EPA 440/1-75/055
GROUP II,
Development Document for
Interim Final Effluent Limitations Guidelines
and New Source Performance Standards
for the
OFFSHORE
Segment of the
OIL AND GAS EXTRACTION
Point Source Category
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
SEPTEMBER 1975
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DEVELOPMENT DOCUMENT
for
INTERIM FINAL EFFLUENT LIMITATIONS GUIDELINES
and
NEW SOURCES PERFORMANCE STANDARDS
for the
OFFSHORE SEGMENT OF THE
OIL AND GAS EXTRACTION
POINT SOURCE CATEGORY
Russell E. Train
Administrator
James L. Agee
Assistant Administrator for Water and Hazardous Materials
Allen Cywin
Director, Effluent Guidelines Division
Martin Halper
Project Officer
September, 1975
Effluent Guidelines Division
Office of Water and Hazardous Materials
U.S. Environmental Protection Agency
Washington, D. C. 20460
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IDFTD7
I'l'JILl'JZ
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ABSTRACT
This development document presents the findings of an
extensive study of the Offshore Segment of the Oil and Gas
Extraction Industry for the purposes of developing effluent
limitation guideines, standards of performance, and
pretreatment standards for the industry to implement
Sections 301, 304, 306, and 307 of the Federal Water
Pollution Control Act Amendments of 1972, (PL 92-500).
Guidelines and standards were developed for the Offshore
Segment of the Oil and Gas Extraction Industry, which was
divided into 2 subcategories.
Effluent limitation guidelines contained herein set forth
the degree of reduction of pollutants in effluents that is
attainable through the application of best practicable
control technology (BPCT), and the degree of reduction
attainable through the application of best available
technology (BAT) by existing point sources for July 1, 1977,
and July 1, 1983, respectively. Standards of performance
for new sources are based on the application of best
available demonstrated technology (BADT).
Supporting data and rationale for the development of
proposed effluent limitation guidelines and standards of
/ performance are contained in this development document.
111
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TABLE OF CONTENTS
Section Page No.
ABSTRACT iii
TABLE OF CONTENTS V
LIST OF TABLES x
LIST OF FIGURES xii
I CONCLUSIONS 1
II RECOMMENDATIONS 3
III INTRODUCTION 7
Purpose and Authority 7
General Description of Industry 8
Exploration 8
Drilling System 9
Production System 14
Evolution of Facilities 20
Field Service 22
Industry Distribution 24
Gulf of Mexico 24
California 25
Cook Inlet, Alaska 25
Industry Growth 26
Bibliography 29
IV INDUSTRY SUBCATEGORIZATION 31
Rationale of Subcategorization 31
Development of Subcategories 32
Facilitiy's Size, Age, and Waste 32
v
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Volumes
Process Technology 33
Climate 33
Waste Water Characteristics 34
Location of Facility 35
Description of Subcategories 35
Subcategory A - Near-Offshore 35
Subcategory B - Far-Offshore 35
Produced Water 37
Deck Drainage 37
Sanitary Waste 37
Domestic Waste 37
Drilling Muds 37
Drill Cuttings 33
Treatment of Wells 38
Produced Sand 33
Bibliography 39
V WASTE CHARACTERISTICS 41
Waste Constituents 41
Production 41
Drilling 47
Sanitary and Domestic Wastes 50
Bibliography 51
VI SELECTION OF POLLUTANT PARAMETERS 53
Parameters for Effluent Limitations 53
VI
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Freon Extractables - Oil and Grease 53
Fecal Coliform - Chlorine Residual 54
Floating Solids 54
Other Pollutants 55
Heavy Metals 55
TDS 56
Chlorides 56
Oxygen Demand Parameters 57
Biochemical Oxygen Demand 58
Total Organic Carbon 58
Phenolic Compounds 59
Bibliography 62
VII CONTROL AND TREATMENT TECHNOLOGY 63
In-plant Control/Treatment Techniques 63
Reduction or Elimination of Waste Waters 63
Waste Character Change 63
Process Technology 63
Pretreatment 65
Operation and Maintenance 65
Analytical Techniques and Field 66
Verification Studies
Variance in Analytical Results for 67
Oil and Grease Concentrations
Field Verification Studies 70
Gas Flotation 74
Parallel Plate Coalescers 77
VI1
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Filter Systems (loose or Fibrous 73
Media Coalescers)
Gravity Separation 79
Chemical Treatitent 79
Effectiveness of Treatment 81
Systems
Zero Discharge Technologies 81
Evaporation 82
Subsurface Disposal 82
Disposal Zone 89
Treatment System By Pass 91
End-of-Pipe Technology for Wastes Other 92
than Produced Water
Deck Drainage 92
Sand Removal 92
Drilling Muds and Drill Cuttings 93
(Offshore)
Drilling Muds and Drill Cuttings 94
(Onshore)
Well Treatment 94
Sanitary (Offshore) 94
Domestic Wastes 97
Bibliography 98
VIII COST, ENERGY, AND NONWATER 101
QUALITY ASPECTS
Cost Analysis 101
Offshore Produced Water Disposal 101
Onshore Produced Water Disposal 105
Offshore Sanitary Waste 116
Vlll
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Energy Requirements for Operating
Flotation Systems
Nonwater-Quality Aspects
Bibliography
IX EFFLUENT LIMITATIONS FOR BEST 119
PRACTICABLE CONTROL TECHNOLOGY
Produced Water Technology
Procedure for Development of
BPCT Effluent Limitations
Domestic Wastes
Deck Drainage 128
By-Pass (Offshore Operations)
Drilling Muds
Drill Cuttings
Well Treatment
Bibliography T^-I
X EFFLUENT LIMITATION FOR BEST AVAILABLE -,33
TECHNOLOGY ECONOMICALLY ACHIEVABLE
Near Offshore Subcategory - Produced Water
Far Offshore Subcategory - Produced Water
and Deck Drainage
XI NEW SOURCE PERFORMANCE STANDARDS 137
XII ACKNOWLEDGEMENTS
XIII GLOSSARY AND ABBREVIATIONS 141
IX
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LIST OF TABLES
Table No. Title Page No,
1 Effluent Limitation - BPCTCA 4
2 Effluent Limitation - BATEA and 5
New Source
3 U.S. Supply and Demand of Petroleum 27
and Natural Gas
4 U.S. Offshore Oil Production 27
5 Pollutants in Produced Water, 43
Louisiana Coastal
6 Pollutants Contained in Produced Water, 45
Coastal California
7 Range of Constituents in Produced 45
Formation Water—Offshore Texas
8 Volume of Cuttings and Muds in 4g
Typical 10,000 Foot Drilling
Operation
9 Typical Raw Combined Sanitary and 49
Domestic Wastes from Offshore Facilities
10 Effluent Quality Requirements for 61
Ocean Waters of California
11 Effect of Acidification on Oil 53
and Grease Data
12 Oil and Grease Data, Texas Coastal 59
13 Oil and Grease Data, California 59
Coastal
14 Performance of Individual Units, 71
Louisiana Coastal
15 Texas Coastal Verification Data 72
16 Verification of Oil and Grease Data, 73
California Coastal
x
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17 Performance of Various Treatment 81
Systems, Louisiana Coastal
18 Design Requirements for 97
Offshore Sanitary Wastes
19 Average Effluents of Sanitary Treatment 97
Systems, Louisiana Coastal
20 Operating Cost Offshore 104
21 Formation Water Treatment Equipment 106
Costs, Offshore Installations, 200
Barrels Per Day Flow Rate
22 Formation Water Treatment Equipment Costs, 107
Offshore Installation, 1,000 Barrels
Per Day Flow Rate
23 Formation Water Treatment Equipment Costs, 108
Offshore Installation, 5,000 Barrels Per
Day Flow Rate
24 Formation Water Treatment Equipment Costs, 109
Offshore Installation, 10,000 Barrels
Per Day Flow Rate
25 Formation Water Treatment Equipment Costs, 110
Offshore Installation, 40,000 Barrels
Per Day Flow Rate
26 Estimated Costs for Onshore Disposal of m
Produced Formation Water by Shallow
Well Injection with Lined Pond For
Standby
27 Estimated Treatment Plant Costs for 112
Sanitary Wastes for Offshore Locations
Package Extended Aeration Process
28 Estimated Horsepower Requirements for the 113
Operation of Flotation Treatment Systems
29 Estimated Incremental Energy Requirements, 114
Flotation Systems
30 Energy Requirements for Flotation Systems 115
as Compared to Net Energy Production
Associated with the Produced Water Flows
XI
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LIST OF FIGURES
Figure No. Title Page NO.
1 Rotary Drilling Rig ^g
2 Shale Shaker and Blowout -Q
Preventer
3 Central Treatment Facility in ^5
Estuarine Area
4 Horizontal Gas Separator ^7
5 Vertical Heater-Treater ^3
6 Rotar-Disperser and Dissolved Gas 75
Flotation Processes for Treatment
of Waste Brine Water
7 Onshore Production Facility with g3
Discharge to Surface Waters
8 Typical Cross Section Unlined 34
Earthern Oil-Water Pit
9 Typical Completion of an Injection g?
Well and a Producing Well
10 99th Percentile of Monthly Average Oil
and Grease Concentration vs. Frequency
of Sampling Each Month
11 Comulative Plot Effluent Concentrations
of all Selected Flotation Units in the
Louisiana Gulf Coast Area
12 Cumulative Plat of Effluent Concentrations
of Ten Selected Flotation Units in the
Louisiana Gulf Coast Area
XI1
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SECTION I
CONCLUSIONS
This study covered the waste treatment technology for the
Offshore Segment Oil and Gas Extraction Point Source
Category. The Oil and Gas Extraction Point Source Category
covers the pollutants arising from the production of crude
petroleum and natural gas, drilling oil and gas wells, and
oil and gas field exploration services.
The offshore segment of this industry is being covered at
this time, with the onshore segment to be completed at a
later time.
The waste associated with the offshore segment result from
the discharge of produced water, deck drainage, drilling
muds, drill cuttings, sanitary and domestic wastes, and well
treatment.
Since the raw waste loads and treatability of the wastes are
independent of size, location and climate and the volume of
production water varies with the age and nature of the
producing formation, the limitations are set in terms of
concentration and the subcategorization is based on a
balance of the costs with the potential environmental
benefits and energy use (loss) . The subcategories developed
for the offshore segment of the oil and gas extraction
industry for the purpose of establishing effluent
limitations are as follows:
1. Near-Offshore All facilities within offshore State waters
2. Far-Offshore All facilities in Federal waters
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SECTION II
RECOMMENDATIONS
The significant or potentially significant waste water
constituents are oil and grease, fecal coliform, oxygen
demanding parameters, heavy metals and toxic materials.
These waste water constituents were selected to be the
subject of the effluent limitations.
Effluent limitations commensurate with the best practical
control technology currently available are proposed for each
subcategory. These limitations, listed in Table 1 are
explicit numerical values (whenever possible) or some other
criteria.
BPCTCA end-of-pipe technology is based on the application of
the existing wastewater treatment processes currently used
in the Oil and Gas Extraction Industry. These consist of
equalization, chemical addition, and gas flotation (or its
equivalent) for the treatment of produced water and deck
drainage. The variability of performance of this type of
wastewater treatment system has been recognized in the
development of the BPCTCA effluent limitations.
Effluent limitations commensurate with the best available
technology economically achievable are proposed for each
subcategory. These effluent limitations are listed in Table
2. The primary end-of-pipe treatment for the near offshore
subcategory is the subsurface disposal of production water
and for the far offshore subcategory it is similar to that
for BPCTCA.
New source performance standards commensurate with the best
available demonstrated technology are the same as the BATEA
limitations. These effluent limitations are listed in Table
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TABLE 1
Subcategory
A. Near Offshore
B. Far Offshore
Notes:
Offshore Segment - Oil and Gas Extraction Industry
Effluent Limitations - BPCTCA
Water Source
produced water
deck drainage
drilling muds
drill cuttings
well treatment
sanitary M10C
M9IM0
domestic
produced sand
produced water
deck drainage
drilling muds
drill cuttings
well treatment
sanitary M10C
M9IM0
domestic
produced sand
Oil 5 Grease - mg/1
Residual Chlorine - mg/1
Maximum for
any one day
72
72
a
a
a
N/A
N/A
N/A
72
72
a
a
a
N/A
N/A
N/A
a
Average of daily
values for thirty
consecutive days
shall not exceed
48
48
a
a
a
N/A
N/A
N/A
a
48
48
a
a
a
N/A
N/A
N/A
a
N/A
N/A
N/A
N/A
N/A
greater than 1D
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A b
greater than 1
N/A
N/A
N/A
a. No discharge of free oil to the surface waters.
b. Minimum of 1 mg/1 and maintained as close to this concentration as possible.
c. There shall be no floating solids as a result of the discharge of these materials.
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TABLE 2
Offshore Segment - Oil and Gas Extraction Industry
Effluent Limitations - BATEA and New Source
Pollutant Parameter - Effluent Limitations
Subcategory
Water source
Oil § Grease - n
Maximum for Avei
any one day vali
cons
sha]
No Discharge
72
a
a
a
N/A
N/A
N/A
a
52
52
a
a
a
N/A
N/A
N/A
ig/1 Residual Chlo
•age of daily
les for thirty
;ecutive days
.1 not exceed
48 N/
XT /
a N/
XT /
a N/
XT 1
a N/
N/A greater
N/A N/
N/A N/
M/
a N/
30 N/
30 N/
a Ny
a N/
XT
a Ny
N/A greatei
N/A N/
N/A N/
Ti T
- mg/1
A. Near Offshroe produced water
deck drainage
drilling muds
drill cuttings
well treatment
sanitary M10
M9IM°
domestic0
produced sand
B. Far Offshore produced water
deck drainage
drilling muds
drill cuttings
well treatment
sanitary M10
M9IM°
domestic0
produced sand a a
Notes:
a. No discharge of free oil to the surface waters.
b. Minimum of 1 mg/1 and maintained as close to this concentration as possible.
c. There shall be no floating solids as a result of the discharge of these materials,
lb
N/A
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SECTION III
INTRODUCTION
Purpoge and Authority
Section 301(b) of the Federal Water Pollution Control Act
Amendments of 1972 requires the achievement by not later
than July 1, 1977, of effluent limitations for point
sources, other than publicly owned treatment works. The
limitations are to be based on application of the best
practicable control technology currently available as
defined by the Administrator pursuant to Section 304 (b) of
the Act. Section 301 (b) also requires the achievement by not
later than July 1, 1983, of more stringent effluent
limitations for point sources, other than publicly owned
treatment works. The 1983 limitations are to be based on
application of the best available technology economically
achievable which will result in reasonable further progress
toward the national goal of eliminating the discharge of all
pollutants, as determined in accordance with regulations
issued by the Administrator pursuant to Section 304(b) of
the Act.
Section 306 of the Act requires the Administrator, within
one year after a category of sources is included in a list
published pursuant to section 306(b)(1)(A) of the Act, to
propose regulations establishing Federal standards of
performances for new sources within such categories. The
Administrator published, in the Federal Register of January
16, 1973 (38 F.R. 1624), a list of 27 source categories.
Publication of an amended list will constitute announcement
of the Administrator's intention of establishing, under
section 306, standards of performance applicable to new
sources within Offshore Segment of the Oil and Gas
Extraction Industry. The list will be amdned when proposed
regulations for the Offshore Segment of the Oil and Gas
Extraction Industry are published in the Federal Register.
The standards are to reflect the greatest degree of effluent
reduction which the Administrator determines to be
achievable through the application of the best available
demonstrated control technology, processes, operating
methods, or other alternatives; where practicable, a
standard may permit no discharge of pollutants.
Section 304 (b) of the Act requires the Administrator to
publish within one year of enactment of the Act, regulations
providing guidelines for effluent limitations. The
guidelines are to set forth:
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The degree of effluent reduction attainable through
application of the best practicable control technology
currently available.
The degree of effluent reduction attainable through
application of the best control measures and practices
economically achievable including treatment techniques,
process and procedure innovations, operation methods, and
other alternatives.
The findings contained herein set forth effluent limitations
guidelines pursuant to Section 304(b) of the Act for certain
segments of the petroleum industry.
Gg.Hg.£al_Pescrigtion of Industry
The segments of the industry to be covered by this study are
the following Standard Industrial Classifications (SIC):
1311 Crude Petroleum and Natural
Gas
1381 Drilling Oil and Gas Wells
1382 Oil and Gas Field Exploration
Services
1389 Oil and Gas Field Services,
not classified elsewhere
Within the above SIC's, this study covers those activities
carries out both onshore and in the estuarine, coastal, and
Outer Continental Shelf areas.
The characteristics of wastes differ considerably for the
different processes and operations. In order to describe
the waste derived from each of the industry subcategories
established in Section IV, it is essential to evaluate the
sources and contaminants in the three broad activities in
the oil and gas industry—exploring, drilling, and
producing—as well as the satellite industries that support
those activities.
Exploration
The exploration process usually consists of mapping and
aerial photography of the surface of the earth, followed by
special surveys such as seismic, gravimetric, and magnetic,
to determine the subsurface structure. The special surveys
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may be conducted by vehicle, vessel, aircraft, or on foot,
depending on the location and the amount of detail needed.
These surveys can suggest underground conditions favorable
to accumulation of oil or gas deposits, but they must be
followed by the drill since only drilling can prove the
actual existence of oil.
Aside from sanitary wastes generated by the personnel
involved, only the drilling phase of exploration generates
significant amounts of water pollutants. Exploratory
drilling, whether shallow or deep, generally uses the same
rotary drilling methods as development drilling. The
discussion of wastes generated by exploratory drilling are
discussed under "Drilling System".
Drilling System
The majority of wells drilled by the petroleum industry
are drilled to obtain access to reservoirs of oil or gas. A
significant number, however, are drilled to gain knoweldge
of geologic formation. This latter class of wells may be
shallow and drilled in the initial exploratory phase of
operations, or may be deep exploration seeking to discover
oil or gas bearing reservoirs.
Most wells are drilled today by rotary drilling methods.
Basically the methods consist of:
1. Machinery to turn the bit, to add sections on the
drill pipe as the hole deepens, and to remove the drill
pipe and the bit from the hole.
2. A system for circulating a fluid down through the
drill pipe and back up to the surface.
This fluid removes the particles cut by the bit, cools and
lubricates the bit as it cuts, and, as the well deepens,
controls any pressures that the bit may encounter in its
passage through various formations. The fluid also
stabilizes the walls of the well bore.
The drilling fluid system consists of tanks to formulate,
store, and treat the fluids; pumps to force them through the
drill pipe and back to the surface; and machinery to remove
cuttings, fines, and gas from fluids returning to the
surface (see Figure 1). A system of valves controls the
flow of drilling fluids from the well when pressures are so
great that they cannot be controlled by weight of the fluid
column. A situation where drilling fluids are ejected from
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A KELLY
B STANDPIPE and ROTARY HOSE
C SHALESHAKER
D OUTLET FOR DRILLING FLUID
E SUCTION TANK
F PUMP
FLOW OF DRILLING FLUID
Fig. 1 ~ ROTARY DRILLING RIG
10
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DRILL
A KELLY
C SHALESHAKER
D OUTLET FOR DRILLING FLUID
G HYDRAULICALLY OPERATED BLOWOUT PREVENTER
H OUTLETS, PROVIDED WITH VALVES
AND CHOKES FOR DRILLING FLUID
-^FLOW OF DRILLING FLUID
DRILL BIT
Fig. 2 -- SHALESHAKER AND BLOWOUT PREVENTER
11
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the well by subsurface pressures and the well flows
uncontrolled is called a blowout, and the controlling valve
system is called the blowout preventer (see Figure 2).
For offshore operations, drilling rigs may be mobile or
stationary. Mobile rigs are used for both exploratory and
development drilling, while stationary rigs are used for
development drilling in a proven field. Some mobile rigs
are mounted on barges and rest on the bottom for drilling in
shallow waters. Others, also mounted on barges are jacked
up above the water on legs for drilling in deeper water (up
to 300 feet). A third class of mobile rigs are on floating
units for even deeper operations. A floating rig may be a
vessel, with a typical ship's hull, or it may be
semi submersible—essentially a floating pleitform with
special submerged hulls and supporting a rig well above the
water. Stationary rigs are mounted on pile-supported
platforms.
Onshore drilling rigs used today are almost completely
mobile. The derrick or mast and all drilling machinery are
removed when the well is completed and used again in a new
location.
Rigs used in marsh areas are usually barge mounted, and
canals are dredged to the drill sites so that the rigs can
be floated in.
The major source of pollution in the drilling system is the
drilling fluid of "mud" and the cuttings from the bit. In
early wells drilled by the rotary method, water was the
drilling fluid, The water mixed with the naturally occurring
soils and clays and made up the mud. The different
characteristics and superior performance of some of these
natural muds were evident to drillers, which led to
deliberately formulated muds. The composition of modern
drilling muds is quite complex and can vary widely, not only
from one geographical area to another, but also in different
portions of the same well.
The drilling of a well from top to bottom is not a
continuous process. A well is drilled in sections, and as
each section is completed it is lined with a section of pipe
or casing (see Figure 2). The different sections may
require different types of mud. The mud from the previous
section must either be disposed of or converted for the next
section. Some mud is left in the completed well.
Basic mud components inlcude: bentonite or attapulgite
clays to increase viscosity and create a gel; barium sulfate
12
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(barite), a weighting agent; and lime and caustic soda to
increase the pH and control viscosity. (Additional
conditioning constituents may consist of polymers, starches,
lignitic material, and various other chemicals). Most muds
have a water base, but some have an oil base. Oil-based
muds are used in special situations and present a much
higher potential for pollution. They are generally used
where bottom hole temperatures are very high or where water-
based muds would hydrate water-sensitive clays or shales.
They may also be used to free stuck drill pipe, to drill in
permafrost areas, and to kill producing wells.
As the drilling mud is circulated down the drill pipe,
around the bit, and back up in annulus between the bore hole
and the drill pipe, it brings with it the material cut and
loosened by the bit, plus fluids which may enter the hole
from the formation (water, oil, or gas). When the mud
arrives at the surface, cuttings, silt, and sand are removed
by shaleshakers, desilters, and desanders. Oil or gas from
the formation is also removed, and the cleansed mud is
cycled through the drilling system again. With offshore
wells, the cuttings, silt and sand are discharged overboard
if they do not contain oil. Some drilling mud clings to the
sand and cuttings, and when this material reaches the water
the heavier particles (cuttings and sand) sink to the bottom
while the mud and fines are swept down current away from the
platform.
Onshore, discharges from the shaleshakers and cyclone
separators (desanders or desilters) usually go to an earthen
(slush) pit adjacent to the rig. To dispose of this
material the pit is backfilled at the end of the drilling
operations.
The removal of fines and cuttings is one of a number of
steps in a continuing process of mud treatment and
conditioning. This processing may be done to keep the mud
characteristics constant or to change them as required by
the drilling conditions. Many constituents of the drilling
mud can be salvaged when the drilling is completed, and
salvage plants may exist either at the rig or at another
location, normally at the industrial facility that supplies
mud or mud components.
Where drilling is more or less continuous, such as on a
multiple-well offshore platform, the disposal of mud should
not be a frequent occurrence since it can be conditioned and
recycled from one well to another.
13
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The drilling of deeper, hotter holes may increase use of
oil-based mud. However, new mud additives may permit use of
water-based muds where only oil muds would have served
before. Oil muds always present disposal problems.
Production System
Crude oil, natural gas, and gas liquids are normally
produced from geological reservoirs through a deep bore well
into the surface of the earth. The fluid produced from oil
reservoirs normally consists of oil,natural gas, and salt
water or brine containing both dissolved and suspended
solids. Gas wells may produce dry gas but usually also
produce varying quantities of light hydrocarbon liquids
(known as gas liquids or condensate) and salt water. As in
the case of oil field brines, the water contains dissolved
and suspended solids and hydrocarbon contaiminants. The
suspended solids are normally sands, clays, or other fines
from the reservoir. The oil can vary widely in its physical
and chemical properties. The most important properties are
its density and viscosity. Density is usually measured by
the "API Gravity11 method which assigns a number to the oil
based on its specific gravity. The oil can range from very
light gasoline like materials (called natural gasolines) to
heavy, viscous asphalt like materials.
The fluids are normally moved through tubing contained
within the larger cased bore hole. For oil wells, the
energy required to lift the fluids up the well can be
supplied by the natural pressures in the formation, or it
can be provided or assisted by various man-made operations
at the surface. The most common methods of supplying man-
made energy to extract the oil are: to inject fluids
(normally water or gas) into the reservoir to maintain
pressure, which would otherwise drop during withdrawal; to
force gas into the well stream in order to lighten the
column of fluid in the bore and assist in lifting as the gas
expands up the well; and to employ various types of pumps in
the well itself. As the fluids rise in the well to the
surface, they flow through various vavles and flow control
devices which make up the well head. One of these is an
orifice (choke) which maintains required back pressure on
the well and controls, by throttling the fluids, the rate at
which the well can flow. In some cases, the choke is placed
in the bottom of the well rather than at the well head.
Once at the surface, the various constituents in the fluids
produced by oil and gas wells are separated: gas from the
liquids, oil from water, and solids from liquids (see Figure
3). The marketable constituents, normally the gas and oil,
14
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CENTRAL TREATMENT FACILITY IN ESTUARINE AREA
HIGH PRESSURE GAS
INTERMEDIATE PRESSURE GAS
( GAS, OIL. WATER, SANOI
GAS LIQUID SEPARATION PLATFORM
nniMvwwvww
FREEWATER
KNOCKOUT PLATFORM
CLEAN WATER TO DISPOSAL
WATFR TREATMENT POLLUTION CONTROL
CRUDE OIL TREATMENT
NATURAL GAS COMPRESSORS
DE HV ORATION [" t»" 1~_~*J~
SijCT^- TO CRUPE OIL SALES
rt <*««»«.«»...........»..«.«».
Fig. 3 — CENTRAL TREATMENT FACILITY IN ESTUARINE AREA
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are then removed from the production area, and the wastes,
normally the brine and solids, are disposed of after further
treatment. At this stage, the gas may still contain
significant amounts of hydrocarbon liquids and may be
further processed to separate the two.
The gas, oil, and water may be separated in a single vessel
or, more commonly, in several stages. Some gas is dissolved
in the oil and comes out of solution as the pressure on the
fluids drops. Fluids from high-pressure reservoirs may have
to be passed through a number of separating stages at
successively lower pressures before the oil is free of gas.
The oil and brine do not separate as readily as the gas
does. Usually, a quantity of oil and water is present as an
emulsion. This emulsion can occur naturally in the
reservoir or can be caused by various processes which tend
to mix the oil and water vigorously together and cause
droplets to form. Passage of the fluids into and up the
well tends to mix them. Passage through well head chokes,
through various pipes, headers, and control valves into
separation chambers, and through any centrifugal pumps in
the system, tends to increase emulsif icatiori. Moderate
heat, chemical action, and/or electrical charges tend to
cause the emulsified liquids to separate or coalesce, as
does the passage of time in a quiet environment. Other
types of chemicals and fine suspended solids tend to retard
coalescence. The characteristics of the crude oil also
affect the ease or difficulty of achieving process
separation.(1)
Fluids produced by oil and gas wells are usually introduced
into a series of vessels for a two-stage separation process.
Figure 4 shows a gas separator for separating gas from the
well stream. Liquids (oil or oil and water) "along with
particulate matter leave the separator through the dump
valve and go on to the next stage: oil-water separation.
Because gas comes out of solution as pressure drops, gas-oil
separators are often arranged in series. High-pressure,
intermediate, and low-pressure separators are the most
common arrangement, with the high-pressure liquids passing
through each stage in series and gas being taken off at each
stage. Fluids from lower-pressure wells would go directly
to the most appropriate separator. The liquids are then
piped to vessels for separating the oil from the produced
water. Water which is not emulsified and separates easily
may be removed in a simple separation vessel called a free
water knockout.
The remaining oil-water mixture will continue to another
vessel for more elaborate treatment (see Figure 5). in this
16
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A B
H
A-OIL AND GAS INLET
B-IMPACT ANGLE
C-DE-FOAMING
ELEMENT
E-MIST EXTRACTOR G-DRAIN
D-WAVE BREAKER AND
SELECTOR PLATE F-GAS OUTLET
H-OIL OUTLET
(DUMP VALVEl
Fig. 4 — HORIZONTAL GAS SEPARATOR
-------
GAS OUT
OAS OUTLET
EMULSION
INLET
(OTHER TYPES OF UNITS
MIGHT CONTAIN THE GRID
OF AN ELECTRIC DEHYDRATOR
IN PLACE OF THE FILTER SECTION)
OIL OUT
WATER OUT
EMULSION IN
Fig.
— VERTICAL HEATER-TREATER
18
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vessel (which may be called a heater-treater, electric
dehydrator, gun barrel, or wash tank, depending on
configuration and the separation method employed), there is
a relatively pure layer of oil on the top, relatively pure
brine on the bottom, and a layer of emulsified oil and brine
in the middle. There is usually a sensing unit to detect
the oil-water interface in the vessel and regulate the
discharge of the fluids. Emulsion breaking chemicals are
often added before the liquid enters this vessel, the vessel
itself is often heated to facilitate breaking the emulsion,
and some units employ an electrical grid to charge the
liquid and to help break the emulsion. A combination of
treatment methods is often employed in a single vessel. In
three-phase separation, gas, oil, and water are all
separated in one unit. The gas-oil and oil-water interfaces
are detected and used to control rates of influent and
discharge.
Oil from the oil-water separators is usually sufficiently
free of water and sediment (less than 2 percent) so as to be
marketable. The produced water or produced water/solids
mixtures discharged at this point contain too much oil to be
disposed of into a water body. The object of processing
through this point is to produce marketable products (clean
oil and dry gas). In contrast, the next stages of treatment
are necessary to remove sufficient oil from the produced
water so that it may be discharged. These treatment
operations do not significantly increase the quality or
quantity of the saleable product. They do decrease the
impact of these wastes on the environment.
Typical produced water from the last stage of process would
contain several hundred to perhaps a thousand or more parts
per million of oil. There are two methods of disposal:
treatment and discharge to surface (salt) waters or
injection into a suitable subsurface formation in the earth.
Surface discharge is normally used offshore or near shore
where bodies of salt or brackish water are available for
disposal. Injection is widely used onshore where bodies of
salt water are not available for surface disposal.
(produced water to be disposed of by injection may still
require some treatment).
Some of the same operations used to facilitate separation in
the last stage of processing (chemical addition and
retention tanks) may be used in waste water treatment, and
other methods such as filtering, centrifuging, and
separation by gas flotation are also used. In addition,
combinations of two or more of these operations can be used
to advantage to treat the waste water. The vast majority of
19
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present offshore and near shore (marsh) facilities in the
Gulf of Mexico and most facilities in Cook Inlet, Alaska,
treat and dispose of their produced water to surface salt or
brackish water bodies.
Several options are available in injection systems. Often
water will be injected into a producing oil reservoir to
maintain reservoir pressure, and stabilize reservoir
conditions. In a similar operation called water flooding,
water is injected into the reservoir in such a way as to
move oil to the producing wells and increase ultimate
recovery. This process is one of several known as secondary
recovery since it produces oil beyond that available by
primary production methods. A successful water flooding
project will increase the amount of oil being produced at a
field. It will also increase produced water volume and thus
affect the amount of water that must be treated,. Pressure
maintenance, of water injection may also increase the amount
of water produced and treated. Injection is also feasible
solely as a disposal method. It is extensively used in all
onshore production areas for disposal of produced water and
is used in California for disposal of produced water from
offshore facilities.
Evolution of Facilities
Early offshore development tended to place wells on
individual structures, bringing the fluids ashore for
separation and treatment (see Figure 3). As the industry
moved farther offshore, the wells still tended to be located
on individual platforms with the output to a central
platform for separation, treatment, and discharge to a
pipeline or barge transportation system.
With increasing water depth, multiple-well platforms were
developed with 20 or more wells drilled directionally from a
single platform. Thus an entire field or a large portion of
a field could be developed from one structure. Offshore
Louisiana multiple-well platforms include all processing and
treatment, in offshore California and in Cook Inlet
facilities, gas separation takes place on the platforms,
with the liquids usually sent ashore for separation and
treatment.
All forms of primary and secondary recovery as well as
separation and treatment are performed on platforms, which
may include compressor stations for gas lift wells and
sophisticated water treatment facilities for water flood
projects. Platforms far removed from shore are practically
independent production units.
20
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Platform design reflects the operating environment. Cook
Inlet platforms are enclosed for protection from the
elements and have a structural support system designed to
withstand ice floes and earthquakes. Gulf Coast platforms
are usually open, reflecting a mild climate. Support
systems are designed to withstand hurricane-generated waves.
A typical onshore production facility would consist of wells
and flowlines, gas-liquid and oil-water production
separators, a waste water treatment unit (the level of
treatment being dependent on the quality of the waste water
and the demands of the injection system and receiving
reservoir) , surge tank, and injection well. Injection might
either be for pressure maintenance and secondary recovery or
soley for disposal. In the latter case, the well would
probably be shallow and operate at lower pressure. The
might include a pit to hold waste water should the injection
system shut down.
A more recent production technique and one which may become
a significant source of waste in the future is called
"tertiary recovery." The process Usually involves injecting
some substance into the oil reservoir to release or carryout
additional oil not recovered by primary recovery (flowing
wells by natural reservoir pressure, pumping, or gas lift)
or by secondary revenue.
Tertiary recovery is usually classified by the substance
injected into the reservoir and includes:
1. Thermal recovery
2. Miscible hydrocarbon
3. Carbon dioxide
4. Alcohols, soluble oil, micellar solutions
5. Chemical floods, surfactants
6. Gas, gas/water, inert gas
7. Gas repressuring, depletion
8. Polymers
9. Foams, emulsions, precipitates
The material is injected into the reservoir and moves
through the reservoir to the producing wells. During this
21
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passage, it removes and carries with it oil remaining in
pores in the reservoir rocks or sands. Oil, the injected
fluid, and water may all be moved up the well and through
the normal production and treatment system.
Nine economically successful applications of tertiary
recovery have been documented (two of them in Canadian
fields): one miscible hydrocarbon application; three gas
applications; two polymer applications, and three
combinations of miscible hydrocarbon with gas drive.
At this time very little is known about the wastes that will
be produced by these production proccess. They will
obviously depend on the type of tertiary recovery used.
Field Service
A number of satellite industries specialize in providing
certain services to the production side of the oil industry.
Some of these service industries produce a particular class
of waste that can be identified with the service they
provide. Of the waste-producing service industries,
drilling(which is usually done by contractor) is the
largest. Drilling fluids and their disposal have already
been discussed. Other services include completions,
workovers, well acidizing, and well fracturing.
When a company decides that an oil or gas well is a
commercial producer, certain equipment will be installed in
the well and on the well head to bring the well into
production. The equipment from this process—called
llcompletion"--normally consists of various valves and
sealing devices installed on one or more strings of tubing
in the well. If the well will not produce sufficient fluid
by natural flow, various types of pumps or gas lift systems
may be installed in the well. Since heavy weights and high
lifts are normally involved, a rig is usually used. The rig
may be the same one that drilled the well, or it may be a
special (normally smaller) workover rig installed over the
well after the drilling rig has been moved.
After a well has been in service for a while it may need
remedial work to keep it producing at an acceptable rate.
For example, equipment in the well may malfunction,
different equipment may be required, or the tubing may
become plugged up by deposits of paraffin. If it is
necessary to remove and reinstall the tubing in the well, a
workover rig will be used. It may be possible to accomplish
the necessary work with tools mounted on a wire and lowered
into the well through the tubing. This is called a wire
22
-------
line operation. In another system, tools may be forced into
the well by pumping them down with fluid. Where possible,
the use of a rig is avoided, since it is expensive.
In many wells, the potential for production is limited by
impermeability in the producing geological formation. This
condition may exist when the well is first drilled it may
worsen with the passage of time, or both situations may
occur. Several methods may be used, singly or in
combination, to increase the well flow by altering the
physical nature of the reservoir rock or sand in the
immediate vicinity of the well.
The two most common methods to increase well flow are
acidizing and fracturing. Acidizing consists of introducing
acid under pressure through the well and into the producing
formation. The acid reacts with the reservoir material,
producing flow channels which allow a larger volume of
fluids to enter the well. In addition to the acid,
corrosion inhibitors are usually added to protect the metal
in the well system. Wetting agents, solvents, and other
chemicals may also be used in the treatment.
In fracturing, hydraulic pressure forces a fluid into the
reservoir, producing fractures, cracks, and channels.
Fracturing fluids may contain acids so that chemical
disintegration, as well as fracturing takes place. The
fluids also contain sand or some similar material that keeps
the fracture propped open once the pressure is released.
When a new well is being completed or when it is necessary
to pull tubing to work over a well, the well is normally
"killed"—that is, a column of drilling mud, oil, water, or
other liquid of sufficient weight is introduced into the
well to control the down hole pressures.
When the work is completed, the liquid used to kill the well
must be removed so that the well will flow again. If mud is
used, the initial flow of oil from the well will be
contaiminated with the mud and must be disposed of.
Offshore, it may be disposed of into the sea if it is not
oil contaminated, or it may be salvaged. Onshore, the mud
may be disposed of in pits or may be salvaged. Contaminated
oil is usually disposed by burning at the site.
In acidizing and fracturing, the spent fluids used are
wastes. They are moved through the production, process, and
treatment systems after the well begins to flow again.
Therefore, initial production from the well will contain
some of these fluids. Offshore, contaiminated oil and other
23
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liquids are barged ashore for treatment and disposal;
contaminated solids are buried.
The fines and chemicals contained in oil from wells put on
stream after acidizing or fracturing have seriously upset
the waste water treatment units of production facilities.
When the sources of these upsets have been identified,
corrective measures can prevent or mitigate the effects. (2)
Industry_DistributiQn
1973, domestic production was 9.2 million barrels-per-day
(bpd) of oil and 1.7 million bpd of gas liquids, for a total
production of 10.9 bpd; down slightly from 1970, 1971, and
1972. (3) Total imports were 6.2 million bpd for 1973.
There are approximately half a million producing oil wells
and 120,000 gas and condensate wells in the United States.
Of the 30,000 new wells drilled each year, about 55 percent
produce oil or gas.
Oil is presently produced in 32 of the 50 states and from
the Outer Continental Shelf (OCS) off of Louisiana, Texas,
and California. Exploratory drilling is underway on the OCS
off of Mississippi, Alabama, and Florida. In 1972, the five
largest oil-producing States were: Texas, Louisana,
California, Oklahoma^ and Wyoming. With development of the
North Slope oil fields and construction of the Alaska
pipeline, Alaska will become one of the most important oil
producing States.
Offshore oil production is presently concentrated in three
areas in the United States: the Gulf of Mexico, the coast
of California, and Cook Inlet in Alaska. Offshore oil
production in 1973 was approximately 62 million barrels from
Cook Inlet, 116 million from California, and 215 million
from Louisiana and Texas,
Gulf of Mexico
Approximately 2,000 wells now produce oil and gas in State
waters in the Gulf of Mexico and 6,000 on the OCS. Over 90
percent are in Louisiana, with the remainder in Texas.
Recent lease sales have been held on the OCS off Texas and
off the Mississippi, Alabama, and Florida coasts.
Discoveries have been made in those areas, and development
will take place as quickly as platforms can be installed,
development drilling completed, and pipelines laid.
24
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Leases have been granted in water as deep as 600 feet.
These deep areas will probably be served by conventional
types of platforms, but their size and cost increase rapidly
with increasing depth.
California
There has been a general moratorium on drilling and
development in the offshore areas of California since the
Santa Barbara blowout of 1969.
Present offshore production in State waters comes from the
area around Long Beach and Wilmington and also from the
Santa Barbara area farther north. OCS production is
confined to the Santa Barbara area. Except for one
facility, all production from both State and Federal leases
is piped ashore for treatment. A large and increasing
amount of the produced brine is disposed of by subsurface
injection.
Exxon Corporation has applied for permits to develop an area
leased prior to 1969 in the northern Santa Barbara Channel
(the "Santa Ynez Unit") . Several fields have been
discovered on these leases in water depths from 700 to over
1,000 feet. Proposed development of the shallower portion
of one of these areas calls for erection of a multiple-well
drilling and production platform in 850 feet of water. If
gas and oil are found in commercial quantities, the gas
would be separated on the platform, with the water and oil
sent ashore for separation and treatment. Produced water
would be disposed of by subsurface injection ashore.
Additional lease sales have been proposed on the OCS off
Santa Barbara and Southern California.
Cook Inlet, Alaska
Offshore production in Cook Inlet comes from 14 multiple-
well platforms on four oil fields and one gas field.
Development took place in the 1960* s and has been relatively
static for the past 5 years. The demarcation line between
Federal and State waters in lower Cook Inlet is under
litigation. The settlement of this dispute will probably
lead to leasing and development of additional areas in the
Inlet.
Present practice is to separate gas on the platforms,
sending the produced water and oil ashore for separation and
treatment. Some platforms are producing increasing amounts
of produced water, and this, plus the occasional plugging of
25
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oil/water pipelines with ice in the winter, will encourage a
change to platform separation, treatment, and disposal of
produced waters.
Cook Inlet platforms are presently employing gas lift and
treat Inlet sea water for water flooding.
Industry Growth
From 1960 to 1970, the Nation's demand for energy increased
at an average rate of U.3 percent. Table 3 gives the
projected national demands for oil and gas through 1985 and
Table H the U.S. offshore oil production from 1970 through
1973.
U.S. offshore production declined by about 78,500
barrels/day from 1972 to 1973. Offshore production amounts
to approximately 10 percent of U.S. demand and about 15
percent of U.S. production
While offshore production declined slightly from 1972 to
1973, the potential for increasing offshore production is
much greater than for increasing onshore production. The
Department of the Interior has proposed a schedule of three
or four lease sales per year through 1978, mainly on
remaining acreage in the Gulf of Mexico and offshore
California. Additional areas in which OCS lease sales will
very probably be held by 1978 include the; Atlantic Coast
(Georges Bank, Baltimore Canyon, and Georgia Embayment) and
the Gulf of Mexico.
Not only will new areas be opened to exploration and
ultimate development, but production will move farther
offshore and into deeper waters in areas of present
development.
26
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TABLE 3
U.S. Supply and Demand of Petroleum
and Natural Gas (5)
1121 1980 1985
Petroleum (million barrels/day)
Projected Demand 15.1 20.8 25.0
% of Total U.S. Energy Demand 44.1 43.9 43.5
Projected Domestic Supply 11.3 11.7 11.7
% petroleum demand fulfilled
by domestic supply 74.9 56.3 46.7
Natural Gas (trillion cubic feet/year)
Projected Demand 22.0 26.2 27.5
X of Total U.S. Energy Demand 33.0 28.1 24.3
Projected Domestic Supply 21.1 23.0 23.8
X gas demand fulfilled
by domestic supply 96.0 87.8 86.6
TABLE 4
U.S. Offshore Oil Production - (million barrels/day) (6)
J1970 19Z1 1212 1973
1.58 1.69 1.67 1.59
27
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Movement into more distant and isolated environments will
mean even more self-sufficiency of platform operations, with
all production, processing, treatment, and disposal being
performed on the platforms. Movement into deeper waters
will necessitate multiple-well structures, with a maximum
number of wells drilled from a minimum number of platforms.
Offshore leasing, exploration, and development will rapidly
expand over the next 10 years, and offshore production will
make up an increasing proporation of our domestically
produced supplies of gas and oil.
28
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SECTION III
Bibliography
1. University of Texas-Austin, Petroleum Extension Service,
and Texas Education Agency, Trade and INdustrial Serivce.
1962. "Treating Oil Field Emulsions." 2nd. ed. rev.
2. Gidley, J.L. and Hanson, H.R. 1974. "Central-Terminal
UPset from Well Treatment Is Prevented."
Oil and Gas_Journal, Vol. 72: No. 6: pp. 53-56.
3. Independent Petroleum Association of America. "United
STates Petroleum Statistics 2974 (Revised)." Washington,
D.C.
4. U.S. Department of the Interior, Geological Survey.
1973. Draft Environment Impact Statement. Vol. 1:
Proposed Plan of Development Santa Ynez Unit, Santa Barbara
Channel, Off California." Washington, DC
5. Dupree, W.G., and West, J.A. 1972. "United States
Energy Through the Year 2000." U.S. Department of Interior.
Washington, DC
6. McCaslin, John C. 1974. "Offshore Oil Prodcution
Soars." Qil_and_Gas_Journal, Vol. 72: No. 18: pp. 136-142.
29
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SECTION IV
INDUSTRY SUBCATEGORIZATION
Eationale^For^Subcategorization
SIC's subcategorize industry into various groups for the
purpose of analyzing production, employment, and economic
factors which are not necessarily related to the type of
wastes generated by the industry. In development of the
effluent limitations and standards, production methodology,
waste characteristics, and other factors were analyzed to
determine if separate limitations need to be designated for
different segments of the industry. The following factors
were examined for delineating different levels of pollution
control technology and possibly subcategorizing the
industry:
1. Type of facility or operation
2. Facility's size, age, and waste volumes
3. Process technology
H. Climate
5. Waste water characteristics
6. Location of facility
Field surveys, waste treatment technology, and effluent data
indicate that the most important factors are the type of
facility, waste water characteristics, and location. The
size of the facility, climate, and volumes of waste
generated are significant with respect to operational
practices but have less influence on waste treatment
technology.
An evaluation of industry's production units (barrels of oil
per day or thousands of cubic feet of gas per day) and waste
volumes indicated no relationship between them. Produced
water production may vary from less than 1 to 90 percent of
the production fluids. High volumes of produced waters are
associated with older production fields and recovery methods
used to extract crude oil from partially depleted
formations. Similarly, the amount of waste generated during
drilling operations is dependent upon the depth of the well,
subsurface characteristics, recovery of drill muds, and
recycling. Therefore, industry subcategorization could not
include an analysis of segmenting the industry on waste load
per unit of production.
31
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Deyelopment of Subcategories
Based upon the type of facility, the industry may be
subdivided into three major categories with similar type
operations or activities: 1) crude petroleum and natural
gas production; 2) oil and gas well filed exploration and
drilling; and 3) oil and gas well completions and workover.
Further subdivision can be made within each to reflect
wastes requiring specific effluent limitations and
standards:
I Crude Petroleum and Natural Gas Production
A. Produced water
B. Deck Drainage
C. Sanitary Waste
II Oil and Gas Well Field Exploration and Drilling
A. Drilling Muds
B. Drill Cuttings
C. Sanitary Waste
III Oil and Gas Well Completions and Workover
A. Chemical Treatment of Wells
B. Production sands
Facility's Size, Age and Waste Volumes
Category I facilities differ little in the type of process
or produced water treatment technology for large, medium, or
small facilities. One of the most significant factors
affecting the size of the facility is the availability of
space for central treatment systems to handle waste from
several platforms or fields. Treatment systems on offshore
platforms are usually limited to meet the needs of the
immediate production facility and are designed for 5,000 to
40,000 barrels/day. In contrast, onshore treatment systems
for offshore production wastes may be designed to handle
100,000 barrels/day or more. For small facilities, wastes
may require intermediate storage and a transport system to
deliver the produced water to another facility for treatment
and disposal. Comparable treatment technology has been
developed for both large and small systems.
32
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The types of treatment for sanitary wastes for large and
small offshore facilities are different, as are facilities
which are intermittently manned. For small and
intermittently manned facilities, the waste may be
incinerated or chemically treated, resulting in no
discharge. Because of operational problems and safety
considerations, other types of treatment systems that will
result in a discharge are being considered. Thus sanitary
wastes must be subcategorized based on facility size.
The state of the art and treatment technology for Category I
has been improving over the past several of years; the
majority of the facilities regardless of age have installed
waste treatment facilities. However, the age of the
production field can impact the quantity of waste water
generated. Many new fields have no need to treat for a
number of years until the formation begins to produce water.
The period before initiating treatment is variable,
depending on the characteristics of the particular field,
and can also be affected by method of recovery. If wastes
are to be treated off shore, the initial design should
provide for the necessary space and energy requirements that
will be needed for the treatment systems to be installed
over the expected life of the platform. No further
subcategorization is needed to account for production field
age or produced water since similar treatment technology is
used regardless of the quantity of water produced.
Process Technology
Process technology was reviewed to determine if the existing
equipment and separation systems influenced the
characteristics of the produced waste. Most oil/water
process separation units consist of heater-treaters,
electric dehydration units or gravity separation (free water
knockout or gun barrel). The type of process equipment and
its configuration are based in part on the characteristics
of the produced fluids. For example, if the fluids contain
entrained oil in a "tight" emulsion, heat may be necessary
to assist in separating water from the oil. Raw produced
water data showed no significant difference in oil content
between the various process units. When high influent
concentrations to the produced water treatment facilities
were observed they were found to be caused by malfunctions
in the process equipment. It was concluded that there is no
basis for subcategorization because of differences in
process systems.
Climate
33
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Climate was considered because conditions in the production
regions differ widely. All regions treat by gravity
separation or chemical/physical methods. These systems are
less sensitive to climatic changes than biological
treatment. Sanitary waste treatment can be affected by
extreme temperatures, but in areas with cold climates,
facilities are enclosed, minimizing temperature variations.
The volume or hydraulic loading due to rainfall may be
significant with respect to the offshore Gulf Coast, but the
waste contaiminants (residual oils from drips, leaks, etc.)
from deck drainage are independent of rainfall. Proper
operation and maintenance can reduce waste oil
concentrations to minimal levels, thus reducing the effect
of rainfall. Therefore, no subcategorization is required to
account for climate.
Waste Water Characteristics
Treatability and other characteristics of produced water are
one of the most significant factors considered for
subcategorization. Produced water may be high in dissolved
solids (TDS), oxygen demanding wastes, heavy metals, and
toxics, in addition to the oil and grease contamination.
The current treatment technologies for produced water are
either subsurface disposal or oil removal prior to
discharge. The technology developed for each area of the
country has been primarily influenced by local regulatory
requirements (water quality and individual state or local
laws), but other factors associated with produced water
treatability and cost effectiveness may also have had an
effect. (1,2,3)
Factors which may affect produced water treatability are:
1. Physical and chemical properties of the crude oil,
including solubility.
2. Concentration of suspended and settleable solids.
3. Fluctuation of flow rate and production method.
4. Droplet sizes of the entrained oil emulsification.
5. Other characteristics of the produced water.
34
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The impact of these variables can be minimized by existing
process and treatment technology, which include desanders,
surge tanks, and chemical treatment.
Location of Facility
The location of the facility affects the applicable
treatment, the cost of that treatment, and the makeup of the
wastes produced. The factors that affect the treatment
method based on location are as follows:
1. Availability of space and site conditions, such as,
dry land, marsh area, or open water.
2. Proximity to shore.
3. Type and depth of subsurface formations suitable
for injection of produced water.
U. Surface water availability ( possible agricultural
use of produced water).
5. Evaporation rate at location.
6. Local water quality and statues.
7. Type of receiving water body.
Location is a significant factor specifically with respect
to areas where saline produced water discharges are not
permitted. The usual procedure in inland areas is to
reinject the produced water to the producing formation,
which assists oil recovery, or to other subsurface
formations for disposal only. Evaporation ponds are used in
some inland areas, with the assumption that all produced
waters are evaporated and no discharge occurs. In an arid
Western oil field an evaporation pond, if properly
maintained, may provide for acceptable disposal of the
produced waters; however, in humid areas in the East and
South, evaporation ponds may not be acceptable.
In inland fields where produced waters are sufficiently low
in total solids, discharges have been used for stock
watering and other beneficial uses.
The technology for disposal of drilling muds, cuttings,
solids, and other materials differs depending upon the
location. In the open water offshore areas, the materials,
if properly treated, are normally discharged into the saline
35
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waters. Onshore technology has been developed to ensure no
discharge to surface waters, and waste materials are
disposed of in approved land disposal sites.
Description gf Subcategories
Based upon the above rationale and discussion the offshore
segment of the oil and gas extraction industry has been
subcategorized as follows:
Subcategory
Subcategory
A - near offshore (facilities located in
offshore state waters)
1.
2.
3.
a.
5.
6.
7.
8.
B -
1.
2.
3.
4.
5.
6.
produced water
deck drainage
drilling muds
drill cuttings
well treatment
sanitary wastes
a.
MlO continuously manned with
more people
10
or
b. M9IM - facilities with 9 or less
people or intermittaritly manned.
domestic wastes
produced sand
far offshore (facilities located in
federal waters)
produced water
deck drainage
drilling muds
drill cuttings
well treatment
sanitary wastes
36
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M10 - facilities contimiously manned
with 10 or more people.
M9IM - facilities with 9 or less
people or intermittently manned.
7. domestic wastes
8. produced sand
Produced Water
Produced water includes all waters and particulate matter
associated with oil and gas producing f ormatations.
Sometimes the terms "formation water" or "brine water" are
used to describe produced water. Most oil and gas producing
geological formations contain an oil-water or gas-water
contact. In some formations, water is produced with the oil
and gas in the early stages of production. In others, water
is not produced until the producing formation has been
significantly depleted and in some cases water is never
produced.
Deck Drainage
Deck drainage includes all waste resulting from platform
washings, deck washings, and run-off from curbs, gutters,
and drains including drip pans and work areas.
Sanitary Waste
Sanitary waste includes human body waste discharged from
toilets and urinals.
Domestic Waste
Domestic wastes are materials discharged from sinks,
showers, laundries, and galleys.
Drilling Muds
Drilling muds are those materials used to maintain
hydrostatic pressure control in the well, lubricate the
drilling bit, remove drill cuttings from the well, or
stabilize the walls of the well during drilling or workover.
Generally, two basic types of muds (water-based and oil
muds) are used in drilling. Various additives may be used
37
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depending upon the specific needs of the drilling program.
Water-based muds are usually mixtures of fresh water or sea
water with muds and clays from surface formations, plus
gelling compounds, weighting agents, and various other
components. Oil muds are referred to as oil-based muds,
invert emulsion muds, and oil emulsion muds. Oil muds are
used for special drilling requirements such as tightly
consolidated subsurface formations and water sensitive clays
and shales. (5) (6) (7)
Drill Cuttings
Drill cuttings are particles generated by drilling into
subsurface geologic formations. Drill cuttings are
circulated to the surface of the well with the drilling mud
and separated there from the drilling mud.
Treatment of Wells
Treatment of wells includes acidizing and hydraulic
fracturing to improve oil recovery. Hydraulic fracturing
involves the parting of a desired section of the formation
by the application of hydraulic pressure. Selected
particles added to the fracturing fluid are transported into
the fracture, and act as propping agents to hold the
fracture open after the pressure is released. Chemical
treatments of wells consists of pumping acid or chemicals
down the well to remove formation damage and increase
drainage in the permeable rock formations.(8)
Produced Sand
Produced sand or solids for this subcategory consist of
particles used in hydraulic fracturing and accumulated
formation sands, which are generated during production.
These sands must be removed when they build up and block
flow of fluids.
38
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SECTION IV
Bibliography
1. Bassett, M.G. 1971. "Wemco Depurator TM System."
Paper presented at the SPE of AIME Rocky Mountain
Regional Meeting, Billings, Montana, June 2-4, 1971.
Preprint No. SPE-3349.
2. Boyd, J.L., Shell, G.L., and Dahlstrom, D.A. 1972.
"Treatment of Oily Waste Waters to Meet Regulatory
Standards." AIChE Symposium. Serial NO. 124, pp. 393-401
3. Ellis, M.M., and Fischer, P.W. 1973. "Clarifying Oil
Field and Refinery Waste Waters by Gas Flotation."
Paper presented at the SPE of AIME Evangeline Section
Regional Meeting, Lafayette, Louisiana, November 9-10,
1970. Preprint No. SPE-3198.
4. U.S. Department of the Interior, Federal Water
Pollution Control Administration. 1968. Report
of the Committee on Water Quality Criteria.
5. U.S. Department of the Interior, Bureau of Land
Management. 1973, Draft Environmental Impact
Statement, "Proposed 1973 Outer Continental Shelf
Oil and Gas General Lease Sale Offshore Mississippi,
Alabama, and Florida." Washington, D.C.
6. Hayward, B.S., Williams, R.H., and Methven, N.E.
1971. "Prevention of Offshore Pollution from
Drilling Fluids." Paper presented at the 46th
Annual SPE of AIME Fall Meeting at New Orleans,
Louisiana, October 3-6, 1971. Preprint No. SPE-3579.
7. Cranfield, J. 1973. "Cuttings Clean-Up Meets Offshore
Pollution Specifications, " Petrol. Petrochem. Int..,
Vol., 13: No. 3: pp. 54-56, 59
8. American Petroleum Institute. Division of Production.
1973. "Primer of Oil and Gas Production." 3rd. ed.
Dallas, Texas.
39
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SECTION V
WASTE CHARACTERISTICS
Wastes generated by the oil and gas industry are produced by
drilling exploratory or development wells, by the production
or extraction phase of the industry, and, in the case of
offshore facilities, sanitary wastes generated by personnel
occupying the platforms. Drilling wastes are generally in
the form of drill cuttings and mud, and production wastes
are generally produced water. (1) Additionally, well
workover and completion operations can produce wastes, but
they are generally similar to those from drilling or
production operations.
Approximately half a million producing oil wells onshore
generate produced water in excess of 10 million barrels-per-
day. Approximately 17,000 wells have been drilled offshore
in U.S. waters, and approximately 11,000 are producing oil
or gas. Offshore Louisiana, the OCS alone produces
approximately 410,000 barrels of water per day (2); by 1983,
coastal Louisiana production will genrate an estimated 1.54
million barrels of water per day.(3)
This section characterizes the types of wastes that are
produced at offshore and onshore wells and structures. The
discussion of drilling wastes can be applied to any area of
the United States since these wastes do not change
significantly with locality.
Other than oils, the primary waste constituents considered
are oxygen demanding pollutants, heavy metals, toxicants,
and dissolved solids contained in drilling muds or produced
water. (4)
Sanitary wastes are also produced during both drilling and
production operations both onshore and offhsore, but they
are discussed only for offshore situations where sanitary
wastes are produced from fixed platforms or structures.
Drilling or exploratory rigs that are vessels are not part
of this discussion.
Waste Constituentg
Production
Production wastes include produced waters associated with
the extracted oil, sand and other solids removed from the
produced waters, deck drainage from the platform surfaces,
sanitary wastes, and domestic wastes.
41
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The produced waters from production platforms generate the
greatest concern. The wastes can contain oils, toxic
metals, and a variety of salts, solids and organic
chemicals. The concentrations of the constituents vary
somewhat from one geographical area to another, with the
most pronounced variance in chloride levels. Table 5 shows
the waste constituents in offshore Louisiana production
facilities in the Gulf of Mexico. The data were obtained
during the verification survey conducted by EPA in 1974.
The only influent data obtained in the survey were on oil
and grease. In planning the verification survey, it was
decided that offshore produced water treatment facilities
would have virtually no effect on metals and salinity levels
in the influent, and that these constituents could be
satisfactorily characterized by analyzing only the effluent.
Total organic carbon (TOG) is also tabulated under effluent
in Table 5, but it is reasonable to assume that actual
analysis of the influent would be higher. Since TOG is a
measurement of all organic carbon in the sample and oil is a
major source of organic carbon, it is logical to assume
removal of some organic carbon when oil is removed in the
treatment process. Suspended solids are also expressed as
effluent data, and this parameter would be expected to be
reduced by the treatment process.
42
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TABLE 5
Pollutants in Produced Water
Louisiana Coastal(a)
Pollutant Parameter
Oil and Grease
Cadmium
Cyanide
Mercury
Total Organic Carbon
Total suspended solids
Total dissolved solids
Chlorides
Range mg/1
Average mq/1
7 - 1300
<0.005 - .675
<0.01 - 0.01
30 - 1580
22 - 390
32,000 - 202,000
10,000 - 115,000
202
<0.068
<0.01
<0.0005
413
73
110,000
61,000
Flow
250 - 200,000 bbls/day 15,000 bbls/day
(a) - results of 1974 EPA survey of 25 discharges
< - less than
43
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Industry data for offshore California describes a broader
range of parameters (see Table 6). Similar data were
provided for offshore Texas (see Table 7). Except as noted
on the tables, all data are from effluents. Oil influent
data for these two areas are listed on Table
Sand and other solids are produced along with the produced
water. Observations made by EPA personnel during field
surveys indicated that drums of these sands stored on the
platform had a high oil content. Sand has been reported to
be produced at approximately 1 barrel sand per 2,,000 barrels
oil. (5,6)
44
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Pollutant
Parameter
TABLE 6
Pollutants Contained in Produced Water
Coastal California (a) (7)
Range, mg/1
Arsenic
Cadmium
Total Chromium
Copper
Lead
Mercury
Nickel
Silver
Zinc
Cyanide
0.001 - 0.08
0.02 - 0.18
0.02 - 0.04
0.05 - 0.116
0.0 - 0.28
0.0005 - 0.002
0. 100 - 0.29
0.03
0.05 - 3.2
0.0 - 0.004
Phenolic Compounds 0.35 - 2.10
BOD
COD
Chlorides
TDS
Suspended Solids
Effluent
Influent
Oil and Grease
370 - 1,920
400 - 3,000
17,230 - 21,000
21,700 - 40,400
1 - 60
30 - 75
56 - 359
(a)Some data reflect treated waters for reinjection.
45
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TABLE 7
Range of Constituents in Produced
Formation Water—Offshore Texas(8)
Effluent Constituent Range, mq/1
Arsenic <0.01 - <0.02
Cadmium
-------
Drilling
Drill cuttings are composed of the rock, fines, and liquids
contained in the geologic formations that have been drilled
through. The exact make-up of the cuttings varies from one
drilling location to another, and no attempt has been made
to qualitatively identify cuttings.
The two basic classes of drilling muds used today are water-
based muds and oil muds. In general, much of the mud
introduced into the well hole is eventually displaced out of
the hole and requires disposal or recovery.(13)
Water-based muds are formulated using naturally occurring
clays such as bentonite and attapulgite and a variety of
organic and inorganic additives to achieve the desired
consistency, lubricity, or density. Fresh or salt water is
the liquid phase for these muds. The additives are used for
such functions as pH control, corrosion inhibition,
lubrication, weighting, and emulsification.
The additives that should be scrutinized for pollution
control are ferrochrome lignosulfonate and lead
compounds. (14)
Ferrochrome lignosulfonate contains 2.6 percent iron, 5.5
percent sulfur, and 3.0 percent chromium. In an example
presented by the Bureau of Land Management in an
Environmental Impact Statement for offshore development, the
drilling operation of a typical 10,000-foot development well
(not exploratory) used 32,900 pounds of ferrochrome
lignosulfonate mud which contained 987 pounds of
chromium.(2) Table 8 presents the volumes of cuttings and
muds used in the Bureau's example of a "typical" 10,000-foot
drilling operation. The amount of lead additives used in
mud composition varies from well to well, and no examples
are available.
Drilling constituents for onshore operations will parallel
those for offshore, except for the water used in the typical
mud formulation. Onshore drilling operations normally use a
fresh water-based mud, except where drilling operations
encounter large salt domes. Then the mud system would be
converted either to a salt clay mud system with salt added
to the water phase, or to an oil-based mud system. This
change in the liquid phase is intended to prevent dissolving
to salt in the dome, enlarging the hole, and causing
solution cavities in the formation.
47
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Table 8
Volume of Cuttings and Muds in Typical
10,000-Foot Drilling Operation (2)
Interval ,
Feet
0-1,000
1,000-3500
2,500-10,000
Hole
Size,
inches
24
16
12
Vol. of
Cuttings,
bbl.
562
623
915
Wt. of
Cuttings,
pounds
505,000
545,000
790,000
Drilling
mud
sea water
& natural
mud
Gelled sea
water
Lime base
Vol of
Mud com-
ponents ,
bbl
variable
700
950
Wt. of
Mud com-
ponents
pounds
81,500
424,000
-------
Table 9
Typical Raw Combined Sanitary and Domestic
Wastes from Offshore Facilities
BOD, mg/1 Suspended
No. of
Men
76
fif,
C.-I
i n_/,n
Flow
gal /day
5,500
i 071;
J-, O/ J
2"! C C
, J.DD
9 onn
5 Solids, mg/1
Average Range Average Range
460 270-770 195 14-543
Af.0 fi9O
Q9n _
Total
Coliform
(X 10)
10-180
Reference
(10)
M-n
-------
In offshore operations, the direct discharge of cuttings and
water based muds create turbidity. Limited information is
available to accurately define the degree of turbidity, or
the area or volume of water affected by such turbid
discharges, but experience observers have described the
existence of substantial plumes of turbidity when muds and
cuttings are discharged.
Oil-based muds contain carefully formulated mixtures of
oxidized asphalt, organic acids, alkali, stabilizing agents
and high-flash diesel oil. (14,15) The oils are the principal
ingredients and so are the liquid phase. Muds displaced
from the well hole also contain solids from the hole. There
are two types of emulsified oil muds: 1) oil emulsion muds,
which are oil-in-water emulsions; and 2) inverted emulsion
muds, which are water-in-oil emulsions. The principal
differences between these two muds and oil based muds is the
addition of fresh or salt water into the mud mixture to
provide some of the volume for the liquid phase. Newer
formulations can contain from 20 to 70 percent water by
volume. The water is added by adding emulsifying and
stabilizing agents. Clay solids and weighting agents can
also be added.
Sanitary and Domestic Waste
The sanitary wastes from offshore oil and gas facilities are
composed of human body waste and domestic waste such as
kitchen and general housekeeping wastes. The volume and
concentration of these wastes vary widely with time,
occupancy, platform characteristics, and operational
situation. Usually the toilets are flushed with brackish
water or sea water. Due to the compact nature of the
facilities the wastes have less dilution water than common
municipal wastes. This results in greater waste
concentrations. Table 9 indicates typical waste flow for
offshore facilities and vessels.
50
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SECTION V
Bibliography
1. Biglane, K.E. 1958. "Some Current Waste Treatment
Practices in Louisiana Industry." Paper presented
at the 13th Annual Industrial Waste Conference,
Purdue University, Lafayette, Indiana.
2. U.S. Department of the Interior. Bureau of Land
Management. Draft Environmental Impact Statement.
"Proposed 1973 Outer Continental Shelf Oil and
Gas General Lease Sale Offshore Mississippi,
Alabama, Florida." Washington, D.C.
3. Offshore Operators Committee, Sheen Technical
Subcommittee. 1974. "Determination of Best
Practicable Control Technology Currently
Available to Remove Oil from Water Procuced
with Oil and Gas." Prepared by Brown and
Root, Inc., Houston, Texas.
4. Moseley, F.N., and Copeland, B.J. 1974.
"Brine Pollution System." In: "Coastal
Ecological Systems of the United States."
Odum, Copeland, and McMahan (ed.). The
Conservation Foundation, Washington, D.C.
5. Garcia, J.A. 1971. "A System for the Removal
and Disposal of Produced Sand." Paper presented
at the 47th Annual SPE of AIME Fall Meeting, San
Antonio, Texas, October 8-11, 1972. Preprint
No. SPE-4015.
6. Frankenberg, W.G., and Allred, J.H. 1969.
"Design, Installation, and Operation of
a Large Offshore Production Complex;" and
Bleakley, W.G., "Shell Production Complex
Efficient, Controls, Pollution--. "Oil
and Gas Journal, Vol. 67:No. 36: pp. 65-69.
7. Western Oil and Gas Association and the
Water Quality Board, State of California.
8. Offshore Operators Committee.
9. Crawford, J.G. 1964. "Rocky Mountain Oil
Field Waters." Chemical and Geological
Laboratories, Casper, Wyoming.
51
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10. Sacks, Bernard R. 1969. "Extended Aeriation
Sewage Treatment on U.S. Corps of Engineers
Dredges." U.S. Department of the Interior,
Federal Water Pollution Control Administration.
11. Amoco Production Company. 1974. "Draft Comments
Regarding Rationale and Guideline Proposals for
Treatment of Sanitary Wastes from Offshore
Production Platforms."
12. Humble Oil and Refining Company. 1970. "Report
on the Human Waste on Humble Oil and Refining
Company's Offshore Platforms with Living
Quarters in the Gulf of Mexico." Prepared
by Waldermar S. Nelson Company, Engineers
and Architects, New Orleans, Louisiana.
13. Hayward, B.S., Williams, R.H., and Methveri, N.E.
1971. "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.
14. Gulf Publishing Company. "Drilling Fluids File."
Special compilation from World_Oil, January 1974.
15. The University of Texas, Petroleum Extension
Service. 1968. "Lessons in Rotary Drilling
- Drilling Mud."
52
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SECTION VI
SELECTION OF POLLUTANT PARAMETERS
Oil and grease from produced water, deck drainage, muds,
cuttings, and solids removal, and residual chlorine and
floating solids from sanitary and domestic sources have been
selected as the pollutants for which effluent limitations
will be established. The rationale for inclusion of these
parameters are discussed below.
for^Effluent Limitations
Freon Extractables - Oil and Grease
No solvent is known which will directly dissolve only oil or
grease, thus the manual "Methods for the Chemical Analysis
of Water and Wastes 1971" distributed by the Environmental
Protection Agency states that their method for oil and
grease determinations includes the freon extractable matter
from waters.
In the oil and gas extraction industry, oils, greases,
various other hydrocarbons and some inorganic compounds will
be included in the freon extraction procedures. The
majority of material removed by the procedure from a
produced water will, in most instances, be of a hydrocarbon
nature. These hydrocarbons, predominately oil and grease
type compounds, will make their presence felt in the COD,
TOC, TOD, and usually the BOD tests where high test values
will result. The oxygen demand potential of these freon
extractables is only one of the detrimental effects exerted
on water bodies by this class of compounds, oil emulsions
may adhere to the gills of fish or coat and destroy algae or
other plankton. Depostion of oil in the bottom sediments
can serve to inhibit normal benethic growths, thus
interrupting the aquatic food chain. Soluble and emulsified
materials ingested by fish may taint the flavor of the fish
flesh. Water soluble components may exert toxic action on
fish. The water insoluble hydrocarbons and free floating
emulsified oils in a wastewater will affect stream ecology
by interfering with oxygen transfer, by damaging the plumage
and coats of water animals and fowls, and by contributing
taste and toxicity problems. The effect of oil spills upon
boats and shorelines and their production of oil slicks and
iridenscence upon the surface of waters is well known.
53
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Fecal Coliform - Chlorine Residual
The concentration of fecal coliform bacteria can serve as an
indication of the potential pathogencity of water resulting
from the disposal of human sewage. Fecal coliform levels
have been established to protect beneficial water use
(recreation and shellfish propagation) in the coastal areas.
The most direct methods to determine compliance with
specified limits are to measure the fecal coliform levels in
the effluent for 7 days. This approach is very applicable
to onshore installations; however, for offshore operations
the logistics become complex, and simplified methods are
desirable.
The two key factors that are related to fecal coliform
levels in the effluent are suspended solids and chlorine
residual. 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, chlorine residual is a reasonable control
parameter.
It may be considered desirable, however, that a 7-day study
of each sanitary treatment system be made at least once a
year to measure influent and effluent biochemical oxygen
demand, suspended solids, and fecal coliform. The purpose
of the survey is to determine the treatment efficiencies, to
evaluate operating procedures, and to adjust the system to
obtain maximum treatment efficiencies and minimize chlorine
usage.
Floating Solids
Marine waters should be capable of supporting indigenous
life forms and should be free of substances attributable to
discharges or wastes which will settle to form objectional
deposits, float of the water, and produce objectionable
odors. Floating solids have been selected as a control
parameters for domestic wastes and sanitary waste from small
or intermittently manned offshore facilities.
54
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Other_Pollutants
Some produced formation waters are known to contain heavy
metals, toxic substances, constituents with substantial
oxygen demand, and inorganic salts. Insufficient data exist
to warrant comprehensive control of these parameters and
there is no discharge technology now in use by the industry
to remove these pollutants.
Heavy Metals
Produced waters have been shown to contain cyanide cadmium,
and mercury. Section 307(a) (1) of the Federal Water
Pollution Control Act Amendments of 1972 requires a list of
toxic pollutants and effluent standards or prohibitions for
these substances. The proposed effluent standards for toxic
pollutants state that there shall be no discharge of
cyanide, cadmium, or mercury into streams, lakes or
estuaries with a low flow less than or equal to 0.283 cubic
meters per second (M3/sec)(10 cubic feet per second) or into
lakes with an area less than or equal to 200 hectares (500
acres). Many estuarine areas fall into this category.
The harmful effects of these toxicants, which include direct
toxicity to humans and other animals, biological
concentration, sterility, mutagenicity, teratogenicity, and
other lethal and sublethal effects, have been well
documented in the development of the Section 307 (a) (1)
proposed regulations.
Produced formation waters have also been shown to contain
arsenic, chromium, copper, lead, nickel, silver, and zinc as
pollutants. According to McKee and Wolfe (6) , arsenic is
toxic to aquatic life in concentrations as low as 1 mg/1.
The toxicity of chromium is very much dependent upon
environmental factors and has been shown to be as low as
0.016 mg/1 for aquatic organisms. Copper is toxic to
aquatic organisms in concentrations of less than 1 mg/1 and
is concentrated by plankton from their habitat by factors of
1,000 to 5,000 or more. Lead has been shown to be toxic to
fish in concentrations as low as 0.1 mg/1, nickel at a
concentration of 0.8 mg/1, and silver at a concentration of
0.0005 mg/1. Zinc was shown to be toxic to trout eggs and
larvae at a concentration of 0.01 mg/1.
55
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TDS
Dissolved solids in produced waters consist mainly of
carbonates, chlorides, and sulfates. U.S. Public Health
Service Drinking Waters Standards for total dissolved solids
are set at 500 mg/1 on the basis of taste thresholds. Many
communities in the United States use water containing from
2,000 to 4,000 mg/1 of dissolved solids. Such waters are
not palatable and may have a laxative effect on certain
people. However, the geographic location cind availability
of potable water will dictate acceptable standards. The
following is a summary of a literature survey indicating the
levels of dissolved solids which should not interfere with
the indicated beneficial use:
Domestic Water Supply 1,000 mg/1
Irrigation 700 mg/1
Livestock Watering 2,500 mg/1
Freshwater Fish and Aquatic 2,000 mg/1
Life
Estuaries are typically bilaminar systems, stratified to
some degree, with each layer dependent upon the other for
cycling of minerals, gases, and energy. The upper, low
salinity, euphotic zone supports production of organic
materials from sunlight and CO2; it also produces oxygen in
excess of respiration so that this upper layer is
characteristically supersaturated with 02 during the
daylight hours. The bottom higher salinity layer functions
as the catabolic side of the cycle, (microbial breakdown of
organic material with subsequent O2 utilization and CO2
production) In a healthy estuarine system, these two
layers are in precarious synchrony, and the alteration of
density, minerals, gases, or organic material is capable of
causing an imbalance in the system.
Apparently due to the stresses resulting from salinity
shocks, anamalous ion ratios, strange buffer systems, high
pH, and low oxygen solubility, few organisms are capable of
adapting to brine-dominated systems. This results in low
diversity of species, short food chains, and depressed
trophic levels.(7)
Chlorides
Chloride ion is one of the major anions found in water and
produces a salty taste at a concentration of about 250 mg/1.
Concentrations of 1000 mg/1 may be undetectable in waters
56
-------
which contain appreciable amounts of calcium and magnesium
ions.
Water is invariably associated with naturally occurring
hydrocarbons underground and much of this water contains
high amounts of sodium chloride. The saltiest oil field
waters are located in the mid-continent region of the
country where the average dissolved solids content is
174,000 ppm; therefore, waters containing high levels of
salt may be expected.
The toxicity of chloride salts will depend upon the metal
with which they are combined. Because of the rather high
concentration of the anion necessary to initiate detrimental
biological effects, the limit set upon the concentration of
the metallic ion with which it may be tied, will
automatically govern its concentration in effluents, in
practicaly all forms except potassium, calcium magnesium,
and sodium.
Since sodium is by far the most common (sodium 75 percent,
magnesium 15 percent and calcium 10 percent) the
concentration of this salt will probably govern the amount
of chlorides in waste streams.
It is extremely difficult to pinpoint the exact amount of
sodium chloride salt necessary to result in toxicity in
waters. Large concentrations have been proven toxic to
sheep, swine, cattle, and poultry.
In swine fed diets of swill containing 1.5 to 2.0% salt by
weight, poisoning symptoms can be induced if water intake is
limited and other factors are met. The time interval
necessary to accomplish this is still about one full day of
feeding at this level.
Problems of corrosion, taste, and quality of water necessary
for industrial or agricultural purposes occur at sodium
chloride concentration levels below those at which toxic
effects are experienced.
Oxygen Demand Parameters
Dissolved oxygen (DO) is a water quality constituent that,
in appropriate concentrations, is essential not only to keep
organisms living but also to sustain species reproduction,
vigor, and the development of populations. Organisms
undergo stress at reduced DO concentrations that make them
less competitive and able to sustain their species within
the aquatic environment. For example, reduced DO
57
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concentrations have been shown to interfere with fish
population through delayed hatching of eggs, reduced size
and 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
all aerobic aquatic organisms need a certain amount of
oxygen, the consequences of total lack of dissolved oxygen
due to a high BOD can kill all inhabitants of the affected
area.
Two oxygen demand parameters are discussed below: BODS, and
TOG.
Almost without exception, waste waters from oil and gas
extraction exert a significant and sometimes major oxygen
demand. The primary sources are soluble biodegradable
hydrocarbons and inorganic sulfur compounds.
Biochemical Oxygen Demand (BOD)
Biochemical oxygen demand is a measure of the oxygen
consuming capabilities of organic matter. 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. 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 oxygen
supply. Conditions are reached frequently where all of the
oxygen is used and the continuing decay process causes the
production of noxious gases such as hydrogen sulfide and
methane. Water with a high BOD indicates the presence of
decomposing organic matter and subsequent high bacterial
counts that degrade its quality and potential uses.
If a high BOD is present, the quality of the water is
usually visually degraded by the presence of decomposing
materials and algae blooms due to the uptake of degraded
materials that form the foodstuffs of the algal populations.
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 a 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,
58
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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 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 waste water samples, enhancing the
popularity of TOC as a fundamental measure of pollution.
The organic carbon determination is free of many of the
variables which plaque the BOD analyses, yielding more
reliable and reproduciable data.
Phenolic Compounds
Many phenolic compounds are more toxic than pure phenol;
their toxicity varies with the combinations and general
nature of total wastes. The effect of combinations of
different phenolic compounds is cumulative.
Phenols and phenolic compounds are both acutely and
chronically toxic to fish and other aquatic animals. Also,
chlorophenols produce an unpleasant taste in fish flesh that
destroys their recreational and commercial value.
It is necessary to limit phenolic compounds in raw water
used for drinking water supplies, as conventional treatment
methods used by water supply facilities do not remove
phenols. The ingestion of concentrated solutions of phenols
will result in severe pain, renal irritation, shock and
possibly death.
Phenols also reduce the utility of water for certain
industrial uses, notably food and beverage processing, where
it creates unpleasant tastes and odors in the product.
As seen from the above discussion on the potential harm from
produced water discharges, the effects of toxicants, high
salinity, low dissolved oxygen, and high organic matter can
combine to produce an ecological enigma.
The State of California, recognizing the potential impact of
industrial wastes in the coastal areas, has adopted effluent
limitations for ocean waters under its jurisdiction (see
Table 10. They were arrived at by first applying safety
factors to known toxicity levels and a consideration of
59
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control technology. This produced proposed standards which
were subjected to the public hearing process, revised
accordingly, and then declared. To meet the coastal water
quality standards, the oil and gas extraction industry has
developed a no discharge technology (reinjection of
production water).
60
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TABLE 10
Effluent Quality Requirements for
Ocean Waters of California
Concentration not to be
exceeded more than:
Unit of
measurement 5OX of time 10% of time
Arsenic
Cadmium
Total Chromium
Copper
Lead
Mercury
Nickel
Silver
Zinc
Cyanide
Phenolic Compounds
Total Chlorine
Res idual
Ammonia(expressed
as nitrogen)
Total Identifiable
Chlorinated Hydro-
carbons
Toxicity Concen-
tration
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
0.01
0.02
0.005
0.2
0.1
0.001
0.1
0.02
0.3
0.1
0.5
1.0
40.0
0.02
0.03
0.01
0.3
0.2
0.00
0.2
O.OU
0.5
0.2
1.0
2.0
60.0
mg/1
tu
0.002 0.004
1.5
2.0
Radioactivity
Not to exceed the limits specified in Title 17,
Chapter 5, Subchapter 4, Group 3, Article 5,
Section 30285 and 30287 of the California Administra-
tive Code.
61
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SECTION VI
Bibliography
1. Great Lakes Water Quality Agreement, April 1972.
2. Federal Water Pollution Control Act Amendments
of 1972, Section 311(b)(3). 40 CFR 1110.
3. California State Water Resources Control
Board. 1972. "Water Quality Control Plan.
Ocean Water of California."
4. Adams, J.K. 1974. "The Relative effects of
Light and Heavy Oils." U.S. Environmental
Protection Agency, Division of Oil and Special
Materials Control, Washington, D.C. Pub.
•No. EPA-520/9-74-021.
5. Evans, D.R., and Rice, S.D. 1974. "Effects
of Oil and Marine Ecosystems: A Review
for Administrators and Policy Makers."
U.S. Department of the Interior,
Bulletin 72(3):pp. 625-638.
6. McKee, J.E., and Wolf, H.W. 1963. "Water
Quality Criteria." California State Water
Quality Control Board. Pub. No. 3-A.
7. Moseley, F.N., and Copeland, B.J. 1974.
"Brine Pollution System." In: "Coastal
Ecology Systems of the United States.111
Odum, Copeland, and McMahan, (ed). The
Conservation Foundation, Washington, D.C.
62
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SECTION VII
CONTROL AND TREATMENT TECHNOLOGY
Petroleum production, drilling, and exploration wastes vary
in quantity and quality from facility to facility. A wide
range of control and treatment technologies has been
developed to treat these wastes. The results of industry
surveys indicate that techniques for in-process controls and
end-of-pipe treatment are generally similar for each of the
industry subcategories; however, local factors, discharge
criteria, availability of space, and other factors influence
the method of treatment.
In-plant Control/Treatment Techniques
In-plant control or treatment techniques are those practices
which result in: 1) reduction or elimination of a waste
stream; or 2) a change in the character of the constituents
and allow the end-of-pipe processes to be more efficient and
cost effective.
Reduction or Elimination of Waste Streams
The two types of in-plant techniques that reduce the waste
load to the treatment system or to the environment are reuse
and recycle of waste products. Examples of reuse are: 1)
reinjection of produced water to increase reservoir
pressures; and 2) utilization of treated production water
(softened, if necessary) for steam generation. An example
of a recycle system is the conservation and reuse of
drilling muds.
Waste Character Change
Examples of character change in waste stream would be: 1)
the substitution of a positive displacement pump for a high
speed centrifugal pump; and 2) substitution of a downhole
choke for a well head choke, thereby reducing the amount of
emulsion created, (1)
Proper pretreatment and maintenance practices are also
effective in reducing waste flows and improving treatment
efficiencies. Return of deck drainage to the process units
and elimination of waste crankcase oil from the deck
drainage or produced water treatment systems are examples of
good offshore pretreatment and maintenance practices.
Process Technology
63
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The single most significant change in process technology is
reinjection to the reservoir formation for secondary
recovery and pressure maintenance. This is distinguished
from injection for disposal purposes only, which is
considered as end-of-pipe treatment. Waters used for
secondary recovery and pressure maintenance must be free of
suspended solids, bacterial slimes, oxygen, sludges, and
precipitates. In some cases the quantity of produced brine
is insufficient to provide the needed water for a secondary
recovery and pressure maintenance system. In this case,
additional make-up water must be found, and wells or surface
water (including sea water) may be used as a source of
make-up water. There may be problems of compatability
between produced water and make-up water. A typical
reinjection water treatment facility consists of a surge
tank, flotation cell, filters, retention tank, and injection
pumps. (2)
Reinjection of produced water for secondary recovery and
pressure maintenance is a very common practice onshore. It
has been estimated that 60 percent of all onshore produced
water is reinjected for secondary recovery.
Water treatment for reinjection at all installations is
similar, both offshore and onshore. Existing reinjection
systems vary from small units which treat 2,000 barrels per
day of brine waste to large complexes which handle over
170,000 barrels per day. Produced water reinjection systems
for presure maintenance and water flooding are less common
in the Gulf Coast, and none are in use in Cook Inlet sea,
Alaska (Cook Inlet water is treated and injected for water
flooding, because of compatibility problems with the
produced water) .
Produced water treatment and reinjection systems are not
generally limited by space availability but must be
specifically designed to fit offshore platforms. Two
limiting factors which affect produced water reinjection are
insuffiecint quantities of produced water to meet the
requirement for reservoir pressure maintenance and
incompatibility between make-up sea water and produced
water.
With the increasing oil demand, new ("tertiary") methods are
being developed to recover greater amounts of oil from
producing formations. The addition of steam or other fluids
into the formation can improve ultimate recovery. A system
which reuses produced water for steam generation is
operating on the west Coast. The system consists of a
64
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typical reinjection treatment unit with water softeners
added to the system.
Changes in process technology have also occurred in drilling
operations. Environmental considerations and high cost of
drilling muds have led to the development of special
equipment and procedures to recycle and recondition both
water-based and oil-based muds. With the system operating
properly, mud losses are limited to deck splatter and the
mud clinging to drill cuttings.
Pretreatment
The main pretreatment process which is applicable to
offshore production systems is the return of deck drainage
to the production process units to remove free oil prior to
end-of-pipe treatment. This method of pretreatment is not
applicable to facilities that flush drilling muds into the
deck drainage system during rig wash down or to facilities
that pipe all produced crude oil and water to shore for
processing and brine treatment.
Operation and Maintenance
A key in-plant control is good operation and maintenance
practices. Not only do they reduce waste flows and improve
treatment efficiencies, but they also reduce the frequency
and magnitude of systems upsets.
Some examples of good offshore operations are:
1. Separation of waste crankcase oils from deck
drainage collection system.
2. Reduction of waste water treatment system upset from
deck washdown by discriminment use of detergents.
3. Reduction of oil spillage through good prevention
techniques such as drip pans and other collection
methods.
4. Elimination of oil drainage from transfer pump
bearings or seals by pumping into the crude oil
processing system.
65
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5. Reduction of oil gathered in the pig (pipeline
scraper) traps by channeling oil back into the gathering
line system instead of the sump system.
6. Elimination of extreme loading of the produced water
treatment system, when the process system malfunctions,
by redirecting all production to shore for treatment.
(3)
Good maintenance practice includes: 1) inspection of dump
valves for sand cutting as a preventive measure; 2) use of
dual sump pumps for pumping drainage into surge tanks; 3)
use of reliable chemical injection pumps for produced water
treatment; U) selection of the best combination of oil and
water treating chemicals; and 5) use of level alarms for
initiating shut down during major system upsets. Operation
and maintenance of a produced water treatment system during
start-up presents special problems. As an example, an
offshore facility had two problems with the heater-treaters
that caused problems with the water treatment system: 1)
insufficient heat in the treaters; and 2) malfunctioning
level controls which caused excessive oil loading. A change
in the type of levels controls and reduced production which
lowered the heating requirements and helped alleviate the
problem during start-up of the produced water treatment
unit. Further improvements were achieved by careful
selection of chemicals for treating oil and produced water,
and the chemical injection and recylcing pumps were
replaced.
The preceding paragraph describes an actual case where
detailed failure analysis and corrective action ended an
upset in the waste treatment system. Evaluation of
operational practices, process and treatment equipment and
correct chemical use is imperative for proper operation and
in the prevention and detection of failures and upsets. The
description of these operation and maintenance practices is
not intended to advocate their universal application.
Nevertheless, good operations and maintenance on an oil/gas
production facility can have a substantial impact on the
loads discharged to the waste treatment system and the
efficiency of the system. Careful planning, good
engineering, and a committment on the part of operating and
management personnel are needed to ensure that the full
benefits of good operation and maintenance are realized.
Analytical Techniques and Field Verification,Studies
Data on the types of treatment equipment and. performance of
the systems in this report were provided by the industry.
66
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An early analysis of data indicated a need to both verify
the information and determine current waste handling
practices. EPA conducted a 3-week sampling verification
study for facilities off the Louisiana Coast; and 3-day
studies were conducted in Texas and California to verify
performance data. In addition, three field surveys were
made to determine the adequacy of laboratory analytical
techniques, sample collection procedures, operation and
maintenance procedures, and general practices for handling
deck drainage. Similar field surveys were made of
facilities located in Cook Inlet.
Variance in Analytical Results for Oil and Grease
Concentrations
Effluent oil and grease values in produced water recorded
and reported by the oil and gas industry are usually
determined by contracting laboratories using various
analytical methods. Analytical methods presently in use
include infrared, gravimetric, utlraviolet- fluorescence,
and colorimetric. The method used by a contractor is
usually governed by regulatory authority, the person in
charge of the laboratory, the client, or some combination of
these. For example. Department of the Interior, U. S.
Geological Survey, Outer Continental Shelf Operating Order
#8 (Gulf of Mexico area) dated October 30, 1970, specifies
to Federal leasees that oil content values for effluents
shall be determined and reported in accordance with the
American Society for Testing and Materials Method D1340,
"Oily Matter in Industrial Waste Water." A regional water
quality board in California specifies APHA Standard Methods,
13th Edition, "Oil and Grease" Test No. 137 (Gravimetric).
The U. S. Environmental Protection Agency lists the APHA
Standard for oil and grease determination under the
provisions of HO CFR Part 136 "Guidelines Establishing Test
Procedures for the Analysis of Pollutants." The manner in
which the sample is prepared for analysis is equally
critical. For example, Table 11 shows oil/grease
concentrations of acidized and unacidized samples from
facilities in California (both analyzed by the same method).
67
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TABLE 11
Effect of Acidification on
Oil and Grease Data
Oil and Grease - mg/1
Date of
Effluent_Samele _Unacidized_ Acidized
7-26-74 7.6 26.3
7-26-74 36.3 61.8
The values after pH adjustment were significantly higher
than the samples that were not acidified. One explanation
is that the acidification converts many of the water-
soluble organic acid salts to water insoluble acids that are
then extractable by hydrocarbon solvents.
The solvent used for the extraction of oil and grease from a
sample is another critical step that can affect analytical
results. For example, petroleum ether extracts all crude
oil constituents from a produced water sample except
asphaltenes or bitumen. This limitation would affect the
reported results of a sample containing high asphaltic
constituents. Other solvents used in oil/grease
determinations are trichlorotrifluroethane (Freon), hexane,
carbon tetrachloride, and methylene chloride, with each
being somewhat selective in the hydrocarbon constituents
extracted.
Reported oil/grease concentrations in waste water effluents
were highly variable within and between geographical areas.
The availabe information did not show any discernible
reason for this variability (difference in waste
treatability or treatment technology). Therfore, EPA
undertook field verification studies to determine the
reasons for the low oil/grease concentration data in the
coastal area of Texas and California as compared to
Louisiana. These field studies included sampling for
oil/grease in effluent waste water discharges and duplicate
samples were provided to the industry for independent
laboratory analysis. Table 12 and 13 compcires the results
of two analytical methods (gravimetric and infrared)
measuring Freon extractible oil/grease arid those values
determined by petroleum ether extraction using the
gravimetric method. This study was conducted by the EPA
Robert S. Kerr Research Laboratory (RSKRL) at Ada, Oklahoma.
68
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Table 12
Oil and Grease Data - Texas Coastal
Analytical Procedure Study
_Qil_and_Grease_^_m3/l_
RSKRL INDUSTRY_LABS__
Sample Freon Freon Freon
Identification Gravimetric Infrared Gravimetric
T-1I 32 45 2
T-1E 126 154 5
T-2I 372 314 178
T-2E 242 197 145
T-3I 643 695 685
T-3E 52 62 10
T-4I 1905 1736 968
T-4E 46 51 6
Table 13
Oil and Grease Data - California Coastal
Analytical Procedure Study
RSKRL INDUSTRY LABS
Sample Freon Freon Pet. Ether Pet. Ether
Identification Gravimetric _!nfra£§
-------
California appear to be more a function of the analytical
techniques and the laboratory rather than an indication of
treatibility of the waste water produced and/or treatment
equipment efficiency. This conclusion was validated by a
statistical analysis of the data, which is contained in
Supplement B. The analysis indicated a high correlation
with the results of the two analytical methods performed
within the EPA laboratory and little or no correlation with
the analytical results between the EPA and contractor
laboratories.
Field Verification Studies
The EPA Field Verification Study of Coastal Louisiana
Facilities included sampling for oil/grease in effluent
waste water discharges. Duplicate samples were provided to
the oil/gas industry for independent laboratory analysis.
The analytical results of this study, contained in
Supplement B, verified the data collected over the years by
Coastal Louisiana facilities. In addition, the study found
a very high correlation between analytical results of
contractor laboratories and the EPA laboratory.
The selection of facilities for the Gulf Coast verification
study was based on a general cross section of the production
industry and did not favor the more efficient systems.
Table 14 indicates types of treatment units, the performance
observed during the survey, and long term performance based
on historical data for each facility. Tables 15 and 16
indicate the comparative oil and grease concentration data
for Texas and California offshore facilities and onshore
treatment of offshore produced water treatment units.
70
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TABLE 14
Performance of Individual Units
Louisiana Coastal
Long Term Mean Effluent
Oil and Grease
Facility,, Identification mq/1
Flotation Cells
GFV01 22
GFV02 23
GFS03 31
GFS04 29
GFS05 32
GFT06 18
GFG07 24
GFS08
GFT09 28
GFG10 18
Parallel Plate Coalescers
GCC11 35
GCC12 66
GCM13 13
GCC14
GCG15 39
GCS16 39
GCC17 51
Loose Media Coalescers
GLG23 25
GLT24 18
Simple Gravity Separators
GPV18
GPT19
GPE20
GIM21
GTT22
GPE25
1System malfunctioning during survey.
EPA Survey Results
Oil and Grease
mg/1
23
6
25
21
32
24
30
31
13
21
78
34
52
19
56
118
12
8
13
26
19
44
63
16
71
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TABLE 15
Texas Coastal Verification Data
Facility Freon Extractibles Freon Extractibles
Identification ^aviffigtric_Method Infrared Method
Influent
T-l 32.0
28.9
830.0
49.0
199.0
36.0
T-2 333.0
372.0
301.0
327.0
352.0
286.0
T-3 1,250.0
643.0
1,626.0
154.0
667.0
1,169.0
T-4 1,583.0
921.0
1,710.0
1,844.0
1,905.0
1,007.0
Oil
:f fluent
126.0
103.0
116.0
561.0
141.0
118.0
220.0
242.0
194.0
185.0
196.0
220.0
13.0
52.0
45.0
50.0
55.0
87.0
37.0
9.0
14.0
24.0
46.0
and Grease -
Influent
45.0
57.0
1,230.0
130.0
300.0
64.0
305.0
314.0
336.0
351.0
293.0
312.0
1,350.0
695.0
1,635.0
206.0
1,242.0
1,215.0
1,520.0
1,578.0
1,677.0
1,780.0
1,736.0
1,884.0
mq/1
Effluent
154.0
134.0
232.0
827.0
304.0
277.0
209.0
197.0
198.0
204.0
188.0
237.0
55.0
62.0
60.0
66.0
81.0
84.0
42.0
9.0
14.0
27.0
51.0
72
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TABLE 16
Verification of Oil and Grease Data
California Coastal
RSKRL, Ada, Oklahoma
Facility
Identification
Freon
Extractibles,
Gravimetric
Method , mg/1
Influent Effluent
Freon
ExtractibleSj
Infrared
Method, mg/1
Influent Effluent
Petroleum Ether
Extractibles,
Gravimetric
Method, mg/1
Influent Effluent
01
O-l
C-2
C-3
04
112.3
97.4
110.7
106.1
359.6
363.6
215.6
599.8
881.1
165.6
163.2
202.2
167.6
56.7
28.9
43.1
26.0
22.3
42.2
44.0
53.5
51.6
55.4
54.0
4-4.3
51.7
46.1
19.1
24.2
19.9
94.0
101.0
122.0
126.0
437.0
446.0
323.0
851.0
1,214.0
188.0
148.0
206.0
197.0
58.0
18.0
18.0
18.0
16.0
39.0
40.0
54.0
47.0
53.0
39.0
34.0
37.0
35.0
16.0
15.0
15.0
6.0
90.0
76.0
241.0
193.0
172.0
462.0
611.0
83.0
100.0
141.0
5.0
27.0-
13.0
19.0
51.0
14.0
23.0
22.0
71.0
7.0
55.0
59.01
102.O1
6.0J
1. Carbon tetrachloride extractibles.
-------
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. Simple treatment systems may
consist of only gravity separation pits without the addition
of chemicals, while more complex systems may include surge
tanks, clarifiers, coalescers, flotation units, chemical
treatment, or reinjection.
Gas Flotation
In a gas flotation unit gas bubbles are released into the
body of waste water to be treated. As the bubbles rise
through the liquid, they attach themselves to any oil
droplet 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: 1) Dispersed gas flotation - these units use
specially shaped rotating mines 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 waste
water flows from one cell to the next, with a net oil
removal in each cell (some oil is recycled back into the
water phase by the rotor action). 2) Dissolved gas
flotation - these units differ from the dispersed gas
flotation because the gas bubbles are created by a change in
pressure which lowers the dissolved gas solubility,
releasing tiny bubbles. A portion of the waste water stream
is recycled back to the bottom of the cell after waste water
has been gassified. This gassification is accomplished by
passing the waste water through a pump to raise the pressure
and then through a contact tank filled with gas. The waste
water leaves the contact tank with a concentration of gas
equivalent to the gas solubility at the elevated pressure.
When the recycled (gassified) water is released in the
bottom of the cell (at atmospheric pressure) the solubility
of the gas decreases and the excess gas is released as
microscopic bubbles. These bubbles then rise to surface
contact the oil and bringing it ot the surface where it is
skimmed off. Dissolved gas flotation units are usually a
single cell only.
74
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CRUDE OIL PRODUCTION PROCESSING
en
„
LOW PRESSURE OIL*
INTERMEDIATE
PRESSURE OIL
WELL
Kh
HIGH
PRESSURE
SEPARATOR
HEAT
PROCESS OIL-
WATER SEPARATION
(HEATER TREATER,
CHEMICAL, ELEC
TRICAL,
GUN BARREL, FREE
WATER KNOCK OUT,
ETC )
OIL TO SALES
BRINE
SURGE TANK,
SKIMMER TANK
HIGH PRESSURE
OILWELL
OIL AND BRINE
SKIMMED OIL RECYCLE
CHEMICAL INJECTION
FROM
GAS
FLOTATION
WASTE WATER TO EITHER
1
L-
:
X
O
ROTOR-DISPERSERS
p n n n
CD\,
/ -
Jo J= > ^2^
Y
SKIMMED OIL RECYCLE TO PROCESS SEPARATION
DISCHARGE
-.OVERBOARD _
FLOTATION
UNIT
SKIMMED OIL RECYCLE
GAS OR AIR
AND CHEMICALS
rn
CONTACT
I I TANK
»
ROTOR-DISPERSER GAS FLOTATION PROCESS DISSOLVED GAS FLOTATION PROCESS
Fig. 6 -- ROTOR-DISPERSER AND DISSOLVED GAS FLOTATION PROCESSES
FOR TREATMENT OF PRODUCED WATER
-------
On production facilities it is usual practice to recycle the
skimmed oily froth back through the production oil-water
separating units. A flow diagram of the two typical
flotation units is shown in Figure 6.
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. Other develop a floe which eases the capture
of oil droplets, gas bubbles, and fine suspended solids,
making treatment more effective.
In addition to the use of chemicals to increase the
effectiveness of gas flotation systems, surge tanks upstream
of the treatment unit also increase its effectiveness. The
period of quiescence provided by the surge tank allows some
gravity separation and coalescence to take place, and
dampens out surges in flow from the process units. This
provides a more constant hydraulic loading to the treatment
unit, which, in turn, aids in the oil removal process.
The verification survey conducted on Coastal Louisiana
facilities included 10 flotation systems which varied in
design capacities form 5,000 to 290,000 barrels-per-day and
included both rotor/disperser and dissolved gas units. The
designs of waste treatment systems are basically the same
for both offshore platform installations and onshore
treatment complexes; however, parallel units are provided at
two of the onshore installations, permitting greater
flexibility in operations.
Information obtained during the field survey of onshore
treatment systems for Cook Inlet indicated that one of the
four onshore systems utilized a dissolved gas flotation
system comparable to those used in the Gulf Coast. This
system provides physical/chemical treatment and consists of
a surge tank, chemical injection, and a dissolved air
flotation unit. In addition, two of the Cook Inlet
platforms use flotation cells for treatment of deck drain
wastes.
Field surveys on the west Coast found that physical/chemical
treatment is the primary method of treating produced water
for either discharge to coastal waters or for reinjection
and that flotation is the most widely used of the
physical/chemical methods. On the West Coast, all treatment
systems except one are located onshore and produced fluids
are piped to these complexes. The majority of the waste
water treatment systems have been converted to reinjection
systems. However, some of those that still discharge are
76
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somewhat different from the systems in the Gulf Coast and
Cook Inlet. One of the more complex onshore systems
consists of pretreatment and grit settling, primary
clarification, chemical addition (coagulating agent),
chemical mixing, final clarification, aeration,
chlorination, and air flotation. This system handles 50,000
barrels-per-day.
Parallel Plate Coalescers
Parallel plate coalescers are gravity separators which
contain a pack of parallel, tilted plates arranged so that
oil droplets passing through the pack need only rise a short
distance before striking the underside of the plates.
Guided by the tilted plate, the droplet then rises,
coalescing with other droplets until it reaches the tip of
the pack where channels are provided to carry the oil away.
In their overall operation, parallel plate coalescers are
similar to API gravity oil water separators. The pack of
parallel plates reduces the distance that oil droplets must
rise in order to be separated; thus the unit is much more
compact than an API separator. Suspended particles, which
tend to sink, move down a short distance when they strike
the upper surface of the plate; then they move down along
the plate to the bottom of the unit where they are deposited
as a sludge and can be periodically drawn off. Particles
may become attached (scale) to the plate surface of the
plate; then they move down along the plate surfaces,
requiring periodic removal and cleaning of the plate pack.
Where stable emulsions are present, or where the oil
droplets dispersed in the water are relatively small, they
may not separate in passing through the unit.
The verification survey of Coastal Louisiana facilities
included seven plate coalescer systems which had design
capacities from 4,500 to 9,000 barrels-per-day. A recent
survey indicated that approximately 10 percent of the units
in this area were plate coalescers and they treated about 9
percent of the total volume of produced water in offshore
Louisiana waters. (4) Both the long-term performance data
and the verification survey indicated that performance of
these units was considerably poorer than that of flotation
units. In addition to the physical limitations, coalescers1
operation and maintenance data indicated that the units
require frequent cleaning to remove solids.
No plate coalescers are in use in Cook Inlet or on the West
Coast.
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Filter Systems (Loose or Fibrous Media Coalescers)
Another type of produced water treatment system is filters.
They may be classified into two general classes based on the
media through which the waste stream passes.
1. Fibrous media, such as fiberglass, usually in the
form of a replacable element or cartridge.
2. Loose media filters, which normally use a bed of
granular material such as sand, gravel, and/or crushed coal.
Some filters are designed so that some coalescing and oil
removal take place continuously, but a considerable amount
of the contaminants (oil and suspended fines) remain on the
filter media. This eventually overloads the filter media,
requiring its replacement or backwashing. Fibrous media
filters may be cleaned by special washing techniques or the
elements may simply be disposed of and a new element 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
gassifying and loosening the media bed.
Filters which require backwashing present somewhat of a
problem on platforms because the valving and controls need
regular maintenance and 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 (provided that the units are
backwashed sufficiently often); however, problems of
excessive maintenance and disposal have caused the industry
in the Gulf Coast to move away from this type of unit, and a
number of them have been replaced with gas flotation
systems.
The Gulf Coast survey information indicated that when filter
systems are used there is no initial pretreatment of the
waste other than surge tanks. Backwashing, disposal of
solids, and complex instrumentation were .reported as the
main problem with these units.
On the West Coast and Cook Inlet, no filter systems are in
use as the primary treatment method. Filters are however,
used for final treatment in injection systems in California
and several steps of filtration are used prior to sea water
injection in Cook Inlet. On the West Coast, these units are
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preceded by a surge tank, flotation unit, and other
treatment units which remove most of the oil and suspended
particles. These units, when used in series with other
systems, perform well.
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, pits, and, occasionally,
barges are used as gravity separation vessels. Large
volumes of storage to permit sufficient retention times are
characteristic of these systems. Performance is dependent
upon the characteristics of the waste water, water volumes,
and availability of space. While total gravity separation
requires large containers and long retention times, any
treatment system can benefit from quiescent retention prior
to further treatment. This retention allows some gravity
separation and dampens surges in volume and oil contact.
About 75 percent of the systems on the Gulf Coast are
gravity separation systems. The majority are located
onshore and have limited application on offshore platforms
because of space limitations. Properly designed,
maintained, and operated systems can provide adequate
treatment. A 30,000-barrel-per-day gravity system with the
addition of chemicals produced an effluent of less than 15
mg/1 during the verification survey.
Two of the onshore treatment systems in Cook Inlet use
gravity separation with various configurations of settling
tanks and pits. No gravity systems were reported to be in
use on the West Coast. The four installations visited in
the Texas verification study all use gravity separation
tanks offshore and a combination of tanks and/or pits
onshore.
Chemical Treatment
The addition of chemicals to the waste water stream is an
effective means to increase the efficiencies of treatment
systems. Pilot studies for a large onshore treatment
complex in the Gulf of Mexico indicated that addition of a
coagulating agent could increase efficiencies approximately
15 percent and the addition of a polyetectrolyte and a
coagulating chemical could increase efficiencies 20 percent.
(5)
Three basic types of chemicals are used for waste water
treatment and, many different formulations of these
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chemicals have been developed for specific applications.
The basic types of chemicals used are:
1. Surface Active Agents - These chemicals modify the
interfacial tensions between the gas, suspended solids, and
liquid. They are also referred to as surfactants, foaming
agents, demulsifiers, and emulsion breakers.
2. Coagulating Chemicals - Coagulating agents assist
the formation of floe and improve the flotation or settling
characteristics of the suspended particles. The most common
coagulating agents are aluminum sulfate and ferrous sulfate.
3. Polyelectrolytes - These chemicals are long chain,
high molecular weight polymers used to assist in removal of
colloidal and extremely fine suspended solids.
The results of two EPA surveys of 33 offshore facilities
using chemical treatment in the Gulf Coast disclosed the
following:
1. Surface active agents and polyelectrolytes are the
most commonly used chemicals for waste water treatment.
2. The chemicals are injected into the waste water
upstream from the treatment unit and do not require
premixing units.
3. Chemicals are used to improve the treatment
efficiencies of flotation units, plate coalescers, and
gravity systems.
4. Recovered oil, foam, floe, and suspended particles
skimmed from the treatment units are returned to the process
system.
A similar survey of facilities in Cook Inlet, Alaska
indicated that a facility uses coagulating agents and
polyelectrolytes to improve treatment efficiency. Recovered
oil and floe are returned to the process system.
Chemical treatment procedures on the West Coast are similar
to those used in the Gulf Coast and Cook Inlet. However,
there are exceptions where refined clays and bentonites are
added to the waste stream to absorb the oil and both are
removed after addition of a high molecular weight nonionic
polymer to promote flocculation. The oil, clay, and other
suspended particles removed from the waste stream are not
returned to the process system but are disposed of at
approved land disposal sites. A 14,000-barrel-per-day
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treatment system using refined clay was reported to have
generated 60 barrels-per-day of oily floe which required
disposal in a State approved site. Selection of the proper
chemical or combination of chemicals for a particular
facility usually requires jar tests, pilot studies, and
trial runs. Adjustments in chemicals used in the process
separation systems may also require modification of
chemicals or application rate in the waste stream. Other
chemicals may also be added to reduce corrosion and
bacterial growths which may interfere with both process and
waste treatment systems.
Effectiveness of Treatment Systems
Table 17 gives the relative long term performance of
existing waste water treatment systems. The general
superiority of gas flotation units and loose media filters
over the other systems is readily apparent. However,
individual units of other types of treatment systems have
produced comparable effluents.
TABLE 17
Performance of Various Treatment Systems
Louisiana Coastal
Mean Effluent, No. of Units
Oil and Grease in Data
Type_Treatment System IDS/I Base
Gas Flotation 27 27
Parallel Plate Coalescers 48 31
Filters
Loose Media 21 15
Fibrous Media 38 7
Gravity Separation (4)
Pits 35 31
Tanks 42 48
Zero Discharge Technologies
Water produced along with liquid or gaseous hydrocarbons may
vary in quantity from a trace to as much as 98 percent of
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the total fluid production. Its quality may range from
essentially fresh to solids-saturated brine. The no
discharge control technology for the treatment of raw waste
water after processing varies with the use or ultimate
disposition of the water. The water may be:
1. Discharged to pits, ponds, or reservoirs and
evaporated.
2. Injected into formations other than their place of
origin.
Evaporation
In some arid and semiarid producing areas, use of
evaporation is acceptable, although limited in its practice.
The surface pit, pond, or reservoir can only be used where
evaporation rates greatly exceed precipitation and the
quantity of emplaced water is small. The pit or pond is
ordinarily located on flat to very gently rolling ground and
not within any natural drainage channel, so as to avoid
danger of flooding. Pit facilities are normally lined with
impervious materials to prevent seepage and subsequent
damage to fresh surface and subsurface waters. Linings may
range from reinforced cement grout to flexible plastic
liners. Materials used are resistant to corrosive
chemically-treated water and oily waste water. In areas
where the natural soil and bedrock are high in bentonite,
montmorillonite, and similar clay minerals which expand upon
being wetted, no lining is normally applied and sealing
depends on the natual swelling properties of the clays. All
pits are normally enclosed to prohibit or impede access.
In much of the Rocky Mountain oil and gas producing area,
the total dissolved solids of the produced waters are
relatively low. These waters are discharged to pits and put
to use for local farmers and ranchers by irrigating land and
watering stock. A typical produced water system widely in
use is shown in Figure 7. A cross section of: the iddivinual
pit is shown in Figure 8.
A producing oil field in Nevada discharges produced water to
a closed saline basin. The basin contains no known surface
or subsurface fresh water and is normally dry. The field
contains 13 wells and produces approximately 33 barrels of
brine per well per day.
Subsurface Disposal
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DETAIL MAP
TREATER
I IFWKO
OHEADER
SAMPLE POINT
DISCHARGE
500 BBL
WATER
SETTLING
TANK
500 BBL
OIL STORAGE
TANKS
LACT
Fig. 7 ~ ONSHORE PRODUCTION FACILITY WITH
DISCHARGE TO SURFACE WATERS
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DIMENSIONS VAUY FOB VOLUME NEEDED
DEPTH WILL VABY WITH
OPERATIONS CONDITIONS
NOTE
PITS ARE EQUIPPED WITH PIPE DRAINS FOR SKIMMING OPERATIONS
TO OBTAIN OIL-FREE WATER DRAINAGE
Fig. g — TYPICAL CROSS SECTION UNLINED EARTHEN
OIL-WATER PIT
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Injection and disposal of oil field produced water
underground is practiced extensively by the petroleum
industry throughout the United States. The term "disposal"
as used here refers to injection of produced fluids,
ordinarily into a formation foreign to their origin. This
injection is for disposal only and plays no intentional part
in secondary recovery systems. (Injection for pressure
maintenance or secondary recovery refers to the emplacement
of produced fluids into the producing formation to stimulate
recovery of additional hydrocarbons and is not considered
end-of-pipe treatment.) Current industry practice is to
apply minimal or no treatment to the water prior to
disposal. If water destined for disposal requires
treatment, it is usually confined to the application of a
corrosion inhibitor and bactericide; a sequestering agent
may be added to waters having scaling tendencies. The
amount of treatment depends on the formation properties,
water characteristics, and the availability and cost of
storage and stand-by wells.
Corrosion is ordinarily caused by low pH, plus dissolved
gasses. Bactericides serve to inhibit the development of
sulfate-reducing and slime producing organisms. Chemicals
and bactericides are frequently combined into a single
commercial product and sol5 under various trade names. (6)
A wide range of stable, semipolar, surface-active organic
compounds have been developed to control corrosion in oil
field injection and disposal systems. The inhibitors are
designed to provide a high degree of protection against
dissolved gasses (carbon dioxide, oxygen, and hydrogen
sulfide), organic and mineral acids, and dissolved salts.
The basic action of the inhibitors is to temporarily "plant"
or form a film on the metal surfaces to insulate the metal
from the corrosive elements. The life of the film is a
function of the volume and velocity of passing fluids.
Inhibitors may be water soluble or dispersible in fresh
water or brine. They may be introduced full strength or
diluted. Treatment, usually in the range of 10 to 50 parts
per million, may be continuous or intermittent (batch or
slug). Effectiveness of corrosion inhibition is determined
in several ways, including corrosion coupons, hydrogen
probes, chemical analyses, and electrical resistivity
measurements.
Three primary types of bacteria attach oil field injection
and disposed systems and cause corrosion:
1. Anaerobic sulfate-reducing bacteria
(Desulfovibrio—desulfuricans). These bacteria promote
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corrosion by removing hydrogen from metal surfaces, thereby
causing pitting. The hydrogen then reduces sulfate ions
present in the water, yielding highly corrosive hydrogen
sulfide, which accelerates corrosion in the injection or
disposal system.
2. Aerobic slime-forming bacteria. These may grow in
great numbers on steel surfaces and serve to protect growths
of underlying sulfate-reducing bacteria. In extreme
instances, great masses of cellular slime may be formed
which may plug filters and sandface.
3. Aerobic bacteria that react with iron. Sphaerotilus
and Gallionella convert soluble ferrous iron in injection
water to insoluble hydrated ferric oxides, which in turn may
plug filters and sandface. Oxygen entry into a system may
also cause the formation of ferric oxide.
Treatment to combat bacterial attack ordinarily consists of
applying either a continous injection of 10 to 50 ppm
concentration of a bactericide or batching once or twice a
week.
Scale inhibitors are commonly used in the injection or
disposal system to combat the development of carbonate and
sulfates of calcium, magnesium, barium, or strontium. Scale
solids precipitate as a result of changes in temperature,
pressure, or pH. They may also be developed by combining of
waters containing high concentrations of calcium,
magnesium, barium, or strontium with waters containing high
concentrations of bicarbonate, carbonate, or sulfate. Scale
inhibitors are basically chemicals which chelate, complex,
or otherwise inhibit or sequester the scale-forming cations.
The most widely used scale sequestrants are inorganic
polymetaphosphates. Relatively small quantities of these
chemicals will prevent the precipitation and deposition of
calcium carbonate scale. Bimetallic phosphates or the
so-called "controlled solubility" varieties are now widely
used by the oil industry in scale control arid are preferred
over the polyphosphates.
The downhole completion of a typical injection well is shown
in Figure 9. A producing well is shown for comparison.
Injection wells may be completed in a complicated fashion
with multiple strings of tubing, each injected into a
separate zone. If the disposal well is equipped with a
single tubing string, and injection takes place through
tubing separated from casing by packer. The annular space
between tubing and casing is filled with noncorrosive fluids
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INJECTION WELL
PRODUCING WELL
oo
O
PROTECTED WITH
CASING AND CEMENT
INJECTION SAND
PROTECTED WITH OIL
STRING AND CEMENT
TYPICAL COMPLETION OF AN INJECTION WELL AND A PRODUCING WELL
-------
such as low-solids water containing a combination corrosion
inhibitor bactericide, or hydrocarbons such as kerosene and
diesel oil. All surface casing is cemented to the ground
surface to prevent contamination of fresh water and shallow
ground water. Pressure gauges are installed on the casing
head, tubing head, and tubing to detect anomalies in
pressure. Pressure may also be monitored by continous clock
recorders which are commonly equipped with alarms and
automatic shutdown systems if a pipe ruptures.
The injection well designed for pressure maintenance and
secondary recovery purposes is completed in a manner
identical to that of the disposal well, except that
injection is into the producing horizon. Treatment prior to
injection may vary from that applied to the disposal well in
as much as water injected into the reservoir sandface must
be as free of suspended solids, bacterial slimes, sludges,
and precipitates as is economically possible. Ordinarily,
selection of injection well sites poses few if any
environmental problems. In many instances where injection
is -used for secondary recovery, the well site is fixed by
the geometry of the waterflood configuration and cannot be
altered.
Water for injection into oil and gas reservoirs requires
treatment facilities and processes which yield clear,
sterile, and chemically stable water. A typical open
injection water treatment system includes a skim pit or tank
(steel or concrete equipped with over-and-under baffles to
remove any vestiges of oil remaining after pretreatment); an
aeration facility, if necessary to remove undesirable gasses
such as hydrogen sulfide; a filtering system; seepage-proof
backwash pit; accumulator tank (sometimes referred to as a
clear well or clear water tank) to retain the finished water
prior to injection; and a chemical house for storing and
dispensing treatment chemicals.
In the system described above no attempt is made to exclude
air. Closed systems, on the other hand, are designed to
exclude air (oxygen). This is desirable because the water
is less corrosive or requires less treatment to make it
noncorrosive. The truly "closed" system is difficult to
attain because of the many potential points of entry-of air
into the production system. Air, for example, can be
introduced into the system on the downstroke of a pumping
well through worn stuffing box packing or seals. In a few
instances, closed injection (or disposal) system is used
where product waters ordinarily have minimal corrosive
characteristics. That is, where salt water is gathered from
relatively few wells, fairly close together; where wells
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produce from a common reservoir; or where a one-owner
operation is involved.
There are instances in which a closed input or produced
water disposal system can be developed. In these systems
all vapor space must be occupied by oxygen-free gas under
pressure greater than atmospheric. If oxygen (air) enters
the system, it is scavenged.
The "open" injection system has a much greater degree of
operational flexibility than does the closed system. Amona
its more desirable factors are:
1. Wider range, type, and control of treatment methods.
2. Ability to handle greater quantities of water from
different sources (diverse leases and fields) and differing
formations. y
3. Ability to properly treat waters of differing
composition. This factor enables incompatible waters to be
successfully combined and treated on the surface prior to
injection.
Disposal Zone
The choice of a brine disposal zone is extremely important
to the success of the injection program. Prior to planning
a disposal program, detailed geologic and engineering
evaluations are prepared by the production divisions of oil
producing companies. Appraisal of the geologic reservoir
must include the answers to questions such as:
1. How much reservoir volume is available?
2. Is the receiving formation porous and permeable?
3. what are the formation's physical and chemical
properties?
H. What geological, geochemical and hydrologic controls
govern the suitability of the formation for injection or
disposal?
5. What are the short-term and long-term environmental
consequences of disposal?
The geologic age of significant disposal and injection
reservoirs throughout the nation, ranges from relatively
young rocks of the Cenozoic-Eocene period to older rocks of
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Cambro- Ordovician period. Depths of disposal zones
oridinarily range from only a few hundred feet to several
thousand. However, prudent operators usually consider it
inadvisable to inject into formations above 1,000 feet,
particularly where the receiving formation has low
permeability and injection pressures must be high. If the
desired daily average quantity of water cannot be disposed
of, except at surface pressures which exceed 0.5 pounds per
square inch surface guage pressure per foot of depth to the
disposal zone, particularly in shallow wells, an alternate
zone is usually sought.
It is necessary to be familiar with both the lithology and
water chemistry of the receiving formation. If interstitial
clays are present, their chemical composition and
compatibility with the injected fluid must be determined.
The fluids in the receiving zone must be compatible with
those injected. Chemical analysis are performed on both to
determine whether their combination will result in the
formation of solids that may tend to plug the formation.
The petroleum industry recognizes that the most carefully
selected injection equipment means nothing if the disposed
water is not confined to the formation into which it is
placed. Consequently, the injection area must be thoroughly
investigated to determine any previously drilled holes.
These include holes drilled for oil and gas tests, deep
stratigraphic tests, and deep geophysical tests. If any
exist, further information as to method of plugging and
other technological data germane to the disposal project is
assembled and evaluated.
On the California Coast there is a definite trend for all
onshore process systems which handle offshore production
fluids to reinject produced water for disposal. Field
investigations made in California were confined to OCS
waters, with visits being made to five installations. Each
of these facilities were performing some subsurface
disposal; none were injecting for secondary recovery or
pressure maintenance. Four of these installations were
sending all or part of the produced fluids to shore for
treatment. All five installations were disposing of treated
water in wells on the platform. Two were sending all fluids
to shore, separating the oil and water, and then pumping the
treated water back to the platforms for disposal. One
installation was separating the oil and water on the
platform and further treating the water so that it could be
injected into disposal wells on the platform. Two of the
platforms had been treating all fluids on the platform and
injecting treated water. Since the total fluids produced
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are presently greater than the capacity of the disposal
system, the excess treated water is being discharged
overboard. Plans were being formulated to increase the
capacity of the disposal system to return all produced water
underground.
Produced water disposal is commonly handled on a cooperative
or commercial basis, with the producing facility paying on a
per-barrel basis. The disposal facility may be owned and
operated by an individual, a cooperative association, or a
joint interest group who may operate a central treatment or
disposal system. The waste water may be trucked or piped to
the facility for treatment and disposal. Two examples of
cooperative systems are operating in the East Texas Field
and the Signal Hill and Airport Fields at Long Beach,
Calfornia.
Treatment System By-Pass
During major breakdown and overhaul of waste treatment
equipment, it is common practice to continue production and
by pass the treatment units requiring repair. This does not
create a serious problem at large onshore complexes where
dual treatment units are available, but at smaller
facilities and on offshore platforms there is usually no
alternate unit to use. By-pass practices (discharge to
surface water) vary considerably from facility to facility.
The following methods are currently practiced offshore:
1. Discharge overboard without treatment.
2. Discharge after removal of free oil in surge tank.
3. Discharge to a sunken pile with surface skimmer to
remove free oil.
Offshore practices to avoid discharge to surface waters
during upset conditions include:
1. Discharge of produced water to oil pipeline for onshore
treatment.
2. Retention on the facility using available storage.
3. Production shutdown.
The method used depends upon the design and system
configuration for the paricular facility.
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End-of-Pige Technology for Wastes Other than Produced Water
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 production water. Platforms in California pipe
the deck drainage and deck washings along with produced
fluids to shore for treatment. In Cook Inlet, these wastes
are be treated on the platform.
Field investigations conducted on platforms at Cook Inlet
indicate 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 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.
Sand Removal
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 manifolds 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.
Field investigations have indicated that some Gulf Coast
facilities have sand removal eguipment 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.
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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 concentration of the
transferred water was less than 1 ppm of the total volume
discharged. (6)
Drilling Muds and Drill Cuttings (Offshore)
Oil and gas drilling operations, including exploratory
drilling, are accomplished offshore with the use of mobile
drilling rigs. These drilling units are either
self-propelled or towed units that are held over the
drilling site by anchors or supported by the ocean floor.
The wastes generated from drilling operations are drilling
fluids or "muds" used in the drilling process, rock cuttings
removed from the wellbore by the drilling fluids, and
sanitary wastes from human activity.
Both water based and oil muds are used. (10) In-plant
control techniques and drilling mud practices are affected
by the type of mud used. Conventional mud handling
equipment is used for water-based muds. Some of the
water-based muds are discharged into the surface waters,
with no special control measures other than routine
conservation and safety practices. Operation and
maintenance procedures on drilling rigs using water-based
muds are routine housekeeping practices associated with
cleanliness and safety. A conventional drilling mud system
for water-based muds consists of a circulating system
including pumps and pipes, mud pits, and accessory
conditioning equipment (shale shakers, desanders, desilters,
degassers).
In-plant control techniques for oil muds are much more
restrictive. They are not discharged into surface waters.
The in-plant practices include mud saving containers on
board, in addition to the conventional mud handling system.
Operations and maintenance practices on rigs using oil muds
generally reflect spillage prevention and control measures,
such as drill pipe and kelly wipers, and catchment pans.
Cuttings from drilling operations are disposed into surface
waters when water-based muds are used. However, cuttings
from oil mud drilling are usually collected and transported
to shore for disposal. Another method is to collect
cuttings, clean them with a solvent-water mixture, and
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subsequently dispose of the washed cuttings into the surface
water body. After washing, the solvent-water is transferred
to shore or contained in a closed liquid recovery system.
(11)
Drilling Muds and Drill Cuttings (Onshore)
With onshore drilling, the discharge from shale shakers,
desilters, and desanders is placed in a large earthen pit.
When drilling operations terminate, the pit is backfilled
and graded over. Remaining muds, either oil or water-based,
are reclaimed.
Well Treatment
Acidizing and fracturing performed as part of remedial
service work on old or new wells can produce wastes.
Additionally, the liquids used to kill a well so that it can
be serviced might create a disposal problem.
Spent acid and fracturing fluids usually move through the
normal production system and through the waste water
treatment systems. The fluids therefore do not appear as a
discrete waste source. Their presence, however, in the
waste treatment system may cause upsets and a higher oil
content in the discharge water.
Liquids used to kill wells are normally drilling mud, water,
or an oil such as diesel oil. If oil is used it is
recovered because of its value, either by collecting it
directly or by moving it through the production system. If
the killing fluid is mud it will be collected for reuse or
discharged as described earlier in this section. If water
is used it will be moved through the production and
treatment systems and disposed of.
Sanitary (Offshore)
The volume and concentration of sanitary wastes vary widely
with time, occupancy, platform characteristics, and
operational situation. The waste water primarily contains
body waste but, depending upon the sanitary system for the
particular facility, other waste may be contained in the
waste stream. Usually the toilets are flushed with fresh
water but, in some cases brackish water or sea water is
used.
The concentrations of waste are significantly different from
those for municipal domestic discharges, since the offshore
operations require regimented work cycles which impact waste
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concentrations and cause fluctuation in flows. Waste flows
have been found to fluctuate up to 300 percent of the daily
average, and BOD concentrations have varied up to 400
percent. (12)
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 facilities for treatment. Offshore facilities usually
treat waste at the source. The treatment systems presently
in use may be categorized 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 ignition
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.
A much more complex physical/chemical system that has been
installed at an offshore platform in Cook Inlet consists of:
primary solids separation; chemical feed; coagulation;
sedimentation; sand filtration; carbon adsorption; and
disinfection. All solids and sludge are incinerated.
Because of start-up difficulties, no data is available for
this facility.
It has been reported that physical/chemical sewage treatment
systems have performed well in testing on land, but offshore
they have developed problems associated with the unique
offshore environment including abnormal waste loadings and
mechanical failure due to weather exposure. (12)
The most common 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 particles; an aeration
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tank with air diffusers; a gravity clarifier return sludge
system; and a tank. These biological waste treatment
systems have proven to be technically and economically
feasible means of waste treatment at offshore facilities
which have more than ten occupants and are continously
manned.
Because of the special characteristics of sanitary waste
generated by offshore operations, the design parameters in
Table 18 have been recommended. Table 19 shows average
effluent concentrations for various types of treatment units
which are in use at offshore facilities in the coastal
waters of Louisiana.
96
-------
TABLE 18
Design Requirements
for Offshore Sanitary Wastes (13)
Design Requirement
Per_Capita_PerJDay
BOD 0.22 Ib
5
Total Suspended Solids 0.15 Ib
Flow 75 gal
TABLE 19
Average Effluents of Sanitary Treatment Systems
Louisiana Coastal (13)
Company
A
B
C
D
E
No. of Units
11
6
17
9
6
BOD
5
mc[/l
35
13
15
25
86
Suspended
Solids
mg/1
24
39
43
36
77
Chlorine
Residual
mg/1
1.2
1.8
1.9
2.5.
1.3
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.
97
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SECTION VII
Bibliography
1. University of Texas-Austin, Petroleum Extension Service,
and Texas Education Agency Trade and Industrial Service,
1962. "Treating Oil Feild Emulsions." 2nd. ed. rev.
2. Offshore Operators Committee, Technical Subcommittee.
1974. "Subsurface Disposal For Offshore Produced Water
- New Source, Gulf of Mexico." New Orleans, Louisiana.
3. U.S. Environmental Protection Agency, National
Environmental Research Center, Raleigh, North Carolina.
1973. "Petroleum Systems Reliability Analysis." Vol.
II: Appendices. Prepared by Computer Sciences
Corporation under Contract No. 68-01-0121.
4. Offshore Operatiors Committee, Sheen Technical
Subcommittee. 1974. "Determination of Best Practicable
Control Technology Currently Available To Remove Oil
From Water Produced With Oil and Gas." Prepared by
Brown and Root, Inc., Houston, Texas.
5. Sport, M.C. 1969. "Design and Operation of Gas
Flotation Equipment for the Treatment of Oilfield
Produced Brines." Paper presented at the Offshore
Technology Conference, Houston, Texas, May 18-21, 1969.
Preprint No. OTC 1051, Vol. 1: 111-145 1-152.
6. Sawow, Rondal D. 1972. "Pretreatment of Industrial
Waste Waters for Subsurface Injection" and, "Undergound
. Waste Management and Environmental Implications." In:
AAPG Memoir 18, pp.93-101.
7. Hanby, Kendall P., Kidd, Robert E., and LaMoreaux, P.E.
1973. "Subsurface Disposal of Liquid Industrial Wastes
in Alabama." Paper presented at the Second
International Symposium on Underground Waste Management
and Artificial Recharge, New Orleans, Louisiana,
September 26-30, 1973.
8. Ostroff, A.G. 1965. "Introduction to Oil Field Water
Technology." Prentice Hall, Inc.
9. McKelvey, V.E. 1972. "Underground Space — An
Unappraised Resource." In: "Underground Waste
Management and Environmental Implications." AAPG Memoir
18, pp. 1-5.
98
-------
10. Hayward, B.S., Williams, R.H., and Methven, N.E. 1971.
"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.
11. Cranfield, J. 1973. "Cuttings Clean-Up Meets Offshore
Pollution Specifications." Petrol. Petrochem. Int., Vol
13: No. 3, pp. 54-56, 59.
12. Martin, James C. 1973. "Domestic Waste Treatment in
the Offshore Environment." Paper presented at the 5th
Annual Offshore Technology Conference. Preprint No. OTC
A. f J / •
13. U.S. Department of the Interior. "Sewage Effluent
Data." (Unpublished Report) August 16, 1972.
99
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SECTION VIII
COST, ENERGY, AND NONWATER-QUALITY ASPECTS
This section will discuss the costs incurred in applying
different levels of pollution control technology. The
analysis will also describe energy requirements,
nonwater-quality aspects and their magnitude, and unit costs
for treatment at each level of technology. Treatment cost
for small, medium, and large oil and gas producing
facilities have been estimated for BPCT, BAT, and new
sources end-of-pipe technologies. For existing facilities
in the oil and gas extraction industry presently discharging
formation water, the estimated capital cost required to
comply with BPCT effluent limitation by 1977 is $147,307,000
and the annual costs for debt service, depreciation,
operation and maintenance, and energy are $43,609,000.
Cost Analysis
Section IV discusses the major categories of industry
operations or activities and identifies subcategories within
each one. For purposes of cost analysis of end-of-pipe
treatment three waste streams are considered — produced
water with discharge, produced water reinjected, and
sanitary wastes. The cost of water treatment or disposal is
significantly affected by availability of space. The cost
analysis has therefore been subdivided into two areas;
offshore water disposal and onshore water disposal. Deck
drainage is considered to be treatable with the production
water. Water-based drilling muds are not presently treated
and oil-based muds are reused. In some instances, the
produced water is transferred to shore along with the crude,
while in others the waste treatment system is installed on
the platforms. Therefore, not all platforms will need to
add all of the treatment equipment or incur all of the
incremental costs indicated to bring their raw discharges
into compliance with the effluent limitations. Existing
water treatment systems include sumps and sump piles, pits,
tanks, plate coalescers, fibrous and loose media coalescers,
flotation systems and reinjection systems.
Qffshgre Produced Water Disposal
The systems currently used or needed for the treatment of
process waste water (formation water) resulting from the
production of oil and gas involve physical separation,
sometimes aided by chemical application, prior to discharge.
Shallow well injection has also been successfully used for
101
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disposal of produced wastes at onshore locations and at
several offshore locations in California.
The methods examined for offshore use include the following
arrangement of components:
Al Gravity separation using tanks, then discharge to
surface water.
A2 Gravity Separation using plate coalescers, then
discharge to surface water.
B Separation by coalescence, using flotation
equipment, then discharge to surface water.
C Separation by coalescence, using flow equilization
(surge tanks), desanders, and flotation, then
discharge to surface water.
D Separation using filters, then discharge to surface
water.
E1 Separation using flow equalization (surge tank) and
filter with disposal by shallow well injection.
E2 Separation using flow equalization (surge tank)
desanders and filters, with disposal by shallow
well injection.
The data available for analysis suggest sizing treatment
facilities for produced water based on these flow rates
(barrels per day): 200, 1000, 5000, 10,000, 40,000. Where
flow equalization is provided for the above systems, surge
tanks of these sizes were used (barrels): 20, 100, 500,
1000, 3000, respectively.
Because of the nature of the problem, development of
realistic cost estimates for the treatment of produced water
should be very generalized. Costs have been developed for
the systems identified based on the following assumptions:
1. All cost data were computed in terms of 1973 dollars
corresponding to an Engineering News Record (ENR)
construction cost index value of 1895 unless otherwise
stated.
2. The annualized costs for capital and depreciation are
based on a loan rate of 15 percent which is equivalent to an
annual average cost of 20 percent of the initial investment
102
-------
comprised of 10 percent for depreciation and 10 percent for
average interest charges.
3. Costs will vary greatly depending upon platform space.
Therefore, investment costs have been prepared for three
options:
a. Option (a) assumes that adequate platform space is
available because existing requirements for waste treatment
are contained in the offshore leases. (1) Therefore, no
additional space will be needed. Rather, the space will be
reused by facilities with more efficient removal capacity.
b. Option (b) assumes that, because of the high costs
involved in building platforms, they have been built to the
minimum size needed for production. Therefore space is not
generally available for water treatment equipment and
ancillary -facilities. Space is provided by cantilevered
additions up to 1,000 square feet. Space requirements
greater than this amount will require an auxiliary platform.
(2)
c. Option (c) is for new platforms being planned. The
needed space would be provided as a basic part of the
platform design and the costs apportioned at $350 per square
foot.
In all three cases estimates are based on platforms located
offshore in 200 feet of water. This depth is assumed to be
an average for the period to 1983.
Where electric energy is required, generating equipment of
adequate capacity for the treatment equipment is provided
for all requirements exceeding 5 horsepower.
Operation and maintenance costs of componenets of the
various systems are based on operating costs of the
equipment. (2) The resulting percentage of investment cost
is shown in Table 20.
103
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TABLE 20
Operating Cost Offshore
Facility
Tanks
Plate Coalescers
Flotation Systems1
Filters^
Subsurface Disposal1
Electrical Supply Facilities
Platforms
Basis for Calculating
Annual O & M Costs
(Percentage of
Investment
11
33
11
11
9
10
2
1 Excludes electrical power supply cost.
104
-------
Energy and power for low demand is computed as 2 percent of
the investment cost. For high demands an electric power
cost of 2-1/2 cents per kilowatt hour is assumed.
The capital costs and annualized costs for the six
alternative produced water treatment systems, for offshore
installation, are contained in Tables 21-25. Options (a),
(b), and (c)r as defined above, reflect equipment costs,
installation, and the cost of platform space requirements.
Onshore Produced Water Disposal
The waste water treated onshore will result from either
onshore production facilities or offshore produced water
sent to shore for treatment. The costs for treatment of
offshore wastes, which are sent to shore, treated and then
discharged will be somewhat less than the costs quoted
above. These lower costs result from cheaper construction
costs onshore, no costs for platform space, lower 0 and M
costs, etc. The costs shown here are for subsurface
disposal onshore.
The typical system for injection for disposal only is a flow
equalizing or surge tank, high pressure pumps, and a
suitable well. Chemicals may be added to prevent corrosion
or scale formation.
When produced water is treated and returned to the producing
formation for secondary recovery, the costs should not be
considered as a disposal cost, but rather as a necessary
cost in production of oil. When produced water cannot be
returned to the formation for secondary recovery or for
water flooding, the costs for treating it and providing the
injection equipment becomes a legitimate disposal cost.
The cost estimates for onshore disposal of produced
formation water include flow equalization tanks for 1,000,
5,000 and 10,000 barrels-per-day water production, pumps
sized for these flow rates and 700 pounds per square inch
pressure, and disposal wells of 3,000 foot depth. A maximum
well capacity of 12,000 barrels-per-day was assumed. In
addition, costs for this system include a lined pond to
provide standby capability for continuing production for
seven days while pump repairs are being made or the
injection system is being worked on. The capital costs and
annualized costs for these systems are contained in Table
26.
105
-------
Table 21
Capital Costs
Annualized Costs
Capital
Depreciation
0 & M
Energy
Total Annualized Costs
Cost of water disposal
$/bbl
Formation Water Treatment Equipment Costs
Offshore Installations
200 Barrels Per Day Flow Rate
EQUIPMENT COSTS (Thousands of 1974 dollars)
Al
59.3
5.93
5.93
2.95
-
14.8
B
69.7
6.97
6.97
4.7
-
18.6
C
87.1
8.7
8.7
6.4
-
23.8
El
348.7
34.9
34.9
28.0
2.4
100.2
E2
400.5
.20
.25
.33
1.37
40.0
40.0
31.8
2.0
113.8
1.55
-------
Table 22
Cost of water disposal
$/bbl
Formation Water Treatment Equipment Costs
Offshore Installations
1,000 Barrels Per Day Flow Rate
EQUIPMENT COSTS (Thousands of 1974 dollars)
Capital Costs
Annual i zed Costs
Capital
Depreciation
0 & M
Energy
Total Annualized Costs
Al B
101 143
10.1 14.3
10.1 14.3
6.7 11.6
1.5
26.9 41.7
C
176.3
17.6
17.6
14.3
1.5
51.0
El
373.3
37.3
37.3
29.7
3.3
107.6
E2
432.2
43.2
43.2
38.0
4.4
128.8
.07
.114
.14
.30
.35
-------
o
oo
Table 23
Formation Water Treatment Equipment Costs
Offshore Installations
5,000 Barrels Per Day Flow Rate
(Thousands of 1973 dollars)
Al A2 B C
E2
Capital Costs
Option (a)
Option (b)
Option (c)
Annual i zed Costs
Capital & Depre-
ciation
Option (a)
Option (b)
Operation &
Maintenance
Energy
Total - Option (a)
Option (b)
Option (a)
Option (b)
47
1,452
432
9.4
290.4
4.32
0.94
14.66
295.66
Cost of
0.008
0.16
21
55
43
4.2
11.0
6.51
0.42
11.13
17.93
Water Disposal
0.006
0.0098
88
146
274
17.6
29.2
8.27
1.76
27.63
39.23
- $/bbl
0.015
0.022
131
204
423
26.2
40.8
12.23
2.62
41.05
55.65
0.023
0.031
74
117
157
14.8
23.4
6.96
1.48
23.24
31.84
0.013
.017
451
518
683
90.2
103.6
39.88
9.02
139.1
152.5
0.076
0.084
-------
o
<£>
Table 24
Formation Water Treatment Equipment Costs
Offshore Installations
10,000 Barrels Per Day Flow Rate
(Thousands of 1973 dollars)
Al A2 B C
E2
Capital Costs
Option (a)
Option (b)
Option (c)
Annual i zed Costs
Capital & Depre-
ciation
Option (a)
Option (b)
Operation &
Maintenance
Energy
Total - Option (a)
Option (b)
Option (a)
Option (b)
60
2,140
a
12
428
5.52
1.20
18.7
434.7
Cost of
0.005
0.117
31
68
66
6.2
13.6
8.28
0.62
15.1
22.5
Water Disposal
0.004
0.006
148
228
488
29.6
45.6
13.91
2.96
46.5
62.5
- $/bbl
0.013
0.017
206
1 ,626
708
41.2
325.2
19.33
4.12
64.7
348.7
0.018
0.096
108
161 1
259
21.6
32.2
10.12
2.16
33.9
44.5
0.009
0.012
563
,972
979
112.6
394.4
52.14
11.26
176
457.8
0.048
0.125
Not considered to be a viable alternative because of large space requirement.
-------
Table 25
Formation Water Treatment Equipment Costs
Offshore installations
40,000 Barrels Per Day Flow Rate
(Thousands of 1973 dollars)
Al A2 B C
E2
Capital Costs
Option (a)
Option (b)
Option (c)
Annual i zed Costs
Capital & Depre-
ci ati on
Option (a)
Option (b)
Operation &
Maintenance
Energy
Total - Option (a)
Option (b)
Option (a)
Option (b)
a 60
a 98
a 102
12
20.4
18.60
1.20
31.8
40.2
Cost of Water Disposal
0.002
0.0028
355
1 ,780 1
880 1
71
356
33.60
7.10
111.7
396.7
- $/bbl
0.0077
0.027
448
,913
,254
89.6
382.6
42.04
8.96
140.6
433.6
0.01
0.030
170
230 2
369 1
34
46.0
15.90
3.40
53.3
65.3
0.004
.005
907
,354
,585
181.4
470.8
89.56
18.14
289.1
578.5
0.020
0.040
No estimate made - method considered to be impractical because of large space requirements.
-------
TABLE 26
Estimated Costs for Onshore Disposal
of Produced Formation Water
by Shallow Well Injection With Lined Pond for Standby
(Thousands of 1973 dollars)
Facility Size
Barrels Per Day
Capital Costs
Equalization or Surge Tank
High Pressure Pump
Well Completion
Pond
Total
Annualized Costs
Capital
Depreciation
O&M
Power
Total Annual Costs
1,000
3.5
4.5
40.5
5.0
53.5
2.5
2.5
5.0
.5
5,000
6.0
15.0
40.5
13.1
74.6
7.46
7.46
6.71
3.0
10,000
8.0
15.0
40.5
20.0
83.5
8.35
8.35
7.52
6.0
20.5
24.63
30.22
111
-------
TABLE 27
Estimated Treatment Plant Costs
For Sanitary Wastes For Offshore Locations
Package Extended Aeration Process
(Thousands of 1973 dollars)
Treatment Plant Capacity
(gallons/day)
2.000 4.000 6,000
Capital Cost 18,000 23,000 28,000
Total Annual Costs 6,010 7,660 9,360
capital 1,800 2,300 2,800
depreciation 1,800 2,300 2,800
operation & maintenance 2,050 2,600 3,200
energy and power 360 460 560
112
-------
Table 28
Estimated Horsepower Requirements
for the Operation of
Flotation Treatment Systems
Source
Level of
Production
bbl/day
5,000
10,000
40,000
Brown
& Root I/
(Hp.)
14
25
118
WEMCO 21
(Hp.)
13
21
61
NATCO 3/
(Hp.)
6
13
47
Rheem 4/
(Hp.)
20
25
50
Komlin 5/
Sanderson
Engring Corp.
(Hp.)
17-1/2
-
81-1/2
I/ Brown and Root. III-ll
2J Wemco Data Sheet, F8-D2, dated 4-19-73
3/
4/
Letter dated June 12, 1974, from National Tank Com. to Mr. R. W.
Thieme, OTA, EPA, plus telephone communication, Friday, July 19,
1974, with Mr. E. Cliff Hill, NATCO
Telephone communication with Mr. Ken Sasseen, Rheem-Superior Corp.,
California.
5/ Telephone conversation with Mr. Arthur Albohn, Komline, 201-234-1000
July 24, 1974.
113
-------
TABLE 29
Estimated Incremental Energy
Requirements Flotation Systems
5,000 bbl/day of water treated;
15 Hp. for 1 yr. = 3.35 x 1()8 BTU/yr.
1 bbl diesel oil = 6 x 106 BTU
15 Hp. - yr. = 55.8 bbl diesel oil/yr.
Assume 20% conversion efficiency, then 15Hp. - yr = 279 bbl
diesel oil/yr.
10,000 bbl/day of water treated:
464 bbl diesel oil/yr.
40,000 bbl/day of water treated:
1115 bbl diesel oil/yr.
114
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TABLE 30
Energy Requirements for Flotation Systems as
Compared to Net Energy Production
Associated with the Produced Water Flows
Assumed Level of Net Energy Energy for Flotation
Produces Water Production in Diesel Oil Units Diesel Oil
Flow - bbl/day Equivalents - bbl/day Equivalents - bbl/day
5,000 50 to 50,000 0.76
10,000 100 to 100,000 1.27
40,000 400 to 400,000 3.05
115
-------
Well completion costs are based on data contained in the
Joint Association Survey of the U.S. Oil and Gas Producing
Industry for 1972. (2) The costs are adjusted upwards by
use of the ENR construction cost index using a value of 1895
for 1973. Energy (power) costs are computed at 2-1/2 cents
per kilowatt hour. Operation and maintenance costs were
computed at 9 percent of the capital cost based on an
industry- sponsored report. (2)
Offshore Sanitary. Waste
Cost estimates for biological systems utilized on offshore
platforms are for the aerobic digestion process or extended
aeration treatment plants. The estimates anticipate the use
of a system including a comminuter to grind the solids into
fine particles, an aeration tank with air diff users, gravity
clarifier return sludge system and a disinfection tank.
Based on the design requirements stated in Table 18 costs
were developed for systems to serve 25 persons (2,000
gallons), 50 persons (4,000 gallons) and 75 persons (6,000
gallons). These costs are contained in Table 27.
lQ§£2Y B§9ui£€:IDJ=Ii£s £.2E QE®£^tiQ3 Flotation Systems
Table 28 presents several estimates of horsepower
requirements of flotation systems for the three levels of
production.
Actual installations will probably comprise a mix of
manufacturers ' units and the typical horsepower requirements
will be some weighted average of the values in Table 28.
For the purpose of estimating energy requirements, the
average requirements are assumed to be 15, 25, and 60
horsepower for the 5,000, 10,000 and 40,000 bbls per day
production levels. (The 118 Hp. figure for the 40,000 bbls
per day unit was rejected as spurious - an incorrect linear
extrapolation on a graph.)
Table 29 presents the calculations that translate these
basic horsepower requirements into total energy
requirements.
One way to evaluate the energy requirements of flotation
systems is to compare their consumption with that of the oil
production associated with their use. Water production
rates do not vary regularly with crude oil production rates.
In some instances, the 5,000 bbl/day of produced water may
be associated with a crude oil production of only 5,000
116
-------
bbl/day. In other cases, crude production rates may be 50
to 100 times the rate of water production or vice versa.
Given these variation and the variable products and costs of
refining the crude oil, it would be a menaingless exercise
to attempt to estimate the net BTU equivalent in terms of
barrels of diesel oil for the oil production associated with
the typical water flows. One can, however, usefully examine
a range of possible levels of net production to get a
general impression of the relative energy requirements of
flotation systems. For example, it is reasonable to assume
that the 5,000 bbl/day water production could be associated
with a net energy production of anywhere from 50 to 50,000
bbl/day of diesel oil. Similarly the 10,000 and 40,000
bbl/day water flows could be associated with ranges of net
diesel oil equivalent flows from 100 and 100,000 and UOO and
400,000 bbl/day, respectively. Table 30 presents a summary
of the flotation systems' energy consumption data as
compared to such associated oil production rates.
It is clear from Table 30 that the energy required for
flotation relative to the net energy being produced is very
small. Even in such a rare case as when water production is
100 times that of crude oil production, the flotation energy
requirements amount to only 1.5 percent of the net energy
being produced.
Nonwater-Quality Aspects
Evaluation of in-plant process control measures and waste
treatment and disposal systems for best practicable control
technology, best available technology, and new source
performance standards indicates that there will be no
significant impact on air quality. A minimal impact is
expected, however, for solid waste disposal from offshore
facilities. The collection, and subsequent transport to
shore of oily sand, silt, and clays from the addition of
desanding units, where appropriate, will generate a possible
need for additional approved land disposal sites. There are
no known radioactive substances used in the industry other
than certain instruments such as well-logging instruments.
Therefore, no radiation problems are expected. Noise levels
will not be increased other than that which may be caused by
the possible addition of power generating equipment on some
offshore facilities.
117
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SECTION VIII
Bibliography
Offshore Operatores Committee, Sheen Technical
Subcommittee. 1974. "Determination of Best Practicable
Control Technology Currently Available To Remove Oil
From Water Produced With Oil and Gas." Prepared by
Brown and Root, Inc., Houston, Texas.
Joint Association Survey of the U.S. Oil and Gas
Producing Industry. 1973. "Drilling Costs and
Expenditures for Exploration, Development and Production
- 1972." American Petroleum Institute, Washington, D.
C.
118
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SECTION IX
EFFLUENT LIMITATIONS FOR
BEST PRACTICABLE CONTROL TECHNOLOGY
Based on the information contained in the previous sections
of this report, effluent limitations commensurate with best
practicable control technology (BPCT) currently available
have been established for each subcategory. The
limitations, which must be achieved not later than July 1,
1977, explicitly set numerical values for allowable
pollutant discharges of oil/grease, chlorine residual and
floating solids. BPCT is based on control measures and
end-of-pipe technology widely used by industry. These
limitations are applicable to both offshore subcategories.
Water Technology,
BPCTCA process control measures include the following:
1. Elimination of raw waste water discharged from free
water knockouts or other process equipment.
2. Supervised operations and maintenance on oil/water level
controls, including sensors and dump valves.
3. Redirection or treatment of waste water or oil
discharges from safety valve and treatment unit by-pass
lines.
BPCTCA end-of-pipe treatment can consists of some, or all of
the following:
1. Equalization (surge tanks, skimmer tanks) .
2. Solids removal desanders.
3. Chemical addition (feed pumps) .
4. Oil removal (dissolved gas flotation) .
5. Filters.
6. Plate coalescers.
7. Gravity systems.
8. Subsurface disposal.
119
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Specific treatability studies are required prior to
application of a specific treatment system to an individual
facility.
P£2c.<=
-------
6. Characteristics of the produced water.
The factors considered controllable are:
1. Operator training.
2. Sample collection and analysis methods.
3. Process equipment malfunction—for example in
heater-treaters and their dump valves, chemical
pumps and sump pumps.
4. Lack of proper equipment—for example, desanders or
large tanks.
5. Noncompatible operations.
The major objective of the detailed data analysis was to
reject inadequate treatment technology and select facilities
utilizing a sound technical rationale. Initially, 138
treatment systems (94 in Coastal Louisiana, 36 in Coastal
Texas, and 8 in Coastal Alaska) were evaluated. The
treatment systems included gas flotation, plate coalescers,
fibrous media filters, loose media filters, and gravity
separation.
EPA survey data show that the majority of the simple gravity
systems produced highly variable effluents and were only
minimally effective in removal of oil. The data from the 36
gravity systems in Coastal Texas were derived from extreme
variations in analytical procedures. EPA attempts to verify
this data failed and all of this data had to be rejected.
Ten of the 94 treatment systems in Coastal Louisiana had 10
or less data points; they were rejected. Data from the 84
remaining units were analyzed along with the data collected
from 25 facilities visited in the EPA verification study.
The variance in treatment efficiencies was reflected in the
data for all types of treatment methods. Both loose media
and fibrous media filters are capable of producing low
average effluents, but because of O&M difficulties the units
are being phased out.
The plate coalescer and gas flotation treatment units in
Louisiana with greater than 10 data points were analyzed
with respect to O&M reliability. A comparison was made to
determine the effectiveness of physical separation of oil
and ability to handle uncontrollable variation in raw waste
characteristics. The treatment efficiencies of plate
coalescers were significantly below those for gas flotation
121
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units. This is supported by an analysis of the design
parameters for plate coalescers, which are similar to API
gravity separators. A review of O&M records and findings
from EPA field surveys indicate that these units are subject
to plugging from solids, iron, and other produced water
constituents. When the parallel plate becomes plugged,
frequent back washing, manual cleaning, or replacement of
plates is required. The effluent data showed highly
variable oil concentrations which indicated that both
controllable and uncontrollable factors significantly
affected treatment efficiencies. Therefore, plate
coalescers were eliminated from consideration.
The remaining 32 Louisiana treatment units were dissolved
gas flotation systems with chemical treatment. Historical
data and reports were available on nine of the units. Each
was evaluated to determine the acceptability of the data and
the causes of significant effluent variations. A review of
the design parameters for the various systems showed that
the systems were designed for the maximum expected water
production. None was designed to handle overload conditions
which may occur during start-up, process malfunctions, or
poor operating practices. Data were rejected which followed
unit installation (start-up), when chemical treatment rates
were modified, and when significant equipment maintenance or
other O&M procedures which affect normal efficiency of the
treatment unit was being performed. Treatment data from
some of the facilities analyzed were highly variable with no
apparent explanation. In this case, all of the treatment
data were accepted since it appeared highly unlikely that
efficiency could be normalized with better O&M procedures.
More likely the varibility seen is attributable to the
geological formation. Units with influent data in excess of
200-300 mg/1 were suspect, since historical data indicated
that high influents could be attributed to dump valve
malfunctions in the process units. These units were
investigated, and if the causes of their high concentrations
were found, they were rejected; otherwise they were
accepted. Units without historical data, but which had
variations similar to those which were rejected were
evaluated and if the variations were judged to be caused by
controllable malfunctions, they were eliminated. Three
systems were rejected because of reported process and
treatment malfunctions, six months of data were rejected
from two other systems due to operational and start-up
problems. For the remaining units, data points were
eliminated since a strong indication of errors in sample
collection and analysis.
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Additional data were obtained for a number of the units from
the oil companies, the Department of the Interior and the
Brown and Root report. These data were screened and
evaluated in a manner similar to that previously described.
A total of 28 units, 27 off the Louisiana coast and one in
Coastal Alaska were selected as potentially usable
facilities. These facilities represent approximately 66
percent of the 41 facilities with the treatment technology
to qualify as BPCT. Of the 28 units, 12 have in excess of
90 data points and one facility has 508 data points covering
an 18-month period.
The EPA field survey included nine of the 28 selected gas
flotation units in the Coastal Louisiana. The results of
the field survey supports the rationale used for selection
of exemplary technology and establishing the data base for
determining effluent limitations.
Upon completion of the technical evaluation of the data and
units, a detailed statistical analysis was conducted to
determine the form of the statistical distribution and to
search for anomalous means or variances which might indicate
a need to subcategorize based upon flow rates and space
limitations. The initial review indicated that the selected
units data were similar in distribution, and although the
observed means and variances differed from unit to unit, no
basis for further subcategorization was discovered.
The statistical analysis indicated that the data were log
normally distributed over most of the data. The various
units could be separated statistically into three groups: 1)
five high; 2) 13 low; and 3) nine average. The means and 99
percent probability of occurance levels were calculated for
the low, high, and total groups. Even though the group of
27 flotation units could be broken down further (into 3
subgroups), it was felt that at the current level of
experience, with this technology, the entire industry could
not be expected to achieve the same level of treatment as
the very best units are now achieving. Therefore, data from
all 27 Louisiana Coastal units were included in determining
the effluent limits for oil.
Further analysis of the data base showed that some of the
reported data were composites (4 grab samples taken in a 24
hour period, analyzed separately and the results averaged)
and the rest were individual grab samples. It was
determined that the grab samples had a higher variance than
the composites and that the compositing technique would
result in more representative results. The compositing
would greatly decrease the effect of sampling and analytical
123
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variance, which is potentially significant in oil and grease
monitoring.
The composited data were than analyzed separately and two
different techniques were used on the grab samples analysis
to simulate composite sampling.
A maximum monthly average was also calculated from the
modified (composite) data base. To utilize all of the data,
two different approaches were used to determine the monthly
averages: 1) based on dates of observed values - this method
averages a given number of samples (N) which are 30/N days
apart, with the analysis being performed on these averages;
2) based on randomized observed values - this method divides
the 2262 data points into 2262/N groups, each group
containing N randomly selected points. The analysis is
performed on the averages of each group.
The first method is free of assumptions, but is limited in
data base since only 9 of the units had more than 2 data
points per month. The second method is simple and utilizes
all of the data, but ignores autocorrelation. Figure 10 is
a plot of the results of these two methods being applied to
the data based. As can be seen the plots begin separating
at 4 samples per month because of the effects of
autocorrelation.
The results of the above analyses are as follows:
1. Long term average (1 year) - 25 mg/1
2. Maximum monthly average (weekly sampling) -US mg/1
3. Maximum day (composited) - 72 mg/1
The data in Figure 11 represent a cumulative plot of the
modified daily concentrations for the 27 Louisiana Coastal
flotation units. The plot is essentially linear over the
last 90 percent of the range, and the straight line
represents a log normal distribution. Of the 2,262 samples,
99 percent have oil concentrations less than 72 mg/1.
A statistical analysis was also conducted to determine the
distribution, and variance for the one flotation unit in
Coastal Alaska which treated produced waters. The average
oil content in the effluent is approximately 15 mg/1. The
operation of this unit appears very similar to the low group
units for Coastal Louisiana.
124
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Figure 10
99th Percentile of Monthly Average Oil and Grease
Concentration vs.
Frequency Of Sampling Each Month
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60
actual
randomized
Number of Samples Per Month (Days Between Samples)
125
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Sanitary Wastes — Offshore Manned Facilities With 10 or
More People
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.
The effluent limitations were based on effluent data
industry provided to the U.S. Geological Survey. Chlorine
residual, BOD, and suspended solids concentrations for the
biological treatment systems were within the range of values
which would meet fecal coliform requirements.
The only limitation being set on sanitary wastes is for
chlorine residual. This requirement is set to control the
fecal coliform level in this effluent. Limits on BOD or
suspended solids for these wastes are ludicrous since the
BOD and TSS content of the produced waters are likely to be
several hundred times greater.
The limit for residual chlorine is, greater than 1 mg/1, but
as close to 1 mg/1 as possible. The facilities for
chlorination on offshore platforms are much less
sophisticated then typical municipal treatment plants and
the flows much more variable. Therefore, it is felt that
the standard residual chlorine limit of 1 mg/1 plus a minus
40 % is unrealistic. There has been no upper limit set
because of a lack of valid data to be used to set such a
limit.
BPCT for sanitary wastes from small offshore facilities and
intermittently manned facilities is based on end-of-pipe
technology currently used by the oil and gas production
industry and by the boating industry. These devices are
physical and chemical systems which may include chemical
toilets, gas fired incinerators, electric incinerators or
macerator-chlorinators. None of these systems has proved
totally adequate. Therefore, the effluent limitations are
based on the discharge technology which consist of a
macerator-chlorinator. For coastal and estuarine areas
where stringent water quality standards are applicable, a
higher level of waste treatment may be required.
127
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The attainable level of treatment provided by BPCT is the
reduction of waste such that there will be no floating
solids.
Domestic Wastes
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.
Deck Drainage
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 lubriciating 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
segregated as it increases the hydraulic loading on the
treatment unit.
The limits for deck drainage are the same as for produced
waters offshore.
By-Pass (Offshore Operations)
By-passing waste water treatment systems may be necessary
when equipment becomes inoperative or requires maintenance.
Waste fluids must be controlled during by-pass conditions to
prevent discharges of raw wastes into surface waters.
128
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Control practices currently used in offshore operations
during by-pass are:
1. Waste fluids are temporarily stored onboard unitl the
waste treatment unit returns to operation.
2. Waste fluids are directed to onshore treatment
facilities through a pipeline.
3. Placing waste fluids in a barge for transfer to shore
treatment.
4. Waste fluids are piped to a primary treatment unit
(gravity separation) to remove free oil and discharged
to surface waters.
BPCT for by-pass is no discharge of free oil to the surface
waters.
Drilling Muds
BPCT for drilling muds includes control practices widely
used in both offshore and onshore drilling operations:
1. Accessory circulating equipment such as shaleshakers,
agitators, desanders, desilters, mud centrifuge,
degassers, and 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.
BPCT end-of-pipe treatment technology is based on existing
waste treatment processes currently used by the oil industry
in drilling operations.
The limitations for offshore drilling muds are as follows:
1. Water-based and natural muds shall contain no free oil
when discharged.
2. Oil-based and emulsion muds shall not be discharged to
surface waters. These muds are to be transported to
shore for reuse or disposal in an approved disposal
site.
Drill Cuttings
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BPCT for drill cuttings is based on existing treatment and
disposal methods used by the oil industry. The limitations
for offshore drill cuttings are as follows:
1. Cuttings in natural or water-based muds shall contain no
free oil when discharged.
2. Cuttings in oil-based or emulsion muds shall not be
discharged to surface waters. Cuttings should be
collected and transported to shore for disposal in an
approved disposal site.
Well Treatment
Workover fluids other than water, or water-based muds are to
be recovered and reused. Materials not consumed during
workovers and completions are returned to shore.
The effluent limitations were determined using data supplied
by industry and service companies serving the oil producing
industry. The limitation for wastes from well treatment
offshore is: well treatment wastes shall contain no free oil
when discharged.
130
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Section IX
Bibliography
1. Offshore Operators Committee, Sheen Technical
Subcommittee. 1974. "Determination of Best Practicable
Control Technology Currently Available to Remove Oil
From Water Produced With Oil and Gas." Prepared by
Brown and Root, Inc., Houston, Texas.
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SECTION X
EFFLUENT LIMITATIONS FOR
BEST AVAILABLE TECHNOLOGY ECONOMICALLY ACHIEVABLE
The application of best available technology economically
achievable is being defined as improved O&M practices and
tighter control of the treatment process, for the far
offshore subcategory. BATEA for the near offshore
subcategory is defined as subsurface disposal for produced
waters. These effluent limitations are to go into effect no
later than July 1, 1983.
The limitations for both subcategories are the same as BPTCA
for drilling muds, drill cuttings, sanitary and domestic
wastes, well treatment, and produced sands. Additionally
the BATEA limitation for deck drainage in the near offshore
subcategory is the same as for BPTCA.
Near Offshore Subcategory - Produced Water
The BATEA limitations for produced water in the near
offshore subcategory is no discharge to surface waters.
This can be accomplished by reinjection or by end-of-pipe
technologies such as, evaporation ponds and holding pits
(when wastes are transferred to shore) or injection to
disposal wells. About 40* of those producing facilities
with no discharge use one of these end-of-pipe technologies.
Existing no discharge systems were reviewed to select the
best technology for the purpose of estabishing effluent
limitations. Holding pits were found to be the least
desirable because of frequent overflow, dike failure, and
infiltration of salt water into fresh water aquifiers. If
properly constructed and lined, evaporation lagoons may
result in no discharge in arid and semiarid regions.
However, erosion, flooding, and overflow may still occur
during wet weather. Disposal well systems which may consist
of skim tanks, aeration facilities, filtering system,
backwash holding facilities, clear water accumulators,
pumps, and wells provide the best method for disposal of
produced water. These systems are equally applicable to
onshore and offshore operations and are the primary method
used to dispose of produced water on the California coast
and in the inland areas.
Far Offshore Subcategory, - Produced Water and Deck Drainage
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The BATEA limitations for produced water and deck drainage
in the far offshore subcategory are based on the same end-
of-pipe technology as used for BPTCA. It is expected that
the industry will have gained sufficient experience in the
redcution of raw waste loads and operation of end-of-pipe
technologies to improve their operation by 1983. In order
to define this level of discharge a statistical analysis was
carried out on the data from the 27 flotation units, used to
define BPTCA, to determine if any units were significantly
better in effluent quality than the rest. A group of 10
flotation units were separated on that basis and their data
analyzed. The resulting BATEA limitations for oil and
grease are, 52 mg/1 daily maximum (composited) and 30 mg/1
maximum monthly average. Figure 12 is a cumulative plot of
the effluent concentrations of these 10 selected flotation
units.
When the BPTCA limitations were derived, it was concluded
that they should be based on what was being achieved by all
facilities using the BPTCA.
This conclusion was reached on the basis of industry
experience. Since the industry will have, by 1983, 8
additional years of experience in waste abatement, there
should be no significant problems in attaining effluent
qualities now being met by many facilities.
134
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Louisiana Gulf Coast Area
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135
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SECTION XI
NEW SOURCE PERFORMANCE STANDARDS
The effluent limitations for new source performance
standards are the same as the BATEA limitations for each
subcategory. The facilities defined here will be built
after this regulation is in affect. These facilities should
therefore, be built with raw waste load reduction and waste
treatability in mind. As a result, the number and magnitude
of both preventable and unpreventable wastes should be
minimized.
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SECTION XII
ACKNOWLEDGEMENTS
The initial draft report was prepared by the special Oil
Extraction Task Force which EPA Headquarters established to
study the oil and gas extraction point source category.
The following members of the Task Force furnished technical
support and legal advice for the study:
Russel H. Wyer, Oil and Special Materials Control
Division (OSMCD), Co-Chairman;
H. D. VanCleave, OSMCD, Co-Chairman; William Bye, OSMCD;
Thomas Charlton, OSMCD; Harold Snyder, OSMCD; Kenneth
Adams, OSMCD; Hans Crump-Weisner, OSMCD; Arthur Jenke,
OSMCD; R. W. Thieme, Office of Enforcement and General
Counsel; Jeffrey Howard, Office of Enforcement and
General Counsel; Charles Cook, Office of Water Planning
and Standards; Martin Halper, Effluent Guidelines
Division; Dennis Tirpak, Office of Research and
Development; Thomas Belk, Permit Programs Division;
Richard Insinga, Office of Planning and Evaluation;
Stephen Dorrler, Edison Water Quality Research
Laboratory, Edison, N.J.
Martin Halper, Project Officer, Effluent Guidelines
Division, contributed to the overall supervision of this
study and perpared this Development Document. Allen Cywin,
Director; Ernst Hall, Deputy Director; and Harold Coughlin,
Branch Chief, all Effluent Guidelines Division, offered
guidance during this program.
Special appreciation is given to Mary Lou Ameling, Charles
Cook, Richard Insinga, and Henry Garson for their
contributions to this effort.
In addition to the Headquarters EPA personnel. Regions V,
VI, and X were extremely helpful in supporting this study.
Special acknowledgement is made to personnel of the
Surveillance and Analysis Division, Region VI, for their
dedicated effort in support of the EPA Field Verification
Study, and to Russ Diefenbach of Region V who assisted with
data acquisition for onshore technology. Regions IV and
VIII assisted in onshore data acquisition.
Special appreciation is extended to the EPA Robert S. Kerr
Research Laboratory (RSKRL), Ada, Oklahoma, for its
technical support. RSKRL managed and conducted the entire
139
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analytical study phase for field verification in Coastal
Louisiana, Texas, and California.
Special recognition is due EPA Edison Water Quality Research
Laboratory, Edison, New Jersey, for its participation in
field studies of oil and gas operations and its review of
contractor-operated analytical laboratories in the Gulf
Coast area.
Acknowledgement is made to Richard Krahl, Robert Evans, and
Lloyd Hamons, Department of the Interior, U.S. Geological
Survey, for their contribution to the EPA Field Verification
Study in the Coastal Louisiana area.
Many state offices assisted in the study by providing data
and assisting in field studies. Among those contributing:
Alabama, Arizona, Arkansas, California, Colorado, Florida,
Illinois, Louisiana, Missouri, Nebraska, Nevada, New Mexico,
North Dakota, Ohio, Pennsylvania, Utah, and Wyoming.
Our special thanks to Mrs. Irene Kiefer for her editorial
services. Appreciation is extended to the secretarial staff
of the Oil and Special Materials Control Division for their
efforts in typing many drafts and revisions to this report.
Appreciation is extended to the following trade
associations and corporations for their assistance and
cooperation:
American Oil Company; American Petroleum Institute,
Onshore Technical Committee, Seth Abbott, Chairman;
Ashland Oil, Inc.; Atlantic Richfield Company; Brown and
Root, Inc.; C. E. Natco; Champlin Petroleum Company;
Chevron Oil Company; Continental Oil Company; Exxon Oil
Company; Gulf Oil Company; Marathon Oil Company; Mobil
Oil Company; Noble Drilling Company; Offshore Operators
Committee; Sheen Technical Subcommittee, William "M."
Berry, Chairman; Oil Operators, Inc.; Phillips
Petroleum; Pollution Control Engineers; Rheem Superior;
Shell Oil Company; Sun Oil Company; Texaco, Inc.;
Tretolite Corporation; United States Filters; Union
Filter Company; and WEMCO.
140
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SECTION XIII
GLOSSARY AND ABBREVIATIONS
Acidize - To put acid in a well to dissolve limestone in a
producing zone, forming passages through which oil or
gas can enter the well bore.
Air/Gas Lift - Lifting of liquids by injection of air or gas
directly into the well.
Annulus or Annular Space - The space between the drill stem
and the wall of the hole or casing.
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, a
special fullers earth, is a hydrous magnesium aluminum
silicate.
Back Pressure - Pressure resulting from restriction of full
natural flow of oil or gas.
l§rite ~ Barium sulfate. An additive used to weight
drilling mud.
I§t£it^ Recovery Unit (Mud Centrifuge) - A means of removing
less dense drilled solids from weighted drilling mud to
conserve barite and maintain proper mud weight.
Barrel - 42 United States gallons at 60 degrees Fahrenheit.
Bentonite - An additive used to increase viscosity of
drilling 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.
Blowout Preventer _(BQPL ~ 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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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.
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. Also see "Desander - Cyclone."
Chemical-Electrical Treater - A vessel which utilizes
surfactants, 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.
Closed-In - A well capable of producing oil or gas, but
temporarily not producing.
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Coagulation - The combination or aggregation of semi- solid
particles such as fats or proteins to form a clot or
mass. This can be brought about by addition of
appropriate electrolytes. Mechanical agitation and
removal of stabilizing ions, as in dialysis, also cause
coagulation.
Coalescence - The union of two or more droplets of a liquid
to form a larger droplet, brought about when the
droplets approach one another close-by enough to
overcome their individual surface tensions.
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.
Qonnate- 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.
Crude oil - A. mixture of hydrocarbons that existed in liquid
phase in natural underground reservoirs and remains
liquid at atmospheric pressure after passing through
surface separating facilities.
Cut Oil - Oil that contains water, also call wet oil.
Cuttings - Small pieces of formation that are the result of
the chipping and/or crushing action of the bit.
. Substructure - Combined foundation and overhead
structure to provide for hoisting and lowering necessary
to drilling.
Desander - Cyclone - Equipment, usually cyclone type, for
removing drilled sand from the drilling mud stream and
from produced fluids.
er - Equipment, normally cyclone type, for removing
extremely fine drilled solids from the drilling mud
stream.
Development Well - A well drilled for production from an
established field or reservoir.
Disposal Well - A well through which water (usually salt
water) is returned to subsurface formations.
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Drill Pipe - Special pipe designed to withstand the torsion
and tension loads encountered in drilling.
Drilling Mud - A suspension, generally aqueous, used in
rotary drilling to clean and condition the hole and to
counterbalance formation pressure; consists of various
substances in a finely divided state, among which
bentonite and barite are most common.
Dump. Valve - A mechanically or pneumatically operated valve
used on separator, treat ers, and other vessesl for the
purpose of draining, or "dumping" a batch or oil or
water.
Emulsion - 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.
E±§!
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Gas Lift - A means of stimulating flow by aerating a fluid
column with compressed gas.
Gas-Oil Ratio - Number of cubic feet of gas produced with a
barrel of oil.
Gathering Line - A pipeline, usually of small diameter, used
in gathering curde oil from the oil field to a point on
a main pipeline.
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
alkalinity 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) .
Inhibitor - An additive which prevents or retards
undesirable changes in the product. Particularly,
oxidation and corrosion; and sometimes paraffin
formation.
§Et Oil JEmulsion MudJ_ - A water- in-oil emulsion where
fresh or salt water is in dispersed phase and diesel,
crude, or some other oil is the continuous phase. Water
increases the viscosity and oil reduces the viscosity.
Kill a Well - To overcome pressure in a well by use of mud
or water so that surface pressures are neutralized.
Location JDrill Site]_ - Place at which a well is to be or
has been drilled.
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
circulating drilling mud.
Multiple Completion - A well completion which provides for
simultaneous production from separate zones.
145
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OCS - Outer Continental Shelf.
Offshore - In this context, the submerged lands between
shoreline and the edge of the continental shelf.
OHM - Oil and Hazardous Material.
Well - A well completed for the production of crude oil
from at least one oil zone or reservoir.
- Dry land, inland bodies and bays, and tidal zone.
OSMCD - Oil and Special Materials Control Division.
Paraffin - A heavy hydrocarbon sludge from crude oil.
Permeability - A measure of ability of rock to transmit a
one-phase fluid under condition of laminar flow.
Presgure 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.
EUfflBx. Q§D£rifugal - A pump whose propulsive effort is
effectuated by a rapidly turning impeller.
B§nk Wildcat - An exploratory well drilled in an area far
enough removed from previously drilled wells to preclude
extrapolation of expected hole conditions.
Beservoir - Each separate, unconnected body of producing
formation.
Drilling - The method of drilling wells that depends
on the rotation of a column of drill pipe with a bit at
the bottom. A fluid is circulated to remove the
cuttings.
Sand - A loose granular material, most often silica,
resulting from the disintegration of rocks.
Separator - A vessel used to separate oil and gas by
gravity.
Shale - Fine-grained clay rock with slatelike cleavage,
sometimes containing an oil-yielding substance.
Shaleshaker - Mechanical vibrating screen to separate
drilled formation cuttings carried to surface with
drilling mud.
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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.
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.
Stripping. ~ Adding or removing pipe when well is pressured
without allowing vertical flow at top of well.
Tank - A bolted or welded atmospheric pressure container
designed for receipt, storage, and discharge of oil or
other liquid.
Tank Battery - A group of tanks to which crude oil flows
from producing wells.
TDS - Total Disolved Solids.
TOG - Total Organic Carbon.
J-Otal Depth lTjJD.j_ - 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.
Waiter Ei22ding - Water is injected under pressure into the
formation via injection wells and the oil is displaced
toward the producing wells.
Well Completion - 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
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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.
Wildcat Well - A well drilled to test formations
nonproductive within a 1-mile radius of previously
drilled wells. It is expected that probable hole
conditions can be extrapolated from previous drilling
experience data from that general area.
Wip_g£.t Pipe-Kelly - A disc-shaped device with a center hole
used to wipe off mud, oil or other liquid from drill
pipe or tubing as it is pulled out of a well.
Work Over - To clean out or otherwise work on a well in
order to increase or restore production.
Work Over Fluid - Any type of fluid used in the workover
operation of a well.
* U S GOVERNMENT PRINTING OFFICE 1975 — 589-828/6015
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