-------
Composition. Prior to the initiation -of this program, very
little data existed on the composition of produced water other
than the conventional parameters which have been studied in
earlier programs. Therefore, the Agency embarked on a systematic
effluent survey to identify and quantify the characteristics of
produced water with- regard to priority toxic pollutants.
Specific characteristics of these wastes are highly dependent on
geographical location. Therefore, separate discussions are pro-
vided on specific characteristics of wastes as obtained in
sampling programs conducted in the three major offshore producing
areas of the United States, i.e., the Gulf of Mexico, Alaska and
California.
The first study consisted of a preliminary screening survey con-
ducted at 6 platforms in the Gulf of Mexico to determine the
presence or absence of priority pollutants in produced water
discharges. The results of this study indicated that consider-
able quantities of organic priority pollutants (including: ben-
zene, ethylbenzene, toluene, phenol and naphthalene) and metallic
priority pollutants (such as chromium, lead, nickel and zinc)
were almost universally present in produced water. In addition
to the indication that priority pollutants were present, this
study also provided information necessary for the development of
the analytical protocols which would be utilized in the full-
scale survey. In a separate effort during this time period, the
Agency concluded the development of an improved analytical proto-
col for the analysis of organic priority pollutants. This
improved method, however, had not been tested with highly saline
effluents such as oil field brine for which the total dissolved
solids is typically several times greater than that of seawater.
For this purpose, a limited sampling program was conducted at two
platforms with the resulting samples sent to 10 laboratories
(both private and industry) to determine if any unforeseen
problems could arise in the full-scale program. As a result of
-119-
-------
this study, some modifications to the original analytical methods
were developed. A complete description of the analytical methods
utilized and the modifications to these methods where required
are contained in the data evaluation reports which are referenced
in the following sections that summarize the information obtained
in the Gulf of Mexico/ Alaska and California verification
sampling programs.
Gulf of Mexico Sampling Program - During the period of October 9
through October 30, 1981, 30 oil and gas production platforms
located in the Gulf of Mexico were sampled to characterize the
quantities of selected conventional, non-conventional and pri-
ority pollutants present in their produced brine discharges
[174], Table 7-17 presents the production characteristics of the
30 sites selected. Overall, 79 individual samples were collected
and analyzed for the parameters listed in Table V-18. Twenty of
the 79 samples collected were obtained from the influent to the
platform treatment system indicated on Table V-17, while the
remaining 59 were treated effluent samples. Table 7-19 presents
an overall summary of occurrence of the organic priority pollu-
tants detected in the effluents. As can be seen from this table,
benzene, ethylbenzene, naphthalene, phenol, toluene,
2,4-dimethylphenol and bis-(2-ethylhexyl) phthalate were observed
in over 50 percent of the effluent samples analyzed. The plat-
form average values of these pollutants are summarized in Table
7-20. An additional 15 organics were detected far less fre-
quently. The occurrence for these parameters ranged from 2 to 32
percent of the effluent samples analyzed. Table 7-21 presents
the overall summary of occurrence for the metallic priority
pollutants while Table 7-22 contains concentrations of metals in
the effluents. As can be noted from this table, zinc is the only
metal regularly measured above the Lowest Reportable 7alue (a
measure of the sensitivity of the method). The platform average
values for the conventional and non-conventional parameters ana-
lyzed are presented in Table 7-23.
-120-
-------
TABLE V-17
CHARACTERISTICS OF PLATFORMS SELECTED
FOR THE GULF OF MEXICO SAMPLING PROGRAM [174]
Number Platform
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
EC
EC
V 1
33A
14CF
19D
V 255A
SMI
23B
V 390
SMI
El
SMI
El
SMI
El
El
£1
El
SS
SS
SS
ST
BM
BDC
ST
WD
WD
WD
GIB
WD
SP
SP
SP
6A
57A-E
115A
120CF
130B
208B
18CF
238A
296B
107(394)
107(393)
219A
177
2C
CF5
135
90A
45E
701
DB600
105C
62A
24/27
65B
Company
Conoco
Mobil
Conoco
Shell
Gulf
Shell
Exxon
Marathon
Shell
Mobil
Shell
Conoco
Shell
Gulf
Placid
Chevron
Chevron
Amoco
Gulf
Shell
Texaco
Gulf
Amoco
Conoco
Conoco
Texaco
Shell
Shell
Shell
Shell
Oil/Con-
densate
(bbl/d)
76.6
807
890
950
228
395
250
1200
750
3500( 1)
21500
1501
2000
40
1500
501
2875
3000
2800
10794
873
6000
2244
745
5273
554
2091
1800
24000
5000
Gas
(MMCF/d)
15.
13.
3.
14
13.
38
0.
150
45
5(
63
0.
30
6
100
1.
5.
7
10
11.
2.
18
10.
2.
15.
0.
12.
1 .
40
8
2
1
4
8
2
1)
2
2
0
7
8
7
3
5
1
1
3
Brine
M bbl/d)
62
2005
2817
1298
495
634
625
500-2000
1200
2000( D
9733
350
22000
2
1470
4610
12500
800-1000
1072
6590
11028
8400
15000
1578
10721
3796
7532
3100
150000
3000
Treatment (2)
OS and
OS
OS and
DISP
OS and
OS and
OS"
OS
OS and
OS and
OS and
DISP
OS and
DISP
OS and
DISP
DISP
OS
DISP
OS and
OS and
DISP
OS and
DISP
DISP
OS and
DISP
OS and
OS and
OS and
DISS
DISP
DISP
DISP
DISP
DISS
DISP
DISS
DISS
DISP
DISP
DISP
DISP
DISS
DISP
DISP
(1) Value for Sampling Period
(2) os « Oil Skimming; DISS = Dissolved Gas Flotation;
DISP » Dispersed Gas Flotation
-121-
-------
TABLE V-18
COMPOUNDS ANALYZED IN THE
GULF OF MEXICO SAMPLING PROGRAM [174]
Fraction
Tradi-
tional s
Volatiles
Compound Name
Chloride
Iron
Oil & Grease
Total Diss. Solids
Ac role in
Acrylonitrile
Fraction Compound Name
Semi- Di-N-8utyl Phthalate
Volatiles Di-N-Octyl Phthalate
Dibenzo( A, H) Anthracene
Diethyl Phthalate
Fluoranthene
Fluorene
Hexachlorobenzene
Fraction Compound Name
Metals Cadmium
Chromium
Copper
Lead
Nickel
Silver
Zinc
Semi-
Volatilea
Benzene
Bis (Chloromethyl)Ether
Bromoform
Carbon Tetrachlonde
Chlorobenzene
Chlorodibromomethane
Chloroethane
Chloroform
Dichlorobromomethane
Dichlorodifluoromethane
Ethylbenzene
Methyl Bromide
Methyl Chloride
Methylene Chloride
Tetrachloroethylene
Toluene
Trichloroethylene
Tnchlorofluoromethane
Vinyl Chloride
1,1-Oichloroethane
1,1-Oichloroethylene
1,1,1-Tnchloroethane
1,1,2-Tnchloroethane
1,1,2,2-Tetrachloroethane
1,2-Dichloroethane
1,2-Dichloropropane
1,2-Trans-Oichloroethylene
1,3-Dichloropropylene
2-Chloroethyl Vinyl Ether
Acenaphthene
Acenaphthylene
Anthracene
Benzidine
Benzo(A) Pyrene
Bis(2-Chloroethoxy) Methane
8is(2-Chloroethyl) Ether
8i3(2-Chloroisopropyl) Ether
Bis(2-Ethylhexyl) Phthalate
Butyl Benzyl Phthalate
Chrysene
Hexachlorobutadiene
Hexachlorocyclopentadiene
Hexachloroethane
Indeno (1,2,3-C,D) Pyrene
Isophorone
N-Nitrosodi-N-Propylamine
N-Nitrosodimethylamine
N-Nitrosodiphenylamine
Naphthalene
Nitrobenzene
P-Chloro-M-Cresol
Pentachlorophenol
Phenanthrene
Phenol
Pyrene
1,12-8enzoperylene
1,2-Benzanthracene
1,2-Oichlorobenzene
1,2-Oiphenylhydrazine
1,2,4-Tnchlorobenzene
1,3-Dichlorobenzene
1,4-Dichlorobenzene
11,12-8enzofluo rant Irene
2-Chloronaphthalene
2-Chlorophenol
2-Nitrophenol
2,4-Oichlorophenol
2,4-Dimethylphenol
2,4-Oimtrophenol
2,4-Oinitrotoluene
2,4,6-Trichlorophenol
2,6-Dinitrotoluene
3,3-Dichlorobenzidine
3,4-8enzofluoranthene
4-8roniophenyl Phenyl Ether
4-Chlorophenyl Phenyl Ether
4-Nitrophenol
4,6-Dimtro-O-Cresol
-122-
-------
TABLE V-19
PERCENT OCCURRENCE OF ORGANICS
FOR TREATED EFFLUENT SAMPLES
GULF OF MEXICO SAMPLING PROGRAM [174]
PARAMETER ( 1 )
Benzene
Ethylbenzene
Naphthalene
Phenol
Toluene
2 , 4-Dimethylphenol
Bis (2-Ethylhexyl) Phthalate
Di-N-Butyl Phthalate
Fluorene
Diethyl Phthalate
Anthracene
Acenaphthene
Benzo(A) Pyrene
P-Chloro-M-Cresol
Dibenzo (A,H) Anthracene
Chlorobenzene
Di-N-Octyl Phthalate
3 , 4-Benzof luoranthene
11,1 2-Benzof luoranthene
Pentachlorophenol
1 , 1-Dichloroethane
Bis ( 2-Chloroethyl) Ether
NUMBER OF (2)
VALID
DETERMINATIONS
59
59
59
58
59
56
•59
59
59
59
29
59
59
59
59
59
59
59
59
59
59
59
NUMBER
OF TIMES
DETECTED
59
59
59
58
59
52
47
19
13
12
3
4
3
1
1
1
1
1
1
1
1
1
PERCENT
OF TIMES
DETECTED
100
100
100
100
100
93
80
32
22
20
10
7
5
2
2
2
2
2
2
2
2
2
(1) - Pollutants not listed were never detected
(2) - Number of samples which yielded valid analytical results
-123-
-------
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-124-
-------
TABLE V-21
PERCENT OCCURRENCE OF METALS
FOR TREATED EFFLUENT SAMPLES
GULF OF MEXICO SAMPLING PROGRAM [174]
PARAMETER
Zinc
Copper
Nickel
Lead
Cadmium
Chromium
Silver
NUMBER OF( 1 )
VALID
DETERMINATIONS
53
53
53
59
59
59
53
NUMBER(2)
OF TIMES
DETECTED
43
10
3
2
1
0
0
PERCENT
OF TIMES
DETECTED
81
19
6
3
2
0
0
(1) - Number of Samples Which Yielded Valid Analytical Results
(2) - Number of Times Reported Concentratration Exceeds LRV
-125-
-------
TABLE V-22
ARITHMETIC MEAN EFFLUENT CONCENTRATIONS OF
PRIORITY POLLUTANT METALS(1)
GULF OF MEXICO SAMPLING PROGRAM [174]
Platform
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Notes: ( 1 )
N-D
NVD
Zinc
(ug/D
37
47
27
52
213
53
65
155
435
230
N-D
396
88
427
N-D
94
63
214
N-D
28
145
202
202
40
N-D
NVD
48
445
NVD
NVD
Copper
(ug/1)
N-D
N-D
N-D
54
N-D
N-D
N-D
N-D
N-D
N-D
23
N-D
23
N-D
N-D
24
41
92
N-D
8
N-D
23
1455
10
N-D
NVD
N-D
N-D
NVD
NVD
For metals detected
reportable value
= Not Detected
= No
Nickel
(ug/D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
138
N-D
N-D
N-D
NVD
72
216
NVD
NVD
at least
Lead
(ug/1)
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
223
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
5700
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
once above
Cadmium
(ug/1)
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
98
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
N-D
lowest
Valid Determinations
-126-
-------
TABLE V-23
ARITHMATIC MEAN EFFLUENT CONCENTRATIONS OF
CONVENTIONALS AND NON-CONVENTIONALS
GULF OF MEXICO SAMPLING PROGRAM [174]
Platform
1
2
3
4
5
6
7
3
9
10
1 1
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
N-D = Not
NVD = No
Oil &
Grease
(mg/1)
51
22
32
53
24
10
33
28
35
66
42
30
74
66
29
514
24
400
40
24
54
7
82
16
88
74
89
22
19
218
Detected
Valid Determinat
Total
Dissolved
Solids
(mg/1)
33258
98090-
147520
121220
155600
60190
145540
176620
258940
175240
1631 10
145440
170280
160560
151960
123500
110520
232320
334360
131 198
1 14433
178030
100700
120188
68275
6876
165350
242565
100620
109000-
ions
Total
Iron
(mg/1)
5
9
22
26
40
9
18
27
78
34
34
34
34
76
26
26
16
84
100
10
1 1
35
19
16
10
0
31
42
17
17
Chloride
(mg/1)
13500
56500
78000
66500
79000
33500
79000
84000
121000
91000
88750
72500
91250
93000
78000
68750
62500
130500
172500
70833
61917
94000
53000
63042
35750
3400
86500
124500
55500
56500
-127-
-------
Alaska Sampling Program - There are two major oil and gas pro-
ducing fields in Alaska: one is offshore in Cook Inlet (Kenai
Peninsula) and the other is on the North Slope of the Brooks
Range, onshore in Prudhoe Bay. Two operating sites were sampled
in Cook Inlet - one treated produced water on the platform and
the other onshore [175]. The Prudhoe Bay facility reinjects all
produced water, thus treatment, in the conventional sense, of
produced water is not provided. The pertinent characteristics of
these facilities are shown in Table V-24. The analytical results
of the effluent samples obtained from this program are summarized
in Table V-25.
California Sampling Program - Sampling of produced water was
carried out in the Santa Barbara Channel oil-producing area.
Platforms located within three miles of the shoreline are within
State of California jurisdiction, while platforms beyond that are
within federal jurisdiction. Producing offshore platforms
located in state waters usually deliver gross fluid onshore,
where oil is separated from water and produced water is treated
by multistage unit processes and then is discharged into coastal
waters or reinjected. There is no overboard discharge from plat-
forms operating in state waters. Platforms located in federally
controlled waters treat and discharge produced water overboard.
The overboard discharge is sometimes augmented by reinjection.
Three facilities were selected to represent oil production in the
Santa Barbara Channel:
1. Summerland Field, offshore from Carpinteria, east of Santa
Barbara in state coastal waters. Treatment and discharge
into coastal waters.
2. Ellwood Field, offshore from Ellwood, west of Santa Barbara
in state coastal waters. Reinjection.
-128-
-------
TABLE V-24
CHARACTERISTICS OP FACILITIES SELECTED
FOR ALASKA SAMPLING PROGRAM [175]
Characteristic
Brine BBL
Oil BBL
Gas MCF
Offshore
Platform
Cook Inlet
18,350
1,300
410
Onshore
Treatment
Cook Inlet
6,600
12,500
—
Prudhoe Bay
Oil Field
13,000
92,100
136,500
Brine Treatment
% of Brine:
Oil Skimming +
Reinjection
Oil Skimming +
Flotation +
Reinjection
Reinjection
Reinjected
Discharged
Sampling Date
59
41
10/12/81
33
67
10/13/81
100
0
10/20/81
-129-
-------
TABLE V-25
ARITHMETIC MEAN EFFLUENT CONCENTRATIONS OBTAINED
FROM THE ALASKA SAMPLING PROGRAM [175]
Parameter
Offshore
Platform
Units Cook Inlet
Onshore
Treatment
Cook Inlet
Prudhoe Bay
Oil Field
Organic Priority Pollutants
Benzene
Ethylbenzene
Toluene
Phenol
2 , 4-Dimethylphenol
Naphthalene
Bis-(2-ethylhexyl)
Phthalate
Priority Pollutant
Copper
Mercury
Zinc
ug/l
ug/l
ug/l
ug/l
ug/1
ug/l
ug/l
Metals
ug/l
ug/l
ug/l
7375
345
3025
1810
438
359
176
' 55
3
1750
7240
170
2805
1683
420
330
80
55
- 3
21
1370
900
9630
3490
830
595
228
—
3
N-D
Convent ionals/Non-conventionals
Oil & Grease
Total Dissolved
Solids
Chloride
mg/1
17
mg/1 24570
mg/1 1
2200
15
25880
13000
10
19800
10220
-130-
-------
3. Offshore platform in federal waters. Overboard discharge and
reinjection.
Characteristics of these three facilities are presented in Table
V-26. Analytical results for effluent samples collected in this
program are summarized in Table V-27.
Produced Sand
Produced Sand is fine sand and clay particles which are separated
from the crude oil and produced water.
Volume. Produced sand discharges may be continuous or intermit-
tent depending on the volumes produced. Compared with typical
maximum produced water discharge rates for the Gulf of Mexico of
4,000-40,000 m^/d, typical maximum produced sand discharge rates
are on the order of 4-40 m3/d. One figure for produced sand,
which is site-specific and cannot be considered typical, is 1
m^ sand per 2,000 m3 oil production. One general figure for
southern California producing fields, which are considered to
produce small quantities of produced sand, is 1 m^/d. Another
estimate is 2 kg/d per well.
Composition. Oil and grease is the primary pollutant parameter
found with produced sand. Estimates of the oil and grease con-
tent after washing are less than 1 mg/1.
Deck Drainage
Deck drainage includes rainwater, wash water, and any lubrication
or product spillage or leakage which may accumulate on the plat-
form deck and enter the deck drainage system.
-131-
-------
TABLE V-26
CHARACTERISTICS OF FACILITIES SELECTED
FOR CALIFORNIA SAMPLING PROGRAM [175]
Characteristic
Brine
Oil
BBL
BBL
Ellwood
Facility
1,230
9,200
Carpinteria
Facility
14,000
6,400
Offshore
Platform
25,000
17,000
Gas MCF
Brine Treatment
% Brine:
Reinjected
Discharged
Sampling Date
Filtration +
Reinjection
100
0
6/23/82
Oil Skimming +
Flotation
0
100
6/2/82
Flotation +
Filtration +
Reinjection
20
80
6/10/82
-132-
-------
TABLE V-27
AVERAGE EFFLUENT CONCENTRATION OBTAINED
FROM THE CALIFORNIA SAMPLING PROGRAM [175;
Parameter
Ell wood
Units Facility
Carpinteria
Facility
Offshore
Platform
Organic Priority Pollutants
Benzene
Ethylbenzene
Toluene
Phenol
2 ,4-Dimethylphenol
Naphthalene
Bis- (2-ethylhexyl)
Phthalate
Priority Pollutant
Copper
Lead
Zinc
ug/1
ug/1
ug/1
ug/1
ug/1
ug/i
ug/1
Metals
ug/1
ug/1
ug/1
4000
348
2940
1046
213
84
L 10
165
1 13
220
1463
148
2750
973
772
86
N-D
109
N-D
46
286
140
544
19
189
127
N-D
198
77
78
Conventionals/Non-conventionals
Oil & Grease
Total Dissolved
Solids
Chloride
mg/1
mg/1
mg/1
N-A
N-A
N-A
5
22700
10500
N-A
N-A
N-A
L - Less than; N-D - Not Detected; N-A - Not Analyzed
-133-
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Vo1ume. Flows are intermittent, occurring during rainfall events
and washdown operations. Typical deck drainage flow rates are
shown in Table V-28.
Composition. Golumbek et al. compiled and analyzed self moni-
toring data on deck drainage supplied from 8 exploratory drilling
platforms to characterize deck drainage before and after treat-
ment. They reported average oil and grease concentrations bet-
ween 10 and 85 mg/1 [8]. Oil and grease and suspended solids are
the primary pollutants of concern in the deck drainage. Total
discharges are likely to be small. One estimate based on a sur-
vey of 23 U.S. platforms was less than 0.25 litres of oil and
grease per day per platform [184].
Sanitary and Domestic Wastes
Sanitary and domestic wastes are generated by continuously manned
production facilities and a.11 drilling rigs during mobilization
and operation. Continuously manned facilities generally discharge
domestic wastes which originate from sinks, showers, laundry and
food preparation areas.
Volume. At its highest occupancy, which generally occurs during
well completion, drilling rigs support between 12 and 80 per-
manent occupants. Production platforms are categorized as
unmanned, manned by 9 or fewer persons, or manned by 10 or more
persons. Typical volumes of sanitary and domestic waste are
0.075 and 0.11 m^/cap/day, respectively. The most extensive
information on actual facility discharges are obtained from
annual Discharge Monitoring Reports submitted to EPA. A review
of DMR's submitted to Region VI from facilities in the Gulf of
Mexico for the reporting periods 4/81 to 3/82 and 4/82 to 3/83
indicate that sanitary waste volumes range from 0.04 m^/day to
2.65 m^/day for facilities manned by 9 or fewer persons and 0.38
-134-
-------
TABLE V-28
DECK DRAINAGE FLOW RATES
LOCATION
REFERENCE
SOURCE
OF FLOW
m3/d
NATURE
OF FLOW
California [188]
Cook Inlet [197]
Gulf of
Mexico
[253]
deck wash
total deck
drainage
0.1
(typical )
0-1 ,500;
76 mean
0-1 ,542
8 mean
intermittent,
not daily
950 sites
intermittent
-135-
-------
m3/day to 22.7 m^/day for facilities manned by 10 or more per-
sons. During these same periods, domestic waste volume ranged
from 0.08 m3/day to 30.3 m^/day.
Composition. Where physical treatment (incineration) of sanitary
wastes is practiced, there is no pollutant discharge. Table V-29
contains typical discharge parameters for platforms providing
separate wastewater treatment for sanitary waters. Table V-29
also shows typical domestic (gray) wastewater loadings and con-
centrations of biochemical oxygen demand (BOD) and suspended
solids (SS).
Ballast Water
Ballast water and storage displacement water discharges are
characterized by intermittent flow at high flow rates over a
relatively short period (a few hours to a few days). Large
storage volumes are required to allow offloading of large
tankers. Volumes and discharge rates for tanker ballast water
range from 49,000 to 115,000 m /d and average 55,000 m /d [197].
Miscellaneous Wastes
A description of the composition and handling of miscellaneous
offshore production wastes is given in Table V-30.
-136-
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TABLE V-29
TYPICAL OFFSHORE SANITARY AND DOMESTIC WASTE CHARACTERISTICS
DISCHARGE
RATE
(ra3/cap/day)
LOADING
BOD S.S
(kg/cap/day) (kg/cap/day)
CONCENTRATION
BOD S.S RESIDUAL
CHLOR
(mg/L) (mg/L) (mg/L)
Sanitary
waste
(treated)
0.075
0.002 (1) 0.003 (1)
30
40 1.7
Domestic
waste
(direct
discharge)
0.11
0.022 (2) 0.016 (2) 195 140
Sources:
(1) Adapted from [3]
(2) Adapted from [34]
-137-
-------
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-138-
-------
REFERENCES
3. Development Document for Interim Final Effluent Limitations
Guidelines and Proposed New Source Performance Standards for
the Oil & Gas Extraction Point Source Category/ U.S.
Environmental Protection Agency, September 1976, EPA
440/1-76-005-a-Group II.
8. Golumbek, J. et al., "Offshore Oil and Gas Exploratory
Drilling Rigs in the Mid-Atlantic Area - Final Report on
Deck Drainage", U.S. Environmental Protection Agency",
Region II, New York, N.Y., June 1979.
23. Appendix A, "Chemical Components and Users of Drilling
Fluids," March 25, 1980, Petroleum Equipment Suppliers
Association Environmental Affairs Committee.
34. "Effluent Limitations for Onshore and Offshore Oil and Gas
Facilities", University of Tulsa, May 1974.
35. "Environmental Aspects of Drilling Muds & Cuttings from Oil
and Gas Extraction Operations in Offshore & Coastal Waters",
OOC Sheen Technical Subcommittee, May 1976.
53. Composition and Properties of Oil Well Drilling Fluids, by
George R. Gray, H.C.H. Darley, and Walter F. Rogers, January
1980.
57. Crude Oil Drilling Fluids, Chemical Technology Review No.
121, Energy Technology Review No. 35.
144. Petrazzuolo, Gary, "Preliminary Report: An Environmental
Assessment of Drilling Fluids and Cuttings Released Onto the
Outer Continental Shelf", Volume One, Technical Assessment,
prepared by: (EPA) Industrial Permits Branch, Office of
Water Enforcement and the Ocean Programs Branch, Office of
Water and Waste Management, March 26, 1981.
163. Houghton, J. P., K. R. Critchlow, D. C. Lees, and R. D.
Czlapinski, Fate and Effects of Drilling Fluids and Cuttings
Discharges in the Lower Cook Inlet, Alaska, and on Georges
Bank - Final Report. U.S. Department of Commerce, National
Oceanic and Atmospheric Administration, and the U.S.
Department of the Interior, Bureau of Land Management, 1981.
164. Kramer, J. R., H. D. Grundy, and L. G. Hammer, Occurrence
and Solubility of Trace Metals in Barite for Ocean Drilling
Operations, Symposium - Research on Environmental Fate and
Effects of Drilling Fluids^and Cuttings,Sponsored by API,
Lake Buena Vista, Florida, January 1980.
-139-
-------
165. McCulloch, W. L., J. M. Neff, and R. S. Carr,
Bioavailability of Selected Metals from Used Offshore
Drilling Muds to the Clam Rangi a c uneata and the Oyster
Crgssostrea gigas, Symposi urn on Envi ronmen tal Fate and
Effects of Drilling"Fluids and' Cuttings,Sponsored by API,
Lake Buena Vista, Florida, January 1980.
166. Ayers, R. C., Jr., T. C. Sauer, Jr., R. P. Meek, and
G. Bowers, An Environmental Study to Assess the Impact of
Drilling Discharges in the Mid-Atlantic, Report 1 - Quantity
and Fate of Discharges, Sympos i urn - Research on
Environmental Fate and Effects of Drilling Fluids and
Cuttings, Sponsored by API, Lake Buena Vista, Florida,
January 1980.
174. Oil and Gas Extraction Industry, Evaluation of Analytical
Data Obtained from the Gulf of Mexico Sampling Program,
Volume 1, Discussion, Prepared by Burns and Roe Industrial
Services Corporation, Prepared for U.S. Environmental
Protection Agency, Effluent Guidelines Division, January
1983, Revised February 1983.
175. Lysyj, I., and M. A. Curran, Priority Pollutants in Offshore
Produced Oil Brines, Rockwell International, Environmental
Monitoring and Services Center and U.S. Environmental
Protection Agency, Industrial Environmental Research
Laboratory, respectively, November 1982.
179. Bureau of Land Management, Final Environmental Statement,
OCS Sale No. 42, Offshore the North Atlantic States, Volumes
1 to 5, U.S. Department of the Interior, 1977.
182. Analysis of Drilling Muds from 74 Offshore Oil and Gas Wells
in the Gulf of Mexico, Prepared by Dalton-Dalton-Newport for
the U.S. Environmental Protection Agency, Monitoring and
Data Support Division, June 1, 1984.
184. Industrial Process Profiles to Support PNIN Review: Oil
Field Chemicals, prepared by Walk Haydel & Associates, Inc.,
for the U.S. Environmental Protection Agency, Economics and
Technology Division, Office of Toxic Substances.
188. Hester, F.J. 1981. Written statement to Offshore California
General NPDES permit Hearing E.P.A. Region IX, Santa Barbara
California, 17 September 1981.
190. Exxon Company, U.S.A. 1981. Application of NPDES Permit No.
CA0110362.
191. Shell Oil Company. 1981. Petroleum extraction industry
comments regarding southern California draft general NPDES
permit. 46 Fed. Reg. 45672. 16 October 1981.
-140-
-------
194. Jackson, G.F., E. Hume, J.J. Wade and M. Kirsch. 1981. Oil
content in produced brine on ten Louisiana production plat-
forms. Prepared by Crest Engineering Inc. for Municipal
Environmental Research Lab. U.S. EPA. Cincinnati, Ohio,
465 pp.
196. Myers, L.H., B.L. DePrater, T.E. Short, and B.B. Shunatona.
1975. Offshore crude oil wastewater characterization study.
Prepared by R.S. Kerr Environmental Research Laboratory for
National Environmental Research Center U.S. EPA Corvallis,
Oregon . 1 1 8 pp .
197. U.S. Environmental Protection Agency (EPA). 1982a. Region
X NPDES monitoring data for Gulf of Alaska oil production
platforms.
240. Duke, T.W. , Parrish, P.R., "Results of the Drilling Fluids
Research Program Sponsored by the Gulf Breeze Environmental
Research Laboratory, 1976-1983 and Their Application to
Hazard Assessment". Environmental Research Lab - Office of
Research and Development, U.S. EPA Gulf Breeze, Fl.,
EPA-600/484-055, June 1984.
244. Petrazzuolo, G., Draft Final Technical Support Document
"Environmental Assessment: Drilling Fluids and Cuttings
Released on to the OCS", Submitted to: Office of Water
Enforcement and Permits, U.S. EPA, January 1983.
245. Ayers, R.C., Sauer, T.C., Exxon, Anderson, P.E. U.S. EPA
"The Generic Mud Concept for Offshore Drilling for NPDES"
presented at IADC/SPE Drilling Conference, New Orleans, LA,
February 20-23, 1983.
248
Duke, T.W. , Parris, P.R., Montgomery, R. , Macauley, S. ,
Macauley, J., and Cripe, G.M., "Acute Toxicity of Eight
Laboratory - Prepared Generic Drilling Fluids to Mysids
(Mysidopsis Bahia)" Environmental Research Laboratory Sabine
Mysopss aa nvronmenta
Island Gulf Breeze, FL, May 1984
249. Results of Laboratory Analysis Performed on Drilling Fluids
and Cuttings, Submitted to: U.S. EPA, Effluent Guidelines
Division, Submitted by: CENTEC Analytical Services, April
3, 1984.
253. Review of US EPA Region VI Discharge Monitoring Reports,
Offshore Oil and Gas Industry, Prepared for U.S. EPA,
Effluent Guidelines Division, by Burns and Roe Industrial
Services Corporation, September 1984.
-141-
-------
271. Final Report for Research on Organic Chemical
Characterization of Diesel and Mineral Oils Used as Drilling
Mud Additives, Prepared for: Offshore Operators Committee,
Environmental Subcommittee, by: BATTELLE New England Marine
Research Laboratory, December 1984.
277. Meyer, R.L., and Vargas, R.H., IMCO Services, "Process of
Selecting Completion or Workover Fluids Requires Series of
Tradeoffs," Oil and Gas Journal, January 30, 1984.
-142-
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VI. SELECTION OF POLLUTANT PARAMETERS
INTRODUCTION
Based on a detailed assessment of the extensive information col-
lected by the Agency in this and in previous studies on the
quantities and characteristics of waste discharges from this
industry, the following pollutants and pollutant characteristics
are of concern and are being considered for first time coverage
or for more stringent effluent limitations and standards:
Drilling Fluids
o Free Oil
o Toxicity
o Priority Pollutants
o Oil-Based Drilling Fluids, Diesel Oil
o Oxygen Demand
Treatment Fluids
o Free Oil
Drill Cuttings
o Free Oil
o Oil-Based Drilling Fluids, Diesel Oil
o Oxygen Demand
Produced Water
o Oil and Grease
o Priority Pollutants
* Produced Sand
o Free Oil
-143-
-------
* Deck Drainage
o Free Oil
Sanitary Wastes
o Fecal Coliform (Total Residual Chlorine)
o Floating Solids
Domestic Wastes
o Floating Solids
* Additional pollutants may be selected pending additional data
collection and analysis.
The following sections provide the rationale utilized to select
these parameters.
DRILLING FLUIDS
Free Oil
The term "no discharge of free oil" is being amended in this pro-
posed rulemaking to prohibit the discharge of applicable waste
streams that would cause a film or sheen upon or a discoloration
of the surface of the receiving water, as determined by the
Static Sheen Test. (The Static Sheen Test is described in
Appendix A of this document.) This definition differs from that
currently specified in 40 CFR 435.11, which requires ". . . that
a discharge not cause a film or sheen upon or a discoloration on
the surface of the water or adjoining shorelines or cause a
sludge or emulsion to be deposited beneath the surface of the
water or upon adjoining shorelines." The limitation was origi-
nally intended to prohibit the discharge of drilling fluids (as
-144-
-------
well as drill cuttings and well treatment fluids) that, when
discharged, would cause a sheen on the receiving water. The
limitation was then extended for final BPT regulations to include
deck drainage, and the current definition of the term "no
discharge of free oil" was established to be consistent with the
oil discharge provisions of Section 311 of the Act. Technically,
however, discharged drilling fluids could be considered "sludge."
For this reason, the Agency is proposing to amend the current
definition by excluding language that prohibits the deposit of
sludge beneath the surface of the receiving water. This would
allow the discharge of drilling fluids, provided that other
effluent limitations are met.
The Static Sheen Test is a proposed method using laboratory pro-
cedures performed on site, prior to discharge, for determining
whether a particular waste stream will cause a sheen on the
receiving water. The existing BPT method of compliance is an
after-the-fact determination performed by observing the receiving
waters after the discharge has occurred. The proposed method
will also eliminate the difficulty of seeing a sheen at night,
under icing conditions, and in rough sea conditions. The test is
conducted by adding samples of the effluent stream into a con-
tainer in which the sample is mechanically mixed with a specific
proportion of seawater, allowed to stand for a designated period
of time, and then viewed for a sheen.
Free oil, oil-based drilling fluids, and diesel oil are all
related to the oil content in drilling fluid waste streams and
the concentration of priority as well as conventional and noncon-
ventional pollutants present in those oils. The pollutants "free
oil," "oil-based drilling fluids," and "diesel oil" are each con-
sidered to be "indicators" of specific priority pollutants pre-
-145-
-------
sent in these complex hydrocarbon mixtures used in drilling fluid
systems. These pollutants include benzene, toluene, ethylben-
zene, naphthalene, and phenanthrene.
Sampling and analysis data demonstrate that when the amount of
oil, especially diesel, is reduced in drilling fluid, the con-
centrations of priority pollutants and the overall toxicity of
the fluid generally is reduced. Controlling of the amount and
type of oil present in drilling fluids with limitations on the
three "indicators" (free oil, oil-based drilling fluids and
diesel oil) provides a substantial level of control of the
priority pollutants present in drilling fluids.
Toxicity (LC50)
Toxicity tests are used to determine levels of pollutant con-
centrations which can cause lethal or sublethal effects on orga-
nisms, and are categorized as either acute or chronic. Acute
toxicity tests involve exposures of 96-hours or less, while chro-
nic toxicity tests involve long-term exposures, usually entire or
partial life-cycles. [254]
Acute toxicity tests are used to determine the short-term effects
of a chemical or mixture on an organism. Results are generally
reported as the concentration at which 50 percent of the orga-
nisms are killed (the LC5Q, or median lethal concentration), or
display a defined effect of toxicological importance, such as
loss of mobility (the EC5Q Or median effects concentration). The
higher the LC^Q or ECco for a given exposure time, the lower the
toxicity of the substance being tested. [254]
Acute toxicity tests can be conducted in static, renewal, or
flow-through systems. Static systems involve exposure to a
-146-
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single batch of test solution for the full test period. Renewal
systems involve periodically replacing the test solution with new
solution of the same concentration. in flow-through systems, the
test solution is continuously replaced and excreted metabolites
are removed. EPA's proposed protocol for toxicity testing of
drilling fluids specifies a static bioassay system (Appendix C of
this report). [254]
Chronic toxicity tests evaluate the long-term effects of pollu-
tant exposure on survivability, growth, maturation, and reproduc-
tion. The results are generally expressed as a range, with the
smaller value the lowest concentration resulting in the
prescribed effect, and the larger value the highest concentration
not producing the effect. [254]
Chronic tests can be life cycle, partial life cycle, or early
life stage. Life cycle testing exposes organisms from embryo or
newly-hatched larval stage through at least 24 hours after the
hatching of the next generation. Partial life cycle tests
expose organisms through part of the life cycle, and are used in
situations where the organism takes a long period (e.g., a year
or more) to mature. Early, life stage testing focuses on the
embryonic stage shortly after fertilization through early juve-
nile development. [254]
Results of research activities show that drilling fluids are
toxic to marine organisms at certain concentrations and exposure
regimes. Further, drilling fluids can adversely affect animals -
especially benthos - through physical contact, by burying, or by
altering substrate composition. Drilling fluids also can exert
effects by disrupting essential physiological functions of orga-
nisms. [240]
-147-
-------
The areas where drilling fluids are most likely to cause detec-
table problems associated with water column toxicity are those
with shallow water (i.e., where dispersion is limited) or poorly
flushed/low energy areas (i.e., where the amount of muds
discharged is large compared to local water flux). Sediment
toxicity to benthic organisms, oxygen depletion effects, and phy-
sical effects due to deposition also are most likely to be
observed in these areas. [254]
When discharges are made from platforms located in open, well-
mixed, and relatively deep (>20 m) marine environments, most
detectable acute effects will be limited to within several
hundred meters of the point of discharge. Based on laboratory-
derived effects data, there will be sufficient dilution of the
drilling fluids in the water column to minimize acute effects on
water column organisms. Benthic organisms within about 300 m of
the discharge will be potentially subject to adverse effects
caused by burial and chemical toxicity; they may also be suscep-
tible to direct effects or substrate changes for greater distan-
ces. Possible exceptions to these generalizations could occur
when discharges are near sensitive biological areas, such as
coral reefs, or in poorly flushed environments. [240]
Additives such as oils and some of the numerous specialty
additives - especially biocides - may greatly increase the toxi-
city of the drilling fluid. The toxicity is, in part, caused by
the presence and concentration of priority pollutants. However,
control of the indicator parameters alone (free oil, oil-based
drilling fluids, and diesel oil) may not be an effective means of
regulating these additives. A toxicity limitation would require
that operators consider toxicity in selecting additives and
select the less toxic alternative. The limitation would also
-148-
-------
encourage the use of generic water-based drilling fluids and the
use of low-toxicity drilling fluid additives (i.e., product
substitution).
The eight generic water-based drilling fluids, whose formulations
are presented in Section V of this document, are adequate for
virtually all drilling situations and are less toxic than oil-
based drilling fluids. In order for a drilling fluid to be
discharged, it should be no more toxic than the proposed LC-50
standard as determined with the Drilling Fluids Toxicity Test
presented in Appendix C of this document.
The most toxic generic fluid is potassiurn/polymer mud (see Table
V-7 of this document). The imposition of an LC-50 toxicity limi-
tation for all drilling fluids which are to be discharged would
allow for use of at least any of the eight generic drilling
fluids. Seven of the generic drilling fluids (i.e., all but
potassium/polymer mud) could be supplemented with low-toxicity
specialty additives and lubricity agents to meet operational
requirements, and be able to comply with the LC-50 toxicity limi-
tation prior to discharge. This conclusion is based on the
results of a toxicity study (reference 248) in which mud samples
were spiked with mineral oil at various concentrations.
Priority Pollutants
The trace metals of interest in drilling fluids include barium,
zinc, lead, and chromium. The source of barium in drilling
fluids is barite; barite may be contaminated with several metals
of interest, including mercury, cadmium, zinc, lead, arsenic, and
other substances. However, seawater solubilities for trace
metals associated with powdered barite generally result in con-
centrations below background levels. [254, p. 3-58]
-149-
-------
Chromium discharged in drilling fluids is primarily adsorbed on
clay and silt particles, although some exists as a free complex
with soluble organic compounds. [254, p.3-60]
Dissolved metals tend to form insoluble complexes through adsorp-
tion on fine-grained suspended solids and organic matter, both of
which are efficient scavengers of trace metals and other con-
taminants. [240]
Trace metals, adsorbed to clay particles and settling to the bot-
tom, are subjected to different chemical conditions and processes
than when suspended in the water column. These sorbed metals can
be in a form available to bacteria and other organisms if located
at a clay lattice edge or at an adsorption site (Houghton et al.,
1981). If the sediments become anoxic, conversion of metals to
insoluble sulfides is the most probable reaction, and the metals
are then removed from the water column. Environments that
experience episodic sediment resuspension favor metal release if
reducing conditions existed previously in buried sediments; such
current conditions also allow further exposure of organic matter
complexes for further reduction and eventual release. [240]
Bioaccumulation of a number of metals from exposure to mud com-
ponents has been demonstrated in the laboratory and in the field.
Laboratory studies have indicated that bioaccumulation has been
observed for nearly all metals that have been studied, including
barium, chromium, cadmium, lead, strontium, and zinc. Barium and
chromium show the most dramatic increases (30- to 300-fold);
others are much lower (2- to 25-fold). Data on mercury are
conspicuous by their absence. [240, 254]
Field data for either one-well operations or small drilling fluid
discharges show that sediment levels were elevated for a variety
-150-
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of metals (barium, chromium, cadmium, mercury, nickel, lead,
vanadium, and zinc) in a distance-dependent manner.
Bioaccumulation was noted in field-collected organisms for
several of these metals, although at relatively low levels (2-to
10 fold compared to organisms collected at reference stations).
Limited laboratory data and field data indicate bioaccumulation
levels of metals are low (2-to 10-fold) with the exception of Ba
(300-fold) and Cr (36-fold). Depuration is often rapid (within
24 hours) and quantitative (40 to 90 percent of excess metals;
inversely related to length of exposure). The available data
suggest limited uptake of toxic metals from limited exposure to
drilling fluid. This uptake is especially a concern because it
has occurred following exposure to substances that would be con-
sidered not readily bioavailable based on their physical and/or
chemical properties. [266]
There are no laboratory or field data that are adequate to assess
the bioaccumulation hazard of organic components of drilling
fluids. [254] Bioaccumulation of organics from drilling fluids,
in particular those associated with (diesel or mineral) oils
added as lubricants, has not been fully studied. [240]
Oil-Based DrilljLng Fluids, Diesel Oil
There is a general consensus that generic drilling muds with no
added diesel oil or mineral oil have relatively low acute, lethal
toxicity. However, industry contends that the use of diesel
and/or mineral oils as lubricating and spotting agents, at rela-
tively high levels (two to four percent), is necessary for
reliable operations. The addition of even small amounts of
diesel oil to generic drilling muds cause them to become signifi-
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cantly more toxic. Also, diesel oil has a high, statistically
demonstrable correlation to observed toxicity. Diesel oil,
either as a component in an oil-based drilling fluid or as an
additive to a water-based drilling fluid is an indicator of toxic
pollutants. The term indicator as used here is a pollutant,
constituent or characteristic that exhibits a correlation with
one or more other constituents in the same waste. The objective
in regulating an indicator is to control the level (s) of the
other constituent(s). The nature of the correlation is positive.
That is, when the indicator's level is increased, the other
constituents' levels are increased; when the indicator's level is
decreased, the other constituents' levels are decreased. Diesel
oils have been found to contain such toxic organic pollutants as
benzene, toluene, ethylbenzene, naphthalene, and phenanthrene
(See Section V of this report).
Oxygen Demand
Dissolved oxygen (DO) is a water quality constituent that, in
appropriate concentrations, is essential not only to keep orga-
nisms living but also to sustain species reproduction, vigor, and
the development of populations. Organisms undergo stress at
reduced DO concentrations that decrease their ability to compete
and survive under such conditions. For example, reduced DO con-
centrations have been shown to interfere with fish population
through delayed hatching of eggs, reduced size nad vigor of
embryos, production of deformities in young, interference with
food digestion, acceleration of blood clotting, decreased
tolerance to certain toxicants, reduced food efficiency and
growth rate,, and reduced maximum sustained swimming speed. Fish
food organisms are likewise affected adversely in conditions with
suppressed DO. Since most higher marine organisms need a certain
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amount of oxygen, a total lack of dissolved oxygen or even
severely suppressed oxygen levels can kill and eliminate the
habitat of these species.
Most wastestreams from oil and gas extraction activities
especially drilling fluids and produced waters - exert a signifi-
cant and sometimes major oxygen demand. The primary sources are
soluble biodegradable hydrocarbons and oxidizable inorganic com-
pounds.
If an ecological system is already subjected to large and varied
contaminant inputs, adding further contaminants may cause signi-
ficant problems, even if the additional load is comparatively
small. Areas which are subject to higher loadings from other
sources of pollution tend to be the nearshore coastal areas,
which include shallow and poorly flushed areas. In addition, the
usage of nearshore coastal areas for recreation and commercial
fishing is characteristically high, which is yet another reason
for concern in assessing potential impacts from these discharges.
[254]
Each of the three oxygen demand control parameters selected are
discussed below.
Biochemical Oxygen Demand (BOD). Biochemical oxygen demand is a
measure of the oxygen consuming capabilities of organic matter in
water. The BOD does not in itself cause direct harm to a water
system, but it does exert an indirect effect by depressing the
oxygen content of the water, depending on dilution and dispersion
of wastes in the environment. Sewage and other organic effluents
during their processes of decomposition exert a BOD, which can
have a catastrophic effect on the ecosystem by depleting the oxy-
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gen supply. Conditions are reached frequently where all of the
oxygen is used and the continuing decay process results in pro-
duction of noxious gases such as hydrogen sulfide. Water with a
high BOD indicates the presence of decomposing organic matter and
subsequent high bacterial counts that degrade its quality and
potential uses.
Chemical Oxygen Demand (COD). Chemical oxygen demand provides a
measure of the equivalent oxygen required to oxidize the
materials present in a wastewater sample, under acid conditions
with the aid of a strong chemical oxidant, such as potassium
dichromate, and a catalyst (silver sulfate). One major advantage
of the COD test is that the results are available normally in
less than three hours. Thus, the COD test is a faster test by
which to estimate the maximum oxygen demand a waste can exert on
a stream. However, one major disadvantage is that the COD test
does not differentiate between biodegradable and non-
biodegradable organic material. In addition, the presence of
inorganic reducing chemicals (sulfides, reducible metallic ions,
etc.) and chlorides may interfere with the COD test.
Total Organic Carbon (TOC). Total organic carbon is a measure of
the amount of carbon in the organic material in a wastewater
sample. The TOC analyzer withdraws a small volume of sample and
thermally oxidizes it at 150*C. The water vapor and carbon
dioxides from the combustion chamber (where the water vapor is
removed) is condensed and sent to an infrared analyzer, where the
carbon dioxide is monitored. This carbon dioxide value
corresponds to the total inorganic value. Another portion of the
same sample is thermally oxidized at 950°C, which converts all
the carbonaceous material to carbon dioxide; this carbon dioxide
-154-
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value corresponds to the total carbon value. TOC is determined
by subtracting the inorganic carbon (carbonates and water vapor)
from the total carbon value.
The recently developed automated carbon analyzer has provided
rapid and simple means of determining organic carbon levels in
wastewater samples, enhancing the popularity of TOC as a fun-
damental measure of pollution. The organic carbon determination
is free of many of the variables which plague the BOD analyses,
yielding more reliable and reproducible data.
WELL TREATMENT FLUIDS
Free Oil
Free oil is a selected pollutant parameter for control of well
treatment fluids. This parameter and its environmental impact,
are discussed in the drilling fluids section above.
DRILL CUTTINGS
Free Oil
Free oil is a selected pollutant parameter for control of drill
cuttings. This parameter and its environmental impact, are
discussed in the drilling fluids section above.
Oil-Based Drilling Fluids, Diesel Oil
Oil-based drilling fluids and diesel oil are selected pollutant
control parameters for drill cuttings. These parameters, along
with their environmental impact, are discussed in the drilling
fluids section presented above.
-155-
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Oxygen Demand
BOD, COD, and TOC are selected oxygen demand parameters for
control of drill cuttings. These parameters and their environ-
mental impact, are discussed in the drilling fluids section pre-
sented above.
PRODUCED WATER
Oil and Grease
Dissolved or emulsified oil and grease are extracted from water
by intimate contact with trichlorotrifluoromethane (Freon).
Freon has the ability to dissolve not only oil and grease but
also other organic substances. No known solvent will selectively
dissolve only oil and grease. Freon will also dissolve sulfur
compounds, organic dyes, chlorophyll, unsaturated fats and fatty
acids. This method, however, also results in the loss of short-
chain hydrocarbons and simple aromatics by volatilization.
Significant portions of petroleum distillates from gasoline
through No. 2 fuel oil are lost in this process. In addition,
heavier residuals of petroleum may contain a significant portion
of materials that are not extractable with this solvent. This
method is currently utilized to quantify the oil content of pro-
duced water discharges.
Oil emulsions may adhere to the gills of fish or coat and destroy
algae or other plankton. Deposition of oil in the bottom sedi-
ments can inhibit normal benthic growth rates, thus interrupting
the aquatic food chain. Soluble and emulsified materials
ingested by fish can taint the flesh which can reduce the commer-
cial and recreational value of the fishery. Water soluble com-
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ponents may have toxic effects on fish. The water insoluble
hydrocarbons and free floating emulsified oils in a wastewater
interferes with oxygen transfer, damages the plummage and coats
of water animals and fowl and increase oxygen demand.
Pr ior i ty Po 11 u,tan ts
In the EPA sampling program of produced water from some 30 plat-
forms in the Gulf of Mexico, benzene, ethylbenzene, naphthalene,
phenol, and toluene were detected in all samples collected. Zinc
was measured in 65 of the 79 samples at concentrations above the
lowest reportable value. The second most frequently detected
metal was copper (in 12 of the 79 samples). [174]
Results of the Gulf of Mexico sampling program mentioned above
are summarized in Tables VI-1, 2 and 3. Priority pollutants ana-
lyzed but not detected in any produced water discharge are listed
in Table VI-1. Table VI-2 is an overall summary of sampling
results for those priority pollutants detected in the treated
effluents. Finally, Table VI-3 is a platform-by-platform distri-
bution of priority pollutants detected in the treated effluents.
Benzene. Benzene is a volatile, colorless, liquid hydrocarbon
produced principally from coal tar distillation and from petro-
leum by catalytic reforming of- light naphthas from which it is
isolated by distillation or solvent extraction. The data from
EPA's produced water sampling programs imply that benzene occurs
naturally in hydrocarbon bearing strata in varying amounts.
Benzene concentrations in the produced waters sampled ranged from
140 to 12,040 mg/1. [258]
The effects of benzene on several saltwater invertebrate and one
fish species have' been studied. The results had a high variabil-
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TABLE VI-1 [174]
PRIORITY POLLUTANTS ANALYZED
BUT NOT DETECTED IN ANY PRODUCED WATER DISCHARGE
Volatile Organics
Acrolein
Acrylonitrile
Bromoform
Carbon Tetrachloride
Chlorodibromomethane
Chloroethane
Chloroform
Dichlorobromomethane
Methyl Bromide
Methyl Chloride
Methylene Chloride
Tetrachloroethylene
Trichloroethylene
Vinyl Chloride
1,1-Dichloroethylene
1,1,1-Trichloroethane
1 ,1,2-Trichloroethane
1,1,2,2-Tetrachloroethane
1,2-Dichloroethane
1,2-Dichloropropane
1,2-trans-Dichloroethylene
1,3-Dichloropropylene
2-Chloroethyl Vinyl Ether
Semi-Volatile Organics
Acenaphthalene
Benzidine
Bis-(2-Chloroethoxy) Methane
Bis-(2-Chloroisopropyl) Ether
Butyl Benzyl Phthalate
Chrysene
Dimethyl Phthalate
Fluoranthene
Hexachlorobenzene
Hexachlorobutadiene
Hexachloro cyclopentadiene
Hexachloroethane
Ideno (1,2,3-C,D) Pyrene
Isophorene
N-Nitrosodi-N-Propylamine
N-Nitrosodimethylamine
N-Nitrosodiphenylamine
Nitrobenzene
Phenanthrene
Pyrene
1 ,12-Benzoperylene
1,2-Benzanthralene
1 ,2-Dichlorobenzene
1,2-Diphenylhydrazine
1,2,4-Trichlorobenzene
1 ,3-Dichlorobenzene
1 ,4-Dichlorobenzene
2-Chloronaphthalene
2-Chlorophenol
2-Nitrophenol
2,4-Dichlorophenol
2,4-Dinitrophenol
2,4-Dinitrotoluene
2,4,6-Trichlorophenol
2,6-Dinitrotoluene
3,3' -Dichlorobenzidine
4-Bromphenyl Phenyl Ether
4-Chlorophenyl Phenyl Either
4-Nitrophenol
4 ,6-Dinitro-o-Cresol
Metals
Chromium
Silver
-158-
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ity among the invertebrate species with a range of effect con-
centrations of 17,600 to 924,000 rag/1. The fish species (striped
bass) was more sensitive with 96-hour LC5Q values of 10,900 and
5,100 mg/1. [258]
This data indicates that acute toxicity to saltwater life occurs
at concentrations as low as 5,100 mg/1 and would occur at lower
concentrations among species that are more sensitive than those
tested. No definitive data are available on the chronic toxicity
of benzene to sensitive saltwater aquatic life, but adverse
effects occur at concentrations as low as 700 mg/1 with a fish
species exposed for 168 days. [258]
In both freshwater and saltwater systems, fish species appear to
be more sensitive than invertebrate species. [258]
Ethylbenzene. Ethylbenzene is an alkyl-substituted aromatic com-
pound which has a broad environmental distribution due to its
widespread use in a plethora of commercial products and its pre-
sence in various petroleum combustion processes. Based on the
concentrations measured in produced water, 19 to over 6,000 mg/1,
ethylbenzene also appears to occur naturally in hydrocarbon for-
mations. [259]
Studies performed on two saltwater fish and three invertebrate
species varied widely with LC50 values ranging from 430 to
1,030,000 mg/1. The effect of temperature, salinity and life
stage on the toxicity of ethylbenzene to the grass shrimp was
studied and all LC50 values were within the range of 10,200 to
17,300 mg/1, which indicated that those variables had no signifi-
cant effect on the 24-hour LCsg values. [259]
-161-
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These studies indicate that acute toxicity to saltwater life
occurs at ethylbenzene concentrations as low as 430 mg/1 and
would occur at lower concentrations among species that are more
sensitive than those tested. No data are available on the chron-
ic toxicity of ethylbenzene to sensitive saltwater species. [259]
Naphthalene. Naphthalene is a bicyclic aromatic hydrocarbon with
the chemical formula C1QH8 and a molecular weight of 128.16. One
of the principal uses of naphthalene as a feedstock in the United
States is for the synthesis of phthalic anhydride. It has also
t
been used directly as a moth repellent and insecticide as well as
an antihelminthic/ vermicide and an intestinal antiseptic.
Naphthalene is the most abundant single constituent of coal tar
and forms the base of many crude oils (Naphthenic Crude). The
solubility of naphthalene in seawater varies according to sali-
nity. In seawater of average composition, the solubility of
naphthalene is about 33,000 mg/1. Naphthalene is biodegradable
to 1,2-dihydro-1,2-dihydroxynaphthalene and ultimately to carbon
dioxide and water. Concentrations of naphthalene in produced
water ranged from 26 to 1179 mg/1. [260]
The effects of naphthalene on saltwater species have been exten-
sively studied as a result of intense interest in the effects of
oil pollution on the marine environment. The most significant
data produced indicated a nearly 200 percent increase in the
occurrence of gill hyperplasia in mummichog after a 15-day expo-
sure to 2 mg/1 (there was a 30 percent occurrence in the controls
and a 80 percent occurrence in the test organisms.) All of the
fish exposed to 20 mg/1 demonstrated necrosis of the tastebuds, a
change not observed in any members of the control group. [260]
The saltwater fish and invertebrate species tested were of about
similar sensitivity to the freshwater species, with LC5Q values
-162-
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of 3,800 mg/1 for a polychaete and
shrimp. There was an apparently
Pacific Oyster of 199,000 mg/1. The m
on the histopathological effects on
michog exposed to concentrations of n
mg/1. [260]
Phenol. Phenol, occasionally referrei
a monohydroxybenzene which is a clea
deliquescent, crystalline solid at 25
formula CgH6o, a molecular weight of 9
of 1.071 at 25°C. Phenol has a wate4
2,350 mg/1 for the grass
atypjical 48-hour value for the
>st critical data are those
a high percentage of mum-
phthalene between 2 and 20
to as "carbolic acid," is
, colorless, hygroscopic,
"C. It has the empirical
.11 and a specific gravity
solubility of 6.7g/100 ml
at 16"C and is soluble at all proportions in water at 669C, It
is also soluble in relatively non-polar solvents such as benzene,
petrolatum, and oils. Phenol has been found in the produced
water discharges of all production platforms sampled at con-
centrations ranging from 65 to almost 21,000 mg/1. [261]
Three saltwater invertebrate and three fish species have been
studied as to the acute effects of phenol. ^5Q values were
observed as low as 5,800 ug/1. Histopathological damage was
observed in the hard clam at concentrations as low as 100 mg/1.
A saltwater fish reacted to concentrations as low as 2,000 mg/1.
[261]
No data are available concerning the chronic toxicity of phenol
to sensitive saltwater aquatic life. [261]
Toluene. Toluene, also referred to as toluol, methylbenzene,
methacide, and phenylmethane, is an aromatic hydrocarbon which is
both volatile and flammable. Toluene is a clear, colorless, non-
corrosive liquid with a sweet, pungent, benzene-like odor and has
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the molecular formula C?H8, a molecular weight of 92.13 and a
density of 0.86694 at 20°C. Toluene was detected in produced
water discharges at concentrations ranging from 104 to over
12,000 mg/1. [262]
Acute toxicity tests were performed on a number of saltwater spe-
cies including the grass shrimp, bag shrimp, mysid shrimp and
pacific oyster. A chronic value of 5,000 mg/1 has been obtained
from an embryo-larval test with the sheepshead minnow in which
the observed adverse effect was on hatching and survival. [262]
The available data indicate that acute and chronic toxicity to
saltwater aquatic life occurs at concentrations as low as 6,300
and 5,000 mg/1, respectively, and would occur at lower con-
centrations among species that are more sensitive than those
tested. [262]
2,4-dimethylphenol. 2,4-dimethylphenol (2,4-DMP) is a naturally
occurring, substituted phenol derived from the cresol fraction of
petroleum or coal tars. 2,4-DMP is also, known as m-xylenol,
2,4-xylenol or m-4-xylenol, and has the empirical formula CgHiQO.
2,4-DMP has a molecular weight of 122.17 and a density of 0.9650
at 20°C. In its normal state it exists as a colorless,
crystalline solid. 2,4-DMP is present in most produced water
discharges at concentrations ranging from 4 to nearly 2,300 mg/1.
[263]
No saltwater organisms have been tested with 2,4-DMP. However,
acute toxicity to freshwater aquatic life occurs at con-
centrations as low as 2,120 mg/1. [263]
Zinc. Zinc is a bluish-white metal with an atomic number of 30
and an atomic weight of 65.38. The chemical behavior of zinc is
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similar to cadmium, which is directly below it on the periodic
table, and is never found free in nature but occurs as a sulfide,
oxide or carbonate. Zinc forms complexes with a variety of orga-
nic and inorganic liquids and is easily adsorbed on clay
minerals, hydrous oxides, and organic matter. The tendency of
zinc to be sorbed is affected not only by the nature and con-
centration of the sorbent but by pH and salinity as well. The
concentrations measured in produced water, from 27 to 445 mg/1,
indicate a moderately strong geographical/geological dependence,
probably a result of weathering of various rock formations during
the geological episodes in which the hydrocarbon bearing strata
were formed. [264]
Acute toxicity data for zinc are available for 21 species of
saltwater invertebrates and represent more than two orders of
magnitude difference in sensitivity. Larval mollusks were the
most sensitive invertebrates with acute values for an oyster of
310 mg/1 and for the hard-shelled clam of 166 mg/1. Acute values
for adult mollusks ranged from 2,500 for the blue mussel to 7,700
for the soft-shelled clam. Zinc was acutely toxic to saltwater
polychaetes over the range from 900 mg/1 for Neanthes arena-
ceodentata to 55,000 for Nereis diversicolor. The decapod crusta-
ceans had 96-hour LC50 values of 175 and 1,000 mg/1 for the
lobster and crab, respectively. The reported acute values for
copepods ranged from 290 mg/1 for Acartia tonsa to 4,090 mg/1 for
Eurytemora affinis. Results from tests with two mysid shrimp
showed similar values; 498 mg/1 for Mysidopsis bahia and 591 mg/1
for Mysidopsis bigelowi. [264]
The data base for saltwater fish contains nine values for three
species of fish and three taxonomic families. The acute values
range from 2,730 for larval Atlantic silversides to 83,000 for
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larval mummichog. Saltwater fish were generally more resistant
to acute zinc poisoning than saltwater invertebrates, although
there were cases of individual overlap. [264]
The only chronic data reported for a saltwater species exposed to
zinc are those for the mysid shrimp, Mysidopsis bahia. In this
flow-through life cycle test the number of spawns recorded at 231
mg/1 was significantly fewer than at 120 mg/1, but the number of
spawns at 59 and 120 mg/1 was not significantly different from
those in the control group. Brood size was significantly reduced
at 231 mg/1 but not at lower concentrations. Based upon repro-
ductive data, the lower and upper chronic endpoints were 120 and
231 mg/1, respectively, which result in a chronic value of 166
mg/1. [264]
Copper. Copper is a soft heavy metal, atomic number 29, with an
atomic weight of 63.54, and a density in elemental form of 8.9
g/cc at 20°C. Copper has two oxidation states: cuprous (Cu(I))
and cupric (Cu(II)). Cuprous copper is unstable in aerated water
over the pH range of most natural waters (6 to 8) and will oxi-
dize to the cupric state. Bivalent copper chloride, nitrate, and
sulfate are highly soluble in water, whereas basic copper car-
bonate, cupric hydroxide, oxide, and sulfide will precipitate out
of solution or form colloidal suspensions in the presence of
excess cupric ion. Cupric ions are also adsorbed by clays, sedi-
ments, and organic particulates and form complexes with several
inorganic and organic compounds. Due to the complex interactions
of copper with numerous other chemical species normally found in
natural waters, the amounts of the various copper compounds and
complexes that actually exist in solution will depend on the pH,
temperature, alkalinity, and the concentrations of bicarbonate,
sulfide, and organic ligands. [265]
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Copper is ubiquitous in the rocks and minerals of the earth's
crust. In nature, copper occurs usually as sulfides and oxides
and occasionally as metallic copper. Compounds of copper are
more soluble in seawater than in freshwater due to the higher
ionic strength of saline waters. Studies also indicate that the
distribution of copper species in seawater vary significantly
with pH and that Cu(OH)2, CuC03, and Cu4"2 would be the dominant
species over the entire ambient pH range. The concentration of
total copper in produced water in the Gulf of Mexico ranged from
8 to nearly 1,500 mg/1. [265]
Although trace quantities of copper are important nutrients for
plant and animal life, slightly higher concentrations have a
definite biocidal effect. Acute toxicity studies on saltwater
invertebrates include investigations on three phyla: annelids,
mollusks, and anthropods (crustaceans). The acute sensitivities
of crustaceans ranged from 31 mg/1 for Acartia tonsa to 600 mg/1
for shore crab, Carcinus maenus. Adult polychaete worm acute
values ranged from 77 mg/1 to 480 mg/1. The 96-hour LC$Q for
Neanthes arenaceodentata increased from 77 mg/1 in a flowing
water system to 200 mg/1 in the presence of a sandy sediment.
Nereis diversicolor exhibited a variable response to salinity
over a range of 5 to 34 g/kg with the greatest toxicity occurring
at 5g/kg. The lowest reported acute value for the bivalve
molluscs was 39 mg/1 for the soft-shelled clam, Mya arenaria, and
the highest was 560 mg/1 for the adult Pacific oyster,
Crassostrea gigas. The sensitivity of Mya arenaria to copper
varied according to the seasonal temperature, with copper being
at least 100 times more toxic at 22°C than at 4°C. [265]
The arthropods (crustaceans) were both the most sensitive inver-
tebrate species tested, with an acute value of 31 mg/1 for
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Acartia tonsa, and the least sensitive of all animals tested,
with an acute value of 600 mg/1 for larvae of the shore crab,
Careinus maenus. The sensitivity of field populations of Acartia
tonsa to copper was strongly correlated with population density
and food ration, whereas cultured Acartia tonsa manifested a
reproducible toxicological response to copper through six genera-
tions. A study reported that lobster larvae appear to be twice
as sensitive to copper as the adults. [265]
The acute values for saltwater fish include data for four species
and two different life history stages. Acute toxicity ranged
from 28 mg/1 for summer flounder embryos, Paralichthys dentatus
to 510 mg/1 for the Florida pompano, Trachinotus carol inus. The
results of the acute tests on the embryos of summer and winter
flounder were used because embryos of these species apparently
are not resistant to copper and because other acute values are
not available for these species. [265]
*.
Studies on the effect of salinity on the toxicity of copper indi-
cate that it is more toxic to adult pompano at 10 g/kg than at 30
g/kg. [265]
The only chronic value reported for a saltwater species was that
for the mysid shrimp, Mysidopsis bahia. The chronic toxicity of
copper to this saltwater invertebrate was determined in a flow-
through life cycle exposure in which the concentrations of copper
were measured by atomic absorption spectroscopy. Groups of 20
individuals were reared in each of five copper concentrations
(control = 2.9 _+ 0.5 mg/1, 24.2 + 7.0 mg/1, 38.5 + 6.3 mg/1,
77.4 4- 7.4 mg/1, 140.2 + 11.8 mg/1) for 46 days at 20°C and 30
g/kg salinity. The biological responses examined included time
of appearance of first brood, the number of spawns, mean brood
-168-
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size, and growth. The appearance of embryos in the brood sac was
delayed for 6 and 8 days at 77 mg/1 and 140 mg/1, respectively.
The number of spawns recorded at 77 mg/1 was significantly fewer
than at 38.5 mg/1. The number of spawns at 24 and 38 mg/1 was
not significantly different from the control. Brood size was
significantly reduced at 77 mg/1 but not at lower concentrations,
and no effects on growth were detected at any of the copper con-
centrations. Based upon reproductive data, adverse effects were
observed at 38 mg/1, but not at 77 mg/1, resulting in a chronic
value of 54 mg/1. [265]
PRODUCED SAND
Free Oil
Free oil is a selected pollutant parameter for control of pro-
duced sand. The parameter itself, along with its environmental
impact, are discussed above as a drilling fluids' parameter.
DECK DRAINAGE
Free Oil
Free oil is a selected pollutant parameter for control of deck
drainage. The parameter itself, along with its environmental
impact, are discussed above as a drilling fluids' parameter.
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SANITARY WASTES
Fecal Coliform (Total Residual Chlorine)
The concentration of fecal coliform bacteria can serve as an
indication of the potential pathogenicity of water resulting from
the disposal of human wastes. Fecal coliform levels have been
established to protect beneficial water use (recreation and
shellfish propagation) in the coastal areas.
The most direct method to determine compliance with specified
limits is to measure the fecal coliform levels in the effluent
for a period representing a normal cycle of operations. This
approach may be applicable to onshore installations; however, for
offshore operations the logistics become complex, and simplified
methods are desirable.
The presence of specific levels of suspended solids and chlorine
residual in an effluent are indicative of corresponding levels of
fecal coliforms. In general if suspended solids levels in the
effluent are less than 150 mg/1 and the chlorine residual is
maintained at 1.0 mg/1, the fecal coliform level should be less
than 200 per 100 ml. Properly operating biological treatment
systems on offshore platforms have effluents containing less than
150 mg/1 of suspended solids; therefore, total residual chlorine
is selected as a control parameter in lieu of direct fecal coli-
form monitoring of sanitary waste discharges.
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DOMESTIC WASTES
Floating Solids
Floating solids interfere with the aesthetic and recreational
character of a water body and its adjacent shoreline and produce
objectionable odors. Floating solids is selected as a control
parameter for sanitary and domestic wastes emanating from small
or intermittently-manned offshore facilities.
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REFERENCES
174. Oil and Gas Extraction Industry, Evaluation of Analytical
Data Obtained from the Gulf of Mexico Sampling Program,
Volume 1, Discussion, Prepared by Burns and Roe Industrial
Services Corporation, Prepared for U.S. Environmental
Protection Agency, Effluent Guidelines Division, January
1983, Revised February 1983.
240. Duke, T.W., Parrish, P.R., "Results of the Drilling Fluids
Research Program Sponsored by the Gulf Breeze Environmental
Research Laboratory, 1976-1983 and Their Application to
Hazard Assessment". Environmental Research Lab - Office of
Research and Development, U.S. EPA Gulf Breeze, Fl.,
EPA-600/484-055, June 1984.
248 Duke, T., Parrish, P., Montgomery, R., Macauley, S.,
Macauley, J., and Cripe, G.M., "Acute Toxicity of Eight
Laboratory - Prepared Generic Drilling Fluids to Mysids
(Mysidopsis Bahia)" Environmental Research Laboatory Sabine
Island Gulf Breeze, FL, May 1984.
254. Assessment of Environmental Fate and Effects of Discharges
from Offshore Oil and Gas Operations, Original by
Dalton-Dai ton-Newport, As Amended by Technical Resources,
Inc., Prepared for U.S. Environmental Protection Agency,
Monitoring and Data Support Division, EPA 440/4-85-002,
March 1985.
258. EPA, "Ambient Water Quality Criteria for Benzene", EPA
440/5-80-01B, October 1980.
259. EPA, "Ambient Water Quality Criteria for Ethylbenzene", EPA
440/5-80-04B, October 1980.
260. EPA, "Ambient Water Quality Criteria for Naphthalene", EPA
440/5-80-059, October 1980.
261. EPA, "Ambient Water Quality Criteria for Phenol", EPA
440/5-80-066, October 1980.
262. EPA, "Ambient Water Quality Criteria for Toluene", EPA
440/5-80-075, October 1980.
263. EPA, "Ambient Water Quality Criteria for 2,
4-dimethylph,enol," EPA 440/5-80-044, October 1980.
264. EPA, "Ambient Water Quality Criteria for Zinc," EPA
440/5-80-079, October 1980.
-172-
-------
265. EPA, "Ambient Water Quality Criteria for Copper", EPA
440/5-80-036, October 1980.
266. Technical Resources, Inc., "Issue Paper: Regulating Cadmium
and Mercury in Drilling Fluid Discharges," prepared for
U.S.E.P.A. Office of Regulations and Standards, and Office
of Water Enforcement and Permits, May 8, 1984.
-173-
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VII. CONTROL AND TREATMENT TECHNOLOGY
INTRODUCTION
This section describes the control and treatment technologies
that are available for use in the offshore oil and gas industry
for the treatment and disposal of pollutants. Various control
and treatment technologies were studied for possible use in this
industry. Several of these technologies were rejected since,
either data was not available on performance or the technologies
were determined to be impractical or technologically infeasible
for use by this industry segment.
Current regulations require compliance with the Best Practicable
Control Technology Currently Available (BPT) effluent limita-
tions. Table VI1-1 presents existing BPT effluent limitations
for each of the major waste streams. The 1976 development docu-
ment [3] describes in detail the basic technologies, treatment
effectiveness and analytical data evaluation used to establish
BPT.effluent guidelines for each of these waste streams. A brief
description of the control and treatment technologies used to
achieve BPT limitations for each waste stream is presented below.
While control and treatment technologies for all of this
industry's waste streams are described in this section, the focus
of this development document effort has been on the following
major streams:
Drilling Fluids;
Well Treatment Fluids;
Drill Cuttings; and
Produced Water
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Control and treatment technologies for produced sand, deck
drainage/ sanitary wastes, and domestic wastes will be further
developed as part of the Agency's plan for investigating the
priority pollutant characteristics of these streams.
A discussion of analytical and monitoring techniques used to
monitor and enforce effluent guidelines is presented in Section
V.
DRILLING FLUIDS
Drilling fluids (muds) serve a number of functions but primarily
they serve to maintain well bore integrity and to carry drill
cuttings to the surface. During the course of drilling a well,
it may become necessary to dispose of varying quantities of a
specific mud formula to maintain proper mud formulation, accom-
modate changing drilling conditions or to perform intermediate
and final well construction operations. Disposal practices for
offshore oil and gas drilling fluids can be considered for two
drilling fluid scenarios.
o Drilling fluid formulations which do not cause signifi-
cant damage to the marine environment (generally water
based fluids).
o Drilling fluid formulations which may cause significant
damage to the marine environment (oil based fluids and
water based fluids that contain highly toxic additives).
Diesel oil is a commonly used drilling fluid additive that
imparts a high toxicity to drilling fluids. Diesel oil is added
for lubricity purposes and to overcome difficult drilling con-
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ditions. Also, certain additives, although typically repre-
senting a small portion of a given drilling fluid system, may
significantly increase the fluid toxicity.
BPT Technology
BPT requirements address the oil and grease content of this
wastestream with use of the following process control practices
plus end-of-pipe treatment [3] . Process control equipment and
practices for drilling fluids that are commonly used in both
offshore and onshore drilling operations include:
1. Accessory circulating equipment such as shaleshakers,
agitators, desanders, desilters, mud centrifuges,
degassers, and other mud handling equipment.
2. Mud saving and housekeeping equipment such as pipe and
kelly wipers, mud saver sub, drill pipe pan, rotary
table catch pan, and mud saver box.
*
3. Recycling of oil based muds.
»
BPT end-of-pipe treatment technologies are based on existing
waste treatment processes currently used by the oil industry in
drilling operations.
The BPT effluent limitations for offshore drilling fluids prohi-
bit the discharge of free oil in muds that would cause a sheen
upon the receiving water when discharged.
Oil based muds effectively cannot be discharged to surface waters
because of the prohibition on discharge of free oil. These muds
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are to be transported to shore for reuse or disposal in an
approved disposal site.
Additional Treatment
Waste management practices which control priority pollutant
discharges in drilling fluids include:
conservation and reuse
use of low toxicity drilling fluids (product
substitution)
treatment and/or disposal on land
Conservation and Reuse. Since drilling fluids are expensive, the
economics of well drilling provide a high incentive for reuse of
both toxic and low toxicity drilling fluids. This is par-
ticularly true of fluids that have hydrocarbon (diesel or mineral
oil) liquid base. However, storage and equipment limitations or
mineral on drilling platforms restrict conservation alternatives.
Drilling platforms contain equipment which removes drill cuttings
from the drilling fluid and the processed fluid is recycled to
the well hole. Eventually the drilling fluid becomes con-
taminated with too many fine particles that the platform equip-
ment cannot remove. The particulates alter drilling fluid
characteristics (e.g., viscosity) which makes the fluid unaccep-
table for continued use.
Examples of reuse practices for contaminated fluids which are
economically attractive for oil based muds are:
1 . Mud company buys back the used mud which is hauled
to shore, processed and re-used.
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2. Mud is treated with additional solids-suspending
agent and used as a packer fluid.
Use of Low-Toxicity Drilling Fluids. Drilling fluids which
are considered to have "low toxicity" are discharged directly
to the ocean at depths ranging from just below the surface to
near the ocean floor.- A discussion of one method for
identifying a "low toxicity" drilling fluid follows under
product substitution.
Treatment and/or Disposal on Land. Drilling fluids which contain
toxic materials can be hauled to shore for treatment and/or
disposal in landfills. Treatment may involve removal of fine
particles and reclamation of the oil-based fluid for reuse or
resale.
Production burners have been used successfully at offshore loca-
tions to dispose of whole-oil muds laden with solids. To burn
properly, the oil mud and diesel oil must be mixed in such a way
that the continuous oil phase can be burned. [274] All hydro-
carbons are burned completely and the residue is a fine powder
comprised of mud products and fine drilled solids. Current prac-
tice is to dispose of most contaminated drilling fluids in
controlled land fills without treatment. However, detoxification
methods are available which remove the toxic materials from the
mud prior to disposal.
Solidification techniques also exist which consist of adding che-
micals to the mud which react to form a solid material which can
be disposed of. The equipment consists of a specially designed
blender to mix the drilling fluids and chemicals and to pump the
slurry into the prepared area for solidification. The prepared
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area can be level farmland that has had the topsoil layer removed
and a shallow pit excavated to -contain the volume of fluid.
[274]
The economics of these two approaches have not been determined
and data on the leachability and integrity of the solid material
has not been quantified.
Product Substitution. Recent studies have sought to identify
drilling fluid formulations and drilling fluid additives which
exhibit low toxicity in the ocean environment and which can be
discharged directly to marine waters. The Agency has conducted a
program to determine the relative toxicity of certain "generic"
formulations. These generic formulations would then serve as a
basis on which industry and regulatory authorities could plan
effective control of drilling fluid discharges. (See Section V -
Analytical data on generic drilling fluids, and Section VI -
Toxicity criteria for drilling fluids.) As a result, the Agency
has designated eight generic water-based drilling formulas that
exhibit relatively low toxicity levels. A listing of drilling
fluid additives which exhibit relatively low toxicity levels in
drilling fluid systems has also been compiled (see listing of
generic drilling fluids and additives in Section V) . Using these
"generic" materials as a base, the acceptability for discharge of
other drilling fluids and additives can be evaluated based upon
their constituents and/or relative toxicity as determined by
established laboratory procedures.
Similarly, the Agency and the oil and gas industry are investi-
gating the use of low-toxicity substitutes for diesel oil. Until
recently, little research had been performed to identify
materials that could perform the specific functions of diesel oil
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and also be acceptable for discharge to the marine environment.
Low toxicity (e.g., mineral) oils have generally been found to
serve as acceptable substitutes for diesel oil in drilling
fluids.
Low-toxicity, or mineral, oils are derived from the same type of
crude oil from which diesel oil is derived. The significant dif-
ference between the two types of oils from an environmental
standpoint is the relatively high aromatic hydrocarbon content of
diesel oil and relatively low aromatic content of mineral
(low-toxicity) oils. The aromatic components of the oils are
generally the components that are most toxic to marine life.
The low-toxicity oils are composed of a wide variation of
paraffinic/napthenic components with very low-aromatic con-
centrations. The oils are referred to by various names such as
mineral oils, low-toxicity oils, low-aromatic oils, etc. White
oils are even more highly refined and purified mineral oils that
have even lower (sometimes zero aromatic content). High purity
white mineral oils are used in foods, laxatives, cosmetics, etc.
Thus, the key attempt to lower the toxicity of hydrocarbon base
oils is to lower, remove, or alter the aromatic compounds.
One study measured the percent retention of mineral oil based mud
on cuttings from the shale shaker and a single-stage cuttings
washer at a offshore Texas well. The findings of the study
suggested that mineral oil muds present a reduced environmental
risk to the marine ecosystem relative to diesel oil muds. Also,
it was concluded that mineral oil muds may be more cost effective
by reducing the operational costs of cleaning and disposing of
cuttings. [241]
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Studies by Bennet [270] and Boyd, [275] show that presently
available low-toxicity oils are as much as 30 times less toxic
than diesel oil to certain marine organisms. Laboratory results
also show that diesel and mineral oil are equally effective as
lubricants in freeing stuck pipe. Both additives achieve the
same reduction in force required to free a stuck pipe [242] .
A variety of mineral and vegetable oil-based products have been
developed as alternatives to petroleum hydrocarbons as drilling
fluid additives. While these products are in limited use in the
U.S., they are used more extensively elsewhere. Field and
laboratory tests of operating characteristics and environmental
acceptability have been conducted. Tests and trial introductions
continue as experience is gained concerning the alternatives'
operating characteristics and environmental acceptability. [251]
In testing a low-polymer-aromatic mineral oil substitute for
diesel oil in the formulation of an oil-base drilling fluid the
following were among the conclusions reached [275] :
1 . The low-polynuclear-aromatic oil is an acceptable
substitute for diesel oil and is compatible with current
market oil mud additives.
2. Emulsion stability, rheological, and filtration control
properties are easily maintained.
3. Low-polynuclear-aromatic-oil muds provide substantial
improvement in regard to toxicity and "polluting"
character when compared to diesel-base muds.
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WELL TREATMENT FLUIDS
Well treatment fluids include completion, work over, and packer
fluids plus miscellaneous discharges of encasement cement and
blow-out prevention (BOP) fluids. Characteristics of these
materials and their waste products have been discussed in
Sections III and V.
BPT Technology
The current BPT requirement is "no discharge of free oil" to
receiving waters.
Well Treatment. Well treatment fluids include chemicals used in
acidizing and fracturing operations performed as part of remedial
service work on old or new wells. Additionally, the fluids used
to "kill" a well so that it can be serviced may create wastes for
disposal. Liquids used to kill wells are normally drilling mud,
water, or an oil, and can occur as discrete discharges. Spent
acid and fracturing fluids usually move through the normal pro-
duction system and through the produced water treatment system.
Therefore, these fluids do not appear as a discrete waste source.
However, their presence in the waste treatment system can cause
upsets and thus a higher oil content in the discharged water.
Additional Treatment
Water treatment processes are not provided for each well treat-
ment fluid since the fluids usually do not return to surface as a
separate discharge. Many well treatment fluids mingle with
drilling fluids or produced water and are co-treated with these
wastestreams. Some of these materials are basically drilling
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fluids with special purpose additives which can be reclaimed and
reused after processing. Others such as stimulation or frac-
turing materials are mostly lost to the formation. When a well
is turned onto production, the fluid lost to the formation
usually appears with the oil or gas an'd is co-treated with the
produced water. This fluid can often cause upsets in the water
treatment equipment. Fluid not lost to the formation is saved
and re-used because of its high cost.
Acids used in stimulation are usually neutralized by the for-
mation and may return to the surface with oil or gas. This
material ends up in the produced water and is treated and
disposed of together with the produced water.
DRILL CUTTINGS
Pollutant type and waste management practices for drill cuttings
are integrally related to the drilling fluid that was employed.
That is, drill cuttings from an oil-base drilling fluid are
heavily contaminated with hydrocarbon wastes (diesel or mineral
oil). Cuttings resulting from use of a low-toxicity, water-based
drilling fluid are considered non-toxic and may be discharged
directly.
Drill cuttings are carried to the surface thoroughly mixed in
drilling fluid. At the surface, a mud treatment system separates
the drill cutting particles from the drilling fluid. A typical
mud treatment system contains the following items of equipment:
Shaleshaker: a vibrating screen through which returning
mud is passed for removal of large solids. The standard
shaker removes cuttings larger than 440 urn while the
fine screen shaker removes cuttings larger than 150 urn.
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Desander: a cyclone separator which is designed to
remove solids larger than 40 to 90 urn.
Desilter: a cyclone separator similar to the desander
but designed to remove solids larger than 15-25 urn.
Centrifuge: increases the rate of settling for par-
ticles in a drilling fluid and removes particles larger
than 3-10 urn.
Mud Cleaner: a desander for a weighted mud. The
weighting material (barite) passes through with the mud
and the cuttings and fines are separated.
Figure VII-1 is a flow diagram of a typical mud treatment system
which shows that seawater may be used to dilute the mud and cut-
tings prior to disposal.
The drilling fluid is reclaimed and recycled to the well and the
cuttings are sorted out for disposal. Discharge from the solids
control system contains rock cuttings, sand and clay particles,
washwater and residual drilling fluid which has not been removed
from the cuttings.
Disposal of cuttings from low-toxicity, water-based drilling
fluids is generally by direct discharge to the ocean. Some regu-
latory authorities stipulate shunting through a vertical pipe to
a specified depth below the water surface. Cuttings contaminated
with oil are either washed before discharge or transported to
approved land disposal sites.
-186-
-------
FIGURE VII-1
FLOWLJNE
FLOW DIAGRAM FOR A TYPICAL
SOLIDS CONTROL SYSTEM
MUD CLEANER
CSWECO)
SLUICING
WATEH
Source: 234
-187-
-------
BPT Technology
BPT control technology is directed at the removal of oil and
grease using the technologies described above. BPT for drill
cuttings is based on treatment and disposal methods presently
used by the oil industry.
The BPT limitations for offshore drill cuttings prohibit the
discharge of free oil based upon the presence of a visible sheen
upon the receiving water. Cuttings that contain free oil should
be collected and transported to shore for disposal in an approved
disposal site or sufficiently washed to remove free oil prior to
discharge.
Additional Treatment
Technologies that have been identified for cleaning drill cut-
tings can be classified according to the following means of
separating oil from cuttings:
Mechanical processes
Solvent Extraction
Vacuum Distillation
Table VII-2 presents the technology type, equipment features,
capacity and performance for each of the systems studied.
Vendor performance data indicates that achieving a residual oil
level of no more than 10 percent by weight is within the capabi-
lities of mechanical cleaning systems. To reduce the level by an
order of magnitude (i.e., less than 1 percent by weight), more
sophisticated solvent extraction or vacuum distillation methods
-188-
-------
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would be required. However, these methods have not been
demonstrated, to the Agency's knowledge, in any full-scale field
application for any extensive length of time.
Comparison of performance data for the systems studied is compli-
cated by:
o Variations in operating conditions and composition of
pollutants.
o Sampling procedures and analytical methods used.
o Historical lack of standardized units of weight or
volume to measure performance.
Mechanical Processes. Mechanical systems are most prevalent in
California, the Gulf of Mexico and the North Sea. In the mecha-
nical processes, drilling mud is first loosened from the cuttings
and then the cuttings are separated from the drilling mud.
Drilling mud is loosened from the cuttings either by high
pressure sprays or by immersion in a tank with agitation. The
spray may be seawater or a wash solution. Drill cuttings may be
immersed in seawater, solvent or the wash solution. Sometimes a
detergent is used to facilitate washing of the cuttings.
The mixture of drill cuttings, drilling mud and wash solution is
sent to a screen for separation of solids and liquids. Liquids
carrying fine solids are sometimes sent to desilters or centrifu-
ges for separating the fine solids. The separated oil and addi-
tives are sent back to the drilling mud system, wash solutions
are recycled and the cleaned cuttings are discharged.
-191-
-------
Cleaned cuttings are discharged either directly overboard or
through a flume below the water level. In a flume system the
cuttings are discharged through the inner pipe of a double pipe
system below the water level (See Figure VTI-2) . In these cases,
more oil is separated and the oil rises through the annulus to
the seawater level. A submersible pump sends the oil to an oil-
water separator for oil recovery. The cleaned cuttings drop to
the ocean bottom.
Mechanical systems offered by vendors employ various combinations
of the above-mentioned techniques. Capacity of these systems
varies from 1.25 to 12 tons per hour. Space requirements are
also different for different systems. Some of the subsections
are modular and can be made to suit available space. Performance
of the cuttings washer system is reported in terms of the resi-
dual oil remaining on the cuttings. Most of the vendors claim
that the residual oil will be less than 10 percent by weight and
there will be no visible sheen resulting from the discharge of
the washed cuttings.
Solvent Extraction. One freon extractable cleaning system con-
sists of a raw feed system, a slurry tank where fluidizing oil is
mixed with the raw feed, a hydrocyclone, two extraction columns,
various solvent and oil separation vessels and a tank where
"cleaned mud and cuttings are mixed with sea water prior to
discharge." Figure VII-3 is a simplified schematic of the system.
The units are available in two sizes: 2500 Ibs per hour and 7000
Ibs per hour. Performance data is not available for a freon
extraction unit in actual, full-scale field operation.
Basically, the mud and cuttings are slurried with oil and fed to
a hydrocyclone where some of the oil is separated and is returned
-192-
-------
FIGURE VII-2
SCHEMATIC OF A FLUME SYSTEM FOR THE DISCHARGE
OF DRILL CUTTINGS
Source:247
-193-
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-194-
-------
to the slurry tank. The mud, cuttings and oil exit the hydro-
cyclone and flow to two extraction columns where freon is added
to extract the oil. The "oil-free" mud and cuttings then flow to
an extractor bottom product hold tank where water is added to
sluice the mud and cuttings to discharge. The oil-laden freon
flows from the extractor column to an evaporator, separation
column and separator where the oil and freon are separated. The
oil phase flows to the fluidizing oil holding tank and the freon
is recycled. Excess oil from the mud and cuttings must be
periodically bled off and freon must be replaced to account for
miscellaneous losses. A small flow of water is generated in the
oil-water separator which is assumed to be directed to the pro-
duced water treatment system.
Required deck area is approximately 680 sq. ft. for either size
unit. The vendor claims that residual oil on the cuttings would
not exceed 1 percent by weight.
Vacuum Distillation. Vacuum distillation of cuttings is basi-
cally a mini-refinery process. Cuttings are ground to a fine
powder, which is fed to a vacuum retort. The retort is heated to
a temperature of about 660 degrees F. A two-stage vacuum pump
removes the evaporated water, oil and chemicals. The mixed vapor
goes through a cyclone for solids separation and finally to a
vapor condenser. Condensed liquid (oil, water and some
chemicals) is recycled to the mud system. Cleaned cuttings, in
the form of a solid residue, are ready for discharge overboard.
Long-term operating performance data is not available from
drilling contractors using this system. Required deck area, for
one vendor's system, is approximately 160 square feet for the
processing units and another 16 square feet for the controller
units. Capacity of this system is approximately 6 barrels (wet
-195-
-------
basis) per hour which corresponds to a drilling rate of 50 feet
per hour for an 8-1/2 inch diameter hole. Multiple units may be
used for processing larger quantities of drill cuttings.
Performance claims by vendors state that the amount of oil
remaining on the cuttings is on the order of 100 to 500 ppm (0.01
to 0.05 percent by weight).
PRODUCED WATER
Produced water consists of formation water plus hydrocarbons and
chemicals which have been mixed with the formation water during
the extraction and separation processes. Section V contains ana-
lytical data which, characterizes produced water from oil and gas
operations. Treatment processes are primarily designed to
control the oil and grease and priority pollutant content of this
waste stream.
Most states currently allow the discharge of brine to surface,
saline water bodies, subject to limitations on the oil and grease
content. Other pollutants are generally not regulated.
Exceptions are the states of California, Alabama and Mississippi.
California has promulgated stringent limits on discharges con-
taining heavy metals effectively precluding the discharge of pro-
duced water to any state waters.
BPT Technology
Existing BPT effluent limitations restrict the oil and grease
concentrations of produced water to a maximum of 72 mg/1 for any
one day and an average of 48 mg/1 for thirty consecutive days.
BPT treatment systems are designed to remove oil and grease from
produced water.
-196-
-------
BPT process control measures include the following:
o Elimination of the discharge of raw wastewater from
free water knockouts or other process equipment.
o Supervised operation and maintenance of oil/water level
controls, including sensors and dump valves.
o Redirection or treatment of wastewater or oil
discharges from safety valve blow offs and treatment
unit by-pass lines.
BPT end-of-pipe treatment can consist of some, or all of the
following:
o Equalization (surge tanks, skimmer tanks).
o Solids removal desander (with or w/o sandwasher).
o Chemical addition (feed pumps).
o Oil and/or solids removal.
o Flotation
o Filters
o Plate coalescers
o Gravity tanks
o Subsurface disposal (reinjection).
-197-
-------
Because of space limitations on offshore production platforms,
oil skimming/equalization, chemical treatment and flotation
comprise the most widely used treatment train.
End-of-pipe control technology for offshore treatment of produced
water from oil and gas production primarily consists of
physical/chemical methods. The type of treatment system selected
for a particular facility is dependent upon availability of
space, waste characteristics, volumes of waste produced, existing
discharge limitations, and other local factors.
Equalization. Surge tanks provide surge volume and primary
separation of oil and water before further treatment.
Skim Piles. " These are constructed of large diameter pipes con-
taining internal baffled sections and an outlet at the bottom.
During the period of no flow, oil will rise to the quiescent
areas below the underside of inclined baffle plates where it
coalesces (see Figure VII-4). Due to the difference in specific
gravity, oil floats upward through oil risers from baffle to
baffle. The oil is collected at the surface and removed by a
submerged pump. These pumps operate intermittently and will move
the separated liquid to a skimming vessel for further treatment
[235].
Solids Remova1. The fluids produced with oil and gas may contain
small amounts of sand which must be removed from lines and
vessels. This removal may be accomplished by opening valves to
create high fluid velocity which flushes the sand into a collec-
tor or a 55-gallon drum. Produced sand may also be removed in
cyclone separators.
-198-
-------
FIGURE VII-4
TYPICAL SKIM PILE
OIL RISERS
QUIESCENT ZONE
X
FLOWING ZONE
Source: 235
-199-
-------
The sand that has been removed is collected and taken to shore
for disposal or the oil is removed with a solvent wash and the
sand is discharged directly to surface waters.
At least one system has been developed that will mechanically
remove oil from produced sand. The sand washer systems consist of
a bank of cyclone separators, a classifier vessel, followed by
another cyclone. The water passes to an oil water separator, and
the sand goes to the sand washer. After treatment, the sand is
reported to have "no trace of oil" [255].
Oil and Grease Removal. Oil is present in produced water in a
range of sizes from molecular to droplet. Reducing the oil con-
tent of produced water involves removing three basic forms of
oil: large droplets of coalescable oil, small droplets of
emulsified oil and dissolved oil. Oil removal units are
generally effective in removing most of the free oil. The remo-
val efficiency and resultant effluent quality achieved by the
treatment unit is dependent upon the influent flow,"the influent
concentrations of oil and grease and suspended solids and the
type of chemicals in the wastewater.
Examples of working ranges for some oil and grease removal units
are:
Unrt Sizes Removed
Flotation above 10-20 urn
Parallel plate coalescers above 30-40 urn
Proprietary (API) separators above 6 urn
Skim Tanks above 15 urn
Smaller oil droplets are formed by the shear forces encountered
in pumps, chokes, valves and high flow rate pipelines. These
-200-
-------
droplets are stabilized (maintained as small droplets) by surface
active agents, fine solids, and high static charges on the
droplets [236]. Any operational change that promotes the for-
mation of smaller droplets or the stabilization of small droplets
will result in upset conditions and higher contents of oil in the
effluent after treatment. Upset conditions can be caused by
detergent washdowns in deck drainage entering the treatment unit,
unusually high flow volumes caused by heavy rainfall, and equip-
ment failures. Other factors leading to treatment plant upsets
are slugs of completion and workover fluids combining with the
produced water.
Chemical Treatment. The addition of chemicals to the wastewater
stream is an effective means of increasing the efficiency of
treatment systems. Chemicals are used to improve the treatment
efficiencies of flotation units, plate coalescers, and gravity
systems.
Three basic types of chemicals are used for wastewater treatment.
Many different formulations of these chemicals have been deve-
loped for specific applications. The. basic types of chemicals
used are:
o Surface Active Agents - These chemicals modify the
interfacial tensions between the gas, suspended solids,
and liquids. They are also referred to as surfactants,
foaming agents, demulsifiers, and emulsion breakers.
o Coagulating Chemicals - Coagulating agents assist the
formation of a floe and improve the flotation or
settling characteristics of the suspended matter. The
most common coagulating agents are aluminum sulfate and
ferrous sulfate.
-201-
-------
o Polyelectrolytes - These chemicals are long chain, high
molecular weight polymers used to assist in the agglo-
meration of colloidal and extremely fine suspended solid
or oil particles.
Surface active agents and polyelectrolytes are the most commonly
used chemicals for wastewater treatment. The chemicals are
injected into the wastewater upstream of the treatment unit and
do not require special premixing units. Serpentine pipes,
existing piping arrangements, etc. induce turbulence which
disperses polyelectrolytes throughout the wastewater. Recovered
oil foam, floe, and suspended particles skimmed from the treat-
ment units are returned to the initial oil/produced water separa-
tion system.
Gas Flotation. In a gas flotation unit gas bubbles are released
into the body of wastewater to be treated. As the bubbles rise
through the liquid, they attach to oil droplets in their path,
and the gas and oil rise to the surface where they may be skimmed
off as a froth. Two types of gas flotation systems are presently
used in oil production; dispersed and dissolved gas flotation.
See Figure VII-5.
Dispersed Gas Flotation - These units use specially shaped
rotating blades or dispersers to form small gas bubbles which
float to the surface with the contacted oil. The gas is drawn
down into the water phase through the vortex created by the
rotors from a gas blanket maintained above the surface. The
rising bubbles contact the oil droplets and come to the surface
as a froth, which is then skimmed off. These units are normally
arranged as a series of cells, each one operating as outlined
above. The wastewater flows from one cell to the next, with oil
removal in each cell.
-202-
-------
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Dissolved Gas Flotation - These units differ from dispersed gas
flotation because the gas bubbles are created by a change in
pressure which lowers the dissolved gas solubility, releasing
tiny bubbles. This gasification is accomplished by passing the
wastewater through a pump to raise the pressure and then through
a contact tank filled with gas. The wastewater leaves the con-
tact tank with a concentration of gas equivalent to the gas solu-
bility at the elevated pressure. When the recycled (gasified)
water is released in the bottom of the cell (at atmospheric
pressure) the solubility of the gas decreases and the excess gas
is released in the form of microscopic bubbles. The gas and oil
then rise to the surface where they are skimmed off. Dissolved
gas flotation units are usually a single cell only.
On production facilities it is usual practice to recycle the
skimmed oily froth back through the production oil-water
separating units.
The addition of chemicals can increase the effectiveness of
either type of gas flotation unit. Some chemicals_increase the
forces of attraction between the oil droplets and the gas
bubbles. Others induce a floe formation which eases the capture
of oil droplets, gas bubbles, and fine suspended solids, making
treatment more effective.
Filter Systems (Loose or Fibrous Media Coalescers). Filters
are also used to treat produced water. Two types of media
are in general use:
1. Fibrous media, such as fiberglass, usually in the
form of a replaceable element or cartridge, see
Figure VII-6.
-204-
-------
FIGURE VII-6
FIBROUS MEDIA COALESCER
UIXTVJflC f LOWS INSIDE TO
OUTSI06 THBOUCH THE
FRAM £8 CLEANA8LE AND
S£?A«ATSO Oil.
mses TO THE
TOP O? THE
VESSEL
REMOVAL'
THE EMULSION
OIL AAO WATEfl IS 3ROKEM
WATSR
l«LOWfS TO THE
QUTLST PIPING
•I.OW QOWN ?Ofl SOLIDS
OUfllNG 3ACX-WASM
OIL WATER MIXTURE
WATER FREE OIL
CLEAN WATER
SOLJOS ' BACKWASH
Source: 237
-205-
-------
2. Loose media filters, which normally use a bed of
granular material such as sand, gravel, and/or
crushed coal, see Figure VII-7.
Fibrous media filters may be cleaned by special washing tech-
niques or the elements may simply be disposed of and a new ele-
ment used. Loose media filters are normally backwashed by
forcing water through the bed with the normal direction of flow
reversed, or by washing in the normal direction of flow after
gasifying and loosening the media bed.
Filters which require backwashing present somewhat of a problem
on platforms because the disposal of the dirty backwash water may
be difficult. Replacing filter media and contaminated filter
elements also create disposal problems.
Measured by the amount of oil removed, filter performance has
generally been good; however, problems of excessive maintenance
with filtration of raw produced water have caused the industry in
the Gulf Coast to move away from this type of equipment. A
number of facilities have replaced filtration equipment with gas
flotation systems.
Parallel Plate Coalescers. Parallel plate coalescers are gravity
separators which contain groups of parallel, tilted plates
arranged so that oil droplets passing through the plates need
only rise a short distance before striking the underside of a
plate. Guided by the tilted plate, the droplet then rises,
coalescing with other droplets until it reaches the top of the
plate where channels are provided to carry the oil away. The
general theory of overall operation of parallel plate coalescers
is similar to API gravity oil-water separators. However, the
-206-
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FIGURE VII-7
GRANULAR MEDIA COALESCER
!:"~tr:t Separated hydrocarbons
Coalesced Hydrocarbons
".'.-':.'V." Oily water •.•'.'.,-. '.'.'•'.''.'-]
0
Source:23S
-207-
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parallel plates reduce the distance that oil droplets must rise
in order to be separated; thus unit sizing is much more compact
than an API separator. Particles which tend to sink move down
along the plates to the bottom of the unit where they are depo-
sited as a sludge and can be periodically drawn off. Particles
may become attached (scale) to the surface of the plates
requiring periodic shutdown and cleaning of the units.
Where stable emulsions are present, or where the oil droplets are
dispersed in the water, separation in this type of unit may not
be possible.
Gravity Separation. The simplest form of treatment is gravity
separation. The produced water is retained for a sufficient time
for the oil and water to separate. Tanks, ponds, pits, and,
occasionally, barges are used as gravity separation vessels.
Large storage volumes for sufficient retention times are charac-
teristic of these systems. Performance is dependent upon the
characteristics of the wastewater, water flow rate, and availabi-
lity of space. The majority are located onshore and. have limited
application on offshore platforms because of space limitations.
While total treatment by gravity separation requires large con-
tainers and long retention times, any treatment system can bene-
fit from even short periods of quiescent retention prior to
further treatment. This retention allows some gravity separation
and dampens surges in flow rate and oil content.
Improved Performance of BPT Technology. EPA evaluated the costs
and feasibility of improved performance of existing BPT treatment
technologies to determine whether more stringent effluent limita-
tions for oil and grease would be appropriate. This technology
would consist of improved operation and maintenance of existing
-208-
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BPT treatment equipment (e.g., gas flotation, coalescers, gravity
oil separation), more operator attention to treatment system
operation, and possibly resizing of certain treatment system com-
ponents for better treatment efficiency.
Based upon statistical analyses of effluent data from facilities
sampled during the Agency's 30-platform survey, EPA determined
that an oil and grease effluent limitation of 59 mg/1 maximum
(i.e., no single sample to exceed) can be achieved through
improved performance of BPT technology. This limitation is sup-
ported by information presented in the report titled Potential
Impact of Proposed EPA BAT/NSPS Standards for Produced Water
Discharges From Offshore Oil and Gas Extraction Industry,
(January 1984), sponsored by the Offshore Operator's Committee
for the Gulf of Mexico. The analysis of information from this
study concluded that at least 75 percent of existing offshore
operations in the Gulf of Mexico were already achieving oil and
grease levels of 59 mg/1 (maximum) or less in produced water. In
addition, an analysis of produced water effluent data from
available discharge monitoring reports (DMR's) was submitted by
operators of offshore production facilities in the Gulf of
Mexico. This data indicates that at least 60 percent of these
facilities are presently achieving an oil and grease con-
centration of 59 mg/1 (maximum) or less in produced water
discharges. Thus, improved, or even existing BPT facilities can
achieve greater reductions in oil and grease than that currently
required for BPT.
-209-
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Additional Treatment
Various technologies for the control of priority pollutants con-
tained in produced water were studied. These technologies
included zero discharge (reinjection or evaporation), biological
treatment, chemical precipitation, filtration and activated car-
bon adsorption. The following discussion outlines the techniques
and design considerations involved in the selection and possible
application of these technologies to the offshore oil and gas
industry.
Reinjection of Produced Waters (Zero Discharge). Disposal of
produced water by reinjecting it into the subsurface geological
strata can serve a number of purposes:
o Provide zero discharge of wastewater pollutants to
surface waters.
o Increase hydrocarbon recovery by flooding or
pressurizing the oil bearing strata.
o Stabilize (support) geological formations which
settle during oil and gas extraction (a significant
problem for onshore and some offshore well fields).
Onshore produced water reinjection is a well-established practice
used for most produced water disposal.
In Texas, the largest oil-producing state in the United States,
more than 99 percent of all produced water generated onshore is
presently reinjected. In Louisiana and California, the
corresponding figures are 65 percent and 58 percent, respec-
tively.
-210-
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Most of the offshore produced water in California waters is pre-
sently reinjected. During 1978, predominantly at onshore or man-
made island installations in California, this amounted to almost
400 million barrels of produced water.
Since geological conditions and technology will be essentially
the same for new sources, reinjection is considered to be
demonstrated and technically feasible for the disposal of pro-
duced water for facilities off the California coast.
In the Gulf of Mexico, most produced water from offshore plat-
forms receives 3PT treatment and is discharged overboard.
Onshore reinjection experience in Texas and Louisiana has shown
that the regional geology is. particularly well suited for the
reinjection of produced waters. Also, geological formations are
similar and thus produced water reinjection conditions are essen-
tially the same offshore and onshore.
Additional examples of injection are found in Alaska.
Waterflooding is employed at a majority of the platforms in Cook
Inlet. [272] Also, reinjection of produced waters is the pro-
posed means of disposal at the Endicott Project (Beaufort Sea).
[273]
Reinjection of produced water is considered to be demonstrated
and technically feasible for the disposal of produced water for
facilities in'the Gulf of Mexico and in Alaskan waters.
Design Conditions. Many of the requirements in the planning,
design and operation of a produced water reinjection system are
the same whether the location is onshore or offshore. These
include important design considerations such as selection of a
-211-
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receiving formation, preparation of an injection well, and choice
of equipment and materials. Significant operational parameters
include scaling, corrosion, incompatibility with receiving stra-
tum and bacterial fouling.
Pretreatment of produced water may be necessary to prevent
scaling, corrosion, precipitation, and fouling from solids and
bacterial slimes. Corrosion and deposits lead to decreased capa-
city in the equipment and to plugging in the underground for-
mation. One method to overcome this problem is to increase
reinjection pressures. However, injection pressure is a regu-
lated parameter in most states, because excessive injection
pressure may fracture the receiving formation causing the escape
of produced water into freshwater or other mineral bearing for-
mations .
Availability of Disposal Formations - Reinjection of produced
water from new sources in the Gulf of Mexico depends upon the
availability of suitable disposal formations offshore.
Initially, there will be little demand for produced waters as
reinjection fluids to enhance recovery. The produced water would
be reinjected for disposal purposes only. The onshore reinjec-
tion experience in Texas and Louisiana has shown that the
regional geology is particularly well-suited for the injection of
produced water. Suitable disposal formations are generally
available in the production leases. Since in the Gulf region,
the geological conditions are essentially the same offshore and
onshore, it is concluded that suitable disposal formations are
available offshore in the Gulf of Mexico. Further, adequate
reservoir capacities are available for the reinjection of all
produced waters from new sources. It should be noted that, con-
sistent with the onshore experience, there may be instances where
-212-
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a suitable disposal formatio
every offshore facility. Rei
tions would be required in th
Pretreatment Technology
including, at a minimum, gr
possibly filtration, would t
complete than the current
sources in the Gulf.
Howe
may not be available at each and
ijection at different offshore loca-
5se cases.
Pretreatment in a closed system
vity separation, gas flotation and
e required prior to reinjection in
the Gulf of Mexico. This leval of pretreatment is generally more
reliability of the pretreat
problems beyond those encoui
the same level of pretreatiru
reinjection.
Other Considerations - Pro\
reinjection system can be m
that overboard discharge o
because of operational proble
such as the transport and on
generated offshore, which ar
because their technical feas
Conclusion - In view of the <
that offshore reinjection
feasible as a control or tre;
produced waters from new soui
Receiving Formation - Select
be based on geologic as wel.
determine the injection capa
cal compatibility of the in
retreatment practices for existing
er, the space requirements or the
nent technology pose no additional
tered offshore in California where
nt is currently practiced prior to
isions for the reliability of the
de through redundancy in design so
f produced water is not required
ms. These and other considerations,
shore disposal of solids and sludges
for the most part economic issues
bility is not in question.
bove considerations, it is concluded
is demonstrated and technically
tment technology for the disposal of
ce facilities in the Gulf of Mexico.
on of the receiving formation should
as hydrologic factors. This is to
city of the formation and the chemi-
jected produced water and the water
-213-
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within the formation. The important region-wide geologic charac-
teristics of a disposal formation are areal extent and thickness,
continuity, and lithological character. This information can be
obtained or estimated from core analysis, examination of bit cut-
tings, drill stem test data, well logs, driller's logs, and
injection tests.
The desirable characteristics for a produced water reinjection
formation are: an injection zone with adequate permeability,
porosity, and thickness; an areal extent sufficient to provide
liquid-storage at safe injection pressures and an injection zone
that is confined by an overlying consolidated layer which is
essentially impermeable to water. There are two common types of
intraformation openings: (1) intergranular and (2) solution vugs
and fracture channels. Formations with intergranular openings
are usually made up of sandstone, limestone, and dolomite for-
mations and often have vugulor or cavity-type porosity. Also,
limestone, dolomite, and shale formations may be naturally frac-
tured. Formations with solution vugs and fracture channels are
often preferable for produced water disposal because fracture
channels are relatively large in comparison to inte.rgranular
openings. These larger channels may allow for fluids high in
suspended solids to be injected into the receiving formation
under minimum pumping pressure with a minimal amount of produced
water pretreatment at the surface.
A formation with a large areal extent is desirable for disposal
purposes because the fluids within the disposal formation must be
displaced to make room for the incoming fluids. An estimate of
the areal extent of a formation is best made through a subsurface
geological study of the area.
-214-
-------
If it is possible to inject water into the aquifer of some oil-
or-gas-producing formation, tire size of the disposal formation is
not too important. Under these circumstances, the reinjected
water would displace water from the aquifer into the producing
reservoir from which fluids are being produced. Thus, the
pressure in the aquifer would only increase in proportion to the
amount that water reinjection exceeds fluid withdrawals.
Pressure-depleted aquifers of older producing reservoirs are
highly desirable as disposal formations.
Selection of Reinjection Well - Whether the objective is enhanced
("secondary") recovery or disposal, a primary requirement for the
proper design of a reinjection well is that the produced waters
are delivered to the receiving formation without leaking or con-
taminating fresh water or other mineral bearing formations. The
reinjection well may be installed by either drilling a new hole
or by converting an existing well. The types of existing wells
which may be converted include marginal oil producing wells,
plugged and abandoned wells, and wells that were never completed
(dry holes). If an existing well is not available for conver-
sion, a new well must be drilled. Moreover, for reinjection from
offshore platforms, equipment and storage space must be provided
at the facilities.
Since pressure-depleted aquifers of older producing reservoirs
are highly reliable receiving formations, conversion of a margi-
nal well to a reinjection well is often a desirable alternative.
The cost of conversion of an existing well is also much less
costly than drilling a new well.
Following completion of a disposal well, injectivity index and
capacity index can measure the effective permeability of the
-215-
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disposal well and disposal formation. The capacity index is
defined as barrels of produced water injected divided by the
increase in bottom-hole pressure. The value can be obtained by
dividing the reinjection flow rate by the difference between the
bottom hole pressure at maximum reinjection rate and the static
bottom hole pressure. A well taking fluid under vacuum indicates
that the formation is capable of fluid reinjection at a higher
rate than that being delivered. This is not necessarily an indi-
cation of the volumetric capacity of the well or formation.
Injectivity index is similar to capacity index. It is defined as
the change in the number of barrels per day of gross liquid in-
jected into a well divided by the corresponding pressure dif-
ferential between mean injection pressure and mean formation
pressure, referring to a specific subsurface datum (usually this
is the mean formation depth). A simple plot of injectivity index
versus time can indicate when the formation is plugging and that
remedial action is necessary. Capacity index tests should be
performed periodically (e.g., monthly) on each well to determine
any changes in the reinjection capacity.
Materials and Equipment - Design considerations for materials and
equipment include:
o Corrosion resistance of injection tubing
o Packing fluid to protect casings
o Corrosion inhibition of well fluids
o Chemical compatibility of materials, fluids and the
produced water to be injected.
-216-
-------
Scaling - Scales and sludges that are commonly found in produced
water disposal systems include: calcium carbonate, magnesium car-
bonate, calcium sulfate, barium sulfate, strontium sulfate, iron
sulfide, iron oxide, and sulfur. Scale and sludge differ in that
scale is a deposit formed on surfaces in contact with water,
while sludge may be formed in one place and deposited in another.
Scales and sludges are formed when the water chemistry adjusts to
equilibrium conditions. Changes in equilibrium are caused by
temperature changes, pressure changes, chemical changes", and the
mixing of two or more stable but incompatible waters. Scale may
form as a result of a chemical reaction between the water, or
some impurity in the water, and the pipe. Corrosion products,
such as iron oxide or iron sulfide, are scales of this type.
Other precipitates, such as sulfur, may form when water with
hydrogen sulfide is mixed with water with a high dissolved oxygen
content.
Carbonate and sulfate scales can be prevented by using chemical
inhibitors containing polyphosphates and polymetaphosphates.
Calcium carbonate scale can be removed mechanically, using scra-
pers, or chemically, using hydrochloric acid.
Incompatibility - Chemical incompatibility of reinjected produced
waters with receiving formation fluids can cause precipitation.
This condition could also occur if incompatible waters from dif-
ferent reservoirs or surface sources are mixed prior to reinjec-
tion. Precipitation damage resulting from incompatible fluids
usually takes the form of plugged pore spaces in the reinjection
zone. The treatment of produced water to prevent incompatibility
consists of reducing the strength of, or removing the reactive
element or otherwise altering the nature of the reinjected fluid.
-217-
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Corrosion - The corrosion of metals, in a produced water disposal
system, is usually caused by electrochemical reactions. In this
type of reaction an anode (electron donor) and cathode (electron
acceptor) must exist in the presence of a electrolyte (ionic
solution) and an external circuit. Anodes and cathodes can exist
at different points on the steel surfaces with the steel pro-
viding the external circuit. Produced water serves as an
excellent electrolyte. Thus, an electric circuit can be set up
in the unprotected, produced water handling pipelines with iron
being oxidized at one portion of the system (cathode) and iron
being reduced and corroded away in another portion (anode).
Dissolved oxygen, carbon dioxide and salts are the major agents
found in produced water which cause corrosion in injection
systems. Bacteria are the "catalysts".
Bacteria Fouling - The presence of bacteria in a system may cause
a corrosion or plugging problem. Bacteria in oil field waters
may be aerobic (active in presence of oxygen), or anaerobic
(active in the absence of oxygen).
Iron bacteria are aerobic and are active in removing iron from
water and depositing it in the form of hydrated ferric hydroxide.
They are commonly active in fresh waters but are occasionally
found in produced water containing oxygen. The slimes that are
formed shield the metal surfaces from oxygen and provide an
environment for the growth of sulfate reducing bacteria that can
corrode metal. Sulfate reducing bacteria are the most common and
economically significant of the bacteria found in salt water
disposal and injection systems. Sulfate reducing bacteria are
anaerobic and have the ability to convert sulfate to sulfide.
Sulfate reducers are most active in neutral to mildly acidic
-218-
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waters, are frequently found under slime deposits, and are most
prolific under corrosion products, tank bottoms, filters, oil
water interfaces, and dead water areas, such as joints, crevices,
and cracks in cement linings. Sulfate reducers may also exist
naturally in some oil and water producing strata.
Control of aerobic bacteria is generally accomplished by treat-
ment with an organic biocide or chlorine. It should be men-
tioned, however, that in a closed system chlorine would not be
used because it is an oxidizing agent. Aerobic bacteria, or
slime formers, can grow in sufficient numbers to cause signifi-
cant well plugging. [216]
Remedial Measures - Examples of remedial measures which may be
employed to restore the receptibility of a reinjecting formation
are:
o acidizing
o hydraulic fracturing
o sand jetting or under reaming
o backflowing
o mechanical cleaning
o treatment with solvents, dispersants and other
chemicals.
Section III contains a discussion of these technologies in terms
of production methods used for secondary and enhanced recovery.
Pretreatment of Produced Water Prior to Reinjection. Treatment
systems may be classified as closed (absence of air) or open
(presence of air), although some systems employ features of both.
-219-
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The closed system prevents produced water/air contact and thus,
maintains the chemical equilibrium of the fluid by alleviating
the problems arising from oxygen induced corrosion, scaling, and
chemical precipitation. In pressure vessels, where oil-water
separation and emulsion treating are carried out, a closed system
is advantageous. In a closed system, a blanket of natural gas is
maintained over the produced water in pipelines and tanks. An
oil blanket is not an effective method of preventing oxygen con-
tamination.
In open systems produced water is aerated for two primary pur-
poses. The first purpose is to drive all acid-causing gases
(carbon dioxide and hydrogen sulfide) out of solution and reduce
corrosion. The second is to oxidize iron and form precipitates
which will be retained in settling tanks or on filters, thereby
preventing these precipitates from coming out of solution in
another part of the system or in the formation. If manganese is
present, it will also be oxidized and precipitated. Aeration has
one disadvantage in that oxygen is dissolved in the water and
will cause corrosion downstream in the system. For this reason,
the use of aeration should be carefully controlled.
Pretreatment in a closed system may consist of residual oil remo-
val and filtration prior to reinjection. In an open system, the
treatment train may be residual oil removal, aeration and degasi-
fication, chemical treatment, including coagulation and settling,
and filtration prior to reinjection.
Oil Removal - Primary separation of oil from produced water is
usually accomplished in free water knockouts, gun-barrel separa-
tors, or heater treaters. The efficiency of these processes is
not always sufficient to ensure relatively oil-free water for
-220-
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introduction into the reinjection system. The efficiency of the
treatment units removing oil from produced water can be greatly
reduced by improper chemical treatment or physical handling of
the oil-water mixture before separation. Examples include:
o Overtreatment of producing wells with certain scale
inhibitors can stabilize emulsions.
o Certain types of corrosion inhibitors act as
emulsifying agents when used applied in batches.
o Certain emulsion breakers can result in very clean
oil, but also can create very stable emulsions of
oil in water.
o Centrifugal pumps can form oil-in-water emulsions.
Gravity separators are generally used in disposal systems to
remove as much residual oil as possible from the produced water.
Dissolved gas flotation is a highly efficient method to remove
oil from water if an oil-in-water emulsion does not exist. See
the previous discussion of these systems in this section.
Sedimentation - Sedimentation processes can be used in open
treatment systems prior to reinjection to remove suspended
solids. However, unless a chemical coagulant is used, removal of
minute, suspended particles called colloids in the size range of
1 to 200 microns cannot be accomplished.
Filtration - This process may be included in both closed and open
systems. In closed systems it is the primary means of removing
suspended solids, whereas, in open systems, it is used to remove
-221-
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floe particles that were not removed in the sedimentation pro-
cess. Sand filters or multi-media filters are commonly used in
produced water treatment systems.
Industry Injection Practices. Reinjection of produced water
onshore is currently practiced extensively in California,
Louisiana and Texas. Also, in California waters, produced water
from most offshore platforms is presently reinjected after some
level of pretreatment. In the Gulf of Mexico, however, the
majority of produced water from offshore platforms is treated and
discharged to ocean waters. Within the limitations of available
data, the following discussion summarizes the industry experience
and current practices in the disposal of produced waters in
California, Louisiana and Texas-.
California - Table VII-3 shows the 1978 produced oil and produced
water statistics for the State of California with breakdowns for
the onshore and offshore segments of the industry. The total
quantity of oil produced onshore during 1978 is 292 million
barrels corresponding to an onshore water production of 1.78
billion barrels during the same period. The oil production
offshore in California waters amounted to 56 million barrels or
about 16 percent of the total production in the state. The total
produced waters in the state amounted to 2.10 billion barrels, of
which 319 million barrels or about 15 percent were produced
offshore. In both onshore and offshore oil production, an
average of 6 barrels of water were produced per barrel of oil on
a state-wide basis.
Table VII-4 summarizes the produced water disposal practices in
California during 1978. About 68 percent of all produced water
in the State was reinjected either to enhance the oil recovery
-222-
-------
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operations or for disposal. In the onshore segment alone, about
58 percent of produced waters were reinjected while the remaining
42 percent were disposed of by other methods (evaporative per-
colation ponds, or reinjection offshore). In the offshore
segment, all of the produced waters were reinjected, mostly for
the purpose of enhanced recovery by water flooding. In fact, the
demand for offshore water flooding exceeded the total amount of
produced waters available through the offshore production of oil.
To meet this demand, 72.5 million barrels of water produced
onshore was reinjected offshore.
Table VII-5 shows the number of produced water reinjection wells
in California in both the onshore and offshore segments. There
are a total of more than 2800 reinjection wells in California.
More than 80" percent of the total, or about 2300 wells, are used
for enhanced recovery by water flooding or pressurizing while the
remaining 20 percent, or about 500 wells, are used for disposal
only. In the offshore segment alone, there are 375 reinjection
wells, of which only 7 are used for disposal while the remaining
368, or more than 98 percent, are used for enhanced recovery pur-
poses. It is clear that, in California waters, reinjection of
produced water offshore is presently practiced predominantly to
enhance the recovery of oil through water flooding. The usual
practice is to convert a marginally producing well, on an
offshore platform, to serve as a reinjection well. Due to econo-
mic reasons, it is not the usual industry practice to drill a new
offshore well for the reinjection of produced water.
Pretreatment prior to offshore reinjection, in California waters,
usually includes gravity separation and gas flotation. But the
level of pretreatment can range from no treatment to chemical
addition, gravity separation, gas flotation and filtration.
-225-
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TABLE VII-5
CALIFORNIA PRODUCED WATER REINJECTION WELLS (1978) [216]
Location
Onshore
Offshore
Total
Number of Reinjection Wells
Enhanced Recovery
Waterf lood
1,882
367
2,249
Pressurizing*
72
1
73
Disposal
504
7
511
Total
2,458
375
2,833
*Includes gas and air
-226-
-------
Treatment systems are mostly of the closed type (air excluded).
Injection pressure is a regulated parameter in California so that
integrity of the receiving formation can be preserved by avoiding
fracturing under excessive pressures.
Chaffee Island Facility - A site visit was made on November 18,
1980 to a California offshore facility to observe operating prac-
tices firsthand. The Chaffee Island site, located about two
miles off Long Beach, California, was selected because of the
utilization of typical produced water pre-treatment and injection
equipment.
Chaffee Island is one of four artificial islands owned by the
City of Long Beach and operated by THUMS (Texaco, Humble -now
EXXON, Union, Mobil, and Shell Oil Companies). Chaffee Island
has the capacity to treat and inject about 50,000 barrels of pro-
duced water per day.
About 400,000 bbl/month of oil and 300,000 bbl/month of water are
produced at the four islands. The produced water is transferred
and injected among the four islands according to production
requirements.
The produced water treatment system following freewater knockout
consists of gravity settling, gas flotation and multi-media
filtration (sand plus anthracite) as shown in Figure VII-8. In
addition, chemicals are added at various points in the treatment
train to enhance treatability. These chemicals include:
Tretolite RY 9545 (an emulsion breaker), Visco 3364 (a coagulant
aid), and Petrol C-145B (a corrosion inhibitor).
A wastewater sampling program was conducted at Chaffee Island
during the period 11-21-80 through 11-24-80. Samples were taken
-227-
-------
at three points in the treatment train, namely: clarifier
influent, dispersed gas flotation effluent and multi-media filter
effluent. These points are shown in Figure VII-8. Both com-
posite (24 hour) and grab samples were taken. The samples were
analyzed for all priority pollutants, other metals and conven-
tional pollutants. The results of these analyses are shown in
Tables VII-6 through VII-8. Priority pollutants not appearing in
these tables were not detected in any of the samples.
California Water Quality Standards for Ocean Waters - The Water
Quality Control Plan for Ocean Waters of California has limiting
concentrations for several metals and phenolic compounds. These
limits are:
Limiting Concentrations, mg/1
Arsenic
Cadmium
Total Chromium
Copper
Lead
Mercury
Nickel
Silver
Zinc
Cyanide
Phenolic Compounds
6-Month
Median
0
0.02
Daily
Maximum
0.008
0.003
.002
0.005
0.008
0.00014
0.02
0.00045
0.020
0.005
0. 12
Instantaneous
Maximum
0.032 .
0.012
0.008
0.020
0.032
0.00056
0.08
0.0018
0.08
0.02
0.3
0.08
0.03
0.02
0.05
0.08
0.0014
0.2
0.0045
0.2
0.05
A comparison of these limits to the analytical results of Table
VII-8 for Chaffee Island (which are assumed to be typical pro-
-228-
-------
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duced water characteristics) explains the need for the widespread
injection practices in California ocean waters.
Louisiana - About 60 percent of the total oil production in
Louisiana during 1978 was from offshore operations. Table VII-9
summarizes the oil . production and produced water statistics for
the State of Louisiana during 1978 with breakdowns for the
onshore and offshore segments. A summary of the onshore produced
water disposal practices is given in Table VII-10. On a state-
wide basis, about 65 percent of the total onshore produced water
is reinjected for disposal purposes only. This is in contrast to
the onshore disposal practices in California where reinjection
for enhanced recovery is the predominant practice.
In Louisiana formations receiving produced waters are highly
porous. In the majority of cases, producers are able to identify
acceptable reinjection formations on the production lease.
Reinjection depths range from 2,000 to 5,000 feet and wellhead
pressures seldom exceed 200 psig. The pretreatment facilities
may include primary separation and sedimentation, although rein-
jection without pretreatment is also practiced.
Offshore produced waters are treated to meet the effluent limita-
tions based on "best practicable control technology currently
available" (BPT) and then discharged to ocean waters. Effluent
BPT limitations for offshore produced waters are:
Oil and Grease: Maximum for any one day 72 mg/1
Average for 30 consecutive days 48 mg/1
Texas - Texas is the largest oil-producing state in the United
States. Table VII-11 summarizes the oil production and produced
-233-
-------
TABLE VII-9
LOUISIANA OIL PRODUCTION AND PRODUCED WATER STATISTICS [216]
LOCATION
Onshore
Offshore
Total
1978 OIL PRODUCTION
Amount
(bbl/year)
222,241,000
310,499,000
532,740,000
Number of
Wells
16,747
7,049
23,796
Average
Production per
Well (bbl/day)
37
121
61
(1)
1974 Water
Production
(bbl/year)
1,068,454,000
(2)
—
(2)
(1) 1978 Water production figures are not available. Onshore oil
production in Louisiana during 1974 was 307,495,000 barrels or
38 percent higher than 1978 level. Proportionately, onshore 1978
water production would be 772,300,000 barrels.
(2) Actual figures are not available.
-234-
-------
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water statistics for Texas including breakdowns for onshore and
offshore segments. In 1978, there were over a billion barrels of
oil produced in Texas involving more than 200 of the 254 counties
in the state. More than 99 percent of the total oil production
in Texas is from onshore wells.
The operation of oil and gas fields in the state is controlled by
the Texas Railroad Commission. Regulations prohibit the
discharge of any produced water to fresh water streams. Because
of the close regulation of the industry and because most fields
have secondary oil recovery using water flooding, reinjection of
produced waters is extensively practiced. Produced water is also
reinjected for disposal on a routine basis. There are currently
over 40,000 onshore produced water reinjection wells, of which
about 32,000 are used for enhanced recovery purposes. The
remaining 8,000 wells reinject produced water for disposal pur-
poses only. More than 99 percent of all produced water from
onshore wells in Texas is reinjected onshore. The water produced
offshore constitutes less than one percent of the State's total
produced water. This offshore produced water is treated to the
level of BPT effluent limitations and-discharged to ocean waters.
Production wells in Texas range in depth from 100 feet to over
20,000 feet. Disposal wells range in depth from 250 feet to over
10,000 feet although the depth usually does not exceed 2,000
feet. The producing well and the reinjection well are often part
of the same lease, with the disposal well located above the pro-
ducing formation. Thus, in the majority of cases, producers are
able to identify acceptable reinjection formations on the produc-
tion lease.
Pretreatment, prior to reinjection, consists primarily of a gun-
barrel separator to remove free oil followed by holding tanks.
-237-
-------
The holding tanks serve the dual purpose of providing additional
oil separation and surge control for the injection pumps.
Reinjection is into single or multiple well systems depending on
the quantity of water to be disposed of. Several pre-treatment
facilities are often interconnected, and use common reinjection
wells. Chemicals are added as required. Biocides are used to
control sulfite reduction (that would precipitate metal
sulfides). Surfactants are used where greater formation per-
meability is required.
A discussion of produced water reinjection technology, as
currently practiced onshore and offshore, was presented in the
preceding sections. Specifically, onshore produced water rein-
jection practices were discussed in the context of industry
experience in Texas, Louisiana, and California. In the offshore
segment industry experience in California provided the context
for the discussion of produced water reinjection technology.
Evaporation - Zero Discharge - Evaporation of produced water to
achieve zero discharge requires ponds with large surface areas
located in regions where climatic conditions are such that net
evaporation (versus rainfall) occurs. The construction of eva-
poration ponds on offshore facilities would be impossible due to
the large areas required. The piping of the produced water to
land-based evaporation ponds is feasible; however, the climatic
conditions along the relatively near coastlines are not subject
to a net evaporation loss (rainfall is greater than evaporation).
Therefore, the use of evaporation for produced water disposal
from offshore facilities is considered technically infeasible.
Biological Treatment - Treatment by biological processes may
remove the priority pollutants in produced water. However, due
-238-
-------
to the relatively large treatment vessels required, the use of
biological treatment on offshore facilities is impractical. The
dissolved solids (measure of brine content) levels in produced
water are significantly higher than levels at which any biologi-
cally activated treatment system has been used or even tested.
Therefore, EPA rejected biological treatment from further con-
sideration for either onshore or offshore for NSPS and BAT
because it is, at present, technologically infeasible to imple-
ment on a national basis for this industry segment.
Chemical Precipitation - Precipitation is a chemical unit process
which converts soluble metallic ions and certain anions to an
insoluble form. It is a commonly used treatment technique for
removal of heavy metals, phosphorous, and hardness. Chemical
precipitation is always followed by a solids separation operation
that may include coagulation, sedimentation or filtration to
remove the precipitates. Precipitation reactions frequently used
for industrial wastewater treatment are one or a combination of
the following processes:
o Hydroxide precipitation
o Sulfide precipitation
o Cyanide precipitation
o Carbonate precipitation
o Co-precipitation
Precipitation is effected by the addition of either hydroxides,
sulfides or other chemicals at elevated pH values which decreases
the solubility of metal ions contained in the wastewater. A pre-
cipitate is formed which is removed from the wastewater by mecha-
nical means such as settling, filtration, etc. This process
usually produces large amounts of sludges which require dewa-
-239-
-------
taring and disposal. If settling is used to remove the precipi-
tates, relatively large treatment vessels are required.
Performance data on chemical precipitation followed by filtration
obtained from other industries are summarized in Table VII-12.
The theoretical minimum solubilities for different metals is
shown on Figure VII-9. For maximum reductions of metals levels
in a solution containing a mixture of metal ions, either an opti-
mum pH level must be determined to minimize the solubilities of
the predominant metals or else a treatment train consisting of
staged precipitation steps to sequentially treat each predominent
metal species must be designed. A complicating factor in the
case of produced water is that the solubility of metals generally
increases with increasing salinity of the wastewater.
The Agency evaluated the efficacy of hydroxide (lime) and sulfide
precipitation, the two most likely types of chemical treatment
for the reduction of metals levels in produced water. The
Agency's analytical data on produced water prior . to treatment
indicates that zinc is the only priority pollutant metal found in
the majority of samples of produced water discharges. Hydroxide
precipitation was determined to effect virtually no removal of
zinc from BPT-treated produced water because of the low con-
centrations of zinc in the BPT effluent. Sulfide precipitation
was found to cause potentially serious problems with its use,
including generation of sulfide gases and toxicity of the treat-
ment chemicals. In addition, with the use of chemical precipita-
•*
tion, large settling facilities would be required to effect
proper treatment and even then the large quantities of generated
sludge would have to be disposed. Thus, EPA rejected chemical
precipitation from further consideration for NSPS and BAT on a
-240-
-------
TABLE VII-12
CONTROL TECHNOLOGY SUMMARY FOR CHEMICAL
PRECIPITATION WITH FILTRATION
FOR SEVERAL INDUSTRIAL GROUPS [217]
DATA POINTS
PILOT FULL
POLLUTANT SCALE SCALE
Classical pollutants, mg/L:
TSS
Total phosphorus
Total phenols
Oil and Grease
Fluoride
Aluminum
Manganese
Vanadium
Barium
Iron
Tin
Titanium
Gold
Palladium
Cyanide, total
Calcium
Magnesium
Sodium
Molybdenum
Cobalt
TDS
Yttrium
Osmium
Indium
Rhodium
Platinum
Boron
Toxic pollutants, ug/L:
Antimony
Arsenic
Beryl liuin
Cadmium
Chromium
Copper
Lead
Mercury
Nickel
Selenium
Si Iver
Thallium
Zinc
Sis (2-ethylhexyl) phthatate
Butyl benzyl phthalate
Di-n-butyl phthalate
Diethyl phthalate
Phenol
Benzene
Toluene
Anthracene
Napthalene
Phenanthrene
Carbon Tetrachloride
Chloroform
Methyl ene chloride
1,1,1 -Tnchloroethane
Tr ichloroethyl ene
6
6
1
5
6
1
1
1
1
6
5
1
5
2
4
1
1
1
1
1
5
1
2
1
2
2
1
1
1
1
5
5
6
6
1
6
1
3
1
6
3
1
3
3
1
1
1
2
2
1
1
1
2
2
1
EFFLUENT REMOVAL
CONCENTRATION EFFICIENCY, %
KANGt
7.0 -
0.58 -
BDL -
1.0 -
0.046 -
NO -
ND -
0.032 -
5.0 -
2,756 -
ND -
0.01 -
NO -
ND -
5.0 -
16 -
NO -
ND -
4.5 -
10 -
SDL -
BOL -
ND -
ND -
ND -
ND -
0.3 -
30
52
8. 0
15
4. 7
0.75
40
0.14
190
5,700
ND
0.10
1.2
19
2,200
1,700
68
1,700
34
60
84
80L
75
75
BDL
16
1.0
MEDIAN RANGE
17 0-98
4.8 9-82
ND
BDL
4.2 15 - 54
1.0
0.02
0.01
0.005
0.18 45 - >99
0.06 0 - >99
0.002
0.14 8 - >99
0.086
70 0-40
110
3.7
500
0.80
0.005
4,800
0.02
ND 99 - >99
0.08*
0.05 69 - 86
0.6
3.0
40
4.0
1.0
6 0 - >99
18 50 - >99
780 14 - 99
23 81 - >99
0.10
205 47 - >99
40
9.0 40 - 78
50
15 82 - >99
10
SDL
8DL
BDL 25 - > 99
13
1.0*
SOL
ND
BDL
ND
BDL
BDL
8
0.7
0.1*
MEDIAN
77
41
>99
44
33
99
92
0
84
95
79
50
50
71
24
NM
66
NM
NM
86
NM
0
>99
NM
78
>99
NM
NM
33
0
14
99
98
92
67
97
NM
42
0
93
95*
NM
NM
62
NM
NM
NM
NM
NM
NM
NM
NM
NM
75
NM
Blanks indicate data not available.
BOL, below detection limit.
ND, not detected.
NM, not meaningful.
* Approximate value.
-241-
-------
FIGURE VII-9
10'
10
Pb(CH).
01 2 3 45 67 3 9 10 11 12 13 14
SOLUBILITY OF METAL HYDROXIDES AND SULFIDES AS A
FUNCTION OF pH
Source:215
-242-
-------
national basis for this industry segment because of operational
problems with implementing the technology and non-quantifiable
reductions of priority pollutant metals levels in produced water.
Activated Carbon Adsorption - Activated carbon is a material
which selectively removes contaminants from wastewater by adsorp-
tion. A treatment system utilizing activated carbon must be
designed using the proper kinetics for the specific wastewater
being treated. In designing an activated carbon system the
proper type and amount of activated carbon, the empty bed contact
time and the periods between regeneration must be determined.
This determination is difficult since the quality of the produced
water is variable and can change from well field to well field.
It is also dependent upon the characteristics of the oil or gas
being produced.
Presently, activated carbon is not utilized in the treatment of
produced waters from oil and gas wells. Therefore, the removal
efficiencies of activated carbon can only be estimated using data
from industries where activated carbon is presently utilized in
the treatment of wastewaters. Data is available from the
following industries and is summarized on Table VII-13:
o Auto and Other Laundries,
o Electrical and Electronic Components,
o Gum and Wood Chemicals,
o Ore Mining and Dressing,
o Organic Chemicals Manufacturing,
o Petroleum Refining,
o Pulp and "Paper Mills,
o Textile Mills, and
o Pesticides Manufacturing.
-243-
-------
Generally, activated carbon systems are preceded by treatment
systems such as chemical treatment or filtration which will
remove suspended solids and other materials that will interfere
with adsorption by activated carbon. A review of the pollutant
reductions achievable by chemical treatment and filtration was
performed and is presented on Table VII-12. This data was com-
pared with that achievable by activated carbon, as shown on Table
VII-13.
EPA determined that carbon adsorption is presently tech-
nologically infeasible to implement in this industry segment.
This is because of the unknown effects that the brine-like nature
of produced waters has on the adsorption process, the lack of
performance information in either the literature or on a pilot or
full-scale basis, and the disproportionately high costs to even
attempt to implement this technology on a national basis for this
industry segment. Therefore, EPA rejected carbon adsorption from
further consideration for NSPS and BAT for produced water.
PRODUCED SAND
The fluids produced with oil and gas may contain small amounts of
sand, which must be removed from lines and vessels. This may be
accomplished by opening a series of valves in the vessel mani-
folds that create high fluid velocity around the valve. The sand
is then flushed through a drain valve into a collector or a
55-gallon drum. Produced sand may also be removed in cyclone
separators when it occurs in appreciable amounts.
The sand that has been removed is collected and taken to shore
for disposal; or the oil is removed with a solvent wash and the
sand is discharged to surface waters directly.
-244-
-------
TABLE VII-13
CONTROL TECHNOLOGY SUMMARY FOR ACTIVATED CARBON ADSORPTION-GRANULAR
FOR
SEVERAL INDUSTRIAL GROUPS [217]
DATA POINTS
POLLUTANT
Classical pollutants, mg/L:
800(5)
COO
TSS
TOC
Total phosphorus
Total phenols
Oil and grease
Aluminum
Manganese
Vanadiun
Bariim
Iron
Sulfides
Calcium
Magnesium
Sodium
Molybdenum
Cobalt
Boron
Ammonia
Toxic pollutants, ug/L:
Antimony
Ar seme
Beryl lium
Cadmium
Chromium
Copper
Cyanide
Lead
Mercury
Nickel
Selenium
Si Iver
Thallium
Zinc
Bis (2-ethylhexyl) phthalate
Butyl benzyl phthalate
Di-n-butyl phthalate
Diethyl phthalate
Dimethyl phthalate
Di-n-octyl phthalate
N-nitrosodiphenylamine
N-nitrosodi-n-propyl anune
PILOT
SCALE
8
25
13
30
8
5
7
8
8
8
8
8
2
8
8
7
3
8
8
6
14
14
14
14
15
16
11 -
15
6
15
11
15
11
16
7
2
7
3
1
1
1
FULL
SCALE
6
7
9
10
1
5
2
1
1
3
3
3
2
3
2
3
3
1
2
1
1
EFFLUENT
CONCENTRATION
RANGE
1.9 -
11 -
CI.3 -
6.2 -
<0.07 -
<0.005 -
2.2 -
0.02 -
<0.005 -
0.006 -
<0.001 -
0.02 -
<0.005 -
4.4 -
0.86 -
51 -
<0.01 -
<0.006 -
0.009 -
0.21 -
1.3 -
<1 -
<0.04 -
<1.5 -
<4 -
<4 -
<2 -
<18 -
<0.01 -
8DL -
<1 -
1,7 -
<15 -
<1 -
4.7 -
SDL -
BOL -
1.2 -
37,000
110,000
2,600
67,000
14
4.3
82
9.2
0.61
0.18
0.08
1.9
0.01
70
5.8
260
<0.2
C0.04
1.1
19
590
42
5.4
<40
260
360
52
79
<1 .1
<700
50
0100
<50
6,000
410
17
11
9.5
MEDIAN
25
330
13
120
1.5
0.02
8.4
0.13
0.03
0.03
0.014
0.24
0.008
5.4
2.7
170
<0.01
<0.006
0.48
1.25
<25
12
<2
<2
<20
<18
<5
<22
<0.5
<36
<20
<5
<15
69
25
SDL
1.1
0.85
SDL
4
0.4
SOL
REMOVAL
EFFICIENCY, %
RANGE
18
0
6
5
0
38
5
0
14
0
0
24
0
0
0
14
0
5
0
0
76
10
13
>1
2
10
0
12
5
26
53
0
- 73
- 99
- 99
- 99
- 57
- 97
- 92
- 81
- >90
- 65
- 55
- 93
- 33
- 26
9
- 82
- 50
- 15
- 33
- >99
- 95
- 95
- >85
- >90
- >72
- 68
- 50
- 36
- >99
- 66
- 99
- 99*
MEDIAN
43
59
59
55
5
86
26
30
40
25
29
59
50
9
10
6
0
>33
4
10
19
0
NM
86
42
>64
>63
5
0
39
11
24
NM
64
46
97
76
5
NM
20
NM
NM
-245-
-------
TABLE VI I-13
CONTROL TECHNOLOGY SUMMARY FOR ACTIVATED CARBON ADSORPTION-GRANULAR
FOR
SEVERAL INDUSTRIAL GROUPS [217]
(Continued)
DATA POINTS
POLLUTANT
2,4-Dichlorophenol
2, 4-0 ime thy 1 phenol
Pentachlorophenol
Phenol
p-Ch loro-m-creso I
Benzene
Chlorobenzene
1 ,2-Qichlorobenzene
Ethyibenzene
Toluene
1 ,2,4-Tnchlorobenzene
Anthracene
8enzo(a)-pyrene
Benzo( k)f luoranthene
Fluor an thene
Fluorene
Napthalene
Phenanthrene
Pyrene
Chloroethane
Chloroform
1 , 1-Di chloroethane
1 ,2-Oichloroethane
1 , 1-Oichloroethylene
1 ,2-Tr ans-dichloroethyl ene
1 ,2-Oichloropropane
Methylene chloride
Tetrachloroethylene
1 , 1 ,1-Trichloroethane
1 , 1 ,2-Tnchloroethane
Tr ichloroethylene
Tnchlorofluorome thane
Vinyl chloride
Alpha - 8HC
4, 4' -DOT
Heptachlor
PILOT
SCALE
2
2
2
7
2
3
1
3
7
8
1
5
2
1
2
1
2
2
12
5
10
13
1
3
4
9
3
2
3
3
2
3
1
1
1
i
EFFLUENT
FULL CONCENTRATION
SCALE RANGE
BDL -
SDL -
2 BOL -
2 BDL -
BDL -
1 SDL -
BDL -
BDL -
3 BOL -
1 NO -
BDL -
BOL -
BDL -
1
BDL -
BDL -
NO -
1 NO -
1 NO -
ND -
1 ND -
1 1.1 -
ND -
2 1.8 -
BDL -
1 ND -
ND -
1 BDL -
BDL -
1,100 -
BDL
0.9
49
49
BDL
210
5.4
1.3
630
94
0.4
0.8
BDL
BDL
BDL
240,000
18
45,000
760,000
1.4
140
BDL
940
32
1 .9
•NO
5
69
9,600
MEDIAN
BDL
0.7
6.5
7
BDL
5
BDL
BDL
BDL
1.6
47
0.1
0.41
BDL
BDL
BDL
78
BDL
BDL
2,300
BDL
ND
90
0.7
58
ND
19
BDL
ND
ND
2.5
35
3,600
1.9
BOL
BDL
REMOVAL
EFFICIENCY, v«
RANGE
59 -
0 -
64 -
23 -
50 -
88*-
97*-
95*-
0 -
64*-
42 -
21 -
96 -
65*-
0 -
99 -
>99 -
58 -
99*
98*
90
99
97*
95
99*
98
>99
>99
>99
>99
98
>99
99
>99
>99
99
MEDIAN
NM
MM
79
50
17*
77
98*
• 99*
50*
75
>99
80
95
90
92
NM
51
98*
97*
>99
>99
>99
>99
>99
97
>99
70
68
>99
>99
75
NM
52
NM
NM
NM
Blanks indicate data not available.
BDL, below detection limit.
ND, not detected.
NM, not meaningful.
* Approximate value.
-246-
-------
Field investigations have indicated that some Gulf Coast facili-
ties have sand removal equipment that flushes the sand through
the cyclone drain valves, and then the untreated sand is bled
into the waste water and discharged overboard.
No sand problems have been indicated by the operators in the Cook
Inlet area. Limited data indicate that California pipes most of
the sand with produced fluids to shore where it is separated and
sent to State approved disposal sites.
At least one system has been developed that will mechanically
remove oil from produced sand. The sand washer systems consist
of a bank of cyclone separators, a classifier vessel, followed by
another cyclone. The water passes to an oil water separator, and
the sand goes to the sand washer. After treatment, the sand is
reported to have no trace of oil, and the highest oil con-
centration of the transferred water was less than 1ppm of the
total volume discharged. [3]
DECK DRAINAGE
Where deck drainage and deck washings are treated in the Gulf
Coast, the water is treated by gravity separation, or transferred
to the production water treatment system and treated with produc-
tion water. Platforms in California pipe and deck drainage and
deck washings along with produced fluids to shore for treatment.
In Cook Inlet, these wastes are being treated on the platform.
Field investigations conducted on platforms at Cook Inlet indi-
cate that the most efficient system for treatment of deck
drainage waste water in this area is gas flotation. Limited data
indicate an average effluent of 25 mg/1 can be obtained from this
-247-
-------
system. The field investigations found that deck drainage
systems operate much better when crankcase oil is collected
separately and when detergents are not used in washing the rigs.
The practice of allowing inverted emulsion muds to get into the
deck drain system, during drilling or workovers, also seemed to
adversely effect treatment. [3]
BPT Technology
BPCT for deck drainage is based on control practices used within
the oil producing industry and include the following:
1. Installation of oil separator tanks for collection of deck
washings.
2. Minimizing of dumping of lubricating oils and oily wastes from
leaks, drips and minor spillages to deck drainage collection
systems.
3. Segregation of deck washings from drilling and workover
operations.
4. O&M practices to remove all of the wastes possible prior to
deck washings.
BPCT end-of-pipe treatment technology for deck drainage consists
of treating this water with waste waters associated with oil and
gas production. The combined systems may include pretreatment
(solids removal and gravity separation) and further oil removal
(chemical feed, surge tanks, gas flotation). The system should
be used only to treat polluted waters. All storm water and deck
washings from platform members containing no oily waste should be
-248-
-------
segregated as it increases the hydraulic loading on the treatment
unit. [3]
SANITARY WASTES
There are two alternatives to handling of sanitary wastes from
offshore facilities. The wastes can be treated at the offshore
location or they may be retained and transported to shore facili-
ties for treatment. Offshore facilities usually treat waste at
the source. The treatment systems presently in use may be cate-
gorized as physical/chemical and biological.
«
Physical/chemical treatment may consist of evaporation-
incineration, maceration-chlorination, and chemical addition.
With the exception of maceration-chlorination, these types of
units are often used to treat wastes on facilities with small
complements of men or which are intermittently manned. The
incineration units may be either gas fired or electric. The
electric units have been difficult to maintain because of salt
water corrosion and heating coil failure. The gas units are not
subject to these problems but create a potential source of igni-
tion which could result in a safety hazard at some locations.
Some facilities have chemical toilets which require hauling of
waste and create odor and maintenance problems. Macerator-
chlorinators have not been used offshore but would be applicable
to provide minimal treatment for small and intermittently manned
facilities. At this time, there does not appear to be a totally
satisfactory system for small operations.
The most biological system applied to offshore operations is
aerobic digestion or extended aeration processes. These systems
usually include: a comminutor which grinds the solids into fine
-249-
-------
particles; an aeration tank with air diffusers; a gravity
clarifier return sludge system; and a tank. These biological
waste treatment systems have proven to be technically and econo-
mically feasible means of waste treatment at offshore facilities
which have more than ten occupants and are continuously manned.
[3]
BPT Technology
BPCT for sanitary wastes from offshore manned facilities with 10
or more people is based on end-of-pipe technology consisting of
biological waste treatment systems (extended aeration). The
system may include a comminutor, aeration tank, gravity
clarifier, return sludge system, and disinfection contact
chamber or other equivalent system. Studies of treatability,
operational performance, and flow fluctuations are required prior
to application of a specific treatment system to an individual
facility. [3]
DOMESTIC WASTES
Domestic wastes result from laundries, galleys, showers, etc.
Since these wastes do not contain fecal coliform, which must be
chlorinated, they must only be ground up so as not to cause
floating solids on discharge. Traceration by a comminutor should
be sufficient treatment.
Since these wastes contain no fecal coliform, chlorination is
unnecessary. Treatment, such as the use of macerators, is
required to guarantee that this discharge will not result in any
floating solids. [3]
-250-
-------
REFERENCES
3. Development Document for Interim Final Effluent Limitations
Guidelines and Proposed New Source Performance Standards for
the Oil & Gas Extraction Point Source Category, U.S.
Environmental Protection Agency, September 1976, EPA
440/1-76-005-a-Group II.
166. Ayers, R. C., Jr., T. C. Sauer, Jr., R. P. Meek, and
G. Bowers, An Environmental Study to Assess the Impact of
Drilling Discharges in the Mid-Atlantic, Report 1 - Quantity
and Fate of Discharges, Symposium - Research on
Environmental Fate and Effects of Drilling Fluids and
Cuttings, Sponsored by API, Lake Buena Vista, Florida,
January 1980.
210. Sport, M.C., Design and Operation of Gas Flotation Equipment
for the Treatment of Oilfield Produced Brines, Presented at
Offshore Technology Conference, Houston, Texas, May 1969.
215. Draft Development Document for Effluent Limitations
Guidelines and Standards for the Metal Finishing Point
Source Category, U.S. Environmental Protection Agency,
EPA-440/1-80/091-a, 1980.
216. Technical Feasibility of Brine Reinjection for the Offshore
Oil and Gas Industry, Prepared by Burns and Roe Industrial
Services Corporation, Prepared for U.S. Environmental
Protection Agency, Effluent Guidelines Division and
Industrial Environmental Research Laboratory, May 1981.
217. Summarized from Information Contained in Development
Documents and Draft Development Documents for Effluent
Limitations Guidelines and Standards for the Referenced
Point Source Categories, U.S. Environmental Protection
Agency, Effluent Guidelines Division, Variously Dated.
234. Swanston, H.W. and H.R. Heffler. 1977. Environmental con-
siderations in waste disposal from drilling in the shallow
Beaufort Sea. The Journal of Canadian Petroleum Technology.
July-September 1977.
235. Engineering Specialities Inc. 1981. Manufacturer's litera-
ture.
236. Ferraro, J.M. and S.M. Fruh. 1977. Study of pollution
control technology for offshore oil drilling and production
platforms. Prepared for U.S. Environmental Protection
Agency. Cincinnati.
-251-
-------
237. Forster, R.L., J.E. Moyer and S.I. Firstman, 1973. Port
collection and separation facilities for oily wastes, Vol.
I. Collection, treatment and disposal of oily water wastes
from ships and Vol. II General technology U.S. Department of
Commerce, Maritime Administration. NTIS COM73-11068 and
-11069.
238. Tramier, B., E. deMerville, G. Oldham, T. Pytel, J. Rudd and
H. Van Laar. 1982a. Treatment of Production Water - State
of the Art. International Exploration & Production Forum.
London, England. Technical Review No. 3.
241 Jones, M., IMCO Services, Burgbacher, J., Shell Offshore
Inc., Churan, M. and Hulse, M.-, IMCO Services. "Efficiency
of a Single Stage Cuttings Washer With a Mineral-Oil Invert
Emulsion Mud and its Environmental Significance". Society
of Petroleum Engineers of AIME presented at 68th Annual
Technical Conference in San Francisco, CA, October 5-8,
1983.
242. Krol, D.A., Gulf Research & Development Co. "An Evaluation
of Drilling Fluid Lubricants to Minimize Differential
Pressure Sticking of Drill Pipe" presented at Drilling
Technology Conference of International Association of
Drilling Contractors, March 19-21, 1984.
243 Cowan, J., Venture Chemicals, Inc. and Brookey, T.,
Hughes/Dmi Drilling Fluids "An Overview of Low Toxicity
Oils" presented at Drilling Technology Conference of
International Association of Drilling Contractors, March
19-21, 1984.
247. Draft Report - Review of Drill Cuttings washer Systems -
Offshore Oil and Gas Industry, Prepared for U.S. EPA, by
Burns and Roe Industrial Services Corporation, October 1983.
251 "Drillings Discharges in the marine Environment," National
Academy Press, 1983.
255. Sawow, Rondal D., 1972. "Pretreatment of Industrial
Wastewaters for Subsurface Injection" and, "Underground
Waste Management and Environmental Implications." In: AAPG
Memoir 18, pp. 93-101.
270. Bennett, R. B., 1983. "New Drilling Fluid Technology -
Mineral Oil Mud," paper presented at: IADC/SPE 1983
ni-illina rnnfiar-Anr-o. N«>u Cir 1 oane: . f.A
Mineral oil Mud," paper presented at:
Drilling Conference, New Orleans, LA.
272. Revised Preliminary Ocean Discharge Criteria Evaluation,
Gulf of Alaska - Cook Inlet, OCS Lease Sale 88 and State
Lease Sales Located in Cook Inlet, USEPA Region 10,
September 28, 1984.
-252-
-------
273. Preliminary Discharge Criteria Evaluation for the Endicott
Development Project, USEPA Region 10, August 1984.
274. Mud Equipment Manual, Handbook II; Disposal Systems, IADC
Manufacturer - User Conference Series on Mud Equipment
Operations, Gulf Publishing Co., 1976.
275. Boyd, P.A., Whitfill, D.L., Cartert, S., and Allamon, J.P.,
"New Base Oil Used in Low-Toxicity Muds", SPE 12119, pre-
sented at the 58th Annual Technical Conference and
Exhibition of SPE, San Francisco, CA, October 5-8, 1983.
276. Petrazzuolo, Gary, "A Review of the Potential Environmental
Effects of Mineral Oil Used on Drilling Fluids," Draft
Report, Technical Resources, Inc., Bethesda, MD, May 16,
1983.
-253-
-------
VIII. COST, ENERGY, AND NON-WATER QUALITY ASPECTS
INTRODUCTION
This section presents the costs, energy requirements, pollution
control and non-water quality aspects of the NSPS, BAT and BCT
technologies discussed in Section VII. An analysis of these
issues was conducted pursuant to Sections 304(b) and (c) of the
Clean Water Act. Table VIII-1 summarizes the treatment options
costed for each waste stream type. It is important to note that
the technology costs contained herein represent the additional
investment required beyond those costs associated with BPT tech-
nologies. In other words, the cost presented in this section are
incremental costs and are related only to the specific control
technology options which may be necessary for compliance with the
recommended BAT or NSPS effluent limitations. This section also
presents the non-water quality aspects of implementing the can-
didate BAT and NSPS technologies. These aspects include energy
requirements, solid waste generation and disposal, air pollution
and consumptive water loss.
COST METHODOLOGY
A critical factor that must be considered in the adoption of any
effluent limitation guideline is the potential economic impact of
such a regulation on the industry being regulated. In order to
address this economic impact, the cost of the control tech-
nologies associated with the proposed effluent limitation guide-
line must be evaluated. Presented below is a discussion of the
methodology used to develop cost data for control technologies
applicable to the offshore oil and gas industry. These costs
-255-
-------
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were then used to assess the economic impact of the proposed
regulatory options on the industry in "Economic Impact Analysis
of Proposed Effluent Limitations and Standards for the Offshore
Oil and Gas Industry," EPA, 1985.
PRODUCED WATER
Oil and gas well production, in addition to the product, includes
quantities of water containing various contaminants. These
waters must be separated from the product and treated so that
they may be disposed of in an environmentally acceptable manner.
Mode1 PIa t f orm Approach
Since it was not practical to evaluate each individual platform
to determine treatment costs, an alternative analytical approach
was needed. In response to this need, 32 model platforms were
developed to represent the platform population in the offshore
oil and gas industry, including both existing and new sources
[218]. For the purposes of this study, various model platform
sizes, based on produced water discharge rates, were selected to
represent the current and future industry profile. Table VIII-2
lists the model platform sizes used and the geographic location
of each. These model platform sizes were judged to encompass the
normal range of production volumes and produced water discharge
volumes expected to occur at facilities in the Gulf of Mexico,
the East Coast, the West Coast and various locations in Alaska.
The maximum flow of produced water that could be expected at any
time was used to size and cost the treatment equipment. The
average flow of produced water over the life of the platform was
used to estimate operating costs. In the discussions that
follow, all control technology options were evaluated on the
-257-
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TABLE VII1-2
OFFSHORE OIL AND GAS EXTRACTION INDUSTRY
PRODUCED WATER GENERATION
MODEL PLATFORM PRODUCED WATER MAX AND AVG FLOWS [219;
f nPlTTHM KIAMP AXir* t»JPT T Q
ijwv*nJL 1\JN CMr\rlIli jHUNU WEjlj-uO
OIL Gulf of Mexico Gulf 4
Gulf 2X5
Gulf 12
Gulf 24
Gulf 40
Gulf 5S
Pacific Coast Pacific 16
Pacific 40
Pacific 34
Atlantic Coast Atlantic 24
Alaska-
Cook Inlet Cook Inlet 24
Gravel Isl. 48
Bering PI. 48
Beaufort Sea Beaufort Pi. 48
GAS Gulf of Mexico Gulf 4
Gulf 2X5
Gulf 12
Gulf 24
Pacific Coast Pacific 16
Atlantic Coast Atlantic 24
Alaska Cook Inlet 12
PRODUCED
FLOW (
MAX
2000
5000
5000
9000
16000
25000
7400
8700
35000
20000
30000
70000
80000
100000
1614
4037
4037
121 1
5744
3074
18432
WATER
BWPD)
AVG
1000
2500
2500
4500
8000
12500
3700
9350
17500
10000
15000
35000
40000
50000
328
433
433
217
551
2376
1614
BWPD: Barrels water per day.
-258-
-------
basis of these model sizes. The costs were developed for these
model platforms on two bases:
(1) Model production platforms which are presently in place
(existing sources). These platforms would be subject
to BAT and BCT regulations, and
(2) Model platforms which are new sources and subject to
New Source Performance Standards (NSPS).
Cost Development Factors
In order to develop cost estimates for the selected control tech-
nologies, certain fundamental factors were developed with respect
to capital and operation/maintenance costs. These cost factors,
which are independent of the specific technology under con-
sideration, are based upon the following assumptions:
Capital Costs - Cost of Equipment
The costs of the equipment required for treatment and disposal
were based on a report which presented engineering designs for
various treatment technologies [219]. All equipment sizing was
based on the maximum quantities of produced water as shown in
Table VIII-2. The prices were obtained using material quantities
and cost data obtained from equipment manufacturers, as well as
from reference [219]. The unit prices were obtained from the
1981 Means Construction Cost Data Manual adjusted to 1982. The
costs for well reinjection pumps and drivers were derived from
equipment manufacturers quotes [220] . For equipment installation
costs on offshore platforms, multipliers of 3.5 were used for
skid-mounted equipment and 4.0 for equipment that has to be
-259-
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assembled on the platform. These multipliers were obtained from
reference [9]. The following assumptions were used in the sizing
of the unit processes:
o Filters are granular media, pressure type, designed to
remove suspended solids and oil and grease from the
produced water. Each system includes a spare filter
unit for use during backwashing operations. Filtration
rates vary from 1.5 gpm/sq.ft. to 6.0 gpm/sq.ft.
depending on the flow of water to be filtered and
filter manufacturers' recommendations.
o Disposal wells and pumps are rated at a maximum rein-
jection rate of 6,000 barrels of produced water per day
(BWPD), each [20], One spare well and one spare injec-
tion pump, with driver, are required at each onshore or
offshore treatment facility. Therefore, a minimum of
two wells and two pumps are provided at each model
facility.
o All equipment is selected and sized for outdoor duty.
o Capital cost calculations for offshore electrical power
eneration equipment are based on the total increase in
generated power required for operation of the
wastewater treatment and disposal facilities above a
spare 25 horsepower that is presently available on the
facility. Onshore power for land-based treatment is
purchased from a local utility at a cost of
$0.035/kilowatt-hr.
o The volumes of sludge to be handled were developed on
conservative assumptions derived from contractor
-260-
-------
experience in the design, construction and operation of
similar types of wastewater treatment processes.
o Filter backwash volumes are estimated as 3 percent of
the total volume of water filtered.
o Solids in filter backwash water are at a concentration
of 5,000 mg/1 which would thicken to 20,000 mg/1 in the
backwash tank prior, to dewatering.
o The filtered and backwashed solids are dewatered in a
centrifuge, to 25 percent solids by weight.
o The water removed from the backwash solids is returned
to the head of the treatment train.
o The dewatered backwash solids are stored on the plat-
form in containers and periodically shipped to land by
supply boat for disposal.
Three of the treatment and disposal options include the treatment
of the produced water on shore. The cost estimates for these
scenarios are based on the following assumptions:
o For new source oil facilities, oil-water separation
occurs on shore; no separate pipe is used to transport
the produced water to shore. This is present practice
in various locations. However, if a third party pipe-
line (common carrier) is to be used for transport of
the oil to shore, the pipeline company may require that
oil-water separation take place on the platform to
minimize the volume of water that is carried. In that
-261-
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event, a separate pipeline and transfer pumps for the
produced water would be necessary and would be an added
capital and annual expense [222]. For existing plat-
forms all water separation was assumed to take place at
the platform.
o For gas facilities, a separate produced water pipeline
is included for both new and existing sources.
o It was assumed that the on-shore treatment facilities
would be located one quarter mile inland at an eleva-
tion of 25 feet above sea level. At the higher model
flow rates, and at a discharge distance of 1000 feet
offshore, the hydraulic head would be sufficient so
that disposal pumping is not required. For disposal
three miles or more offshore, pumping would be
required. For the lower model flow rates, pumping is
required at all distances.
o Onshore and offshore reinjection wells are 3500 feet
deep [223] .
o The costs of complying with underground reinjection
regulatory requirements are not included (i.e., UIC
requirements under the Safe Drinking Water Act).
o Treatment equipment installation costs for onshore
facilities do not include the 3.5 or 4.0 installation
multiplier factors used for offshore installation.
Instead, a standard onshore installation factor of 30%
of equipment caital cost is used.
-262-
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The base location is for facilities in the Gulf of Mexico with a
capital cost multiplier of 1 used to determine installed costs.
For offshore facilities in other areas the following cost
multipliers were used.
Location
Atlantic Coast
California Coast
Alaska
Norton Basin
Beaufort Sea
Bristol Bay
Gulf of Alaska
Cook Inlet/Shelikof
Strait
Cook Inlet/Shelikof
Strait
Capital Cost
Multiplier for
Installation[218]
1 .6
1 .6
3.5
3.5
3.5
3.5
2.0
2.5
Applicable to
Equipment and wells
Equipment and wells
Equipment and wells
Equipment and wells
Equipment and wells
Equipment and wells
Equipment and wells
Wells
Well Costs. The costs of offshore wells drilled specifically for
the purpose of reinjection of produced water and the costs of
reworked dry wells were obtained from a report prepared by Walk,
Haydel and Associates, Inc., titled "Potential Impact of Proposed
EPA BAT/NSPS Standards for Produced Water Discharges From
Offshore Oil and Gas Extraction Industry" [223]. The costs for
onshore reinjection wells were derived from a report titled "1982
Association Survey on Drilling Costs " prepared by the Statistics
Department of the American Petroleum Institute [224]. These well
costs vary greatly depending upon the demand for wells by
-263-
-------
industry at a given time and the well location. Table VIII-3
shows that the cost per foot of onshore wells can vary by as much
as 250 percent. Although equipment costs increased between 1981
and 1982 [225] the cost of onshore wells decreased by as much as
47 percent during that same period.
Platform Costs. The additional areas required on offshore
platforms to accommodate the treatment facilities were calculated
using three assumptions:
o The maximum deck area that could be added to an
existing platform is 1000 square feet.
o If more than 1000 square feet were required at an
existing platform, an auxiliary platform would be
required which is assumed to be installed in 150 feet
of water.
o For new platforms, the required area and the required
reinjection well slots would be included in the initial
design.
The costs of auxiliary platforms were derived from the Brown and
Root report [9]. The costs to construct additional space
(cantilevered platform) on an existing platform are taken at an
industry estimate of $220 per square foot. The cost of addi-
tional area on'a new platform is $350 per square foot. Costs of
additional well slots were estimated to be $148,000 per slot
[227]. The costs of auxiliary platforms were estimated using the
following formula, derived from [219] data:
Cost = ($1,406,000 + [square feet required - 1000] x $78) x
ENR-CCI* (3825/2212). (*Engineering News Record - Construction
-264-
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TABLE VIII-3
OFFSHORE OIL AND GAS INDUSTRY
TREATMENT OF PRODUCED WATER
DERIVATION OF ONSHORE REINJECTION WELL COSTS
GEOGR. AVERAGE AVERAGE AVERAGE COST/ NUMBER WEIGHTED
LOCATION DEPTH COST COST/FT 3500 FT OF COST
(FT) ($1000) ($) ($1000) WELLS ($1000)
COL. 1 COL. 2 COL. 3 COL. 4 COL. 5 COL. 6 COL. 7
Texas
RR Comm.
Dist. 2
Dist. 3
Dist *
Louisiana
(South)
Alabama
3251
3281
ins?
3038
2980
105
21 1
162
252
214
32
64
52
83
72
113
225
184
290
251
64
96
76
32
50
7235
21608
13959
9272
12544
318 64617
Weighted Cost Per Well: Sum Col. 7/Sum Col. 6 = $203,199
Say: $203,200
NOTES:
1. Data in Columns 1, 2, 3 and 6 from 1982 Association
Survey on Drilling Costs, Statistics Dept.,
American Petroleum Institute, November 1983.
[224]. Drilling costs are for the year 1982.
2. Costs in Column 3 include all costs associated
with drilling wels including mobilization,
engineering, contingencies, bonding, etc.
(Ref. p. 63 in Report cited in Note 1).
3. Assumption is that costs are linear for depths to
3500 ft.
-265-
-------
Cost Index - 3825 = average ENR-CCI for 1982, 2212 ~ average
ENR-CCI for 1975.)
For BAT, i.e., platforms that are presently producing, it is
assumed that either (1) the well slots required for reinjection
are available by using exhausted or dry wells that could be
reworked to serve as reinjection wells or (2) a combination of
exhausted production wells, dry wells and new reinjection wells
would be used. The additional platform space required is dedi-
cated to wastewater treatment equipment.
For new sources, any additional deck area and well slots that
would be required for reinjection purposes are included in the
initial design. It was assumed that (1) fifteen percent of the
total number of well slots on the platform are available for use
as reinjection wells, and (2) the same rate of dry holes would be
encountered at new platforms as were encountered at existing
platforms and are available for injection wells. The costs of
additonal deck area and well slots were not escalated by using
the location multiplier because these items do not affect the cost
of placing a facility in a particular geographical location.
Table VIII-4 shows the availability of dry holes for reinjection
based upon the above assumptions. However, in estimating the
costs for reinjection by new sources, the overriding assumption
was that all well slots, both production and reinjection, would
be included in the initial platform design since it would not be
known if enough dry holes would be available until the develop-
ment program nears completion.
Table VIII-5 presents the cost effects of locating onshore treat-
ment facilities further inland or transporting the produced water
-266-
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TABLE VIII-4
OFFSHORE OIL AND GAS EXTRACTION INDUSTRY - NSPS
PRODUCED WATER TREATMENT - ON PLATFORM FILTRATION AND REINJECTION
DRY WELL AVAILABILITY AND COSTS FOR NEW WELLS AND DRY WELL REWORKING
MODEL
PLATFORM
WELLS USABLE NEW WELLS COSTS FOR DRY COSTS FOR
REQ'D* DRY HOLES REQUIRED WELLS REWORK NEW WELLS
Oil
Gulf 4 2
Gulf 2X6 2
Gulf 12 2
Gulf 24 3
Gulf 40 4
Gulf 58 6
Pacific 16 3
Pacific 40 4
Pacific 34 7
Atlantic 24 5
Cook Inlet 24 6
Gravel Isl. 48 13
Bering Plat.48 15
Beaufort Pi.48 18
Gas
1
4
4
7
12
19
1
1
1
3
2
3
3
3
1
0
0
0
0
0
2
3
6
2
4
10
12
15
390
780
780
1170
1560
2340
390
390
390
1 170
780
1170
1170
1 170
725
0
0
0
0
0
1450
2175
4350
1450
2900
7250
8700
10875
Gulf 4
Gulf 2X6
Gulf 12
Gulf 24
Pacific 16
Atlantic 24
Cook Inlet 12
2
2
2
2
2
2
4
1
4
4
7
1
3
1
1
0
0
0
1
0
3
390
780
780
780
390
780
390
725
0
0
0
725
0
2175
NOTES;
1. Costs are in $1000 - 1982
2. A new well costs $725,000. A reworked well costs $390,000. Not
included in these figures is a multiplier of 1.10 (engineering)
x 1.15 (contingencies) x 1.04 (bonding and insurance) = 1.316,
applicable to both new well and reworked well costs.
3.* Includes one spare injection well per platform.
-267-
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TABLE VIII-5
OFFSHORE OIL AND GAS INDUSTRY
PRODUCED WATER TREATMENT
INCREMENTAL COSTS OF EXTENDING PRODUCED WATER PIPELINES
EITHER FURTHER OFFSHORE OR FURTHER INLAND (ONSHORE)
(All costs in 1982 ?) [219],
MODEL PLATFORM
Oil
Gulf 4
Gulf 2X5
Gulf 12
Gulf 24
Gulf 40
Gulf 58
Pacific 16
Pacific 40
Pacific 34
Atlantic 24
Cook Inlet 24
Gravel Island 48
Bering Platform
Beaufort Plat 48
Gas
Gulf 4
Gulf 2X5
Gulf 12
Gulf 24
Pacific 16
Atlantic 24
Cook Inlet 12
FLOW
( BWPD )
2000
5000
5000
9000
16000
25000
7400
8700
35000
20000
30000
70000
80000
100000
1614
4037
4037
12-11
5744
3074
18432
DIA.
(IN)
4
4
4
5
8
10
4
5
12
8
10
18
18
20
4
4
4
4
4
4
8
ADD'L CAP.
COST/MILE
(51000)
OFF.
200
200
200
250
400
500
200
250
600
400
500
900
900
1000
200
200
200
200
200
200
400
ON.
90
90
90
123
228
309
90
123
396
228
309
608
608
673
90
90
90
90
90
90
228
ADD'L MAINT Al
COST/MILE Al
($1000) a
OFF.
6.0
6.0
6.0
7.5
12.0
15.0
6.0
7.5
18.0
12.0
15.0
27.0
27.0
30.0
6.0
6.0
6.0
6.0
6.0
6.0
12.0
ON.
2.7
2.7
2.7
3.7
6.8
9.3
2.7
3.7
11 .9
6.8
9.3
18.2
18.2
20.2
2.7
2.7
2.7
2.7
2.7
2.7
6.8
DD'L
WUAL
DST/
ILE
20
112
112 '
180
99
116
178
180
121
185
197
162
246
269
16
65
65
20
155
52
139
TOT. ADD'L
ANN. COST/
MILE ($1000)
OFF.
6.0
6.1
6.1
7.7
12.1
15.1
6.2
7.7
18.1
12.2
15.2
27.2
27.2
30.3
6.0
" 6.1
6.1
6.0
6.2
6.1
12.1
ON.
2.7
2.8
2.8
3.9
6.9
9.4
2.9
3.9
12.0
7.0
9.5
18.4
18.5
20.5
2.7
2.8
2.8
2.7
2.9
2.8
7.0
-268-
-------
to shore from further offshore. These costs were prepared
without the use of detailed plans and specifications and thus
have an accuracy of approximately + or - 30 percent.
To arrive at total capital investment, a factor of 10 percent for
engineering, 15 percent for contingencies and 4 percent for the
costs of bonding and insurance were added to the base facilities
costs (multiplier 1.1 x 1.15 x 1.04 = 1.316).
The costs for onshore treatment of produced water from existing
offshore facilities includes the cost of piping and pumping of
produced water to shore in a separate pipeline since many
existing sources have BPT facilities and water separation at the
platform.
Annual Operating and Maintenance Costs
Annual operating and maintenance costs were estimated based on
average flows as shown on Table VIII-2.
The following operating and maintenance cost assumptions were
used :
o Maintenance
Maintenance is three percent of the total capital cost.
Where dry wells are converted to reinjection wells, a
cost equal to 3 percent of the cost of a new well was,
used since 3 percent of the reworking costs alone would
not adequately reflect the total cost of reinjection
well maintenance.
-269-
-------
o Operating Personnel
A salary of $30.00/hr per operator was assumed, which
includes fringe benefits, insurance, etc.
o Electricity
$0.035 per kilowatt-hr.
o Chemicals
Prices were obtained from the Chemical Marketing
Reporter.
o Other Power Costs
Gas turbines are used for injection of produced water.
Natural gas at the platform is the source of fuel. A
bulk commercial rate for natural gas of $5 per 1000
cubic feet was used to determine the operating costs
[231] .
o Solids Disposal
The cost of land disposal of sludge and solid is esti-
mated to be $11.00 per barrel [228].
Cost of Treatment Options for Produced Water
Seven technologies for the treatment and/or disposal of produced
water were studied [225]. These technologies are as follows:
-270-
-------
o Biological treatment
o Chemical precipitation
o Filtration
o Activated Carbon Adsorption
o Air Stripping
o Breakpoint Chlorination
o Reinjection
As discussed in Section VII/ only reinjection and filtration were
retained as technologically feasible alternatives to implement on
a national basis for this industry segment.
In addition to reinjection in wells, filtration and discharge to
surrounding waters at the platform was costed as a disposal
alternative. Where onshore treatment of the produced water was
considered, the costs of disposal to surface waters at distances
of 1000 feet and three miles offshore were estimated. Add-on
costs as shown in Table VIII-5 were also considered where facili-
ties may be located further inland and for production facilities
that are further than three miles offshore.
For all treatment technologies studied it was assumed that a
level of treatment at least equal to BPT was in place for
existing sources and would be installed as a minimum for new
sources since it is presently a requirement of the regulations.
Therefore, the costs developed for the candidate technologies are
incremental to BPT costs. The following six options were eva-
luated :
-271-
-------
Option No. Technologies
1 For new sources, produced water is filtered at the
platform and disposed in new reinjection wells
drilled for that purpose. This option was not
applied to existing sources (BAT) since a com-
bination of new, exhausted, and dry wells could be
used for reinjection at existing facilities.
2 For existing sources, produced water is filtered
at the platform and reinjected in reworked dry or
exhausted production wells and in any additional
new wells required to accommodate the necessary
reinjection capacity.
3 Produced water is filtered at the platform and
disposed by discharge to surface waters at the
platform.
4 Produced water is filtered at shore and disposed
to surface waters 1000 feet offshore.
5 Produced water is filtered at shore and disposed
to surface waters 3 miles offshore.
6 Produced water is filtered at shore and disposed
by reinjection in wells located at shore.
The capital and annual operating and maintenance costs were
estimated for each of the options for both existing and new
sources. These costs are summarized in tables VIII-6 and
VIII-7, respectively.
-272-
-------
TABLE VI11-6 •
OFFSHORE OIL AND GAS EXTRACTION INDUSTRY
PRODUCED WATER TREATMENT
SUMMARY OF CAPITAL AND ANNUAL 0/M COSTS FOR EXISTING SOURCES
($1000-1982)
MODEL PLATFORM 0
1
OIL
Gulf 4
Gulf 2X5
-
Gulf 12
-
Gulf 24
-
Gulf 40
-
Gulf 53
-
Pacific 16 -
-
Pacific 40
-
Pacific 34
-
Atlantic 24
-
Cook Inlet 24
-
Gravel Isl. '48
-
Bering Plat. 48
-
Beaufort Pi. 48
-
GAS
Gulf 4
-
Gulf 2X5
-
Gulf 12
-
Gulf 24
-
Pacific 16
-
Atlantic 24
-
Cook Inlet 12
—
P
2
3600
(164)
5700
(257)
5700
(257)
7300
(344)
8600
(447)
10600
(591)
10300
(456)
14800
(696)
21800
( 1089)
15300
(663)
26100
( 1069)
70600
(3052)
72600
(3204)
91800
(3964)
3400
(145)
5600
(213)
5600
(213)
2900
(128)
8200
(295)
7300
(298)
18700
(623)
T
3
1700
(93)
4300
(174)
4300.
(174)
5200
(213)
5600
(236)
6000
(267)
5700
(262)
7700
(343)
9100
(446)
8000
(294)
10200
("367)
20800
(1033)
22400
( 1093)
32600
( 1439)
1600
(86)
4200
(164)-
4200
(164)
1500
(84)
5200
(198)
5100
(197)
9300
(317)
I
4
1500
(90)
1600
(107)
1600
(107)
2000
(128)
3100
(184)
3700
(230)
2800
(189)
5100
(295)
6900
(413)
5000
(230)
7500
(323)
22000
(1143)
22300
(1181)
26600
(1362)
1300
(86)
1600
(96)
1600
(96)
1300
(77)
2700
(137)
2400
(124)
6400
(233)
0
5
2300
(115)
2500
(134)
2500
(134)
3000
(161)
4700
(236)
5800
(294)
4200
(234)
7800
(393)
10900
(538)
7600
313
11700
(451)
35200
(1541)
35500
( 1580)
41300
( 1805)
2300
. (1H )
2400
(111)
2400
(111 )
2300
i (109)
4000
(165)
3800
(166)
9700
(333)
N
6
1800
(107)
2000
(138)
2000
(138)
2600
(186)
3900
(276)
5100
(377)
3700
(247)
5600
(388)
9700
(653)
6800
(370)
1100
(559)
33100
( 1780)
35500
( 1922)
41 100
(2231 )
900
(70)
1000
(73)
1000
(73)
900
(69)
1700
(99)
1500
(115)
4400
(187)
NOTE: Cost format presented as follows, e.g.
-273-
1000 - Capital
(700) - Annual
-------
TABLE VIII-7
OFFSHORE OIL AND GAS EXTRACTION INDUSTRY
PRODUCED WATER TREATMENT
SUMMARY OF CAPITAL AND ANNUAL 0/M COSTS FOR NEW SOURCES
($1000-1982)
MODEL PLATFORM
OIL
Gulf 4
Gulf 2X5
Gulf 12
Gulf 24
Gulf 40
Gulf 58
Pacific 16
Pacific 40
Pacific 34
Atlantic 24
Cook Inlet 24
Gravel Isl . 48 •
Bering Plat. 48
Beaufort PI. 48
GAS
Gulf 4
Gulf 2X5
Gulf 12
Gulf 24
Pacific 16
Atlantic 24
Cook Inlet 12
0
, 1
4400
(197)
5100
(261)
5100
(261)
7400
(389)
9300
(536)
12500
(755)
8900
(376)
14400
(648)
22700
( 1048)
16600
(721)
27300
(1143)
75200
(3145)
85900
(3545)
1 10400
(4457)
4300
(175)
5000
(199)
5000
(199)
4200
(169)
7500
(272)
7200
(299)
19800
(657)
P
2
4000
(185)
4300
(237)
4300
(237)
6100
(350)
7500
(482)
9900
(677)
7400
(331)
13700
(627)
22000
( 1027)
14400
(655)
25400
( 1086)
70600
(3007)
81300
(3413)
105800
( 4319)
3900
(163)
4100
(172)
4100
(172)
3300
(142)
6800
(251)
5800
(257)
19000
(633)
T
3
1800
(95)
2500
(123)
2500
(123)
3400
(163)
3900
(186)
4300
(215)
3900
(209)
6000
(292)
7500
(397)
6300
(243)
8600
(319)
20800
(1033)
20900
( 1054)
31400
( 1402)
1700
(39)
2400
(110)
2400
(110)
1700
(89)
3500
(146)
3300
(142)
7600
(266)
I
4
500
(59)
700
(77)
700
(77)
800
(90)
1100
(125)
1300
(159)
1200
(102)
1800
(154)
2300
(212)
1900
(159)
2700
(213)
6900
(710)
7100
(749)
9700
(886)
1000
(74)
1600
(96)
1600
(96)
1000
(75)
2700
(133)
2400
(128)
6400
(237)
0
5
1300
(84)
1500
(103)
1500
(103)
1800
(123)
2800
(177)
3400
(223)
2600
(146)
4300
(234)
6300
(337)
4600
(242)
6900
( 341 )
20000
( 1106)
20300
(1148)
24400
(1330)
1400
(83)
2400
(111 )
2400
(111 )
1400
(81 )•
4000
(161 )
3500
( 161 )
9700
(337)
N
6
900
(91)
1100
(137)
1 100
(137)
1400
(201)
2000
(311)
2700
(454)
2100
(237)
3300
(423)
5100
(728)
3700
(394)
6300
(594)
18000
(1758)
20300
( 1960)
26100
(2400)
900
(72)
1000
(79)
1000
(79)
900
(69)
1700
(104)
1500
(140)
4400
(207)
NOTE: Cost format presented as follows, e.g
-274-
1000 - Capital
(700) - Annual
-------
DRILLING FLUIDS AND CUTTINGS
Drilling fluids can be either oil or water based. Oil may be
added to a water-based drilling fluid as a lubricity agent or
when it is necessary to free a stuck drill bit or string. When a
replacement drilling fluid is needed to meet the requirements of
a change in the formation characteristics or when a well is
completed, the used drilling fluid must be disposed. In addi-
tion, as the drilling operation takes place a portion of the
drilling fluid may have to be purged to maintain the proper for-
mula, density, etc.
The following assumptions were made in determining costs of
drilling solids disposal:
o Based on data in the "1982 Association Survey on
Drilling Costs," API, Independent Petroleum Association
and Mid-Continent Oil arid Gas Association, November
1983, 10,000-feet was used as an average well depth for
the Gulf of Mexico. The drilling time for this well
would be 35 days with 20 days of actual drilling [228] .
The time required to drill from 8,000-feet to 10,000
feet was assumed to be 8 days.
o The amounts of drilling fluids and cuttings generated
for a 10,000-foot well are as follows [228]:
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Well Depth(ft) Mud Used (bbls) Cuttings Discarded (bbls)
0-150 -* 188
150-1,000 1,477 258
1,000-4,500 2,012 551
4,500-8,000 1,184 275
8,000-10,000 676 158
Subtotals 5,349 1,430
Total: 6,779 bbls
*Assuming casing water jetted so no drilling fluids are used or
generated.
Diesel and mineral oil may be used in the drilling operations.
Various scenarios were developed when these oils are used and
costs of disposing the generated solids were determined. The
scenarios developed are as follows:
o Scenario 1.- Drilling muds are diesel oil-based for the
entire 10,000 foot drilling depth (rarely done).
o Scenario 2.- Drilling muds are water-based, with' diesel
oil used as a lubricity agent down to the 8,000 foot
level. Between 8,000 and 10,000 feet a diesel spot is
added to the mud system to free a stuck drill bit or
string.
o Scenario 3.- Drilling muds are water-based with no
lubricity agent added. However, diesel oil is used as
a spotting agent between 8,000 and 10,000 feet.
-276-
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With the three scenarios stated, various degrees of treatment
were considered:
o Removal of diesel oil from discharges (product substitution)
o Removal of all oils from discharges (land disposal)
o Removal of some oils and some solids from discharges (land
disposal)
o Removal of all oil and solids from discharges (land
disposal)
The unit costs used in estimating the treatment and disposal
alternatives are based on the following:
o The increased cost of substituting mineral oil for
diesel oil is $1.90 per gallon including storage and
maintenance [230].
o The cost for washing cuttings over a 35-day period for
drilling a single well, is estimated at $54,000. This
includes daily rental charges for the cuttings washer
and operating costs during actual days of drilling
[228].
o
The cost of a dedicated boat for transporting solids to
land is $3000 per boat per actual day of drilling
[228,229].
The total cost of land disposal of solids is $11 per
barrel [228] .
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Costs for Scenario 1
The cost of treating and handling the muds and cuttings in
Scenario 1 to the point of removing all diesel oil from use and
removing a portion of the substituted mineral oil and a portion
of the solids from discharge is $509,000 per well. The opera-
tions involved, and their respective costs, are as follows:
Substitute mineral oil for diesel oil $276,000
Wash oil from drill cuttings 54,000
Discharge washed cuttings 0
Transport oil-based mud to shore for disposal 179,000
Total $509,000
The total cost of removing all oils and all mud and cuttings
discharges by transporting to shore for disposal is $195,000.
Costs for Scenario 2
The costs of treating the muds and cuttings in Scenario 2 to
remove all diesel oil from use is $29,000 per well. The opera-
tions involved, and their respective costs, are as follows:
Substitute mineral oil for diesel oil $ 29,000
(as lubricant spotting fluid)
Discharge to surrounding waters 0
Total $ 29,000
-278-
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The total cost for removing all oils and all solids from the
discharges by transporting to shore for disposal is $195,000.
Costs for Scenario 3
The costs of treating the muds and cuttings in Scenario 3 to
remove all diesel from use by substituting mineral oil for diesel
oil is $3300 per well. The operations involved, and their
respective costs, are as follows:
Substitute mineral oil for diesel oil $ 3,300
as a spotting fluid
Discharge to surrounding waters 0
Total $ 3,300
The total cost for removing all oils and solids from discharges
by transporting to shore for disposal is $195,000.
DISPOSAL OF SOLIDS OTHER THAN DRILLING FLUIDS AND CUTTINGS
The volume of dewatered solids generated as a result of produced
water pretreatment prior to reinjection is estimated at approxi-
mately 0.06 percent of the volume of produced water. They may be
disposed of by deposition on the sea bed in the vicinity of the
platform or transported to shore and disposed of in landfills.
The cost of disposal on the sea bed is virtually nil. The cost
of disposal on land is $11 per barrel plus the costs of platform
storage containers and transportation to shore.
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ENERGY REQUIREMENTS
Additional energy requirements of the candidate treatment tech-
nologies are due primarily to the filtration and pumping of pro-
duced water into reinjection wells for those new source
facilities subject to the zero discharge standard. The energy
requirements for the estimated 132 new source platforms that
would be required to reinject produced water total approximately
170 million kilowatt-hours per year. This represents approxima-
tely 0.05 percent of the energy content of the produced hydrocar-
bons from these facilities. Therefore/ the small incremental
energy requirements for reinjection of produced water will not
significantly affect the cost of production, nor will they signi-
ficantly reduce energy supplies.
There are no measurable increases in energy requirements beyond
BAT for those new sources that would be subject to improved per-
formance of BPT technology for produced water.
Table VIII-8 illustrates the effect of reinjection on the power
requirements. It compares the power requirements of filtration
and surface water disposal and filtration with reinjection. The
difference between the two is the power required for injection
well disposal.
-280-
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TAB
TOTAL ANNUAL
(THOUSANDS OF
FI
MODEL PLATFORM RE
(0
Gulf 4
Gulf 2X5
Gulf 12
Gulf 24
Gulf 40
Gulf 58
Pacific 16
Pacific 40
Pacific 34
Atlantic 24
Cook Inlet 24
Gravel Island 48
Bering Platform 48
Beaufort Platform 48
E VIII-8
OWER REQUIREMENTS
KILOWATT HOURS
TRATION AND
NJECTION
TION 2)
330
830
830
1390
2310
3520
1200
2740
4840
2860
4180
9500
10830
13470
FILTRATION AND
SURFACE WATER
DISPOSAL
(OPTION 3)
74
180
180
230
260
300
240
340
350
280
320
500
540
620
-281-
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AIR POLLUTION
When additional pumping is required, due to the application of a
particular pollution control technology for produced water, addi-
tional air emissions will be created due to the use of fuel to
power either electric generators or prime movers. However, the
use of gas turbine engines is projected for the majority of sites
offshore which should result in minimum emissions to the
atmosphere when compared to the pollutant removals associated
with the treatment technologies. If treatment facilities are
located on-shore, power would be obtained from local electric
powe r compan i e s.
CONSUMPTIVE WATER LOSS
Since no water is added to any of the unit operations no consump-
tive water loss is expected as a result of the proposed regula-
tions.
REFERENCES
9. "Potential Impact of EPA Guidelines for Produced Water
Discharges from the Offshore and Coastal Oil and Gas
Extraction Industry," October 1975, Brown and Root, Inc.,
Houston, TX October 1975. Prepared for the Offshore
Operators Committee.
20. "Determination of Best Practicable Control Technology
Currently Available to Remove Oil from Water Produced with
Oil and Gas," Brown and Root, Inc., March 1974. Prepared
for the Offshore Operators Committee.
-282-
-------
218. Summary of Cost Estimates for Systems to Treat Produced
Water Discharges in the Offshore Gas and Oil Industry to
Meet BAT and NSPS, Kohlmann Ruggiero Engineers, P.C., pre-
pared for Effluent Guidelines Division, U.S. EPA, September
19, 1984.
219. "Cost Estimates for Systems to Treat Produced Water
Discharges in the Offshore Gas and Oil Industry to Meet BAT
and NSPS," Hydrotechnic Corp., September 1981. Revised
August 1983. Prepared for Effluent Guidelines Division,
U.S. EPA.
220. Letter from Burns and Roe to U.S. EPA, Effluent Guidelines
Division, dated 12 June 1984.
222. Personal communications between H. Hofstein (KRE, P.C.) and
various oil company personnel, October 1983.
22"3. "Potential Impact of Proposed EPA BAT/NSPS Standards for
Produced Water Discharges From Offshore Oil and Gas
Extraction Industry," Walk, Haydel and Associates, January
1984. Prepared for the Offshore Operators Committee.
224. "1982 Association Survey on Drilling Costs," Statistics
Dept., American Petroleum Institute, November 1983.
225. "Technologies for the Treatment of Produced Waters From
Offshore Oil and Gas Platforms On-Shore," Kohlmann Ruggiero
Engineers, P.C., October 1983.
227. Telephone conversation between H. Kohlmann (KRE, P.C.) and
Offshore Operators Committee Member.
-283-
-------
228. Alternate Disposal Methods for Mud and Cuttings/ Gulf of
Mexico and Georges Bank, OOC, December 7, 1981.
229. OOC Information, December 1983.
230. Comparison of diesel and mineral oil costs obtained by
telephone contact with industry, 1984.
231. Telephone conversation with Consolidated Edison Company of
New York, 1984.
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IX. NEW SOURCE PERFORMANCE STANDARDS
The basis for new source performance standards (NSPS) under
Section 306 of the Act is the best available demonstrated control
technology. When new facilities are planned, the operators have
the opportunity to incorporate in their designs the best and most
efficient processes and waste treatment technologies. Therefore,
Congress directed EPA to consider the best demonstrated process
changes, in-plant controls, and end-of-process control and treat-
ment technologies that reduce pollution to the maximum extent
feasible.
The Agency has investigated several control and treatment
options as a.basis for NSPS to reduce the discharge of pollutants
in waste streams generated by the offshore segment of this
industry. These options and the rationale for selecting NSPS are
presented in this section for the waste streams covered by the
proposed regulation.
NEW SOURCE DEFINITION
The exploration, development, and production of oil and gas in
offshore waters involves operations sometimes unique from normal
industrial operations performed on land. While the provisions in
the NPDES regulations that define new source (40 CFR 122.2) and
establish criteria for a new source determination (40 CFR
122.29(b)) are applicable to this subcategory, two terms, "water
area" and "significant site preparation work," are defined in
this subcategory-specific new source definition in order to give
the terms meanings relevant to offshore oil and gas operations.
These special definitions are consistent with Section
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122.29(b)(1) which provides that Sections 122.2 and 122.29(b)
shall apply "except as otherwise provided in an applicable new
source performance standard." See 49 FR 38048 {September 26,
1984) .
Before discussing the two special definitions, a brief discussion
follows on the scope of the term "new source" as applicable to
all activities covered by the offshore subcategory. This inclu-
des mobile and/or fixed exploratory and development drilling
operations as well as production operations. Coverage of all
such offshore oil and gas operations is required by Section 306
of the Act.
Section 306(a){2) defines a "new source" to mean "any source, the
construction, of which is commenced" after publication of the pro-
posed NSPS if such standards are promulgated consistent with sec-
tion 306. The Act defines "source" to mean any "facility ...
from which there is or may be the discharge of pollutants" and
"construction" to mean "any placement, assembly, or installation
of facilities or equipment...at the premises where such equipment
will be used." The term "source" clearly would include all
drilling rigs and platforms as well as production platforms. The
breadth of the term "construction," which encompasses the concept
of "placement" of "equipment" at the "premises," would include
the location and commencement of drilling or production opera-
tions at an offshore site to be "construction" of a new source.
This is a critical distinction. Drilling rigs obviously are
moved from site to site for several years. Production platforms
are built on shore and transported to an offshore site. The
appropriate reading of section 306(a)(5) would not make the date
of building the rig or platform determinative of whether the rig
or platform was a new source, but rather when the rig or platform
-286-
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was placed at the offshore site where the drilling and production
activity and discharge would occur. Therefore, drilling opera-
tions that commence after the NSPS are effective, even if per-
formed by an existing mobile rig, would be new sources, coming
within the definition of "constructed" by "placement" of
"equipment" at the "premises."
Similarly, a mobile drilling rig which carries the drilling
equipment would be considered "placed" at the location it anchors
for drilling, which would be the "premises." The Agency con-
siders the drilling rig to be the "facility...from which there is
or may be the discharge of pollutants" within the meaning of
Section 306(a)(3). The same reasoning applies to development
drilling rigs and structures and production structures, platforms
or equipment. The critical determination of whether a source is
*
a "new source" is the date of placement and commencement of
operations, not the date the source originally was built.
The first special term that is defined in these proposed regula-
tions is "water area" as used in the term "site" in Section
122.29(b). The term "site" is defined in Section 122.2 to
include the "water area" where a facility is "physically located"
or an activity is "conducted." For the purposes of determining
the "site" of new source offshore oil and gas operations, the
Agency is proposing to define "water area" to mean the specific
geographical location where the exploration, development, or pro-
duction activity is conducted, including the water column and
ocean floor beneath such activities. Therefore, if a new plat-
form is built at or moved from a different location, it will be
considered a new source when placed at the new site where its oil
and gas activities take place. Even if the facility is placed
adjacent to an existing facility the new facility will still be
-287-
-------
considered a "new source," occupying a new "water area" and
therefore a new site.
EPA considered defining "water area" as a larger body of water,
such as a lease block area. This alternative was rejected
because such an artificial distinction would allow the commen-
cement of many additional oil and gas activities (not considered
to be "new sources") in an area merely by virtue of the fact that
an existing activity was currently operating in the lease block.
This result is inconsistent with the definitions and purpose of
Section 306 of the Act. Under Section 306 a "new source" means
"any source" the construction of which begins after the Agency
publishes a NSPS.
The second special term for which EPA is proposing a special
definition is "significant site preparation work." As explained
above, the date of "placement" of a rig or platform is deter-
minative of when a source is considered to be "constructed." The
date of "placement" (i.e., "construction") may be earlier under
the provision of 40 CFR 122.29(b){4) which defines construction
as being commenced when "significant site preparation work" has
been done at a site. The effect of the proposed definition for
"significant site preparation work" is important in determining
what individual sources would be considered to have "commenced
construction" or commenced "placement" prior to the publication
of the NSPS and therefore, would not be considered a new source.
EPA is proposing to define this term to mean the processes of
clearing and preparing an area of the ocean floor for purposes of
constructing or placing a development or production facility on
or over the site. Therefore, if clearing and preparation of an
area for development or production had occurred at a site prior
to the publication of the NSPS, then subsequent development and
-288-
-------
production activities at that site would not be considered a new
source. The significance of this definition is that exploration
activities at a site prior to the effective date of the NSPS are
not considered significant site preparation work. Therefore, if
only exploratory drilling had been performed at a site, sub-
sequent development and production activities would not be
"grandfathered in" as existing sources at the site but rather
would be considered "new sources". The Agency does not consider
exploratory activities to be "significant site preparation work"
because such activities are not necessarily followed by develop-
ment or production activities at a site. Even when exploratory
drilling ultimately leads to drilling and production activities,
the latter may not be commenced for months or years after the
exploratory drilling is completed. The purpose of this provision
is to allow a future source to be considered an existing source
if "significant site preparation work," thereby evidencing an
intent to establish full-scale operations at a site, had been
performed prior to NSPS becoming effective. While a development
or production platform would not be built unless an exploratory
well had been drilled, exploration wells are drilled at vastly
more sites and can precede development by months or years.
Another provision of Section 122.29 (b)(4) regarding when
construction of a new source has commenced, provided that
construction has commenced if the owner or operator has "entered
into a binding contractual obligation for the purchase of facili-
ties or equipment which are intended to be used in its operation
within a reasonable time." The Agency is not proposing a special
definition of this provision believing it should appropriately be
a decision for the permit writer. However, the Agency carefully
has considered this provision and is providing the following
general guidance concerning the proper application of the provi-
-289-
-------
sion for the special circumstances of offshore oil and gas acti-
vities.
A common practice in the industry is for oil companies to enter
into long-term contracts with independent drilling companies.
These contracts may require that the drilling company will pro-
vide its services for a specified number of wells over a period
of months or years. The exact site for the exploratory drilling
services may not be specified. The Agency believes such
contracts would appropriately fall within the provision of
Section 1 22.29(b)(4)(ii), thereby making the drilling activities
under those contracts existing sources, not new sources. Such
contracts generally do not or cannot specify the exact site for
future exploratory drilling.
The situation generally is not the same for development drilling
or production activities. Contracts for these activities usually
specify the site where activities are to be conducted or facili-
ties placed. Therefore, drilling activities under a contract
that meets the conditions of Section 122.29(b)(4) (ii) for an
exact site probably would not be considered a new source.
However, a general contract for construction or use of a develop-
ment or production platform with no indication of the location
where it would be placed or used would not qualify to make a
future selected site for its use an existing source. An opposite
result would allow companies to move an existing platform or use
old platforms at new sites in shallow water areas thereby
avoiding the NSPS zero discharge requirement for produced water.
Such a result would be contrary to the purpose of establishing
NSPS.
An issue of continuing concern under the Clean Water Act has been
whether NSPS must be applied after their proposal or only after
-290-
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their promulgation. Section 306(a)(1) of the Act provides that a
"new source" is a source, the construction of which commences
after proposal of NSPS if such NSPS are promulgated in accordance
with Section 306. Section 306(b)(1)(B) requires promulgation
within 120 days of proposal. EPA's implementing regulations for
direct discharges provide that a new source means a source, the
construction of which commenced either after proposal if the
NSPS are promulgated within 120 days or after promulgation in all
other cases (Section 122.2).
EPA does not intend that the NSPS for this subcategory shall be
effective until they are promulgated unless they are promulgated
within 120 days of proposal in which case the effective date
would be the date of proposal. Therefore, no source will be con-
sidered a "new source" subject to NSPS until the Agency promulga-
tes the NSPS. This decision is consistent with the Agency's
definition of "new source" in 40 CFR 122.2 since for the reasons
discussed below the Agency will not be able to promulgate NSPS
within 120 days of proposal. While the Agency continues to
believe the definition of new source in Section 122.2 is
appropriate and consistent with the Act, the Third Circuit Court
of Appeals has twice in NAMF v. EPA, 719 F.2d 624, 641 (3rd Cir.
1983) and Pennsylvania Department of Environmental Resources v.
EPA, 618 F.2d 991 (3rd Cir. 1980), held that as a general matter
EPA's new source standards shall be applied as of their date of
proposal. However, the Court in those cases also recognized that
there may be circumstances, such as cases where "substantial
changes" may occur between proposal and promulgation that would
justify an 'NSPS effective date as the date of promulgation. See
NAMF v. EPA, 719 F2.d at 643 n.20. The Agency believes that
these proposed regulations are such a case, as discussed below.
-291-
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First, one of the issues is the definition of "new source." The
Agency has solicited public comment on the proposed definition of
new source. The Agency's final decision on the definition of new
source for this subcategory will be critical to knowing what
facilities must comply with the NSPS. Because the proposed defi-
nition of NSPS may change upon promulgation, individual
dischargers would be unable to determine their status for an
extended period of time. This would hinder operational planning
during the period.
Second, the proposed standards may change on promulgation. After
proposal and prior to promulgation, the Agency will be collecting
substantial additional data on the proposed standards and will be
reconsidering its decisions. In light of this fact and the
substantial number of expected comments, it seems inappropriate
to require compliance with the proposed NSPS.
Finally, one of the primary effects of a decision to apply NSPS
at the date of proposal would be that the National Environmental
Policy Act (NEPA) would apply to the action of issuing the permit
for the new source. For new lease areas, the Department of
Interior ("DOI") already is preparing environmental impact state-
ments (EIS) that consider the proposed oil and gas operations in
the lease areas. EPA has entered into a memorandum of
understanding with DOI providing for EPA participation in the EIS
process. Therefore, for new federal lease areas, the provisions
of NEPA are being applied.
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PRODUCED WATER
Control and Treatment Options Considered
EPA evaluated the following three control and treatment options
for establishing NSPS for produced water.
Option 1 - Improved BPT Performance. Option 1 would base perfor-
mance standards on the improved performance of BPT technology. A
discharge standard of 59 mg/1 (maximum) for oil and grease would
result from this option. For the 833 projected new source plat-
forms in the years 1985 thru 2000 [252], this level of technology
would result in an annual reduction of 700,000 pounds of oil and
grease beyond the allowable BPT discharge level. Reductions of
priority pollutants beyond those achieved by existing BPT-type
treatment technologies cannot be quantified for this option.
The Agency was unable to develop incremental cost estimates for
imposing Option 1 on all new source platforms. This is because
the elements of improved operation and maintenance of BPT treat-
ment equipment are very site specific. However, the Agency does
believe that, for any particular new source platform, such costs
are minimal compared to the installed costs of the BPT equipment
and the cost of operation and maintenance to achieve the BPT
effluent limitations. Also, new source operators have the oppor-
tunity to design for and install the latest equipment as an
integrated part of the platform superstructure; therefore they
would not be subject to any retrofit expenditures that would be
required by existing platforms to comply with improved BPT treat-
ment technologies. Furthermore, the Offshore Operator's
Committee report titled Potential Impact of Proposed EPA
BAT/NSPS Standards for Produced Water Discharge From Offshore
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Oil and Gas Extraction Industry (January 1984), projects that at
least 75 percent of the existing offshore platforms in the Gulf
of Mexico are already achieving the 59 mg/1 oil and grease limi-
tation with treatment technology designed to achieve compliance
with the present BPT limitations.
Option 2 - Filtration. Option 2 would base performance standards
on granular media filtration as an add-on technology to 3PT.
This level of technology would result in additional reductions of
conventional pollutants beyond the BPT level of control.
Effluent limitations of 20 mg/1 monthly average and 30 mg/1 daily
maximum for both oil and grease and total suspended solids would
result from this option. For the 833 projected new source plat-
forms, this option would result in an annualized cost of $275.7
million in the year 2000 (1983 dollars). Investment costs for
the 62 platforms expected to be installed in the year 2000 are
estimated to be $185.4 million (1983 dollars). These compliance
costs are incremental to BPT technology, i.e., they do not
include the costs for BPT technology. [252]
This option would result in an annual reduction of 4.2 million
pounds of conventional pollutants beyond the levels allowed under
the BPT level of control. Significant reductions of total
suspended solids levels are also achieved by granular media
filtration. Reductions of priority pollutants cannot be quan-
tified through the use of this option.
Option 3 - Zero Discharge. Option 3 would require zero
discharge, based upon reinjection technology. This level of
technology would result in no discharge of pollutants to surface
waters.
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For the projected 833 new platforms, this option would result in
an annualized cost of $487.1 million in the year 2000 (1983
dollars). Investment costs for the 62 platforms expected to be
installed in the year 2000 are estimated to be $442.0 million
(1983 dollars). These compliance costs are incremental to 3PT
technology, which may be required-ahead of the reinjection system
required by this option.
This option would result in an annual reduction of 3.9 million
pounds of priority pollutants beyond the discharge levels
observed by existing platforms using BPT technology. This option
would also result in an annual reduction of 7.0 million pounds of
conventional pollutants (oil and grease) beyond the levels
allowed under the BPT level of control. Significant reductions
of total suspended solids levels are also achieved by this
option.
Selected Option and Basis for Selection
The option which the Agency is proposing for NSPS is a com-
bination of Options 1 and 3. Option 3, or zero discharge, would
be required for all oil production facilities that are located in
or discharge to shallow water areas, i.e., platforms in 20 meters
of water or less in the Gulf of Mexico, the Atlantic Coast, and
the Norton Basin; in 50 meters of water or less for the
California Coast, Cook "Inlet/Shelikof Strait, Bristol Say, and
Gulf of Alaska; and in 10 meters of water or less in the Beaufort
Sea. The Agency has selected Option 1 , improved BPT-treatment
technology, which requires compliance with a 59 mg/1 limitation
for oil and grease (maximum), for all oil facilities that are not
located in these shallow water areas, for all gas facilities
regardless of location or water depth, and for all exploratory
facilities.
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This selected option would require an estimated 132 new oil pro-
duction facilities to meet the zero discharge standard. The
other 701 new facilities would be required to meet an oil and
grease standard of 59 mg/1 (maximum) based upon improved perfor-
mance of BPT technology.
In selecting NSPS for produced water, the Agency considered the
technical feasibility and indus'try compliance costs of imposing
each of the above three NSPS options. In addition, EPA calcu-
lated aggregate industry compliance costs with various com-
binations of these options based upon platform type and location.
Because Option 3, which is based on reinjection, is the only
treatment technology that EPA found to be both technologically
feasible to implement and capable of achieving reductions of all
pollutants, including priority pollutants, the Agency focused its
evaluation on reinjection. The Agency recognized that, while
reinjection is an available and demonstrated technology for
controlling the discharge of pollutants in produced water from
offshore oil and gas facilities, the Agency also had to consider
the costs of implementing such a control option. The estimated
total annualized cost for all 833 projected new facilities to
implement reinjection of produced water is $487.1 million in the
year 2000 (1983 dollars). In light of the statutory mandate to
consider cost in establishing NSPS, EPA decided to reject the
imposition of this option on all new facilities in the offshore
subcategory because of its very high aggregate cost. This
prompted the Agency to evaluate limiting the scope of a zero
discharge requirement (i.e., reinjection) in order to reduce the
total cost.
To analyze possible ways to reduce the total aggregate cost of
Option 3, the Agency then developed costs for reinjection based
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upon the type of facility, i.e., oil platforms or gas platforms.
Not imposing a zero discharge requirement on the estimated 537
new source gas platforms would reduce the annualized cost of NSPS
Option 3 by $217.8 million in the year 2000 (1983 dollars). The
Agency decided to exclude all gas platforms from coverage by
Option 3 to reduce total aggregate costs.
To confirm this decision, EPA evaluated the characteristics of
produced water from oil platforms versus gas platforms. The
Agency determined that, while produced water from gas wells exhi-
bits higher concentrations of the priority pollutants than pro-
duced water from oil wells (approximately fourfold higher), the
typical flow of produced water from gas wells is significantly
less (approximately 1/15) than that from oil wells. Thus, on a
mass basis, Discharges of priority pollutants from gas wells are
approximately 25 percent of those from oil wells. The higher
quantity of priority pollutants discharged from oil platforms
compared to gas platforms supports the Agency's decision that
deleting gas platforms from a zero discharge requirement to
reduce aggregate annualized costs was appropriate. This reduced
total annualized costs to $269.3 million (1983 dollars) while
continuing to target attention on the discharges of greatest con-
cern.
While total projected annualized costs were reduced, the Agency
believed that $269.3 million was still too high and evaluated
reducing costs further by limiting the zero discharge option to
shallower waters where compliance costs would be less.
Facilities in shallow waters generally have the alternative of
onshore reinjection which is less costly than reinjection
offshore.
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The Agency has found that in shallower waters a high percentage
of the existing production platforms pipe the produced water to
shore for treatment rather than treating the produced waters on
the platform. The Agency has also determined that the costs of
drilling reinjection wells on land is less costly than drilling
reinjection wells at the platform.
The Agency has selected variable depth limits for different
offshore development areas which represent the shallower waters
and which generally allow for the alternative of onshore reinjec-
tion by the facility.
Industry data for the Gulf of. Mexico indicate that 82 percent of
the projected new sources in state waters and 25 percent of the
projected new sources in federal waters would pipe produced water
to shore for treatment. The data also indicate that about 52
percent of all new sources in 15 meters or less of offshore
waters would pipe produced water to shore. The Agency believes
this same percentage of platforms in water depths of 20 meters or
less could pipe to shore and reinject.
The 20 meter water depth was also selected for the Atlantic
Coast. There is no historic trend for production platforms in
this area. Therefore, the Gulf of Mexico statistics on the pro-
bable practice of onshore reinjection were assumed to be appli-
cable for production facilities in the Atlantic Ocean.
In California, statistics indicate that 60 percent of the active
production platforms located in water depths of 50 meters or less
pipe produced water to shore for treatment; whereas only eight
percent of the facilities in greater than 50 meters pipe the pro-
duced water to shore for treatment. Based on this data, reinjec-
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tion of produced water was selected at a depth of 50 meters or
less for the California Coast.
The Agency does not have historic data on production platforms
for some parts of Alaska since no offshore production platforms
have been constructed to date in the offshore subcategory. All
of the 14 existing production platforms in Cook Inlet are
classified in the coastal subcategory. The Agency believes that
the Southern Alaskan bathymetry is somewhat similar to
California's bathymetry and therefore, reinjection is proposed
for platforms at water depths of 50 meters or less for Southern
Alaska since platforms locating is these water depths may choose
to pipe produced water to shore for treatment. The Southern
Alaska region includes the Bristol Bay/Aleutian Island Chain,
Cook Inlet and the Gulf of Alaska. The Agency realizes that some
of these areas may not be amenable to piping or onshore reinjec-
tion because of seasonal ice formations, glaciers, or unsuitable
terrain. However, the Agency believes that piping to shore in
shallow waters will occur in areas that are suitable.
For other parts of Alaska, the Agency believes the platforms
which locate in the Norton Basin in water depths of 20 meters or
less and in the Beaufort Sea in 10 meters or less will have the
option of piping produced water to shore for treatment. These
more northern regions have harsher climates and thus a lesser
probability of piping the produced water to shore for treatment.
The Agency developed a zero discharge option for platforms
located in 20 meters of water or less in the Gulf of Mexico, the
Atlantic Coast and the Norton Basin; for 50 meters of water or
less for the California Coast and Southern Alaska including the
Aleutian Island Chain; and for 10 meters of water or less in the
Beaufort Sea.
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EPA then calculated the total costs of this zero discharge option
in shallower waters. In the Gulf of Mexico, the Agency projects
that 124 new platforms will be built in 20 meters of water or
less by the year 2000. The Agency estimates annualized costs of
a zero discharge standard to be $50.0 million in the year 2000
(1983 dollars). For the California Coast, the Agency projects
two new platforms that will be built in 50 meters or less of
water and estimates the annualized cost to be $5.5 million (1983
dollars) . While six platforms are projected to be built in the
shallow waters of the Beaufort Sea, the Agency is not attributing
incremental compliance costs to this regulation because existing
Department of Interior and State of Alaska lease stipulations
already require zero discharge. However, these costs are
included in the Agency's baseline economic analysis for these
proposed regulations. Similarly, no costs are attributed to
Atlantic Coast operations because no facilities are projected to
be built in 20 meters of water or less by the year 2000.
Nonetheless, EPA realizes that development is possible in the
Atlantic and has found that reinjection technology is feasible
for meeting a zero discharge standard for platforms located in 20
meters of water or less for the Atlantic Coast,
The proposed regulatory option, developed from the variable depth
considerations presented above, results in an annualized cost of
$55.6 million in the year 2000 (1983 dollars). The annualized
costs apply to 126 of the 132 new oil facilities expected to be
built between 1986 and the year 2000 and which would be subject
to this zero discharge requirement. The other six facilities are
projected to be located in Alaskan waters and subject to reinjec-
tion, but the cost of reinjection is not attributed to this regu-
lation, as described above. The Agency found these costs to be
economically achievable. This cost represents the total
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annualized cost of NSPS because the Agency has selected improved
BPT performance (i.e./ 59 mg/1 oil and grease maximum) for all
facilities not required to meet the no discharge standard.
As explained above, the Agency assumes only minimal incremental
costs for new sources to meet 59 mg/1 oil and grease for produced
water. The Agency selected Option 1 (improved BPT) over option 2
(filtration) because the aggregate annualized cost of $275.7
million (1983 dollars) to implement Option 2 is believed to be
too high.
The proposed regulatory option would result in an estimated
annual reduction of 700,000 pounds of priority pollutants beyond
discharge levels observed at existing platforms using BPT tech-
nology. This option would also result in an annual reduction of
1.3 million pounds of conventional pollutants beyond the
discharge levels allowed under the BPT level of control. No
decline in energy production is projected to occur from this
option.
Both reinjection and improved BPT technology represent the appli-
cation of the best available demonstrated control technology to
meet the proposed standards. The Agency has thoroughly con-
sidered the cost of achieving the proposed standards and conclu-
des that the costs will not be a barrier to future entry into
offshore oil and gas exploration, development or production
operations. No adverse non-water quality environmental impacts
or substantial increases in energy requirements will occur as a
result of the proposed standards.
This proposed option would require produced water from all new
exploration facilities regardless of location or water depth to
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comply with a 59 mg/1 (maximum) oil and grease standard, based
upon improved operation of BPT. Because of the relatively short
duration of exploratory operations, only a small amount of pro-
duced water will be generated. In addition, each exploratory
operation would require the drilling of an additional reinjection
well if reinjection were required. The Agency concluded that the
cost of a zero discharge requirement for exploratory operations
was too high especially considering the small amount of produced
water that would be generated.
EPA is proposing that development/production facilities that
would have to implement zero discharge under this option would
have up to 300 days from the commencement of well drilling opera-
tions to begin complying with the zero discharge standard. For
this purpose,, commencement of well drilling operations means the
start of borehole drilling for the first development well at an
offshore facility. During this 300-day period, any discharges of
produced water would have to comply with a 59 mg/1 (maximum) oil
and grease standard, which is based upon improved performance of
BPT technology. This 300-day period is being proposed in order
to allow for the use of any dry (non-producing) wells that are
drilled which are suitable for reinjection. If no dry wells
become available and are ready for use as injection wells within
this period, then compliance with the zero discharge standard
would be achieved by drilling and equipping an injection well for
use by the 301st day from the commencement of development
drilling operations.
The 300-day allowance for discharge of produced water after com-
mencement of development drilling, was selected based upon two
factors. These factors are (1) the length of time required to
drill a reinjection well and (2) the average percentage of deve-
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lopment wells drilled that prove to be dry and would be used as
reinjection wells. Fifteen percent has been established as the
percentage of dry wells encountered and 35 days as the calendar
time to drill a 10,000 foot injection well (20 days of actual
drilling). Using 15% as the factor for dry wells encountered in
development drilling, one in seven wells drilled will be a dry
well. Seven wells times 35 days results in 245 days. Assuming a
dry well is not encountered by the seventh well drilled, then 35
additional days are required to drill a reinjection well.
Assuming that up to 20 more days are required to complete, con-
nect, and start-up the reinjection well, a maximum of 300 calen-
dar days from commencement of development drilling would lapse
before an injection well were operating.
The Agency estimates that, typically, less than two percent by
volume of the produced water generated over the life of a faci-
lity would be discharged during the initial 300-day period. The
Agency estimates that the difference in cost between the use of a
new injection well and use of a reworked dry well for reinjection
is a minimum of $400,000 per facility. Because of these substan-
tial costs, the Agency believes that it is reasonable to delay
the requirement for meeting zero discharge by new offshore oil
facilities for 300 days from the commencement of development
drilling.
The reasonableness of the Agency's decision to require zero
discharge in the shallow waters is confirmed by the Agency's ana-
lyses which show that it would provide protection to the most
environmentally sensitive marine environments. In reviewing the
following environmental documents, the Agency determined that the
highest probability of direct environmental effects of produced
water discharges is most prevalent in shallower waters:
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EPA final report 440/4-85-002, Assessment of Environmental Fate
and Effects of Discharges from Offshore Oil and Gas Operations,
March 1985.
API Publication No. 4291, Effects of Oilfield Brine Effluent on
Benthic Organisms in Trinity Bay, Texas.
API Project No. 248, Ecological Effects of Produced Water
Discharges from Offshore Oil and Gas Production Platforms, by
B.S. Middleditch, March 1984.
In the Gulf of Mexico, for example, species distribution data
provided by the National Oceanic and Atmospheric Administration
(NOAA) indicate that water depths of 20 meters or less encompass
approximately 88 percent of the nursery areas for selected fish
and invertebrates. The Agency projected that 124 new platforms
would be built in 20 meters or less of water in the Gulf of
Mexico.
The Agency also evaluated the Beaufort Sea, Norton Basin, Cook
Inlet/Shelikof Strait, Bristol Bay, and the Gulf of Alaska in
Alaska. EPA analyses indicated that a water depth of 10 meters
or less (i.e., 10-meter isobath) in the Beaufort Sea; a 20-meter
isobath in the Norton Basin; and a 50-meter isobath in Cook
Inlet/Shelikof Strait, Bristol Bay, and the Gulf of Alaska would
provide substantial protection of critical life stages of the
commercial and subsistence species in each region.
For the California Coast, EPA's analyses indicate that the
50-meter isobath will protect the majority of the designated
areas of biological significance. It will also protect most of
the known nursery areas.
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Along the Atlantic Coast, species distribution data were obtained
from NOAA that indicate approximately 83 percent of the nursery
areas for the selected fish and invertebrates are encompassed by
water depths of 20 meters or less.
A zero discharge requirement for produced water would also
achieve control of many nonconventional, toxic pollutants in
addition to the 126 listed priority pollutants (See Appendix D of
this document). An EPA survey of 10 production platforms in
Louisiana [194] identified chemicals containing toxic or noncon-
ventional, toxic pollutants in use on the platforms that were
either present or likely to be present in produced water. These
chemicals include biocides, coagulants, corrosion inhibitors,
cleaners, dispersants, emulsion breakers, paraffin control
agents, reverse emulsion breakers, and scale inhibitors.
Detergents used to clean the platforms were also found in pro-
duced water.
DRILLING FLUIDS
Control and Treatment Options Considered
This following section presents the regulatory options considered
for NSPS for drilling fluids. Because these options are the same
as the options considered for BAT, the discussion of costs is
presented in the BAT section for drilling fluids. Thus there are
no NSPS costs or impacts incremental to BAT.
Option 1 - Toxicity Limitation. This option would result in the
regulation of free oil, oil-based fluids, diesel oil, cadmium,
mercury and the toxicity of the discharged drilling fluid. Most
of these limitations are achieved by product substitution - spe-
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cifically, through the use of water-based drilling fluids (i.e.,
generic muds), low toxicity specialty additives, the use of
mineral oil instead of diesel oil for lubricity and spotting pur-
poses, and use of barite with low toxic metals content.
Under this option the discharge of free oil would be prohibited,
as in the existing BPT regulation. The discharge of oil-based
drilling fluids would also be prohibited. Oil-based drilling
fluids usually contain 50 or more percent of oil by volume. One
method of compliance is substitution with less toxic water-based
fluids.
The prohibition on the discharge of free oil for BPT effectively
prohibits the discharge of oil-based drilling fluids. Therefore,
any differential costs incurred to implement substitution of
water-based for oil-based fluids is a cost attributable to
compliance with BPT requirements. Moreover, in contrast to the
BPT regulation, this NSPS option contains an explicit prohibition
on the discharge of oil-based fluids in addition to the prohibi-
tion on discharges of free oil. The alternative to product
substitution, i.e., use of water based mud systems, is to
transport the spent mud system to shore for reconditioning, reco-
very and/or land disposal.
The prohibition on the discharge of oil-based drilling fluids is
included in this option as an "indicator" of the toxic pollutants
present in these fluids. These pollutants include: benzene,
toluene, ethylbenzene, naphthalene and phenanthrene. The free
oil discharge prohibition in BPT originally was imposed to pre-
vent the discharge of oils in amounts that would cause a sheen on
receiving waters and this limitation will continue.
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The discharge of diesel oil, either as a component in an oil-
based drilling fluid or as an additive to a water-based drilling
fluid, would be prohibited under this option. Diesel oil would
be regulated because it contains such toxic organic pollutants as
benzene, toluene, ethylbenzene, naphthalene, and phenanthrene.
The method of compliance with this prohibition is to use mineral
oil instead of diesel oil for lubricity and spotting purposes.
Mineral oil is a less toxic alternative to diesel oil and is
available to serve the same operational requirements. Low toxi-
city mineral oils are also available as substitutes for diesel
oil and continue to be developed for use in drilling fluids.
However, mineral oil cannot necessarily be substituted into a
product formulation tailored for diesel oil. Other adjustments
in the product components may have to be made to accommodate
mineral oil.
The purpose of the toxicity limitation for any spent drilling
fluids which are to be discharged is to encourage the use of
generic or water-based drilling fluids and the use of low-
toxicity drilling fluid additives (i.e., product substitution).
The basis for the toxicity (LC-50) limitation is the toxicity of
the most toxic of the generic fluids. The most toxic generic
fluid is potassium/polymer mud (see Table V-7). The imposition
of an LC-50 toxicity limitation for all drilling fluids which are
to be discharged would allow for use of any of the eight generic
drilling fluids. Seven of the generic drilling fluids (i.e., all
but potassium/polymer mud) could be supplemented with low-
toxisity specialty additives and lubricity agents to meet opera--
tional requirements, and should still be able to comply with the
LC-50 toxicity limitation prior to discharge. The
potassium/polymer drilling fluid probably could not be supple-
mented with additives that exhibit a toxicity greater than the
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proposed LC-50 limitation because the LC-50 toxicity limitation
is based upon the base formulation of this drilling fluid.
However, industry operators and drilling fluid suppliers have
indicated that potassium/polymer drilling fluid is seldom used.
In drilling situations where there is no substitute for
potassium/polymer drilling fluid for operational reasons, such a
spent mud system would comply with the proposed LC-50 toxicity
limitation (3 percent, diluted suspended particulate phase) only
if any required lubricity agents (oils) or specialty additives
are no more toxic than the base mud formulation. Such additives
are available and continue to be developed. However, where the
toxicity of the spent mud system exceeds the LC-50 toxicity limi-
tation, the method of compliance with this option would be to
transport the spent fluid system to shore for either recon-
ditioning for reuse or land disposal.
The toxicity limitation would apply to any periodic surges of
drilling fluid as well as to bulk discharges of drilling fluid
systems. The term drilling fluid systems refers to the major
types of muds used during the drilling of a single well. As an
example, the drilling of a particular well used a spud mud for
the first 200 feet, a seawater gel mud to a depth of 1,000 feet,
a lightly treated lignosulfonic mud to 5,000 feet, and finally a
freshwater lignosulfate mud system to a bottom hole depth of
15,000 feet. Typically, bulk discharges of 1,000 to 2,000
barrels of spent drilling fluids occur when such mud systems are
changed or at the completion of a well.
For the purpose of self monitoring and reporting requirements in
NPDES permits, it is intended that only samples of the spent
drilling fluid system discharges be analyzed in accordance with
the proposed bioassay method. These bulk discharges are the
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highest volume mud discharges and will contain all the specialty
additives included in each mud system. Thus, spent drilling
fluid system discharges are the most appropriate discharges for
which compliance with the toxicity limitation should be
demonstrated. In the above example, four such determinations
would be necessary.
For determining the toxicity of the bulk discharge of mud used at
maximum well depth, samples may be obtained at any time after 80
percent of actual well footage (not total vertical depth) has
been drilled and up to and including the time of discharge. This
would allow time for a sample to be collected and analyzed by
bioassay and for the operator to evaluate the bioassay results so
that the operator will have adequate time to plan for the final
disposition of the spent drilling fluid system, e.g., if the
bioassay test is failed, the operator could then anticipate and
plan for transport of the spent drilling fluid system to shore in
order to comply with the effluent limitation. However, the
operator is not precluded . from discharging a spent mud system
prior to receiving analytical results. Nonetheless, the operator
would be subject to compliance with the effluent limitations
regardless of when self-monitoring analyses are performed. The
prohibition on discharges of free oil, oil-based drilling fluids,
and diesel oil would apply to all discharges of drilling fluid at
any time.
Cadmium and mercury would be regulated at a level of 1 mg/kg,
each, as a maximum ("not-to-exceed" value) on a dry weight basis
in any spent drilling fluid system discharge. These two toxic
metals would be regulated to control the metals content of the
barite component of any drilling fluid discharges. The method of
compliance with these limitations is product substitution. This
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involves use of barite from sources that either do not contain
these raetals or contain the metals at low enough levels such that
resultant levels in the whole fluid system do not exceed the
limitations.
The causes for noncompliance with the specific requirements of
this option could include: inability to use a drilling fluid that
can meet the proposed toxicity limitation, such as the need for
an oil-based mud or a potassium/polymer mud with oil additives
because of operational reasons, the need to add lubricity agents
or other specialty additives to a mud system to meet particular
operational requirements, or the unavailability of barite con-
taining low toxic metals levels. However, as previously noted,
BPT effectively prohibits the discharge of oil-based drilling
fluids, and less toxic water-based fluids are available substi-
tutes. Although the potassium/polymer mud represents the most
toxic water-based fluid allowed for discharge, it is seldom used
for offshore drilling purposes. However, potassium/polymer mud
is used in Alaska where disposal alternatives are limited. It is
also recognized that the availability of barite stocks containing
low levels of trace metals could be limited at any given time due
to market conditions. Nonetheless, the Agency does believe that
sufficient sources of such barite do exist and can be directed to
offshore drilling use in those cases where an operator intends to
discharge drilling fluids. Mineral oil is an available alter-
native to diesel oil for use as a lubricant or spotting fluid.
Although there are specialty additives for which less toxic
substitutes have not been identified, the toxicity limitation is
applied to the discharge of the entire drilling fluid system, and
not to individual components. Thus, the Agency believes that
only a limited number of offshore drilling operations would not
be allowed to discharge spent drilling fluids due to violation of
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one or more of the requirements of this option. A conservative
estimate is that, at most, ten percent of all spent drilling
fluid systems would violate the proposed limitations and would
have to be transported to shore to comply with this NSPS option.
Option ? - Clearinghouse Approach. The effluent limitations to
be imposed under Option 2 would be the same as those under Option
1 . However, Option 2 would establish a different mechanism for
determining compliance with the acute toxicity limitations. A
central data base, or clearinghouse, would be developed and main-
tained by the Agency to collect and store information on toxicity
and pollutant characteristics of drilling fluid formulations and
specialty additives. The information could then be used by both
permitting authorities and industry permittees for evaluating the
acceptability of spent muds for discharge. The clearinghouse
approach would allow an operator to determine, as early as
possible, whether a specific formulation would likely comply with
the discharge toxicity limitation or whether it would have to be
transported to land for disposal.
The clearinghouse would be a central library of data that indexes
pollutant characteristics for individual additives or for-
mulations that an offshore operator, manufacturer, or supplier
would submit to the Agency for consideration. The operator or
supplier would conduct selected toxicity and chemical analyses on
their products and provide this information to the Agency for
quality assurance review and inclusion in the data base. The
clearinghouse could then be used as a tool for estimating
compliance with effluent limitations for drilling fluids, but
would not function as a means of establishing or determining
actual compliance with individual discharge permit limitations.
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Option 3 - Zero Discharge. This option would require zero
discharge for all drilling fluids, based upon transport of spent
drilling fluids to shore for recovery, reconditioning for reuse,
and/or land disposal, or transport to an approved ocean disposal
site. This level of technology would result in no discharge of
pollutants to surface waters except at approved ocean disposal
sites.
Selected Option and Basis for Selection
EPA has selected Option 1 as the basis for proposed new source
performance standards for drilling fluids. The proposed stan-
dards include the following limitations:
o A prohibition on the discharge of free oil, oil-based
drilling fluids, and diesel oil, all considered as
"indicators" of priority pollutants.
o A 96-hour LC-50 toxicity limitation on the discharged
drilling fluids of no less than 3.0 percent by volume
of the diluted suspended particulate phase.
o A maximum limitation (no single sample to exceed) for
cadmium and mercury in the discharged drilling fluid of
1 mg/kg each, dry weight basis.
The prohibitions on the discharge of free oil, oil-based drilling
fluids, and diesel oil are all intended to limit the oil content
in drilling fluid wastestreams and, thereby, control the priority
as well as conventional and nonconventional pollutants present in
those oils. The pollutants "free oil," "oil-based drilling
fluids," and "diesel oil" are each considered, to be "indicators"
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of the priority pollutants present in these complex hydrocarbon
mixtures used as additives to drilling fluids. These pollutants
include: benzene, toluene, ethylbenzene, naphthalene and phe-
nanthrene. The Agency's primary concern is controlling the
priority pollutants in the oils although these prohibitions also
will serve to control nonconventional and conventional pollu-
tants. The Agency selected the "indicator" approach as an alter-
native to establishing limitations on each of the specific toxic
and non-conventional pollutants present in these oil-contaminated
wastestreams.
The sampling and analysis data demonstrate that when the amount
of oil, especially diesel, is reduced in drilling fluid, the con-
centrations of priority pollutants and the overall toxicity of
the fluid generally is reduced. The Agency has determined that
control of the amount or type of oil present in drilling fluids
with limitations on the three "indicators", free oil, oil-based
drilling fluids and diesel oil, will provide a satisfactory level
of control of the priority pollutants present in drilling fluids.
This method of toxic regulation obviates the difficulties and
costs of monitoring and analysis if limitations were established
for each of the organic priority pollutants present in the
drilling fluids.
The LC-50 toxicity limitation on the discharge of drilling fluids
is to reduce the toxic constituents in the drilling fluid system.
While the three indicator limitations on the amount or type of
oil present in drilling fluids should significantly reduce the
toxic pollutants present in drilling fluids, other additives such
as mineral oil or some of the numerous specialty additives may
greatly increase the toxicity of the drilling fluid. The toxi-
city is, in part, caused by the presence and concentration of
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priority pollutants. By establishing a toxicity limitation, the
Agency believes that operators will consider toxicity in
selecting additives and select the less toxic alternative. For
instance, there can be a broad spectrum in the toxicity of
various mineral oil sources. The Agency believes that the Clean
Water Act authorizes the Agency to establish a toxicity limita-
tion as an effluent limitation designed to control the chemical
or toxic constituents of the discharge. The availability of a
wide selection of additives makes product substitution the best
available demonstrated technology for complying with the toxicity
limitation. The Agency has considered the costs of product
substitution and finds them to be acceptable for this industry,
resulting in no barrier to future exploration and development.
These standards are not expected to have any adverse non-water
quality environmental impacts or increase in energy requirements.
The generic drilling fluids list is a primary basis for both the
prohibitions on the discharge of free oil and oil-based drilling
fluids and the LC-50 limitation. As discussed in Section V, EPA
has determined, through the NPDES permit process, that the eight
generic water-based drilling fluids, whose formulations are pre-
sented in Table V-7 of this document, are adequate for virtually
all drilling situations and are less toxic than oil-based
drilling fluids. In order for a drilling fluid to be discharged,
it must be no more toxic than the proposed LC-50 standard as
determined with the Drilling Fluids Toxicity Test presented in
Appendix C of this document.
Under this option, a drilling fluid can be discharged only if it
does not contain additives that would cause its toxicity to
exceed the toxicity of the most toxic generic mud. Further, EPA
has determined that refined mineral oil is an adequate substitute
for diesel oil since it is less toxic and operationally satisfac-
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tory. Accordingly, diesel oil would not be an allowable addi-
tive, either as a lubricity agent or spotting fluid, to a
drilling fluid intended to be discharged. Mineral oil would be
allowed as a lubricity agent and spotting fluid in the drilling
fluid provided that its addition would not cause the toxicity of
the discharged drilling fluid, including all other additives, to
exceed the proposed LC-50 standard.
The limitations on cadmium and mercury, both priority pollutants,
are intended to control the concentrations of toxic metals in
barite, a major component of drilling fluids. As discussed
above, these limitations would be met by product substitution.
In addition, the Agency is proposing a different definition of
the term "no .discharge of free oil" from that promulgated for the
BPT regulation (44 FR 22075, April 13, 1979). The rationale for
the proposed change is the same as that discussed in Section
X. Also, a test procedure for determining compliance with this
prohibition on free oil discharges is proposed. This test proce-
dure is called the "static sheen test", and is presented in
Appendix A of this document.
This NSPS option is the same as the proposed BAT option for
drilling fluids, as discussed below. Therefore, there are no
NSPS compliance costs or impacts incremental to BAT for drilling
fluids.
Option 2 was not selected as the basis for NSPS at this time
because the Agency does not anticipate such a "clearinghouse"
program to be established prior to promulgation of NSPS.
Development of listing methodologies and criteria and compilation
of an adequate toxicity data base, which is central to the
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"clearinghouse approach" of Option 2, is estimated to take from
three to five years. Such methodologies, criteria and data are
essential for full implementation on a nationwide basis. The
Agency has begun to investigate the requirements for management
of a clearinghouse approach. Upon completion of this investiga-
tion and if the Agency decides to establish such a program, the
Agency may propose to amend the toxicity approach to NSPS.
The Agency rejected Option 3, zero discharge, for implementation
on a national basis for two major reasons. The Agency believes
that the aggregate industry compliance costs of $126.3 million
annually (1983 dollars) for transport and land disposal of all
spent drilling fluids is too high. In addition, the Agency
believes that there may be problems with adequate land availabi-
lity for disposal of all spent drilling fluids. In part, this
may be due to existing or future restrictions on the land dispo-
sal of drilling fluids under the requirements of hazardous waste
disposal laws.
DRILL CUTTINGS
Control and Treatment Options Considered
The following section presents the regulatory options considered
for NSPS for drill cuttings.
Option 1 - Product Substitution. This option would result in the
regulation of free oil, oil-based fluids, and diesel oil in
discharged drill cuttings. These limitations, as for the
selected option for drilling fluids, are achieved by product
substitution. Water-based drilling fluids would be substituted
for oil-based fluids and mineral oil would be substituted for
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diesel oil. These three pollutant parameters would be regulated
in a manner identical to that for the same pollutant parameters
for drilling fluids Option 1 and the rationale for their regula-
tion is also the same because the constituent of concern in the
drill cuttings waste stream is the residual drilling fluid that
adheres to the drill cuttings.
Option 2 — Product Substitution Plus Oil Limitation. This option
would be equivalent to Option 1 plus a limitation on the
allowable oil content of the discharged cuttings. The oil con-
tent limitation of 10 percent maximum by weight would be based
upon water/detergent washer technology, as discussed in
Section VII of this document. This "residual oil" limitation
would be imposed as an indicator of toxic pollutants, specifi-
cally the priority organic pollutants in oils that are added to
drilling fluid systems.
Option 3 - Zero Discharge. This option would require zero
discharge of all drill cuttings, based upon transportation of
drill cuttings to shore for land disposal or to an approved ocean
disposal site. This option would result in no discharge of
pollutants to surface waters except at approved ocean disposal
sites.
Selected Option and Basis for Selectign
The Agency selected Option 1 as the basis for proposed NSPS for
drill cuttings. The requirements of Option 1 are comparable to
those of the selected option for drilling fluids.
The Agency did not select Option 2 at this time because it
believes that establishing an oil content limitation on drill
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cuttings may be redundant because the prohibition on the
discharge of free oil in conjunction with the prohibition of cut-
tings from oil-based muds appears to be a more stringent limita-
tion. While presently demonstrated cuttings washer technology
will reduce residual oil content to less than ten percent by
weight, the Agency's data base indicates that visible sheen can
be caused by as little as one percent oil, by weight. Thus, the
free oil discharge prohibition may be more stringent than any
residual oil limitation that can be presently attained with cut-
tings washer technology that has been demonstrated on a full-
scale basis. The Agency will collect and evaluate additional
cuttings washer performance data, especially with respect to the
use of mineral oil for lubricity and spotting purposes, to
establish whether an oil content limitation is more stringent
than the prohibition on the discharge of free oil.
The Agency rejected Option 3, zero discharge, because of high
aggregate compliance costs and land availability problems as
discussed below for drilling fluids BAT Option 3.
DECK DRAINAGE
As with BAT/BCT, the Agency is proposing to establish NSPS for
deck drainage the same as the BPT level of control. This would
result in a prohibition on the discharge of free oil. The tech-
nology "basis is oil-water separation. The Agency is reserving
coverage for all other pollutant parameters and characteristics
for deck drainage pending additional data collection and analy-
sis. This additional data will include toxic, nonconventional,
and conventional pollutant information and control and treatment
technology evaluation.
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The method of determining compliance with the free oil prohibi-
tion is by the static sheen test discussed earlier and as pre-
sented in Appendix A of this document. Where deck drainage is
collected and treated separately from produced water, the free
oil prohibition would apply. However, where deck drainage is
commingled and cotreated with produced water, the effluent limi-
tations for produced water would apply to these two combined
waste streams.
Because this proposed standard is equal to BAT/BCT, there are no
incremental compliance costs due to NSPS.
SANITARY WASTES
The Agency is proposing to establish NSPS for sanitary wastes
equal to the BAT/BCT level of control. This would result in: (1)
a prohibition on the discharge of floating solids for facilities
manned by nine or fewer persons or intermittently manned by any
number of persons; and (2) an effluent standard for residual
chlorine of 1 mg/1 minimum and to be maintained as close as
possible to 1 mg/1, for facilities continuously manned by ten or
more persons. Because these proposed standards are equal to
BAT/BCT, there are no incremental compliance costs due to NSPS.
DOMESTIC WASTES
The Agency is proposing to establish NSPS equal to the BCT level
of control for domestic wastes. This would result in a prohibi-
tion on the discharge of floating solids. Since NSPS would equal
BCT, no compliance costs incremental to BCT are associated with
this standard.
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PRODUCED SAND
The Agency is proposing to establish a prohibition on the
discharge of free oil for produced sand under NSPS. The tech-
nology basis for this standard is water or solvent wash of pro-
duced sands prior to discharge, or transport of produced sand to
shore for land disposal. The method of determining compliance
with the free oil prohibitation is by the static sheen test as
presented in Appendix A of this document. There are no
compliance costs incremental to the proposed BAT limitation.
The Aqency is reserving coverage for all other pollutant parame-
ters and characteristics for produced sand pending additional
data collection and analysis. This additional data will include
toxic, non-conventional, and conventional pollutant information
and control and treatment technology evaluation.
WELL TREATMENT FLUIDS
The Agency is proposing to establish a NSPS prohibition on the
discharge of free oil from well treatment fluids as an
"indicator" of specific toxic pollutants to reduce or eliminate
the discharge of any toxic pollutants in the free oil to surface
waters. These pollutants include: benzene, toluene, ethylben-
zene, naphthalene, and phenanthrene. This is equal to the pro-
posed BAT level of control, as discussed below. Therefore, there
are no compliance costs incremental to BAT.
The Agency is reserving NSPS coverage of all other pollutants for
well treatment fluids pending additional data collection and eva-
luation. This additional data will include toxic, nonconven-
tional and conventional pollutant information and control and
treatment technology evaluation.
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REGULATORY BOUNDARIES
New source offshore oil production facilities located in or
discharging to the following areas are subject to the zero
discharge standard for produced water, depending upon water depth
at the location of the facility or discharge. Unless otherwise
stated below, the outer boundary for each designated area is the
200-mile boundary of the Fishery Conservation Zone.
Gulf of Mexico - Water Depth 20 Meters or Less
Extending from the inner boundary of the .territorial seas
offshore of Eastern Texas, Louisiana, Mississippi, Alabama, and
Western Florida.
Atlantic Coast - Water Depth 20 Meters or Less
Extending from the inner boundary of the territorial seas
offshore of the contiguous states between and including Maine
and Florida
California, Coast - Water Depth 50 Meters of Less
Extending offshore of California and bounded on the north by
approximately 42°N latitude and bounded on the south by the U.S.
- Mexico boundary.
Alaska
1. Gulf of Alaska - Water Depth 50 Meters or Less
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It is bounded approximately on the west by 151" 55'W. longi-
tude; thence east along 59°N latitude to 148°W longitude;
thence south to 58°N latitude; thence east along 589N lati-
tude to 147°W longitude, thence south.
2. Cook Inlet/Shelikof Strait - Water Depth 50 Meters or Less
Lies east of 156°W longitude and north of 57°N latitude to
the inner boundary of the territorial seas near Kalgin
Island.
3. Bristol Bay/Aleutian Range - Water Depth 50 Meters or Less
a. North Aleutian Basin: Lies in the eastern Bering Sea
northwest of the Alaskan Peninsula and south of 59 °N
latitude. It is bounded on the west by 165°W longitude
and in the east by the inner boundary of the terri-
torial seas.
b. St. George Basin - Water Depth of 50 Meters or Less
Lies in the eastern Bering sea northwest of the
Aleutian Islands chain and is bounded on the north by
59°N latitude and on the west by 174aW longitude from
59°N latitude to 56°N latitude; thence east to 171 9W
longitude, thence south. It is bounded on the east by
165'W longitude.
4. Norton Basin - Water Depth 20 Meters or Less
Lies south and southwest of the Seaward Peninsula. It is
bounded on the south by 63°N latitude, on the west by the
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U.S. Russia Convention Line of 1867, on the north by 65°
34"N latitude, and on the east by the inner boundary of the
territorial seas.
5. Beaufort Sea - Water Depth 10 Meters or Less
Lies offshore of Alaska in the Beaufort Sea and the Arctic
Ocean. It is bounded on the west by the Mineral Management
Service Chukchi Sea planning area, extends eastward to the
limit of U.S. jurisdiction, and on the south by the inner
boundary of the territorial seas.
To determine water depth at a particular facility location,
reference the most recent nautical charts or bathymetric maps
with the smallest scale (highest resolution) available from the
National Oceanic and Atmospheric Administration for the area of
future development in question. Water depth is the mean lower
low water depth indicated on the appropriate map for the location
of the facility or discharge. Water depth at the facility is
based upon the proposed location of the facility's well slot
structure.
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REFERENCES
194. Jackson, G.F., E. Hume, J. J. Wade and M. Kirsch. 1981.
Oil content in produced brine on ten Louisiana production
platforms. Prepared by Crest Engineering Inc. for Municipal
Environmental Research Lab., U.S. EPA. Cincinnati, Ohio,
465 pp.
252. Eastern Research Group, Inc., "Economic Impact Analysis of
Proposed Effluent Guidelines Regulations for the Offshore
Oil and Gas Industry," Prepared for U .3. EPA, August 1984.
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X. BEST AVAILABLE TECHNOLOGY (BAT)
PRODUCED WATER
The Agency is reserving coverage of produced water for existing
sources at this time. This is because the Agency lacks suf-
ficient information to properly evaluate the technological feasi-
bility and economic achievability of a reinjection requirement
for existing sources. EPA is presently undertaking a comprehen-
sive data collection effort to obtain industry profile infor-
mation, retrofit costing information for reinjection, and
information on the extent of biocide and other chemical usage for
existing platforms. This information will be analyzed by the
Agency to develop appropriate discharge regulations for the BAT
level of control.
Because BAT is intended to control toxic and nonconventional
pollutants, improved BPT or filtration technologies were rejected
by the Agency for existing sources because these technologies
primarily control conventional pollutants, and do not effect
quantifiable reductions of toxic pollutants. The Agency will
continue to consider a reinjection option for BAT as presented
for NSPS above, including options based on variable water depths.
DRILLING FLUIDS
Control and Treatment Options Considered
Option 1 - Toxicity Limitation. This option is the same as NSPS
Option 1 for drilling fluids. It would regulate the discharge of
free oil, oil-based drilling fluids, diesel oil, cadmium, mercury
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and the toxicity of discharged drilling fluids. These limita-
tions are achieved by product substitution - through the use of
water-based drilling fluids (i.e., generic muds), low toxicity
specialty additives, the use of mineral oil instead of diesel oil
for lubricity and spotting purposes, and use of barite with low
toxic metals content. The purpose and rationale for these
effluent standards is the same as that presented above for NSPS.
This option would result in an annual cost of $26.3 million (1983
dollars) for an estimated 1166 wells. These costs are incremen-
tal to BPT requirements and are based upon the following:
transport of ten percent of all spent drilling fluid systems
either, to shore for land disposal or to an approved ocean dispo-
sal site; a 15 percent increase in barite costs due to increased
storage and handling costs and increased demand for barite with
low toxic metals content; testing costs associated with the toxi-
city limitation and the mercury and cadmium effluent limitation;
and monitoring costs. The differential cost of substituting
mineral oil for diesel oil (approx. $1.90 per gallon inlcuding
costs for storage and handling) is not attributable to the BAT
option as an incremental cost to BPT. While BPT does not prohi-
bit the discharge of diesel oil, the discharge of diesel oil in
any significant amounts (i.e., one volume percent or more) would
cause a sheen on receiving waters which would violate the BPT
prohibition on the discharge of free oil. Therefore, the amount
of mineral oil required to comply with a proposed prohibition on
the discharge of diesel oil would be minimal, and the associated
costs would be minimal.
Option 2 - Clearinghouse Approach. This option is the same as
NSPS Option 2 for drilling fluids. It is based upon the
establishment by EPA of a listing of drilling fluid formulations
and additives that are considered acceptable for discharge.
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Option 3 -Zero Discharge. This option is the same as NSPS
Option 3 for drilling fluids. It would require zero discharge
for all drilling fluids, based upon transport of spent drilling
fluids to shore for recovery, reconditioning for reuse, land
disposal, or transport to an approved ocean disposal site. This
level of technology would result in no discharge of pollutants to
surface waters, except at approved ocean disposal sites.
For the estimated 1166 wells drilled annually, this option would
cost $126.3 million (1983 dollars). These compliance costs are
incremental to BPT requirements, and reflect barging and moni-
toring costs.
This option would result in an annual reduction of the discharge
of 6.2 million barrels of drilling fluids to surface waters.
Selected Option and Basis for Selection
EPA has selected Option 1 as the basis for proposed BAT for
drilling fluids. BAT would include the same limitations as NSPS:
o A prohibition on the discharge of free oil, oil-based
drilling fluids, and diesel oil, all considered as
"indicators" of toxic pollutants.
o A 96-hour LC-50 toxicity limitation on discharged
drilling fluids of no less than 3.0 percent by volume of
the diluted suspended particulate phases.
o A maximum limitation (no single sample to exceed) on the
amount of cadmium and mercury in discharged drilling
fluids of 1 mg/kg each, dry weight basis.
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Options 2 and 3 were rejected for the same reasons as discussed
above for NSPS.
As with NSPS, the prohibitions on oil will be used as
"indicators" of toxic pollutants. These pollutants include:
benzene, toluene, ethylbenzene, naphthalene, and phenanthrene.
The Agency believes it is appropriate to establish these prohibi-
tions as BAT toxic limitations. The primary purpose is to
control the priority pollutants present in the oils. Control of
the oil content in fluids could also be achieved through a
numeric limitation on the conventional pollutant "oil and
grease." In fact, the Agency has included the prohibition on the
discharge of free oil as a BCT limitation in recognition of the
complex nature of the oils present in drilling fluids. However,
the Agency's- decision to establish BAT limitations through the
three oil prohibitions was based on the consideration that it
would be less difficult and costly to comply with these three
"indicator" limitations than numeric limitations on each of the
organic priority pollutants present in the oils. This decision
to establish limitations on oils as indicators of priority pollu-
tants is consistent with the Agency's listing of "oil and grease"
as a conventional pollutant. (44 PR 44501). The Agency solicits
comments on its decision to establish these indicator pollutant
limitations as BAT rather than setting numeric limitations on the
specific organic priority pollutants. Since the oils would be
considered BAT toxic indicators, such limitations would not be
subject to Section 301(c) or Section 301(g) modifications.
Related to this option, the Agency is proposing to amend the
current definition of the term "no discharge of free oil." The
current definition of'"no discharge of free oil" defines the term
to mean "that a discharge does not cause a film or sheen upon or
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a discoloration on the surface of the water or adjoining shoreli-
nes or cause a sludge or emulsion to be deposited beneath the
surface of the water or upon adjoining shorelines,"
The amended definition is accompanied by a test procedure for
determining compliance with the prohibition on free oil
discharges. This test is the "static sheen test" presented in
Appendix A of this document. This method would apply to the same
waste streams that are regulated by the existing BPT regulations,
i.e., deck drainage, drilling fluids, drill'cuttings, and well
treatment fluids.
The compliance monitoring procedure previously required by per-
mits was a visual inspection of the receiving water after
discharge. However, since the intent of the limitation is to
prohibit discharges containing free oil that will cause a sheen,
the method of determining compliance should examine oil con-
tamination prior to discharge. Also, conce'rns have been raised
that the intent of the existing definition of "no discharge of
free oil" may be violated too easily for the limitation to be
effective. Violations which may result from intentional or unin-
tentional actions include the use of emulsifiers or surfactants,
discharges that occur under poor visibility conditions (i.e., at
night or during stormy weather), and discharges into heavy seas,
which are common in offshore areas. Additionally, concerns have
been expressed over the utility of the visual observation of
receiving water compliance monitoring procedure for certain
discharges during ice conditions as in Alaskan operations. These
include above-ice discharges where the receiving water would be
covered with broken or solid ice, and below-ice discharges where
the effluent stream would be obscured.
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To correct for these monitoring problems, the Agency developed an
alternative compliance test, the Static Sheet Test, which is pre-
sented in Appendix A of this document. The alternative test con-
tinues the visual observation for sheen, but provides for testing
before discharge using laboratory procedures. The test is con-
ducted by adding samples of the effluent stream into a container
in which the sample is mechanically mixed with a specific propor-
tion of seawater, allowed to stand for a designated period of
time, and then viewed for a sheen.
Since the intent of a "no discharge of free oil" limitation is to
prevent the occurrence of a sheen on the receiving water, the new
test method will prevent the discharge of fluids that will cause
such a sheen.
DRILL CUTTINGS
Control and Treatment Options Considered
Option 1 - Product Substitution. Option 1 is the same as NSPS
Option 1 for drill cuttings. It would result in the prohibited
discharge of free oil, oil-based drilling fluids, and diesel oil
with discharged dr.ill cuttings. These limitations, as for the
selected option for drilling fluids, are achieved by product
substitution. The rationale for these limitations is also the
same as for drilling fluids Option 1 because the constituent of
concern in the drill cuttings waste stream is the residual
drilling fluid that mixes with and adheres to the drill cuttings.
For the estimated 1166 wells drilled annually, this option would
result in an estimated annual barging and monitoring cost of $8.6
million (1983 dollars). No investment costs are expected to
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occur from this option. This option would result in an estimated
annual reduction of at least 1.3 million pounds of oil otherwise
discharged to surface waters.
Option 2 - Product Substitution plus Oil Limitation. Option 2 is
equivalent to Option 1 plus a limitation on the allowable oil
content of the discharged cuttings. This option is the same as
NSPS Option 2 for drill cuttings. The oil content limitation of
10 percent maximum by weight would be based upon drill cuttings
water/detergent washer technology, as discussed in Section X of
this document.
Option 3 - Zero Discharge. Option 3 would require zero discharge
of all drill cuttings, based upon transport of drill cuttings to
shore for land disposal, or transportation to an approved ocean
disposal site. This option would result in no discharge of
pollutants to surface waters, except at approved ocean disposal
sites. This option is the same as NSPS Option 3 for drill cut-
tings.
For the estimated 1166 wells drilled annually, this option would
result in annual monitoring and barging costs of $77.1 million
(1983 dollars). This option would result in an annual reduction
of 1.7 million barrels of drill cuttings discharged to surface
waters.
Selected Option and Basis for Selection
The Agency selected Option 1 as the basis for proposed BAT for
drill cuttings. The requirements of Option 1 are comparable to
those of the selected option for drilling fluids. This option is
based on product substitution which is both a technologically
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feasible and economically achievable means for compliance by the
industry.
The Agency is not selecting Option 2 at this time because it
believes, as discussed above for NSPS, that establishing an oil
content limitation on drill cuttings may be redundant because the
prohibition on the discharge of free oil appears to be a more
stringent limitation. The Agency will collect and evaluate addi-
tional cuttings washer performance data, especially with respect
to the use of mineral oil for lubricity and spotting purposes, to
establish whether an oil content limitation is more stringent
than the free oil limitation.
The Agency rejected Option 3, zero discharge, because of high
aggregate compliance costs and concern for adequate land availa-
bility for disposal as discussed above for NSPS.
DECK DRAINAGE
The Agency is proposing to establish BAT for deck drainage equal
to the BPT level of control. This would result in a prohibition
on the discharge of free oil to reduce or eliminate the discharge
of any toxic pollutants in the free oil to surface waters. The
technology basis is oil-water separation. BAT compliance costs
incremental to BPT consist of additional compliance monitoring
expenditures of $1.09 million (1983 dollars) annually, reflecting
use of the proposed static sheet test to determine compliance
with the prohibition on the discharge of free oil.
The Agency is reserving coverage of all other toxic and noncon-
ventional pollutant parameters and characteristics for deck
drainage pending additional data collection and analysis. This
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additional data will include toxic pollutant information and
control and treatment technology evaluation.
SANITARY WASTES AND DOMESTIC WASTES
The Agency is not proposing to establish BAT effluent limitations
for these waste streams because there have been no toxic or non-
conventional pollutants of concern identified in sanitary or
domestic wastes.
PRODUCED SAND
The Agency is proposing to establish a BAT prohibition on the
discharge of free oil for produced sand as an "indicator" to
reduce or eliminate the discharge of any toxic pollutants in the
free oil to surface waters. The technology basis for this limi-
tation is water and/or solvent wash of produced sands prior to
discharge, or transport of produced sand to shore for land dispo-
sal. Because this waste stream is of low volume and because most
facilities currently practice either washing or land disposal,
the Agency did not attribute any compliance costs to this pro-
posed limitation, except for nominal compliance monitoring expen-
ses to perform the static sheen test to determine the presence of
free oil.
The Agency is reserving coverage of all other toxic and non-
conventional pollutant parameters and characteristics for pro-
duced sand pending additional data collection and analysis. This
additional data will include toxic pollutant information and
control and treatment technology evaluation.
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WELL TREATMENT FLUIDS
The Agency is proposing to establish a BAT prohibition on the
discharge of free oil for well treatment fluids as an "indicator"
to reduce or eliminate the discharge of any toxic pollutants in
the free oil to surface water. This is equal to the BPT level of
control. Therefore, there are no compliance costs incremental to
BPT, except for nominal compliance monitoring expenses to perform
the static sheen test to determine the presence of free oil.
The Agency is reserving BAT coverage of all other pollutants and
characteristics for well treatment fluids pending additional data
collection and evaluation. This additional data will include
toxic and nonconventional pollutant information and control and
treatment technology evaluation.
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XI. BEST CONVENTIONAL TECHNOLOGY (BCT)
The 1977 amendments added section 301(b)(4)(E) to the Act,
establishing "best conventional pollutant control technology"
(BCT) for discharges of conventional pollutants from existing
industrial point sources. Conventional pollutants are those
defined in section 304(b)(4) - BOD, TSS, fecal coliform and pH
-and any additional pollutants defined by the Administrator as
"conventional." On July 30, 1979, EPA designated "oil and
grease" as a conventional pollutant (44 PR 44501).
BCT is not an additional limitation; rather it replaces BAT for
the control of conventional pollutants. BCT requires that limi-
tations for. conventional pollutants be assessed in light of
"cost-reasonableness." EPA published proposed rules for BCT on
October 29, 1982 (47 FR 49176). These proposed rules set forth a
revised procedure which includes two tests to determine the
reasonableness of costs incurred to comply with candidate BCT
technologies. These cost tests are the "POTW test" and the
"industry cost test." On September 20, 1984, EPA published a
"notice of data availability" concerning the proposed BCT regula-
tions (49 FR 37046).
PRODUCED WATER
Control and Treatment Options Considered
EPA examined the three treatment options for removing conven-
tional pollutants from produced water in relation to the proposed
BCT methodology.
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Option 1 - Improved Performance of BPT. This option would
require effluent limitations based on the improved performance of
BPT technology. As presented above for NSPS option (a), this
level of technology would result in additional reductions of oil
and grease beyond the BPT level of control. A discharge limita-
tion of 59 mg/1 maximum (no single sample to exceed) for oil and
grease would result from this option.
Option 2_ - Filtration On Site. This option would require
effluent limitations based on granular media filtration as an
add-on technology to BPT. Filtration equipment would be
installed on the platform with the treated effluent being
discharged at the platform. This level of technology would
result in additional reductions of conventional pollutants beyond
the BPT level of control. Effluent limitations of 20 mg/1
monthly average and 30 mg/1 daily maximum for oil and grease
would result from this option.
Option 3 - Filtration Onshore. This option is the same as Option
2 except it is applicable to facilities which presently separate
produced water from hydrocarbon product at the platform, pipe the
produced water to shore for treatment to meet BPT effluent limi-
tations, and discharge the treated effluent to surface waters.
Selected Option and Basis for Selection
The Agency rejected the options presented above and is proposing
to establish BCT for produced water at the BPT level of control.
This would result in effluent limitations of 48 mg/1 monthly
average and 72 mg/1 daily maximum for oil and grease, based upon
oil-water separation technologies. The Agency rejected Options 1
through 3 because they all fail the first part of the Agency's
proposed BCT cost test (the "POTVJ test").
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For Option 1, the Agency was unable to directly perform the POTW
test because the Agency lacks sufficient information to accura-
tely estimate the incremental cost of improved BPT performance
(see Section IX NSPS Produced Water Control and Treatment
Options,• above); this cost is necessary in order to perform the
POTW test. Therefore/ the Agency analyzed this option by deter-
.mining the maximum dollar expenditure per day that model plat-
forms could incur to implement this option without exceeding the
POTW test benchmark.
The maximum cost per pound of conventional pollutant removal
whereby the "POTW test" will be passed is presented in the BCT
"notice of data availability" referenced above. These maximum
costs were used to calculate the total dollars that could be
expended at .each of the 32 model platforms, discussed in Section
VIII, to comply with this option and still pass the "POTW test."
This was accomplished by multiplying the pounds of conventional
pollutants that would be removed by BCT Option 1 technology for
each of the 32 model platforms developed for this study by the
maximum cost per pound presented in the "notice of data
availability."
This total cost for each model platform ranged from $0.79 per day
for the smallest platform to $182 per day for the largest plat-
form. The Agency believes that the cost of implementing Option 1
is minimal, although not as low as the range of daily costs pre-
sented above. Therefore, the Agency rejected Option 1 because it
fails the POTW cost test.
For Options 2 and 3, the Agency calculated compliance costs
(incremental to BPT) for each of 32 model platforms and then per-
formed the POTW test for each model size platform. The range in
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costs per pound of conventional pollutant removed beyond BPT for
Options 2 and 3 based on model platform size, is as follows:
Lowest Cost Highest Cost
$/lb Removed $/lb Removed
(1980 dollars) (1980 dollars)
Option 2 64 71
Option 3 54 63
These costs were compared with the fourth quarter, 1980 POTW pro-
posed benchmark of $1.04 per pound of conventional pollutant
removed; the POTW test failed for Options 2 and 3 for all model
platforms. Therefore, EPA rejected these options for the 3CT
level of control. The Agency intends to evaluate reinjection
technology for BCT after collection of certain additional tech-
nology and cost information prior to promulgation of the final
regulations. The Agency may also re-evaluate the proposed BCT
limitations for produced water when the final BCT methodology is
promulgated.
DRILLING FLUIDS, DRILL CUTTINGS, DECK DRAINAGE AND WELL
TREATMENT FLUIDS
With one exception, the Agency is reserving BCT requirements for
drilling fluids, drill cuttings, deck drainage and well treatment
fluids until final promulgation of the general BCT methodology.
The exception is a prohibition on the discharge of free oil.
This limitation is equal to the BPT level of control for these
waste streams. Therefore, no incremental costs are associated
with this proposed BCT limitation. Because BCT is proposed to be
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equal to BPT, the free oil discharge prohibition will pass any
BCT methodology adopted. When the final BCT methodology is prom-
ulgated, the Agency may propose to establish BCT limitations for
other conventional pollutants for these waste streams. At this
time, the Agency is soliciting comment on what pollutants in
drilling fluid and drill cuttings waste streams should be con-
sidered conventional pollutants. Specifically, the Agency soli-
cits comments on whether the solids components of the fluids and
cuttings should be considered total suspended solids.
DOMESTIC AND SANITARY WASTES
The Agency is proposing BCT coverage for sanitary and domestic
wastes equal to the BPT level of control. The Agency is pro-
posing a re_sidual chlorine effluent limitation for facilities
continuously manned by 10 or more persons of 1 mg/1 minimum and
to be maintained as close to this level as possible in sanitary
discharges. Residual chlorine is being treated as a BCT para-
meter because its purpose is to control the conventional pollu-
tant fecal coliform.
The proposed BCT limitation for domestic wastes from all facili-
ties and sanitary wastes from facilities continuously manned by 9
or fewer persons or manned intermittently by any number of per-
sons is "no discharge of floating solids." No compliance costs
incremental to BPT are associated with the proposed BCT limita-
tions. Since no additional costs will be incurred these limita-
tions pass the BCT cost tests.
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PRODUCED SAND
With one exception, the Agency is reserving BCT coverage for pro-
duced sand until the promulgation of the final BCT methodology.
The Agency is proposing a BCT limitation that would prohibit the
discharge of free oil for produced sand discharges. As discussed
above for BAT, this limitation would result in negligible
compliance costs.
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XII. BEST MANAGEMENT PRACTICES
Section 304(e) of the Clean Water Act authorizes the Adminis-
trator to prescribe "best management practices" ("BMP") to
control "plant site runoff, spillage or leaks, sludge or waste
disposal, and drainage from raw material storage." Section
402(a)(1) and NPDES regualtion (40 CFR 122) also provide for best
management practices to control or abate the discharge of pollu-
tants when numeric effluent limitations are infeasible. However,
the Administrator may prescribe BMP's only where he finds that
they are needed to prevent "significant amount" of toxic or
hazardous pollutants from entering navigable waters.
In the offshore oil and gas industry there are various types of
wastes that may be affected by the application of BMP's in NPDES
permits. These include deck drainage and leaks and spoils from
various sources. The amount of contaminated deck drainage can be
decreased considerably if proper segregation is practiced.
"Clean" deck drainage should be segregated from sources of con-
tamination. Many sources exist on an offshore platform where
leaks or spillages could occur. The areas should be managed so
that all leakages and/or spills are contained and not discharged
overboard.
Good operation and maintenance practices reduce waste flows and
improve treatment efficiencies, as well as reducing the frequency
and magnitude of system upsets. Some examples of good offshore
operation are:
1. Separation of waste crankcase oils from deck drainage
collection systems.
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2. Minimization of wastewater treatment system upsets by
the controlled usage of deck washdown detergents.
3. Reduction of oil spillage through the use of good pre-
vention techniques such as drip pans and other handling
and collection methods.
4. Elimination of oil drainage from pump bearings and/or
seals by directing the drainage to the crude oil pro-
cessing system.
5. If oil is used as a spotting fluid, careful attention
to the operation of the drilling fluid system could
result in the segregation from the main drilling fluid
system of the spotting fluid and the drilling fluid
that has been contaminated by the spotting oil. Once
segregated, the contaminated drilling fluid can be
disposed of in an environmentally acceptable manner.
Proper initial engineering of the various systems is essential to
proper operation and ease of maintenance. The use of spare
equipment is a requirement for continual operation when break-
downs occur. Selection of proper treatment chemicals, to insure
optimum pollutant removals, is essential. Alarms should be pro-
vided to make the operator aware of off-normal conditions so
corrective action can be taken.
Careful planning, good engineering and a commitment on the part
of the operating, maintenance and management personnel are needed
to ensure that the full benefits of all pollution reduction faci-
lities are realized.
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6. Careful application of drill pipe dope to minimize con-
tamination of rceiving water and drilling muds. Pipe
dope can contribute high amounts of lead and probably
other metals to discharged muds.
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XIII. ACKNOWLEDGEMENTS
Many individuals representing numerous organizations, cor-
porations, and agencies have contributed material, time and
energy to the technical studies conducted in developing these
effluent limitations guidelines and standards, and to the produc-
tion of this document.
This document was prepared under the direction of Mr. Dennis
Ruddy, Project Officer in the Energy and Mining Branch of EPA's
Industrial Technology Division. Mr. William Telliard, Chief of
the Energy and Mining Branch, also provided extensive direction
and assistance during the course of the program.
Appreciation is expressed to Mr. Harold Kohlmann of Kohlmann,
Ruggerio Engineers for his support in several sections of the
document.
Many individuals from organizations associated with the petroleum
industry provided cooperation in providing requested information
and support in field data collection activities. These organiza-
tions include the Offshore Operations Committee and the American
Petroleum institute.
The substantial cooperation and assistance from the numerous
people from the various offices at EPA Headquarters involved with
this program is deeply appreciated.
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XIV. BIBLIOGRAPHY
API, Bui 13F: Oil and Gas Well Drilling Fluid Chemicals,
Section2 "Drilling Fluid Chemicals."
American Petroleum Institute, Basic Petroleum Data Book,
Petroleum Industry Statistics, Vol. Ill/ No. 3, September
1983.
Aquatic Hazard Evaluation Division Energy Resources Company,
Inc., Environmental Assessment of an Active Oil Field in the
Northwestern Gulf of Mexico.
API, "Recommended Practice for Production Facilities on
Offshore Structures," API RP 2G, first edition, January
1974.
API, "Specification for Oil and Gas Separators," API Spec.
12J, fourth edition, March 1978.
API, "Bulletin on Oil and Gas Well Drilling Fluid
Chemicals," API BUL 13F, first edition, August 1978.
API, "Recommended Practice for Biological Analysis of
Subsurface Injection Waters," API RP 38, third edition,
December 1975, reissued March 1982.
Acosta, D., "Special Completion Fluids Outperform Drilling
Muds," Oil & Gas Journal, March 2, 1981 pp. 83—86.
Arctic Laboratories Limited ESL Environmental Sciences
Limited and SKM Consulting Ltd., Offshore Oil and Gas
Production, Waste' Characteristics, Treatment Methods,
Biological Effects and Their Application to Canadian Regions
(DOS File No. 4753-KE 145-2-0245) Draft report prepared for
the Canadian Environmental Protection Service, Water
Pollution Control Directorate, April 1983.
American Petroleum Institute Production Department,
Subsurface Salt Water Injection and Disposal, Book 3 of the
Vocational Training Series,second editionT978.
Bureau of Land Management, Beaufort Sea Final Environmental
Impact Statement, Vol. 1, 1979.
Baker, R., A Primer of Oil-Well Drilling/ 4th Edition,
University of Texas At Austin,Texas.
Booz, Allen & Hamilton, "Cost and Feasibility of Disposal and
Monitoring Options for Oil and Gas Facilities." prepared for
USEPA Office of Water Planning and Standards, June 5, 1980.
-347-
-------
Burns and Roe Industrial Services Corp. "Draft Report Review
of Drill Cuttings Washer Systems Offshore Oil and Gas
Industry" for U.S. EPA, October 14, 1983.
Cranfield, J., "Cutting Clean-Up Meets Offshore Pollution
Specifications," Petrol. Petrochem. Int., Vol. 13, No. 3 pp.
54-56, 59
California Division of Oil & Gas, 64th Annual Report of the
State Oil and Gas Supervisor.
Drilling Contractor, "Know Your Drilling Mud Components,"
Vol. 36, Issue 3, pp 92-110, March 1980.
ECOMAR under direction of EXXON Production Research Company,
Maximum Mud Discharge Study, for the Offshore Operator's
Committee,Environmental Subcommittee, June 1980.
Exxon Research and Engineering Company, "Study of 'Pollution
Control Technology for Offshore Oil Drilling and Production
Platforms", February 1977.
ERCO "Acute Toxicity of Suspender Particulate Phase of
Drilling Fluids Containing Diesel Fuels" for U.S., EPA, May
1984.
Environmental Conservation - The Oil and Gas Industries
National Petroleum Council, 1982.
Gallaway, B.J., Margin, L.R., Howard, R.L., Bol-and, G.S. and
Dennis, G.S. A Case Study of the Effects of Gas and Oil
Production on Artificial Reef and Demersal Fish and
Macrocrustacean Communities in the Northwestern Gulf of
Mexico.
"Global action points to gain in offshore production," Oil &
Gas Journal, February 9, 1981, pp. 27-33.
Geological Survey Circular 725, Geological Estimates of
Undiscovered Recoverable Oil and Gas Resources in the United
States, 1975.
Hayward, B.S., Williams, R.H., and Methven, M.E.,
"Prevention of Offshore Pollution from Drilling Fluids,"
Paper presented at the 46th Annual SPE of AIME Fall Meeting,
New Orleans, Louisiana, October 3-6, 1971, Preprint No. SPE
3579.
IMCO Services, The Basics of Drilling Fluids, Houston,
Texas.
IMCO Service, Product Data Book, Houston, TExas.
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Jackson, George P., et al, "Project Summary - Oil Content in
Produced Brine on Ten Louisiana Production Platforms," U.S.
EPR MERL, Cinn., OH, EPA-600/S2-81-209, Oct. 1981.
Jones, M., "Well History and Technical Report."
Jorda, R.M., Use of Data Obtained from Core Tests in the
Design and Operation of Spent Brine Injection Wells in
Geopressured or Geothermal Systems/ Completion Technology
Company, March 1980.
Middleditch, B.S., APR Project No. 248 Ecological Effects of
Produced Water Discharges from Offshore Oil and Gas
Production Platforms, March 1984.
Menzie, Charles A., The Environmental Implications of
Offshore Oil and Gas Activities," ES&T, Vol. 16, No. 8,
1982.
National Marine Pollution Program Office National Oceanic
and Atmospheric Administration, "Evaluation Panel Report
Review of Federal Programs in Environmental Impact Studies
of Petroleum in the Marine Environment," conducted for
Interagency Committee on Ocean Pollution Research,
Development and Monitoring, December 1980.
National Petroleum Council, "Materials and Manpower
Requirements for Oil and Gas Exploration and Production -
1979-1990," December 1979.
Offshore Oil Scouts Assn., Status of the Offshore Oil
Industry as of January 1, 1980 & Statistical Review of
Events between July 1, 1979 and January 1, 1980.
Petroleum Equipment Supplies Association Environmental
Affairs Committee, "Cnemical Components and Uses of
Drilling Fluids," Appendix A, March 25, 1980.
Petroleum Extension Service, University of Texas, "Primer of
Offshore Operations", 1976.
Parker, J. and Ferrante, J. "A Survey of Discharges From A
Natural Gas Drilling Operation In Lake Erie," EST, 1982, 16,
363-367.
Petrazzuolo, G., Draft Final Technical Support Document
"Environmental Assessment: Drilling Fluids and Cuttings
Released onto the OCS," Submitted to Office of Water
Enforcement and Permits U.S. EPA, January 1983.
-349-
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Ray, James P. "Offshore Discharge of Drill Muds and
Cuttings", Outer Continental Shelf Frontier Technology,
Proceedings of a Symposium, December 6,1979," National
Academy of Sciences.
Ranney, M.w., Crude Oil Drilling Fluids, Chemical
Technology Review No. 121, Energy Technology Review No. 35,
Noyes Data Corp., Park Ridge, N.J. 1979.
Railroad Commission of Texas, Oil and Gas -Division, "Rules
Having Statewide General Application to Oil, Gas, and
Geothermal Resource Operations Within the State of Texas,"
Revised May 1, 1974.
Rice University Studies, The Offshore Ecology Investigation,
Vol. 65, Nos. 4 and 5, Fall 1979.
Sheen Technical Subcommittee of the Offshore Operators
Committee, Louisiana Coastal Production Operations,
"Supplemental Performance Data on Fibrous and Loose Media
Coalescers, and Magnetic Oil-Water Separation Apparatus",
May 1974.
Sheen Technical Subcommittee of the Offshore Operators
Committee, Environmental Aspects of Produced Waters from
Oil and Gas Extraction Operations in Offshore and Coastal
Waters, September 30, 1975.
State of Louisiana, Office of Conservation, "Secondary
Recovery and Pressure Maintenance Operations in- Louisiana"
1978.
The University of Texas at Austin, Principles of Drilling
Fluid Control, 12th Edition, Austin, Texas
Technical Subcommittee, Offshore Operators Committee,
"Subsurface Disposal for Offshore Produced Water - New
Sources Gulf of Mexico", New Orleans, LA., September 1974.
U.S. Environmental Protection Agency, Industrial Process
Profiles for Environmental Use: Chapter 2, Oil and Gas
Production Industry, February 1977, EPA-600/2-77-Q23b.
United States Department of the Interior, "Outer Continental
Shelf Statistics", June 1980.
U.S. Environmental Protection Agency, Office of Water
Planning and Standards, A Study of the Environmental
Benefits of Proposed 3ATEA and NSPS Effluent Limitations
ffor the Offshore Segment of the Oil and Gas Extraction
Point Source Category, Washington, D.C. EPA-440 1-77-011 .
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U.S. Environmental Protection Agency, Development Document
for Interim Final Effluent Limitation Guidelines and New
Source^Performance Standards for the Offshore Segment of the
Oil and Gas Extraction Point Source Category, 'September
1975, EPA 440/1/75/055.
U.S. Environmental Protection Agency, Office of Research and
Development, Brine Disposal Treatment Practices Relating to
the Oil Production Industry, Washington, D.C. May 1974,
EPA-660/2-74-037
University of Oklahoma, Petroleum Data System of North
America, Users Guide.
USEPA Corvallis, Oregon, Offshore Crude Oil Wastewater
Characterization Study.
U.S. Army Corps of Engineering and U.S. EPA, Draft
Programmatic EIS: U.S. Lake Erie Natural Gas Resource
Development.
U.S. Environmental Protection Agency, Industrial
Environmental Research Laboratory, "Sulfide Precipitation of
Heavy Metals," EPA-600/2-80-139, June 1980.
Worldwide Directory Offshore Contractors and Equipment,
T y b u .
World Oil's "Guide to Drilling, Workover and Completion
Fluids," periodically updated.
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XV. GLOSSARY AND ABBREVIATIONS
Act - The Clean Water Act.
Air/Gas Lift - Lifting of liquids by injection of air or gas
directly into the well.
Ann u1us or Annu1ar Space - The space between the drill stem and
the wail "of"' the hole or casing.
AOGA - Alaskan Oil and Gas Association.
API - American Petroleum Institute.
API Gravity - Gravity (weight per unit of volume) of crude oil as
measured by a system recommended by the API.
Attapulgite Clay - A colloidial, viscosity-building clay used
principally in salt water muds. Attapulgite is a hydrous
magnesium aluminum silicate.
Back Pressure - Pressure resulting from restriction of full
naturalFlow of oil or gas.
Barite - Barium sulfate. An additive used to weight drilling
mud.
Barrel - 42 United States gallons at 60 degrees Fahrenheit.
BAT - The best available technology economically achievable,
under Section 304(b)(2)(B) of the Act.
BCT - The best conventional pollutant control technology.
BDT - The best available demonstrated control technology
processes, operating methods, or other alternatives,
including where practicable, a standard permitting no
discharge of pollutants under Section 306(a)(1) of the Act.
Bentonite - A clay additive used to increase viscosity of drill-
ing mud.
Blowcase - A pressure vessel used to propel fluids intermittently
by pneumatic pressure.
Blowout - A wild and uncontrolled flow of subsurface formation
fluids at the earth's surface.
Blowou t Preven te r (BOP) - A device to control formation pressures
in a well by closing the annulus when pipe is suspended in
the well or by closing the top of the casing at other times.
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BMP - Best management practices under Section 304(e) of the Act.
BOD - Biochemical oxygen demand.
BPT - The best practicable control technology currently
available, under Section 304(b)(1) of the Act.
Bottom-Hole Pressure - Pressure at the bottom of a well.
Brackish Water - Water containing low concentrations of any
soluble salts.
Brine - Water saturated with or containing a high concentration
of common salt (sodium chloride); also any strong saline
solution containing such other salts as calcium chloride,
zinc chloride, calcium nitrate, etc.
BS&W - Bottom Sediment and water carried with the oil.
Generally, pipeline regulation limits BS&W to 1 percent of
the volume of oil.
Casing - Large steel pipe used to "seal off" or "shut out" water
and prevent caving of loose gravel formations when drilling a
well. When the casings are set, drilling continues through
and below the casing with a smaller bit. The overall length
of this casing is called the string of casing. More than one
string inside the other may be used in drilling the same
well.
Centrifuge - A device for the mechanical separation of solids
from a liquid. Usually used on weighted muds to recover the
mud and discard solids. The centrifuge uses high-speed
mechanical rotation to acheive this separation as
distinguished from the cyclone-type separator in which the
fluid energy alone provides the separating force.
C hem i cal-Electrical Treat er - A vessel which utilizes surfac-
tants, other chemicals and an electrical field to break oil-
water emulsions.
Choke - A device with either a fixed or variable aperture used
to release the flow of well fluids under controlled pressure.
Christmas Tree - Assembly of fittings and valves at the top of
the casing of an oil well that controls the flow of oil from
the well.
Circulate - The movement of fluid from the suction pit through
pump, drill pipe, bit annular space in the hole and back
again to the suction pit.
Clean Water Act - The Federal Water Pollution Control Act Amend-
ments of 1972 (33 U.S.C. 1251 et sea.), as amended by the
Clean Water Act of 1977 (Pub. L. 95-217).
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Closed-In - A well capable of producing oil or gas, but tem-
porarily not producing,
COD - Chemical oxygen demand.
Condensate - Hydrocarbons which are in the gaseous state under
reservoir conditions but which become liquid either in
passage up the hole or at the surface.
Connate Water - Water that probably was laid down and entrapped
with sedimentary deposits as distinguished from migratory
waters that have flowed into deposits after they were laid
down.
Cuttings - Small pieces of formation that are the result of the
chipping and/or crushing action of the bit.
Cyclone - Equipment, usually cyclone type, for removing drilled
sand from the drilling mud stream and from produced fluids.
Deck Drainage - Any waste resulting from deck washings, spillage,
rainwater, and runoff from gutters and drains including drip
pans and .work areas within facilities addressed by this docu-
ment.
Derrick and Substructure - Combined foundation and overhead
structure to provide for hoisting and lowering necessary to
drilling.
Desilter - Equipment, normally cyclone type, for removing extre-
mely fine drilled solids from the drilling mud stream.
Development Facility - Any fixed or mobile structure addressed by
this document that is engaged in the drilling and completion
of productive wells.
Diesel Oil - The grade of distillate fuel oil, as specified in
the American Society for Testing and Materials' Standard
Specification D975-81, that is typically used as the con-
tinuous phase in conventional oil-based drilling fluids.
Pif fe r e n ti a1 Pressure Sticking - Sticking which occurs because
part of the drill string (usually the drill collars) becomes
embedded in the filter cake resulting in a non-uniform
distribution of pressure around the circumference of the
pipe. The conditions essential for sticking require a per-
meable formation and a pressure differential across a nearly
impermeable filter cake and drill string.
Disposal Well - A well through which water (usually salt water)
is returned to subsurface formations.
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Domestic Waste - Materials discharged from sinks, showers,
laundries, and galleys located within facilities addressed by
this document.
Drill Cuttings - Particles generated by drilling into subsurface
geologic formations and carried to the surface with the
drilling fluid.
Drilling Fluid - The circulating fluid (mud) used in the rotary
drilling of wells to clean and condition the hole and to
counterbalance formation pressure. A water-base drilling
fluid is the conventional drilling mud in which water is the
continuous phase and the suspending medium for solids,
whether or not oil is present. An oil-base drilling fluid
has diesel, cruide, or some other oil as its continuous phase
with water as the dispersed phase.
Drill Pipe - Special pipe designed to withstand the torsion and
tension loads encountered in drilling.
Dump Valve - A mechanically or pneumatically operated valve used
on separator, treaters, and other vessels for the purpose of
draining, or "dumping" a batch of oil or water.
EmuIs ion - A substantially permanent heterogenous mixture of two
or more liquids (which are not normally dissolved in each
other, but which are) held, in suspension or dispersion, one
in the other, by mechanical agitation or, more frequently, by
adding small amounts of substances known as emulsifiers.
Emulsions may be oil-in-water, or water-in-oil.
EPA - United States Environmental Protection Agency.
Exploration Facility - Any fixed or mobile structure addressed
by this document that is engaged in the drilling of wells to
determine the nature of potential hydrocarbon reservoirs.
Field - The area around a group of producing wells.
Flocculation - The combination or aggregation of suspended solid
particles in such a way that they form small clumps or tufts
resembling wool.
Flowing Well - A well which produces oil or gas without any means
of artificial lift.
Fl uid Injection - Injection of gases or liquids into a reservoir
to force oil toward and into producing wells. (See also
"Water Flooding.")
Formation - Various subsurface geological strata penetrated by
well bore.
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Formation Damage - Damage to the productivity of a well resulting
from invasion of mud particles into the formation.
Fracturing - Application of excessive hydrostatic pressure which
fractures the well bore (causing lost circulation of drilling
fluids).
Freewater Knockout - An oil/water separation tank at atmospheric
pressure.
Gas Lift - A means of stimulating flow by aerating a fluid column
with compressed gas.
Gas-Oil .Ratio - Number of cuic feet of gas produced with a barrel
of oil.
Gathering Line - A pipeline, usually of small diameter, used in
gathering crude oil from the oil field to a point on a main
pipeline.
Gel^ - A term used to designate highly colloidal, high-yielding,
viscosity-building commercial clays, such as bentonite and
attapulgite clays.
GC - Gas chromatography.
Gun Barrel - An oil-water separation vessel.
Header - A section of pipe into which several sources of oil, such
as well streams, are combined.
Heater-Treater - A vessel used to break oil water emulsion with
heat.
Hydrocarbon Ion Concentration - A measure of the acidity or alka-
linity of a solution, normally expressed as pH.
Hydrostatic Head - Pressure which exists in the well bore due to
the weight of the column of drilling fluid; expressed in
pounds per square inch (psi).
I nhi b itor - An additive which prevents or retards undesirable
changes in the product. Particularly, oxidation and corro-
sion; and sometimes parrafin formation.
Invert Oil Emulsion Drilling Fluid - A water-in-oil emulsion
where fresh or salt water is the dispersed phase and diesel,
crude, or some other oil is the continuous phase. Water
increases the viscosity and oil reduces the viscosity.
Killing a Well - Bringing a well under control that is blowing
out. Also, the procedure of circulating water and drilling
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fluids into a completed well before starting well servicing
operations.
Location (Drill Site) - Place at which a well is to be or has
"been"drilled.
96-hr LC-5Q - The concentration of a test material that is
lethal to 50 percent of the test organisms in a bioassay
after 96 hours of constant exposure.
M_1_0 - Those offshore facilities continuously manned by ten (10)
or more persons.
M9IM - Those offshore facilities continuously manned by nine (9)
or fewer persons or only intermittently manned by any number
of persons.
Mud_Pit - A steel or earthen tank which is part of the surface
~*drilling mud system.
Mud Pump - A reciprocating, high pressure pump used for cir-
culating drilling mud.
Mult iple Completion - A well completion which provides for
simultaneous production from separate zones.
NPDES Permit - A National Pollutant Discharge Elimination System
"permitissued under Section 402 of the Act.
NRDC - Natural Resources Defense Council.
NSPS - New source performance standards under Section 306 of the
Act.
OOC - Offshore Operators Committee.
PBSA - Petroleum Equipment Suppliers Association.
Packgr Fluid - Any fluid placed in the annulus between the
tubing and casing above a packer. Along with other func-
tions, the hydrostatic pressure of the packer fluid is uti-
lized to reduce the pressure differentials between the
formation and the inside of the casing and across the packer
itself.
Pressure Maintenance - The amount of water or gas injected vs.
the oil and gas production so that the reservoir pressure is
maintained at a desired level.
Priority Pollutants - The 65 pollutants and classes of pollutants
declared toxic under Section 307(a) of the Act. Appendix C
contains a listing of specific elements and compounds.
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Production Facility - Any platform or fixed structure addressed
by this document that is used for active recovery of hydro-
carbons from producing formations.
Produced Water - The water (brine) brought up from the hydrocar-
bon-bearing strata during the extraction of oil and gas, and
can include formation water, injection water, and any chemi-
cals added downhole or during the oil/water separation pro-
cess.
Produced Sand - Slurried particles used in hydraulic fracturing
and the accumulated formation sands and scale particles
generated during production.
RCRA - Resource Conservation and Recovery Act (Pub. L. 94-580)
of 1976. Amendments to Solid Waste Disposal Act.
Rank Wildcajt - An exploratory well drilled in an area far enough
removed from previously drilled wells to preclude extrapola-
tion of expected hole conditions.
Reservoir - Each separate, unconnected body of producing
formation.
Rotary Drilling - The method of drilling wells that depends on
the rotation of a column of drill pipe with a bit at the bot-
tom. A fluid is circulated to remove the cuttings.
Sanitary Waste - Human body waste discharged from toilets and
urinals located within facilities addressed by this document.
Separator - A vessel used to separate oil and gas by gravity.
Shaleshaker - Mechanical vibrating screen to separate drilled
formation cuttings carried to surface with drilling mud.
Shut In - To close valves on a well so that it stops producing;
said of a well on which the valves are closed.
Skimmer - A settling tank in which oil is permitted to rise to
the top of the water and is then taken off.
SPCC - A spill prevention control and countermeasure plan
required under Section 311(j) of the Act.
Spot - The introduction of oil to a drilling fluid system for
the purpose of freeing a stuck drill bit or string.
Stripper Well (Marginal Well) - A well which produces such small
volume of oil that the gross income therefrom provides only a
small margin of profit or, in many cases, does not even cover
actual cost of production.
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Stripping - Adding or removing pipe when well is pressured
without allowing vertical flow at top of well.
TDS - Total Disolved Solids.
Territorial Seas - The belt of the seas measured from the line
of ordinary low water along that portion of the coast which
is in direct contact with the open sea and the line marking
the seaward limit of inland waters, and extending seaward a
distance of three miles.
TOC - Total Organic Carbon.
Total Depth (T.D.) - The greatest depth reached by the drill bit.
Treater - Equipment used to break an oil - water emulsion.
TSS - Total Suspended Solids.
USCG - United States Coast Guard.
USGS - United States Geological Survey.
Water Flooding - Water is injected under pressure into the for-
mation via injection wells and the oil is displaced toward
the producing wells.
Wei1 Complet ion - In a potentially productive formation, the
completion of a well in a manner to permit production of oil;
the walls of the hole above the producing layer (and within
it if necessary) must be supported against collapse and the
entry into the well of fluids from formations other than the
producing layer must be prevented. A string of casing is
always run and cemented, at least to the top of the producing
layer, for this purpose. Some geological formations require
the use of additional techniques to "complete" a well such as
casing the producing formation and using a "gun perforator"
to make entry holes, the .use of slotted pipes, consolidating
sand layers with chemical treatment, and the use of surface-
actuated underwater robots for offshore wells.
Well Head - Equipment used at the top of a well, including casing
head, tubing head, hangers, and Christmas Tree.
We 11 Treatment F1uids - Those fluids used in stimulating a hydro-
carbon-bearing formation or in completing a well for oil and
gas production, and drilling fluids used in reworking a well
to increase or restore productivity.
Wildcat Well - A well drilled to test formations nonproductive
within a 1-mile rardius of previously drilled wells. It is
expected that probable hole conditions can be extrapolated
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from previous drilling experience data from that general
area.
WOGA - Western Oil and Gas Association.
Workover - To clean out or otherwise work on a well in order to
increase or restore production.
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APPENDIX A - STATIC SHEEN TEST (ANALYTICAL PROTOCOL)
1. Scope and Application
This method is to be used as a compliance test for the "no
discharge of free oil" requirement for discharges of drilling
fluids, drill cuttings, deck drainage and produced sand. Free
oil refers to any oil contained in a waste stream that when
discharged will cause a film or sheen upon or a discoloration of
the surface of the receiving water.
2. Summary of Method
Samples of drilling fluid and deck drainage (0.15 mL and 15 mL)
and samples of drill cuttings and produced sand (1.5 g and 15 g,
wet weight basis) are introduced into ambient seawater in a con-
tainer having an air to liquid interface area of 1000 cra2.
Samples are dispersed within the container and observations made
no more than 1 hour later to ascertain if these materials cause a
sheen, irridescence, gloss, or increased reflectance on the sur-
face of the test seawater. The occurrence of any of .these visual
observations will constitute a demonstration that the tested
material contains "free oil", and therefore, results in a prohi-
bition on its discharge into receiving waters.
3. Interferences
Residual "free oil" adhering to sampling containers, the magnetic
stirring bar used to mix drilling fluids, and the stainless steel
spatula used to mix drill cuttings will be the principal sources
of contamination if improperly washed and cleaned equipment are
used for the tes.t. The use of disposable equipment minimizes the
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potential for similar contamination from pipets and the test con-
tainer.
4. Apparatus materials and Reagents
4.1 Apparatus
4.1.1 Sampling containers - 1 liter polyethylene beakers
4.1.2 Graduated cylinder - 100 mL graduated cylinder required
only for operations where predilution of mud discharges is
required.
4.1.3 Plastic disposable weighing boats
4.1.4 Triple beam scale
4.1.5 Disposable pipets - 1 mL and 25 mL disposable pipets
4.1.6 Magnetic stirrer and stirring bar
4.1.7 Stainless steel spatula
4.1.8 Test container - open plastic container whose internal
cross-section parallel to its opening has an area of 1000 _+
50 cm2, and a depth of no more than 30 cm.
4 .2 Materials and Reagents
4.2.1 Plastic liners for the test container - Oil free, heavy
duty plastic trash can liners that do not inhibit the spreading
of an oil film. Liners must be of a sufficient size to comple-
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tely cover the interior surface of the test container.
Permittees must determine an appropriate local source of liners
that do not inhibit the spreading of 0.05 mL diesel fuel added to
the lined test container under the test conditions and protocol
described below.
4.2.2 Ambient receiving water
5. Calibration
None currently specified
6. Quality Control Procedures
None currently specified
7. Sample Collection and Handling
7.1 Sampling containers must be thoroughly washed with
detergent, rinsed a minimum of 3 times with fresh water, and
allowed to air dry before samples are collected.
7.2 Samples of drilling fluid must be obtained once per day from
the active mud pit; the sample volume should range between 200 mL
and 500 mL.
7.3 Samples of drill cuttings and produced sand must be obtained
from each type of solids control equipment from which' discharges
occur on any given day prior to addition of any washdown water;
samples should range between 200 and 500 grams.
7.4 Samples of deck drainage must be obtained from the deck
drainage holding facility prior to discharge; the sample volume
should range between 200 mL and 500 mL.
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7.5 Samples must be tested no later than 1 hour after collec-
tion.
7.6 Drilling fluid samples must be mixed in their sampling con-
tainers for 5 minutes prior to testing using a magnetic bar
stirrer. If predilution is imposed as a permit condition, the
sample must be mixed at the same ratio with the same prediluting
water as the discharged muds and stirred for 5 minutes.
7.7 Drill cuttings must be stirred and well mixed by hand in
their sampling containers prior to testing, using a stainless
steel spatula.
8. Procedure
8.1 Ambient receiving water must be used as the "receiving
water" in the test. The test container must have an air to
liquid interface area of 1000 _+ 50 cm2. The surface of the water
should be no more than 5 cm below the top of the test container.
8.2 Plastic liners shall be used, one per container per test,
and discarded afterwards. Some liners may inhibit spreading of
added oil; operators shall determine an appropriate local source
of liners that do not inhibit the spreading of the oil film.
8.3 Drilling fluid materials and deck drainage must be intro-
duced into the test container 1 cm below the water surface, by
pipet, at 0.15 mL and 15 mL. Pipets must be filled and
discharged with test material prior to the transfer of test
material and its introduction into test containers. The test
water-test material mixture must be stirred using the pipet to
distribute the test material homogenously throughout the test
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water. The pipet must be used only once for a test and then
discarded.
8.4 Drill cuttings and produced sand should be weighed on
plastic•weighing boats; 1.5 gram and 15 gram samples must be
transferred by scraping test material into the test water with a
stainless steel spatula. The weighing boat must be immersed in
the test water and scraped with the spatula to transfer any resi-
dual material to the test container. The test material must be
stirred with the spatula to an even distribution of solids on the
bottom of the test container.
3.5 Observations must be made no later than 1 hour after the
test material is transferred to the test container. Viewing
points above- the test container should be made from at least
three sides of the test container, at viewing angles of approxi-
mately 60 deg and 30 deg from the horizontal. Illumination of
the test container must be representative of adequate lighting
for a working environment to conduct routine laboratory proce-
dures.
8.6 Any detection of a "silvery" or "metallic" sheen, gloss, or
increased reflectivity; visual color; or irridescence on the
water surface shall constitute a demonstration of "free oil" for
the sample. These visual observations include patches, sheets,
or streaks of such altered surface characteristics.
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APPENDIX B - ANALYSIS OF DIESEL OIL IN DRILLING FLUIDS AND DRILL
CUTTINGS (ANALYTICAL PROTOCOL)
1. Scope and Application
This method is to be used as a compliance test for detecting the
presence of diesel oil in drilling fluids and drill cuttings
waste streams. The method involves the separation of diesel oil
from drilling fluid or drill cuttings samples and subsequent
qualitative and quantitative analysis by capillary column gas
chromatography. The method makes no attempt to chemically
identify the individual diesel components but uses a pattern
recognition technique for data analysis.
2. Summary of Method
A weighed amount of drilling fluid or.drill cuttings is placed in
a retort apparatus and distilled according to the retort
manufacturer's instructions. The distillate is extracted with
methylene chloride, an internal standard is added, and a GC
analysis is conducted. Using low attenuation for high
sensitivity, a detection of 1 mg/kg of diesel oil in the sample
is possible with this method.
The analyst is cautioned that there is no standard diesel oil.
The components, as seen by gas chromotography, will differ
depending upon the crude source, the date of the diesel oil pro-
duction and the producer. In addition, there are three basic
types of diesel oils: ASTM Designations No. 1-D, No. 2-D, and No.
4-D. The No. 2-D is most commonly referred to in terms of
"diesel oil." However, No. 2-D is sometimes blended with No.
1-D which has a lower boiling range. Thus it is highly desirable
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that the sample chromatograms be matched with a reference stan-
dard made from the same diesel oil source suspected to be in the
sample.
3. Apparatus, Reagents and Materials
3.1 Apparatus
3.1.1 Gas Chromatograph (GC) - A temperature programmable GC
equipped with a flame ionization detector.
3.1.2 Integrator - A recording integrator capable of resolving
and integrating capillary peaks.
3.1.3 Chromatographic Column - A borosilicate glass capillary
column (WCOT), 30 meter x 0.25 mm ID, coated with Supelco SPB -
1 (Bonded SE-30 methyl silicone) with 1.0 um thickness (Supelco
Catalog No. 2-4029). Other columns may be substituted if they
can demonstrate similar and satisfactory results.
3.1.4 Distillation Apparatus - A 20 mL retort apparatus (IMCO
Services Model No. R2100 or equivalent).
3.1.5 Kuderna - Danish Concentrator - A 500 mL flask, 3 - ball
Snyder column and a 10 mL (or 15 mL) receiving ampule graduated
in 0.1 ml units at the bottom.
3.1.6 Separatory Funnel - A 60 mL separatory funnel with a Teflon
stopcock and glass stopper.
3.1.7 Glass Filtering Funnel - A glass filtering crucible holder
(Corning No. 9480 or equivalent).
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3.2 Materials and Reagents
3.2.1 Glass Wool - Corning No. 3950 or equivalent.
3.2.2 Anhydrous Sodium Sulfate - Analytical grade.
3.2.3 Methylene Chloride - Nanograde or equivalent.
3.2.4 Trichlorobenzene (TCB) Internal Standard - Dissolve 1.0 gm
of 1/3,5 Trichlorobenzene (Kodak No. 1801 or equivalent) in 100
mL of Methylene Chloride. Store in glass and tightly cap with
Teflon lid liner to prevent solvent evaporation loss.
4. Procedure
4.1 Sample Preparation
4.1.1 Preweigh or tare the retort sample cup and cap to at least
the nearest 0.1 gm. Transfer a well homogenized and represen-
tative portion of the material to be tested into the sample cup,
filling it to the top. Place the cap on the cup, wipe off the
excess material and reweigh. Record the weight of the sample to
at least the nearest 0.1 gm.
4.1.2 Following the retort manufacturer's instructions, distill
the sample into the unit's glass receiving cylinder. The pre-
sence of solids in the distillate will require that the distilla-
tion be rerun starting with a new portion of sample. Placing
more steel wool in the retort expansion chamber, per
manufacturer's instructions, will help prevent the solids from
going over in the distillation.
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4.1.3 Pour the retort distillate into a 60 mL separatory funnel.
Rinse the distillate container with two full portions of methy-
lene chloride into the separatory funnel. Stopper and shake for
1 minute and allow the layers to separate.
4.1.4 Prepare a glass filtering funnel by plugging the bottom
with a piece of glass wool and pouring in 1 to 2 inches of
anhydrous sodium sulfate. Wet the funnel with a small portion of
methylene chloride and allow it to drain to a waste container.
4.1.5 Place the glass filtering funnel into the top of a Kuderna
- Danish (K-D) flask equipped with a 10 mL receiving ampule.
Drain the methylene chloride (lower) layer into the K-D flask
passing it through the glass filtering funnel.
4.1.6 Repeat the methylene chloride extraction twice more,
rinsing the retort unit's glass receiving cylinder with two
thorough washings each time and draining each methylene chloride
extraction into the K-D flask.
4.1.7 Place a Snyder column on the K-D flask and evaporate on a
steam bath. Concentrate the sample to a 1.0 mL final volume or
until the contents will not concentrate any further and note the
final volume. The receiving ampule graduations should be labora-
tory calibrated for accuracy.
4.2 Gas Chromatography
4.2.1 Using a micropipet, transfer equal portions of the sample
from the K-D ampule and the TCB internal standard (a 100 ul por-
tion of each is suggested) into a GC injection vial or other
suitable container. Mix thoroughly.
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4.2.2 Set up the gas chromatograph conditions as follows:
(a) GC - Injector Port and manifold temperature = 275 C
(b) Column - A SPB-1, 30 meter column with a nitrogen
carrier at approximately 2 ml/min, a split ratio of
100:1 and nitrogen make-up (if needed) at 60 mL/min.
(c) Temperature Program - 90 C initial temperature with no
hold, 5 C per minute to a final temperature of 250 C;
final hold for at least 10 minutes.
(d) Detector - FID with 30 mL/min hydrogen and 240 cc/min
air is recommended. Set the amplifier range at
10~11 amps full scale (X10 on most instruments)
(e) Recording Integrator - Set the chart speed at a minimum
of 1 mL/min. Adjust the attenuation during the run as
to exclude minor peaks.
4.2.3 Inject 1 uL of the sample containing the internal stan-
dard. The TCB will elute at approximately 8.5 minutes into the
run and should be approximately 50 percent at full scale at 8 x
10-11.
4.2.4 Prepare a reference standard using, if possible, the same
diesel oil suspected to be in the sample. Using Table 1 as a
guide, weigh out the appropriate amount of oil into a tared 10 mL
volumetric flask and dilute to volume with methylene chloride.
Mix equal portions of the reference oil standard and the TCB as
outlined in 4.2.1 and analyze using the same GC conditions used
for the analysis of the sample.
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TABLE 1
Percent Ranges of Diesel and Standards
Expected % Wt of Diesel
Diesel oil oil in 10 mL
in Sample Volumetric* (g)
5 use undiluted oil
3 7.6
1 3.0
,5 1.5
* Weigh oil to the nearest O.OOIg
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5. Interpretation of Data
5.1 Compare the sample chromatogram to the chromotogram of the
standard. If the sample contains diesel oil, the major peaks
present in the standard (e.g. those greater than 1 percent of the
total integrated area) should also be present in the sample and
in the same relative intensity and pattern (See Figure 1).
5.2 Some mineral oil lubricity additives have similar chroma-
tographic patterns to that of diesel oil. The presence of early,
smaller peaks from 1 minute (following the solvent peak) to
approximately 4 minutes will differentiate between distillates
containing only mineral oil and those with diesel oil (See Figure
2).
5.3 The use of the TCB internal standard makes it possible to
correlate peaks from sample to standard on the basis of Relative
Retention Time (RTT). Approximate RRT's are presented in Table
2.
6. Calculation of Results
6.1 Choose those peaks that are applicable as outlined in
Section 5; a minimum of 10 peaks should be used. Sum the
integrated areas of the chosen peaks in the sample and divide by
the integrated area of the Internal Standard in the sample:
lAps = RF
Ais
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_ O
^
00*
O UI
m i
UJ
o 2
^ =3
cr
- o
UJ
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o:
a.
=± 00
UJ
CL
Ld
-
UJ CM
o:
1=3
o
U.
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cr
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o
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cn
o
cc
o
LJ
00
-376-
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00
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ID
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01
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TABLE 2
Approximate Relative Retention Times for TCB Internal Standard
and No. 2-D Diesel Oil.
1,3,5 Trichlorobenzene Internal Standard » 100
Expected RRT's for Predominate Peaks in No 2-D Diesel Oil:
124 207 276
155 216 299
179 220 324
183 231 348
186 245 370
188 260
193 273
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where:
EAps = Summation of peak areas of interest in sample
SAis * Area of internal standard peak in sample
RFs * Response factor for sample
6.2 Repeat the above process (6.1) for the chosen peaks in the
standard:
jiAp_r = RFr
Air
where:
2Apr * Summation of peak areas of interest in reference standard
Air = Area of internal standard peak in the reference standard
RFr = Response factor for reference standard
6.3 Calculate the mg/kg of diesel oil in the sample as follows:
mg/kg Diesel Oil = RFs x Vs x Cr x 1000
RFr x Gs
where:
RFs = Response factor for sample
RFr = Response factor for reference standard
Vs = Final volume of sample from K-D in mL
Cr = Concentration of reference standard in mg/mL
Gs = Starting weight of sample in grams on a wet weight or whole
mud basis.
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Note: This equation does not take into account attenuation
changes if they affect the calculated peak areas as reported by
the integrator.
7. Quality Control
7.1 Each laboratory that uses this method is required to operate
a formal quality control program. The minimum requirements of
this program consist of an initial demonstration of laboratory
capability, the analysis of a retorted diesel oil standard as a
continuing check on recovery, and duplicate samples for a preci-
sion check on performance. The laboratory is required to maintain
performance records to define the quality of data that are
generated. Ongoing performance checks must be compared with
established performance criteria to determine if the results of
analyses are within accuracy and precision limits expected of the
method.
7.2 In order to demonstrate recovery , a diesel oil standard
must be subjected to the entire analytical procedure starting
with Section 4.1. Pipette 1.00 ml of the reference diesel oil
into the preweighed or tared retort sample cup and weigh to the
nearest 0.001 gram. Place a small plug of steel wool into the
cup, cap and proceed with the retort distillation. Calculate the
percent recovery of the retorted reference standard to that of a
reference standard prepared as specified in Section 4.2.4. The
percent recovery of the retorted reference standard must fall
within 80 to 120 percent recovery. This should be performed on
each retort unit utilized before attempting any sample analyses.
Reference standards should be subjected to the entire analytical
procedure starting with Section 4.1 at least once for each batch
of samples processed or for every ten samples analyzed.
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7.3 The laboratory must analyze duplicate samples for each
sample type at a minimum of 20 percent. A duplicate sample shall
consist of a well-mixed, representative aliquot of the sample and
should be subjected to the entire analytical procedure starting
with Section 4.1. The relative percent differences (RPD) for
duplicates are calculated as follows:
RPD - (D1 - D2) x 100
(D1 + D2)/2
where:
RPD = relative percent difference
D1 = percent of diesel oil in the first sample
D2 = percent diesel oil in the second sample
(duplicate)
A control limit of +_ 20 percent for RPD shall be used.
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APPENDIX C - DRILLING FLUIDS TOXICITY TEST
I. SAMPLE COLLECTION
The collection and preservation methods for drilling fluids
(muds) and water samples presented here are designed to minimize
sample contamination and alteration of the physical or chemical
properties of the samples due to freezing, air oxidation, or
drying.
1-A. Apparatus
(1) The following items are required for water and drilling mud
sampling and storage:
a. Acid-rinsed linear-polyethylene bottles or other appropriate
noncontaminating drilling mud sampler.
b. Acid-rinsed linear-polyethylene bottles or other appropriate
noncontaminating water sampler.
c. Acid-rinsed linear-polyethylene bottles or other appropriate
noncontaminated vessels for water and mud samples.
d. Ice chests for preservation and shipping of mud and water
samples.
1-B. Water Sampling
(1) Collection of water samples shall be made with appropriate
acid-rinsed linear-polyethylene bottles or other appropriate non-
contaminating water sampling devices. Special care shall be taken
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to avoid the introduction of contaminants from the sampling devi-
ces and containers. Prior to use, the sampling devices and con-
tainers should be thoroughly cleaned with a detergent solution,
rinsed with tap water, soaked in 10 percent hydrochloric acid
(HC1) for 4 hours, and then thoroughly rinsed with glass-
distilled water.
1-C. Drilling Mud Sampling
(1) Drilling mud formulations to be tested shall be collected
from active field systems. Obtain a well-mixed sample from
beneath the shale shaker after the mud has passed through the
screens. Samples shall be stored in polyethylene containers or
in other appropriate uncontaminated vessels. Prior to sealing
the sample containers on the platform, flush as much air out of
the container by filling it with drilling fluid sample, leaving a
one inch space at the top.
(2) Mud samples shall be immediately shipped to the testing
facility on blue or wet ice (do not use dry ice) and. continuously
maintained at 0-4°C until the time of testing.
(3) Bulk mud samples shall be thoroughly mixed in the laboratory
using a 1000 rpm high shear mixer and then subdivided into indi-
vidual, small wide-mouthed (e.g., one or two liter) non-
contaminating containers for storage.
(4) The drilling muds stored in the laboratory shall have any
excess air removed by flushing the storage containers with nitro-
gen under pressure anytime the containers are opened. Moreover,
the sample in any container opened for testing must be thoroughly
stirred using a 1000 rpm high shear mixer prior to use.
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(5) Most drilling mud samples may be stored for periods of time
longer than 2 weeks prior to toxicity testing provided that
proper containers are used and proper conditions are maintained.
II. SUSPENDED PARTICULATE PHASE SAMPLE PREPARATION
(1) Mud samples that have been stored under specified conditions
in this protocol shall be prepared for tests within three months
after collection. The SPP shall be prepared as detailed below.
2-A. Apparatus
(1) The following items are required:
a. Magnetic stir plates and bars.
b. Several graduated cylinders, ranging in volume from 10 mL to
16
c. Large (15 cm) powder funnels.
d. Several 2-liter graduated cylinders.
e. Several 2-liter large mouth graduated Erlenmeyer. flasks.
(2) Prior to use, all glassware shall be thoroughly cleaned.
Wash all glassware with detergent, rinse five times with tap
water, rinse once with acetone, rinse several times with
distilled or deionized water, place in a clean 10-percent (or
stronger) HC1 acid bath for a minimum of 4 hours, rinse five
times with tap water, and then rinse five times with distilled or
deionized water. For test samples containing mineral oil or
diesel oil, glassware should be washed with petroleum ether to
assure removal of all residual oil. NOTE: If the glassware with
nytex cups soaks in the acid solution longer than 24 hours, then
an equally long deionized water soak should be performed.
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2~B* Test Seawater Sample Preparation
(1) Diluent seawater and exposure seawater samples are prepared
by filtration through a 1.0 micrometer filter prior to analysis.
(2) Artificial seawater may be used as long as the seawater has
been prepared by standard methods or PSTM methods, has been pro-
perly "seasoned," filtered, and has been dil.uted with distilled
water to the same specified 20 +_ 2 ppt salinity and 20 +_ 2°C tem-
perature as the "natural" seawater.
2-C. Sample Preparation
(1) The pH of the mud shall be tested prior to its use. If the
pH is less than 9, if black spots have appeared on the walls of
the sample container, or if the mud sample has a foul odor, that
sample shall be discarded. Subsample a manageable aliquot of mud
from the well-mixed original sample. Mix the mud and filtered
test seawater in a volumetric mud-to-water ratio of 1 to 9. This
is best done by the method of volumetric displacement in a
2-L, large mouth, graduated Erlenmeyer flask. Place 1000 ml of
dilute seawater into the graduated Erlenmeyer flask. The mud
subsample is then carefully added via a powder funnel to obtain a
total volume of 1200 ml. (A 200 mL volume of mud will now be in
the flask).
The 2-L, large mouth, graduated Erlenmeyer flask is then filled
to the 2000 mL mark with 800 mL of seawater, which produces a
slurry with a final ratio of one volume drilling mud to nine
volumes water. If the volume of SPP required for testing or ana-
lysis exceeds 1500 to 1600 mL, the initial volumes should be pro-
portionately increased. Alternatively, several 2-L drill
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mud/water slurries may be prepared as outlined above and combined
to provide sufficient SPP.
(2) Mix this mud/water slurry with magnetic stirrers for 5 minu-
tes. Measure the pH and, if necessary, adjust (decrease) the pH
of the slurry to within 0.2 units of the seawater by adding 6N
HC1 while stirring the slurry. Then, allow the slurry to settle
for 1 hour. Record the amount of HC1 added.
(3) At the end of the settling period, carefully decant (do not
siphon) the Suspended Particulate Phase (SPP) into an appropriate
container. Decanting the SPP is one continuous action. In some
cases no clear interface will be present; that is, there will be
no solid phase that has settled to the bottom. For those samples
the entire SPP solution should be used when preparing test con-
centrations. However, in those cases when no clear interface is
present, the sample must be remixed for five minutes. This
insures the homogeneity of the mixture prior to the preparation
of the test concentrations. In other cases, there will be
samples with two or more phases, including a solid phase. For
those samples, carefully and continuously decant the supernatant
until the solid phase on the bottom of the flask is reached. The
decanted solution is defined to be 100 percent SPP. Any other
concentration of SPP refers to a percentage of SPP that is
obtained by volumetrically mixing 100 percent SPP with seawater.
(4) SPP samples to be used in toxicity tests shall be mixed for
5 minutes and must not be preserved or stored.
(5) Measure the filterable and unfilterable residue of each SPP
prepared for testing. Measure the dissolved oxygen (DO) and pH
of the SPP. If the DO is less than 4.9 ppm, aerate the SPP to at
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least 4.9 ppm which is 65 percent of saturation. Maximum
allowable aeration time is 5 minutes using a generic commercial
air pump and air stone. Neutralize the pH of the SPP to a pH 7.8
£.1 using a dilute HC1 solution. If too much acid is added to
lower the pH saturated NaOH may be used to raise the pH to 7.8
^. 1 units. Record the amount of acid or NaOH needed to lower/
raise to the appropriate pH. Three repeated DO and pH measure-
ments are needed to insure homogeneity and stability of the SPP.
Preparation of test concentrations may begin after this step is
complete.
(6) Add the appropriate volume of 100 percent SPP to the
appropriate volume of seawater to obtain the desired SPP con-
centration. The control is seawater only. Mix all con-
centrations and the control for 5 minutes by using magnetic
stirrers. Record the time; and, measure DO and pH for Day 0.
Then, the animals shall be randomly selected and placed in the
dishes in order to begin the 96-hour toxicity test.
III. GUIDANCE FOR PERFORMING SUSPENDED PARTICULATE PHASE
TOXICITY TESTS USING Mysidopsis bahia.
3-A. Apparatus
(1) Items listed by Borthwick [267] are required for each test
series, which consists of one set of control and test containers,
with three replicates of each.
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3-B. Sample Collection Preservation
(1) Drilling muds and water samples are collected and stored,
and the suspended particulate phase prepared as described in
Section 1-C.
3-C. Species Selection
(1) The Suspended Particulate Phase (SPP) tests on drilling muds
shall utilize the test species Mysidopsis bahia. Test animals
shall be 3 to 6 days old on the first day of exposure. Whatever
the source of the animals, collection and handling should be as
gentle as possible. Transportation to the laboratory should be
in well-aerated water from the animal culture site at the tem-
perature and salinity from which they were cultured. Methods for
handling, acclimating, and sizing bioassay organisms given by
Borthwick [267] and Nimmo [268] shall be followed in matters for
which no guidance is given here.
3.D. Experimental Conditions
(1) Suspended particulate phase (SPP) tests should be conducted
at a salinity of 20 +_ 2 ppt. Experimental temperature should be
20 j^ 29C. Dissolved oxygen in the SPP shall be raised to or
maintained above 65 percent of saturation prior to preparation of
the test concentrations. Under these conditions of temperature
and salinity, 65 percent saturation is a DO of 5.3ppm. Beginning
at Day 0- before the animals are placed in the text containers
DO, temperature, salinity, and pH shall be measured every 24
hours. DO should be reported in milligrams per liter.
(2) Aeration of test media is required during the entire test
with a rate estimated to be 50-140 cubic centimeters/minute.
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This air flow to each test dish may be achieved through polyethy-
lene tubing (0.045-inch inner diameter and 0.062-inch outer
diameter) by a small generic aquarium pump. The delivery method,
surface area of the aeration stone, and flow characteristics
shall be documented. All treatments, including control, shall be
the same.
(3) -Light intensity shall be 1200 microwatts/cm2 using cool
white fluorescent bulbs with a 14-hr light and 10-hr dark cycle.
This light/dark cycle shall also be maintained during the accli-
mation period and the test.
3-E. Experimental Procedure
(1) Wash all glassware with detergent, rinse five times with tap
water, rinse once with acetone, rinse several times with
distilled or deionized water, place in a clean 10 percent HC1
acid bath for a minimum of 4 hours, rinse five times with tap
water, and then rinse five times with distilled water.
(2) Establish the definitive test concentration based on results
of a range finding test. A minimum of five test concentrations
plus a negative and positive (reference toxicant) control is
required for the definitive test. To estimate the LC-50, two con-
centrations shall be chosen that give (other than zero and 100
percent) mortality above and below 50 percent.
(3). Twenty organisms are exposed in each test dish. Nytex* cups
shall be inserted into every test dish prior to adding the ani-
mals. These "nylon mesh screen" nytex holding cups are fabri-
cated by gluing a collar of 363-micrometer mesh nylon screen to a
15-centimerer wide Petri dish with silicone sealant. The nylon
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screen collar is approximately 5 centimerers high. The animals
are then placed into the test concentration within the confines
of the Nytex® cups.
(4) Individual organisms shall be randomly assigned to treat-
ments. A randomization procedure is presented in Section V of
this protocol. Make every attempt to expose animals of approxi-
mately equal size. The technique described by Borthwick [267] ,
or other suitable substitutes, should be used for transferring
specimens. Throughout the test period, mysids shall be fed daily
with approximately 50 Artemia (brine shrimp) nauplii per mysid.
This will reduce stress and decrease cannibalism.
(5) Cover the dishes, aerate, and incubate the test containers
in an appropriate test chamber. Positioning of the test con-
tainers holding various concentrations of test solution should be
randomized if incubator arrangement indicates potential position
difference. The test medium is not replaced during the 96-hour
test.
(6) OBservations may be attempted at 4, 6 and 8 hours; they must
be attempted at 0, 24, 48, and 72 hours and must be made at 96
hours. Attempts at observations refers to placing a test dish on
a light table and visually count the animals. Do not lift the
•"nylon mesh screen" cup out of the test dish to make the obser-
vation. No unnecessary handling of the animals should occur
during the 96 hour test period. DO and pH measurements must also
be made at 0, 24, 48, 72, and 96 hours. Take and replace the
test medium necessary for the DO and pH measurements outside of
the nytex cups to minimize stresses on the animals.
(7) At the end of 96 hours, all live animals must be counted.
Death is the end point, so the number of living organisms is
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recorded. Death is determined by lack of spontaneous movement.
All crustaceans molt at regular intervals, shedding a complete
exoskeleton. Care should be taken not to count an exoskeleton.
Dead animals might decompose or be eaten between observations.
Therefore, always count living, not dead animals. If daily
observations are made, remove dead organisms and molted exoskele-
tons with a pipette or forceps. Care must be taken not to
disturb living organisms and to minimize the amount of liquid
withdrawn.
IV. METHODS FOR POSITIVE CONTROL TESTS (REFERENCE TOXICANT)
(1) Sodium lauryl sulfate (dodecyl sodium sulfate) is used as a
reference toxicant for the positive control. The chemical used
should be approximately 95 percent pure. The source, lot number,
and percent purity shall be reported.
(2) Test methods are those used for the drilling fluid tests,
except that the test material was prepared by weighing one gram
sodium lauryl sulfate on an analytical balance, adding the chemi-
cal to a 100-milliliter volumetric flask, and bringing the flask
to volume with deionized water. After mixing this stock solu-
tion, the test mixtures are prepared by adding 0.1 milliliter of
the stock solution for each part per million desired to one liter
of seawater.
(3) The mixtures are stirred briefly, water quality is measured,
animals are added to holding cups, and the test begins.
Incubation and monitoring procedures are the same as those for
the drilling fluids.
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V. RANDOMIZATION PROCEDURE
(1) The purpose of this procedure is to assure that raysids are
impartially selected and randomly assigned to six test treatments
(five drilling fluid or reference toxicant concentrations and a
control) and impartially counted at the end of the 96-hour test.
Thus, each test setup, as specified in the randomization proce-
dure, consists of 3 replicates of 20 animals for each of the six
treatments, i.e., 360 animals per test. Figure 1 is a flow
diagram that depicts the procedure schematically and should be
reviewed to understand the over-all operation. The following
tasks shall be performed in the order listed.
(2) Mysids are cultured in the laboratory in appropriate units.
If mysids are purchased, go to Task 3.
(3) Remove mysids from culture tanks (6, 5, 4, and 3 days before
the test will begin, i.e. Tuesday, Wednesday, Thursday, and
Friday if the test will begin on Monday) and place them in
suitably large maintenance containers so that they can swim about
freely and be fed.
NOTE: Not every detail (the definition of suitably large con-
tainers, for example) is provided here. Training and experience
in aquatic animal culture and testing will be required to suc-
cessfully complete these tests.
(4) Remove mysids from maintenance containers and place-all ani-
mals in a single container. The intent is to have a homogeneous
test population of mysids of a known age (3-6 days old).
(5) For each toxicity test, assign two suitable containers
(500-milliliter (mL) beakers are recommended) for mysid
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Figure 1
Mysid Randomization Procedure
"ask
Culture Units
Main ten an ca
Container's)
Test Population
Con tain er(s)
Separation/
Enumeration
Containers
Counting
(rcpvat tasks i—7
for A1 it A2 eoniam«rs)
_ Distribution
O Containers
7 Test
/ Containers
Myaids Are Collected
3 To 6 Days Prior
To Testing
if Mysida
Are Purchased
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separation/enumeration. Label each container (A1, A2, B1, B2,
and C1, C2, for example, if two drilling fluid tests and a
reference toxicant test are to be set up on one day). The pur-
pose of this task is to allow the investigator to obtain a close
estimate of the number of animals available for testing and to
prevent unnecessary crowding of the mysids while they are being
counted and assigned to test containers. Transfer the mysids
from the large test population container to the labeled separa-
tion and enumeration containers but do not place more than 200
mysids in a 500-mL beaker. Be impartial in transferring the
mysids; place approximately equal numbers of animals (10-15
mysids is convenient) in each container in a cyclic manner rather
than placing the maximum number in each container at one time.
Note: It is important that the animals not be unduly stressed
during this selection and assignment procedure. Therefore, it
will probably be necessary to place all animals (except the batch
immediately being assigned to test containers) in mesh cups with
flowing seawater or in larger volume containers with aeration.
The idea is to provide the animals with near optimal conditions
to avoid additional stress.
(6) Place the mysids from the two labeled enumeration containers
assigned to a specific test into one or more suitable containers
to be used as counting dishes (21iter Carolina dishes are
suggested). Because of the time required to separate, count, and
assign mysids, two or more people may be involved in completing
this task. If this is done, two or more counting dishes may be
used, but the investigator must make sure that approximately
equal numbers of mysids from each labeled container are placed in
each counting dish.
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(7) By using a large-bore, smooth-tip glass pipette, select
mysids from the counting dish(es) and place them in the 36 indi-
vidually numbered distribution containers (10-ml beakers are
suggested). The mysids are assigned two at a time to the 36 con-
tainers by using a randomization schedule similar to the one pre-
sented below. At the end of selection/assignment round 1, each
container will contain two mysids; at the end of round 2, they
will contain four mysids; and so on until each contains ten
mysids.
Example of a Randomization Schedule
Selection/Assignment Round
(2 mysids each)
1
Place mysid in the numbered
distribution containers in
the random order shown
8, 21, 6, 28, 33, 32, 1, 3, 10,
9, 4, 14, 23, 2, 34, 22, 36, 27,
5, 30, 35, 24, 12, 25, 11, 17, 19,
26, 31 , 7, 20, 15, 18, .13, 16, 29
35, 18, 5, 12, 32, 34, 22, 3, 9, 16,
26, 13, 20, 28, 6, 21, 24, 30, 8,
31, 7, 23, 2, 15, 25, 17, 1, 11, 27,
4, 19, 36, 10, 33, 14, 29
7, 19, 14, 11, 34, 21, 25, 27, 17,
18, 6, 16, 29, 2, 32, 10, 4, 20, 3,
9, 1, 5, 28, 24, 31, 15, 22, 13, 33,
26, 36, 12, 8, 30, 35, 23
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30, 2, 18, 5, 8, 27, 10, 25, 4, 20,
26, 15, 31, 36, 35, 23, 11, 29, 16,
17, 28, 1, 33, 14, 9, 34, 7, 3, 12,
22, 21, 6, 19, 24, 32, 13
34, 28, 16, 17, 10, 12, 1, 36, 20,
18, 15, 22, 2, 4, 19, 23, 27, 29,
25, 21, 30, 3, 9, 33, 32, 6, 14, 11,
35, 24, 26, 7, 31, 5, 13, 8
(8) Transfer mysids from the 36 distribution containers to 18
labeled test containers in random order. A label is assigned to
each of the three replicates (A, B, C) of the six test con-
centrations. Count and record the 96 hour response in a impar-
tial order.
(9) Repeat tasks 5-7 for each toxicity test. A new random sche-
dule should be followed in Tasks 6 and 7 for each test.
NOTE: If a partial toxicity test is conducted, the procedures
described above are appropriate and should be used to prepare the
single test concentration and control, along with the reference
toxicant test.
5-B. Data Analysis and Interpretation
(1) Complete survival data in all test containers at each obser-
vation time shall be presented in tabular form. If greater than
10 percent mortality occurs in the controls, all data shall be
discarded and the experiment repeated. Unacceptably high control
mortality indicates the presence of important stresses on the
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organisms other than the material being tested/ such as injury or
disease, stressful physical or chemical conditions in the con-
tainers, or improper handling, acclimation, or feeding. If 10
percent mortality or less occurs in the controls, the data may be
evaluated and reported.
(2) A definitive, full bioassay conducted according to the EPA
protocol is used to estimate the concentration that is lethal to
50 percent of the test organisms that do not die naturally. This
toxicity measure is known as the median lethal concentration, or
LC-50. The LC-50 is adjusted for natural mortality or natural
responsiveness. The maximum likelihood estimation procedure with
the adjustments for natural responsiveness as given by D. J.
Finney, in Probit Analysis 3rd edition, 1971, Cambridge
University Press, Chapter 7, can be used to obtain the probit
model estimate of the LC 50 and the 95 percent fiducial
(confidence) limits for the LC-50. These estimates are obtained
using the logarithmic transform of the concentration. The
heterogeneity factor (Finney 1971, pages 70-72) is not used. For"
a test material to pass the toxicity test, according, to the
requirements stated in the offshore oil and gas extraction
industry BAT regulation, the lower 95 percent limit for the LC-50
adjusted for natural responsiveness must be greater than 3 per-
cent suspended particulate phase (SPP) concentration by volume
unadjusted for the 1 to 9 dilution. Other toxicity test models
may be used to obtain toxicity estimates provided the modeled
mathematical expression for the lethality rate must increase con-
tinuously with concentration. The lethality rate is modeled to
increase with concentration to reflect an assumed increase in
toxicity with concentration even though the observed lethality
may not increase uniformly because of unpredictable animal
response fluctuations.
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(3) The range finding test is used to establish a reasonable set
of test concentrations in order to run the definitive
test.However, if the lethality rate changes rapidly over a narrow
range of concentrations, the range finding assay may be too
coarse to establish an adequate set of test concentrations for a
definitive test.
(4) The EPA Environmental Research Laboratory in Gulf Breeze,
Florida prepared a Research and Development Report titled Acute
Toxicity of Eight Drilling Fluids to Mysid Shrimp (Mysidopsis
bahia), May 1984 EPA-600/3-84-067. The Gulf Breeze data for
drilling fluid number 1 are displayed in Table 1 for purposes of
an example of the probit analysis described above. The SAS
Probit Procedure (SAS Institute, Statistical Analysis System,
Gary, North Carolina, 1982) was used to analyze these data. The
96-hour LC50 adjusted for the estimated spontaneous mortality
rate is 3.3 percent SPP with 95 percent limits of 3.0 and 3.5
percent SPP with the 1 to 9 dilution. The estimated spontaneous
mortality rate based on all of the data is 9.6 percent.
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TABLE 1
LISTING OF ACUTE TOXICITY TEST DATA
(8/83-9/83) WITH EIGHT GENERIC DRILLING
FLUIDS AND MYSID SHRIMP
FLUID N2=1
Percent
Concentration
Number Number
Number Dead Alive
Exposed (96 Hours)(96 Hours)
0
1
2
3
4
5
60
60
60
60
60
60
3
1 1
11
25
48
60
57
49
49
35
12
0
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5-C. The Partial Toxicity Test for Evaluation of Test Material
(1) A partial test conducted according to EPA protocol can be
used economically to demonstrate that a test matrial passes the
toxicity test, the partial test cannot be used to estimate the
LC-50 adjusted for natural response.
(2) To conduct a partial test follow the test protocol for pre-
paration of the test material and organisms. Prepare the control
(zero concentration), one test concentration (3 percent suspended
particulate phase) and the reference toxicant according to the
methods of the full test. A range finding test is not used for
the partial test.
*
(3) Sixty test organisms are used for each test concentration.
Find the number of test organisms killed in the control (zero
percent SPP) concentration in the column labeled XO of Table 2.
If the number of organisms in the control (zero percent SPP)
exceeds the table values, then the test is unacceptable and must
be repeated. If the number of organisms killed in the 3 percent
test concentration is less than or equal to corresponding number
in the column labeled X1 then the test material passes the par-
tial toxicity test. Otherwise the test material fails the toxi-
city test.
(4) Data shall be reported as percent suspended particulate
phase.
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TABLE 2
xi
0 22
\ "
2 23
3 23
4 24
5 24
6 25
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6. References
267. Borthwick, Patrick W. 1978. Methods for acute static
toxicity tests with mysid shrimp (Mysidopsis bahia).
Bioassay Procedures for the Ocean Disposal Permit
Program, EPA-600/9 78-010: March.
268. Nimmo, D.R., T. L. Hamaker, and C. A. Somers. 1978.
Culturing the mysid (Mysidopsis bahia) in flowing sea
water or a static system. Bioassay Procedures for the
Ocean Disposal Permit Program, EPA-600/9-78-010: March.
269. American Public Health Association et al. 1980. Standard
Methods for the Examination of Water and Wastewater.
Washington, D.C. 15th Edition: 90-99.
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APPENDIX D - 126 PRIORITY POLLUTANTS
Acenaphthene
Acrolein
Acrylonitrile
Benzene
Benzidine
Carbon tetrachloride (tetrachloromethane)
Chlorobenzene
1,2,4-trichlorobenzene
Hexachlorobenzene
1,2-dichloroethane
1,1,1-trichloroethane
Hexachloroethane
1,1-dichloroethane
1,1,2-trichloroethane
1,1,2,2-tetrachloroethane
Chloroethane
Bis(2-chloroethyl) ether
2-chIoroethyl vinyl ether (mixed)
2-chloronaphthalene
2,4,6-trichlorophenol
Parachlorometa cresol
Chloroform (trichloromethane)
2-ehlorophenol
1 ,2-dichlorobenzene
1 ,3-dichlorobenzene
1,4-dichlorobenzene
3,3-dichlorobenzidine
1,1-dichloroethylene
1,2-trans-dichloroethylene
2,4-dichlorophenol
1,2-dichloropropane
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1,2-dichloropropylene (1,3-dichloropropene)
2,4-dimethylphenol
2,4-dinitrotoluene
2,6-dinitrotoluene
1 , 2-diphenylhydrazine
Ethylbenzene
Fluoranthene
4-chlorophenyl phenyl ether
4-bromophenyl phenyl ether
Bis(2-chloroisopropyl)ether
Bis(2-chloroethoxy) methane
Methylene chloride(dichloromethane)
Methyl chloride (dichlororaethane)
Methyl bromide (bromomethane)
Bromoform (tribromomethane)
Dichlorobromomethane
Chlorodibromomethane
Hexachlorobutadiene
Hexachlorocyclopentadiene
Isophorone
Naphthalene
Nitrobenzene
2-nitrophenol
4-nitrophenol
2,4-dinitrophenol
4,6-dinitro-o-cresol
N-nitrosodimethylamine
»
N-nitrosodiphenylamine
N-nitrosodi-n-propylamine
Pentachlorophenol
Phenol
Bis(2-ethylhexyl)phthalate
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Butyl benzyl phthalate
Di-N-Butyl Phthalate
Di-n-Octyl phthalate
Diethyl Phthalate
Dimethyl phthalate
1,2-benzanthracene (benzo(a)anthracene)
Benzo(a)pyrene (3,4-benzo-pyrene)
3,4-Benzofluoranthene(benzo(b)fluoranthene)
11,12-benzofluoranthene(benzo(b)fluoranthene)
Chrysene
Acenapthylene
Anthracene
1,12-benzoperylene(benzo(ghi)perylene)
Fluorene
Phenanthrene
1,2,5,6-dibenzanthracene(dibenzo(h)anthracene)
Indeno(1,2,3-cd)pyrene(2,3-o-phenylene pyrene)
Pyrene
Tetrachloroethylene
Toluene
Trichloroethylene
Vinyl chloride (chloroethylene)
Aldrin
Dieldrin
Chlordane (technical mixture and metabolites)
4,4-DDT
4,4-DDE(p,p-DDX)
4,4-DDD(p,p-TDE)
Alpha-endosulfan
Beta-endosulfan
Endosulfan sulfate
Endrin
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Endrin aldehyde
Heptachlor
Heptachlor epoxide(BHC-hexachlorocyclohexane)
Alpha-BHC
Beta-BHC
Gamma-BBC{1indane)
Delta-BHC(PCB-polychlorinated biphenyls)
PCB-1242(Arochlor 1242)
PCB-1254(Arochlor 1254)
PCB-1221(Arochlor 1221)
PCB-1232(Arochlor 1232)
PCB-1248(Arochlor 1248)
PCB-1260(Arochlor 1260)
PCB-1016(Arochlor 1016)
Toxaphene
Antimony
Arsenic
Asbestos
Beryllium
Cadmium
Chromium
Copper
Cyanide, Total
Lead
Mercury
Nickel
Selenium
Silver
Thallium
Zinc
2,3,7,8-tetrachloro-dibenzo-p-dioxin (TCDD)
"U.S. GOVERNMENT PRINTING OPFICEs 1985-461-217-.
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