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ENVIRONMENTAL ENGINEERING SCIENCE
Volume 25, Number 2, 2008
© Mary Ann Liebert, Inc.
DOI: 10.1089/ees.2007.0026
Produced Water in the Western United States:
Geographical Distribution, Occurrence, and Composition
Katie L. Benko
1,2*
and Jörg E. Drewes
2
1
U.S. Bureau of Reclamation
Denver, CO 80225-0007
Environmental Science & Engineering Division
2
Colorado School of Mines
Golden, CO 80401-1887
ABSTRACT
Coproduced water is a byproduct of oil and natural gas production. Because it is in contact with hydrocarbon
products and geologic formations in underground basins, it usually contains elevated concentrations of inorganic
and organic constituents. This paper aims to illustrate the concentration ranges for specific contaminants and the
estimated quantity of coproduced water in the Western United States. The total dissolved solids (TDS) concen-
tration in coproduced water can vary between 1,000 mg/L and over 400,000 mg/L; however, some basins tend
to have much lower median values of TDS. Sodium chloride was found to be most dominant salt found in co-
produced water across all basins studied. Oil and grease, ethyl benzene, benzene, phenols, and toluene are the
most common organic contaminants found in coproduced water. The total oil content in coproduced water can
range from 40 mg/L to 2,000 mg/L. Understanding the composition and quantity of coproduced water is essen-
tial for assessing the viability of beneficial reuse and selecting appropriate treatment processes for the water.
Key words: coproduced water; water quality; oil; natural gas; geographical distribution
239
*Corresponding author: U.S. Bureau of Reclamation, P.O. Box 25007, Denver, CO 80225-0007. Phone: 303-445-2013; Fax: 303-
445-6329; E-mail: kbenko@do.usbr.gov
INTRODUCTION
C
OPRODUCED WATER
is defined as water that is extracted
from subsurface geologic formations containing oil and
gas (Society of Petroleum Engineers, N.D.). It is estimated
that the oil and gas industry generates 10 times more water
than oil and gas (Desalination and Water Purification Tech-
nology Roadmap, 2003). Current practice for disposal of co-
produced water includes reinjection into underground for-
mations, surface discharge into receiving waters, or land
application. Reinjection is an expensive option for oil and
gas producers and can only be done when the underground
structure can accommodate the water. Surface discharge can
cause contamination of drinking water or irrigation water
supplies either underground or on the surface. When applied
to land, the excess salt commonly found in coproduced wa-
ter can make soil less permeable to air and water and reduce
the availability of nutrients in the soil (Veil et al., 2004).
The estimated amount of coproduced water generated in
the United States is between 6.1 10
6
m
3
/day and 7.8
10
6
m
3
/day (1,600 mg.day and 2,100 mg.day) (Boysen et
al., 2002; Veil et al., 2004). This amount of water is greater
than the combined daily water consumption for New York
City and Los Angeles (“More Masses Huddling, 2006; Los
Angeles Department of Water and Power, N.D.). In many
areas of the United States, fresh water supplies have been
fully allocated; therefore, additional sources of water must
be identified to meet increasing water demands (Desalina-
tion and Water . . . , 2003). In the arid regions of the West-
ern United States, treated coproduced water may relieve
stresses on conventional water supplies and provide a sta-
ble source of water during times of drought (Veil et al.,
2004). Especially the Western U.S. is currently experienc-
ing a significant growth of coproduced water production due
to the increasing interest in exploring unconventional nat-
ural gas resources (coal bed methane, oil shale, and tight gas
sands) to diversify the energy portfolio of the United States
(Stevens et al., 1998). Coal bed methane (CBM) accounts
for 7% of the total natural gas production and 8% of the gas
reserves in the United States. Development from the Rocky
Mountain states of Colorado, New Mexico, Utah, and
Wyoming accounts for nearly 8% of the total coalbed
methane production in the United States (Bryner, 2006).
Understanding the chemical characteristics of coproduced
water is important for determining appropriate treatment
technologies and optimal beneficial uses of the water. Re-
actions between dissolved constituents in the water and in-
teractions between the water and surrounding rocks or pe-
troleum can affect the composition of coproduced water
(Veil et al., 2004). The inorganic chemical characteristics
of coproduced water vary considerably depending on the ge-
ographic location and the geologic formation from which
the petroleum and water were produced. The organic con-
tent of coproduced water depends heavily on the type of hy-
drocarbon produced and exists in two forms: suspended, dis-
persed oil droplets, and dissolved organic material
(Stephensen, 1992).
The purpose of this study is to describe the current state
of knowledge regarding the chemical characteristics of co-
produced water from both conventional and nonconven-
tional oil and gas, including the inorganic and organic con-
tent, along with the estimated volume of water available
based on peer reviewed literature. Additionally, the scope
of interest for this paper is the Western United States, in-
cluding Montana, North Dakota, South Dakota, Wyoming,
Utah, Colorado, Nebraska, Kansas, Arizona, New Mexico,
Oklahoma, Texas, and California. The major oil and gas pro-
ducing basins in the Western U.S. are Williston, Powder
River, Big Horn, Wind River, Green River, Denver, Uinta-
Piceance, Paradox, San Juan, Raton, Anadarko, Permian,
San Joaquin, and Los Angeles (Energy Information Ad-
ministration, 2004). A basin is a geographically confined
depression in the earth’s surface, consisting of layers of strat-
ified rock, in which sediments accumulated and hydrocar-
bons may have formed (Van Dyke, 1997). This paper pro-
vides insight into the quantity and quality of coproduced
water originating from these 14 basins.
CONVENTIONAL OIL AND GAS
COPRODUCED WATER CHARACTERISTICS
Methodology
The U.S. Geological Survey (USGS) has published an ex-
tensive database containing the major ion analysis and total
dissolved solids for water from 58,706 oil and gas wells (pri-
marily from conventional oil and gas operations) from the
mainland U.S., Alaska, and offshore (Breit and Otton, 2002).
The database allows the user to download data by state or
region. For this work, data were used from Montana, North
Dakota, Wyoming, South Dakota, Utah, Colorado, Ne-
braska, Kansas, Arizona, New Mexico, Oklahoma, Texas,
and California. There were 33,189 wells considered in this
analysis (56.5% of the entries in the database where used).
The geologic basin is provided for each well in the data-
base. The data was reorganized by geologic basin, rather
than by state. For some basins, the total dissolved solids
(TDS) varied by geographical location and for these basins,
the data was further organized by state within the basin. The
minimum, median, first quartile, third quartile, and maxi-
mum values were calculated for each basin. Using the ma-
jor ion analysis provided by the USGS database, mil-
liequivalent concentrations were calculated for each ion. The
anion and cation with the largest milliequivalent concentra-
tion was considered the dominant salt in the water.
A limitation of the USGS database is that it does not ex-
plicitly state which wells produce oil and which produce nat-
ural gas, the lifecycle of the wells, the flow rate of water
from the well at the time of sampling, or the extraction tech-
nique used. Thus, the database is best used to draw general
conclusions about the water generated by the petroleum in-
dustry as a whole.
Inorganic constituents
Coproduced water is generally characterized as brackish
groundwater with elevated concentrations of total dissolved
solids. The inorganic constituents present in coproduced wa-
ter are primarily derived from the rock formations with which
the water is in contact; therefore, the water quality regarding
inorganic constituents is organized and presented by geologic
basin. Water from conventional oil and gas can exhibit a wide
range of TDS concentrations; 1,000 mg/L to over 400,000
mg/L. The TDS concentration range observed in coproduced
water represented in the USGS database is presented in a box
and whisker format with the minimum, first quartile, third
quartile, and maximum value of TDS within each basin (Fig.
1). The data is presented on a log-scale to accommodate the
large range of TDS values observed. For basins in which the
TDS varied significantly, TDS statistics were calculated for
each state occupied by the basin.
The Williston Basin exhibits the most geographical vari-
BENKO AND DREWES
240
ation by state of any of the basins studied. The TDS of wa-
ter samples within the Williston Basin are much higher for
the portion of the basin that lies in North Dakota. Ranges
of the most common inorganic constituents were obtained
for all basins (Table 1). The TDS concentration ranged from
1,000 mg/L to 400,000 mg/L, with a median value of 32,300
mg/L for all basins. Sodium and chloride were the ions gen-
erally found in the highest concentrations.
Data was not available for arsenic, boron, and silica; how-
ever, these constituents are important to consider when us-
ing and treating the water because boron and arsenic are not
removed by the majority of treatment processes and silica
can cause scaling problems in membrane processes.
The USGS Produced Waters Database was used to com-
pute the dominant salts present for each water sample ana-
lyzed. Sodium chloride was found to be the dominant salt
in over 76% of the coproduced water samples. The next most
common salts found in coproduced water are sodium bicar-
bonate and sodium sulfate (Fig. 2). Magnesium sulfate and
magnesium chloride were found in a high concentration in
the Big Horn Basin, Permian Basin, and Wind River Basin.
Organic contaminants
In contrast to the occurrence of inorganic constituents,
which are determined by the geology of a basin, the quan-
tity and characteristics of organic contaminants in copro-
duced water is impacted by a number of factors including
type of hydrocarbon product the water is in contact with,
volume of water production, artificial lift technique, and the
age of production. To date, no studies have been conducted
to quantify the impact of these factors on the organic con-
tent of coproduced water. The organic data presented here
was derived from sources that reported on the organic con-
tent regardless of location and type of product. Table 2 lists
the concentration ranges of organic material commonly
found in coproduced water from oil and gas operations. Ben-
zene, ethyl benzene, toluene, and phenol typically occur in
the highest concentration in coproduced water (Table 2).
The data presented in Table 2 does not distinguish between
water from oil operations and water from gas operations; how-
ever, water from gas production tends to have higher con-
centrations of low molecular-weight aromatic hydrocarbons,
such as benzene, toluene, ethyl benzene, and xylene, than wa-
ter from oil production (Jacobs et al., 1992). Detectable con-
centrations of volatile organics are found in 75 to 80% of all
gas coproduced water samples (Fillo et al., 1992). Semi-
volatile organics are rarely found in gas coproduced water
and are much more prevalent in oil coproduced water.
Coproduced water occurrence
The amount of water generated during oil and gas ex-
traction is not known exactly. Some states keep records of
COPRODUCED WATER OCCURRENCE AND COMPOSITION
ENVIRON ENG SCI, VOL. 25, NO. 2, 2008
241
Figure 1. Distribution of TDS in produced water by basin. (Note: the outline of the box represents the 1
st
and 3
rd
quartiles, the bar
in the box represents the median value, and the wisker length represents the minimum and maximum TDS values).
coproduced water volumes, but for other states, estimates
of water production are derived from oil/gas to water ra-
tios. A number of different sources have provided esti-
mates of coproduced water quantities (Boysen et al., 2002;
Veil et al., 2004; Bryner, 2006); however, there is a large
variation in the water quantities reported. Where multiple
values were obtained for water volume, the state reported
figure was used preferentially. The oil/gas to water ratio
was used only when a state figure was not available. The
total amount of water generated in within the basins pre-
BENKO AND DREWES
242
Table 1. Ranges of common inorganic constituents in coproduced water.
Number of data
Constituent Units Low High Median points considered Reference
TDS mg/L 1000 400,000 32,300 33,189 Breit and Otton, 2002
Sodium mg/L ND 150,000 9,400 33,189 Breit and Otton, 2002
Chloride mg/L ND 250,000 29,000 33,189 Breit and Otton, 2002
Barium mg/L ND 850 Unknown Unknown Breit and Otton, 2002
Strontium mg/L ND 6,250 Unknown Unknown Breit and Otton, 2002
Sulfate mg/L ND 15,000 500 33,189 Breit and Otton, 2002
Bicarbonate mg/L ND 15,000 400 33,189 Breit and Otton, 2002
Calcium mg/L ND 74,000 1,500 33,189 Breit and Otton, 2002
Note: “unknown” in table signifies information not provided by the source.
Figure 2. Dominant salts in produced water by geologic basin.
sented is estimated to vary from 106,000 m
3
/day (28 mgd)
(Veil et al., 2004) to over 1,197,000 m
3
/day (316 mgd)
(Van Dyke, 1997). Water production data, median TDS
value, and the potential for treatment was determined for
each of the major producing basins in the Western United
States (Table 3).
The potential for treatment within each basin was de-
termined based on the median TDS concentration and the
quantity of water within the basin, and is used as a pre-
liminary assessment of where desalination treatment ef-
forts should be focused on. Basins containing large quan-
tities of water with relatively low TDS are considered to
have more potential for treatment than basins producing
small quantities with elevated TDS concentrations. Addi-
tional considerations impacting the potential for reuse,
which were not considered in this study, are agricultural
activity, stream flows, population centers, and logistical
infrastructure (i.e., chemical supplies for water treatment
processes) in proximity to the water production.
COPRODUCED WATER OCCURRENCE AND COMPOSITION
ENVIRON ENG SCI, VOL. 25, NO. 2, 2008
243
Table 2. Concentration ranges of organic material in coproduced water from conventional oil and gas.
Constituent Low High Median Technique (method) Reference
TOC (mg/L) ND 1,700.000 Unknown UV Oxidation/IR (EPA 415.1) Tibbetts et al. 1992
TSS (mg/L) 1.200 1,000 Unknown Gravimetric (EPA 160.2) Tibbetts et al. 1992
Total volatile organics 0.390 35 Unknown GC/MS (EPA 1624 Rev B Tibbetts et al. 1992
(mg/L) and EPA 24 & CLP)
Total polar compounds 9.700 600 Unknown Florisil column/IR Tibbetts et al. 1992
(mg/L)
Volatile fatty acids 2000. 4,900 Unknown Direct GC/FID of water Tibbetts et al. 1992
(mg/L)
Total recoverable oil 6.900 210.0 39.800 Unknown Science Applications, 1994
and grease (mg/L)
2-Butanone (mg/L) ND 0.37 Unknown Unknown Wesolowski et al., 1986
Benzene (mg/L) ND 27 10.000 EPA Method 1624 and 624 Fillo et al., 1992
Benzoic acid (mg/L) ND 13.5 3.800 Unknown Science Applications, 1994
Bis (2-chlorethyl) ether ND 0.03 Unknown Unknown Wesolowski et al., 1989
(mg/L)
Ethyl benzene (mg/L) ND 19 1.800 EPA Method 1624 and 624 Wesolowski et al., 1989
Hexanoic acid (mg/L) ND 3.43 0.815 Unknown Science Applications, 1994
Methylene Chloride 1.410 1.71 0.179 Unknown Science Applications, 1994
(mg/L)
m-xylene (mg/L) 0.015 0.611 0.137 Unknown Science Applications, 1994
Naphthalene (mg/L) ND 0.556 0.119 Unknown Science Applications, 1994
N-decane (mg/L) ND 0.797 0.116 Unknown Science Applications, 1994
N-dodecane (mg/L) ND 2.89 0.245 Unknown Science Applications, 1994
N-hexadecane (mg/L) ND 1.11 0.298 Unknown Science Applications, 1994
N-octadecane (mg/L) ND 0.246 0.106 Unknown Science Applications, 1994
N-tetradecane (mg/L) ND 0.404 0.138 Unknown Science Applications, 1994
p-cresol (mg/L) ND 0.541 0.123 Unknown Science Applications, 1994
Phenol (mg/L) 0.009 23 NA Silylation GC/MS Tibbetts et al., 1992
Toluene (mg/L) ND 37 9.700 EPA Method 1624 and 624 Fillo et al., 1992
ND, below detection limit; unknown, information was not provided by reference.
Table 3. Coproduced water generation by geologic basin.
Median TDS Potential for
Geologic basin m
3
/day mg day
a
(mg/L)
b
treatment
Williston 18,000 4.9 132,400 Low
Powder River 370,000 97 7,300 Very high
Big Horn 360,000 94 4,900 Very high
Wind River 54,000 14 5,300 Very high
Green River 41,000 11 9,400 High
Denver 14,000 3.8 10,200 High
Uinta-Piceance 42,000 11 13,200 High
Paradox 21,000 5.6 67,000 Low
San Juan 14,000 3.6 22,700 Medium
Anadarko 34,000 8.9 132,200 Very low
Permian
c
250,000 65 89,200 Low
San Joaquin NA NA 22,700 Medium
Los Angeles NA NA 30,330 Medium
a
Boysan et al, 2002;
b
Breit and Otton, 2002;
c
for natural gas only
and for the New Mexico portion of the Permian Basin.
Water production
CBM COPRODUCED
WATER CHARACTERISTICS
Methodology
Public domain and peer reviewed papers were used to
gather data on the inorganic and organic constituents found
in coal bed methane coproduced water.
Inorganic constituents
There are significant differences in the concentrations of
major ions in coproduced water from CBM compared to
conventional oil and gas. CBM generally produces water
that has significantly lower TDS concentrations, ranging
from 300 mg/L to 15,000 mg/L (Van Voast, 2003).
Water associated with CBM has a common chemical char-
acter: minimal sulfate, calcium, and magnesium, and larger
quantities of sodium and bicarbonate (Van Voast, 2003).
Based on the solubility of calcium and magnesium in the
presence of bicarbonate, higher bicarbonate concentrations
cause calcium and magnesium to precipitate, thus explain-
ing their low concentrations in CBM coproduced water
where bicarbonate is the dominant anion (Van Voast, 2003).
There are five geologic basins that produce the majority of
the CBM in the Western U.S.: Powder River, Uinta,
Piceance, Raton, and San Juan. The TDS range for CBM
water generated in these basin is presented in Table 4. The
concentration ranges of the common ions found in CBM wa-
ter from the Powder River Basin are provided in Table 5.
Organic contaminants
The organic contaminants in water from CBM are derived
from coal. CBM coproduced water generally has no oil and
grease, and has relatively low dissolved organic carbon con-
centrations, usually varying from 2 mg/L to 10 mg/L
(Kharaka and Rice, 2003). Some of the dissolved organic
constituents known to be present in CBM water include
goitrogens, such as 2-methyl resorcinol, 5-methylresorcinol,
and hydroxypyridines. Polycyclic aromatic hydrocarbons,
such as aminophenols and aromatic amines, are also known
to leach into water from coals (Fisher and Santamaria, 2002).
To the best knowledge of the authors, no studies have at-
tempted yet to characterize dissolved organic constituents
from CBM water.
Quantity of coproduced water
The quantity and quality of coproduced water in each
basin was used to determine which basins are the most likely
candidates for treatment of coproduced water toward bene-
BENKO AND DREWES
244
Table 4. Total dissolved solids concentration for CBM producing basins.
Number of data
Basin Units Low High Mean points considered Reference
Powder River mg/L 370 1,940 15,840 47
a
Uinta mg/L 6,000 43,000 15,000 Unknown
b,c
Piceance mg/L 7,252 15,500 Unknown Unknown
d
San Juan mg/L 10,434 23,464 Unknown Unknown
d
Raton mg/L 1,100 4,600 1,500 Unknown
c,e
Unknown, reference did not provide information;
a
Rice, 2000;
b
Handbook, 2003;
c
Hightower,
ND;
d
Myers, 2005;
e
Raton Basin, 2003.
Table 5. Ranges of common inorganic constituents in coproduced water from CBM in the
Powder River Basin (Rice, 2000).
Number of data
Constituent Units Low High Mean points considered
Sodium mg/L 130 800 300 47
Chloride mg/L 6.3 64 13 47
Barium mg/L 0.14 1.6 0.62 47
Strontium mg/L 0.10 1.9 0.70 47
Sulfate mg/L ND 12 2.4 47
Bicarbonate mg/L 290 2,320 950 47
Calcium mg/L 5.9 57 32 47
ficial use. Basins exhibiting small TDS values and high wa-
ter volumes were considered to have the most potential for
reuse. The following values were compiled for water pro-
duction from CBM producing basins (Rice and Nuccio,
2000) (Table 6).
QUALITY ASSURANCE
It is noteworthy that information regarding the makeup of
coproduced water from both conventional and CBM explo-
ration are associated with a fair degree of uncertainty. Al-
though individual producers usually have a good under-
standing of quantity and quality of coproduced water from
their operations, frequently this information is not readily
available. Where possible, water quality parameters and wa-
ter quantity estimates provided in this study were obtained
from multiple sources. Additionally, these values were
checked and found to be consistent with select complete wa-
ter quality analyses from various coproduced water samples
collected and analyzed by the authors.
SIGNIFICANCE OF WATER QUALITY AND
QUANTITY TO TREATMENT
The analysis conducted in this study provides a starting
point for determining what types of treatment strategies are
appropriate for different types of coproduced water. Treat-
ment technologies need to be tailored to the types and con-
centrations of constituents present in the water, the type of
intended end-use, and the conditions under which the treat-
ment will occur. Findings of this study illustrate that the
TDS concentration of coproduced water might frequently be
unsuitable for the desired end use of the water, and desali-
nation technologies must be employed. Typical desalination
technologies that have been used or proposed to treat co-
produced water include reverse osmosis and nanofiltration,
electrodialysis, capacitive deionization, ion exchange,
chemical precipitation, and thermal or distillation processes,
and hybrid combinations of these technologies. Some of
these technologies may not be capable in achieving the de-
sired inorganic constituent removal efficiency or might ex-
hibit limitations due to the presence of organic contaminants.
Because many basins exhibit very similar water composi-
tions, appropriate treatment process combinations are
needed that meet the unique goals of coproduced water treat-
ment, such as a high degree of robustness, high water re-
covery, little need for maintenance and treatment chemicals,
minimal generation of treatment residuals, and ease of op-
eration.
Attention should also be given to certain constituents pres-
ent in the water that can be recovered and potentially sold
as a product. In some cases, these products, such as iodide,
can generate revenues that could cover the cost of the wa-
ter treatment (Xu and Drewes, 2006). Currently, informa-
tion is lacking regarding the concentrations of recoverable
products within the basins targeted in this study; these con-
stituents will need to be analyzed for on an individual ba-
sis.
CONCLUSIONS
Understanding the chemical composition and quantity of
water available provides an idea of which areas of the West-
ern U.S. have water most favorable for treatment, leading
to beneficial use. Nearly all of the water qualities presented
would require at least minimal organics removal and de-
salination to render it for beneficial use. Because the ma-
jority of coproduced waters exhibits a rather homogeneous
composition of major ions, such as sodium, chloride, sul-
fate, and bicarbonate, desalination technologies that are al-
ready well established in the water industry like reverse os-
mosis, nanofiltration, or electrodialysis or combinations of
these processes could assure a treated water quality that
meets nonpotable and potable standards. However, some of
the basins presented here have water with such high TDS
concentrations that treatment will most likely not be cost
effective. For these basins, treatment for beneficial use is
not practical, and other options need to be investigated for
disposal. Future research should be directed toward the de-
velopment of robust, low-maintenance, easy to operate,
package treatment technologies that can be employed at the
wellhead or well clusters of oil and gas production sites.
ACKNOWLEDGMENTS
The authors thank the U.S. Bureau of Reclamation Sci-
ence and Technology program for its financial support. The
authors also thank George Breit and Jim Otton with the
USGS, John Veil with Argonne National Laboratory, John
Ford with DOE NETL, and Geoff Thyne with University of
Wyoming for their advice.
COPRODUCED WATER OCCURRENCE AND COMPOSITION
ENVIRON ENG SCI, VOL. 25, NO. 2, 2008
245
Table 6. Coproduced water generation by geologic basin.
Median TDS Potential for
Geologic basin m
3
/day mg day
a
(mg/L) treatment
Powder River 170,000 46.1 15,840 Very high
Uinta 19,000 5.1 15,000 Medium
San Juan 12,000 3.2 10,000 High
Raton 13,000 3.6 1,500 High
a
Rice and Nuccio, 2000.
Water production
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