EPA 660/2-74-037
MAY 1974
Environmental Protection Technology Series
Brine Disposal Treatment Practices
Relating to the Oil Production Industry
Office of Research and Development
U.S. Environmental Protection Agency
Washington D.C. 20460
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and
Monitoring, Environmental Protection Aqency, have
been grouped into five series. These five broad
categories were established to facilitate further
development and application of environmental
technology. Elimination of traditional grouping
was consciously planned to foster technology
transfer and a maximum interface in related
fields. The five series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
This report has been assigned to the ENVIRONMENTAL
PROTECTION TECHNOLOGY series. This series
describes research performed to develop and
demonstrate instrumentation, equipment and
methodology to repair or prevent environmental
degradation from point and .non-point sources of
pollution. This work provides the new or improved
technology required for the control and treatment
of pollution sources to meet environmental quality
standards.
EPA REVIEW NOTICE
This report has "been revieved "by the Office of Research and
Development, EPA, and approved for publication. Approval does
not signify that the contents necessarily reflect the views
and policies of the Environmental Protection Agency, nor does
mention of trade names or commercial products constitute
endorsement or recommendation for use.
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EPA- 660/2-74-037
May 1974
BRINE DISPOSAL TREATMENT PRACTICES
RELATING TO THE OIL PRODUCTION INDUSTRY
by
George W. Reid
LealeE. Streebin
Larry W. Canter
Justin R. Smith
School of Civil Engineering and Environmental Science
University of Oklahoma Research Institute
Norman, Oklahoma 73069
Contract No. 14-12-873
Project 14020 FVW
Program Element 1BB040
Project Officer
Fred M. Pfeffer
Robert S . Kerr Environmental Research Laboratory
P.O. Box 1198
Ada, Oklahoma 74820
Prepared for
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
For sale by the Superintendent of Documents, U.S. Government Printing Office Washington, D.C. 20402 - Price $2.'.K)
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ABSTRACT
Methodology is developed for the economic evaluation of environmentally
acceptable brine disposal systems . Specifically, a procedure is pre-
sented for determining total unit costs of alternative systems. These
are then compared in order to select the least expensive, legally-
permitted disposal processes. The text progresses from a broad and
simplified discussion of resources economics to the more specific sub-
jects of disposal mechanisms and disposal cost analyses. Methods are
included for obtaining the necessary information for use in the analyses.
A listing is made of state regulatory agencies and their exact roles in
administering brine disposal policies .
This report was submitted in fulfillment of Project No. 14020 FVW,
Contract No. 14-12-873, by the University of Oklahoma Research
Institute under the sponsorship of the Environmental Protection Agency.
11
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CONTENTS
Page
Abstract ii
List of Figures vii
List of Tables ix
Acknowledgments x
Sections
I INTRODUCTION 1
II BRINE POLLUTION 5
STATE AND FEDERAL REGULATIONS 5
EFFECTS OF SALINITY 5
EFFECTS OF NONIONIC COMPONENTS 6
III BRINE DISPOSAL 8
CONSIDERATIONS IN SELECTING METHODS 8
GATHERING SYSTEM 9
Pipe Sizing 11
Materials 11
Scale Removal 11
Pumps 13
DIRECT DISCHARGE 14
EVAPORATION PONDS 14
Evaporation Rate 16
Design Considerations 19
Operation 21
INJECTION 21
Design Considerations 23
Selection 23
Installation 25
Materials 31
Testing 32
111
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Section Page
OPERATIONAL CONSIDERATIONS 33
Treatment 33
Injection Pressure 34
Remedial Measures 34
Detection of Salt Pollution 35
IV BRINE WATER TREATMENT 39
DEGREE OF WATER TREATMENT 41
ANALYTICAL TESTS 41
FORMATION PLUGGING AND SCALING 43
DEPOSITS 44
Calcium Carbonate (CaCO.J 44
Magnesium Carbonate (MgCO.,) 46
Hydrated Calcium Sulfate (CaSO4)—Gypsum 46
Barium Sulfate (BaSO.) 47
Iron Deposits 47
Biological Deposits 48
TREATMENT REQUIREMENTS FOR SCALE
PREVENTION 48
CORROSION 49
PREVENTION OF CORROSION 51
TREATMENT SYSTEMS 52
Closed System 52
Open System 54
OIL REMOVAL 54
AERATION AND DEGASIFICATION 55
COAGULATION AND SEDIMENTATION 57
FILTRATION 58
Slow Sand Filters 59
Rapid Sand Filters 59
IV
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Sections Page
V ANALYSIS OF DISPOSAL ALTERNATIVES 62
ANALYSIS FOR DIRECT DISCHARGE OR
CONVEYANCE 63
DIRECT DISCHARGE ANALYSIS 63
DIRECT DISCHARGE CALCULATIONS 64
DATA SUMMARY 65
COST PROCEDURE FOR DIRECT DISCHARGE 66
SUPPLY LINE COST 66
PUMP STATION COST 69
TOTAL DIRECT DISCHARGE SYSTEM COST
(PIPELINE + PUMPING) 71
ANALYSIS FOR EVAPORATION POND OR PIT 73
EVAPORATION POND 73
EVAPORATION POND ANALYSIS 75
DATA SUMMARY 80
EVAPORATION POND SYSTEM COST ANALYSIS 82
TOTAL EVAPORATION SYSTEM COSTS
(EVAPORATION POND + PIPELINE + PUMP) 84
INJECTION 84
DESIGN LIMITATIONS ON CASING AND TUBING 87
INJECTION WELL FIELD DESIGN PROCEDURE 88
FLUID MECHANICS (SEE APPENDIX D FOR
DERIVATIONS) 88
DISTRIBUTION PIPING--CEMENT-LINED 92
INJECTION PUMP AND POWER REQUIREMENTS 93
INJECTION WELL FIELD COST ESTIMATES 94
OTHER EQUIPMENT 98
INJECTION SYSTEM CAPITAL AND ANNUAL COST 98
INJECTION COST SUMMARY 105
TOTAL INJECTION SYSTEM COST (INJECTION
WELL + PIPELINE + PUMPING) 105
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Sections Page
WATER TREATMENT FOR BRINE DISPOSAL 105
WATER TREATMENT ANALYSIS 108
DESIGN ANALYSIS 109
SELECTION OF BEST ALTERNATIVE 115
DEFINITION OF TERMS 116
VI IMPROVEMENTS TO INDIVIDUAL DISPOSAL 118
SECONDARY RECOVERY 118
MINERAL BY-PRODUCT RECOVERY 120
VII REFERENCES 124
VIII APPENDICES 131
VI
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FIGURES
No^ Page
1 Oil production-disposal scheme 10
2 Map of annual net evaporation in inches 17
3 Typical plan and sections for brine disposal ponds 20
4 Open and closed hole injection well completions 27
5 Typical injection well completions 30
6 Typical oilfield brine disposal scheme (Bayou Sorrel
SWD system--Shell) 53
7 Sectional view of skim tank 56
8 Rapid filter and accessory equipment 61
9 Cost of plastic or cement lining of pipe in dollars
per foot versus outside diameter of pipe in inches 67
10 Cost of installed centrifugal pump and motor in
dollars per horsepower versus brake horsepower 70
11 Estimated operation and maintenance cost for pump
station or well field in dollars per year versus daily
flow rate in gallons per day 72
12 Depth of precipitate per foot of solution in feet per
year versus salinity of water in thousands of parts
per million 77
13 Evaporation pond surface area in acres versus annual
input depth in feet for determining the depth of
precipitate deposited in one year for various daily
rates of input 78
14 Dike volume in cubic yards per linear yard versus
dike height in feet 81
15 Maximum tubing inside diameter in inches versus
depth of well in feet 89
16 Friction factor versus Reynolds number 91
17 Cost of wellhead equipment in dollars versus tubing
outside diameter in inches 95
18 Injectivity test cost in dollars versus depth of well
in feet 96
19 Cost of water storage facilities in thousands of dollars
versus water storage in millions of gallons 99
20 Pre-injection waste treatment scheme
VII
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No. Page
21 Cost of treatment plant in dollars versus plant
capacity in gallons per day 111
22 Annual cost of operation of injection water treatment
plant in dollars versus quantity of water treated in
gallons per day 113
23 Region rating code 1 233
24 Region rating code 2 234
25 Region rating code 3 235
26 Region rating code 4 236
27 Region rating code 5 237
28 Region rating code 6 238
via
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TABLES
No. Pa£
1 COMPARISON OF SEAWATER AND OILFIELD BRINE 1
2 STATE CRUDE PRODUCTION AND TAXATION 3
3 SALINE WATER TOLERANCES 6
4 PUBLISHED DATA ON PIPE GENERALLY USED IN
SALT WATER GATHERING SYSTEM SERVICE 12
5 SUMMARY OF DIRECT DISCHARGE DISPOSAL 15
6 SUMMARY OF EVAPORATION POND INFORMATION 22
7 COMMON IMPURITIES IN BRINE 42
8 TREATMENT OPERATIONS 107
9 UNDESIRABLE WASTE CHARACTERISTICS AND
REMOVAL OPERATIONS 108
10 WATERFLOODING ADVANTAGES AND DISADVANTAGES 119
11 MIDLAND BRINE CONSTITUENTS 120
12 DOLLAR VALUE OF DISSOLVED CHEMICALS A BRINE
SHOULD CONTAIN PER 1 MILLION POUNDS (2,840 bbl)
OF BRINE PRODUCED FROM A GIVEN DEPTH 121
13 AMOUNT OF ELEMENT PER 1 MILLION POUNDS OF
BRINE NECESSARY TO PRODUCE CORRESPONDING
CHEMICAL PRODUCT WORTH $250 121
14 BRINE QUANTITIES 122
15 RRC ZONES 224
16 WELL COST VARIATION WITH HOLE DIAMETER 232
IX
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ACKNOWLEDGMENTS
This investigation was supported by Grant No. 14-12-873 from the
Water Quality Office, Environmental Protection Agency, for which we
express our sincere appreciation.
The many contributions of those connected with the oil industry as well
as oil regulating agencies throughout the United States is gratefully
acknowledged, along with the invaluable assistance of the University
of Oklahoma School of Civil Engineering and Environmental Science
and the University of Oklahoma Research Institute.
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SECTION I
INTRODUCTION
As an average, 2-3 barrels of brine are produced per barrel of oil (the
actual range may be negligible volumes to over 100 bbl/bbl oil) . This
represents 20-30 million bbl/day brine production in the United States.
While there have been rare instances of potable oilfield brines, most
are highly saline. The major salts contributing to brine salinity are
-2 -1 -1
the sulfates (SO. ), bicarbonates (HCO, ), and chlorides (Cl ) of
+ +2 +7
the cations sodium (Na ), calcium (Ca ), and magnesium (Mg ) . The
concentrations of these and other constituents normally found in oilfield
brine are compared to those of seawater in Table 1.
Table 1. COMPARISON OF SEAWATER AND OILFIELD BRINE1'3
Na+1
K+1
Ca+2
Mg+2
cr1
Br"1
r1
HCO ~1
_32
so4 2
Seawater
(MR/I)
10,600
400
400
1,300
19,000
65
0.05
7
2,700
Oilfield Brine
(mg/1)
12,000-150,000
30- 4,000
1,000-120,000
500- 25,000
20,000-250,000
50- 5,000
1- 300
0- 1,200
0- 3,600
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As an indication of the important domestic geographic areas, state oil
production and tax figures are presented in Table 2.
The two basic types of oil producers are the majors (often diversified
conglomerates) and the independents. Generally, the majors are inte-
grated corporations having multibillion-dollar assets. They tend to
engage in all aspects of petroleum operations: exploration, production,
transportation, refining, and distribution. Operations cover offshore
and onshore drilling on a worldwide scale. Chase Manhattan Bank lists
a group of 27 major oil corporations whose 1969 operations accounted
for approximately 70% of all the crude oil produced in the United States
and nearly 60% of the total output of the rest of the world. '
The second type of oil operations involves the activities of thousands of
independent oil companies. As a general rule these companies operate
in the North American Continent--mainly in the United States. With
regard to economic size and operation, independents tend to be much
smaller than majors . Operations are directed almost exclusively to
exploration and production. While independents produce a substantial
quantity of the oil used in the United States, perhaps their largest con-
tribution is in the field of exploration. Approximately 85% of the domestic
exploratory wells completed in the United States are drilled by the inde-
pendents . The independents often resort to financial arrangements
such as promotional speculation, in which a package operation is funded
by speculators. In exchange for providing a portion of the expenses, a
driller may trade a percentage of the profit, such as 25% of the strike.
Published information reveals that approximately 70% of the operator
risk capital is obtained from outside investors.
Much of the activity of the independent producers is termed stripper
•well operation, meaning that the maximum output per well is < 10
barrels per day (special legislation which restricts production to this
level is an exception to the definition) . In 1969 there were a total of
358,000 stripper wells which produced 454 million barrels of crude oil
fj
(an average of 3. 5 barrels per well per day) .
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Table 2. STATE CRUDE PRODUCTION AND TAXATION
(1967 or 1968 Statistics)
Statea
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Florida
Illinois
Indiana
Kansas
Kentucky
Louisiana
Maryland
Michigan
Mississippi
Missouri
Montana
Nebraska
Nevada
New Mexico
New York
N. Dakota
Ohio
Oklahoma
Pennsylvania
S. Dakota
Tennessee
Texas
Utah
Virginia
W. Virginia
Wyoming
Crudeb
M. bbl
7.3
74.1
2.4
21.1
460.9
31.9
1.6
56.4
10.1
94.5
15.5
817.4
.2
13.7
58.7
0
48.5
13.4
.2
128.6
2.0
25.0
9.9
223.6
4.4
.2
0
1133.4
23.5
0
3.6
144.2
Prod, tax
%
.4
6.3
0
.8
4.6
.4
1.9
0
.2
.2
0
33.8
0
.4
3.0
0
2.3
.5
0
5.3
0
3.4
0
10.2
0
0
0
18.8
.7
0
1.0
.2
Pet. taxd
%
21
56
--
23
17
16
18
16
19
15
19
51
14
16
28
16
26
38
--
28
7
19
24
29
16
23
24
40
16
19
17
21
Amt. pet.
state tax
$M
100.0
33.9
--
66.1
798.8
54.5
194.0
275.2
144.0
55.2
86.9
355.3
90.5
237.8
90.4
97.5
27.2
52.1
--
60.8
300.0
19.3
274.0
126.6
287.5
18.8
122.4
513.5
29.7
123.5
46.5
14.3
rState
Production crude oil, annual (million barrels)
j% state revenue consisting of total petroleum production tax
% state revenue consisting of total petroleum tax
Amount total petroleum state tax (million dollars)
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The combined services of the majors and independents currently supply
Q
approximately 75% of the total energy requirements of the United States.
Considering the modes and areas of operation of the majors and independ-
ents , a rather interesting configuration seems to be inferred linking pro-
duction with demand, The majors, by definition, supply petroleum
products to their consumers in usable form via the refining and distribu-
tion functions they perform. These companies bring the crude oil from
production sites to the refineries by pipelines, trucks, railcars, ocean
tankers, or a blend of these transport vehicles. However, approximately
15% of American oil production comes from production sites of the inde-
pendents in the 32 oil-producing states, and roughly 85% of the total
exploratory drilling is done by independents. Combining these figures
implies that (assuming a successful well is equally likely for an inde-
pendent as for a major) much of the supply of American production
results from the initial exploratory efforts of the independents.
The implication is that, while almost all the oil used in the United States
has been processed by at least one of the majors, of the 80% produced
domestically, 15% has come from independent production, and 85% of
the burden for discovering the remaining domestic production has come
from the exploratory efforts of the independents. Further, if it is recog-
nized that oil in place has no more value than gold or uranium in place—
which is zero in reality—then the contribution of the independent is not
quite so overwhelmed by the activities of the majors .
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SECTION II
BRINE POLLUTION
STATE AND FEDERAL REGULATIONS
Prior to 1935, indiscriminant discharge of oilfield brine was common
practice. Thereafter, federal and state legislation and policy impacted
brine disposal. In general, oil-producing states regulate brine disposal
activities within their respective borders. The U.S. Environmental
Protection Agency (EPA) can, under certain conditions, instigate civil
action in the event of brine pollution.
A listing of state agencies responsible for regulating oil and gas is
found in Appendix A. The information was gathered through corre-
spondence with each of the 50 states from January to June, 1971.
Entries have been divided into five categories for each state: state
oil regulatory agency; publication of regulations (most recent title and
date); other state agencies assisting in oil production and brine dis-
posal; published allowable disposal methods; and disposal permit costs.
Because of reoccurring changes in state and federal legislation, opera-
tors who are contemplating brine disposal would be well advised to
obtain current revisions to state regulations, EPA's policy on subsur-
Q
face disposal, and the Federal Water Pollution Control Act.
EFFECTS OF SALINITY
The high salinity of most oilfield brines, as measured by total dissolved
solids, is caused by soluble salts. The major species have been listed
in Table 1. Some of these inorganic ions have adverse effects on animal
and plant life. Upper limits for human drinking water established by
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the USPHS are chloride (250 mg/1 Cl) , sulfate (250 mg/1 SO4) , and total
dissolved solids (500 mg/1) . In the case of some brines, 1 barrel could
cause over 700 barrels of fresh water to exceed the USPHS chloride
3
limit. The taste threshold of sodium chloride is about 500 mg/1 Cl,
meaning that a salt taste was identified at this concentration and higher
(actual range for individuals is 120-1200 mg/1 Cl) . Magnesium con-
centrations in excess of 125 mg/1 Mg can exert on humans a laxative
effect. Livestock tolerances to brine depend upon the concentration
and composition of the salinity and the availability of alternative sources
of fresh water. For adult animals, the upper safe limits for salinity
composed mostly of NaCl are presented in Table 3.
Table 3 . SALINE WATER TOLERANCES
Species
Poultry
Swine
Horses
Cattle
Sheep
Total Soluble
Salts (mg/1)
2,860
4,300
6,500
10,000
13,000
EFFECTS OF NONIONIC COMPONENTS
In addition to salinity, certain nonionic materials are common to oilfield
brines, such as oil, dissolved organics, and dissolved gases. Some of
these are toxic, and others are detrimental to surface water resources .
For example, oil may interfere with the transfer of oxygen from the
atmosphere into the water (essential for fish life) , coat birds and fish,
impart an objectionable taste to fish, exert a direct toxic action on some
organisms, or interfere with the fishfood organisms in the natural food
-------
cycle. Oil can adsorb onto clay particles, settle to the bottom, and
remain as a continuing source of pollution. Fish can suffer from
depletion of dissolved oxygen brought about by chemical oxidation of
dissolved gases such as hydrogen sulfide or biological oxidation of
petroleum products.
Some testing has been performed with oils to determine general toxicity
levels. These levels vary according to the species involved, and the
conditions of exposure, but, in general, aromatics are the most toxic
of the usual oil constituents, Naphthenes and olefins are intermediate
in toxicity, and straight paraffins are the least toxic. Within the above
general groups , the low-boiling aromatics and the smaller molecular
constituents are the most toxic.
It is difficult to gauge the pollutional significance of the oil which
accompanies a brine released to surface water. Oilfield wastewaters
contain as much as 0.1-0.33% oil by volume. Although dissolved gases
and components of the oil are potentially hazardous, these substances
tend to dissipate before they accumulate and reach toxic levels. Should
oil accumulate to a concentration of 3-5 mg/1, freshwater fish which are
especially sensitive to oil components may begin to experience toxic
effects. In 1963, petroleum operations accounted for 44% of the fish
killed by industrial pollution and 14% of the fish killed by industrial/
municipal pollution.
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SECTION III
BRINE DISPOSAL
CONSIDERATIONS IN SELECTING METHODS
Once-common brine disposal practices which are now illegal include
indiscriminant surface discharge, controlled release to streams at high
flow, and impoundment in unlined evaporation/seepage pits. These
early methods have resulted in pollution of surface and groundwaters
through salt seepage and surface scarring over large land areas.
Selection of a disposal method depends on several considerations ,
beginning with the legal specifications set forth by the state regulatory
agency (see Appendix A) . In most states, the operator must apply for
a disposal permit (at no cost or a small fee) prior to initiating brine
disposal. The application provides for a statement by the regulatory
agency as to suitability, legality, size, and location of the proposed
disposal method. In this way, the state maintains up-to-date records
on disposal operations and is assured a margin of safety with protec-
tion of fresh water resources .
State disposal records are available to operators and contain extensive
information on the location, size, and type of geologic formations en-
countered at each well location. The legal responsibility for develop-
ing, operating, and abandoning a disposal operation rests with the
individual operator, who must be familiar with current state revisions
on the subject.
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The operator must then choose among the several disposal methods
permitted by the state. Site conditions are important considerations:
soil types, geology and hydrology, formation characteristics, and well
penetrations in the vicinity. For example, abandoned, improperly-
plugged wells represent avenues of brine movement from the receiving
formation to freshwater aquifers and even surface water.
Economic considerations are then superimposed. The operator must
adopt a plan at the initial stage of reservoir development which will
effectively deal with an initially high rate of oil production, gradually
decreasing, and an initially low rate of brine production, gradually
increasing. This decision may involve a multimillion dollar combined
operation lasting in excess of 30 years .
GATHERING SYSTEM
The production/disposal system is illustrated in Figure 1. The flow-
lines and related equipment originating at the oil separator constitute
the beginning of the disposal process.
Three modes of gathering systems are possible: by gravity, by pres-
sure, or via a combination of the two. A gravity gathering system uses
no pumps, and flowlines conform to the natural drainage patterns of the
land. The pressure system does not require as extensive a topographic
survey because pumps supply the main driving force. Probably the
most logical design would be a combination of the two systems, taking
advantage of natural drainage as well as reducing the number of flow-
lines where topography is unfavorable.
The gathering system should be designed and equipped not only to
withstand the corrosive characteristics of brine but also to alleviate
potential scaling which, along with oil, is most likely to accumulate in
the high points. Where arches are unavoidable, vents should be used.
These can be constructed from a tee in the line with a riser above the
hydraulic gradient.
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1 Oil Reservoir 9
2 Producing Well 10
3 Test Separator 11
4 Production Separator 12
5 Flow Treater 13
6 Stock Tank 14
7 Oil Gathering Line 15
8 Gas Gathering Line -^
Brine Disposal Tank
Filter
Brine Disposal Well
Circulating Pump
Gas Meter
Chemical Injection
Emergency Brine Pit
Diked Inclosure
Figure 1. Oil Production-Disposal Scheme.
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Pipe Sizing
Maximum expected flow rates , available head, and head loss due to
friction are criteria from which pipe sizing is determined. Future
brine production must be carefully estimated since an increase in line
capacity is difficult to obtain.
Materials
The choice in materials for saltwater piping depends on the operating
pressure and temperature, the corrosive characteristics of the brine,
the life of the system, and the relative costs involved. In most systems
corrosion is the predominant criteria. Table 4 shows the type and ser-
vice conditions of pipe used in saltwater gathering systems of the East
Texas Salt Water Disposal Company. Savings in time and labor are
possible where plastic pipe can be used. An example is a 12-mile
installation of 3- and 4-inch polypropylene pipeline in the Person-
Panna Maria field in Texas . The line was completed in 11 days by a
three-man crew and heat-fusion was used to weld the joints in less than
1-1/2 minutes each.
The East Texas Salt Water Disposal Company has had experience in the
use of several different types of pipe, including asbestos-cement-lined,
17
cast iron, and plastic. The cast iron pipe was lined with a special
Portland Cement mix and seal-coated on the exterior with coal tar .
Asbestos-cement was used almost exclusively, but cast iron was pre-
ferred for lines requiring an excess of 200 psi. The asbestos-cement
pipe was resistant to brine corrosion but was rather fragile and re-
quired considerable care in installation. The cement-lined pipe had
the disadvantages of large variances in the internal diameter and the
possibility of damaging the lining, particularly while coupling the
joints .
Scale Removal
At regular time intervals, scale removal from the internal surfaces of
pipe is required. The most common method is to flow a "scraper" or
11
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Table 4. PUBLISHED DATA ON PIPE GENERALLY
USED IN SALT WATER GATHERING SYSTEM SERVICE
17
Type of Pipe
Nominal
Size, Inches
Working Pressure, Psi Applicable
Rated at 80° F Rated at~150° F Service
Steel
Schedule 40
Grade A 2-12 incl.
Continuous-weld
and lap-weld 2-12 incl.
Cement-lined 2-12 incl.
Plastic-lined 2-12 incl.
Asbestos Cement
Class 100 3-12 incl.
Class 150 3-12 incl.
Class 200 3-12 incl.
150-ft. head 3- 8 incl.
Plastic
Butyrate 2
Butyrate 3
Butyrate 4
Vinyl 2
Vinyl 3
Vinyl 4
Fiber-reinforced epoxy 2
Fiber-reinforced epoxy 3
Fiber-reinforced epoxy 4
750- 490
750- 490
750- 490
100
150
200
65
102
73
70
133
103
98
500-1,000
350-1,000
200- 500
1,900-910
750-490
750-490
750-490
100
150
200
65
20
11
11
44
32
29
360-775
270-775
150-360
Noncorrosive
Noncorrosive
Corrosive
Corrosive
Corrosive
Corrosive
Corrosive
Corrosive
Corrosive
Corrosive
Corrosive
Corrosive
Corrosive
Corrosive
Corrosive
Corrosive
Corrosive
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"pig" through the line, introducing and removing it at scraper traps.
Types vary, but the most common are the steel-ball, chained rubber
ball, cementing plug with trailing wire-brush, go-devil with lead-end
18
knives and cutter wheels, and the spiralbrush. Scraper traps are
placed at strategic locations, such as the connection to a tank battery
or a point of line size change. Care must be taken to prevent spilling
brine when opening a trap. In cases where scrapers are not effective,
it becomes necessary to either acidize the line or dismantle it and
mechanically remove the scale. Acid has the disadvantage of attacking
steel, cement-lined, and asbestos-cement pipe.
Pumps
Because they can handle relatively large volumes of fluid at low pressures,
centrifugal pumps are used extensively in saltwater gathering systems.
They are easily adaptable to electric motors, easily maintained, and can
operate under a shut-in head if necessary. Experience obtained in the
East Texas oilfield has indicated that attention to suction conditions is
one of the most critical considerations of design . Inadequate filling of
the suction can seriously erode or cause cavitation of an impeller in a
matter of days . Flooded suctions have been found to pay for the increased
costs of installation by savings in maintenance cost. The suction line
should be a straight run and as short as possible, with the line size at
least twice that of the pump suction inlet.
Corrosion-resistant pump parts are also a critical consideration in brine
systems. The metallic elements used in pump construction should be
closely related in the electromotive series; otherwise corrosion will take
place by galvanic action. Two examples of the metal combinations used
in a centrifugal pump for brine service are: all-bronze pumps with monel
shafts and packing sleeves, and cast-iron cases with aluminum/bronze
impellers. Brand name alloys, such as Ampcoloy and Worthite, have
1R
also given excellent service.
13
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DIRECT DISCHARGE
In a very limited number of cases the quality of oilfield brine is such that
direct utilization or legal discharge to surface water is possible with little
or no treatment. Examples can be found in Wyoming and Southern Cali-
fornia where the brine is used for irrigation and livestock watering.
For economic reasons, brine discharge to tidewater or to the ocean is
limited to operators in relatively close proximity to coastlines. In addi-
tion , coastal states such as California are drafting effluent limitations on
ocean discharges for many of the common constituents of oilfield brine
(e.g. , phenolics, suspended solids, metals, ammonia, and extractable
oil) . Studies of desalinization brines suggest that discharges to
shorelines (especially bays and estuaries) could adversely affect the
marine environment if circulation patterns either channel harmful mater-
ials along coastlines to important marine habitats or hinder the rapid
19
dilution of toxicants necessary to prevent fatality in fish and shellfish.
Because of current controversy over direct discharge, the operator is
advised to contact the appropriate state regulatory agency before
attempting such a system. Table 5 summarizes the advantages and
disadvantages of direct discharge disposal.
EVAPORATION PONDS
The evaporation pond or pit is a surface handling mechanism which,
when properly constructed and operated, relies on the atmosphere to
concentrate brine by removal of water vapor. Major producing states
are viewing evaporation pits with disfavor because of a history of faulty
design and operation. For example, Texas and Oklahoma have outlawed
their usage for brine disposal. Ponds improperly constructed are
"seepage" pits and result in the formation of pockets of salt in the soil
which slowly migrate to groundwater via leaching and percolation and
may cause pollution for hundreds of years .
14
-------
Table 5. SUMMARY OF DIRECT DISCHARGE DISPOSAL
Advantages
May be very inexpensive to 1
build and operate.
May require minimum treat-
ment.
2,
Is not restricted by the
amount of brine it can
handle. 3,
Does not require extensive
geohydrologic analysis nec-
essary to ascertain suitable 4,
disposal aquifer.
May be mixed with other
water and diluted to a 5,
quality which is
acceptable for agricul-
tural and cooling uses.
6.
Does not depend on evap-
oration rate.
Disadvantages
Impractical for long distance
to discharge site or where
rough terrain boosts pipe-
line and pumping costs.
Pipeline right-of-way cost
may prove overly expensive.
Treatment costs for agriculture
or cooling use may be prohibi-
tive.
Ocean discharge pipeline and
other equipment requires ex-
tensive corrosion protection.
May require regular , extensive
chemical testing which can
prove expensive.
May require outfall off-shore
to protect fish spawning areas.
May require sophisticated and
costly pretreatment.
15
-------
Evaporation Rate
The successful operation of an evaporation pond depends on the annual
net evaporation rate of the brine in question for the locality of origin.
Values of annual net evaporation rate of fresh water for the United
States (Figure 2) are useful only in making relative comparisons of
the major geographic areas. Evaporation rate for brine will be signifi-
cantly lower because of the presence of dissolved solids and oil film.
Other variables affect the rate: air and brine temperature, relative
humidity, and wind speed. The operator can approximate brine evap-
oration rate in a specific locale by applying a salt correction to the
following expression which describes freshwater evaporation:
E = NU (e - e ) (1)
O 3.
where E = evaporation in cm/day.
U = wind speed in miles per hour (mph) measured
2 meters (6.5 feet) above the ground surface.
e = vapor pressure in millibars (mb) of saturated
air at the brine surface temperature (available
from meteorological tables) .
e = vapor pressure in mb of the air at the 2-meter
3.
air temperature (meteorological tables) .
N = mass transfer coefficient in cm/ (day -mph -mb) .
The salt correction is as follows:
~ , ,. Replace e by e'
Concentration ^ o 3 o
At saturation 50,000 mg/1 NaCl e' - .97 e
150,000 mg/1 NaCl e1 = .91 e
5 oo
300,000 mg/1 NaCl e1 = .80 e
5 oo
Evaporation of brine within the temperature range 76°-90° F is described
by the following multiple regression analysis:
16
-------
Figure 2. Map of Annual Net Evaporation in Inches
(Pan Evaporation Minus Precipitation) .
-------
E = B1 (AT) + B2 (W) + B3 (RH) + B4 (C) + BS (WT) + B& (AT)1/2
1/2 1/2 1/2
B? (W) + Bg (RH) + B9 (C) + B1Q (WT) + BU (AT) (W)
B12 (AT) (RH) + BJ3 (AT) (C) + B^ (AT) (WT) + BJ5 (W) (RH)
B16 (W) (C) + B1? (W) (WT) + Blg (RH) (C) + BJ9 (RH) (WT)
B (C) (WT) (2)
where E = evaporation rate (centimeters per day) .
AT = air temperature (degrees Farenheit) .
W = wind speed (miles per hour) .
RH = relative humidity (percent) .
C = concentration of NaCl in increments of
50 , 000 mg/1 NaCl (i . e . , for a solution
containing 150,000 mg/1, C = 3) .
WT = brine temperature (degrees Centigrade)
[° C = 5/9 (° F - 32)] .
The B values refer to the following coefficients (rounded to the nearest
.0001):
B, =-0.2276 B0 =-0.6812 B1C= -0.0019
l o ID
B- = 0.2426 BQ =-0.0781 B,, = -0.0068
c, 7 ib
B3 = 0.0874 BIQ = 0.9523 BI? = 0.0017
B. = 0.2129 Bn1 = -0.0015 B, = 0.0001
*r 11 lo
B5 =-0.3424 B12= -0.0003 B19= -0.0011
B, = 1.8153 B, = -0.0002 B-rt= -0.0076
O 13 £.\J
B? = 0.2063 B14 = 0.0046
Data using this equation have deomonstrated a high degree of correlation
23
between calculated values and actual measurements of evaporation.
18
-------
Design Considerations
Design considerations begin with the pond location. This should be
close to, but preferably downhill from, the production site to minimize
pipelines, rights-of-way, and pumping requirements. A site removed
from within well-defined drainage basins will negate the potential
pollution from pond failure during heavy runoff. The states which
permit evaporation ponds require construction on an impervious
stratum or with a lining such as PVC, Hypalon, or Gunite.
Lining materials must be inert to the organic and acid constituents of
brine. Preferably, liners should be tested for reactivity to the brine
in question. Flexible liners require a compacted sub-base and soil
covering to keep it in place and minimize weathering and puncture (see
Figure 3) . Underdrains installed at 1 to 2 foot depths beneath the liner
(including sides of ponds) are recommended to indirectly describe the
integrity of the lining by monitoring the quality of the seepage. Detection
of a liner break necessitates emptying into an adjacent pond and locating
and repairing the failure .
Pond height can be estimated by assuming a 6 to 12 inch soil cover over
the liner, about 4 feet of accumulated salt precipitate for a 15-20 year
disposal operation, 1 to 1.5 feet of liquid depth, and a freeboard of 2
feet (cumulative depth 8 to 10 feet) . Banks should slope approximately
2: 1 (horizontal to vertical) and be lined and soil-covered in a manner
similar to the base. Allowance for width along the tops of embankments
will accommodate vehicles for use in maintenance and weed control. All
banks require compaction for stability. An estimate of the fill material
needed for the finished earthwork will require preliminary in-place
density measurements.
The operator is advised to consult state regulations when an evaporation
pit is abandoned. Common procedure is to install an impervious, corrosion-
resistant liner over the dried residue of the pond at a point level with the
19
-------
A
L
i. \
J
N\/X
J
PLAN
Anchor Bern
Provide Surface Drain
If Required
2:1
Sand And Gravel Cover
Compacted
Embankment
Original Ground Surface
Accumulated
Salt
i\ Earth Cover
SECTION A-A
Sand And Gravel Cover
Anchor Berm
2:1
Refill
Membrane Lining
Original
Ground
Surface
Figure 3. Typical Plan and Sections for Brine Disposal Ponds .
24
20
-------
bottom of the freeboard. Then a 2-foot layer of earth is placed on the
liner and lightly compacted. Finishing of the surface will depend upon
the geographic area (forested, sandy, or grassland terrain).
Operation
Inflow to ponds is an operation requiring regulation to prevent scouring
of earthwork. Damage to embankments from erosion and scour should
receive early attention. The recommended liquid depth in ponds is 1 to
1.5 feet. While a lesser depth offers higher evaporation rates, extremely
shallow water levels subject flexible liners to drying and cracking,
especially if inflows are intermittent. Greater liquid depths do not take
full advantage of the increased evaporation rate brought about by solar
heating of the liquid mass .
Several methods of increasing evaporation rate have been advanced.
The addition of dyes has been shown to have marginal benefit in
24 25
increasing solar heating of the fluid body. ' A liquid surface free
of oil and floatable materials is imperative for good evaporation. Oil
films can exist as thin as 1.5 x 10 inch, meaning that under proper
conditions 25 gallons of oil could coat one square mile of liquid surface.
Increasing evaporation rate by use of a spray system relies on the theory
of exposing more water surface to air by atomizing the water mass.
Studies have revealed that under the right circumstances increased
evaporation of brine can be realized at a cost savings. Consideration
must be given to spray nozzle type, spray configuration and capacity,
corrosion-resistant materials, and maintenance.
Table 6 summarizes evaporation pond information.
INJECTION
Increased attention to ecology and pollution control has led to the adop-
tion of more stringent state brine disposal regulations and to stricter
enforcement of those regulations, particularly as regards surface dis-
posal methods such as evaporation pits and direct discharge to streams.
21
-------
Table 6. SUMMARY OF EVAPORATION POND INFORMATION
Advantages
1. Elevated brine temperature
beneficial.
2 . Relatively quick to construct
and easy to maintain.
3. Only oil and other film-creating
floatable materials need be re-
moved prior to disposal,
implying minimal water treat-
ment .
4. Most effective in relatively
arid sections of the country
where land costs are
relatively low.
5. Frequently the least expensive
brine disposal alternative,
especially in arid areas of the
country.
6. Brine quality, except for oil
content, is not a major problem
in the operation of an evapora-
tion pond.
Disadvantages
Extremely high potential for
groundwater and surface
water pollution, due to fail-
ures in the system during
the life of the pond and be-
cause of the extensive salt
deposit remaining after the
pond is abandoned.
Source of continuing legal
scrutiny because of history
of land scarring and water
pollution.
High land costs may make
this method impractical.
Can be used only where high
evaporation rates combine
with low land costs .
Oil film on brine surface can
seriously affect evaporation
process.
May be difficult to find a
reasonably priced liner
resistant to chemical degra-
dation of some brines .
22
-------
Thus, the alternative to surface disposal, subsurface injection, is
becoming more accepted legally and, in fact, has been used effectively
for many years.
The design and operation of injection systems are regulated by many of
the producing states, mainly to safeguard groundwater resources.
Groundwater moves very slowly. Consequently, salt buildup usually
is detected only after an extensive portion of the aquifer has been con-
taminated, requiring perhaps centuries to recover via natural recharge.
The operator is advised to consult the exact regulations for injection
systems in his state .
Brine may be returned to the formation of origin or be injected into
another formation (oil bearing or not) . In addition to being a disposal
avenue, injection into the producing formation serves in maintaining
reservoir pressure, thereby retarding the gradual decline of primary
oil production. Waterflooding, on the other hand, is a secondary
recovery operation that utilizes injected water under pressure to drive
the oil to the producing well. Waterflooding is normally begun late in
the primary recovery period, usually after the formation pressure has
declined. Both operations increase the recovery of oil in place, and
both require volumes of water often in excess of the brine production.
Brine satisfies an economic need in this case.
Important design considerations include selection and analysis of a
receiving formation, creation of a new injection system versus renova-
tion of an old production well(s) , unitization of the disposal system,
and choice of equipment and materials. Operational parameters are also
significant: brine pretreatment, compatibility with receiving water and
makeup water, injection pressure, and remedial measures.
Design Considerations
Selection--
The intent of a brine injection system may be the maintenance of
formation pressure as petroleum is withdrawn, the recovery of oil by
23
-------
waterflooding, or simply the disposal of brine. The selection of the
receiving formation should be based on geologic as well as hydrologic
relationships in order to ascertain the injection capacity of the forma-
tion and the chemical compatibility of the injected brine and the water
within the formation. The important region-wide geologic character-
istics of a disposal formation are areal extent and thickness, continuity,
and lithological character. This information can often be obtained from
existing geologic maps, such as those of a producing oilfield. On a
local basis, it is necessary to know formation depth and thickness,
stratigraphic position, lithology, porosity, permeability, reservoir
pressure, and temperature. This information can be obtained or esti-
mated from core analysis , examination of bit cuttings , drill stem test
data, well logs, driller's logs, and injection tests.2'
28
The desirable characteristics for a waste injection formation are: an
injection zone with adequate permeability, porosity, and thickness; an
areal extent sufficient to provide liquid-storage at safe injection pres-
sures; and an injection zone that is vertically below the major fresh-
water zones and is confined by an overlying consolidated layer which
is essentially impermeable to water. Knowledge of the vertical confine-
ment and lateral movement of water within the prospective injection zone
is an assurance against saltwater movement into groundwater and onto
the ground surface.
There are two common types of intraformation openings: (1) inter-
granular and (2) solution vugs and fracture channels. Formations with
openings in the first category are usually made up of sandstone, lime-
stone, and dolomite formations and often have vugulor or cavity-type
porosity. Also, limestone, dolomite, and shale formations may be
naturally fractured. The second type of formation opening is often
preferable for waste disposal because fracture channels are relatively
large in comparison to intergranular openings. These larger channels
may allow fluids high in suspended solids to be injected into the re-
ceiving formation under minimum pumping pressure and with a minimum
amount of water treatment at the surface.
24
-------
As a basis for further consideration in the selection process, mathematical
relationships have been derived which predict the receptivity of a forma-
15 17
tion to injected fluid ' and the change in intake rate per unit of
29
time. The information derived through their usage should be regarded
as approximation, for the reason that the conditions upon which the
formulae are based dp not necessarily hold for the prospective injection
zone. Finally, the selection of a suitable location for waste disposal
28
could depend on the local incidence of earthquakes, which cause
movement along faults, can damage wells in the area, and may be
enhanced by pressurizing formations. Earthquakes have thus far not
been a problem in conjunction with oilfield brine disposal; however,
the fault zone aspects should be considered.
Installation —
The installation of a brine injection system may be via conversion of a
marginal oil-producing well, work-over of an abandoned well, or drill-
ing and completion of a new well. If the depth of hole reaches the antici-
pated injection zone, a converted well may be more economical, especially
if leak-free casing is present. However, this route may be precluded if
cement plugging and crooked casing strings are encountered or if the
existing casing is too small to accommodate injection tubing. The ad-
vantage of planning a new well is the assurance that the well is drilled
and completed properly, thereby safeguarding potable groundwater.
The American Petroleum Institute lists the following accepted
techniques:
1. Drill a full-sized hole to total depth and set the well
casing through the porous disposal zone or zones. This
method is recommended for unconsolidated formations
subject to sloughing or caving.
2. Drill a full-sized hole through all porous zones or to a
point where circulation is lost and set the casing immed-
iately above the porous disposal zones.
25
-------
3. Drill a full-sized hole to a point immediately above, or to
the top of, the disposal formation and set the casing at
this point. Then drill a reduced-sized hole through all
the porous zones or until circulation is lost. If possible,
clear water should be used for drilling fluid in drilling
the reduced hole to prevent plugging from mud and lost
circulation material.
4. Drill a full-sized hole to a point immediately above, or
to the top of, the disposal zone, then drill a reduced-
size hole to total depth and set the casing at the point
where the hole size has been reduced. After the casing
has been set, ream the rat-hole or reduced hole to
remove the mud, using water for the drilling fluid. If
the casing and hole size permit, the rat-hole may be
reamed with a larger-diameter bit in a conventional
manner. If conventional reaming cannot be done, the
rat-hole may be underreamed.
Liners are often used when converting an old well for injection pur-
poses to protect fresh water and other mineral bearing formations.
Open hole completions are preferred in consolidated formations due to
increased permeability and ease of cleaning, while an unconsolidated
formation may require that casing be set through the formation and
perforated. Other possibilities in the case of unconsolidated formations
include a gravel pack or screened liner. It may be possible to improve
the well permeability (ease of flow) of the formation face and mud in-
vasion zone by circulating clear water, scratching or reaming the open
hole, or swabbing to induce a backflow of fluid from the formation. Often
it is necessary to increase the permeability in the vicinity of the well
bore by acidizing in the case of limestone or dolomite formations or by
hydraulic fracturing (see Figure 4) .
There are many methods of completing injection wells for the disposal of
brine or other liquid wastes . The wells can be completed with or without
26
-------
Casing Pressure
Gauge \
Jk
-H^L''--
Surface Pas i ng "* /f » LI .-
. . j__ > ".
// ? " » '/ •• .
A-
Tj-ing ^^ri n*j Casino ••-
//->//*//c» *
xnjcction Tuijuiy //// A^
1
x-
• 1
iv^^r— L-_ In J ection
— T^1—
^" Well Head Pressure
'^^H^^7 Gauge
•—•_-*; Fresh Water Sands
,'.'_' ",','T* Impermeable Shale
'-^ ,-- < ' Fresh Water Sands
JTTT1-^
/'-SrXX*.^
•' '// /
/ / /, ~» Gravel
Casing Pressure
Gauge
Annulus Fill Line
Surface Casing
Cement
Long String Casing
Noncorresive Fluid
Injection Tubing
Packer Element
Injection
Well Head Pressure
Gauge
Fresh Water Sands
Impermeable Shale
Fresh Water Sands
Impermeable Shale
Injection Horizon
Figure 4. Open and Closed Hole Injection Well Completions
45
27
-------
a packer (a special tool usually used to seal off the annulus between the
tubing and casing) . Packers are sometimes necessary to protect the
casing from high injection pressures and are also used to protect the
annulus from the corrosive effects of the brine by preventing the escape
of brine up the annulus . After setting the packer , the annulus should be
filled with a noncorrosive fluid such as kerosene, diesel oil, naphtha,
crude oil, or chemically treated water, although it is also possible in
many cases to use these fluids in the annulus without the benefit of a
packer. The purpose of this operation is to replace the water that nor-
mally fills the annulus of the well with a noncorrosive fluid in a quantity
sufficient to pressure balance the brine in the tubing at static conditions.
If the static fluid level in the tubing is not high enough to support a
column of noncorrosive fluid in the annulus, a packer must be used.
Corrosion and unseating difficulties in brine injection wells make the
use of packers desirable only when absolutely necessary. As injection
commences, resistance to flow in the tubing and formation causes the
fluid in the tubing to rise, with a subsequent rise of the fluid in the
annulus. A record of casing-head pressure along with injection rates
taken at bimonthly intervals can reveal the following indicators in the
operation of an injection well:
1. A constant injection rate and an increase in pressure
indicate the formation is becoming plugged.
2. A decrease in injection rate at a constant pressure or
an increase in injection pressure indicates an increased
friction head in the tubing due to scale formation.
3. A constant rate or a greatly increased rate and a
sudden decrease in pressure indicate a tubing or
casing leak with possible pollutional consequences.
A variety of types of completions are presently being used for injection
service; however, not all of these are satisfactory from a pollution-
•3 -I
control standpoint.
28
-------
As mentioned previously, discussions with regulatory officials in sev-
eral states indicate that improperly plugged, abandoned wells are the
major sources of brine pollution. Many of these wells either do not
have cement plugs or have a top plug and no bottom plug. If improperly
plugged, the well may leak at the ground surface, in which case it can
be detected and remedied. A single top plug or a faulty cement job is
extremely difficult to detect and poses a continuous threat to fresh
groundwater. Compounding the problem is the lack of recorded infor-
mation regarding wells drilled prior to about 1940, many of which are
now abandoned and whose locations are unknown.
A review of the various types of completions presently being used for
injection are shown in Figure 5. The type D completion is encouraged
for brine injection because it can be effectively controlled and checked
by surface tests . The following recommendations are presented for
effective subsurface injection operations:
1. Design well completions for fluid injection and salt-
water disposal service that may be effectively
monitored and controlled by surface tests.
2. Give due consideration to environmental conditions
in the project area.
3. In the design of saltwater disposal systems, select
zones that have sufficient reservoir volume to accept
the present and expected volume of produced water
without developing overcharged conditions in the
formation.
4. Control operating conditions of injection systems to
avoid mechanical failure.
5. Encourage field personnel to be zealous in their
checking of operating systems so that trouble may
be detected and remedied at an early date.
6. Attempt to design water treatment programs that will
also control failures due to corrosion.
29
-------
Injection Zone
A. Cement Circulated, Injection
Down Casing .
B. Cement Circulated, Injection
Down Tubing .
3
)
?
/
X
X
rl
3
5
£
^
X
/
^
^
Primary
Cement
f
r
*
— .
?
/
••
\7 >
^"^ '.
.>
^
Primary
Cement
Injection Zone
C. Cemented Surface Pipe,
Injection Down Casing.
D. Cemented Surface Pipe,
Injection Down Tubing .
29
Figure 5. Typical Injection Well Completions.
30
-------
7. Keep detailed records of injected volume and pro-
duced volume so that any loss of injected fluid might
be detected and remedied at an early date.
8. Give careful consideration to state regulations regard-
ing depth and cementing of surface casing, landing of
the long string, injection through tubing below a
packer, and monitoring of casing-head pressure.
Materials--
The corrosive nature of brine, particularly where dissolved oxygen and
sulfides are present, dictates the usage of special materials in the injec-
tion system. Tubing and casing should be internally lined with plastic
or cement to prevent the bare metal from contracting brine. In some
32
instances, epoxy resin-lined tubing has been used successfully.
Unlined steel tubing is susceptible to corrosion and accumulation of
scale and will eventually exhibit flow characteristics inferior to plastic-
lined and epoxy resin tubing which are not susceptible. Care must be
exercised when handling or running tools in the lined casing to prevent
cracks or breaks in the lining. The pipe should be carefully inspected
before being run downhole.
Two types of pumps are used for fluid injection. Centrifugal pumps are
used for high volume service where the injection pressures are less than
about 300 psi, and reciprocating, positive displacement pumps are nec-
essary for pressures greater than 300 psi.
The piston-type duplex pump and the plunger-type inverted triplex are
33
used in the East Texas oilfield. Duplex piston pumps are generally
used for pressures up to 500 psi, whereas the triplex pumps have been
found to be suited for higher pressures . A primary consideration in
pump design is the selection of the proper materials for saltwater service,
The usual oilfield fittings such as pistons , liners , rods , valves, seats ,
and packing cannot be used in brine service because the salt water pro-
vides little lubrication and is extremely corrosive. The East Texas Salt
31
-------
Water Disposal Company reports that liners made from "Janney 30,"
Monel, and "Ni-resist" are fully satisfactory from both the corrosion and
wear resistance standpoint. In the same operations, rods made of 303
stainless steel, with valves and seats of aluminum-bronze and magnesium-
bronze, have also proven satisfactory.
Testing--
Following completion of a disposal well, well testing will describe its
ability to receive brine. Injectivity index and capacity index are two
such tests which measure the effective permeability of the disposal well
and disposal formation as a whole. The capacity index is defined as
barrels of brine injected divided by the increase in bottom-hole pressure
(psi) . This value can be determined by measuring the static bottom-hole
pressure and the bottom-hole pressure at the maximum possible flow rate,
and dividing the quantity injected by the corresponding pressure change.
The tubing or casing should be kept filled, if possible, during the test,
and flow should be continued until a stabilized rate is established. A
well taking fluid under vacuum indicates that the formation is capable of
fluid injection at a higher rate than that being delivered, but this is not
necessarily an indication of the capacity of the well.
Injectivity index is similar to capacity index. It is defined as the change
in the number of barrels per day of gross liquid injected into a well
divided by the corresponding pressure differential between mean injec-
tion pressure and mean formation pressure, referring to a specific sub-
29
surface datum (usually this is the mean formation depth) .
One way to determine the injectivity index is as follows. Shut down the
well until the transient back pressure is falling very slowly, which
probably will take several hours . This means that the pressures in
the formation around the well bore have become equalized. Begin injec-
tion and maintain a steady pressure for a short period of time (e.g. , 5
minutes) . Record the volume injected during the period--or, if possible,
record the instantaneous rate at the end of the period—then raise the
pressure in equal increments (e.g., 100 psi) , taking additional volume
32
-------
readings. Follow this procedure until enough points are obtained to
establish the relationship between intake rate and pressure. The result-
ing graph should be a straight line, the slope of which is the injectivity
index. A simple plot of injectivity index versus time can indicate when
the injection formation is plugging and that remedial action is necessary.
Capacity index tests should be performed periodically (e.g. , monthly)
on each well to determine any changes in the injection capacity.
OPERATIONAL CONSIDERATIONS
Treatment
Brine receives treatment prior to injection. Treatment procedures
depend upon whether brine is handled in an open or closed system. The
closed system prevents brine/air contact and thus helps maintain the
fluid's chemical equilibrium by alleviating the problems arising from
oxygen-induced corrosion, scaling, and chemical precipitation. Other
factors which threaten chemical equilibrium are the pressure and tem-
perature changes that occur when the fluid comes from the reservoir to
the surface. In a completely closed system the only treatment necessary
is the removal of entrained oil and suspended solids and, on occasion,
the addition of biocides . There is some doubt as to the feasibility of
34
maintaining a completely closed system in normal oilfield practice
because of the many points in a disposal system where air can leak into
the system, but some operations can be designed with a minimum of air
contact (semi-closed systems) .
Open (presence of air) systems are by far the most common type of dis-
posal system and usually require more extensive treatment of the brine
before injection because of oxygen-induced changes in the brine's chemi-
cal equilibrium. The treatment generally involves removal of the dis-
solved gases, suspended solids, some dissolved substances, and possi-
bly dissolved oxygen. In addition, biocides may be added to eliminate
bacterial clogging of the formation.
33
-------
The chemical and physical nature of the disposal formation and the water
within it determines, in large measure, the degree and extent of the water
treatment necessary prior to injection. Some limestone and dolomite for-
mations will take untreated brine under a vacuum; some sandstone for-
mations require that the brine be treated to a high degree. If the injected
brine is incompatible with the formation brine, precipitates may form
upon contact of the two, eventually plugging the face of the formation in
the vicinity of the well bore.
Injection Pressure
The maximum bottom-hole injection pressure is a regulated parameter.
The purpose is to prevent formation fracturing and possible escape of
brine into freshwater aquifers . Some state regulatory agencies
recommend a maximum figure of 0. 5 psi per foot of depth. In the case
of deep wells , this value may be reduced to 0.4.
Remedial Measures
During the life of an injection well, capacity may decrease significantly
due to formation plugging (from suspended solids, precipitation, hydro-
carbons, or bacteria) or fouling of flowlines from scale. The following
remedial measures have been used to increase capacity.
1. Acidizing. Hydrochloric acid will remove most scales
with the exception of barium sulfate, strontium sulfate,
and calcium sulfate which may have to be removed
mechanically by scraping or reaming with a drill bit.
Hydrofluoric acid will dissolve sand, clay, or mud if
these are the plugging agents. A detergent may be
added to the acid to help remove oil films from the
reservoir and facilitate the acid reaction with rock.
2. Hydraulic fracturing. In this technique, a fracturing
fluid can be introduced into the formation with suffi-
cient pressure to induce horizontal fractures in the
formation, thereby increasing permeability. A mater-
ial, such as coarse sand, is pumped with the fluid
34
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to act as a propping agent to maintain permeability
after the pressure is released. Brine, which is
normally injected into the formation, is the logical
"hydrofracing" fluid. Care must be taken not to
apply excessive injection pressures which could cause
tubing failures or vertical fractures communicating
with fresh water.
3. Backflowing. Under certain conditions, wells can be
backflowed to clean the formation face. Occasionally
special strings of tubing are used to facilitate this
operation.
4. Mechanical cleanout. In cases where large deposits
of hard scale are formed on the formation face, tools
such as reamers and bits may be used to restore
permeability.
5. Chlorine and other chemicals. The injection of chlorine
has in some instances doubled the rate of input into
35
injection wells. The reasons for this improvement
were theorized as:
a. Chlorine in water solution forms hypochlorous
acid which dissolves carbonate deposits .
b. Chlorine kills bacteria and thus reduces
plugging caused by bacterial slimes.
Carbon disulfide has been used as a solvent for free sulfur, which can
collect on the formation face. However, the toxicity and highly flam-
mable nature of carbon disulfide make it extremely dangerous to handle.
Detection of Salt Pollution
A series of techniques can be employed in the detection of salt pollution
in the injection systems. Comb
mended for each individual case:
in the injection systems. Combinations of these methods are recom-
35
-------
As background information about the geographic area
in question, review the history of the field, the salt-
water disposal methods and volumes, and the salt
pollution. Also study the local geology and hydrology.
Isolate the problematic injection well or pit by conduct-
ing area-wide surveys . Obtain groundwater samples
which characterize the natural (unpolluted) chloride
levels in the freshwater formations of concern. Sample
existing domestic and irrigation wells and other test
holes. If several disposal systems are in operation, a
program of selective shutdown may reveal the faulty
system by the process of elimination. Ultimately, con-
struction and sampling of a network of permanent test
wells may be required.
Suspected failures in injection wells can be verified by
several tests:
a. Records of casing head and injection pressures.
b. Additive Tracer Test. Dyes are added to
injected water and observations made in
seepage areas.
c. Pressure Falloff Test. This is a test to further
detect a casing leak, or channeling, by com-
paring several wells operating under similar
conditions.
d. Injection Well Performance. Overcharging
of the injection zone can be detected by run-
ning performance tests at intervals (e.g. ,
every 6 months) throughout the life of the well.
The test is run over a 48- to 72-hour period
with alternating shut-in, injection, shut-in
cycles. An increasing shut-in pressure
indicates overcharging with possible pollu-
tional consequences.
36
-------
e. Relative Inject!vity Tests. Two methods are
available:
(1) Plot the location of the injection wells
on a map with their respective injection
ratios (i.e., injection pressure/injection
rate) . Any large deviations can indicate
casing leaks or channeling.
(2) A graph of rate-pressure profiles for
several different wells should show
similar slopes. Any large deviation in
slope is evidence of a casing leak or
channeling .
f. Subsurface Tracer Surveys. Tracers such as
dyes or radioactive material are injected into
the disposal formation; a corresponding detec-
tion test run in the casing can indicate casing
leaks and channeling.
g. Wire-Line Plug Method. It may be possible to
pump a cement plug down the well and have it
stop at a point just below a casing leak by check-
ing the well pressure as the plug is lowered.
h. Temperature Survey. Distinct changes in tem-
perature may indicate a possible casing leak.
i. Pipe-Inspection Logs. These may be used by an
experienced operator to detect holes in casing.
j . Subsurface Pressure Gauge. Running a pres-
sure profile may show a shift in the graph just
below the leaks .
k. Packer and Tubing Test. A packer which has
been set up to allow pressure in the tubing,
casing, and annulus could be set at various
points in the casing. This procedure would
37
-------
divide the pressure falloff section of the
annulus from the section where pressure
doesn't fall off, thus isolating a leak.
38
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SECTION IV
BRINE WATER TREATMENT
Oilfield brine water treatment is a process whereby the brine is in some
way altered to reduce the unwanted effects of scaling or corrosion, or
to remove any other conditions that might hinder disposal. While brine
water treatment is predominantly the problem of the injection system
operator, scale and corrosion effects are of general importance to all
operations that involve the separating , transporting, and/or handling
of oilfield brine.
Although more specifically explained in electrochemical terminology,
corrosion might be visualized as a phenomena that occurs when a con-
stituent in the brine has a stronger attraction for an element in the
material of the brine handling system (pipeline, tank, etc.) than the
system itself possesses. Thus, the element is literally pulled out of
the system and combines with the material in the brine which exerted
the stronger attraction. As would be expected, corrosion damage nor-
mally appears in the form of holes or similar depressions in the inside
surface of the brine handling system, usually in areas of higher fluid
velocity. Treating brine to prevent corrosion involves either removing
the strongly attractive brine constituent or altering the nature of the
brine to reduce the strength of or eliminate the corroding agent. An
alternative to brine treatment for corrosion is to line the inside of all
brine containers and piping with a nonreactive material.
Scaling, on the other hand, may be visualized as the opposite effect of
corrosion. Scaling generally occurs as a result of conditions in the
39
-------
brine which cause a constituent(s) to be removed by chemical reaction
or precipitation. Scaling damage is normally in the form of mineral
deposits on the inside surfaces of the brine containers or pipes , usually
at areas of lowered fluid velocity. These deposits gradually clog up the
pipe openings increasing the amount of pumping necessary to move the
fluid. Treating brine to prevent scaling broadly involves removing the
potential scale-forming brine constituents or altering the nature of the
fluid to keep the potential scale formers in solution (dissolved) .
Another factor that might create disposal problems and require treat-
ment of the brine is fluid incompatibility. Like corrosion and scaling,
incompatibility is a chemical effect. Unlike those problems, however,
incompatibility is most troublesome in brine injection reservoirs. Gen-
erally , incompatibility occurs when one or more of the chemicals in the
brine reacts with chemicals in the existing reservoir fluid to cause an
undesirable effect, such as precipitation. Precipitation damage result-
ing from incompatible fluids is usually in the form of plugged pore
spaces in the injection zone. Treating brine to prevent incompatibility
consists of reducing the strength of or removing the reactive element,
or altering the nature of the injected fluid. Alternatives to treatment
include selection of another legally acceptable disposal method or
another injection zone. The last two brine handling/disposal problem
areas are suspended solids and excessive amounts of oil. Suspended
solids may be organic or inorganic. If the solids are organic, then
bacteria may also be present in the brine, especially if the organic
material is present in relatively high amounts. These bacteria can
prove excessively troublesome not only at the injection well interface
but throughout the entire brine gathering system. The most damaging
effects of bacterial action include release of soluble SO. which reacts
to form hydrogen sulfide (H-S), and the physical clogging of injection
reservoir pores. Treatment usually takes the form of filtering and the
addition of a good bactericide. If high amounts of dissolved and sus-
spended organic materials are present, more elaborate treatment
40
-------
devices or alternate legally acceptable disposal methods may be
required. Inorganic suspended material may cause the same brine
disposal problems as precipitation and scaling.
The addition of oil magnifies disposal problems considerably. Oil coagu-
lates around inorganic solids and binds them together. The effect is to
produce a. type of gel which can plug the injection interface. Treatment
may consist 6f removing the inorganic solids by filtering, by chemical-
aided settling, or by removing a higher percentage of the oil before it
gets to the disposal system.
DEGREE OF WATER TREATMENT32' 36
The degree of water treatment required in a brine disposal project
depends on the constituents in the water, the type of disposal system
(open Or closed), the type of disposal mechanism, the kind of materials
used in the well equipment, and the characteristics of the disposal for-
mation (in the case of injection) . In some instances, the combination of
these factors is such that no water treatment, or at most a minimum of
water treatment, is required. A closed system injecting a high quality
brine into a very permeable formation may only require the addition of
one or two chemicals to help prevent precipitation or corrosion. In all
cases, a laboratory analysis of the brine must be made before the design
of water treatment process can proceed. The common impurities of
brine are shown in Table 7.
ANALYTICAL TESTS
The analytical tests that are normally run on brine to be injected are
listed in Appendix C. The analytical procedures , reagents, and prep-
aration of reagents for these tests are well described in Standard
37
Methods. A Bureau of Mines publication by Watkins also describes
Q Q
many of these tests giving field test procedures . As Watkins ex-
plains , "In some of the tests extreme accuracy, such as required in an
analytical laboratory, has been sacrificed for rapidity and convenience.
However, for most of the tests , the methods described herein are accu-
o o
rate enought for plant-control purposes."
41
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Table 7. COMMON IMPURITIES IN BRINE
53
Type of
Material
Form of
Material
Material
Dissolved
Material
Solids
Inorganic
Material
calcium &
magnesium
sodium
(bicarbonate
Jcarbonate
]sulfate
^chloride
bicarbonate
carbonate
sulfate
fluoride
chloride
iron
manganese
Organic
Material
Vegetable material
Gases
hydrogen sulfide
carbon dioxide
oxygen
nitrogen
Suspended Solids
Inorganic
Organic
bacteria
algae
protozoa
animal & vegetable matter
oil
42
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In addition to the tests listed in Appendix C, it is often desirable to run
corrosion tests to determine the weight loss for various metals expected
to be used in the gathering system and disposal wells. This is accom-
plished by flowing the brine past a corrosion coupon (sample of the
metal to be tested) that is rigidly suspended in the stream. The rate
of corrosion is determined by weighing the coupon at various time
intervals. Visual examinations of these coupons can also indicate the
type of corrosion in some instances .
Membrane filtration tests are often used in determining the overall
plugging tendencies of the suspended solids in water being injected.
Membrane filters are made of cellulose ester or polyethylene and range
in pore size from about 10 microns to 0.45 microns (the 0.45 micron
size is used in the membrane filter test) . The membrane filtration test
is usually carried out at 20 psi pressure, and the volume of filtrate is
determined as a function of time. From these tests, a graph of flow rate
(ordinate or vertical values) versus cumulative volume (abscissa or
horizontal values) is obtained, the slope of which indicates the quality
of water. A horizontal line indicates perfect water for injection pur-
poses, while a slope greater than 1.8 indicates poor water. Plugging
tendencies can only be evaluated when the results of filtration testing
are coupled with compatibility studies .
Microscopic examination is also advisable to determine the presence of
microorganisms . Bacteria are the primary microbial offenders in the
disposal systems of oilfield brines and can be a source of both corro-
sion and formation plugging. If a microscopic examination reveals the
presence of appreciable quantities of microorganisms, a more detailed
examination should be conducted in a suitable laboratory to determine
appropriate treatment devices .
FORMATION PLUGGING AND SCALING
One of the major objectives in brine treatment is to prevent the deposits
of solid material in the gathering system or, in the case of injection, in
the formation surrounding the well bore.
43
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As brine is produced from an oil well, its temperature and pressure
decrease. An increase in temperature increases the solubility of most
salts and gases. On the other hand, a decrease in pressure decreases
the solubility of gases. Therefore, the usual overall effects of bringing
the brine to the surface are the precipitation of salts and the release of
gases from solution.
In injection, the compatibility of injected water and water already in the
formation must be considered because a reaction between the chemical
constituents of the two different waters may form insoluble compounds
which precipitate. This condition could also occur if incompatible
waters from different reservoirs or surface sources are to be mixed
prior to injection.
DEPOSITS
To deal effectively with chemical and biological deposited materials, the
operator must be familiar with their specific natures and reactions. The
substances most commonly deposited by oilfield brines are:
1. Calcium carbonate or calcite (CaCO.,); scale.
2. Magnesium carbonate (MgCO,); scale or sludge.
3. Calcium sulfate (CaSCO; scale.
4. Barium sulfate (BaSO,); sludge.
5. Iron compounds; corrosion products .
6. Biological deposits .
Calcium Carbonate (CaCO,,)
The solubility of calcium carbonate in oilfield waters is influenced by
the partial pressure of carbon dioxide (relative amount of the CO_ gas
dissolved in the brine compared to the amount in the atmosphere) ,
brine temperature, pH, and the concentration of other salts in the brine.
Dissolved calcium carbonate does not exist in solution as calcium ions
(Ca ) and carbonate ions (CO_ ) but as calcium ions and bicarbonate
ions (HCO ) . Calcium carbonate is formed according to the equation:
44
-------
Ca(HC03)2 = CaC03 + H2O + CO2 (3)
Decreasing the pH or increasing the carbon dioxide partial pressure
would drive the equation to the left (i.e. , increase the concentration of
calcium bicarbonate and decrease the amount of calcium carbonate
scale) . Likewise, an increase in the brine pH, corresponding to a
decrease in the carbon dioxide partial pressure, would cause calcium
carbonate to be deposited. The latter condition usually exists when
pressure is released as the brine is produced from an oil production
well.
The loss of carbon dioxide from solution in brines is a function of the
pH changes in the solution. If the pH of the water is near 8.0, the
calcium carbonate will exist in solution as about 2% carbonate ion, 93%
bicarbonate ion, and 5% carbon dioxide gas dissolved in water. If the
pH were at 7.0, there would be only a trace of carbonate ions, 80%
bicarbonate ions , and 20% carbon dioxide gas dissolved in the water.
As discussed previously, most brines rarely exceed pH = 9.0. In
39
fact, the usual range is pH 5.5 to pH 8.0.
The decrease in both temperature and pressure in produced waters
coming to the surface decreases the solubility of calcium carbonate, but
39
in nearly all instances the loss in pressure exerts the greater effect.
A decrease in the temperatures of brine being injected into a well de-
creases the solubility of calcium carbonate. This partially explains
plugging and scaling problems encountered by injecting brine at sur-
face temperatures into lower temperature formations .
Several equations are available for predicting the calcium carbonate
scaling tendency of water. One of these is the Stiff and Davis Stability
39
Index which is an extension of the Langelier method developed
specifically for oilfield brines:
SI = pH - K - pCa - pAlk (4)
45
-------
SI is the stability index value. A positive value indicates scaling
conditions, whereas a negative value indicates corrosion. The ideal
condition is to maintain the stability index at zero so that neither
scaling nor corrosion will occur. Values for K, pCa, and pAlk are
obtained from graphs. The reader is referred to the Appendix section
39
of Introduction to Oilfield Water Technology by A. G. Ostroff for a
more complete explanation of the method.
Magnesium Carbonate (MgCO_)
Magnesium carbonate can be deposited as a scale or sludge, and its
solubility in water is affected by the same factors as calcium carbonate.
The difference is that magnesium carbonate is many times as soluble as
calcium carbonate. Since most waters contain both calcium and magne-
sium, calcium carbonate would precipitate first, thereby reducing the
carbonate ion content. Thus, magnesium carbonate is not likely to
precipitate unless the magnesium content is extremely high. At high
temperatures magnesium carbonate decomposes into magnesium hydrox-
ide (and other reaction products) which may form deposits in the
tubing in deep, high temperature wells.
Hydrated Calcium Sulfate (CaSCO--Gypsum
Calcium sulfate is common to oilfield brines and deposits as a scale
rather than a sludge. It is more difficult to remove than calcium car-
bonate. Temperature variations do not influence calcium sulfate solu-
bility as much as they do calcium carbonate, but a decrease in
temperature may decrease the calcium sulfate solubility causing
scaling. Carbon dioxide does not affect the solubility of calcium sul-
fate as it does with calcium carbonate and magnesium carbonate.
Calcium sulfate exists in nature as gypsum (CaSO. ' 2H2O) or anhydrite
(CaSCO . The anhydrite form exists at high temperatures and may be
found in deep wells . Metter and Ostroff have also developed a method
for predicting the approximate solubility of calcium sulfate in oilfield
39
brines .
46
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Barium Sulfate (BaSO.)
Barium sulfate is very insoluble and very difficult to remove once formed
due to its fine particle size. The solubility of barium sulfate increases
slightly with increasing temperature and the presence of certain salts.
Problems with plugging from insoluble barium sulfate can result from
injecting sulfate-laden brine into a disposal aquifer containing soluble
barium salts .
Iron Deposits
Iron deposits in disposal systems come from two sources, the water
itself or the corrosion of iron or steel in the system. These deposits
may form scale or remain in the water as colloids (suspended particles) .
Precipitates from iron and hydrogen sulfide reactions can cause iron
sulfide scales . The presence of large amounts of dissolved oxygen can
cause hydrated ferrous hydroxide and ferric hydroxide scales or
deposits. Dissolved carbon dioxide can cause ferrous bicarbonate
scales, which are loosely held on metallic surfaces and can flake off
with resultant plugging of the injection formation.
Iron in natural waters exists in such oxidation states as ferrous (Fe )
ions , ferric (Fe ) ions , or as complex ions . The pH of the water
influences the solubility of the ionic form; that is, at pH values higher
than 3.0 the ferric ions combine with hydroxide ions to form ferric
hydroxide. The solubility of the ferrous ion may be controlled by the
hydroxide (OH ) ion concentration or the bicarbonate (HCO, ) ion
concentration. Formation waters containing dissolved iron can deposit
ferrous carbonate, ferrous sulfide, ferrous hydroxide, ferric hydrox-
ide, and/or ferric oxide.
The oxidation state of dissolved iron (ferric or ferrous form) is useful
in predicting its deposition tendencies . By using a method based on
the oxidation-reduction potential of the water, the pH of the water, the
bicarbonate ion concentration of the water, and an iron stability dia-
gram, the maximum permissible concentration of dissolved iron can be
39
estimated.
47
-------
Biological Deposits
Certain microorganisms which grow in disposal systems are able to
corrode steel and form precipitates. Biological growths can also plug
the injection reservoir formation face and such surface equipment as
filters. Algae and bacteria are the primary offenders; however, algae
require sunlight and are able to grow only in open treatment systems.
Under conditions where oilfield brines contain the necessary nutrients
(chemical food materials) to support large bacterial growths, those
organisms known as sulfate producers grow profusely.
TREATMENT REQUIREMENTS FOR SCALE PREVENTION
Treatment for scale prevention may be either physical or chemical.
1R 3A
Physical methods include: i0' JD
1. Separation and removal of incompatible constituents.
2. Prevention of conditions causing supersaturation (the
chemical "excess" condition which must exist prior to
precipitation and scale formation) .
3 . Elimination of air entry .
4. Use of some type of settling or filtration mechanism .
Certain scale-preventing chemicals are often added to brines as part of
the treatment process. In chemical treatment, the prevention of scale
deposition involves either removal of the anion or cation of the scale
forming combination, or the addition of a chemical scale inhibitor which
ties up the scale forming cation. The inhibitor usually chelates or
complexes the cations so that they remain in solution and cannot combine
with the appropriate anions. The process of tying up the ions in this
manner is called sequestration. Probably the most popular sequester-
ing agents are the inorganic polymetaphosphates which are adsorbed on
the surfaces of crystal nuclei and prevent their growth. Organic chelates
such as EDTA (ethylene-diaminetetracedic acid) are also useful in scale
inhibition. EDTA forms stable soluble complexes with magnesium,
48
-------
calcium, strontium, barium, and other divalent metals. Iron sequester-
ing agents such as citric acid salts have also proven useful.
18
Case reports that stabilization processes consisting of coagulation
(mixing) , settling in open basins, and filtration can prove expensive
and difficult to control--to the point of being impractical. If such is
the case (or for other reasons) , chemical scale inhibitors may prove a
more satisfactory answer to scaling problems. One major operator
reported that after extensive testing:
1. Scale-preventing chemicals only worked on chemicals
that yield a crystalline form (inorganic) .
2. The most effective of the scale inhibitors tested were
organic polyphosphonates.
3. Combination corrosion and scale inhibitors were
relatively ineffective in reducing either scale or
corrosion.
Case further points out that the disposal system operator should insist
on regular check-tests to assure that the scale inhibitors are performing
properly.
CORROSION
The corrosion of metals in a brine disposal system is usually caused by
electrochemical reactions . In this type of reaction an anode (electron
donor) and cathode (electron acceptor) must exist in the presence of an
electrolyte (ionic solution) and an external circuit. Anodes and cathodes
can exist at different points on the steel surfaces with the steel provid-
ing the external circuit. A brine solution provides an excellent electro-
lyte. Thus, an electric circuit can be set up in the unprotected,
brine-handling pipelines with iron being oxidized at one portion of the
system (cathode) and iron being reduced and corroded away in another
portion (the anode) .
49
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Corrosion damage can occur uniformly as a gradual thinning of the anode
portion, or it can occur in the form of pitting where localized electroly-
tic cells are set up. It can also occur as galvanic corrosion when two
different metals come into contact and form an electrolytic cell.
Dissolved oxygen is probably the greatest producer of corrosion.
Oxygen-induced corrosion is the result of differences in oxygen concen-
trations in the system which cause an electrochemical potential difference.
While oxygen is normally absent in formation waters, it is unavoidably
absorbed by contact with air in the open system of oil production-
disposal .
Dissolved carbon dioxide (CCO is not as corrosive as dissolved oxygen,
assuming equal concentrations. Carbon dioxide is present in water as an
integral part of the carbonate system; however, any carbon dioxide above
that necessary to keep bicarbonate in solution is termed "aggressive"
carbon dioxide and is free to dissolve in water and act as an acid. Thus,
the pH decreases and the corrosion rate increases with an increasing
partial pressure of carbon dioxide. Water containing both oxygen and
carbon dioxide is more corrosive for equal concentrations than water
containing either by itself.
Hydrogen sulfide (H-,S) is soluble in water and, when dissolved,
behaves as a weak dibasic acid. Brine with dissolved hydrogen sul-
fide and oxygen may even be corrosive to acid-resistant alloys . The
corrosion of mild carbon steel when exposed to a hydrogen sulfide
solution increases to a maximum rate at around 400 ppm H_S, then
becomes fairly constant to about 2500 ppm H_S. Corrosion rates for
metals exposed to hydrogen sulfide in brine are higher than those
exposed to hydrogen sulfide in distilled water. When carbon dioxide
is present, the corrosion rates are still greater.
Dissolved salts greatly affect the corrosiveness of water . Sulfates
), chlorides (Cl ), and bicarbonates (HCO ~) are among the
50
-------
most common anions in brine, with the sulfate ion having the greatest
effect on corrosion. The effect of ions on corrosion depends upon the
metal and the ion's ability to penetrate the protective coatings formed
on the metal. The corrosiveness of waters with dissolved salts
usually increases with increasing salt concentration up to a maximum,
and then it decreases . The pH of the electrochemical solution influ-
ences the corrosion rate of most metals to a large extent.
Temperature can affect the corrosion rate in a rather complex manner;
however, the corrosion rate generally increases with an increase in
temperature. The corrosion rate will increase with a corresponding
rise in temperature, reach a maximum, then decrease. The decrease
is due to an appreciable decrease in the solubility of oxygen.
The effect of velocity on corrosion rate can be complex. The corrosion
rate has been observed to increase as the velocity increased in small
diameter pipes, possibly due to the effect of turbulence.
PREVENTION OF CORROSION
Corrosion can be prevented or at least reduced by certain brine treat-
ments . De-aeration will remove oxygen, degasification will remove
dissolved gases such as carbon dioxide and hydrogen sulfide, and
water softening will remove dissolved calcium and magnesium hardness.
Chemical substances called inhibitors are often added to reduce or pre-
vent corrosion. However, caution should be exercised in selecting a
specific inhibitor because some of the inhibitors added in the incorrect
concentrations can cause a corrosive condition themselves. These sub-
stances are both organic and inorganic in nature. The organic com-
pounds usually form films on the metallic surface. Many inhibitors
contain surface active agents that will remove loose scale when added
for the first time and may cause plugging if precautions are not taken.
Corrosion can also be prevented by the use of coatings . Metallic coat-
ings can be noncorrosive or sacrificial. The latter type protects
cathodically, which is an electrochemical reaction that is imposed so
51
-------
that current and sacrificial metallic ions flow in a direction opposite to
that which would normally occur. Other coatings used are vitreous
enamels, cement, phosphate coatings, oxide coatings, paint, lacquer,
and plastic. The correct choice of metals such as brass and Monel
for brine service will prevent corrosion and reduce maintenance costs.
Cathodic protection is often used to protect metallic surfaces in contact
with brine. In cathodic (active) protection of the submerged areas of
equipment such as tanks and filters, an external current may be
applied (an active system) such that the current enters all areas of
the metallic surface that were previously anodic. Sacrificial anodes
such as magnesium and zinc may be used (a passive system) in the
protection of pipes and tanks .
TREATMENT SYSTEMS
Treatment mechanisms require careful design and regular maintenance,
and considerable care should be used in their selection. Brine disposal
systems are usually classified as closed (absence of air) or open
(presence of air), although some systems employ features of both.
Figure 6 illustrates a typical oilfield brine disposal scheme.
Closed System
A closed system does not ensure a stable water for reasons discussed
under the topics of scaling and corrosion; however, by eliminating
oxygen, precipitation of insoluble compounds and corrosion problems
are usually minimized. In pressure vessels where oil water separation
and emulsion treating are carried out, a closed system would be
advantageous. In a closed system, an effort is made to maintain a
blanket of natural gas over the brine in all of the pipelines and tanks,
but experience has shown that complete air exclusion is very difficult.
A complete closed system treatment operation usually consists of resid-
ual oil removal (probably in the form of a skimming tank) , filtration and
backwash, filtered water storage, and injection.
52
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Ul
U)
From Field Wells
Free-Water Knockout
Emulsion , •
Gas
Emulsion
Treater
Water
Skimmed Oil Gas
Blanket
, , Oil To Storage
__ Disposal
Hells
Disposal Zone
Sand And Fresh
Water To Pit
Bayou
Figure 6. Typical Oilfield Brine Disposal Scheme
(Bayou Sorrel SWD System - Shell) .4b
-------
Open System
Open systems usually occur when the oil is separated from the water in
open gun-barrel type separators or when the water is stored in open pits
or tanks prior to its being introduced into the disposal system. A coop-
erative disposal system with many operators is usually of the open type
since a variety of techniques and equipment is used to separate and
store the water, much of which is open to the air. A completely open
system usually consists of residual oil removal, aeration and degasifi-
cation, chemical treatment including coagulation and settling, filtration
and backwash, storage, and injection. The additional treatment is
necessary since exposure to air results in a change in the carbon diox-
ide partial pressure, which may cause precipitation, as well as
corrosion due to free hydrogen sulfide and dissolved oxygen. Algae
and aerobic bacteria are also free to enter open systems.
OIL REMOVAL
Primary separation of oil from water is usually accomplished in free
water knockouts , gun-barrel separators , or heater treaters . The
efficiency of these processes is not always sufficient to ensure rela-
tively oil-free water for introduction into the disposal system.
The ease of removing oil from water is greatly influenced by the chemical
treatment or physical handling of the oil-water mixture before separa-
18
tion. Examples include:
1. Overtreating producing wells with certain scale
inhibitors can stabilize emulsions.
2. Certain types of corrosion inhibitors act as
emulsifying agents when used in slug treatment.
3. Certain emulsion breakers can give very clean oil,
but also very stable emulsions of oil in water .
4. Centrifugal pumps can form oil-in-water emulsions .
Gravity separators are generally used in disposal systems to remove as
much residual oil as possible from the water. (Horizontal pressure
54
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vessels are often used in closed systems.) One section of the separator
vessel has a mechanism to remove large droplets of oil and regulate the
flow. Another section of the vessel is used for gravity separation. The
oil rises and is skimmed off through a riser. Open systems often utilize
large open concrete basins with baffles and slotted-pipe collectors to
accomplish the separation and skimming. These basins are often similar
to the conventional API separator used in oil refineries and may be wood
or steel tanks. A typical skim tank is shown in Figure 7. A vertical
baffle aids in gravity separation and the floating oil is skimmed off
through a trough. Skim tanks are suited for both open and closed sys-
tems. Wood tanks are preferred in many instances for their corrosion
resistance.
Dissolved gas flotation is a highly efficient method to remove oil from
18
water if an oil-in-water emulsion does not exist. Flotation is a process
in which gases are dissolved in the water under pressure. On release
of the pressure, bubbles form, become attached to the oil and particulate
matter, and then float the oil matter to the surface where it can be skim-
med off. If the flotation unit becomes overloaded when oil or emulsions
are present, the addition of absorbent clays followed by a polyelectrolyte
is recommended. Alum, a coagulant used in municipal water treatment,
will also aid a flotation cell that is overloaded or receiving emulsions.
AERATION AND DEGASIFICATION
In open systems brine is aerated for two primary purposes. The first
purpose is to drive all acid-causing gases (carbon dioxide and hydrogen
sulfide) out of solution and reduce corrosion. The second is to oxidize
iron and form precipitates which will be retained in the settling basins
or on the filters, thereby preventing these precipitates from coming out
of solution in another part of the system or in the formation. If manga-
nese is present, it will also be oxidized and precipitated. Aeration has
one disadvantage in that oxygen is dissolved in the water and will cause
corrosion downstream in the system. For this reason, aeration should
be carefully controlled.
55
-------
Normal Water Level
Skim And
Overflow
Line
To Burn Pit
Outgoing
* & M
Incoming
ixi x-
Figure 7. Sectional View of Skim Tank.17
56
-------
Aeration equipment usually consists of spray nozzles, atmospheric
towers where the water cascades over a series of splash trays , forced
draft blowers where air is forced countercurrent to a flow of water cas-
cading over splash trays, or free-fall or step-type aerators where the
water falls on a spreader or tumbles down a series of steps.
COAGULATION AND SEDIMENTATION
Coagulation and sedimentation processes are used in open treatment
systems to remove the suspended solids and precipitates that have
formed due to equilibrium changes and aeration. In some disposal sys-
tems, sedimentation is employed without the help of chemical aids. The
settling process in this case is known as plain sedimentation. The design
of settling basins is based on the settling velocity of the smallest parti-
cle specified. The settling velocity of a particle in a liquid is a function
of the specific gravity and viscosity of the liquid and the specific gravity,
size, shape, and possibly concentration of the particles. The sedimenta-
tion basin can be rectangular or circular in shape with the fluid flow
being either horizontal or vertical. A term generally used in the design
of sedimentation basins is called the loading rate or flow rate per unit of
surface area (Q/A) . The average value for loading rate is between 600
and 1,200 gallons per day per square foot of sedimentation surface area,
and the outlet weir loading rate usually is set at 30,000 gallons per day
28
per foot of weir length. Experience has shown that these rates ensure
an even distribution throughout the basin if it is properly designed to
prevent fluid short circuiting (fluid flow directly from inlet to outlet
with no settling time) .
Chemicals called coagulants are often added prior to sedimentation to
speed up and increase the efficiency of the process. This allows for
smaller sedimentation basins and lower initial cost. Coagulation con-
sists of feeding the chemicals, followed by a rapid mix of about 2 min-
utes, and then by a slow mix called flocculation for about 30 minutes.
The chemicals or coagulants used are aluminum sulfate (alum), ferrous
57
-------
sulfate, ferric sulfate, ferric chloride, sodium aluminate, and poly-
electrolytes. Coagulation is designed mainly to remove minute, sus-
pended particles called colloids in the size range of 1 to 200 microns.
Colloids are essentially nonsettleable because of their small size and
cannot be removed by plain sedimentation.
Colloids may be both organic and inorganic. The colloids of particular
interest in a treatment system are compounds of iron such as ferric
hydroxide. The addition of coagulants in the rapid mix phase involves
the neutralization of the predominantly negatively-charged colloids by
adding an excess of positively charged particles. These are usually
hydrous oxide colloids formed by the reaction of the coagulant with ions
in the water. The hydrous oxide particles form floes which attract the
negative colloids . During the flocculation or slow-mix phase, the fine
floe particles are collected into larger floe particles that can settle out
more rapidly. Slow mixing must be done at very low fluid velocities to
prevent physically breaking the floe particles.
The various coagulants will only operate effectively within certain pH
ranges . The pH range for alum is 5.5 to 8.0, with 6.0 to 7.0 being
optimal. Hydrated lime is usually added to adjust the pH to this range.
Other chemical additions may include compounds called coagulation aids
which are sometimes used in conjunction with the basic coagulating
chemicals . Coagulation aids include such compounds as activated silica
and polyelectrolytes which aid in the formation of larger, stronger, and
denser floes.
Centrifugal separators (desanders) have also been used to supplement
28
gravity separation in the removal of solids from injection water.
FILTRATION
Filtration is a treatment process usually included in both closed and open
systems . In closed systems it is the primary means of removing sus-
pended solids, whereas in open systems it is used to remove floe parti-
cles that were not removed in the sedimentation process. The most
58
-------
common types of filters used in brine disposal systems are the slow
sand filter and the rapid sand filter.
Slow Sand Filters
Slow sand filters are composed of sand bedding with the top layer of sand
used as the filtering media. A disadvantage of this type of mechanism is
that the sand bedding material cannot be back-washed or cleaned; rather
it must be removed and replaced after clogging.
Wright indicates that the slow sand filter has been superseded by the
rapid sand filter in all new installations built in recent years because
slow sand filters are relatively inflexible and require too much surface
area.
Rapid Sand Filters
Rapid sand filters are classified as gravity sand filters or pressure sand
filters. The gravity filter is usually open to the atmosphere, whereas
the pressure filter is enclosed in vessels and operated at elevated
pressures which can increase the flow rate and prolong the filter cycle.
Gravity filters are usually operated at a rate of 2 gallons per minute
(gpm) per square foot of filter surface area, whereas pressure filters
42
may be operated at 3 gpm per square foot. Rapid sand filters usually
have a layer of sand on layers of graded gravel; however, in some
instances, coal (e.g. , "anthrafil") has been used in place of the sand,
or as another layer on top of the sand. Filtration does not occur on the
top layer of a rapid filter as it does in a slow filter. Instead, the partic-
ulate matter is adsorbed on the sand at different depths .
The filter media must be periodically back-washed to remove the filtered
sediment. This means that when the pressure drop through a filter ex-
ceeds a certain value it is taken off line for backwashing. The reverse
flow of water up through the filter media must expand the bed on the
order of 30 to 50 percent of its normal depth to provide enough permea-
bility for the wash water to thoroughly remove entrapped sediment.
The back-wash rate is in the order of 12 to 15 gallons per square foot
59
-------
42
of filter surface area per minute and is applied for about 5 minutes.
The backwash cycle stratifies the sand, arranging the fine sand on top
and the coarse material on the bottom of the filter bed (see Figure 8) .
The theory and design of filters, as well as the other unit operations
involved in water treatment, are fairly complicated to design and oper-
ate; however , these procedures are well documented .
In some disposal applications, proper brine water treatment can be the
most difficult phase of the entire operation, as well as the most expen-
sive. The prospective operator is advised to refer to Introduction to
Oilfield Water Technology and Water Problems in_ Oil Production,
18
An Operator's Manual for a more complete presentation of brine water
treatment.
60
-------
Operating
Table
Rate Of Plow And Loss
Of Head Guages
Operating
Floor
Pipe Gallery
Floor
Filter Drain
Filter To Waste
Wash Line
Wash Troughs
Filter Sand
Graded Gravel
Filter Bed
Cast-Iron'
Manifold
Pressure Lines To
Hydraulic Valves From
Operating Tables
Influent To Filters
Effluent To
Clear Well
Drain
perforated
Laterals
Figure 8. Rapid Filter and Accessory Equipment.
42
-------
SECTION V
ANALYSIS OF DISPOSAL ALTERNATIVES
At this point the prospective brine disposal mechanism operator should
begin to consider his own disposal needs. In this regard, the assump-
43
tion is that he will have to answer two basic questions:
1. What type of disposal system do I need?
2. How much will it cost me to construct and operate an
appropriate disposal system on an annual basis?
The answer to the first question is provided, basically, by the specifi-
cations of the oil regulating agency in each state, as well as the physical
considerations of each system. Specific design arrays of brine disposal
systems have been developed for desalinization processes in other publi-
1 f -in
cations ' and are useful for oilfield brine considerations . These
arrays will be presented, after conversion to appropriate terminology,
in this section.
An effort has been made to present these analytical methods in a logically
consistent manner, supplemented by clarifying instructions, to result
ultimately in a realistic, easy to follow procedure. In addition, a
computer program (Appendix E) has been prepared for calculating
general configuration designs and costs of new construction within the
basic design configurations. The derivations of formulaic relationships
used in these analyses are developed in Appendix D. Along with each
calculation are the necessary terminology and explanations to complete
the cost analyses .
62
-------
ANALYSIS FOR DIRECT DISCHARGE OR CONVEYANCE
Basically, this analysis develops the design configuration of pure water
flowing in a pipeline from the point of brine collection to the direct dis-
charge site (or to the brine water treatment plant, if this operation is
necessary). In function, the supply pipeline and pumping analysis is
that of simple fluid transport and remains the same whether used to
transport the brine to the direct discharge site, evaporation pond or
pit, injection site, or to another piece of equipment such as a treatment
system or storage tank. Of course, many areas use tank trucks to haul
the brine from the production site to the disposal site, where discharge
occurs either directly into a disposal mechanism, into a holding tank,
or to a small water treatment plant. If trucking is used in place of pipe-
lining, the cost in dollars per barrel will already be known and can be
added to disposal mechanism cost in determining total and annual dis-
posal costs.
DIRECT DISCHARGE ANALYSIS
The following information is required before beginning the analysis:
1. Quantity of brine to be disposed of in gallons
(42 gallons per barrel) per day (XR): gpd
2. Quantity of oil in gallons per day produced
with brine (X ): gpd
3. Number of years of project (Y): years
4. Company's discount rate (i): decimal
fraction
5. Length of pipeline in miles from brine
collection point to discharge point (F1): miles
6. Discharge elevation in feet above (-) or
below (+) brine collection point (EL): ft
7. Cost of right-of-way (assume a 30-foot wide
strip at a land cost of $109/acre—unless
better cost can be obtained) (ROW): $
63
-------
8. Cost of pipe per foot (CPU):
9. Cost of lining pipe with cement, per foot
(CCU):
10. Cost of pipe installation per foot:
11. Cost per kilowatt hour of electricity (ECU):
12. Current year Engineering News Record
$/ft
13.
Building Cost Index (ENRBCI):
State specifications for design.
.53
DIRECT DISCHARGE CALCULATIONS'
1. If the pipe requires a cement liner, calculate
the inside diameter required for the liner (I.D.)
assuming a liner thickness of .25 inch:
I.D. = (X Q'45) (.017) + .50
if no liner:
I.D. = (XB'45) (.017)
2. Enter O.D. corresponding to the cement liner:
O.D. = (1.07) (I.D.) = I.D. + 1/2 inch
3 . Enter weight per foot (total) of pipe:
4. Enter yield pressure of pipe used (P ):
s
5. Calculate head loss due to friction (Hf)
for water flowing through a cement-lined
pipe:
Hf = (.003) (5,280) (F1)
6. Calculate the required pumphead (H ):
(H ) = discharge elevation - Hf
H = E - H,
P f
7. Calculate the required pump discharge
pressure (which is also the minimum allow-
able yield pressure for the pipe):
Pump discharge (PrO - -434 pumphead (H )
64
_$/ft
$/ft
S/KWH
decimal
fraction
inches
inches
_lb/ft
psi
ft
ft
psi
-------
8. If calculated for more than one size of pipe,
compare the pipe yield pressure (P ) with the
s
calculated yield pressure (P^) and select least
expensive pipe whose yield pressure (spec) ^> P_
9 . Pump requirement? yes
(A pump will be required if H is (-) . )
10. Pump power requirements:
a. Hydraulic horsepower = HHP
no
HHP =
(XB) (PD)
HHP
(2.468) (1,000,000)
b . Brake horsepower = BHP
- Hydraulic horsepower
Pump efficiency
(Assume pump efficiency = .85 if not stated.)
c . Kilowatt hours = KWH
T
-------
2. Pump power requirements
a. brake horsepower: BHP
b. kilowatts: KWH
COST PROCEDURE FOR DIRECT DISCHARGE
1. Cost of pipe:
a. Cost per foot (CPU): $/ft.
b. Cost of Pipeline (CP) = (F) (CPU): $
2. Cost of cement lining (see Figure 9 ):
a. Cost of cement lining per foot (CCU): $/ft.
b. Cost of lined pipe (CC) = (F) (CCU): $
3. Subtotal (ST ):
ST1 = [CP + CC] F $
4. Construction cost subtotal (ST ):
2
a. Piping installation cost (CI) = (F)
($/foot installed) $
b. Cost of right-of-way (ROW):
Cost of right-of-way=(ROW) = (F)
($/foot right-of-way) $
5. Pipeline Construction cost (ST ):
ST2 = ST^ + Cl + ROW] F $
SUPPLY LINE COST
1. Capital cost:
a. Cost of pipeline (ST ) $
66
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b. Contingencies (.10) (ST ) :
(Assume 10% of pipeline cost.)
c. Engineering (.10) (ST + contingencies):
(Assume 10% of pipeline and contingencies
cost.)
d. Interest on construction (i ):
c
(Assume 1.625% of cumulative capital costs.)
i = (.01625) (ST + contingencies +
c 2
engineering)
e. Capital cost (CC ) :
CC = ST + contingencies + engineering + i
2. Annual expenditure ($/yr) :
a. Annual amortized expenditure (A_) :
Ap= (CC > $/yr<
P
b. Operation, Maintenance, and Supplies (Op):
(Assume .25% of capital cost.)
Op = (.0025) (CCp) _ $/yr.
c. Interest on working capital (iwc) :
(Assume .7% of all annual expenditures.)
iwc = (.007) (Ap+0p) _ $/yr.
d. Total annual expenditure = TAE :
TAEp = Ap + Op + iwc _ $/yr.
68
-------
PUMP STATION COST
1. Capital cost (knowing brakehorsepower ,
determine cost of pump and motor; see
Figure 10).
a. Cost of pump (P ) :
b. Contingencies (.10) (P ):
(Assume 10% of pump cost)
c. Engineering (.10) (P + contingencies):
(Assume 10% of pump cost and engineering)
d. Interest on construction (ic) :
(Assume 1.625% of cumulative capital costs.)
ic = (.01625) (P + contingencies +
engineering)
e. Capital cost (CCps) :
CCpg = PCU + (contingencies + engineering +
2. Annual expenditure ($/yr) :
a. Annual amortized expenditure
A = (rc )
^s
b. Materials and supplies (Mps) :
(Assume .25% of capital cost.)
MpS = (.0025) CC _ $/yr.
-TO
c. Power cost (EC):
EC - (KWH) (ECU) 8760 hr/yr _ $/yr
69
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d. Operations and maintenance (OM):
(Obtain estimate from curve in Figure 11.)
e. Payroll overhead (PO = (.15) (OM):
(Assume 15% of operations and maintenance
cost.)
f. General and administrative (GA):
(Assume 30% of operation and maintenance,
and payroll overhead cost.)
GA = (OM + PO) (.30)
8-
Interest on working capital (± ):
(Assume .7% of other annual costs.)
iwc = (.007)
4- Mps + EC + OM 4- PO 4- GA)
h. Total annual expenditure (TAE ) :
TAE
ps
i O
+ EC + OM 4 PO + GA +
Total unit cost of supply pipeline and pumping
per barrel of oil (TUG ) :
Ulrlr o
TUG
(TAEp + TAEpg) (42)
OPPS
(XQ) (365.)
Total unit costs of supply pipeline and pumping
per barrel of brine handled (TUCDTiT,c) :
(TAET
TUG
TAEpg) (42)
BPPS
(XB) (365.)
$/yr
$/yr
$/yr
$/yr
$/yr
$/brl oil
$/brl brine
TOTAL DIRECT DISCHARGE SYSTEM COST (Pipeline + Pumping)
1. Total capital cost (TCCPOO):
•TIT O
TCC
PS
CCp 4- CCps
71
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DAILY FLOW RATE, GALLONS PER DAY
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-------
2. Total annual expenditures (TAEp ) .
= TAEp + TAEps _ $/yr
3 . Total unit cost per barrel of oil produced
(TUCopps): _ $/bbl oil
4. Total unit cost per barrel of brine handled
(TUCBppS): _ $/bbl brine
ANALYSIS FOR EVAPORATION POND OR PIT
This analysis considers only the design configuration and associated
approximate costs necessary to develop an appropriate evaporation
pond (see Figure 3) . The evaporation unit is assumed to be installed
at the discharge end of the pipeline previously developed in the direct
discharge analysis; i.e. , the complete evaporation system would in-
volve both the direct discharge analysis from the point of brine collec-
tion to the inlet of the evaporation pond and the analysis for the
evaporation pond. From a cost point of view, this means that the
total evaporation system cost equals the sum of the costs associated
with the pipeline and pumping, those associated with the evaporation
pond, and those associated with storage units which might be needed.
EVAPORATION POND
Assuming the brine is piped to the evaporation site, the following
information is required before beginning the analysis. From pipeline
and pump (Direct Discharge) :
73
-------
1. Total capital cost (CC ) :
i L O
2. Total annual expenditure (TAEppS) :
3. Total unit cost per barrel of brine handled
4. Total unit cost per barrel of oil produced
(TUCopps) :
_$
_$
_$/brl brine
$/brl oil
_ppmTDS
The following information will also be used in the analysis.
1. Average quantity of brine in gallons per day to
be disposed of (Xg) : gpd
2. Total dissolved solids in brine (Q,,) :
D
3. Quantity of oil in gallons per day produced with
the brine (X0) : gpd
4. Number of years of project (Y) : yrs
5. Campany's average cost of capital or discount
rate (i):
6. Land cost (CLU) :
7. Cost of electricity per kilowatt hour (ECU):
8. Net evaporation rate (NER)
(See disposal pond section for evaporation rate
calculation methods.) in./day
_(decimal
fraction)
_$/acre
$/KWH
9. 24-hour point rainfall depth for 50-year recurrence
(storm) interval: ft.
10. Liner cost installed if liner used (or assume
$.031/ft2): $/ft:
74
-------
11. Cost of clearing land (or assume $100/acre): $/acre
12. Cost of liner fill if liner used (or assume
$.40/yd3): $/yd3
13. Cost of excavating dike (or assume
$1.00/yd3): $/yd3
14. Current year Engineering News Record
Building Cost Index (ENRBCI) :
15. State specifications for design.
EVAPORATION POND ANALYSIS
1. The actual number (or fraction) of acres required for the
pond depends on the evaporation rate, depth of brine to be
maintained in the pond (combined with the flow rate of the
incoming brine) , and the general amount of land available
either due to physical or economic limitations. In effect,
there is a balance between capacity and land area, with
overriding topographic considerations. In addition, the
average daily amount of brine flowing into the pond (XR) is
assumed to be constant and containing insufficient oil to form
an evaporation-retarding film on the surface of the pond.
(As little as 1/2 pint of oil forms a film on an evaporation
pond with a surface area of one acre.)
XB
SA = Surface area required (acres) = *Mr-p 017 T—n^-i
INI E*xx \ L* • \ L* X. J. • U )
*It should be pointed out that the net evaporation
rate (NER) should be adjusted for brine salinity
as indicated in the earlier section on evaporation.
75
-------
Although the recommended average evaporation pond liquid
depth is 1 to 1.5 feet, the operator may want to increase the
liquid depth capacity to accommodate peak quantities of brine
and rainfall and to provide for extended periods of humid
weather and low wind velocity. Thus, he may actually
maintain the 1 to 1.5 foot level but increase the liquid depth
capacity to 2 feet or even 4 feet.
Design pond brine liquid depth capacity feet
2 . Another factor to consider is that as the water is evaporated
from the brine, the suspended and dissolved materials accumu-
late at the bottom of the pond as a residue. The depth of this
accumulated residue may be obtained in the following manner.
First, having obtained the brine salinity by chemical analysis,
locate the decimal fraction of deposit per foot of brine depth
per year corresponding to the salinity of the inflowing brine
from Figure 12. Next, knowing the inflow volume of brine in
barrels per day, (Xg), and the surface area of the evap-
oration pond in acres, locate the depth of brine solution per
year from Figure 13. This depth, when multiplied by the
decimal fraction of residue per foot of brine previously
determined, gives the number of feet of residue which can
be expected to accumulate each year in the evaporation pond.
Assuming that the brine flow rate and salinity remain constant
over the life of the evaporation pond, multiply the project
life, in years, by the number of feet per year of residue
76
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accumulation. This value is the expected total residue build-up
over the life of the project.
Total residue feet
3. Next, determine the 24-hour maximum point rainfall depth for a
recurrence interval of 50 years (storm) from the weather bureau
for the vicinity of the evaporation pond.
Maximum rainfall feet
4. Assume a freeboard of 2 feet. This value is good up to an 80
miles per hour wind blowing over a pond with a downwind length
of 2,000 feet.
Total freeboard 2 feet
5. Assume a 1-foot soil cover over the pond liner (if not surrounded
by impervious soil).
Soil cover l feet
6. The total pond depth, measured from the bottom of the pond to
the top of the dike, is the sum of these depths (Dike height, H):
Liquid capacity feet
Total Residue feet
Maximum rainfall in a 24-hour, 50-year storm feet
Total freeboard feet
Soil cover over liner feet
Total pond depth (H) feet
Note: The dike is assumed to have 4-foot crest with a 2:1 slope
on the toe and a 3:1 slope on the heel.
79
-------
7. The next step is to determine the length of the dike necessary
to enclose the pond. To obtain this value, add the lengths of
the sides of the pond; i.e., the perimeter (EP).
Total pond perimeter (EP) yards
8. From Figure 14, determine the volume of dike material, in cubic
yards, required per linear yard of dike. Normally, material for
dikes is obtained from pond excavation materials.) For example,
a pond with a dike height of 10 feet would require 32 cubic yards
of material per yard of dike length.
Total volume of dike material (VT) yds3
9. Next, determine the amount (square feet) of liner material (ALA)
required. (Omit this step if the soil is impervious and a liner
is not required by the state.)
ALA = Area of liner required = (.0111 SA+6)(H-5) + (1.0111)(SA)
(10)
ft2
10. Finally, calculate the quantity of fill (VF) necessary to cover
the liner with one foot of cover.
n r.,-i-i (35 SA+15.000) (H-5) . /1to<;weA\ . r nnn
VF = Cover fill = ^ ' — + (1625) (SA) + 5,000
10
DATA SUMMARY
1. Evaporation area (SA): acres
2. Dike height (H) : feet
3. Length of dike (EP): vards
4. Volume of dike material (VT) : yds
80
-------
oo
1J
t-1-
OQ
CL
3 ~
S 3
[fl ft)
M- O
rt ("
5-3.
^
(T)
O
o:
<
tr
<
LJ
cr
ui
a.
Q
a:
55
50
45
40
35
S 30
25
Ul
Q
15
10
V
789
DIKE HEIGHT. FEET
10
12
13
14
-------
5. Liner area (ALA): ft
6. Volume of liner fill (VF) : yds3
EVAPORATION POND SYSTEM COST ANALYSIS
1. Land Cost (LC) = (cost per acre)(number
of acres): $
2. Cost of stripping the land (CS):
(Assume $100 per acre.)
CS = ($100) (number of acres) $
3. Liner cost (CLL)—omit if necessary:
n
(Assume $.031 per ft ; ALA = liner area)
CLL = (ALA) (.031) $
4. Cost of liner cover fill (CF):
(Assume $.40 per cubic yard for labor, material,
and equipment.)
CF = (VF)($.40) $
5. Dike cost (CD):
(Assume $1.00 per cubic yard for labor, material,
and equipment.)
CD = (VT)($1.00) $
6. Subtotal, evaporation pond cost (ST^,) :
STE = LC + CS + CLL + CF + CO $
7. Capital costs:
a. Evaporation pond cost
82
-------
b. Contingencies (CE): (ST )(.10)
LJ
(Assume 10% of pond cost.)
c. Engineering (Eg): (E£)(.10)(STg + Cg)
(Assume 10% of pond cost and contingencies)
d. Interest on construction (IrF) :
I = (.01625)(ST + Cr + E )
(Assume 1.625% of cumulative capital costs.)
e. Capital cost (CCE) :
CCE = ST£ + CE + E£ + ICE
8. Annual expenditure:
a. Amortization expense (AE) :
AE = CCE
b. Operation and maintenance (OME):
(Assume .5% of capital cost.)
OME = (.005)(CCE)
c. Payroll overhead (PO ):
(Assume 15% of operation and maintenance.)
P0£ = (.15)(OME)
(.007)(GAE + POE
83
OM
A)
$/year
$/year
$/year
General and administrative (GAE):
(Assume 30% of operation and maintenance, and
payroll overhead.)
GA£ = (.30)(OME + P0£) $/year
Interest on working capital (IWE):
(Assume .7% of all annual expenditures.)
$/year
-------
f. Total annual expenditure (TAEE) :
TAE£ = (IWE + GAE + POE + OME + AE) _ $/year
9. Total unit cost of evaporation pond per barrel of
oil (TUG ) :
OE
TAE£ (42)
TUC
OE (X0)(365.)
10. Total unit cost of evaporation pond per barrel
of brine (TUCRT;,) :
DC/
TAB (42)
TUCBE - (XB)(36S.) _ $/brl Oi
TOTAL EVAPORATION SYSTEM COSTS (Evaporation Pond + Pipeline + Pump)
1. Total capital cost (TCCL,,,) :
CO
2. Total annual cost (TAE ):
TAEES = TAEE + TAEp + TAEps $/year
3. Total unit expense per barrel of oil produced
-f TUCopps $/brl oil
4. Total unit expense per barrel of brine disposed
(TUCBES):
TUCBES = TUCBE + TUCBpps $/brl brine
INJECTION
The question of what to do with the brine produced with oil is often
84
-------
conveniently answered by secondary recovery of oil. That is, from a
pollution point of view, the use of brine as a secondary recovery fluid
represents disposal. However, due to treatment costs which may be
necessary to prepare the brine for injection into a production strata,
a separate, non-productive strata is often selected for brine disposal.
The two basic options in subsurface disposal are to drill a new well or
to convert an old well. The following analysis may be used for either
case. As in previous analyses, basic values are assumed to simplify
the analysis procedure. If better values are obtainable, they should
be substituted for the assumed values in the cost or design configura-
tion analysis.
Basically, an injection disposal system is a combination of some type of
brine handling device, a treatment plant, and an injection well. The
brine handling device consists of either trucking or pipeline and pump-
ing (discussion presented in the Direct Discharge Analysis at the
beginning of this section). To the capital and/or annual costs of brine
handling must be added the costs of storage facilities (if used), treat-
ment facilities (if used) , distribution piping and pumping, and the
injection well.
Put rather simply, the injection process is one of moving a fluid (brine
or other injection liquid) down a vertical tube and then dispersing the
fluid within a porous reservoir formation. Thus , the design analysis of
an injection well involves fluid and reservoir mechanics.
85
-------
The injected fluid encounters a fluid friction force with the walls of the
tubing and exerts a static pressure head (height-force) which is essen-
tially the weight of the column of fluid in the tubing. The static pressure
head aids injection; however, the fluid friction force along with the
pressure of fluid already in the formation resists injection. The amount
of resistance to flow depends on such factors as the inside diameter of
the injection tube (the smaller the diameter, the greater the friction
force on the fluid) , the amount of flow, and the viscosity of the brine.
In the reservoir, resistance to flow is influenced by the depth, thick-
ness, porosity, and permeability of the formation. The calculations for
these factors are given in Appendix D,
Assuming the brine is piped to the injection site, the following informa-
tion is required before beginning the analysis. From pipeline and pump:
1. Total capital cost (CCppg): $
2. Total annual expenditure (TAEpp-): $/year
3. Total unit cost per barrel of brine handled
(TUCBpps): $/bbl brine
4. Total unit cost per barrel of oil produced
(TUCopps): $/bbl brine
In addition to the information supplied in the conveyance or direct dis-
charge analysis, the following must also be provided:
86
-------
1.
2.
3.
4.
6.
7.
9.
10.
11.
12.
13.
14.
Quantity of brine to be disposed of in gal-
lons (42 gallons per barrel) per day (X ):
Quantity of oil in gallons per day produced
with brine (XQ):
Number of years of project life (Y) :
Company's average cost of capital or
discount rate (i):
Cost of right-of-way (assume a 30-foot
wide strip at a land cost of $109/acre unless
better cost can be obtained)(ROW):
Cost per kilowatt hour of electricity (ECU):
Current year Engineering News Record Building
Cost Index (ENRBCI):
Disposal formation lithology requirement (Li)
(0 closed hole, 1 open hole):
Total disposal well depth (L) :
Disposal formation porosity ($):
Disposal formation permeability (K):
Disposal formation effective height (h) :
Disposal formation reservoir pressure (P ):
State specifications for design.
_gP
-------
2. Maximum casing head pressure (P )
ch
Pch - .5(L)
3. Minimum tubing I.D. =2 inches
(to prevent excessive friction)
psi
INJECTION WELL FIELD DESIGN PROCEDURE
1. Select tubing I.D. (but do not exceed maximum in
Figure 15)(d):
2. O.D. of external upset tubing of I.D.:
3. Tubing coupling O.D. :
4. Minimum collapse resistance of production
casing = 2L (note: 2 psi/ft depth):
5. Production casing I.D. equal tubing coupling
O.D. plus 2 inches minimum (check collapse
resistance; must be equal to or greater than
minimum):
6. Production casing O.D.:
7. Production casing coupling O.D.:
8. Bottom hole diameter (production hole diam-
eter) , equal to production casing coupling
O.D. plus 2 inches:
inches
_inches
_inches
psi
_inches
_inches
inches
inches
FLUID MECHANICS (See Appendix D for Derivations)
1. Well radius (R ) = 1/24 (bottom hole diameter)
2. Well diameter = Tubing I.D. = d
inches
inches
88
-------
I
u
z
o
z
2
I
x
Z
10
BASED ON COLLAPSE OF
ACCOMPANYING PRODUCTION
CASING
1000 2000 3000 4000
500O
DEPTH OF WELL,FEET
Figure 15. Maximum Tubing Inside Diameter in ,-n
Inches Versus Depth of Well in Feet.
89
-------
3. Number of injection wells (N) (usually 1):
XB
4. Flow rate per well = Xg^ = — gpd
5. Velocity of injected fluid (V):
V = (2.84) (10~4) -5i ft/sec
d2
6. Reynolds Number (N ):
K£J
NUT? = (7.75) (103) (d) (V)
7. Enter friction factor (f) from Figure 16
(use NR£):
8. Friction loss (P ):
Pf = (32.36) (10~2) (f) (L) (V2)/(d)
9. Fluid radius at end of project (r ):
(XR,)(Y)
r^ = (124.6) r ,. °__ % i feet
10. Well spacing (2 r£) : _ feet
11. Bottom hole driving pressure (?d) :
(XR. )log [IS.]
r oi _ '-r^j J ,
Pd ~ L(128.9)(k)(h) J - Psi
12. Static fluid pressure (P ) = .434 (L) _ psi
13. Calculated casing head pressure (P ) :
en
Pch - Pd + Pr + Pf - Pc
14. Allowable maximum P , = (1.0)(L): _
en -
Note: If Calculated P is greater than allowable limit (1.0XL)> repeat
steps 2 through 12 assuming 1 more well each time until P is
less than or equal to (l.OXL)- Also recheck for design limita-
tions above.
90
-------
TO
P
^
(D
n
rt-
h-1-
o
3
ft
K
en
S
in
£1
ft
^
3
o
»-
o
u
£
.02
.01
.009
.002
.001
10*
10 :
10 r
e
3
cr
REYNOLDS NUMBER, N
-------
DISTRIBUTION PIPING - -CEMENT-LINED
1. Arrange wells around injection pump so that the
minimum distance between any two wells is at
least (2) (r ) of the wells.
Note: 1 well.
Brine Flow
-OWell
2 wells.
3 wells
Well 1
Well 3
y-jWell 1
4 or more wells
on branches .
Well 4
Vell 3
Determine the pipe size (d) of the line
from the pump to each well:
d = (1.7)(10~2)(X'45) where X is the
Bl Bi
flow of brine in gpd in the line
being sized.
Add 4 inch to d for cement lining (d')
Well 2
Well 2
jLnches
inches
92
-------
4. Minimum yield pressure from previous section
-------
4. Kilowatts KWH.._:
KWH = (BHP)(.802) KWH,
xi
(See derivation in Appendix D)
5. Required pump capacity =
XD gpm
1440
INJECTION WELL FIELD COST ESTIMATES
1. Well Cost:
a. Enter the cost of pipe ($/ft): $/ft
b. Obtain total cost of well pipe ($/ft)(L): $
c. Enter value for cost of well-head equipment
vs. O.D. (from Figure 17 or use better cost
if available): $
d. Plastic lining:
(1) Enter value for cost of plastic lining
pipe vs. pipe O.D>. (from Figure 9 or
use better cost if available): $/ft
(2) Cost = ($/ft)(L-h) or ($/ft)(L)
if sandstone, i.e. , for sandstone
lithology = 0 $
e. Enter value for injectivity test cost from
Figure 18 : $
94
-------
of 570). To update to current year, multiply graph values
by (ENRBCI of current year/570).
Figure 17. Cost of Wellhead Equipment in Dollars
Versus Tubing Outside Diameter in Inches.47
8888888881$
J $ * * I ;. ? | « S S
swvnoo 'iN3*tdtno3 av3Hii3M
ote: Data used in the preparation of this grap
1962 (Engineering News Record Building Co
CD 3" ™
rt
M pl 9nn
3 CD zo°
n> o
. -
^
^
^
^
^
^
^
^
^
^
^
^
• ' ft "o > 2 3 4 S 6 7 I » PO II IZ IS 14 13 l« 17 It
M H-
g 3 PIPE OQ.INCHES
?O fD
w &•
o
M H-
- 3
-------
of 570). To update to current year, multiply graph values
by (ENRBCI of current year/570).
Figure 18 . Injectivity Test Cost in Dollars
Versus Depth of Well in Feet.47
8OOOQQOOOOOOO
ooooSoSooooo
— - O. *_ «>. K. UJ. «_ *_ « CJ — O ff>
Nfl — ---------
SdVTIOO Ml 1SOO J.S31 AilAliD3rNI
ote: Data used in the preparation of this graph was obtained in
1962 (Eneineering News Record Building Cost Index, ENRBCI,
—
/
/
/
/
/
/
/
/
/
/
/
I.OOO 2 POO J.OOO 4.OOO 5,000 6.0OO 7,000 8POO 9pOO IO,OOO M.OOO I2.OOO I3.0OO I4.OOO I5.OOO I6.00O
DEPTH \N FEET
-------
f. Total well cost (T^) :
T =a+b+c+d+e $/well
wu
g. Total well cost = (T ):
wcl
T = (No. wells)(cost $/well)
2. Distribution Pipe Cost:
a. For each pipe listed in item 6, "Distribu-
tion Piping - Cement-Lined," enter $/ft:
Type Wt. Ib/ft Feet $/ft (line?
or unlined)
_$
_$
$
Note: May be more or fewer than 3 distribution pipes; one
pipe per well.
b. Total feet = . Total Distribution
Cost (TDpc): $
c. Installation and construction cost:
(1) Construction cost (T ) :
ICC
(Assume $.60 per foot or use better
value.)
TICC = ($-60/ft)(total feet) $
(2) Right-of-way (ROW):
(Assume $109 per acre with 30'
right-of-way or better value).
ROW = ($.075)(total feet) $
97
-------
(3) Total cost of installation and con
struction (TTrJ:
Tic " Ticc + ROW
OTHER EQUIPMENT (See Figures 10 and 19)
1. Pump station cost (T ):
W .to
(Enter value from Figure 10 with
BHP approximation.)
2. Storage cost (T ):
b C
(With storage volume = 1/3 daily flow =
X
"Ri
, enter from Figure 19.)
3. Treatment plant. This option is explored
separately due to its potential applica-
tion with any of the three types of dis-
posal mechanisms.
INJECTION SYSTEM CAPITAL AND ANNUAL COST
1. Well Field:
a. Capital costs:
(1) Total well cost (T ):
T =T +T +T +T +• T
WC WC1 DPC 1C WPS SC
(2) Site cost (S.C.) :
s-c- = '2T5Tg.??re (no- wells) ($/acre)
98
-------
80
-I
_J
O
o
V)
o
z
-------
(3) Contingencies = (.10)(T +S.C.):
WC
(Assume 10% of well cost and site
cost.)
(4) Engineering = (. 10) (T^+S .C.
contingencies):
(Assume 10% of well cost, site cost,
and contingencies.)
(5) Interest on construction money
i = .01625 ((3) + (4))
c
(Assume 1.625% of cumulative capital
costs.)
(6) Total capital cost (T):
Tcc =
Engineering + i )
b . Annual expenditures:
(1) Operation and maintenance (OM),
(enter value from "Estimated Opera-
tion and Maintenance" from Figure H
(2) Supplies and materials = (.0025)
(total capital cost) :
(Assume .25% of total capital costs.)
(3) Annual workovers =
(No. wells) ($/ft) (ft/well):
_$/year
_$/year
_$/year
100
-------
(4) Payroll overhead = (,15%)(OM):
(Assume 15% of operations and
maintenance.) $/year
(5) General and administrative:
(Assume 30% of operation and
maintenance and payroll.) $/year
(6) Amortization of capital cost (A):
A = (total capital cost) [ i(1+i^—]$/year
(7) Subtotal, annual expenditures (ST ):
A.CJ
STAE = ((1) + (2) + (3) + (4) +
(5) + (6)) $
(8) Interest on working capital (i ):
we
(Assume .7% of other annual costs.)
i = (.007)(Subtotal) $
we
(9) T°tal - TAWC - (TSA+iwc> $
2. Distribution Pipeline Costs:
a. Capital costs:
(1) Construction costs (T-r~) :
(See 2.c.(3), under "Injection Well
Field Cost Estimates.") $
(2) Contingencies = (.10)(total construc-
tion cost)
(Assume 10% of total construction
cost.) $
101
-------
(3) Engineering = 10% (Contingencies 4- total
construction cost)
(Assume 10% of total contingencies and
construction cost.)
(4) Interest on construction money (i )
i = (.01625) (construction cost,
c
contingencies, and engineering)
(Assume 1.625% of cumulative capital
costs.)
(5) Total distribution pipeline capital
cost = T + Contingency + Engineer-
ing + i
b. Annual expenditures ($/yr) :
(1) Operation, maintenance, and sup-
plies (OM&S):
OM&S = (.0025) (total dist. pipeline
capital cost)
(Assume .25% of total distribution
capital cost.)
(2) Amortization of capital cost (A) :
A = (capital cost dis. pipes) [ 1
(3) Interest on working capital (i ) :
we
i = (.007) (OM&S + A)
we
(Assume .7% of other annual costs.)
$/year
$/year
$/year
102
-------
(4) Total distribution pipeline annual
expenditure (TDpE):
TDpE = OM&S + A + iwc $/year
3. Pump Station and Storage:
a. Capital cost:
(1) Pump station cost (Figure 10): $
(2) Storage cost (Figure 19): $
(3) Total facility cost ((1) + (2)): $
(4) Site cost = (no. acres)[!iL] : $
acre
(5) Contingencies = .10 ((3) + (5))
(Assume 10% of facility and site cost.) $
(6) Engineering = .10 ((3) + (5) + (6)):
(Assume 10% of facility and site cost
and contingencies.) $
(7) Subtotal = ((3) + (5) + (6) + (7)): $
(8) Interest on construction money (i ):
c
ic = (.01625)(Subtotal)
(Assume 1.625% of cumulative capital
cost.) $
(9) Total capital cost
CC = T + i
i ST we
b. Annual Expenditures:
(1) Power cost (P ):
C
PC = (KWH)(8760)(ECU) $/year
(See Injection and Power Requirements, KWH)
103
-------
(2) Enter value from "Operation and
Maintenance" from Figure 11 $/year
(3) Supplies and materials (C ):
CSM= (.0025)(TCC)
(Assume .25% of total capital cost.) $/year
(4) Payroll extras = (.15)(OM):
(Assume 15% of Operation and Main-
tenance cost.) $/year
(5) General and administrative (GA):
GA = (.30)(OM + payroll)
(Assume 30% of Operation and
Maintenance, and Payroll costs.) $/year
(6) Amortization of capital cost (A):
A = (capital cost) [ i(l+i)Y ]
(l+i)Y-l $/year
(7) Subtotal = (1) + (2) + (3) + (4) + (5) + (6):
$/year
(8) Interest on working capital (i ):
we
i = (.007)(Subtotal)
we
(Assume .7% of all annual
expenditures.) $/year
(9) Total annual expenditure for in-
jection well field (TAE.):
TAE = (Subtotal + i ) $/year
i we
104
-------
INJECTION COST SUMMARY
1. Total unit cost of injection well field per
barrel of brine (TUG .):
Bi
TAB. (42)
TUCBi =(XB)(365.) $/brl brine
2. Total unit cost of injection well field per
barrel of oil (TUCoi):
TAB. (42)
TUCn. = $/brl oil
01 (X )(365.)
o
TOTAL INJECTION SYSTEM COST (Injection Well + Pipeline + Pumping)
1. Total capital cost (TCC ):
is
TCCJ = CC. + CC + CC $
is i p ps
2. Total annual cost (TAB ):
is
TAEis = TAEi + TAEp + TAEps $/year
3. Total unit cost for injection system per
barrel of brine injected (TUG,,. ):
Bis
TUCBis = TUCBi + TUCBpps $/brl brin
4. Total unit cost for injection system per
barrel of oil produced (TUG ):
v/1 S
TUCOis * TUCOi + TUCOPPS
WATER TREATMENT FOR BRINE DISPOSAL
Generally, there are several degrees and types of brine treatment. The
treatment process selected depends on the characteristics of the brine to
105
-------
be treated and the degree of treatment required for disposal or beneficial
use of the water. This topic was described more thoroughly in the sec-
tions on pollution and water treatment; therefore, it will not be developed
here.
This discussion of treatment is oriented to brine handling prior to dis-
posal (although treatment may be necessary prior to other methods of
disposal) . The treatment process (if it is necessary) can be inserted
almost anywhere in the supply and distribution system connecting the
production well and disposal device but is usually placed just prior to
the disposal system. In this way, the treated water or brine has a
minimal chance of being altered prior to injection.
Two general descriptions of the design configuration-cost analysis
approach to treatment will be given. The first involves the use of a
47
single, overall relationship developed by Koenig to describe pre-
injection treatment. This relationship is displayed graphically as
capital and operating costs associated with pre-injection treatment.
(This analytical procedure is also followed by the computer program
described in Appendix E.)
The second method is to identify undesirable characteristics and present
appropriate relationships to handle each case. It should be empha-
sized that the intent of both of these analyses is not to present or identify
exact costs but to sequence the arrangements of either approach to treat-
ment. Also, since this discussion is oriented toward disposal or prep-
aration prior to disposal, a higher order beneficial use could conceivably
introduce processes and costs not considered in this analysis.
Table 8 gives treatment operations.
106
-------
Table 8. TREATMENT OPERATIONS
54
Operation/Equipment
1. Baffles . 1.
2. Skimming .
3 . Aeration . 3 .
Chlorination.
Chemical coagulation and
sedimentation (hydrated
lime and alum) .
Filtration (pressure,
carbon, and sand).
Objective
Regulate flow (velocities and
directions) .
2. Remove floating oil.
Oxidation of soluble ferrous
compounds to insoluble ferric
compounds and soluble carbon-
ate compounds to insoluble
carbonate compounds.
Aid in the further oxidation
of iron, and control algae
and bacterial growths .
Removal of the compounds which
would form scales on the reservoir
interface; e.g., iron compounds,
calcium compounds, and small
amounts of hydrocarbon com-
pounds .
Removal of small particles from
sedimentation operation.
107
-------
Table 9 lists undesirable waste characteristics and removal operations.
Table 9. UNDESIRABLE WASTE CHARACTERISTICS AND REMOVAL OPERATIONS
54
I ^.desirable Characteristics
Treatment Operations
1. Suspended Material:
a. Oils and other floating
material.
b. Solids, colloids, etc.
c. Biological growths
(e.g. slime forming
algae and bacteria)
2. Dissolved Substances:
a. Gases
b. Undesirable ions
3. Corrosiveness:
A.P.I. Separator
Skimming
Floatation
Chemical coagulation
Sedimentation
Centrifugation
Gravity Sand Filtration
Pressure Sand Filtration
Diatomite Filtration
Chlorination
Filtration
Aeration
Purging
Vacuum Degasifer
pH Adjustment
Neutralization
Precipitation, Chemical
Coagulation
Ion Exchange
Membrane Process
Removal of Gases
pH Control
WATER TREATMENT ANALYSIS
e. following information is required before beginning the analysis
108
-------
1. X = Quantity of oil produced with brine in
gallons per day. gpd
2. X = Quantity of brine to be treated in gal-
ls
Ions per day. gpd
3. MX = Quantity of brine to be treated in
millions of gallons per day.
jj
MXR = mgpd
1,000,000
4. i = Discount rate or cost of capital. decimal
fraction
5. Y = Project life. years
DESIGN ANALYSIS
A typical pre-injection system is shown in Figure 20. Components and con-
figuration are reasonable; however, the less the amount of brine to be
treated, the smaller the treatment plant. This analysis assumes a minimum
of 1,000 gallons of brine to be treated per day, 365 days per year.
1. Capital cost:
a. Capital cost may be taken directly from
Figure 21 : $
b. Capital cost may instead be assumed to be
composed of principal component costs
(enter zero if component not used) :
(1) Primary treatment (sedimentation)
cost (C ) :
Cp = (.345)(MXB)'708 (10547.) $
109
-------
20% NaOH
Backwash to Sump
Acid Waste
pH RC
Slowdown to
Sump
To Injection Well
Injection Pump
Polishing Filters
Cartridge
Figure 20. Pre-Injection Waste Treatment Scheme.
54
Filter
Backwash
Neutralization
Tank
Primary Filters
Anthrafilt
Backdown
to
Sump
-------
53
O
rt
(D
p>
OQ
C
*t
n
o
o
en
3 Ul
.-»•
•s
o
3
0.
*°
n
•^
D
P
(O
C
CO
cr o M o
v< t-h vo P>
O\ rt
,-x Ui 10 P>
C
CO
(D
W
n
o o
M>
c
o -o
c a
n> n>
3
n> n
Cn (D
«j 3
O rt
(D
OQ
3 H-
(I) 3
n>
rt
y
(D
Do
CD SO
ya p>
o
X a4
pi
03
3
(D
D-
C O
(D M H-
W - p
100,000
CAPACITY. GALLONS PER DAY
-------
(2) Secondary treatment (aeration)
Cost (C )':
.785,
Cs = (.531)(MXB)"OJ(10547.) - Cp
c. Subtotal treatment system construction
Cost (enter either a or applicable of
(1), (2) (CTg):
d. Contingencies = (.10)(C ):
•i- O
(Assume 10% of construction cost.)
e. Engineering = (.10)(contingencies +
CTS)
(Assume 10% of construction cost and
contingencies.)
f. Interest on construction money (i ):
ic = (.01625)(C + contingencies +
engineering)
(Assume 1.625% of cumulative capital
costs.)
g. Total capital cost (CC ):
TS
CC = (C + contingencies + engineer-
Is TS
ing + 1).
2. Annual Cost:
a. Annual expense may be taken directly from
Figure 22'
b. Annual cost may instead be assumed to be com-
posed of appropriate principal component costs ;
52
_$/year
112
-------
(JQ
C
2
o
t\J
po
o. a
o
VI
O
3
H.
§ 3
o
O
to
Ln
O
ho
0
Hi
o.
pj
fl>
ft
CD
tu
O rt
CM
'w en
3 CD
K) Cu
H-
3 H-
n 3
n>
M rt
H- O*
3 fb
10
X3
ID n>
w to
w to
n H.
o o
3
CL
O
bd MI
H- rt
CO
3
» TO
O to
O Tl
3 cn
a.
o
cr
w H-
< g 3
I-1 W CL
C O
ro H H-
cn - 3
IfiOOfOO
IOQPOO
K
Ul
o.
s
I.OOO I
KJ.OOO 11x^000 ipoo.ooo
AVERAGE QUANTITY OF WATER TREATED, GALLONS PER DAY
10.000,000
-------
(1) Annualized capital cost for ap-
propriate components:
ATS = CCTS - _ $/year
TS lb
(2) Annual Operations and Maintenance
for appropriate component (enter
zero if component not used).
(a) Primary treatment (sedimentation)
cost operation and maintenance (OM ) :
OMp = (4.561)(10~2)(MXB)-'205(.565XB)
_ $/year
(b) Secondary treatment (aeration)
cost operation and maintenance (OM )
-2 -
OMg = (8. 679) (10 Z)(MXB) ' (. 565Xg) - (OMp)
_ $/year
(3) Operation and maintenance cost (OM ):
J- O
OMTS = °MP + °MS $/year
(4) Subtotal annual expenditures or sum
of component annual costs:
(a) Operation and maintenance (OM ): $/year
J- L>
(b) Annual amortized expenditure (A ): $/year
•*- O
(5) Interest on construction (assume .7%)
(i ):
c
ic = (.007)(OMTS + Ajg) $/year
114
-------
(6) Total annual expenditure (TAETg):
TAE^ = i + OM + A S/year
TS c TS TS
(7) Total unit cost of treatment plant
per barrel of brine treated
TAE
TUC__p = TS (42) $/brl brine
BTP (XB)(365.) treatment
(8) Total unit cost of treatment plant
per barrel of oil produced (TUCOTp):
TAE
TUCOTP ' r $/brl
SELECTION OF BEST ALTERNATIVE
If more than one disposal method is considered (assuming no treatment), then:
1. Compare TUC^ with TUC^ with TUC0pps.
2. Select the least expensive allowable alternative on the basis
of lowest annual cost.
3. These TUG values may be compared directly with oil price at the
well-head for use in analyzing the impact of disposal on pro-
duction, as well as total production-disposal expenses.
If treatment is necessary, then:
1. Obtain the value of TUC which is composed of factors most
nearly approximating each system's treatment needs.
2. Add appropriate TUC to applicable disposal system.
115
-------
3. Compare TUG values after treatment costs have been added.
4. Select the allowable disposal alternative based on lowest
annual costs.
DEFINITION OF TERMS
Hf = Head loss due to friction (feet)
F " = Length of pipeline (miles)
F = Length of pipeline (feet = 5280F")
L = Total depth of well (feet)
X = Quantity of disposed brine (gallons per day)
X = Quantity of produced oil (gallons per day)
Y = Project life (years)
i = Discount rate; cost of capital (decimal fraction)
EL = Relative elevation of discharge point (feet)
ROW = Right-of-way cost (%/acre)
ECU = Electricity cost ($/KWH)
H = Required pumphead (feet)
TAE = Total annual pipeline expenditure ($/year)
TAB = Total annual pump station expenditure ($/year)
ps
TUG = Total unit cost of pipeline and pumping per barrel of
P P
oil produced ($/brl oil)
= Total unit of pipeline and pumping per barrel of brine
handled ($/brl brine)
116
-------
TAE_ = Total annual evaporation pond expenditure ($/year)
ti
TUG = Total unit cost of evaporation pond per barrel of oil
Ulj
produced ($/brl oil)
TUCL,., = Total unit cost of evaporation pond per barrel of brine
DCi
produced with the oil ($/brl brine)
TAE. = Total annual injection well field expenditure ($/year)
TUC = Total unit cost of injection well field per barrel of
Bi
brine injected ($/brl brine)
TCU . = Total unit cost of injection well field per barrel of oil
produced ($/brl oil)
TAE Q = Total annual cost of brine treatment plant $/year
J. O
TUCL,™ = Total unit cost per barrel of brine treated for treatment
JJlr
plant
TUC = TAETS
BTP XB (365) (42) $/brl brine
TUC^-n = Total unit cost per barrel of oil produced for treatment
B ir
plant
TAP
TUC_Tp = TS $/brl oil
Ui X (365) (42)
o
117
-------
SECTION VI
IMPROVEMENTS TO INDIVIDUAL DISPOSAL
No discussion of oilfield brine disposal is complete without mentioning
two areas which could potentially increase the efficiency of production
disposal (as far as lowering brine disposal costs) and result in an addi-
55
tional source of income. The first area is secondary recovery. Actu-
ally, secondary recovery is a special kind of beneficial use in which
the injected brines are used to displace a portion of the remaining oil in
the reservoir. Brines used in secondary recovery may also be used later
for some type of industrial or agricultural application such as cooling or
irrigation. (See the previous sections on beneficial uses for limitations.)
The second type of beneficial use is by-product recovery in which the
value attached to the minerals in brine is sufficient to warrant extraction.
SECONDARY RECOVERY
State oil production regulating agencies specify procedures for unitizing
a reservoir. Usually, the consent of a majority of the landowners over
a reservoir is sufficient to establish a unit (provided the majority is
equal to or greater than the percent specified by state law) . After or
concurrent with the landowners' consent, a formula for dividing oil
production revenues is devised and approved by the members of the
unit. The next step is to decide how the unit will be run and who will
run it. Normal practice is for the largest operator in the field to direct
the production and secondary recovery operations of the entire reservoir.
118
-------
It is not the intent of this publication to discuss waterflooding; however,
a summary of the advantages and disadvantages of this method of opera-
tion might prove useful to prospective unit participants,
gives that summary.
57
Table 10
Table 10. WATERFLOODING ADVANTAGES AND DISADVANTAGES
3.
4,
Advantages
Permits efficient, controlled
production of a reservoir for
maximum yield at minimum
cost.
Handles large volumes of
fluid economically.
Eases the burden of disposal.
Small landowner can partici-
pate without drilling.
Conserves reservoir energy
through higher yields; i.e. ,
more complete production and
increased productive life.
Disadvantages
1. Pool may be too small to
justify secondary recovery.
2 . Pool may have so many
landowners that arbitration
may be impossible.
3. Reservoir characteristics
might prevent secondary
recovery.
4. Major operator's interest
may be too small to justify
his participation.
5. Pressurization may initiate
groundwater pollution (not
previously existent in the
field) via unplugged aban-
doned wells or seismographic
holes.
6. Difficulty and expense of
locating and plugging verti-
cal holes of communication
may preclude developing the
field by waterflood.
In addition to references 53 and 58 , three publications may be helpful
as guidelines in secondary recovery operations: 57 , 59, and 60-
119
-------
MINERAL BY-PRODUCT RECOVERY
There are numerous operations which withdraw saline groundwater
j * * i* j • i 61, 62, 63, 64, 65 . . . ,
and extract salts and minerals . An analysis of a
typical mineable midland brine is given in Table 11.
Table 11. MIDLAND BRINE CONSTITUENTS63
Constituents Concentration
Calcium Chloride (CaC^) 190,000 ppm
Magnesium Chloride (MgC^) 36,500 ppm
Sodium Chloride (NaCl) 52,000 ppm
Potassium Chloride (KC1) 16,800 ppm
Bromine (Br2) 2,600 ppm
Iodine (i 38 ppm
Relatively recently, there have been several publications advocating
the potential of mineral by-product recovery from oilfield brines. A
a
valid basis for this interest is the estimate that approximately 8 x 10
barrels of brine are produced each year with the oil produced in the
/ / 0
United States. These brines contain more than 1.3 x 10 tons of
minerals and salts (32 pounds per barrel) (see Table 1).
Another article developed the point that based on sheer quantity, the
mineral content of oilfield brine disposed of each year is worth more
than $3 billion. As a rough estimate, Tables 12 and 13 indicate
the dependence of the market value of specific recoverable chemicals
on the quantity of fluid handled and depth of reservoir.
When Table 12 is used with Table 13, it becomes apparent that consid-
erable profits can result if it is possible to process a concentrated brine
either at the surface of the ground after oil separation or upon raising
the brine from a fairly shallow depth.
120
-------
Table 12. DOLLAR VALUE OF DISSOLVED CHEMICALS A BRINE
SHOULD CONTAIN PER 1 MILLION POUNDS (2,840 bbl)
OF BRINE PRODUCED FROM A GIVEN DEPTH
Value ($/million Ib of brine)
210
440
650
Depth of Well (ft)
2,500
7,000
10,000
Table 13. AMOUNT OF ELEMENT PER 1 MILLION POUNDS
OF BRINE NECESSARY TO PRODUCE CORRESPONDING
CHEMICAL PRODUCT WORTH $250
Element
Sodium
Potassium
Lithium
Magnesium
Calcium
Strontium
Boron
Bromine
Iodine
Sulfur
Concentration (ppm)
50,000
14,000
170
8,000
11,000
4,000
1,400
1,700
250
5,300
Product
Sodium chloride
Potassium chloride
Lithium chloride
Magnesium chloride
Calcium chloride
Strontium chloride
Sodium borate
Bromine
Iodine
Sodium sulfate
121
-------
These two tables should be used together; i.e. , 1 million pounds
(2,840 barrels) of brine containing 50,000 ppm sodium and 1,700 ppm
bromine produced from a depth of 7,000 feet would be worth $250
+ $250 - $440 = $60 (assuming Table 12 gives cost of mining) .
The Dow Chemical Company has mined iodine (10 to 135 ppm) from
California oil brines; however, little has appeared recently to indi-
cate the extent of mineral mining or by-product recovery. Perhaps
one reason for the seeming general lack of activity can be explained
by operating figures for some of the companies currently mining
bromine in the Smackover region of Arkansas (not intentionally pro-
ducing oil) . These figures are given in Table 14.
Table 14. BRINE QUANTITIES
Company
1
2
3
4
5
6
Volume
(bbl/month)
2,055,818
175,797
355,895
4,823,242
2,038,923
2,691,120
Concentration
Bromine (ppm)
4,800
4,000
5,000
4,500
4,500
4,500
Depth (ft)
8,300
7,600
7,600
8,400
7,700
7,400
Company No . 6 processes approximately 3.16 million pounds of brine
a day. Assuming it is worth (2 .65) ($250) = $663 per million pounds of
brine, then the company could have a gross revenue from this activity
of $2,090 - (3.16) (450) = $668 per day.
Unfortunately, the brine flow from most oil wells or collection of oil
wells is considerably less than this rate. The reluctance of most small
122
-------
operators to get into mineral by-product operations seems mainly due
to the following reasons:
1. There are relatively high capital and operating costs,
especially in remote areas .
2. Proration and well spacing requirements make accumula-
tion of high brine volumes expensive.
3. Occasional oil in the brine fouls separating mechanisms,
especially if the process of chelation is used. ^0
4. Equipment is fairly complicated to operate.
5 . Market for minerals is variable.
While it appears that several of the majors are conducting exploratory
efforts in this area, mineral by-product recovery has few possibilities
for the individual small independent. On the basis of a sizeable unit or
similar cooperative group, however, the individual small operator
acquires the resource potential of a large operator (from the reservoir
operations point of view), and such operations as mineral by-product
recovery enter his realm as a potential source of additional profit.
123
-------
SECTION VII
REFERENCES
Collins, A. G. Here's How Producers Can Turn Brine Disposal
into Profit. Oil and Gas Journal. 64(27): 112, 1966.
Handbook of Chemistry and Physics. Chemical Rubber Publishing
Co. , 42nd Edition, 1961.
Wright, Jack, et al. Analysis of Brines from Oil-Productive
Formations in Oklahoma. USBMRept. Invest. 5326, 1957. p. 71.
Gambs, Gerard C. , and Arthur A. Rauth. The Energy Crisis.
In: Chemical Engineering . Albany, McGraw-Hill Publishing Co.,
1971. p. 59-60.
Sparkling, Richard C. , Norma J. Anderson, and John G. Winger.
1969 Annual Financial Analysis of a Group of Petroleum Companies.
New York, Chase Manhatten Bank, 1970. p. 8, 12, 22.
Root, Paul J., John P. Klingstedt, Neil J. Dikeman, Jr., and A. G.
Homan. The Impact of Changes in the Intangible Drilling Costs
and Depletion Allowance Provisions on the Independent Oil Pro-
ducers in Oklahoma Economy. Bureau for Business and Economic
Research, Univ. of Okla., Norman, Okla. 1969. p. 2, 13, 27.
National Stripper Well Survey. Interstate Oil Compact Commission,
Oklahoma City, Okla. 1970. p. 2.
The Oil Producing Industry in Your State. Independent Petro-
leum Association of America, Tulsa, Okla. 1970. p. 4, 8.
124
-------
9. Federal Water Pollution Control Act Amendments of 1972. Public
Law 92-500, 92nd Congress, S. 2770, October 18, 1972. p. 89.
10. U.S. Public Health Service Drinking Water Standards, 1962.
USPHS Publication No. 956. Washington, D.C., U.S. Government
Printing Office . p. 61.
11. McKee, Jack Edward, and Harold W. Wolf. Water Quality Criteria.
State Water Quality Control Board, Sacramento, California. 2nd
Ed. 1963. p. 88, 112, 129-147, 149, 151-154, 159-163, 201-202,
210-212, 258-259, 275-277.
12. McKee, J. E. Report on Oil Substances and Their Effects on the
Beneficial Uses of Water . State Water Pollution Control Board,
Sacramento, Calif. Publ. 16. 1956. p. 45.
13. Water Quality Criteria. Report of the National Technical Advisory
Committee to the Secretary of the Interior, Superintendent of Docu-
ments. Washington, B.C., U.S. Government Printing Office.
1968. p. 45-46, 72-74.
14. Pollution-caused Fish Kills in 1963. U.S. Department of Health,
Education, and Welfare, Washington, D.C. p. 14.
15. Subsurface Salt Water Disposal. Dallas, Texas , American
Petroleum Institute, 1960.
16. Collins, A. Gene. Are Oil and Gas-Well Drilling, Production
and Associated Waste Disposal Practices Potential Pollutants of
the Environment? U.S. Dept. of Interior, Bureau of Mines,
Bartlesville Petroleum Research Center, Bartlesville, Okla.
1970. p. 11.
17. East Texas Salt Water Disposal Company. Salt Water Disposal—
East Texas Oil Field. 2nd Ed. Petroleum Extension Service,
Univ. of Texas, Austin, Texas. 1958.
18. Case, L. C. Water Problems in Oil Production, An Operator's
Manual. Tulsa, Okla. , The Petroleum Publishing Co. 1970.
p. 22-119.
125
-------
19. Thompson, D. A., A. R. Mead, and J. R. Schreiber. Environ-
mental Impact of Brine Effluents on the Gulf of California. U.S.
Department of the Interior, Office of Saline Water, Washington,
B.C. Report 387. 1969. 172 p.
20. Water Quality Control Plan for Ocean Waters of California.
California Water Resources Control Board. July 6, 1972.
21. Fryberger, J . S . Rehabilitation of a Brine-Polluted Aquifer .
U.S. Environmental Protection Agency. Report EPA-R2-72-014.
December 1972. p. 61.
22. Smoak, W. G. Spray Systems—A Method of Increasing Water
Evaporation Rates to Facilitate Brine Disposal from Desalting
Plants. U.S. Department of the Interior, Office of Saline Water,
Washington, D.C. Report 480. 1969. p. 8-13.
23. Moore, J. , and J. R. Ruwkles. Evaporation from Brine Solutions
Under Controlled Laboratory Conditions. Texas Water Develop-
ment Board, Austin, Texas. Report 77. 1968. p. 35-49.
24. Day, M. E. Brine Disposal Pond Manual. U.S. Department of the
Interior, Office of Saline Water, Washington, D.C. Report 588.
1970. p. 2-7.
25 . Keyes , C . G . , Jr . , W . S . Gregory, N . N . Gunaji, and J . V .
Lunsford. Disposal of Brine by Solar Evaporation: Design
Criteria. U.S. Department of the Interior, Office of Saline Water,
Washington, D.C. Report 564. 1970. p. 55-90.
26. Buttermore, P.M. Water Use in the Petroleum and Natural Gas
Industries. Bureau of Mines I .C . 8284. 1966. p. 4.
27. Galley, J. E. (ed.). Subsurface Disposal in Geologic Basins—
A Study of Reservoir Strata. The American Association of Petro-
leum Geologists, Tulsa, Okla. 1968. p. 11-19.
126
-------
28. Warner, Don L. Deep Well Waste Injection—Reaction with Aquifer
Water. In: Proc . Am. Soc. Civil Eng ., Sanit. Eng . Div.,
92.CSA4): 45-69, 1966.
29. Payne, R. D. Salt Water Pollution Problems in Texas. Journal
of Petroleum Technology. 18_(11): 1401-1407, 1966.
30. Wright, C. C. , and D. W. Davis. The Disposal of Oilfield Waste-
water. American Petroleum Institute, Los Angeles, California.
1966.
31. Melton, C. G. , and R. L. Cook. Water-Lift and Disposal Operations
in Low-Pressure Shallow Gas Wells. Journal of Petroleum Tech-
nology. 1_6(6): 619-622, 1964.
32. Blair, J. V. Treatment of Produced Salt Water . Oil and Gas
Journal. 4^(42): 176-185, 1952.
33. Roschle, A., J. E. Smith, and M. E. Wills. Let Engineering
Know-How Solve Salt Pollution Problems. Oil and Gas Journal.
63_(32): 75-79, 1965.
34. Muskat, M. Physical Principles of Oil Production. New York,
McGraw-Hill Book Co . 1949.
35. Reid, G. W., et al. Deep Subsurface Disposal of Natural and Man-
made Brines in the Arkansas and Red River Basins. Univ. of
Okla., Norman, Okla. August I960.
36. Wheeler, R. T. Water-Treating Plants. Oil and Gas Journal.
5H7): 95-96, 1952.
37. Standard Methods for the Examination of Water and Wastewater,
American Public Health Association, Inc., New York, N.Y.
12th Ed. 1966.
38. Watkins, J. W. Analytical Methods of Testing Waters to be
Injected into Subsurface Oil Productive Strata. U.S. Department
of the Interior, Bureau of Mines . Report 5031. 1954.
127
-------
39. Ostroff, A. G. Introduction to Oilfield Water Technology.
Englewood Cliffs, N.J. , Prentice-Hall, Inc. 1965. p. 148-399.
40. DePree, David O. , and Herman H. Weyland. Recovery of Metal
Salts from Concentrated Brines by Chelation. U.S. Department
of the Interior, Office of Saline Water, Washington, D.C.
Report 435. 1969. p. 2.
41. Combating Corrosion—Third Annual Corrosion Control Short
Course. Sponsored by the College of Engineering, Univ. of
Okla. , Norman, Oklahoma, 1956. 1969. p. 149-238.
42. Fair, G. M. , and J. C. Geyer. Water and Wastewater Engineering.
Vol.2. New York, J. Wiley. 1966.
43. Rice, I. M. Organizing, Designing, and Operating a Salt-Water
Disposal System. Oil and Gas Journal. 5JK11): 80-94, 1951.
44. Kohler, M. A., T. J. Nordenson, and D. R. Baker. Evaporation
Maps for the United States . Washington, D .C. 1959.
45. Stagle, K. A. , and J. M. Strogner. Oil Fields Yield New Deep-
Well Disposal Technique. Water and Sewage Works. 11^(6): 240,
242, 1970.
46. Bleakley, Bruce. Bayou Sorrel Salt Water Disposal System.
Oil and Gas Journal. 681(38): 146, September 12, 1970.
47. Koenig, Louis . Ultimate Disposal of Advanced Treatment Waste.
U.S. Public Health Service. May 1964. p. 14, 15, 63-65.
48. Standardized Procedure for Estimating Costs of Conventional
Water Supplies. Kansas City, Mo., Black and Veatch. 1963.
p. 49.
49. Burnitt, S. C. , and R. L. Crouch. Investigation of Ground Water
Contamination. Texas Water Commission. June 1964.
50. Holloway, H. D. , and T. R. Weaver. The Potential Contribution
of Desalting to Future Water Supply in Texas. Southwest Research
Institute, Austin, Texas. 1966. p. 78.
128
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51. Perry, JohnH. Chemical Engineer's Handbook. New York,
McGraw-Hill Book Co., Inc. 3rd Ed. 1950. p. 382.
52. Economic Evaluation Mode System (EEMS) for Analysis of the
Desalination Potential. U.S. Department of the Interior, Office
of Saline Water, Washington, D.C. 1970.
53. Proceedings of the Conference on Water Quality Control for Sub-
surface Injection. School of Petroleum Engineering, Univ. of
Okla., Norman, Okla. , 1956. p. 23.
54. Moseley, Joe Clifton, II, and Joseph F. Malina. Relationships
Between Selected Physical Parameters and Cost Responses for the
Deep-Well Disposal of Aqueous Industrial Wastes . Univ. of
Texas, Department of Civil Engineering, Austin, Texas. 1968.
p. 41-45, 48, 50, 51, 218-231.
55. Torrey, Paul D. Future Water Requirements for the Production
of Oil in Texas. Texas Water Development Board, Austin, Texas.
Report 44. Reprint 1969.
56. Coburn, A. A. , and Charles E. Bowlin, Jr. Water Use by the
Petroleum Industry. Interstate Oil Compact Commission, Okla-
homa City, Okla. 1967.
57. Khan, Anwar A. , and Harry H. Power. Engineering Base of
Participation in Unit Agreements. Interstate Oil Compact Commis-
sion, Oklahoma City, Okla. 1960.
58. A Survey of Unitized and Cooperative Agreement Projects in the
United States. Interstate Oil Compact Commission, Secondary
Recovery Division, Oklahoma City, Okla. 1952.
59. Unitized Oilfield Conservation Projects in the United States.
Interstate Oil Compact Commission, Oklahoma City, Okla. 1959.
60. Unitized Oilfield Conservation Projects in the United States and
Canada. Interstate Oil Compact Commission, Oklahoma City,
Okla. 1962.
129
-------
61. George, D'Arey R. , G. M. Riley, and Laird Crocker. Preliminary
Process Development Studies for Desulfating Great Salt Lake
Brines and Sea Water. U.S. Department of the Interior, Bureau
of Mines, Washington, D.C. 1967.
62. Leiserson, Lee, and Paul C. Scott. Chemicals from Sea Water
Brines. U.S. Department of the Interior, Washington, D.C.
Report 445. 1969.
63. Kelly, James A ., and Albert A. Gunkler. Production of Chemicals
from Brine. Dow Chemical Co., Midland, Michigan, p. 1-7.
64. Brennan, P. J. Nevada Brine Supports Big New Lithium Plant.
In: Chemical Engineering . McGraw-Hill Publishing Co.
August 15, 1966. p. 86-88.
65. Sawyer, Frederick, G. , M. F. Ohman, and Fred E. Lusk. Iodine
from Oil Well Brines. Industrial and Engineering Chemistry.
jl: 1548-1552, August 1949.
66. Angio, Enerst E. Selective Element Recovery from Oil Field
Brines. Water Resources Research, 6(5): 1502, October 1970.
67 . Collins , A . Gene . Finding Profits in Oil-Well Waste Waters .
Chemical Engineering, p. 165-168. September 21, 1970.
68. Joint Association Survey of Industry Drilling Costs (Section 1),
Sponsored by American Petroleum Institute, Independent Petroleum
Association of America, Mid-Continent Oil and Gas Association,
Tables 1-39. 1962.
130
-------
SECTION VIII
APPENDICES
Pat
A. SUMMARY OF STATE OIL REGULATING AGENCIES 132
B . SUMMARY OF STATE WATER CONTROL AGENCIES,
POWERS, AND PENALTIES 177
C. LABORATORY TESTS 212
D. ANALYSES FORMULA DEVELOPMENT 213
E. COMPUTER PROGRAM FOR DISPOSAL BY INJECTION,
EVAPORATION, DIRECT DISCHARGE 223
131
-------
APPENDIX A
SUMMARY OF STATE OIL REGULATING AGENCIES
ALABAMA
1. Regulating Agency:
State Oil & Gas Board of Alabama
P.O. Drawer 0
Walter Bryan Jones Hall
University, Alabama 35486
2. Publication of Regulations:
Oil & Gas Laws of Alabama with Oil & Gas Board
Forms and Definitions of Oil and Gas Terms
Geological Survey of Alabama
Reprint Series 20
(1967)
3. Coordinating Agency:
Alabama Water Improvement Commission
Montgomery, Alabama
4. Application Flow Chart
Brine
Disposal
Applicant
Permit petitioned
at public hearing
Reviewed by board &
approved or rejected
Oil &
Gas Board
5. Allowable Methods of Disposal:
Injection.
Pits, lined.
Pits, unlined (depending on soil),
132
-------
ALABAMA (Cont)
6. Permit Costs
None.
ALASKA
1. Regulating Agency:
Department of Natural Resources
Oil and Gas Conservation Committee
3001 Porcupine Drive
Anchorage, Alaska 99504
Publication of Regulations:
Oil and Gas Conservation Regulations
and Statutes
(1969)
3. Coordinating Agencies:
Department of Health and Welfare
Pouch H
Juneau, Alaska 99801
Environmental Protection Agency
Alaska Operations Office
Room 8, Federal Building
605 Fourth Avenue
Anchorage, Alaska 99501
No brine disposal permits to date.
No regulations on brine disposal.
133
-------
ARIZONA
Regulating Agency:
Oil & Gas Conservation Commission
State of Arizona
4515 North 7th Avenue
Phoenix, Arizona 85013
Publication of Regulations:
Rules and Regulations,
The Oil and Gas Conservation Commission
of the State of Arizona
(1965)
3. Coordinating Agency:
Department of Health
Fifth Floor
Goodrich Building
14 North Central Avenue
Phoenix, Arizona 85004
4. Application Flow Chart:
Application
for permit
Oil & Gas
Conservation
Commission
Permit approved
or refused
5. Allowable Methods of Disposal:
Injection.
Pits, lined.
Pits, unlined (where approved depending on soil)
134
-------
ARIZONA (Cont)
6. Permit Costs:
Injection: $25.00 (plus $5,000 plugging bond),
Pits: No permit required.
ARKANSAS
1. Regulating Agency:
State of Arkansas Oil & Gas Commission
Oil & Gas Building
El Dorado, Arkansas
2. Publication of Regulations:
General Rules & Regulations Relating
to Oil & Gas
Order No. 2-39
(revised February 1956)
3. Coordinating Agencies:
State Geological Survey
State Capitol Building
(Director, Norman F. Williams)
State Department of Health
4815 W. Markham Street
Little Rock, Arkansas 72201
4. Application Flow Chart:
135
-------
ARKANSAS (Cont)
Brine
Disposal
Operator
fc Oil & Gas
Commission
*-
otate (jeo-Logicai
Survey
Department of
Uool »-h
Note: The commission, in passing on applications for the use
of non-producing formations for disposal formations, will be ad-
vised by the technical recommendations of the State Geological
Survey and the State Board of Health in determining whether such
formations may be safely and legally used.
Allowed Disposal Methods:
Injection.
Ponds, lined.
Ponds, unlined.
Disposal Permit Costs:
Injection: None.
Ponds: None.
CALIFORNIA
1. Regulating Agency:
Department of Conservation
Division of Oil & Gas
1416 Ninth Street
Sacramento, California 95814
136
-------
CALIFORNIA (Cent)
2. Publication of Regulations:
California Laws for Conservation
of Petroleum and Gas
(1968)
3. Coordinating Agency:
California State Water Resources
Control Board
Room 1140, 1416 Ninth Street
Sacramento, California 95814
4. Allowable Methods of Disposal:
Injection.
Pits, lined.
Pits, unlined (depending on soil).
Discharge into ocean.
5. Permit Costs:
None listed in regulations.
COLORADO
1. Regulating Agency:
Oil & Gas Conservation Commission
Room 237, Columbine Building
1845 Sherman Street
Denver, Colorado 80203
137
-------
COLORADO (Cont)
Publications of Regulations:
Rules & Regulations, Rules of
Practice and Procedure and
Oil and Gas Conservation Act
(1970)
3. Coordinating Agencies:
Division of Game,
Fish & Parks
6060 Broadway
Denver, Colorado 80221
Water Pollution Control Commission
4210 E. llth Avenue
Denver, Colorado 80220
Division of Water Resources
1845 Sherman Street
Denver, Colorado 80203
Geological Survey
1845 Sherman Street
Denver, Colorado 80203
4. Application Flow Chart:
Oil & Gas
Conservation
Commission
Division of
Water
Resources
138
-------
COLORADO (Cont)
Note: Copies of the application are given to the Division of
Water Resources and the Water Pollution Control Commission for
comments. If they have no objection and there is no objection
from land owners near the well site, then the application is
approved.
No permit needed for pits.
5. Allow Disposal Methods:
Injection.
Pits, lined.
Pits, unlined (depending on soil).
6. Permit Costs:
Injection: $75 (plus $5,000 plugging bond per well or
$15,000 blanket bond).
Pits: None.
CONNECTICUT
No regulating agency (no production).
DELAWARE
No regulating agency Cno production).
139
-------
FLORIDA
1. Regulating Agency:
Department of Natural Resources
Bureau of Geology
Oil & Gas Administration
P.O. Drawer 631
Tallahassee, Florida 32302
Publication of Regulations:
General Rules and Regulations
Governing the Conservation of Oil
and Gas in Florida
(1962)
Coordinating Agency:
Department of Air and Water
Pollution Control
P.O. Drawer 631
Tallahassee, Florida 32302
4. Application Flow Chart:
Permit granted
or refused
Note: All applications for permits for disposal of brine are
made through the Oil and Gas Administrator and acted on by the
Executive Board of the Department of Natural Resources, which
is the Cabinet and the Governor. After a public hearing, rules
for use of the injection well are devised and an order from the
department is issued.
140
-------
FLORIDA (Cont)
5. Allowable Methods of Disposal:
Injection only.
6. Permit Costs:
None.
IDAHO
No regulating agency (no production),
ILLINOIS
1. Regulating Agency:
Department of Mines & Minerals
Division of Oil & Gas
400 South Spring Street, Room 112
Springfield, Illinois
2. Publication of Regulations:
An Act in Relation to Oil, Gas Coal & Other
Surface & Underground Resources and
Rules and Regulations
(1969)
3. Coordination Agency:
141
-------
ILLINOIS (Cont)
Department of Mines & Minerals
Mining Board
400 South Spring Street, Room 112
Springfield, Illinois
4. Application Flow Chart;
Request for
disposal permit
^
Mining
Board
Request approved
or denied
Note: Application either accepted or refused by Mining Board
within 10 days after receipt. Application must be resubmitted
each year. Sites subject to inspection by Mining Board.
5. Allowed Disposal Methods:
Injection, drilled or converted well.
Ponds, lined or unlined (depending on soil characteristics).
6. Disposal Permit Costs:
Injection: $40/year (plus $1,000 plugging bond per well or
$2,500 blanket bond).
Ponds: None, but permit must be resubmitted each year.
INDIANA
1. Regulating Agency:
142
-------
INDIANA (Cont)
Department of Natural Resources
Division of Oil & Gas
606 State Office Building
Indianapolis, Indiana 46204
2. Publication of Regulations:
Indiana Division of Oil & Gas
Department of Natural Resources
Rules and Regulations
(1964)
3. Coordination Agencies:
Indiana State Board of Health
Stream Pollution Control Board
1330 W. Michigan Street
Indianapolis, Indiana
Indiana State Board of Health
Water Pollution Control
1330 W. Michigan Street
Indianapolis, Indiana
Indiana State Board of Health
Industrial Waste Disposal Section
1330 W. Michingan Street
Indianapolis, Indiana
Indiana Geological Survey
611 North Walnut Grove Avenue
Bloomington, Indiana 47401
4. Application Flow Chart:
Application for
disposal permit
Permit approved
or denied
143
-------
INDIANA (Cont)
Note: All applications for brine disposal permits are submitted
to the Department of Natural Resources for processing. If there
is any particular question in regard to a disposal application,
one or more agencies may be contacted. If there are no questions
the permit is processed and issued under the Statutes and Regu-
lations. Any applications for salt water evaporation pits are
also submitted to this office and each pit is then checked in
the field for size, type of construction, etc. If the pit meets
all requirements, a permit is issued for one year only. The
operator must re-apply for a permit each year, and the pit is
checked on each application.
5. Allowable Methods of Disposal:
Injection.
Pits, lined.
Pits, unlined (depending on soil).
6. Permit Costs:
Injection: $25 for new well, none for converted well.
Pits: None.
IOWA
No production.
1. Regulating Agency:
Iowa Natural Resources Council
Grimes State Office Building
Des Moines, Iowa 50319
144
-------
IOWA (Cont)
2. Publication of Regulations:
Iowa Natural Resources Council
Code Chapter 84
Relating to Oil & Gas Wells
(1966)
KANSAS
1. Regulating Agency:
State Corporation Commission
State Office Building
Topeka, Kansas 66612
2. Publication of Regulations:
General Rules and Regulations for the Conservation
of Crude Oils and Natural Gas
(1966)
3. Coordination Agencies:
Kansas State Department of Health
State Office Building
Topeka, Kansas 66612
State Geological Survey
University of Kansas
Lawrence, Kansas 66044
4. Application Flow Chart:
145
-------
KANSAS (Cont)
State Geology
Survey
5. Allowable Methods of Disposal:
Injection.
Pits, lined.
Pits, unlined (depending on soil).
6. Permit Costs:
Injection: $15.00 where one lease is involved, $5.00 for each
additional lease.
Pits: None.
KENTUCKY
1. Regulating Agency:
Department of Mines and Minerals
P.O. Box 680
120 Graham Avenue
Lexington, Kentucky 40501
2. Publication of Regulations:
Rules and Regulations Affecting the Oil
and Gas Industry in Kentucky
(1967)
146
-------
KENTUCKY (Cont)
Coordinating Agencies:
Water Pollution Control Commission
275 East Main Street
Frankfort, Kentucky 40601
Department of Fish and Wildlife
State Office Building Annex
Frankfort, Kentucky 40601
Application Flow Chart:
Permit refused
or approved
Application to
use permit
Permit refused
or approved
Note: Drilling is controlled by Department of Mines and Minerals,
and use of wells is controlled by Water Pollution Control Commis-
sion.
5. Allowable Methods of Disposal:
Injection.
Pits, lined.
Pits, unlined (depending on soil).
6. Permit Costs:
Injection: $10(plus $10,000 plugging bond)
Pits: None.
147
-------
LOUISIANA
1. Regulating Agency:
Department of Conservation
Louisiana Geological Survey
Geology Building
Box G
University Station
Baton Rouge, Louisiana 70903
Publication of Regulations:
Salt Water & Waste Disposal Wells
State Regulations & Geological Problems
(Revised, 1968)
3. Coordination Agency:
None.
4. Application Flow Chart
Brine
Disposal
Applicant
— ^~~~
Permit
application
Approved or
denied
— —
Louisiana
Geological
Survey
5. Allowable Methods of Disposal:
Injection.
Pits, lined.
Pits, unlined.
In tide-affected waters (waters unfit for human comsumption
or agricultural purposes).
148
-------
LOUISIANA (Cont)
6. Permit Costs:
No costs given.
MAINE
No production.
1. Regulating Agency:
Maine Mining Bureau
State House
Augusta, Maine 04330
2. Publication of Regulations:
Maine Mining Law for
State-Owned Lands
(1969)
MARYLAND
Natural Gas Production.
1. Regulating Agency:
Maryland Geological Survey
214 Latrobe Hall
John Hopkins University
Baltimore, Maryland 21218
2. Publication of Regulations:
149
-------
Maryland (Cont.)
Rules & Regulations Governing
Oil & Gas Wells
(1964)
3. Coordinating Agency:
Department of Water Resources
State Office Building
Annapolis, Maryland 21401
Note: Above agency is responsible for regulating the quality
of surface and ground water in Maryland.
4. Allowable Method of Disposal:
No rules or regulations for brine disposal in publication of
regulations.
MASSACHUSETTS
No regulating agency (no production).
MICHIGAN
1. Regulating Agency:
Oil and Gas Section (Regulatory Control Unit)
Michigan Geological Survey Division
Department of Natural Resources
Stevens T. Mason Building
Lansing, Michigan 48900
150
-------
MICHIGAN (Cont)
2. Publication of Regulations:
General Regulations Governing Oil & Gas
Operations in the State of Michigan
(1963)
3. Coordination Agency:
None.
4. Application Flow Chart
Brine
Disposal
Applicant
f^"
Request for
disposal permit
Permit approved
or denied
^
Oil and
Gas Section
5. Allowable Methods of Disposal:
Injection only.
6. Permit Costs:
Injection: $25.00 (plus $6,000 plugging bond per well or $15,000
blanket bond).
MINNESOTA
No regulating agency (no production).
151
-------
MISSISSIPPI
Regulating Agency:
State Oil & Gas Board
1207 Woolfork State Office Building
P.O. Box 1332
Jackson, Mississippi
Publication of Regulations:
State Oil & Gas Board
State of Mississippi
Statutes Rules of
Procedure Statewide
Rules and Regulations
(1970)
3. Coordination Agencies:
Mississippi Air & Water Pollution
Control Commission
Robert E. Lee Office Building
Jackson, Mississippi 39201
Mississippi Board of Water Commissioners
416 N. State Street
Jackson, Mississippi 39201
Note: Agencies consulted in cases involving pollution or proba-
ble pollution.
4. Application Flow Chart;
Oil and Gas
Board
152
-------
MISSISSIPPI (Cont)
5. Allowable Methods of Disposal:
Injection.
Pit, unlined (in impervious soil).
Pit, lined (in porous soil).
Into receiving bodies of water when not prohibited by State Fish
and Game Commission or other regulatory bodies.
6. Permit Costs:
Injection: $50 for new wells, $25 for converted wells.
Earthen pits: None.
Discharge into receiving body of water: None.
MISSOURI
1. Regulating Agency:
Missouri State Oil and Gas Council
P.O. Box 250
Rolla, Missouri
2. Publication of Regulations:
State of Missouri Rules and Regulations Governing
Practice and Procedure Before the State Oil & Gas
Council Under the Provisions of Senate Bill No. 13
Second Extra Session, 73rd General Assembly
(1970)
153
-------
MISSOURI (Cont)
3. Coordinating Agency:
Missouri State Oil and Gas Council
P.O. Box 250
Rolla, Missouri
Note: The State Oil & Gas Council is composed of one staff mem-
ber from each of the following State agencies with the State
Geologist as active administrator.
1. Division of Geological Survey and Water Resources.
2. Division of Commerce and Indsutrial Development.
3. Missouri Public Service Commission.
4. Water Pollution Board.
5. University of Missouri (a professor of petroleum en-
gineering) .
4. Allowable Methods of Disposal:
Injection.
Note: Pertinent data concerning details of the proposed opera-
tion shall be submitted by letter to the State Geologist for
approval.
5. Permit Costs:
Injection: $25.00
MONTANA
1. Regulating Agency:
Oil & Gas Conservation Commission
325 Fuller Avenue
Box 217
Helena, Montana 59601
154
-------
MONTANA (Cont)
2. Publication of Regulations:
General Rules & Regulations and
Rules of Practice & Procedure
Relating to Oil & Gas
(1954)
3. Coordinating Agencies:
State Department of Health
Cogswell Building
Helena, Montana 59601
Water Resources Board
Mitchell Building
Helena, Montana 59601
4. Application Flow Chart:
r
Brine
Disposal
Applicant
Injection
request
Approve or
dissapprove
O.&G.
Cons .
Comm.
technical
staff review
Consult
in
irregularities
Water Re-
sources Board
Department of
Health
Note: The State Department of Health and the Water Resources
Board report and consult on water pollution.
5. Allowed Disposal Methods:
Injection. (encouraged)
Pits, lined.
Pits, unlined.
155
-------
MONTANA (Cont)
Permit Costs:
Injection: Depth Cost
0' - 3,500' $ 25.00
3,501' - 7,000' $ 75.00
7,000' - below $150.00
(plus $5,000 to $20,000 bond. See page 12 of Regulations.)
Pits. No permits required.
NEW HAMPSHIRE.
No regulating agency (no production)
NEW JERSEY
No regulating agency (no production).
NEW MEXICO
1. Regulating Agency:
New Mexico Oil Conservation Commission
P.O. Box 2088
Santa Fe, New Mexico 87501
2. Published Regulations:
State of New Mexico Oil Conservation Commission
Rules & Regulations
(1968)
156
-------
NEW MEXICO (Cont)
3. Coordinating Agency:
New Mexico Water Quality Control Commission
P.O. Box 2088
Santa Fe, New Mexico 87501
4. Application Flow Chart:
Request for
disposal permit
Request approved
or rejected
L
Oil
Conservation
Commission
U.S.G.S.
Indian Lands
Water Quality
Control Commission
Note: When Indian lands are involved, the United States
Geological Survey is consulted. Normally, the Water Quality
Control Commission acts as consultant to the Oil Conservation
Commission. The Water Quality Control Commission is made up
of the heads of the Oil Conservation Commission, Department
of Health and Social Services, Department of Game and Fish,
Department of Agriculture, and one citizen at large.
5. Allowable Methods of Disposal:
Injection.
Pits, lined.
Pits, unlined (depending on soil)
6. Permit Costs:
Injection:
None (but $10,000 plugging bond and $10,000
performance bond on treatment plants).
Pits: None.
157
-------
NEW YORK
Regulating Agency:
Division of Mineral Resources
Department of Environmental Conservation
Albany, New York 12201
Publication of Regulations:
State of New York, Division of Mineral Resources
Environmental Conservation Department
Bureau of Oil and Gas Rules and Regulations
(1966)
Coordinating Agencies:
Division of Quality Services
Department of Environmental Conservation
Albany, New York 12201
Division of Pure Waters
Department of Environmental Conservation
Albany, New York 12201
Application Flow Chart:
Brine
Disposal
Applicant
1
Request for
disposal permit
Permit approved
or rejected
j
i
1
i
Department of
Environmental
Conservation
1
1
i
Division of
Quality Services
Division of
Pure Waters
«•• a^
Note: The Divisions of Quality Services and Pure Waters con-
sult only in cases where irregularities exist.
5. Allowable Methods of Disposal:
Injection.
158
-------
NEW YORK (Cont)
Pits, lined.
Pits, unlined (depending on soil).
6. Permit Costs :
Injection: None (but $2,000 plugging bond for new wells and
$1,000 plugging bond for old wells).
NEVADA
1. Regulating Agency:
Nevada Oil & Gas Conservation Commission
c/o Nevada Bureau of Mines
University of Nevada
Reno, Nevada 89507
Publication of Regulations:
Oil & Gas Conservation Law and
General Rules & Regulations
(1954)
3. Coordinating Agency:
None.
Note: Only 13 wells and three operators in state.
159
-------
NEVADA (Cont)
4. Application Flow Chart:
Request for
disposal permit
Permit approved
or denied
-*--_
Oil and Gas
Conservation
Commission
5. Allowable Methods of Disposal:
Injection.
Pits, lined.
Pits, unlined (depending on soil).
6. Permit Costs:
Injection: None (but $2,500 plugging bond)
Pits: None.
NEBRASKA
Regulating Agency:
Nebraska Oil & Gas Conservation Commission
Box 399
Sidney, Nebraska
2. Publication of Regulations:
Rules & Regulations of the Nebraska Oil &
Gas Conservation Commission
(1969)
160
-------
NEBRASKA (Cont)
3. Coordination Agencies:
Department of Health
State Capitol Building
Lincoln, Nebraska
Nebraska Geological Survey
Nebraska Hall
Lincoln, Nebraska
4. Application Flow Chart:
Brine
Disposal
Applicant
, — —-—
Request for
disposal permit
Permit approved
or denied
~-
Oil & Gas
Conservation
Commission
5. Allowable Disposal Methods:
Injection only.
6. Permit Costs:
Injection. None (but $2,500 plugging bond)
NORTH CAROLINA
No regulating agency (no production).
161
-------
NORTH DAKOTA
1. Regulating Agency:
North Dakota Industrial Commission
University Station
Grand Forks, North Dakota 58201
2. Publication of Regulations:
General Rules and Regulations for the
Conservation of Crude Oil and Natural Gas
(1969)
3. Coordinating Agency:
None.
4. Allowable Methods of Disposal:
Injection.
Pits, lined (in permeable soil).
Pits, unlined (in impermeable soil).
5. Permit Costs:
Permits must be obtained for both pits and injection wells,
but no prices given.
OHIO
1. Regulating Agency:
Department of Natural Resources
162
-------
OHIO (Cont)
Division of Oil & Gas
1500 Dublin Road
Columbus, Ohio 43215
2. Publication of Regulations:
Ohio Oil & Gas Law
Revised Code Chapter 1509
with Rules & Regulations
(1970)
3. Coordinating Agency:
None.
4. Application Flow Chart;
Request for
disposal permit
Permit approved
or denied
~^-
Chief of
Division of
Oil and Gas
Note: The Chief of the Division of Oil and Gas either accepts
or rejects the application for disposal permit.
5. Allowable Disposal Methods:
Injection.
Pits, lined.
Pits, unlined (depending on soil)
163
-------
OHIO (Cont)
6. Permit Costs :
Injection: None.
Pits: None.
OKLAHOMA
Regulating Agency:
Oil Corporation Commission
Jim Thorpe Building
Oklahoma City, Oklahoma 73105
2. Publication of Regulations:
Regulations of the Oklahoma Corporation Commission
Conservation Division
(1969)
3. Coordination Agency:
Department of Pollution Control
Jim Thorpe Building
Oklahoma City, Oklahoma 73105
Note: Copies of all applications for subsurface disposal
are sent to the other member agencies of the Department of
Pollution Control for their review and comments.
4. Allowable Methods of Disposal:
Injection only.
164
-------
OKLAHOMA (Cont)
5. Permit Costs:
None.
OREGON
No production in 1971.
1. Regulating Agency:
Department of Geology & Mineral Resources
1069 State Office Building
Portland, Oregon 97201
2. Publication of Regulations:
Rules & Regulations for the Conservation of Oil &
Natural Gas and Laws relating to Development of
Oil & Gas Minerals
(1962)
3. Coordinating Agency:
Department of Environmental Quality
720 State Office Building
Portland, Oregon 97201
4. Allowed Disposal Methods:
Injection.
Pits, lined.
Pits, unlined (depending on soil).
165
-------
OREGON (Cont)
5. Cost of Permits:
No production. No permits issued as of February 1971,
PENNSYLVANIA
1. Regulating Agency:
Department of Mines & Minerals Industries
Oil & Gas Division
Towne House Apartments
660 Boas Street
Harrisburg, Pennsylvania
2. Publication of Regulations:
Commonwealth of Pennsylvania
Compilation of Oil and Gas Laws
Administered by the Department of Mines
and Mineral Industries, Oil and Gas Division
(1969)
3. Coordination Agency:
Sanitary Water Board
Department of Health
Towne House Apartments
660 Boas Street
Harrisburg, Pennsylvania
Note: The Oil and Gas Division coordinated with the Sanitary
Water Board in the adoption of rules for the prevention of
stream pollution.
166
-------
PENNSYLVANIA (Cont)
Allowable Methods of Disposal:
"For all producing wells, adequate provision shall be made to
receive all salt water, oil and basic sediment (B.S.) in tub
tanks or suitable containers from which all such wastes, tank
bottoms, and other petroleum residues shall be discharged into
one or more dumps of adequate size, or into equivalent settling
devices, equipped with baffles, siphons, or other suitable means
to prevent all oil and residues from reaching the water of the
Commonwealth." (Quoted from Regulations.)
5. Permit Costs:
Treatment Plant Permit: $25.00
RHODE ISLAND
No regulating agency (no production).
SOUTH CAROLINA
No regulating agency (no production).
SOUTH DAKOTA
1. Regulating Agency:
Oil & Gas Board
State Capitol
Pierre, South Dakota 57501
2. Publication of Regulations:
Out of print.
167
-------
SOUTH DAKOTA (Cont)
Coordinating Agency:
Department of Health
State Capitol
Pierre, South Dakota 57501
4. Application Flow Chart:
I
Permit
Request
Approved
nr Hpni e*r\
Oil &
Gas
Board
1
Permit
Reauest
Approved
nT Hpm-i &r\
Department
of Health
1
Note: An oil well operator, in addition to complying with
the regulations of Oil & Gas Board, must also apply for a
permit for the discharge of waste from the South Dakota Com-
mittee on Water Pollution (Department of Health).
5. Allowable Methods for Disposal:
Present policy is to dispose of brine by evaporation in a
properly sealed holding pond. No injection of brine as of
March 18, 1971.
6. Costs of Permits: None given.
TENNESSEE
1. Regulating Agency:
State Oil & Gas Board
G-5 State Office Building
Nashville, Tennessee 37219
168
-------
TENNESSEE (Cont)
2. Publication of Regulations:
Rules & Regulations Pertaining to Oil &
Gas Exploration Adopted by the
State Oil & Gas Board
3. Coordinating Agency:
Department of Health
Division of Stream Pollution
G-5 State Office Building
Nashville, Tennessee 37219
Note: According to the State Oil and Gas Board, there has
been no brine for disposal to date.
TEXAS
Regulating Agency:
The Railroad Commission of Texas
Oil and Gas Division
Ernest 0. Thompson Building
Capitol Station, P.O. Drawer 12967
Austin, Texas 78711
2. Publication of Regulations:
The Railroad Commission of Texas
General Conservation Rules & Regulations
of state wide application. State of Texas
(1971)
169
-------
TEXAS (Cont)
Coordinating Agencies:
Texas Water Quality Board
1108 Lavaca Street
Austin, Texas 78701
Texas Water Development Board
P.O. Box 12386
Austin, Texas 78711
Texas Parks and Wildlife Department
John H. Reagan Building
Austin, Texas 78701
State Health Department
1100 W. 49th Street
Austin, Texas 78756
Application Flow Chart
Request for
disposal permit
Permit approved
or denied
Note: All brine disposal permit applications are processed
through the Oil and Gas Division. A majority of the requests
are acted on administratively; however, if the request is for
an exception to a Statewide Rule, it may be set for public
hearing.
Allowable Methods of Disposal:
Injection.
No pits.
Discharge into waters off shore and adjacent estuarine zones.
170
-------
TEXAS (Cont)
6. Permit Costs:
Permits required but no cost given.
UTAH
1. Regulating Agency:
Division of Oil & Gas Conservation
Department of Natural Resources
1588 West North Temple
Salt Lake City, Utah 84116
2. Publication of Regulations:
The Oil and Gas Conservation Act and
The General Rules and Regulations and
Rules of Practice and Procedure
(1969)
3. Coordinating Agencies:
Utah Water Pollution Committee
Calvin K. Sudweeks, Executive Secretary
44 Medical Drive
Salt Lake City, Utah 84113
U.S. Geological Survey
1588 West North Temple
Salt Lake City, Utah 84116
4. Application Flow Chart:
171
-------
UTAH (Cont)
Brine
Disposal
Applicant
1
App
App
den
Application
Application
recommendations
Application
recommendations
Note: Disposal applications submitted and approved or denied
by Division of Oil and Gas Conservation with consideration
given to recommendations given by Utah Water Pollution Com-
mittee and the U.S. Geological Survey.
5. Allowable Methods of Disposal:
Injection.
Pits, lined (in porous soil).
Pits, unlined (in tight soil).
6. Permit Costs:
None.
VERMONT
No regulating agency (no production)
VIRGINIA
1. Regulating Agency:
172
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Department of Labor and Industry
Division of Mines and Quarries
Big Stone Gap, Virginia 24219
2. Publication of Regulations:
Mining Laws of Virginia (Including Oil and Gas)
Issued by The Department of Labor and Industry
(1970)
3. Coordinating Agency:
State Water Control Board
P.O. Box 11143
Richmond, Virginia 23230
There are no rules or regulations covering the disposal of
brine.
WASHINGTON
No production
1. Regulating Agency:
State Oil & Gas Conservation Committee
Division of Mines & Geology
General Administration Building
Olympia, Washington 98501
Note: The Supervisor of the Division of Mines and Geology
of the Department of Natural Resources is also Supervisor
for the State Oil and Gas Conservation Committee.
173
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WASHINGTON (Cont)
2. Publication of Regulations:
Department of Natural Resources
Oil and Gas Rules and Regulations
(1957)
No provisions for brine disposal.
WEST VIRGINIA
1. Regulating Agency:
Department of Mines
Oil and Gas Division
P.O. Box 206
Grantsville, West Virginia
2. Publication of Regulations:
Oil and Gas Division of the
Department of Mines
(1969)
3. Coordinating Agency:
Department of Natural Resources
Charleston, West Virginia
4. Allowable Methods of Disposal:
Injection.
174
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WEST VIRGINIA (Cont)
5. Permit Costs:
Injection: $100.00.
WISCONSIN
No regulating agency (no production)
WYOMING
1. Regulating Agency:
Oil and Gas Conservation Commission
State Oil and Gas Supervisor
E.S.C. Building
P.O. Box 2640
Casper, Wyoming 82601
Publication of Regulations:
Rules and Regulations of Wyoming Oil and Gas Conservation
Commission including Rules of Practice and Procedure
(1969)
3. Coordinating Agencies:
Wyoming Department of Health and Social Services
Division of Health and Medical Services
Cheyenne, Wyoming 82001
Wyoming Game and Fish Commission
Cheyenne, Wyoming
175
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WYOMING (Cont>
Note: The Wyoming Department of Health and Social Services
is concerned with the quality of water in lakes and streams.
The Wyoming Game and Fish Commission is also concerned with
water quality in lakes and streams and becomes involved in
pollution problems when the quality of these waters is threat-
ened .
4. Allowable Methods of Disposal:
Injection.
Pits.
5. Permit Costs:
Injection: $25.
Pits: $25.
176
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APPENDIX B
SUMMARY OF STATE WATER CONTROL AGENCIES,
POWERS, AND PENALTIES
ALABAMA
Agency:
Alabama Water Improvement Commission
State Office Building
Montgomery, Alabama 36104
2. Agency Powers:
a. Develop programs for treatment and disposal of industrial wastes
and sewage.
b. Establish water quality standards.
c. Receive and examine plans.
d. Determine permit compliance.
e. Issue Orders.
3. Penalties:
$100 to $10,000; also damages for loss or destruction of wild life,
aquatic, fish, or marine life.
ALASKA
1. Agency:
Department of Health and Welfare
Division of Environmental Health
Pouch H
Juneau, Alaska 99801
2. Agency Powers.
177
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ALASKA (Cont)
Jurisdiction to:
a. Abate and prevent pollution.
b. Adopt standards.
c. Issue, modify, or revoke pollution control permits.
3. Penalties:
Up to $25,000 fine and/or up to one year in prison. Also liable up
to $100,000 in civil action. Fines for oil discharges from vessels
up to $14 million.
ARIZONA
1. Agency:
State Department of Health Division of Water Pollution Control
Hayden Plaza West
4019 No. 33rd Ave.
Phoenix, Arizona 85917
2. Agency Powers:
a. Issue, modify, or revoke orders prohibiting or abating waste
discharge into state waters.
b. Require submission of disposal plans and specifications prior
to construction.
c. Issue, modify, or revoke orders requiring construction or modi-
fication of disposal systems.
d. Adopt remedial measures to abate, prevent, or control pollution.
178
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ARIZONA (Cont)
3. Penalties:
Induction, conviction of misdemeanor.
ARKANSAS
1. Agency
Arkansas Pollution Control Commission
1100 Harrington Avenue
Little Rock, Arkansas 72202
2. Agency Powers:
a. Administer and enforce laws.
b. Conduct research, investigations, surveys, and studies,
c. Establish or alter water quality standards.
d. Require submission of plans and specifications.
e. Issue or revoke orders and permits.
f. Adopt rules and regulations.
3. Penalties:
Misdemeanor. Each day a separate offense.
CALIFORNIA
1. Agency
179
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CALIFORNIA (Cont)
State Water Resources Control Board
Division of Water Quality, Rooms 1140-1416
9th Street
Sacramento, California 95814
2. Agency Powers:
a. Adopt water pollution and water quality control plans.
b. Regulate a new water appropriations to carry out plans.
c. Review actions of regional boards.
d. Accept grants.
e. Conduct research.
f. Make loans.
3. Penalties:
Misdemeanor and/or injunctive relief.
COLORADO
1. Agency
Colorado Department of Health
Water Pollution Control Commission
4210 E. llth Ave.
Denver, Colorado 80220
2. Agency Powers:
a. Supervise administration and enforcement of Act.
180
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COLORADO (Cont)
b. Adopt, modify, and repeal rules and orders.
c. Accept and administer loans and grants.
d. Certify costs and expenditures for pollution control equip-
ment and construction.
e. Hold hearings.
3. Penalties:
$50 to $2,500 per day.
CONNECTICUT
1. Agency:
Water Resources Commission
Room 225
State Office Building
Hartford, Connecticut 06115
2. Agency Powers:
a. Advise, consult, and cooperate with state and federal agencies
and industry.
b. Submit prevention and control plans.
c. Conduct studies, investigations, research, and demonstrations.
d. Collect and disseminate information.
e. Issue, revoke or modify orders or permits.
f. Hold hearings.
181
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CONNECTICUT (Cont)
g. Require submission of plans and specifications.
h. Require proper operation and maintenance of disposal systems,
3. Penalties:
$1,000. Each day a separate offense.
DELAWARE
1. Agency:
State of Delaware
Division of Environmental Control
Department of Natural Resources and Environmental Control
P.O. Box 916
Dover, Delaware 19901
2. Agency Powers:
a. Conduct experiments, investigations, research, and studies.
b. Issue general and special orders.
c. Adopt rules and regulations.
d. Make inspections.
e. Enter into agreements.
3. Penalties:
$500 per day of violation. Court stoppage orders.
182
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FLORIDA
1. Agency
Department of Air and Water Pollution Control
Suite 300
Tallahassee Bank Building
315 S. Calhoun Street
Tallahassee, Florida 32301
2. Agency Powers:
a. Hire necessary personnel.
b. Accept state monies.
c. Adopt, modify, and repeal rules and regulations.
d. Hold hearings.
e. Establish water standards.
f. Conduct field studies.
g. Establish permit system.
h. Issue orders.
i. Require construction notice.
j. Collect and disseminate information.
3. Penalties:
$1,000. Each day a separate offense. Injunctive relief.
GEORGIA
1. Agency:
183
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GEORGIA (Cent)
Georgia Water Quality Control Board
47 Trinity Avenue, S.W.
Atlanta, Georgia 39334
2. Agency Powers:
a. Establish standards.
b. Require registration and report filing for operations producing
pollution (board).
c. Accept and administer loans and grants.
d. Conduct studies, investigations, research, and demonstrations.
e. Collect and disseminate information.
f. Issue orders.
g. Hold hearings.
h. Require maintenance and operation of abatement systems (depart-
ment) .
3. Penalties:
Misdemeanor. Each day a violation.
HAWAII
1. Agency:
Environmental Health Division
Department of Health
P.O. Box 3378
Honolulu, Hawaii 96801
184
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HAWAII (Cont)
2. Agency Powers:
a. Enforce water quality standards via a permit system.
b. Surveillance and monitoring of coastal waters.
3. Penalties:
$500 and/or one year in prison.
IDAHO
1. Agency:
Environmental Improvement Division
Idaho Department of Health
Statehouse
Boise, Idaho 83707
2. Agency Powers:
a. Establish and enforce regulations.
b. Establish effluent quality standards.
c. Require inspection and approval of plans.
3. Penalties:
$1,000 and/or one year in prison. Each day a separate offense.
185
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ILLINOIS
1. Agency
Environmental Protection Agency
State of Illinois
2200 Churchill Road
Springfield, Illinois 62706
2. Agency Powers:
a. Enforce state standards.
b. Assist design engineers.
3. Penalties:
Fine not to exceed $10,000 for a violation, and additional fine not
to exceed $1,000 for each day violation continues.
INDIANA
1. Agency:
Indiana Stream Pollution Control Board
1330 W. Michigan Street
Indianapolis, Indiana 46206
2. Agency Powers:
a. Establish water quality standards.
b. Make regulations.
c. Conduct hearings.
d. Issue orders.
186
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INDIANA (Cont)
e. Enforce law.
3. Penalties:
Misdemeanor. $100 and 90 days in jail. Each day $100 extra.
IOWA
1. Agency:
State Department of Health
Lucas State Office Building
Des Moines, Iowa 50319
2. Agency Powers:
a. Adopt, modify, or repeal reasonable water quality standards.
b. Hold hearings.
c. Issue orders.
d. Direct Health Department to approve plans and specifications and
issue permits.
3. Penalties:
Injunction, $100.
187
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KANSAS
1. Agency:
Environmental Health Services
Kansas State Department of Health
5th Floor State Office Building
Topeka, Kansas 66612
2. Agency Powers:
a. Revoke permits on 30 days notice.
b. Adopt water quality standards and regulations.
c. Unlimited emergency powers.
3. Penalties:
$25 per day for failure to comply with regulations; $50 to $500
per day for failure to comply with order.
KENTUCKY
Agency:
Legislative Research Commission
Capitol Building
Frankfort, Kentucky 40601
2. Agency Powers:
a. Conduct studies, investigations, research, experiments, and
demonstrations.
b. Establish water quality standards.
c. Hold hearings.
188
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KENTUCKY (Cont)
d. Issue orders.
e. Examine plans and specifications.
f. Inspect construction.
g. Issue, revoke, or modify permits.
h. Examine records.
3. Penalties:
$1,000; value of fish or wildlife killed.
LOUISIANA
1. Agency:
Louisiana Stream Control Commission
P.O. Drawer FC
University Station
Baton Rouge, Louisiana 70803
2. Agency Powers:
a. Set water quality standards.
b. Order or regulate waste discharges.
c. Prohibit discharge.
3. Penalties:
$1,000 and/or up to one year in prison.
189
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MAINE
1. Agency:
Environmental Improvement Commission
State House
Augusta, Maine 04330
2. Agency Powers:
a. Recommend best use classifications.
b. Issue permits.
c. Approve plans.
d. Enforce legislation.
3. Penalties:
$25 to $1,000 fine each day of violation.
MARYLAND
1. Agency:
Maryland State Department of Health and Mental Hygiene
2305 N. Charles Street
Baltimore, Maryland 21218
2. Agency Powers:
a. Health Department controls sewage pollution as it affects health.
b. Department of Water Resources has control of all other sources.
190
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MARYLAND (Cont)
3. Penalties:
$500. $50 each additional day.
MASSACHUSETTS
1. Agency:
Water Resources Commission
Commonwealth of Massachusetts
Division of Water Pollution Control
100 Cambridge Street
Boston, Massachusetts 02202
2. Agency Powers:
Division of Water Pollution Control has joint jurisdiction with
Department of Public Health.
3. Penalties:
$100 each day of violation.
MICHIGAN
1. Agency:
Water Resources Commission
Department of Natural Resources
Stevens T. Mason Building
Lansing, Michigan 48926
191
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MICHIGAN (Cont)
2. Agency Powers:
a. Issue orders and permits.
b. Restrict new disposal.
c. Enforce laws.
3. Penalties:
$500 each day of violation.
MINNESOTA
1. Agency:
Minnesota Pollution Control Agency
717 Delaware Street, S.E.
Minneapolis, Minnesota 55440
2. Agency Powers:
a. Set water quality and effluent standards.
b. Inspect plans.
c. Issue permits.
d. Enforce compliance.
e. Issue orders.
f. Assume municipality powers to construct disposal system and
levy taxes.
192
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MINNESOTA (Cont)
3. Penalties:
Injunction. $300 or 90 days in jail or both. Each day is a separate
offense.
MISSISSIPPI
1. Agency:
Mississippi Air & Water Pollution Control Commission
P.O. Box 827
Jackson, Mississippi 39205
2. Agency Powers:
a. Enforce rules and regulations.
b. Accept and administer loans and grants from the federal govern-
ment.
c. Conduct studies, research, investigations, and demonstrations.
3. Penalties:
Up to $3,000 and/or one year in prison. Each day a separate violation.
MISSOURI
1. Agency:
Missouri Water Pollution Board
P.O. Box 154
Jefferson City, Missouri 65101
193
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MISSOURI (Cont)
2. Agency Powers:
a. Issue or restrict permits.
b. Enforce law.
c. Issue tax bills for construction.
d. Seek injunctions.
3. Penalties:
Injunction. $25 to $500 fine. Maximum of $100 per day for con-
tinuing violation.
MONTANA
1. Agency:
Water Pollution Control Section
Division of Environmental Sanitation
State Department of Health
Helena, Montana 59601
2. Agency Powers:
a. Establish standards.
b. Recommend research and demonstrations.
c. Direct Board of Health to Issue orders.
d. Holding hearings.
e. Cause surveys and investigations.
194
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MONTANA (Cont)
3. Penalties:
Fines up to $1,000 for each day of violation.
NEBRASKA
1. Agency:
Nebraska Water Pollution Control Council
Box 94757
State House Station
Lincoln, Nebraska 68509
2. Agency Powers:
a. Supervise administration and enforcement of pollution control
laws.
b. Accept and administer loans and grants.
c. Collect and disseminate information.
d. Conduct studies, investigations, research, and demonstrations.
e. Issue orders and permits.
f. Hold hearings.
g. Require submission of plans and inspect construction.
3. Penalties:
$100 to $500 and $10 each additional day.
195
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NEVADA
1. Agency:
Department of Health, Welfare and Rehabilitation
210 S. Fall Street
Carson City, Nevada 89701
2. Agency Powers:
a. Approve loans and grants to municipalities from Federal aid.
b. Adopt and enforce reasonable rules and regulations.
3. Penalties:
Gross misdemeanor
NEW HAMPSHIRE
1. Agency:
Water Supply and Pollution Control Commission
State of New Hampshire
61 S. Spring Street
Concord, New Hampshire 03301
2. Agency Powers:
a. Conduct experiments, investigations, and research.
b. Require filing of plans and specifications.
c. Set standards of design and construction.
d. Monitor pesticides in water.
196
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NEW HAMPSHIRE (Cont)
e. Set up laboratories.
f. Investigate applications for Federal Aid.
3. Penalties:
$1,000 each day of violation
NEW JERSEY
1. Agency
Department of Environmental Protection
P.O. Box 1390
Trenton, New Jersey 08625
2. Agency Powers:
Department of Environmental Protection is responsible for abating
all water pollution and maintaining water quality and has broad
powers regarding sanitation and sewage disposal.
3. Penalties:
Injunctive relief and various penalties.
NEW MEXICO
1. Agency:
197
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NEW MEXICO (Cont)
New Mexico Water Quality Control Commission
P.O. Box 2348
Sante Fe, New Mexico 87501
2. Agency Powers:
Adopt standards and regulations for pollution prevention,
3. Penalties:
Injunction and fine
NEW YORK
1. Agency:
New York State Department of Health
84 Holland Avenue
Albany, New York 12208
2. Agency Powers:
a. Hold hearings.
b. Issue orders.
c. Issue, extend, deny, revoke, or modify permits.
d. Conduct investigations.
3. Penalties:
Injunction. Fine of $100 to $500 per day of violation
198
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NORTH CAROLINA
1. Agency:
Water Pollution Control Division
North Carolina Department of Water and Air Resources
P.O. Box 9392
Raleigh, North Carolina 27603
2. Agency Powers:
a. Issue permits.
b. Approve plans.
c. Organize programs.
3. Penalties:
$100 to $1,000. Each day a separate violation.
NORTH DAKOTA
1. Agency:
Division of Water Supply and Pollution Control
North Dakota State Department of Health
Bismarch, North Dakota 58501
2. Agency Powers:
a. Supervise enforcement of rules and regulations.
b. Accept and administer loans and grants.
c. Conduct demonstrations.
199
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NORTH DAKOTA (Cont)
d. Collect and disseminate information.
e. Issue, modify, or revoke orders.
f. Hold hearings.
g. Require submission of plans and specifications.
h. Require proper maintenance and operation of disposal system.
3. Penalties:
Injunction, misdemeanor.
OHIO
1. Agency:
Ohio Water Pollution Control Board
P.O. Box 118
Columbus, Ohio 43216
2. Agency Powers:
a. Conduct research, education, and investigation.
b. Enforce programs.
c. Require construction or modification of sewage or waste disposal
systems.
d. Suspend construction.
e. Obtain injunctions.
200
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OHIO (Cont)
3. Penalties:
$500 and/or one year imprisonment.
OKLAHOMA
1. Agency:
Environmental Health Services
Oklahoma State Department of Health
3400 North Eastern
Oklahoma City, Oklahoma 73105
2. Agency Powers:
a. To prevent or abate water pollution.
b. Conduct studies investigation, research, and demonstrations.
c. Adopt rules and regulations.
d. Accept funds and grants.
e. Prescribe water criteria.
3. Penalties:
$500 and/or 90 days in jail. Each day a separate violation.
OREGON
1. Agency:
201
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OREGON (Cont)
Oregon State Department of Environmental Quality
State Office Building
1400 S.W. Fifth Avenue
Portland, Oregon 97201
2. Agency Powers:
a. Formulate rules and regulations.
b. Conduct studies, investigations, and programs.
c. Cooperate with other agencies.
d. Issue orders and hold hearings.
e. Employ personnel.
3. Penalties:
Vary, civil or criminal.
PENNSYLVANIA
1. Agency:
Bureau of Sanitary Engineering
Pennsylvania Department of Environmental Resources
P.O. Box 2351
Harrisburg, Pennsylvania 17120
2. Agency Powers:
a. Require discharge permits.
b. Set treatment standards.
202
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PENNSYLVANIA (Cont)
3. Penalties:
$100 to $5,000 plus imprisonment up to one year. Civil penalties:
$10,000 plus $500 per day.
RHODE ISLAND
Agency:
Division of Water Supply and Pollution Control
Rhode Island Department of Health
335 State Office Building
Providence, Rhode Island 02903
2. Agency Powers:
a. Advice, consult, and co-operate with other agencies.
b. Accept and administer loans and grants.
c. Conduct studies, investigations, research, and demonstrations.
d. Collection and disseminate information.
e. Adopt, modify and repeal water classes and standards.
f. Hold hearings and issue orders.
g. Require submission of plans and inspect construction.
h. Consult advisory board.
i. Make, amend, and revoke pollution control rules and regulations.
j. Superior court empowered to enforce orders of division.
3. Penalties:
203
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RHODE ISLAND (Cont)
$500 fine and/or 30 days in prison.
SOUTH CAROLINA
1. Agency:
South Carolina Pollution Control Authority
J. Marion Sims Building
Columbia, South Carolina 29201
2. Agency Powers:
a. Require waste sources to meet standards.
b. Act as state agent in Federal Government dealings with water
pollution.
c. Perform all necessary acts.
3. Penalties:
$100 to $5,000 and/or one year in prison. Each day a separate viola-
tion.
SOUTH DAKOTA
1. Agency:
South Dakota Committee on Water Pollution
State Department of Health
Pierre, South Dakota 57501
>04
-------
SOUTH DAKOTA (Cont)
2. Agency Powers:
a. Establish Class A and Class B water standards, which can be
modified when necessary.
b. Conduct investigations.
c. Issue orders.
d. Instigate hearings.
e. Issue annual permits upon approval of applications.
3. Penalties:
$100 and/or one year imprisonment.
TENNESSEE
1. Agency:
Tennessee Stream Pollution Control Board
612 Cordell Hull Building
Nashville, Tennessee 37219
2. Agency Powers:
a. Establish air quality standards, emission standards, permit
system.
b. Promulgate rules and regulations, hold hearings.
c. Collect fees.
d. Require information submission.
205
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TENNESSEE (Cont)
3. Penalties:
Misdemeanor, injunctive relief.
TEXAS
1. Agency:
Texas Water Quality Board
1108 Lavaca Street
Austin, Texas 78701
2. Agency Powers:
a. Establish water quality standards.
b. Issue and amend permits.
c. Limit or reduce septic tanks.
d. Inspect and conduct investigations.
e. Accept and administer funds.
f. Enforce Water Quality Act.
g. Make agreements with Federal agencies.
3. Penalties:
Injunction. Up to $1,000 for each violation or day of violation.
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UTAH
1. Agency:
Utah Water Pollution Committee
44 Medical Drive
Salt Lake City, Utah 84113
2. Agency Powers:
a. Hold hearings.
b. Review and approve plans.
c. Issue orders to correct pollution.
d. Issue permits.
e. Establish standards.
3. Penalties:
Misdemeanor. Also can be enjoined.
VERMONT
1. Agency:
Vermont Department of Water Resources
State Office Building
Montpelier, Vermont 05602
2. Agency Powers:
a. Issue orders.
b. Hold hearings.
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VERMONT (Cont)
c. Conduct studies, investigations, and demonstrations.
d. Supervise flood control, channel clearing, and river bank pro-
tection.
e. Adopt, modify, and enforce rules and regulations.
f. Issue permits.
g. Administer loans and grants.
h. Require filing of new construction plans.
3. Penalties:
$50 each day of violation; up to $1,000 total.
VIRGINIA
1. Agency:
State Water Control Board
P.O. Box 11143
Richmond, Virginia 23230
2. Agency Powers:
a. Establish water quality standards.
b. Maintain standards.
c. Issue orders
d. Compel compliance.
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VIRGINIA (Cont)
3. Penalties:
Injunction. Up to $5,000 fine for each day.
WASHINGTON
1. Agency:
Washington Water Pollution Control Commission
P.O. Box 829
Olympia, Washington 98501
2. Agency Powers:
a. Approve reports, plans, and specifications for waste treatment
facilities.
b. Issue waste discharge permits.
c. Administer state and federal construction grants.
d. Establish basin policy on waste collection, treatment, and dis-
charge.
3. Penalties:
Criminal prosecution; $100 fine each day; recovery of damages incur-
red; oil discharge penalty, maximum $20,000 fine; full or partial
closure of discharger.
WEST VIRGINIA
1. Agency:
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WEST VIRGINIA (Cont)
Division of Water Resources
Department of Natural Resources
1201 Greenbriar Street
Charleston, West Virginia 25311
2. Agency Powers:
a. Issue permits.
b. Obtain compliance.
c. Institute criminal proceedings.
3. Penalties:
Violation, $100 to $1,000; willful violation, $1,000 to $10,000.
Also up to 6 months prison.
WINCONSIN
Agency:
Division of Environmental Protection
Department of Natural Resources
P.O. Box 450
Madison, Wisconsin 53701
2. Agency Powers:
a. Monitor surface water quality,
b. Conduct stream surveys.
c. Hold hearings.
d. Issue orders.
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WISCONSIN (Cont)
e. Approve plans.
f. Disburse state and Federal aid.
g. Issue licenses and permits.
3. Penalties:
Up to $5,000 each day of violation.
WYOMING
1. Agency:
Division of Health and Medical Services
Wyoming Department of Health and Social Services
State Office Building
Cheyenne, Wyoming 82001
2. Agency Powers:
a. Suggest to, advise, and assist the council.
b. Conduct and supervise studies, investigations, and research.
c. Require consultations and approval of plans prior to construction
of waste treatment facilities.
3. Penalties:
Up to $1,000.
211
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APPENDIX C
LABORATORY TESTS
Chemical Lab Tests (ppm and meq/1) Other Tests (ppm and meq/1)
Dissolved Oxygen (DO)
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
21.
Total dissolved solids
Total solids
Organic solids
Iron Oxide (FeO)
Iron Sulfide (FeSO4)
Calcium Carbonate (CaCO,)
Silica (Si)
Barium Sulfate (BaSOJ
Carbonate (CO, )
Bicarbonate (HCO, )
Sulfate (S04=)
Chloride (Cl~)
Calcium (Ca )
Magnesium (Mg )
Sodium (Na )
Barium (Ba )
Dissolved iron
pH
Hydrogen Sulfide (H2S)
Specific gravity
Oil content (ppm)
1,
2,
3,
4.
5.
Free carbon dioxide (CO?)
Turbidity
Bacteria
Chlorine residual if chlorine
used as a bacteriacide
Not all of these tests are required on all oilfield brines which are to be
disposed of. Exactly which tests should be run depends primarily on
the type of disposal mechanism and the requirements of Oil Regulating
Agencies and Water Quality Agencies.
212
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APPENDIX D
ANALYSES FORMULA DEVELOPMENT
The progression of calculations used in the disposal mechanism anal-
ysis is lengthy but relatively simple.
Initial information which should be obtained includes the following.
(A more thorough explanation can be found in any college level fluid
mechanics book.)
General
X. = Flow rate per well in gallons per day (gpd)
Y = Life of project in years (yrs).
D = Outside diameter of pipe (ft).
p = Density of fluid (lb/ft3).
y = Viscosity of the fluid (Ib /ft-sec).
Force due to gravity:
g = Constant
pounds mass-foot
32.17 pounds force-second •
FL = Pressure loss due to friction (psi) .
(assume 0.003 psi per foot of pipe)
SG = Specific gravity .
Injection
r = Radius of the well bore (ft)
213
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k = Average formation permeability (darcies).
h = Effective height of the formation face (ft).
A = Average formation porosity as a decimal fraction; volume of
voids divided by total volume.
P = Reservoir pressure (psi).
P = Bottom hole pressure; pressure at the bottom of the well
b (psi).
The following relationships should be developed to accompany these
basic facts.
Pipe Diameter, d
d = Inside diameter of pipe in inches.
W = Fluid flow rate in thousands of pounds per hour (Ib /hr)
m
3 47
p = Density of the fluid (Ib /ft ) Note: Koenig . Pure
Assume: P = 62.5 Ib /ft water may be used because
m
fluid density is not a major
.45
d = 2.2W ' factor in injection.
(P)
.31
X± = Gallons per day = Wj m[ [24 hrjh ft3 | (7.48 gal)
Vhr~/Vdayy^2.5 Ib / V 3 }
X = (2.87)(L03)CW)
2.87
""0.45
214
-------
'45
d =
= 2-2xi
(3.6)(35.9)
= (1.7) (1Q-2) (X.-45)
Fluid Velocity. V
A = Cross section area of pipe (ft ); r = Pipe radius (ft);
Q = Volume flow rate (ft /sec); d (in.) and D (ft) = pipe diameter,
Q
i^-ACftWft
sec sec
„. ^ 1 day 1 ft
Isecl Mdayj 186400 sec|\7.48 gal
f^]- -
I a d r* I
(ft ,
v sec ; (86400) (7
r = — = Radius of pipe
2
,2 en2) v(il}
is eel
X.
(86400)(7.48)
Xi (ft3)
.48)(3.14)r2(ftz)(sec)
D- d
12
and
24
576
then V=
576
(86400)(7.48)(3.14)
\ }
and V = (2.84) (10~4)
215
-------
Injection
Fluid radius, r , at end of project life (Y) .
e
r = Fluid radius (extent of injected fluid from well assuming
e homogeneous formation and fluid dispersion into formation
in the shape of a cylinder of height, h, and radius, r ).
e
Y = Project life (years).
X = Flow rate per well (gpd) .
h = Formation height (ft).
<(> = Formation porosity (decimal fraction) .
Vol = Volume injected over project life
= 365 (x ,
= 48.8
Vol
, = Volume of void space in formation = (TT) (r ) (h) () = Vol
-L e
48.8
r —
e
r =
e
48800 I
T7
(124.6)
12
H(
K
i
(1000) (h)
i
1/2-
1/2"
(1000) (h) ($)
Reynold's Number
N = YD = vi
re
V ;i
D = -
12
216
-------
Assume: = 62.
\ 1 Ib
and y= 1 centipoise
ft
1488(ft-sec)
then N = (1488) (62.5) (V)(d)(S.G.)
re
12
and N = (7.75X103) (d)(V)(S.G.) or 2 . 201 XiS .G .
d
f = Fluid friction factor = function of N obtained using
Moody Diagram (see fluid mechanics text).
Friction Loss, Pf (psi)
H = Head loss due to friction =
2f T V
(H ) .
but P = Pressure loss due to friction =—' and D =
f 144 12
so P
2fLV
12p
144
193.02(d)
Assuming: p = Pure water density (negligible effect on overall
analysis) = 62.5> then
p (psi) . 2(12) (62.5)
f * (32.17)(144) d
and P = 32.36 (10~2)(fLV2/d).
Driving Pressure, P (psi)
X. = Fluid flow rate through the formation (gpm).
K = Formation permeability (darcies).
217
-------
A = Area of the formation face perpendicular to the direction
of flow (ft2).
y = Fluid viscosity (centipoise).
I = Injection pressure gradient (ratio of the difference) in
pressure between the bottom hole and reservoir pressure to
the difference in distance between the fluid radius and well
bore radius).
X =
_ KIA
y
x - ,
p -p
b r
r - r
- e v
2?rrh
X
X
-e dr_
r
= 2irhk
y
w
dp
X In
w
= P
2-rrhk
y
/ \
r
e
P = J^
d 2Tthk
V W/
K = 1 darcy =
•, , 2
(sec)(atm)
2
= .001076 ft
218
-------
1 atm = 14.7 lbf
in
-8V
Ib -ft-in
1 darcy = (4.92) (10 ") EL
Substituting:
Ib -sec
X
gal
day,
/Ib
m
2.303 log r (lb,-sec)
\ wJ t
VL488 ft-sec/ (2)(3.14)(h)(ft)(K)(4.92)(10~8)(lb ) (f t) (in2)
m
= (7.75)(10"3)
X±ulog/r
hk
w-1-1
Let y= 1 centipoise,
X log
then P =
_ i
w,
d (128.9)(K)(h)
Static Pressure (Constant), P (psi)
P (Ib, / in2) =
Assume : p = [62.5
'c
Ib
n
ft-
(S.G.) and g = 32.17
ft
sec
P =
(62.5 lbm)(L)(ft)(32.17)(ft)(lbf-sec2)(l)(ft2) (S.G.)
(ft3)(sec2)(32.17)(Ib -ft)(144)(in2)
m
(62.5) (L) (IbJ (S.G.)
P = £
c
144
in2
219
-------
Ib
P = (0.434) (L) — (S.G.)=
—
in
Wellhead Pressure, P , (psi)
P = Wellhead pressure = pressure at the top of the well
ctl P, + P, - P .
b f c
Note: P may also be thought of as a change in the pressure head to
be supplied by the pump. That is, both P, and P, must be over-
b i
come if the fluid is to flow in the pipe. Therefore, if P +
P - P is negative, no pressure must be supplied by pumping.
If P + P - P is positive, the combined resistance to flow
of the reservoir exceed the pressure head of weight of the
fluid column in the tube, and pumps must be supplied to drive
water into the receiving formation.
PL=P +P -P,
ch b f c
but
therefore, P , = P, + P +P..-P,
ch d r f c
Hydraulic Horsepower
P = P , + FL
p ch
P = Pum£ discharge pressure = Change in pressure head (P in psi)
p + FL (in psi)(pipeline pressure loss due to friction)
220
-------
HHP = Hydraulic Horsepower = p x
HHP
(550)(7.48)(86400)
(Pp) (X.)
(2.468)(106)
Brake Horsepower
DUD T> i u Hydraulic Horsepower
BHP = Brake Horsepower = — l - c -
Pump Efficiency
(Assume a pump efficiency of .85)
BHP =
.85
Kilowatts
KW = Kilowatts = (Brake Horsepower)(.7457 kw/hp)
motor efficiency
(Assume a motor efficiency of .93)
KW = - (BRp) (>
.93
KW = (HHP) (.943).
Pump Capacity
GPM = X pall°ns x 1 day
1 day 1440 (minute)
221
-------
X.
GPM = —
1440
Right-of-Way Cost
$/ft = (cost per acre)[_§—\( 1 acre j (Right-of-way width)(ft)
^acrej^43560 ft2)
Assume: $109 per acre and 30 ft right-of-way width,
then $foot = (109) (30) = .075.
43560
222
-------
APPENDIX E
COMPUTER PROGRAM FOR DISPOSAL BY INJECTION, EVAPORATION,
DIRECT DISCHARGE (PRICING FOR ALL-NEW EQUIPMENT) ' 9
The computer program follows the previously given hand calculation dis-
posal system analysis very closely; however, a few major factors differ.
The hand calculation scheme has sufficient flexibility that: it may be
used for new or converted injection systems; any piping may be used with
any suitable pump merely by substituting design and cost values for the
equipment (including 'O1 if the equipment is not used); and up-to-date
prices can be used.
The computer only takes specific information (i.e., instead of up-to-
date pipe costs, introduce the RRC code (Region Rating Code, Table 15)
of the state in which the drilling will be done and the computer will
assign the costs from tables already in the program for appropriate 9"
diameter J-55 or N-80 pipe). Also, some of the costs must be updated
by referring to the Engineering News Record Building Cost Index (ENRBCI
in program is 570 for 1962). Cost updating must be read into the com-
puter. The program only calculates the cost of an all new system.
Input
The operator has the option of selecting any combination of disposal
223
-------
Table 15. RRC ZONES
68
Zone 1
Louisiana
Mississippi
Southwest Texas
Gulf Texas
North Central Texas
North Dakota
Kansas
Zone 2
Florida
Arizona
New Mexico
California
South Dakota
Zone 3
Wyoming
West Texas
Panhandle Texas
Colorado
Zone 4
Pennsylvania
New York
West Virginia
Ohio
Virginia
Nebraska
Indiana
East Texas
Alabama
Zone 5
Utah
Nevada
Zone 6
Montana
Michigan
Oklahoma
Arkansas
Illinois
Kentucky
-------
configurations he wishes using the first input card. This program card
calls the desired disposal system. If more than one disposal system is
desired, the operator simply enters additional program call cards in the
order in which he wishes to look at the prospective disposal system(s).
Following the first program call card, the data for the specific disposal
system is put into the computer.
Program Call Card
The program call card contains combinations of the numbers 1, 2, and
3 followed by a decimal point. The number 1. in any two columns of
columns 1-10 calls the injection program. If the number 2. is enter-
ed in any two columns of columns 11-20, the evaporation program is
called. The number 3. in any two columns of columns 21-30 calls the
conveyance or direct discharge model.
Once the program call card starts a particular disposal system, the com-
puter will calculate as many different configurations as desired; how-
ever, the computer operator must enter all the data necessary for each
different configuration.
Data Cards
The specific data array of each program follows, but a brief intro-
ductory explanation is necessary. For any disposal program to work,
225
-------
all the data required by the program must be inputted. Even if only a
slight change is made in a variable value of a disposal method, all the
data necessary for the new configuration must be printed on a data card
because the computer saves no data from one system to the next. The last
number in the last data card of each different type of disposal system
must be the number 1 to designate the completion of the particular dis-
posal system input (injection and evaporation are different types of dis-
posal systems; injection and injection are different configurations of
the same disposal system) in the ten data columns following those columns
containing disposal system data.
Data Deck
1. Program call card with a 1. in columns 1-10, a 2. in columns
11-20, and/or a 3. in columns 21-30.
2. Injection data requires two data cards per injection config-
uration in addition to and following the program call card,
for a total of at least three cards. A "1." must be placed
anywhere in the reserved ten columns after the value of the
last variable, EL, in the final injection system configuration
data card. (Note, F 10.0)
3. Evaporation requires three data cards per evaporation config-
uration in addition to and following the program call card
for a total of at least four cards. A "1." must be placed
after the value of the last variable, BCI, in the final evapor-
ation system configuration data card. (Note, F 10.0)
226
-------
4. Conveyance also requires three data cards per configuration
in addition to and following the program call card for a
total of at least four cards. A "1." must be placed after
the value of the last variable, Y, in the final conveyance
system configuration. (Note, F 10.0)
Variables
1.
Injection
Variable
54
Format
a. JC 13
b. PLACE (I) 10Al
c. RRC A2
d. XO
g- *
h. II
i. ENR
LI
F5.3
e. RKW F3.3
f. CPA F4.0
12
F4.3
F3.0
II
Description
Job code; number configurations.
Location name.
Regional Rating Code; state num-
ber.
Total daily volume to be inject-
ed, Kgd (thousands of gallons per
day) .
Cost of electrical power, $/KWH.
Cost of land for pump station,
injection well, and connecting
distribution pipe, $/acre.
Estimated project life, years.
Interest or discount rate, deci-
mal fraction.
Current Year Engineering News
Record Building Cost Index,
necessary to update cost values
already in computer (ENRBCI = 570)
1962
Lithology - type of completion 0
(zero) indicates closed hoi'
quired; 1 indicates open 1
227
-------
Variable
k. L
1. H
m. PHI
q. COR1
v. XP
w. DPM
x. EL
Format
F5.0
F3.0
F2.2
n. PK
o. PR
p. D
F4.3
F4.0
F3.2
F4.1.
r. VCPIPE F3.2
s. VCFORM F3 .2
t. SPGR F2.1
u. PCHTF F3.2
F5.0
F4.0
F4.0
y. X LAST F10.0
2. Evaporation
Variable Format
a. XO
F10.3
Description
Total depth of well, feet.
Effective height of injection
zone, feet.
Formation porosity, decimal frac-
tion.
Formation permeability, darcies.
Reservoir pressure, psi.
Inside diameter of injection con-
duit, inches.
Drilling correction cost term
(allows for hole sizes other than
standard 9 inches).
Fluid viscosity of brine, centi-
poise.
Fluid viscosity of brine, centi-
poise.
Specific gravity of brine.
Maximum casing head pressure test
factor, psi/ft.
Oil flow, Kgd.
Distance from collection point to
well, miles.
Elevation of well below (+) or
above (-) brine collection point,
feet.
Write 1. at end of last configura-
tion data card.
Description
Brine flow, Kgd.
228
-------
Variable Format Description
b. XW F10.3 Oil flow, Kgd.
c. CE F10.3 Brine concentration, ppm.
d. PREC F10.3 Precipitation, inches/year.
e. EO F10.3 Evaporation rate (gross), inches/
year.
f. FF F10.3 Distance from collection point
to pond, miles.
g- EL F10.3 Elevation of pond below (+) or
above (-) brine collection point,
feet.
h.
i.
j-
k.
1.
ECU
CLU
I
Y
BCI
F10.3
F10.3
F10.3
F10.3
F10.3
Power cost, $/KWH.
Land cost, $/acre.
Capital discount rate or interest,
decimal fraction.
Project life, years.
Current Year Engineering News
Record Building Cost Index.
m. X LAST
F10.0
Write 1. at end of last configu-
ration data set.
3. Conveyance (Direct Discharge)-^
Variable Format
a. XO
b. XW
c. FF
d. EL
e. ECU
F10.2
F10.2
F10.3
F10.2
F10.2
Description
Brine flow, Kgd.
Oil product flow, Kgd.
Distance from brine collection
point to discharge, miles.
Elevation of discharge below (+)
or above (-) collection point,
feet.
Power cost $/KWH.
229
-------
Variable
f .
g-
h.
i .
ZI
BCI
Y
X LAST
Format
F10.2
F10.2
F10.4
F10.0
Description
Capital discount rate or interest,
decimal fraction.
Current Year Engineering News
Record Building Cost Index.
Project life, years.
Write 1. at end of last configu-
ration data set.
Program Quirks and Limitations
1. Injection. Disregard Product Petrol Concentration, ppm, in
printout.
2. Evaporation. Printout of capital investment for evaporation
pond only, not entire system.
3. Computer program relationships only good for daily brine flow
greater than 1,000 barrels per day.
4. Treatment capital and operating costs taken from Figures 23
and 24.
Regional Rating Code (RRC) Zones
The Regional Rating Code divides the continental United States (ex-
cluding Alaska and Hawaii) into six zones by average drilling costs
per zone as reported in Joint Association Survey of Industrial Dril-
ling Costs (Section 1). 1962. An adjustment has been made for states
having predominently shallows cheaper wells. RRC zones are given in
Table 15-
230
-------
Of note is the variable, COR 1 F4. 1, in the injection program. Certainly
drilling and development expenses in either a production or development
well are highly dependent on the diameter of the well bore. While hand
calculations allow individual size allocations with regard to well
diameter, the computer does not, directly. Rather, an expression re-
lating cost with diameter and depth developed by Koenig and others is
used to express well diameter and drilling costs in terms of a standard
well; in effect, a common denominator. A statistical analysis of oilwell
diameter performed by Koenig47 revealed that the most common
weighted production hole diameter (WPHD) was 9 inches. This computer
program uses the previously mentioned standard types of pipes with diameters
of 9 inches. Therefore, the COR 1 value must be calculated for each
drilling situation to adjust for actual WPHD diameters. If a 9-inch
diameter is used, the value entered will not be an adjusted value.
To arrive at the appropriate drilling cost adjustment for well diameter,
the first step is to calculate the weighted production hole diameter,
WPHD (because often the surface casing is larger in diameter than the
production or bottom hole diameter)54.
WPHD = N(SHD) + (10 - N)(BHD)
10
Where WPHD = Weighted production hole diameter (inches).
Ll
N = -— x 10 = Fraction of total depth which surface
J_j
casing extends.
L = Total depth of the well (feet).
L = Depth to which surface casing is set (feet).
231
-------
BHD = Bottom hole diameter (inches).
SHD = Surface hole diameter (inches).
Using the value obtained the next step is to read, from Table 16 the
Koenig Index corresponding to the weighted production hole diameter (WPHD)
Table 16. WELL COST VARIATION WITH HOLE DIAMETER47' 54
Bit Size (Inches)
6 3/4
7 3/8
7 5/8
7 3/4
7 7/8
8 1/2
8 5/8
8 3/4
9
9 5/8
9 7/8
10 5/8
11
12
12 1/4
12 3/4
15
17 1/2
Koenig Index (ft)
88.5
91.5
93.1
93.9
94.5
98.5
98.8
99.3
100
112.3
117.5
131
143
172
180
226
250
292
From Table 15 , obtain the Regional Rating Code number of the well. Look
up the cost ($/foot) of drilling at the depth desired in the appropriate
RRC Graph (Figures 23 through 28 ), and multiply this value by the well
depth. This value is the drilling cost of a 9-inch diameter well (D )
and should be expressed in thousands of dollars (K dollars).
To calculate the COR 1 value (in K dollars), use the formula:
Drilling Cost = (Drill Cost x KoeniS Index }.
(.LUK JJ 9 1QQ >
232
-------
14,000[
12,000[
io,oooL
Region No. 1
Louisana, Kansas, Mississippi, Southwest
Texas, Texas Gulf, North Central Texas,
and North Dakota
8,000[
6,000
4,000
Note:
Data used in the preparation of this graph
was obtained in 1962 (Engineering News Record
Building Cost Index. ENRBCI, of 570). To up-
date to current year, multiply graph values by
(ENRBCI of current year/570).
2,000
10
20
30
40
50 60 70
Cost/Foot (Dollars)
Depth vs Cost/Foot
Figure 23. Region Rating Code 1.
68
233
-------
14,000
12,000
10,000
Region No. 2
New Mexico, California, Florida,
Arizona, and South Dakota
-------
14,000
12,000
10,000
Region No. 3
Wyoming, West Texas, Pan-
handle Texas, and Colorado
8,000
0)
fn
6,000
4,000
Note:
Data used in the preparation of this graph
was obtained in 1962 (Engineering News Record
Building Cost Index, ENRBCI, of 570). To up-
date to current year, multiply graph values
by (ENRBCI of current year/570).
2,000
10
20
30
40
50 60 70
Cost/Foot (Dollar-
Depth vs Cost/Foot
Figure 25. Region Rating Code 3.
68
235
-------
14,000
12,000
10,000
Region No. 4
East Texas, Indiana, Alabama, Nebraska,
Virginia, Ohio, West Virginia, New York,
and Pennsylvania
cu
QJ
8,000
4-J
o.
d)
6,000
4,000
2,000
Note:
Data used in the preparation of this graph
was obtained in 1962 (Engineering News Record
Building Cost Index, ENRBCI, of 570). To up-
date to current year, multiply graph values
by (ENRBCI of current year/570).
10
20
30
40
50 60 70
Cost/Foot (Dollars)
Depth vs Cost/Foot
Figure 26. Region Rating Code 4.
68
236
-------
14,000
12,000
10,000
Region No. 5
Utah and Nevada
0)
01
8,000
D,
-------
14,000
12,000
10,000
8,000
Region No. 6
Montana, Michigan, Oklahoma,
Arkansas, Illinois, and Kentucky
ex
01
Q
6,000
4,000
2,000
10
Note:
Data used in the preparation of this graph
was obtained in 1962 (Engineering News Record
Building Cost Index. ENRBCI, of 570). To up-
date to current year, multiply graph values
by (ENRBCI of current year/570).
20
30
40
50 60 70
Cost/Foot (Dollars)
Depth vs Cost/Foot
Figure 28. Region Rating Code 6.
68
238
-------
The value thus obtained is the well drilling cost adjusted for diameter
and expressed in thousands of dollars (K dollars).
The following is a computer printout of the main program for brine dis-
posal.
-------
IV C IFVFI ;>i i<;,;i , TT3eii3,2)i OTC
lt CPC
1 TTq(lR,?), TT1CI1?,?), nil(F,2) 11C
OCn oF«n 1C.C1.C7.C1
ocr« 10 rr0"/" ( *f ir.c )
nc"c mci.fc.i.i rr TC 21
CfCf rr Tf •>•;
OCC^ ?\ fil I INJFCT
CCC" ?•! fF(r?.FC.?. I PC TC 31
?ccc cr ir -7
mio 'i rfi.i FV/SF
on i ?T iFic^.rc .1. i cr TC 41
nn 12 rr ir «c
non «l r ft L ro VFV
cr". "i < trp
oci" FN"
-------
IV C IEVFI 20 IMFCT C«TE - 713?*
Ill, I, ^, PHI, PK.PR, C, CCR1, VCPIPE, VCFCRC, SPCR, FCI-TF,
C FCPX'T FCR PF«t
130 FCRW8T (II, |C*1, «2, F5.C, F3.3, f,.0, 12,F«.3,F3.0, II. F5.C,
1F?.T, F2.2, FA.3, F*.C, F3.2, F*.1,F2.J, F3.Z, F2.1, F3.2/
'F-;.C,?F4.C,FIC.C)
C fr^vF-T INPUTS TC PRCFER
»r - xr « locc.
10CC.
^«^f
MCE CCC?
Ter
no" i
0"e?
CC'.'-
C
C
r
>F=»f »10CO.
CTR i = CCRI
Fl = 2"=.
;CT IF nit-w
CFT IMTUL
f* - I
C«l.rLl»TF U
3C2S
303C
30*0
30*1
ro
v.f •
vcn
OCf '
OC67
006P
OCfC
CC7C
0071
OC7?
CT7T
007«
007-
CC7f
OC77
C
C
r
C
C
r
c
C
C
C
C
C
C
C
cr rr jic
J'-t IF (C .CT. ft.CI CC TC 203
JT7 ».Hr ^ ICfC. « 3C. « (C - «.OI
rr TT ?ic
?f VHf = 1110. « 101.6 « (C-6.0)
J1C CTNT IMF
TflCLLiTF PUSTIC IIMNC CCST?
P»PL = .1<:77 * r
TAICILATF PPCrUCTICIi HCLE fHPFTEP
Rfc - 7.0 « 1 .« « (C-l .C I
CTNVEP1 ^TFRF5T R«Tf FSCk FFPCF^T
? I I = II « .01
C«irUl»TF C»FlT»l RECrvEPV F4CTOR
C'F = (tl*(l. « m**»/(fl. • 1II«*V - I.)
T«l CLl«TE C£NS IT>
Ohf1 - 62. «1 * SPfR
CfNVfRT Rt, fro* DM Tf RACIL5 flf.C ^Ct-FS TC FFFT
TI-F INJECTION FIELP
VEIL
PC - I » RHP / 1««.
N = KLKPER CF WFILS
IF ( ^ .EC. 0) CC TC f
cr ir •>•*
FINO M»PEP TF WFLLS
N = K « I
cHdi«Tr Firv R»TE
xi = >c/^
CALCLUTE FLIIT VFICCITV IK
V = .COO2B1 » X| / (C<*2»
C»ltll«TF RFYKCITS M»PFP
x^RF = i IJA. * PHC * r * v ) /
LfTK-tP F»KK!f,C FRICTICK FACTCR
C'll TIKK1T1, I, 1C, »M=E, F, 1,
C«lniMF FRK.T1CN LC55
pr = ( at-f / ici.cj | » f « | » (
joec
3CFS
?c^c
3cc<;
31CC
30";<;
3110
31 IS
3120
3070
31CC
3I3C
1I3S
'I5C
3i;<;
MtC
317C
32C1
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CCMMCK / C / EKR, CRF, >C, XP
7E,P
CCM"0/ 74PLF/ 771(10,2). 772( 11,2 ) ,773A( 14, 2 1 . 7738(13,2),
1 173CM3.2I, 7730(14.2). 773E(ll,2), 773FU5.2), 774(4,2),
2 775J(2C,2>, 775N(21,2I, 776(7,.
?). 777(13,21. 778(6.2),
3 774(18,2). 7710(12,2), 7711(8,2)
HIMCrMCN PL»CE(4C), VCRM40I, PM»E(6>, 7ES7I20)
ffTA FLANK/' '/.SABCV/'APCVF [R •/, SB FLO/ • BELCH BR'/
'01
'0?
30'
304
'C6
"17
'01
'Cc
'10
311
>0?
312
313
?I4
MS
?1«
317
1
1'6 •/
SCRlF(y)»SCR7(»l
PBTMVPFB»AMM CA7* 7«CLES
PR(N7 '01, (771(1,1), 771(1.2). I-
PPtwi 3C2, (772(1,11, 772(1.2), I-
PO|M 30', (773MI.1), 773«(t,2l,I
<">1M 30t, (TT?Clltll, 773CU.2).
PPINT -«fl7, (7730(1,1), 773r(I,2),
PRINT T6, (773EH.1), 773E(I,2),
P1IK7 'OS, (773F(I,ll, 773F(I,2),
FBIN7 ?1C, (774(1,1), 774(1,2). I'
F»!M 105, (775N(1,1), 775^(I,2I,
PRIM ?12, (77((I,l), 176(1,2). 1-
PRINT 112, (777(1,1), 777(1,2), I-
PRIM 314, (778(1,1), 178(1,2), l-
»»fVT ?15, (77S(l,l), 77«(I,2), 1-
PPIN7 31t, (7710(1,1), 771C(I.2>.
PRIM 317, (7711(1,1), 7711(1,2),
FCRMA* (IHl, 3H771,//(2F2C.4»)
frpttfr (m, 31-772, // (2^20 «4 ))
fCeifl (IHl, 4f-713A,// (2F20.4))
FfRVM (11-1, 4^773B, // (2F2C.4I)
FCR»M (1H, 41-773C,// (2F20.4I)
FCR»AT (IHl, 4H773C, // (2F2C.4I)
FTRMJT (in, 4I-773E, // (2F2C.4I)
ffaxtl (IHl, 4K773F, // (2F20.41)
FCRfA7 (IHl, 4H774 , // (2F2C.4II
tCRf^T (IHl, 4H775J, // (2F2C.4))
FTRPA7 (IHl, 4H775K, // (2^20.41)
FORMM (in, 4^77e , // (2F2C.4U
FTRKJ7 (IHl, 41-777 , // (2F20.4I)
FCRMA7 (IHl, 4H778 , // (2F2C.4H
FCR«
-1.12)
-1,8)
REAT ICO, JC, (PtACF(l), I - 1,10), RPC, XC, RKW, CPA, V, II,
1060
C7C
0*0
040
110
1110
2CCS
2010
2020
2C3C
204C
2o;c
20(0
207C
2cec
2CSC
21 OC
21IC
212C
2130
214C
2150
?1*C
21<2
2210
222C
2230
224C
22«C
2260
227C
22£C
2290
23CC
231C
2320
233C
2340
2350
23
-------
CO
•(^
OJ
Ff«TR«K
OC7P
OC7<;
00*0
or"i
ncf -
OCFI
OC<".
CCF'
DCS*
11P7
or*?
nrpc
rr<:r
ro<; i
m<;7
f c^ °
"C*"4
cccl^
res*
(IOC?
1CCC
CCCe
OKC
OKI
cu?
nic1
11C4
fir?
nr*
1K7
OKR
IV C I*VEL ?n IKJFCT DATE « 71356 12/«<>
r CALCLKTF CISTAKCF TC CUTTERfCST FLCCC FRCKT
PF = 124. f * 5CRTFIM « > /«1000. » H « FHMI
r CUCUATF CRIVINf PRESSLRF VITH DARCY ECLATICK
r.f.\t> '(XI * .434294482 » ICCFIRE/R* 1 1/( 12?.J, K, V, XNRE, F, PF.OCC, OELP, PC, PCH
1111 FCPf«T
IF(K ,CT. ?5» CC TC 77
GC TC 7*
77 5WN = 1
CC Tf ^
If SkN = C
f TFST COWPUTFr PCH AGAIKST CAX. AtlCWABlE PCH
IFfPO - FCHTF * I I S3, 4, 3
q •» | F| OCH-C .C IC2 , SI, SI
17 It'P* 1
PCH* c.n
cc re 4
"I ILP » 0
C K I? ^w THF »*XIPl»i MPPEP CF WELLS KEECEC
r «f IS ThE MIMKUI" OIMAIVCF RFlkFFK A^V 2 fcELL!
<• CCMIM.F
r I?F LL
C tTMPLTF TOTAL INJECT 1C K PLKP HFAC
PI - PCI- 4 FL
IF«LI F -i) <;c, P«, e<;
"<; en? = 1.1
cr TC PR
C CAICllATF RECO ERAKE HCRSEFCliFP FCR UJECTICN FtfFS
re 8HP = cxr » Pt/2*6eCCC.)/.P5
C fCMPLTF E^FR^Y RECUIPFPEATS FC« IhJFCTICK Pli»PS
Od KV, = PHP « .746 / .<:••
C CCNVEPT HP TC FFET CF HEAT
PI * tl 1 ( RHC / 14«. )
C CO'VERT FLC.W RATE FRC»< GPC TC GPf
rtv * XT/144C.
r CAICLI ATE riAI>FTER Cf SCFFLY LUE
rrn = .cri«i * » xr*«.4« ) * ( RHC**. 14 i
C CCXPLTF HFJC ICSS IK ?LPPLY LINF
HF = .cc' * HPK * «2tc.
/5t
321?
322C
322S
323C
323S
324C
324S
325C
325C
32M
3252
/ 32'2
3Z55
»325t
3257
3256
3256
325S
3260
326C
326C
3262
3264
3266
3267
326t
327C
3280
32?C
32'!';
3300
33CS
331C
3215
332C
3322
3324
3326
332S
3330
333S
3340
3*4?
33'C
335"!
33
-------
IV r
70
IMECT
C*TE « 7135*
12/5S/M
FACE C004
to
OIC"
oi ir
•Mil
on?
Oil'
Ol 14
01 I"
out
0117
OH*
01??
Ol2r
Cl ?t
"1/7
012fl
C1T
01??
013
01'7
Ol'P
Ol'c
oi«r
0111
0143
OM«
014*
0147
01«P
rFTFR»IKF TCt»l HEAC PECIIPEC
rut- * FI - HF
C»lCLim SUFFIY HEAT RECt
("•I* = APSF I CEIH I * 1H-C / 144.
SFT Pl-P AND Kh EOlll TC 7ERC
4014
402C
IHTEll- - O.I 5, 6. (
CCCPITF PHF HFEOFCFC* SLFFIY FUPFS
f. »H>? < (»r • P)>IN/24/.eS
CCHFLTE FrtiFli RFCUlREPfMS
KV? - PHP? * .746 / .<3
C'ICllATE CAPACITY OF <1GRAGE FACALITIES
t ?CXC = XC/ 3.
IFJK - II ft, f7, Jt
"7 »F = C.O
ft TFHP - SPFIC
IFIEl - C.I t*, P4, 14
«s TF»P = s»ecv
CFNTER TITLE CH CUTFIT FACE
»4 KL * C
1
PUCK
rr PI u - 1, tf
Jl = 4C - II
IF(Pl»CF»Jll .EC. PlAfKI CC TC 82
cr TC PC
Kl
8? Kl
"1 CPNTIMF
CC TC 7?
»0 Kl - Kl/?
CC 7^ III = 1, Jl
7C hPRKIKl 4 111 I < PL ACE(III I
PPIHT 2»C FACE TITLE!
7" DRINT 107, IkCRKIII. 1=1, Id,
1 R«C, K, RF, XP, IFC<
PCH. XP. FI, IPC, CPP. Bt-P. Y,
F»0.
ABSFIFLI
10, Hi
11
1C
403C
4034
4040
405C
3C5S
4C(C
4139
414C
4210
422C
423C
4240
4250
42!?
4260
427C
42EC
42SO
43CC
432C
433C
4340
4360
4370
44C4
44C5
Kt> 4410
4413
44I«
PRIM 2KT FACECATA
SFT IF TEWP PRINTING WRIABLFS **19
11 PR1KT 1O3, II, HKU, F, CPA.CP^l, ENR, »C, SCXC, CPf, TE»P, FFl, 442C
t IFKAfFIII. 1=1,61 **'0
IF(LI - Cl 13, 12, 13 ***C
!2 FRINT IC4 **-C
Cr TC 14 44tO
13 FRIKT 10? 447C
14 Pt-Ifl = PV • 24. *^*C
P«, H, PR, H, PHIC, SPCR, VCPIPE, VCFCPP, PCHF44SO
•C7C
24.
PRINT lOf, L, PHI,
-------
t\)
**
Ul
ni «•>
01".
Olf 7
llftl
01*7
01*P
Ctf
017C
C17t
117?
117-"
1174
017'
1176
0177
011F
ci 7<;
11P1
11 p?
IV G LEVM 20 IKJFCT
c PECIK COST COFUTATICK;
c
C SFIFCT PRCPFR RRC CISTSICT
74 CC 1« 1=1,12
IFIPRC .FC. 1E5TIII1 CC TC 16
DATE
71356
12/59/56
PAGE CCC'
FPINT 111, RFC
GC ir <;<;
RRC = — I — — 2 — — 3 — — * — — *. —
It T T (21, ?1, 22,22, 18,18, 19,19, 2C.2C,
irnx-tp TBIIIIM; cesi
17 CML TIKIITT?*, ?, IS, L, F, C, CI
GC 1C Z1
IP CUI T1KKTT3P, 3, 12, I, F, C, CI
cr TT 23
l<: CiLL UKIUT^C, ?, 13, I, F, C, 01
GP TT ?3
?0 C»IL TlKL(TT3r, ?, 1«, L, F, 0, 01
fir TC n
?l Ctlt TLKI., 11, L, f, C, CI
C-T TC ?1
72 CHL TLKI.nT3F, 3, 1^, I, F, C, CI
2? F * L « F
FKSTIC 11MK rcST
17,171,1
OlFf
»00 PIC = PAPl * ll-Lt«(-l
CC TC PC?
PCI PIT = P«PI * II-II*HI «ic. * t-
POP CCMTIMJF
C II I? 0 FCP t 5A^CSTC^E FCBC*TICK, TVEPEFCPE I- IS NOT USFH
C*LI TLKIITTA, 4, «, I, FF, C, CI
C CittlUTf CCST CF EKI- KELl
TVC = F » I.HC » FLC 4 FF « CCP1
inni CCNTIM.F
C CC»PLTE CCST CF «Ll VEILS
1VC » N * ThC
C*U TLKLI TT1I, 11, f, CCD, F, C, 0»
C CC»«? = .075 * TP* * «?ec.
C C4ICLI4TF CCSR CF SCFFIV PIPF
SS»R = F « ntf * 528C.
C KC LIN^C PFCt FCK SlfflV FIFE
CSLC = C.O
C LCCK-LP FUHF I-. P. SUES
C»LL TLKLITT7, 7, 11, e^F, F, 1, 11
CFUMF = PfP * F
CPU»F2 = 0.0
IFIPFLU 27, 2F, 28
27 r«H. TLKL(TT7, 7, 13, BI-P2, F, 1, 11
CFUHF2 ' PHP2 * F
C SFT l» TFMP VARI/IBIF FCP STC«»CF. CAPACITY
IN
5oeo
5120
«1?C
517C
?S1C
522C
5?3C
52«C
5250
?26C
527C
52PO
52SC
5300
5310
'311
«330
5150
536C
5370
603C
tC4
-------
FrR1««K IV G IFVFl 70
UJECT
C»TE
F*GE CCCt
11P7
rise
Clcl
f irfK-LP STCRACf COSTS
ruiL UKUTTR, B, 6, F, STRC, 0, 01
f CM.Cll.ATF TRF1TPEKT FIAKT CAPITAL COSTS
TPir = 1C.**(4.062 * .C4M * ICCFIXOI
f ICOK-IP kEll FIEIO C«»
OIL TLKI.ITTS, St It, >C, F, Ct Cl
C SFT tF E^R CCKVEPSICK FACTCR
CFNR i E*R/?7C.
C RCUNC CFf Alt I-ITEPS TO NEAREST DCltAR
*15C
t!5S
61«C
6ie<;
(17C
«2C?
*21C
621'
till
N>
Oil*
cic«
ozoc
0?CI
P2C7
C2C'
C'C*
n?r^
c?ct
f»cc
c?ic
P?12
021*
C2!t
07)7
CSI C = K
^»-.2«*K*CF*».•
MFSC-KX
PSSC'KX
siTLC-ss«r«c
-------
F1RTRAN IV f
INJECT
CATS * 71356
FAOF CC07
ts)
it*
-J
023!
1776
02?7
17?"
c?,c
024r-
1241
0247
024'
17<4
0?4f
0246
0747
174>
„«
X?*.?:
0?« 1
02??
12*3
17'=4
07"
025*
17*7
171!"
025?
T2f C
•12*1
02*?
17* '
O'64
02*"
O7*f
1267
07* f
PSPC*M
F = F * 1 .495
r CAlCtlATF ANT PRIKT FFCAIHTEP CF CCST ITEPS
C CCST fcFUhEAC CrwPONEMS
CALL *>rKEV(TVC, fcFSC, t.FS» • WFhCV « F, C., fcf, Vf, hICM,
1 WSLK. MFAI>, fcFlVr, kSLPAE, kFC, kFCI
C fCST StPFLV 1 !*F CCNFC^F^T«
f«LL "CKFVISITIC » CfU*F2, SIC«C, StFC, .0029, SC, SE, SIC*.
1 S5t»>, SIAC, 'IIWC, SSIPAF, SEC, SFCI
c CCPPITF SUPPIV iikE r * TSCt> » FSU> 1 / 10COOOO.
PBTNT 107. CPLArEMI. 1=1,101. (PKAWE(J), J, C£l>, TStC, FStf, TS1
PRINT 10
-------
IV C IFVFI
INJECT
DATE
12/54/56
FACE 0008
C77C
C27I
0272
17.7*
0774
077?
177*
0277
027P
P77>?
0?PC
0?"1
07P7
02P?
07B*
IN)
4*.
oo
07B7
0?P«
02C'
0717
C7SF
03CC
TSI » »>E * SF 4 CE » TFE « PF
"RIM 117, t.F, SF, OF, TFE, PE, TSI
TSI = KICK * SIC* « CICI" < TPIC»> « PIO
PRtM l!«, fc!CP, SIC>, CICP.TFIOt PICC, IS1
T«l » hSLMAE « S5VAE « CSll«»F » 1SUME
PRINT 110, NSUMF, SSUHtE. CSUKAE, TSUf*E, PSUN»E, TS1
TSI = WFCM » sio « c;tf « TPCC « PSCI»
PRINT 17.C, HFC*, SlOP, OSCf, TPC»«, PSCf, TSI
151 * hF«
TSI
PRINT 124, VFGA, T, T,
TS] » MFAM 4 SIA* 4 C!
T51
TCE
«co
77 SUN
TlTPtT FCRP^TS
67IC
6720
673C
tuc
6750
676C
677C
S810
S82C
M10
6846
FSSC
PRINT 171, HFSf, T, T, T, PSSP, TSI
PRINT 122, HFtiCV, T, T, 1, T, MFkCV
1U " liFPC 4 PSPC
PRINT 123, WFPC, T, T, T, PSPC, TSI
MFGA 4 FSGA
FSG*. TSI
TPAr 4 PSAP
PRINT 125, WFAIi, SlAPi, TSAf, TPAr, PSAf, TSI
TSI - fcFIWC 4 HUC 4 CSIhC 4 TPIkC 4 FSUC
PRINT 126, HFIfcC, SllkC, OSIkC, TPIhC. PSUC. TSI
SIPC 4 PSPC
127, T, SIPC, T, T, PSPC, TSI
VEC 4 SEC 4 TEC 4 PEC
PRINT 128, fcFC, SIC, TEC, TEC, PEC, TCE
TSI - hPC 4 SPC 4 CPC 4 TPC 4 PPC
PRINT 124, HFC, SPC, CPC, TFC, PPC, TSI
XC IN MUIt»S
xn / iccccce.
0
IFIXLAST.FC.l.l CC TC C87
rc TC i
PLlll STCP
<; CTNTIMF
7600
7?2C
7MC
7040
71CC
F8.C,F5.n, 2PF3.0, 3PF4.0, CPF4.C, 12, 4PF8.C71C4
pete
8870
eeee
88SO
8400
PS1C
8920
P930
F.44C
8S50
OtC
t,712C
2«=«.0,5H FEET,/,17H (FFILENT VCIUKE ,??X , FP .0 ,<^ CPT, //,?«(- EFFLUENT7 13C
2NT CCNCF\TR»TICN,
3 l6X,I7,4h PPM,16X,20hTUBING HEAC PRESSURE , 15X , Ft. C, 7HC
*4H PSI.//.2ZH PRCPIJCT PETRC VClLfE , 1 7X ,F8 .0 ,«K CPC , 16X , 14t< IN JECT I715C
SCN "(j»V hf»C,l6X,FP.C,5h FEET.//.S4H PROCLCT PETRC CCNCEN TR»T ICN ,7160
frl7X,I6,4> PP»>,16X,23HNJFCTICN FU»
-------
I=<-«TRAH IV G LEVEL JO
IMECT
C«TF - 7135t
12/5S/56
FA6F CtC<5
031?
OT'
vO
OT7
3311
OM2
T313
O'K
1317
0"* t B
037P
0371
CI32«
1 17> PCWER RATE, 7215
? ?SX,CFFt.4,eH t/KVt-,14X,mSUPPLV PL'ff HEAC ,l«>,Fe .C ,5H FEET.//722C
311H IAKC CCST,32X,F«.C,7H S/ACPF , 1 3X , 20K SUF FlY FU*P C»P»CIT¥, 15»t723C
3 Ffl.C, 7235
*4^ rp»,//,2^h EKP RtllCUC CCST INDEX, 1 «> ,F* .C, / ,67 >, ?«MPEMPEM 124C
5 Pt*KT C1PACITV.IIX.FF.G.4F CPr,//,13H KFll FIEIC . 5«X, I tKSTORAC E 725C
6 CAPACITY, 1SX, Ft. C.^ C«l.t//t«X,26HCIST«KCE FPCf EP.Crt FC IM .12X7260
7,F3.C,6t- CIl FSt//,6X ,30HEIFV«T ICf CF IKJECTKK SKI ICK , / , 1 IX ,AF , 727C
PlCH.Ctl POrNT,13X,F5.C.5H FFE1,///,lth FCPKirCK K •»•£ .32K ,5»8 ,*2 )72PO
l!T^Cltc>,^7x, CH?»NCMCNE> eoio
IITHCKGYI C02C
1O >=r(!»««TllHC.l?K TCTll rFPTH.2ex,F6.C,«h FEF1,//,10H PCPCSITV .3*X , 803C
I 2PF3.0.SK FFRCFUT , FC35
? //,\4K PFRfF.«PILM>,?f!>lOFF5.3.aH C*RC IES ,//, 1«F EFFECTIVE ^EIeC4C
1GhT,2;x,F*.0,5F FEET,//,?CH P.FSERVCIP PRESSIPE,22».F5.C .41- PSI.//805C
*/,l«F TURING T. 0..27X.F6.3.7F INCHES, //, 231- PKCCUCT IGK HPIE I. fC6C
807C
8060
8C83
C0f7
6 25H
7 FH.
» •?0^
1Q7
SPECIFIC fPAVlTV,24X,F5.3,//,
EFFLUENT VISCOSMV IK —./, 21H ISJECTICK TLRING.20X,
3F CP,/. 14h FCPMTICK, 27X, Ft.3, 31- CP»//.
FRFSSUPE TEST FACTCP, 12X, F5.3, 71- PS I/FT )
SHOCiHC* ,10Al,33X,<;i-R.R.CCOE ($A8.A2,/,7X,17H
HLFKT vniu«F .F8.0.4I- GFC ,74 X.27FEFFLUENT CCUCFKTPATICK ,17, 81CC
2 4H PPM,/, 7X,UHP«nClCl VCLLPE ,F8.C,4H GPO .24X.28HFPCCLCT FETPC 8110
TREATCEM FUPF STAT ICK,'/,78»,51-81?0
PIAKT ANC STCRAGE TCTAL814C
1C8
109
11C
111
112
113
1 14
lit
llf
117
11"
6)
FCP«»TC 1HC,2?I-CAPIT«1 CCST, *
<:r»»'*T(11-0,22F HELL CCST
Frp«»T(lHO,22h SITE CCST
FrR"AT( 11-0,
t 1 H ,
FCP* *T ( lf-C ,
1 1H ,
FTPPAT I lt-0.
FTRfATJ IHC,
FCRM AT ( 11-0 ,
FrP"Al( 11-0.
fw/nt IHO,
,6IFM.O,2X) 1
,6(F11.0.2». 1K?3HO
ANNUAL FXPEMMTLPE
r « K
SLPPLIE; « PATER
kCRKOVER!
PAYRCLl CVEPFEAf
G « A
APOPT I2AT ICIS
IMPREST CK
WCPKING CAPITAL
FCHFP CCST
• KMAL CCST PEP
. *
IAL
1000
,6(F11.C,2X)
,6(F11.C,2X)
,6CF11. 0,2X1
,6(F11. 0,2X1
,6(F11.C,2X)
,6(F11.0,2X)
,6(F11.C,2X)
,/,
,6
-------
FORTRAN IV r IFVFI '0 UJICT CATE « 71356 12/55/it »AGE CC1C
<«T(lHl,14h PRC 0151PICT,, A2.11H IS L'M>KCMM 8500
03?1
-------
IV C IFVEl 20
kfC
C*TE « 71356
F»GE CCOI
nooi
OCC7
UFO ^, xc, »t, rev, PC, PIC, cc, Rhc, xn. P.I-O i 1010
TUS SUPP CESICH.S TMt ISTP. IfltT IOK SVSTEf FOP. THE kFUFIEtO 1C2C
IF «H-1» I, |, «C 1C3C
cccc
OJ
OCC"
occ=
ccic
ecu
0112
CC1'
OC1«
11 IS
0017
002?
OC27
CC?"
CCT
003"!
004°
CC'C
no1;?
*« * RI-C**.M * .5
cc-o.
RFTLB^
sr rri- .oncsi « i >c / K
IF |k-?» SI, «l, S2
«1 C«ll CFTCST (fCl, FC»^, CFFl.ClPFl.KSkl
ci-ol
Cf'C.
IF (K-2» 2, ?, Ml
rn« c.58
Cl« 1.73
cc rr «s
Cr« c.S
ri= i.c
fC TC «S
IF (^-s^ «, «, s
re- c.7i
<•!« J.82t
CC TC 99
CC- I.C
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-------
INPUT TRANSACTION
*. :t :v-.-
DISPOSAL TftKATMENT PRACTICES RELATING
TO THE OIL PftOUUCnON INDUSTRY,
Reid, C.'.W., Str««/ol«» L.E., Canter, L.W.. and Smith, J,R.
School of Civil Fnglnfeering and Environmental Science
University of Oklahoma Research Institute
Norioan, Oklahoma 73068
14020 FV'W
14-12-873
&/»;,''£#^^ .-,'. .
Environmental Protection Agency report number EPA-660/2-74-037, fey 19fl
Methodology in developed for the economic evaluation of envtrcoroarstally acceptable
brinf disposal systems. Specifically, a procedure is for determining total
unit of alternative systems, These are compared in order to the
least expensive, tegaUj.-permitted disposal processes. The text progresses from a
broad simplified discussion of resources economics to the more specific subjects
of cost analyses, are included for
the necessary infartJiation for use in the , A listing Is of
regulatory their in brine disposal
policies . {Pfeffer -EPA)
*C11 industry, *Brine disposal, *Coet analyses. Stale peraiits, Evaporation,
Injection wells.
Brine , State-permitted brine mechanisms,
05E
Sfad To,
'"red M. Pfeffer
Promotion
------- |