ENVIRONMENTAL
                                                   PROTECTION
                                                     AGENCY
                        906R87101               OAUAS-TEXA8
                                                    LIBRARY
WASTES FROM THE EXPLORATION,  DEVELOPMENT AND PRODUCTION OF
      CRUDE OIL,  NATURAL GAS  AND GEOTHERMAL ENERGY
                      INTERIM REPORT
                      April  30,  1987
               Contractors'  Reports  Submitted to
              U.S.  Environmental.  Protection Agency
                     Office  of  Solid Waste
                        Washington,  D.C.

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     This Interim Report is a compilation of documents prepared
by contractors for the Office of Solid Waste, U.S. EPA.  This
document has not been formally reviewed by EPA.

     Chapter 7, the Summary of State and Federal Oil and Gas
regulations, was delayed due to incorporation of comments from
the States.  It will be available by May 11, 1987.

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                        Table of Contents


                      Part I - Oil and Gas


Chapter 1 - Overview of the Oil and Gas Industry

Chapter 2 - Current and Alternative Practices

Chapter 3 - Oil and Gas Damage Cases

Chapter 4 - Human Health and Environmental Health
            Risk Assessment

Chapter 5 - Costs of Baseline and Alternative Waste
            Management Practices for the Onshore Oil
            and Gas Industry

Chapter 6 - Economic Impact of Alternative Waste
            Management Practices for the Onshore
            Oil and Gas Industry

Chapter 7 - Summary of State and Federal Regulations



                  Part II - Geothermal Energy

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   PART I






OIL AND GAS

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             CHAPTER 1
OVERVIEW OF THE OIL AND GAS INDUSTRY

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                           DISCLAIMER



Mention of trade names or commercial products does not constitute



EPA endorsement or recommendation for use.
                             I-ii

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                 LIST OF ABBREVIATIONS
API -       American Petroleum Institute
bbl -       Barrels
°C  -       Degrees centigrade
Dept. -     Department
°F -        Degrees Fahrenheit
FR -        Federal Register
ft -        Feet
ft3 _       Cubic feet
gal -       Gallon
M3 -        Cubic meters
mill, cf -  Million cubic feet
NPDES -     National Pollutant Discharge Elimination System
NGL -       Natural gas liquids
thous.  -    Thousand
UIC -       Underground Injection Control
U.S. DOE -  United States Department of Energy
U.S. EPA -  United States Environmental Protection Agency
yr -        Year
                        I-iii

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                        TABLE OF CONTENTS
                                                             Page

DISCLAIMER	   ii
LIST OP ABBREVIATIONS	; . .  iii
LIST OF TABLES	    v
LIST OF FIGURES	   vi

INTRODUCTION 	 1-1

EXPLORATION AND DEVELOPMENT OPERATIONS 	 1-2
     Well Drilling	1-11
     Formation Evaluation  	 1-24
     Well Completion	1-25
     Reservoir Stimulation 	 1-28
     Drilling Waste Volume Estimates 	 1-31

PRODUCTION OPERATIONS  	 1-38
     Surface Production Operations 	 1-51
     Downhole Production Operations  	 1-59
     Produced Water Volume Estimates 	 . 1-66

REFERENCES	1-77

APPENDIX	I-A2
                                 I-iv

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                         LIST OF TABLES
Table                                                        Page
1-1       U.S. Production and Drilling Activity:
          1981-1985	    1-9
1-2       Classification of Drilling Fluids  	    1-18
1-3       List of Potential Drilling Wastes	    1-22
1-4       Factors Influencing the Volume of Drilling Waste    1-23
1-5       Estimated U.S. Drilling Waste Volumes  	    1-39
1-6       U.S. Produced Water Estimates;   1981-1985  .  .  .    1-67
1-7       List of Agencies Contacted in Produced  Water
          Survey	    1-70
1-8       Summary of Produced Water Calculations  	    1-73
                                 I-v

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                         LIST OF FIGURES

Figure                                                       Page

 1-1      Petroleum Basin Map of the Lower  48  States  .  .  .    1-4

 1-2      Petroleum Basin Map of Alaska	.  .    1-6

 1-3      Annual Drilling Activity and Footage,  1981-1985     1-8

 1-4      Rotary Drilling Rig and Circulation  System  .  .  .    1-13

 1-5      Typical Land-Based Rotary Drilling Operation
          (Lower 48 States)	    1-14

 1-6      Typical Arctic Rotary Drilling Operation  ....    1-15

 1-7      Production Well	    1-27

 1-8      Reserve Pit Construction for Estimating Drilling
          Waste Volumes	    1-37

 1-9      Estimated Drilling Waste Volumes, 1981-1985   .  .    1-48

 1-10     Inventory of U.S.  Producing Oil and  Gas
          Wells, 1981-1985 	    1-50

 1-11     Typical Production Operation (Lower  48 States)  .    1-53

 1-12     Conventional Crank Counterbalanced Beam Pumping
          Unit  and Downhole  Equipment	    1-62

 1-13     Underground Pumping and Surface Operations  .  .  .    1-63

 1-14     Annual Hydrocarbon Production and Estimated
          Produced Water Volume,  1981-1985  	    1-68
                                 I-vi

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              OVERVIEW OF THE OIL AND GAS INDUSTRY






INTRODUCTION



The oil and gas industry explores, develops, and produces



petroleum resources in the United States.  Petroleum is a complex



mixture of hydrocarbons occurring in the earth as gases, liquids,



and solids.  For the purposes of this discussion, oil is defined



as crude petroleum oil and other hydrocarbons which are produced



at the wellhead in liquid form.  Natural gas is any hydrocarbon



fluid which is produced in a natural state from the earth and



which maintains a gaseous state at 16°C (60*F) and standard



atmospheric pressure.  Gas liquids are the liquid hydrocarbons



known as "natural gasoline" recovered from natural gas.



Petroleum occurs naturally underground, primarily in the pore



spaces of sedimentary rocks.  In general, petroleum is recovered



from within the earth through drilled holes.








Petroleum is found and recovered on all of the earth's continents



except Antarctica.  In the United States, the first onshore oil



well was drilled by Col. E. T. Drake near Titusville,



Pennsylvania,  in 1859.  Drake struck oil at 69-1/2 feet from the



surface.  Since then, more than 2.5 million oil and gas wells



have been drilled in the United States (Twentieth Century, 1986).



This estimate is considered conservative because it does not



include wells drilled for enhanced recovery (water injection or



gas injection), or wells drilled for storage of petroleum.
                               1-1

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As of 1983, the earth's verified petroleum reserves totaled

approximately 600 billion barrels (Kirk-Othmer, 1985).  Domestic

reserves were estimated at 28.4 billion barrels of oil, 193,369

trillion cubic feet of natural gas,  and 7.9 billion barrels of

natural gas liquids in 1985 (U.S. DOE, 1985).*  Between 1917 and

1986, 141 million barrels of crude oil, natural gas liquids, and

other hydrocarbons were produced in the United States (Twentieth

Century, 1986).  However, the rate of discovery of large

petroleum reserves has steadily declined for the past four

decades.  Future demands will be met through exploration and

discovery of new fields (operations that will become more costly

as fewer and fewer reserves are located) and through new

extraction techniques being developed to recover portions of

crude petroleum left behind by conventional extraction methods.

Barring the advent of cheaper alternative energy sources, all of

these elements will result in higher crude oil prices in the

future.



EXPLORATION AND DEVELOPMENT OPERATIONS

Exploration operations are those activities occurring in the

search for petroleum in areas or at depths previously undeveloped

with regard to petroleum reserves.  These operations include

activities associated with locating potential petroleum reserves

or potential underground storage for hydrocarbons or other gases,
*The crude oil production unit has traditionally been the
 barrel, which is equivalent to 0.159 M3, 42 U.S. gallons, or
 5.61 ft3.
                              1-2

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exploration and confirmation well drilling, well logging, and



well testing.  Development operations are similar to exploratory



operations except that developmental operations occur in the



attempt to establish production wells in areas known to contain



commercial quantities of petroleum reserves.  Development



operations including well drilling, logging, completion, and



stimulation are conducted in known reservoirs or oil fields with



the objective of further enhancing the productivity of an area.



The vast majority of well drilling operations in the United



States is developmental activity.







Drilling activity in the United States is almost entirely limited



to 32 states.  As shown in Figures 1-1 and 1-2, these states are



grouped by petroleum-bearing geologic basins, which are



contiguous between many states.  Alaska and California are



notable exceptions.







From 1981 to 1985, drilling activity proceeded at a rate



averaging 73,000 wells per year.  Figure 1-3 shows annual



drilling activity and footage drilled for 1981 through 1985.  In



1986 the worldwide drop in oil prices caused drilling activity to



decrease by almost 50 percent (oil and Gas Journal,  1986b).   New



wells range in depth from several hundred feet to over 20,000



feet.








Table 1-1 presents a summary of U.S.  drilling activity and



production figures.  Thirty-three states currently are producing
                               1-3

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                        KEY TO FIGURE 1-1
Number       Basin

  1       Anardarko Basin
  2       Appalachian Basin
  3       Arkoma Basin
  4       Black Warrior Basin
  5       Central Nebraska
            Basin
  6       Central Oklahoma
            Platform
  7       Cincinnati Dome
  8       Coast Range Basin
  9       Colorado North Basin
 10       Crazy Mountain Basin
 11       Dalhart Basin
 12       Delaware Basin
 13       Denver Basin
 14       Dodge City Embayment
 15       East Texas Salt
            Basin
 16       Eocene Basin
 17       Forrest City Basin
 18       Great Basin
 19       Green River Basin
 20       Gulf Coast Basin
 21       Hardeman Hollis
            Basin
 22       Hanna Basin
 23       Hugoton Embayment
 24       Illinois Basin
 25       Laramie Basin
 26       Las Vegas Basin
Number        Basin

   27      Llano Basin
   28      Marfa Basin
   29      Michigan Basin
   30      Mississippi Basin
   31      Mississippi Salt
             Dome Basin
   32      Paradox Basin
   33      Permian Basin
   34      Piceance Basin
   35      Powder River Basin
   36      Raton Basin
   37      San Jouquin Basin
   38      San Juan Basin
   39      San Luis Basin
   40      Snake River
             Downwrap
   41      South Alberta
             Basin
   42      South Florida
             Embayment
   43      South Park Basin
   44      South Texas Salt
   45      Tucumcari Basin
   46      Tyler Basin
   47      Uinta Basin
   48      Ventura Basin
   49      Washakie Basin
   50      Williston Basin
   51      Wind River Basin
   52      Wyoming Big Horn
             Basin
                               1-5

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1-6

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     KEY TO FIGURE 1-2


Number               Basin

  1             Bethel Basin
  2             Cook Inlet Basin
  3             Copper River Basin
  4             Galena Basin
  5             Koyukuk Basin
  6             North Slope Basin
  7             Yukon Kandik Basin
            1-7

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Total
Wells
Drilled
(x 103)
80-
                                     ~ 400
Total
Footage
Drilled #
(x 106)
                                               - 380
                                               - 360
                                               - 340
                                               ~ 320
                                               L 300
                                               - 280
            Includes oil wells, gas wells, and dry holes.
     Figure 1-3.  Annual Drilling Activity and Footage,
                  1981-1985
                  Source:  See Table 1-1.
                             1-8

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                      TABLE 1-1  (Continued)

        U.S. PRODUCTION AND DRILLING ACTIVITY:  1981-1985
FOOTNOTES

aProduction data, numbers of drilled wells, and footage
 drilled are reported for onshore only.  Offshore production
 data were obtained from the U.S. Department of Energy,
 National Energy Information Center  (see Sources).  Numbers of
 onshore wells drilled and footage were obtained from API's
 Quarterly Completion Reports  (see Sources).

bNumber of producing oil wells includes stripper wells
 (< 10 bbls./day).  For some states, the reported number of
 producing oil wells is less than the reported number of
 producing stripper wells.  Also, reported total production may
 be less than reported stripper production.  This discrepency
 exists because of the different sources of data used by IPAA
 (see Sources).

°Numbers of producing oil and gas wells and stripper wells
 include offshore data, as reported by IPAA (see Sources).

°Data for footage drilled were not reported by IPAA for
 exploratory and development wells until 1983.  Footage data
 for 1981 and 1982 were obtained from API's Quarterly
 Completion Report (see Sources).  In addition, when IPAA's
 number of drilled wells differed from API's for 1981 and
 1982, API's data were used.   (API is IPAA's source for this
 data.)
** Data not available.
Sources:  API, 1986b;  API, 1986c; API, 1987 (for Alaska's 1985
          oil drilling data only); IPAA, 1982; IPAA, 1983; IPAA,
          1984; IPAA,  1985; IPAA, 1986; U.S. DOE, 1987.
                                 1-10

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oil and/or natural gas.  Data in Table 1-1 are given for the



years 1981 through 1985, because data reported prior to or after



these years are incomplete.







Well Drilling



Cable-tool drilling and rotary drilling are the two drilling



methods practiced in the United States.  Early oil and gas wells



were drilled with impact tools by cable-tool drilling.  In this



drilling method, a chisel-like bit is suspended from a cable to a



lever on the surface, and an up-and-down motion of the lever



causes the bit to pound the bottom of the hole and chip away the



rock.  Rock and liquids are removed by removing the bit and



running a bailer in the hole.  Cable-tool drilling is used on a



very limited basis in the United States.  Cable-tool drilling is



limited to low pressure reservoirs.








During the last five decades rotary drilling has become the



predominant drilling technique.  Rotary drilling has proven to be



much faster and safer than cable tool drilling.  Cable tool



drilling was very slow and provided no means of controlling high



pressures often encountered in deeper wells.  Rotary drilling



provides for control of high pressure oil/gas/water flows by the



use of drilling fluids (see Drilling Fluids).  Rotary drilling



techniques make it possible to drill wells over 28,000 feet deep.







In rotary drilling,  the bit and the drill pipe suspended above



the bit are slowly rotated, gouging and chipping away the rock at
                               1-11

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the bottom of the well.  Figure 1-4 illustrates this process.  As



the well becomes deeper, additional sections of drill pipe are



added.  Surface casing  (set below the base of fresh water) is



almost universally required in the United States.  Surface casing



is set during drilling  to protect freshwater zones.  Intermediate



casing may also be required to seal off either oil or saltwater



zones.  Some states may require a short length of wide-diameter



conductor casing.







As shown in Figure 1-4, the drill core is circulated with a



drilling fluid (or "mud") which maintains pressure to prevent



formation fluids from entering the well bore.  As the well is



drilled, fluid is circulated down the drill pipe where it picks



up cuttings and carries them up the hole to the surface.  At the



surface, mechanical devices separate the drilling fluid from



cuttings.  The fluid is largely recirculated; cuttings and



unneeded drill fluid are placed into an earthen reserve pit.  The



reserve pit receives this mixture (including the chemicals



associated with these wastes) and rig deck drainage.  Depending



on the site,  it may also receive sewage and other drill site



wastes.  Reserve pits, mud pits, and/or freshwater pits (or



tanks) are usually associated with rotary drill sites.  Burn pits



or test pits may also be used.  Most states have construction



requirements or guidelines for these pits; many states have



specific pit reclamation requirements.  A schematic of a typical



rotary drilling surface operation for the lower 48 states is



shown in Figure 1-5, and in Figure 1-6 for an arctic operation.
                               1-12

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                                         CHILLING LINE
    MUD PUMi
                                           ROTARY TABLE
                                                 OUT
                                               PREVENTER
                                            ELLAR
                                       SURFACE CASING
             HEAVY DRILL  COLLAR
                                      REGULAR TOOL JOINT
                                      PRILLING MUO MOVING DOWNWARD
                                       THROUGH  DRILL STEM
                                     MUD STREAM CARRYING DRILL
                                     CUTTINGS TO SURFACE
                                    • IT
Figure  1-4.   Rotary  Drilling Rig and  Circulation System
                 Source:   Chilingarian,  1983.
                               1-13

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The differences between rotary drilling in the lower 48 states



and in arctic conditions primarily are differences in surface



operations to accommodate the arctic climate.








A recent development in rotary drilling involves using a fluid-



powered turbine at the bottom of the hole to provide the rotary



motion of the bit.  In this method, the drill pipe does not



rotate but is used to weigh down the bit and carry the drilling



fluid to turn the turbine.








     Drilling Fluids



The primary function of drilling fluids is to facilitate



successful completion of the well.  In so doing, the drilling



fluid must remove cuttings from the hole, control downhole




pressure,  seal off permeable formations, prevent cave-ins,



support and lubricate downhole drilling equipment, and perform



other specialized functions as required (Chilingarian, 1983).



Each situation requires careful evaluation for appropriate



selection of drilling fluid and additives.  Fluid selection and



fluid characteristics are continually adjusted during drilling



operations to provide the needed traits.  Fluid density, fluid



viscosity, and filtrate loss are the most important



characteristics.








Drilling fluids are commonly classified, according to their base



fluid, into three main groups:  (1) water-base drilling fluids,



(2) oil-base drilling fluids,  and (3) gaseous drilling fluids
                               1-16

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 (Chilingarian, 1983).  Table 1-2 presents major classifications



 of drilling fluids.







 For a specific drill site, selection of the type of drilling



 fluid is dependent on economics, availability, types of geologic



 formations anticipated, and downhole data collection



 tools/practices.  First, the drilling fluid must be economically



 available at the drill site.  It also must be capable of



 performing the functions of drilling fluid as described above.







     Water-base Drilling Fluids.  Water-base drilling fluids



 predominate U.S. drilling.  The availability of fresh water or



 salt water at drill sites is a key factor in selection of water-



 base fluids.  However, the use of water-base drilling fluids is



 limited to formations which are not sensitive to water.  Water-



 sensitive formations might swell or cave in with exposure to



 water-base drilling fluids.  Other limitations to the selection



 of water-base drilling fluids include the types of chemicals



 needed to condition the fluid and the potential interference with



 downhole data collecting tools or techniques.








Water-base drilling fluid characteristics may be tailored to



 specific requirements, within the limitations described above,  by



 the addition of colloidal materials (primarily clays) and



weighting materials (barite or fine sand) combined with chemical



 additives.  A myriad of chemical additives may be used during



 drilling to condition the fluid.  These include strong acids and
                               1-17

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                            TABLE 1-2

                CLASSIFICATION OF DRILLING FLUIDS*


     WATER-BASE DRILLING MUDS

          Fresh-water muds (little or no chemical treatment)
               o  Inhibited muds
               o  Spud muds
               o  Natural muds

          Chemically-treated muds (no calcium compounds added)
               o  Phosphate muds
               o  Organic-treated muds
                    - Lignite
                    - Quebracho and other extracts
                    - Chrome-lignosulfonate

          Calcium-treated muds
               o  Lime
               o  Calcium chloride
               o  Gypsum

          Salt-water muds
               o  Sea-water muds
               o  Saturated salt-water muds

          Oil-emusion muds (oil-in-water)

          Special muds
               o  Low-solids oil-emulsion muds
               o  Low-clay-solids weighted muds
               o  Surfactant muds
               o  Low-solids muds
                    - Clear water
                    - Polymer muds
                    - Low-solids, non-dispersed muds

     OIL-BASE DRILLING MUDS

          Oil-base muds

          Invert emulsion muds (water-in-oil)

     GASEOUS DRILLING FLUIDS

          Air or natural gas

          Aerated muds

          Foams
*Source:   Chilingarian,  1983.
                               1-18

-------
bases, corrosion inhibitors, lost circulation additives, wetting



agents, defearners, flocculants, surfactants, biocides, and



lubricators.  Water-base drilling fluids may contain considerable



amounts of oil in emulsion.  Similarly, oil-base drill fluids may



contain substantial amounts of water in emulsion.  There is



overlap in definitions of water-in-oil emulsions and oil-in-



water emulsions.







As shown in Table 1-2, the aqueous base also may be varied



considerably by additives or by creation of emulsions.  These



treatments widen the usefulness of water-base muds.








     Oil-base Drilling Fluids.  Oil-base drilling fluids account



for approximately 5 to 10 percent of the total volume of drilling



fluids used (Chilingarian, 1983).  Oil-base drilling fluids



consist of a continuous phase of oil and asphalt which may be



conditioned with water, emulsifiers, surfactants, calcium



hydroxide, weighting materials, and other chemical additives



(Chilingarian, 1983).  The oil base may consist of crude oil,



refined oil (usually heavier fuel oils, kerosene, or diesel oil),



or mineral oil.  Oil-base drilling fluids may have comparable



fluid characteristics to water-base drilling fluids; however,



oil-base fluid performance excels in very deep wells.








     Gaseous Drilling Fluids.  Low-density drilling fluids are



used in special types of formations.  These fluids include air,



natural gas, mist, stable foam, and aerated "mud" foam.  The use
                               1-19

-------
of air as a drilling fluid ("air drilling") predominates gaseous



drilling.  Air drilling may be favored over drilling using water-



base or oil-base fluids when the underlying formations are hard



and dry rock or in shallow locations where the use of.fluids to



maintain subsurface pressure is not required.  In these



circumstances, air drilling is considerably faster and less



expensive than drilling using3water-base or oil-base fluids.  In



air drilling, low density fluids under backpressure are



circulated to lift cuttings back to the surface and to cool the



bit.  As with all rotary drilling, the drill bit is driven by the



rotating drill string.  However, in air drilling, once the



cuttings reach the surface, water is injected into the cuttings



return line for dust suppression.  The resulting slurry of



cuttings and water is deposited into an earthen waste pit at most



drill sites.  When fluids are encountered during air drilling,



foaming agents may be used to bring the fluids to the surface.



The fluid and foaming agents are also placed into the waste pit.



The pit may subsequently be treated with defoamants.







In the United States, air drilling is used more commonly in the



Appalachian Basin,  in southeastern Kansas/northeastern Oklahoma,



in the Four Corners area of the Southwest (New Mexico, Colorado,



Utah,  and Arizona), and in the Rocky Mountain states (see Figure



1-1).   Air drilling has been used in permafrost areas for very



shallow boreholes,  such as those needed for the initial surface



casing (Chilingarian, 1983).
                               1-20

-------
Other very low density drilling fluids can be used in similar



special situations.  Natural gas or other gases may be used as



drilling fluids.  These gases may be dispersed with liquids



(creating mist or fog) or with solids (creating smoke).  Low



density liquid drilling fluids may be dispersed with gases



(foams/ gas emulsions), other liquids (emulsions), or solids



(suspensions).  Low density solid drilling media may be dispersed



with gases (solid foams), liquids (gels), or other solids



(Chilingarian, 1983).  Thus, the analysis of low-density drilling



fluids may vary widely depending on the selection of drilling



media components.








     Waste Generation from Drilling Operations



The preceding discussions mention numerous materials used in the



course of drilling operations, many of which may be disposed in



reserve pits.  Table 1-3 summarizes these materials, in addition



to other wastes associated with exploration and development



activities.  All of the wastes listed in Table 1-3 have the



potential of entering a reserve pit, either due to direct



disposal or because of inadequate solids control in the drilling



fluid circulation system.








Virtually every aspect of drilling operations affects the



quantity of wastes generated.  Table 1-4 presents a listing of



factors which can influence waste volumes.  These factors may



influence waste volumes individually, but usually are so strongly
                               1-21

-------
                  TABLE 1-3

      LIST OF POTENTIAL DRILLING WASTES


o    Drilling fluid

     o    Water-based drilling fluid system
     o    Oil-based drilling fluid system
     o    Pneumatic drilling fluid system

               Air
               Foam
               Mist
               Aerated mud

     o    (Some) produced fluids

o    Drill cuttings

o    Deck drainage

o    Well completion fluids/well treatment fluids

o    Reservoir stimulation fluids

o    Packing fluids

o    Waste lubricantsf waste cement, waste hydraulic
     fluids, waste solvents, and waste paints

o    Sanitary waste
                       1-22

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                   TABLE 1-4

FACTORS INFLUENCING THE VOLUME OF DRILLING WASTE


 Geology, e.g.  -    Hard rock formations
                     Shale
                     Sandstone

 Well  Depth / Hole Size / Casing Program

 Drilling fluid; e.g.
                     Mud type
                     Air
                     Gas
                     Foam

 Extent of solids control equipment used; e.g.
                     Influences the amount of water
                     added to the circulating mud system
                     Cuttings washing efficiency

 Problems encountered  during the operation; e.g.
                     Stuck pipe
                     Lost circulation
                     High pressures and temperatures
                     (expected/unexpected)
                     Sidetracking

 Service products used; e.g.
                     Types of products used
                     Numbers of products used
                     Solids vs. liquids
                         1-23

-------
interrelated that the effect of a single factor can be difficult,



if not impossible, to evaluate.







For example, anticipated downhole geology dictates the type of



drilling media to be used.  However, if water-bearing formations



are encountered, waste volumes increase (via water displaced to



the surface).  The presence of formation water (called connate



water) causes changes in the drilling media which must be



compensated.  In addition, the presence of connate water



contributes to the possibility of another waste-producing



problem, e.g., stuck drill pipe.








Once the drilling fluid and drill cuttings are brought to the



surface, the type and extent of solids control equipment used



influences how well the cuttings can be separated from the



drilling fluid,  and hence influences the volume of waste



discarded in the reserve pit.  Drilling media must be diluted



with makeup water to counter the addition of solids from



downhole.  Thus, as the effectiveness of solids control equipment



declines, the volume of drilling fluid increases.  This example



is illustrative of the interacting factors which affect final



waste volume.  All of the factors in Table 1-4 are similarly



complex.








Formation Evaluation



At certain points during the drilling of a well,  and when final



depth is reached, downhole formations are measured and analyzed
                              1-24

-------
to provide the driller with important geological information.
After the drill string is removed from the hole, a mobile
wireline unit lowers logging tools to the bottom of the hole.  As
they are retrieved back up the hole, they measure and record
properties of the formations.  Well logging typically generates
no waste.
                             a
If the presence of hydrocarbon zones is indicated, a drill stem
test can tell much about the characteristics of the reservoir.
Lowered to the bottom of the hole on the end of the drill string,
the drill stem test tool isolates the reservoir interval.  A
valve is opened, allowing formation fluids to enter the tool and
activate a pressure recorder.  When the test is completed,
formation fluids collected in the drill stem are analyzed and
disposed of through flaring, emplacement in the reserve pit, or
removed from the drill site for disposal.

Well Completion
If tests show that one or more of the hydrocarbon zones are
economical for petroleum production, production casing will be
set and the well completed.  When cemented into the drilled hole,
this final string of casing seals off the wellbore.  Casing
requirements vary from state to state.   In the contiguous United
States, the production casing usually is between 11.4 and 17.8
centimeters (5 to 7 inches) in diameter.  It creates a permanent
well through which the productive formations may be reached.
After the casing is in place, production tubing is extended from
                               1-25

-------
the surface to the productive formation.  Production tubing is



usually 3.8 to 14.0 centimeters (1.5 to 5.5 inches) in diameter.



A packing device is used to seal the productive interval from the



rest of the well.  In less frequent situations where multiple



productive formations are found, as many as four production



strings of tubing may be hung in the same cased well.







When the subsurface equipment is in place, and before perfor-



ating, a network of valves (called a "wellhead" or "Christmas



tree") is installed on the surface and arranged so that flow from



the well may be regulated, and so that tools to perform



subsurface work may be introduced through the tubing.  The



wellhead may be very simple,  such as might be found on a low-



pressure well that must be pumped, or it may be very complex, as



in the case of a high-pressure well with multiple producing



strings.  Figure 1-7 shows a completed production well.







In an open-hole completion,  the producing zone is left uncased.



Typically, though,  the hole is completely cased, requiring



openings to be placed in the casing to expose the producing



zones.  A down-hole perforator uses an explosive to shoot holes



through the casing and cement and into the formation.  The



perforating tool is usually lowered on a wire line, although



expendable perforation guns sometimes are lowered at the end of



production tubing.   When the perforating tool is in the correct



position,  the charges are triggered electrically from the
                              1-26

-------
          WELL HEAD CONNECTIONS
              AGROUND LEVEL

                BOTTOM CELLAR

                SURFACE PIPE
                CEMENTED
                TUBING
             INTERMEDIATE STRING
                CEMENTED
 OIL
 SAND
 PACKER

  STRING  CEMENTED

OPEN HOLE
Figure  1-7.  Production Well
            Source:  API, 1981,
               1-27

-------
surface.  Such perforating is adequate if the formation is



sufficiently productive.







During completion procedures, drilling fluid in the well may be



modified or replaced by specialized fluids.  For long-term



corrosion protection, a packer fluid is circulated into the



casing/tubing annulus.  Solids-free diesel oil or crude oil is a



good packer fluid if its density is high enough.  Otherwise,



drilling fluid treated to meet alkalinity, electrical stability,



and corrosion inhibition specifications may be suitable.



Perforating procedures may require a clean, solids-free fluid



below the production packer so that the producing zone does not



become immediately plugged up when it is perforated.  A typical



completion fluid consists of a brine solution modified with



petroleum products, resins, polymers,  and other chemical



additives,  depending upon the properties of a particular



reservoir.   When the well is produced initially, the completion



fluid may be reclaimed or it becomes a waste product that is



disposed of into the reserve pit or removed from the drill site



for disposal.








Reservoir Stimulation



After drilling,  completion, and perforation are completed,



reservoir stimulation techniques may be performed to enhance



production.  Acidizing is one of the original reservoir



stimulation techniques still in modern use.  Hydraulic fracturing



is another  widely practiced reservoir stimulation technique.
                              1-28

-------
Both practices are also routinely used to restore productivity of

existing wells.



     Acidizing

The first and by fa-r the most successful well stimulation

technique uses hydrochloric acid introduced into the petroleum-

bearing formation (hence, "acidizing").  Hydrochloric acid

stimulation is used in dolomite and limestone formations.  When

these acids are introduced into the formation, they react quickly

to enlarge existing channels by dissolving rock.  This treatment

can produce carbon dioxide, calcium chloride, and/or magnesium

chloride.



Another acid treatment uses a solution of hydrochloric and

hydrofluoric acids to stimulate wells in sandstone formations.

In this instance, sodium fluoride is an additional reaction

product.  Other acidizing systems include:

     Organic acids - formic and acetic acid (usually used in
     combination with hydrochloric or hydrofluoric acid)

     Powdered acids - sulfamic acid, chloroacetic acid

     Retarded acid systems - gelled, acids, chemical retarded
     acids, emulsified acids



Other chemical agents that are added to petroleum wells to

maintain well productivity and integrity are the following:

     Corrosion inhibitors - to reduce the destruction of
     metal through electrochemical action.

     Surfactants - to prevent emulsification, to reduce
     interfacial tension, alter formation wettability, speed
     clean-up, prevent sludge formation.
                               1-29

-------
     Friction reducers - to minimize pumping energy.  Usually
     these are organic polymers added to the stimulation fluids
     (guar, cellulose, fatty acids).

     Acid flow-loss additives - Composed of solid particles that
     enter formation pores, and a gelatinous material to plug
     pores, silica fluor, calcium carbonate, polyvinyl alcohol,
     polyacrylamide.

     Diverting agents - to direct stimulation fluids.

     Complexing agents - to solubilize iron and other pipe or
     metal corrosion products which might precipitate.  Ethylene
     diamine tetracetic acid (EDTA) is commonly used.

     Cleanup additives - After acid treatment, the well must
     be cleansed of the reactor products and unusual
     reagents.  They are flushed with water, and removed by
     use of nitrogen gas.  Alcohols and wetting agents are
     added to ease these tasks (Williams, et al, 1979).

Although the formation may retain some of these fluids, most

water-soluble reagents, sludges,  and organic residue are

eventually pumped from the well to the surface.  In general,

these wastes are displaced into onsite tanks or into holding

ponds for treatment and disposal.
     Hydraulic Fracturing

In hydraulic fracturing, fluid is pumped into a well under enough

pressure to create actual breaks in the formation.  This

procedure allows more area for hydrocarbon flow into the well by

extending fractures further into the formation.  Types of

fracturing fluids may be oil-base, water-base, or acid-base.

Gases, especially nitrogen, are also used as fracturing fluids.



Hydraulically fractured formations tend to lose fluid-carrying

capacity with time unless "propping agents" are used to hold the
                               1-30

-------
fractures open.  Sand, nut shells, or beads of aluminum,  plastic,

or glass may be used as propping agents (API,  1986a).



The combination of fracturing fluid and propping agents can

create a "very complex substance" (API, 1986a).  Although the

formation may react with or retain some of these fluids,  water-

soluble reagents, sludges, and organic residues eventually are

pumped from the well to the surface.  These wastes generally are

placed into onsite tanks or holding ponds to accumulate prior to

treatment and disposal.



Drilling Waste Volume Estimates

This section presents the methodology used to develop estimates

of drilling waste volumes.  Estimated volumes are presented at

the conclusion of the methodology.  Individual sources of wastes

that were considered in designing the methodology include

drilling fluid, well completion treatment, and well stimulation

fluids.



EPA considered the following four methodologies prior to

selecting one to estimate the volumes of drilling wastes

generated from exploration and development activities:

     Method 1.  Determine the average well depth nationwide.
     Develop an estimate of the volume of drilling fluids and
     drill cuttings generated (either per foot or per the
     determined average well depth)  based on site-specific or
     standard industrial calculations (Chilingarian,  1983).
     National volume would be estimated by multiplying the volume
     of drilling fluids used by the average number of wells
     drilled over the past 3 to 5 years.
                              1-31

-------
     Method 2.  Interview and gather data from operators by state
     and/or by region.  Extrapolate these data to the national
     level.

     Method 3.  Develop a model to consider all the possible
     variables or only the most important shown in Table 1-4.
     This method could be simplified by developing a model to
     address only the most important variables in Table 1-4.

     Method 4.  Develop a list of generic drilling waste pit
     sizes.  Assign percentages of the pit sizes by state based
     upon field observation and professional judgment.
Of the aforementioned methods, Methods 1, 2, and 3 were

considered and rejected.  Method 4 was selected and implemented.



     Method 1 - Drilling/Footage Estimate

This method was rejected for several reasons.  First, this method

would estimate only the potential volume of drilling fluids and

drill cuttings generated.  It would not account for any

associated wastes generated during drilling operations.  Second,

estimating the amount of drilling fluid to be used during

drilling is not necessarily linear to the amount of waste

generated.  Therefore, EPA would not be estimating reasonable

quantities.  This approach would be a viable candidate only if a

standard drilling fluid volume per foot of drilling could be

determined regardless of the type of drilling fluid (i.e., oil-

base, water-base, or gaseous), the size of the hole, or

geological conditions.  Nationwide percent usage of solids

control equipment could not be accounted using this method.  This

complex variable directly affects waste generation and the amount

of make-up water needed.  Air drilling water (added directly into

the cuttings return line for dust suppression) could not be


                               1-32

-------
accounted  for using this method.  Method 1 was rejected because



EPA did not have the information necessary to implement this



method effectively.







     Method 2 - Survey



Conducting a survey of operators to request waste volumes



information would have been a viable method if there were ample



time and funding.  The court-mandated 21-month schedule for this



study precluded EPA from conducting the necessary survey.



However, EPA has relied extensively upon state assistance during



this study and, therefore, has been provided much regional and



local data.  Also, the American Petroleum Institute (API) has



conducted a survey of member companies to obtain drilling waste



volume information.  Currently, the API data are not available to



the Agency for evaluation.







     Method 3 - Modeling



As with Method 2, this method may have been viable given



considerable time and ample funding.  More critically, this



method requires very specific technical data.  As described



earlier, drilling wastes are comprised of a multitude of separate



wastes including cuttings, drill fluids, completion fluids,



reservoir stimulation fluids,  and other chemical agents which may



be added to improve conditions for  drilling operations (see



Table 1-3).  Ideally,  inventories of these wastes would be



available for summation into an estimate of national drilling



waste volumes.   A review of the literature indicates that there
                               1-33

-------
are virtually no comprehensive published data available regarding



individual drilling wastes.  Further investigation revealed that



the drill site operator maintains a "driller's log" which



describes "the depth, kind of rocks, fluids, and anything else of



interest that he notices while drilling a well" (API, 1986a).



While the driller's log may provide a glimpse of actual waste



volumes on a site-by-site basis, these records are not available



for the Agency's use in estimating waste volumes.   EPA would have



had to conduct Method 2 in order to collect the data to design



and implement this method; thus, Method 3 was rejected.







     Method 4 - Pit Volume Estimates



EPA chose to estimate drilling waste volumes using this method,



referred to as the "pit method."  Although data were not



available to estimate volumes of each individual waste, data were



available regarding pit sizes and regional practices for the



combined wastes disposed into reserve pits.  This  information was



collected during a field sampling program conducted in 1986 and



through extensive contact with state agencies between 1984 and



1987.   (The American Petroleum Institute also has  collected pit



size information.  When the Agency receives this information,



these estimates may be further refined.)  The Agency developed a



range of pit sizes to accommodate this information.  A



distribution of pit sizes was multiplied by the percentage of



each pit size and by the total number of wells drilled in that



state to generate total drill waste volume estimates.
                               1-34

-------
This methodology has the advantages of accommodating regional



practices as well as including most individual wastes in the



volume estimate.  Pit construction details, such as sloping pit



walls and freeboard requirements, have been included.







This approach precluded the development of volume estimates for



small miscellaneous sources.  Any incremental estimate of these



waste volumes was considered small in relation to pit waste



volumes.







Certain assumptions and generalizations had to be made in order



to use total pit volumes for estimating drilling waste volumes.



The assumptions detailed below are deliberately conservative;



they do not represent a "worst case" scenario.  These assumptions



necessarily tend to oversimplify the complexities involved in



drilling a well.







First, it was assumed that factors influencing the quantity of



waste at any given site average out across the estimation.  This



assumption was necessary because drilling waste data and



information about the factors affecting the quantities of



drilling waste could not be obtained within the scope of this



project.








Second,  it was estimated that there is one pit per drill site in



the lower 48 states.  Third, it was assumed that a limited number
                              1-35

-------
of pit sizes would be available.  For the lower 48 states, the

following pit sizes  (including freeboard) were selected:
                  Length x Width x Depth (Volume)

     Small 	  100 ft x  30 ft x  6 ft  (1,984 bbl)
     Medium 	  175 ft x 125 ft x  8 ft (22,700 bbl)
     Large 	  250 ft x 250 ft x 10 ft (87,240 bbl)
Pit construction also was assumed to include pit walls inclined

120 degrees away from the pit floor (see Figure 1-8).  Drilling

fluid volumes were calculated based on 2 feet of freeboard, and

included both the liquid and the solid (sludge) portions of the

contents within the pit.



Fourth, assumptions were made in estimating the percentage of

each pit size for each state.  For example, in Texas it is

assumed that none of the pits is "small," fifty percent of the

pits are "medium," and fifty percent of the pits are "large."

Percentages of pits in each size were based on field observations

and discussions with state regulatory personnel.



Finally, Alaskan waste management practices are considered

sufficiently different from lower 48 operations that they have

been addressed separately.  Estimation of North Slope drilling

wastes were based on 20 wells per pit.  North Slope pits were

estimated at 500 feet x 1,500 feet x 5 feet, including 2 feet of

freeboard and pit walls inclined 120 degrees from the pit floor.

A drill pad with 20 wells would have 400,244 barrels of pit
                               1-36

-------
                  2-ft freeboard
Figure 1-8.
Reserve Pit  Construction for Estimating
Drilling Waste Volumes
                    1-37

-------
capacity or approximately 20,012 barrels per well.  Estimates for



other Alaskan operations were based on three wells per pit.



Average pit dimensions were assumed to be 100 feet x 400 feet



x 10 feet, including 2 feet of freeboard and pit walls inclined



120 degrees from the pit floor.  These pits would have 55,093-



barrel capacity or 18,364 barrels per well.








These assumptions were the foundation for calculations estimating



drilling waste volumes for each state.  Estimates of drilling



waste volumes were made for each state by multiplying the total



number of reserve pits constructed in a given year (based on the



number of wells drilled) by the pit waste volume (in barrels),



then multiplying the result by the percentage of pits of that



size in the state.  Table 1-5 presents detailed waste volume



estimates for each state.








Figure 1-9 presents estimated annual and cumulative volumes for



1981 through 1985.  The average estimated volume of drilling



wastes generated in the U.S. from 1981 to 1985 is 2.72 billion



barrels annually.  Cumulative estimates for the 5-year period



from 1981 through 1985 exceed 13.6 billion barrels.








PRODUCTION OPERATIONS



Production operations include all activities associated with the



recovery of petroleum from geologic formations.  Production



operations are delineated into those activities associated with




downhole operations (such as petroleum recovery techniques,
                               1-38

-------
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            15-
Waste
Volume
(x 109bbls)
           10-
            5 -
ANNUAL WASTE
GENERATION
CUMULATIVE WASTE
GENERATION
SINCE 1981
                                            - 15
                      Waste
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              1 bbl = 42 gal.
       Figure 1-9.  Estimated Drilling Waste Volumes,
                  1981-1985
                  Source:  See Table 1-5.
                            1-48.

-------
workovers, and reservoir stimulation techniques), and those



activities associated with surface operations (such as



oil/gas/water separation and treatment of oil, gas, gas liquids,



or produced water).  The vast majority of production operations



are conducted onshore.  These operations are described below.



Similar production operations are used in coastal and offshore



locations.








The U.S. Department of Energy estimates 1985 domestic reserves at



28.4 billion barrels of oil, 193,369 trillion cubic feet of



natural gas, and 7.9 billion barrels of natural gas liquids.



About one-third of these reserves are in the Alaskan Arctic.



Less than one-half of domestic oil in place will ultimately be



recovered with existing technology and economic conditions.



Unfavorable reservoir geology, adverse fluid properties, or low



oil content in the reservoir rock limit recovery prospects for



petroleum resources.







By the end of 1985, there were 834,831 producing oil and gas



wells in the United States, excluding offshore wells (see Figure



1-10).  These wells yielded 2.82 billion barrels of crude oil and



12.6 trillion cubic feet of gas annually.







Approximately 70 percent of the total number of oil wells in the



United States are "stripper oil wells."  Stripper oil wells are



defined as those oil wells producing less than 10 barrels of oil



per day (44 FR 22069).  Marginal gas wells correspond to the
                               1-49

-------
Number
   of
 Wells
(x 103)
       1,200-
        800'
        40(T
   Total producing oil
   and gas wells (includes
   stripper oil wells)
            1981
1982
1983
1984
1985
                         Number
                           of
                          Wells
                         (x 103)
                                               1,200
                           •800
                                             -400
       Figure 1-10.  Inventory of U.S. Producing  Oil
                    and Gas Wells, 1981-1985
                    Source:  See Table 1-1
                            1-50.

-------
situation of stripper oil wells.  Many definitions have been



advanced regarding marginal gas wells.  The definition of



marginal gas wells often referred to is 60 thousand cubic feet of



gas per day (43 FR 56448, 59056, 59481, 59836).  This definition



is based on a rough energy equivalence of 60 thousand cubic feet



of gas per day to 10 barrels of oil per day.








Water is produced along with crude petroleum and/or natural gas.



This water, called "produced water" or "brine," is an aqueous



solution containing many dissolved compounds, including minerals



(such as sodium chloride) and dissolved hydrocarbons in widely



varying concentrations.








Surface Production Operations



Surface production operations generally include transport of the



well fluids (oil, gas, gas liquids, water) from a wellhead or



from a group of wells to a facility that separates the fluids and



treats them prior to sale.  The separation facility is usually



called a "tank battery" in the contiguous United States.  In



Alaska, this is called a "gathering center" or a "flow station."



Products may be transported from the tank battery by truck or



pipeline.








For clarity, the following discussion of production processes



focuses separately on oil and gas and briefly considers the case



where gas production is concomitant with oil production.  The



first example to be discussed is production of oil.
                               1-51 '

-------
     Oil  Production Operations



Water, oil, oil/water emulsion, and gas flow into the well and



are brought to the wellhead.  This mixture is piped from the



wellhead—usually through an oilfield gathering system serving



many wells—to the tank battery, although some wells have



dedicated surface facilities Jsee Figure 1-11).








A "separator" may be used to separate produced gas from produced



fluids (including oil and water at this point) and entrained



solids.  A. separator is a vertical or horizontal baffled vessel;



it is designed for sufficient retention time to allow gas to



break out of the wellhead fluids.  If the quantity of gas is low,



a "free water knock out" vessel may be used to make the initial



separation of free water (taken off the bottom of the vessel) and



gas (taken off the top of the vessel) from free oil and oil



emulsion  (taken from the midsection of the vessel).  Gas from the



separator and/or the free water knock out may be routed into a



low pressure gas gathering system or, less frequently, flared



(burned in a controlled manner onsite).  The gaseous fraction of



production from oil wells is handled as described below in Gas



Production Operations.








The free oil and oil emulsion may be treated differently from



site to site,  depending upon how difficult the emulsion is to



break and^upon other factors.  If the emulsion is difficult to



break,  the free oil and oil emulsion may be heated and chemically
                               1-52

-------
                                                           en
                                                           0)
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                                                           00
                                                              CO
                                                            QJ
                                                           *•*  c
                                                               fl
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                                                            a m
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                                                            0
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                                                            3
1-53

-------
treated prior to mechanical or gravity separation.  A "heater-



treater" is used to heat the free oil and oil emulsion prior to a



settling process.







If the emulsion can be broken through longer settling time (with



or without emulsion-breaking chemical addition), the free oil and



oil emulsion is sent to a larger settling vessel, usually a "gun



barrel."  The gun barrel may be used as the settling vessel after



the heater-treater or it may be used alone.







Crude oil flows from the final separator to stock tanks.



Ownership of the oil may change past the stock tank.  Stock tank



oil is measured (corrected to 60*F) and moved off the lease or



unit for sale.








Modern production sites have computerized oil transfer gauging



systems called Lease Automatic Custody Transfer (LACT) units.



These units take samples, record temperature, and determine the



quality and net volume of the oil.  They also recirculate bad oil



for reprocessing,  keep records for production and accounting



purposes and shut down and sound an alarm when something goes



wrong.  LACT units are used mainly with pipeline systems.








Produced water is the largest volume production waste.  It is



collected from surface production operations and placed into



tankage, an impoundment, or a pit.  Produced water must be



treated, stored, or disposed.  Generally, the percentage of water
                               1-54

-------
in the crude oil/water mixture increases as the well ages.  In



California, for instance, there are areas where crude oil wells



produce 98-99 percent produced water with 1 to 2 percent crude



oil.  For stripper well production, 25 to 80 percent of wellhead



fluids are produced water (U.S. EPA, 1986a).







Produced water may contain residual chemicals or by-products from



downhole surface operations.  For example, it is expected that



polymers eventually will be found in produced water from wells in



a polymer-flooded field.  Similarly it is expected that reservoir



stimulation fluids (or by-products from their reactions) will be



detected after the well is treated.  Other chemical agents which



have been added to a well to maintain or increase production



(i.e., biocides, corrosion inhibitors, surfactants, etc.) and



well contaminants may eventually reach surface production



operations.  These constituents vary widely in produced water and



production operation sludges.








Entrained solids can precipitate to form an accumulation of



particulate matter and oily residue in production vessels.  This



waste, referred to as "bottoms" or "tank bottoms," must be



periodically removed and disposed.  The frequency of cleaning



varies from a few months to decades.  The average frequency is



1 to 3 years.
                               1-55.

-------
     Gas Production Operations



Gas production must be separated from crude oil, hydrocarbon



condensate, water, entrained solids, and impurities prior to



marketing.  These separation processes can occur in the producing



field or in a gas processing plant.








Crude oil, hydrocarbon condensate, some free water, and entrained



solids are removed by separators as described in Oil Production



Operations.  A variety of separators (e.g., horizontal, vertical,



two-phase, three-phase, multi-stage, etc.) are currently used.



Once removed, free water may be accumulated in tanks, pits, or



impoundments, pending disposal or reuse.







After the gas has been processed for market, it contains a



relatively pure mixture of hydrocarbons ranging from methane



(CH4) to decane (CioH22)«  This mixture is separated into natural



gas (predominantly methane) and natural gas liquids (ethane and



heavier hydrocarbons).  In one predominant technique, water and



heavier hydrocarbons can be removed in one process.  Natural gas



from the well enters a chamber where the pressure on the gas is



decreased.  This causes a concurrent decrease in temperature,  and



petroleum liquids and water precipitate out of the gas stream and



flow through a drain at the chamber bottom.  Natural gas collects



near the top of the chamber.  Heat exchangers are also used with



this system to further cool the gas.  This process is also called



"low temperature separation."  In this system, the petroleum



liquid that settles out of the separator bottoms enters a low
                               1-56

-------
pressure separator chamber where additional gas is removed.



Natural gas, natural gas liquids, and hydrates are the products



that leave this separator.  The natural gas from the separator is



warmed and sent to a gathering system.  Natural gas liquids from



the separator are stored and transported to gas plants or



refineries as feedstocks.  Hydrates are melted, and the resulting



water must be disposed (API, 1976; 1986a).








One problem associated with the production of natural gas is the



presence of free water entrained in the gaseous phase.  Free



water accelerates corrosion and formation of hydrates.  Both



corrosion and hydrates cause flow restrictions and a decrease in



pressure.







Hydrates are precipitates that form in the presence of free water



under certain conditions.  The greater the pressure in the



equipment,  the higher the temperature at which hydrates will



form.  Hydrates will form of methane, ethane,  propane, isobutane,



normal butane,  hydrogen sulfide,  and carbon dioxide from a



natural gas stream (API,  1976).







Formation of hydrates may be lessened by dehydrating the gas



stream or by preventing formation of hydrates in other ways.



Water may be removed by glycol dehydration, by desiccants, or by



expansion-refrigeration.   Glycol is a liquid desiccant which



absorbs water from the gas.  When using liquid absorbent, the gas



passes through a chamber into which a fine spray of the liquid is
                               1-57

-------
introduced.  The liquid flows out the bottom of the chamber and



is distilled to separate the water and glycol, which is reused.



The dry gas exits the chamber at the top.  This process results



in waste glycol and gaseous emissions.







Solid adsorbents (desiccants) are used in conjunction with a gas



permeable filter through which the gas flows.  The solid



adsorbent may be renewed by heating (API, 1976).








If dehydration is not used, hydrate formation can be prevented



through other treatment methods.  One method is to heat the gas



stream to keep the hydrate from becoming saturated in the gas.



When using this method, heating must be repeated at every point



where hydrate formation is likely.  Another method of hydrate



control is to add a chemical to the gas stream to lower the



temperature at which the hydrate will precipitate (i.e.,



"antifreeze agent").  Alcohol is usually used for this.  A solid



filter can be used to remove hydrogen sulfate hydrate.  As the



gas stream containing hydrogen sulfide passes through this



filter, the gaseous hydrogen sulfide is converted to solid iron



sulfide (API, 1976).  These filters cannot be reused and must be



properly disposed.








Other impurities,  such as hydrogen sulfide and carbon dioxide,



are removed from the gas stream in "sweetening" processes.



Several commercial processes are used to sweeten natural gas;



they can be classified as chemical absorption, physical absorp-
                               1-58

-------
tion, or adsorption processes.  In the absorption processes, the

acid gas stream contacts a liquid absorbent that selectively

removes certain acid gases from the natural gas.



API's Fundamentals of Petroleum (1986) describes three sweetening

processes as follows:

     In chemical absorption, the acid gases react chemically with
     the liquid absorbent.  Heat and/or low pressure is used to
     regenerate the absorbent, that is, to separate the acid
     gases from the absorbent so that it can be used again.  The
     most widely used sweetening processes in the industry are
     the amine processes.  An amine process is a continuous-
     operation that uses a solution of water and a chemical amine
     to remove carbon dioxide and several sulfur compounds.

     In physical absorption, the acid gases are physically
     dissolved in the liquid absorbent, and the absorbent is
     regenerated by driving off the acid gases through heating or
     pressure reduction.  Commercial processes of this type
     include the Fluor solvent, Selexol, Sulfinal,  and Rectisol
     processes.

     In adsorption, or dry-bed, processes, the acid gas stream
     contacts a solid adsorbent that removes sulfur compounds
     and/or carbon dioxide.  The acid gas is vaporized and
     removed from the adsorbent bed by heating or pressure
     reduction.
Each of these processes results in the generation of acid gases

and spent absorbent (or adsorbent) which must be disposed.

Produced water disposal is described in the previous section, Oil

Production Operations.



Downhole Production Operations

Downhole production operations are processes that occur inside

the wellbore and/or in the producing formation, such as  recovery

processes, workovers,  and reservoir stimulation.   Thus, any of
                               1-59

-------
these wastes that are returned to the surface becomes a waste



that must be managed.







     Oil and Gas Recovery Techniques



Conventional primary and secondary recovery processes produce



about one-third of the original oil in place.  These techniques



are described below.  Recovery efficiency is determined by the



properties of the specific rock, the properties of the petroleum



fluid, and the recovery technique(s) employed.







Petroleum recovery methods result in the generation of aqueous



solutions during production operations.  These wastes must be



treated, stored, recycled, or disposed (see Surface Production



Operations).








     Primary Petroleum Recovery.  "Natural drive" production



relies on natural reservoir pressure to drive the oil through the



complex rock pore network to the surface.  The driving pressure



is derived from the expanding of liquid and the release of



dissolved gas from the oil as the pressure of the well decreases



during production.   Also affecting the flow is the expansion of



free gas or "gas cap," the influx of natural water, and the



density of the fluids.








Many oil wells do not have a formation pressure high enough to



push the head of oil standing in the well to the surface.   In



these cases some artificial method for lifting the oil must be
                              1-60

-------
installed.  The most common installation involves a motor and



"walking beam" (like a seesaw) on the surface that operates the



pump on the bottom of the production string (see Figure 1-12).  A



chain of solid metal rods connects the beam and the pump.



Another method, called "gas lift," uses the buoyancy of gas



bubbles introduced into the oil column in the wellbore to lift



the oil to the surface.  A third type of artificial lift forces



some of the produced oil down the well at high pressure to



operate a pump at the bottom of the well.  Even though initially



an oil field may have enough pressure to produce naturally,



artificial lift will usually be required in later stages of



production.  Gas wells that produce little or no liquid do not



need artificial lift devices.  However, many low-rate gas wells



require compressors to maintain economic production levels.








     Secondary Petroleum Recovery.  Eventually,  the natural



reservoir pressure lowers to a point at which added energy must



be applied to the reservoir to produce significant amounts of oil



and gas.  Secondary recovery methods apply external energy to



move the petroleum through the reservoir.  Secondary oil recovery



usually involves the injection of gas or liquid into the



petroleum-bearing formation around producing wells.  The injected



fluids maintain reservoir pressure and displace a portion of the



remaining crude oil to the production wells (see Figure 1-13).








Although some formations are not amenable to water flooding, it



is the leading secondary recovery method and accounts for a very
                               1-61

-------
                                        HOHSEHEAD
        GEAR REDUCER


          BRAKE


       BELT COVER
PRIME
MOVER
     CRANK
     PIN BEARING
                                                           POLISHED
                                                           ROD
                                         STUFFING
                                         BOX
                      WIRELINE
                      HANGER (BRIDLE)
                                                             CASINGHEAD
     Figure  1-12.
Conventional Crank Counterbalanced Beam
Pumping Unit and Downhole Equipment
Source:  University of  Texas, 1979.
                                 1-62'

-------
!
                                         ^
                                         f
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                                                    CP
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1-63.

-------
large part of all U.S. oil production.  Fresh water, treated



produced water, or treated sea water is usually used as the



flooding liquid.







In the contiguous United States, the use of natural gas for



secondary recovery is limited because of its cost.  Natural gas



has a high market value and would only be used when water is not



available.  In northern Alaska, where natural gas currently has a



low market value, gas injection occurs for gas conservation,



reservoir pressuring, and secondary/tertiary recovery techniques.







     Tertiary Petroleum Recovery.  Tertiary (or enhanced) oil



recovery is the recovery of the last segment of oil that can



economically be produced from the petroleum reservoir over and



above what has already been economically recovered by



conventional primary and secondary methods.  Tertiary recovery



can be divided into the following techniques or methods:



chemical, miscible, and thermal.  All of these methods involve



injection of a solution or gas into the reservoir to improve the



mobility of the crude oil toward the production wells (U.S. DOE,



1984).







The chemical methods of enhanced recovery include polymer



flooding, surfactant flooding, and alkaline flooding.  Each



method is usually tied to a specific set of formation and crude



oil conditions.  Polymer flooding is becoming widely accepted for



commercial use.  Surfactant flooding is more expensive;  it has
                               1-64

-------
undergone limited field tests.  Alkaline flooding is undertaken



in  formations containing more acidic crude oils.







Miscible oil recovery involves formation flooding with such gases



as  carbon dioxide, nitrogen, or a hydrocarbon, e.g., propane.



The specific application of these techniques is the recovery of



low viscosity crudes.  Hydrocarbon flooding has been commercially



available since the 1950s.  Carbon dioxide and nitrogen flooding



are more recent developments.








Thermal recovery methods include steam injection and in situ



combustion ("fire flopding").  Steam processes are most often



applied to formations containing viscous crudes and tars.  In



situ combustion remains a terminal recovery technique because it



burns out the hydrocarbons as the firefront advances through the



formation.  However, in situ combustion can yield up to 4 barrels



of crude for each barrel burned.








     Workover Operations



As a well continues to produce crude oil and/or natural gas, its



production may begin to decrease and may even cease despite the



presence of significant reserves.  There are many geological and



mechanical reasons for this nonproductivity.  Workover operations



are operations on a producing well to restore or increase



production.   Producing wells need a workover operation when there



has been a mechanical failure or a blockage from corrosion
                               1-65

-------
products or sand, or when it i3 necessary to complete other zones



of the producing formation.







The circulating fluids used for workover operations generally are



similar to completion fluids (see Well Completion section).



While maintaining hydrostatic pressure in the well to overcome



formation pressure, a workover fluid must be compatible with the



formation and not adversely affect permeability.  Specially



treated brines or drilling fluids are used as workover fluids.



Produced water is frequently used.  When the well is put back on



production, workover fluids are disposed of into the reserve pit



or removed from the drill site for disposal.







     Reservoir Stimulation Techniques



The reservoir stimulation techniques discussed under Reservoir



Stimulation are equally applicable to production well



enhancement.  Stimulation wastes may include acids, additives,



and other wastes as discussed above.







Produced Water Volume Estimates



This section presents the methodology used to estimate produced



water volumes.  National produced water volume estimates for the



years 1981 through 1985 are presented in Table 1-6 and in



Figure 1-14.   Cumulative estimates for the 5-year period from



1981 through 1985 exceed 56.2 billion barrels.
                               1-66

-------
                                   TABLE 1-6

                     U.S. PRODUCED WATER ESTIMATES:  1981-1985
                                  (1,000 barrels)
                     1981
1982
1983
1984
1985
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Florida
Illinois
Indiana
Kansas
Kentucky
Louisiana
Maryland
Michigan
Mississippi
Missouri
Montana
Nebraska
Nevada
New Mexico
New York
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
South Dakota
Tennessee
Texas
Utah
Virginia
West Virginia
Wyoming
22,569
45,565
498
311,286
2,062,010
146,969s
37,145W
6,814b
5,340s
1,916,250C
13,496a
866,780C
0
76,632
403,020
574
145,831
65,028
1,263
313,771b
5,071b
54,871
7,342°
1,540,056°
0
26,205°
2,078
815C
2,690,275°
92,114°
0
7,158a
224,510°
24,831
45,224
434
184,189
2,147,551
157,307a
49,472.
7,838°
6,293a
1,916,250°
15,147a
819,615°
0
73,810
389,387
686
142,339
66,588
1,642
305,804u
5,029°
63,684
2,716
1,586,210°
0
27,825°
2,411
815°
2,620,828°
106,000
0
6,651a
231,749°
25,915
68,334
325
243,099
2,242,611
141,619s
58, 9H
8,259°
6,019s
1,916,250°
16,253s
774,555°
0
74,452
370,629
1,211
149,842
62,060
2,407
316,901
5,843
73,678
5,899
1,586,040°
31
29,467°
2,207
815°
2,546,022°
108,000
0
7,477s
238,993°
29,187
89,541
250
207,195
2,386,223
148,552s
77,361
8,165°
6,251s
1,916,250°
16,029s
799,390°
0
71,679
386,194
1,862
158,467
70,910
3,059
342,112
5,772
82,544
10,099
1,683,850°
120
31,104°
2,662
815°
2,486,000
114,000
0
7,263s
246,237°
34,039
112,780
288
226,784
2,553,326
154,255s
85,052
8,560
5,846s
1,916,250°
16,055s
794,030°
0
64,046
361,038
2,177
159,343
73,411
3,693
368,249
4,918
88,529
13,688
1,627,390°
33
31,131°
3,127
800°
2,576,000
126,000
0
7,327s
253,476°
U.S. Totals    11,091,336   11,008,325  11,084,127    11,389,143  11,671,641
aEstimate calculated from water/oil ratio from surrounding states.

°Estimate calculated from water/oil ratio from other years for which data was
 available.

°Estimate calculated by various means, based on information provided by State
 representatives.  Details of these calculations are presented in Table 1-8.
                                    1-67-

-------
            12-
   Total
Hydrocarbon  9-
 Production*
 (x 103bbl)
             6 -
             3 -
                    Produced Water Volume
                     Hydrocarbon Production
                1981
1982
1983
1984
1985
                         -12
                         - 9
                          Total
                        Produced
                         Water
                       (x 106bbl)
                                               - 6
                         - 3
          Crude oil, natural gas & NGL. Natural gas & NGL
          included on a Crude Oil Equivalence basis.

      Figure 1-14.   Annual Hydrocarbon Production and Estimated
                   Produced Water Volume,  1981-1985
                   Sources:  See Tables 1-1  and 1-6
                              1-68'

-------
Of all the wastes generated  from oil and gas exploration,

development, and production  operations, produced water figures

are reported with the most frequency (U.S. EPA, 1986b).  However,

problems exist with most of  the data presented.  One difficulty

is verifying the source.  Another problem is determining how to

evaluate data when it is derived using different approaches.



To avoid difficulties using  data from literature sources, EPA

used a direct approach by contacting representatives of state

agencies involved in collecting produced water volumes as

reported by oil and gas operators in their states.  The 33 states

currently producing oil and/or gas were cen"t~Ojf("«^l.

         Informationvp|untltei'*«( by agency representatives was

derived from three sources:

     o    Annual production  reports compiled by state
          agencies

     o    Injection reports  filed with state
          Underground Injection Control (UIC) offices

     o    An agency representative's estimation.



Table 1-7 lists the agencies contacted in this e-ffort* , in

addition to the types of information they provided.



Annual production reports consist of information submitted

monthly by operators.  These reports can include listings of

producing and non-producing wells and their locations, production

statistics for oil,  gas, and produced water, volumes of reserves,

or any other production data required by the particular state.
                               1-69

-------
                             TABLE 1-7

        LIST OF AGENCIES CONTACTED IN PRODUCED WATER SURVEY
State

ALABAMA
ALASKA

ARIZONA
ARKANSAS

CALIFORNIA

COLORADO

FLORIDA
ILLINOIS
INDIANA
KANSAS
KENTUCKY
LOUISIANA

MARYLAND
MICHIGAN

MISSISSIPPI
MISSOURI
MONTANA
NEBRASKA
NEVADA
MEW MEXICO
NEW YORK

NORTH DAKOTA
OHIO

OKLAHOMA
OREGON
PENNSYLVANIA

SOUTH DAKOTA
TENNESSEE
TEXAS
UTAH
VIRGINIA
WEST VIRGINIA
WYOMING
   Agency

State Oil and Gas Board
Oil and Gas Conservation
  Commission
Oil and Gas Commission
Oil and Gas Conservation
  Commission
Oil and Gas Conservation
  Commission
Oil and Gas Conservation
  Commission
Bureau of Geology
State EPA

Corporation Commission

Oil and Gas Conservation
  Commission
Oil and Gas Geology
State Dept. of Natural
 Resources

Oil and Gas Council
Oil and Gas Commission
Oil and Gas Commission
Dept. of Minerals
Oil Conservation Division
State Dept. of
  Environmental Resources
Industrial Commission
State Dept. of Natural
  Resources
Corporation Commission
Dept. of Geology
State Dept. of
  Environmental Resources
Oil and Gas Board
State Oil and Gas Board
Railroad Commission
Gas and Mining Division
Oil and Gas Commission
Dept. of Mines
Dept. of Environmental
  Quality
Source of Data

Injection Reports
Production Reports

Production Reports

Production Reports

Production Reports

Estimate
Production Reports
Production Reports

Estimate
No Information Available

Estimate
Production Reports

Production Reports

Injection Reports
Production Reports
Production Reports
Injection Reports
Production Reports

Hauling Reports
Production Reports

Injection Reports
Estimate
Production Records

Estimate
Production Reports
Estimate
Production Reports
Production Reports
Production Reports
No Information Available

Estimate
                                 1-70

-------
Survey contacts explained that the produced water volumes listed



in these reports are usually estimated by the operator from



water-to-oil ratios and metered production volumes, and are



therefore considered the most reliable estimates.  However, the



completeness of a state's inventory of production reports depends



on when the state began permitting procedures for production



operations.  Thus, the number of production reports on file does



not necessarily represent the number of production operations in



the state.  Production reports were the source of data from 17 of



the states (see Table 1-7).








Injection reports (or'disposal reports) are submitted by the



operators as required by a state UIC office.  Injection reports



contain operators' estimates of produced water volumes that have



been disposed,  either by injection into disposal wells or by



hauling to a centralized disposal well depending on the state's



reporting requirements.  The estimates may be based on flow meter



readings, hauling manifests, or an operator's estimation.  These



estimates represent only the volume of produced water that is



disposed of by injection,  and do not account for the total amount



of water that is actually produced.  Therefore,  injection reports



are considered a second-choice source of produced water volume



estimates.  Data from injection reports was provided by four of



the states in this survey (see Table 1-7).








Estimates based on the experience and judgment of the state



agency representatives were used if documented data were not
                              1-71

-------
available.  The representatives were asked to provide an



estimation that could be used in a calculation that would produce



a volume estimate.  Representatives of six states provided either



an estimated state-wide daily water production per well,



estimated state-wide water-to-oil ratios, or documented produced



water volumes for individual months.  Final produced water



estimates were calculated using these numbers with reported well



inventory and/or annual production figures (see Appendix).  Table



1-8 summarizes the calculations used for these estimates.








Produced water data were not available or were incomplete for



some states.  For example, if a produced water volume estimate



was available for only one year in a particular state, this



volume was used in a water-to-oil ratio to calculate estimates



for the missing years.  Similarly, if no data were available for



a particular state, water-to-oil ratios from neighboring



producing states would be used to calculate the data for each



year.  This approach assumes that neighboring states share common



geologies,  particularly producing basins (see Figures 1-1 and



1-2).  No estimate of produced water associated with gas



production could be included in these estimates.  Data for ten



states were calculated using these methods (see Table 1-6).
                               1-72

-------
                            TABLE 1-8

              SUMMARY  OF  PRODUCED WATER  CALCULATIONS


STATE:  Kansas

Information Provided by State Agency:

     o  5 to 5.5 million bbl of produced water is reinjected
        daily throughout the state.  (Using this number requires
        the assumption that this injection rate has been constant
        from 1981 to 1985.)

Calculation:

     o  Average of 5 and 5.5 is 5.25 million bbl/day

     o  Average annual produced water volume =
        (5,250,000 bbl/day) x (365 days/yr)  =
                                    1,916,250 thousand bbl/yr


STATE:  Louisiana

Information Provided by State Agency:

     o  Statewide ratio of produced water injected per volume of
        oil production is 5 bbl water/1 bbl oil.  (Using this
        number requires the assumption that this ratio has been
        constant from 1981 to 1985.)

Calculation:

     o  In 1981, oil production was 173,356 thousand barrels.
        Thus, annual produced water volume for 1981 =
        (173,356,000 bbl oil) x  (5 bbl water/bbl oil) =
                                         866,780 thousand bbl

        (This calculation was repeated for 1982 through 1985.)


STATE:  Oklahoma

Information Provided by State Agency:

     o  Statewide ratio of produced water injected per volume of
        oil production is 10 bbl water/1 bbl oil.  (Using this
        number requires the assumption that this ratio has been
        constant from 1981 to 1985.)
                                1-73

-------
                      TABLE 1-8 (Continued)

              SUMMARY  OF  PRODUCED WATER CALCULATIONS

Oklahoma Continued:

Calculation:

     o  In 1981, oil production was 154,056 thousand barrels.
        Thus, annual produced water volume for 1981 =
        (154,056,000 bbl oil) x (10 bbl water/bbl oil) =
                                       1,501,400 thousand bbl

        (This calculation was repeated for 1982 through 1985.)


STATE:  Pennsylvania

Information Provided by State Agency:

     o  Statewide ratio of produced water injected per volume of
        oil production is 1 bbl water/1 bbl oil.  (Using this
        number requires the assumption that this ratio has been
        constant from 1981 to 1985.)

     o  Statewide daily rate of produced water production per gas
        well is 3 bbl water/gas well/day, or 1095 bbl water/gas
        well/year.  (Using this number requires the assumption
        that this rate has been constant from 1981 to 1985.
        Pennsylvania was the only state that provided produced
        water information associated with gas production.)

Calculation:

     o  In 1981, oil production was 3,729 thousand barrels.
        Thus, annual produced water volume for 1981 (from oil
        production) =
        (3,729,000 bbl oil) x (1 bbl water/bbl oil)  =
                                           3,729 thousand bbl

     o  In 1981, the total number of active gas wells was
        20,526.  Thus, annual produced water volume for 1981
        (from gas production) =
        (1095 bbl water/gas well/yr) x (20,526 gas wells) =
                                          22,476 thousand bbl

     o  Total produced water volume for 1981 =
        (3,729,000 bbl water from oil) +
                          (22,476,000 bbl water from gas) =
                                          26,205 thousand bbl

        (This calculation was repeated for 1982 through 1985.)
                                1-74 .

-------
                      TABLE 1-8 (Continued)

              SUMMARY OF  PRODUCED WATER CALCULATIONS
STATE:  Tennessee

Information Provided by State Agency:

     o  Statewide daily produced water rate is 3 bbl/well/day for
        744 stripper wells.  (Using this number requires the
        assumptions that all produced water in the state has come
        from 744 stripper wells from 1981 to 1985, and that this
        daily rate has been constant from 1981 to 1985.)

     o  800,000 bbl of produced water were reported for 1985.
        (This was the only year for which a specific volume was
        provided.  Calculations were used to estimate volumes for
        the remaining years.)

Calculation:

     o  For the years 1981 through 1984,
        (3 bbl water/well/day)  x (744 wells) x (365 days/yr) =
                                             815 thousand bbl/yr

STATE:  Wyoming

Information Provided by State Agency:

     o  All produced water in the state is discharged through the
        NPDES permit system.

     o  In 1980, approximately 500 dischargers were permitted.
        In 1986, approximately 600 dischargers were permitted.
        Each discharger produces approximately 50,000 gallons
        daily, or 1,190.5 bbl/day. ( Using these numbers requires
        the assumptions that the number of NPDES dischargers
        increased linearly from 1980 to 1986, and that the rate
        of 1,190.5 bbl water/day has been constant from 1980 to
        1986.)
                               1-75

-------
                      TABLE 1-8 (Continued)

             SUMMARY OF PRODUCED WATER CALCULATIONS
Wyoming Continued:

Calculations:

     o  The following data were calculated by linear
     interpolation:

             Year            tfo. of Dischargers
             1980                  500
             1981                  516.67
             1982                  533.33
             1983                  550
             1984                  566.67
             1985                  583.33
             1986                  600

     o  Annual rate of produced water production for each
        discharger =
        (1190.5 bbl water/day)  x (365 days/yr)  =
                             434,532.5 bbl water/discharger/yr

     o  Annual produced water volume for 1981 =
        (434,532.5 bbl water/discharger) x (516.67 dischargers)
                                        271,266  thousand bbl

        (This calculation was repeated for 1982 through 1985.)
                               1-76 .

-------
                                         t
                            REFERENCES

American Petroleum Institute.  1976.  Primer of Oil and Gas
     Production, API, Dallas, TX.

         1981.  Primer of Oil and Gas Production, API, Dallas,
     TX.

     	.  1983.  Introduction to Oil and Gas Production.  Book 1
     of Vocational Training Series, pp.8 and 19.

     	.  1986.  Fundamentals of Petroleum.  3rd Ed.  Petroleum
     Extension Service.

     	.  1986.  Quarterly Completion Report.  Fourth Quarter,
     1985 (Marchl"!

         1986.  Quarterly Completion Report.  Third Quarter, 1986
     Toctober).

         1987.  API 1985 Production Waste Survey.
Chilingarian, G.V., and P.Vorabutr, 1983.  Drilling and Drilling
     Fluids.  Elsevier.

Federal Register. Vol 44, No. 73 (April 13, 1979), p. 22069.

	.  Vol 43, pp. 56448, 59056,  59481, 59836.

Interstate Oil Compact Commission.   1986.  History of Production
     Statistics;  Production and Reserves 1966-1985 (October).

Independent Petroleum Association of America.  1982.  The Oil
     Producing Industry in Your State, 1982 (SeptemberTT

	.  1983.  The Oil Producing Industry in Your State, 1983
     Tseptember).

	.  1984.  Petroleum Independent; The Oil and Gas Producing
     Industry in Your State, 1984(September).

	.  1985.  Petroleum Independent; The Oil and Gas Producing
naepena
,  1985-
     Industry in Your State, 1985-1986 (September).

	.  1986.  Petroleum Independent;  The Oil and Gas Producing
     Industry in Your State, 1986-1987 (September).

Kirk-Othmer Concise Encyclopedia of Chemical Technology.
     1985. 3rd Edition (abridged).New York:John Wiley &
     Sons, p. 853.
                              . 1-77

-------
                      REFERENCES (Continued)

Oil and Gas Journal.  September 23, 1985, p. 74.

	.  April 14, 1986.

	.  September 15, 1986, p. 64

Standard Oil Production Company.  1987.  Letter and attachments
     from M. T. Heffner re Technical Report on Oil and Gas and
     Geothermal Industry Wastes.  EPA Docket No. FG-86-OGRN-FFFFF
     (January 12).

Twentieth Century Petroleum Statistics.  1986.  Dallas, TX:
     Degolyer & McNaughton, eds.

U.S. Department of Energy, National Petroleum Council. 1984.
     Enhanced Oil Recovery (June).

U.S. Department of Energy, Energy Information Agency.  1985.
     U.S. Crude Oil, Natural Gas, and Natural Gas Liquids
     Reserves for 1985. DOE 10216(85).

U.S. Department of Energy, National Energy Information
     Center, 1987.

U.S. EPA.  Industrial Technology Division.  1985.  Proceedings
     Onshore Oil and Gas State/Federal Western Workshop
     (December).

	.   1986.  Oil and Gas Exploration, Development, and
     Production - Sampling Strategy (May).

	.  1986.  Technical Report;  Wastes from the Exploration,
     Development and Production of Crude Oil,  Natural Gas,  and
     Geothermal Energy (October).

University of Texas at Austin.  1979.   A Primer of Oilwell
     Service and Workover.

Williams, B. B., J. L. Gidley, and R.  S. Schechter.  1979.
     Acidizing Fundamentals.  Society of Petroleum Engineers of
     AIME, pp. 1-17, 92-102.
                              1-78 '

-------
                     APPENDIX






U.S. PRODUCTION AND DRILLING ACTIVITY:  1981-1985

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i
I
              U.S.  PRODUCTION AND DRILLING  ACTIVITY:   1981-1985
      FOOTNOTES

      aState rank in  U.S.  production  is  based  on  relative  production
       among the 33 producing  states.  States  that  have  no production
       of either oil  or  gas  (MD and OR)  have a rank of zero.

      bData  obtained  from  IOCC (see Sources).   All  other data  from
       IPAA, unless otherwise  noted.

      cNumber of producing oil wells  includes  stripper wells
       « 10 bbls./day).   For  some statesf  the reported  number of
       producing oil  wells is  less than  the reported number of
       producing stripper  wells.  Also,  reported  total production may
       be less than reported stripper  production.   This  discrepency
       exists because of the different sources of data used by IPAA
       (see  Sources).

      "Data  for footage  drilled were  not reported by IPAA  for
       exploratory and development wells until 1983.  Footage  data
       for 1981 and 1982 were"obtained from API's Quarterly
       Completion Report  (see  Sources).   In addition, when IPAA's
       number of drilled wells differed  from API's  for 1981 and
       1982,  API's data were used.   (API is IPAA's  source  for  this
       data.)

      eProduction data, numbers of drilled  wells, and footage
       drilled are reported for onshore  only.   Offshore  production
       data  were obtained  from the U.S.  Department  of Energy,
       National Energy Information Center  (see Sources).   Numbers of
       onshore wells  drilled and footage were  obtained from API's
       Quarterly Completion Reports  (see Sources).

      ^Numbers of producing oil and gas  wells  and stripper wells
       include offshore data,  as reported by IPAA  (see Sources).


      **  Data  not available.
     Sources:  API, 1986b; API, 1986c; API, 1987  (for Alaska's 1985
               oil drilling data only); IOCC, 1986; IPAA, 1982;
               IPAA,  1983; IPAA, 1984; IPAA, 1985; IPAA, 1986;
               U.S. DOE, 1987.
                                     I-A35

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