United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
EPA-600/2-79-077
April 1979
Research and Development
SEPA
Multimedia Assessment
of the Natural Gas
Processing Industry
-------
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the ENVIRONMENTAL PROTECTION TECH-
NOLOGY series. This series describes research performed to develop and dem-
onstrate instrumentation, equipment, and methodology to repair or prevent en-
vironmental degradation from point and non-point sources of pollution. This work
provides the new or improved technology required for the control and treatment
of pollution sources to meet environmental quality standards.
EPA REVIEW NOTICE
This report has been reviewed by the U.S. Environmental Protection Agency, and
approved for publication. Approval does not signify that the contents necessarily
reflect the views and policy of the Agency, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
-------
EPA-600/2-79-077
April 1979
Multimedia Assessment of the Natural
Gas Processing Industry
by
Willard A. Wade III
TRC - The Research Corporation of New England
125 Silas Deane Highway
Wethersfield, Connecticut 06109
Contract No. 68-02-2615
W.A. 2
Program Element No. 1AB604
EPA Project Officer: Irvin A. Jefcoat
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
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CONTENTS
1. Introduction 1
2. Summary and Conclusions 2
3. Industry Description 4
4. Present Environmental Regulations Affecting The Natural Gas
Processing Industry 19
Federal Regulations 19
Air Pollution 19
Water Pollution 19
State Regulations - Louisiana 21
Water Pollution Control 21
Air Pollution Control 22
Solid Waste 23
State Regulations - Texas 23
Water Pollution Control 23
Air Pollution Control 24
Solid Waste 25
5. Natural Gas Processing Operations 28
Liquid Separation 28
Acid Gas Removal 28
Amine Processes 31
Dehydration 31
Liquid Desiccant Absorption 33
Solid Desiccant Adsorption 33
Injection of Hydrate Point Depressants 36
Expansion Refrigeration 36
Sulfur Recovery 38
Tail-Gas Conditioning 39
Wet-Reduction Processes 41
Shell SCOT Process 41
Parson's Beavon Process 41
Pritchard's Clean Air Process 43
Trentham's Trencor-M Process 43
Wet-Oxidation Processes 43
Wellman-Lord Process 43
USBM Citrate Process 46
Wet-Extension Processes 46
IFP Process 46
Stauffer Aquaclaus Process 46
Townsend Process 48
ASR Sulfoxide Process 48
-111-
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CONTENTS
(Continued)
5. Natural Gas Processing Operations (continued)
Dry-Extension Processes 48
SNPA/Lurgi Sulfreen Process 48
Amoco CBA Process 49
Dry-Oxidation Processes 49
Shell SFGD Process 49
Westvaco Process 49
SNPA/TOPSOE Catalytic-Oxidation Process 49
Heavy Hydrocarbon Stripping 50
Absorption 50
Refrigerated Absorption 52
Refrigeration Process 52
Compression 55
Adsorption 55
Cryogenics/Turbo-Expansion 55
Future Processing Trends 59
6. Air Pollution Aspects of the Domestic Gas Processing
Industry 61
Air Emissions in the Natural Gas Processing Industry . . 61
Sulfur Dioxide 62
Hydrocarbons 62
Hydrogen Sulfide 65
Glycol 66
Texas Emission Inventory 66
Louisiana Emission Inventory 69
Compliance Status of Natural Gas Plants 82
Process Sources of Air Pollution 82
7. Water Pollution Aspects of the Domestic Natural Gas Processing
Industry 86
Produced Water 86
Cooling Water 86
Other Sources of Water Pollution 89
Wastewater Treatment 89
References 91
Appendices
A. List of Natural Gas Processing Plants, Capacities, Products
as of January 1, 1977 93
B. List of Conversion Factors, English-Si Metric System .... 113
C. Major Domestic Gas Supply Companies, 1975 115
D. Acid Gas Removal Processes Used in the Natural Gas Processing
Industry 119
-iv-
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LIST OF FIGURES
FIGURE PAGE
1 Location of domestic natural gas processing
plants, 1977 5
2 Total U.S. marketed production of natural gas and
interstate domestic gas production 1955-1976 .... 7
3 Overall material balance for natural gas
production - 1976 11
4 Graph of U.S. natural gas reserves 15
5 History of total interstate gas supply 16
6 Graphs of supply and demand for various NGL
products 17
7 Flow diagram of the natural gas industry 29
8 Flow diagram for a three-stage wellhead separation
unit 30
9 Flow diagram of the amine sweetening process .... 32
10 Flow diagram of the glycol dehydration process ... 34
11 Flow diagram of the adsorbent dehydration process . . 35
12 Flow diagram of the glycol injection dehydration
process 37
13 Flow diagram of a Glaus sulfur plaat . 40
14 Flow diagram of the SCOT process 42
15 Flow diagram of the Beavon process 44
lb Flow diagram of the Wei Iman-Lord process 45
17 Flow diagram of the IFP-2 process 47
18 Absorption plant for natural gasoline 51
19 Flow diagram of the refrigerated absorption process . 53
20 Flow diagram of the refrigeration process 54
-v-
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LIST OF FibuRES (C ont iiiuecl)
FICURE PAGE
21 Flow diagram of the compression process 56
22 Flow diagram of adsorption process 57
23 Flow diagram of the expander cycle 58
24 Louisiana emission inventory, NO emissions (1973)
vs. gas throughput for the natural gas processing
industry 73
25 Louisiana emission inventory, HC emissions (1973)
vs. gas throughput for the natural gas processing
industry 74
LIST OF TABLES
CABLE PAGE
1 Domestic Gas Processing Capacities by State as
of January 1, 1977 ................. 6
2 Supply and Disposition of Gas in the United States,
1955 - 197b ..................... 9
Production at Domestic Natural Gas Processing Plants
for April , 1977 ................... 10
Overall Size and Capacity ot the Natural Gas Processing
Industry, 1976 . . . . . .............. 12
Capital Investment in the Natural Gas Processing
Industry ...................... 14
Natural Gas Treated for Natural Gasoline and Allied
Products, and Quantities and Value of Products
Recovered, 1955-1975 ................ 14
Planned Construction of Domestic Natural Gas Prcceosi rlf,
Plants as of January 1, 1977 ............ 18
Outline Summary of Rule 8 ot the Texas Railroad
Commission ..................... 26
-v-
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LIST OF TABLES (Continued)
TABLE PAGE
9 Comparison of Domestic Gas Products Extraction
Processes 60
10 Comparison of Several Operation Parameters for
Absorption vs. Cryogenic Plants 60
11 Comparison of Estimates for Sulfur Dioxide Emissions
from Process Sources in the Natural Gas Processing
Industry, 1969 vs. 1976 63
12 Comparison of S02 Emissions from All Sources .... 64
13 Estimate of Emissions from Natural Gas Processing,
1976 Plant and Pipe Line Power Generation Equipment . 64
14 Texas Emission Inventory Summary for Natural Gas
Processing Plants. 1973 Data 67
15 Point Source Emissions from Industrial Processes
Texas Emission Inventory - 1973 Pollutant in
Metric (Short) Tons Per Year . . . 68
16 Louisiana Emission Inventory Summary for the Natural
Gas Processing Industry, 1975 Data 70
17 Flare Emissions for Natural Gas Processing Industry,
Louisiana Emission Inventory, 1973 75
18 Storage Tank Emissions for Natural Gas Processing
Industry, Louisiana Emission Inventory, 1973 .... 76
19 Engine Emissions for Natural Gas Processing Industry,
Louisiana Emission Inventory, 1973 77
20 Heater Emissions for Natural Gas processing Industry,
Louisiana Emission Inventory. 1973 79
21 Emission Factors for Natural-Gas Combustion 81
22 Emission Factors for Heavy-Duty, General-Utility,
Stationary Engines Using Gaseous Fuels 81
-vi i-
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LIST OF TABLES (Continued)
TABLE PAGE
23 Point Source Emissions from Industrial Processes,
Louisiana Emission Inventory - 1975, Pollutant in
Metric (Short) Tons Per Year 83
24 Sources of Wastewater - Natural Gas Processing
Operations 87
25 Natural Gas Processing Plants Typical Discharge
Characteristics 88
-viLI-
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SECTION 1
INTRODUCTION
Natural gas processing is a major activity associated with the energy
industry. Once considered a waste product in the extraction and production of
crude oil, the sale of natural gas and its associated products is a
multibillion dollar business ($27 billion in 1976). The largest single market
is industrial, commercial, and residential usage of pipeline natural gas.
Chemical and petrochemical industries are making ever-increasing demands on
natural gas products which are desirable feedstocks for many of their synthetic
operations.
The natural gas processing industry combines many activities, including
extraction from the earth, processing to remove undesirable components, and
final distribution of the gas and liquid fractions. Many processes have been
developed to clean the gas and separate the mixture into saleable products.
These processes include acid gas removal, dehydration, and heavy hydrocarbon
stripping. Physical and chemical processing steps, such as de-entrainment,
liquid or solid absorption, expansion and compression, and refrigeration are
used to achieve economic yields of specification products.
Air and water pollution emissions result from the extraction, processing,
and distribution aspects of the industry. These emissions are regulated under
a variety of state and local regulations. It was the objective of this study
to review the available literature on air and water pollution relevant to the
natural gas processing industry and to assess, if possible, the overall impact
of this industry on the environment.
-1-
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SECTION 2
SUMMARY AND CONCLUSIONS
Sources of air and water pollution exist at each of the processing steps
from extraction and processing to final distribution. Air pollution
emissions, mainly hydrocarbons, occur at the wellhead from venting and
flaring, miscellaneous leaks in the processing of the gas and from working and
breathing losses in storage and handling of the end products. Sulfur dioxide
and hydrogen sulfide emissions occur from the extraction and processing of sour
natural gas. These emissions are regulated by state and local laws and through
the individual State Implementation Plans. Owners of processing plants are
required to file reports on operations and emissions on a regular basis. These
reports generally consist of emissions estimates based on mass balances of
unknown accuracy and emission factors generated by the Environmental Protec-
tion Agency. No data were found relating emissions to operating capacities
substantiated by source tests.
Water pollution emissions consist of produced water, scrubber and boiler
blowdown, and miscellaneous spillage and runoff. Produced water originates in
the producing well and is usually very high in salinity. Boiler and cooling
water blowdown usually contain anti-sealants and corrosion inhibitors. In
many cases varying amounts of the total plant wastewaters are reinjected into
the producing strata to maintain well pressure or disposed of in other strata.
Disposal of wastewater in this industry is regulated mainly by state and
local laws. State disposal permits are required as a means of protecting
useful aquifers from contamination by deep well injection of highly saline
wastes. Spill prevention and control plans are required for producing,
processing and distribution facilities as a means of limiting and controlling
hydrocarbon contamination of receiving waters. There are no federal effluent
guidelines which affect the industry. The single toxic substance associated
with this industry at this time is chromium. As of yet the industry is not
subject to the Toxic Substances Control Act (TSCA) reporting and testing
requirements. Reports filed on a regular basis as dictated by state laws are
often unclear as to the origin of individual volumes of waste streams within a
given plant. The values reported are mostly the result of sample analysis, but
the contribution of each operation remains unclear within the scope of this
review.
It can be concluded from this literature review that there are quantities
of several pollutants, hydrocarbons, SOa , HaS, NO , being emitted by natural
gas processing plants. The reported values are primarily calculated from
emission factors and known production volumes. Inventorying of reported
emissions is lagging substantially behind the current year and the development
-------
of a relationship between this industry and others has been hampered. There
is, as of yet, no information available on the fugitive or nonpoint emissions
from activities in this industry. It is most likely that fugitive hydrocarbon
emissions could be a substantial fraction of the total emissions from the
industry.
We estimate that SOa emissions have decreased by approximately 20%
between 1969 and 1976 (the latest year for which data were available). This
was primarily due to the addition of new sulfur recovery facilities at natural
gas processing plants. This industry is a source of approximately 15% of the
SOa emitted nationwide in ,.972. This industry is a minor source of the other
criteria pollutants.
The survey of Texas and Louisiana emission inventories showed that the
natural gas industry is highest in both states as a source of NO . Primarily,
NO emissions are the result of internal combustion engines which power the
compression, refrigeration and pumping systems in the plants. The industry in
Texas is the greatest source of sulfur oxides but not in Louisiana.
Hydrocarbon emissions place the industry as the third highest source in both
states .
Process specific wastewater characteristics are uncertain, but the impact
of wastewater discharges on the environment appears to be minimal in light of
the information currently available.
The development of accurate data on the air and water pollution aspects of
the industry can only be developed by instituting a comprehensive testing
program. Extrapolation of a few specific tests to apply throughout the
industry would be frustrated by the uniqueness of the various plants, which are
specifically designed for a given crude gas composition and final product mix.
-3-
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SECTION 3
INDUSTRY DESCRIPTION
The natural gas industry consists of numerous activities from the
wellhead to the end user such as, drilling, extraction, processing, marketing,
and distribution. The final products from these plants are pipeline-quality
natural gas and natural gas liquids (NGL). The NGL products include ethane,
liquified petroleum gases (LPG-butane, propane, and isobutane), natural
gasoline and condensate mixtures. Finished products from plants having
fractionation capability include finished gasoline, naphtha, jet fuel,
kerosene, and distillate fuel oil.(l)
Raw natural gas originates in subsurface strata often under high pressure
(in excess of 8.8 MPa (1,000 psia)) and in combination with crude oil
(associated or casinghead gas). However, 82% of the domestic gross production
of raw natural gas originates from wells dedicated solely to natural gas and
natural gas liquids extraction.(2) Raw natural gas hydrocarbons may include
only methane and ethane (dry natural gas) or methane to pentanes (wet natural
gas). Only 2-5% of domestic gas is classified as 'sour' because of the
presence of hydrogen and carbonyl sulfides. Sweet gas contains very little or
none of these contaminants. Carbon dioxide, water vapor, nitrogen, helium, and
mercaptans may also be present in the raw gas. The liquid phase may include
natural gasoline, butane, propane, and saltwater. Approximately 95% of
natural gas must be processed (prior to distribution) to separate useful
hydrocarbons and to remove undesirable contaminants.
Gas processing plants are usually located in the producing field or in an
area common to several gas fields. Figure 1 shows the geographic distribution
of the domestic gas processing plants. As of January 1, 1977, there were 763
gas processing plants in the United States.(3) Table 1 shows their location
and average daily production by state. A tabulation of all domestic gas
processing plants as of January 1, 1977 is included in Appendix A. As shown in
Table 1, the average daily throughput for 1976 was 1.4 x 109 cubic meters per
day* (1.4 Gcum per day) (48,000 mcfd)**, 0.5 Tcumpy (17.5 trillion cubic feet
per year) with a total capacity of 2.0 Gcumpd (73.0 mcfd). Figure 2 shows the
marketed and interstate natural gas production from 1955-1976. Texas,
Louisiana, Oklahoma, California, New Mexico, and Kansas account for 93% of the
total domestic production. Natural gas liquids (NGL) production should reach
2.5 x 10s million cubic meters per day (0.25 Mcumpd) (1.6 mbpd)*** in 1977.
*Volume at standard conditions, 0.1 MPa (14.73 psia), 289°K (60°)
**Million cubic feet per day.
***Million barrels per day.
-4-
-------
Figure 1: Location of domestic natural gas
processing plants, 1977.
-------
TABLE 1
DOMESTIC GAS PROCESSING CAPACITIES BY STATE
AS OF JANUARY 1, 1977 (3)
Al ,'ib.ima
Alaska
Akansas
California
Co ! orado
Florida
II lino is
Kansas
Kentucky
Louisiana
Michigan
Mi ssi ssippi
Montana
Nebraska
New ML'xiro
North Dakota
Oklahoma
Pennsylvania
South Oikotn
lex-is
!'t ah
We - r \'i TZ \ u i i
Total
Ttefd
No.
plants
3
2
3
40
24
2
1
29
2
108
8
8
8
2
35
4
82
2
1
352
8
4
33
7f>3
Gas
capacity
37.5
60.0
168.0
1,427.0
767.5
722.5
550.0
5,520.5
895.0
23,576.8
602.3
852.7
56.3
23.0
3,513.1
137.0
4.209.8
5.0
38.0
27,469.1
313.5
36R.O
1,297.5
72,610.1
Gas
through-
put
29.0
44.9
89.4
553.9
509.9
630.0
411.0
4,369.9
669.8
16,439.4
335.4
364.2
28.5
7.8
2,927.1
85.3
2,990.4
3.2
12.0
17,136.5
142.9
242.4
779.5
49j_802.4
Ethane
34.1
391.8
482.9
420.0
107.0
1,434.3
65.3
82.7
4,359.5
175.'.
7,553.0
Production - 1,000 gal/day
Propane
9.3
10.5
15.0
341.4
180.6
362.9
247.2
1,017.9
34.0
1,981.2
57.4
34.2
30.3
10.6
497.4
93.9
853.3
2.4
7.0
5,846.7
123.4
107.6
356.6
12,220.8
Isobutane
4.5
25.8
48.7
116.6
446.0
2.2
22.5
118.3
803.8
18.3
1.7
1 ,608.4
Normal
or
unspltt
butane
14.3
6.0
111.7
92.4
202.4
110.2
334.7
22.0
698.5
0.7
28.2
9.6
5.6
211.3
58.5
278.7
1.1
2,368.0
58.4
34.3
151.6
V798.2
(Average based on the
LP-Cas
mix
78.0
54.1
503.2
39.5
751.6
33.4
8.0
24.0
19.0
648.4
7.7
689.5
6.0
168.0
3,030.4
raw NGL
mix
48.0
27.0
80.0
353.7
318.1
25.5
1,012.8
8,438.5
622.2
31.0
16.0
4,044.4
1.5
2,689.4
13,509.0
130.4
349.0
622.4
32,218.9
past 12 months)
Debut. nat
gaso.
8.3
7.0
168.4
91.4
113.6
25.5
300.0
30.0
854.0
2.9
23.3
22.6
7.8
128.8
43.5
283.3
1.5
2 , 84 5 . 7
58.5
34.5
128.3
5,178.9
Other
2.0
33.1
1.1
244.0
1,184.4
40.5
6.0
190.3
565.5
2,566.7
13.1
4,846.7
Tota
produc
79
11:
11;
1,18?
1,219
1,09'
91,
3,241
43;
15,788
759
13f:
10;
2.
5,17 =
19-
5,51 =
U
32.9RS
3>
71"
1,44'
71,55:
Since this compilation Includes cycling plants reprocessing pipeline gas, totals shown h
-------
36,000
32.000
28.000
24,000
u 20,000
O
18,000
12,000
8,000
4,000
I I t I
MARKETED PRODUCTION
INTERSTATE DOMESTIC
GAS PRODUCTION
' < I t
i i i t ; t i
1955
1960
1965
1970
1975
1980
Conversion factor: Million mcf x 0.028 » MMcum
Figure 2: Total U.S. marketed production of natural gas
and interstate domestic gas production 1955-1976.(2)
-7-
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Propane production should be 87,500 cumpd (550,000 bpd), butane 33,400 cumpd
(210,000 bpd), and isobutane 22,300 cumpd (140,000 bpd). This represents a 4%
decline from 1976 production with most of this loss attributable to the
declining availability of natural gasoline and heavier products. Table 2
shows the supply and disposition of domestic gas from 1955-1976. Table 3 shows
the latest available information for total NGL production at domestic natural
gas processing plants. In 1976, the processing of natural gas also yielded
19.6 Mcura (699 mcf) of helium and 1.2 x 106 metric tons of elemental sulfur.
Figure 3 shows an overall material balance for the natural gas processing
industry for 1976.
A list of conversion factors for English and SI metric units is provided
in Appendix B.
Plant size and processing methods vary as a function of gas field size and
the characteristics of the raw gas. Table 4 shows a breakdown of production
for various plant size categories based on arbitrarily-chosen size designa-
tions .
Unit operations in natural gas processing plants are selected to fulfill
intended market needs based on characteristics of the raw natural gas to be
processed. Processing methods include absorption, refrigerated absorption,
refrigeration, compression, absorption, cryogenic, and turbo-expansion. Re-
frigerated absorption is the leader in gas liquids recovery. Cryogenic and
turbo-expander plants have dominated new plant construction since the 1960's.
Cryogenic processing became economically feasible when the Federal Government
initiated a helium storage program for national defense which has been recently
discontinued. Turbo-expansion processing was introduced in 1964 and is now the
dominant processing method employed in the United States.(4) Ninety-five
percent of gas sweetening is done by the several amine processes. The Glaus
process is used most widely for sulfur recovery from acid gases.
There are approximately 12,000 gas producers in the United States.
However, in 1964, 34 companies accounted for 96% of the interstate volume.
Eighteen of the top 20 gas producers are owned by oil companies. Exxon
Corporation is the largest domestic producer and pipelines approximately 20%
of the domestic gas supply. The 25 largest pipeline companies handled 95% of
all interstate gas shipments.(6) Many interstate pipelines have also become
major gas producers. The two largest pipelines have also become major gas
producers. The two largest pipeline companies in 1975 were El Paso Natural Gas
Company and the Tennessee Gas Pipeline Company. Their production volumes
(1975) were 34 Gcum (1.223 tcf) and 33.9 Gcum (1.211 tcf), respectively. El
Paso Natural Gas Company was the ninth largest of all producers in 1973. A
tabulation of the major gas supply companies, their annual productions and
reserves with gross exchanges, from 31 December 1970 to 31 December 1975, is
included in Appendix C. Independent gas producers, those not associated with
pipeline companies, are usually under longterm contracts to supply specified
quantities at fixed prices to the pipeline companies. Seventy-five percent of
the domestic processing plants are owned by producers, with the balance owned
by pipeline companies.
-8-
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TABLE 2
SUPPLY AND DISPOSITION OF GAS IN THE UNITED STATES, 1955 - 1976
(Millions o< cubic foci) '
Disposition of Gross Production
Grou Production*
Year
1955
1956
1957
1958
1959
I960
l%l
1462
1963
1464
1465
1466
1467
1468
1969
1970
1971
1972
1973
1974
1975
1976
Gas Wells
7.841.958
8.306.550
8.716,835
9,154,051
10,101.7.54
10.853.426
11,195.087
11.702.382
12.606.022
13.035,200
13.521,600
13.843.421
15,346.853
16.539.925
17,489.415
18.544.658
18,925.1.16
19.042.592
19.371.600
18.669.212
17.380.293
17,190.655
Oil Wells
3.877.8.16
4.006,355
4,189.834
3.992.584
4.127.S1S
4.214.485
4,265.225
4.3)6.591
4.3o7.346
4.405.100
4. 419. SIX)
5,134,418
4.9O4.421
4.785.075
5.184.780
5,191,745
5,162.895
4,973.517
4.695,602
4.180.581
3,723.237
3,753.123
Rep.es-
Total suring
11.719.794 1,540,804
12,372.905
1 2,906, 669
13.146,635
14,229.272
15.087,911
15.460.312
16.038.973
16.473.368
17.440.300
17.963.100
14,033,839
20.251.776
21.325.000
22.679,195
23,786,453
24,088,031
24.016.109
24.067.202
22.849,791
.426.648
,417.263
.482,975
.612.109
.753.996
.682.754
.736.722
.843.297
,638.161
.604.204
.451,516
.590.574
.486.092
.455.205
,376,351
.310.458
.2.16.292
.171.161
.079.890
21,103.5.1(1 860.956
20.443,778 859,410
Vanled
and
flared
773,6.14
864.334
809.148
613,412
571,048
562.877
523.533
4ZS.629
38.1.408
339,996
319.141
375,695
489,877
516,508
515,750
489,460
28J.561
248,119
248,292
164.381
133.913
I3I.43Q
Marketed
Production0
4,405.351
10.081.923
I0.680.2.S8
1 1 .0.10,248
I2/M6.II5
12.771.038
13.254,025
13,876.622
14,746.663
15.462.143
16.039.753
17.206,628
18.171.325
19.322.400
20.648.240
21.420.642
22.443.012
22.531.648
22.647,544
21,600,522
20.108.661
14,452.438
Eilraction and
Loss Plant Fuel
1.507,671
1.420,550
1.479.720
1.604.104
1,737,402
1,779.671
1.881,208
1.993.128
2,081.339
2.082.029
1.909.697
1,772.708
784.514 .140,966
827.877 .237.131
866.560 .345.648
906.413 ,348.758
883.127 .413.650
907,993 ,455,563
916,551 ,495,915
887.49Q ,477.386
872.282 ,396.277
860.000d 1,380,000*
Net Oungc
in Under-
ground
Storage
67,934
116.470
141,3%
8.1.081
118,742
131.644
145,616
86.487
110,772
I28.8O4
118.115
68.855
184.829
45,539
119.500
398,160
3.1 1.768
135.714
441. 5O4
83.663
344.054
(IOO.OOO)11
Pipeline
Fuel
245.246
295.972
294,235
312,221
349.348
347.075
377,607
382.446
423,783
4.13,204
500.524
535.353
575,752
590.965
6.10.%2
722.166
742.592
766,156
728.177
668,792 '
582,963
600.000d
Unaccounted
For
246,933
212,992
205,373
283,597
223,112
274,231
234,808
285.726
364,658
302,781
318.711
401,203
296,214
325,062
331,587
227,650
338,994
328,002
195.863
288,731
235. W.B
230,000d
Net
Imports
(20.141)
(25,583)
(1.714)
97.078
115. 5/7
144.314
208.113
385,720
389,247
421.421
430.262
455.141
482.612
558.140
075.647
750,967
854,336
941.483
955.732
^882.495"^
880.333
899.058
Delivered
lo
Consurnersc
7.317,426
7,940,356
8,500,820
8,844,323
9,732.888
10,382.681
in.822.849
11.514.505
12.135.358
12. 436. 74o
13.622.968
14.883,650
15.671,642
16.803.966
18,079.630
19.018.462
19.637.212
14,879.733
19.825.271
19,076,955
17,558.353
17.881 ,4%d
a. Include* gas (mostly residue gas) blown to the air but does not Include direct waste on producing properties, except wl
b. "Marketed Production" equali "Total Gross Production" kts "Repressurmg" and "vented and Flared". It include!
c. Includes net imports, but excludes Substitute Natural Gas.
d. Data not available at lime of publication. Estimated by A.G. A.
Sources: U.S. Bureau of Mines, NaturmlGas, Annual
'here data are available.
an allowance for natural gas liquids content in the natural gas.
Conversion factor: mcf x 0.028 = Mcum
-------
TABLE 3
PRODUCTION AT DOMESTIC NATURAL GAS PROCESSING PLANTS
FOR APRIL, 1977 (5)
Product
Ethane
Propane
Isobutane
N Butane
Other Butanes
Butane-Propane Mix
Total
Natural Gasoline
& Isopentane
Plant Condensate
Other Products
Total
Throughput
cu.m (1000 barrel)
1925
2490
390
700
370
30
5905
1810
175
20
7910
(12,119)
(15,707)
(2,471)
(4,429)
(2,333)
(199)
(37,258)
(11,407)
(1,111)
(140)
(49,916)
Stocks
cu.m
2060
8555
900
2165
235
155
14070
960
60
15
15105
(1000 barrel)
(12,964)
(53,886)
(5,664)
(13,640)
(1,480)
(984)
(88,618)
(6,051)
(383)
(92)
(95,144)
-10-
-------
OVERALL MATERIAL BALANCE FOR NATURAL GAS PRODUCTION - 1976
VENTING & FLARING
re nci/w UNTREATED GAS
in. n Ten 28 GCUM
i
GROSS
PRODUCTION
SflS RCIIM
120.9 TCFI
,, . oi°t
$M$&
,
11 TCFI
MARKETED
NATURAL GAS
PRODUCTION J^ J PROCESSING PLANT
^•'••"•oVv
|$!^&Cl'
REPRESSURING
24 GCUM
10. 8B TCFI
rLHrei uoc.
36.4 GCUM
(1.3 TCFI
1
MISC. LOSS
6.4 GCUM
(0 23 TCFI
STORAGE
(.•(•i- • ,. 28 r.ci/M
•'•'"";'/"•'•':'',-"•. lo ' TCF1
'l^fe^V'v.-'t
viti^SBv?]-'?^,
IMPORTS
25.2 GCUM
1.9 TCFI
,
^ ninriiiMr MKTiinAi pAn
L — ^-rllcLINc NAIUnAL uAo
500 GCUM
(H.B TCFI
-•-PIPELINE FUEL \ 168GCUM
-"-rirtuivt rutt \ (0 „ TCf,
^-NATURAL GAS LIQUIDS
, 22.MCUM
NATURAL GASOLINE } (Q (< ^
} 70MCUM
' 10.44 BBI
FINISHED GASOLINE & NAPHTHA } Ig'/^
EXTRACTION LOSS
24 GCUM
II) BR TCFI
OTHER )
I INC PLANT CONDENSATE
KEROSENE.DISTILLATE & MISC.)
2.5 MCUM
,,„. MB)
Figure 3: Overall material balance for natural gas production - 1976.
-------
TABLE 4
OVERALL SIZE AND CAPACITY OF THE
NATURAL GAS PROCESSING INDUSTRY, 1976 (2)
Size
Designation
Small
Medium
Large
TOTAL
Production
Capacity
Mcumpd Number of
(mcfd) Plants
< 0.3 225
(.5 to 9)
0.3 to 1.13 268
(9.1 to 40)
>1.13 270
(40.1 & up)
763
Volume
Produced
Gcum Percent of
(tcf) Total Production
10 2
(.36)
90 18
(3.2)
400 80
(14.2)
500 100
(17.8)
-12-
-------
The gas processing industry employs approximately 15,000 people. Based
on the present salary-income structure, the industry pays an average of $6.59
per hour, thus providing $197.7 million in direct income.(6) Capital
investment within the industry is shown in Table 5.
As shown in this table, capital investment has been increasing sharply
while the number of plants has been decreasing. Higher demand and decreasing
supplies have influenced the industry to maximize efficiency and improve
product recovery. The total value of NGL production in 1975, 95 Mcum (596
million barrels), is estimated at $2.8 billion. Natural gas liquids production
for 1976, 93 Mcum (587 million barrels), generated approximately $3.3 billion
in revenues (see Table 6). Pipeline natural gas yielded revenues of $23.7
billion in 1976 from total shipments of 557 Gcum (19.9 tcf).
Revenues from helium and sulfur production (1974) were $18 million and $36
million, respectively.
Several factors are influencing the future disposition of the natural gas
industry. As shown in Appendix C, the reserves of the major pipelines are
declining and additions to reserves are small. Figure 4 shows the history of
proven reserves and additions and the gross production of the industry. These
data show a decline of approximately 6% from 1975 to 1976 to approximately 6
Tcum (216 tcf).
A graph of interstate domestic gas production is shown in Figure 5. The
1976 production was 339 Gcum (12.1 tcf), while 1975 production was 344 Gcum
(12.3 tcf), 1.4% higher. This trend is likely to continue since the volume of
reserves dedicated to interstate pipelines has been declining since 1967 (see
Figure 4). The overall marketed production of natural gas and NGL declined
only 0.8%, from 591 Gcum (21.1 tcf (1973)) to 557 Gcum (19.9 tcf (1976)).
Figure 6 shows the projected isobutane supply and demand for total NGL, as
well as for propane and butane, through 1986. These data show a decline from
the 1976 domestic production of NGL to 77 Mcumpy (485 million barrels per year)
by 1980. Ethane production has been expanding as demand for its use as the
preferred feedstock for ethylene synthesis has increased substantially in
recent years.
Twenty-five new plants are either under construction or in the planning
stages (see Table 7). These plants are replacing old facilities, additions to
capacity at existing fields, or part of new field development. Their
construction represents a major portion of the estimated $5 billion required by
the industry for capital outlay by 1986.(7) Of course, substantial new
discoveries in the Outer Continental Shelf (DCS) off the East Coast,
California, Alaska, and the Gulf Coast would have a great effect on the
industry's capital outlay, as well as on the supply-demand picture.
-13-
-------
„
TABLE 5
T. MT^L GAS
*— (7)
Year
1972
1973
1974
1975
Millions of Dollars
Expended
175
150
225
325
TABLE 6
NATURAL GAS TREATED FOR NATURAL GASOLINE AND ALLIED PRODUCTS,
AND QUANTITIES AND VALUE OF PRODUCTS RECOVERED,
1955-1976 (2)
— ~~ ' Products Recowred —
" I — ' "
Year
1955
1956
1951
1958
1959
I960
1961
1962
1963
1964
I%S
1966
l%7
1968
1969
1970'
1971
1972
1973
1974
1975
1976P
•
Natural Gu
Trellcd
(Millions °f
cubic feet)
8.185.953
8.445.009
B 57b,S61
8.452.544
9.186.862
9.768.189
10,261.669
11,089.241
12.430.353
13.176,126
13.772.101
14.924.429
15.641,633
16.316.674
17.655,108
18.509,309
19.152.807
19.906,893
19.679,291
18.684.480
17,748.426
b
_ ~
Natural Gasoline
Quantity
(Thousands
of gallons)
4,457.079
4.438.890
4.499.495
4.355.025
4.222.266
4.479.454
4.666.319
4,772.260
4.899,323
5,286,703
5.457.367
5.564.139
5,850,271
6,210,708
6.633,018
6.935.838
6.942.474
6.875.442
6,791.73d
6.212.766
5.620.608
5.575.584
Value
(Thousands
of dollars)
S313.075
316.646
305.937
300.666
290,311
313.058
311.966
333.965
320.131
341,714
360.603
366.332
389.156
411.695
457.986
468.602
496,676
500.425
568.214
974.825
777.637
882.718
.
Liquefied Petroleum
Gases
Quantity
(Thousands
of gallons)
5,972.698
6.487,413
6 65S.282
6,783.000
7.874.706
8.444,074
S.085,465
9,409,083
10.302.250
10 743.591
11.257,267
12.134,294
13,717.861
14.7S3.004
15.895,194
16.783,662
17,540.628
18.678.912
18,775.386
18.813.732
18.651.612
18.369.372
Value
(Thousands
of dollars)
_____ •
$|OS,231
265,185
263.665
296.571
349.802
391.566
370.186
353.334
359.770
362.792
417.249
527,223
632,994
552,335
498.927
672.088
769.397
828.718
1.188.289
1.9U0.769
1.893.890
* 2.298.647
.
--'
FiiiiahedGaioBawaiid Other Products*
Naphtha
Quantity
(Thousands
of (aliens)
823.103
832,915
779.807
701,456
660.666
503.659
473.4%
450,991
499.901
506,505
439,267
380.135
307.263
280.728
374.514
240.702
224,784
186,732
136,038
- 52,878
45.528
40.572
• —
Value Quantity
(Thousands (1JK>U"°?
of dollars) of gallons)
J72.192 564.7«
75,102 S».»
T) icj 4S5.005
slioi 539.977
S'M7 714.170
«.4io «S».3»«
31.9%
37,347 1
40.922 1
37.815 1
36.270 1
33,380 . ''
28.044 1
26,577
36,954 '<
23.234 '
23.210 1
20.737 '
13.902
10.028
8.411
965.648
1,021.271
1.135.743
1.206.973
1,391,436
1.604.154
1.731.727
1.868.622
1,467.3%
1 .488.270
1.240.344
1,063.986
942,606
797,664
712.488
9.650 °7°-»2
• '
Value
(Thousands
of dollars)
138,508
40,210
37.700
39,072
61.866
60.361
68,057
73.505
78.120
84.071
97.481 1
120.426
129,742
133.407
108.144
111,188
96,771
83.261
86.668
122.305
92.650
93.074
• '
a. Include* plant condtnsate. kerosene, dikttltate fuel oil. and miscellaneous products.
b. Nut available.
p— Preliminary.
Source: U.S. Bureau ol Minei.
Conversion factor: 1000 gal * 0.0038 -
-14-
-------
U.S. NATURAL GAS RESERVES
320-
Trillions of Cubic Feet
-320
300 - PROVED RESERVES
280
-300
-280
260.
-260
240
•240
220
220
200
-200
ISO
160-
(As of Dec. 31)
.J40 ' ' '
•180
•160
I i i I
till
I I I I
i I i i
I I I I
40
25
20
15
10
5
0
5
•10
15
20
25
5
0
5
10
15
I Ml 111111111111 IN 1111111 III
—iiJJJIIMIIIIIIIIIIIIIIIII
ri 11 l?|}|;l 111
4JJIIIIIH
20— PRODUCTION
25-
1947 48 49'50 51 52 53 54'55 56 57 58 59*60 61 62 63 64'65 66 6768 69'70 71 72 73 74*7576
AGA Committee on Natural Gas Reserves
Conversion factor: trillion cu ft x .028 = Tcum
Figure 4: Graph of U. S. natural gas reserves.(2)
-15-
-------
Oomtstk Kwtrm and Gas Supply U*4*r Import C«»tr*cb (Cm*, Unit*, t»4 Nffrii)
(Billion Mcf at 14.73 Psia @ 60 F)
Gas Supply
Company Owned
Independent Producer Contracts
Produced and Purchased
Import Contracts
Independent Producer Contracts
1963 1964 1965 1966 1967 1968 1969 1970 1971 1972 1973 1974
Conversion factor: Billion Mcf x 0.0028 = Gcum
Figure 5: History of total interstate gas supply. (8)
-16-
-------
U.S. NGL
supply-demand
2,000
1,500
1,000
500
o
o
o
1976
'80
'82 '84 1986
YEAR
U.S. NORMAL BUTANE
supply-demand
400 i—=
100
0
1976 '78
82 '84 1986
U.S. PROPANE
supply-demand
O
O
O
1,200
1,000
800
600
400
200
0
-o
JD
O
O
o
YEAR
LEGEND
DEMAND
IMPORTS
SUPPLIED FROM
REFINERY PRODUCTION
1976 '78
'80 '82
YEAR
'84 1986
U.S. ISOBUTANE
supply-demand
200
1976
1986
SUPPLIED FROM REFINERY PRODUCTION
|(FOR CHEMICAL 4 FUEL USE. DOES NOT
1 INCLUDE THAT PRODUCED & CONSUMED
INTERNALLY FOR MOTOR FUELS.)
[ SUPPLIED FROM NATURAL-GAS PROCESSING
Conversion factor: 1000 b/d x 0.159 = kcum/d.
Figure 6: Graphs of supply and demand for various NGL products.(4)
-17-
-------
TABLE 7
PLANNED CONSTRUCTION OF DOMESTIC
NATURAL GAS PROCESSING PLANTS
AS OF JANUARY 1, 1977 (3)
oo
I
•AMINOIL USA INC. Lucien, Okla. 16.0 MMcfd
by expander process (old plant to be shut down)
44,800 g/d raw natural gas liquids mix. En-
gineering stage. Contractor: Wcrley. Comple-
tion: July 1977.
ATLANTIC RICHFIELD CO. Crittendon plant,
Winkler County, Tex. 35 MMcfd expansion.
58,000 gal/d raw natural gas liquids mix
under construction. Contractor: Dresser. Cryo-
genic turbo-expander process. $4.8 MM.
BP ALASKA INC. North Pole. 83.000 b/d
dehydrators (six each) in engineering stage.
Eng: Howe-Baker. Contractor: Brown & Root.
•CHEVRON USA INC. Points Coupee, Parish,
La. 100 MMcfd. Iron sponge process. Comple-
tion: May 1977.
•CITIES SERVICE CO. Hutchinson, Kan. 44,-
000 b/d de-ethanizer system. Engineering
stage. Contractor: Dresser.
•CONSUMERS POWER CO. Jackson, Mich.
1.5 MMscfd each of three field compressors.
Proposed. Completion: December 1977.
•EXXON CO. Arcadia Parish, La. 950 MMcfd
Blue Water plant. Contractor: Fish Eng. Com-
pletion: late 1978.
Crane County, Tex. 65 MMcfd replacement of
processing facilities at Sand Hills plant. Com-
pletion: late 1978.
•GENERAL CRUDE OIL CO. Salt Creek,
Kent County, Tex. 30,000 g/d demethanizer. Re-
frigeration process. Planned. Contractor: Ort-
loff.
•GETTY OIL CO. Hatter's Pund, Mobile
County, Ala. 50 MMcfd expansion. 72,000 g/d
propane, 51,800 g/d butane 15,500 g/d debu-
tanized natural gasoline. Refrigeration method.
Engineering stage. Contractor: Delta. Comple-
tion: June 1978.
•HOUSTON OIL AND MINERAL CORP. Texas
City, Tex. 400 MMcfd by cryogenic turboex-
pander method. 105,000 g/d ethane, propane,
butanes-*-. Planned. Completion: Oct. 1978.
•MOBIL OIL CORP. Vermilion Parish, La. 150
MMcfd plant planned. Design stage.
Coyanosa, Peeps County, Tex. 125 MMcfd ex-
pansion. Cryogenic process. Contractor: Trend.
Completion: June 1977.
Midland County, Tex. 90 MMcfd expansion.
Cryogenic process. Contractor: Dresser. Comple-
tion: June 1977.
NORTHERN NATURAL GAS. Ventura, La. 10
MMscfd LNG unit under construction. Contrac-
tor: J. F. Pritchard. Completion: 1977.
•NORTH TEXAS LPG CORP. South Salves-
ton. Proposed plant. Cryogenic process. States:
Cost-benefit analysis.
PHILLIPS PETROLEUM CO. Crane County,
Tti. 20 MMcfd natural gas liquids expander
plant. Contractor: Tulsa Pro-Quip. Completion:
May 1977.
Kingfisher County, Okla. 75 MMcfd natural
gas liquids expander plant. Contractor: Dress-
er. Completion: July 1977.
Sherman plant, Hansfora County, Tex. 75 MM-
cfd natural gas liquids expander plant. Staff
will build. Completion.- May 1978.
Spraberry plant, Glasjcock County, Tex. 25
MMcfd natural gas liquids expander plant. Com-
pletion: July 1977.
•PLACID OIL CO. Patterson Plant 2, St.
Mary Parish, La. 600 MMcfd by turboexpander
method 610,000 g; d products. Under construc-
tion. Contractor: Delta Eng. Completion: July
1977.
SHELL OIL CO. Kalkaita, Mich. 100 MMcfd
expansion. 180,00 g/d demethanized gasoline.
Additional ethane recovery (parallel existing
process). Turboexpander process. Contractor:
Hudson. Completion: November 1977.
SKELLY OIL CO. Eunice, Hew Mexico. 140
MMcfd expansion under construction. Contrac-
tor: Randall.
•TUCO INC. Hobbs, N.M. 75 MMcfd by ex-
pander method. 125,000 g/d demethanized
product. Contractor: Randall. Completion: Sept.
1977.
U.S. NAVY. Elk Hills, Calif. 100 MMscfd plant.
Engineering stage. Contractor: Ameron Process.
Completion: Dec. 1977.
-------
SECTION 4
PRESENT ENVIRONMENTAL REGULATIONS AFFECTING
THE NATURAL GAS PROCESSING INDUSTRY
The natural gas processing industry is subject to federal, state, and
local regulations which control by permit its air, water and solid waste
impacts on the environment.
The primary air pollutants associated with gas processing include sulfur
dioxide (SOa), hydrogen sulfide (H2S) and hydrocarbons. Cooling water
blowdown and water extracted from the wells (produced water) are the primary
sources of water pollution for the industry. Blowdown from cooling water
usually contains treatment chemicals such as chromates and/or other metals and
high dissolved solids. Produced water, often a brine liquid, has a very high
content of mineral salts.
Solid waste from natural gas processing plants usually consists of spent
absorbents. Noise and odor problems are incidental and generally do not affect
the community.
FEDERAL REGULATIONS
Air Pollution
There are no New Source Performance Standards (NSPS) for the natural gas
processing industry at this time. However, sulfur dioxide and hydrocarbons,
the principal pollutants for the industry, are criteria pollutants. As such,
their emission is controlled via State Implementation Plans (SIP's) devised to
enable each state to meet the national air quality standards by July, 1975.
The Clean Air Act Amendments of 1977 will require substantial revision to
the SIP's to address the prevention of significant deterioration in attainment
areas and reduction of emissions from stationary sources in non-attainment
areas. The industry may thus be affected in the future by regulations
developed in response to these Amendments.
Water Pollution
There are several different means by which the Federal government may
effect point source water pollution. The Federal Water Pollution Control Act
has provisions for:
1. Technology-based effluent guidelines
2. Water quality standards
-19-
-------
3. Limitations on toxic substances
4. Control and prevention of oil spills.
Federal technology-based effluent guidelines have not been promulgated
for the natural gas processing industry. However, states are free to impose
effluent limitations on a case-by-case basis. The Federal Water Pollution
Control Act (FWPCA) also dictates that states develop water quality standards
and implementation plans to achieve these goals. This is one of the primary
means by which the industry is affected by Federal regulations.
Section 311 of the FWPCA is written to encourage the prevention of spills,
leaks and other nonroutine discharges of oils and hazardous materials. These
regulations have undergone significant modification and will be promulgated in
the near future. At present, spill prevention control and countermeasure
(SPCC) plans are required if a potential spill could affect a navigable
waterway.
The issue of deep well injection of produced water and the intent of the
FWPCA has not been established at this time. EPA's direct authority has been
challenged successfully although states are required to regulate subsurface
disposal before being granted NPDES permitting authority.
Part C of the Safe Drinking Water Act also deals with the protection of
underground sources of drinking water. Regulations wil be promulgated in the
near future with primary enforcement responsibility assigned to the states.
These regulations will include a specific prohibition of interference with
injections of brine, etc. in connection with oil and natural gas production
unless such requirements are essential to protect underground supplies of
drinking water.
The single toxic substance associated with this industry at present is
chromium which is used as a corrosion inhibitor in cooling water.
The newly-enacted Toxic Substance Control Act (TSCA) imposes new
requirements on manufacturers and processors of chemical substances and
mixtures. Although this law is still in its initial implementation phase, it
is quite possible that natural gas processors will be treated as manufacturers
or processors of chemical substances. If so, the industry will become subject
to TSCA's reporting and testing requirements as well as any general
requirements of EPA with respect to chemicals posing an unreasonable risk to
public health or the environment.
Federal involvement in solid waste disposal has been greatly expanded
with the enactment of the Resource Conservation and Recovery Act (RCRA) of
1976. This Act provides for Federal standards for transport and disposal of
hazardous and other solid waste. States may be granted authority by EPA by
initiating programs comparable to the Federal solid waste management guide-
lines.
The FWPCA establishes an elaborate permit system (NPDES) to insure that
the substantive requirements of the statutes are fulfilled. Authority for
-20-
-------
permit issuance lies with EPA. However, EPA may delegate its authority to
states which have adopted acceptable programs. Where states issue NPDES
permits, EPA serves in an oversight capacity and can block permit issuance.
Permits are issued by EPA for Texas which has 46% of the natural gas processing
plants and Louisiana with 14% of the total.
STATE REGULATIONS - LOUISIANA
Water Pollution Control
The Louisiana Stream Control Commission, chaired by the Director,
Louisiana Wild Life and Fisheries Commission, is the water quality control
authority for the State. Other members of the Commission are the heads of the
following State agencies, or their designated representatives:
1. President, Louisiana Board of Health
2. Commissioner, Department of Conservation
3. Attorney General
4. Commissioner, Department of Agriculture and Immigration
5. Executive Director, Department of Commerce and Industry
6. Director, Department of Public Works
The Division of Water Pollution Control under the Louisiana Wild Life and
Fisheries Commission, serves as the research, investigative, and enforcement
group for both the Stream Control Commission and the Wild Life and Fisheries
Commission in matters pertaining to water quality and pollution (Source:
Acts 1940, No. 367; Acts 1942, No. 199; Acts 1948, No. 87; Acts 1952, No. 254;
Acts 1970, No. 405, No. 628; as listed under Title 56).
The Louisiana Stream Control Commission is authorized to make the
"certifications" which applicants for Federal permits are required to provide
to the appropriate Federal agencies (i.e., Environmental Protection Agency,
U. S. Coast Guard—Oil Transfer Facilities, etc.) under the Federal Water
Pollution Control Act, Section 21 (Source: Acts 1970, No. 628, Section 1).
Eight rules are set forth in the Louisiana regulations which relate to
water pollution from oil and gas operations:
Rule No. 1.
Waste oil, oil sludge, etc. shall be destroyed on the lease where the
wastes originate by burning (smoke prohibited by the Louisiana Air
Control Board rules) or otherwise in a manner to eliminate any pollution
hazard.
Rule No. 2.
No oil fluids permitted to flow on surface of the ground or allowed to
flow into any stream, lake, or other body of water.
-21-
-------
Rule No. 3.
Each land located producing well and pumps handling oily fluids shall be
provided with a surrounding ditch and gathering sump. Each marine located
pumping well shall be equipped with an impervious deck or catch tank
installed around the wellhead. All workover and drilling barges shall
have a keyway gate to retain oil or oily fluids. All workover, drilling,
or power unit barges will be equipped with an oil combing drain system and
catch tank.
Rule No. 4.
Each permanent oil tank or tank battery located within corporate limits,
within 500 feet of a highway or inhabited dwelling, or closer than 1000
feet to a church or school must be surrounded by a dike (fire wall)
capable of containing the total volume of the encompassed tanks. Tanks
not falling into these categories must have a means to collect and contain
spillage or leaks so as to prevent pollution of the surrounding area.
Rule No. 5.
Oil lines, oil barges, and oil transfer facilities will be operated at all
times with full precaution and design considerations against spillage.
Rule No. 6.
Written approval is necessary for transferring unseparated salt water
from a lease to a central treating facility. Oil field brines discharged
to streams shall not have an oil content in excess of 30 ppm.
Rule No. 7.
No oil field brine shall be discharged into any body of water when it is
determined by the Stream Control Commission that it would be detrimental.
Rule No. 8.
Whenever possible, disposition of oil field brine should be into disposal
wells. Disposal wells shall be drilled, cased, cemented, equipped, and
operated so that no fresh water horizon(s) shall be polluted.
Air Pollution Control
The Louisiana Air Control Law was enacted by the State Legislature as law
by Act 259. The Air Control Law created the Louisiana Air Control Commission.
The Louisiana Department of Health is authorized by the Air Control Commission
to promulgate and administer regulations (R.S. 40:2204A).
Detailed regulations and the Louisiana Air Standards Implementation Plan
became effective January 30, 1972, on submittal to the Federal Environmental
Protection Agency (EPA). This Plan was approved by EPA on May 30, 1972, with
certain exceptions. Necessary amendments and revisions were approved by EPA in
August, 1972.
-22-
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A certificate of approval is required (before construction begins) from
the Louisiana Air Control Commission for all installations constructed after
June 19, 1969 which might produce emissions. Emergency operation emissions
shall be reported to the Air Control Commission without delay.
The Commission is authorized to prevent the construction or operation of
sources if emissions would cause violation of the ambient standards. Standards
currently exist for particulates, SC>2, CO, non-methane hydrocarbons, reactive
hydrocarbons, and NO .
Outdoor burning of waste hydrocarbon products is allowed where it occurs
from petroleum exploration development, production, or natural gas processing
operations. Burning at the site of occurrence is permitted for such products
as (but not limited to) basic sediments, liquid produced in well testing
operations, paraffin, and hydrocarbons spilled from pipeline breaks or other
failures. These burning operations are permitted where it is not practicable
to recover and transport the waste products for sale or reclamation or to
dispose of them lawfully in some other manner.
Except for imminent threat or injury to human life or significant property
damage, outdoor burning shall be conducted under the following conditions:
a. The burning location shall not be within or adjacent to a city or
town or in such proximity thereto that the ambient air is affected.
b. Burning operations allowed only between 8:00 a.m. and 5:00 p.m.
c. Burning shall be controlled so as not to create a traffic hazard.
Solid Waste
Louisiana has a comprehensive solid waste management which meets the
requirements provided by RCRA. EPA has granted Louisiana interim authoriza-
tion to carry out its program for two years from October 21, 1978 to
October 21, 1980.
STATE REGULATIONS - TEXAS
Water Pollution Control
Although general water pollution control authority in Texas is vested in
the newly-formed Department of Water Resources, the Texas Railroad Commission
is solely responsible for the control and disposition of waste and the
abatement and prevention of pollution of surface and subsurface water
resulting from activities associated with the exploration, development, and
production of oil and gas. The Texas Railroad Commission may issue permits for
the discharge of waste resulting from these activities, and discharge of waste
into any water in this State resulting from these activities shall meet the
water quality standards established by the Texas Water Quality Board.
-23-
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In applying the law that the Railroad Commission is responsible for
matters "associated with the exploration, development, and production of oil
or gas," the Texas Water Quality Board and the Railroad Commission have agreed
that the Commission's responsibility includes gas processing and oil and gas
transmission lines.
The basic regulatory provision of the Texas Railroad Commission with
respect to water protection is Rule 8 which is outlined in Table 8.
Air Pollution Control
The Texas Clean Air Act was enacted to safeguard the air resources of the
state from pollution. The Texas Air Control Board (TACB) was named as the
principal authority concerning air quality and pollution control.
A comprehensive set of rules and regulations was adopted by the TACB on
January 26, 1972, in an effort to implement Federal laws concerning air quality
standards and implementation plans. Some rules required compliance effective
March 5, 1972. Others required compliance by specified times with provisions
that periodic progress reports be submitted.
Texas has eight substantive regulatory requirements governing air
pollution. Regulation I refers to visible emissions and particulate matter.
Regulations I, II, V and VI affect the natural gas industry.
Visible emissions from currently constructed stationary flues may not
exceed 30 percent opacity averaged over a five-minute period. Flues
constructed after January 31, 1972 may not cause emissions which will exceed 20
percent opacity averaged over a five-minute period. Special provisions are
made for soot blowing and ash removal.
Visible emissions from a waste gas flare for more than five minutes during
any two-hour period are prohibited except during major upsets.
Regulation II governs sulfur compound emissions. Although emission
limits are not specified for natural gas processing plants, general limits for
HaS are established for all sources based on thirty-minutes average ground
level concentrations at the property line.
Regulation V has the most direct bearing on the natural gas processing
industry. This regulation was adopted for the abatement of photochemical smog
in heavily populated areas where this is a problem at the current time. It is
to apply only in Aransas, Bexar, Brazoria, Calhoun, Dallas, El Paso, Galveston,
Travis, and Victoria Counties. Crude oil and condensate are generally excluded
from the group of volatile organic compounds known to be causing small
problems. However, in some of the rules, they are not specifically excluded.
The following rules under Regulation V should be noted:
-24-
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Rule 502.1.
Volatile organic compounds other than crude oil and condensate stored in
containers with a capacity of more than 25,000 gallons are to be equipped
with a means of preventing vapor loss to the atmosphere.
Rule 502.2.
New stationary vessels of more than 1,000 gallons capacity and for storing
volatile organic compound other than crude oil and condensate are to be
equipped with submerged fill pipes unless it is of a pressure type or
fitted with a vapor recovery system.
Rule 502.3.
Crude oil and condensate storage containers are exempt from vapor control
regulations of Rules 502.1 and 502.2.
Rule 503.
Except for crude oil, volatile organic compound loading facilities
averaging 20,000 gallons a day are to be equipped with vapor collection
systems. Ships and barges are exempt.
Rule 505.
Certain hydrocarbons and other compounds may be disposed of only by proper
burning in excess of 1300°F smokeless flares or incinerators.
Rule 506.
Compliance with this regulation is required by December 31, 1972.
Progress reports required every four months beginning September, 1972.
Finally, Regulation VI is the general permit regulation. Anyone who
plans to construct a new facility or modify an existing facility which may emit
air contaminants must obtain a construction permit before the work is begun and
must also obtain an operating permit within 60 days after startup.
Solid Waste
Texas has a comprehensive solid waste management which meets the
requirements provided in RCRA. EPA has granted Texas interim authorization to
carry out its program for two years from October 21, 1978 to October 21, 1980.
-25-
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TABLE 8
OUTLINE SUMMARY OF RULE 8
OF THE TEXAS RAILROAD COMMISSION
A. Fresh surface and groundwater shall be protected from pollution.
B. Exploratory well drilling, completion, or abandonment must be conducted
so as to not pollute surface or subsurface waters.
C. Earthen salt water pits prohibited.
(1) Salt water disposal pits prohibited.
a. Burning pits allowed (smoke prohibited by TACB rules).
b. Impervious pits may be approved by the Commission.
c. Except where permitted by the Commission, brine discharges into
water courses prohibited. (This includes bays and estuaries.)
d. Off lease disposition of salt water must be permitted by
Commission.
(2) Exceptions may be granted with good cause. (TRC will certify
applications to the Environmental Protection Agency (EPA) to
discharge brine into navigable waters under certain conditions.)
(3) Violators penalized by pipeline severance.
(4) Unused pits shall be backfilled.
D. Pollution Prevention
(1) Operators shall not pollute offshore and adjacent estuarine waters.
(2) Drilling and production shall be done so as to prevent pollution. In
particular, the following procedures shall be used:
a. No harmful liquid wastes may be discharged. Salt water and
other materials from which harmful constituents have been
removed are permitted.
b. No oil or other hydrocarbons to be discharged.
c. Decks of drilling and workover platforms shall be curbed and
wastes contained.
d. Solid waste may be burned and ashes disposed of in the water.
Edible garbage may also be discharged but solids such as cans
and bottles must go to shore.
e. Only oil-free cuttings and fluids from mud systems may be
disposed in the water.
f. Fluids from offshore wells shall be contained with adequate
safeguards to prevent pollution.
-26-
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TABLE 8
(Continued)
OUTLINE SUMMARY OF RULE 8
OF THE TEXAS RAILROAD COMMISSION
g. Producing platforms shall be curbed and equipped to collect
wastes in a collecting tank or sump.
h. Any person observing water pollution shall report it to the
Commission.
i. Pollution shall be corrected immediately by the responsible
operator.
(3) The Commission may suspend operations of a violator.
(4) Provisions of Rule 8D are applicable to operations on inland and
fresh waters of Texas.
-27-
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SECTION 5
NATURAL GAS PROCESSING OPERATIONS
The natural gas extracted from the well has a variety of undesirable
impurities and valuable fractions which must be removed or separated prior to
sale to an end user. Knockout drums, dehydration, refrigeration, amine and
carbonate absorption and solid bed sweetening are used to remove impurities
such as water, mercaptans, hydrogen and carbonyl sulfide, carbon dioxide and
carbon disulfide. Valuable hydrocarbons such as natural gasoline, NGL, LPG,
naphtha, kerosene and isobutane which are worth more as liquid mixtures are
stripped from the raw gas in refrigeration units and knockout drums. They are
also removed to prevent pipeline freeze ups and other operational difficulties
in liquefaction plants. Figure 7 shows a schematic of the general natural gas
processing steps used to purify and separate the raw gas into useful products.
Typical sales specifications for pipeline quality gas are:
Heating Value: 37.6 MJ/m3 (1000 BTU/ft3)
3 3
Hydrogen Sulfide: <6 mg/m (0.25 grains/100 ft )
Total Sulfur: 120-480 mgm3 (5-20 grains/100 ft3)
Water Dewpoint: <190°K (-120°F)
The following sections describe in more detail the operations used to
process raw natural gas into marketable products.
LIQUID SEPARATION
The initial gas-liquid separation is typically done in a three stage well
head unit, shown in Figure 8. The produced water, crude oil and heavy
hydrocarbon liquids are stripped from the gas at this point usually in close
proximity to a well head or group of wells. The motive force to operate this
separator is supplied by the well pressure head or by pumps. Glycol or
methanol injected into the well stream to prevent freezing may also be stripped
at this point. The gas, relatively liquid free, is then cooled by heat
exchangers to near-freezing to reduce the water and liquid hydrocarbon content
even further.
ACID GAS REMOVAL
Acid gas removal, or "sweetening", is necessary for an increasing
percentage, presently 6%, of the domestic gas production, and usually follows
the liquid separation step. The hydrogen sulfide (H2S) and carbon dioxide
-28-
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I
N3
EMERGENCY
FLARE-OFF
t
MISC FUGITIVE
EMISSIONS
, i
/X\ , FLARE
fSxr"i i i 1
/^XQ _ FIELD
" ^" SEPARATION
DEHYDRATION
\
i
REINJE
OIL
GAS
WATER
I
CTION
SOUR GAS FEEDSTOCK TO CHEMICAL PLANTS
EMERGENCY
FLAREi [~
f 1 1
SOUR GAS AcmGAS SULF(JR
REMOVAL RECOVERY
{
EXHAUST
DEHYDRATION i
T
1
i
SWEET GAS ' HEAVY
bWttl bAJ> HYDROCARBON
STRIPPING
a». PIPFI INE
FLARE
INCINERATOR
TAIL-GAS
CLEAN UP
RESIDENTIAL.
COMMERCIAL &
INDUSTRIAL
USERS
J NATURAL GAS
LIQUIFIED
PETROLEUM
GASES ~~
^INDUSTRIAL
USERS
HIGHER
•HYDROCARBONS
LIQUIDS
INDUSTRIAL
USERS
Figure 7: Flow diagram of the natural gas industry.(9)
-------
i
u>
o
i
HIGH PRESSURE NATURAL GAS
GAS TO SALES OR FLARES
t
WATER
KNOCK-OUT
"/A \s/s
WELL
FIRST
STAGE
INTERMEDIATE PRESSURE NATURAL GAS T0
^-SWEETENING
SECOND
STAGE
LOW PRESSURE NATURAL GAS OR
^-MARKET
THIRD
STAGE
GAS-OIL SEPARATORS
WATER (TO WASTE OR RETURN TO RESERVOIR)
VENT
FIELD
CONDENSATE
STORAGE
(LEASE TANK)
-—OIL
Figure 8: Flow diagram for a three-stage wellhead
separation unit.(10)
-------
have limited solubility in liquefied natural gas and would cause
operational difficulties in liquefaction plants.
Thirty different processes are available for sweetening, which can be
divided into five basic categories:
1. Amine Processes
2. Carbonate Processes
3. Physical Absorption
4. Solid Bed Sweetening
5. Stretford Process
Amine Processes
Amine processes are used for approximately 95% of all domestic gas
sweetening. A flow diagram of a typical amine process for gas sweetening is
presented in Figure 9.
The sour gas enters an absorber, which is a trayed vessel with 20 or more
trays in it, where it is contracted with an amine solution and the H2S and COa
are absorbed from the natural gas. The gases leaving the absorber are
considered sweet. The knockout drum removes the entrained solution and the
gases go on to the next step. The rich solution (liquids) are let down in
pressure in a vent tank where the majority of the hydrocarbon gases are
released and then used as fuel. The rich solution then enters an exchanger
where it is heated and then passed on to a still. In the still or stripper, the
solution is stripped of the absorbed H2S and CC>2 by means of heat applied
through a reboiler at the bottom of the tower and by fractionation. The gases
are sent overhead to a condenser in which the entrained water and the
regenerated solutions are condensed and returned through the heat exchanger to
a surge tank and then pumped back to the absorber. A carbon absorption
facility is also included to keep the solution clean of impurities such as iron
sulfide, non-regenerable compounds, etc. Another impurity that can cause
problems, particularly in the sulfur plant, is liquid hydrocarbons. These
condense in the still overhead accumulator and surge tank and are then removed
via skimming facilities.
There are nine variations to this basic process with the difference
primarily being the amine solution used. These nine processes are discussed in
more detail in Appendix D.
The four less commonly used sweetening processes are also discussed in
Appendix D.
DEHYDRATION
After the removal of the acidic impurities, the gases often remain
saturated with water. The water and/or water vapor are removed from the
natural gas for several reasons: To prevent formation of hydrates in
transmission lines which can plug valves, fittings, and lines when the gas is
compressed or cooled; to meet a water dew point requirement for a gas sales
contract; and to prevent hardware corrosion from acidic gas streams. The water
-31-
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ABSORBER KO DRUM
SWEET GAS
SOUR GAS
LO
NJ
RICH AMINE
SOLUTION
LEAN AMINE
SOLUTION
HIGH PRESS PUMP BOOSTET~PUMP
REFLUX PUMP
Figure 9: Flow diagram of the amine sweetening process.(11)
-------
concentration in the incoming gas stream should be reduced to 0.76 mg/m3
(1 ppm) for LNG plants, and approximately 110 mg/m3 (150 ppm) for interstate
shipment.
Techniques for dehydrating natural gas include:
o Absorption using liquid desiccants
o Adsorption using solid desiccants
o Inhibition by injection of hydrate point depressants
o Dehydration by expansion refrigeration
These methods will be discussed in the following subsections.
Liquid Desiccant Absorption
The more common liquids in use for dehydrating natural gas are triethylene
glycol (TEG), diethylene glycol (DEC), ethylene glycol (EG), and calcium
chloride brine. In general, glycols are used for applications where dew point
depressions of the order of 290-320°K (60-120°F) are required. TEG is the most
common, principally because of higher glycol vapor losses when DEG and EG are
used. Also, greater dew point depressions are obtained with TEG.
The glycol dehydration process, which is typical of the processes using
absorbents, is shown in Figure 10. Gas is brought into the system through an
inlet scrubber to remove any entrained liquid water or hydrocarbon. The gas is
then dried by countercurrent contact with the absorbent in the absorber.
Dehydrated gas leaves the system from the top of the absorber and the absorbent
containing water leaves from the bottom. Since the absorber is normally
operated at pressures 2.0 MPa (290 pounds per square inch, absolute), some gas
will be dissolved in the absorbent. This gas is separated in a flash vessel at
reduced pressure and delivered to the fuel gas system. The absorption liquid
is then fed to a distillation column, or still, for regeneration. Water is
distilled overhead, along with a minor amount of gas which is sent to the
flare. The regenerated absorbent is recycled to the absorber after cooling by
exchange with the feed stream and cooling water.
Solid Desiccant Adsorption
There are a number of commercially-available desiccants that are used for
gas dehydration. The most widely used are alumina, silica gel, and
silica-alumina beads, and molecular sieves. These desiccants can be
regenerated so that they can be used through many cycles of absorption and
reactivation. Some of them can produce exit water content as low as 0.76 mg/m3
(1 ppm) or less.
The basic process, shown in Figure 11, consists of two dehydration
vessels to permit continuous operation since the adsorbent is regenerated in
place. Gas is brought into the system through an inlet scrubber to remove any
entrained liquid water. The main flow, to the No. 1 desiccant tower, flows
downward through the tower and dehydration gas leaves the process from the
bottom. The No. 2 tower is regenerated while the first is on-stream. A bypass
stream from the main gas flow is heated and passed through the second tower.
-33-
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i
OJ
ABSORBER
TO FLARE
OVERHEAD
ACCUMULATOR
WATER TO WASTE
WATER SYSTEM
STM
—&-£
TO WASTE
WATER SYSTEM
FLASH TANK
Figure 10: Flow diagram of the glycol dehydration process.(12)
-------
N0.1 DESICCANT TOWER NO. 2 DESICCANT TOWER
INLET
SCRUBBER
GAS
—»
IN
rtx>
STEAM
TO WASTE
WATER SYSTEM
FCV
7
rtxj-
-tXI— I
HX3-
CONDENSATE
SEPARATOR
CW
-4
TO WASTE
WATER SYSTEM
DEHYDRATED GAS
Figure 11: Flow diagram of the adsorbent dehydration process.(13)
-------
Gas and water vapor from the tower are cooled to condense the water. The wate
is separated from the gas in the condensate separator and the gas is returne
to the main gas stream. After regeneration, the desiccant bed is cooled b
bypassing the heater and passing cool gas through the tower.
The use of alumina as the desiccant will produce a dew point under 200°
(-100°F). A disadvantage is that alumina tends to require more regeneratio
heat than some other desiccants. It also tends to absorb heavy hydrocarbon:
which are difficult to remove in regeneration. Alumina is alkaline and i;
subject to reaction with mineral acids which are sometimes found i:
well-treating chemicals.
Silica gel and silica-alumina beads will produce dry gas with watei
content as low as 7.6 mg/m3 (10 ppm). Their regeneration is the easiest of the
various desiccants discussed. They also absorb heavy hydrocarbons but releasf
them more easily than alumina in regeneration. They are acidic materials anc
will react with caustic, ammonia, and other basic materials. Liquid water
causes them to crack or break.
Molecular sieves are discussed in Appendix D as a method for acid gas
sweetening. They are also used for dehydration and can produce dry gas water
contents as low as 0.76 mg/m3 (1 ppm). An advantage is that they tend not tc
adsorb heavy hydrocarbons due to molecular size discrimination. A disadvan-
tage is that the external surface of the particles is subject to fouling by oi!
or glycol carryover. Also, they require the highest reactivation temperatures
and are subject to irreversible acid attack because they are alkaline.
Injection of Hydrate Point Depressants
Hydrate point depressants are used along with expansion refrigeratior
(discussed in the following section) if there is danger of forming hydrates it
the pre-cooling heat exchanger. The most common inhibitor used is liquid
glycol injected into the gas stream. Glycols have low volatility and are
easily separated from liquid hydrocarbons and from the water they absorb. They
allow continuous hydrate control in plants that have suitable regeneration and
recycle equipment. Ethylene, diethylene, and triethylene glycols have all
been used for glycol injection with ethylene glycol being the most common due
to cost and operating characteristics. Glycol must be present at the very
point where wet gas is cooled to its hydrate temperature. The glycol and its
absorbed water are separated from the gas stream along with the liquid
hydrocarbons. A flow diagram of this process is presented in Figure 12.
Another inhibitor used is methanol. It is frequently used for
intermittent or continuous injection in natural gas field-gathering systems
and transmission lines to protect against hydrate formation when the gas is
cooled by the environment. In gas-processing plant operations, intermittent
injection is frequently used where there is a slow build-up of hydrates.
Expansion Refrigeration
With wellheads under positive pressure, dehydration can be accomplished
by expansion refrigeration. The gas stream is cooled by adiabatic expansion,
-36-
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IN
C
COLD GAS
SALES GAS
LIQUID
HYDROCARBONS
WATER LEAN WATER RICH^/
^ GLYCOL I GLYCOL
WATER
^~
WATER
-2-
HEAT
INPUT
GLYCOL PUMP
Figure 12: Flow diagram of the glycol injection dehydration process.(14)
-------
with the incoming gas being heat exchanged with cold off-gas from the
separator. Expansion refrigeration without an inhibitor is used only when the
available pressure drop allows the desired water dew point to be attainec
without the formation of hydrates while pre-cooling the inlet gas stream aheac
of the point of pressue drop. Hydrates are allowed to form and are immediately
collected in the low temperature separator. The warm incoming gas stream is
directed through a heating coil to melt the hydrates.
SULFUR RECOVERY
The next step in natural gas processing is the conversion of HaS to high
purity sulfur. This is accomplished in a Glaus sulfur-recovery unit. The HaS
containing acid gas stream, which results from the sweetening processes, is
subjected to either a "once-through" or "split-stream" process.
The once-through scheme is selected if the acid gas feed contains 30-40
mol % H2S or greater since it gives the highest overall sulfur recovery and
permits maximum heat recovery at a high temperature. In this scheme, all of
the acid gas is fed to a reaction furnace, along with enough air to burn
one-third of the HzS to SOa and all hydrocarbons completely. Sufficient
retention time is then provided to allow reaction of the SOa generated with the
unburned HaS to form sulfur vapor. The thermal conversion step takes place
above 1300°K (1,900°F) with no catalyst present. Up to 70% of the overall
conversion of HaS to sulfur can take place at this point. The hot gases then
pass through a waste-heat boiler, where they are typically cooled to about
560°K (550°F). If a two-pass boiler is used, the gases are cooled to 800-910°K
in the first pass, and on to 560°K (550°F) in the second pass. The hot gas from
the first pass serves as the source for hot-gas bypass streams, as a method of
reheating which minimizes energy costs.
If the HaS concentration in the feed is low, a split-flow scheme is used.
In this scheme a portion of the feed is burned completely to SOa and combined
with the remainder of the feed to provide the proper HaS/SOa ratio for the
remainder of the process. The optimum HaS/SOa ratio in the tail gas is 2:1,
which will give the maximum sulfur conversion. A ratio either above or below
2:1 will cause a loss in conversion efficiency.
Following the waste-heat boiler, a sulfur condenser is provided to
condense and remove the sulfur produced by the thermal-conversion step in the
reaction furnace. After the condensation step, the gas must be reheated before
it flows to the first catalytic converter. The first condenser usually
produces 0.3MPa (45 psia) steam and operates with a gas-outlet temperature
440-460°K (340-370°F). The gas is reheated 500-530°K (450-500°F) before entry
into the first converter.
If the feed gas contains appreciable COa (say more than 8-10 mol %), the
first converter is operated somewhat hotter than the subsequent converters to
enhance COS and CSa conversion to sulfur in the first converter. Frequently a
special catalyst is placed in the converter to hydrolyze the COS and CSa to HaS
and COa to prevent their emissions from the plant.
-38-
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After the first condenser, the Glaus plant consists of a series of
"reheat, conversion, and condensation" steps. These steps are repeated as many
times as desired, but two or three catalytic converters are usually the optimum
choice. Typically all the condensers produce low-pressure steam in the range
of 0.38-0.52 MPa (40-60 psig) with the last condenser producing 0.24 MPa
(20 psig) steam. The gas outlet from the last condenser usually operates at
400-405°K (260-265°F) which is safely above the sulfur-solidification point of
390°K (246°F).
The inlet gas to each catalytic converter is usually reheated to 470-490°K
(400-430°F), with the first converter inlet running 500-530°K (450-500°F).
There are four basic reheat schemes which may be used: (1) hot-gas bypass,
(2) in-line burners, (3) gas-to-gas exchangers, and (4) indirect heaters,
using either fuel firing or steam heating. These are listed, in the order of
increasing cost and effectiveness in increasing the overall sulfur conversion.
The catalyst commonly used in Glaus plants is 2/4 mesh bauxite. New,
improved catalysts are available (such as Kaiser S-201 and Thone-Progil CR),
which can have advantages over bauxite such as greater resistance to sulfate
formation, lower pressure drop, better COS and CS2 conversion, etc.
The sulfur recovery efficiency of a Glaus plant can range from 70-98%
depending on the H2S concentration in the feed gas, the number of catalytic
stages, and the quality of catalyst used. The unrecovered sulfur is converted
to SC-2 in the tail-gas incinerator, or further processed via one of the many
tail-gas conditioning processes.
A flow diagram of the Glaus process is presented in Figure 13.
TAIL-GAS CONDITIONING
Several processes are available for cleanup of the remaining sulfur
compound in the tail gas from a Glaus plant. Some of these procedures are very
efficient and carry the Glaus reaction to further completion with 99+% of the
sulfur in the acid gas stream removed overall.
The six leading tail-gas treatment processes are: (1) Parson's Beavon
Process; (2) Pritchard's Clean Air Process; (3) IFP-2 Process; (4) Shell's
SCOT Process; (5) SNPA/Lurgi's Sulfreen Process; and (6) the Wellman Lord
Process. The Sulfreen and IFP Processes will not yield 1.4 g/m3 (500 ppm) SOz
emissions. Another process that is viable but which does not yield a 1.4 g/m3
(500 ppm) SOa-emissions level is the SNPA Catalytic Oxidation Process.
Chiyoda's process is viable, but it produces a gypsum by-product which creates
a solid-disposal problem and is not used in the United States. Additionally,
there are eight other processes that are in an early stage of development or
commercialization. These eight are: (1) Stauffer's Aquaclaus Process;
(2) Shell's SFGD Process; (3) Westvaco's Adsorption Process; (4) USBM's
Citrate Process; (5) Townsend Process; (6) ASR's Sulfoxide Process; (7) Tren-
tham's Trendor-M Process; and (8) Amoco"s CBA Process.
-39-
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O
I
INLET SEPARATOR
PC
ACID GAS
T
START-UP
FUEL GAS
o
PC
F RC
IVENT
SHIFT CONVERTERS
SPLIT FLOW PROCESS
F R C & B,PILE,R
AIR BLOWER SULFUR
MOLTEN SULFUR J SEPARATOR
TO STORAGE i=i
SULFUR
B F W
INCINERATOR
AIR BLOWER
Figure 13: Flow diagram of a Claus sulfur plant.(12)
-------
These 16 processes can be divided into two main categories: Wet-scrubbing
processes and dry-bed processes. These two main categories can be further
subdivided into five subcategories: (a) Wet-reduction to HaS with subsequent
absorption or reaction; (b) wet-oxidation to S02 with subsequent absorption or
reaction; (c) wet-expansion of the Glaus reaction in liquid phase with
catalyst present; (d) dry-expansion of the Glaus reaction on a solid bed; and
(e) dry-oxidation to SC-2 with subsequent absorption or reaction. These
categories and their associated processes are discussed further in the
following paragraphs.
Wet-Reduction Processes
Shell SCOT Process —
The Shell Glaus Off-Gas Treating (SCOT) process can increase the sulfur
recovery efficiency of Glaus units from the usual level of about 95% to more
than 99.8%. The process essentially consists of a reduction section and an
alkanolamine absorption section.
In the reduction process, all sulfur compounds and free sulfur present in
non-incinerated Glaus off-gas are completely converted into HzS over a
cobalt/molybdenum catalyst at 570°F (570°K) in the presence of H2 or a mixture
of Hz and CO. Reducing gas can be supplied from an outside source, or a
suitable reducing gas can be generated by substoichiometric combustion in the
direct heater. This heater is required in any case for heating process gas to
the reactor inlet temperature. Reactor effluent is cooled subsequently in a
heat exchanger and a cooling tower. Water vapor in the process gas is
condensed, and condensate is sent to a sour water stripper.
Cooled gas, normally containing up to 3% vol HaS and up to 20% vol C02, is
countercurrently washed with an alkanolamine solution in an absorption column
specially designed to absorb almost all H2S but relatively little C02. The
treated gas from the absorption column, which contains only a trace of HzS, is
burned in a standard Glaus incinerator.
The concentrated H2S is recovered from the rich absorbent solution in a
conventional stripper and is recycled to the Glaus unit.
The benefits of this process are: Easy adaptability to an existing Glaus
plant, the use of familiar process technology and equipment, easy and flexible
operation, elimination of secondary air and water pollution, and a high degree
of sulfur removal over a wide range of operating conditions. It is also
favored since initial costs of installation are relatively low.
A flow diagram is presented in Figure 14.
Parson's Beavon Process —
This process consists of three basic steps: (1) Hydrogenation of
sulfurous compounds to H2S in a catalytic converter; (2) cooling of the
converter-effluent gases; and (3) conversion of the HaS in the tail gas from
the cooler to elemental sulfur by the use of either the Stretford or Takahax
processes. This proven process is preferred if the tail gas has a "high" C02
content (20-40% by volume).
-41-
-------
REACTOR
REDUCING GAS
CLAUS UNIT
OFF-GASj-j
START
COOLING
TOWER
TO CLAUS UNIT
INCINERATOR
LEAN
5
AMIPJE
FAT AMINE TO
CONDENSATE TO
SOUR WATER
STRIPPER
REGENERATOR
Figure 14: Flow diagram of the SCOT process.(13)
-------
In the first portion of the process, all sulfur compounds in the Glaus
tail gas (S0a» SO , COS, CSg) are converted to H2S. The tail gas is heated to
reaction temperature by mixing with the hot combustion products of fuel gas and
air. This combustion may be carried out with a deficiency of air if the tail
gas does not contain sufficient H2 and CO to reduce all of the SQz and SO to
HjS. The heated gas mixture is then passed through a catalyst bed in which all
sulfur compounds are converted to HaS by hydrogenation and hydrolysis. The
hydrogenated gas stream is cooled by direct contact with a slightly alkaline
buffer solution before entering the HjS removal portion of the process.
The Stretford or Takahax process is then used to remove HjS from the
hydrogenated tail gas. The Stretford process involves absorption of the HjS in
an oxidizing alkaline solution. The oxidizing agents in the solution convert
the HzS to elemental sulfur, then are regenerated by air oxidation, which
floats the sulfur off as a slurry. This sulfur slurry is then filtered,
washed, and melted to recover the Stretford solution and produce a high-purity
sulfur product.
A flow diagram is presented in Figure 15.
The Japanese Takahax process is essentially the same as the Stretford
process, except for the chemicals used. Takahax uses an absorbent solution of
sodiun carbonate: 1, 4-naphthoquinone, and 2-sulfonate sodiun.
Ptitchard's Clean Air Process —
This process recovers 99.9% of the sulfur from the Glaus plant tail gas,
leaving no more than 570 mg/m3 (200 ppm) SOa equivalent in the effluent. This
process is installed upstream of the incinerator in a conventional Glaus plant
and consists of three stages, installed stepwise, to achieve decreasing
amounts of sulfur emitted to the atmosphere. The first stage removes SOz and
sulfur by aqueous scrubbing in a tower which quenches the gas from 400 to 300°K
(270 to 120°F). The second stage removes the HzS in a Stretford unit. Stage
three reduces the COS and CSz by approximately 90% by operating in Glaus
reactors at elevated temperatures.
Trentham's Trencor-M Process —
This process is similar to the SCOT process. The tail gas is heated to
560°K(550°F) and reacted with hydrogen over a noble-metal catalyst to reduce
all sulfurous compounds to HzS. The stream is then cooled and pumped to an
line absorber.
Wet-Oxidation Processes
Wellman-Lord Process —
Tail-gas from sulfur units is first incinerated to convert all of the
sulfur compounds originally present (HzS, COS, CSz, etc.) to S02. The hot
gases are cooled in a waste heat boiler, then quenched and fed to the SOz
absorber. (See Figure 16.)
The acid bottoms from the absorber flow to the oxidizer, where air is
blown into the tower. The oxidizing catalyst is an inexpensive, nonpoisonous
compound that is soluble in the acid. Part of the acid goes from the oxidizer
-43-
-------
REACTOR
STRETFORD
ABSORBER
OXIDIZER
FILTER
SULFUR
MELTER
SULFUR PLANT
TAIL GAS
START
AIR
FUEL GAS
HYDROGENATED
COOLED TAIL GAS
TO H2S RECOVERY A CLEAN
f
GAS
SULFUR
FROTH
LIQUOR SULFUR
RETURN
-------
WASTE
HEAT
BOILER
HP
STEAM
QUENCH&GAS
SO,
CLAUS PLANT
TAIL GAS
< »
i 1
START
INCINERATOR
COOLING SECTION ABSORBER
EVAPORATOR
CLEAN
AIR
PRODUCT S02RECYCLED
TO CLAUS PLANT
DISSOLVING
TANK
Figure 16: Flow diagram of the Wellman-Lord process.(13)
-------
back to the absorber, while the rest goes to a crystallizer . Limestone is
mixed with the acid solution in the crystallizer to form gypsum crystals.
Despite high initial costs this tail gas clean up process is preferred if the
tail gas has a high COz content.
USBM Citrate Process —
In the U. S. Bureau of Mines (USBM) Citrate process, the Glaus tail gas is
first incinerated and cooled by conventional means. Then the gas flows to an
absorption tower, where the S02 is absorbed in an aqueous solution of citric
acid and other carboxylat:;s. The rich solution flows to a stirred reactor
vessel where EzS is added to precipitate elemental sulfur.
The sulfur is concentrated by air flotation, and is ultimately melted and
drawn off from the system as a liquid. The HaS required for the reaction step
is taken from the feed stream to the Glaus plant.
Wet-Extension Processes
IFF Process —
There are two different schemes in the Institute Francais de Petrole (IFP)
process. IFP-1 removes HaS and SC-2 from tail-gas to an SOa level of 4.3 to 5.7
g/m3 (1500 to 2000 ppm). IFP-2 removes the SO^ to a 1.4 g/m3 (500 ppm) level or
below.
In the IFP-1 process, tail-gas is injected into a packed tower and
contacted countercurrent with solvent containing catalyst. Sulfur is formed,
collected and removed from the bottom of the tower. Operating temperatures in
the tower range from 390-410°K (250-280°F).
In the IFP-2 process (shown in Figure 17), the tail-gas is scrubbed with
aqueous ammonia after incinceration. Clean overhead is incinerated and vented
up the stack. Brine containing sulfites, bi-sulfites and a small amount of
sulfates from the scrubber are evaporated; sulfates are reduced, and mixed
overheads are injected into the bottom of the contactor along with the
stream. Solvent containing catalyst is circulated countercurrent to the
gas flow. Operating temperature in the contactor ranges from 390 to 410°K
(250-280°F). Sulfur is formed, collected and removed from the bottom of the
tower. Anmonia is removed overhead and returned to ths scrubber.
Stauffer Aquaclaus Process —
The Aquaclaus process is a new concept developed by the Stauffer Chemical
Co. It is a wet-absorption system that is reported to be capable of producing
a treated gas which contains less than 0.27 g/m (100 ppm) of S02-
In this process, the Glaus tail-gas is first incinerated to convert all
sulfur-bearing compounds, such as H2S, COS, CSa, etc., to SOj. Then the stream
is cooled in a waste-heat boiler and/or a direct-contact cooler, and is fed to
an absorption tower. The S02 is absorbed by the Aquaclaus solution, aqueous
sodium phosphate.
The rich solvent from the absorber is contacted with fresh H2S feed, from
the front of the Glaus plant, in a reactor vessel to form elemental sulfur by
-46-
-------
TO STACK
L-i
FUEL GAS
NH
CATALYTIC
REACTOR
AMMONIA SCRUBBER
MAKE-UP
\
NH, RECYCLE
j __»
H9S-CONTAINING GAS
*
AMMONIACAL
BRINE
TAIL
GAS
• •• - ••* n ITI ivi u i* i
A A BRIK
FUEL
IL GAS
SULF1TE
EVAPORATOR
AND S02
REGENERATOR S04
THERMAL
CATALYTIC
INCINERATOR
PURE
SULFATE LIQUID
REDUCER SULFUR
SOLVENT
MAKE-UP
Figure 17: Flow diagram of the IFP-2 process.(13)
-------
the classic Glaus reaction occurring in an aqueous phase. The solution i;
heated and liquid sulfur is withdrawn. The Aquaclaus solution is cooled anc
recirculated to the absorber after the sulfur is separated.
A few disadvantages, such as undesirable side reactions occurring in the
absorber and reactor and high maintenance costs, have been noted to date.
Townsend Process —
The Townsend process is similar to the IFF process, in that it uses at
organic solvent (such as triethylene glycol) to allow HaS and S02 to react
(Glaus reaction) to form elemental sulfur. The reactor is operated at ;
temperature above the melting point of sulfur, so that liquid sulfur is
produced from the bottom.
This process may be applied directly to treatment of Glaus-plant tail gas,
without any preconditioning of the gas. As far as is presently known, COS o:
CSa are not removed from the gas. Therefore, it has some of the same drawback;
(for attaining very low emissions) as the IFF process.
ASR Sulfoxide Process —
The Sulfoxide process, marketed by Alberta Sulfur Research Ltd. (ASR), i<
likely to remove sulfur compounds from gas streams at better than 99.9%. Thi:
process uses an organic sulfoxide as a liquid-catalyst reaction medium for the
Glaus reaction. The process chemistry involves the initial formation of a:
adduct between the sulfoxide and the HaS, which in turn forms a complex wit:
the other sulfur compounds present. The oxidation-reduction reactions occu:
in this complex to yield HaO, COa and sulfur.
Typical low concentrations of HaS and SOa in tail-gas streams can be
reacted virtually to completion. A most-important factor in the process is it;
ability to convert COS and CSa to COa and sulfur. The process can convert
better than 70% of the COS and CSa present to sulfur.
Dry-Extension Processes
SNPA/Lurgi Sulfreen Process —
This process is essentially an extension of the Claus process, except that
HaS and SOa are made to react at temperatures below the sulfur dew point of the
reaction gas mixture:
2HaS + SOa -»• 3S + 2H20 + 35 Real.
Since equilibrium conversion becomes more complete as the temperature i<
lowered, substantially higher sulfur recovery is possible than in a norma.
Claus plant. The reaction takes place in the presence of a catalyst, eithe:
alumina or special activated carbon. Sulfur formed is adsorbed on the catalyst
which eventually becomes saturated, requiring periodic regeneration b;
desorption of the sulfur with hot gas. The process reduces sulfur compounds it
the gas stream to a minimum, as the catalyst acts as a very effective adsorbent
for liquid sulfur. COS and CSa are not affected.
-48-
-------
An alternate of the Sulfreen process involving a two-stage treatment can
provide overall recoveries exceeding 99%. A two-stage Sulfreen unit consists
of two catalytic beds in series. In the first bed HaS and SOa form sulfur
according to the Glaus reaction; however, the ratio of HaS/SO a is adjusted in
such a manner that essentially all of the SOz is consumed and the effluent gas
contains only HaS. After addition of air to the first stage effluent, HaS is
oxidized directly to sulfur in the second stage.
Amoco CBA Process —
The Amoco Production Co. "cold-bed" absorption (CBA) process is very
similar to the Sulfreen process, except CBA uses a process stream indigenous to
the Glaus plant to accomplish regeneration of the sulfur-fouled catalyst beds
in the CBA reactors. As with Sulfreen, the CBA process is basically an
extension of the Glaus reaction over a cool bed, 400-420°K (260-300° F), of
conventional Glaus catalyst. Amoco claims overall recoveries (Glaus + CBA) of
98-99.5%.
Dry-Oxidation Processes
Shell SFGD Process —
Shell Oil Co. developed its Shell flue-gas-desulfurization (SFGD) process
mainly for SOa recovery from stacks, but it can also be applied for Glaus
tail-gas stream cleanup. In this version of the SFGD process, the tail-gas is
first incinerated to oxidize all sulfur compounds to SOz- The gases are cooled
somewhat to about 670°K (750°F) and are passed to a fixed bed of copper
oxide-on-alumina to adsorb SOa from the gases. Two or more beds are used, and
a swing-bed scheme is used to adsorb, regenerate, adsorb, etc. The SOa is
desorbed from the adsorbent, at about 670°K (750°F), by addition of a hot
reducing gas such as Ha or Ha/CO mixture. The SOa may be used to produce
sulfur, sulfuric acid, or other by-products.
Westvaco Process —
The Westvaco Corp. has developed an activated-carbon adsorption process
for COa removal from stack gases and Glaus tail-gas. The Glaus tail-gas is
first incinerated at 810°K (1000°F) and diluted with air to bring the oxygen
level to about 3.5 vol %. Then the gas is cooled in three stages to 360°K
(200° F) .
The gas then flows to a three-stage SOa adsorber. This is a continuous,
countercurrent, multistage, fluidized-bed adsorber, with carbon particles
flowing downward and tail gas flowing upward. The SOa is adsorbed from the gas
as sulfuric acid by the activated carbon. The treated tail-gas leaves the
adsorber containing less than 0.54 g/m3 (200 ppm) SOa. The SOa is released
from the HaSOi»/carbon in the regenerator, and is recycled back to the front of
the Glaus plant.
SNPA/TOPSOE Catalytic-Oxidation Process —
The Societe Nationale des Petroles d'Aquitaine (SNPA) of France and
Haider Topsoe of Denmark have developed a wet-contact catalytic-oxidation
process for treating Glaus unit tail-gases.
-49-
-------
In the SNPA/Topsoe Process, the Glaus unit tail-gases are first inciner-
ated to transform all sulfur into SOs. The gases are cooled in a waste-heat
boiler to 690°K (790°F). They are then passed through a converter containing a
vanadium oxide-base catalyst. SOa is oxidized to SOs, with a 95% yield.
The converted effluent gases are cooled in a boiler feedwater economizer
to 570°K (570°F), and then go through an acid concentrator and on to the
absorber, in which SOa is absorbed to form 80 wt % HaSOif. This "weak" acid is
then sent to the concentrator, in which heat from the incoming gases evaporate
part of the HaO and a 94 rt % of HzSCK is produced. The product acid is cooled
and sent to storage.
The clean tail-gas from the absorber may be reheated or sent to the stack
directly.
HEAVY HYDROCARBON STRIPPING
The final phase of the natural gas processing procedure is the recovery of
the natural gas liquids: ethane, propane, butane, pentane, isobutane, and
natural gasoline. There are both economic and operational reasons for the
recovery of these components. They are worth more sold as a liquid than as a
gas. The presence of small amounts of liquid in the pipeline can reduce the
efficiency 10% since the pressure drop increases for a given flow rate as the
liquids condense.(15) Also, the presence of heavy hydrocarbons in the feed
entering a liquification unit can result in freeze-ups in heat exchangers or
require the inclusion of additional liquid separators and special piping in the
cold box to remove these materials from the process gas stream.
There are seven major processes for this gas separation step: absorption,
refrigerated absorption, refrigeration, compression, adsorption, fractiona-
tion, and cryogenics/turboexpansion. These will be discussed in the following
subsections.
Absorption
This process is used to remove natural gasoline, LPG (mixed ethane,
propane and butane) from a wet natural gas. A flow diagram of the process is
presented in Figure 18. 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.
-50-
-------
RESIDUE GAS
NATURAL
GASOLINE
Figure 18: Absorption plant for natural gasoline.(10)
-51-
-------
Refrigerated Absorption
A flow sheet of the refrigerated absorption process is presented in
Figure 19.
In this process, the incoming gas is dehydrated to a 230°K (-40°F) dew
point. This is accomplished by bringing the incoming natural gas into contact
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 8.1 kg/106 m3 (0.1 lb/raillion ft3) of
gas processed into the atmosphere. After dehydration, the gas passes through
two absorbers in series at 230°K (-40°F). 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 is 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 0^+ hydrocarbon
stream for sales.
High recoveries of ethane using this process are uneconomical, due to the
large steam requirement and amount of oil that must be circulated. Yet it is a
favorable process for LNG recovery at remote locations since the refrigerant
(propane) and the absorption oil (natural gasoline) can be recovered from the
feed gas itself.
Refrigeration Process
The amount of heavy hydrocarbon vapor that can be held at saturation by
natural gas decreases with decreasing temperature and/or increasing pressure.
Increased recovery of LPG and natural gasoline can be achieved in a compressor
plant if refrigeration is used in place of cooling water in the compressed gas
coolers.
A refrigeration plant is shown in Figure 20. In this process, the inlet
gas is dried to a dew point of 190°K (-120°F), using molecular sieve beds.
Water vapor is adsorbed on these beds which are used in parallel, arranged so
that one is on-stream while the other is being regenerated. 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
operating bed. The dry gas from the molecular sieve is then passed through a
heat exchanger where it is cooled to 236°K (-35°F). Liquids which condense are
removed in a separator. The gas from the separator is cooled to 180°K (-135°F)
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 cools the incoming feed gas. The
liquids from the two separators are fed to five distillation columns in a
series where methane, ethane, propane, isobutane, normal butane and natural
gasoline are recovered as separate products.
-52-
-------
STEAM&GLYCOL
INLET GAS
100F
C. &TO SALES
4
RICH OIL
OEMETHANIZEB
Figure 19: Flow diagram of the refrigerated absorption process.(10)
-53-
-------
TAIL GAS
(TO PIPE LINE)
MAIN HEAT EXCHANGERS
SEPARATOR
KNOCKOUT DRYER REFRIGERANT) V
DRUM
SEPARATOR I
NORMAL
BUTANE
NATURAL GASOLINE
Figure 20: Flow diagram of the refrigeration process.(13)
-54-
-------
Compression
Natural gas is often transported through high pressure pipelines as a
matter of economy. Where the gas is produced at low pressure, the gas must
first be compressed. Although natural gas is seldom compressed solely for the
purpose of LPG or natural gasoline recovery, significant amounts of these
products are recovered from compressor stations. Under pressure, the heavy
hydrocarbons are condensed and separated from the natural gas. Since the
increase in pressure per stage is limited by practical considerations, several
stages of compression may be needed to reach the required pressure.
Figure 21 is a flow chart for a typical two-stage compressor station. Gas
enters through an inlet scrubber or knockout drum to remove entrained liquid.
The gas is compressed in the first stage cylinder, cooled by a cooling water
exchanger and sent to the first stage accumulator. Water and hydrocarbons are
separated from the gas under liquid level and interface level control. The
liquid hydrocarbons are sent to a distillation unit for recovery of LPG and
natural gasoline. The gas is then compressed in the second-stage in a similar
manner.
Adsorption
The flow sheet of this process (Figure 22) 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.
Other adsorbants which are used include alumina, silica gel, molecular
sieve, zeolites, and charcoal.
Cryogenics/Turbo-Expansion
Cryogenic or turbo-expansion gas processing uses temperatures in the
140°-200°K (-100 to -200°F) range. The lower temperatures enable greater
percentages of ethane and propane to be extracted. There are two methods of
lowering the gas temperature using pressure drop and heat exchange. The first
is by a choke of throttling calorimeter expansion. . In the process of expanding
across the control valve (choke), the temperature of the gas is lowered. The
second is the expander-cycle process which uses a "reverse running" centri-
fugal compressor or turbine. In the process of expansion through the turbine,
the gas works on the wheel of the turbine; thus, useful work is produced which
is usually used for recompression.
Figure 23 presents the basic expander cycle. The gas must first be
dehydrated to a dew point at least as low as 200°K (-100°F) by any one of the
dehydration processes.
-55-
-------
GAS (FROM FIELD!
COMPRESSOR
SEPARATOR
SEPARATOR
0.37 MP,i
(M) PS 1C,)
COMPRESSOR
GAS (TO PIPELINE!
l.ftt MPa
fjn PS in)
HIGH
STAGE GASOLINE
LOW STAGE GASOLINE
Figure 21: Flow diagram of the compression process.(13)
-------
STEAM
—txj—»•
0
MX—i
B
ADSORBERS
•5**
NATURAL GAS
•CXh-
(FROM FIELD)
RESIDUE GAS _
(TO PIPELINE)
CONDENSER
LIQUIDS
WATER
NOTE: FLOWS AND VALVE POSITIONS ARE SHOWN FOR
ADSORBER 'A' ON STREAM AND ADSORBER 'B'
ON REGENERATION.
Figure 22: Flow diagram of adsorption process.(10)
-57-
-------
i
i-n
OO
I
*RECOMPRESSOR
TO 800 psif))
FEED GAS
1.0 to 10.5 HI'a
(150 TO 1',()() |
If." TO 3H°C
TO ioo"r
TO
((100° TO 130")
\EXPANDER
SUPPLEMENTAL
COMPRESSION
IF REQUIRED
TO PLANT FUEL
/INLET GASV"
"\SEPARATOR
INLET RESIDUE
GAS EXCHANGER
CONDENSATE
STABILIZER
0.3b to 4.1 MPa
(50 TO COO psiq)
SALES GAS
-180 TO 120°C
(00 TO -180°F)
*RLCOMPRESSOR CAII BE SHITCIIEC TO FLED
GAS COMf'RCSSION TO MAKE BEST USE Of
EXPANDER WORK IN CERTAIN CASES.
**l'kODl)CT RECOVERIES DEPEND ON THE ACTUAL
DESIGN CONDITIONS AND THE DESIRED PRODUCTS.
ETHANE RECOVERY OF UP TO 90': ANO/OR
PROPANE RECOVERY FROM 70i TO 9n;, WILL FIT
MOST APPLICATIONS. BUTANES AND HEAVIER
RECOVERY HAY RAIIOE FROM >)') fd lull IN
THESE CASES.
**
RAW
HEAT
^.MEDIUM
PRODUCT TO
STORAGE
OR
FRACTIONATION
COND. STABILIZER
REBOILER
RAW PRODUCT
COOLER
38 TO
(lnn° T0 12f)°F)
Figure 23: Flow diagram of the expander cycle. (16)
-------
After dehydration, the feed is chilled down with cold residue gas. A
large amount of liquid is produced which is separated before entering the
expander. This liquid flows to the condensate stabilizer. Gas from the
separator flows to the expander. The expander exhaust stream typically
contains up to 20 wt % liquid. This two-phase mixture flows to the top section
of the stabilizer which separates the liquid and gas. The liquid stream flows
down the tower and acts as reflux. Cold gas from the stabilizer cools the feed
and is then compressed by the expander-driven compressor. Supplemental
compression is supplied, if required.
FUTURE PROCESSING TRENDS
Future processing trends tend to fall into several main areas: low
temperature hydrocarbons recovery, increasing automatic and less manual
process control, energy conservation and construction of small modular plants
which can be moved from site to site. Of these, only the first is actually
concerned with new processing methods. The others are related to current
process improvement.
The main processing trend is away from the traditional absorption process
to the cryogenic and expander plants for hydrocarbons recovery. Table 9
presents a tabulation and comparison of the U. S. gas-products-extraction
processes used in 1976 and 1977. As can be seen, the expander and cryogenic
processes show the greatest use increase by a wide margin. The low temperature
processes require less fuel and recover greater percentages of ethane and
butane. These parameters are compared in Table 10 with those of the absorption
process.
The second area of future trends is the area of energy conservation and
automatic process control. The growing shortage of domestic energy requires
all industry to try to optimize energy usage. This is directly tied to the
trends of turbo-expansion which requires less energy than absorption and
computer use which optimizes the processes more accurately than heretofore
possible.
Another innovation being developed is the construction of portable
gas-processing plants. Portable gas-processing plants are also coming into
use because of the energy demand. As the demand for energy continues to grow,
the feasibility of processing smaller volumes of natural gas increases
substantially. The relatively short fabrication and installation time for the
current generation of small, portable gas processing plants enables them to be
quickly set up so that small oil and gas fields can be developed and produced
efficiently and economically.
-59-
-------
TABLE 9
COMPARISON OF DOMESTIC GAS PRODUCTS EXTRACTION PROCESSES (17)
Process
Refrigerated absorption
Refrigeration
Absorption
Expander
Adsorption
Cryogenic
Compression
Fractionation
Total
1976
Number of Installations
1977 Change % Change
337
180
131
13
56
17
14
4
317
163
125
82
55
42
15
7
-20
-17
- 6
+69
- 1
+25
+ 1
+ 3
-5.9
-9.4
-4.6
+530.8
-1.8
+147.1
+ 7.1
+75.0
752
806
+54
TABLE 10
COMPARISON OF SEVERAL OPERATION PARAMETERS FOR
ABSORPTION VS. CRYOGENIC PLANTS (18)
Parameter
Temperature
Fuel Consumption
Ethane Recovery
Propane Recovery
Type of Plant
Absorption Cryogenic
240-300°K
(-20 - 90°F)
2-4%
0 - 35%
50 - 90%
170°K
(-150°F)
1 - 2%
60 - 90%
92 - 98%
-60-
-------
SECTION 6
AIR POLLUTION ASPECTS OF THE DOMESTIC GAS PROCESSING INDUSTRY
Quantitative information on natural gas processing emissions is very
limited. Emission inventories for Texas and Louisiana, the states with over
60% of the total number of plants in the U.S., were the most comprehensive
information sources found. The National Emissions Data System (NEDS) does not
have any emissions information for natural gas plants. It was intended that a
comparison of gas industry emissions estimates with NEDS data for other
industry categories could provide a perspective of this industry's contri-
bution to the total domestic emissions load. However, the NEDS data is based
on major sources, those emitting more than 100 tons per year of a criteria
pollutant. The estimates of gas processing industry emissions are based on
data for all gas processing plants, not just those emitting more than 100 tons
per year. Because of this dissimilarity between sources of information,
comparing natural gas processing industry emissions with a range of other
industrial categories within this scope of work was not possible. The
evaluation of the air pollution aspects of the industry was limited to
providing the following:
o an estimate of the industry's emissions
o a summary of the Texas and Louisiana emission inventories
o a discussion of in-plant emission sources and control techniques
currently employed in the industry.
AIR EMISSIONS IN THE NATURAL GAS PROCESSING INDUSTRY
There are four major pollutants associated with the natural gas
processing industry:
o Sulfur Dioxide (SOa)
o Hydrocarbons (HC)
o Hydrogen Sulfide (HzS)
o Glycol
-61-
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Sulfur Dioxide
Sulfur dioxide is a significant pollutant emission associated with sour
gas processing plants. Historically, field flares and waste gas venting at
field sites and processing plants were major point sources. However, air
pollution regulations and increased market value for natural gas products has
led to a remarkable decrease in venting and flaring since 1970 (75%
reduction). Flares and vents are generally used only as safety devices.
Sulfur dioxide is a combustion byproduct of HzS and is largely emitted
from HaS flares in processing plants that do not have sulfur recovery
facilities. Sulfur recovery facilities, such as Glaus plants, generally have
tail gas cleanup process which can routinely reduce SOa emissions to 1.4 g/m
(500 ppm).
The total estimated S02 emissions from the natural gas processing industry
in 1976 were approximately 4900 ktpy (5400 thousand short tons per year (Tpy) ) .
(See Table 11.)
As these data show, S02 emissions have decreased approximately 20% between
1969 and 1976. This is primarily due to the addition of substantial, new
sulfur recovery capacity over the last seven years. A significant element
affecting these estimates is the average industry-wide utilization for Glaus
plants which we set at 65% to be consistent with prior work. (10) However,
plants without sulfur recovery do remain the most significant contributors in
the industry, irrespective of the utilization factor (within practical
limits). We have assumed a Glaus plant sulfur recovery efficiency of 90% to be
consistent with prior work. However, most plants in Texas and Louisiana are
required by law to be 94-97% efficient. (13) We have also assumed a 99% sulfur
recovery efficiency for Glaus plants with tail-gas cleaning.
It is likely that future SOa emissions will stabilize or diminish against
rising production as old fields phase out of production and new ones are
developed. It is likely that the new processing plants serving these fields
will have sulfur recovery facilities whereas it is unlikely that older plants
will be retro-fit.
As the data in Table 12 show, the natural gas processing industry could
account for up to 20% of the total estimated sulfur dioxide emissions in the
United States in 1972.
Table 13 shows an estimate of the emissions from the fuel burning sources
associated with the natural gas industry (lease, plant and pipeline turbines).
These emissions with the exception of NO appear to be minor.
X
Hydrocarbons
The second most important pollution associated with natural gas process-
ing is miscellaneous hydrocarbons. Since the primary objective of gas processing
is to provide maximum yields of valuable products, hydrocarbon losses are
-62-
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TABLE 11
COMPARISON OF ESTIMATES FOR SULFUR DIOXIDE EMISSIONS
FROM PROCESS SOURCES IN THE NATURAL GAS PROCESSING INDUSTRY
1969 vs. 1976
1969 1976
Mtpy Mtpy
(xlO6 Tpy) (xlO6 Tpy)
Sulfur production in Glaus plants* 0.78 1.2
(0.87) (1.3)
Sulfur dioxide emissions, Claus plant
all without tail gas clean up** 0.15 0.23
(0.17) (0.26)
all with tail gas clean up*** 0.015 0.023
(0.017) (0.026)
Field venting and flaring volume(2) 14.7 Gcum 3.7 Gcum
(526 x 106 ft3) (132 x 106 ft3)
Sulfur dioxide emissions, 0.16 - 0.036
Field vents and flares (0.18) 0.04
Sulfur dioxide emissions .without 6.7 5.3
sulfur recovery plants ' (7.4) (5.8)
Sulfur in marketed gas 0S02 0.003 0.003
(0.003) (0.003)
Total estimated sulfur dioxide 6.9-7.1 5.4-5.5
emissions from process sources (7.6-7.8) (5.9-6.1)
*Industry capacity: 1969: 1200 kt/yr,(10) 1976: 1800 kt/yr;(19) 65%
utilization.
**Assune: 90% sulfur recovery( 10) .
***Assume: 99% sulfur recovery.
tAssume: 80% is flared,(10) 0.5 Mol% sulfur in raw gas.(10)
ttAssume: 100% flared product gas contains 0.5 Mol% sulfur and 95%
conversion to SO2-
-63-
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TABLE 12
COMPARISON OF SOz EMISSIONS FROM
ALL SOURCES
kt/year
(106 T/year)
Natural gas industry, 1972* 5500-5600
(6.1-6.3)
CEQ Data - 1972(13)
All industrial processes 4600
(5.1)
Stationary sources using 23900
fuel combustion (26.3)
Solid waste disposal 900
(0.1)
Miscellaneous 900
(0.1)
Total (except S02 from 29600
natural gas) (32.6)
*prorata 1969-1976
TABLE 13
ESTIMATE OF EMISSIONS FROM NATURAL GAS PROCESSING,
1976 PLANT AND PIPE LINE POWER GENERATION EQUIPMENT(2),(20)
Emissions
Pollutant ktpy
Particulate 5-15
Sulfur Oxides 0.6
•is n 2
Carbon Monoxide 13.0
Hdrocarbons 3.0
Oxides 120-230
-64-
-------
minimized by routine maintenance and plant design consistent with good
engineering practice. Major sources of hydrocarbon emissions are vents, and
storage facilities.
The total hydrocarbon emissions from the natural gas processing industry
in 1976 (latest year for which data are available) are estimated to be an
average of 4,400 tpd (4,900 Tpd) by venting and flaring. An additional 28,600
tpd (31,500 Tpd) is unaccounted for in the entire production, distribution and
final usage network. These estimates are based on the data in Table 2 and the
following assumptions:
o 20% of "vented and flared" gas is vented.
o Flaring of the remaining gas reduces the hydrocarbon emissions by
90%.
o All "unaccounted for" gas is lost to the atmosphere by miscellaneous
fugitive sources.
o The emitted hydrocarbons have an average density of 1.6 kg/m3 (0.1
Ib/cf) (mainly methane, ethane, propane and butane).
As data in Table 2 show, an substantial decrease in "venting and flaring',
from 2% to 0.6% of the total gross production, has occurred from 1970 to 1976.
It is logical to assume that some additional improvement will be made
in curtailing venting and flaring as the value of these products increase.
Losses "unaccounted for" have remained consistently at 10% of total production
since 1970. We presume these losses, which are a substantial part of the total
of 33,000 tpd (36,400 Tpd) are fugitive emissions from miscellaneous sources
such as flanges, pumpseals, pressure safety relief valves, etc.
Lease plant and pipeline power generating equipment contributes 2,700 tpy
(3,000 Tpy) of hydrocarbons (see Table 13).
No information has been found that could be used to differentiate reactive
and nonreactive components of the total hydrocarbon emissions from this
industry. A typical natural gas as extracted from the well may contain up to
90-95% methane, ethane, carbon dioxide, hydrogen sulfide and water. The
balance is primarily paraffinic.
Hydrogen Sulfide
We were not able to find sufficient information to develop a reliable
estimate for total industry-wide hydrogen sulfide emissions. Others have
estimated these emissions as approximately 47 metric tons per day (52 Tpd).(10)
-65-
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Glycol(lQ)
To estimate the amount of triethylene glycol (TEG) emitted to the
atmosphere, the following information was required:
o the number and capacity of plants using glycol dehydration and which
vent the water vapor produced by the dehydration step, and
o the quantity of triethylene glycol consumed as a function of gas
processed.
This information was not readily available so the following assumptions were
made:
o 25% of all gas produced in the U.S. is dehydrated with TEG.
o All plants vent the dehydration water.
o 50% of glycol losses are entrained with vented dehydration water.
The other half is entrained in the gas stream.
Maximum glycol losses are estimated as 1.06 kg/Mm3 (0.1 gallons/mcf)
which leads to a daily emission rate of 6.3 tpd (7 Tpd).(lO)
TEXAS EMISSION INVENTORY
An emission inventory was obtained from the Texas Air Control Board in
Austin, Texas. The inventory contains quantified emissions data for 1973. The
data are broken down into natural gas processing plants, alphabetically by
county, for each of the state's twelve regions. The data includes the yearly
quantities of NO , SO , hydrocarbons (HC), CO, particulates (P), and HaS
emitted from all 518 Texas plants.
Space limitations prevent listing the emissions for each of the 418
plants. However, the results are summarized in Table 14.
As can be seen from the tables NO and SO are the emissions produced in
the greatest quantity by Texas natural gas processing plants. Hydrocarbons
rank third at about 40 percent of the SO level. The other three pollutants
are of minor importance.
Table 15 shows the contribution to sulfur and nitrogen oxides and
hydrocarbon air pollution in Texas by major industries. The natural gas
industry is the most significant in sulfur and nitrogen oxides and the third
highest in hydrocarbons as reported in the 1973 Texas Emission Inventory.
-66-
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TABLE 14
TEXAS EMISSION INVENTORY SUMMARY FOR NATURAL GAS PROCESSING PLANTS
1973 DATA
RPR ton
1
2
3
4
5
6
7
R
9
10
11
12
Ho. of
Plants
43
47
2
18
56
133
40
22
11
7
0
39
State Totals 418
Emissions in Metric Tons Per Year
(Short Tons Per Tear)
NO
X
13204
(14555)
39317
(43340)
66
(73)
5211
(5744)
41714
(45982)
95831
(105636)
33667
(37111)
4382
(4830)
2223
(2450)
2238
(2467)
—
15743
(17354)
253597
(279542)
SO
X
252
(278)
24902
(Z7450)
5401
(5954)
—
2425
(2673)
170888
(188372)
72
(79)
2612
(2879)
11480
(12655)
—
—
54971
(60595)
273004
(300935)
HC
2457
(2708)
16174
(17829)
31
(34)
2898
(3195)
22132
(24396)
27039
(40828)
16987
(18725)
2685
(2960)
1676
(1848)
659
(726)
—
9338
(10293)
112076
(123542)
CO
4.5
(5)
18
(42)
0.9
(1)
2.7
(3)
44
(48)
141
(155)
64
(71)
3.6
(4)
5.4
(6)
1.8
(2)
—
25
(28)
331
(365)
Part
38
(42)
207
(228)
5.4
(6)
13.6
(15)
216
(238)
494
(544)
308
(339)
27
(30)
34
(37)
16
(18)
—
142
(157)
1500
(1654)
H,S
763
(841)
9
(1.0)
8856
(9762)
117
(129)
214
(236)
9959
(10978)
-------
TABLE 15
POINT SOURCE EMISSIONS FROM INDUSTRIAL PROCESSES
TEXAS EMISSION INVENTORY -1973
POLLUTANT IN METRIC (SHORT) TONS PER YEAR
Industry
Sulfur Oxides
Nitrogen Oxides
Hydrocarbons
00
I
Natural Gas Processing
Petroleum Industry
Chemical Manufacturing
Primary Metal
Secondary Metals
Mineral Products
Wood Products
Food /Agriculture
Metal Fabrication
Leather Products
Textile Manufacturing
(300,935)
272,957
(253,309)
229,759
(153,774)
139,478
(133,049)
120,679
(59,867)
54,301
(12,614)
11,441
(5,177)
4,696
(56)
51
0
0
0
(279,542)
253,553
( 92,484)
83,886
(12,767)
11,580
(6,950)
6,304
(443)
402
(3,415)
3,098
(678)
615
(172)
156
0
0
0
(123,542)
112,076
(330,450)
299,728
(498,814)
452,439
(2,672)
2,424
(296)
268
(2,134)
1,936
(355)
322
(37)
34
(6)
5
0
0
-------
LOUISIANA EMISSION INVENTORY
A visit was made to the Louisiana Air Control Commission in New Orleans,
Louisiana, to obtain more detailed plant emission information than, was
possible to get with a general emission inventory such as that obtained from
Texas. Each of the natural gas processing plants in the State of Louisiana is
required to complete an emission inventory questionnaire. These questionnaires
provide information on total plant consumption, products, and emissions, as
well as the charging rates and emissions fcr each individual emission source
within the plant. The visit to New Orleans produced total plant emission
information for 52 plants and detailed individual point source emission
information for 18 of them. With this detailed information, it was possible to
determine what types of heaters and engines are in use and the emissions they
produce as well as the emissions associated with flares and storage tanks.
Table 16 presents a summary of the total plant emissions for 52 Louisiana
gas processing plants for the year 1975 along with the processes used for heavy
hydrocarbon stripping and the total plant throughput. It can be seen that
refrigerated absorption is most commonly used for hydrocarbons recovery with
approximately 75 percent of the plants using this process alone or in
combination with other processes. NO emissions predominate in the 52 plant
sample with CO emissions being secondary. However, high CO levels are noted in
only three plants (42, 44, and 47) with the remaining plants showing much lower
levels. The hydrocarbon level is about 30 percent of the NO level which is
similar to that noted in Texas. The big difference is the low SO level in
Louisiana compared with the high level in Texas. This could be 2ue to the
differences in raw gas quality. There does not appear to be any relationship
between total plant throughput and total plant emissions as can be seen in
Figures 24 and 25. Figure 24 is a plot of total plant NO emissions versus
throughput and Figure 25 is a plot of hydrocarbons emission versus throughput.
Table 17 through 20 present the charging rates, emissions, and emission rate
for flares, storage tanks, engines, and heaters, respectively. Emissions from
flares are mainly NO with the maximum noted being 5 tpy. Emissions from
storage tanks, which arise from breathing and working (i.e., filling) losses
are typically only 3.0 tpy (3.3 Tpy) from plant f/13's scrubber oil tank.
Engine emissions are NO , SO , and hydrocarbons with NO predominating by far.
Several plants utilize engines that produce about 635 t (700 T) of NO per
year. Heater emissions include all five pollutants, but only NO is prevalent
with a maximum of 172 tpy (190 Tpy) from a waste heat boiler.
An examination of the emission rates presented in the four tables reveals
that for the majority of the plants, the emission levels are derived from the
charging rates using emission factors obtained from AP-42 emission factors.
Tables 21 and 22 present these emission factors. This means that the values
presented for the emission levels are only estimates and are not based on
actual measurements. The total plant emissions are merely a function of the
number of engines, heaters, flares, and storage tanks along with their charging
rates and are not based on plant-wide measurements.
-69-
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TABLE 16
LOUISIANA EiMISSION INVENTORY SUMMARY
FOR THE NATURAL GAS PROCESSING INDUSTRY
1975 DATA
Nii'nber
1
2
3
4
5
6
7
8
9
in
11
12
n
1A
15
16
17
IS
19
Process
Used1
T
2
2
2
2
2
5
1
3
2
2,6 •
2,5
2
2
2
2
2
2
1
ThroiiRliput hm'/d
(MMcfd)
19752
2.4
(84.9)
5.4
(189.6)
1.0
(34.8)
J.6
(57.0)
1.2
(41.4)
1.0
(34.2)
0.3
(10.3)
0.25
(9.0)
—
2.2
(76.0)
22.3
(788. 3)
7.2
(254.1)
—
—
0.4
(15.0)
—
1.4
(50.5)
l.fi
(57.4)
—
19763
1.9
(66.0)
5.4
(190.0)
0.7
(26.0)
1.2
(44.0)
0.9
(31.0)
0.8
(28.0)
0.2
(7.1)
0.2
(7.1)
0.01
(4)
2.2
(79.0)
19.0
(671.5)
7.3
(258.9)
10. fl
(380.0)
2.2
(76.0)
—
2.5
(«9.4)
! .3
(46.0)
1.6
(57.4)
6.1
(215.0)
Emissions In Metric Tons Per Year'
(Short Tons)
"°x
816
(890)
2206
(2432)
353
(389)
251
(277)
816
(899)
170
(187)
3.6
(4)
26
(29)
0.9
(1)
160
(176)
404
(445)
734
(809)
227
(250)
142
(157)
26
(29)
60
(66)
403
(444)
496
(547)
320
(353)
SO
0.9
(1)
0.9
(1)
2.7
(3)
0.9
(1)
(
HC
1.8
(2)
5.4
(60)
1.8
(2)
0.9
(1)
1.8
(2)
0.9
(1)
17
(19)
3.6
(4)
93
(103)
56
(62)
111
(122)
19
(21)
7.2
(«)
29
(32)
140
(154)
198
(218)
330
(364)
CO
0.9
(1)
2.7
(3)
0.9
(1)
1.8
(2)
0.9
(1)
0.9
(1)
0.9
(1)
2.7
(3)
1.8
(2)
0.9
(I)
0.9
(1)
56
(62)
14
(15)
3.6
(4)
49
(34)
77
(85)
29
(32)
P«rt.
0.9
(1)
2.7
(3)
0.9
(1)
1.8
(2)
0.9
(1)
0.9
(1)
1.8
(2)
24
(26)
22
(24)
12
(13)
1.8
(2)
1.8
(2)
2.7
(3)
4.5
(5)
3.6
(4)
H2S
-70-
-------
TABLE 16 (Continued)
Nximber
20
21
22
23
24
25
26
27
28
29
30
11
32
33
34
35
' 36
37
38
Frocpgs
Used1
7,7
.-
7
2
2
2
2
2
2
2
i!
-
2
1
6,7
2,6,7
2
2
2
Throughput hm3/d
(MMcfd)
1975'
14.6
(515.1)
—
14.2
(500.0)
13.8
(488.5)
1.0
(35.9)
3.fl
(135.3)
4.8
(168.0)
2.7
(98.0)
1.0
(37.0)
33.4
(1180.0)
0.4
(15.6)
—
43.!
(1520.5)
1.7
(59.0)
3.4
(120.0)
17.0
(600.0)
0.4
(15.5)
1.6
(r'5.0)
45.9
(1620.0)
197&3
11.8
(417. •»
—
9.8
(346.0)
12.9
(457.0)
—
—
4.5
(160.0)
2.2
(76.0)
0.4
(14.7)
34.3
(1211.2)
0.1
(4.5)
—
37.2
(1315.3)
1.1
(40.5)
2.6
(91.7)
13.5
(478.3)
0.3
(11.8)
1.6
(57.3)
45. S
(1617.8)
Emissions In Metric
(Short 1
HO
X
409
(451)
23
(25)
605
(667)
365
(402)
40
(44)
185
(204)
2607
(2874)
559
(616)
H3
(125)
447
(493)
19
(21)
41
(45)
630
(694)
130
(143)
4.5
(5)
390
(430)
21
(23)
1524
(1680)
980
(1080)
sox
0.9
(1)
4.5
(5)
3.6
(4)
7.2
(8)
0.9
(1)
0.9
(1)
1.8
(2)
0.9
(1)
1.8
(?)
I1C
48
(53)
240
(265)
48
(53)
154
(172)
22
(24)
103
(116)
792
(873)
206
(227)
19
(21)
1251
(1379)
0.9
0)
254
(280)
588
(648)
113
(125)
9
(10)
16
(18)
2.7
(3)
181
(200)
46
(51)
: Tonn fer Year1
fens)
CO
5.4
(6)
185
(204)
1.8
(2)
37
(41)
29
(32)
137
(151)
265
(292)
67
(74)
1.8
(2)
1.8
(2)
10
(ID
27
(63)
1.8
(2)
0.9
(1)
54
(60)
1.8
(2)
P«rt.
8.)
(9)
13
(14)
3.6
(4)
44
(4R)
0.9
(1)
0.9
(1)
2.7
(3)
0.9
(1)
1.8
(2)
1.8
(1)
5.4
(6)
34
(37)
0.9
(I)
33
(36)
12
(13)
84
(93)
H2S
1.8
(2)
7.2
(8)
-71-
-------
TABLE 16 (Continued)
Number
39
'.0
41
42
43
44
45
46
47
4«
49
50
Process
t.'seJ '
5
2
2
2
2,6
2
2,6
6,7
2
6,7
2
1
Swcpt-
enlng
Swpet-
enlng
Throughput hm'/d
(MMcfd)
197^2
22.9
(807.1)
0.008
.3
0.6
(21.6)
7.2
(113.4)
0.6
(21.5)
0.7
(25.8)
5.9
(209.0)
0.6
(20.0)
24.1
1 850.0)
25.5
(900.0)
22.2
(785.0)
0.04
(1.3)
1976'
10.9
(386.0)
—
0.5
(18.8)
2.7
(96.4)
5.2
(185.0)
0.6
(22.1)
5.2
(185.0)
—
—
—
—
0.2
(7.0)
Emissions in Metric Tons Per Year1
(Short Tons)
NO
X
1672
(1843)
21
(23)
223
(246)
314
(346)
107
(118)
219
(241)
1491
(1644)
14
(15)
1042
(1149)
783
(863)
1556
(1715)
2.7
(3)
9
(10)
24159
(26631)
SO
986
(1087)
544
(600)
61
(67)
4.5
(5)
1624
(1790)
HC
30
(33)
118
(130)
641
(707)
10
(ID
242
(267)
621
(685)
494
(54)
10
(H)
194
(214)
7527
(8297)
CO
223
(246)
2.7
(3)
105
(116)
8382
(9240)
4628
(5101)
177
(195)
10
(11)
2190
(2635)
44
(49)
315
(347)
17379
19157)
P«rt.
2.7
(3)
0.9
(1)
10
(11)
1 .8
(2)
5.4
(6)
2.7
(3)
228
(251)
47
(52)
625
(689)
H2S
0.9
(1)
3.6
(4)
14
1S1
NOTES:
1 - Absorption
2 - P<*frlEprated Absorption
3 - RpfriRpratfon
4 - Compression
5 - Adsorption
6 - Cryogenic
7 - Erp^ndpr
•'Number obtained from 1975
F.mlselon Inventory Questionnaire
'Number Ohtnlned from Reft
llata Is for 1976.
-72-
-------
?000
600
1000
bOO
_L
100
200
GA:; THROUGHPUT
300
100
500
Figure 24: Louisiana emission inventory, NOX emissions (1973) vs. gas throughput
for the natural gas processing industry.
-------
1000
1X)0
LUIJL-.1ANA I.MlGSiOtl INVb'HORY
HC (MISSIONS vs GAS mi'OUr.HPUT
700
GOO
500
400
300
100
J_
J_
100
200 300
GAS THROUGHPUT , hm'V'J
400
500
Figure 25: Louisiana emission inventory, HC emissions (1973) vs. gas throughput
for the natural gas processing industry.
-------
TABLE 17
FLARE EMISSIONS FOR NATURAL GAS PROCESSING INDUSTRY
LOUISIANA EMISSION INVENTORY, 1973
Ul
I
Plant
Number
1
2
3
it
5
6
10
11
12
52
Charging Rate
to Flare
hmVyear (MMcf/yr)
0.11
(3.9)
0.75
(26.6)
0.07
(2.6)
0.42
(14.9)
0.02
(8.1)
0.22
(7.7)
0.08
(2.7)
1.08
(38.1)
0.88
(31.1)
10.33
(365.0)
Emissions In Metric Tons/Year
(Short Tons Per Year)
N0x
.41
(.45)
2.81
(3.10)
.27
(.30)
1.54
(1.70)
.84
(.93)
.80
(.88)
.15
(-16)
4.56
(5.03)
3.73
(4.11)
— —
S0x
.0005
(.0006)
.0036
(.0040)
.0004
(.0004)
.0021
(.0023)
.0011
(.0012)
.0010
(.0011)
—
—
—
60.8
(67)
HC
.005
(.006)
.036
(.040)
.004
(.004)
.020
(.022)
.011
(.012)
.010
(.011)
.004
(.004)
—
—
— '
CO
.030
(.033)
.209
(.230)
.020
(.022)
.118
(.130)
,063
(.069)
.060
(.066)
.021
(.023)
—
—
—
Part.
.026
(.029)
.181
( . 200)
.018
(.020)
.100
(.110)
.055
(.061)
.051
(.057)
.006
(.007)
.830
(.915)
.678
(.747)
—
Emlanlon Kate in Metric Tonn/lm'
(Short Tons Per MMcf)
H0x
3.68
(.115)
3.75
(.117)
3.68
(.115)
3.65
(.114)
3.68
(.115)
3.65
(.114)
1.89
(.059)
4.23
(.132)
4.23
(.132)
—
SO
X
.0048
(.00015)
.0048
(.00015)
.0048
(.00015)
.0048
(.00015)
.0048
(.00015)
.0045
(.00014)
—
— —
—
5.89
(.184)
HC
.048.1
(.0015)
.0481
(.0015)
.0481
(.0015)
.0481
(.0015)
.0481
(.0015)
.0449
(.0014)
.0481
(.0015)
—
—
—
CO
.2723
(.0085)
.2750
(.0086)
.2723
(.0085)
.2787
(.0087)
.2723
(.0085)
.2755
(.0086)
.2723
(.0085)
—
—
—
Part
.237
(.007
.240
(.007
.246
(.007
.237
(.007
.240
(.007
.237
(.007
.083
(.002
.768
(.024
.768
(.024
— •
-------
TABLE 18
STORAGE TANK EMISSIONS FOR NATURAL GAS PROCESSING INDUSTRY
LOUISIANA EMISSION INVENTORY, 1973
riant
Number
1
2
2
2
3
3
4
5
6
6
8
8
8
8
9
13
13
13
14
U
Mnlcrlnl
Rtored
Meth.inol
Hctlmnnl
nlntllnte nmt
nbsorptlon oil
Slnp tank
Itethnnol
Hcltinnol
Absorption oil
Hcth.inol
Absorption oil
nintlllnte
Diesel oil
Distillate
Comtennatc
rondensnte
Condensnte
Absorption oil
Sponge oil
Scrubber oil
Condensnte
Absorption oil
Drpnthlng
Losses
(HOnl/Yr)
6.3
8.4
50.4
16.8
3.8
4.2
1A. 8
6.3
10.0
1GB. 0
59.8
202.0
315.7
271.5
i
205.0
.17
.21
.60
.18
.09
Working
losses
(nnnl/Vr)
4.6
40.8
1944.4
500.0
2.6
2.6
173.7
3.4
78.0
1499.0
1.5
21.7
4J.1
35.2
23.9
—
.40
.17
.01
Fjiilsslons In Metric Tonn/Y^nr
(Short Tons Per Yc.ir)
no
X
—
—
—
—
—
—
~—
—
— -
—
—
—
—
—
—
—
—
SO
X
—
—
—
—
—
~~
—
—
—
—
— -
—
—
—
—
—
—
IIP.
.15
(17)
l.f.3
(1. BO)
0.09
(.10)
50.89
(56.10)
.83
(.92)
.87
(.96)
.42
(.46)
(l.RO)
.18
(.20)
.64
(.70)
.07
(.OB)
.27
(.30)
.48
(.**)
.41
(-37)
.31
(.28)
.49
(.54)
.64
(.70)
2 no
0.30)
.82
(.90)
.27
( . 10)
CO
—
—
—
—
—
—
"•"
—
--
—
—
—
—
—
—
— —
—
—
Part.
--
—
—
—
—
—
~~
—
—
—
—
—
—
—
—
"
—
—
Emission R.ite (Tons Ter lit;
MO
X
—
—
—
—
—
—
™"~
—
~
—
—
—
—
—
—
"
—
—
SO
X
—
—
—
—
—
—
~
—
—
—
—
—
—
—
—
~~*
—
—
lie
.0156
.0366
.0001
.1086
.I4JJ
.1333
.0024
.1649
.0023
.0004
.0013
.0013
.0013
.0013
.0013
3.176
3.333
3.300
2.571
2.911
t:o
—
—
—
—
—
—
--
—
—
—
—
—
—
—
—
—
—
—
ICnl)
-------
TABLE 19
ENGINE EMISSIONS FOR NATURAL GAS PROCESSING INDUSTRY
LOUISIANA EMISSION INVENTORY, 1973
Type of
Ki>r. Inr
fipcowprensor
RpfrIgerntIon Oonprrnsor
fipnprnror
Refrtcprntton Coi»prrnnor
Dprotnprpnsor
Rcf r lRnr.it Ion Compreiisor
flpnernlor
DrcomprcoBor
RBfrlBcrntlon Comprengor
r.ompiennor
Dceomprcflsor
Rrfr iRrrntloii Cowprrsnor
Grnerntor
Writer Well Fump
Lean Oil Pump
Comprrnnor
Rrf rlr.prntlnn Co
Churgln*
Rntc
(MMcf/Tr)
30.1
88.7
58.2
157,8
53.3
49.8
50.5
90.0
41.0
35.0
102.5
19.3
60.2
25.7
70.3
41.5
3.1
27.7
2.4
3.6
F.ml union* In HMtle Tons
(Short Tonn ter Tj
N°X
43.?
('•«.z>
59fi.O
(657.0)
15B.9
(175.2)
181.4
(700,0)
43.7
(48.2)
99.3
(109.5)
39.7
(43.8)
I-.8.9
(175.2)
31.8
(35.0)
43.7
(48.2)
596.0
(657.0)
0.4
(.4)
158.9
(175.2)
19.9
(21.9)
99.3
(109.5)
31.8
(35.0)
3.2
(1.5)
8.0
(8.8)
0.2
(?)
O.'i
(4)
SO
X
.OO'M
(.0045)
.OMB
(.0130)
.oono
(.oonrt)
.021B
(.0240)
.0073
( . OOflO)
. 00fi8
(.0075)
. 0069
(.0076)
.0127
(.0140)
.0006
(.0062)
.0048
(.0053)
.0136
(.0150)
.0026
(.0029)
.0081
(.0091)
.0033
(.0039)
.0100
(.0110)
.0087
(.0063)
.0005
(.0005)
.0073
(.0080)
.0007
(.0000)
.((009
(.0010)
IIC
.016
(.018)
.0'.B
(.053)
.012
(.035)
.085
(.094)
.027
(-032)
.027
(.030)
.027
(.OJO)
.049
(.054)
.023
(.025)
.019
(.021)
.056
(.062)
.011
(.012)
.083
(.036)
.014
(.015)
.038
(.04?)
.023
(.025)
,OO2
(.002)
15.096
(16.641)
1.313
(1.447)
1.970
(2.171)
Per Tmr
«)
CO
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Fart.
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
fnitflitton Hntp 1
(Short
»°K
51.29
(1.601)
237.29
(7.407)
96.43
(3.010)
142. It
(4.4)6)
28.96
(.90A)
70.45
(2.199)
27.78
(.867)
62.37
(1.947)
27.36
(.854)
44.11
(1.377)
205.35
(6.410)
0.74
(0.13)
93.23
(2.910)
27.29
(.852)
49.91
(1.558)
27.01
(.843)
36.17
(1.129)
10.12
(.316)
2.72
(.985)
3.20
(.100)
SO
.0048
(.00015)
.0048
(.00015)
,00'iB
(.00015)
.004B
(.00015)
.0048
(.00013)
.0048
(.00015)
.0048
(.00015)
.0051
(.00016)
.0040
(.00015)
.0048
(.00015)
.0048
(.00015)
.0048
(.00015)
.0048
(.00015)
.0048
(.00013)
.0051
(.00016)
.0048
(.00015)
.0048
(.00015)
.0093
(.00029)
.0106
(.OOOJ3)
.0090
(.00028)
n Metric Tom
Tan* per MHc
IIC
.0192
(.0006)
.0192
(.0006)
.0192
(.0006)
.0192
( . 0006)
.0192
(.0006)
.0192
(.0006)
.0192
(.0006)
.0192
(.0006)
.0192
( . 0006)
.0192
(.0006)
.0192
(.0006)
.0192
(.0006)
.0192
(.0006)
.0192
(.0006)
.0192
(.0006)
.0192
(.00t>6)
.0192
(.0006)
19.22
(.6000)
19.22
(.6000)
19.23
(.6001)
i IVr hm'
)
CO
—
—
—
—
—
—
—
—
—
—
—
—
—
— '
—
~~
—
— '
F«rt.
—
—
--
—
—
—
—
—
—
—
"
—
—
~"~*
~~
—
"
— ""
-._
-------
TABLE ]9 (Continued)
Plant
Number
10
10
10
11
12
12
12
14
14
14
15
15
15
15
15
15
If,
Type of
Engine
C,18
Cas
C.in
Fuel Cas Recomprennor
Recycle Ctwupressor
Compressor
Turbine
Decompressor
Compressor
Onnerator
Internal Combustion
Internal Combustion
Internal Combustion
Internal Combustion
Internal Combustion
Internal Combustion
Ctimpr rnnor
Charging
Rate
(MHcf/Yr)
22.0
55.5
18.0
28.7
61.2
80.7
82.9
26.6
113.9
39.1
5.0
7.4
8.3
.9
3.2
1.9
41.0
Emissions In Metric Tons Per Year
(Short Tons Per Year)
NO
X
20.0
(22.0)
59.9
(66.0)
10.0
(11.0)
56.1
(61.8)
11B.4
(131.6)
157.3
(173.4)
8.7
(9.6)
19.9
(21.9)
21.3
(23.5)
25.9
(28.5)
2.0
(2.2)
3.0
(3.3)
3.4
(3.7)
.4
(.4)
t.3
(1.4)
.7
(.8)
667 . 5
(735.8)
S0x
._
—
—
—
—
—
.0073
(.0080)
.2722
( . 3000)
.0091
(.0100)
—
—
—
.5715
(.6100)
IIC
11.793
(13.000)
29.937
(33.000)
9.979
(11.000)
—
—
—
.018
(.020)
2.177
(2.400)
.018
(.020)
2.359
(2.600)
3.502
(3.860)
3.946
(4.350)
.408
(.450)
1.515
(1.670)
.889
(.980)
.953
(1.050)
CO
._
—
—
—
—
—
5.90
(6.50)
—
—
—
—
—
16.21
(17.87)
Tart.
—
—
—
—
0.73
(0.80)
—
—
—
—
—
—
9.53
(10.51)
Rmlsslon Rnte Ji
(Short 1
NO
X
32.04
( 1 . 000)
38.09
(1.189)
19.57
(.611)
68.97
(2.153)
68.88
(2.150)
68.85
(2.149)
3.72
(.116)
26.37
A. 60
(.206)
23.35
(.729)
14.35
(.448)
14.38
(.449)
14.38
(.449)
14.42
(.450)
14.42
(.450)
14.42
(.450)
574.96
(17.497)
SO
X
—
—
—
.0096
( . 00030)
.0843
(.00263)
.0083
(.00026)
—
—
--
--
—
—
.'.924
(.01537)
i Metric To
Tons per HM<
IIC
18.93
(.5909)
19.05
(.5946)
19.58
(.OJ11)
—
—
__
.0256
(.0008)
.6760
(.0211)
.0160
(.0005)
16.73
(.5221)
16.73
(.5223)
16.79
(.5241)
16.63
(.5190)
16.72
(.5219)
16.79
(.5241)
0.8201
(.0256)
is Trr
•O
CO
-_
_...
-_
__
--
1.8
(.05
—
—
--
—
—
—
—
13.
(.'•3
Fait
.2243
(.007)
8.70
-------
HEATER EMISSIONS FOR NATURAL GAS PROCESSING INDUSTRY
LOUISIANA EMISSION INVENTORY, 1973
flnnt
Number
I .-
1
1
2
2
3
4
4
5
5
5
6
6
1
B
8
n
a
9
9
Tjrpe of
llc.-tter
Flrrtl llentor
C lye til Rrliollrr
Snlt Reclaimer Holler
Fired lleatpr
nlyrol Krboller
fJlycol Rrboller
Fired Heater
Rtycol Roboller
Flre
-------
TAI'.l.i, J, U uiiL iiiue'd
flnnt
H.imfrPr
in
10-
it
M
11
n
17
17
17
12
I?
n
11
11
11
n
M
K.
52
17
52
Tip* of
Procnn* llrntrr
(111 Rprlnlmrr
rrorpr>w Finllpr
Wnntp llrnt Hollrr
RpRpnrrnlnr Cnn llpnlcr
llollrr
Rlrli Oil llpnlrr
tlullpr .
Rpp/'tiPtfl tor Hprttpr
(Ml llrntpr
rtlH Rpliollrr llcntpr
S(pjim tipnprnlor
Stpnm Hpnprfltor
Bollpr FppJwntpr l|pnt«»r
Wnnlp Mpitt Rpclnlmpr
llpntrr
Flrpil llprirrr
rirril llpntrr
Hpnl pr
fins Inrlnpmlor
pphytlriitor trot-pn* Itentrr
Tntlirr Inf, 1.1 np llpfltrr
Charging
Mte
(Utef/Tt)
1B4.0
7..0
792.2
1997.0
45.1
719.0
485. 0
119.0
777. 0
1*1. n
1MJ.O
frftd.O
780.0
46.8
489.0
144.0
38.7
41.0
95.0
11.1
8.8.
1
Knilmlotm fn Mptrlc Tonn Tft T*«r
(Sliort Toim Ter Tmr)
N"x
9.9n
(11. IK))
.11
(.17)
55.fi1>
(f.1.19)
171.01
(190.09)
7.47
(7.77)
17.79
(14.10)
M.fifi
(14.90)
19.21
(71.7(J)
n. n
(18.00)
8.01
(8.81)
2f,.04
(78.70)
(25.80)
(10.40)
(9.70)
(101.00)
(B.r,o)
(4.17)
(40.10)
(5.r,9)
(.79)
(.51)
SO
X
—
.2139
(.2ino)
.Oft 4 4
(.0710)
.012)
(.nliK)
.060(1
(.on/o)
.1124
(.1460)
.OHM
(.0960)
.0751
(.0810)
.0)99
(.0440)
.0526
(.0580)
( . 2000)
(.7100)
(.1200)
( 1 . 1000)
(.0400)
—
(.1051)
( 1 . 2600)
(.1110)
( . 2080)
He
.71ft
(.260)
.001
(.001)
14. H4
(15.800)
4. 282
(4.720)
.822
( . 90S)
4.078
(4.410)
8.809
(9.710)
5.788
(6.180)
5.076
(5.540)
2.611
(2.900)
1.570
—
(1.000)
(1.200)
(.980)
(10.100)
(1.200)
(.502)
(.526)
--
__
CO
1.542
(l.;oo)
.015
(.017)
.141
(.I'.B)
.041
(.04?)
.oon
(.009)
.041
(.045)
.088
(."97)
.058
(.064)
.051
(.056)
.026
(.029)
.015
(.019)
(5.670)
•
(6.600)
(1.700)
(28.100)
—
—
(2.978)
--
T«rt.
.161
(.400)
.1105
(.005)
6. Bit
(f.510)
2.012
(2. 240)
(.410)
(2.0TO)
(4.170)
(2.B70)
(2.490)
(1.100)
(1.150)
(1.700)
(1.900)
(.»0)
(1.400)
(.160)
(.185)
(2. 6711)
(.710)
(.099)
(.066)
F.i" I •• Inn Rntr In H"trlp Tnnn fpr lim'
(Slmrt Tonn ppr tftlcf)
"«*
1.92
(.060)
1.92
( . O60)
2.50
(.078)
1.00
(.096)
1.92
(.060)
2.05
(.064)
2.11
(.072)
2.1?
(.067)
7. OB
(.065)
1.95
(.061)
2.56
(.080)
1.25
(.019)
1.25
(.019)
6.61
(.207)
6.61
(.707)
1.97
(.050)
1.62
(.111)
11.5
(.901)
1.92
(.060)
1.92
(.060)
I.»Z
(.060)
so
X
.0096
(.000111)
.0011
(.0000/i )
.0096
(.OOO 10)
.0099
(.00011)
. 0096
(.00010)
. 0096
(.00010)
.0096
(.00010)
.0096
(.00010)
.0051
(.00016)
.0096
( . 00010)
.0096
(.00010)
.0811
(.00260)
.0815
(.00270)
.0177
(.00102)
--
.0820
(.00756)
.7623
(.112180)
.767J
(.02180)
.7625
(.07160)
lie
.0'i'.9
(.0(114)
.o'.ni
(,001'»)
.6175
(.0199)
.0769
(.002'.)
.6407
(.0700)
.6501
( t"01)
.r,'.o;
(.0200)
,6407
(.0200)
.6'.07
(.0700)
.6407
(.0700)
.1524
(.0110
.0481
(.0015)
.0481
(.0015)
.6696
(.0209)
.6760
(.0211)
1.8016
(.0561)
.4169
(.0110)
.5702
(.0178)
—
--
--
CO
.7
-------
TABLE 21
EMISSION FACTORS FOR NATURAL-GAS COMBUSTION(20)
Industrial Process Boiler
Pollutant kg/hm3 (Ib/mcf)
Participates 80-240 (5-15)
Sulfur Oxides 9.6 (0.6)
Carbon Monoxide 272 (17)
Hydrocarbons 48 (3)
Nitrogen Oxides 1922-3684 (120-230)
TABLE 22
EMISSION FACTORS FOR HEAVY-DUTY, GENERAL-UTILITY,
STATIONARY ENGINES USING GASEOUS FUELS(20)
Pollutant kg/hm3 (Ib/mcf)
Sulfur Oxides 9.6 (0.6)
Hydrocarbons 19.2 (1.2)
-81-
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The emissions of sulfur and nitrogen oxides and hydrocarbons in Louisiana
as reported in the 1975 emission inventory are shown in Table 23. In contrast
to the case in Texas, the natural gas processing industry is the sixth highest
source of SO . The industry is the major source of NO in the state as in
Texas. Also, as in Texas, natural gas processing is the third highest source
of hydrocarbons exceeded by the same two industries, chemical manufacturing
and the petroleum industry.
COMPLIANCE STATUS OF NATUR/L GAS PLANTS
The report entitled "Compliance Status of Major Air Pollution Facilities"
(EPA-340/1-77-011) was examined to determine whether any facility having one
of the listed SIC codes was not in compliance. The facilities are listed in
order by EPA region, state, and standard industrial classification (SIC) code.
Six different SIC codes are pertinent to natural gas processing. These six
are:
1311 - Crude petroleum and natural gas production including
flares, dehydrators, separators, gas sweetening plants,
and gas processing plants
1321 - Natural gas liquids
2819 - Industrial inorganic chemicals, not classified elsewhere,
including sulfur recovery plants
4922 - Natural gas transmission
4923 - Natural gas transmission and distribution
4924 - Natural gas distribution.
Of all the plants in this publication, only six were found that were not in
compliance and only one appears to be in operation at this time.
PROCESS SOURCES OF AIR POLLUTION
There are several sources of air pollution associated with natural gas
processing. Some of these sources are unique to the industry while most are
common to many types of industrial activity. Natural gas processing operations
that are likely to be sources of air pollution include:
o
o
o
o
wellhead testing and completion
separation and dehydration
acid gas removal
sulfur recovery
-82-
-------
TABLE 23
POINT SOURCE EMISSIONS FROM INDUSTRIAL PROCESSES
LOUISIANA EMISSION INVENTORY - 1975
POLLUTANT IN METRIC (SHORT) TONS PER YEAR
Industry
Sulfur Oxides
Natural Gas Processing
Petroleum Industry
Chemical Manufacturing
oo Primary Metal
i
Secondary Metals
Mineral Products
Wood Products
Food/Agriculture
Nitrogen Oxides
Hydrocarbons
(3,580)
3,247
(75,209)
68,217
(113,253)
102,724
(4,056)
3,679
(1,373)
1,245
(9,870)
.8,952
(5,932)
5,380
(63)
57
(53,262)
43,310
(48,729)
43,790
(17,073)
15,486
(1,259)
1,142
(2,622)
2,378
(6,658)
6,039
(1,237)
1,122
(50)
45
(16,594)
15,051
(212,500)
192,744
(585,926)
531,452
(6,000)
5,442
(28)
25
(29)
26
(144)
131
(17)
15
-------
o tail gas cleanup
o heavy hydrocarbon stripping.
General plant, equipment likely to create air emissions are:
o gas engines
o flares
o storage tanks
o reciprocating pumps , compressors and valves
Possible emissions from well testing and completion are hydrogen sulfide,
mercaptans, carbon disulfide and carbonyl sulfide (if the well contains sour
gas), in addition to light hydrocarbon vapors which can create a safety hazard
if not flared. These low temperature flares create many incomplete combustion
products and SQz if the well is producing sour gas.
There are no emissions associated directly with field separation and
dehydration since these operations are carried out in a closed system.
However, reciprocating engines powered by natural gas, gasoline, or diesel
fuel are used to provide power for the operations and create sulfur dioxide,
hydrocarbons and NO . Lease tanks are another source of hydrocarbon emissions
if they are vented to the atmosphere. For remote locations these off gases are
usually flared. In some locations they are recycled or sold.
Gas sweetening produces waste acid gases which are usually flared or
incinerated or sent to a sulfur recovery operation. The combustion of waste
acid gases in flares is usually enhanced by adding natural gas to increase
combustion temperatures. These ambient condition flares are usually 98%
efficient and sulfur dioxide is the only major pollutant emitted. Modern
smokeless flares with fuel and stream injection are more common today and are
more efficient than the ambient condition type. A tail gas incinerator is a
more elaborate and more efficient type of flare in which raw gas and oxygen are
fed to the combustion chamber and HaS is virtually completely converted to SOa-
For sulfur recovery operations, SOa is usually converted to HaS via
catalytic hydrogenat ion or hydrolysis at 590-640°K (600-700°F). The products
are then cooled to remove water vapor. Sodium carbonate solution is then added
to yield sodium hydrosulf ide. Sodium vanadate is then used to oxidize this to
elemental sulfur. The finely divided sulfur froth is skimmed and dried by
centrifugation for sale. Overall recovery approaches 100%.
Heavy hydrocarbon stripping operations are usually powered by internal
combustion engines yielding combustion related emissions, NO , SO , and
hydrocarbons. Storage tanks are a major source of hydrocarbon emissions to the
atmosphere via working (filling) and breathing. Most modern facilities have
emissions controls to reduce these losses. Such controls include vapor
recovery, incineration flaring, as well as floating roof and variable vapor
-84-
-------
space storage tank designs. The floating roof design usually yields a 90%
emissions reduction. Variable vapor space tanks are similarly effective. This
type of tank has a movable lifter roof which rises and falls with changes in
vapor volume. Other types have a flexible diaphragm that compensates for
changes in vapor volume. Vapor recovery systems maintain a slight positive
pressure of natural gas on a manifold connected to several tanks. Any vapor
generated by the tanks is compressed and piped to the installation's fuel
system.
Glycol losses are associated with refrigeration absorption processes. As
mentioned earlier, some losses of this material occur when water vapor is
vented in the dehydration process.
-85-
-------
SECTION 7
WATER POLLUTION ASPECTS OF THE DOMESTIC NATURAL GAS
PROCESSING INDUSTRY
The major sources of water pollution from natural gas processing
operations are produced water, extracted with the hydrocarbons from the well,
and cooling water used to extract heat from process operations and equipment.
The produced water is very often a highly concentrated brine. Cooling water
usually contains corrosion inhibitors and antifoulants to protect process
equipment. The major sources of wastewater are listed in Table 24.
Typical wastewater characteristics for different types of gas processing
facilities are shown in Table 25. As the data show, there is substantial
variation in values reported on the NPDES permits. There is no correlation
between gas throughput and flow or pollutant loadings. Many of the plants have
several different permits for surface water discharge, underground injection
and underground disposal. Some wastes are disposed of by evaporation or are
hauled off-site by licensed scavengers. The myriad permits and disposal
options available to a specific plant have made it virtually impossible to
generate a satisfactory relationship between plant type or size, and pollutant
loadings. Our development of an industry-wide assessment of the industry's
water pollution aspects has been frustrated by the multiplicity of inconsis-
tencies in the data, conflicting reports and absence of information.
We can make several general observations regarding gas processing plant
effluents, their characteristics and general means of disposal.
PRODUCED WATER
Produced water is usually re-injected into the gas producing strata to
enhance well production. If re-injection does not improve gas recovery, the
produced water is often injected into non-producing, porous rock structures.
Because of the risk of contaminating freshwater aquifers, this disposal option
is regulated by permit. Discharge of produced water into surface waters is
non-existent. Such disposal of saline wastes would have substantial impact on
freshwater streams. It is unclear if the re-injected wastes may also include
blowdown, deionizer regenerants, and process and scrubber wastes.
COOLING WATER
Generally, cooling water comprises the largest portion of wastewater dis-
charged from gas plants, typically from 70 to 100% of the total wastewater
generated. Although some plants use once through cooling which avoids the
-86-
-------
TABLE 24
SOURCES OF WASTEWATER -
NATURAL GAS PROCESSING OPERATIONS
Liquid Separation
Acid Gas Removal
Dehydration
Sulfur Recovery
Tail Gas Conditioning
Heavy Hydrocarbon Stripping
Power Plant
CU
jj
cfl
^
M
C
• H
f— (
0
o
o
X
X
X
X
X
X
^
0)
U
nj
^
*O
(U
^0
U
CTJ
O.
0)
X
j^
•U CU
CQ 4.1
3: CO
(0
T3 C
Q) O
o -a
3 C
73 O
O O
Vw ^-^
cu
X
X
£
(U
4J
cu 3:
1 1
qj j^
S
cu
OS
^
-------
TABLE 25
NATURAL GAS PROCESSING PLANTS
TYPICAL DISCHARGE CHARACTERISTICS (i)
Flow, m3 discharged
106 m3
gas produced
pH, Standard units
BODs, mg/fi,
COD, mg/£
Oil & Grease, mg/£
Chromium, rag/£
Zinc, rag/Jc
TDS, mg/4,
Chloride, mg/&
Sulfate, mg/£
Absorption
U4 Plants)
12-6351
812
6.5-8.0
7.7
4.1-87
34
29-190
79
0-10
3.3
0-15
1.8
0.2-3.1
1.6
2,300-9,700
3,400
140-1,600
310
560-2,100
1,400
Refrigerated
Absorption
(23 Plants)
3-3,324
79
7.3-8.2
7.4
4.4-150
17
40-95
75
2.0-15
10
0.4-3.2
1.3
0.2-0.9
0.4
3,900-8,000
4,600
180-1,100
950
300-620
520
Other
(8 Plants)
4-152
43
6.4-9.8
7.7
1.0-281
11
2.3-640
130
0-75
1.5
0-2.5
0.2
0-0.9
0.2
1,000-28,000
3,900
70-17,000
9,500
9.5-1,800
700
Combined
(49 Plants)
3-3,324
51
6.4-9.8
7.7
1.0-281
15
2.3-640
98
0-75
3.0
0-15
0.8
0-3.1
0.3
1,000-28,000
4,000
70-17,000
750
9.7-2,100
600
EPA Region VI NPDES Permits
Low-high Median
-88-
-------
necessity of water treatment, most plants use varying degrees of recircula-
tion. Recirculation, often to 4 cycles of concentration, requires some degree
of pH and corrosion control to protect process equipment. Chromium, zinc and
phosphate compounds are common ingredients in corrosion inhibitors. Anti-
foulants may contain chlorine compounds and possibly minute amounts of toxic
materials to prevent biological growth. Cooling water blowdown thus contains
measurable quantities of these compounds plus high dissolved solids and any
materials that may leak into the cooling water from the process equipment.
These leaks, which are minimized by good maintenance practices, often increase
the oil, grease, and BODs content of the cooling water blowdown.
OTHER SOURCES OF WATER POLLUTION
Boiler blowdown is usually the third most significant source of plant
wastewater. These waters also contain treatment chemicals for corrosion and
fouling control similar to cooling water blowdown. There are no other
materials such as oil and grease, or BODs/COD usually associated with these
wastes.
Spills, leaks and stormwater runoff comprise an additional and unpre-
dictable fraction of plant wastewaters. They are an undetermined factor in
the total picture.
Condensed stripping steam is also a possible source of wastewater within
plants that use wet system oil separation. These waters are often very high in
oil and grease, BODs, and COD.
WASTEWATER TREATMENT
The quality of wastewater discharge is controlled by:
o good plant operation and maintenance practice
o use of non-polluting water treatment chemicals
o end of pipe treatment.
Good plant operation, including timely cleanup of leaks and spills and
segregation of runoff from plant wastewater systems, is routinely applied.
Substitutes for chrome-zinc corrosion inhibitors are available but frequently
offer less than desirable protection for process equipment.
End of pipe treatment includes oil-water separation, reduction-precipita-
tion for heavy metals and biological oxidation and cooling lagoons and ditches.
The control parameters for plant wastewater discharges are: pH, tempera-
ture, BODs, COD, oil, and grease. For plants using recirculated cooling water,
chromium and zinc limitations are also included.
The following concentrations represent the best practicable control tech-
nology currently available (BPCTCA):
-89-
-------
Monthly Average 24-hr Average
(mg/ft) (mg/A)
BOD5 20 24
COD 200 350
Oil & Grease 10 12
Total Chromium 0.25 0.25
Zinc 1.0 1.0
pH 6.0-9.0
It is also likely that local conditions could allow the injection of all
plant wastewater, in addition to produced water, into underground strata. Land
disposal by percolation is discouraged at this time. Solar evaporation ponds
must be lined and are used to dispose of an undetermined quantity of wastes,
primarily produced water, but may also include process water.
-90-
-------
REFERENCES
1. U.S. Bureau of Mines, Minerals Yearbook - 1974.
2. American Gas Association, Gas Facts - 1976.
3. Oil & Gas Journal, Worldwide Directory of Refining and Gas Processing
-1977-1978.
4. Oil & Gas Journal, Petroleum-2000, 1977.
5. Federal Energy Administration, National Energy Outlook, 1977.
6. American Petroleum Institute, Crude Petroleum, Products & NGL, 1973.
7. Chase Manhattan Bank, Energy Economics Division publication, 1977.
8. Federal Power Commission Bureau of Natural Gas; The Gas Supplies of
Interstate Natural Gas Pipeline Companies, 1975; January 1977.
9. "Atmospheric Emissions Survey of the Sour Gas Processing Industry,"
Ecology Audits, Inc., EPA-450/3-75-076, October 1975.
10. "Screening Report - Crude Oil & Natural Gas Production Processes-Final
Report," Processes Research Inc., EPA-R2-73-285, December 27, 1972.
11. "Process for Sour Natural Gas Treating," A.M. Younger, AICHE Symposium
Series, No. 148, Vol 71.
12. "Field Surveillance and Enforcement Guide for Petroleum Refineries," A.V.
Sims, EPA-450/3-74-042, July 1974.
13. "Characterization of Sulfur Recovery in Oil and Natural Gas Production,"
K.S. Murthy, EPA-450/3-75-081, August 1974.
14. "API Recommended Gas Plant Good Operating Practices for Protection of the
Environment," APIRPSO, January 1975.
15. "Environmental Problem Definition for Petroleum Refineries, Synthetic
Natural Gas Plants, and Liquified Natural Gas Plants," EPA-600/2-75-068,
E.G. Cavanaugh, J.D. Colley, P.S. Dzierlenga, V.M. Felix, D.C. Jones,
T.P. Nelson, November 1975.
16. "Natural Gas Processing at Low Temperatures," C.M. Jordan, Chemical Eng-
ineering Progress, Vol 68, No. 9, September 1972.
17. "U.S. Gas Processing Continues to Slide from 1972 Peak," E. Seaton, The
Oil and Gas Journal, July 11, 1977.
-91-
-------
18. "Gas Processing Looks to the Future," C.P. Mathias, B.L. Kline, J.E.
Moody, The Oil and Gas Journal, 75th Anniversary Issue, August 1977.
19. 1977 Directory of Chemical Producers - U.S.A. Chemical Information Ser-
vices, Stamford Research Institute.
20. "Compilation of Air Pollutant Emission Factors," EPA AP-42.
-92-
-------
APPENDIX A
LIST OF NATURAL GAS PROCESSING PLANTS, CAPACITIES,
PRODUCTS AS OF JANUARY 1, 1977(3)
-93-
-------
Company, plant, location
Marathon Oil Co. — 'South Coles Levee plant and
field, Kern County, 3-31s-25e
Petrolane Gasoline Co. — Harbor plant
Wilmington field, Los Angeles County
Signal Hill plant, Long Beach field,
Los Angeles County
Reserve Oil Inc.* — Reserve Standard plant,
North Tejon field, Kern County,
17-lln-19w
Shell Oil Co. — Molino plant and field,
Santa Barbara County, 35-5n-31w
Ventura plant, Sespa-Ventura field,
Ventura County, 28-3n-23v»
Sun Production Co.— Newhall plant, RSF
field, Los Angeles County, 27-4n-14w
Superior Oil Co.— Rio Bravo plant, various
fields, Kern County, 34&35-28s-25e
Texaco Inc.J — Honor Rancho plant, Los
Angeles County, 36-5n-17w-SBBM
Shields Canyon plant, Ventura County,
4-4n-19w-S8BM
Union Oil Company of California —
Bell plant, Santa Fe Springs field,
Los Angeles County, 6-35-1 Iw
'Coalinga Nose plant and field,
Fresno County, 7-20s-16e
Dominguez plant and field, Los
Angeles County, 33-3s-9w
Santa Clara Valley plant, Torrey
field, Ventura County, 4n-18w
Santa Maria plant, Santa Maria Valley
field, Santa Barbara County, 24-10n-34w
Stearns plant, Brea-Olinda field,
Orange County, 7-3s-9w
Total
fAII figures are capacity
COLORADO
Amoco Production Co. — Peoria plant and
field, Arapahoe County, 334s-60w
Spindle plant and field, Weld County,
34-2n-67w
Third Creek plant and field, Adams County,
7-2s-65w
Wallenberg plant and field, Adams County,
32-3s-65w
Chevron USA Inc. — Rangely Hagood plant and
field, Rio Blanco County
Continental Oil Co.— fruita plant, Western Slope
Gas Co. field, Mesa County, 34-9s-10w
Crystal Oil Co.— Crystal Gas Resources plant,
Roggen field, Weld County
Excelsior Oil Corp. — Venter plant, various
fields, Logan County, 1-11-53
Koch Oil Co. — Third Creek plant, various fields,
Adams County, 18-2s-65w
Matrix Land Co. — Piceance Creek plant and
field, Rio Blanco County, 15-25-96*
Northwest Pipeline Corp. — Ignacio plant,
San Juan Basin field, La Platte County,
swtt-36-34n-9w
Phillips Petroleum Co.— JWeld plant, Tampa,
field, Kiowa & Bent Counties,
Planet Engineers Inc.— McClave plant and
field, Kiowa & Bent Counties,
32-48w-20s
Sun Production Co. — Denver Central plant,
several fields, Arapaho County, 5-5s-62w
Dragon Trail plant and field, Rio
Blanco County, 35-2s-102w
Texaco Inc.— iWilson Creek plant and field,
Rio Blanco County, 27-3n-94w
Union Oil Company of California — Adena plant
and field, Morgan County, 12-ln-58w
Vallery Corp. — Vallery plant, Poe, Lamb,
Canal, Vallery, Renegade fields,
Morgan County, 15-3n-59w
Vessels Gas Processing Co. — Bennett plant
and field, Adams County, nw corner-
ne4-28-2s-€3w . . .
Brighton plant. Spindle field. Weld
County, s*4-28-ln-67w
, MM
Gas
capacity
80.0
50.0
10.0
40.0
45.0
120.0
70.0
38.0
18.0
10.0
9.0
46.0
20.0
20.0
35.0
20.0
1,427.0
10.0
30.0
10.0
150.0
10.0
20.0
21.0
10.0
25.0
40.0
300.0
7.0
12.0
20.0
10.5
28.0
3.0
1.0
15.0
eft • •>
Gas
through-
put
77.1
31.0
8.0
4.8
2.0
14.0
29.4
20.0
NR
NR
1.8
58.2
3.9
20.0
17.0
9.2
553.9
7.3
30.0
4.0
119.0
5.0
18.4
14.0
3.1
17.7
26.0
194.2
5.0
7.7
13.4
NR
4.1
2.0
0.6
8.0
-94
Proceft
methoi
2
3
3
5
2
1
2
1
1
1
NR
1
1
3
1
1
7
7
3
7
3
5
2
2
?
2
1
2
2
?
3
?
3
4
3
/ — Production— 1,000 gal/ day (Avtnft based on thi past 12 months) — ,
Normal Raw Dibut.
s orunsplit LP-jis NGL rat
1 Ethan* Prep. Isobut butam mix mix jaso. Other
39.4 5.9 7.5 23.7 26.5 "33.1
9.5
4.5 46.6
0.6
1.6 1.9
16.6 27.5
19.4 12.3
6.0 1.2 2.1 3.2
20,0 . ... 16.0 16.0
22.0 . ... 17.0 33.0
9.2
17.0 14.0 10.6 19.7
5.3 8.7
13.1 8.8
23.8 ... 16.2 17.4
16.7 29.1
341.4 25.8 111.7 54.1 353.7 168.4 33.1
19.0 23.7 17.9
174.2
9.7
'
417,8
30.3
9.0 7.1 2.9
44.0
6.1 6.7
17.3 34.7 5.2 13.0
6.5 8.0
45.4 57.7 48.1
60.0
4.5 3.3
18.6 13.3
11.5 11.8
21.0 21.0
8.7 . 2.4 7.0
3.0
0.8
5.8 .... 10.8
-------
Company, plant, location
Bugle plant and field, Adams County,
sw corner-sw4-32-ls-66w
Irondale plant and field, Adams County,
sw corner-se4-24-2s-62w
Irondale Cryogenics plant, Irondale field,
Adams County, sw corner-se4-24-2s-62w
Space City plant and field, Weld County,
ne4-3Hn-65w
Total
FLORIDA
Exxon Co. USA— Jay plant, Jay field, LEC
unit, Santa Rosa County, 43-5n-30w
Florida Hydrocarbons Co. — Brooker plant,
Bradford County
Total
ILLINOIS
U.S. Industrial Chemicals Co. Division of
National Distillers & Chemical Corp.—
Tuscola plant, Hugoton via PEPL, Douglas
County, Ficklyn Township
Total
KANSAS
Ulamo Chemical Co. (owned by Phillips Petroleum
Co.) — tGreenwood plant, Greenwood-Sparks
field, Morton County, se4-se4-7-33s-43w
tooco Production Co. — Kinsler plant and
field, Grant County, 10-30s-37w
Ulysses plant, Hugoton field, Grant
County, 5-29s-38w
^nadarko Production Co. — Cimarron River plant
and field, Seward County, 26-33s-32w
Interstate plant, Interstate-Baca field,
Morton County, 29-34s-43w
Woods plant, Council Grove field,
Seward County, 22-33s-34w
Central States Gas Co. — Rattle Snake Creek
plant, Stafford County, nw 10 acres of
ne4-28-25s-13w
Cities Service Co. — Cheney plant, various
fields, Kingman County, 22-28s-5w
Hutchinson fractionation plant, various
fields, Reno County, 22-235-6w
Jayhawk plant, Kansas-Hugoton field,
Grant County, 2-29-35w
Midway plant, various fields, Kingman
County, 33-275-5w
Spivey plant, Spivey-Grabs field.
Harper County, 5-31s-8w
Sunflower plant, Kansas-Hugoton field,
Scott County, 17-18-33w
Wichita plant, various fields, Sedgwick
County, 17-28-le
Wilburton plant, S. Taloga & Wilburton
fields, Morton County, 33-34s41w
Cciarado Interstate Gas Co. — Lakin plant,
Hugoton field, Kearney County,
• 2 of ne4-29-24s-36w
Morton plant, Greenwood field, Morton
County, ne4-18-33s43w
Kansas Refined Helium Co. — Otis plant.
'eichel and other fields, Rush County,
25-17-16W
Vesa Petroleum Co. — Ulysses plant, Hugoton
field, Grant County, 10-30s-37w
'toil Oil Corp. — Hickok plant, Hugoton
field, Grant County, 31-28s-35w
National Helium Corp.— National Helium plant,
Seward County, 23-335-32w
Northern Gas Products— Northern Gas plant,
Eiisworth County, 31-17s-9v»
Northern Helex Co.— Northern Helex plant,
Eiisworth County, 31-17s-9w
Northern Natural Gas Co.— Holcomb plant,
Hugoton field, Finney County, 3-24s-34w
Gas
Gas tnnjufh-
capacity put
1.0
15.0
10.0
4.0
767.5
90.0
NR
722.S
550.0
550.0
84.0
20.0
400.0
15.0
16.0
10.0
12.0
100.0
520.0
25.0
70.0
250.0
130.0
5.5
215.0
112.0
24.0
242.0
210.0
1,000.0
950.0
520.0
200.0
1.0
4.0
3.0
2.0
509.9
124.0
506.0
630.0
411.0
411.0
NR
5.5
326.0
18.0
4.0
9.5
7.0
84.8
486.0
20.7
48.9
157.8
100.2
3.2
137.0
46.0
24.0
147.3
121.1
610.0
900.0
500.0
192.0
- — Production— 1 ,000 gal/ day (Average based on tin past 1 2 months) — .
Normal Raw Debut
Process orunsplit LP-fas NGL nat.
method Ethane Prep. Isobut butane mix nix zaso. Other
3
3 7.8
6
3
34.1 180.6
647 391.8 328.3
NR 34.6
391.8 362.9
2 482.9 247.2
482.9 247.2
3
2
2 107.8
2 ' 10.4
2 6.5
2 3.2
2
2
(762.0)
2&6
2
I 1.8
3&6
1 46.7
3
1
5
3
2
1 16.5
3 163.0
2 420.0 650.0
NR
3
2.7
9.2
9.1
3.6
914 503.2 318.1 91.4
•
176.5 113.6
25.9 25.5
202.4 25.5 113.6
48.7 110.2 25.5
48.7 110.2 25.5
60.0
14.2 "0.6
30.7 92.7 89.6
13.9
6.2
5.2
4.5
72.2
(97.6) (310.8) (343.6)
434.8
30.5
0.5 1.6
84.8
15.9 37.5 30.8
11.6 -.
21.5
§0.5
4.9
122.0
44.9
34.0 .... 119.0
70.0 170.0 115.0
(ID
21.1
-95-
-------
• MMcfd v ,— Production—1,000 gal / day
-------
Gas
Gas ttrrafk-
Company, plant location capacity put
Grand Chenier plant, Tennessee Gas Transmission
Line, Cameron Parish, 2-39-40-15s-6v»
Crystal Oil Co. — Kings Bayou plant Hog Bayou-
Kings Bayou field, Cameron Parish
Exxon Co. USA— Avery Island plant and field,
Iberia Parish, 53-13s-5e
College Point plant and field, St. James
Parish ....
Garden City plant and field, St. Mary
Parish, 45-46-15s-10e
Grand Isle plant and field, Jefferson
Parish, 3Z-21s-25e . . .
Lirette plant and field, Terrebonne
Parish, 23-19s-19e
Opelousas plant, St. Landry Parish,
100-6s-4e
Thibodaux plant, Lafourche Parish,
35-35-15s-16e
Getty Oil Co.— Bastian Bay plant, West Bastian
Bay field, Plaquemines Parish, 21s-28e-42 ...
Cameron plant and field, Cameron
Parish, 29-14s-9w
Hollywood plant and field, Terrebone
Parish, 17s-17e-101
Venice plant and field, Plaquemines
Parish, 21s-30e-25
Gulf Energy and Minerals Co. — Krotz Springs
plant and field, St. Landry Parish,
22-6s-6&7e
SE Bastian Bay plant and field,
Plaquemines Parish, 4-21s-29e
Venice Plant, various fields, Plaquemines
Parish, 25-21s-30e
Kerr-McGee Corp.— Bayou Crook Chene plant and
field, St. Martin Parish, 534-105-9e
Dubach plant, Lincoln Parish,
526-&34-20n-3w .. ....
;ch Oil Co. — Bayou Postillion plant, Iberia
Parish
Manchester plant, Calcasieu Parish
Gloria Oil & Gas Co.— Rayne plant and field,
Acadia Parish, ll-9s-2e
yjid Products Recovery Inc. — Bourg plant
and field, Lafourche Parish
Napoleonville No. 1 plant and field,
Lafourche Parish
Napoleonville No. 2 plant and field.
Assumption Parish
South Grand Chenier plant and field,
Cameron Parish
Vscherie plant and field, St. James
Parish
;^st Ridge Gas Processing Co.— Locust Ridge
P ant, Locust Ridge, Buckhorn, and other fields,
"ensas Parish, 21-10n-lle
'.•- :;iana Land and Exloration Co. — Point Au
Ctiien plant and field, Terrebonne Parish
lS-19s-20e
!a--:hon Oil Co. — Cotton Valley plant and field,
tester Parish, 26-21n-10v»
'd Louisiana Gas Co. — Kenmore plant, College
-. rt and St. James fields, St James
Parish, 44-12S-4 . ....
fcsissippi River Transmission Corp. —
5 ryville plant, Morehouse Parish
'; ; on Corp. — Cameron plant, various fields,
aneron Parish, 23-15s-13w
> Island plant, various fields, Vermilion
3fish, 29-3s-2e
5*a plant, various fields, Jefferson
«v:s Parish, 18-95-6*
erside Fractionation plant, Ascension
2-sh, 49-9s-5e
v -' 4 Prichard — *Burtville plant and field,
^:t Baton Rouge Parish, 47-8s-le
; -PS Petroleum Co.— tRollover plant, Gas
'^mission Pipeline, Jefferson Davis
f3r'sh, nw4-ll-lls-3w
'Dillon plant North Erath and Grosse
S|s fields, Vermilion Parish,
**-se441-13s4e
950.0
80.0
11.0
20.0
960.0
100.0
300.0
110.0
45.0
150.0
65.0
150.0
65.0
100.0
150.0
1,000.0
12.5
175.0
25.0
6.0
176.0
15.0
30.0
11.0
20.0
10.0
20.0
125.0
220.0
10.0
500.0
470.0
825.0
500.0
8.0
190.0
45.0
671.5
45.0
13.0
4.0
380.0
76.0
215.0
127.0
9.0
56.6
NR
89.4
41.7
46.0
74.0
592.0
NR
NR
12.0
2.8
57.4
4.0
8.0
6.0
11.0
4.0
6.0
60.0
67.0
1.5
215.0
417.0
457.0
346.0
6.0
NR
NR
Process
method
246
2
2
5
2
2
2
2
2
7
2
2
2
2
5
2
2
2
5
5
2
5
5
5
5
5
NR
3
2
1
1
2&7
2
7
(t)
244
2
2
- — ProihctioB— 1,000 pi/day (Averaf* hast* OB the past 12 morths) — ,
•ruAtalrt IP-cas Nfil mi
Ethane Prep. Isobut butane nix nix gaso. Otter
(Liquids fractionated by others) 597.5
10.2 9.2 2.8 2.0 4.3
8.4
0.5
159.3 133.4 40.7 31.6 70.9
14 7 178 9.2 9.8
230.8
25.7 10.6 9.6 21.3
3.7 5.8
83.6
8.0 .... "1.0
53.6
47.2
47.9 31.2 20.3
6.1
.... 194.6 47.4 53.8 130.6 '166.6
21.6
66.1 26.1 37.5 '1573
•24.8
U19.3
0.4
"4.8
35.8 83.9 .... "61.0
0.3
U
1.0
0.5
8.0 "1.2
44.9 31.2 11.7 11.7 19.7 "1.7
1022 43.5 14.7 14.7 "9.3
"0.2
118.2 '202.2
366.5
90.1
(117.6) (64.2) (44.4) (102.7) "(242.1)
05 ul 5
75.0
25.0
-97-
-------
Company, plant location
MMcf d , ,— Production—1,000 pi/ dqr ttvtrafe b»«<' on the pat 12 months) —N
Gas Normal Raw Debut.
Gas through- Process oromalit LP-fas NGL rat
capacity put method Ethane Prop. Isonul butane mil mix gaso. Other
Placid Oil Co.— *Black Lake plant and field,
Natchitoches Parish, 14-lln-6w
Lapeyrouse plant and field, Terrebonne
Parish, 71-20-18e
Patterson 1 plant, Patterson field, St.
Mary Parish, 48-15s-lle
Shell Oil Co. — Bayou Goula plant, Line Plant
Field, Iberville Parish, 67-10s-12e
Black Bayou plant and field, Cameron
Parish, 18-12s-12w
Calumet plant, 2-Line Plant field, St.
Mary Parish, ll-12-51-52-15s-lle
Chalkley plant and field, Cameron Parish,
27-12s-6w
Crawfish pant, Line Plant field, St.
Charles Parish, 36-13s-20e
Kings Bayou plant and field, Cameron
Parish, 34-14s-7w
LaPice plant and field*, St James
Parish, 38-12s-15e
Mermentau plant, Line Plant field,
Acadia Parish, 70-IOs-2w
Norco fractionator plant, Yscloskey &
Toca fields, St. Charles Parish, 6-12s-8e
North Terrebonne plant, 2-Line Plant
field, Terrebonne Parish, 20-29-33-17s-15e
Tebone fractionator plant, North
Terrebonne plant, Ascension Parish,
8&46-10s-2e
Timbalier Bay plant, Line Plant field,
Terrebonne Parish, nw4 of 32-16 sw/4 of
33-19s-19e
Toca plant, Line Plant field, St.
Bernard Parish, 54-14s-14e
Weeks Island plant and field, Iberia Parish,
13-14s-6e
West Lake Verret plant and field, St.
Martin Parish, 15-14s-12e
Yscloskey plant, Line Plant field, St.
Bernard Parish, 39-13s-15e
Sohio Petroleum Co. — 'South Fields plant, Wilcox
"B" Sand Unit, Beauregard Parish
Southern Natural Gas Co.— 'Toca plant St. Bernard
Parish, 55-14s-14e
South Louisiana Production Co. Inc. — Cocodrie
plant various fields, Evangeline Parish,
35-2s-2e
St. Landry plant, various fields, Evangeline
Parish, 35-2s-2e
Sun Production Co. — Bayou Sale plant, Land
Sand East field, St. Mary Parish,
14-16s-10e
Belle Isle plant and field, St. Mary
Parish, .28-17s-10e
Delhi plant and field, Richmond Parish,
15-17n-9e
Fordoche plant and field, Point Coupee
Parish 41-68-8e
Maurice plant and field, Lafayette Parish,
3HOs4e
South Sarepta plant and field, Bossier
Parish, 16-12s-4w
Superior Oil Co. — Bayou Penchant plant and
field, Terrebonne Parish, 2-19s-13e
Four Isle plant, Four Isle Dome field.
Terrebonne Parish, 24-21s-16e
Gueydan plant, Southeast Gueydan field.
Vermilion Parish, 21-12s-lw
Lowry plant, various fields, Cameron
Parish, 15-12s-4w
Tenneco Oil Co. — 'Stephens plant, Haynesville
field, Claiborne Parish, 6A7-13s-12e
Texaco Inc.i — Alligator Bayou plant, Lake
Fausse Point field, St. Martin Parish,
sw 14-34-1 Os-9e .
Floodway plant, St. Mary Parish,
16-15s-12e
Fordoche plant and field, Pointe Coupee
Parish 28-6s-8e
Henry plant, Vermilion Parish,
21-13s-4e
Paradis plant St. Charles Parish,
29-14s-20e
150.0
100.0
200.0
71.0
18.0
1,200.0
23.0
120.0
60.0
12.0
120.0
1,250.0
100.0
830.0
129.0
60.0
1,850.0
10.0
525.0
50.0
60.0
16.0
200.0
15.0
50.0
32.0
300.0
75.0
75.0
30.0
300.0
35.0
27.0
900.0
30.0
825.0
800.0
160.0 2
43.0 2
76.0 2
14.7 2
11.8 2
1,211.2 2
4.5 2
91.7 6&7
14.0 5
10.3 5
40.5 2
.... (t)
1,315.3 2
.. (t)
53.9 6&7
478.3 2-6-7
57.3 2
9.8 6&7
1,617.8 2
10.0 3
386.0 5
NR 2
NR 2
12.7 2
96.4 2
18.8 2
22.1 2
15.2 2
185.0 2&6
78.0 5
44.0 5
15.0 5
185.0 2&6
18.0 2
NR 647
NR 627
NR 2
NR 2
NR 2
363.9
49.5
87.7
22.5
6.4
782.1
2.3
106.5
1.1
0.2
42.1
(695.1) (434.3) (127.9) (144.8) (219.6)
(Liquids fractionated at Tebone plant) 1,131.0
(351.2) (343.9) (106.8) (96.7) (232.3)
81.8
610.2
12.2 26.0
7.7
1,288.3
12.0
39.4
22.5 16.8 11.1
24.4 16.3 10.8
11.2
48.3 15.0
20.9 6.4 11.9 30.4
33.2
17.5
8.7 8J 7.5
7.5
39
n i
• • ... .... . . .... u.l . . .
59.8 63.1 23.2 14.9 33.0
3.0 2.9 4.7
47 0
• • • . • ^f .U . . .
945 n
• • - • .... TtiJ.U . . .
220 16 0 qn
fcfc»** • - • 1U.U . . ... 3.U
346.5 283.5 93.0 420.0
200.0 429.0 mn mn
"212.5
"22.2
U27.5
"08
U.Q
"0,8
"19.1
•5.0
-98-
-------
;ompaay, plant location
Sea Robin plant, Vermilion Parish,
21-13s-4e
South Lake Arthur plant. Lake Arthur
field, Jeff Davis Parish, 13-lls-3w
jnion Oil Company of California — Houma plant
and field, Terrebonne Parish,
26-17s-17e
jnion Texas Petroleum — Eunice plant, various
fields, Acadia Parish
Rayne plant various fields, Acadia
Parish
Sligo plant and field, Bossier Parish
Toca plant various fields, St. Bernard
Parish
jnited Gas Pipe Line Co. — Greenwood Dehydration
plant, Greenwood field, Caddo Parish,
3-17n-16w
Varren Petroleum Co. — Johnson Bayou plant,
Cameron Parish, 32-33-15s-12w
Total
Fractionation. tAII figures capacity, (Figures in
Weathered natural gasoline.
MICHIGAN
moco Production Co.— Kalkaska plant, Niagaran
Reef Trend of North Michigan field,
Kalkaska County, 31-27n-7w
aw Chemical Co.— Beaver Creek Station,
Beaver Creek Unit Crawford County,
204w-25n
Marathon Oil Co.— Scipio plant and field,
Hillsdale County, 2-55-3w
1 chigan Consolidated Gas Co. —
Leonard plant and field,
Oakland County, Addison 5n-lle
'chigan Wisconsin Pipeline Co. —
'Loreed plant and field, Osceola
County, 30-18n-10w
tobil Oil Corp.— Aurelius plant, Mason
'ield, Ingham County, 36-2n-2w
hell Oil Co. — Kalkaska plant, various
•elds, 32-27n-7w 6
un Production Co. — Columbus Three
St. Clair County, 3-5n-15e
Total
MISSISSIPPI
j-serch Exploration Inc. — Hurricane
Lake and field, Lincoln County,
se4-9-6iv6e
jx:n Co.— HUB FEU #2 field, Marion
County
3et:y Oil Co.— Bay Springs plant and field,
:3$per County, 27-2n-10e
-^ Oil Co.— Goodwater plant and field,
: arke County, 5-10n-8«r
"allahala Creek plant and field,
Smith County, 5-ln-9e
ktwn Natural Gas Co.— *Muldon Dehydration
Fiant, Muldon Storage field, Monroe
County, 27-15s-6e
:-• 3roduction Co. — Mercer plant and field,
siams County, 16-9n-2w ...
'was on 4 Gas Corp.— Harmony plant various
' eids, Clarke County, 26-2n-14e
Total
ONTANA
"-! 'snco Inc. — Culbertson plant Big Muddy
' s d, Roosevelt, 26-29rt-55e
S.2UX plant and field, Richland County
:9-25n-58e
^matra plant, West Sumatra field,
Wlshell County, 19-lln-32e
febch Gas Processing Corp.— Fairview
: "t, Richland County, 1042n-57e
'•i Creek plant and field, Roosevelt
-unty, 14-30n-48e
'•'-e'bird Petroleums Inc.— Westco Refining Co.,
UftJ
Gas
opacity
900.0
60.0
80.0
1,100.0
750.0
290.0
190.0
25.0
29.5
Gas
tftroigR- Process
pit mtked Ethane
NR 647
NR 647
45.0 2
785.0 2 283.6
725.9 2 107.6
44.0 NR
92.0 2
7.0 5
23.6 7
23,576.8 16,439.4 1,434.3
parenthesis do not represent primary
100.0 89.8 647
5.0 0.9 4
38.0 26.4 2
30.0 10.0 3
54.0 25.0 2
23.0 19.5 2
350.0 162.0 2
2.3 NR .1
602.3
1.0
36.0
10.0
15.0
10.0
750.0
0.7
30.0
852.7
4.0
3.0
2.0
6.0
2.5
335.4
0.6 3
12.0 5
NR 2
5.9 3
5.3 3
317.0 5
0.4 3
15.0 3
364.2
1.2 3
12 3
0.8 3
3.0 2
05 3
fcctjstt— 1,000 gat/day (Amat* based on the past 12 months) — >
Nenui Raw Debut
Ofunplit LP-fas NGL Bit
Prep. Isoirt. Brtaw mix Mix lasa. Other
738.0
122.0
49.5
253.4 66.0 65.7
131.3 36.4 34.0 76.3
14.4 4.9 5.0
56.0 16.6 18.7
1.5
272
1,981.2 446.0 698.5 751.6 8,438.5
production, and are not added in state totals).
91.0
0.4
35.3 33.4
4.4 2.2 0.7
17.7 25.9
498.0
6.9
57.4 22 0.7 33.4 622.2
1.4
0.5
8.0 6.0
4.1 3.1
5.1 5.1
21.8
1.3
25.0 20.0
34.2 28.2 8.0 31.0
4.0
5.0
70
6.0 12.0
2.5 5.0
187.6
15.6
36.4
854.0 1,184.4
"0.5
•10.0
2.9
. "30.0
2.9 48.5
4.0
4.3
15.0 "6.0
-99-
-------
i MMcf d * - — Production— 1 ,000 pi/ day (Averagt bastd on tnt past 1 2 months) • — .*
Gas Normal Raw Debut.
Gas through- Process orunsplit LP-ga* N6L nat
Company, plant, location capacity put method Ethane Prop. IsobuL butane mix mil gaso. other
Cut Bank Sands field, Glacier County,
48-38-40—112-02-30
True Oil Co. — Bob Rhodes plant, 4-Mile Creek Held,
Richland County, 4-25n-58e
Union Texas Petroleum — Glendive plant,
Pine-Cabin Creek field, Fallen
County
Total
NEBRASKA
Cities Service Co. — Kimball plant, various
fields, Kimball County, 10-12n-55w
Marathon Oil Co. — West Sidney plant and field,
Cheyenne County, 4-13n-50w
Total
30.0
3.0
5.8
S6.3
10.5
12.5
23.0
17.8 1
1.2 3
2.8 1
28.5
1.4 1
6.4 2
7.8
10.8
11.0
30.3
2.8
7.8
10.6
9.6 8.3
7.0
14.3
9.6 24.0 1S.O 22.6
0.5 2.8 ....
5.1 5.0
5.6 7.8
NEW MEXICO
Amoco Production Co.—'Empire Abo plant and
field, Eddy County, 3-18s-27e
Cities Service Co.—Bluitt plant, Chaveroo
Tobac, Sawyer, other fields, Roosevelt
County, 15-85-36e
'Empire Abo plant and field. Eddy County,
27-17s-27e
Continental Oil Co.—Maljamar plant and field,
Lea County, 2H7s-52e
El Paso Natural Gas Co.—Blanco plant, San
Juan field, San Juan County, n2/n2-14-29n-llw
Cnaco plant, San Juan field, San Juan
County, sw4-l 6-26n-l 2w
Jal No. 1 plant, Lea County & Emperor
field, Lea County, 37e-26s-36
Jal No. 3 plant, Langlie-Mattox & Blinebry
fields, Lea County, nw4/sw4-33-24s-37e .
Jal No. 4A plant, Blinebry-Jalmat fields,
Lea County, se4/se4-32-23s-37e
Jal No. 48 plant, Lea County,
se4/se4-32-23s-37e
San Juan River plant, San Juan Basin field,
San Juan County, l-29n-15w
Wingate plant, McKinley County,
164l7-15n-17w
Gas Company of New Mexico, division of
Southern Union Co.—Avalon plant, Indian
Basin field, Eddy County, 9-21s-27e
Getty Oil Co.—Eunice No. 1-2 plant, various
fields, Lea County, 27-22s-37e
Marathon Oil Co.—Indian Basin plant and
field, Eddy County, 6-22s-24e
Northern Natural Gas Co.—Hobbs plant,
Blineberry Tubb, Eumont, Jalmat
fields, Lea County, 6-19s-37e
North Texas LPG Corp.—Lone Pine #1 plant,
McKinley County
Lone Pine #2 plant, McKinley County
Perry Gas Processors Inc.—Antelope Ridge
plant, Lea County, Unit K-34-23-24
Artesia plant, Eddy County
Phillips Petroleum Co.t—Artesia plant, various
pools, Eddy County, s2-se-4-7-18s-28e
Eunice plant, Eunice, Seminole, Hobbs
fields, Lea County, ne4-5-21s-36e
Hobbs plant and field, Lea County,
n2-nw4^-19s-38e
Lee plant, Vacuum and other fields, Lea
County, sw4-se4-30-mv4-ne4-31-17s-35e
Lovington plant, Lovington, San Andres 4
various fields, Lea County, sw4-31-I6s-37e .
Lusk plant, Lusk and other fields,
Lea County, nw4-ne4-I9-19s-32e
Wilson plant, Wilson and other fields,
Lea County, ne4-5-21s-36e
Southern Union Refining Co.—Kutz No. 1 plant,
San Juan Basin field, San Juan County,
11, 12, 13, 14-28n-llw
Lybrook plant, San Juan Basin field,
Rio Arriba County, 14-23n-7v»
Texaco Inc.—Buckeye plantt, Vacuum field,
Lea County, 3641-175418s-34e
Tipperary Corp.—Denton plant and field,
Lea County
45.5
39.2 647
37.0
4.0
26.0
558.0
594.0
303.0
225.0
185.0
71.0
30.0
150.0
220.0
220.0
5.0
5.0
20.0
5.0
43.0
88.0
38.0
85.0
10.0
60.0
6.0
100.0
80.0
22.5
NR
34.0
4.0
12.9
450.0
536.9
247.9
134.2
155.9
55.5
22.0
NR
186.8
220.0
3.0
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
105.0
70.0
NR
5.0
2
7
2
1
2
2
2
1
(t)
1
(t)
2
2
2
2
3
3
1
1
347
347
1
143
1
143
3
2
2
6
3
-100
65.0
42.9
16.1 33.5 4.5 11.1
28.5 -96.0
12.1
25.1 30.7
17.1
"0.3
(102.2) (125.7)
11.4 .... 17.2
(403.2) (119.2) (279.4)
119.0 la.O 51.0
15.9
187.6
72.0
10,0
2.1
13.6
381.2
702.2
79.7
162.8
136.3
(150.9)
18.4
(327.5)
62.0 .... *94.0
174.9
53.8
8.3
320.0
450.0
115.0
245.0
50.0
230.0
7.5
230.0
170.0
144.6
30.0
-------
Company, plant location
EM
Gas tknt|k- Process
capacity ant method Ethane Prop
hodwfleo—1,000 ial/*nr
-------
Company, plant location
Exxon Co. USA— Camargo plant, Putnam field,
Dewey County, 10-18n-19w
Dover-Hennessey plant and field,
Kingfisher County, l-18n-7w
Getty Oil Co. — East Velma Middle Block plant,
various fields, Stephens County, 4-2s-4w .
Marlow plant, West Marlow field,
Stephens County, ll-2n-8w
Velma plant and field, Stephens County,
23-ls-5w
Grimes Gasoline Co. — Okemah plant and
field, Okfuskee County, se4-23-ll-9
Kerr-McGee Corp. — Milfay plant,
Creek County, 21-15n-7e
Koch Oil Co. — Fitts plant, Fitts & Jesse
fields, Pontotoc & Coal Counties, 30-2n-7e
Ladd Petroleum Corp. — Leonel plant, SW Canton
field, Oewey County, nw4-14-16n-14w
Mapco Inc. — Tyrone plant, Hugoton field,
Texas County, ll-6n-18e
Mobil Oil Corp.— Chitwood plant, various fields,
Grady County, 34-5n-6w
Northeast Trail plant, Putnam field,
Dewey County, H7n-18w
Postle Hough plant, Hough field,
Texas County, 13-5n-13ecm
Putnam Oswego plant, West Crane and Putnam
fields, Dewey County, 35-16n-16w
Selling plant and field, Woodward
County, 32-20n-17w
Sholem Alechem plant, Sho-Vel-Tum field,
Stephens County, 2-ls4w
Taloga plant, Putnam field,
Dewey County, 30-18n-17w
West Putnam plant, Putnam field,
Dewey County, 9-17n-17w
Mustang Gas Products Co.— Calumet plant.
Watonga Trend field, Canadian County,
nw^-nw^4"27-14n-9w
Northern Natural Gas Co. — Cabot-Highland plant,
Anadarko field, Beaver County, l§4n-27e
Phillips Petroleum Co.t — Bradley plant and
field, Garvin County, ne4-nw4-18-4n-4w
Cimarron plant and field, Woodward
County, e2-ne4-27-20n-17w
Edmond plant and field, Oklahoma
County, w4-se4-31-14n-3w
Natura plant and field, Okmulgee County,
ne4-ne4-ne4-17-15n-13e
Norge plant, Northwest Norge field,
Grady County, ne4-3-6n-8w
Okla plant, Oklahoma City field,
Oklahoma County, ne4-sw4-l-lln-3w
Sooner #1 plant, Sooner field,
Major County, se4-se4-se4-17-20n-9w
Pioneer Gas Products Co. — Binger plant
and field, Caddo County, 26-10n-llw
Madill plant Cumberland field.
Marshall County, 32-7e-5s
Ringwood plant and field.
Major County, ll-22n-10w
Shell Oil Co.— Selling plant, Ellis, Dewey,
Gage et al fields, Oewey County, 4-19n-17w
Sohio Petroleum Co. — Elmore plant, Eola field,
Garvin County, 17-ln-lw
Norman plant. East Washington field.
McClain County
Sun Production Co. — Carney plant, Fallis field,
Lincoln County, 12-15n-2e
Goldsby Central plant, several fields,
McClain County, 3-7n-3w
Laverne plant and field,
Harper County, 20-26n-25w
Steedmaa plant, Allen field,
Pontotoc County, 36-5n-7e
Tonkawa plant Tonkawa SE field,
Kay County, 30-25n-le
Wateta pJant s*waJ telds,
Grant County, 5-27n-7w
Tenneco Oil Co.— Ames plant, Major County,
seVi of swV4-12-20n-10w
^^^™^*— "M MCT fr^^^™™^^
Gas
Gas through-
capacity put
15.0
107.0
30.0
15.0
70.0
1.0
12.0
3.5
26.0
65.0
60.0
25.0
18.5
50.0
20.0
70.0
15.0
11.0
250.0
50.0
140.0
56.0
150.0
2.0
27.0
16.0
12.0
15.0
27.0
80.0
75.0
75.0
5.0
17.5
45.0
225.0
3.0
2.0
15.0
65.0
10.6
90.0
NR
NR
NR
0.6
NR
1.6
26.0
50.0
35.5
11.4
9.4
56.3
8.3
51.8
2.6
2.8
202.0
10.0
NR
NR
NR
NR
NR
NR
NR
32
20.1
60.1
44.0
75.0
4.0
3.2
37.4
184.2
0.7
0.5
9.3
50.0
-
Process
method
2
2
2
2
2
4
2
3
3
2
2
2
2
2
3
6
2
3
2
5
1
3
1
3
3
1
3
7
2
247
2
142
3
2
7
7
3
3
2
2
102-
, — Production — 1,000 gal /day (Average based on the past 12 months) — v
Normal Raw Debut.
orunsplit LP-tas NGL rat
Ethane Prop. Isobut butane mix mix gaso. Other
10.0 8.0
269.0
6.0
109.0
5.2 2.0
1.1
0.3 10.8 2.3 4.5
41.2
86.1
21.5 23.2
46.9
21.6 29.5
(All products fractionated at N. E. Trail)
7.9 143.5
(All products fractionated at N. E. Trail)
(All products fractionated at N. E. Trail)
84.2 68.7
. •. . —
250.0
112.0
260.0
3.0
160.0
60.0
20.0
18.3
26.0 2.3
147.8
41.0 37.0
12.0 27.0
1.0
6.8
125.6
85.0 16.8 44.4
1.8 1.7
2.0
30.1
. .. 87.9
40.0
48.0 U1.Q
1.0
3.6
2.7
4.3
'4
1.5
16.8
2 0.0 '75.0
3.0
58.0 "245.7
"4.9
-------
Company, plant location
Texaco Inc.*— Apache plant and field,
Caddo County, 2-5n-12w . .
Camrick plant and field,
Beaver County, 31-ln-20ecm
Enville plant, SW Enville field,
Love County, 7-7s-3e
Texas Oil & Gas Corp.— Cimarron plant,
various fields, Blaine County, 24-18n-34w . .
Custer plant, various fields,
Custer County, 24-14n-16w
Jefferies plant, various fields,
Major County, 14-23n-12w
Union Oil Company of California— Caddo plant
and field. Carter County, 23-3s-le
Union Texas Petroleum — Chaney Dell plant,
various fields, Major County
Warren Petroleum Co.— Knox plant, Knox
Bromide field, Grady County, 33-3n-5w
Maysville plant, Golden Trend field,
Garvin County, 18-4n-2w
Mocane plant, Beaver County, 18-5n-25e, eon
Total
tAII figures are capacity
PENNSYLVANIA
Seneca Co. — Lament plant and field,
Elk County
Van plant and field, Venango County
Total
SOUTH DAKOTA
McCulloch Gas Processing Corp. — Belle
Fourche plant, Butte County, 24-12n-le
fatal
TEXAS
Adobe Oil Co.— Sale Ranch plant, Spraberry
Trend field, Martin County, 23-ln-37
Aluminum Company of America— Alcoa plant,
various fields, Calhoun County
^Amerada Hess Corp. — Adair plant and
field, Terry County, 5-C37-PS1
Aminoil USA Inc. — Birthright plant, Birthright,
Brantley-Jackson fields, Hopkins County
Amoco Gas Co.— Texas City extraction plant,
Galveston County, John Grant A-72
Amoco Production Co.— Anton Irish plant and
field, Hale County, 14-DT-HE & WT RR
Burnell-North Pettus plant and field,
Bee County, A-591
East Bay City plant and field,
Matagorda County, 54-3
Edgewood plant and field,* Van Zandt
County Z. Roberts-A 702
Hastings plant and field,
Brazoria County, 1-ACH+D-A 416
LaBlanca plant 'and field,
Hidalgo County, Tex-Mex RR
LaRosa plant* and field, Refugio
County, Jose M Aldrete
Levelland plant and field, Hockley County,
Labor 7, League 72, Val Verde Co. School Land
Luby plant, Luby-Petronia field, Nueces
County, Canutillo Colony Dutch Co
Midland Farms plant and field, Andrews
County, 8-42-T-T-N G&MMB&A
Monahans plant and field, Winkler
County 24-10-PSL
North Cowden plant, Cowden field,
Ector County, 34-3543-lm-T&P Ry
Old Ocean plant and field, Brazoria County,
Charles Breen League A46 • • •
Prentice plant and field,
Yoakum County, 20K PSL
Ropes plant and field, Hockley County,
12-5 Wlbarger County School Land
Slaughter plant and field, Hockley County,
14-15-49 Edwards & Scurry County School Land
tat
Gas threat*-
CM3t*itw not
7.5
45.0
23.0
90.0
50.0
20.0
10.0
100.0
NR
NR
NR
4,209.8
3.0
2.0
5.0
38.0
38.0
NR
150.0
5.0
30.0
140.0
16.0
130.0
150.0
60.0
70.0
50.0
16.0
40.0
90.0
45.0
5.0
45.0
570.0
6.0
2.0
80.0
NR
NR
NR
85.0
35.0
5.0
7.5
60.8
21.2
60.7
113.7
2,990.4
2.4
0.8
3.2
12.0
12.0
12.0
90.0
4.7
7.9
123.0
3.2
79.6
18.0
21.8
73.5
21.1
9.0
19.8
32.7
32.5
5.4
43.2
261.0
5.1
1.1
38.4
Proem
nethod
3
2
2
7
2
2
3
2
1
7
2
1
1
2
2
2
3&4
2
3
3
]
5
2
6&7
4
3
1
2
6&7
3
547
2
1
3
1
, — ProdMttoo— 1,000 tal/dayOUenfe oaso* enttepast IZmntfts) — .
•rinplit IP-cas NGL tat
Ethane Prop Isobot bitane ma viz tut. Other
3.0 7.0
88.7
10.3 . ... 6.5
150.0
21.0 23.0
13.0
8.1 7.2
112.9
7.3 0.9
47.7 7.2 31.1
12.6 24.5 . 45.4
82.7 853.3 118.3 278.7 648.4 2,689.4
'.'.'.'. 2.4 '.'.'.'. "l.l '.'.'.'. '..'.'.
2.4 1.1
7.0 7.7
7.0 7.7
76.2
49.5
17.5 12.0
7.6 13.1
24.8 15.4 40.2 26.7
30.5
17.8 15.9 .... 9.0 0.4 22.1
17.0 86.0
30.0
57.9 . ... 30.0
7.5 .... 12.7
128.0
78.3 . ... 55.0
149.0 97.0 30.0 28.0
33.0
121.0 .... 79.0
6.2
"37.7
38.8 «52.5
•91.6
283.3 565.5
0.5
1.0
1.5
7.6
"0.6
"2.7
•54.0
U3.2
U2.5
23.6
12.3 «20.1
"0.8
... "12.0
51.5 '115.0
92.0 '16.0
"8.7
63.0 «64.3
-103-
-------
Company, plant, location
, MMcftf • i ,— Production—1,000 gal/ day (Average based on the past 12 months) •
Gas Normal Raw Debut
Gas through- Process orunsplit LP-gas NGL nat
capacity put method Ethane Prop. Isobut butane mix mix gaso. Other
South Fullerton plant, Fullerton field,
Andrews County, 8-A 48-PS1
South Gillock plant* and field, Galveston
County, John Sellers
West Yantis plant* and field, Wood
County, 3-Oscar Engleton A 181
Wiilamar Miocene plant, Willamar West,
Miocene 6.U. field, Willacy County,
A J. Jones Estate Share 13
White Flat plant and field, Nolan County,
John Clark-A 287
Anchor Gasoline Corp. — Tabasco plant and field,
Hidalgo County, NW corner of Tract 322,
Las Ejidas de Reynosa Vieja Grant
Arkansas Louisiana Gas Co. — Jefferson plant
and field, Marion County, Heirs of John
Haniss A-188
Waskom plant, various fields, Harrison
County, J. Blair
Willow Springs plant, Willow Springs-
Manziel field, Gregg County, P.P. Rains
Atlantic Richfield Co. — 'Block 31 plant and
field, Crane County, 33-31
Crane plant, Wilshire field, Upton County,
128-DCCS&RRNG RRCo
Crittendon plant and field, Winkler County,
24-e23-PSL . . .
Dayton plant and field, Liberty County,
7 HT&BRR
East Rhodes plant and field, McMullen
County, Seale & Morris 9-A 441
Eldorado plant, Hulldale field,
Schleicher County, 81-TTTC RR
Fashing plant, Edwards Line Fashing field,
Atascosa, Karnes County, 131 Wm Smith
Hull plant, Hull-Merchant field,
Liberty County, William Smith A-342
Longview plant, East Texas field.
Gregg County, J. Moseley
Midland plant, Pegasus field. Midland
County, 17-40-4S-T&PRR
Northeast Thompsonville plant and field,
Jim Hogg County, 4r Holheim subdivision
La Animas GT Pena Tracts A-244
Nueces River plant, various fields, Live
Oak County, Cameron CSL 32-A-34
Price plant, East Texas field, Rusk County,
J. B. Cadena
Refugio plant and field, Refugio County
Roos Field Center plant, Roos field, McMullen
County, Chas. T. Stansel I02-A-1141
Silsbee plant and field, Hardin County,
George W. Brooks A4
South Hampton plant and field,
Hardin County, F. Simmons A451
Taft plant East White Point field, San
Patricio County, 48 & 48A Coleman Fulton
Pasture Lands
Beacon Gasoline Co. — Strawn plant,
H. J. Strawn field, Tom Green County
Biackhawk Gasoline Corp.— Game plant, County
Reg field, Jack County, 9 miles east of Graham
Breckenridge Gasoline Co. — Eliasville plant,
Stephens County Regular field, Stephens
County, TE&L Co. 1174
Lodi plant, Rodessa field, Cass County,
Wm R Meyers #1-166
Cabot Corp.— Estes plant North Ward field,
Ward County, 3-16, University Lands
Walton plant, Kermit field,
Winkler County, 11-26-PSL .
Champlin Petroleum Co.— Conroe plant and
field, Montgomery County
East Texas plant, Carthage & Bethany
fields, Panola County
Gulf Plains plant, Stratton-Agua
Dulce field, Neuces County
Chevron USA Inc. — Chevron plant and field,
Kleberg County, Lat. 27°25' Long. 97°17'
Kermit plant and field, Winkler County
North Snyder plant, Snyder field, Scurry County
10.0
32.0
50.0
110.0
S.5
67.0
3.5
205.0
20.0
130.0
15.0
50.0
70.0
12.0
50.0
12.0
18.0
35.0
10.0
100.0
90.0
15.0
6.5
42.0
50.0
25.0
40.0
7.0
700.0
5.0
5.0
11.5
33.5
65.0
220.0
250.0
80.0
50.0
44.0
9.6
25.6
15.6
12.7
2.3
NR
0.9
50.0
7.8
136.6
10.5
33.0
27.0
3.0
29.5
7.5
5.0
17.0
9.6
35.0
33.0
3.0
4.5
10.0
20.0
5.0
22.0
6.5
400.0
2.0
3.4
7.5
21.2
66.0
170.0
131.0
15.0
17.0
43.0
6&7
2
3
5
3
1
5
2 18.0 7.0 9.5
5
2 0.2 106.4 57.1
3 7.2 7.9 4.8
7 29.9 16.0 3.6 4.4
2 17.6 12.9 3.6 3.7
5
1 36.6 19.7
1
2 2.4
2&6 19.2 88.7
3 4.1 5.8 3.9
5
2 3.0 18.0 9.0
1 15.5 15.5
5 ..
2 10.5 10.5 4.6 5.1
1 1.4 1.0
2 4.0 3.0
3
344
2 . ... 2.8 1.9
1
6
6
7
7 40.5 44.1 38.5
2 62.9 48.9 14.9 14.9
5
2 5.0 8.9
3 103.9 163.3 18.6 62.2
93.0
9.2 513.1
U71.7
"0.3
"19.0
11.0 3.8
"0.5
33.5 '1,5
•1.0
102.0
"
3.0 ...
45.6 U209.4
4.0 110.1
7.2
6.3
"2.3
53.6 12.9 "7.1
1.2 1.6 "1.8
3.3 ...
110.5
3.4 "0.1
"4.9
7.0
19.2
1.5
"7.8
13.3
2.1 ...
5.0
25.0
0.9 0.6
2.6
5.5
45.6
66.9
146.3
101.5
75.2
2.1
U18.3
53.5
-104-
-------
Company, plant location
Sherman plant and field, Grayson County ...
Sivells Bend plant and field, Cooke County
Cities Service Co.— Chico plant various fields,
Wise County, GH&HRR Co. A-384
Corpus Bay plant Corpus Christ! Bay field,
San Patricia County, Lot 9, Gregory
Sub'd, Geronimo Valdez A-296
East Texas plant and field, Gregg County,
Wm. Castleberry A-38
Ector plant*, Harper Devonian fietd,
Ector County, 28-44-2s PPRRCS
Lefors plant, E&W Panhandle field,
Gray County, 2-1, AC H&B
May plant and field, Kleberg County,
Lot 12, Blk. 5, Gabriel Trevion, A-232
Myrtle Springs plant and field, Van Zandt
County, J. Salngva, A-765
Pampa plant*, Panhandle & White Deer fields,
Gray County, 133 & 136 I&GNRR
Panola plant, West Carthage field, Panola
County, Matthew Parker A-527
Roberts Ranch plant*, various fields.
Midland County, 16-41-3s— T&PRR
Robstown plant and field, Nueces County,
Simmons & Perry's Subv. of Fred Elliffer Tract
San Antonio Bay plant, North San Antonio
Bay field, Calhoun County, Lot 11, Miguel
Castillo A-7 . . .
Stonewall plant, various fields, Stonewall
County, E. Borden A-831 .
Waco plant, various fields, McClennan
County, J. D. Sanchez A-36
Welch plant, various fields, Dawson
County, 67-Block M of EL&RRRR
West Seminole plant* and field, Gaines
County, 335-GCCSD&RGNGRR
West World plant*, various fields,
Crockett County, 19-AGCSFRR
Clark Fuel Producing Co.— South Kelsey plant
and field, Starr County Tract 3-A Santa
Teresa Grant . .
Sullivan City plant and field, Hidalgo
County, Tract 238, Portion 40
Coastal States Gas Producing— Albany plant
Shackelford County
Freer plant Webb County .
Hidalgo plant Hidalgo County
Mission plant, Hidalgo County
Coates, George H., Estate of— Jay Simmons
plant and field, Starr County, San Jose Grant
Colorado Interstate Gas Co. — Bivins plant,
Panhandle field, Moore County, 33-PMc EL&RR
Fourway plant, Panhandle field, Moore
County, s2 of sw4 49-6T T&RR
Continental Oil Co.— Chittim plant, Chittim
Ranch field, Maverick County, N. J. Chittim
Ranch
Hamlin plant Round Top field, Fisher
County l&TC-l
Port plant, Port Acres-Port Arthur field,
Jefferson County, 14-1C-RL
Ramsey plant, Ford Sullivan field.
Reeves County, 36-38-1
Rincon plant and field, Starr County,
485-CCSD-R6N6RR
CRA Inc.— Eldorado plant Schleicher County,
33-MGH4SA
Mertzon plant, Irion County, Tom Green
County School Land-#l
Quitman plant, Wood County, SG Purse A-456
Delta Drilling Co.— Ozona plant and field,
Crockett County, MN-1
Diamond Shamrock Corp. — McKee plant, Moore,
Hugoton, Ochiltree fields, Moore County,
39944-HATC
Dorchester Gas Producing Co. — Cargray plant,
West Panhandle field, Carson County, 46-4-I4GN
Sterling plant, Conger field. Sterling
County, 10-22-KiTC
Texon plant, Big Lake field,
Reagan County, 12-2-University
fin
Gas ttranck-
caoacity pot
40.0
5.0
55.0
75.0
27.0
4.0
32.0
50.0
30.0
50.0
100.0
95.5
65.0
12.4
20.0
60.0
2.5
40.0
15.0
3.0
20.0
15.0
190.0
80.0
30.0
5.0
165.0
150.0
5.0
20.0
175.0
10.0
33.0
25.0
25.0
30.0
60.0
375.0
100.0
18.0
5.Q
22.0
1.0
45.0
' 38.0
20.5
2.5
9.0
5.0
15.0
18.0
22.0
80.0
22.0
7.9
4.8
43.0
2.3
28.0
5.5
1.2
0.8
3.0
81.0
10.0
23.0
2.0
103.0
47.0
3.5
8.7
3.1
2.3
17.2
10.0
12.5
5.7
39.6
322.0
33.0
12.0
2.2
Process
method
2
1
2
2
2
7
2
2
2
2
2
2
1
2
2
7
3
2
2
2
3
3
2
2
2
1&2
2"
1
3
3
2
3
5
6&7
6&7
1
5
2&6
1
3
3
-105-
— ProdBctlot— 1,000 pi,
Ethan* Prop. Isabirt.
15.6
0.7
80.9 95.2
17.6 13.1
38.3 74.3
7.4
30.0
6.1
9.3 5.3
2.9 3.2
18.9
9.2
5.4
'.'.'.'. 12.5
1.6
5.5
7.1
3.3
2.5
2.6
1.3
5.7
(Liquids fractionated by
5.2 2.7
3.5
6 J
'.'.;; 5.8
53.9
284.9
17.1
52.6
7.4
or Buplit LP-fas
butaM nix
17.7
0.9
31.2
4.2
55.8
7.6
13.4
1.2
2.4
1.3
10.6
4.1
2 £
19.1 '.'.'.'.
2.0
13.2
3.0
6.5
others) 51.2
12
2.7
6.3
13.0 :
28.9
116.9
16.9
B the part 12 months) — ,
Raw Debit
NCL nat
mix fan. Other
0.5
5.2
46.7
5.8
135.7
25.2
34.4
1.8
14.6
144.2
93.1
25.0
60.0
22.0
10.8
9.2
29.1
6.9
34.6
3.8
18.5
7.7
2.1
6.5
5.7
1.6
il.7
2.6
4.6
1.5
2.4
9.9
10.5
138.9
14.8
•41.6
•8.7
U2.0
'Mil
"36.6
•269.3
'4.5
•22.0
•1.7
-------
Company, plant, location
Woodlawn plant and field,
Harrison County, L Watkins
Eagle Petroleum Corp. — KMA plant,
KMA, Wichita field, Wichita County
El Paso Natural Gas Co.— Midkiff plant,
Spraberry field, Reagan County,
nw4-nw2-sw4-22-T&PR Co.-97-55
Santa Rosa plant, Rosa-Ft. Stockton field,
Pecos County, $2-105-8 H&GRR Co
Sealy Smith plant, Monhans, Yarbrough-
Allen fields, Ward County, nw4-43A
Westlake plant, Lake Trammel! field, Nolan
County, e2-ne4-sw4-w2-nw4-se4-76-X T&P
Wilshire plant and field, Upton County,
e2-ne4-ne44ne4-se4-ne4-135-E CCS
D4RGNGRR Co
Enserch Exploration Inc. — Carlsbad plant and
field, Tom Green County, Mason and Perry
subdivision of Collyns Ranch
Gordon plant, Palo Pinto County,
Thomas Reed A-384
Madisonville plant, Madison County,
Alfred Gee A-16
Needville plant, Ford Bend County,
Patrick H. Durst A-166
Pueblo plant, East land County,
SP RR Co.464
Ranger plant and field, Eastland County,
H&TCRR4-4
Red Oak plant, Leon County
Springtown plant, Parker County,
J. L. Hodges A-690
Sonora plant, Button County,
0. H. Corbin 6-JK A-1437 & 1433
Trinidad plant, Henderson County,
North Addison A-17
Etexas Producers Gas Co. — Chapel Hill plant,
Chapel Hill-Oelaney field, Smith County
Exxon Co. USA— Amelia plant and field,
Jefferson County, C. Williams
Anahuac plant and field, Chambers County,
H&TCRR-51 A-112
Clear Lake plant and field, Harris County,
James Lindsey
Conroe plant and field, Montgomery County,
R House
East Texas plant and field, Rusk County, .
T. J. Martin
Hawkins plant and field, Wood County,
H. Watson
Heyser plant and field, Calhoun County,
Agaton Sisneros
Jourdanton plant and field, Atascosa
County, Edward Estes
Katy plant and field, Waller County,
110 A-332
Kellers Bay plant and field, Calhoun
County, N. Covassos League A-2
Kelsey plant and field, Brooks County,
LaBlanca Grant A-459
King Ranch plant, Seeligson field,
Kleberg County, R. King 172
Magnet Withers plant and field, Wharton
County, Syivanus Castleman
Neches plant and field, Cherokee County,
J. H. Shaw
Northeast Loma Novia plant and field,
Duval County, J .Poitevent 213 A-923
Pita plant and field. Brooks County
Pledger plant and field, Pledger County,
W. C Carson
Pyote plant, Ward County,
32-16 University Lands
Sand Hills plant and field, Crane County,
17 18, 19-32-13&22-27-PSL
Santa Fe plant and field, Brooks County,
San Salvador del Tuie A-290
Sarita plant and field, Kenedy County,
J. A. Balli A-2
Sugar Valley plant and field, Matagorda
Countv. Burnett & Soioumer
mm
Gas
capacity
100.0
3.0
168.0
30.0
17.0
25.0
30.0
4.0
50.0
20.0
96.0
8.0
7.0
10.0
75.0
90.0
65.0
12.0
16.0
275.0
200.0
117.0
25.0
125.0
22.0
26.0
1,260.0
47.0
. 250.0
2,650.0
100.0
40.0
47.0
30.0
200.0
100.0
60.0
47.0
255.0
12.0
Icfd .
Gas
through- Process
put method
8.0 1
1.0 3
82.9 1
16.1 1
9.1 4
10.6 1
11.9 4
1.1 3
37.1 7
10.7 5
29.5 5
8.5 2
4.2 2
3.1 5
66.7 7
26.6 7
64.3 7
2.4 1
11.0 5
246.6 2
176.3 2
95.0 2-6-7
12.0 3
107.0 2
16.0 5
19.0 1
734.1 2
9.0 2
110.0 2
1,665.0 2
32.8 5
23.0 2
10.0 2
4.0 5
176.0 6&7
52.0 6
64.0 2
16.0 2
94.0 2
9.6 5
, — Production— 1 ,000 gal/ day (Average based on the past 1 2 months) — «
Normal Raw Debut
orunsptit IP-gas NGL rat
Ethane Prop. Isobut butane mix mix gaso. Other
0.1 4.3 4.0 nI6.0
1.8 2.0
88.4 168.1 76.7 62.9
28.2
3.1
40.0
4.0
2.1
123.6
' 1.4
3.7
17.7
.... . . . ID. 9 . . . .
0.5
250.5
17.1
88.1
2.6 2.5
"0.7
79.0 60.1 17.2 16.4 40.7 U4.2
108.4 76.0 18.1 16.8 39.5 "2.1
71.8 59.9 13.6 21.5 43.9 "7.6
35.2 65.7 13.5 35.1 30.3 "2.7
56.1 113.9 51.5 64.0 99.6 "12.3
3.7
3.7 1.1 4.1 5.6 103.7
541.9 179.3 46.0 46.3 181.8 "4.9
0.2 3.9 1.5 1.3 2.3
52.0 55.2 17.6 18.4 "42.8
993.7 416.3 158.1 122.4 10429.2
"2.0
15.7 31.2 6.3 16.0 19.5 "0.9
3.9 5.1 1.3 1.6 2.4
0.7
36.2 27.8 84 68.0 *05
"0'.3
U2.2
53.0
108.0
8.6 5.8 2.6 1.8 "4.2
60.4 25.6 9.5 8.6 "18.6
«vifi
-106-
-------
/
Company, plant, location
Thompson plant and field, Fort Bend
County, John Rabb
Tomball plant and field, Harris County,
C. Goodrich . ...
Tom O'Connor plant and field, Refugio
County, Maria Ximines A-324
West Ranch plant and field, Jackson
County, Ramon Musquez
Seneral Crude Oil Co. — Salt Creek plant
and field, Kent County
Gerlane Petroleum Co. — Mobeetie plant and
field, Wheeler County
Setty Oil Co. — East Vealmor plant, various
fields, Howard County, 20-27-H-2C
Headlee plant, Headlee Ellenburger field,
Ector County, 41-2S-T&PRR
Headlee Devonian plant* and field,
Ector County, 41-2S-T&PRR
Kingsmills, Schafer, Watkins plant, Panhandle
field, Hutchinson, Carson, Gray Counties,
88-4-1 PN
New Hope plant and field, Franklin
County, Isaac Barre A-20 .
Normanna plant and field, Bee County,
Thomas Duty
Spearman plant, Hansford field,
Ochiltree County, 23-R-B-B
Umbrella plant and field, Chambers
County, TST 87-Galveston Bay
West Bernard plant and field, Wharton
County, J. M. Rose Heirs
irimes Gasoline Co. — North Dora plant and
field, Nolan County, e2-45-20-T4RR
iulf Energy & Development Corp.— Powell
plant and field, Navarro County
Rio Grande City plant, various fields,
Starr County
Runge plant, various fields, Karnes County . .
Houston Oil & Minerals Corp. — Smith Point
Extraction plant, North Point Bolivar field.
Chambers County, E. T. Branch A-40
South Liberty Extraction plant, South
Liberty field, Liberty County
ING Petrochemicals Inc. — Bammel plant,
various fields, Harris County, HT&BRA-A420 .
Gregory plant, various fields, San Patrick)
County, Geronimo Valdez A269
Liverpool plant, various fields, Brazoria
County, Day Land & Cattle Co. A-601
Loma Blanca plant, various fields, Brooks
County, Loma Blanca Grant-F. G. Chapa A98 . .
Robstown plant, various fields, Nueces
County, Mathis Garcia A116
Sonora plant, various fields, Sutton
County, HEXWTRRA 352
Tuleta plant, various fields, Bee County,
Brooks & Burleson
Victoria plant, various fields, Victoria
County, James Reed A236 . . .
lunt Estate, H. L — *Pecos Valley plant and
field, Pecos County, 3-H&TCRR
iunt Oil Co. — 'Fairway plant, Fairway James
Lime Unit field, Henderson County,
s2 G. E. Milner Tract, Jose Mora A497
idian Wells Oil Co.— Southwest Ozona plant and
field, Crockett County, 2-2 I&GN
rion County Plant— Rocket B "II" plant,
Spraberry Trend field, Irion County,
nw4-78 H&TC 14
'm McGee Corp. — Hobart Ranch plant, Hemphill
County, 70-A-2 H&GN
Pampa plant East Panhandle field, Gray
County, 5163-3 I&GN
-:;u:d Energy Corp. — Mineral Wells plant, Palo
Pinto County
'iguid Products Recovery Inc.— East Ramsey plant
and field, Colorado County
-c/aca Gathering Co.— Bay City plant,
Matagorda County
Corpus Christi plant Nueces County
Sohlke plant, DeWitt County
San Antonio nlant. Bexar Courrtv
MMc
Gas
capacity
40.0
80.0
150.0
23.0
28.0
NR
55.0
30.0
120.0
220.0
50.0
32.0
50.0
12.0
30.0
4.5
15.0
31.0
52.0
150.0
18.0
100.0
70.0
24.0
25.0
75.0
50.0
45.0
94.0
10.0
137.0
15.0
NR
43.5
24.0
30.0
15.0
500.0
200.0
1250
120.0
fd ,
Gas
ttrofljb-
P«t
31.0
72.2
112.0
18.1
20.0
9.0
NR
16.7
140.0
NR
40.3
18.5
NR
40
114
3.0
9.0
19.0
42.0
105.0
12.0
64.5
42.7
10.0
10.2
17.1
52.9
24.5
177
1.7
120.0
150
10.0
NR
NR
300
7.5
2320
162.0
1340
1070
. — ProimctioB— 1.000 gal/d
P roots
method Ethan* Prop. Isabel
6&7 17.4 11.0 2.0
2 250 191 5.2
1 17.0 10.2
3
4
2
2 144.0 16.0
2
2
2 82.0 25.0
1 " 15.8
2 7.0 9.4
2 28.0
5
1 1.1
3 10.0
1
2 5.5
2 25.0 22.0
5
3
2 27.2 13.5
2 .... 23.8
2 ....
2
2 13.8 10.2
2
1
2 4.5
3
2 27.3
2
3
3
2
2
3
2
2 40.6 50.4 25.9
?
7 .... 121
lay (Average based on tfae past 12 months) — .
Momal Raw Debut
orunspiit IP-fas NGL nat
butane mix mix gaso. Other
3.0 3.7
6.4 21.2 U3.9
11.3 29.4 "1.4
"3.6
1.4
11.0
78.0 62.0 '194.0
44.6
251.2
50.0 83.0 26.0
14.7 83.5
5.1 38
35.0
08
3.3 57
8.0 5.0
3.8 30
13.0 12.0
7.5 "08
3.0
6.5 4.6
18.6 9.6
6.1
112
65.7 4.3
64.2
12.2 94
50 40
1.7
29.4 235.0 30.3
600 "6.5
401.0
102J U23 7
48.7
91 2 U4.2
'. 5.5
43.4 "878
23.6 34.0 ....
119.9 "574
27.3 2t3
-107-
-------
Company, plant, location
, MMcfd , ,— Production— 1,000 gal/ day (Average based on the past 12 months) —.
Gas Normal Raw Debut.
Gas through- Process orunsplit IP-gas NGL itat.
capacity put method Ethane Prop. Isobut. butane mix mix taso. Other
Mapco Inc. — Westpan 950 plant, West Panhandle
field, Hutchmson County, 92-Y2-TTRR
Westpan 1000 plant, West Panhandle
field, Hutchinson County, 92-Y2-TTRR
Marathon Oil Co. — Markham plant, North Markham-
North Bay City fields, Matagorda County,
4-9-9
Susan Peak plant and field, Tom Green
County .
Welder plant, Plymouth field, San Patricio
50.0
145.0
165.0
1.5
47.7
105.4
112.8
1.8
?
?
2
3
125.7
215.3
89.3
3.0
2.9
County, 49-R. Montgomery 199 and Ewen Cameron
A-97
Yates plant and field, Pecos County,
194-Scrap 1234-1 .
Matrix Land Co. — Box-Elmdale plant, Callahan
field, Callahan County . .
Tuscola plant, Taylor County Regular
field, Taylor County . . . ...
Mobil Oil Corp. — Canadian plant, Northeast
Canadian field, Hemphill County, NE
corner of David Crockett
Coyanosa plant* and field, Pecos
County, 48 OWTTRR
Desdemona plant and field, Eastland
County, J. W. Carruth Farm W. M.
Fundenburg
Electra plant and field, Wilbarger
County, 17-13 H&TCRR
Kittie-Hagist complex, various fields,
Ouval & Live Oak Counties, Tract 53
Kittie George West Ranch subdivision
La Gloria plant and field, Jim Wells
County, 9-83 La Gloria subdivision
'Pegasus plant and field, Midland County,
62-30-40-4S T&PRR
Seeligson plant* and field, Jim Wells
County, Jaboncillas Grant A. Ramirena
Vanderbilt plant, West Ranch field,
Jackson County, R. Musquez A-59
* Waha plant and field, Pecos County,
5-C3 PSL
Wilcox plant, Provident City field,
Lavaca County, J. R. Ragsdale A-377
Monsanto Co.— Diamond "M"— Sharon Ridge plant
and field, Scurry County, 182-97 H&TC
Natural Gas Pipeline Co. of America — One Sixty-one
plant, Panhandle field, Hutchinson County,
s5-by2 TTRR Co
One Sixty-two plant, Panhandle field,
Moore County, 1 TTRR Co.
North Texas LPG Corp.— Barton Chapel plant,
Jack County
Eastland plant, Eastland County
Galveston plant, LaFitte's field, Galveston
County
Huckabay plant, Erath County
La Sal Vieja plant, Willacy County
Lone Camp No. 1 plant, Palo Pinto County .
'.one Camp No. 2 plant, Palo Pinto County
lone Camp No. 3 plant, Palo Pinto County
Lone Camp No. 4 plant, Palo Pinto County
Ponder No. 1 plant, Denton County
Ponder No. 2 plant, Oenton County
Ranger No. 1 plant, Eastland County
Ranger No. 2 plant, Eastland County
Seven Oaks plant, Polk County
Sutton plant, Sutton County
Northern Gas Products — Spraberry field, Martin
County, 31-37-2n T&PRR
Sprayberry plant, Martin County, 4-HA
Northern Natural Gas Co.— Jasper plant, Puckert
North Ellenberger field, Pecos County, CSL
16-19
Spearman plant, Hansford-Ochiltree fields,
Ochiltree County, 23-B&RR
Odessa Natural Corp. — Foster plant, multi fields,
Ector County, 1842-2S-T&PRR
Ozona Gasoline Plant — Ozona plant and field,
Crockett County, 13-TCRR R
Palo Pinto Oil & Gas Co.— Markley plant, Markley SE
Marble Falls field, Jack County, SPRR
A-583
55.0
20.0
NR
NR
35.0
550.0
1.3
1.4
70.0
318.0
NR
318.0
88.0
NR
255.0
55.0
242.0
242.0
15.0
2.0
15.0
15.0
15.0
10.0
10.0
10.0
30.0
2.0
2.0
5.0
10.0
20.0
10.0
10.0
5.0
35.0
200.0
24.0
4.0
4.0
26.9
20.0
3.0
1.0
23.0
240.6
1.0
0.8
70.0
231.0
80.4
223.0
92.0
138.3
65.0
31.8
134.1
137.8
14.0
1.0
14.0
14.0
7.0
10.0
9.0
9.0
27.0
2.0
2.0
4.0
4.0
12.0
10.0
5.6
3.3
12.0
100.0
21.0
3.0
1.0
-
1
2 7.2
3
3
6
2
3
3
1 63.5 24.3 15.6
6 201.6 95.7 31.3 25.2
2 83.1 66.6
6 165.6 58.0 16.5 13.9
2&5
2
2 27.2 36.8 19.1
3 113.9 164.1 75.0
5
5
7
3
7
7
7
?
7
7
7 ... .
3
6
3
7
2
7
3
3
2
3
? 56.0 48.5 . 30.0
3
3
108-
6.2
30.0
9.0
Z.O
61.9
166.7
3.1
6.1
76.9
230.9
50.3
1.1
49.8
47.0
2.0
14.4
21.3
9.6
21.8
23.2
23.2
65.8
1.5
1.5
8.1
8.1
17.8
22.6
28.0
20.0
7.0
6.0
7.7
"192.1
7.8
5.3
19.5
65.7 "17.0
56.6 "11.0
37.3 515.4
25.1
"1.7
"0.1
"0.6
"0.5
"0.5
U1.6
U1.8
18.2
25,0
-------
UUrf-*
Company, plant, location
Parade Co.— Giles plant, East Texas field,
Rusk County ... .
Pecos Co. — Barnhart plant*, Barnhart and Farmers
field, Reagan County, 5-HE&WT RR
Permian Corp. — Possum Kingdom plant, lies North
field, Stephens County, Edward
Romershaven
Todd Ranch plant, Todd Held, Crockett
County, 28-WX GCD SFRY
Perry Gas Processors — Bakersfield plant,
Pecos County
Barstow plant, Ward County
Dimmit plant, Dimmit County
Hokit plant, Pecos County
Howe plant, Ward County
La Salle plant, La Salle County
Pawnee plant, Bee County
Pyote plant, Ward County
Thompsonville plant, Jim Hogg County
Petroleum Corp. of Texas — Ibex plant, Ibex,
Shackelford Co. Regular field, Shackelford
County, nw28-BAL
South Bend plant and field, Young County,
J. Garrett
PGP Gas Products Inc. — Imperial plant, Abell
and other fields, Crane & Pecos County,
21-1 H&TCRR
Phillips Petroleum Co4— Andrews plant, various
fields, Andrews County, w2-nw4-19-
A46-PSL
Bertedum plant, Pembrook, Stiles and other
fields, Upton County, w2-se446-Y-MK4T
Brazoria plant, Chocolate Bayou field,
Brazoria County, nw4-5-HT&B-A221
Canadian plant, West Panhandle field,
Hutchinson County, nw4-se4-l-X02-H40B
Crane plant, McElroy and other fields,
Crane County, ne4-216-F-CCSD&RGNR RR
Dumas plant. West Panhandle field, Moore
County, nw4-181-44-H4TC
Ector plant, Grayburg-Strawn field, Ector
County, sw4-ne4-33-44-ln-T4P
Fulleiion plant, Fullerton and Shafer
Lake fields, Andrews County, 17-A-
32-PSt
Goldsmith plant, Goldsmith, Harper-Penwell
and other fields, Ector County
nw4-se4-3344-ln-T4P
Gray plant, East Panhandle field, Gray
County, e2-32-B2-H4GN
Hansford plant, West Panhandle field,
Hansford County, 7-8-1-PSL
Henderson plant, North Henderson field.
Rusk County, sw portion A. H. Grain
(Anderson Tract)
Luling plant, Branyon, Darst, Salt Flat,
& Spiller fields, Caldwell County,
North Corner, John Henry, Abst. 12
North plant, East Panhandle field, Gray County,
se4-sw4-35-nw4-ne4-36-3-M4GN
Pantex plant, West Panhandle field,
Hutchinson County, 8&9-M Whitley
Puckett plant and field, Pecos County,
n2-26-101-TC RR
Rock Creek plant, West Panhandle field,
Hutchinson County, nw4-22-y-A4B
Sanford plant, West Panhandle field,
Hutchinson County, $2-n2-w2-s2-82-46-H4TC
Sherman plant, West Panhandle field, Hansford
County, 748-1-PSl
Sneed plant, West Panhandle field, Moore
County, w2-nw4-Freeman Brazemore
Sprayberry plant, Tex-Harvey & Azalea fields,
Midland County, se4-25-3s-37-T4P
Tunstill plant and field, Reeves County,
ne4-ne4-10-2-56-T4P
3ioneer Gas Products Co.— Arrington plant,
Anadarko Basin field, Hemphill County,
62-A-2
East Goldsmith plant, Ector County,
34-34
Fain plant, West Panhandle field, Potter
Countv. GAM 10-181-3
Gas
Gas tftrough-
capacity pot
7.5
25.0
5.0
5.0
8.0
25.0
10.0
25.0
75.0
20.0
20.0
300.0
50.0
10.0
8.0
20.0
115.0
85.0
55.0
18.0
63.0
330.0
40.0
55.0
370.0
74.0
170.0
370.0
12.0
5.0
40.0
250.0
150.0
150.0
34C.O
250.0
40.0
28.0
40.0
50.0
130.0
3.9
6.0
2.5
1.8
NR
NR
NR
NR
NR
NR
NR
NR
NR
7.0
7.0
12.0
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
42.1
15.1
70.0
, — ProdBrttaB— 1,080 eal/oay(Avtrafelttjid on tt« past 12 moiraw) — ,
Moreui Raw Ortut
Process orinplit LP-fas NGL nat
method Ethane Prop. Isonot butane mix mix faso. Other
1 31.6
1 . . 6.6
3
3
1
1
1
1
1
1
1
1
1 . .
1 . .. 11.0
1 10.9
647 6.4 10.7
1
1
2
1
2
1
1
1
1-3-7
1
1
1
347
1
1
1
347
1
2
1
1
1
2
2*7
2 35.1
12.0
3.7 3.7
7.5
15.0
10.8
13.4
1.5 4.6 4.7
400.0
270.0
106.0
100.0
300.0
550.0
100.0
480.0
1,400.0
250.0
125.0
15.0
60.0
52.0
250.0
200
2500
270.0
500.0
270.0
300.0
75.0
54.8
49.0
430 9Q7
-ino-
-------
, MMcfd
fias
Gas through-
Company, plant, location capacity put
Pampa plant, East Panhandle field, Gray
County, H&GN 96-B-2
Turkey Creek plant, West Panhandle field,
Potter County, G&M 36-M-2
Richardson, Sid Carbon & Gasoline Co. — Keystone
plant* and field, Winkler County, 5-B-2 Public
School Land
Shell Oil Co.— Bryans Mill plant*, Bryans
Mill, Frost, Carbondale and Lower Glen
Rose fields, Cass County, B. F. Lynn
A-651
Conley plant, Conley, W. Odell, Thrash
fields, Hardeman County, 80-H W&NW RR.
Houston Central plant, Sheridan, Provident
City, other fields, Colorado County,
F. Mayhar A-400, K. Winn A589
Northwest Ozona plant and field, Crockett
County, 46-OP GC&SF RR
Person plant, Person and other fields,
Karnes County, Jesus Hernandez A-140
Tippett plant, Crossett, El Cinco, Tippett
West fields, Crockett County, 28-31
H&TC RR
TXL plant, TXL, Wheeler, Harper fields,
Ector County, 1745-1-ST&P RR
Wasson plant, Wasson and Brahaney fields.
Yoakum County, 827-0 J. H. Gibson
Southwest Forest Gas Gathering— Rocker B 1
plant, Spraberry Trend field, Reagan
County
Stiles Plant Operators— Stiles plant, Spraberry
Trend field, Reagan County
Suburban Propane Gas Corp. — Lubbock County plant,
Idalou Strawn Pool field, Lubbock County,
N/2 59-A ELRA
Martha F. Berry plant, West Big Foot Gas
field, Frio County, M, C. Patton 1178
A-542
Sun Production Co. — Big Wells plant and field,
Dimmit County, l&gnrr-4-233-82-l
Concho plant, several fields, Concho
County, 153-72-T&NO
Jameson plant and field, Coke County,
315-1A-H&TCRR
Luby plant and field, Nueces County,
9-G Part Petronilla Ranch
Red Fish Bay plant, Redfish-Mustang field,
San Patricio County, R. W. Williamson
Shamburger plant, South Lake field, Smith
County, John Lane A-557
Snyder plant, Kelly Snyder field, Scurry
County, 16-1 J. P. Smith
Sun plant and field. Starr County,
239-AB225-CCSD4RGNGRR
Tijerina-Canales plant, Tijerina-Canales-
Blucher fields, Jim Wells County, 343-
CCSO&RGNG
Victoria plant, several fields, Victoria
County, Felipe Oimitt A-20
West Helen Gohlke plant and field,
Victoria County, 1-1 RR
Superior Oil Co. — Portilla olant and field,
San Patricio County, J. Francisco —
E. Portilla— A-53
Tenneco Oil Co. — Chesterville plant, Colorado
County, 16-WeITs Thompson A-708
LaPorte plant, Harris County, Tract 55
Johnson Hunter League A-35
Leabo plant, Matagorda County, swVi-17
A-351
Pearce plant, Aransas County, 64-65-66-
75-77-78-38-89-90 Lamar
Ward plant, McAllen field, Hidalgo County,
Porcion 68, Gregorio Camacho A-28
Texaco lnc.$— Blessing plant, Matagorda County,
59-C J. E. Pierce H&GN
Encinitas plant, Brooks County, nw4 San
Antonio Grant A214
Fuller plant, Scurry County, 642-97
H&TCRR
60.0
100.0
140.0
70.0
6.0
425.0
10.0
54.0
75.0
65.0
175.0
NR
4.0
0.6
22.0
35.0
10.0
45.0
10.0
140.0
1.0
150.0
88.0
75.0
40.0
40.0
15.0
55.0
21.0
95.0
75.0
140.0
65.0
17.0
58.0
14.7
60.3
100.0
67.3
1.0
205.2
8.0
28.5
52.0
43.0
154.0
13.0
2.0
0.2
5.0
33.0
5.3
42.8
4.9
39.7
1.2
133.0
84.4
34.9
17.3
12.3
12.0
30.0
13.0
20.0
18.0
40.0
NR
NR
NR
> , — Production — 1,000 sal/day (Average based on the past 12 months) — >
Normal Raw Debut
• Process orunsplit IP-gas NGL nat.
method Ethane Prop. Isohot butane mix mix gaso. Other
2 13.8
2 34.9 38.3
7 28.0 17.0
2 48.9
3 3.0 2.0
2 181.3 148.7 34.1 44.6
3
2 16.0 11.2
2&7 97.0 61.0
1 49.0 72.0 31.0
142 214.0 443.0
3
3
3
2 4.0 1.3
2 ' 31.6 29.1
2
2 48.9 55.8 27.8
NR
2
3
6 188.6 29.4 86.1
3 44.5 51.1 30.1
2 3.9 5.8
2
2
2
2 17.5 4.9 6.0
(t) (4.5) (3.2) (2.9)
2
2 12.0
2 11.3 9.2
2 20.0 15.0
2
2 58.0 46.0
-110-
24.2
37.2
18.0 "105.0
73.2
2.0
40.3 '18.7
"96.4
15.0 5.0
10.6 "2.9
52.0
30.0
480.0
42.0
12.0
1.8
1.8
20.7
5.6 2.3
32.4
6.7 2.3 "1.7
27.1 12.6
4.6
1,192.8 89.3 "1.1
49.0 '8.4
7.0 '16.4
"5.8
24.4
19.5
9.0 4.9
8.8
(2.3)
25.9
21.8
15.5 '1.5
47.3
24.0
227.5 59.0
-------
Gas
Gas throufR-
Company, plant location capacity put
Handy plant, Grayson County, se4 A-1441
IG&NRRCO
Humble plant, Harris County, J. B.
Stevenson Fee A-703 B-4
Lamesa plant, Dawson County, 36-34-5n
T&PRR
Lockridge plant, Ward County, 101-34
H&TCRR
Mabee plant, Andrews County, 3240&
31-39-2n
Ozona plant, Crockett County, 3-MN-
GC&SERR
South Kermit plant, Winkler County,
22-22 B-3 PSL
Tijerina plant, Jim Wells County, A Canalas
300 A79
Texas Oil & Gas Corp. — Coyanosa plant, various
fields, Pecos County, 18-143-T&STL
Oenton plant, various fields, Denton County,
BB8&CRR A-175 .
East Texas plant, various fields, Marion
County, John H. Kernels A-235
Laredo plant, various fields, Webb County,
Porcion 14 N. D. Hachar East
Shackelford plant, various fields, Callahan
County, SYR 23424 B.D.H. Lands
Tipperary Corp.— Bowie plant, Montague County
Claytonvifle plant, Fisher County
Tuco Inc. — Carson County plant, Panhandle field,
Carson County, 4-5 I&GN PR
Union Oil Co. of California — Bakke plant and
field, Andrews County, 20-A44-PSL
Dollarhide plant and field, Andrews
County, 25-A52-PSL
Fort Trinidad plant* and field, Houston
County, RCS-A-23
Van plant and field, Van Zandt
County, JWS A-891
Union Texas Petroleum — Benedum plant, Spraberry
Trend and various fields, Upton County
Marrs-McLean plant, McLean field,
Jefferson County
Perkins plant, various fields, Cooke County
Southeast Seminole plant and field,
Gaines County
Walnut Bend plant and field, Cooke County
Wellman plant and field, Terry County
United Gas Pipe Line Co.— Agua Dulce Dehydration
plant and field, Nueces County, 4-6 Ross Peters
£2 of the Puentecitas Andres Fernandes .
Block Dehydration plant, Bethany field,
Harrison County, Samuel Monday
Galveston Bay plant and field, Chambers
County, Jacob Armstrong A-2
Willow Springs Dehydration plant and field,
Gregg County, Isaac Skillern
Warren Petroleum Co. — Azalea plant,
Midland County, 2-B38-TWP 3S
Breckenridge plant, Stephens County,
22 Lunatic Asylum Lands
Como plant, Hopkins County,
Nacogdoches U. A-703
Encinal plant, San Patricio County, 18 G.
H. Paul Sub. Coleman Fulton
Fannett plant, Jefferson County,
W. H. Smith A-198
Fashing plant, Atascosa County, B-144-J
Wilkenson
Gladewater plant, Gregg County, David
Ferguson
Glass plant, Martin County, 10-38-ln T&P RR
GM&A plant, Wise County, P. Nicholas A-654 .
McLean plant, Wheeler County, 33-24
Monahans plant, Ward County, 4-F
Moores Orchard plant, Fort Bend County,
German Immigration No. 8
North Port Nueces plant. Orange County,
John Stevenson A-169
Sand Hills plant, Crane County, 21-PSL B-21
Shackelford plant, Shackelford County,
522 TE4L
Soear olant. Greee Countv. Marv Van Winkle .
10.0
3.0
6.0
47.5
20.0
25.0
35.0
35.0
75.0
30.0
75.0
30.0
30.0
NR
NR
20.0
19.0
75.0
40.0
15.0
55.0
35.0
25.0
2.5
28.0
4.5
35.0
25.0
40.0
25.0
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
75.0
11.0
75.0
7.0
15.0
3.0
13.0
NR
5.4
38.1
24.1
12.5
16.1
6.0
18.3
1.3
9.5
0.7
76.0
2.0
15.0
4.0
8.0
5.7
6.1
13.9
17.1
60.6
12.7
0.3
142.6
9.8
35.4
16.5
4.0
43.3
7.5
2.1
Process
method
2
3
3
2
2
3
2
2
7
2
7
2
2
1
2
7
2
1
2
2
2
4
6&7
3
2
647
5
5
5
5
3
3
1
2
' 2
1
7
3
1
6
7
?
7
1
3
4
/ — Production — 1,000 cat/day (Average based on the past 12 months) — <
Normal Raw Debut
orunsplit IP-fas NGL nat
Ethane Prop. Isohot butane mix mil faso. Other
48.6
11.0
10.0 15.0
21.1
104.4
73.5
7.3 33.0
9.3
194.0
30.0
25.0 20.0
10.0
2.0 15.0 . ... 8.0
'...'. '.'". ''.'.'.'. '.'.'.'. '.'.'.'. 1410
23.8
39.9
56.7 29.6 25.6
14.7 10.7 9.4
27.4 30.0 26.8
15.5 36.7 3.4 11.8
0.8
127.2
10.9
27.9 . ... 14.5
10.2
5.2
0.8
18.0
0.6
29.3
36.4
0.1 28.6
11.0
4.0
12.7 25.1
25.6 64.2 102.2
U
.... 119.0 19.5 35.7 .... 287.8
48.7
99.5
27.9
. 4.1
102.8
.. . 27.3
13.1
•36.0
20.0
3.0
40.0
15.5
11.6 '.'.'.'.
•12.8
13.7
4&2 " "
'.'.'.'. '12.8
-111-
-------
Company, plant, location
Waddell plant, Waddell-Sand Hills fields,
Crane County, 25-B 25
Worsham plant, Ward County, 56-34 H&TC RR
Total
UTAH
Chevron USA Inc.— Red Wash plant and field,
Uinta County
El Paso Natural Gas Co.— Aneth plant and
field, San Juan County, nw4-6-41s-24e
Gary Operating Co.— Altonah plant and field,
Duchesne County, 5-2s-3w
Bluebell plant and field, Duchesne
County, 23-lsl2w
Koch Oil Co.— Cedar Rim plant and field,
Ducnesne County, 21-3s-6w
Quasar Energy Inc. — Pineview plant and field,
Summit County, 3-2n-7e
Shell Oil Co.— Altamont plant, Altamont and
Bluebell fields, Duchesne County, 34-ls-4w
Union Oil Co. of California — "Lisbon plant
and field, San Juan County, 22-30s-24e
Total
WEST VIRGINIA
Columbia Gas Transmission Corp.— Cobb plant,
Central W. Va. field, Kanawha County,
Big Sandy
Kenova plant, Southern W. Va. and
Eastern Kentucky field, Wayne
County, Ceredo district
Consolidated Gas Supply Corp. — Hastings
plant, Wetzel County
Pennzoil Co.— *13 small plants
Total
WYOMING
Amoco Production Co.— 'Bairoil plant, Lost
Soldier-Wertz field, Sweetwater County,
7-25n-90w
Beaver Creek plant and field,
Fremont County, 10-33n-96w
Beaver Creek Phosphoria plant, Beaver
Creek field, Fremont County, 10-33n-96w
Elk Basin plant and field, Park County,
29-58n-99w
Apexco Inc. — Recluse plant and field, Campbell
County, 15-56n-74w
Atlantic Richfield Co.— Gillette plant, Kitty &
Recluse fields, Campbell County, 18-50n-73w
Riverton Dome plant and field,
Fremont County, 36-Is4e
Champlin Petroleum Co. — Brady plant* and
field. Sweetwater County
Patrick Draw plant* and field, Sweetwater
County
Chevron USA Inc. — Birch Creek plant and field,
Sublette County
Cities Service Co. — Thunder Creek plant and
field, Campbell County, 2443n-69w
Colorado Interstate Gas Co.— Rawlins plant,
Carbon County, sw4-sw4-25-21n-86w
Colorado Oil Co. Inc. — Patrick Draw plant
and field, Sweetwater County
Continental Oil Co. — Sussex plant and field,
Johnson County, 243-41n-78w
CRA Inc.— Joe Creek plant, Campbell County
Lazy B plant, Campbell County
Girrther Gas Processing Plants— Rozet plant and
field, Campbell County, 18-50n-69w
Sprmgen plant, Spnngen Ranch field,
Campbell County, 28-51n-71w
Husky Oil Co. — Ralston plant, various fields,
Park County, sw%-3-56n-101w6
Kansas-Nebraska Natural Gas Co. Inc. — Casper
plant, main line field, Natrona County,
10-33n-65w
Flat Top plant, Flat Top and other fields,
Converse County, 20-33-68
< MMcfd ,
Gas
Gas through- Process
capacity put method
NR
NR
27,469.1
38.0
100.0
12.5
23.0
10.0
10.0
40.0
80.0
313.5
35.0
170.0
150.0
13.0
368.0
5.0
65.0
20.0
17.0
10.0
31.0
30.0
65.0
30.0
20.0
18.0
220.0
10.0
15.0
2.0
5.0
4.0
8.0
7.0
80.0
8.0
71.6 1
11.8 7
17,136.5
9.0 3
19.1 1
7.1 3
21.0 2
8.3 3
4.0 3
20.0 3
54.4 3
142.9
30.0 2
113.0 2
90.0 3
9.4 3-4-5
242.4
4,3 3
51.0 2
8.0 3
10.5 1
8.0 3
18.2 3
8.9 2
34.0 2
10.0 2
14.0 5
8.0 7
203.0 2
6.0 2
2.3 3
0.3 3
2.8 3
0.2 2
1.0 2
3.0 3
44.0 2
2.3 2
-112-
, Production — 1,000 gal/day (Average based on the past 12 months) — *
Normal Raw Debut
orunsplit LP-gas NGL nat
Ethane Prop. Isobut. butane mix mix gaso. Other
4,359.5 5,846.7
14.9
7.3
22.9
6.1
32.0
40.2
123.4
175.4 107.6
175.4 107.6
3.1
13.2
9.9
17.5
44.1
9.1
65.5
4.0
2.8
'.'" 4.4
0.9
3.4
0.3
19.0
3.4
317.6
18.0
803.8 2,368.0 689.5 13,509.0 2,845.7
2.8
74.2
5.4 6.1
38.7
5.3 10.9
6.0
20.2 41.4
27.5 14.8
58.4 6.0 130.4 58.5
101.0
223.0
18.3 34.3 34.5
25.0
18.3 34.3 349.0 34.5
13.0
16.0 16.7
8.8
14.6 21.3
18.6
23.0 18.9
2.0
17.1
1.7 2.5 6.2
1.5
5.7
36.4 18.7
2.0 4.0
3.2
2.4
4.5
0.9 1.4
11.2 8.7
... 3.2
2,566.7
U1.5
^.6
-------
APPENDIX B
LIST OF CONVERSION FACTORS
ENGLISH - SI METRIC SYSTEM
-113-
-------
LIST OF CONVERSION FACTORS
To Convert From
Cubic Feet
Short Ton, t
Barrel (petroleum, 42 gal)
Gallon
ppm SO 2
ppm H2S
pounds-per-square inch, psi
Multiply By
0. 0283
0.907
0.159
0.00378
0.350
0.186
6895.
To Get
Cubic Meter
Metric Ton, T
Cubic Meter
Cubic Meter
mg/m3 SO 2
mg/m3 H2S
Pas cal s, Pa
-114-
-------
APPENDIX C
MAJOR DOMESTIC GAS SUPPLY COMPANIES, 1975(8)
-115-
-------
Table 25 - MAJOR GAS SUPPLY COMPANIES
Annual Groat Change In Reserves, Annual Production and Cross Change-ProduceIon (GC/P) Ratios I/
12-31-70 Co 12-31-75
(All Volumes In Thousands Mcf at 14.73 Psla @ 60°F.)
Company
Arkansas Louisiana Gas Co.
Cities Service Gas Co.
Colorado Interstate Gas Co.
Columbia Gas Transmission Corp.
Consolidated Gas Supply Corp.
El Paso Natural Gat Co.
Florida Gas Transmission Co.
Kansas -Nebraska Natural Gas
Co . , Inc .
Michigan Wisconsin Pipe Line Co,
Item
Reserves
Annual Production
GC/P Ratio
Reserves
Annual Production
GC/P Ratio
Reserves
Annual Production
GC/P Ratio
Reserves
Annual Production
GC/P Ratio
Reserves
Annual Production
GC/P Ratio
Reserves
Annual Production
GC/P Ratio
Reserves
Annual Production
GC/P Ratio
Reserves
Annual Production
GC/P Ratio
Reserves
Annual Production
GC/P Ratio
Year End
1970
6,6)9.466
496,350
6,072,876
492,981
4,786,359
365,543
9,104,479
794,190
1,033,953
117,811
26,746,900
1,666,700
1,421,059
136,479
2,475,162
167,531
8,353,799
601,603
Annual Gross Change In Reserves l_l
Increase or ^Decrease)
1971
(218,950)
431,951
(0.50)
76,221
493,461
0.15
198,296
353,564
0.56
728,737
839,510
0.87
203,183
107,426
1.89
142,800
1,703,600
0.08
131,349
115,157
1.14
(39,264)
126,338
(0.31)
162,462
636,082
0.26
1972
161,335
407,515
0.40
111,489
487,177
0.23
21,304
361,472
0.06
(832,317)
878,895
(0.95)
57,802
101,248
0.57
(25,800)
1,688,800
(0.02)
(93,728
114,953
(0.82)
(52,127)
121,281
(0.43)
716,251
678,60-'.
1.06
1973
(181,276)
405,981
(0.44)
174,245
462,220
0.38
(78.418)
409.664
(0.19)
235.589
860,401
0.27
165,761
109,618
1.51
(200.711)
1,533.799
(0.13)
(11.782)
119.242
(0.10)
8,631
115,075
0.07
364,072
713,671
0.61
1974
26,951
331,051
0.08
(47,224)
401,820
0.12
237,397
384,318
0.62
(253,256)
792,489
0.32
140,487
109,209
1.29
(4,817,872)
1.314,633
3.66
(119,776)
102,166
(1.17)
(1,628)
123,347
0.01
(263,703)
711,21*
0.37
1975
79,204
315,888
0.25
317,544
358,041
0.89
546,012
383,713
1.42
(353,172)
616,105
(0.57)
44,146
103,775
0.43
130,274
1.2J3.366
0.11
66,005
75,833
0.87
41,630
119,509
0.35)
'688)311
(0.11)
Year End
1975
4,594,344
315,888
4,502,432
358,041
3,818,219
383,713
4,642,660
616,105
1.114.056
103,775
14,511,393
1,223.366
865,776
75,833
1,826,854
119.509
5,828,603
688,311
Total Change
12-31-70 to
12-31-75
(132,736)
1,892.386
(0.07)
632,275
2,202,719
0.29
924,591
1,892.731
0.49
(474,419)
3,987,400
(0.12)
611,379
531,276
1.15
(4,771,309)
7,464,198
(0.64)
(27,932)
527,351
(0.05)
(42,758)
605,550
(0.07)
902,690
3,427,886
0.26
-------
Table 25 - MAJOR GAS SUPPLY COMPANIES
Annual Gross Chang* In Reserves, Annual Production and Gross Change-Production (GC/P) Ratios I/
12-31-70 to 12-31-75
(All Volumea In Thousand* Mcf at 14.73 Psla & 60°F.)
Montana-Dakota Utllittaa Co.
Mountain Fual Supply Co.
Natural Gai Pipeline Co,
of Aoarica
Northern Natural Gat Co.
Northwest Pipeline Corp.
(First Font IS filed foe
year 1974)
Panhandle Eaatarn Pip* Lin* Co.
Sea Robin Pipeline Co.
South Texas Natural Gat
Gathering Co.
Southern Natural Ga« Co.
Tenneiaee Gai Pipeline Co.
(Civilian of Tenneco)
Reaervea
Annual Production
GC/P Ratio
Reserves
Annual Production
GC/P Ratio
Reserves
Annual Production
GC/P Ratio
Reaervea
Annual Production
GC/P Ratio
Reserves
Annual Production
GC/P Ratio
Reaervea
Annual Production
GC/P Ratio
Reaerves
Annual Production
GC/P Ratio
Reserves
Annual Production
GC/P Ratio
Reserves
Annual Production
GC/P Ratio
Reserves
Annual Production
GC/P Ratio
Year End
1970
916,449
63,016
1,465,935
93,287
10,575,947
988,384
13,748,646
899,734
6,542,927
553,378
948,109
4,774
88,109
67,870
5,979,871
593,684
18,188,079
1,380,693
Annual Gross Change in Reaervea 2l
Increase or (Decrease)
1971
29,343
58,264
0.50
58,298
95,129
0.61
264,395
961,834
0.27
778,918
907,108
0.86
(17,384)
586,469
(0.03)
(174,038)
77,431
(2.31)
(402,389)
73,308
(5.49)
54,845
574,727
0.10
741,131
1,346,791
0.55
1972
15,202
55,811
0.27
155,622
94,098
1.65
124,780
923,390
0.14
315,283
928,633
0.34
(9,657)
594,061
0.02
762,190
96,811
7.87
106.760
63,037
1.69
74,569
601,353
0.12
(838,072)
1,348.646
1973
93,954
55,838
1.68
83,789
99,578
0.84
161,613
879,868
(0.18)
(614,121)
949,810
(0.65)
175,816
592,761
0.30
120,873
206,206
0.59
36,743
60,286
0.61
(31,596)
507,789
(0.06)
385,003
1,327,130
0.29
1974
56,657
53,072
1.07
49,008
97,713
0.50
476,765
844,835
0.56
(99,633)
918,252
0.11
4,661,581
147,507
765,975
586,258
1.31
127
270,863
0.00
(43.527)
52.268
0.83
362,167
472,977
(0.77)
(1,206,793)
1I273I023
0.95
1975
(14,458)
51,444
(0.28)
85.065
-00,519
0.85
(139,277)
880,405
(0.16)
(393,398)
905,911
(0.43)
(17,275)
147,535
(0.12)
31J.971
540,160
0.59
35,641
290,976
0.12
(100,986)
43,858
(2.30)
82,922
442,492
0.19
(785,339)
l,21i; 104
(0.65)
Year End
1975
822,718
51,444
1,410,680
100,519
6,973,891
880,405
9,123,981
905,911
4,349,264
147,535
4,874,939
540,160
751,205
290,976
291,953
43,858
3,199,104
442,492
..HWB
Total Change
12-31-70 to
12-31-75
180,698
274,429
0.66
431,782
487,037
0.89
888,276
4,490,332
0.20
(12,951)
4,609,714
0.00
4,644,306
295,042
15.7
1,231,721
2,899,709
0.42
744,793
942,287
0.79
(403,399)
192,757
(1.38)
(181,427)
2,599,340
(0.07)
(1,704,070)
6I506I694
(0.26)
-------
Table 25 - MAJOR GAS SUPPLY COMPANIES
Annual Gross Change In Reserves, Annual Production and Gross Change-ProductIon (GC/P) Ratios I/
12-31-70 to 12-31-75
(All Volumes in Thousands Mcf at 14.73 Psla
-------
APPENDIX D
ACID GAS REMOVAL PROCESSES USED IN THE
NATURAL GAS PROCESSING INDUSTRY
-119-
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AMINE PROCESSES
Monoethanolamine (MEA) —
This first amine solution is composed of 10-20 wt % MEA in water. This
alkaline compound is the strongest base of the three common amines. It reacts
most rapidly with the acid gases and removes both H2S and C02. MEA has the lowest
molecular weight of the common amines, so it has a greater carrying capacity for
acid gases on a unit weight or volume basis. This means that less solution
circulation is necessary to remove a given amount of acid gases. MEA is
chemically stable which minimizes solution degradation. However, it reacts
irreversibly with COS and CS2 which results in solution loss and buildup of
reaction products in the MEA solution. Also, it has a higher vapor pressure than
the other amines. This can result in significant solution losses through
vaporization although this handicap can usually be overcome by a simple water
wash of the sweetened gas stream. This is the most commonly used acid-gas
removal process.
The advantages of MEA are high reactivity, low solvent cost, good chemical
stability, ease of reclamation, high selectivity for acid gases, and lower plant
investment. The disadvantages are irreversible degradation by COS, CS2 and 02 in
the gas, high vaporization losses, ineffectiveness in removing mercaptans,
nonselectivity for H2S in the presence of C02, and high utility costs. The
general guidelines for use are for gases containing up to 1.4 g/m3 (4 grains
H2S/100 scf) to 15 mol % total acid gas, with acid gas partial pressures up to .69
MPa (100 psia).
Diethanolamine (DEA) —
This amine solution is comprised of 20-30 wt % DEA in water. It is similar
to MEA but reacts very slowly with COS and CS2 making it more useful where these
compounds are prevalent. It is also less volatile than MEA so there are lower
losses of amine solution due to vaporization. The disadvantages of DEA are lower
reactivity, higher solvent circulation rates, and higher solvent cost.
Triethanolamine (TEA) —
TEA is less reactive with acid gases and has less acid gas carrying capacity
per volume of solution than either MEA or DEA. It is unable to reduce H2S content
to general pipeline specifications but has the advantage of high selectivity for
H2S.
Methyldiethanolamine —
This amine is not commercially competitive with MEA and DEA, but it may have
some value in special applications.
Glycol-Amine —
The glycol-amine process utilizes MEA (or occasionally DEA) in combination
with a glycol to simultaneously sweeten and dehydrate the gas stream. Typical
solutions consist of 10-30% MEA, 45-85% glycol, and 5-25% water by weight. The
combined process costs less than separate MEA and glycol units. However, it has
the disadvantages of high MEA vaporization losses due to high regeneration
-120-
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temperature, intricate corrosion problems, and reclaiming must be by vacuum
distillation. Its best application is for gas streams not requiring low water
dewpoint control.
Fluor Econamine or Diglycolamine (DGA) —
The treating agent used in this process patented by Fluor is an aqueous
solution of the primary alkanolamine HO-C2Hif-HN2> tradename Diglycolamine. It
is also known as 2(2-amino-ethoxy) ethanol. There are several advantages of this
process over MEA. It can be used in concentrations of 50-80% which results in
approximately twice as much acid gas pickup per gallon as an MEA solution in the
15-20% range. The freezing point of DGA is 233°K (-40°F), thus it is good for
cold weather areas. It removes COS and mercaptans as well as CO2 and HjS and has
lower vaporization losses than MEA. It is in use at about 15 plants in the U.S.
Sulfinol —
The Sulfinol process, patented by Shell, is based on the use of an organic
solvent, sulfolane (tetrahydrothiophene dioxide) mixed with an alkanolamine
(di-isopropyl-amine or DIPA), and water. This is a unique process that involves
simultaneous physical and chemical absorption through a physical solvent and a
chemically reactive agent. A typical solvent is composed of 40-50% sulfolane,
40-45% DIPA, and 10-20% water. This process is equivalent to MEA at lower
partial pressures but it is superior at higher partial pressures with an
extremely high affinity for the sour components. Sulfinol can also absorb more
hydrocarbons than its MEA equivalent as well as removing COS, CSz, thiols, and
mercaptans. Its best application is for gas streams with relatively high ratios
of HjS (HaS to CO2 ratios 1:1 or greater) and when acid-gas partial pressures
exceed 0.75 MPA (110 psia). Sulfinol is used primarily on so-called "dry gases,"
i.e., when there is very little Cs+ or even much Cs and CH present. DBA is used
when treating the hydrocarbon rich gases (high content of Cg+). It is the second
most widely used acid gas removal process. This process is in use at about 40
plants in the U.S.
SNPA-DEA —
This process is similar to the conventional amine process but utilizes a
higher weight percent of DEA (25-30%) than the conventional DBA process (20-25%).
It is used for sweetening raw gas streams containing a total of about 10% or more
of acid gases at operating pressures of about 3.4 MPa (500 psia) or higher.
Unlike MEA units, COS is removed without degradation of the DEA solutions. The
main differences with a conventional DEA process, aside from the higher DEA
concentrations, are the optimization of operating conditions to achieve higher
than conventional loading of the rich DEA in terms of cubic meters of gas per
cubic meter of solution (SCF per gallon). A slipstream of a lean solution is
conditioned to maintain low level of solids, corrosion products, and hydro-
carbons .
Adip —
The last amine process used for sweetening is the Adip process licensed by
Shell. The process is based on an absorption-regeneration cycle using a
circulating aqueous solution of an alkanolamine (DIPA) which reacts with acidic
gases. The Adip process has a low steam consumption rate which is economically
-121-
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beneficial. It is very selective for H2S in the presence of C02 and substantial
H2S removal is realized to less than 26 mg/m3 (10 ppm) with partial removal of
COS, C02 and mercaptans.
CARBONATE PROCESSES
A flow diagram of a typical carbonate process is presented in Figure D-l.
The basic concept is that the C02 reacts with potassium carbonate to form
bi-carbonate which decomposes at elevated, temperatures. A similar reaction
takes place with H2S. Various additives, frequently arsenates, accelerate H2S
removal by forming thioarsenates which decompose into arsenates and elemental
sulfur. Some additives assist the rate of gas absorption by accelerating the
hydration of C02 gas. C02 has a high affinity for potassium carbonate with H2S
having a lesser affinity. The reactions are as follows:
K2C03 + H20
K2C03 + H2S ^KHS + KHC03
High temperatures are employed to keep the salt in solution. The process won't
work if there is only H2S present and no C02 since potassium bisulfide is
difficult to regenerate in the absence of C02.
The advantage of the carbonate process is that COS and CS2 can be removed
without significant solution degradation. The disadvantages are the highly
corrosive nature of the absorbents and absorbent-acid compounds and the
difficulty in removing H2S to pipeline specifications. An amine process clean-up
is frequently needed.
The following paragraphs describe seven processes that are used or have been
used for acid gas sweetening in this manner.
Hot Potassium Carbonate (Uncatalyzed) —
In this form the carbonate process, the absorber and regenerator both
operate at elevated temperatures in the neighborhood of 380-390°K (230-240°F).
The higher temperatures increase the solubility of the potassium bicarbonate in
solution, permitting the use of the concentrated K2C03 solution, which increases
its carrying capacity for acid gases. Since this process runs at a much higher
temperature than an amine process, savings are realized in heat exchange and
heating equipment. This process is very effective where 5 to 8 mol % acid gases
are present in large quantities at contactor pressures of 2.1 MPa (300 psia).
The solution is typically 15 to 30 wt % potassium carbonate in water.
Catacarb Process —
The Catacarb process is a variation of the hot potassium carbonate process
in which amine borates are used to increase the activity of the hot potassium
carbonate solution. This solution is not highly ionized and has few hydroxyl
ions which can react directly with COz- The Catacarb process is based on the
-122-
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SWEETENED GAS
ABSORBER
fTS
STRIPPER
ACID GAS
CO
I
SOUR GAS
il
LEAN
PUMP
HEAT
EXCHANGER
SOLUTION
RICH SOLUTION
STEAM
REBOILER
Figure D-l: Flow diagram of conventional hot carbonate process.(9)
-------
fact that C02 must first react with water or a hydrate to form carbonic acid.
Next, the carbonic acid reacts with a carbonate ion to form two bicarbonate ions.
The process also frequently contains corrosion inhibitors. The solutions
frequently become contaminated by potassium formate and potassium sulfate.
These contaminants have a negative effect on solution activity. They can be
removed or maintained at a satisfactory level in the solution, but to do so is
expensive and results in potassium carbonate losses.
Benfield Process —
The Benfield process is another version of the hot potassium carbonate
process which uses diethanolamine as the activation agent to improve the treating
capabilities of the solution. The flow and operating conditions are essentially
the same as those for the hot potassium carbonate process. It can be used for
gases containing up to 75% COz and HaS.
DBA Carbonate —
This process is a combination of the DEA and hot potassium carbonate
processes. Gas entering the absorber first contacts an activated potassium
carbonate solution. It then flows to the upper section where it is treated with
the DEA solution. This enables a more complete removal of the acid gases. The
solutions are segregated in both the absorber and regenerator. The spent DEA
from the absorber is preheated by the carbonate solution before it is introduced
to the lower section of the regenerator and both sections are reboiled before
entering the regenerator.
The DEA-Carbonate process requires a high percentage of C02 to operate
effectively. An advantage is that it can save as much as 10% in operation costs
over the DEA process alone in certain applications.
Giammarco-Vetrocoke (GV) Process —
The GV process is used for the continuous removal of HzS by scrubbing the
sour gas with alkali arsenates and arsenite solutions, thus producing sulfur as a
direct precipitate. Sodium carbonate is the alkali usually applied since it is
relatively inexpensive. C02 is also removed since the catalyst increases the
rate of absorption of COz in alkali carbonate solutions.
There are many reasons for choosing this process:
o Treating costs are about one-half the costs of most other processes.
o Low capital costs.
o Low corrosivity.
o No solution degradation.
o The treated gas has a low HzS content.
-124
-------
o The process can operate at pressures as low as atmospheric and
temperatures up to 420°K ( 300° F) .
However, the use of this process in the U.S. is extremely limited due to the high
toxicity of the arsenic used in the absorption solution.
Seaboard Process —
This process was developed by the Koppers Co. in 1920 and is no longer of
major industrial significance. It is a regenerative process without recovery of
the product removed. An aqueous solution of 3-3.5% sodium carbonate is used for
absorbing HzS in a bubble tray or packed tower. The foul solution is pumped to a
second tower where it is regenerated by aeration to release the absorber HaS to
the atmosphere.
Vacuum Carbonate Process —
The vacuum carbonate process is a modification of the Seaboard process which
also uses 3-3.5% sodium carbonate as an absorbent. It was especially adapted to
recovery of HaS from manufactured gases and is used for treating coke-oven gases.
PHYSICAL ABSORPTION PROCESSES
These methods use organic solvents and accomplish the acid-gas removal
mainly by physical absorption, rather than chemical reaction, which is directly
proportional to the acid-gas partial pressure in the sour-gas stream. A physical
process should be considered under the following conditions:
o The partial pressure of the acid gas in the feed is 0.34 MPa (50 psig)
or higher.
o The concentration of heavy hydrocarbons in the feed gas is low.
o Only bulk removal of the acid gas is desired.
o The solvent is able to do satisfactory dehydration as well as acid gas
removal .
o Selective H2S removal is desired.
If heavy hydrocarbons are present in any great quantity, problems will arise with
the physical processes. All of the physical solvents used have a relatively high
solubility for the heavy hydrocarbons. This is especially true of the aromatic
and unsaturated hydrocarbons. If these are present and care is not taken in the
regeneration cycle, then the acid gases will be rendered unsuitable for feed gas
to a sulfur recovery unit. Another disadvantage is the high solvent costs.
-125-
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Water Absorption —
The water absorption process is simply the washing of the acid gas stream
with water which acts as a solvent for the acid gases. A flow diagram of this
process is presented in Figure D-2. It is a good process to use as a companion to
an amine process. A water wash followed by an amine process clean-up requires
12-14% lower investment. Additionally, there is an approximate 50% savings in
operational costs of an equivalent amine unit designed to do the total job.
Fluor Solvent Process —
The Fluor Solvent Process employs an anhydrous organic compound to remove
C02 and HaS from natural gas streams. The compound can be one of four: propylene
carbonate, glycerol triacetate, butoxyl diethylene glycol acetate, or methoxy-
triethylene glycol acetate. Propylene carbonate is the most common one in use
today. The use of the high capacity solvent, which absorbs acid gas by
dissolution, permits solvent regeneration simply by pressure letdown of the rich
solvent, usually without the application of heat. Other advantages are low
solvent loss due to the low vapor pressure of propylene carbonate and a virtually
zero solvent breakdown rate. The process is favored when there are high
concentrations of COa and HaS and when their combined partial pressure is 0.52
MPa (75 psia) or higher. In addition, the use of this process is favored for raw
gas with low heavy hydrocarbon content.
A flow diagram of this process is presented in Figure D-3.
Selexol Process —
The Selexol Process is used for gas purification removal of HaS, C0a> COS,
mercaptans, etc., from gas streams. The solvent, dimethylether or polyethylene
glycol, is trade named Selexol by Allied Chemical Corp. It has a strong
preference for sulfur-based compounds, while retaining the capability to absorb
bulk quantities of all impurities economically. It is also capable of
simultaneously dehydrating gas to pipe line specfications. Its advantages are
lower initial plant cost and lower operating costs than MEA or potassium
carbonate, more selectivity for H2S than MEA, and better ability to remove for
HaS than hot potassium carbonate. It is primarily used on high C02 content
streams (18-43 mol %) with low HaS (<1 ;nol %). This process is not effective for
low acid-gas partial pressures.
A flow diagram of this process is presented in Figure D-4.
Rectisol Process —
This process which uses methanol as a solvent, was developed by the German
Lurgi Co. Because of the vapor pressure of methanol, the process is normally
applied at extremely low temperatures, i.e., 200-240°K (-30 to -100°F). It is
used primarily for synthesis gas, but has been applied for purification of
natural gas for LNG production. The process is best suited where there are
limited quantities of ethane and heavier components. Ammonia evaporation and
cold, purified gas are used to cool the feed gas to the desired temperature.
A flow diagram is presented in Figure D-5
-126-
-------
CONTACTOR
i
t—•
NJ
I
SOUR GAS-
PARTIALLY SWEETENED GAS
TO AMINE UNIT
c w
ACID GAS AND HYDROCARBONS
TO AMINE UNIT
ACID GAS
INTERMEDIATE-
PRESSURE FLASH
TANK
LOW-PRESSURE
FLASH TANK
PUMP
LEAN SOLUTION
POWER RECOVERYTURBINE
PUMP
PUMP
Figure D-2: Flow diagram of a typical water wash absorption unit.(9)
-------
ABSORBER
TREATED GAS
/^
RECYCLE GAS
\ LEAN SOLVENT r
J
i
>—•
00
FEED GAS
START-
iAS 1
^—L
I RICh
ISDLVE
RICH
SOLVENT
u
HYDRAULIC TURBINE (
FLASH DRUMS
EXPANSION
/-STURBINE
ACID GAS
A
PUMP
Figure D-3: Flow diagram of Fluor solvent process.(13)
-------
ABSORBER
RECYCLE
HIGH INTERMEDIATE LOW
PRESSURE PRESSURE PRESSURE STRIPPER
FLASH FLASH FLASH
VENT
ho
VO
START
SOUR
FEED
GAS
AIR OR
INERT
GAS
Figure D-4: Flow diagram of Selexol process.(13)
-------
DESULFURIZATION REGENERATION REGENERATION C02 REMOVAL
" (C02)
SHIFT CONVERSION
IH2S + COS)
o
I
TO
METH/WATER
SEPARATION
Figure D-5: Flow diagram of the Rectisol process.(13)
-------
Purisol Process —
The Purisol Process, also developed by Lurgi , uses an absorbing solution of
N-methyl-pyrrolidone (NMP) for removing acid gases from synthetic and natural
gas streams. The process is highly selective for H2S. Other advantages include
low temperature operation (ambient), C02 removal by pressure letdown, excellent
solvent stability, and nontoxic, fumeless operation.
A flow diagram is presented in Figure D-6.
Estasolven Process —
This is a process that utilizes the solvent tri-n-butyl phosphate (TBP) for
either sweetening only or sweetening combined with liquid hydrocarbon recovery.
In addition to removing H2S, TBP will remove mercaptans and other organic sulfur
compounds .
Other Solvents —
Various other physical solvents can be used in natural gas sweetening.
Possible solvents include: methyl cyanoacetate , glutaronitrile , trimethylene
cyanohydrin, dimethyl formamide, and DEC dimethyl ether. Any of these may be
applicable depending upon plant design and the nature of the gas to be sweetened.
SOLID BED SWEETENING PROCESSES
Solid bed sweetening processes are all based on the adsorption of the acid
gases on the surface of the solid sweetening agent or on the reaction with some
component on that surface. These processes are best applied to gases containing
low to medium concentrations of H2S or mercaptans, but are not widely used. They
do not usually remove significant quantities of CO 2- An advantage is that
pressure has little effect on the adsorptive capacity of the sweetening agent.
Iron Sponge —
The iron sponge process, also known as the iron oxide or dry box process,
was introduced in England in the mid-1 9th century. The process involves contact
of the sour gas with wood chips impregnated with ferric oxide in hydrated form.
Ferric sulfide is formed which oxidizes to sulfur and ferric oxide when exposed
to air. The ferric oxide can then react with additional HaS. The process is as
follows:
2Fe203 + 6H2S +2Fe2S3 + 6H20
2Fe2S3 + 302 -»-2Fe203 + 6S
This is repeated several times until the sulfur covers most of the surface of the
oxide particles.
The reasons for the choice of this process are:
-131-
-------
ABSORBER
STRIPPER
SOLVENT DRYER
TREATED GAS
HoO
U)
N3
I
START
C W
Figure D-6: Flow diagram of the Purisol process.(13)
-------
o Efficiently removes trace amounts of H2S in the gas.
o Batch process has low capital and operating cost.
o HjS removal is independent of gas pressure.
o Easy installation.
The disadvantage is that the removed sulfur is wasted - it cannot be recovered
economically. The used iron oxide becomes a solid waste problem. It is also
limited to gas streams with low EzS content <0.35 kgHaS/m3 (1000 grains/100 scf)
due to the economics of bed replacement.
A flow diagram of the iron sponge process is presented in Figure D-7.
Molecular Sieve —
The molecular sieve process is used in dehydrate and removes C02, HzS, and
sulfur compounds from natural gas. Crystalline sodium-calcium-alumino silicates
are used. This material is porous, with the pore openings all the same size, and
is formed by driving off the water of crystallization that is present during the
material synthesis process. The large surface area and highly localized polar
charges are the reasons for the very strong adsorption of polar or polarizable
compounds on molecular sieves. This results in much higher adsorptive capacities
for these materials by the sieves than by other adsorbents particularly in the
lower concentration ranges. However, there is a problem with COS formulation
which irreversible contaminates the molecular sieve.
A flow diagram of this process is presented in Figure D-8.
EFCO Process —
The EFCO Process is a molecular sieve process developed by the Engineers and
Fabricators Company. Sour gas enters the unit through a separator and filter
which removes all liquids and entrained solids. The gas then flows downward
through two molecular sieve beds and leaves the plant as sweetened gas. A
portion of the sweet gas stream is removed and flows downward through a third bed
which has been regenerated but it is still hot. The sweetened gas removes heat
from the bed and flows through a gas-to-gas exchanger before going through the
regeneration heater. Following heating, this gas flows upward through the bed on
regeneration cycle, heating it and removing the adsorbed H2$ and sulfur
compounds. The gas from the bed then flows through heat exchange with the
sweetened gas to the tower and then through a cooler. The EFCO process rejects
from the gas stream only the acid gas constituents and burns only the amount of
gas required to provide regeneration heat.
STRETFORD PROCESS
One final sweetening process is the Stretford Process. This process is
described separately because it does not really fall into any of the other four
categories. The gas is washed with an aqueous solution containing sodium
carbonate, sodium vanadate, and anthraquinone disulfonic acid (ADA). The
solution reaches equilibrium with respect to COz in the gas and only relatively
small amounts of COa are removed by the process. Thus, the process represents an
-133-
-------
SOUR GAS
IN
WATER
u>
-p-
I
REGENERATION
REGENERATION
STREAM
GAS OUT
Figure D-7: Flow diagram of iron sponge process.(13)
-------
5.6x!06 m
U)
Ul
I
START
ABSORBING
fri)
.ow
HYUROI
RCCOVI
1
I
TEMPERATURE
CARBON ,_n_
"RY j _T_rvA
Y v-X
A f
I fX^L ^1
"
(
— »»
)
H20
^?±fS""y DESORBING ,
*• ... .
PIPELINE
DEHYDRATION
jfc, SWEETENING
START*"!
5. fix H)6 m3/day f A
(?(i()iirn4Cfft)
fl" C02
10- inn qr 1135
110 N lljO/lO^n3 '
(7»h/mnscf(J)
Y
I „
r-^-i ^ ,-C>i£^ i
| ?. 5xl()6 mi/day 1^-^ ^| T
JL (9'mmscfd) JL 1 — I i
V
-
r— t?
-TL
V /
q . S-^
AMINE
SCRUBBER
T
GLYCOL
SCRUBBER
"~1 2.8xl06 n\3/day
1
- V H/0 ^ -^
_jsl^L_ .^J 2.8xl06 m3/d«y
TXSJ ^ (Jfittimscfd)
fir co
«0.2b qr M2S '
< (lOOnnscfd)
Mil CO?
110 kg M20/106!
(71b/iiix',cfd)
5.6x11)6 mVdsy
(?UOmi\scfd)
3S CO
<0.?5 gr H?S
^
ABSORBING
COOLING
DESORBING
Figure D-8: Flow diagram of molecular sieve process.(13)
-------
economic route for sweetening sour, CO2-containing gas with much less shrinkage
than that associated with amine based processes.
The sour gas is cocurrently washed with regenerated liquor. The H2S
dissolves in the alkaline solution and is removed to any desired level. The H2S
formed reacts with the 5-valent state vanadium and is oxidized to elemental
sulfur. The liquor is regenerated by air blowing, and the reduced vanadium is
restored to the 5-valent state through a mechanism involving oxygen transfer.
The sulfur is removed by froth flotation and the scum produced can be processed
several ways depending on the desired end product, total sulfur produced and
utilities cost. The reactions upon which the process is based are essentially
insensitive to pressure.
The process can be written as follows:
Step 1: H2S absorption
H2S + Na2C02 + 1/2 62 (air) ^ NaHS + NaHC03
Step 2: Sulfur precipitation
2NaV03 + NaHS + NaHC03 -*• S 4- + Na2V2Os + Na2COa + H20
Step 3: Sodium vanadate regeneration
Na2V205 + ADA (oxidized) •* 2NaV
-------
CONTACTOR
SWEET GAS
SKIM TANK
FILTRATION
u FILTRATION AND
AUTOCLAVE
CENTRIFUGATION
OXIDIZER
CENTRIFUGATION
AND HEATING
SULFUR CAKE
*
MOLTEN
SULFUR
SULFUR CAKE
MOLTEN SULFUR
Figure D-9: Flow diagram of Stretford process,
-------
Sodium Phenol ate Process —
This is a process that involves a concentrated solution of sodiun phenolate
in a heat conversion-heat regenerative flow process. It has a high capacity for
H2$ but, unfortunately, a low efficiency for HzS removal. It can remove only
about 90% of the HaS in sour gas which is usually not enough to meet pipeline
specifications .
Phenoxide Process —
This process is not used anymore due to operating difficulties. It used a
solution of sodium phenoxide as an absorbent.
Alkacid Process —
This was a process used in Germany prior to World War II and is not pre-
sently used in the U.S.
-138-
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/2-79-077
2.
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Multimedia Assessment of the Natural Gas
Processing Industry
5. REPORT DATE
April 1979
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
Willard A. Wade
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
10. PROGRAM ELEMENT NO.
TRC - The Research Corporation of New England
125 Silas Deane Highway
Wethersfield, Connecticut 06109
1AB604
11. CONTRACT/GRANT NO.
68-02-2615, W.A. 2
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Task Final: 9/77 - 11/78
14. SPONSORING AGENCY CODE
EPA/600/13
15. SUPPLEMENTARY NOTES
officer I. A. Jefcoat is no longer with IERL-RTP; for
details contact Bruce A. Tichenor, MD-62, 919/541-2547.
16 ABSTRACTThe report gives results of an assessment of the air and water pollution
potential of the natural gas processing industry, based on a review of publicly avail-
able literature. It reviews natural gas processing operations and discusses the pot-
ential air and water emissions from the industry. It describes acid gas removal,
dehydration, purification, and stripping unit operations, primarily to indicate their
potential for air and water pollution. It presents historical production data and dis-
cusses future trends in applications of new techniques. It reviews Federal and State
regulations affecting the industry and discusses their limitations and reporting re-
quirements. It discusses the impact of the myriad rules, regulations, and reporting
requirements on obtaining quantifiable data on the industry. It estimates air emis-
sions for each criteria pollutant for the industry nationwide, as well as for Texas
and Louisiana, the two largest producing states. It shows the significance of emis-
sions from natural gas processing operations relative to other industrial sectors.
It compares these estimates with overall mass balance calculations based on pub-
lished production and distribution data. It discusses, generally, the water pollution
potential of the industry and describes shortcomings in available data.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Pollution
Natural Gas
Industrial Processes
Assessments
Dehydration
Purification
Stripping
Regulations
Pollution Control
Stationary Sources
Natural Gas Processing
Environmental Assess-
ment
Acid Gas
Criteria Pollutants
13B
21D
13H
14B
07D,07A
14G
05D
3. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
147
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
-139-
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