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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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
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42 South Florida
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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ANNUAL WASTE
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CUMULATIVE WASTE
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- 15
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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
wellheadusually through an oilfield gathering system serving
many wellsto 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
-------
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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'
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1-63.
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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
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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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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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