DALLAS, TEXAS

           CHAPTER 2


      Introduction	1
             Sources  of Information	2
             Limitations	3
             Organization of This Section	3
      Drilling-Related Wastes	5
             Waste Characterization	5
                   Drilling Fluids (Muds)	5
                   Cuttings	6
                   Waste Chemicals	7
                   Fracturing  and Acidizing Fluids	7
                         Completion and Workover Fluid Wastes	14
                   Rigwash  and Other  Miscellaneous Wastes	15
             Onsite Waste Management Methods	15
                   Reserve Pits	16
                         Description	16
                         Environmental Performance	18
                                Advantages	19
                                Disadvantages	19
                         Regulatory Issues	20
                                Design, Construction, and Performance
                                Requirements	20
                                Closure and Reclamation	22
                   Annular Disposal of Pumpable Wastes	22
                         Description	22
                         Environmental Performance	23
                                Advantages	24
                                Disadvantages	24
                         Regulatory Issues	25
                   Reserve Pit Wastes Solidification	26
                         Description	26
                         Environmental Performance	26
                                Advantages	26
                                Disadvantages	27
                         Regulatory Issues	27
                                Implementation Requirements	27
                   Treatment and Discharge of Liquid Wastes to Land or
                   Surface Water	28
                         Description	28
                         Environmental Performance	29
                                Advantages	29
                                Disadvantages	30
                         Regulatory Issues	30

                          Restrictions on Chloride Levels and Other
                          Conventional Pollutants	30
                          Discharge of Heavy Metals and Other
                          Potentially Toxic Materials	33
             Closed Treatment  Systems	34
                    Description	34
                    Environmental Performance	35
                          Advantages	35
                          Disadvantages	35
                    Regulatory Issues	36
       Offsite Waste Management Methods	36
             Centralized  Disposal Pits	36
                    Description	36
                    Environmental Performance	37
                          Advantages	38
                          Disadvantages	38
                    Regulatory Issues	39
                          Design and Performance Issues for
                          Commercial Facilities	39
                          Post  closure  issues	41
             Centralized Treatment Facilities	41
                    Description	41
                    Environmental Performance	42
                          Advantages	43
                          Disadvantages	43
                    Regulatory Issues	43
             Commercial Landfarming	44
                    Description	44
                    Environmental Performance	45
                          Advantages	45
                          Disadvantages	46
                    Regulatory Issues	46
                          Availability	46
                          Reuse of Byproduct Materials Generated By
                          Landfarming	48
             Reconditioning and Reuse of Drilling Media	48
                    Description	48
                    Environmental Performance	49
                          Advantages	50
                          Disadvantages	50
                    Regulatory Issues	50
Production-Related Wastes	50
       Waste Characterization	50
             Produced Waters	50
             Low Volume Production Wastes	51
       Onsite Management Methods	51
             Subsurface Injection	52
                    Description	52

                   Environmental Performance	57
                          Advantages	58
                          Disadvantages	58
                   Regulatory Issues	59
                          Design, Construction, Operation, and Testing.... 61
                          Proximity to Other Wells and to Protected
                          Aquifers	62
                          Annular  Disposal	62
             Evaporation and Percolation  Pits	63
                   Description	63
                   Environmental Performance	63
                          Advantages	63
                          Disadvantages	63
                   Regulatory Issues	64
                          Availability	64
             Discharge of Produced Waters to Surface Water Bodies	66
                   Description	66
                   Environmental Performance	66
                          Advantages	66
                          Disadvantages	66
                   Regulatory Issues	67
                          Federal Effluent Limitation Guideline	67
             Other Production-Related Pits	69
                   Description	69
                   Environmental  Issues	70
                          Advantages	70
                          Disadvantages	70
                   Regulatory Issues	70
       Offsite Management Methods	71
             Road or  Land  Application	71
                   Description	71
                   Environmental Performance	71
                          Advantages	71
                          Disadvantages	71
                   Regulatory Issues	71
Well Closure and Post-Closure Issues	71
       Waste Characterization	71
       Onsite  Measures	72
             Well Plugging and Abandonment Procedures	72
                   Description	72
                   Environmental Performance	73
                          Advantages	73
                          Disadvantages	73
                   Regulatory Issues	73
                          Implementation Provisions	73
                          Temporary Closures	74
                          Trust  Funds	74


Table 1: States with Major Oil Production Used As
        Primary  References In This Study	4
Table 2: Characterization of Oil and Gas Drilling Fluids	8

Figure 1:  Annular Disposal of Waste Drilling Fluids	25
Figure 2:  Brine Disposal Well Design	56
Figure 3:  Annular Disposal of Production Waters	57
Figure 4:  Pollution of Fresh Water Aquifer Through Abandoned Wells	58


       Managing wastes produced by the oil and gas industry is a complex, large-scale
problem.  By the estimates gathered for this report, in 1985 over 2.*f4 billion barrels of
muds and 9 billion barrels of produced waters (brines) were disposed of in the 33 States
that have significant exploration, development, or production activity.  In that same year
there were 834,831 active oil and gas wells, of which about 70 percent (about 580,000)
were small-scale stripper operations.

       The purpose of this section is to review available waste management technologies
employed for wastes at all phases of the exploration-development-production cycle of the
onshore oil and gas industry.  To accomplish this, it is convenient to divide wastes into two
broad categories.  The first includes drilling muds, well-bore cuttings,  and chemical
additives related to the drilling and well completion process. These tend to be managed
together, and may be in the form of either liquids or sludges. The second broad category
includes all wastes associated with oil and gas production.  Produced water is the major
waste stream here; it is by  far the highest volume  waste  associated with oil and gas
production. Other production-related wastes include relatively small volume wastes such as
bacteriocides, fungicides, corrosion inhibitors, and other additives used to ensure efficient
production, wastes from oil/gas/water separators and other onsite processing  facilities,
production tank bottoms, scrubber bottoms, and chemicals used as packer fluids to rework
wells already in production.

       In addition to looking at these two general waste categories, it is important to view
waste management in relation to the sequence of operations that occur in the life cycle of a
typical well.  The chronology involves  both drilling and production—the two phases
mentioned above—but it also can include "post-closure" events, such  as leakage of brines
from wells following shut-in or improper abandonment, or migration of wastes from
closed reserve pits. These are discussed in this chapter as a separate waste management

       Section 8002(m) of Rc.ftR' requires EPA to consider both current and alternative
technologies in carrying out the present study.  Unfortunately, crisp distinctions are almost
impossible to make because of the wide variation in practices among States and among
different types of operations.  Furthermore, waste management technology in this field is
technically fairly  simple—at least for the major high-volume streams, there are no
significant newly-invented technologies in the research and development stage that fall
within the unusual definition of "innovative" or "emerging."  Virtually every waste
management practice that exists can be considered current in  one specific situation or
another; practices that are routine in  one location may be considered innovative or
alternative elsewhere (if they are applicable at all).  This is because different climatological
or geological settings may demand different management procedures, either because of
technical convenience in designing or running a facility, or because of local environmental
problems. Issues such as depth to groundwater, soil permeability, net evapotranspiration,
and other site-specific factors can strongly influence the selection and design of waste
management procedures.

       In the light  of these circumstances, this section responds to Congress's directive by
focusing  on  the environmental  adequacy and desirability of the  various  available
technologies in different situations.  Emphasis is on establishing the performance of a given
technology in  relation to a given  waste, and on identifying those contexts in which the
technology is most effective and appropriate.  It is particularly important to distinguish
physical and geographical variations in waste management practices from those imposed
by State regulations.  Even where geographic and production factors are similar, States
may impose quite different conditions on waste management,  or may review permit
requirements on a case-by-case or regional basis.

       Sources  of Information

       The descriptions and interpretations presented here are based on State or Federal
regulatory requirements,  published technical  information,  observations gathered onsite
during the waste sampling program, and interviews with State officials and  private
industry.  Emphasis is on practices in thirteen  states that  represent a cross-section of the

petroleum extraction industry based on their current drilling activity, rank in production,
and geographic distribution (see Table 1).


       Data on the prevalence, environmental effectiveness, and enforcement of the
various waste management requirements are difficult to obtain. Published data are scarce
and often outdated. Some of the State regulatory agencies that were interviewed for this
study have only very limited statistical information on the volumes of wastes generated and
on the  relative use of the various methods.   Time was not available to attempt to gather
statistics from the other States that have significant oil and  gas activity.  This lack of
concrete data makes it difficult for EPA to complete a definitive assessment of available
disposal options.

       Organization of This Section

       The following discussion is divided into three principal subsections, one each for
the three categories of wastes: (1) drilling muds, cuttings and related wastes, (2) produced
waters (brines), and production chemicals and additives, and (3) post-closure wastes,
generally brines but also occasionally leachate from buried reserve pits. Each subsection
first characterizes the wastes of concern in qualitative terms, discussing their nonhazardous
as well as potentially hazardous constituents.  Technologies available for managing these
wastes are then presented in a standard format. For each technology, the report presents:
       1.     A  brief technical description that includes, as appropriate, design  and
              construction specifications,  operation and maintenance requirements, and
              geographic or other pertinent constraints on application.
       2.     An evaluation of environmental performance, including such factors as
              potential risks  associated  with routine  operation, potential  routes of
              environmental or health-related exposures under failure conditions, and key
              factors that influence environmental performance (i.e., relationships to
              design, operation and maintenance, and compliance).
       3.     Regulatory issues: these include regulatory variations across States that
              influence environmental performance (e.g., whether or not a  particular
              practice  is legally available,  applicable design and construction
              requirements, necessary inspection or testing procedures, and so forth).

                     Table  1

States With Major Oil Production Used As Primary
            References In This Study

                    New Mexico
                    West Virginia
                      — 4 —

       Detailed technical material on the principal technologies that were modeled in
connection with the risk assessment portion of this study are contained in Appendix II.
Drilling-Related Wastes

       Waste Characterization

       Drilling wastes include a wide variety of materials, ranging in volume from the
hundreds to thousands of barrels of fluids ("muds") used to drill a well, to much smaller
quantities of wastes associated with various additives and chemicals used to condition the
drilling fluids, stimulate or complete the well, or for other purposes. Some of the wastes
involved contain substances that are potentially hazardous under RCRA because of their
toxicity, corrosiveness, reactivity, or ignitability.  These would include such metals as
chromium, lead, and arsenic,1 which can be constituents of drilling muds. Other wastes,
such as drill cuttings (the soils and minerals extracted from the bore hole) are unlikely to be
hazardous by RCRA's definitions, but must still be handled as an integral part of the waste
management  system. The design and implementation of management techniques for the
potentially hazardous components of oil and gas wastes are often influenced by the need to
accommodate and process drill cuttings and other relatively high volume but nonhazardous
waste constituents.
       Drilling Fluids  (Muds)

       The largest volume of wastes generated are the  spent drilling fluids or "muds."
Water was the first drilling fluid to be used in oil and gas operations and still is the principal
component of most muds. The composition of modern  drilling muds, however, is quite
complex and  can vary widely, not only from one geographical area to another, but also at
different depths of the same well as it is drilled.

       Muds fall  into two general categories: water-based muds, which account for the
great majority  used, and oil-based muds,  which are primarily used when the  target
production formation is water-sensitive. Water based muds can be made with either fresh
1      Under the Land Disposal Restrictions Program, these metals are included on the so-called
"California list" of toxic wastes.

or saline water, oil-based muds are used for the protection of producing formations, drilling
water soluble formations, drilling deep, hot, holes and for mitigating severe drill-string

       Drilling muds are composed of four essential parts: (1) liquid, usually water; (2)
reactive solids, the density-building parts of the system, mainly clays; (3) inert solids such
as barite, plus inert undesirable solids such as formation cuttings; and (4)  additives to
control the chemical properties of the mud. These basic components perform various
functions, for example: clays increase viscosity to create a gel, barium sulfate (barite) acts
as a weighting agent to maintain pressure in the well, and lime and caustic soda increase the
pH and control viscosity.  Additional conditioning materials  include polymers,  starches,
lignitic material, and various other chemicals (Canter et al., 1984).

       Table 2 presents a partial list, by use category, of additives to drilling muds, some
of which may be hazardous in some  situations.  Substances that are listed as priority
pollutants under the Clean Water Act are highlighted by an underline.

       Well cuttings include all solid materials produced  in the drilling process that
eventually must be managed as part of the  content of the waste drilling muds.  A large part
of the material consists of rock and other heavy material that settles out by gravity. Some
material may be soluble, and can pose problems in waste disposal. One common cutting
contaminant is sodium chloride, since many wells encounter salt strata before  reaching the
producing zone.  This can lead to chloride contamination  of pit fluids and potential
environmental damage, such as chloride contamination of nearby drinking water supplies,
if fluids migrate away from the site for any reason.  Other possible contaminants include
naturally occurring minerals such as arsenic-bearing materials, which may be  encountered
in significant concentrations in certain wells and in certain parts of the country.

       Waste Chemicals

       In the course of well operations, chemicals may be disposed of by placing them in
the reserve pit.  These can include any substances otherwise deliberately added to the
drilling mud for the various purposes mentioned above (see Table 2).
       Fracturing and Acidizing Fluids

       Hydraulic fracturing is a process used for several purposes:
       •       To create deep-penetrating reservoir fractures to improve the productivity of
              a well;
       •       To improve the ultimate recovery from a  well by extending the flow
              channels farther into the formations;
       •       To aid secondary recovery operations; and
       •       To increase the rate of injection of brine and industrial waste material into
              disposal wells.

       The  process involves  breaking down, or "fracturing," the  formation by  the
application of hydraulic pressure, followed by pumping mixtures of gelled carrying fluid
and sand into the induced fractures to hold open the fissures in the rocks after the hydraulic
pressure is released.  Fracturing fluids can be oil-based, water-based, or acid-based.
Additives are used to reduce leak-off rate, to increase the amount of propping agent carried
by the fluid (i.e., the sand used to keep the fissures open), and to reduce pumping friction.

       The two most common additives for fluid gelling and reducing friction are guar
gum and polymers. Starch, bentonite, silica flour, and guar gum are among the additives
used to reduce fluid loss to the formation. If a water-based fracturing fluid uses water that
is relatively fresh, chemical treatment may be necessary to minimize problems with water-
sensitive clays in the pores of the reservoir rock. Sodium, calcium, or potassium chloride
salts can be added to increase the density of the material.

                                        Table  2

                                Characterization  of Oil
                                and  Gas  Drilling  Fluids

       The following is a qualitative description of componants commonly found in drilling fluids
and produced water associated with oil and gas production. It does not represent a formal or
exhaustive characterization of substances found in drilling fluids.  Substances listed as Priority
Pollutants under the Clean Water Act are shown with an underline.
                                     Drilling Fluids

Drilling fluid products contain a variety of substances that may present health or environmental
hazards in certain situations.  The following is a partial list of such products

Chromic Chloride-
Trademark of NL Industries,

Descp-Trademark of Drilling
Specialties Co.

Duratone HT-Trademark of
NL Industries, Inc.

Flosol-Trademark of Drilling
Specialties Co.

Galena-Trademark of NL
Industries, Inc.

K-Lig-Trademark of NL
Industries, Inc.

Q-Broxin-Trademark of
Georgia-Pacific Corp.

Sodium Chromate-
Trademark of NL Industries,

Sodium Bichromate-
Trademark of NL Industries,

Contains Chromium (III).  Is used to cross-link polymers.

Contains Chromium (VI). Is used as a thinner and for
filtrate reduction.

Contains Nonyl Phenol. Is used as a filtrate reducer.

Contains Asbestos.  Is used as a viscosifier.
Contains  Lead Sulfide.  Is used as a  high density
weighting material.

Contains Chromium (VH.  Is used as a thinner and filtrate

Contains Chromium (III).  Is used as a thinner and filtrate

Contains Chromium (VI). Is used as a corrosion inhibitor.
Contains Chromium (VI). Is used as a corrosion inhibitor.

BaraB33  (Surflo B33)-
Trademart< of NL Industries,

CaBr2/ZnBr2-Trademark of
NL Industries, Inc.
Contains 2-4 Dichloroohenol.  Is used as a biocide.
Contains ziQC- Is used as a weighting completion fluid.

       Bases used in formulating drilling fluid are fresh water, salt water, and oils including diesel
and mineral oils. It is estimated that the industry used 30,000 tons of diesel oil per year in drilling
                                  Weighting  agents

Common weighting agents found in drilling fluids are barite, calcium carbonate and galena (PbS).
Approximately 1,900,000 tons of barite, 2,500 tons of calcium carbonate, and 50 tons of galena
are used in drilling each year.
Viscosifiers found in drilling fluid include:

               Bentonite clays



       •       Asbestos

                      650,000 tons/year

                      85,000 tons/year

                      10,000 tons/year

                      10,000 tons/year

                      500 tons/year.
                                        —  9  —

Dispersants used in drilling fluid include:
              Cadmium, chromium.
              iron and other metal Lignosulfonates
              Natural, causticized, chromium
              and zinc lignite
              Inorganic phosphates
              Modified tannins
65,000 tons/year

50,000 tons/year
1,500 tons/year
1,200 tons/year).
                                Fluid Loss  Reducers
Fluid loss reducers used in drilling fluid include:
               starch/organic polymers
               cullulosic polymers (CMC, HEC)
               guar gum
               acrylic polymers
15,000 tons/year
12,500 tons/year
100 tons/year
2,500 tons/year
                              Lost Circulation  Materials
       Lost circulation materials used include a variety of nontoxic substances including
cellophane, cotton seed, rice hulls, ground formica, ground leather, ground paper, ground pecan
and walnut shells, mica, wood and cane fibers. A total of 20,000 tons of these materials are used
per year.
                               Commercial  Chemicals
Commercial chemicals used in drilling fluid include:
              Sodium hydroxide
              Sodium chloride
              Sodium carbonate
50,000 tons/year
50,000 tons/year
20,000 tons/year
                                       — 10 —

              Calcium chloride                             12,500 tons/year
              Calcium hydroxide/calcium oxide               10,000 tons/year
              Potassium chloride                           5000 tons/year
              Sodium chromate/dichromate                 4,000 tons/year
              Calcium sulfate                              500 tons/year
              Potassium hydroxide                         500 tons/year
              Sodium bicarbonate                          500 tons/year
              Sodium sulfite                               50 tons/year
              Magnesium oxide                            <10 tons/year
              Barium carbonate                            no quantity given.
       These commercial chemicals are used for a variety of purposes including pH control,
corrosion inhibition, increasing fluid phase density, treating out calcium sulfate in low pH muds,
treating out calcium sulfate in high pH muds.

                                 Corrosion  Inhibitors
Corrosion inhibitors used include:
              Iron oxide                                   100 tons/year
              Ammonium bisulfite                          100 tons/year
              Basic zinc carbonate                         100 tons/year
              Zinc chromate                               <10 tons/year.

                               Surface  Active Agents
Surface active agents (used as emulsifiers, detergents, defoamants) include:
              Fatty acids, naphthenic acids, and soaps        5,000 tons/year
              Organic sulfates/sulfonates                   1,000 tons/year
              Aluminim stearate                            (quantity not available)
                                       — 11 —

Lubricants used include:
              Vegetable oils
500 tons/year
<5 tons/year
                                 Flocculating  Agents
The primary flocculating agents used in drilling are:
              Acrylic polymers
2,500 tons/year
Biocides used in drilling include:
               Organic amines, amides, amine salts
        •       Aldehydes (paraformaldehyde)
               Chlorinated phenols
               Organosulfur compounds
               and organometallics
1,000 tons/year
500 tons/year
<1 ton/year

(quantity not available)
Miscellaneous drilling fluid additives include:
               Ethoxylated alkyl phenols
               Aaliphatic alcohols
               Aluminum anhydride derivatives
               and chrom alum
1,800 tons/year
<10 tons/year

(quantities not available)
                                       — 12 —

       The volume of fracturing fluids used to stimulate a well can be significant.2 Since
most petroleum fields that are currently  being developed contain low-permeability
reservoirs, hydraulic fracturing is very prevalent.

       The two basic types of acidizing treatments use are:
       •      Low pressure/low rate acidizing: this avoids fracturing the formation and
              allows acid to work through the natural pores (matrix) of the reservoir.
       •      High temperature/high rate acidizing:  this fractures the reservoir rock and
              keeps the induced fractures open during the operation.

       The types of acids normally used are hydrochloric acid (in concentrations ranging
from 15 to 28 percent in water), hydrochloric-hydrofluoric acid mixtures (12 percent and 3
percent respectively), and acetic acid. Factors influencing the selection of fluid type include
reaction time, corrosion of tubular agents, formation solubility, reaction products effects,
and sludging and emulsion-forming properties of the crude oil.

       Additives used for fracturing include corrosion inhibitors, surfactants, sequestering
agents, and suspending  agents.

       Corrosion inhibitors protect the production tubulars from attack by acids. Both
inorganic and organic inhibitors are available. Although inorganic inhibitors are cheaper
and more effective than organic inhibitors, they generally contain sodium  arsenate, which
tends to destroy refining catalysts during oil processing. As a result their use is declining,
but they can still be used in dry gas wells.  In addition to being more  expensive than
inorganic inhibitors, organic inhibitors tend to  have lower temperature ratings, making
them generally more suitable for shallow wells.  The higher the temperature of the bottom
of the wellbore, the higher the concentration of inhibitors necessary to provide suitable
2      Mobil Oil recently set a well stimulation record (single stage) in a Wilcox formation well in
Zapata County, Texas, by placing 6.3 million pounds of sand, using a fracturing fluid volume of 1.54
million gallons (World Oil, January 1987).
                                      — 13 —

       Surfactants are used with acid treatment fluids to reduce surface tension of raw acid
and spent acid solutions. The surfactant also helps to prevent emulsion formation and aids
the effectiveness of  the process by dispersing and suspending  fine solids, thereby
providing better cleanup of the treatment and/or improved compatibility with the formation.
Both nitrogen and carbon dioxide are used, along with fracturing fluids, both to improve
fracturing efficiency and to assist in unloading and cleanout of the fracturing fluid after
treatment of the well.

       Sequestering agents inhibit precipitation of reaction products.  They are particularly
useful in treating injection or disposal wells where insoluble iron compound scales are
deposited.  Citric, lactic, and acetic acids are common sequestering agents. "Suspending"
agents are used to hold in suspension the fine clay and silt particles that sometimes remain
after an acidizing treatment.

       Shut-in time is the  length of time a well is closed in after the acidizing treatment.
This time is determined by the type of formation, formation temperature,  and pressure.
After an  acid solution has been spent (1.5 percent concentration), it is no longer effective.
It may, however, become harmful to the formation permeability if allowed to remain in the
formation. Most acid treatments, with the exception of retarded systems, are designed for
minimum shut-in times prior to returning the waste acid  solution  to the surface. This
would cause the spent acid solution to have reactive acid properties prior to discharge to a
testing pit (or in some cases, the  reserve pit) or to a "frac"  tank, the contents of which
would have to be disposed of offsite.
       Completion and Workpyer Fluid Wastes

       Completion and workover fluids are chemically similar but have different functions.
Completion fluids are used to help initiate production from the reservoir; workover fluids
are used  to help recondition  wells whose production has declined because of reservoir
pressure or depletion, to reopen a shut-in well, or for some other purpose.

       In low pressure, low temperature completions, the completion fluid is usually field
saltwater, where the salt content inhibits clay swelling. In high pressure, high temperature
completions, additional salts may be added to field saltwater to obtain formulations with the
                                     — 14 —

necessary density and to prevent gelation of the completion fluid; additional solid weighting
materials may also be needed in some cases (Eaton et al., 1981).  Chloride and bromide
salts of  sodium, potassium, calcium, or zinc may be used as weighting materials,
depending on the fluid density required. The control of viscosity and filtration rate also
requires  special consideration in  these low-solids systems; organic polymers, such as
hydroxy ethyl  cellulose  and xanthum gum, are used for these purposes.   Corrosion
inhibitors, such as amine derivatives, help reduce damage to casing; at the concentrations
used (0.004 to  0.014 mg/1, or  1.5 to 5 Ibs/bbl), these corrosion inhibitors also serve as
biocides. These formulated completion fluids are also used as packer fluids in the casing-
tubing annulus for corrosion protection.

       Similar fluids are used in workover operations.

       When the completion or workover operation is completed, the fluids in the wellbore
are discharged  into a tank, the reserve pit, or a workover pit.  Some States prohibit the
discharge of completion fluids to the reserve pit because they contain corrosion inhibitors,
high levels of chlorides, and produced hydrocarbons.
       Rigwash  and Other  Miscellaneous  Wastes

       Rigwash materials are compounds used to clean decks and other rig equipment and
are mostly detergents, though they  may include some organic solvents, such as degreasers.

       Other miscellaneous wastes include pipe dope, used to seal joints in pipes, sanitary
sewage, trash, spilled diesel oil, and lubricating oil.

       All of these materials may,  in some operations, be disposed of in the reserve pit,

       Onsite  Waste Management  Methods

       Several  technologies can be used to manage oil and gas drilling wastes onsite. The
material presented below separately discusses reserve pits, landspreading, annular
disposal, solidification of reserve  pit wastes, treatment and disposal  of liquid wastes to
surface  water,  and closed treatment systems.   It is difficult, however, to  make clear
distinctions among these technologies,  since several may be employed at a particular site
                                    — 15 —

simultaneously.  Issues associated with reserve pits are particularly complex because
reserve pits are both an  essential element of the drilling process and a method for
accumulating, storing, and disposing of wastes.   This section therefore begins with a
general discussion of several aspects of reserve pits—design, construction, operations, and
closure—and then continues with more specific discussions of the other technologies.
       Reserve  Pits

       Reserve pits are an essential design component in the great majority of well drilling
operations,3 being used to accumulate, store and,  to a large extent, dispose of spent
drilling fluids, cuttings and  associated drilling site  wastes  generated during drilling,
completion, and testing operations.

       There is generally one reserve pit per well; in 1985, therefore, approximately
80,000 reserve pits  were constructed.  In the past, reserve pits were used both to remove
drilled solids and cuttings  and to store the active mud system prior to its being recycled to
the well being drilled. As more advanced solids control and drilling fluid technology has
become available, mud tanks have begun to replace the reserve pit as the storage and
processing  area for  the  active mud  system, but  these are—and  are  expected to
remain—used only  for special purpose applications.  Reserve pits will continue to be the
principal method of drilling fluid storage and management.

       A reserve pit is typically excavated directly adjacent to where the rig and associated
mud equipment will be sited.  Ideally, pits should be excavated from undisturbed, stable
subsoil in order to  avoid  pit wall failure. For areas where it is impossible to excavate
below ground level, the pit berm is usually constructed as an earthen dam so as to prevent
runoff of supernatant liquid into adjacent areas.

       Reserve pit  sidewalls  should be constructed with a slope of less than 3:1 to  give
support and to minimize seepage.  Whenever possible, a  reserve pit should not be
3      Closed systems, which do not involve reserve pits, are used very occasionally (see discussion
                                     — 16 —

constructed on sloping ground or near the edge of a hilltop. This is sometimes impossible
to avoid, however. Where it is necessary to build on a hillside, the hillside must be
contoured in such a way that the runoff water is diverted around the drilling location and
reserve pit. Pits should be located a minimum of 300 feet laterally from the high water
mark of the nearest water body and/or intermittent water courses (MoeCo, 1984). The site
chosen should be high enough to escape flooding in heavy rains from any nearby bodies of

       It is not uncommon to find the  reserve pit being used to store  trash, waste
lubricating oils, treatment fluids,  produced water, and waste  chemicals. However,  the
primary sources of contamination (by volume) are salts, oil and grease, and  dissolved
heavy metals.  Sources of soluble salt contamination include downhole salt layers and
formation waters, and drilling fluid additives. Sources of organic contamination include
lubricating oil from equipment leaks, diesel line air purge, well pressure control equipment
testing, heavy oil-based lubricants  used to  free stuck drill pipe and, in some cases, oil base
muds used to drill and  complete the target formation. Sources of potential heavy metal
contamination are drilling fluid additives, drilled solids, weighting materials, pipe dope and
spilled chemicals.  (Rafferty, 1985).

       The reserve pit  itself can be used  for final disposal of all, or part of, the drilling
wastes—with or without prior onsite treatment of wastes—or as temporary storage prior to
offsite methods of disposal.  Most often reserve pits are used in combination with  some
other disposal technique. Methods used depend on waste type, geographical location of the
site, climate, regulatory requirements, and (if appropriate) lease agreements with  the

       The major onsite waste disposal methods include:
       •      Dewatering the pit wastes (by evaporation or  decantation)  followed by
             backfilling of the pit itself,  using the pit walls as a source of material. This
             is the most common technique; an alternative to backfilling the pit, where
             appropriate, is landspreading  all or part of the pit content onto the area
             immediately adjacent to the pit.
       •      Injecting or pumping all or part of the wastes into the well annulus.
                                     —  17 —

       Other, less common, onsite management methods include:
       •       Chemical solidification of the wastes.
       •       The use of portable equipment to dewater, treat and discharge the liquid
              fraction, followed by burial of the dewatered solids.
       •       The use of closed treatment systems.

       Dewatering and burial of reserve pit wastes (or, alternatively, landspreading the pit
contents) are discussed here because it is usually an integral aspect of the design  and
operation of the reserve pit.  The other techniques are discussed separately.

       Dewatering of reserve pit wastes can be accomplished by the natural process of
evaporation (in areas of net evaporation) and/or possible seepage through the pit walls and
bottom. This method is used where the climate permits and pit closure time limits are not
restrictive.  Alternatively, dewatering can be accomplished in areas of net precipitation by
siphoning or pumping free liquids,  followed by disposal  of the liquid  by subsurface
injection or trucking offsite to an  appropriate disposal operation.  Backfilling consists of
burying the residual pit contents by pushing in the berms or  pit walls followed by
compaction and leveling. Landspreading involves spreading out on surrounding soils the
excess muds that are squeezed out during the burial operation; in  the event that there is a
considerable quantity of this n aterial, landowners' permission is generally sought to
disperse this material on acreage some distance from the  site.  It is important in reserve pit
construction that the sides, or berms, of the pits be high enough to provide for 3 to 5 feet of
native topsoils on top of the drilling muds and cuttings  after backfilling. The dewatered
material left in the soil may include toxic heavy metals, chlorides,  and organics associated
with the original fluids.
       Environmental Performance

       Construction of reserve pits is technically simple and straightforward. They do not
require intensive maintenance to assure proper function, but they may pose environmental
hazards during their operational phase in certain circumstances.
                                        18 —

       Pits are generally built from native surface and subsurface soils that are often
unconsolidated and therefore highly permeable. Reserve pits are also generally unlined.
The result may be seepage of liquid through the pit berms and bottom into any shallow,
unconfined aquifers that may be present.  Since reserve pits are used only for temporary
storage, leakage to ground water is temporary, but it may in some cases be significant.

       Other routes of environmental exposure associated with reserve pits include rupture
of pit berms or overflow of pit contents, with consequent discharge to land or surface
water.  This can happen in areas of high rainfall, or where soil used for berm construction
is particularly unconsolidated.  In such situations, berms can become saturated and
weakened, increasing the potential for failure.  Maintenance of berm walls can become a
significant issue.  Occasionally, pits are deliberately breached  to allow pit contents to
escape to the surrounding area as a means of disposal. This practice is more prevalent
(with more  incentive to do so) in remote areas having undeveloped land and absentee

       Leaching of pollutants after pit closure can also occur and may be a long term
problem especially in areas with highly permeable soils.

       There are no inherent environmental advantages to the use of reserve pits.  They are
the industry norm ( and usually the most economical  system)  for onsite  drilling fluid
management, against which the performance of other waste management methods can be

       I.  Fluid loss can occur as a result of levee  (berm) breaching and/or over-topping.
Pollutants in the pit fluids that may be present in sufficient concentrations to cause surface
water pollution upon fluid release include chlorides, COD, TOC, sulfate, and TDS, heavy
metals, waste chemicals, and drilling fluid conditioning chemicals (biocides,  corrosion
inhibitors, and other substances mentioned in Table 2).
                                     — 19  —

       2.  Significant groundwater pollution can occur as a result of seepage through the
walls and bottom of reserve pits constructed in permeable soils. Factors influencing the
potential  for groundwater contamination by  seepage from unlined pits include soil
permeability, depth to water table, rates of precipitation and evaporation, nature and volume
of wastes, and geochemical characteristics of the soils (Canter 1985).  Considerable
controversy exists in the industry as to the prevention of seepage through the bottom of the
reserve pit by the "sealing" effect  of the clays used to formulate  the drilling muds.
Although experimental studies have shown that hydraulic permeabilities of pit sediments
are very low (restricting movement of heavy metal contaminants), sodium chloride leaching
is not arrested because of its high solubility (Deeley, 1986).

       3.  Leaching of pollutants from closed reserve pits may, over the long term, pose
significant environmental and human health hazards from contamination of drinking water
supplies and shallow ground water with toxic materials.  The potential for such problems
varies considerably and depends primarily  on local environmental and  geological
       Regulatory Issues

       There is currently little emphasis at the State level on reserve pit siting and
monitoring requirements, though over the last few years there has been a general trend of
improvement in many States to implement stricter controls over most aspects of reserve pit
use.  The regulatory issues of most concern are  (1) design, construction, and performance
requirements, including use of liners,  and (2) closure and reclamation requirements.
       Design, Construction, and Performance Requirements

       Design, construction, and performance requirements for reserve pits vary  widely
from State to State.  Some have construction guidelines covering above or below ground
construction, required freeboard, and compaction.  Most States (Wyoming is probably a
typical example) rely on broad general statements calling for the protection of ground and
surface water and soil, yet provide  few specifics on how such protection is to be achieved.
Typical language might state that mud pits, sumps, reserve pits, or tanks "be of sufficient
size  and managed to prevent contamination of ground water and damage to the surface
                                    — 20

environment."  Responsibility for interpreting these general environmental requirements is
left largely up  to individual  operators.  Without specific guidance on what constitutes
proper performance, enforcement is difficult.

       Some States do have clear standards, however.  Michigan's regulations, for
example, are among the most specific and demanding.  Liners are required when drilling
with saltwater based fluids or when drilling through salt formations or brine-containing
formations.  When used, liners must be 20 mil virgin PVC, must be installed in a manner
that prevents vertical and lateral leakage, and must be in one piece or have factory-installed
seams. Case-by-case exemptions to this requirement can be  granted but are  rarely
requested.  Michigan also states that reserve pits may not be constructed where ground
water is visible  at the depth of the proposed excavation.  No salt cuttings from drilling may
be released to the reserve pit as solids; they must be screened out and dissolved before
being released, via a closed system, to the pit.

       Louisiana's regulations, although not currently as strict as Michigan's, have been
markedly upgraded.4  Such  revisions are typical of a trend in many States to improve
design, construction, and performance regulations for oil and gas operations generally.
Several States appear to be using these new Louisiana regulations  as a model in upgrading
their  own regulations.  In  addition to the design requirements  already mentioned,
Louisiana's new rule includes stringent operational requirements for reserve pits, including
segregation of the  drilling wastes in reserve pits from produced water or waste oil,
protection of surface waters by levees, walls, and drainage ditches, and maintenance of a 2-
foot freeboard.  To some extent, these strict new regulations are in response to Louisiana's
special conditions.  The State has particularly high ground-water levels throughout much of
its oil and gas development areas.

       Some other States require liners, but they tend to require them  only in specified
situations. Liners are coming into wider use, but design requirements vary.  In Texas, for
instance, liners are not required in most situations but are often used voluntarily; no design
requirements apply, however,  and liner seams may be left entirely unsealed.
4      Oil and gas operations prior to January 20,1986, are "grandfathered" until January 20,1989, when
the new, much more restrictive, regulations take effect
                                     — 21 —

       Monitoring to ensure pit integrity is not currently required by any State as a general
practice, although it may be required under unusual circumstances.
       Closure and Reclamation

       Closure requirements, like design, construction, and performance requirements,
vary considerably  among the States. Most have very general requirements.  Where pit
burial after dewatering is selected as a waste disposal technique, typical requirements may
state that, after a well is completed or abandoned, the fluids are to be removed and disposed
of properly, and that all mud pits, sumps, reserve pits, and dikes usually must be backfilled
with earth or graded and compacted in such a manner at to be returned to a nearly  natural
       Annular Disposal of Pumpable  Wastes

       Annular disposal involves the pumping of drilling fluids within the annulus created
between the surface and intermediate casing, or between the surface and production casing,
of a well. (Disposal within the surface casing in the absence of an inside casing comes
under the heading of annular injection, but can be considered more of a borehole disposal
approach.) Annular disposal is significantly more costly than land application, and is
generally used when  the pit contains an objectionable level of a  contaminant or
contaminants (such as  chlorides, oil and grease, or acid) that limits availability  of land
application.  No statistics are available on  how frequently annular injection of drilling
wastes is used, but it is probably used at less  than 15 percent of all drilling sites.

       Surface casing strings are cemented all the way to the surface to protect fresh water;
this depth may range from approximately  300 feet to 2,000 feet.  Intermediate casing
strings, if used,  are cemented from 8,000 to 10,000 feet up to whatever depth is required to
seal off all potential producing zones above the casing seat.  The annular space has open
hole exposure below the surface casing seat and permits fluids to go down between the
surface casing and the intermediate casing into the subsurface formations. In cases where
there is no intermediate casing, fluids will go down below the surface casing and above the
top  of the cement on the production casing and out into the zones of least resistance.
                                     — 22  —

Usually these zones of least resistance are highly-permeable, salt-water sands or various
other nonproductive sands.

       Injection into the well bore itself,  which can  be done with  the surface and
intermediate (and at times the production) casing left in place, utilizes the casing employed
in the drilling process and causes the fluids to be injected into a more specific zone.  This
approach is only employed for dry holes, where a bottom hole plug can be  set and the
casing perforated where injection is desired. However, in some cases the operator may
remove the intermediate or production casing and then  inject the fluid into  the surface
casing. Although this is not quite a well-bore approach, it is permissible in  some cases
after a bottom hole plug has been set.  The  integrity of the surface casing is always an
important criterion for injection outside the intermediate or production  casing.  Figure 1
illustrates the alternatives for annular disposal of drilling wastes.
       Environmental Performance

       During drilling, rotational stress can impair the integrity of the surface casing,
which is what protects upper ground  water  layers during drilling and after annular
injection. This is especially true if abnormal drilling conditions have been encountered and
the hole becomes partially deviated, causing the drillstring to rest against the surface casing
during drilling.  There is no way to test  the surface casing  annulus without incurring
significant expense. States do not require testing of the annulus prior to annular disposal of
the reserve pit contents, so holes in the casing or parted casings may exist unknown to the
operator, possibly leading to unintentional ground-water contamination from leakage of
reserve pit fluids from the annulus.

       Assuming the annulus is sound, the critical implementation factor is the pressure at
which the reserve pit contents are injected.  States usually allow operators to inject as much
of the reserve pit contents as possible (including both liquids and muds) to the extent of one
well's worth of these wastes. They do not require reporting of injection pressures used in
the process. The receiving formations are usually relatively shallow sandstones having low
fracture pressures; if the fracture  or safe operating pressure is exceeded during annular
                                     — 23 —

injection, vertical fractures can be produced, potentially allowing migration of reserve pit
                                      — 24  —

                                                   .»  u  r
                                                   3  <  <
                                                      7 *
                                                  i  2
                                                   ..  f
                                                   "•  SJ

       contents into freshwater zones.  This can happen when injected mud plugs the
receiving formation, causing the operator, in the hope of continuing the disposal process,
to increase the injection pressure to the point where the formation fractures.

       Another important environmental aspect of annular injection is identification and
characterization of of the confining shale layer above the receiving formation.  Very often,
shallow shale layers are discontinuous.  If an unidentified discontinuity exists close to the
borehole, the potential is created for migration of reserve pit wastes into ground water.

       1. By disposal of drilling fluids by annular injection below the level of any fresh
water formations on a one-time-per-well basis, less environmentally desirable surface
disposal practices can be avoided.  Environmental advantages exist especially when the
drilling pit wastes  are contaminated  with high levels of chlorides or heavy  metals
(McCaskill, 1985).

       1. The potential exists for contamination of fresh water formations or aquifers with
the injected drilling fluids.  The disposal zone may begin at the base of the surface casing
seat, which is usually set about 200 feet below the base of any fresh water reservoirs.  The
use of high pressure pumping equipment and the suspended solids in the waste, which tend
to plug the permeable disposal zone during pumping, can easily cause the fracturing or
breakdown of any sealing barrier between the disposal zone and the fresh water sands.

       2.  Groundwater contamination can occur through undetected leaks in the surface
casing.  Casing integrity is difficult to test through the annular space.

       3.  Poor cement bonding or lack of cement between the casing and the borehole
may also cause fluid migration to shallow fresh water zones.
                                     — 26 —

       Regulatory Issues

       Annular injection is specifically allowed in four of the States studied for this project:
Alaska, Oklahoma, Texas and Louisiana. Other state regulations reviewed are silent in the

       In the North Slope of Alaska, reserve pit wastes are frequently injected down the
annulus either of the well being drilled, or of another well on the pad. A general permit for
the North Slope for annular disposal was issued by the Alaska  Department of
Environmental Conservation (ADEC) for the period of August 6, 1985 to April 30, 1987.
The permit applies to the discharge of fluids produced from the drilling, servicing or testing
of oil and gas exploration, development, service and stratigraphic test wells, including but
not limited to drilling fluids, rig washwater, completion fluids, formation fluids, reserve pit
meltwaters and domestic wastewaters..."

       Discharge must occur below the permafrost zone; the minimum depth must be
1,000 feet. No discharge must be into any zone containing TDS of less  than 3,000 ppm.
Operators must notify DEC at least two weeks before beginning injection, and must include
information on volumes and types of material being injected, the zone and depth of the
injection, and the method to be used to seal the injection zone at the completion of disposal.
Written approval must be received from DEC.

       This is a short term option with any specific well, since the annulus must soon be
cemented closed to preserve the integrity of the permafrost.

       In Oklahoma, 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 intermediate casing) is set and cemented (set) at least
200 feet below the base of treatable water.  Injection pressure must be limited so that
vertical fractures will not extend to the base of treatable water (Rule 3-312).
                                     — 27

       Reserve Pit Wastes  Solidification

       Problems  with  onsite  burial of reserve pit contents reported by landowners
(including reduced load-bearing capacity of the ground over the pit site and the formation of
wet spots), as well as  environmental problems caused  by leaching of salts and toxic
constituents into ground water, have prompted increased interest in reserve pit wastes

       In the solidification process, the total reserve pit waste (fluids and cuttings) is
combined with solidification agents such as commercial cement, flyash, and lime kiln dust.
During the process a relatively insoluble concrete-like matrix is formed, reducing the
overall moisture content of the mixture. The end product is more physically stable and
easier to handle than the usual reserve pit buried material. The solidification process can
involve the injection of the solidifying agents into a reserve pit, or pumping the waste into a
mixing chamber near the pit. The waste does not have to be dewatered prior to  treatment
and sulfates do not interfere  with  the solidification process. The treated waste can
experience a significant increase in weight and bulk which may be a disadvantage to the use
of this method.
       Environmental Performance

       Solidification of reserve pits wastes offers a variety of environmental improvements
over simple burial of wastes, with or without dewatering.  By reducing the mobility of
potentially hazardous materials, such as heavy metals, the process reduces,  and may
entirely avoid, the potential for contamination of ground water.

       1.  This method reduces the likelihood of erosion and the leaching of metals and
organics into the soil and ground water because the solidified material is more physically
stable than material in the typical reserve pit burial process.
                                     —  28 —

       2.  Permeabilities and migration rates have been found to be low; thus, any resultant
bioaccumulation is believed to be limited and to potentially affect only  a small area
immediately adjacent to the pit (Musser, 1985).

       3.  Recent laboratory studies conducted with reserve pit wastes and solidifying
agents concluded that extractable levels of certain metals (using the EPA toxicity leaching
test) fell well below EPA RCRA limits (Deeley and Canter, 1985).

       4.  Solidification provides a faster means of closing a pit, particularly in areas of net
precipitation where seasonal changes often interfere with site restoration (Crabtree, 1985).

       1.      Solidification costs more than conventional pit burial, although costs are
expected to vary significantly according to the location of the well. In addition, the volume
of solidified material to be disposed of can increase significantly.

       2.      The potential still exists for  leaching of organics and nonmetallic ions
(particularly chlorides)  into groundwater and/or bioaccumulation in plants (Hanson et al.
       Regulatory Issues

       Solidification of pit wastes is not extensively practiced in most States. Regulatory
issues are  therefore not well defined; the basic concern is whether or not States have written
specific performance or implementation requirements to cover this practice.
       Implementation Requirements

       Among the thirteen States studied, several have regulations defining solidification
of reserve pit wastes as an acceptable disposal alternative. The remaining States do not
have specific regulations governing this practice. Principal concerns of the States that do
regulate solidification practices include (1) structural integrity of the solidified mass in the
pit and (2) permeability and leachability of the  material after it is treated.
                                      — 29 —

       Louisiana's Statewide Order No. 29-B, which is among the most specific and
comprehensive general statutes, requires that an operator to demonstrate that the buried
solidified material has the required integrity by complying with specific values related to
compressibility,  wet-dry cycling, permeability,  and leachate tests.5 These tests are
conducted on the final solidification product in order to demonstrate compliance.  The only
Guidelines  for Limiting constraints  (GLC)  values  specified  by the Louisiana Oil
Conservation Commission are limited to pH and oil and grease.

       Freezing wastes substitutes for chemical solidification in Alaska. Title 18 of the
Alaska Administrative Code, Chapter 60, specifically addresses construction requirements
for "a containment structure which is designed to contain drilling wastes in a permanently
frozen state", including a waste surface level 2 feet below the active thaw zone.6

       Michigan's Supervisor of Miner Wells Instruction 1-84 specifies lined pit closure
requirements, and includes the following statement regarding solidification:

       "Earthen materials shall be mixed with the pit contents to stiffen it sufficiently to
provide physical  stability and support for the pit  cover.  A pit stiffening process as
approved by the Supervisor may be used at the option of the operator."
       Treatment and Discharge of Liquid Wastes to Land or Surface Water

       Under the Federal NPDES (National Pollutant Discharge Elimination System)
Program, the liquid phase of waste drilling muds having low chloride concentrations can be
chemically  treated using coagulants and flocculants;  the treated aqueous phase  (at an
appropriate  alkaline pH) can then be legally discharged to land or surface water bodies.
The addition of selected reagents to reserve pit liquids must achieve the necessary reactions
to allow effective separation of the suspended solids prior to dewatering of the sludge in the
5      This order applies immediately to all operations initiated after January 20, 1986. As of January
20, 1989, it applies retroactively to all operations under way as of January 20, 1986 or before.
6      Even on the North Slope, wastes do not remain frozen year round; alternative methods for disposal
of reserve pit wastes on the North Slope include annular disposal and discharge directly to the tundra (see
discussion below).
                                     — 30  —

reserve pit.

       Onsite treatment technologies used prior to discharge are commercially available for
reserve pit fluids as well as solids and are typically provided by mobile equipment brought
to the drill site.  These methods include pH adjustment,  aeration, coagulation  and
flocculation, centrifugation, filtration, dissolved gas flotation and reverse osmosis.  All
these methods, however, are expensive compared to the  more common  dewatering
methods (i.e., evaporation) and are used only  under special circumstances.  Usually a
treatment company employs a combination of these specialized methods in order to treat the
sludge and aqueous phases of reserve pit wastes.

       Treatment techniques that could be used in the field include:
       •     Use of a coagulant, such as aluminum sulfate,  added to the pit followed by
             addition of  a  flocculant (a natural  or synthetic polymer)  to remove
             suspended solids from the aqueous phase.
       •     If the liquid phase is successfully separated from the solids (including the
             possible requirement for centrifugation or  filtration to achieve  this
             separation), the liquids may be  pumped from the pit and, following pH
             adjustment (if required), discharged to a surface water body or to the land. *
       Environmental Performance

       Treatment and discharge of liquid wastes  is used primarily to shorten the time
necessary to close a pit.  If an area has high rates of precipitation or low evaporation
potential, it may be impossible to meet State-mandated closure schedules unless the liquid
portion of the reserve pit wastes can be disposed of properly. Assuming the effluent meets
applicable discharge standards, the practice offers the environmental advantage of reducing
the potential for seepage of wastes from the pit to surface water or ground water.

       1. Treatment and  discharge, where used, allows for more rapid pit closure,  thus
reducing potential seepage to ground water, as well as meeting appropriate State deadlines
for allowable time for pit closure following drilling completion.
                                    — 31 —


       1. Improper treatment caused by poor quality control or exceeding of equipment
capacity can cause discharge of pollutants exceeding allowable levels in the permitted
discharge requirements.

       2.  Costs are significantly higher than those associated with conventional pit
contents dewatering and burial.
       Regulatory Issues

       Environmentally, the two regulatory issues of primary concern are the standards
established under State NPDES programs for  (1) allowable chloride levels and (2) for
allowable priority pollutant levels in the discharged effluent.7
       Restrictions on Chloride Levels and Other Conventional Pollutants

       Chloride levels in discharged effluent should be limited under the discharge permit
in order to avoid impacts to receiving waters.  Since saline waters  can obviously accept
considerably higher chloride levels than fresh waters, the use of this disposal technique is
can be much more extensive in coastal States than in inland States. Coastal States will set
different discharge limits according to whether the discharge site is inland or to a saline
water body.  Dissolved chloride limits for inland disposal are quite low, usually about 500
ppm; the notable exception is West Virginia, as discussed below.  The other most common
limitations (other than on priority pollutants or other definitions of hazardous substances)
include pH, total dissolved solids (including chlorides), oil and grease.

       In Texas, the Texas Railroad Commission permits treatment  and discharge of non-
oil-based 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
7      The Clean Water Act lists 126 "priority pollutants" that can be considered in permit requirements
for NPDES discharge permits. These include a variety of toxic organic and inorganic pollutants, including
the principal heavy metals (such as lead, cadmium, nickel, and chromium) that may be of concern in reserve
pit wastes.
                                      — 32 —

choose the technology but must provide proof that the selected technology will meet the
Commission's criteria. Texas's requirements are as follows:
             Chlorides (coastal)    <      l,000mg/l
             Chlorides (inland)     <      500mg/l
       •      Chemical oxygen demand     <      200mg/l
       •      Total suspended solids       <      50 mg/1
             Total dissolved solids  <      3,000 mg/1
             Oil and grease <      15 mg/1
             pH    6.0 to 9.0
       •      24-hour bioassay by Texas Parks and Wildlife
       •      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."

       In coastal areas of Texas, if the receiving body of water has concentrations of IDS
or chlorides in excess of 3,000  mg/1 or 1,000 mg/1 respectively, then the concentration of
the treated reserve pit fluids may exceed those limits, but may not exceed the actual level in
the receiving water body.  In such cases the effluent must be piped to the receiving water

       Under the special conditions imposed by operations in permafrost areas, the State
of Alaska imposes more liberal conditions on pit waste disposal.  The Department of
Environmental  Quality issued a seasonal general permit  on May 12, 1986 (expired
September 30, 1986) for discharges onto the tundra from reserve pits used for  storage of
"produced waters, drilling fluids and cuttings, boiler blowdown, rig washing  fluids,
workover fluids, completion fluids,  excess  fluids from blowouts and drill pad runoff."
Only those pits were eligible which had received no discharges or placements  of any
materials into the pit since August 1,1985 (that is, pits which had gone through  a one year
                                    — 33 —

freeze-thaw cycle to precipitate contaminants). Furthermore, pits must have no visible oil
sheen on the surface.

       Operators must notify the Alaska Department of Environmental Conservation two
weeks prior to any discharge, and include information on volumes and analyses of
constituents.  Written approval must be received from DEC prior to the discharge.  The
permit applies only to discharge, and include information on volumes and analyses of
constituents.  The permit applies only to discharges of the clarified supernatant from pits.
The maximum drawdown is 18 inches from pit bottom at point of withdrawal.  Other
management practices, such as injection, must be used for further drawdown. Effluents
must be monitored during discharge. The effluent limitations for 1986 (excluding heavy
metals, discussed below) were:
              Salinity      3,000 ppm
              COD   200mg/l
       •       pH          6.0-8.5 (or within 0.5 of receiving water)
       •       Settleable solids       1 mg/1
       •       Oil and grease 15 mg/1
       •       Aromatic hydrocarbons       10 (j.g/1

       These limitations will be reevaluated prior to issuance of the  1987 general permit.
Limitations are also being evaluated for copper, zinc, aluminum,  and boron. The process
of reevaluation after 1985 led to the elimination of an effluent limitation for manganese in
the  1986 general permit.  DEC figures in the information sheet with the 1986 general permit
indicate approximately 36 million gallons of liquid were discharged from 43 reserve pits in
1985, 35 of the reserve pits exceeded the limitations.  Sixteen of these pits exceeded the
limitation for manganese, which is found at naturally high levels in waters on the slope.

       West Virginia, an inland State, is an extreme exception to  the general rule that
inland discharges of saline waters must be held to low concentrations.  Treated wastewaters
generated during drilling, reworking and treatment of  wells may be discharged for land
application  on-site, subject to the following limitations:
                                     — 34 —

             Chloride      25,000 mg/1
             pH    6.0 - 10.0
       •      Total iron     6 mg/1
       •      Free or floating oil    No visible sheen on land

       This extraordinarily permissive standard for chloride discharges is unique to West
Virginia; no other State allows discharges of this concentration even to saline waters.

       In addition, West Virginia  requires  monitoring for  TSS, dissolved oxygen,
manganese, conductivity, settleable solids, and total organic carbon.  Discharge onto
property off the drilling site requires both a permit and the permission of the landowner.
Required treatment includes aeration and extended settling for at least 10 days. Free or
floating oil shall be skimmed off and removed from the pit before treatment and, if
observed, before discharge.  Land application may not be carried out on saturated, frozen,
impermeable, or unvegetated land, and must be  at a rate that will not cause ponding or
erosion.  To prevent discharge of sludge, there must be a discharge device on the pit that
ensures that the discharge will be from near the surface of the pit water level.
       Discharge of Heavy Metals and Other Potentially Toxic Materials

       Discharge of heavy metals and other toxic materials are regulated under the NPDES
program as well. Although some States, such as West Virginia, do not limit discharges of
these materials, where discharge limits are specified they tend to be fairly consistent among
States.  For instance, Texas  specifies that discharge cannot exceed concentrations of
hazardous metals as defined by Texas Water Development Board Rules
.009.  (these include such metals as arsenic, cadmium, chromium, lead and  mercury).
Alaska's limits are:
       •      Arsenic       .05 mg/1
       •      Barium       1 mg/1
       •      Cadmium     .01 mg/1
             Lead  .05  mg/1
                                    — 35

       •      Mercury       .002 mg/1
       Closed Treatment Systems

       A closed cycle waste treatment system can be an alternative to the use of a reserve
pit for onsite management of drilling wastes. Essentially an adaptation of offshore systems
for onshore use, closed systems have come into use only relatively recently.  Because of
their high costs they are used very rarely—usually only when operations are located at
extremely delicate sites  (such as a highly sensitive wildlife area), in special development
areas (such as in the center of an urbanized area), or where the cost of land reclamation is
considered excessive.  It can also be used where limited availability of make-up water
makes control of drilled solids by dilution infeasible.

       Closed cycle systems are defined as systems in which mechanical solids control
equipment (shakers, impact type sediment separation, mud cleaners, centrifuges, etc.) and
collection equipment (roll-off boxes, vacuum trucks, barges, etc.) are utilized so that waste
mud and cuttings volumes to be disposed of on or offsite are minimized. This in turn
serves to maximize the volume of fluid (chemically treated water or oil) and/or weighting
materials returned to the active mud system.  Benefits derived from the equipment's use
include (Hanson et al., 1986):
       •      A reduction in the amount of water or oil needed for mud maintenance,
       •      An increased rate of drilling bit penetration,
       •      Lower mud maintenance costs,
       •      Reduced waste volumes to be disposed of, and
       •      Reduction in reserve pit size or total elimination of the reserve pit.

       Closed cycle systems range  from very complex to fairly simple. The degree of
solids control should be based on the mud type and/or drilling program and the economics
of waste transportation to offsite disposal facilities (particularly the dollars per barrel
charges at these facilities versus the cost per day for additional solids control equipment
rental).  Closed systems at drilling sites can be operated to have recirculation of the liquid
                                     — 36

phase, the solid phase, or both. In reality, there is no completely closed system for solids
because cuttings are always produced and removed. The closed system for solids, or the
mud recirculation system, can vary in design from site to site, but the system must have
sufficient solids handling equipment to effectively remove the cuttings from muds to be

       Water that is removed from the mud along with the cuttings can be reused.  A
separate closed  system for water reuse can be operated onsite along with the mud
recirculation system.   As with mud recirculation  systems,  the  design of a water
recirculation system can vary from site to site, depending on the quality of the recycled
water required for further use.  This may include chemical treatment of the water. Also,
any solids must be removed from the water.  This can be accomplished through the use  of
centrifuge or filtration apparatus.
       Environmental Performance

       Although closed systems offer many environmental advantages, their high  cost
seriously reduces their potential use.

       1. The main advantage of closed systems as a replacement for conventional reserve
pits  for  handling waste drilling  muds is the minimization  or elimination  of  any
environmental impacts caused by leaching or seepage of chlorides or heavy metals into the

       2. Closed systems also reduce the volume of the wastes that must ultimately be
disposed of.

       1. There appear to be no environmentally-related disadvantages in the use of closed
systems for drilling fluid use and control.
                                    — 37 —

       2.  The costs of these systems are prohibitive for other than highly specialized
situations, i.e., high water table areas (such as on the Gulf Coast) or in sensitive wildlife
       Regulatory Issues

       Closed systems have only come into use relatively recently.  States therefore have
not had an opportunity to review the process so as to frame possible regulatory controls.
However, none of the States studied have any regulations prohibiting the use of closed
systems for drilling fluids use and control.

       Closed systems have been used in several States.  Examples include the following:

       In California, one site was know to use a mud recirculation system using two shale
shakers. The reduction of mud generated waste at this site was necessary because the
wastes were stored in above-ground storage bins. At the conclusion of  drilling, the
contents of these bins were emptied and transported to a centralized treatment facility (EPA
- CA, 1986).

       In Michigan, a particular site used a mud recirculation system similar to the one
observed in  California. At this site, drilling wastes at the end of drilling were placed in a
lined pit and were later removed by a vacuum truck (EPA - MI, 1986).

       Offsite Waste Management Methods

       Offsite waste management methods include the use of centralized disposal pits
(either privately or commercially operated), centralized treatment facilities, commercial
landfarming, and reconditioning and reuse of drilling media.
       Centralized Disposal Pits

       Centralized disposal pits are used in many States to store and dispose of reserve pit
wastes. In  some cases, large companies developing an  extensive oil or gas field may
operate centralized pits within the field for their own convenience.  Most centralized pits are
                                        38 —

operated commercially, however, primarily for the use of smaller operators who cannot
afford to construct properly designed and sited disposal pits for the own use. Typically,
centralized pits are used when storage and disposal of pit wastes onsite is undesirable
because of the high chloride content of the wastes or because of some other factor that
raises potential problems for the operators.8

       The number of commercial centralized pits in major oil-producing States may vary
from a few dozen to a few hundred.  The number of privately-developed centralized pits is
not known.

       Technically, a centralized pit is identical in basic construction to a conventional
reserve pit (other than the typical State requirement that the former have a suitable barrier to
prevent leaching to ground water). It is an earthen impoundment, which can be either lined
or unlined, used to accumulate, store and dispose of drilling fluids from drilling operations
within a certain geographical area. Central pits do, however, tend to be considerably larger
than single-well pits; surface areas can be as large as 15 acres, depths as great as 50 feet.
No treatment of the pit contents is usually  performed.  A properly sited, designed,
constructed and operated centralized pit allows the natural evaporation process (in areas of
net evaporation) to concentrate drilling fluids  with  the  liner preventing seepage to
groundwater.  Most States have regulations  covering  these  operations, including
requirements for synthetic or clay liners to prevent groundwater contamination.

       Centralized pits may serve the disposal needs for drilling or production wastes from
multiple wells over large geographical areas.   They should  be close  to drilling and
production sites to be cost-effective, yet they  should be located in environmentally safe
areas.  A site removed from well-defined drainage basins will minimize the potential for
surface water pollution from heavy runoff (University of Oklahoma, 1984).
       Environmental Performance

       Centralized pits are merely  a storage and disposal operation; they perform  no
treatment of wastes. Commercial operations do, however, tend to have stricter State design
8      Smaller operators, for instance, may be required under their lease agreements with landowners not
to dispose of their pit wastes onsite because of the potential for ground-water contamination.
                                     — 39 —

and operation standards than reserve pits (data on requirements for centralized pits operated
privately were not available to this study.) These improved standards are a response to
substantial environmental abuses of centralized pits in the past (see below).

       1.  The ground-water barrier requirements of commercial centralized disposal pits
(operating under State permits)  allow disposal of drilling fluids,  and in  some cases
produced water and other oil field wastes, which contain pollutant levels too high for onsite
disposal.  Such procedures are inherently  more controlled than typical reserve pit onsite
disposal, which usually does not include similar performance standards.  Monitoring of at
least some significant parameters (chlorides, pH) is generally required.

       2.  Closure of commercial centralized pits in most States is regulated by State
agencies (unlike onsite reserve pit closure) and therefore should be more conducive to the
protection of the environment.

       1.  Higher concentrations and higher volumes of contaminants in a centralized
disposal pit location pose a higher potential for environmental damage than onsite reserve
pits if the pit were to leak during operation, or leach contaminants after closure.

       2.  Centralized disposal pits on production sites may lack suitable ground-water
barriers, thus creating potential for contamination of these waters with leachate from the

       3.   Monitoring  of pit operations is based mostly on pH and salinity levels;
monitoring for oil and grease and heavy metal pollutants is usually not carried out.

       4.  In most cases, State regulations do not require monitoring wells to be installed
in order to detect leakage and migration of contaminants from the disposal site.
                                     — 40 —

       5.  Costs for disposal in centralized pits is significantly higher than costs of onsite
disposal.  In addition to fees paid for use of the pit, operators must pay to transport their
wastes from the drilling site.
       Regulatory Issues

       Centralized pits have been widely abused in the past.  Overtopping, improper
siting, and improper closure have been problems in several major oil-producing States.
This has led in recent years to significantly upgraded regulations or stringent repermitting
programs, the practical effect of which has been to reduce the number of commercial
facilities in operation.  Some new pits are being opened, however.

       In  some States, upgrading of centralized pit requirements may effectively eliminate
the availability of this practice.  This could pose difficulties for small operators because it
would narrow the options available to them for proper disposal of problem wastes.

       For commercial centralized pits, general regulatory issues include (1) design and
performance standards for commercial facilities, and (2) closure requirements.
       Design and Performance Issues for Commercial Facilities

       States that have had poor experience with centralized disposal pits have responded
either by implementing strict design and performance standards (e.g., Oklahoma) or by
using existing authorities to repermit centralized pits with an implicit aim of eliminating any
facility that could operate in a substandard manner (e.g., Texas).

       In  Oklahoma, there are now approximately 95 centralized pits with surface areas as
large as 15 acres and with depths up to 50 feet. Rule 3-110.2 of the Oklahoma Corporation
Commission now allows centralized pits to operate only in accordance with the following
installation and operational requirements:
       1.     None shall be constructed or maintained as to receive outside runoff water.
             The fluid level shall be maintained at least twenty-four inches below the
             lowest point of the embankment.
       2.     No pit shall be constructed in the 100 year flood  plain of any drainage
                                     — 41 —

       3.      No pit shall contain fluids with a chloride content greater than 3,500 mg/1.

       4.      No pit  shall contain a soil seal less than twelve inches thick with the co-
              efficient of permeability no greater than 10-7 cm/sec.

       5.      Two test borings shall  be drilled and  submitted to demonstrate the
              subsurface profile of the pit.

       6.      Any pit containing deleterious substances shall be lined so as to prevent the
              contamination of fresh water.  Type of  liner must be approved by the
              Corporation Commission.

       7.      Written certification that the seal  was provided and  constructed in
              accordance with approved specifications shall be provided by the supplier,
              project engineer, or independent soils laboratory.

       8.      All offsite pits shall be filled and leveled within one year after abandonment.

       9.      No  abandoned mines or  strip pits shall be used,  unless the geology and
              hydrology demonstrate that such disposal will not contaminate the fresh
              waters  of the state.

       10.    No  offsite pit shall contain deleterious substances unless the geology and
              hydrology demonstrate that such disposal will not contaminate the fresh
              waters  of the state.

       Operators of new central!zed pits are required to install and sample monitoring wells

for chlorides and pH.  The pits are periodically sampled  and checked for chloride.  If the

contents are above the chloride limit, they must be  treated  and removed to a hazardous

waste disposal site.   It is proposed to make these requirements applicable to  existing

centralized pits.

       Other States have more general  requirements. In Wyoming, the Department of
Environmental Quality regulates centralized pits.  Such pits require construction permits

from the State.  To receive these permits, the pit operators must demonstrate that pit
construction and operation will not allow a discharge to ground water by direct or indirect
discharge, percolation or filtration.  Also, it must be shown that the wastewater quality will

not cause violation  of any ground water standards and that existing geology will not allow a

discharge to ground water.
                                     — 42 —

       Ohio's response has been to take over operation of centralized pits itself.  The
contents of reserve pits may be required to be removed and transported to an Ohio State
Environmental Protection Agency regulated disposal site. This is because of potential
groundwater contamination from the pits. When reserve pit contents are to be removed, the
State requires tests to determine whether the waste can be disposed of in an approved

       In California, drilling fluids may be transported to centralized pits.  Drilling fluids
are generally received by centralized evaporation pits, but many of these pits are also used
for percolation where  no freshwater source is nearby. Some of these pits have been in
operation for years and no background water analysis is possible to determine the original
chloride content.  No State manifest is required unless the material is classified by the State
as hazardous. On the  western side  of the San Joaquin Valley, where ground waste is of
poor quality, there is a commercial facility on Federal land.  At this facility, there are 20 to
40 acres  of permitted pits for evaporation and  percolation.  The  Bureau of Land
Management has pits on Federal leases that are limited to 5 acres in area.
       Post closure issues

       Closure of centralized pits is another potential issue, since in the past some pits
have simply been abandoned, sometimes because of the bankruptcy of the original
operator.  So far as EPA has been able to determine, only one State—Louisiana—requires
operators to post a bond or irrevocable letter of credit (based on closing costs estimated in
the facility plan) and to  have  at least $1 million of liability insurance in  force to cover
operations of open pits. In other States, closure requirements may be enacted as part of the
State solid waste management programs.
       Centralized Treatment Facilities

       A  centralized treatment facility for oil and gas drilling wastes is a process facility
that accepts  such wastes solely for the purpose of conditioning and treating wastes to allow
for discharge or final disposal. They are distinct from centralized disposal pits, which do
not treat drilling wastes as part of their storage and disposal functions. The use of such
                                     — 43 —

facilities removes the burden of disposal of wastes for the operators in situations where
State regulations have imposed stringent disposal requirements for burying reserve pit
wastes onsite (one example would be Louisiana's Statewide Order 29-B).

       Centralized treatment is an economically viable alternative to onsite waste disposal
only for special drilling fluids, such as oil base muds or salt saturated brines.  It is more
economical to bury freshwater-based muds onsite than it is to remove them to centralized
treatment facilities.  The removal, hauling, and treatment costs incurred by treatment at
commercial sites will generally outweigh landspreading or onsite burial costs. A treatment
facility can have a design capacity large enough to accept a great quantity of wastes from
many drilling and/or production facilities.

       Many  different treatment technologies can potentially be  used in centralized
treatment of oil and gas drilling wastes.  The actual technology used at the particular facility
would depend on a number of factors.  One of these factors is type of waste.  Currently,
some facilities are designed to treat solids  (muds and cuttings), while others are designed to
treat produced waters, completion and stimulation fluids.  Some facilities can treat a
combination of wastes. Other factors determining treatment technology include facility
capacity, discharge  options and requirements, solid waste disposal options, and other
relevant State or local requirements.
       Environmental Performance

       Experience with centralized treatment is limited. Up until recently it has been used
only for treatment of offshore wastes;  its use in recent years for onshore wastes is
commercially speculative, being principally a commercial response  to the anticipated
impacts of stricter new State rules (such as in Louisiana).  The operations have not been
particularly successful as business ventures so far.   Potentially, however, centralized
treatment facilities offer significant environmental advantages over conventional burial of
wastes in a reserve pit.
                                     — 44 —


       1. Centralized treatment can take advantage of economies of scale to offer more
advanced technical practices, including monitoring of site performance, than are otherwise
typically used by operators.

       1  They can be more conveniently inspected and supervised by State personnel.

       2 Centralized treatment is a closed loop operation wherein all of the drilling fluids
can be kept in a controlled, monitored system until the inert cuttings are separated from the
pumpable fluids.  The cuttings are suitable for landfilling (onsite or offsite) or for use as
road aggregate.  The pumpable fluids can be injected into disposal wells at the centralized
treatment facility.

       4. Operation of centralized treatment facilities (as  compared to onsite burial of
reserve pit wastes) allows for more rigorous control of the materials handled including
sampling and monitoring of these materials prior to treatment in order to establish pollutant
levels and optimum methods of treatment needed to prepare the wastes for environmentally
acceptable disposal.

       1. Improper operation and inadequate monitoring of centralized treatment facilities
can result in significant environmental impact to groundwater in the vicinity of the treatment
facility, i.e., improperly dewatered drilling muds, if stored at the facility landfill, can result
in leaching of high chloride levels into the groundwater.
       Regulatory Issues

       All of the major oil and gas producing States allow properly permitted centralized
treatment and disposal facilities for handling reserve pit wastes.9  (A few of the minor
producing States do not allow them, including Alabama and Mississippi.) However, some
of these operations have been only marginally economic, and, upon cessation of operations
9      Some of the central treatment facilities for reserve pit wastes also accept brines for subsurface
injection, sometimes preceded by treatment to remove heavy metals or suspended solids. (See discussion
below on Subsurface Injection.)
                                      — 45 —

because of business failure, have lacked funds for proper maintenance or closure of these
facilities, creating potential for eventual ground-water contamination.

       One example of a centralized drilling waste treatment system is found in California.
Drilling fluids at some drilling sites are accumulated in disposal bins. The contents of these
bin are removed by vacuum pump trucks and transported to a facility that uses a proprietary
process to convert the sludge into a substance having a gel-like consistency that hardens in
two hours. Metals within the drilling fluids are converted into stable, nonleachable metal
silicates. The final product can be disposed of by landfill or can be used for backfilling or
landfill covers  (Yen Virotek,  1986).  California does not require a State Manifest  for
transporting material unless it is determined to be hazardous under State regulations.

       Louisiana has approximately 33  commercial centralized facilities currently in
operation.  Some accept only brines, while others accept mud and brine. They must be
permitted for operation by the State.
       Commercial  Landfarming

       Landfarming is a method for converting reserve pit waste material into soil-like
material through soil incorporation. The method can also be used to process production
wastes, such  as production tank bottoms, emergency pit cleanouts, and scrubber bottoms
(see discussion below).  Incorporation into soil uses dilution, chemical alteration, metals
adsorption, and biodegradation mechanisms of soil bacteria to reduce waste constituents to
acceptable soil levels consistent with intended land use.

       The approach is basically simple. Solid wastes are distributed over the land surface
and mixed with soils by mechanical means.  Frequent turning or disking of the soil is
necessary to ensure uniform biodegradation. Ratios are normally about 1:4 waste to soil in
order to restrict concentrations of certain pollutants in the mixture (particularly chlorides
and oil).  (Tucker, 1985).  Liquids can be applied to the land surface by various types of
irrigation including sprinkler, flood, and ridge and furrow. Detailed landfarming design
procedures are discussed in the literature (Freeman and Duell, 1984).
                                     — 46 —

       Landfarming methods have been applied to reserve pit wastes in commercial offsite
operations.  The technique provides both treatment and final disposition of salts, oil and
grease, and  solids.  Landfarming eventually produces large volumes of soil-like material
that must be removed from the area to permit operations to continue. Requirements for
later reuse or disposal of this material must be determined separately.
       Environmental Performance

       Landfarming is generally done in agricultural areas large enough to incorporate the
volume of waste to be treated. Especially in commercial landfarming operations, where the
volume of materials treated within a given area is large, steps must be taken to ensure
protection of surface and ground water.   It is  important, for instance, to  minimize
application of free liquids so as to reduce rapid transport of fluids though the soils.

       The  process is most suitable  for the treatment of organics, especially the lighter
fluid fractions that tend to distribute themselves quickly into the soil, because of the action
of biodegradation.  Heavy metals are also "treated" in the sense that they are adsorbed to
soil particles, presumably within a few feet of where they are applied, but the capacity of
soils to accept metals is limited.  Similarly, the ability of the soil to accept chlorides and still
sustain beneficial use is also limited.

       1. Because the predominant constituents in water-based drilling fluids are bentonite
clay and barite—materials that are commonly found in surface soils—landfarming is an
appropriate technique for most drilling waste disposal  (Freeman  and Duell, 1984).

       2. The dilution of salts and the breakdown of organics occurs more efficiently by
working  wastes into the soil  surface than it does  when the same materials are buried in
more concentrated form and away from aerobic soil bacteria, as  in conventional reserve pit
burial (Lloyd, 1985).10
                                     — 47 —


       1.   One of the most serious environmental problems with this method is the
possible high chloride content of the waste/soil mixture, since salts (sodium, calcium, and
potassium) can be harmful to crops after closure, assuming land is farmed (Lloyd, 1985).
Excessive application of heavy metals may also be a significant issue.

       2.  Landfarming requires open, relatively flat terrain of suitable soil texture to allow
heavy equipment work and prevent runoff and/or erosion.

       3.  This method is not suitable for all climates and all soil types.

       4.  Water tables must be at sufficient depth to prevent contamination.

       5.  If serious damage to surface soil results from improper landfarming manage-
ment, long-term restoration methods must be implemented to repair the site.
       Regulatory Issues

       The chief regulatory issues  of concern with this practices are (1) its degree of
availability in various States, especially the major oil-producing States, and (2) reuse of
materials generated through the landfarming process.

       The States studied that completely prohibit commercial landfarming of reserve pit
wastes include Oklahoma and Kansas. Environmental conditions in Michigan prevent any
significant amount of soil farming.  Drilling fluids in that State are generally too high in
sodium and chloride ions to  permit disposal of the  fluids or cutting at the surface.
Accidental discharge of drilling fluids on farm land has resulted in extensive damage. The
use of potassium-based drilling fluids  in land farming is being  considered in areas of
Michigan where several hundred feet of salt section is not encountered. (Cooper, 1985).

       In  Alaska, California, Colorado,  New Mexico,  Ohio, West Virginia, and
Wyoming, it appears to be permissible to  operate an offsite commercial landfarming
operation based on existing State regulations, although in Alaska, the practice appears to be
                                     —  48  —

infeasible (especially on the North Slope) either because of climate conditions or for lack of

large areas of flat, arable, land.  Some of these States require detailed permit applications

and hearings before operations begin.

       Texas, for instance, allows commercial landfarming after application and hearings.

The  following information must be submitted to the Texas Railroad Commission for a
commercial landfarming operation:

       1.     Methods used to apply and mix the drilling fluid into the soil (Necessary to
              prevent runoff and overloading).

       2.     Area in feet that will be covered by each tank truck load.

       3.     Map showing location of proposed landfarming site.

       4.     Description of proposed site by owner, tract size, and location.

       5.     Description of the contour of the disposal site, including water courses of

       6.     Estimated chloride concentration of drilling fluid to be landfarmed.

       7.     Plans to control access to the facility.

       8.     Plans to control  storm water runoff and to retain incoming wastes during
              wet weather, including plans to prevent runoff into creeks.

       9.     Plans for closing the disposal site when operations cease, including an
              estimate of time required for closure.

       Where landfarming is an available technique, States vary in the degree to which
they specify which wastes may be legally landfarmed. Louisiana Statewide Order No. 29-

B, for instance, has a detailed list of exclusions to prevent chemically unsuitable wastes

from being landfarmed. The following materials are specifically excluded from disposal in
commercial landfarming facilities in that State (Wascom, 1986):

       1.     Drilling fluids and raw drilling fluid components or additives which have
              not been used in the drilling or workover of an oil, gas, or injection well.
              Only waste drilling fluids  used in  the drilling of an identifiable well may be
              accepted by commercial facilities.
                                     — 49 —

       2.      Washrack sump wastes (solids or wash water) generated by the cleaning of
              oil field related equipment (trucks, packers, production equipment, etc.) at
              oil field service companies.
       3.      Waste water from salvage oil operators who receive waste oil taken from
              service stations, fuel tanks, and other industrial sources.
       4.      Wash water from oil field related carriers (vessels) that have transported
              hazardous waste or material.
       5.      Wash water generated in the cleaning of fuel tanks, engine rooms, bilges,
       6.      Bilge water.
       7.      Waste motor oil or hydraulic fluid.
       8.      Any other wastes or materials not specifically identified in Statewide Order
              No. 29-B or identifiable to a particular lease or well and which are regulated
              under other applicable State or Federal programs.

       Other States have standards that specifically exclude chloride levels, pH, and spent
acids in wastes to be landfarmed.   Louisiana's regulations also contain  detailed
requirements for permitting and operation of commercial landfarming facilities (Sections
13.2 and 13.3).
       Reuse of Byproduct Materials Generated By Land/arming

       Louisiana allows some re-use of materials treated at commercial facilities.  Materials
determined to meet certain standards and considered nonhazardous after treatment can have
a limited re-use, such as a daily sanitary landfill cover or in roadbed construction. The
State is concerned that any such re-use not effect any part of the food chain.
       Reconditioning and Reuse  of Drilling Media

       Reconditioning and reuse of drilling media is currently practiced in only a few well-
defined situations.  The first is reconditioning of oil-based muds, which is almost universal
because of the high cost of these fluids. The second is reuse of reserve pit fluids as "spud"
muds (i.e., the muds used  in drilling the initial  shallow portions of the  hole) where light-
                                     — 50 —

weight muds can be used. Another generic approach is in the plugging procedure for well
abandonments. Pumpable portions of the reserve pit are transported by vacuum truck to
the well being closed. The muds (in some States having a minimum density under State
regulation) are placed in the wellbore to isolate possibly productive and salt-water strata
from each other and from ground water reservoirs.

       These limited reconditioning and reuse approaches are of little consequence from
the broader environmental standpoint because oil-based muds are used in only a small
minority of wells  (and must eventually be disposed of by other means anyway, and
because spud muds, being composed almost entirely of innocuous constituents) probably
have the lowest potential of any drilling fluid to cause environmental damage. These two
examples, however, raise the broader issue  of minimization  of drilling fluids as an
approach to limiting the environmental impacts of drilling-related wastes.

       Conventional freshwater muds used in the deeper portions of typical wells are
generally not deliberately recycled or reused as drilling media, but the potential for at least
some increased recycling and reuse  appears to exist primarily through more efficient
management of mud handling systems. Specific attempts to minimize the use of muds are
discouraged, at present, by  two factors: (1) drilling  mud  systems  are operated by
independent contractors, for whom sales of muds are a primary source of income, and (2)
the central concern  of all parties is success of the well, resulting in a general bias in favor of
using virgin materials.

       In spite of these economic disincentives, recent industry studies suggest that the
potential for decreases in drilling mud use are significant (AMOCO, 1985), perhaps as high
as 30 percent.  If this is so, "waste minimization" could emerge  as a promising approach
for management of oil and gas related wastes.
       Environmental Performance

       Experience  in reconditioning and reusing spud muds and oil-based muds does not
provide any estimate of specific benefits that might be associated with recycling or reuse of
most conventional drilling muds. Benefits are therefore speculative at this time, but generic
the approach is promising; they could possibly include lessening of the potential of spills
                                    — 51 —

related to reserve pit overtopping, and a broad proportional reduction in impacts on surface
and  ground water.  On  the other hand, recycling of muds would  tend to increase
contaminant levels within the muds, making them more difficult to dispose of properly in
the long run.

       1.  Reuse of muds minimizes the amount of waste that must ultimately be disposed
of by other means.

       1.  Continued recycle/reuse can cause  buildup of contaminants in the mud,
potentially making it more difficult to dispose of the purged waste muds.
       Regulatory Issues

       Due to the limited use of this highly site-specific method, most State regulations are
silent on the practice. However, most States specify the use of heavy, mud-laden fluid
between cement plugs in the plugging and abandonment procedures for production or
service well closures.
Production-Related Wastes

       Waste Characterization
       Produced Waters

       When oil and gas are produced, water is often produced simultaneously.  This is
known as produced water, formation water, or brine (because of its generally high chloride
levels).  Produced water may originate from the reservoir or from waterflood treatment of
the field (secondary recovery).  The quantity of water produced is dependent upon the
method of recovery, the nature of the formation, and the length of time the field has been
producing: generally, the ratio of produced water to oil increases with time.

       Most produced water is saline.  Occasionally, chloride  levels may be low enough
(i.e., less than 500 ppm chlorides) to allow the water to be  used for beneficial purposes
                                    — 52 —

such as crop irrigation or livestock watering. More often salinity levels are considerably
higher, ranging from a few thousand parts per million to over 100,000 parts per million.
Seawater, by contrast, is typically about 19,000 ppm chlorides, which tends to put limits
on the possible discharge of production brines to coastal waters or brackish estuaries.

      Produced water also tends to contain trace quantities of petroleum hydrocarbons
(especially lower molecular weight compounds), higher molecular weight alkanes and
polynuclear aromatic hydrocarbons, and metals.  It may also contain biocides and other
additives associated with the use of production chemicals; these can include coagulants,
corrosion inhibitors, cleaners, dispersants, emulsion breakers, paraffin control agents,
reverse emulsion breakers,  and scale inhibitors (see Table 2 above).  Other inorganic
compounds may include ammonia and hydrogen sulfide.

      Lower molecular weight hydrocarbons are more soluble in produced water than are
the higher molecular weight compounds.  They include the light aromatics—benzene
through napthalene—and may be present in produced water in concentrations of between
10 and 20 ppm.  An EPA study of brines produced at offshore facilities (EPA, 1985)
estimated that at these concentration ranges, discharge  rates at larger facilities for such
compounds as benzene, toluene, and ethylbenzene could exceed 10 kg/day.

      Radioactive materials, such as radium, have been found in some oil field produced
waters. RA-226 activities in filtered and unfiltered produced waters have been found to
range between 16 and 395 picocuries/liter; Ra-228 activity may range from 170 to 570
pa/liter (EPA, 1985).
      Low Volume Production Wastes

      Low volume production-related wastes include many of the chemical additives
discussed above in relation to drilling (see Table 2).

      Onsite Management Methods

      Onsite management methods include subsurface injection, the use of evaporation
and percolation  pits, discharge of produced waters to surface water, and storage  or
                                    — 53 —

(occasionally) disposal in other production-related pits, such as emergency pits or brine
handling pits.
       Subsurface  Injection

       Today, subsurface injection is the primary method for disposing of produced
waters from onshore operations.  Nationally,  approximately 60 to 70 percent of all
produced waters are disposed of in injection wells permitted under EPA's Underground
Injection Control (UIC) Program. In the major oil-producing States, over 90 percent of
wastes are disposed of by this method.  Disposal may be done at injection wells either
onsite or offsite, but the procedures are the same in either case.  (In this discussion, the two
are combined.)

       Underground injection is a produced water disposal method in which the waste is
placed into subsurface formations. The sequence of steps used includes:
       •       Separation of free oil and grease from the water or brine,
       •       Tank storage,
       •       Filtration,
       •       Chemical treatment (coagulation, flocculation, and possibly pH adjustment),
              and, ultimately,
       •       Hydraulic pumping or vacuum (gravitational) systems.

       The two types of subsurface injection are enhanced recovery and waste disposal.
In secondary recovery projects, produced water is generally reinjected into the same
reservoir from which the water was initially produced.  In waste disposal applications,
produced water is injected into shallower, saltwater formations, older depleted producing
formations, or nondepleted formations (where injection tends to increase ambient pressure
in the strata above preexisting levels).

       Produced water is injected to nonproducing formations (or "safe horizons") by two
methods.  The method often preferred by State regulatory agencies is the use of disposal
                                     — 54 —

wells specifically drilled, cased, and completed to accommodate brine.  Many disposal
wells are, however, converted producing wells and are usually operated by the leaseholder.
If the lease is large enough and there are no producing wells that could be converted to
disposal wells, the leaseholder may utilize a contract disposer for offsite disposal.

       Figure 2 displays a typical saltwater disposal well pumping into a zone located
below the freshwater table (Elmer E. Templeton and Associates, 1980). New wells may be
constructed for this purpose  or old wells may  be  retrofitted to meet construction
requirements.  Converted production wells are by far the more prevalent type. Figure 3
and  Figure 4 illustrate these techniques (Templeton, 1980).

       Wells used  for produced water  must be carefully constructed so as  to protect
freshwater aquifers.  When old wells are retrofitted for brine disposal, ground-water
contamination may occur as a result of casing failure. Consideration must also be given to
the possible presence of abandoned wells in the vicinity of a proposed disposal well site.
Figure I-11  illustrates the potential for freshwater contamination created by abandoned
wells (Illinois EPA, 1978).

         Although not a very widespread practice, some produced water is disposed of
through the use of annular injection in producing wells. In this method, produced water is
   injected through the annular space between the production casing and the tubing.  The
                                     — 55 —


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disposal zone is shallower than the producing zone in this case. This method has a much
higher potential to contaminate fresh groundwater because of (1) the vulnerability of the
single protective string of casing, and (2) the more involved and  expensive  methods
necessary to test the mechanical integrity of the casing. The highly corrosive  effect of
produced saltwater on the casing may result in casing leak(s), which are difficult to repair
and may go undetected for long periods.  A method of testing the mechanical integrity of
the casing, through the annulus, without removing the tubing and  packer, is by using
radioactive tracers and sensing devices. This method involves the pumping of water spiked
with a low-level radioactive tracer into the injection  zone,  followed by the  use of a
radioactivity-sensing logging tool through the tubing string. This method should detect any
shallow casing leaks or any fluid migration between the casing and the bore hole. Most
State regulatory agencies discourage annular injection and usually allow the practice only in
small volume, low pressure applications.
       Environmental Performance

       From the environmental standpoint, the inherent issue with disposal of chloride -
containing waters is isolation of the chlorides from potable waters and arable land (because
of their high solubility in water, there is no practical way to immobilize them chemically, as
can be done  with heavy metals and many other pollutants associated with oil and  gas

       Although there is theoretically no method for permanently  disposing of chloride-
containing waters, if properly done, subsurface injection is among the most effective and
environmental sound methods of disposal.  The two potential problems with injection are
(1) migration of wastes out of the intended receiving formation, and (2) inadvertent
injection of wastes into the wrong formation (such as a potable aquifer).

       Ordinarily, the most desirable method of disposal is to inject  wastes into a  saltwater
reservoir comparable in content and pressure to that from which it was extracted.  This can
be done simply by reinjecting produced water back into its original formation, often as part
of a waterflooding program to enhance recovery from the field.  Migration is more likely if
wastes are injected into a nondepleted reservoir, the addition of more fluids into such zones
                                     — 59 —

increases pressures and thereby increases the potential for leaks between strata (such as into
adjoining reservoirs or into useful water supplies).

       Migration out of the intended  receiving zone can also occur if there  is any
connection between the saline layer and a freshwater layer.  In such cases, chloride ions
will tend to migrate to the freshwater layer, thereby contaminating it. Migration problems
are most likely if unplugged or improperly plugged wells of any type exist in the area in the
strata of concern.  Often in older oil or gas fields many such wells may exist, often without
proper documentation of their closure or even their location.

       Inadvertent injection of wastes into improper formations can occur because of leaks
in the casing of the injection well. The  EPA UIC program requires periodic mechanical
integrity tests (MIT) to ensure proper well performance. Such testing can detect problems
if it is conscientiously conducted on schedule. Response is generally to suspend disposal
operations until the well is repaired, or to plug and abandon the injection well.  Major
factors influencing well failure include the design, construction, and age of the well itself
(converted producing wells, being older, are more likely to fail than newly-constructed
Class II injection wells) and the corrosivity of the injected fluid (which varies chiefly by its
chloride content).  Another  potential issue is the nature of the mechanical integrity test
itself.  Test requirement vary among States, making it theoretically possible for a well that
might pass a test in one State to fail the test imposed by another.

       1. The primary advantage of  underground injection is that produced waters  are
disposed of in formations far below any usable groundwater reservoirs.

       2.  Mechanical integrity testing on injection wells can detect problems and allow
remedial action to be taken.

       1.  Fresh water aquifers may be contaminated by  undetected shallow casing leaks.
                                     — 60 —

       2.  Freshwater aquifers may be contaminated in shallow disposal wells by fluid
migration related to poor cement bonding between the borehole and the production/surface

       3.  Another potential form of freshwater contamination is through  underground
communication with improperly plugged, abandoned wells in the immediate vicinity of the
injection well. Many of these wells were abandoned before plugging regulations were in
place, and often their locations are not known and may no longer be evident.
      y-. The potential exists for contamination of surface water and vegetation because of
leaks in flowlines and other associated surface facilities.
      Regulatory Issues

      Injection of produced saltwater in Class n wells is Federally regulated through the
Underground Injection Control (UIC) Program.  The Federal requirements for injection
well regulations  are  specified in the Safe Drinking Water Act  of 1974, which is
administered by  the Environmental Protection Agency.  EPA's regulations include
construction, permit, operating, monitoring, and reporting requirements.  Most of the
major producing States, however, have primacy over their UIC program and may have
additional, more stringent regulations.

      Under the UIC program, underground injection of produced water in Class II wells
is regulated at the Federal level.  With respect to requirements for mechanical integrity
testing of injection wells, the federal law governing the  UIC program states that "an
injection well has mechanical integrity if: (1) There is no  significant leak in the casing,
tubing or packer; and (2) There is no significant fluid movement into an  underground
source of  drinking water through vertical channels adjacent to the injection well bore."
The  term "significant" is not defined, allowing for considerable variation in the way
                                    — 61 —

individual States interpret MIT tests, and therefore there may be significant variation in
what constitutes a sound well from State to State.

       Under the UIC program there are specific, stringent, requirements for construction
of Class n wells, all or some of which may be avoided in practice, however.  For example:
"Where a State did not have regulatory controls for casing and cementing prior to the time
of the submission of the State program to the Administrator, the Director need not apply the
casing and cementing requirements in paragraph (b) of this section if he submits as a part of
his application for primacy, an appropriate plan for casing and cementing of existing,
newly converted, and newly drilled wells in existing fields, and the Administrator approves
the plan."

       To date, there is considerable variation in the actual construction of Class n wells in
operation nationwide. This is primarily due to the large number of injection wells in use
prior to the implementation of the UIC program. Construction ranges from wells in which
all  water zones are fully protected with casing and cementing, and the injection zone
isolated with cement to shallow multiple string wells with little or no cement.

       While the UIC legislation spells out specific monitoring requirements such  as
monitoring of injection pressures, volumes, nature of fluid being injected,  and five-year
tests for mechanical integrity, only the MIT results are reported by the State to the Federal
level. When these tests are reported, actual results are not provided. Reported figures are
only on wells passing and wells failing. As test results are presented in pressure lost over
time, it would be beneficial to see the actual results instead of simply wells passing versus
wells failing.  In the instance of injection wells used for hydrocarbon storage  and enhanced
recovery, well may "be monitored on a field or project basis rather than on  an  individual
well basis by manifold monitoring.  Manifold monitoring may be used in cases of facilities
consisting of more than one injection well, operating with a common manifold. Separate
monitoring systems for  each well are  not  required provided the  owner/operator
demonstrates that manifold monitoring is comparable to individual well monitoring." To
date, about 70 percent of all Class n injection wells have been tested nationwide. Some
EPA regions have tested more than 70 percent, others have tested fewer than 70 percent of
the Class n injection wells in the region.
                                     — 62 —

       Injection pressures are not reported at the Federal level under the UIC program.

       The definition of fresh water to be protected varies significantly from State to State.
Generally, lower quality water occures at greater depths, thus the quality of water to be
protected determines the depth required for cemented surface casing. Some examples:
Texas  defines fresh water as that containing  3,000 ppm TDS; Louisiana, 1,500 ppm;
California—not quantified; New Mexico, 5,000 ppm; Alaska—not defined; Mississippi-
10,000 ppm; West Virginia—no standards (Arthur D. Little, Inc., 1979).

       Major regulatory issues of concern include (1) design, construction, operation, and
testing requirements, (2) review requirements concerning the location of other producing or
nonproducing wells in the vicinity of the injection well, and the degree of specification
required concerning the formations to be protected, and (3) whether or not annular injection
of brines is allowed.
       Design, Construction, Operation, and Testing

       Although State requirements for new injection wells are quite extensive, not every
State has required the full use of all technology which might be deemed the "best available"
in the  industry. In  addition, State  requirements have evolved over time and most wells
operate with a lifetime permit. As a result, not all existing injection operations meet the
current construction requirements in State regulations.

       Nearly all State regulations require permits for all disposal or enhanced recovery
injection wells, whether new  or converted.  Construction standards include requirements
for cemented surface casing through freshwater zones, cement plugs set immediately above
the injection zone.  Most states require injection through tubing and packer (a downhole
sealing device which plugs the space between the tubing and casing) set immediately above
the injection zone.

       In addition to initial pressure testing prior to initiation of service, States (including
those that do not have primacy under the  UIC program) also require  monitoring or
mechanical integrity tests of Class II injection wells at least once every five years.  In lieu
of such a casing  pressure test, the operator may, each month, monitor or record the
                                     — 63 —

pressure in the casing/tubing annulus during actual injection, and report the pressure
       Proximity to Other Wells and to Protected Aquifers

       States may request information on the permit application about the proximity of the
injection well to potable aquifers, or to producing wells, other injection wells or abandoned
oil or gas producing wells within a half-mile radius. In Oklahoma, for instance, additional
restrictions are placed on UIC Class II wells within a 1/2 mile of an active or reserve
municipal water supply well unless the applicant can "prove by substantial evidence" that
the injection well will not pollute a municipal water supply. New Mexico regulations are
similar to most other States, but they restrict saltwater disposal to receiving zones that
contain 10,000 mg/1 of TDS (total dissolved solids) or more.

       Most  States require operators to submit some  information on nearby wells.
Administrative review of this information is supplemented by public hearings in many
states. Although these requirements exist, it is important to recognize that:
       •       Policy on review  of nearby wells varies widely from State  to State, and the
              injection well operator has  had only  a limited responsibility to identify
              possible channels of communication between the injection zone and
              freshwater zones.
       •       Many injection operations predate current regulations on the review of
              nearby wells and because of "grandfather" clauses are exempt.
       •       Many States do not  specifically protect aquifers by  identifying the
              quantitative level of freshwater to be protected with surface casing or other
              construction measures (A.D. Little, 1979).
       Annular Disposal

       Most States prohibit annular disposal of brines altogether.  Ohio, however, allows
annular injection  with limitations on maximum volume only where used  under
gravity—pressurized annular injection is not allowed.
                                    — 64 —

       Evaporation  and  Percolation Pits

       Evaporation and percolation pits (see discussion above) are also used for produced
water disposal. An evaporation pit is defined as a surface impoundment that is lined by a
clay or synthetic liner. An evaporation/percolation pit is one that is unlined. No other
treatment, except for spraying to enhance evaporation, is performed on the pit contents.
       Environmental Performance

       Evaporation of brines can occur only under suitable climatic conditions, which
limits the potential use of this practice to the hotter, dryer producing areas within the States.
Percolation of brines into soil is not inherently restricted, but has been allowed more often
in areas where the ground  water underlying the pit areas is already  saline to a level not
usable for beneficial purposes (irrigation, livestock watering, or drinking water).

       1.  In a properly designed evaporation pit, produced water is contained in an
impermeable impoundment  to allow for natural evaporation, settling of solids and
skimming of oil and grease.  Chlorides are therefore unable to affect the groundwater or
surface water as long as the liner is intact.

       1. The potential for ground and surface water contamination exists by seepage of
pollutants through permeable soils underlying the pit. Most brine pits are unlined.  Where
they are lined, liner integrity and durability are critical to ground water protection;
impermeability must be maintained indefinitely after closure as well as during operation.
                                     — 65 —

       Regulatory Issues

       Evaporation pits are allowed in a few States (sometimes only in restricted areas of
States). Significant regulatory issues include: (1) availability (whether or not the practice is
allowed at all), and (2) monitoring requirements (particularly if lined evaporation pits are
used above useable aquifers).

       Evaporation and percolation pits were much more widely used in the past than they
are today. Because of the potential for ground-water contamination and the availability of
the more environmentally sound disposal practice of underground injection, produced
water disposal pits are usually not allowed by most States. In Ohio, for instance, where
saltwater disposal is one of the major environmental problems in the  State, evaporation or
percolation pits are not allowed.  Under requirements of the revised rules promulgated in
April,  1985, "no pit or dike shall be used for  the ultimate disposal of brine."  Earthen
impoundments may, however, be used for the  temporary storage of brine in association
with a salt water injection or enhanced recovery well.

       Some  States discriminate  between commercial disposal  pits and privately-
constructed disposal pits.  In Oklahoma, for instance, only commercial offsite pits are
allowed. These must be constructed and operated in a manner "to prevent the escape of
any deleterious material." Chloride content of commercial pits, which in some cases serve
individual wells, are limited to 3,500 mg/1 and may be sampled periodically to enforce the

       Permits can be obtained in some other States, but these States generally impose a
strict burden-of-proof to demonstrate that there is no usable groundwater or that no seepage
can occur at the disposal site. In Wyoming, which has among the more permissive policies
regarding use of disposal pits, the Oil and Gas Conservation Commission has jurisdiction
over the permitting, construction and management of all pits serving a single well.  The
Commission requires permits for pits receiving  more than 5 barrels of produced water per
day.  Such permits include requirements for liners only in special cases where "potential for
communication between the pit contents and surface waste or shallow ground water is
                                     — 66 —

high." The Commission may administratively approve field-wide or area-wide applications
covering earthen retaining pit construction and operation.

       States that have historically had relatively lax regulations have revised or are
revising them substantially.  New Mexico, for instance, is now revising its regulations
pertaining to use of these pits above areas of the Ogallala Aquifer in the southeast portion of
the State. Regional orders determine requirements for saltwater storage or disposal pits in
the petroleum producing areas of the State. The use of unlined pits are prohibited in these
areas of the state, although exemptions are made for low-volume discharges. Lined pits are
permitted on the basis 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."

       Under the new Statewide Order No. 29-B,  all production pits in Louisiana must be
lined with natural or artificial liners and must meet a hydraulic conductivity limitation of 1 x
10'7 cm/sec.  Salt water disposal pits located near inland tidal waters are exempt from liner
requirements provided they are designed to remove residual oil and grease.

       In Texas, 388 centralized commercial disposal pits were known to be in operation
as of December, 1986, though some undocumented sites may also exist. These pits are
regulated by the Texas Railroad  Commission,  which is currently in the  process  of
examining and re-permitting the operations of each of the known operational pits. Disposal
pits can operate without liners if  the operator can prove to the Commission that pit
operation will not adversely affect ground water. Lining requirements are determined on a
case-by-case basis.  So far only about 13 of these pits have received operating permits;
these were for low chloride applications or where there was no possibility of detrimental
effects on fresh subsurface water. The others are either pending or have been denied.  The
practical result of this policy will be to drastically reduce the number of centralized pits in
                                     — 67 —

       Discharge of Produced Waters to Surface Water Bodies

       Discharge to surface water bodies is divided into (1) coastal or tidally influenced
waters and (2) agricultural and wildlife use categories. Discharge occurs after the produced
water is treated to control pH and and a variety of common pollutants, such as oil and
grease, total dissolved solids, and sulfates. Typical treatment methods include simple oil
and gas separation followed by a series of settling  and skimming pits.  Although more
sophisticated physical-chemical and biological processes are available for  wastewater
treatment, they are normally not employed because of their high operating cost.
       Environmental Performance

       Direct discharge of produced waters, even after pretreatment of conventional
pollutants, should be limited to receiving waters that can accommodate whatever levels of
chlorides the waste may contain. It is rare that produced waters have low enough chloride
levels (< 500 ppm) to be used directly for beneficial purposes such as livestock watering or
crop irrigation.

       1.  Low-salinity produced water may be used for beneficial uses such as for
livestock watering, crop irrigation or wildlife, but, as noted, this is rare.

       1.  The potential exists for oil  spills caused by separation equipment malfunction or
over-topping of pits after heavy rains.

       2.  Groundwater may be contaminated by heavy aromatics such as benzene that is
found in significant concentrations in produced saltwater (CENTEC, 1987).

       3.  Adverse effects on stream sediments may occur, indirectly causing adverse
impacts on stream flora and fauna.
                                       68 —

       Regulatory Issues

       This practice is controlled under the "Agricultural and Wildlife Water Use"
subcategory under the onshore segment of the Federal Oil and Gas Extraction Industry
Effluent Limitations Guideline. Permits are issued under the National Pollution Discharge
Elimination System (NPDES).
       Federal Effluent Limitation Guideline

       The Agricultural and Wildlife Water Use subcategory, defined in 40 CFR Part 435,
Subpart E, as authorized by the Clean Water Act, addresses the use of produced water that
is of good enough quality to be used for livestock watering or other agricultural uses.  It
was established because many western States petitioned EPA to allow produced water to be
discharged and used for agricultural and wildlife purposes. Investigation showed that in
arid portions of the Western United States, low-salinity produced waters were  often a
significant (if not the only) local source of water used for those purposes.

       To qualify for the use of produced water under Agricultural and Wildlife use, a
facility must be located west of the 98th meridian.  This boundary was chosen because it
approximates the boundary of relevant geographic and arid or sem-arid climatic regions that
influenced the creation of the subcategory. Also, in order to qualify the facility must show
that the discharge water will be used for agriculture or wildlife purposes.  States using this
disposal method include the Rocky Mountain States (Colorado, Wyoming, Montana) and
California, all of which suffer from scarce surface water.

       The framework for regulating treatment and disposal methods used in coastal areas
is derived from the Coastal subcategory of the onshore segment of  the oil and  gas
extraction industry effluent limitations guideline, defined in 40 CFR 435, Subpart D, as
authorized by the Clean Water Act. The Coastal subcategory defines "coast" as "any body
of water landward of the territorial seas, or any wetlands adjacent to such waters."  There
are  inconsistencies from State to State for the issuance of discharge limits under the
Agricultural and Wildlife Use.
                                     — 69 —

       For instance, there are eighteen permitted production facilities in Montana, with a
total daily discharge of 14,000 barrels per day.  Discharge limits are imposed on total
dissolved solids (TDS) oil and grease, phenols and metals.

       Wyoming has issued 550 NPDES permits in this category with effluent limitation
              Sulfates       3000 mg/1
              Chlorides     2000 mg/1
              pH   6.5-8.5
       •       Oil and grease 10 mg/1

       Colorado, similar to those of Wyoming, has a few facilities with similar effluent

       There are at least twelve permits in the Fresno office of California's Central Valley
Regional Water Quality Control Board.  Effluent limitations are similar to the other stages
except for boron which is set at 1 mg/l.Coastal Discharge.  ..

       The Texas Railroad Commission allows discharge of produced water into coastal
areas under individual permits.  Sufficient collecting and skimming pits must be maintained
to prevent any oil from entering the tidal waters. Random samples of the discharged brine
must be tested for oil content every 30-40 days.

       West of the 98th meridian, the Railroad Commission permits limited "beneficial
use" of produced waters.

       In  Louisiana, discharge of produced water is permitted into brackish and saline
areas, with a discharge limit for oil and grease  of 72 mg/1 (monthly sample).  A report is
required on monthly volumes discharged and on oil and grease, and an annual report on
chloride level  (though no limit is established).  The discharge must be to an open flowing
                                     — 70 —

water body of sufficient volume to prevent stratification and significant buildup of ambient

       Exceptions to the restriction against discharges in freshwater bodies are given for

the Mississippi River and its tributaries below Venice, Louisiana and the Atchafalaya River
below Morgan City.

       New regulations in November, 1985 required for the first time that all of the above
discharges be permitted.  A mailing was sent out in 1986 requiring filing of information

and permit applications  for current discharges.  When these are received and evaluated,

discharges actually occurring in freshwater areas not covered  by the above exceptions

would be required to end.

       Other Production-Related  Pits


       A wide variety of pits are used for ancillary storage and management of produced

waters and other production-related wastes.  These can include:11

       1.     Basic sediment pits: Pit used in conjunction with a tank battery for storage
             of basic sediment removed from a production vessel or from the bottom of
             an oil storage tank. [Also referred to as burn pits.]

       2.     Brine pits: Pit used for storage of brine used to displace hydrocarbons from
             an underground hydrocarbon storage facility.

       3.     Collecting pits: Pit used for storage of produced water prior to disposal at a
             tidal disposal facility, or pit used for storage of produced water or other oil
             and gas wastes prior to disposal at a disposal well or fluid injection well. In
             some cases one pit is both a collecting pit and a skimming pit.

       4.     Completion/workover  pit:  Pit used for storage or disposal of spent
             completion fluids, workover fluids, and drilling fluid, silt, debris, water,
             brine, oil, scum, paraffin, or other materials that have  been cleaned out of
             the well bore of a well being completed or worked over.

       5.     Emergency produced water storage pit: Pit used for storage of produced
             water for limited period of time.   Use of the  pit is necessitated by a
             temporary shutdown of a disposal well  or fluid injection well and/or
11      List adapted from Texas Railroad Commission Rule 8, amended March 5,1984.
                                     —  71

              associated equipment, by temporary overflow of produced water storage
              tanks on a producing lease, or by a producing well loading  up with
              formation fluids such that the well may die.  Emergency produced water
              storage pits may sometimes be referred to as emergency pits or blowdown

       6.     Flare pit: Pit that contains a flare and that is used for temporary storage of
              liquid hydrocarbons that are sent to the  flare during equipment malfunction,
              but that are not burned.  A flare pit is used in conjunction with a  gasoline
              plant, natural gas processing plant, pressure maintenance of repressurizing
              plant, tank battery, or a well.

       7.     Skimming pit:  Pit used for skimming oil off produced water prior to
              disposal of produced water at a tidal disposal facility, disposal well, or fluid
              injection well.

       8.     Washout pit:  Pit located at truck year, tank yard, or disposal facility for
              storage or disposal of oil and gas waste reside wasted out of trucks, mobile
              tanks, or skid-mounted tanks.

       Environmental Issues

       All of these pits can cause environmental damage if they leak, are improperly closed

or abandoned, or are used for improper purposes.


       1.     These pits are necessary and useful parts of the production process.


       1.     They are  subject to potential  abuse;  as example would be use of an
emergency pit for disposal (through percolation or evaporation) of produced water.

       Regulatory Issues

       These ancillary pit types are generally regulated in parallel with reserve pits and
other major drilling and production facilities (see discussions above). Perhaps the most

important regulatory issue here is inspection and enforcement of applicable State standards

and guidelines.  Being minor facilities used as a support to major operations, inspection

and enforcement resources committed to these types of pits tend to low, making it relatively

more difficult for States to ensure proper compliance.
                                     — 72 —

       Offsite Management Methods
       Road or Land Application

       Produced brine is sometimes disposed of by application to roads as a deicing agent
or for dust control. It may also be sprayed directly on land from vacuum trucks. From the
environmental point of view, the processes are essentially identical.
       Environmental Performance

       Both techniques may cause contamination of ground water through seepage of
brines to unconfined freshwater aquifers.  They may also pollute nearby surface water
through overland flow, particularly if the road or land is water saturated. In some cases,
nonvolatile aromatic pollutants in brines sprayed on roads for dust control may be ingested
by breathing dust particles.

       1.     Both practices are inexpensive.

       1.     Both practices have significant potential for causing environmental damage,
and may potentially cause human health problems.
       Regulatory Issues

       States that have allowed road application in the past (such as Texas and Michigan)
are now phasing it out.
Well  Closure  and Post-Closure Issues

       Waste Characterization

       The wastes associated with improper well closure and abandonment are brines that
leak out of the bore or between strata below ground. These have already been described
                                    — 73 —

       Onsite Measures

       There are an estimated 1,200,000 abandoned oil or gas wells in the United States.

       Leakage  of brines from improperly plugged or abandoned wells can only be

addressed onsite, by plugging or replugging  the well.  All types of wells may cause

problems, but injection wells,  especially disposal (as opposed to secondary recovery)

wells, are most susceptible.  This is because of pressurization of the injection zone by

previous or continuing injection operations caused by the same well or by others in the

same project area.  Problems  can also occur in areas that have pressurized aquifers

independent of the producing zone (an example is the Coleman Junction in the Permian

Basin area of Texas).

       Well Plugging and Abandonment  Procedures


       A typical field procedure for plugging a well is as follows:

       1.     Load well with field saltwater or mud.

       2.     Remove "Christmas tree" and install blowout preventer.

       3.     Disengage and remove downhole equipment, such as packers, anchors, and
              screens, together with production/injection tubing.

       4.     Circulate drilling mud through the workover string to the bottom of the hole
              to remove any sane and debris.

       5.     Mix and spot concrete plugs at abandoned production or injection interval,
              and other potentially productive intervals, as required. (Some States allow
              bridge plugs that are set using electric wireline equipment followed by
              dumping of concrete on top of plug.)

       6.     Perforate production/intermediate casing and squeeze  concrete into the
              annular space with the surface casing. This procedure is required in order
              to protect freshwater in cases where there is no concrete in the annular space
              at the surface casing seat or at the base of the freshwater zone.

       7.     Spot concrete surface plugs inside and outside all annuli.

       8.     Dig out and cut casing strings several feet below ground level, weld steel
             plate on top stub, and backfill.
                                    — 74 —

       Environmental Performance

       Proper well plugging is essential in all producing areas.  Even properly done,
however, it may not be permanent: concrete may decay in time, especially in the presence
of corrosive saline solutions.  Replugging of wells may be a particular problem for
injection wells and other areas  where subsurface pressures may be elevated either
artificially or naturally.

       1.      Plugging prevents leakage of brines to the surface or to adjoining  useable
water strata.

       1.      None.
       Regulatory Issues

       Plugging  and abandonment procedures have been codified  only relatively
recently—for most major oil and gas-producing States, within the last 30 years. To date,
thirty-seven States have promulgated requirements for the plugging and abandonment of
wells.  The significant regulatory issues include: (1) variations in the specificity and
comprehensiveness of closure requirements, (2) provisions covering temporary closures,
(3) inspection and enforcement, and (4) availability of funds for closure of abandoned
       Implementation Provisions

       As in other regulatory areas, the specificity of well closure provisions varies greatly
from State to State. Some, such as Michigan, Wyoming, and New Mexico, provide only
very general guidance. Others, such as Texas, Louisiana, Oklahoma, and others,  include
specifications for the distance that plugs must extend above or below producing formations
and other oil  and gas zones, freshwater zones, surface  casing seats,  and the  ground
surface. States also vary in the degree to which they specify or define strata that must be
protected.  Most States are concerned about protection of upper freshwater zones in relation
                                     — 75 —

to possible leaks of the surface casing seat.  West Virginia, on the other hand, lists only
protection of coal strata.
       Temporary Closures

       Similarly, State requirements for closure of wells that have been temporarily
abandoned vary considerably. Wells that have not produced for three months or more are
generally considered candidates for permanent closure. Louisiana requires wells to be
abandoned after three months, but most States that have specific requirements call for
abandonment after six months (e.g., Alabama, California, and New Mexico) or one year
(e.g., Alaska, Texas, Kansas, Oklahoma,  and Michigan).  All these  States allow
extensions; most allow continual renewal of exemptions for an additional three months, six
months, or one year,  whichever period applies in the particular State. Among the States
with temporary abandonment provisions, only Missouri appears to have a limit (two years)
after which no further extensions may be granted.

       Four States, however, have no requirements at all limiting the length of time that a
well can be out of production before it must be closed.  These include Wyoming,  Ohio,
Colorado, and Arkansas.
       Trust Funds

       Closure provisions cannot be enforced if the owner or operator of an abandoned
well is unknown or bankrupt. The only practical remedy in such cases is for the State to
assume to costs of closure.  These average approximately $7,000 in Texas, for instance,
but may vary upward  considerably in adverse situations.

       EPA has noted only one State—Texas—that has developed an independent trust
fund for the closure of abandoned  wells.  The fund in question has been small in relation to
the potential need in the State—when funded it was approximately $2 million, or enough to
close less than 300 wells (there are an estimated 400,000 abandoned wells in Texas). The
fund has  since been attached to the State's General Fund because of the current downturn
in State tax revenues.
                                    — 76

       Establishment and continuing major funding of such trust funds would, however,
be environmentally highly desirable, especially in the major oil producing States.
                                     — 77 —

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