-thaw
cycle before disposal. Application is specifically designated for
particular roads and pads. Spraying is prohibited when the surfaces are
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already wet. Spraying is to be made no closer than three feet from the
edge of the shoulder of any pad or road to prevent spraying onto adjacent
areas. Compliance with effluent limitations is to be determined at the
edge of the road or pad. The required limitations are the same as those
for discharge to the tundra, except for the range for pH (6 to 9).
Sampling and monitoring reports are required.
Annular Disposal:
Reserve pit wastes are frequently injected down the annulus either
of the well being drilled, or of another well on the pad. A general
permit for the North Slope for annular disposal was issued by DEC for the
period of August 6, 1985 to April 30, 1987. The permit applies to the
discharge of "fluids produced from the drilling, servicing or testing of
oil and gas exploration, development, service and stratigraphic test
wells, including but not limited to drilling fluids, rig washwater,
completion fluids, formation fluids, reserve pit meltwaters and domestic
wastewaters...."
Discharge must occur below the permafrost zone; the minimum depth
must be 1,000 feet. No discharge must be into any zone containing TDS of
less than 3,000 ppm. Operators must notify DEC at least two weeks before
beginning injection, and must include information on volumes and types of
material being injected, the zone and depth of the injection, and the
method to be used to seal the injection zone at the completion of
disposal. Written approval must be received from DEC. A report must be
submitted after closure of the well, stating volumes and types of liquids
injected, well location, well designations, date and time of injections,
and depth of injection zones.
This option may require that the operator perform annual maintenance
on the well to preserve the permafrost.
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Injection Wells
The Oil and Gas Conservation Commission has responsibility for Class
II UIC wells. The Commission permits the disposal of both oil field waste
fluids and produced waters into wells dedicated for disposal of oil field
wastes (20 AAC 25.252), and approves injection into wells for enhanced
recovery (20 AAC, Article 5). While the numbers continually change,
current figures provided in February and March, 1987 were 17 disposal
wells (14 North Slope; 3 Kenai) and 387 enhanced recovery wells.
Since more water is injected for enhanced recovery in Alaska than is
produced with oil and gas production, produced waters are injected into
disposal wells only when they are removed from any enhanced recovery
operation. Additional water for enhanced recovery is drawn from both Cook
Inlet and the Arctic Ocean.
Injection for enhanced recovery may be carried out under area
injection orders (20 AAC 25.460). The Commission may issue orders
permitting injection on an area basis, rather than for each individual
well, if the wells are essentially similar, within the same field or site
or similar area, are operated by a single operator, and are used to
inject other than hazardous waste.
Reserve pit fluids may be injected into dedicated disposal wells, or
in some instances returned down the annulus to formation.
Injection wells must be cased with safe and appropriate casing,
tubed to prevent leakage, and cemented to protect oil, gas, and fresh
water strata. At application, information must be provided on all wells
within a quarter mile of the injection well which penetrate the injection
zone. Adequate evidence must be provided that a proposed injection well
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will not cause or increase fractures in overlying strata which could
allow injected or formation liquids to enter fresh water strata. (Fresh
water aquifers may be exempted from the restrictions affecting them if
they do not currently and cannot in the future serve as sources of
drinking water, are between 3,000 and 10,000 mg/1 IDS but cannot be
reasonably expected to supply a public water system, or if too
contaminated for economic or technologically practical recovery).
Injection wells must be equipped with tubing and packer or other
equipment which isolates pressure to the injection interval. Wells must
undergo pressure tests for mechanical integrity before operation. The
test must be for 30 minutes at 1500 psi or 0.25 psi/ft times the vertical
depth of the casing shoe, whichever is greater (but must not exceed 70%
of the minimum yield strength of the casing), with a maximum pressure
decline of 10%. Thereafter, mechanical integrity must be demonstrated by
thfi operator by monitoring the pressure in the casing-tubing annulus
during actual injection. The monitored pressure must be reported monthly.
At present, two applications are pending with the EPA for permits
for dedicated, Class I, disposal wells on the North Slope, one for the
Prudhoe Bay Unit and one for the Endicott Unit. These wells will be for
restricted oil and gas development wastes.Plugging/Abandonment
All wells that have been permitted on a property must be abandoned
within one year following cessation of the operator's oil and gas
activity within the field where the wells are located. Any well which,
after drilling, is not completed, must be abandoned or suspended before
removal of the drilling equipment.
The Commission may approve suspension of a well if it has future
productive or service use, and if there is justifiable reason for the
suspension (e.g., unavailability of production or marketing facilities).
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The operator of a suspended well must set a bridge plug 200-300 feet
below the casing head and cap with 100 linear feet of cement. Additional
plugging requirements for a suspended well would be determined on a site-
specific basis by the Commission.
Abandoned wells must be plugged to prevent movement of fluid into or
between freshwater and hydrocarbon sources. Uncased portions of a well
must be cased to keep fluids in original strata; cement plugs must be
placed from 50 feet below to 100 feet above hydrocarbon strata, and from
150 feet below to 50 feet above the base of the lowest freshwater stratum.
Uncased and cased portions of the well bore must be segregated;
various cementing method/plug placement combinations may be used (e.g.,
plug from 100 feet below to 100 feet above casing shoe, by displacement
method).
Cased portions of the well bore must be plugged with cement to
confine hydrocarbons and freshwater to original strata. Perforated
intervals must be plugged by one of several methods (e.g., cement plugs
extending from 100 feet below to 50 feet above the base and from 50 feet
below to 100 feet above the top of each interval, or by placing a
mechanical bridge with 75-foot cement cap 50 feet over the interval), as
must casingstubs within the outer casing (plug from 100 feet above to 100
feet below the stub, bridge plug 25 feet over stub with 75-foot cap, or
downsqueeze 150 feet of cement through retainer with additional 50 foot
plug).
Surface plugs must seal annular openings in communication with the
open hole, and a 150-foot cement plug must extend to within 5 feet of
grade elevation.
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Cements used for plugging within permafrost zones must be designed
to set before freezing and have low heat of hydration. Muds equaling or
exceeding density of mud used to drill each interval should fill
intervals between plugs.
Final abandonment of the wells and drillsites must also be approved
by the Alaska Department of Natural Resources if the site is on State
land.
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References
Alaska Meeting Report. 1985. Proceedings of the Onshore Oil and Gas
State/Federal Western Workshop. U.S. Environmental Protection
Agency, Washington, D.C. (December 1985).
Summary of State Statutes and Regulations for Oil and Gas Production.
1986. Interstate Oil and Gas Commission (June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil Compact
Commission (December).
Regulations, Alaska Administrative Code, Title 20, Alaska Oil and GAs
Conservation Commission, April 2, 1986.
Regulations, Alaska Administrative Code, Title 18, Alaska Department of
Environmental Conservation: Chapter 60 (Solid Waste Managemtent),
October 9, 1983; draft revisions, October 31, 1986: Chapter 72
(Wastewater Disposal), January, 1983.
Alaska Statutes, Title 31, Chapter 05, Alaska Oil and Gas Conservation
Act.
Title 46, Water, Air, Energy, and Environmental conservation:
Chapters 3 (Environmental Conservation; 4, (oil Pollution Control);
and 8-9 (Oil and Hazardous Substance Release).
Fristoe, Bradley R. 1985. Letter Communication to EPA. State of Alaska
Department of Environmental Conservation.
Alaska Department of Environmental Conservation: General Wastewater
Disposal Permits for surface discharges from reserve pits
(#8640-DB001; May 12, 1986) and annular injection (#8540-DB001;
August 6, 1985); and individual permits for road application
(#8636-06003 & DB004).
Personal Communications:
Dan Wilkerson, Alaska Department of Environmental Conservation (907)
274-2533.
Doug Redburn, Chief of Water Quality Managemtent Section, Juneau
(907) 465-2666.
William Barnwell, Alaska Oil and Gas Conservation Commission (907)
279-1433
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Douglas Lowery, Alaska Department of Environmental Conservation
(907) 452-1714
Michael Frank, Alaska Sttorney General's Office, Natureal Resources
Division (907) 276-3550
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ARIZONA
Introduction
Arizona produced 214,000 barrels of oil and 225 MMCF of gas in 1984.
Production was from 26 oil wells and 5 gas wells. Approximately 655
bbls/day of brines are produced in the State per day.
Regulatory Agencies
There are five agencies that regulate the oil and gas industry in
Arizona:
- Arizona Oil and Gas Conservation Commission
- U.S. Bureau of Land Management
- U.S. Bureau of Indian Affairs
- Arizona Department of Health and Safety
- EPA, Region IX
The Bureau of Land Management has the authority to issue oil and gas
drilling permits for Federal minerals. Where Indian mineral rights
prevail, oil and gas activity may be governed by both the BLM and the
Bureau of Indian Affairs.
The Arizona Oil and Gas Conservation Commission reviews all oil and
gas drilling applications and is primarily responsible for approving and
enforcing oil and gas activities. The Oil and Gas Commission's
regulations pertain to the construction, location, and operation of
onsite drilling and production activities.
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Arizona does not have NPDES or UIC program primacy. The Department
of Health and Safety Coordinates with EPA's Region IX for any surface
water discharge or underground injection permit. Region IX administers
the UIC program; there are no discharges from oil and gas facilities.
State Rules and Regulations
Drilling
Reserve pits receive drilling fluids and muds, drill cuttings, and
any waters produced during drilling. The pits are allowed to evaporate
before closure, and then are filled.
Production
All brines produced during the production phase are reinjected,
either for enhanced recovery or disposal. Permit approval is required
*•*
both from EPA-Region IX and the Commission for drilling an injection
well. The casing and cementing requirements in the Arizona state
regulations are general, requiring "safe or adequate casing or tubing in
order to prevent leakage," cemented and set to prevent damage to gas, oil
or fresh water strata. Surface casing is required to be pressure tested
at 600 psi for 30 minutes, with a maximum allowable drop of 10% in
pressure.
Plugging/Abandonment
There are no provisions in the regulations specifying a time limit
for plugging after the cessation of production. Decisions are made on a
case-by-case basis. In the case of a dry hole, plugging must take place
within 60 days after the cessation of drilling, unless permission for
temporary abandonment is granted by the Commission.
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When a well is plugged, a 50-foot cement plug must be placed
immediately above each producing formation, and a continuous cement plug
must be placed through, and to 50 feet above, and below all freshwater
strata. A 20-foot cement plug must be placed at or near the surface of
the well. Intervals between plugs must be filled with heavy mud. An
uncased hole must be plugged with heavy mud up to the base of the surface
string, at which point a 50-foot plug must be placed in and out of the
bottom of the surface pipe.
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References
Ray Brady, Deputy State Director, Division of Mineral Resources. Letter
to EPA. September 4, 1985.
"Arizona Administrative Code" Chapter 7, Oil and Gas Conservation
Commission, Article 1. Oil, Gas and Helium. 1982.
Personal Communications:
Lyndon Mammon, NPDES Permits Section Manager, Arizona Department of
Health and Safety. September 29, 1986 (602) 257-2262.
Nate Lau, Director of the UIC Division, EPA Region IX. September 28,
1986 (415) 974-0893.
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Arkansas
Introduction
Arkansas produces 19,715,691 barrels of oil and 194,483 MM cubic
feet of gas in 1985. Production is from 9,490 oil wells and 2,492 gas
wells. The State is divided into two geographical districts. The Arcoma
Basin, located in the northwest corner of the State, produces 99 percent
natural gas on a volume basis. The Mississippi Embayment in southeastern
Arkansas produces approximately 90 percent oil and 10 percent gas.
State Regulatory Agencies
Two agencies regulate oil and gas activity in Arkansas:
- Arkansas Oil and Gas Commission
- Arkansas Department of Pollution Control and Ecology
The Arkansas Oil and Gas Commission, regulates industry practices
regarding drilling and production activities of oil and gas wells under
the authority of Act 105 of 1939 (the "Oil and Gas Act"), Act 937 of
1979, and Act 523 of 1981. Act 105 created the Oil and Gas Commission,
and authorized it to prevent waste of oil and gas resources and to
prevent pollution of fresh water supplies by oil, gas or saltwater. Act
937 authorized the Commission to prevent waste in brine production. Act
523 amended the "Oil and Gas Act" to authorize the Oil and Gas Commission
to "acquire primary enforcement responsibility either singularly or
jointly with the Department of Pollution Control and Ecology for the
control of underground injection under the applicable provisions of the
Safe Drinking Water Act." Drilling and production practices are
regulated under the "General Rules and Regulations" of the Commission
(Order No. 2-39). The General Rules and Regulations do not address all
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aspects of industry practices, and refer the reader to "special rules
pertaining to individual oil, gas, or salt water fields and pools."
Special rules of any non-emergency nature require a public hearing, and
are provided for in Rules A-2 and B-38 of the General Rules and
Regulations.
The Arkansas Department of Pollution Control and Ecology (ADPCE)
regulates pollution generally, or pollution specifically related to oil
and gas drilling and production wastes, under authority of Act 472 of
1949 (the "Arkansas Water and Air Pollution Control Act"), Act 120 of
1961, Act 254 of 1969, and Act 743 of 1975. Act 472 provided authority
to ADPCE to establish pollution standards and industrial discharge limits
for state waters. Act 120 includes "wells" within the definition of
waters of the state, and made it a violation to cause pollution in waters
of the state. Act 254 provided a tax penalty for operators allowing
saltwater to escape a lease, and required ADPCE to identify the source of
pollution and take steps to eliminate it if the chloride level in any
stream exceeded 250 ppm. Act 743 of 1975 provided ADPCE jurisdiction to
permit disposal of pollutants into wells.
The principal regulations of ADPCE related to oil and gas drilling
and production wastes are found in Regulation No. 1: "Regulation for the
Prevention of Pollution by Salt Water and Other Oil Field Wastes Produced
by Wells in New Fields or Pools." The regulation was promulgated on
October 13, 1958, pursuant to the authority provided by Act 472.
ADPCE is currently considering revisions to Regulation No.l which
would be modeled on Louisiana State Order No.29-B. But at the beginning
of 1987, timing and outcome of the effort were not yet certain.
Arkansas has primacy for both the NPDES program and the UIC program.
The NPDES program is administered by ADPCE. There is a Memorandum of
2
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Agreement (March 25, 1982) governing the division of authority between
ADPCE and the Oil and Gas Commission with respect to underground
injection wells, but there continues to be some disagreement between the
two agencies as to what the agreement actually allows or requires.
Under the agreement, ADPCE has primary responsibility for Class I,
III, IV, and V injection wells, except for bromine related brine disposal
wells. AOGC is given "administrative management responsibility for the
issuance of construction and operating permits for Class II and Class V
bromine related disposal wells. AOGC shall be responsible for enforcement
in respect to all Class II wells." AOGC is further described as
responsible for well integrity and the migration of wastes from the
injection strata into actual or potential drinking water aquifers.
But the Memorandum also notes the statutory overlap of jurisdiction
which it was intended to resolve. The degree to which this issue is
still unresolved is reflected in the introduction, during the current
session of the legislature, of a bill drafted by counsel for the
Commission which would have established exclusive authority with respect
to Class II wells for the Commission and repealed all portions of
statutes giving ADPCE any claim to such jurisdiction. The bill failed to
get out of committee.
The result of this conflict is that operators do not always comply,
or believe they need to comply, with all of the requirements of ADPCE.
According to information provided by both the Department and the
Commission, operators in the gas fields in the northern part of the state
tend to follow the Department's requirements, while those in the older
oil fields in the south frequently fail to apply for ADPCE permits or
follow their requirements.
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State Rules and Regulations
Drilling
The Oil and Gas Commission does not have any specific regulations
governing the construction or management of reserve pits or the disposal
of drilling wastes, nor does Regulation No.l of ADPCE impose any
requirements on reserve pits. Typical practices include onsite disposal
in unlined reserve pits or landspreading in the vicinity of the pit.
ADPCE, however, has been sending out letters of authorization
intended to serve as informal permits which stipulate management
practices for reserve pits and disposal of drilling wastes. Many of the
provision required by the letter are those the Department would like to
include in a proposed revision of Regulation No.l. The lack of specific
regulations containing the provisions in the letter has resulted in
uneven compliance with the letter's requirements by operators. The
letter lists conditions which the Department of Pollution Control and
Ecology expects to be followed during drilling operations pertaining to
reserve pit construction, pit fluid and drilling mud disposal, and drill
site reclamation.
Under the letter's requirements, all earthen pits must be lined with
a synthetic liner (20 mils thick) or a clay liner (18 to 24 inches
thick), and must maintain at least 2 feet of freeboard. Pits must be
reclaimed to grade and seeded within 60 days after the drilling rig has
been removed from the site.
Reserve pit fluids may be only by State permitted disposal services.
The letter of authorization also states that completion fluids high
in total dissolved solids, such as KCL, should be kept separate from the
4
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contents of the reserve pit, and recommends that a lined pit be used for
this purpose..
Production
Rules C-7 and C-8 of the General Rules and Regulations define the
means by which salt water produced from oil and gas wells may be
discharged into subsurface formations for disposal or enhanced recovery.
The Oil and Gas Commission states that it will consult the State
Geological Survey and the State Board of Health, when reviewing an
application to inject salt water, in order to protect fresh water
supplies.
Wells for disposal and enhanced recovery are to be cased and
cemented "in such manner that damage will not be caused to oil, gas or
freshwater resources." Injection pressure must be limited to ensure that
fractures are not propagated in the confining zones. Injection must be
through tubing set on a packer. Information must be provided by the
applicant on all wells or dry holes within a half mile of the new or
converted injection well.
Section 4 of Regulation No. 1 forbids discharging salt water from
any oil or gas well in a manner whereby the salt water may come in
contact with "any of the waters of the State, whether by natural
drainage, seepage, overflow, or otherwise." Other sections of Regulation
No. 1 require the well operator to obtain a permit for a waste disposal
system that prevents the wastes from contacting State waters. The
regulation provides two alternatives for salt water disposal: subsurface
discharge in disposal wells constructed in accordance with the Rules and
Regulations of the Arkansas Oil and Gas Commission, and surface discharge
5
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into lined earthen pits. Currently, only subsurface disposal is
permitted.
The letter of authorization issued by the Arkansas Department of
Pollution Control and Ecology states that salt water produced any time
during the lifetime of a well will remain the responsibility of the
production company, and "shall be stored in a plastic or fiberglass tank
above ground and resting on a concrete pad."
Offsite Disposal
Disposal of reserve pit fluids and drilling mud requires a permit
from the Arkansas Department of Pollution Control and Ecology. The
permit requires that the disposal company provide an analysis of the pit
fluids and drilling mud, the amount hauled, and its final destination. A
disposal company that is permitted to land apply pit fluid and drilling
mud near the well must provide the Department with a copy of the land
owner's agreement as well as an analysis of the wastes. An analysis of
pit fluid will include tests for chlorides and pH, and a drilling mud
analysis will include tests for chromium, zinc, chlorides, and pH.
Plugging/Abandonment
Wells which are not completed as commercially productive after
drilling must be abandoned and plugged before the drilling equipment is
released from the drilling operation. No time limitation is established
in the regulations, however, for temporary abandonment of a properly
cased well.
When plugging, a 100-foot cement plug must be placed above each
producing stratum, or a bridge plug may be used. A cement plug of 100
feet must be placed 50 feet below the base of the freshwater stratum if
6
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surface casing is not cemented below that stratum; if it is, a 100-foot
cement plug should be placed inside the base of the surface casing. A
plug should be set at the surface of the ground in such way as to not
interfere with cultivation. Intervals between plugs should be filled with
heavy mud-laden fluid.
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References
Personal Communication with Mr. David A. Thomas, Arkansas Department of
Pollution Control and Ecology, August, 1986.
Telephone (501) 562-7444.
Arkansas Department of Pollution Control and Ecology, "Regulation No. 1,"
October 1958.
Arkansas Oil and Gas Commission, "State of Arkansas Rules and Regulations
Order No. 2-39," revised 1983.
Interstate Oil Compact Commission, The Oil and Gas Compact Bulletin,
Volume XLIV, No. 2, December 1985.
Intestate Oil Compact Commission, Summary of State Statutes and
Regulations for Oil and Gas Production, June 1986.
U.S. Environmental Protection Agency, Proceedings: Onshore Oil and Gas
State/Federal Western Workshop, December 1985.
Letter of Authorization from Mr. David A. Thomas, Arkansas Department of
Pollution Control and Ecology, to Mr. William S. Walker, Stevens
Production Company, August 20, 1986.
Letter to Mr. Naresh R. Shah, West Virginia Department of Natural
Resources Permits Brance, from Mr. Terry Muse, Arkansas Department
of Pollution Control and Ecology, regarding Arkansas Water Permit
No. 2839-W, March 2, 1984.
Personal Communications:
Steve Drown, Arkansas Department of Pollution Control and
Ecology (501) 562-7444.
Phil Deisch, Arkansas Department of Pollution Control and
Ecology, (501) 562-7444.
Lynn Fite, Arkansas Oil and Gas Commission, (501) 862-4965.
William Wynne; Crumyler, O'Connor, and Wynne; serving as counsel to
Arkansas Oil and Gas Commission, (501) 863-8118.
John Welch, Arkansas Game and Fish Commission (501), 223-6319
8
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CALIFORNIA
Introduction
California produced 423,900,000 barrels of oil and 493 billion
Q
x 10 cubic feet of gas in 1985. California ranked fourth in U.S. oil
production and sixth in U.S. gas production. Production was from 55,079
producing oil wells and 1,566 producing gas wells. Approximately 55% of
the oil production is attributed to enhanced recovery.
Regulatory Agencies
Several agencies regulate oil and gas activity in California:
- California Department of Conservation, Division of Oil and Gas
California Water Resources Control Board, and the nine Regional
Water Quality Control Boards
- California Department of Health Services
- California Air Resources Board, and the county or regional Air
Pollution Control Districts
- State Lands Commission
California Coastal Commission
Local government agencies
U.S. Bureau of Land Management
- U.S. Department of Energy
The Division of Oil and Gas of the California Department of
Conservation, created in 1915, issues permits for the drilling, reworking
and abandonment of oil and gas wells. Under authority delegated by EPA,
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the Division also issues UIC permits for Class II injection wells. As
part of its responsibilities, the Division is responsible for ensuring
that the drilling and operation of such wells does not endanger fresh
groundwater strata.
The California Water Resources Control Board is generally responsible
for protecting the waters of the State, and for preserving all present
and anticipated beneficial uses of these waters. EPA has delegated
authority to issue NPDES permits to the Water Resources Control Board.
This responsibility is implemented through nine Regional Water Quality
Control Boards, which issue Waste Discharge Requirements (California's
NPDES permits) for point sources of water pollution. The Water Resources
Control Board has the authority to adopt statewide water quality policy
and water quality control plans for Regional Boards to follow.
The Regional Boards must at minimum implement requirements as strict
as those of the State Board. But they have autonomy to develop more
stringent requirements within their regions. All discharges of drilling
wastes or produced waters to surface impoundments or surface waters are
subject to the permitting authority of the Regional Boards. Under a
Memorandum of Under/standing between the Regional Water Quality Control
Boards and the Division of Oil and Gas, the Regional Boards also have the
responsibility for reviewing permits written by the Division of Oil and
Gas to ensure the incorporation of the concerns of the Regional Boards.
The California Department of Health Services is responsible for the
regulation of hazardous wastes. The Department has responsibility for
determining which waste streams and constituents are hazardous under
California's laws, including determinations as to the hazardousness of
drilling fluids and muds. The Department is also responsible for the
regulation of injection wells into which hazardous wastes are being
-------
injected. Further, the Department of Health Services shares with the
Regional Water Quality Control Boards responsibility for the regulation
of hazardous waste landfills and surface impoundments.
For wells on State-owned, onshore lands, the State Lands Commission
has joint responsibilities with the Division of Oil and Gas. Their
responsibilities are expressed in the provisions of the lease terms.
The California Department of Fish and Game, while not a permitting
agency for drilling projects, provides comments and recommendations on
methods to mitigate any problems that oil and gas operations may create
for fish and wildlife. The Department of Fish and Game coordinates State
operations involving any spills that affect fish and wildlife.
Local Air Pollution Control Districts issue permits to operate
equipment that emits pollutants into the atmosphere. The equipment
includes steam generators used for enhanced oil recovery projects.
The California Coastal Commission issues permits for any development
proposed within the coastal zone. This zone extends from the State's 3-
mile seaward limit to 1,000 yards inland. Oil and gas projects within
this area would need permits, although there are provisions for
exemptions.
Cities and counties also issue land use permits for oil and gas
operations. Generally, a condition of their permits requires that an
operator comply with the regulations of the Division of Oil and Gas.
The Bureau of Land Management approves approximately 400 oil and gas
drilling permits per year on Federal lands, and additionally provides
permits for wells for reinjection of produced waters. Since operators of
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these wells must meet the requirements of the state as well as BLM, they
are subject to dual permitting. In 1985, there were 6,200 oil, gas and
injection wells on Federal lands. The oil and gas wells produced about
22.4 million barrels of water per month, with most going to reinjection
and some to evaporation percolation ponds.
The Department of Energy manages the Elk Hills Naval Petroleum
Reserves. In 1985, these fields produced approximately 86,000 barrels of
water, 128,000 barrels of oil, and 184 billion cubic feet of gas per
day. Produced waters have been reinjected or disposed in earthen sumps,
but the Department of Energy has been managing a transition to disposal
only in injection wells.
State Rules and Regulations
Drilling: Under Article 9 of Title 22 of the California
Administrative Code, drilling fluids and drilling muds are listed as
wastes which come under the provisions of the regulations for hazardous
wastes if they contain a hazardous material. Most muds actually in use
in California, however, do not fall under this provision. The Department
of Health Services has prepared a list (available to operators on
request) of additives and fluids which are non-hazardous if used
according to the manufacturer's recommendations. The Department will
also review test data submitted by companies on new muds or fluids when
requested to do so, in order to determine if they are non-hazardous.
Discharges of drilling muds and cuttings which do not contain
halogenated solvents into on-site sumps are specifically excluded from
the requirements affecting "Discharges of Waste to Land" (Subchapter 15,
Chapter 3, Title 23) under the jurisdiction of the Regional Water Quality
Control Boards, provided that the operator takes appropriate measures at
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the conclusion of drilling operations. The operator must either "(1)
remove all wastes from the sump, or (2) remove all free liquid from the
sump and cover solid and semisolid wastes, provided that representative
sampling of the sump contents after liquid removal shows residual solid
wastes to be nonhazardous."
Drilling pits may or may not need to be lined or sealed depending on
their location. While the Regional Water Quality Control Boards do not
prescribe pit construction conditions, the conditional use permit that a
driller obtains from each county may detail the pit requirements. If the
fluids contain hazardous materials, the pits would have to have liners.
On Federal lands, drilling fluids are left in the sump until
completion of the well. After completion of the well, drilling fluids
are hauled to a Class II disposal site for oil field wastes.
Before drilling a well, operators must file an indemnity bond with
the Division of Oil and Gas, to ensure that the applicant complies with
the permit requirements, and properly abandons or completes the well.
After proper abandonment or completion, the Division releases the bond.
Produced Waters
Produced waters may be reinjected for enhanced recovery or disposal,
discharged on the surface for beneficial use, placed in lined sumps for
evaporation or unlined sumps for evaporation and percolation, or disposed
of in sewer systems. In some cases, produced waters ultimately disposed
of in sumps are first discharged into watercourses which carry the
saltwater to the sumps. The impact and legality of this practice is
currently under review. The approximate percentages of produced water
disposed of by each method are:
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Evaporation in percolation sumps - 18%
Evaporation in lined sumps - 6%
Disposal in sewer systems - 2%
Surface disposal (beneficial) - 18%
Injection for enhanced recovery - 41%
Injection for disposal - 15%
'0
Surface Discharge for Beneficial Use: In cases where the quality of
the water is sufficient for beneficial use for irrigation, livestock
and/or wildlife, produced waters may be permitted for discharge into
surface waters (principally into irrigation canals, dry ditches and
ephemeral streams). There are at least 12 such permits in the Fresno
office of the Central Valley Regional Water Quality Control Board.
Discharge permit limits include the following maximum values:
Oil and grease - 35 mg/1
Chlorides - 200 mg/1
Boron - 1 mg/1
Electrical conductivity - 1,000 u mhos
Sewer Disposal: The small percentage that goes to sewer systems is
predominantly within the Los Angeles County Sanitation District.
Production waters entering such sewers must meet applicable pretreatment
standards, including a maximum oil and grease content of 75 mg/1, and
limits on heavy metals, cyanide, chlorinated hydrocarbons, and sulfides.
There is no pretreatment limit for chloride.
Pits: Regulation of all saltwater sumps is under the jurisdiction of
the Regional Water Quality Control Boards, which have the authority to
regulate discharges to surface impoundments "by issuing waste discharge
requirements, including discharge prohibitions, which implement water
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quality control plans." (Title 23, Chapter 3, Subchapter 15 of the
California Administrative Code). But while minimum regulatory standards
are established for various classes of impoundments under Subchapter 15,
a specific exemption is provided for evaporation ponds and percolation
ponds if "the applicable regional board has issued waste discharge
requirements, reclamation requirements, or waived such issuance." To be
eligible for the exemption, the discharge must also be nonhazardous,
comply with the State Board's nondegradation policy, and comply with "the
water quality objectives set forth in the applicable water quality
control plan...." For example, unlined sumps containing produced waters
which could adversely affect freshwater aquifers would not be permitted
in locations which could impact such aquifers.
Regional Water Quality Control Boards while they must at least
implement the requirements established by the State Board, have the
authority to establish requirements more stringent than those established
by the State Board. Thus the Regional Boards may establish specific pit
construction requirements (e.g., liners to prevent percolation from the
sumps) in sensitive areas.
Any sump, other than an operations sump, containing a mixture of oil
and water, must be covered with screening to restrain entry of wildlife.
If the Department of Fish and Game deems the condition of a sump to be
hazardous for wildlife, the Department notifies the Division of Oil and
Gas, which requires the operator to abate the condition within 10 days
(if an immediate or grave danger) or 30 days.
In addition to discharge to on-site saltwater sumps, substantial
volumes of saltwater are discharged to offsite sumps. These are
discussed below.
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Injection: Over half of produced waters in California are
reinjected, either for enhanced recovery or disposal. Authority for
management of Class II injection wells is delegated by EPA to the
Division of Oil and Gas. The Regional Water Quality Control Boards,
under a Memorandum of Understanding with the Division of Oil and Gas, may
comment on Class II injection well permits on matters which could affect
water quality, including degradation of ground/water.
On Bureau of Land Management leases, operators of Class II wells must
obtain permits from both the Division of Oil and Gas and BLM. Many of
the injection wells are for enhanced recovery, and therefore could
significantly affect BLM's royalty earnings from its leases. As a
result, BLM wants to maintain joint signatory authority on UIC permits.
BLM and the Division of Oil and Gas are in the process of trying to
develop a Memorandum of Understanding on joint permitting.
Injection wells, other than those injecting steam, air, or pipeline
quality gas, must be equipped with tubing and packer set immediately
above the approved zone of injection. Exceptions may be granted where
there is no evidence of freshwater-bearing strata, where more than one
string of casing is cemented below the base of freshwater, or where the
operator can demonstrate that freshwater and oil zones can be protected
without tubing and packer. The pressure in the well must not be
sufficient to fracture the zone of injection.
To obtain approval from the Division of Oil and Gas, operators must
file plans, geologic analyses, evaluations of the impact of the planned
well on other wells in the area, monitoring program, the source and
analysis of the water being injected, and analysis of water in the
injection zone. A new chemical analysis of the water being injected must
be filed whenever the source of the water is changed or as requested by
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the Division. Mechanical integrity tests are carried out annually,
except for thermal enhanced recovery wells and wells with special
conditions. In these cases, MIT's are performed on varying schedules -
usually every three years.
Some disposal of saltwater in California also takes place in
combination with other oil field related nonhazardous wastes in Class V
wells; regulation of Class V wells has not been delegated to the state.
Any wells into which wastes defined as hazardous under California
regulations are being injected, regardless of the Federal classification,
would become subject to the requirements established in the Toxic
Injection Well Control Act of 1985, which are generally more stringent
than Federal requirements. These requirements are under the jurisdiction
of the Department of Health Services.
Offsite Facilities
Central Sumps for Produced Waters: On the western side of the San
Joaquin Valley, a series of large percolation/evaporation sumps receive
produced water discharged to them through natural watercourse drainage.
The Department of Energy has ordered the closure of two of these sumps,
which are on the property of the Elk Hills Naval Petroleum Reserve; the
two sumps no longer receive produced waters, and are in the process of
closure. The remaining sumps are still operating. Some of the wells
discharging to the sumps, and some of the watercourses through which the
discharges go, are on Federal lands managed by the Bureau of Land
Management. Currently, most of the sumps either operate under
requirements dating from more than two decades ago, or have no
requirements at all.
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While this disposal method is currently allowed, the Central Valley
Regional Water Quality Control Board is con/sidering whether these
produced waters should be regulated under the requirements for California
"designated" wastes (if they contain pollutants which exceed water
quality objectives or could cause degradation of the waters of the
state). There is also a question as to whether this method of disposal
is in accordance with 435.32 of 40 CFR, since the discharge to the sumps
is through natural watercourses, and the discharged waters generally do
not meet the requirements for agriculture and wildlife use.
Waste Disposal Facilities for Drilling Wastes: Drilling wastes may
be transported offsite for disposal. If hazardous by California's
definition, the wastes must be disposed of (as required by Section 2521,
Subchapter 15, Chapter 3, Title 23) in Class I waste management units
(requiring double liners and no migration). If classified as
"designated" wastes, they may be disposed of in Class II facilities
(single liners, no migration, and design and construction "for the
containment of the specific wastes which will be discharged") or Class I
facilities. If non-designated, alternative uses would be permissible.
Transport: An invoice for an undesignated waste is required for
trucks hauling brine. If being trucked to a central injection facility,
the Division of Oil and Gas requires that the trucker carry a ticket
designating the volume and source of the fluid. The operator of the
central facility collects a copy of the ticket and files it.
Plugging/Abandonment
Under Section 3237 of the Public Resources Code, suspension of
activity and removal of drilling activity is evidence of desertion of a
well after six months. Removal of production equipment is evidence of
10
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t
desertion after two years. The Supervisor of the Division of Oil and Gas
may order the plugging of a well which has been deserted. But the
Division of Oil and Gas generally exercises its discretion for previously
producing wells (particularly those which were permitted prior to the
existence of a bonding requirement), actively communicating with
operators about plugging with respect to wells which have been out of
production for five years.
When a well is plugged, it is generally required that cement plugs be
placed across specified intervals to protect oil, gas, and usable water
zones. The district deputy may allow cement to be mixed with or replaced
by other substances with adequate physical properties. Intervals which
are not plugged are to be filled with mud fluid of "sufficient weight and
consistency" to prevent movement of other fluids into the well bore.
At the surface, the hole and all annuli must be plugged with at least
a 25-foot cement plug. In an open hole, a cement plug must be placed
from at least 100 feet below the bottom to at least 100 feet above the
top of each oil or gas zone, and at least a 200-foot plug must be placed
across all fresh-saltwater interfaces. Where the hole is open below the
shoe, a cement plug is required from 50 feet below to 50 feet above the
shoe.
In a cased hole, all perforations must be plugged with cement, and a
plug must extend at least 100 feet above the top of a landed liner, the
uppermost perforations, the casing cementing point, the water shutoff
holes, or the oil or gas zone, whichever is highest. If cement is behind
casing across fresh-saltwater interface, a 100-foot cement plug must be
placed at the interface inside the casing. If the top of the cement
behind the casing is below the top of the highest saltwater sands,
squeeze-cementing is required through perforations to protect the
freshwater, in addition to a 100-foot plug inside the casing.
11
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References
California Meeting Report. 1985. Proceedings of the Onshore Oil and Gas
State/Federal Western Workshop. U.S. Environmental Protection
Agency, Washington, D.C. (December 1985).
Summary of State Statutes and Regulations for Oil and Gas Production.
1986. Interstate Oil and Gas Commission (June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil Compact
Commission (December).
California Administrative Code: Titles 14, 22 & 23. Title 14, Chapter
4 - Development, Regulation and Conservation of Oil & Gas Resources
Title 23, Chapter 3, Subchapter 15 - Discharges of Waste to Lead
Title 22, Chapter 30 - Minimum Standards for Management of Hazardous
and Extremely Hazardous Wastes.
Mefferd, Marty. 1985. Letter Communication to EPA.
Supervisor, Division of Oil and Gas.
Personal Communications:
Bob Reid, Division of Oil and Gas (916) 445-9686.
Scott Smith, Central Valley Water Quality Control Board
(209) 445-5116.
Chong Rhee, L.A. County Sanitation District (213) 699-7411.
Greg Williams, Department of Health Services, (916) 322-0453
Theodore R. Anderson, Bureau of Land Management, Bakersfield,
(805) 861-4177
Shelton Gray, Central Valley Water Quality Control Board,
(209) 445-5142
Hal Bopp, Division of Oil & Gas, (805) 322-4031
12
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COLORADO
Introduction
Colorado has a long history of regulating oil and gas activities. As
far back as 1889, Colorado passed a bill prohibiting the discharge of
oil, petroleum, or other substances into any waters of the State. In
1927, a second bill was passed that included provisions for well
plugging. In 1951, the Oil and Gas Conservation Act was passed. The
Solid Wastes Disposal Sites and Facilities Act was passed. The Solid
Wastes Disposal Sites and Facilities Act (Title 30-20-Part 1, C.R.S.
1973, as amended) also has jurisdiction.
In 1985, Colorado produced 30,552,685 barrels of oil from 5,287
wells; 275,684 million cubic feet of gas were produced from 4,665 gas
wells. Mud and air drilling are both encountered.
State Regulatory Agencies
Three agencies share regulatory authority for oil and gas wastes in
Colorado:
- Department of Natural Resources-Oil and Gas Conservation Commission
- Department of Health
- U.S. Bureau of Land Management
The Oil and Gas Conservation Commission has primary responsibility
for the management of oil and gas exploration, development and production
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t
activities in Colorado. The Commission is responsible for the
conservation of oil and gas, the protection of the rights of all parties,
and has general authority to protect the environment from pollution by
oil and gas activities on the site of drilling and production
operations. The Commission is also responsible for regulation and
permitting of central disposal facilities operated by the producing
companies.
The Colorado Department of Health, and specifically the Water Quality
Control Division/Commission and the Waste Management Division, has
statutory and regulatory authority over solid waste disposal sites and
facilities and NPDES permits, and is generally concerned with
endangerment of public health and the environment. Commercial disposal
facilities for wastes from oil and gas production operations are subject
to the Department's permitting and regulation. In addition, the
Department is responsible for permitting of discharges for beneficial use
for agriculture and wildlife.
Because the two agencies shared certain areas of responsibility under
their statutes, they developed a Memorandum of Understanding in 1971 to
specifically allocate responsibilities. Under this agreement, the Water
Quality Control Commission of the Department of Health designated the
Oil and Gas Conservation Commission as "its authorized representative to
exercise authority for the administration of water pollution prevention,
abatement and control required to protect the waters of the state from
conditions and activities arising from the drilling, production and
plugging of wells and all other operations for the production of oil and
gas." This relationship has subsequently been clarified in the
regulations of both agencies. The Department of Health regulations
specify that the Department:
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"...will consider oil and gas liquid waste impoundments to be in
compliance with these regulations if:
A. The disposal facilities are regulated by the Oil and Gas
Conservation Commission,
B. There is no imminent or substantial endangerment to the public
health or the environment from the disposal facilities, and
C. Compliance with the Certificate of Designation requirement is not
required by the County within which the site is located (for
central disposal facilities only)."
The U.S. Bureau of Land Management has jurisdiction over Federally-
owned mineral rights. The U.S. Forest Service retains surface rights on
Federally-owned forests and grasslands. EPA retains responsibility for
approving underground injection wells on Indian land. The requirements
of these agencies are discussed separately under Federal Agencies.
State Rules and Regulations
Drilling
Pit Requirements: Oil and Gas Conservation rules require that
"before commencing to drill, proper and adequate slush pits shall be
constructed for the reception and confinement of mud and cuttings and to
facilitate the drilling operation. Special precautions shall be taken to
prevent contamination or pollution of state waters."
According to information provided by the Oil and Gas Conservation
Commission, most wells are drilled using tanks rather than reserve pits;
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I
the reserve pits are used primarily when the mud is displaced during the
running of pipe. While there are no rules prohibiting the discharge of
produced waters into a reserve pit, this is not commonly done. If the
volume of produced water exceeded five barrels/day, this would make the
reserve pits subject to the construction requirements and reviews in Rule
325. Otherwise, pits "for temporary storage and disposal of substances
produced in the initial completion and testing or workover of wells
drilled for oil and/or gas for a period of time not in excess of ninety
(90) days" are excluded from application of many of the provisions of the
Rule.
Most drilling fluids and muds in Colorado are bentonite and fresh
water based. Very few oil-based drilling fluids are used, and those are
moved from operation to operation until disposed of into an approved
landfill.
Pit Closure/Discharge: If the well is a dry hole and is abandoned,
backfilling of pits and reclamation of the land must be completed within
six months, unless an extension is granted for unusual circumstances
(Rule 319(a)(8)).
Generally, after decanting of the lighter fluids in the reserve pits,
reserve pit sludges may be dried out and disposed of on the surface by
tilling into the ground. The sludge may be removed to a different
location before land disposal. The sludge may also be buried when the
pit is backfilled. The Commission has permitted one facility for land
discharge of wastes with limitations on total suspended solids, total
dissolved solids, oil and grease, and chemical oxygen demand.
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Produced Waters
Produced water is disposed of through reinjection (c. 85%), placement
in storage and disposal pits (c. 15%), and discharge for beneficial use
for agriculture and wildlife (<1%).
Disposal and Storage Pits: The Oil and Gas Conservation Commission
regulates all produced-water storage or disposal pits except for the
commercial disposal facilities regulated by the Department of Health.
This includes both on-site pits and central pits. A central pit is a
storage or disposal pit serving several leases or batteries in a field,
and operated by one of more oil and gas operators, under a field
operators agreement approved by the Commission.
Both central and on-site pits are subject to the requirements of Rule
325, which specifies informational, construction and operating
requirements. Minimally, such pits are required to have adequate storage
capacity for the volume of produced water expected, and to be kept free
of surface accumulations of oil or other hydrocarbons which could impede
evaporation. Certain of the other requirements in the Rule do not apply
where the volume of water to be disposed does not exceed 5 barrels per
day on a monthly basis.
Generally, applicants for permits to construct produced-brine
disposal pits must provide substantial information on surface waters and
groundwaters, geology and soil types in the area of the well. The
application must also indicate the source and expected volume of water to
be produced daily, and a chemical analysis of the water, assessing all
factors related to salinity. If a pit is located over permeable soil,
and will receive, at full capacity, in excess of 100 barrels of fluid/day
with a TDS content of 5,000 ppm or more, the operator must provide a plan
for lining the pit and detecting leaks. Liners may be required where
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I
water placed in the pit has a higher IDS content than underlying aquifers
hydrologically connected, regardless of the amount of water delivered to
the pit.
The Commission makes case-by-case determination on lining
require/ments for all produced-water storage and disposal pits on the
basis of site-specific evaluations. According to information provided by
the Commission, 90% of the pits for wells producing more than 5 barrels
per day of water are required to be lined (approximately 2/3 with clay
and 1/3 with synthetic liners). Of the remaining pits, either the
received water is fresh and is allowed to percolate, or the pits are over
impervious shales and the water evaporates.
Injection: Produced water is reinjected into Class II wells both for
enhanced recovery (667 wells) and disposal (134 wells). The UIC Class II
injection program has been delegated to the Oil and Gas Conservation
Commission.
Wells used for injection into oil or gas producing disposal zones
must have "safe and adequate casing or tubing so as to prevent leakage,
and shall be so set or cemented that damage will not be caused to oil,
gas or fresh water resources." Detailed reports on fluids received and
injected must be filed monthly.
Mechanical integrity tests must be performed on new injection wells
before starting injection, and every five years thereafter. The test
pressure must be 300 p.s.i. or the minimum injection pressure, whichever
is greater, and not more than the maximum injection pressure, with a
pressure variance of no more than 10%. Monthly injection reports are
submitted which list volumes injected and injection pressures. All
injection facilities are inspected by the Commission staff on a routine
basis.
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Discharges for Wildlife and Agricultural Use: A few facilities in the
states have permits from the Department of Health for effluent discharges
under the BPT Wildlife and Agricultural Use Subcategory. The effluent
limitations are:
pH - 6.0 to 9.0
Total suspended solids - 30 mg/1 (30-day average)
45 mg/1 (1 day maximum)
Oil and grease - 10 mg/1
Total dissolved solids - 5,000 mg/1 (30-day average)
7,500 mg/1 (1-day maximum)
Offsite Disposal
Commercial off-site produced water evaporation or evaporation/
percolation pits are regulated by the Division of Waste Management of the
Department of Health. According to information provided by the
Department of Health, there are currently eight commercial disposal pits,
of which half are lined. Lining requirements are determined by
classifications of impoundments. Class I facilities (in recharge area
for drinking water aquifer, where seepage from impoundment would impair
use of the groundwater) require double liners with leak-detection
systems. Class II impoundments (where seepage would damage a freshwater
aquifer if no liner were used) require single liners and monitoring
systems. Class III impoundments (located outside a recharge area, or
competent bedrock between the surface and the aquifer, or impairment
would not result from unrestricted seepage) require no liners.
Truckers transporting produced brines to offsite impoundments or
injection wells must file monthly reports on the source, volume and
recipient of the waters hauled. Similar records must be kept by the
receiving facility. These records will be subject to computerized cross-
tabulation.
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Plugging/Abandonment
Wells that have ceased production or are incapable of production are
to be abandoned within six months, unless granted an extension by the
Director of the Oil and Gas Conservation Commission (Rule 319(b)). In
practice, if a well is shut down for economic reasons, the Commission
will not require a formerly producing well to be plugged. If, however,
the operator of the well has numerous wells which are closed down for
economic reasons, and is operating all such wells under a single blanket
bond, the Director may require the provision of individual bonds for each
well. The operator must file a status report every six months indicating
plans for future operations.
Wells must be plugged so as to confine oil, gas, or water to original
strata. The operator must obtain approval of plugging method from the
Commission prior to plugging operation. Surface casing may not be
removed from the well unless approved by the Director. Generally, cement
plugs are required 50 feet above and below each permeable zone, a 100-
foot plug at the base of the surface casing, and a cement plug at the top
of the surface casing. The operator may plug above perforated zones, or
may squeeze with cement prior to abandoning the well or before
recompleting into another formation..
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t
References
Interstate Oil Compact Commission, The Oil and Gas Compact Bulletin,
Volume XLIV, No. 2, December 1985.
U.S. EPA, Proceedings of the Onshore Oil and Gas State/Federal Western
Workshop, December 1985.
Colorado Department of Health. Statement of the Colorado Department of
Health for the Informational Hearing Regarding Oil and Gas Brine
Waste Disposal to the Colorado Water Quality Control Commission. May
10, 1983.
State of Colorado. Department of Natural Resources. Oil and Gas
Conservation Commission. Rules and Regulations, Rules of Practice
and Procedure, and Oil and Gas Conservation Act (As Amended).
Effective July 16, 1984.
Order 1-39, modifying the Rules and Regulations of the Oil & Gas
Conservation Commission. Effective August 8, 1986.
State of Colorado. Regulations Pertaining to Solid Waste Disposal Sites
and Facilities, Effective Date: October 1, 1984.
Personal Communications:
William R. Smith, Oil & Gas Conservation Commission, (303) 866-3531
10
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I
Florida
Introduction
Florida produced 14,090,000 barrels of oil and 15 x 10g
cubic feet
of gas in 1984. Production was from 165 oil wells; there are no
producing gas wells. Virtually all drilling fluids as well as produced
fluids are reinjected.
Regulatory Agencies
Four agencies are responsible for regulating the oil and gas
industry in Florida:
- Florida Department of Natural Resources, Division of
Resource Management, Florida Geological Survey
- Florida Department of Environmental Regulation
- Florida Regional Water Management Districts
- U.S. Environmental Protection Agency, Region IV
Primary regulatory responsibility rests with the Department of
Natural Resources (DNR). DNR is the permitting agency for oil and gas
wells, including approval to dispose of waste fluids by subsurface
injection. The DNR regulates the exploration, drilling, and production
of the oil and gas industry with respect to reporting, spacing, safety,
and construction.
The Department of Environmental Regulation oversees the industry
with respect to water quality standards and dredge and fill requirements
(for pits) if oil and gas activities occur in wetlands of the State.
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t
Florida's Regional Water Management Districts, which are separate
regulatory groups on a local level, regulate oil and gas activities with
regard to water use. Consumptive use permits are issued if applicable.
Other State agencies may be involved on a case-by-case basis. These
agencies are most commonly the Florida Game and Freshwater Fish
Commission, the Department of Community Affairs, and the Department of
Transportation.
The State of Florida does not have primacy for Class II UIC program
wells. The State operates a separate program for injection wells with a
State permit and State inspections. A driller wishing to inject fluids
underground must apply for permit to do so from two separate governmental
entities, the U.S. Environmental Protection Agency Region IV and the
State, and undergo two sets of inspections.State Rules and Regulations
Drilling fluids are put into pits during operation but then disposed
of by reinjection. Pits are nearly dry when they are backfilled. They
are lowered as fast as possible by pumping down the well bore prior to
plugging the well. All produced waters are reinjected.
The DNR is governed by Chapter 377, Florida Statutes, and its
implementing rules, Chapters 16C-25 through 16C-30, Florida
Administrative Code. Part of Chapter 377s specific purpose is to
"require the drilling, casing, and plugging of wells to be done in such a
manner as to prevent the pollution of fresh, salt, or brackish waters on
the lands of the State." And Section 377.371 further states that, "No
person drilling for or producing oil, gas, or other petroleum products
shall pollute land or water ; damage aquatic or marine life, wildlife,
birds, or public or private property."
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t
UIC permits are issued pursuant to Chapter 403, Florida Statutes and
Chapter 17,28, Florida Administrative Code. If,applicable, dredge and
fill activities are regulated under Chapter 403, Florida Statutes, and
Chapter 17-12 Florida Administrative Code. Water standards are issued
under Chapters 17-3 and 17-4, Florida Administrative Code. Water
management licenses (consumptive use) are issued under Chapter 373,
Florida Statutes, by the regional Water Management Districts.
Plugging/Abandonment
Each request for temporary abandonment will be considered on a case-
by-case basis. But the requirements for temporary abandonment are not
significantly different than those for abandonment. Only the placement
of a surface plug and the restoration of the surface area are not
required.
When plugging an abandoned well, perforated intervals require cement
retainers 100 feet above the interval, a 100-foot plug placed at the top
of the retainer, and cement squeezed into the interval, or they require a
200-foot plug extending 100 feet above and below the interval. With
respect to open hole below casing string, a plug must be placed 100 feet
above and below the casing shoe. A plug must be placed 100 feet above and
below the casing stub if the casing is cut. Annular space must be plugged
with a minimum 100-foot plug at the top of the casing. In uncased holes,
200-foot plugs must be placed opposite hydrocarbon formations, and at
contact points between saline and fresh water zones. Additional plugs
must be placed in the casing of smallest diameter (25-foot on dry land;
150-foot for wetlands).
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References
Lloyd Wise, Region IV NPDES permit writer, Summary of EPA
Workshop presentation, Onshore Oil and Gas Workshop
Meeting Report. July 1985.
Lynn Griffin, Environmental Specialist, Department of
Environmental Regulation. Letter to W.A. Telliard, EPA,
March 22, 1985.
State of Florida Regulatory and Review Procedures for Land
Development. Chapter 14. November 1, 1984.
Personal Communication:
Lynn Griffin, Environmental Specialist, Department of Environmental
Regulation, October 2, 1986 (904) 488-8615.
David Curry Florida Department of Natural Resources (904) 487-2219.
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ILLINOIS
Introduction
Illinois produced 28,873,000 barrels of oil and 15 x 10 cubic feet
of gas in 1984. Production is from 28,920 oil wells and 157 gas wells.
Nineteen barrels of brine are produced for every barrel of oil. Seven
thousand injection wells are operating in the State.
State Regulatory Agencies
Principally one agency regulates the oil and gas industry in Illinois:
- Department of Mines and Minerals, Division of Oil and Gas
The Department of Mines and Minerals operates under an Act in
Relation to Oil, Gas, Coal and Other Surface and Underground Resources.
Section 8A of the Act provides the Department with the power and
authority to regulate the disposal of salt- or sulphur-bearing water and
any oil field waste produced in the operation of any oil or gas well, and
to adopt proper rules and regulations relative thereto. Section 8B
provides that no person shall drill, convert or deepen a well for the
purpose of injecting gas, air, water, or other liquid into any
underground formation or strata without first securing a permit
therefor. Section 8C(A) states that no person shall operate an oil field
brine transportation system without an oil field brine transportation
permit. Section 8G(3) specifies that the permittee shall not dispose of
oil field brine onto or into the ground except at locations specifically
approved and permitted by the Mining Board. No oil field brine shall be
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placed in a location where it could enter any public or private drain,
pond, stream or other body of surface or ground water.
The Division of Oil and Gas has UIC program primary for Class II
wells. There are Federal lands in Illinois but there is no drilling or
production on Federal lands currently. The Illinois Environmental
Protection Agency has been delegated NPDES authority but no surface water
discharges from the oil and gas industry are allowed.
State Rules and Regulations
Drill ing
Before commencement of drilling a new well, the operator must execute
a bond of $2,500 unless the operator already has a blanket bond of
$25,000. The bond is cancelled only after the well has been plugged, and
all related restoration activities have been completed.
There are no State requirements that drilling pits be permitte or
lined. Fluids from the pits may be disposed in a dry drill hole. When
the pit mud dries, the pit is back-filled and reclaimed. Pits must be
reclaimed within 6 months after drilling ceases.
Production
Produced waters go into lined holding-evaporation ponds or are
reinjected into certified injection wells. If pits are used, the lining
must be an impermeable material which will prevent seepage. Most
requests are for fiber glass or concrete lined pits. Earthen lined pits
have been substantially eliminated during the past 5 years. The
Department of Mines and Minerals has been reducing the number of old pits
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by removing and injecting the brines, stabilizing the contents, applying
topsoil, and vegetating the pit area.
Neither road spreading nor land farming is allowed.
Seven thousand injection wells for disposal or enhanced recovery are
operating in Illinois, of which the majority are water flooding wells.
Permits for injection wells must be obtained from the Division of Oil and
Gas. The permit application must include the location and depth of any
existing wells within a half-mile of the proposed new or converted
injection well, and information to show that injection into the proposed
zone will not initiate fractures through the overlying strata which would
enable injection or formation fluids to enter fresh water strata.
Injection must be through adequate tubing and packer.
A mechanical integrity pressure test must be carried out before
initiation of injection. Thereafter, the well must be tested at least
every five years (or, alternatively, monthly records of actual injection
pressure in the casing tubing annulus may be reported annually). Test
pressures for new wells must be at the the greater of 300 psi or the
maximum authorized injection pressure; the same range applies for newly
converted wells or on retests, except the ceiling is 1,000 psi.
Offsite/Commercial Disposal
Use is not made of offsite or commercial pits in the state of
111inois.Brines may be transported offsite to injection wells.
Transporters must have oil field brine hauling permits. Well operators
must maintain detailed records of all brine removed from their leases,
and of the haulers with whom they contracted for the removal.
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Plugging/Abandonment
A well must be plugged within 30 days of the cessation of drilling
operations if no production casing has been run. Wells at which there
have been no production operations for six months must be plugged, unless
the operator has been granted an extension. Requests for extensions will
be granted by the Mining Board for good cause so long as all casing
remains sound and in the well. The length of the extension is at the
discretion of the Board. When an extension is granted, if no bond
covering the well is in effect, a bond is required from the operator,
which remains in effect until the well is plugged. If, at expiration of
the extension, Mining Board denies a further extension, the well must be
plugged and abandoned.
When plugging, cement plugs must be placed opposite any producing
formation and extend 20 feet above the formation. Cement plugs must also
be placed from 50 feet below to 100 feet above any coal seam thicker than
30 inches, from 20 feet below to 20 feet above the casing seat of the oil
string, and from 10 feet below to 15 feet above the base of the surface
casing. If surface casing was not used, a 25 foot plug must be used below
the surface with a one foot mushroom cap. Where surface casing was used,
the casing must be cut off three feet below the ground and a one foot cap
added. Mud must fill the remainder of the well. There are no specific
provisions for plugs over zones with potable water.
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References
Summary of State Statutes and Regulations for Oil and Gas Production.
1986. Interstate Oil and Gas Commission (June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil Compact
Commission (December).
Illinois Meeting Report. 1985. Proceedings of the Onshore Oil and Gas
Workshop. U.S. Environmental Protection Agency, Washington, D.C.
(March 26-27 in Atlanta, GA).
State of Illinois. 1984. An Act in Relation to Oil, Gas. Coal and Other
Surface and Underground Resources. Revised Edition.
State of Illinois. 1984. Rules and Regulations. Department of Mines and
Minerals, Division of Oil and Gas. Revised Edition.
Personal Communication:
George R. Lane, Division of Oil and Gas (217) 782-7756.
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INDIANA
Introduction
Indiana produced 4,758,609 barrels of oil and 367,084,000 cubic feet
of gas in 1986. Production was from 7,600 oil wells and 806 gas wells.
State Regulatory Agencies
Two agencies principally regulate oil and gas activity in Indiana:
- Indiana Department of Natural Resources, Division of Oil and Gas
U.S. Environmental Protection Agency, Region V
The Indiana Division of Oil and Gas regulates the industry through
Rule 310 IAC 7-1. No discharge to surface waters is allowed so that any
involvement of the Indiana Department of Environmental Management would
occur as a result of improper disposal of oil and gas wastes. Concerns
that owners of Federal lands may have regarding oil and gas surface
treatment are satisfied thorough conditions of the respective lease
agreements.
The Oil and Gas Division does not have primacy for UIC program Class
II wells. The State is in the process of attaining such status.
Currently, however, anyone interested in underground injection must
obtain two permits--one from the State, and one from the U.S.
Environmental Protection Agency.
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State Rules and Regulations
Drilling
Adequate pits for muds or wastes associated with drilling operations
are required. Drill pits must be reclaimed within 60 days after drilling
has stopped. Fluids associated with such drill pits generally can be
classified as fresh-water and are mixed with bentonite clays. When a pit
is closed, the practice is to pump the small amount of fluid in the pit
to the surrounding land, bury the drill cuttings and other pit muds, and
reclaim the land.
Production
Pits used for gathering production fluids and storing them until
reinjection must be lined with impervious clay or an artificial liner.
All production fluids must be reinjected underground. Evaporation pits
were disallowed by the State two years ago.
Plugging/Abandonment
Any well which is not producing must be capped and sealed
immediately. If not placed back in production within two years, the
operator may be required to plug and abandon the well, to recase the
well, or to demonstrate (through pressure testing or other approved
method) that the well casing is in good condition and there is no
commingling of fluids.
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When the well is plugged, cement plugs are required from 50 feet
below (or from the bottom of the well) to 100 feet above any stratum with
oil, gas, or commercial deposits of coal. Where insufficient casing is
set or surface casing was not cemented to surface, production casing
should be removed from 50 feet below the deepest aquifer containing
potable water, and a cement plug placed from the remaining production
string to three feet below the surface. In the case of a dry hole which
has not encountered coal, a similar surface plug may be placed after
filling the hole from the bottom with mud. The use of bridges is
prohibited.
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References
Summary of State Statutes and Regulations for Oil and Gas Production.
1986. Interstate Oil and Gas Commission (June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil Compact
Commission (December).
Personal Communications:
Mike Nickolaus, Indiana Division of Oil and Gas (317) 232-4055.
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KANSAS
Introduction
Q
Kansas produced 75,723,000 barrels of oil and 466.6 x 10 cubic
feet of gas in 1984. Production is from 57,633 producing oil wells and
12,680 gas wells. Kansas ranks seventh in both U.S. oil production and
U.S. gas production. There are 11,000 injection wells in the State.
Oil was found in Kansas in the 1860s, but it was not commercially
developed until 1895. Oil and gas regulation began in 1935.
State Regulatory Agencies
One agency regulates oil and gas activities in Kansas:
Kansas Corporation Commission
On July 1, 1986, by passage of House Bill 3078, the Kansas
Legislature transferred the Department of Health and Environment's
regulatory responsibilities for oil and gas activities to the Kansas
Corporation Commission. Prior to July 1, 1986, the Department of Health
and Environment had responsibilities related to lease maintenance,
emergency pits, drill pits, burn pits, storage ponds and Class II oil
field brine and enhanced recovery injection wells. Under Kansas'
Statutes (Chapter 55, Article 10, 55-1003) plans and specifications for
the disposal of oil and gas brines and mineralized waters were to be
submitted to and approved by both the State Corporation Commission and
the Secretary of Health and Environment. Subsequent to the 1988
legislative action, the Secretary of Health and Environment no longer is
a party to such action.
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There are few Federal lands and little involvement of Indian Tribes
in the Kansas oil and gas industry. The State informs neither party
directly when an application for a permit to drill has been received.
Such information is published as a routine matter in local news outlets,
and if there are specified requirements by the Bureau of Land Management
or Indian Tribes, they are communicated directly to the driller through
lease agreement condition or by other legal means.
State Rules and Regulations
Regulation of the industry is through the issuance of drilling and
well operation permits. A compliance or surety bond is not required.
With the recent departmental transfer of responsibilities, the
Corporation Commission is in the process of revising and proposing
regulations pertaining to those activities formerly administered by the
Secretary of Health and Environment.
Pit Requirements: Drilling pits and burn pits have been permitted
and regulated, without requiring a separate permit application, under a
general rule for a maximum period of 365 days unless the operator
requests and receives approval for an extension. Drilling pits may be
used to temporarily confine "salt water, oil or refuse resulting from oil
and gas activities during the drilling, completion or testing of any oil,
gas, exploratory, wildcat, service or storage wells." Permits are
required for emergency pits.
Liners are not required for drilling pits unless the Commission
determines a liner to be necessary to protect soil or water resources in
geologically or hydrologically sensitive areas. In such areas liners or
portable pits can be required. In areas with sandy soils, for example,
drilling pits are required to be lined. In the heavy clay region of the
north-central portion of the state, however, such pits would most likely
not be lined.
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Pit Closure: On-site burial, after evaporation or mechanical
dewatering, is the primary method of pit closure. After May 1, 1987,
backfilling is required "as soon as practical or as required by the
commission" after abandonment. Most lease agreements already contain
such a requirement. Landfarming is prohibited. In geologically or
hydrologically sensitive areas, in situ disposal of drilling pit contents
can be prohibited.
Produced Waters
Injection: Ninety-nine percent of produced water is disposed of into
injection wells for enhanced recovery (9,399 wells) or for salt water
disposal (5,536 wells). The Kansas Corporation Commission has primacy
for the UIC Class II program. Operators may inject produced saltwater
into enhanced recovery or disposal wells after receiving approval of
their applications from the Commission. Water injected into disposal
wells may be returned to any horizon from which produced, or to other
subsurface waterbearing formations which contain or previously produced
saltwater or appreciably mineralized water.
All injection and disposal wells requiring wellhead pressure to
inject fluids must inject through tubing under a packer set immediately
above the uppermost perforation or open-hole interval. The annulus
between the tubing and the casing shall be filled with a corrosion-
inhibiting fluid or hydrocarbon liquid. Packerless or tubingless
pressure completions may be authorized under special conditions. (For
example, injection through tubing without a packer must, among other
requirements, have no surface wellhead pressure). Wells must be cased
and cemented in such manner as to prevent damage to hydrocarbon sources
or fresh and usable water sources.
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Mechanical integrity tests must be conducted before injection begins,
and at least every five years thereafter. Packerless wells shall be
tested using a retrievable plug immediately above the uppermost
perforation or open-hole zone. The test pressure must be 100 psi or the
authorized injection pressure, whichever is greater. No time period or
pressure variance for the test is specified in the regulations.
Other Storage/Disposal Practices: Spreading of salt water on roads
under construction is not prohibited if approval is received from the
Kansas Department of Health and Environment.
Requests for a surface pond permit are granted unless denied by the
Commission within 10 days. According to proposed Rule 82-3-600, the
Commission, in approving applications for surface pond permits, shall
consider the protection of soil and water resources from pollution. Each
operator of a surface pond shall install observation trenches, holes, or
wells if required by the Commission, and seal the pond with artificial
material if the Commission determines that an unsealed condition will
present a pollution threat to soil or water resources. Surface drainage
is to be prevented from entering the pond. During the past two years, it
has become a practice, on a case-by-case basis, to require monitoring
wells in association with surface ponds and emergency pits in areas of
shallow groundwater supply.
There are approximately 25 permanent pits, receiving a total of 30
barrels of brine a day, mostly in the Southeast corner of the State where
there are no groundwater or seepage problems and where TDS concentrations
of the produced waters are less than 10,000 ppm. Surface discharges of
produced brine are not allowed nor is pit disposal allowed.
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Upon the permanent cessation of the flow of fluids into any surface
pond, all fluids resulting from oil and gas activities shall be removed
to a disposal well approved by the Commission, or used for road
maintenance or construction if approved by the Commission. Pond solids
may be transported to a permitted solid waste landfill or to an approved
offsite disposal area. Either action requires a permit from the
Department of Health and Environment under the Kansas Solid Waste
Statutes.
Offsite and Commercial Pits
Use is not made of offsite or commercial pits.
PIugging/Abandonment
Kansas Statute 55-156 states that prior to abandonment of any well
*••*
which has been drilled, is being drilled, or may hereafter be drilled,
the operator shall protect usable groundwater or surface water from
pollution, and from loss through downward drainage, by plugging the well
in accordance with the rules and regulations adopted by the Commission.
Failure to comply with these rules and regulations shall be a class E
felony.
Within 90 days after operations cease on any well, the operator must
plug the well or give notice of temporary abandonment. If no production
has begun after a year, the operator must either reapply for temporary
abandonment status or plug the well. Extensions are given for good cause,
which means primarily for economic reasons.
Cement plugs of at least 50 feet in length shall be placed above each
present or past productive formation, and both above and below any
freshwater horizons. Intervals between all plugs shall be filled with
approved heavy mud-laden fluid.
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References
Kansas Meeting Report. 1985. Proceedings of the Onshore Oil and Gas
State/Federal Western Workshop. U.S. Environmental Protection
Agency, Washington, D.C. (December 1985).
Summary of. State Statutes and Regulations for Oil and Gas Production.
1986. Interstate Oil and Gas Commission (June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil Compact
Commission (December).
General Rules and Regulations, the State Corporation Commission of the
State of Kansas (Effective May 1, 1986).
Personal Communication:
Jim Schoff, Kansas Corporation Commission (316) 263-3238.
Rick Hesterman, Kansas Corporation Commission (316) 263-3238.
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Kentucky
Introduction
Kentucky produced 7,788,000 barrels of oil and 61.5 x 109 cubic
feet of gas from 8,798 gas wells, 19,334 oil wells, and 283 combination
wells in 1984.
State Regulatory Agencies
Five agencies regulate oil and gas activity in Kentucky:
- Kentucky Division of Oil and Gas
- Kentucky Department of Natural Resources and Environmental
Protection
- U.S. Bureau of Land Management
- U.S. Army Corps of Engineers
- U.S. Environmental Protection Agency, Region IV
The Kentucky Division of Oil and Gas in the Department of Mines and
Mining, issues drill permits and provides well casing and well plugging
requirements. The State is seeking primacy but does not yet have primacy
for the UIC Class II well program.
The Kentucky Department of Natural Resources and Environmental
Protection has NPDES - delegated authority. The Department issues
permits for holding pits containing production fluids and instructions,
pursuant to regulations, for pit construction.
The U.S. Army corps of Engineers becomes involved in oil and gas
activities on lands maintained for water management projects.
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State Rules and Regulations
Drilling
Pursuant to Kentucky regulation 401 KAR 5:090, there can be no
discharge from a pit without an NPDES permit. Pits used to contain
drilling muds or fluids associated with drilling activities have a permit
by rule (unde Title 401, Chapter 47 - Solid Waste Facilities) for
construction and operation , provided that the pit life is not longer
than 30 days after completion of exploration or drilling activities.
Where the pit life is longer than 30 days beyond completion of
exploration or drilling activities, the pit is defined as a holding pit,
and a facility-specific permit is required. When a pit no longer is in
service, it must be backfilled and the land restored. There are no liner
requirements for a drilling pit.
Production
A holding pit is a pit "designed to receive and store produced water
at a facility." A holding pit must have a permit and must be lined with
a synthetic material of ZOmil minimum thickness. The State may grant an
exemption to the lining clause for pits that pre-existed the date of
regulatory enactment. Construction requirements include at least 1 foot
of freeboard and a 2-foot berm above ground around the pit. Surface
waters must be divertied from the pit.
No NPDES permits have been issued for discharges from holding pits.
However, the Department of Natural Resources and Environmental Protection
recently was sued and entered into a consent decree which specified a
water quality criterion of 600 mg/1 chlorides as appropriate for
receiving water quality. It is anticipated that there will be a number
of requests for NPDES permits to discharge produced fluids.
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Some holding pits are used as produced water storage pits until a
contract hauler transports the fluids for well injection or other
purposes. There is no manifest system per se, but there is reporting of
the producer, the amount of the fluid and its destination following
transportation. Most of the fluid goes into injection wells.
There is no roadspreading or landspreading of produced fluids in
Keentucky. Some use is being made currently of mechanical evaporation.
PIuggi ng/Abandonment
A well may be temporarily abandoned for cause for two years, on a
renewable basis. The well must be capped in such a way as to prevent
escape of oil, gas or water from the well, or entrance of foreign
materials into the well.
When a well not drilled through a coal-bearing stratum is abandoned,
it must be securely plugged "by placing above the oil-producing sand a
plug of pine, poplar or some other material that will prevent the well
from becoming flooded." After 7 feet of clay or sediment above the plug,
another plug of the same kind should be set. A similar combination of
plugs and clay should be placed with the lower plug 10 feet below the
casing. [Sec.353.180] Additional requirements are imposed for wells
drilled through coal-bearing strata, including the use of cement
plugs.[Sec.353.120].
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References
Summary of State Statutes and Regulations for Oil and Gas Production.
1986. Interstate Oil and Gas Commission (June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil Compact
Commission (December).
Personal Communications:
Brian C. Gelpin, Kentucky Division of Oil and Gas (606) 257-3812.
Brad Lambert, Kentucky Department of Natural Resources and
Environmental Protection (502) 264-3410.
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LOUISIANA
Introduction
Q
Louisiana produced 449,545,000 barrels of oil and 5,867 x 10 cubic
feet of gas in 1984. Louisiana ranks third in U.S. oil production and
second in U.S. gas production. Over half of Louisiana's 25,823 oil wells
are strippers. More than two-thirds of Louisiana's 14,436 gas wells are
marginal (produce less than 60 thousand cubic feet of gas per day.)
Eighty five percent of all produced fluids is salt water.
State statutes have regulated drilling operations since 1940. On
January 20, 1986, the Office of Conservation promulgated amended rules
and regulations regarding "the storage, treatment, and disposal of non-
hazardous oilfield waste."
State Regulatory Agencies
Four agencies regulate oil and gas activity in Louisiana:
- Louisiana Department of Natural Resources, Office of Conservation
- Louisiana Department of Environmental Quality
- U.S. Bureau of Land Management
- U.S. Corps of Engineers
The Louisiana Department of Natural Resources Office of Conservation
regulates all subsurface and surface disposal of oil- and gas-associated
wastes. These powers are delegated to the Office of Conservation under
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Title 30 of the Louisiana Revised Statutes of 1950. The Office of
Conservation has been granted primacy for all classes of UIC wells.
The Office of Conservation does not coordinate with EPA on NPDES
permits, but does coordinate with the Louisiana Department of
Environmental Quality, Office of Water Resources, on any problem
discharges originating from oil and gas activities. The Office of Water
Resources also permits discharges of brine and reserve pit fluids. The
effluent standards incorporated in the permits represent DEQ-OWR policy;
the proposed effluent regulations for oil and natural gas development
have not yet been adopted. The regulatory basis for that policy is found
in rather general rules (January 27, 1953) of the Stream Control
Commission, and a subsequent order (July 1, 1968) of the Commission.
The Bureau of Land Management has jurisdiction over lease
arrangements and post-lease activity on Federal lands where the mineral
rights are federally held. Surface rights in Federal forests and
grasslands are retained by the U.S. Forest Service. These rules,
regulations, and orders are discussed in a separate section, Federal
Agencies. The Bureau of Indian Affairs has some jurisdiction in limited
areas of Louisiana.
State Rules and Regulations
Dril1 ing
Pit Construction/Management: Reserve pits utilized in the drilling
of oil and gas wells do not have to be lined. However, Louisiana
Statewide Order No.29-B contains stringent operational requirements for
reserve pits, including segregation of the drilling wastes in reserve
pits from produced water or waste oil, protection from surface waters by
levees, walls and drainage ditches, and maintenance of 2-foot freeboard.
-------
Pit Closure/Discharge: Reserve pits must be emptied of fluids and
closed within six months of completion of drilling or workover
operations. Prior to closure, and for all closure and onsite and offsite
disposal techniques except subsurface injection of reserve pit fluids,
wastes must be analyzed for pH, oil and grease, and a number of metal and
salinity parameters. (An exemption to the testing requirement is granted
for reserve pit fluids from wells drilled to less than 5,000 feet using
fresh water "native" mud with limited amounts of bentonite, barite or
caustic soda). Disposal of drilling and workover waste fluids at pit
closure may be accomplished through annular injection, injection down
another newly-drilled well which will be plugged, onsite land treatment,
solidification and burial onsite, mixing waste with native soil and
burial onsite, wastewater discharge, or offsite disposal at permitted
commercial facilities.
The Water Pollution Control Division issues a standard permit to
oilfield service companies to discharge wastewater from treated drilling
site reserve pits and abandoned or inactive production pits in order to
facilitate pit closure. This permit allows the discharge of fluids
meeting the following maximum effluent limitations:
Oil and Grease - 15 mg/1
Total Suspended Solids - 50 mg/1
Chemical Oxygen Demand - 125 mg/1
Total Chromium - 0.5 mg/1
Zinc - 5-.0 mg/1
Chlorides - 500 mg/1
pH - 6.0 to 9.0
There are provisions for dilution of the wastewater to meet the
chloride limitation provided all other parameters are met (predilution
-------
chloride concentrations must be less than 2000 mg/1 in freshwater areas
and less than four times ambient chlorinity in brackish and saline areas).
Reserve pit fluids may be disposed of onsite providing applicable
technical criteria are met. For either land treatment, burial or
trenching, waste/soil mixture must not exceed:
pH - 6-9
Arsenic - 10 ppm
Barium - 2,000 ppm
Cadmium - 10 ppm
Chromium - 500 ppm
Lead - 500 ppm
Mercury - 10 ppm
Selenium - 10 ppm
Silver - 200 ppm
Zinc - 500 ppm
Onsite land treatment may be used for closing pits containing only
nonhazardous oilfield wastes by mixing wastes with soil from pit walls or
levees and adjacent areas, providing the resultant waste/soil mixture
meets the above criteria, has an oil and grease content no greater than
1% (dry weight), and meets additional parameters in freshwater wetlands
not normally inundated and in uplands:
Electrical conductivity (EC) - < 8 mmhos/cm (wetlands)
< 4 mmhos/cm (uplands)
Sodium absorption ratio (SAR) - <14 (wetlands)
<12 (uplands)
Exchangeable sodium % (ESP) - <25% (wetlands)
<15% (uplands)
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Pits may be closed by mixing the waste with soil and burying the
mixture onsite if it meets the above pH and metals limits, has moisture
content <50% by weight, EC 12 mmhos/cm, and oil and grease content 3% by
weight. The top of the burial site must be at least 5 feet below ground
level and covered by native soil, and the bottom at least 5 feet above
the seasonal high water table.
Pits may be closed by solidification and onsite burial, using the
same cover and depth requirements, if they have a pH of 6-12, and do not
exceed the following limits in leachate tests:
Oil & grease
Arsenic
Barium
Cadmium
Chromium
The solidified material must also meet permeability, compressive strength
and wet/dry durability criteria.
Injection of drilling and workover waste fluids (including reserve
pit fluids) may only be done at the well where used, and must not
endanger underground sources of drinking water. Surface casing annular
injection may be authorized if the surface casing is set and cemented at
least 200 feet below the base of the lowest underground source of
drinking water. Injection may be through perforations in the
intermediate or production casing if that casing is set and cemented .at
similar depth. Surface casing open hole injection may be approved if, in
addition to meeting the 200-foot requirement, there is a cement plug of
at least 100 feet across the uppermost potential hydrocarbon zone.
10 mg/1
0.5 mg/1
10 mg/1
0.1 mg/1
0.5 mg/1
Lead
Mercury
Selenium
Silver
Zinc
0.5 mg/1
0.02 mg/1
0.1 mg/1
0.5 mg/1
5 mg/1
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Production:
Pits: All production pits must be lined such that the hydraulic
conductivity of the liner does not exceed 1 x 10" cm/sec. Liners may
consist of clays, soils mixed with cement or clays, synthetics (at least
10 mil thickness), or any combination meeting the 1 x 10" cm/sec
limitation. Production pits located within inland tidal waters, lakes
bounded by the Gulf of Mexico, and saltwater marshes are exempted from
the liner requirement provided they are part of an approved treatment
train for removal of residual oil and grease. Natural gas processing
pits and compressor station pits which collect and store process water
and stormwater runoff are also exempted.
Surface Discharge: The current policy of the Office of Water
Resources is that discharge of produced water is permitted into brackish
and saline areas, with a discharge limit for oil and grease of 72 mg/1
(monthly sample). A report is required on monthly volumes discharged and
on oil and grease, and an annual report on chlorinity (though no limit is
established). The discharge must be to an open flowing water body of
sufficient volume to prevent stratification and significant buildup of
ambient salinity. The actual regulatory requirement states that
"saltwater may be disposed of in normally saline waters, tidally affected
waters, brackish waters or other waters unsuitable for human consumption
or agricultural purposes.
Exceptions to the restriction against discharges in fresh water
bodies are given for the Mississippi River and its distributaries below
Venice, and the Atchafalaya River below Morgan City.
New regulations in November, 1985 required for the first time that
all of the above discharges be permitted. A mailing was sent out in 1986
requiring filing of information and permit applications for current
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discharges. When these are received and evaluated, discharges actually
occurring in fresh water areas not covered by the above exceptions would
be required to end.
Injection: Over two-thirds of produced water is reinjected for
enhanced recovery or disposal, both onsite and commercial. Injection
wells must be equipped with tubing set on a mechanical packer, set no
higher than 150 feet above the top of the disposal zone. Surface casing
must be set through the deepest underground source of drinking water and
cemented back to the surface. Long string casing must be cemented above
the injection zone.
Mechanical integrity tests must be carried out at least every five
years. Test pressures should be at the maximum permitted injection
pressure, but within the interval of 300 - 1,000 psi. The test interval
should be 30 minutes, with no greater than a 5 psi variance.
Offsite Disposal
Reserve pit contents can be transported offsite to permitted
commercial land treatment or pit disposal facilities. Produced water can
be transported to commercial underground injection wells.
Louisiana requires a substantial degree of financial commitment from
commercial facility operators. Applicants for permits for commercial
facilities must provide evidence of sufficient financial capability to
ensure both adequate coverage of any liability incurred, and a guarantee
of funding for proper closing of the facility. A bond or irrevocable
letter of credit must be provided for closing, based on closing costs
estimated in the facility plan. Insurance against any liabilities which
may be incurred must be provided through certificates of insurance,
letters of credit, or other acceptable financial instruments. Required
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minimums are $1 million for commercial facilities operating open pits;
$500,000 for commercial facilities that store treat or dispose of
nonhazardous oilfield solids; $250,000 for commercial saltwater
underground injection/closed storage systems; and $100,000 for transfer
stations operated in conjunction with permitted commercial facilities.
Commercial facilities may use lined pits for temporary storage, not
permanent disposal, of nonhazardous oilfield wastes. Such pits must be
located on the site of the permitted treatment system, must not exceed
50,000 barrels capacity, and must have maximum hydraulic conductivity of
1 x 10" cm/sec.
Commercial land treatment facilities must be isolated from contact
with water supplies, and are subject to extensive and continuous
monitoring and sampling requirements. Limitations on concentrations and
other parameters are established as maximums at any time in the treatment
zone (a), at the time of closure in the treatment zone (b), and in
surface runoff water from the facility (c):
(a)
(b)
(c)
PH
Oil & Grease
EC
SAR
ESP
TSS
COD
Chloride
Arsenic
Barium
Cadmium
6.5 - 9
5%
10 mmhos/cm
12
15%
40 ppm
3,000 ppm
10 ppm
6.5 - 9
3%
10 mmhos/cm
12
15%
10 ppm
3,000 ppm
10 ppm
6.5 - 9
15 ppm
0.75 mmhos/cm
10
60 ppm
125 ppm
500 ppm
0.2 ppm
undetermined
0.05 ppm
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Chromium
Lead
Mercury
Selenium
Silver
Zinc
1,000 ppm
1,000 ppm
10 ppm
10 ppm
200 ppm
500 ppm
1,000 ppm
1,000 ppm
10 ppm
10 ppm
200 ppm
500 ppm
0.15 ppm
0.1 ppm
0.01 ppm
0.05 ppm
1 ppm
Commercial facilities may also receive permits to produce reusable
materials from nonhazardous oilfield waste. Such materials may be used
as daily cover in sanitary landfills, or as construction fill (subject to
case-by-case review by the Commissioner). The oil and grease and metals
leachate test limits are identical to those for leachate tests for
solidification (above); the ESP, SAR and pH limits are the same as those
for treatment zones at commercial land treatment facilities; EC is 8
mmhos/cm.
A complete manifest system to track the transportation and disposal
of wastes taken to offsite commercial facilities is enforced.
PI uggi ng/Abandonment
Wells must be plugged within 90 days of notice in "Inactive Well
Report" unless the operator submits a plan describing the well's future
use, and the well is then classified as having future utility.
When plugging, a cement plug of 100 feet must be placed above or
across the uppermost perforated interval. Where production casing was
not run or was removed, a cement plug shall run from 50 feet below to 50
feet above the shoe of the surface casing. If freshwater strata are not
protected by casing, a cement plug must extend from 100 feet below to 150
feet above the deepest freshwater stratum, and a plug shall be placed
from 50 feet below to 50 feet above the shoe of the surface casing. A
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30-foot plug must be placed at the top of the well. Additional plugs
must be placed to contain high pressure oil, gas, or water sands. In
wells completed with screen or perforated liners which cannot practically
be removed, a 100-foot cement plug must be placed with its bottom as near
as practical to the top of the liner or screen. Mud-laden fluids must
fill those portions of the well not filled with cement.
10
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References
Louisiana State Statutes 1950 30:204.
Interstate Oil Compact Commission, Oil and Gas Compact Bulletin, Volume
XLIV, No. 2, December 1985.
State of Louisiana Department of Natural Resources, Office of
Conservation, "Amendment to Statewide Order No. 29-B," January 20,
1986.
Wascom, Carroll, D., "Oilfield Pit Regulations - A First for the
Louisiana Oil and Gas Industry," May 30, 1986.
Personal Communications:
Lynn Wellman, Water Pollution Control Division, Office of Water
Resources, Department of Environmental Quality (504) 342-6363
11
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MARYLAND
Introduction
Maryland produced 20 million cubic feet of gas from 6 gas wells, and
no oil, in 1986.
State Regulatory Agencies
Two agencies regulate oil and gas activities in Maryland:
- Department of Natural Resources, Geological Survey
- Department of Health and Mental Hygiene, Office of Environmental
Programs
The Department of Natural Resources regulates oil handling, storage,
and transportation. It issues drilling permits and regulates site
erosion.
All wastewater regulation is managed by the Department of Health.
Section 6-104 of the public general laws of Maryland provides that a
person may not dispose of any product of a gas or oil well without a
permit issued by the Department. The Department has both NPDES
delegation and DIG program authority.
State Rules and Regulations
Drilling and Production
Drilling and production wastes are managed by the Department of
Health, Office of Environmental Programs. There is no differentiation
between pits that are associated with drilling or production activities.
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A pit may be lined with an impervious material such as clay or a
plastic to prevent groundwater pollution. Fluids introduced to lined
pits generally are transported to a brine disposal facility or to a
sewage treatment plant, or they may be transported out of State for
disposal purposes. There are no requirements on thickness or type of pit
liners. There is no manifest system associated with transporting gas
wastes unless such wastes are defined as hazardous.
Pits that are not lined must have a groundwater discharge permit
issued under Code of Maryland regulations. The requirements associated
with pit contents that would meet permit conditions for groundwater
discharge are determined on a site-by-site basis. If there is surface
discharge from a pit, an NPDES permit would be required.
Due to the absence of facilities, the State currently has neither
issued an NPDES permit for surface discharges nor a UIC permit for
underground injection. There is a groundwater discharge gas storage
extraction facility in the western part of the State that is permitted to
discharge about 1 million gallons per year. The permit requires that the
first of a series of ten ponds be lined. There are periodic monitoring
requirements for the ponds and in a nearby stream, but there are no
monitoring limits and no monitoring wells.
Offsite and Commercial Pits
The only offsite pit used in the State is the one in Western Maryland
described above. Some transported production fluids are received by this
facility.
Plugging/Abandonment
There are no specific requirements in the regulations relating to the
time within which a well must be plugged.
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Injection: Over half of produced waters in California are
reinjected, either for enhanced recovery or disposal. Authority for
management of Class II injection wells is delegated by EPA to the
Division of Oil and Gas. The Regional Water Quality Control Boards,
under a Memorandum of Understanding with the Division of Oil and Gas, may
comment on Class II injection well permits on matters which could affect
water quality, including degradation of ground/water.
On Bureau of Land Management leases, operators of Class II wells must
obtain permits from both the Division of Oil and Gas and BLM. Many of
the injection wells are for enhanced recovery, and therefore could
significantly affect BLM's royalty earnings from its leases. As a
result, BLM wants to maintain joint signatory authority on UIC permits.
BLM and the Division of Oil and Gas are in the process of trying to
develop a Memorandum of Understanding on joint permitting.
Injection wells, other than those injecting steam, air, or pipeline
quality gas, must be equipped with tubing and packer set immediately
above the approved zone of injection. Exceptions may be granted where
there is no evidence of freshwater-bearing strata, where more than one
string of casing is cemented below the base of freshwater, or where the
operator can demonstrate that freshwater and oil zones can be protected
without tubing and packer. The pressure in the well must not be
sufficient to fracture the zone of injection.
To obtain approval from the Division of Oil and Gas, operators must
file plans, geologic analyses, evaluations of the impact of the planned
well on other wells in the area, monitoring program, the source and
analysis of the water being injected, and analysis of water in the
injection zone. A new chemical analysis of the water being injected must
be filed whenever the source of the water is changed or as requested by
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When plugging, the well must be filled with mud, clay, or other
nonporous material from the bottom (or from a bridge 30 feet below the
lowest stratum) to 20 feet above the lowest oil, gas or water-bearing
stratum, at which point a cement plug should be placed. Similar filling
and cementing steps should be taken for each oil, gas or water stratum.
A plug should be anchored about 10 feet below the bottom of the largest
casing in the well, and the remainder of the well filled with nonporous
material to within 2 feet of the surface.
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References
Summary of State Statutes and Regulations for Oil and Gas Production.
1986. Interstate Oil and Gas Commission (June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil Compact
Commission (December).
Personal Communications:
Al Hooker, Department of Natural Resources, Bureau of Mines (301) 689-
4136.
Bob Creter and David Fluke, Department of Health, Office of
Environmental Protection (301) 791-4787.
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MICHIGAN
Introduction
Michigan produced 29,140,000 barrels of oil and 152,840 MMCF of gas
in 1985 from 1,380 flowing wells and 4,480 pumping wells. In 1984, the
State ranked twelfth in U.S. oil production and thirteenth in U.S. gas
production. Oil and gas production in Michigan peaked in 1980 and has
been on a slight decline for the past 5 years.
The first successful Michigan oil well was drilled in 1886. The
first oil and gas drilling permit was issued in 1927.
Regulatory Agencies
Five agencies regulate oil and gas activities in Michigan:
- Michigan Department of Natural Resources.
Michigan Department of Commerce, Public Service Commission
U.S. Forest Service.
- U.S. Bureau of Land Management.
U.S. Environmental Protection Agency.
The Michigan Oil and Gas Act of 1939 (PA 61) established the
Supervisor of Wells and designaed the Director of the Department of
Natural Resources to that office. The Director, as authorized, appointed
the Chief of the Geological Survey Division as the Assistant Supervisor
-------
of Wells to act on his behalf. The prime regulator of the oil and gas
industry is the Assistant Supervisor of Wells and herein shall be
referred to as the Supervisor. The Supervisor has authority to subpoena,
to establish well spacing requirements, to develop orders without
legislative interference, and to control disposal of solid and liquid
wastes from drilling. The Oil and Gas Act provides the Supervisor broad
authority to regulate the industry from "cradle to grave"; it stresses
"prevention of wastes" from exploration to well abandonment. The State
requires a bond, an environmental assessment, spacing minimums, and
approves of well construction design.
The Water Resources Commission Act of 1929 (PA 245) regulates
discharges to and the pollution of any waters of the State; it is under
Act 245 that National Pollution Discharge Elimination System (NPDES)
permits are issued. Michigan is an NPDES delegated State with such
permits issued by the Surface Water Quality Division of the Bureau of
Environmental Protection in the Department of Natural Resources. No
NPDES permits are issued for oil and gas wastes.
The Solid Waste Management Act of 1978 (PA 641) provides for the
licensing of solid waste disposal sites.
The State of Michigan does not require NPDES or landfill permits for
disposal of liquid or solid oil field drilling wastes; these activities
are regulated by the Supervisor of Wells. Other divisions of the
Department of Natural Resources provide assistance to the Geological
Survey Division in enforcing the Act by providing liaison with the
Attorney General and with county prosecutors for action by the local
courts through cooperative efforts of Department of Natural Resources law
enforcement conservation officers. Where a groundwater problem has been
-------
identified through investigation and monitoring by the Geological Survey
Division, and groundwater restoration is required, an NPDES permit by the
Water Quality Division is issued on the restored water.
The Air Quality Division of the Department of Natural Resources
regulates gaseous emissions to the atmosphere. The Michigan Public
Service Commission regulates the production of gas from dry natural gas
reservoirs and safety of gas pipe line construction.
When drilling occurs on Federal lands, Federal review of the drilling
applications depends on whether Federal ownership is restricted to
surface rights, or includes both surface and mineral rights. When only
surface rights are owned by the Federal government, a copy of the
drilling application is sent to the Federal agency involved, generally
the U.S. Forest Service. Two separate investigations then follow: one
by the Geological Survey, and one by the U.S. Forest Service, which
involves fish and wildlife, geological, and other Federal experts. A
Federal surface use permit then is issued. The drilling application is
not approved by the State until all reviews have been completed and
pertinent comments made a part of permit conditions. When both surface
and mineral rights are Federally owned, a copy of the drilling
application is sent to both the U.S. Forest Service and Bureau of Land
Management.
The U.S. Environmental Protection Agency administers the UIC program
for the State (40 CFR 147.1151)
State Rules and Regulations
Dri11 ing: Pit Construction/Site Management Requirements. According
to Instruction 1-84 (effective February 1, 1985) of the Supervisor of
Wells, liners are required for mud pits when drilling with saltwater
-------
based drilling fluids, or when drilling through salt formations or brine-
containing formations. While case-by-case exceptions to the requirement
for lined drilling pits may, in principle, be approved in cases where a
well is to be drilled which will only encounter fresh water (as in the
southern part of the peninsula), such an exception is rarely requested.
Liners for mud pits must be of an impervious material that will meet
or exceed the specifications for 20 mil virgin PVC. Liners of other than
20 mil virgin PVC must be approved by the Supervisor. Liners must be
installed in a manner which prevents vertical and lateral leakage, and
must be one piece or with factory-installed seams. Mud pits may not be
built where the groundwater table is observed at the depth of the
proposed excavation. In such cases steel tanks are used and the drilling
muds disposed of at an approved offsite location.
Instruction 1-84 restricts the use of mud pits to "drilling muds,
drilling fluids, cuttings, native soils, cementing materials and/or
approved pit stiffening materials." No salt cuttings from drilling may
be released to the pit as solids; they must be screened out and dissolved
before being released (via a closed system) to the pit.
Instruction 1-84 also requires that cellars be sealed, and rat holes
and mouse holes equipped with a closed-end steel liner or otherwise
sealed or cased in such a manner that all fluids entering the cellar, rat
hole and/or mouse hole shall not be released to the ground but shall be
discharged to steel tanks, the lined reserve pit, or the mud circulation
system. Aprons of 20 mil virgin PVC or other equivalent material shall
be installed under steel mud tanks and overlapping the mud pit apron, and
in ditches or under pipes used for brine conveyance from cellars to pits
or to steel mud tanks.
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Pit Closure: At closure, all free liquids above the solids in the
mud pits shall be removed to the maximum extent possible and either
reused or disposed. The remaining mud pit solids may be required to be
stiffened (mixed with earthen materials). In any event the residue is
encapsulated and buried on site or removed to an approved waste disposal
site. For on-site disposal the edges of the pit liner must be folded
over the pit, and a separate piece of 10 mil virgin PVC used to entirely
encapsulate the pit. The top of the cover must be buried at least 4 feet
below grade. The Supervisor may require additional measures under
special circumstances.
For abandoned pits, or pits used prior to Special Order 1-81 issued
in 1981 and not meeting its specifications, no action is taken unless a
contamination problem has been detected. When a potential contamination
problem exists, the site is investigated by the Survey's groundwater
unit. If it can be shown that an identifiable entity is responsible,
damages may be sought administratively or through the courts.
Pisposal: Free liquids from the mud pits must be pumped off prior to
encapsulation, either for disposal or for use in the drilling of
additional wells. Fluids may be disposed in Class II injection wells.
Two additional options are specified in Special Order 1-85. The
Supervisor may authorize disposal of fluids on-site to dry holes as part
of plugging operations. Under rare conditions, where production casing
is run, fluids generated during drilling of the well may be injected in
the annular space. In both cases, drilling fluids must be injected in
permeable formations isolated below fresh water horizons.
Prior to Special Order 1-85, pit fluids were allowed to be spread on
roads for dust and ice control. A 1983 estimate showed that 22 million
of the 28 million gallons of pit fluids generated during the year were
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spread on roads. Special Order 1-85 prohibited use of pit brines for ice
control on March 29, 1985, and prohibited their use for dust control as
of September 1, 1985.
Offsite disposal in approved lined landfills with leachate collection
systems is also permitted.
Produced Fluids
Injection: Over 90% of Michigan's produced brines are now disposed
of by injection into Class II wells. Such wells must have a surface
string of casing which is cemented and completely isolates the fresh
water aquifers from the down hole disposal zone.
The wells must be "cased and sealed to prevent the loss or injection
of brine into any unapproved formation." Wells must be equipped with
tubing and packer. Since Michigan does not have delegated UIC authority,
EPA's Region V directly implements the mechanical integrity test
program. Wells are required to meet a standard pressure test of 300 psi
for 30 minutes, with 3% allowable bleed-off.
Annular disposal of produced brines is prohibited. Although
exceptions are technically allowed under the regulations, none has ever
been requested.
Surface Disposal: Produced brines were formerly used for both ice
and dust control in Michigan. Special Order 1-85, issued on March 29,
1985, immediately banned the use of brine for ice control. The use of
brine for dust control may continue through September 12, 1987 (provided
the brines meet specifications for benzene, toluene, and xylene
content). Annual one year extensions may be granted that would allow
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continued use of brine for dust control. Such one year extensions may
continue until a 3 year DNR environmental impact study has been
completed. The decision to whether to allow continued road application
of brine will be based on the results of this study.
Offsite Facilities Disposal
Solid drilling wastes may be disposed of in an approved, licensed
solid waste landfill, with the agreement of the landfill operator, where
the landfill is lined and has a leachate collection system, a groundwater
monitoring system, and a treatment process prior to the discharge of
waste leachate.
Road disposal of produced brines remains temporarily available for
dust control; producers may provide brine to a hauler if the hauler can
verify in writing the authorization to receive brines on behalf of a
governmental unit.
Plugging Abandonment
Plugging operations must commence within 60 days after completion as
a dry hole, or within a year after cessation of production. Extensions
may be granted by the Supervisor if there are sufficient reasons for
retaining the well.
Oil, gas, brine and fresh water shall be confined to the strata in
which they occur by use of muds, cement, or other suitable materials;
both the materials and methods of placement must be specified and
approved by the Supervisor. The surface pipe is abandoned with the hole
and must be cut off below plow depth and sealed with a cement plug or
other approved material.
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References
Crabtree, Allen F. 1985. "Drilling Mud and Brine Waste Disposal in
Michigan." Paper presented at the Reclamation Review Technical
Advisory Committee Seminar/Workshop on Gel and Saline Based Drilling
Wastes, Edmonton, Alberta, Canada, April 24, 1985.
Supervisor of Mineral Wells Instruction 1-84. "Use of Liners in Earthen
Drilling Pits, Sealing of Cellars, Rate Holes, Mouse Holes and other
Procedures to Protect Ground Waters," effective February 1, 1985.
Order of the Supervisor of Wells, Special Order 1-85, dated March
29, 1985.
Summary of State Statutes and RFqulations for Oil and Gas Production.
1986. Interstate Oil and Gas Commission (June).
The Oil and Gas_.Compact Bulletin. 1935. Interstate Oil Compact
Commission (December).
Debrabander, S. 1985. Letter Communication to EPA. Geological Survey
Division, Michigan Department of Natural Resources.
Michigan Meeting Report. 1985. Proceedings of the Onshore Oil and Gas
Workshop. U.S. Environmental Protection Agency, Washington, D.C.
(March 26-27 in Atlanta, GA).
Personal Communications:
Bill Shaw, DNR Office of Water Quality (517) 373-8088.
Steve Debrabander, DNR Geological Survey Division (517) 334-6976.
Rex Tefertiller, Permits, Geological Survey Division (517) 334-6974.
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MISSISSIPPI
Introduction
Mississippi produced 31,879,000 barrels of oil in 1984 from 3,569 oil
q
wells; 210 x 10 cubic feet of gas were produced from 715 gas wells.
State Regulatory Agencies
Four agencies regulate the oil and gas activity in Mississippi:
- State Oil and Gas Board
- Mississippi Department of Natural Resources, Bureau of Pollution
Control
Department of Wildlife Conservation
- U.S. Environmental Protection Agency, Region IV.
The State Oil and Gas Board regulates the oil and gas industry "to
prevent the pollution of freshwater supplies by oil, gas or saltwater"
and to promote, encourage, and foster the oil and gas industry (Section
53-1-17, State Statutes). The Oil and Gas Board does not have UIC
program authority.
The Department of Natural Resources, Bureau of Pollution Control, is
responsible for the investigation of water pollution and for the issuance
of NPDES permits. No NPDES permits are issued for drilling fluids,
completion fluids, workover fluids, or produced brines generated by the
onshore oil and gas industry.
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The Department of Wildlife Conservation is responsible for the
maintenance of fish and wildlife within the State.
The U.S. Environmental Protection Agency, Region IV, issues UIC
program Class II injection well permits for Mississippi. In this
activity area, the State Oil and Gas Board maintains a separate well
injection permitting program; a well operator must obtain an injection
permit both from the State and Federal Governments.
A 1982 memorandum of Agreement among the Department of Natural
Resources, Department of Wildlife Conservation, and the State Oil and Gas
Board coordinates the activities of the three State agencies related to
the oil and gas industry. The Agreement ensures that the Mississippi
Commission on Wildlife Conservation has an opportunity to review the
drill plan, as drilling may impact the sensitive environmental nature of
the State's wetland resources. The Agreement further allows for
suspension of a lessee's operations by the Oil and Gas Board where any
signatory agency determines such operations to be in violation of
applicable laws or regulations.
State Rules and Regulations
Drilling
The use of drilling reserve pits, or mud pits, does not require a
special permit; the permit to drill constitutes the permit for the
drilling reserve pit. Reserve pits must be constructed to prevent
pollution of surface or subsurface fresh waters. The only specific
construction requirements in the regulations are that the pit must be
protected from surface waters by dikes and drainage ditches, and that no
siphons or openings may be placed in the walls or dikes that would permit
contents of the pit to escape.
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The reserve pit must be emptied of fluids, backfilled and compacted
within three months of the completion of drilling operations. Exceptions
may be granted if warranted, and the reserve pits may be used as test
pits, with agreement of the Board's field representative, if they meet
the conditions for well test pits.
When closing the reserve pit, there are several options for disposing
of the drilling muds. Where the well is a dry hole, the muds may be
pumped back into the hole before plugging and abandonment, provided the
surface casing has been set to a point below the base of the USDW. They
may be landfarmed if they will "not . . . cause contamination of soils."
The muds may be hauled to a commercial disposal facility designed to
handle drilling muds. Or the muds may be treated in the pit with
flocculants to aid in precipitation, coagulation and sedimentation. The
supernatant water is then sampled in place to determine that it does not
exceed the following limits established by the Department of Natural
Resources in its "Reserve Pit Discharge Policy:"
Chlorides - 500 mg/1
pH - 6-9
Suspended solids - 100 mg/1
Specific conductance - 1000 umhos/cm
COD - 250 mg/1
Zinc - 5 mg/1
Chromium - 0.5 mg/1
Phenol - 0.1 mg/1
If the fluids meet this limit, they may be discharged. These
discharges are considered to be part of the policy covered by the
drilling permit, and do not require a separate discharge permit. The Oil
and Gas Board is in the process of incorporating these limits formally
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into their pit regulations (in Rule 63, Section III.E.9). After the
discharge, the dewatered muds are covered in place and the pit is closed
as noted above.
Production
Pits: The regulations of the State Oil and Gas Board contain a
provision, now a decade old, requiring that earthen pits "be phased out
and discontinued, except as hereinafter provided." The regulations
further specify limited conditions under which specific types of pits may
be used, and the requirements which must be met in their construction and
management. When permits are issued for pits (other than reserve pits),
the longest permit period is two years. In addition to reserve pits,
permits are issued for four types of pits:
Temporary saltwater storage pits: The Board's regulations stipulate
that this type of pit will be "permitted only if no other means of
storing or disposing of saltwater is available" (e.g., in remote areas).
When permitted, these pits must be lined with an impervious material,
must have no siphons or openings in the walls or dikes, and must be
protected from surface waters by dikes and drainage ditches. Only
produced waters should be placed in the pit (after separation), and fluid
levels should never rise to within one foot of the top.
Emergency pits: Produced water should never intentionally be placed
in such pits, but only in the event of an emergency such as a saltwater
disposal or water injection system failure. A field representative of
the Board must be notified within 72 hours. Within two weeks after the
emergency period, the pit must be emptied so as to contain no more than
two feet of water. The fluid level must never rise to within one foot of
the top of the pit; there must be no siphons or openings in the walls of
the pit; and dikes and drainage ditches should be used to protect the pit
from surface water.
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Burn pits: This may be used to burn tank bottoms and other refuse
products, the burn pit must be place at least 100 feet away from the
facilities for storing and/or treating the oil or gas, must be
constructed to prevent escape of contents or ingress of surface water,
must never have fluid levels closer than two feet to the top of the pit
walls, and must not be used for noncombustible fluids (except as these
are naturally associate with the combustible wastes).
Well test pits: These are small pits used in testing producing wells
for short periods of time. Well test pits must be placed at least 100
feet away from the facilities for storing and/or treating the oil or gas,
must be constructed to prevent escape of contents or ingress of surface
water, and must maintain a 2-foot freeboard.
When any of these pits is abandoned, it must be empties of fluids,
backfilled, leveled and compacted.
There are areas where even this use of pits is prohibited. In areas
where public water supplies, or recreational, wildlife, or fishery
resources would be adversely affected (e.g., coastal wetlands),
"impervious containers shall be used . . . [and] the contents removed and
properly disposed of within ninety days following usage."
Injection: Annular disposal of produced saltwater is permitted. The
Board's policy is that disposal in the annulus is allowed only where the
operator can make an absolute showing of no endangerment to the
environment or fresh groundwater, and can demonstrate that there is no
economic alternative. The applicant is required to provide the Board an
economic study of the well and of the economics of alternative methods of
disposal. Generally, the economic showing could only be made in a
setting where there was no well which could be converted to an injection
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well; this would likely be in remote, small fields. The applicant would
be required to provide the Board with a radioactive tracer survey to
prove that the injected fluid was not leading through the casing and was
entering the correct zone.
As note above, Mississippi does not have delegated authority for
regulation Class II wells. But the state issues permits for all
injection wells, and operators must obtain permits both from EPA and the
State Oil and Gas Board. The state regulations require information on
wells within 1/4 mile of the proposed injection well, injection pressure
limited to 75% of estimated fracture pressure of the target formation,
injection through tubing and packer set no more than 150 feet above the
injection zone, and mechanical integrity tests before initial injection
and every five years thereafter. Test pressures are required to be at
the greater of maximum authorized injection pressure or 300 psi (for a
new well), with a ceiling of 500 psi (for a converted well).
Offsite and Commercial Pits
Except for two commercial pits in southern Mississippi, both of which
are phasing down, use is not made of offsite and commercial pits within
the state.
Plugging/Abandonment
All wells which are drilled and found dry must be plugged within 120
days, unless an extension is granted by the Supervisor. A production or
service well which ceases to operate must be listed, after six months, on
the Inactive Well Status Report. The operator must classify the well as
having future utility or having no future utility. If the "future
utility" designation is accepted, no further action is necessary. If the
well is designated as having no future utility, it must be plugged within
120 days.
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When plugging a well in which production casing has been set, if the
production casing is not to be pulled, a cement or bridging plug must be
placed near the bottom of the casing string to protect any producible
pool. If the production casing is to be pulled, a cement or bridge plug
should be placed at the bottom of the production string, a 100-foot
cement plug about 50 feet below all freshwater-bearing strata, additional
plugs to protect freshwater sands, a 100-foot plug at the bottom of the
surface pipe, and a plug at the surface. The remainder of the hole must
be filled with mud.
When plugging an uncased hole, 100-foot plugs must be placed to
protect each producible pool. Additionally, 100-foot plugs must be
placed approximately 50 feet below all fresh water bearing strata, and at
the bottom of the surface pipe. A plug must be placed at the surface of
the ground in a manner so as not to interfere with soil cultivation.
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References
Summary of State Statutes and Regulations for Oil and Gas Production.
1986. Interstate Oil and Gas Commission (June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil
Compact Commission (December).
Mississippi Meeting Report. 1985. Proceedings of the Onshore Oil
and Gas Workshop. U.S. Environmental Protection Agency,
Washington, D.C. (March 26-27 in Atlanta, GA).
Statutes and Statewide Rules and Regulations, State of Mississippi,
State Oil and Gas Board, Revised 7/1/86.
Personal Communication:
Richard Lewis, Mississippi Oil and Gas Board
(601) 359-3725.
Jerry Cain, Mississippi Department of Natural
Resources, Bureau of Pollution Control (601) 961-5073.
Richard Ball, Mississippi Department of Natural
Resources, Bureau of Pollution Control (601) 961-5171.
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MISSOURI
Introduction
Missouri produced 131,000 barrels of oil from 557 oil wells in 1984.
There is no commercial gas production. The State has 9 evaporation pits
and 229 injection wells. In 1984, Missouri had a total of 2.6 million
barrels of produced waters, most of which were injected. The reason for
injection exceeding production is that two major steam operations import
fresh water to steam out the oil, which results in an increased quantity
of injectable fluids. Missouri has not had commercial gas production
since 1977.
State Regulatory Agencies
Three agencies regulate oil and gas activities in Missouri:
- Department of Natural Resources, Division of Geology and Land
Survey
U.S. Bureau of Land Management
The State Oil and Gas Council was formed by Rule 10 CSR 50-1.010 and
is composed of the executive heads of the Division of Geology and Land
Survey, Division of Commerce and Industrial Development, Missouri Public
Service Commission, Clean Water Commission, the University of Missouri,
and two persons knowledgeable of the oil and gas industry, appointed by
the Governor with the advice and consent of the Senate. The State
Geologist who serves as Director of the Division of Geology and Land
Survey, is charged with the duty of enforcing the rules, regulations, and
orders of the Council. The State has primacy for UIC program Class II
wells.
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Federal lands in Missouri are confined to U.S. Air Force bases, but
there is drilling on these lands. When a request for a permit to drill
is received, the Bureau of Land Management prepares the draft permit,
which is issued by the State Oil and Gas Council.
The Department of Natural Resources, Division of Environmental
Quality becomes involved only when there is a breach of a pit dike, and a
spill of fluids occurs. Appropriate action under the Division of
Environmental Quality regulations then occurs.
State Rules and Regulations
Drilling
Rule 10 CSR 50-2.040 provides requirements during the drilling of
wells to prevent contamination of either surface or underground fresh
water resources. There is a bonding requirement before commencing oil or
gas drilling operations, and all wells must be plugged when abandoned.
There are no regulations related to drill pits. Drill pits are not
lined. When pit muds dry, the muds are buried on site.
Produced Waters
There are no regulations related to construction of evaporation -
percolation pits for produced waters. About 32,370 barrels of produced
waters were put in such pits in 1984.
The remainder of produced waters are injected into Class II wells for
disposal or enhanced recovery. Injection wells must be completed with
strings of casing properly cemented at sufficient depths to protect any
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fresh water strata. The specific casing and cementing requirements will
be based on the depth to the base of lowest underground drinking water
source, the nature of the fluids being injected, and the hydraulic
relationship between the injection zone and the base of the underground
source of drinking water. Maximum injection pressure must be established
by the state geologist to avoid fracturing the confining zone.
All injection wells must be tested for mechanical integrity before
initiating injection, and at least every 5 years thereafter. Procedures
may include a pressure test, monitoring of annulus pressure after an
initial pressure test, or other methods deemed effective by the state
geologist.
Offsite Disposal
Some of the produced fluid is trucked to other injection sites.
There is no manifest required for the transportation of produced brine.
Plugging/Abandonment
Notification is required within 90 days after operations cease, and
the Council may require temporary plugging to prevent pollution of
freshwater strata. After 6 months, the operator must plug and abandon
the well, unless granted an additional 6 month extension for good cause.
Further 6-month extensions may be granted, up to a limit of two years.
Plugging must assure that all fluids remain in their original
strata. Cement plugs must be placed from the bottom of any oil or gas
stratum to at least 25 feet above the top of that stratum. Appropriate
means must be taken to prevent migration of surface water into a plugged
well. Casing must be cut off below plow depth.
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References
Summary of State Statutes and Regulations for Oil and Gas Production.
1986. Interstate Oil and Gas Commission (June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil Compact
Commission (December).
Missouri Meeting Report. 1985. Proceedings of the Onshore Oil and Gas
State/Federal Western Workshop. U.S. Environmental Protection
Agency, Washington, D.C. (December 1985).
Rules and Regulations of Missouri Oil and Gas Council, June 1985.
Personal Communications:
Kenneth Deason, Missouri Oil and Gas Council (314) 364-1752.
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MONTANA
Introduction
Montana produced 20,079,819 barrels of oil and 52,981,382 billion
cubic feet of gas in 1984. Production is from 4,665 oil wells and 2,152
gas wells. A total of 622 wells were drilled for oil and gas in 1985.
About 320,000 barrels of brine per day are produced from the
approximately 1,600 full producing oil wells. The remaining stripper
wells produce about 40 barrels each of brine per day.
Responsible Regulatory Agencies
Four agencies regulate oil and gas activities in Montana:
- Montana Department of Natural Resources and Conservation, Oil and
Gas Conservation Division
- Montana Department of Health and Environmental Sciences, Water
Quality Bureau
- U.S. Environmental Protection Agency, Region VIII
- U.S. Bureau of Land Management.
the Oil and Gas Conservation Division issues drilling permits and
regulates the oil and gas industry in Montana. There is a compliance
bond. Montana does not have primacy for the UIC program, but the Board
of Oil and Gas Conservation is planning to negotiate with EPA on
assumption of privacy..
The Montana Department of health and Environmental Sciences, Water
Quality Bureau, controls water quality issues, the Bureau has primacy
for the issuance of NPDES permits.
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Region VIII of the Environmental Protection Agency issues UIC permits
for the injection of brines in Montana.
The Bureau of Land Management uses their own form for drilling
permits; thus, a driller must obtain a State as well as a Federal permit
to drill for oil or gas on Federal lands. The Board of Oil and Gas
Conservation has a cooperative agreement with the Bureau of Land
Management concerning spacing of wells and field rules on Federal lands.
BLM issued the permits to drill on Indian lands. The Board has no
jurisdiction over Indian lands but does maintain files on those wells if
the operation chooses to file the permit requests and reports that would
be required on other wells.
State Rules and Regulations
Drilling
Permits are not required for drilling pits. The regulations of the
Oil and Gas Conservation Division (36.22.1005) require the operator to
"contain and dispose" of drilling operation wastes either by removal from
the site or burial at least three feet below the surface of the land.
further, the operator is required to "construct his reserve pit in a
manner adequate to prevent undue harm to the soil or natural water in the
area. When a salt base mud system is used as the drilling medium, the
reserve pit shall be sealed when necessary to prevent seepage."
The lining requirement for reserve pits is decided case by case,
based upon soil composition, slope, drilling, fluids, and proximity to
water sources. Fluids may be removed from reserve pits by several
methods. One method is to remove fluids by truck and haul them to
another drill site or disposal facility. No manifest is required for
transporting fluids. Another method is to allow fluids, other than oil,
to remain in a reserve pit for up to a year for evaporation.
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Alternatively, the fluids may be treated chemically so that they may be
used for beneficial purposes. After the fluids have been removed, the
remaining solids are left to dry before backfilling. If a plastic liner
has been used, it is folded into and buried in the reserve pit.
Produced Waters
Full producing wells in Montana produce approximately 200 barrels per
day of brine; strippers about 40 barrels per day. Most produced water is
reinjected, but some is disposed of by evaporation, and a small amount by
discharge for beneficial use.
Rule 36.22.1227 of the Board of Oil and Gas Conservation states that
salt or brackish water may be disposed of by evaporation when impounded
in excavated earthen pits which may only be used for such purpose when
the pit is underlaid by tight soil such as heavy clay or hardpan. At no
time shall salt or brackish water impounded in earthen pits be allowed to
escape over adjacent lands or into streams.
Rule 36.22.1228 allows salt water to be injected into the stratum
from which produced or into other proven saltwater-bearing strata.
Injection is also permitted to producing formations to enhance production
of oil and gas. The UIC program, however, is administered by EPA -
Region VIII.
NPDES discharge permits are issued by the Water Quality Bureau of the
Montana Department of Health and Environmental Sciences for 18 facilities
under the beneficial use provision of the wildlife and agricultural use
subcategory with a total permitted discharge of 0.6 million gallons per
day. Of those issued, only about two of the permitted facilities
discharge. Discharges are to a closed basin in the northern part of the
State. Discharge limits include total dissolved solids of less than
1,000 mg/1 and an oil and grease of 15 mg/1 absolute with an average of
10 mg/1. Other discharge limits including phenols and metals are imposed.
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PI ugging/Abandonment
Once a well is no longer being used for the purpose for which it was
drilled, it should be plugged. But a well can remain idle on a field
with other producing wells, while being held for possible future use
(unless causing damage to oil, gas, or freshwater strata). But at the
point that other wells in that field cease to produce because of
depletion of the reservoirs, the operator must commence drilling and
abandonment operations within 90 days. Before plugging work begins, the
operator must submit forms laying out the specific plans for plugging.
After approval by the Petroleum Engineer, plugging may proceed.
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References
Summary of State Statutes and Regulations for Oil and Gas
Production. 1986. Interstate Oil and Gas Commission (June)
The Oil and Gas Compact Bulletin. 1985. Interstate Oil
Compact Commission (December).
Personal Communications:
Charles Maio, Administrator, Board of Oil and Gas
(406) 656-0040.
Abe Horpestad, Water Quality Bureau (406) 444-2459.
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NEBRASKA
Introduction
Nebraska produces 6,470,000 barrels of oil and 2,347 MM cubic feet
of gas each year. Production is from 2.072 oil wells and 18 gas wells.
Most of the State production is in two areas: the five county area in
the Denver Bsin, and Red Willow and Hitchcock Counties. Strippers
account for about 85 percent of the State production.
Regulatory Agencies
Three agencies regulate oil and gas activity in Nebraska:
- Nebraska Oil and Gas Conservation Commission
- Nebraska Department of Environmental Control
- U.S. Bureau of Land Management
The Nebraska Oil and Gas Conservation Commission regulates industry
practices and procedures with regard to construction, location, and
operation of onsite drilling. The Commission issues permits for oil and
gas drilling and UIC Class II wells. The Commission has three members
who are appointed by the Governor. At least one member must have
experience in oil or gas production.
Nebraska is an NPDES - delegated State. The Nebraska Deparetment
of Environmental Control issues all NPDES permits and regulates all other
classes of UIC wells.
The Bureau of Land Management has jurisdiction over drilling and
production on Federal lands. The Bureau is addressed in a separate
section.
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State Rules and Regulations/Drilling
When drilling is complete, the supernatant in mud pits is allowed to
evaporate. The muds in use are generally fresh water gels. After the mud
pit has dried, the residues are land spread, and the pit is backfilled.
Production
Under Rule 3.002, "No salt water, brackish water, or other water
unfit for domestic, livestock, irrigation, or general use shall be
allowed to flow over the surface or into any stream or underground fresh
water zone." Brine may be disposed by evaporation pits, road spraying,
or injection.
Pits:
Generally, evaporation pits are used in the panhandle, where net
evaporation is as high as 60 inches annually. Under Commission Rule
3.022, retaining pits must be permitted. The Commission approves or
disapproves the pit upon receipt of the application. The pits are
required to be lined or constructed with impermeable material when the
underlying soil conditions would permit seepage to reach subsurface fresh
water zones. They must have the capacity for at least three times the
average daily fluid influx into the facility.
This rule does not apply to burn pits or emergency pits. Burn pits
are required to be a safe distance from any other structure, and must be
constructed to prevent any materials from escaping the pit, or surface
water from entering the pit. Open pit storage of oil is not allowed
unless during an emergency or by special permission from the Director of
the Commission.
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Road Spraying:
Road spraying of brine is considered on a case-by-case basis. When
allowed, spraying must be done with a spreader bar and in such a way as
to prevent runoff.
Injection:
In southwest Nebraska, most brines are reinjected, either into
disposal or enhanced recovery wells. There are about 500 Class II wells
in Nebraska, and most are used for enhanced recovery. Injection wells
must be completed, maintained and operated to confine injected fluids to
approved formations, and to prevent pollution to fresh water or damage to
sources of oil or gas. Information must be submitted with injection well
applications on other wells within a half-mile of the proposed injection
well, as well as a demonstration that injection will not lead to vertical
fractures allowing injection or formation fluids to enter fresh water
strata. Injection must be through adequate casing or casing and tubing.
Mechanical integrity tests must be at the greater of 125% of the maximum
authorized injection pressure or 300 psi. (Alternately, for wells without
tubing and packer, the operator shall record actual injection pressure
weekly, and report it monthly).
PIugg i ng/Abandonment
There are no specific time requirements related to plugging of a
well. State policy is to encourage operators not to permanently plug
wells with any further potential for secondary recovery operations.The
operator must notify the Director before plugging of the specific plans
for plugging, but the regulations make no specific mention of
requirements for positive approval or witnessing of plugging. The well
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must be plugged with "mud-laden fluid, cement, mechanical plug, or some
other suitable material" so as to prevent migration of oil, gas, or water
from the strata of origin.
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References
Nebraska Oil and Gas Conservation Commission, Rules and Regulations,
December 1985.
The Oil and Gas Compact Bulletin. 1985. Interstate Oil Compact
Commission (December).
Coubrough, Rob, State Regulatory Information Submitted in 1985.
Nebraska Meeting Report. 1985. Proceedings of the Onshore Oil and Gas
State/Federal Western Workshop. U.S. EPA, Washington, D.C.
(December 1985).
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NEVADA
Introduction
During 1984, Nevada produced 1,953,000 barrels of oil from a total of
34 oil wells. There are no producing gas wells in this State. All of
these wells are on Federal land and most use reserve pits to evaporate
drilling fluids. Reinjection is applied to produced waters. Between
200,000 and 500,000 barrels per year of brine are produced in Nevada's
major production area (the Carbonate Belt). Reinjection of these waters
is accomplished collectively into some 5-9 injection wells. No produced
waters are discharged under the beneficial use subcategory. Nevada has
NPDES primary, but is currently negotiating for UIC primacy.
Regulatory Agencies
Four agencies regulate the oil activity in Nevada:
- Nevada Department of Minerals
- Nevada Department of Conservation and Natural Resources, Division
of Environmental Protection
- Bureau of Land Management
- EPA, Region IX, Underground Injection Section
The Nevada Department of Minerals, created as a single State
department by the State legislature in 1983, regulates the industry on
the State level with respect to construction, location, and operation of
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onsite drilling and production, and issues all operation permits.
Operators must obtain permits both from the Department and from BLM.
The Division of Environmental Protection in the Department of
Conservation and Natural Resources has adopted Underground Injection
Control Regulations governing the use of all types of injection wells.
As of April, 1987 the U.S. Environmental Protection Agency had not yet
granted delegation of the program to the State. However, it is expected
that by October, 1987 the State will be administering the program.
The Division also regulates the disposal of solid waste and
supervises the cleanup of any major spills of any pollutants. The
discharge of any produced brines during the exploration and testing phase
is also regulated. Depending on the quality of the discharge waters and
the nearby surface and ground waters, discharge to the surface may or may
not be allowed.
The Division has jurisdiction over all waters of the State, both
surface and ground waters, and regulates activities on State and Federal
lands.
The Bureau of Land Management has jurisdiction over drilling and
production on Federal lands. For such drilling, the Bureau of Land
Management handles all Applications to Drill. The Bureau requires
extensive environmental documentation, including environmental
assessments, and develops environmental impact statements for drilling on
Federal land-.
U.S. EPA - Region IX regulates the underground injection of wastes
from oil wells under the UIC program. The applicable regulations are
found in 40CFR 144 and 146. Operators must obtain permits both from U.S.
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EPA and from the Division of Environmental Protection. Upon delegation
of the UIC program to the State, EPA will no longer issue permits.
Further discussion of BLM and U.S. EPA UIC regulations can be found
in the section on Federal regulations.
State Rules and Regulations
The Regulations and Rules of Practice and Procedures under Chapter
522 of the Nevada Revised Statutes of the Oil and Gas Conservation Law
were adopted by the Department of Minerals on December 20, 1979. Section
200.1 of these rules states that, "Fresh water must be protected from
pollution whether in drilling, plugging or producing oil or gas or in
disposing of salt water already produced." The regulations govern the
"drilling, safety, casing, production, abandoning and plugging of
wells." The regulations do not include a provision for allowing or
disallowing discharges nor is their mention of a discharge allowance.
Section 308, however, states that all excavations must be drained and
filled and the surface leveled so as to leave the site as near to the
condition encountered when operations were commenced as practicable.
Section 407 further states that "Oil or oil field wastes may not be
stored or retained in unlined pits in the ground or open receptacles
except with the approval of the Division." Section 600.1 states that,
"The underground disposal of salt water, brackish water, or other unfit
for domestic, livestock, irrigation or other use, is permitted only upon
approval of the Administrator."
Plugging is required for wells with production casing which have not
been operated for a year, and for wells without production casing in
which drilling operations have ceased for 30 days. Six-month extensions
may be granted for good cause. Plugging is required with cement and heavy
mud to seal hydrocarbon or water formations.
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References
Proceedings of the Onshore Oil and Gas State/Federal Western Workshop.
Summary of presentation given by Scott McDaniel, Nevada Department of
Minerals. December 1985.
Nevada Department of Conservation and Natural Resources, Division of
Mineral Resources. Regulations and Rules of Practice and
Procedures. Chapter 522. December 20, 1979.
Personal Communications:
Cathy Loomis, Engineering Technician, Nevada Department of Minerals,
September 26, 1986 (702) 885-5050.
Dan Gross, Division of Environmental Protection, Department of
Conservation and Natural Resources, September 26, 1986 (702) 885-4670
Ellis Hammett, Permit Processor, Nevada Bureau of Land Management,
September 26, 1986 (702) 784-5123.
Nate Lau, Director, UIC Division, EPA Region IX, September 26, 1986
(415) 974-0893.
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NEW MEXICO
Introduction
New Mexico produced 78,500,000 barrels of oil and 893.3 x 109 cubic
feet of gas in 1985, ranking fourth in U.S. gas production and eighth in
U.S. oil production. Production is from 21,986 oil wells and 18,308 gas
wells. Twenty percent of oil production is from the stripper well
category.
State Regulatory Agencies
The following agencies have responsibilities for regulating oil and
gas activities in New Mexico:
- New Mexico Energy and Minerals Department, Oil Conservation
Division
New Mexico Oil Conservation Commission
- New Mexico Water Quality Control Commission
- U.S. Bureau of Land Management
The Oil Conservation Division of the Energy and Minerals Department
is responsible for regulating the oil and gas industry. It regulates
exploration and drilling, production and refining with respect to
protection of water quality.
The Oil Conservation Commission has "concurrent jurisdiction and
authority with the division to the extent necessary for the commission to
perform its duties as required by law." The three members of the
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Commission are the Commissioner of Public Lands, the Director of the Oil
Conservation Division, and the State Geologist. The Commission serves as
an appeal body for permit applicants who object to decisions of the
Division; the applicant must seek review from the Commission before going
to court. The Commission may also initiate rules and orders to be
administered by the Division, as in the case of Orders R-3221 and R-7940,
which restrict surface discharges of produced water in areas of the state
with vulnerable aquifers (see below).
New Mexico has relatively few statewide specific regulations relating
to fresh water protection from oil and gas discharges because of the
diversity of the climate, diversity of the geology, and diversity of the
quantity and type of waste that is produced. Statewide rules require
that all fresh surface and ground waters be protected from contamination.
Statewide UIC rules have been adopted and there is a plugging bond
requirement that endures until well abandonment has been approved by the
Division.
But the Oil and Gas Act also allows the adoption of special rules or
orders tailored to the particular characteristics of a production area.
As a result, rules controlling specific disposal practices in differing
geographic areas of the state have been adopted.
The U.S. EPA has the responsibility for NPDES permitting in New
Mexico; however, the Environmental Improvement Division of the New Mexico
Health and Environment Department certifies those permits. No NPDES
permits have been issued for the New Mexico oil and gas industry drilling
and production facilities.
The Water Quality Control Commission (WQCC) is an interagency
commission with members from several state government agencies, including
the Environmental Improvement Division and the Oil Conservation
Commission. The WQCC is responsible for the development of water quality
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control standards and water pollution regulations. It delegates the
administration of the regulations it develops to constituent agencies.
WQCC is prohibited from taking any action which would interfere with the
exclusive authority of the Oil Conservation Commission over all persons
and things necessary to prevent water pollution as a result of oil or gas
operations.
The Oil Conservation Division administers WQCC regulations at oil
refineries and natural gas processing facilities. The Environmental
Improvement Division administers and enforces WQCC regulations at brine
manufacturing operations, including all brine production wells, holding
ponds and tanks. The Oil Conservation Division regulates brine injection
through its Class II UIC program if the brine is used in the drilling for
or production of oil and gas.
The U.S. Bureau of Land Management takes the lead on oil and gas
drilling activities on Federal and Indian lands. Where drilling on
Federal land occurs, the BLM issues a drilling permit, but concurrence by
the State is required. The State maintains primacy in waste disposal
activities associated with any such drilling or production activities.
Issues with drilling on Indian lands currently remain unresolved.
Some Tribes have issued regulations concerning oil and gas drilling and
production activities. Some Tribes have applied for UIC program
delegation. The State has not waived jurisdiction in regard to
regulating the oil and gas industry on Indian lands, however. Where
Tribe regulations go beyond those of the State, the Tribe regulations
prevail.
State Rules and Regulations
New Mexico has developed many of its rules in response to problems
identified or anticipated in particular production areas in the state.
In the southeast, contamination now is being detected related to oil and
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gas activities which occurred three or four decades ago. These cases may
be related to improper casing, pit construction, improper plugging or any
number of practices. Contamination includes increases in chlorides and
total dissolved solids, dissolved aromatic and phenolic hydrocarbons, and
natural gas.
In northwest New Mexico, contamination has mainly been natural gas
seeping into water wells. An active plugging program for old abandoned
wells is in effect. Little groundwater monitoring has been performed in
northwest New Mexico, so the extent of contamination from casing leaks or
unlined pits is unknown. In many areas, contamination is unlikely due to
deep ground water, thick, low permeability vadose zones, and small volume
discharges. Additional investigation is being carried out by the Division
in shallow groundwater areas.
Drill ing
There is a general regulatory requirement that the operator provide a
drilling pit sufficient for accumulation of drill cuttings, and that
drilling fluids and drill cuttings must be disposed of at the well site
in a manner to prevent contamination of surface or subsurface waters.
There are, however, no specific rules on construction of such pits. The
District Supervisor would have the responsibility of making a
determination if there were a potential problem in vulnerable areas.
No drilling fluids are authorized to be discharged to surface waters.
Land application is generally not done, although there are no specific
statewide rules on landfarming. The reserve pits are generally dried out
through evaporation, and the dried muds buried in the pits. The areas of
New Mexico in which there is oil and gas drilling have significant net
evaporation. In the southeast, annual rainfall averages 14-17 inches,
with 80 inches evaporation. In the northwest, rainfall averages 7-12
inches annually, and evaporation is 40-50 inches.
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Removal of drilling fluids or drill cuttings for offsite disposal
must be approved by the appropriate District Supervisor,
Produced Waters
Storage/Disposal Pits: Regional Orders determine the requirements
for saltwater storage or disposal pits in the most important areas of the
state for oil and gas production. In 1967, Order No.R-3221 prohibited
most surface disposal of produced waters in a four-county area in
southeastern New Mexico. In 1985, another set of regional regulations
(Order No.R-7940) was established, effective January 1, 1987, for areas
with potentially vulnerable aquifers in the northwestern part of the
state.
In the southeast, Order R-3221 prohibits the disposal of produced
water onto the ground or into unlined pits due to the presence of shallow
groundwater which could be adversely affected by the brine. An exemption
is made for pits receiving no more than one barrel/day per 40 acre tract,
with a maximum of 16 barrels/day for any pit. An amendment to the Order
(R-3221-B) excepted areas in the four counties where the only water
present was already highly saline.
In the northwest, Order R-7940 defines areas where aquifers are
vulnerable to the effects of produced brine, and prohibits unlined pits
in such areas. Exemptions are made (so long as groundwater depth is at
least 10 feet) if a pit receives no more than 5 barrels per day of
produced water, and the water is less than 10,000 mg/1 IDS, or if the pit
receives no more than 1/2 barrel per day.
Lined pits may be permitted in areas where unlined pits have been
prohibited. Order R-3221-C states that "the utilization of lined
evaporation pits is feasible and in the interest of good conservation
practices, provided they are properly designed, constructed and
maintained." Order R-7940 authorizes administrative approval of lined
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pits or below grade tanks within the Vulnerable Area "upon a proper
showing that the tank or lined pit will be constructed and operated in
such a manner as to safely contain the fluids to be placed therein and to
detect leakage therefrom."
Operators must obtain approval from the Division for lined pits, and
appropriate requirements for pit construction are found both in R-3221-C
and in "Guidelines for the Design and Construction of Lined Evaporation
Pits." R-3221-C requires that the pit provide at least 600 square feet
of evaporative surface for each barrel deposited in the pit on a daily
average basis throughout the year, and that the lease or leases served by
the pit should have an even or decreasing rate of water production.
Header pits must be provided to prevent oil from reaching the evaporation
pits. Pits must be lined with an impervious material at least 30 mil in
thickness, and have leak detection capability.
Other Surface Discharge: No NPDES permits are issued for discharges
of produced waters, and no discharges to surface waters are allowed.
However, individual farmers may contract for use of produced water as
drinking water for cattle (although not for irrigation). Agreement must
be obtained from the District Supervisor. No specific limits are placed
on produced water used for this purpose, nor does the approval of the
District Supervisor constitute certification as to the quality of the
produced water for such purpose.
Injection: Over 90% of produced water is reinjected into wells for
enhanced recovery (3,508) or saltwater disposal wells (363). The Oil
Conservation Division has responsibility for the Class II UIC injection
permitting program.
Generally, disposal of produced waters into zones containing waters
of 10,000 mg/1 or less IDS will not be permitted except after notice and
hearing, unless the water being injected is of higher quality than the
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native water in the zone. But the Division may establish exempted
aquifers for such zones where such injection may be approved
administratively.
Regulations impose the general requirement that injection wells be
cased with safe and adequate casing or tubing to prevent leakage, and the
casing or tubing must be set and cemented to prevent the movement of
formation or injected fluid from the injection zone into any other zone
or to the surface around the outside of any casing string.
Failure of any injection well must be immediately reported. Where
injected fluids have not been confined to the authorized zone or zones,
the wells may be restricted as to volume or pressure of injection, or
shut-in, until identification and correction of the failure.
Before injection, wells must be tested to assure the "initial
integrity of the casing and the tubing and packer, if used, including
pressure testing of the casing-tubing annulus. "Tests should be for 15
minutes at pressures in the range of 250-300 psi, with a maximum variance
of 10%. Additional tests are required at least every 5 years.
Offsite Disposal
Production and drilling wastes are sometimes sent to commercial or
centralized surface disposal or collection facilities. Commercial
facilities are those receiving compensation. Centralized facilities are
non-commercial facilities "receiving produced water, drilling fluids,
drill cuttings from any off-well-site location for collection, disposal,
evaporation, or storage in surface pits, ponds, or below grade tanks."
The Commission issued Order No.R-7940-A in 1986 to regulate such offsite
facilities in the northwest. For commercial pits, the Division may
approve use of lined or unlined pits, so long as they are constructed
adequately to protect fresh water. For proposed centralized pits,
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applications must be filed with the Division, unless the facility will
never receive more than 16 barrels/day in a 24-hour period and is at
least 10 feet above groundwater, or serves emergency purposes during
drilling for periods not exceeding 10 days. Applications are required in
any case where the pits receive drilling or completion wastes.
Where pits are required to be lined, they must be lined according to
the provisions of the "Guidelines" for lined evaporation pits. The
"Guidelines" require that the pit must provide the minimum evaporative
surface necessary for the maximum yearly volume of water to be discharged
to the pit. It should have adequate freeboard to protect against wave
action, and levees at least 18 inches above the ground. It must have a
double liner system, with a leak detection system between the top and
bottom liners. Synthetic liners must be at least 30 mil thick. Skimmer
ponds or tanks must be used to separate any oil from the water prior to
discharge to the evaporation pit.
Transporters of oil field wastes must register, but need keep no
records of source, destination and volumes of the specific wastes hauled.
Plugging/Abandonment
Wells may not be temporarily abandoned for more than six months
unless a permit for temporary abandonment has been approved by the
Division. The maximum period of the permit is one year, with an
additional possible one year extension. The Division may waive this
limitation and grant further extensions in the case of a remote or
unconnected gas well, a presently non-commercial gas well which could
become commercial in the foreseeable future, or a currently non-producing
well with commercial potential in a field where secondary recovery has
been demonstrated to be commercially feasible. Such further extensions
are limited to two years, but are renewable.
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Before a permit for temporary abandonment can be granted, evidence
must be furnished that the condition of the well will not allow damage to
producing zones or the contamination of fresh water. A one-well plugging
bond may be required for any well under extension for temporary
abandonment.
Specific well-plugging plans must be approved by the Division. The
general regulatory requirement is that plugging must "confine all oil,
gas, and water in the separate strata originally containing them. This
operation shall be accomplished by the use of mud-laden fluid, cement and
plugs, used singly or in combination as may be approved by the Division."
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References
New Mexico Meeting Report. 1985. Proceedings of the Onshore Oil and Gas
State/Federal Western Workshop. U.S. Environmental Protection
Agency, Washington, D.C. (December 1985).
Summary of State Statutes and Regulations for Oil and Gas Production.
1986. Interstate Oil and Gas Commission (June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil Compact
Commission (December).
State of New Mexico, Energy and Minerals Department, Oil Conservation
Division. Rules and Regulations. April 1, 1986.
State of New Mexico. Water Quality Control Commission Regulations.
March 3, 1986.
Chavez, Frank. 1985. "Management and Regulation of Drilling Waste
Disposal: The New Mexico Approach." Proceedings of a National
Conference on Disposal of Drilling Wastes. University of Oklahoma
Environmental and Ground Water Institute, Norman, OK, pp. 151-164.
Order of the Oil Conservation Commission of the State of New Mexico,
Order No's. R-3221, and R-3221-A through C.
Order of the Oil Conservation Commission of the State of New Mexico,
Order No's R-7940 and R-7940-A
Memorandum, R. L. Stamets, Director, Oil Conservation Commission,
regarding Hearings for Exceptions to Order No. R-3221, dated October
22, 1985.
Personal Communications:
David Boyer, Hydrogeologist, New Mexico Oil Conservation Division,
(505) 827-5812.
10
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NEW YORK
Introduction
New York is one of the pioneer states for oil and gas production and
use. Proven oil reserves were documented in 1627, and drilling began in
the late 1800s. Since then it is estimated that 30,000 to 50,000 wells
have been drilled in New York.
New York produced 1,071,000 barrels of oil from 4,621 wells in 1985.
Thirty-five billion cubic feet of natural gas was produced from 4,818 gas
wells in 1985.
Regulatory Agencies
Background
In 1963 the New York legislature passed laws regarding oil and gas
operations. A working permitting system was instituted in 1966 under the
purview of the Department of Environmental Conservation. The regulations
have been revised fairly often over the last twenty years. In fact,
further revisions are expected in the next year or two as a result of a
Generic Environmental Impact Statement scheduled for completion in late
1987.
Agencies
Oil and gas activities in New York are regulated by:
- NY Department of Environmental Conservation
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- Bureau of Land Management (Federally-held mineral rights only)
- U.S. Forest Service (surface activities in U.S. forests)
Most oil and gas activities in New York are regulated by the
Department of Environmental Conservation. The Department of
Environmental Conservation is authorized to regulate the "development,
production, and utilization of natural resources of oil and gas ... in
such a manner that a greater ultimate recovery of oil and gas may be
had." the Department also has authority for "prevention of pollution and
migration." New York is NPDES-delegated, with the Department of
Environmental Conservation responsible for the program. New York does
not have UIC primacy.
An Oil, Gas, and Solution Mining Advisory Board (with 11 members, a
majority of whom are industry representatives) meets a minimum of twice a
year, and is charged with providing DEC with its recommendations on
developing rules and regulations which could impact the oil and gas
industry.
The U.S. Bureau of Land Management has regulatory authority for oil
and gas activities when mineral rights are Federally held. Their
regulations are discussed in a separate section, Federal Agencies.
The U.S. Forest Service has jurisdiction over surface activities on
federal forest lands even when mineral rights are held privately.
The Water Quality Division, Fish and Wildlife Division, Regulatory
Affairs, Law Enforcement, and Lands and Forests provide instrumental
manpower and enforcement actions, when applicable.
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Rules and Regulations
Drilling
The Division of Mineral Resources in the Department of Environmental
Conservation issues all oil and gas drilling permits. The Mineral
Resources Regulations establish a general objective that must be
incorporated in all permits: "Pollution of the land and/or of surface or
ground fresh water resulting from exploration or drilling is
prohibited." Each permit requires that the fluids generated by drilling
be "hauled away and properly disposed of." The regulations do not
provide specific direction regarding what practices constitute proper
disposal. Rather, the operator must submit and receive approval for a
plan for the "environmentally safe and proper ultimate disposal of such
fluids."
If drilling muds are freshwater natural clay-based muds, they are
considered non-polluting and are specifically excluded from this
requirement. Muds contaminated with oil or other pollutants must be
disposed in a certified landfill. Drilling pits are dewatered and the
fluid disposed of properly prior to reclamation. During reclamation, pit
liners are shredded or removed and the rock cuttings disposed in situ.
After drying, the cuttings are buried.
Other drilling wastes must be disposed or discharged in a manner
acceptable to the Department considering the environmental sensitivity
and geology of the area. Historical experience with drilling operations
in the same area may also be used in considering an application. Permits
may be required for disposal or discharge of drilling wastes (excluding
drilling muds) in addition to the drilling permit.
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DEC has required that all drilling pits be properly constructed,
sized, and lined since 1982. It is a permit condition on all wells. The
only exception has been the closely observed, pitless drilling
experiments associated with some air-drilled wells.
DEC has noted that the majority of wells in new York are drilled with
air and there is very little associated fluid associated with the drill
cuttings in the drill pit. As a result, there has been some
experimentation with pitless drilling, which DEC reports "creates a
temporary dust problem and some vegetation is killed by the associated
brine, but less than would be killed by clearing the land for a drilling
pit."
Brine and salt water generated during drilling are considered
"polluting fluids" in the Mineral Resources Regulations. These fluids,
and other polluting fluids, may be stored in watertight tanks or lined
pits for up to 45 days after drilling ends prior to disposal. An
extension may be granted if the operator plans to use the fluids for
later activities. The disposal alternatives for brines and salt water
generated during drilling would generally be the same as those for waters
generated during production.
The Department is also responsible for well construction and spacing
requirements.
Produced Water
Part 556 of the Mineral Resources Regulations addresses operating
practices applicable to oil and gas wells. Section 556.5 prohibits
pollution of the land and/or surface or ground fresh water resulting from
producing, refining, transportation, or processing of oil, gas, and
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products. Brine (i.e., produced water) may be stored in water-tight
tanks or in lined pits prior to disposition. Although specific
construction requirements are not described in the regulation, pits must
be constructed and lined to prevent percolation into the soil, over or
into adjacent lands, streams, or bodies of water.
The only disposal alternative described in the regulation is
injection. The Department of Environmental Conservation has procedures
for application and approval of permits to inject brines; since New York
does not have primacy for the UIC program, an operator would have to
obtain a permit from EPA-Region II as well.
According to DEC, the predominant method of disposal of the dilute
brines associated with oil production in the old waterflooded fields of
New York is under SPDES permits. Road spreading is the predominant brine
disposal method for the concentrated brines associated with the state's
gas wells. Road spreading is conducted on a manifest system under a
separate permit. Criteria for road spreading are established on a case-
by-case basis, and include such requirements as time of day, use of
spreading bar, prohibition on spreading during rain storms, and
concentration limits.
The Department of Environmental Conservation allows "processing [of
brines] at sewage disposal plants, permitted onsite discharges, and
hauling to other states with approved disposal facilities." DEC allows
brine discharges from stripper wells under permits with the following
limitations:
- oil and grease 15 mg/1
- pH 6 to 9
- benzene 10 micrograms/1
- toluene 10 micrograms/1
- xylene 10 micrograms/1
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Sampling is done infrequently on any given well. Annular disposal is
not allowed.
Offsite Pits
New York regulations do not address the use of offsite pits for long
term storage or disposal.
PIuggi ng/Abandonment
Wells which are commercially producible may be shut-in for one year,
and may be granted additional one-year extensions (renewable) for good
cause. Wells may only be temporarily abandoned for 90 days without
specific permission, but extensions for a "reasonable time period" will
be granted, and renewed, for good cause.
The well bore must be filled with cement from the bottom of the well
to 15 feet above the shallowest formation from which production was every
obtained in the vicinity. Alternatively, a bridge topped with 15 feet of
cement may be placed above each formation from which production was ever
obtained. If casing is left in the well, 15 foot plugs must be placed at
top and bottom. If casing extending below deepest potable water is not
to remain, a 15 foot plug must be placed 50 feet below that water level.
If the surface casing is withdrawn, a 15-foot plug should be placed
immediately below where lower end of casing rested, and the well filled
with cement from that point to the top. Intervals between plugs must be
filled heavy mud-laden fluid. If casing left in the hole was never
cemented, it must be perforated and cement squeezed into the annular
space. Additional requirements to ensure proper abandonment are added by
permit condition.
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References
Interstate Oil Compact Commission, The Oil and Gas Compact
Bulletin. Volume SLIV, Number 2, December 1985.
Cornell University, "Oil, Gas and Solution Mining
Legislation in New York As Amended through September 1985."
New York State Statute 550.2, Subchapter B - "Mineral Resources,"
Parts 550 through 558, as amended.
New York State Environmental Conservation Law, Article 23,
Title 1-5 (circa 1985).
...New York Meeting Report. 1985. Proceedings of the Onshore
Oil and Gas Workshop, U.S. EPA, Washington, D.C.,
March 26-27 in Atlanta, GA). July 1985.
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North Dakota
Introduction
North Dakota produced 45,624,000 barrels of oil and 62 x 109 cubic
feet of gas in 1986. Production was from 3,595 oil wells and 103 gas
wells.
Regulatory Agencies
Three agencies regulate oil and gas activity in North Dakota:
- North Dakota Industrial Commission, Oil and Gas Division
- U.S. Department of Agriculture, Forest Service
- U.S. Bureau of Land Management
The North Dakota Industrial Commission, Oil and Gas Division, has the
regulatory responsibility to oversee the drilling and production of oil,
protect the correlative rights of the mineral owners, prevent waste, and
protect all sources of drinking water. Other responsibilities of the
Division are to collect monthly reports on oil, gas, and water; oversee
proper disposal of brine; and issue drilling permits. The Division also
has primacy for UIC Class II wells and issues such permits.
The Bureau of Land Management has jurisdiction over drilling and
production on Federal lands, but the operator must obtain a permit from
the Oil and Gas Division. When drilling is to occur on U.S. forestland,
no additional permit is needed but additional stipulations are placed by
the U.S. Forest Service.
State Rules and Regulations
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Drilling
Before a drilling permit is issued by the Commission, the operator of
the well must be bonded. Single well bonds are $15,000 a ten-well bond
is $50,000, and a blanket bond is $100,000. The Commission will release
the bond after site restoration is approved. Before drilling activities,
Commission inspectors will survey the site for pit location. The
inspectors also decide whether or not to require a pit liner at the site.
Under Commission Rule 43-02-03-19, "Pits shall not be located in or
hazardously near, stream courses, nor shall they block natural
drainages. Pits shall be constructed in such manner so as to prevent
contamination of surface or subsurface waters by seepage or flowage
therefrom. Under no circumstances shall pits be used for disposal,
dumping or storage of fluids, wastes and other debris not used in
drilling operation." ~Within 1 year after the completion of a well, the
pit site must be restored. Pit restoration does require approval from
the Commission. Reclamation includes removal of the fluid from the pit
and redistributing topsoil that was removed from the site at the
beginning of drilling activities.
When drilling is on U.S. forest lands, the U.S. Forest Service has
stipulations in addition to those of the Commission. The Forest Service
requires a complete survey and design of the drilling site. This survey
must be approved before drilling. All reserve pits must be lined with a
material that meets the minimum requirement set by the Forest Service.
The reclamation plan must also be approved by the Forest Service before
implementation.
Production
Under Commission Rule 43-02-03-53, "All saltwater liquids or brines
produced with oil and natural gas shall be disposed of without pollution
2
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of freshwater supplies. At no time shall saltwater liquids or brines be
allowed to flow over the surface of the land or into streams." Surface
pits are not allowed for brine storage. Surface tanks are allowed
provided they are diked and are leak-proof.
Brine may be disposed by use of injection wells for either enhanced
recovery or disposal. When a central tank battery or central production
facility is planned to be used, approval must be received from the
Commission, or from the Forest Service if on U.S. forest lands. Both
methods require permits issued by the Commission. All injection wells
must be cased and cemented to prevent movement of fluids into or between
underground sources of drinking water. Planning for drilling a well must
include an analysis of all other pits within the applicable area of
review, the taking of corrective action, if needed, on other wells
penetrating the injection zone, and the evaluation of appropriate
pressure to avoid generating or spreading fractures in the confining
zone. Mechanical integrity tests must be carried out before initiating
injection, and at least every five years thereafter (although regular
monitoring of annulus pressure or records showing a consistent
relationship between injection pressure and flow rate may be used in lieu
of later pressure tests). Wells must be pressure tested for at least 15
minutes. Test pressure is dependent upon maximum injection pressure.
Allowed pressure variance depends upon the stabilized test pressure and
maximum injection pressure.
Offsite Disposal
There are several commercial brine disposal wells in the state, but
no pits. The brines hauled onto commercial facilities are stored in
tanks.
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Plugging/Abandonment
A well may be temporarily abandoned (generally for economic reasons)
and no casing pulled with approval of the enforcement officer. A plug
must be placed at the top of the casing. Wells which have been shut-in
for long periods will be reviewed on a case-by-case basis, including
tests of casing integrity. A well where drilling operations have been
suspended for six months must be plugged and abandoned unless a permit
for temporary abandonment has been obtained.
When wells are plugged, perforations must be squeezed or a cast iron
bridge plug set above the perforations and capped with 5 sacks of
cement. Cement plugs are set 50 feet in and 50 feet over the top of each
productive zone, a 100-foot plug half in and half over the Dakota
Formation, and a 10-sack plug at the surface. If the casing is pulled,
100-foot plugs are placed spanning the casing top and the bottom of the
surface casing. Field inspectors must witness every plugging.
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References
North Dakota Industrial Commission, Statutes and Rules for the
Conservation of Oil and Gas. January 1985.
Williams, Tex. State regulatory information submitted in 1985.
U.S. EPA. North Dakota Meeting Report. Proceedings of Onshore Oil and
Gas State/Federal Western Workshop. U.S. EPA, Washington, D.C.
(December 1985).
U.S. Department of Agriculture, Special Forest Service stipulations,
September 1986.
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OHIO
Introduction
Ohio produced 14,987,592 barrels of oil and 182.2 x 10 cubic feet
of gas in 1985 from 2,798 full producing oil wells and approximately
26,412 stripper wells producing less than 10 barrels per day, and 31,343
gas wells, almost all of which were stripper wells producing less than
60,000 cubic feet per day.
State Regulatory Agencies
Two agencies regulate oil and gas activities in Ohio:
- Ohio Department of Natural REsources
- Ohio Environmental Protection Agency
The Ohio Department of Natural Resources, Division of Oil and Gas,
issues permits for oil and gas drilling and for underground brine
injection. The statutes and rules of the Division of Oil and Gas do not
contain provisions for effluent discharges. The Division operates on
revenues from permit fees and severance taxes on oil and gas.
Enforcement activities are dependent primarily upon approximately 50
field staff employees who inspect well sites and conduct investigations.
The Division of Oil and Gas has authority to review, investigate, and
require corrective action related to all oil and gas drilling and
production activities. Compliance bonds are require by the Division,
Ohio has been delegated NPDES authority. NPDES permits are issued
through the Ohio Environmental Protection Agency, Water Quality Division;
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none is issued for the oil and gas drilling and production industry. The
jurisdiction of the Ohio EPA extends to any pollution of the waters of
the State. Where brine spills may impair waters of the State, for
example, there is coordination between the Ohio DNR and Ohio EPA in
damage assessment and corrective measures. When there is potential for
groundwater contamination, the Ohio Environmental Protection Agency may
assist in the investigation and joint charges may be filed with the Ohio
Department of Natural Resources.
A five-member oil and gas Board of Review was created by statute
within the Ohio Department of Natural Resources. Members of the Board,
appointed by the Governor for five-year terms, consist of representatives
of a major petroleum company, the public, independent petroleum
operators, and individuals experienced in oil and gas law and in
geology. Any person claiming to be aggrieved or adversely affected by an
order of the Chief of the Division of Oil and Gas may appeal to the Board
for an order vacating or modifying such an order.
On occasion, there is oil and gas drilling on Federal lands. When
application for such drilling is filed, the permittee obtains a lease
from the appropriate Federal authority prior to requesting a permit from
the Division of Oil and Gas. The permitting process then is managed as a
standard procedure with no special coordinating efforts.
State Rules and Regulations
Drill ing: Earthen pits may be used to contain produced brine,
drilling muds and cuttings, fracture fluids, or other substances
"resulting, obtained or produced in connection with drilling, fracturing,
reworking, reconditioning, plugging back, or plugging operations, but
such pits shall be constructed to prevent the escape of brine and such
substances." There is no requirement for clay or synthetic liners,
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unless prescribed on a site-specific basis in an area identified as being
hydrogeologically sensitive. When there is a history of groundwater
problems associated with an area, a plastic liner requirement is made
part of the drilling permit.
The pits must be emptied and backfilled within five months of the
commencement of drilling. The regulations specify that "muds, cuttings,
and other wastes shall not be disposed of in violation of any rule." In
most cases, pit solids are buried on the well site when no environmental
harm is expected. Drilling fluids are disposed of either by underground
injection.
Produced Waters
Recently enacted laws, which became effective on April 12, 1985,
established new standards for well operators and waste brine
transporters. Brine disposal has been a major environmental issue in
Ohio. Well drillers now are required to submit a brine disposal plan
stating the temporary storage method and ultimate disposal method and
site for all produced brine.
Operators are required to identify the transporter of the brine
including the transporter's address. Anyone who transports brines must
pay a $500 one-time fee, provide a $300,000 certificate of insurance for
bodily injury and liability, post a $15,000 bond to be used in paying for
damages, and provide detailed information. The detailed information
includes a daily log that identifies ultimate brine disposal such as time
and date of brine loading and amount, road spreading location, disposal
well permit number, time and date of brine disposal, etc. The driver is
required to maintain a daily log showing driver name, registration
certificate number, sites visited, and destination.
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Brine production is estimated at 40-50,000 barrels per day. Recent
reports indicate that approximately 90% of produced brine is disposed of
through injection wells; 10% by surface application and annular disposal.
Storage/Disposal Pits: Under the requirements of the revised rules
legislated in April, 1985, "no pit or dike shall be used for the ultimate
disposal of brine." Earthen impoundments may be used for the temporary
storage of brine in association with a saltwater injection or enhanced
recovery well.
Road Spreading: For road or land spreading, a county, township or
municipal government must pass a resolution to allow brine disposal that
meets several minimum requirements:
- prohibitions on brine application to a water-saturated surface, to
vegetation, within 12 feet of bridges or other road surfaces
crossing bodies of water or drainage channels, or during night
(except for ice control);
regulations on the rate, amount, and methods of application;
- and a prohibition against discharge by the vehicles making the
application at any points other than the surfaces specifically
approved.
A resolution with these minimum required specifications will be
deemed approved when submitted to the Division of Oil and Gas, without
any requirement for further review or approval by the Division.
Injection: Ohio has delegated authority for Class II well
injection. Brine injection may be into wells for enhanced recovery (170
wells), into disposal wells (182), or into the annulus of a producing
well (c. 4,000 wells). Permits are required for injection into disposal
wells or enhanced recovery wells. Notification and approval is required
for annular disposal.
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For disposal and enhanced recovery wells surface casing must be set
at least 50 feet below the deepest underground source of water containing
less than 10,000 mg/1 IDS or less than 5,000 mg/1 chlorides, and must be
cemented to the surface. Surface casing must be cemented to surface or
properly sealed with prepared clay. Injected fluids must be isolated by
the use of casing mechanically centralized and enclosed in cement to a
height no less than 300 feet above the top of the injection zone.
Injection must be through tubing and a packer set no less than 100 feet
above the injection zone.
A variance from some construction requirements may be granted if the
injected volume is less than 25 barrels/day at minimal pressures or if
the chief determines that the variance sought will result in the
construction of an injection well equivalent in its ability to protect
freshwater aquifers.
Prior to any injection, the casing outside the tubing must be
pressure tested at 300 p.s.i. or at the maximum allowable pressure,
whichever is greater, for a period of 15 minutes, with no more than a
five percent decline in pressure. The mechanical integrity test must be
readministered at least once every five years.
The maximum volumes which may be disposed of with annular injection
are 10 barrels per day (if the surface casing is sealed with cement) or 5
barrels per day (if sealed with prepared clay). Annular disposal can
only use the force of'gravity. Only saltwater and standard well
treatment fluids may be disposed of in the annulus. When a well ceases
to produce oil or gas, annular disposal must stop and the well must be
plugged.
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For annular disposal, the surface casing must be sealed with cement
or clay, and the sealing material circulated to the surface. The surface
casing must be set at least 50 feet below the deepest underground source
of water with less than 10,000 ppm TDS or 5,000 ppm chloride. Annular
disposal systems must be airtight. Brine may only be disposed of by
liquid tight pipeline at an annular disposal well. No trucking of brine
is permitted.
Mechanical integrity shall be demonstrated for annular disposal wells
at least once every 5 years, using tracer surveys, noise logs,
temperature surveys, or other tests approved by the Division.
Offsite and Commercial Disposal
When a groundwater problem history exists, pit solids may be required
to be removed and transferred to an Ohio EPA regulated disposal site.
Or, if there is a request to move pit solids to an offsite area, an EP-
toxicity test for hazardous waste characteristics is required prior to a
transfer to a State-approved hazardous or nonhazardous landfill, as
appropriate. Abandoned pits are investigated when alleged to be the
cause of a groundwater problem. When found to contribute to such a
problem, the owner of the pit is required to remove solids and transport
them to a State-approved solids disposal facility.
Plugging/Abandonment
Enforcement of plugging regulations is split between two enforcement
agencies in Ohio. Wells plugged in non-coal bearing townships must be
plugged in accordance with rules adopted in coal bearing townships must
be plugged in accordance with rules adopted by the Ohio Department of
Industrial Relations, Division of Mines. Plugging rules adopted by the
two agencies differ somewhat.
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Any operator plugging a well must inform owners of the land on which
the well is sited, owners of adjacent land, and mine owners of the
intention to abandon the well. Plugging operations for dry holes must
begin immediately upon abandonment of the hole. Plugging operations for
abandoned production or injection wells must begin "without undue delay
after production, extraction, or injection operations have ceased."
Temporary abandonment status will be granted for a period of six months
if the well poses no environmental threat; remedial action must be taken
to correct environmental threats before such status will be granted.
Surface casing may not be pulled from a rotary drilled well. Surface
casing may be pulled from a cable tool drilled well if the conductor pipe
is left in place. Cement plugs must be placed from a minimum of 50 feet
below the base to a minimum of 100 feet above the top of the lowest
reservoir rock. If clay is used as the plug, the plug must extend 400
feet above the top of the reservoir. For each succeeding reservoir,
until within 100 feet of the bottom of the surface casing, the
requirements are identical for cement plugs; for clay plugs the required
minimum height above the top of a reservoir is reduced to 200 feet. For
freshwater zones, cement plugs must extend from 50 feet below to 100 feet
above the zone. A cement plug shall also be placed from 50 feet below
grade level to 30 inches below grade level. If a clay plug is used, the
plug must extend from 50 feet below the base of the freshwater zone to 30
inches below grade. All portions of the well which are not filled by the
plugs are to be filled with mud-laden fluid.
After a well is abandoned, a detailed report containing information
about the plugging and the identity of witnesses to the plugging must be
filed by the operator with the Division of Oil and Gas.
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References
Chapter 1509 of the Ohio Revised Code.
Chapter 1501, Rules of the Division of Oil and Gas of the Ohio Department
of Natural Resources.
Summary of State Statutes and Regulations for Oil and Gas Production.
1986. Interstate Oil and Gas Commission (June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil Compact
Commission (December).
Hodges, David H. 1985. Letter Communication to EPA. Division of Oil
and Gas, Ohio Department of Natural Resources.
Ohio Meeting Report. 1985. Proceedings of the Onshore Oil and Gas
Workshop. U.S. Environmental Protection Agency, Washington, D.C.
(March 26-27 in Atlanta, GA).
Personal Communications:
David A. Hodges, DNR, Division of Oil and Gas (614) 265-6917.
Ted DeBrosse, DNR, Division of Oil and Gas (614) 265-6894.
Dick Schockley, DNR, Division of Oil and Gas (614) 984-2344.
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OKLAHOMA
Introduction
Oklahoma produced 153,250,000 barrels of oil and 1,996 x 10" cubic
feet of gas in 1984. It ranked fifth in U.S. oil production and third in
U.S. gas production. Oklahoma had 99,030 producing oil wells and 23,647
producing gas wells. There are approximately 200 million barrels of salt
water produced by the oil industry per year. There are about 7,900
saltwater disposal wells and 14,900 enhanced recovery injection wells.
Approximately 200 of the disposal wells are commercial facilities.
Regulatory Agencies
Four agencies regulate oil and gas activities in Oklahoma:
- Oklahoma Corporation Commission, Oil and Gas Conservation Division
- Oklahoma Water Resources Board
Osage Indian Tribe
U.S. Bureau of Land Management
The Oklahoma Corporation Commission, Oil and Gas Conservation
Division, has exclusive jurisdiction over all laws and regulations
"relating to the conservation of oil and gas and the prevention of
pollution in connection with the exploration, drilling, producing,
transporting, purchasing, processing and storage of oil and gas...."
Pollution of surface or subsurface water during any well activity is
prohibited. Currently, there are 55 inspectors who have the authority to
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shut down operations if regulations are not followed. Oklahoma has
received primacy for the UIC program, and the Division is responsible for
the permitting and regulation of Class II wells.
The Oklahoma Water Resources Board is responsible for protection of
all surface and ground water to ensure that pollution does not occur The
Board has permitting authority for all discharges, which must meet
specified water quality standards, including beneficial use limits.
However, discharges to water from oil and gas activities are not
allowed. The principal role of the Board in oil and gas
drilling/production activities is in identifying spills from oil and gas
activities and referring them to the Corporation Commission for further
action. On occasion, the Board will participate with the Commission in
cleaning up the spills.
The Osage Indian Tribe has sole primacy regarding oil and gas
operations in Osage County, and has been delegated UIC program
responsibility for Class II wells.
The U.S. Bureau of Land Management has primacy where both surface and
mineral rights are owned by the Bureau or by an Indian Tribe other than
the Osage Tribe. In those cases where mineral rights are owned by the
Bureau or an Indian Tribe, but not the surface rights, both the Bureau
and the Oklahoma Corporation Commission would become involved and would
coordinate the permitting procedures.
State Rules and Regulations
Drilling
Pit Construction/Management: Commission Rule 3-104 establishes a
general requirement that "pits and tanks for drilling mud or deleterious
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substances used in the drilling, completion, and recompletion of wells
shall be constructed and maintained so as to prevent pollution of surface
and subsurface fresh water." It further requires that deleterious fluids
other than fresh water drilling muds from drilling and workover
operations be kept separate from the fresh-water muds, and be placed in
lined pits (plastic liner of at least 30 mil) or metal tanks for separate
disposal.
Emergency pits, burn pits, and circulating, frac, or reserve mud pits
used for drilling, reworking or plugging a well may be constructed on-
site (serving only the lease or unit on which located) without a permit.
Notices of construction must be filed, however, for emergency and burn
pits (Rule 3-110.1).
The only requirements, other than the general restriction against
pollution, applying to reserve pits as well as other on-site pits are
that they must maintain the fluid level at least 18 inches below the
lowest point of the embankment, and must be constructed to prevent
incursion of outside runoff water.
Pit Closure: Reserve pits must be dewatered and leveled within 12
months of the end of drilling operations. A single 6-month extension may
be granted for reasonable cause. Circulating pits must be leveled within
60 days after drilling ceases, and fracture pits within 60 days after
completion of fracture operations.
Disposal: Four methods are used for disposing of drilling fluids:
annular injection, evaporation followed by burial of pit solids, non-
commercial landfarming, or vacuum truck removal to offsite pits.
Commercial landfarming is currently prohibited, but is under
consideration by the Oklahoma Corporation Commission.
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Annular Injection: An operator must apply for approval of on-site
annular injection of reserve pit fluids. Surface casing injection (or
intermediate casing injection) may be authorized if the surface casing
(or intermediate casing) is set and cemented (set) at least 200 feet
below the base of treatable water. Injection pressure must be limited so
that vertical fractures will not extend to the base of treatable water.
(Rule 3-312)
Landfarming: Permits (required) for non-commercial soil farming may
only be applied for by the operator of the reserve pit of which the
contents are to be landfarmed (Rule 3-110.3). To apply for a soilfarming
permit, the operator must have a written agreement from the landowner
which is consistent with the regulatory requirements, an analysis of the
soil, an analysis of the reserve pit contents, and loading calculations
to determine the maximum number of barrels/acre which may be landfarmed.
Permits expire 6 months after approval.
Pit contents must be applied uniformly by injection or spray
irrigation and incorporated into the soil (within 14 days of application)
by injection or disking. The Commission may approve other methods.
An effort must be made to re-establish vegetative cover within 120
days of the completion of soil farming.
Soil farming is limited to water based type muds and the cuttings and
accumulated precipitation in the pit of oil based muds. Soil farming of
oil based muds is prohibited.
Generally, landfarming is not allowed unless receiving soils are
suitable and the hydrology will not lead to pollution of surface or
groundwaters.
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Specifically, landfarming is prohibited where:
- the land has a slope greater than 5%,
- depth to bedrock is less than 20 inches,
- floods occur more often than once every two years,
- the soil lacks 12 inches of loam, clay, silt, or sand,
- any of the soil is severely saline (>8,000 micromhos/cm),
a water table is within 6 feet of the soil surface.
When soilfarming is permitted, it must be at least 100 feet away from
property line boundaries, freshwater ponds or lakes, and streams
designated by Oklahoma Water Quality Standards; at least 50 feet from any
natural drainageway; 300 feet from any domestic or irrigation water well;
and 800 feet from any active municipal water well.
The maximum application rate for soilfarming is determined by
the most limiting of the following parameters:
Total weight of applied materials 400,000 Ibs./acre
Total soluble salts 6,000 Ibs./acre
(less TSS in soil)
Arsenic 80 Ibs./acre
Cadmium 5 Ibs./acre
Hydrocarbons 100,000 Ibs./acre
(5%by weight)
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If hydrocarbon content is in excess of 20,000 IDS. acre (1% by
weight), fertilizer may have to be incorporated with the cuttings and
reserve pit effluent from oil based drilling fluids.
Runoff of soil farmed material prior to incorporation is prohibited.
Soilfarming may not be practiced in winds gusting over 30 mph, in rain,
when the ground is frozen, or when the ground is too highly saturated.
Produced Waters
Injection: Produced waters are injected underground for both
enhanced recovery (14,900 wells) and disposal (17,700 onsite and 200
commercial wells). Permits are required from the Commission for all such
wells, whether new or converted.
Neither enhanced recovery injection wells nor disposal wells are
permitted within 1/2 mile of an active or reserve municipal water supply
well unless the applicant can "prove by substantial evidence" that the
injection well will not pollute the municipal water supply. In addition,
the applicant may be required to provide information on the present
status of all active or abandoned wells within 1/2-mile of the enhanced
recovery or disposal well, and to identify any abandoned well which was
improperly plugged or remains unplugged.
Wells must be constructed and operated to confine injected fluids to
the approved intervals, and to prevent pollution of fresh water or damage
to oil or gas resources. Surface casing or a stage collar must be
installed to at least 90 feet below the surface or 50 feet below any
treatable water strata, whichever is lower, and the annular space behind
the casing must be filled with cement from the base of the surface casing
or stage collar to the surface. (Alternative casing and cementing
methods are permissible under some circumstances).
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Injection or disposal of any substance must be through tubing and
packer. Adequate above-ground extensions shall be installed in each
annulus in the well. Appropriate fittings must be provided to allow for
measurement of injection pressure.
Before wells for disposal or enhanced recovery can be operated, they
must be pressure tested under supervision of the Conservation Division.
For new wells, the casing outside the tubing must be tested at the
maximum authorized injection pressure or 300 psi, whichever is greater.
For converted wells, the test must be at the lesser of 1,000 psi or the
maximum authorized injection pressure, but no lower than 300 psi. Test
duration is 30 minutes.
With the exception of wells which elect to monitor, each disposal or
enhanced recovery well must be pressure tested at least once every five
years. The casing-tubing annulus above the packer must be tested at the
lower of 1,000 psi or the maximum authorized injection pressure, with a
minimum of 300 psi. In lieu of such a casing pressure test, the operator
may, each month, monitor and record the pressure in the casing)tubing
annulus during actual injection, and report the pressure annually.
(Rules 3-206, 3-301 through 3-309, 8-8)
Commercial Offsite Pit
Under Rule 3-110.2, the Oklahoma Corporation Commission permits the
use of offsite earthen pits. Such pits must be constructed or sealed
with an impervious material, and must be operated in such a way as to
prevent the escape of any deleterious material. The operator must
provide a bond or irrevocable letter of credit as guarantee that the pit
will be emptied and leveled "upon termination of disposal activities."
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Some offsite pits service individual wells, in situations where pits
are not allowed at the site of the well (e.g., wells within city limits,
where city ordinances prohibit such pits). But there are also
approximately 100 commercial offsite pits throughout Oklahoma, ranging
from less than an acre to ten acres in size. Some offsite pits may
contain over 3,000,000 barrels of waste, which calculates to 387 acre
feet of fluids.
Commercial pits must have a soil seal at least 12 inches thick, with
permeability no greater than 10' cm/second. If the pit contains
deleterious substances, it must be lined according to specifications
determined by the Commission. The pit must not contain fluids with a
chloride content greater than 3,500 ppm, and may be sampled periodically
to enforce that limit. The pit may not be built in a 100-year flood
plain, must be built to prevent incursion of outside water runoff, and
must be managed to maintain the surface fluid level 24 vertical inches
below the lowest point of the embankment. Such pits must be "filled and
leveled within one year after abandonment.
"Truckers hauling oil and gas field wastes offsite must hold a
Deleterious Substance License, but do not have to report or maintain
records on materials and volumes transported.
PIugging/Abandonment
Wells in which neither surface nor production casing has been run
must be plugged within 72 hours after drilling or testing is completed.
If only surface casing has been run and cemented, plugging must take
place within 90 days. In either case, however, if there is any risk of
contaminating the environment, oil or gas formations, or treatable water
strata, the well must be plugged within 24 hours.
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Where production casing has been run, a well must be plugged within
one year after the cessation of drilling (if not completed or tested),
after the cessation of the latter of completion or testing (if no
production), or after the cessation of production. There are, however,
numerous exemptions from this requirement. Exemptions include shut-in
gas wells, wells for which the Commission has issued an exception to
plugging requirements (e.g., where production has ceased for economic
reasons), wells located on leases on which other wells are still
producing (so long as granted a Temporary Exemption by the Commission).
Operators of stripper wells may temporarily plug a well for up to two
years.
Plugging shall provide for sealing off each productive formation from
the well bore above and below the formation. Cement plugs must extend
from 50 feet below to 50 feet above the base of each formation, and from
50 feet below to 50 feet above the top of each formation. Exceptions to
these requirements may be granted if: (a) the formation is already sealed
off from the well bore with adequate casing, and (b) if the only openings
from the productive formation are perforations in the casing, and the
annulus between the casing and the outer walls of the well is filled with
cement 50 feet below the base and 50 feet above the top of the
formation. In such case, a bridge plug capped with 10 feet of cement set
at the top of the producing formation is authorized.
All fresh water strata in the well must be sealed off by adequate
casing from 50 feet below the base of the lowest fresh water stratum to 3
feet from the top of the well bore, and by completely filling the annular
space behind such casing with cement. If surface or other casing meets
requirements, cement plug may be set 50 feet below base of lowest fresh
water stratum to 50 feet above shoe of surface pipe. Top 30 feet of well
bore below 3 feet from surface shall be filled with cement. The surface
pipe shall be cut off 3 feet from the surface and capped with a steel
plate.
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Any uncased hole below the shoe of any casing to be left in the well
shall be filled with cement to a depth at least 50 feet below the shoe of
the casing, or the bottom of the hole, and the casing above the shoe
shall be filled with cement to at least 50 feet above the shoe of the
casing. If the well is completed with a screen or liner, and the screen
or liner is not removed, the well bore must be filled with cement from
the base of the screen or liner to at least 50 feet above the top of the
screen or liner.
All intervals between cement plugs in the well bore must be filled
with mud of not less than 9 Ibs. gallon and not less than 36 viscosity.
All plugging operations must be conducted under the supervision of an
authorized representative of the Conservation Division.
10
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References
Oklahoma Meeting Report. 1985. Proceedings of the Onshore Oil and Gas
State/Federal Western Workshop. U.S. Environmental Protection
Agency, Washington, D.C. (December 1985).
Summary of State Statutes and Regulations for Oil and Gas Production.
1986. Interstate Oil and Gas Commission (June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil Compact
Commission (December).
General Rules and Regulations of the Oil and Gas Conservation Division,
The Corporation Commission of the State of Oklahoma (1986).
Oklahoma Drilling Waste Conference.
Personal Communications:
Mike Battles, Manager of Pollution Abatement, Oklahoma Corporation
Commission (405) 521-4456.
Tim Baker, Oklahoma Corporation Commission (405) 521-2500
Walter Kramer, Oklahoma Corporation Commission (405) 521-3088
Karen Dihrberg, Geologist, Water Resources Board (405) 271-2549
Margaret Graham, Permits, Water Resources Board (405) 271-2561
Bob Thomas, Water Resources Board (405) 271-2541
11
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OREGON
Introduction
Oregon does not produce oil. Oregon's only producing gas field was
g
discovered in 1979. Thirteen active gas wells produced 4.5 x 10 cubic
feet of gas in 1986. There is one saltwater injection well for the
field. In 1986, approximately 40,000 barrels of brine were injected
underground; about 5,000 barrels went to surface land disposal.
State Regulatory Agencies.
Two agencies regulate oil and gas activity in Oregon:
- Oregon Department of Geology and Mineral Industries
- Oregon Department of Environmental Quality.
Oil and gas drilling permits are issued by the Oregon Department of
Geology and Mineral Industries. The State Geologist serves as the
implementor of rules, orders, and enforcement actions taken by the
Department's governing board. The Department is also responsible for
regulating Class II wells.
The Oregon Department of Environmental Quality has delegated
authority for the NPDES program and issues UIC permits. The State has
maintained a permitting program since 1968. No NPDES permits have been
issued because there have been no requests to discharge waste to public
waters.
None of the gas wells is on Federal lands. If, in the future,
drilling were to take place on Federal lands, there would be two separate
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permitting actions — one by the U.S. Bureau of Land Management and one by
the Oregon Department of Geology and Mineral Industries.
State Rules and Regulations
Drilling
Oregon Administrative Rule 632-10-205 requires a surety bond of up
to $25,000 for one well, or a blanket bond of $150,000 for more than one
well, conditioned upon the faithful compliance by the principal with the
rules, regulations, and orders of the Department of Geology and Mineral
Industries.
Rule 632-10-140 requires that any fluid necessary to the drilling,
production, or other operations by the permittee shall be discharged or
placed in pits and sumps approved by the State Geologist and the State
Department of Environmental Quality. The operator shall provide pits,
sumps, or tanks of adequate capacity and design to retain all mateials.
In no event shall the contents of a pit or sump be allowed to:
1. Contaminate streams, artificial canals or
waterways, groundwaters, lakes, or rivers.
2. Adversely affect the environment, persons,
plants, fish, and wildlife and their
population.
When no longer needed, fluid in pits and sumps is to be disposed of
in a manner approved by the Department of Environmental Quality and the
sumps filled and covered and the premises restored to a near natural
state. The restoration need not be done if arrangements are made with
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the surface owner to leave the site suitable for beneficial subsequent
use.
Drilling mud pits are not allowed to hold over winter because of lack
of sufficient storage for winter rainfall. If drilling muds dry in the
reserve pits before winter occurs, the pit is then closed.
There has not been a problem with abandoned pits; the surety bond
provides a mechanism to ensure adequate pit closure.
Production
Rule 632-10-192 of the Department of Geology and Mineral Industries
provides that brines or saltwater liquids may be:
1. Disposed in pits only when the pit is lined with impervious
material and a Water Pollution Control Facility permit has
been issued by the Department of Environmental Quality.
Earthen pits used for impounding brine or salt water shall be
so constructed and maintained as to prevent the escape of
fluid.
2. Disposed by injection into the strata from which produced or
into other proved saltwater bearing strata.
3. Disposed by ocean discharge, which may be permitted if water
quality is acceptable and if such discharge is approved by the
State Department of Environmental Quality through issuance of
a National Pollutant Discharge Elimination System Waste
discharge permit.
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Produced brines are permitted to be spread on dirt roads --
predominantly logging roads -- when such is done in dry weather.
Offsite and Commercial Pits
There are no operational offsite pits. One dump-site has been used
as an emergency pit. Operators must dispose of drilling muds in a
Department of Environmental Quality approved solid waste disposal site.
Such solids may be tested prior to disposal to determine if they contain
hazardous materials.
PIuggi ng/Abandonment
The State Geologist may authorize suspension of operations for good
cause for whatever time period is stated in the written authorization,
and further extensions may be granted upon expiration of the
authorization.
Rule 632-10-198: When a well is plugged, producing strata and strata
with fluid at greater than hydrostatic pressure must be plugged with
cement from 50 feet below to 50 feet above each stratum. A 100-foot
cement plug must be placed across the base of the freshwater bearing
strata, when it is in open hole. When there is open hole below the base
of any casing, a cement plug must extend from 50 feet below to 50 feet
above the base of the casing. All casing strings must be cut off at
least four feet below the ground, and plugged with cement to a depth of
ten feet. Intervals between plugs must be filled with heavy mud-laden
fill.
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References
Oregon Meeting Report. 1985. Proceedings of the Onshore Oil
and Gas State/Federal Western Workshop. U.S.
Environmental Protection Agency, Washington, D.C.
(December 1985).
Summary of State Statutes and Regulations for Oil and Gas
Production. 1986. Interstate Oil and Gas Commission (June)
The Oil and Gas Compact Bulletin. 1985. Interstate Oil
Compact Commission (December).
Olmstead, Dennis L. 1985. Letter Communication to EPA.
Oregon Department of Geology and Mineral Industries.
Personal Communications:
Dan Wermiel, Department of Geology and Mineral Industries
(503) 229-5580.
Kent Ashbaker, Department of Environmental Quality (503)
229-5325.
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Pennsylvania
Introduction
g
Pennyslvania produced 4,825,000 barrels of oil and 166 x 10 cubic
feet of gas in 1984. Production was from 20,739 oil wells and 24,050
gas wells.
Until 1955, requirements for the oil and gas industry were minimal
if not nonexistent. State laws did not require permitting or
registration of oil and gas wells. In 1961, the statutes were
strengthened to prohibit wasting in production wells, establish spacing,
and provide other requirements. It was not unit 1984 that the Coal and
Gas Resources Coordination Act and the Oil and Gas Act made sweeping
changes in permit review and requirements. There had been little
uniformity in Pennsylvania oil and gas laws until then. Combined, these
statutes enable Pennsylvania permitting authority to put terms and
conditions on permits, and to deny permits. Passage of House Bill 1375
in mid-September, 1986, further strengthens the regulatory management of
the oil and gas industry in Pennsylvania, and requires the development of
new regulations relating to solid waste management and the disposal of
wastes onsite.
The first commercial oil well was drilled near Titusville, PA, 1859.
Regulatory Agencies
Five agencies regulate oil and gas activities in Pennsylvania:
- Department of Environmental Resources, Bureau of Oil and
Gas Management
- U.S. Environmental Protection Agency, Region III
- Pennsylvania Fish Commission
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- U.S. Forest Service
- U.S. Bureau of Land Management
The Bureau of Oil and Gas Management was created in 1984 to
coordinate and combine all related regulatory activities of the oil and
gas industry. The Oil and Gas Conservation Law, enacted in 1961,
established powers and duties of the Oil and Gas Conservation
Commission. Those powers and duties were transferred to the Department
of Environmental Resources in 1970. The Oil and Gas Act of 1984 created
an Oil and Gas Technical Advisory Board to advise the Department in
regulatory activities (Section 216 of 1984 Act). The five member board
consists of three representatives of the oil industry, one from the
Citizen's Advisory Council, and one from the coal industry.
Section 207(a) of the Act requires that the disposal of drilling and
production brines be consistent with the requirements of the Clean
Streams Law (which, was first passed in 1937, and most recently amended
in 1980). Section 208(a) requires that any well owner who affects the
public or private water supply by pollution or diminution shall restore
or replace the affected supply with an alternative source. Section 205
prohibits drilling of wells within 200 feet of buildings or water wells
without the consent of the owner, within 100 feet of any body of water,
or within 100 feet of a wetland 1 acre or more in size. There is a
compliance bond conditioned on the operator's faithful performance of the
drilling, restoration, water supply replacement, and well plugging
requirements of the Oil and Gas Act.
The U.S. Environmental Protection Agency, Region III, issues UIC
program permits for underground injection and secondary recovery. The
Bureau of Oil and Gas Management has not sought primacy in the UIC
program.
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The Pennsylvania Fish Commission seeks out pollution of surface
waters and takes appropriate action under the Pennsylvania Fish and Boat
Code.
The U.S. Forest Service and the U.S. Bureau of Land Management
provide requirements they may have in lease agreements. The well driller
must demonstrate his notification of landowners and water supply owners
of the intent to drill. Mineral rights in the Allegheny National Forest
are privately owned. The Bureau of Oil and Gas Management issues
drilling permits on Federal lands.
State Rules and Regulations
Drilling
Drilling pits to the present time have been virtually unregulated.
Pits typically are unlined. Such pits contain drilling cuttings,
contaminated fresh and salt water produced during construction and well
stimulation, and various additives used during drilling and well
stimulation. Pits are not reclaimed and no permit is required for a
drill pit. There is no contingency fund for management of abandoned
pits. The Bureau is in the process of developing regulations to further
control oil and gas operations. The thrust on drilling pits is to remove
liquids to an offsite and commercial treatment and disposal facility and
to dispose of solids waste on site with pit reclamation. However,
presently many pits remain on-site and may be used for oil/water
separation during the production phase.
Production
It has been estimated that Pennsylvania has 17,000 impoundments
associated with oil and gas brines. If an impoundment is associated with
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an individual well, a permit has not been required. Permits are required
for offsite and commercial treatment systems. The trend since 1985 has
been to move in the direction of centralized treatment facilities for
oil and gas waste materials. However, there are still only a few
facilities within the State presently operating to solely treat
production wastewaters.
There are other production fluid disposal alternatives, which are
discussed in the Oil and Gas Operator's Manual published by the Bureau of
Oil and Gas Management. As the Manual notes, the practices suggested are
options, not regulations. Alternatives include:
- Disposal wells
- Annular disposal
- Treatment and discharge to surface waters
- Onsite treatment and land disposal of top hole water
- Discharge to existing treatment facility
- Road spreading
- Evaporation (through waste heat)
Since these alternatives are not binding regulations, it is largely
left to the operator to choose accepatble techniques for disposal.
Offsite and Commercial Pits
Water Quality Management Part II permits and NPDES permits are
required for treatment facilities that discharge to waters of the
Commonwealth. Treatment afforded production fluids may include flow
equalization, pH adjustment (if necessary) gravity separation and surface
skimming, retention and settling and aeration. The discharges from
several offsite produced-fluids treatment facilities may be covered under
a single NPDES permit, if the management of those facilities is under the
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control of one owner/operator and the geographic area is such as to allow
for effective monitoring and surveillance.
The NPDES permit criteria and limits will be governed by receiving
water quality standards. Generally, however, total suspended solids will
be limited to an instananeous maximum of 60 mg/1 and an average monthly
of 30 mg/1. Oil and grease will be limited to an instantaneous maximum
of 30 mg/1 and an average monthly of 15 mg/1. Dissolved iron has an
instantaneous maximum of 7 mg/1, and the acidity shall be less than the
alkalinity.
Plugging/Abandonment
If wells are certified as having future utility, and are in adequate
condition to prevent vertical flow of fluids, contamination of
freshwater, or damge of productive zones, a permit can be issued for
inactive status. The permit is valid for five years, and is renewable.
While revised regulations on plugging are to be adopted under the
new law, current requirements under Act 225 (as amended by Act 265 of
1968) are that: cement plugs of at least 20 feet should be set 20 feet
above each stratum which has had oil, gas, or water; a bridge capped with
ten feet of cement should be placed 30 feet below the water string of
casing, after which the casing may be drawn; a plug should be placed
about 10 feet below the bottom of the largest casing in the well; all the
spaces between the bottom or top of the well and cement plugs, or between
the cement plugs, should be filled with sand pumpings, mud, or other
equally non-porous material. Additional plugging requirements are
specified for wells passing through workable coal seams, and for wells
where the operator wishes to pull the casing. Additional recommendations
are made in the Oil and Gas Operator's Manual published by the Bureau of
Oil and Gas Management.
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References
Summary of State Statutes and Regulations for Oil and Gas Production.
1986. Interstate Oil and Gas Commission (June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil Compact
Commission (December).
Slack, Peter. 1985. Letter Communication with EPA Division of Permits
and Compliance, Bureau of Water Quality Management, Department of
Environmental Resources.
Pennsylvania Meeting Report. 1985. Proceedings of the Onshore Oil and
Gas Workshop. U.S. Environmental Protection Agency, Washington,
D.C. (March 26-27 in Atlanta, GA).
The Oil and Gas Act, Act of 12-19-84, P.L. 1140, No.223.
The Oil and Gas Conservation Law. 1961, P.O. 825, No. 359.
Rules and Regulations, Department of Environmental Resources, Chapter 97,
Industrial Wastes.
Personal Communication:
Carlyle Westlund, Bureau of Oil and Gas Management (717) 783-9645.
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South Dakota
Introduction
South Dakota produced 710,000 barrels of oil and 2.5 x 10 cubic
feet of gas in 1984. The State has 312 full production and 33 stripper
oil wells, and 41 full production and 1 marginal production gas wells.
State Regulatory Agencies
Four agencies regulate oil and gas activities in South Dakota:
- South Dakota Department of Water and Natural Resources
- South Dakota Department of School and Public Lands
- U.S. Bureau of Land Management
- U.S. Environmental Protection Agency, Region VIII
The South Dakota Department of Water and Natural Resources is the
primary regulatory agency for oil and gas operations through its Oil and
Gas Program in the Division of Environmental Quality. The primary
enforcement agency for the UIC program, and non-delegated responsibility
for NPDES compliance, is the Department's Office of Water Quality. The
Department of Water and Natural Resources also houses the Board of
Minerals and Environment, which has power to conduct hearings and take
ction on other oil and gas program related enforcement measures.
South Dakota has not been delegated NPDES authority. Two of the
active wells have NPDES permits because of beneficial use associated with
wastewaters. Draft NPDES permits are prepared by the State and issued
by the Water Management Division, U.S. Environmental Protection Agency,
Region VIII.
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In the event of a desire to drill on Federal lands, two applications
for drilling would be filed -- one with the State Department of Water and
Natural Resources, and one with the U.S. Bureau of Land Management. The
State would defer to the Bureau regarding any pre-drilling permit
investigation. Two permits, one from each entity, would be issued to the
driller. In the event of a request to inject drilling fluids
underground, the Bureau would defer to the State, and the State would
issue the injection permit. The Bureau has no means of holding
hearings, and the State Board of Minerals and Environment would hold such
hearings prior to permit issuance.
The South Dakota Department of School and Public Lands has
enforcement powers for lease compliance on State-owned lands and for
State-owned minerals.
State Rules and Regulations
Drilling
When drilling operations cease, supernatant in the drilling pit is
allowed to evaporate and the mud is allowed to dry. The time interval
for this to occur is a various and unknown factor. When the mud has
sufficiently dried, the pit is buried and the surface is reclaimed to
natural conditions.
The Department of Water and Natural Resources requires a Plugging
and Performance Bond for wells, and a Surface Restoration Bond.
Production
Discharge of produced wates is permitted to total retention-
evaporation ponds, to Class II DIG wells, and for beneficial
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use. There are no specific requirements related to pit construction,
but the state is currently giving consideration to a proposal to require
that pits have liners or be of impermeable construction.
Discharge of brine from oil well production is allowed when a
beneficial use of the water can be documented. An NPDES permit is
required for such discharge. The two NPDES permitted discharges from
wells in South Dakota are used for stock watering. NPDES permits
contain not-to-exceed limits for oil and grease of 10 mg/1, total
dissolved solids of 5,000 mg/1, and a pH of 6.0 to 9.0. The flow is not
to exceed 4,500 gallons per day.
Offsite and Commercial Pits
There are no offsite pits in use, but if there were a request for
such usage, the request would be managed through the solid waste
permitting process.
Plugging Abandonment
A well may be classified as temporarily abandoned for a period of
six months for good cause, and this status may be extended on a case-by-
case basis.
Wells must be plugged when they can no longer fulfill the purpose
for which they were drilled. Plugging must follow scheduling and
requirements approved by the state geologist.
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References
Summary of State and Statutes and Regulations for Oil and Gas
Production. 1986. Interstate Oil and Gas Commission (June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil Compact
Commission (December).
Pirner, S. M. 1986. Letter Communication to EPA. South Dakota
Department of Water and Natural Resources, Office of Water Quality.
Personal Communications:
Steven M. Pirner, DWNR, Office of Water Quality (605) 773-3351.
Fred V. Steece, DWNR, Supervisor of Oil and Gas Program
(605) 394-2385.
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Tennessee
Introduction
Tennessee produced about 937,000 barrels of oil from 798 wells in
1984. Only 54 oil wells produced more than 10 barrels of oil per day .
Of 507 gas wells, 474 produce less than 60 thousand cubic feet per day.
Regulation of oil and gas drilling operations began in 1968. Wells
drilled prior to 1968 do not have to be permitted unless they are
deepened, reopened, or reentered.
State Regulatory Agencies
Three agencies regulate oil and gas activities in Tennessee:
- State Oil and Gas Board
- Tennessee Department of Health and Environment
- U.S. Department of the Interior, Bureau of Land
Management
The State Oil and Gas Board of the Tennessee Department of
Conservation is authorized by the Tennessee Code Annotated (Revised 1982)
to regulate activities related to the production of oil and gas in
Tennessee. The State Oil and Gas Board regulates the industry according
to the General Rules and Regulations (Tennessee State Oil and Gas Board
Statewide Order No. 2). The State Oil and Gas Board issues drilling
permits and regulates surface disposal.
The Department of Health and Environment is the NPDES authority in
Tennessee. They do not currently have UIC primacy, but are working
towards being granted primacy by EPA. Discharges of oil and gas wastes
are not permitted by the Tennessee Department of Health and Environment.
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The U.S. Bureau of Land Management has jurisdiction over lease
arrangements and post-lease activity on Federal lands where the mineral
rights are Federally held. Surface rights in Federal forests and
grasslands are retained by the U.S. Forest Service.
State Rules and Regulations
Drilling
Much of the drilling in Tennessee is air drilling. The types of
wastes most commonly in drilling pits are foaming agents used during the
drilling process and spent acids from well treatments.
Before an applicant can complete the permit process and begin to
drill, one of the Board's inspectors must approve all pollution control
structures, including pits, dikes, diversion drainage ditches, and
tanks. In addition, during drilling, inspectors are required to monitor
casing programs, particularly with respect to circulation of cement
behind the surface casing to reduce the likelihood of groundwater
contamination.
The Board requires operators to drain surface pits of water and back
fill them with dirt immediately after they are no longer needed for
drilling or testing.
Produced Water
Produced saltwater may be disposed of by discharge into an
evaporation pit, by annular injection, or by disposal into a dedicated
disposal well. In addition, produced water could be used for injection in
an enhanced recovery project. The use of evaporation pits is acceptable
where both the method and the pit have been approved by a representative
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of the Board. According to information provided by the Board, it is now
the policy of the Board to require the lining of pits, particularly in
areas where brine will be the major constituent of the fluids in the pit.
The policy was adopted to prevent contamination of groundwater from
percolation of pit fluids.
An operator may obtain a permit for annular disposal of produced
water for a year. Water injected into the annulus must not be allowed to
enter formations with oil, gas, or fresh water.
PIugging/Abandonment
Dry wells must be plugged within six months after drilling is
finished, with an extension of 90 days for good cause. Gas wells which
pass a deliverability test may be classified as shut-in indefinitely.
Wells no longer used for the purpose they were drilled or converted must
be plugged. Wells which are neither producing nor plugged must be cased
and capped to protect oil, gas, and fresh water. Cash bonds are required
for all wells being temporarily abandoned.
When plugged, wells must be filled with sufficient mud to offset the
hydrostatic pressure of any formation penetrated. Sufficient plugs must
be placed to prevent commingling of fluids and to isolate extractable
minerals.
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References
Zurawski, Ronald P. "1985 EPA Onshore Oil and Gas Workshop
Request for Information on Tennessee Activity and
Technology," circa mid-1985.
State of Tennessee - State Oil and Gas Board. "General Rules
and Regulations, Statewide Order No. 2," Effective
November 1972.
Zurawski, Ronald P. Drilling Waste Conference submittal, circa
mid-1985.
State of Tennessee State Oil and Gas Board. "Oil and Gas Laws
in Tennessee and Mineral Test Hole REgulatory Act, "
Amendments added 1982.
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TEXAS
Introduction
In 1985, Texas produced over 830 million barrels of oil from over
210,000 wells. Gas production was 5,805 billion cubic feet from 68,811
gas wells. It is estimated that 75 percent of all active Texas wells are
marginally-producing wells.
Regulation of the oil and gas industry in Texas began when the
Railroad Commission was assigned jurisdiction over oil and gas activities
in 1919.
Regulatory Agencies
The following agencies have jurisdiction over the disposal of oil and
gas wastes in Texas:
- Railroad Commission of Texas
- Texas Air Control Board
- Texas Parks and Wildlife Department
- U.S. Corps of Engineers
U.S. Environmental Protection Agency
Oil and gas activities in Texas are regulated almost entirely by the
Oil and Gas Division of the Railroad Commission of Texas. Unlike many
State oil and gas commissions, the Railroad Commission is responsible for
both prevention of waste and for preventing pollution. Thus one agency
is responsible for well spacing, construction requirements (casing,
etc.), and most aspects of environmental protection.
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In 1985, the Texas legislature amended Section 91.101 of the Natural
Resources Code to make explicit the scope of authority of the Railroad
Commission with respect to activities related to the exploration,
development and production of oil and gas, as well as Section 26.131 of
the Water Code. It specified that production activities included all
activities associated with the storage, handling, reclamation, gathering,
transportation or distribution of oil and gas prior to the refining of
the oil or the use of the gas (including activities associated with
natural gas and natural gas liquid processing plants). It also
specifically included within the jurisdiction of the Commission the
drilling of injection-water source wells which penetrate the base of
useable quality water. These wells produce water to be used in enhanced
recovery injection wells. The major change in the statute was the
specification of activities which were to be considered related to
"production."
Statewide Rule 8 (governing "water protection") of the Railroad
Commission was amended on January 6, 1987 to incorporate these changes in
the Natural Resources Code.
The Railroad Commission issues permits for any discharges related to
oil and gas exploration, development and production activities. Since the
state does not currently have NPDES jurisdiction, such discharges are
also subject to EPA permitting.
The Railroad Commission has jurisdiction over Class II underground
injection wells. The Railroad Commission is currently evaluating the
need for a Class I well program. The Commission has jurisdiction over
the injection of gas plant wastes which may need to be injected into a
Class I well if they are not sufficiently diluted by produced water to
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allow injection into a Class II well. Currently, all Class I wells are
regulated by the Water Commission, and gas-plant wastes are subject to
Class II requirements.
The Texas Air Control Board has jurisdiction over the regulation of
oil field activities generating air emissions.
The Texas Parks and Wildlife Department, Pollution Surveillance
Branch, investigates fish kills and water pollution complaints and
evaluates the effects of discharged wastes on fish and wildlife. The
Texas Parks and Wildlife Department has statutory authority to recover
the monetary value of damaged fish and wildlife. The Parks and Wildlife
Department may also enforce the Texas Water Code when permit violations,
discharges in excess of permit limitations, or discharges without a
permit occur.
- The Texas Railroad Commission has jurisdiction over oil and gas
activities on Federal lands in Texas, regardless of who owns the mineral
rights.
The U.S. Corps of Engineers has permitting responsibility for any
activities which would affect wetlands subject to Section 404 of the
Clean Water Act.
State Rules and Regulations
General: Texas Statewide Rule 8 prohibits any "person conducting
activities subject to regulation by the [Railroad] Commission" from
causing or allowing pollution of surface or subsurface waters in
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Texas. With limited exceptions (e.g., landfarming or burial of
drilling fluids under specified conditions), "no person may dispose
of oil and gas wastes by any method without obtaining a permit to
dispose of such wastes." These exceptions are authorized under Rule
8, along with the corresponding conditions which must be met to
fulfill the Rule's requirements. The Rule's "authorizations" thus
serve the same function as a "general permit" in some other states.
Under Statewide Rule 9, permits are required for disposal of oil and
gas waste by injection into formations not productive of oil or gas.
Statewide Rule 46 requires permits for injection into productive
formations.
Drilling
Pit Construction Permits: The Railroad Commission authorizes, by
Rule, the maintenance and use without a permit of reserve pits, mud
circulation pits, completion/workover pits, basic sediment pits, flare
pits, fresh makeup water pits, and water condensate pits, provided that
such pits are operated and closed as required by Rule 8. The use of
reserve pits and mud circulation pits for oil and gas wastes is
restricted to drilling fluids, drill cuttings, sands, silts, wash water,
drill stem test fluids, and blowout preventer test fluids.
Permits are required for drilling fluid storage pits (other than mud
circulation pits) and drilling fluid disposal pits (other than reserve
pits or slush pits), and any other pits not specifically authorized by
the Rule. For pits requiring permits, pit locations are evaluated on a
case-by-case basis to determine what construction requirements are
necessary to prevent waste of oil and gas resources or pollution of
surface water or groundwater. Proposed unlined pits which will be
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continuous use saltwater service are also evaluated to determine whether
the pit would cause pollution of surrounding productive agricultural
land. The requirements may or may not include liners.
Pit Closure: The Railroad Commission requires that pits be
dewatered, backfilled and compacted for closure. Backfill requirements
(for all types of pits) vary according to the type of pit and the
chloride concentration of the pit contents. Reserve pits (and mud
circulation pits) containing fluids with a concentration of over 6,100
mg/1 chloride must be dewatered within 30 days of cessation of drilling
operations. Reserve pits containing fluids with a concentration of 6100
mg/1 or less must be dewatered within a year. In both cases, backfilling
must be carried out within a year of the cessation of drilling
operations. Because of dewatering time limits, reserve pit fluids may
need to be hauled offsite for disposal.
Completion/workover^pits must be dewatered within thirty days and
backfilled and compacted within 120 days of cessation of
completion/workover operations.
Disposal: The Railroad Commission permits treatment and discharge of
reserve pit fluids to land or to surface waters provided
that the discharge does not cause a violation of Texas water quality
standards. The Rule does not specify what processes constitute
acceptable treatment technologies. The applicant for a permit may choose
the technology, but must provide proof that the selected technology will
meet the Commission's criteria. The criteria for discharges to surface
waters are:
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- Chemical oxygen demand < 200 mg/1
- Total suspended solids < 50 mg/1
- Total dissolved solids < 3000 mg/1
- Oil and grease < 15 mg/1
- Chlorides (coastal) < 1000 mg/1
- Chlorides (inland) < 500 mg/1
- pH 6.0 to 9.0
- 24-hour bioassay in accordance with procedure developed by Texas
Parks and Wildlife Department
- Water color must be adjusted to match the receiving stream
- Volume of the discharge must be "controlled so that a minimum
5:1 dilution of the wastewater by the principal receiving stream
is maintained."
- Discharge cannot exceed concentrations of hazardous metals as
defined by Texas Water Development Board Rules 156.19.15.001 -
.009.
In coastal areas, if the receiving body of water has concentrations
of TDS or chlorides in excess of 3,000 mg/1 or 1,000 mg/1 respec/tively,
then the concentration of the treated reserve pit fluids may exceed those
limits, but may not exceed the levels in the receiving water body at the
point and time of discharge. In such cases the effluent must be piped to
the receiving water body.
Rule 8 authorizes landfarming or burial of water-based drilling
fluids and associated wastes which meet specific conditions. The
authorizations do not extend to oil-based drilling fluids, which require
a permit for disposal.
The authorization for landfarming applies where water-based drilling
fluids have a chloride concentration equal to or less than 3,000 mg/1.
Under the authorization, the wastes must be disposed of on the same lease
where generated, and the operator must have the written consent of the
landowner. Landfarming encompasses sprinkler irrigation, trenching,
injecting under the surface, discing, and surface spreading by vehicles;
the waste must be applied in such a way that it will not migrate off the
landfarmed area.
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Where the water-based drilling fluids have a chloride concentration
in excess of 3,000 mg/1, but the wastes have been dewatered, burial is
authorized at the well site where the waste is generated.
One-time disposal of reserve pit fluids down the annulus of a well is
allowed, but requires a "minor permit" for each disposal incident.
Produced Fluids
More that 90% of produced waters are disposed of by injection, with
most of the remainder disposed of in coastal ("tidally influenced")
waters. Less than 1% is disposed of in pits.
Pits: Individual permits are required for brine pits, collecting
pits, skimming pits, emergency saltwater storage pits, and saltwater
disposal pits.
A 1984 amendment to Rule 8 required the re-permitting or closure of
all previously-permitted lined or unlined pits for the storage or
disposal of oil field brines. The 1984 amendment also required the
permitting of other types of pits which did not have to be permitted
prior to the amendment. With the exception of emergency saltwater
storage pits, permits for unlined pits will only be granted if the
operator can "conclusively" show that "use of the pit cannot cause
pollution of surrounding productive agricultural land nor pollution of
surface or subsurface water." Since the amendment, the Railroad
Commission has received approximately 8,900 permit applications for all
types of pits, half of which are for emergency saltwater storage pits
used in connection with injection and storage wells. Of the 8,900
applications, 2,675 are for pits that were permitted prior to the
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amendment. As of December 1, 1986, the Commission had received 388
applications for saltwater disposal pits (unlined, because of the need
for both evaporation and percolation for disposal purposes); 13 were
approved, 233 denied, with the rest still under consideration. Approvals
were largely for low-chloride (<500 ppm chloride) produced waters in
areas where there was no possible impact on fresh subsurface water. The
Commission expects to complete the processing of the 8,900 applications
by late 1988.
Lining requirements are determined on a case-by-case
basis. Generally, all continuous-use pits (e.g., skimming pits) would
require linings. Emergency saltwater storage pits in sandy soils would
also require linings. Specific lining/monitoring requirements would be
determined on a case-by-case basis.
In.lection: Class II injection wells are used both for enhanced
recovery (36,368 wells) and disposal (16,404 wells). Requirements for
Class II enhanced recovery wells are found in Rule 46 of the Texas
Railroad Commission; requirements for Class II disposal wells are found
in Rule 9.
The Commission requires that a newly drilled Class II injection well
have surface casing cemented to the surface. Rule 9 requires that the
well shall be equipped with tubing set on a mechanical packer, set no
higher than 100 feet above the top of the permitted injection interval.
Mechanical integrity tests must be conducted before injection begins,
and at least once every five years thereafter. Most mechanical integrity
tests are pressure tests. Test pressures must equal the maximum
authorized injection pressure or 500 psig, whichever is less, but in no
case less than 200 psig. Tests are acceptable if the test is conducted
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at a pressure within 10% of the pressure required by the formula.
However, once the casing pressure stabilizes, the test must be conducted
for 30 minutes with no variation.
Specifications under Rule 46 are identical with respect to casing,
the requirement for using tubing and packer, and mechanical integrity
tests. The required setting for the packer is no higher than both 200
feet below the known top of cement behind the long string casing and 150
feet below the base of usable quality water.
Surface Discharge: The Railroad Commission allows discharge of
produced water into coastal areas under individual permits. Sufficient
collecting and skimming pits must be maintained to prevent any oil from
entering the tidal waters. Random samples of the discharged brine must
be tested for oil content every 30-40 days.
Offsite Facilities
Transportation: Transporters of produced water (other than by
pipeline) must hold a Salt Water Hauler Permit from the Railroad
Commission. Haulers must keep a record of the volume of water
transported, the property from which it originated, and the amount
delivered to which specific disposal facility. Similar records must be
kept by the producer. No similar requirements are imposed on transport
of dril1 ing fluids.
Disposal: All offsite disposal of oil and gas wastes requires
individual permitting. The primary offsite facilities in Texas are
disposal wells which receive materials by truck. There are approximately
200 Class II commercial wells in Texas.
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In addition, there are approximately 100 central disposal pits for
drilling fluids, 50-75 central drilling fluid landfarming facilities, and
a few facilities for treatment and discharge of drilling fluids in
coastal areas. Management requirements for these facilities are
determined on a case-by-case basis.
Plugging/Abandonment
Plugging procedures for dry or inactive wells which cease drilling or
operations between January 1, 1986 and January 1, 1988 must commence
within one year of the cessation of operations. (For other wells, the
limit is 90 days). In addition, a further reasonable extension of time
is available at the discretion of the Director of the Oil and Gas
Division if the well does not present a pollution hazard, and the
operator has posted a performance bond, or if a well is in an enhanced
recovery operation, and the operator has presented a viable plan for
further use of the well within a reasonable time period.
A well plugging fund has been established to enable the state to plug
abandoned wells. The major source of funding is provided by a $100
drilling permit fee for each new well.
Cement plugs shall be set by the circulation or squeeze method
through tubing or drill pipe, and shall have sufficient volume to fill
100 feet of hole plus 10% for each 1,000 feet of hole from the ground
surface to the bottom of the plug. All portions of the well not filled
with cement must be filled with mud-laden fluids of at least 9.5
Ibs./gallon.
For wells with surface casing, plugging requirements depend on
whether the surface casing is set to protect all usable water quality
strata. Where it does, a cement plug shall be set which extends from at
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least 50 feet below to 50 feet above the shoe of the surface casing.
Where the casing has been set deeper than 200 feet below the base of the
deepest usable water strata, an additional plug, within the casing, must
extend from at least 50 feet below the base to at least 50 feet above the
top of the lowest such stratum. Where the casing does not afford such
protection, a similar plug must be placed across the shoe of the surface
casing, and another plug from at least 50 feet below the base to at least
50 feet above the top of the lowest usable water stratum.
For wells with intermediate or production casing which has been
cemented through all usable water quality or productive horizons, a
cement plug shall be placed inside the casing and extend from at least 50
feet below the base to at least 50 feet above the top of the deepest
usable water quality stratum. Where such casing has not been cemented
through all strata and horizons, the casing shall be perforated at the
required depths to place cement outside the casing by squeeze cementing.
A plug shall also be wet above each perferated interval or open hole
completion.
For wells without production casing and open hole completions,
productive horizons or formations in which pressure or formation water
problems exist shall be isolated by plugs centered at the top and bottom
of the formations. Such plugs are to be continuous if the formation is
less than 100 feet thick.
.The District Director may require additional plugs to cover and
contain any productive horizon or to separate any water stratum from any
other water stratum if the water qualities or hydrostatic pressures
differ sufficiently to justify separation.
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References
Railroad Commission of Texas, Oil and Gas Division. Rules Having
Statewide Application to Oil Gas and Geothermal Resource Operations
Within the State of Texas, September 1985.
Interstate Oil Compact Commission, The Oil and Gas Compact Bulletin,
Volume XLIV, Number 2, December 1985.
Railroal Commission of Texas, Oil and Gas Division. Annual Report - 1985.
Railroad Commission of Texas, Oil and Gas Division. Water Protection
Manual, April 1985.
U.S. Environmental Protection Agency, Proceedings - Onshore Oil and Gas
State/Federal Western Workshop, December 1985.
"Texas Surface Water Quality Standards," TDWR Publication LP-71.
Railroad Commission of Texas, "Application Information - Casing/Annul us
Disposal of Drilling Fluid." Not dated.
Railroad Commission of Texas, Letter communication to EPA, October 1985.
Personal Communications:
William H. Barnes, Texas Railroad Commission, (512) 463-6790
Windle J. Taylor, Texas Railroad Commission, (512) 463-6803
Lori Wrotenbery, Texas Railroad Commission, (512) 463-6769
20
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Utah
Introduction
Utah produced 38,053,871 barrels of oil from 1,862 wells in 1984.
Approximately 20 percent of these wells are stripper wells. Utah
produced 183,061,947 MCF of gas from 728 gas wells in 1984. This gas
production volume includes recycled injection gas attributed mainly to
pressure maintenance operations at the Anschutz Ranch East field. Any
discharge of produced water onto roads is prohibited.
State Regulatory Agencies
Four agencies share regulatory responsibility for oil and gas
activities in Utah:
- Utah Department of Natural Resources, Division of Oil, Gas, and
Mining
- Department of Health, Bureau of Water Pollution Control
- U.S. Bureau of Land Management (and possibly the Bureau of Indian
Affairs)
- U.S. Forest Service (surface rights only)
The Division of Oil, Gas, and Mining adopted new Oil and Gas
Conservation General Rules effective December 2, 1985. These rules cove
drilling and operating practices, UIC Class II responsibility, and rules
governing purchasing, transportation, refining, and rerefining. The
Department of Health currently has regulatory authority over disposal
ponds. The Department of Oil, Gas, and Mining is hoping to bring most
aspects of oil and gas regulations under one agency by assuming authority
for disposal ponds in the near future.
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The U.S. Department of the Interior, Bureau of Land Management, has
jurisdiction over lease arrangements and post-lease activity on Federal
lands where the mineral rights are Federally held. Surface rights in
Federal forests and grasslands are retained by the U.S. Forest Service.
State Rules and Regulations
Drilling
Rule 308 of the Division of Oil, Gas, and Mining rules requires oil
and gas operators to "take all reasonable precautions to avoid polluting
streams, reservoirs, natural drainage ways, and underground water." This
requirement is supported by a specific rule for reserve pits (Rule 309).
"Salt water and oil field wastes associated with the drilling process
may be disposed of by evaporation if impounded in excavated earthen
reserve pits underlain by tight soil such as heavy clay or harden or
lined in a manner acceptable to the Division." Pit liquids are not
allowed to escape onto the land surface or into surface waters.
Since most of Utah has very rapid evaporation rates, the reserve pit
supernatant is generally allowed to evaporate before pit closure. Final
pit closure requirements were not found in the rules.
In areas of net precipitation,, or in areas where pit construction
is especially difficult (i.e., steep mountain sides), the Division may
allow the reserve pit supernatant to be disposed down the annulus of the
new well into a properly confined zone of poor quality. This
determination is made by the Division of Oil, Gas and Mining on a case-by-
case basis.
The Division of Oil, Gas, and Mining has extensive technical rules
regarding well siting, casing requirements, and well drilling.
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Production
Most produced water is injected for water flooding or for disposal.
Utah has approximately 560 Class II injection wells, including about 45
active disposal wells. The Division of Oil, Gas, and Mining controls
injection wells and onsite disposal facilities.
The Utah Department of Health regulates surface disposal of produced
wastes from gas and oil wells. No pond is allowed to discharge to the
surface (land or water). Construction requirements specify that pits
must be protected from intrusion of surface water, be constructed of
impervious materials, and be located at least 5 feet above groundwater.
Pits must be properly located above ordinary high water marks for surface
wastes. Pits may not located within 200 feet of a fault or at the
*
bottom of creeks, rivers, or natural drainages.
Surface disposal into unlined ponds is allowed if the wastewater
contains less than 5,000 mg/1 total dissolved solids, and if the
wastewater does not contain "objectionable or toxic levels of any
constituent as shown by chemical analyses." This requirement is waived
for sites discharging less than 5 barrels of water per day. Small
dischargers into unlined pits are required only to notify the Department
of Health with minimal site information. Application for approval to
Onsite disposal facilities are presumed to include onsite evaporation
pits. The Division of Oil, Gas, and Mining rules do not include
specific guidance regarding onsite disposal facilities; however,
their reserve pit guidance is probably applied to produced water pits
as well. There appears to be some overlap in authority for onsite
pits between the Utah Department of Health and the Division of Oil,
Gas and Mining.
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discharge into unlined pits must include an estimate of waste volume,
estimate of percolation and net evaporation rates, and information about
freshwater aquifers within a one square mile radius of the proposed site.
For disposal ponds without artificial liners which receive more than
100 barrels per day , the Department of Health requires a monitoring
program including monitoring wells.
For artificially-lined ponds, the Department of Health requires "an
underlying gravel-filled sump and lateral system, or other suitable
devices for detection of leaks." The Department of Health, Bureau of
Water Pollution Control, is considering a requirement that all ponds
(lined or unlined) be equipped with a leak detection system. In general,
the Bureau feels that pit siting is more important than construction
requirements. Any discharge of produced water onto roads is prohibited.
All injection wells must be operated to prevent damage to drinking
water or other resources, and to confine injected fluids to the approved
interval. The application for an injection well must include information
on all other wells within a half-mile area of the proposed injection
well. It must also provide adequate evidence that the proposed injection
pressures will not result in fracturing of the confining interval that
could enable injected or formation fluids to migrate out of that
interval. Before injection begins, the operator must use a pressure test
to test the casing. The test must be at the greater of 300 psi or the
maximum authorized pressure (for a new well), with a ceiling of 1,000 psi
(for a converted well). Subsequent pressure tests must be administered
every five years (except that, in lieu of pressure tests, the operator
may monitor and report on the pressure in the casing-tubing annulus on a
monthly basis, or use other test methods approved by the Division).
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Plugging/Abandonment
No time limit is established for temporary abandonment of a well. A
well is temporarily abandoned if operations have ceased, intervals open
to the well bore have been properly sealed with a cement plug or bridge
plug, and there is no migration of fluids.
When plugging, cement plugs must be placed above each producing
formation (100-foot length), from 50 feet below to 50 feet above the
fresh water zone (or 100-foot plugs centered at the base and top of the
zone), at the base of the surface casing (50-foot), and centered across
the casing stub if any casing is cut and pulled (100-foot, along with a
second plug the same length centered across the casing shoe of the next
larger casing). At least 10 bags of cement shall be placed at the surface
completely plugging the entire hole (including all annuli, if more than
one string of casing remains at the surface). Perforated intervals must
be plugged with cement. Intervals between plugs must be filled with a
noncorrosive fluid of adequate density to prevent migration.
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References
Interstate Oil Compact Commission, The Oil and Gas Compact Bulletin.
Volume XLIV, Number 2, December 1985.
U.S. Environmental Protection Agency, Proceedings - Onshore Oil and Gas
State/Federal Western Workshop, December 1985.
Hunt, Gil. Letter to Ms. Susan de Nagy with attachments dated
September 20, 1985.
Swindel, D. B. Letter to Kerri Kennedy with attachments dated
June 6, 1986.
"The Oil and Gas Commission General Rules," effective December 2, 1985.
Utah Water Pollution Control Committee, State of Utah, Department of
Health, Division of Environmental Health, Wastewater Disposal
Regulations -- Part VI Surface Disposal of Produced Water from Gas
and Oil Wells, January 20, 1982.
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V i rg i n i a
Introduction
Virginia produced 26,654 barrels of oil from 41 producing oil wells
and 15,041,438 (mcf) cubic feet of gas from 495 gas wells in 1985.
State Regulatory Agency
One agency principally regulates oil and gas activities in Virginia:
Virginia Department of Mines, Minerals, and Energy/Division of
Mines - Oil and Gas Section
The Oil and Gas Section is governed by the Virginia Oil and Gas Act
and by the Rules and Regulations for Conservation of Oil and Gas
Resources and Well Spacing. These Rules and Regulations were adopted by
the Virginia Oil and Gas Conservation Commission, the Virginia Well
Review Board, and the Chief of the Division of Mines and Quarries (DMQ)
and issued by the Virginia Department of Labor and Industry in 1983. In
1985, a reorganization of state government created the Department of
Mines, Minerals and Energy (DMME). This resulted in the shift of DMQ,
now referred to as the Division of Mines, from Labor and Industry to
DMME. The Oil and Gas Section issues drilling permits and regulates the
details of the industry through this process. The State does not have
primacy for the UIC program Class II wells, but there is no underground
injection of fluids currently associated with the Virginia industry.
There has been drilling on Federal lands, but such lands are owned by the
National Forest Service and the Service serves as another surface
landowner in such drilling activity. The Service would manage their
concerns principally through the surface lease process. The Virginia
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Water Control Board would become involved only in the event of an
incident that potentially could affect surface water quality.
State Rules and Regulations
Drilling
All disturbance to the land associated with the development of the
drilling site, including the construction of pits and access roads, must
comply with standards set down in the Virginia Soil and Erosion Control
Handbook.
Pits associated with the drilling of a well must prevent water
pollution. It is the policy of the Oil and Gas Section that drilling
pits must be lined with a plastic liner. After drilling is complete,
liquids in the pits may be treated,primarily to adjust pH, and land
applied solids are buried in the pit. The drill site and any associated
pits must be reclaimed within 1 year after drilling ceases.
In general, there is little fluid associated with the drilling
process in Virginia. Such fluids as may be present are not high in
chloride concentration. Generally, the fluid is tested by the driller,
the pH is adjusted if necessary, and the water is sprayed on the
surrounding land. Pit muds are buried on site and the pit area reclaimed,
Production
No pit may be used for the ultimate disposal of salt water. [Part
III, Regulation 3.09(e) for Conservation of Oil and Gas]. Salt water
must be periodically drained or removed, or properly disposed of from
any pit in which it is retained.
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Almost no fluid is associated with gas production in Virginia. Very
small amount of fluids are produced with the 100 gallons of oil produced
per day statewide. As a result, produced wastes generally are held in
steel tanks. Dikes are required around the tanks, and fluids generally
are allowed to flow into the diked area, where they disappear through
evaporation and infiltration .
Offsite and Commercial Pits
No use is made of offsite and commercial pits in Virginia.
PIugg i ng/Abandonment
Under the Virginia Oil and Gas Act, operators are required to
immediately plug a well "upon the abandonment or cessation of operation"
of that well. Where there is good economic cause, however, gas wells may
be capped for an indefinite period.
Different plugging requirements exist for wells, depending on
whether they penetrate coal seams and, if they do, with or without coal
protection string. Cement plugs are required 20 feet above each oil, gas,
or water-bearing stratum, and 10 feet below the bottom of the largest
casing left in the well. Mud, clay or another nonporous material is to
fill all spaces in the well not filled by plugs. Additional requirements
are made for perforations which cannot be readily filled by the above
methods, and for the protection of coal seams.
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References
Summary of State Statutes and Regulations for Oil and Gas
Production. 1986. Interstate Oil and Gas Commission
(June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil
Compact Commission (June).
Personal Communication:
James Henderson, State Oil and Gas Inspector (703) 628-
8115.
William Edwards, Department of Mines, Minerals and Energy
(804) 257-0330.
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WEST VIRGINIA
Introduction
West Virginia produces about 3.6 million barrels of oil and 7.5 BCF
of gas per year from 15,895 wells. Gas production of 142.5 billion cubic
feet annually is realized from 32,500 gas wells. Between 1,800 and 2,500
drilling permits are issued annually, although the number of wells
drilled dropped in 1986.
Regulatory Agencies
Two agencies now regulate oil and gas activities in West Virginia:
- West Virginia Department of Energy, Oil and Gas Division
- U.S. Bureau of Land Management
The West Virginia Energy Act, passed on April 12, 1985, created the
West Virginia Department of Energy, and vested in the Department
jurisdiction over oil and gas activities (as well as other energy-related
activities) in the state. The Department has assumed the
responsibilities previously carried out by the Department of Mines,
Office of Oil and Gas, and is in the process of assuming relevant program
responsibilities from the Department of Natural Resources, Water
Resources Division. Among the programs which are to be transferred,
after approval by EPA, are those aspects of the delegated NPDES,
underground injection and hazardous waste programs which bear on oil and
gas exploration, development and production. Pending re-delegation by
EPA, the Department of Natural Resources is still the lead agency for
these activities, and the Department of Natural Resources and the
Department of Energy are cooperating on the environmental regulation and
oversight of the oil and gas production industry.
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Within the Department of Energy, the Division of Oil and Gas has
responsibility for the regulation of the State's oil and gas industry.
The Division has new regulations which have been approved by the state
legislature. The regulations will go into effect, about June 14, 1987.
The regulatory requirements summarized below describe these rules.
The U.S. Bureau of Land Management has jurisdiction over lease
arrangements and post-lease activity on Federal lands. Their rules are
discussed in a separate section on Federal Agencies. The U.S. Forest
Service retains surface rights for Federal forests and grasslands. The
Service coordinates surface stipulations with the Bureau of Land
Management where applicable.
State Rules and Regulations
Drilling
Pit Construction/Management: Each pit used for drilling wastes is
subject to the terms of a general West Virginia NPDES permit for
construction, management and discharge. The general permit was first
established by the Division of Water Resources of the Department of
Natural Resources on July 10, 1985. The requirements in the general
permit are also found in the proposed Department of Energy regulations.
Pits must be constructed "to prevent seepage, leakage or overflows"
and maintain integrity. If an operator is unable to maintain adequate
freeboard to prevent overflows, he must build an additional pit. There
is no liner requirement, but there is a stipulation that where the soil
"is not suitable to prevent seepage or leakage, other materials which are
impervious shall be used as a liner for a pit." Unlined dikes must be
free of large rocks, trees or other growth which could damage the pit's
integrity.
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During operation of the pit, it is prohibited to dump into the pit
production brine, unused frac fluid or acid, compressor oil, refuse,
diesel, kerosene, halogenated phenol, or drilling additives prepared in
diesel or kerosene.
Pit Closure: Pits are to be filled within six months after the
cessation of drilling. The drill cuttings may be buried on site, after
disposal of liquids.
Disposal: Treated wastewaters generated during drilling, reworking
and treatment of wells may be discharged for land application on-site,
subject to the following limitations:
pH 6.0 - 10.0
total iron 6 mg/1
chloride 25,000 mg/1
free or floating oil no visible sheen on land
In addition, monitoring is required for TSS, dissolved oxygen,
manganese, conductivity, settleable solids, and total organic carbon.
Required treatment includes pH adjustment, aeration and extended
settling for at least 10 days. Free or floating oil shall be skimmed off
and removed from the pit before treatment and, if observed, before
discharge. Land application may not be carried out on saturated, frozen,
impermeable, or unvegetated land, and must be at a rate that will not
cause ponding or erosion. To prevent discharge of sludge, there must be
a discharge device on the pit that ensures that the discharge will be
from near the surface of the pit water level.
Discharge onto property off the drilling site requires both a permit
and the permission of the landowner.
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Produced Waters
The Department of Energy regulations, beyond prohibiting the
placement of produced saltwater in the drilling pits, specify that when
such water is produced it must be "contained in sump pits no larger than
necessary for the purpose." There is no general permit for land
discharge of saltwater, and discharge into waters of the State is
prohibited. Saltwater may be injected into Class II wells. (For figures
on actual disposal patterns, see the section on current management
practices.) There is no prohibition against use of brines on roads, and
this possibility is currently undergoing research.
Injection: Class II injection wells are permitted both for enhanced
recovery (529 wells) and disposal (53 wells).
Injection shall be through a tubing and packer arrangement, with the
packer set immediately above the injection zone. The annulus must be
monitored by pressure-sensitive device. Injection pressure must be
regulated to minimize the possibility of fracturing the confining
strata. "Disposal into the same formation from which the water is
produced is preferable."
Mechanical integrity tests for injection wells are made at one-and-
one-half to two times the injection pressure for 20 minutes, with a 5%
allowable variance.
Offsite Facilities
Wastes may be transported offsite to appropriate disposal
facilities. If these facilities discharge wastes after treatment, they
must be separately permitted.
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PIugg i ng/Abandonment
Wells completed as dry holes, or wells not in use for a period of
twelve months, are presumed abandoned, and must be "promptly" plugged,
unless the operator can prove "bona fide future use."
Cement plugs (of unspecified length) shall be set 20 feet above each
oil, gas, or water-bearing stratum (except that if such strata are not
widely separated and are free from water, they may be treated as a single
stratum). A final plug must be placed ten feet below the bottom of the
largest casing in the well. Mud, clay or other nonporous material is to
fill all space in the well from the bottom of the well (or from a
permanent bridge anchored 30 feet below the lowest stratum) to the lowest
plug, between each of the plugs, and from the highest plug to the
surface. Unfillable cavities created when strata were shot shall be
isolated by plugs placed 20 feet above and below the stratum, or a liner
shall be placed from at least 20 feet above to 20 feet below the stratum
and filled with cement.
Special additional requirements (e.g., use of expanding rather
hydraulic cement, and additional cement plugs) are imposed to protect
workable coal beds.
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References
Interstate Oil and Gas Compact Commission, History of Production
Statistics, Production and Reserves 1966 - 1985.
Personal Communication with Mr. Ted Streit, former head of Office of Oil
and Gas. September 25, 1986.
West Virginia Department of Energy, "Notice of Public Hearing and Comment
Period on Proposed Rules," not dated. Received October 1986.
Streit, T. M. Letter submitted to William A. Telliard, U. S. EPA,
May 28, 1985
West Virginia Legislative Rule Department of Energy - Division of Oil and
Gas Chapters 22-1 and 22B-1 Series 2.
West Virginia Meeting Report. 1985. Proceedings of the Onshore Oil and
Gas Workshop. U.S. EPA, Washington, D.C. (March 26-27 in Atlanta, GA).
Personal Communications:
John Johnston, Oil & Gas Division, West Virginia Department of Energy
(304) 348-3741.
Ron Shipley, West Virginia Department of Natural Resources,
(304) 348-2754.
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WYOMING
Introduction
Wyoming produced 130,984,917 barrels of oil and 597,896,000 MCF of
gas in 1985. Production is from 12,218 oil wells and 2,220 gas wells.
Fifty-two percent of the state's oil production is produced from the
20 largest fields. Twelve of those fields are 58 years old or older.
Oil, water, and gas have always been produced from these areas. The
produced water historically has been reinjected, evaporated in pits, or
discharged into drainages.
Regulatory Agencies
Three agencies regulate oil and gas activity in Wyoming:
- Wyoming Oil and Gas Conservation Commission
- Wyoming Department of Environmental Quality
- U.S.Bureau of Land Management
The Wyoming Oil and Gas Conservation Commission has general authority
over all oil and gas production in Wyoming, and the specific
responsibility to "monitor and regulate, by the promulgation of rules and
the issuance of orders, the location, operation, and reclamation of
produced water and emergency overflow pits associated with oil and gas
production." The Commission regulates industry practices and procedures
with regard to construction, location and operation of drilling and
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production pits, both onsite and offsite. The Oil and Gas Conservation
Commission is chaired by the Governor of Wyoming; four other
commissioners serve with the Governor. The Office of the State Oil and
Gas Supervisor is primarily responsible for regulation of industry
practices.
Wyoming is an NPDES-delegated State. The Wyoming Department of
Environmental Quality has NPDES authority for all discharges. DEQ also
has responsibility for permitting the construction, maintenance and
operation of commercial pits. DEQ also has authority for land
application of all types of exploration and production wastes.
The specific division of roles between the Wyoming Oil and Gas
Conservation Commission and the Department of Environmental Quality was
previously defined by a "Memorandum of Agreement" of September 13, 1983,
a memorandum from the Attorney General's office on January 18, 1982, and
an MOA dated October 14, 1981.
However, the 1987 session of the Wyoming State Legislature passed a
bill creating a new section in the Wyoming Oil and Gas Conservation
Commission Act. The new legislation gives the Commission exclusive
authority over all noncommercial oil field pits on a lease, unit, or
communitized area (except for discharges from such pits subject to NPDES
permitting). See /30-5-104(d)(VI)(A) and (B).
The Bureau of Land Management has jurisdiction over drilling and
production on Federal lands. For drilling on Federal land, BLM handles
all Applications to Drill. BLM requires extensive environmental
documentation, including environmental assessments, and develops
environmental impact statements. For produced water, the Bureau
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routinely approves discharges of up to 5 barrels/ day under NTL-2B. For
further discussion of the rules and procedures of BLM, see the section on
Federal regulations.
State Rules and Regulations
Drilling
Pit Construction/Management: Earthen pits are required to be
constructed to prevent pollution of streams, underground water, or
unreasonable damage of the surface of leased premises or other lands.
The rules do not require pit or pond liners, leak detection, or other
modifications to a simple earthen pit except where "potential for
communication between the pit contents and surface water or shallow
ground water are high." Each pit application is reviewed before approval
taking into consideration a wide variety of factors, including the soil
type on which a proposed pit is to be constructed. Quality of the
contained water, expecially the IDS level, is also an important
consideration. The State Supervisor makes this determination based on
the information presented in the permit application form. Use of
chemicals which destroy, remove or reduce the fluid seal of a reserve pit
is prohibited. Chemical or mechanical treatment of reserve pits may be
specially allowed after a public hearing before the Oil and Gas
Conservation Commission.
Workover and completion pits are exempted from permit requirements if
their use is limited to containment of oil and/or water, and they do not
contain acids or other chemical fluids. There is no requirement in the
regulations for segregation of drilling muds, produced waters or other
wastes associated with drilling or production. Practices tends to vary
significantly with the operator.
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Pit Closure: Reserve pits must be reclaimed within a year of last
use, unless the Supervisor grants a variance. After evaporation,
discharge or hauling of the liquid material in the pit, the drill
cuttings are buried on-site, and the land rehabilitated in accordance
with the landowner's wishes. Bonds guaranteeing plugging of the well and
pit reclamation are not released until the Commission has inspected and
approved the reclaimed pit and drillsite.
Discharge: Drilling fluids from reserve pits may be evaporated,
applied to road surfaces, applied to land other than road surfaces, or
hauled to a central disposal facility.
Section 326 of the rules of the Oil and Gas Conservation Commission
states: "A permit may be allowed by DEQ for one time land application of
drilling fluids. At no time will drilling fluids be discharged into live
waters or into any drainages that lead to live waters of the state."
Section 11(a) of Chapter VII of the regulations of the Department of
Environmental Quality establishes a no-discharge rule for "drilling muds
and other liquids associated with the drilling of oil and/or gas wells."
But section ll(b) allows exceptions where the operator has provided a
complete analysis of the drilling liquid, the volume and location of
discharge, and the name of the receiving water; DEQ has determined that
the discharge would not cause significant environmental damage or
contamination of public water supplies; and the landowner has agreed.
During the period 1983 to 1985, DEQ approved 21 permits for
application of drilling fluids to roads. The state does not currently
have specific road permit standards or numeric criteria. Information is
currently required on pH, conductivity and IDS contents of the wastes.
Actual concentrations of IDS in permits approved for road application of
drilling fluids during the above period varied from a few hundred to
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10,900 mg/1. A DEQ memorandum notes several criteria established in such
permits. Those that apply to drilling fluids include: limitation of
application rates to those specified in the permit; application to avoid
runoff or ponding; no application on slopes exceeding 8%, within 300 feet
of definable high water marks of drainages, irrigation canals, lakes or
reservoirs, or when the soil is saturated; and landowner approval.
During the same 1983-1985 period, DEQ issued 16 permits for drilling
fluids to be applied to land other than roads. Such permits require that
the fluids meet the criteria established in Chapter XI, Section
55(c)(ii), Part E for irrigation water quality, including:
Total dissolved solids
Chlorides
Oil and grease
Sulfates
Boron
Arsenic
Chromium
Selenium
Nickel
Zinc
Copper
Bicarbonates
pH
2100 mg/1
1500 mg/1
20,000 Ibs./acre, when soil incorporated
(surface 6 inches); 2,000 Ibs./acre when
surface applied
960 mg/1
2 mg/1
.1 mg/1
1 mg/1
.2 mg/1
-.2 mg/1
2 mg/1
1 mg/1
<50% of total anion
concentration meq/1
4.5 - 9.0
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Produced Waters
Produced waters are disposed of through injection for enhanced
recovery (c.63%), surface water discharge (c.30%), injection into
disposal wells, discharge into centralized disposal pits, discharge into
commercial disposal pits, or road application.
Disposal/Storage Pits: The Oil and Gas Conservation Commission has
jurisdiction over the permitting, construction and management of all
produced water pits on private and state lands. The Commission requires
permits for pits receiving more than 5 barrels of produced water per
day. But such permits include requirements for liners only in special
cases where "potential for communication between the pit contents and
surface water or shallow ground water is high." The Commission may
administratively approve field-wide or area-wide applications covering
earthen retaining pit construction and operation.
•i^
Pits must be kept reasonably clear of surface accumulations of oil or
other liquid hydrocarbons, and the accumulations must be cleared within
10 days when discovered. Pits must be fenced when near human habitation
or sensitive areas for wildlife or domestic stock and flagged as required.
Surface Discharge: The Wyoming Department of Environmental Quality's
Water Quality Rules and Regulations, Chapter VII, describe the rules for
discharges of produced water which could enter surface waters, as
permitted by EPA's "Agricultural and Wildlife Water Use Subcategory."
Discharge of produced water may be permitted if the following effluent
limitations are met:
Chlorides - 2,000 mg/1
Sulfates - 3,000 mg/1
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Total dissolved solids - 5,000 mg/1
pH - 6.5 - 8.5
Oil and grease - 10 mg/1
There is also a general prohibition on discharges containing toxic
substances in concentrations or combinations toxic to human, animal or
aquatic life.
Exceptions may be granted to the above limitations if a landowner
submits a "letter of beneficial use" specifically requesting that the
discharge in question be allowed to continue and indicating the specific
beneficial use and its history, or if the Wyoming Fish and Game
Department indicates the discharge is of value to fish or wildlife. This
exemption does not apply if the produced waters would be discharged to
the waters of the United States, or if the discharge would lead to a
violation of Wyoming's water quality standards.
During 1983-1985, five permits were issued by DEQ for road
application of produced waters. In addition to the road application
restrictions which apply to drilling fluids; produced water must have a
TDS concentration of greater than 5,000 mg/1 and less than 50,000 mg/1.
Injection: The Wyoming Oil and Gas Conservation Commission has
delegated responsibility for the UIC Class II program, and issues permits
for both enhanced recovery (4,548 wells) and non-commercial disposal (196
wells). Disposal wells permitted by the Commission meet the permitting
requirements of Chapter IX, Wyoming Water Quality Rules and Regulations.
For both type of well, the applicant has the burden of demonstrating at a
public hearing that the injection or disposal zone is not a source of
drinking water and by certain criteria can be exempt from protection as
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fresh and potable water. The applicant must also supply an application
for approval of use of the well for injection which includes the
following points:
a. Proof that the well is cased and cemented in such a way that
fluids are prevented from entering any zone but that exempt.
b. Evidence and data to demonstrate that operation of the well at
the proposed maximum injection pressure with proposed volumes
will not initiate fractures through the confining zone.
c. Statement detailing procedures for pressure testing the casing in
the well prior to any use.
d. A plat showing the location of all wells within a quarter mile
radius of the proposed injection or disposal well and a statement
relative to the mechanical condition or abandonment of each.
e. Affidavit showing that all surface owners and owners of interest
within a one-half mile radius of the well have been provided
notice of the proposal.
f. A geologic description of the reservoir which will receive the
fluids which includes its areal extent.
Surface casing must be run to reach a depth below all known or
reasonable estimated utilizable domestic fresh water levels. Surface
casing shall be cemented with sufficient cement to fill the annulus to
the top of the hole.
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Before beginning injection, and at least once every subsequent five
year period, the operator must test the well's mechanical integrity. In
a new well, the casing outside the tubing must be tested at a pressure
not less than the maximum authorized injection pressure, or at 300 psi,
whichever is greater. In a converted well, the test must be at the
lesser of 1,000 psi or the maximum authorized injection pressure, but no
less than 300 psi. A retrievable bridge plug or approved logging
technique will be used in casing to test tubingless completions.
Offsite Disposal
The Department of Environmental Quality permits the construction of
commercial pits. Chapter III of the Wyoming Water Quality Rules and
Regulations establishes permit processing and application requirements.
Minimum standards for pits and wells are established in Chapter XI. The
operator must demonstrate either that the facility will not allow a
discharge to groundwater by direct or indirect discharge, percolation or
filtration, or that the quality of the wastewater will not cause a
violation of groundwater standards, or that existing soils or geology
will not allow a discharge to groundwater. If the applicant cannot
demonstrate any of the alternatives, the operator may conduct a
subsurface investigation and develop a design to prevent violation of
groundwater standards. These designs may consist of leachate collection
systems, barriers with pumpback system, attenuation, or aquifer cleanup
after completion of the operation. DEQ may require a monitoring program
for such facilities.
At the present time there are 11 facilities authorized to receive
drilling fluids and produced water, and an additional 11 that are
authorized to receive produced water only.
-------
Plugging/Abandonment
A well may be temporarily abandoned, so long as the hole is cased or
left in such a manner as to prevent migration of oil, gas water, or other
substances from the formations or horizons of origin. Monthly reports
must be submitted to the Commission, and bonding requirements are kept in
force until the well is permanently abandoned. There are no restrictions
on the time period for which the well may retain such status; however,
specific approval must be obtained from the Wyoming Oil and Gas
Conservation Commission if a well is TA'd for more than one year.
Temporarily abandoned injection wells must meet the 5 year testing
requirements of the UIC program.
When wells are plugged, cement plugs of at least 100 feet must be
placed over openhole porous and permeable formations (or every 2500 feet
in lieu of such formations), over the stub of the casing left in the
wellbore, and in the base of the surface casing. Cast iron bridge plugs
set in the casing will be capped with at least two sacks of cement. Open
perforations must be squeeze cemented.
10
-------
References
Wyoming Department of Environmental Quality Water Quality Rules and
Regulations, Chapters III, VII, IX, XI
Rules and Regulations of Wyoming Oil & Gas Conservation Commission.
(January 1, 1985) Memorandum of Agreement between the Wyoming Oil and
Gas Conservation Commission and the Department of Environmental
Quality, Water Quality Division, September 120, 1983.
Personal Communications:
Ms. Janie Nelson, Wyoming Oil and Gas Conservation Commission, August
14, 1986. Telephone (307) 234-7147.
Mr. E. J. Fanning, Department of Environmental Quality, Water Quality
Division, August 11 and August 14, 1986, and March 6, 1987.
Telephone (307) 777-7781.
11
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SUMMARY OF FEDERAL REGULATIONS
A-125
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U.S. FOREST SERVICE
National Forest Systems, which include National forests and
National grasslands, are administered by the U.S. Forest Service
within the U.S. Department of Agriculture. Every application to
drill for oil and gas that impacts the above lands is reviewed by
the Service.
Where a road use permit is required, or where permit conditions
related to oil and gas drilling are appropriate, such are
conveyed by interagency communication to the Bureau of Land
Management. The Bureau issues the lease conditions at the
request of the U.S. Forest Service.
The nature of any lease condition depends upon case-by-case site
specific requirements.
Communication:
Craig Losche, U.S. Forest Service (703) 235-9873-
A-126
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BUREAU OF LAND MANAGEMENT
INTRODUCTION
Exploration, development, drilling, and production of onshore oil and gas
on Federal and Indian lands are regulated separately from non-Federal
lands. This separation of authority is significant for western States
where oil and gas activity on Federal and Indian lands is a large
proportion of statewide activity.
REGULATORY AGENCIES
The U.S. Department of the Interior is authorized by 43 CFR 3160 for
regulation of onshore oil and gas practices on Federal and Indian lands.
The Department of Interior administers their regulatory program through
State Bureau of Land Management offices. These agencies generally have
procedures in place for coordination with State agencies on regulatory
requirements. Where written agreements are not in place, the Bureau of
Land Management usually works cooperatively with the respective State
agencies.
The Bureau works closely with the U.S. Forest Service for surface
stipulations in Federal forests or Federal grasslands. This agreement is
also provided for in the Federal regulations.
RULES AND REGULATIONS
The Bureau of Land Management has authority over all aspects of oil and
gas activities on Federal lands. The authority includes leasing,
bonding, and royalty arrangements, construction and well spacing
regulations, waste handling, waste disposal, site reclamation, and site
maintenance as well as other areas. These responsibilities are extensive
and the documentation regarding them is voluminous; only those portions
of the regulations relating to waste handling, treatment, and disposal
will be summarized herein.
Historically the Bureau of Land Management has controlled oil and gas
activities through "Notice to Lessees." The requirements of current
notices are described below. The Bureau is working to revise all notices
into Oil and Gas Orders, which will be Federally promulgated. To date,
Oil and Gas Order No. 1 has been issued. Other oil and gas orders are
expected to be promulgated in the next year.
-------
DRILLING
The Bureau of Land Management considers reserve pits, and some
other types of pits, as temporary. Notice to Lessees 2B contains
the following provisions for "Temporary Use of Surface Pits:"
Unlined surface pits may be used for handling or storage
of fluids used in drilling, redrilling, reworking,
deepening, or plugging of a well provided that such
facilities are promptly and properly emptied and
restored upon completion of the operations. Mud or
other fluids contained in such pits shall not be
disposed of by cutting the pits walls without the prior
authorization of the District Engineer. Until finally
restored, unattended pits must be fenced to prevent
access by livestock and wildlife. Unless otherwise
specified by the District Engineer, unlined pits may be
used for well evaluation purposes for a period of 30
days.
Land spreading of drilling and reworking wastes by breaching pit
walls is allowed when approved by the District Engineer.
PRODUCTION
Produced waters may be disposed into the 'subsurface, either for
enhanced recovery of hydrocarbon resources or for disposal. The
operator must present detailed information regarding the proposed
disposal site, including subsurface configuration of the proposed
injection well, to the Bureau of Land Management prior to
approval to inject. This documentation is required to ensure
that the injected wastes will be confined'to a receiving
formation of poor quality. Further, the operator must identify
the sources of the produced water, must submit estimated daily
quantities of produced water, and must submit an analysis of the
water. The analysis is limited to total dissolved solids, pH,
chlorides, and sulfates.
The Bureau of Land Management also permits disposal of produced
water into lined and unlined pits. "Lined and unlined pits
approved for water disposal shall:
1. Have adequate storage capacity to safely
contain all produced water even in those
months when evaporation rates are at a
minimum.
2. Be constructed, maintained, and operated to
prevent unauthorized surface discharges of
water. Unless surface discharge is
authorized, no siphon, except between pits,
will be permitted.
A-128
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3. Be fenced to prevent livestock or wildlife
entry to the pit, when required by the
District Engineer.
4. Be kept reasonable free from surface
accumulations of liquid hydrocarbons by use
of approved skimmer pits/ settling tanks, or
other suitable equipment.
5. Be located away from the established drainage
patterns in the area and be constructed so as
to prevent the entrance of surface water."
«
For disposal into lined pits, the operator must submit:
- Site identification
- Planned waste quantities
- Net evaporation data
- Method of disposal for accumulated solids
- Information documenting the liner material
and the impervious nature of the proposed liner
• Method used for leak detection
The operator^nust submit a water analysis "which include the
concentrations of chlorides, sulfates, and other constituents
which are toxic to animal, plant, or aquatic life." Mo list of
required analytes is included in the Notice.
Leak detection is required for all lined produced water disposal
pits. The recommended detection system is an "underlying gravel-
filled sump and lateral system." Other systems may be considered
acceptable upon application and evaluation.
Oil and gas operators may be permitted to use unlined pits on any
one of the following bases: If the pit will receive 5 barrels or
less of water per day (monthly basis), no permit is required. If
the water contains less than 5,000 ppm total dissolved solids,
and does not contain "objectionable levels of any constituent
toxic to animal plant, or aquatic life," use of unlined pits is
allowed. If the water will be used for wildlife watering,
irrigation, or livestock watering, unlined pits may be used.
Unlined pits may be used when the produced water is of better
quality than surface or subsurface waters of the area. Unlined
pits permitted for surface discharges under the National
Pollutant Discharge Elimination System are also allowed.
Operators are required to provide information regarding the
sources and quantities of produced water, topographic map,
evaporation rates, estimated soil percolation rates, and "depth
and extent of all usable water aquifers in the area."
A-129
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REFERENCES
Personal communication with Mr. Steve Spector September 23,
1986.
U.S. Land Management, "Federal Onshore Oil and Gas Leasing
and Operating Regulations. Not dated.
43 CFR 3100 (entire group)
U.S. Bureau of Land Management, NTL-2B.
U.S. Department of the Interior - Geological Survey
Division. " Notice to Lessees and Operators of Federal
and Indian Oil and Gas Leases (NTL-2B)," not dated.
.A-130
-------
U.S. ENVIRONMENTAL PROTECTION AGENCY
. EFFLUENT LIMITATIONS GUIDELINES
On October 30, 1976, the Interim Final BPT Effluent Limitations
Guidelines for the Onshore Segment of the Oil and Gas Extraction
Point Source Category were promulgated. [41 FR 44942] The
rulemaking also proposed Best Available Technology Economically
Achievable (BAT), and New Source Performance Standards (Table
1).
On April 13, 1979, BPT Effluent Limitations Guidelines were
promulgated for the Onshore Subcategory, Coastal Subcategory, and
the Agricultural and Wildlife Water Use Subcategory of the Oil
and Gas Extraction Industry. [44 FR 22069] Effluent limita-
tions were reserved for the Stripper Subcategory due to lack of
technical data.
The 1979 BPT regulation established a zero discharge limitation
for all wastes under the Onshore Subcateogy. Zero discharge
Agricultural and Wildlife Subcategory limitations were
established, except for produced water which has a 35 rag/I oil
and grease limitation.
The American Petroleum Institute (API) challenged the 1979
regulation (including the BPT regulations for the Offshore
Subcategory). [661 F.2D.340(1981)] The court remanded EPA's
decision transferring 1,700 wells from the Coastal to the Onshore
Subcategory. [47 FR 31554] The court also directed EPA to
consider special discharge limits for gas wells. Table 2
provides regulatory details related to onshore oil and gas
activities.
A:-U1
-------
TABLE 1. SUMMARY OF MAJOR REGULATORY ACTIVITY
RELATED TO ONSHORE OIL AND GAS
October 13, 1976 - Interim Final BPT Effluent Limitations
Guidelines and Proposed (and Reserved) BAT
Effluent Limitations Guidelines and New
Source Performance Standards for the Onshore
Segment of the Oil and Gas Extraction Point
Source Category
April 13, 1979 - Final Rules
- BPT Final Rules for the Onshore,
Coastal, and Wildlife and Agricultural
Water Use Subcategories
- Stripper Oil Subcategory Reserved
- BAT and NSPS never promulgated
July 21, 1982 - Response to American Petroleum Institute vs
EPA Court Decision
- Recategorization of 1700 "onshore"
wells to Coastal Subcategory
- Suspension of regulations for Santa
Maria Basin, California .
- Planned reexamination of marginal gas
wells for separate regulations
AT 132
-------
TABLE 2. ONSHORE SEGMENT SUBCATEGORIES
o ONSHORE:
o BPT LIMITATION
— ZERO DISCHARGE
o DEFINED: HQ discharge of wastewater pollutants into
navigable waters from ANY source associated with
production, field exploration, drilling/ well completion,
or well treatment (i.e., produced water, drilling muds,
drill cuttings, and produced sand).
O STRIPPER (OIL WELLS):*
o CATEGORY RESERVED
o DEFINED: TEN barrels per well per calendar day or less
of crude oil.
o COASTAL
o BPT LIMITATIONS
— No Discharge of Free Oil (No Sheen)
— Oil and Grease: 72 mg/1 (Daily)
48 mg/1 (Average Monthly)
(Produced Waters)
o DEFINED: Any body of water landward of the territorial
seas, or any wetlands adjacent to such waters.
O WILDLIFE AND AGRICULTURE USE
o BPT LIMITATIONS
~ Oil and Grease: 35 MG/L (Produced Waters)
—• Zero Discharge: ANY Waste Pollutants
o DEFINED: That produced water is of good enough quality
to be used for wildlife or livestock watering or other
agricultural uses ... west of the 98th meridian.
*This subcategory does not include marginal gas wells.
A-133
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UNDERGROUND INJECTION CONTROL
The Underground Injection Control (UIC) Program was established
under Part C of the Safe Drinking Water Act (SDWA) to provide
minimum standards for procedural and technical requirements for
individual State and Federal UIC Programs. Part C of the SDWA
requires the EPA to: (1) identify a list of States for which UIC
programs may be necessary; (2) approve or disapprove, in whole or
in part, UIC programs submitted by the listed States; and (3)
develop programs and regulate those States that do not have
approved UIC programs. The Federal UIC Program is defined in 40
CFR Parts 144, 145, and 146.
Table 3 is a list of States having full or partial primacy over
their particular UIC Programs. The second column from the left
in Table 3 lists the section of the SDWA under which the States
applied for approval of their UIC Programs. The third column
from the left lists the classes of wells, defined in Table 4, for
which primacy has been given. The classes of wells that a State
can regulate depend upon the SDWA section under which a State's
authority is granted. Section 1422 was originally designed to
cover all classes of wells. Brine disposal injection wells were
later addressed specifically in Section 1425, which was created
by Congress (Dec. 5, 1980) to further define the conditions by
which these wells would be regulated. In essence, a State may
show that it has a program already in place that has been
effective in protecting underground sources of drinking water and
that includes record keeping, reporting, permitting, and
inspections authority over Federal agencies, and assurance that
authorized wells do not endanger underground sources of drinking
water.
Minimum standards for UIC programs as defined in 40 CFR 144, 145,
and 146 include, respectively, permitting requirements, guidance
to obtain approval for State primacy, and technical criteria and
standards to be met in permits and authorizations. Part 144 also
serves as part of the UIC program for States to be administered
by EPA. Part 147 lists and sets specific criteria for those
States whose UIC programs are administered by EPA.
A-134
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TABLE 3. UIC PRIMACY STATES (PROGRAMS APPROVED)
Date June 9, 1986
STATE
1425
1422
1425
1422/25
1425
1422
1422
1425
1422
1425
1425
1422
1422
1425
1422
1425
1422
1422
1422
1422
1425
1425
1422
1422
1422
1422
1422
1425
1422/25
1425
1422
1425 '
1425.
1422
1425
1422
1422
1422
1422
1422
1422
1422
1422
1422
1422
1422/25
1425
1422
1422
1422
1422
1425
CLASSES
II
i, in, rv, v
ii
I - V
ii
i, in, rv, v
i, in, rv, v
ii
I - V
ii
ii
I - V
i, in, rv, v
ii
i, in, rv, v
ii
I - V
i, HI, rv, v
i, in, rv, v
I - V
ii
ii
i, in, rv, v
I - V
i, in, rv, v
I - V
i, in, rv, v
ii
I - V
ii
i, in, rv, v
ii
ii
I - V
n
I - V
I - V
I - V
I - V
i, in, rv, v
I - V
I -V
I - V
- v
mvtv e. v
, rv, v
- v
i
, in, rv, v
- v
i, in, rv, v
I - V
ii
DATE APPROVED
December 2, 1981
January 6, 1982
February 5, 1982
April 23, 1982
April 23, 1982
June 24, 1982
July 6, 1982
August 2, 1982
September 21, 1982
October 8, 1982
November 22, 1982
November 23, 1982
January 19, 1983
February 3, 1983
February 7, 1983
February 11, 1983
May 2, 1983
July 11, 1983
July 15, 1983
July 15, 1983
August 23, 1983
August 23, 1983
August 25, 1983
August 25, 1983
August 25, 1983
September 30, 1983
December 2, 1983
December 2, 1983
December 9, 1983
February 1, 1984
Feburary 1, 1984
February 9, 1984
March 26, 1984
March 26, 1984
April 2, 1984
April 5, 1984
April 19, 1984
April 19, 1984
April 19, 1984
June 12, 1984
June 22, 1984
July 10, 1984
August 1, 1984
August 9, 1984
*-r|-«nK«r ?1 lOflil
SePwMllJBr +±t X7at
September 25, 1984
October 24, 1984
November 29, 1984
June 7, 1985
July 17, 1985
July 17, 19H5
May 6, 1986
FR errs
Oklahoma
Texas
New Mexico
Louisiana*
Texas*
Oklahoma*
Arkansas
Alabama
New Hampshire*
Utah
Wyoming
Massachusets*
Utah*
Nebraska
Florida**
California**
Guam*
New Mexico*
Wyoming*
New Jersey*
North Dakota
Ohio
Alabama*
Maine**
Mississippi**
Wisconsin*
Kansas
Missouri
West Virginia*
Illinois
Illinois*
Kansas*
Arkansas*
Connecticut*
Colorado* •
Delaware*
Maryland*
North Carolina*
Georgia*
Nebraska*
Vermont*
South Carolina*
Rhode Island*
Washington*
North Dakota*
Oregon'
South Dakota**
Ohio*
Idaho*
Missouri*
am* .
Alaska**
•Full primacy, ae of date indicated
••Partial primacy
46 FR
47 FR
47 F?
47 FR
47 FR
47 FR
47 FR
47 FR
47 FR
47 FR
47 FR
47 FR
48 FR
48 FR
48 FR
48 FR
48 FR
48 FR
48 FR
48 FR
48 FR
48 FR
48 FR
48 FR
48 FR
48 FR
48 FR
48 FR
48 FR
49 FR
49 FR
49 FR
49 FR
49 FR
49 FR
49 FR
49 FR
49 FR
49 FR
49 FR
49 FR
49 FR
49 FR
49 FR
49 FR
49 FR
49 FR
49 FR
50 FR
50 FR
50 FR
51 FR
584U3
618
5412
17487
17488
27273
29236
33263
41561
44561
52434
52705
2321
4777
5556
6336
19717
31640
32343
32343
38237
38238
38640
38641
38641
44783
54350
54349
55127
3990
3991
4725
11179
11179
13040
13525
15553
15553
15553
24134
25633
28057
30698
31875
37065
37593
42728
46896
23956
28941
28942
16683
A-135
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TABLE 4. CLASSIFICATION OF INJECTION WELLS
Class I o Wells used by generators of hazardous waste or
owners or operators of hazardous waste management
facilities to inject hazardous waste beneath the
lowermost formation containing, within one quarter
(1/4) mile of the well bore, an underground source
of drinking water.
o Other industrial and municipal disposal wells
which inject fluids beneath the lowermost
formation containing, within one quarter mile of
the well bore, an underground source of drinking
water.
Class II Wells used to inject fluids:
o Which are brought to the surface in connection
with conventional oil or natural gas production
and may be commingled with waste waters from gas
plants which are an integral part of production
operations, unless those waters are classified as
a hazardous waste at the time of injection;
o For enhanced recovery of oil or natural gas; and
o" For storage of hydrocarbons which are liquid at
standard temperature and pressure.
Class III Wells used to inject for extraction of minerals
including:
o Mining of sulfur by the Frasch process.
o In situ production of uranium or other metals.
This category includes only in situ production
from ore bodies which have not been
conventionally mined. Solution mining of
conventional mines such as stopes leaching is
included in Class V.
o Solution mining of salts or potash.
Class IV o Wells used by generators of hazardous waste or of
radioactive waste, by owners or operators of
hazardous waste management facilities, or by
owners or operators of radioactive waste disposal
sites to dispose of hazardous waste or radioactive
waste into a formation which within one quarter
(1/4) mile of the well contains an underground
source of drinking water.
A-136
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TABLE 4. CLASSIFICATION OF INJECTION WELLS
(Continued)
Class IV o Wells used by generators of hazardous waste or of
(Cont'd) radioactive waste, by owners or operators of
hazardous waste management facilities or by owners
or operators of radioactive waste disposal sites
to dispose of hazardous waste or radioactive waste
above a formation which within one quarter (1/4)
mile of the well contains an underground source of
drinking water.
o Wells used by generators of hazardous waste or
owners or operators of hazardous waste management
facilities to dispose of hazardous waste, which
cannot be classified under Sect. 146.05(a)(l) or
146.05(d) (1) and (2) (e.g., wells used to dispose
of hazardous wastes into or above a formation
which contains an aquifer which has been exempted
pursuant to Sect. 146.04).
Class V o Injection wells not included in Class I, II, III,
or IV.
A-137
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REFERENCES
Federal Register, 40 C?R Parts 144, 145, 146, and 147.
Safe Drinking Water Act, Part C, December 16, 1974, as amended by
PL 96-502, December 5, 1980.
Personal Communication with Mr. Mario Salazar, U.S. EPA UIC
Program, October 7, 1986. Telephone 202- 382-5561.
A-138
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