Environmental Protection
             Agency
                Office of Solid Waste
                and Emergency Response
                Washington, DC 20460
EPA/530-SW-88-003
December 1987
EPA
             Solid Waste
Report to Congress


Management of Wastes from the
Exploration, Development, and
Production of Crude Oil, Natural Gas,
and Geothermal Energy

        Volume 3 of 3
        Appendices
        A-Summary of State Oil and Gas Regulations
        B-Glossary of Terms for Volume 1
        C-Damage Case Summaries

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              REPORT TO  CONGRESS
          MANAGEMENT OF  WASTES FROM THE
    EXPLORATION,  DEVELOPMENT,  AND PRODUCTION
OF CRUDE OIL, NATURAL GAS, AND GEOTHERMAL ENERGY
                       VOLUME 3
                      APPENDICES

      A -  Summary of State Oil  and Gas Regulations
      B -  Glossary of Terms for Volume 1
      C -  Damage Case Summaries


      UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
      Office of Solid Waste and Emergency Response
                Washington,  D.C.  20460
                    December  1987

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                             TABLE OF CONTENTS
APPENDIX A   SUMMARY OF STATE OIL AND GAS REGULATIONS 	A-l
      Alabama 	A-l
      Alaska 	A-7
      Arizona 	A-21
      Arkansas 	A-25
      California 	A-33
      Colorado 	A-47
      Florida 	A-57
      Illinois 	A-61
      Indiana 	A-67
      Kansas 	A-71
      Kentucky 	A-79
      Louisiana 	A-83
      Maryland 	A-95
      Michigan 	A-99
      Mississippi 	A-107
      Missouri 	A-115
      Montana 	A-119
      Nebraska 	,	A-125
      Nevada 	A-131
      New Mexico 	A-135
      New York 	A-145
      North Dakota  	A-153
      Ohio 	A-159
      Oklahoma 	A-169
      Oregon 	A-181
      Pennsylvania  	A-187
      South Dakota  	A-193
      Tennessee 	A-197
      Texas 	A-201
      Utah 	A-215
      Virginia 	A-221
      West Virginia 	A-225
      Wyoming 	A-231

APPENDIX B - GLOSSARY OF TERMS FOR VOLUME 1 	B-l

APPENDIX C   DAMAGE CASE SUMMARIES 	C-l
      OH 49 	C-l
      OH 45 	C-3
      OH 07 	C-4
      OH 12 	C-5
      OH 38 	c -7
      WV 18	C-8

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                       TABLE OF CONTENTS  (Continued)
APPENDIX C   Continued
      WV 20 	c-10
      PA 02 	c-12
      PA 09 	c-13
      WV 17 	C-15
      PA 08 	C-17
      WV 13 	C-19
      KY 01 	C-20
      LA 67 	C-22
      LA 20 	C-24
      LA 45 	C-26
      LA 15 	C-28
      LA 64 	C-30
      LA 90 	C-32
      AR 07 	C-33
      AR 10 	C-35
      AR 04 	C-36
      AR 12 	C-38
      MI 05 	C-39
      MI 06 	'	C-41
      MI 04 	C-42
      KS 01 	C-44
      KS 08 	C-46
      KS 05 	C-48
      KS 03 	C-50
      KS 06 	C-51
      TX 55 	C-53
      TX 31 	C-54
      TX 29 	C-56
      OK 08 	C-58
      OK 02 	C-59
      OK 06 	c-61
      TX 21 	C-63
      TX 22 	C-64
      WY 03 	   C-66
      WY 01 	C-67
      WY 05 	C-69
      WY 07 	C-70
      NM 02 	           C  72
      NM 05 	                              ' 'c  73
      NM 01 	'.'.'.'.'.'.'.'.'.'.'.'.'.'.'.C-77
      CA 21 	C-79
      CA 08 	C-81
      AK 06 	C-83

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                       TABLE OF CONTENTS (Continued)


                                                                 Page
APPENDIX C - Continued
      AK 07 	C-84
      AK 08 	C-86
      AK 12 	C-87
      AK 10 	C-88
      AK 03 	C-90
      AK 01 	C-92
      KS 14 	C-94
      TX 11 	C-96
      TX 15 	C-97
      LA 65 	C-99
      NM 03 	C-101
      NM 04 	C-103
      AK 09 	C-104

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             APPENDIX A
SUMMARY OF STATE OIL AND GAS REGULATIONS

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INTRODUCTION

    Alabama produced 8,486,000 barrels of oil,  11,392,000  barrels  of
                        n
condensate, and 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  and  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 been revised  continually
over the past 40 years.

REGULATORY AGENCIES

    Four agencies regulate oil and gas activity  in Alabama.  They  are:

    •  Alabama State Oil and Gas Board;
    •  Alabama Department of Environmental  Management;
    •  U.S. Bureau of Land Management; and
    •  U.S. Army 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, from the issuance of drilling permits  through  the
production phase.  The Oil and Gas Board has the authority to  issue
permits for Underground Injection Control  (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  National  Pollutant
Discharge Elimination System (NPDES)  authority.   The  Oil  and Gas Board
and the Department of Environmental  Management operate  under a 1979
Memorandum of Agreement that requires the  Board  to forward  information
regarding actual or proposed discharges to the Department of
Environmental Management.

    The U. S. Bureau of Land Management's  authority and regulations for
Federally-held mineral  rights are discussed  separately  in the  section on
Federal agencies.  (See Volume 1, Chapter  VII.)   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 these pits.
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 ensure the protection of surface  or ground-water resources.
Many of the wetland areas  in Alabama fall  within the  jurisdiction of the
Alabama Coastal Area Management Program, which  is enforced  by ADEM.  The
Certificate of Consistency,  which must  be  issued by ADEM before a permit
can be granted by the Board, requires use  of portable aboveground tanks
for any well drilled in the coastal  area.
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    Drilling muds and pit fluids may be disposed of 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-wetlands, 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; or
    •  There will be no discharge to a 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 (1) the disposal of waters
produced in association with oil and/or natural gas, (2) the disposal of
nonhazardous wastewaters that may be generated during the operation of a
gas plant, (3) the enhanced recovery of oil or natural gas, or (4) the
storage of liquid hydrocarbons 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.

    According to Rule 400-1-5-.04, "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,  obtaining approval  to drill  or  convert a well  for injection
purposes,  includes a review of all  well  construction within a one-quarter
mile radius of the proposed injection well,  along with 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 will be made 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 two-tenths of 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 start injection.  Once injection
begins,  the operator must submit  monthly reports on injection volumes,
injection pressures, and the casing-tubing annulus pressures.  The
injection pressure and the casing-tubing annulus pressure must be
recorded daily or computed on an  average daily basis from weekly
measurements.  Also, chemical analyses  of injected fluids must be
submitted on an annual  basis, and a pressure test should be performed at
least once every 5 years.

    Produced waters  from coal bed  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 and settle.  They would then  be discharged directly
into live streams. The Department of Environmental Management stipulates
that operators must  obtain permits  for  such  discharges and requires that
such discharges meet a 600 mg/L in-stream limit.
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PI uggi ng/Abandonment

    Plugging is required after 6 months, but wells may be approved for
temporary abandonment if future utility can be shown. Thereafter, well
status must be reported every 6 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 freshwater 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 should be placed over the casing stub. Intervals
between the plugs must be filled with mud-laden fluid.
                                    A-5

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                                References

State Oil  and Gas Board of Alabama.   Submittal to EPA regarding Onshore
    Oil and Gas Subcategory,  March 1985.

          Administrative Code.   General  Order Prescribing Rules and
    Regulations Governing the Conservation of Oil and Gas in Alabama  and
    Oil and Gas Laws of Alabama with Oil  and Gas Board Forms, Oil and  Gas
    Report 1, 1983.

USEPA.  1985.  U.S.  Environmental  Protection Agency.  Alabama Meeting
    Report.  Proceedings of the Onshore;. Oil and Ga.s. Workshop (March 26-27
    in Atlanta, Ga.).  Washington,  D.C.:*  U.S.  Environmental Protection
    Agency.

Personal Communication:

    Treena Pizner,  Alabama  Department of Environmental  Management
    (205) 271-7850.
                                    A-6

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                                ALASKA

INTRODUCTION

    Alaska produced 681,309,821 barrels of oil  and  316  x  109  cubic  feet
of gas in 1986.  During 1986, 608,225,599 barrels  of  water  and
          g
1,066 x 10  cubic feet of gas were injected into  producing  formations
for enhanced oil recovery.

    Alaska ranked second in U.S. oil  production,  but  23rd  in  the  number
of production wells (1,191 wells) in  1986.  It  ranke'd 8th  in  U.S. gas
production and 24th in the number of  producing  gas  wells  (104 wells).

    In 1986, oil and gas in Alaska were produced  from two development
regions, the South Central region (including Cook  Inlet and the Kenai
Peninsula) and the North Slope region.   The State  contains  other
•protective regions, but to date no discoveries have  been made there.
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 Endicott Field (Duck Island) will  begin  production  in
early 1988.  Production at the 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.
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REGULATORY AGENCIES

    The eight agencies that  regulate  oil  and  gas  activities in Alaska are:

    •  Alaska Oil  and Gas  Conservation  Commission;
    •  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;  and
    •  U.S. Fish and Wildlife Service.

    The Alaska Oil and Gas Conservation Commission  (AOGCC)  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  (DEC) 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 nonhazardous oil and gas wastes (which are not
regulated as Class II wastes).  Since Alaska  does not have responsibility
                                    A-8

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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
the Onshore Oil and Gas Order No. 1.  More information on BLM regulations
can be found in the section on Federal programs.  (See Volume 1, Chapter
VII.)

    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 operation for all oil and gas activity on State lands.  The approval
letter contains site-specific stipulations developed through inter-agency
review.  In addition, the Department  conducts field inspections of
operations and abandonments.

    Under Section 404 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

                                    A-9

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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

    New revisions to the regulations for the  handling  of drilling and
production wastes (18 AAC  60)  in Alaska were  adopted by the Department of
Environmental Conservation in  June 1987.  These  amendments  impose more
stringent requirements on  the  management of reserve pits and drilling
wastes.

Reserve Pits

    The management and disposal  of drilling wastes primarily involve the
proper operation and closure of the reserve pit  used 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  continuous use because of
the directional  drilling of multiple wells  from  a  single pad.  There are,
however, a variety of ways in  which drilling  wastes are ultimately
disposed of, such as subsurface injection.   (In  18 AAC 60.910, "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
                                   A-10

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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
prevent contamination of ground water and damage to the surface
environment."  The general construction requirement is that the pits must
be rendered "impervious."

    The new DEC regulations impose specific construction and performance
requirements for reserve pits. The particular requirements depend on
factors such as the proximity of surface water or ground water that is
used for drinking water, the proximity of an existing or developing
population, and whether the pit is being built in an area of continuous
permafrost. For example, a reserve pit being constructed in a
nonpermafrost region within 100 feet of a surface water body used for
drinking water would require a double liner, leachate collection (if
there  is 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 are needed for all discharges.  Pits must be closed
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within 12 months after the final  drilling wastes have been disposed of  in
the pit.

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
permitted disposal facilities was operated by an independent
concessionaire on Kenai Borough-owned land, but DEC canceled the permit
because contaminants were 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 Ejection
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 that had
received no discharges or placements of any materials into the pit since
August 1, 1985, were eligible (that is,  pits that had gone through a
1-year freeze-thaw cycle to precipitate contaminants). Further, pits must
have no visible sheen  on the surface.  Operators must notify DEC 2 weeks
prior to any discharge, and include information on volumes and analyses
for salinity, settleable solids, arsenic, and chromium.  Written approval
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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/L
         pH                                      6.0   8.5(or
                                                 within 0.5 of
                                                 receiving water)
         Salinity                                3 parts/thousands
         Settleable solids                       1 mg/L
         Oil and grease                          15 mg/L
         Aromatic hydrocarbons                   10 ug/L
         Arsenic                                 0.05 mg/L
         Barium                                  1 mg/L f
         Cadmium                                 0.01 mg/L
         Chromium                                0.05 mg/L
         Lead                                    0.05 mg/L
         Mercury                                 0.002 mg/L.

     These  limitations were to 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 that approximately 36 million gallons of liquid
were discharged from  43 reserve pits in 1985, 35 of which exceeded
limitations.  Sixteen of  these pits, however, exceeded only the
limitation  for manganese, which is found at naturally high levels in
waters on the slope.
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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 1-year freeze-thaw cycle
before disposal. Application  is specifically designated for particular
roads and pads. Spraying is prohibited when the surfaces are already wet.
Spraying is to be made no closer than 3 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 annular disposal  for the  North Slope 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...."
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    Discharge must occur below the permafrost zone; the minimum depth
must be 1,000 feet. No discharge must be into any zone containing total
dissolved solids  (IDS) of less than 3,000 ppm. Operators must notify DEC
at least 2 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.

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 to 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 geographically distant from any
enhanced recovery operation. Additional water for enhanced recovery is
drawn from both Cook Inlet and the Arctic Ocean.
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    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;  are within the same field,
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 freshwater
strata. At application, information must be  provided on all wells within
one-quarter mile of the injection well  that  penetrate the injection zone.
Adequate evidence must be provided that a proposed injection well will
not cause or increase fractures in overlying strata, which could allow
injected or formatic.. liquids to enter freshwater strata.  (Freshwater
aquifers may be exempted  from the restrictions affecting them if they
currently do not and cannot in the future serve as sources of drinking
water; are between 3,000  and 10,000 mg/L IDS but cannot be reasonably
expected to supply a public water system; or if they are too contaminated
for economic or technologically practical recovery.)

    Injection wells must  be equipped with tubing and packer or other
equipment that would isolate pressure to the injection interval. Wells
must undergo pressure tests for mechanical integrity before operation.
The test must run for 30  minutes at 1,500 psi or 0.25 psi/ft times the
vertical depth of the casing shoe, whichever is greater  (but must not
exceed 70 percent of the  minimum yield strength of the casing), with a
maximum pressure decline  of 10 percent. Thereafter, mechanical integrity
must be demonstrated by the operator by monitoring the pressure  in the
casing-tubing annulus during actual injection. The monitored pressure
rr.ust be reported monthly.
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    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.

PIugging/Abandonment

    All wells  that have been permitted on a property must be abandoned
within 1 year  following cessation of the operator'.s oil and gas activity
within the field where the wells are located.  Any well that is not
completed after drilling must be abandoned or suspended before the
drilling equipment is removed.

    The Commission may approve suspension of a well if it has future
productive or  service use, and if there is a justifiable reason for the
suspension (e.g., unavailability of production or marketing facilities).
The operator of* a suspended well must set a'bridge plug 200 to 300 feet
below the casing head and cap with 100 linear feet of cement. Additional
plugging requirements for a suspended well would be determined by the
Commission on  a site-specific basis.

    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 wellbore must be segregated;
various cementing method/plug placement combinations may be used (e.g.,
plug from 100  feet below to 100 feet above the casing shoe, using the
displacement method).
                                    A-17

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    Cased portions of the well bore must be plugged with cement to confine
hydrocarbons and fresh water to the original  strata. Perforated intervals
must be plugged by one of several  methods (e.g.,  by extending cement
plugs 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 a 75-foct cement cap 50 feet over the interval),
as must casing stubs within the outer casing  (plug from 100 feet above to
100 feet below the stub, bridge plug 25 feet  over  the stub with a 75-foot
cap, or downsqueeze 150 feet of cement through the retainer with an
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.

    Cements used for plugging within permafrost zones must be designed to
set before freezing and have low heat of hydration.   Muds equaling or
exceeding the density of mud used  to drill  each interval  should fill  the
intervals between plugs.

    Final abandonment of the wells and drill  sites must also be approved
by the Alaska Department of Natural  Resources if the site is on State
land.
                                   A-18

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                                 References

Alaska Department of Environmental Conservation.  General Wastewater
    Disposal Permits for surface discharges from reserve pits
    (#8640-06001; May 12,  1986) and annular injection (28540-DB001;
    August 6,  1985); and individual permits for road application
    (#8636-DB003 and DB004).

	.  Regulations. Alaska Administrative Code, Title  18,
    Chapter 60  (Solid Waste Management), September 1987; Chapter 72
    (Wastewater Disposal), January 1983.

Alaska Oil and Gas Conservation Commission.  1986.  Regulations, Alaska
    Administrative Code, Title 20, April 2, 1986.

Alaska Statutes. Title 31, Chapter 05, Alaska Oil and Gas Conservation
    Act.

Fristoe, Bradley R.  1985.  Letter communication to EPA.  State of Alaska
    Department of Environmental Conservation.

Interstate Oil and Gas Commission.  1986.  Summary of State statutes and
    regulations for oil  and gas production. June 1986.

Interstate Oil Compact Commission.  1985.  The Oil and Gas Compact
    Bulletin,  Vol. XLIV, Mo. 2, December 1935.

Title 46, Water, Air, Energy, and Environmental Conservation:
    Chapters 3  (Environmental Conservation); 4  (Oil Pollution Control);
    and 8-9  (Oil and Hazardous Substance Release).

USEPA.  1985.  U.S. Environmental Protection Agency.  Alaska Meeting
    Report.  Proceedings of the Onshore Oil and Gas State/Federal Western
    Workshop (March 26-27  in Atlanta, Ga.).  Washington, D.C.:  U.S.
    Environmental Protection Agency.

Personal Communications:

    William Barnwell, Alaska Oil and Gas Conservation Commission
    (907) 279-1433.

    Michael Frank, Alaska  Attorney General's Office, Natural Resources
    Division (907) 276-3550.

    Douglas Lowery, Alaska Department of Environmental Conservation
    (907) 452-1714.
                                    A-19

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Doug Redburn,  Chief of Water Quality  Management Section,  Juneau
(907) 465-2666.

Dan Wilkerson,  Alaska Department  of Environmental  Conservation
(907) 274-2533.
                              A-20

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                               ARIZONA

INTRODUCTION

    Arizona produced 214,000  barrels of oil and 225 MMCF of yas in  1984.
Production was from 26 oil  wells  and 5 gas wells.  Approximately
655 barrels of produced waters  are  produced in the State per day.

REGULATORY AGENCIES

    The five agencies that  regulate the oil and gas industry in Arizona
are:

    •  Arizona Oil  and Gas  Conservation Commission;
    •  U.S. Bureau  of Land  Management;
    •  U.S. Bureau  of Indian  Affairs;
    •  Arizona Department of  Health and Safety; and
    •  EPA, Region  IX.

    The Bureau of Land Management (BLM) 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.
                                   A-21

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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  permits.   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 waters produced during  the  production phase are  reinjected,  for
either enhanced recovery or disposal.   To dri>l  an  injection well,  permit
approval is required from both  EPA  Region IX and the Commission.   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 freshwater
strata.  Surface casing is required to be pressure  tested at 600  psi  for
30 minutes, with a maximum allowable  drop of 10 percent  in pressure.

PIuggi ng/Abandonment

    The regulations do  not specify  a  time limit for plugging a well  after
production ceases.  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  pe-~mi;sion  for temporary abandonment  is
granted by tne 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
Brady,  Ray.   Deputy State Director,  Division of Mineral Resources.  Letter
    to U.S.  Environmental Protection Agency, September 4, 1985.

Oil and Gas  Conservation Commission.  1982.   Arizona Administrative Code
    Chapter  7.  Article 1.  Oil.  Gas, and Helium.

Personal  Communications:

    Lyndon Hammon,  NPDES Permits Section Manager,  Arizona Department of
    Health and  Safety.  September 29,  1986  (602)  257-2262.

    Nate  Lau,  Director of the UK Division,  EPA Region IX.   September 28,
    1986  (415)  974-0893.
                                   A-24

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                              ARKANSAS

INTRODUCTION

    Arkansas produced 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.

REGULATORY AGENCIES

    The two agencies that regulate oil  and gas activity in Arkansas are:

    •  Arkansas Oil  and Gas Commission; and
    •  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 the waste  of oil and gas resources and the
pollution of freshwater supplies by  oil, gas, or salt water.  Act 937
authorized the Commission to prevent waste in produced water 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 aspects of industry practices, and refer the  reader to
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"special  rules  pertaining  to  individual  oil,  gas,  or salt water fields
and pools."   Special  rules  of any  nonemergency  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  included "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 salt
water to escape a lease, and  required ADPCE to  identify the source  of
pollution and to take steps to eliminate it if  the chloride level in any
stream exceeded 250 ppm.  Act 743  of i975 provided ADPCE with
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. 1 that
would be modeled on Louisiana State Order No. 29-B.   As of the start of
1987, however,  the timing  and outcome of the effort were uncertain.

    Arkansas has pr-iacy for  both  the NPOES program and the UIC program.
The M'DES program is doministereo  by ADPCE.   A  Memorandum of Agreement
{'•larch 25.  1982) governs the  division of authority between ADPCE and
                                   A-26

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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.

    The Memorandum  also  notes, however, the statutory overlap of
jurisdiction that it was intended to resolve.  The degree to which this
issue  is still unresolved is reflected in the introduction, during the
currenJt session of  the  legislature, of a bill drafted by counsel for the
Commission that would have given the Commission exclusive authority with
respect to Class II wells, while repealing 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.
                                    A-27

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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. 1 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 that stipulate management  practices
for reserve  pHs and disposal of drilling wastes.  Many of the provisions
required by  the letter are  those the Department would like to  include  in
a proposed revision of Regulation No. 1.  The lack of specific
regulations  containing the  provisions in the  letter, however,  has
resultM in  uneven  compliance with these requirements by operators.  The
letter lists conditions that 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 can  be  disposed  of  only
by ADPCE permitted  disposal  services.

    The letter of authorization also states that  completion  fluids  high
in total dissolved  solids,  such as KC1.  should be kept  separate  from  the
                                   A-2B

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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 can 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 freshwater
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 one-half mile of the new or converted
injection wel1.

    Section 4 of Regulation No. 1 forbids discharging salt water from any
oil or gas well in  a manner whereby the salt water might 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 saltwater disposal:  (1) subsurface
discharge in disposal wells constructed in accordance with the Rules and
Regulations of the  Arkansas Oil and Gas Commission, and (2) surface
discharge into lined earthen pits.  Currently, only subsurface disposal
is permitted.
                                    A-29

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    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 stipulates that the disposal  company  must 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 landowner'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 contain  tests for chromium, zinc, chlorides,
and pH.

PIuggi ng/Abandonment

    Wells that 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 wel1.

    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
                                   A-30

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100 feet must be placed 50 feet below the base of the freshwater stratum
if surface casing is not cemented below that stratum; if it is cemented,
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 a way
as not to interfere with cultivation. Intervals between plugs should be
filled with heavy mud-laden fluid.
                                   A-31

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                                References

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  and Gas Commission.   1986.   Summary of State statutes and
    regulations for oil  and gas  production.  June 1986.

Interstate Oil  Compact Commission.   1985.   The Oil  and Gas Compact
    Bulletin,  Vol. XLIV,  No.  2,  December 1985.

Letter to Mr.  Naresh R.  Shah,  West  Virginia Department of Natural
    Resources  Permits Branch,  from  Mr.  Terry Muse,  Arkansas Department
    of Pollution Control  and  Ecology,  regarding Arkansas Water Permit No.
    2839-W, March  2, 1984.

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.

USEPA.  1985.   U.S. Environmental  Protection Agency.   Proceedings:
    Onshore Oil and Gas  State/Federal  Western Workshop (March 26-27 in
    Atlanta,  Ga.).  Washington,  D.C.:   U.S.  Environmental Protection
    Agency.

Personal Communications:

    Phil Deisch, Arkansas Department  of Pollution  Control and
    Ecology (501)  562-7444.

    Steve Drown, Arkansas Department  of Pollution  Control and
    Ecology (501)  562-7444.

    Lynn Fite,  Arkansas  Oil and  Gas Commission (501)  862-4965.

    David A.  Thomas. Arkansas  Department  of Pollution Control  and
    Ecology.  August 1986,  (501)  562-7444.

    John Welch, Arkansas  Game  and  Fish  Commission  (501)  223-6319.

    William Wynne: Crumyler,  O'Connor,  and Wvnne:  serving as counsel to
    Arkansas  Oil and Gas  Commission (501)  863-8118.
                                   A-32

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                            CALIFORNIA

INTRODUCTION

    California produced  423,900,000 barrels of oil  and 493  billion
    g
x 10  cubic feet of gas  in  1935.  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 percent of the oil  production is attributed to enhanced  recovery.

REGULATORY AGENCIES

    A number of agencies regulate oil and gas activity .in California,
including:

    •  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; and
    •  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,
the Division also issues UIC  permits for Class II injection wells.   As
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part of its  responsibilities,  the  Division  ensures  that the drilling and
operat-ion of such  ,/ells  do  not  endanger  fresh  ground-water 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.   cPA has  delegated authority
to issue NPDES permits  to the  Water Resources  Control  Boara.  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 a  minimum,  implement  requirements as
strict as those of the  State  board; however,  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 Understanding 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 determines 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 the injection wells
into which hazardous wastes are being  injected.  Further, the Department
or Health Services shares with the  Regional  Water Quality Control Boards
                                   A-34

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the responsibility for regulating hazardous waste landfills and surface
impoundments.

    For wells on State-owned, onshore lands, the State Lands Commission
has joint responsibility 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 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 cil 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, (BLM) approves approximately 400 oil
and gas drilling permits per year on Federal lands and 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 of 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 that  come under
the provisions  of the  regulations for  hazardous wastes if they  contain a
hazardous material.   Most muds actually  in use in California do not  fall
under this provision,  however.   The  Department of Health  Services  has
prepared a list (available  to  operators on request)  of additives and
fluids that  are nonhazardous if used according to the manufacturers'
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  nonhazardous.

    Discharges  of drilling  muds  and  cuttings that do  not  contain
halogenated  solvents into onsite sumps are specifically excluded from the
requirement, affecting "Discharges of  Waste  to Land"  (Subchapter 15,
Chapter 3. Title  23)  under  the jurisdiction  of the Regional  Water  Quality
                                   A-36

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Control Boards, provided that the operator takes appropriate measures at
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 semi sol id wastes, provided that
representative sampling of the sump contents after liquid removal shows
residual solid wastes to be honhazardous."

    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 which 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 salt
water  to the sumps.  The impact and legality of this practice are
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%.

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
cana-ls, 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/L
    Chlorides                                200 mg/L
    Boron                                    1 mg/L
    Electrical conductivity                  1,000 umhos.

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/L, and limits on
heavy metals, cyanide, chlorinated  hydrocarbons, and sulfides.  There  is
no pretreatment limit for chloride.
                                   A-38

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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
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 and
comply with the State Board's nondegradation policy and with "the water
quality objectives set forth  in the applicable water quality control
plan...."  For example, unlined sumps containing produced waters that
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 set 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.
                                    A-39

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    In addition to discharge to  onsite  saltwater sumps, substantial
volumes of salt water are discharged  to offsite sumps.   These are
discussed below.

Injection

    Over half of the produced waters  in California are  reinjected, either
for enhanced recovery or for disposal.   The 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 that  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 attempting 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 fresh water, 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.
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    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 programs, 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
the Division.  Mechanical integrity tests (MITs) are carried out
annually, except for thermal enhanced recovery wells and wells with
special conditions.  In these cases, MITs are performed on varying
schedules--usually every 3 years.

    Some disposal of salt water 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 1905, which are generally more stringent
than Federal requirements.  These requirements are under the jurisdiction
of the Department of Health Services.

Offsite Disposal

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
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produced waters  and  are  in  the  process  of  closure.   The remaining sumps
are still  operating.   Some  of  the  wells  discharging to the sumps, and
sorr.e 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  back two decades, or have
no requirements  at  all.

    Mile this disposal  method  currently is allowed,  the Central Valley
Regional Water Quality Control  Board is  considering whether  these
produced waters  should be regulated  under  the  requirements for California
"designated" wastes  (if  they contain pollutants  that  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  nondes^gnated,  a'ternative  uses would be
permissible.
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Transport

    An invoice for an undesignated waste is required for trucks hauling
produced water.  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.

PIugging/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 6  months.  Removal of production equipment is evidence of
desertion after 2 years.  While the Supervisor of the Division of Oil and
Gas may order the plugging of a well that has been deserted, the Division
of Oil and Gas generally exercises  its discretion for previously
producing wells (particularly those that were permitted prior to the
existence of  a bonding requirement).  Moreover, the Division actively
communicates  with operators about plugging wells that have been out oF
production for 5 years.

    When a well is plugged, cement  plugs generally should be placed
across specified intervals to protect oil, gas, and usable water zones.
Tne district  deputy may allow cement to be mixed with or replaced by
other  substances with adequate physical properties.  Intervals that are
not plugged are to be filled with mud fluid of "sufficient weight and
consistency"  as to prevent movement of other fluids into the wellbore.

    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
                                    A-43

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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
the casing across  the 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 fresh
water, in addition to a  100-foot plug  inside the casing.

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                                 References


California Administrative Code:  Titles 14, 22, and 23.  Title 14,
    Chapter 4 - Development, Regulation and Conservation of Oil and 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.

Interstate Oil and Gas Commission.  1986.  Summary of State statutes and
    regulations for oil and gas production. June 1986.

Interstate Oil Compact Commission.  1985.  The Oil and Gas Compact
    Bulletin. Vol. XLIV, No. 2, December 1985.

Mefferd, Marty.   1985.  Letter communication to EPA.
    Supervisor, Division of Oil and Gas.

USEPA.  1985.  U.S. Environmental Protection Agency.  California Meeting
    Report.    Proceedings of  the Onshore Oil and Gas State/Federal
    Western Workshop  (March 26-27 in Atlanta, Ga.).  Washington, D.C.:
    U.S. Environmental Protection Agency.

Personal Communications:

    Theodore  R. Anderson, Bureau of Land Management, Bakersfieid,
    (805) 861-4177.

    Hal Bopp, Division of Oil  and Gas (805) 322-4031.

    Shelton Gray, Central Valley Water Quality Control Board
    (209) 445-5142.

    Bob Reid, Division of Oil  and Gas (916) 445-9686.

    Chong Rhee, L.A.  County Sanitation District (213) 699-7411.

    Scott Smith,  Central Valley Water Quality Control Board
    (209) 445-5116.

    Greg Williams, Department  of Health Services (916) 322-0453.
                                    A-45

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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  enacted 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 in 1973.   The
Solid Wastes Disposal  Sites  and Facilities Act (Title 30-20-Part  1,
C.R.S. 1973, as  amended) also  has jurisdiction over oil  and gas
activities.

     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.

REGULATORY AGENCIES

    The three agencies sharing regulatory authority for oil and gas
wastes in Colorado are:

     •  Department of Natural  Resources—Oil and Gas Conservation
       Commission;
     •  Department of Health;  and
     •  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 activities  in Colorado.  The Commission is responsible  for the
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conservation of oil  and  gas  and  the protection of the rights of all
parties.   It has general  authority to protect the environment from
pollution b> oil and gas  activities on the sites of drilling and
production operations.   The  Commission is  also responsible for the
regulation and permitting of central  disposal facilities operated by the
producing companies.

    The Colorado Department  of Health, 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 the
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:

       "...will consider oil and gas liquid waste impoundments to be in
       compliance v^th  these regulations if:

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    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  in the
section on Federal agencies.  (See Volume  1,  Chapter VII.)

STATE RULES  AND REGULATIONS

Drilling

Pit Requirements

     Oil and Gas Conservation Commission 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;
the reserve pits are used primarily when the mud is displaced  during  the
running of pipe.  While no rules prohibit  the discharge of produced
waters into a reserve pit, this is not commonly done.   If the
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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 Rule's
provisions.

    Most drilling fluids and muds  in Colorado are bentonite- and
freshwater-based.  Very few  oil-based drilling fluids are used, and these
are moved from operation to  operation until  disposed of into an approved
landfill.

Pit Closure/Pischarge

    If the well is a  dry hole and  is abandoned, backfilling of pits and
reclamation of t..e land must be completed within 6 months unless an
extension is granted  for unrusual circumstances (Rule 319(a)(8)).

    Generally, after  the lighter fluids are  decanted 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 cnenical oxygen demand.

Produced Waters

    Produced water is disposed of through reinjection (approximately
85 percent), placement in storage and disposal pits (approximately
15 percent), and discharge  for beneficial use for agriculture and
wildlife (<1 percent).
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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 orisite 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 o'il and gas
operators under a  field operator's agreement approved by the Commission.

    Both central and onsite 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 that could impede
evaporation.   Certain other requirements in the Rule do not apply where
the volume of  water to  be  disposed of does not dxceed five barrels per
day on  a monthly basis.
                                                      «?%
    Generally, applicants  for permits to construct produced water
disposal pits  must provide substantial information OP surface  waters and
ground  waters, 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
water placed in the pit has a higher  TDS content than underlying aquifers
hydrologically connected,  regardless  of the amount of water delivered to
the pit.
                                    A-51

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    The Commission  makes  a  case-by-case  determination on lining
requirements for all  produced-water  storage  and  disposal pits on the
basis of site-specific  evaluations.   According  to information provided by
the Commission,  90  percent  of  the  pits  for wells producing more than
five barrels per day  of water  are  required to  be lined (approximately two-
thirds with clay and  one-third with  synthetic  liners).  Of the remaining
pits, either the received water is fresh and allowed  to percolate,  or the
pits are over impervious  shales and  the  water  evaporates.

In.lect ion

    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  5 years  thereafter.  The test
pressure must be 300  psi  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 percent.   Monthly injection reports
are submitted listing 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 State facilities 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/L (30-day average)
                                            45 mg/L (1-day maximum)
    Oil and grease                          10 mg/L
    Total dissolved solids                  5,000 mg/L (30-day average)
                                            7,500 mg/L (1-day maximum).
Offsite Disposal

    Commercial offsite 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,
half of which are lined.  Lining requirements are determined by
classifications of  impoundments.  Class I facilities (in a recharge area
for a drinking water  aquifer where seepage from impoundment would impair
use of the ground water) 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 (those located outside a recharge area,
having competent bedrock between the surface and the aquifer, or where
impairment would not  result from unrestricted seepage) require no liners.

    Truckers transporting produced waters to offsite impoundments or
injection wells must  file monthly reports on the source, volume, and
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recipient of the waters hauled.   Similar records must be kept by the
receiving facility.   These records  will  be subject to computerized
cross-tabulation.

PIuggi ng/Abandonment

    Wells that have  ceased production or are incapable of production are
to be abandoned within 6 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 that are closed down for
economic reasons,  arrd 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 6 months indicating
plans for future operations.

    Wells must be plugged so as  to  confine oil, gas, or water to the
original strata.  The operator must obtain approval of the plugging
method from the Commission prior to the plugging operation.  Surface
casing may not be removed from the  well  unless approved by the Director.
Generally, requirements call for the placement of cement plugs 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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                                 References


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.

Interstate Oil Compact Commission.  1985.   The Oil and Gas Compact
    Bulletin. Vol. XLIV, No. 2, December 1985.

Order 1-39, modifying the Rules and regulations of the Oil and Gas
    Conservation Commission.  Effective August 8, 1986.

State of Colorado.  Regulations pertaining to solid waste disposal sites
    and facilities. Effective Date:  October 1, 1984.

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.

USEPA. ' 1985.  U.S. Environmental Protection Agency.  Colorado Meeting
    Report.  Proceedings of the Onshore Oil and Gas Stare/Federal Western
    Workshop (March 26-27 in Atlanta, Ga.).  Washington, D.C.:  U.S.
    Environmental Protection Agency.

Personal Communication:

    William R. Smith, Oil and Gas Conservation Commission (303) 866-3531.
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                               FLORIDA

INTRODUCTION
                                                         Q
    Florida produced 14,090,000 barrels of oil and 15 x 10  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

    The four agencies responsible  for  regulating the oil and gas industry
in Florida are:

    •  Florida Department of Natural  Resources, Division of Resource
       Management, Florida Geological  Survey;
    •  Florida Department of Environmental Regulation;
    •  Florida Regional  Water Management Districts; and
    •  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
regard 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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    Florida's  Regior.al  Water  Management  Districts,  which are separate
regulatory groups  on  a  local  level,  regulate  oil  and  gas activities
involving water use.  Consumptive  use  permits  are issued if applicable.

    Other State agencies  may  tie  involveJ on a  case-by-case basis.   These
agencies are most  commonly  the Florida Carrie 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 DIG 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  a  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 are
disposed of by reinjection.  Pits  are  nearly  dry when they are
backfilled.   They  are lowered as fast  as possible by  pumping down  the
wellbore prior to  plugging  the well.   All  produced  waters are reinjected.

    The DNR is governed by  Chapter 377,  florida  Statutes, and its
implementing rules, Chapters  15C-25  thro-.s^h  16C-30,  Florida
Administrative Code.  One aspect of  Chapcer 377's 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."   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."
                                   A-«:S

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    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.

PIuggi ng/Abandonment

    Each request for temporary abandonment will be considered on a
case-by-case basis; however, the requirements for temporary abandonment
do not differ significantly from 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 a 200-foot plug
extending 100 feet above and below the interval.  With respect to the
open hole below the 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 freshwater zones. Additional plugs must
be placed in the casing of the smallest diameter (25-foot on dry  land;
150-foot for wetlands).
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                                References

Griffin, Lynn.   Environmental  Specialist.  Department of
    Environmental  Regulation.   Letter to W.A.  Tel "hard, EPA, March 22,
    1985.

State of Florida regulatory and review procedures for land
    development.  Chapter 14.   November 1,  1984.

Wise, Lloyd.   Region IV NPDES  permit writer.   1985.   Summary of EPA
    workshop  presentation,  Onshore Oil  and  Gas Workshop Meeting Report.
    July 1985.

Personal Communications:

    David Curry, Florida  Department of Natural  Resources (904)  487-2219.

    Lynn Griffin,  Environmental  Specialist,  Department  of Environmental
    Regulation,  October 2,  1986 (904)  488-8615.
                                   A-63

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                              ILLINOIS

INTRODUCTION
                                                          Q
    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.

REGULATORY AGENCIES

    Principally, one agency regulates the oil and gas industry in
Illinois:

    •  Department of Mines and  Minerals, Division of Oil and Gas.
                                                               t

    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 related rules and regulations.  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.  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  placed in a location where it could
                                   A-61

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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  primacy for Class II
wells.  While there are  Federal  lands  in Illinois,  there is no drilling
or production on these lands at  present.   The  Illinois  Environmental
Protection Agency has been delegated NPDES authority;  however,  no surface
water discharges from the oil  and  gas  industry are  allowed.

STATE RULES AND REGULATIONS

Drilling

    Before a new well is drilled,  the  operator must execute a bond of
$2,500 unless the operator already has a blanket  bond  of $25,000.  The
                                                     i
bond  is canceled only after  the  well  has oeen  plugged  and all  related
restc/ation activities have  been completed.

    There are no State requirements that drilling pits  be permitted or
lined.  Fluids from the  pits may be disposed  of  in  a dry drill  hole.
When  the pit mud dries,  the  pit  is backfilled  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  that will  prevent seepage.   Most requests
are for fiberglass- or concrete-lined  pits.   Earthen-lined pits have been
substantial!;, eliminated during  the oast 5 years.  The Department of
Mines and Minerals has been reducing the number  of old pits by removing

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and injecting the produced waters, stabilizing the contents, applying
topsoil, and vegetating the pit area.

    Neither roadspreading nor landfarming 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 inj-ection 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 one-half mile of the proposed new or converted
injection well, as well as 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 freshwater
strata. Injection must be through adequate tubing and packer.

    A mechanical  integrity pressure test must be carried out before
injection is initiated.  Thereafter, the well must be tested at least
                                                                  . -vr
every 5 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 300 psi or the maximum authorized
injection pressure, whichever is greater.  The same range applies for
newly converted wells or for retests, except that the ceiling is
1,000 psi.

Offsite Disposal

    Offsite or commercial pits are not used in the State of Illinois.
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 contracted for the removal.
                                    A-63

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PIugging/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 6 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,  a bond is required
from the operator if no bond covering the well  is in effect.   This bond
remains in  effect until the well is plugged.   If, at expiration of the
extension,  the 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  the surface  casing was not used, a 25-foot plug must be used
below the surface with  a 1-foot mushroom cap. Where a surface casing was
used, the casing must be cut off 3 feet below the ground and  a 1-foot cap
should be added.  Mud must fill the remainder of the well.  There are no
specific provisions for plugs over zones with potable water.
                                   A-64

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                                 References

Interstate Oil and Gas Commission.  1986.  Summary of State statutes and
    regulations for oil and gas production,  June 1986.

Interstate Oil Compact Commission.  1985.  The Oil and Gas Compact
    Bulletin. Vol. XLIV, No. 2, December 1985.

State of Illinois.  1984.  An act in. relation to oil, gas, coal and other
    surface and underground resources.  Revised edition.

      ..  1984.  Rules and regulations.  Department of Mines and
    Minerals, Division of Oil and Gas.  Revised edition.

USEPA.  1985.  U.S. Environmental Protection Agency.  Illinois Meeting
    Report.  Proceedings of the Onshore Oil and Gas Workshop
    (March 26-27 in Atlanta, Ga.).  Washington, D.C.:  U.S. Environmental
    Protection Agency.

Personal Communication:

    George R. Lane, Division of Oil and Gas (217) 782-7756.
                                    A-65

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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.

REGULATORY AGENCIES

    The two agencies that principally regulate  oil  and  gas  activity  in
Indiana are:

    •  Indiana Department of Natural Resources,  Division  of Oil and
       Gas;  and
    •  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 only as a result of the improper disposal  of oil  and  gas wastes.
Any concerns that owners of Federal lands may  have regarding oil and  gas
surface treatment are satisfied through the conditions  of the  respective
lease agreements.

    The Oil and Gas Division does not have primacy for  UIC  program Class
II wells; however, the State is in the process  of  attaining such status.
Currently, anyone interested in underground injection must  obtain two
permits — one from the State and one from the  U.S.  Environmental
Protection Agency.
                                   A-67

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STATE RULES AND REGULATIONS

Drill ing

    Adequate pits are required  for  muds  or  wastes  associated with
drilling operations.   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 inixed 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 2  years  ago.

PIuggi ng/Abandonment

    Any well that is  not  producing  must  be  capped  and  sealed
immediately.  If not  placed back  in production within  2  years, the
operator may be required  to plug  and  abandon the well,  to  recase the
well,  or to demonstrate (through  pressure testing  or another approved
method) that the well  casing is in  good  condition  and  there  is no
commingling of fluids.
                                   A-68

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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 commercia"1 deposits of coal.  Where insufficient casing is
set or surface casing was not cemented to the surface, production casing
should be removed from 50 feet below the deepest aquifer containing
potable water, and a cement plug should be placed from the remaining
production string to 3 feet below the surface.  In the case of a dry hole
that 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.
                                    A-69

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                                References


Interstate Oil  and Gas Commission.   1986.   Summary of State statutes and
    regulations for oil  and  aas  production.  June 1986.

Interstate Oil  Compact Commission.   1985.   The Oil and  Gas Compact
    Bulletin.  Vol. XLIV,  No.  2,  December 1985.

Personal  Communication:

    Mike  Nickolaus,  Indiana  Division  of Oil  and Gas (317)  232-4055.
                                   A-70

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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 oil wells and 12,680 gas
wells.  Kansas ranks  seventh in both U.S.  oil  production and U.S. gas
production.  There are 14,935 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.

REGULATORY AGENCY

    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 that  date, 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
produced water and enhanced recovery injection wells.  Under Kansas'
Statutes  (Chapter 55, Article 10, 55-1003) plans and specifications for
the disposal of oil and gas produced waters  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  1986
legislative action, the Secretary of Health  and Environment no longer is
a party to such action.
                                   A- 71

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    There are few Federal  lands  and  little  involvement  of Indian tribes
in the Kansas oil and gas  industry.   When  an  application for a permit to
drill  has been received,  notice  is published  routinely  in local  news
outlets.   If requirements  are  specified  by  the  Bureau of Land Management
or Indian tribes, they are communicated  directly to the driller through
lease agreement conditions or  by other legal  means.

STATE RULES AND REGULATIONS

Drill ing

    The industry is regulated  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 has revised and implemented regulations  pertaining to those
activities formerly administered by  the  Secretary of Health  and
Environment.

Pit Requirements

    Until May 1987, drilling  pits and burn  pits were permitted and
regulated under a general  rule for a maximum  period of  365 days  unless
the operator requested and received  approval  for an extension.  A
separate permit application was  not  required.   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 were
required for emergency pits.
                                   A-72

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    Liners are not required for drilling pits unless the Commission
determines that a liner is necessary to protect soil or water .resources
in geologically or hydrologically sensitive areas. In such areas, liners
or portable pits may be required.  In areas with sandy soils, for
example, drilling pits must be lined.  In the heavy clay region of the
north-central portion of the State, however, such pits most likely would
not be 1ined.

Pit Closure

    Onsite burial, after evaporation or mechanical dewatering, is the
primary method of pit closure.  After May 1, 1S87, 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.
 a.
Produced Waters

Injection

    Ninety-nine percent of produced water is disposed of into injection
wells for enhanced recovery (9,399 wells) or for saltwater disposal
(5,536 wells).  The Kansas Corporation Commission has primacy for the UIC
Class II  program.  Operators may inject produced salt water 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 mineralized water-bearing formation that is not oil or gas
producing in the area of the proposed disposal, or to other subsurface
water-bearing formations that contain or previously produced salt water
or mineralized water exceeding 10,000 mg/L IDS.  Enhanced recovery and
waterflood injection wells must return water to an oil-producing zone,
but not necessarily to the one from which it originated.
                                    A-73

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    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  should  be filled with a
corrosion-inhibiting fluid or  hydrocarbon liquid.   Packerless or
tubingless pressure  completions may be  authorized  under special
conditions.  (For  example, disposal  through tubing without a packer must,
among other requirements,  have no  surface wellhead pressure.)  Wells must
be cased and cemented  in such  a manner  as to prevent  damage to
hydrocarbon sources  or fresh  and usable water sources.

    Mechanical  integrity tests must be  conducted before injection begins
and at least every 5 years thereafter.  Packerless wells should  be tested
using a  retrievable  plug immediately  above the uppermost perforation or
open-hole zone.   The test  pressure must be 100 psi for  old wells, 300 psi
for new  wells,  or  the  authorized injection pressure,  whichever is
greater.  The  duratron of  the  test is 30  n.nutes and  the usual limit
allowed  for loss of  pressure  is 10 percent.

Other Storaqe'Disposal Practices

    Spreading  of salt  water on roads  under construction, as well  as for
maintenance, is  allowed if approval  is  received from  the Kansas
Department of  Health and Environment.

    Requests for a surface pond permit  are statutorily  granted unless
denied by the  Commission within 10 days.   According to  proposed  Rule
82-3-600, the  Commission,  in  approving  aoplications for surface  pond
permits, must  consider the protection of  soil and  water resources from
pollution.  Each operator  of  a surface  pond must install observation
trenches, holes, or  observation wells  if  required  by  the Commission, and
seal the pond  with artificial  material  if the Commission determines that
                                   A-74

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an unsealed condition will present a pollution threat to soil or water
resources.  Surface drainage must be prevented from entering the pond.
During the past 2 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 ground-water supply.

    There are approximately 25 permanent p-ts, receiving a total of
30 barrels of produced water a day, mostly in the southeast corner of the
State where there are no ground-water or seepage problems and where IDS
concentrations of the produced waters are less than 10,000 ppm.  Neither
surface discharges of produced water nor pit disposal are allowed.

    Upon  the permanent cessation of the flow of fluids into any surface
pond, all fluids resulting from oil and gas activities, plus rainwater
(salt contaminated), must be removed to a disposal well approved by the
Commission, or used for lease 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 Disposal

    Use is not made of offsite or commercial pits.

PIugging/Abandonment

    Kansas Statute 55-156 states that prior to abandonment of any well
that has  been drilled, is being drilled, or may hereafter be drilled, the
operator  shall protect usable ground water or surface water from
pollution, and from loss through downward drainage, by plugging the well
                                    A-75

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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.   Temporary  abandonment
approvals are issued by  the Commission only  after a field inspection and
fluid level measurement  have been conducted  to determine that there is no
evidence of casing holes.   A mechanical  integrity test  or remedial action
on the well may be required if the water level  measurement indicates
problems.

    Cement plugs of at least 50 feet in  length must be  placed above each
present or past productive formation,  and both above and below any
freshwater horizons.   Intervals between  all  plugs must  be filleo* with
approved heavy mud-laden fluid.
                                   A-76

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                                 References


Interstate Oil and Gas Commission.  1986.  Summary of State statutes and
    regulations for oil and gas production, June 1986.

Interstate Oil Compact Commission.  1985.  The Oil and Gas Compact
    Bulletin, Vol. XLIV, No. 2, December 1985.

The State Corporation Commission of the State of Kansas.  General rules
    and regulations, effective May 1, 1986.

USEPA.  1985.  U.S. Environmental Protection Agency.  Kansas Meeting
    Report.   Proceedings of the Onshore Oil and Gas State/Federal Western
    Workshop  (March 26-27 in Atlanta, Ga.).  Washington, D.C.:  U.S.
    Environmental Protection Agency.

Personal Communications:

    Rick Hesterman, Kansas Corporation Commission (316) 263-3238.

    Jim Schoff, Kansas Corporation Commission (316) 263-3238.
                                    A-77

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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.
REGULATORY AGENCIES

    The five agencies that regulate  oil and gas activity in Kentucky are:

    •  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;  and
    •  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  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.
                                   A-79

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STATE RULES AND REGULATIONS

Drill ing

    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 (under Title 401, Chapter 47 -  Solid Uaste  Facilities)  for
construction and operation, provided that the pit life is no longer'than
30 days after completion of exploration  or drilling activities.  Where
the pit life is longer than SO^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 is.no longer  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 20 mil 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 aboveground around the pit.  Surface
waters must be diverted 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 that specified a
water quality criterion of 600 mg/L chloride as a 30-day average, with a
maximum concentration not to exceed 1,200 mg/L at any time, as
appropriate for receiving water quality.  It is anticipated that there
will be a number of requests for NPDES permits to discharge produced
fluids.
                                    A  80

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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 the producer, the
amount of fluid, and its destination following transportation must be
reported.  Most of the fluid goes into injection wells.

    There is no roadspreading or landspreading of produced fluids  in
Kentucky.  Some use currently is being made of mechanical evaporation.

PIuggi ng/Abandonment

    A well may be temporarily abandoned for cause for 2 years on a
renewable basis. The well must be capped in such a way as to prevent the
escape of oil, gas, or water from the well, or the 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 is placed 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.352.180].   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

Interstate Oil  and Gas Commission.   1986.   Summary of State statutes  and
    regulations for oil  and gas production,   June 1986.

Interstate Oil  Compact Commission.   1985.   The Oil and Gas Compact
    Bulletin,  Vol. XLIV,  No.  2. December 1985.

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
                                                               g
    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 the State's  14,436 gas wells  are
marginal (produce less  than  60,000 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."

REGULATORY AGENCIES

    Four agencies regulate oil and gas activity in  Louisiana.  They are:

    •  Louisiana Department  of Natural Resources, Office of
       Conservation;
    •  Louisiana Department  of Environmental Quality;
    •  U.S. Bureau  of Land Management; and
    •  U.S. Army 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
                                   A-C3

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Title 30 of the Louisiana  Revised  Statutes  of 1950.   The Office of
Conservation hcis 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 produced  waters 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 on Federal
agencies.  (See Volume 1,  Chapter  VII.)   The  Bureau  of Indian Affairs has
some jurisdiction in limited areas of Louisiana.

STATE RULES  AND REGULATIONS

Drill ing

Pit Construction/Management

    Reserve pits used in  the drilling of oil  and gas wells do not have to
^e lined.  However. Louisiana  Statewide  Order  No.  29-B contains stringent
operational requirements  tor reserve pits,  including segregation of the
                                   A 34

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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 6 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, as well as 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 freshwater "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 that
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/L
    Total suspended solids                   50 mg/L
    Chemical oxygen demand                  125 mg/L
    Total chromium                            0.5 mg/L
    Zinc                                      5.0 mg/L
    Chlorides                               500 mg/L
    pH                                        6.0 to 9.0.

                                    A-85

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    There are provisions  for dilution of the wastewater to meet the
chloride limitation,  provided all  other parameters are met (i.e.,
prediction chloride  concentrations must be less than 2,000 mg/L in
freshwater areas and  less  than four times ambient chlorinity in brackish
and saline areas).

    Reserve pit fluids may be disposed of onsite if applicable technical
criteria are met.  For land treatment, burial,  or trenching, waste/soil
mixture must not exceed:
    pH
    Arsenic
    Barium
    Cadmium
    Chromium
    Lead
    Mercury
    Selenium
    Si 1ver
    Zinc
   6-9
   10 ppm
2,000 ppm
   10 ppm
  500 ppm
  500 ppm
   10 ppm
   10 ppm
  200 ppm
  500 ppm.
    Onsite land treatment may be used to close pits containing only
nonhazardous oil field wastes by mixing wastes with soil from pit walls
or levees and adjacent areas, provided the resultant waste/soil mixture
meets the above criteria, has an oil  and grease content of no greater
than 1 percent (dry weight),  and meets additional parameters in
freshwater wetlands not normally inundated and in uplands:
    Electrical conductivity (EC)
    Sodium absorption ratio (SAR)

    Exchangeable sodiio °* (ESP)
      < 8 mmhos/cm (wetlands)
      < 4 mmhos/c;n (uplands)
      ^14 (wetlands)
      <12 (uplands)
      -25:i (wet'ands)
      <15:» (uplands).
                                   A-86

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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 a moisture
content <50 percent by weight, EC 12 mmhos/cm, and an oil and grease-
content 3 percent by weight.  The. top of the burial site must be at least
5 feet below ground level and covered by native soil; the bottom should
be 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 to 12 and do
not exceed the following limits in leachate tests:

    Oil and 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 a
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.
10.0 mg/L
0.5 mg/L
10.0 mg/L
0.1 mg/L
0.5 mg/L
Lead
Mercury
Selenium
Silver
Zinc
0.5 mg/L
0.02 mg/L
0.1 mg/L
0.5 mg/L
5.0 mg/L
                                    A-87

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Production

Pits

    All  production pits must be lined so 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
                                                 _7
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 that 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/L (monthly sample).  A report
is required  on monthly volumes  discharged and on oil  and grease, and an
annual report is required 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 jf 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 freshwater bodies
are given for the Mississippi River and its tributaries belcw. Venice and
the Atchafalaya River below Morgan City.
                                   A-88

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    New regulations, issued in November 1985, for the first time required
that all of the above discharges be permitted.  A mailing, sent out in
1986,  required the filing of information and permit applications for
current discharges.  When these applications are received and evaluated,
discharges actually occurring -in freshwater areas not covered by the
above exceptions would be required to end.

In.lection

    Over two-thirds of the 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, 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
5 years.  Test pressures should be at the maximum permitted injection
pressure, but within the interval of 300 to 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

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of funding for proper closure of the facility.   A send or irrevocable
letter of credit must be provided for closing,  based on closing costs
estimated in the facility plan.   Insurance against any liabilities that
may be incurred must be provided through certificates of insurance,
letters of credit,  or othar acceptable financial  instruments.  Required
minimums are 51 million for commercial facilities operating open pits;
5500,000 for commercial facilities that store,  treat, or dispose of
nonhazardous oil field 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 oil field  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)
PH
Oil and grease
EC
SAR
ESP
6.5 - 9
5%
10 mmhos/cm
12
15'.
6.5 9
3%
10 mmhos/cm
12
15%
   (c)

6.5 - 9
15  ppm
0.75 mmhos/cm
10
                                   A -90

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                      (a)
                        (b)
                     (c)
TSS
COD
Chloride
Arsenic
Barium
Cadmium
Chromium
Lead
Mercury
Selenium
Silver
Zinc
   40 ppm
3,000 ppm
   10 ppm
1,000 ppm
1,000 ppm
   10 ppm
   10 ppm
  200 ppm
  500 ppm
   10 ppm
3,000 ppm
   10 ppm
1,000 ppm
1,000 ppm
   10 ppm
   10 ppm
  200 ppm
  500 ppm
 60  ppm
125  ppm
500  ppm
0.2  ppm
undetermined
0.05 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 oil field 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; and EC is
8 mmhos/cm.

    A complete manifest system tj track the transportation and disposal
of wastes taken to offsite con.mercial facilities is enforced.

PIuggi ng/Abandonment

    Wells must be  plugged within 90 days of notice in the "Inactive Well
Report" unless the operator submits a plan describing the well's future
use; the well is then classified as having future utility.
                                    A-91

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    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 must run from 50 feet below to
50 feet above the shoe of the surface casing.   If freshwater strata are
not protected by the casing,  a cenent plug must extend from 100 feet
below to 150 feet above  the deepest freshwater stratum, and a plug should
be placed from 50 feet below to 50 feet above  the shoe of the surface
casing.  A 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 that
cannot be practically removed,  a 100-foot  cement plug must be placed with
its bottom as near  as possible to the top  of the liner or screen.
Mud-laden fluids must fill  those portions  of the well  not filled with
cement.

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                                 References
Interstate Oil  Compact Commission.  1985.  Oil and Gas Compact Bulletin,
    Vol.  XLIV,  No. 2, December 1985.

Louisiana State Statutes 1950 30:204.

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  Communication:

    Lynn Wellman, Water Pollution Control Division, Office of Water
    Resources,  Department of Environmental Quality (504) 342-6363.
                                    A-93

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                             MARYLAND

INTRODUCTION

    In 1986 Maryland  produced 20 million cubic feet  of  gas  from six gas
wells and no oil.

REGULATORY AGENCIES

    The two agencies  regulating oil and gas activities  in Maryland are:

    »  Department  of  Natural Resources, Geological Survey;  and
    •  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  general public laws of Maryland provides that a
person may not dispose of  any product of i. gas or  oil well  without a
permit issued by the  Department.  The Department has both NPDES
delegation and UIC 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.
                                   A-95

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    A pit may be lined with an impervious material  such as clay or a
plastic to prevent ground-water pollution.   Fluids  introduced to lined
pits generally are transported to a produced water  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 ground-water discharge permit
issued under Code of Maryland regulations.   The requirements associated
with pit  contents that would meet permit conditions  for ground-water
discharge are determined on a site-by-site  basis.   If there is surface
discharge from a pit, an NPDES permit would be required.

    Because of the absence of facilities, the State  currently has issued
neither an NPDES permit for surface discharges nor  a UIC  permit for
underground injection.  There is a ground-water 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 a nearby stream, but  there are no
monitoring limits and no monitoring wells.

Offsite Disposal

    The only offsite disposal pit used in the State  is the one in western
Maryland described above.  Soire transported production fluids are
received by this facility.

PIuggi ng/Abandonroent

    There are no specific requirements in the regulations relating to the
t-Te within which a well must be plugged.
                                   A-96

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    When plugging, the well Tust 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 should be filled with
nonporous material to within 2  feet of the surface.
                                    A-97

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                                References
Interstate Oil  and Gas  Commission.   Summary of State statutes and
    regulations for oil  and  oas  production,  June 1986.

Interstate Oil  Compact  Commission.   1985.   The Oi1  and Gas Compact
    Bulletin,  Vol. XLIV,  No.  2,  December 1985.

Personal  Communications:

    Bob Creter  and David  Fluke.  Department  of Health,  Office of
    Environmental  Protection  (301)  791-4787.

    Al  Hooker,  Department  of  Natural  Resources,  Bureau of Mines
    (301)  689-4136.
                                   A-98

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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 12th in U.S. oil  production and 13th 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

    The five agencies  that  regulate  oil and gas activities in Michigan
are:

    •  Michigan Department  of Natural Resources;
    •  Michigan Department  of Commerce, Public Service Commission;
    •  U.S.  Forest Service;
    •  U.S.  Bureau of Land  Management; and
    .  U.S.  Environmental  Protection Agency.

    The Michigan  Oil and  Gas  Act  of  1939 (PA 61) established the position
of Supervisor of  Wells and  designated 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 will be referred
to as the Supervisor.   The  Supervisor has authority to subpoena, to
establish well  spacing requirements, to develop orders without
                                   A-99

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legislative interference,  and  to control  the disposal  of solid and liquid
wastes from aril ling.   The Oil  and  Gas Act provides the Supervisor with
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  environmenta1  assessment, and spacing
minimums. and approves all well construction design.

    The Water Resources Commission  Act of 1929 (PA 245) regulates
discharges to and the pollution of  any waters of the  State; NPDES permits
are issued under Act 245.   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.  Law enforcement conservation
officers of the Department of Natural Resources provide liaison with the
Attorney General  and the county prosecutors  in dealing with local court
actions.  Where a ground-water  problem has been identified through
investigation and monitoring by the Geological Survey Division, and
ground-water restoration is required, the Water Quality Division issues
an NPOES permit for discharging the restored water.

    The Air Quality Division of the Department of Natural Resources
regulates gaseous emissions to  the  atmosphere, while  the Michigan Public
Service Commission regulates the production  of gas from dry natural gas
reservoirs and the safety of gas pipeline construction.
                                   A-10C

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    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 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
have been 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 the 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

Drilling

    There are  several 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 when a
well to be drilled will encounter only fresh water  (as in the southern
part of the  peninsula), such an exception is rarely  requested.
                                   A-1C1

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    Liners for mud pits must be made of an impervious material that will
meet or exceed the specifications for 20 :n-;i  virgin FVC.  Liners of other
than 20 mil virgin PVC must be approved by the Supervisor.  Liners must
be installed in a manner that would prevent vertical and lateral leakage,
and must be either one piece or have factory-installed seams.  Mud pits
cannot be built where the ground-water table is observed at the depth of
the proposed excavation.  In such cases, steel tanks are used and the
drilling muds are 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 and
mouse hol^s be equipped with a closed-end steel 'liner or otherwise sealed
or cased so that all fluids entering the cellar,  rat hole, and/or mouse
hole would not be released to the ground, but would instead be discharged
to steel tanks, the lined reserve pit, or the mud circulation system.
Aprons of 20 mil virgin PVC or other equivalent material should be
installed under steel mud tanks and overlapping the mud pit apron, and in
ditches or under pipes used for produced water conveyance from cellars to
pits or to steel mud tanks.

Pit Closure

    At closure, all free liquids above the solids in the mud pits must be
removed to the maximum extent possible and either reused or disposed of.
The remaining mud pit solids may be required to be stiffened (mixed with
earthen materials).  In any event, the residue is encapsulated and buried
onsite or removed to an approved waste disposal site.  For onsite
                                   A-1C2

-------
disposal, the edges of the pit liner must be folded over the pit, and a
separate piece of 10 mil virgin PVC should be 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 ground-water
unit.  If it can be shown that an identifiable entity is responsible,
damages may be sought administratively or through the courts.

Disposal

    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 of in Class II injection
wel1s.

    Two  additional  options are specified in Special Order 1-85.  The
Supervisor may authorize the disposal of fluids onsite 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 freshwater 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
spread on roads.  Special Order 1-85 prohibited the use of pit brines for
ice control on March 29, 1985, and prohibited their use for dust control
as of  September 1,  1985.

                                   A-103

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    Offsite disposal  in  approved  lined  landfills with leachate collection
systems is  also permitted.

Produced Fluids

Injection

    Over 90 percent of Michigan's produced waters are now disposed of by
injection into Class II  wells.  Such wells must have a surface string of
casing that is cemented  and completely  isolates the freshwater aquifers
from the downhole 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 doas not have delegated UIC authority,
EPA's Region V directly  implements the  mechanical integrity test
program.  We'ls are required to meet a  standard pressure test of 300 psi
for 30 minutes, with 3 percent  allowable bleed-off.

    Annular disposal of  produced  waters is prohibited.  Although
exceptions  are technically allowed under the regulations, none have ever
been requested.

Surface Disposal

    Produced waters were formerly used  for both ice and dust control in
Michigan.  Special Order 1-85,  issued or March 29, 1985, immediately
banned the use of produced water  for ice control.  The use of produced
waters for dust control  may continue through September 12, 1987 (provided
the produced waters meet specifications for benzene, toluene, and xylene
content).  Annual 1-year extensions may be granted allowing continued use
                                   A-lOi

-------
of brine for dust control.  Such 1-year extensions may continue until a
3-year DNR environmental  impact study has been completed.  The decision
as to whether to allow continued road application of produced waters will
be based on the results of this study.

Offsite 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
ground-water monitoring system, and a treatment process prior to the
discharge of waste leachate.

    Road disposal of produced waters remains temporarily available for
dust control; producers may provide oroduced waters to a hauler if the
hauler can verify in writing the authorization to receive produced waters
on behalf of a  governmental unH.

PIuggi ng/Abandonment

    Plugging operations must begin 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, produced water, and fresh water should 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.
                                   A 105

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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.

Debrabander, S.  1985.  Letter communication  to EPA.  Geological Survey
    Division,  Michigan Department  of Natural  Resources.

Interstate Oil and Gas Commission.  1986.   Summary of State statutes and
    regulations for oil  and gas production, June 1986.

Interstate Oil Compact Commission.  1985.   The  Oil  and Gas Compact
    Bulletin.  Vol.  XLIV,  No. 2, December 1985.

Order of the Supervisor of Wells,  Special  Order 1-85, dated
    March 29,  1985.

Supervisor of Mineral  Wells Instruction 1-34.   Use of Liners in  Earthen
    Drilling Pits,  Sealing of Cellars, Rat Holes, Mouse Holes and Other
    Procedures to Protect Ground Waters,  effective February 1,  1985.

USEPA.   1985.   U.S. Environmental  Protection  Agency.  Michigan Meeting
    Report.  Proceedings  of the Onshore Oil and Gas Workshop (March 26-27
    in  Atlanta, Ga.).   Washington, O.C.:   U.S.  Environmental Protection
    Agency.

Personal  Communications:

    Steve Oebrabander, DNR Geological  Survey  Division (517) 334-6976.

    Bill  Shaw, DNR Office of Water Quality (517) 373-8088.

    Rex Tefertiller,  Permits,  Geological  Survey Division (517)  334-6974.
                                   A-iC6

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                           MISSISSIPPI

INTRODUCTION

    Mississippi  produced  31,379,000 barrels of oil  in 1984  from  3,569 oil
               Q
wells; 210 x 10   cubic  feet  of  gas were produced from 715 gas  wells.

REGULATORY AGENCIES

    Four agencies regulate the  oil and gas activity in Mississippi:

    e  State Oil and Gas  Board;
    •  Mississippi Department of  Natural Resources, Bureau  of  Pollution
       Control;
    •  Department of Wildlife Conservation; and
    •  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 waters generated by the
onshore oil and gas industry.

    The Department of Wildlife  Conservation is responsible  for the
maintenance of fish and wildlife  wir.hin the State.
                                  A-107

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    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 from both  the  Federal  and State 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
the contents of the pit to  escape.

    The reserve pit must  be emotied of fluids,  backfilled, and compacted
within 3 months of the completion of drilling  operations.  Exceptions may
                                   A-108

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be granted -if warranted, and the reserve pits may be used as test pits,
with the 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 L 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.  The muds may  also 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/L
                                                 i
         pH                                      6-9
         Suspended solids                        100 mg/L
         Specific  conductance                    1,000 mmhos/cm
         COD                                     250 mg/L
         Zinc                                    5 mg/L
         Chromium                                0.5 mg/L
         Phenol                                  0.1 mg/L.

    If the fluids  meet this limit, they can 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
into their pit regulations (in Rule  63, Section III.£.9).  After the
discharge, the dewatered muds are covered in place and the pit is closed
as noted above.
                                   A-109

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Production
Pits
    The regulations of the State Gil  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 that must be met in  their construction and
management.  When permits are issued for pits (other than reserve pits),

the longest permit period is 2 years.   In addition to reserve pits,

permits are issued for four types of pits:


    (1)  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 salt water is available"
         (e.g., in remote areas).  When permitted, these pits must be
         lined wjth 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 1 foot of the top.

    (2)  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 2 weeks after the emergency period, the pit
         must be emptied so as to contain no more than 2 feet of water.
         The fluid level must never rise to within 1 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 wat2r.

    (3)  Burn pits:  These pits may be used to burn tank bottoms and
         other refuse products.  The burn pit 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 the escape of
         contents or ingress of  surface water,  must never have fluid
         levels closer than 2 feet to the top of the pit walls, and must
         not be used for noncombustible fluids (except as these are
         naturally associated with the combustible wastes).
                                   A-110

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    (4)   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 emptied 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 salt water is permitted.  The Board's
policy  is that disposal in the annulus  is allowed only where the operator
can absolutely show that there is no endangerment to the environment or
fresh ground water, and can demonstrate that there is no economic
alternative.  The applicant must provide the Board with an economic study
of the  well and of the  economics of alternative methods of disposal.
Generally, such an economic demonstration could only occur in a setting
in which there was no well that could be converted to an injection 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 leaking through the casing and was
entering the correct zone.

    As  noted above, Mississippi does not have the delegated authority for
the regulation of Class II wells.  The  State does, however, issue permits
for all injection wells, and operators must obtain permits from both EPA
                                   A-lll

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and the State Oil  and Gas Board.   Tl-e State regulations require
information on wells within one-fourth mile of the proposed  injection
well,  injection pressure limited  to 75 percent 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 5 years thereafter.  Test
pressures are required to be at the maximum authorized  injection pressure
or 300 psi (for a new well), whichever is greater, with a ceiling of
500 psi (for a converted well).

Offsite Disposal

    Except for two .commercial pits in southern Mississippi,  both of which
are phasing down,  use is not made of of^site and commercial  pits within
the State.

PIuggi ng/Abandonment

    All wells that are drilled and found dry must be plugged within
120 days, unless an extension is  granted by the Supervisor.  A production
or service well that ceases to operate must be listed on the Inactive
Well Status Report after 6 months.  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
latter designation is assigned, the wel"! must be plugged within 120 days.

    When plugging a well in which the 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, the following placements
                                   A-112

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should be made:  a cement or bridge plug 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 ac 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 ber.
placed approximately 50 feet below  all freshwater-bearing strata and at
the bottom of the surface pipe.  A  plug must be placed at the surface of
the ground so as not to interfere with soil cultivation.
                                    A-113

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                                References
Interstate Oil  and Gas Commission.   1986.   Summary of State  statutes  and
    regulations for oil  and aas production. June 19£6.

Interstate Oil  Compact Commission.   1985.   The Oil  and Gas Compact
    Bulletin.  Vol. XLIV,  No.  2, December 1985.

State of Mississippi,  State Oil and Gas Board.  1986.  Statutes and
    statewide  rules and  regulations.   Revised July 1, 1986.

USEPA.  1985.   U.S. Environmental  Protection Agency.  Mississippi Meeting
    Report.  Proceedings  of the Onshore 'Oil and Gas Workshop (March 26-27
    in Atlanta, Ga.).   Washington,  D.C.:  U.S. Environmental Protection
    Agency.

Personal Communications:

    Richard Ball,  Mississippi  Department of Natural
    Resources,  Bureau  of  Pollution  Control  (501)  961-5171.

    Jerry Cain, Mississippi  Department  of  Natural
    Resources,  Bureau  of  Pollution  Control  ;601)  961-5073.

    Richard Lewis, Mississippi  Oil  and  Gas  Board
    (601) 359-3725.
                                   A-i!4

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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 had no commercial gas production
since 1977.

REGULATORY AGENCIES

    Two agencies regulate oil  and gas  activities in Missouri.  They are:

    •  Department of Natural  Resources, Division of Geology and Land
       Survey; and
    .  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, the Clean  Water Commission, the University of
Missouri, and two persons with knowledge 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.
                                   A-115

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    Federal  lands  in  Missouri  are  confined  to  U.S.  Air For« bases,  but
there is drilling  on  these  lands.   Whan  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  is then taken under the
Division of Environmental Quality  regulations.

STATE RULES AND REGULATIONS

Drilling

    Rule 10 CSR  5C-2.040 provides  requirements during the drilling  of
wells to prevent  contamination of  either surface or under-ground
freshwater resources.  Bonding is  required  before  oil  or gas drilling
operations are initiated 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 onsite.

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.

    Remaining 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
                                   A - i ] 6

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freshwater strata.  The specific casing and cementing requirements will
be based on the depth to the base of the 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.  No
manifest is required for the transportation of produced water.

PI uggi ng/Abandonment

    Notification  is required within 90 days after operations cease, and
the Council may specify temporary plugging to prevent pollution of
freshwater strata.  After 6 months, the operator must plug and abandon
the well unless granted an additional 6-mcnth extension for good cause.
Further 6-month extensions may be granted, up to a limit of 2 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.
                                   A-117

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                                References


Interstate Oil  and Gas Commission.   1986.   Summary of State statutes
    and regulations for oil  and gas production, June 1986.

Interstate Oil  and Compact Commission.   1985.  The Oil  and Gas Compact
    Bulletin.  Vol. XLIV.  No.  2, December 1985.

Rules and Regulations of  Missouri  Oil  and  Gas Council,  June 1985.

USEPA.   1985.   U.S. Environmental  Protection Agency.   Missouri Meeting
    Report.   Proceedings  of the Onshore Oil  and Gas State/Federal Western
    Workshop (March 26-27 in  Atlanta,  Ga.).   Washington,  D.C.:  U.S.
    Environmental  Protection  Agency.

Personal  Communication:

    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 produced water per day are produced from
the approximately 1,600 full-producing  oil wells.  The remaining stripper
wells each produce about 40 barrels  of  produced water per day.

REGULATORY AGENCIES

    The four agencies that regulate  oil  and gas activities in Montana are:

    •  Montana Department of Natural  Resources and Conservation1, Oil
       and Gas Conservation Division;
    •  Montana Department of Health  and  Environmental Sciences, Water
       Qua!ity Bureau;
    •  U.S. Environmental  Protection Agency,  Region VIII; and
    •  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.
                                   A-119

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    Region VIII  of the  Environmental  Protection  Agency issues UIC permits
for the injection  of produced  water  in  Montana.

    The Bureau of  Land  Management  uses  its  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  3  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,
                                   A-120

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to remain  in  a reserve  pit  for  up  to  a year  for  evaporation.
Alternatively, the  fluids may be treated  chemically  so  that  they  can  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  produced water;  strippers yield about  40  barrels per  day.  Most
produced water is  reinjected, but  some is disposed of by evaporation.  A
small amount  is disposed  of 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 can  only be  used for such purpose  when
the pit is underlaid by tight soil such as heavy clay or hardpan.   At no
•time should 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 it is  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  made to a  closed  basin  in  the northern part of
the
                                    A-121

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State.  Discharge limits include total  dissolved solids of less  than
1.000 mg.. L and an oil  and grease limit  of 15 mg/'L absolute with  an
average of 10 mg.'L.   Other discharge limits including phenols and metals
are imposed.

PI uggi ng/Abandonment

    Once a well  is no longer being used for the purpose for which it was
drilled, it should be plugged.   Nevertheless,  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).  At the point
that other wells in  that field  cease to produce because of depletion of
the reservoirs,  however, 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.
                                   A-122

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                                 References

Interstate Oil  and Gas Commission.  1986.   Summary of State statutes and
    regulations for oil  and gas production.  June 1986.

Interstate Oil  Compact Commission.  1985.   The Oil and  Gas Compact
    Bulletin. Vol. XLIV, No. 2, December 1985.

Personal  Communications:

    Abe Horpestad, Water Quality Bureau (406) 444-2459.

    Charles Maio, Administrator, Board of Oil and Gas (406) 656-0040.
                                   A-123

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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 basin and Red  Willow  and Hitchcock Counties.   Strippers
account for about 85 percent  of  the State production.

REGULATORY AGENCIES

    The three agencies that regulate oil and gas activity in Nebraska  are:

    •  Nebraska Oil  and Gas Conservation Commission;
    •  Nebraska Department  of Environmental Control; and
    •  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 Department 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.
                                  A-125

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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  freshwater gels.   After the mud
pit has dried, the  residues are landspread  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."  Produced  water may be disposed  of 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
freshwater 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 from the pit or
surface water from entering the pit.  Open pit  storage of oil is only
allowed during an emergency or by special permission from the Director of
the Commission.
                                   A-126

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Road Spraying

    Road spraying of produced water 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 produced waters 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.  Along with injection well applications,
information must be submitted on other wells within one-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 freshwater strata. Injection must be through adequate casing or
casing and tubing. Mechanical integrity tests must be at 125 percent of
the maximum authorized  injection pressure or 300 psi, whichever is
greater.  (Alternatively, for wells without tubing and packer, the
operator should record  the actual injection pressure weekly and report it
monthly.)

PI uggi ng/Abandonment

    There are no specific time requirements related to plugging of a
well.  It is State policy to encourage operators not to permanently plug
wells that have any further potential for secondary recovery operations.
Before plugging, the operator must notify the Director of the plans for
plugging, but the regulations make no mention of specific requirements
for positive approval or for having witnesses to the plugging.
                                   A-127

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The well  must be plugged  with  "mud-laden  fluid,  cement,  mechanical  plug
or some other suitable  material"  in  order to  prevent  migration of oil,
gas.  or water from the  strata  of  origin.
                                  A-128

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                                 References
Coubrough, Rob.  State regulatory information submitted in 1985.

Interstate Oil Compact Commission.  1985.  The Oil and Gas Compact
     Bulletin.  Vol. XLIV, No. 2, December 1985.

Nebraska Oil and Gas Conservation Commission.  Rules and regulations,
     December  1985.

USEPA.  1985.  U.S. Environmental Protection Agency.  Nebraska Meeting
     Report.   Proceedings of the Onshore Oil and Gas State/Federal
     Western Workshop  (March 26-27 in Atlanta, Ga.).  Washington, D.C.:
     U.S. Environmental Protection Agency.
                                   A-129

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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  i's applied to produced waters.  Between
200,000 and 500,000 barrels per  year of waters are produced in Nevada's
major production area (the  Carbonate Belt).   Reinjection of these waters
is accomplished collectively into some five to nine injection wells.  No
produced waters are discharged under the beneficial use subcategory.
Nevada has NPDES primacy, but  is currently negotiating for UIC primacy.

REGULATORY AGENCIES

  »  The four agencies that  regulate  the oil activity in Nevada are:

    •     Nevada Department of Minerals;
    •     Nevada Department of Conservation and  Natural Resources,
          Division of Environmental  Protection;
    •     Bureau of Land Management  (BLM); and
    •     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
onsite drilling and production,  and  issues all operation permits.
Operators must obtain permits  from both the Department and BLM.

    The Division of Environmental  Protection  in  the Department of
Conservation and Natural Resources has adopted Underground Injection
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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 pollutants.  The discharge
of any produced waters 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
1 ands.

     The Bureau of Land Management has jurisdiction ove,  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 40  CFR 144 and 146.  Operators must  obtain permits from both the
U.S. EPA and  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.  (See  Volume 1, Chapter VII.)
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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 there 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 declares 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."  Finally, Section 600.1 states, "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 that 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 should be done with cement and
heavy mud in order to seal hydrocarbon or water formations.
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                                References
Nevada Department of Conservation and Natural Resources, Division of
    Mineral  Resources.   Regulations and rules of practice and
    procedures.   Chapter 522.   December 20,  1979.

USEPA.  1985.   U.S.  Environmental Protection Agency.  Proceedings of the
    Onshore  Oil  and  Gas State/Federal Western Workshop (March 26-27 in
    Atlanta,  Ga.).   Washington,  D.C.:  U.S.  Environmental Protection
    Agency.

Personal  Communications:

    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.

    Cathy Loomis,  Engineering  Technician,  Nevada Department  of Minerals,
    September  26",  1986  (702)  885-5050.
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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.

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;  and
    •  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 protects
water quality by  regulating exploration and drilling, production, and
refining.

    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
Commission are the Commissioner of  Public Lands, the Director of the Oil
Conservation Division,  and the State Geologist.  The Commission serves as
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an appeals 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 specific statewide regulations relating
to freshwater protection from oil and gas discharges because of the
diversity of the climate, geology, and 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.

    The Oil and Gas Act also allows for the adoption of special  rules or
orders tailored to the particular characteristics of a production area.
As a result, rules have been adopted controlling specific disposal
practices in various geographic areas of the State.

    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
control standards and water pollution regulations.  It delegates the
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administration of the regulations it develops to constituent agencies.
WQCC is prohibited from taking any action that would interfere with the
exclusive authority of the Oil Conservation Commission over all  persons
and things necessary to prevent water pollution resulting from 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 in the production of oil and gas.

    The U.S. Bureau of Land Management (BLM) takes the lead in oil  and
gas drilling activities on Federal and Indian lands.  When 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 drilling or production activities.

    Issues involved when drilling on Indian lands currently remain
unresolved.  Some tribes have issued regulations concerning oil  and gas
drilling and production activities.  Other tribes have applied for  UIC
program delegation.  The State has not waived jurisdiction over  the
regulation of the oil and gas industry on Indian lands, however.
Nevertheless, in instances where tribal  regulations go beyond those of
the State, the tribal 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.
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In the southeast,  contamination  is  only now being detected that resulted
from oil  and 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 involved the
seepage of natural gas  into  water  wells.   An active plugging program for
old abandoned wells is  in effect.   Since  little ground-water monitoring
has been performed in northwest  New Mexico,  the extent of contamination
from casing leaks or unlined pits  is unknown.   In many areas,
contamination is  unlikely because  of deep ground water;  thick, low
permeability vadose zones;  and  small  volume discharges.  Additional
investigations are being carried out by the Division in  shallow
ground-water areas.

Drilling

    There is a general  regulatory  requirement  that the operator must
provide a drilling pit  sufficient  for the accumulation of drill  cuttings,
and that drilling fluids and drill  cuttings must be disposed of at the
well site in a manner that  will  prevent contamination of surface or
subsurface waters.  There are,  however, no specific rules on construction
of such pits.   The District  Supervisor would be responsible for
determining if a  potential  problem exists 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 usually dried out
through evaporation and the  dried  muds are buried in the pits.  The areas
of New Mexico in  which  oil  and  gas drilling occurs have significant net
evaporation.  In  the southeast,  annual rainfall averages 14 to 17 inches,
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with 80 inches of evaporation.  In the northwest, rainfall averages 7 to
12 inches annually and evaporation is 40 to 50 inches.

    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 areas of the State where oil and gas production
predominates.  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 in the northwestern
part of the State with potentially vulnerable aquifers.

    In the southeast, Order R-3221 prohibits the disposal of produced
water onto the ground or into unlined pits because of the presence of
shallow ground water, which could be adversely affected by the produced
water.  An exemption is made for pits receiving no more than 1 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 water and prohibits unlined pits  in
such areas. Exemptions are made (as long as ground-water depth is at
least 10 feet) if a pit receives no more than five barrels per day of
produced water and the water is less than 10,000 mg/L IDS, or if the pit
receives no more than one-half barrel per day.
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    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
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 to use produced water as drinking water for cattle (although
not for irrigation).  Agreement must be obta-ined 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 that the quality of the produced water is satisfactory for
such a purpose.
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In.lection

    Over 90 percent of the 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/L or less IDS will not be permitted except after notice and
hearing, unless the water being injected is of higher quality than the
native water in the zone.  The Division may establish exempted aquifers
for such zones, however, where such injections may be approved
administratively.

    Regulations impose the general requirement that injection wells must
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 reported immediately.   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 the failure is identified and corrected.

    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 last for
15 minutes at pressures in the range of 250 to 300 psi, with a maximum
variance of 10 percent.  Additional tests are required at least every
5 years.
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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
noncommercial  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 either lined or unlined pits,  so  long as they are
constructed adequately to protect fresh water.  For proposed centralized
pits, 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 ground water, or serves emergency purposes during
drilling for periods not exceeding 10 days.  Applications are required in
all instances where the pits  receive drilling or completion wastes.

    Uhere lining is required,  pits 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
its 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
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PIuggi ng/Abandonment

    Wells cannot be temporarily abandoned for more than 6 months unless a
permit  for temporary abandonment has been approved by the Division.  The
maximum period of the permit is 1 year, with an additional 1-year
extension possible.  The Division may waive this limitation and grant
further extensions in the case of a remote or unconnected gas well, a
presently noncommercial gas well that could become commercial in the
foreseeable future, or a currently nonproducing well with commercial
potential in a field where secondary recovery has been demonstrated to be
commercially feasible.  Such further extensions are limited to 2 years
but are renewable.

    Before a permit for temporary abandonment can be granted, evidence
must be furnished that the condition of the well is satisfactory and will
not allow damage to producing zones or contamination of fresh water.  A
one-well plugging bond may be required for any well granted an extension
for temporary abandonment.

    Specific wel1-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
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, Okla., pp.  151-154.

Interstate Oil  and Gas Commission.  1986.   Summary of State statutes and
    regulations for oil  and gas production.  June 1986.

Interstate Oil  Compact Commission.  1985.   The Oil  and  Gas Compact
    Bulletin.  Vol. XLIV.  No. 2, December 1985.

Order of the Oil  Conservation Commission of the State of New Mexico,
    Order Nos.  R-3221, and  R-3221-A through C.

Order of the Oil  Conservation Commission of the State of New Mexico,
    Order Nos.  R-7940  and R-7940-A.

Stamets, R.  L.  1985.   Director, Oil  Conservation Commission.   Memorandum
    regarding  Hearings for  Exceptions to Order No.  R-3221, dated October
    22, 1985.

State of New Mexico.   Water Quality Control /Commission  regulations.
    March 3, 1986.

State of New Mexico,  Energy and Minerals Department,  Oil  Conservation
    Division.   Rules  and  regulations.   April  1,  1986.

USEPA.   1985.   U.S.  Environmental  Protection  Agency.   New Mexico Meeting
    Report.   Proceedings  of the Onshore  Oil  and Gas State/Federal Western
    Workshop (March 26-27 in Atlanta,  Ga.).   Washington,  D.C.:   U.S.
    Environmental Protection Agency.

Personal Communication:

    David Boyer,  Hydrogeologist,  New Mexico Oil  Conservation Division
    (505) 827-5812.
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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 were 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 frequently over the last 20 years.  In fact, further
revisions are expected  in the next  few years 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:

    •  New York  Department  of Environmental Conservation;
    •  Bureau of Land Management  (Federally-held mineral rights only); and
    .  U.S. Forest Service  (surface activities in U.S.  forests).
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    Most oil  and  gas  activities  in  New York are regulated by the
Department of Environmental  Conservation  (DEC).   The Department 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."   DEC  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  that 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.   The Bureau's
regulations are discussed in a separate section,  Federal  Agencies.  (See
Volume 1, Chapter VII.)

    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, and the
Regulatory Affairs, Law Enforcement,  and  Lands  and  Forests  Divisions,
provide instrumental  manpower and enforcement  actions, when applicable.

STATE RULES AND REGULATIONS

Drill ing

    The Division  of Mineral  Resources in  the  Department of Environmental
Conservation issues all oil  and  gas drilling  permits.  The Mineral
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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 guidance regarding what practices constitute proper
disposal.  Rather, the operator must submit and receive approval of 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 nonpolluting and are specifically excluded from this
requirement.  Muds contaminated with oil or other pollutants must be
disposed of in a certified  landfill.  Drilling pits are dewatered and the
fluids are disposed of properly prior to reclamation.  During
reclamation, pit liners are shredded or removed and the rock cuttings are
disposed of in situ.  After drying, the cuttings are buried.
                                                                       . 4* .
    Other drilling wastes must be disposed of 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.  In
addition to the drilling permit, permits may be required for disposal or
discharge of drilling wastes (excluding drilling muds).

    Since 1982 DEC has required that all drilling pits be properly
constructed, sized, and lined.  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 most of the wells in New York are drilled with
air, and there is very little fluid associated with the drill cuttings in
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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."

    Produced waters generated during drilling are considered "polluting
fluids" in the Mineral Resources Regulations.  These 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 produced waters 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 Hater

    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
products.. Brine (i.e., produced water) may be stored in watertight 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, or 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 produced waters; since
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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 disposing of the dilute
produced waters associated with oil production in the old waterflooded
fields of New York is under NPDES permits.  Roadspreading is the
principal produced water disposal method for the concentrated brines
associated with the State's gas wells.  Roadspreading is conducted on a
manifest system under a separate permit.  Criteria for roadspreading are
established on a case-by-case basis and include such requirements as time
of day, use of spreading bar, prohibition on spreading during rainstorms,
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
produced water discharges from stripper wells under permits with the
following limitations:

         Oil and grease                  15 mg/L
         pH                               6 to 9
         Benzene                         10 micrograms/L
         Toluene                         10 micrograms/L
         Xylene                          10 micrograms/L.

    Sampling is done infrequently on any given well.  Annular disposal is
not allowed.

Offsite Disposal

    New York regulations do not address the use of offsite pits for long-
term storage or disposal.
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PI uggi ng/Abandonment

    Wells that are commercially producible may be shut in for 1 year, and
may be granted additional  1-year extensions (renewable) for good cause.
Wells may be temporarily abandoned for only 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 ever
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 the casing is left in the well,  15-foot plugs must be
placed at the top and bottom.   If the casing extending below the 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  the lower end of the casing
rested, and  the well should be filled with cement from that point to the
top.  Intervals between plugs  must be filled with heavy,  mud-laden
fluid.  If the 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
Cornell University.  Oil, Gas and Solution Mining Legislation in New York
    As Amended through September 1985.

Interstate Oil Compact Commission.  1985.  The Oil and Gas Compact
    Bulletin, Volume XLIV, No. 2, December 1985.

New York State Environmental Conservation Law, Article 23, Title 1-5
    (circa 1985).

New York State Statute 550.2, Subchapter B   Mineral Resources, Parts
    550 through 558, as amended.

USEPA.  1985.  U.S. Environmental Protection Agency.  New York Meeting
    Report.  Proceedings of the Onshore Oil and Gas Workshop (March 26-27
    in Atlanta, Ga.).  Washington, D.C.:  U.S. Environmental Protection
   • Agency.
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                          NORTH  DAKOTA

INTRODUCTION

    North Dakota  produced 45,624,000 barrels of oil  and 62 x 10   cubic
feet of gas in 1986.   Production was from 3,595 oil  wells and 103 gas
wells.

REGULATORY AGENCIES

    The following 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; and
    •  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 produced water;  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,
the operator must obtain a  State permit and meet additional stipulations
required by the U.S.  Forest Service.
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STATE RULES AND REGULATIONS

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 10-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
get underway, Commission  inspectors will  survey the site  for pit
location.  The inspectors  also decide  whether  or not to require a pit
1iner 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  a manner 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, wa-stes 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  removing the  fluid  from the pit and
redistributing the topsoil  that  was removed  from the site  at the  start 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  requirements set by the Forest Service.
The reclamation plan must  also  be approved by  the Forest  Service  before
implementation.
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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
of freshwater supplies.  At no time shall saltwater liquids or brines be
allowed to flow over the surface of the land or into streams.11  Surface
pits are not allowed for produced water storage.  Surface tanks are
allowed provided they are diked and leak-proof.

    Produced water may be disposed of by use of injection wells for
either enhanced recovery or disposal.  When use of a central tank battery
or central production facility is planned, 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 the movement of fluids into or
between the underground sources of drinking water.  Plans for drilling a
well must include*an analysis of all other pits within the applicable
area of review, the initiation 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 injection is
initiated and at least every 5 years thereafter (although regular
monitoring of the 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.
                                   A-155

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Offsite Disposal

    The State has several  commercial  produced water disposal wells but no
pits.   The produced waters hauled onto commercial facilities are stored
in tanks.

Plugging/Abandonment

    A well may be temporarily abandoned (generally for economic reasons)
and no casing can be pulled without the approval  of the enforcement
officer.  A plug must be placed at the top of the casing.  Wells that
have been shut in for long periods will be reviewed on a case-by-case
basis, including tests of casing integrity.   A well in which drilling
operations have been suspended for 6  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 must be set above the perforations and capped with five sacks
of cement.  Cement plugs are set 50 feet in  and 50 feet over the top of
each productive zone; a 100-foot plug is set half in and half over the
Dakota Formation; and a ten-sack plug is set 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.  1985.   Statutes and rules for the
    conservation of oil and gas.  January 1985.

U.S. Department of Agriculture Special  Forest Service stipulations,
    September 1986.

USEPA.  1985.  U.S. Environmental Protection Agency.  North Dakota
    Meeting Report.  Proceedings of Onshore Oil and Gas State/Federal
    Western Workshop (March 26-17 in Atlanta, Ga.).  Washington, D.C.:
    U.S. Environmental  Protection Agency-

Williams, Tex.  State regulatory information submitted in 1985.
                                   A-157

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                                  OHIO

INTRODUCTION

    Ohio produced 14,987,592 barrels  of oil  and  182.2  x  109  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.

REGULATORY AGENCIES

    Two agencies regulate oil  and gas activities  in Ohio:

    •  Ohio Department of Natural  Resources;  and
    •  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  produced
water 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 about 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 required by the Division.

    Ohio has been delegated NPDES authority.   NPDES permits  are issued
through the Ohio Environmental  Protection Agency, Water  Quality Division;
none are issued for the  oil and gas drilling  and'production  industry.
                                   A-159

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The jurisdiction of the Ohio EPA extends  to any pollution of the waters
of the State.   Where produced water spills  may impair waters of the
State, for example,  the Ohio DNR and the  Ohio EPA jointly coordinate
damage assessment and corrective measures.   When the potential  for
ground-water contamination  exists,  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 an
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

Dril1 ing

    Earthen pits may be used to contain produced water,  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 oe constructed to prevent the escape  of brine and such
                                   A-160

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substances."  There is no requirement for clay or synthetic liners,
unless prescribed on a site-specific basis in an area identified as being
hydrogeologically sensitive. When a history of ground-water" problems is
associated with an area, a plastic liner requirement is made part of the
drilling permit.

    The pits must be emptied and backfilled within 5 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 by either underground
injection or land application.

Produced Waters
                                                      t
    Recently enacted laws, which became effective on April 12, 1985,
established new standards for well operators and waste produced watar
transporters.  Produced water disposal has been a major environmental
issue in Ohio.  Well drillers now are required to submit a produced water
disposal plan stating the temporary storage method and ultimate disposal
method and the site for all produced water.

    Operators are required to identify the transporter of the produced
water including the transporter's address.  Anyone who transports
produced water 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.
This information includes a daily log that identifies the ultimate
produced water disposal such as the time and date of produced water
loading and the amount, roadspreading location, disposal well permit
number, time and date of produced water disposal, etc.  The driver must
maintain a daily log showing driver name, registration certificate
number, sites visited, and destination.
                                   A-161

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    Produced water production  is  estimated at 40,000 to 50,000 barrels
per day.   Recent reports  indicate that approximately 90 percent of
produced  water is disposed of  through injection wells,  10 percent 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 produced
water."  Earthen impoundments  may be used  for the temporary storage of
produced  water in association  with a saltwater injection or enhanced
recovery  we!1.

Roadspreadinq

    For roadspreading or  landspreading,  a  county,  township, or municipal
government must pass a resolution to allow produced wat°r disposal that
meets several minimum requirements:

    •  Prohibitions on produced water 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
       the 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.
                                   A-162

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Injection

    Ohio has delegated authority for Class II well injection.  Produced
water may be injected into wells for enhanced recovery (170 wells), into
disposal wells (182), or into the annulus of a producing well
(approximately 4,000 wells).  Permits are required for injection into
disposal wells or enhanced recovery wells.  Notification and approval are
required for annular disposal.

    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/L IDS or less than 5,000 mg/L chlorides, and must be
cemented to the surface.  Surface casing must be cemented to the 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 of 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 psi or at the maximum allowable pressure,
whichever is greater, for a period of 15 minutes, with no more than a
5 percent decline in pressure.  The mechanical integrity test must be
readministered at least once every 5 years.
                                   A-163

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    The maximum volumes  that  can  be disposed of with annular injection
are 10 barrels per cay (if the surface casing is sealed with cement) or
5 barrels per day (if sealed  with prepared clay).   Annular disposal can
use only the force of gravity.  Only salt water and standard well
treatment fluids can 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.

    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.   Produced water can be disposed of by
liquid-tight pipeline only at an  annular disposal  well.  No trucking of
produced water is permitted.

    Mechanical integrity must 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 Disposal

    When a history of ground-water problems exists, pit solids  may have
to be removed and transferred to  an Ohio EPA-regulated disposal site.  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 transfer to
a State-approved hazardous or nonhazardous landfill, as appropriate.
Abandoned pits are investigated when alleged to be the cause of a
ground-water problem.  If found to contribute to such a problem, the
owner of the pit must remove  the  solids and transport them to a
State-approved solids disposal facility.
                                   A-164

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PI uggi rig/Abandonment

    In Ohio, enforcement of plugging regulations is split between two
enforcement agencies.  Wells plugged in noncoal-bearing townships must be
plugged in accordance with rules adopted by the Ohio Division of Oil and
Gas, while wells plugged 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.

    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 as soon as the hole is abandoned.  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 6 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 cannot be pulled from a rotary drilled well.  Surface
casing can 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, must also be placed from 50 feet below
grade level to 30 inches below grade level.  If a clay plug is used, the
                                   A-165

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plug must extend from 50 feet below the base of the freshwater zone to
30 inches below grade.   All  portions of the well  that are not filled by
the plugs are to be filled with mud-laden fluid.

    After a well is abandoned,  the operator must  file,  with the Division
of Oil  and Gas, a detailed report containing information about the
plugging and the identity of witnesses  to the plugging.
                                  A-166

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                                 References


Chapter 1501, Rules of the Division of Oil and Gas of the Ohio Department
    of Natural Resources.

Chapter 1509 of the Ohio Revised Code.

Hodges, David H.  1985.  Letter communication to EPA.  Division of Oil
    and Gas, Ohio Department of Natural Resources.

Interstate Oil and Gas Commission.  1986.  Summary of State statutes and
    regulations for oil and gas production, June 1986.

Interstate Oil Compact Commission.  1985.  The Oil and Gas Compact
    Bulletin. Vol. XLIV, No. 2, December 1985.

USEPA.  1985.  U.S. Environmental Protection Agency.  Ohio Meeting
    Report.  Proceedings of the Onshore Oil and Gas Workshop (March 26-27
    in Atlanta, Ga.)-  Washington, D.C.:  U.S. Environmental Protection
    Agency.

Personal Communications:

    Ted DeBrosse,'DNR, Division of Oil and Gas (614) 265-6894.

    David A. Hodges, DNR, Division of Oil and Gas (614) 265-6917.

    Dick Schockley, DNR, Division of Oil and Gas (614) 984-2344.
                                   A-167

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                              OKLAHOMA

INTRODUCTION

    Oklahoma produced  153,250,000  barrels of oil and 1,996 x 109 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.   Approximately 200 million barrels of salt water are
produced by the oil  industry  per year.  There are about 7,900 saltwater
disposal wells and 14,900 enhanced  recovery injection wells.  About 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 (in Osage County); and
    •  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,  55 inspectors  have the authority to 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.
                                  A-169

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    The Oklahoma Water Resources  Board  is  responsible for the 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 to identify  spills  from oil  and gas  activities and refer
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 these cases  where  the  mineral  rights,  but not the
surface rights, are owned  by the  Bureau or  an Indian  tribe,  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  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
                                   A-170

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freshwater drilling muds from drilling and workover operations be kept
separate from the freshwater 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, fracturing, 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 they are
located) without a permit.  Notices of construction must be filed,
however, for emergency and burn pits  (Rule 3-110.1).

    Other than the general restriction against pollution, the only
requirements applying to reserve pits as well as other onsite pits are
that they must maintain the fluid level at least 18 inches below the
lowest point of the embankment, and they 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 to dispose  of drilling fluids: annular
injection, evaporation followed by burial of pit solids, noncommercial
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 onsite annular injection of
reserve pit fluids.   Surface casing injection (or intermediate casing
injection) may be authorized if the surface casing (or inter-mediate
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).

Landfarmi nq

    Permits (required) for noncommercial soilfarming can be applied for
only by the operator of the reserve pit, the contents of which are to be
landfarmed (Rule 3-110.3).  To apply for a soilfarming permit, the
operator iiust have a written agreement from the landowner that 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 that can 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 soilfarming.

    Soilfarming is limited to water-based muds and the cuttings and
accumulated precipitation in the pit of oil-based muds.  Soilfarming of
oil-based muds is prohibited.
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    Generally, landfarming is not allowed unless receiving soils are
suitable and the hydrology will not lead to pollution of surface or
ground waters.

    Specifically, landfarming is prohibited where:

    •  The land has a slope greater than 5 percent;
    •  The depth to bedrock is less than 20 inches;
    •  Floods occur more often than once every 2 years;
    •  The soil lacks 12 inches of loam, clay, silt, or  sand;
    •  Any of the soil is severely saline (>8,000 micromhos/cm); and
    •  A water table is within 6 feet of the soil surface.

    When soil farming 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 Ib/acre
    Total soluble salts                               6,000 Ib/acre
                                                      (less TSS  in soil)
    Arsenic                                              80 Ib/acre
    Cadmium                                               5 Ib/acre
    Hydrocarbons                                    100,000 Ib/acre
                                                         (5% by  weight).

    If hydrocarbon content is in excess of 20,000 Ibs/acre (1 percent by
weight), fertilizer may have to be incorporated  with the cuttings and
reserve pit effluent from oil-based drilling fluids.
                                   A-173

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    Runoff of soilfarmed 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

In.iection

    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 one-half 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 one-half mile of
the enhanced recovery or disposal  well, and to identify any abandoned
wells that were improperly plugged or remain 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.)
                                   A-174

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    Substances must be injected or disposed of through tubing and
packer.  Adequate aboveground extensions should 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 the 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 operators who elect to monitor their wells,
each disposal or enhanced recovery well must be pressure tested at least
once every 5 years.  The casing-tubing annulus above the packer must be
tested at 1,000 psi or the maximum authorized injection pressure,
whichever is lower, 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).

Offsite Disposal

    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).   However, there are also
approximately 100 commercial  offsite pits throughout Oklahoma, ranging
from less than an acre to 10  acres in size.   Some offsite pits may
contain over 3,000,000 barrels of waste,  which calculates to
387 acre/feet of fluids.

    For any commercial pit, a qualified  engineer must prepare a plan for
site selection, construction, and closure.   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 cannot be
built in a 100-year flood plain,  must be  built to prevent incursion of
outside water runoff, and must be managed to i,.uintain the surface fluid
level 36 vertical inches below the lowest point of the embankment.   Such
pits must be filled and leveled within 1  year after abandonment.

    Truckers hauling oil  and  gas  field wastes offsite must hold a
Deleterious Substance License, but do not have to report or mai-ntain
records on materials and volumes  transported.

Commercial Landfarming

    Under an order of the Corporation Commission, issued in June 1987,
commercial landfarming is permitted, provided the operator has obtained a
Commission Order to Landfarm a specific  trade, and receives a permit for
each application of waste.  Many of the  requirements for commercial
landfarming are similar to those for noncommercial landfarming, but some
are more stringent.  The least vertical  distance to ground water from a
                                   A-176

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commercial  operation, for example, must be 25 feet; for noncommercial
landfarming, only 6 feet is required.  The maximum application rates for
commercial  landfarming are:

    Total day weight of applied material        400,000 Ib/acre
    Total soluble salts                           6,000 Ib/acre
                                                (less TSS in soil)
    Arsenic                                          80 Ib/acre
    Cadmium'                                          5 Ib/acre
    Chromium                                         40 Ib/acre.

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.

    Where production casing has been run, a well must be plugged  within
1 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), and wells located on leases on which other wells are still
producing (if they have been granted a Temporary Exemption by the
Commission).  Operators of stripper wells may plug a well temporarily for
up to 2 years.
                                   A-177

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    Plugging must provide for sealing off each productive formation from
the wellbore 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 wellbore with adequate casing,  and (b) 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 a situation,  a bridge plug capped with 10 feet of
cement set  at the top of the producing formation is authorized.

    All freshwater strata in the well must be sealed off by adequate
casing from 50 feet below the base of the lowest freshwater stratum to
3 feet from the top of the wellbore, and by  completely filling the
annular space behind the casing with cement.   If surface or other casing
m^°ts the requirements,  a cement plug may be set 50 feet below the base
of the lowest freshwater stratum to 50 feet  above the shoe of the surface
pipe.  The  top 30 feet of the wellbore below 3 feet from the surface must
be filled with cement.  The surface pipe must be cut off 3 feet from the
surface and capped with a steel plate.

    Any uncased hole below the shoe of any casing to be left in the well
should be filled with cement to a depth of at least 50 feet below the
shoe of the casing, or the bottom of the hole, and the casing above the
shoe should 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 wellbore 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 1iner.
                                   A-178

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    All  intervals between cement plugs in the well bore must be filled
with mud of not less than 9 Ib/gal and not less than 36 viscosity.

    All  plugging operations must be conducted under the supervision of an
authorized representative of the Conservation Division.
                                   A-179

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                                References


The Corporation Commission of the  State of Oklahoma.  1986.  General
    Rules and Regulations of the Oil  and Gas Conservation Division.

Interstate Oil  and Gas Commission.   1985.  Summary of State statutes and
    regulations for oil  and oas production.  June 1986.

Interstate Oil  Compact Commission.   1985.  The Oil  and Gas Compact
    Bulletin. Vol. XLIV,  No.  2, December 1985.

Oklahoma Drilling Waste  Conference.

USEPA.  1985.  U.S. Environmental  Protecti-on Agency.  Oklahoma Meeting
    Report.  Proceedings  of the Onshore Oil  and Gas State/Federal Western
    Workshop (March 26-27 in Atlanta,  Ga.).   Washington,  D.C.:  U.S.
    Environmental Protection Agency.

Personal Communications:

    Tim Baker,  Oklahoma  Corporation  Commission (405) 521-2500.

    Mike Battles, Manager of Pollution Abatement,  Oklahoma Corporation
    Commission  (405)  521-4456.

    Karen Dihrberg, Geologist,  Water  Resources Board (405) 271-2549.

    Margaret Graham,  Permits,  Water  Resources Board (405) 271-2561.

    Walter Kramer, Oklahoma Corporation Commission  (405)  521-3088.

    Bob Thomas, Water Resources Board  (405)  271-2541.
                                   A-180

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                                OREGON

INTRODUCTION

    Oregon does not produce  oil.   Oregon's only producing gas field was
                                                               Q
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 produced water were
injected underground; about  5,000  barrels went to surface land disposal.

REGULATORY AGENCIES

    Two agencies regulate oil  and  gas activity in Oregon:

    •  Oregon Department of  Geology and Mineral Industries and
    •  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 are  on Federal lands.  If drilling were to take
place on Federal  lands in the  future,  there would be two separate
                                   A-181

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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  be discharged or placed
in pits and sumps approved  by the State Geologist and the State
Department of environmental  Quality. The  operator must provide  pits,
sumps, or tanks of  adequate  capacity and design to retain all  materials.
In no event should  the contents of a pit or sump  be allowed to:

    1. Contaminate  streams,  artificial  canals or  waterways, ground
       waters, lakes,  or rivers;  or
    2. Adversely affect  the  environment, persons, plants, fish,  and
       wildlife and  their population.

    When no longer  needed,  fluid  in pits and sumps must be disposed of in
a manner approved by the Department of  Environmental Quality.   In
addition, the sumps  must be  filled and  covered and the premises  must be
restored to a near  natural  state.  The  restoration need not be done if
arrangements are made with  the  surface  owner to leave the site suitable
for beneficial subsequent use.
                                   A-182

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    Drilling mud pits are not allowed to hold over the winter because of
lack of sufficient storage for winter rainfall.  If drilling muds dry in
the reserve pits before winter arrives, the pit is then closed.

    There has been no 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 of 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 of by injection into the strata from which they were
       produced or into other proved saltwater-bearing strata.
    3. Disposed of 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 an
       NPDES waste discharge permit.

    Produced brines are permitted to be spread on dirt roads--
predominantly  logging roads--if done in dry weather.

Offsite Disposal

    There are no operational offsite pits.  One dumpsite 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.
                                   A-183

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PI uggi 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.

    According to 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 an 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 4 feet below the ground and plugged with cement to a depth of
10 feet.  Intervals between plugs must be filled with heavy,  mud-laden
fill.
                                   A-184

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                                 References

Interstate Oil  and Gas Commission.  1986.  Summary of State statutes and
    regulations for oil and gas production,  June 1986.

Interstate Oil  Compact Commission.  1985.  The Oil and Gas Compact
    Bulletin. Vol. XLIV, No. 2, December 1985.

Olmstead, Dennis L.  1985.  LettercCommunication to EPA.  Oregon
    Department of Geology and Mineral Industries.

USEPA.  1985.  U.S. Environmental Protection Agency.  Oregon Meeting
    Report.  Proceedings of the Onshore Oil  and Gas State/Federal Western
    Workshop, December 1985.  Washington, DC.:  U.S. Environmental
    Protection Agency.

Personal Communications:

    Kent Ashbaker.  Department of Environmental Quality (503) 229-5325.

    Dan Wermiel.  Department of Geology and Mineral Industries (503)
    229-5580.
                                   A-185

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                          PENNSYLVANIA

INTRODUCTION
                                                              Q
    Pennsylvania 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 until 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.  House Bill 1375, passed 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  in the United States was drilled near
Titusville, Pennsylvania,  in  1859.

REGULATORY AGENCIES

    Five agencies regulate oil and gas activities in  Pennsylvania:

    •  Department of Environmental Resources, Bureau  of Oil  and Gas
       Management;
                                  A-187

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    .  U.S.  Environmental  Protection Agency, Region III:
    •  Pennsylvania Fish Commission:
    .  U.S.  Forest Service:  and
    .  U.S.  Bureau of Lard 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.  Section 216 of the Oil and Gas Act of
1984 created an Oil and Gas  Technical  Advisory Board to advise the
Department in  regulatory activities.  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 was 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
the affected supply or replace it with  an alternative source.  Section
205 prohibits  the 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 upon 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.
                                   A-188

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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.

     Requirements of the U.S. Forest Service and the U.S. Bureau of Land
Management are contained in lease agreements.  The well driller must
demonstrate that landowners and water supply owners have been notified 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 the 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 offsite and commercial treatment and disposal facilities and
to dispose of solid wastes onsite with pit reclamation.  Presently,
however, many pits remain onsite 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 produced waters.  If an impoundment is
associated with an individual well, a permit has not been required.

                                   A-189

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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, only a
few facilities within the State presently operate to treat solely
production wastewaters.

     Other production fluid disposal alternatives 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 the following:

       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; and
       Evaporation (through waste heat).

    Since these alternatives are not binding regulations, it  is largely
left to the operator to choose acceptable techniques for disposal

Offsite Disposal

    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 control of one owner/operator and the  geographic area is such
as to allow for effective monitoring and surveillance.
                                   A-190

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     The NPDES permit criteria and limits will be governed by receiving
water quality standards.  Generally, however, total suspended solids will
be limited to an instantaneous maximum of 60 mg/L and an average monthly
of 30 mg/L.  Oil and grease will be limited to an instantaneous  maximum
of 30 mg/L and an average monthly of 15 mg/L.  Dissolved iron has an
instantaneous maximum of 7 mg/L, and the acidity must be less than the
alkalinity.

PIuggi ng/Abandonment

     If wells are certified as having future utility and are in adequate
condition to prevent a  vertical  flow of fluids, contamination of fresh
water, or damage of productive zones, a permit can be issued for inactive
status. The permit is valid for  5 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:  (1) cement plugs of at least 20 feet should be set
20 feet above each stratum that  has had oil, gas, or water;  (2) a bridge
capped with 10 feet of  cement should be placed 30 feet below the water
string of casing, after which the casing may be drawn; (3) a plug should
be placed about  10 feet below the bottom of the largest casing in the
well; and  ($) 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  nonporous 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.
                                   A-191

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                                 References

Department of Environmental  Resources.  Rules and regulations.  Chapter
     97, industrial wastes.

Interstate Oil and Gas Commission.  1986.  Summary of State statutes and
     regulations for oil and gas production, June 1986.

Interstate Oil Compact Commission.  1985.  The Oil and Gas Compact
     Bulletin, December-1985.

Oil and Gas Act, Act of 12-19-84, P.L. 1140, No.223.

Oil and Gas Conservation Law, 1961, P.O.  825, No. 359.

Slack, Peter.  1985.  Letter communication with EPA Division of Permits
     and Compliance, Bureau of Water Quality Management, .Department of
     Environmental Resources.

Personal Communication:

     Carlyle Westlund, Bureau of Oil and Gas Management  (717) 783-9645.
                                   A-192

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                          SOUTH  DAKOTA

INTRODUCTION

    South Dakota produced  1,342,237  barrels of oil and 2.5 x 109 cubic
feet of gas in 1984.   The  State  has  145 full production and 33 stripper
oil  wells, and 41 full  production  gas wells and  1 marginal production gas
well.

REGULATORY AGENCIES

    These 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; and
    •  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, which also has nondelegated
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 the power to conduct
hearings and take action 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.
                                   A-193

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     In order 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 tne Bureau  regarding any predrilling permit
investigation.  Two permits,  one from each entity,  would be issued to the
driller.  When a request  to inject drilling fluids  underground is
received, the Bureau would defer to the State,  and  the State would issue
the injection permit.   Since  the Bureau has no means of holding hearings,
the State Board of Minerals and  Environment would do so 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 fluid in the drilling
pit is  allowed to evaporate and  the mud is allowed  to dry.  The time
interval required for this to occur is  a  various and unknown factor.
When the mud has dried  sufficiently,  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 wastes  is permitted to total retention-
evaporation ponds, to Class II UIC wells,  and for beneficial use.   There
                                   A-194

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are no specific requirements related to pit construction, but the State
is currently considering a proposal to require pits to have liners or to
be of impermeable construction.

     Discharge of produced water from a producing oil well is allowed
when a beneficial use of the water can be documented.  An NPDES permit is
required for such a 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/L, total dissolved
solids of 5,000 mg/L, and a pH of 6.0 to 9.0.  The flow is not to exceed
4,500 gallons per day.

Offsite Disposal

     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 under the Board of Minerals and Environment.

PIuggi ng/Abandonment

     A well may be classified as temporarily abandoned for a period of
6 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.
                                   A-195

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                                References

interstate Oil  and Gas Commission.   1986.   Summary of State statutes
     and regulations for oil  and gas production,  June 1986.

Interstate Oil  Compact Commission.   1985.   The Oil and Gas Compact
     SuTTetin,  Vol.  XLIV,  No.  2,  December  1985.

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.
                                  A-196

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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  produced  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.

REGULATORY AGENCIES

     Three agencies regulate  oil and gas activities in Tennessee:

    .  State Oil and Gas  Board;
    •  Tennessee Department of  Health and Environment; and
    •  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.  It does not  currently have UIC primacy but is working
                                  A-197

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toward being granted primacy  by  EPA.   Discharges  of oil  and gas wastes
are not permitted by the Tennessee  Department  of  Health  and Environment.

     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 most common
types of wastes 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  ground-water
contamination.

     The Board requires operators to  drain  surface pits  of water and
backfill them with dirt immediately after they are no  longer needed for
drill ing or testing.
                                   A-198

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Produced Water

     Produced salt water 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
of the Board. According to information provided by the Board, it  is now
the Board policy to require the lining of pits, particularly in areas
where produced  water will  be  the major constituent of  the fluids  in the
pit. The policy was adopted to prevent contamination of ground water 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.
»
PIuggi ng/Abandonment

     Dry wells  must be plugged within  6 months after drilling is
finished, with  an extension of 90  days for good cause. Gas wells  that
pass a deliverability  test may be  classified as shut-in indefinitely.
Wells no longer used for the  purpose for which they  were  drilled  or
converted must  be plugged. Wells that  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.  Adequate plugs must  be
placed to prevent the  commingling  of fluids and to isolate extractable
minerals.
                                    A-199

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                                References

State of Tennessee   State Oil  and Gas Board.  General Rules and
     Regulations,  Statewide Order  No.  2,  effective November 1972.

State of Tennessee State Oil  and Gas Board.   Oil  and Gas Laws in
     Tennessee Mineral  Test Hole Regulatory Act,  Amendments added
     1982.

Zurawski,  Ronald P.   1985.   Drilling Waste Conference submittal.

     ..   1985.  EPA-Onshore Oil  and Gas Workshop  request for information
     on Tennessee activity and  technology.
                                  A-200

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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:

       Texas Railroad Commission;
       Texas Air Control  Board;
       Texas Parks and Wildlife Department;
       U.S. Army Corps of Engineers;  and
       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.  The Railroad Commission
is responsible  for the prevention of  both waste and pollution.  Thus, one
agency is responsible for well  spacing, construction requirements
(casing, etc.), and most  aspects of environmental protection.

    In 1985,  the Texas legislature  amended  Section  91.101 of the Natural
Resources Code, as well as Section  26.131 of  the  Water codes, to make
explicit the scope of authority of  the Railroad Commission with respect
                                   A-201

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to activities related to the exploration,  development,  and production of
oil  and gas.   It specified that production activities include activities
associated with natural  gas or natural  gas liquids processing plants and
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.  It also specifically included within the
jurisdiction of .the Commission the drilling of injection-water source
wells that penetrate the base of usable 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 that were to be
considered related to "production."

    Statewide Rule 8 (governing "water protection") of the Railroad
Commission was amended effective 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 currently does not have NPDES jurisdiction, such discharges are
also subject to EPA permitting.

    The Railroad Commission has jurisdiction over Class II underground
injection wells and has undertaken a study to determine the need for a
Class  I well program for wells under its jurisdiction,  specifically wells
used for the injection of gas plant wastes.  Currently, all injection of
gas plant wastes in Texas is subject to Class II requirements.  The
preliminary results of the Commission's study indicate that gas plant
injection wells in the State meet Class II well criteria.

    The Texas Air Control Board has jurisdiction over the regulation of
oil field activities generating air emissions.
                                   •A-202

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    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. Army Corps of Engineers has permitting responsibility for
any activities that 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 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."  The
exceptions are authorized in Rule 8, under conditions specified in the
Rule.  The Rule's "authorizations" thus serve the same  function as
"general permits" in some other States.  Under Statewide Rule 9, permits
                                   A-203

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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), 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 ground water.  Proposed unlined pits, which will be
continuous-use saltwater pits, are also evaluated to determine whether
these pits would cause pollution of surrounding  productive agricultural
land.  The requirements may or may not include liners.
                                   A-204

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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/L chloride must be dewatered within
30 days of cessation of drilling operations.  Reserve pits  containing
fluids with a concentration of 6,100 mg/L 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 30 days and
backfilled and compacted within 120 days of cessation of completion or
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 as follows:
                                   A-205

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    .   Che-nica!  oxygen  demand                      < 200 mg/L
    .   Total  suspended  solids                       < 50 mg/L
    .   Total  dissolved  solids                     < 3000 mg/L
    .   Oil  and  grease                              < 15 mg/L
    .   Chlorides (coastal)                        < 1000 mg/L
    .   Chlorides (inlanc)                          < 500 mg/L
    .   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 -
       156.19.15.009.

    In coastal  areas, if the receiving body of water has concentrations

of TDS or chlorides in  excess  of 3,000 mg/L or 1,000 mg/L, respectively,
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 that meet specific conditions. The

authorizations  do not extend to oil-based drilling fluids, which require
a permit for  disposal.
                                   A-206

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    The authorization for landfarming applies where water-based drilling
fluids have a chloride concentration equal to or less than 3,000 mg/L.
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.

    Where the water-based drilling fluids have a chloride concentration
in excess of 3,000 mg/L, 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 than 90 percent of produced waters are disposed of by injection,
with most of the remainder disposed of in coastal ("tidally influenced")
waters.  Less than 1 percent is disposed of in pits.
Pits
    Individual permits are required for produced water 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 produced waters.  The 1984 amendment also required
the permitting of other types of pits that did not have to be permitted
prior to the amendment.  With the exception of emergency saltwater
                                   A-207

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storage pits,  permits for unlined pits will  be granted only if the
operator can "concl jsively"  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
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.

    Specific lining/monitoring requirements  are determined on a
case-by-case basis.  Generally, all  continuous-use pits (e.g.,  skimming
pits) would require linings, as would emergency saltwater storage pits in
sandy soils.

Injection

    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 disposal well  have
surface casing set to fully  protect underground sources of drinking water
with cement circulated to the  surface.  Rule 9 stipulates that  the well
must be equipped with tubing set on a mechanical  packer, set no higher
than 100 feet  above the top  of the permitted injection interval.

                                   A-208

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    Mechanical  integrity tests must  be conducted  before  injection  begins,'
and at least once every 5 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 they are  conducted at a
pressure within  10 percent of the  pressure required by the  formula.
However, once the casing pressure  stabilizes, a test  must be  conducted
for 30 minutes  with no variation.

    Specifications under Rule 46  for  enhanced recovery wells  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
qua!ity 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 produced water  must be
tested for oil  content every 30 to 40 days.

Offsite Disposal

Transportation

    Persons who transport produced water for hire (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

                                   A-209

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kept by the producer.   No requirements of this type are imposed on the
transport of drilling  fluids.

Disposal

    All offsite disposal  of oil  and gas wastes requires individual
permitting.  The primary  offsite facilities in Texas are disposal wells
that receive materials by truck.  There are approximately 200 Class II
commercial wells in Texas.

    In addition, there are  approximately 100 central disposal pits for
drilling fluids, 50 to 75 central  drilling fluid landfarming facilities,
and a few facilities for  the treatment and discharge of drilling fluids
in coastal areas.  Management requirements for these facilities are
determined on a case-by-case basis.

PIuggi ng/Abandonment

    Plugging procedures for dry or inactive wells that cease drilling or
operations between January  1,  1986, and January 1,  1988, must commence
within 1 year of the cessation of operations.  (For other wells, the
limit is 90 days.)  In addition, a 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
either posted a plugging  bond or letter of credit,  or presented a plan
for further use of the well in enhanced recovery operations.

    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 should be set by the circulation or squeeze method
through tubing or drill pipe, and should have sufficient volume to fill

                                   A-210

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100 feet of hole plus 10 percent 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 Ib/gal.

    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 should be set to extend from at
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, with another plug placed 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 that has been
cemented through all usable quality water or productive horizons, -a
cement plug should 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 quality water stratum.  Where such casing has not been cemented
through all strata and horizons, the casing must be perforated at the
required depths to place cement outside the casing by squeeze-cementing.
A plug should also be set above each perforated 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 should 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.
                                   A-211

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    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.
                                  A-212

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                                 References

Interstate Oil  Compact Commission.  1985.  The Oil and Gas Compact
    Bulletin, Vol. XLIV, No. 2, December 1985.

Texas Railroad Commission.  Application information
    casing/annulus disposal of drilling fluid.  Not dated.

	.   Letter communication to EPA, October 1985.
Texas Railroad Commission, Oil and Gas Division.  1985.  Annual
    report - 1985.

	.   1985.  Rules having statewide application to oil, gas, and
    geothermal resource operations within the State of Texas, September
    1985.

   	.  1985.  Water protection manual, April 1985.
Texas surface water quality standards. TDWR Publication LP-71.

USEPA.  1985.  U.S. Environmental Protection Agency.  Proceedings of the
   ^Onshore Oil and Gas State/Federal Western Workshop December 1985.
   "Washington, D.C.:  U.S. Environmental Protection Agency.

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.
                                   A-213

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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.

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);  and
    •  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 cover
drilling and operating practices;  UIC Class  II  injection well
responsibility; and purchasing,  transportation, refining, and
rerefining.  The Division 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  regulation under  one agency by assuming
authority for disposal ponds  in  the  near future.
                                   A-215

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     The U.S.  Department of me 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  hard  pan 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 mountainsides), the Division may allow
the reserve pit supernatant to be disposed  of 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.
                                   A-216

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Production

     Most produced water  is  injected for water  flooding or for  disposal.
Utah has approximately 650 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 the 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, must be
constructed of impervious materials, and must be located at least  5 feet
above ground water.  Pits must be properly located above ordinary
high-water  marks for surface wastes.  Pits may  not be 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/L 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
  'Onslte 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.
                                     A-217

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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 1-square-mile radius of the proposed site.

     For disposal  ponds without artificial liners that 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, which
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 300 psi or the maximum
authorized pressure (for a new well), whichever is greater, with a
ceiling of 1,000 psi (for a converted well).  Subsequent pressure tests
must be administered every 5 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
freshwater 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 should 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.
                                   A-219

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                                References
Hunt, Gil.   Letter to Ms.  Susan de Nagy with attachments dated
     September 20, 1985.

Interstate  Oil Compact Commission. The Oil  and Gas Compact Bulletin,
     Vol. XLIV. No.  2, December 1985.

Swindel. D.B.   Letter to  Kerri  Kennedy with attachments dated
     June 6, 1986.

USEPA.  1985.   U.S.  Environmental  Protection Agency.   Proceedings of the
     Onshore Oil  and Gas  State/Federal Western Workshop December 1985.
     Washington,  D.C.:  U.S.  Environmental  Protection Agency.

Utah Department of Natural  Resources,  Division of Oil, Gas, and Mining.
     1985.   Oil and  Gas Conservation General Rules,  effective December 2,
     1985.

Utah Water  Pollution Control  Committee.   1982.  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.
                                   A-220

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                              VIRGINIA

INTRODUCTION

     Virginia produced  26,654  barrels  of oil from 41 producing oil  wells
and 15,041,438 MCF of gas  from 495  gas wells in 1985.

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 were issued by the  Virginia Department of Labor and Industry in
1983.  In 1985, a reorganization  of the State government created the
Department of Mi.nes, Minerals, and  Energy (DMME). sThis 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 no
underground injection of fluids is  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
its 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 coula 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 onsite and the pit area  is
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  amounts 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 Disposal

     No use is made of offsite and commercial pits in Virginia.

PIuggi 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, whether 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 used to fill all spaces in  the well not filled by plugs.
Additional requirements are made for perforations that cannot be readily
filled by the above methods and for the protection of coal seams.
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                                References

Interstate Oil  and Gas Commission.   1986.   Summary of State statutes and
     regulations for oil  and gas production,  June 1986.

Interstate Oil  Compact Commission.   1985.   The Oil and Gas Compact
     Bulletin.  June 1985.

Personal  Communications:

     William Edwards,  Department of Mines,  Minerals  and Energy
     (804) 257-0330.

     James Henderson,  State Oil  and Gas  Inspector (703) 628-8115.
                                  A-224

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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; and
    •  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 that are to be transferred, after
approval by EPA, are those aspects of the delegated NPDES, underground
injection, and hazardous waste  programs that 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  that  have been  approved by the State
legislature.  The regulations were scheduleed  to  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,  Volume 1,  Chapter
VII.  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, an additional  pit must be  built.   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."
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Unlined dikes must be free of large rocks, trees, or other growth that
could damage the pit's integrity.

     During operation of the pit, it is prohibited to dump into the pit
production brine, unused fracturing 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 6 months after the cessation of
drilling.  The drill cuttings may be buried onsite, after disposal of
liquids.

Disposal

     Treated wastewaters generated during drilling, reworking, and
treatment of wells may be discharged for  land application'onsite, subject
to the following limitations:

          pH                                 6.0 - 10.0
          Total  iron                         6 mg/L
          Chloride                           25,000 mg/L
          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 should be skimmed
off and removed  from the pit before treatment and, if observed, before
                                   A-227

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discharge.   Land application should 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  the 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.

Produced Waters

     The Department of Energy  regulations, beyond prohibiting the
placement of produced salt water in 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 salt water,  and discharge into waters of the State is
prohibited.  Salt water may be injected into Class II wells.   (For
figures on actual disposal patterns, see the section on current
management practices, Volume 1,  Chapter III.)  There is no prohibition
against use of brines on roads,  although research is currently underway
on this possibility.

In.lection

     Class II injection wells  are permitted for both enhanced recovery
(529 wells) and disposal  (53 wells).

     Injection should be through a tubing  and packer arrangement, with
the packer set immediately above the injection zone.  The annulus must be
monitored by a 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."
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     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 percent allowable variance.

Offsite Disposal

     Wastes may  be transported offsite to appropriate disposal
facilities.  If these facilities discharge wastes after treatment, they
must be separately permitted.

PIugging/Abandonment

     Wells completed as dry holes, or wells not in use for a .period of
12 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 10 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 perforated should
be isolated by plugs placed 20 feet above and below the stratum, or a
liner should 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 than
hydraulic cement,  and more cement plugs) are imposed to protect workable
coal beds.
                                   A-229

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                                 References
Interstate Oil  and Gas Compact Commission.  History of production
    statistics, production and reserves 1965   1935.

Streit, T. M.  Letter submitted to William A. Tel Hard, U. S. EPA,
    May 28, 1935.

USEPA.  1985.   U.S.  Environmental Protection Agency.  West Virginia
    Meeting Report.   Proceedings of the Onshore Oil and Gas Workshop
    March 26-27 in Atlanta,  Ga.   Washington, D.C.:  U.S. Environmental
    Protection  Agency.

West Virginia  Department of Energy.  Notice of public hearing and comment
    period on  proposed rules.   Not dated.   Received October 1986.

West Virginia  Legislative Rule,  Department of Energy   Division of Oil
    and Gas,  Chapters 22-1 and 22B-1,  Series 2.

Personal Communications:

    John Johnston, Oi.l and Gas Divisi-on,  West Virginia Department of
    Energy (304)  348-3741.

    Ron Shipley,  West Virginia Department  of Natural Resources
    (304) 348-2754.

    Ted Streit, former head  of Office  of  Oil and Gas,  September 25,  1986.
                                   A-230

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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;  and
    •  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
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.
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    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.  In addition,  DEQ has  authority for the
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"  (MOA) 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 f30-5-104(d)(VI)(A) and (B).

    The Bureau of Land Management (BLM) 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, BLM 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, Volume 1, Chapter VII.
                                   A-232

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STATE RULES AND REGULATIONS

Drill ing

Pit Construction/Management

    Earthen pits are required to be constructed to prevent pollution of
streams or underground water,"or unreasonable damage to 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 is 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, especially the TDS level,
is also'an important consideration.  The State Supervisor makes this
determination based on, the information presented in the perjnit
application form.  Use of chemicals that 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 tend to vary
significantly with the operator.

Pit Closure

    Reserve pits must be reclaimed withjn a year of last use, unless the
Supervisor grants a variance.  After evaporation, discharge, or hauling

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of the liquid material  in the pit.  the drill  cuttings are buried onsite
and the land is rehabilitated in accordance with the landowner's wishes.
Bonds guaranteeing plugging of the  well  and pit reclamation are not
release:! until the Conriission 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 ll(a) of Chapter VII of the regulations of the Department of.
Environmental Quality (UEQ) establishes a no-discharge rule for "drilling
muds and other liquids associated with the drilling of oil and/or gas
wells."  Section  ll(b), however, 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 currently lacks
specific road permit standards or numeric criteria.  Information is
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
10.900 Tig L.  A DEQ memorandum notes several criteria established in such
                                   A-234

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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 percent,  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 to 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
 2,100 mg/L
 1,500 mg/L
20,000 Ib/acre,  when soil  incorporated
(surface 6 inches);  2,000  Ib/acre  when
 surface applied
   960 mg/L
     2 mg/L
   0.1 mg/L
     1 mg/L
   0.2 mg/L
   0.2 mg/L
     2 mg/L
     1 mg/L
 <50% of total  anion
 concentration  mq/L
 4.5 - 9.0.
                                   A-235

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Produced Waters

    Produced waters are disposed of through injection for enhanced
recovery (approximately 63 percent),  surface water discharge
(approximately 30 percent),  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.  However, 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 eannen retaining
pit construction and operation.

    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 must  be 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 that 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:
                                   A-236

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    Chlorides                          2,000 mg/L
    Sulfates                           3,000 mg/L
    Total  dissolved solids            .5,000' mg/L
    pH                                 6..5   8.5
    Oil  and grease                     10 mg/L.

    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 6f Wyoming's water quality standards.

    During 1983 to 1985, five permits were issued by DEQ for road
application of produced waters.  In addition to the road application
restrictions that apply to drilling fluids, produced water must have  a
TDS concentration of greater than 5,000 mg/L and less than 50,000 mg/L.

Injection

    The Wyoming Oil and Gas Conservation Commission has delegated
responsibility for the UTC Class II program and issues permits for both
enhanced recovery (4,548 wells) and noncommercial disposal (196 wells).
Disposal wells permitted by the Commission meet the permitting
requirements of Chapter IX, Wyoming Water Quality Rules and Regulations.
For both types of well, the applicant has the burden of demonstrating at
                                   A-237

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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
fresh and potable water.   The applicant must also supply an application
for approval  of use of ihe well  for injection,  which includes the
following points:

    1. Proof that the well is cased and cemented in such a way that
       fluids are prevented from entering any zone but that exempt;
    2. 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;
    3. A statement detailing procedures for pressure testing the casing
       in the well prior  to any  use;
    4. A plat showing the location of all wells  within a one-quarter mile
       radius of the proposed injection or disposal  well and a statement
       relative to the mechanical condition or  abandonment of each;
    5. An 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; and
    6. A geologic description of the  reservoir  that will receive the
       fluids, which includes its areal extent.

    The surface casing must be run to reach a depth below all known or
reasonably estimated utilizable  domestic freshwater levels.  The surface
casing should be cemented with sufficient cement to fill the annulus to
the top of the hole.

    Before beginning injection,  and at least once every subsequent 5-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
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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 that the facility will not allow a discharge to
ground water by direct or indirect discharge, percolation, or filtration;
that the quality of the wastewater will, not cause a violation of
ground-water standards; or that existing soils or geology will not allow
a discharge to ground water.  If the applicant cannot demonstrate any of
these alternatives, the operator may conduct a subsurface investigation
and develop a design to prevent violation of ground-water standards.
These designs may consist of leachate collection systems, barriers with a
pumpback system, attenuation, or aquifer cleanup after completion of the
operation.  DEQ may require a monitoring program for such facilities.

    At the present time, 11 facilities are authorized to receive drilling
fluids and produced water, and an additional 11 are authorized to receive
produced water only.

PIuggi ng/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
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status: however,  specific approval  must be obtained from the Wyoming Oil
and Gas Conservation Commission if a well  is temporarily abandoned for
more than 1  year    Temporarily abandoned injection wells must meet the
5-/ear testing requirements of the UIC program.

    When wells are plugged, cement plugs of at least 100 feet must be
placed over  open  hole porous and permeable formations (or every
2,500 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.
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                                 References
Wyoming Department of Environmental Quality.  Water Quality Rules and
    Regulations, Chapters III, VII, IX, XI.

Rules and regulations of Wyoming Oil and 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 12, 1983.

Personal Communications:

    E. J. Fanning, Department of Environmental Quality, Water Quality
    Division, August 11 and August  14, 1986, and March 6, 1987.  (307)
    777-7781.

    Janie Nelson, Wyoming Oil and Gas  Conservation Commission, August 14,
    1986.   (307) 234-7147.
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  APPENDIX B

GLOSSARY OF TERMS
  FOR VOLUME 1

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Abandon:  To cease producing oil or gas from a well when it becomes
unprofitable.  A wildcat may be abandoned after it has been proven
nonproductive.  Usually, before a well is abandoned, some of the casing
is removed and salvaged and one or more cement plugs are placed in the
borehole to prevent migration of fluids between the various formations.
In many States, abandonment must be approved by an official regulatory
agency before being undertaken.

Acid:  Any chemical compound, one element of which is hydrogen, that
dissociates in solution to produce free-hydrogen ions.  For example,
hydrochloric acid, HC1, dissociates in water to produce hydrogen ions,
H+, and chloride ions, Cl".

Acidize:  To treat oil-bearing  limestone or other  formations, using a
chemical reaction with acid, to increase production.  Hydrochloric or
other acid is injected into the formation under pressure.  The acid
etches the rock, enlarging the  pore spaces and passages through which the
reservoir fluids flow.  The-acid is then pumped out and the well is
swabbed and put back  into production.  Chemical inhibitors combined with
the acid prevent corrosion of the pipe.

Additive:  A substance or compound added in small  amounts to a larger
volume of another substance to  change some characteristic of the latter
In the oil industry,  additives  are used in lubricating oil, fuel,
drilling mud, and cement for cementing casing.

Adsorption:  The adhesion of a  thin film of a gas  or liquid to the
surface of a solid.   Liquid hydrocarbons are recovered from natural gas
by passing the gas through activated charcoal, which extracts the heavier
hydrocarbons.  Steam  treatment  of the charcoal removes the adsorbed
hydrocarbons, which are then collected and recondensed.

Aeration:  The technique of injecting air or other gas into a fluid.
For example, air is injected into drilling fluid to reduce the density of
the fluid.

Air Drilling:  A method of rotary drilling that uses compressed air
as its circulation medium.  This method of removing cuttings from the
wellbore is as efficient or more efficient than the traditional methods
using water or drilling mud; in addition, the rate of penetration is
increased considerably when air drilling is used.  However, a principal
problem in air drilling is the  penetration, of formations containing
water, since the entry of water into the system reduces its efficiency.
                                    B-l

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Alkalinity:  The combining power of a base, or alkali, as measured by
the number of equivalents of an acid with which it reacts to form a salt.

Annular Injection:  Long-tern disposal  of wastes between the outer
wall of the drill  stem or tubing and the inner wall of the casing or open
hole.

Annulus or Annular Space:  the space around a pipe in a wellbore, the
outer wall of which may be the wall of either the borehole or the casing.

API:  The American Petroleum Institute.   Founded in 1920, this
national oil trade organization is the leading standardizing organization
on oil-field drilling and producing equipment.  It maintains departments
of transportation, refining, and marketing in Washington, D.C., and a
department of production in Dallas.

Artificial Lift:  Any method used to raise oil to the surface through
a well after reservoir pressure has declined to the point at which the
well no longer produces by means of natural energy.  Artificial lift may
also be used during primary recovery if the initial reservoir pressure is
inadequate to bring the hydrocarbons to the surface.   Sucker-rod pumps,
hydraulic pumps, submersible pumps, and gas lift are  the most common
methods of artificial lift.

Attapulgite:  A fibrous clay mineral that is a viscosity-building
substance, used principally in saltwater-based drilling muds.

Bactericide:  Anything that destroys bacteria.

Barite:  Barium sulfate, BaSC^; a mineral used to increase the
weight of drilling mud.  Its specific gravity is 4.2.

Barrel (bbl):  A measure of volume for petroleum products.  One
barrel (1 bbl) is equivalent to 42 U.S.  gallons or 158.97 liters.  One
cubic meter (1 m3) equals 6.2897 bbl.

Basin:  A synclinal structure in the subsurface, formerly the bed of
an ancient sea.  Because it is composed of sedimentary rock and its
contours provide traps for petroleum, a basin is a good prospect for
exploration.  For example, the Permian Basin in West  Texas is a major oil
producer.

Basic Sediment and Water (BS&W):  The water and other extraneous
material present in crude oil.  Usually, the BS&W content must be quite
low before a pipeline will accept the oil for delivery to a refinery.
The amount acceptable depends on a number of factors  but usually runs
from less than 5 percent to a small fraction of 1 percent.

Bentonite:  A colloidal clay, composed of montmorillonite, which
swells when wet.  Because of its gel-forming properties, bentonite is a
major component of drilling muds.

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Bit:  The cutting or boring element used in drilling oil and gas
wells.  Most b-its used in rotary drilling are roller-cone bits.  The bit
consists of the cutting element and the circulating element.  The
circulating element permits the passage of drilling fluid and utilizes
the hydraulic force of the fluid stream to improve drilling rates.  In
rotary drilling, several drill collars are joined to the bottom end of
the drill-pipe column.  The bit is attached to the end of the drill
collar.

Slowdown:  The emptying or depressurizing of a material from a
vessel.  The material thus discarded.

Blowout Preventer (BOP):  Equipment installed at the wellhead at
surface level on land rigs and on the seafloor of floating offshore rigs
to prevent the escape of pressure either in the annular space between the
casing and drill pipe or in- an open hole during drilling and completion
operations.

Blow Out:  To suddenly expel oil-well fluids from the borehole with
great velocity.  To expel a portion of water and steam from a boiler to
limit its concentration of minerals.

Borehole:  The well bore; the hole made by drilling or boring.

Brackish Water:  Water that contains relatively low concentrations of
any soluble salts.  Brackish water is saltier than fresh water but not as
salty as salt water.
                                                         •J P
Brine:  Water that has a large quantity of salt, especially*sodium
chloride, dissolved in it; salt water.

Burn Pit:  An earthen pit in which waste oil and other materials are
burned.

Cable Tool Drilling:  A drilling method in which the hole is drilled
by dropping a sharply pointed bit on the bottom of the hole.  The bit is
attached to a cable and the cable is picked up and dropped, picked up and
dropped, over and over, as the hole is drilled.

Casing:  Steel pipe placed in an oil or gas well as drilling
progresses to prevent the wall of the well from caving in during drilling
and to provide a means of extracting petroleum if the well is productive.

Casinghead Gas:  Gas produced with oil.

Casing String:  Casing is manufactured in lengths of about 30 ft,
each length or joint being joined to another asicasing is run in a well.
The entire length of all the joints of casing is called the casing string,
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Cement:  A powder consisting of alumina, silica, lime, and other
substances which hardens when mixed with water.  Extensively used  in the
oil industry to bond casing to the walls of the wellbore.

Cement Additive:  A material added to cement during cementing of a
well to change its properties.  Chemical accelerators, chemical
retarders, and weight-reduction materials are common additives.

Cement Bond:  The adherence of casing to cement and cement to
formation.  When casing is run in a well, it is set, or bonded, to the
formation by means of cement.

Cement Plug:  A portion of cement placed at some point in the
wellbore to seal it.

Centralized Brine Disposal Pit:  An excavated or above-grade earthen
impoundment located away from the oil or gas operations from which it
receives produced fluids (brine).  Centralized pits usually receive
fluids from many wells, leases, or fields.

Centralized Combined Mud/Brine Disposal Pit:  An -excavated or
above-grade earthen impoundment located away from the oil or gas
operations from which it receives produced fluids (brine) and drilling
fluids.  Centralized pits usually receive fluids from many wells, leases,
or fields.

Centralized Mud Disposal Pit:  An excavated or above-grajde earthen
impoundment located away from the drilling operations from which it
receives drilling muds.  Centralized pits usually receive fluids from
many drill ing sites.

Centralized Treatment Facility (Mud or Brine):  Any facility
accepting drilling fluids or produced fluids for processing.  This
definition encompasses municipal  treatment plants, private treatment
facilities, or publicly owned treatment works for treatment of drilling
fluids or produced fluids.  These facilities usually accept a spectrum of
wastes from a number of oil, gas, or geothermal sites, or in combination
with wastes from other sources.

Centrifuge:  A device for the mechanical separation of solids from a
liquid.  Usually used on weighted muds to recover the mud and discard
solids.  The centrifuge uses high-speed mechanical rotation to achieve
this separation as distinguished from the cyclone-type separator in which
the fluid energy alone provides the separating force.

Christmas Tree:  Assembly of fittings and valves at the tip of the
casing of an oil well that controls the flow of oil from the well.
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Circulate:  To pass from one point throughout a system and back to
the starting point.  Drilling fluid circulates from the suction pit
through the drill pipe to the bottom of the well and returns through the
annul us.

Clean Water Act:  The Federal Water Pollution Control Act Amendments
of 1972 (33 U.S.C. 1251 et seq.), as amended by the Clean Water Act of
1977 (P. L. 95-217).

Close-in:  A well capable of producing oil or gas, but temporarily
not producing.

Collar:  A coupling device used to join two lengths of pipe.  A
combination collar has left-hand threads  in one end and right-hand
threads in the other.  A drill collar.

Commercial Production: .Oil and gas output of sufficient quantity to
justify keeping a well in production.

Completion Fluid:  A special drilling mud used when a well is being
completed.  It is selected not only for its ability to control formation
pressure, but also for its properties that minimize formation damage.

Completion Operations:  Work performed in an oil or gas well after
the well has been drilled to the point at which the production string of
casing  is to be set.  This work includes  setting the casing, perforating,
artificial stimulation, production testing, and equipping the well for
production, all prior to the commencement of the actual production of oil
or gas  in paying quantities, or in the case of an injection or service
well, prior to when the well is plugged and abandoned.

Condensate:  A light hydrocarbon liquid obtained by condensation of
hydrocarbon vapors.  It consists of varying proportions of butane,
propane, pentane, and heavier fractions, with little or no ethane or
methane.

Conductor Pipe:  A short string of large-diameter casing used
offshore and in marshy locations to keep the top of the wellbore open and
to provide a means of conveying the upflowing drilling fluid from the
wellbore to the mud pit.

Coning:  The encroachment of reservoir water into the oil column and
well because of uncontrolled production.

Conductivity:  The ability to transmit or convey (as heat or
electricity),

Connate Water:  The original water retained in the pore spaces, or
interstices, of a formation from the time the formation was created.
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Cooling Tower:  A structure in which air contact is used to cool a
stream of water that has been heated by circulating through a system.
The air flows counter- or cross-currently to the water.

Corrosion:  A complex chemical or electrochemical process by which
~,e:al  is destroyed through reaction with its environment.  For example,
rust is corrosion.

Crude Oil:  Unrefined liquid petroleum.  It ranges in gravity from
9° to 55° API and in color from yellow to black, and it may have a
paraffin, asphalt, or mixed base.  If a crude oil, or crude, contains a
sizable amount of sulfur or sulfur compounds, it is called a sour crude;
if it has little or no sulfur, it is called a sweet crude.  In addition,
crude oils may be referred to as heavy or light according to API gravity,
the lighter oils having the higher gravities.

Cuttings:  The fragments of rock dislodged by the bit and brought to
the surface in the drilling mud.  Washed and dried samples of the
cuttings are analyzed by geologists to obtain information about the
formations drilled.

Oeflocculation:  The dispersion of solids that have stuck together in
drilling fluid, usually by means of chemical thinners.

Defoamer:  Any chemical that prevents or lessens frothing or foaming
in another agent.

Dehydrate:  To remove water from a substance.  Dehydration of crude
oil is normally accomplished by emulsion treating with  emulsion
breakers.  The water vapor in natural gas must be removed to meet
pipeline requirements; a typical maximum allowable water vapor content is
7 Ib per MMcf.

Demulsify:  To resolve an emulsion, especially of water and oil, into
its components.

Desander:  A centrifugal device used to remove fine particles of sand
from drilling fluid to prevent abrasion of the pumps.  A desander usually
operates on the principle of a fast-moving stream of fluid being put into
a whirling motion inside a cone-shaped vessel.

Desiccant:  A substance able to remove water from another substance
with which it is in contact.  It may be liquid (as triethylene glycol) or
sol id (as silica gel).

Desilter:  A centrifugal device, similar to a desander, used to
remove very fine particles, or silt, from drilling fluid to keep the
amount of solids in the fluid to the lowest possible level.  The lower
the solids content of the mud is, the faster the rate of penetration.
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Development Well:  A well drilled in proven territory in a field to
complete a pattern of production.

Discovery Well:  The first oil or gas well drilled in a new field;
the well that reveals the presence of a petroleum-bearing reservoir.
Subsequent wells are development wells.

Disposal Well:  A well into which salt water is pumped; usually part
of a saltwater-disposal system.

Dope:  A lubricant for the threads of oil field tubular goods.

Drill:  To bore a hole in the earth, usually to find and remove
subsurface formation fluids such as oil and gas.

Drill Collar:  A heavy, thick-walled tube, usually steel, used
between the drill pipe and the bit in the drill stem to weight the bit in
order to improve its performance.

Drilling Fluid:  The circulating fluid (mud) used in the rotary
drilling of wells to clean and condition the hole and to counterbalance
formation pressure.  A water-based drilling fluid is the conventional
drilling mud  in which water is the continuous phase and the suspended
medium for solids, whether or not oil is present.  An oil-based drilling
fluid has diesel, crude, or some other oil as its continuous phase with
water as the  dispersed phase.  Drilling fluids are circulated down the
drill pipe and back up the~*hole between the drill pipe and the walls of
the hole, usually to a surface pit.  Drilling fluids are used to
lubricate the drill bit, to lift cuttings, to seal off porous zones, and
to prevent blowouts.  There are two basic drilling media:  muds (liquid)
and gases.  Each medium comprises a number of general types.  The type of
drilling fluid may be further broken down into numerous specific
formulations.

Drill Pipe:   The heavy seamless tubing used to rotate the bit and
circulate the drilling fluid.  Joints of pipe 30 ft long are coupled
together by means of tool joints.

Drill Site:   The location of a drilling rig.

Drill Stem:   The entire length of tubular pipes, composed of the
kelly, the drill pipe, and drill collars, that make up the drilling
assembly from the surface to the bottom of the hole.

Drill String:  The column, or string, of drill pipe, not including
the drill collars or kelly.  Often, however, the term is loosely applied
to include both the drill pipe and drill collars.
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Drum:  A cylindrical steel container with a capacity of 50 to  55  U.S.
gal (200 liters) used to ship refined products.

Dry Hole:  Any well that does not produce oil or gas in commercial
quantities.  A dry hole may flow water, gas, or even oil, but  not enough
to justify production.

Emulsion:  A mixture in which one liquid, termed the dispersed phase,
is uniformly distributed (usually as minute globules) in another  liquid,
called the continuous phase or dispersion medium.  In an oil-water
emulsion, the oil is the dispersed phase and the water the dispersion
medium; in a water-oil  emulsion the reverse holds.  A typical  product of
oil wells, water-oil emulsion also is used as a drilling fluid.

Emulsion Breaker:  A system,  device, or process used for breaking
down an emulsion and rendering it into two or more easily separated
compounds (as water and oil).  Emulsion breakers may be (1) devices to
heat the emulsion, thus achieving separation by lowering the viscosity of
the emulsion and allowing the water to settle out; (2) chemical
compounds, which destroy or weaken the film around each globule of water,
thus uni'ting all the drops; (3) mechanical devices such as settling tanks
and wash tanks; or (4)  electrostatic treaters, which use an electric
field to cause coalescence of the water globules.  This is also called
electric dehydration.

Enhanced Oil Recovery (EOR):   A method or methods applied to depleted
rese.voirs to nrake them productive once again.  After an oil well has
reached depletion, a certain amount of oil remains in the reservoir,
which enhanced recovery is targeted to produce.  EOR can encompass
secondary and tertiary production.

EPA:  United States Environmental Protection Agency.

Exploration:  The search for reservoirs of oil and gas, including
aerial and geophysical  surveys, geological studies, core testing, and the
drilling of wildcats.

Field:  A geographical  area in which a number of oil or gas wells
produce from a continuous reservoir.  A field may refer to surface area
only or to underground productive formations as well.  In a single field,
there may be several separate reservoirs at varying depths.

Flocculation:  A property of contaminants or special additives to a
drilling fluid that causes the solids to coagulate.

Flowing Well:  A well that produces oil or gas without any means  of
artificial lift.
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Foaming Agent:  A chemical used to lighten the water column in gas
wells, in oil wells producing gas, and in drilling wells in which air or
ga's is used as the drilling fluid so that the water can be forced out
with the air or gas to prevent its impeding the production or drilling
rate.

Formation:  A bed or deposit composed throughout of substantially the
same kinds of rock; a lithologic unit.  Each different formation is given
a name, frequently as a result of the study of the formation outcrop at
the surface and sometimes based on fossils found in the formation.

Formation Pressure:  The pressure exerted by fluids in a formation,
recorded in the hole at the level of the formation with the well shut
in.  It is also called reservoir pressure or shut-in bottomhole pressure.

Formation Water:  The water originally in place in a formation.

Fracturing:  A method of stimulating production by increasing the
permeability of the producing formation.  Under extremely high hydraulic
pressure, a fluid is pumped downward through tubing or drill pipe and
forced into the perforations in the casing.  The fluid enters the
formation and parts or fractures it.  Sand grains, aluminum pellets,
glass beads, or similar materials are carried in suspension by the fluid
into the fractures.  These are called propping agents.  When the pressure
is released at the surface, the fracturing fluid returns to the well, and
the fractures partially close on the propping agents, leaving channels
through which oil flows to the well.

Free Water:  The water produced with oil.  It usually settles out
within 5 minutes when the well fluids become stationary in a settling
space within a vessel.

Gas Lift:  The process of raising or lifting fluid from a well by
injecting gas down the well through tubing or through the tubing-casing
annulus.  Injected gas aerates the fluid to make it exert less pressure
than the formation does; consequently, the higher formation pressure
forces the fluid out of the wellbore.  Gas may be injected continuously
or intermittently, depending on the producing characteristics of the well
and the arrangement of the gas-lift equipment.

Gas-Oil Ratio:  Number of cubic feet of gas produced with a barrel of
oil.

Gas Plant:  An installation in which natural gasrt_is processed to
prepare it for sale to consumers.  A gas plant separates desirable
hydrocarbon components from the impurities in natural gas.

Gathering Line:  A pipeline, usually of small diameter, used in
gathering crude oil from the oil field to a point on a main pipeline.
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Gel:  A ss-nisolid.  jelly 1i:
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Joint:  A single length (30 ft) of drill pipe or of drill collar,
casing,  tubing, or rod that has threaded connections at both ends.
Several  joints screwed together constitute a stand of pipe.

Kelly:  The heavy settle member, four- or six-sided, suspended from
the swivel through the rotary table and connected to the topmost joint of
drill  pipe to turn the drill stem as the rotary table turns.  It has a
bored passageway that permits fluid to be circulated .into the drill stem
and up the annulus, or vice versa.

Lease:  A legal document executed between a landower, or a lessor,
and a company or individual, as lessee, that grants the right to exploit
the premises for minerals or other products.  The area where production
wells, stock tanks, separators, and production equipment are located.

Location  (Drill Site):  Place at which a well is to be or has been
drilled.

Log:  A systematic recording of data, as from the driller's log, mud
log, electrical well log, or radioactivity log,  Many different logs are
run in wells being produced or drilled to obtain information about
various characteristics of downhole formations.

Log.a well:  To run any of the various logs used to ascertain
downhole  information about a well.

Manifold:  An accessory system of piping to a main piping system (or
another conductor) that serves to divide a flow into several parts, to
combine several flows into one, or to reroute a flow to any one of
several possible destinations.

Marginal Well:  An oil or gas well that produces such a small volume
of hydrocarbons that the gross income therefrom provides only a small
margin of profit or, in many cases, does not even cover the cost of
production.

Mud:  The liquid circulated through the wellbore during rotary
drilling  and workover operations.  In addition to its function of
bringing cuttings to the surface, drilling mud cools and lubricates the
bit and drill stem, protects against blowouts by holding back subsurface
pressures, and deposits a mud cake on the wall of the borehole to prevent
loss of fluids to the formation.  Although it originally was a suspension
of earth  solids (especially clays) in water, the mud used in modern
drilling operations is a more complex, three-phase mixture of liquids,
reactive  solids, and inert solids.  The liquid phase may be fresh water,
diesel oil, or crude oil and may contain one or more conditioners.
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Mud Pit:  A reservoir or tank,  usually made of steel plates, through
which the drilling mud is cycled to allow sand and fine sediments to
settle out.  Additives are mixed with mud in the pit, and the fluid is
temporarily stored there before being pumped back into the well.  Mud
pits are also called shaker pits, settling pits, and suction pits,
depending on their main purpose.

NPDES Permit:  A National Pollutant Discharge Elimination System
permit issued under Section 402 of the Clean Water Act.

96-hr LC-50:  The concentration of a test material that is lethal to
50 percent of the test organisms in a bioassay after 96 hours of constant
exposure.

Oil and Gas Separator:  An item of production equipment used to
separate the liquid components  of the well stream from the gaseous
elements.  Separators are vertical or horizontal and are cylindrical or
spherical in shape.  Separation is accomplished principally by gravity,
the heavier liquids falling to  the bottom and the gas rising to the top.
A float valve or other liquid-level control  regulates the level  of oil in
the bottom of the separator.

Oil-based Mud:  An oil mud that contains from less than 2 percent up
to 5 percent water.  The water  is spread out, or dispersed, in the oil as
small droplets.

Oil Field:  The surface area overlying an oil reservoir or
reservoirs.  Commonly, the term includes not only the surface area but
also the reservoir, wells, and  production equipment.

Operator:  The person or company, either proprietor or lessee,
actually operating an oil well  or lease.

Packer:  A piece of downhole equipment, consisting of a sealing
device, a holding or setting device, and an inside passage for fluids,
used to block the flow of fluids through the annular space between the
tubing and the wall of the wellbore by sealing off the space.  It is
usually made up in the tubing string some distance above the producing
zone.  A sealing element expands to prevent fluid flow except through the
inside bore of the packer and into the tubing.  Packers are classified
according to configuration, use, and method of setting and whether or not
they are retrievable (i.e., whether they can be removed when necessary,
or whether they must be milled  or drilled out and thus destroyed).

Packer Fluid:  A liquid, usually mud but sometimes salt water or oil,
used in a well when a packer is between the tubing and casing.  Packer
fluid must be heavy enough to shut off the pressure of the formation
being produced, must not stiffen or settle out of suspension over long
periods of time, and must be noncorrosive.
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Perforate:  To pierce the casing wall and cement to provide holes
through which formation fluids may enter or to provide holes in the
casing so that materials may be introduced into the annulus between the
casing and the wall of the borehole.  Perforating is accomplished by
lowering into the well a perforating gun, or perforator, that fires1
electrically detonated bullets or shaped charges from the surface.

Permeability:  A measure of the ease with which fluids can flow
through a porous rock.

Pig:  A scraping tool that is forced through a pipeline or flow line
to clean out accumulations of wax, scale, and so forth, from the inside
walls of a pipe.  A cleaning pig. travels with the flow of product in the
line, cleaning the walls of the pipe with blades or brushes.  A, batching
pig is a cylinder with neoprene or plastic cups on either end used to
separate different products traveling in the same pipeline.

Plug and Abandon (P&A):  To place a cement plug into a dry hole and
abandon it.

Porosity:  The quality or state of possessing pores (as a rock
formation).  The ratio of the volume of  interstices of a substance to the
volume of its mass.

Primary Recovery:  Oil production in which only existing natural
energy sources in the reservoir provide  for movement of the well fluids
to the well bore.

Produced Water:  The water (brine) brought up from the hydrocarbon-
bearing strata during the extraction of  oil and gas.  It can include
formation water, injection water, and any chemicals added downhole or
during the oil/water separation process.
               1 "-' j' ".
Producing Zone:  The zone or formation from which oil or gas is
produced.

Production:  The phase of the petroleum  industry that deals with
bringing the well fluids to the surface  and separating them and with
storing, gauging, and otherwise preparing the product for the pipeline..

Production Casing:  The last string of casing or liner that is set in
a well, inside of which is usually suspended the tubing string.

Propping Agent:  A granular substance (as sand grains, walnut shells,
or other material) carried in suspension by the fracturing fluid that
serves to keep the cracks open when the  fracturing fluid is withdrawn
after a fracture treatment.
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Radioactive Tracer:  A radioactive material (often carnotite) put
into a well to allow observation of fluid or gas movements by means of a
tracer survey.

RCRA:  The Resource Conservation and Recovery Act of 1976, as amended.

Reservoir:  A subsurface,  porous,  permeable rock body in which oil or
gas or both are stored.   Most reservoir rocks are limestones, dolomites.
sandstones, or a combination of these.   The three basic types of
hydrocarbon reservoirs are oil, gas, and condensate.  An oil  reservoir
generally contains three fluids--gas,  oil,  and water—with oil the
dominant product.  In the typical  oil  reservoir, these fluids occur in
different phases because of the variance in their gravities.   Gas, the
lightest, occupies the upper part  of the reservoir rocks; water, the
lower part; and oil, the intermediate  section.  In addition to occurring,
as a cap or in solution, gas may accumulate independently of the oil; if
so, the reservoir is called a gas  reservoir.   Associated with the gas, in
most instances, are salt water and some oil.   In a condensate reservoir,
the hydrocarbons may exist as a gas, but when brought to the surface,
some of the heavier ones condense  to a  liquid or condensate.   At the
surface the hydrocarbons from a condensate  reservoir consist of gas and a
high-gravity crude (i.e.,  the condensate).   Condensate wells are
sometimes called gas-condensate reservoirs.

Resistivity:  The electrical resistance offered to the passage of
current; the opposite of conductivity.

Rig:  The derrick, drawworks, and  attendant surface equipment of a
drilling or workover unit.

Rotary:  The machine used to impart rotational power to the drill
stem while permitting vertical  movement of  the pipe for rotary drilling.
Modern rotary machines have a special  component, the rotary bushing,  to
turn the kelly bushing,  which permits  vertical movement of the kelly
while the stem is turning.

Secondary Recovery:  Any method by which an essentially depleted
reservoir is restored to producing status by  the injection of liquids or
gases (from extraneous sources) into the wellbore.  This injection
effects a restoration of reservoir energy,  which moves the formerly
unrecoverable secondary reserves through the  reservoir to the wellbore.

Sediment:  The matter that settles to  the bottom of a liquid; also
called tank bottoms, basic sediment, and so forth.

Separator:  A cylindrical  or spherical  vessel  used to isolate the
components in mixed streams of fluids.
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Shale Shaker:  A series of trays with sieves that vibrate to remove
cuttings from the circulating fluid in rotary drilling operations.  The
size of the openings in the sieve is carefully selected to match the size
of the solids in the drilling fluid and the anticipated size of
cuttings.  It is also called a shaker.

Sour:  Containing hydrogen 'sulfide or caused by hydrogen sulfide or
another sulfur compound.

Specific Gravity:  The ratio of the weight of a substance at a given
temperature to the weight of an equal volume of a standard substance at
the same temperature.  For example, if 1 in.-* of water at 39°F
weighs 1 unit and 1  in.  of another solid or liquid at 39°F
weighs 0.95 unit, then the specific gravity of the substance is 0.95.  In
determining the specific gravity of gases, the comparison is made with
the standard of air  or hydrogen.

Spud:  To move the drill stem up and down in the hole over a short
distance without rotation.  Careless execution of this operation creates
pressure surges that can cause a formation to break down, which results
in lost circulation.

Spud In:  To begin drilling; to start the hole.

Stock Tank:  A crude oil storage tank.

Stripper:  A well nearing depletion that produces a very small amount
of oil or gas.

Sump:  A low place in a vessel or tank used to accumulate settlings
that are later, removed through an opening in the bottom of the vessel.

Supernatant:  A liquid or fluid forming a layer above settled solids.

Surface Pipe:  The first string of casing set in a well after the
conductor pipe, varying in length from a few hundred feet to several
thousand.

Surfactant:  A substance that affects the properties of the surface
of a liquid or solid by concentrating on the surface layer.   The use of
surfactants can ensure that the surface of one substance or object is in
thorough contact with the surface of another substance.

Tank Battery:  A group of production tanks located in the field that
store crude oil.
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Tertiary Recovery:   A recovery method used to remove additional
hydrocarbons after secondary recovery methods have been applied to a
reservoir.  Sometimes more hydrocarbons can be removed by injecting
liquids or gases (usually different from those used in secondary recovery
and applied with different techniques) into the reservoir.

Tubing:  Small-diameter pipe that is run into a well to serve as a
conduit for the passage of oil and gas to the surface.

Viscosity:  A measure of the resistance of a liquid to flow.
Resistance is brought about by the internal friction resulting from the
combined effects of cohesion and adhesion.  The viscosity of petroleum
products is commonly expressed in terms of the time required for a
specific volume of the liquid to flow through an orifice of a specific
size.

Volatile:  Readily vaporized.

Waterflood:  A method of secondary recovery in which water is
injected into a reservoir to remove additional quantities of oil that
have been left behind after primary recovery.  Usually, a waterflood
involves the injection of water through wells specially set up for water
injection and the removal of the water and oil from the wells drilled
adjacent to the injection wells.

Weighting Material:  A material with a specific gravity greater than
that of cement; used to increase the density of drilling fluids or cement
slurries.

Well bore:  A borehole; the hole drilled by the bit.  A well bore may
have casing in it or may be open (i.e., uncased); or a portion of it may
be cased and a portion of it may be open.

Well Completion:  The activities and methods necessary to prepare a
well for the production of oil and gas; the method by which a flow line
for hydrocarbons is established between the reservoir and the surface.
The method of well  completion used by the operator depends on the
individual characteristics of the producing formation or formations.
These techniques include open-hole completions, conventional perforated
completions, sand-exclusion completions, tubingless completions, multiple
completions, and miniaturized completions.

Wellhead:  The equipment used to maintain surface control of a well,
including the casinghead, tubing head, and Christmas tree.

Well Spacing:  The regulation of the number and location of wells
over a reservoir as a conservation measure.
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Well  Stimulation: ' Any of several operations used to increase the
production of a well.

Wildcat:  A well drilled in an area where no oil or gas production
exists.  With present-day exploration methods and equipment, about one
wildcat out of every six proves to be productive although not necessarily
profitable.

Workover:  One or more of a variety of remedial operations performed
on a producing oil well to try to increase production.  Examples of
workover operations are deepening, plugging back, pulling and resetting
the liner, squeeze-cementing, and so on.

Workover Fluids:  A special drilling mud used to keep a well under
control when it  is being worked over.  A workover fluid is compounded
carefully so it will not cause formation damage.
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    APPENDIX C
DAMAGE  CASE SUMMARIES

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OH 49

    State:  Ohio

    Region: 2

    County/Parish:  Ashtabula

    City/Town:  Rartsgrove

    Test of Proof:  Administrative and Scientific

Description
In 1982, drilling activities of an unnamed oil and gas company
contaminated the well that served a house and barn owned by a Mr. Bean,
who used the water for his dairy operations. Analysis done on the water
well by the Ohio Department of Agriculture found high levels of barium,
iron, manganese, sodium, and chlorides.  (Barium is a common constituent
of drilling mud.)  Because the barium content of the water well exceeded
State standards, Mr. Bean was forced to shut down his dairy operations.
Milk produced at the Bean farm following contamination of the water well
contained 0.63 mg/L of barium.  Concentrations of chlorides, iron,
sodium, and other residues in the water well were above the U.S. EPA's
Secondary Drinking Water Standards.   Mr. Bean drilled a new well, which
also became contaminated.  As of September 1984, Mr. Bean's water well
was still showing signs of contamination from the drilling-related
wastes.  It is not known whether Mr. Bean was able to recover financially
from the disruption of his dairy business.

Waste Analysis
Water samples from Mr. Bean's well showed concentrations of barium above
the National Primary Drinking Water Standard; concentrations of chloride,
iron, manganese, and residue above EPA's Secondary Drinking Water
Standards; and high levels of sodium.  Milk samples taken from Bean's
                                    C  1

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dairy operation indicated barium contamination at 0.63 mg/L.  A new well
that was drilled also became contaminated.

Comments
API states that "The source of damage to freshwater wells is uncertain."
Dave Planner/, representing independent oil and gas producers in Ohio,
                                                                *
asserts that this discharge violates State regulations and that t'he State
enforcement agency took appropriate action.

Violation of State Regulations:  Yes

Documentation
References for case cited:  Ohio EPA,  Division of of Public Water
Supply, Northeast District Office, interoffice communication from E. Mohr
to M. Hilovsky describing test results on Mr. Bean's water well, 7/21/86.
Letters from E. Mohr, Ohio EPA, to Mr. Bean and Mr. Hart explaining water
sampling results, 10/20/82.  Letter from Miceli Dairy Products Co. to E.
Mohr, Ohio EPA, explaining test results from Mr. Bean's milk and water
well. Letters from E. Mohr, Ohio EPA, to Mr. Bean explaining'water
sampling results from tests completed on 10/7/82, 2/2/83, 10/25/83,
6/15/84, 8/3/84, and 9/17/84.  Generalized stratigraphic sequence of the
rocks in the Upper Portion of the Grand River Basin.

OH 45

    State:  Ohio

    Region:  2

    County/Parish:  Portage

    City/Town:  Windham

    Test of Proof:  Administrative and Scientific
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Description
The Miller Sand and Gravel Co., though an active producer of sand and
gravel, has also served as an  il-legal disposal site for oil field
wastes.  An investigation by the Ohio Department of Natural Resources
found that the sand and gravel pits  and the surrounding swamp were
contaminated with oil and high-chloride produced waters.  Ohio  inspectors
noted a flora kill of unspecified size.  Ohio Department of Health
laboratory analysis of soil and liquid samples from the pits recorded
chloride concentrations of 269,000 mg/L.  The surrounding swamp chloride
concentrations ranged from 303 mg/L  (upstream from the pits) to 60,000
mg/L (area around the pits).   This type of discharge is prohibited by
State regulations.

Waste Analysis
Samples taken from the pits showed conductivities >50,000 u/cm  and
chloride concentrations over 269,000 mg/L.  Chloride concentrations in
the surrounding swamp ranged from 303 mg/L (upstream from the pits) to
'60,600 mg/L (area around  the pits).

Comments
David  Flannery, representing independent oil and gas producers  in Ohio,
notes that this discharge is prohibited by State regulation.

Violation of State Regulations:  Yes

Documentation
References for case cited:  Ohio EPA, Division of Wastewater Pollution
Control, Northeast District Office,  interoffice communication from
E. Mohr to D. Hasbrauck,  District Chief, concerning the results from
sampling at the sand and  gravel site. Ohio Department of Health,
Environmental Sample Submission Reports from samples taken on 6/22/82.
                                     C-3

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OH 07

    State:  Ohio

    Region:  2

    County/Parish:  Knox

    City/Town:  Howard

    Test of Proof:  Administrative and Scientific

Description
Equity Oil & Gas Funds, Inc., operates Well #1 on the the Engle Lease,
Knox County.  An Ohio DNR official inspected the site on April 5, 1985.
There were no saltwater storage tanks on site to collect the
high-chloride produced water that was being discharged from a plastic
hose leading from the tank battery into a culvert that, in turn, emptied
into a creek.  The inspector took photos and samples.  Both produced
water and oil and grease levels were of sufficient magnitude  to cause
damage to flora and fauna, according to the notice of violation filed by
the State.  The inspector noted that a large area of land along the
culvert had been contaminated with oil and produced water.  The
suspension order indicated that the "...violations present an imminent
danger to public health and safety and are likely to result in immediate
and substantial damage to natural resources."  The operator was required
by the State to "...restore the disturbed land surface and remove the oil
from the  stream in accordance with Section 1509.072 of Ohio Revised
Statutes	"

Waste Analysis
Water samples taken from these locations yielded the following results:
Sample -1,  west side of Co. Rd. 35 at the culvert,  indicated chloride,
43.0 mg/L: oil and grease, <1;  Sample = 2, from the east side of Co.  Rd.
                                    C-4

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35 at the culvert, showed chloride, 45.0 mg/L; oil and grease, <1.
Sample #3, from the end of the pipe that runs from the tank to the
culvert, indicated chloride, 168,000 mg/L; oil and grease, present in the
sample. Sample #4, east side of Co. Rd. 35 at the stream, indicated
chloride, 2,:060 mg/L; oil and grease, <1. Sample #5-, from the mouth of
the stream entering the creek, revealed chloride, 470 mg/L; oil and
grease, 4,070 mg/L.

Comments
David Flannery, representing independent oil and gas producers in Ohio,
notes that this discharge violates both State and Federal regulations.

Violation of State Regulations:  Yes

Documentation
References for case cited:  The Columbus Water and Chemical Testing Lab,
lab reports.  Ohio Department of Natural Resources, Division of Oil and
Gas, Notice of Violation, 5/5/85.

OH 12

    State:  Ohio

    Region:  2

    County/Parish:  Muskingum

    City/Town:  Hopewell

    Test of Proof:  Administrative, Legal, and Scientific

Description
Zenith Oil & Gas  Co. operated Well #1 in Hopewell Township.  The Ohio DNR
issued a suspension order to Zenith in March of  1984 after State
    "*.-••
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inspectors discovered produced water discharges onto the surrounding site
from a breach irv a produced water pit. and pipe leading from the pit.  A
Notice of Violation had been issued in Februar.y 1984  but the violations
were still in effect >in March 1.984.  A State inspection of-an adjacent
site,' also operated by Zenith Oil & Gas Co., discovered a plastic hose
extending from one of the tank batteries discharging high-chloride
produced water into a breached pit and onto the site surface.  Another
tank was discharging produced water from an open valve directly .onto the
site surface.  State inspectors also expressed  concern about lead and
mercury contamination from the discharge;,  Lead-levels in the discharge
were 2.5 times the accepted level for drinking water, and mercury levels
were 925 times the acceptable levels for drinking water, according to
results filed for the State by a private laboratory.   The State issued a
suspension order stating that the discharge was "...causing contamination
and pollution..." to the surface and subsurface soil, and in order to
remedy the problem the operator would have to restore the disturbed
land.  (Ohio no longer allows the use of produced water disposal pits.)

Waste Analysis
A water sample taken at 10 feet below the pit from water covering the
soil of the Mckee Lease Well #2 showed chloride, 6,300 mg/L; lead,
0.12 mg/L; and mercury, 1.85 mg/L.

Comments
David Flannery, representing independent oil and gas producers in. Ohio,
states that this discharge violated State regulations and that
appropriate enforcement action was taken.

Violation of State Regulations:  Yes

Documentation
References for case cited:  Ohio Department of Natural Resources,
Division of Oil and Gas, Suspension Order #84/07, 3/22/84.  Muskingum
County Complaint Form. Columbus Water and Chemical Testing Lab sampling
report.
                                    C-6

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OH 38

    State:  Ohio

    Region:  2

    County/Parish:  Perry

    City/Town:  Logan

    Test of Proof:  Administrative, Legal, and Scientific

Description
The Donofrio well was a production oil well with an annular disposal
hookup fed by a 100-bbl produced water storage tank.  In December 1975,
shortly after completion of the well, tests conducted by the Columbus
Water and Chemical Testing Lab on the Donofrio residential water well
showed chloride concentrations of 4,550 ppm.  One month after the well
contamination was reported, several springs on the Donofrio property
showed contamination from high-chloride produced water and oil, according
to Ohio EPA inspections.  On January 8, 1976, Ohio EPA investigated the
site and reported evidence of oil overflow from the Donofrio well
production facility, lack of diking around storage tanks, and the
presence of several produced water storage pits.  In 1986, 9 years after
the first report of contamination, a court order was issued to disconnect
the annular disposal lines and to plug the well. The casing recovered
from the well showed that its condition ranged from fair to very poor.
The casing was covered with rust and scale, and six holes were found.

Waste Analysis
Water samples from the Donofrio well indicated increasing chloride
concentrations from 12/1/75 (4,550 ppm) to 3/25/76 (13,000 ppm). Water
samples from springs on the Donofrio property also showed chloride
contamination (ranging from 7,300 to 121,000 ppm), and on two occasions
                                    C-7

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(7 20.75 arc! 3 2- 7~) oil  .'.as seen flowing from the springs. Nine years
later (9 26,84).  the Donofrio well revealed 598 ppm of chloride.

Comments
Comments in the Docket by David Flannery and American Petroleum  Institute
(API) pertain to  OH 33.  Mr  Flannery states that "...the water  well
involved in that  case showed contamination levels which predated the
commencement of annular disposal...."  This statement refers to  bacterial
contamination of  the well  discovered in 1974.   (EPA notes that the damage
case discusses chloride contamination of the water well, not bacterial
contamination.)

Violation of State Regulations:  Yes

Documentation
Ohio Department of Natural Resources, Division of Oil  and Gas,
interoffice communication from M.  Sharro-ek to  S.  Kell  on the condition of
the casing removed from the Donofrio well.  Communication from Attorney
General's Office. E.S. Post, discussing court  order to plug the Donofrio
well.  Perry County Common Pleas Court Case #19262.  Letter from R.M.
Kimball, Assistant Attorney General, to Scott  Kell,  Ohio Department of
Natural Resources, presenting case summary from 1974 to 1984.  Ohio
Department of Health lab sampling  reports from 1976 to 1985. Columbus
Water and Chemical Testing Lab, sampling reports  from 12/1/75, 7/27/84.
and 8/3/84.

WV 18

    State:  West  Virginia

    Region:  2

    County/Parish:  Doddridge
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    City/Town:  'Center Point

    Test of Proof:  Legal, and Scientific.,

Description
Beginning in 1979, Allegheny Land and Mineral Company of West Virginia
operated a gas well, ?A-226, on the property of Ray and Charlotte
Willey.  The well was located in a corn field where cattle were fed in
winter, and within 1,000 feet of the Willey's residence.  The well was
also adjacent to  a stream known as the Beverlin Fork.  Allegheny Land and
Mineral also operated another gas well above the residence known as the
?A-306, also located on property owned by the Willeys.  Allegheny Land
and Mineral maintained open reserve pits and an open waste ditch, which
ran into Beverlin Fork.  The ditch served to dispose of produced water,
oil, drip gas, detergents, fracturing fluids, and waste production
chemicals.  Employees of the company told the Willeys that fluids in the
pits were safe for their livestock to drink.
 •
The Willeys alleged that their cattle drank the fluid in the reserve pit
and became poisoned, causing abortions, birth defects, weight loss,
contaminated milk, and death.  Hogs were also allegedly poisoned,
resulting in infertility and pig still-births, according to the complaint
filed  in the circuit court of Doddridge County by the Willeys against
Allegheny Land and Mineral.  The Willeys claimed that the soil on the
farm was contaminated, causing a decrease in crop production and quality;
that the ground water of the farm was contaminated, polluting the water
well from which they drew their domestic water supply; and that the value
of their real estate had been diminished as a result of these damages.
Laboratory tests  of soil and water from the property confirmed this
contamination.  The Willeys incurred laboratory expenses in having
testing done on livestock, soil, and water.  A judgment filed in the
circuit court of  Doddridge County was entered in 1983 wherein the Willeys
were awarded a cash settlement in court for a total of $39,000 plus
interest and costs.
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Waste Analysis
Water analysis was done on fluid from a waste holding tank on the
production site. The analysis revealed chlorides, 360,000 mg/L; phenols,
0.2 ir.g/L; sodium, 59.000 mg.V, aluminum,  2.0 mg/L; barium, 7.0 mg/L; and
iron, 150 mg/L.  A complete analysis is located in the file.

Violation of State Regulations:  Yes

Comments
The West Virginia Department of Energy states that "...now the Division
does not allow that type of practice, and would not let a landowner
subvert the reclamation law."

Documentation
References for case cited:  Complaint form filed in circuit court of
Doddridge County, West Virginia, #81-c-18.  Judgment  form filed in
circuit court of Doddridge County,  West Virginia.   Water quality summary
of Ray Willey farm.  Letter from D.  J.  Horvath to Ray Willey.  Water
analysis done by Mountain State Environmental Service.  Veterinary report
on cattle and hogs of Willey farm.   Lab reports from National Veterinary
Services Laboratories documenting abnormalities in Willey livestock.

WV 20

    State:  West Virginia

    Region:   2

    County/Parish:  Wood

    City/Town:  Dallison

    Test of Proof:  Administrative  and Legal
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Description
On February 2,3, 1983, Tom Ancona, a fur trapper, filed a complaint
concerning a fish kill on Stillwell Creek.  A second complaint was also
filed anonymously by an'employee of Marietta Royalty Co.  Ancona,
accompanied by a State fisheries biologist, followed a trail,consisting
of dead fish, frogs, and salamanders up to a drilling site operated by
Marietta Royalty Co., according to the complaint filed with  the West
Virginia DNR.  There they found a syphon hose draining the drilling waste
pit into a tributary of Still well Creek.  Acid  levels at the pit measured
a pH of 4.0, enough to shock and kill aquatic life, according to West
Virginia District Fisheries Biologist Scott Morrison.  Samples and
photographs were taken by the DNR.  No dead aquatic life was found above
the sample site.  Marietta Royalty Co. was fined a total of  $1,000 plus
$30 in court costs.

Waste Analysis
Waste analysis indicated a pH of 4.0.

Comments
The West Virginia Department of Energy states that "This activity lias now
been regulated under West Virginia's general permit for drilling fluids.
Under that permit there would have been no environmental damage."

Violation of State  Regulations:  Yes

Documentation
References .for case cited:  Complaint Form #6/170/83, West Virginia
Department of Natural Resources, 2/25/83.  West Virginia Department of
Natural Resources Incident Reporting Sheet, 2/26/83.  Sketches of
Marietta drill site.  Complaint for Summons or  Warrant, 3/28/83.  Summons
to Appear, 3/18/83.  Marietta Royalty Prosecution Report, West Virginia
Department of Natural.Resources.  Interoffice   memorandum containing
spill investigation details on  Marietta Royalty incident.
                                    C-ll

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    State:   Pennsylvania

    Region:   2

    County/Parisn:   McKean.  Forest  and,  Venango

    City/Town:  Lafayette and  Keating

    Test of Proof:   Scientific

Description
The U.S. Fish and Wildlife Service  conducted a survey of several streams
in Pennsylvania from 1982-85 to determine the impact on aquatic life over
a period of years resulting from discharge of oil  field wastes to
streams.  The area studied has a history of chronic discharges of wastes
from oil and gas operations.  The discharges were  primarily of produced
water from production and enhanced  recovery operations.  The streams
studied were Miami  Run,  South  Branch of Cole Creek, Panther Run, Foster
Brook, Lewis Run, and Pithole  Creek.  The study noted a decline
downstream from discharges in  all fish populations and populations of
frogs, salamanders,  and crayfish.

Waste Analysis
Data are all on file, but they are  too extensive to list all measured
levels (in mg/L) here.   Ambient levels found at Foster Brook indicated
that chloride, total hardness, and  resistivity exceeded DER limits; at
Lewis Run chlorides, manganese, osmotic pressure,  and total dissolved
solids exceeded DER limits; at Pithole Creek resistivity, total hardness,
manganese, and chloride exceeded DER limits.  At actual discharge points
into Pithole Creek and Cherry  Run,  metals were found (e.g., cadmium,
<1-280 ug.l;  barium, 940-396.000 ug/L; chromium,  <10-130 ug/L; and lead,
<10-1J80 ug/L). as well  as high levels of chloride (e.g.,  124  to
45.250 mg L).
                                    C  12

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Comments
David Flannery, on behalf of independent oil and gas producers in
Pennsylvania, notes that these discharges are prohibited by State and
Federal regulation.

Violation of State Regulations:  Yes

Documentation
References for case cited:  U.S. Fish and Wildlife, Summary of Data from
Five Streams in Northwest Pennsylvania, 3/85.  Background information on
the streams selected for fish tissue analysis, undated but after
10/23/85.  Tables  1 through 3 on point source discharge samples collected
in the creeks  included  in this study, undated but after 10/30/84.

PA 09

    State:  Pennsylvania

    Region:  2

    County/Parish:  McKean, Warren, Venango, and Elk

    City/Town:  Numerous

    Test of Proof:  Administrative and Scientific
                                              i
Description
The U. $. EPA  declared  a four-county area (including McKean, Warren,
Venango, and Elk counties) a major spill area in the summer of 1985. The
area is the oldest commercial oil-producing region  in the world.  Chronic
low-level releases have occurred in the region since earliest production
and continues  to this day.  EPA and other agencies  (e.g., U.S. Fish and
Wildlife, Pennsylvania  Fish and Game, U.S.  Coast Guard) were concerned
that continued discharge into the area's streams has already and will in
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the future have major environmental  impact.  The area is.dotted with
thousands of marginal stripper wells (producing^ high ratio of produced
water to oil), as well as thousands  of abandoned wells and pits.  In the
Allegheny Reservoir itself, divers spotted 20 of 81 known improperly
plugged or unplugged wells, 7 of which were leaking oily high-chloride
produced water into the reservoir and have since been plugged.  EPA is
concerned that many others are also  leaking oily produced water.

The U.S. Coast Guard  (USCG) surveyed the forest for oil spills and
produced water discharges, identifying those of particular danger to be
cleaned immediately, by government if necessary.  In the Allegheny Forest
alone, USCG identified over 500 sites where oil is leaking from wells,
pits, pipelines, or storage tanks.  In 59 cases, oil was being discharged
directly into streams; 217 sites showed evidence of past discharges and
were on the verge of discharging again into the Allegheny)Reservoir.
Illegal disposal of oil field wastes has had a detrimental effect on the
environment: "...there has been a lethal effect on trout streams and
damage to timber and habitat for deer, bear and grouse."  On Lewis Run,
52 discharge sites have been identified and the stream supports little
aquatic life.  Almost all streams in the Allegheny Forest have suppressed
fish,population as a  "...direct result of pollution from oil and gas
activity."   (API notes that oil and produced water leaks into streams
are prohibited by State and Federal  regulations.)

Waste Analysis
See: PA 02.  EPA, USCG, PaFG, USFW,  and USGS conducted analyses and
identified oil and gas waste streams and constituents  in four counties.
In 1986,  USGS sampled the following sites: Allegheny Springs, where
drinking wells were found to have elevated barium levels and undesirable
methane concentrations;   Penn DOT Roadside Rest Rt. 62, which indicated
barium, 2.3 mg/L, chloride, 267 mg/L, and total dissolved solids,
750 mg/L (all above EPA limits);  Sugar Grove., where abandoned oil wells
located less than 200 feet from a contaminated domestic water well were
found to contain high levels of aromatic hydrocarbons; and Tidioute
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Borough,  where a drinking water well showed high levels of metals,
including iron, 7.2 mg/L and manganese,• 0.5 mg/L.

Comments
Comments in the Docket by API pertain to PA 09.  API states that
"...litigation is currently pending with respect to this case in which
questions have been raised about the factual basis for government action
in this case."

Violation of State Regulations:  No

Documentation
References for case cited:  U.S. Geological Survey letter from Buckwalter
to Rice concerning sampling of water in northern Pennsylvania, 10/27/86.
Pennsylvania Department of Environmental Resources press release on
analysis of water samples, undated but after 8/83.  Oil and Water: When
One of the By-products of High-grade Oil Production is a Low-grade
Allegheny National Forest, It's Time to Take a Hard Look at Our
Priorities by Jim Morrison,  Pennsylvania Wildlife, Vol. 8, No.  1.
Pittsburgh Press, "Spoiling a Wilderness,"  1/22/84; "Oil Leaking into
Streams at 300 Sites  in Northwestern Area of the State," 1985.  Warren
Times, "Slick  Issues  Underscore Oil Cleanup in National Forest," 1986.

WV 17

    State:  West Virginia

    Region:  2

    County/Parish:  Jackson

    City/Town:  Ripley

    Test of Proof:  Administrative and Scientific
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Description
In 1982,  Kaiser Gas Co.  drilled a gas well  on the property of Mr.  James
Parsons.   The well  was fractured using a typical  fracturing fluid or
gel.   The residual  fracturing fluid migrated into Mr.  Parson's water well
(which was drilled to a depth of 416 feet), according  to an analysis by
the West  Virginia Environmental Health Services Lab of well water samples
taken from the property.   Dark and light gelatinous material (fracturing
fluid) was found, along with white fibers.   (The gas well is located less
than 1,000 feet from the water well.)  The chief of the laboratory
advised that the water well was contaminated and unfit"for domestic use,
and that  an alternative source of domestic water had to be found.
Analysis  showed the water to contain high levels of fluoride, sodium,
iron, and manganese.  The water, according to DNR officials, had a
hydrocarbon odor, indicating the presence of gas.  To  date Mr. Parsons
has not resumed use of the well as a domestic water source.  (API states
that this damage resulted from a malfunction of the fracturing process.
If the fractures are not limited to the producing formation, the oil and
gas are lost from the reservoir and are unrecoverable.)

Waste Analysis
Well water was analyzed and found to contain high levels of fluoride,
sodium, iron, manganese, as well as elevated alkalinity.  The water had a
hydrocarbon odor indicating the presence of gas.  Dark and light
gelatinous material (fracturing fluid) was found along with white fibers.

Comments
Comments in the Docket pertain to WV 17, by David Flannery and West
Virginia, Department of Energy.  Mr. Flannery states that "...this is an
area where water problems have been known to occur  independent of oil  and
gas operations."  EPA notes that the "problems" Mr. Flannery is referring
to are the natural  high level  of fluoride, alkalinity, sodium, and total
dissolved solids in the water.  However, the constituents of concern
found in this water well were  the gelatinous material  associated with  the
fracturing process, and hydrocarbons.  West Virginia Department of Energy
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states that the WVDOE "...had no knowledge that the Pittsburgh sand was a
fresh water source."   Also, WVDOE pointed out that WV Code 22B-1-20
"...requires an operator to cement a string of casing 30 feet below all
fresh water zones."   According to case study records, Kaiser Gas Co. did
install  a cement string of casing 30 feet below the Pittsburgh sand.

Violation of State Regulations:  No

Documentation
References for case cited:  Three lab reports containing analysis of
water well.  Letter from J. E. Rosencrance, Environmental Health Services
Lab, to P. R. Merritt, Sanitarian, Jackson County, West Virginia.  Letter
from P. R. Merritt to J. E. Rosencrance requesting analysis.  Letter from
M. W. Lewis, Office of Oil  and Gas, to James Parsons stating State cannot
help in recovering expenses, and Mr. Parsons must file civil suit to
recover damages.  Water well inspection report = complaint.  Sample
report forms.

PA 08

    State:  Pennsylvania

    Region:  2

    County/Parish:  Venango

    City/Town:  Bel mar

    Test of Proof:  Legal  and Scientific

Description
Civil suit was brought by  14 families living in the village of Belmar
against a Meadville-based  oil drilling company, Norwesco Development
Corporation, in June  1986.  Norwesco had drilled more than 200 wells near
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Bel mar,  and residents of the village claimed that the activity had
contaminated the ground water from which they drew their domestic water
supply.   The Pennsylvania Department of Environmental Resources and the
Pennsylvania Fish Commission cited Norwesco at least 19 times for
violations of State regulations.   Norwesco claimed it was not responsible
for contamination of the ground water used by the village of Bel mar.
Norwesco suggested instead that the contamination was from old,.
long-abandoned wells.  The Pennsylvania Department of Environmental
Resources (DER) agreed with Belmar residents that the contamination was
from the current drilling operations.  Ground water in Belmar had been
pristine prior to the drilling operation of Norwesco. -All families •
relying on the ground water lost their domestic water-supply.  The water .
from the contaminated' wells would "...burn your eyes in the shower, and
your skin' is so dry and itchy when you get out."  Families had to buy-
bottled water for drinking and had to drive, in some cases, as far as 30
miles to bathe.  Not only were residents not able to drink or bathe using
the ground water; they could not use the water for washing clothes or
household items without causing permanent stains.  Plumbing fixtures were
pitted-by the high level of total dissolved solids and high chloride*
levels.

In early 1986, DER ordered Norwesco to provide Belmar with an alternative
water supply that was equal in quality and quantity to what the Belmar
residents lost when their wells were contaminated.  In November 1986
Norwesco offered a cash settlement of $275,000 to construct a new water
system for the village and provided a temporary water supply.

Waste Analysis
Tests on one water well owned by the Neidirch family showed that it.had
15 times the maximum level of chlorides (3,750 ppm) and 13 times the
level of total dissolved solids (7,500 ppm) recommended by EPA.  Other
water wells in Belmar tested similarly.
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Comments
David Flannery. on behalf of independent oil and gas producers in
Pennsylvania, states that these activities are in violation of Federal
and State regulations.

Violation of State Regulations:  Yes

Documentation
References for case cited:  Pittsburgh Press, "Franklin County Village
Sees Hope after Bad Water Ordeal,"  12/7/86.  Morning News, "Oil  Drilling
Firm Must Supply Water to Homes," 1/7/86; "Village Residents Sue  Drilling
Company," 6/7/86.

WV 13

    State:  West Virginia

    City/Town:  Mt. Zion

    Region:  2

    County/Parish:  Calhoun

    Test of Proof:  Administrative

Description
In early 1986 Tower Drilling land-applied the contents of a reserve pit
to an area 100 feet by 150 feet.  All vegetation died in the area where
pit contents were directly applied, and three trees adjacent to the land
application area were dying allegedly because of the leaching of high
levels of chlorides into the soil.  A complaint was made by a private
citizen to the West Virginia DNR.  Samples taken by West Virginia DNR of
the contaminated soil measured  18,000 ppm chloride.
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Waste Analysis
Analysis was done on affected soil.  The results showed dissolved oxygen
at 7.0 mg/L, specific conductance of 43,000 umhos/cm, and chloride  at
18,000 mg/L.

Comments
Comments in the Docket by David Flannery and API pertain to WV 13.  The
statements by API and Mr. Flannery are identical.  They state that  it
might not be "...possible to determine whether it was the chloride
concentration alone which caused the vegetation stress."  Also, they
claim that the damage was short term and "...full recovery of vegetation
was made."  Neither commenter submitted supporting documentation.

Violation of State Regulations:  No

Documentation
References for case cited:  West Virginia Department of Natural Resources
complaint form #6/131/86.  Analytical report on soil analysis of kill
area.

KY 01

    State:  Kentucky

    Region:  2

    County/Parish:  Lawrence and Johnson

    Test of Proof:  Administrative and Scientific

Description
From April 29 through May 8, 1986, representatives of the U.S. EPA,
Region IV, conducted a surface water investigation in the Blaine Creek
watershed near Martha, Kentucky.  The study was requested by the U.S. EPA
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Water Management Division to provide additional baseline information on
stream water quality conditions «in the Blaine Creek area.  Blaine Creek
and its tributaries have been severely impacted by oil production
activities conducted in the Martha oil field since the early 1900s.  The
Water Management Division issued an administrative order requiring that
direct and indirect brine discharges to area streams cease by May 7, 1986.

For the study in 1986, 27 water chemistry sampling stations, of which 13
were also biological sampling stations, were established in the Blaine
Creek watershed.  Five streams in the study area were considered control
stations.  Biological sampling indicated that macroinvertebrates in the
immediate Martha oil field area were severely impacted.  Many species
were reduced or absent at all stations within the oil field.  Blaine
Creek stations downstream of the oil field, although impacted, showed
gradual improvement in the benthic macroinvertebrates.  Control stations
exhibited the greatest diversity of benthic macroinvertebrate species.
Water chemistry results for chlorides generally indicated elevated levels
in the Martha oil field drainage area.  Chloride values in the affected
area of the oil field ranged from 440 to 5,900 mg/L.  Control station
chloride values ranged from 3 to 42 mg/L.

In May of 1987, U.S. EPA, Region IV, conducted another surface water
investigation of the Blaine Creek watershed.  The study was designed to
document changes in water quality in the watershed 1 year following the
cessation of oil production activities in the Martha oil field.  By May
of 1987, the major operator in the area, Ashland Exploration, Inc., had
ceased operations.  Some independently owned production wells were still
in service at this time.  Chloride levels, conductivity, and total
dissolved solids levels had significantly decreased at study stations
within the Martha oil field.  Marked improvements were observed in the
benthic invertebrate community structures at stations within the Martha
oil field.  New species that are considered sensitive to water quality
conditions were present in 1987 at most of the biological sampling
stations, indicating that significant water quality improvements had
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occurred following cessation of oil production activities  in  the  Martha
field.  Chloride level's in one stream in the Blaine Creek  watershed
decreased from 5,900 mg/L to 150 mg/l.

Hater Analysis
Chloride values in the affected area of the oil field ranged  from 440 to
5.900 mg/L.  Control station chloride values ranged from 3 to 42  mg/L.
Chloride levels in one stream in the Blaine Creek watershed decreased
from 5,900 mg/L to 150 mg/L after cessation of operations.

Comments
None.

Violation of State Regulations:  Yes

Documentation
References for case cited:  Martha Oil Field Water Quality Study, Martha,
Kentucky, U.S. EPA, Athens, Georgia, May 1986.   Martha Oil Field  Water
Quality Study, Martha, Kentucky, U.S. EPA,  Athens, Georgia, May 1987.

LA 67

    State:  Louisiana

    City/Town:  Abbeville

    Reg ion:  4

    County/Parish:  Vermilion

    Test of Proof:  Administrative, Legal,  and Scientific

Description
In 1982,  suit was brought on behalf of Dudley Romero et al. against
operators of an oil waste commercial disposal facility. PAB Oil Co.  The

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plaintiffs stated that their domestic water wells were contaminated by
wastes dumped into open pits in the PAB Oil Co. facility which were
alleged to have migrated into the ground water, rendering the water wells
unusable.  Oil field wastes are dumped into the waste pits for skimming
and separation of oil.  The pits are unlined. The PAB facility was
operating prior to Louisiana's first commercial oil field waste facility
regulations. . After promulgation of new regulations, the facility
continued to operate for 2 years in violation of the new regulations,
after which time the State shut down the facility.

The plaintiffs' water wells are downgradient of the facility, drilled to
depths of 300 to 500 feet.  Problems with water wells date from 1979.
Extensive analysis was performed by Soil Testing Engineers,  Inc., and
U.S. EPA on the plaintiffs' water wells adjacent to the site to determine
the probability of the well contamination coming from the PAB Oil Co.
site.  There was also analysis on surface soil contamination.  Soil
Testing Engineers, Inc., determined that it was possible for the wastes
in the PAB Oil Co. pits to reach and contaminate the Romeros' water
wells.  Surface sampling around the perimeter of the PAB Oil Co. site
found high concentrations of metals.  Resistivity testing showed that
plumes of chloride contamination in the water table lead from the p'its to
the water wells. Borings that determined the substrata makeup suggested
that it would be possible for wastes to contaminate the Romeros' ground
water within the time that the facility had been in operation if the
integrity of the clay cap in the pit has been lost  (as by deep excavation
somewhere within it).  The pit was  12 feet deep and within range to
percolate into the water-bearing sandy soil.

Plaintiffs complained of sickness,  nausea, and dizziness, and a loss of
cattle.  The case was settled out of court.  The plaintiffs  received.
$140,000 from PAB Oil Co.
                                    C-23

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Waste Analysis
Surface sampling around the perimeter of the PAB Oil Co. site found high
concentrations of metals (in ppm).   Upstream soil samples indicated:
arsenic. 19.8;  cadmium. 3.2; chromium, 31.3; copper, 14.8; lead, 13.2;
nickel, 13.0; and zinc. 43.3.  The  PAB Oil  Co.  NE pit sample showed:
arsenic, 16.2; cadmium, <18.0; beryllium,  <18.0; chromium, 18.9; copper
<18: lead.  <27; nickel. <18; silver,  <18;  and zinc,  58.6. Romero well
test results revealed:  barium, 0.074; cadmium,  <0.005; copper, <0.01;
iron, 1.9:  lead. <0.04; nickel,  <0.02: and  zinc, 0.26.

Comments
None.

Violation of State Regulations:   No

Documentation
References  for case cited:   Soil  Testing Engineers,  Inc., Brine Study,
Romero, et  al., Abbeville,  Louisiana, 10/19/82.  U.S. EPA lab analysis  of
pits and wells, 10/22/81.   Dateline,  Louisiana:  Fighting Chemical
Dumping, by Jason Berry, May-June,  1983.

LA 20

    State:   Louisiana

    Region:   4

    County/Parish:   Terrebonne

    City/town:   Not Applicable

    Test of Proof:   Scientific
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Description
In 1984, the Glendale Drilling Co., under contract to Woods Petroleum,
was drilling from a barge at the intersection of Taylor's Bayou and Cross
Bayou. The operation was discharging drill cuttings and mud into the
bayou within 1,300 feet of an active oyster harvesting area and State
oyster seeding area.  At the time of discharge, oyster harvests were in
progress.  (It is State policy in Louisiana not to grant permits for the
discharge of drill cuttings within 1,300 feet of an active oyster
harvesting, area.  The Louisiana Department of Environmental Quality does
not allow discharge of whole rnud into estuaries.).

A State Water Pollution Control Division inspector noted that there were
two separate discharges occurring from the barge and a low mound of mud
was protruding from the surface of the water beneath one of the
discharges.  Woods Petroleum had a letter from the Louisiana Department
of Environmental Quality authorizing them to discharge the drill cuttings
and associated mud, but this permit would presumably not have been issued
if it had been known that the drilling would occur near an oyster
harvesting area.  While no damage was noted at time of inspection, there
was great concern expressed by the Louisiana Oyster Growers Association;
the Louisiana Department of Wildlife and Fisheries, Seafood Division; and
some  parts of the Department of Water Pollution Control Division of the
Department of Environmental Quality.  The concern of these groups stemmed
from  the possibility that the discharge of muds and cuttings with high
                "f'^F*                         (
content of metals may have long-term impact on the adjacent commercial
oyster fields and the State oyster seed fields in nearby Junop Bay.  In
such  a situation, metals can precipitate from the discharge, settling in
progressively higher concentrations in the bayou sediments where the
oysters mature.  The bioaccumulation of these metals by the oysters can
have  an adverse  impact on the oyster population and could also lead to
human health problems if contaminated oysters are consumed.

The Department of Environmental Quality decided in this case to direct
the oil company  to stop the discharge of drill cuttings and muds  into the
                                    C-25

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Savon.  ~.n this in£:ince,  t're Ie:art;r,ent of Environmental QuaMty  ordered
thit a drill  cutting barge be used to contain the remainder of the drill
cuttings.   The company was not ordered to clean up the mound, of drill
cuttings that it had already deposited in the bayou.

Waste Analysis
Split samples used in laboratory analysis of both discharges indicated
elevated levels of chromium.

Comments
The Louisiana Office of Conservation notes that  "Generally, drill
cuttings discharged with weighted drilling fluids (containing borite,
calcium chloride, etc.) are allowed in brackish and saline areas provided
the discharge does not take place within 1,300 feet of an active oyster
lease or seed bed	"  In freshwater marshes, drill cuttings can also be
discharged if the operator can meet stringent conditions preventing
excessive  turbidity. In the future, WPCD plans to issue a general permit
for drilling  fluid discharges in tidally affected brackish and saline
areas.

Violation of State Regulations:  No

Documentation
References for case cited:  Louisiana Department of Environmental
Quality, Water Pollution Control Division, Office of Water Resources,
internal memorandum, 6/3/85.

LA 45

    State:  Louisiana

    Region:  4

    County'Parish:   Lafourche
                                   C-26

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    City/Town:  Lewistown

    Test of Proof:  Scientific

Description
Two Louisiana Water Pollution Control inspectors surveyed a swamp
adjacent to a KEDCO Oil Co. facility-to assess flora damage recorded on a
                                 ' '                                 •i'.l'Ajt
Notice of Violation issued to KEDCO on 3/13/81.  The Notice of Violation
discussed brine discharges into an adjacent canal that emptied into a
cypress swamp from a pipe protruding from the pit levee.  Analysis of a
sample collected by a Mr. Martin, the complainant, who expressed concern
over the high-chloride produced water discharge  into the canal he used to
obtain water for his crawfish pond, showed salinity levels of 32,000 ppm
(seawater is 35,000 ppm).

On April 15, 1981, the Water Pollution Control inspectors made an effort
                                                              • V--    ->«?•
to measure the extent of damage to the trees in  the cypress swamp_.  After
surveying the size of the swamp, they randomly selected a compass bearing
and surveyed a transect measuring 200 feet by 20 feet through the swamp.
They-counted and then classified all trees in the area according to the
degree of damage they had sustained.  Inspectors found that "...an
approximate«total area of 4,088 acres of swamp was severely damaged."
Within the randomly selected transect, they classified all trees
according to the degree of damage.  Out of a total of 105 trees, 73
percent were dead, 18 percent were stressed, and 9 percent were normal.
The inspectors' report noted that although the transect ran through a
heavily damaged area, there were other areas much more severely
impacted.  They therefore concluded, based upon  data collected and
firsthand observation, that the percentages of damaged trees recorded,
"...are a representative, if not conservative, estimate of damage over
the entire affected area."  In the opinion of the inspectors, the
discharge of produced water had been occurring for some time, judging by
the amount of damage sustained by the trees.  KEDCO was fined $9,500 by
the State of Louisiana and paid $4,500 in damages to the owner of the
affected crawfish farm.
                                    C-27

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Waste Analysis
See: LA 38. At the time of the most recent inspection on 2/2/81, field
testing for salinity in the water revealed that the canal had 19,000 ppm;
salinity under a railroad trestle in the canal, at the point where the
canal empties into The cypress swamp,  was 39.5 ppm.  Analysis of the
sample collected by Mr. Martin (the complainant who expressed concern
over the produced water discharge into the canal he used to obtain water
for his crawfish pond) at the time of the discharge into the canal on
1/30/81 showed salinity at 32,000 ppm.

Comments
None.

Violation of State Regulations:  Yes

Documentation
References for case cited:  Louisiana Department of Natural  Resources,
Water Pollution Control Division, internal memo, Cormier and St. Pe to
Givens concerning damage evaluation of swamp near the KEDCO Oil  Co.
facility, 6/24/81.  Notice of Violation, Water Pollution Control Log
=2-8-81-21.

LA 15

    State:  Louisiana

    Region:  4

    County/Parish:  Terrebonne

    City/Town:  Thibodeaux

    Test of Proof:  Administrative and Scientific
                                   C-28

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Description
Sun Oil Co. operates a site located in the Chacahoula Field.  A
Department of Natural Resources inspector noted a site configuration
during an inspection (6/25/82) of a tank battery surrounded'by a pit
levee and a  pit  (30 yards by 50 yards).  The pit was discharging
produced water into the adjacent swamp in two places, over a low part in
the levee and from a pipe that had been put through the ring levee
draining directly into the swamp.  Produced water, oil, and grease were
being discharged  into the swamp.  Chloride concentrations from samples
taken.by the inspectors ranged from 2,948 ppm to 4,848 ppm, and oil and
grease concentrations measured 12.6 ppm to 26.7 ppm.  The inspector noted
that the discharge into the swamp was the means by which the company
drains the tank battery ring levee area.  A notice of violation was
issued to Sun Oil by the Department of Natural Resources.

Waste Analysis

Sampl-e analysis indicated the following results: at the discharge pipe
from the tank to  the pit, chloride at 75,230 ppm, conductivity,
110,000 umhos; at the discharge from the pit to the swamp, chloride at
4,748 ppm, conductivity, 100,000 umhos; at the discharge from the tank to
the pit, chemical oxygen demand, 5,909 ppm,  oil and grease, 12.6 ppm;
and at the discharge from the large pipe leading from the tank battery
pit area, chloride at 2,948 ppm, conductivity, 9,700 umhos, chemical
oxygen demand, 369 ppm, and oil and grease, 26.7 ppm.

Comments
None.

Violation of State Regulations:  Yes

Documentation
References for case cited:  Louisiana Department of Natural Resources,
                       'K
Water Pollution Control Division, internal memo from Cormier to Givens,
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8 !5 22.  cor
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would be lowest, the sugar cane appeared healthy.  Subsequent field
investigation and soil sampling conducted by Dr. Subra in November of
1986 found the field to be nearly barren, with practically no sugar cane
growing.  Dr. Subra measured concentrations of salts in the soil ranging
from a low of 1,403 ppm to 35,265 ppm at the -edge of the field adjacent
to the oil operation.  Sun has undertaken a reclamation project to
restore the  land.  It is estimated that the project will  take 2 to 3
years to complete.  In the interim, Sun Oil will pay the sugar cane
farmer for loss of crops.

Waste Analysis
All sampling done for salt was conducted on 11/15/86.  The following
results were obtained: Twelve soil samples from the cane field
downgradient indicated salt concentrations  on the perimeter of the
facility near the produced water storage tank ranging from 5,259 to
71,940 ppm;  samples from the middle of the cane field ranged from 1,403
to 6,478 ppm, and samples from the extreme edge of the field ranged from
20,186 to 35,265 ppm;  four water samples from the cane field at the
perimeter of the facility near the produced water storage tank ranged
from 1,774 to 3,383 ppm; and one sample near the edge of the field showed
2,210 ppm.

Comments
API states that an accidental release occurred in this case.  EPA records
show this release lasted 2 years.

Violation of State Regulations:  No

Documentation
References for case cited:  Documentation from Dr. Wilma Subra, including
a series of maps documenting changes in the sugar cane over a period of
time, 12/86.  Maps showing location of sampling and salt concentrations.
                                    C-31

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LA 90

    State:  Louisiana

    Region:  4

    County/Parish:  Vermilion

    City/Town:  Abbeville

    Test of Proof:  Administrative, Legal, and Scientific

Description
Chevco-Kengo Services, Inc., operates a centralized disposal facility
near Abbeville, Louisiana.  Produced water and other wastes are
transported from surrounding production fields by vacuum truck to the
facility. Complaints were filed by private citizens alleging that
discharges from the facility were damaging crops of rice and crawfish,-
and that the facility represented a threat to the health of nearby
residents.  An inspection of the site by the Water Pollution Control
Division of the Department of Natural Resources found that a truck
washout pit was emptying oil field wastes into a roadside ditch flowing
into nearby coulees.

Civil suit was brought by private citizens against Chevco-Kengo Services,
Inc., asking for a total of 54 million in property damages, past and
future crop loss, and exemplary damages.   Lab analysis performed by the
Department of Natural Resources of waste samples indicated high metals
content of the wastes, especially in samples taken from the area near the
facility and in the adjacent rice fields, indicating that the discharge
of wastes from the facility was the source of damage to the surrounding
land.  The case is in litigation.
                                    C  32

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Waste Analysis
Or. Subra's analysis revealed these concentrations in crawfish tails from
the adjacent pond: barium, 18 ppm, zinc, 16.5 ppm; from the roadside
ditch on the south side of Parish Rd. P-3-5, 0.3 miles west of the Chevco
site: salt, 854 ppm. barium, 1,250 ppm, chromium, 15 ppm, lead, 16 ppm,
zinc, 548 ppm: from the roadside ditch on the west side of the Chevco
main entrance from Parish Rd. P-3-5: barium, 1,190 ppm, chromium,
301 ppm, lead, 184 ppm,  zinc, 1,203 ppm;   from the roadside ditch
directly across Parish Rd. P-3-5 from the Chevco outfall: barium, 2,200
ppm, chromium, 8.8 ppm, lead, 38 ppm, and zinc, 190 ppm.  Rice field
ranges were: zinc, 13.7 to 29.5 ppm; lead,  6 to 26 ppm; chromium, 4.5 to
12.2 ppm; and barium, 65 to 230 ppm.

Comments
API states that these discharges were accidental.

Violation of State Regulations:  Yes

Documentation
References for case cited:  Louisiana Department of Natural Resources,
Water Pollution Control Division, internal  memo, lab analysis, and
photographs, 8/25/83.  Letter from Westland Oil Development Corp. to
Louisiana Department of Natural Resources,  4/15/83.

AR 07

    State:  Arkansas

    Region:  4

    County/Parish:  Union

    City/Town:  El Dorado

    Test of Proof:  Administrative

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Description
An oil  production unit operated by Mr.  J.C. Langley was discharging oil
and produced water in large quantities  onto the property of Mr. Melvin
Dunn and Mr. ',-.'.  C. Shaw.   The oil  and produced water discharge allegedly
caused  severe damage to the property, interfered with livestock on the
property, and delayed construction of a planned lake.  Mr. Dunn hac
spoken  repeatedly with a  co-7ipan> representative operating the facility
concerning the oil and produced water discharge, yet no changes occurred
in the  operation of ihe facility  A complaint was made to Arkansas
Department of Pollution Control and Ecology (ADPCE), the operator was
informed of the  situation,  and the facility was brought into
compliance.   Mr. Dunn then hired  a private attorney in order that
remedial action  would be  taken.  It is  not known whether the operator
cleaned up the damaged property.

Waste Analysis
Not available.

Comments
API states that  this incident constituted a spill and is therefore a
non-RCRA issue.

Violation of State Regulations:  Yes

Documentation
References for case cited:   Arkansas Department of Pollution Control  and
Ecology (ADPCE)  Complaint form, ?EL 1721, 5/14/84.  Letter from Michael
Landers, attorney to Mr.  Dunn, requesting investigation from Wayne Thomas
concerning Langley violations.  Letter  from J. C. Langley to Wayne
Thomas. ADPCE. denying responsibility for damages of Dunn and Shaw
property, 6, 5 84.  Certified letter from Wayne Thomas to J.  C. Langley
discussing violations of  facility  and required remedial actions,
5 30 84.  Map of violation  area, 5,29/84.  ADPCE oil field waste survey
                                   C-34

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documenting unreported oil spill on Langley unit, 5/25/84.  Letter from
Michael Landers, attorney to ADPCE, discussing damage to property of Dunn
and Shaw, 5/11/84.

AR 10

    State:  Arkansas

    Region:  4

    County/Parish:  Ouachita

    City/Town:  Louann

    Test of Proof:  Administrative

Description
On September 20, 1984, an anonymous comp.laint was filed -with ADPCE
concerning the discharge of oil and produced water in and near Smackover
Creek from production units operated by J. S. Beebe Oil Account.  Upon
investigation by ADPCE, it was  found that salt water was leaking from a
saltwater disposal well located on the site.  Mr. Beebe wrote a letter
stating his willingness to correct the situation.  On November 16, 1984,
the site was again investigated by ADPCE, and it was found that pits on
location were being used as the primary disposal facility and were
overflowing and leaking into Smackover Creek.  The ADPCE issued a Notice
of Violation (L1S 84-066), and  noted that the pits were below the creek
level and overflowed into the creek when heavy rains occurred.  One pit
was being siphoned over the pit wall, while waste from another pit was
flowing onto the ground through an open pipe.  The floors and walls of
the pits were saturated, allowing seepage of waste from the pits.  ADPCE
ordered Mr. Beebe to shut down  production and clean up the site and fined
him $10,500.
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Waste Analysis
Not available.

Comments
API states that this case represents a violation of Arkansas' rules and
regulations.

Violation of State Regulations:  Yes

Documentation
References for case cited:  ADPCE complaint form #EL 1792, 9/20/84, and
8/23/84.  ADPCE inspection report, 9/5/84.  Letter from ADPCE to J. S.
Beebe outlining first run of violations, 9/6/84.  Letter stating
willingness to cooperate from Beebe to ADPCE, 9/14/84.  ADPCE complaint
form #EL 1789, 9/19/84.  ADPCE inspection report, 9/25 and 9/26/84.
ADPCE complaint form #EL 1822, 11/16/84.  ADPCE Notice of Violation,
Findings of Fact,  Proposed Order and Civil Penalty Assessment, 11/21/84.
Map of area.  Miscellaneous letters.

AR 04

    State:  Arkansas

    Region:  4

    County:  Miller

    City/Town:  Not Applicable

    Test of Proof:  Administrative and Scientific

Description
In 1983 and again in 1985, James M. Roberson, an oil and gas operator,
was given surface access by the Arkansas Game and Fish Commission  for
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drilling in areas in the Sulphur River Wildlife Management Area (SRWMA),
but was not issued a drilling permit by either of the State ..agencies that
share jurisdiction over oil and gas operations.  Surface- rights are owned
by the Arkansas Game and Fish Commission.  The Commission attempted to
write its own permits for this operation to protect the wildlife
management area resources.  Mr. Roberson repeatedly violated the
requirements contained in these surface use permits, and the Commission.
also determined that he was in violation of general State and Federal
regulations applicable to his operation in the absence of OGC or ADPCE
permits.  These violations led to release of oil and high-chloride
produced water into the wetland areas of the Sulphur River and Mercer
Bayou from a leaking saltwater disposal well and illegal produced water
disposal pits maintained by the operator.

Oil and saltwater damage to the area was documented in a study conducted
by Hugh A. Johnson, Ph.D., a professor of biology at Southern Arkansas
University.  His study mapped chloride levels around each well site and
calculated the affected area.  The highest chloride level recorded in the*
wetland was 9,000. ppm (native vegetation begins to be stressed from
exposure to 250 ppm chlorides).  He found that significant areas around
each well site had dead or stressed vegetation related to excessive
chloride exposure.  The Game and Fish Commission fears that continued
discharges of produced water and oil in this area will threaten the last
remaining forest land in the Red River bottoms.

Waste Analysis
Oil and saltwater damage were documented in a study of the area by Hugh
A. Johnson, Ph.D.   The study mapped chloride levels around each well
site and calculated the area of damage.  Highest chlorides in wetlands
were 9,000 ppm.  Significant areas around each well site had dead or
stressed vegetation due to saltwater exposure.

Comments
API states that the Arkansas Water and Air Pollution Act gives authority
at several levels to require cleanup of these illegal activities and to
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prevent further jtCL;rr=rK3i.  EP3. noT.es that while  the  authority  exists.
an effeciive implementation -echjnism appears to be  lacking.

Violation of State Regulations:  Yes

Documentation
References for case citec:  Letter from Steve Forsythe, Department  of  the
Interior (DOI). to Pat Stevens, Army Corps of Engineers (ACE),  stating
that activities of Mr. Roberson have resulted in significant  adverse
environmental impacts and disruptions and that DOI recommends  remedial
action be taken.  Chloride Analysis of Soil and Water Samples  of  Selected
Sites in Miller County. Arkansas, by Hugh A. Johnson, Ph.D, 10/22/85.
Letter to Pat Stevens, ACE, from Dick Whittington, EPA, discussing
damages caused by Jimmy Roberson in Sulphur River Wildlife Management
Area (SRWMA) and recommending remedial  action and denial of new permit
application.  Oil and Gas well drilling permits dated 1983 and  1985 for
Roberson activities.  Numbers of letters and complaints addressing
problems in SRWMA resulting from activities of James Roberson.
Photographs.  Maps.

AR 12

    State:   Arkansas

    Region:   4

    County/Parish:   Columbia

    City/Town:   Stephens

    Test of Proof:   Administrative

Description
On September 19.  1984, Mr. James Tribble made a complaint to the Arkansas
Department  of Pollution Control  and Ecology concerning salt water that

                                   C-38

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was coming up out of the ground in his yard, killing his grass, and
threatening his water well.  There are many oil wells in the area, and
water flooding is a common enhanced recovery method at these sites.  Upon
inspection of the wells nearest to his residence, it was discovered that
the operator, J. C. McLain, was injecting salt water into an unpermitted
well.  The salt water was  being injected into the casing, or annulus, not
into tubing.  Injection into the unsound casing allegedly allowed
migration into the freshwater zone.  A produced water pit at the same
site was near overflowing.  State  inspectors later noted in, a followup
inspection that the violations had been corrected.  No fine was
levied.

Waste Analysis
Not available,

Comments
API notes that this case represents a violation of Arkansas rules and
regulations.

Violation of State Regulations:  Yes

Documentation
References for case cited:  ADPCE  Complaint form, #EL 1790, 9/19/84.
ADPCE inspection report, 9/20/84.  Letter from ADPCE to Mr. J. C. McLain
describing violations and  required corrective action, 9/21/84.  ADPCE
reinspection report, 10/11/84.

 MI 05

    State:  Michigan

    Region:  5

    County:  Osceola
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    Test of Proof:   Scientific

Description
in June 1983.  a water well  ov,nea by Mrs.  Geneva Brown was tested after
sr.e had filed  a coT.pl aint to the Michigan Geological Survey.  After
responding, the Michigan Geological Survey found a chloride concentration
of ^90 ppm in  the water.  Subsequent sampling from the water well of a
neighbor, Mrs. Dodder, showed that her well  measured 760 ppm chloride in
August.  There are a total  of 15 oil and  gas wells in the area
surrounding the contaminated water wells.  Only five of the wells are
still producing, recovering a combination of oil and produced water.
The source of  the pollution was evidently the H.E. Trope, Inc., crude oil
separating facilities and produced water  storage tanks located upgradient
from the contaminated water wells.  Monitoring wells were installed to
confirm the source of the contamination.  Stiff diagrams were used to
confirm the similarity of the constituent: of the formation brine and the
chloride contamination of the affected water wells.   Sample results
                                                 »
located two plumes of chloride contamination ranging in concentration
from 550 to 1,800 ppm that  are traveling  in a southeasterly direction
downgradient from the produced water storage tanks and crude oil
separator facilities owned  by H.E. Trope.

Waste Analysis
Water well samples from the domestic wells owned by G. Brown and
M. Dodder showed chloride concentrations  ranging from 490 to 550 ppm and
550 to 800 ppm, respectively. Monitoring  wells used in the study showed
chloride concentrations ranging from 550  to 1,800 ppm. A produced water
sample from the storage tanks measured 191,000 ppm.

Comments
API states that this case appears to represent a non-RCRA issue as damage
was due to leaks or spills  of produced water.
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Violation of State Regulations:  Yes

Documentation
References for case cited:  Open file report, Michigan Department of
Natural Resources, Investigation of Salt-Contaminated Groundwater in Cat
Creek Oil Field, Hersey Township, conducted by D. W. Forstat, 1984.
Appendix includes correspondence relating to investigation, area water
well drilling logs, Stiff diagrams and water analysis, site monitor well
drilling logs, and water  sample analysis for samples used in the
investigation.

MI 06

    State:  Michigan

    Region:  5

    County/Parish:  Muskegon

    City/Town:  Laketon

    Test of Proof:  Scientific

Description
In April 1980, residents  of Green Ridge Subdivision, located in Section
15, Laketon Township  in Muskegon County, complained of bad-tasting water
from their domestic water wells.  Some wells sampled by the local health
department revealed elevated chloride concentrations.  Because of the
proximity of the Laketon  Oil Field, an investigation was started by the
Michigan Geological Survey.  The Laketon Oil Field consists of dry holes,
producing oil wells,  and  a produced water disposal well, the Harris Oil
Corp. Lappo $1.  Oil  wells produce a mixture of oil and produced water.
The produced water is separated and disposed of by gravity in the brine
disposal well and is  then placed back in the producing formation.  After
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reviewina "oni ror;na well and electrical resistivity survey data,  the
Michigan Geological Survev concluded that the source of the contamination
was the Harris Oil Corp. Lappo ~I produced water disposal well, which was
beinq operated in violation of UIC regulations.

Waste Analysis
Water samples from observation and residential wells indicated produced
water contamination from the Harris Oil  Corp. Lappo =1 disposal well.
Chloride in the sampled residential wells ranged from background
concentrations to 1,000 ppm.  Monitor wells showed chloride
concentrations ranging from 65 to 19,000 ppm.

Comments
API notes that the UIC program is administered by EPA Region V in
Michigan.

Violation of State Regulations:   Yes

Documentation
References for case cited:   Open file report, Michigan Department of
Natural  Resources. Investigation of Salt-Contaminated Groundwater in
Green Ridge Subdivision, Laketon Township,  conducted by B.  P.  Shirey,
1980.  Appendix includes correspondence  relating to investigation, area
water well arilling logs, Stiff  diagrams and water analysis, site monitor
well drilling logs, and water sample analysis for samples used in the
investigation.

MI 04

    State:  Michigan

    Region:  5

    County/Parish:  Calhoun
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    City/Town:  Perm field

    Test of Proof:  Scientific

Description
Drilling operations at the Burke Unit ?1 caused the temporary chloride
contamination of two domestic water wells and longer lasting chloride
contamination of a third well closer to the drill site.  The operation
was carried out in accordance with State regulations and special site
restrictions required for urban areas, using rig-engines equipped with
mufflers, steel mud tanks for containment of drilling wastes, lining for
earthen pits that may contain salt water, and the placement of a
conductor casing to a depth of 120 feet to isolate the well-from the
freshwater zone beneath the rig.

The drilling location is underlain by permeable surface sand, with
bedrock at a depth of less than 50 feet.  Contamination of the ground
water may have occurred when material flushed from the mud tanks remained
in the lined pit for 13 days before removal.  (The material contained
high levels of chlorides, and liners can leak.)  According to the State
report, this would have allowed sufficient time for contaminants to
migrate into the freshwater aquifer.  A leak from the produced water
storage tank was also reported by the operator to have occurred before
the contamination was detected in the water wells.  One shallow well was
less than 100 feet directly east of the drill pit area and 100 to 150
feet southeast of the produced water leak site.  Chloride concentrations
in this well measured by the Michigan Geological Survey were found to
range from 750 ppm (9/5/75) to 1,325 ppm (5/23/75). By late August, two
of the wells had returned to normal, while the third well still measured
28 times its original background concentration of chloride.

Waste Analysis
Before the drilling operation began, the water well owned by H. Rop
showed chloride concentrations of 27 ppm on 12/5/74.  Five months after
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drilling was coT.p'etea.  the ROD well  showed chloride concentrations of
1,325 ppm on 5,23/75.   Chloride concentrations decreased with time to
750 ppm on 9/5/75.

Comments
API notes that since 1975.  Michigan nas adopted regulations requiring
pits to be lined in most instances.

Violation of State Regulations:  Yes

Documentation
References for case cited.   Open file report,  Michigan Department of
Natural Resources,  Report on Ground-Water Contamination, Sullivan and
Company, J.D. Burke No.  1,  Pennfield  Township, conducted by J. R.
Byerlay, 1976.  Appendix includes correspondence relating to
investigation, area water well drilling logs,  Stiff diagrams and water
analysis, site monitor well drilling  logs,  and water sample analysis for
samples used in the investigation.

KS 01

    State:  Kansas

    Region:  6

    County:  Montgomery

    City/Town:  Not applicable

    Test of Proof:   Administrative and Legal

Description
Temple Oil Company and Wayside Production Company operate a number of oil
production leases in Montgomery County.  The leases were operated with
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illegally maintained saltwater containment  ponds, improperly  abandoned
reserve pits,  unapproved emergency  saltwater pits, and  improperly
abandoned saltwater pits.  Numerous  oil  and saltwater spills  were
recorded during  operation of the  sites.   Documentation of these  incidents
started in  1977  when adjacent landowners began to complain about  soil
pollution,  vegetation kills, fish  kills, and pollution of freshwater
streams due to oil  and saltwater  runoff  from these sites.  The  leases
also contain a large number of abandoned,  unplugged wells, which  may pose
a threat to ground  water.1  Complaints were received by the
Conservation Division, Kansas Department of Health and the Environment
(KDHE), Montgomery  County Sheriff,  and Kansas Fish and Game Commission.
A total of  39 violations on these  leases were documented between  1983  and
1984.

A water sample taken by KDHE from  a  4  1/2-foot test hole between  a
freshwater  pond  and a creek on one  lease showed chloride concentrations
of 65,500 ppm. Water samples taken  from  pits on other leases  showed
chloride concentrations ranging from 5,000  to 82,000 ppm.

The Kansas  Corporation Commission  issued an administrative order  in  1984,
fining Temple and Wayside a total  of $80,000.  Initially, $25,000 was
collected,  and the  operators could  reapply  for licenses to operate  in
Kansas in 36 months if they initiated  adequate corrective measures.    The
case is currently in private litigation. The Commission found that  no
progress had been made toward bringing the  leases into compliance and,
therefore,  reassessed the outstanding  $55,000 penalty.  The Commission
has since sought judicial enforcement  of that penalty in the  District
Court, and  a journal entry has been  signed  and was reviewed by  the
Commission  and is now ready to be  filed  in  District Court.  Additionally,
  *   Comments in the Docket by the Kansas Corporation Commission (Beatrice Stong) pertain to
kS 01.  With regard to the abandoned wells, Kansas Corporation Commission states that these wells
are "...cemented from top to bottom...", they have "...limited resource energy,..." and the static
fluid level these reservoirs could sustain are "...well below the location of any drinking or usable
water
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in a separate lawsuit between the landowners, the lessors, and the
Temples regarding operation of the leases, the landowners were successful
and the leases have reverted back to the landowners.  The new operators
are prevented from operating without Commission authority.

Waste Analysis
Water sampled from a 4 1/2-foot test hole between a freshwater pond and a
creek on the Fowler's lease showed soil  in the unsaturated zone with
chloride concentrations of 65,500 ppm.  Water samples taken from pits on
the owners' leases (the Fowler's and others) showed chloride
concentrations ranging from 5,000 to 82,000 ppm.

Comments
Comments in the Docket by the Kansas Corporation  Commission (Beatrice
Stong) pertain to KS 01.   With regard to the abandoned wells,  Kansas
Corporation Commission states that these wells are "...cemented from top
to bottom...", they have  "...limited resource energy..." and the static
fluid level these reservoirs could sustain are "...well  below the
location of any drinking  or usable water."

Violation of State Regulations:  Yes

Documentation
References for case cited:   The Kansas  Corporation Commission Court Order
describing the evidence and charges against the Temple Oil Co., 5/17/84.

KS 08

    State:  Kansas

    Region:  6

    County/Parish:  Montgomery

    City/Town:  Not Applicable

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    Test of Proof:  Administrative and Legal

Description
On January 31, 1986, the Kansas Department of Health and the Environment
inspected the Reitz lease in Montgomery County, operated by Marvin Harr
of El Dorado, Arkansas.  The lease included an unpermitted emergency pond
containing water that had 56,500 ppm chlorides.  A large seeping area was
observed by KDHE inspectors on the south side of the pond, allowing the
flow of salt water down the slope for about 30 feet.  The company was
notified and was asked to apply for a permit and install a liner because
the pond was constructed of sandy clay and sandstone.  The operator was
directed to immediately empty the pond and backfill  it if a liner was not
installed.  On February 24, the lease was reinspected by KDHE and the
emergency pond was still full and actively seeping.  It appeared that the
lease had been shut down by the operator.  A "pond order" was issued by
KDHE requiring the company to drain and backfill the pond.  On April 29,
the pond was still full and seeping.

Water samples taken from the pit by KDHE showed chloride concentrations
of from 30,500 ppm (4/29/86) to 56,500 ppm  (1/31/86). Seepage from the
pit showed chloride concentrations of 17,500 ppm (2/24/86).   The Kansas
Department of Health and the Environment stated that "...the use of the
pond...has caused or is likely to cause pollution to the soil and the
waters of the State."  An administrative penalty of  $500 was assessed
against the operator, and it was ordered that the pond be drained and
backfilled.

Waste Analysis
Water samples taken from the pit indicated chloride  concentrations
ranging from 30,500 ppm (4/29/86) to 56,500 ppm (1/31/86). Leakage from
the pit showed a chloride concentration of  17,500 ppm (2/24/86).

Comments
None.

Violation of State Regulations:  Yes

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Documentation
References for case cited:  Kansas Department of Health and Environment
Order assessing civil penalty, in the matter of Marvin Harr,  Case No.
86-E-77, 6/10/86.  Pond Order issued by Kansas Department of Health and
Environment, in the matter of Marvin Harr, Case No. 86-PO-008, 3/21/86.

KS 05

    State:  Kansas

    Region:  6

    County/Parish:  Osborne

    City/Town:  Paradise

    Test of Proof:  Administrative and Scientific

Description
Between February 9 and 27, 1986, the Elliott #1 was drilled on the
property of Mr. Lawrence Koelling.  The Hutchinson Salt member, an
underground formation, was penetrated during the drilling of Elliott #1.
The drilling process dissolved between 100 and 200 cubic feet of salt,
which was disposed of in the unlined reserve pit.  The reserve pit lies
200 feet away  from a well used by Mr. Koehling for his ranching
operations.  Within a few weeks of the drilling of the Elliott #1, Mr.
Koelling's nearby well began to pump water containing a saltwater
dril1 ing fluid.

Ground water on the Koehling ranch has been contaminated with high levels
of chlorides allegedly because of leaching of the reserve pit fluids  into
the ground water.  Water samples taken from the Koehling livestock water
well  by the KCC Conservation Division showed a chloride concentration  of
1,650 mg/L.  Background concentrations of chlorides were in the range  of
100 to  150 ppm.   It  is stated in a KCC report, dated November  1986, that
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further movement of the saltwater plume can be anticipated, thus
polluting the Koehling domestic water well and the water well used by a
farmstead over 1 mile downstream from the Koehling ranch.  It is also
stated in this KCC report that other wells drilled in the area using
unlined reserve pits would have similarly affected the ground water.

The KCC now believes the source of ground-water contamination is not the
reserve pit from the Elliott #1.  The KCC has drilled two monitoring
wells, one 10 feet from the edge of the reserve pit location and the
other within 400 feet of the affected water well, between the affected
well and the reserve pit.  The monitoring well drilled 10 feet from the
reserve pit site tested 60 ppm chlorides.  (EPA notes that it is not
known if this monitoring well was located upgradient from the reserve
pit.)  The monitoring well drilled between the affected well  and the
reserve pit tested 750 ppm chlorides.  (EPA notes that the level of
chlorides in this monitoring well is more than twice the level of
chlorides allowed under the EPA drinking water standards).  The case is
still open, pending further investigation.   EPA believes that the
evidence presented to date does not refute the earlier KCC report, which
cited the reserve pit as the source of ground-water contamination, since
the recent KCC report does not suggest an alternative source of
contamination.

Waste Analysis
Water samples from the Koehling livestock water well showed chloride
concentrations of 900 and 950 ppm.  Background concentrations of chloride
would be in the range of 100 to 150 ppm.

Comments
None.

Violation of State Regulations:  No
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Documentation
References for case cited:  Summary Report, Koehling Water Well
Pollution, 22-10-15W, KCC, Conservation Division, Jim Schoof, Chief
Engineer, 11/86.

KS 03

    State:  Kansas

    Region:  6

    County/Parish:  Kingman

    City/Town:  Wichita

    Test  of Proof:  Administrative and Scientific

Description
Mr. Leslie, a private land owner in Kansas, suspected that chloride
contamination of a natural spring occurred as a result of the presence of
an abandoned reserve pit used when Western Drilling Inc. drilled a well
(Leslie  #1) at  the Leslie Farm. Drilling in this area required
penetration of  the Hutchinson Salt member, during which 200 to 400 cubic
feet of  rock salt was dissolved and discharged into the reserve pit.  The
ground in the area consists of highly unconsolidated soils, which would
allow for migration of pollutants into the ground water.  Water at the
top of the Leslie ffl had a conductivity of 5,050 umhos.  Conductivity of
the spring water equaled 7,250 umhos.  As noted by the KCC, "very saline
water" was coming out of the springs.  Conductivity of 2,000 umhos will
damage soil, precluding growth of vegetation.  No fines were levied  in
this case as there were no violations of State rules and regulations.
The Leslies filed suit in civil court and won their case for a total of
Sll.OOO  from the oil and gas operator.
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Waste Analysis
Salt water at the top of the Leslie #1 had conductivity of 5,050 umhos.
Conductivity of spring water was 7,250 umhos.  The KCC noted "very saline
water" coming out of the springs.  It also indicated that conductivity of
2,000 umhos will damage soil, precluding the growth of vegetation.

Comments
API states that KDHE had authority over pits at this time.  The KCC now
requires permits for such pits.

Violation of State Regulations:  No

Documentation
Reference for case cited:   Final Report, Gary Leslie Saltwater Pollution
Problem, Kingman County, KCC Conservation Division, Jim Schoof, Chief
Engineer, 9/86.    Contains  letters, memos,  and analysis pertaining to
the case.

KS 06

    State:  Kansas

    Region:  6

    County/Parish:  Graham

    City/Town:  Mori and

    Test of Proof:  Scientific

Description
On July 12, 1981, the Kansas Department of Health  and  the  Environment
(KDHE) received a complaint  from Albert Richmeier,  a  landowner operating
an irrigation well  in the South Solomon River valley.  His  irrigation
well had encountered salty  water.  An  irrigation well  belonging to an
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adjacent landowner,  L.  M.  Paxson,  had become salty in the fall of 1980.
Oil has been produced in the area  since 1952, and since 1962 secondary
recovery by water flooding has been used.   Upon investigation by the
KDHE, it was discovered that the cause of the pollution was a saltwater
injection well  nearby,  operated by Petro-Lewis.  A casing profile caliper
log was run by an operator-contractor under the direction of KDHE staff,
which revealed numerous holes in the casing of the injection well.  The
producing formation,  the Kansas City-Lansing, requires as much as 800 psi
at the wellhead while injecting fluid to create a profitable enhanced oil
recovery project.  To remediate the contamination, the alluvial  aquifer
was pumped, and the initial  chloride concentration of 6,000 mg/L was
lowered to 600 to 700 mg/L in a year's time.  Chloride contamination in
some areas was lowered from 10,000 mg/L to near background levels.
However, a contamination problem continues in the Paxson well,  which
shows chlorides in the range of 1,100 mg/L even though KDHE, through
pumping, has tried to reduce the concentration.  After attempts at
repair, Petro-Lewis decided to plug the injection well.

Waste Analysis
Richmeier and Paxson wells showed  a chloride concentration at over 6,000
mg/L and 4,700 mg/L,  respectively, in 7/81. As wells were pumped, the
chloride concentration decreased.

Comments
Comments in the Docket by the KCC  (Bill Bryson) pertain to KS 06.  KCC
states that of the affected irrigation wells, one is "...back in service
and the second is approaching near normal  levels as it continues to be
pumped."   API states that Kansas  received primacy for the UIC program in
1984.

Violation of State Regulations:  No

Documentation
References for case cited:  Richmeier Pollution Study,  Kansas Department
of Health and Environment, G. Blackburn and W. G. Bryson, 1983.

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TX 55

    State:  Texas

    Region:  7

    County/Parish:  Harris

    City/Town:  Not Applicable

    Test of Proof:  Administrative and Scientific

Description
In Texas, oil and gas producers operating near the Gulf Coast are
permitted to discharge produced water into surface streams if they are
found to be tidally affected.  Along with the produced water, residual
production chemicals and organic constituents may be discharged,
including lead, zinc, chromium, barium, and water-soluble polycyclic
aromatic hydrocarbons (PAHs).  PAHs are known to accumulate  in sediment,
producing liver and lip tumors in catfish and affecting mixed function
oxidise systems of mammals, rendering a reduced immune response.  In
1984, a study conducted by the U.S. Fish and Wildlife Service of sediment
in Tabb's Bay, which receives discharged produced water as well as
discharges from upstream industry (i.e., discharges from ships in the
Houston Ship Channel), indicated severe degradation of the environment by
PAH contamination.  Sediment was collected from within 100 yards of
several tidal discharge points of oil field produced water.  Analytical
results of these sediments indicated severe degradation of the
environment by PAH contamination.  The study noted that sediments
contained no benthic fauna, and because of wave action, the  contaminants
were continuously resuspended, allowing chronic exposure of  contaminants
to the water column.  It is concluded by the U.S. Fish and Wildlife
Service that shrimp, crabs, oysters, fish, and fish-eating birds in this
location have the potential to be heavily contaminated with  PAHs.  While
these discharges have to be within Texas Water Quality Standards,  these

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standards are for conventional pollutants and do not consider the
water-soluble components of oil that are in produced water such as PAHs.

Waste Analysis
Tabbs Bay (Galveston Bay) sediment analysis showed naphthalenes at
95 ppb, biphenyls at 120 ppb, phenanthrene at 105 ppb, anthracene at
74 ppb, pyrene at 150 ppb, chrysene at 122 ppb, fluoranthenes at 376 ppb,
benzo-pyrene at 195 ppb, and perylene at 261 ppb.

Comments
NPDES permits have been applied for but not issued for these discharges
on the Gulf Coast.  The Texas Railroad Commission (TRC) issues permits
for these discharges.  The TRC disagrees as to the actual source of
damage in this case.

Violation of State Regulations:  No

Documentation
References for case cited:  Letter from U.S. Department of the Interior,
Fish and Wildlife Service, signed by H. Dale Hall, to Railroad Commission
of Texas, discussing degradation of Tabb's Bay because of discharge of
produced water in upstream estuaries; includes lab analysis for
polycyclic aromatic hydrocarbons in Tabb's Bay sediment samples.  Texas
Railroad Commission Proposal for Decision on Petronilla Creek case
documenting that something other than produced water is killing aquatic
organisms in the creek.  (Roy Spears, Texas Parks and Wildlife, did LC50
study on sunfish and sheepshead minnows using produced water and Arkansas
Bay water.  Produced water diluted to proper salinity caused mortality of
50 percent.  (Seawater contains 19,000 ppm chlorides.)

TX 31

    State:  Texas

    Region:  7

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    County/Parish:  Galveston

    City/Town:  Galveston

    Test of Proof:  Scientific

Description
Produced water discharges contain a high ratio of calcium ions to
magnesium ions.  This high ratio of calcium to magnesium has been found
by Texas Parks and Wildlife officials to be lethal to common Atlantic
croaker, even when total salinity levels are within tolerable limits.  In
a bioassay study conducted by Texas Parks and Wildlife, this fish was
exposed to various ratios of calcium to magnesium, and it was found that
in 96-hour LC50 studies, mortality was 50 percent when exposed to
calcium-magnesium ratios of 6:1, the natural ratio being 1:3.  Nearly all
of oil field produced water discharges on file with the Army Corps of
Engineers in Galveston contain ratios exceeding the 6:1 ratio, known to
cause mortality in Atlantic croaker as established by the LC50 test.

Waste Analysis
Analysis is in the form of a table showing calcium-magnesium ratios and
numbers of surviving fish at 24-, 48-, and 96-hour intervals.  At the
natural ratio of 1:3, all fish survived the 96 hour test.  At 7:1, half
the fish died after 48 hours.

Comments
API comments in the Docket pertain to TX 31.  API states that models show
that "...rapid mixing in Bay waters results in no pollution to Bay waters
as a whole from calcium ions or from the calcium/magnesium ratio."

Violation of State Regulations:  No

Documentation
References for case cited:  Toxic Effects of Calcium on the Atlantic
Croaker: An Investigation of One Component of Oil Field Brine, by Kenneth
N. Knudson and Charles E. Belaire, undated.
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TX 29

    State:  Texas

    Region:  7

    County/Parish:  Nueces

    City/Town:  Driscoll

    Test of Proof:  Administrative and Scientific

Description
For over 50 years, oil operators (including Texaco and Amoco) have been
allowed to discharge produced water into Petronilla Creek, a supposedly
tidally influenced creek.  Discharge areas were as much as 20 miles
inland and contained fresh water.  In 1981, the pollution of Petronilla
Creek from discharge of produced water became an issue when studies done
by the T-exas Parks and Wildlife and Texas Department of Water Resources
documented the severe degradation of the water and damage to native fish
and vegetation. All freshwater species of fish and vegetation were dead
because of exposure to toxic constituents in discharge liquid.  Portions
of the creek were black or bright orange in color.  Heavy oil slicks and
oily slime were observable along discharge areas.

Impacts were observed in Baffin Bay, where the creek empties.  Petronilla
Creek is  the only freshwater source for Baffin Bay, which is a nursery
for many fish and shellfish in the Gulf of Mexico.  Sediments in Baffin
Bay show elevated levels of toxic constituents found in Petronilla
Creek.  For 5 years, the Texas Department of Water Resources and Texas
Parks and Wildlife, along with environmental groups, worked to have the
discharges stopped.   In  1981, a hearing was held by the TRC.  The
conclusion of the hearing was that discharge of the produced water plus
disposal of other trash by the public was degrading Petronilla Creek.
The TRC initiated a joint committee (Texas Department of  Water Resources,

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Texas Parks and Wildlife Department, and TRC) to establish the source of
the trash, clean up trash from the creek, and conduct additional
studies.  After this work was completed, a second hearing was held in
1984.  The creek was shown to contain high levels of chromium, barium,
oil, grease, and EPA priority pollutants naphthalene and benzene.  Oil
operators stated that a no dumping order would put them out of business
because oil production in this area is marginal.  In 1986, the TRC
ordered a halt to discharge of produced water into nontidal portions of
Petronilla Creek.

Waste Analysis
A 1984 analysis of stream water  indicated chloride at 40,700 ppm,
chemical oxygen demand at 425 ppm, oil at 18 ppm, sulfates at 350 ppm,
temperature at 120 degrees F., and arsenic at 14 ppm.  Creek sediments
revealed chromium at 9.6 ppm, barium at 1,900 ppm, oil and grease at
10,500 ppm, volatile solids at 48,700 ppm, and zinc at 150 ppm.

Comments
None.

Violation of State Regulations:  No

Documentation
References for case cited:  The  Effects of Brine Water Discharges on
Petronilla Creek, Texas Parks and Wildlife Department, 1981.  Texas
Department of Water Resources interoffice memorandum documenting spills
in  Petronilla Creek from 1980 to 1983.  The  Influence of Oilfield Brine
Water Discharges on Chemical and Biological  Conditions in Petronilla
Creek, by Frank Shipley, Texas Department of Water Resources, 1984.
Letter from Dick Whittington, EPA, to Richard Lowerre, documenting
absence of NPDES permits for discharge to Petronilla Creek.  Final Order
of  TRC, banning discharge of produced water  to Petronilla Creek,
6/23/86.  Numerous letters, articles, legal  documents, on Petronilla
Creek case.
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OK 08

    State:  Oklahoma

    Region:  7

    County/Parish:  Beckham

    City/Town:  Elk City

    Test of Proof:  Legal and Scientific

Description
On November 20, 1981, the Michigan-Wisconsin Pipe Line Company began
drilling an oil and gas well on the property of Ralph and Judy Walker.
Drilling was completed on March 27, 1982.  Unlined reserve pits were used
at the drill site.  After 2 months of drilling, the water well used by
the Walkers became polluted with elevated levels of chloride and barium,
(683 ppm and 1,750 ppb, respectively).  The Walkers were forced to haul-
fresh water from  Elk City for household use. The Walkers filed a
complaint with the Oklahoma Corporation Commission (OCC), and an
investigation was conducted.  The Michigan-Wisconsin Pipe Line Co. was
ordered to remove all drilling mud from the reserve pit.

In the end, the Walkers retained a private attorney and sued
Michigan-Wisconsin for damages sustained because of migration of reserve
pit fluids into the freshwater aquifer from which they drew their
domestic water supply.  The Walkers won their case and received an award
of 550,000.

Waste Analysis
Analysis done on  the Walker water well on March 29, 1982, indicated
chloride at 683 mg/L and barium at 1,750 ug/L.  Analysis prior to
drilling of the oil and gas well showed chlorides at 10 mg/L.
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Comments
API states that the Oklahoma Corporation Commission is in the process of
developing regulations to prevent leaching of salt muds into ground
water.

Violation of State Regulations:  No

Documentation
References for case cited:  Pretrial Order, Ralph Gail Walker and Judy
Walker vs. Michigan-Wisconsin  Pipe Line Company and Big Chief Drilling
Company, U.S. District Court,  Western District of Oklahoma,
5CIV-82-1726-R.  Direct Examination of Stephen G. McLin, Ph. D.  Direct
Examination of Robert Hall.  Direct Examination of Laurence Alatshuler,
M. D.  Lab results from Walker water well.

OK 02

    State:  Oklahoma

    Region:  7

    County/Parish:  McClain

    City/Town:  Still water

    Test of Proof:  Legal and  Scientific

Description
In 1973, Horizon Oil and Gas drilled an oil well on the property of
Dorothy Moore.  As was the common practice, the reserve pit was
dewatered, and the remaining mud was buried on site.  In 1985-86,
problems from the buried reserve pit waste began to appear.  The reserve
pit contents were seeping into a nearby creek and pond.  The surrounding
soil  had very high chloride content as established by Dr. Billy Tucker,
an agronomist and soil scientist. Extensive erosion around the reserve

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pit became evident,  a common problem with high-salinity soil.  Oil slicks
were visible in the  adjacent creek and pond.  An irrigation well on the
property was tested  by Dr.  Tucker and was found to have 3,000 ppm
chlorides; however,  no monitoring wells had been drilled to test the
ground water prior to the drilling of the oil well and background levels
of chlorides were not established.

Dorothy Moore has filed civil  suit against the operator for damages
sustained during the oil  and gas drilling activity.  The case is pending.

Waste Analysis
An extensive analysis of soil  and water samples was performed by Dr.
Billy Tucker.  For soil,  results indicated levels of total  soluble salt
at 1,630 ppm or "...63 times higher than normal and sufficiently high to
reduce yield of even salt tolerant crops."  Exchangeable sodium in soil
was found at 72 percent,  or 47,038 ppm.  For water, total  soluble salt
levels were recorded at 51,810 ppm and chloride at 5,000 ppm.  "Water of
this quality is not  recommended for crop irrigation".

Comments
API comments in Docket pertain to OK 02.  API states that  "...there is no
evidence that there  has been any seepage whatsoever into surface water."
API states that there are no irrigation wells on Mrs.  Moore's farm.
Further, it states that erosion has been occurring for years and is the
"...result of natural conditions coupled with the failure  of Mrs. Moore
to repair terraces to prevent  or limit such erosion."   API  does not
provide supporting documentation.

Violation of State Regulations:  No

Documentation
References for case  cited:   Extensive soil and water analysis results
interpreted by Dr. Billy Tucker, agronomist and soil scientist,
Stillwater, Oklahoma.  Correspondence and conversation with Randall Wood,
private attorney. Stack and Barnes, Oklahoma City, Oklahoma.

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OK 06

    State:  Oklahoma

    Region:  7

    County/Parish:  Noble

    City/Town:  Perry

    Test of Proof:  Administrative, Legal, and Scientific

Description
The Devore ?1, a  saltwater  injection well  located on the property of Verl
and Virginia Hentges, was drilled  in 1947  as an exploratory well.
Shortly afterwards, it was  permitted by the Oklahoma Corporation
Commission (OCC)  as a saltwater  injection  well.  The injection formation,
                                                                 /
the Layton, was known to be capable of accepting 80 barrels per hour at
150 psi.   In 1984, George Kahn acquired the well and the OCC granted an
exception  to Rule 3-305, Operating Requirements for Enhanced Recovery
Injection  and Disposal Wells, and  permitted the well to inject 2,000
barrels per day,at 400 psi.  Later in 1984, it appeared that there was
saltwater migration from the intended injection zone of the Devore #1 to
the surface.2  The Hentges alleged that the migrating salt water
had polluted the ground water used on their ranch.  In addition, they
alleged that the migrating  salt.water was  finding its way to the
surface and polluting Warren Creek, a freshwater stream used by
downstream residents for domestic water.   Salt water discharged to the
surface had contaminated the soil  and had  caused vegetation kills.  A
report by the OCC concluded that "the Devore #1 salt water disposal well
operations are responsible  for the contaminant plume in the adjacent
alluvium and streams."  The OCC required that a workover be done on the
well.   The workover was completed, and the operator continued to dispose
of salt water in the well.  The Hentges then sought private legal
assistance and filed a lawsuit against George Kahn, the operator, for

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$300,000 in actual  damages and $3,000,000 in punitive  damages.   The
lawsuit is pending,  scheduled for trial in October  1987.

Waste Analysis
Analyses done by  OCC and Southwell Laboratory produced similar results.
The OCC results showed  the following: at monitor well  #1,  chlorides at
550 ppm; at well  #3,  chlorides at 113,600 ppm;  at well  #4;  chlorides at
77,900 ppm;  at the tributary of Warren Creek,  chlorides  at 93,000 ppm
and at Warren Creek,  chlorides at 77,550 pprn.

Comments
API states that the operator now believes old abandoned saltwater pits to
be the source of  contamination as the, well now  passes  UIC  tests.
Comments by API in  the  Docket pertain to OK 06.  API  states that
"...tests on the  well  [pressure test and tracer logs]  indicate- the
injection well  is not a source of salt water."  API  has not provided
documentation with  this statement.

Violation of State  Regulations:  No

Documentation
References for  case cited:  Remedial Action Plan for Aquifer Restoration
within Section  #2,  Township 21 North, Range 2 West,  Noble  County,
Oklahoma, by Stephen G. McLin, Ph. D:  Surface  Pollution  at the De Vore
#1 Saltwater Disposal  Site, Oklahoma Corporation Commission, 1986.
District Court  of Noble County, Amended Petition, Verl E.  Hentges and
Virginia L. Hentges vs. George Kahn, ffC-84-110, 7/25/85.   Lab analysis
records of De Vore  well from Oklahoma Corporation Commission'and
Southwell Labs.   Communication with Al'an DeVore, plaintiffs' attorney.-
  o
     Comments by AP! in the Docket pertain to OK 06. API states that "...tests on the well
pressure test and tr.icer logs  indicate the injection well is .not  a source of salt water."  API has
not .provided documentation'with this statement.
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TX 21

    State:  Texas

    Region:  7

    County/Parish:  Lavaca

    City/Town:  Speaks

    Test of Proof:  Administrative and Scientific

Description
On May 16, 1984, Esenjay Petroleum Co. had completed the L.W. Bing #1
well at a depth of 9,900 feet and had hired T&L Lease Service to clean up
the drill site.  During cleanup, the reserve pit, containing
high-chromium drilling mud, was breached by T&L Lease Service, allowing
drilling mud to flow  into a tributary of Hardy Sandy Creek.  The drilling
mud was up to 24 inches deep along the north bank of Hardy Sandy.
Drilling mud had been pushed into the trees and brush adjacent to the
drill site.  The spill was reported to the operator and the Texas
Railroad Commission.  The TRC ordered cleanup, which began on May 20.

Because of high levels of chromium contained in the drilling mud,
warnings were issued  by the Lavaca-Navidad River Authority to residents
and landowners downstream of the spill as it represented a possible
health hazard to cattle watering from the affected streams.  The River
Authority also advised against eating the fish from the affected waters
because of the high chromium levels in the drilling mud.

Waste Analysis
Total chromium from samples from the streambed was recorded at 30.8 to
47.6 ppm and pH at 8.0 to 9.6.
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Comments
None.

Violation of State Regulations:  Yes

Documentation
References for case cited:  Memorandum from Lavaca-Navidad River
Authority documenting events of Esenjay reserve pit discharge, 6/27/84,
signed by J. Henry Neason.  Letter to TRC from Lavaca-Navidad River
Authority thanking the TRC for taking action on the Esenjay case, "Thanks
to your enforcement actions, we are slowly educating the operators in
this area on how to work within the law."  Agreed Order, Texas Railroad
Commission, £2-83,043, 11/12/84, fining Esenjay $10,000 for deliberate
discharge of drilling muds.  Letter from U. S. EPA to TRC inviting TRC to
attend meeting with Esenjay Petroleum to discuss discharge of reserve pit
into Hardy Sandy Creek, 6/1/84, signed by Thomas G. Giesberg.  Texas
Railroad Commission spill report on Esenjay operations, 5/18/84.

TX 22

    State:  Texas

    Region:  7

    County/Parish:  Live Oak

    City/Town:  Beeville

    Test of Proof:  Administrative and Scientific

Description
On September 15, 1983, TXO Production Company began drilling its Dunn
Lease Well No. B2 in Live Oak County.  On October 5, 1983, employees of
TXO broke the reserve pit levee and began spreading drilling mud downhill
from the site, towards the fence line of property owned by the Dunns.  By

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October 9, the mud had entered the draw that flows into two stock tanks
on the Dunn property.  On November 24 and 25, dead fish were observed in
the stock tank.  On December  17, Texas Parks and Wildlife documented over
700 fish killed in the stock  tanks on the Dunn property.  Despite
repeated requests by the Dunns, TXO did not clean up the drilling mud and
polluted water from the Dunn  property.

Lab results from TRC and Texas Department of Health indicated that the
spilled drilling mud was high  in levels of arsenic, barium, chromium,
lead, sulfat.es, other metals,  and chlorides.  In February 1984, the TRC
stated that the stock tanks contained unacceptable levels of nitrogen,
barium, chromium, and iron, and that the chemicals present were
detrimental to both fish and  livestock.  (The Dunns water their cows at
this same stock tank.)  After further analysis, the TRC issued a
memorandum stating that the fish had died because of a cold front moving
through the area, in spite of the fact that the soil, sediment, and water
in and around the stock pond  contained harmful substances.  Ultimately;
TXO was fined $1,000 by the TRC, and TXO paid the Dunns a cash settlement
for damages sustained.

Waste Analysis
Soil analysis revealed arsenic at 4.8 ppm, barium at 7,800 ppm, chromium
at 17 ppm, lead at 18 ppm, and mercury at 0.04 ppm.  Tank bottom analysis
showed arsenic at 0.87 ppm, chromium at 12 ppm, and zinc at 23 ppm.
Analysis performed on dead fish by the Texas Veterinary Medical
Diagnostic Laboratory System  stated that the fish died of oxygen
depletion.

Comments
API states that the fish died from oxygen depletion of the water.  The
Texas Railroad Commission believes that the fish died from exposure to
cold weather.

Violation of State Regulations:  Yes
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Documentation
References for case cited:  Texas Railroad Commission Motion to Expand
Scope of Hearing, ^2-82,919, 6/29/84.  Texas Railroad Commission Agreed
Order, *2-82,919, 12/17/84.  Analysis by Texas Veterinary Medical
Diagnostic Laboratory System on dead fish in Dunn stock tank.  Water and
soil sample analysis from the Texas Railroad Commission. Water and soil
samples from the Texas Department of Health.  Letter from Wendell Taylor,
TRC, to Jerry Mullican, TRC, stating that the fish kill was the result of
cold weather. 7/13/84.  Miscellaneous letters and memos.

WY 03

    State:  Wyoming

    Region:  8

    County/Parish:  Campbell

    City/Town:  Rozet

    Test of Proof:  Administrative and Scientific

Description
Altex Oil Company and its predecessors have operated an oil production
field for several decades South of Rozet, Wyoming.  (Altex purchased the
property in 1984.)  An access road runs through the area, which,
according to Wyoming Department of Environmental Quality (WDEQ), for
years was used as a drainage for produced water from the oil field
operations.

In August of 1985, an official with WDEQ collected soil samples from the
road ditch to ascertain chloride levels because it had been observed that
trees and vegetation along the road were dead or dying.  WDEQ analysis of
the samples showed chloride levels as high as 130,000 ppm.  The road was
chained off in October of 1985 to preclude any further illegal disposal
of produced water.
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Waste Analysis
Analysis done on soil along the ditch on the side of the roadbed and at
the discharge point  indicated chlorides ranging from 5,100 to
130,000 ppm.

Comments
Comments in the Docket from the Wyoming Oil and Gas Conservation
Commission  (WOGCC)  (Mr. Don  Basko) pertain to WY 03.  WOGCC states that
"...not all water from Altex Oil producing wells..." caused the
contamination problem.  Further, WOGCC states that "Illegal dumping, as
well as a flow line  break the previous winter, had caused a high level of
chloride in the soil which probably contributed to the sagebrush and
conttonwood trees dying."

Violation of State  Regulations:  Yes

Documentation
References  for case  cited:  Analysis of site by the Wyoming Department of
Environmental Quality  (WDEQ), Quality Division Laboratory, File #ej52179,
12/6/85.    Photographs of dead  and"dying cottonwood trees and sagebrush
in and around site.  Conversation with WDEQ officials.

WY 01

    State:  Wyoming

    Region:  8

    County/Parish:   Laramie

    City/Town:  Cheyenne

    Test of Proof:   Administrative, Legal, and Scientific
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Description
In early October 1985,  Cities Service Oil Company had completed drilling
at a site northeast of Cheyenne on Highway 85.  The drilling contractor,
Z&S Oil Construction Company, was suspected of illegally disposing of
drilling fluids at a site over a mile away on the Pole Creek Ranch.  An
employee of Z&S had given an anonymous tip to a County detective.  A
stake-out of the illegal operation was made with law enforcement and WDEQ
personnel.  Stake-out personnel took samples and photos of the reserve
pit and the dump site.   During the stake-out, vacuum trucks were
witnessed draining reserve pit contents down a slope and into a small
pond on the Pole Creek Ranch.  After sufficient evidence had been
gathered, arrests were made by Wyoming law enforcement personnel, and the
trucks were impounded.   The State sued Z&S and won a total  of $10,000.

Waste Analysis
Analysis done on samples from the reserve pit and from the dump site
showed that reserve pit mud contained aluminum at 20,591 ppm, arsenic at
4.06 ppm, barium at 144 ppm, chromium at 16.5 ppm, copper at 8.2 ppm,
iron at 19,520 ppm, lead at 84 ppm, manganese at 108 ppm, and zinc at
129 ppm.

Comments
None.

Violation of State Regulations:  Yes

Documentation
References for case cited:  WDEQ memorandum documenting chronology of
events leading to arrest of Z&S employees and owners.  Lab analysis of
reserve pit mud and effluent, and mud and effluent found at dump site.
Consent decree from District Court of First Judicial District, Laramie
County, Wyoming, docket #108-493, The People of the State of Wyoming vs.
Z&S Construction Company.  Photographs of vacuum trucks dumping at Pole
Creek Ranch.
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WY 05
    State:  Wyoming

    Region:  8

    County:  Big Horn

    City/Town:  Byron

    Test of Proof:  Administrative, Legal, and Scientific

Description
During the week of April 8,  1985,  field personnel at the Byron/Garland
field operated by Marathon Oil Company were cleaning up a storage yard
used to store drums of oil field chemicals.  Drums containing discarded
production chemicals were punctured by the field employees and allowed to
drain into a ditch adjacent  to the yard.  Approximately 200 drums
containing 420 gallons of fluid were drained into the trench.  The
chemicals were demulsifiers, reverse demulsifiers, scale and corrosion
inhibitors, and surfactants.  Broken transformers containing PCBs were
leaking into soil in a nearby area.  Upon discovery of the condition of
the yard, Wyoming Department of Environmental Quality ordered Marathon to
begin cleanup procedures.  At the  request of the WDEQ, ground-water
monitors were installed, and monitoring of nearby Arnoldus Lake was
begun.  The State filed a civil suit against Marathon and won a $5,000
fine and $3,006 in expenses  for lab work.

Waste Analysis
Analysis was done on volatile and  semi volatile compounds in the soil.
Compounds found include methylene  chloride, 390 mg/kg; acetone,
250 mg/kg; vinyl acetate, 720 mg/kg; ethylbenzene, 220 mg/kg;  xylenes,
1,300 mg/kg; naphthalene, 1,500 mg/kg; 2/ methylnaphthalene, 3,800 mg/kg;
phenanthrene, 80 mg/kg; toluene, 205 mg/kg; and pyrene, 50 mg/kg.
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Comments
API states that the operator, thinking the drums had to be empty before
transport offsite, turned the drums upside down and drained 420 gallons
of chemicals into the trench.

Violation of State Regulations:  Yes

Documentation
References for case cited:  Summary of Byron-Garland case by Marathon
employee J. C. Fowler.  List of drums, contents, and field uses.
Cross-section of disposal trench area.  Several sets of lab analyses.
Map of Garland field disposal yard.  Newspaper articles on incident.
District court consent decree, The People of the State of Wyoming vs.
Marathon Oil Company. ?108-87.

WY 07

    State:  Wyoming

    Region:  8

    County/Parish:  Fremont

    City/Town:  Lander

    Test of Proof:  Scientific

Description
A study was undertaken by the Columbia National Fisheries Research
Laboratory of the U. S. Fish and Wildlife Service to determine the effect
of continuous discharge of low-level oil  effluent into a stream and the
resulting effect on the aquatic community in the stream.  The discharges
to the stream contained 5.6 mg/L total hydrocarbons.  Total hydrocarbons
in the receiving sediment were 979 mg/L to 2,515 mg/L.  During the study,
samples were taken upstream and downstream from the discharge.  Species

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diversity and community structure were studied.  Water analysis was done
on upstream and downstream samples.  The study found a decrease in
species diversity of the macrobenthos community (fish) downstream from
the discharge, further characterized by total elimination of some species
and drastic alteration of community structure.  The study found that the
downstream community was characterized by only one dominant species,
while the upstream community was dominated by three species.  Total
hydrocarbon concentrations in water and sediment increased 40 to 55 fold
downstream from the discharge of produced water.  The authors of the
study stated that "...based on our findings, the fisheries and aquatic
resources would be protected if discharge of oil into fresh water were
regulated to prevent concentrations in receiving streams/ water and
sediment that would alter structure of macrobenthos communities."

Waste Analysis
Analysis indicated the following results: total oil in the effluent was
5.6 mg/L, well below the permitted level of 10 mg/L;  total oil in the
sediments was 2,515 ppm, at the station furthest downstream;  receiving
stream concentrations were 46 to 85 ppb;  naphthalenes, cadmium,
chromium, copper, lead, and zinc were detected at elevated levels in the
stream and sediment; and species diversity indexes were characteristic of
moderately polluted habitats.

Comments
None.

Violation of State Regulations:  No

Documentation
References for case cited:  Petroleum Hydrocarbon Concentrations in a
Salmonid Stream Contaminated by Oil Field Discharge Water and Effects on
the Macrobenthos Community, by D.  F. Woodward and R. G. Riley, U.S.
Department of the Interior, Fish and Wildlife Service, Columbia National
Fisheries Research Laboratory, Jackson, Wyoming, 1980; submitted to
Transactions of the American Fisheries Society.
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NM 02

    State:  New Mexico

    Region:  9

    County/Parish:  San Juan

    City/Town:  Shiprock

    Test of Proof:  Scientific

Description
In July 1985, a study was undertaken in the Duncan Oil Field in the San
Juan Basin by faculty members in the Department of Chemistry at New
Mexico State University, to analyze the potential for unlined produced
water pit contents, including hydrocarbons and aromatic hydrocarbons, to
migrate into the ground water.  The oil field is situated in a flood
plain of the San Juan River.  The site chosen for investigation by the
study group was similar to at least 1500 other nearby production sites in
the flood plain.  The study group dug test pits around the disposal pit
on the chosen site.  These test pits were placed abovegradient and
downgradient of the disposal pit, at 25-and 50-meter  intervals.  A total
of nine test pits were dug to a depth of 2 meters, and soil and
ground-water samples were obtained from each test pit.  Upon analysis,
the study group found volatile aromatic hydrocarbons were present  in both
the soil  and water samples of test pits downgradient, demonstrating
migration of unlined produced water pit contents into the ground water.

Environmental impact was summarized by the study group as contamination
of shallow ground water with produced water pit contents due to leaching
from an unlined produced water disposal pit.  Benzene was found in
concentrations of 0.10 ppb.  New Mexico Water Quality Control Commission
standard  is  10 ppb.  Concentrations of ethylbenzene,  xylenes, and  larger
hydrocarbon molecules were found.  No contamination was found in test
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pits placed abovegradient from the disposal pit.  Physical signs of
contamination were also present, downgradient from the disposal pit,
including black, oily staining of sands above the water table  and black,
oily film on the water itself.  Hydrocarbon odor was also present.

Waste Analysis
Extensive and complex analysis of water and soil samples for volatile
organic compounds indicated estimated concentrations of benzene, 0.1 ppb,
and toluene, 0.3 ppm in test pits, as well as benzene at 21 ppb and
160 ppb in waste pit water and produced water, respectively.   The
analysis also contains proof of extensive mobility of these compounds in
the ground water and surrounding sandy soil.

Comments
None.

Violation of State Regulations:  No

Documentation
References for  case cited:  Hydrocarbons and Aromatic Hydrocarbons in
Groundwater Surrounding an Earthen Waste Disposal Pit for Produced Water
in the Duncan Oil Field of New Mexico, by G. A. Eiceman, J.T.  McConnon,
Masud Zaman, Chris Shuey, and Douglas Earp, 9/16/85.  Polycyclic Aromatic
Hydrocarbons in Soil at Groundwater Level Near an Earthen Pit  for
Produced Water  in the Duncan Oil Field, by B. Davani, K. Lindley, and
G.A. Eiceman, 1986.  New Mexico Oil Conservation Commission hearing to
define vulnerable aquifers, comments on the hearing record by  Intervenor
Chris Shuey, Case No. 8224.

NM 05

    State:  New Mexico

    Region:  9

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    County:  San Juan

    City/Town:  Farmington

    Test of Proof:  Administrative and Scientific

Description
Lee Acres  "modified" landfill (meaning refuse is covered weekly instead
of daily as is done in a "sanitary" landfill) is located 4.5 miles
east-southeast of Farmington, New Mexico. It is owned by the U.S. Bureau
of Land Management  (BLM).  The landfill is approximately 60 acres in size
and includes four unlined liquid-waste lagoons or pits, three of which
were actively used.  Since 1981,  a variety of liquid wastes associated
with the oil and gas industry have been disposed of in the lagoons.  The
predominant portion of liquid wastes disposed of in the lagoons was
produced water, which is known to contain aromatic volatile organic
compounds  (VOCs).   According to the New Mexico Department of Health and
Environment, Environmental Improvement Division, 75 to 90 percent of the
•produced water disposed of in the lagoons originated from Federal and
Indian oil and gas  leases managed by BLM.  Water produced on these leases
was hauled from as  far away as Nageezi, which is 40 miles from the Lee
Acres site.  Disposal of produced water in these unlined pits was,
according  to New Mexico State officials, in direct violation of BLM's
rule NTL-2B, which  prohibits, without prior approval, disposal of
produced waters into unlined pits, originating on Federally owned
leases.  The Department of the Interior states that disposal in the
lagoons was "...specifically authorized by the State of New Mexico for
disposal of produced water."  The State of New Mexico states that "There
is no truth whatsoever to the assertion that the landfill lagoons were
specifically authorized by the State of New Mexico for disposal of
produced water."  Use of the pits ceased on 4/19/85; 8,800 cubic yards of
waste were disposed of prior to closure.

New Mexico's Environmental Improvement Division (NMEID) asserts that
leachate from the unlined waste lagoons that contain oil and gas wastes

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has contributed to the contamination of several water wells in the Lee
Acres housing subdivision located downgradient from the lagoons and
downgradient from a refinery operated by Giant Refining Company, located
nearby.  NMEID has on file a soil gas survey that documents extensive
contamination with chlorinated VOCs at the landfill site.  High levels of
sodium, chlorides, lead, chromium, benzene, toluene, xylenes,
chloroethane, and trichloroethylene were found in the waste lagoons.  An
electromagnetic terrain survey of the Lee Acres landfill site and
surrounding area, conducted by NMEID, located a plume of contaminated
ground water extending from the  landfill. This plume runs into a plume of
contamination known to exist, emanating from the refinery.  The plumes
have become mixed and are the source of contamination of the ground water
serving the Lee Acres housing subdivision.  One domestic well was sampled
extensively by NMEID and was found to contain extremely high levels of
chlorides and elevated levels of chlorinated VOCs, including
trichloroethane.  (Department of the Interior (DOI) states that it is
unaware of any violations of New Mexico ground-water standards involved
in this case.  New Mexico states that State ground-water standards for
chloride, total dissolved solids, benzene, xylenes, 1,1-dichloroethane,
and ethylene dichloride have been violated as a result of the plume of
contamination.  In addition, the EPA Safe Drinking Water Standard for
trichloroethylene has been violated.)   New Mexico State officials state
that "The landfill appears to be the principal source of chloride, total
dissolved solids and most chlorinated VOCs, while the refinery appears to
be the principal source of aromatic VOCs and ethylene dichloride."

During the period after disposal operations ceased and before the site
was closed, access to the lagoons was essentially unrestricted.  While
NMEID believes that it is possible that non-oil and gas wastes illegally
disposed of during this period may have, contributed to the documented
contamination, the primary source of ground-water contamination appears
to be from oil and gas wastes.

The State has ordered BLM to provide public water to residents affected
by the contamination, develop a ground-water monitoring system, and

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investigate types of drilling,  drilling procedures, and well construction
methods that generated the waste accepted by the landfill.  BLM submitted
a motion-to-stay the order so as to include Giant Refining Company and El
Paso Natural Gas in cleanup operations.  The motion was denied.  The case
went into litigation.  According to State officials, "The State of New
Mexico agreed to dismiss its lawsuit only after the Bureau of Land
Management agreed to conduct a  somewhat detailed hydrogeologic
investigation in a reasonably expeditious period of time.  The lawsuit
was not dismissed because of lack of evidence of contamination emanating
from the landfill."  While it is true that past refinery operations also
have contaminated ground water,  it should be noted that the refinery
company, unlike the Bureau of Land Management,  has completed an extensive
hydrogeologic investigation and  has already implemented both containment
and cleanup measures.

Waste Analysis
Extensive water analysis has been done on the pits and the contaminated
water wells. High levels of sodium, chlorides,  lead, chromium, benzene,
toluene, xylenes, chloroethane,  and trichloroethylene were found in the
pits. High levels of chlorides  and VOCs were found in a downgradient
monitoring well. Complete analysis is in the file.  One domestic well was
sampled extensively and found to contain extremely high levels of
chloride and elevated levels of  chlorinated VOC's,  including
trichloroethane.  Except for benzene, the contaminants found in this well
(Reynold's well) are not characteristic of the  contaminats generated by
the nearby refinery.

Comments
In a letter dated 8/20/87, Giant Refining Company states that "Benzene,
toluene, and xylenes are naturally occurring compounds in crude oil, and
are consequently in high concentrations in the  produced water associated
with that crude oil.  The only  gasoline additive used by Giant that has
been found in the water of a residential well is OCA [ethylene
dichloride], which has also been found in the landfill plume."  Giant
also notes that the refinery leaks in the last  2 years resulted in less

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than 30,000 gallons of diesel being released rather than the 100,000
gallons stated by Michael Poling in his letter to EPA of 8/11/87.

Comments in the Docket from BLM and the State of New Mexico pertain to
NM 05.  BLM states that the refinery upgradient from the subdivision is
responsible for the contamination because of their "...extremely sloppy
housekeeping practices..." which resulted in the loss of "...hundreds of
                                            Si-
thousands of gallons of refined product through leaks in their
underground piping system."   The Department of the Interior states that
"There is, in fact, mounting evidence that the landfill and lagoons may
have contributed little to the residential well contamination in the
subdivisions."  DOI states "...we strongly recommend that this case be
deleted from the Damage Cases [Report to Congress]."  New Mexico states
that "EID [Environmental  Improvement Division] strongly believes that the
Lee Acres Landfill has caused serious ground water contamination and is
well worth inclusion in the Oil and Gas Damage Cases chapter of your
[EPA] Report to Congress  on Oil, Gas and Geothermal Wastes."

Violation of State Regulations:  No

Documentation
References for case cited:  State of New Mexico Administrative Order No.
1005; contains water analysis for open pits, monitor wells, and impacted
domestic wells.  Motion-to-stay Order No. 1005. Denial of motion to stay.
Newspaper articles.  Southwest Research and Information Center, Response
to Hearing before Water Quality Control Commission, 12/2/86.  Letter to
Dan Derkics, EPA from Michael Poling, Department of the Interior,
refuting Lee Acres damage case, 8/11/87.  Letter to Dan Derkics, EPA from
Michael J. Burkhart, NMEID, refuting DOI letter of 8/11/87, dated
8/18/87.  Letter to Dan Derkics, EPA, from Giant Refining Company,
8/20/87.

NM 01

    State:  New Mexico

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    Region:   9

    County/Parish:   Lea

    City/Town:  Caprock

    Test of Proof:   Legal  and Scientific

Description
A saltwater injection well,  the BO-3,  operated by Texaco,  is used for
produced water disposal for the Moore-Devonian oil  field in southeastern
New Mexico.   Injection occurs at about 10,000 feet.   The Ogallala
aquifer, overlying the oil  production  formation,  is  the sole source of
potable ground water in much of southeastern New Mexico.  Dr.  Daniel B.
Stephens, Associate Professor of Hydrology at the New Mexico Institute of
Mining and Technology, concluded that  injection well  BO-3  has  contributed
to a saltwater plume of contamination  in the Ogallala aquifer.   The plume
is nearly 1 mile long and  contains chloride concentrations of  up to
26,000 ppm.

A local rancher sustained  damage to crops after irrigating with water
contaminated by this saltwater plume.   In 1973, an irrigation  well was
completed satisfactorily on the ranch  of Mr. Paul Hamilton, and, in 1977,
the well began producing water with chlorides of 1,200 ppm.
Mr. Hamilton's crops were  severely damaged, resulting in heavy economic
losses, and his farm property was foreclosed.  There is no evidence of
crop damage from irrigation prior to 1977.  Mr. Hamilton initiated a
private law suit against Texaco for damages sustained to his ranch.
Texaco argued that the saltwater plume was the result of leachate of
produced water from unlined produced water disposal  pits,  now banned in
the area.  Dr. Stephens proved that if old pits in the vicinity,
previously used for saltwater disposal, had caused the contamination,
high chloride levels would have been detected in the irrigation well
prior to 1977.  Dr. Stephens also demonstrated that the BO-3 injection
well had leaked some 20 million gallons of produced water into the fresh
                                    C  78

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ground water, causing chloride contamination of the Ogallala aquifer from
which Mr. Hamilton drew his irrigation water.  Based on this evidence, a
jury awarded Mr. Hamilton a cash settlement from Texaco for damages
sustained both by the leaking injection well and by the abandoned
disposal pits.  The well has had workovers and additional pressure tests
since 1978.  The well is still in operation, in compliance with DIG
regulations.

Waste Analysis
A hydrogeologic configuration illustrated a plume of contamination, and
water analysis showed chlorides as high as 25,000 ppm in the aquifer
around the BO-3 injection well.  Analysis of the irrigation well
indicated chlorides at  1,200 ppm.

Comments
None.

Violation of State Regulations:  No

Documentation
References for case cited:  Oil-Field Brine Contamination - A Case Study,
Lea Co. New Mexico, from Selected Papers on Water Quality and Pollution
in New Mexico - 1984; proceedings of a symposium, New Mexico Bureau of
Mines and Resources.

CA 21

    State:  California

    Region:  10

    County/Parish:  Kern

    City/Town:  Taft

    Test of Proof:  Scientific

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Description
For the purposes of this study conducted by Bean/Logan Consulting
Geologists, ground water in the study area was categorized according to
geotype and compared to produced water in sumps that came from production
zones.  Research was conducted on sumps in Cymric Valley, McKittrick
Valley, Midway Valley, Elk Hills, Buena Vista Hills, and Buena Vista
Valley production fields.  While this recent research was not
investigating ground-water damages per se, the study suggests obvious
potential for damages relating to the ground water.   The hydrogeologic
analysis prepared for the California State Water Resources Control Board
concludes that about 570,000 tons of salt from produced water were
deposited in 1981 and that a total of 14.8 million tons have been
deposited since 1900.  The California Water Resources Board suspects that
a portion of the salt has percolated into the ground water and has
degraded it.  In addition to suspected degradation of ground water,
officers of the California Department of Fish and Game often find birds
and animals entrapped in the oily deposits in the affected ephemeral
streams.  Exposure to the oily deposits often proves to be fatal  to these
birds and animals.

Waste Analysis
See: CA 8.   Ground water in the study area has been  categorized according
to geotypes and compared to produced waters in sumps that came from
production zones.   Research found that sumps in Cymric,  McKittrick, and
Midway Valleys, Elk Hills and Buena Vista Hills, and Buena Vista Valley
fields were responsible in part for ground-water brine. Table 22 in the
Westside Groundwater Study, which analyzed "feed water" (brines)  to
sumps, indicated the following results: chlorides at 729 to 10,726 ppm,
conductivity of 4,500 to 28,260 uhos; total dissolved solids at 3,258 to
20,488 ppm, and boron at 5.2 to 19.2 ppm.

Comments
API states that the California Regional Water Quality Board and EPA are
presently deciding whether to promulgate additional  permit requirements
under the Clean Water Act and NPDES.
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Violation of State Regulations:  No

Documentation
References for case cited:  Lower Westside Water Quality Investigation
Kern County and Lower Westside Water Quality Investigation Kern County:
Supplementary Report, Bean/Logan Consulting Geologists, 11/83; prepared
for Califormia State Water Resources Control Board.  Westside Groundwater
Study, Michael R. Rector, Inc., 11/83; prepared for Western Oil and Gas
Association.

CA 08

    State:  California

    Region:  10

    County/Parish:  Kern

    City/Town:  Bakersfield

    Test of Proof:  Scientific

Description
Produced water from the Crocker Canyon area flows downstream to where it
is diverted into Valley Waste Disposal's large unlined evaporation/
percolation sumps for oil recovery  (cooperatively operated by local oil
producers).  In one instance, discovery by California Fish and Game
officials of a significant spill was made over a month after it
occurred.  According to the California State Water Quality Board, the
incident was probably caused by heavy rainfall, as a consequence of which
the volume of rain and waste exceeded the containment capacity of the
disposal facility.  The sumps became eroded, allowing oily waste to flow
down the valley and into a wildlife habitat occupied by several
endangered species including blunt-nosed leopard lizards, San Joaquin kit
foxes, and giant kangaroo rats.
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According to the State's report, there were 116 known wildlife losses
including 11 giant kangaroo rats.  The count of dead animals was
estimated at only 20 percent of the actual number of animals destroyed
because of the delay in finding the spill, allowing poisoned animals to
leave the area before dying.  Vegetation was covered with waste
throughout the spill area.   The California Department of Fish and Game
does not believe this to be an isolated incident.   The California Water
Resources Control Board, during its investigation of the incident, noted
"...deposits of older accumulated oil, thereby indicating that the same
channel had been used for wastewater disposal  conveyance in the past
prior to the recent discharge.  Cleanup activities conducted later
revealed that buildup of older oil  was significant."  The companies
implicated in this incident were fined $100,000 and were required to
clean up the area.  The companies denied responsibility for the
discharge.

Waste Analysis
A description by a Department of Fish and Game official based on a visual
inspection indicated thai the waste was produced water and oil  from the
facilities listed above.

Comments
None.

Violation of State Regulations:  Yes

Documentation
References for case cited:    Report of Oil Spill in Buena Vista Valley.
by Mike Glinzak, California Division of Oil  and Gas (DOG), 3/6/86; map of
site and photos accompany the report.  Letters to Sun Exploration and
Production Co. from DOG, 3/12 and 3/31/86.  Newspaper articles in
Bakersfield Californian, 3/8/86, 3/11/86, and  undated.   California Water
Quality Control Board,  Administrative Civil  Liability Complaint #ACL-016,
8/8/86.  California Water Quality Control Board, internal memoranda,
Smith to Pfister concprning cleanup of site, 5/27/86;  Smith to Nevins

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concerning description of damage and investigation, including map,
8/12/86. California Department of Fish and Game, Dead Endangered Species
in a California Oil,Spill, by Capt. E.A Simons and Lt. M. Akin, undated.
Fact Sheets:  Buena Vista Creek Oil Spill, Kern County, 3/7/8.6, and
Mammals Occurring on Elk Hills and Buena Vista Hills, undated. Letter
from Lt. Akin to EPA contractor, 2/24/87.

AK 06

    State:  Alaska

    Region:  11

    County/Parish:  Prudhoe Bay

    City/Town:  Not Applicable

    Test of Proof:  Scientific
                      rtff:0
Description
In 1983, a study of the effects of reserve pit discharges on water
quality and the macroinvertebrate community of tundra ponds was
undertaken by the U. S. Fish and Wildlife Service in the Prudhoe Bay oil
production area of the North Slope.  Discharge to the tundra ponds is a
common disposal method for reserve pit fluid in this area.  The study
shows a clear difference in water quality and biological measures among
reserve pits, ponds receiving discharges from reserve pits (receiving
ponds), distant ponds affected by discharges through surface water flow,
and control ponds not affected by discharges.  Ponds directly receiving
discharges had significantly greater concentrations of chromium, arsenic,
cadmium, nickel, and barium than did control ponds, and distant ponds
showed significantly higher levels of chromium than did control ponds.
Chromium levels in reserve pits and in ponds adjacent to drill sites may
have exceeded EPA chronic toxicity criteria for protection of aquatic
life.
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Waste Analysis
Analysis was done on all parameters for all pits and ponds;.  Statistical
tests were performed on data to show the statistical significance of the
results.  Conductivity was as high as 9,500 umhos/cm; lead, 0.093 mg/L;
copper, 0.029mg/L;  zinc, 0.33 mg/L; cadmium, 0.0009mg/L; chromium,
0.21 mg/L; arsenic, 0.05 mg/L; nickel, 0.17 mg/L; aluminum, 97 mg/L; and
barium, 4.4 mg/L.  Results indicated statistically sifgnificant
differences in biological measures and water quality between pits,
receiving ponds, and distant ponds.

Comments
None.

Violation of State Regulations:  No

Documentation
References for case cited:  The Effects of Prudhoe Bay Reserve Pit Fluids
on the Water Quality and Macroinvertebrates of Tundra Ponds (Draft
report), by Robin L. West and Elaine Snyder-Conn, Fairbanks Fish and
Wildlife Enhancement Office, U.S.  Fish and Wildlife Service, Fairbanks,
Alaska, 10/8/86.

AK 07

    State:  Alaska

    Region:  11

    County/Parish:  Prudhoe Bay

    City/Town:  Not Applicable

    Test of Proof:  Scientific
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Description
In the summer of 1985, the U. S. Fish and Wildlife Service developed a
field method to evaluate toxicity of reserve pit fluids discharged into
tundra wetlands at Prudhoe Bay, Alaska.  Results of the study document
acute toxicity effects of reserve pit fluids on Daphnia.  Acute toxicity
in Daphnia was observed after 96 hours of exposure to liquid in five
reserve pits.  Daphnia exposed to liquid in receiving ponds also had
significantly higher death/immobilization than did Daphnia exposed to
liquid in control ponds after 96 hours.  At Drill Site 1, after 96 hours,
100 percent of the Daphnia introduced to the reserve pit had been
immobilized or were dead, as compared to a control pond that showed less
than 5 percent immobilized or dead after 96 hours.  At Drill Site 12,
80 percent of the Daphnia exposed to the reserve pit liquid were dead or
immobilized after 96 hours and less than 1 percent of the Daphnia exposed
to the control pond were dead or immobilized.

Waste Analysis
The results of the bioassays described above constitute the only analyses
available on environmental damage for this case.
                          **

Comments
API comments in the Docket pertain to AK 07.  API discusses the relevance
of the Daphnia study to the damage cases.

Violation of State Regulations:  No

Documentation
References for case cited:  An  In Situ Acute Toxicity Test with Daphnia:
A Promising Screening Tool for Field Biologists? by Elaine Snyder-Conn,
U.S. Fish and Wildlife Service, Fish and Wildlife Enhancement, Fairbanks,
Alaska, 1985.
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AK 08

    State:  Alaska

    Region:  11

    County/Parish:  Prudhoe Bay

    City/Town:  Not Applicable

    Test of Proof:  Scientific

Description
In June 1985, five drill sites and three control sites were chosen for
studying the effects of drilling fluids and their discharge on fish and
waterfowl  habitat on the North Slope of Alaska.  Bioaccumulation analysis
was done on fish  tissue using water samples collected from the reserve
pits.  Fecundity  and growth were reduced in daphnids exposed for 42 days
to liquid  composed of 2.5 percent and 25 percent drilling fluid from the
                Kk.
selected drill sites.  Bioaccumulation of barium, titanium, iron, copper,
and molybdenum was documented in fish exposed to drilling fluids for as
little as  96 hours.

Waste Analysis
Highest readings  found in water samples were: conductivity,
4,200 umhos/cm; bromine, 54 mg/L; aluminum, 0.853 mg/L; arsenic, 0.177
mg/L; boron, 2.33 mg/L; cadmium, 0.005 mg/L; chromium, 0.493 mg/L;
copper, 0.095 mg/L; iron, 1.180 mg/L; magnesium, 14.9 mg/L; manganese,
0.808 mg/L; phosphorous, 0.226 mg/L;  lead, 0.06 mg/L; and titanium,
0.139 mg/L.  Sediment analysis highs were:  aluminum, 21,000 mg/kg;
arsenic,  138 mg/kg; barium, 7,380 mg/kg; cadmium, 6.0 mg/kg; cobalt,
17 mg/kg;  chromium, 792 mg/kg;  copper, 1,780 mg/kg;  manganese,
1,930 mg/kg; lead, 1,300 mg/kg; and titanium, 37 mg/kg.
                                    C-86

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Comments
None.

Violation of State Regulations:  No

Documentation
References for case cited:  Effects of Oil Drilling Fluids and Their
Discharge on Fish and Waterfowl Habitat in Alaska, U.S. Fish and Wildlife
Service, Columbia National Fishery Research Laboratory, Jackson Field
Station, Jackson, Wyoming, February 1986.

AK 12

    State:  Alaska

    Region:  11

    County/Parish:  National Petroleum Reserve-Alaska

    City/Town:  Not Applicable

    Test of Proof:  Scientific

Description
The Awuna Test Well No. 1, which is 11,200 feet deep, is in the National
                                                                        n'
Petroleum Reserve in Alaska (NPRA) and was a site selected for cleanup of
the NPRA by the U.S. Geological Survey in 1984.  The site is in the
northern foothills of the Brooks Range.  The well was spud on February 29,
1980, and operations were completed on April 20, 1981.  A side of the
reserve pit berm washed out into the tundra during spring breakup,
allowing for reserve pit fluid to flow onto the tundra.  As documented by
the U.S. Geological Survey (USGS) cleanup team, high levels of chromium,
oil,  and grease have leached into the soil downgradient from the pit.
Chromium was found at 2.2 to 3.0 mg/kg dry weight.  The high levels of
oil and grease may be from the use of Arctic Pack (85 percent diesel

                                    C-87

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fuel) at the well  over the winter of 1980.  The cleanup team noted that
the downslope soils were discolored and putrefied, particularly in the
upper layers.  The pad is located in a runoff area allowing for erosion
of pad and pit into surrounding tundra.  A vegetation kill area caused by
reserve pit fluid exposure is approximately equal to half an acre.  Areas
of the drill pad may remain barren for many years because of contamination
of soil with salt and hydrocarbons. The well site is in a caribou calving
area.

Waste Analysis
Analysis done on reserve pit mud, fluid,  and soil around the pad and pits
indicated mud with a pH of 8.1, chlorides at 10,300 ppm, chemical  oxygen
demand at 140,000, iron at 2,900 ppm,  oil and grease at 7,560 ppm, and
chromium at 230 ppm.  Soil 50 feet from the pit showed a pH of 6.8,
chlorides at 86.2 ppm, chromium at 3.0 ppm, and oil  and grease at
10,000 ppm.

Comments
API states that exploratory reserve pits  must now be closed 1 year after
cessation of drilling operations.  EPA notes that it is important  to
distinguish between exploratory and production reserve pits.   Production
reserve pits are permanent structures  that remain open as long as  the
well or group of wells is producing.

Violation of State Regulations:  No

Documentation
References for case cited:  Final Wellsite Cleanup on National Petroleum
Reserve - Alaska,  USGS, July 1986.

AK 10

    State:  Alaska

    Region:  11

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    County/Parish:  Prudhoe Bay

    City/Town:  Not Applicable

    Test of Proof:  Administrative and Scientific

Description
North Slope Salvage, Inc. (NSSI) operated a salvage business in Prudhoe
Bay during 1982 and 1983.  During this time, NSSI accepted delivery of
various discarded materials from oil production companies on the North
Slope, including more than 14,000 fifty-five gallon drums, 900 of which
were full or held more than residual amounts of oil and chemicals used in
the development and recovery of oil.  The drums were stockpiled and
managed by NSSI in a manner that allowed the discharge of hazardous
substances.  While the NSSI site may have stored chemicals and wastes
from other operations that supported oil and gas exploration and
production (e.g., vehicle maintenance materials), such storage would have
constituted a very small percentage of NSSI's total inventory.

The situation was discovered by the Alaska Department of Environmental
Conservation (ADEC) in June 1983.  At this time, the State of Alaska
requested Federal enforcement, but Federal action was never taken. An
inadequate cleanup effort was mounted by NSSI after confrontation by
ADEC.  To preclude further discharges of hazardous substances, ARCO and
Sohio paid for the cleanup because they were the primary contributors to
the site.  Cleanup was completed on August 5, 1983, after 58,000 gallons
of chemicals and water were recovered.  It is unknown how much of the
hazardous substances were carried into the tundra.  The discharge
consisted of oil and a variety of organic substances known to be toxic,
carcinogenic, or mutagenic, or suspected of being carcinogenic or
mutagenic.

Waste Analysis
Samples were taken from many locations at the site, both directly from
drums and from soil and water.  GC/MS was done on each sample to define

                                    C-89

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organic compounds present.   Analysis indicated pH at 13.8, benzene at
20.0 ug/L, xylene at 67.0 ug/L, and toluene at 190 ug/L.  Other results
are in the file.

Comments
Alaska Department of Environmental Conservation (ADEC) states that this
case "...is an example of how the oil  industry inappropriately considered
the limits of the exemption [under RCRA Section 3001]."

Violation of State Regulations:  No

Documentation
References for case cited:   Report on  the Occurrence, Discovery, and
Cleanup of an Oil and Hazardous Substances Discharge at Lease Tract 57,
Prudhoe Bay, Alaska, by Jeff Mach - ADEC, 1984.  Letter to Dan Derkics,
EPA, from Stan Hungerford,  ADEC, 8/4/87.

AK 03

    State:  Alaska

    Region:  11

    County/Parish:  Kenai Peninsula

    City/town:  Sterling

    Test of Proof:  Administrative and Scientific

Description
Operators of the Sterling Special Waste site have had a long history of
substandard monitoring, having failed  during 1977 and 1978 to carry out
any well sampling and otherwise having performed only irregular
sampling.  This was in violation of ADEC permit requirements to perform
quarterly reports of water quality samples from the monitoring wells.  An

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internal DEC memo (L.G. Elphic to R.T. Williams, 2/25/76) noted "...we
must not forget...that this is the State's first sanctioned hazardous
waste site and as such must receive close observation during its initial
operating period."

A permit for the site was reissued by ADEC in 1979 despite knowledge by
ADEC of lack of effective ground-water monitoring.  In July of 1980, ADEC
Engineer R. Williams visited the site and filed a report noting that the
"...operation appears completely out of control."  Monitoring well
samples were analyzed by ADEC at this time and found to be in excess of
drinking water standards for iron, lead, cadmium, copper, zinc, arsenic,
phenol, and oil and grease.  One private water well in the vacinity
showed 0.4 ppb 1,1,1-trichloroethane.  The Sterling School well showed
2.1 ug/L mercury.  Subsequent tests show mercury concentration below
detection limits--0.001 mg/kg.  Both contamination incidents are alleged
to be caused by the Sterling Special Waste Site.  Allegations are
unconfirmed by the ADEC.

Waste Analysis
Typical mud contents include barium, chromium, cadmium, phenols, diesel
oils, etc.  (See AK 02.)  Specific analysis of the contents of the
Sterling Site showed the following: ethlybenzene, 0.6 mg/L; toluene,
5.6 mg/L; iron, 184 mg/L; lead, 0.88 mg/L; zinc, 28 mg/L; cadmium,
0.08 mg/L; and copper, 2.3 mg/L.
                           a
Comments
The term "hazardous waste site" as used in this memo does not refer to a
"RCRA Subtitle C hazardous waste site."

Violation of State Regulations:  Yes

Documentation
References for case cited:  Dames and Moore well monitoring report,
showing elevated metals referenced above, October 1976.  Dowling Rice &
Associates monitoring results, 1/15/80, and Mar Enterprises monitoring
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results,  September 1980,  provided by Walt Pederson, showing elevated
levels of metals,  oil,  and grease in ground water.   Detailed letter from
Eric Meyers to Glen Aikens,  Deputy Commissioner, ADEC, recounting permit
history of site and failure to conduct proper monitoring, 1/22/82.
Testimony and transcripts from Walt Pederson on public forums complaining
about damage to drinking  water and mismanagement of site.  Transcripts of
waste logs of site from 9/1/79 to 8/20/84,  indicating only 264,436 bbl of
muds received, during a period that should  have generated much more
waste.  Letter from Howard Keiser to Union  Oil, 12/7/81,  indicating that
"...drilling mud is being disposed of by methods other than at the
Sterling Special Waste Site and by methods  that could possibly cause
contamination of the ground water."

AK 01

    State:  Alaska

    Region:  11

    County/Parish:  Kenai Peninsula

    City/Town:  Soldatna

    Test of Proof:  Administrative, Legal,  and Scientific

Description
This case involves a 45-acre gravel pit on  Poppy Lane on  the Kenai
Peninsula used since the  1970s for disposal of wastes associated with gas
development.  The gravel  pit contains barrels of unidentified wastes,
drilling muds, gas condensate, gas condensate-contaminated peat,
abandoned equipment, and  soil contaminated  with diesel and chemicals.
The property belongs to Union Oil Co. (UNOCAL), which bought it around
1968.  Dumping of wastes  in this area is illegal; reports of last
observed dumping were in  October 1985, as witnessed by residents  in the
area.
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In this case, there has been demonstrated contamination of adjacent water
wells with organic compounds related to gas condensate (ADEC laboratory
reports from October 1986 and earlier).  Alleged health effects on
residents of neighboring properties include nausea, diarrhea, rashes, and
elevated levels of metals (chromium, copper) in the blood of two
residents.  Property values have been effectively reduced to zero for
residential resale.  A fire on the site on July 8, 1981, was attributed
to combustion of petroleum-related products, and the fire department was
unable to extinguish it.  The fire was allegedly set by people illegally
disposing of wastes in the pit.

Fumes from organic liquids are noticeable in the breathing zone onsite.
UNOCAL has been directed on several occasions to remove gas condensate in
wastes from the site.  Since June 19, 1972, disposal of wastes regulated
as solid wastes has been illegal at this site. The case has been actively
under review by the State since 1981.

Waste Analysis
A sample contained a series of compounds identified through gas
chromatography as gas condensate.  Onsite test wells have shown elevated
levels of arsenic and other metals.  Analysis indicated exceedences of
EPA Drinking Water Standards for chromium, 0.17 mg/L; iron, 82 mg/L; and
manganese, 1.5 mg/L.

Comments
None.

Violation of State Regulations:  Yes

Documentation
References for case cited:  Photos showing illegal dumping in progress.
Field investigations.  State of Alaska Individual Fire Report on
"petroleum dump," 7/12/81.  File memo on site visit by Howard Keiser,
ADEC Environmental Field Officer, in response to a complaint by State
Forestry Officer, 7/21/81.  Memo from Howard Keiser to Bob Martin on his

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objections to granting a permit to Union Oil for use of site as disposal
site on basis of impairment of wildlife resources, 7/28/83.  Letter, ADEC
to Union Oil, objecting to lack of cleanup of site despite notification
by ADEC on 10/3/84.  Analytical reports by ADEC indicating gas condensate
contamination on site, 8/14/84.  EPA Potential Hazardous Waste Site
Identification,  indicating continued dumping as of 8/10/85.  Citizens'
complaint records.  Blood test indicating elevated chromium for
neighboring resident Jessica Black, 1/16/85.  Letter to Mike Lucky of
ADEC from Union Oil confirming cleanup steps, 2/12/85.  Memo by Carl
Reller, ADEC ecologist, indicating presence of significant toxics  on
site, 8/14/85.  Minutes of Waste Disposal Commission meeting, 2/10/85.
ADEC analytic reports indicating gas condensate at site, 10/10/85.
Letters from four different real estate firms in area confirming
inability to sell residential  property in Poppy Lane area.  Letter from
Bill Lamoreaux, ADEC, to J. Black and R.  Sizemore referencing high
selenium/chromium in the ground water in the area.  Various miscellaneous
technical documents.  EPA Potential Hazardous Waste Site Preliminary
Assessment, 2/12/87.

KS 14

    State:  Kansas

    Region:  6

    County/Parish:  Sedgwick

    City/Town:  Witchita

    Test of Proof:  Legal

Description
In 1961, Gulf and its predecessors began secondary recovery operations in
the East Gladys Unit in Sedgwick County,  Kansas.  During secondary
recovery, water is pumped into a target formation at high pressure,

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enhancing oil production.  This pumping of water pressurizes the
formation, which can at times result in brines being forced up to the
surface through unplugged or improperly plugged abandoned wells.  When
Gulf began their secondary recovery in this area, it was with the
knowledge that a number of abandoned wells existed and could lead to
escape of salt water into fresh ground water.

Gerald Blood alleged that three improperly plugged wells in proximity to
the Gladys unit were the source of fresh ground-water contamination on
his property.  Mr. Blood runs a peach orchard in the area.  Apparently
native brine had migrated from the nearby abandoned wells into the fresh
ground water from which Mr. Blood draws water for domestic and irrigation
purposes.  Contamination of irrigation wells was first noted by Mr. Blood
when, in 1970, one of his truck gardens was killed by irrigation with
salty water.  Brine migration contaminated two more irrigation wells in
the mid-1970s.  By 1980, brine had contaminated the irrigation wells used
to irrigate a whole section of Mr. Blood's land. By this time, adjacent
landowners also had contaminated wells.  Mr. Blood lost a number of p'each
trees as a result of the contamination of his irrigation well; he also
lost the use of his domestic well.

The Bloods sued Gulf Oil in civil court for damages sustained by their
farm from chloride contamination of their irrigation and residential
wells.  The Bloods won their case and were awarded an undisclosed amount
of money.

Waste Analysis
Water samples from wells owned by Mr. Blood showed chloride
concentrations of 977 and 765 ppm in 1962. In 1970, the two wells showed
chloride concentrations of 1,570 and 1,730 ppm.

Comments
API states that damage in this case was brought about by "old injection
practices".
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Violation of State Regulations:  No

Documentation
References for case cited:  U.S. District Court for the district of
Kansas, Memorandum and Order, Blood vs. Gulf; Response to Defendants'
Statement of Uncontroverted Facts; and Memorandum in Opposition to Motion
for Summary Judgment. Means Laboratories, Inc., water sample results.
Department of Health, District Office #14, water samples results.
Extensive miscellaneous memoranda, letters, analysis.

TX 11

    State:  Texas

    Region:  7

    County/Parish:  Runnels

    City/Town:  Miles

    Test of Proof:  Administrative and Scientific

Description
In West Texas, thousands of oil and gas wells have been drilled over the
last  several decades, many of which were never properly plugged.  There
exists in the subsurface of this area a geologic formation known as the
Coleman Junction, which contains extremely salty native brine and
possesses natural artesian properties.  Since this formation is
relatively shallow, most oil and gas wells penetrate it.  If an abandoned
well  is not properly plugged, the brine contained in the Coleman Junction
is under enough natural pressure to rise through the improperly plugged
well  and to the surface.

According to scientific data developed over several years, and presented
by Ralph Hoelscher,  the ground water in and around San Angelo, Texas,  has

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been severely degraded by this seepage of native brine, and much of the
agricultural land has absorbed enough salt as to be nonproductive.  This
situation creates a hardship for farmers in the area.  The Texas Railroad
Commission states that soil and ground water are contaminated with
chlorides because of terracing and fertilizing of the land.  According to
Mr. Hoelscher, a long-time farmer in the area, little or no fertilizer is
used in local agriculture.

Waste Analysis
Analysis of Ralph Hoelscher's domestic water well indicated sodium at
334 ppm, calcium at 359 ppm, strontium at 3.4 ppm, sulfate at 191 ppm,
chloride at 980 ppm, nitrate at 229 ppm, and total dissolved solids of
2,479 ppm.  Soil analysis on a portion of the Hoelscher farm revealed
chloride at 10,000 ppm, sodium at 6,440 ppm, magnesium at 1,302 ppm, and
calcium at 15,400 ppm.

Comments
None.

Violation of State Regulations:  Yes

Documentation
References for case cited:  Water analysis of Ralph Hoelscher's domestic
well.  Soil Salinity Analysis, Texas Agricultural Extension Service - The
Texas A&M University System, Soil Testing Laboratory, Lubbock, Texas
79401.  Photographs.  Conversation with Wayne Parrel!, San Angelo Health
Department. Conversation with Ralph Hoelscher, resident and farmer.

TX 15

    State:  Texas

    Region:  7

    County/Parish:  Tom Green

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    City/Town:   San Angelo

    Test of Proof:   Scientific

Description
In the 1950s, oil was discovered in what is known as the Yankee Canyon
Field, Texas, producing from the Canyon Sand at about 4,000 feet. In
1958, the field was converted to the water flood secondary recovery
process.  More than 50 wells were drilled in this field with only 12 to
15 of the wells producing  while the balance of the old wells remain
unplugged and abandoned.  One well  is located on a farm owned by
J.K. Roberts and is about  200 yards from his 70-foot deep domestic water
well.  Chlorides in his well have climbed from 148 ppm in 1940 to
3,080 ppm in 1970.   Mr. Hoelscher believes that the unplugged abandoned
well 200 yards from Mr. Roberts' water well is allowing migration of salt
water into the freshwater  aquifer.   Responding to pressure from the local
media and from Mr.  Hoelscher, the Texas Railroad Commission performed
remedial work on a number  of wells  in the field in the 1980s.

Waste Analysis
Roberts' water well showed a chloride concentration of 148 ppm on
11/11/40, 3,080 ppm on 5/22/70, and 3,120 ppm on 4/29/84.

Comments
None.

Violation of State Regulations:  No

Documentation
References for case cited:  Letter from J.K. Roberts of 259 Robin Hood
Trail, San Angelo,  Texas 76901, to U.S. Army Engineer District, Major
C. A. Allen, explaining the water well contamination; enclosed with
letter are sampling results from the water well.  SW Laboratories,
sampling reports from 6/8/70. Letter from E.G. Long, Texas Water Quality
Board, to L.D.  Gayer, attorney for Mr. Roberts, explaining that case will

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be forwarded to the Texas Railroad Commission.  Letter and sampling
report from F.B. Conselman, consulting geologist to W. Marschall,
explaining sample results and recommendations.

LA 65

    State:  Louisiana

    Region:  4

    County/Parish:  Concorida

    City/Town:  Ferriday

    Test of Proof:  Legal and Scientific

Description
Crow Farms, Inc., the operator of the Angelina Plantation in Louisiana,
initiated a $7 million civil suit against operators of active and
abandoned oil test wells, oil production wells, and an injection well,
for allegedly causing progressive loss of agricultural revenue because of
native brine contamination of ground water used to irrigate 1.7 square
miles of rice, soybeans, and rye.  Analysis of the site by private
technical consultants concluded that it will take 27 years to restore the
soil and a longer period to restore the aquifer.

At least seven wells have allegedly affected the ground water in the
area, including two active oil production wells, both operated by Smith,
Wentworth and Coquina, and five abandoned oil test wells drilled by
Hughes & New Oil Co. An extensive study conducted by Ground-Water
Management,. Inc., concluded that Crow Farms, Inc., used irrigation wells
contaminated by brine water from the oil-producing formation.  Crow
Farms, Inc., engaged Donald 0. Whittemore of the Kansas Geological Survey
to chemically "fingerprint" the wastes and confirm that the brines in the
irrigation water originated in the oil-producing formation.  This brine

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traveled up unplugged or improperly plugged wells or down the annul us of
producing wells, leaking into the freshwater aquifer used for irrigation,
thereby contaminating the aquifer with chloride levels beyond the
tolerance levels of the crops.  Records of the case state, "Surface
casings may not have been properly cemented into the Tertiary clays
underlying the alluvial freshwater aquifer.  If these casings were not
properly cemented, brine could percolate up the outside of these casings
to the freshwater aquifer at an oil or gas well test location where
improper abandonment procedures occurred.   Any brine in contact with
steel casings will rapidly corrode through the steel wall thickness
gaining communication with the original bore hole."

Crow Farms has spent in excess of $250,000 in identifying the source of
ground-water degradation.  The case is pending.

Waste Analysis
Contaminated irrigation wells were compared to nearby uncontaminated
wells over a 5-year period.  Test wells were also drilled for
comparison.  Chlorides in contaminated wells ranged from 341  to
3,200 mg/L.  Background chloride levels registered between 30 and
100 mg/L in the area. Conductivity was found to average 3.6 umhos for
contaminated wells and 0.81 /mhos for background wells. The
sodium-adsorption ratio (SAR) tests showed an average of 44.6 for
contaminated wells and 7 for background wells.   Resistivity testing of
the irrigation aquifer found high brine concentration levels  in areas
around wells suspected of being a contamination pathway to the aquifer.

Comments
Comments in the Docket from Louisiana's Office of Conservation pertain to
LA 65.  The Office of Conservation states  that "...the technical evidence
that has been gathered and is being presented by Angelina is  currently
being refuted by technical evidence that was gathered on behalf of the
defendant oil companies."  One defendant oil company hypothesizes that
"...Bayon Cocodine was the source of the contamination based  on a review
of data presented by Angelina at the hearing."  Another defendant oil

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company states that "...salt water was present, as an occurrence of
nature in the base of the Mississippi River Alluvial  Aquifer....Excessive
pumpage could result in upcoming, bringing this salt  water to the
surface."

Violation of State Regulations:  No

Documentation
References for case cited:  Brine Contamination of Angelina Plantation,
Concordia Parish, Louisiana by Groundwater Management, Inc.;  includes
extensive tables, testing, maps, figures, 8/25/86.  Geochemical
Identification of the Salt Water Source Affecting Ground Water at
Angelina Plantation, Concordia Parish, Louisiana, by  D. 0. Whittemore,
4/86.  Calculated Chloride Distribution and Calculated Plume, Soil
Testing Engineers, Inc., 1986.

NM 03

    State:  New Mexico

    Region:  9

    County/Parish:  San Juan

    City/Town:  Flora Vista

    Test of Proof:  Administrative and Scientific

Description
The Flora Vista Water Users Association, Flora Vista, New Mexico,
operates a community water system that serves 1,500 residents and small
businesses.  The Association began operation of the system in 1983  with
two wells, each capable of delivering 60 to 70 gallons per minute.   In
1980, Manana Gas, Inc., drilled the Mary Wheeler No.  1-E, and began
producing natural gas and oil on a production site less than 300 feet

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from one of the Flora Vista water wells.  In 1983, one Flora Vista water
supply well became contaminated with oil and grease, allegedly by the
Manana Gas well, and was taken out of service.  After extensive testing
and investigation, the New Mexico Oil Conservation Division concluded
that the Manana Gas well was the source of oil and grease contamination
of the Flora Vista water well.   The Conservation Division investigation
included water analysis on affected water wells and on five monitoring
wells as well as pumping tests to ascertain the source of the
contamination.  Although the gas well lies downgradient from the water
well, it was demonstrated that pumping of the water well  drew the oil and
grease upgradient, thus contaminating the water well.   Water now has to
be purchased from the town of Aztec and piped to Flora Vista.  There is,
no indication in reports that the production well  responsible for this
contamination has been shut down or reworked to prevent further
contamination of ground water.  The State asserts that very recent work
done at the site has determined the source of contamination to be a
dehydrator located near the production well.

Waste Analysis
Water analysis was done on water wells affected as well as on five
monitor wells.  Analysis shows hydrocarbon contamination  of ground water;
methane was found at 1,200 times the ambient levels.  Pumping tests were
also done to ascertain the source of pollution.  Although the gas well
lies downgradient from the water well, it was demonstrated that pumping
of the water well drew the oil and grease upgradient, thus contaminating
the water well.

Comments
Comments in the Docket by the Governor of New Mexico pertain to NM 03.
The Governor states that the case incorrectly cites the gas well as the
source of hydrocarbon contamination and comments that another OGC report
specifically eliminated the gas well because of "...fully cemented
surface casing extending to a depth of over 220 feet."  The New Mexico
Oil and Gas Commission is still investigating the source of
contamination.
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Violation of State Regulations:  No

Documentation
References for case cited:  Final Report On Flora Vista Contamination
Study, October 1986, prepared by David G. Boyer, New Mexico Oil
Conservation Division.   Water analysis results of the Flora Vista Well
field area.

NN 04

    State:  New Mexico

    Region:  9

    County:  Lea

    City/Town:  Hobbs

    Test of Proof:  Administrative and Scientific

Description
Lea County, New Mexico, has been an area of major hydrocarbon production
for a number of decades.  Oil field contamination of freshwater sources
became apparent as early as the 1950s.  Contamination of the freshwater
aquifer has resulted from surface waste pit seepage and seepage from
production and injection well casings.  Leakage of oil from oil
production well casings has been so great in some areas as to allow
ranchers to produce oil from the top of the Ogallala aquifer using
windmill pumps attached to contaminated water wells. Approximately
400,000 barrels of oil have been pumped off the top of the Ogallala
aquifer to date, although production is decreasing because of repairs of
large leaks in oil production wells.  Over 120 domestic water wells in
the area have been so extensively contaminated with oil and brine as to
preclude further use of the wells for domestic or irrigation purposes.
Many residents have been using bottled water for a decade or more as a
result of the contamination.

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Waste Analysis
Water analysis performed on numerous Hobbs private water wells showed the
following high levels of contaminants: chloride, 1,947 mg/L; total
dissolved solids, 3,742 mg/L; and benzene, 0.004 mg/L.

Comments
None.

Violation of State Regulations:  No

Documentation
References for case cited:  Sampling data from residential wells in
Ogallala aquifer in Lea County, N.M.  Report:  Organic Water Contaminants
in New Mexico, by Dennis McQuillan, 1984.  Windmills in the Oil Field, by
Jolly Schram, circa 1965.

AK 09

    State:  Alaska

    Region:  11

    County/Parish:  Storkersen Point

    City/Town:  Not Applicable

    Test of Proof:  Scientific

Description
From 1971 to 1975, a study was done for the Department of the  Interior by
individuals from Iowa State University concerning water birds, their
wetland resources, and the development of oil at Storkersen Point on the
North Slope of Alaska. The area is classified as an arctic wetland.
Contained in the study area was a capped oil well (owner of well not
mentioned).  Adjacent to the capped oil well was a pond that had been

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severely polluted during the drilling of this well.  Damage is summarized
in the study as follows:

"The results of severe oil pollution are indicated by the destruction of
all  invertebrate and plant life in the contaminated pond at the
Storkersen Point well; the basin is useless to water birds for food, and
the contaminated sediments contain pollutants which may spread to
adjacent wetlands.  Petroleum compounds in bottom sediments break down
slowly, especially in cold climates, and oil-loaded sediments can be
lethal to important and abundant midge larvae, and small shrimp-like
crustaceans.  Repopulation of waters over polluted sediments by
free-swimming invertebrates is unlikely because most aquatic
invertebrates will be subjected to contact with toxic sediments on the
bottom of wetlands during the egg or overwintering stage of their life
cycle.  Unfortunately, human-induced change may create permanent damage
before we can study, assess, and predict the complications.  First order
damage resulting from oil development will be direct effects of oil
pollution on vegetation and wetland systems.  Oil spills almost anywhere
in this area where slopes are gradual and drainage patterns indefinite,
could result in the deposition of oil in many basins during the spring
thaw when melt water flows over the impermeable tundra surface.  Any
major reduction of food organisms through degradation of preferred
habitats by industrial activity will be detrimental to local aquatic bird
populations."

Waste Analysis
Not Available.

Comments
None.

Violation of State Regulations:  No
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Documentation
References for case cited:  Water Birds and Their Wetland Resources  in
        o
Relation to Oil Development at, Strokersen Point, Alaska, United States
Department of the Interior, Fish and Ui'tdlife Service, Resource
Publication 129.  1977.
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