United States
Environmental Protection
Agency
Office of
Research and
Industrial Environmental Research
Laboratory
Cincinnati, Ohio 45268
EPA-600.7-77-080
July 1977
OFFSHORE OIL AND GAS
EXTRACTION:
An Environmental Review
Interagency
Energy-Environment
Research and Development
Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, US. 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 INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA’s mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/7-77-080
July 1977
OFFSHORE OIL AND GAS EXTRACTION
AN ENVIRONMENTAL REVIEW
by
»
N. A. Frazier
D. L. Maase
R. Clark
BATTELLE
Columbus Laboratories
Columbus, Ohio 43201
Contract No. 68-02-1323
Project Officer
Eugene Harris
Resource Extraction and Handling Division
Industrial Environmental Research Laboratory
Cincinnati, Ohio 45268
INDUSTRIAL ENVIRONMENTAL RESEARCH LABORATORY
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
CINCINNATI, OHIO 45268
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DISCLAIMER
This report has been reviewed by the Industrial Environmental Research
Laboratory, U.S. Environmental Protection Agency, and approved for publi—
cation. Approval does not signify that the contents necessarily reflect
the views and policies of the U.S. Environmental Protection Agency, nor
does mention of trade names or commercial products constitute endorsement
or recommendation for use.
11
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FOREWORD
When energy and material resources are extracted, processed, converted,
and used, the related pollutional impacts on our environment and even on
our health often require that new and increasingly more efficient pollution
control methods be used. The Industrial Environmental Research Laboratory—
Cincinnati (IERL—Ci) assists in developing and demonstrating new and
improved methodologies that will meet these needs both efficiently and
economically.
This report reviewed the emission sources and emissions from United
States offshore oil and gas exploration, drilling, and processing. The
intent of the study was to rank the technological problems associated with
the control of pollution from the industry. The findings should be of
interest to regulatory agencies, the oil and gas industry, and organiza-
tions interested in energy and the environment. The Extraction Technology
Branch may be contacted for additional information on this important topic.
David G. Stephan
Director
Industrial Environmental Research Laboratory
Cincinnati
iii
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ABSTRACT
A small study was conducted to rank technological problems of controlling
emissions to the environment from offshore oil and gas exploration, drilling,
and production operations. A firm basis ranking for these problems could not
be developed during the study. Conclusions pertain to topics of environmental
studies that are believed to he necessary for the identifying and ranking
of control technology problems.
iv
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FOREWORD
ABSTRACT
FIGURES.
TABLES
Introduction.
Summary and Conclusions
Geographical Distribution of Oil Industry Activities
in U.S. Offshore Areas
Geophysical Surveying
Exploratory and Development Drilling
Production
IV. Emission Sources: Normal Offshore Operations
Geophysical Surveying
Exploratory and Development Drilling
Production
V. Emissions Sources: Accidents During Drilling
and Production
Emissions to the Air Environment .
Emissions to the Water Environment .
VI. Pollution Control
Geophysical Surveying
Exploratory and Development Drilling
Production
REFERENCES
APPENDIX. OFFSHORE REGULATIONS AND DISCHARGE LIMITATIONS
CONTENTS
I.
II.
III.
111
iv
vi
vii
1
2
4
4
7
12
16
16
18
27
33
33
35
39
39
39
43
48
51
v
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FIGURES
Number Page
1 U.S. Offshore Regions 5
vi
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TABLE S
Number Page
1 Seismic and Gravity Offshore Geophysical Exploration
Activity, by State, 1960 to 1964. . 6
2 U.S. Offshore Geophysical Exploration for Petroleum
1972—1974 8
3 Types and Methods of U.S. Offshore Petroleum
Surveys: 1974 . . . . 9
4 Estimate of Total U.S. Offshore Drilling and
Production 1960—1964 10
5 Total U.S. Offshore Drilling Activity 1973—1974 . . 11
6 U.S. Offshore Production of Crude Oil and Lease
Condensate 1969—1975 13
7 Comparison of U.S. Total and Offshore Production of
Crude and Lease Condensate 1969—1975 14
8 Emission Factors for Motorships 17
9 Estimate of Quantity of Emissions From Burning of
Well Testing Gas 19
10 Emission Factors for Diesel Powered Industrial
Equipment 19
11 Evaporative Emission Factors for Fixed Roof Storage Tanks 21
12 Gelled Seawater Mud——Typical Composition 23
13 Mud Additives 24
14 Mud Components Used in Seawater——Lignosulfonate Systems
to 15,000 Feet 26
15 Location and Estimated Size of Gulf of Mexico Offshore
Produced Water Discharges . . . . 28
vii
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TABLES
Number Page
16 Produced Formation Water Composition 30
17 Comparison of Seawater and Oilfield Brine 30
18 Range of Constituents in Offshore Produced Formation Water 31
19 Chemical Content of Representative Offshore Brines 32
20 Estimate of Quantities of Emissions From Blowouts
From Crude Oil 34
21 Estimate of Quantities of Emission From Blowout From
Natural Gas
22 Probabilities of Oil Spills Ashore From Hypothetical
Spill Sites in the Atlantic Ocean 38
23 A Comparison of Proposed Toxic Effluent Standards and
Surveyed Production Platforms for Toxicants in
Produced Formation Water
24 BPCTA E f1uent Limitations: Near— and Far—Offshore 53
25 Proposed BATEA Effluent Limitations 54
viii
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SECTION I
INTRODUCTION
The objective of this small study was to rank the technological problems
of controlling emissions associated with offshore oil and gas exploration,
drilling, and production. The information base for the study included
literature and reports on emission sources, emissions, control technology,
pollution prevention and environmental practices, geographical distribution
of offshore activities, impact assessments of offshore lease offerings,
environmental problems, the EPA’s interim and proposed effluent guidelines
and supporting development documents, state regulations, and the USGS’s
Outer Continental Shelf orders.
1
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SECTION II
SUNMARY AND CONCLUSIONS
Currently applicable Federal regulations, within the scope of this
study, are in the form of the U.S. Geological Survey’s Outer Continental
Shelf Orders and the EPA ’s interim effluent limitations for Best Practical
Control Technology Currently Available (BPTCA) for existing offshore sources.
Effluent limitations for Best Available Technology Economically Achievable
(BATEA), pretreatment standards, and new sources have also been proposed
by the EPA. Applicability of various States’ air and water quality criteria
or regulations to offshore operations was not readily discernible in the
sample of information reviewed.
Existing Federal regulations set limitations on oil that can be dis-
charged to the offshore water environment, specify measures for reducing
the probability of accidental oil spills occurring during drilling and
production, and require capability for controlling spiiis in the event of
an accident. The technology reflected in the EPA’s proposed BATEA effluent
limitations is that of no near—offshore discharge of pollutants in pro-
duced water and a 30—day average not to exceed 30 mg/i of oil in produced
water and deck drainage discharged to far—offshore regions. These effluent
limiations, as well as the BPTCA limitations, also call for no discharge of
free oil in drilling muds, borehole cuttings, well treatment fluids, and
produced sand and establish a minimum for residual chlorine in sanitary
effluents.
A firm basis could not be developed during this study as a foundation
for ranking other possible pollutants in discharges to offshore waters.
This resulted from what was judged to be deficiencies in the formation
reviewed concerning the possible pollutants and their fate and effect.
Other possible pollutants could include metals in produced water,
drilling muds, and borehole cuttings and chemicals sometimes used in
drilling muds or well treatment fluids. The number of possible pollutant
species is large and they can occur in a variety of forms, e.g., dissolved,
suspended, or settleable solids or simply as metals in rock cuttings from
a shale shaker. Technologies involving principles of equalization and
sedimentation for removal of solids are widely applied on land but their
capabilities are space limited on offshore platforms. Studies to determine
the leachability or mobility of metals in borehole cuttings for evaluating
one practice for their disposal, viz., discharge to offshore waters, were
not noted in the information reviewed.
2
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Produced water is the largest single source of emissions to offshore
waters. The amount of water produced can vary widely between fields and
reservoirs and during the lifetime of a producing field. Effluent limi-
tations on oil in produced water, which are based on concentrations rather
than load, are a reflection of the wide variations in quantities of
produced water. Numerous metal species are present in produced water but
the concentrations noted in this study for metals of most environmental
concern were low. One available technology for achieving no discharge
of produced brines to navigable waters is to inject the produced brines
into a subsurface formation. If that is not a viable option for technical
or geohydrological reasons and if the produced water cannot be discharged
offshore because of high metal concentrations, technology for removal of
the metal(s) of environmental concern will very likely be a problem, at
least within a BATEA frame of reference.
Comparatively little attention and concern in the literature has been
given to quantitative evaluations of emissions to the air environment
resulting from offshore geophysical exploration, drilling, and production.
Sources of these emissions are internal combustion engines, gas in drilling
muds, venting of gas during testing and production, and vapors from crude
and fuel storage tanks. Technologies for limiting these sources on land——
engine exhaust controls, fixed or floating roof storage tanks, and flaring
of combustible gases——are available to or being practiced in offshore
operations. Evaluations of these sources based on field studies of their
emissions and environmental impacts were not noted in the information
reviewed.
On the basis of the foregoing discussion, the conclusion of this report
is that additional environmental studies of normal (as opposed to accidental)
emissions should be conducted before technological problems of controlling
sources not now the subject of interim proposed regulations can be ident-
ified and ranked. Topics of the studies are given below together with an
estimate of their relative priorities, from highest to lowest:
• Field evaluations of the fate and effect of toxic metals
in produced waters discharged to offshore waters
• Fate and effect of possible chemical pollutants in
drilling muds and water treatment fluids if discharged
to offshore waters
• Leachability/mobility of toxic metals in borehole cuttings
with an evaluation of the fate and effect of metals released
to offshore waters
• Field measurements of sources of air emissions and assess-
ment of their potential for environmental impact.
3
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SECTION III
GEOGRAPHICAL DISTRIBUTION OF OIL INDUSTRY
ACTIVITIES IN U.S. OFFSHORE AREAS
Presented in this section is information on the geographical distri-
bution of U.S. oil industry activities in marine areas offshore from the
continental United States (see Figure 1). Information presented is in the
form of selected statistics on offshore geophysical surveying, drilling,
and production.
For purposes of this study, oil industry activities commence by
surveying an area of interest by one or more marine geophysical exploration
methods. Dependent on those results and geological knowledge of subsurface
either a stratigraphic test or an exploratory test may then be drilled.
The basic difference between these two tests is that the stratigraphic test
is drilled for purposes of acquiring data on the geologic section and on
the potential reservoir rock specifically. In contrast, the exploratory
test (often called a wildcat) is drilled with the intent of finding oil or
gas, although it too provides data on the geologic section and potential
reservoir. If the exploratory test is successful, then development wells
are drilled and the new field or pool is put on production.
The above description is highly simplified and generalized and the
nomenclature built around objectives of drilling and classification of a
hole is quite extensive (see Reference Cl) for nomenclature used by the
American Association of Petroleum Geologists and the American Petroleum
Institute). Similarly, geophysical surveying activities range from those
conducted at reconnaissance scales for regional studies to detailed
surveying of a drilling prospect. As a general rule, mobile drilling rigs
or drill ships are replaced by a fixed—platform drilling unit if a new
field exploratory test is successful. Development drilling and subsequent
production of many (e.g., 12 to 24) wells from a fixed platform is common
practice.
GEOPHYSICAL SURVEYING
Geophysical surveys have been conducted in parts of all offshore
regions shown in Figure 1. Seismic methods have been and continue to be
dominant over all other methods in the number of crew months expended and
line miles surveyed. For example, of the 878 geophysical crew months
reported in the 5—year interval, 1960 to 1964, 87 percent were for seismic
surveys (see Table 1). In the 3—year period, 1972 to 1974, 92 percent of
4
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- -
/
/
/
Pacific (
Coast \
\
\
Offshore
Alaska
It
\
\
/
At I an t I C
Coast
FIGURE L
U.S. OFFSHORE REGIONS
(No Scale)
5
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TABLE 1. SF.ISNIC AND GRAVITY OFFSHORE GEOPHYSICAL EXPLORATiON ACTIVITY,
BY STATE, 1960 to 1964 (Crew_Months)*
Offshore
Location of
Surveys
Seismic—Gravity
1960
1961
1962
1963
1964
Alaska
Oregon
Washington ?
CaliforniaJ
4
——
34
——
53
3 39
i
S
19
4
L17
— —
1 (a)
1(a)
-—
Louisiana
64
2
102
17
83
28 103
20
168
9
Texas
F1or da
Atlantic Coast:
ND
——
——
ND
——
——
ND
——
——
ND
.
ND
ND! 8
——
— — ——
JND
‘ j D
-
40
3
17
18
15(b)
——
Totals
68
2
136
17
136
31 150
21
273
44
Source: Crew—month data courtesy of Neal Smith, Chairman, Committee on Geophysical Activity,
Society of Exploration Geophysicists.
(a) Gravity surveys off Oregon and Washington during 1964 were surface—ship—instrument type.
Gravity surveys off other three states were bottom—instrument type.
(b) The 15 crew—months of gravity survey work was distributed along the Gulf Coast of
Louisiana, including Florida.
* Reproduced/modified from Reference (2).
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the 867 geophysical crew months reported were for seismic surveys (see Table
2). In 1974, 93 percent of the more than 365,000 line miles surveyed
included exploration by seismic methods (see Table 3).
Geographically, of the offshore areas shown in Tables 1 and 2, Louisiana
led all other areas in the number of seismic crew months expended offshore.
However, seismic crew months expended in offshore Louisiana declined from
68 percent to 35 percent of the total seismic crew months in the 1960—1964
and 1972—1974 time intervals, respectively.
Seismic methods of marine petroleum exploration, in contrast to gravity
and magnetic methods, involves the use of a man—made energy source.
However, in recent years and as shown in Table 3, compressed air and gas
exploders have essentially eliminated the use of explosives in the water
as the energy source.
EXPLORATORY AND DEVELOPMENT DRILLING
U.S. offshore drilling statistics for the 5—year period 1960—1964 and
for the 2—year period 1973—1974 are given in Tables 4 and 5, respectively.
Of the 3,625 holes drilled during the earlier of these two periods, about
90 percent were offshore from Louisiana and 8 percent were offshore from
California. Average depth of all holes drilled was about 10,000 feet.
During the 1973—1974 time period, a total of 1,950 exploratory and
development holes were drilled with 80 percent of the total being offshore
from Louisiana, 12 percent offshore from Texas, and 6 percent offshore from
California. Average depth of all holes was about 9,100 feet.
An estimate of well drilling activities offshore from California, Texas,
and Louisiana for 1975 and 1976 is given below:( 3 )
1975 1976
Total Total Total
Total Total Footage Total Total Field Footage
Wells Wildcats ( 1000 ft) Wells Wildcats Wells ( 1000 ft )
CA 69 4 271 95 25 70 349
TX 174 54 1558 308 182 126 2674
LA 641 168 6042 704 142 562 6707
The projection of U.S. offshore drilling activity for the — ear
period, 1975—1980 for the U.S. offshore regions, is as follows:
7
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TABLE 2. U.S. OFFSHORE GEOPHYSICAL EXPLORATIPN FOR
PETROLEUM 1972—1974 (CREW MONTHS) a 1
State/Area
Seismic
Gra yi y/Magnetics/Other
1972 1973 1974
1972
1973
1974
Alabama
0
4
2.7
0
0
Alaska
22
23
54.3
1
1
Atlantic Coast
2
21
——
0
0
CalifornIa
3
27
58.2
2
6
Florida
27
54
5,9
6
5
Georgia
3
——
0.2
0
—
Louisiana
54
99
123.4
o
5
Maine
1
——
10
0
—
N. Carolina
——
——
2.3
—
—
Texas
Utah
37
—-
44
——
103.2
9 (b)
0
0
Washington
0
——
0
0
—
Other
——
——
7.7
—
—
Total
149
272
376.9
9
17
44
(a) Compiled from Geophysics : 39/1, 1974; 39/6, 1974; 40/5, 1975
(b) Great Salt Lake (?)
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TABLE 3. TYPES AND METHODS OF U. . OFFSHORE
PETROLEUM SURVEYS: 1974 a)
Type/Method
Crew
Months
Line—Miles
Surveyed
Seismic
Compressed air
260
237,497
Gas exploder
92
88,144
Implosive
12
7,186
Solid chemical
1
1,238
Other
8
7,719
Remote sensing
2
1,850
Gravity
2
2,600
Gravity/Magnetic
10
8,000
Magnetic
9
11,700
Sonic/velocity logging
21
(a) From Geophysics : 40/5, 1975, p 892
9
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TABLE 4. ESTIMATE OF TOTAL U.S. O F HORE DRILLING
AND PRODUCTION 1960 _ 1964 a
Region/State
Drilling
Production
Crude and
Condensate
Holes
Drilled
Foota .
Drilled /
Aver M
Depth
Alaska
9
92
10.2
Pacific Coast
276
1,431
5.2
Washington
1
5
5
California
275 (d)
1426 (d)
5 • 2 (d)
21100 (e)
Gulf Coast
3,340
35,233
10.5
Texas
64
640
10
minor
Louisiana
3,267
34,497
10.6
636,500
Florida
9
96
10.7
Total U.S. Offshore
3,625
36,756
10.1
657,600
Basic data from Reference (2 )
Thousands of feet
Thousands of barrels
Excludes slant holes drilled from shore installations
Excludes an estimated 150 million barrels from slant holes drilled from
shore installations
0
(a)
(b)
Cc)
(d)
(e)
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TABLE 5. TOTAL U.S. OFFSHORE DRILLING ACTIVITY
A. EXPLORATORY DRILLING COMPLETIONS
Region/State Oil Gas Dry Totais(b) Average(h)
Producers Producers Holes Holes Footage Hole Depth
3
0
4
7
7
31
537
575
4,894.3
8.5
6
28
182
216
1,805.9
8.4
1
3
355
359
3,088.4
8.6
0
0
14
14
105.4
7.5
Alaska
Pacific Coast
California
Gulf Coast
Texas
Louisiana
N. Gulf of Mexico
Total U.S. Offshore
Alaska
Pacific Coast
California
Gulf Coast
Texas
Louisiana
Total U.S. Offshore
Pacific Coast
California
Gulf Coast
Louisiana
Texas
Total U.S. Offshore
B.
DEVELOPMENT DRILLING
17
0 0
17
140.2
8.2
99
1 7
107
345.3
3.2
504
382 333
1,219
12,040
9.9
2
13 4
19
168.4
8.9
502
369 329
1,200
11,871.6
9.9
620
383 340
1,343
12 ,525 . 5
9. 3
C. NO
INTENT OF HYDROCARBON
Stratigraphic
& Core Tests (b)
Footage
PRODUCTION
No.
Service
Wel ls(h)
Footage
No.
2
0
0
2
5
0
0
5
18
35
0
53
50
291.2
0
341 .2
(a) Compiled from data in Bulletin, American Association of Petroleum Geologists,
Vol. 58, No. 8, 1974, pp 1475—1505 and Vol. 59, No. 8, 1975, pp 1273—1310
(b) Thousands of feet
11
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Total Holes
Offshore Region to be Drilled
Alaska 1017
Pacific Coast 5133
Gulf Coast 9583
Atlantic Coast 57
More than 15 tests(S) drilled in the northeast part of the Gulf of
Mexico (offshire Mississippi, Alabama, and Florida) have been unsuccessful
since the first Federal lease sale in December, 1973.(6) Areas drilled
include the Destin anticline some 50 to 60 miles off the Florida panhandle,
reefs and domes south of Mobile, Alabama, and reefs or structures west of
St. Petersburg, Florida. Exxon, as operator for a group, has drilled seven
unsuccessful tests at the Destin dome, the last of which was plugged and
abandoned in mid-1975. (7)
The Atlantic Continental Offshore Stratigraphic Test group (COST) has
scheduled two stratigraphic tests in the Atlantic Coast Region. The semi—
submersible drill rig was reported undertow on December 5, 1975, to the
first location designated as B—2, which is in the Baltimore Canyon area 75
miles east of the New Jersey coast in 290 feet of water. The same rig is
to drill the second test, designated as G—l, which is to be located in the
Georges Bank area about 100 miles southeast of the Massachusetts coast in
140 feet of water.( 8 ,9) During September, 1975, a total of l O0O line
miles of seismic surveys was conducted in these two areas.( - 0 )
Other U.S. offshore frontier areas which might be drilled in the
nearer—term future include the Gulf of Alaska and the Lower Cook Inlet.
Industry has nominated 778 tracts comprising more than 44 million acres
some 20 to 80 miles seaward from the Carolinas and Geor ia.(l 2 ) The Blake
Plateau area off the Florida coast is in deeper water(S) and presumably
drilling activity in this area would be in the more distant future.
The Outer Continental Shelf of f south Texas has been the location of
some drilling activity. However, the area is apparently either not too
promising or of low priority because fewer than one—third of the tracts
offered in the Federal lease sale in February, 1975, drew bids.(S) Gas
was discovered or at least tested in a well drilled during 1975 about 35
miles southeast of Corpus Christi, Texas. (11)
PRODUCTION
Selected statistics on U.S. offshore production of crude and lease
condensate are given in Tables 4 and 6 for the years 1960 through 1965,
and 1969 through 1975, respectively. In Table 7, U.S. offshore production
is compared to total U.S. production for the years 1969 through 1975.
Referring to Table 6, about 33 percent and 67 percent of 2.85 billion
barrels produced in the 5—year period, 1971—1975, were from state and
12
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TABLE 6. U.S. OFFSHORE PRODUCTION OF CRUDE OIL AND LEASE CONDENSATE 1969—1975
A. Production
(Thousands of barrels)
1969 1970 (a) l97l 1972 (b)
1973 (b) 1974 (b) 1975 (b) 1971 — 1975
66,065
101,470
70,445
31,025
2,920
1,095
1. ,825
443,840
58,035
385,805
614,295
195,640
418,655
312,199
449,090
344,513
104 ,577
7,788
3,1145
4,343
2,076,644
275.959
1,800,685
2,845,721
936,116
1,909,505
B.
1969 1970 1971 1975 1971—1975
Alaska
State (Total) 60,955 70,080 63,744 61,789 60,308
60,293
California (Total) 95,995 104,390 95,578 89,028 83,918
79,096
State 86,140 79,205 73,015 70,253 67,139
63,661
Federal 9,855 25,185 22,563 18,775 16,779
15,435
Texas (Total) 2,920 2,920 1,611 1,397 1,081
779
State 365 730 751 669 577
353
Federal 2,555 2,190 860 728 504
426
Louisiana (Total) 365,730 398,580 446,639 426.784 398,329
361,052
State 65,700 64,970 77,824 53,298 46,825
39,977
Federal 300,030 333,610 368,815 373,486 351,504
321,075
Total U.S. Offehore 525,600 575,970 607,572 578,998 543,636
501,220
State 213,160 214,985 215,334 186,009 174,849
164,284
Federal 312,440 360,985 392,238 392,889 368,787
336,936
Percent of U.S. Offshore
1972 1973 1974
Alaska
Production(t ______________________________________
State 11.6 12.2 10.8 10.5 10.7 11.1
12.0
31.0
California (Total) 18.3 18.1 16.5 15.7 15.4 15.4
15.8
15.8
State 16.4 13.8 11.5 12.0 12.1 12.3
12.7
12.1
Federal 1.9 4.4 5.1 3.7 3.2 3.1
3.1
3.7
Texas (Total) 0.6 0.5 0.5 0.3 0.2 0.2
0.2
0.3
State 0.1 0.1 0.2 0.1 0.1 0.1
0.1
0.1
Federal 0.5 0.4 0.3 0.1 0.1 0.1
0.1
0.2
Louisiana (Total) 69.6 69.2 72.2 73.5 73.7 73.3
72.0
73.0
St3te 12.5 11.3 9.4 12.8 9.2 8.6
8.0
9.7
Feieral 57.1 57.9 62.8 60.7 64.5 64.7
64.1
63.3
T ta1 U.S. Offshore 100 100 100 100 100 100
100
100
State 40.6 37.3 31.8 35.4 32.1 32.2
32.8
32.9
Federal 59.4 62.7 68.2 64.6 67.9 67.8
67.2
67.1
Ca) Daily averages times 365 days per year. Daily averages from:
American Petroleum Institute, “Annual Statistical Review, Petroleum Industry Statistics, 1964—1973”,
September 1974 (API data from U.S. Geological Survey).
(b) Annual production from Bureau of Mines, Petroleum Review, monthly issues.
(c) Totals may not add to 100 percent because of rounding.
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TABLE 7. COMPARISON OF U.S. TOTAL AND OFFSHORE PRODUCTION
OF CRUDE AND LEASE CONDENSATE 1969—1975(a)
A. Offshore Production: Percent of U.S. Total Production
1969 1970 1971 1972 1973 1974 1975 1969—1975
15.6 16.4 17.8 17.6 17.3 17.0 16.4 17.2
B. 1969 Offshore Production = 100
1969 1970 1971 1972 1973 1974 1975
U.S. Offshore 100 110 117 116 110 103 95
Total U.S. 641 669 657 656 638 609 581
(a) Based on data and references in Table 6.
-------
Federal leases, respectively. Of that total, 73 percent was from offshore
Louisiana, 15.8 percent from California, 11 percent from Alaska, and 0.3
percent from Texas. The vast majority of offshore production in the first
half of the 1960’s was from offshore Louisiana (Table 4).
In the 1969—1975 period, U.S. offshore production reached a maximum in
1971 when 614 million barrels (Table 6) were produced, continuously declining
since then to a low in 1975 when production was 95 percent of 1969 production
(Table 7). Within this same time interval, total U.S. production peaked in
1970 at 3,517.5 million barrels, continuously declining since then to 3,052
million barrels in 1975.
Offshore production, as a percentage of total U.S. production during
1969—1975, reached a maximum of 17.8 percent in 1971. This percentage
decreased to 16.4 percent in 1975 (Table 7).
15
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SECTION IV
EMISSION SOURCES: NORMAL OFFSHORE OPERATIONS
Information on emission sources associated with normal or “routine”
offshore operations of geophysical exploration, drilling, and production is
reviewed in this section. Data permitting characteristics of emissions to
the air and water environment from the various sources are summarized. Terms
such as “major” or “minor” are sometimes used to compare, on a relative
basis, sources within an operation without connoting the environmental
significance of the sources. For example, although internal combustion
engines may be the major source of air emissions to the environment from an
operation, the environmental impact of emissions from the engines may be
environmentally acceptable, unacceptable, or unknown.
GEOPHYSICAL SURVEYING
Emissions to the Air Environment
Exhausts from internal combustion engines powering geophysical survey
boats Is the major source of air emissions in offshore geophysical surveying.
Horsepower of engines used often range between 500 and 2,500.
Air emissions resulting from geophysical exploration have not been a
source of environmental concern in the literature reviewed. Surveys are
conducted at considerable distances from shore and ship tracks may range
from less than 1 mile to several miles apart. Thus, air emissions from
geophysical surveying do not represent many sources emitting in small areas
for extended periods of time.
Data on air emissions of geophysical survey boats were not located.
Of possible relevance is emission factors of motorships shown in Table 8.
Emissions to the Water Environment
During geophysical exploration, water emission sources include debris,
bilge, domestic, and sanitary waste from survey vessels. Exploratory use
of propane oxygen guns and/or high—powered oscillators now in use appear to
have no adverse affects on the water environment. Bottom sampling/coring
does slightly perturb bottom water conditions. (13)
16
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TABLE 8. EMISSION FACTORS FOR MOTORSHIPS(a)
Lb/Mile
Pollutant (Underway)
Particulates 2.0
(b) 1.5
Carbon Monoxide 1.2
Hydrocarbons .9
Nitrogen Oxides (NO 2 ) 1.4
Aldehydes (HCHO) 0.07
Total 8.07
(a) Accuracy of factors: below average
(b) 0.5 weight percent sulfur in fuel assumed
Source: Compilations of Air Pollutant Emission Factors, Second Edition,
U.S. Environmental Protection Agency, Office of Air and Water
Programs, Office of Air Quality Planning and Standards, Research
Triangle Park, North Carolina, April, 1973.
17
-------
On—board domestic waste sources include laundries, gallies, showers,
and body wastes. Discussions concerning these waste sources are lacking in
the offshore exploration literature. Such sources concentrated in a small
area, e.g., harbors and bays, are known to be capable of degrading water
quality, if not controlled. (14)
EXPLORATORY AND DEVELOPMENT DRILLING
Air emissions from exploratory and development drilling can result
from burning of gas recovered from testing of wells and from internal com-
bustion engines used for powering drill rig equipment. Possible emissions
to the water environment include drilling fluids/cuttings, deck drainage,
and sanitary wastes. These sources are present throughout offshore oil and
gas development, but since they do not appear to be a major source during
production, they are only discussed in this section.
Emissions to the Air Environment
Various tests are conducted on a potential oil or gas well. The testing
time varies with each well, but the average testing time for an oil well is
2 to 3 hours and for a development gas well, from 2 to 4 hours, and 1 to 7
days for an exploratory well. Because of the short test time required for
development wells, the initial production of gas or oil is relatively
small, but gas from an exploratory well can flow at a rate from a few
thousand cubic feet per day to millions of cubic feet per day. (15)
The oil and gas produced during well testing is passed through equip-
ment such as sepa:ators, tank and vent lines, then is disposed of ultimately.
Well testing gas is usually burned releasing the products of combustion.
Emissions can be visible when flaring gas; however, there are commercially
available “smokeless” flares. The quantity of emissions from flaring of
natural gas were estimated by assuming the rate of emissions would be
similar to those from commercial fired combustion equipment. Table 9 shows
the estimated emissions from flaring of natural gas during well testing
operations.
The source of power for most drilling rigs is natural gas or diesel
fueled internal combustion engines. The exhaust from a diesel fueled
engine can be properly adjusted so that it does not emit smoke in violation
of air pollution control regulations. Table 10 shows average emission rates
from industrial—type diesel engines.
Another source of air emission is gas in the drilling mud. This gas
is generally vented to the atmosphere unless H 2 S is present in the gas
stream in which case the drilling mud can be treated with various chemicals
to alter or precipitate the H 2 S.( .l 7 )
In a producing oil well, the fluid is either naturally flowing, or
artifically lifted or pumped to the surface. The oil from a pumping well
often has very little gas associated with it, and is usually treated only
18
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TABLE 9. ESTIMATE OF QUANTITY OF EMISSIONS FROM
BURNING OF WELL TESTING GAS
Pollutant
Lb/Million Cubic Feet
Particulate
19
Sulfur dioxide (so 2 )
(a)
.6
Carbon monoxide
20.0.
Hydrocarbons (CH 4 )
8.0
Nitrogen oxides NO 2
120.0
(a) Based on average sulfur content
Burning is assumed to be the
combustion equipment.
6 3
of natural gas of 2000 grains/lU ft
same as natural gas firing for commercial
Source: Compilation of Air Pollutant Emission Factors, Second Edition,
U.S. Environmental Protection Agency, Office of Air and Water
Programs, Office of Air Quality Planning and Standard, Research
Triangle Park, North Carolina.
I
TABLE 10. EMISSION FACTORS FOR DIESEL POWERED
INDUSTRIAL EQUiPMENT
Pollutants
Lb/Hour
Lb/lU 3 Gal
Particulates
.143
33.5
Oxides of Sulfur
.133
31.2
Aldehydes
.030
7.04
Oxides of Nitrogen
2.01
469.0
Carbon Monoxide
.434
102.0
Exhaust Hydrocarbons
.160
37.5
Source: Supplement No. 4 for Compilation of Air Pollutant Emission Factors,
Second Edition, U.S. Environmental Protection Agency, Office of
Air and Waste Management, Office of Air Quality Planning and
Standard, Research Triangle Park, North Carolina, January, 1975.
19
-------
for water separation before it is moved into the stock tank. The oil from
a flowing well may contain various quantities of gas and generally goes to
a separation unit. The resultant gas is either flared or vented.
Hydrocarbon Emission From Storage Tanks——
Storage tanks are used to store crude oil and distillage oil on of f—
shore platforms. However, crude storage tanks that are used usually have
a capacity of 10,000 bbl or less since space is at a premium on a plat.—
form.O- 3 ) The storage tank used would probably be of fixed—roof type
whose emissions are greater than those of a floating—roof type. Shown in
Table 11 are emission rates from fixed—roof storage tanks for crude and
distillate oils. Emissions also occur during the loading and unloading of
storage tanks. Factors affecting hydrocarbon vapor emissions are changes
in pressure or temperature, and volatility of the liquid stored.
Emissions to the Water Environment
The major emission sources associated with exploratory and development
drilling which can influence the aquatic environment include drilling
fluids/cuttings, deck drainage, and sanitary wastes. The latter two, deck
drainage and sanitary wastes, are considered minor waste sources.(1 8 )
Compressor drains, cooling and heating circuit discharges, and domestic
water treatment system blowdowns (desalination units) are also a part of
offshore operations, but respective emissions are not well defined in the
literature. These sources and discharges from crew boats, tugs, and
service/supply boats, for the purposes herein, are considered negligible. (19)
Drilling Fluids and Cuttings——
Drilling fluids and bore cuttings constitute the primary source of
emissions to the water environment from drilling operations. An integral
part of drilling involves the use of drilling mud to prevent blowouts by
counterbalancing formation pressures. The mud also acts as a lubricant,
provides bore hole side wall control, and is the medium which transports
the cuttings to the surface. The time involved in use of drilling muds is
relatively short in comparison to the total life of an offshore development
with drilling normal1,y var ’ing from less than 10 days to more than 3 weeks
per well completion. ” 6 ’ 20 The number of wells completed from one offshore
development is increasing and may range from less than 10 to more than 30.
Drilling muds are often organized into two categories——water based and
the more expensive oil based fluids. Water—based muds are composed of
bentonite or attapulgite clays and a variety of additives to control the
pH, corrosion, emulsification, lubrication, and density properties of the
drilling fluid. Oil—based muds contain a mixture of organic acids,
asphaltic stabilizing agents, and high flash diesel oil.( 2 l) Unrecovered
water—based muds are more often disposed of to surface waters than spent
oil—based muds wh ich are generally barged ashore for final disposition. (18)
The primary pollutants in drilling muds are oil and grease. Oil—based
muds, normally used in deeper/hotter holes, can contain over 50 percent
hydrocarbons in the liquid phase.( 2 -) Typical compositions of a gelled
20
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TABLE 11. EVAPORATIVE Et4ISSION FACTORS FOR FIXED ROOF STORAGE TANKS
Breathing Loss Working Loss
Product
New
lb/
Tank Condition
day lO gal
Old Tank Condition
lb/day lO gal
lb/b 3 gal
throughput
Crude Oil
.15
.17
7.3
Distillate
Oil
.036
.041
1.0
(Diesel fuel)
Source: Supplement No. 1 for Compilation of Air Pollutant Emission
Factors, Second Edition, U.S. Environmental Protection Agency,
July, 1973.
-------
seawater mud and a lignosulfonate mud is shown in Table 12. As shown in
the table, chromium amounts to about 3 percent of the mud on a dry weight
basis. Barite (BaSO 4 ), a major component of drilling muds, is used to
control blowouts by increasing the weight (specific gravity 4.5) of mud
column. The nature, use and normal concentration of other mud additives
is shown in Table 13.
Generally oil and gas production can be expected from depths of 6,000
to 12,000 feet. For a typical depth of 10,000 feet, 7,000 barrels of
drillin mud containing about 258 tons of commercial mud components are
needed.” 22 ) An example of drilling mud needs is summarized in Table 14.
In a typical 10,000 foot development, well cuttings can amount to more than
1,700 bbls (‘i.’700 tons).O - 6 )
To increase production, acid or other fluid and suspended particulate
matter may be pumped through the well bore into producing formations. The
spent acid returns up the well when production is resumed and is handled
as are other fluids from the well. Other procedures to increase produc-
tivity and oil recovery include the injection of high—pressure steam, water
and/or gas into specially prepared injection wells. The water used for
this purpose may be taken from the ocean or from formation water. Water
too contaminated to be treated, polished, and discharged can be reinjected
Into formations. (23)
Deck Drainage—-
During drilling and/or workover operations, the potential for accumu-
lation of pollutants which can contribute to deck drainage is greatest.
During well completion, much of this material is drilling fluids, the com-
position of which has previously been discussed. Chronologically most
workover operations occur during the production phase of oil and gas
development. However, as these operations are short—term in duration
(about 1/3 of the time( 2 0) needed to drill the same well, the resulting
deck drainage is discussed here.
Well completion activities can result in spillage of drilling fluids.
Other sources of spills are valve failures.( 13 ) Acids (hydrochloric,
hydrofloric, and various organic acids) employed during workover operations
can also contribute to deck drainage. These acids are generally neutralized
by other deck wastes and/or brines prior to further handling for disposition.
Oil is considered the primary pollutant in deck drainage.
Sanitary Wastes and Refuse——
The largest volume of sanitary wastes and refuse are generated during
the well completion phase of oil and gas production. Estimates of permanent
inhabitants on the development facilities range from about 12 to more than
80 occupants.( 24 ) Domestic wastes include toilet, kitchen, and laundry
inputs. Toilets are usually flushed with site—ambient water.(lS) Sixty
gallons per day per person (gpcd) with a biochemical oxygen demand of about
0.2 pounds per capita day are considered realistic estimates of domestic
occupation waste generation rates.( 24 ) Solid wastes include food packaging
and other nondurable goods.
22
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TABLE 12. CELLED SEAWATER MUD - TYPICAL
COMPOSITION (23)
Mud Component Used
Weight, lb
Attapulgite Clay
Caustic (Sodium Hydroxide)
Organic Polymer
Ferrochrome Lignosulfonate
(Iron—2.6%, Chromium—3. Sulfur—5.5%)
Pregelatinized Starch
Seawater
Total Mud Components
500
As Required
69,300
Mud Component Used
Barium Sulfate (Weighting Agent)
Caustic (Sodium Hydroxide)
Ferrochrome Lignosulfonate
(Fe—2.6%, Cr—3.0%, S—5.5%)
Organic Polymer
Bentonite Clay in Freshwater, or
Attapulgite Clay in Seawater
Proprietary Defoamer
Water
Total Mud Components
Total Mud Components,
Less Barium Sulfate
Weight, lb
319,000
22,500
29,600
4,100
17,100
325
As Required
392,625
72,625
56,300
5,500
3,700
3,300
LIGNOSULFONATE MUD - TYPICAL COMPOSITION
23
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(23)
TABLE 13. MUD ADDITIVES
Amount
Function Name (lb/bb l)
Alkalinity &
pH Control 1. Sodium Hydroxide NaOH 0.1—0.3
2. Sodium Bicarbonate NaHCO 3 0.1—1.5
3. Calcium Chloride CaC1 2 0.1—3.0
4. Calcium Hydroxide Ca(OH) 2 0.5—8.0
Bacteriocides
1. Paraformaldehyde (CH 2 0) 0.5—1.0
2. Sodium Chloride NaC1 5.0—10.0
3. Sodium Chromate Na 2 CrO 4 0.1—4.0
Calcium Removers
1. Sodium Bicarbonate NaHCO 3 0.1—1.5
2. Sodium Carbonate Na2CO 3 0.5—2.0
3. Sodium Hydroxide NaOB 0.1—3.0
4. Organic Phosphate 0.1—0.5
Corrosion Inhibitors
1. Calcium Hydroxide Ca(OH) 2 0.5—8.0
2. Sodium Chromate Na 2 CrO 4 0.1-4.0
3. Film Forming Amine 2.0
Defoamers
1. Aluminum Stearate 1.0—10.0
IC R 3 (CH 2 ) 16 C00/3A1
2. Alkyl Aryl Sulforiate 0.2—0.3
3. Silicones 0.1—3.0
Emulsifiers
1. Calcium Lignosulfonate 1.0—4.0
2. Oxyethylated Alkyl Phenol 0.5—3.0
3. Ferrochrome Lignosulfonate 0.1—2.0
4. Quebracho 0.2—5.0
Filtrate Reducers
1. Bentonite 5.0—10.0
2. Sodium Carboxymethylcellulose 0.1—1.5
3. Sodium Polyacrylate 1.0—3.0
4. Starch 2.0—8.0
24
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TABLE 13. (Continued)
Function Name Amount
(lb/bbl)
Flocculants
1. Acrylamide Polymeric Hydrolite .005—.0l
2. Bentonite 1.0 —5.0
3. Lignosulfonate 1.0 —5.0
Foaming Agents
1. Alkyl Polyoxyethylene 8.0—16.0
Lost Circulation
1. Cottonseed Hulls 3.0—25.0
2. Cane Fibers 2.0— 6.0
3. Asbestos 2.0— 6.0
4. Cellophane 5.0—10.0
5. Mica 2.0—10.0
Lubricants
1. Oxidized Asphalt 3.0—6.0
2. Carbon Powder 1.0-2.0
Shale Control
Inhibitors
1. Oxidized Asphalt 3.0—6.0
2. Calcium Hydroxide 0.5—8.0
3. Sodium Silicate 0.1-3.0
4. Calcium Lignosulfonates 0.1—3.0
Surface Active Agents
1. Oxyethylated Alkyl Phenol 0.5-3.0
2. Alkyl Aryl Sulfonate 0.2—0.3
Thinners & Dispersants
1. Sodium Tetraphosphate 0.1—0.2
Na 6 P 4 O 13
2. Calcium Lignosulfonate 1.0—4.0
3. Sodium Chromate Na 2 CrO 4 0.5—3.0
4. Quebracho 1.0—10.0
Viscosifiers
1. Bentonite 1.0—5.0
2. Asbestos 2.0—6.0
3. Sodium Carboxymethyl Cellulose 0.1—1.5
25
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TABLE 14. MUD COMPONENTS USED IN SEAWATER - LIGN0sULFONArE SYSTEMS (16)
TO 15,000 FEET. (WEIGHT IN FOUNDS)
Interval Sub—Total Interval Sub—Total Interval Total
0—900 900—3500 3500 3 b—iO,0O0 10,000 10—15,000 15,000
Component Feet Feet Feet Feet Feet Feet Feet
Barium Sulfate (Barite) 3,000 3,000 6,000 529,000 535,000 625,000 1,160,000
Bentonitic Clay 10,000 10,000 20,000 36,000 56,000 9,000 65,000
Attapulgite Clay 5,000 5,000 10,000 — 10,000 — 10,000
Caustic 500 500 1,000 20,000 21,000 23,000 44,000
Aromatic Detergent 1,000 1,000 2,000 3,000 — 3,000
Organic Polymers 1,000 1,000 3,000 4,000 — 4,000
Ferrochrome Lignosulfonate 26,000 26,000 69,000 95,000
Sodium Chromate 2,000 2,000
Totals 18,500 20,500 39,000 616,000 655,000 728,000 1,383,000
1/ It is emphasized that these are “typical” values and quantities may vary by as much as 50% from well to
well.
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PRODUCTION
During the production phase of offshore development, major air emission
sources include separator associated vents/flares, diesel engine emissions,
and storage tank losses. Coproduced brine constitutes the major source of
discharge to the water environment. Deck drainage and sanitary wastes are
not considered a major source during production.
Emissions to the Air Environment
The normal operation on a production platform consist mainly of handling
production from oil and/or gas wells and separation of oil, gas, and water
phases. Most air emissions attendant with production operations are from
oil/water/gas/separators, diesel engines, and petroleum storage tanks. Gas
from the separators is generally flared, although if the methane is too low,
or the quantity is insufficient to be flared, it is then vented.
Most of the air pollutants associated with the production of oil or
gas or emitted into the atmosphere as a result of venting or burning vapors
and liquid waste. The air pollutants most often emitted into the atmos-
phere are unburned hydrocarbons, products of combustion, products of
incomplete combustion, and acid gases such as hydrogen sulfide and sulfur
dioxide. The concentration of air pollutants from gas or oil production
varies greatly with location and concentration of the producing facilities.
Emissions to the Water Environment
Coproduced water constitutes the major source for emissions to the
water environment during production. Deck drainage pollutants should be
less available than during development drilling. As manpower needs are
also relatively low, sanitary effluents are also considered less important
during normal production operations. During well workovers, however, both
deck drainage and sanitary waste sources may become as important as during
well drilling operations.
Coproduced Basic Sediment and Water (BW&W)——
The major waste stream from offshore production is the coproduced
Itbrinett water. Sand may also be produced along with oil normally at rates
from near 0 to 1 barrel/2,000 barrels of liquid.( 21 -) As reported, copro—
duced formation water can range from 2 to 98 percent of oil production.
Based on a 1963 study, an estimate of 3.2 times the amount of oil produced
is often used as a basis for treatment cost projections.( 20 ) More recent
estimates of coproduced water range from less than 25 percent(25) through
about 50 percent( 22 ’ 26 ) to more than 100 percent of the oil produced( 1 - 8 ),
with age of a well being a major factor influencing the quantities of
coproduced water. Shown in Table 15 are data on coproduced water dis-
charges in the Gulf of Mexico.
More than 700 platforms and nearly 250 rigs are operating in the Gulf
of Mexico.( 20 More than 2,000 wells are in state waters and 6,000 wells
are on the Outer Continental Shelf (OCS).(i 8 ) The reported number of
27
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TABLE 15.LOCATION AND ESTIMATED SIZE OF GULF OF MEXICO
OFFSHORE PRODUCED WATER DISCHARGES( 2 ’) (Louisiana
and Texas)
Capacity,
(Produced Water, bpd)
( )
Coastal a
Of
(State
fshor
and
e (b)
OCS)
1,000
434
393
2,000
146
132
5,000
115
71
10,000
70
36
40,000
40
805
0
632
(a) 606 Discharge points in Louisiana and 199 in Texas.
(b) 452 Discharge points in Louisiana and 180 in Texas.
28
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possible separate discharge points in the Gulf range from a total of
1,098(27) to 1,437 for OCS——Louisiana alone.( 2 -) A breakdown of the former
estimate is as follows:
Coproduced Water Discharges ( 27 )
Texas Louisiana Total
State 296 475 771
OCS 10 317 327
Total 306 792 1,098
Another reference indicates that out of the 1893 OCS—Louisiana develop-
ments, only 214 discharge 180,000 bbls/day to the Gulf. As reported, a
total of 420,000 bbls/day is coproduced with 240,000 bbls/day being piped
to shore prior to separation.( 26 ) The disposition of water transported to
shore and of near—shore coproduced waters are not specifically addressed
in the recent literature. However, the Interstate Oil Compact Couiniission
states that 72 percent of a U.S. total of 25 million bbls/day of coproduced
water is reinjected for either secondary recovery or disposal. Rivers
received 12 percent and 12 percent is reused or transported to “approved
disposal sites”. 33 Total OCS coproduction of brine water in the Gulf is
reported to be about 605,000 bbls/day with 305,000 bbls/day transported to
shore. (22)
Offshore oil production and consequently coproduced brine water pro-
duction in other U.S. coastal areas is not as extensive as the Gulf.
Except for one facility, all brine production off California is piped
ashore for treatment and disposal. Brine is coproduced at nine platforms
offshore from California and the BS&W is transported with the oil for
phase separation on shore. After separation, the brine water is disposed
of by subsurface injection. In Alaska’s Cook Inlet, 14 multiple well
platforms on four oil fiels and one gas field pump BS&W to land for
separation prior to disposal to the Inlet’s surface waters.Gl- 8 , 2 l)
The Bureau of Land Management indicates that coproduced formation
water contains an average of 112,513 mg/i of total dissolved solids (TDS)
with ranges normally between 61,552 and 270,400 mg/l.(22 ,2S 2 5 ,2 8 , 2 9)
Coproduced brine water also contains suspended and settleable solids and
hydrocarbons. Concentrations of oil and grease in coproduced water range
from less than 100 to more than 1,000 mg/i, averaging 196 mgIi.( 2 1 ) The
average oil and grease results from a 1974 EPA Survey 0 - 8 ) compares favorably
with this estimate (see Table 16). In Table 17, the averages of selected
constituents of an oil field brine are compared with those of seawater.
The range of constituents in California and Texas offshore produced f or—
mation water is presented in Table 18. A breakdown of total solids in
representative offshore brines is shown in Table 19. As shown in these
tables, TDS can approach 100 pounds per barrel and the major component,
chloride, normally ranges from about 12 lbs/bbl to 50 lbs/bbl. Average
TDS of open ocean water is about 35,000 mg/i ( 12 lbs/bbl) with a chloride
content of 19,000 mg/i (“. 6.7 lb/bbl). At 50 ppm effluent oil concentrations,
the loss of oil to the water environment has been estimatedat nine barrels
for each million barrels of oil produced. (30)
29
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TABLE 16. PRODUCED FORMATION WATER COMPOSITION (18, a)
Parameters Average
Oil and Crease (Influent) 202 mg/I
Cadmium 0.0678 mg/i
Cyanide 0.01 mg/i
Chlorides 61,142 mg/i
Mercury Trace
Total Organic Carbon 413 mg/I
Salinity 110,391 mg/i
API Gravity 33.6 degrees
Suspended Solids 73 mg/i
(a) 25 Discharges analyzed in 1974 EPA survey, Gulf of Mexico.
TABLE 17. COMPARISON OF SEAWATER AND OILFIELD BRINE (25)
Seawater Oilfield Brine
(mg/i) (mg/i)
Na+i 10,600 12,000—150,000
400 30— 4,000
Ca+ 2 400 1,000—120,000
Mg+ 2 1,300 500— 25,000
Cl 1 19,000 20,000—250,000
Br 1 65 50— 5,000
I i 0.05 1— 300
UCO 2 0- 1,200
SO 4 2 2,700 0— 3,600
30
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TABLE 18. RANGE OF CONSTITUENTS IN OFFSHORE PRODUCED
FORMATION WATER (21)
California
Texas
Range
Parameter mg/i
Range,
mg/1(a)
Arsenic
Cadmium
Total Chromium
Copper
Lead
Mercury
Nickel
Silver
Zinc
Cyanide
Phenolic Compounds
BOD 5
COD
Chlorides
TDS
Suspended Solids
0.001—0.08
0.02 —0.18
0.02 —0.04
0.05 —0.116
0.0 —0.28
0.0005—0.002
0.100—0.29
0.03
0.05 —3.2
0.0 —0.004
0.35 —2.10
370— 1,920
340— 3,000
17,230—21,000
21,700—40,400
1—75
0.01—0.02
0.02—0.193
0. 10—0. 23
0. 10—0. 38
0.01—0.22
0.001—0.13
0. 10—0. 44
0. 01—0. 10
0.10—0.27
(b)
53
126—342
182—582
42,000—62,000
806—169,000
12—656
(a) Some data reflect treated waters for reinjection.
(b) Not available.
31
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TABLE 19. CHEMICAL CONTENT OF REPRESENTATIVE OFFSHORE BRINEG (16,a)
Component
High
Solids
Average
Solids
Low
Solids
mg/i
Percent
of
Total
mg/i
Percent
of
Total
mg/i
Percent
of
Total
Iron
153
0.057
15
0.011
139
0.226
Calcium
17,000
6.287
4,675
3.294
772
1.254
Magnesium
2,090
0.773
1,030
0.726
152
0.247
Sodium
84,500
31.250
49,120
34.612
22,651
36.800
Bicarbonate
37
0.014
100
0.070
933
1.516
Sulphate
120
0.044
0
—
188
0.305
Chloride
166,500
61.575
86,975
61.287
36,717
59.652
Total Solids
270,400
100%
141,915
100%
61,552
100%
(a) From U. S. Geological Survey, Oil and Gas Supervisor, Gulf of Mexico Area
New Orleans, Louisiana.
-------
SECTION V
EMISSIONS SOURCES: ACCIDENTS DURING
DRILLING AND PRODUCTION
Accidents during drilling and production can result in the emissions
to the air and water environment. Past major accidents have resulted in
environmental damage and strong public concern. Human error has been shown
to account for most accidental emissions. The distance to shore from an
accident is perhaps the single most important factor relating to the
potential for environmental damage from accidental emissions.
EMISSIONS TO THE AIR ENVIRONMENT
Blowouts will emit hydrocarbons directly into the atmosphere and with
additional hydrocarbons emitted by evaporation of oil that is dispersed on
the water. The rate of emission depends upon the chemical composition of
the crude oil and increases as the fraction of light ends in the crude oil
increases. Also, should a fire occur with the blowout, the products of
combustion——CO, NOR, SO and particulates——are released into the atmosphere.
Emissions from blowouts shown in Table 20 below represent complete
combustion of crude oil. In reality, the combustion would probably be
incomplete, and materials such as nitrous monoxide, sulfur monoxide,
petroleum particulates, and other partially oxided matter would probably
be emitted into the atmosphere. At this time, there is no reliable method
to estimate the quantities of emissions from the incomplete combustion of
crude oil.
The average composition of natural gas delivered to pipe lines in the
United States is shown below.
Methane CH 4 72.3%
Ethane C2H 6 14.4%
Carbon Dioxide CO 2 0.5%
Nitrigen N 2 12.8%
Small amounts of sulfurs and other materials could also be present. If a
gas well is not burning, these constituents would be released into the
atmosphere. If the gas well were on fire, emissions would consist almost
entirely of carbon dioxide and water. The nitrogen would remain as N 2 and
sulfur present would be oxidized to SO 2 Quantities of emissions resulting
from the blowout of a gas well are given in Table 21.
33
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TABLE 20. ESTIMATE OF QUANTITIES OF EMISSIONS
FROM BLOWOUTS FROM CRUDE OIL
Emissions,
oil
pounds per barrel of
discharged ( 26 )
Fires(a)
Evaporation
Total
Particulate
s 02 (b)
MC
1
19
0.1
——
——
38
1
19
38.1
CO
0.91
--
0.01
NO
x
2.5
—-
2.5
(a) Burning assumed to be the same as residual oil firing in industrial
burners. Emission factors from “Compilation of Air Pollutant
Emission Factors”, (revised), U.S. Environmental Protection Agency,
Office of Air Programs, Research Triangle Park, North Carolina,
April 1973.
(b) Assumes sulfur 2.9 percent
TABLE 21. ESTIMATE OF QUANTITIES OF EMISSION FROM
BLOWOUT FROM NATURAL GAS. EMISSIONS
POUNDS PER MILLION CUBIC FEET BURNED a)
Pollutant
lb/b 6 f B(a)
Particulates
Sulfur dioxide 1
19.0
.6
Carbon monoxide
20.0
Hydrocarbons
8.0
Nitrogen oxides
80.0
Source: Compilation of Air Pollutant Emission Factors, Second Edition,
U.S. Environmental Protection Agency, Office of Air and Water
Programs, Office of Air Quality Planning and Standard, Research
Triangle Park, North Carolina, April 1973.
(a) Emission factors are from domestic combustion equipment.
(b) Based on average sulfur content of natural gas of 2000 grains/b 6 ft 3 .
34
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EMISSIONS TO THE WATER ENVIRONMENT
Accidental oil losses are the cause of the most evident damage to the
water environment. However, they contribute only about 10 percent of an EPA
estimate of 2.1 million metric tons of oil that man directly introduces to
the world’s oceans.( 3 1) When other sources such as waste automobile
industrial machinery oil and discharges from refinery/petrochemical
operations are also considered, the often used Bureau of Land
Management estimates of about 5 million metric tons per year can be
approached.( 16 ’ 22 ’ 23 ’ 28 ’ 32 ) Of this larger estimate, only 2.1 percent
(‘ 1O3,OO0 metric tons/year) has been attributed to offshore drilling and
production. Accidents, such as blowouts, contribute approximately 600
barrels per day( 30 ) ( 29,500 metric tons/year). During the drilling of
14,000 offshore wells between 1937—1970 (9,000 in OCS), only 25 blowouts
were reported.( 33 ) As a further reference, natural seepage to oceans is
estimated to contribute less than 0.1 to 0.2 million metric tons per year
to the oceans. (34)
Oil spill statistics reported in 1974 range from a fraction of a
barrel to over 150,000 barrels. Most spills are near the low end of this
range. In 1972, 96 percent of spills were less than 24 barrels. In 1970
and 1972, three spills were reported each year which accounted for two—
thirds of the total accidentally spilled oil in the United States for those
years. The very large spills account for most of the reported losses. For
example, the single Torrey Canyon accident (1967) resulted in the release
of twice as much oil as was spilled in the United States in 1970. The U.S.
Geological Survey reports that in the period of 1964 to the first quarter
of 1974, a total of 44 oil spill incidents connected with Federal OCS oil
and gas operations in the Gulf of Mexico involved 50 barrels or more, and
one spill of greater than 50 barrels occurred in the California OCS. The
individual incidents included above represent platform fires and blowouts,
storm or ship damage to platforms, OCS pipeline failures, and OCS barge
leaks. (25)
OCS-Gulf of Mexico statistics indicate that one well blowout occurs
for every 2,860 wells drilled and approximately 2,100 barrels are lost in
the blowoutJ 25 Chances of accidents during drillin and workover operations
are greater than during normal production operations .O- 3 ’ 2 O ’ 30 ) Most of
these events have been associated with human error.
Cause of Spills
The accidental release of oil or gas in OCS drilling and production can
be a result of the following: human error, equipment failure, natural
hazards, or combination of these causes. Federal and industry regulations
are aimed at minimizing the number and severity of such accidents.
Fires on drilling or production platforms can be ignited by a variety
of events. The proximity of combustible hydrocarbon liquids or vapors to
arcing electrical devices or overheated mechanical equipment is the most
common cause of ignition. More rarely, lightning or static electricity
35
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may be the ignitor.( 1 - 6 ’ 22 ’ 23 ) If a secondary combustible fluid is ignited,
as opposed to the hydrocarbon being produced on the platform, a fire may be
rapidly controlled with only minor damage. Once a well or storage tank
becomes involved, damage is usually major. Release of large amounts of
hydrocarbons to the marine environment does not always occur, however.
Most fires are extinguished quickly with little damage or release. (16,22,23)
If a blowing well is releasing mostly or entirely natural gas, the ocean
pollution is usually minimal. An extinguished well may become reignited
during repair; however, oil or gas fires fed by large amounts of condensate
are usually left burning while control procedures are planned and executed.
While adding pollutants to the air, marine releases are minimized and the
fire hazard of large amounts of floating oil is minimized.
Surface and subsurface currents, ice, and storm surges can be the cause
of accidental release of petroleum to the marine environment. The primary
natural hazards in currently developed OCS areas are hurricanes and earth-
quakes and resulting tsunamis.
Earthquake damage can result from structural failure caused by dynamic
shaking or foundation failure due to loss of soil stability or strength.
Modern structural techniques can protect structures in Gulf and Atlantic
areas and in many areas of the Gulf of Alaska; however, some unstable soil
types in this area remain unsuitable for platform drilling and production.
To date no incidences of oil spillage resulting from damage caused by
a tsunami have been recorded. Most production to date has been from areas
where these seismically—induced events are relatively rare. Large under-
water storage tanks and tankers in birth are the most vulnerable to tsunami
damage.
Developments in the Gulf of Mexico have provided extensive experience
with and explosure to hurricanes. In the past, storage tanks have been the
primary cause of loss from hurricane damage. With the transition to pipe-
line transfer of the oil produced, the number of such tanks and thus the
loss has been minimal. While physical damage can occur to the platform,
little if any oil may be lost. Current OCS procedures call for the advance
evacuation procedures in or adjacent to a projected hurricane path. All
surface equipment and wellhead controls are shut—in before evacuation.
Spill Movement
Oil spilled onto the surface of the sea spreads and is transported by
the winds and ocean movements. From the time of the spill, oil begins to
weather. Oil that has been in the water for some time (weathered) is
different from fresh oil. The volatile and soluble components decrease or
are lost with time, with toxicity usually being reduced. However, weathered
oil may still be toxic to birds and marine organisms and can remain for
long periods of time in sediments.
The rate and direction of movement and spread of an oil slick from its
source is dependent on the following variables which are listed generally
in order of importance( 35 ):
36
-------
• Wind direction and speed
• Sea state
• Surface currents
• Latitude
• Surface temperature
• Oil density and viscosity at temperature
• Volatility
• Inherent tendency toward emulsification with sea water
• Volume——rate of discharge at source
• Interfacial and surface tension, spreading pressure.
The probability of a spill reaching land is determined by a similar
list of factors plus the added condition of distance from the source to
landfall and the physiography of the shoreline. The season of the year and
ambient weather conditions are important in determining the extent of the
shoreline, if any, that will be affected. The trajectory of hypothetical
spills in the Atlantic Ocean have been plotted with respect to distance from
shore.(1 3 ) The probability of these spills reaching the shore is recorded
in Table 22. Similar analyses have been done of other existing or proposed
offshore oil production areas. In some areas, spills will almost always
reach shore if the accident occurs near enough to land. In other areas,
spills will infrequently or never reach shore. Each shoreline must be
specifically analyzed to project the probability of offshore oil spill
reaching shore under the range of weather and sea state conditions which
are normal to that area.
37
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TABLE 22. PROBABILITIES OF OIL SPILLS COMiNG ASHORE FROM
HYPOTHETICAL SPILL SITES IN THE ATLANTIC OCEAN
Shore Point
Season’
10
Miles
East
Distance from Shore
Center of EDS
25
Miles
East
50
Miles
East
75
Miles
East
100
Miles
East
125
Miles
East
Nantucket
Spring
Autumn
65%
30
45%
10
30%
5
25%
0—5
20%
0—5
20%
Near 0
15% (EDS 1)
Near 0 (EDS 1)
Nantucket Shoals
Spring
Winter
50
5
50
5
35
5
30
5
20
5
20
4—5
20 (EDS 2)
35 (EDS 3)
Near 0 (EDS 2)
Near 0 (EDS 3)
Davis South Shoal
Great South Bay 2
(Long Island)
Spring
Winter
Summer
Winter
55
10
95—100
30
50
10
75
15
35
5
10
Near 0
25
5
—
—
20
5
—
—
-
—
—
—
50 (EDS 4)
5—10 (EDS 4)
10 (EDS 5)
Near 0 (EDS 5)
Atlantic City
Spring
Winter
—
—
20
0—5
25
0—5
15
0—5
—
—
—
—
20 (EDS 6)
0—5 (EDS 6)
Fenwick Island
Spring
Winter
—
—
15
0—5
20
0—5
20
5
—
—
—
—
20 (EDS 7)
5 (EDS 7)
Chincoteague Inlet
Spring
Autumn
—
—
5
0—5
15
0—5
25
0—5
—
—
—
-
20 (EDS 8)
0-5 (EDS 8)
Cape Henry, Va.
Spring
Autumn
—
—
Near 0
Near 0
Near 0
Near 0
Near 0
Near 0
—
—
-
—
Near 0 (EnS 9)
Near 0 (EDS 9)
Cape Romain, S.C.
Spring
Autumn
—
—
95
Near 0
65
Near 0
Near 0
Near 0
—
—
—
—
95 (EDS 10)
Near 0 (EDS 10)
Savannah
Spring
Autumn
—
—
95—100
20
95
5
80
Near 0
20
Near 0
—
-
95—100 (EDS 11)
5 (EDS 11)
Fernandina Beach,
Fla.
Spring
Winter
—
—
95
15
60
10
25
Near 0
0—5
Near 0
-
90 (EDS 12)
15 (EDS 12)
Daytona Beach,
Fla.
Summer
Autumn
—
—
—
—
—
—
—
—
—
-
-
—
50 (EDS 13)
Near 0 (EDS 13)
— Computer model not run at this point.
1 Two seasons are listed for each area. In the first season, oil spilled has the highest
probability of reaching shore; in the second season, oil spilled has the lowest probability.
Probabilities are intermediate in the unlisted seasons.
2 The estimates for Great South Bay are distances south of the bay rather than east.
Source: Massachusetts Institute of Technology Department of Ocean Engineering.
38
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SECTION VI
POLLUTION CONTROL
Offshore pollution control measures are required by state and Federal
agencies. Federal regulatory bodies include the United States Geological
Survey and the Environmental Protection Agency. A summary of the Federal
and state regulations and/or standards is included in the appendix. The
primary emissions to the environment, requiring control, occur during
drilling and production operations. Prevention and control are emphasized.
Further control of normal operation emissions appear economically limited
by associated facility space/structure constraints.
GEOPHYSICAL SURVEYING
Discharges to the environment during geophysical exploration are not of
expressed concern in the oil and gas literature. Air emissions from survey
boats can be minimized by adjustment and timely maintenance of the engines.
Sanitary wastes from survey boats can be a problem in harbors but onboard
reduction, containment, and discharge to shore—based sanitary treatment
systems has reduced discharges to the water environment. Oily discharges
should not be a problem as the U.S. Coast Guard has established standards
which make it illegal to discharge oil of any kind within U.S. territorial
waters. (22)
EXPLORATORY AND DEVELOPMENT DRILLING
Pollution control practices are applied during offshore exploratory
and development drilling to both minimize the accident potential and
emissions from normal operations. Measures to minimize potential for blow—
outs and/or fires are most important to safe environmentally sound operations.
During drilling of development wells and/or workover operations, the primary
emissions to the air environment result from well testing and internal com-
bustion engines. The major emissions to the water environment being
controlled include the surface water disposal of drilling fluids/cuttings,
deck drainage, and sanitary wastes.
Control of Accidental Emissions
to the Environment
Modern practice in exploratory drilling is to use a variety of blowout
preventors to minimize the chances for loss of life, destruction of the
rig, loss of the well, and loss of products that can cause damage to the
39
-------
environment.( 20 ) In addition, API issued specifications in November, 1973,
covering design, manufacture, testing, installation, and operation of sub—
surface safety valves (surface and subsurface controlled) . (13) The USGS
requires the use of these criteria.
To minimize the potential for accidental losses of oil to the environ-
ment, the U.S. Geological Survey has established offshore development and
operation criteria. These OCS orders, which are summarized in the appendix,
are in some cases specific to the area of development. OCS Order #2
requires that the surface casing must be set to protect all fresh water
aquifiers. In California, a minimum surface casing depth of 1,000 feet is
required. OCS Order #2 also specifies the number and type of blowout pre—
ventors required. Under an assumption that half of the cost of these blowout
preventors is attributable to environmental protection, the cost per “typical
rig” has been estimated at 0.25 million.( 20 ) ocs orders #5 and #8 require
installation of various surface and subsurface controls to reduce the likeli-
hood of well and/or equipment failures. Pressure measurement at the drill
bit can also reduce the chances of blowouts.O- 3 ) OCS Order #7 provides for
an approved emergency oil pollution clean—up plan.
A number of choices are available to deal with accidental release of
oil into the environment——a spill. Present technology offers the following
options: (a) do nothing, (b) set fire to the oil or gas if it is not
already afire, (c) physical containment and removal, (d) dispersal, or (e)
sinking.( 13 ) Each of these alternatives is appropriate under selected con-
ditions. To date, no environmental damage has been observed to occur from
the accidental release of natural gas beyond the physical effects and/or fire
damages associated with blowouts. The following discussions deal with the
alternate techniques available for clean up of oil and oil products.
Leaving spills can be a viable or preferable option in offshore waters,
even though the same spill would require cleanup in a nearshore environment.
Small and rapidly spreading spills may not only be difficult to treat with
cleanup techniques but may be best left untreated. Such would be the case
of a small spill far offshore in rough seas under adverse weather conditions.
Burning of spilled oil is most often applied in conjunction with some
type of coxitainment technique. Burning of oil on water is incomplete and
produces large amounts of black smoke. This contribution to air pollution
may be intolerable nearshore but may not be considered prohibitive in an
offshore context. The burning of spilled oil as a means of removal does not
at present appear to be of widespread practicability.
Chemical agents can be applied to sink spilled oil, but the mass does
not remain stable and may move both vertically and horizontally. It is also
not chemically or biologically inert and the potential exists for increasing
or prolonging total toxicity by the introduction of the sinking chemicals.
The use of chemical dispersants presents the same sorts of potential
problems. In general, chemical depressants received a bad name in the early
period of their testing and development (such chemicals were used in the
Torey Canyon Spill) . Several of the compounds and subsequent emulsion
products proved to be more toxic than the oil. Present generation chemicals
40
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are significantly less toxic and are currently being used successfully in
Europe, particularly in the rough waters of the North Sea, where physical
approaches are often ineffective, without lasting ecological damage.
Physical recovery approaches range from devices and/or chemicals which
surround, draw together, lift off, or sponge up the oil from the water
surface. Success in use of these techniques is a function of the seas and
the time to deployment. Physical recovery is generally the best approach
to clean up in the nearshore area. The inland waters are frequently calmer
and deployment time of the large amounts of necessary equipment can be
minimal with required prior planning. Physical recovery nearshore remains
difficult in wave breaking stretches along the beaches where absorbent
materials for later recovery may be required.
Opinions differ concerning the relative merits of chemical dispersants
vs. physical containment and recovery. Further ecological and physiochemical
evidence from areas in which the various techniques have been applied is
required.
Control of Normal Operational Emissions
to the Air Environment
Most regulations require some control device to minimize the loss of
organic vapors into the atmosphere. Control equipment such as floating
roof and vapor recovery systems are used to control emissions from storage
tanks. The painting of storage tanks is also required as a means of
reducing losses.
Exploration and development drilling is generally thought to have a
relatively low potential for contribution to the air pollution problem.
Diesel engines can be adjusted so that visible emissions are within regu-
lations. The oil produced during well testing is not a substantial quantity
and can be discharged into holding tanks.
Control of Normal Operational Emissions
to the Water Environment
Emissions to the water environment which are being controlled include
drilling fluids/cuttings, deck drainage, and sanitary wastes. Criteria and
effluent regulations have been established or proposed to limit discharges
to the environment (see the appendix). Treatment costs are, comparably,
higher than for more stringent onshore requirements.
Drilling Fluids and Cuttings--—
The handling, treatment, and disposition methods for drilling fluids!
cuttings is regulated both by laws and the high cost of drilling muds. Shale
shakers, disilters, and desanders are used to separate the mud from cuttings.
The separated cuttings are normally dumped over the side following a washing
with a solvent—water mixture to cleanse them of surface oil (always
necessary when an oil—based mud is employed). The environmental effects of
this disposal approach is believed to be negligible. (18)
41
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Perhaps the major problem with the offshore dumping of waste muds and
cuttings is the increase of down current turbidity. For each well drilled,
it is reported that 300 tons of turbidity—producing materials are dis—
charged.(1 6 ) However, this estimate may be high as waste muds are commonly
left in dry holes and often used to fill the annulus between the casing and
tubing of completed production wells. Onshore it was recommended that
drilling mud not be discharged to surface waters. ( 36 )
Deck Drainage——
Deck drainage is controlled as OCS Order #7 requires that offshore
facilities must be curbed and have gutters and surge tanks to control storm
drainage. Installation costs have been estimated at near $100,000 per
offshore facility.( 20 ) Deck drainage can be treated by gravity separation
and/or by the coproduced water treatment system.O- 8 ) Spend acid and
fracturing fluids are also usually handled by the brine water treatment
system. Drip pans and separate sumps can be used to eliminate lubricating
oils and other oily wastes from the deck drainage. ( - 8 ’ 26 Waste crank case
oils can also be separately contained and transported to shore for further
disposition. (21)
Sanitary Wastes——
Since 1970, the offshore oil and gas industry has been required to
provide sewage treatment as its necessity, at least nearshore, is readily
apparent.( 24 ) Sewage treatment normally provided is physically very similar
to the common septic tank but with the addition of chlorination.( 16 )
Package type extended aeration treatment units are also used. Recommended
sizing criteria for offshore aeration systems is 10—20 lbs BOD/l,000 ft 3 ,
with clarification retentions of 4 to 6 hours (surface overflow rate <1,000
gpd/ft 2 ) and 30 minute chlorine contact retention C 4 times average flow).( 24 )
OSC Order #8 requires that sanitary effluents have a BOD <50 ppm,
suspended solids <150 ppm and a chlorine residual of about 1.0 mg/l. Such
effluent requirements are not considered stringent and generally should not
be difficult to meet. However, as the offshore sewage treatment plants are
often small and since their use due to operations can vary greatly, the
treatment plans are susceptible to overloading and/or “shock” loads
(especially hydraulic) and can be “killed” by toxic cleaners. ( 24 ) On an
average basis, BOD and SS removal ranges around 90 percent 8 ; well within
OSC Order #8 criteria. Recent EPA standards for offshore sanitary wastes
are less restrictive (see the appendix).
Representative costs for offshore sewage treatment have been summarized
as follows(18):
Total Annual
Number of (1973) Costs
Gal/Dai People ( $1,000 )
2,000 25 6,010
4,000 50 7,660
6,000 75 9,360
42
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Solid wastes are compacted and/or incinerated in burn baskets suspended
from the platform. Incombustibles are transported to shore for landfill
disposal. (16)
PRODUCTION
Pollution control practices are applied during offshore production to
both minimize the accident potential and normal operation emissions to the
environment. Control of accidental emissions has been discussed previously.
Flares/vents and evaporative losses from storage tanks are considered the
primary air emissions requiring control during production. During normal
operations, the possible emissions to the water environment requiring
control include treated coproduced brine discharges and generally of lesser
importance deck drainage and sanitary wastes.
Control of Normal Operational Emissions
to the Air Environment
The production of oil and gas is generally thought to have a relatively
low potential for contribution to the air pollution problem. Control of
evaporation from storage tanks is required. Reflection painting of tanks
to reduce insolation is often required. “Smokeless t ’ or nonluminous flares
are commercially available. The hydrocarbon emission rate is estimated to
be about 2 x i0 3 percent of the oil produced.( 26 ) Power demands are
normally less than during drilling. Diesel engines can be adjusted so that
visible emissions are within regulations.
Control of Normal Operational Emissions
to the Water Environment
Coproduced brines are the primary source of potential discharge to
water environment requiring control during production and regulations exist
for controlling associated effluent oil concentrations. Deck drainage and
sanitary wastes are also controlled during production and well workover
operations.
Environmental control practices on offshore facilities are dictated in
part by proximity of the development to the coast line. For example, the
production stream from the oil well in the Santa Barbara Channel is piped
to shore where the oil/water/gas separation is performed. When platforms
are some distance from shore, the phase separation is normally conducted
at the platform and only the gas and oil are shipped to land. Separate
losses of oil to the water environment, when controlled, have been estimated
to average about 4 x iO- percent of production.
Coproduced Basic Sediment and Water——
The total dissolved solids content of coproduced waters is normally
much higher than ambient surface waters but the major pollutant of expressed
concern is the oil concentration in coproduced waters. As inferred from
Table 23, metals and cyanides are not considered a major problem.
43
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TABLE 23. A COMPARISON OF PROPOSED TOXIC EFFLUENT STANDARDS AND SURVEYED 36
PRODUCTION PLATFORMS FOR TOXICANTS IN PRODUCED FORMATION WATER
Pro
posed Toxic
Effluent Standards
Surveyed Production
— Platform
Concentration,
mg/i
Concentration,
mg/i
Maximutnp ds/day
Toxicant
Low
Flow
All
Waters
Med1um
Flow
Fresh
(Tidal)
High
Flow
Fresh
(Tidal)
Mean Range
Stream
Lake Estuary
Coastal
Cadmium
0
0.004
(0.032)
0.040
(0.320)
12.96
10.8 86.4
102.6
0.068 O.5O—.262
Mercury
0
0.002
(0.010)
0.020
(0.100)
1.62
1.35 27.0
32.4
—— Traces
Cyanide
0
0.010
(0.010)
0.100
(0.100)
——
—— ——
——
0.010 0.010
) Propo
sed EPA reg
ulations (38
FR 35388,
December 27,
1973).
(b) Less than 10 cfa.
(c) Less than lOx waste stream.
(d) More than lOx waste stream.
-------
A wide range of control and treatment technologies have been employed
to reduce oil emissions. Heater—treaters for oil/water separation are
coimnonly used to separate “tight oil emulsions” and downhole chokes can
also be used to reduce formation of emulsions.O- 3 ) Treatment approaches
ending in a surface discharge include simple gravity separation, parallel
and loose media coalescers, and flotation cells. Gravity separation
approaches are the most prominent.
USGS OCS Order #8 requires that production waste water discharges must
average less than 50 ppm oil with a maximum value less than 100 ppm. The
U.S. EPA’s interim BPTCA and proposed BATEA effluent limitations on oil and
grease that be discharged to near—offshore and far—offshore waters are
given in the appendix.
The proposed BATEA limitations provide for no discharge to near—shore
waters of pollutants in produced waters. For far—offshore waters, BATEA
would limit discharges of oil and grease in produced waters to 30 mg/i
(average for 30 consecutive days) compared to BPTCA limits of 48 mg/i in
both offshore categories. Other sources of oil and grease discharges
affected by the BPTCA and BATEA limitations are deck drainage, drilling
muds, drill cuttings well treatment fluids, and produced sand.
The requirement and characteristics of offshore treatment approaches
can be summarized as follows:
• Tanks——the most widely used technology; often an effective
separation device; large area requirement limits capacity
• Flotation systems——either diffused gas or roto/disperser
systems offer good performance; they require electrical
energy, but have a relatively low operating cost
• Plate coalescers——require little space and no electrical
energy; subject to upset due to rapid changes in flow—rate;
also frequent cleaning results in high operating costs
• Fibrous and loose media coalescers——require frequent
backwashing or filter changing creating a secondary
disposal problem
• Chemicals——coagulating agents, demuisifiers, or polyelectrolytes
can serve to increase separation efficiencies.
Much work is reported in the literature concerning removal efforts,
costs, and problems in the application of the various configurations of
treatment equipment for control of oil discharges.(1 3,18,20,21, 27 , 37 ) The
best removal efficiencies are reported with air flotation cells with a
final discharge concentration of about 30 ppm. ( 38 ) However, parallel plate
coalescers, with an average discharge oil concentration of about 50 ppm( 21 -),
require the least area( - 8 ). Flotation equipment requires about twice the
area while loose and fibrous media coalescers need facility areas on the
45
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order of 10 times that of parallel plate coalescers.O- 8 ) Backwash wastes
from coalescer operations offshore also contribute to disposal problems. (21)
The major factor which appears to dominate the final wastewater oil
concentration is most often the available retention time provided. An
offshore facility retention time, which can be “economically ’ t provided, is
often considered as constrained by space (generally surface area) and/or
weight. For the Gulf of Mexico, the reported maximum storage capacity on
an individual platform is 10,000 barrels. Onshore where treatment space
area is less limiting, effluent oil concentrations below 10 mg/l can be
routinely achieved with large retention capacities; often greater than
40,000 bpd. 0 - 3 ) The retention capacity of most offshore equipment is
nearer to 1,000 bpd. To enhance oil/water separation, additional chemical
treatments can be used to artificially increase retention capacities.
However, for the treatment capacities normally provided of fshore, only a
15 to 20 percent increase in removal efficiencies can be gained. 1 8)
A review of recently collected offshore effluent data indicates that
test and laboratory variations can mask the field operation removal
efficiency differences in treatment system types.(1 8 , 2 1.) It is believed
that differences in sample collection, preparation, and analysis procedures
account for much of the noted variability. However, the observed greater
variability of test results as compared to treatment type performance
variability supports an opinion that effluent oil concentrations are
dominately controlled by offshore facility space constraints. A review of
the cost components in recent which contain estimates
of treatment costs, further support this observation. As needed, treatment
retention capacities increase in order to comply with established discharge
criteria offshore space requirements control treatment costs as unit space
costs average about $350 per square foot (for facilities at 200—foot
depths).(l 8 ) As an example, the following summary of BPT annual costs is
given below.
BPT Annual Costs (l0 Dollars)
Parallel Plate Coalescer Flotation
( iO BPD) Platform(a) Total Platform(b) Total
1 110.3 143.3 201.3 238.0
2 183.8 236.8 297.8 349.5
5 332.5 398.5 735.0 870.0
10 551.3 632.0 1,102.5 1,315.5
40 3,018.8 3,191.8 3,937.5 4,413.5
(a) 2.5 x (sum of parallel plate coalescer area and surge
tank area) x $350/ft 2 @ offshoredepthsof :200 ft.
(b) 2.5 x (sum of flotation unit, surge tank and generator
area) x $350/ft 2 @ offshoredepthsof 200 ft.
BPT brine disposal costs have been estimated to run about 2 percent of net
oil sales for onshore operations. (26)
46
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Subsurface Injection of Coproduced Brine—--
As an alternative to a surface discharge, coproduced bines can be
injected into a subsurface formation. Brines may also be reinjected into
the oil reservoir for the purposes of secondary recovery. Current industry
practice is to apply minimal or no treatment to reinjection water prior to
disposition. If treatment is required, it normally consists of addition of
a corrosion inhibitor and a bacteriocide. Water used for reinjection must
also be free of suspended matter, chemically stable, and be anoxic. A
typical injection system consists of a surge tank, flotation cell, filters,
retention tank, injection pumps, and well. (21)
As is the case for oil well development casing needs, extensive geologic
and engineering studies are required to minimize the potential of damage to
freshwater horizons.( 38 ) For wastewater flows of 5,000 to 10,000 bpd, costs
for reinjection offshore have been estimated at $1 million and $40 thousand
for capital and operation maintenance costs, respectively. Coastal rein—
jection costs are near $0.25 million and $20 thousand . ( 36 ) Reported ratios
of offshore subsurface reinjection costs to surface treatment costs range
from less than 6.5 to about 9.0.O 8,27) Costs of onshore reinjection are
roughly comparable to the cost of the offshore surface discharge.
Treatment costs of deep well injection could be reduced as the
secondary oil recovery efforts increase. However, the deeper well oil
formation reinjection operation requirements must be considered. A corn—
parison of reported surface discharge treatment costs and shallow well
injection costs is shown below.
Total Annual Costs (iO 1973 Dollars)
Surface Discharge(a) Shallow Well Injection
( 103 BPD) Treatment Onshore(b) Of fshore(C )
1 20.5 ——
5 10—40 24.6 139
10 15—65 30.2 176
40 30—140 289
(a) Range of costs associated with use of parallel plate
coalescers, flotation systems with or without equali—
zation and desanding.
(b) With standby lined pond.
(c) With filtration and desanding.
Sand Disposition——
As essentially no sand is coproduced with oil offshore of Alaska, its
disposal has not been a problem. Sand from offshore California is separated
on land. Separated sand in the Gulf operations is normally disposed to
surface water, but the sand must be purged of surface oil prior to discharge
to ambient waters.
47
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REFERENCES
1. Wagner, Fred J., “North American Drilling Activity in 1974”, Bulletin,
AAPG, (8) August, 1975, 1273—1310.
2. Battelle—Columbus Laboratories, “Development Potential of 13.5.
Continental Shelves”, U.S. Department of Commerce, Environmental
Science Services Administration, April, 1966.
3. Oil and Gas Journal , December 26, 1976, p 114.
4. Battelle—Columbus Laboratories, “The Economic Impact of Environmental
Regulations on the Petroleum Industry——Phase II Study”, Draft Final
Report to American Petroleum Institute, February 13, 1976.
5. King, Robert E., “World—Wide Offshore Oil and Gas Prospects and
Potential”, Ocean Industry , April, 1976, pp 37—43.
6. Oil and Gas Journal , December 12, 1973, p 23.
7. Oil and Gas Journal , June 16, 1975, p 41.
8. Oil and Gas Journal , October 20, 1975, p 39.
9. Oil and Gas Journal , December 15, 1975, p 41.
10. Oil and Gas Journal , January 19, 1976, p 20.
11. McNabb, Dan, “Gas Find Reported on South Texas OCS”, Oil and Gas
Journal , October 27, 1975, pp 46—47.
12. Oil and Gas Journal , November 17, 1975, p 37.
13. Council on Environmental Quality, “OCS Oil and Gas——An Environmental
Assessment, A Report to the President”, Volumes 2—5, U.S. Government
Printing Office, April, 1974.
14. “Offshore Segment of the Oil and Gas Extraction Point Source Category”,
Federal Register , 40 (179), Part 435, 42543—42550, 42573—42577,
September 15, 1975.
15. U.S. Department of the Interior, “Draft Environmental Statement——
Proposed Increase in Acreage to be Offered for Oil and Gas Leasing
on the Outer Continental Shelf”, Volume 2; DES—74—90.
48
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16. U.S. Department of the Interior, “Final Environmental State——Proposed
1974 Outer Continental Shelf Oil and Gas General Lease Sale, Offshore
Louisiana”, Volume 1, FES—74—41.
17. Bettge, G. W., “Zinc Carbonate Can Control H2S in Drilling Mud”, Oil
and Gas Journal , August 18, 1975, pp 128—132.
18. U.S. Environmental Protection Agency, “Draft Development Document for
Effluent Limitations Guidelines and New Source Performance Standards
for the Oil and Gas Extraction Point Source Category”, October, 1974.
19. Smith, R. S., “Support Facilities Affect Platform Structural Design”,
Oil and Gas Journal , August 18, 1975, pp 120—126.
20. Battelle—Columbus Laboratories, “The Economic Impact of Environmental
Regulations on the Petroleum Industry——Phase II Study”, Draft Final
Report to American Petroleum Institute, February 13, 1976.
21. Battelle—Columbus Laboratories, “Cost of Implementation and Capabilities
of Available Technology to Comply with P.L. 92—500”, Report to National
Commission of Water Quality, Volume I, Industry 3 — Petroleum and Gas
Extraction, July 3, 1975.
22. U.S. Department of the Interior, “Final Environmental Statement——
Proposed 1975 Outer Continental Shelf Oil and Gas General Lease,
Offshore Central Gulf”, Volume 2, DES 74—110.
23. U.S. Department of the Interior, “Final Environmental Statement——
Proposed 1974 Outer Continental Shelf Oil and Gas General Lease Sales,
Offshore Texas”, Volume I, FES 74—14.
24. Lintfield and Hunter, Inc., “Treatment of Domestic Sewage at Offshore
Locations”, Proceedings of the 8th Mississippi Water Resources
Conference, April 10—li, 1973.
25. U.S. Department of the Interior, “Draft Environmental Impact Statement——
Outer Continental Shelf, Northern Gulf of Alaska”, June, 1975.
26. Battelle—Columbus Laboratories, “Environmental Considerations in Future
Energy Growth, Volume I: Fuel/Energy Systems, Technical Summaries and
Associated Environmental Burdens”, Report to U.S. EPA, April, 1973.
27. Brown and Root, Inc., “Potential Impact for Produced Water Discharges
From Offshore and Coastal Oil and Gas Extraction Industry”, October,
1972.
28. U.S. Department of the Interior, “Draft Environmental Statement——
Proposed 1975 Outer Continental Shelf Oil and Gas General Lease,
Offshore Central Gulf”, Volume I, FES 74—110.
49
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29. U.S. Department of the Interior, “Draft Environmental Statement——
Proposed Increase in Acreage to be Offered for Oil and Gas Leasing
on the Outer Continental Shelf”, Volume I, DES 74—90.
30. Kash, D. K., et al., “Energy Under the Oceans——A Technology Assessment
of the Outer Continental Shelf Oil and Gas Operations”, University of
Oklahoma Press, 1973.
31. “Assessing Potential Ocean Pollutants”, A Report of the Study Panel on
Assessing Potential Ocean Pollutants to the Ocean Affairs Board
Commission on Natural Resources, National Research Council, National
Academy of Sciences, Washington, D.C., 1975.
32. U.S. Department of the Interior, “Final Environmental Statement——
Proposed 1975 Outer Continental Shelf Oil and Gas General Lease,
Offshore, Texas”, Volume I, FES 74—63.
33. “Water Problems Associated with Oil Production in the United States”,
Interstate Oil Compact Commission (prior to 1970).
34. “Man’s Impact on the Global Environment——Assessment and Recommendations
for Action”, Report of the Study of Critical Environmental Problems
(SCEP), MIT Press, 1970.
35. Battelle Memorial Institute, Richiand, Washington, “Oil Spillage Study
Literature Search and Critical Evaluation for Selection of Promising
Techniques to Control and Prevent Damage”, November 20, 1967.
36. Reid, G. W., et al., “Brine Disposal Treatment Practices Relating to
the Oil Production Industry”, Oklahoma University, May, 1974.
37. Smith, R. S., “Water Treatment Design Important”, Oil and Gas Journal ,
September 1, 1975, pp 113—116.
38. “Environmental Conservation, The Oil and Gas Industries”, Volume 2,
National Petroleum Council’s Committee on Environmental Conservation,
February, 1972.
39. “Outer Continental Shelf Resource Development Safety, A Review of
Technology and Regulation for the Systematic Minimization of Environ-
mental Intrusion”, Panel on Operational Safety Offshore Resource
Development for U.S. Geological Survey, December, 1972.
40. Code of Federal Register, Title 30 Mineral Resources, revised as of
July 1, 1975, Part 250, pp 565—581.
41. U.S. Department of the Interior, Proposed OCS Orders for Gulf of Alaska,
Federal Register, Volume 40, No. 3, January 6, 1975, pp 1086—1107.
42. Bureau of National Affairs, Inc., Environmental Reporter, State Water
Laws.
50
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APPENDIX
OFFSHORE REGULATIONS AND DISCHARGE LIMITATIONS
The majority of regulations which are designed to control oil and gas
production waste emission to the air and water environment fall into three
broad categories: USGS OCS orders, EPA effluent guidelines, and State
requirements. As gleaned from short review of these “regulations”, the OCS
orders apply only to the waters in areas beyond the historic state limits,
and state requirements to areas with state U.S. EPA effluent limitations
are subcategorized by near—offshore (state waters) and far—offshore (sea-
ward from state waters).
OCS ORDERS
Originally, the USGS OCS orders related primarily to safety. Lack of
specific guidance, standards, tests, etc. rendered the OCS orders inadequate
to protect the public interest.( 39 ) Recent updates of the OCS orders are
more specific. The “USGS Area Supervisor” is solely empowered by law to
judge the “substantialness” of waste emissions to the air and water environ—
ment.
The OCS orders for the Gulf, West, and Alaska coasts are basically
similar.( 394 -) In fact, the first nine orders relate to the same subjects
as follows:
• Marking of wells, platforms, and structures
• Drilling procedures
• Plugging and abandonment of wells
• Suspensions and determination of well producibility
• Installation of subsurface safety, devices
• Procedures for completion of oil and gas wells
• Pollution and waste disposal
• Approval procedure for installation and operation
• Approval procedure for oil and gas pipelines.
51
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The West Coast OCS order #10 concerns drilling of twin case holes. The
Gulf OCS orders #10—12 relate to sulfur drilling off Louisiana and Texas
interim oil and gas production rates, and public inspection of records.( 9 )
Topics of Alaska OCS orders #11 and #12 generally correspond to the same
numbered orders for the Gulf of Mexico.
Operator reports and on—site inspections are employed for improving
compliance with OCS orders. The frequency rate for inspections is approxi-
mately one every 9 months.( 28 ) The warnings and suspensions issued by the
USGS area inspectors in the Gulf during December 1, 1972, through September
30, 1974, are as follows:
Warnings Suspensions
Drilling 48 34
Workover 9 6
Production 3,525 2,294
All malfunctions reported as identified during special in 9 ections averaged
about 4 percent of the equipment tested during l971—1973. ( 9)
EPA REGULATIONS AND EFFLUENT LIMITATIONS
There are no EPA standards governing air emission attendant with of f—
shore drilling and production. Legislation addressing nondegradation could
perhaps be utilized, but impact of the exhaust from stationary power units
and service vessels is generally thought to be insi nfficant. (2i) With
regard to water quality, the EPA in September, 1975(14), established a point
source category for offshore oil and gas extraction and issued in interim
final form BPTCA effluent limitations and guidelines for two existing source
subcategories: (1) near offshore (state water, i.e., territorial seas
excluding Great Lakes), and (2) far—offshore (Federal waters, i.e., all
waters seaward from the territorial seas). These effluent limitations are
given in Table 24. The term “Nb ” refers to offshore facilities manned
by 10 or more persons on a continuous basis. N9IN refers to offshore
facilities continuously manned by 9 or less persons, or intermittently
manned by any number of persons.
The EPA in September, 1975(14), proposed effluent limitations pertaining
to the near and far—offshore subcategories for BATEA, and pretreatment
standards, and new sources. The proposed BATEA effluent limitations are
shown in Table 25. Proposed limitations for new sources are the same as
those for BATEA.
STATE REGULATIONS TO CONTROL AIR EMISSIONS
No state regulations specifically designed to control air emissions
from offshore drilling operations were located. Regulations such as open
burning restrictions, visible emissions, and volatile organic substance
52
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TABLE 24. BPCTA EFFLUENT LIMITATIONS:
NEAR- AND FAR-OFFSHORE
Oil
and Grease
Average of Daily
Maximum for
Values for 30 Con—
Residual Chlorine
any 1 d,
secutive Days Shall
Minimum for any 1
Pollutant Parameter
Milligram
Not Exceed Milligram
d, Milligram
Waste Source
Per Liter
Per Liter
Per Liter
Produced Water
72
48
NA
Deck Drainage
72
48
NA
Drilling Muds
(a)
(a)
NA
Drill Cuttings
(a)
(a)
NA
Well Treatment
(a)
(a)
NA
Sanitary
Ml0
NA
NA
(b)l
M91M(c)
NA
NA
NA
Domestic(c)
NA
NA
NA
Produced Sand
(a)
(a)
NA
(a) No discharge of free oil.
(b) Minimum of 1 mg/i and maintained as close to this concentration as
possible.
(c) There shall be no floating solids as a result of the discharge of these
wastes.
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TABLE 25. PROPOSED BATEA EFFLUENT LIMITATIONS
Oil and Grease
Average of Daily
Maximum for Values for 30 Con— Residual Chlorine
any 1 d, secutive Days Shall Minimum for any 1
Milligram Not Exceed Milligram d, Milligram
Per Liter Per Liter Per Liter
Deck Drainage
Near—Offshore
72 48 NA
Drilling Muds
(a) (a) NA
Drill Cuttings
(a) (a) NA
Well Treatment
(a) (a) NA
Sanitary
MlO
NA NA (b)l
M91M
NA NA NA
Domestic(C)
NA NA NA
Produced Sand
(a) (a) NA
Produced Water
No dischar e of waste water pollutants to navigable
waters Cd).
Produced Water
Far—Offshore
52 30 NA
Deck Drainage
52 30 NA
Drilling Muds
(a) (a) NA
Drill Cuttings
(a) (a) NA
Well Treatment
(a) (a) NA
Sanitary
M1O
M91M(’)
NA NA (b)l
NA NA NA
Domestic(b)
NA NA NA
Produced Sand
(a) (a) NA
(a) No discharge of free oil.
(b) Minimum of 1 mg/i and maintained as close to this concentration as
possible.
(c) There shall be no floating solids as a result of the discharge of these
wastes.
(d) In the event that a permit under Sec. l421(b)(2) of the Safe Drinking
Water Act is refused and there is no other reasonable means of disposal
available that would comply with the BATEA standard for State waters,
then the BATEA standard for Federal waters shall apply.
54
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storage are most often utilized to control, reduce, or eliminate emissions
from onshore oil and gas drilling operations.
“Open burning” means the burning of any material such that the products
of combustion are emitted directly into the atmosphere without passing
through a stack or flare. Most states prohibit the open burning of oil
wastes. “Volatile organic substance” means any organic substance, mixture
of organic substances, including but not limited to, petroleum crudes,
petroleum fractions, petrochemicals, solvents, diluents, and thinners.
Visible emission regulations are expressed as percent opacity or
Rengelmann number. The following table shows the Rengelmann number vs.
percent opacity:
Ringelmann Number Percent Opacity
.5 10
1.0 20
1.5 30
2.0 40
3.0 60
4.0 80
5.0 100
Most states use the 20 percent opacity for all sources, although some states
still permit higher emission for older equipment. “Opacity” means the
characteristic of a substance which render it partially or wholly opague to
transmittance of light and causes obstruction to an observer’s view.
STATE CRITERIA AND REGULATIONS TO
CONTROL WATER EMISSIONS
The water criteria and regulations of nine states were sampled and
briefly reviewed.( 42 The “regulations” are summarized as they relate to
oil, settleable solids, turbidity, and heavy metals. Applicability of
criteria to oil and gas extraction in offshore waters was often not readily
discernible.
Oil
Alaska——
Public water suppiy——below normally detectable amounts.
Swimming——no visible concentrations of oil sludge that may adversely
affect use indicated.
Fish and wildlife——none permitted.
Shellfish——no visible evidence of wastes. Less than acute or chronic
problem levels.
55
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Agriculture——none in sufficient quantities to cause soil plugging.
Industrial——no visible evidence.
California——
Varies from basin to basin, but generally of following type. The waters
shall be free from floating debris, oil, scum, grease, or other carried or
floating materials. Phenolic compounds must be less than 0.5 and 1.0 mg/i
50 and 10 percent of the time sampled, respectively.
Florida——
Free from floating debris, oil, scum, and other floating materials
attributable to municipal, industrial, agricultural, or other discharge
in amounts sufficient to be unsightly or deleterious. Shall not exceed
15 mg/l or that no visible oil defined as iridescence be present to cause
taste and odors or interfere with other beneficial uses.
Georgia——
All waters shall be free from oil, scum, and floating debris associated
with municipal or domestic sewage, industrial waste, or other discharges
in amounts sufficient to be unsightly or to interfere with legitimate water
uses.
Louisiana——
There shall be no slicks of free or floating oil present in sufficient
quantities to interfere with the designated uses, and emulsified oil cannot
be present in sufficient quantities to interfere with the designated uses.
Massachusetts——
Bathing, shellfish, industrial waters none allowable. In recreational
boating and secondary contact recreation, aesthetic enjoyment waters none
allowable except those amounts that may result from the discharge from
waste treatment facilities providing appropriate treatment.
New York--
In waters for recreation and fishing, none which are readily visible
and attributable to sewage, industrial wastes or other wastes of which
deleteriously increase the amounts of these constituents in receiving
waters after opportunity for reasonable dilution and mixture with the
wastes discharged thereto.
None alone or in combination with other substances or wastes in suf-
ficient amounts or at such temperatures as to be injurious to fish life,
make the waters unsafe or unsuitable as a source of water supply for
drinking, culinary or food processing purposes, or impair the waters for
any other best usage as determined for the specific waters which are
assigned to this class.
Texas——
Substantially free from oil.
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Settleable Solids
California——
(Statement varies among the 32 regional water boards but generally
limits settleable solids as follows.) Less than the concentration that
would change the physical nature of the stream bottom or adversely affect
the aquatic environment.
Florida——
Minimum conditions of all waters; all waters shall be free from settle—
able substances——substances attributable to municipal, industrial, agri—
cultural, or other discharges that will settle to form putrescent or
otherwise objectionable sludge deposits.
Georgia——
All waters of the state shall be free from materials associated with
municipal or domestic sewage, industrial waste, or any other waste which
will settle to form sludge deposits that become putrescent, unsightly, or
otherwise objectionable.
Louisiana——
None that will produce distinctly visible turbidity, solids or scum,
nor shall there be any formation of slimes, bottom deposits, or sludge
banks, attributable to waste discharges.
Massachusetts—---
Public water supplies and recreation——none allowable. All other clas-
sifications which are sludge deposits, solid refuse, floating solids, oils,
grease, and scum——non allowable except those amounts that may result from
the discharge from waste treatment facilities providing appropriate treat-
ment.
New York--
In Public Water Supply and Shellfish waters——none attributable to
sewage, industrial wastes, or other wastes. All other classes——none which
are readily visible and attributable to sewage, industrial wastes, or other
wastes, or which deleteriously increase the amounts of these constituents
in receiving waters after opportunity for reasonable dilution and mixture
with the wastes discharged thereto.
New Jersey——
None noticeable in the water or deposited along the shore or on the
aquatic substrate in quantities detrimental to the natural biota. None
which would render the waters unsuitable for the designated uses.
Texas——
All waters of the state shall be essentially free of floating debris
and settleable suspended solids conducive to the production of predescri1 ble
sludge deposits or sediment layers which would adversely affect benthic
biota or other lawful uses. Essentially free of settleable suspended solids
57
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conducive to changes in the flow character of stream bottoms, to the untimely
filling of reservoirs and lakes, which might result in unnecessary dredging
costs.
Turbidity
Alaska——
Swimming——25 JTU (Jackson Turbidity Units)
Fish and wildlife—--25 JTU
Shellfish——25 JTU.
California——
Light penetration shall not be significantly impaired by suspended or
floating matter of other than natural origin. There shall be no turbidity
other than of natural origin that will cause substantial visible contrast
with the natural appearance of the water.
Louisiana——
No discharges that will produce distinctly visible turbidity, solids
or scum, nor shall there be any formation of slimes, bottom deposits, or
sludge bank attributable to waste discharges.
Massachusetts——
Freshwater——none in such concentrations that would impair specified
usages.
New Jersey——
None noticeable in the water or deposited along the shore or on the
aquatic substrate in quantities detrimental to the natural biota. None
which would render the waters unsuitable for the designated uses.
Metals
Alaska——
USPHS Standards Class B water supply
All toxic materials, Narrative Recreation
including metals statement Growth propogation of
fish and other aquatic
wildlife, agriculture,
industry.
All toxic materials, including narrative statement, shellfish metals,
pesticides (heavy metal constituents) 0.001 of the LC 50 for the most
sensitive organisms on 96—hr exposure.
58
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California——
Effluent Quality Requirements for
Ocean Waters of Caiifornia(1 8 )
Concentration not to be
Unit of Exceeded More Than:
Measurement 50% of Time 10% of Time
Arsenic mg/i 0.01 0.02
Cadmium mg/i 0.02 0.03
Total Chromium mg/i 0.005 0.01
Copper mg/i 0.2 0.3
Lead mg/i 0.1 0.2
Mercury mg/i 0.001 0.002
Nickel mg/i 0.1 0.2
Siiver mg/i 0.02 0.04
Zinc mg/i 0.3 0.5
Florida——
Criteria
Metal Value in mg/i
Copper 0.50
Zinc 1.0
Chromium (hexavalent) 0.50
Chromium (total) 1.0 (in effluent)
0.05 (after mixing)
Lead 0.05
Iron 0.30
Louisiana——
All toxic materials, including metals: 0.1 48—hr TLM.
59
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TECHNICAL REPORT DATA
(Please read Inwuctions on the re ’erse before co,npleting,1
1. REPORT NO. 2.
EPA—600/7—77—080
3. RECiPIENT’S ACCESSI0 NO.
4. TITLE AND SUBTITLE
Offshore Oil And Gas Extraction
An Environmental Review
5. REPORT DATE
.Ttily 1977 issiiin t ’1t tp
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
N. A. Frazier, B, L. Naase, R. Clark
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Battelle
Columbus Laboratories
Columbus, Ohio 43201
10. PROGRAM ELEMENT NO.
EHE 623
11. CONTRACT/GRANT NO.
68—02—1323
12. SPONSORING AGENCY NAME AND ADDRESS
Industrial Environmental Research Laboratory—Cin.,OH
Office of Research and Development
U.S. Environmental Protection Agency
Cincinnati, Ohio 45268
13. TYPE OF REPORT AND PERIOD COVERED
Final
14. SPONSORING AGENCY CODE
EPA/600/12
15. SUPPLEMENTARY NOTES
16. ABSTRACT
Reported are the results of an environmental review of emission sources and
emissions associated with U.S. offshore oil and gas exploration, drilling, and
production. The purpose of the review was to rank technological problems of
controlling these emissions. Existing or proposed effluent limitations reflect
BPTCA and BATEA technologies for controlling oil in effluents to near and offshore
waters. No firm basis could be developed for ranking technological problems of
controlling other possible emissions to the environment. Conclusions of the small
study are that additional information is needed on the fate and effect of other
possible pollutants, mainly metals, that might be in discharges to offshore waters
and on quantitative evaluations of air emission sources. In the information reviewed,
greatest environmental concern was with accidental spills of oil that can occur
during drilling and production. Little or no environmental concern with air emission
sources was noted in the information reviewed.
17 KEY WORDS AND DOCUMENT ANALYSIS
5. DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
C. COSATI Field/Group
Offshore Structures, Exploration, Vapors,
Production, Drilling, Air, Water, Gases,
Emission, Offshore Drilling, Oil Recovery,
Air Pollution, Water Pollution
13B
18. DISTRIBUTION STATEMENT
Release to the public
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
68
20.SECURITYCLASS(Thi spage)
Unclassified
22.PRICE
EPA Form 2220-1 (9-73) 60
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