EPA 440/1-76/055-a
Group II
Development Document for Interim
Final Effuent Limitations Guidelines
and
Proposed New Source Performance
Standards for the
OIL & GAS EXTRACTION
Point Source Category
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
SEPTEMBER 1976
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DEVELOPMENT DOCUMENT
for
INTERIM FINAL
EFFLUENT LIMITATIONS GUIDELINES
and
PROPOSED NEW SOURCE PERFORMANCE STANDARDS
for the
OIL AND GAS EXTRACTION
POINT SOURCE CATEGORY
Russell E. Train
Administrator
Andrew W. Breidenbach
Assistant Administrator for
Water and Hazardous Materials
Eckardt C. Beck
Deputy Assistant Administrator for
Water Planning and Standards
Robert B. Schaffer
Director, Effluent Guidelines Division
Martin Hal per
Project Officer
September, 1976
Effluent Guidelines Division
Office of Water and Hazardous Materials
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 limitations guidelines, for existing point
sources and standards of performance for new sources, to
implement Sections 301, 304, 306 and 307 of the Federal Water
Pollution Control Act, as amended (33 U.S.C. 1551, 1314, and
1316, 86 Stat. 816 et. seq.) (the "Act"). Guidelines and
standards were developed for the Oil and Gas Extraction Industry,
which was divided into 6 subcategories.
Effluent limitations guidelines contained herein set forth the
degree of effluent reduction attainable through the application
of the best practicable control technology currently available
(BPCTCA) and the degree of effluent reduction attainable through
the application of the best available technology economically
achievable (BATEA) which must be achieved by existing point
sources ty July 1, 1977 and July 1, 1983, respectively. The new
source performance standards (NSPS) contained herein set forth
the degree of effluent reduction which are achievable through the
application of the best available demonstrated control
technology, processes, operating methods, or other alternatives.
Supporting data and rationale for the development of proposed
effluent limitations guidelines and standards of performance are
contained in this development document.
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TABLE OF CONTENTS
Section Pace
ABSTRACT 1
I CONCLUSIONS 1
II RECOMMENDATIONS 3
III INTRODUCTION 7
Purpose and Authority 7
General Description of Industry 8
Industry Distribution 23
Industry Growth 26
Bibliography 29
IV INDUSTRY SUBCATEGORIZATION 31
Rationale of Subcategorization 31
Development of Subcategories 32
Description of Subcategories 36
Bibliography 40
V WASTE CHARACTERISTICS 41
Waste Constituents 41
Bibliography 53
VI SELECTION OF POLLUTANT PARAMETERS 55
Parameters for Effluent Limitations 55
Other Pollutants 56
Oxygen Demand Parameters 59
Phenolic Compounds 60
Bibliography 63
111
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Section Page Np_.
VII CONTROL AND TREATMENT TECHNOLOGY 65
In-plant Control/Treatment Techniques 65
Analytical Techniques and field 68
Verification Studies
Zero Discharge Technologies 85
End-of-Pipe Technology for Wastes Other 94
than Produced Water
Bibliography 100
V11I COST, ENERGY, AND NONWATER 103
QUALITY ASPECTS
Cost Analysis 103
Offshore Produced Water Disposal 103
Onshore Produced Water Disposal 106
Offshore Sanitary Waste 116
Energy Requirements for Operating 116
Flotation Systems
Nonwater-Quality Aspects 117
Bibliography 123
IX EFFLUENT LIMITATIONS FOR BEST 125
PRACTICABLE CONTROL TECHNOLOGY
Produced Water Technology 125
Procedure for Development of 126
BPCT Effluent Limitations
Bibliography 138
X EFFLUENT LIMITATIONS FOR BEST AVAILABLE 139
TECHNOLOGY ECONOMICALLY ACHIEVABLE
Near Offshore and Coastal Subcategories - 139
Produced Water
Far Offshore Subcategory - Produced Water 139
and Deck Drainage
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Section ^i No.
XI NEW SOURCE PERFORMANCE STANDARDS 143
XII ACKNOWLEDGEMENTS ^45
XIII GLOSSARY AND ABBREVIATIONS 147
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LIST OF TABLES
Table No. Title Page No.
1 Effluent Limitation - BPCTCA 4
2 Effluent Limitation - BATEA and 5
New Source
3 U.S. Supply and Demand of Petroleum 28
and Natural Gas
4 U.S. Offshore Oil Production 28
5 Pollutants in Produced Water, 42
Louisiana Coastal
6 Pollutants contained in Produced Water, 44
coastal California
7 Range of Constituents in Produced 45
Formation Water—Offshore Texas
8 Range of Constituents in Produced 46
Formation Hater—Onshore California
9 Range of Constituents in Produced 47
Formation Water—Wyoming
10 Range of Constituents in Produced 47
Formation Water—Pennsylvania
11 Range of Constituents in Produced 48
Formation Water—Onshore Louisiana
12 Range of Constituents in Produced 48
Formation Water—Onshore Texas
13 Volume of Cuttings and Muds in 51
Typical 10,000 Foot Drilling
Operation
14 Typical Raw Combined Sanitary and 52
Domestic Wastes from Offshore Facilities
15 Effluent Quality Requirements for 62
Ocean Waters of California
16 Effect of Acidification on Oil 69
and Grease Data
17 Oil and Grease Data, Texas Coastal 71
vii
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Table No. Title page J
18 Oil and Grease Data, California 71
Coastal
19 Performance of Individual Units, 73
Louisiana Coastal
20 Texas Coastal Verification Data 74
21 Verification of Oil and Grease Data, 75
California Coastal
22 Performance of Various Treatment 84
Systems, Louisiana Coastal
23 Performance of Various Treatment 84
Systems, Wyoming and Pennsylvania
24 Design Requirements for 99
Offshore Sanitary Wastes
25 Average Effluents of Sanitary Treatment 99
Systems, Louisiana Coastal
26 Operating Cost Offshore 106
27 Formation Water Treatment Equipment 107
Costs, Offshore Installations, 200
Barrels Per Day flow Rate
28 Formation Water Treatment Equipment Costs, 108
Offshore Installation, 1,000 Barrels
Per Day Flow Rate
29 Formation Water Treatment Equipment Costs, 109
Offshore Installation, 5,000 Barrels Per
Day Flow Rate
30 Formation Water Treatment Equipment Costs, 110
Offshore Installation, 10,000 Barrels
Per Day Flow Rate
31 Formation Water Treatment Equipment Costs, 111
Offshore Installation, 40,000 Barrels
Per Eay Flow Rate
32 Capital Costs for Onshore Disposal by 113
Reinjection of Produced Formation Water
From Field Surveys in Selected States
Vlll
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Table No. Title Page No.
33 Annual Operating Cost for Onshore Disposal 114
by Reinjection of Produced Formation Water
From Field Surveys in Selected States
34 Cost Estimates for Treatment in Ponds and 115
Disposal by Discharge for Stripper Well
Facilities
35 Cost Estimates for Treatment by Gas 116
Flotation and Pond and Discharge for
Beneficial Dischargers
36 Cost Estimates for Treatment by Gas 116
Flotation and Discharge for Coastal
Platforms
37 Estimated Treatment Plant Costs for 119
Sanitary Wastes for Offshore Locations
Package Extended Aeration Process
38 Estimated Horsepower Requirements for the 120
Operation of Flotation Treatment Systems
39 Estimated Incremental Energy Requirements, 121
Flotation Systems
40 Energy Requirements for Flotation Systems 122
as Compared to Net Energy Production
Associated with the Produced Water Flows
41 Conversion Table 154
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LIST OF FIGURES
Figure No. Title Page No.
1 Rotary Drilling Rig 10
2 Shale Shaker and Blowout 11
Preventer
3 Central Treatment Facility in 15
Estuarine Area
H Horizontal Gas Separator 16
5 Vertical Heater-Treater 18
6 Rotor-Disperser and Cissolved Gas 77
Flotation Processes for Treatment
of Produced Water
7 Onshore Production Facility with 86
Discharge to Surface Waters
8 Typical Cross Section Unlined 87
Earthern Oil-Water Pit
9 Typical Completion of an Injection 90
Well and a Producing Well
10 99th Percentile of Monthly Average Oil 131
and Grease Concentration vs. Frequency
of Sampling Each Month
11 Cumulative Plot Effluent Concentrations 132
of all Selected Flotation Units in the
Louisiana Gulf Coast Area
\± Cumulative Plot of Effluent Concentrations 134
of all Wyoming Data
13 Cumulative Plot of Effluent Concentrations 141
of Ten Selected Flotation Units in the
Louisiana Gulf Coast Area
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SECTION I
CONCLUSIONS
This study covered the waste treatment technology for the Oil and
Gas Extraction Point Source Category. The Oil and Gas Extraction
Point Source Category covers the pollutants arising from the
production of crude petroleum and natural gas, drilling oil and
gas wells, and oil and gas field exploration services.
The wastes associated with this category result from the
discharge of produced water, drilling muds, drill cuttings, well
treatment, and produced sands for all subcategories and
additionally, deck drainage, sanitary and domestic wastes for the
offshore and coastal subcategories.
Since the raw waste loads and treatability of the wastes are
independent of size, location and climate and the volume of
production water varies with the age and nature of the producing
formation, the limitations are set in terms of concentration and
the subcategorization is based on a balance of the costs with the
potential environmental benefits and energy use (loss). The
subcategories developed for the oil and gas extraction industry
for the purpose of establishing effluent limitations are as
follows:
Subcategory Operations Included
1. Near-offshore All facilities within offshore State
waters.
2. Far-Offshore All facilities in Federal waters.
3. Onshore All facilities landward of the territorial
seas (except as defined by 4, 5, and 6
below).
4. Coastal All facilites in the coastal bays and
estuaries of Louisiana and Texas.
5. Beneficial Use These facilites with low TDS content
produced waters who* s discharge serves
some beneficial use.
6. Stripper All facilities with less than 10 barrels
of crude oil per calendar day of
production.
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SECTION II
RECOMMENCATIONS
The significant or potentially significant waste water
constituents are oil and grease, fecal coliform, oxygen demanding
parameters, heavy metals, total dissolved solids, and toxic
materials. These waste water constituents were selected to be
the subject of the effluent limitations.
Effluent limitations commensurate with the best practicable
control technology currently available are promulgated interim
final for each sutcategory. These limitations, listed in Table 1
are explicit numerical values (whenever possible) or some other
criteria.
BPCTCA end-of-pipe technology is based on the application of the
existing waste water treatment processes currently used in the
Oil and Gas Extraction Industry. These consist of equalization,
chemical addition, and gas flotation (or its equivalent) for the
treatment of produced water and deck drainage. The variability
of performance of this type of waste water treatment system has
been recognized in the development of the BPCTCA effluent
limitations.
Effluent limitations commensurate with the best available
technology economically achievable are proposed for each
subcategory. These effluent limitations are listed in Table 2.
The primary end-of-pipe treatment for the near offshore
subcategory is the subsurface disposal of production water and
for the far offshore subcategory it is similar to that for
BPCTCA.
New source performance standards commensurate with the best
available demonstrated technology are the same as the BATEA
limitations. These effluent limitations are listed in Table 2.
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Subcategory
A. Near Offshore
B. Far Offshore
D. Coastal
C. Onshore
E. Beneficial Use
Notes:
TABLE 1
Oil and Gas Extraction Industry
Effluent Limitations - BPCTCA
Water Source
produced water
deck drainage
drilling muds
drill cuttings
well treatment
sanitary M10
M9IMC
domestic0
produced sand
produced water
drilling muds
drill cuttings
well treatment
produced sand
Oil & Grease - mq/1
Residual Chlorine - mg/1
Maximum for
any one day
72
72
a
a
a
N/A
N/A
N/A
a
Average of daily
values for thirty
consecutive days
shall not exceed
48^
48d
a
a
a
N/A
N/A
N/A
a
no discharge
no discharge
no discharge
no discharge
N/A
N/A
N/A
N/A
N/A
N/A
greater than 1D
N/A
N/A
N/A
N/A
a - No discharge of free oil to the surface waters.
b - Minimum of 1 mg/1 and maintained as close to this concentration as possible.
c - There shall be no floating solids as a result of the discharge of these materials.
d - Not applicable to the Coastal subcategory.
e - For the onshore subcategory - no discharge; for the beneficial use subcategory - 45 mg/1
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Subcategory
A. Near Offshore
D. Coastal
B. Far Offshore
A. Near Offshore
B. Far Offshore
C. Onshore
D. Coastal
E. Beneficial Use
Notes:
TABLE 2
Oil and Gas Extraction Industry
Effluent Limitations - BATEA and New Source
Water Source
produced water
deck drainage
produced water
deck drainage
drilling muds
drill cuttings
well treatment
sanitary M10
M9IM
domestic
produced sand
Pollutant Parameter - Effluent Limitations
Oil & Grease - mg/1
Residual Chlorine - mg/1
Maximum for
any one day
Average of daily
values for thirty
consecutive days
shall not exceed
72
52
52
a
a
a
N/A
N/A
N/A
a
No discharge
48
30
30
a
a
a
N/A
N/A
N/A
a
N/A
N/A
N/A
N/A
N/A
N/A
greater than 1
N/A -
N/A
N/A
a - These BAT and New Source limitations are identical to those applicable for each
subcategory as for BPT listed in Table 1.
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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
achievement by not later than July 1, 1983, of more stringent
effluent limitations for point sources, other than publicly owned
treatment works. The 1983 limitations are to be based on
application of the best available technology economically
achievable which will result in reasonable further progress
toward the national goal of eliminating the discharge of all
pollutants, as determined in accordance with regulations issued
by the Administrator pursuant to Section 304(b) of the Act.
Section 306 of the Act requires the Administrator, within one
year after a category of sources is included in a list published
pursuant to section 306 (b) (1) (A) of the Act, to propose
regulations establishing Federal standards of performances for
new sources within such categories. The Administrator published,
in the Federal Register of January 16, 1973 (38 F.R. 1624) , a
list of 27 source categories. Publication of an amended list
will constitute announcement of the Administrator's intention of
establishing, under section 306, standards of performance
applicable to new sources within the Oil and Gas Extraction
Industry. The list will be amended when proposed regulations for
the Oil and Gas Extraction Industry are published in the Federal
Register.The standards are to reflect the greatest degree of
effluent reduction which the Administrator determines to be
achievable through the application of the best available
demonstrated control technology, processes, operating methods, or
other alternatives; where practicable, a standard may permit no
discharge of pollutants.
Section 304 (b) of the Act requires the Administrator to publish
within one year of enactment of the Act, regulations providing
guidelines for effluent limitations. The guidelines are to set
forth:
The degree of effluent reduction attainable through application
of the best practicable control technology currently available.
The degree of effluent reduction attainable through application
of the best control measures and practices economically
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achievable including treatment techniques, process and procedure
innovations, operating methods, and other alternatives.
The findings contained herein set forth effluent limitations
guidelines pursuant to Section 304(b) of the Act for certain
segments of the petroleum industry.
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 elsewhere
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 derived from each of the industry subcategories established
in Section IV, it is essential to evaluate the sources and
contaminants in the three broad activities in the oil and gas
industry—exploring, drilling, and producing—as well as the
satellite industries that support those activities.
Exploration
The exploration process usually consists of mapping and aerial
photography of the surface of the earth, followed by special
surveys such as seismic, gravimetric, and magnetic, to determine
the subsurface structure. The special surveys 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
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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 formation. This latter class of wells may be shallow
and drilled in the initial exploratory phase of operations, or
may be deep exploration seeking to discover oil or gas bearing
reservoirs.
Most wells are drilled today by rotary drilling methods.
Basically the methods consist of:
1. Machinery to turn the bit, to add sections on the drill
pipe as the hole deepens, and to remove the drill pipe
and the bit from the hole.
2. A system for circulating a fluid down through the drill
pipe and back up to the surface.
This fluid removes the particles cut by the bit, cools and
lubricates the bit as it cuts, and, as the well deepens, controls
any pressures that the bit may encounter in its passage through
various formations. The fluid also stabilizes the walls of the
well bore.
The drilling fluid system consists of tanks to formulate, store,
and treat the fluids; pumps to force them through the drill pipe
and back to the surface; and machinery to remove cuttings, fines,
and gas from fluids returning to the surface (see Figure 1). A
system of valves controls the flow of drilling fluids from the
well when pressures are so great that they cannot be controlled
by weight of the fluid column. A situation where drilling fluids
are ejected from the well by subsurface pressures and the well
flows uncontrolled is called a blowout, and the controlling valve
system is called the blowout preventer (see Figure 2).
For offshore operations, drilling rigs may be mobile or
stationary. Mobile rigs are used for both exploratory and
development drilling, while stationary rigs are used for
development drilling in a proven field. Some mobile rigs are
mounted on barges and rest on the bottom for drilling in shallow
waters. Others, also mounted on barges are jacked up above the
water on legs for drilling in deeper water (up to 300 feet). A
third class of mobile rigs are on floating units for even deeper
operations. A floating rig may be a vessel, with a typical
ship's hull, or it may be semisubmersible—essentially a floating
platform with special submerged hulls and supporting a rig well
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A KELLY
B STANDPIPE and ROTARY HOSE
C SHALESHAKER
D OUTLET FOR DRILLING FLUID
E SUCTION TANK
F PUMP
FLOW OF DRILLING FLUID
Fig. 1 — ROTARY DRILLING RIG
10
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j --••?—
n
fit
il
^ A
h — :>
CASING
1
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. 2 -- SHALESHAKER AND BLOWOUT PREVENTER
11
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above the water.
platforms.
Stationary rigs are mounted on pile-supported
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.
The drilling of a well from top to bottom is not a continuous
process. A well is drilled in sections, and as each section is
completed it is lined with a section of pipe or casing (see
Figure 2). The different sections may require different types of
mud. The mud from the previous section must either be disposed
of or converted for the next section. Some mud is left in the
completed well.
Basic mud components include: bentonite or attapulgite clays to
increase viscosity and create a gel; barium sulfate (barite), a
weighting agent; and lime and caustic soda to increase the pH and
control viscosity. (Additional conditioning constituents may
consist of polymers, starches, lignitic material, and various
other chemicals). Most muds have a water base, but some have an
oil base. Oil based muds are used in special situations and
present a much higher potential for pollution. They are
generally used where bottom hole temperatures are very high or
where water based muds would hydrate water-sensitive clays or
shales. They may also be used to free stuck drill pipes, to
drill in permafrost areas, and to kill producing wells.
As the drilling mud is circulated down the drill pipe, around the
bit, and back up in annulus between the bore hole and the drill
pipe, it brings with it the material cut and loosened by the bit,
plus fluids which may enter the hole from the formation (water,
oil, or gas) . When the mud arrives at the surface, cuttings,
silt, and sand are removed by shaleshakers, desilters, and
desanders. Oil or gas from the formation is also removed, and
the cleansed mud is cycled through the drilling system again.
With offshore wells, the cuttings, silt and sand are discharged
12
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overboard if they do not contain oil. Some drilling mud clings
to the sand and cuttings, and when this material reaches the
water the heavier particles (cuttings and sand) sink to the
bottom while the mud and fines are swept down current away from
the platform.
Onshore, discharges from the shaleshakers and cyclone separators
(desanders or desilters) usually go to an earthen (slush) pit
adjacent to the rig. To dispose of this material the pit is
backfilled at the end of the drilling operations.
The removal of fines and cuttings is one of a number of steps in
a continuing process of mud treatment and conditioning. This
processing may be done to Jceep 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 fce 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.
Production System
Crude oil, natural gas, and gas liquids are normally produced
from geological reservoirs through a deep bore well into the
surface of the earth. The fluid produced from oil reservoirs
normally consists of oil, natural gas, and salt water or brine
containing both dissolved and suspended solids. Gas wells may
produce dry gas but usually also produce varying quantities of
light hydrocarbon liquids (known as gas liquids or condensate)
and salt water. As in the case of oil field brines, the water
contains dissolved and suspended solids and hydrocarbon
contaminants. The suspended solids are normally sands, clays, or
other fines from the reservoir. The oil can vary widely in its
physical and chemical properties. The most important properties
are its density and viscosity. Density is usually measured by
the "API 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 materials.
The fluids are normally moved through tubing contained within the
larger cased bore hole. For oil wells, the energy required to
13
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lift the fluids up the well can be supplied by the natural
pressures in the formation, or it can be provided or assisted by
various man-made operations at the surface. The most common
methods of supplying man-made energy to extract the oil are: to
inject fluids (normally water or gas) into the reservoir to
maintain pressure, which would otherwise drop during withdrawal;
to force gas into the well stream in order to lighten the column
of fluid in the bore and assist in lifting as the gas expands up
the well; and to employ various types of pumps in the well
itself. As the fluids rise in the well to the surface, they flow
through various 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 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 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 4
shows a gas separator for separating gas from the well stream.
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CENTRAL TREATMENT FACILITY IN ESTUARINE AREA
HIGH PRESSURE GAS
Ln
II- L. XL Jl
Fig. 3 .— CENTRAL TREATMENT FACILITY IN ESTUARINE AREA
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A B
C-DE-FOAMING
A-OIL AND GAS INLET ELEMENT E_M|SJ EXTRACTOR 6-DRAIN
D-WAVE BREAKER AND
B-IMPACT ANGLE
SELECTOR PLATE
F-GAS OUTLET
H-OIL OUTLET
(DUMP VALVEl
Fig. 4 — HORIZONTAL GAS SEPARATOR
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Liquids (oil or oil and water) along with particulate matter
leave the separator through the dump valve and go on to the next
stage: oil-water separation. Because gas comes out of solution
as pressure drops, gas-oil separators are often arranged in
series. High-pressure, intermediate, and low-pressure separators
are the most common arrangement, with the high-pressure liquids
passing through each stage in series and gas being taken off at
each stage. Fluids from lower-pressure wells would go directly
to the most appropriate separator. The liquids are then piped to
vessels for separating the oil from the produced water. Water
which is not emulsified and separates easily may be removed in a
simple separation vessel called a free water knockout.
The remaining oil-water mixture will continue to another vessel
for more elaborate treatment (see Figure 5) . In this 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 trine on the bottom, and a layer
of emulsified oil and brine in the middle. There is usually a
sensing unit to detect the oil-water interface in the vessel and
regulate the discharge of the fluids. Emulsion breaking
chemicals are often added before the liquid enters this vessel,
the vessel itself is often heated to facilitate breaking the
emulsion, and some units employ an electrical grid to charge the
liquid and to help break the emulsion. A combination of
treatment methods is often employed in a single vessel. In
three-phase separation, gas, oil, and water are all separated in
one unit. The gas-oil and oil-water interfaces are detected and
used to control rates of influent and discharge.
Oil from the oil-water separators is usually sufficiently free of
water and sediment (less than 2 percent) so as to be marketable.
The produced water or produced water/solids mixtures discharged
at this point contain too much oil to be disposed of into a water
body. The object of processing through this point is to produce
marketable products (clean oil and dry gas). In contrast, the
next stages of treatment are necessary to remove sufficient oil
from the produced water so that it may be discharged. These
treatment operations do not significantly increase the quality or
quantity of the saleable product. They do decrease the impact of
these wastes on the environment.
Typical produced water from the last stage of process would
contain several hundred to perhaps a thousand or more parts per
million of oil. There are two methods of disposal: treatment
and discharge to surface (salt) waters or injection into a
suitable subsurface formation in the earth. Surface discharge is
normally used offshore or near shore where bodies of salt or
brackish water are available for disposal. Injection is widely
used onshore where bodies of salt water are not available for
17
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GAS OUT
OAS OUTLET
EMULSION
INLET
EXCELSIOR
(OTHER TYPES OF UNITS
MIGHT CONTAIN THE GRID
OF AN ELECTRIC DEHYDRATOR
IN PLACE OF THE FILTER SECTION)
OILOUT
WATER OUT
EMULSION IN
Fig. 5 — VERTICAL HEATER-TREATER
18
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surface disposal. (produced water to be disposed of by injection
may still require some treatment).
Some of the same operations used to facilitate separation in the
last stage of processing (chemical addition and retention tanks)
may be used in waste water treatment, and other methods such as
filtering, and separation by gas flotation are also used. In
addition, combinations 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 produced water to surface salt or brackish water bodies.
The sophistication of the treatment employed by dischargers of
produced water is dependent upon the regulation governing such
discharges. For instance in the Appalachian states most produced
water is discharged to local streams after only treatment in
ponds; while in California dischargers utilize a high degree of
treatment. The state of Wyoming allows discharge for beneficial
use if the produced water meets oil and grease and total
dissolved solids (IDS) requirements.
Several options are available in injection systems. Often water
will be injected into a producing oil reservoir to maintain
reservoir pressure, and stabilize reservoir conditions. In a
similar operation called water flooding, water is injected into
the reservoir in such a way as to move oil to the producing wells
and increase ultimate recovery. This process is one of several
known as secondary recovery since it produces oil beyond that
available by primary production methods. A successful water
flooding project will increase the amount of oil being produced
at a field. It will also increase produced water volume and thus
affect the amount of water that must be treated. Pressure
maintenance of water injection may also increase the amount of
water produced and treated. Injection is also feasible solely as
a disposal method. It (injection) is extensively used in onshore
production areas except in the Appalchian states of Pennsylvania,
West Virginia, New York and Kentucky, where useable shallow
horizons do not exist. In California, produced water from
offshore facilities is transported to shore for disposal by
reinjection.
The treatment associated with produced water disposal by
injection is dependent upon the permeability of the receiving
formation. In most all cases corrosion-inhibiting chemicals are
necessary, but the treatment can range from simply skim tanks to
gas flotation followed by mixed-media filtration.
Evolution of Facilities
Early offshore development tended to place wells on individual
structures, bringing the fluids ashore for separation and
19
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treatment (see figure 3), As the industry moved farther
offshore, the wells still tended to be located on individual
platforms with the output to a central platform for separation,
treatment, and discharge to a pipeline or barge transportation
system.
With increasing water depth, multiple-well platforms were
developed with 20 or more wells drilled directionally from a
single platform. Thus an entire field or a large portion of a
field could be developed from one structure. Offshore Louisiana
multiple-well platforms include all processing and treatment, in
offshore California ard in Cook Inlet facilities, gas separation
takes place on the platforms, with the liquids usually sent
ashore for separation and treatment.
All forms of primary and secondary recovery as well as separation
and treatment are performed on platforms, which may include
compressor stations for gas lift wells and sophisticated water
treatment facilities for water flood projects. Platforms far
removed from shore are practically independent production units.
Platform design reflects the operating environment. Cook Inlet
platforms are enclosed for protection from the elements and have
a structural support system designed to withstand ice floes and
earthquakes. Gulf Coast platforms are usually open, reflecting a
mild climate. Support systems are designed to withstand
hurricane-generated waves.
A typical onshore production facility would consist of wells and
flowlines, gas-liquid and oil-water production separators, a
waste water treatment unit (the level of treatment being
dependent on the quality of the waste water and the demands of
the injection system and receiving reservoir) , surge tank, and
injection well. Injection might either be for pressure
maintenance and secondary recovery or solely for disposal. In
the latter case, the well would probably be shallow 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 called "tertiary
recovery." The process usually involves injecting some substance
into the oil reservoir to release or carryout additional oil not
recovered by primary recovery (flowing wells by natural reservoir
pressure, pumping, or gas lift) or by secondary recovery.
Tertiary recovery is usually classified by the substance injected
into the reservoir and includes:
1. Thermal recovery
2. Miscible hydrocarbon
20
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3. Carbon dioxide
4. Alcohols, soluble oil, micellar solutions
5. Chemical floods, surfactants
6. Gas, gas/water, inert gas
7. Gas repressuring, depletion
8. Polymers
9. Foams, emulsions, precipitates
The material is injected into the reservoir and moves through the
reservoir to the producing wells. During this passage, it
removes and carries with it oil remaining in pores in the
reservoir rocks or sands. Oil, the injected fluid, and water may
all be moved up the well and through the normal production and
treatment system.
Nine economically successful applications of tertiary recovery
have been documented (two of them in Canadian fields): one
miscible hydrocarbon application; three gas applications; two
polymer applications, and three combinations of miscible
hydrocarbon with gas drive.
At this time very little is known about the wastes that will be
produced by these production processes. They will obviously
depend on the type of tertiary recovery used.
Field Service
A number of satellite industries specialize in providing certain
services to the production side of the oil industry. Some of
these service industries produce a particular class of waste that
can be identified with the service they provide. Of the waste-
producing service industries, drilling (which is usually done by
a contractor) is the largest. Drilling fluids and their disposal
have already been discussed. Other services include completions,
workovers, well acidizing, and well fracturing.
When a company decides that an oil or gas well is a commercial
producer, certain equipment will be installed in the well and on
the well head to bring the well into production. The equipment
from this process—called "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
21
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rig may be the same one that drilled the well, or it may be a
special (normally smaller) workover rig installed over the well
after the drilling rig has been moved.
After a well has been in service for a while it may need remedial
work to keep it producing at an acceptable rate. For example,
equipment in the well may malfunction, different equipment may be
required, or the tubing may become plugged up by deposits of
paraffin. If it is necessary to remove and reinstall the tubing
in the well, a workover rig will be used. It may be possible to
accomplish the necessary work with tools mounted on a wire and
lowered into the well through the tubing. This is called a wire
line operation. In another systeir, tools may be forced into the
well by pumping them down with fluid. Where possible, the use of
a rig is avoided, since it is expensive.
In many wells, the potential for production is limited by
impermeability in the producing geological formation. This
condition may exist when the well is first drilled, it may worsen
with the passage of time, or both situations may occur. Several
methods may be used, singly or in combination, to increase the
well flow by altering the physical nature of the reservoir rock
or sand in the immediate vicinity of the well.
The two most common methods to increase well flow are acidizing
and fracturing. Acidizing consists of introducing acid under
pressure through the well and into the producing formation. The
acid reacts with the reservoir material, producing flow channels
which allow a larger volume of fluids to enter the well. In
addition to the acid, corrosion inhibitors are usually added to
protect the metal in the well system. Wetting agents, solvents,
and other chemicals may also be used in the treatment.
In fracturing, hydraulic pressure forces a fluid into the
reservoir, producing fractures, cracks, and channels. Fracturing
fluids may contain acids so that chemical disintegration, as well
as fracturing takes place. The fluids also contain sand or some
similar material that keeps the fracture propped open once the
pressure is released.
When a new well is being completed or when it is necessary to
pull tubing to worx 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 te disposed of in pits or may be
22
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salvaged. Contaminated oil is usually disposed by burning at the
site.
In acidizing and fracturing, the spent fluids used are wastes.
They are moved through the production, process, and treatment
systems after the well begins to flow again. Therefore, initial
production from the well will contain some of these fluids.
Offshore, 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
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
1974, domestic production was 8.8 million barrels-per-day (bpd)
of oil and 1.7 million bpd of gas liquids, for a total production
of 10.5 bpd; down slightly from the four previous years. (3)
Total imports were 6.1 million bpd for 1974.
There are approximately half a million producing oil wells and
126,000 gas and condensate wells in the United States. Of the
30,000 new wells drilled each year, about 55 percent produce oil
or gas.
Oil is presently produced in 32 of the 50 states and from the
Outer Continental Shelf (OCS) off of Louisiana, Texas, and
California. Exploratory drilling is underway on the OCS off of
Mississippi, Alabama, and Florida. In 1972, the five largest
oil-producing States were: Texas, Louisana, California, Oklahoma,
and Wyoming. With development of the North Slope oil fields and
construction of the Alaska pipeline, Alaska will become one of
the most important oil producing States.
Offshore oil production is presently concentrated in three areas
in the United States: the Gulf of Mexico, the coast of
California, and Cook Inlet in Alaska. Offshore oil production in
1973 was approximately 62 million barrels from Cook Inlet, 116
million from California, and 215 million from Louisiana and
Texas,
Gulf of Mexico - Texas and Louisiana
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
23
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can be installed, development drilling completed, and pipelines
laid.
Leases have been granted in water as deep as 600 feet. These
deep areas will probably be served by conventional types of
platforms, but their size and cost increase rapidly with
increasing depth.
In addition to offshore activities, onshore production in Texas
for 1974 accounted for 1,226 million barrels of oil and 7,942,352
million cubic feet of gas, the largest contribution of any state.
Oil production has been on a decline in Texas since the peak year
of 1972. Oil and gas production in Texas is widespread,
involving 212 out of 254 counties and approximately 165,000 gas,
condensate, and crude oil wells. The amount of produced water
generated is dependent on the method of oil production and the
field location. Higher water cut ratios are experienced near the
Gulf. Regulation by the State Railroad Commission prohibits
discharge of produced water to fresh water bodies, and therefore
reinjection for recovery and disposal technology has been
developed to a high degree.
Onshore activity in Louisiana is also significant, accounting for
307 million barrels of crude in 1974 originating from 61 out of
the 64 parishes (counties) in the State. There are approximately
11,500 wells producing crude oil onshore and less than one
percent of these wells are in the stripper category (less than
ten barrels per day production). Of the 1,068 million barrels of
produced water generated in 1974 the majority was rexnjected for
either recovery or disposal purposes; the remainder was
discharged to unlined puts, saltwater estuaries or fresh water
streams. The discharge of production water to fresh water
streams is limited to the southern and central parts of the State
where drilling of reinjection wells is extremely costly.
Discharge to saltwater estuaries is practiced along the Gulf
Coast. Treatment prior to discharge consists of skim tanks and
settling/separator ponds. Where reinjection is practiced the
facilities are unsophisticated, consisting of a primary separator
and sedimentation. The disposal formations are at 2000-5000 foot
depth and are very permeable, resulting in low well head pressure
and power costs. Approximately 60% of the oil production under
State onshore leases is generated at facilities which discharge
their produced water.
California
There has been a general moratorium on drilling and development
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
24
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area farther north. OCS production is confined to the Santa
Barbara area. Except for one facility, all production from both
State and Federal leases is piped ashore for treatment. A large
and increasing amount of the produced brine is disposed of by
subsurface injection.
Exxon Corporation has applied for permits to develop an area
leased prior to 1969 in the northern Santa Barbara Channel (the
"Santa Ynez Unit"). Several fields have been discovered on these
leases in water depths from 700 to over 1,000 feet. Proposed
development of the shallower portion of one of these areas calls
for erection of a multiple-well drilling and production platform
in 850 feet of water. If gas and oil are found in commercial
quantities, the gas would be separated on the platform, with the
water and oil sent ashore for separation and treatment. Produced
water would be disposed of by subsurface injection ashore.
Additional lease sales have been made on the OCS off Santa
Barbara in Southern California.
Total oil production in California for 1974 was approximately 390
million barrels (83 million barrels offshore), a decline from the
previous year. In addition to offshore facilities, the major
areas of production in California are in the southern San Jacquin
Valley, centered around the city of Bakersfield, and in the Long
Beach-Wilmington area. In California, steam, hot water, and
water flooding methods of secondary recovery are used. The total
produced water is approximately 2,044 million barrels per year,
the majority of which is either reinjected for recovery or
disposal or evaporated in ponds. Only eight producers in the
State have discharge to navigable waters.
Cook Inlet, Alaska
Offshore production in Cook Inlet comes from 14 multiple-well
platforms on four oil fields and one gas field. Development took
place in the 1960's and has been relatively static for the past 5
years. The demarcation line between Federal and State waters in
lower Cook Inlet is under litigation. The settlement of this
dispute will probably lead to leasing and development of
additional areas in the Inlet.
Present practice is to separate gas on the platforms, sending the
produced water and oil ashore for separation and treatment. Some
platforms are producing increasing amounts of produced water, and
this, plus the occasional plugging of oil/water pipelines with
ice in the winter, will encourage a change to platform
separation, treatment, and disposal of produced waters.
Cook Inlet platforms are presently employing gas lift and treat
Inlet sea water for water flooding.
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Appalachia - Pennsylvania
Oil was discovered over 100 years ago in Pennsylvania, the
earliest discovery in the United States. Today the State of
Pennsylvania's oil production industry, like the other
Appalachian states, is characterized by marginal production of
0.3 barrles per day per well average for the 31,000 producing
wells in the State, operating on approximately 2,300 leases.
Although the amount of oil production is low (only 0.1% of the
U.S. total), Pennsylvania crudes supply 20% of all U.S. lube oil
production. Small independent operators dominate the industry,
accounting for 65-70* of the production. The oil fields are
located primarily in the northwest section of the State, McKean
County alone accounting for 50* of the State's production. The
oil-bearing strata is shallow (1000-2000 feet) and relatively
impermeable (1-20 millidarcies).
All produced water generated is discharged to the surface
following ripple aeration and separation/sedimentation in earthen
ponds. Where water flooding is practiced, ground water is used
after treatment as the source. There are plans on some of the
larger leases to utilize production water for flooding, despite
earlier failure of this method from plugging of the formation
strata. Current discharge practices are in part justified by the
absence of formations acceptable for reinjection due to
permeability, surface outcroppings, lack of void space and
substandard well abandonment procedures in the past.
Industry Growth
From 1960 to 1970, the Nation's demand for energy increased at an
average rate of 4.3 percent. Table 3 gives the projected
national demands for oil and gas through 1985 and Table H the
U.S. offshore oil production from 1970 through 1973.
U.S. offshore production declined by about 78,500 barrels/day
from 1972 to 1973. Offshore production amounts to approximately
10 percent of U.S. demand and about 15 percent of U.S.
production.
While offshore production declined slightly from 1972 to 1973,
the potential for increasing offshore production is much greater
than for increasing onshore production. The Department of the
Interior has proposed a schedule of three or four lease sales per
year through 1978, mainly on remaining acreage in the Gulf of
Mexico and offshore California. Additional areas in which OCS
lease sales will very probably be held by 1978 include the
Atlantic Coast (George's Bank, Baltimore Canyon, and Georgia
Embayment) and the Gulf of Mexico.
26
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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.
Movement into more distant and isolated environments will mean
even more self-sufficiency of platform operations, with all
production, processing, treatment, and disposal being performed
on the platforms. Movement into deeper waters will necessitate
multiple-well structures, with a maximum number of wells drilled
from a minimum number of platforms.
Offshore leasing, exploration, and development will rapidly
expand over the next 10 years, and offshore production will make
up an increasing proportion of our domestically produced supplies
of gas and oil.
27
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TABLE 3
U.S. Supply and Demand of Petroleum
and Natural Gas (5)
1971 1980 1985
Petroleum (million barrels/day)
Projected Demand
% of Total U.S. Energy Demand
Projected Domestic Supply
% petroleum demand fulfilled
by domestic supply
Natural Gas (trillion cubic feet/year)
Projected Demand
% of Total U.S. Energy Demand
Projected Domestic Supply
% gas demand fulfilled
by domestic supply
15. 1
44.1
11.3
74.9
22.0
33.0
21.1
96.0
20.8
43.9
11.7
56.3
26.2
28. 1
23.0
87.8
25.0
43.5
11.7
46.7
27.5
24.3
23.8
86.6
TABLE 4
U.S. Offshore Gil Production - (million barrels/day) (6)
1970 1971 1972 1973
1.58 1.69 1.67 1.59
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SECTION III
Bibliography
1. University of Texas-Austin/ Petroleum Extension Service, and
Texas Education Agency, Trade and Industrial Serivce. 1962.
"Treating Oil Field Emulsions." 2nd. ed. rev.
2. Gidley, J.L. and Hanson, H.R. 1974. "Central-Terminal Upset
from Well Treatment is Prevented." Oil and Gas Journal, Vol.
72: No. 6: pp. 53-56.
3. Independent Petroleum Association of America. "United States
Petroleum Statistics 2974 (Revised)." Washington, D.C.
4. U.S. Department of the Interior, Geological Survey. 1973.
Draft Environment Impact Statement. Vol. 1: Proposed Plan
of Development Santa Ynez Unit, Santa Barbara Channel, Off
California." Washington, DC
5. Dupree, W.G., and West, J.A. 1972. "United States Energy
Through the Year 2000." U.S. Department of Interior.
Washington, D.C.
6. McCaslin, John C. 1974. "Offshore Oil Production Soars."
Oil and Gas Journal, Vol. 72: No. 18: pp. 136-142.
29
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SECTION IV
INDUSTRY SUBCATEGORIZATION
Rationale For Subcategorization
The Standard Industrial Classification's subcategorize industry
into various groups for the purpose of analyzing production,
employment, and economic factors which are not necessarily
related to the type of wastes generated by the industry. In
development of the effluent limitations and standards, production
methodology, waste characteristics, and other factors were
analyzed to determine if separate limitations need to be
designated for different segments of the industry. The following
factors were examined for delineating different levels of
pollution control technology and possibly subcategorizing the
industry:
1. Type of facility or operation
2. Facility's size, age, and waste volumes
3. Process technology
4. Climate
5. Waste water characteristics
6. Location of facility
Field surveys, waste treatment technology, and effluent data
indicate that the most important factors are the type of
facility, the facility's size, age, waste water volume, waste
water characteristics, and location. The factor of climate is
significant with respect to operational practices but has less
influence on waste treatment technology. Process technology was
found to have very little influence on the selection of pollution
control technology.
An evaluation of industry's production units (barrels of oil per
day or thousands of cubic feet of gas per day) and waste volumes
indicated no relationship between them. Produced water
production may vary from less than 1 to 90 percent of the
production fluids. High volumes of produced waters are
associated with older production fields and recovery methods used
to extract crude oil from partially depleted formations.
Similarly, the amount of waste generated during drilling
operations is dependent upon the depth of the well, subsurface
characteristics, recovery of drill muds, and recycling.
Therefore, industry subcategorization could not include an
analysis of segmenting the industry on waste load per unit of
production.
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Development of Subcategories
Based upon the type of facility, the industry may be subdivided
into three major categories with similar type operations or
activities: 1) crude petroleum and natural gas production; 2)
oil and gas well field exploration and drilling; and 3) oil and
gas well completions and workover. Further subdivision can be
made within each to reflect location - offshore and onshore - and
any wastes requiring specific effluent limitations and standards.
Since sanitary wastes for onshore operations normally don't
result in a discharge and since deck drainage is not applicable
to onshore operations, these subcategories are only applicable to
offshore facilities. Therefore, considering location and wastes,
the major groups are subcategorized as follows:
I Crude Petroleum and Natural Gas Production
A. Produced Water
B. Deck Drainage
C. Sanitary and Domestic Waste
II Oil and Gas Well field Exploration and Drilling
A. Drilling Muds
B. Drill Cuttings
C. Sanitary and Domestic Waste
III Oil and Gas Well Completions and Workover
A. Chemical Treatment of Wells
B. Production Sands
Facility's Size, Age and Waste Volumes
Offshore facilities in Category I differ little in the type of
process or produced water treatment technology for large, medium,
or small facilities. One of the most significant factors
affecting the size of the facility is the availability of space
for central treatment systems to handle waste from several
platforms or fields. Treatment systems on offshore platforms are
usually limited to meet the needs of the immediate production
facility and are designed for 5,000 to 40,000 barrels/day. In
contrast, onshore treatment systems for offshore production
wastes may be designed to handle 100,000 barrels/day or more.
For small facilities, wastes may require intermediate storage and
a transport system to deliver the produced water to another
facility for treatment and disposal. comparable treatment
technology has been developed for both large and small systems.
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For onshore facilities, the type of produced water treatment
technology does tend to differ according to the size of the
facility but there are notable exceptions. Since for the primary
unit treatment process (the separation of oil and water), ponds
of sufficient size are feasible for smaller facilities while
mechanical systems (such as flotation) are required where larger
amounts of produced water are handled. Smaller facilities are
least likely to have the type cf operating staff required for
sophisticated water treatment systems and are more likely to
receive operating variances from local regulatory authorities.
The types of treatment for sanitary wastes for large and small
offshore facilities are different, as are facilities which are
intermittently manned. For small and intermittently manned
facilities, the waste may be incinerated or chemically treated,
resulting in no discharge. Because of operational problems and
safety considerations, other types of treatment systems that will
result in a discharge are being considered. Thus sanitary wastes
must be sutcategorized based on facility size.
The state of the art and treatment technology for Category I has
been improving over the past several years; the majority of the
facilities regardless of age have installed waste treatment
facilities. However, the age of the production field can impact
the quantity of waste water generated. Many new fields have no
need to treat for a number of years until the formation begins to
produce water. The period before initiating treatment is
variable, depending on the characteristics of the particular
field, and can also be affected by method of recovery. If wastes
are to be treated off shore, the initial design should provide
for the necessary space and energy requirements that will be
needed for the treatment systems to be installed over the
expected life of the platform.
Process Technology
Process technology was reviewed to determine if the existing
equipment and separation systems influenced the characteristics
of the produced waste. Most oil/water process separation units
consist of heater-treaters, electric dehydration units or gravity
separation (free water knockout or gun barrel). The type of
process equipment and its configuration are based in part on the
characteristics of the produced fluids. For example, if the
fluids contain entrained oil in a "tight" emulsion, heat may be
necessary to assist in separating water from the oil. Raw
produced water data showed no significant difference in oil
content between the various process units. When high influent
concentrations to the produced water treatment facilities were
observed they were found to be caused by malfunctions in the
process equipment. It was concluded that there is no basis for
subcategorization because of differences in process systems.
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Climate
Climate was considered because conditions in tiie production
regions differ widely. All regions treat by gravity separation
or chemical/physical methods. These systems are less sensitive
to climatic changes than biological treatment. Sanitary waste
treatment can be affected by extreme temperatures, but in areas
with cold climates, facilities are enclosed, minimizing
temperature variations. The volume or hydraulic loading due to
rainfall may be significant with respect to the offshore Gulf
Coast, but the waste contaminants (residual oils from drips,
leaks, etc.) from deck drainage are independent of rainfall.
Proper operation and maintenance can reduce waste oil
concentrations to minimal levels, thus reducing the effect of
rainfall. Therefore, no sufccategorization is required to account
for climate.
Waste Water Characteristics
Treatability and other characteristics of produced water are one
of the most significant factors considered for subcategorization.
Produced water may be high in dissolved solids (TDS) , oxygen
demanding wastes, heavy metals, and toxics, in addition to the
oil and grease contamination. The current treatment technologies
for produced water are either subsurface disposal or oil removal
prior to discharge. The technology developed for each area of
the country has been primarily influenced by local regulatory
requirements (water quality and individual state or local laws),
but other factors associated with produced water treatability and
cost effectiveness may also have had an effect. (1,2,3)
Factors which may affect produced water treatability are:
1. Physical and chemical properties of the crude oil,
including solubility.
2. Concentration of suspended and settleable solids.
3. Fluctuation of flow rate and production method.
4. Droplet sizes of the entrained oil emulsification.
5. Other characteristics of the produced water.
The impact of these variables can be minimized by existing
process and treatment technology, which include desanders, surge
tanks, and chemical treatment.
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Location of Facility
The location of the facility affects the applicable treatment,
the cost of that treatment, and the makeup of the wastes
produced. The factors that affect the treatment method based on
location are as follows:
1. Availability of space and site conditions, such as, dry
land, marsh area, or open water.
2. Proximity to shore.
3. Type and depth of subsurface formations suitable for
injection of produced water.
4. Surface water availability ( possible agricultural use
of produced water).
5. Evaporation rate at location.
6. Local water quality and statues.
7. Type of receiving water body.
Location is a significant factor specifically with respect to
areas where saline produced water discharges are not permitted.
The usual procedure in inland areas is to reinject the produced
water to the producing formation, where the formation
configuration permits (to assist in oil recovery) , or to other
subsurface formations for disposal only. Evaporation ponds are
used in some inland areas, with the assumption that all produced
waters are evaporated and no discharge occurs. In an arid
Western oil field an evaporation pond, if properly maintained,
may provide for acceptable disposal of the produced waters;
however, in humid areas in the East and South, evaporation ponds
may not be acceptable.
In inland fields where produced waters are sufficiently low in
total solids, discharges have been used for stock watering and
other beneficial uses where the treated produced water is of
sufficient quality to meet the regulations for other
constituents, such as oil and grease.
In the Appalachian area, typified by the northwest portion of
Pennsylvania, discharge of produced water is the rule, not the
exception. Treatment consisting of ripple aeration and
semimentation/separation in ponds achieves a high degree of free
oil removal apparently due to the separability of the crude.
The technology for disposal of drilling muds, cuttings, solids,
and other materials differs depending upon the location. In the
open water offshore areas, the materials, if properly treated,
are normally discharged into the saline waters. Onshore
technology has been developed to ensure no discharge to surface
35
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waters, and waste materials are disposed of in approved land
disposal sites.
Description of Sufccategories
Based upon the above rationale and discussion the oil and gas
extraction industry has been sutcategorized as follows:
Subcategory
Subcategory
A - near offshore (facilities located in
offshore state waters)
1.
2.
3.
a.
5.
6.
7.
8.
B -
1.
2.
3.
4.
5.
6.
produced water
deck drainage
drilling muds
drill cuttings
well treatment
sanitary wastes
a.
M10 continuously manned with 10 or more
people
b.
M9IM - facilities with 9 or
or intermittantly manned.
less people
domestic wastes
produced sand
far offshore (facilities located in
federal waters)
produced water
deck drainage
drilling muds
drill cuttings
well treatment
sanitary wastes
a. Mlu continuously manned with 10 or more
people
36
-------
b. M9IM - facilities with 9 or less people
or intermittantly manned.
7. domestic wastes
8. produced sand
Subcategory C - onshore
1. produced water
2. drilling muds
3. drill cuttings
4. well treatment
5. produced sand
Subcategory D - coastal
1. produced water
2. deck drainage
3. drilling muds
4. drill cuttings
5. well treatment
6. sanitary wastes
a. M10 continuously manned with 10 or more
people
b. M9IM - facilities with 9 or less people
or intermittantly manned.
7. domestic wastes
8. produced sand
Subcategory E - beneficial use
1. produced water
2. drilling muds
3. drill cuttings
U. well treatment
37
-------
5. produced sand
Subcategory F - stripper
1. produced water
2. drilling muds
3. drill cuttings
4. well treatment
5. produced sand
Produced Water
Produced water includes all waters and particulate matter
associated with oil and gas producing formations. Sometimes the
terms "formation water" or "brine water" are used to describe
produced water. Most oil and gas producing geological formations
contain an oil-water or gas-water contact. In some formations,
water is produced with the oil and gas in the early stages of
production. In others, water is not produced until the producing
formation has been significantly depleted and in some cases water
is never produced. (4) The amount of produced water generated is
also dependent on the method of oil recovery. If water injection
is used some of the injected water is recovered by the production
causing higher percentage water cuts.
Deck Drainage
Deck drainage includes all waste resulting from platform
washings, deck washings, and run-off from curbs, gutters, and
drains including drip pans and work areas.
Sanitary Waste
Sanitary waste includes human body waste discharged from toilets
and urinals.
Domestic Waste
Domestic wastes are materials discharged from sinks, showers,
laundries, and galleys.
Drilling Muds
Drilling muds are those materials used to maintain hydrostatic
pressure control in the well, lubricate the drilling bit, remove
drill cuttings from the well, or stabilize the walls of the well
during drilling or workover.
38
-------
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, weighting
agents, and various other components. Oil muds are referred to
as ox! based muds, invert emulsion muds, and oil emulsion muds.
Oil muds are used for special drilling requirements such as
tightly consolidated subsurface formations and water sensitive
clays and shales. (5) (6) (7)
Drill Cuttings
Drill cuttings are particles generated by drilling into
subsurface geologic formations. Erill cuttings are circulated to
the surface of the well with the drilling mud and separated there
from the drilling mud.
Treatment of Wells
Treatment of wells includes acidizing and hydraulic fracturing to
improve oil recovery. Hydraulic fracturing involves the parting
of a desired section of the formation by the application of
hydraulic pressure. Selected particles added to the fracturing
fluid are transported into the fracture, and act as propping
agents to hold the fracture open after the pressure is released.
Chemical treatments of wells consists of pumping acid or
chemicals down the well to remove formation damage and increase
drainage in the permeable rock formations.(8)
Produced Sand
Produced sand or solids for this subcategory consist of particles
used in hydraulic fracturing and accumulated formation sands,
which are generated during production. These sands must be
removed when they build up and block flow of fluids.
39
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SECTION IV
Bibliography
1. Bassett, M.G. 1971. "Wemco Depurator TM System." Paper
presented at the SPE of AIME Rocky Mountain Regional Meeting,
Billings, Montana, June 2-4, 1971. Preprint No. SPE-3349.
2. Boyd, J.L., Shell, G.L., and Dahlstrom, D.A. 1972.
"Treatment of Oily Haste Waters to Meet Regulatory
Standards." AIChE Symposium. Serial NO. 124, pp. 393-401.
3. Ellis, M.M., and Fischer, P.W. 1973. "Clarifying Oil Field
and Refinery Waste Waters by Gas Flotation." Paper presented
at the SPE of AIME Evangeline Section Regional Meeting,
Lafayette, Louisiana, November 9-10, 1970. Preprint No. SPE-
3198.
4. U.S. Department of the Interior, Federal Water Pollution
Control Administration. 1968. Report of the Committee on
Water Quality Criteria.
5. U.S. Department of the Interior, Bureau of Land Management.
1973. Draft Environmental Impact Statement, "Proposed 1973
Outer Continental Shelf Oil and Gas General Lease Sale
Offshore Mississippi, Alabama, and Florida." Washington,
D.C.
6. Hayward, B.S., Williams, R.H., and Methven, N.E. 1971.
"Prevention of Offshore Pollution from Drilling Fluids."
Paper presented at the 46th Annual SPE of AIME Fall Meeting
at New Orleans, Louisiana, October 3-6, 1971. Preprint No.
SPE-3579.
7. Cranfield, J. 1973. "Cuttings Clean-Up Meets Offshore
Pollution Specifications, " Petrol. Petrochem. Int., Vol.,
13: No. 3: pp. 54-56, 59
8. American Petroleum Institute. Division of Production. 1973.
"Primer of Oil and Gas Production." 3rd. ed. Dallas, Texas.
40
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SECTION V
WASTE CHARACTERISTICS
Wastes generated by the oil and gas industry are produced by
drilling exploratory or development wells, by the production or
extraction phase of the industry, and, in the case of offshore
facilities, sanitary wastes generated by personnel occupying the
platforms. Drilling wastes are generally in the form of drill
cuttings and mud, and production wastes are generally produced
water. (1) Additionally, well workover and completion operations
can produce wastes, but they are generally similar to those from
drilling or production operations.
Approximately half a million producing oil wells onshore generate
produced water in excess of 20 million barrel s-per-day of which
it is estimated 50 % is reinjected for recovery purposes.
Approximately 17,000 wells have been drilled offshore in U.S.
waters, and approximately 11,000 are producing oil or gas. The
offshore Louisiana OCS alone produces approximately 410,000
barrels of water per day (2) ; by 1983, coastal Louisiana
production will generate an estimated 1.54 million barrels of
water per day. (3)
This section characterizes the types of wastes that are produced
at offshore and onshore wells and structures. The discussion of
drilling wastes can be applied to any area of the United States
since these wastes do not change significantly with locality.
Other than oils, the primary waste constituents considered are
oxygen demanding pollutants, heavy metals, toxicants, and
dissolved solids contained in drilling muds or produced water.
Sanitary wastes are also produced during both drilling and
production operations both onshore and offshore, but they are
discussed only for offshore situations where sanitary wastes are
produced from fixed platforms or structures. Drilling or
exploratory rigs that are vessels are not part of this
discussion.
Waste Constituents
Production
Production wastes include produced waters associated with the
extracted oil, sand and other solids removed from the produced
waters, deck drainage from the platform surfaces, sanitary
wastes, and domestic wastes.
The produced waters from production platforms generate the
greatest concern. The wastes can contain oils, toxic metals, and
41
-------
a variety of salts, solids and organic chemicals. The
concentrations of the constituents vary somewhat from one
geographical area to another, with the most pronounced variance
in chloride levels. Table 5 shows the waste constituents in
offshore Louisiana production facilities in the Gulf of Mexico.
The data were obtained during the verification survey conducted
by EPA in 1974. The only influent data obtained in the survey
were on oil and grease. In planning the verification survey, it
was decided that offshore produced water treatment facilities
would have virtually no effect on metals and salinity levels in
the influent, and that these constituents could be satisfactorily
characterized by analyzing only the effluent.
Total organic carbon (TOC) is also tabulated under effluent in
Table 5, but it is reasonable to assume that actual analysis of
the influent would be higher. Since TOC is a measurement of all
organic carbon in the sample and oil is a major source of organic
carbon, it is logical to assume removal of some organic carbon
when oil is removed in the treatment process. Suspended solids
are also expressed as effluent data, and this parameter would be
expected to be reduced by the treatment process.
TABLE 5
Pollutants in Produced Water
Louisiana Coastal (a)
Pollutant Parameter Range mq/1
Oil and Grease
Cadmium
Cyanide
Mercury
Total Organic Carbon
Total suspended solids
Total dissolved solids
Chlorides
7 -
<0.005 -
<0.01 -
30 -
22 -
32,000 -
10,000 -
1300
.675
0.01
1580
390
202,000
115,000
Average mq/1
202
<0.068
<0.01
<0.0005
413
73
110,000
61,000
Flow (bbl/day)
250 - 200,000
15,000
(a) - results of 1974 EPA survey of 25 discharges
< - less than
42
-------
Industry data for offshore California describes a broader range
of parameters (see Table 6). Similar data were provided for
offshore Texas (see Table 7). Except as noted on the tables, all
data are from effluents.
Sand and other solids are produced along with the produced water.
Observations made by EPA personnel during field surveys indicated
that drums of these sands stored on the platform had a high oil
content. Sand has been reported to be produced at approximately
1 barrel sand per 2,000 barrels oil.(5,6)
-------
TABLE 6
Pollutants Contained in Produced Water
Coastal Calif ornia (a) (7)
Pollutant
Parameter
Arsenic
Cadmium
Total Chromium
Copper
Lead
Mercury
Nickel
Silver
Zinc
Range, mq/1
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
Cyanide
Phenolic Compounds 0.35 - 2.10
BOD
COD
Chlorides
TDS
Suspended Solids
Effluent
Influent
Oil and Grease
370 - 1,920
400 - 3,000
17,230 - 21,000
21,700 - 40,400
1 - 60
30 - 75
56 - 359
(a)Some data reflect treated waters for reinjection.
44
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TABLE 7
Range of constituents in Produced
Formation Water—Offshore Texas(8)
Pollutant Parameter Range, mg/1
Arsenic <0.01 - <0.02
Cadmium <0.02 - 0.193
Total Chromium
-------
As part of a recent EPA study (1976) to collect information on
treatment technologies and costs, surveys were made of onshore
production facilities in California, Wyoming, Texas, Louisiana
and Pennsylvania. The data represented in tables 8-12 is from
the effluent of the treatment facilities prior to reinjection for
secondary recovery or disposal. It could be expected that the
quality of the untreated produced water from the production
separator would range from 200-1000 mg/1 oil and grease and 100-
400 mg/1 suspended solids. The remainder of the analyzed
constituents such as TDS, phenols and heavy metals would be
unaffected by treatment.
The analytical methods used were from "Standard Methods for Waste
and Wastewater" 13th edition (16) with the exception of the
procedure for oil and grease. Prior to the utilization of the
freon extraction method for oil and grease, the samples were
screened for organic acids and if they were present in quantities
greater than 100 mg/1 the sample was not acidified. Therefore,
the results for oil and grease as reported in tables 8-12,
particularly in California where organic acids are known to be a
part of the crude oil, are not comparable to data in other parts
of this report and are shown only for information.
TABLE 8
Range of Constituents in Produced
Formation Water—Onshore California
Pollutant Parameter Range, mq/1 Median, mg/1
Oil and Grease 16-191 75
Suspended Solids 3-51 31
Total Dissolved Solids 580-27,300 6,300
Phenol 0.07-0.15 0.11
Arsenic <0.01-0.03 0.11
Chromium <0.01 <0.01
Cadmium <0.005-0.02 <0.005
Lead <0.05 <0.05
Barium <0.2-0.4 0.3
< = less than
46
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TABLE 9
Range of Constituents in Produced
Formation Water—Wyoming
Pollutant Parameter
Oil and Grease
Suspended Solids
Total Dissolved Solids
Phenol
Arsenic
Chromium
Cadmium
Lead
Barium
< = less than
Range, mq/1
1.5-205
<1-64
345-90,400
0.07-0.33
<0.01-0.06
<0.01
<0.005-0.023
<0.05-0.08
<0.2-9.7
Median, mq/1
67
12.8
13,800
0.16
0.01
<0.01
<0.005
<0.05
0.9
TABLE 10
Range of Constituents in Produced
Formation Water—Pennsylvania
Pollutant Parameter
Oil and Grease
Suspended Solids
Total Dissolved Solids
Phenol
Arsenic
Chromium
Cadmium
Lead
Barium
< = less than
Range,mg/1
<0.2-114
1.4-666
1500-109,400
0.06-0.35
<0.01
<0.01-0.025
<0.005-0.013
<0.05-0.50
0.1-36
Median, mg/1
25
107
29,000
0.19
<0.01
<0.01
<0.005
<0.05
8.6
47
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TABLE 11
Range of Constituents in Produced
Formation Water—Onshore Louisiana
Pollutant Parameter
Oil and Grease
Suspended Solids
Total Dissolved Solids
Range, mg/1
16-441
20.8-155
42,600-132,000
Median, mg/1
165
82
73,900
TABLE 12
Range of Constituents in Produced
Formation Water—Onshore Texas
Pollutant Parameter
Oil and Grease
Suspended Solids
Total Dissolved Solids
Range mq/1
57-1,200
30-473
42,600-132,000
Median, mg/1
460
143
94,000
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
48
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control, corrosion inhibition, lubrication, weighting, and
emulsification.
The additives that should be scrutinized for pollution control
are ferrochrome lignosulfonate and lead compounds.(14)
Ferrochrome lignosulfonate contains 2.6 percent iron, 5.5 percent
sulfur, and 3.0 percent chromium. In an example presented by the
Bureau of Land Management in an Environmental Impact Statement
for offshore development, the drilling operation of a typical
10,000-foot development well (not exploratory) used 32,900 pounds
of ferrochrome lignosulfonate mud which contained 987 pounds of
chromium.(2) Table 13 presents the volumes of cuttings and muds
used in the Bureau's example of a "typical" 10,000-foot drilling
operation. The amount of lead additives used in mud composition
varies from well to well, and no examples are available.
Drilling constituents for onshore operations will parallel those
for offshore, except for the water used in the typical mud
formulation. Onshore drilling operations normally use a fresh
water based mud, except where drilling operations encounter large
salt domes. Then the mud system would be converted either to a
salt clay mud system with salt added to the water phase, or to an
oil based mud system. This change in the liquid phase is
intended to prevent dissolving 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 turbidity. Limited information is
available to accurately define the degree of turbidity, or the
area or volume of water affected ty such turbid discharges, but
experienced observers have described the existence of substantial
plumes of turbidity when muds and cuttings are discharged.
Oil-based muds contain carefully formulated mixtures of oxidized
asphalt, organic acids, alkali, stabilizing agents and high-flash
diesel oil. (14,15) The oils are the principal ingredients and so
are the liquid phase. Muds displaced from the well hole also
contain solids from the hole. There are two types of emulsified
oil muds: 1) oil emulsion muds, which are oil-in-water emulsions;
and 2) inverted emulsion muds, which are water-in-oil emulsions.
The principal differences between these two muds and oil based
muds is the addition of fresh or salt water into the mud mixture
to provide some of the volume for the liquid phase. Newer
formulations can contain from 20 to 70 percent water by volume.
The water is added by adding emulsifying and stabilizing agents.
Clay solids and weighting agents can also be added.
-------
Sanitary and Domestic Waste
The sanitary wastes from offshore oil and gas facilities are
composed of human body waste and domestic waste such as kitchen
and general housekeeping wastes. The volume and concentration of
these wastes vary widely with time, occupancy, platform
characteristics, and operational situation. Usually the toilets
are flushed with brackish water or sea water. Due to the compact
nature of the facilities the wastes have less dilution water than
common municipal wastes. This results in greater waste
concentrations. Table 14 indicates typical waste flow for
offshore facilities and vessels.
50
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Table 13
Volume of Cuttings and Muds in Typical
10,000-Foot Drilling Operation (2)
Interval,
Feet
0-1,000
1,000-3,500
3,500-10,000
Hole
Size,
inches
24
16
12
Vol. of
Cuttings,
bbl.
562
623
915
Wt. of
Cuttings,
pounds
505,000
545,000
790,000
Drilling
mud
sea water
& natural
mud
Gelled sea
water
Lime base
Vol of
Mud com-
ponents ,
bbl
variable
700
950
Wt. of
Mud com-
ponents
pounds
81,500
424,000
-------
IP
K)
Table 14
Typical Raw Combined Sanitary and Domestic
Wastes from Offshore Facilities
BOD, mg/1 Suspended
No. of
Men
76
A9
Flow 5
gal/day Average Range
5,500 460 270-770
9 i cc 77 c
7 OHO Q9H
Solids, mg/1
Average Range
195 14-543
1 r\9c — —
con
99CI — —
Total
Coliform
(X 10)
10-180
Reference
(10)
fT\\
-------
SECTION V
Bibliography
1. Biglane, K.E. 1958. "Some Current Waste Treatment Practices
in Louisiana Industry." Paper presented at the 13th Annual
Industrial Waste Conference, Purdue University, Lafayette,
Indiana.
2. U.S. Department of the Interior. Bureau of Land Management.
Draft Environmental Impact Statement. "Proposed 1973 Outer
Continental Shelf Oil and Gas General Lease Sale Offshore
Mississippi, Alabama, Florida." Washington, D.C.
3. Offshore Operators Committee, Sheen Technical Subcommittee.
1974. "Determination of Best Practicable Control Technology
Currently Available to Remove Oil from Water Produced with
Oil and Gas." Prepared by Brown and Root, Inc., Houston,
Texas.
4. Moseley, F.N., and Copeland, E.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
AIML Fall Meeting, San Antonio, Texas, October 8-11, 1972.
Preprint No. SFE-4015.
6. Frankenberg, W.G., and Allred, J.H. 1969. "Design,
Installation, and Operation of a Large Offshore Production
Complex;" and Bleakley, W.G., "Shell Production Complex
Efficient, Controls, Pollution—. "Oil and Gas Journal, Vol.
67:No. 36: pp. 65-69.
7. Western Oil and Gas Association and the Water Quality Board,
State of California.
8. Offshore Operators committee.
9. Crawford, J.G. 1964. "Rocky Mountain Oil Field Waters."
Chemical and Geological Laboratories, Casper, Wyoming.
10. Sacks, Bernard R. 1969. "Extended Aeriation Sewage
Treatment on U.S. Corps of Engineers Dredges." U.S.
Department of the Interior, Federal Water Pollution Control
Administration.
53
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11. Amoco Production Company. 1974. "Draft Comments Regarding
Rationale and Guideline Proposals for Treatment of Sanitary
Wastes from offshore Production Platforms."
12. Humble Oil and Refining Company. 1970. "Report on the Human
Waste on Humble Oil and Refining Company's Offshore Platforms
with Living Quarters in the Gulf of Mexico." Prepared by
Waldermar S. Nelson Company, Engineers and Architects, New
Orleans, Louisiana.
13. Hayward, B.S., Williams, R.H., and 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."
54
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SECTION VI
SELECTION OF POLLUTANT PARAMETERS
Oil and grease from produced water, deck drainage, muds,
cuttings, and produced sands and solids, and residual chlorine
(as an indicator of fecal coliform) and floating solids from
sanitary and domestic sources have been selected as the
pollutants for which effluent limitations will be established.
The rationale for inclusion of these parameters are discussed
below.
Parameters for Effluent Limitations
Freon Extractables - Oil and Grease
No solvent is known which will directly dissolve only oil or
grease, thus the manual "Metnods for the Chemical Analysis of
Water and Wastes 1974" distributed by the Environmental
Protection Agency states that their method for oil and grease
determinations includes the freon extractable matter from waters.
In the oil and gas extraction industry, oils, greases, organic
acids, various other hydrocarbons and some inorganic compounds,
such as sulfur, will be included in the freon extraction
procedures. The majority of material removed by the procedure
from a produced water will, in most instances, be of a
hydrocarbon nature. These hydrocarbons, predominately oil and
grease type compounds, will make their presence felt in the COD,
TOC, TOD, and usually the BOD tests where high test values will
result. The oxygen demand potential of these freon extractables
is only one of the detrimental effects exerted on water bodies by
this class of compounds. Oil emulsions may adhere to the gills
of fish or coat and destroy algae or other plankton. Depostion
of oil in the bottom sediments can serve to inhibit normal
benthic growths, thus interrupting the aquatic food chain.
Soluble and emulsified materials ingested by fish may taint the
flavor of the fisxi flesh. Water soluble components may exert
toxic action on fish. The water insoluble hydrocarbons and free
floating emulsified oils in a waste water will affect stream
ecology by interfering with oxygen transfer, by damaging the
plumage and coats of water animals and fowls, and by contributing
taste and toxicity problems. The effect of oil spills upon boats
and shorelines and their production of oil slicks and
iridenscence upon the surface of waters is well known.
Fecal Coliform (Chlorine Residual)
The concentration of fecal coliform bacteria can serve as an
indication of the potential pathogencity of water resulting from
the disposal of human wastes. Fecal coliform levels have been
55
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established to protect beneficial water use (recreation and
shellfish propagation) in the coastal areas.
The most direct method to determine compliance with specified
limits is to measure the fecal coliform levels in the effluent
for a period representing a normal cycle of operations. This
approach may be applicable to onshore installations; however, for
offshore operations the logistics become complex, and simplified
methods are desirable.
However, the presence of specific levels of suspended solids and
chlorine residual in an effluent are indicative of corresponding
levels of fecal coliforms. In general if suspended solids levels
in the effluent are less than 150 mg/1 and the chlorine residual
is maintained at 1.0 mg/1, the fecal coliform level should be
less than 200 per 100 ml. Properly operating biological
treatment systems on offshore platforms have effluents containing
less than 150 mg/1 of suspended solids; therefore, chlorine
residual is a reasonable control parameter.
It may be considered desirable, however, that a study of each
sanitary treatment system be made at least once a year to measure
influent and effluent biochemical oxygen demand, suspended
solids, and fecal coliform. The purpose of the survey is to
determine the treatment efficiencies, to evaluate operating
procedures, and to adjust the system to obtain maximum treatment
efficiencies and minimize chlorine usage.
Floating Solids
Marine waters should be capable of supporting indigenous life
forms and should be free of substances attributable to discharges
or wastes which will settle float on the water, and produce
objectionable odors. Floating solids have been selected as a
control parameters for domestic wastes and sanitary wastes from
small or intermittently manned offshore facilities.
Other Pollutants
Some produced formation waters are known to contain heavy metals,
toxic substances, constituents with substantial oxygen demand,
and inorganic salts. Insufficient data exist to warrant
comprehensive control of these parameters and there is no
discharge technology now in use by the industry to remove these
pollutants, although some concomitant reduction in oxygen
demanding constituents may take place as a result of treatment
not specifically designed for their removal.
56
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Heavy Metals
Produced waters have been shown to contain cyanide cadmium, and
mercury. Section 307 (a) (1) of the Federal Water Pollution
Control Act Amendments of 1972 requires a list of toxic
pollutants and effluent standards or prohibitions for these
substances. The proposed effluent standards for toxic pollutants
state that there shall be no discharge of cyanide, cadmium, or
mercury into streams, lakes or estuaries with a low flow less
than or equal to 0.283 cubic meters per second (M3/sec) (10 cubic
feet per second) or into lakes with an area less than or equal to
200 hectares (500 acres). Many estuarine areas fall into this
category.
The harmful effects of these toxicants, which include direct
toxicity to humans and other animals, biological concentration,
sterility, mutagenicity, teratogenicity, and other lethal and
sublethal effects, have been well documented in the development
of the Section 307 (a) (1) proposed regulations.
Produced formation waters have also been shown to contain
arsenic, chromium, copper, lead, nickel, silver, and zinc as
pollutants. According to McKee and Wolfe (6), arsenic is toxic
to aquatic life in concentrations as low as 1 mg/1. The toxicity
of chromium is very much dependent upon environmental factors and
has been shown to be as low as 0.016 mg/1 for aquatic organisms.
Copper is toxic to aquatic organisms in concentrations of less
than 1 mg/1 and is concentrated by plankton from their habitat by
factors of 1,000 to 5,000 or more. Lead has been shown to be
toxic to fish in concentrations as low as 0.1 mg/1, nickel at a
concentration of 0.8 mg/1, and silver at a concentration of
0.0005 mg/1. Zinc was shown to be toxic to trout eggs and larvae
at a concentration of 0.01 mg/1.
TDS
Dissolved solids in produced waters consist mainly of carbonates,
chlorides, and sulfates. U.S. Public Health Service Drinking
Waters Standards for total dissolved solids are set at 500 mg/1
on the basis of taste thresholds. Many communities in the United
States use water containing from 2,000 to 4,000 mg/1 of dissolved
solids. Such waters are not palatable and may have a laxative
effect on certain people. However, the geographic location and
availability of potable water will dictate acceptable standards.
The following is a summary of a literature survey indicating the
levels of dissolved solids which should not interfere with the
indicated beneficial use:
57
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Domestic Water Supply 1,000 mg/1
Irrigation 700 mg/1
Livestock Watering 2,500 mg/1
Freshwater Fish and Aquatic 2,000 mg/1
Life
Estuaries are typically bilaminar systems, stratified to some
degree, with each layer dependent upon the other for cycling of
minerals, gases, and energy. The upper, low salinity, euphotic
zone supports production of organic materials from sunlight and
CO2; it also produces oxygen in excess of respiration so that
this upper layer is characteristically supersaturated with 02
during the daylight hours. The bottom higher salinity layer
functions as the catabolic side of the cycle, (microbial
breakdown of organic material with subsequent O2 utilization and
CO2 production). In a healthy estuarine system, these two layers
are in precarious synchrony, and the alteration of density,
minerals, gases, or organic material is capable of causing an
imbalance in the system.
Apparently due to the stresses resulting from salinity shocks,
anamalous ion ratios, strong buffer systems, high pH, and low
oxygen solubility, few organisms are capable of adapting to
brine-dominated systems. This results in low diversity of
species, short food chains, and depressed trophic levels. (7)
Chlorides
Chloride ion is one of the major anions found in water and
produces a salty taste at a concentration of about 250 mg/1.
Concentrations of 1000 mg/1 may te undetectable in waters which
contain appreciable amounts of calcium and magnesium ions.
Some produced water associated with naturally occurring
subsurface hydrocarbons may contain extremely high amounts of
sodium chloride. These "so-called" connate brines developed
because the particular geologic formation has not allowed the
entrance of surface water for dilution. In the mid-continent
region where these brines are found, they average 174,000 mg/1 of
dissolved solids.
The toxicity of chloride salts will depend upon the metal with
which they are combined. Because of the rather high
concentration of the anion necessary to initiate detrimental
biological effects, the limit set upon the concentration of the
metallic ion with which it may be tied, will automatically govern
its concentration in effluents, in practically all forms except
potassium, calcium, magnesium, and sodium.
Since sodium is by far the most common (sodium 75 percent,
magnesium 15 percent and calcium 10 percent) the concentration of
58
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this salt will probably govern the amount of chlorides in waste
streams.
It is extremely difficult to pinpoint the exact amount of sodium
chloride salt necessary to result in toxicity in waters. Large
concentrations have been proven toxic to sheep, swine, cattle,
and poultry.
In swine fed diets of swill containing 1.5 to 2.OX salt by
weight, poisoning symptoms can be induced if water intake is
limited and other factors are met. The time interval necessary
to accomplish this is still about one full day of feeding at this
level.
Problems of corrosion, taste, and quality of water necessary for
industrial or agricultural purposes occur at sodium chloride
concentration levels below those at which toxic effects are
experienced.
Oxygen Demand Parameters
Dissolved oxygen (DO) is a water quality constituent that, in
appropriate concentrations, is essential not only to keep
organisms living but also to sustain species reproduction, vigor,
and the development of populations. Organisms undergo stress at
reduced DO concentrations that make them less competitive and
able to sustain their species within the aquatic environment.
For example, reduced DO concentrations have been shown to
interfere with fish population through delayed hatching of eggs,
reduced size and vigor of embryos, production of deformities in
young, interference with food digestion, acceleration of blood
clotting, decreased tolerance to certain toxicants, reduced food
efficiency and growth rate, and reduced maximum sustained
swimming speed. Fish food organisms are likewise affected
adversely in conditions with suppressed DO. Since all aerobic
aquatic organisms need a certain amount of oxygen, the
consequences of total lack of dissolved oxygen due to a high BOD
can kill all inhabitants of the affected area.
Two oxygen demand parameters are discussed below: BODS, and TOC.
Almost without exception, waste waters from oil and gas
extraction exert a significant and sometimes major oxygen demand.
The primary sources are soluble biodegradable hydrocarbons and
inorganic sulfur compounds.
Biochemical Oxygen Demand (BOD)
Biochemical oxygen demand is a measure of the oxygen consuming
capabilities of organic matter. The BOD does not in itself cause
direct harm to a water system, but it does exert an indirect
effect by depressing the oxygen content of the water. Sewage and
59
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other organic effluents during their processes of decomposition
exert a BOD, which can have a catastrophic effect on the
ecosystem ty depleting the oxygen supply. Conditions are reached
frequently where all of the oxygen is used and the continuing
decay process causes the production of noxious gases such as
hydrogen sulfide and methane. Water with a high BOD indicates
the presence of decomposing organic matter and subsequent high
bacterial counts that degrade its quality and potential uses.
If a high BOE is present, the quality of the water is usually
visually degraded by the presence of decomposing materials and
algae blooms due to the uptake of degraded materials that form
the foodstuffs of the algal populations.
Total Organic Carbon (TOC)
Total organic carbon is a measure of the amount of carbon in the
organic material in a wastewater sample. The TOC analyzer
withdraws a small volume of sample and thermally oxidizes it at
150°C. The water vapor and carbon dioxides from the combustion
chamber (where the water vapor is removed) is condensed and sent
to an infrared analyzer, where the carbon dioxide is monitored.
This carbon dioxide value corresponds to the total inorganic
value. Another portion of the same sample is thermally oxidized
at 950°C, which converts all the carbonaceous material to carbon
dioxide; this carbon dioxide value corresponds to the total
carbon value. TOC is determined by subtracting the inorganic
carbon (carbonates and water vapor) from the total carbon value.
The recently developed automated carbon analyzer has provided
rapid and simple means of determining organic carbon levels in
waste water samples, enhancing the popularity of TOC as a
fundamental measure of pollution. The organic carbon
determination is free of many of the variables which plaque the
BOD analyses, yielding more reliable and reproducible data.
Phenolic Compounds
Many phenolic compounds are more toxic than pure phenol; their
toxicity varies with the combinations and general nature of total
wastes. The effect of combinations of different phenolic
compounds is cumulative.
Phenols and phenolic compounds are both acutely and chronically
toxic to fish and other aquatic animals. Also, chlorophenols
produce an unpleasant taste in fish flesh that destroys their
recreational and commercial value.
It is necessary to limit phenolic compounds in raw water used for
drinking water supplies, as conventional treatment methods used
by water supply facilities do not remove phenols. The ingestion
60
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of concentrated solutions of phenols will result in severe pain,
renal irritation, shock and possibly death.
Phenols also reduce the utility of water for certain industrial
uses, notably food and beverage processing, where it creates
unpleasant tastes and odors in the product.
As seen from the above discussion on the potential harm from
produced water discharges, the effects of toxicants, high
salinity, low dissolved oxygen, and high organic matter can
combine to produce an ecological enigma.
The State of California, recognizing the potential impact of
industrial wastes in the coastal areas, has adopted effluent
limitations for ocean waters under its jurisdiction (see Table
15. 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 oil and gas
extraction industry has developed a no discharge technology
(reinjection of production water).
61
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TABLE 15
Effluent Quality Requirements for
Ocean Waters of California
Concentration not to be
exceeded more than;
Unit of
measurement
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
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
10X 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
Arsenic
Cadmium
Total Chromium
Copper
Lead
Mercury
Nickel
Silver
Zinc
Cyanide
Phenolic Compounds
Total Chlorine
Residual
Ammoni a(expr esse d
as nitrogen)
Total Identifiable
Chlorinated Hydro-
carbons mg/1 0.002 0.004
Toxicity Concen-
tration tu 1.5 2.0
Radioactivity not to exceed the limits specified in Title 17,
Chapter 5r Subchapter 4, Group 3, Article 5, Section 30285 and
30287 of the California Administrative Code.
62
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SECTION VI
Bibliography
1. Great Lakes Hater Quality Agreement, April 1972.
2. Federal Water Pollution Control Act Amendments of 1972,
Section 311 (b) (3). 40 CFR 1110.
3. California State Water Resources Control Board. 1972.
"Water Quality Control Plan. Ocean Water of California."
4. Adams, J.K. 1974. "The Relative Effects of Light and Heavy
Oils." U.S. Environmental Protection Agency, Division of Oil
and Special Materials Control, Washington, D.C. Pub. No.
EPA-520/9-74-021.
5. Evans, D.R., and Rice, S.D. 1974. "Effects of Oil and
Marine Ecosystems: A Review for Administrators and Policy
Makers." U.S. Department of the Interior, Bulletin 72(3):pp.
625-638.
6. McKee, J.E., and Wolf, H.W. 1963. "Water Quality Criteria."
California State Water Quality Control Board. Pub. No. 3-A.
7. Moseley, F.N., and Copeland, B.J. 1974. "Brine Pollution
System." In: "Coastal Ecology Systems of the United
States." Oduon, Copeland, and McMahan, (ed) . The Conservation
Foundation, Washington, D.C.
63
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SECTION VII
CONTROL AND TREATAiENT TECHNOLOGY
Petroleum production, drilling, and exploration wastes vary in
quantity and quality from facility to facility. A wide range of
control and treatment technologies has been developed to treat
these wastes. The results of industry surveys indicate that
techniques for in-process controls and end-of-pipe treatment are
generally similar for each of the industry subcategories;
however, local factors, discharge criteria, availability of
space, and other factors influence the method of treatment.
In-plant control/Treatment Techniques
In-plant control or treatment techniques are those practices
which result in: 1) reduction or elimination of a waste stream;
or 2) a change in the character of the constituents and allow the
end-of-pipe processes to be more efficient and cost effective.
Reduction or Elimination of Waste Streams
The two types of in-plant techniques that reduce the waste load
to the treatment system or to the environment are reuse and
recycle of waste products. Examples of reuse are: 1) reinjection
of produced water to increase reservoir pressures; and 2)
utilization of treated production water (softened, if necessary)
for steam generation. An example of a recycle system is the
conservation and reuse of drilling muds.
Waste Character Change
Examples of character change in waste stream would be: 1) the
substitution of a positive displacement pump for a high speed
centrifugal pump; and 2) substitution of a downhole choke for a
well head choke, thereby reducing the amount of emulsion created.
(1)
Proper pretreatment and maintenance practices are also effective
in reducing waste flows and improving treatment efficiencies.
Return of deck drainage to the process units and elimination of
waste crankcase oil from the deck drainage or produced water
treatment systems are examples of good offshore pretreatment and
maintenance practices.
Process Technology
The single most significant change in process technology is
reinjection to the reservoir formation for secondary recovery and
pressure maintenance. This is distinguished from injection for
disposal purposes only, which is considered as end-of-pipe
treatment. Waters used for secondary recovery and pressure
65
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maintenance should toe free of suspended solids, bacterial slimes,
oxygen, sludges, and precipitates. In some cases the quantity of
produced water is insufficient to provide the needed water for a
secondary recovery and pressure maintenance system. In this
case, additional make-up water must be found, and wells or
surface water (including sea water) may be used as a source of
make-up water. There may be problems of compatability between
produced water and make-up water. A typical reinjection water
treatment facility consists of a surge tank, flotation cell,
filters, retention tank, and injection pumps. (2)
Reinjection of produced water for secondary recovery and pressure
maintenance is a very common practice onshore. It has been
estimated that 60 percent of all onshore produced water is
reinjected for secondary recovery.
Produced water treatment for reinjection is similar, both
offshore and onshore. Existing reinjection systems vary from
small units which treat less than 100 barrels per day of brine
waste to large complexes which handle over 170,000 barrels per
day. Produced water reinjection systems for presure maintenance
and water flooding are less common in the Gulf Coast, and none
are in use in Cook Inlet, Alaska (Cook Inlet water is treated and
injected for water flooding, because of compatibility problems
with the produced water),
Produced water treatment and reinjection systems are not
generally limited by space availability but must be specifically
designed to fit offshore platforms. Two limiting factors which
affect produced water reinjection are insuffiecint quantities of
produced water to meet the requirement for reservoir pressure
maintenance and incompatibility between make-up sea water and
produced water.
With the increasing oil demand, new ("tertiary") methods are
being developed to recover greater amounts of oil from producing
formations. The addition of steam or other fluids into the
formation can improve ultimate recovery. A system which reuses
produced water for steam generation is operating on the West
Coast. The system consists of a typical reinjection treatment
unit with water softeners added to the system.
Changes in process technology have also occurred in drilling
operations. Environmental considerations and high cost of
drilling muds have led to the development of special equipment
and procedures to recycle and recondition both water based and
oil based muds. With the system operating properly, mud losses
are limited to deck splatter and the mud clinging to drill
cuttings.
66
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Pretreatment
The main pretreatment process which is applicable to offshore
production systems is the return of deck drainage to the
production process units to remove free oil prior to end-of-pipe
treatment. This method of pretreatment is not applicable to
facilities that flush drilling muds into the deck drainage system
during rig wash down or to facilities that pipe all produced
crude oil and water to shore for processing and brine treatment.
Operation and Maintenance
A key in-plant control is good operation and maintenance
practices. Not only do they reduce waste flows and improve
treatment efficiencies, but they also reduce the frequency and
magnitude of systems upsets.
Some examples of good offshore operations are:
1. Separation of waste crankcase oils from deck drainage
collection system.
2. Reduction of waste water treatment system upset from
deck washdown by discriminant use of detergents.
3. Reduction of oil spillage through good prevention
techniques such as drip pans and other collection
methods.
4. Elimination of oil drainage from transfer pump bearings
or seals by pumping into the crude oil processing
system.
5. Reduction of oil gathered in the pig (pipeline scraper)
traps by channeling oil back into the gathering line
system instead of the sump system.
6. Elimination of extreme loading of the produced water
treatment system, when the process system malfunctions,
by redirecting all production to shore for treatment.
(3)
Good maintenance practice includes: 1) inspection of dump valves
for sand cutting as a preventive measure; 2) use of dual sump
pumps for pumping drainage into surge tanks; 3) use of reliable
chemical injection pumps for produced water treatment; 4)
selection of the best combination of oil and water treating
chemicals; and 5) use of level alarms for initiating shut down
during major system upsets. Operation and maintenance of a
produced water treatment system during start-up presents special
problems. As an example, an offshore facility had two problems
67
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with the heater-treaters that caused problems with the water
treatment system: 1) insufficient heat in the treaters; and 2)
malfunctioning level controls which caused excessive oil loading.
A change in the type of level controls and reduced production
which lowered the heating requirements and helped alleviate the
problem during start-up of the produced water treatment unit.
Further improvements were achieved by careful selection of
chemicals for treating oil and produced water, and the chemical
injection and recylcing pumps were replaced.
The preceding paragraph describes an actual case where detailed
failure analysis and corrective action ended an upset in the
waste treatment system. Evaluation of operational practices,
process and treatment equipment and correct chemical use is
imperative for proper operation and in the prevention and
detection of failures and upsets. The description of these
operation and maintenance practices is not intended to advocate
their universal application. Nevertheless, good operations and
maintenance on an oil/gas production facility can have a
substantial impact on the loads discharged to the waste treatment
system and the efficiency of the system. Careful planning, good
engineering, and a committment on the part of operating and
management personnel are needed to ensure that the full benefits
of good operation and maintenance are realized.
Analytical Techniques and Field Verification Studies
Data on the types of treatment equipment and performance of the
systems in this report were provided by the industry. An early
analysis of data indicated a need to both verify the information
and determine current waste handling practices. EPA conducted a
3-week sampling verification study for facilities, off the
Louisiana Coast; and 3-day studies were conducted in Texas and
California to verify performance data. In addition, three field
surveys were made to determine the adequacy of laboratory
analytical techniques, sample collection procedures, operation
and maintenance procedures, and general practices for handling
deck drainage. Similar field surveys were made of facilities
located in Cook Inlet.
Performance verification studies were also conducted to identify
the most efficient onshore facilities and to determine
geographical and process differences based on crude oil residual
separability and various produced water treatment processes.
Variance in Analytical Results for Oil and Grease concentrations
Effluent oil and grease values in produced water recorded and
reported by the oil and gas industry are usually determined by
contracting laboratories using various analytical methods.
Analytical methods presently in use include infrared,
gravimetric, utlraviolet- fluorescence, and colorimetric. The
68
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method used by a contractor is usually governed by regulatory
authority, the person in charge of the laboratory, the client, or
some combination of these. For example. Department of the
Interior, U. S. Geological Survey, Outer Continental Shelf
Operating Order #8 (Gulf of Mexico area) dated October 30, 1970,
specifies to Federal leasees that oil content values for
effluents shall be determined and reported in accordance with the
American Society for Testing and Materials Method D1340, "Oily
Matter in Industrial Waste Water." A regional water quality
board in California specifies APHA Standard Methods, 13th
Edition, "Oil and Grease" Test No. 137 (Gravimetric). The U. S.
Environmental Protection Agency lists the APHA Standard for oil
and grease determination under the provisions of 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 16 shows
oil/grease concentrations of acidized and unacidized samples from
facilities in California (both analyzed by the same method).
TABLE 16
Effect of Acidification on
Oil and Grease Data
Oil and Grease - mg/1
Date of
Effluent Sample Unacidized Acidized
7-26-74 7.6 26.3
7-26-74 36.3 61.8
The values after pH adjustment were significantly higher than the
samples that were not acidified. One explanation is that, the
acidification converts many of the water soluble organic acid
salts to water insoluble acids that are then extractable by
hydrocarbon solvents.
The solvent used for the extraction of oil and grease from a
sample is another critical step that can affect analytical
results. For example, petroleum ether extracts all crude oil
constituents from a produced water sample except asphaltenes or
bitumen. This limitation would affect the reported results of a
sample containing high asphaltic constituents. Other solvents
used in oil/grease determinations are trichlorotrifluroethane
69
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(Freon), hexane, carbon tetrachloride, and methylene chloride,
with each being somewhat selective in the hydrocarbon
constituents extracted.
Reported oil/grease concentrations in waste water effluents from
offshore facilities were highly variable within and between
geographical areas. The available information did not show any
discernible reason for this variability (difference in waste
treatability or treatment technology). Therefore, EPA undertook
field verification studies to determine the reasons for the low
oil/grease concentration data in the coastal area of Texas and
California as compared to Louisiana. These field studies
included sampling for oil/grease in effluent waste water
discharges and duplicate samples were provided to the industry
for independent laboratory analysis. Tables 17 and 18 compare
the results of two analytical methods (gravimetric and infrared)
measuring Freon extractible oil/grease and those values
determined by petroleum ether extraction using the gravimetric
method. This study was conducted by the EPA Robert S. Kerr
Research Laboratory (RSKRL) at Ada, Oklahoma.
70
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Table 17
Oil and Grease Data - Texas Coastal
Analytical Procedure Study
Oil and Grease - mq/1
RSKRL
Sample Freon
Identif ication Gravimetric
T-1I
T-1E
T-2I
T-2E
T-3I
T-3E
T-4I
T-4E
32
126
372
242
643
52
1905
46
Freon
Infrared
45
154
314
197
695
62
1736
51
INDUSTRY LABS
Freon
Gravimetric
2
5
178
145
685
10
968
6
Table 18
Oil and Grease Data - California Coastal
Analytical Procedure Study
Sample
Identification
C-1I
C-1E
C-2I
C-2E
C-3I
C-3E
RSKRL
Freon
Gravimetric
106
22.3
359.6
42.2
167.6
46.1
Freon
Infrared
126
16
473
39
197
35
Pet. Ether
Gravimetric
INDUSTRY LABS
Pet. Ether
Gravimetric
76
5
241
27
141
7
79
3.1
508
3.6
189.1
11.2
1 - unacidified samples
I - influent
E - effluent
71
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The preceding tables indicate that there was good correlation in
analytical results when EPA uses two different methods on the
same sample. There is no correlation between the same sample
analyzed by the same method by EPA and the industry labs in Texas
and California (EPA's results did correlate well to the contract
labs during the Louisiana verification study). Therefore the low
oil and grease concentrations reported by Texas and California
appear to be more a function of the analytical techniques and the
laboratory rather than an indication of treatibility of the waste
water produced and/or treatment equipment efficiency. This
conclusion was validated by a statistical analysis of the data,
which is contained in Supplement B. The analysis indicated a
high correlation with the results of the two analytical methods
performed within the EPA laboratory and little or no correlation
with the analytical results between the EPA and contractor
laboratories.
Field Verification Studies
The EPA field verification study of coastal Louisiana facilities
included sampling for oil/grease in effluent waste water
discharges. Duplicate samples were provided to the oil/gas
industry for independent- laboratory analysis. The analytical
results of this study, contained in Supplement B, verified the
data collected over the years by coastal Louisiana facilities.
In addition, the study found a very high correlation between
analytical results of contractor laboratories and the EPA
laboratory.
The selection of facilities for the Gulf Coast verification study
was based on a general cross section of the production industry
and did not favor the more efficient systems. Table 19 indicates
types of treatment units, the performance observed during the
survey, and long term performance based on historical data for
each facility. Tables 20 and 21 indicate the comparative oil and
grease concentration data for Texas and California offshore
facilities and onshore treatment of offshore produced water
treatment units.
72
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TABLE 19
Performance of Individual Units
Louisiana Coastal
Long Term Mean Effluent
Oil and Grease
Facility Identification mq/1
Flotation Cells
GFV01 22
GFV02 23
GFS03 31
GFS04 29
GFS05 32
GFT06 18
GFG07 24
GFS08
GFT09 28
GFG10 18
Parallel Plate Coalescers
GCC11 35
GCC12 66
GCM13 43
GCC14
GCG15 39
GCS16 39
GCC17 51
Loose Media Coalescers
GLG23 25
GLT24 18
Simple Gravity Separators
GPV18
GPT19
GPE20
GIM21
GTT22
GPE25
iSystem malfunctioning during survey.
EPA Survey Results
Oil and Grease
mg/l
23
6
25
21
32
24
1481
30
31
13
21
78
34
52
19
56
118
12
8
13
26
19
44
63
16
73
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TABLE 20
Texas Coastal Verification Data
Facility Freon Extractibles Freon Extractibles
Identification Gravimetric Method Infrared Method
T-l
T-2
T-3
T-4
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
Oil
Effluent
126.0
103.0
116.0
561.0
141.0
118.0
220.0
242.0
194.0
185.0
196.0
220.0
13.0
52.0
45.0
50.0
55.0
87.0
37.0
9.0
14.0
24.0
46.0
and Grease
Influent
45.0
57.0
1,230.0
130.0
300.0
64.0
305.0
314.0
336.0
351.0
293.0
312.0
1,350.0
695.0
1,635.0
206.0
1,242.0
1,215.0
1,520.0
1,578.0
1,677.0
1,780.0
1,736.0
1,884.0
- mg/1
Effluent
154.0
134.0
232.0
827.0
304.0
277.0
209.0
197.0
198.0
204.0
188.0
237.0
55.0
62.0
60.0
66.0
81.0
84.0
42.0
9.0
14.0
27.0
51.0
74
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TABLE 21
Verification of Oil and Grease Data
California Coastal
RSKRL, Ada, Oklahoma
Facility
Identification
Freon
Extractibles,
Gravimetric
Method , mg/1
Influent Effluent
Freon
ExtractibleSj
Infrared
Method, mg/1
Influent Effluent
Petroleum Ether
Extractibles,
Gravimetric
Method, mg/1
Influent Effluent
C-l
01
C-2
C-3
C-4
112.3
97.4
110.7
106.1
359.6
363.6
215.6
599.8
881.1
28.9
43.1
26.0
22.3
42.2
44.0
53.5
51.6
55.4
165.6
163.2
202.2
167.6
56.7
54.0
44.
51.
46.
19.1
24.2
19.9
94.0
101.0
122.0
126.0
437.0
446.0
323.0
851.0
1,214.0
188.0
148.0
206.0
197.0
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
6.0
58.0
16.0
15.0
15.0
90.0
76.0
241.0
193.0
172.0
462.0
611.0
83.0
100.0
141.0
5.0
27.0
13.0
19.0
51.0
14.0
23.0
22.0
71.0
7.0
55.0
59.01
102.O1
6.0J
1. Carbon tetrachloride extractibles.
-------
End-of-pipe control technology for offshore treatment of produced
water from oil and gas production primarily consists of
physical/chemical methods. The type of treatment system selected
for a particular facility is dependent upon availability of
space, waste characteristics, volumes of waste produced, existing
discharge limitations, and other local factors. Simple treatment
systems may consist of only gravity separation pits without the
addition of chemicals, while more complex systems may include
surge tanks, clarifiers, coalescers, flotation units, chemical
treatment, or reinjection.
Gas Flotation
In a gas flotation unit gas bubbles are released into the body of
waste water to be treated. As the bubbles rise through the
liquid, they attach themselves to any oil droplet in their path,
and the gas and oil rise to the surface where they may be skimmed
off as a froth.
Two types of gas flotation systems are presently used in oil
production: 1) Dispersed gas flotation - these units use
specially shaped rotating mines or dispersers to form small gas
bubbles which float to the surface with the contacted oil. The
gas is drawn down into the water phase through the vortex created
by the rotors, from a gas blanket maintained above the surface.
The rising bubbles contact the oil droplets and come to the
surface as a froth, which is then skimmed off. These units are
normally arranged as a series of cells, each one operating as
outlined above. The waste water flows from one cell to the next,
with a net oil removal in each cell (some oil is recycled back
into the water phase by the rotor action) . 2) Dissolved gas
flotation - these units differ from the dispersed gas flotation
because the gas bubbles are created by a change in pressure which
lowers the dissolved gas solubility, releasing tiny bubbles. A
portion of the waste water stream is recycled back to the bottom
of the cell after waste water has been gasified. This
gasification is accomplished by passing the waste water through a
pump to raise the pressure and then through a contact tank filled
with gas. The waste water leaves the contact tank with a
concentration of gas equivalent to the gas solubility at the
elevated pressure. When the recycled (gasified) water is
released in the bottom of the cell (at atmospheric pressure) the
solubility of the gas decreases and the excess gas is released as
microscopic bubbles. These bubbles then rise to the surface
contacting the oil and bringing it to the surface where it is
skimmed off. Dissolved gas flotation units are usually a single
cell only.
On production facilities it is usual practice to recycle the
skimmed oily froth back through the production oil-water
separating units. A flow diagram of the two typical flotation
units is shown in Figure 6.
76
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CRUDE OIL PRODUCTION PROCESSING
LOW PRESSURE OIL WELL'/''
INTERMEDIATE
PRESSURE OIL
WELL
HIGH
PRESSURE
SEPARATOR
HIGH PRESSURE
OILWELL
HEAT
PROCESS Ol L-
WATER SEPARATION
(HEATER TREATER,
CHEMICAL, ELEC
TRICAL,
GUN BARREL, FREE
WATER KNOCKOUT,
ETC.)
01 LTD SALES
OIL AND BRINE
1
c
H_
\
0
ROTOR-DISPERSERS
p n n n
k
ofc=> <=>*=> Xeie?
Y
SKIMMED OIL RECYCLE TO PROCESS SEPARATION
SURGE TANK,
SKIMMER TANK
GAS OR AIR
AND CHEMICALS
WASTE WATER TO EITHER
J
ROTOR-DISPERSER GAS FLOTATION PROCESS DISSOLVED GAS FLOTATION PROCESS
Fig. 6 — ROTOR-DISPERSER AND DISSOLVED GAS FLOTATION PROCESSES
FOR TREATMENT OF PRODUCED WATER
-------
The addition of chemicals can increase the effectiveness of
either type of gas flotation unit, some chemicals increase the
forces of attraction between the oil droplets and the gas
bubbles. Others develop a floe which eases the capture of oil
droplets, gas bubbles, and fine suspended solids, making
treatment more effective.
In addition to the use of chemicals to increase the effectiveness
of gas flotation systems, surge tanks upstream of the treatment
unit also increase its effectiveness. The period of quiescence
provided by the surge tank allows some gravity separation and
coalescence to take place, and dampens out surges in flow from
the process units. This provides a more constant hydraulic
loading to the treatment unit, which, in turn, aids in the oil
removal process.
The verification survey conducted on Coastal Louisiana facilities
included 10 flotation systems which varied in design capacities
from 5,000 to 290,000 barrels-per-day and included both
rotor/disperser and dissolved gas units. The designs of waste
treatment systems are basically the same for both offshore
platform installations and onshore treatment complexes; however,
parallel units are provided at two of the onshore installations,
permitting greater flexibility in operations.
Information obtained during the field survey of onshore treatment
systems for Cook Inlet indicated that one of the four onshore
systems utilized a dissolved gas flotation system comparable to
those used in the Gulf Coast. This system provides
physical/chemical treatment and consists of a surge tank,
chemical injection, and a dissolved air flotation unit. In
addition, two of the Cook Inlet platforms use flotation cells for
treatment of deck drain wastes.
Field surveys on the West Coast found that physical/chemical
treatment is the primary method of treating produced water for
either discharge to coastal waters or for reinjection and that
flotation is the most widely used of the physical/chemical
methods. On the West coast, all treatment systems except one are
located onshore and produced fluids are piped to these complexes.
The majority of the waste water treatment systems have been
converted to reinjection systems. However, some of those that
still discharge are 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.
Surveys of onshore production facilities in California revealed
induced gas flotation being used for treatment of produced water
for recovery, disposal by reinjection and discharge. A total of
78
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seven units were observed, three of which were utilized ahead of
sand filters and one unit was followed by a pond. The size range
of the entire group was from 10,500 to 350,000 Bbl/day. Surge
tanks normally preceded the flotation units with the floe going
to a sump or being recycled.
In Wyoming two dispersed air flotation systems were observed,
both of which discharge and reinjected for recovery the treated
produced water. The system consisted of a skim tank, flotation
unit, surge tank and in the case of the discharged stream, an
earthen pond. The addition of chemicals was used to increase
separation efficiency. The produced water treatment capacities
of the two systems surveyed were 70,000 and 340,000 Bbl/day
re spec ti vel y.
Parallel Plate Coalescers
Parallel plate coalescers are gravity separators which contain a
pack of parallel, tilted plates arranged so that oil droplets
passing through the pack need only rise a short distance before
striking the underside of the plates. Guided by the tilted
plate, the droplet then rises, coalescing with other droplets
until it reaches the tip of the pack where channels are provided
to carry the oil away. In their overall operation, parallel
plate coalescers are similar to API gravity oil water separators.
The pack of parallel plates reduces the distance that oil
droplets must rise in order to be separated; thus the unit is
much more compact than an API separator. Suspended particles,
which tend to sink, move down a short distance when they strike
the upper surface of the plate; then they move down along the
plate to the bottom of the unit where they are deposited as a
sludge and can be periodically drawn off. Particles may become
attached (scale) to the plate surface of the plate; then they
move down along the plate surfaces, requiring periodic removal
and cleaning of the plate pack.
Where stable emulsions are present, or where the oil droplets
dispersed in the water are relatively small, they may not
separate in passing through the unit.
The verification survey of Coastal Louisiana facilities included
seven plate coalescer systems which had design capacities from
4,500 to 9,000 tarrels-per-day. A recent survey indicated that
approximately 10 percent of the units in this area were plate
coalescers and they treated about 9 percent of the total volume
of produced water in offshore Louisiana waters. (4) Both the
long-term performance data and the verification survey indicated
that performance of these units was considerably poorer than that
of flotation units. In addition to the physical limitations,
coalescers1 operation and maintenance data indicated that the
units require frequent cleaning to remove solids.
79
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No plate coalescers are in use in Cook Inlet or California,
either onshore or offshore.
Filter Systems (Loose or Fibrous Media Coalescers)
Another type of produced water treatment system is filters. They
may be classified into two general classes based on the media
through which the waste stream passes.
1. Fibrous media, such as fiberglass, usually in the form
of a replacable element or cartridge.
2. Loose media filters, which normally use a bed of
granular material such as sand, gravel, and/or crushed
coal.
Some filters are designed so that some coalescing and oil removal
take place continuously, but a considerable amount of the
contaminants (oil and suspended fines) remain on the filter
media. This eventually overloads the filter media, requiring its
replacement or backwashing. Fibrcus 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 gasifying and loosening the media bed.
Filters which require backwashing present somewhat of a problem
on platforms because the valving and controls need regular
maintenance and disposal of the dirty backwash water may be
difficult. Replacing filter media and contaminated filter
elements also create disposal problems.
Measured by the amount of oil removed, filter performance has
generally been good (provided that the units are backwashed
sufficiently often); however, problems of excessive maintenance
and disposal have caused the industry in the Gulf Coast to move
away from this type of unit, and a number of them have been
replaced with gas flotation systems.
The Gulf Coast survey information indicated that when filter
systems are used there is no initial pretreatment of the waste
other than surge tanks. Backwashing, disposal of solids, and
complex instrumentation were reported as the main problems with
these units.
On the West Coast and Cook Inlet, no filter systems are in use as
the primary treatment method. Filters are however, used for
final treatment in injection systems in California and several
steps of filtration are used prior to sea water injection in Cook
Inlet. On the west Coast, these units are preceded by a surge
tank, flotation unit, and other treatment units which remove most
80
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of the oil and suspended particles. These units, when used in
series with other systems, perform well.
In Wyoming a site was visited where approximately 6,600 Bbl/day
was being treated by a mixed sand media pressure filter. Earthen
ponds both preceded and followed the filter unit with backwash
feed being pumped from the final pond and discharged to the
primary pond.
Gravity Separation
The simplist form of treatment is gravity separation. The
produced water is retained for a sufficient time for the oil and
water to separate. Tanks, pits, and, occasionally, barges are
used as gravity separation vessels. Large volumes of storage to
permit sufficient retention times are characteristic of these
systems. Performance is dependent upon the characteristics of
the waste water, water volumes, and availability of space. While
total gravity separation requires large containers and long
retention times, any treatment system can benefit from quiescent
retention prior to further treatment. This retention allows some
gravity separation and dampens surges in volume and oil content.
About 75 percent of the systems on the Gulf Coast are gravity
separation systems. The majority are located onshore and have
limited application on offshore platforms because of space
limitations. Properly designed, maintained, and operated systems
can provide adequate treatment. A 30,000-barrel-per-day gravity
system with the addition of chemicals produced an effluent of
less than 15 mg/1 during the verification survey.
Two of the onshore treatment systems in Cook Inlet use gravity
separation with various configurations of settling tanks and
pits. No gravity systems were reported to be in use on the West
Coast. The four installations visited in the Texas verification
study all use gravity separation tanks offshore and a combination
of tanks and/or pits onshore.
The most prevalent treatment method for produced water
encountered in the onshore field surveys of California, Wyoming,
Texas, Louisiana and Pennsylvania onshore production sites were
tanks and ponds when utilized as the single treatment process.
As previously mentioned, tanks do not afford the retention times
of ponds, but whether or not their primary function is separation
they are effective in skimming readily removed free oil.
In California four sites were visited which utilized tankage as
the single method of treatment prior to disposal by reinjection.
The capacity of these systems to treat produced water ranged from
6,000-35,000 Bbl/day.
81
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In Wyoming a total of 37 production facilities were visited which
utilized either tanks or ponds as the method of treatment, of
the 23 sites using tanks for treatment ranging in produced water
capacity from 920 to 34,000 Bbl/day, 11 were reinjecting for
disposal and the remainder were reinjecting for secondary
recovery purposes. Of the 14 sites using ponds for treatment,
nine were discharging, two were reinjecting for recovery, while
the remaining three both discharged and reinjected for recovery.
In Pennsylvania, where disposal ty discharge is the rule rather
than the exception, 11 sites were visited which utilized ponds
for separation treatment ranging in capacity from 2-8,000 Bbl/day
of produced water capacity.
Distillation
In California a site was visited which utilized produced water as
boiler feedwater. The boiler was fired by field natural gas and
discharged condensate to the local groundwater table. The steam
was utilized to heat onsite crude storage tanks and the boiler
blowdown containing oil and grease residue was hauled to a Class
I (California Classification) landfill site. Reported daily fuel
costs for the 150 Bbl/day facility are $70.
Chemical Treatment
The addition of chemicals to the waste water stream is an
effective means to increase the efficiencies of treatment
systems. Pilot studies for a large onshore treatment complex in
the Gulf of Mexico indicated that addition of a coagulating agent
could increase efficiencies approximately 15 percent and the
addition of a polyelectrolyte and a coagulating chemical could
increase efficiencies 20 percent. (5)
Three basic types of chemicals are used for waste water treatment
and, many different formulations of these chemicals have been
developed for specific applications. The basic types of
chemicals used are:
1. Surface Active Agents - These chemicals modify the
interfacial tensions between the gas, suspended solids,
and liquid. They are also referred to as surfactants,
foaming agents, demulsifiers, and emulsion breakers.
2. Coagulating Chemicals - Coagulating agents assist the
formation of floe and improve the flotation or settling
characteristics of the suspended particles. The most
common coagulating agents are aluminum sulfate and
ferrous sulfate.
82
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3. Polyelectrolytes - These chemicals are long chain, high
molecular weight polymers used to assist in removal of
colloidal and extremely fine suspended solids.
The results of two EPA surveys of 33 offshore facilities using
chemical treatment in the Gulf Coast disclosed the following:
1. Surface active agents and polyelectrolytes are the most
commonly used chemicals for waste water treatment.
2. The chemicals are injected into the waste water upstream
from the treatment unit and do not require premixing
units.
3. Chemicals are used to improve the treatment efficiencies
of flotation units, plate coalescers, and gravity
systems.
4. Recovered oil, foam, floe, and suspended particles
skimmed from the treatment units are returned to the
process system.
A similar survey of facilities in Cook Inlet, Alaska indicated
that a facility uses coagulating agents and polyelectrolytes to
improve treatment efficiency. Recovered oil and floe are
returned to the process system.
Chemical treatment procedures on the West Coast are similar to
those used in the Gulf Coast and Cook Inlet. However, there are
exceptions where refined clays and bentonites are added to the
waste stream to absorb the oil and both are removed after
addition of a high molecular weight nonionic polymer to promote
flocculation. The oil, clay, and other suspended particles
removed from the waste stream are not returned to the process
system but are disposed of at approved land disposal sites. A
14,000-barrel-per-day treatment system using refined clay was
reported to have generated 60 barrels-per-day of oily floe which
required disposal in a State approved site. Selection of the
proper chemical or combination of chemicals for a particular
facility usually requires jar tests, pilot studies, and trial
runs. Adjustments in chemicals used in the process separation
systems may also require modification of chemicals or application
rate in the waste stream. Other chemicals may also be added to
reduce corrosion and bacterial growths which may interfere with
both process and waste treatment systems.
Effectiveness of Treatment Systems
Table 22 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
83
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readily apparent. However, individual units of other types of
treatment systems have produced comparable effluents.
TABLE 22
Performance of Various Treatment Systems
Louisiana Coastal
Mean Effluent, No. of Units
Oil and Grease in Data
Type Treatment System mg/1 Base
Gas Flotation 27 27
Parallel Plate Coalescers 48 31
Filters
Loose Media 21 15
Fibrous Media 38 7
Gravity Separation (4)
Pits 35 31
Tanks 42 48
Table 23 gives the performance of existing produced water
treatment systems over a 6-month to one and one-half year period
of weekly and monthly sampling. The data has been divided into
treatment systems according to State of location.
TABLE 23
Performance of Various Treatment Systems
Wyoming and Pennsylvania
Type of Mean Effluent No. of Units
Treatment Oil and Grease in Data
State System mq/1 Base
Wyoming Ponds 8.2 6
Gas Flotation 10.6 2
Sand Filtration 12.5 1
Pennsylvania Ponds 4.1 4
84
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Zero Discharge Technologies
Water produced along with liquid or gaseous hydrocarbons may vary
in quantity from a trace to as much as 98 percent of the total
fluid production. Its quality may range from essentially fresh
to solids-saturated brine. The no discharge control technology
for the treatment of raw waste water after processing varies with
the use or ultimate disposition of the water. The water may be:
1. Discharged to pits, ponds, or reservoirs and evaporated.
2. Injected into formations other than their place of
origin.
Evaporation
In some arid and semiarid producing areas, use of evaporation is
acceptable, although limited in its practice. The surface pit,
pond, or reservoir can only be used where evaporation rates
greatly exceed precipitation and the quantity of emplaced water
is small. The pit or pond is ordinarily located on flat to very
gently rolling ground and not within any natural drainage
channel, so as to avoid danger of flooding. Pit facilities are
normally lined with impervious materials to prevent seepage and
subsequent damage to fresh surface and subsurface waters.
Linings may range from reinforced cement grout to flexible
plastic liners. Materials used are resistant to corrosive
chemically-treated water and oily waste water. In areas where
the natural soil and bedrock are high in bentonite,
montmorillonite, and similar clay minerals which expand upon
bexng wetted, no lining is normally applied and sealing depends
on the natual swelling properties of the clays. All pits are
normally enclosed to prohibit or impede access.
In much of the Rocky Mountain oil and gas producing area, the
total dissolved solids of the produced waters are relatively low.
These waters are discharged to pits and put to use for local
farmers and ranchers by irrigating land and watering stock. A
typical produced water system widely in use is shown in Figure 7.
A cross section of the individual pit is shown in Figure 8.
A producing oil field in Nevada discharges produced water to a
closed saline basin. The basin contains no known surface or
subsurface fresh water and is normally dry. The field contains
13 wells and produces approximately 33 barrels of brine per well
per day.
Subsurface Disposal
Injection and disposal of oil field produced water underground is
practiced extensively by the petroleum industry throughout the
85
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DETAIL MAP
THEATER
I IFWKO
QHEADER
SAMPLE POINT
f
§
o
m
t
PIT
•• 75'»-
PIT
1
\
-f
DISCHARGE
500 BBL
WATER
SETTLING
TANK
I
500 BBL
OIL STORAGE
TANKS
LACT
Fig. 7 — ONSHORE PRODUCTION FACILITY WITH
DISCHARGE TO SURFACE WATERS
86
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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. 8 — TYPICAL CROSS SECTION UNLINED EARTHEN
OIL-WATER PIT
87
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United States. The term "disposal" as used here refers to
injection of produced fluids, ordinarily into a formation foreign
to their origin. This injection is for disposal only and plays
no intentional part in secondary recovery systems. (Injection
for pressure maintenance or secondary recovery refers to the
emplacement of produced fluids into the producing formation to
stimulate recovery of additional hydrocarbons and is not
considered end-of-pipe treatment.) Current industry practice is
to apply minimal or no treatment to the water prior to disposal.
If water destined for disposal requires treatment, it is usually
confined to the application of a corrosion inhibitor and
bactericide; a sequestering agent may be added to waters having
scaling tendencies. The amount of treatment depends on the
formation properties, water characteristics, and the availability
and cost of storage and stand-by wells.
Corrosion is ordinarily caused by low pH, plus dissolved gasses.
Bactericides serve to inhibit the development of sulfate-reducing
and slime producing organisms. Chemicals and bactericides are
frequently combined into a single commercial product and sold
under various trade names. (6)
A wide range of stable, semipolar, surface-active organic
compounds have been developed to control corrosion in oil field
injection and disposal systems. The inhibitors are designed to
provide a high degree of protection against dissolved gasses
(carbon dioxide, oxygen, and hydrogen sulf ide), organic and
mineral acids, and dissolved salts. The basic action of the
inhibitors is to temporarily "plant" or form a film on the metal
surfaces to insulate the metal from the corrosive elements. The
life of the film is a function of the volume and velocity of
passing fluids. Inhibitors may be water soluble or dispersible
in fresh water or brine. They may be introduced full strength or
diluted. Treatment, usually in the range of 10 to 50 parts per
million, may be continuous or intermittent (batch or slug).
Effectiveness of corrosion inhibition is determined in several
ways, including corrosion coupons, hydrogen probes, chemical
analyses, and electrical resistivity measurements.
Three primary types of bacteria attach oil field injection and
disposed systems and cause corrosion:
1. Anaerobic sulfate-reducing bacteria
(Desulfovibrio—desulfuricans). These bacteria promote
corrosion by removing hydrogen from metal surfaces,
thereby causing pitting. The hydrogen then reduces
sulfate ions present in the water, yielding highly
corrosive hydrogen sulfide, which accelerates corrosion
in the injection or disposal system.
2. Aerobic slime-forming bacteria. These may grow in great
numbers on steel surfaces and serve to protect growths
88
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of underlying sulfate-reducing bacteria. In extreme
instances, great masses of cellular slime may be formed
which may plug filters and sandface.
3. Aerobic bacteria that react with iron. Sphaerotilus and
Gallionella convert soluble ferrous iron in injection
water to insoluble hydrated ferric oxides, which in turn
may plug filters and sandface. Oxygen entry into a
system may also cause the formation of ferric oxide.
Treatment to combat bacterial attack ordinarily consists of
applying either a continuous injection of 10 to 50 ppm
concentration of a bactericide or batching once or twice a week.
Scale inhibitors are commonly used in the injection or disposal
system to combat the development of carbonate and sulfates of
calcium, magnesium, barium, or strontium. Scale solids
precipitate as a result of changes in temperature, pressure, or
pH. They may also be developed by combining of waters containing
nigh concentrations of calcium, magnesium, barium, or strontium
with waters containing high concentrations of bicarbonate,
carbonate, or sulfate. Scale inhibitors are basically chemicals
which chelate, complex, or otherwise inhibit or sequester the
scale-forming cations.
The most widely used scale sequestrants are inorganic
polymetaphosphates. Relatively small quantities of these
chemicals will prevent the precipitation and deposition of
calcium carbonate scale. Bimetallic phosphates or the so-called
"controlled solubility" varieties are now widely used by the oil
industry in scale control and are preferred over the
polyphosphates.
The downhole completion of a typical injection well is shown in
Figure 9. A producing well is shown for comparison. Injection
wells may be completed in a complicated fashion with multiple
strings of tubing, each injected into a separate zone. If the
disposal well is equipped with a single tubing string, and
injection takes place through tubing separated from casing by
packer, the annular space between tubing and casing is filled
with noncorrosive fluids such as low-solids water containing a
combination corrosion inhibitor bactericide, or hydrocarbons such
as kerosene and diesel oil. All surface casing is cemented to
the ground surface to prevent contamination of fresh water and
shallow ground water. Pressure gauges are installed on the
casing head, tubing head, and tubing to detect anomalies in
pressure. Pressure may also be monitored by continous clock
recorders which are commonly equipped with alarms and automatic
shutdown systems if a pipe ruptures.
The injection well designed for pressure maintenance and
secondary recovery purposes is completed in a manner identical to
89
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INJECTION WELL
PRODUCING WELL
vo
o
FRESH WATER —
PROTECTED WITH
CASING AND CEMENT
INJECTION SAND
PROTECTED WITH OIL
STRING AND CEMENT
CO
t
O
< tl
a.
: Cement
O
— QJ
S 2.
»«
-
O 0)
3 3
o tt
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— co
=.3
CD (D
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Q) at
^* 3
re 3
-i re
Cfl 3
3 Z
Q. re
(0 O
i re
3<
a -*
o
FIGURE
TYPICAL COMPLETION OF AN INJECTION WELL AND A PRODUCING WELL
-------
that of the disposal well, except that injection is into the
producing horizon. Treatment prior to injection may vary from
that applied to the disposal well in as much as water injected
into the reservoir sandface must te as free of suspended solids,
bacterial slimes, sludges, and precipitates as is economically
possible. Ordinarily, selection of injection well sites poses
few if any environmental problems. In many instances where
injection is used for secondary recovery, the well site is fixed
by the geometry of the waterflood configuration and cannot be
altered.
Water for injection into oil and gas reservoirs requires
treatment facilities and processes which yield clear, sterile,
and chemically stable water. A typical open injection water
treatment system includes a skim pit or tank (steel or concrete
equipped with over-and-under baffles to remove any vestiges of
non-soluable material remaining after pretreatment) ; an aeration
facility, if necessary to remove undesirable gasses such as
hydrogen sulfide; a filtering system; seepage-proof backwash pit;
accumulator tank (sometimes referred to as a clear well or clear
water tank) to retain the finished water prior to injection; and
a chemical house for storing and dispensing treatment chemicals.
In the system described above no attempt is made to exclude air.
Closed systems, on the other hand, are designed to exclude air
(oxygen). This is desirable because the water is less corrosive
or requires less treatment to make it noncorrosive. The truly
"closed" system is difficult to attain because of the many
potential points of entry of air into the production system.
Air, for example, can be introduced into the system on the
downstroke of a pumping well through worn stuffing box packing or
seals. In a few instances, closed injection (or disposal) system
is used where product waters ordinarily have minimal corrosive
characteristics. That is, where salt water is gathered from
relatively few wells, fairly close together; where wells produce
from a common reservoir; or where a one-owner operation is
involved.
There are instances in which a closed input or produced water
disposal system can be developed. In these systems all vapor
space must be occupied by oxygen-free gas under pressure greater
than atmospheric. If oxygen (air) enters the system, it is
scavenged.
The "open" injection system has a much greater degree of
operational flexibility than does the closed system. Among its
more desirable factors are:
1. Wider range, type, and control of treatment methods.
2. Ability to handle greater quantities of water from different
sources (diverse leases and fields) and differing formations.
91
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3. Anility to properly treat waters of differing composition.
This factor enables incompatible waters to be successfully
combined and treated on the surface prior to injection.
Disposal Zone
The choice of a brine disposal zone is extremely important to the
success of the injection program. Prior to planning a disposal
program, detailed geologic and engineering evaluations are
prepared by the production divisions of oil producing companies.
Appraisal of the geologic reservoir must include the answers to
questions such as:
1. How much reservoir volume is available?
2. Is the receiving formation porous and permeable?
3. What are the formation's physical and chemical properties?
U. What geological, geochemical and hydrologic controls govern
the suitability of the formation for injection or disposal?
5. What are the short-term and long-term environmental
consequences of disposal?
The geologic age of significant disposal and injection reservoirs
throughout the nation, ranges from relatively young rocks of
Cambro-Ordovician period. Depths of disposal zones oridinarily
range from only a few hundred feet to several thousand. However,
prudent operators usually consider it inadvisable to inject into
formations above 1,000 feet, particularly where the receiving
formation has low permeability and injection pressures must be
high. If the desired daily average quantity of water cannot be
disposed of, except at surface pressures which exceed 0.5 pounds
per square inch surface guage pressure per foot of depth to the
disposal zone, particularly in shallow wells, an alternate zone
is usually sought.
It is necessary to be familiar with both the lithology and water
chemistry of the receiving formation. If interstitial clays are
present, their chemical composition and compatibility with the
injected fluid must be determined. The fluids in the receiving
zone must be compatible with those injected. Chemical analyses
are performed on both to determine whether their combination will
result in the formation of solids that may tend to plug the
formation.
The petroleum industry recognizes that the most carefully
selected injection equipment means nothing if the disposed water
is not confined to the formation into which it is placed.
Consequently, the injection area must be thoroughly investigated
to determine any previously drilled holes. These include holes
92
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drilled for oil and gas tests, deep stratigraphic tests, and deep
geophysical tests. If any exist, further information as to
method of plugging and other technological data germane to the
disposal project is assembled and evaluated.
On the California coast there is a definite trend for all onshore
process systems which handle offshore production fluids to
reinject produced water for disposal. Field investigations made
in California were confined to OCS waters, with visits being made
to five installations. Each of these facilities were performing
some subsurface disposal; none were injecting for secondary
recovery or pressure maintenance. Four of these installations
were sending all or part of the produced fluids to shore for
treatment. All five installations were disposing of treated
water in wells on the platform. Two were sending all fluids to
shore, separating the oil and water, and then pumping the treated
water back to the platforms for disposal. One installation was
separating the oil and water on the platform and further treating
the water so that it could be injected into disposal wells on the
platform. Two of the platforms had been treating all fluids on
the platform and injecting treated water. Since the total fluids
produced are presently greater than the capacity of the disposal
system, the excess treated water is being discharged overboard.
Plans were being formulated to increase the capacity of the
disposal system to return all produced water underground.
Produced water disposal is commonly handled on a cooperative or
commercial basis, with the producing facility paying on a
per-barrel basis. The disposal facility may be owned and
operated by an individual, a cooperative association, or a joint
interest group who may operate a central treatment or disposal
system. The waste water may be trucked or piped to the facility
for treatment and disposal. Two examples of cooperative systems
are operating in the East Texas Field and the Signal Hill and
Airport Fields at Long Beach, Calfornia.
Alternate Handling
During major breakdown and overhaul of waste treatment equipment,
it is common practice to continue production and by pass the
treatment units requiring repair. This does not create a serious
problem at large onshore complexes where dual treatment units are
available, but at strailer facilities and on offshore platforms
there may not be an alternate unit to use. Alternate handling
practices vary considerably from facility to facility. The
following methods are currently practiced offshore:
1. Discharge overboard without treatment.
2. Discharge after removal of free oil in surge tank.
93
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3. Discharge to a sunken pile with surface skimmer to remove
free oil.
4. Discharge of produced water to oil pipeline for onshore
treatment.
5. Retention on the facility using available storage.
6. Production shutdown.
The method used depends upon the design and system configuration
for the paricular facility.
End-of-Pipe Technology for Wastes Other than Produced Water
Deck Drainage
Where deck drainage and deck washings are treated in the Gulf
Coast, the water is treated by gravity separation, or transferred
to the production water treatment system and treated with
production water. Platforms in California pipe the deck drainage
and deck washings along with produced fluids to shore for
treatment. In Cook Inlet, these wastes are being treated on the
platform.
Field investigations conducted on platforms at Cook Inlet
indicate that the most efficient system for treatment of deck
drainage waste water in this area is gas flotation. Limited data
indicate an average effluent of 25 mg/1 can be obtained from this
system. The field investigations found that deck drainage
systems operate much better when crankcase oil is collected
separately and when detergents are not used in washing the rigs.
The practice of allowing inverted emulsion muds to get into the
deck drain system, during drilling or workovers, also seemed to
adversely effect treatment.
Sand Removal
The fluids produced with oil and gas may contain small amounts of
sand, which must be removed from lines and vessels. This may be
accomplished by opening a series of valves in the vessel
manifolds that create high fluid velocity around the valve. The
sand is then flushed through a drain valve into a collector or a
55-gallon drum. Produced sand may also be removed in cyclone
separators when it occurs in appreciable amounts.
The sand that has been removed is collected and taken to shore
for disposal; or the oil is removed with a solvent wash and the
sand is discharged to surface waters directly.
Field investigations have indicated that some Gulf Coast
facilities have sand removal equipment that flushes the sand
-------
through the cyclone drain valves, and then the untreated sand is
bled into the waste water and discharged overboard.
No sand problems have been indicated by the operators in the Cook
Inlet area. Limited data indicate that California pipes most of
the sand with produced fluids to shore where it is separated and
sent to State approved disposal sites.
At least one system has been developed that will mechanically
remove oil from produced sand. The sand washer systems consist
of a bank of cyclone separators, a classifier vessel, followed by
another cyclone. The water passes to an oil water separator, and
the sand goes to the sand washer. After treatment, the sand is
reported to have no trace of oil, and the highest oil
concentration of the transferred water was less than 1 ppm of the
total volume discharged. (6)
Drilling Muds and Drill Cuttings (Offshore)
Oil and gas drilling operations, including exploratory drilling,
are accomplished offshore with the use of mobile drilling rigs.
These drilling units are either self-propelled or towed units
that are held over the drilling site by anchors or supported by
the ocean floor. The wastes generated from drilling operations
are drilling fluids or "muds" used in the drilling process, rock
cuttings removed from the wellbore by the drilling fluids, and
sanitary wastes from human activity.
Both water based and oil muds are used. (10) In-plant control
techniques and drilling mud practices are affected by the type of
mud used, conventional mud handling equipment is used for water
based muds. Some of the water based muds are discharged into the
surface waters, with no special control measures other than
routine conservation and safety practices. Operation and
maintenance procedures on drilling rigs using water based muds
are routine housekeeping practices associated with cleanliness
and safety. A conventional drilling mud system for water based
muds consists of a circulating system including pumps and pipes,
mud pits, and accessory conditioning equipment (shale shakers,
desanders, desilters, degassers).
In-plant control techniques for oil muds are much more
restrictive. They are not discharged into surface waters. The
in-plant practices include mud saving containers on board, in
addition to the conventional mud handling system. Operations and
maintenance practices on rigs using oil muds generally reflect
spillage prevention and control measures, such as drill pipe and
kelly wipers, and catchment pans.
Cuttings from drilling operations are disposed into surface
waters when water based muds are used. However, cuttings from
oil mud drilling are usually collected and transported to shore
95
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for disposal. Another method is to collect cuttings, clean them
with a solvent water mixture, and subsequently dispose of the
washed cuttings into the surface water body. After washing, the
solvent water is transferred to shore or contained in a closed
liquid recovery system. (11)
Drilling Muds and Drill Cuttings (Onshore)
With onshore drilling, the discharge from shale shakers,
desilters, and desanders is placed in a large earthen pit. When
drilling operations terminate, the pit is backfilled and graded
over. Remaining muds, either oil or water based, are reclaimed.
Well Treatment
Acidizing and fracturing performed as part of remedial service
work on old or new wells can produce wastes. Additionally, the
liquids used to kill a well so that it can be serviced might
create a disposal problem.
Spent acid and fracturing fluids usually move through the normal
production system and through the waste water treatment systems.
The fluids therefore do not appear as a discrete waste source.
Their presence, however, in the waste treatment system may cause
upsets and a higher oil content in the discharge water.
Liquids used to kill wells are normally drilling mud, water, or
an oil such as diesel oil. If oil is used it is recovered
because of its value, either by collecting it directly or by
moving it through the production system. If the killing fluid is
mud it will be collected for reuse or discharged as described
earlier in this section. If water is used it will be moved
through the production and treatment systems and disposed.
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 water but, in some cases brackish or sea
fresh 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. (12)
96
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There are two alternatives to handling of sanitary wastes from
offshore facilities. The wastes can be treated at the offshore
location or they may be retained and transported to shore
facilities for treatment. Offshore facilities usually treat
waste at the source. The treatment systems presently in use may
be categorized as physical/chemical and biological.
Physical/chemical treatment may consist of
evaporation-incineration, maceration-chlorination, and chemical
addition. With the exception of maceration-chlorination, these
types of units are often used to treat wastes on facilities with
small complements of men or which are intermittently manned. The
incineration units may be either gas fired or electric. The
electric units have been difficult to maintain because of salt
water corrosion and heating coil failure. The gas units are not
subject to these problems but create a potential source of
ignition which could result in a safety hazard at some locations.
Some facilities have chemical toilets which require hauling of
waste and create odor and maintenance problems.
Macerator-chlorinators have not been used offshore but would be
applicable to provide minimal treatment for small and
intermittently manned facilities. At this time, there does not
appear to be a totally satisfactory system for small operations.
A much more complex physical/chemical system that has been
installed at an offshore platform in Cook Inlet consists of:
primary solids separation; chemical feed; coagulation;
sedimentation; sand filtration; carbon adsorption; and
disinfection. All solids and sludge are incinerated. Because of
start-up difficulties, no data is available for this facility.
It has been reported that physical/chemical sewage treatment
systems have performed well in testing on land, but offshore they
have developed problems associated with the unique offshore
environment including abnormal waste loadings and mechanical
failure due to weather exposure. (12)
The most common biological system applied to offshore operations
is aerobic digestion or extended aeration processes. These
systems usually include: a comminutor which grinds the solids
into fine particles; an aeration tank with air diffusers; a
gravity clarifier return sludge system; and a tank. These
biological waste treatment systems have proven to be technically
and economically feasible means of waste treatment at offshore
facilities which have more than ten occupants and are
continuously manned.
Because of the special characteristics of sanitary waste
generated by offshore operations, the design parameters in Table
24 have been recommended. Table 25 shows average effluent
concentrations for various types of treatment units which are in
use at offshore facilities in the coastal waters of Louisiana.
97
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Domestic Wastes
Domestic wastes result from laundries, galleys, showers, etc.
Since these wastes do not contain fecal coliform, which must be
chlorinated, they must only be ground up so as not to cause
floating solids on discharge. Traceration by a comminutor should
be sufficient treatment.
98
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Parameters
BOD
TABLE 24
Design Requirements
for Offshore Sanitary Wastes (13)
Design Requirement
Per Capita Per Day
Total Suspended Solids
Flow
0.22 Ib
0.15 Ib
75 gal
TABLE 25
Average Effluents of Sanitary Treatment Systems
Louisiana Coastal (13)
Company
A
B
c
D
E
No. of Units
11
6
17
9
6
BOD
5
mg/1
35
13
15
25
86
Suspended
Solids
mq/1
24
39
43
36
77
Chlorine
Residual
mq/1
1.2
1.8
1.9
2.5
1.3
99
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SECTION VII
Bibliography
1. University of Texas-Austin, Petroleum Extension Service, and
Texas Education Agency Trade and Industrial Service, 1962.
"Treating Oil 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. Sport, M.C. 1969. "Design and Operation of Gas Flotation
Equipment for the Treatment of Oilfield Produced Brines."
Paper presented at the Offshore Technology conference,
Houston, Texas, May 18-21, 1969. Preprint No. OTC 1051, Vol.
1: 111-145 1-152.
6. Sawow, Rondal D. 1972. "Pretreatment of Industrial Waste
Waters for Subsurface Injection" and, "Underground Waste
Management and Environmental Implications." In: AAPG Memoir
18, pp.93-101.
7. Hanby, Kendall P., Kidd, Robert E., and LaMoreaux, P.E.
1973. "Subsurface Disposal of Liquid Industrial Wastes in
Alabama." Paper presented at the second International
Symposium on Underground Waste Management and Artificial
Recharge, New Orleans, Louisiana, September 26-30, 1973.
8. Ostroff, A.G. 1965. "Introduction to Oil Field Water
Technology." Prentice Hall, Inc.
9. McKelvey, V.E. 1972. "Underground Space — An Unappraised
Resource." In: "Underground Waste Management and
Environmental Implications." AAPG Memoir 18, pp. 1-5.
10. Hayward, B.S., Williams, R.H., and Methven, N.E. 1971.
"Prevention of Offshore Pollution From Drilling Fluids."
Paper presented at the 46th Annual SPE of AIME Fall Meeting,
100
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New Orleans, Louisiana, October 3-6, 1971. Preprint No.
SPE-3579.
11. Cranfield, J. 1973. "Cuttings Clean-Up Meets Offshore
Pollution Specifications." Petrol. Petrochem. Int., Vol. 13:
No. 3, pp. 54-56, 59.
12. Martin, James C. 1973. "Domestic Waste Treatment in the
Offshore Environment." Paper presented at the 5th Annual
Offshore Technology Conference. Preprint No. OTC 1737.
13. U.S. Department of the Interior. "Sewage Effluent Data."
(Unpublished Report) August 16, 1972.
101
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SECTION VIII
COST, ENEJRGY, 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 costss for treatment at each level
of technology. Treatment cost for small, medium, and large oil
and gas producing facilities have teen estimated for BPCT, BAT,
and new sources end-of-pipe technologies. For existing
facilities in the oil and gas extraction industry presently
discharging formation water, the estimated capital cost required
to comply with BPCT effluent limitation by 1977 is $147,307,000
and the annual costs for debt service, depreciation, operation
and maintenance, and energy are $43,609,000.
Cost Analysis
Section IV discusses the major categories of industry operations
or activities and identifies subcategories within each one. For
purposes of cost analysis of end-of-pipe treatment three waste
streams are considered — produced water with discharge, produced
water reinjected, and sanitary wastes (offshore). The cost of
water treatment or disposal for produced water generated in the
offshore and coastal subcategories is significantly affected by
availability of space. The cost analysis has therefore been
subdivided into two areas; offshore water disposal and onshore
water disposal. The onshore water disposal has been further
subdivided regionally. Deck drainage is considered to be
treatable with the production water. Handling of drilling muds,
well treatment wastes, and produced sands do not add any
significant costs because the regulations requirements are common
industry practice. In some instances offshore, the produced
water is transferred to shore along with the crude, while in
others the waste treatment system is installed on the platforms.
Therefore, not all platforms will need to add all of tne
treatment equipment or incur all of the incremental costs
indicated to bring their raw discharges into compliance with the
effluent limitations. Existing water treatment systems include
sumps and sump piles, pits, tanks, plate coalescers, fibrous and
loose media coalescers, flotation systems and reinjection
systems.
Offshore Produced Water Disposal
The systems currently used or needed for the treatment of process
waste water (formation water) resulting from the production of
oil and gas involve physical separation, sometimes aided by
chemical application, prior to discharge. Shallow well injection
has also been successfully used for disposal of produced wastes
103
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at onshore locations and at several offshore locations in
California.
The methods examined for offshore use. include the following
arrangement of components:
Al Gravity separation using tanks, then discharge to
surface water.
A2 Gravity separation using plate coaleseers, then
discharge to surface water.
B Separation by coalescence, using flotation equipment,
then discharge to surface water.
C Separation by coalescence, using flow equalization
(surge tanks), desanders, and flotation, then discharge
to surface water.
O Separation using filters, then discharge to surface
water.
£1 Separation using flow equalization (surge tank) and
filter with disposal by shallow well injection.
£2 Separation using flow equalization (surge tank)
desanders and filters, with disposal by shallow well
injection.
The data available for analysis suggest sizing treatment
facilities for produced water based on these flow rates (barrels
per day): 200, 1,000, 5,000, 10,000, 40,000. Where flow
equalization is provided for the above systems, surge tanks of
these sizes were used (barrels): 20, 100, 500, 1,000, 3,000,
respectively.
Because of the nature of the problem, development of realistic
cost estimates for the treatment cf produced water should be very
generalized. Costs have been developed for the systems
identified based on the following assumptions:
1. All cost data were computed in terms of 1973 dollars
corresponding to an Engineering News Record (£NK)
construction cost index value of 1,895 unless otherwise
stated.
2. The annualized costs for capital and depreciation are based
on a loan rate of 15 percent which is equivalent to an annual
average cost of 20 percent of the initial investment
comprised of 10 percent for depreciation and 10 percent for
average interest charges.
10U
-------
3. Costs will vary greatly depending upon platform space.
Therefore, investment costs have been prepared for three
options:
a. Option (a) assumes that adequate platform space is
available because existing requirements for waste
treatment are contained in the offshore leases. (1)
Therefore, no additional space will be needed. Rather,
the space will be reused by facilities with more
efficient removal capacity.
b. Option (t) assumes that, because of the high costs
involved in building platforms, they have been built to
the minimum size needed for production. Therefore space
is not generally available for water treatment equipment
and ancillary facilities. Space is provided by
cantilevered additions up to 1,000 square feet. Space
requirements greater than this amount will require an
auxiliary platform. (2)
c. Option (c) is for new platforms being planned. The
needed space would be provided as a basic part of the
platform design and the costs apportioned at $350 per
square foot.
In all three cases estimates are based on platforms located
offshore in 200 feet of water. This depth is assumed to be an
average for the period to 1983.
Where electric energy is required, generating equipment of
adequate capacity for the treatment equipment is provided for all
requirements exceeding 5 horsepower.
Operation and maintenance costs of components of the various
systems are based on operating costs of the equipment. (2) The
resulting percentage of investment cost is shown in Table 26.
105
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TABLE 26
Operating Cost offshore
Facility
Tanks
Plate Coalescers
Flotation Systems*
Filters*
Subsurface Disposal1
Electrical Supply Facilities
Platforms
Basis for Calculating
Annual O & M Costs
(Percentage of
Investment
11
33
11
11
9
10
2
1 Excludes electrical power supply cost.
Energy and power for low demand is computed as 2 percent of the
investment cost. For high demands an electric power cost of 2-
1/2 cents per kilowatt hour is assumed.
The capital costs and annualized costs for the six alternative
produced water treatment systems, for offshore installation, are
contained in Tables 27-31. Options (a), (b) , and (c) , as defined
above, reflect equipment costs, installation, and the cost of
platform space requirements.
Onshore Produced Mater Disposal
The waste water treated onshore will result from either onshore
production facilities or offshore produced water sent to shore
for treatment. The costs for treatment of offshore wastes, which
are sent to shore, treated and then discharged will be somewhat
less than the costs quoted aJDOve. These lower costs result from
cheaper construction costs onshore, no costs for platform space,
lower 0 and M costs, etc. The costs shown here are for
subsurface disposal onshore.
The typical system for injection for disposal only is a flow
equalizing or surge tank, high pressure pumps, and a suitable
well. Chemicals may be added to prevent corrosion or scale
formation.
106
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Table 27
Capital Costs
Annualized Costs
Capital
Depreciation
0 & M
Energy
Total Annualized Costs
Cost of water disposal
$/bbl
Formation Water Treatment Equipment Costs
Offshore Installations
200 Barrels Per Day Flow Rate
EQUIPMENT COSTS (Thousands of 1974 dollars)
Al
59.3
5.93
5.93
2.95
-
14.8
B
69.7
6.97
6.97
4.7
-
18.6
C
87.1
8.7
8.7
6.4
-
23.8
El
348.7
34.9
34.9
28.0
2.4
100.2
E2
400.5
.20
.25
.33
1.37
40.0
40.0
31.8
2.0
113.8
1.55
-------
Table 28
o
00
Formation Water Treatment Equipment Costs
Offshore Installations
1,000 Barrels Per Day Flow Rate
EQUIPMENT COSTS (Thousands of 1974 dollars)
Capital Costs
Annual i zed Costs
Capital
Depreciation
0 & M
Energy
Total Annual ized Costs
Al
101
10.1
10.1
6.7
-
26.9
B
143
14.3
14.3
11.6
1.5
41.7
C
176.3
17.6
17.6
14.3
1.5
51.0
El
373.3
37.3
37.3
29.7
3.3
107.6
E2
432.2
43.2
43.2
38.0
4.4
128.8
Cost of water disposal
$/bbl
.07
.114
.14
.30
.35
-------
o
vo
Table 29
Formation Water Treatment Equipment Costs
Offshore Installations
5,000 Barrels Per Day Flow Rate
(Thousands of 1973 dollars)
Al A2 B C
E2
Capital Costs
Option (a)
Option (b)
Option (c)
Annuali zed Costs
Capital & Depre-
ci ati on
Option (a)
Option (b)
Operation &
Maintenance
Energy
Total - Option (a)
Option (b)
Option (a)
Option (b)
47
1,452
432
9.4
290.4
4.32
0.94
14.66
295.66
Cost of
0.008
0.16
21
55
43
4.2
11.0
6.51
0.42
11.13
17.93
Water Disposal
0.006
0.0098
88
146
274
17.6
29.2
8.27
1.76
27.63
39.23
- $/bbl
0.015
0.022
131
204
423
26.2
40.8
12.23
2.62
41.05
55.65
0.023
0.031
74
117
157
14.8
23.4
6.96
1.48
23.24
31.84
0.013
.017
451
518
683
90.2
103.6
39.88
9.02
139.1
152.5
0.076
0.084
-------
Table 30
Formation Water Treatment Equipment Costs
Offshore Installations
10,000 Barrels Per Day Flow Rate
(Thousands of 1973 dollars)
Al A2 B C
E2
Capital Costs
Option (a)
Option (b)
Option (c)
Annual i zed Costs
Capital & Depre-
ciation
Option (a)
Option (b)
Operation &
Maintenance
Energy
Total - Option (a)
Option (b)
Option (a)
Option (b)
60
2,140
a
12
428
5.52
1.20
18.7
434.7
Cost of
0.005
0.117
31
68
66
6.2
13.6
8.28
0.62
15.1
22.5
Water Disposal
0.004
0.006
148
228
488
29.6
45.6
13.91
2.96
46.5
62.5
- $/bbl
0.013
0.017
206
1,626
708
41.2
325.2
19.33
4.12
64.7
348.7
0.018
0.096
108
161 1
259
21.6
32.2
10.12
2.16
33.9
44.5
0.009
0.012
563
,972
979
112.6
394.4
52.14
11.26
176
457.8
0.048
0.125
Not considered to be a viable alternative because of large space requirement.
-------
Table 31
Formation Water Treatment Equipment Costs
Offshore Installations
40,000 Barrels Per Day Flow Rate
(Thousands of 1973 dollars)
Al A2 B C
E2
Capital Costs
Option (a)
Option (b)
Option (c)
Annuali zed Costs
Capital & Depre-
ciation
Option (a)
Option (b)
Operation &
Maintenance
Energy
Total - Option (a)
Option (b)
Option (a)
Option (b)
a 60
a 98
a 102
12
20.4
18.60
1.20
31.8
40.2
Cost of Water Disposal
0.002
0.0028
355
1 ,780 1
880 1
71
356
33.60
7.10
111.7
396.7
- $/bbl
0.0077
0.027
448
,913
,254
89.6
382.6
, 42.04
8.96
140.6
433.6
0.01
0.030
170
230 2
369 1
34
46.0
15.90
3.40
53.3
65.3
0.004
.005
907
,354
,585
181.4
470.8
89.56
18.14
289.1
578.5
0.020
0.040
No estimate made - method considered to be impractical because of large space requirements.
-------
When produced water is treated and returned to the producing
formation for secondary recovery, the costs should not be
considered as a disposal cost, but rather as a necessary cost in
production of oil. When produced water cannot fce returned to the
formation for secondary recovery or for water flooding, the costs
for treating it and providing the injection equipment becomes a
legitimate disposal cost.
Generalized cost estimates for onshore disposal of produced
formation water were developed to include flow equalization tanks
for 1,000, 5,000 and 10,000 tarrels-per-day water production,
pumps sized for these flow rates and 700 pounds per square inch
pressure, and disposal wells of 3,000 foot depth. A maximum well
capacity of 12,000 fcarrels-per-day was assumed. In addition,
costs for this system include a lined pond to provide standby
capability for continuing production for seven days while pump
repairs are being made or the injection system is being worked
on. The capital costs and annualized costs for these systems are
contained in Tables 32 and 33.
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)
Other costs for reinjecting produced formation water have been
developed from field surveys conducted by the EPA during the
first half of 1976. The sites surveyed were selected as being
representative of reinjection disposal technology within the
various states. The actual data, which can be found in
Supplement B, was taken from data formats submitted by industry
for the selected sites and is presented for the most part without
major adjustment. In two cases, Pennsylvania and Texas/Louisiana
nearshore platforms, field data was not available and engineering
estimates were developed. The values for capital and operating
costs shown in Tables 32 and 33 are from regression analysis of
the field data.
112
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State
TABLE 32
Capital costs <»> for Onshore Disposal
by Reinjection of Produced Formation Water
From Field Surveys in Selected States
(Thousands of 1975 Dollars)
Description f of Sites Reiniection Capacity, bbl/day
California
Wyoming
Texas and
Louisiana
Land-based
Land-based
Land-based
6
11
14
10 100
74
80
40
1000
146
117
140
10,000
280
300
375
Pennsylvania Land-based
Case I
Land-based
Case II
Texas
Louisiana
Nearshore
Platforms
Nearshore
Platforms
(2),
(3),
CO
CO
CO
(4)
28 5^
15 24
400
400
190
61
500
470
470
110
1600
1680
(1) Regression analysis data points.
(2) Production sites without existing reinjection facilities.
(3) Production sites presently reinjecting fresh water.
(4) Engineering estimates.
113
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TABLE 33
Annual Operating*»> Costs for Onshore Disposal by
Reinjection of Produced Formation
Water From Field. Surveys in Selected States
(Thousands of 1975 Dollars)
State
California
Wyoming
Texas and
Louisiana
Description
Land-based
Land-based
Land-based
t of Sites Reinlection Capacityff bbl/day
10 100 1000 10,000
Pennsylvania Land-based
Case I
Land-based
Case II
6
11
14
(2) , (4)
(3) ,(4)
7.6
5
Texas
Louisiana
Nearshore
Platforms
Nearshore
Platforms
5.6
8.8
12.5
14
6.5
40
40
15.5
18.5
25
46
16.5
45
45
52
32
50
100
32
122
134
(1) Regression analysis data points excluding capital and
depreciation charges.
(2) Production sites without existing reinjection facilities.
(3) Production sites presently reinjecting fresh water.
(4) Engineering estimates.
As an alternative to no discharge - reinjection technology, cost
estimates were developed for discharge to navigable waters. The
subcategories of production facilities selected for separate
estimates were those described in Section IV, Industry
Subcategorization. The treatment technology selected for each
category was the most efficient type of treatment observed in
general use during the 1976 field survey.
Treatment technology for the stripper well category was selected
as a surge tank followed by chemical addition and ponds. The
steel surge tank has 2-10 day storage. The three unlined ponds
in series have a 5-foot operating depth and a retention time of
100-600 hours, depending upon the system's capacity. Annual
costs consist of: operation at 1-3 hours per day, maintenance at
5* of constructed value, electrical power at 4* per kilowatt
hour, chemical costs at 5 mils per barrel and capital plus
depreciation at 2051 of constructed value. The capital and
114
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operating costs for stripper well facilities in the size range
10-10,000 bbl/day are shown on Table 34.
Treatment technology for beneficial dischargers was selected as
surge tank, skim basin, chemical feed and gas flotation followed
by ponds. The surge tank has a 1-2 hour storage capacity and the
skim basin is provided with an automatic skimming device. The
gas flotation system uses induced air and the ponds have a
12-hour retention time. A standby pond of 48 hours retention
time is also provided. Annual costs consist of: operation at
6-12 hours per day, maintenance at 8* of equipment constructed
value, electrical costs at 40 per kilowatt hour and chemicals at
3 3/4 mils per barrel. The capital and operating costs for
beneficial dischargers in the size range 5,000-100,000 bbl/day
are shown on Table 35.
Treatment technology for the coastal platforms was selected as a
surge tank followed by chemical feed and gas flotation.
Additional platform space was assumed required to accommodate the
treatment system. Design criteria and costing methods were
patterned after the 1975 Brown and Root Report (3). The capital
and operating costs so devised for coastal platforms are shown on
Table 36. Details of cost estimating procedure for all
categories is available in Supplement "B".
TABLE 34
Cost Estimates for Treatment in Ponds and
Disposal by Discharge for Stripper Well Facilities
(Thousands of 1976 Dollars)
System Capacity Produced Water, Bbl/day
Cost Item 10 50 100 500 1000 5000 10,000
Construction 12 19.6 24 30.1 36 65.7 90
Operation &
Maintenance 5.6 7.5 8.7 13.8 18.8 38.1 53.2
115
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TABLE 35
Cost Estimates for Treatment by Gas Flotation
& Ponds & Discharge for Beneficial Dischargers
(Thousands of 1976 Dollars)
Cost Item
Construction
Operation &
Maintenance
System Capacity Produced Water, Bbl/day
500 1000 5000 10,000 25,000 50,000 100,000
92
32
96
37
155
72
198
85
289
137
425
220
600
343
TABL£ 36
Cost Estimates for Treatment by Gas
Flotation 6 Discharge for Coastal Platforms
(Thousands of 1976 Dollars)
Cost Item
Construction
Operation &
Maintenance
System Capacity Produced Water, Bbl/day
100 1000 5000 15,000 25,000
55
8
133
43
267
83
394
132
482
172
Offshore Sanitary Wastes
Cost estimates for biological systems utilized on offshore
platforms are for the aerobic digestion process or extended
aeration treatment plants. The estimates anticipate the use of a
system including a comminuter to grind the solids into fine
particles, an aeration tank with air diffusers, gravity clarifier
return sludge system and a disinfection tank.
Based on the design requirements stated in Table 24 costs were
developed for systems to serve 25 persons (2,000 gallons), 50
persons (4,000 gallons) and 75 persons (6,000 gallons). These
costs are contained in Table 37.
Energy Requirements for Operating Flotation Systems
Table 38 presents several estimates of horsepower requirements of
flotation systems for the three levels of production.
116
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Actual installations will probably comprise a mix of
manufacturers' units and the typical horsepower requirements will
be some weighted average of the values in Table 38. For the
purpose of estimating energy requirements, the average
requirements are assumed to be 15, 25, and 60 horsepower for the
5,000, 10,000 and 40,000 bbls per day production levels. (The
118 Hp. figure for the 40,000 bbls per day unit was rejected as
spurious - an incorrect linear extrapolation on a graph.)
Table 39 presents the calculations that translate these basic
horsepower requirements into total energy requirements.
One way to evaluate the energy requirements of flotation systems
is to compare their consumption with that of the oil production
associated with their use. Water production rates do not vary
regularly with crude oil production rates.
In some instances, the 5,000 bbl/day of produced water may be
associated with a crude oil production of only 5,000 bbl/day. In
other cases, crude production rates may be 50 to 100 times the
rate of water production or vice versa. Given these variation
and the variable products and costs of refining the crude oil, it
would be a meaningless exercise to attempt to estimate the net
BTU equivalent in terms of barrels of diesel oil for the oil
production associated with the typical water flows. One can,
however, usefully examine a range of possible levels of net
production to get a general impression of the relative energy
requirements of flotation systems. For example, it is reasonable
to assume that the 5,000 bbl/day water production could be
associated with a net energy production of anywhere from 50 to
50,000 bbl/day of diesel oil. Sindlarly the 10,000 and 40,000
bbl/day water flows could be associated with ranges of net diesel
oil equivalent flows from 100 and 100,000 and 400 and 400,000
bbl/day, respectively. Table 40 presents a summary of tae
flotation systems' energy consumption data as compared to such
associated oil production rates.
It is clear from Table 40 that the energy required for flotation
relative to the net energy being produced is very small. Even in
such a rare case as when water production is 100 times that of
crude oil production, the flotation energy requirements amount to
only 1.5 percent of the net energy being produced.
Nonwater-Quality Aspects
Evaluation of in-plant process control measures and waste
treatment and disposal systems for best practicable control
technology, best available technology, and new source performance
standards indicates that there will be no significant impact on
air quality. A minimal impact is expected, however, for solid
waste disposal from offshore facilities. The collection, and
subsequent transport to shore of oily sand, silt, and clays from
117
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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.
118
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TABLE 37
Estimated Treatment Plant Costs
For Sanitary Wastes For Offshore Locations
Package Extended Aeration Process
(Thousands of 1973 dollars)
Treatment Plant Capacity
(gallons/day)
2.000 4.000 6.000
Capital Cost 18,000 23,000 28,000
Total Annual Costs 6,010 7,660 9,360
capital 1,800 2,300 2,800
depreciation 1,800 2,300 2,800
operation & maintenance 2,050 2,600 3,200
energy and power 360 460 560
119
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Table 38
Estimated Horsepower Requirements
for the Operation of
Flotation Treatment Systems
Source
Level of
Production
bbl/day
5,000
10,000
40,000
I/ Brown
2J Wemco
3/ Letter
Brown
& Root I/
(Hp.)
14
25
118
and Root. I 11-11
WEMCO 2/ NATCO 3/ Rheem 4/
(Hp.) (Hp.) (Hp.)
13 6 20
21 13 25
61 47 50
Komi in 5/
Sanderson
Engring Corp.
(Hp.)
17-1/2
-
81-1/2
Data Sheet, F8-D2, dated 4-19-73
dated June 12, 1974
, from National Tank Com. to Mr. R. W.
Thieme, OTA, EPA, plus telephone communication, Friday, July 19,
1974, with Mr. E. Cliff Hill, NATCO
kj Telephone communication with Mr. Ken Sasseen, Rheem-Superior Corp.,
California.
_5/ Telephone conversation with Mr. Arthur Albohn, Komline, 201-234-1000
July 24, 1974.
120
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TABLE 39
Estimated Incremental Energy
Requirements Flotation Systems
5,000 bbl/day of water treated;
15 Hp. for 1 yr. = 3.35 x 1()8 BTU/yr.
1 bbl diesel oil = 6 x 106 BTU
15 Hp. - yr. = 55.8 bbl diesel oil/yr.
Assume 20% conversion efficiency, then 15Hp. - yr = 279 bbl
diesel oil/yr.
10,000 bbl/day of water treated;
464 bbl diesel oil/yr.
40,000 bbl/day of water treated;
1115 bbl diesel oil/yr.
121
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TABLE 40
Energy Requirements for Flotation Systems as
Compared to Net Energy Production
Associated with the Produced Water Flows
Produces Water
Flow - bbl/day
5,000
10,000
40,000
Assumed Level of Net Energy
Production in Diesel Oil
Equivalents - bbl/day
50 to 50,000
100 to 100,000
400 to 400,000
Energy for Flotation
Units Diesel Oil
Equivalents - bbl/day
0.76
1.27
3.05
122
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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. 1973. "Drilling Costs and Expenditures for
Exploration, Development and Production - 1972." American
Petroleum Institute, Washington, D. C.
3. Offshore Operators Committee, Sheen Technical Subcommittee
1975 "Potential Impact of EPA Guidelines for Produced Water
Discharges from the Offshore and coastal Oil and Gas
Extraction Industry," Prepared by Brown and Root, Inc.,
Hous ton, Texas.
123
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SECTION IX
EFFLUENT LIMITATIONS FOR
BEST PRACTICABLE CONTROL TECHNOLOGY
Based on the information contained in the previous sections of
this report, effluent limitations commensurate with best
practicable control technology (BPCT) currently available have
been established for each subcategory. The limitations, which
must be achieved not later than July 1, 1977, explicitly set
numerical values for allowable pollutant discharges of
oil/grease, chlorine residual and floating solids. BPCT is based
on control measures and end-of-pipe technology widely used by
industry.
Produced Water Technology
BPCTCA process control measures include the following:
1. Elimination of raw waste water discharged from free water
knockouts or other process equipment.
2. Supervised operations and maintenance on oil/water level
controls, including sensors and dump valves.
3. Redirection or treatment of waste water or oil discharges
from safety valve and treatment unit by-pass lines.
BPCTCA end-of-pipe treatment can consists of some, or all of the
following:
1. Equalization (surge tanks, skimmer tanks) .
2. Solids removal desanders.
3. Chemical addition (feed pumps) .
4. Oil and/or solids removal.
a. Flotation.
b. Filters.
6. Plate coalescers.
d. Ponds.
e. Gravity Tanks.
5. Subsurface disposal.
125
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Specific treatability studies are required prior to application
of a specific treatment system to an individual facility.
Procedure for Development of EPCT Effluent Limitations
The effluent guidelines limitations for produced water were
determined using effluent data for oil and grease. This data was
provided by the oil and gas producing industry, Department of the
Interior (U.S. Geological Survey), several States, EPA regional
offices, 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 average
operating efficiency and variability for various types of
treatment. The end-of-pipe technologies assessed for offshore
and coastal facilities were; flotation units, plate coalescers,
and fibrous media/loose media filters. For onshore facilities
that discharge the end-of-pipe technologies assessed were;
filters, flotation units, and ponds.
Information was also obtained from the industry that included
schematics, diagrams, and narratives of operation and maintenance
for 25 selected producing facilities.
A review of the effluent data showed a wide range of treatment
efficiencies from facility to facility with similar treatment,
variability between different treatment methods, and 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 factors considered uncontrollable
by current technology are:
1. Physical and chemical properties of the crude oil,
including solubility in water.
2. Suspended solids concentrations.
3. Fluctuations in flow rate.
4. Droplet sizes of the entrained oil (some control
possible).
5. Degree of emulsification (some control possible).
6. Characteristics of the produced water.
The factors considered controllable are:
126
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1. Opera-tor training.
2. Sample collection and analysis methods.
3. Process equipment malfunction--for example in
heater-treaters and their dump valves, chemical pumps
and sump pumps.
4. lack of proper equipment—for example, desanders or
large tanks.
5. Noncompatible operations.
The major objective of the detailed data analysis was to reject
inadequate treatment technology and select facilities utilizing a
sound technical rationale.
Offshore and Coastal - Initially, 138 treatment systems (94 off
Louisiana, 36 off Texas, and 8 off Alaska) were evaluated. The
treatment systems included gas flotation, plate coalescers,
fibrous media filters, loose media filters, and gravity
separation.
EPA survey data show that the majority of the simple gravity
systems produced highly variable effluents and were only
minimally effective in removal of oil. The data from the 36
gravity systems in Coastal Texas were derived from extreme
variations in analytical procedures. EPA attempts to verify this
data failed and all of this data had to be rejected.
Ten of the 94 treatment systems off Louisiana had 10 or less data
points; they were rejected. Eata from the 84 remaining units
were analyzed along with the data collected from 25 facilities
visited in the EPA verification study. The variance in treatment
efficiencies was reflected in the data for all types of treatment
methods. Both loose media and fibrous media filters are capable
of producing low average effluents, but because of O6M
difficulties the units are being phased out.
The plate coalescer and gas flotation treatment units in
Louisiana with greater than 10 data points were analyzed with
respect to O&M reliability. A comparison was made to determine
the effectiveness of physical separation of oil and ability to
handle uncontrollable variation in raw waste cnaracteristics.
The treatment efficiencies of plate coalescers were 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 produced water
constituents. When the parallel plate becomes plugged, frequent
back washing, manual cleaning, or replacement of plates is
127
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required. The effluent data showed highly variable oil
concentrations which indicated that both controllable and
uncontrollable factors significantly affected treatment
efficiencies. Therefore, plate coalescers were eliminated from
consideration.
The remaining 32 Louisiana treatment units were dissolved gas
flotation systems with chemical treatment. Historical data and
reports were available on nine of the units. Each was evaluated
to determine the acceptability of the data and the causes of
significant effluent variations. A review of the design
parameters for the various systems showed that the systems were
designed for the nraximum expected water production. None was
designed to handle overload conditions which may occur during
start-up, process malfunctions, or poor operating practices.
Data were rejected which followed unit installation (start-up),
when chemical treatment rates were modified, and when significant
equipment maintenance or other O6M procedures which affect normal
efficiency of the treatment unit was being performed. Treatment
data from some of the facilities analyzed were highly variable
with no apparent explanation. In this case, all of the treatment
data were accepted since it appeared highly unlikely that
efficiency could be normalized with better O&M procedures. More
likely tne varibility seen is attributable to the geological
formation. Units with influent data in excess of 200-300 mg/1
were suspect, since historical data indicated that high influents
could be attributed to dump valve malfunctions in the process
units. These units were investigated, and if the causes of their
high concentrations were found, they were rejected; otherwise
they were accepted. Units without historical data, but which had
variations similar to those which were rejected were evaluated
and if the variations were judged to be caused by controllable
malfunctions, they were eliminated. Three systems were rejected
because of reported process and treatment malfunctions, six
months of data were rejected from two other systems due to
operational and start-up problems. For the remaining units, data
points were eliminated since a strong indication of errors in
sample collection and analysis.
Additional data were obtained for a number of the units from the
oil companies, the Department of the Interior and the Brown and
Root report. These data were screened and evaluated in a manner
similar to that previously described. A total of 28 units, 27
off the Louisiana coast and one in Coastal Alaska were selected
as potentially usable facilities. These facilities represent
approximately 66 percent of the 41 facilities with the treatment
technology to qualify as BPCT. Of the 28 units, 12 have in
excess of 90 data points and one facility has 508 data points
covering an 18-month period.
The EPA field survey included nine of the 28 selected gas
flotation units off Louisiana. The results of the field survey
128
-------
supports the rationale used for selection of exemplary technology
and establishing the data base for determining effluent
limitations.
Upon completion of the technical evaluation of the data and
units, a detailed statistical analysis was conducted to determine
the form of the statistical distribution and to search for
anomalous means or variances which might indicate a need to
subcategorize based upon flow rates and space limitations. The
initial review indicated that the selected units data were
similar in distribution, and although the observed means and
variances differed from unit to unit, no basis for further
subcategorization was discovered.
The statistical analysis indicated that the data were log
normally distributed over most of the data. The various units
could be separated statistically into three groups: 1) five high;
2) 13 low; and 3) nine average. The means and 99 percent
probability of occurance levels were calculated for the low,
high, and total groups. Even though the group of 27 flotation
units could be broken down further (into 3 subgroups), it was
felt that at the current level of experience, with this
technology, the entire industry could not be expected to achieve
the same level of treatment as the very best units are now
achieving. Therefore, data from all 27 Louisiana units were
included in determining the effluent limits for oil.
Further analysis of the data base showed that some of the
reported data were composites (4 grab samples taken in a 24 hour
period, analyzed separately and the results averaged) and the
rest were individual grab samples. It was determined that the
grab samples had a higher variance than the composites and that
the compositing technique would result in more representative
results. The compositing would greatly decrease the effect of
sampling and analytical variance, which is potentially
significant in oil and grease monitoring.
The composited data were than analyzed separately and two
different techniques were used on the grab samples analysis to
simulate composite sampling.
A maximum monthly average was also calculated from the modified
(composite) data base. To utilize all of the data, two different
approaches were used to determine the monthly averages: 1) based
on dates of observed values - this method averages a given number
of samples (N) which are 30/N days apart, with the analysis being
performed on these averages; 2) based on randomized observed
values - this method divides the 2262 data points into 2262/N
groups, each group containing N randomly selected points. The
analysis is performed on the averages of each group.
129
-------
The first method is free of assumptions, but is limited in data
base since only 9 of the units had more than 2 data points per
month. The second method is simple and utilizes all of the data,
but ignores autocorrelation. Figure 10 is a plot of the results
of these two methods being applied to the data base. As can be
seen the plots begin separating at 4 samples per month because of
the effects of autocorrelation.
The results of the above analyses are as follows:
1. Long term average (1 year) - 25 mg/1
2. Maximum monthly average (weekly sampling) - 48 mg/1
3. Maximum day (composited) - 72 mg/1
The data in Figure 11 represent a cumulative plot of the modified
daily concentrations for the 27 Louisiana flotation units. The
plot is essentially linear over the last 90 percent of the range,
and the straight line represents a log normal distribution. Of
the 2,262 samples, 99 percent have oil concentrations less than
72 mg/1.
A statistical analysis was also conducted to determine the
distribution, and variance for the one flotation unit in Coastal
Alaska which treated produced waters. The average oil content in
the effluent is approximately 15 mg/1. The operation of this
unit appears very similar to the low group units for Louisiana.
Beneficial Use - Data for this sutcategory were collected from
nine facilities in Wyoming representing filters, flotation and
ponds as end-of-pipe technology. These facilities were visited
by the technical contractor and were considered to have well run
and well maintained operations. An analysis of the data from the
individual units showed no significant difference between the
three technologies used. In addition to this data, 292 data
points which represented sampling done throughout Wyoming by
Region 8 were analyzed.
Since there is no apparent difference in the first nine units,
this data (160 points) were combined and analyzed. This data
base has a mean of 10.0 and a daily maximum of 45 (both mg/1 of
oil and grease) .
The Region VIII data base analysis showed a mean of 7.2 and a
daily maximum of 45.
An additional analysis was run combining all the above data
points (452 points) and this data base had a mean of 8.2 and a
daily maximum of 44.
130
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Figure 10
99th Percentile of Monthly Average Oil and Grease
Concentration vs.
Frequency Of Sampling Each Month
» actual
*** randomized
Number of Samples Per Month (Days Betwaen Samples)
131
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FIGURE 11
Cumulative Plot of Effluent Concentrations of All
Selected Flotation Units in the Louisiana Gulf Coast Area
a
W
10 20 30 40 50 60 70 80 98 95 98 99
Per of Samples Equal To Or Less Than Ordinate Value
132
-------
Figure 12 represents a cumulative plat of the combined data base.
A slight modification was made to the analysis procedure
described for the offshore data. In order to have the data form
a straight line over the entire range, rather than the upper 80-
90% of the range, a constant is added to each data point so that
log (X+A) is plotted rather than log X. Since the affect of the
constant A is more pronounced for smaller values of X the result
is a straight line fit over the total range of data. Once the
99th percentile is determined for the distribution of X+A the
constant is subtracted and the resulting value is the best fit to
the distribution of X; this method is called the three parameter
log normal analysis.
Sanitary Wastes — Offshore and Coastal Manned Facilities With 10
or More People
BPCT for sanitary wastes from offshore manned facilities with 10
or more people is based on end-of-pipe technology consisting of
biological waste treatment systems (extended aeration). The
system may include a comminutor, aeration tank, gravity
clarifier, return sludge system, and disinfection contact chamber
or other equivalent system. Studies of treatability, operational
performance, and flow fluctuations are required prior to
application of a specific treatment system to an individual
facility.
The effluent limitations were based on effluent data provided by
industry to the U.S. Geological Survey. Chlorine residual, BOD,
and suspended solids concentrations for the biological treatment
systems were within the range of values which would meet fecal
coliform requirements.
The only limitation being set on sanitary wastes is for chlorine
residual. This requirement is set to control the fecal coliform
level in this effluent. Limits on BOD or suspended solids for
these wastes are not justified since the BOD and TSS content of
the produced waters are likely to be several hundred times
greater.
The limit for residual chlorine is greater than 1 mg/1, but as
close to 1 mg/1 as possible. The facilities for chlorination on
offshore platforms are much less sophisticated then typical
municipal treatment plants and the flows much more variable.
Therefore, it is felt that the standard residual chlorine limit
of 1 mg/1 plus or minus 40 % is unrealistic. There has been no
upper limit set because of a lack of valid data to be used to set
such a limit.
BPCT for sanitary wastes from small offshore facilities and
intermittently manned facilities is based on end-of-pipe
technology currently used by the oil and gas production industry
and by the boating industry. These devices are physical and
133
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100
90
80
70
60
50
40
30
:r 20
z
o
t—I
jj
LU
%
O
o
Ul
10
<.
UJ
a:
to
08
—i
i—i
o
X
45 10 20 30 40 50 60 70 «0 90 95
PERCENT OF SAMPLES EQUAL TO OR LESS THAN ORDINATE VALUE
Fig.12 - Cumulative Plot of Effluent Concentrations
or All Wyoming Data (values are plotted as %•+ 1.3)
98 99
134
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chemical systems which may include chemical toilets, gas fired
incinerators, electric incinerators or macerator-chlorinators.
None of these systems has proved totally adequate. Therefore,
the effluent limitations are based on the discharge technology
which consists 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.
Domestic Wastes - Offshore and Coastal
Since these wastes contain no fecal coliform, chlorination is
unnecessary. Treatment, such as the use of macerators, is
required to guarantee that this discharge will not result in any
floating solids.
Deck Drainage - Offshore and Coastal
BPCT for dec* drainage is based on control practices used within
the oil producing industry and include the following:
1. Installation of oil separator tanks for collection of deck
washings.
2. Minimizing of dumping of lubricating oils and oily wastes
from leaks, drips and minor spillages to deck drainage
collection systems.
3. Segregation of deck washings from drilling and workover
operations.
4. O&M practices to remove all of the wastes possible prior to
deck washings.
BPCT end-of-pipe treatment technology for deck drainage consists
of treating this water with waste waters associated with oil and
gas production. The combined systems may include pretreatment
(solids removal and gravity separation) and further oil removal
(chemical feed, surge tanks, gas flotation). The system should
be used only to treat polluted waters. All storm water and deck
washings from platform members containing no oily waste should be
segregated as it increases the hydraulic loading on the treatment
unit.
The limits for deck drainage are the same as for produced waters
offshore.
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Alternate Handling - Offshore and Coastal
Alternate handling of waste water may be necessary when equipment
becomes inoperative or requires maintenance. Waste fluids must
be controlled during these conditions to prevent discharges of
raw wastes into surface waters. Control practices currently used
in offshore and coastal operations are:
1. Waste fluids are temporarily stored onboard until the waste
treatment unit returns to operation.
2. Waste fluids are directed to onshore treatment facilities
through a pipeline.
3. Placing waste fluids in a barge for transfer to shore
treatment.
4. Waste fluids are piped to a primary treatment unit (gravity
separation) to remove free oil and discharged to surface
waters.
Drilling Muds
BPCT for drilling muds includes control practices widely used in
both offshore and onshore drilling operations:
1. Accessory circulating equipment such as shaleshakers,
agitators, desanders, desilters, mud centrifuges, degassers,
and mud handling equipment.
2. Mud saving and housekeeping equipment such as pipe and kelly
wipers, mud saver sub, drill pipe pan, rotary table catch
pan, and mud saver box.
3. Recycling of oil based muds.
BPCT end-of-pipe treatment technology is based on existing waste
treatment processes currently used by the oil industry in
drilling operations.
The limitations for offshore and coastal drilling muds are as
follows:
1. Water based and natural muds shall contain no free oil when
discharged.
2. Oil based and emulsion muds shall not be discharged to
surface waters. These muds are to be transported to shore
for reuse or disposal in an approved disposal site.
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The limitations for onshore drilling muds are as follows:
1. The muds shall be discharged to surface waters. These muds
are to be transported to and disposed of in an approved
disposal site.
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 as follows:
1. Cuttings in natural or water based muds shall contain no free
oil when discharged.
2. Cuttings in oil based or emulsion muds shall not be
discharged to surface waters. Cuttings should be collected
and transported to shore for disposal in an approved disposal
site.
The limitation for onshore drill cuttings areas follows:
1. No drill cuttings shall be discharged to surface waters.
These drill cuttings are to be transported to and disposed of
in an approved disposal site.
Well Treatment
Workover fluids other than water, or water based muds are to be
recovered and reused. Materials not consumed during workovers
and completions are to be transported to and disposed of in an
approved site.
The effluent limitations were determined using data supplied by
industry and service companies serving the oil producing
industry. The limitation for wastes from well treatment offshore
is: well treatment wastes shall contain no free oil when
discharged.
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Section IX
Bibliography
1. Offshore Operators Committee, Sheen Technical Subcommittee.
1974. "Determination of Best Practicable Control Technology
Currently Available to Remove Oil From Water Produced With
Oil and Gas." Prepared by Brown and Root, Inc., Houston,
Texas.
138
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SECTION X
EFFLUENT LIMITATIONS FOR
BEST AVAILABLE TECHNOLOGY ECONOMICALLY ACHIEVABLE
The application of best available technology economically
achievable is defined as improved O6M practices and tighter
control of the treatment process for the far offshore
subcategory. BATEA for the near offshore and coastal
subcategories are defined as subsurface disposal for produced
waters. BATEA for the onshore, beneficial use, and stripper
subcategories are the same as BPTCA. These effluent limitations
are to go into effect no later than July 1, 1983.
The limitations for all subcategories are the same as BPTCA for
drilling muds, drill cuttings, sanitary and domestic wastes, well
treatment, and produced sands. Additionally the BATEA limitation
for deck drainage in the near offshore subcategory is the same as
for BPTCA.
Near Off shore and Coastal Su beat egor i es - Produced Water
The BATEA limitations for produced water in the coastal and near
offshore subcategories is no discharge to surface waters. This
can be accomplished by reinjection or by end-of-pipe technologies
such as, evaporation ponds and holding pits (when -wastes are
transferred to shore) or injection to disposal wells. About H0%
of those producing facilities with no discharge use one of these
end-of-pipe technologies.
Existing no discharge systems were reviewed to select the best
technology for the purpose of establishing effluent limitations.
Holding pits were found to be the least desirable because of
frequent overflow, dike failure, and infiltration of salt water
into fresh water aquifiers. If properly constructed and lined,
evaporation lagoons may result in no discharge in arid and
semiarid regions. However, erosion, flooding, and overflow may
•still occur during wet weather. Disposal well systems which may
consist of skim tanks, aeration facilities, filtering systems,
backwash holding facilities, clear water accumulators, pumps, and
wells provide the best method for disposal of produced water.
These systems are equally applicable to onshore and offshore
operations and are the primary method used to dispose of produced
water on the California coast and in the inland areas.
Far Offshore Subcategory - Produced Water and Deck Drainage
The BATEA limitations for produced water and deck drainage in the
far offshore subcategory are based on the same end-of-pipe
technology as used for BPTCA. It is expected that the industry
will have gained sufficient experience in the reduction of raw
waste loads and operation of end-of-pipe technologies to improve
139
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•their operation by 1983. In order to define this level of
discharge a statistical analysis was carried out on the data from
the 27 flotation units, used to define BPTCA, to determine if any
units were significantly better in effluent quality than the
rest. A group of 10 flotation units were separated on that basis
and their data analyzed. The resulting BATEA limitations for oil
and grease are, 52 mg/1 daily maximum (composited) and 30 mg/1
maximum monthly average. Figure 13 is a cumulative plot of the
effluent concentrations of these 10 selected flotation units.
When the BPTCA limitations were derived, it was concluded that
they should be based on what was being achieved by all facilities
using the BPTCA.
This conclusion was reached on the basis of industry experience.
Since the industry will have, by 1983, 8 additional years of
experience . in waste abatement, there should be no significant
problems in attaining effluent qualities now being met by many
facilities.
140
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100
90
80
70
60
50
40
30
20
12
10
9
8
7
6
5
4
X*
5 10 20 30 40 50 60 70 80 90 95 9"8 99
PERCENT OF SAMPLES EQUAL TO OR LESS THAN ORDINATE VALUE
Fig. 13-Cumulative Plot of Effluent Concentrations
of Ten Selected Flotation Units in the
Louisiana Gulf Coast Area
99.8
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SECTION XI
NEW SOURCE PERFORMANCE STANDARDS
The effluent, limitations for new source performance standards are
the same as the 6ATEA limitations for each suJbcategory. The
facilities defined here will be built, after this regulation is in
affect. These facilities should therefore, be built with raw
waste load reduction and waste treatability in mind. As a
result, the number and magnitude of t>oth preventable and
unpreventable wastes should be minimized.
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SECTION XII
ACKNOWLEDGEMENTS
The initial draft report was prepared by the special Oil
Extraction Task Force which EPA Headquarters established to study
the oil and gas extraction point source category.
The following members of the Task Force furnished technical
support and legal advice for the study: Russel H. Wyer, Oil and
Special Materials Control Division (OSMCD), Co-chairman; H. D.
VanCleave, OSMCD, Co-chairman; William Bye, OSMCD; Thomas
Charlton, OSMCD; Harold Snyder, OSMCD; Kenneth Adams, OSMCD; Hans
Crump-Weisner, OSMCD; Arthur Jenke, OSMCD; R. W. Thieme, Office
of Enforcement and General Counsel; Jeffrey Howard, Office of
Enforcement and General Counsel; Charles Cook, Office of Water
Planning and Standards; Martin Halper, Effluent Guidelines
Division; Dennis Tirpak, Office of Research and Development;
Thomas Belk, Permit Programs Division; Richard Insinga, Office of
Planning and Evaluation; Stephen Dorrler, Edison Water Quality
Research Laboratory, Edison, N.J.
Martin Halper, Project Officer, Effluent Guidelines Division,
contributed to the overall supervision of this study and perpared
this Development Document. Allen Cywin, Director; Ernst Hall,
Deputy Director; Harold Coughlin, Branch Chief, and John
Cunningham, all Effluent Guidelines Division, offered guidance
during this program.
Special appreciation is given to Mary Lou Ameling, Charles Cook,
Richard Insinga, and Henry Garson for their contributions to this
effort.
In addition to the Headquarters EPA personnel. Regions V, VI, and
X were extremely helpful in supporting this study. Special
acknowledgement is made to personnel of the Surveillance and
Analysis Division, Region VI, for their dedicated effort in
support of the EPA Field Verification Study, and to Russ
Diefenbach of Region V who assisted with data acquisition for
onshore technology. Regions IV and VIII assisted in onshore data
acquisition.
Special appreciation is extended to the EPA Robert S. Kerr
Research Laboratory (RSKRL), Ada, Oklahoma, for its technical
support. RSKRL managed and conducted the entire 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
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contractor-operated analytical laboratories in the Gulf Coast
area.
Acknowledgement is made to Richard Krahl, Robert Evans, and Lloyd
Hamons, Department of the Interior, U.S. Geological Survey, for
their contribution to the EPA Field Verification Study in the
Coastal Louisiana area.
Many state offices assisted in the study by providing data and
assisting in field studies. Among those contributing: Alabama,
Arizona, Arkansas, California, Colorado, Florida, Illinois,
Louisiana, Missouri, Nebraska, Nevada, New Mexico, North Dakota,
Ohio, Pennsylvania, Utah, and Wyoming.
Our special thanks to Mrs. Irene Kiefer for her editorial
services. Appreciation is extended to the secretarial staffs of
the Oil and Special Materials control Division and the Effluent
Guidelines Division for their efforts in typing many drafts and
revisions to this report.
Appreciation is extended to the following trade associations and
corporations for their assistance and cooperation: American Oil
Company; American Petroleum Institute, Onshore Technical
Committee, Seth Abbott, Chairman; Ashland Oil, Inc.; Atlantic
Richfield Company; Brown and Root, Inc.; C. E. Natco; Champlin
Petroleum Company; Chevron Oil Company; Continental Oil Company;
Exxon Oil Company; Gulf Oil Company; Marathon Oil Company; Mobil
Oil Company; Noble Drilling company; Offshore Operators
Committee, Sheen Technical Subcommittee, William M. Berry,
Chairman; Oil Operators, Inc.; Phillips Petroleum; Pollution
control Engineers; Rheem superior; Shell Oil company; Sun Oil
Company; Texaco, Inc.; Tretolite Corporation; United states
Filters; Union Filter Company; and WEMCO.
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SECTION XIII
GLOSSARY AND ABBREVIATIONS
Acidize - To put acid in a well to dissolve limestone in a
producing zone, forming passages through which oil or gas can
enter the well bore.
Air/Gas Lift - Lifting of liquids by injection of air or gas
directly into the well.
Annulus or Annular Space - The space between the drill stem and
the wall of the hole or casing.
API - American Petroleum Institute.
API Gravity - Gravity (weight per unit of volume) of crude oil as
measured by a system recommended by the API.
Attapulgite Clay - A colloidial, viscosity-building clay used
principally in salt water muds. Attapulgite, a special
fullers earth, is a hydrous magnesium aluminum silicate.
Back Pressure - Pressure resulting from restriction of full
natural flow of oil or gas.
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 degrees Fahrenheit.
Bentonite - An additive used to increase viscosity of drilling
mud.
Blowcase - A pressure vessel used to propel fluids intermittently
by pneumatic pressure.
Blowout - A wild and uncontrolled flow of subsurface formation
fluids to the earth's surface.
Blowout Preventer (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.
Bottom-Hole Pressure - Pressure at the bottom of a well.
Brackish Water - Water containing low concentrations of any
soluble salts.
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Brine - Water saturated with or containing a high concentration
of common salt (sodium chloride): also any strong saline
solution containing such other salts as calcium chloride,
zinc chloride, calcium nitrate.
BS&W - Bottom Sediment and water carried with the oil.
Generally, pipeline regulations limit BS&W to 1 percent of
the volume of oil.
Casing - Large steel pipe used to "seal off" or "shut out" water
and prevent caving of loose gravel formations when drilling a
well. When the casings are set, drilling continues through
and below the casing with a smaller bit. The overall length
of this casing is called the string of casing. More than one
string inside the other may be used in drilling the same
well.
Centrifuge - A device for the mechanical separation of solids
from a liquid. Usually used on weighted muds to recover the
mud and discard solids;. The centrifuge uses high-speed
mechanical rotation to achieve this separation as
distinguished from the cyclone-type separator in which the
fluid energy alone provides the separating force. Also see
"Desander - Cyclone."
Chemical-Electrical Treater - A vessel which utilizes
surfactants, other chemicals and an electrical field to break
oil-water emulsions.
Choke - A device with either a fixed or variable aperture used to
release the flow of well fluids under controlled pressure.
Christmas Tree - Assembly of fittings and valves at the top of
the casing of an oil well that controls the flow of oil from
the well.
Circulate - The movement of fluid from the suction pit through
pump, drill pipe, bit annular space in the hole and back
again to the suction pit.
Closed-In - A well capable of producing oil or gas, but
temporarily not producing.
Coagulation - The combination or aggregation of semi-solid
particles such as fats or proteins to form a clot or mass.
This can be brought about by addition of appropriate
electrolytes. Mechanical agitation and removal of
stabilizing ions, as in dialysis, also cause coagulation.
Coalescence - The union of two or more droplets of a liquid to
form a larger droplet, brought about when the droplets
148
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approach one another close-by enough to overcome their
individual surface tensions.
Condensate - Hydrocarbons which are in the gaseous state under
reservoir conditions but which become liquid either in
passage up the hole or at the surface.
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 - Cyclong - 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
established field or reservoir.
Disposal Well - A well through which water (usually salt water)
is returned to subsurface formations.
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 separators, treaters, and other vessels for the purpose of
draining, or "dumping" a batch or oil or water.
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Emulsion - A substantially permanent heterogenous mixture of two
or more liquids which are not normally dissolved in each
other, but which are held in suspension or dispersion, one in
the other, by mechanical agitation or, more frequently, by
adding small amounts of substances known as emulsifiers.
Emulsions may be oil-in-water, or water-in-oil.
EPA - United States Environmental Protection Agency.
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 Vvell - A well which produces oil or gas without any means
of artificial lift.
Fluid Inlection - Injection of gases or liquids into a reservoir
to force oil toward and into producing wells. (See also
"Water Flooding.11)
Formation - Various subsurface geological strata penetrated by a
well bore.
Formation Damage - Damage to the productivity of a well resulting
from invasion of mud particles into the formation.
Fracturing - Application of excessive hydrostatic pressure which
fractures the well bore (causing lost circulation of drilling
fluids.)
Freewater Knockout - An oil/water separation tank at atmospheric
pressure.
Gas Lift - A means of stimulating flow by aerating a fluid column
with compressed gas.
Gas-Oil Ratio - Number of 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 Barr el - An oil-water separation vessel.
Header - A section of pipe into which several sources, of oil
such as well streams, are combined.
Heater-Treater - A vessel used to break oil water emulsion with
heat.
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Hydrogen Ion Concent.rat.ion - A measure of the acidity or
alkalinity of a solution, nornrally expressed as pH.
Hydrostatic Head - Pressure which exists in the well bore due to
the weight of the column of drilling fluid; expressed in
pounds per square inch (psi).
Inhibitor - An additive which prevents or retards undesirable
changes in the product. Particularly, oxidation and
corrosion; and sometimes paraffin formation.
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.
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 shoreline
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 - A measure of ability of rock to transmit a
one-phase fluid under condition of laminar flow.
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Pressure Maintenance - The amount of water or gas injected vs.
the oil and gas production so that the reservoir pressure is
maintained at a desired level.
Pump, Centrifugal - A pump whose propulsive effort is effectuated
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.
Shale - Fine-grained clay rock with slatelike cleavage, sometimes
containing an oil-yielding substance.
Shaleshaker - Mechanical vibrating screen to separate drilled
formation cuttings carried to the 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.
Stripper Well (Marginal Welljt - A well which produces such a
small volume of oil that the gross income therefrom provides
only a small margin of profit or, in many cases, does not
even cover actual cost of production.
Stripping - Adding or removing pipe when a well is pressured
without allowing vertical flow at the top of the well.
Tank - A bolted or welded atmospheric pressure container designed
for receipt, storage, and discharge of oil or other liquid.
Tank Battery - A group of tanks to which crude oil flows from
producing wells.
TDS - Total Disolved Solids.
TOC - Total Organic Carbon.
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Total Depth (T.D.) - The greatest depth reached by the drill bit.
Treater - Equipment used to break an oil - water emulsion.
TSS - Total Suspended Solids.
USC6 - United States Coast Guard.
USGS - United States Geological Survey.
Water Flooding - Water is injected under pressure into the
formation via injection wells and the oil is displaced toward
the producing wells.
Well Completion - Jn a potentially productive formation, the
completion of a well in a manner to permit production of oil;
the walls of the hole above the producing layer (and within
it if necessary) must be supported against collapse and the
entry into the well of fluids from formations other than the
producing layer must be prevented. A string of casing is
always run and cemented, at least to the top of the producing
layer, for this purpose. Some geological formations require
the use of additional techniques to "complete" a well such as
casing the producing formation and using a "gun perforator"
to make entry holes, the use of slotted pipes, consolidating
sand layers with chemical treatment, and the use of
surface-actuated underwater robots for offshore wells.
Well Head - Equipment used at the top of a well, including casing
head, tubing head, hangers, and the 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. ripe-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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TABLE 41
METRIC: TABLE
CONVERSION TABLE
MULTIPLY (ENGLISH UNITS) by TO OBTAIN (METRIC UNITS)
ENGLISH UNIT ABBREVIATION CONVERSION ABBREVIATION METRIC UNIT
acre ac
acre - feet ac ft
British Thermal
Unit BTU
British Thermal
Unit/pound BTU/lb
cubic feet/minute cfm
cubic feet/second cfs
cubic feet cu ft
cubic feet cu ft
cubic inches cu in
degree Fahrenheit °F
feet ft
gallon gal
gallon/minute gpm
horsepower hp
i nches i n
inches of mercury in Hg
pounds Ib
million gallons/day mgd
mile mi
pound/square
inch (gauge) psig
square feet sq ft
square inches sq in
ton (short) ton
yard yd
* Actual conversion, not a multiplier
0.405
1233.5
0.252
0.555
0.028
1.7
0.028
28.32
16.39
0.555(°F-32)*
0.3048
3.785
0.0631
0.7457
2.54
0.03342
0.454
3,785
1.609
(0.06805 psig +1)*
0.0929
6.452
0.907
0.9144 .
ha
cu m
kg cal
kg cal/kg
cu m/min
cu m/min
cu m
1
cu cm
°C
m
1
I/sec
kw
cm
atm
kg
cu m/day
km
atm
sq m
sq cm
kkg
m
hectares
cubic meters
kilogram - calories
kilogram calories/kilogram
cubic meters/minute
cubic meters/minute
cubic meters
1i ters
cubic centimeters
degree Centigrade
meters
1i ters
liters/second
killowatts
centimeters
atmospheres
kilograms
cubic meters/day
kilometer
atmospheres (absolute)
square meters
square centimeters
metric ton (1000 kilograms)
meter
154
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