EPA-650/2-75-030
December 1974
Environmental Protection Technology Series
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EPA-650/2-75-030
SULFUR COMPOUND EMISSIONS
OF THE PETROLEUM
PRODUCTION INDUSTRY
by
Ecology Audits Inc.
9995 Monroe Drive
Dallas, Texas 75220
for
The M.W. Kellogg Company
1300 Three Greenway Plaza East
Houston, Texas 77046
Contract No. 68-02-1308, Task 26
ROAP No. 21ADE-010
Program Element No. 1AB013
EPA Project Officer: Max Samfield
Control Systems Laboratory
National Environmental Research Center
Research Triangle Park, North Carolina 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF RESEARCH AND DEVELOPMENT
WASHINGTON, D.C. 20460
December 1974
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EPA REVIEW NOTICE
This report has been reviewed by the National Environmental Research
Center - Rcsearch Triangle Park, Office of Research and Development,
EPA, and approved for publication. Approval does not signify that the
contents necessarily reflect the views and policies of the Environmental
Protection Agency, nor does mention of trade names or commercial
products constitute endorsement or recommendation for use.
RESEARCH REPORTING SERIES
Research reports (if the Office of Research and Development. U.S. Environ-
mental Protection Agency. have’ been grouped into series. These broad
categories were established to facilitate further development and applica-
tion of environmental technology. Elimination of traditional grouping was
consciously planned to foster technology transfer and maximum interlace
in related fields. These series are;
1. ENVIRONMENTAL HEALTH EFFECTS RESEARCH
2. ENVIRONMENTAL PROTECTION TECHNOLOGY
3. ECOLOGICAL RESEARCH
4. EN IJRONMENTAL MONITORING
5. SOCiOECONOMiC ENVIRONMENTAL STUDIES
6. SCIENTIFIC AND TECHNICAL ASSESSMENT REPORTS
9. MISCELLANEOUS
This report has been assigned to the ENVIRONMENTAL PROTECTION
TECHNOLOGY series. ‘I’his series describes research performed to
develop and demonstrate instrumentation, equipment and methodology
to repair or prevent environmental degradation from point and non-
point sources of pollution. This work provides the new or improved
technology required for the control and treatment of pollution sources
to meet environmental quality standards.
This document is available to the public for sale through the National
Technical Information Service, Springfield, Virginia 22161.
Publication No. EPA-650/275030
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TABLE OF CONTENTS
PAGE NO .
GLOSSARY hr
I. INTRODUCTION 1
A. Sources of Sulfur Emissions in the Petroleum
and Natural Gas Production Industry 1
B. General Sources of Pertinent Data 14
II. OVERALL SUMMARY AND CONCLUSIONS 1 5
III. PART I - A STUDY TO ASSESS THE OPTIMUM METHOD
TO COLLECT DATA 18
A. Summary 18
B. Purpose of the Study 20
C. Evaluation of Information Sources 23
D. Recommendations for Estimating Emissions
From the Petroleum Production Industry 36
IV. PART II - COLLECTION OF DATA AND EVALUATION OF
SULFUR COMPOUND EMISSiONS 44
A. Summary and Conclusions 44
B. Purpose and Methods 46
C. Summary of Emissions for Study Area 75
V. APPENDICES
1. List of Plants Studied 1—1
2. Production of Sulfur by Counties 2-1
3. Report Forms Used by Several State
Petroleum Regulatory Agencies 3-1
4. Ecology Audits, Inc. Data Forms 4-1
5. Tabular Data for Plants Studied 5-1
6. M.W.Kellogg’s Evaluation of the Assump-
tions, Methods and Results in IV 6-1
111
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GLOSSARY
Acid Gas
A blend of hydrogen sulfide (H 2 S) and carbon dioxide (C0 2 ) that
is separated by the amine process from raw natural gas. Most
plants meter their total acid gas.
Amine Process
A process using one of the amines in which raw natural gas is
bubbled through the solution which absorbs essentially all CO 2
and H 7 S (acid gas). The solution is regenerated by boiling
and tFie acid gas sent on for further processing.
Casinghead Gas
The term used to denote that the gas is principally solution gas
produced in association with crude oil.
Drilling Mud
A fluid system containing clay materials and weighting agents and
circulated in a drilling well to cool and lubricate the drill bit
and to conduct the drilled materials to the surface.
Field
A single well or group of wells that penetrate and produce from
one or more petroleum-bearing formations.
Flare Stack
One conunon way to dispose of acid gas is to mix it with some raw
natural gas and burn it at the end of a flare stack. The combus-
tion takes place in the natural atmosphere and in virtually all
the studies done by Ecology Audits, the combustion of H 2 S to SO 2
is over 98 percent complete. Sometimes a strong wind will extin-
guish a flare causing emissions of hydrogen sulfide until the
flare is re-ignited.
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Formation
A strata or series of associated earth materials having similar
conditions of origin. A single petroleum well will often produce
from several formations in a vertical sequence, and the fluids
found’ in each may be significantly different chemically. As a
result, the composition of the produced fluid may change with time.
Gasoline Plant
A gas processing plant that separates natural gasoline (pentanes
and hexanes-and-heavier) from natural gas streams. These plants
also often produce ethane, propane and butane. By definition,
these plants produce either natural gasoline or blends from which
gasoline can be separated.
Grains per 100 std. Cu. ft. (Gr./lOO ft. 3 )
Standard term for reporting H 2 S concentration in natural gas.
1 Gr./lOO ft. 3 is equivalent to 16 ppm (parts per million) of H 2 S
in natural gas.
Sour Gas
Natural gas containing hydrogen sulfide in concentrations of
4 to 16 ppm or greater.
Sulfur Recovery Plants
A plant which recovers elemental sulfur from a charge gas stream
composed principally of a mixture of H 2 S and CO 2 . Where the acid
gas stream is sufficient, an operator will elect to install a
sulfur recovery plant. Sometimes these plants are operated in
conjunction with gasoline plants, and at other times they are
built independently of any additional gas processing facilities.
Sweet Gas
Natural gas whose hydrogen sulfide content is less than
approximately 4 ppm.
Sweetening Plant
A plant which processes a sour natural gas charge stream,
selectively recovers the H 2 S and CO content and yields a
sweet natural gas stream and an acid gas (H 2 S and C0 2 ) stream
as products.
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I. INTRODUCTION
A. SOURCES OF SULFUR EMISSIONS IN THE PETROLEUM AND NATURAL GAS
PRODUCTION INDUSTRY
The most common volatile sulfur compound found in petroleum and
encountered in petroleum and natural gas production is hydrogen
sulfide. Natural gas is considered to be sour if the hydrogen sul-
fide content exceeds a certain level which varies from 4 ppm to
16 ppm, depending on the company or government body. The Texas Air
Control Board considers crude oil to be sour if it emits a sour gas.’
Other sulfur compounds found in petroleum include mercaptans, organic
sulfur complexes and dissolved elemental sulfur. Sour natural gas
contains hydrogen sulfide in widely varying concentrations, plus
trace amounts of organic sulfur compounds such as mercaptans, carbonyl
sulfide (COS) and carbon disulfide (CS 2 ). Gases processed as part of
refinery operations often contain much larger quantities of organic
sulfur compounds, but these contribute insignificant amounts in the
field production operations.
Nearly all of the dissolved hydrogen sulfide in crude oil volatilizes
in field storage. For example, while the well stream in the Jay Field
is 8 to 10 percent hydrogen sulfide, the concentration of hydrogen
1 Definitions 1.31 and 1.32, Gene’ral Rules, Texas Air Control Board,
November 1, 1973.
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sulfide in the crude going to a refinery is less than SO ppm. Other
compounds, minor in quantity, remain in the crude oil and are part
of the feedstock in a refinery.
1. Location of Sour Gas and Oil
The petroleum industry uses special terminology to describe the
locations of petroleum. A well is drilled through several
formations. Near the surface there are often fresh water aquifers.
At greater depths there are saline aquifers and, hopefully, one
or more petroleum bearing formations. In some locations a single
well can extract petroleum from several formations, each at
different depths. The extent of the petroleum bearing formation
is found by drilling a series of wells. The series of wells is
called a field.
One formation from which the petroleum production is nearly always
sour is the “Smackover”. It runs in a large arc from south of
San Antonio, Texas, northeasterly along the southern boundary of
Arkansas to Jackson, Mississippi, to Pensacola, Florida. Geologists
anticipate that the drilling proposed for offshore Florida will
produce sour gas and oil.
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Mother area in which sour production is often found is the
Permian Basin. Between 10 and 20 percent of the wells in this
area of West Texas and Southeastern New Mexico produce sour
petroleum. There are also some sour fields in Wyoming, Michigan,
Oklahoma, California, Ohio, Montana, Colorado, Arizona and North
Dakota. However, it is estimated that the production from the
Smackover formation and Permian Basin represents about 80 percent
of total sour petroleum production in the United States.
Petroleum found in other areas is usually sweet. This includes
the present production of coastal and offshore areas of Texas,
much of Louisiana, and all of Alaska.
2. Drilling and Testing Operations
When a well is drilled, the bit is lubricated and cooled with
“drilling muds”. These muds are circulated to the surface to
remove the cuttings. Most operators monitor the muds for the
presence of hydrocarbons, and if it is expected, hydrogen sulfide.
When a well is to be “completed” the petroleum is allowed to flow
freely and push the mud and cuttings out of the hole. Natural gas
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is flared during this operation while the muds and oil flow
into a settling basin or temporary tanks. The oil, too, is often
flared. The particulates arising from these fires are a worse
problem than sulfur dioxide. Well completions generally require
no more than portions of a day or two and represent only a minor
fraction of sulfur emissions.
Some states require that all wells be tested perIodically,
usually annually. When this is done, the well is allowed to
flow freely for up to several hours to determine its productivity.
The gas produced during this test is frequently flared.
During the life of a well, it is likely that between 0.001 and 0.1
percent of production is emitted to the atmosphere during drilling
and testing.
3. Production of Oil
Gas, and frequently saline water, is produced along with crude
oil. When the mixture gets to the surface it flows through
separator units. The oil then flows to a tank battery, the water
is reinjected or disposed of otherwise, and the gas is disposed
of in one of several ways.
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One common way to break down a crude oil/water emulsion is to
heat it. Thus, some of the produced gas or oil is used at the
well site as fuel to furnish heat in a “heater-treater”.
Sulfur dioxide will be emitted if the fuel for the heater-
treater is sour.
Produced gas (called casinghead gas if found associated in
essentially solution ratio proportions with oil) is usually
collected in a gathering system and sent to a processing plant.
In some instances where there are no gathering or sweetening
facilities, flaring is authorized by the petroleum regulatory
agency on a temporary basis. In other cases, the petroleum
regulatory agency will force a field to be closed until facili-
ties are available to handle the gas to prevent its loss.
Crude oil is usually stored in a tank battery for several days,
and this permits most of the gases such as hydrogen sulfide and
carbon dioxide to escape. The vapors from sour crude oil contain
hydrogen sulfide. Many states, including Texas, New Mexico,
and Mississippi, regulate the quantities of hydrogen sulfide that
can be present in ambient air. As a result, many tank batteries
located near residences have vapor recovery systems. The vapors
from stored crude can be quite valuable so, aside from any air
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pollution interests, many firms install vapor recovery systems
as an economic investment. Additional investment in vapor
recovery systems can be expected as the price of natural gas
and natural-gas liquids increases. The recovered vapors are
collected in a gathering system. On rare occasions where the
purpose of the recovery system is to reduce hydrogen sulfide
emissions to the atmosphere and there is no economical way to
treat the gas, it is burned in a flare.
4. Production of Gas
Natural gas is found in reservoirs sometimes with and sometimes
without oil. If found with oil, it is called tt casinghead” gas.
The majority of gas production, both from gas wells and casing-
head gas, is collected and sent to processing plants. In Texas,
for example, reports show that 1.8 percent of casinghead gas is
vented or flared while only 0.016 percent of gas well gas is
vented or flared. 2 The gas moves through gathering systems and
normally none escapes except for leaks in valves or at compressor
stations. Occasionally some will be flared because of a processing
plant malfunction or as a safety device.
2 Annual Report of the Oil and Gas Division, 1973, The Railroad Commission
of Texas.
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5. Processing of Gas
All processing of gas is done either to provide a product which
conforms to customer standards or to maximize financial profit
while conforming to regulatory requirements.
a. Customer Standards
Gas pipelines have standards which set minimum values for
heat content and maximum values for contaminants such as
sulfur compounds and water. Heat content can be improved
by removal of nitrogen and carbon dioxide. Hydrogen sulfide 1
the principal sulfur compound, and carbon dioxide are most
frequently removed by an amine scrubbing system. When sour
gas is found some distance from a processing plant, producers
may install small packaged units to remove acid gases (carbon
dioxide and hydrogen sulfide) prior to sending it on via
pipeline. The tail gases from these small units are either
burned in an incinerator, burned in a flare or vented.
b. Maximize Profits
The processing of lease separator gases can be very profitable.
The most common processing involves separation of the heavier,
easily liquified hydrocarbons from ethane and methane, the
light gaseous components. Methane (CU 4 ) is the principal
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component of natural gas, but it has the lowest heat value
per unit volume and the lowest relative price. Propane
(C 3 H 3 ) and butane (C 4 U 10 ) are familiar bottled gases and
have higher heat values and command higher prices. Heavier
hydrocarbons such as pentane, hexanes and heavier are
generally processed to make motor fuel.
c. Gasoline Plants
The definition of gasoline plants varies. Plants that produce
a blend of natural gas liquids (NGL) are frequently called
natural gas plants. The Texas Railroad Commission reserves
the term for those plants which produce gasoline (pentane
and hexane-and-heavier fractions). An increasing portion
of new plants produce natural gas liquids which are sent to
existing gasoline plants for fractionation.
These types of plants are expensive to construct and costly
to operate. Unless a stream has a flow of at least a few
million cubic feet per day, a processing plant may not be
financially attractive. As a result, many smaller fields sell
gas to pipelines without processing to remove heavier hydro-
carbons.
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There are numerous existing gas processing installations
in the Permian Basin area of West Texas and Southeastern
New Mexico. As a result, there is more complexity
associated with processing in this area. Plant operators
try to maximize profit by keeping their plants operating
at capacity. As a result, some operators do only partial
processing. For example, in one location, the producer
sells the gas to gas pipeline Company A who compresses the
gas and sells it to oil Company B who extracts the propanes
and heavier components and sells the still sour gas stream
back to A who sweetens it at a plant some twenty miles away.
Oil Company B flares the amine regenerator stream resulting
from the sweetening of its products. Both firms emit to
the atmosphere sulfur compounds from the same original gas
stream.
In the other areas studied, there was far less complexity
because plants are built to serve the needs of a particular
field or area.
To minimize corrosion in the plant, most operators sweeten
plant charge streams in which the hydrogen sulfide content
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exceeds 1/4 grain/lOO SCF (4 ppm). The tail gases from the
sweetening plant are used in several ways. If there is a
sufficient quantity of sulfur, usually more than S long tons
per day, a sulfuric acid plant or a sulfur recovery plant will
be built. In most cases, the tail gases from sulfur recovery
and sulfuric acid plants are incinerated, vented or flared,
although occasionally they are reinjected to maintain reservoir
pressure.
d. Cycling Plants
In a number of fields the produced gas is processed to remove
the heavier components and the gas is reinjected into the for-
mation to maintain pressure and increase ultimate recovery.
These are called cycling operations. The produced gas is often
first sweetened prior to processing and reinjection.
e. Other
Another market for sour natural gas is carbon black manu-
facturers where the sulfur content in the raw material is not
detrimental to the end product.
Another minor market is in power plants which have been equipped
to burn sour gas.
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6. Shipment of Natural Gas
The great bulk of the approximately 21 trillion cubic feet of 3
natural gas consumed in the United States annually is transported
between the gas producing areas and gas distribution utilities by
about 20 major gas transmission compai iies. Each firm sets its own
purchasing standards which typically are the same as those in the
tariffs filed with the Federal Power Commission.
The most common standard for hydrogen sulfide is a maximum 0.25
grains per 100 standard cubic feet or about 4 parts per million.
It has been found that gas containing more hydrogen sulfide than
this not only presents health hazards to pipeline workers, but
causes excessive corrosion damage, particularly in compressors.
Because of the general shortage of natural gas at current prices,
transmission companies will consider the purchase of gas with
hydrogen sulfide levels up to 1 gr/lOO SCF if it will not result,
upon dilution with gas in their system, in concentrations exceeding
0.25 gr/lOO SCF.
U.S. Department of Commerce, Statistical Abstract of the United States
1971, p. 645.
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Another common standard for natural gas is 20 grains of total
sulfur per 100 standard cubic feet of gas. One exception to
this is Transwestern Pipeline Company which specifies only a
0.5 gr/l00 SCF tariff with Southern California Gas. As a
practical matter, hydrogen sulfide is rarely less than 95 percent
of the total sulfur content. The reason for the total sulfur
standard has to do with the end users. Sulfur can “poison”
catalysts in petrochemical plants using natural gas feedstocks
and cause discoloration or embrittlement of certain metals during
heat treating. Sulfur can also cause discoloration of glass used
to make engineered products such as light bulbs and television
picture tubes.
The mercaptans used to odorize natural gas are usually added by
the distribution utility unless local laws require the trans-
mission companies to do this.
The accompanying schematic flow sheet, Fig. 1, illustrates the
various sources and channels of disposition of gaseous materials
which are encountered in the production of petroleum and natural
gas.
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FLARE OURU4G WELL
TESTING B COMPLETION
TO FLAREIVENT
OR INCINERATOR
LEASE
EXHA uST
REINJ ECT ION
OR
PIPE LINE
GAS
O iL
WATER
LEASE FUEL
Fig. L SOURCE & DISPOSITION OF GAS IN PETROLEUM PRODUCTION OPERATIONS
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B. GENERAL SOURCES OF PERTINENT DATA
Some, but not all, petroleum producing states have well established
petroleum regulatory agencies to which production data are reported
on a periodic basis, usually monthly. The forms required for
reporting in the different states vary widely, and some are much
more nearly complete than others. Also, many states now have active
air pollution control agencies, and much data on sulfur production
and sulfur emissions from petroleum production operations are
available from this source. Other general sources of data include
trade organizations, manufacturers of equipment or chemicals industry
publications and commercial data sources, independent consultants
and private correspondence, in addition to the petroleum producers
and the gas pipeline companies themselves.
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II. OVERALL SUMMARY AND CONCLUSIONS
A preliminary survey of data sources indicated the feasibility
of obtaining meaningful data on sulfur emissions in the United
States by the natural gas production industry. This preliminary
survey also indicated that there were serious discrepancies as
well as wide differences in the total U.S. sulfur emission values
for the petroleum production industry as reported in two earlier
studies made for the U.S. Environmental Protection Agency.
The major portion of natural gas production industry emissions
of sulfur compounds is contributed by natural gas sweetening
processes in which hydrogen sulfide is removed from the natural
gas. Two large producing areas, the Permian Basin in West Texas
and Southeastern New Mexico and the Smackover Formation which runs
in a large arc starting south of San Antonio, Texas and following
northeasterly along Southern Arkansas and then southeasterly to
Jackson, Mississippi and Pensacola, Florida, account for approxi-
mately 80 percent of the sulfur emissions from natural gas production
operations in the United States. The detailed study was limited to
these two areas.
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long tons/year
metric tons/year
short tons/year
95 percent
confidence limits
Total emissions by the natural gas producing industry in the United
States in 1973 are estimated to be equivalent to 408,000 long tons of
sulfur (415,000 metric tons) which are equal to 914,000 short tons
(829,000 metric tons) of sulfur dioxide. The accuracy of this estimate
is plus or minus 24 percent, indicating a range of 695,000 short tons
(630,000 metric tons) to 1,133,000 short tons (1,028,000 metric tons).
A comparison of the emissions value resulting from the present study
with values from the two previous studies is presented on the following
page:
A study of the available data indicates that the emissions of sulfur
compounds by the natural gas producing industry from the areas studied
were equivalent to 304,000 long tons (309,000 metric tons) of sulfur
in 1973. This resulted in emissions to the atmosphere of 664,000
short tons (602,000 metric tons) of sulfur dioxide and 9,000 short
tons (8,000 metric tons) of hydrogen sulfide. These results are
summarized below: (see Table 5, p. 77 for more detail)
Total Emissions _________________________________
Reported As
Elemental Sulfur —___________
304,000
309,000
340,000
Actual - Emissions
Sulfur Dioxide Hydrogen Sulfide
593,000 8,000
603,000 8,000
664,000 9,000
± 15%
:!: 15%
15%
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Estimated Total Annual Emissions of Sulfur From
Natural Gas Producing Operations in the United States
Reported As Reported As
Sulfur Sulfur Dioxide
Long Tons Metric Tons Short Tons Metric Tons
EAI Study 408,000 ± 24% 415,000 ± 24% 914,000 ± 24% 829,000 ± 24%
Battelle Study 48,400 50,000 108,000 100,000
Process Research, Inc.
Study #1 3,400,000 3,084,000
Study #2 7,340,000 6,659,000
The present study indicates that the weighted average efficiency
of the 55 sulfur recovery plants operating in the study area is
85.3 percent. The weighted average was calculated by summing the
product of the inlet gas charge to each sweetening plant and its
recovery efficiency and dividing the sum by the total amount of
gas sweetened. Recovery efficiency drops rapidly as the ratio of
hydrogen sulfide to carbon dioxide in the acid gas stream decreases.
It will be difficult to maintain a 90 percent recovery efficiency,
even with new plants operating on acid gas streams of 80 percent
and greater hydrogen sulfide content.
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111, PART I - A STUDY TO ASSESS ThE OPTIMUM METHOD TO COLLECT DATA
(This section was submitted in August, 1974, at the conclusion of the
initial study phase.)
A. SUMMARY
This study was conducted by contacting over thirty organizations
including state petroleum and air quality regulatory agencies, trade
associations, publications, manufacturers, service companies for the
petroleum production industry, petroleum production companies and
gas transmission companies. The purpose was to determine an optimum
way to obtain data on the emissions of hydrogen sulfide and sulfur
dioxide by the petroleum production industry.
The major share of petroleum production industry emissions of sulfur
compounds arises from the natural gas sweetening process in which
hydrogen sulfide is removed from natural gas. The hydrogen sulfide
is vented, flared, reinjected or further processed to make elemental
sulfur or commercial products. The 1972 emissions inventory of the
petroleum production industry for Texas showed a total of about
300,000 short tons (272,000 metric tons) of sulfur dioxide emissions,
virtually all of which result from the combustion of hydrogen
sulfide. Based on approximate data, the emissions in Texas are
probably between 50 and 65 percent of the total United States
emissions by this industry.
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There are several other less important sources of sulfur emissions,
such as hydrogen sulfide vapors at field crude oil storage tanks,
the use of unprocessed gas and the combustion of processed gas.
Based on information developed to date, these sources are probably
less than 10 percent of those associated with gas treating plants.
The availability of data varies greatly by state. Fortunately,
Texas and Wyoming, which probably have over 65 percent of U.S.
emissions, have excellent records at both the petroleum and
environmental regulatory agencies. Available data for the other
states can be compiled and then a telephone survey conducted to
resolve discrepancies and fill gaps in information.
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B. PURPOSE OF THE STUDY
This section of the report describes the purpose of the study
and the methods that were employed.
1. Purpose
The purpose of this study was to investigate existing
sources of information to determine the optimum way to
obtain data on the emissions of sulfur compounds by the
natural gas producing and processing and the oil production
industries.
2. Methods
Personal interviews were conducted with nearly all individuals
contacted. Not only were data obtained, but opinions were
solicited on the optimum way to collect data. Below is a
listing of the organizations contacted. Detailed contact
reports are included in Appendix 8 of this report.
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Petroleum Regulatory Agencies
Federal Power Commission
Colorado Oil and Gas Conservation Commission
Louisiana Department of Conservation
Mississippi State Oil 8 Gas Board
Texas Railroad Commission
Wyoming Oil and Gas Conservation Commission
Air Pollution Control Agencies
Colorado Air Pollution Control Division
Louisiana Air Control Commission
Mississippi Air and Water Pollution Control Commission
Texas Air Control Board
Wyoming Department of Environmental Quality
Trade Organizations
American Gas Association
Gas Producers Association
Texas Mid-Continent Oil and Gas Association
Manufacturers of Equipment or Chemicals
C-E Natco Company
Ford, Bacon and Davis
Jefferson Chemical (interview refused)
John Zink Company
Publications and Commercial Data Sources
Bureau of Mines, Department of Interior
R. W. Byram a Co.
Oil and Gas Journal
Petroleum Information Corporation
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Petroleum Producers and Gas Pipeline Companies
Amoco Production Co.
Arkansas Louisiana Gas Co.
Cities Service Oil Co.
Exxon Corporation, U.S.A.
Lone Star Gas
Phillips Petroleum Co.
Shell Oil Co.
Transcontinental Gas Pipeline Corp.
Transwestern Pipeline Co.
Trunkline Gas Co.
United Gas Pipeline
Warren Petroleum Company
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C. EVALUATION OF INFORMATION SOURCES
Visits were made to organizations within eight categories of
information sources. Below is an evaluation of each:
1. State Oil and Gas Regulatory Agencies
All states require operators of gas processing plants to
file monthly reports. The plant operator provides data on
the source of incoming natural gas, the sales or shipments
of products and processed gas and the disposition of the
remainder or “Residue Gas”. These reports are typically
filed by the accounting section of the processor’s company.
Texas asks for data on hydrogen sulfide and production of
sulfur while Wyoming and Mississippi only ask for sulfur
production. Louisiana and Colorado have no such requirement
because sour gas is either rare or non-existent in these
states. Sample report forms are included in the Appendix.
Texas accumulates data on all types of gas processing plants
including gasoline, cycling and “other” plants. “Gasoline
Plants” are defined as those that produce gasoline (natural
gasoline) along with natural gas and other products such as
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butane, propane and ethane. “Cycling Plants” are associated
with gas condensate reservoirs. The produced well stream is
separated at relatively high pressure and the vapors are
processed for sweetening, if necessary, and removal of normal
liquid components. The processed gas is then reinjected to
maintain reservoir pressure as near the original pressure
as possible. “Other Plants” are those where compression
condensate, line drips and similar unfractionated feedstocks
for gasoline plants or refineries are separated from wet-gas
streams and collected.
In 1972 the Texas Railroad Commission 1 reported the following:
Annual Sulfur
Total Number Production
Type of Plant of Plants ( long tons )
Gasoline 340 193,000
Cycling 30 217,000
Other 600 46,000
970 456,000
Oil Gas Journal 2 369 403,000
1 Annual Report of the Oil and Gas Division, 1972. The Railroad
Commission of Texas.
2 “1973 Survey of Gas-Processing Plant”, Oil and Gas Journal
July 9, 1973, for Texas.
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It appears that the Oil Gas Journal survey includes only
the gasoline and cycling plants and omits the “other” plants.
None of the other four states surveyed required reports on
the “other” category of plants.
No state collects data on the use of crude oil as a fuel at
well sites or in plai ts, or flared. Only total production
data are reported. Also, there are no data collected on the
hydrogen sulfide content of crude oil.
2. State Air Control Agencies
All states were required by the Environmental Protection Agency
to have emissions inventories prepared as part of their imple-
mentation plans. Of the five states surveyed, only Texas has
a regular emissions inventory requirement.
Each source is required in Texas to submit data annually on its
emissions. The data are processed in a variety of ways, and
complete data on 1973 emissions by the petroleum production
industry in Texas should be available in October, 1974. (These
data are still not available at the completion of the second
phase of the study, December, 1974.)
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The 1972 inventory as reported to the Texas Air Control Board
shows that the emissions of the petroleum production industry
total about 300,000 short tons (272,000 metric tons) per year
of sulfur dioxide.
There are inconsistencies between the data filed with the
Texas Air Control Board (TACB), data filed with the Railroad
Commission (RRC) and some of the source testing work done by
Ecology Audits, Inc. One reasoi for the inconsistency between
the two state agencies is that the reports are generally
prepared by two different individuals in the company. Reports
for the TACB are usually prepared by the environmental manager
while the RRC reports are furnished by the processor’s accounting
department.
Many clients of Ecology Audits have been surprised by the
higher than expected emissions in stack tests. They relied on
plant balances prior to the general usage of stack testing
which began in 1973. Sulfur production is easy to measure,
but apparently small errors occur in measuring the large volumes
of incoming gas or its hydrogen sulfide content. There are
several possible explanations.
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Sour gas is quite corrosive, and it may damage the orifice
plate measuring incoming flow. This would result in
erroneously low values of inlet gas flow and indicate high
recovery efficiency. Another possible source of error may be
that hydrogen sulfide is so chemically active it reacts with
the sampling and analytical devices such as sample bombs and
tubing in chromatographs. This would also result in under-
stated hydrogen sulfide content of the incoming gas, boost
apparent plant efficiency, and understate tail gas incinerator
emissions.
Several conclusions may be made. The errors in measuring
produced hydrogen sulfide and in estimating the emissions
from a sweetening plant without sulfur recovery are likely to
be small -- generally less than a 5 percent underestimation.
The errors in estimating the stack emissions from sulfur
recovery plants by material balance are likely to be much
greater, perhaps on the order of underestimating by 15 to 30
percent.
None of the other states surveyed had, in their opinion, reliable
and current emission inventories.
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3. Trade Organizations
No data collection or processing is done in the industry by
the three organizations visited. Hydrogen sulfide has not
been studied by the American Gas Association except from the
standpoint of corrosion and safety. The Gas Processors
Association generally is involved with phase equilibria and
enthalpy properties for process design, but it does not
accumulate statistical data on production. The Mid-Continent
Oil and Gas Association acts as a coordinating body for
industry committees and does not accumulate statistical
production data.
4. Manufacturers of Equipment and Chemicals
Companies in this group were very reluctant to discuss any
aspect of their business. By disclosing information about
customers, they run two risks: 1) that competitors will find
out who their customers are and 2) that their customers may
be subjected to an Environmental Protection Agency inquiry.
Neither risk has offsetting commercial advantages.
One maker of chemicals said that there was no easy way to get
a list of plant operators. The sales manager said that the
published directories were of limited help, and that he relied
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on his long-term relationships with most gas processors to
tell him where and when they were planning their next plants.
In short, he confirmed the essence of this study, that there
is no easy or simple way to find out by whom and where gas
sweetening is taking place.
5. Publications/Commerical Data Sources
The Oil Gas Journal does an annual survey of gas-processing
plants. This survey is voluntary and most firms respond. Below
is a tabulation of the plants reported to the petroleum regulatory
agencies and the Oil Gas Journal:
Gas Processing Plants Reported To
State Petroleum Regulatory Agency Oil Gas Journal
Colorado 17 12
Louisiana 169 132
Mississippi 14 10
Texas* 370 369
Wyoming 33 27
Other States 358** 236
Texas “Other” 600 --
U.S. Total 1561 786
* Includes only gasoline and cycling plants. “Other” plants are excluded.
** Estimates based on ratio of underreporting in Colorado, Louisiana,
Mississippi and Wyoming.
-.2 9-
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It appears that the coverage for Texas is good if only
because the format of the Oil Gas Journal report is similar
to that of the Texas Railroad Commission. Data for the other
states shows that the Oil Gas Journal survey covers 75 to
80 percent of the gasoline plants. If this ratio applies
elsewhere then there should be about 358 plants in these states.
This and the 600 “other” Texas plants suggests a U.S. total of
1561 plants.
Starting in 1974, the Oil Gas Journal modified their
questionnaire specifically to request data on sulfur production.
Until then many, but not all, sulfur producers voluntarily
listed sulfur production in the “other” category.
The Bureau of Mines, U.S. Department of the Interior, publishes
a monthly and annual report of sulfur production as part of
its Mineral Industry Surveys. Their mailing list for sulfur
recovery plants is derived from the Oil Gas Journal report.
This survey covers only sulfur recovery plants, and no data on
individual plants can be made available because of departmental
disclosure rules. The Bureau of Mines list of plants can
provide a useful check to verify data obtained from state
regulatory agencies.
-30-
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Below is a comparison of the Bureau of Mines report and the
Oil Gas Journal Report. It shows that many firms responding
to the Oil Gas Journal survey did not include their sulfur
production.
Comparison of Data - Gas Processing Plants
Recovering Sulfur, 1972 Shipments and Capacity
State Bureau of Mines Oil Fi Gas Journal
Number Shipments Number Capacity
of Plants** (1000 long tons)* of Plants (1000 long tons)
1972
Alabama 1 * -- --
Arkansas 2 * 1 2
Florida 1 92 --
Mississippi 2 * 2 80
New Mexico 6 35 2 11
North Dakota 2 * 1 42
Oklahoma 1 1 -- --
Texas 36 * 20 403
WyOming 4 40 2 37
* Data only reported for those states where all recovered sulfur
is made in gas processing plants.
** The number of plants is based on the current Bureau of Mines list
of plants which was annotated on about June 15, 1974, by Roland
W. Merwin and sent to the author.
-31-
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Several firms summarize data filed with the oil and gas
regulatory agencies and make it available on a fee basis.
Petroleum Information, a subsidiary of A. C. Nielson Company,
has some of the data computerized, but there are gaps in
material extracted from the reports.
6. Petroleum Production and Gas Transmission Companies
All of the major petroleum companies were anxious to cooperate.
In general, they are not enthusiastic over additional reports
so they want all existing data currently available to the
public to be summarized. All expressed a desire to cooperate
with a survey of facilities in states where there is limited
public data available.
The gas transmission firms fell into two categories: those
that were cooperative and several that almost refused to
answer any question. It appears that their reluctance to
provide information stems from their tight regulation by the
Federal Power Commission and by the barrage of surveys and
reports resulting from the energy crisis.
-32—
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7. Service Company Data
a. Compositions of Oil and Gas Well Production
Generalized data on approximately 2,000 reports of
reservoir fluids studied over a 35 month period were
examined. Samples from wells in the United States
numbered 856 and of these 158 (18.5 percent) showed
hydrogen sulfide, ranging between 0.01 and 49.0 mol
percent. The lower limit of the content reported is
0.01 mol percent (approximately 6 grains per 100 cubic
feet), which is governed by the analytical accuracy of
the instruments. No data are contained in these reports
on the potential or current production rate of the wells.
Generally, sour reservoirs are tested much more extensively
than sweet reservoirs because of the problems associated with
handling hydrogen sulfide. It is not correct, therefore, to
conclude that 18 percent of new reservoirs contain sour gases.
It also appears that after testing, some well owners have
sold their interests to others or found the wells uneconomical
to produce. Data more than 10 years old, therefore, is probably
of limited value in identifying owners of sour production.
-33-
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Similar data may be obtained for an additional 4,000 to
4,500 studies made during the past ten years, of which
about 350 to 400 may be expected to contain sour gas.
There will be significant dupiication since well owners
frequently have the original well and nearby development
wells tested.
All of the specific well data are confidential, but the
generalized data can be used to identify areas where
hydrogen sulfide exists.
b. Anbient Air and Stack Monitoring
Since its founding in 1967, Ecology Audits has conducted
ambient air studies at 43 sites at or near petroleum
production facilities. In addition, it has conducted 34
stack tests on sulfur recovery plant incinerators for
sulfur dioxide and, in some cases, for hydrogen sulfide.
Much of these data were obtained to aid firms in determining
their compliance status and, in many cases, new equipment
has been installed to control emissions. Another trend is
the reduction in emissions as operators learn more about the
operating characteristics of their plants.
-34-
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All the specific data are confidential, but the generalized
summaries may be used to identify areas where emissions of
sulfur compounds exist.
-35-.
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D. RECOMMENDATIONS FOR ESTIMATING EMISSIONS FROM ThE PETROLEUM
PRODUCTION INDUSTRY
Based on analysis of the information that is available, Ecology
Audits proposes to carry Out a study as presented below:
1. Scope of Work
Ecology Audits proposes to conduct a study whereby the quantity
and disposition of hydrogen sulfide contained in natural gas
produced in the year 1973 from the Permian Basin and the
Smackover Formation will be estimated. Information provided
on the disposition of this hydrogen sulfide will include data
on venting, flaring, incinerating, conversion into elemental
sulfur, and reinjection.
2. Methods
a. Source of Emissions
Emissions of hydrogen sulfide and sulfur dioxide can come
from a variety of sources. The letter by each source
indicates the section to be found in the next following
pages in which these emissions are discussed.
-36-
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Hydrogen Sulfide b. vented from gas sweetening plants
b. emitted by low-temperature (700-
1200°F) tail gas incinerators
operating on sulfur recovery plants
d. emitted by carbon black plants using
sour gas as a feedstock
c. vented unprocessed natural gas
released by sour crude stored in
tanks without vapor recovery
(not included in this study)
Sulfur Dioxide b. released by flares and/or incinerators
at gas sweetening plants
b. released by flares or incinerators
fed by tail gases from sulfur recovery
plants or plants making chemicals
containing sulfur
d. released by users of sour gas such as
power plants
c. flared or burned unprocessed natural
gas
released by the burning of sour crude
in heaters located at plant and well
sites (not included in this study)
released by users of commercial grade
natural gas (not included in this study)
In rare cases hydrogen sulfide is reinjected with other gases to
maintain reservoir pressure. The difficulties in handling
hydrogen sulfide preclude widespread reinjection if any other
gases are available.
-------
b. Emissions of Gas Sweetening and Sulfur Recovery Plants
This group of sources is probably responsible for over 90
percent of the total emissions. All available data will be
assembled on a county basis.
Analysis sheets will be prepared for each county known to
produce sour gas. All available information from state
agencies, publications and service company sources will be
compared and analyzed. Inconsistencies will be identified
and phone calls made to the producer to resolve these. Some
personal visits will be required to both Austin and Santa Fe
and possibly other state capitols.
Special attention will be given sulfur recovery plants,
injection systems and producers selling tail gases to chemical
companies for further processing.
C. Emissions From Flaring, Burning or Venting of Unprocessed Sour
Natural Gas
The amount of gas reported to the state agencies as vented
or flared is less than 0.5% of total gas production. Data
on the emissions from the burning or venting of unprocessed
-38-
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sour natural gas only will be obtained to determine the
accuracy of these values. The following procedure will be
used:
The gross production into each gathering system will be
determined along with the receipts by gas plants. The
difference is assumed to be used, in an unprocessed state,
on the lease and will be considered to be as sour as the
average produced gas in the county.
d. Miscellaneous Sources of Sulfur Dioxide and Hydrogen Sulfide
For many years sour natural gas has been used as a feedstock
for carbon black plants. The process results in the emissions
of some hydrogen sulfide which will be estimated as part of
the study.
There is also at least one power plant that has been reported
that burns sour natural gas. This plant and other industrial
users of sour natural gas will be studied.
Excellent data are available in Texas where it has been
estimated that between SO and 6S percent of the emissions
occur. Field survey work will probably be required in some
other states.
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3. Report
A draft report will be prepared discussing the industry, the
sources of emissions and the methods used to collect the data.
Tabular summaries of data collected for the Permian Basin and
the Smackover Formation will be broken down by County, AQCR
and State. The summaries will show:
a. Production of hydrogen sulfide along with natural gas by
county in the study areas.
b. Production of elemental sulfur and other products in sulfur
equivalents from plants using by-products of gas processing
plants as feedstock.
C. Emissions of hydrogen sulfide and sulfur dioxide occurring
at field operations including:
1.) use or venting of unprocessed gas
2.) disposal of tail gases from sweetening operations
3.) tail gas incineration associated with sulfur recovery
and sulfur products production operations
4.) operation of non-petroleum facilities using natural gas
not meeting usual pipeline standards
-40-
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d. Shipment of hydrogen sulfide along with sweetened natural
gas to pipeline customers.
e. Typical range of hydrogen sulfide content of natural gas by
county in the areas studied and calculated average concen-
trations by county based on the hydrogen sulfide analyses.
f. Estimate of the degree of accuracy of the data reported on
a county-by-county basis.
Detailed information will be provided on the data sources and
the methods used to estimate data.
The final report will include:
I. Summary
II. Purpose and Methods
III. Description of Facilities and Processes, Including a Flow
Sheet
IV. Statistical Summaries of Data for the Two Study Areas
V. Summary of Information in Other Areas
Appendices
A. Contact Reports
B. Copies of Important Statistical Source Material
C. Glossary of Terms
-41-
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4. Time Schedule for Project
The accompanying bar chart indicates the approximate time
allocation and the dates for completion of the various phases
of the proposed study.
-42-
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SCHEDULE OF WORK
Weeks Ending:
13
Collect Service
Company Data
Make Up County
Sheets
Visit Austin,
Santa Fe and
Other Capitals
F I
Phone Calls
Analyze Data
Draft Report
Meeting on Draft
Final Report
Preparation
8 9 10 11
23 306 13 20 274 11 18 251 8 15
12
22 29 6
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ri. PART II - COLLECTION OF DATA AND EVALUATION OF SULFUR COMPOUND EMISSIONS
A. SUMMARY AND CONCLUSIONS
1. The emissions of sulfur compounds by the natural gas producing
industry from the Permian Basin and Smackover Formation in 1973
were equivalent to 304,000 long tons of sulfur. This resulted
in emissions to the atmosphere of 664,000 short tons of sulfur
dioxide and 9,000 short tons of hydrogen sulfide. These data
are estimated to be accurate to within plus or minus 15 percent.
2. The emissions by the natural gas producing industry in the United
States but outside of the study area are estimated to be equivalent
to 104,000 long tons of sulfur. The accuracy of this estimate
is plus or minus 50 percent.
3. The emissions by the natural gas producing industry in the United
States, in 1973 are estimated to be equivalent to 408,000 long
tons of sulfur which is equal to 914,000 short tons of sulfur
dioxide. The accuracy of this estimate is plus or minus 24
percent. Emissions could be as high as 1,133,000 or as low as
695,000 short tons of sulfur dioxide in 1973.
-44-
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4. In the study area about 33 percent of all gas produced was
processed for the removal of hydrogen sulfide. This volume
represents about 14.4 percent of total U.S. production of
natural gas. It is likely that about 19 percent of all U.S.
gas production is treated for hydrogen sulfide removal. The
gas production in the study area, therefore, represents
approximately 76 percent of the natural gas which is processed
in the U.S. for the removal of hydrogen sulfide.
5. The weighted average recovery efficiency of the 55 sulfur
recovery plants fed by natural gas in the study area is 85.3
percent. Even the newest three stage plants have difficulty
maintaining 90 percent recovery efficiency on acid gas streams
containing over 80 percent hydrogen sulfide. Recovery
efficiency drops rapidly as the ratio of hydrogen sulfide to
carbon dioxide in the acid gas stream decreases.
6. The reports of the Texas Railroad Commission show that 9.6
billion cubic feet of produced sour gas was either vented or
used as lease fuel in 1973. This activity resulted in minor
emissions: 1233 long tons of sulfur per year, or less than one-
third of one percent of total sulfur intake to sweetening plants.
The data for other states, had they been available, are likely to
show a similar ratio.
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B. PURPOSE AND METHODS
1. Purpose of the Study
The purpose of the study was to perform an investigation of
existing sources whereby the quantity and disposition of
hydrogen sulfide contained in natural gas produced in the
year 1973 from the Permian Basin and the Smackover Formation
will be estimated. Information provided on the disposition
of this hydrogen sulfide will include data on reinjection,
recovery as elemental sulfur and emissions from venting,
flaring, and incinerating.
2. Sources of Information
This section describes the sources of public information
concerning the oil and gas production industry. The first
subsection discusses the data collected by national organiza-
tions. Subsequent parts discuss the data available in each
state.
-46-
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a. General Sources
L) Oil Gas Journal
The Oil Gas Journal (Petroleum Publishing Company,
Tulsa, Oklahoma) makes an annual survey of natural gas
processing plants. The survey is voluntary and most
firms respond.
Table 1 presents comparative data on the number of plants
that reported data to the Oil Gas Journal with plants
reporting to the respective petroleum regulatory agencies
for the states studied.
Because of the different reporting rules among the states,
data in Table 1 should be used only as an approximate
guide. In Texas, for example, some gas processing plants
do not make reports to the state agency because they
produce no hydrocarbon liquids. Reports of the gas
sweetening plants in the Jay Field of Florida were made
to the state agency, even though the recovered liquids are
recombined with field crude. These plants were not
included in the Oil Gas Journal survey.
-47-
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TABLE 1
Gas Processing Plants Reported To
Petroleum Regulatory Oil & Gas
State Agency Journal
Alabama 3 1
Arkansas 4 3
Florida 5 1
Louisiana* 147 124
Mississippi 14 9
Southeastern New Mexico 33 24
Texas** 366 301
(Texas) (575) (70)
*The Petroleum Regulatory Agency column contains 37 plants not
responding to the Oil Gas Journal survey while the Oil Gas
Journal column includes 14 plants not on the state mailing
list.
**Incl es gasoline and cycling plants. “Other” plants are indicated
by parenthesis ( ) and include sulfur recovery plants, drip stations
and plants that produce an unseparated blend of natural gas liquids.
-48-
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The Oil Gas Journal data for states covers about 75 to
80 percent of the gasoline plants, but only a small
fraction of other gas processing units such as sweetening
and dehydration facilities. Although the questionnaire
requested data on sulfur production, only about 33 of the
plants provided this information. No data is provided
on the hydrogen sulfide gas losses of each plant.
2.) Bureau of Mines
The Bureau of Mines of the Department of the Interior
collects and reports United States sulfur production.
The data is reported by state, but several states are
combined where necessary to avoid disclosing the pro-
duction of individual operators.
Mr. Roland Merwin (703/557-0495) provided Ecology Audits
a list of all sulfur recovery plants in the United States
and indicated which of these were at sites of natural gas
processing plants.
Under departmental rules, the data furnished by companies
is treated in confidence except that it may be disclosed
to Federal Defense Agencies.
-49-
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3.) Service Company Data
a.) Well Stream Data
Data contained in 5981 reports of reservoir fluid
studies made by a world-wide service company during
a 10-year period from 1964 to 1973 were examined.
Of these, 2304 reports represent reservoirs in all
of the major producing areas in the United States,
including 265 reports (11.5 percent) on petroleum
containing some hydrogen sulfide.
Since all of the reservoir study data are confidential,
the generalized c ua1itative data were used only to
identify areas where hydrogen sulfide exists. No
data are contained in these reports on the potential
or current production rate of the wells.
The lower limit of content reported is 0.01 mol
percent (approximately 6 grains per 100 standard
cubic feet) which is governed by the analytical
accuracy of the instruments. Any content below
0.01 mol percent is reported as a trace or zero.
—so-
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Generally, sour reservoirs are tested more extensively
than sweet reservoirs because of the problems associated
with handling hydrogen sulfide. In addition, there
tended to be more samples analyzed in the case of sour
petroleum reservoirs per report; therefore, a conclu-
sion that 11.5 percent of reservoirs contain hydrogen
sulfide would not be correct.
b.) Ambient Air and Stack Monitoring
Since its founding in 1967, Ecology Audits has
conducted ambient air studies at 43 sites at or near
petroleum production facilities. In addition, it has
conducted 35 stack tests on sulfur recovery plants
and acid gas incinerators.
Most of this data was used by clients to determine
their compliance status. In many cases new equipment
has been installed to control emissions. As in the
case of reservoir studies, all test data is confiden-
tial, but it can be used to identify areas where
sulfur dioxide and hydrogen sulfide emissions occur.
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b. New Mexico
1.) New Mexico Oil Conservation Commission
Monthly reports are made by all gas processing plant oper-
ators on Form C-lll (See Appendix). No data is collected on
acid gas or hydrogen sulfide. Information on the 33 facili-
ties, including 30 extraction plants, located in Southeastern
New Mexico was obtained from the New Mexico Oil and Gas
Engineering Committee, p. o. Box 127, Hobbs, New Mexico.
The data includes plant intake, plant fuel use, lease
use, sales, reinjection, shrinkage and vented gas.
2.) New Mexico Environmental Improvement Agency
The Air Quality Section provided a listing of plants with
estimated emissions of sulfur dioxide of 25 tons per year
or more. The list was compiled in 1971 for the year 1970
by an EPA contractor assisting the state in the preparation
of its implementation plan. State officials expressed
their reservations regarding the list, and Ecology Audits
confirmed that there were some omissions. Subsequently,
the state provided data on selected plants for which
emissions data had been submitted by plant operators.
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c. Texas
1.) The Railroad Commission of Texas, Oil and Gas Division
All operators of gasoline plants, cycling plants or
any facility which produces or collects liquids is
required to file information monthly on Form GP-l. Data
is collected on hydrogen sulfide, although many operators
report total acid gas (hydrogen sulfide and carbon
dioxide) as hydrogen sulfide.
Where operators do provide information on the composition
of acid gas, it is from ratios given to the operator’s
accounting department by process engineers. Unfortunately,
the engineers sometimes do not keep the accountants up-to-.
date on changes in acid gas composition which occur as
new wells are drilled and old wells cease production.
All reports for 1973 were reviewed, and if hydrogen sulfide
loss was reported, the following data were collected:
-53-
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- - hydrogen sulfide loss
-- sulfur production
- - total plant intake
-- unprocessed gas used in the fuel system or on
a lease
- - vented unprocessed gas
A total of 99 facilities have some reported hydrogen
sulfide Out of a total of 941 facilities (10.5 percent).
This is not a complete list of all potential sources of
sulfur compound emissions because plants which do not
collect liquids, such as sweetening facilities or sulfur
recovery plants, are not required to report to the
Commission.
2.) The Texas Air Control Board
For the past three years the Texas Air Control Board
has sent out questionnaires to all plants in the state
which emit 50 or more tons of pollutants annually. The
data for 1973 was extracted from their working papers for
173 facilities, many of which have emissions less than
50 tons per year of sulfur dioxide. Although these data
are more comprehensive, the emission reports are estimates
-54-
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which are subject to possible error in calculation
methods.
3.) Texas Comptrollers Office
Texas has a severence tax on sulfur, and this office
furnished copies of quarterly production reports by the
35 sulfur plants in the state paying taxes. There are
six more plants in the state that apparently are not
aware of their potential tax liability.
d. Arkansas
1.) State of Arkansas Oil and Gas Commission
Mr. Lynn Fite of this agency provided production and
operating statistics on the four gas processing plants
located in Arkansas. No data is collected on acid gas
or hydrogen sulfide. Mr. Fite also commented on
some specific sour gas wells by indicating that these
had been plugged or that production was initiated from
sweet zones.
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Arkansas is a leading producer of elemental Bromine.
The feedstock for these plants is from saline aquifers
which are tapped in the same manner as petroleum
reservoirs. These aquifers often contain high levels
of hydrogen sulfide. No attempt was made to assess the
emissions from these facilities because it is outside
the scope of the study.
2.) Arkansas Department of Pollution Control and Ecology
Several requests have been made of this agency, but no
letter has been received as of the date of this report.
The Department did confirm that the data developed in
this study for Arkansas is essentially correct.
e. Louisiana
1.) Louisiana Department of Conservation
Monthly reports are required of all gasoline and cycling
plants on Form R-6. No data is collected on either acid
gas or hydrogen sulfide. Officials with the agency said
there may be isolated sour gas flares in Louisiana, but
only the regional directors would have information.
The agency furnished a copy of their mailing list of
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firms submitting monthly reports. Contact was made
with all six district managers and the only sour gas
flares were located in the Southeastern part of the
state, several hundred miles from the Smackover
Format ion.
2.) Louisiana Air Control Commission
The technical secretary of the Commission knew of no
amine treating units in the state. He provided the
names of individuals in industry who might provide
some assistance. It was his opinion that the problems
associated with the natural gas industry are very
minor compared to the other problems in the state.
f. Mississippi
1.) Mississippi State Oil and Gas Board
Monthly reports are made by all gas processing plant
operators on Form 11-10CC G-9 (See Appendix 3.) Data
is required on acid gas in section III of this report.
Copies of reports furnished by the four plants that
report acid gas losses were obtained and summarized.
-57-
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2.) Mississippi Air and Water Pollution Control Commission
Several requests have been made of this agency, but no
letter has been received as of the date of this report.
3.) Region IV Environmental Protection Agency
This region has been requesting firms to submit infor-
mation on emissions. Ms. Carolyn I -teller (404/526-3286)
provided copies of reports furnished by seven operators
in Mississippi. This program is relatively new and not
all sources have been asked to submit data as of the
date of this report.
g. Alabama
1.) State Oil and Gas Board
Mr. Donald B. Moore provided copies of the monthly
data on petroleum activities in Alabama. During 1973,
one gasoline plant and one gas sweetening plant operated
in Alabama. Three more plants commenced operations in
1974. Although no data are collected on hydrogen
sulfide, it did furnish test reports in their fi]es on
two sour gas fields.
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Gas produced on the Alabama side of the Jay and Little
Escambia Creek Fields is treated at the Wiggin’s Lake
facility located just across the state line in Florida.
2.) Alabama Air Pollution Control Commission
Mr. James W. Cooper, Director, provided data on the
emissions of the two plants in the state, only one of
which operated in 1973.
h. Florida
1.) Division of Interior Resources, Bureau of Geology
Mr. Charles Hendly provided copies of monthly reports for
the four gas treating plants located in Northwestern Florida.
These plants remove the hydrogen sulfide from the casinghead
gas. A gasoline plant is currently under construction.
No data are collected on hydrogen sulfide, but most producers
do show their recovered sulfur production.
2.) Department of Pollution Control
Mr. Henry Sobala, Regional Manager of far Northwest Florida,
sent copies of all test reports furnished to his department
by the Jay Field plant operators.
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3. Analysis of Data
a. Data Analysis Sheets
All available data from public sources were entered on a
data sheet. A copy of the type of data sheet used in tabu-
lating the data is included in Appendix 4 as sheet No. 1.
The heading shows the state and the counties within the
state. The left stub provides information on the company
and field and/or plant as appropriate.
Service Company information was used to provide an indi-
cation of the presence of sour gas. G/O is an indication
that the analysis is for Gas or Oil. W/S indicated a well
stream analysis. The hydrogen sulfide content of sour gas
varies with the pressure in the separator, so only in
general terms could the reservoir fluid analysis be used
to indicate the hydrogen sulfide content of the gas stream
going to a processing plant.
Air Agency refers to information provided by the State Air
Control Agency. All reported emissions were reduced to
long tons of sulfur.
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32 2000
SO 2 tons per year X 64 X 2240 - long tons sulfur per year
(.4464)
32 2000
H 2 S tons per year X X 2240 = long tons sulfur per year
(.8403)
Only Texas had up-to-date emissions information on this
industry.
01]. and Gas Journal data was extracted from their 1973 report.
The daily “capacity” in long tons per day was multiplied by 365
to obtain annual data. Comparisons of the data indicate that
“production” rather than “capacity” was reported in many cases.
The Bureau of Mines provided a list of all known sulfur
plants. A plant on their list is indicated by an “X”. In
the lower space data reported to the Texas Comptroller’s
office in long tons of sulfur per year is recorded.
Data for Gas Processing Plants were obtained from each state
agency. The first column shows the total plant throughput
in millions of cubic feet for the year. Where reported,
the “hydrogen sulfide” extraction loss appears in the next
column. In many cases the “hydrogen sulfide” number is
actually the metered acid gas volume from the amine regen-
erator and includes carbon dioxide and some hydrocarbons.
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The “hydrogen sulfide” loss is reduced to long tons of
sulfur as follows:
1 lb. mol = 359.05 cubic feet at 32°F, 14.7 psia
Molecular weight of hydrogen sulfide = 34
Molecular weight of sulfur = 32
Standard reporting conditions to Texas Railroad
Commission: 60°F, 14.65 psia
One long ton = 2240 pounds
Calculate the cubic feet per pound under TRRC conditions:
359.05 460 + 60 14.70
34 X 460 + 32 X 14.65 = 11.21 cubic feet per pound
of hydrogen sulfide
Calculate the tons of sulfur per million cubic feet of
hydrogen sulfide:
1,000,000 1 32
11.20 X 2240 X 34 = 37.48 long tons.sulfur per
MMCFH 2 S
Some operators reported the l-1 2 S content of their produced gas
in terms of grains per 100 standard cubic feet. To calculate
the tons of sulfur per million cubic feet of gas containing
one grain of H 2 S per 100 standard cubic feet, the following
calculation is used:
-62-
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1MMCF = 10,000 grains of hydrogen sulfide
7,000 grains = 1 pound
10,000 32 1
7,000 X 34 X 2240 = .000600 long tons sulfur per
1 4CF with 1 grain H 2 S content
The average “H 2 S” content is calculated by dividing the
loss” by the total plant intake.
Sulfur production is based on data reported to the petroleum
regulatory agency.
Data on unprocessed gas obtained from the state regulatory
agency are recorded in the next column. Both fuel use and
vented gas are reported. Then, using the same average
hydrogen sulfide content as the inlet gas to the plant,
the hydrogen sulfide losses are calculated and converted
into emissions of long tons of sulfur.
The data were then transferred to another data sheet, one for
each facility. This data form is included in Appendix 4, Sheet
No. 2. These sheets were mailed to the operators of several
plants for their comments. Those who operate only one or two
plants were contacted by telephone to verify the data.
-63-
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Included in Appendix 6 is M. W. Kellogg’s Evaluation
of the Assumptions, Methods, and Results used in this
section of the report.
b. Analytical Methods
There are several methods that can be used to analyze a
gas treating facility. Below are some methods used in
the preparation of this report.
1.) Sulfur recovered analysis
Calculate the ratio between plant intake and recovered
sulfur. If the plant is fed by a single field of
similar gas wells, the ratio should remain constant.
Typically, the gas plant intake will show a reasonably
uniform monthly flow except for periodic dips. The
recovery rate will usually show declines each month
until the plant is shut down (the reason for the dip
in monthly intake) and the catalyst bed in the sulfur
recovery unit is renewed after which the recovery rate
peaks again. Below is data for a sulfur recovery plant
which illustrates this:
-64-
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TABLE 2
Gas Sulfur Ratio
Production Recovered LI/mo.
Month MMCF LT/mo. per MMCF
January 339 712 2.10
February 234 813 3.47
March 720 2,576 3.58
April 685 2,451 3.58
May 712 2,307 3.24
June 786 2,247 2.86
July 800 1,705 2.13
August 696 979 1.41
September 680 514 .76
October 0 0 - -
November 781 2,785 3.57
December 897 1,997 2.23
TOTAL 7,330 19,086 2.60
One can readily see that catalyst beds were changed
in January and early February and again in October.
The decrease in catalyst efficiency is clearly observed
in the ratio column. If the plant claims it is 95
percent efficient, one can set the ratio of the best
or second-best month equal to 95 and then get a rough
idea of the efficiency for the other months. In this
case assume that 3.57 is 95 percent, then the annual
average efficiency is 69.2%.
2. 60
Annual average efficiency= t 95) = 69.2%
-65-
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The efficiency for each month can also be calculated.
This method is only valid if the incoming well stream
is uniform.
2.) Unknown acid gas stream
For some plants data on sales gas is known but the
amount of hydrogen sulfide in the incoming gas stream
is not available. If the operator has furnished a plant
material balance based on actual experience, calculations
can be made to determine the mols of acid gas in the
plant inlet gas stream. The mols of water are subtracted
and dry mols of acid gas determined. Since mols are
directly proportional to volume, the hydrogen sulfide
can be calculated on a dry basis for the incoming gas
stream. Below is an illustration of the method
-66-
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TABLE 3
SAMPLE MATERIAL BALANCE
Acid Gas
lbs. mols Sweet Gas
H 2 S 276,828 8,142
CO 2 80,696 1,834
H 2 0 12,546 697
CH 4 224 14
C 2 H 6 151 5
C 3 H 8 176 4
Total Wet Basis 370,621 10,696 1,039,949
Total Dry Basis 9,999
Volume
(MMCF) 4,072 17,335
Volume
(dry) 3,807
3,807
Acid gas is 3,807 + 17,335 = 18.0%
( 3,807 f8,142
H 2 S in feed is 3,8O7 + 17,335/ 9,999J = 14.7%
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c. Survey Information
There were far more public data available on plants located
in Texas than on plants located in the other six states.
Plants in Texas accounted for about 75 percent of the
facilities studied.
When all public data was assembled for Texas plants, there
were discrepancies in the great majority. The discrepancies
for other states were significantly less, if only for the
fact that less data were publicly available.
Copies of the individual data sheets on each plant were mailed
to most multi-plant operators.
Then all operators, both single
and multi-plant, were contacted by telephone and asked to comment
on the data and verify the emissions data. Confirming informa-
tion was obtained from more than 99 percent of the more than
200 plant operators contacted.
Among the reasons for the discrepancies are:
• The Railroad Commission data were incorrect because
some operators reported their acid gas loss as
“H 2 S loss”. In other cases, the operator’s accounting
-68-
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department was using a stream analysis made several
years ago to divide the metered acid gas stream into
H 2 S and CO 2 components. As reservoir pressure changes
and as new wells feed a plant, significant composi-
tional changes occur in acid gas. In some cases,
operators merely neglected to fill in some data, such
as sulfur produced, for some months.
• The Air Control Board data was in error frequently
because of various reporting practices. Some operators
merely annualized their stack test data. This is a
poor practice because most operators “tune” their
plants and take special operating precautions to “pass”
stack tests. After the test is complete, these stand-
ards are relaxed. As a result, stack tests are rarely
indicative of long-term emission levels.
Other operators merely assumed that their plant was
95 or 96 percent efficient and reported emissions as
5 or 4 percent, respectively, of their elemental
sulfur recovery. There appear to be some cases where
operators figured out their allowable emissions and
reported actual emissions at some arbitrary, slightly
smaller number.
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There were also operators who simply confessed that
they had made mathematical errors in their calculations.
In discussing the reports with the operators, Ecology Audits
sometimes felt that some operators reaffirmed emission data
that was much too low. This often occurred where there have
been or are currently court Suits or hearings. In about 10
percent of the cases the operator did not care to take the
time to investigate the discrepancies. In these cases,
Ecology Audits tabulated both the operator’s estimate and
then made its own estimate, based on what, in some cases,
is confidential data.
One of the conclusions of this study is that the use of
infrequent stack test data to show annualized plant efficiency
has limited value if used alone. Much more reliable data can
be obtained by analyzing and developing a material balance for
the incoming gas, the acid gas, the sales gas streams and
sulfur recovery. Meters are almost always installed on these
vapor lines to measure flow continuously. Daily data are
also obtained on sulfur recovered. Periodic checks of stream
-70-
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compositions by on-site analytical techniques and sulfur
recovery, together with occasional stack tests, provide
data for both optimum and long-term emissions evaluation.
4. Other Reports for EPA on this Subject
The Environmental Protection Agency has purchased two prior
studies on the industry. During 1972 a study was made by
Processes Research, Inc., and during 1974 a study was conducted
by Battelle Columbus Laboratories.
a. Processes Research, Inc. Study
The results of this work were reported in two publications:
“Sulfur Dioxide from Natural Gas Fields,” July 21, 1972
conducted under Task Order No. 20 Contract No. CPA 70-1.
“Screening Report Crude Oil and Natural Gas Production
Processes,” December 27, 1972 conducted under Task Order
No. 13, Contract No. 68-02-0242.
The first report comments on the fact that very little data
is available in the public records on the sulfur content of
natural gas. The author assumes that the emissions come
from three sources: sulfur recovery plants were assumed to
emit sulfur (as sulfur dioxide) in an amount equal to 10
-71-
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percent of sulfur recovered. Then it was assumed that
about 20 percent of all gas produced was sour and contained
400 grains per 100 scf (0.64 mol percent). The acid gases
from these plants were assumed to be flared. Finally, it
was assumed that the balance of natural gas contained 20
grains of sulfur per 100 standard cubic feet of gas.
All three assumptions are considerably in error. First,
most sulfur recovery plants do not operate, or at least did
not operate in 1970, at 90 percent recovery efficiency.
Second, the occurrence of sour natural gas varies widely
but in no instance is it as high as was assumed. Finally,
it was found in the first phase of this study that well over
95 percent of the total sulfur in natural gas occurs as
hydrogen sulfide and this compound is usually limited by the
pipelines to 0.25 grains per 100 scf. The reported conclusion
that total sulfur dioxide emissions from natural gas producing
operations totals 3.4 million tons is a vast overstatement
and is unsupported by data of either industry or regulatory
bodies.
-72-
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The second report uses a slightly different set of assump-
tions. It assumes that all the 20.7 trillion cubic feet
of gas marketed contained, when produced, 0.5 mol percent
of sulfur. It was estimated that of the 3.88 million long
tons of sulfur produced, 686,000 long tons are recovered.
The remainder is emitted, some as hydrogen sulfide and
the major portion as sulfur dioxide from the burning of
natural gas. The report arrives at the conclusion that
annual emissions of sulfur are 7.34 million short tons as
sulfur dioxide. This includes 7.15 million short tons
related to marketed gas and 190,000 short tons from vented
and flared gas.
The assumption concerning the sulfur content of natural gas
fails to recognize that most natural gas contains no sulfur.
The assumptions are also at variance with a tabulation of
gas processing plants coittained on pages 32 to 42 in their
report.
b. Battelle Columbus Laboratories Study
The results of this work were reported in “Characterization
of Sulfur Recovery in Oil and Natural Gas Production”,
August 28, 1974, under Task 6, Contract No. 68-02-0611.
-73-
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The report relies heavily on the data in the Oil and Gas
Journal survey for 1972. It assumes that sulfur recovery
plants have an efficiency of 95 percent and that the annual
emissions of sulfur is 50,000 metric tons per year (100,000
metric tons of sulfur dioxide). The author noted the
availability of data from the Railroad Commission in Texas,
but did not attempt to analyze it because so many firms
report acid gas as “H 2 S loss”.
The conclusions of this report greatly understate emissions.
First, the Oil Gas Journal reported on only 20 of the 40
plants in Texas. Further, the results of the present study
indicate sulfur recovery efficiency of approximately 85.3
percent rather than the 95 percent assumed in the report.
The report also does not analyze the emissions from numerous
plants where the acid gas is flared and sulfur not recovered.
-74-
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C. SUMMARY OF EMISSIONS FOR STUDY AREA
1. Study Areas
The study covers all or parts of seven states where gas production
from the Permjan Basin and the Smackover Formation is encountered.
These include Texas, Arkansas, Louisiana, Mississippi and Alabama,
and parts of Southeastern New Mexico and Wostern Florida. No sour
gas was located in Northern Louisiana, so this state will be
excluded. Also excluded were air quality control regions (AQCR)
where there were no reported sour gas production. Table 4 sum-
marizes the AQCRs where emissions of sulfur compounds were found.
Appendix 5 contains data and methods of computing values for Table 4.
Table 4 shows that in the study area 1,304,000 long tons of
sulfur was produced in 1973 in the form of hydrogen sulfide along
with natural gas. Of this amount 1,000,000 long tons were
recovered and 304,000 long tons were emitted to the atmosphere,
normally in the form of sulfur dioxide. All of the sulfur
recovery plants -incinerate their tail gas streams and virtually
all gas sweetening plants burn their acid gas streams through
either flaring or incineration. Many firms that burn their acid
gas (hydrogen sulfide and carbon dioxide) streams erroneously
report the total as emissions of hydrogen sulfide. Ecology Audits
estimates the emissions and their accuracy in Table 5.
-75-
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Natural C ’ i . J;b duct . Air Q iality Cc t ol . y Area
AQCR
Location
No.
of
Plants
Total
Intake
M? f1CF/YR
Gas
Sweetening
‘lant Intake
1MCF/YR
% of Gas
Sweetened
H 2 S in Sour
Natural Gas
as Produced
H 2 S in all
Natural Gas
produced
Quantities in Thousand LT/YR
Sulfur
Produced
Sulfur
Recovered
Elemental
Sulfur
Emitted*
155
(NM)
Pecos
Permian Basin
30
590
587
100
0.49%
0.49%
108
48
60
218
(TX)
Midland-Odessa
San Angelo
81
2726
1801
66**
0.35%
0.23%
236
126
110
211
(TX)
Amarillo
Lubbock
23
1359
530
39**
0.20%
0.08%
40
22
18
217
(TX)
San Antonio
8
159
76
48
1.65%
0.79%
47
34
13
215
210
212
214
(TX)
Dallas-Ft. Worth
Abilene-Wichita
Falls-Austin-
Waco-Corpus
Christi
10
2456
56
2
3.63%
0.08%
77
62
15
213
216
(TX)
Brownsville-
Laredo-Houston
Galveston
SE Texas
--
2213
--
0
--
--
--
22
(TX)
(AR)
Shreveport-
Texarkana-Tyler
14
459
129
28
7.50%
2.10%
362
314
48
5
(MS,Al
FL)
Mobile-Pensacola
Panama City
Southern Miss.
14
165
71
43
16.2%
7.03%
434
394
40
Total (excluding
“other Texas”)
Total Study Area
180
7914
10127
3250
41**
32**
1.07 %
0.44%
0.34%
1304
1000
304
*As estimated by Ecology Audits . Emitted principally as sulfur dioxide from tail gas incineration.
**Approximation - see text
-------
Table 5
Emissions of Sulfur Compounds in the Study Area
Total Emissions Actual Emissions
Reported As
Elemental Sulfur Sulfur Dioxide Hydrogen Sulfide
long tons/year 304,000 593,000 8,000
metric tons/year 309,000 603,000 8,000
short tons/year 340,000 664,000 9,000
95 percent
confidence limits 15% t 15% 50%
(Emissions from Claus plant tail gasses are approximately
172,000 long tons per year of elemental sulfur or 344
long tons per year of SO 2 (see Table 6, p. 83] and this
is included in these totals.)
-77-
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The Texas Railroad Commission publishes data monthly and annually
on the disposition of produced natural gas. Based on this study,
hydrogen sulfide is about 11 percent of the acid gas loss as
reported in Table 8 of their recent annual reports (see Appendix 3).
This is equal to 20 billion cubic feet per year, or about 750,000
long tons of sulfur, equivalent to 58 percent of the hydrogen
sulfide produced in the study area.
2. Facilities Studied
A total of 261 plants were studied, of which 180 plants are believed
to emit more than 50 short tons of sulfur dioxide per year in the
study area. Also, approximately another 40 to 50 plants were identi-
fied, but no data were recorded due to their extremely small size.
It was not possible to obtain data on plant intake for all plants.
Some firms, particularly pipeline companies, did not wish to dis-
close annual volumes. In other cases, the same gas may be processed
by more than one facility. Not all “Gas Sweetening Plant Intake”
as shown in Table 4 and Appendix 5 is sour. Some sweet gas often
by-passes the sweetening unit, but many operators did not have
complete data available and reported total gas processed as
sweetening plant intake. Thus, the data on the share of gas produc-
tion that is treated should be used only as a rough approximation.
-78-
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It is common practice in West Texas for the same gas to be
processed several times. One operator of a major plant which
processes over 100 billion cubic feet per year, sweetens gas to
each individual customer’s specifications. Obviously this
process greatly complicates calculations of emissions for the
operator. Not all gas leaving the plant is of regular pipeline
quality. That gas which is not sweetened by the processor is
sweetened by the customer down the line either in his own plant
or in a contractor’s “line straddle” plant. In other instances,
gasoline plants operate on sour gas. These gasoline plants
sweeten their gasoline product and, at times, their fuel. They
sell their still unsweetened residue “gas” to a gas pipeline
company who sweetens it.
Because much of the gas in West Texas is only slightly sour, up
to about 200 grains of H 2 S/lOO scf (0.32 mol percent), a great
deal of partial processing of gas takes place. In the Smackover
area, the gas is generally more sour, and so each plant there
does a complete job of sweetening the gas up to pipeline standards.
The variations in hydrogen sulfide content also affect the use of
sour gas within gas treating plants and for heating purposes at
-79-.
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the lease operations. A total of 30 plants in Texas reporting
hydrogen sulfide losses sent some unprocessed gas back to lease
operations or vented unprocessed gas. Of these, 28 were in West
Texas. Since many West Texas plants are fed by several streams,
only one or two of which may be sour, the unprocessed gas can,
and often may, be sweet. Further details on the use of
unprocessed gas are contained in Item C.6 of this report (p. 89).
Another factor, which does not affect total emissions, is the use
of sour gas as boiler and compressor fuel. Some companies always
use sweet fuel because of the corrosive effect of sour fuel.
Other companies have learned to cope with corrosion and hence use
sour fuel for in-plant purposes. Since the point of emission of
exhaust gases from these facilities is generally lower than a
flare stack, emissions will result in somewhat higher ground level
concentrations of sulfur oxides closer to the plant.
3. Sulfur Recovery Plants
In the study area, there are 55 plants that recover sulfur or
sulfur products. These plants have an average production of 50
long tons per day of sulfur and recover an average of 85.3
percent of the sulfur in the acid gas feed.
-80-
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Several factors affect the efficiency of sulfur recovery plants:
• Percent of capacity . Newer plants tend to achieve higher
efficiencies because they are operated closer to designed
conditions than older plants which serve partially depleted
fields.
• Carbon dioxide content of acid gas . The presence of
carbon dioxide in the acid gas can have dramatic effects
on efficiency, a factor not present in Claus sulfur recovery
plants located at refineries. Recovery efficiency varies
directly with the percent of hydrogen sulfide in the acid
gas stream. For pure or nearly pure hydrogen sulfide
streams, efficiencies of three stage new plants are designed
to reach in the range of 95 percent, but if the stream is
only 5 to 10 percent hydrogen sulfide, recoveries of sulfur
may be as low as 10 to 20 percent.
• Number of stages . Some older sulfur recovery plants have
only one stage, but most of those in the survey have two
stages. New plants with large capacities often have three
stages. Practical recovery efficiency of plants processing
-81-
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pure hydrogen sulfide streams rises from about 75 percent
with one stage to about 90 percent with two stages and
95 percent with three stages.
• Measurement accuracy . Nearly all gas treating plants have
an acid gas meter. The corrosiveness of hydrogen sulfide
tends to enlarge the orifice hole, reducing the apparent
pressure drop. Mother common practice is to analyze acid
gas streams by taking a sample in a pressure container back
to a laboratory. Hydrogen sulfide tends to react with the
container resulting in erroneously low analyses, especially
in streams containing less than 0.1 mol percent. Thus, both
metering and stream analysis errors tend to understate the
amount of acid gas and overstate apparent plant efficiency.
Table 6 summarizes the data on the 55 sulfur recovery plants.
These plants:
• process 37 percent of all gas sweetened.
• process 89.9 percent of all sulfur produced from the ground
as hydrogen sulfide.
• emit 57 percent of the sulfur dioxide emissions resulting
from gas sweetening.
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TABLE 6
Plants Recovering Sulfur and Sulfur Products From Natural Gas
In Air Quality Control Regions in the Study Area
AQCR
Location
No.
of
Plants
Gas
Sweetening
Plant Intake
MMMCF/YR
% of Sweetened
Gas Processed
In Plants With
Sulfur Recovery
Quantities in Thousand LT/Yr
Average
Recovery
Efficiency
%
Sulfur
Produced
Sulfur
Recovered
Elemental
Sulfur
Emitted *
155
(N.M.)
Pecos
Permian Basin
5
116
20
61
48
13
78
218
(TX)
Midland-Odessa
San Angelo
19
584
32
175
126
49
72
211
(TX)
Amarillo
Lubbock
5
252
47
27
22
5
80
217
(TX)
215
210
212
214
(TX)
San Antonio
6
71
93
46
34
11
75
Dallas-Ft. Worth
Abilene-Wichita
Falls-Austin-
Waco-Corpus
Christi
3
34
32
62
13
82
22
(TX AR)
Shreveport-
Texarkana-Tyler
10
114
88
358
314
44
88
5
(MS,AL
FL)
Mobile-Pensacola
Panama City
Southern Miss.
7
63
88
430
394
36
92
TOTAL
55
1234
37
1172
1000
172
85.3
*As estimated by Ecology Audits.
Emitted principally as sulfur dioxide from tail gas incineration.
-------
Appendix 1 contains a list of sulfur recovery plants in the
study area.
In at least three cases, the sulfur plant makes sulfuric acid
instead of sulfur when it is profitable to do so. Two plants
bubble hydrogen sulfide through an ammonia solution. The
remaining plants produce elemental sulfur.
Of the 55 plants, only one does not utilize the Claus process.
A Stretford unit has been in the start-up stages for over a year
to remove hydrogen sulfide from an acid gas stream with a very
high carbon dioxide content. To date, the Stretford unit has not
yet consistently met even the very low recovery efficiency of the
Claus plant it replaced.
Many sulfur recovery plants, particularly smaller units, operate
unattended. It would be a major error to compare these plants
with Claus plants at refineries because the refinery units rarely
have carbon dioxide, which markedly reduces the operating
efficiency, and they do have 24 hour on-site availability of
chemical engineers, instrumentation specialists and maintenance
personnel. Many of the small and medium-sized sulfur plants
operate with semi-skilled personnel. Engineers and maintenance
-84-
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personnel often only visit the plants periodically. As a result,
Ecology Audits believes that, considering the operating handicaps,
the state of the art limits three-stage plant efficiency to about
90 percent on a long-term basis, with reductions for increases in
carbon dioxide content in the acid gas.
4. Gas Sweetening Facilities
There were 125 facilities studied in this survey, each of which
appeared to emit more than 50 tons of sulfur dioxide annually.
It is likely that there may be another 10 or 15 facilities which
were not included because, based on preliminary review of reported
data, they produced less than the 50 tons per year used as a
minimum in the study.
Many of these plants were associated with gasoline plants, but a
surprising number, about one-third, are not included in petroleum
regulatory agency records. Petroleum regulatory agencies are
concerned principally with liquids and if a gas sweetening plant
collects no liquids, and many do not, then there is no need to
furnish reports. The only way these facilities have been identified
is through the survey work of field personnel of the various state
air control agencies and the reports furnished by the plant operators.
-85-.
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The gas sweetening plants:
• process 63 percent of all gas sweetened.
• process 10.1 percent of all sulfur produced from the
ground.
• emit 43 percent of sulfur dioxide emissions resulting
from gas sweetening.
5. Estimates for Balance of United States
The Natural Gas Industry marketed approximately 21,000 billion
cubic feet of natural gas in 1973. By using the ratio of
production to sales in Texas of 1.1:1, U.S. production is
estimated to be about 23,000 billion cubic feet annually.
Table 7 provides details on the estimated natural gas production
of other states and the estimates of sulfur dioxide emissions.
It shows that the study area includes 87 percent of all sulfur
production, 92 percent of recovered sulfur and about 74 percent
of the sulfur emissions. Below are comments on the sulfur content
of production of the states:
• Alaska - all gas is sweet.
• Arkansas - all production in the northern half of the
state is sweet.
-86-
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TABLE 7
U.S. NATURAL GAS AND SULFUR DATA
NOT INCLUDED IN SURVEY
Estimated 1973 Quantities in Thousand LT/YR
Natural Gas
Production Estimated Estimated Estimated
Billions of Sulfur Sulfur Sulfur
State Cubic Feet Production Recovered Emissions
Arkansas (N) 121* -- -- --
Cal ifornia 5Q4* 6 1 5
Colorado 130* 1* - 1*
Kansas 900 5 5
Kentucky 90 - - - -
Louisiana (S) 8,000 2* 2*
Michigan 44* 5 5
Montana 58* 3 - 3
North Dakota 30* 62* 42* 20
New Mexico (NW) 480* 10 -- 10
Ohio 50 1 - - 1
Oklahoma 1,800 30 3 27
Pennsylvania 70 - - - - - -
Utah 50
West Virginia 250 - - - - - -
Wyoming 370* 72 47* 25
Other States 75 - - - - - -
197 93 104
95 percent confidence limits 35% 20% 50%
*Based on information provided by various state agencies.
Other data is estimated based on knowledge of the area.
-87-
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• California - most California production is sweet, with
the exception of some in the Santa Barbara area and
offshore.
• Colorado - all production is sweet except for some small
fields on the western slope.
• Kansas - some sour gas may exist in the southwestern part
of the state.
• Kentucky - no known sour gas production.
• Louisiana - there are fewer than 10 fields that have sour
production. All are within 100 miles of New Orleans and
flare their acid gas. With this exception, all gas in the
state and offshore is sweet.
• Michigan - many of the newer discoveries are sour.
• Montana - some sour production occurs in this state although
there are no known sulfur recovery plants.
• New Mexico - there is some sour production in the northwest
part of the state.
• North Dakota - some gas in North Dakota is sour and at least
one sulfur recovery plant operates in this state.
• Ohio - there is some minor sour gas production.
-88-
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• Oklahoma - most gas produced in this state will have
the same characteristics as that of the Texas Panhandle.
One sulfur plant operates in this state.
• Pennsylvania - no known major sources of sour gas.
• Utah - no known major sources of sour gas.
• West Virginia - no known major sources of sour gas.
• Wyoming - a significant portion of Wyoming gas is sour.
Four sulfur recovery plants are operated in the state.
All data marked with asteriks (*) in Table 7 were furnished by
state agencies and is considered accurate. All other data have
been estimated by Ecology Audits and, as indicated in Table 7,
are subject to a considerable degree of uncertainty, especially
in the estimates of emissions.
6. Fuel Use and Venting of Gas Prior to Processing
The venting and fuel use of gas can take place either within a
plant or at other locations in the field.
The data collected by most agencies concentrates on the emissions
by plants and large identified facilities. In this report data
-89-
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are compiled on total plant intake, the average sulfur content
of gas, sulfur recovery and the balance which is assumed to
be flared or vented. From an emissions standpoint, it made
no difference whether an operator used sour or sweet gas in
his plant process heaters so long as the gas was part of total
plant intake.
Some gathering systems do not deliver all of their gas to a
plant. The gas not delivered to a plant is often used in
field process heaters, or it is vented or flared. For example,
if the gathering system develops a leak, the gas in the system
will be flared in the field to purge the lines.
The reports for Texas were careful to distinguish whether the
venting and fuel use took place after (Section III, lines 4 and
13 of GP-l) or before (Section II, lines 1 and 9 of GP-l) it
became part of a plant’s intake. No other state compiled this
type of data.
Ecology Audits compiled data on 30 gathering systems associated
with plants known to process sour gas. It was assumed that the
gathering system gas had the same hydrogen sulfide content as
-90-
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the gas entering the plant served by the system. This is
a conservative assumption since many gas plants have several
feed streams and often only one or two will be sour. The
available data does not indicate whether the gas used or
vented outside the plant was sweet or sour. All but two of
these 30 systems are in West Texas. Table 8 summarizes the
data on this venting and field use. The emissions from this
are included in Table 4.
In summary, over 99 percent of the emissions of sulfur compounds
take place after the gas has entered the plant. Only a minor
portion is emitted from produced gas in the field. Furthermore,
the venting and fuel use of unprocessed gas generally takes
place only in areas where the hydrogen sulfide content of the
gas is relatively low.
-91-
-------
Table 8
Disposition of Sour Unprocessed Gas
From Gathering Systems in Texas
Fuel System and Lease Use 9084 MMC.F/year
Vented 561 MMCF/year
Total 9647 MMCF/year*
Sulfur emissions 1233 long tons/year
Average hydrogen sulfide content
of unprocessed gas 0.34 percent
Portion of all Texas emissions
represented by unprocessed gas 0.60 percent
Portion of Texas field vented and
fuel gas to total gas sweetening
plant intake 0.29 percent
*The numbers are probably under-reported because some lease
fuel is used before metering. However, this is negligible.
-92-
-------
Appendix 1
LIST OF PLANTS STUDIED
(Texas)
SULFUR
AQCR COUNTY FIRM PLANT NAME RECOVERED
215 Hunt Quinlan Processing Quinlan
Kaufman Belco Petroleum Tawakoni Gas
Navarro Gulf Energy Development
Co. Powell Gas Treating X
217 Atascosa Atlantic Richfield Co. Fashing X
Elcor Chemical Co.l] “ x
“ Lone Star Gas Co. “
“ Warren Petroleum Co. “ X
Exxon Company, USA Jourdonton X
Gonzales HNG Petrochemicals DuBose
Karnes LoVaca Gathering Co. Persons X
Shell Oil Co. Person X
22 Camp Texas Oil Gas Co. Gilmer X
Cass Shell Oil Co. Bryan’s Mill X
Franklin Getty Oil Co. New Hope X
Texas Oil Gas Co. Chitsey
Gregg Cities Service Oil Co. East Texas
Hopkins Burmah Oil Gas Birthright X
Schneider, Josey Corey Nelta
“ Warren Petroleum Co. Como X
Upshur Arkansas Louisiana Gas
Co. Gilmer
Van Zandt Amoco Production Co. Edgewood X
Cities Service Oil Co. Myrtle Springs X
Wood Amoco Production Co. West Yantis X
210 Fisher Continental Oil Hamlin
Scurry Monsanto Co. Diamond M
211 Carson Shell Oil Co. Bryan
Skelly Oil Co. Crawford
Schafer
1] Bought acid gas stream from Lone Star Gas Co. Plant has been shut down.
1—1
-------
1. LIST OF PLANTS STUDIED
(Texas)
SULFUR
QCR COUNTY FIRM PLANT NAME RECOVERED
211 Cochran Cities Service Oil Co. Lehman X
Gray Skelly Oil Co. King’s Mill
Hansford Phillips Petroleum Co. Sherman
Hockley Amoco Production Co. Slaughter X
Levelland
Anton Irish
P-C Gas Systems Levelland
Hutchinson Colorado Interstate Sanford
Phillips Petroleum Co. Candiam
Texas Sulfur Products 2] “ x
Skelly Oil Co. Watkins
Moore Colorado Interstate Bivins
Diamond-Shamrock McKee X
Phillips Petroleum Co. Sneed
Dumas
Texas Sulfur Products 2] Dumas X
Panhandle Eastern Cabot Booster
Wheeler Natural Gas Pipeline Plant #163 (Briscoe)
Yoakum Amoco Production Co. Prentice
Shell Oil Co. Wasson
Freestone Getty Oil Co. Teas X
Limestone Lone Star Production Co. Box Church
214 Bee Coastal States Gas Co. Pawnee
McMullen Transcontinental Gas
Pipeline Co. Tilden X
Kenedy Exxon Company, USA Santa
Andrews Amoco Production Co. Midland Farms X
South Fullerton X
El Paso Natural Gas Co. Fullerton
Phillips Petroleum Co. Fullerton
“ “ Andrews X
“ Union Oil Co. Bakke
Dollarhide
Texaco, Inc. Mabee
‘] Buys acid gas from nearby Phillips plants.
1-2
-------
1. LIST OF PLANTS STUDIED
(Texas)
SULFUR
AQCR COUNTY FIRM PLANT NAME RECOVERED
218 Crane El Paso Natural Gas McElroy
Mobil Oil Corp. Sand Hills
Phillips Petroleum Co. Crane X
Warren Petroleum Co. Waddell X
“ I’ “ Sand Hills X
Atlantic Richfield Co. Block 31
‘I Exxon Company, USA Sand Hills X
Crockett El Paso Natural Gas co. Midway Line
Ozona Gas Processing Ozona
Permian Corp. Todd
Perry Gas Processors N. Tippett
It Texas Oil E Gas Co. MPI
Dawson Cities Service Oil Co. Welch X
Ector Amarillo Oil Co. Andector X
Amoco Production Co. N. Cowden X
El Paso Natural Gas Co. Goldsmith
Getty Oil Co. Headlee
Phillips Petroleum Co. Goldsmith X
Shell Oil Co. TXL
Odessa Natural Gasoline Texas X
Gaines Amoco Production Co. Cedar Lake
Phillips Petroleum Co. Seminole
Cities Service Oil Co. West Seminole
II TI I I TI Sulfur Plant No. 67 X
Howard Skelly Oil Co. East Vealmoor
Irion CRA, Inc. Mertzon
Midland Mobil Oil Co. Pegasus
Pecos El Paso Natural Gas Co. Santa Rosa
“ Hassie Hunt Trust N. Puckett
Intratex Gas. Co. W. Gomez
U Mobil Oil Co. Waha
It Coyanasa X
‘I Northern Natural Gas. Co. Pikes Peak
I I TI II Jasper
Texas Oil Gas Coyanasa
II LoVaca Gathering Co. Gomez
1-3
-------
1. LIST OF PLANTS STUDIED
(Texas)
SULFUR
AQCR COUNTY FIRM PLANT NAME RECOVERED
Pecos LoVaca Gathering Co. W. Gomez
Petco
Marathon Oil Co. Yates X
Transwestern Pipeline Co. Chenot-Putnam
Atlantic Richfield Co. Imperial
Reagan Dorchester Gas Co. Texon X
Pecos Co. Barnhart X
Reeves Pioneer Natural Gas Co. Barstow
El Paso Natural Gas Co. Waha
LoVaca Gathering Co. Greasewood
Texaco, Inc. Knight
Schleicher Atlantic Richfield Co. El Dorado
Tom Green Beacon Gasoline H. J. Strawn
H Marathon Oil Suzan Peak
Upton El Paso Natural Gas Co. Wilshire
Atlantic Richfield Co. Crane
Ward Cabot Corp. Estes
Intratex Gas MiVida X
H Natural Gas Pipeline Plant #160 (Pyote)
H Northern Natural Gas Co. Lockridge
Perry Gas Processors Pyote
“ Warren Petroleum Co. Monohans
LoVaca Gathering Co. MiVida
Pyote
Block 21
Transwestern Pipeline Co. Pyote
Estes
Winkler Amoco Production Co. Monohans
Perry R. Bass Halley
Cabot Corp. Walton
Northern Natural Gas Kermit
Transwestern Pipeline Co. Halley
H U Walton
“ Plant #164 (Kermit)
U “ Keystone
Natural Gas Pipeline Kermit
Texaco, Inc. South Kermit
1-4
-------
1. LIST OF PLANTS STUDIED
(New Mexico)
SULFUR
AQCR COUNTY FIRM PLANT NAME RECOVERED
155 Eddy Amoco Production Empire Abo X
Yates Gasoline Artesia
(operated by Transwestern)
‘I Southern Union Gas Indian Hills
Marathon Oil Co. Indian Basin X
Phillips Petroleum Co. Artesia X
Lusk
Lea Climax Chemical Hobbs X
Continental Oil Maijamar
El Paso Natural Gas Monument 3]
Jal No.1
H H Jal No.3
Jal No. 4
‘I ‘I Eunice 4]
Northern Natural Gas Hobbs
Perry Gas Processors Antelope Ridge
Tipperary-Resources Denton- Lovington
Warren Petroleum Co. Monument 3]
‘I Saunders
U Eunice
U H Tatum
Texaco, Inc. Buckeye
I’ Skelly Oil Co. Eunice No. 1
H Eunice No. 2
Phillips Petroleum Co. Wilson 4]
It It It Lovington
Eunice 4]
I, Hobbs
‘I Buckeye
Transwestern Pipeline Co. Belle Lake
Roosevelt Cities Service Oil Co. Bluitt X
3] Acid gas from these plants is sold to Climax Chemical, Hobbs.
4] Wilson and Eunice plants of Phillips are adjacent. Eunice acid gas stream
goes to El Paso Eunice plant.
1-5
-------
1. LIST OF PLANTS STUDIED
(Arkansas, Mississippi, Alabama and Florida)
SULFUR
AQCR COUNTY FIRM PLANT NAME RECOVERED
22
.ansas Columbia Arkansas-Louisiana Gas Hamilton X
Lafayette Phillips Petroleum Co. McCamey X
5
ssippi Clarke Shell Oil Co. Goodwater X
Tonkawa Gas Co. Harmony
Continental Oil Co. Pachuta Creek G West Nancy
‘I Getty Oil Co. Pachuta Creek Area
Amerada-I-Iess Eucutta Station
Smith Shell Oil Co. Tallahala Creek
Rankin “ ‘I Thomasville X
Wayne Amerada-Hess Quitmon Cypress Creek
Mobil Oil S. Cypress Creek
5
Alabama Escambia Exxon Co. USA Flomaton X
5
- rida Escambia Louisiana Land
Exploration Co. Wiggins Lake X
Exxon Co. USA Jay X
Amerada-Hess
(Mississippi-Florida) Jay X
Sun Oil Co. Jay X
1-6
-------
Appendix 2
PRODUCTION OF SULFUR BY COUNTIES
5,000 500
50,000 to to less than
or more 50,000 5,000 500
STATE LT/YR LT/YR LT/YR LT/YR
New Mexico Lea Eddy
Roosevelt
Alabama Escambia
Florida Escambia
Mississippi Rankin Clarke Wayne Smith
Arkansas Lafayette Columbia
Texas Cass Franklin Crockett Gregg
Van Zandt Hopkins Dawson Upshur
Crane Wood Reagan Howard
Ector Andrews Gonzales Midland
Gaines Carson Schleicher
Pecos Cochran Irion
Reeves Hutchinson Tom Green
Ward Wheeler Upton
Winkler Hunt Hansford
Atascosa Navarro Bee
Karnes Limestone
Hockley Fisher
Moore Scurry
Yoakum Kaufman
McMullen Gray
Fre estone
2-1
-------
AREAS STUDIED FOR
SULFUR EMISSIONS
EPA CONTRACT N 2 68-02-1308
TASK N 2 26
-------
PRODUCTION OF SULFUR BY COUNTY IN ALABAMA
METROPOLITAN
BIRMINGHAM
INTRASTATE
ALABAMA
AND
TOMBIGBEE
RIVERS
INTRASTATE
TENNESSEE RIVER VALLEY (ALABAMA)
CUMBERLAND MOUNTAINS (TENNESSEE)
INTERSTATE
PHENIX CITY (ALABAMA)
INTERSTATE
SOUTHEAST
ALABAMA
INTRASTATE
5,000 to 50,000 LT/YR
EAST
ALABAMA
INTRASTATE
COLUMBUS (GEORGIA)
AQCR 5
MOBILE (ALABiVvIA) - PENSACOLA - PA;IA;,IA CITY
(FLORIDA) - SOuTHERN MISSISSIPPI INTERSTATE
Eliliftifi
2-3
-------
PRODUCTION OF SULFUR BY COUNTY IN ARKANSAS
L i
500 to 5,000 LT/YR
5,000 to 50,000 LT/YR
TROPOUTAN
FORT SMITH
INTERSTATE
(ARKANSAS
AQCR 22
TYLER
INIZRSTATE
(ARKANSAS
LOU ISIAMIA-
OKLAHOMA-
TEXAS
MONROE-
EL DORADO
INTERSTATE
(ARKANSAS-
LOU ISIANNA
ILlillitil
2-4
-------
PRODUCTION OF SULFUR BY COUNTY IN FLORIDA
JACKSONvILLE -
BRUNSWICK
INTERSTATE
50,000 or more LT/YR
PANAMA CITY-
SOUTHERN
MISSISSIPPI AQCR 5
INTERSTATE
(ALABAMA-
FLORIDA)
CENTRAL
FLORIDA
WEST
FLORIDA
INTRASTATE
SOUTHWEST
FLORIDA
INTRASTATE
FLORIDA
INTRASTATE
2-5
-------
PRODUCTION OF SULFUR BY COUNTY IN MISSISSIPPI
MISSISSIPPI
DELTA
INTRASTATE
AQCR 5
MOBILE-
PENSACOLA
PANAMA CiTY-
SOUTHERN
MISSISSIPPI
INTERSTATE
(ALABAMA-
FLORIDA-
MISSISSIPPI)
500 to 5,000 LT/YR
5,000 to 50,000 LT/YR
50,000 or more LT/YR
METROPOLITAN
MEMPHIS
INTERSTATE
(ARKANSAS-
MISSISSIPPI-
TENNESSEE)
NORTHEAST
MISS ISSIPPI
INTRASTATE
Less than 500 LT/YR
2-6
-------
PRODUCTION OF SULFUR BY COUNTY IN NEW MEXICO
ALBUQUERQUE.
MID RID GRANDE
INTRASTATE
FOUR CORNERS
INTERSTATE
(ARIZONA-
COLORADO-
NEW MEXICO-
UTAH)
SOUTH VfESTERN
MOUNTAINS-
AUGUSTINE
PLAINS
INTRASTATE
ARIZONA-
NEW MEXICO
SOUTHERN
BORDER
INTERSTATE
UPPER
RIO GRANDE
VALLEY
INTRASTATE
NORTHEASTERN
PLAINS
INTRASTATE
AQCR 155
PECOS-PERMIAN
BASIN
INTRASTATE
EL PASO-
LAS CRUCES-
ALAMOGORDO
INTERSTATE
(NEW MEXICO-
TEXAS)
1ft1 5,000 to 50,000 LT/IK
50,000 or more LT/YR
2-7
-------
PRODUCTION OF SULFUR BY COUNTY IN TEXAS
AQCR 212
INTRASTATE
Less than 500 LT/YR
500 to 5,000 LT/YR
5,000 to 50,000 LT/YR
50,000 or more LT/YR
AQCR 211
AMARILLO-
LUBBOC’(
INTRASTATE
AQCR 210
ABILENE-
WICHITA FALLS
AQCR 215
METROPOLITAN
DALLAS-
FORT WORTH
AQCR 218
MIDLANC-
ODESSA-
SAN ANCELO
SHREVEPORT-
TEXARKAMA-
TYLER
INTERSTATE AQCI 22
(ARKANSAS-
LOWSIANA-
OKLAHOMA-
EL PASO
SOUTHERN
AL.A ’OCOROO
INTE: STATE
JEXAS
NEW MEXICO)
TEXAS
INTERSTATE
METROPOLITAN
SAN ANTONIO
INTRASTATE
AQCR 217
AQCR 216
BROWNSVILLE-
LAREDO
INTRS’ISTATL
AQCR 213
VICTORIA
INTRASTATE
11ll1uI
2-8
-------
Appendix 3
REPORT FORMS USED BY SEVERAL STATE PETROLEUM
REGULATORY AGENCIES
3-1
-------
orm A-i8
_‘- .t I
ALABAMA OIL AND GAS BOARD
CASOLINE OR OTHER EXTRACTION PLANT MONTHLY REPORT
- :o t of - - - ror the month of , 19 -
—
— (Main Office) (PI3nt) —
- Report all Volumes in M C F. at 14 4 lbs. plus 4 oz. pressure
_________________— INTAKE VOLUME
i al Gas From Oil Wells (Detail on Sheet 2)
-‘i1 Gas From Gas Wells (Detail on Sheet 2)
.al Gas from Other Sources (Detail on Sheet 2)
TOTAL
DISPOSITION OF RESIDUE
y, ’
:ied for Lease Fuel
.r Other Disposition (Detail Below)
- - -‘icd to Earth
-! age
OTAL
MCF
Detail of Sale or Other Disposition of Residue
NAME OF PURCHASER OR USER ADDRESS USED FOR
M C F
TOTAL
- Plant Production,_Receipts, Deliveries and Stock, in Barrels of 42 U. S. Gallons
PRODUCE - OPi PING STOCK RECEIPTS PRODUCTION DELIVERIES CLOSING STOCK
‘ i OiI
. flSd .C
)‘re
ane
‘ ;osene
‘ AL
-a ks
- - AFFIDAVIT
OF.
- TYOF
efore me, the undersigned authority, on this day personally appeared
i. wn to me to be the person whose name is subscribei to this report, who after being by me duly sworn on
or affirmation states that he is authorized to make and execute this report, that this report, including
:.et 2, Is a true and correct reflection of the record of the operations reported herein, and that no pertinent
• ‘er inquired about in this report has been onitted therefrom
Name of Operator
‘:‘orn to and subscribed before me this
- - 19 (Signature) (Titie)
Slotary Public In and for
(Follow instructions on reverse side)
3-2
-------
1N LZtU .,&iIJL
The addresses, as required on this report, shall be clear and definite as
to street number, city and state.
A report on this form, including sheet 2, shall be made by each operator
of a gasoline plant, cycling plant, or any other plant, at which gasoline,
butane, propane, condensate, kerosene, oil or other liquid products are ex-
tracted from natural gas.
This report shall be filed on or before the 25th day of each calendar
month and shall be complete as to data covering the calendar month next
preceding the date of filing. An executed copy shall be filed with the Ala-
bama Oil and Gas Board.
NOTE: “Deliveries”—show under “REMARKS” the name of the Trans-
porter and the quantity delivered to each, except deliveries to trucks may
be reported in Total only.
On Sheet 2 of this form, group and report by lease the volumes of “Gas
from Oil Wells,” and the total thereof; group and report by well the volume
of “Gas from Gas Wells” and the total thereof; report by each source the
volume of “Gas From Other Sources” and the Total thereof; and report the
Total Intake Volume from All Sources.
Make a separate report for each plant.
If any space does not apply, fill in the word “none”.
Please use the typewriter if possible.
3-3
-------
Form A-18
Sheet 2
ALABAMA OIL AND GAS BOARD
GASOLINE OR OTHER EXTRACTION PLANT MONTHLY REPORT
Report of.
for the month of
Report all Volumes in M. C. F. at 14.4 lbs. plus 4 oz. pressure
Detail of Intake Volume
‘AME OF PRODUCER
Lease Name
Location
County
Kind
of Well
Well
No.
Allowable
M. C F
Take
M. C. r
TOTAL
3-4
-------
AOOC.7.(64)
Arkansas Oil and Gas Commission
EL DORADO, ARKANSAS
MONTHLY GAS REPORT
wrn.
Report of For the Month of • 19_
(Nwcr of ln iIaI Take,)
Gum 0111cc) (Local cc Ficid Olfica)
Report All Volumes in M. C. F. at 14.4 Lbs. Plus 4 Oz. Pressure
ACQUISITION
Name of Producci
Lease Name
%Vell
No.
Allowable
M C. F.
Production
M C F
Over/Under
P .1 C. F.
Accumulaizd
Over/Under MC. F.
TOTAL
DISPOSITION
Used For
Name of Company
Addrc.
Volume
Fuel System
Lease Use
Transmlsiion System
Other Dlaposltion (Detail)
TOTAL
Remarks
(If ipam berewab n inadequate—please write letter and attach hereto)
CERTIFICATE
I declare under the penalties of perjury that this report baa been examined by me and to the beat of my
knowledge is true, correct and complete.
3-5
-------
INSTRUCTIONS
The addresses, as required on this report, shall be clear and definite as
to street number, city and state.
Report on this form all gas taken into a fuel system, transmission sys-
tem, or any other system, except gas taken into a gasoline, cycling, or
other extraction plant gathering system which is required to be reported
on Gasoline or Other Extraction Plant Monthly Report, Form AOGC 8-(56).
In case the gas from any well is taken by any person other than the pro-
ducer, then such person taking the gas shall make and file said report.
Where such gas is taken from an oil or gas well by the producer, then the
producer shall make and file said report.
This report shall be filed on or before the 15th day of each calendar
month and shall be complete as to data covering the calendar month next
preceding the date of filing. An executed copy shall be filed with the Ar-
kansas Oil and Gas Commission, El Dorado, Arkansas.
Report the volume of gas taken from each gas well separately. Report
the volume of gas taken from oil wells by leases. All volumes shall be
reported in M. C. F. at 14.4 Lbs. plus 4 Oz. pressure.
3-6
-------
AOGC—8—(56)
ARKANSAS OIL AND GAS COMMISSION Sheet
EL DORADO. ARKANSAS
Gasoline or Other Extraction Plant Monthly Report
Report of___________________________________________ ._For the Month of , 19_
r uureba—_
—
(Ma iriOfficc)
(Plant) —
-
-
Report All Volumes in M. C. F. at 14.4 Lbs. Plus 4 Oz Pressure
Intake Volume
TOTAL GAS FROM OIL WELLS (Detail on Sheet 2)
TOTAL GAS FROM GAS WELLS (Detail on Sheet 2)
TOTAL GAS FROM OTHER SOURCES (Detail on Sheet 2)
MCF
TOTAL
Disposition of Residue
PLANT FUEL
RETURNED FOR LEASE FUEL.
SOLD OR OTHER DISPOSITION (Detail Below)
RETURNED TO EARTIr
VENTED
SI(RINKAGE
M C F -
TOTAL
Detail of Sale or Other Disposition of Residue
‘
Name of Purchaser or User
Address
Used For
M C F
TOTAL
Plant Production,
Receipts, Deliveries and Stock, in Barrels of 42 U S Gallons
Product Opening Stock Receipts Production Deliveries Closing Stock
CRUDE OIL
CONDENSATE
GASOLINE
BUTANE
PROPANE
KEROSENE
OTHER
TOTAL ______ ______ ______ ___________
Remarks — - —.— - —
CE RTIF IC ATE
I declare under the penalties of perjury that this repoit. has been examined by me and to the best of my knowl-
edge is true, correct and complete
3-7 _______________________________________
-------
INSTRUCTIONS
The addresses, as required on this report, shall be clear and definite as
to street number, city and state.
A report on this form, including Sheet 2, shall be made by each operator
of a Gasoline Plant, Cycling Plant, or any other Plant, at which Gasoline,
Butane, Propane, Condensate, Kerosene, Oil or Other Liquid Products are
extracted from Natural Gas.
This report shall be filed on or before the 15th day of each calendar
month and shall be complete as to data covering the calendar month next
preceding the date of filing. An executed copy shall be filed with the Ar-
kansas Oil and Gas Commission.
NOTE: “DELIVERIES”—show under “REMARKS” the name of the
Transporter and the quantity delivered to each, except deliveries to trucks
may be repoited in Total only.
On Sheet 2 of this form, group and report by lease the volumes of “Gas
From Oil Wells,” and the total thereof; group and report by well the volume
of “Gas From Gas Wells” and the total thereof; report by each source the
volume of “Gas From Other Sources” and the total thereof; and report the
Total Intake Volume From All Sources.
Make a separate report for each plant.
If any space does not apply, fill in the word “NONE.”
Please use typewriter if possible.
3-8
-------
Department of Natural Resources
State of Florida
Monthly Producer’s Natural Gas Report
Form 8
Field
Report
of
(Name of Producer)
(Address of Main Office)
Month of
19_
(Address of Local or Field Office)
State of Florida
Affidavit
Report all Volumes in M. C. F. at 14.4 lbs plus 4 oz Pressure and 60°F.
Production
Zone--LeaseNarne
Well
No.
County
Location
Allowable
M.C.F.
Production
M.C.F.
Survey
Section
— Grand Total
Dispositions
Utilization
M. C. F.
Producer’s Field Operations
Reserved by Lessors
Vented to Atmosphere from Gas Wells
Vented to Atmosphere from Oil Wells________________________________
Others (denote)
Sales or Deliveries
Name of Company Address
.
Total
County of
3-9
-------
GASOLINE PLANT OR PRESSURE MAINTENANCE PLANT MONTHLY REPORT
Type of plant
!eI system & lease use
lilt
pressuring & pressure maintenance
irutmission line
rtC
6 Other processing plant, or carbon black plants
Openg stock
I’ aceipt .
- TON Ill—DISPOSITION OF RESIDUE GAS (MC? MONTHLT
;t ction loss 2 AcId gas 3 Plant fuel 4 Lease fuel 6 Ga. lift 6 Repreeaurtng &
pre ,. msint
‘in black p1 6 Other proc 91 9 Tran.miss. line 10 Vented 11 Total
X’TION IV—PLANT PRODUCTION. RECEIPTS. DELIVERIES. FLARE AND STOCK IN 42-GAL EELS
‘rduct
nil
t.
] —
q
;‘
) fltn
?
Production
Deliveries
Flare
CIo.g stock
3erator Address
1 Name Field County —
Av. Intake capacity
MC ?
Av. intake pressure
PSIA
Ày tested gpm Recovered gpm
ION I—INTAKE VOLUMES (MC ? MONTHLY)
Ga. well,
Ca.lnghead
Total
of wells produced
q into gathering system
mllvertes from gathering .ystem. (Total of section II)
1 ng system to plant for processing
intake—from plant meters
or gain—Dill between lines 4 & 6
from other .ources (Detail in Remarks)
I
• -y and storage vapors
m . to plant for processing
• -‘ i Il—DISPOSITION OF UNPROCESSED GAS FROM GATHERING SYSTEM (MCF MONTELE i
0aswell,
Tot&
on Reverse Side
MISSISSIPPI STATE OIL AND GAS BOARD
Gasoline Plant or Pressure Maintenance Report
FORM Ii 0CC 04
Autl.orlssd by Ord.r No. lie-se tffsdiv. No,.mb.r I l 38
3-10
-------
Company
t ie.
Proce S Sed
I Reaeon for venting unprocessed gas
2 Reason for venting residue gas
3
SECTION VT—DETAIL OF MONTHLY OAR INTAKE CURE POEM ENTITLED “DETAIL. OF I .ITA1CE VOLUME” WHEN NECESSARY)
Well owner
Name of laee
Kind of gas
Well number
Take M C. P
NOTE AU volumes must be corrected to a prex ’si.re f —pela and to a temperature of _______________________________________ F.
Executed this lbs day of • 19
State of___________________________________ —
Signature of Afflant
County oL..._..
Before me, the undersigned authority, on thIs day personally sppeare 4 known to me 10
be the person whose name is subscribed to th, above mu Ir, nent. who betng by me dully sworn on oath stateS, that be Ia duly autbortiod to
make the above report and that he has knowledge of I he i.. . ta elated therein, and that said report Is true and Correct
Subscribed and eworn to before me this __.._day of 19
SEAL
My commission expires — Notary Public ta and for
3-11
-------
NFW MEXICO OIL CONSERVATION COMMISSION
5WlIV FORM c us (Rrv S7 1 721
BOX 2O SANTA FE. NEW MEXICO bUBMIT URl INALVOO CSANTAFE
ONE COPY TO 0CC DUST OFFICE
OPERA TOR S MON TIlL V R EPOR 1 ONE COPY TO TRANSPORTER
Ciim ny or
Ope iio )_._._______ _____________ _________ (Add eNi_ _.._._______ _FORMONTII _____.___Puga_ of_._
1 — — ON OF GAS DISPOSITION OF OIL
POOL NAME (Und thnr ) I tOTAL LIOUIOS PRODUCED 0 DISPOSITI
LEASE NAME I I MONTHLY ACTUAL 8ANR LS PRODUCED
0 —- ____
GAS --—i- • -& ;—
0 HAND TO 0 TRANS HAND
I -i I OIL I BARRELS OF WATER UCP ? V (NTEO USED ON
ED L(A 3E SOLD PURCH OrHER BEG OF TRANS OTHER 0 PORTER I
WLLL NO UNIT SEC PAP RHO IALLOWABLEIPRODUCED PRODUC
USRSE NAME — Ind e Stub Lo Ls e Nu i Fed Le. N rnber
STA1US CODE : t ER GAS DISPOSITION CODE OTHER OIL DISPOSITION CODE I HEREBY CERTIFY THAT THE INFORMATION GIVEN IS TRUE AND
F FLOWING X USED OFF LEASE (DESTINATION MUST BE SHOWN ON FORM Cliii C CIRCULATING Oil. COMPLETE TO THE BEST OF MY KNOWLEDGE
P PUMPING 0 USED FOR DRULLINGI I LOST
0 GAS LIFT G GAS LIFT S SEDIMENTATION (BS&W)
S SHUT IN L LOST (MCF ESTIMATED) E EXPLANATION ATTACHED _________________________________ — —
1 TEMP ABANDONED E EXPLANATION ATTACHED (SIGNATURE) (DATE)
I INJECTION R REPRESEURING OR PRESSURE MAINTENANCE
(POSITION)
-------
NEW MEXICO OIL CONSERVATION COMMISSION Fbrm C-Ill Sheet No.1
GAS PURCHASERS MONTHLY REPORT Supersedes old Form C-ill &C.I14
Eflective I - I - 65
Operator and Address
Plant Month
REPORT ALL VOL
UMES OF GAS IN MCF AT 15.025 PSIA AND 60°F
SECTION 1 — Volume of Gas Taken
VOLUME — MCF
Tot il Gas From Oil Wells (l)etail on Sheet 2)
Total Gas From Gas Wells (l)etail on Sheet 2)
‘fot tl Gas From Other Sources (Detail on Sheet 2)
TOTA L TA KES
Gasoline or Qiher Extraction Pla
nt Only:
l)cduct Volume ‘fhat By-Passed
Plant and Was Not Processed
TO’l’AL PLANT INPUT
SECTION II — Disposition
r rvi
UNPROCESSEDGAS
VOLUME MCF
ITEM
PI. ANT RESIDUE
VOLUME MCF
Lease Use
—
Detail Below
a.
h.
(; l)r.llingp tton
I’
j . . . ..
J ....
(‘.as Lift
1 ad System
‘‘
c.
.j.._
.J ....
llcturncd to Lease l”or l ”uel
.
EleLurnc(l to Eni tit
°
——
Sold or Other Disposition
..&. .
— —
Plant l’ue I
n ted
Shrinkage
1’ota Is
GRANI) i’OTAL — ALL DISPOSITION
(Show cach in
IS [ ’CT iUN Ill — Detail of Disposition (Attach addigi
ITEM I NAME AND ADDRESS OF PURCH
-- -r
dividual disposition of items above.)
onal sheets if necessary)
ASER OR USER
-______________________
USED FOR
VOLUME — MCF
SECTION IV — Plant Production. Receipts, Deity
eries , and Stock in Barrels of 42 U.S. Gallons.
PRODUCT
OPENING STOCK
RECEIPTS
PRODUCTION
DELIVERIES
CLOSING STOCK
Oil
Condensate
Gasoline
Butane
Propane
Kerosene
Other
‘l’OTA L
Remarks:
Title _________________________________ Date
3-13
-------
C I SSION E RS
EN RAMSEY
Cho irm
‘N TUNNELL
jIM C LANODON
OSBORNE. Secret.ry
ARTHUR H BARDECK
Chief Engineer
MEMORANDUM TO:
SUBJECT:
All Plant Operators
Reporting Facilities on Form GP-l, Monthly Report
for Gas Processing Plants
Form GP-l, revised October, 1968, is now available at all District
Offices. This form is required to be used by plant operators in
filing reports for January, 1969, which are due in the District
Office on or before February 25, 1969.
Please note that the new Form GP-l is designed to facilitate the
reporting of a whole plant system (including drips, scrubbers,
compressors, etc.) on one report at the option of the operator.
Attached are instructions and examples concerning the filing of
revised Form GP-.1. If further information is needed, please contact
the Railroad Commission of Texas, Oil & Gas Division, Production
and Proration Section, P. 0. Drawer EE, Austin, Texas, 78711.
RAILROAD COMMISSION 01’ TEXAS
OIL AND GAS DIVISION
AUSTIN. TEXAS
3-14
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Page 2
FORM GP-l
ICNTItLY REPORT FOR GAS PROCESSING PLANTS
AND/OR OTHER FACILITIES REPORTED ON GP-i
before January 15, and July 15, of each year and are to show
the connectiocte as of January 1 • end July 1, respectively.
The list should he arranged by field, operator, lease, REC
lease number, and each wall number.
GEMERAL INSTRUCTIONS
Th u report shall be filed in four 4) duplicate originala with
the District Director of the Railroad Coiseion of Teaaa f or
the Diatrict in which the plant is located aa coon after the
first of the month as poaeible for the preceding month, and
never later than the twenty-fifth of the month.
Form GP-l ia required for all planta processing netural gaa.
Processing includes recovering liquid hydrocarbons and/or treat-
ing gas for 1425 and CO2. All gas volumes rust be reported at a
ease Pressure of 14.65 pounds per square inch absolute and a
Base Temperature of 60 degrees Fahrenheit. All liquid quantities
shown on this report shall be in barrels of 42 U. 5. Gallons
based on actual, physical gauges computed f roe. 100% U. S. Tent
Tables or other method of measurement approved by the Commission
and corrected from the temperature at the ties of measurement to
a standard temperature of 60 degrees Fahrenheit.
Do not use fractions of thousands of cubic feet of gas or
fractions of barrels of liquid on this report.
CERTIFICATE OF COSifLIAZICE
In accordance with Ststewide Rule SI, no gasoline plant shell be
operated without a Certificate of Compliance approved by the
Coem.isslon which ehell be in effect for a tiselva-eceth period,
and is to be renewed each year.
In accordance with Statewide Rule 62, no cycling plant shall be
operated without a Certificate of Compliance. Application for
Certificate of Compliance shall be filed each year for renewal,
August 1. After Statement of Inspection’ on Application has been
approved at the District Office, a Certificate of Compliance for
Cycling will be issued from the Austin Office.
A Certificate of Compliance for Cycling (where gas is in)ectad
into a reservoir for credit to gas wells) is sufficient compliance
for all products that may be recovered at the plant.
The Certificete of Compliance for Gasoline Plants and Application
for Certificate of Compliance for Cycling Plants, are to be filed
in triplicate with the District Director of The Railroad Commission
in which District the plant is locatad.
No Certificate of Compliance is required for other type plants
(Drips, Scrubbers, Separatore, Dehydrators, etc.) when only
condensate or unprocessed liquid hydrocarbons are recovered.
SEMI - ANNUAL CAS INCHEAD GAS CONNECTIONS
A esmi-annual list of casinghead gas connections is required from
all plant operstors that gather casinghead gee from oil wells.
These flats are to be filed in duplicate with the District Director
of the Commission District in which the plant is located on or
Ths maximum Daily MC? that plant was constructed
to process.
SECTION I : INTAKE VOLUMES
mien filing a system report, this and all appropriate sections
should include 1 the wells sad volumes from all wells connected
to the whole system.
1. Number of Wells Producedi
Gee Wells - Total number of sweet, sour, non-associated
and/or associated gas wells produced.
Oil Welts - For the purpose of this report, a producing
oil well is one that is producing or has an
assigned allowable which may be transferred
and produced by another well or wells for
injection or efficiency purposes.
2. Gas Into Gathering System:
Instiel reporting of gaa production from wells connected to
plant for processing regsrdlese of the ownership and/or
operstion of the gathering system. The voli s shown as
Gas Into the Gathering System’ should be the volumes
measured et the well for gee well gas and on the lease for
caainghead gas, or these well and/or lease volumes adjusted
by a central point delivery meter volume.
YUan IUS’rItUtT loNS
HEADING
District Number - Railroad Commission District in which the
plant is located.
Serial Number — Assigned by District Director of District
in which the plant is located.
Plant Name - Name of plant being reported. Several
Facilities (Drips, Scrubbera, Compressors,
Central Separation Facilities, etc.) may be
reported on one Form GP—l if the plants
serve a main system where gas is delivered
for final processing end disposition. (See
attached examples,)
System Name - Name of system that plant serves, if any.
Fields - Source of Gas Supply
County - L ocation of Pleat
Deity Average
Intake Capacity
of Plant -
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Page 3
Page 4
SECTION II : DISPOSITION OF UNP SSED GAS PI M GAT RING SYSTEM
Total disposition must balance and total must agre, with volume
reported on Line 3, Section 1.
Definition of dispositions applicable to this section shown in
Section III.
SECTION I II: DISPOSITION OP RESIDUE GAS
Extraction Loss
Loss in volume due to removal of liquid hydrocarbons. The ,oluaet-
nc equivalent must be reported for liquids recovered from any
type facility when gas volumes are reported. Do not include
any H2S or C02 leases in this disposition. Uae lines 2 and/
or 3.
Lease Fuel and Use
Gas used, sold, or given for field operations, laaae drilling
fuel, compreasor fuel, etc.
Gas Lift
Gas used, sold, or given for injection into oil wells to lift
oil.
Reprassuring & Pressure Maintenance
Gas used, sold, or given to maintein or build up reservoir
pressure through an injection well in an oil reservoir, Oil
wells receive credit for gas injected and reported as iia issur—
I j ’ nd Pressure Maintenance.’
Cycling
Normally gas returned to gas cycling piojects (gas reservoir
Of gas cap of associated reservoir) after extraction of
hydrocarbon liquids. Gas wells receive credit for gas injected
and reported as ‘Cycled’.
Underground Storage
Gee injected into underground storage.
Carbon Black Plant
Gas delivered to a gas Carbon Black Plant.
Other Processing Plants
Gas that is delivered to another gas proceesiag plant or facility
being reported on Form GP-l. Gas delivered to Industrial Plants
(not reported on Form GP-l) should be reported to Transmission
Line.
Tranamission Line
Gas used for industrial purposes, irrigation fuel, refinery fuel.
etc.
Mater Difference
Difference that occurs within the planta.
Total
Total disposition must balance and agree with total reported
on Line 12, Section I.
SECTION IV: SULFUR AND CO 2 RECOVERY
Report in Long Tons and/or Standard Berrels.
You are reminded to complete all sections of Form GP—l for treat-
ing plants whether or not liquid hydrocarbons are recovered. This
information is needed for statistical purposes,
C#3
0 )
Do not include any gas volume into the gathering system
that has been previously reported on Form GP-l for another
facility. Gas received from other facilities is correctly
reported on Line B as ‘Gas From Other Processing Plants. -
3. Deliveries Prom Gathering System:
Any delivery or use of gas that is not processed for
recovery of liquid hydrocarbons.
4. Gathering System to Plant for Processing:
Difference between lines 2 and 3.
5. Plant Intake — From Plant Meters:
Plant intake meter voiwass of gas produced by walls connected
to gathering system and reported in lines above. Gas
volumes reported on Lines 7 through 11 should not be included.
Complete Line 5 whether a Loss or Gain from plant is shown.
6. Loss or Gain:
Difference between Lines 4 and 5
7. Refinery and Storage Vapors:
B. Gas from Other Processing Plants:
Gas that is received for further processing from another
processing plant or facility being reported on Form GP-l.
Show name of plant that gas is received from on this line
and the amount of gas in Total Column.
9. Gas From Main Transmission Line:
10. Gas Withdrawn From Storege:
11. Gas Imported From Other States:
Report all gas imported from other States that is received
into plant for processing or further disposition. Show
name of State on this line and the amount of gas in the
Total Column.
12. Net Gas to Plant for Processing:
Total of Lines 5 and Lines 7 through 11.
-------
Page 5
Page 6
SECTION Vt PLAIFr LIOUZO HYDI CARBON PRODUCTION
Report all liquid production in this Section and Section
VII. The Total (Line 9) should reflect total liquid recovery
of the system, and production reported as “Condensate Prom
Gas Well Gas and ‘Drip and/or Scrubber Oil From Casinghead Gas
must be included. Total on Line 9, Section V, must balance
and agree with total reported on Line 5, Section VU. Consider
allocated scrubber oil a detail sub-total of the amount of
acrubber oil ahown on the line above.
Condensate Prom Gaa Well Gas
Drip and/or condensate production fro. gas well gas when Forci
GP—l is used for reporting liquids. Do not report any conden-
sate production on Form P—2 that ia reported on Form GP-l.
Drip and/or Scrubber Oil Prom Casinahead Gas
Scrubber oil recovered in excess of 0.75 barrel per well per
— conth (Statewide Rule 56) ii not allowable free and must be
allocated beck to the oil leases where produced and reported aa
production by the operator on Form P—I. Disposition of acrubber
oil allocated back to leases may be made in the Other Column”
on Form P—I with 5” aa the code. Explanation of 5 (Lost in
Casieghead Gas System) should be shown on Form. Furnish this
office with an original and one copy of your allocation of
excess scrubber oil. List field, operator, lease name, RRC
lease number, and number of barrels allocated.
“Drip and/or Scrubber Oil produced in excess of Statewide Rule
56 and allocated back to leases for operator to report on Form
P-I’ is only a sub-total or detail mnount and the liquids shown
as such should be included under ”Drip and/or Scrubber Oil From
Castnghsad Gas” in the line shove.
Plant Condensate
Report in this category only under conditions approved by the
Coimaiasion.
‘Plant Condensate” andCondsnsate From Gas Well Gasmay be combined
as production and deliveries in Section VII.
Hydrocarbon Mixtures
For statistical purposes, report the components of any Hydrocarbon
orLPG mixes in Section V and Section VII. You may state that
product is delivered as a mix in Section VIII.
SECTION VII AND SECTION VIII: LIQUID OPERATIONS (RECEIPTS,
PRODUCTION, AND DELIVERIES )
Report actual product received in Section VIII. If product
received is fractioneted, the components may be ttported on
Line 4, Section VII, and included in Deliverie. ’.
Do not include any products received in the production sections
(Section V and Soction VII). Production should b only those
products extracted from natural gas taken into the plant for
proceesing.
Do not include LPG in underground storage in your plant opening
and closing inventoriec. You may report the initial production
of product and include tho amount to storaga in ‘ eltverles ”.
My further Storage Tabulation (Injection, withdrawala, and
accumulated balances should be reported o.i a supplemental sheet.
SECTION II ( REPORT OF AS INJECTED - RFPRESSU NG. PRESSURE
MAI! TENANCE. CYCLI 1G AND UNDERt.be)LJl.D STORAGE
Report volume of gas returned to r.servrirs for each injection
well.
If core space is needed, use Form GP—3.
SECTION X: DETAIL OF DELIVERY OF GAS-EXCEPT FUEL SYSTEM AND
LEASE USE
Use the proper column for reporting delivery of gas. Unprocessed
Gas column should be used for dispostion reported in Section II
and Residue Can” coiwun for disposition reported in Section III.
Complete section even though no delivery or sale of trar.s’ .Ission
line gas is made.
SECTION XI: REMARES
State the reason for venting unprocessed and residue gas.
Whenever a report is final, show Finsl Report”. Do not state
report is final if there is a closing inventory of stock reported
in Section VII. Form CP-l must be continued until stock has
been disposed of.
Also, note any change in the plant operating name and show the
effective date of change.
SECTION VI , DETAIL OP DRIP OR SCRUBBER RE VERY
This section is to be used to show the detailed scrubber recovery
when filing a ‘System” report.
The name of drip or scrubber, wells, and barrels of liquid
recovered from these facilities must be reported in this section.
and the wells and liquid production will also be included in
Sections I and V above. See examples for proper reporting of
these facilities.
-------
RAILROAD COMMISSION OF TEXAS
OIL AND GAS DIVISION 3—150 1
SERIAL NO. -
FOR THE MONTH OF January — 69
ADpRESS P.O. Box 134 —Austin,Texas 78720
SYSTEM NAME_Blanche
COUNTY Orange
‘ . F PLANT Gasoline DAILY AVERAGE INTAKE CAPACITY OF PLANT 170,000
IF-.TAKEPRESSURE 800 PSIA AVG TESTEDGP 1.420 RECOVEREDGPM 1.649
c . OPT ALL GAS VOLUMES IN MCF AT 1465 PS1A PRESSURE AND 6O FAHRENHEIT IN ACCORDANCE WITH GAS MEASUREMENT LAW
— intake Volume, (MCF monthly)
C OFWELLSPRODUCED
GAb WELLOAS
CASINGHEAO
TOTAL
80
750
830
NTOGATHERINGSYSTEM
.JERIES FROM GATHERING SYSTEM
2 ’ 5 oQL° 2 _
1,201,419
3,701,444
150 1725
30 , 900
181,625
1 IlING bYSTEM TO PLANT FOR PROCESSING —
2 ,
1,T70, 519
3 , 519, 19
TlNTAKE— ROMPLANTMETCRS
2,345,409
1,172,043
3,517,452
ORDAIN - GIFF BETWEENLINES4 65
3,891
1,524
2,367
ERY AND STORACL VAPORS
FROMOTHER PROCESSING PLANTS J & J Gas Company — Plant No. 3
- FROMMAINTRANSMISSIONLINE M& W Pipeline Company -___________
GAS WITHDRAWN FROM STORAGE
A5 IMPORTEO FROM OTHER STATES Loui Tana
204,671
300,960
10,009
GASTO PLANT FOR PROCESSING - — —
4,033,092
II: Deposition of Unprocessed Go. from Gathering Spstem (MCF monthly)
GAS WFLI. GAS
CASINGHEAO
TOTAL
L SYSTEM AND LEASE USE
LIFT
3 REPRESStIRING A PRFSSURE MAINTENANCE
4 YCLED
..,. ,ERGROUND STORAGE
..OTHER PROCESSING PLANTS
LARSON BLACK PLANTS
‘ N5MISSION LINE
TED
1,284
- 150.725
30,900
181,625
. V Plant Liquid Hydrocarbon Production (barrel, monthly)
- DRIP AND. OR SCRUBBER OI_ FROM CASINGHEAO GAS
J, ‘ ‘cr Scrubber Oil produced in excess of Statewide Rule 56 and aI!ocated back to leases for operator to report on Form p-i
1,044 14 PROPANE 31,0001, ETHANE
L’ T CONDENSATE
50,550 5 BUTANE PROPANE MIX Is
L OLINE —
25,133 IS ISO-BUTANE — TOTAL
VANE
- Vii Detail of Drip or Scrubber R.coeery (Production riclud.d abase)
- OF- DRIP OR SCRUBBER
— ‘ eson Compressor Station
4 arimore Compressor Plant
h’rubber No. 1
Scrubber No. 2
NO OF GAS WELLS
10
0
12
10
NO OF OIL WELLS
415
21
4
0
BARRELS
j
110
36
60
t-,chment If Necoeeory) TOTAL
REPORT FOR
• PLANTS
I..T NO.
3
I
Total Production Comaanv
Blanche
lAME _________ ——
ABC & Rri -K
FORM OP-I
Rev. 10/68
20,450
10,465
22.040
12,563
2 1 ,4i4
15,011
23, U4
97,770
,)PI Ill D..pa.ition of Residue Gas (MCF monthly)
.j I lii.
173,539
ii. ,U45
9 i, 1 l0
- (TRACTION LOSS
LOSS
C 5S
FUEL
I ‘ UEL A USE
Sulfur and C02 Recosery
150 ,193
28,928
GASLIFT 24,455
7 PEPRESS S PRESS MAINT ______—
8 CYCLED
S UFIDERGROUF.D STORAGE _________-
CAPSC) .J BLACK PLANTS
ION OF SULFUR FROM PROCESSING NATURAL GAS _ 100 (Lonq ) TONS
NSATE FROM GAS WELL .AS
II OTHER PROCESS PLANT’
IZ TRANSMISSION 637,461
13 VENTED ___________
774 91
14 METER DIFFERENCE ________________
I TOTAL 4,0 3,09 ___
CO
00 L5
TO F1S
530
3-18
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2
SECTION VII: Barrels -ISO—But
OPENINGBALANCE
Condensate
Drip .tnd i.e
Scrubber Oil
Gasoline
Butane
Propane
Ethane
Other
Total
201
15
10,019
6,045
3,041
2,055
0
21,376
2 FROZEN STOCK
0
0
- 0
0
0__
0
0
3 T0rAL OPENING STOCK
201
15
10,019
j,045_-
2,055_
0
21,376
4 RECEIVED
52
0
3,015
5,038
3,049
1,151
0
12,305
a eac.nuce
6 DELIVERED
1239
1442
335
330 -
50,550
56,989
25,133
31,952
38,000
38,054
41,258
39,767
2,345
L 45
158,860
170,879
7L 0 5:
0
0
0
0
0
0
0
0
a TO1.LCLOSINGSTOCI(
50
20
6,595_
&.264
.A,036
4.697
0
21.662
S FROZEN STOCK
0
0_
— 0
0
0
- 0
0
0
10 CLOSING DALANCE 50 206,595
SECTION VIII L.quid Operation, Sta emenP
RECEIPTS I
Receivet front Commoditi. ilarrels W, etis’eci
E & S Gas Co. Hydrocarbon
Mix 12,305
6 036
•_4,697
- 0_
21,662
DELIVERIES —
Delisered to
Commodity
Barrels Delivered
L & D Oil Co.
DXL Oil Company
do
T & P Oil Company
do
do Pro
Ethane
Condensate
Scrubber oi
Gasoline
Butane
& Iso But M
39,767
1,442
330
56,989
31,952
x40,399
TOTALS
170,879
SECTION IX Repo.I of Ga. Iniected — Repres .unng. Pressuic Maintenance. Cycling, and Underground Slorag.
Field and Reservoir Well Owner — L°. .se
Well
No
Injection
Pressure
MCF
Monthly
Blanche IA—l i
—— — - —--
Total Production Co.
.———-- ——---
Ward “A”
——
1
2600
37,111
xxxxxxx
SECTION X Dstu,I of Deheery ol Gas — Eacepi Fuel System and Lasso Use (MCF moi ,ihly)
— Delivered to Whom — — Us e or flicpi . s it :.tn kinp;ocessed Gas(Sec.
J & .1 Gas Company(Day Planit) Processing 97,770
B & H Transmission Co. Transmission Line
Farmers’ Co-OP Irrigation
H) Residue Gas (See ill)
3,623,363
14,098
SECTION X I Remark,
I Pf ’ ON FOR VENTING UNPROCESSED GAS
Compressor Down
Date Slqnoiur.
INSTRUCTION S
I This report shell be tiled iii four (4) iiuplici .ii irigilis’. with il’ Di iinci Dire—or of the RaI.ro. id Commission of Tees, for the District In which the Plunt
is Iocaied as soon slier the l.mst of the Month as 1.0.5101. br the iir .c.ding Moi , ’, iiiiit moser Isier fln the Twenty-Fifth of the month
2 This report is required of all Plants pro eesing Naiursi (.O ’i All Di i Volumes must he repori. .t at ii I3ose Pressure 01 14 b 5 pounds per square inch
absolute end a Disc Tempcrnture of hO dcgri.’rs Fehrenhctt All liquid quantities shown on mis report shell be In barrels of 42 U S Gallons based on actual
physical gauges computed from 100% U S Tank Tables rim .,ther method of menauremeni .pprooed by the Commission end corrected from the temperature
at the time of measurement to a siandord iemperature of 50 decrees Fshrenimsit Do not use fraction, of thousand, of cubic feet of •ea, or fractioss of
b.ftels of liquid on t im ,. report
3 Detailed Instruction, a silabIr from Rsilrood Co misiuoi cif Tees, Oil & Gs Disisi n. Produc.tiar & Proration Section. P 0 Drswer EE, Austin.
Tess. 78711 3—19
2 RFA5ON FOR VENTING RESIDUE GAS
3 —
CERTIFICATE I, the undeisigned. state that I air — - Plant Superintendent . (TITLE) of
Total !roduction_ca___ (COMPANY AND PLANT)
arid that I am authorized by said company to make this report, and that this port was prepsre utidi r my supervision and direction and that the facts
stated therein are true, correct and complete to thc bust ol dg
2—20—69 T.P. Vjtek — 1 512—475—3803
Area Codu und Teiephoriu Number
-------
SERIAL NO.
FOR THE MONTH OF January 69
ADDRESS P.O.Box 1340—Austin, Texas 78720
SYSTEMNAME2 & P Oil Co. Plant #1
COUNTY Brazoria
JGNTHLY REPORT FOR
, A! PROCESSING PLANTS
STRICT NO.
3
T
RAILROAD COMMISSION OF TEXAS
OIL AND GAS DIVISION
vaj.
TotaL P OQUCt1Ofl Co.
vai.
3—100
FORM GP-1
Rev. 10/68
1- I LuS _____________________________________________________________________________________ ___________________________________
L OF PLANT Compressor Station DAILY AVERAGE INTAKE CAPACITY OF PLANT
.S.. NTAKC PRESSURE ______________ P S I A AVG TESTED OPM RECOVERED GPM __________________________
EPORT ALL GAS VOLUMES IN MCF AT 1465 PSIA PRESSURE AND 60 FAHRENHEIT_IN_ACCORDANCE WITH GAS MEASUREMENT LAW
S;cilon I Intake Voium . (MCF monthly)
GAS WELL GAS
CASINGHEAO
TOTAL
P .IO.OFWELLSPRODUCED
10
130
140
-—
‘5INTOGATHERINGSYSTEM
• .LIVERIES FROM GATHERING SYSTEM
.THERING SYSTI M TO PLANT FOR PROCESSING —- —
.ANTINTAKE-FROMPLANTMETERS
—
325,096
500,045
825,141
5,230
25,093
30, 323
319,866
474,952
794, 818
319,866
474,952
794,818
S OR GAIN - 01FF. DETWEEN LINES 4 5 5
FINERY AND STORAGE VAPORS
AS FROM OTHER PROCESSING PLANTS
-
GAS FROM MAIN TRANSMISSION LINE
‘0 GAS WITHDRAWN FROM STORAGE
I GAS IMPORTED FROM OTHER STATES
-. . T GAS TO PLANT FOR PROCESSING
794 818
.. ,3N II. Du.po..tlon of Unproce...d Ga. from Gathering System (MCF monthly)
GAS WELL GAS
CASINGHEAO
TOTAL
IUELSYSTEMANDLEASEUSE
5,230
5,090
10,320
.ASLIFT
4,950
4,950
3 REPRESSURING & PRESSURE MAINTENANC.C
CYCLED
UNOERGROUNO STORAGE
6 OTHERPROCESSINGPLANTS
15,053
15,053
7 CARBON BLACK PLANTS
. ANSMISSION LINE
t ‘NTED
5,230 25,093 30,323
CTI0N IlI DispositIon of Residue Ga. (MCF monthly)____________________________________________
I YTRACTION LOSS 282 — S GAS LIFT II OTHER PROCESS PLANT ’ 5 ° , 666
LOSS 7 REPRESS & PRESS MAINT 12 TRANSMIS5ION LINE
LOSS —______________ B CYCLED I) VENTED
22,090 (—) 547
ANT FUEL 0 UNOI RGRUUND STORAGE 14 METER DIFFERENCE
55,434 I94,81t
• ASE FUEL B USE CARBON BLACK PLANTS. .___ 15 TOTAL ——
“4 lV Sulfur and C02 Recovery
JCTION OF SULFUR FROM PROCESSING NATURAL GAS TONS CO 2
• ‘GM V Plant LiquId Hydrocarbon Production (barrel, monthly)
;NL, 1.4SATE FROM GAS WELL GAS 110 DRIP ANDIOR SCRUBBER OIL FROM CASINGHEAO GAS 165 —
Orip and/or Scrubber Oil produced in excess of Statewide Rule 56 and allocated back to leases for operator to relxrt on Form P I 67
PLANT CONDENSATE 4 PROPANE 7 ETHANE —_____________
GASOLINE 5 BUTANE- PROPANE MIX B
auTANE 6 ISO.BUTANE 9 TOTAL
iN Vit Detail of Drip or Scrubber Ricov.ry (Produclion includ.d above)
- lAME OF DRIP OR SCRUBBER
NO. OF GAS WELLS
NO. OF OIL WELLS
BARRELS
• Iachmonl II Necessar TOTAL
3-20
-------
SECTION VII: Barrels
I OPENING BALANCE
Condensate
Drip and/or
SCrUbber Oil
Gasoline
Butane
Propane
Ethane
.
Other
Total
100
50
150
2 FROZEN STOCK
0
0
0
3 TOTAL OPENING STOCK
100
50
150
4 RECEIVED
0
0
0
3 PRODUCED
6 DELIVERED —
110
165
275
150
140
.________
290
7 LOSS
0__
0
—
B TOTAL CLOSING STOCK
60 ——
0
75
135
9 FROZEN STOCK
0
75
0
10 CLOSING BALANCE
60
—
135
SECTION VIII. Liquid Operotons Statement
RECEIPTS
DEL IVI•.RIES
lthrre ls RecetvLd Delivered to Commodity l3arrels Delivered
Received from
Commodi lv
DXL Oil Co.
do
Condensate
Scrubber Oi
150
140
TOTALS —
290
SECTION IX Report of Gee ln 1 .cIed — Represtunog. Pressure Maintenance, Cycling, and Underground Storage
Field aniL Reservoir ——
Well Owner
Lease
Well Injection
No. Pressure
MCF
Monthly
Total
SECTION X Detail of D.I,v.ry of Gas — Eec.pt Fuel System and Lea .. Use (MCF monthly)
xxxxxxx
Delivered to Whom
— Use or Disposition
Processing Plant
Processing Plant
TransmissionLine
Jnproccssed Gas(Sec. U)
Residue Gas (Sec Ill)
J & W Gas Co.-Bexar Plant
T & P Oil Company-Plant #1
0 & L Pipeline Co.
15,053
150,666
566,893
SECTION XI. Remark.
I REASON FOR VENTING UNPROCESSED GAS — ——_________________________________________________________________
2 SEA ON FOB VENTING RESIDUE GAS ——______
3
CERTIFICATE I. the :uidersigned. state that I am thi’ P].antS perintendent (TITLE) of
the Total Production Co . _________—_____________________ (CcAIPANY AND PLANT)
and that I am authort?cd by said company to make this report, and that this report was prepared under my supervision and directtnn and that the facts
stated therein are true. correct and Co e to the est of my knowledge
2—20—69 —7T ___________ 512—475—3803 —
- Area Code crnd lelephuni. Niunber
INSTRUCTIOPIS
i Tb.. report ihati be flied lfl (Oil, (4t diiplicale ongii..iI wiifl hi. District nire. mr of the Riiil,oad Commipsion of Tess. lo, the Ol.I ,ict In which Ihe Plant
i. located us soon tiller the firsi of the Month as pc.s uhl. for ihe IIre. rding Month. unit never line, than th . Tenty-p,fth of the nonih
2 Tb.. report is .qUured of .iII Plant a pror t atur..i G. Au Gns V iwnr, must be reported ci a 3 ... Pressure of 14 65 pound, per square Inch
ab.olut . end a Ba.n Temperature of 60 degrei s fah,enheil All liquid quantities .hown on Ibis report shall be in barrels of 42 Ii S Gallon. based on •ctual
physical gauge, computed from 100% U q Tank Tnblea Or ot’..r method nI measurement approved by the Commi..ion and Corrected from the temperature
.1 the time of meuqurement ID a niendurnI temperature of 60 degrees Fahrenheit Do not uae fraction, of thou.and. of cubic feel of gas. or fractions of
bsftels of iiqui,l on this report
I Detailed instructions available from Railroad Coi.umiaaion of tenas. f. Gab Di laion. Production & Proration Section. P 0 Dram., BE. Austin.
Teeaa 78711 3— i
!,lrIflntuT_
-------
• ‘ E OF DRIP OR SCRUBBER
Main Line Drip No. 1
Main Line Drip No. 2
in Line Drip No. 3
Attachment Ii Neceasalyl —
MONTHLY REPORT FOR I RAILROAD COMMISSION OF TEXAS
PROCESSING PLANTSI
OIL AND GAS DIVISION 3.409
- SERIAL NO. —
3
DiSTRICT NO. FOR THE MONTH OF Jt 1axV . IS 69
Total Pipe Line Company ODRESS P.O.Box 1340-Austin 1 Texas
F ArOR
Main Transmission Line Drip Delivery
• •r • NAME
ELDS COUNTY
• YPE OF PLANT Mainline Drips —__________________ DAILY AVERAGE INTAKE CAPACITY OF PLANT
.VG INTAKE PRESSURE P 5 A AVG RECOVERED GPM
FORM OP-i
Rev. 10/68
78720
•-- tUu m
REPORT ALL GAS VOLUMES IN MCF AT 1465 PSIA PRESSURE AND6O FAHRENHEIT IN_ACCORDANCE WITH GAS MEASUREMENT LAW
.ctIon I: Inialce Votumei (MCF monthly)
GAS WELL GAS
CASINGHEA D
TOTAL
OFWELLSPROOUCED
S INTO GATHERING SYSTEM
)L IVERIE5 FROM GATHERING SYSTEM
THERING SYSI EM 13 PLANT FOR PROCESSING
•ANT INTAKE — FROM PLANT METERS
:SS OR CAIN - 01FF. BETWEEN LINES 4 1 S
REFINERY AND STORAGE VAPORS
AS FROM OTHER PHOCESSING PLANTS
9 GAS FROII MAIN TRANSMISSION LINE
10 GAS WITHDRAWN FPOM STORAGE
1A5 IMPORTED FROM O IlCR STATES
•. ET GAS ro PLANT FOR PROCESSING
CTI0N II- Diepocition of Unproce.sed Go. from Gath.r.ng System (NCF nionthi,)
GAS WELL GAS
CASINGHEAO
TOTAL
• ‘UEL SYSTEM AND LCASE USE
2 GAS LIFT
a REI RESSUPING ft PRE SSURE M4IP TENAH E -______________________
CYCLED
S UNDERGROUND STORAGE
6 OTHER PROCESSING PLANTS
CARBON BLACK PLANTS - —
• RANSMISSION LINE -
1 NTED
OTAL
SECTION III Disposition of R.iidu. Ga. (MCF monthly) —
r TRACTION LOSS 6 GAS LIFT —— II OTHER PROCESS PLANTc
LOSS 7 REPRESS ft PRESS MAINT 12 TRANSMISSION LINE
1) 1.055 5 CYCLED — 13 VENTED
ANTFUEL 9 UNDERGROUNDSTORAGE — 4 METEROIFFERENCE
. 5E FUEL 5 USE tO CARBON BLACK PLAIJTS ..... .______ IS TOTAL
•P1 IV: Sulfur and C02 Recovery —
PRODUCTION OF SULFUR FROM PROCESSING NATURAL GAS TONS CO 2 ——
• , ON V Pled Liquid Hydrocarbon Production (barrel, monthly)
CON3ENSATE FROM GAS WELL GAS Mainline DRIP ANDFOR SCRUBBER 645
Dnp and/or Scrubber Oil produced Ifl excess of Statewide Rule 56 and allocated back to leases for operator to repert on Form P-I
I PLANT CONDENSATE 4 PROFANE 7 ETHANE
GASOLINE — 5 BUTANE-PROPANE MIX B
UTAI IE —___________ B ISO-BUTANE - 9 TOTAL 645
CTI0N VI: D.t.il of Drip or Scrubber R.cov.ry (PioducAlon included above)
NO OF GAS WELLS
NO OF OIL WELLS
B APR ELS
245
290
11.0
3-22
TOTAL D4D
-------
SECTION VII Barrels
Drip nod/or
nèe sate Scrubber Oil Gasoline Butane Propane Ethane Other Totol
I OPENING BALANCE 75 75
-
2 Fqozl- roct(
0
75
U
3 TorAL0PEN,NGSTOCK
7
4 RECSVL-11 -—
5 PROOUCFI)
0
0
645
645
DELIVEP D
L
- I
- 0 ]
0
8 TOTAL CLOSING STOCK 147 j —-_____ 147
9 0 I 0
ID cLosu ;oALAeur 1 147 T — — 147
SFCTION VIII t_.cs,d Operation Saismeni
RECEIPTS DEL1V R1ES
l r ’eivt d Corantijijity Itatrels Rereiveti Delivered to Commodity I3arrels Delivered
DXL Oil Company Drip Conden)ate
573
TOTALS — ________ -— — —
— ——
SECTiON IX Report of Gas in 1 ecIed — Repr.i.vring. Praa ijre Maintenance, Cycleng, and Underground Storag.
Well Injection MCI’
I ietd anti Re crvoir Well Owner Lease No. Pressure Monthly
Totel
xxsxxxx
SECTION X: D.eail of D.Iuv.ry of Gas — Escapt Fuel
to Whom
Sy .t.m arid Lees. U.. fMCF monthly)
Use or Disposition Jnprocessed Ga (Sec. II)
Residue Go’s (Sec. Ill)
SECTION XI Remarks
I PEAtON FOR VENTING UNPROCESSED 0* 5 -______________________
2 ‘ r i’ eN roe VENTING RESIDUE GAS —____________________________________________________________________________________
3 ———— - —
uperintenaent ____________________________
CERTIFICATE I. the undersigned, state that I am the ______ - (TITLE) of
theT0t Pipe Line Co . ______________________ _________ (COMFAMYANDPLANT)
and that 1 am authorized by said company to make thus repoil, and that this report was prepared under my supervision and direction anti that the facts
stated therein are true, correct end compl to the b I of y k ledge.
2—20—69 7 7 -— SJ.2—475—3803
Area L.ode c id Telephone Niirnlter
INSTRUCTIONS
The reran ,holl be IiI ti in four (4) dup9caie ,rigiaol, with I ,p Disiri. t turn tor of lb. Stuilnouad Commie.ion of Tesos be the. Dialnict in which the Plant
ic mated as soon afte., th . first of the ionth -it rns.i ’,I, to, ‘hr preceding M,nth anti nrvnr blot Ilian the Twenty-Fifth ol the month
2 Thie i.porI . required a i tilt Plant. procoasing Natural Ga. Al! Ci i Volts-ti’s must be rep ried at a Boss Pressure of 14 65 pound. per square Inch
ab.Qlute and a Base Temperature of 60 degrees Fahrenheit Ad liquid quantitie . shown on this report shalt be In barrels of 42 U S Gallon. based on actual
physical gauges computed from 100% U S Tenk Tables a, other method if measurement approved by the Coinmisaton and con-acted from the tamperalurs
at the tfme of meaturement to a .tancford temperature of 60 ntegreca Fahrenheit Do riot use Fraction, of thousand, of cubIc (sat of gas, or frecUons ol
bor?els of liquid on thin repori
3 Detailed instruction. s *llsble ‘rem Psairoad Commission nf e .ns, I , Gas Dislaior Production & Frorelton Section, F 0. Drewar 55. Austin.
Teas. 78711
-------
TEXAS RAILROAD COMMISSION ANNUAL REPORT
TASI.I NO. S
ULTIMATE DISP ITION OF ALL 0*1 PRODUCTION
£1.1. GAS VOLUVER RIPORTID AT A STANDARD BASE P 1 1 5 1 3 2 1 1 OP 453 P 8 I ABSOLUTE AND A STANDARD BASE PRISSURI OP 50 P
YEAR 1972
RantS.
Ezt,.ctlan
I..s.
Acid 0..
H 2 5 &
Plant Vw.4
Lass. Ii ..
P,,..wu
M.inL &
R.prn
Twcanl.sIa .
Us..
CycI.d
Caiton
Black
U sda ,.
round
SIae.Ea
Vested
an
Fisted
Plant
Nat . .
Di130 , .nce
T st s l
Gas
Produc.dA
Ma ,ketsd
PandaictionS
3snua.
F.bniy
Maid.
ApnI
lIsp
3w..
JuIp
August
5.ptemb. .
Oct . 6s,
If.s.mbs.
Dacesiba.
31.114.452
37.447.606
40.987.373
39.363.207
41.061.892
39.141.724
40.693.073
39.951.511
38.862.447
40.343,339
38.331.630
38.560.262
15.504.425
14.471.379
13.957.616
13,450660
13.116.664
13.962,106
I5.490.lII
35.225393
15.127.762
15,395.970
15.689.158
15.941.219
49.700.167
47.301.265
49.545.209
48.023,966
49.544.873
47767.293
49.709.046
50.334.496
47.944,534
49.285.339
45.701.671
50.544.262
31.736.122
36.311.949
39.690.974
40.734,120
43.694.854
40.933,359
39.842.497
39.225.747
39.447.530
39.038.338
36.0S6.303
36.842.037
635.534.249
604.577.762
626.146.173
605.432.611
609,301.677
595.429.950
622.081.173
635.615.794
599.510.965
633,345,064
633.306.547
633.353.277
33.174.044
33.734.203
33.117,591
30.890.796
30.365.693
28.754.956
29.343.090
29.751.757
29.645.395
33.017.936
23.576.004
29.896.890
1.616.850
1.616.217
1.776.921
1,690.837
1.744.284
1.519.996
1.751.231
3.723.305
3.532.433
3.694.567
1764,982
1.626.268
519.941
171.676
2.602.604
3.526.138
2.777.995
3,378.510
2.054.569
1.149.521
8.106.350
2.119.746
427.844
345.076
5.438.894
1.950.100
5.487.332
5.470.126
5. 108.004
5.407.045
5.336.365
5.405.633
4.653.850
4.703.368
4.206.066
4.202.206
2.256.722
3.213.726
3.470.360
4.434.673
3.723.393
4.759.223
5.234.965
5.186.515
4.386.333
2.277,115
2.047.270
883.200
620.845.866
711.109.908
817.783.371
795.795.119
803.644.330
779.130.990
113.341.704
803.633.661
732.037.559
807.039,242
787.338.175
814.199.697
687.053.266
653.502.764
678.465.303
651.145.414
660.597.832
644.717.197
673.541.457
667.723.595
649.057.932
672.324.990
663.773.200
617.523.807
TOTAL
472.672.992
171.040.231
536.367.117
470.513.590
7.355.432.262
366.773.340
20.334.378
38.257.223
60.347.917
43.650,000
9,602.629,629
7.994.504.260
P.sc..t
01 TolsI
4.92
1.16
6.33
,
4.90
7691
382
0.33
0.39
063
0.43
• Egi ,acliau, Lass us lIuruiiba3e us Gas V.Iu.ei d v i (a ricaval of Liquefiable Nyd,.ca ,bo s
• Ma,keI d P,od,csuc, us hi 4,1.1 333 I i Trc.,.Issiout Lises, Carbo. Block. osd Plo,t Fuil aid Leats Use
6 Disposition Vilu.es not adjusted for corrected reparus.
TABLE NO. $
ULTIMATE DISPOSITION OF ALL. GAS PRODUCTION
ALl. 0* 5 VOLUMES RIPOSTED AT A STANDARD BASE PRESSURE OP 3465 P S I ABSOLUTE AND A STANDARD BASE TEUPERATURE OP 60 F
YEAR 3973
Nnth
Estracilos
Loss
Acid Gas
H 2 8 CO 2
Plant Pu . 1
L.a.. Us.
Pr..surs
M.i.t.
R.p.es.unn
Trau.smi..los,
Lii..
Cycled
C.,bon
Black
Und..-
,ound
Starsge
Vented
or
FIs.ed
Plant
Mete,
DIfle.once
Tst.I
C..
Prnducedl
Ita.li.u.d
P,oductuoe
3snuuu
? bivary
lI.,ch
April
Map
j ly
August
$.ptsaibsr
Octoban
N.vss.bac
D.cs.bsI
37.697.524
33,304.766
39.805.353
37.698.093
40.575,118
38,372.455
39,833,978
39.302.093
31.991.005
40,151.332
29.066.656
39.307.603
15.777.164
34,349,999
34.579.654
14,256,181
15. 150.519
34.976.282
35,736.969
35.801,873
33.096.559
15.192.628
15,105.615
35.378,879
49.335.353
45.276.423
49.286.303
47.543.5S9
49.331.933
46.629.823
48,456.979
45,496,697
46.355.424
47.941.405
46,894.236
48.807.932
35.501.603
32,99I IS0
36.608.085
35.942.933
36,560.534
34.999.051
35.380.707
35.859,414
34.105.031
34.496.053
33.412.900
33.369.934
635.66 1. 18 1
574.707.295
637.793.864
590.810.955
599.620.373
585.335.798
633.504.373
012,661.673
583.369.464
599,753.005
539.394.096
636,478.377
28.470.078
75,473,354
28.195.645
28.627.598
28.069.630
26.765.542
26.890.839
20544.922
36.468.71i
27.531.956
25.550.270
25.953.832
1.478.334
1,431.657
3.607.403
3.543.825
3.753.937
3.675.424
3.542.090
1.541,353
3.636.029
1.631. 127
3.265,326
1.469,291
421.119
879.327
3.097,865
4.280.032
6,230.881
3.536.299
4.054.529
3.662.847
4.002.624
3.552.635
3.352.396
553.293
4.304446
3,403545
3.953.392
3,696.334
3.364.398
3.539.646
3.544.683
3.338,993
3.190.357
3.002. 190
2.984,905
3.399.202
3.274.904
3.349.114
5.120.672
3.008.205
6,355259
6.163.282
6.597.636
7,764.674
5.364.384
3.453.065
2,775730
2,350.100
811.726.944
736.623.233
800.037.039
767.407.733
787.322.770
763.956.612
795.563.513
794.976.236
759.099.499
776,912,400
750.438.130
787,596419
666.473.308
620.972.378
bbI.t. 17.570
639.893.339
650,50..227
633.621,01’
663.533.142
.62.703.723
6.3 1.6lO.0I7
649.i5 .630
637.J ’4.65 1
666,753, .50
TOTAL.
466,343.054
151.402,322
574.657.920
419.431,440
7.218,421.246
324.571.531
16.515.781
39.704.069
41.891.917
55.843.607
9,340,612,987
7.811.694.047
a s T.u.l
4,99
1.94
6.35
4.40
77.28
3.47
0.70
0 43
045
0.60
• E.u ,oe(u.uu Loss ii shr..ba 3 e In C ia VoIu.e, due (0 rosPvol of Liquefiable Hyd,eco,bis ,
• Marketed Preduculo.u a the total gsa to T,ans ..Iaulo, L.ns. ro.b. 9 Dhac6 ..d Plant net and I ease I .e
£ Dlsp.ulIu.a Voluess sot •dlusted for corrected .cpartt
3-24
-------
COMPANY
P 0 8o 12 O
TuIsd, Oklahoma 74101
List all plants processing natural gas and short.
cycle acsorotion units. includinc dehydrators from
which h .i;ocarbons are recoverea. List partnership
planis only if you’re the operator. Report only
iruividual streams which you make in your plant.
LOCATION
(For legal description give
section-township-range or
section-block-survey.)
YOUR OFFICE ADDRESS
GAS GAS
CAPACITY THROUGH
_________ PUT
(MMcf daily)
CYCL-
ING
Yes
or
No
PROCESS METHOr
1 — sorp. only
2—Ref rig. _abs.
3—Refriq. on1
4—Compress.only
5 —á , sorption
2—
3—
4—
5-
1914 ANNUAL GAS—PROCESSING PLANT SURVEY
YOUR NAME
EXISTING PLANTS
Iso-
Ethane Propane butane
CITY
YOUR TITLE
STATE
— PRODUCTION — Goltons per day
Base average on production the past 12 months
Normal or
unsplit
butane
E thane—
Propane
mix
(give %
of each)
Report only if
produced as such.
LP—gas RawNGL
mix mix
Debut.
nat.
gaSo.
Other
I. Isopent ane
2. Upgraded motor fuel
3. Diesel 4. Kerosine
List others
1—
2—
3—
4—
12. Sulfur T/d
scriprion.
Plant name:
i—
2—
3...
4—
5.
:
:
:
:
:
1—
2—
3
4_.
Field:
County:
State: Legal d c .
scription:
Plant name
Field:______________________________
1—
2—
3 .
4
s—
:
:
:
:
:
1—
2—
3
4..
County:
State: Legal de-
scription:
OIL&GAS.
JOURNAL :
Plant name: _____________________
Field: __________________________
e County:
U I State: Legal de-
• Pentanes plus
(Use back side if more space is needed for new construction)
-------
Page 2
(New plant or expansion continued....)
NEW CAPACITY BE- PRODUCTS & CAPACITIES COMPLETION
LOCATION STATUS CONTRACTOR PROCESS METHOD REMARKS: Cost etc.
ING ADDED ( MMcfd) Gallons per day month—year _____________________ ______________________
PLEASE LIST SHUT DOWN PLANTS HERE (note if sold and to whom)
Plant name: ________________________ Plant nar,e ________________________ Plant nnme.
Field ____________________________ Field ___________________________ Field ____________________________
County County County.
State ____________ Legal de- State. Legal de State Legal de-
scription scription. scription
New owner _____________________________ New owner ______________________________ New owner
-------
Appendix 4. ECOLOGY AUDITS, INC. DATA FORMS
No. 1 /
/1 _______________________ 2. ____________________ —.____________________ 4 .
STATE / COUNTY
_____ ECOLOGY AUDITS, INC.
S9gSMonroeDr OaIIas Texas 75220
t2 4 350’ 1893
Sv iaiy 0! Co’e La oqaIo,i Inc
-------
No. 2
COMPANY_________________________________ PLANT_________________________________
long tons
sul fur/year
Oil & Gas Journal reported capacity long tons/day X 365
GP-l Data - 12 mos. 1973 — Sulfur Production
Gas Plant Intake MMCF __________
H 2 S Loss MMCF __________ X 37.48 long tons/MMCF=
H 2 S as mol % of Intake ________
Apparent Sulfur Recovery __________
Unprocessed Gas
Fuel Use MMCF
Vented MMCF
Total
Assumed H 2 S mol%
H 2 S Loss: MMCF X 37.48 long tons/MMCF=
Total Apparent Emissions - Processed and unprocessed Gas
Texas Air Control Board Data - 1973
502 EmissIons _________ tons/year x .4464 long tons/ton SO 2 emission
H 2 S Emissions _________ tons/year x .8403 long tons/ton H 2 S emission
Total atmospheric emission - sulfur compounds
4-2
-------
No. 3 _________________- .__/ 1. __________— 2._.____________ 3. ____________
State / County County
= 10%
AQCR B=t25%
C = + 200%
Range Sulfur Emitted __________ - 50%
Range of Sulfur Sulfur As As Re- As Esti-
Intake of H 2 S Produced Recovered Reported estimated mated by
Company Plant MMCF/Y % LT/YR LT/YR To State In Survey Ecol. Audit _____
CA) ______ _______ ________ _____
Total
County Data
Sulfur Plants
-------
Appendix 5. TABULAR DATA FOR PLANTS STUDIED
The following tables in Appendix 5 show total values only, rather
than values for individual plants in the columns for “Total Intake”,
“% of Gas Sweetened”, “H 2 S in Sour Natural Gas as Produced” and
in all Natural Gas Produced.” lndividual plant data would identify
specific plants in many cases and violate the confidentiality of some
of the information provided for the study. Much of the l 12S content
data were obtained from individual operators in varying terms of
percentages of H 2 S and 502 in an acid gas stream, percent in a
plant charge stream, grains of per 100 std. cu. ft. of gas plant
charge or pipeline receipt, ppm of H 2 S in a stream, etc. Since the
objective of the present study is to evaluate total emissions of
sulfur, a compLete itemization of data by plant is not called for.
Further, plant processing varies widely from day to day in some
areas (see pages 78 -80) which may make individual plant numbers
misleading. As an example of cooperative operation, plants No. 2
and No. 10 of AQCR 155 send all or most of their sour gas stream to
plant No. 12 for sulfur recovery. Data for these three plants should
provide a balance on sulfur produced, recovered and emitted.
The average value of “U 2 S in Sour Natural Gas as Produced” was calculated
for each AQCR by converting the total quantity of sulfur produced to
MMSCF of U 2 S and dividing this value by the total gas sweetening plant
5 — 1
-------
intake. Take AQCR 155 as an example:
108,100 LT/yr = 2884.2 MMCF H 2 S/yr (Refer to Page 62
L / for explanation)
2884.2 x 100
586,800 = 0.49% H 2 S in Gas Sweetening Plant Intake
The percentage of “H 2 S in all Natural Gas Produced” is obtained by
considering “Total Intake” rather than “Gas Sweetening Plant Intake.”
Similar calculations can be made for each plant if such data are desired.
As examples:
Plant No. 2, AQCR 155
17,100 X 100 = 1.59% H S in Gas Sweetening Plant Intake
37.48 x 28,700 2
Plant No. 7, AQCR 155
37.48 x 63,400 = 0.28% H 2 S in Gas Sweetening Plant Intake
Plant No. 9, AQCR 155
37.48 x 70,200 = 0.073% H 2 S in Gas Sweetening Plant Intake
H 2 S concentrations range from a few grains per 100 cubic feet to 16 or 18
percent of the sweetening plant intake gas to the various plants, but the
total values provide the weighted average, which is the significant
quantity in the present study.
5-2
-------
Natural Gas and Sulfur Production for Air Quality Control Regions in the Study J\rea
AQCR
Location
Plant
No.
Total
Intake
MMMCF/YR
Gas
Sweetening
Plant Intake
MMMCF/YR
% of Gas
Sweetened
H 2 S in Sour
Natural Gas
as Produced
H 2 S itt all
Natural Gas
produced
Quantities in Thousand LT/YR
Sulfur
Produced
Sulfur
Recovered
Elemental
Sulfur
Einitted*
155
Pecos
Permian Basin
11.6
.1
2
28.7
17.1
--
3
2.0
.1
.1
4
3.9
—
<.1
<.1
5
88.0
5.8
5.8
6
7.1
7.1
cj l
7
63.4
6.6
6.6
8
62.2
1.5
1.5
70.2
1.9
1.9
10
2.0
13.1
9.5
11
6.9
.
2.0
2.0
12
18.3
2.5
13
8.3
.3
.3
14
24.1
.8
.8
No. of plants studied with
small or no sulfur emissions
T ai ____
estimated by Ecology Audits. Emitted principally as sulfur dioxide from tail gas incineration.
-------
Natural Gas and Sulfur Production for Air Quality Control Regions in the Study Area
AQCR
Location
Plant
4O.
Total
Intake
MI4I4CF/YR
Gas
Sweetening
Plant Intake
MM F/YR
% of Gas
Sweetened
H 2 S in Sour
Natural Gas
as Produced
H 2 S in all
Natural Gas
produced
Quantities in Thousand IT/YR
Sulfur
Produced
Sulfur
Recovered
Elemental
Sulfur
Emitted*
155
Pecos
Permian Basin
15
12.2
.9
9
16
25.3
1.7
1.7
17
1.9
.8
.8
18
2.8
.2
.2
19
26.3
.9
.4
20
13.9
1.3
1.3
.
21
7.0
1.2
1.2
22
2.6
1.0
1.0
23
20.1
1.2
1.2
24
12.5
1.6
1.6
25
6.6
10.2
4.6
26
3.1
.5
.5
27
9•3
5.8
3.3
2.5
28
•3
.1
.1
No. of plants studied with
small or no sulfur emissions
Total
*M estimated by Ecology Audits. Emitted principally as sulfur dioxide from tail gas incineration.
-------
Natural Gas and Sulfur Production for Air Quality Control Regions in the Study Area
AQCR
Location
Plant
NO.
Total
Intake
HNMCF/YR
Gas
Sweetening
Plant Intake
MMI F/YR
% of Gas
Sweetened
H 2 S in Sour
Natural Gas
as Produced
I-1 2 S in all
Natural Gas
produced
Quantities in Thousand LT/YR
Sulfur
Produced
Sulfur
Recovered
Elemental
Sulfur
Emitted*
155
Pecos
Permian Basin
29
63.0
11.9
10.6
1.3
30
8.6
12.4
10.9
1.5
cji
c
___
No. of plants studied wi
small or no sulfur emiss
th -
ions
Total
30
590
586.8
100
49
.49
108.1
47.7
59.9
As estimated by Ecology Audits. Emitted principally as sulfur dioxide from tail gas incineration.
-------
Natural Gas and Sulfur Production for Air Quality Control Regions in the Study Area
AQCR
Location
Plant
No.
Total
Intake
MMMCF/YR
Gas
Sweetening
Plant Intake
MM F/YR
% of Gas
Sweetened
H 2 S in Sour
Natural Gas
as Produced
H 2 S in all
Natural Gas
produced
Quantities in Thousand LT/YR
Sulfur
Produced
Sulfur
Recovered
Elemental
Sulfur
Emitted*
218
Midland-Odessa
S2n Angelo
1
11.0
.4
.4
2
24.1
.
2.2
_________
2.2
3
33.4
1.1
1.1
4
7.3
.3
.3
5
7.9
.7
.7
6
19.3
-_______
.9
.9
al
‘
c
7
12.2
.8
.8
8
11.0
1.0
1.0
15.3
.1
.1
10
1.6
.1
.1
11
18.9
.2
.2
12
s.s
.7
.7
13
3.0
.7
.7
14
104.7
3.5
3.5
No. of plants studied•with
small or no sulfur emissions
Total
• estimated by Ecology Audits. Emitted principally as sulfur dioxide from tail gas incineration.
-------
Natural Gas and Sulfur Production for Air Quality Control Regions in the Study Area
AQCR
Location
Plant
No.
Total
Intake
MMMCF/YR
Gas
Sweetening
Plant Intake
MMMCF/YR
% of Gas
Sweetened
I-1 2 S in Sour
Natural Gas
as Produced
H 2 S in all
Natural Gas
produced
Quantities in Thousand LT/YR
Sulfur
Produced
Sulfur
Recovered
Elemental
Sulfur
Emitted*
218
Midland-Odessa
San Angelo
15
30.1
.
.9 -
16
35.6
2.6
2.6
17
23.0
1.6
1.6
18
70.3
1.4
1.4
19
unknown
.5
•
20
147.6
9.1
5.0
4.1
21
3.8
1.1
1.1
22
5.1
<.1
<.1
23
5.0
.4
.4
24
.7
<.1
<.1
25
.9
<.1
<.1
26
14.0
.1
<.1
27
19.7
2.6
2.6
28
35.9
.
3.4
3.4
No. of plants studied with
small or no sulfur emissions
Total
estimated by Ecology Audits. Emitted principally as sulfur dioxide from tail gas incineration.
-------
Natural Gas and Sulfur Production for Air Quality Control Regions in the Study Area
AQCR
Location
Plant
No.
Total
Intake
MMMCF/YR
Gas
Sweetening
Plant Intake
MJ 1 4F/YR
% of Gas
Sweetened
H 2 S in Sour
Natural Gas
as Produced
H 2 S in all
Natural Gas
produced
Quantities in Thousand LT/YR
Sulfur
Produced
Sulfur
Recovered
Elemental
Sulfur
Emitted*
218
Midland Odessa
29
unknown
2.0
2.0
30
unknown
.
.1
.1
31
.9
1.8
1.0
.9
32
2.1
.6
.5
.1
33
3.1
.2
.2
c 1
,
34
5.3
1.5
1.5
35
1.3
.2
.2
36
3.4
5.2
3 7
1.6
37
120.5
.2
.2
38
93.9
.3
.3
39
26.3
5.7
5.7
40
5•
.6
.6
41
unknown
.3
.3
42
112.2
4.7
.7
4.0
No. of plants studied wi
small or no sulfur emiss
th
ions
Total
*M estimated by Ecology Audits. Emitted principally as sulfur dioxide from tail gas incineration.
-------
Natural Gas and Sulfur Production for Air Quality Control Regions in the Study Area
AQCR
Location
Plant
4o.
Total
Intake
!4MMCF/YR
Gas
Sweetening
Plant Intake
MMNCP/YR
% of Gas
Sweetened
H 2 S in Sour
Natural Gas
as Produced
H 2 S in all
Natural Gas
produced
Quantities in Thousand LT/YP.
Sulfur
Produced
Sulfur
Recovered
Elemental
Sulfur
Emitted*
218
Midland-Odessa
San Angelo
77.1
3.7
3.7
44
126.7
.
.6
.6
45
5.2
.7
.7
46
7.4
1.2
1.2
47
30.2
.1
.1
48
.2
<.1
<.1
r
C D
49
18.8
.3
•3
50
10.4
4.5
1.2
51
10.5
9•4
1.6
52
--
8.3
2.8
53
.1
3
.3
.
54
7.1
6.5
4.5
2.0
55
25.2
3.3
3.3
56
85.8
23.1
16.5
6.6
No. of plants studied with
small or no sulfur emissions
Total
estimated by Ecology Audits. Emitted principally as sulfur dioxide from tail gas incineration.
-------
Natural Gas and Sulfur Production for Air Quality Control Regions in the Study Area
AQCR
Location
Plant
No.
Total
Intake
P4MMCF/YR
Gas
Sweetening
Plant Intake
MMM F/YR
% of Gas
Sweetened
H 2 S in Sour
Natural Gas
as Produced
H 2 S in all
Natural Gas
produced
Quantities in Thousand LT/YR
Sulfur
Produced
Sulfur
Recovered
Elemental
Sulfur
Emitted*
218
Midland-Odessa
San An2elo
57
57.8
.1
.1
58
unknown
.3
.3
59
28.8
15.3
8.7
6.5
60
unknown
1.1
1.0
.1
61
.8
1.4
.5
.8
62
-.3
.1
.1
63
1.0
1.9
1.9
64
11.7
.1
.1
65
unknown
.9
.9
66
26.6
9.7
6.1
3.6
67
38.4
.7
•4**
68
55.7
18.6
14.8
3.8
69
38.5
29.6
25.9
3.7
70
15.8
20.2
18.2
2.0
No. of plants studied wi
small or no sulfur emiss
h
ions
Total
* estimated by Ecology Audits. Emitted principally as sulfur dioxide from tail gas incineration.
** Some is sold sour.
-------
Natural Gas and Sulfur Production for Air Quality Control Regions in the Study Area
AQCR
Location
Plant
No.
Total
Intake
MMMCF/YR
Gas
Sweetening
Plant Intake
MMMCF/YR
% of Gas
Sweetened
I-1 2 S in Sour
Natural Gas
as Produced
t1 2 S in all
Natural Gas
produced
Quantities in Thousand LT/YR
Sulfur
Produced
Sulfur
Recovered
Elemental
Sulfur
Emitted*
218
Midland-Odessa
San Angelo
71
6.9
2.1
2 1
.
72
unknown
•7
7
73
7.6
2.7
1.4
1.2
74
20.7
.8
.8
75
3.1
.4
.4
76
12.6
7.3
5.3
2.1
!
77
11.7
4.2
78
unknown
--
3.2
79
5.9
1.9
1.6
.3
80
11.3
2.7
2.5
.2
81
unknown
<.1
<.1
No. of plants studied with - 40
small or no sulfur emissions
Total
81
2726.1
1801.2
66
0.35
0.23
236.4
126.2
110.0
estimated by Ecology Audits. Emitted principally as sulfur dioxide from tail gas incineration.
** Sells some sour gas.
-------
Natural Gas and Sulfur Production for Air Quality Control Regions in the Study Area
AQCR
Location
Plant
O.
Total
Intake
MMMCF/YR
Gas
Sweetening
Plant Intake
MM?’CF/YR
% of Gas
Sweetened
H 2 S in Sour
Natural Gas
as Produced
H 2 S in all
Natural Gas
produced
Quantities in Thousand LT/YR
Sulfur
Produced
Sulfur
Recovered
Elemental
Sulfur
Emitted*
211
Amarillo/Lubbock
1
70.1
5.1
5.1
2
2.5
.
•7
.7
unknown
.1
.1
4
2.0
1.0
5
104.5
.s
6
13.8
.9
.9
7
122.3
6.7
5.5
1.1
8
7.3
.2
.2
g
5.3
1.2
1.2
10
.8
.3
11
4.2
1.1
——
12
unknown
.5
13
.9
.2
.2
14
3.0
.3
•
No. of plants studied with
small or no sulfur emissions
Total
*M estimated by Ecology Audits. Emitted principally as sulfur dioxide from tail gas incineration.
-------
Natural Gas and Sulfur Production for Air Quality Control Regions in the Study Area
AQCR
[ ,ocation
Plant
No.
Total
Intake
M141 CF/YR
Gas
Sweetening
Plant Intake
MMMCF/YR
% of Gas
Sweetened
H 2 S in Sour
Natural Gas
as Produced
H 2 S in all
Natural Gas
produced
Quantities in Thousand LI/YR
Sulfur
Produced
Sulfur
Recovered
Elemental
Sulfur
Emitted*
211
Amarillo/Lubbock
15
8.8
.9
.9
16
16.2
14.8
13.7
1.1
17
73.6
- .4
.4
18
70.0
1.2
1.2
19
6.9
.2
.2
20
4.5
1.4
.4
1.0
a’
s
—
-,
21
0.0
..J
.3
.
22
7.3
.6
.6
23
2.3
.1
.1
No. of plants studied with -12
small or no sulfur emissions
.
lotal
23
1,358.8
530.3
39
0.20
0.08
40.4
22.4
17.9
•AS estimated by Ecology Audits. Emitted principally as sulfur dioxide from tail gas incineration.
-------
Natural Gas and Sulfur Production for Air Quality Control Regions in the Study Area
AQCR
Location
Plant
No.
Total
Intake
MMMCF/YR
Gas
Sweetening
Plaiit Intake
MMMCF/YR
% of Gas
Sweetened
H 2 S in Sour
Natural Gas
as Produced
H 2 S in all
Natural Gas
produced
Quantities in Thousand LI/YR
Sulfur
Produced
Sulfur
Recovered
Elemental
Sulfur
Emitted*
217
San Antonio
1
16.2
10.5
7.0
3.5
2
2.0
1.0
1.0
--
3
5.0
1.4
--
1.4
4
8.3
7.1
4.6
2.6
5
20.3
13.0
9.8
3.2
6
19.3
10.6
.5
Ui
I
—
)
7
-
93
.
.
8
5.0
2.6
•
No. of plants studied with -
small or no sulfur emissions
Total
8
159.0
76.1
47.9
1.65
0.79
47.1
34.3
12.8
*As estimated by Ecology Audits. Emitted principally as sulfur dioxide from tail gas incineration.
-------
Natural Gas and Sulfur Production for Air Quality Control Regions in the Study Area
AQCR
Location
Plant
Jo.
Total
Intake
MMMCF/YR
Gas
Sweetening
Plant Intake
MMMCF/YR
% of Gas
Sweetened
H 2 S in Sour
Natural Gas
as Produced
H 2 S in all
Natural Gas
produced
Quantities in Thousand LTIYP.
Sulfur
Produced
Sulfur
Recovered
Elementa]
Sulfur
Emitted*
215
Dallas-Ft. Worth
1
3.0
2.6
.3
2.3
2
.1
.1
.1
3
.7
•
.
210
Abilene-tvichita
Falls
4
5.0
.1
i
.
5
13.9
.
.3
212
Austin-Waco
6
.9
.3
.3
1
7
4.2
39.7
33.0
6.7
214
Corpus Christi
8
0.6
<.1
<.1
9
26.8
32.6
28.4
4.2
10
1.1
.3
.3
No. of plants studied with -12
small or no sulfur emissions
Total
10
2455.7
56.3
2
3.63
0.008
76.7
61.7
15.0
•M estimated by Ecology Audits. Emitted principally as sulfur dioxide from tail gas incineration.
-------
Natural Gas and Sulfur Production for Air Quality Control Regions in the Study Area
AQCR
Location
Plant
No.
Total
Intake
MMMCF/YR
Gas
Sweetening
Plant Intake
MM1 4F/YR
% of Gas
Sweetened
H 2 S in Sour
Natural Gas
as Produced
H 2 S in all
Natural Gas
produced
Quantities in Thousand LT/YR
Sulfur
Produced
Sulfur
Recovered
Elemental
Sulfur
Emitted*
22
Shreveport-
Texarkana-Tyler
1
6.3
13 3
12 0
1 3
2
7.1
77.0
67.4
9.6
3
28.1
114.6
106.6
8.0
“
3.6
.4
.4
5
4.5
12.4
10.1
2.4
6
2.6
-
2.7
2.7
gi
. -‘
0
7
3.8
5.4
45
.9
8
7.8
.4
.4
9
.9
.7
.7
10
17.1
40.1
36.6
3.5
11
21.7
79.9
64.8
15.1
12
2.7
2.9
2.1
.8
13
16.0
10.9
9.6
1.4
14
6.6
1.4
.4
1.0
No. of plants studied.with - 4
small or no sulfur emissions
Total
14
459.1
128.6
28
7.5
2.1
362.1
314.1
48.2
* estimated by Ecology Audits. Emitted principally as sulfur dioxide from tail gas incineration.
-------
Natural Gas and Sulfur Production for Air Quality Control Regions in the Study Area
AQCR
Location
Plant
No.
Total
Intake
MMMCF/YR
Gas
Sweetening
Plant Intake
MMl CI /YR
% of Gas
Sweetened
H 2 S in Sour
Natural Gas
as Produced
FI 2 S in all
Natural Gas
produced
Quantities in Thousand LT/Yh
Sulfur
Produced
Sulfur
Recovered
Elemental
Sulfur
Emitted*
5
flobile-Pensacola
Panama City-So. i
;s
.2
.4
.4
2
.2
•7
•7
3
.2
.2
.2
4
.1
.1
.1
5
.2
.1
.1
6
———
10.5
•
-
153.4
150.3
3.1
——--—
U i
a...
-I
7
2.9
.1
- —
.1
—
2.6
s
4.9
2.6
2.6
4.9
4.2
•‘
10
22.7
127.3
112.7 —
14.6
11
13.6
77.5
4.1 —
12
2.9
17.2
16.1
1.1
13
3.1
.
19.7
]8.4
1.4
14
7.3
29.9
19.1
10.8
No. of plants studied with -
small or no sulfur emissions
Total
14
164.6
71.4
43
16.2
7.03
434.1
394.2
40.0
*As estimated by Ecology Audits. Emitted principally as sulfur dioxide from tail gas incineration.
-------
Appendix 6
M.W. KELLOGG’S EVALUATION OF THE ASSUMPTIONS,
METHODS AND RESULTS iN W
KELLOGG’S ROLE IN THIS STUDY
This study was authorized by EPA as part of Contract 68—02-1308,
Task No. 26, change 1. The actual work was performed by
Ecology Audits, Inc. During the course of the subject
study Kellogg worked closely with the EPA and Ecology Audits,
Inc. and reviewed the work being done.
A detailed discussion of Kellogg’s evaluation of the work
done under this task is presented in this section of the
Appendix.
In Kellogg’s opinion the methods used and the results
obtained are satisfactory.
6 -1
-------
Kellogg’s Review of Ecology Audits’ Assumptions On
Source and Disposition of Gas in Production Operations
The basis for the determination of how much emission of
sulfur compounds occur from petroleum production has been
shown in the flowsheet (Figure 1) used by Ecology Audits
Inc. and is part of this report. M.W. Kellogg
and the EPA had agreed for this to be the basis for the
entire study. A similar flowsheet has been discussed
in greater detail by Harold R. Jones (1).
The approach taken by Ecology Audits to estimate the total
sulfur emissions has been:
“The total sulfur emissions from a plant to the atmosphere
is the difference between the amount of hydrogen sulfide
produced from the ground less what is recovered. The
total emitted by the entire study area or an AQCR region
is the sum of the emissions from the individual plants within
that region.”
There is further breakdown possible for how this sulfur is
disposed off (vented, flared or emitted as SO 2 ). As far
as the computation of the total amount of sulfur emission
is concerned this approach is valid when the data for the
total plant intake and the amount of S recovered are avail-
able.
The various sources of information that are available as
public data do not contain sufficient information to compute
6-2
-------
the percentage of H 2 S in the gas produced. In certain cases
the data available do not appear to be reasonable. There are
a number of ways in which the data have been reported to
different agencies depending upon the requirements of the
agency. Also, where data were missing and had to be gathered
by personal contact, the data reported by the operators
were in terms of grains per 100 standard cubic feet.
Different methods used for computing the various quantities
are discussed and evaluated in the following pages.
6-3
-------
Sample Calculations When Gas Analysis is Reported in
Grain Per 100 Standard Cubic Feet
1 MMCF = 10,000 grains of H 2 S
7,000 grains — 1 lb.
10,000 32 1
7 000 X X 2240 = 0.000600 long tons of S
per MMCF with 1 grain H 2 S
content.
Sample Calculations Performed by Kellogg To Evaluate
Figures Obtained By Ecology Audits
Input Data
(assumed available either from public data or
from the survey)
Plant Name, County, State, Plant 1 - Any County, Any State
Source GP—1 Data
Gas plant Intake MMCF 927
H 2 S Loss NMCF 48.8
H 2 S as % of Intake
100 = 5.26%
Converting H 2 S _ Loss to Long Tons of Sulfur
1 lb. mol @ 32°F, 14.7 Psia = 359.05
Molecular weight of H 2 S 34
Molecular weight of S = 32
Texas railroad Commission
reporting condition = 60°F, 14.6 psia
6-4
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cft/lb of H 2 S
359.05 460 + 60 14.70
= 34 X 460 + 32 X 14.65 =11.21 cft/lb of H 2 S
Sulfur per million cubic feet of H 2 S
X 2240 x = 37.48 LT/MMCF of H 2 S
Total sulfur in long tons produced = 37.48 x 48.8
= 1830 LT/Yr.
Apparent sulfur recovery (based on the data available from
the same source as above or by survey) - 54.4%
Total sulfur recovered from this plant
(.54 x 1830) = 990 Long Tons/Year
Sulfur emitted by plant (including flaring)
1830—990 = 840 LT/Yr.
This is the figure that must go into the summary of the
county or the AQCR’s total emissions and is entered into
the work sheet 2 and work sheet 3 in their respective
columns.
If the data on emissions are available from an other source
for example in this case - the total apparent emissions -
(processed and unprocessed gas) is reported as 852 L. tons.
The two figures are close enough and either one of them
could be used.
Whenever a large discrepancy occurs between the reported
values then certain discretion has to be used. The values
used in this study are those in the column labelled - “As
estimated by Ecology Audits.” One of the major objectives
of this study was to resolve such differences in data.
6-5
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Example Plant of Any County, Any State
Input data 46 grains/l00 SCF
Plant Intake 70184 MMCF
Long Tons of Sulfur = 70184 x 46 x .0006
1937
Apparent sulfur recovery 55%
Amount Recovered = .55 x 1937
= 1065.0
Amount Emitted = 872 Tons/Yr.
This figure is entered in County totals on Work sheet W 2
Compute percentage of H 2 S-Given the SO 2 Emissions by
the Agency .
S(Long Tons) = SO 2 in tons/year x .4464
1 MMCF of H 2 S = 37.48 Long Tons
Amount of H 2 S IMMCF)
= 2.2 Emissions x .4464 = 0.0119 x (SO 2 emissions)
Example - SO 2 emissions (T/Yr.) = 21311
S emissions (LT/Y) = .4464 x 21311
= 9513 Long Tons
Plant Intake = 2026 NMCF
Amount of H 2 S (MMCF) = .0119 x 9513
= 113.2
Assuming an apparent sulfur recovery = 55%
Total amount of H 2 S (MMCF) = 113.2 = 251
H 2 S % in Gas Stream = 2026 X 100
= 12.4%
NOTE: The apparent sulfur recovery along with the SO 2
emissions (reported in tons/year) can be used to
find out gas intake analysis.
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STATISTICAL ANALYSIS ON DATA
General Approach in the
Evaluation of Data used by Ecology Audits
In Cases where Data were Missing.
General Approach To Evaluate the Data
As pointed out earlier in this evaluation the Ecology Audits
survey had to gather information from some of the plants
on their H 2 S percentages, plant intake and the amount of
sulfur recovered. This information, in some cases where
it was not publicly available had to be obtained from the
data gathered by a worldwide service company as part of
their (service company) contracts with the individual
plants. These data are confidential and are not disclosed.
However, in order to evaluate how good the figures used by
Ecology Audits are, Kellogg has taken the following approach.
1. Tabulate data for a given AQCR or a county (if county
has a large number of plants) - in a table as shown in
(MWKW 2)
2. Obtain figures for different columns from the data
sheets supplied by Ecology Audits and get averages
for public data.
3. Compare these averages with the values substituted or
supplied by Ecology Audits.
4. Determine the amount of deviations between data avail-
able and perform other statistical analysis on the
data used by Ecology Audits Inc. for the purpose of
this study.
6-7
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The conclusions drawn on the validity of the data and the
confidence that can be placed on the overall figures is
based on the above steps. This will give a fairly good idea
of the accuracy of the measurements made by the Service
company and the data gathered by the Ecology Audits’ survey.
Analysis of Data on County/AQCR Basis
To illustrate the approach described above and show the
step by step calculations in arriving at the conclusion on
the validity of the data for a given county or AQCR the
following worksheets have been used by Kellogg.
Worksheet 1) MWK-W 1 - (Statistical Analysis by County)
Worksheet 2) MWK-W 2 - (Summary of Data by County)
where necessary the source of data and calculations have
been indicated.
Some of the plants do vent some of the gas and to determine
what % of the intake is vented and establish the overall
% of the gas that is vented a breakdown for this quantity
is also computed.
Based on the analysis of the data supplied for missing values
of H 2 S for a particular region the following conclusions
are drawn.
1. The values substituted for missing data for a
few of the plants with missing data in the AQCR
regions reviewed by Kellogg the data fell within the
95% confidence limits.
2. Whenever the % of H 2 S appeared to be exceptionally
high, the cause for it was determined by reviewing
the raw data supplied. This was generally due to the
fact that the plant was a recycling plant and H 2 S %
6-8
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was not a true figure. This has been discussed in
greater detail in Section IV of this report.
With regard to the % of unprocessed gas vented the following
conclusion is drawn.
The % in most of the plants is less than 1% of the intake
gas and only in a few plants is this % higher.
For an explanation of this, the raw data and the operators’
comments have to be referred to for that particular plant.
Section IV outlines some of the possible reasons for this
discrepancy.
References -
(1) “Pollution Control in the Petroleum Industry”, Jones, H.R.,
r oyes data Corporation, 1973.
6-9
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( WORKSHEET MWK-W 1)
STATISTICAL ANALYSIS (MWK-W 2) BY COUNTY/AQCR
Refer to Worksheet (MWK-W 2) for the corresponding State,
and County.
State
AQCR Region
County(s)
Number of plants in this Region
Number of plants with complete Data;
Number of plants with missing
percentage of H 2 S
Number of plants with public Data
on H 2 S percentages
Average % of H 2 S in the gas in
this area
Average of Values % of H 2 S used
by Ecology Audits based
on their data
% of vented gas computation :
Average % of gas vented using
Public Data :
Average % of gas vented using
Ecology Data
Statistical Analysis of Above Data
95% Confidence Limit on the % H 2 S for this region --
95% Confidence Limit on the % of gas vented in this region --
6-10
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WORKSHEET ( MWX-W 2 )
DOTE 12/6/74
ov H.A. Nhan
EST .aO
JOBNO 4118—26
0
C
0
U
1H M W KELLOGG COMPANY
a CIVIOPON OP PULLMAN INCOU sAtEO
CUST0 ER
—
STAI’E/AQCR/COUNTY
PLANT NO.
% H S G
— 2—
1 UBLIC
)ATA
PRODUCED
ECOLOGY DIFFERENC
AUDITS ASS. %
PLANT LW
PUBLIC
DATA
AKE (MMCF
EPORrED
S.EMISSI
S (T/YR.)
ECOLOGY DIFFERENC
AUDITS BS.
ATh ON
VENTING
0
LMCF INTAF
ECOLOGY
AUDITS
PUBLIC
DATA
01
02
03
04
05
06
07
OB
09
10
11
12
TOTAL
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TECHNICAL REPORT DATA
(Please read Iasz,uctfons on the reverse before completing)
I REPORT NO.
EPA—650/2—75-030 2.
3.
4. TITLE AND SUBTITLE
S. REPORT DATE
Sulfur Compound Emissions of the Petroleum
Production Industry
December 1974
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S) Ecology Audits, Inc.
8. PERFORMING ORGANIZATION REPORT NO.
9995 Monroe Drive, Dallas, Texas 75220
9. PERFORMING ORG NIZATION NAME AND ADDRESS
10. PROGRAM ELEMENT NO.
The M.W. Kellogg Co.
.300 Three Greenway Plaza East
fouston, Texas 77046
1AB013 ROAP 2IADE-010
11. CONTRACT/GRANT NO.
68-024308, Task 26
12. SPONSORING AGENCY NAME AND ADDRESS
PA, Office of Research and Development
NERC-RTP, Control Systems Laboratory
13. TYPE OF REPORT AND PERIOD COVERED
Fask Final, 5-11/74
14. SPONSORING AGENCY CODE
i esearch Triangle Park, NC 27711
15. SUPPLEMENTARY NOTES
16. RDOur MI..I.1 report gives results of a study of sulfur compound emissions from the
Permian Basin and the Smackover Formation, two areas that represent about 80%
of the sulfur emissions from oil and gas fields in the U. S. 502 emissions from
these twa areas are estimated to be 664,000 short tons per year, of which 384,000
short tons per year are from Claus plant tail gases. H2S emissions are estimated
to be 9000 short tons per year. The report lists the plants studied and tabulates
the production of sulfur emissions by counties.
I
17. KEY WORDS AND DOCUMENT ANALYSIS
I DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
C. COSATI Field/Group
Air Pollution Fuels
Emissions
Petroleum Refining
Petroleum Products
Sulfur Oxides
Hydrogen Sulfide
Air Pollution Control
Stationary Sources
Permiari Basin
Smackov-er Formation
13B, 21D
13H
07B
18 OISTRIBUTION STATEMENT
fT 14wif ,l
JflL 1lI l .. A
19. SECURITY CLASS (This Report)
Unclassified
21 NO. OF PAGES
169
20 SECURITY CLASS (This page)
Unclassified
22. PRICE
IPA Form 222O 1 (9.73)
6-12
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