&EPA
United States
Environmental Protection
Agency
Office of Air Quality
Planning and Standards
Research Triangle Park NC 27711
EPA-450/3-78-047
August 1978
Air
Evaluation of
Emissions from
Onshore Drilling,
Producing, and
Storing of Oil
and Gas
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EPA-450/3-78-047
Evaluation of Emissions from
Onshore Drilling, Producing,
and Storing of Oil and Gas
by
L Norton, J. Hang, P. Farmanian, and R. Sakaida
Pacific Environmental Services, Inc.
1930 14th Street
Santa Monica, California 90404
Contract No. 68-02-2606
EPA Project Officer: David Markwordt
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air, Noise, and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
August 1978
-------
This report is issued by the Environmental Protection Agency to report
technical data of interest to a limited number of readers. Copies are
available free of charge to Federal employees, current contractors and
grantees, and nonprofit organizations - in limited quantities - from the
Library Services Office (MD-35), U.S. Environmental Protection Agency.
Research Triangle Park, North Carolina 27711; or, for a fee, from the
National Technical Information Service, 5285 Port Royal Road, Springfield,
Virginia 22161.
This report was furnished to the Environmental Protection Agency
by Pacific Environmental Services, Inc., 1930 14th Street, Santa Monica,
California 90404, in fulfillment of Contract No. 68-02-2606.
The contents of this report are reproduced herein as received
from Pacific Environmental Services, Inc. The opinions, findings,
and conclusions expressed are those of the author and not necessarily
those of the Environmental Protection Agency. Mention of company
or product names is not to be considered as an endorsement by the
Environmental Protection Agency.
Publication No. EPA-450/3-78-047
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TABLE OF CONTENTS
Section Page
1.0 ABSTRACT 1-1
2.0 INTRODUCTION 2-1
2.1 Emission Estimates 2-1
2.2 Projection of Emissions Through 1987 2-1
2.3 Costs and Analyses of Control Options 2-3
3.0 DRILLING OPERATIONS 3-1
3.1 Cable Tool Drilling 3-1
3.2 Rotary Drilling 3-3
3.3 Relative Usage 3-5
3.4 Rotary Drilling Emission Sources 3-6
3.5 Emission Assumptions 3-7
3.6 1976 Emission Estimates 3-10
3.7 Projected Emissions Through 1987 3-10
4.0 PRODUCTION AND PROCESSING 4-1
4.1 Collection of Individual Oil and Gas Field
Statistics 4-1
4.2 Production Technique Identification 4-2
4.2.1 Primary Production Methods 4-5
4.2.2 Secondary Production Methods 4-12
4.2.3 Production Method Assignment 4-15
4.2.4 Well Treatment 4-16
4.3 Surface Equipment Description 4-17
4.3.1 Oil and Gas Separators 4-18
4.3.2 Gun Barrel 4-19
4.3.3 Wash Tank and Settling Tanks 4-19
4.3.4 Heater Treater 4-20
4.3.5 Equipment Specific to Certain Production
Processes 4-21
4.3.6 Water Treatment Facilities 4-22
4.3.7 Custody Transfer 4-23
4.3.8 Artificial Lift Power 4-24
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Section Page
4.4 Field Specific Surface Equipment Identification... 4-25
4.4.1 Cold Climate Modification 4-27
4.5 Levels of Activity and Emission Estimation
Assumptions 4-29
4.5.1 FWKO Units 4-29
4.5.2 Gun Barrel 4-31
4.5.3 Heater Treater Liquid Separation 4-32
4.5.4 Wash and Settling Tanks 4-34
4.5.5 "Special" Heater Treater 4-35
4.5.6 Steam Generators 4-36
4.5.7 Fugitive Hydrocarbon Sources 4-38
4.6 Year of Record Estimates 4-38
4.7 Projected Emissions Through 1987 4-40
4.7.1 Projection Assumptions 4-40
4.7.2 Projection Calculations 4-46
4.8 Sulfur Compound Emissions From Natural Gas
Production 4-46
4.8.1 Year of Record Estimates 4-46
4.8.2 Projected Emissions Through 1987 4-50
5.0 PRODUCTION STORAGE 5-1
5.1 Storage Tank Data Base 5-1
5.2 Establishment of Storage Capacity - Field
Relationships 5-1
5.3 Tank Size Assignments 5-4
5.4 Emission Estimates and Tank Inventory 5-7
5.5 Projected Emissions 5-7
6.0 COSTS AND ANALYSES OF CONTROL OPTIONS 6-1
6.1 Control of Hydrocarbon Emissions From Fixed Roof
Storage Tanks 6-1
6.1.1 Vapor Recovery Using Compression 6-1
6.1.2 Internal Floating Roof 6-2
6.1.3 Potential Emission Reduction Achievement... 6-5
6.2 H2S Emissions From Natural Gas 6-5
6.2.1 Stretford Process 6-7
6.2.2 Claus Plant and Beavon Tail Gas Treatment.. 6-10
6.2.3 Potential Emission Reduction Achievement... 6-11
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Section
Page
6.3 Fugitive Hydrocarbon Emissions 6-14
6.4 Alternate Fuels in Steam Generators 6-16
7.0 CONCLUSIONS 7-1
8.0 REFERENCES 8-1
9.0 ACKNOWLEDGMENTS 9-1
APPENDIX I State by State Emission Estimates for Each
Projected Year 1-1
APPENDIX II Individual State Data Base Sources II-l
APPENDIX III Companies Contacted to Determine Extent of
LACT Activities Versus Trucking of Crude Oil III-l
APPENDIX IV Gun Barrel Emission Calculations IV-1
APPENDIX V The Emissions Calculations From a 1,000
Barrel Wash Tank V-l
APPENDIX VI Calculation of Wash Tank Relationship VI-1
APPENDIX VII Annual Oil Production Rates by States and
Railroad Commission Districts to the Year
1987 VII-1
APPENDIX VIII Surface Processing Emissions VIII-1
APPENDIX IX Storage Tank Calculations IX-1
m
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LIST OF ILLUSTRATIONS
Figure Page
3-1 Histogram of Land Rigs in the United States During
March 1978 3-8
3-2 Drilling Rig Projected Increases Through 1987 3-15
4-1 Sample Chart for Encoding Field Information 4-3
4-2 Mechanical Lift Pumping Unit 4-11
4-3 Field Equipment Prediction Model 4-28
4-4 Field Equipment Prediction Model Adjusted for Cold
Cl imates 4-30
5-1 Storage Capacity Relationships 5-3
LIST OF TABLES
Table Page
2-1 States Engaged in the Petroleum Production Industry... 2-2
3-1 Typical 3,048 m Drilling Rig Components 3-9
3-2 Active Rotary Drilling Rigs in Each State in 1976 3-11
3-3 Drilling Emissions for the Year 1976 3-12
3-4 Emissions From Drill Rig Engine 3-13
3-5 Nationwide Drilling Emissions for Years 1976-1987 3-16
4-1 Number of Fields Encoded for Each State 4-4
4-2 Cold Climate States 4-27
4-3 Comparison of Fuel Oil Emission Factors 4-37
4-4 Fugitive Hydrocarbon Emission Factors 4-39
4-5 Year of Record Surface Processing Emissions 4-41
4-6 Stripper Well Adjustment to Year of Record Surface
Processing Emission Totals.... 4-42
4-7 Decline or Growth Projections for Each State as a
Percentage Change From the Previous Year 4-47
4-8 Nationwide Production and Processing Emissions for
Years 1978-1987 4-48
4-9 Emissions of Sulfur Compounds in the United States in
1973 4-49
4-10 Projected Sulfur Compound Emissions in the United
States 1974-1987 4-51
5-1 Tank Inventory Summary 5-4
5-2 Calculation of Number of Tanks in Oil Fields Producing
150,000 Bbl/Yr and Not Employing Secondary Production. 5-6
5-3 Year of Record Storage Tank Summary 5-8
5-4 Storage Tank Hydrocarbon Emissions for the Years
1978-1987 5-10
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Table Page
5-5 Stripper Well Adjustments to Storage Tank Estimates
for the Years 1978-1987 5-11
6-1 Cost Parameters for Control of HC Emissions From
Fixed Roof Tanks 6-3
6-2 Control Cost Estimates for Existing Fixed Roof Tanks.. 6-4
6-3 Potential Hydrocarbon Reductions Due to Retrofit
of Tanks With Internal Floating Roofs 6-6
6-4 Cost Parameters for Control of H2S From Natural
Gas at Wellhead 6-8
6-5 Control Cost Estimates for Control of HoS From
Natural Gas at Wei 1 head 6-9
6-6 Cost Estimates for Control of H2S 6-12
6-7 Cost Parameters for Control of H2S From High Sulfur
Content Natural Gas 6-13
6-8 Impact of Sulfur Control Strategies on 1973 Emission
Estimates 6-15
6-9 Emission Estimates From the Combustion of Various
Fuels 6-17
7-1 Existing Annual Emissions From Drilling, Production
and Processing, and Storage Activities for Year 1976.. 7-2
7-2 1987 Projected Emissions 7-3
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1.0 ABSTRACT
This study provides an estimate of current HC, NO , CO, SO , and
X X
H-S emissions from the drilling, production, and storage of oil and
natural gas. Values used in this estimate are based on a combination
of published information, acquired field inventory data and a series
of model algorithms. Information presented includes number of wells
drilled in 1976, a methodology to predict the type and amount of
surface processing equipment expected in a specific field, and an
estimation of the number and size mix of storage tanks in each state.
Adjustments to the processing and storage tank emission estimates are
made to eliminate emissions associated with stripper well activities.
Projected emission levels for each year through 1987 are presented
for each process. Various control options and their cost effective-
ness are discussed. These include retrofitting existing storage tanks
with internal floating roofs and applying various sulfur recovery
processes to natural gas processing plants.
1-1
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2.0 INTRODUCTION
The purpose of this project v/as to evaluate the HC, SO , NO ,
A A
CO, and H2S emissions from the drilling, production and storage of
oil and natural gas in the United States. These activities are
currently being conducted in 32 states. These states are listed in
Table 2-1.
2.1 EMISSION ESTIMATES
Drilling emissions were calculated for each state. For reasons
of data quality and type of activity, production and processing, and
storage emissions were not calculated for seven states: Maryland,
Missouri, New York, Ohio, Pennsylvania, Virginia, and West Virginia.
Disregarding these states removes from the evaluation less than 1
percent of the national totals for 1975 for both oil and gas. Sulfur
emissions from natural gas processing were presented on a nationwide
basis. Each activity is discussed separately with drilling prac-
tices discussed in Section 3.0, production and processing (including
natural gas) presented in Section 4.0 and storage tanks appearing
in Section 5.0.
2.2 PROJECTION OF EMISSIONS THROUGH 1987
Projected levels of drilling activities for each state through
1987 were estimated using figures presented in the September 19, 1978
edition of The Oil and Gas Journal. For the purpose of projecting
state by state oil and gas production levels for each year through
1987, the services of Dr. Floyd Preston, Chairman of the Chemical
and Petroleum Engineering Department, University of Kansas were re-
tained. Dr. Preston presented growth or decline values for each
state by year based on a series of assumptions. These values were
used to calculate emission estimates from production and processing
2-1
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Table 2-1. STATES ENGAGED IN THE PETROLEUM PRODUCTION INDUSTRY
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
PENNSYLVANIA
SOUTH DAKOTA
TENNESSEE
TEXAS
UTAH
VIRGINIA
WEST VIRGINIA
WYOMING
2-2
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equipment and storage tanks for the years 1978-1987. Sulfur emis-
sions from the processing of natural gas were also projected from
1974-1987 based on the values prepared by Dr. Preston. Each pro-
jection scenario is discussed in the section relating to its ac-
tivity.
2.3 COSTS AND ANALYSES OF CONTROL OPTIONS
Various possible control options for specific types of equip-
ment or processes are discussed with special emphasis being placed
on establishing the cost effectiveness of each system. This discus-
sion appears as Section 6.0.
2-3
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3.0 DRILLING OPERATIONS
During 1976, a total of 39,348 wells were drilled in the
United States, requiring the operation of 1,658 drilling rigs
(Reference 1). Wells being drilled are typically classified
as either an exploratory (wildcat) or development type. An
exploratory well is searching for new hydrocarbon formations.
A development well is drilled into a known field in an effort
to improve the recovery efficiency of the extraction operation.
The majority of wells drilled (between 75 and 80 percent) are of
the development type.
There are two basic drilling methods available for use in
the United States today, the cable tool and the rotary.
3.1 CABLE TOOL DRILLING
Cable tool drilling is an old technique used for centuries
to drill water wells which has been applied to the search for
new oil and gas. The well is produced by successive strikes of
a steel bit against the formation rock. A "spudder" is commonly
used, working off an eccentric that alternately raises and drops
the bit +_ 3 feet to impact the bit on the bottom.
Components of a cable tool drilling rig consist of the
drilling string, rig lines, walking beam, prime movers, bailers,
and sand pumps. The drilling string is composed of a drill
bit, drill stem, jars and tool joints. The drill bit is a
heavy steel bar, generally 1.2 (4) to 2.4 m (8 ft) long, which
can be sharpened to different degrees depending on the formation
being penetrated. Additional weight for the downward blow is
furnished by the drill stem, a cylindrical steel bar which is
attached to the string directly above the bit. Jars are heavy
3-1
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steel links which form directly above the bit. Jars are heavy
steel links which form a chain. Their function is to assist in
extracting the tools from soft, sticky formations. Tool joints
are metallic connectors which attach such items as the bit and
drill stem to each other.
The prime mover for a cable tool drill rig is commonly an
internal combustion engine although electric and steam drive
applications are available. The prime mover drives a belt which
rotates the band wheel. Using a series of connections, includ-
ing a walking beam, the rotating band wheel imparts the recipro-
cating motion to the drilling line necessary for the operation.
The debris formed in the bottom of the hole as the well is
being drilled is called cuttings. Accumulated volumes of this
material can interfere with the drilling process. To remove
the cuttings, at periodic intervals the drilling string must be
lifted from the hole and a bailer sent down. The bailer acts
as a scoop to remove the debris. A valve in the bottom of the
bailer is opened and closed by a protruding stem as the bailer
is alternately raised and lowered. Often the debris is too
coarse to be collectable using the bailer. When this happens,
a vacuum pump termed a sand pump is lowered into the hole to
collect the material.
The rig has three different cables: drilling line, sand
line and calf line. The drilling line connects the drilling
string to a large surface spool which controls the raising
and lowering of the apparatus. The sand line is normally
attached to a bailer, which is alternately raised and lowered
to remove the accumulated cuttings periodically from the well.
The calf line is used to run casing into the well.
3-2
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3.2 ROTARY DRILLING
The drilling method now almost exclusively in use in the
United States is rotary drilling. In the rotary drilling
method, a downward force is applied to a rotating bit which is
fastened to and rotated by a drill string. The drill string
is composed of high quality drill pipe and drill collars with
new sections or joints being added as drilling progresses.
Drilling fluid or mud continuously circulates down the inside
of the drilling string through nozzles in the bit and upward
in the annular space between the drill pipe and the bore hole
lifting cuttings from the bottom to the well surface. At the
surface, the returning fluid is diverted through a series of
tanks or pits to allow cutting separation and necessary treating.
Then, the mud is picked up by the pump suction and repeats the
cycle.
The basic rotary rig components include a derrick or a
mast and substructure, draw works, mud pumps, prime movers, drill-
ing string, bits, drilling line and miscellaneous rig equipment.
The derrick or mast and substructure provide the necessary raising
and lowering vertical clearance of the drilling string during
drilling operations.
The draw works is the key piece of equipment. It functions
as a control center from which the driller operates the rig.
The draw works retains the drum which stores the drilling line
during hoisting and drilling operations. For the circulation
of drilling fluid, a mud pump is employed to ensure the desired
pressure and volume. A prime mover is necessary to generate
power for operations such as circulation of drilling fluid and
hoisting. Although the internal combustion engine is the most
commonly used prime mover, the electric motor and steam engine
are also employed.
3-3
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An extremely expensive rig component is the drilling string
which must be replaced periodically. The rotary bit can be
classified into three general types: drag type, rolling cutter
and diamond type. The drag and rolling cutter types are gener-
ally used for drilling through soft, sticky formations, and the
diamond type is normally used in hard formations. The rotary
drilling line functions as a means of handling the loads sus-
pended from the hook. The rotary table transmits the rotation
to the drilling string and suspends the pipe weight connections
and trips. The traveling block connects the drilling line to
the hook and swivel.
The drilling fluid is an important feature of the rotary
drilling method. It functions as bit coolant, drill cutting
lifter, remover of any entrained formation gases, provider of
a hydrostatic column that will overcome the pressure in the
formation drilled and preventer of fluid encroachment into the
well bore.
The first rotary drilling fluid was water. Since water
could not adequately support the borehole and prevent caving
in of the quicksand encountered during drilling progression
through softer formation, a muddy drilling fluid was devised.
When selecting the drilling fluid, the specific require-
ments of the geologic area in question and the fluid's ability
to perform the function necessary in that area have to be
considered. In soft rock areas, a precise control of mud
properties is required, while in hard rock areas plain water
may be a satisfactory and even superior drilling fluid.
The drilling fluid is mostly composed of prepared benton-
itic clays, caustic soda, starch, lignin or lignocellulose
and barium sulfate, a weight additive. Water or oil may be
3-4
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used as the fluid constituent of the mud. Since the bottom
hole temperature affects the property of the mud in deep well
drilling, drilled material is added constantly to the drilling
fluid as temperature changes.
When the formation pressure exceeds that of the drilling
fluid, the resevoir fluid will begin to flow into the well bore
and cause either a controlling kick or blowout. If a wellhead
is equipped with special heavy-duty equipment, it can be shut
off during periods when adverse pressure differences are
encountered.
3.3 RELATIVE USAGE
There are advantages attached to each technique. The cable
tool method has lower equipment costs, daily operating expenses,
and transportation costs. The drilling rig set-up time and
expenses are also lower for a cable tool rig. Disadvantages of
the cable tool method include slower drilling rates (about half
that of a rotary rig), inability to provide an automatic control
over high pressure, unconsolidated or caving formations, high
failure rates of the drilling line, and increased danger of
blowouts.
Current application of the cable tool method is generally
restricted to shallow holes into known formations. It is esti-
mated that wells drilled by the cable tool method numbered
between 1 and 10 percent in the United States with the trend
being toward lower usage rates. Therefore, for the purpose
of estimating emissions from drilling activities, the evaluation
will be directed toward the rotary drilling method.
3-5
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3.4 ROTARY DRILLING EMISSION SOURCES
The important emission sources associated with rotary
drilling operations are mud degassing, blowouts, and power
generation. Only power generation and its related combustion
contaminants is a continuous source of significant air pollution
emissions. The drilling rig prime mover is commonly an internal
combustion engine. While there are several fuels which can be
used in these engines, the most popular seems to be diesel fuel.
Emissions from mud degassing have a more intermittent
character. As the drilling bit passes through a gas producing
formation, a small amount of the gas may seep into the well bore
and become entrained in the drilling mud. Normally, gases
encountered in this manner are unexpected and of small volumes.
Consequently, after separation from the mud in a mud-gas separator
(degasser), the gases are vented to the atmosphere. In rare
instances where large volumes of gases are anticipated or toxic
gases (containing HLS) are expected, the mud degassing will be
performed in a fully enclosed system and all gases released are
captured and flared. Due to the high variability in frequency
and volume discharges of such occurrences, no calculations of
emissions from mud degassing are attempted in this report. How-
ever, the amount of gas escaping to the atmosphere from these
operations is expected to be small.
A similar situation exists for blowouts. By properly
maintaining blowout preventers in the well hole as drilling
progresses, the frequency of a blowout can be expected to be
small. Since a blowout is an upset condition and does not
represent normal operations, emission estimates are not made.
Again, the overall relative contribution of blowout emissions
to the atmosphere can be expected to be small.
3-6
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3.5 EMISSION ASSUMPTIONS
The size of rotary drilling rigs employed for oil and gas
drilling varies with the type of formation being drilled and
the drilling depth. Variables include the required engine
power output, size of derrick, substructure, draw work and mud
pump. According to the "Histogram of Land Rigs in the United
States During March 1978" obtained from the American Petroleum
Institute (Figure 3-1), the average drilling rig rating is
approximately 3,048 m (10,000 ft). The basic rig components
and sizes for the average rig are listed in Table 3-1.
Calculable emissions from drilling then arise only from
the internal combustion diesel engine of 708.4 kW selected as
typical. The reported fuel use associated with this engine of
p
2,650 f (70 gal) per hour results in an engine load factor of
between 55 and 60 percent.
In order to attach drilling emission values to rig
activities in a particular state, the most desirable means
would be to use Table 3-1 to establish the total footage drilled
in each state during 1976 and then attach an energy requirement
(Btu of hp per footage drilled) to this value. Several factors
arose during this evaluation which made this methodology unreal-
istic. No individual contacted was willing to assign specific
values to the amount of energy necessary to drill a foot.
Reasons for this reluctance were the high variability in forma-
tion hardness which could be expected to be found. Evaluators
next attempted to verify a value of 147 kWh/m (60 hph/ft)
drilled which appears on page 83 of Atmospheric Emissions From
Offshore Oil and Gas Development and Production (Reference 2).
Again, drilling contractors contacted were unable to satis-
factorily apply this value to onshore activities.
3-7
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to
co
5 G 7 0 9 10 11 12 13 14 15 1C 17 10 19 20 21 22 23 24 25 20 27 28 29 30 31 32 33 34 35
DRILLING Itlfi RATINGS - 1000 FT.
Figure 3-1 Histogram of Land Rigs in the United States During March 1978
(Provided Courtesy of the American Petroleum Institute
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Table 3-1. TYPICAL 3,048m DRILLING RIG COMPONENTS9
Prime mover - 2 diesel fired reciprocating engines totaling up to
708.4 kW (950 hp) at 2,100 rpm
Power takeoff pump - Driven from prime mover transmission
Drawworks - Hoisting drum (diameter x length) - 59.0 cm x 111.8 cm
(23% in x 44 in)
Line size - 2.9 cm (1-1/8 in)
Brake rims (diameter x width) - 116..8 cm x 31.8 cm (46 in x 12% in)
Effective brake area - 21,445 cm2 (3,324 in2)
Brake cooling mechanism - Circulating water
Hoisting speeds - 5 forward, 1 reverse
Rotary speeds - 5 forward, 1 reverse
Hydromatic drive chain - 3.2 cm (1% in) quadruple
Rotary drive chain - 3.8 cm (1% in) double
Drum drive chain - Two 3.2 cm (1% in) triple
Mast - Clear height (with 13 ft floor) - 30.4 m (99 ft 7 in)
Leg spread - 2.6 m (8 ft 6 in)
Hook load capacity - 8 lines - 158.8 MT (350,000 Ib)
(API Standard 4E) 10 lines - 165.6 MT (365,000 Ib)
Racking capacity - 11.4 cm (4% in) outside diameter drill pipe -
3,505.2 m (11,500 ft)
(Range 2 doubles) 10.2 cm (4 in) outside diameter drill
pipe - 3,901.4 m (12,800 ft)
Substructure - Floor height - 3.4 m, 4.0 m, and 4.6 m (11 ft, 13 ft,
and 15 ft)
Floor size (length x width) - 4.2 m x 5.5 m (13 ft 8 in x 18 ft)
Ground overall dimensions (length x width) - 12.2 m x 3.7 m
(40 ft x 12 ft)
Rotary capacity - 158.8 MT (175 ton)
Setback capacity - 90.7 MT (100 ton)
Total simultaneous capacity - 249.5 MT (275 ton)
Rig field weights - Front - 27.2 MT (30.0 ton)
Rear - 27.2 MT (30.0 ton)
Total - 54.4 MT (60.0 ton)
a Reference 3
3-9
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Project engineers were forced to abandon this methodology
in favor of a different evaluation. A total of 1,660 rotary
drilling rigs were reported in operation in 1976 (Reference 1).
Table 3-2 shows the average number of rigs active in each
producing state during 1976. Due to the downtime for logging,
running electrical surveys, cementing, waiting on cement to set,
rigging down, moving and rigging up, it is estimated that each of
these average rigs operates 65 percent of the time. Combining
all of these factors, drilling emissions for each state can be
calculated.
3.6 1976 EMISSION ESTIMATES
The 1976 drilling emission totals for each state are
shown in Table 3-3. The method of calculation is as follows
(the discussion is presented in English units to be consistent
with emission factor units).
(70 gal/hr)(8,760 hr/yr)(.65) = 398,580 gal/yr/rig
By then multiplying by the average number of rigs active in a
state in 1976, the total amount of diesel fuel burned in
drilling operations in that state are made.
Emission estimates for these figures are made based on
the following emission factors from Compilation of Air Pollu-
tion Emission Factors, AP-42, Part A, Second Edition, Table
3.3.3-1 (refer to Table 3-4).
3.7 PROJECTED EMISSIONS THROUGH 1987
Drilling projections were made based on figures appear-
ing in The Oil and Gas Journal, September 18, 1978 (Reference 4).
In the report it is estimated that the U.S. rotary rig count
3-10
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Table 3-2. ACTIVE ROTARY DRILLING RIGS IN EACH STATE IN 1976a
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Florida
Illinois
Indiana
Kansas
Kentucky
Louisiana
Maryland
Michigan
Mississippi
Missouri
17
14
1
15
89
38
5
22
2
51
1
231
1
24
32
lb
Montana
Nebraska
Nevada
New Mexico
New York
North Dakota
Ohio
Oklahoma
Pennsylvania
South Dakota
Tennessee
Texas
Utah
Virginia
West Virginia
Wyoming
28
8
2
54
9
19
26
186
10
2
lb
653
19
lb
12
86
Reference 1
Assumed a minimal level of activity if wells were
drilled during 1976, even if reported average was
zero
3-11
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Table 3-3. DiRILLING EMISSIONS FOR THE YEAR 1976
(103 kg)
State
Al abama
Alaska
Arizona
Arkansas
Cal ifornia
Colorado
Florida
111 inois
Indiana
Kansas
Kentucky
Louisiana
Maryland
Michigan
Mississippi
Missouri
Montana
Nebraska
Nevada
New Mexico
New York
North Dakota
Ohio
Oklahoma
Pennsylvania
South Dakota
Tennessee
Texas
Utah
Vi rginia
West Virginia
Wyoming
TOTAL
SOX
96
79
6
85
502
214
28
124
11
288
6
1,303
6
135
181
6
158
45
11
305
51
107
147
1,049
56
11
6
3,684
107
6
68
485
9,366
NOX
1,442
1,187
85
1,272
7,547
3,222
424
1,866
170
4,325
85
19,587
85
2,035
2,713
85
2,374
678
170
4,579
763
1,611
2,205
15,772
848
170
85
55,370
1,611
85
1,018
7,292
140,761
HC
115
95
7
102
603
258
34
149
14
346
7
1,566
7
763
217
7
190
54
14
366
61
129
176
1,261
68
14
7
4,427
129
7
81
583
11,857
CO
314
258
18
277
1,641
701
92
406
37
941
18
4,260
18
443
590
18
516
148
37
996
166
350
480
3,430
184
37
18
12,042
350
18
221
1,586
30,611
3-12
-------
Table 3-4. EMISSIONS FROM DRILL RIG ENGINE'
Pollutants
Carbon monoxide
Hydrocarbons
Oxides of nitrogen
Oxides of sulfur
Emission Factor
lb/103 gal
102
37.5
469
31.2
g/hphr
3.03
1.12
14.0
0.931
Emission Rate
kg/hr
3.22
1.18
14.88
1.00
Ib/hr
7.1
2.6
32.8
2.2
Basis: 950 hp diesel engine using 70 gph fuel. The load fac-
tor is between 55 and 60 percent
3-13
-------
has grown at a pace of about 170 rigs per year. While the trend
has accelerated over the past 18 months, the value of 170
additional rigs per year for the years through 1987 presents a
representative scenario for future activities which is consis-
tent with the modest increasing trend over the next 5 years ex-
pected by API drilling experts.
Figure 3-2 presents a graphic illustration of the projected
drilling activities for the years through 1987. Using the
number of rotary rigs active in each state during the base year
1976 (see Table 3-2), the 170 additional active rigs each year
were assigned proportionally to each state and emission esti-
mates calculated. The results of applying this projection
procedure to the 1976 data are presented in Table 3-5. Using
the assumption that drilling activities will increase by an
average of 170 rotary rigs per year through 1987, an approximate
111 percent increase in drilling emissions can be expected.
State by state emission estimates for each projected year are
presented in Appendix I.
3-14
-------
CO
I
4,600-
4,400-
4,200-
4,000-
3,800-
3,600-
3,400-
3,200-!
3,000-
2,800-
2,600-
2,400-
2,200-
2,000-
1,800-
1,600-
1,400-
1,200-
1,000-
800-
600-
Slope = 170 rigs/yr
1972 1973 1974 1975 1976 19/7 1978 1979 1980 1981 1932 1983 1984 1985 1986 1987
Year
Figure 3-2. Drilling Rig Projected Increases Through 1987
-------
Table 3-5. NATIONWIDE DRILLING EMISSIONS FOR YEARS
1976-1987
(103 kg)
Year
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
S0x
9,366
10,324
11,265
12,238
13,185
14,158
15,103
16,075
17,025
17,973
18,907
19,855
N0y
A
140,761
155,098
164,100
183,678
198,538
212,448
226,530
239,353
255,124
269,216
283,291
297,548
HC
11,857
14,027
15,159
16,327
17,463
18,642
19,780
20,947
22,087
23,220
24,352
25,499
CO
30,611
33,752
36,805
39,980
43,053
46,272
49,338
52,485
55,553
58,661
61,728
64,835
3-16
-------
4.0 PRODUCTION AND PROCESSING
A three step process proved necessary to estimate emissions
from oil and gas field production and processing operations:
(1) identification and data collection for oil and gas fields
on a state-by-state basis; (2) assignment of production methods
to each oil and gas field; and (3) prediction of the types and
numbers of processing equipment which could be expected to be
found in each field.
4.1 COLLECTION OF INDIVIDUAL OIL AND GAS FIELD STATISTICS
The first step in the identification of petroleum producing
fields involved contacting the related state agency in each pro-
ducing state. Information from each of these states was reviewed
for suitability to project needs. In some cases, the information
received was inadequate. In those instances, the International
Oil and Gas Development (Reference 5) published by the Inter-
national Oil Scouts served as a supplementary document and
accuracy check.
By combining the two sources of information, it was possible
to compile a fairly detailed list of petroleum fields in most
states. However, there were exceptions. Data were not available
on an individual field basis for activities in Maryland, Ohio,
and Virginia. Since the combined contribution to the national
production totals for these states in 1975 amounted to less than
0.5 percent for oil and less than 0.6 percent for gas (Refer-
ence 6) they were excluded from this study.
Under the Scope of Work of the contract which generated
this report, the study was to disregard stripper well activity.
A stripper well is defined as any well which produces 10 barrels
4-1
-------
a day or less. The National Stripper Well Association in Tulsa,
Oklahoma was contacted in an attempt to identify and geographic-
ally locate stripper activities. After consultation with Mr.
Frank B. Taylor of that organization and review of the National
Stripper Well Survey, January 1, 1977 (Reference 7), it was
judged that production activities in Missouri, New York, Penn-
sylvania, and West Virginia were 100 percent stripper in nature
and were not included in this study.
Field information was encoded for the remaining 25 states
on forms similar to the one in Figure 4-1. Often, a field
extracts oils of distinctly different characteristics from dif-
ferent levels of formation. These specific zones of oil are
termed pools. In some instances, the state data were detailed
enough to allow individual pool information to be recorded. For
many fields and/or pools in a state, the production value for
the Year of Record was zero. Since the method of calculating
emissions was totally dependent on the production value, these
fields were ignored. Table 4-1 presents the number of fields
encoded for each producing state and whether or not pool infor-
mation was also available. The specific information used to
establish the data base for each state is presented in Appendix II.
The field information was entered onto the sheets using a
series of numerical codes. Specific oil or gas characteristics
were unavailable for most field cases. One supplemental source
used to improve the oil sulfur content statistics was a publica-
tion titled Sulfur Content of Crude Oils (Reference 8).
4.2 PRODUCTION TECHNIQUE IDENTIFICATION
The second step in the generation of production and pro-
cessing operation emission estimates is the identification of
the production technique used in each field. A complex combination
4-2
-------
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Figure 4-1. Sample Chart for Encoding Field Information
-------
Table 4-1. NUMBER OF FIELDS ENCODED FOR EACH STATE
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Florida
Illinois
Indiana
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Montana
Nebraska
Nevada
New Mexico
North Dakota
Oklahoma
South Dakota
Tennessee
Texas
Utah
Wyoming
Total
Number
of Fields
33
21
4
254
395
534
11
342
210
2,049
268
1,182
455
363
219
349
2
830
132
1,948
12
46
18,612
109
681
29,061
Individual Pool
Information Exists
No
Yes
No
Yes
Yes
Yes
No
No
No
No
No
No
No
Yes
Yes
No
No
No
Yes
No
No
No
No
No
No
Not Encoded
Mary!and
Missouri
New York
Ohio
Pennsylvania
Virginia
West Virginia
4-4
-------
of formation and petroleum fluid characteristics will determine
the necessary method of extraction. While individual fields
often utilize a combination of techniques, in general, a new
field will begin production using one of the natural lift
primary production methods, move to artificial lift as pressure
losses decrease the field's natural ability to force the fluids
to the surface and finally resort to secondary recovery tech-
niques requiring injection or flooding to encourage the oil to
flow to production wells.
4.2.1 PRIMARY PRODUCTION METHODS
Two types of production methods are categorized as primary,
natural lift (also termed flowing) or artificial lift. Oil
cannot move and lift itself from reservoirs through wells to
the surface. Natural lift production methods utilize the energy
of formation in the gas or salt water (or both) occurring under
high pressures with the oil to force oil through and from the
pores of the reservoir into the wells.
When the reservoir pressure drops to the point where it is
not possible for a well to flow naturally, or the desired pro-
duction rate is greater than the actual production rate, it
becomes necessary to install artificial lift to supplement the
reservoir energy for lifting fluids from a well.
Artificial lifts used for this purpose are the gas lift,
plunger lift and well pumps, the last of which can be classified
according to the type of pump installed at the bottom of the hole,
Although plunger pumps are the most commonly used oil-well pump,
electric and hydraulic pumps are also used.
4-5
-------
4.2.1.1 Natural Lift Methods
4.2.1.1.1 Dissolved Gas Drive
In nearly all reservoirs, varying quantities of gas are
dissolved in the oil. Well completion into such a formation
results in a reduction in pressure in the reservoir causing the
gas to emerge and expand. As the gas escapes from the oil and
expands, it drives oil through the reservoir toward the wells
and assists in lifting it to the surface. For the fields where
the reservoir is at or below the bubble point pressure, the
recovered oil is replaced by an equal amount of expanding gas
as the reservoir depletion begins. This process accelerates
as the reservoir pressure decreases, requiring more gas expan-
sion per unit volume of oil produced. Consequently, this
production method is generally considered the least effective
type, yielding maximum recoveries of between 15 and 25 percent
of the oil originally present in the reservoir.
4.2.1.1.2 Expanding Gas Cap Drive
In many cases there exists more gas with the oil in a
reservoir than the existing conditions of temperature and pres-
sure will allow to be held dissolved in the oil. This extra
gas, being lighter than the oil, exists in the form of a cap
of gas over the oil. Such a gas cap is an important additional
source of energy, for, as production of oil and gas proceeds and
the reservoir pressure is lowered, the gas cap expands to help
fill the pore spaces formerly occupied by the oil and gas pro-
duced. Also, when conditions are favorable, some of the gas
coming out of the oil is conserved by moving upward into the gas
cap to further enlarge the gas cap. This method is more effective
4-6
-------
than dissolved gas drive alone, yielding oil recoveries from
25 to 50 percent.
4.2.1.1.3 Natural Water Drive
The natural water drive process is effective when there is
a vast quantity of salt water existing under pressure in the
surrounding parts of the oil and gas formation. As the pres-
sure in the reservoir is reduced by production of oil and gas,
energy is generated by the expansion of the water*. This energy
in turn supplies the required driving forces to move the water
into the regions of lowered pressure and displace the oil and gas
in an upward direction toward the wells. This process is
capable of yielding up to 50 percent of the oil originally
present in the reservoirs.
4.2.1.2 Artificial Lift Methods
4.2.1.2.1 Plunger Lift
Plunger lift is also known as free piston lift. The pro-
duction of oil and gas is accomplished by a steel plunger, or
swab, which utilizes the reservoir pressure for lifting and
gravity for returning it to the producing zone. During the
production operation, the force of gravity pulls the plunger
* Water actually will compress, or expand, to the extent of about
one part in 2,500 per 690,000 pascal (100 psi) change in pres-
sure. This effect is slight for any small quantity, but becomes
of great importance when changes in reservoir pressure affect
enormous volumes of salt water that are often contained in the
same porous formation adjoining or surrounding a reservoir
(Reference 9).
4-7
-------
from the top to the bottom of the well. As the plunger strikes
the footpiece, its bottom valve closes. A column of fluid is
collected. The casing pressure is then gradually built up to
its peak, and the plunger starts lifting its fluid column to
the surface where it is discharged into the flow line. The
plunger continues to rise until it strikes the bumper which
opens the plunger valve. Then, the process repeats itself.
4.2.1.2.2 Gas Lift
Gas lift is a process of lifting fluids from a well by the
injection of relatively high pressure gas between the casing and
tubing strings. The injected gas from the annul us enters the
tubing through the installed gas lift valves, where energy is
being generated by the expansion of high pressure gas. When
this energy builds to a level exceeding the bottom hole pressure,
it begins to lift fluids to the well surface. The production
rate of the fluids is a function of the gas injection rate, which
can be stabilized by fixing it at some pre-determined injection
point. In the case of slow production wells, an intermittent
gas lift method is employed to provide the necessary energy to
lift oil and gas to the surface at a more desirable rate.
4.2.1.2.3 Electric Pumps
Electric submersible pumps are centrifugal pumps with their
shafts connected directly to an electric motor. The required
power for this submerged unit is supplied by an insulated cable,
which runs from the power source at the surface to the motor at
the well bottom. As a result of the revolving motion of the
impellers in the pump, the applied pressure forces the fluid
through the tubing to the surface. The capacity of this type
of pump is generally high and depends upon the depth and size of
4-8
-------
the well being lifted, varying from 250 to 26,000 barrels of
fluid per day.
4.2.1.2.4 Subsurface Hydraulic Pumping
Hydraulic pumping is accomplished by a hydraulic engine
directly connected to a rodless reciprocating pump, which is
powered by a fluid (termed power oil). Surface power is supplied
from a standard engine-driven pump.
There are several types of hydraulic pumping systems. The
first type consists of two strings of tubing along side one
another or a small string inside the other. Power oil is forced
through the larger size tubing by the high pressure pump at the
surface, triggering the submerged hydraulic engine, which in turn
moves a power piston connected to the production plunger in
the bottom hole pump. The exhausted power oil becomes mixed with
the well fluid and returns to the surface via the smaller tub-
ing. The second pumping system requires only one string of tubing
set on a casing packer. Power oil is forced down through the
tubing string as in the first type of system. The power oil
mixes with well fluids and passes through the submersible pump
and is transported to the surface using the space between the
tubing and the casing string. The third type of system is the
closed power fluid system. This system is being used where
there is limited surface area or where clean power oil is
unavailable. The system is termed closed because exhausted
power oil returns to the surface through a separate string of
tubing than the produced well fluid.
4.2.1.2.5 Mechanical Lift
This type of artificial lift utilizes pumps at the bottom
4-9
-------
of the hole, run by a string of rods. The drive mechanism for
these plunger pumps is provided at the surface. Energy from
the prime mover is transferred to the well using the familiar
pumping unit shown in Figure 4-2.
Pumping wells need a means of packing or sealing off the
pressure inside the tubing to prevent leakage of fluid and gas
outside the polished rod. Stuffing boxes consist of flexible
material or packing housed in a box which provides a method of
compressing the packing. When the stuffing box becomes worn
and loses its seal, it is replaced by the fluid pump operator.
Generally speaking, the atmospheric emissions from stuffing box
packings are considered to be negligible. Gases diverted into
the casing are also a potential source of hydrocarbon emissions.
These gases commonly are being disposed of as field fuel or
sales when a large enough quantity of gas is available. Other-
wise, it is vented directly to the atmosphere or flared.
Subsurface equipment consists of sucker rods and the plunger
pump. Sucker rods are solid high-grade steel rods that are run
inside of the producing tubing string to connect the subsurface
pump to the pumping unit. Plunger pumps are cylindrical pumps
consisting of the following basic parts: the working barrel,
the plunger, a standing valve, and a traveling valve. These
pumps can be categorized into three groups: tubing pumps, rod
pumps, and casing pumps.
Tubing pumps utilize a working barrel that is attached to
the lower end of the well tubing, while the plunger is suspended
on the lower end of the sucker rods. Rod pumps have their work-
ing barrel and plunger assembled together as a single unit, which
may be installed or withdrawn by the rods. Casing pumps are
those with no auxiliary tubing used and a packer is set against
4-10
-------
PRIME MOVER
OR POWER PLANT
2- GEAR REDUCER
3- CRANK AND
COUNTER WEIGHT
4- PITMAN
5- WALKING BEAM
6- HORSE HEAD
7- COUNTER WEIGHT
8- SAMPSON POST
9- BRIDLE
10-CARRIER BAR
II- POLISHED ROD CLAMP/
12- POLISHED ROD
13-STUFFING BOX
14-TEE
15-TUBING RING
16-CASING HEAD
17-CASING STRINGS
18-TUBING STRING
19-SUCKER ROD
20-FLUID LEVEL
21-ROD PUMP
Figure 4-2. Mechanical Lift Pumping Unit (Reference 9)
4-11
-------
the tubing string to support the rod pump.
The plunger pump is set at a depth in the well at which the
pump will stay covered by fluid during the pumping operation.
The upward stroke of the rod pulls the plunger up through the
working barrel. This action causes the traveling valve to
close, which permits the column of fluid above to rise with the
plunger, while the standing valve opens to admit fluids from
the well to the working barrel. On the downward stroke, the
traveling valve opens, while the standing valve closes and the
rod pushes the plunger down through the working barrel, forcing
the fluid from the working barrel into the tubing. The result
is fluid being lifted to the surface through the tubing on each
upstroke of the plunger.
4.2.2 SECONDARY PRODUCTION METHODS
In primary recovery, naturally occurring forces, such as
those associated with gas and liquid expansion are utilized to
produce the oil. However, the possibility of a field producing
in this manner for its entire lifetime is exceedingly small.
In almost all cases, primary production accounts for less than
50 percent of the total recoverable reserves. In recent years,
the high cost of oil and gas has made it more profitable to
recover this additional oil by enhanced recovery methods. The
most widely applied techniques to recover oil once primary
methods are no longer economically satisfactory are secondary
recovery methods, a term applied to processes which restore
or inject the needed producing energy back into the well.
Secondary recovery can be broken down into three categories:
(1) waterflooding, (2) repressurization and pressure mainte-
nance, and (3) thermal methods (steam soak and steam drive).
4-12
-------
Thermal methods technically belong to a category of production
types termed tertiary. Their inclusion in this report as a
secondary method is made to make this discussion consistent
with contract requirements.
4.2.2.1 Pattern waterflooding
Pattern waterflooding is a technique employed whereby
additional oil is recovered from reservoirs following depletion
of the natural reservoir energy. In a program of this type,
the wells to be used for water injection are interspersed between
producing wells. The injection of water into the alternative
wells forces oil into the well bores of adjoining producers
that would otherwise remain in the sand unrecovered. There are
many injection patterns that can be used. A common type of
waterflooding is one in which each oil well is surrounded by
four water-injection wells (located at the four corners of a
square).
4.2.2.2 Water and Gas Injection, and Pressure Maintenance
Projects
The production of oil from a reservoir usually causes a
decline in pressure. Since in most instances the produced oil
is accompanied by significant amounts of gas and water, the
decline in pressure for a given amount of oil production may
be much greater than if only the oil itself had been withdrawn
from the reservoir. Maintaining this pressure will permit
greater oil recovery and more economical operation of the wells.
Pressure maintenance is the application of fluid injection early
in the producing life of a reservoir to extend a field's pro-
duction life.
In certain fields, there is a plentiful supply of water,
usually called an aquifer, in direct contact with the oil
4-13
-------
reservoir and connected by means of a highly permeable channel
to allow replacement of the oil as it is withdrawn. In fields
having such a natural active water drive, the pressure may be
maintained simply by replacing the produced fluids with aquifer
water. In a field of this type, pressure maintenance by water
injection is never required because natural conditions are such
as to accomplish the end that a man-made project would be
designed to accomplish.
In a field where such a condition does not exist, it is
necessary to inject water or gas back into the reservoir as a
means of replacing the reservoir fluids withdrawn while produc-
ing oil.
4.2.2.3 Thermal Methods (Steam Injection)
The utilization of steam for increased oil recovery is
called steam injection. There are two steam injection processes,
steam soak and steam drive.
4.2.2.3.1 Steam Soak
Steam soak is also known as the "huff and puff" method.
Steam is injected into a reservoir at the location of the produc-
ing well head. This is termed the huff stage. The well head is
subsequently closed for a period of from 1 week up to 2 months.
This period allows the heat of the steam to be transferred to
the crude oil in the reservoir. Hence, the viscosity of the oil
decreases to the point where it can flow more easily. The
puff stage begins when the well head is opened and the well
starts producing. The produced fluid is a combination of oil
and water.
4-14
-------
4.2.2.3.2 Steam Drive
Steam drive is very similar to water-flooding. The main
difference being that steam is used instead of water. Steam is
generally injected at the perimeter of a reservoir, similar to
pattern operations used in waterflcoding. This essentially drives
the oil into the producing zone where it is recoverable. The
technique is generally employed in formations containing heavy
(low API gravity) oil. The steam lowers the viscosity of the
oil and permits it to flow.
4.2.3 PRODUCTION METHOD ASSIGNMENT
Each field identified was assigned a production technique.
Since it is common to find more than one production method
employed in a single field, provisions were made for multiple
entries into the data base. The quality of information obtained
was such that a determination could only be made between natural
flowing wells, artificial lift wells, and the three specific
secondary production methods. Numerical well assignments to each
of these five production categories were made for each field.
Referring to Figure 4-1, the following numerical coding scheme
was applied to wells in each field:
Primary production method — Column 76
Natural flowing wells — 1
Artificial lift wells - 2
Secondary production methods - Column 80
Waterflood - 1
Repressurization — 2
Steam injection - 3
4-15
-------
4.2.4 WELL TREATMENT
Wells often may be treated to improve the natural drainage
pattern, or to remove barriers within the oil-bearing formation
which prevent easy passage of fluids into the well bore. Such
processes are classified as well stimulation treatments. Stimu-
lation treatments are classified primarily as fracturing, acid-
izing, or use of other special chemicals. These processes are
often used in combination since they frequently help each other.
Programs for individual wells vary according to well character-
istics and conditions, economics, and end result desired.
4.2.4.1 Fracturing
Fracturing is a process by which fluid pressure at the
bottom of a well is developed by high pressure pumps to the
extent necessary to counterbalance the weight of rock above it,
plus sufficient additional pressure to crack the formation.
This makes possible the introduction of fluids carrying sand,
walnut hulls, or other small particles of material into the new
crevices created to keep the fractures open.
4.2.4.2 Acidizing
Acidizing is a process by which acids are applied to the
producing formation to enlarge existing crevices, or are forced
into the pores of the formation to increase the flow capacity
of the drainage system.
4.2.4.3 Special Chemical Treatments
Special chemical treatments are those in which acid is not
a material part. Although many of the materials in this group
often are used in conjunction with fracturing and acidizing,
4-16
-------
they have definite application in their own right.
Water can sometimes create a block when present in the tiny
pore spaces of a formation. Certain chemicals may be applied to
lower surface tension. By contact, the chemicals break large
^drops of water into several smaller ones thus, allowing fluid
trapped behind the surface tension to be released to flow to
the well bore.
In many instances, when oil and water become intimately
mixed they form an emulsion. With continued agitation, the
emulsion may form a very thick mass which impairs flow of fluids
to the well bore. Chemicals may be used to break this emulsion.
The resulting decrease in viscosity frees the fluids to move
to the well bore.
4.2.4.4 Exclusion Justification
Emission estimations from well treatment activities have
been excluded from this study. These practices are normally
handled by contractors who bring their own equipment to the site.
Since injection is commonly done under extremes of pressure, it
is important to minimize leaks from the equipment. The only
major potential source of emission would occur if combustion
materials were used to generate needed energy requirements.
The most common fuel consumed is diesel in an internal combus-
tion engine. Since the well treatment processes are intermittant
and vary with the geographical area, these sources have been
disregarded from this study.
4.3 SURFACE EQUIPMENT DESCRIPTION
The third step necessary before emission estimates can be
made involves the identification of the surface equipment used
4-17
-------
in a given field. Once oil has been extracted from the ground
using one of the previously mentioned production techniques,
it is the very rare case in which that oil can be transported
directly to the refinery. Sediments and water produced with
the oil necessitates the presence of equipment in the field
that cleans the oil and removes most of the water. The most
commonly found activities and pieces of equipment are described
below.
4.3.1 OIL AND GAS SEPARATORS
There are many types of separation systems including low
pressure and high pressure systems, and free water knockout
(FWKO) units. In each case, the separator is a pressure vessel
used for the purpose of separating well fluids into gaseous
and liquid components.
The FWKO unit is a two phase separator that sets apart the
gas and liquid petroleum from water. Low pressure and high
pressure separators can be a two or three phase vessel. They
are usually sized to handle high instantaneous rates of flow.
Generally, FWKO's or other separation equipment such as gun
barrels or wash tanks (see next section) are added to the
field treating system when the system becomes overloaded
because of increasing water production. The additional equip-
ment eliminates this water and saves energy requirements and
treatment capacity. The gas coming off from these separators
is usually vented to the atmosphere. However, if sufficiently
high quantities are generated, they will be compressed for
uses such as field fuel, gas lift, gas re-injection or sales.
This report will not discuss the handling of this associated
produced gas.
4-13
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4.3.2 GUN BARREL
A gun barrel is a cylindrical tank used to separate oil
from water when oil characteristics make the differentia-
tion easy to accomplish. The tank is equipped with a flume
which routes the fluids received either directly from the well
or from the separators downward to a level below the oil-water
interface. Released at this level, the oil and water separate
with the lighter oil floating to the upper level of the tank,
where it is withdrawn to storage by means of a pipe. Water
exits through piping with a dump valve or water siphon
controlled flow. The water siphon has a closed equalizer loop
back into the tank for gases breaking free of the water. Any
gases entrained in the fluids would be liberated directly to
the atmosphere. Gun barrel applications are made only when the
difference in densities between the oil and water is great
enough to allow easy separation.
4.3.3 WASH TANK AND SETTLING TANKS
A wash tank is commonly used when a combination of low gas
quantities and emulsified mixtures of oil and water are present.
The wash tank is a large vessel equipped with a low-pressure
liquid separator (located atop the tank), a spreader, level
control, and heating coil. Mixtures of oil and water first
enter the separator where any entrained gas in the liquid is
removed and vented to the atmosphere. When vapor amounts are
substantial, a vapor recovery system may be employed. The
liquid is then gravitationally brought through a large diameter
vertical pipe to be dispersed uniformly by the spreader below
the level of the oil-water interface. In order to break the
oil-water emulsion, heat is applied to this zone of the tank
by hot water or steam circulated in heating coils. Clean oil
4-19
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is skimmed at the top of the oil layer and water is drawn off
at the bottom of the tank.
A settling tank is a fixed roof tank used to assist in the
reduction of the water content in the oil. The tank is commonly
used in conjunction with a wash tank if large quantities of
water are produced at the well head. By placing the settling
tank ahead of the wash tank, it can serve both as flow regula-
tor and reduce the separation time required in the wash tank.
4.3.4 HEATER TREATER
A heater treater is a pressure vessel equipped with a heat-
ing capability to break emulsions that basic separation cannot
achieve. The most commonly used treaters are the direct-gas-
fired vessel for oil treating and the indirect-gas-fired vessel
for gas treating. The flow in the treaters is essentially the
same as that in the wash tank. The main difference is that the
treaters operate under pressure, which separates substantial
volumes of gas. Although an indirect treater can also be
used for treating oil emulsions at lower pressures with minor
amounts of gas, its use is usually for heating gas at elevated
pressures. It raises the temperature of the gas so that
hydrates will not form when pressure is reduced.
Often used in place of or in combination with heat to
break the emulsion are chemicals. A great variety of chemicals
can be used for this purpose, but no one material has proved
effective for all emulsions.
After being heated and/or chemically treated, the emulsion
is allowed to enter a tank where the water can separate from
the oil. The separated liquids are then drawn off — the oil
going to the stock tanks, and the water going to the disposal
system.
4-20
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4.3.5 EQUIPMENT SPECIFIC TO CERTAIN PRODUCTION PROCESSES
Each of the types of equipment just discussed is generally
utilized in a field as a result of fluid characteristics instead
of the production method used. However, several secondary pro-
duction techniques do require specific pieces of equipment to
be effective.
4.3.5.1 Mater Injection and Flooding
In general, field equipment employed in secondary water
injection projects is similar to that used in primary produc-
tion. Mechanical lift pumping units and submersible pumping
units are extremely common in a typical water injected field.
Techniques used to separate the crude oil from the water (i.e.,
heater treaters, wash tanks, etc.) are identical with those
techniques used in primary production. The basic difference is
that provisions for injection of water into the reservoir must
be provided. The heart of a system of this type is the water
injection pump station. Here, water usually transported from
the formation is pumped to the water injection well. The
water injection well sometimes is an old shut-in well that was
previously producing. It can also be a newly drilled hole made
solely to be used as a water injection well. The water injected
has generally been reclaimed at the production site from the
crude oil. After separation from the crude oil and removal
of any residual oil, the water is usually softened and then
either reinjected into the formation or routed to disposal.
4.3.5.2 Thermal Operations
The heart of a steam injection field or a steam drive field
is the steam generator. This unit is generally fueled by crude
4-21
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oil or natural gas. The steam is produced on-site and trans-
ported to the injection wells in heated or highly insulated
pipelines. In the case of steam drive, it commonly takes four
to five barrels of water as injected steam to produce one barrel
of oil. For steam injection, the amount of steam used can vary
greatly. Once the oil has been produced, the surface treatment
procedures are similar to those used in other production systems
in which the produced fluid contains water.
4.3.6 WATER TREATMENT FACILITIES
The water leaving the free water knockout unit, the wash
and surge tanks, the gun barrels, and heater treaters must be
properly treated to reduce the oil and sediment content before
discharging into sewers, the ocean, or injecting into the
injection wells.
Gravity settling basins are commonly used when a high
degree of water cleaning is not necessary. Otherwise, filters
are installed as a secondary cleaning method, especially for
waterflood systems, where the water must be thoroughly cleaned
of oil and sediment.
Another treatment method employs flotation cells. When
this system is employed, air or gas is injected upstream of the
main process pumps of the system. Some waste waters require
chemical treatment for control of basic oxygen demand, micro-
organisms, and certain gases. The chemical is mixed with air
and the water inside the pump and discharged to the retention
tank, where the pressure is approximately 203,000 (2) to
304,000 pascal (3 atmospheres).
As the water enters the flotation cell, the air is released
as the pressure drops to atmospheric. This causes small sludge
4-22
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and oil particles to be pushed to the top of the flotation cell
where a rotating skimming arm sweeps the oil sludge into a
compartment for removal. The settled solids at the bottom of
the cell are removed by a bottom grit scraper which is also
rotated by the same drive shaft as the skimming arm. The clean
water effluent is then discharged into the environment or used
for repressurizing the well.
4.3.7 CUSTODY TRANSFER
After the produced fluids have been separated, the result-
ing crude oil must be transported to the refinery. For many
years, the oil industry handled this problem by storing the
crude in tanks on or near the field. This oil was eventually
transported to the refinery using trucks. During the last
decade, concentrated engineering efforts have developed pipeline
deliveries and automatic devices for handling and measuring
oil. Lease automatic custody transfer (LACT) units now exist
at most major fields, with oil still being tank gauged in the
remaining fields.
A typical LACT unit uses several surge tanks for "averaging"
deliveries to the pipeline. In some cases, compressors are
tied directly into surge tanks to recover gas and stabilize oil
and materially aid overall vapor recovery.
An automatic detector monitors the amount of basic sediment
and water (BS & W) flowing and diverts oil for further treatment
if the content exceeds a preset maximum. This is another advan-
tage to using LACT units. Some pipelines will not accept more
than 0.2 percent BS & W content although 0.3 percent is a more
common limit.
In order to properly evaluate emissions due to custody
transfer it is necessary to ascertain how common LACT units and
4-23
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pipeline systems and their associated negligible hydrocarbon
emissions are used as opposed to tank gauging and trucking of
oil with their higher emission potential. A telephone survey
to a number of pipeline companies throughout the United States
(see Appendix III) revealed that in almost any field producing
significant quantities of oil, LACT units (and by assumption,
a pipeline) will be employed. Trucking and tank gauging is
more common in fields containing a majority of stripper wells.
Since this study excludes stripper well activities, it is
assumed that all transport is achieved via LACT units and pipe-
lines.
4.3.8 ARTIFICIAL LIFT POWER
The vast majority of production pumping units are powered
by electricity. Pumping units were originally powered by gas
produced at the field. The introduction of electricity as the
primary power source took place many years ago. The primary
reason for the switchover to electric motors was to reduce
maintenance costs. Electrical motors are far more dependable
under a variety of climatic conditions. The old-fashioned gas
driven motors inevitably freeze up during periods of cold weather.
Production time and money are lost. Another reason for prefer-
ring electricity over gas is that many wells are not allowed
or are unable to oil 24 hours a day. Wells of this nature are
called "on clock." An electric driven pump can easily be put
"on clock" automatically. However, a gas driven pump requires
a field operator present to turn the pumping unit on or off.
Today, the occurrence of gas powered pumping equipment is
often limited to isolated well locations where electricity
is not available. Due to the maintenance and operation costs,
4-24
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the installation of gas powered pumping units at an "on clock"
well is impractical.
Investigators concluded that the occurrence of gas powered
pumping can be expected to be very infrequent. By assuming that
power will be supplied by purchased electricity, the emission
levels in the fields from power generation will be zero. What
will not be considered here is the impact of this electrical
demand on powerplant emissions.
4.4 FIELD SPECIFIC SURFACE EQUIPMENT IDENTIFICATION
The technique used to remove water from produced oil varies
greatly with the location of the field and the type of oil being
produced. To be able to estimate emissions from surface ac-
tivities, it was necessary to predict what type of equipment
could be found in each field. A limiting condition for this pre-
diction was the field parameters available. After evaluation
of the data base, it was concluded that the only field parameters
which were consistently available from state to state were the
oil and gas production statistics for each field, the API gravity
of the oil in each field, and the number of wells.
In some cases, the decisions were relatively easy and straight-
forward. All fields were assumed to utilize water treatment fa-
cilities. Thermal operations had been specifically defined in the
data base, making fields containing steam generators easy to iden-
tify. While it would also be an easy matter to identify water in-
jection fields requiring an additional pumping station, since
this only results in increased power consumption, a fact which is
disregarded, no special emphasis was placed on these fields.
The major effort in this area was concentrated on utilizing
available field parameters to predict the types of oil-gas-water
separation systems which would be found in a field. Primary emphasis
4-25
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was placed on the API gravity, a parameter that describes the spe-
cific gravity of the produced oil. The higher the API gravity of a
certain oil, the lighter it is and hence the easier it separates from
water (with an API gravity of 10). After careful study and field
investigations in California, Colorado, Louisiana, New Mexico,
and Texas, it was found that generally, an oil with an API gravity
of 35 or greater could easily be separated from water in a gun barrel.
Since a gun barrel operates at atmospheric pressure, if gases were pre-
sent in fluids passing through a gun barrel, they would be lost.
Therefore, in fields which produce gas as well as oil with a high
API gravity, a FWKO unit was assumed to be online ahead of the gun
barrel to remove the gas.
Oils with an API gravity less than 35 were found to have a
tendency to emulsify, making separation more difficult. Treatment
of these oils required the more involved systems of heater treaters
or wash tanks and surge tanks. Wash tanks and heater treaters both
perform the same function, the difference being that a heater treater
is pressurized and a wash tank is not. Any oil containing gas which
passed through a wash tank would lose that gas to the atmosphere.
Fields which produce gas as well as oil with an API gravity of less
than 35 were expected to utilize a FWKO unit followed by a pres-
surized heater treater. Fields which produce oil with negligible
quantities of gas only were assumed to treat the fluids through a
settling tank followed by a wash tank.
A great many fields produce gas and/or condensate without any
oil. These fields utilize the indirect fired heater treater to
separate these two products. It was assumed that any field which
produced one or both of these products without oil would require
this "special" heater treater.
All fields identified in the nationwide inventory have been
assigned a numerical code to describe the petroleum products recovered.
4-26
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The numerical code is:
Oil production - 1
Oil and condensate production only - 2
Oil, condensate and gas production - 3
Condensate and gas production only - 4
Oil and gas production only - 5
Gas production only - 6
Condensate only - 7
A computer program was written to apply the equipment prediction model
to each field based on the numerical code for that field. Figure
4-3 presents the steps used in the model to describe field surface
equipment.
4.4.1 COLD CLIMATE MODIFICATION
In field investigations of operations in Colorado it was dis-
covered that in certain northern states the climatic conditions
necessitate heating the produced fluids regardless of how light the
oil. These states are summarized in Table 4-2. In such a state
Table 4-2 COLD CLIMATE STATES
Alaska
Colorado
Michigan
Montana
Nebraska
North Dakota
South Dakota
Utah
Wyoming
4-27
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API > 35
I
IV)
CO
Oil, water and gas
Fluids from well head
Field codes 2, 3, 5
Oil and water only
Field code 1
Gas and condensate only
Field codes 4, 6, 7
Figure 4-3. Field Equipment Prediction Model
-------
it became necessary to modify the Field Equipment Prediction Model.
Basically, the gun barrel was eliminated from consideration. For
fields in these states which produce gas in conjunction with any
type of oil, surface treatment would consist of a FWKO unit followed
by a heater treater. For fields which produce oil only,a surge tank
followed by a wash tank would be used. The modified model is
shown in Figure 4-4.
4.5 LEVELS OF ACTIVITY AND EMISSION ESTIMATION ASSUMPTIONS
Once the Field Equipment Prediction Model has been applied to a
field and expected surface equipment identified, it is necessary to
assign levels of activity to each field so that emission estimates
can be made. Due to the nature of the field data encoded, levels of
activities and emission estimates were modified to be expressed in
terms of barrels of throughput per year.
4.5.1 FWKO UNITS
These units are pressurized vessels which do not utilize combus-
tion. The only sources of emissions would be any control valves
associated with routing fluids into or around the process and the
occasional venting of gases during an overpressurized situation.
It is not possible to quantify emergency pressure relief valve vent-
ings but the amount is expected to be small. Control valve emissions
are assumed to be handled in a general production field fugitive
hydrocarbon emission factor which is applied to each field. Number
of units and emissions from FWKO units were not calculated.
4-29
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Fluids from well head
*-
-p>
i
CO
o
Oil , water and gas
Field codes 2, 3, 5
Oil and water only
Field code 1 ""
Gas and condensate only
Field codes 4, 6, 7
Any API
Any API
Special
Heater Treater
FWKO
Settling Tank
*,
Heater
Treater
Wash Tank
^
T
0
S
T
o
R
A
G
E
A
N
D
L
A
C
T
Figure 4-4. Field Equipment Prediction Model Adjusted for Cold Climates
-------
4.5.2 GUN BARREL
Data used in predicting the number of gun barrels present in a
field were obtained in field visits to New Mexico and Texas. The
standard size of a gun barrel is 280 barrels capacity with dimen-
sions of 3 m (10 ft) diameter by 6.1 m (20 ft) high. Since the unit
operates at atmospheric pressure it was assumed to have emission
characteristics similar to a fixed roof tank with a flat roof.
Calculated emissions from each tank are 96.8 kg of HC/year (see
Appendix IV).
In order to correlate this value for one gun barrel to a pro-
ducing field utilizing several tanks, a relationship must be formed
between gun barrel and field throughputs. Field investigations
revealed that a settling tank of 280 barrels capacity has a maximum
daily throughput of 125 barrels of oil. A field correlation can be
developed using the following procedure. The relationship:
(field production in net bbl/yr)
(125 net bbl/day/gun barrel)(365 day/yr)
establishes the number of gun barrels expected in a field. Mul-
tiplying this number by 96.8 kg of HC/year/gun barrel will give the
annual emissions from this field due to gun barrel activities. Cor-
relating this directly to field size as reported in thousand
barrels per year yields:
(field size in 103 bbl/vr) I"-, (96.8 kg of HC/.yr/gun barrel)(103)
mem size m lu DDi/yr; [(125 net bbl/day/gun barrel}(365 day/yr)(
(field size in 103 net bbl/yr)(0.00212 WT/103 bbl) = HC emissions from gun barrels
4-31
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4.5.3 HEATER TREATER LIQUID SEPARATION
To predict the amount of energy needed to treat given amounts
of oil, the following relationship was used:
Q = M(Cp)(At)
where Q = heat gain, Btu/yr
co = production weight rate, Ib/yr
Cp = heat content of oil, Btu/lb-°F
At - necessary temperature change of oil, °F
Production weight rate information in the data base is in 10 bbl/yr.
To convert GO to allow use of this value, the following modification
is made:
w= [(X)bbl/yr](350,000 lb/103 bbl of water) (0.85 Ib of
oil/lb of water)
- 297,500 (x) Ib/yr where x = annual oil production in
103 bbl
The temperature change (At) needed to bring the crude oil to
treating temperature will vary from field to field and with the
season. Little or no heat may be required in the summer with up
to 60 to 80°F required in the winter. For the purpose of this
study, a mid-range value of 40°F for At was used. Combining this
value with the figure 0.5 for Cp (provided by the American Petroleum
Institute), the heat gain necessary to treat a given amount of oil
can be calculated as:
Q - [297,500 (x) lb/yr](0.5 Btu/lb-°F)(40°F)
= 5.95 x 106 (x) Btu/yr
If it is assumed that no heat is lost to the heater's surroundings,
then the heat gained by the fluid is equal to the burner heat
4-32
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release. Conversion of heat input to burner heat release will not
be 100 percent efficient. If the overall heater treater efficiency
is 60 percent, the necessary heat input will be:
5.95 x 106x) Btu/yr = 6
Assuming the heat input to be provided by the combustion of natural
gas with a heat content of 1,050 Btu/ft3 (AP-42, Appendix A, page
A-4), the amount of fuel required will be:
9.917 x 106 (x) Btu/yr = 44 (x) ft3/
1,050 Btu/ftJ
The combustion of natural gas in the heater treater is expected to
produce emission characteristics similar to indirect fired units.
Corresponding emission factors from AP-42, page 1.4-2 are:
SO = 0.0006 lb/103 ft3 of gas burned
X
NO = 0.23 lb/103 ft3 of gas burned
/\
HC = 0.003 lb/103 ft3 of gas burned
CO = 0.017 lb/103 ft3 of gas burned
Therefore, to calculate heater treater emission totals from a
given field for each of these four pollutants in terms of metric
tons (MT) per year, the values used are:
^n _ (0.0006 lb/103 ft3)[9.444(x) x IP3 ft3/yr]
bux ~ 2,204.6 Ib/MT
= 2.6 x 10"6(x) MT/yr
NOV = 9.9 x 10"4(x) MT/yr
X
HC = 1.3 x 10"5(x) MT/yr
CO = 7.3 x 10"5(x) MT/yr
4-33
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4.5.4 WASH AND SETTLING TANKS
As with the heater treater, the wash tank utilizes heat to
separate oil and water emulsions. No information was available
concerning heat inputs from these units. Although the heat input
to a wash tank may generally be less than a heater treater, it
was assumed that the combustion relationship for the heater treater
also applies to the wash tank.
Unlike the heater treater, both the settling tank and the wash
tank operate at atmospheric pressure. This will result in fugitive
hydrocarbon losses. An inventory of wash tanks in California showed
the representative size of the units to be 1,000 barrels and emis-
sions from each tank to be 550.2 kg/yr (see Appendix V).
To relate the emissions of hydrocarbons per wash tank to a
field predicted to engage in that activity, it is necessary to
calculate the number of wash tanks expected in each field. Data
presented in Appendix VI can be correlated into the following
relationship:
y = 139 - 7.99(x) where y = expected wash tank capacity
per 1CP barrels of annual
throughput
x - annual production in 10
barrels
Once (y) has been calculated for a field, by multiplying that value
by the field size, an expression for the wash tank capacity in that
field can be made. Dividing this number by 1,000 and rounding up
to the nearest whole number to account for partial storage will
determine the number of wash tanks in a field.
It was assumed that one settling tank of identical size
would be associated with each wash tank. By multiplying the number
of wash tanks by two and then by 0.5502 MT/yr/tank, the hydrocarbon
4-34
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emissions from a field's wash tank and settling tank activities
can be predicted.
4.5.5 "SPECIAL" HEATER TREATER
From consultation with various equipment manufacturers
(Reference 10) it was found that the most commonly used indirect
field heater treater for separating gas and condensate is a 0.6 (2)
by 1.8 m (6 ft) unit utilizing eight (8) coils, each with a surface
? 2
area of 2.7 m (.29 f t ). Coil working pressure is 23.2 mega pascal
(3,372 psig). The heater treater utilizes 264 mega joule (250,000
Btu) per hour of heat input, usually in the form of natural gas,
3 3
and is capable of processing 1 mega m (35 million ft ) of gas per
day.
O
The value 35 million ft per day corresponds to 12,776 million
ft per year. To determine the number of heater treaters being
used in a gas field it is only necessary to divide the reported
3
value from the data base by 12,776 million ft per year and
round upward to the nearest whole number to account for partial
3
capacity. Using the value of 1,050 Btu/ft for the heat content
of natural gas, the generation of 250,000 Btu/hr will require
3
the consumption of 238.1 ft /hr of gas.
Emission factors used are from AP-42, page 1.4-2.
S0x = 0.6 lb/106 ft3 burned
CO =17 lb/106 ft3 burned
HC = 3 lb/106 ft3 burned
NOV = 230 lb/106 ft3 burned
X
These values correspond to:
SO = 5.6 x 10 MT/yr/heater treater
x -7
CO = 1.6 x 10 MT/yr/heater treater
4-35
-------
HC - 2.8 x 10"3 MT/yr/heater treater
NO = 2.2 x 10"1 MT/yr/heater treater
A
4.5.6 STEAM GENERATORS
The secondary recovery methods termed Thermal Operations utilize
a steam generation system to inject heated fluids into the reservoir.
Data obtained in field visits to Long Beach and Kern County, California
thermal operations, as well as the American Petroleum Institute,
indicate that a good rule of thumb in steam operations is that one
barrel of crude oil is used for fuel for each four barrels of crude
oil produced.
Recently published reports have identified emission factors for
the combustion of crude oil. Data from these reports were supplied
to project investigators by the Western Oil and Gas Association and
are presented in Table 4-3. The last column of the table represents
the average of the other two sets of factors. Evaluators used the
average values for crude oil combustion.
3
Since annual production figures are only available in 10
barrels, it is necessary to adjust the emission factors to this
number. A total of 250 barrels of oil will be combusted to recover
one thousand barrels.
/ 250 barrels of oil burned \(42 11ons/barre]
MO-3 barrels of oil produced/
produced/
3 3
= 10.5 x 10 gallons of oil burned/10 barrels of oil produced
Emissions factors in terms of metric tons (MT) of pollutant per
thousand barrels of oil produced are therefore:
en - (10.5 x 103 gal/103 bb1)(150.5 1b/103 gal) _ n 717 MT/1n3 ,,,
bUx - 2,204.6 Ib/MT " U>/l/ m/IU DDI
4-36
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Table 4-3. COMPARISON OF FUEL OIL EMISSION FACTORS
(lb/103 gal)
Pollutant
Sulfur Dioxide
Sulfur Trioxide
Carbon Monoxide
Hydrocarbons
Nitrogen Oxides (NO,,)
High Sulfur Crude1
Oil (1.5%)
137. 5(S)2
5.3(S)2
5.0
0.8
36.3
Low Sulfur Crude
Oil (0.5%)
164. 4(S)
9.4(S)
3.1
1.6
30.7
Average Value
(1%)
150. 53
4.1
1.2
33.5
t
GO
Data from: Air Pollutant Emissions Testing Report, Oil Field Steam Generators. Performed
at the Midway-Sunset Oil Field, Kern County, California; Ryckman/Edgerly/Tomlinson &
Associates; July, 1977.
(S) = weight percent of sulfur
3SO weighted average calculated as follows for S0?: ^7. 5(1. 5) + 164.4(0.5) = 144>2(i.o)
= 144.2
forS03: 5.3(1. S),* 9.4(0.5) =6.3(1.0) = 6.3
-------
CO - 0.020 MT/103 bbl
HC = 0.006 MT/103 bbl
NO = 0.160 MT/103 bbl
X
Not all oil in a field can be assumed to be produced using
Thermal Operations. In order to establish the portion of the annual
production in a field associated with this activity, a proportioning
routine is followed. Fields identified as engaged in steam projects
will have a certain number of secondary wells (injection and produc-
tion) associated with the activity. These wells will be designated
in Columns 77-79 of the coded information for that field (see Figure
4-1). Dividing this number by the total wells in the field (Columns
64-66) will provide an estimate of the percentage of total produc-
tion attributable to the Thermal Operations.
4.5.7 FUGITIVE HYDROCARBON SOURCES
A significant source of hydrocarbon emissions from a produc-
tion field come from what are considered to be "fugitive" sources.
Types of equipment usually categorized as sources of fugitive
hydrocarbon emissions include: compressor seals, relief valves,
wastewater separators, pipeline valves, and pumps. Table 4-4
presents emission factors for each of these sources based on
barrels of oil produced. Several studies are now under way to
revise these fugitive emission factors, however, these studies
are not complete so the value of 107 Ib of HC/10 bbl of oil
produced was used to calculate fugitive loses from production
activities.
4.6 YEAR OF RECORD ESTIMATES
Using the equipment prediction model and the estimation proce-
dures just discussed, state estimates of emissions were made for
4-38
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Table 4-4. FUGITIVE HYDROCARBON EMISSION FACTORS0
(lb/103 bbl)
Unit
Compressor seals
Relief valves
Wastewater separator
Pipeline valves
Pumps
Total
Crude Oil
Production
4
8
8
12
75
107
Burklin, C.E., R.L. Honerkamp, Revision of
Evaporative Hydrocarbon Emission Factors, for
U.S. EPA-450/3-76-039, August 1976.
4-39
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the base year of activity (between 1974 and 1977, depending on the
state). These emissions are presented in Table 4-5. As stated
earlier, stripper well activities were to be disregarded. It was
not possible in most cases to identify the location of the stripper
wells with regard to individual fields and pools. Instead, the
National Stripper Well Survey (Reference 7) summary totals for each
state were used. In addition to Missouri, New York, Pennsylvania
and Virginia having 100 percent stripper activity, it was discovered
that Alaska, Florida and Nevada have no wells which can be classified
as stripper.
To adjust the Year of Record estimates to take into account
stripper well activities, a percentage factor for each state during
that year has been calculated. This value represents the portion of
that state's production activities that are stripper in nature.
The annual totals are adjusted downward by these percentages. Table
4-6 summarizes the revised values.
4.7 PROJECTED EMISSIONS THROUGH 1987
In order to effectively estimate the growth of crude production
by state to the year 1987 and use those estimates to predict emissions,
the services of Dr. Floyd Preston, a consultant from the University
of Kansas, were retained. A description of his analysis follows.
4.7.1 PROJECTION ASSUMPTIONS
Prediction of future oil production on a state by state basis
cannot be done with high precision or accuracy. The few extent
methods for extrapolating production from wells, leases, fields or
states all rely upon past data to establish the pattern for the future.
To the extent that the future contains unexpected events such as
discovery of large new fields (Alaska for instance) or dramatic
4-40
-------
Table 4-5. YEAR OF RECORD SURFACE PROCESSING EMISSIONS
(103 kg/yr)
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Florida
Illinois
Indiana
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Montana
Nebraska
Nevada
New Mexico
North Dakota
Oklahoma
South Dakota
Tennessee
Texas
Utah
Wyomi ng
Year of
Record
1976
1976
1977
1976
1976
1976
1975
1975
1976
1975
1975
1974
1975
1976
1976
1975
1976
1975
1976
1975
1976
1976
1976
1976
1976
Total
HC
774
3,881
22
12,899
15,593
2,002
2,104
1,411
291
3,419
349
16,147
1,203
2,634
1,818
254
44
4,798
1,018
12,501
20
68
58,707
1,794
6,948
150,699
NO
X
2
79
Neg.
118
13,264
64
4
2
1
59
5
226
44
34
40
5
1
78
19
113
Neg.
2
2,344
39
511
17,054
SO
X
Neg.
Neg.
Neg.
Neg.
58,169
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
1
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
322
Neg.
1,632
60,124
CO
Neg.
6
Neg.
9
1,644
5
Neg.
Neg.
Neg.
4
Neg.
17
3
3
3
Neg.
Neg.
6
1
8
Neg.
Neg.
175
3
56
1,943
4-41
-------
Table 4-6. STRIPPER WELL ADJUSTMENT TO YEAR OF RECORD SURFACE PROCESSING EMISSION TOTALS
(1,000 kg/hr)
-f^
I
ro
State
Alabama
fl 1 x <; I A
n \ a b Kd
Arizona
Arkansas
Cal ifornia
Colorado
Mori da
11 1 inois
Indiana
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Montana
Nebraska
»i i
New Mexico
North Dakota
Oklahoma
South Dakota
Tennessee
Texas
Utah
Wyoming
Total
Year of Record
Production
(bbl)
10,140,000*
519,000*
18,097,000*
326,392,000*
38,992,000*
26,487,000
4,609,000*
57,156,000
7,555,821
323,234,000
24,321,000
46,072,000*
32,814,000*
4,774,000
90,753,522
21,725,000*
157,118,000
447,000*
598,000*
1,153,941,000*
37,317,000*
134,148,000
Year of Record
Stripper Well Production*
(bbl)
162,399
5,723
5,198,866
52,245,703
2,012,511
25,214,700
4,470,827
43,706,695
6,182,821
7,501,798
4,760,253
1,214,582
2,947,320
1,545,430
11,082,540
1,075,074
73,459,288
20,516
140,436
129,699,764
261,823
4,790,719
Stripper Well
Adjustment Factor
0.0160
0.0134
0.287
0.160
0.0516
0.952
0.970
0.765
0.818
0.0232
0.196
0.0264
0.0898
0.324
0.122
0.0495
0.468
0.0459
0.235
0.112
0.00702
0.0357
ur
\l\j
762
^ Rftl
J , OO 1
22
9,197
13,097
1,899
9 i n/i
L , 1 UH
68
9
803
64
15,772
967
2,564
1,655
171
nn
4,213
967
6,651
19
52
52,132
1,781
6,700
125,594
NO
X
2
79
Neg.
84
11,142
61
n
H
Neg.
Neg.
14
1
221
35
33
36
3
]
68
18
60
Neg.
2
2,081
39
493
14,477
SO
X
Neg.
Neg
Neg.
Neg.
48,862
Neg.
Neg.
Neg.
Neg.
Neg.
1
Neg.
Neg.
Neg.
Neg.
WPH
Neg.
Neg.
Neg.
Neg.
Neg.
286
Neg.
1,574
50,723
CO
Neg.
6
Neg.
6
1,381
5
Npn
iicy .
Neg.
Neg.
1
Neg.
17
2
3
3
Neg.
NeQ .
5
1
4
Neg.
Neg.
155
3
54
1,646
*Reference 9 values.
-------
changes in economic conditions (for instance the oil embargo of
1972-73) then the past is not a good estimator of the future pro-
duction. In the selection of the method for extrapolation of past
data it was recognized that the purpose of the prediction of future
oil production for this study was a secondary objective to the
primary one of estimating future statewide pollution levels from oil
field production. The method used was the time-honored one of decline
curve analysis.
The data were the most recent (1976) API historical records of
oil production by state and within Texas by the Railroad Commission
District.
The annual oil production from this compilation was plotted
on semi-log paper (log of annual oil production) versus year. By
visual analysis, the curves for each state, and for Texas,
each district, were classified into two categories, (a) those curves
for which three or more years of production counting from 1976 back-
ward could be said to follow a linear decline pattern, and (b) those
for which this was not true. Particular significance was placed on
whether the production of the most recent years (1976 or 1977) seemed
to be establishing a new trend.
For those states or districts in which a linear decline was
evident [category (a) above], a qualitative choice was made as to
how many years to include in the linear least-squares analysis of the
data. A computer program calculated the linear least-squares of
future production and predicted values for the years 1977 through
1987.
For those states whose production data did not follow a semi-
log (constant rate) decline over the past several years, a subjective
estimate of the decline was made under the following assumptions.
4-43
-------
Where the recent history (one to several years) was one of actual
increase (Arkansas, Michigan, Nebraska, North Dakota, Ohio, and
Texas District 1) then the trend was allowed to continue to 1977.
Beyond that period, the decline was taken to be that established
earlier for the state before the increase started. The estimate
of that earlier rate was obtained through visual estimation of
the most applicable constant decline rate.
Two states, Alaska and Florida, and Texas District 8A presented
special problems. Alaskan production from 1970 through 1976 declined
at approximately 4.5 percent per year. Extrapolation of this rate
for the future would be entirely inappropriate because of the pre-
sent production increase associated with opening of the Alaskan
pipeline. The data used to estimate this future production was taken
from a Lewin and Associates study for ERDA (Reference 11). The
report displayed graphically (no tabular data given) the Alaskan
production from 1976 through 1995 as an increment above expected
United States (non-Alaskan) production.
Florida has recently experienced a sharp increase in oil pro-
duction because of the recent discovery (1970) of the prolific Jay
field. However, production for the period 1972-1976 though increasing,
indicates that the state's annual production rate is nearing a peak.
For this state, the production for 1976 was taken to be the peak and
the decline was figured at the overall U.S. decline rate (3.85 per-
cent figured over the last 5 years). This is a somewhat arbitrary
process but no other data were available.
Texas District 8A presents a somewhat analogous situation to
that of Florida, although the production rate was considerably
higher (for 1976, 360,776,000 barrels versus 43,680,000 barrels).
Here again the U.S. decline rate of 3.85 percent was applied starting
in 1976.
4-44
-------
It is widely recognized that additional drilling will discover
future oil. However, the rate of drilling and the consequent rate of
discovery and rate of production from such activity is extremely
uncertain. Very approximate predictions of future national oil
production for 1976 through 1990 have been made by FEA (Reference 12)
under various scenarios of decontrol of oil prices, continuation of
present controls and various expectations as to future discoveries
of oil. No state by state predictions were made by FEA and no
attempt was made in this study to incorporate such estimates because
of their highly uncertain nature. The extrapolations in the present
report are therefore dependent in large measure on the continuance
of current pricing and other economic policies.
An additional factor that can influence future oil production
is the extent to which future enhanced oil recovery methods (also
called tertiary oil recovery, and improved oil recovery methods)
will be employed in the future. For the purposes of the present
study, one prediction for future oil production rate from enhanced
oil recovery processes was chosen. This was from the Office of
Technology Assessment (OTA) (Reference 13) study assuming high pro-
cess performance and current (1976) upper tier oil price ($11.62
per barrel).
The method to proportion these annual rates to each state was
to assume that the rates in each state will be proportional to the
expected ultimate recoveries in each state as given in the OTA
study. This is a highly oversimplified assumption since each pro-
cess is in a somewhat different state of technological development
and the mixture of enhanced oil recovery processes is not the same
for all states. Neither will any given enhanced process be developed
at the same rate in all states. However, without an extensive study
such factors could not be considered.
4-45
-------
4.7.2 PROJECTION CALCULATIONS
The results of Dr. Preston's analysis was a table presenting
the expected annual production rate for each state through 1987
(see Appendix VII). For calculation purposes, these production fig-
ures were converted into annual percent changes for each state.
Table 4-7 shows the projection matrix used to calculate emissions.
For the 1978 values, it was necessary to apply the percentage change
to the year of record. The projected annual nationwide emissions
for the years 1978-1987 appear in Table 4-8. State by state emis-
sion estimates for each projected year are presented in Appendix VIII.
Values in these tables reflect the stripper well adjustments shown
in Table 4-6.
4.8 SULFUR COMPOUND EMISSIONS FROM NATURAL GAS PRODUCTION
A problem arose in the identification and quantification of
sources of hUS. The only consistently recorded measure of sulfur
in crude oil is the organic sulfur content. It was not possible
to correlate the presence of ^S to this value. Discussions with
the U.S. Geological Survey and specific state agencies did not
uncover any information or statistics for sulfur reported as hLS.
Without specific field or state information, the emission discussion
will have to be general in nature.
4.8.1 YEAR OF RECORD ESTIMATES
Data used in this discussion comes from Sulfur Compound Emis-
sions of the Petroleum Production Industry (Reference 14). Table
4-9 reproduces combined information from two tables in that docu-
ment (Table 5, page 77 and Table 7, page 87) concerning sulfur
emissions from natural gas production. The numbers presented are
for the amount of sulfur emitted. The actual amount produced is
approximately 1,400,000 MT/yr but the major portion (1,000,000 MT/yr)
is recovered.
4-46
-------
Table 4-7. DECLINE OR GROWTH PROJECTIONS FOR EACH STATE AS A
PERCENTAGE CHANGE FROM THE PREVIOUS YEAR
State
Alabama
Alaska
Arizona*
Arkansas
California
Colorado
Florida
Illinois
Indiana
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Montana
Nebraska
Nevada*
New Mexico
North Dakota
Oklahoma
South Dakota
Tennessee
Texas
Utah
Wyoming
1978
- 3.75
+46.7
- 1.31
- 1.97
- 0.32
- 3.86
- 3.81
- 7.62
- 8.55
- 3.30
- 8.79
- 9.46
- 4.75
- 6.07
- 1.88
-12.5
- 1.31
- 3.61
+ 6.98
- 4.29
- 6.30
-11.8
- 1.75
- 7.53
- 1.60
1979
- 3.68
+88.1
+ 2.76
- 1.34
0
- 3.72
- 3.96
- 6.80
- 8.78
- 3.04
- 8.76
- 9.03
- 4.72
- 6.20
- 1.92
-13.0
+ 2.76
- 6.63
- 3.48
- 4.48
- 6.20
-11.8
- 1.79
- 4.81
- 2.44
1980
-3.82
+39.9
+ 2.27
- 1.36
- 0.32
- 4.17
- 3.87
- 6.77
- 8.70
- 2.74
- 8.83
- 9.14
- 4.68
- 6.06
- 1.63
-13.4
+ 2.27
- 3.21
- 5.41
- 3.91
- 6.34
-12.0
- 1.82
- 3.11
- 2.50
1981
- 3.74
+ 4.73
- 2.24
- 2.76
- 1.27
- 3.73
- 3.75
- 7.82
- 8.84
- 4.23
- 8.63
- 9.48
- 4.91
- 6.16
- 1.99
-13.8
- 2.24
- 0.83
- 5.71
- 5.69
- 6.18
-11.6
- 1.85
- 2.41
- 1.71
1982
- 3.65
0
- 0.85
- 2.13
- 1.29
- 6.77
- 3.90
- 7.27
- 8.96
- 3.99
- 8.76
- 9.21
- 4.60
- 6.25
- 1.69
-14.0
- 0.85
- 4.04
- 5.05
- 4.31
- 6.27
-11.9
- 2.83
- 1.23
- 2.61
1983
- 3.78
0
- 5.17
- 2.17
- 1.31
- 0.69
- 6.67
- 7.19
- 8.61
- 3.94
- 8.84
- 9.09
- 4.78
- 6.33
- 2.06
-11.6
- 5.17
- 3.92
- 4.79
- 5.41
- 6.35
-11.7
- 1.94
- 0.83
- 2.68
1984
- 3.80
- 4.51
- 3.54
- 2.96
- 1.32
- 3.83
- 0.93
- 7.04
- 8.97
- 3.87
- 8.86
- 9.23
- 4.68
- 6.05
- 1.75
-13.2
- 3.54
- 3.78
- 5.03
- 4.76
- 6.43
-12.1
- 1.78
- 2.94
- 1.83
1985
- 3.68
- 4.91
- 3.83
- 2.29
- 1.01
- 3.99
- 4.08
- 6.06
- 8.37
- 3.55
- 8.51
- 9.32
- 4.91
- 6.06
- 1.79
-13.6
- 3.83
- 3.77
- 2.94
- 4.30
- 6.11
-11.5
- 2.02
- 0.43
- 2.80
1986
- 3.68
- 2.39
- 1.35
+ 2.34
+ 3.01
- 3.77
- 3.59
- 0.81
- 9.14
+ 3.69
- 8.97
- 7.94
- 4.80
- 4.44
- 2.18
-12.3
- 1.35
- 0.16
- 6.06
+ 1.78
- 6.50
-11.9
- 1.13
- 2.61
- 0.96
1987
- 3.82
- 5.10
- 2.03
+ 2.29
+ 2.63
- 3.92
- 3.73
0
- 8.28
+ 3.79
- 8.76
- 8.12
- 4.65
- 4.64
- 1.86
-12.0
- 2.03
- 0.16
- 5.81
+ 2.16
- 6.09
-11.8
- 1.14
- 1.79
- 0.97
*No specific state data available, so used nationwide figures.
-e*
-pa
-------
Table 4-8. NATIONWIDE PRODUCTION AND PROCESSING
EMISSIONS FOR YEARS 1978-1987
(1,000 kg/yr)
Year
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
HC
123,686
125,091
126,041
123,327
119,567
116,402
112,787
109,221
108,041
106,536
N0x
14,397
14,412
14,384
14,182
13,937
13,726
13,504
13,313
13,581
13,814
S0x
50,537
50,494
50,295
49,648
48,984
48,321
47,675
47,166
48,523
49,743
CO
1 ,639
1,642
1,636
1,613
1,587
1,564
1,542
1,522
1,558
1,590
4-48
-------
Table 4-9. EMISSIONS OF SULFUR COMPOUNDS IN THE UNITED STATES IN 1973
(1,000 kg/yr)
Location Estimated Sulfur Emissions
Study Area:
Actual Emissions
Sulfur Dioxide
i
i
Alabama, Arkansas South,
Florida, Louisiana North, 309,000 603,000
Mississippi, New Mexico East,
Texas
;
Hydrogen Sulfide
8,000
i
Outside Study Area: '
Arkansas (N) 0 00
California 5,080
10,026* 75*
Colorado 1,016 i 2,006* 15*
Kansas 5,080 ! 10,206* 75*
Kentucky 0 0
0
Louisiana (S) 2,032 j 4,010* 30*
Michigan 5,080
Montana
North Dakota
New Mexico (NW)
Oklahoma
Utah
Wyoming
TOTAL
3,048
20,321
10,061
27,435
0
25,401
413,554
10,026*
6,016*
40,110*
19,858*
54,152*
0
50,136*
809,336
75*
45*
299*
149*
404*
0
375*
1,542
Note: Ohio values disregarded since activities are not being considered.
*Estimated ratio based on study area relationship.
-------
4.8.2 PROJECTED EMISSIONS THROUGH 1987
To calculate emissions for the years 1974-1977, the U.S. petro-
leum production decline rate over the last five years (as reported
by Dr. Preston) was used. For the years 1978-1987, nationwide per-
centage changes based on Dr. Preston's own work are used (see
Appendix VII). The results are shown in Table 4-10. This projec-
tion assumes a uniform HpS concentration in natural gases processed
during that period.
4-50
-------
Table 4-10. PROJECTED SULFUR COMPOUND EMISSIONS IN
THE UNITED STATES 1974-1987
(1,000 kg/yr)
Year
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
Percentage Change As A
Function of Previous Year
-3.85
-3.85
-3.85
-3.85
-1.31
+2.76
+2.27
-2.24
-0.85
-5.17
-3.54
-3.83
-1.35
-2.03
Sulfur Dioxide
778,177
748,217
719,411
691,713
682,652
701,493
717,417
701,347
695,386
659,435
636,091
611,729
603,471
591,221
Hydrogen Sulfide
1,483
1,426
1,371
1,318
1,301
1,337
1,367
1,336
1,325
1,256
1,212
1,166
1,150
1,127
4-51
-------
5.0 PRODUCTION STORAGE
Produced oil and condensate must be stored prior to custody
transfer (pipeline or truck). Such storage is commonly performed
in a series of tank batteries usually situated at or near the various
production and processing facilities spread about a field. The
tank itself commonly has a fixed roof, and is of either welded
or bolted construction. Hydrocarbon emissions from these tanks
can be expected to constitute one of the more significant sources
of pollution from the oil and gas production industry. This sec-
tion discusses the methodology used by the investigators to esti-
mate the number of storage tanks in each state, the tank size mix
and the hydrocarbon emission estimates for both the year of record
and each projected year through 1987.
5.1 STORAGE TANK DATA BASE
For a variety of reasons including lack of applicable regulations,
very few extensive inventories of production field tankage have been
completed. Project investigators were able to discover only two.
One inventory was produced by the Kern County, California, Air Pollu-
tion Control District and contained tankage data by company for all
fields in the county. The second inventory was of all tanks in Texas
fields. This information was gathered by the Texas Mid-Continent Oil
and Gas Association and relayed to PES by Mr. C.R. Kreuz of Mobil
Oil Corporation in Houston, Texas.
5.2 ESTABLISHMENT OF STORAGE CAPACITY — FIELD RELATIONSHIPS
In each inventory case, the first step involved the grouping
of storage tanks by individual fields. Once all possible individual
field and tank assignments had been made, a storage capacity ratio
was calculated. This number was obtained by dividing the total field
5-1
-------
storage capacity in barrels by the field size expressed as thousands
of barrels of annual production. A total of 61 such relationships
could be calculated for California fields and 1,028 ratios were cal-
culated for Texas.
The relationships for each state were plotted separately on
natural log-log paper to determine if a linear correlation of data
existed. A least-square analysis of each set of data was performed,
resulting in an expression for the relationship in each state.
Figure 5-1 shows the relationships calculated for each set of infor-
mation. The mathematical expression for each is:
0 29
California expression y = 3,837 (x) ' ,
T • on rin I \-0.605
Texas expression y = 28,519 (x)
where: x is the field annual production in barrels and
y is the storage capacity ratio in barrels per thousand
barrels of annual production.
The expected field storage capacity can then be calculated by
multiplying the storage capacity ratio by the field production in
thousands of barrels.
Close examination of the California and Texas ratios show that
they are based on two very different field storage tank densities,
especially in large field situations. Investigators undertook to
discover if either or both expressions were representative and in
what recognizable field situations. The solution was provided by
Dr. Pr'eston, who stated that the Texas data reflect the process of
unitization, a condition not generally in effect in the Kern County
fields. Unitization is a system of operating a certain oil and
condensate reservoir in order to conduct some form of pressure
maintenance, repressurizing, waterflood, or other cooperative form
to increase ultimate recovery. By utilizing unitization, field
operators are able to combine resources, reducing the total number of
5-2
-------
10,000-
1,000-
Barrels of
Capacity/103
Barrels of
^reduction
A - California relationship
B - Texas relationship
en
oo
100-
10-
100
1,000 10,000 100,000 1,000,000
Field Size
Figure 5-1 . Storage Capacity Relationships
10,000,000
-------
tanks found in a field. Project engineers decided to apply the
Texas storage tank ratio to any field exhibiting secondary produc-
tion activities and the California ratio to any field without
secondary activities.
5.3 TANK SIZE ASSIGNMENTS
To predict emissions from storage of crude oil, it is necessary
to establish the number of tanks and the size mixture to be assigned
to the calculated field storage capacity value. The Texas and
California inventories indicated three dominant tank sizes: 210
barrels, 500 barrels, and 1,000 barrels capacity. All of the
inventoried fields had the various assigned tanks categorized by
size into three groups: (1) 250 barrels or less, (2) 250 to 500
barrels, and (3) more than 500 barrels. Table 5-1 summarizes the
tank categorization distributions for different field sizes.
Table 5-1. TANK INVENTORY SUMMARY
Field Size
(103 bbl/yr)
0-10
10-100
100-1,000
1 ,000-and
greater
Number of
Tanks in
Survey
1,009
2,309
3,179
3,157
Percent of Tanks in Each Size Category
> 250 bbl
48.86(27.16)*
36.68(18.06)
20.89(8.27)
5.83(2.22)
250 to 500 bbl
47.27(62.59)
56.74(66.51)
60.82(57.34)
80.52(73.02)
7,500 bbl
3.87(10.25)
6.58(15.43)
18.24(34.39)
13.65(24.76)
*Values in parentheses represent the percent of total capacity
stored in each size category.
5-4
-------
The table indicates that for fields producing 10,000 barrels
per year or less, 48.86 percent of the tanks inventoried were in
the size category of 250 barrels or less, 47.27 percent in the
250 through 500 barrel category, and 3.87 percent in the greater
than 500 barrel category. All tanks in each of these size cate-
gories were assumed to be the same size. The smallest tanks were
all assumed to be 210 barrel units, with the medium size being
500 barrels, and the largest tanks all 1,000 barrels in size.
The tank percentages cannot be directly applied to a field stor-
age capacity ratio, since the first number concerns numbers of
tanks and the second is in terms of field capacity (bbl/10 bbl of
production). Using the tank distribution and specific tank size
assumptions, Table 5-1 indicates that for a field of 10,000
barrels per year or less, the following distribution of storage
capacities among the various tank sizes will be available:
(0.4886)(0.21 x 103 bbl) = 0.1026
+ (0.4727)(0.5 x 103 bbl) = 0.2364
+ (0.0387)(1.0 x 103 bbl) = 0.0387
Total = 0.3777 x 103 bbl
Of this total of 0.3777 x 103 bbl, the 210 barrel tanks while com-
prising nearly 50 percent of the number of tanks, only represent
27.16 percent of the available capacity. This conversion
to capacity relationships has been performed for each tank size and
field category and appears as the values in parentheses in Table
5-1. With these values, tank assignments can be made to specific
fields.
Based on the size and type of field, the calculated storage
capacity relationship is multiplied by the specific tank capacity
distribution percentages and then divided by the appropriate tank
size to assign the number of each size tank to that field. A
sample calculation is demonstrated in Table 5-2.
5-5
-------
Table 5-2. CALCULATION OF NUMBER OF TANKS IN OIL FIELDS PRODUCING 150,000 BBL/YR
AND NOT EMPLOYING SECONDARY PRODUCTION
Step 1
Calculate field storage
capacity ratio
3, 837(150, GOO)"0'29
= 121 bbl/103 bbl of
production
Step 2
Calculate total field storage
capacity
(121 bbl/103 bbl)(150 x 103 bbl)
= 18,150 bbl
Step 3
Calculate Number of Tanks of Each Size
210
(0.0827)(18,150 bbl)
= 1,501 bbl
1,501 bbl . , ,r .
210 bbl/tank /Jb tankj
500
(0.5734)(18,150 bbl)
= 10,407 bbl
10,407 bbl _ ,„ 0 .
500 bbl/tank LU'B tankj
1,000
(0.3439)(18,150 bbl)
= 6,242 bbl
6,242 bbl . e , .
1,000 bbl/tank b-L tanks
-------
5.4 EMISSION ESTIMATES AND TANK INVENTORY
Several recent studies have been performed which indicate that
hydrocarbon losses from fixed roof storage tanks may be significantly
lower than those calculated using the traditional relationships.
However, much of this work has still to be finalized. For the
purpose of this study, the emission factors presented in Compilation
of Air Pollutant Emission Factors, AP-42, Part A, Second Edition,
Section 4.3, "Storage of Petroleum Liquids", April, 1977, were used.
Emissions from each of the three tank types were calculated to
be (see Appendix IX):
210 barrel unit: 0.49 MT/yr/tank
500 barrel unit: 1.273 MT/yr/tank
1,000 barrel unit: 2.61 MT/yr/tank
All tanks were assumed to utilize a fixed roof, to experience 30
turnovers per year (AP-42 assumption), and to vent uncontrolled to
the atmosphere. Evaluators are aware that a certain proportion of
existing crude oil storage tanks employ vapor recovery as a control
measure. However, inquiries of state and local air control agencies
could not produce figures for the level of activity in any state.
Without accurate information, evaluators did not include a vapor
recovery adjustment in the emission estimates.
Table 5-3 presents the calculated tank mix and hydrocarbon
estimates for each state during the year of record.
5.5 PROJECTED EMISSIONS
The amount of oil being extracted and processed from a given
field will vary from year to year based on a variety of conditions
specific to both that field and the total industry. It is felt
that as these production fluctuations are experienced, tank usage
will be affected both in throughput and number of tanks in
5-7
-------
Table 5-3. YEAR OF RECORD STORAGE TANK SUMMARY
i
co
State
Alabama
Alaska
Arizona
Arkansas
Cal ifornia
Colorado
Florida
111 inois
Indiana
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Montana
Nebraska
Nevada
New Mexico
North Dakota
Oklahoma
South Dakota
Tennessee
Texas
Utah
Wyoming
TOTAL
Number of Tanks
210 bbl
245
10
26
1,525
2,260
1,501
85
642
299
4,423
612
5,411
1,601
2,827
626
741
23
2,424
744
4,178
46
58
33,131
280
2,262
65,980
500 bbl
755
82
57
7,325
6,146
2,576
283
998
403
6,305
914
19,517
2,994
6,094
1,613
952
68
5,580
1,584
9,834
74
98
70,567
1,559
6,434
152,812
1 ,000 bbl
185
14
14
1,268
1,282
398
72
141
56
856
133
4,146
561
1,128
329
103
20
1,086
357
1,691
12
20
12,143
279
1,324
27,618
Total
1,185
106
97
10,118
9,688
4,475
440
1,781
758
11,584
1,659
29,074
5,156
10,049
2,568
1,796
111
9,090
2,685
15,703
132
176
115,841
2,118
10,020
246,410
Hydrocarbon
Estimation
(1,000 kg/yr)
1,565
147
121
13,337
12,269
4,985
590
1,910
780
12,155
1,800
38,272
6,028
11,986
3,184
1,772
151
11,076
3,307
18,848
148
205
136,380
2,853
12,717
296,586
Stripper Well
Estimation
(1,000 kg/yr)
1,540
147
119
9,509
10,306
4,728
590
92
23
2,856
328
37,384
4,847
11,670
2,898
1,198
151
9,725
3,143
10,027
141
157
121,105
2,833
12,263
247,780
-------
service. Decisions to operate solely by varying tank throughputs
or to either add or decrease tankage will be an individual decision
and cannot be predicted within the scope of this project. For the
purpose of predicting future tankage and emissions, it has been
assumed that state production fluctuations will be reflected in
corresponding tank usage modifications. To provide these anti-
cipated changes, the projection matrix developed from Dr. Preston's
data will be used. Table 5-4 shows the projected hydrocarbon
emissions from storage tanks for the years 1978-1987. Table 5-5
presents the final estimation when adjustments are made assuming
a stable statewide level of stripper well activities for the years
in question.
5-9
-------
Table 5-4. STORAGE TANK HYDROCARBON
THE YEARS 1978-1987
(1,000 kg/yr)
EMISSIONS FOR
State
Alabama
Alaska
Arizona
Arkansas
Cal ifornia
Colorado
Florida
Illinois
Indiana
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Montana
Nebraska
Nevada
New Mexico
North Dakota
Oklahoma
South Dakota
Tennessee
Texas
Utah
Wyoming
TOTAL
1978
1,506
215
119
13,074
12,230
4,793
567
1,765
713
11,754
1,641
34,651
5,741
11,259
3,124
1,551
149
10,676
3,538
18,039
138
181
133,993
2,638
12,514
286,569
1979
1,451
404
122
12,900
12,230
4,614
545
1,644
650
11,396
1,498
31,522
5,470
10,561
3,063
1,349
153
9,969
3,415
17,231
130
160
131,595
2,511
12,208
276,791
1980
1,396
566
125
12,724
12,191
4,422
523
1,533
594
11,084
1,366
28,641
5,215
9,921
3,014
1,169
156
9,649
3,230
16,557
122
141
129,200
2,433
11,903
267,875
1981
1,344
593
122
12,372
12,037
4,257
504
1,413
541
10,615
1,249
25,926
4,959
9,310
2,954
1,007
152
9,569
3,046
15,616
114
125
126,810
2,375
11,699
258,709
1982
1,295
593
121
12,109
11,881
3,969
484
1,311
492
10,191
1,140
23,539
4,731
8,728
2,904
867
151
9,183
2,892
14,942
107
no
123,221
2,346
11,394
248,701
1983
1,246
593
115
11,846
11,726
3,949
452
1,216
450
9,790
1,039
21,399
4,504
8,176
2,844
766
143
8,823
2,754
14,134
101
97
120,830
2,326
11,088
240,407
1984
1,198
566
m
11,495
11,571
3,798
448
1,131
409
9,411
948
19,424
4,293
7,681
2,794
665
138
8,489
2,616
13,461
94
86
118,680
2,258
10,885
232,650
1985
1,154
538
107
11,232
11,453
3,646
429
1,062
375
9,077
868
17,613
3,871
7,215
2,744
575
133
8,169
2,539
12,882
88
76
116,282
2,248
10,580
224,956
1986
1,112
526
106
11,494
11,798
3,509
414
1,053
340
9,412
790
16,215
3,686
6,895
2,684
505
131
8,157
2,385
13,111
82
68
114,968
2,190
10,479
222,110
1987
1,070
499
104
11,758
12,108
3,372
398
1,053
313
9,769
721
14,898
3,515
6,575
2,635
444
128
8,144
2,247
13,394
77
59
113,658
2,151
10,378
219,468
en
i
-------
Table 5-5. STRIPPER WELL ADJUSTMENTS TO STORAGE TANK ESTIMATES
FOR THE YEARS 1978-1987
(1,000 kg/yr)
State
Alabama
Alaska
Arizona
Arkansas
Cal ifornia
Colorado
Florida
Illinois
Indiana
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Montana
Nebraska
Nevada
New Mexico
North Dakota
Oklahoma
South Dakota
Tennessee
Texas
Utah
Wyoming
TOTAL
1978
1,481
215
117
9,321
10,273
4,545
567
85
21
2,762
299
33,847
4,616
10,961
2,844
1,048
149
9,374
3,362
9,596
132
138
118,986
2,619
12,067
239,425
1979
1,427
404
120
9,198
10,273
4,376
545
79
19
2,678
272
30,791
4,399
10,282
2,788
912
153
8,753
3,246
9,167
124
123
116,855
2,494
11,772
231,250
1980
1,373
566
123
9,072
10,240
4,194
523
74
18
2,605
248
27,977
4,192
9,660
2,743
790
156
8,472
3,070
8,809
116
108
114,729
2,416
11,477
223,751
1981
1,322
593
120
8,822
10,111
4,037
504
68
16
2,494
227
25,325
3,987
9,064
2,688
681
152
8,402
2,895
8,307
109
95
112,608
2,358
11,282
216,267
1982
1,274
593
119
8,633
9,981
3,764
484
62
15
2,395
207
22,992
3,803
8,497
2,643
586
151
8,063
2,749
7,950
103
84
109,421
2,329
10,987
207,885
1983
1,226
593
113
8,446
9,850
3,746
452
59
14
2,300
189
20,902
3,621
7,960
2,588
518
143
7,747
2,618
7,519
96
74
107,297
2,310
10,692
201,073
1984
1,179
566
109
8,196
9,720
3,602
448
54
12
2,212
173
18,974
3,452
7,478
2,543
449
138
7,454
2,486
7,161
90
66
105,388
2,242
10,496
194,688
1985
1,135
538
106
8,008
9,620
3,458
429
51
11
2,133
158
17,205
3,113
7,025
2,498
389
133
7,173
2,413
6,853
84
58
103,259
2,233
10,203
188,286
1986
1,094
526
105
8,196
9,910
3,328
414
50
10
2,212
144
15,839
2,964
6,713
2,443
341
131
7,161
2,267
6,975
78
51
102,092
2,174
10,105
185,323
1987
1,053
499
103
8,383
10,170
3,198
398
50
9
2,296
131
14,553
2,826
6,401
2,398
300
128
7,151
2,136
7,126
74
45
100,928
2,135
10,007
182,498
en
i
-------
6.0 COSTS AND ANALYSES OF CONTROL OPTIONS
The types of operations in use in the petroleum production
industry present several important control options. The most
important emission sources to be considered are: (1) hydrocarbon
emissions from storage tanks, (2) control of H2S removed from
natural gas, (3) fugitive hydrocarbon emissions from surface
valves and seals, and (4) use of alternate fuels in specific
combustion sources.
6.1 CONTROL OF HYDROCARBON EMISSIONS FROM FIXED ROOF STORAGE TANKS
6.1.1 VAPOR RECOVERY USING COMPRESSION
Vapor recovery, a control technique commonly applied in
petroleum refineries, has had only limited applications in produc-
tion operations. While its use in very large tank battery situa-
tions in California and Texas cannot be overlooked, the control
strategy is not considered to have general application to the
petroleum production industry.
The recovered compressed gas must be disposed of by either
combustion or removal. Due to the small volumes considered
[10.6 m3/day/tank (375 ft3/day/tank)]*, routing the gases to a
flare or fuel-fired unit would not be practical. Compression
and removal would require the availabilty of a pipeline. There-
fore, the first limiting factor is the need for a field utilizing
a pipeline for custody transfer.
* This value is obtained by dividing the figure of 15.77 Ib of
HC/day/tank (see Appendix IX) by the value of 0.042 lb/ft3 of
methane at 60°F.
6-1
-------
The second problem involves the minimum available size for
the compression unit. The stated minimum size for the necessary
3 3
compression system is approximately 122 m (4,300 ft ) per day
(Reference 15). Using the calculated value for hydrocarbon vapor
3
loss volumes from the largest 1,000 barrel tanks of 375 ft /day/
tank, to utilize such a compression system would require a battery
of 12 such tanks in close enough proximity to be connected to the
one compressor. Review of the tank inventory revealed only a
small number of fields where these requirements could possibly be
met. The project staff concluded that this system was not viable
on an industry-wide basis.
6.1.2 INTERNAL FLOATING ROOF
A hydrocarbon control technique with a wider application to
the total industry is the installation of an internal floating
cover to existing tanks. As with the vapor recovery system,
there are limits to its use. Many of the smaller bolted tanks
as well as tanks containing other internal obstructions such as
heating coils would be unavailable for installation of internal
covers. However, the potential application and emission reduc-
tion is felt to be significant enough to warrant consideration.
The cost parameters for the three tank sizes under consideration
are presented in Table 6-1. The installed capital cost is an
average of quotes obtained from three different manufacturers
(References 16, 17, 18). Uncontrolled emissions are the calcu-
lated values using AP-42 fixed roof equations. The controlled
value was obtained by applying the AP-42 floating roof equation
to each tank.
Control cost estimates for retrofitting existing fixed
roof tanks with an internal floating roof are presented in
Table 6-2. The net annual cost subtracts a petroleum credit
6-2
-------
Table 6-1. COST PARAMETERS FOR CONTROL OF HC EMISSIONS FROM
FIXED ROOF TANKS (INTERNAL FLOATERS)
Tank Size
bbl (liters)
Installed Capital
Cost ($)a
Annual Operational
Cost (% of b
installed capital )
Replacement Life (yrs)
Uncontrolled Emissions
(kg/yr)
Controlled Emissions
(kg/yr)
Percent Control
Petroleum Value ($/kg)b
210 ,
(33 x -\V6}
3,890
6
30
490
200
59
.136
500 ,
(79 x 10 )
4,880
6
30
1,270
320
75
.136
1 ,000 .
(159 x 10J)
6,130
6
30
2,610
480
82
.136
References 16, 17,18
b EPA 450/2-77-036, December 1977, Control of Volatile Organic
Emissions from Storage of Petroleum Liquids in Fixed Roof
Tanks.
6-3
-------
Table 6-2. CONTROL COST ESTIMATES FOR
EXISTING FIXED ROOF TANKS3
Control Device
Tank Size
bbl (liters)
Installed Capital
Cost ($)
Operating and
Maintenance ($/yr)
Capital Charges ($/yr)
Petroleum Credit ($/yr)
Net Annual Cost or
(Credit)($/yr)
VOC Reduction (kg/yr)
Cost (Credit) per kg
($/kg)
Internal Floating Roof
210 ,
(33 x 10J)
3,890
230
570
(40)
760
290
2.62
500 -
(79 x 10^)
4,880
290
710
(130)
870
950
0.92
1,000 -
(159 x 10J)
6,130
370
890
(290)
970
2,130
0.46
See Table 6-1.
Capital recovery factor for 30 year life, and 10 percent
interest plus 4 percent for taxes, insurance and adminis-
tration (see Reference b, Table 6-1).
6-4
-------
associated with the reduced hydrocarbon losses experienced when
an internal floater is installed. The final value is an expres-
sion for the amount of money necessary to recover a kilogram of
hydrocarbon.
6.1.3 POTENTIAL EMISSION REDUCTION ACHIEVEMENT
Table 6-3 demonstrates the amount of hydrocarbon reduction
that can be achieved when internal floating roofs are installed
on all existing tanks. Estimates are presented for both the year
of record and 1987. An effort was made to quantify the percentage
of tanks which would have heating coils and therefore be unavailable
for the retrofit. Insufficient information existed in the data
base to make such a determination. The frequency of such tanks
will be higher in colder states and areas where heavy crudes
having a pour point of approximately 38°C (100°F) or less are
processed.
6.2 H2$ EMISSIONS FROM NATURAL GAS
The production of pipeline grade natural gas requires the
removal of large quantities of H2S from the reservoir gas.
Currently (1973), approximately 70 percent of the sulfur removed
in this manner is reduced to elemental sulfur. The remainder is
either burned to S02, allowed to leak or vent to the atmosphere
as H2S, or is emitted as HLS, S02, COS, or CS2 from a sulfur
recovery operation.
Table 4-8 shows that for the year 1973, after sulfur recovery,
an additional 413,554 MT/yr of sulfur were emitted to the atmos-
phere. This figure was assumed to be represented by 809,336 MT/yr
of S02 and 1,542 MT/yr of H2S. Of the sulfur value, it was
reported that 172,000 MT/yr represented Claus plant tail gas
6-5
-------
Table 6-3. POTENTIAL HYDROCARBON REDUCTIONS DUE TO RETROFIT OF
TANKS WITH INTERNAL FLOATING ROOFS
(1,000 kg/yr)
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Florida
111 inois
Indiana
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Montana
Nebraska
Nevada
New Mexico
North Dakota
Oklahoma
South Dakota
Tennessee
Texas
Utah
Wyoming
TOTAL
Year of Record*
Uncontrolled
1,540
147
119
9,509
10,306
4,728
590
92
23
2,856
328
37,384
4,847
11,670
2,898
1,198
151
9,725
3,143
10,027
141
157
121,105
2,833
12,263
247,780
Controlled
373
35
30
2,323
2,549
1,248
142
25
6
778
87
9,102
1,244
2,976
727
340
36
2,451
786
2,550
37
40
31,112
684
3,034
62,715
1987
Uncontrolled
1,053
499
103
8,383
10,170
3,198
398
50
9
2,296
131
14,553
2,826
6,401
2,398
300
128
7,151
2,136
7,126
74
45
100,928
2,135
10,007
182,498
Controlled
255
119
26
2,048
2,515
844
96
14
2
625
35
3,543
725
1,632
602
85
31
1,802
534
1,812
19
11
25,929
515
2,476
46,295
* Based on Tables 5-3 and 5-5 which utilize stripper well
adjustments.
6-6
-------
emissions, (since the average recovery efficiency was 85.3 percent
for these plants, it was assumed that tail gas cleanups were not
in use).
The remaining 241,554 MT/yr of sulfur emitted was assumed to be
uncontrolled. To recover the sulfur, it will be necessary to utilize
either the Stretford Process for low hLS concentration streams or
the Claus-Beavon system.
6.2.1 STRETFORD PROCESS
The Stretford Process has been used in Great Britain for many
years to recover hydrogen sulfide from natural gas and convert it
to sulfur. The feed gas is passed through an absorption tower which
removes the hLS. The absorbent is an organic liquid which also serves
to oxidize the dissolved hLS to sulfur. The sulfur is removed from the
liquid by filtration, and the solvent is regenerated by air oxidation.
Very high conversions of hLS to sulfur are possible with this process.
The advantages of the Stretford process are that it functions
well at atmospheric pressure, is unaffected by any carbon dioxide
present, purifies the gas to a very high degree and does not require
special operator skills. Several United States engineering firms
have produced operational units of this process — Parsons and
Pritchard primarily.
Table 6-4 presents the cost parameters for a Stretford system
as estimated by engineers at J.F. Pritchard and Company. The control
efficiency estimation was also supplied by Pritchard personnel.
Control cost estimates for the installation of a Stretford Process
unit are presented in Table 6-5. The final value is an expression for
the amount of money necessary to recover a kilogram of hydrogen
sulfide.
6-7
-------
Table 6-4. COST PARAMETERS FOR CONTROL OF H2S FROM
NATURAL GAS AT WELLHEAD
(Stretford Process for Low
Flow Rate Mega liters per day (MMSCFD)
Inlet Sulfur (ppmv)
Uncontrolled h^S Emissions (kg/yr)
Outlet Sulfur (ppmv)
Controlled F^S Emissions (kg/yr)
Capital Cost Installed ($)
Annual Operating Cost
Chemicals
El ectricity
Maintenance
Total
Sulfur Recovery
Percent Emissions Control (%)
1,557 (55)
1,490
1.20 x 106
2.97
2.4 x 103
1,270,000
3,600
15,900
38,100
57,600
none
99.8
6-3
-------
Table 6-5. CONTROL COST ESTIMATES FOR CONTROL OF H2S
FROM NATURAL GAS AT WELLHEAD3
Control Technique
Stretford Process
Installed Capital Cost ($)
Operating Cost ($/yr)
Capital Charges ($/yr)b
Net Annual. Cost ($/yr)
Controlled Emissions (kg/yr)
Percent Reduction (%)
Cost per kg of HgS Controlled ($/kg)
1,270,000
57,600
257,400
315,000
2.5 x TO3
99.8
0.26
See Table 6-4
b Capital recovery factor for 10 year life and 10% interest plus 4%
for taxes, insurance and administration.
6-9
-------
6.2.2 CLAUS PLANT AND BEAVON TAIL GAS TREATMENT
In the Claus reaction, hydrogen sulfide is converted to elemental
sulfur in two steps according to the following reactions:
H2S + 3/2 02 —^ S02 + H20
2H2S + S02 *• 2H20 + 3S
In the first step, H^S is partially burned to S02 using air. The
HpS/SOp mixture is then reacted over a catalyst to produce sulfur
and water. This reaction is known as the shift conversion and is
carried out in one to three stages with sulfur removal after each
stage. The design of a sulfur recovery plant depends upon the inlet
HpS concentration. If the concentration of H2S in the feed is high,
a "straight-through" process is used. In the straight-through con-
figuration, all of the FLS and air are fed to the burned (boiler).
If the FLS concentration in the feed is low, a "split-flow" or
"sulfur recycle" process is used.
The Beavon unit simply hydrogenates the sulfur compounds, S02,
COS, and CS2 to H2S under moderate temperature and pressure conditions
using a cobalt-molybdate catalyst. After the reactor, the hydrogen-
ated stream is cooled, water is condensed out, and vapor, containing
HpS, is ready for processing to eliminate the sulfide. It would be
desirable to return this H2S to the Claus plant feed but, unfortun-
ately, the stream contains so much C02 that cannot be easily removed
that the build-up of inert gas in the Claus unit could not be tolerated.
Since the H^S concentration is about 10,000 ppm and must
ultimately be reduced to 1 ppm, a Stretford section is added. This
H2S stream id directed into a column and contacted with sodium
carbonate to convert it to sodium hydrosulfide. This is oxidized
to sulfur by sodium vanadate. Subsequently, vanadium is oxidized
back to the penta valent state by blowing in air with sodium anthra-
quinone disulfonate working as an oxidation catalyst. Sulfur particles
6-10
-------
are finely divided, and appear as a froth which is skimmed, filtered
and returned to the Claus plant to be included in the elemental
sulfur product. The tail gas will now contain less than 250 ppm SCL
and 10 ppm hLS.
Table 6-6 presents the cost estimates for two 100 long ton
(102 MT) per day Claus reactors, one having a sulfur conversion
efficiency of 90 percent and the other 95 percent. The use of the
102 MT/day unit was suggested by engineers at Ralph W. Parsons,
who prepared the estimate, as the most representative size. This
value was confirmed as reasonable by project engineers from data
appearing on pages 5-3 through 5-17 of Reference 17. A total of
55 gas processing plants utilizing the Claus process had a daily
average recovery rate of 49.8 LT (50.6 MT). Table 6-6 also
presents an analysis of the addition of a Beavon tail gas cleanup
system to the Claus reactor. The cost per kg of hLS controlled
for the Claus plus the Beavon unit is given as $40/MT. This value
does not demonstrate the incremental cost of the addition of the
Beavon unit. To go from a 95 percent efficient Claus plant to a
99 percent efficiency Beavon system will result in an 800,000 kg
additional emission reduction. The difference in the net annual
cost of installing such a system will be $480,000. Therefore the
cost per kg hLS for this additional control will be $600/MT.
Table 6-7 presents the cost parameters for the Claus plant
and the Beavon unit.
6.2.3 POTENTIAL EMISSION REDUCTION ACHIEVEMENT
As of 1973, a total of 413,554 MT of sulfur were being emitted
to the atmosphere. Of this total, 172,000 MT was the result of
Claus conversion. Insufficient information is available to differen-
tiate between lean and heavy hLS streams and determine the
6-11
-------
Table 6-6. COST ESTIMATES FOR CONTROL OF H2S
Control Technique
Installed Capital Cost ($)
Operating Cost ($/yr)
Capital Charges ($/yr)
Sulfur Credit ($/yr)
Net Annual Cost ($/yr)
H2S Controlled (kg/yr)
% Controlled
Cost per kg H2S Controlled
($/kg)
Claus
(95%)
1.67 x 106
0.10 x 106
0.34 x 106
(0.125 x 106)
0.31 x 106
18.7 x 106
95
0.017
Claus
(90%)
1.67 x 106
0.10 x 106
0.34 x 106
(0.12 x 106)
0.32 x 106
17.7 x 106
90
0.018
Claus &
Beavon
3.17 x 106
0.28 x 106
0.64 x 106
(0.13 x 106)
0.79 x 106
19.5 x 106
99
0.040
I
rv>
-------
Table 6-7. COST PARAMETERS FOR CONTROL OF H2S FROM HIGH
SULFUR CONTENT NATURAL GAS
Control Technique
Claus Plant
Beavon Process
Installed Capital Cost ($)
Operating Cost ($/yr)
Power
Fuel
Soft Water
Chemicals
Catalyst
Steam Credit
Uncontrolled
Emissions (kg/yr)*
Controlled Emissions
for Claus as
at 95% (kg/yr)
at 90% (kg/yr)
Controlled Emissions
from Beavon as
Sulfur Recovered
at 95% (kg/yr)
at 90% (kg/yr)
Sulfur Credit ($/kg)
1.67 x 106
0.100 x 106
19.7 x 106
0.99 x 106
1.97 x 106
17.6 x 106
16.7 x 106
0.0071
1.50 x 106
0.177 x 106
0.087 x 106
0.095 x 106
0.004 x 106
0.066 x 106
0.006 x 106
(0.081)x 106
1.97 x 105
18.4 x 106
0.0071
*Assumes 92.5 percent conversion efficiency,
6-13
-------
relative applicability of the Stretford versus the Claus and Beavon
units to existing field conditions. Project investigators have
decided to apply each system to the total 1973 values to show the
relative merits of each system.
The 1973 sulfur emissions can be distributed in the following
manner. A total of 413,554 MT of sulfur were emitted as 809,336
MT of S02 and 1,542 MT of H2S. Eliminating 172,000 MT of sulfur
emitted as SO,, from tail gas combustion in existing Claus plants,
leaves 241,554 MT of sulfur generated as H,,S which is either
converted to SO^ or remains as hUS without passing through a Claus
plant.
Applying the Stretford process to all this remaining sulfur
will produce 483 MT of sulfur as H2S. Passing all of the remain-
ing sulfur through either a 90 percent of 95 percent efficient
Claus plant without any further treatment other than incineration
will result in 24,155 MT or 12,078 MT of sulfur as S02. By add-
ing a tail gas cleanup system to both the new Claus facilities
and the existing units, the complete sulfur recovery system will
have an efficiency of 99 percent with an efficiency of 97.3 per-
cent attributed to the Beavon system. This will result in the
241,554 MT being reduced to 2,415 MT of sulfur emitted as S02 and
an additional 4,644 MT as S02 from controlling the 172,000 MT of
sulfur currently leaving existing Claus plants. Table 6-8
summarizes these results.
6.3 FUGITIVE HYDROCARBON EMISSIONS
Several recent studies conducted in petroleum refineries
have determined that fugitive emission factors are a direct func-
tion of maintenance. Experimental results indicate that by
initiating a comprehensive inspection and maintenance program,
6-14
-------
Table 6-8. IMPACT OF SULFUR CONTROL STRATEGIES
ON 1973 EMISSION ESTIMATES
(1,000 kg/yr)
Situation
Existing situation
Adding Stretford to
non-Claus emissions
Adding 90 percent
efficient units for
non-Claus emissions
Adding 95 percent
efficient Claus
units for non-Claus
emissions
Placing Beavon tail
gas treatment
systems on all new
and existing Claus
units
Atmospheric
Emissions
as Sulfur
413,554
172,483
196,155
184,078
7,060
Actual Emissions
so2
809,336
334,000
392,310
368,156
14,120
H2S
1,542
543
_
—
—
6-15
-------
existing emission from valves, flanges, and seals can be reduced
up to ten-fold (References 19 and 20). The problem stems from
defining what constitutes such a program. There is a great deal
of discussion currently as to what amount of resources in the
form of manpower is required to initiate and maintain such a
program. Until a conclusion is reached, it will not be possible
to evaluate the cost effectiveness of these actions.
6.4 ALTERNATE FUELS IN STEAM GENERATORS
Thermal operations utilize a steam generator which commonly
burns crude oil. The emission reduction which can be achieved by
combusting diesel fuel or natural gas instead is shown in Table
6-9. A great many variables concerning transportation costs and
storage will make the relative cost effectiveness for each of
these fields different in each situation. For this reason, no
further analysis is considered representative.
6-16
-------
Table 6-9. EMISSION ESTIMATES FROM THE
COMBUSTION OF VARIOUS FUELS
Fuel
Crude Oil
Diesel*
(Distillate)
Natural Gas*
Emissions [kg/giga joule (lb/10 Btu)J
S0x
2.167
(1.037)
1 .04
(0.496)
.002
(0.001)
CO
0.059
(0.028)
0.071
(0.034)
0.033
(0.016)
HC
0.017
(0.008)
.015
(0.007)
.006
(0.003)
NOX
.482
0.231
0.316
(0.151)
0.458
(0.219)
* Based on values appearing in AP-42, Second Edition, Part A.
6-17
-------
7.0 CONCLUSIONS
The primary goal of this study was to estimate existing annual
HC, SO , NO CO, and hLS emissions from drilling, production, and
A A L.
storage of oil and gas and project these emissions through the year
1987. The scope of the project called for the exclusion of stripper
•a
well activities. Disregarding these activities called for modifica-
tion of production and processing as well as storage tank estimates.
Projected emission levels for production and processing activities
were made only for the stripper well adjusted values. The most
recent data available concerning individual oil fields were obtained.
The years this information pertained to ranged from 1974-1977, with
the majority occurring in 1976. The base year was termed the Year
of Record. Table 7-1 summarizes the nationwide production and proces-
sing and storage emissions for the Year of Record and drilling and
sulfur extraction values for the year 1976.
Table 7-2 presents the expected nationwide emissions levels in
1987 without initiation of controls. The installation of internal
floating roofs on all storage tanks would reduce nationwide emissions
from these sources by approximately 75 percent (see Table 6-3). The
routing of all HpS and S02 streams generated by the processing of
natural gas through Claus recovery units and/or tail gas cleanup
systems would reduce sulfur emissions from these sources by over
98 percent (see Table 6-8).
7-1
-------
Table 7-1. EXISTING ANNUAL EMISSIONS FROM DRILLING, PRODUCTION AND PROCESSING,
AND STORAGE ACTIVITIES FOR YEAR 1976
(1,000 kg/yr)
Acti vi ty
Dri 1 1 ing
Production and
Processing
Sul fur Emissions
From Natural
Gas Processing
Storage
TOTAL
Without Stripper Well Adjustment
HC
11,857
150,699
-
296,586
459,142
NO
X
140,761
17,054
-
-
157,815
CO
30,611
1,943
_
-
32,554
SO
X
9,366
60,124
719,411
-
788,901
H2S
-
1,371
-
1,371
With Stripper Well Adjustment
HC
11,857
125,594
_
247,780
385,114
NO
X
140,761
14,477
.
-
155,238
CO
30,611
1,646
-
32,257
SO
X
9,366
50,723
719,411
_
779,500
H2S
-
1,371
_
1,371
-------
Table 7-2. 1987 PROJECTED EMISSIONS
(1,000 kg/yr)
1
OJ
Activity
Dril 1 ing
Production and
Processing
Sulfur Emissions
From Natural
Gas Processing
Storage
TOTAL
Without Stripper Well Adjustment
HC
25,499
127,831*
_
219,468
372,798
NO
X
297,548
16,273*
.
-
313,821
CO
64,835
1,877*
.
-
66,712
S0x H2S
19,855
58,962*
591,221
-
670,038
-
1,127
-
1,127
With Stripper Well Adjustment
HC
25,499
106,536
.
182,498
314,533
NO
X
297,548
13,814
-
311,362
CO
64,835
1,590
-
66,425
SOX
19,855
49,743
591,221
-
660,819
H2S
-
_
1,127
-
1,127
^Estimated
-------
8.0 REFERENCES
1. The Oil Producing Industry in Your State, 1977 Edition,
published by the Independent Petroleum Association of America,
Washington, D.C.
2. Atmospheric Emissions From Offshore Oil and Gas Development
and Production, R.H. Stephens, C. Braxton, M.M. Stephens,
prepared by Energy Resources Company, Inc., under Contract No.
68-02-2512 for the U.S. Environmental Protection Agency,
EPA-450/3-77-026, June 1977
3. Composite Catalogue of Oil Field Equipment and Services, 1976,
published bi-annually by World Oil
4. "Drilling Authority Forecasts All Point Up for 1979," The Oil
and Gas Journal, September 18, 1978, pp. 96-102
5. International Oil and Gas Development, Volume 46, Part II,
Production, (Review of 1975), published by International Oil
Scouts Association, 1977
6. The Oil Producing Industry in Your State, 1976 Edition,
published by the Independent Petroleum Association of America,
Washington, D.C.
7. National Stripper Well Survey, January 1, 1977, a joint
project of the Interstate Oil Compact Commission and the
National Stripper Well Association, published and distributed
by the Interstate Oil Compact Commission
8. Sulfur Content of Crude Oils, Information Circular 8676,
United States Department of the Interior, 1975
9. Primer of Oil and Gas Production, published by Production
Department of the American Petroleum Institute, fifth
printing, 1977
10. Kobe, A Subsidiary of Baker Oil Tools, Inc., Bulletin 110,
Copyright Kobe, Inc., 1975
11. Research and Development in Enhanced Oil Recovery, Final
Report (Overview Section, Part 1 of 3), Contract £(49-18)2294,
Stock No. 060-000-00047-6, U.S. Government Printing Office,
December 1976. Exhibit V-l, p. V-3
8-1
-------
12. National Energy Outlook, February 1976, Federal Energy
Administration, Washington, D.C., U.S. Government Printing
Office, Stock No. 041-018-00097-6, p. XXIX
13. Enhanced Oil Recovery Potential in the United States, Office
of Technology Assessment, Congress of the United States,
Washington, D.C., January 1978, U.S. Government Printing
Office, Stock No. 052-003-00503-4, Library of Congress
Catalogue No. 77-600063
14. Sulfur Compound Emissions of the Petroleum Production
Industry, EPA-650/2-75-030, December 1974
15. Information provided by Western Oil and Gas Association, 1978
16. Marquez, J., Service Pipeline Company, 1978
17. Hart, J., Ultraflote Corporation, 1978
18. Lohmeier, R., American Bridge and Steel Company, 1978
19. Harrison, P.R., Detection and Classification of Fugitive
Component Leaks, presented at U.S. EPA Symposium/Workshop on
Petroleum Refining Emissions, April 26-28, 1978
20. Hanzevack. K.M., Fugitive Hydrocarbon Emissions - Measurement
and Data Analysis Methods, presented at U.S. EPA Symposium/
Workshop on Petroleum Refining Emissions, April 26-28, 1978
8-2
-------
9.0 ACKNOWLEDGMENTS
A great number of people were contacted during the course of
this investigation. Special thanks is given to the following in-
dividuals and organizations for their assistance.
1. American Petroleum Institute, Fugitive Hydrocarbon Task Force,
W.J. Woodriff, Chairman
2. Gordon Bidscar, The Superior Oil Company, Conroe, Texas
3. Ed Crockett, American Petroleum Institute
4. Fred Dueser, Senior Vice President, Petroleum Corporation of
Texas, Breckendidge, Texas
5. C.R. Kreuz, Division Environmental and Regulatory Manager,
Mobil Oil Corporation, Houston, Texas
6. Larry Landis, Air Sanitation Chemist, Kern County Air Pollution
Control District
7. Glen Michel, Executive Vice President, West Central Texas Oil
and Gas Association
8. Johnny M. Morgan, Production Supervisor, Yates Petroleum Corpora-
tion, Artesia, New Mexico
9. Dr. Floyd Preston, Chemical and Petroleum Department, University
of Kansas
10. L.D. "Luke" Porter, Area Foreman, Amoco Production Company,
Denver, Colorado
11. Jamie Replogle, Counsel, Independent Petroleum Association of
America
12. Edward D. Webster, Environmental Analyst, Getty Oil Company,
Bakersfield, California
13. Francis C. Wilson II, Secretary/Treasurer, Wilson Oil Company,
Santa Fe, New Mexico
14. Wesley Wisdom, Mechanical Engineer, Long Beach Oil Development
Company
15. David E. Wittig, Engineer, Getty Oil Company, Bakersfield,
California
9-1
-------
APPENDIX I
STATE BY STATE EMISSION ESTIMATES
FOR EACH PROJECTED YEAR
-------
DRILLING EMISSIONS FOR THE YEAR 1977
(103 kg)
State
Al abama
Alaska
Arizona
Arkansas
Cal i form' a
Colorado
Florida
Illinois
Indiana
Kansas
Kentucky
Louisiana
Maryland
Michigan
Mississippi
Missouri
Montana
Nebraska
Nevada
New Mexico
New York
North Dakota
Ohio
Oklahoma
Pennsylvania
South Dakota
Tennessee
Texas
Utah
Virginia
West Virginia
Wyoming
TOTAL
SOX
107
85
6
96
553
237
34
135
11
316
6
1,438
6
147
197
6
175
51
11
338
56
119
164
1,156
62
11
6
4,061
119
6
73
536
10,324
NOX
1,611
1,193
85
1,442
8,310
3,561
509
2,035
170
4,749
85
21,622
85
2,205
2,968
85
2,629
763
170
5,088
848
1,781
2,459
17,383
933
170
85
61,051
1,781
85
1,102
8,055
155,098
HC
129
101
7
115
664
285
41
1,879
14
380
7
1,729
7
176
237
7
210
61
14
407
68
142
197
1,390
75
14
7
4,881
142
7
88
546
14,027
CO
350
263
18
332
1,807
775
111
443
37
1,033
18
4,703
18
480
645
18
572
166
37
1,106
184
387
535
3,781
203
37
18
13,278
387
18
240
1,752
33,752
1-1
-------
DRILLING EMISSIONS FOR THE YEAR 1978
(103 kg)
State
Alabama
Alaska
Arizona '•
Arkansas
Cal ifornia
Colorado
, Fl orida
i Illinois i
Indiana
Kansas
Kentucky :
Louisiana : 1
Maryland
Michigan ;
Mississippi
Missouri
1 Montana
Nebraska
Nevada ;
New Mexico
New York
North Dakota
Ohio
Oklahoma ! 1
i Pennsylvania
: South Dakota
: Tennessee
! Texas 4
; Utah ;
i Virginia
West Virginia
• Wyoming
TOTAL 11
i
SOX ; NOX
113 : 1,696
96 : 1,204
6 85
102 ' 1,526
604 : 4,073
260 ; 3,901
34 : 509
147 2,205
11 170
344 5,173
6 i 85
,568 23,573
6 85
164 2,459
220 3,307
6 85
192 2,883
56 | 848
11 ; 170
367 5,512
62 933
130 1,950
175 2,629
,264 i 18,994
68 1,018
11 170
6 , 85
,434 . 66,732
130 : 1,950
6 85
79 1,187
587 8,818
,265 164,100
i
HC
136
112
7
122
725
312
41
1,893
14
414
7
1,885
7
197
264
7
230
68
14
441
75
156
210
1,519
81
14
7
5,336
156
7
95
607
15,159
CO
369
275
18
350
1 ,973
848
111
480
37
1 ,125
18
5,127
18
535
719
18
627
184
37
1,199
203
424
572
4,131
221
37
18
14,513
424
18
258
1,918
36,805
1-2
-------
DRILLING EMISSIONS FOR THE YEAR 1979
(103 kg)
State
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
Pennsylvania
South Dakota
Tennessee
Texas
Utah
Virginia
West Virginia
Wyoming
TOTAL
SOX
124
102
6
113
654
282
39
164
17
378
6
1,704
6
175
237
6
209
56
17
400
68
141
192
1,371
73
17
6
4,806
141
6
90
632
12,238
NOX
1,866
1,210
85
1,696
9,836
4,240
594
2,459
254
5,681
85
25,608
85
2,629
3,561
85
3,137
848
254
6,020
1,018
2,110
2,883
20,605
1,102
254
85
72,329
2,120
85
1,357
9,497
183,678
HC
149
117
7
136
786
339
48
1,913,
20"
454
7
2,047
7
210
285
7
251
68
20
481
81
170
231
1,648
88
20
7
5,783
170
7
109
661
16,327
CO
406
281
18
387
2,139
922
129
535
55
1,236
18
5,569
18
572
775
18
682
184
55
1,309
221
461
627
4,481
240
55
18
15,730
461
18
295
2,065
39,980
1-3
-------
DRILLING EMISSIONS FOR THE YEAR 1980
(103 kg)
1
State ; SOX
Al abama
Alaska
Arizona
Arkansas
135
113
6
118
California 705
Colorado 305
Florida 39
Illinois ' 175
Indiana 17
Kansas : 406
Kentucky I 6
Louisiana 1,839
Maryland i 6
NOX
2,035
1,221
85
1,781
10,599
4,579
594
2,629
254
6,105
85
27,643
85
Michigan 192 2,883
Mississippi 254 3,816
Missouri 6 85
Montana 220 3,307
Nebraska 62 i 933
Nevada 17
New Mexico 429
New York 73
North Dakota
Ohio
Okl ahoma
Pennsyl vania
South Dakota
152
209
1.478
79
17
Tennessee 6
Texas 5,184
254
6,444
1,102
2,290
3,137
22,216
1,187
254
848
78,010
Utah 152 ; 2,290
Virginia | 6 , 85
West Virginia
Wyomi ng
TOTAL
96 : 1,442
683 • 10,260
13,185 198,538
HC
! 163
129
7
143
847
366
: 48
1,927
i 20
488
7
2,210
7
231
305
7
264
75
20
515
88
183
251
1,776
95
20
7
6,237
183
7
115
722
17,463
CO
443
292
18
405
2,305
996
129
572
55
1,328
18
6,012
18
627
830
18
719
203
55
1,401
240
498
682
4,832
258
55
18
16,966
498
18
313
2,231
43,053
1-4
-------
DRILLING EMISSIONS FOR THE YEAR 1981
(103 kg)
State
Al abama
Alaska
Arizona
Arkansas
Cal ifornia
Colorado
Florida
Illinois
Indiana
Kansas
Kentucky
Louisiana
Maryland
Michigan
Mississippi
Missouri
Montana
Nebraska
Nevada
New Mexico
New York
North Dakota
Ohio
Oklahoma
Pennsylvania
South Dakota
Tennessee
Texas
Utah
Virginia
West Virginia
Wyoming
TOTAL
SOX
147
118
11
130
762
322
45
186
17
434
11
1,969
11
203
271
11
237
68
17
457
79
164
220
1,585
84
17
11
5,562
164
11
101
733
14,158
NOX
2,205
1,227
170
1,950
11,447
4,833
678
2,798
254
6,529
170
29,593
170
3,053
4,070
170
3,561
1,018
254
6,953
1,187
2,459
3,307
23,827
1,272
254
170
83,691
2,459
170
1,526
11,023
212,448
HC
177
134
14
156
915
386
54
1,940
20
522
14
2,366
14
244
325
14
285
81
20
556
95
197
264
1,905
102
20
14
6,692
197
14
122
783
18,642
CO
480
298
37
442
2,490
1,051
147
609
55
1,420
37
6,436
37
664
885
37
775
221
55
1,512
258
535
738
5,182
276
55
37
18,202
535
37
332
2,397
46,272
1-5
-------
DRILLING EMISSIONS FOR THE YEAR 1982
(103 kg)
State
Al abama
Alaska
Arizona
Arkansas
Cal i form' a
Colorado
Florida
111 inois
Indiana
Kansas
Kentucky
Louisiana
Maryland
Michigan
Mississippi
Missouri
Montana
Nebraska
Nevada
New Mexico
New York
North Dakota
Ohio
Oklahoma
Pennsylvania
South Dakota
Tennessee
Texas
Utah
Virginia
West Virginia
Wyoming
sox
152
124
11
135
812
344
45
198
17
463
11
2,104
11
220
293
11
254
73
17
485
84
175
237
1,692
90
17
11
5,940
175
11
107
784
TOTAL ' 15,103
NOX
2,290
1,232
170
2,035
12,210
5,173
678
2,968
254
6,953
170
31,628
170
3,307
4,409
170
3,816
1,102
254
7,377
1,272
2,629
3,561
25,438
1,357
254
170
89,287
2,629
170
1,611
11 ,786
226,530
HC
183
140
14
163
976
413
54
1,954
20
556
14
2,529
14
264
352
14
305
88
20
590
102
210
285
2,034
109
20
14
7,146
210
14
129
844
19,780
CO
498
303
37
460
2,656
1,125
147
646
55
1,512
37
6,879
37
719
959
37
830
240
55
1,604
276
572
775
5,533
295
55
37
19,437
572
37
350
2,563
49,338
1-6
-------
DRILLING EMISSIONS FOR THE YEAR 1983
(103 kg)
State
Al abama
Alaska
Arizona
Arkansas
Cal ifornia
Colorado
Florida
Illinois
Indiana
Kansas
Kentucky
Louisiana
Maryland
Michigan
Mississippi
Missouri
Montana
Nebraska
Nevada
New Mexico
New York
North Dakota
Ohio
Oklahoma
Pennsylvania
South Dakota
Tennessee
Texas
Utah
Virginia
West Virginia
Wyoming
TOTAL
SOX
164
135
11
147
863
367
51
214
17
496
11
2,234
11
231
310
11
271
79
17
519
84
186
254
1,800
96
17
11
6,318
186
11
118
835
16,075
NOX
2,459
1,243
170
2,205
12,973
5,512
763
3,222
254
7,462
170
33,578
170
3,477
4,664
170
4,070
1,187
254
7,886
1,272
2,798
3,816
27,049
1,442
254
170
94,968
2,798
170
1,781
12,549
239,353
HC
197
151
14
177
1,037
441
61
1,974
20
597
14
2,685
14
278
373
14
325
95
20
631
102
224
305
2,163
115
20
14
7,600
224
14
143
905
20,947
CO
535
315
37
497
2,822
1,199
166
701
55
1,623
37
7,303
37
756
1,014
37
885
258
55
1,715
276
609
830
5,883
313
55
37
20,673
609
37
387
2,729
52,485
1-7
-------
DRILLING EMISSIONS FOR THE YEAR 1984
(103 kg)
State
Al abama
Alaska
Arizona
Arkansas
Cal ifornia
Colorado
Florida
Illinois
Indiana
Kansas
Kentucky
Louisiana
Maryland
Michigan
Mississippi
Missouri
Montana
Nebraska
Nevada
New Mexico
New York
North Dakota
Ohio
Oklahoma
Pennsylvania
South Dakota
Tennessee
Texas
Utah
Virginia
West Virginia
Wyoming
TOTAL
sox
175
141
11
152
914
390
51
226
23
525
11
2,369
11
248
327
11
288
84
23
547
90
198
265
1,907
101
23
11
6,690
198
11
124
880
17,025
NOX
2,629
1,249
170
2,290
13,736
5,851
763
3,392
339
7,886
170
35,613
170
3,731
4,918
170
4,325
1,272
339
8,310
1,357
2,968
3,985
28,600
1,526
339
170
100,565
2,968
170
1,866
13,227
255,124
HC
211
157
14
183
1,098
468
61
1,988
27
631
14
2,847
14
298
393
14
346
102
27
665
109
238
319
2,292
122
27
14
8,047
238
14
149
960
22,087
CO
572
320
37
515
2,988
1,273
166
738
74
1,715
37
7,745
37
811
1,070
37
940
276
74
1 ,807
295
646
885
6,233
332
74
37
21 ,890
646
37
406
2,877
55,553
1-8
-------
DRILLING EMISSIONS FOR THE YEAR 1985
(103 kg)
State
Al abama
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
Pennsylvania
South Dakota
Tennessee
Texas
Utah
Virginia
West Virginia
Wyoming
SOX
181
152
11
164
965
412
56
237
23
553
11
2,505
11
260
350
11
304
84
23
581
96
203
282
2,014
107
23
11
7,068
203
11
130
931
TOTAL 17,973
i
NOX
2,714
1,260
170
2,459
14,499
6,190
848
3,562
339
8,310
170
37,648
170
3,901
5,257
170
4,579
1,272
339
8,819
1,445
3,053
4,240
30,272
1,611
339
170
106,246
3,053
170
1,950
13,991
269,216
HC
217
168
14
197
1,159
495
68
2,001
27
665
14
3,010
14
312
420
14
366
102
27
705
115
244
339
2,420
129
27
14
8,502
244
14
156
1,021
23,220
CO
590
331
37
552
3,154
1,347
184
775
74
1,807
37
8,188
37
848
1,143
37
996
276
74
1,918
313
664
940
6,584
350
74
37
23,126
664
37
424
3,043
58,661
1-9
-------
DRILLING EMISSIONS FOR THE YEAR 1986
(103 kg)
State
Alabama
Alaska
Arizona
Arkansas
Cal i form' a
Colorado
Florida
Illinois
Indiana
Kansas
Kentucky
Louisiana
Maryland
Michigan
Mississippi
Missouri
Montana
Nebraska
Nevada
New Mexico
New York
North Dakota
Ohio
Oklahoma
Pennsylvania
South Dakota
Tennessee
Texas
Utah
Virginia
West Virginia
Wyoming
TOTAL
SOX
192
158
11
169
1,016
435
56
248
23
581
11
2,634
11
276
367
11
321
90
23
609
101
215
299
2,121
112
23
11
7,440
215
11
135
982
18,907
NOX
2,883
1,266
170
2,544
15,262
6,529
848
3,731
339
8,734
170
39,598
170
4,155
5,512
170
4,833
1,357
339
9,243
1,526
3,222
4,494
31,883
1,696
339
170
111,927
3,222
170
2,035
14,754
283,291
.HC
231
174
14
204
1,220
522
68
2,015
27
698
14
3,166
14
332
440
14
386
109
27
739
122
258
359
2,549
136
27
14
8,956
258
14
163
1,082
24,352
CO
627
337
37
570
3,320
1,420
184
812
74
1,899
37
8,612
37
904
1,199
37
1,051
295
74
2,010
332
701
996
6,934
368
74
37
24,361
701
37
442
3,209
61,728
1-10
-------
DRILLING EMISSIONS FOR THE YEAR 1987
(103 kg)
State
Alabama
Alaska
Arizona
Arkansas
Cal ifornia
Colorado
Florida
111 i no is
Indiana
Kansas
Kentucky
Louisiana
Maryland
Michigan
Mississippi
Missouri
Montana
Nebraska
Nevada
New Mexico
New York
North Dakota
Ohio
Oklahoma
Pennsylvania
South Dakota
Tennessee
Texas
Utah
Virginia
West Virginia
Wyoming
TOTAL
SOX
203
163
11
180
1,066
457
62
265
23
609
n
2,770
11
288
384
11
333
96
23
643
107
226
310
2,228
118
23
11
7,812
226
11
141
1,033
19,855
NOX
3,053
1,272
170
2,714
16,026
6,869
933
3,986
339
9,158
170
41,633
170
4,325
5,766
170
5,003
1,442
339
9,752
1,611
3,392
4,664
33,494
1,781
339
170
117,608
3,392
170
2,120
15,517
297,548
HC
245
179
14
217
1,281
549
75
2,035
27
732
14
3,329
14
346
461
14
400
115
27
780
129
272
373
2,678
143
27
14
9,410
272
14
170
1,143
25,499
CO
664
343
37
607
3.486
1,494
203
867
74
1,992
37
9,055
37
941
1,254
37
1,088
313
74
2,120
350
738
1,033
7,285
387
74
37
25,597
738
37
461
3,375
64,835
1-11
-------
APPENDIX II
INDIVIDUAL STATE DATA BASE SOURCES
-------
INDIVIDUAL STATE DATA BASE SOURCES
1. ALABAMA
State of Alabama Oil and Gas Board
a. Oil. Gas and Condensate Production for State of Alabama for
b. Letter dated May 29, 1978 from Mark R. Wyatt, Geologist.
2. ALASKA
State of Alaska, Department of Natural Resources, Division of
Oil and Gas Conservation, Statistical Report for the Year 1976.
3. ARIZONA
Oil and Gas Conservation Commission, State of Arizona, Oil , Gas
and Helium Production, December 1977.
4. ARKANSAS
Arkansas Oil and Gas Commission, Annual Oil and Gas Report, 1976.
5. CALIFORNIA
Annual Review of California Air and Gas Production, 1976, Conserv-
ation Committee of California Oil Producers.
6. COLORADO
State of Colorado Oil and Gas Conservation Commission, 1976 Oil
and Gas Statistics.
7. FLORIDA
International Oil and Gas Development (Reference 7), page 64.
8. ILLINOIS
Petroleum Industry in Illinois, 1975, Illinois State Geological
Survey.
9. INDIANA
Oil Development and Production in Indiana During 1976, Department
of Natural Resources.
10. KANSAS
a. International Oil and Gas Development (Reference 7), pages
102-180.
b. Enhanced Oil Recovery Operations in Kansas, 1976, for the
Kansas Enhanced Oil Recovery Committee.
11. KENTUCKY
International Oil and Gas Development (Reference 7), pages 181-196,
-------
12. LOUISIANA
a. Louisiana Annual Oil and Gas Report, 1974. Department of
Conservation.
b. Secondary Recovery and Pressure Maintenance Operating in
Louisiana, 1976 Report, Department of Natural Resources,
Office of Conservation.
13. MICHIGAN
a. International Oil and Gas Development (Reference 7). pages
261-276.
b. Michigan's Oil and Gas Fields. 1976, Department of Natural
Resources, Geological Survey Division.
14. MISSISSIPPI
Mississippi Oil and Gas Bulletin, Annual Report, 1976, Mississippi
Oil and Gas Board .
15. MONTANA
Oil and Gas Conservation Division, Annual Review for the Year
1976, Relating to Oil and Gas.
16. NEBRASKA
a. International Oil_and Gas. De_ve_lopjnent (Reference 7), pages
297-305.
b. Nebraska Oil and Gas Conservation Commission, Secondary
Recovery Report, December 1976.
17. NEVADA
International Oil and Gas Development (Reference 7), page 306
18. NEW MEXICO
a. International Oil and Gas Development (Reference 7), pages
307-325.
b. New Mexico Secondary Recovery Projects as of December 31 ,
1976, Oil Conservation Commission.
19. NORTH DAKOTA
Production Statistics and Engineering Data, Oil in North Dakota,
first and second half of 1976, North Dakota Geological Survey.
20. OKLAHOMA
a. International Oil and Gas Development (Reference 7), pages
332-426.
b. Secondary Recovery Operations, Oklahoma, last six months 1976,
Petroleum Information Corporation.
JI-2
-------
21. SOUTH DAKOTA
International Oil and Gas Development (Reference 7), page 429.
22. TENNESSEE
Tennessee 1976 Oil and Gas Production, Tennessee Division of
Geology.
23. TEXAS
a. The Railroad Commission of Texas, Oil and Gas Division,
Annual Report.
b. Personal visit to Austin to obtain secondary information
from Railroad Commission files.
24. UTAH
Monthly Oil and Gas Production Report, December 1976. Division
of Oil and Gas Mining.
25. WYOMING
Wyoming Oil and Gas Statistics, 1976, The Wyoming Oil and Gas
Conservation Commission.
II-3
-------
APPENDIX III
COMPANIES CONTACTED TO DETERMINE EXTENT OF LACT
ACTIVITIES VERSUS TRUCKING OF CRUDE OIL
-------
COMPANIES CONTACTED TO DETERMINE EXTENT OF LACT AND PIPELINE
ACTIVITIES VERSUS TRUCKING OF CRUDE OIL
1. Company:
Individual Contacted:
Telephone Number:
Results of Conversation:
Arapahoe Pipe Line Company,
Brush, Colorado
D.W. Lee
(303) 842-2881
60 percent of oil received is by way
of LACT units and pipelines with the re-
maining oil handled by truck. "The trend
is toward more LACT units. As time goes
on, treatment plants are becoming more
centrally located. This makes LACT units
more economically desirable."
2. Company:
Individual Contacted:
Telephone Number:
Results of Conversation:
Exxon Pipeline Company
Houston, Texas
L.J. Baube
(713) 656-5646
90 percent of oil received is by way of
LACT and pipelines with the remaining
oil handled by truck.
3. Campany:
Individual Contacted:
Telephone Number:
Results of Conversation:
Jayhawk Pipeline Corporation
Wichita, Kansas
Mike McCool
(316) 267-0361
60 percent of oil received is by way of
LACT and pipelines with the remaining
oil handled by truck.
4. Company:
Individual Contacted:
Telephone Number:
Results of Conversation:
Lakehead Pipeline
Superior, Wisconsin
Mr. Burley
(715) 392-5631
100 percent of oil is received by LACT
and pipelines.
III-l
-------
5. Company:
Individual Contacted:
Telephone Number:
Results of Conversation:
6. Company:
Telephone Number:
Results of Conversation:
7. Company:
Individual Contacted:
Telephone Number:
Results of Conversation:
8. Company:
Telephone Number:
Results of Conversation:
National Transit Company
Oil City, Pennsylvania
Mr. Dickenson
(814) 645-1251
70 percent of oil received is gauged
through pipelines with the remaining
oil received by truck. No LACT units
are used.
Portal Pipeline
Billings, Montana
(406) 259-4521
100 percent of oil is received by LACT
and pipelines.
Sunniland Pipeline Company
Fort Lauderdale, Florida
Mr. St. John
(305) 467-0769
89 percent of oil received is by LACT
and pipelines with the remainder
received by truck.
Texoma Pipeline Company
Tulsa, Oklahoma
(918) 749-0959
100 percent of oil is received by LACT
and pipelines.
III-2
-------
APPENDIX IV
GUN BARREL EMISSION CALCULATIONS
-------
GUN BARREL EMISSION CALCULATIONS
Fixed roof emissions consist of breathing and working losses.
Fixed roof breathing losses consist of: vapor expelled from a tank
because of the thermal expansion of existing vapors; vapor expan-
sion caused by barometric pressure changes; and/or an increase in
the amount of vapors due to added vaporization in the absence of
liquid-level change. Fixed roof working losses consist of vapor
expelled from a tank as a result of filling and emptying operations.
Filling loss is the result of vapor displacement by the input of
liquid. Emptying loss is the expulsion of vapors subsequent to
product withdrawal, and is attributable to vapor growth as the
newly inhaled air is saturated with hydrocarbons.
A gun barrel has a very high volume of liquids passing through
it with little or no fluctuation in the liquid level within the tank.
Therefore, working losses are assumed to be essentially zero.
Fixed roof breathing losses are calculated using the relation-
ship presented on page 4.3-6 of "Compilation of Air Pollutant
Emission Factors," AP-42, Part A, Second Edition.
L (Ib/day) = 2.21 x 10"4 M
B
where M = molecular weight, presumed to be 50 from Table
4.3-1 of AP-42
P = true vapor pressure, assumed to be 2.8 psia at
60°F, from same table
D = tank diameter, 10 ft
H = vapor space height; gun barrel was assumed to be
85 percent full at all times, leaving (0.14)(20)
= 3 ft for H
AT = average ambient temperature change from day to
night, 15°F
F = paint factor 1.15 (white paint, poor condition)
IV-1
-------
C = adjustment factor for small diameter tanks, 0.52
Kc = crude oil factor, 0.65
A r ? « -i0.68 i 70 n en n sn
_ p on in~"/irn\l i. . O | / n n\ I . IJ i 0^ U. D I / n c \ U . 3U
(1.15)(0.52)(0.65)
= 0.585
LT = LB = 0.585 Ib/day = 213.5 Ib/yr = 96.8 kg/yr
IV-2
-------
APPENDIX V
THE EMISSIONS CALCULATIONS FROM A
1 ,000 BARREL WASH TANK
-------
THE EMISSIONS CALCULATIONS FROM A 1,000 BARREL TANK
The wash tank was assumed to be a fixed roof storage tank with
potential breathing and working losses. As with the gun barrel, (see
Appendix IV), the wash tank has a high volume of liquids passing
through it with little or no fluctuation in the liquid level within
the tank. Therefore, working losses are assumed to be essentially
zero.
Fixed roof breathing losses are calculated using the relationship
presented on page 4.3-6 "Compilation of Air Pollutant Emission Factors,"
AP-42, Part A, Second Edition
-4
LB (Ib/day) = 2.21 x 10"* M
14.7-P
0.68
D1.73H0.51AT0.50F
as discussed and defined in Appendix IV, the following values are
assigned:
M = 50 Ib/lb mole
P = 2.8 psia at 60°F
D = 21.1
H = 15 percent of a 16 ft high tank is 2.4 ft
AT = 15°F
Fp = 1.15
C = 0.91
KC = 0.65
0.68
LR - 2.21 x 10-4 (50) [ 2-8 1 (21.1)1-73(2.4)°-51(15)0-50
b L14.7-2.8J
= 3.323
LT = Lg = 3.323 Ib/day = 1,212.9 Ib/yr = 550.2 kq/yr
V-l
-------
APPENDIX VI
CALCULATION Oh" WASH TANK RELATIONSHIP
-------
CALCULATION OF WASH TANK RELATIONSHIP
Data used to calculate the wash tank relationship were
obtained from an inventory of tanks done in Kern County, California
during 1977. The inventory was sorted by field and the number of
wash tanks identified in each case. The data base obtained is
presented in Table VI-A. The last column presents a value
expressing the amount of wash tank capacity which is available in
3
a specific field as a function of the annual capacity in 10
barrels.
In order to utilize this information to predict the number of
wash tanks expected in a given field, it was necessary to attempt
to find a correlation for these data. Figures VI-A and VI-B show
the Wash Tank Coefficient for two size ranges of fields.
The next step in the calculation process involves assuming
that the data presented represent a linear relationship.
Careful examination of Figures VI-A and VI-B will reveal that
the field size is presented logarithmically (natural). Any
linear relationship based on these data must utilize the natural
log of the actual field size. Using this information, the data
can be statistically correlated into the following relationship:
y - 139 - 7.99(x)
where x = natural logarithm of the field production in
bbl/yr
y = Wash Tank Coefficient in bbl/103 bbl of
production
This relationship is more easily presented as follows:
139 - ln(x)
y =
7.99
VI-1
-------
Table VI-A. KERN COUNTY INVENTORY OF WASH TANKS
Field Size
172,897
152,490
357,673
526,292
75,412
33,537
556,729
11 ,056,269
3,163,729
117,076
69,079
2,412,737
269,471
3,279,896
1 ,382,132
13,793
1 ,009,769
547,000
561 ,420
100,481
3,961 ,312
30,669,002
2,212,466
564,220
5,590,364
38,270,880
3,858,816
529,347
28,486
No. of
Tanks
1
9
4
16
2
1
13
20
24
1
7
2
1
25
81
1
31
4
40
3
48
76
22
4
24
175
55
53
6
Total
Capacity
1 ,600
8,000
3,250
18,500
2,500
300
29,750
41,972
30,400
2,000
9,350
6,500
1 ,500
20,070
68,470
1 ,000
48,050
5,250
43,250
2,050
131 ,400
224,500
32,090
4,000
51 ,343
325,678
254,601
43,000
6,850
Average Tank
Size
in Barrels
1 ,600
889
813
1,156
1,250
300
2,288
2,099
1,267
2,000
1 ,336
3,250
1,500
803
845
1 ,000
1,550
1 ,313
1 ,081
683
3,738
2,954
1,459
1 ,000
2,139
1 ,861
4,629
811
1 ,142
Wash Tank
Coefficiency
(bbl/103bbl
of Annual
Production)
9.25
52.5
9.09
35.2
33.2
8.95
53.4
3.80
9.61
17.1
135.4
2.69
5.57
6.12
49.5
72.5
47.6
9.60
77.0
20.4
33.2
7.32
14.5
7.09
9.18
8.51
66.0
81 .3
240.8
VI-2
-------
Table VI-A. KERN COUNTY INVENTORY OF WASH TANKS (CONCLUDED)
Field Size
124,462
131,807
1,446,379
91,462
49,783
584,471
364,819
29,906
204,426
634,798
419,729
825,069
4,690,890
123,844
2,263
2,616
21,020
20,478
1,388
14,489
13,347
No. of
Tanks
3
2
21
2
1
23
4
1
2
17
3
7
6
4
1
1
3
1
1
1
4
Total
Capacity
1,600
1,250
33,350
5,000
300
57,150
6,700
1,500
3,000
21,078
1,750
8,750
9,750
2,250
200
250
740
300
500
500
2,150
Average Tank
Size
in Barrels
533
625
1,588
2,500
300
2,485
1,675
1 ,500
1 ,500
1,240
583
1,250
1,625
563
200
250
247
300
500
500
538
Wash Tank
Coefficiency
(bbl/103bbl
of Annual
Production)
12.9
9.48
23.1
54.7
6.03
97.8
18.4
50.2
14.7
33.2
4.17
10.6
2.08
18.2
88.4
95.6
35.2
14.6
36.0
34.5
161.1
VI-3
-------
150
Tank
Coefficient
(bbl/103bbl
of Production)
TOO
50
1,000 10,000
Field Size (bbl of production per year)
50,000
Figure VI-A. Wash Tank Data for Fields Less Than or Equal to 50,000 bbl/yr
-------
I
en
150
TOO
Wash Tank
Coefficient
(bbl/103bbl
of Produc-
tion)
50
50,000
100,000
f]
1
1 ,000,000
Field Size (bbl of production per year)
10,000,000
Figure VI-B. Mash Tank Data for Fields Greater Than 50,000 bbl/yr
-------
where x = annual production in bbl
Wash Tank C
production.
y = Wash Tank Coefficient in bbl/103 bbl of
VI-6
-------
APPENDIX VII
ANNUAL OIL PRODUCTION RATES BY STATES AND
RAILROAD COMMISSION DISTRICTS
TO THE YEAR 1987
-------
ANNUAL OIL PRODUCTION RATES BY STATES AND RAILROAD COMMISSION
DISTRICTS (TEXAS) TO THE YEAR 1987 (IN THOUSANDS OF BARRELS)
State
United States
Alabama
Alaska
Arkansas
Cal ifornia
Colorado
Florida
111 inois
Indiana
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Montana
Nebraska
New Mexico
New York
North Dakota
Ohio
Oklahoma
1977
2865914
9590
137000
15200
316000
36300
42000
22300
3860
54500
6260
465000
40000
41200
31900
88000
83000
768
21500
10400
140000
1978
2828402
9230
201000
14900
315000
34900
40400
20600
3530
52700
5710
421000
38100
38700
31300
77000
80000
724
23000
9800
134000
1979
2906410
8890
378000
14700
315000
33600
38800
19200
3220
51100
5210
383000
36300
36300
30700
67000
72300
683
22200
9800
128000
1980
2972314
8550
529000
14500
314000
32200
37300
17900
2940
49700
4750
348000
34600
34100
30200
58000
74700
644
21000
8700
123000
1981
2905876
8230
554000
14100
310000
31000
35900
16500
2680
47600
4340
315000
32900
32000
29600
50000
71700
608
19800
8200
116000
1982
2881119
7930
554000
13800
306000
28900
34500
15300
2440
45700
3960
286000
31400
30000
29100
43000
68800
573
18800
7700
111000
1983
2732066
7630
554000
13500
302000
28700
32200
14200
2230
43900
3610
260000
29900
28100
28500
38000
66100
541
17900
7200
105000
1984
2635462
7340
529000
13100
298000
27600
31900
13200
2030
42200
3290
236000
28500
26400
28000
33000
63600
510
17000
6800
100000
1985
2534481
7070
503000
12800
295000
26500
30600
12400
1860
40700
3010
214000
21700
24800
27500
28500
61200
481
16500
6400
95700
1986
2500267
6810
491000
13100
304000
25500
29500
12300
1690
42200
2740
197000
25800
23700
26900
25000
61100
454
15500
6000
97400
1987
2449406
6550
466000
13400
312000
24500
28400
12300
1550
43800
2500
181000
24600
22600
26400
22000
61000
428
14600
5700
99500
-------
I
IX)
State
Pennsyl vania
South Dakota
Tennessee
Texas - Total
District 1
District 2
District 3
District 4
District 5
District 6
District 7B
District 7C
District 8
District 8A
District 9
District 10
Utah
West Virginia
Wyoming
Miscel laneous
1977
2970
413
527
1140000
22700
58600
153000
25800
17900
136000
32800
24000
241000
347000
34500
16000
29200
2390
125000
636
1978
3010
387
465
1120000
22000
55400
149000
22000
17400
131000
31900
22200
234000
333000
32300
14800
27000
2380
123000
566
1979
3050
363
410
1100000
21800
52300
145000
18700
16800
125000
31000
20600
226000
321000
30200
13800
25700
2380
120000
504
1980
3100
340
361
1080000
19500
49400
141000
15900
16200
120000
30200
19100
219000
308000
28300
12800
24900
2380
117000
449
1981
3050
319
319
1060000
18700
46600
138000
13600
15700
115000
29400
17700
212000
296000
26500
11900
24300
2330
115000
400
1982
3000
299
281
1030000
17800
44000
134000
11500
15200
111000
28600
16400
205000
285000
24900
11100
24000
2280
112000
356
1983
2970
280
248
1010000
16900
41600
131000
9820
14700
106000
27800
15200
198000
274000
23300
10300
23800
2240
109000
317
1984
2930
262
218
992000
16000
39300
127000
8360
14200
102000
27100
14000
192000
264000
21800
9550
23100
2200
107000
282
1985
2900
246
193
972000
15300
37100
12400
7110
13700
97600
26300
13000
186000
253000
20400
8870
23000
2170
104000
251
1986
3240
230
170
961000
14900
35000
121000
6050
13300
93600
25600
12000
180000
244000
19100
8250
22400
2310
103000
223
1987
3560
216
150
950000
13600
33100
118000
5150
12800
89800
24900
11200
174000
234000
17900
7660
22000
2460
102000
192
-------
APPENDIX VIII
SURFACE PROCESSING EMISSIONS
-------
SURFACE PROCESSING EMISSIONS FOR THE YEAR 1978
(1,000 kg/yr)
State
Alabama
Alaska
Arizona
Arkansas
Cal i form' a
Colorado
Florida
111 inois
Indiana
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Montana
Nebraska
Nevada
New Mexico
North Dakota
Oklahoma
South Dakota
Tennessee
Texas
Utah
Wyoming
TOTAL
HC
733
5,693
22
9,016
13,055
1,826
2,024
63
8
111
58
14,280
921
2,408
1,624
150
43
4,061
1,034
6,366
18
46
51,220
1,647
6,593
123,686
NOX
2
116
-
82
11,106
59
4
-
_
14
1
200
33
31
35
3
1
66
19
57
-
2
2,045
36
485
14,397
sox
_
-
-
-
48,706
-
-
-
-
-
-
1
-
-
-
-
-
-
-
-
-
-
281
-
1,549
50,537
CO
_
9
-
6
1,377
5
-
-
-
1
-
15
2
3
3
-
-
5
1
4
-
-
152
3
53
1,639
- = Negligible
VIII-1
-------
SURFACE PROCESSING EMISSIONS FOR THE YEAR 1979
(1,000 kg/yr)
State
Alabama
Alaska
Arizona
Arkansas
Cal ifornia
Colorado
Florida
Illinois
Indiana
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Montana
Nebraska
Nevada
New Mexico
North Dakota
Oklahoma
South Dakota
Tennessee
Texas
Utah
Wyoming
TOTAL
HC
706
10,709
23
8,895
13,055
1,758
1,944
59
8
753
53
12,991
878
2,259
1,593
131
44
3,792
998
6,081
17
41
50,303
1,568
6,432
125,091
NOX
2
218
-
81
11,106
57
4
-
-
13
1
182
31
29
34
2
1
62
18
54
-
2
2,008
34
473
14,412
sox
-
-
-
-
48,706
-
-
-
-
-
-
1
-
-
-
-
-
-
-
-
-
276
-
1,511
50,494
CO
-
17
-
6
1,377
5
-
-
-
1
-
14
2
3
3
-
-
5
1
4
-
-
149
3
52
1,642
- = Negligible
VIII-2
-------
SURFACE PROCESSING EMISSIONS FOR THE YEAR 1980
(1,000 kg/yr)
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Florida
Illinois
Indiana
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Montana
Nebraska
Nevada
New Mexico
North Dakota
Oklahoma
South Dakota
Tennessee
Texas
Utah
Wyoming
TOTAL
HC
679
14,982
23
8,774
13,013
1,685
1,869
55
7
732
48
11,804
837
2,122
1,567
113
45
3,670
944
5,843
16
36
49,387
1,519
6,271
126,041
NOX
2
305
-
80
11,070
55
4
-
-
13
1
165
30
27
34
2
1
60
17
52
-
1
1,971
33
461
14,384
sox
_
-
-
-
48,550
-
-
-
-
-
-
1
-
-
-
-
-
-
-
-
-
271
-
1,473
50,295
CO
-
24
-
6
1,373
4
-
-
-
1
-
13
2
2
3
-
-
4
1
4
-
146
3
50
1,636
- = Negligible
VIII-3
-------
SURFACE PROCESSING EMISSIONS FOR THE YEAR 1981
(1,000 kg/yr)
State
Alabama
Alaska
Arizona
Arkansas
Cal ifornia
Colorado
Florida
111 i no is
Indiana
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Montana
Nebraska
Nevada
New Mexico
North Dakota
Oklahoma
South Dakota
Tennessee
Texas
Utah
Wyoming
TOTAL
HC
654
15,691
23
8,532
12,848
1,622
1,799
51
6
701
44
10,685
796
1,991
1,536
97
44
3,640
890
5,511
15
32
48,473
1,482
6,164
123,327
NOX
2
319
-
78
10,929
53
3
-
-
12
1
149
28
26
33
2
1
60
16
49
-
1
1,935
32
453
14,182
sox
_
-
-
-
47,933
-
-
-
-
-
-
1
-
-
-
-
_
-
-
-
266
-
1,448
49,648
CO
_
25
-
6
1,356
4
-
-
-
1
-
11
2
2
3
-
_
4
1
3
-
-
143
2
50
1,613
- = Negligible
VIII-4
-------
SURFACE PROCESSING EMISSIONS FOR THE YEAR 1982
(1,000 kg/yr)
State
Al abama
Alaska
Arizona
Arkansas
Cal ifornia
Colorado
Florida
Illinois
Indiana
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Montana
Nebraska
Nevada
New Mexico
North Dakota
Oklahoma
South Dakota
Tennessee
Texas
Utah
Wyoming
TOTAL
HC
630
15,691
22
8,350
12,682
1,512
1,729
47
6
673
40
9,701
759
1,867
1,510
83
44
3,493
845
5,273
14
28
47,101
1,464
6,003
119,567
NOX
2
313
_
76
10,788
49
3
-
-
12
1
135
27
24
32
1
1
57
15
47
-
1
1,880
32
441
13,937
sox
_
_
_
-
47,315
-
-
-
-
-
-
1
-
-
-
-
-
-
-
-
-
-
258
-
1,410
48,984
CO
_
25
_
5
1,339
4
-
-
-
1
-
10
1
2
3
-
-
4
1
3
-
-
139
2
48
1,587
- = Negligible
VIII-5
-------
SURFACE PROCESSING EMISSIONS FOR THE YEAR 1983
(1,000 kg/yr)
State
Al abama
Alaska
Arizona
Arkansas
Cal ifornia
Colorado
Florida
Illinois
Indiana
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Montana
Nebraska
Nevada
New Mexico
North Dakota
Oklahoma
South Dakota
Tennessee
Texas
Utah
Wyoming
TOTAL
HC
606
15,691
21
8,167
12,516
1,502
1,614
44
5
646
37
8,819
723
1,749
1,479
73
42
3,356
805
4,988
13
25
46,187
1,452
5,842
116,402
NOX
2
313
-
74
10,647
49
3
-
-
11
1
123
26
22
32
1
1
55
15
45
-
1
1,844
32
429
13,726
sox
_
-
-
-
46,695
-
-
-
-
-
-
1
-
-
-
-
-
-
-
-
-
-
253
-
1,372
48,321
CO
_
25
-
5
1,321
4
-
-
-
1
-
9
1
2
3
-
-
4
1
3
-
-
136
2
47
1,564
- = Negligible
VIII-6
-------
SURFACE PROCESSING EMISSIONS FOR THE YEAR 1984
(1,000 kg/yr)
State
Al abama
Alaska
Arizona
Arkansas
Cal i form' a
Colorado
Florida
111 inois
Indiana
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Montana
Nebraska
Nevada
New Mexico
North Dakota
Oklahoma
South Dakota
Tennessee
Texas
Utah
Wyoming
TOTAL
HC
583
14,983
20
7,925
12,351
1,444
1,599
41
5
621
33
8,005
689
1,643
1,453
64
40
3,229
765
4,751
12
22
45,365
1,409
5,735
112,787
NOX
2
299
-
72
10,506
47
3
-
-
11
1
112
25
21
30
1
1
53
14
42
-
1
1,811
31
421
13,504
sox
—
_
_
-
46,079
-
-
-
-
-
-
1
-
-
-
-
-
-
-
-
248
-
1,347
47,675
CO
_
24
_
5
1,304
4
-
_
_
1
-
9
1
2
2
_
-
4
1
3
-
-
134
2
46
1,542
- = Negligible
VIII-7
-------
SURFACE PROCESSING EMISSIONS FOR THE YEAR 1985
(1,000 kg/yr)
State
Alabama
Alaska
An' zona
Arkansas
Cal ifornia
Colorado
Florida
111 i no is
Indiana
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Montana
Nebraska
Nevada
New Mexico
North Dakota
Oklahoma
South Dakota
Tennessee
Texas
Utah
Wyoming
TOTAL
HC
562
14,247
20
7,744
12,226
1,386
1,534
38
4
599
31
7,259
655
1,543
1,427
55
38
3,107
743
4,547
11
19
44,449
1,403
5,574
109,221
NOX
2
284
-
71
10,400
45
3
-
-
11
-
102
23
20
29
1
1
51
14
41
-
1
1,774
31
409
13,313
sox
_
-
-
-
45,614
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
243
1,309
47,166
CO
_
22
-
5
1,291
4
-
-
-
1
-
8
1
2
2
-
-
4
1
3
-
-
131
2
45
1,522
- = Negligible
VIII-8
-------
SURFACE PROCESSING EMISSIONS FOR THE YEAR 1986
(1,000 kg/yr)
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Florida
Illinois
Indiana
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Montana
Nebraska
Nevada
New Mexico
North Dakota
Oklahoma
South Dakota
Tennessee
Texas
Utah
Wyoming
TOTAL
HC
541
13,906
19
7,925
12,594
1,334
1,479
38
4
621
28
6,683
624
1,474
1,396
48
38
3,102
698
4,628
11
17
43,947
1,366
5,520
108,041
NOX
1
277
-
72
10,713
43
3
-
-
11
-
94
22
19
29
1
1
51
13
41
-
1
1,754
30
405
13,581
SOX
_
-
-
-
46,987
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
240
-
1,296
48,523
CO
_
22
-
5
1,330
4
-
-
-
1
-
7
1
2
2
-
-
4
1
3
-
-
130
2
44
1,558
- = Negligible
VIII-9
-------
SURFACE PROCESSING EMISSIONS FOR THE YEAR 1987
(1,000 kg/yr)
State
Alabama
Alaska
Arizona
Arkansas
Cal ifornia
Colorado
Florida
111 i no is
Indiana
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Montana
Nebraska
Nevada
New Mexico
North Dakota
Okl ahoma
South Dakota
Tennessee
Texas
Utah
Wyomi ng
TOTAL
HC
520
13,197
19
8,106
12,925
1,282
1,424
38
4
645
25
6,140
595
1,406
1,370
42
37
3,097
657
4,728
10
15
43,446
1,342
5,466
106,536
NOX
1
263
-
74
10,995
42
3
-
-
11
-
86
21
18
28
1
1
51
12
42
-
1
1,734
29
401
13,814
sox
_
-
-
-
48,223
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
237
-
1,283
49,743
CO
_
21
-
5
1,365
3
-
-
-
1
-
7
1
2
2
-
-
4
1
3
-
-
129
2
44
1 ,590
- = Negligible
VIII-10
-------
APPENDIX IX
STORAGE TANK CALCULATIONS
-------
1. 210 Barrel Unit
As discussed when calculating the gun barrel emission estimate,
hydrocarbon vapor losses from a fixed roof tank consist of breath-
ing and working fractions. Unlike both the gun barrel and the
wash tank, storage tank liquid levels are not expected to remain
constant, meaning that working losses must be considered.
A. Breathing Losses
LB(lb/day) = 2.21 x
,-4.
14.7-P
0.68
D1.73H0.51AT0.50
where: M = 50 Ib/lb mole
P = 2.8 psia at 60°F
D = 10 ft
H = 50 percent of 15 ft or 7.5 ft
AT = 15°F
Fp = 1.14
C = 0.52
K = 0.65
\f
LR = 2.21 x
(50)
2.8 I0'
.14.7-2.8.
68
(lO)1'73 (7.5)0'51 (15)0'50
(.1 ..14) (0.52) (0.65).
= 0.92 Ib of HC/day = 335.8 Ib of HC/yr
B. Working Losses
Lw (lb/103gal) = 2.4 x 10'2 (M)(P)(KN)(K£
where: M = 50 Ib/lb mole
P = 2.8 psia at 60°F
K = 0.84
c
IX-1
-------
LW = 2.4 x TO"2 (50)(2.8)(1)(0.84)
= 2.82 lb/103 gal
Assuming 30 turnovers per year for the tank (AP-42 value), annual
losses are:
(2.82 lb/103 gal)(30 turnovers/yr)(210 bbl/turnover)(0.042
x 103 gal/bbl) = 746.2 Ib of HC/yr
Total hydrocarbon losses are: 335.8 + 746.2 Ib/yr = 1,082 Ib of HC/yr
= 0.49 MT/yr
2. 500 Barrel Unit
A. Breathing Losses
Different parameters include:
D = 15.43 ft
C = 0.75
LR = 2.21 x 10"4(50)
0.68
(15.43)1'73 (7.5)0'51 (IS)0'50
14.7-2.8
(1.14)(0.75)(0.65)
= 2.82 Ib/day = 1,029.3 Ib/yr
B. Working Losses
LW is same as for 210 barrel tank: 2.82 lb/10 gal
(2.82 lb/103 gal)(30 turnovers/yr)(500 bbl/turnover)
(0.042 x 103 gal/bbl) = 1,776.6 Ib/yr
Total losses are: 1,029.3 + 1,776.6 = 2,805.9 Ib/yr
= 1 .273 MT/yr
IX-2
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3. 1.000 Barrel Unit
A. Breathing Losses
Different parameters include:
D = 21.13 ft
H = 50 percent of 16 ft, or 8 ft
C = 0.90
0.68
LR = 2.21 x 10"4 (50) ^— (21.13)1'73 (8)0'51 (1.14)
B [14.7-2.8J
(0.90)(0.65) = 6.04 Ib/day = 2,204.6 1b/yr
B. Working Losses
3
LB is same as for 210 barrel tank: 2.82 lb/10 gal
(2.82 lb/103 gal)(30 turnovers/yr)(1,000 bbl/turnover)
(0.042 gal/bbl) = 3,553.2 Ib/yr
Total losses = 2,204.6 + 3,553.2 Ib/yr = 5,757.8 Ib/yr = 2.61 MT/yr
IX-3
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TECHNICAL REPORT DATA .
(Please read Instructions on the reverse before completing)
1. REPORT NO.
2.
3. RECIPIENT'S ACCESSION NO.
[. TITLE AND SUBTITLE
Evaluation of Emissions from Onshore Drilling,
Producing, and Storing of Oil and Gas
5. REPORT DATE
August, 1978
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
L. Norton, J. Hang, P. Farmanian, and R. Sakaida
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Pacific Environmental Services, Inc.
1930 14th Street
Santa Monica, California 90404
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-02-2606
12. SPONSORING AGENCY NAME AND ADDRESS
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina
13. TYPE OF REPORT AND PERIOD COVERED
27711
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16. ABSTRACT
This report provides an estimate of current HC, NOX, CO, SOX, and ^S emissions
from the drilling, production, and storage of oil and natural gas. Projected
emission estimates for each year through 1987 are presented. Various control
options and their cost effectiveness are discussed.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS C. COSATI F'ield/Group
Air Pollution
Control Methods
Hydrocarbons
Onshore Drilling
Storage Tanks
Air Pollution Control
Hydrocarbon Emission
Control
Organic Vapor
Stationary Sources
8. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
20. SECURITY CLASS {This page)
Unclassified
22. PRICE
EPA Form 2220-1 (Rev. 4-77) PREVIOUS EDITION is OBSOLETE
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