DRAFT
DEVELOPMENT DOCUMENT FOR
EFFLUENT LIMITATIONS GUIDELINES
AND NEW SOURCE PERFORMANCE
STANDARDS FOR THE
OIL AND GAS EXTRACTION
POINT SOURCE CATEGORY
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
OCTOBER 1974
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PUBLICATION NOTICE
This is a draft development document for proposed effluent
limitations guidelines and new source performance
standards. As such, this report is subject to changes
resulting from comments received during the period of
public comments of the proposed regulations.
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DRAFT DEVELOPMENT DOCUMENT
for
EFFLUENT LIMITATIONS GUIDELINES
and
NEW SOURCE PERFORMANCE STANDARDS
for the
OIL AND GAS EXTRACTION
POINT SOURCE CATEGORY
Russel E. Train
Administrator
James L. Agee
Assistant Administrator for Water and Hazardous Materials
Kenneth E. Biglane
Director, Oil and Special Materials Control Division
Allen Cywin
Director, Effluent Guidelines Division
Russel H. Wyer
Henry Van Cleave
Co-Chairmen, Oil Extraction Task Force
Martin Halper
Project Officer
October, 1974
U. S. Environmental Protection Agency
Washington, D. C. 20460
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ABSTRACT
This development document presents the findings of an extensive study
of the oil and gas extraction industry for the purposes of developing
effluent limitation guidelines, standards of performance, and pretreat-
ment standards for the industry to implement Sections 304, 306, and
307 of the Federal Water Pollution Control Act of 1972, (PL 92-500).
Guidelines and standards were developed for the overall oil and gas
extraction industry, which was divided into 14 subcategories.
Effluent limitation guidelines contained herein set forth the degree of
reduction of pollutants in effluents that is attainable through the appli-
cation 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 demonstration technology (BADT).
Annual costs for the oil and gas extraction industry for achieving BPCT
by 1977 are estimated at $192,000,000.00. This preliminary cost
estimate could be revised when more data for small facilities become
available.
Supporting data and rationale for the development of proposed effluent
limitation guidelines and standards of performance are contained in
this development document.
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TABLE OF CONTENTS
Section Page No.
ABSTRACT i
TABLE OF CONTENTS ii
LIST OF TABLES viii
LIST OF FIGURES xi
I CONCLUSIONS 1-1
II RECOMMENDATIONS II-1
III INTRODUCTION III-l
Purpose and Authority III-2
General Description of Industry III-2
Exploration III-3
Drilling System III-3
Production System III-l0
Evolution of Facilities III-18
Field Services 111-21
Industry Distribution 111-24
Gulf of Mexico 111-25
California III-26
Cook Inlet, Alaska 111-26
Industry Growth 111-27
Bibliography 111-30
11
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Table of Contents, contd.
Section Page No.
IV INDUSTRY SUBCATEGORIZATION IV-1
Rationale of Subcategorization IV-1
Development of Subcategories IV-2
Facility's Size, Age and Waste Volumes IV-3
Process Technology IV-5
Climate IV-5
Waste Water Characteristics IV-6
Facility Location IV-8
Description of Subcategories IV-11
Production Brine Waste IV-11
Deck Drainage IV-11
Sanitary Waste IV-12
Drilling Muds IV-12
Drill Cuttings IV-12
Physical/Chemical Treatment of Wells IV-13
Solids Removal IV-13
Bibliography IV-14
V WASTE CHARACTERISTICS V-l
Waste Constituents V-2
Production (Offshore) V-2
Production (Onshore) V-5
111
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Table of Contents, contd.
Section Page No.
V, contd.
Drilling V-9
Sanitary Wastes V-12
Bibliography V-14
VI SELECTION OF POLLUTANT PARAMETERS VI-1
Selected Parameters VI-1
Parameters for Effluent Limitations VI-1
Oil and Grease VI-1
Fecal Coliform - Chlorine Residual VI-1
Floating Solids VI-3
Other Pollutants VI-4
Bibliography VI-10
VII CONTROL AND TREATMENT TECHNOLOGY VII-1
In-plant Control/Treatment Techniques VII-1
Process Technology VII-2
Pretreatment VII-4
Operation and Maintenance VII-4
Analytical Techniques and Field
Verification Studies VII-6
Variance in Analytical Results for
Oil and Grease Concentrations VII-7
Field Verification Studies VII-11
IV
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Table of Contents, contd.
Section Page No.
VII, contd.
End-of-Pipe Technology: Waste Water
Treatment (with Brine Discharges to
Sea or Coastal Waters) VII-16
Dissolved Gas Flotation VII-16
Parallel Plate Coalescers VII-20
Filter Systems (Loose or Fibrous
Media Coalescers) VII-22
Gravity Separation VII-23
Chemical Treatment VII-24
Effectiveness of Treatment Systems VII-27
End-of-Pipe Technology: Waste Water
Treatment (With No Discharge of Brine
to Sea or Coastal Waters) VII-29
Subsurface Disposal VII-33
Disposal Zone VII-39
End-of-Pipe Technology: Other Treatment
Systems VII-42
Treatment System By Pass VII-42
Deck Drainage VII-43
Sand Removal VII-44
Drilling Operations (Offshore) VII-45
Drilling Operations (Onshore) VII-47
Field Services VII-47
Sanitary (Offshore) VII-48
Bibliography VII-53
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Table of Contents, contd.
Section Page No.
VIII COST. ENERGY, AND NONWATER-
QUALITY ASPECTS VIII-1
Cost Analysis VIII-1
Offshore Brine Disposal VIII-2
Onshore Brine Disposal VIII-6
Offshore Sanitary Waste VIII-10
Nonwater-Quality Aspects VIII-13
Bibliography VIII-14
IX EFFLUENT LIMITATIONS FOR BEST
PRACTICABLE CONTROL TECHNOLOGY IX-1
Production Brine Waste - Discharge
Technology IX-1
Gulf Coast and Coastal Alaska IX-1
Procedure For Development of
BPCT Effluent Limitations IX-2
Production Brine Waste - No Discharge
Technology IX-13
Procedure for Development of
BPCT Effluent Limitations IX-14
Sanitary Wastes -- Offshore Manned
Facilities With 10 or More People DC-14
Sanitary Wastes -- Small Offshore
Manned Facilities Operating
Intermittently IX-15
Deck Drainage IX-16
By Pass (Offshore Operations) IX-17
VI
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Table of Contents, contd.
Section Page No.
IX, contd.
Drilling Muds IX-18
Drill Cuttinge IX-20
Workover IX-2 2
Produced Sand IX-23
X EFFLUENT LIMITATION FOR BEST
AVAILABLE TECHNOLOGY X-l
XI NEW SOURCE PERFORMANCE STANDARDS XI-1
XII ACKNOWLEDGMENTS XII-1
XIII GLOSSARY AND ABBREVIATIONS XIII-1
Vll
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LIST OF TABLES
Table No. Title Page No.
II-l Industry Subcategorization II-3
II-2 Effluent Limitation - BPCT II-4
II-3 Effluent Limitation - BAT and New Source II-5
III-l U.S. Supply and Demand of Petroleum
and Natural Gas 111-28
III-2 U.S. Offshore Production 111-28
V-l Averages of Constituents in Produced
Formation Water - - Gulf of Mexico V -4
V-2 Range of Constituents in Produced
Formation Water -- Offshore California V-6
V-3 Range of Constituents in Produced
Formation Water -- Offshore Texas V-7
V-4 Ranges of Dissolved Constituents for
Selected Onshore Subsurface Formation
Water V-8
V-5 Volume of Cuttings and Muds in Typical
10, 000 Foot Drilling Operation V-ll
V-6 Raw Sanitary Wastes V-l3
VI-1 Selected Parameters VI-2
VI-2 A Comparison of Toxic Effluent Standards
and Surveyed Production Platforms For
Toxicants in Produced Formation Water VI-6
VI-3 Effluent Quality Requirements For Ocean
Waters of California VI-9
VII-1 Preparation of Analytical Samples VII-8
VII-2 Oil and Grease Data, Texas Coastal VII-10
Vlll
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List of Tables, contd.
Table No. Title Page No.
VII-3 Oil and Grease Data, California Coastal VII-10
VII-4 Performance of Individual Units,
Lousiana Coastal VII-13
VII-5 Verification of Oil and Grease Data,
Texas Coastal VII-14
VII-6 Verification of Oil and Grease Data,
California Coastal VII-15
VII-7 Performance of Various Treatment
Systems, Louisiana Coastal VII-28
VII-8 Per Capita Design Parameters For
Offshore Sanitary Wastes VII-51
VII-9 Average Effluents of Sanitary
Treatment Systems, Coastal Louisiana VII-51
VII-10 Treatment Facilities For Sanitary
Wastes, Offshore Gulf Coast VII-52
VIII-1 Operating Cost Factors For Brine
Treatment Facilities Offshore VIII-5
VIII-2 Cost For Treating Brine on Offshore
Installations, 5, 000-Barrel-Per-Day
Flow Rate VIII-7
VIII-3 Costs For Treating Brine on Offshore
Installations, 10, 000-Barrel-Per-Day
Flow Rate VIII-8
VIII-4 Costs For Treating Brine on Offshore
Installations, 40, 000-Barrel-Per-Day
Flow Rate VIII-9
VIII-5 Estimated Costs For Onshore Disposal
of Produced Formation Water by
Shallow Well Injection With Lined Pond
For Standby VIII-11
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List of Tables, contd.
Table No. Title Page No.
VIII-6 Estimated Treatment Plant Costs For
Sanitary Wastes For Offshore Locations
Packed Extended Aeration Process VIII-12
IX-1 Statistical Results. Oil and Grease IX-10
IX-2 BPCT For Sanitary Wastes IX-15
IX-3 BPCT For Deck Drainage IX-17
IX-4 BPCT For By Pass IX-18
IX-5 BPCT For Drilling Muds, Offshore DC-19
IX-6 BPCT For Drilling Muds, Onshore DX-20
IX-7 BPCT For Drill Cuttings, Offshore IX-21
DC-8 BPCT For Drill Cuttings, Onshore DC-21
DC-9 BPCT For Workover and
Completions, Offshore DX-22
IX-10 BPCT For Workover and
Completions, Onshore DX-23
IX-11 BPCT For Produced Sand K-23
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LIST OF FIGURES
Figure No. Title Page No.
III-l Rotary Drilling Rig III-5
III-2 Shale Shaker and Blowout Preventer III-6
III-3 Central Treatment Facility in
Estuarine Area III-12
III-4 Horizontal Gas Separator III-14
III-5 Vertical Heater-Treater 111-16
VII-1 Rotar-Disperser and Diffused Gas
Flotation Processes For Treatment
of Waste Brine Water VII-18
VII-2 Onshore Production Facility With
Discharge to Surface Waters VII-31
VII-3 Typical Cross Section Unlined Earthern
Oil-Water Pit VII-32
VII-4 Typical Completion of an Injection Well
and a Producing Well VII-37
IX-1 Cumulative Plot Effluent Concentrations
of All Selected Flotation Units in the
Louisiana Gulf Coast Area IX-11
DC-2 Effluent Concentrations of Selected
Flotation Units IX-12
XI
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SECTION I
CONCLUSIONS
EPA's Oil Extraction Task Force conducted a major study of
the waste water treatment technology for the oil and gas extraction
point source category. The study consisted of four phases: (1)
literature survey, (2) field verification study, (3) data collection
and analysis, and (4) data evaluation and documentation. The
Task Force reached the following major conclusions:
. The most significant wastes generated by the oil and
gas extraction category are production brines, drilling muds,
and cuttings. Minor wastes include sanitary wastes and oil
from deck drainage.
. Type of operation, waste characteristics, and location
are the main factors affecting subcategorization of the industry
for the purpose of establishing effluent limitations. Size of
facility, climate, and volumes of waste generated have little
influence on treatment technology.
. Oil and grease are the most important pollutants con-
tained in wastes from brine production, deck drainage, drilling
operations, and sand removal. Oil and grease require establish-
ment of effluent limitations.
. Control and treatment technology for produced brine
wastes have been developed which eliminates effluent discharges
into surface waters. Current practice in the Gulf of Mexico and
Coastal Alaska utilize technology which discharges treated brine
waste into saline waters.
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. Physical/chemical brine treatment systems consisting of
equalization, chemical addition, and gas flotation are the best
demonstrated technology for facilities located in the Gulf of Mexico
and Coastal Alaska. The long term average for oil and grease is
27 mg/1 for the exemplary treatment systems.
. Physical/chemical treatment followed by reinjection is
the best demonstrated technology for control of produced brines
in Coastal California and onshore areas.
. Control and treatment technology is subject to malfunc-
tions which are caused by formation characteristics, improper
operating procedures, equipment failure, or start-up problems.
An effective program to investigate the causes of failure and
take corrective action could eliminate the majority of the
malfunctions and reduce the present high variability in effluent
oil and grease concentrations.
. Equipment failure often results in untreated or partially
treated brine discharges to surface waters. Minimal gravity
separation systems on by pass lines are provided at some
facilities to remove free oil.
. Oil and grease sampling and laboratory analytical pro-
cedures are not uniform throughout the industry, which causes
considerable error in reports on performance of treatment
systems.
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. Application of best practicable and best available treat-
ment technologies will result in little additional impact on air
quality, solid waste disposal, and noise pollution control.
. The total cost to industry for application of best
practicable control technology is estimated at $192, 000, 000. 00.
1-3
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SECTION II
RECOMMENDATIONS
Based on the finding and conclusion of the study of the control
and treatment technology for the oil and gas extraction industry,
the Task Force makes the following major recommendations:
. For the purpose of establishing effluent limitations,
the industry be subcategorized as indicated in Table II-1.
. For the discharge technology subcategory, the best
practicable control technology (BPCT) or end-of-pipe brine treat-
ment be based upon physical/chemical technology consisting of
equalization, chemical injection, and gas flotation.
. For the no discharge technology subcategory, the
best practicable control technology be based upon physical/
chemical treatment followed by reinjection.
. Effluent limitations for best practicable control
technology for all subcategories be established in accordance
with the values listed in Table II-2.
. Best available technology (BAT) for brine wastes be
based upon physical/chemical treatment followed by reinjection,
and effluent limitations be established in accordance with the
values listed in Table II-3.
. New source performance standards be based upon best
available technology, and effluent limitations be established in
accordance with Table II-3.
II-1
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. A program to investigate causes of failures and take
corrective action programs be implemented to eliminate
controllable malfunction and reduce high variability in
effluent oil and grease concentrations.
. Standardized procedures for collecting, preserving,
and analyzing samples be adopted throughout the industry to
improve analysis of treatment systems performance, treat-
ment system operating procedures, and process operations.
II-2
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TABLE II-l
Industry Subcategorization
Production Brine Wastes
No Discharge Technology
Discharge Technology (Gulf Coast and Coastal Alaska)
Offshore
Deck Drainage
Drilling Muds
Drill Cuttings
Sanitary
Manned facilities with 10 or more people (M1O)
Manned facilities with less than 10 people or
intermittently manned (M9IM)
Physical/Chemical Treatment of Wells
Solids Removal
Onshore
Drilling Muds
Drill Cuttings
Physical/Chemical Treatment of Wells
Solids Removal
II-3
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TABLE II-2
Effluent Limitation - BPCT
Allowable Effluent Levels
Subcategory
Oil & Grease
mg/1
Daily Monthly
Max. Max.
Chlorine Floating Other
Residual Solids
mg/1
Production Brine Waste
No Discharge Technology
Discharge Technology
Offshore
Deck Drainage
Drilling Muds
Drill Cuttings
Sanitary
M1O
M9IM
Physical/Chemical
Treatment of Wells
Solids Removal
85
85
None
None
None
57
57
None
None
None
1. 0 + 40%
None
No dis-
charge
None None
Onshore
Drilling Muds
Drill Cuttings
Physical/Chemical Treat-
ment of Wells
Solids Removal
No dis-
charge
No dis-
charge
No dis-
charge
No dis-
charge
II-4
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TABLE II-3
Effluent Limitation - BAT and New Source
Allowable Effluent Levels
SUBCATEGORY
Oil & Grease
mg/1
Daily Monthly
Max. Max.
Chlorine
Residual
mg/1
Floating
Solids
Other
Production Brine Waste
No Discharge Technology
Discharge Technology
Offshore
Deck Drainage
Drilling Muds
Drill Cuttings
Sanitary
M10
M91M
Physical/ Chemical
Treatment of Wells
Solids Removal
None None
None None
None None
None None
1. 0 + 40%
None
No dis-
charge
No dis-
charge
No dis-
charge
Onshore
Drilling Muds
Drill Cuttings
Physical/Chemical Treat-
ment of Wells
Solids Removal
No dis-
charge
No dis-
charge
No dis-
charge
No dis-
charge
II-5
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SECTION III
INTRODUCTION
Purpose 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 achieve-
ment 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 accor-
dance with regulations issued by the Administrator pursuant to
Section 304(b) of the Act.
Section 306 of the Act requires the achievement by new
sources of a Federal standard of performance providing for the
control of the discharge of pollutants. 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.
III-l
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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:
. The degree of effluent reduction attainable through application
of the best practicable control technology currently available.
. The degree of effluent reduction attainable through appli-
cation 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 limitation
guidelines pursuant to Section 304(b) of the Act for certain segments
of the petroleum industry.
General Description 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 else-
where
Within the above SIC's this study covers those activities carried
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
III-2
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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 subsur-
face structure. The special surveys 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 knowledge of geologic
III-3
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formation. This latter class of wells may be shallow and conducted
in the initial exploratory phase of operations, or may be deep
exploration seeking to to discover oil- or gas- bearing reservoirs.
Most wells are drilled today by rotary drilling methods. The
basic components of this system consist of:
. 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.
. 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 III-l). 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
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 III-2).
Ill-4
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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. III-l — ROTARY DRILLING RIG
III-5
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CASING
DRILL PIPE
DRILL BIT
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
Fig. III-2 ~ SIIALESHAKER AND BLOWOUT PREVENTER
III-6
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For offshore operations, drilling rigs may be mobile or
stationary. Mobile rigs are used for both exploratory and development
drilling, while stationary rigs arc 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 semisubmersible -- essentially a floating
platform 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 or" 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.
Ill-7
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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 III-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 include: bentonite or attapulgite clays
to increase viscosity and create a gel; barium sulfate (barite), a
weighing 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 the 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 have entered the hole from the formation
(water, oil, or gas). When the mud arrives at the surface, cuttings,
silt, and sand are removed by shale shakers, desilters, and
desanders. Oil or gas from the formation is also removed, and
III-8
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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
cutting, 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 shale shakers and cyclone
separators (desanders or desilters) usually go to an earthen (slush)
pit adjacent to the rig. To dispose of this material, at the end of
drilling operations, the pit is backfilled.
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.
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.
Ill-9
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Production System
Crude oil, natural gas, and gas liquids are normally pro-
duced from geological reservoirs through a deep bore well into the
surface of the earth. The fluid produced from oil reservoirs nor-
mally consists of oil, natural gas, and salt water or brine contain-
ing both dissolved and suspended solids. Gas wells may produce
dry gas but usually also produce varying quantities of light hydro-
carbon liquids (known as gas liquids or condensate), and salt
water. As in the case of oil field brines, the water contains dis-
solved and suspended solids and hydrocarbon contaminants. The
suspended solids normally are 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 Gravity" 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 material.
These 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
IH-10
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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 valves
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 III-3). The
marketable constituents, normally the gas and oil, 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
III-11
-------
CENTRAL TREATMENT FACILITY IN ESTUARINE AREA
HIGH PRESSURE GAS
I GAS OIL. WATER. SAND)
S-LIQUID SEPARATION PLATFORM
WATFR TREATMENT POLLUTION CONTROL P .-
Fig. III-3 — CENTRAL TREATMENT FACILITY IN ESTUARINE AREA
-------
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 emulsification. 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 III-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-pres-
sure, 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
III-13
-------
M
M
I
H
A-OIL AND GAS INLET
B-IMPACT ANGLE
C-DE-FOAMING
ELEMENT
D-WAVE BREAKER AND
SELECTOR PLATE
E-MIST EXTRACTOR G-DRAIN
F-GAS OUTLET
H-OIL OUTLET
(DUMP VALVEl
Fig. IXI-4 — HORIZONTAL GAS SEPARATOR
-------
oil from the brine. Water which is not emulaified 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 HI-5). In this 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 elec-
trical 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 1 percent) so as to be
marketable. The brine or brine/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 market-
able products (clean oil and dry gas). In contrast, the next stages
III-15
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OAS OUTLET
EMULSION
INLET
EXSELSIOR
FILTER
(OTHER TYPES OF UNITS
MIGHT CONTAIN THE GRID
OF AN ELECTRIC DEHYDRATOR
IN PLACE OF THE FILTER SECTION)
OIL OUT
GAS OUT
EMULSION IN
WATER OUT
Fig. III-5 — VERTICAL HEATER-TREATER
111-16
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of treatment are necessary to remove sufficient oil from the brine
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 waste brine 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. (Brines 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 present offshore and near shore (marsh) facilities in
the Gulf of Mexico and most facilities in Cook Inlet, Alaska, treat
and dispose of their brine waste 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
III-17
-------
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 wells and increase ultimate recovery.
This process is one of several known as secondary recovery since
it produces oil beyond that available by ordinary production methods.
A successful waterflood project will increase the amount of oil
being produced at a field. It will also increase brine production
and thus effect the amount of waste water that must be treated.
Pressure maintenance by 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 waste brine and is used in
California for disposal of brine from offshore facilities.
Evolution of Facilities
Early offshore development tended to place wells on individ-
ual structures, bringing the fluids ashore for separation and treat-
ment (see Figure III-3). As the industry moved farther offshore,
the wells still tended to be located on individual platforms but the
output to a central platform for separation, treatment, and dis-
charge 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
111-18
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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, including
compressor stations for gas lift wells and sophisticated water treat-
ment facilities for water flood projects.
Platform design reflects the operating environment. Cook
Inlet platforms are enclosed as 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. Present platforms far removed from shore are
practically independent production units.
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 maintenanp^and secondary recovery
or solely for disposal. In the latter case, the well would probably
be shallower and operate at lower pressure. The system 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 so-called "tertiary
m-19
-------
recovery." The process usually involves injecting some substance
into the oil reservoir to release or carry out additional oil not
recovered by primary recovery (flowing wells by natural reservoir
pressure, pumping, or gas lift) or by secondary recovery.
Tertiary recovery is usually classified by the substance
injected into the reservoir; and includes:
. Thermal recovery.
Miscible hydrocarbon.
Carbon dioxide.
Alcohols - soluble oil - micellar solutions.
. Chemical floods - surfactants.
. Gas - gas/water - inert gas.
. Gas repressuring - depletion.
. Polymers.
. Foams, emulsions, precipitates.
The material is injected into the reservoir and moves through
the reservoir to the producing wells. During this 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 applica-
tions; and three combinations of miscible hydrocarbon with gas drive.
Ill-20
-------
At this time very little is known about the wastes that will be
produced by these production processes. They will obviously
depend on the type of tertiary recovery used.
Field Services
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 the 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 "completion" -- 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,
111-21
-------
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 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 or it may worsen with the
passage of time, or both. 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.
HI-2 2
-------
In fracturing, hydraulic pressure forces a fluid into the reservoir,
producing fractures, cracks and channels. Fracturing fluids may contain
acids so that chemical disintegration takes place as well as fracturing.
The fluids also contain sand or some similar material that keeps the
fractures 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 contaminated 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 of 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 pro-
duction from the well will contain some of these fluids. Offshore,
contaminated oil and other 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
111-23
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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 Distribution.
Oil is presently produced in 32 of the 50 states and from the Outer
Continental Shelf (OCS) off of Louisiana, Texas, and California. Explor-
atory drilling is underway on the OCS off of Mississippi, Alabama, and
Florida. The five largest oil-producing States in 1972 were: Texas,
Louisiana, 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 producing States.
For 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.
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. Oil is produced from State waters in all three
and from the OCS off the Gulf of Mexico and California. Offshore oil
production in 1973 was approximately 62 million barrels from Cook
Inlet, 116 million from California, and 215 million from Louisiana
and Texas.
HI-24
-------
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.
Leases have been granted in water depths as great 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 develop-
ment in the offshore areas of California since the Santa Barbara
blowout of 1969. (4)
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
HI-25
-------
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-weU 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. Brine 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 last five
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 brine and oil ashore for separation and treatment. Some plat-
forms are producing increasing amounts of brine, and this, plus the
occasional plugging of oil/water pipelines with ice in the winter, will
encourage a change to platform separation, treatment, and disposal of
brines.
Cook Inlet platforms are presently employing gas lift and are
treating Inlet water for water flooding.
III-2B
-------
Industry Growth.
From 1960 to 1970, the Nation's demand for energy increased
at. an average rate of 4. 3 percent. Table III-l gives the projected
national demands for oil and gas through 1985 and Table III-2 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 of 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 three areas in the Atlantic Coast (Georges Bank,
Baltimore Canyon, and Georgia Embayment) plus 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.
Ill-2 7
-------
TABLE III-l
U.S. Supply and Demand of Petroleum
and Natural Gas (5)
1971 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
% of Domestic Petroleum Demand that
will be fulfilled by domestic supply 74. 0 56. 3 46. 6
Natural Gas (trillion cubic feet/year)
Projected Demand 22.0 26.2 27.5
% of Total U. S. Energy Demand 33.0 28.1 24.3
Projected Domestic Supply 21.1 23.0 23.8
% of Domestic Gas Demand that will
be fuHilled by domestic supply 96.0 85.5 80.7
TABLE III-2
U.S. Offshore Oil Production - million barrels/day (6)
1970 1971 1972 1973
1.58 1.69 1.67 1.59
111-28
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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 increas-
ing proportion of our domestically produced supplies of gas and oil.
111-29
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SECTION III
Bibliography
1. The University of Texas-Austin, Petroleum Extension Service, and
Texas Education Agency, Trade and Industrial Service. 1962.
"Treating Oil Field Emulsions. " 2d. 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 1974 (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, D. C.
5. Dupree, W. G., and West, J. A. 1972. "United States Energy
Through the Year 2000." U.S. Department of Interior.
Washington, D. C.
6. McCaslin, John C. 1974. "Offshore Oil Production Soars. "
Oil and Gas Journal, Vol. 72: No. 18: pp. 136-142.
111-30
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SECTION IV
INDUSTRY SUBCATEOGRIZATION
Rationale of Subcategorization
SICs 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:
. Type of facility or operation.
. Facility's size, age, and waste volumes.
. Process technology.
. Climate.
. Waste water characteristics.
. Location of facility.
Field surveys, waste treatment technology, and effluent data
indicate that the most important factors are the type of operations,
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.
IV-1
-------
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. Brine production may vary
from less than one percent of the production fluids to 90 percent.
High volumes of brines 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 are dependent upon the depth of the well, subsur-
face characteristics, recovery of drill muds, and recycling. There-
fore industry subcategorization did not include an analysis of segment-
ing the industry on waste load per unit of production.
Development of Subcategories
Based upon the type of facility, the industry may be subdivided
into three major categories with similar type operations or
activities -- crude petroleum and natural gas production; oil and gas
well field exploration and drilling; and oil and gas well completions
and workover. Further subdivision can be made within each to reflect
location -- offshore and on shore -- and any wastes requiring specific
effluent limitations and standards. Since sanitary wastes for onshore
operations normally do not result in any discharge and since deck
drainage is not applicable to onshore operations, these subcategories
are only applicable to offshore facilities. Considering location and
wastes, the major groups are subcategorized as follows:
I Crude Petroleum and Natural Gas Production
A. Production Brine Waste
IV-2
-------
B. Deck Drainage - Offshore
C. Sanitary Waste - Offshore
II Oil and Gas Well Field Exploration and Drilling
A. Drilling Muds
B. Drill Cuttings
C. Sanitary Waste - Offshore
III Oil and Gas Well Completions and Workover
A. Chemical Treatment of Wells
B. Solids Removal
All six factors were then examined in detail to uncover additional
relationships that would permit still further subcategorization.
Facility's Size, Age and Waste Volumes
Category I facilities differ little in the type of process or brine
waste 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 brines to another facility for treatment and
disposal. Comparable treatment technology has been developed for
both large and small systems.
IV-3
-------
The types of treatment for sanitary wastes for large and small
offshore facilities are different, as are facilities which are intermit-
tently maimed. For smaller and intermittent facilities, the waste may
be incinerated or chemically treated, resulting in no discharges.
Because of operational problems and safety considerations, other types
of treatment systems that will result in a discharge are being con-
sidered. 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 number 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 brines for a number of years until the formation begins to pro-
duce water. The period before initiating treatment is variable, depend-
ing on the characteristics of the particular field, and can also be
affected by method of recovery. If wastes are to be treated offshore,
initial design should provide for the treatment system, the space
required for equipment, platform loads, and energy requirements
even though actual waste water treatment will not be required for a
number of years. No further subcategorization is needed to account for
production field age or brine produced since similar treatment tech-
nology is used regardless of the quantity of brine produced.
IV-4
-------
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 brine waste data showed no significant difference
in oil content between the various process units; when high influent
concentrations to the brine 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
different process systems.
Climate
Climate was considered because conditions in the production
regions differ widely. All regions treat by gravity separation or
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 offshore 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
contaminants (residual oils from drips, leaks, etc. ) for- dec:k drainage
IV-5
-------
are independent of rainfall. Proper operation and maintenance can
reduce waste oil concentrations to minimal levels, thus reducing the
effect of rainfall. No subcategorization is required to account for
climate.
Waste Water Characteristics
Treatability and other characteristics of brine waste water are
one of the most significant factors considered for subcategorization.
Production waters high in total dissolved solids (TDS) cannot be dis-
charged into fresh water; therefore, treatment technologies for
onshore operations have been developed which result in no effluent
discharge. Similarly, because of rigid State controls on specific
brine components, treatment technology has been developed for use in
California to eliminate discharges to saline waters as well as fresh
water. The brine treatment systems for the Gulf Coast and
Coastal Alaska differ from the California oil production areas since
the technology was developed to meet requirements that permitted
effluent discharges to saline waters.
The technology developed for each area has been primarily
influenced by local regulatory requirements, but other factors
associated with brine water treatability and cost effectiveness may
also have had an effect. (1, 2, 3) Factors which may affect brine
water treatability are:
Physical and chemical properties of the crude oil,
including solubility.
IV-6
-------
. Concentration of suspended and settable solids.
. Fluctuation of flow rate and production method.
. Droplet sizes of the entrained oil emulsification.
. Other characteristics of the produced water.
The impact of these variables can be minimized by existing
process and treatment technology, which includes desanders, surge
tanks, and chemical treatment.
Other factors that affect the type of treatment process
selected are as follows:
. Availability of space and site conditions such as dry
land, marsh area, or open water.
. Proximity to shore.
. Type and depth of subsurface formations suitable for
reinjection of brine waste.
If adequate land is available and the facility is relatively close
to shore, more complex onshore treatment systems may be provided
including: primary clarification, coagulation, secondary clarification,
and filtration.
Based on the results of four field surveys, information provided
by the oil industry, equipment manufacturers, chemical suppliers,
and literature surveys, there is insufficient technical information to
determine which of the above factors or combination of factors (if any)
could be used to subcategorize the industry based on waste water
treatability and other characteristics.
IV-7
-------
Initial information on performance levels for efiluent discharges
off the Texas and California coasts indicated that these systems are
more efficient than those off the coast of Louisiana; however, field
verification surveys indicated that the data was not comparable
because of variations in analytical procedures. Effluent levels for
similar treatment systems which had effluent discharges were found
to be comparable for all areas.
An initial evaluation of brine treatability, treatment technology
and related factors indicated that there may be no justification for sub-
categorizing based upon discharge and no discharge technologies. How-
ever, upon further review of the complexity of the variables involved,
it was concluded that existing treatment systems in the Gulf Coast and
Coastal Alaska which have effluent discharges should be subcategorized
to allow discharge technology; no further subcategorization based on
brine chara.cteristi.es is justified, however.
Discharges are permitted in inland areas where the brines are
low in TDS and the water is used for beneficial purposes such as in
stock watering and irrigation. These are exceptional cases and will be
discussed in other sections of this report.
Facility Location
Location is a significant factor specifically with respect to
areas where brine discharges are not permitted. The usual procedure
in inland areas is to reinject the brine to the producing formation,
which assists oil recovery, or to other subsurface formations for
IV-8
-------
disposal only. Evaporation ponds are used in some inland areas, with
the assumption that all brines are evaporated and no discharge occurs.
In an arid Western oil field an evaporation pond, if properly main-
tained, may provide for acceptable disposal of the brines; 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 to allow discharges to be used for stock watering
and other beneficial uses, subcategorization based on brine charac-
teristics takes into account these location factors, and no further
subdivision is needed.
For Categories II and III, the technology for disposal of drill-
ing mucls, 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 waters.
Onshore technology has been developed to ensure no discharge to
surface waters, and waste materials are disposed of in approved
land disposal sites. Categories II and III have been subcategorized
to reflect the different technologies for onshore and offshore
locations.
Another important consideration with respect to subcategorizing
based on discharge and no discharge technology is the division between
the two areas. Current practice allows discharges into salt water and
excludes them from fresh water except for brines with low TDS. There
IV-9
-------
are facilities that are located in areas where fresh and salt water
interface or that have low TDS levels; therefore, the division
between the different technologies has been established in accord-
ance with the impact of brine discharges on the receiving water.
Treatment technology which results in a discharge has been appli-
cable if the effluent does not violate approved State Water Quality
Standards, otherwise the no discharge technology has been required.
Based upon the above rationale and discussion the oil production
industry has been subcategorized as follows:
I Crude Petroleum and Natural Gas Production
A. Production Brine Waste
1. No Discharge Technology
2. Discharge Technology (Gulf Coast & coastal Alaska)
B. Deck Drainage - Offshore
C. Sanitary Waste - Offshore
a. Facilities continuously manned with 10 or more people.
b. Facilities with less than 10 people or intermittently
manned.
II Oil and Gas Well Field Exploration and Drilling
A. Onshore
1. Drilling Muds
2. Drill Cuttings
B. Offshore
1. Drilling Muds
2. Drill Cuttings
3. Sanitary Waste
IV-10
-------
a. Facilities continuously manned with 10 or more people.
b. Facilities with less than 10 people or intermittently
manned.
Ill Oil and Gas Well Completions and Workover
A. Onshore
1. Physical/Chemical Treatment of Wells
2. Solids Removal
B. Offshore
1. Physical/Chemical Treatment of Wells
2. Solids Removal
Description of Subcategories
Production Brine Waste
Production brine waste includes all waters and participate
matter associated with oil- and gas- producing formations. Sometimes
the terms "formation water" or "brine water" are used to describe
production brine waste water. Most oil- and gas- producing geo-
logical formations contain an oil-water or gas-water contact.
In some formations, water is produced with the oil and gas in early
stages of production; in others, water is not produced until the pro-
ducing formation has been significantly depleted; in still other types
of oil- and gas- producing formations, water is never produced. (4)
Deck Drainage
Deck drainage includes all waste resulting from platform wash-
ings, deck washings and run-off from curbs, gutters, and drains
(including drip pans, and work areas).
IV-11
-------
Sanitary Waste
Sanitary waste includes human body waste materials discharged
from toilets and urinals and domestic waste 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 dur-
ing drilling or workover.
Generally, two basic types of muds (water-based and oil muds)
are used in drilling. Various additives may be used 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, weighing 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 forma-
tions 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. Cuttings are separated from the drilling
mud at the surface.
IV-12
-------
Physical/Chemical Treatment of Wells
Physical/chemical treatment of wells includes acidizing and hydrau-
lic fracturing of the well to improve oil recovery. Hydraulic factur-
ing 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 until the pressure is released.
Chemical treatment of wells consists of pumping acid or chemicals
down the well to remove formation damage and increase drainage in
the permeable rock formations. (8)
Solids Removal
The 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.
IV-13
-------
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, Novem-
ber 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._
8. American Petroleum Institute. Division of Production. 1973.
"Primer of Oil and Gas Production. " 3d. ed. Dallas,
Texas.
IV-14
-------
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
brine watered) 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 brine 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
420, 000 barrels of brine water per day (2); by 1983, Louisiana
coastal production will generate an estimated 2. 54 million
barrels of brine water per day. (3)
This section characterizes the types of wastes that are pro-
duced at offshore and onshore wells and structures. The dis-
cussion of drilling wastes can be applied to any area of the United
States since these wastes do not change significantly with locality.
V-l
-------
Other than oils, the primary waste constituents considered
are heavy metals and other toxicants contained in drilling muds
or formation fluids. (4),)
Sanitary wastes are also produced during both drilling and
production operations both onshore and offshore, but they are
discussed and 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 Constituents
Production (Offshore)
Production wastes include formation waters associated with
the extracted oil, sand and other solids removed from the
formation waters, deck drainage from the platform surfaces,
and sanitary wastes.
The foranation waters or brines 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 some-
what from one geographical area to another, with the most pro-
nounced variance being chloride levels. Table V-l shows the
waste constituents in offshore Louisiana production facilities
in the Gulf of Mexico. The data were obtained during the veri-
fication survey conducted by EPA in 1974. The only influent
data obtained in the survey were on oil and grease. In planning
V-2
-------
the verification survey, it was decided that offshore brine
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 (TOO is also tabulated under effluent
in Table V-l, but it is reasonable to assume that actual analysis
of the influent would show higher levels. Since TDC is a measure-
ment 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 treat-
ment process.
V-3
-------
TABLE V-l
Averages of Constituents in
Produced Formation Water
-- Gulf of Mexico
Influent
Oil and Grease 202 mg/1
Effluent
Cadmium 0.0678 mg/1
Cyanide 0. 01 mg/1
Chlorides 61,142 mg/1
Mercury Trace
Total Organic Carbon 413 mg/1
Salinity 110,391 mg/1
API Gravity 33. 6 degrees
Suspended Solids 73 mg/1
Volumes
Range - 250 to 200, 000 bbls brine water/day
Average - 15, 000 bbls brine water/day
Source: 25 discharges analyzed in 1974 EPA survey.
V-4
-------
Industry data for offshore California describes a broader
range of parameters (see Table V-2). Similar data were pro-
vided for offshore Texas (see Table V-3). Except as noted on
the tables, all data are from effluents. Oil influent data for
these two areas are listed on Table VII-10.
Sand and other solids are produced along with the production
fluids. Observations made by EPA personnel during field sur-
veys indicated that the sands had a high oil content. Sand has
been reported to be produced at approximately 1 barrel sand
per 2, 000 barrels oil. (5,6)
Production (Onshore)
In general, onshore production fluids are not given the broad
scrutiny that offshore production fluids receive for possible
toxicants and other pollutants. The primary reason is that the
total dissolved solids (TDS) levels in the produced brines are too
high to be discharged to surface fresh water streams. If discharge
is prohibited, then the presence of pollutants other than TDS is
moot.
Iii some arid areas of the United States, produced brine waters
that are reasonably low in TDS are being used for livestock water-
ing and irrigation. Some of these brines are reported to reach
surface streams in these areas. Table V-4 describes brine
water quality in terms of TDS, for a number of onshore oil
production areas which utilize brine water for agricultural
purposes.
V-5
-------
TABLE V-2
Range of Constituents in Produced Formation Water
a
-- Offshore California (7)
Effluent
Constituent
Arsenic
Cadmium
Total Chromium
Copper
Lead
!VI ercury
Nickel
Silver
Zinc
Cyanide
Phenolic Comounds
BOD
5
Range, mg /I
0.001 - 0.08
0.02 - 0.18
0.02 - 0.04
0.05 - 0.116
0.0 - 0.28
0.0005-0.002
0.100 - 0.29
0.03
0.05 - 3.2
0.0 - 0.004
0.35 - 2.10
370 - 1,920
b
State of California
Ocean Effluent Limits
mg/1
0.02
0.03
0.01
0.3
0.2
0.002
0.2
0.04
0.5
0.2
1.0
COD 340 - 3,000
Chlorides 17,230-21,000
TDS 21,700 - 40,400
Suspended Solids
Effluent 1 - 60
Influent 30-75
Oil and Grease 56 - 359
a
Some data reflect treated waters for reinjection.
b
Concentrations not to be exceeded more than 10% of time.
V-6
-------
TABLE V-3
Range of Constituents
in Produced Formation Water
-- Offshore Texas (8)
Effluent a
Constituent Range, mg/1
Arsenic * LO. 01 - LO. 02
Cadmium LO. 02 -0. 193
Total Chromium LO. 10 - 0. 23
Copper LO. 10 - 0. 38
Lead LO. 01 - 0. 22
Mercury LO. 001 - 0. 13
Nickel LO. 10 - 0.44
Silver LO. 01 - 0. 10
Zinc 0. 10 - 0. 27
Cyanide N. A.
Phenolic Compounds 53
BOD 126-342
5
COD 182-582
Chlorides 42, 000 - 62, 000
TDS 806-169,000
Suspended Solids 12 - 656
a
L - less than
N.A. - not available
V-7
-------
TABLE V-4
Ranges of Dissolved Constituents
for Selected Onshore Subsurface
Formation Water (9)
Location Total Dissolved Solids,mg/1
Colorado 333-10,795
Montana 3 50 -15, 2 30
Utah 373-120,395
Wyoming 291-276,390
V-8
-------
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, weighing, 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 pre-
sented 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
V-9
-------
987 pounds of chromium. (2) Table V-5 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. No environmental surveys have been conducted
to determine the spread, migration, or biological impact of
these materials.
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 the salt in the
dome, enlarging the hole, and causing solution cavities in
the formation.
In offshore operations, the direct discharge of cuttings and
water based muds create short term pollution problems due
to 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 experienced observers
have described the existence of substantial plumes of turbidity
when muds and cuttings are discharged.
V-10
-------
TABLE V-5
Volume of Cuttings and Muds in Typical
10, 000-Foot Drilling Operation (2)
Interval,
feet
0-1,000
1, 000-3500
Hole
Size,
inches
24
16
Vol. of
Cuttings,
bbl.
562
623
Wt. of
Cuttings,
pounds
505, 000#
545,000
Drilling
Mud
Sea water
& natural
mud
Gelled sea
water
Vol. of
Mud Com-
ponents,
bbl.
Variable
700
Wt. of
Mud Com-
ponents,
pounds
81, 500
2,500-10,000 12
915
790,000
Lime base 950
424,800
V-ll
-------
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 ingre-
dients, thus are the liquid phase. When muds are displaced
from the well hole they also contain solids from the hole. There
are two types of emulsified oil muds -oil emulsion muds, which
are oil-in-water emulsions, and invert 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 per-
cent water by volume. The water is added by adding emulsifying
and stabilizing agents. Clay solids and weighing agents can also
be added.
Sanitary Wastes
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 V-6 indicates typical waste flow
for offshore facilities and vessels.
V-12
-------
TABLE V-6
Raw Sanitary Wastes
BOD , mg/1 Suspended
No. of
Men
76
RR
OD
R7
D (
42
B'low,
gal/ day
5, 500
1 nsn
1 87^
1,010
2, 155
9 ann
5 Solids, mg/1
Avg. Range Avg. Range
460 270-770 195 14-543
Q*7 ^ ____.. 1 fl 9 ^
ARn - - - - fi9n
225 220
Total
Coli-
form (X 10 )
10-180
Refer-
ence
(10)
ti ^
\i 6)
a
-------
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 Tech-
nology Currently Available To Remove Oil From Water
Produced With Oil and Gas. " Prepared by Brown and
Root, Inc., Houston, Texas.
4. Moseley, F.N., and Cop eland, 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 Produc-
tion 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.
V-14
-------
Sec. V, Bibliography, contd.
10. Sacks, Bernard R. 1969. "Extended Aeration Sewage Treat-
ment 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 Regard-
ing 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 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.
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. "
V-15
-------
SECTION VI
SELECTION OK POLLUTANT PA HA METERS
S<.'lt't:lod Parameters
Oil and grease from produced water, deck drainage, muds,
cuttings, and sand removal, and residual chlorine and floating
solids from sanitary sources have been selected as the pollutants
lor which effluent limitations will be established (see Table VI-1).
The rationale for inclusion of these parameters are discussed
below.
Parameters for Effluent Limitations
Oil and grease
Oil and grease (i. e., petroleum) have long been known to
damage marine ecosystems; the harmful effects of petroleum
have been recognized by international, national and state govern-
ments. (1, 2, 3) The harmful effects of petroleum include, but are
not limited to, acute toxicity, coating and smothering, inhibition of
photosynthesis, and interference with subtle life processes such
as chemical communication. (4, 5)
Fecal Coliform - Chlorine Residual
The concentration of fecal coliform bacteria can serve as an
indication of the potential pathogenicity of water resulting from the
disposal of human sewage. Fecal coliform levels have been estab-
lished to protect beneficial water use (recreation and shellfish
propagation) in the coastal areas.
VI-1
-------
TABLE VI-1
Selected Parameters
Category
Production Brine Waste
No Discharge
Discharge
Offshore Installations
Drilling Muds
Drill Cuttings
Workover
Sanitary
Manned (over 10 people)
Small, intermittent
Onshore Installations
Drilling Muds
Drill Cuttings
Workover
Parameter
Not Applicable
Oil and Grease
Oil and Grease
Oil and Grease
Oil and Grease
Chlorine Residual
Floating Solids
Not Applicable
Not Applicable
Not Applicable
VI-2
-------
The most direct methods to determine compliance with
specified limits are to measure the fecal coliform levels in the
efiluent for seven 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 milligrams per liter (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
determined on a daily basis is a reasonable control parameter.
It is 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 treat-
ment 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
VI-3
-------
discharges or wastes which will settle to form objectional deposits,
float on the surface of the water, and produce objectionable odors.
Floating solids have been selected as a control parameter for
sanitary waste from small or intermittently manned offshore
facilities.
For coastal areas where water quality criteria have been
established other parameters may be selected to meet the
requirement of a specific location.
Other Pollutants
Produced formation waters are known to contain toxic sub-
stances, constituents with substantial oxygen demand, and inorganic
salts. Insufficient data exist to warrant comprehensive control
of these parameters; however, restrictions on these parameters
may be required as a result of water quality requirements as
pointed out in Section V and below.
Formation produced waters have been shown to contain
cyanide, cadmium, and mercury. Section 307(a)(l) 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
3
than or equal to 0. 283 cubic meters per second (m /sec)(10 cubic
feet per second) or into lakes with an area less than or equal to
202 hectares (500 acres). Many estuarine areas fall into this category.
VI-4
-------
The proposed standards include limits for other water bodies
based on dilution and mass emission parameters (see Table VI-2).
The harmful effects of these toxicants, which include direct
toxicity to humans and other animals, biological concentration,
sterility, mutagenicity, teratogenicity, and other lethal and sub-
lethal effects, have been well documented in the development of
the Section 307(a)(l) 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 Wolf (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 .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.
Estuaries, excepting hypersaline lagoons, have salinities rang-
ing from 1 to 35 parts per thousand (ppt). The average brine salinity
VI-5
-------
TABLE VI-2
A Comparison of Toxic Effluent Standards
and Surveyed Production Platforms For
Toxicants in Produced Formation Water
307(a) Toxic Effluent Standards
Concentration, mg/1
Maximum pounds/day
Surveyed Prochic-
tion Platforms
Concentration,
Toxicant
Cadmium
Mercury
L^yiiniuc
a 1
low medium
flow flow
all fresh
waters tidal
0 0.004
0.032
n n nn9
0.010
On n 1 n
0.010
.") C
high
flow
fresh stream lake estu- coast-
tidal ary al
0.040 12.96 10.8 86.4 102.6
0. 320
On9O 1 R9 1 9R 97 n 39 d
. U^-U 1 . DŁ> JL . O O ^I.U o^.t
0. 100
01 nn ____ ____ ____ ____
0. 100
mean range
0.068 0. 50-. 262
— 1 Fd. C (:} S
001 n n n 1 n
less than 10 cfs.
3
less than lOx waste stream.
more than 10 cfs.
VI-6
-------
given in Table VI-2 would be approximately 110 ppt and would
be characteristically devoid of oxygen and high in CO . It is
2
feasible to expect this anoxic, hyper saline fluid, since it is
more dense than the receiving water, to displace the estuarine
bottom waters. This displacement increases density stratification,
preventing aeration while simultaneously adding to the oxygen deficit
and increasing the CO of the bottom waters.
2
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 CO ; it also produces oxygen in excess of respiration so that
2
this upper layer is characteristically supersaturated with O
2
during the daylight hours. The bottom higher salinity layer
functions as the catabolic side of the cycle, (microbial break-
down of organic material with subsequent O utilization
2
and CO production). In a healthy estuarine system, these
2
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, anomalous ion ratios, strange buffer systems, high pH,
and low oxygen solubility, few organisms are capable of adapt-
ing to brine-dominated systems. This results in low diversity
of species, short food chains, and depressed trophic levels. (7)
VI-7
-------
As seen from the above discussion of potential harm from
produced formation 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 VI-3). They were arrived at by first applying safety
factors to known toxicity levels and a consideration of 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
petroleum industry has developed a no discharge technology
(reinjection of brine production water).
VI-8
-------
TABLE VI-3
Effluent Quality Requirements For
Ocean Waters of California
Concentration not to be
exceeded more than:
Unit of
measurement
Arsenic
Cadmium
Total Chromium
Copper
Lead
Mercury
Nickel
Silver
Zinc
Cyanide
Phenolic Compounds
Total Chlorine Residual
Ammonia (expressed as
nitrogen)
Total Identifiable
Chlorinated Hydrocarbons
Toxicity Concentration
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
mg/1
tu
50% of time
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
0.002
1.5
10% of time
0.02
0.03
0.01
0. 3
0.2
0.002
0.2
0.04
0. 5
0.2
1.0
2.0
60.0
0.004
2.0
Radioactivity
Not to exceed the limits
specified in Title 17,
Chapter 5, Subchapter 4,
Group 3, Article 5, Sec-
tion 30285 and 30287 of
the California Adminis-
trative Code.
VI-9
-------
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 on
Marine Ecosystems: A Review for Administrators and
Policy Makers. " U.S. Department of the Interior,
Bureau of Fisheries and Wildlife. Fishery
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". Odum, Copeland, and McMahan, {ed. ). The
Conservation Foundation, Washington, D.C.
VI-10
-------
SECTION VII
CONTROL AND TREATMENT TECHNOLOGY
Petroleum production, drilling, and exploration wastes vary in
quantity and quality from facility to facility; and 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 the reduction or elimination of a waste stream or vary the
character of the constituents and allow the end-of-pipe processes to
be more efficient and cost effective. The two general 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 reinjection of waste brine water to increase reservoir
pressures and utilization of treated production water for steam
generation. An example of recycle systems is the conservation
and reuse of drilling muds. An example of character change in a
waste stream would be the substitution of a positive displacement
pump for a high speed centrifugal pump, thereby reducing the
amount of emulsified oil in the stream and so easing treatment, or
VII-1
-------
substition of a downhole choke for a well head choke, thereby reducing
the amount of emulsion created. (1)
Proper pretreatment and maintenance practices also are effective
in reducing waste flows and improving treatment efficiencies. Return
of deck drainage to process units and elimination of waste crank case
oil from the deck drainage or brine treatment systems are examples
of good offshore pretreatment and maintenance practices.
Process Technology
The single most significant change in process technology which
results in the elimination of brine waste is reinjection of produced
brine water to the reservoir formation for secondary recovery and
pressure maintenance. This is distinguished from reinjection for brine
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 insuffi-
cient to provide the needed water for a secondary recovery and pres-
sure maintenance system. In this case, additional make-up water
must be found, and wells or surface water (including sea water) may
all be used as a source of make-up water. There may be problems
of compatability between produced water and make-up water. A typical
injection system treatment facility for pressure maintenance consists
of a surge tank, flotation cell, filters, retention tank, injection
pumps, and injection wells. (2)
Reinjection of produced brine for secondary recovery and pres-
sure maintenance is a very common practice onshore. It has been
VII-2
-------
estimated that 60 percent of all onshore produced water is reinjected
for secondary recovery.
Water treatment for injection at all installations is similar,
both offshore and onshore. Existing injection systems vary from small
units which treat 2, 000 barrels per day of brine waste to large com-
plexes which handle over 170,000. Waste brine reinjection systems
for pressure maintenance and water flooding are less common in the
Gulf Coast, and none are in use in Cook Inlet, Alaska (Cook Inlet
water is treated and injected for water flooding).
Brine water treatment and injection systems are not limited by
space availability but must be specifically designed to fit offshore
platforms. Two limiting factors which affect brine water reinjection
are insufficient quantity of produced brine water to meet the require-
ment for reservoir pressure maintenance and incompatibility
between make-up sea water and produced water. The sea water
currently injected into the producing formation in Cook Inlet is
reported to be incompatible with produced brine 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 typical injection treatment units; additionally,
water softeners are added to the system.
VII-3
-------
Also, changes in process technology have occurred in drilling
operations. Environmental considerations and high cost of drilling
muds have led to the development of special equipment and proce-
dures 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
brine to shore for processing and brine treatment.
Operation and Maintenance
In addition to the reuse of wa'ste brine water, recycling of
drilling muds, and reduction of waste loads in flows by other in-
plant techniques, another 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 fre-
quency and magnitude of systems upsets.
Some examples of good offshore operations are:
. Elimination of deliberate dumping of waste crankcase oils
into deck drainage collection system.
VII-4
-------
. Reduction of waste water treatment system upset from deck
washdown by eliminating use of detergents.
. Reduction of oil spillage through good prevention techniques
such as drip pans and other collection methods.
Elimination of oil drainage from transfer pump bearings or
seals by pumping into the crude oil processing system.
Reduction of oil gathered in the pig (pipeline scraper) traps
by channeling oil back into the gathering line system instead of the
sump system.
Elimination of extreme loading of the waste brine water
treatment system, when the process system malfunctions, by re-
directing all production to shore for treatment. (3)
Good maintenance practice includes: an inspection of dump
valves for sand cutting as a preventive measure, the use of dual sump
pumps for pumping drainage into surge tanks, use of reliable chemical
injection pumps for waste brine water treatment, and selection of
the best combination of oil- and water-treating chemicals, and
use of level alarms for initiating shut down during major system
upsets.
Operation and maintenance of a waste brine water treatment
system during start-up present special problems. One example on
an offshore facility began with the oil process units upstream of the
waste brine water treatment system. Two problems with the heater-
treaters interfered with the water treatment system: insufficient
heat in the treaters and malfunctioning level controls which caused
VII-5
-------
heavy loading of the water treatment system. A change of the type
of level controls and reduced production from wells contributing large
volumes of water reduced the heating requirements and helped alleviate
the problem during start-up of the waste brine water treatment unit.
Further improvements were achieved by careful selection of the best
chemical combinations for treating oil and waste brine water, and
replacing chemical injection pumps and recycling pumps.
The preceding paragraph describes an actual case where a
detailed failure analysis with corrective action ended an upset in the
waste treatment system. Evaluation of operational practices, process
and treatment equipment and correct chemical use is feasible and is
an engineering technique that should be used to determine the causes
of failures and upsets and to correct them.
The description of these operation and maintenance practices is
not intended to advocate their universal application. The practices
nevertheless indicate that good operations and maintenance on an oil/
gas production facility can have substantial impact on the loads
discharged to the waste treatment system and the efficiency of the
system. Careful planning, good engineering, and a commitment
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. An early
VII-6
-------
analysis of the 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;
also 3-day studies were conducted in Texas and California to verify
performance data. In addition, three field surveys were made to
determine 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 brine waste water recorded and
reported by the oil and gas industry are usually determined by con-
tracting laboratories using various analytical methods. Analytical
methods presently in use include infrared, gravimetric, ultraviolet-
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
VII-7
-------
APHA Standard for oil and grease determination under the provisions
of 40 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 VII-1 compares oil/grease concentrations
of acidized and not acidized samples from facilities in California.
TABLE VII-1
Preparation of Analytical Samples
From California
Oil & Grease Oil & Grease
Date of Not Acidized Acidized
Effluent Sample mg/1 mg/1
7-26-74 7.6 26.3
7-26-74 36.3 61.8
The values after pH adjustment are 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 extracted by halogenated hydrocarbon solvents.
Extraction of oil and grease from a sample is another critical step that
can affect values. The extraction procedure usually depends on the analyti-
cal determinative step and the physical/chemical properties of the oil/
grease in the sample. For example, petroleum ether extracts all crude
oil constituents from a brine waste water sample except asphaltenes or
VII-8
-------
bitumen. This limitation would affect the reported results of a sample
containing high asphaltic constituents. Other extractants used in oil/
grease determinations are trichlorotrifluroethane (Freon), hexane,
carbon tetrachloride, and methylene chloride.
Reported oil/grease concentrations in waste water effluents were
highly variable within and between geographical areas. There were no
data to support that this variability was the result of the treatability
of the waste stream or the treatment technology. Therefore, EPA
undertook field verification studies to determine the reasons for the
high variability of 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.
Duplicate samples were provided to the oil/gas industry for independent
laboratory analysis. Table VII-2 shows the results of two analytical
methods (gravimetric and infrared) measuring Freon extractible oil/
grease and comparing those determined values to petroleum ether
extractables using the gravimetric method. This comparison study was
conducted by the EPA Robert S. Kerr Research Laboratory (RSKRL)
at Ada, Oklahoma. In addition, contract laboratories independently
analyzed identical samples using extraction procedures and analytical
methods as indicated in Table VII-3.
VII-9
-------
TABLE VII-2
Oil and Grease Data, Texas Coastal
RSKRL, Ada, Okla. Contractor Lab
Facility Freon Extractibles
Identification Gravimetric Method
T-l
T-2
T-3
T-4
Influent
32.0
372.0
643.0
1905.0
Effluent
126.0
242.0
52.0
46.0
Freon Extractibles
Infrared Method
Influent
(mg/1)
45.0
314.0
695.0
1736.0
Effluent
154. 0
197.0
62.0
51.0
Freon Extractibles
Gravimetric Method
Influent
2.0
178.0
685.0
968.0
Effluent
5.0
145.0
10.0
6.0
Facility
Identification
C-l
C-2
C-3
TABLE VII-3
Oil and Grease Data, California Coastal
liSKtif,, Ada, Qkla.
Freon
Extractibles
Gravimetric
Method
a a
Inf. Eff.
106.0 22.3.
359.6 42.2
167.6 46.1
Freon
Extractibles
Infrared
Method
Inf. Eff.
(mg/1)
126.0 16.0
473.0 39.0
197.0 35.0
Pet. Ether
Extractibles
Gravimetric
Method
Inf.
Eff.
76.0 5.0
241.0 27.0
141.0 7.0
Contractor
Laboratory
Pet. Ether
Extractibles
Gravimetric
Method
Inf.
79.0
508.0
189.1
Eff.
3.1
3.6
11.2
Inf. = Influent
Eff. = Effluent
VII-10
-------
The preceding tables indicate that there is slight variance in analytical
results when EPA uses two different methods on the same sample. There
is great variance on the same sample analyzed by the same method by
EPA and contract laboratories. Therefore, the low oil and grease
concentrations reported by Texas and California before the field
sampling and analysis verification study appear to be more a function
of the analytical techniques and the laboratory rather than an indication
of treatability of the waste brine water and/or treatment equipment
efficiency. This conclusion was validated by a separate statistical
analysis of the data, which is contained in Supplement B to the Effluent
Guideline Study. 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 oil/gas facilities. In addition, the study found a very high
correlation between analytical results of contractor laboratories and
the EPA laboratory.
VII-11
-------
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 VII-4 indicates types
of treatment units, the performance observed during the survey, and
long term performance based on historical data for each facility.
Tables VII-5 and VII-6 indicate the comparative oil and grease
concentration data for Texas and California offshore facilities and
onshore treatment of offshore brine waste water treatment units.
VII-12
-------
TABLE VII-4
Performance of Individual Units
Louisiana Coastal
Long Term Mean Effluent, EPA Survey Results,
Oil and Grease, Oil and Grease,
Facility Identification mg/1 mg/1
Flotation Cells
GFV01 22 23
GFV02 23 6
GFS03 31 25
GFS04 29 21
GFS05 32 32
GFT06 18 24
a
GFG07 24 148
GFS08 30
GFT09 28 31
GFG10 18 13
Parallel Plate Coalescers
GCC11 35 21
GCC12 66 78
GCM13 43 34
GCC14 52
GCG15 39 19
GCS16 39 56
GCC17 51 118
Loose Media Coalescers
GLG23 25 12
GLT24 18 8
Simple Gravity Separators
GPV18 13
GPT19 26
GPE20 19
GIM21 44
GTT22 63
GPE25 16
a
System malfunctioning during survey.
VII-13
-------
Facility
Identification
T-l
T-2
T-3
T-4
TABLE VII-5
Verification of Oil and Grease Data,
Texas Coastal
JISKRL, Ada, Oklahoma
Freon Extractibles
Gravimetric
Influent
32.0
28.9
830.0
49.0
199.0
36.0
333.0
372.0
301.0
327.0
352.0
286.0
1.250.0
643.0
1,626.0
154.0
667.0
1,169.0
1,583.0
921.0
1,710.0
1,844.0
1,905.0
1,007.0
Method
Effluent
(mg/1)
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
Freon Extractibles
Infrared
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
Method
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
VII-14
-------
TABLE VII-6
Verification of Oil and Grease Data,
California Coastal
RSKRL, Ada, Oklahoma
Facility
Identification
C-l
C-2
C-3
C-4
Freon
Extractibles
Gravimetric
Method
Freon
Extractibles
Infrared
Method
Influent
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
Effluent
28.9
43.1
26.0
22.3
42.2
44.0
53.5
51.6
55.4
54.0
44.3
51.7
46.1
19.1
24.2
19.9
Influent
(mg/1)
94.0
101.0
122.0
126.0
437.0
446.0
323.0
851.0
1214.0
188.0
148.0
206.0
197.0
58.0
Effluent
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
Petroleum
Ether
Extractibles
Gravimetric
Method
Influent Effluent
90.0
76.0
241.0
193.0
172.0
462.0
611.0
83.0
100.0
141.0
55.0
a
59.0
102.0
6.0
5.0
27.0
13.0
19.0
51.0
14.0
23.0
22.0
71.0
7.0
a
6.0
Carbon tetrachloride extractibles.
VII-15
-------
End-Of-Pipe Technology; Waste Water Treatment (with Brine Discharge
to Sea or Coastal Waters)
End-of-pipe control technology for offshore treatment of brine
waste from petroleum 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 only of gravity separation pits without the addition of chemicals,
while more complex systems may include surge tanks, clarifiers,
coalescers, flotation units, chemical treatment, or reinjection.
Dissolved Gas Flotation
In a dissolved gas flotation unit tiny gas bubbles are dispersed
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 dissolved gas flotation systems are presently used
in oil production: rotor/disperser systems and diffused gas systems.
Rotor/disperser units use specially shaped rotating mixers or disper-
sers to disperse gas, from a blanket maintained over the surface
of the liquid, in the form of fine bubbles throughout a tank containing
the waste water. The resulting froth can be skimmed off at the surface.
These units are normally arranged in a series of cells with a separate
VII-16
-------
rotor for each cell. The waste water passes through each cell in
series, being regassified and skimmed as it passes through each.
In the diffused gas system, either the entire waste water stream
or a stream of recycled effluent is gassified by passing it through a
centrifugal pump while gas is introduced in the pump suction. The
stream is then passed into a contact tank at two to four atmospheres
of pressure where the bubbles of the gassified stream are collapsed
and go into solution. The gassified stream remains in the contact tank
for a few minutes and is then passed through a valve or orifice into the
bottom of the flotation unit, which is at or near atmospheric pressure.
With the drop in the pressure on passing through the valve, gas bubbles
in the gassified stream reform and, in passing through the body of
waste water, attach themselves to any oil droplets in their path. The
droplets with attached bubbles rise to the surface where they can be
skimmed off. On production facilities it is usual practice to recycle
the skimmed oily froth back through the production oil-water separating
units.
Of the two types of systems, the rotor/disperser systems seem
to remove a higher percentage of oil. The reason is not readily
apparent -- perhaps it is because the system uses a series of cells,
the waste stream being treated each time it passes through a cell.
A flow diagram of the two typical flotation units is shown in Figure
VII-1.
The addition of chemicals can increase the effectiveness of either
type of dissolved gas flotation unit. Some chemicals used in brine water
VII-17
-------
CRUDE OIL PRODUCTION PROCESSING
M
M
»-»
00
LOW PRESSURE OIL WELL'
INTERMEDIATE-
PRESSURE OIL
WELL
HIGH PRESSURE
OIL WELL
HIGH
PRESSURE
SEPARATOR
HEAT
PROCESS OIL-
WATER SEPARATION
(HEATER THEATER.
CHEMICAL. ELEC
TRICAL,
GUN BARREL, FREE
WATER KNOCK OUT.
ETC.!
OIL TO SALES
^ r
BRINE S
OIL AND BRINE
SKIMMED OIL RECYCLE
A
CHEMICAL INJECTION
-*•
WASTE WATER TO EITHER
1
r
O
nu i UK— uiaf tni>tH UH UII-I-D;
ROTOR-DISPERSERS
p n n n
k
1 1 x^J
Y
SKIMMED OIL RECYCLE TO PROCESS SEPARATION
DISCHARGE
1 OVERBOARD _|
!
SURGE TANK.
SKIMMER TANK
FROM
GAS
FLOTATION
FLOTATION
UNIT
SKIMMED OIL RECYCLE
GAS OR AIR
AND CHEMICALS
ROTOR-DISPERSER GAS FLOTATION PROCESS DIFFUSED GAS FLOTATION PROCESS
Fig. vii-i - ROTOR-DISPERSER AND DIFFUSED GAS-FLOTATION PROCESSES FOR
TREATMENT OF WASTE BRINE WATER
-------
treatment increase the forces of attraction between the oil droplets
and the gas bubbles. Others develop a floe which eases the capture
of both 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 also 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 from
5,000 to 290,000 barrels-per-day and included both rotor/ disperser
and diffused 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.
Four of the flotation units are preceded by surge tanks.
Information obtained during the field survey of onshore treatment
systems for Cook Inlet produced brines indicated that one of the four
onshore systems utilized a diffused air flotation system comparable to
those used in the Gulf Coast. This system provides physical/chemical
VII-19
-------
treatment and consists of a surge tank, chemical injection, and a
dissolved air flotation unit.
Field surveys on the West Coast found that physical/chemical
treatment is the primary method of treating brine waste 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 injection
systems. However, some of those that still discharge are 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 top 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
VII-20
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much more compact than an API separator, but the principle of
operation is the same.
Suspended particles, which tend to sink, move down a short dis-
tance 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 arid can be periodically drawn off. Particles may become
attached to 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. Consequently, the oil content of effluents
from these systems is generally higher than from gas flotation units
or filter systems.
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 brine produced in
offshore Louisiana waters. (4) Both the long-term performance
data and the verification survey indicate that performance of these
units was considerably lower than that of flotation units. In addition
to the physical limitations of these coalescers1 operation and mainte-
nance, data indicated that the units require frequent cleaning to
remove solids.
VII-21
-------
No plate coalescers are in use in Cook Inlet and none were re-
ported to be in use on the West Coast.
Filter Systems (Loose or Fibrous Media Coalescers)
Another type of brine water treatment systems are the filters.
They may be classified into two general classes based on the media
through which the waste stream passes.
. Fibrous media, such as fiberglass, usually in the form of a
replacable element or cartridge.
. 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 washing.
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.
The backwashing of filters presents several problems. Systems
with automatic backwash cycles are available, but the valving and
controls are complicated and need much maintenance. Disposal of
dirty backwash water and contaminated filter elements present
problems.
VII-2 2
-------
Measured by the amount of oil removed, filter performance has
generally been good (provided that the units were backwashed suf-
ficiently 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.
Gulf Coast survey information indicated that when filter systems
are used, they are the primary treatment units, with no initial pre-
treatment 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; however, filters are used for final
treatment for brine 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 preceded by a surge tank, flotation
unit, and other treatment units which remove the majority of the oil
and suspended particles. Backwashing is still required; however,
these units, when used in series with other systems, perform well
and are used extensively with reinjection systems.
Gravity Separation
The simplest form of treatment is gravity separation, where
the waste brine is retained for a sufficient time for the oil and water
to separate. Tanks, lagoons (often called pits), and, occasionally,
barges are used as gravity separation vessels. Large volumes of
VII-23
-------
storage to permit sufficient retention times are characteristic of these
systems, and performance is dependent upon the characteristics of the
waste water, brine volumes, and availability of space. While total
gravity separation requires large containers and long retention times,
any treatment system can benefit from storage, which provides the
opportunity for some simple gravity separation and, more impor-
tantly, dampens out the production surges before the waste water
enters the main phase of the treatment system.
About 75 percent of the systems on the Gulf Coast are simple
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 simple gravity system
with the addition of chemicals produced an effluent of less than 15 mg/1
during the verification survey.
Three of the onshore treatment systems in Cook Inlet use simple
gravity separation, including various configurations of settling tanks,
lagoons, and pits. No simple gravity systems were reported to be
in use on the West Coast.
The four installations visited in the Texas verification study
all use simple 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 effec -
tive means to increase the efficiencies of treatment systems. Pilot
VII-24
-------
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 to 20 percent with the
addition of a polylectrolyte and a coagulating chemical could increase
efficiencies 20 percent. (6)
Three basic types of chemicals are used for waste water treat-
ment; however, many different formulations of these chemicals have
been developed for specific application. The basic types of chemicals
used to aid waste treatment offshore are as follows:
. Surface Active Agents - These chemicals modify the inter-
facial tensions between the gas, suspended solids, and liquid. They
are also referred to as surfactants, foaming agents, demulsifiers,
and emulsion breakers.
. Coagulating Chemicals - Coagulating agents assist the for-
mation of floe and improve the flotation or settling characteristics
of the suspended particles. The most common coagulating agents
are aluminum sulfate and ferrous sulfate.
. 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:
. Surface active agents and polyelectrolytes are the most
commonly used chemicals for waste water treatment.
. The chemicals are injected into the waste water upstream
from the treatment unit and do not require prernixing units.
VII-25
-------
. Chemicals are used to improve the treatment efficiencies
of flotation units, plate coalescers, and simple gravity systems.
. Recovered oil, foam, floe, and suspended particles skimmed
from the treatment units are returned to the process system.
A similar survey of offshore and related facilities in Cook Inlet,
Alaska indicated that a facility uses coagulating agents and poly-
electrolytes chemicals 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; oil and clay then 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 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 chem-
icals 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
VII-26
-------
growths which may interfere with both process and waste treatment
systems.
Effectiveness of Treatment Systems
Table VII-7 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.
VII-27
-------
TABLE VII-7
Performance of Various Treatment Systems,
Louisiana Coastal
Type Treatment System
Gas Flotation
Parallel Plate Coalescers
Filters
Loose Media
Fibrous Media
Gravity Separation (4)
Pits
Tanks
Mean Effluent,
Oil and Grease
mg/1
27
48
21
38
35
42
No. of Units
in Data
Base
27
31
15
7
31
48
VII-28
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End-Qf-Pipe Technology: Waste Water Treatment (with No Discharge
of Brine to Sea or Coastal Waters)
Water produced along with liquid or gaseous hydrocarbons may
vary in quantity from a trace to as much as 98 percent of 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:
. Discharged to pits, ponds or reservoirs and evaporated.
. Injected into formations other than their place of origin.
In some of the Nation's arid and semiarid western and south-
western oil and gas producing areas, use of the first method is an
acceptable, although limited, 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
by overland flow of water following precipitation. Pit facilities are
normally lined with impervious materials to prevent seepage and sub-
sequent 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
VII-29
-------
natural 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 beneficial use by local
farmers and ranchers by irrigating land and watering stock. A typical
produced water system widely in use is shown in Figure VII-2. A cross
section of the individual pit is shown in Figure VII-3.
A producing oil field in Nevada discharges brine 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.
VII-30
-------
DETAIL MAP
TREATER
QHEADER
SAMPLE POINT
DISCHARGE
500 BBL
WATER
SETTLING
TANK
500 BBL
OIL STORAGE
TANKS
LACT
Fig. VII-31 ~ ONSHORE PRODUCTION FACILITY WITH
DISCHARGE TO SURFACE WATERS
VII-31
-------
DIMENSIONS VARY FOR VOLUME NEEDED
DEPTH WILL VARY WITH.
OPERATIONS CONDITIONS
NOTE
PITS ARE EQUIPPED WITH PIPE DRAINS FOR SKIMMING OPERATIONS
TO OBTAIN OIL-FREE WATER DRAINAGE
Fig. VII-3 — TYPICAL CROSS SECTION UNLINED EARTHEN
OIL-WATER PIT
VII-32
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Subsurface Disposal
Injection and disposal of oil field brines into the subsurface 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,
for disposal only and playing no intentional part in secondary recovery
systems. (Injection for pressure maintenance or secondary recovery
refers to the emplacement of produced brines 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 minimal application of a corrosion inhibitor and bactericide; a
sequestering agent may be added to waters having scaling tendencies.
Brine composition and system characteristics determine the amount
of chemical required.
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 fre-
quently combined into a single commercial product and sold under
various trade names. (7)
A wide range of stable, semipolar, surface-active organic
compounds have been developed to control corrosion in oil field injec-
tion and disposal systems. The inhibitors are designed to provide a
high degree of protection against corrosive dissolved gasses such as
VII-33
-------
carbon dioxide, oxygen, hydrogen sulfide, organic and mineral acids,
and dissolved salts. The basic action of the inhibitors is to temporarily
"plate" 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 attack oil field injection and
disposed systems and cause corrosion. These are:
. Anaerobic sulfate-reducing bacteria (Desulfovibrio —
desulfuricans). These bacteria promote 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, that accelerates corrosion in the injection or disposal
system.
. 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.
VII-34
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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.
Treatment to combat bacterial attack ordinarily consists of
applying either a continuous injection of 10 to 50 ppm concentra-
tion of a bactericide or batching once or twice a week, beginning
at the heater-treater or water knockout with approximately 100 ppm
bactericide.
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, but they may also
be developed by combining of waters containing moderately high to
high concentrations of calcium, magnesium, barium, or strontium
with waters containing high concentrations of biocarbonate, 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 polymeta-
phosphates. Relatively small quantities of these chemicals will
prevent the precipitation and deposition of calcium carbonate scale.
Dimetallic phosphates or the so-called "controlled solubility"
varieties are now widely used by the oil industry in scale control
and are preferred over the polyphosphates.
VII-35
-------
The downhole completion of a typical injection well is
shown in Figure VII-4. A typical producing well is also shown
for comparison. Injection wells may be completed in a more
complicated fashion with multiple strings of tubing, each inject-
ing into a separate zone. 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 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 casing head, tubing head, and tubing to
detect anomalies in pressure. Pressure may also be monitored
by continuous clock recorders which are commonly equipped with
alarms and automatic shutdown systems if a pipe ruptures. (8)
The brine injection well designed for pressure maintenance
and secondary recovery purposes is completed in a manner identical
to that of the disposal well. Treatment prior to injection may vary
from that applied to the disposal well inasmuch as water injected
into the reservoir sandface must be entirely free of suspended
solids, bacterial slimes, sludges, and precipitates. (9)
Ordinarily, selection of injection wellsites poses few if any
environmental problems. In many instances where injection is
used for secondary recovery, the wellsite is fixed by the geometry
of the waterflood configuration and cannot be altered.
VII-3 6
-------
INJECTION WELL
PRODUCING WELL
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TYPICAL COMPLETION OF AN INJECTION WELL AND A PRODUCING WELL
-------
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); aeration facility if necessary
to remove undesirable gasses such as hydrogen sulfide; filter-
ing 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 chemical house
for storing and dispensing treatment chemicals.
In addition to the system described where no attempt is
made to exclude air, there also exists a "closed" system. A
closed system excludes air (and oxygen) from the water; its use
is desirable because the water is less corrosive or requires less
treatment to make it noncorrosive. The truly "closed" system
is, for all practical purposes, 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 down-
stroke of a pumping well through worn stuffing box packing or
seals.
In few instances the so-called "closed type" injection (or
disposal) system is used where brines ordinarily have minimal
corrosive characteristics; where salt water is gathered from
VII-38
-------
relatively few wells, fairly close together; where wells produce from
a common reservoir; or where a one-owner operation is
involved.
There are instances in which a "closed" input or salt 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. Among more
desirable factors are:
. Wider range, type, and control of treatment methods.
Ability to handle greater quantities of water from different
sources (diverse leases and fields) and differing formations.
. 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:
How much reservoir volume is available ?
Is the receiving formation porous and permeable?
VII-39
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. What are the formation's physical and chemical properties ?
What geologic, geochemical and hydrologic controls govern
the suitability of the formation for injection or disposal ?
What are the short-term and long-term environmental
consequences of disposal? (10)
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 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 at surface pressures in excess of 0.5 pounds per
square inch gauge per foot of depth to the disposal zone, particularly
in shallow wells, an alternate zone is usually sought.
It is necessary to be famililar 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 com-
patible with those injected. Chemical analyses are performed on both
to determine whether their combination will result in the formation
of solids that may tend to plug the formation.
VII-40
-------
The petroleum industry recognizes that the most carefully
selected injection equipment means nothing if the disposed brine 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 tech-
nological data germain 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 brine for disposal. Field investigations made in California
were confined to OCS waters, with visits being made to five installa-
tions. All are disposal systems only -- none are used 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 brine in wells on the
platform. Two were sending all fluid to shore, separating 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; however, the total fluids produced are presently greater
than the capacity of the disposal system and the excess treated
VII-41
-------
water is being discharged overboard. Plans were being formulated
to increase the capacity of the disposal system to return all produced
water underground.
Salt 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 individ-
ual or a cooperative association, or a joint interest group may operate
a central treatment and 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, California.
End-of-Pipe Technology; Other Treatment Systems.
Treatment System By Pass
During major breakdown and overhaul of waste treatment equip-
ment, 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; however, at smaller facilities and on offshore platforms
only single units are usually provided. By pass practices (discharge
to surface water) vary considerably from facility to facility. The
following methods are currently practiced offshore:
. Discharge overboard without treatment.
Discharge after removal of free oil in surge tank.
. Discharge to sunken pile with surface skimmer to remove
free oil.
VII-42
-------
Offshore practices to avoid discharge to surface waters
during upset conditions:
. Discharge of brine to oil pipeline for onshore treatment.
. Retention on the facility using available storage.
. Production shutdown.
The method used depends upon the design and system configura-
tion for the particular facility.
Deck Drainage
Where deck drainage and deck washings are treated in the Gulf
Coast, the waste water is treated by simple gravity separation,
or it is transferred to the production brine treatment system and
treated with the production brine. Platforms in the Cook Inlet and
California offshore areas may pipe the deck drainage and deck
washings along with produced fluids to shore for treatment; in Cook
Inlet, these wastes may be treated on the platform.
Field investigations conducted on two platforms at Cook Inlet
indicate that the most efficient system for treatment of deck drainage
waste water in this area involves collecting oily deck drainage and
deck wash water and feeding it to a surge tank, which provides gravity
separation of oil, water, and solids. The water flows from the surge
tank and is chemically treated with emulsion breaking and floccula-
ting chemicals before the water passes through a gas flotation system.
Limited data indicate an average effluent of 25 mg/1 can be obtained
from this system. The field investigations also found that deck drain-
age systems operate much better when crankcase oil is collected
VII-43
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separately and when detergents are not used in washing the rigs.
Also, the field visits noted the most difficult wastes to handle
were the deck washings from drilling and workover operations using
invert emulsion muds.
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 or in a water stream.
Field investigations have indicated that some Gulf Coast facili-
ties have sand removal equipment that flushes the sand through the
cyclone drain valves, and then the untreated sand is bled into the
waste water and discharged overboard. Excessive amounts of oil
are carried overboard since oil that might cling to the sand particles
has not been removed.
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.
VII-44
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Additional information is needed to determine the overall
efficiencies of the sand-cleaning equipment, as there is limited
information on the amount of oil that adheres to the sand particles.
However, it has been established that 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, and
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 Operations (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.
Drilling muds perform many different functions and therefore
must have differing physical and chemical properties satisfing the
individual drilling requirements and well conditions. There are
no differences in usage of drilling muds from one geographic area
to another.
VII-45
-------
Both water based and oil muds are used. (11) 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 conser-
vation 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 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 restric-
tive. 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 catch-
ment 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 subsequently dispose of the washed
VII-46
-------
cuttings into the surface water body. After washing, the solvent-water
is transfered to shore or contained in a closed liquid recovery
system. (12)
Drilling Operations (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.
Field Services
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 produce 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 discreet waste source; however, their
presence in the waste treatment system may cause upsets and 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 produc-
tion system. If the killing fluid is mud it will be collected for reuse or
discharged as described earlier in this section under "Drilling Opera-
tions (Offshore). " If water is used it will be moved through the produc-
tion and treatment systems and disposed of.
VII-47
-------
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;
however, 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 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. (5)
There are two alternatives to handling of sanitary wastes from
offshore facilities. The waste can be treated at the offshore location
or they may be retained and transported to shore facilities for treat-
ment. Because of the high cost involved in retention and shore treat-
ment, offshore facilities usually treat waste at the source. The treat-
ment 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 compliments
of men or on platforms which are intermittently manned. The
VII-48
-------
incinerator 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 prob-
lems but create a potential source of fuel and ignition which could
result in a safety hazard at some locations. Some facilities have
chemical toilets which require hauling of waste and also 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 are avail-
able for this facility; however, similar facilities located onshore
obtain a mean effluent level of suspended solids of 17 mg/1.
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. (5)
The most common biological systems applied to offshore
operations are aerobic digestion or extended aeration processes.
VII-49
-------
These systems usually include a comminutor which grinds the solids
into fine particules, an aeration tank with air diffusers, gravity
clarifier return sludge system, and disinfection 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 continuously manned.
Because of the special characteristics of sanitary waste
generated by offshore operations, the design parameters in Table
VII-8 have been recommended. Table VII-9 shows average effluent
concentrations for various types of treatment units which are in use
at offshore facilities in the coastal water of Louisiana.
VII-50
-------
TABLE VII-8
Per Capita Design Parameters
for Offshore Sanitary Wastes (13)
Offshore Design
BOD 0.22 Ib/day
5
Total Suspended Solids 0.15 Ib/day
Flow 75 gal/day
TABLE VII-9
Average Effluents of Sanitary Treatment Systems
Louisiana Coastal (13)
BOD Suspended Solids Chlorine Residual
5
Company No. of Units mg/1 mg/1 mg/1
A
B
C
D
E
11
6
17
9
6
35
13
15
25
86
24
39
43
36
77
1.2
1.8
1.9
2.5
1.3
VII-51
-------
Table VII-10 indicates typical existing facilities, design capacity,
and effluents for a particular company located in the Gulf Coast.
TABLE VII-10
Treatment Facilities for
Sanitary Wastes, Offshore Gulf Coast
Distance from Water Capacity, BOD , Suspended
Shore, Depth, gallons/ 5 Solids,
No. of Men miles feet day mg/1 mg/1
16 27 50 2,000 42 111
30
46
21
52
9
18
160
55
340
4,000
4,000
3,000
1
44
5
29
92
74
40 26 375 5,000 10 11
VII-52
-------
SECTION VII
Bibliography
1. University of Texas-Austin, Petroleum Extension Service, and
Texas Education Agency Trade and Industrial Service, 1962.
"Treating Oil Field 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 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.
5. Martin, James C 1973. "Domestic Waste Treatment in the Offshore
Environment. " Paper presented at the 5th Annual Offshore
Technology Conference. Preprint No. OTC 1737.
6. 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.
7. Sadow, Ronald D. 1972. "Pretreatment of Industrial Waste Waters
for Subsurface Injection". 1972. "Underground Waste Manage-
ment and Environmental Implications. " In: AAPG Memoir 18,
pp. 93-101.
8. 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.
9. Ostroff, A. G. 1965. "Introduction to Oil Field Water Technology. "
Prentice Hall, Inc.
VII-53
-------
Section VII, Bibliography, contd.
10. McKelvey, V. E. 1972. "Underground Space —An Unappraised
Resource." In: "Underground Waste Management and
Environmental Implications." AAPG Memoir 18, pp. 1-5.
11. 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.
12. Cranfield, J. 1973. "Cuttings Clean-Up Meets Offshore Pollution
Specifications." Petrol. Petrochem. Int., Vol. 13: No. 3,
pp. 54-56, 59.
13. U.S. Department of the Interior. "Sewage Effluent Data."
(Unpublished Report) August 16, 1972.
VII-54
-------
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 tech-
nologies. The expected annual cost for existing plants in the oil and
gas extraction industry to comply with BPCT effluent limitations by
1977 are estimated at $192, 000. 000. Estimated annual costs to
comply with BAT effluent limitations and for new source will be pub-
lished as an addendum to this report as soon as the computations are
completed.
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 -- production brine with discharge, production brine
reinjected, and sanitary wastes. The cost of brine treatment or dis-
posal is significantly affected by availability of space; therefore, the
cost analysis has been subdivided into iwo areas -- offshore brine
disposal and onshore brine disposal. Of the other subcategories, deck
drainage is considered to be treatable with the production brine water;
water-based drilling muds are not presently treated, while oil-based
VIII-1
-------
muds are reused. In some instances, the production brine is transferred
to shore along with the crude, while in others a variety of equipment
has been installed on the platforms. Therefore, not all platforms will
be required to add all of the treatment capabilities or incur all of
the incremental costs indicated to bring their raw discharges into
compliance with the effluent limitations. Existing brine treatment
systems include a mix of sumps and sump piles, pits, tanks, plate
coalescers, fibrous and loose media coalescers, flotation systems,
and reinjection systems.
Offshore Brine Disposal
The systems currently used or needed for the treatment of process
waste water (formation waste water) resulting from the production of
oil and gas involve physical separation, sometimes aided by chemical
application. This physical separation is or has been obtained by
quiescent gravity separation, coalescence, and filtration. Shallow well
injection has also been successfully used for disposal of brine wastes
at onshore locations and at several offshore locations in California.
The methods examined for offshore use include the following
arrangement of components:
A Gravity separation using tanks, then discharge to surface
1
water.
A Gravity separation using plate coalescers, then discharge
Łt
to surface water.
B Separation by coalescence, using flotation equipment, then
discharge to surface water.
VIII-2
-------
C Separation by coalescence, using flow equalization (surge tanks),
desanders, and flotation, then discharge to surface water.
D Separation using filters, then discharge to surface water.
E 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 production brines based on these flow rates:
Small facility 5, 000 bbls/day
Medium facility 10,000 bbls/day
Large facility 40, 000 bbls/day
Where flow equalization was provided, surge tanks of these sizes
were used:
Small facility 500 bbls
Medium facility 1, 000 bbls
Large facility 3, 000 bbls
The development of realistic cost estimates for the treatment of
produced brines of necessity should be very generalized because of the
nature of the problem. Costs have been developed for the systems
identified based on the following assumptions:
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.
The annualized cost 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 comprised of 10 percent for
depreciation and 10 percent for average interest charges.
VIII-3
-------
Costs will vary greatly depending upon platform space. Therefore,
investment costs have been prepared for three assumptions:
. 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.
. Option (b) assumes that, because of the high costs involved in
building platforms, they have been built to minimum size needed for
production. Therefore space is not generally available for brine treat-
ment equipment and ancillary facilities. Space is provided by canti-
levered additions up to 1, 000 square feet, space requirements greater
than this amount will require an auxiliary platform. (2)
. 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 on the basis of area at $350 per square foot.
In all three cases platform estimates are based on platforms
being 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 five horsepower.
Operation and maintenance costs of components of the various
systems are based on operating costs reported by the industry and
correlated with capital costs of the equipment. (2) The resulting
percentage of Investment Cost is shown in Table VII-1.
VIH-4
-------
TABLE VIII-1
Operating Cost Factors
For Brine Treatment Facilities Offshore
Facility
Tanks
Plate Coaleseers
a
Flotation Systems
a
Filters
a
Subsurface Disposal
Electrical Supply Facilities
Basis for Calculating
Annual O & M Costs
(Percentage of
Investment Cost)
11
33
11
11
9
10
Excludes electrical power supply cost.
VIII-5
-------
Energy and power for low demand is computed as 2 percent of the
Investment Cost; on large requirements an electric power cost of
2-1/2 cents per kilowatt hour is assumed.
The annualized cost for the six alternative brine treatment methods
for offshore installation of small, medium and large sizes are contained
in Tables VIII-2, VIII-3, and VIII-4. Capital cost for options (a), (b),
and (c) reflect equipment cost, installation and platform space costs.
Onshore Brine Disposal
The major source of waste water from onshore petroleum produc-
tion is produced formation water. Produced formation water or oil
field brine is sometimes used for pressure maintenance and water
flooding to improve production. In areas where the water is not used
for these purposes, it must be disposed of properly. Reinjection into
a suitable underground formation is the generally accepted means.
Treatment of the unwanted brine is generally held to the minimum
that will permit the reinjection to function continuously. The typical
system for reinjection 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 formation 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 pro-
duction 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 reinjection equipment becomes a legitimate
disposal cost.
VIII-6
-------
TABUE VIII-2
Cost for Treating Brine on Offshore Installations
5, 000-Barrel-Per-Day Flow Rate
(Thousands of 1973 dollars)
Treatment Technology
A
1
Capital Cost
Option (a) 47
Option (b) 1, 452
Option (c) 432
A
2
21
55
43
B
88
146
274
C D
131
204
423
74
117
157
E
451
518
683
Annualized Costs (Thousands of 1973 dollars)
Capital & Depre-
ciation
Option (a)
Option (b)
Operation &
Maintenance
Energy
Total - Option (a)
Option (b)
Cost of
Option (a)
Option (b)
9.4
290.8
4.32
0.94
14.66
295. 66
4,2
11.0
6.51
0.42
11. 13
17.93
Brine Processed (1973
0.008
0.16
0.006
0.0098
17.6
54.8
8.27
1.76
27.63
64.83
262
84. 6
12.23
2.62
41.05
99.45
14.8
31.4
6.96
1.48
23.24
39.84
902
1366
39.88
9.02
139. 1
185.5
dollars/barrel)
0.015
0.036
0.023
0.054
0.013
0.022
0.076
0.102
-------
oo
TABLE VIII-3
Costs for Treating Brine on Offshore Installations
10,000-Barrel-Per-Day Flow Rate
(Thousands of 1973 dollars)
Treatment Technology A
1
Capital Cost
Option (a)
Option (b)
Option (c)
A
2
B
C
60 31 148 206
2, 140 68 228 1, 626
a 66 488 708
Annualized Costs (Thousands of 1973 dollars)
D
108
161
259
1
E
563
,972
979
Capital & Depre-
ciation
Option (a)
Option (b)
Operation &
Maintenance
Energy
Total - Option
Option
Option (a)
Option (b)
12
428
5.
1.
(a) 18.
(b) 434.
Cost of Brine
0.
0.
52
20
7
7
6.2
13.6
8.28
0.62
15.1
22.5
Processed (1973
005
117
0.004
0.006
29.
97.
13.
2.
46.
114.
6
6
91
96
5
5
41.
325.
19.
4.
64.
348.
2
2
33
12
7
7
21.
51.
10.
2.
33.
64.
6
8
12
16
9
1
112.
394.
52.
11.
176
457.
6
4
14
26
8
do liars /barrel)
0.
0.
013
031
0.
0.
018
096
0.
0.
009
018
0.
0.
048
125
a
Not considered to be a viable alternative because of large space requirement.
-------
TABLE VIII-4
Cost for Treating Brine on Offshore Installations
40, 000-Barrel-Per-Day Flow Rate
(Thousands of 1973 dollars)
a
Treatment Technology A A B C D E
1 2
Capital Cost
Option (a) 60 355 448 170 907
Option (b) 98 1,780 1,913 230 2,354
Option (c) 102 880 1,254 369 1,585
Annualized Costs (Thousands of 1973 dollars)
Capital & Depre-
ciation
Option (a) 12 71 89.6 34 181.4
Option (b) 20.4 356 382.6 73.8 470.8
Operation &
Maintenance 18.60 33.60 42.04 15.90 89.56
Energy 1.20 7.10 8.96 3.40 18.14
Total - Option (a) 31.8 111.7 140.6 53.3 289.1
Option (b) 40. 2 396. 7 433. 6 93. 1 578. 5
Cost of Brine Processed (1973 dollars/barrel)
Option (a) 0.002 0.0077 0.01 0.004 0.020
Option (b) 0.0028 0.027 0.030 0.006 0.040
a
No estimate made - method considered to be impractical because of large space
requirements
-------
The cost estimates for onshore disposal of produced formation
water include a flow equalization tanks for 1, 000, 5, 000 and 10, 000
barrels-per-day brine production, pumps are sized for these flow
rates, 700 pounds per square inch pressure, and disposal wells
for 3,000 foot depth. A maximum well capacity of 12, 000 barrels-
per-day was assumed. In addition, costs are determined for this
system with a lined pond to provide standby capability for continuing
production for seven days while pump repairs are being made or the
reinjection well is being worked on (see Table VIII-5).
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 Wastes
Cost estimates for biological systems utilized on offshore
platforms are of 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 diffusers, gravity clarifier return sludge
system and a disinfection tank.
Based on the per capita design parameters stated in Table VII-8
costs were developed for systems to serve 25 persons (2,000 gallons),
VIII-10
-------
TABLE VIII-5
Estimated Costs for Onshore Disposal
of Produced Formation Water
by Shallow Well Injection With Lined Pond for Standby
(Thousands of 1973 dollars)
Investment Costs:
Equalization or Surge Tank
High Pressure Pump
Well Completion
Pond
Total
Annualized Costs:
Capital
Depreciation
O&M
Power
Total Annual Costs
1,000 BPD
Facility Size
Barrels -Per-Day
5, 000 BPD
10.000 BPD
$ 3.5
4.5
40.5
5.0
$53.5
$2.5
2.5
5.0
.5
$ 6.0
15.0
40.5
13. 1
$74.6
$ 7.46
7.46
6.71
3.0
$ 8.0
15.0
40.5
20.0
$83. 5
$ 8.35
8.35
7.52
6.0
$20.5
$24.63
$30.22
VIII-11
-------
TABLE VIII-6
Estimated Treatment Plant Costs
For Sanitary Wastes For Offshore Locations
Package Extended Aeration Process
(Thousands of 1973 dollars)
Investment Cost
Total Annual Costs
capital
depreciation
operation & maintenance
energy & power
Treatment Plant Capacity
(gallons/day)
2,000 4,000
$18,000 $23,000
6,010 7,660
1,800 2,300
1,800
2,050
360
2,300
2,600
460
6,000
$28,000
9,360
2,800
2,800
3,200
560
VIU-12
-------
50 persons (4,000 gallons) and 75 persons (6,000 gallons). These
costs are contained in Table VIII-6.
Nonwater-Quality Aspects
Evaluation of in-plant process control measures and waste treat-
ment 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.
VIII-13
-------
SECTION VIII
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.
2. Joint Association Survey of the U.S. Oil and Gas Producing
Industry. 1972. "Drilling Costs and Expenditures for
Exploration, Development and Production - 1972. "
American Petroleum Institute, Washington, D. C.,
November 1973.
VIII-14
-------
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.
Production Brine Waste - Discharge Technology
Gulf Coast and Coastal Alaska
For BPCT where discharge is permitted (in Gulf Coast and
Coastal Alaska), the process control measures used include:
. Elimination of raw waste water discharged from free water
knock-outs or other process equipment.
. Improved operations and maintenance on oil/water level
control measures including sensors and dump valves.
. Redirection or treatment of waste water or oil discharges
from safety valve and treatment unit by pass lines.
The treatment consists of:
. Equalization (surge tanks, skimmer tanks).
. Solids removal (desanders).
. Chemical addition (feed pumps).
IX-1
-------
. Oil removal (dissolved gas flotation).
Specific treatability studies are required prior to application
of a specific treatment system to an individual facility.
Procedure For Development of BPCT Effluent Limitations
The effluent guidelines limitations were determined using effluent
data for oil and grease provided by the oil and gas producing industry,
Department of the Interior (U. S. Geological Survey), and the States,
as well as EPA data obtained during three field verification studies
and four field surveys of operating platforms in the Gulf Coast,
Cook Inlet, Alaska, and Coastal California.
The oil-grease effluent data were analyzed to assess variability
and data limitations for the various types of treatment which involve:
flotation units, plate coalescers, and fibrous media/loose media
filters.
The following additional information was obtained (this data on
file in Effluent Guidelines Division): oil/gas industry reports;
schematics, diagrams, and narratives of operation and maintenance
for 25 selected producing facilities; Petroleum Systems Reliability
Analysis Report; National Academy of Engineering's Outer Continental
Shelf Technology Safety Report; reports of EPA field surveys; and
literature surveys.
A review of the effluent data showed a wide range of
treatment efficiencies from facility to facility with similar
IX-2
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treatment, variability between different treatment methods, and
high variability of effluent levels within an individual facility.
Additional information was reviewed in detail to determine the
reasons for these variations. It was concluded that treatment
efficiency is affected by uncontrollable factors related to
geological formation and controllable factors related to industry,
operations and analytical procedures. The uncontrollable factors
are:
. Physical and chemical properties of the crude oil. including
solubility.
. Suspended solids concentrations.
. Fluctuation of flow rate.
. Droplet sizes of the entrained oil.
. Degree of emulsification.
. Characteristics of the produced water.
The controllable factors are:
. Operator training.
. Sample collection and analysis methods.
. Process equipment malfunction-- for example in heater-treaters
and their dump valves, chem-electrics and their dump valves, chemical
pumps and sump pumps.
. Lack of proper equipment -- for example, desanders or
surge tanks.
. N on-compatible operations.
IX-3
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The major objective of the detailed data analysis was to reject
inadequate treatment technology and select exemplary 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 simple gravity separation.
EPA survey data snow that the majority of the simple gravity
systems produced highly variable effluents and were only minimally
effective in removal of oil. EPA could not verify effluent data
provided by industry because of extreme variations in analytical
procedures; therefore, all data were rejected for the 36 simple
gravity systems located in Coastal Texas waters.
Ten of the 94 treatment systems in Coastal Louisiana had 10 or
less data points; they were rejected. Statistical data on the oil
effluent levels from the 84 remaining units were analyzed; in addi-
tion, the data collected from 25 selected facilities visited in the
EPA verification study were analyzed. This analysis led to the
conclusion that treatment efficiencies are significantly affected by
operation and maintenance (O&M) procedures and factors associated
with the producing geological formation. The variance in treatment
efficiencies was reflected in the data for all types of treatment
methods and within a facility treatment system. Both loose media
and fibrous media filters are capable of producing low effluents,
but because of O&M difficulties the units are being phased out.
IX-4
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The plate coalescer and gas flotation treatment units in Louisiana
with greater than ten data points were analyzed with respect to
O&M reliability. A comparison analysis was made to determine the
effectiveness of physical separation of oil and ability to handle un-
controllable variation in raw waste characteristics.
The treatment efficiencies of plate coalescers are significantly
below those for gas flotation 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 brine constituents. When the parallel
plate becomes plugged, frequent back washing, manual cleaning,
or replacement of plates are required. According to the effluent
data, the oil concentrations are highly variable, 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 other
reports were available on nine of the units and each was evaluated
to determine the acceptability of the data and the cause of significant
effluent variations. A review of the design parameters for the
various systems showed that the systems were designed for the
maximum expected brine production. None was designed to
handle overloads conditions which may occur during start-up,
IX-5
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process malfunctions, or poor operating practices. Therefore,
data were rejected when treatment units were installed (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 performed. Treatment
data from some of the facilities analyzed were consistently highly
variable with no apparent explanation. In this case, all of the treat-
ment data were accepted since it appeared highly unlikely that
efficiency could be normalized with better O&M procedures. The
causative factors relating to this situation are possibly 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;
if the variations were judged to be caused by controllable mal-
functions, 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
evaluated, and 14 erratic high values were eliminated since they
are a strong indication of errors in sample collection analysis.
IX-6
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Additional data were obtained for a number of the units from
the oil companies and the Department of the Interior. Also addi-
tional data were extracted from the Brown & 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 was selected as potential
exemplary 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, with one facility having 508 data points covering an
18-month period.
The EPA field survey included nine of the selected 28 gas
flotation units in the Coastal Louisiana and the effluent data for
seven systems fell within close proximity of the long term
averages computed from the modified data. This was expected
since none of the seven systems were experiencing malfunctions
but were subject to formation fluctuations. Two systems were
experiencing malfunctions and the effluent data fell outside the
expected range for these units. The malfunctions were caused
by operational and equipment problems which were correctable.
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
IX-7
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the shape 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 were similar in the shape of their
statistical distribution, and although the observed means and
variances differed from unit to unit, no basis for further sub-
categorization was discovered.
The statistical analysis indicated that the data were log
normally distributed; according to the test for distribution,
the various units could be separated into three statistical
groups -- five were in a high, 13 in a low, and nine in an average
group. The means and 99 percent levels were calculated for the
low, high, and total groups. The average group was of significance
from both a technical and statistical point of view; therefore,
rejecting all units except the low group was not considered to be
valid. Similarly, no technical or statistical reason was found
to justify rejecting or subcategorizing the high units; therefore,
data from all 27 Louisiana Coastal units were included in deter-
mining the effluent limits for oil.
The data in Figure IX-1 represent a cumulative plot of the
of the observed concentrations for the 27 Louisiana Coastal flota-
tion units. The plot is essentially linear over the last 80 percent
of the range, and the straight line represents a log normal
distribution. Of the 2,286 samples, 99 percent have oil concen-
trations less than 85 mg/1.
IX-8
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A statistical analysis was also conducted to determine the
normality, distribution, and variance for the one flotation unit in
Coastal Alaska which treated produced brine waters. The average
oil content in the effluent is approximately 15 mg/1. If the concen-
trations are assumed to be log normally distributed, it can be
estimated from approximately 40 observed points that 99 percent
of future samples will have oil concentrations less than about 75
mg/1. The operation of this unit appears very similar to the low
group units for Coastal Louisiana. Figure IX-2 represents a plot
of the Cook Inlet data and the best fit straight line (solid); this
figure also shows, for comparison, the 27 Coastal Louisiana
flotation units data (dot-dash line), and the plot of a flotation unit
in the low group (dashed line). The first two curves converge at
about the 99 percent level; however, at the 50 percent level, the
Cook Inlet facility has a much better performance, with a median
of 7 mg/1 as compared to 23 mg/1 for Coastal Louisiana facilities.
The comparison of the Cook Inlet data to a Louisiana unit, in the
low group, shows medians of 7 and 9 mg/1, respectively, and the
Louisiana unit having a lower predicted 99 percent upper limit.
The statistical data base included data obtained from single
grab samples and averaged daily samples. The majority of the
data was from average daily samples; therefore, additional
analysis based only on averaged data would have little effect on
the long-term average but would result in a slight reduction of
IX-9
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the daily maximum. Table 1X-1 summarizes the results of the
statistical analysis. The long-term average is the value that
would be expected to be obtained if grab samples were collected
four times each day for a period of 1-year and the analytical results
averaged. The monthly maximum in the maximum value at the
99 percent level that would be expected if four grab samples were
taken in a 2 4-hour period four times a month and the analytical
results averaged. The daily value is the maximum value that
would be expected at the 99 percent level if four grab samples
were taken during a 24-hour period and the analytical results
averaged. The monthly maximum value is dependent upon the
number of averaged daily sample collected during a 1-month
period.
Effluent Limitation
TABLE IX-1
Statistical Results
Oil and Grease
Long Term Monthly
Average Maximum
(mg/1)
27
57
Concentration
at 99% Level
85
IX-10
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100
90
80
70
60
50
40
30
20
o
H
H
w
CJ
§
o
W
10
9
8
7
6
5
5 10 15 20 30 40 50 60 70 80 85 90 95
PERCENT OF SAMPLES; EQUAL TO OR LESS THAN ORDINATE VALUE
Fig. IX-1—Cumulative Plot of Effluent Concentrations
of All Selected Flotation Units in the
Louisiana Gulf Coast Area
IX-11
98
-------
t-t
M
CJ
90
80
70
60
50
40
30
20
10
9
8
7
6
5
4
All Selected Flotation Units
in Louisiana Gulf Coast Area
A Flotation Unit in
La. Gulf Coast Area
A Flotation Unit
in the Cook Inlet
5 10 15 20 30 40 50 60 70 80 85 990
PERCENT OF SAMPLES EQUAL TO OR LESS THAN ORDINATE VALUE
Fig. IX-2 — All Selected Flotation Units
in the Louisiana Gulf Coast Area
Compared with Single Units in the
Louisiana Coast Area and the Cook
Inlet.
95
98
IX-12
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Production Brine Waste - No Discharge Technology
BPCT for production brine waste where no discharge is
permitted consists of the process control measure of reinject-
ing produced brine water for reservoir pressure maintenance and
for secondary recovery where it is compatible with reservoir
characteristics.
The end-of-pipe treatment technology used consists of evapora-
tion ponds, holding pits, and reinjection disposal wells. About
40 percent of the facilities with no discharge use end-of-pipe
technology. Existing disposal systems were reviewed to select the
exemplary technology for the purpose of establishing effluent
limitations. Holding pits were found to be the least desirable
because of frequent overflow, dike failure, infiltration of brine
into fresh water aquifiers, and in proper O&M. 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
periods. Disposal well systems consisting of skim tanks,
aeration facilities (if required), filtering system, backwash
holding facilities, clear water accumulators, pumps, and
wells provide the best method for disposal of produced brine.
These systems are equally applicable to onshore and offshore
operations and are the primary method used to dispose of
produced brines on the California coast and in the inland areas.
IX-13
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BPCT end-of-pipe treatment consists of skim tanks, aeration
facilities, filtering systems, backwash facilities, accumulators,
pumps, and disposal well. Specific treatability and subsurface
studies are required prior to application of a specific treatment
and disposal system to an individual facility.
Procedure for Development of BPCT Effluent Limitations
Effluent limits for produced brine are based on the reinjection
of produced brines and are applicable to all areas except for
Coastal Louisiana and Coastal Alaska, where discharge technology
has been permitted. In addition, there are two other exceptions
where discharges are now permitted because low TDS waters
are used to water livestock and because brines are discharged
to a dry salt basin. BPCT and effluent limitations for these two
areas are not proposed in this report because of insufficient
information.
The attainable level for BPCT is no discharge of production
water.
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
includes a comminutor, aeration tank, gravity clarifier, return
sludge system, and disinfection contact chamber. Studies of specific
treatability, operational performance, flow fluctuations and waste
characteristics are required prior to application of a specific treat-
ment system to an individual facility.
IX-14
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The effluent limitations were based on effluent data industry
provides to the U.S. Geological Survey; the data were compared to
the effluent levels achieved by similar systems and other
units which treat domestic wastes. Chlorine residual, BOD, and
suspended solids concentrations for the biological treatment
systems were within the range of values which would meet fecal
coliform requirement. The chlorine residuals for BPCT for offshore
facilities are presented in Table IX-2. The value specified is
the daily average and shall be maintained within the specified range.
TABLE IX-2
BPCT for Sanitary Wastes
Chlorine Residual,
Category mg/1
Oil and Gas Production 1. 0 +_ 40%
Exploration and Drilling 1. 0 + 40%
Sanitary Wastes -- Small Offshore Manned Facilities Operating
Intermittently
BPCT for sanitary wastes from small offshore 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
IX-15
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macerator-chlorinators. None of these systems has proved
totally adequate to meet the requirement for this subcategory;
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.
The attainable level of treatment provided by BPCT is the
reduction of waste such that there will be no floating solids.
Deck Drainage
BPCT for deck drainage is based on control practices used
within the oil producing industry and includes the following:
. Installation of oil separator tanks for collection of deck
washings.
. Elimination of dumping of lubricating oils and oily wastes
from leaks, drips and minor spillages to deck drainage collection
systems.
. Segregation of deck washings from drilling and workover
operations.
. O&M practices to remove all free-oil wastes 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 involve pretreat-
ment {solids removal and gravity separation) and further oil
IX-16
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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.
BPCT for deck drainage is presented in Table IX-3.
TABLE IX-3
BPCT for Deck Drainage
Oil and Grease
Long-term Average Max. Daily
Category (mg/1)
Oil and Gas Production 27 85
Exploration and Drilling 27 85
By Pass (Offshore Operations)
BPCT for by passing waste brine water treatment systems is
necessary when equipment becomes inoperative or requires mainte-
nance. Waste fluids must be controlled during by pass conditions
to prevent discharges of raw wastes into surface waters. Control
practices currently used in offshore operations are:
. Waste fluids are directed to onboard storage for temporary
holding until the waste treatment unit returns to operation.
. Waste fluids are directed to onshore treatment facilities
through a pipeline.
IX-17
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. Placing waste fluids in a barge for transfer to shore treatment.
. Waste fluids are piped to a primary treatment unit (simple
gravity separation) to remove free oil and discharged to surface
waters.
BPCT for by pass is presented in Table IX-4.
TABLE IX-4
BPCT For By Pass
Category Oil and Grease
Offshore Oil and Gas No discharge of free
a
Production oil to surface waters
a
Except soluble oil components.
Drilling Muds
BPCT for drilling muds includes control practices widely
used in both offshore and onshore drilling operations.
. Accessory circulating equipment such as shale shakers,
agitators, desanders, desilters, mud centrifuge, degassers, and
mud handling equipment.
. 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.
IX-18
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. 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 BPCT for offshore drilling muds is presented in Table IX-5
and BPCT for onshore is presented in Table IX-6.
TABLE IX-5
BPCT For Drilling Muds,
Offshore
Category
Natural & Water-Based Muds
Oil-Based &. Emulsion Muds
Oil and Grease
a
None
No discharge to surface water
Except for trace amounts of hydrocarbon-base pipe thread
compound which will enter the mud system during drilling.
>
All oil muds are to be transported to shore for reuse or disposal
in an approved disposal site.
IX-19
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TABUE IX-6
BPCT For Drilling Muds,
Onshore
Category Oil and Grease
Natural and Water-Based Muds No discharge to surface waters.
Oil-Based and Emulsion Muds No discharge to surface waters.
Drill Cuttings
BPCT for drill cuttings is based on existing treatment and
disposal methods used by the oil industry. The limitations for
offshore drill cuttings are presented in Table IX-7, and for
onshore drill cuttings are presented in Table IX-8.
IX-20
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TABLE IX-7
BPCT For Drill Cuttings,
Offshore
Category Oil and Grease
Cuttings in Natural or Water-
a
Based Mud None
b
Cuttings in Oil Muds None
a
Except for trace amount of hydrocarbon base pipe thread
compound which will enter the mud system during drilling.
b
Cuttings may be collected and transported to shore for
disposal in an approved disposal site.
TABLE IX-8
BPCT For Drill Cuttings,
Onshore
Category Oil and Grease
Cuttings in Natural or Water-
a
Based Mud No discharge
a
Cuttings in Oil Muds No discharge
a
Cuttings may be disposed of in an approved disposal site.
IX-21
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Workover
Workover fluids other than Gulf waters, ocean waters, or
water-based muds are recovered and reused. Materials not
consumed during workovers and completions are returned
to shore, if utilized offshore, or are returned to the service
areas when used onshore.
The effluent limitations were determined using data
supplied by industry and service companies serving the oil
producing industry. The limitations are shown in Tables
IX-9 and IX-10.
TABLE IX-9
BPCT For Workover and Completions,
Offshore
Cateogry Oil and Grease
a
Offshore Workover and Completion None
a
Except for trace amounts of hydrocarbon base pipe thread
compound which will enter the system during workover and
completion operations.
IX-22
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TABLE IX-10
BPCT l-'or Workover and Completions,
Onshore
Category Oil and Grease
Onshore Workover and Completion No discharge to surface waters.
Produced Sand
BPCT for produced sand is based on existing disposal methods
used by the oil industry. The limitations for produced sand are
presented in Table IX-11.
TABLE IX-11
BPCT For Produced Sand
Category Oil and Grease
Offshore Oil/Gas Production No discharge to surface waters.
Offshore Workover and Completion " " " " "
IX-23
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SECTION X
EFFLUENT LIMITATIONS FOR
BEST AVAILABLE TECHNOLOGY
Best available technology is defined as the very best control
and treatment technology employed by a specific point source within
the industrial category or subcategory. BAT that is readily trans-
ferable may be required of other industrial processes. These effluent
limitations are to go into effect not later than July 1, 1983. BAT
for all subcategories except brine production discharge technology
and deck drainage is the same as BPCT. BAT for brine production
wastes from the Gulf Coast and Coastal Alaska and for deck drainage
is defined as no discharge technology. This may be accomplished
through process or end-of-pipe treatments. This technology has been
demonstrated both for inland and offshore production operations.
BAT process technology is based on control practices now
practiced by some production facilities in the oil and gas produc-
tion industry and consists of:
. Reinject produced brine water for reservoir pressure
maintenance and secondary recovery operations where
compatible with reservoir characteristics.
. Combine all deck drainage waste with production fluids and
provide pretreatment in process units.
X-l
-------
SECTION XI
NEW SOURCE PERFORMANCE STANDARDS
Recommended effluent limitations for new source performance
standards are based on best available technology and effluent
limitation for each of the subcategories.
XI-1
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SKCTION XII
AC KNOW M'llXlKMKNT
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 II. Wyer, Oil and Special Materials Control Division
(OSMCD), Co-Chairman
II. I). Van Cleave, OSMCD. Co-Chairman
William Bye, OSMCD
Thomas Charlton, OSMCD
Harold Snyder, OSMCD
Kenneth Adams, OSMCD
Hans Crump-Wiesner, OSMCD
Arthur Jenke, OSMCD
R. W. Thieme, Office of Enforcement & General Counsel
Jeffrey Howard, Office of Enforcement & General Counsel
Charles Cook, Office of Water Planning & Standards
Martin Halper, Effluent Guidelines Division
Dennis Tirpak, Office of Research & Development
Thomas Belk, Permit Programs Division
Richard Insinga - Office of Planning & Evaluation
Stephen Dorrler, Edison Water Quality Research Laboratory,
Edison, N. J.
XII-1
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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 aquisition for onshore technology. Regions IV and
VIII assisted in onshore data aquisition.
Special appreciation is extended to the EPA Robert S. Karr
Research Laboratory (RSKRL), Ada, Oklahoma, for its technical
support. RSKRL managed and conducted the entire 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 surveys. Among those contributing: Alabama,
Arizona, Arkansas, California, Colorado, Florida, Illinois,
Louisiana, Missouri, Nebraska, Nevada, New Mexico, North
Dakota, Ohio, Pennsylvania, Utah, and Wyoming.
XII-2
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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 Berry - Chairman
XII-3
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Oil Operators, Inc.
Phillips Petroleum
Pollution Control Engineers
Rheem Superior
Shell Oil Company
Sun Oil Company
Texaco, Inc.
Tretolite Corporation
United States Filters
Union Oil Company
WEMCO
XII-4
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SECTION XIII
GLOSSARY AND ABBREVIATIONS
Acidize - To put acid in a well to dissolve limestone in a producing
zone so that passages are formed 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.
Barite - Barium sulfate. An additive used to weight drilling mud.
Barite 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 degree 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.
Blow out-Pre venter (BOP) - A device to control formation
pressures in a well by closing the annulus when pipe is suspended
in the well or by closing the top of the casing at other times.
XIII-1
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Bottom-Hole Pressure ~ Pressure at the bottom of a well (see
Formation Pressure).
Brackish Water - Water containing low concentrations of any
soluble salts.
Brine - Water saturated with or containing a high concentration
oT common salt (sodium chloride): also any strong saline
solution containing such other salts as calcium chloride,
zinc chloride, calcium nitrate.
BS&W - Basic sediment and water measured with oil. Generally
pipeline regulation limits the contents of 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 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 high
specific gravity solids from a drilling fluid. Usually used
on weighted muds to recover weight material and discard
solids. The centrifuge uses high-speed mechanical rotation
to achieve this separation as distinguished from the cyclone-
type separator in which the fluid energy alone provides the
separating force. See nDesander - Cyclone."
Chemical-Electrical Treater - A vessel which utilizes surfactants,
other chemicals and an electrical field to break oil-water
emulsion.
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.
XIII-2
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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.
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
tentions.
Coagulation - The combination or aggregation of semi-solid particles
such as fats or protems 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 change from a liquid to a thickened curd-like
state by chemical reaction. Also the combination of globules
in an emulsion caused by molecular attraction of the surfaces.
Connate Water - Water that probably was laid down and entrapped
with sedimentary deposits as distinguished from migratory
waters that have flowed into deposits after they were laid down.
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 called wet oil.
Cuttings - Small pieces of formation that are the result of
the chipping and/or crushing action of the bit.
Derrick and 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.
Desilter - Equipment, normally cyclone type, for removing
extremely fine drilled solids from the drilling mud stream.
Development Well - A well drilled for production from an estab-
lished 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, treaters, and other vessels for the purpose
of draining, or "dumping" a batch of oil or water.
Emulsion - A substantially permanent heterogeneous mixture
of two or more liquids (which are not normally dissolved
in each other, but which are) held in suspension or dis-
persion, 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.
Field - The area around a group of producing wells.
Flocculation - The combination or aggregation of suspended solid
particles in such a way that they form small clumps or tufts
resembling wool.
Flowing Well - A well which produces oil or gas without any
means of artificial lift.
Fluid Injection - Injection of gases or liquids into a reservoir
to force oil toward and into producing wells. (See also
"Water Flooding.")
Formation - Various subsurface geological strata penetrated
by well bore.
Formation Damage - Damage to the productivity of a well
resulting from invasion into the formation by mud particles.
Formation Pressure - See "Pore Pressure. "
Fracturing - Application of excessive hydrostatic pressure which
fractures the well bore (causing lost circulation of drilling
fluids.)
Freewater Knockout - An oil/water separation tank at atmospheric
pressure.
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Gas Lift - A means of stimulating flow by aerating 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 crude 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 -Tr; eater - A vessel used to break oil-water emulsion
with heat.
Hydrocarbon - A compound consisting only of atoms of
hydrogen and carbon.
Hydrogen 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 weigfrt of the column of drilling fluid; expressed in
pounds per square inch (psi).
Inhibitor - An additive which, when present in a petroleum
product, prevents or retards undesirable changes taking
place in the product, particularly oxidation and corrosion,
and sometimes paraffin formation.
Invert Oil (Emulsion Mud) - 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 (Drill 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.
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Multiple Completion - A well completion which provides for
simultaneous production from separate zones.
PCS - Outer Continental Shelf.
Offshore - In this context, the submerged lands between shore-
line and the edge of the continental shelf.
OHM - Oil and Hazardous Material.
Oil Well - A well completed for the production of crude oil
from at least one oil zone or reservoir.
Onshore - 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 - Normal permeability is a measure of
ability of rock to transmit a one-phase fluid under
condition of laminar flow.
Pressure Maintenance The amount of water or gas injected and
the oil and gas production are controlled in such a manner
that the reservoir pressure is maintained at a desired level,
Pump, Centrifugal - A pump whose propulsive effort is effec-
tuated by a rapidly turning impeller.
Rank Wildcat - An exploratory well drilled in an area far
enough removed from previously drilled wells to preclude
extrapolation of expected hole conditions.
Reservoir - Each separate, unconnected body of producing
formation.
Rotary Drilling - The method of drilling wells that depends
on the rotation of a column of drill pipe with a bit at the
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.
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Shale - Fine-grained clay rock with slate-like cleavage, some-
times containing (an oil-yielding substance).
Shale Shaker - Mechanical vibrating screen to separate drilled
formation cuttings carried to surface with drilling mud.
Shut In - To close valves on a well so that it stops producing;
said of a well on which the valves are closed.
Skimmer - A settling tank in which oil is permitted to rise to
the top of the water and is then taken off.
Stock Tank - See "Flow Tank. "
Stripper Well (Marginal Well) - A well which produces such
small volume or oil that the gross income therefrom pro-
vides 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.
TOG - Total Organic Carbon.
Total Depth (T. D.) - The greatest depth reached by the drill bit.
TDS - Total Dissolved Solids.
Treater - Equipment used to break an oil - water emulsion.
TSS - Total Suspended Solids.
USCG - United States Coast Guard.
USGS - United States Geological Survey.
Water Flooding - Water is injected under pressure into the for-
mation via injection wells and the oil is displaced toward
nearly producing wells.
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Well Completion - In a potentially productive formation, the
well must be completed 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 produc-
ing layer, for this purpose. Some geological formations
require the use of additional techniques to "complete" a
well such as casing the producing formation and using a "gun
perforator" to make entry holes, the use of slotted pipes,
consolidating sand layers with chemical treatment, and the
use of surface-actuated underwater robots for offshore wells.
Well Head - Equipment used at the top of a well, including casing
head, tubing head, hangers, and Christmas Tree.
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.
Wiper,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.
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