SCREENING REPORT
CRUDE OIL AND NATURAL GAS
PRODUCTION PROCESSES
FINAL REPORT
TASK ORDER NO. 13
CONTRACT NO. 68-02-0242
DECEMBER 27, 1972
PREPARED BY
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
CINCINNATI, OHIO
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
SCREENING REPORT
CRUDE OIL AND NATURAL GAS
PRODUCTION PROCESSES
FINAL REPORT
TASK ORDER NO'. 13
CONTRACT NO. 68-02-0242
December 27, 1972
Prepared by
Processes Research, Inc.
Industrial Planning and Research
Cincinnati, Ohio
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This report was furnished to the Environmental Protection Agency by
Processes Research, Inc., Cincinnati, Ohio, in fulfillment of Contract
No. 68-02-0242.
The contents of this report are reproduced herein as received from Processes
Research, Inc. The opinions, findings and conclusions expressed are those of
the author and not necessarily those of the Environmental Protection Agency
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ABSTRACT
There are about 600,000 to 700,000 producing oil and gas wells and about
800 natural gas processing plants in the United States. The field separation
equipment serving these wells and the natural gas processing plants emit pol-
lutants to the atmosphere. In 1971, an estimated total of 7,000 to 18,000 tons
per day of hydrocarbons, about 20,000 tons per day of sulfur oxides, and about
52 tons per day of sulfides (as, H2S) were emitted. It is estimated that 90 per-
cent of the field processing equipment has adequate emissions control.
Technology is available for 100 percent control; however, economics are not
favorable for recovery of hydrocarbon losses from small production fields in
remote locations. This report presents information on the processes used in
producing crude oil and natural gas, the location and production rates for the
existing production facilities, applicable air pollution control regulations,
the processes used in reducing air pollution from oil and gas processes, and
methods for testing and analysis of air contaminant emissions.
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SCREENING REPORT
CRUDE OIL AND NATURAL GAS
PRODUCTION PROCESSES
FINAL REPORT
TASK ORDER NO. 13
CONTRACT NO. 68-02-0242
INDEX
Section Title Page
I Introduction and Scope 1
II Summary 2
III Detailed Discussion
A. Objective 3
B. Field Production of Crude Oil and Natural
Gas 3
C. Processes Used and Atmospheric Emissions
Therefrom 4
D. Location of Production Facilities 14
E. Production - Past Five Years and Estimated
Future Five Years 15
F. Estimates of Nationwide Air Contaminate
Emissions 16
G. Applicable State and. Local Laws and
Regulations 24
H. Practical Emission Controls 25
I. Plants with Best Emission Control Methods 27
J. Available Methods for Testing and Analysis
of Air Contaminant Emissions 27
K. Research and Development Needs for Emission
Control Equipment 28
L. Estimated Costs for Emission Control 28
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Appendix
A Natural Gas Processing Plants in the United States,
January 1, 1972
B Methods For Sampling and Analysis of Waste Gases From
Petroleum Processes
C Crude Oil Production in United States
D Marketed Production of Natural Gas in United States
E Process Flow Sheets
F Emissions Control Process Flow Sheet
G State Air Pollution Laws and Regulations
H Bibliography
I Persons Contacted For Information
J Conference Memorandums
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SECTION I - INTRODUCTION AND SCOPE
Production of gas and oil involves the loss (emission) of hydrocarbons and
.sulfur-bearing compounds into the atmosphere. The objective of this study is
to provide background information on such production. The study summarizes the
types of field processing in use, the source and magnitude of the emissions,
and methods available for reducing them.
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SECTION II - SUMMARY
This study was conducted by surveying available literature and by consulta-
tion with people in some of state agencies concerned with control of air
pollution from oil and gas production.
Crude oil and natural gas are produced in 31 states of the United States.
In 1971 there were 805 natural gas processing plants located in 24 different
states and 280 counties. In 1969 there were about 520,000 producing oil wells
and about 114,500 producing natural gas wells. A majority of these wells are
located in 258 major oil fields and 38 major gas fields. There are about
3,000 companies engaged in the production of crude oil and natural gas.
It is estimated that, in the United States, between 7,000 and 18,000 tons
per day of hydrocarbons are emitted to the air in the production of crude oil
and natural gas. The SOX emissions are estimated to be 20,000 tons per day,
while sulfide emissions are estimated to be 52 tons (as equivalent ^S) per day.
The burning and emission of hydrocarbons in the field has been drastically
reduced in recent years because of regulations by state conservation departments,
and because it was to the economic advantage to the companies to recover such
hydrocarbons.
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SECTION III - DETAILED DISCUSSION
A. OBJECTIVE
The objective of this study is to provide background information on
facilities for crude oil and natural gas production, and the atmospheric emis-
sions from those facilities and their control. Numbers in parentheses refer to
the applicable references in Appendix H.
B. FIELD PRODUCTION OF CRUDE OIL AND NATURAL GAS
The composition of crude oil and natural gas at the well head varies
from field to field. Each well produces some or all of the following components:
Parafinic hydrocarbons; e.g., methane, ethane, propane and highers
Napthenic hydrocarbons; e.g., cyclohexane
Nitrogen
Helium
Carbon dioxide and hydrogen sulfide, which are acid gases
Water or salt water
Combined sulfur compounds; e.g., COS and RSH
Oxygen
The wells are classified as gas wells or oil wells based on the ratio
of oil/gas produced. For example, Texas law defines an oil well as "....any
well which produces one (1) barrel or more of crude petroleum oil to each one
hundred thousand (100,000) cubic feet of natural gas." (20). A gas well is one
which has an oil/gas ratio less than that quoted.
Field processing is required to separate the well head stream where
both liquids and gases are present. Also, the quantities of oil and gas pro-
duced are measured in the field. Any natural gas produced is either fed to a
gas collection line, recompressed and recycled to the producing strata to main-
tain pressure,.or, in remote areas, it may be burned at the well head. Any
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crude oil produced goes to a refinery or to a crude oil pipeline. Any liquid
water produced is either a waste product or is returned to the formation for
repressuring.
Natural gas is classified as "dry gas" or "wet gas." Dry gas is
defined as gas that contains no hydrocarbons heavier than methane or ethane (57).
Wet gas, or casing-head gas, contains hydrocarbons from methane through pentanes.
Natural gas is also classified as either "sweet gas" or "sour gas." Sweet gas
is defined as gas which contains little or no hydrogen sulfide, while sour gas
contains varying amounts of'hydrogen sulfide (57). Texas law (20) defines a
sour gas as one containing more than 1-1/2 grains of hydrogen sulfide or more
than 30 grains of total sulfur per 100 cubic feet. These variations and the
fact that the gas may also contain carbon dioxide, helium, and/or water vapor
means that each natural gas plant is designed to process the particular gas .
mixture it receives.
C. PROCESSES USED AND ATMOSPHERIC EMISSIONS THEREFROM
1. Introduction. A block flow sheet showing the relationship of the
crude oil field separation process to that of the natural gas process is pre-
sented on Flow Sheet E-l of Appendix E. Flow Sheet E-2 of Appendix E shows a
block flow sheet for the field processing of dry natural gases.
2. Field Separation Processes for Crude Oil and Wet Natural Gas. Flow
Sheet E-3 of Appendix E is an overall flow diagram showing the major steps used
in field separation processes (49). One process train may serve only a single
well, all wells on the same lease with common ownership, or all wells in a field.
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The latter case is referred to as a unitized field; i.e., one where all wells
are operated by a single operator for all of the owners of the field.
The first step in the field separation process for crude oil is
the "water knockout" where any liquid water is removed. To facilitate this
separation, an emulsion-breaking step (not shown) is frequently required ahead
of the knockout. Emulsion-breaking is accomplished by adding a chemical and/or
by heating. If liquid hydrocarbons separate out they are transferred to a tank
at the well head (lease tank) or to the gas-oil separator. The gas from the
water knockout goes to the gas-oil separator.
The gas-oil separator is used to separate crude oil or natural gas
liquids from the gas and to recover the gas at as high a pressure as possible.
This is usually accomplished in three gas-oil separation tanks in series. Each
succeeding tank operates at a lower pressure than the previous tank. Each
reduction in pressure results in a separation of liquids and gas. This separa-
tion occurs because the mutual solubility of the gas and liquids is lower with
lower pressure. The liquids which separate out go to the lease tank, operating
at atmospheric pressure. At this point, residual gases dissolved in the liquid
flash off and are vented to the air if the tank is open. Vented gas is lost
unless it is recovered by vapor emission controls system. Vapor emission con-
trols are not shown on Flow Sheet E-3, but are discussed in Section III H.
The above-described gas-oil separation process is used where well
head pressure is several hundred psi. At many wells, the pressure is much
lower, and hence, fewer than three stages are used. At some locations, the
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well head pressure is very low and all gas is removed in the water separation
step; thus, no separate gas-oil separator is used.
The crude oil collected in the lease tank goes to a refinery. At
some locations, this crude oil is treated before it leaves the field to remove
water or E^S.
The gas which leaves the process usually goes by pipeline to either
a gas processing plant or to sales, or it is recycled to maintain field under-
ground pressure. At remote locations where recycling is not practiced or where
it is not economical to sell the gas produced, it is burned (flared).
Flaresj where they exist, and hydrocarbon vapors from vented lease
tanks are the chief source of emissions.
3. Field Processes for Dry Natural Gas. Dry natural gas is field pro-
cessed either if it contains liquid water or water vapor which will freeze in
the pipeline or if it contains acid gas. As shown on Flow Sheet E-l, gas which
contains water passes through a water knockout and then through a gas dehydrator,
employing either glycol absorption or desiccant adsorption. Acid gases are then
removed in the sweetening process. The I^S removed either goes through a Glaus
sulfur plant or, if the quantity is small, it is usually flared.
4. Natural Gas Processes. The purpose of natural gas processing plants
is to separate ethane, methane, propane and/or natural gasoline, and to produce
a dry natural gas for sales. A usual sales specification for natural gas is a
gross heating value of not less than 1,000 Btu per cubic foot, a maximum of
0.25 grains of H2S per 100 scf, with a maximum of 20 grains total sulfur
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(Private Communication 7 in Appendix I), and a water content low enough so that
line freeze-ups will not occur.
Flow Sheets E-l and E-2 of Appendix E show some of the process
arrangements used. The steps used are: (1) Acid gas treating, if required,
with or without the Glaus sulfur plant (if a Claus plant is not used, the acid
gases are burned to convert the H2S to the less toxic sulfur oxides before
venting); (2) gas dehydration; and (3) gas separation. The gas separation
step separates the entrained hydrocarbons. Variations exist in the process
arrangements shown; e.g., some plants have the acid gas treating step after
the dehydration step and some treat the natural gas after it leaves gas separa-
tion.
The gas fractionation process steps may be carried out at different
locations; e.g., one plant will separate the gas into a natural gas stream and
a liquids stream containing the C2*s and heavier fractions, which liquids
stream is then fractionated at another plant.
There are seven acid gas treating processes commonly used in the
United States. These are listed in Table 1. The description of these processes
is not a part of this report. They all produce a sales specification natural
gas with respect to the acid gas content and an acid gas stream containing
and C02 with only traces of hydrocarbons.
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TABLE NO. 1
COMMERCIAL ACID-GAS TREATING PROCESS IN UoS,
IN NATURAL GAS SERVICE (12)
Process
Benfield
Diglycolamine or
Econamine
Fluor Solvent
Girbitol or MEA
Molecular Sieves
Selexol
Sulfinol
No. of
Plants^
18
15
6
200
Gas Rate
Scfd
37
>1,000,000,000
>1,000,000,000
>900,000,000
Special Features
Used for gases containing 75
percent C02 and
Used to remove COS and RSH,
as well as C02 and H2S
Used for gases with high con-
centrations of C02 and H2S
This is the most commonly
used process
Used on low acid gas concen-
trations «100 grains H2S/100
cubic feet) and for RSH removal
Used on high C02 with low H2S,
especially when H2S goes to
Claus
Used on wide range of H2S and
C02 concentrations
The gas dehydration step is either a glycol injection process,
described below as part of the refrigerated absorption process, or a solid
desiccant process, described below under the refrigeration process.
In the gas separation step, there are eight processes used in the
United States. These processes are absoption, refrigerated absorption,
refrigeration, compression, adsorption, fractionation, cryogenic, and turbo-
expansion. The name of the process with the exception of the fractionation
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process, is derived from the step used to separate the ethane and heavier hydro-
carbons from the natural gas feed. The process descriptions which follow and
the respective flow sheets shown in Appendix E, present either the .basic step
for separating natural gas from a liquids mixture or a complete plant process.
Where only the basic separation step is presented, it should be realized that
any given plant may have any or all of the steps shown on Flow Sheets E-l or
E-2, together with a complete distillation train, in addition to the basic
process step.
a^. Absorption Process. This process is used to remove natural
gasoline, LPG (liquified petroleum gases, mixed ethane, propane and butane) from
a wet natural gas, as shown on Flow Sheet E-4 in Appendix E. The gas from the
field passes through an absorber where an absorber oil removes the propane and
heavier molecules. The residue gas, consisting chiefly of methane and ethane,
is sold as natural gas. The enriched absorber oil goes to a stripper which
separates the absorbed propane and heavier molecules from the absorption oil.,
The gas stream of propane and heavier molecules goes to the stabilizer where
methane and ethane are driven off and recycled to the absorber. The remainder
(bottoms) from the stabilizer goes to a splitter, a distillation column, where
the LPG comes off as the overhead product while natural gasoline is the bottoms
product. Appendix A indicates that 164 plants in the United States use an
absorption process. A well designed and operated plant has no atmospheric
emissions, except for an occasional leak or other mechanical failure. The
natural gasoline is usually stored in tanks. Where these tanks are vented, they
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lose (emit) hydrocarbons to the atmosphere due to breathing and filling. The
cost of these losses can be as much as several thousand dollars per year for
each tank. Most tanks are equipped with emission controls as an economic
measure to control losses. Emission controls for tanks are discussed in
Section III H.
b^. Refrigerated Absorption Process. A flow sheet of a refrigerated
absorption process plant, which was started up in 1970, is shown on Flow Sheet E-5
of Appendix E (24).
In this process, the incoming gas is dehydrated to a minus 40F
dew point. This is accomplished by bringing the incoming natural gas into con-
tact with triethylene glycol to absorb the water vapor. The glycol is regenerated
by boiling off the water. At some plants, this water vapor leaves the process
as steam and carries glycol at less than 0.5 pounds per 1,000,000 cubic feet of
gas processed into the atmosphere. After dehydration, the gas passes through
two absorbers in series at minus 40F. All hydrocarbons except methane are
absorbed by oil in the first absorber. A sponge oil regenerator recovers the
hydrocarbons which were absorbed in the second stage absorption. These recovered
hydrocarbons are mixed with the rich oil from the first stage absorption and fed
to the primary demethanizer. The overhead gases from the demethanizer return to
the absorber. The bottoms go to a rich-oil demethanizer where any remaining
methane is removed as fuel gas. The rich oil then goes to a still where the
balance of the absorbed hydrocarbons are distilled off, thus regenerating the
first stage absorber oil. The overheads from this still are fractionated in two
steps to produce ethane, propane and a 64+ hydrocarbon stream for sales. There
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are no deliberate emissions from this process, although there may be some
breathing and filling losses from the C4+ liquid storage tankage. Refrigerated
absorption is used by 448 plants in the United States.
£. Refrigeration Process. The refrigeration process plant is
shown on Flow Sheet E-6 of Appendix E (27). In this process, the inlet gas is
dried to a dew point of minus 120F, using molecular sieve beds. Water vapor
is adsorbed on the bed. Two beds are used in parallel, arranged so that one is
on-stream while the other is being regenerated (not shown). Regeneration is
accomplished by means of heat and a stream of hot gas. The hot gas from the bed
being regenerated is cooled to condense the water and is then fed to the opera-
ting bed. The dry gas from the molecular sieve is then passed through a heat
exchanger where it is cooled to minus 35F. Liquids which condense are removed
in a separator. The gas from the separator is cooled to minus 135F and passes
through a second separator where more condensed liquids drop out. The gas from
this separator then passes back through the two heat exchangers countercurrent
to the incoming gas, where it exchanges heat with (cools) the incoming feed gas.
The liquids from the two separators are fed to five distillation columns in
series where methane, ethane, propane, isobutane, normal butane and natural gaso-
line are recovered as separate products. The only emissions from this process
are leakage and storage tank breathing and filling losses.
d_. Compression Process. The basic elements of a compression pro-
cess step are on Flow Sheet E-7 of Appendix E. This process uses two stages of
compression, each followed by cooling and gas oil separation, to produce a wet
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natural gas product and natural gasoline. Less than 3 percent of the plants
listed in Appendix E are indicated as using compression processes.
£. Adsorption Process. The flow sheet of this process (Flow
Sheet E-8 in Appendix E) shows the steps used to obtain a natural gas product
and a mixed hydrocarbons product. The resulting liquids product is fed to a
fractionation process.
The basic process consists of two or more beds of activated
carbon. The beds are used alternately, with one or more beds on-stream while
the others are being regenerated. The activated carbon adsorbs all hydrocarbons
except methane. The bed is regenerated by means of heat and steam, which remove
the adsorbed hydrocarbons as a vapor. This vapor is then condensed permitting
the water to be separated from the liquid hydrocarbons. About 12 percent of the
existing natural gas plants listed use an adsorption process. Hydrocarbon emis-
sions to the atmosphere may occur at the condenser and from vented liquid storage.
The amounts of these emissions depends on how the equipment is operated and
whether or not emissions controls exist. See Section III H for a discussion of
emission controls.
£ Other Processes. Less than 2 percent of the plants listed use
processes other than the five processes previously described.
There are 13 plants which are listed as using fractionation
processes. These processes separate natural gas liquids into the various hydro-
carbon fractions using distillation as described in Subsection III C 4 £. above,
and shown on the bottom half of the Flow Sheet E-6. The-feed to-these plants is
a mixed liquid from another plant.
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One plant uses a turboexpansibn process;. This process is
similar in principle to that of the gas-oil separator step discussed under Sub-
section III C 2. The difference is that turboexpanders are used to control
the pressure reduction of the gas. These expanders recover a portion of the
pressure energy in the gas which is otherwise lost when pressure reduction is
effected by means of a control valves.
Another process used is cryogenic in nature. This process is
used to recover helium from natural gas. No flow sheets are presented for this
process as it is of relatively minor importance in the industry as a whole.
£. Miscellaneous. The literature search disclosed two processes
related to the production of crude oil and natural gas that can serve as sources
for and contribute to H2S and sulfur-oxide emissions.
The first process involves the secondary recovery of crude oil
by use of water flood. In this process, water is pumped into an oil-bearing
stratum to push oil to the pump intake of an oil well. In some fields in Texas,
the water used is a sour water (contains H2S) obtained from a different stratum
in the oil field than that producing the oil. H2S and sulfide are stripped from
this water by countercurrent contact with an oxygen-free gas. The sulfides
removed are ultimately flared. The reason for removing the sulfides from this
water is'to prevent the sulfides from contaminating the sweet oil and gas being
recovered from the oil stratum.
Two installations are known (31)(32). One installation flares
2 tons per day of sulfur (equivalent to 4 tons per day as 802). The other
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installation flares about 2.5 tons per day of sulfur (5 tons per day 802). The
bibliography, with one of the two articles, indicates that there may be other
installations of this type.
The second process is not related to crude oil and natural gas
except that it affects the processing of natural gas. Texas law (20, pages 18,
19 and 20) permits the use of sour gas under certain restrictions in the manu-
facture of carbon black. No effort was made to determine how much gas is used
for this purpose, or how much sulfur oxides are emitted to the air from plants
using sour gas in making carbon black.
D. LOCATION OF PRODUCTION FACILITIES
Crude oil and natural gas is produced in 31 states of the United States
(see Appendix C).
A list of the natural gas processing plants in the United States and
Canada appears yearly in the Oil and Gas Journal. The list, as of January 1,
1972, shows 805 plants in the United States (3) located in about 280 counties
in 24 different states. This list was retabulated by states and counties and
appears in Appendix A. This tabulation shows the number of plants in each
county, total gas throughput',. total1 gas capacity and other information for
these plants.
Preparation of a list of field processing facilities for crude oil and
natural gas proved to be impractical. No such tabulation, or data from which
such a tabulation could be made, was found in the literature.
As noted in Subsection III C 2., page 4, a facility may serve a single
well, a group of wells, or all of the wells in a field. One source lists about
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542,000 oil wells and about 114,500 gas wells in the United States in 1969 (19,
Table 1052, page 643 and Table 1056, page 645). An attempt to make a list of
all the oil fields (or a list of the 258 major oil fields and 38 major gas fields)
and their location, was attempted using the API crude oil pipeline maps (17 and
18) and published lists of the major oil and gas fields by states in the United
States (4 and 5). This attempt was abandoned because many of the major oil
fields could not be located by county or counties. A list of oil and gas pro-
ducers is published every two years. The 1966-67 list gave names of about 3,000
producing companies in the United States with their mailing addresses (58).
However, there was no information provided on specific locations of these facili-
ties.
E. PRODUCTION - PAST FIVE YEARS AND ESTIMATED FUTURE FIVE YEARS
The number of natural gas processing plants has diminished in recent
years while their total gas capacity and throughput have increased. As of
January 1, 1970, there were 839 plants with a capacity of 67,900.7 MM cfd and
an average throughput of 56,216.3 MM cfd (59) while as of January 1, 1972, the
number of plants had diminished to 805 while the total capacity and throughput
had increased to 75,137 MM cfd and 58,997.3 MM cfd, respectively (3).
A table of "Crude Petroluem Produced in the United States" for the
years 1966 through 1970 appears in Appendix C, while a table of "Marketed Pro-
duction of Natural Gas in the United States" for the same five years appears
in Appendix D. These tables list the production by states in the United States.
No estimates were found for the next (future) five years, although an estimate
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is available for the year 1972 for the United States as a whole (5, page 140).
Therefore, estimates were made for each state for the year 1975, by extrapolating
the trend for the past three to five years as modified by other available in-
formation for some of the states (55, 60, 61 and 62). These estimates show
decreases in crude oil production in all states except Alaska, Louisiana, and
Mississippi, with an overall decrease in the production for the United States
as a whole. The Alaska increase is predicated on the completion of the pipeline
to the Prudhoe Field, while Louisiana and Mississippi may be at their peak now.
The only states showing real increases in natural gas production are Alaska,
Louisiana and Texas. The increase for the first two states, if it comes, will
be the result of an anticipated installation of facilities to market gas
presently being flared. Information received from the Texas Railroad Commission
indicates that in 1971 the gas produced was at or above the estimated figure
given for 1975. Texas oil fields are presently being operated at. their capacity
and total production will go down as these fields are depleted. The present
downward trend in production in the United States could be reversed if large new
fields are discovered in the future. However, any new fields will require new
processing facilities.
F. ESTIMATES OF NATIONWIDE AIR CONTAMINATE EMISSIONS
The major portion of air contaminate emissions from production of crude
oil and natural gas are hydrocarbons and sulfur oxides. The lesser portion of
such emissions are hydrogen sulfide and glycols. No information has been
obtained which will permit the making of a reliable estimate of the quantity of
any of the above contaminants. However, it is possible to make rough estimates.
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1. Estimated Hydrocarbon Emissions. An order-of-magnitude estimate
of the total hydrocarbon emissions from the production of crude oil and natural
gas in 1969 can be made from a table in "Minerals Yearbook, 1969" (63, page 744).
This table indicates that in 1969 about 526 billion cubic feet of natural gas
was vented and flared in the field production of oil and gas and at gas pro-
cessing plants in the United States. A large percentage of this gas is flared.
If we assume that 75 to 90 percent of this gas is flared and that the gas vented
without flaring had a density of 0.1 pounds per cubic foot, then between 7,000
and 18,000 tons per day of hydrocarbons were vented. This estimate can be
checked by separate calculations for field emissions and for natural gas plant
emissions.
For an estimate of the natural gas plant emission, another table in
"Minerals Yearbook, 1969" (63, page 740) was used. This table indicates that in
natural gas processing plants, an estimated 41.9 billion cubic feet of gas were
vented and flared and an estimated 54.6 billion cubic feet of gas were unaccounted
for. The following assumptions were used:
£. All the unaccounted-for gas is lost to the atmosphere.
Is. Twenty percent of the vented and flared gas is emitted without
burning.
£. The emitted hydrocarbons have a density of 0.1 pounds per cubic
foot. These hydrocarbons will be mainly methane, ethane, propane, and butanes.
Calculations using the above estimates and assumptions indicate
that unburned hydrocarbons emitted to the atmosphere for the 54.6 billion cubic
feet per year unaccounted-for losses amount to 7,500 tons per day of hydrocarbons.
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Assuming that 20 percent of the 41.9 billion cubic feet reported as vented and
flared was vented without burning, an additional 1,100 tons per day of hydro-
carbons would be emitted. This gives total unburned hydrocarbon emissions from
natural gas plants of 8,600 tons per day or about 10 to 11 tons per day per plant.
In estimating the hydrocarbon emissions in field processing, three
literature articles (41, 42, 44) were used. These articles related to vapor
recovery systems for field processing tanks. Examples were given for five vapor
recovery systems, recovering between 40 and 125 cubic feet per barrel of crude
oil processed. The average for the five cases was 96.5 cubic feet per barrel.
The following assumptions were used to calculate the emissions:
_a. Vapor recovery systems reduce potential emissions by 90 percent.
b_. The 10 percent uncontrolled production emits 96.5 cubic feet
of hydrocarbons per barrel of crude oil produced.
£. The density of the vented hydrocarbons is 0.1 pounds per cubic
foot.
Based on these assumptions and the fact that 3.37 billion barrels
of crude oil were produced in 1969 (Appendix C), it is estimated that 4,100 tons
per day of hydrocarbons were emitted in field processing.
The total for field emissions and gas plant emission is 12,800 tons
per day which compares favorably with the 7,000 to 18,000 tons per day estimated
at the start of this subsection.
It has been estimated (71) that the loss by evaporation in pro-
ducing and storing crude oil and other petroleum products amounts to 2 to 3 per-
cent of the total crude oil produced. This amounted to 26,000 to 38,000 tons
18
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
per day in 1969. Of this, less than one third (8,200 tons per day) is lost in
field production. The remainder is lost in refining and in distribution of
products to the consumer. The production losses are generally in areas far from
large population centers, while the losses in refining and distribution are
generally in or near such centers.
2. Sulfur Dioxide Emissions. In the production of crude oil and
natural gas, sulfur dioxide is emitted as a result of the following:
a_. Field flaring or burning of waste gases containing sulfur.
b_. Flaring of hydrogen sulfide from gas sweetening processes
having no Glaus sulfur plant.
jc. Burning of waste gases from Glaus sulfur recovery plants.
cU Flaring of hydrogen sulfide from the sweetening of sour water
used for water flooding in secondary oil recovery.
£. From the vent stacks of carbon black plants that burn sour gas.
A study of the last two sources is not included in this report.
In order to obtain an accurate estimate of the sulfur oxide emis-
sions from the first three sources, the following information is required:
£. The rates of production and the hydrogen sulfide and total sul-
fur content of the natural gases from the major oil and gas fields which produce
a significant quantity of sour gas.
]>. A list of all natural gas sweetening plants and the quantity
and sulfur content of the feed gas.
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
£. A list of all Glaus sulfur recovery plants which process acid
gases from natural gas sweetening, including the quantity of sulfur fed and the
plant efficiency.
A search of the literature and consultation with Government Bureaus
in six states (Appendix I, Items 5 through 11) produced very meager information
on the sulfur content of natural gases. The available data are tabulated in
Table II. The gas rates shown are design rates for gas sweetening plants. In-
formation is available on the natural gas production in 1971 from major gas
fields in the United States (5, page 211). The total accounts for less than
20 percent of the total amount of natural gas produced in 1971. No list of the
natural gas sweetening plants has been obtained. A list of Glaus sulfur
recovery plants appears in a report prepared for the Environmental Protection
Agency (70, page Cl). Sixty-four of these plants which were built prior to 1970
are listed as processing acid gases from natural gas sweetening. Only the sulfur
capacity of these plants was given. Thus, there is inadequate information to
prepare a reliable estimate of the total sulfur oxides or hydrogen sulfide
emissions.
A rough estimate of sulfur dioxide emissions has been made by using
the following, assumptions:
a_. The 64 sulfur plants using acid gas feed from natural gas
sweetening operated at 65 percent of their total production capacity.
l>. These plants operated at an average sulfur recovery efficiency
of 90 percent (Reference 70 indicates that Glaus plants have efficiencies be-
tween 89 and 97 percent).
20
-------
TABLE II
State
Texas
Texas
Texas
Arkansas
Arkansas
Texas
New Mexico
Texas
Texas
Texas
Texas
Texas
Texas
Florida
Texas
County
Ward
Hemphill
Hunt
Escambia
SULFUR
Field
Lockridge
Buffalo Wallow
Washita Creek
Magnolia
McKamie-PaHun
Quinan
Monument
New Hope
Dates
Terrell Plant
Gray Ranch
Gomez
Puckett
Jay
Buffalo Wallow
(Hunton)
(Morrow)
CONTENT OF NATURAL GASES
H£S
Grains
100 cf
6.35
27.0
19.0
1500
> 1500
0.1 Percent
0.38 Percent
14 Percent
8
220
1
8
0.2 Percent
11 Percent
18-30
0.26
RSH
Grains
100 cf
0.75
0.2
-
-
15
-
3
-
-
-
-
Design
Gas Rate
MM Cfd
150
50
150
50
130
220
275
250
180
35
Reference
(Appendix and
Item No.)
H-25
H-25
H-25
1-12
1-12
H-46
H-64
H-65
H-67
H-66
H-66
H-68
H-l and H-2
H-21
H-21
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
_c. The average sulfur content of all gas produced in the United
States is 0.5 mole percent.
d_. All gas marketed in 1969 required sweetening to below 0,25
grains per 100 cubic feet (less than 0.0005 mole percent).
\ The sulfur oxides emission from Glaus sulfur plants were calculated
as follows: the 64 Glaus plants had a sulfur capacity of 3,270 long tons per
day. At 65 percent of capacity, the possible production would be 2,120 long
tons per day. The sulfur loss at 90 percent efficiency calculates to 240 long
tons per day, or about 538 short tons S02 per day emitted by Glaus sulfur
recovery plants associated with natural gas production.
Sulfur oxides emissions from gas sweetening plants having no Glaus
plant were calculated as follows: 20.7 trillion cubic feet of gas was marketed
in 1969. This quantity of gas, at 0.5 mole percent sulfur, contains 11,900 short
tons of sulfur per day. From this was subtracted the 2,380 short tons (2,120
long tons) of sulfur per day fed to Glaus plants leaving 9,520 short tons of sul-
fur per day flared to produce 19,040 tons of sulfur dioxide per day. The sulfur
in 526 billion cubic feet of natural gas vented and flared, assuming 0.5 mole
percent sulfur, is 320 short tons per day. Subtracting the 50 tons sulfur per
day as H2S emissions, calculated in next section, leaves 27.0 tons of sulfur
burned per day to produce 540 tons of sulfur dioxide per day.
Hence, the total sulfur dioxide emitted per day in the production
of crude oil and natural gas is 538 plus 19,040 plus 540,. or 20,118 (say 20,000)
tons.
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
3. Hydrogen Sulfide Emissions. No information was obtained to permit
the making of a reliable estimate. However, the hydrogen sulfides emissions can
be approximated by using numbers previously calculated and assuming that the
85 billion cubic feet of gas emitted in field processing contains 0.5 percent
sulfur. This calculates to an estimated 52 tons (as equivalent hydrogen sulfide)
emitted per day.
A. Glycol Emissions. To estimate the triethylene glycol emission rate,
information is required as follows:
£. The number and capacities of plants which use glycol dehydra-
tion, and which vent the water vapor produced.
ID. The amount of triethylene glycol per million cubic feet of gas
processed vaporized with the water produced.
This information has not been obtained, so the following assump-
tions have been made.on which to prepare an estimate:
&. One fourth of all gas marketed in the United States is dehydra-
ted by use of the glycol process.
b^. All plants using the glycol process vent the water vapor
produced.
£. Half of all of the glycol lost in the process is emitted with
the water vapor while the other half is entrained with the gas processed.
Using these assumptions, together with the reported maximum glycol
loss of 0.1 gallons per million cubic feet of gas processed (69), it is estimated
that a national total of about 7 tons of TEG is emitted per day by the glycol
dehydration processes.
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
G. APPLICABLE STATE AND LOCAL LAWS AND REGULATIONS
A condensation of the applicable sections from the state air pollution
control laws and regulations for the states which produce crude oil and/or
natural gas are tabulated in Appendix G. This information was abstracted from
the publication "Environmental Reporter, BNA, State Air Laws,," (54) This publi-
cation listed regulations for 26 of the 31 states which produce oil and gas;
however, it did not include local regulations. Of the 26 states that have regu-
lations, 17 issued such regulations since January 1, 1972. No attempt was made
to obtain local regulations. The magnitude of the job of surveying several
hundred counties where crude oil and gas is produced is beyond the scope of this
project.
In addition to state air pollution control regulations, the production
of crude oil and natural gas is subject to state conservation laws and regula-
tions. Telephone calls were made to the conservation departments of the states
of California, Louisiana, and Oklahoma and to the Railroad Commission of Texas.
(Appendix I, Items 1, 2, 3 and 4). These four states produce 78 percent of the
crude oil in the United States. Three of these states prohibit the venting or
flaring of gas from gas wells except under special conditions. They prohibit or
limit the amount of gas that may be vented or flared from oil wells. Oklahoma
has no laws or regulations prohibiting venting or flaring. The Oklahoma Division
of Conservation discourages the wastage of large quantities of gas. Economics
usually dictate whether or not individual producers vent gases.
The effect of the Texas regulations and the realization by producers
that it was to their economic advantage to recover gas instead of wasting it
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
vaa to reduce the percent of the gas vented and flared in that state from 5.59
percent in 1953 to 0,74 percent in 1971. Prior to 1953, the quantity of casing-
head gas that was vented or flared was not reported.
H. PRACTICAL MISSION CONTROLS
The technology exists for control of hydrocarbon emissions. The decision
to install required control equipment is usually based on economics. Equipment
for vapor conservation may include floating roof tanks, diaphragm tanks or vapor
recovery systems. Whenever a tank is vented, emissions will occur to the atmos-
phere due to tank "breathing." Most crude oil contains gas dissolved under con-
siderable pressure. Vapor recovery is used to save the gases which are released
from solution when the pressure on the hydrocarbon liquid is reduced.
Two vapor recovery systems are in general use and are shown on the flow
sheet in Appendix F. The first system is used where the lease tank cannot be
sealed, as is frequently the case in older fields where wooden tanks were in-
stalled because the crude oil is corrosive due to high sulfur content. This
vapor recovery system consists of a vessel, known as "gas boot," which receives
the crude oil from the oil-gas separator and is maintained at atmospheric
pressure. Vapors and gas which flash from solution in the gas boot are collected,
compressed, cooled and fed to a knockout vessel. The dehydrated gas from the
knockout vessel goes to a natural gas pipeline. Liquids from the gas boot and
the knockout go to the lease tank. The second system is used where the lease
tank can be made vaportight. The vent from the lease tank serves as a suction
pipe for a compressor. The compressed gases and vapors are cooled and pass to
a knockout vessel. The gas from the knockout vessel goes to a natural gas
25
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PROCESSES RESEARCH,
INDUSTRIAL PLANNING AND RESEARCH
pipeline. Liquids from the knockout are returned to the lease tank. A pressure-
controlled bypass line is installed between the compressor discharge and suction
lines to prevent the creation of a vacuum in the lease tank when no vapors are
being generated therein.
Hydrogen sulfide tends to come out of the solution in the crude oil
with the light hydrocarbon gases. Its emission is controlled when those of the
light hydrocarbon are controlled. The hydrogen sulfide is separated when natural
gas is sweetened. Where state regulations do not prohibit, many plants burn the
hydrogen sulfide removed from the gas to produce less odorous and less toxic
sulfur dioxide, before discharging to the atmosphere. Other plants have installed
modified Glaus sulfur plants to convert the hydrogen sulfide to sulfur, which is
sold. Claus plants convert about 89 to 96 percent of the sulfur in the gas to
elemental sulfur. The percent recovery depends on the sulfur concentration of
the gas fed to the Claus unit and on the number of reactor stages used (70,
page 9). The waste gas from the Claus unit is burned in an open flare to convert
hydrogen sulfide and other sulfides to sulfur dioxides.
Sulfur oxide emissions result from the burning of sulfur-containing
waste gases. To reduce these emissions requires use of a Claus tail gas process
before incineration or scrubbing of the gases after incineration. The Beavon
Sulfur Removal Process and the Cleanair Sulfur Process are claimed to increase
the sulfur recovery for Claus processes to 99.9 percent (70, page 2). The IFP
Process is claimed to increase sulfur recovery to 97 percent (70, page 3). These
processes and flue gas scrubber processes are either relatively new or still
being developed.
26
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
I. PLANTS WITH BEST EMISSION CONTROL METHODS
In plants having good control of emissions, most of the crude oil field
processes have vapor-emission control systems on the field lease tanks. It is
economically advantageous at such plants to recover these vapors. In addition,
it is required by state conservation regulations. Many of these systems were
installed at the time that a field became unitized. The literature (2, 26, 30,
41, 42, 43, 44) reports six locations where vapor emissions control are used;
namely °.
Sun Oil Company
Jay Field, Florida
Shell Oil Company
Cedar Creek Anticline, Montana
Little Beaver Field, Montana
Little Beaver East Field, Montana
Block 24 and 27 Offshore Fields, Louisiana
Cities Service Oil Company
Devonian Formation Field, Texas
Dora Roberts Ranch Field, Texas
(Three of eleven fields had installations in 1965, others
were being studied)
Humble Oil & Refining Company
King Ranch, Four Field Area, Texas
Gulf Oil Company
Various West Texas Fields, Texas
J. AVAILABLE METHODS FOR TESTING AND ANALYSIS OF AIR CONTAMINANT EMISSIONS
Methods for testing and analysis of air contaminant emissions for crude
oil and natural gas processes are listed in Appendix B. These methods appear to
be satisfactory and further R&D does not appear to be warranted.
27
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
K. RESEARCH AND DEVELOPMENT NEEDS FOR EMISSION CONTROL EQUIPMENT
Equipment to control hydrocarbon emissions is adequate and no need for
further research is indicated. Three processes are presently available to
reduce SOX emissions. The cost of installing and operating these processes in
their present form cannot be justified economically. Research and development
might result in cost reduction.
The estimates of hydrocarbon and sulfur-oxide emissions presented in
this report are very crude, because of lack of information. To obtain more
accurate estimates, an extensive industry survey would be required to quantita-
tively determine types and capacities of field processing equipment used,
existence, type and efficiencies of vapor recovery systems used, existence, type
and efficiencies of gas sweetening processes used, sulfur analysis of gas from
each well, gas and oil production rates, methods for disposal of sulfur recovered,
and similar information.
L. ESTIMATED COSTS FOR EMISSION CONTROL
The following costs, based on information in Reference 41, are for a
vapor recovery system using a gas boot (see System 1, Section III H) <, The com-
pressor discharges to a gas gathering system operating at 30 to 60 psig. The
costs have been escalated to 1972 levels and scaled up for plants having a vapor
rate of 500 mcfd and 1,000 mcfd.
Mcfd of Installed Cost
Vapor Recovered Dollars
100 10,000 to 13,000
500 22,000 to 28,000
1,000 33,000 to 43,000
28
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
The costs for systems with closed field tanks and no boot would be
about $1,000 less at 100 mcfd to $3,000 less at 1,000 mcfd.
Many systems in Texas operate on closed field lease tanks and discharge
to a 15 psig sales line,. These systems consist of a compressor with an auto-
matic control system and have no condenser or knockout. At 1972 prices, an in-
stallation would cost about $6,000 for a recovery of 30 mcfd of vapors (41)
Most of the vapor recovery systems reported in the literature for large
systems were installed in conjunction with 'Other processing improvements and the
costs reported for these systems do not segregate the costs of vapor recovery.
Costs for Claus sulfur plants and tail gas processes for Claus plants
are given in Reference 70. These plants would be installed as additions to those
gas sweetening plants that are presently burning the hydrogen sulfide produced <,
For a typical Claus plant having a capacity of 100 long tons of sulfur
daily, the investment and sulfur production costs for various acid gas concentra-
tions are approximately:
Claus Plant Sulfur Production
Mole Percent I^S Investment Cost Per Long Ton
In Acid Gas Feed Dollars Dollars
15 1,400,000 14
50 1,000,000 11
90 900,000 9
The product sulfur capacity has a pronounced effect on costs of Claus
plants. For typical plants using 50 mole percent I^S feed gas, the investment
and sulfur production costs for various capacities are approximately:
29
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
Product Sulfur Glaus Plant
Daily Capacity Investment Cost Per Long Ton
(Long Tons) Dollars Dollars
10 300,000 26
100 1,000,000 11
1,000 4,300,000 8
For those plants that must attain a 99 plus percent sulfur recovery,
the investment and operating costs for adding a Beavon Sulfur Removal Process
are about equal to the cost for the Glaus plant alone, while the costs for adding
an IFP process will be about 50 percent greater than the costs for a Beavon
Process.
These costs are for the control systems only. Where gathering lines
are involved, total costs become much higher. Isolated oil wells may be hundreds
of miles from sulfur removal facilities. In such cases, oil is now usually
pumped to a lease tank and hauled to a buyer by truck, while the gas and hydrogen
sulfide from the well is usually burned in a flare.
30
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
APPENDIX A r- NATURAL GAS PROCESSING PLANTS
IN UNITED STATES, JANUARY 1, 1972
31
-------
to
to
NATURAL GAS
i STATE
COUNTY
COUNTY
POP.
1160
TOTAL
NUMB Eft
OF
PROCESSING- PLANTS /M UNITED STATES/ JANUARY 1, 1172.
TOTAL \ TOTAL
GAS GAS
NUMBER] RECYCLED SULFUR
OF CAS\ PLANTS RfZOVeRY
CAPACITY THRV-PUT\ RECYCLE* CAPACITY
PLANTS MMCFD MMCFO j PLANTS i MM CFO
T " I [
ALABAMA }
MOBILE 31+300
\
ALASKA
KENAI BUKPt/GHi ~
i
i
AR120NA
APACHE i 30,100
\
ARKANSAS
COLUMBIA
LAFAYETTE
CALIFORNIA
FRESNO
KERN
KINGS 8 FRESHO
LOS ANGELES
ORANGE
SANTA
BARBARA
VENTURA
COLORADO
ARAPAHOE
LA PL AT TA
LOGAN
MESA
MORGAN
f?/0 RLANCA
'
2
»
i
I (, 000 2
36S",ieo
ziijOoo
;
16
~~ 1
6,03^000
70+fOOO
17
f
1 6%OOO\ 7
^1%OOO
113,000
11,000
2.0,000
57,000
ZlfOOO
FOOO
6
1
1
1
1
3
+
2.0 1.3
j
O
\
ir.o w.z. i /
2.r (o
/"t/iA/rs
SULFUR
SECOVfK-
FP
. PA
TYPE OF Pf*OCe:$S**AND NUMBER
OF PLANTS t/S\N& EACH fKOCl
A B
NUM8EHI LT/DAYl
1
, i
1
1
f.O
\
o
i
-
\
j
7s:o 10.0 i
7I.O 3.5- &) t 8.0
46.0 tT3.0 I
i
8.0 1
_._
fH.f 3 6*. 7 | 3 *6?.O
tOO.O -H.O - - - *
101.0 1.-2S.1 4
I4O.O 13.1 j - - | -
2S~0.0 \IF.O - -
180,0 60.6
9.0 7.6
300.0 2064
1 0.0 6.O
2.0.0 H,3
31.0 16.1
fOJWij 31.1(4)
-
-
-
-
^
-
-
-
-
-
-
*
~
"
f
-
-
"
*
-
"
*
-
*
-
*-
'
i
6
T
2.
/
A
1
3
2
/
2
2
1
f
&
C
/
2
/
,
6
0
;
5-
i
f
i
/
/
1
'. ~r . . T i F
/
/
2
/
'
£
/
;
/
/
OTHEff
~.
rE 'I
ss.
Hfff-
AtfAlL,
1
t
y
-------
\
NATURAL GAS PROCESSING PLANTS IN UNITED STATES ; JANUARY
STATE
COUNTY
FLORIDA
BRADFORD
ILLINOIS
DOUGLAS
KANSAS
BARBER
ELLSWORTH
PIHNEY
&ORD
&RANT
HARPER
HARVEY
JtEARNEiY
KINGHAN
MORTOH
PRATT
ftffNO !
fftUSH \
SCOTT I
$EDOWI$K
SEWARO '
STANTON
KENTUCKY
FLOYD !
&REEH
GREEHUP\
I i
COUNTY
Pfooo
\flOO
\poo
7000
,OOO
OQQ
,000
,000
000
ooo
I
2
»
;
3
»
/
/
2
1
/
/
/
4
I
;
i,
I
(
TOTAL
e*s
CAPACITY
HHCFD
100.0
f
\0&
30.0
It
2.6.0
iooa
2*0
iptr.o
9SJ
3.0
iff.O
n
7-O7.T
11. 0
(.o
1.0
jr.;
j
(
<
v.a.
c)
P)W
Nt/1 Sf/?
OF e/^s
RECYCLE
JPU1NTS
«
-
-
-»
J-
-
*
*
T
-
-
!-
*
4
-i-
4
4
i
1
i
RECYCLE
PLANTS
CAPACITY
fi M CPO
i
:
-
-
*
-
-
-
-
-
-
-
-
*
-
T
»
4
RECOVERY
PLANTS
NUMBER
\
I
4
-*
4
i
4
4
4
4
-f
H.
-
-
*
-j
4-
t
+.
4
i
i
';
j
i
SULFUR
RECOV-
ERED
4
4.
i
i
*
f
4
~
-
-
-
-
4
t
f
4
i
i
i
j
TYPE Of
0? PLAt
A
1
1
f
f
1
/
t
B
1
1
/
/
4-
2~
1
1
1
1
£
/
' I
PROCCS.
ITS USII
C
1
Z.
1
"AHD A
)G EACH
D
1
I
!
i
C
UH&C**
PPOCfS
i
I
/
i
t
i
OTHf/?
H t
fi? /
. ..:
it/:. -2.
t
s
^Sm.
i
<
,. _
. r- -
-------
NATURAL GAS PROCESSING PUNTS /N UNITED STATES ] JANUARY I, 1172. ;
STATE
COUNTY
LOUISIANA
ACADIA
ALLEN
»5C£"NSION
! ASSUHPTIOU
\ AVOYELLES
BEAUREGARD
BOSSIER
CADDO
CALCASIEU
CAM£/?0M
CLAldORNE
CONCOKOIA
EAST BATOU
ROUGE
EVANGELINE
I6ERIA
\BERVILLE
COUNTY
POP.
I°SO
fQjOOO
ZOjOOO
2.8 ooo
1 0,000
3BOOO
lljOOO
57,000
Z31}OOO
\5\000
7000
HjOOO
Z0,000
i30,000
32.000
JZjOOO
30,000
JEFFERSON Z0%000
JEFFER50N
DAVIS 30,000
LAFAY£TT£ } 85,000
LAFOURCHE \ SfyeQ
LINCOLN
noREHOuse
NATCHITOCHES
QUA CHITA
PLAQUFMINSS
POINTE COVPEE
RICHLANO
ST. BERNARD
ST. CHARLE5
Z.1,000
J4;000
36000
\oijooo
22/300
Z2,000
ZAOOO
32,006
ZI.OOO
TOTAL
NUrtBE*
OF
PLANTS
7
1
2.
3
'
3
jr
I
6
13
3
/
3
1
/
4
/
i
3
i
i
1
7
3
1
-t
2.
TOTAL
GAS
CAPACITY
^flM CFD
Z1.o
(e)
4 l.ttfii
1.0
Zl.o
1TO.O
Zf.o
rt).o^)
^p.(ftS'
Jf.otf)
7.0
i.o
\40jO
I6f.ff
11.0
100.0
4ZZ0
3-Z.O
iui0
33>0.o
SO 0.0
irt.o
it'f.o
ltie.o
' lyt.t
If.t
llfF.f
' fff.O^t)
TOTAL
G-AS
THRU-PI/7
nfi CFO
w.r
12. C
(e)
2W)
CCI
n.i
t°.i
(c,)
W&W
>,(7J-£
-------
NATURAL GAS PROCESSING PLANTS IH UNITED STATES, JANUARY I, 1972
STATE
COUNTY
LOUISIANA
ST. JAMES
ST. LANDRY
ST. MARTIM
ST. MARY
TENSAS
r f«/?E BON ME"
VFRM/U0K/
W£"85Tf «
NORTH 0I&
ISLAND FIELD
MICHIGAN
CRAWFORD
HlLLSDALf
OSCEOLA
ST. CLAia
WASH TEN AW
MISSISSIPPI
ADAMS
CLARKE
FORREST
JASPER
MARION
PIK£
SMITH
MONTANA
FALLOH
GLACIER
MVSSELSHELL
COUNTY
POP.
1160
IBpoo
6\tooo
21,000
50,000
1,1,000
1, 000
31tOOO
40,000
"*
SflOO
35000
/
-------
NATURAL G-AS PROCESSING PLANTS IN UNITED STATES; JANUARY /, 1972
PAGE
BOUNTY ;
---'-- - ---"-T. t
p
«
f
u £
OWDER R/l/f «
»CHL^WOj
OOSEVELW
I
R A AS if A
cjwcrewN^
k/MflALL ;
eo,or
r
fl
/i
J
Nflf
1cK(NLEY
)0 ARRIBA
'OOSEVELT
AN JUAN
ITH DAKOTA
QURKE
COUNTY
POP.
j
g^wo
liooo
\\000
I £000
6,000
5LOOO
3^000
z^ooo
liooo
59,000
itooo
WILLIAMS, &,ooo
2i
LAHOMA \
iLFALFA \ 9.000
$E/WE« t
i
i
<
IECKHAM IjOOO
\LA\NE li.OOO
:ADDO
topoo
'ANADIAN I Z&OQO
:A«TE«
CIMAffRQN
CLEVELAND
fyooe
V.OOO
i
TOTAl.
NUMBER
or
PLANTS
/
i
1
j
i,
\
4
i;
1!
1
S
$.
t
7
/
2,
1
1
2;
»'
24'
TOT
.o
b.o*
TOTAL
GAS
JHRU-PUT
MM CFD
4.0
o.e
7.0
6.I
2f7.T«J
i,oitU)
(t)
tt.i
347
izij.z
i
lltU)
712.
4u
zri.7
4f.o
T75"
6c)
IQ( 18
7 IA
4 1.0
i^.B.te
HUMBER
OF MS
RECYCLE
PLKHTS
-
4-
*
f
/
-
-;"
r
r
t
-t
4-
-f
;
i!
i-
j
4
' 1
4-
i
4
f
RE-CYCLE
PLANTS
CAPACITY
MHCFP
-
-
-
ra.o
SULFUR
RECOVERY
PLANTS
HUM&ER
-
*
^
^/TO
i-
-
-r
»
-r
^
t
225".o
-f
-
i
i
'_
-*
"*
'
^
.
»
-
-
*
JULFUR
RECOV-
ERED
LT /DAY
~
TYPE" OF PROCF5SU'/»WD NUMBER**
OF PLANTS USIN& EACH PROCESS
A ^
-
«.
27 /
*** ^
i
~ i
1
3
~"
/2/
'
._
Z
-
-
"
^
^
B
1
1
1
2
1
I
1
'
2.
t
2
1
2
/
/
C
/
'
3
D
E
t
j
OTHE/?
j
1 t
1
« /
NOT
AVAIL.
1
0 1
\
I |
i i
1
1
/
1
/
1
1
;
I '
i
i
c- /
-------
NATURAL GAS PROCESSING PLANTS IN UNITED STATES, JANUARY I, 1472.
PAG-E- e
STATE
COUNTY !
OKLAHOMA
(tREEK
&USTER I
[>EWEY !
ELLIS i
G-A£ FIELD
&ARVIN \
$RADY i
(rRANT I
HARPER
WL/GHES :
W !
WN6 FISHER
LINCOLN
1.0 (5AM
itOVE ;
toAJQB
itlARSMAtJL
r
*
£
leLEAN i
/OBL£ '
>KfUSKE(F
OKLAHOMA
/i»ftNT0TO$
<
'
Pff
EM/NOLff
fTEFHEN5
rcxAs |
WOODWARD
I
iMfYLVAtilA
:LK. 1
(EUANGO
COUHTY
P&P.
W80
+q,ooo
21
«
4
«»
,000
,000
poo
51000
2#>«7
3<
<
\0
>00o
4.000
a
/i
/
;ooo
,900
1*00
/|t«w
(
spoo
\POO
pot?
/
J
/
2.
2
3
3
t
TOtAL
OF
2
2
fi
/
^
4
i
j
y
1
4
3
1
i
. i
}
\ooo\ 4
J,000i jj
?>OOQ
/I
j ood\ 4>
^ooo a
4tw?
3
4
4
;
i
j
TOtAL
6 AS
CAPACITY
MM CFD
2.1.0
ft.O
ns.o
50.0
203.0
Zl 6.0( \
r
.
*
3
1
Z
/
1
1
3
2.
0 | E
~ "7~ r~
i
1
1 1
1
1
/
t
' i '
4
f
/
Z
/,
I
OTHER
WOT
A l/AIL
2.
1
j j
/
i
i
j
i
!
-------
.STATE
COUM
SOUTH
BUT!
TEXAS
M DEI
AW0f?
AA?M
ATACt
SEE
0EX>?
PR/**
eflf
CR0C
D'AU/J
DEWI
D/MM
PWKA
PAST
TY
D^K0Tvi
E
?50N
EWJ
s/is
.SA
? ;
OAlA
CS
lUk/
.HAM
(>N
.ee/?s
OKEE
?*iN
?/U?a
VCHE
HQ
IE;
oo
1 1,000
UPOQ
6*i,o?e
74000
looo
11000
%ooo
. &M°
z*,o?o
IOfOQO
33,000
6000
4,000
IQOOQ
t^OOO
4,000
2.3000
Spoo
4,000
11,000
2J,000
\»tooo
13000
io.000
11,000
TOTAL
NUMSF/?
OF
PLANTS
1
1
a
_, J
. 4
J
1
...,.ifl.
1
4
I,
i
4
: 1
__J_ ....
3
. 4
J
/
£
6
6
2^ ..
1
1
Z
_*_
a
TOTAL.
&AS
CAPACITY
M.M CFD
38.0
tf.0
itt.0
T5-.0
\ F60H.
101.0
\FO.O
^501.7
7/y.ff
233.0
r.«
- 10.9
tf.9
Z17.0W
)6,«
J&A
l)C.t
nr.o
50
14.0
310
ifr.otf
> n.o
f.O
\?.«.o
IF. 9
iar.9
_i3JL_
.911,0
;S5fN
PLAMTS
NUMBCf?
.. i .-r .
/
^
4_
1
£.
t
T^TE5
SULEUIB
ftECQV-
fflEP
LiT/OXV
i
*j>
yjrtf
: t
itf.p
- i
! -4- '
. vjwt.
; T -i
- *-..;...
4 '
i ._ , .
^. >
/2iPJfl
t- i
; +- j
3^3
, ivM^U
:. IDCPf
[OF f
;A:
11 "i 1~ '
i
. u:
..:£!.
: 'i:
; /
. :2]
...|.2i..
- "I i-
i
.... /! .
./:
. .3
1
1
_.
Af?y /, t
J&F £RQ(
LAWTS
.*;. .
./ ;..
.\
4
r
. . t -
-------
PAGE
STATE '..
COUNTY
.
TEXAS
; ERATH
FISHEfi
FORT 5EKD
FR AUK LIU
FRIO
GAIMES
GALVESTOti
0-RAY
&RAY5ON
GREGG
HALE
HAMS FORD
HARD.EMAM
HARQ/NI
HARRIS
HARRISON
HENDERSON
HIDALGO
HOCkLEY
HOPKINS
HOUSTON
HOWARD
HVTCHIUSOU
IRION
JACK
JACkSQN
JEFFERSOU
JIM. HOG-&
JIM WELLS
KARlHES
KEN COY
NATURAL GAS
COUNTY
POP.
I960
\ 6,OOO
4-1,000
spoo
10,000
IZ,OOO
l^oooo
3^ooo
73,000
61,000
37,000
TOTAL
NUMBER
OF
PLANTS
1
2.
3
1
1
3
4
6
3
r
i
6,000 z
&jOOO\ I
' \
/, 2*3,000! 5
+6,OOO -4
22,000 3
I9\,000_ II
22000; 3
/ ' ^
1 1,000 I
I1,O00 I
40,OOQ |
34; OOO{ 1
1,000: 2.
7,000 ; 3
14)000 5
/ !
S.OOO : 0
* . b_
\ S^OOO
1000
\'
/
I
PROCESSING PLANTS JN\ UNITED STATES-/ {J/\NUAf?Y I, 1^72. I
TOTAL
GAS
CAPACITY
nn CFO
ZS.o
3.0.0
132.0
?
-
- . i - -
- j - ;
- ! -
_ i - :
-
i - ; / 3*.o
< 1 1 4/
- - '. -
TYPE: OF PROCESS ""IANO NUMBER'*'
OF PLANTS i USING EACH f?ROCes3
A
0
1
1
1
z
z
1
/ ,
1
^
; .
2.
/
Z
z
4-
1
". Z
1
/
z
/
i 1
;5".
-
1 '.
1
(C) . ; - - .
1313.0 HOW) 1 i Z10.0 : - -
30.6 US
11.0 | I1.£
?)7.ff(4)
IOt.0
fS.6.0
.6.0.0
T-IO.O
2J3.?
7V, 7
llff.M)
41.0
2.01.6
/ j 2.6 ; -
;
57. a |
/ *~>.o \
_
2. 31 1.O
/ 2>tf^ (/
-
'"»
1 1
^
_
_
/
.3
1 /
i
....3.
: J
_
I
..3
: (
*
c\
\
1
i
i .
. 2J .
o
i
i :
t :
r
/ i
1 ..
.1
1 :
. .'..
2.'.
f
.,
\
z.
'- i i
1
/
£.
OTHER
i
i j
NOT\
WAIL.
J j
2. ; ; ;
/
1
/
i
4
..... L.
2.
/
i .
f
i
4 2.
t
1 '.
1
1
i
j
. j ;
: i '
: 1
j
; . /...
: i :
i " 1 : :
; i
-------
PAGE
NATURAL GAS PROCESSING- PLANTS /N UNITED STATES tJANUA RY I, I OOO
irOjOoo
1,000
7tooo
8,000
Spoo
2.6,000
isooo
(,6,000
\5tOOO
27,000
\5poo
34/300
11000
112,000
1,000
21,000
fifOOQ
23,000
t't,000
116,000
\ooo
ifyooo
i i/ooo
IS, 000
TOTAL
KU'lBEfl
OF
PLANTS (
1
2
3
1
4
5
/
2
1
1
^
a
I
7
1
f
7
1
3
10
2.
3
P
2
TO-Mi-
s/\s
CAPACITY
f^J A-J Cf P
/«.£?
I7T10
2, 7^0
\ 0»0
\52.0
2(>7.0
60.0
n.o
ZO.O
3.2
-2.3.0
1,001.0
f.O
H7.0(it)
2J-.0
160.0
IfW. 0
12.0
16,0
129.0
' 15-0.0
120.0
6 79. 0 (el)
I3ZO
TOTAL
GAS
- - j
WU«eEfl 'RECYCLE
OF G-AS PLANTS
THKV-p'JTlRECYCLE \CAPACITY
AIM CFO
12.6
'iie.o.'jr
112.5-
1.7
76.2
1 37.2
16*
26.0
11. 7
2.f
11.0
162.MJ
2,2
>83.W
.8
I05.6
te-t.o
\\.o
21.1
H6.(>
1 Zff.&tftt
ff.4
33 3.6~<4>
106.7
PLANTS IMM CFO
\
1 -
/ l.72f.O
1 /
i
i -
/ 1 1X0
-
-
;
/ 20.0
-
3 lOfC'tJ
- t -
_ _
-
-
-
«? »,0i£.0
-------
\o
NATURAL GAS PROCESStM& PLANTS IN UNITED STATES: JANUARY I, 1172-
IcOl/NTrl TOTAL TOTAL
STATE ' POP. \NUMBER\ GAS
COUNTY 1460 i OF \CAPACITY
^PLANTS MM CFO
i i
TEXAS I !
RUSK 36,000; 4
SAN PATH 1 CIO +5,000\ &
SCHLEICHER 3,OOO\ \
SCURRY 20,000 +
; SHACKLE FORD +000. 2
SMITH &6,000\ 2.
5~S.f
45 7.5 J.
56.0
102.0
i-7.0
\ 3.0
\ STARR ; I7,000\ 7 2.51.0
I STEPHENS ! 9000\ 6 \ 36.04
STONEWALL i ZpOO- \
TAYLOR \ 101,000] i
TERRY } 16/JOO] I
TOM GREEN '-. 65,000, 2
L'PTON $OCO! 6
VAN ZANDT 13,000-, 3
16.0
K.O
5.0
7.0
167.0ft
10X0
VICTORIA 46,000\ 3 141.0
WALLER 12,000. \
WAffC 15,000, 4-
WEBB (.5,000 1
\MHARTOK 3B,000\ 2.
\MHEELEf* 6,000' Z
WlLflAflfi'FR \Q,OCO \
WILL AC Y 2.0,000 2
WlNKLkR, 14,000. 7
W/5£ 17,000 2
W00C 18,000 5
YOAKUn 8,000 2
YOUNG- {1,000 3
? (VJ£ST PAN- - :
W.N DIE FIELD,, - \ i
i 1
lt 2. 60.0
#4. Sfl
\10.0
I3C.O
16.04
1.4
llf.o
300. f 4
lf-0 f(
iie.9 4
£37.0
23. 0
10.0
TOTAL
&AS
THRU-PUT
NUMB£P\RECYCLe SULFUR \SULFUR\ TYPE OF PROCESS**1 AND NUrtBER}
OF GAS \ PLANTS RECOVERY: KECOV-
RECYC LE \CAPACITY PLANTS I ERE.D
nrt CFD\ PLAHJS \nn CFD NUMBER [LT/PAY
2./JV
Z17.7
?OA
1 10.64
I7.O
l.f
2A6.0
2.4*4
1.8
2.r
4.7
3.1
66.04
SI. I
fl.f
1,076.0
lO.ttl
\30.O
61.f
2.1. 0
0.1
11.1
236.14
2)1.1
iOI.14
2.26S
If.f
4f.o
i ; T
;
« |
j ;
1 .
~ . -
/ S6.0 - }
-
-
.
-
/
-
-
-
-
-
-
-
/
/
-
-
;
- ; -
_ : '
' - ;
-:-.-
_
-
(1.0
-
/
-
-
-
-
' -
11.0
30.0
-
;
_ . -.
;
-
i ~
z i sii.o
:
» .
:
- ;
:
- i
:
' ; -
- .
I 26.0
. . -
^
j
s
j
OF PLANTS USING EACH PROCESS
T I T - --( -
A
3
/
i
a
1
/
i
i
j
i
i
i
B \ C D E OTHE/?
I
~ - ' 1 1
i
i
I !
6
1
6
1
/
/
3
2.
1
2
/
/
f-
1
i
I
/
1
j
2.
/
1
3
/
/
2.
Z
1
"" " - -* \
\
i
1
1 '
; j
' !
ii
NOT
AVAIL.
'~"~ "~"" *"
1
; ' 1
1
1
f
' i
1 ; /
ill i I ;
2, ':
i :
' j -'"'
1 i
i
i
-------
NATURAL GAS PROCESSING PLANTS IN UNITED STATES',
I, //JRgiAIM
KAN AW HA £63,000
TOTAL.
NUHBER
OF
PLANTS
r T '
TOTAL i TOT/IL
&/tS ! 6X5
NUMBER RFCYCt-r j 5J/LFUR 5ULR//?
OF &>\5 PLANTSiRECOl/fffy RECOV-
CAPACITY\THRV-PVt\ RECYCLE
MM CFO iMM CFO
h~ "1
; i
2.
/
1
WAYNE 33,000: 1
WETZEL 19000
WYOMING
CAMPBELL 6,000
CARBOU \5flOO
CONVERSE 6,000
' CROOK 5,000
FREMONT : 2.6,000
JOHNSON -. 5,000
LINCOLN ; 9,000
MATRONA ; 50,000
P/l«K i 17,000
SU8LETTE I 4,000
SWEETWATER \ 18,000
UINTA IQOO
WASHAKIE 3,000
U.S. TOTAL -
;
i |
j
. i
/
9
2
2
2.
2.
1
1
1
2.
1
2.
1
1
gas
1
180.0 1 IO3.8
38.0
35-.0
no.o
80.0
151.6
222.5
108.0
I7.O
11.6
ir.o
2.5 '0.0
80.O
Z2.7
io.o
40.0
I Ot>,O
5V. 0
i
i
I7.6
ZI.O
104.0
82.. f
(29.8
IdS.t
Zjfcl
9.0
77.1
-f.7
110.6
60.0
I8.7
1 2/t
36.iT
28..T
3/.r
JPLANTS,
C/»P/»C/TY! PLANTS ERED
MM CFO. NUMBER\L.T/DAY
1 j
i
\ I
-
-
-
-
-
-
-
-
-
2
__
-
^"8
; "
-
i
- ; -
"
-
-
-
;
-
TYPE OF PROCESS AND NUMBER*6'
OF PLANTS USING EACH PROCESS
A
1
8
/
j
_ t
i
.
';
-
-
-
; I | 400
- -
-
-
-
-
It.O
_
-
-
i
i
I
-
-
Z
-
a-f
-
-
61.0 I
-
-
- I
~ I '
t,H).Y (64
I
/
1
I
2.
1
1
C
1
1
1
1
1 1
\ 1
1
1
1
2.
4+ *
t
;
\
D
E \OTHEK
1
j
'(
no
zt
I
It
if
NOT
AVAIL.
1
,
21
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
NOTES FOR NATURAL GAS PROCESSING PLANTS
Notes:
(a) Processes
A. Absorption.
B. Refrigerated Absorption.
C. Refrigeration.
D. Compression.
E. Adsorption.
F. Sulfur Recovery (Process Unknown).
G. Fractionation.
H. Cryogenic.
J. Turboexpander
(b) Some plants use more than one process; therefore, the number of plants
may be less than the total number of processes.
(c) Not available.
(d) The rate was not reported for one or more plants. The amount shown is
total for those plants reported.
(e) Feed stream is from another natural gas plant.
(f) Reference: 3.
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
APPENDIX B - METHODS FOR SAMPLING AND ANALYSIS
OF WASTE GASES FROM PETROLEUM PROCESSES
44
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
APPENDIX B
LIST OF METHODS FOR SAMPLING
AND ANALYSIS OF WASTE GASES
FROM PETROLEUM PROCESSES
1. Hydrocarbon Evaporation Losses from Oil and Water Separation Processes -
API Method 754-60. (Reference 56).
This analysis measures total hydrocarbon loss, and does not identify
specific compounds. There are no interferences. Two methods are described:
ja. Method A, "Gravity Difference Method" has a precision of +_ 10 percent
of mean.
b_. Method B, "ASTM (Engler) Distillation Method." Precision is not
reported.
2. Hydrocarbons in the Atmosphere. "Mass Spectrometer Freeze-out Method,
API Method 766-58." (Reference 56).
Determines hydrocarbons from C2 through CIQ in a sample from the atmosphere
when the concentration is 0.1 ppm to 100 ppm. Nitrous oxides interfere.
Precision: For a sample containing 34.5 ppm of C-j, 64 and C$ hydrocarbons,
the standard deviation was 5.75 ppm with a spread of 17.5 ppm.
3. Nitrogen Oxides in Gaseous Combustion Products. "Phenoldisulfonic Acid
Method. API Method 770-59." (Reference 56).
Two methods are given.
&. "Peroxide Method," for N02 from 5 ppm to several thousand ppm. Organic
nitrates, nitrites and organic nitrogen compounds interfere. S0£ may
interfere. Accuracy is + 3 percent up to 500 ppm, greater than +
3 percent above 500 ppm.
b_. "Permanganate Method," for N0£ 20 ppm to several thousand ppm. Pre-
cision and accuracy + 10 percent in range, 20 ppm to 1200 ppm nitrogen
oxides.
45
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
4. Hydrogen Sulfide.
a. "Tutweiler Apparatus Method, API Method 771-54." (Reference 56).
Determines I^S concentration from 0.05 percent to 10 percent by
volume. Mercaptans interfere. Precision is 0.2 ml of titrant.
(Note: About 9 ml of titrant is used for each percent H2S in sample).
b_. "Ammoniacal Cadmium Chloride Method, API Method 772-54." (Reference 56.)
Concentration range and interferences are not given. Precision,
+ 10 percent of mean.
5. Hydrogen Sulfide and Mercaptans. "Electrometric Titration Method, API
Method 773-54." (Reference 56).
Any radical (e.g., bromine, iodine, or cyanide) which in alkaline solutions,
precipitates a silver salt less soluble than silver mercaptide will inter-
fere with test, as will substances capable of reducing silver ion to
metallic silver in alkaline solutions. Precision: Duplicate results by
the same operator should not differ by more than 1 percent of mean.
6. Total Sulfur Oxides. "Acidimetric Method. API Method 774-54."
(Reference 56).
Acid gases, such as hydrogen chloride, interfere. Precision: Repeatability,
2 percent of mean.
7. Sulfur Dioxide and Sulfur Trioxide. "Acidimetric Method. API Method
775-54." (Reference 56).
Acid gases, such as hydrogen chloride, interfere. Precision: Repeatability
2 percent of mean.
8. Sulfur Dioxide in the Atmosphere. "Disulfitpmecurate Method, API Method
776-59." (Reference 56).
Nitrogen dioxide interferes at concentrations greater than 2 ppm unless
special procedure, described, is followed. Precision: + 10 percent of
mean. Accuracy + 10 percent of true value.
9. Hydrocarbons.
"Flame lonization Method." Reported in Appendix E of Federal Register,
Vol. 36, No. 21, Saturday, January 30, 1971, Pages 1512-1513.
46
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
APPENDIX C - CRUDE OIL PRODUCTION IN UNITED STATES
47
-------
N10P
Job.
location
Subject .
E.P. A.
DURHAM, N.C.
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING
AND RESEARCH
File Mo 034) O
C defied by _
No
Dal*.
CINCINNATI
NEW YOIK Compiled ^
.T.
CRUDE PETROLEUM PRODUCED IN UNITED STATE'S
QUANTITY: THOUSAND BARRELS FOR VEAF?
STATE
ALABAMA
ALASKA
ARIZONA
ARKANSAS
CALIFORNIA
COLORADO
FLORIDA
ILLINOIS
IND/ANA
KANSAS
KENTUCKY
LOL//5/ANA
MICHIG-AM
MISSISSIPPI
MI550U/?!
MONTANA
NEBRASKA
NEVADA
NEW MEXICO
NEW YORK
NORTH DAKOTA
OHIO
OKLAHOMA
PENNSYLVANIA
1966*
8,030
14,358
132
Z3,824
345, 275
33,472
1,71?
61,66 1
10,6/7
1 03, 73B
18,016
674,3/8
14,273
53Z27
17
35>380
13,850
307
f £4,154
1,735
27,/26
1 0,811
/
4,337
,1*7>
7,348
27,I2£
2,124
2J,075
357,2/7
33,705
1,568
5^/42
10,081
11,iOO
1 5,535
774,527
13,664
57,147
15
34,757
13,373
277
12^,144
l,f7Z
25^3/5
%724
230,747
4,387
a
66,204]
»1,464
/,474
JOS'
14, OJ6j
8J7.426J
I2y174
$8,10S
95
27!
128,550
1,5-32
25,0f0
223,623J
73y753
2433
18,047
37-JTZ1/
50,724i
7,841
88,7/6
12,2/3
64,283
£7
223
27,227
\°no
Z2703
1^772
224,727
___ 4^446
7,263
1,784
?8,035
24,723
43,747
7,487
5-75"
37,87?
H,45/
/47
12^/84
*, 108
223^574)
ESTIMATE
6,400
365;00rf\
t,000
65", 000
8,000
1,000,000
10,000
7S,000\
5VOOO
\0,000\
wo\
70O
2.2*,000\
4.QOOJ
-------
109
Job
E.PA.
PROCESSES RESEARCH, IMC. F.I. NO 034 ) Q <,.... Nn O2.
........
Subject
INDUSTRIAL PLANNING
AND RESEARCH
Checked by
CINCINNATI
NEW YORK Computed by.
& N .T
.Date.
Date
CRUDE: PETROLEUM PRODUCED IN LIMITED STATES
C?UAN7lTY.' THOUSAND BARRELS FOR YEAR
STATE
SOUTH DAKDTA
TENNESSEE
TEXAS
UTAH
V/RG-IW/A
WEST VIRGINIA
US. fOTAL
131
7
1,057,70$
I
3,027763
,
1167
2//
7
3,215742
787
), 133,380
23,504
3i
3,3/2 3,
,.111250 ]?\
158
32
1 3^7 /, VI
I6O
307
1,2+1,617
23,370
3/24
,/fP/3L?5
3,^7/fTfl
I 1 7JT
E5TIMATF
300
(300,000
2.3,000
2^00
A
b
c
TABLE 3, PAtl 6, REFCRENCF 3*?
TA BLE 3y PA6E 7, /?EFEf? E N C E 33
TA0LE 3y P/»CE 7, REFERENCE 28
EST/NATE5 SA5EO 0N TRENP OF DATA
A9
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
APPENDIX D - MARKETED PRODUCTION OF
NATURAL GAS IN UNITED STATES
50
-------
Job
E.P.A.
PROCESSES RESEARCH, INC. F.I. NO
NC.
Subjtd
INDUSTRIAL PLANNING
AND RESEARCH
CINCINNATI
NEW YORK
_.Sheet No P" /
Dale
Checked by
Computed hy & N.T. Dale D'2.0
J172
MARKETED PRODUCTION! OF NATURAL £AS /NUN/TED
MILLION CUBIC FEET PER DAY
STATE
ALASKA
ARKANSAS
CALIFORNIA
COLORADO
ILLINOIS
KANSAS
KENTUCKY
LOUISIANA
MICHIGAN
M/S5|S5/PPI
MONTANA
NEBRASKA
NEW MEX/C0
NEW YORK
NORTH DAKOTA
OH/ 0 '
OKLAiHOriA
PENNSYLVANIA
TEXAS
UTAH
VIRGINIA
WE5T WfffrJWIA
Wy0MIN£
OTH|RS
TOTALS
1166*
2.1
Z16
1,1 65
3 16
17
2,322
116
) 3 ^f 7
I OS
3S/
11
E7
2,770
6
1 /£.
1 IS
3,315
2.16
1 1, / 65
1 44
8
585
7/5"
&
^t £" fb A ^
^i ^F 23 t^
1167*
40
3 11
Iy866
320
14
2,3*1
244
J5,f 64
12
382
7*
23
2>ia5
I)
/01
1/3
3,8 7/
246
11,617
J34
\0
571
65«
7,
ti?*4
1168*
47
428
332
12
2, 2 03
24J
17, 530
i 1 1
36T
53
22
3,1 8 /
13
1 12
1 17
3,000
240
20,478
126
1
647
671
6
52J12
1161*-
139
464
1,857
325
10
2.420
223
11,802.
11
36(7
1 13
11
3,1 IS
13
12
136
4,175
2.17
2.1,5/6
126
8
635
832.
5"
5*6,708
/
zro
J 0
2,r00
z/
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
APPENDIX E - PROCESS FLOW SHEETS
52
-------
WET
GAS
WELL
01L
WELL
502.
A
cc
z>
o
ACID-G-AS
TREATING
FIELD
5EP/A RA
TION
CLAU5
SULFUR
UNIT
5ULFUR
t>
c
£LYC0LS
- O
z m
o
NATURAL G-AS
DRATION
(TO 5ALE\5)
ETHANE
TI0N
BUTANE5
NATURAL
CRUDE OIL
(TO REFIMERY)
'PROCESSING- 5TEP5 FOR THE PRODUCTION!
OF CRUDE OIL ANO PURIFIED -IN>ATURAL GAS FROM
OIL WELLS AND WET G-AS WELL5
O
vw
O
N
-------
01
SOUR
DRY
GAS
WELL
..
.--*
S
y
\
/\CIO-G-^5
TREATING
H.
,5'
I ra
REMOVAL
^
SWEET.
~-T.
>*
,
DRY
G-AS
WELL
i
1
5C?
i
VI 2. 3 **" ^^^~
^*
\
CLAUS
SUL
FUR
UNIT
2. **
SULFUR
-^,
-^
|
?
rn
T)
NATURAL GAS (.TO SALES) ? -I
. V ^_ z z m
\
r
j
>^_
-^
CrA
y
r
5
DEHY-
DRATION
\ 1
«^
G-/^
^
.
5EP/\RA-
T/ON
***~ * o u»
5 »- m
°» f>
i/» 1*1
s» 5
c,* * I.
*^ -.^
o 2
"
PROCESSING- STEPS FOR PURIFICATION OF NATURAL 6-A5
FROM DRY (SAS WELLS
H
N
-------
109
Job
E.P.A.
DURHAM, N.C.
Subied
PROCESSES RESEARCH, INC. m* NO
INDUSTRIAL PLANNING
AND RESEARCH
CINCINNATI
NEW YORK
No "
Checked by Dale
Computed hy
-------
100
Job..
loca
N.C. i
i i
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING
! AND RESEARCH
NO 034'fjP
ier ked
..Sheet No -"
-------
DL/frHAH
PROCESSES RESEARCH, INC.
INb/USTRI&l PUNNING
AND RISEARCh
C INC IN*AT I
YORK
file No O3+IO
Checked fay
Computed by .
lOOf*
INLBT
SEPARAJOR
£4
NATURAL GAS PR0CE55 "0"
REFRIGERATED ABS0RPTI0N PR0CES5
57
-------
« I09|
lab
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PROCESSES RESEARCH, INC.
fin NO 034<<^ u»t NO E'6
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NATURAli ..GA5. P
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RO
NATURAL :c;/ASOLll
U _ M
58
-------
lob
Subject
, N.C.
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING
AND RESEARCH
CINCINNATI
NEW YORK
File Mo 054 \O
>
5
^
O
LOW SI
*
^4 A"
^V v
'AGE £AS0t/N
(TO
^.Ls
COMPRESSOR
-4
NATURAL £A5 PROCE55 "
P80CE55
-------
Subject
PROCESSES RESEARCH, INC.
INDUSTRIAL PUNNING
AND RESEARCH
Fit. Na 034/O " ON STREAM .AND ADSORBER "8" ON
REG-EN ERATI ON.
REFERENCE,
NATURAL ^AS PROCESS t
AD50/?PTION PROCE55
60
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
APPENDIX F - EMISSIONS CONTROL PROCESS FLOW SHEET
61
-------
N>
rn
3
Cn
OU
^) -
C^>
D 2
ni
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
APPENDIX G - STATE AIR POLLUTION LAWS AND REGULATIONS
Table G-l Government Agencies Authorized by State
Law to. Enact and Enforce Air Pollution
Control Regulations
Table G<~2 State Air Pollution Control Regulations
63
-------
TABLE G-l
tob
£PA
locttio*
Svbiccl .
DURHAH MC.
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING
AND RESEARCH
CINCINNATI
NEW YORK
File No
Checked by
Computed b
GOVERNMENT A6EUCIES AUTHORISED
BY STATE LAW 7"0 ENACT AND ENF-ORCE
AlFt POLLUTION CONTROL
STATS'
ALABAMA
ALAS HA
ARIZONA
ARKANSAS
CALIFORNIA
COLORADO
F LOR 10 A
ILLINOIS
INDIANA
KANSAS
KENTUCKY
\ LOUISIANA
\ MICHIGAN
MISSISSIPPI
MISSOURI
MONTANA
NEBRASKA
HEVA9A
HEW MEX/C0
NSW YORK
NORTH DAKOTA
OHIO
OKLAHOMA
1 DAT£-
LATEST
MENTts)
1171
1171
1170
\i cr
1 171
H7f
11*1
1170
1170
1161
tier
Il7i
I17Z
11(7
1172-
ini
ini
1171
117V
STATE
X
X
X
X
-------
U(
Su
DVftHAFt, /VC. '
»jo« 1 / i ur i i
1 CINCH
G-OVEftriMENT AG-Efr
BY STATS: LAW TO
NDUSTRIAl PUNNING
AND RESEARCH
4NATI NEW YORK
1CIES AUTHOR
Checked hy Dji»
Computed by ~2Y
IZEO
ENACT AND ENFORCE
AIR POLLUTION CONTROL REGULATIONS
STATE
PEW/v'5Ytkfl/v//i
SOUTH DAKOTA
r£WA/£55£T
rrx/4s
UTAH
VIRGINIA
WEST VIRGINIA
WY0M/NS-
DATE-
LATEST
EHACT-
1169
1171
1171
1171
'
I16/ \
I 9*7
] }
1 AGrCMCr \
i
,
STATB
CITIES COUNTIES
f TOWNS
\
X
X
X
X
X
X
X
X
X
X
X
X
^ (?^
X
*
y
X
X
!
REGIONS )
<
-,-, , . i
I
.
!
!
i
!
j
65
-------
PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
NOTES
(a) Reference 54.
(b) Counties or districts of counties enact and enforce regulations; these
to be equal to or more restrictive than criteria established by State.
(c) State established districts for basis of establishing regulations.
(d) Cities may not have enforcement program in counties that have a program.
(e) Counties with population greater than 100,000 must establish air pollution
control. Counties with less than 100,000 population may establish program.
State regulates emissions in counties with no regulations.
(f) State Control Bpard may delegate enactment and enforcement responsibilities
to local units.
(g) State Board may establish control districts, the.regulations of a control
district supersede any other local regulations in that district.
66
-------
TABLE G-2
STATE AIR POLLUTION CONTROL REGULATIONS <
Page 1
STATE
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Florida
Illinois
Indiana
Kansas
MAXIMUM
EFFECTIVE NONMETHANE
DATE OF HYDROCARBONS
REGULATIONS CONCENTRATION
January 1972 AAQS
(d) (d)
AAQS
80 ug/m3 (e)
January 1972 (d)
(d) (d)
(d) (d)
February 1972 AAQs(b)
160 pg/m3
(d)
(d)
VISIBLE EMISSIONS
MAXIMUM SMOKE
CONCENTRATION
(d)
(d)
(d)
Existing units:
Rlngelmann - 2
New units:
Rlngelmann - 1
(d)
Existing units:
Ringelmann - 2
until July 1, 1972
then Ringelmann-1
New units:
Rlngelmann - 1
(d)
Rlngelmann - 2
(d)
BURNING OF
PETROLEUM
WASTES
(d)
(d)
Open burning is
prohibited
Open burning of waste
hydrocarbons is per-
mitted at remote
locations under
certain conditions ("
(d)
Flaring of waste
gases is permitted
if visible emis-
sions are not
exceeded
Open burning of
waste gases is per-
mitted, if no air
pollution results
(d)
(d)
MAXIMUM EMISSIONS RATES AND GROUND
S02
Sulfur recovery plant emissions^
Existing: 0.16 Ib (S02)/lb SCC)
(d)
Ground level concentration:
50 ng/m3(e) annual average
150 ug/m3(e) 3-day average
250 ug/m3(e) 24-hour average
850 jig/mXe) 1-hour average
Emissions: 0.20 ppm
AAQS<">
0.5 ppm; 1-hour average
0.04 ppm;. 2-hour average
(d)
Sulfur recovery plant emissions
New: 0.004 Ibs S02/lb sulfur
Existing: Same as for new
by July 1, 1975
Emission: 2,000 ppm
(d)
AAQs(b>
43 >ig/ni3(*' annual geo. mean
215 pg/m3'6' 24-hour average
not to be exceeded by more
than 1 sample/3 months
1001 ug/m3(*) 1-hour average
never exceeded
LEVEL CONCENTRATIONS
H2S & MERCAPTANS
(d)
(d)
(d)
(d)
AAQS
H2S: 0.03 ppm,
1 hour
(d)
(d)
H2S or mer cap tans:
0.65 Ibs in any
5 minutes
(d)
(d)
-------
TABLE G-2
STATE AIR POLLUTION CONTROL REGULATIONS 1.5 pal):
Tank > 40, 000 gala
to be totally enclosed,
floating roof or have
other emissions control
901 efficient vapor
recovery required for
20,000 gal/day tank
loading station
Louisiana January 1972 AAQS^ ' ,, . Volatile organics Smoke from flares:
160 ps/<^ (V.P.> 1.5 psi): Ringelmaon - 2
3 hours, 6-9 AM Tanks? 40,000 gals
must have vapor
emissions control
device
00 Michigan 1967 (d) (d) Ringelmann - 2
Miasisaippi May 1970 (d) (d) AAQS
10 grains/100
cubic feet
All process gas
streams containing
sulfur compounds
must be flared or
burned
(d)
(d)
Ambient air concen-
tration: H2S
0.03 ppm by vol. In
30 minutes exceeded
less than 2 times In
5 days, or 0.05 ppm
by vol. In 30 minutes
2 times/year maximum
(d)
Nebraska
(d)
(d)
(d)
(d)
(d)
(d)
(d)
-------
TABLE G-2
STATE AIR POLLtmOB CONTROL REGULATIONS(a)
Page 3
STATE EFFECTIVE
DATE OF
REGULATIONS
Nevada February 1972
New Mexico March 1972
New York February 1967
North Dakota (d)
Ohio February 1972
Oklahoma As noted
MAXIMUM
NONMETHANE
HYDROCARBONS
CONCENTRATION
AAQs(b)
160 ug/m3*6) 3 hour
6 AM to 9 AM
AAQS
0.19 ppm, 3 hour
average
(d)
AAQS
160 Bg/m3(e>; 3-hour
6 AM to 9 AM
AAQS(b)
126 jig/m3*6'
3-hour arithme-
tic mean
6 AM to 9AM
331 Hg/m3(e'
24-hour arithme-
tic mean 1 day per
year max.
(d)
EMISSIONS CONTROL
REQUIRED FOR
VOLATILE ORGANICS
TANKAGE & TRANSFER
Tanks 40,000 gallons
and larger must be
totally enclosed, have
floating roof, or
emissions control. Tanks
less than 40,000 gallons
to have emissions con-
trol where feasible
(d)
(d)
Tanks 65,000 gallons
and larger must be
totally enclosed or
have floating roof or
other emissions control.
Loading facilities
handling 20,000 gals
per day require sub-
merged fill lines or
other controls (above
for new only)
(d)
Regulation 15, effec-
VISIBLE EMISSIONS,
MAXIMUM SMOKE
CONCENTRATION
Emissions:
Opacity 201
Ringelmann - 1
Ringelmann > 1 for
<1 minute in 30
minutes. Oil
well drilling rigs
and oil well ser-
vice rigs are
excluded
Emissions:
New sources,
Ringelmann - 1
Existing sources,
Ringelmann - 2
Emissions:
Existing sources,
Ringelmann - 2
New sources,
Ringelmann - 1
Emissions, any
stationary source,
Ringelmann - 1
compliance by
July 1, 1975
All sources;
BURNING OF
PETROLEUM
WASTES
Open burning pro-
hibited, except by
special permit
Open burning per-
mitted for gas
wastes at compres-
sor stations and
oil and gas wells
when necessary for
safety
(d)
Open burning per-
mitted^'
No organic compounds
emissions except
blowdown. and emer-
gency relief unless
burned in smokeless
flare
Open burning is
prohibited. Waste
hydrocarbon gas
streams except emer-
gency reliefs must
be flared
Open burning is per-
MAXIMUM EMISSIONS RATES AND GROUND
S02
AAQS
SOx as equivalent S02
60 jig/m3Ce) annual arithmetic mean
260 ug/m3(e) max. 24-hour cone.
1300 ug/m3(e) max. 3-hour cone.
AAQS
0.10 ppm max. 24- hour average
0.02 ppm max. annual arithmetic
mean
AAQS(b>
0.10-0.15 ppm(b) 24-hour average
0.25-0.40 ppm"' 1-hour average
No emissions regulations for SO2
are listed. Emission limits
may be established if AAQS
H2S, 0.10 ppm,
1-hour average
Waste gases containing
H2S must be burned or
treated before release
AAQS(b>
H2S; 45 ug/m3(e)
30 minutes cone.
not exceeded> 2 tlmes/5
days. 75 ug/m3(e)
30 minutes cone.
not exceeded > 2 times
H2S emissions in excess of
100 grains per 100 scf.
Must be removed before
venting or burning
(d)
tlve July 1, 1972
limits emissions from
the lease atmospheric
crude oil stock tank
to 1.5% of stock tank
volume or 25 cubic feet
per barrel of stock
tank oil
Ringelmann - 1
(effective April 15,
1971; compliance
by October 15, 1972)
mitted in isolated
areas for spilled
oil where other dis-
posal means are not
available
(effective January 1,
New: SO, as S02 20 Ibs/ton of
sulfur
-------
TABLE G-2
STATE AIR POLLUTION CONTROL REGULATIONS
(a)
Page 4
STATE EFFECTIVE
DATE OF
REGULATIONS
Pennsylvania March 1972
South Dakota (d)
Tennessee January 1972
MAXIMUM
NONMETEANE
HYDROCARBONS
CONCENTRATIONS
(d)
(d)
AAQS
Primary & secon-
dary
160 ug/m3*6'
3-hours AM
EMISSIONS CONTROL
REQUIRED FOR
VOLATILE ORGANICS
TANKAGE & TRANSFER
Tanks larger than
40,000 gallons for
organic liquids with
V.P. of 15 psla or
higher must be pressure
tight or have other
emissions control-
Loading facilities
loading 20,000 gals
or more per day must
have vapor recovery
(d)
(d)
VISIBLE EMISSIONS
MAXIMUM SMOKE
CONCENTRATION
Opacity:
201 for period or
periods up to 3
minutes In any
hour
(d)
Emission,
Rlngelmann - 1, for
new sources as of
August 9, 1969, and
and existing sources
by August 9, 1973
BURNING OF
PETROLEUM
WASTES
Open burning; for-
bidden in any air
basin; permitted
elsewhere, with
restrictions
(d)
Open burning of
waste hydrocarbons
from oil production
or pipeline breaks
at remote sites Is
permitted
MAXIMUM EMISSIONS RATES AND GROUND LEVEL CONCENTRATIONS
S02 H2S & MERCAPTANS
Sulfur recovery plant emissions AAQS^
expressed graphically; I.e., H2S, 0.005 ppm, 24-hour
0.1 Ibs S0?/ton sulfur for 10 ton/ 0.10 ppo. 1-hour
day plant and 0.001 Ibs SOz/ton W-. »-"
sulfur for 100,000 tons/day plant
Other source emissions
SOx as S02 500 ppa vol.
(d) (d)
Process emissions, S02 (d)
Existing: 2,000 ppm; by August 8,
1973. 500 ppm; by July 1,
1975. --
New: 500 ppm
Texas
As noted
(d)
Tanks for crude oil
are exempt from
emissions control
(Effective Dec. 31,
1973)
No visible emissions
from waste gas
flares for more
than 5 minutes In
any 2-hour period
(Effective Dec. 31,
1973)
Open burning of waste
petroleum from ex-
ploration, develop-
ment, or production
Is permitted at
remote sites
(Effective Jan. 1967)
(d)
(d)
Utah January 1972 AAQs(b>
160 ug/m3 3-hour
6 AM to 9 AM
Primary and second-
ary standards
Virginia March 1972 AAQS^
Primary and second-
ary, 160 ug/mJW
3-hour 6 AM to 9 AM
(d) Emissions
Existing sources:
Rlngelmann - 2
New sources:
Rlngelmann - 1
Controls required Emissions:
only In areas where All sources
board designates Rlngelmann - 1
excessive photo-
chemical oxldant
levels exist
Open burning, (1)
not permitted
Open burning not per- Sulfur recovery plant emissions
mitted. Hydrocarbon Existing: 8,000 ppa(J)
emissions, except
accidental or emer-
gency, must be burned
In smokeless flare
(d)
Emission:
H2S: 15 grains/ 100
cubic feet
West Virginia As noted
AAQS
Effective September,
1971. Primary and
secondary
160 ug/m3
3-hour 6 AM to 9 AM
(d)
(d)
Open burning not
permitted
(Effective Septem-
ber 1969)
Sulfur recovery plant emissions
0.06 Ibs S02/lb sulfur processed
by June 30, 1975
Other sources: 2,000 ppm vol
by June 30, 1975
H2S; 50 grains per
100 cubic feet by
June 30, 1975
-------
TABLE G-2
STATE AIR POLLUTION CONTROL REGULATIONS <
Page 5
STATE
Wyoming
EFFECTIVE
DATE OF
REGULATIONS
February 1972
MAXIMUM
NONME THANE
HYDROCARBONS
CONCENTRATION
AAQS
Primary and Second-
ary, 160 ug/m3
3-hour 6 AM to 9 AM
EMISSIONS CONTROL
REQUIRED FOR
VOLATILE ORGANICS
TANKAGE & TRANSFER
(d)
VISIBLE EMISSIONS
MAXIMUM SMOKE
CONCENTRATION
Opacity:
New Sources. 201
existing sources
401
BURNING OF
PETROLEUM
WASTES
Open burning
prohibited,
except by special
permit
MAXIMUM EMISSIONS RATES AND GROUND
S02
AAQS^ H2S
60 /ig/n>3(e) annual arithmetic mean
260 pg/m-H6) max. 24-hour cone.
1 year max.
1,300 ;ig/m3
70 /ig/mXe) 30 minute
average 2 times/year max
40 /ig/m3(e> 30 minute
average 2 times/ 5 days
maximum
(a) Reference 54.
(b) Ambient Air Quality Standard.
(c) Pounds of sulfur as equivalent S02, per pound of sulfur processed or produced.
(d) Not reported In reference.
(e) Mlcrograas per cubic meter.
(f) Open burning Is permitted at the site of origin of waste hydrocarbons from oil exploration, development, or production or from natural gas processing plants or
materials spilled or lost from pipeline breaks where, because of Isolated location, such waste products cannot be reclaimed, recovered or disposed of lawfully
In any other manner.
(g) A permit is required froa the local air pollution control regulatory agency for open burning.
(h) Value differs for each of five air quality areas.
(1) New Instillations with a potential to emit sulfur oxides greater than 250 tons of sulfur per year, as gas or mist, shall install controls to limit discharge to
less than 20 percent of input sulfur.
(J) Regulations also contain a table of mass emission rates based on sulfur production capacity.
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
APPENDIX H - BIBLIOGRAPHY
72
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
BIBLIOGRAPHY
1. Uthlaut, G. E., "Jay Field Developed fast Despite Unique Problems", Oil & Gas
Journ., 70 No. A3; pgs 66-71, (Oct. 30, 1972).
2. Farrar, G. L., "Sun Plant Removes Sulfur from Jay Crude and Gas", Oil & Gas
Journ.. 70 No. 39; 98-100, (Sept. 25, 1972).
3. Cantrell, A., "1972 Survey of Gas-Processing Plants", Oil & Gas Journ.,
70 No. 28; 92, 94, 96, 98, 101-102, 104, 106-107, 110-112, 114-118, 120-121,
124-125, (July 10, 1972).
4. Anon., "Where are the Reserves Around the United States?" Oil & Gas Journ.,
70 No. 5; 95-96, 100, (Jan. 31, 1972).
5. "International Petroleum Encyclopedia 1972", The Petroleum Publishing Co.,
Tulsa, Oklahoma.
6. Anon., "Sulfur Signs Shifting", Chemical Week: 18. (Dec. 1, 1971).
7. Anon., "Alberta's Sulfur Stockpiling Program is Dead", Chemical Week; 23,
(Nov. 24, 1971),
8. Buckingham and Roman, "Sulfur and the Energy Industry", Hydrocarbon Processing,
50 No. 8; 121-124, (Aug., 1971).
9. Anon., "1971 Survey of Gas-Processing Plants", Oil & Gas Journ., Vol. 69
No. 28; 78-80, 83-102, 104, 106, 110, 112, 114, 117, 118, (July 12, 1971).
10. Barthel, et al, "Treat Glaus Tail Gas", (I.F.P. Process) Hydrocarbon Process-
ing. Vol. 50 No. 5: 89-91, (May 1971).
11. Henderson and Cox, "Drill High-Concentration H2S Gas Wells Safely", Oil & Gas
Journ.. Vol. 69 No. 15: 57-61, (April 12, 1971).
12. Wall, J., "NG/SNG Handbook", Hydrocarbon Processing. Vol. 50 No. 4: 93-122, .
(April 1971).
13. Gittinger, L. B., "Sulfur", Engineering/Mining Journ.. :133-136, (Mar., 1971).
14. Beavon, "Prevention of Air Pollution by Refinery Sulfur Plants", presented at
the Japanese Petroleum Inst., (Feb. 26, 1971).
15. Winton, J. M., "Dark Cloud on Sulfur's Horizon", Chemical Week. :25-27, 30-32,
34, 36, (Feb. 10, 1971).
73
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
16. "Petroleum Facts and Figures 1971", pages 76-85, American Petroleum Institute,
Washington, D. C.
17. "Crude Oil Pipe Line Map of the United States and Southern Canada, Fifth
Edition, January 1, 1971", American Petroleum Institute, Washington, D. C.
18. "Products Pipe Line Map of the United States and Southern Canada, Fifth
Edition, January 1, 1971", American Petroleum Institute, Washington, D. C.
19. "Statistical Abstracts of the United States 1971, 92nd Annual Edition",
U. S. Dept. of Commerce, Bureau of Mines.
20. "Texas Oil and Gas Conservation Laws: Title 102 Revised Civil Statutes of
Texas", Railroad Commission of Texas, January 1971.
21. Richards, J. D. and Swanson, T.C., "Anadarko Basin, Buffalo Wallow Field r-
Operation of Deep Gas Wells and Gathering System Serving Them", presented at
SPE of AIME Central Plains Mtg., Preprint No. SPE-3170, 1970.
22. Anon., "Hugoton-Andarko Gas Prices Boosted", Oil & Gas Journ., Vol. 68
No. 37: 33-34, (Sept. 28, 1970).
23. Wilson, H. M., "Alaska Outlook: Great - but Frustrating", Oil & Gas Journ.,
Vol. 68 No. 30: 103-140, (Aug. 10, 1970).
24. Swing, R. C., "New Gas Processing Plant on Stream", Oil & Gas Journ., Vol. 68
No. 28: 91-93, (July 13, 1970).
25. Frazier, "How's the Sulfinol Process Working?", Hydrocarbon Processing, Vol. 49
No. 4: 101-102, (April 1970).
26. Parrish, R. J., "How Humble Produces King Ranch Reservoirs", Oil & Gas Journ.,
Vol. 68 No. 2: 54-58, (Jan. 12, 1970).
27. Rosenzweig, M. D., "Cryogenics for Natural Gas Extraction/Fractionation, Process
Flowsheet", Chem. Eng.. 77: 74-76 (Jan. 12, 1970).
28. "Petroleum Statement Annual: Petroleum Products and Natural Gas Liquids, 1970
(Final Summary)," Mineral Industry Surveys, U. S. Dept. of Interior, Bureau
of Mines.
29. "Mineral facts and Problems, Bulletin 650", U. S. Dept. of Interior, Bureau of
Mines, 1970 edition.
30. Bleakley, W. B., "Shell Production Complex efficient, controls Pollution",
Oil & Gas Journ.. Vol. 67 No. 36: 65-69 (Sept. 8, 1969).
74
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
31. Frank, W. J., "Engine Exhaust Economically Sweetens Injection Water", World
Oil. :79-80, 83, 86, (March, 1969).
32. Frank, W. J., "Removal of H2S and C02 from Injection Water by Hydrocarbon
Gas Cycling Process", J. Pet. Tech., Vol. 21 No. 2: 163-166, (Feb., 1969).
33. "Petroleum Statement Annual: Crude Petroleum Products, and Natural Gas Liquids,
1968 (Final Summary)", Mineral Industry Surveys, U. S. Dept. of Interior,
Bureau of Mines.
34. Grekel, Palm, and Kilmer, "Why Recover Sulfur from H2S?", Oil & Gas Journ.,
:92-101, (Oct. 28, 1968).
35. Meredith E. Lewis, "Desulfurization and the Energy Industry", C.E.P., Vol. 64
No. 9: 57-59, (Sept. 1968).
36. Nelson, W. L., "What is Cost of Sulfur-recovery Plants?", Oil & Gas Journ.,
:111, 114, (May 27, 1968).
37. Beebe and Curtis, "Natural Gases of North America", Vol. II, pages 1966-1968,
American Association of Petroleum Geologists, Tulsa, Okla"., 1968.
38. Vanderlinde, L. G., "Stock Tank Vapor Recovery Systems", presented at
Canadian Natural Gas Process, Tech. Mtg., (Feb. 24, 1967).
39. "Petroleum Statement Annual: Petroleum Products, and Natural Gas Liquids, 1966
(Final Summary)", Mineral Industry Surveys, U. S. Dept. of Interior, Bureau
of Mines.
40. Stormont, D. H., "U. S. Refiners' Sulfur Output Soaring", Oil & Gas Journ..
:84-85, (Aug. 1, 1966).
41. Lieb, H. P., "4 New Ideas in Vapor Recovery Systems", World Oil. :164-167,
July, 1966).
42. Lieb, H. P., "Methods of Vapor Recovery in the Permian Basin", presented at
Spring Mtg, Southwestern Dist, Div. of Production, API, Paper No. 906-11-L,
(Mar. 16-18, 1966).
43. Bleakley, W. B., "Gas Processing, Vapor Recovery Ease Shell's Montana Problems",
Oil & Gas Journ.. pgs 108-110, (Dec. 13, 1965).
44. Bleakley, W. B., "Vapor Recovery Increases Profits in West Texas", Oil & Gas
Journ.. Vol. 63 No. 12: 78-80, (Mar. 22,.1965).
45. "Mineral Facts and Problems, Bulletin 630", U. S. Dept. of Interior, Bureau
of Mines, 1965 edition.
75
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
46. Miller and Norrell, "Analysis of Natural Gases of the United States 1961",
Information Circular 8221, U. S. Dept. of Interior, Bureau of Mines,
1964.
47. "Journal Survey of Natural-Gasoline Plants in the United States", Oil & Gas
Journ.. 58, No. 18: 108-112, 114, 116, 118, 120-122, 123-125, 127-130, 132-
137, 139, (May 2, 1960).
48. Anon., "Operators Handbook for Gasoline Plants, Part I", Petroleum Refiner,
Vol. 38 No. 5: 155-160, (May 1959).
49. Katz, D. L. et al., "Handbook of Natural Gas Engineering", McGraw-Hill Book
Company, Inc., N. Y., N. Y., 1959.
50. Noel, H. M., "Petroleum Refinery Manual", Reinhold Publishing Corporation,
New York, N. Y., 1959
51. Banner, W. E., "Two-Stage Distillation and Two-Stage Reabsorber System",
Oil & Gas Journ., pg 85-87, (Dec. 12, 1955).
52. Kohl and Blohra, "Technical Aspects of Glycol-Amine Gas Treating", Petrol.
Engr.. Vol. 22 No. 6: C37-8, 40-42, 44, (June 1950).
53. Huntington, R. L., "Natural Gas and Natural Gasoline", McGraw-Hill Book
Company, Inc., New York, N. Y., 1950.
54. "Environment Reporter, BNA, State Air Laws", The Bureau of National Affairs,
Inc., Washington, D. C. (Oct., 1972).
55. Bachman, W. A., and DuVal, D., "Industry has Good Year Ahead if not Sidetracked
by Politics, Economics", Oil & Gas Joum.. Vol. 70 No. 5: 81-89, (Jan. 31,
1972).
56. "Manual on Disposal of Refining Wastes, Vol. V, Sampling and Analysis of Waste
Gases and Particulate Matter", American Petroleum Institute, Division of Re-
fining, Washington, D. C., 1954.
57. "World Book Encyclopedia", Vol. 8, page 56, Field Enterprises Educational
Corporation, Chicago, 111., 1965.
58. "1966-67 International Petroleum Register", Palmer Publications, New York,
N. Y.
59. "1970 Survey of Gas-Processing Plants" Oil & Gas Journ.. Vol. 68, No. 28
:97-98, 103-106,108-111, 114-127, (July 13, 1971).
76
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PROCESSES RESEARCH, Ixc.
INDUSTRIAL PLANNING AND RESEARCH
60. Wilson, H. M., "Alaska Outlook: Great - but Frustrating", Oil & Gas Journ..
68 No. 32; 103-148, (Aug. 10, 1970).
61. Anon., "Demand Outstrips Texas, Louisiana Potential", Oil & Gas Journ.,
Vol. 70, No. 34, page 32, (Aug. 21, 1972).
62. Anon., "TRC Cutting Back Output of 40 Fields in West Texas", Oil & Gas Journ.,
Vol. 60 No. 44, page 32, (Oct. 30, 1972).
63. "Minerals Yearbook - 1969", Volume I-II, United States Dept. of Interior, Bureau
of Mines, (1971).
64. Dingman and Moore "Compare DGA and MEA Sweetening Methods", Hydro. Proc.,
Vol. 47 No. 7; 138-140 (July 1968).
65. Swaim, C. D. Jr., "Gas Sweetening Processes of the 1960*s", Hydro. Proc..
Vol. 49 No. 3: 127 (Mar. 1970).
66. Hegnar and Harris, "Selexol Solves High H2S/C02 Problems", Hydro. Proc.,
Vol. 49 No. 4: 103-4, (April 1970).
67. Buckingham, Hydro. Proc. & Pet. Ref.. 43 No. 4: 113 (April, 1964).
68. Anon., "Sweet-Gas Process Makes U. S. Debut", Chem. Eng., :166-169 (Sept. 19,
1960).
69. O'Donnel, J. P., "Pecan Island Plant has 900 MMcfd Capacity", Oil & Gas Journ..
Vol. 70 No. 38: 63-66, (Sept. 18, 1972).
70. "Characterization of Glaus Plant Emissions", Final Report, Task Order No. 2,
Contract No. 68-02-0242, Prepared for Environmental Protection Agency, Control
Systems Division, by Processes Research, Inc., (September 11, 1972).
71. Devys, J. G., "Preventing Evaporation Losses from Atmospheric Storage. Tanks",
Chem. Eng.. page 87, (March 30, 1964).
77
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
APPENDIX I - PERSONS CONTACTED FOR INFORMATION
78
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
APPENDIX I
PERSONS CONTACTED FOR INFORMATION
1. Rob Ro Hudson, Director
Research and Inspection
Railroad Commission of Texas
Oil and Gas Division
Capital Station, P. 0. Drawer 12967
Austin, Texas 78711
2. Carlton V* Hudson
Department of Conservation
Baton Rouge, Louisiana
Phone (504)-389-5161
3. J. R. Weddle
Department of Conservation
Sacramento, California
Phone (915)-455-9686
4. Don Edinger
Division of Conservation of Oklahoma Corporation Commission
Jim Thorpe Building
Oklahoma City, Oklahoma 73105
Phone (405)-521-2308
5. Jack Curry
Mississippi Air-Water Pollution Control Commission
Jackson, Mississippi
Phone (60D-354-6783
6. Don H. Baker, Jr=, Director
New Mexico Bureau of Mines and Mineral Resources
Campus Station
Socorro, New Mexico 87801
Phone (505)-835-5420
7. Carolton Homan, Chief Engineer
El Paso Natural Gas Co.
P. 0. Box 1492
El Paso, Texas 79978
Phone (915)-543-2600 Ext. 4953
79
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
8. Dr. William L. Fisher, Director
Bureau of Economic Geology
University of Texas
Box X, University Station
Austin, Texas 78712
Phone (512)-471-1534
9. Charles Harden,
Texas Air Pollution Control Board
Austin, Texas 78712
Phone (512)-475-2323
10. Dr. Daniel Miller
State Geologist
Geological Survey of Wyoming
Box 3008, University Station
Laramie, Wyoming 82070
11. Donald Basco
Wyoming State Oil and Gas Supervisor
Casper, Wyoming
Phone (307)-234-7147
12. William Wright
Arkansas Oil and Gas Commission
El Dorado, Arkansas
Phone (50D-862-4965
13. William Caplan
Petroleum Geologist
Arkansas Geological Commission
446 State Capitol
Little Rock, Arkansas 72201
Phone (501)-371-1730
14. William H. Moore
Mississippi Geological, Economic & Topographical Survey
P. 0, Box 4915
Jackson, Mississippi 39216
15. James Borthwick
Chief Engineer
Mississippi Oil and Gas Board
Jackson, Mississippi
Phone (601)-354-7104
80
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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
APPENDIX J - CONFERENCE MEMORANDUMS
81
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CONFERENCE MEMORANDUM
PROCESSES RESEARCH. INC.
NEW YORK CINCINNATI CHICAGO
W.O. 03410
Task Order No. 13
Contract No. 68-02-0242
Memo 1
Date:
Place:
Client:
Present:
Subject:
Notes by:
October 4, 1972
Offices of Processes Research, Inc.
Environmental Protection Agency
Control Systems Division
National Environmental Research Center
Richard Atherton
M. R. Jester
C. M. Jones
G. N. Thomas
Screening Report
Crude Oil Production
G. N. Thomas
Environmental Protection Agency
Processes Research, Inc.
Processes Research, Inc.
Processes Research, Inc.
Distribution: Richard Atherton - 5
Joseph A. McSorley - 2
1. Environmental Protection Agency transmitted to Processes Research, Inc., a
copy of APTIC literature search on petroleum processes.
2. EPA transmitted to PR a copy of Dun and Bradstreet computer print-out of
gas and oil producers based on SIC numbers 1311, 1381 and 2911.
3. It was decided to use the API abstracts service as provided by The Petroleum
Publishing Company, Tulsa, Oklahoma, to aid in the literature search. PR is
to determine the subject(s) to be searched.
4. PR called attention to the probability that the major source of emissions
from crude oil processing may be from tankage operated by a large number
of small operators. Searching to date has not produced information that
will quantify these losses.
5. The search has indicated 805 gas processing plants in the United States as
of January 1, 1972. Therefore, it was decided that the list of producers
would indicate the number of plants in each county and state where plants
exist and no attempt will be made to indicate the population density around
a given plant.
Memo 1-1
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PROCESSES RESEARCH, INC.
NEW YORK CINCINNATI CHICAGO
W.O. 03410
Task Order No, 13
Contract No. 68-02-0242
Memo 1
6. PR will attempt to locate and report on ten plants with good emission
control. No attempt will be made to list all plants with good emission
control.
7. It was decided that technology exists for control of emissions from gas
and oil processing. Therefore, research should be required only as it
relates to location of sources of uncontrolled emissions in producing
fields.
GNT:fj
October 9, 1972
Memo 1-2
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PROCESSES RESEARCH. INC.
NEW YORK CINCINNATI CHICAGO
W.O. 03410
Memo 2
CONFERENCE MEMORANDUM
Date:
Place:
Client:
Participants:
Subject:
Notes by:
November 6, 1972
Telephone Conversation
Environmental Protection Agency
Mr. Harris
Go N. Thomas
Screening Report
Crude Oil Production
G. N. Thomas
Texas Railroad Commission, Austin, Texas
Telephone 512-475-4519
Processes Research, Inc.
Distribution: Richard Atherton - 5
Joseph A. McSorley - 2
1. Mr. Harris stated that field venting and flaring of natural'and casinghead-
gas is restricted by Texas Penal Codes.
2. All vented burnable waste gas from, crude oil and gas production in Texas must
be flaredo
3. The Texas Railroad Commission prohibits flaring of natural gas in the field
unless it is not economically feasible to put this gas to commercial use.
4. The first no-flaring orders were issued in 1947.
5. In 1971, 0.63 percent of the nine trillion cubic feet of natural gas produced
in Texas was flared. The percent flared has been reduced year by year.
6. Mr. Harris is sending to PR a copy of the Texas Railroad Commission's regula-
tions pertaining to crude oil and natural gas production. These regulations
.contain the applicable section of the Texas Penal Codes.
<**
7. Mr. Harris stated that the operating cost for a single stage compressor is
4 to 5 cents per 1000 cubic feet of gas. If three stage compression
is required, the cost is 15 cents. If any significant length of pipeline
is required, the total cost for recovering the gas presently being flared
exceeds the market price for the gas,
GNT:fj
November 8, 1972
Memo 2-1
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PROCESSES RESEARCH. INC.
NEW YORK CINCINNATI CHICAGO
W.O. 03410
Memo 3
CONFERENCE MEMORANDUM
Date:
Place:
Client:
Participants:
Subject:
Notes by:
November 6, 1972
Telephone Conversation
Environmental Protection Agency
C. V. Hudson
G. N. Thomas
Screening Report
Crude Oil Production
G. N. Thomas
Louisiana Department of Conservation
Baton Rouge, Louisiana
Telephone: 504-389-5161
Processes Research, Inc.
Distribution: Richard Atherton - 5
Joseph A. McSorley - 2
1. The Louisiana Department of Conservation prohibits the venting of gas from
any gas well and prohibits the venting of gas in excess of 2000 cubic feet
per barrel of crude oil produced.
2. All vented gas must be flared.
3. The Louisiana Department of Conservation encourages all oil producers to
recover all gas that is economically feasible including the gas where the
costs equal the selling price. The present wellhead price for gas is
21 cents per 1000 cubic feet.
4. Mr. Hudson estimates that less than 1 percent of the gas produced in
Louisiana is flared. Most of this flaring is at offshore oil wells where
the cost of collecting is too high.
5. Louisiana gas is a sweet gas. Therefore, any S0£ produced when this gas is
flared is not considered to be a pollution problem.
GNT : fj
November 8, 1972
Memo 3-1
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PROCESSES RESEARCH. INC.
NEW YORK CINCINNATI CHICAGO
W.O. 03410
Memo 4
CONFERENCE MEMORANDUM
Date: November 6, 1972
Place: Telephone Conversation
Client: Environmental Protection Agency
Participants: J. R. Weddle California Department of Conservation
Sacramento, California
Telephone: 915-445-9686
G. N. Thomas Processes Research, Inc.
Subj ect: Screening Report
Crude Oil Production
Notes by: G. N. Thomas
Distribution: Richard Atherton - 5
Joseph A. McSorley - 2
1. California State law prohibits wastage of any natural gas. This is a
conservation measure. Flaring is also prohibited.
2. There is some bubbling loss from field tanks.
3. The gas recovery from offshore wells is probably better than for the onshore
wells.
Cf
4. The total losses of natural gas in California are probably less than 1/2 per-
cent of the total gas produced. Included in this percentage are small
quantities of gas that are collected on site and burned for tank heating or
fed as fuel to gas engines.
5. In general, most odors around crude oil processing equipment are due to poor
housekeeping, such as not cleaning up accidental spills. The Department of
Conservation is promoting better housekeeping in the oil fields, even at
isolated locations.
GNT:fj
November 8, 1972
Memo 4-1
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PROCESSES RESEARCH. INC.
NEW YORK CINCINNATI CHICAGO
W.O. 03410
Memo 5
CONFERENCE MEMORANDUM
Date: November 6, 1972
Place: Telephone Conversation
Client: Environmental Protection Agency
Participants: D. Edinger Division of Conservation of Oklahoma
Corporation Commission
Jim Thorpe Building
Oklahoma City, Oklahoma 73105
Telephone: 405-521-2308
G. N. Thomas Processes Research, Inc.
Subject: Screening Report
Crude Oil Production
Notes by: G. N. Thomas
Distribution: Richard Atherton - 5
Joseph A. McSorley - 2
1. There is no law or regulation in Oklahoma prohibiting venting or flaring of
gases from crude oil production.
2. The Division of Conservation discourages the venting of large quantities of
gas.
3. Economics usually dictate as to whether or not individual producers vent
gases.
4. The amount of gases lost or vented as reported in the Minerals Yearbook, by
the U. S. Bureau of Mines, is based on estimates by Mr. Edinger's Department.
These are the best estimates available.
5. Any additional questions should be referred to Mr. S. Shakely of the Division
of Conservation.
GNT:fj
November 8, 1972
Memo 5-1
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CONFERENCE MEMORANDUM
PROCESSES RESEARCH. INC.
NEW YORK CINCINNATI CHICAGO
W.O. 03410
Task Order No. 13
Contract No. 68-02-0242
Memo 6
Date:
Place:
Client:
Present:
Subj ect:
Notes by:
December 5, 1972
Offices of Processes Research, Inc.
Environmental Protection Agency
Richard Atherton
M. R. Jester
C. M. Jones
G. N. Thomas
Screening Report
Crude Oil Production
G. N. Thomas
Environmental Protection Agency
Processes Research, Inc. (Part-time)
Processes Research, Inc.
Processes Research, Inc.
Distribution:
Richard Atherton - 5
Joseph A. McSorley - 2
1. Very little information has been obtained regarding hydrocarbon emissions.
PR can provide only a rough estimate. Mr. Atherton will advise PR on Thursday,
December 7, 1972, if such an estimate should be attempted.
2. The flaring of gas and the emissions of hydrocarbons have been drastically
reduced, in recent years, in the oil fields because the1 producers have found
that it is to their economic advantage to recover gas that-formerly was
wasted.
3. PR indicated that air pollution control regulations have not been obtained
for some of the states or from any local unit of government. EPA will send
any local regulations they have.
4. No new information has been obtained on SC>2 or H2S emissions from crude oil
production for the six states that have most of the sour gas in the United
States. Two articles present information that permits the estimation of S02
emissions in the Jay Field in Florida.
GNT:pm
December 6, 1972
Memo 6-1
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PROCESSES RESEARCH. INC.
NEW YORK CINCINNATI CHICAGO
W.O. 03410
Task Order No. 13
Contract No. 68-02-0242
Memo 7
CONFERENCE MEMORANDUM
Date: March 19, 1973
Place: Telephone Conversation
Client: Environmental Protection Agency
Participants: J. Walters American Petroleum Institute
Washington, D. C.
G. N» Thomas Processes Research, Inc.
Subject: Screening Report
Crude Oil Production
Notes by: G. No Thomas
Distribution: Richard Athertoti - 5
Joseph A. McSorley - 2
1. The western section of the crude oil pipeline maps which was ordered as part
of the set of maps on November 1, 1972, has not been received by PR.
2. In expediting the five maps which they previously sent, API did not follow
up on sending the missing map. If the missing map is in stock in Washing-
ton it will be sent immediately.
GNT:jt
March 20, 1973
Memo 7-1
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