Science and Technology Program Report No. 157

Oil and Gas Produced Water

Management and Beneficial Use

in the Western United States

U.S. Department of the Interior

Bureau of Reclamation September 2011
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1. REPORT DATE (DD-MM-YYYY)

September 2011

2. REPORT TYPE

Final

3. DATES COVERED (From - To)

10/2006 to 9/2010

4. TITLE AND SUBTITLE

Oil and Gas Produced Water Management and Beneficial Use in the 

Western United States

5a. PROJECT NUMBER

3180

5b. GRANT NUMBER

5c. PROGRAM ELEMENT NUMBER

6. AUTHOR(S)

Katie Guerra, Katharine Dahm, Steve Dundorf

5d. PROJECT NUMBER

5e. TASK NUMBER

5f. WORK UNIT NUMBER

7. PERFORMING ORGANIZATION NAME(S) AND ADDRESS(ES)

U.S. Department of the Interior

Bureau of Reclamation 

Denver Federal Center 

PO Box 25007

 Denver CO 80225-0007

8. PERFORMING ORGANIZATION REPORT 

 NUMBER

9. SPONSORING / MONITORING AGENCY NAME(S) AND ADDRESS(ES)

U.S. Department of the Interior

Bureau of Reclamation,

Denver Federal Center

PO Box 25007, Denver CO 80225-0007

10. SPONSOR/MONITOR’S ACRONYM(S)

Reclamation

11. SPONSOR/MONITOR’S REPORT 

 NUMBER(S)

S&T Report No. 157

12. DISTRIBUTION / AVAILABILITY STATEMENT

Available from the National Technical Information Service

Operations Division, 5285 Port Royal Road, Springfield VA 22161

13. SUPPLEMENTARY NOTES

Report can be downloaded from Reclamation Web site:

www.usbr.gov/pmts/water/publications/reports.html

14. ABSTRACT (Maximum 200 words)

Produced water from oil and gas operations is currently handled as a waste product. The quality of produced water varies 

significantly based on the geochemistry of the producing formation, the type of hydrocarbon produced, and the 

characteristics of the producing well. If produced water meets appropriate water quality criteria, it may be used 

beneficially for purposes such as irrigation, livestock watering, aquifer storage, streamflow augmentation, and municipal 

and industrial uses. Treatment may be required to improve the quality of produced water so that it can be put to 

beneficial use.

15. SUBJECT TERMS

Water reuse, wastewater treatment, ultrasound, disinfection, sonochemical process

16. SECURITY CLASSIFICATION OF: 17. LIMITATION 

 OF ABSTRACT

SAR

18. NUMBER 

 OF PAGES

113

19a. NAME OF RESPONSIBLE PERSON

Katie Guerra

a. REPORT

UL

b. ABSTRACT

UL

c. THIS PAGE

UL

19b. TELEPHONE NUMBER (include area code)

303-445-2013

Standard Form 298 (Rev. 8/98)

Prescribed by ANSI Std. 239-18
U.S. Department of the Interior

Bureau of Reclamation

Technical Service Center

Water and Environmental Resources Division

Water Treatment Engineering Research Group

Denver, Colorado September 2011

Desalination and Water Purification Research 

and Development Program Report No. 157

Oil and Gas Produced Water 

Management and Beneficial Use 

in the Western United States

Prepared for Reclamation Under Agreement No. A10-1541-8053-381-01-0-1

by

Katie Guerra

Katharine Dahm

Steve Dundorf
Disclaimer

The views, analysis, recommendations, and conclusions in this report are those of 

the authors and do not represent official or unofficial policies or opinions of the 

United States Government, and the United States takes no position with regard to 

any findings, conclusions, or recommendations made. As such, mention of trade 

names or commercial products does not constitute their endorsement by the 

United States Government.

MISSION STATEMENTS

The U.S. Department of the Interior protects America’s natural 

resources and heritage, honors our cultures and tribal communities, 

and supplies the energy to power our future.

The mission of the Bureau of Reclamation is to manage, develop, and 

protect water and related resources in an environmentally and 

economically sound manner in the interest of the American public.
iii

Acronyms

acre/lb acres per pound 

AFY acre-feet per year

AOC assimilable organic carbon

AWWA American Water Works Associations

BAF biological aerated filter

bbl/MCF barrels per million cubic feet

bpd barrels per day

BAC biologically active carbon

BOD biological oxygen demand

BOE barrels of energy

BTEX benzene, toluene, ethylbenzene, and xylene 

CBM coal bed methane, also coal bed natural gas

CIP clean in place

COD chemical oxygen demand

COGCC Colorado Oil and Gas Conservation Commission 

DBP disinfection byproduct

DGF dissolved gas flotation 

ECw electrical conductivity

EOR enhanced oil recovery

DAF dissolved air flotation

DO dissolved oxygen

DOE U.S. Department of Energy

dS/m decisiemens per meter

ED electrodialysis

EDI electrodeionization 

GAC granular activated carbon

gpd gallons per day

IGF induced gas flotation 

kgal kilogallon 

kWh/day kilowatthours per day 
iv

Acronyms (continued)

m

2

/gram square meters per gram

MCF million cubic feet

meq/L milliequivalent per liter

MF microfiltration

mrem/yr millirem per year

MFL magnetic flux leakage

mg/L milligrams per liter

NOM natural organic matter 

NORM naturally occurring radioactive materials

O&M operation and maintenance

OPUS optimized pretreatment and unique separation

pCi/L picocuries per liter

ppm parts per million 

psi pounds per square inch

Reclamation Bureau of Reclamation

SAR sodium absorption ratio

S/cm siemens per centimeter

TDS total dissolved solids

THMs trihalomethanes

TN total nitrogen

TOC total organic carbon

TSS total suspended solids

UF ultrafiltration 

USEIA U.S. Energy Information Administration

USEPA U.S. Environmental Protection Agency

USGS U.S. Geological Survey

UV ultraviolet

VOC volatile organic chemicals

WAC weak acid cation

ZLD zero liquid discharge

°F degree Fahrenheit

μg/L microgram per liter
v

Acronyms (continued)

μm micrometers

> greater than

< less than

% percent

vii

Contents

Page

Acronyms....................................................................................................... iii

1. Executive Summary ................................................................................ 1

2. Background ............................................................................................. 3

2.1 Petroleum Resource Formation and Production ............................. 3

2.1.1 Conventional Oil and Gas................................................... 3

2.1.2 Unconventional Petroleum Resources................................ 3

2.2 Produced Water Generation and Production................................... 5

2.2.1 Conventional Oil and Gas................................................... 5

2.2.2 Unconventional Resources.................................................. 6

2.3 Current Produced Water Management Practices............................ 7

2.4 Environmental Impacts Caused by Produced Water ..................... 8

2.5 Study Objectives............................................................................. 9

3. Conclusions and Recommendations........................................................ 11

4. Geographical Occurrence of Produced Water......................................... 13

4.1 Conventional Oil and Gas Resources ............................................. 13

4.2 Unconventional Oil and Gas Resources ......................................... 17

4.2.1 Oil Shale.............................................................................. 17

4.2.2 Gas Shale ............................................................................ 17

4.2.3 Tight Sands Gas.................................................................. 17

4.2.4 Coalbed Methane ................................................................ 17

4.3 Geographic Distribution of Produced Water Generation................ 20

5. Beneficial Uses of Produced Water ........................................................ 23

5.1 Produced Water Use ....................................................................... 24

5.2 Produced Water Volumes Compared to Use Demands.................. 24

5.3 Beneficial Uses of Produced Water................................................ 26

5.3.2 Livestock Watering............................................................. 27

5.3.3 Irrigation ............................................................................. 29

5.3.4 Stream Flow Augmentation ................................................ 31

5.3.5 Rangeland Restoration........................................................ 33

5.3.6 Industrial Uses .................................................................... 33

5.3.10 Domestic ............................................................................. 37

6. Produced Water Quality Characterization............................................... 41

6.1 Salt Concentration and Composition .............................................. 42

6.2 Inorganic Constituents.................................................................... 49

6.2.1 Major Ions........................................................................... 49

6.2.2 Minor Ions........................................................................... 53

6.3 Organic Constituents....................................................................... 56

6.3 Organic Constituents....................................................................... 56

6.4 Naturally Occurring Radioactive Materials.................................... 58

6.5 Chemical Additives......................................................................... 60

6.6 Beneficial Use Potential.................................................................. 60
viii

Contents (continued)

Page

7. Assessment of Technologies for Treatment of Produced Water............. 69

7.1 Organic, Particulate, and Microbial Inactivation/

Removal Technologies.............................................................. 70

7.1.1 Biological Aerated Filters................................................... 70

7.1.2 Hydrocyclone...................................................................... 72

7.1.3 Flotation .............................................................................. 73

7.1.4 Adsorption........................................................................... 74

7.1.5 Media Filtration .................................................................. 75

7.1.6 Oxidation............................................................................. 75

7.1.7 Settling ................................................................................ 76

7.1.8 Air Stripping ....................................................................... 76

7.1.9 Surfactant Modified Zeolite Vapor Phase Bioreactor......... 77

7.1.10 Constructed Wetlands......................................................... 78

7.1.11 Granular Activated Carbon................................................. 78

7.1.12 Ultraviolet Disinfection ...................................................... 80

7.1.13 Microfiltration/Ultrafiltration ............................................. 81

7.2 Desalination Technologies.............................................................. 84

7.2.1 Reverse Osmosis and Nanofiltration .................................. 85

7.2.2 Electrodialysis/Electrodialysis Reversal............................. 85

7.2.3 Forward Osmosis................................................................ 86

7.2.4 Hybrid Membrane Processes .............................................. 86

7.2.5 Thermal Processes .............................................................. 87

7.2.6 Alternative Desalination Processes..................................... 88

7.3 Commercial Processes.................................................................... 89

7.3.2 CDM Produced Water Technology .................................... 89

7.3.3 Veolia OPUSTM................................................................... 91

7.3.4 Altela RainSM (Dewvaporation).......................................... 91

7.3.5 212Resources...................................................................... 91

7.4 Implications of Water Quality for Treatment Technologies........... 92

8. GIS-Based Approach to Produced Water Management.......................... 93

8.1 Produced Water GIS Database........................................................ 93

8.1.1 Base Map and Reference Data............................................ 93

8.1.2 Oil and Gas Distribution, Well and Basin Data.................. 93

8.2 Examples of GIS-Based Approach ................................................. 97

8.2.1 Denver Basin Example ....................................................... 98

8.2.2 Powder River Basin Example ............................................. 101

8.2.3 Uinta-Piceance Basin Example........................................... 102

9. References............................................................................................... 107
ix

Tables

Page

Table 1 CBM recoverable gas reserves and water quality.................. 5

Table 2 Geographic location of conventional oil and 

gas resources in the Western United States ........................... 16

Table 3 Geographic location of unconventional oil and gas 

resources in the Western United States.................................. 18

Table 4 Water use and produced water generation in the 

Western United States............................................................ 26

Table 5 Water intake volumes for livestock ....................................... 27

Table 6 National Science Foundation recommended levels 

of specific constituents for livestock drinking water............ 28

Table 7 TDS categories for livestock water........................................ 29

Table 8 Crop tolerance to boron in irrigation water............................ 31

Table 9 Constituent limits for irrigation water.................................... 32

Table 10 Acute and chronic concentration levels by hardness............. 34

Table 11 USEPA drinking water standards .......................................... 38

Table 12 Conventional basins TDS and SAR statistics........................ 51

Table 13 Common inorganic constituents in conventional 

produced water....................................................................... 52

Table 14 Ranges of inorganic constituents in produced water ............. 55

Table 15 Organic material in produced water from oil operations....... 58

Table 16 Volatile organics in produced water from 

gas operations......................................................................... 58

Table 17 Chemicals added for treatment of produced water ................ 61

Table 18 Suitability statistics for produced water for 

agricultural uses..................................................................... 64

Table 19 Constituents with the potential to be detected 

above requirements................................................................ 67

Table 20 Comparison of organic contaminant and 

particulate removal technologies for treatment 

of produced water .............................................follows page 70

Table 21 Comparison of desalination technologies for

treatment of produced water .............................follows page 84

Figures

Page

Figure 1 Typical water and gas production for CBM .......................... 6

Figure 2 Geographic location of major oil and gas producing 

wells and basins in the United States.................................... 14

Figure 3 Geographic distribution of oil wells in the Western 

United States.......................................................................... 15
x

Figures (continued)

Page

Figure 4 Geographic distribution of conventional gas wells 

in the Western United States.................................................. 15

Figure 5 Conventional and unconventional well 

distribution by State ............................................................... 21

Figure 6 Produced water quantities by State in the Western 

United States.......................................................................... 22

Figure 7 Overlay of oil and gas producing basins and areas 

with a potential for water conflict.......................................... 23

Figure 8 Fresh water usage in the Western United States.................... 25

Figure 9 Suitability of water for irrigation (adapted from 

Ayers and Westcot 1994)....................................................... 30

Figure 10 Distribution of TDS for conventional basins......................... 43

Figure 11 Distribution of TDS concentration for conventional 

oil and gas.............................................................................. 45

Figure 12 Distribution of TDS concentration for unconventional

CBM basins............................................................................ 45

Figure 13 Major cations and anions for produced water........................ 47

Figure 14 Dominant salt types of produced water ................................. 48

Figure 15 Western United States oil and gas basins: dominant 

salt type distribution............................................................... 48

Figure 16 Geochemical fingerprints of conventional and 

unconventional basins............................................................ 52

Figure 17 Western United States oil and gas basins: water 

geochemistry.......................................................................... 54

Figure 18 Radioactive oilfield equipment (USGS Fact 

Sheet 0142-99)....................................................................... 59

Figure 19 Conventional versus unconventional well 

distribution in the TDS requirement categories for 

each beneficial use ................................................................. 62

Figure 20 Western United States oil and gas basins: percentage 

of wells in various beneficial use categories.......................... 63

Figure 21 Conventional versus unconventional well 

distribution in the irrigation requirement 

categories for SAR................................................................. 65

Figure 22 Western United States oil and gas basins: percentage 

of wells in SAR irrigation categories..................................... 66

Figure 23 Dead-end versus cross flow filtration .................................... 81

Figure 24 Schematic diagram of CDM produced water 

treatment process ................................................................... 91

Figure 25 Base map with reference data and sources ............................ 94

Figure 26 Location of oil and gas producing basins and the 

top 100 producing oil and gas wells in the Western 

United States.......................................................................... 95
xi

Figures (continued)

Page

Figure 27 Geographic relationship between hydrologic units 

and petroleum basins.............................................................. 95

Figure 28 Potential water conflict and produced water generation........ 96

Figure 29 Areas of irrigated agriculture compared to 

produced water generation..................................................... 97

Figure 30 Selection of top 100 producing well in the 

Denver basin .......................................................................... 98

Figure 31 Agricultural data within the study area.................................. 99

Figure 32 Oil and gas well location data within the study area ............. 100

Figure 33 Irrigated land within the study area ....................................... 100

Figure 34 Powder River basin example area.......................................... 101

Figure 35 Location of oil and gas wells within 5-mile radius of 

top producing well in the Powder River basin....................... 102

Figure 36 Irrigated and nonirrigated agriculture within the 

study area ............................................................................... 103

Figure 37 Uinta-Piceance basin example study area.............................. 103

Figure 38 Five-mile study radius for Piceance basin example............... 104

Figure 39 Surface discharge beneficial use option for 

Uinta-Piceance study area...................................................... 104

1

1. Executive Summary

Due to increasing demand on fresh water sources, there is a need to develop new 

water supplies in the Western United States. Large volumes of water produced 

during oil and gas extraction, called produced water, are generated in drought 

prone locations that are also experiencing an increase in population. Produced 

water is a waste byproduct of the oil and gas industry; however, with appropriate 

treatment and application to beneficial use, produced water can serve as a new 

water supply in the Western United States.

The Bureau of Reclamation (Reclamation) Technical Service Center gathered 

data from publically available sources to describe the water quality characteristics 

of produced water, performed an assessment of water quality in terms of 

geographic location and water quality criteria of potential beneficial uses, 

identified appropriate treatment technologies for produced water, and described 

practical beneficial uses of produced water. 

Produced water quality varies significantly based on geographical location, type 

of hydrocarbon produced, and the geochemistry of the producing formation. In 

general, the total dissolved solids concentration can range from 100 milligrams 

per liter (mg/L) to over 400,000 mg/L. Silt and particulates, sodium, bicarbonate, 

and chloride are the most commonly occurring inorganic constituents in produced 

water. Benzene, toluene, ethylbenzene, and xylene (BTEX) compounds are the 

most commonly occurring organic contaminants in produced water. The types of 

contaminants found in produced water and their concentrations have a large 

impact on the most appropriate type of beneficial use and the degree and cost of 

treatment required.

Many different types of technologies can be used to treat produced water; 

however, the types of constituents removed by each technology and the degree of 

removal must be considered to identify potential treatment technologies for a 

given application. For some types of produced water, more than one type of 

treatment technology may be capable of meeting the contaminant removal target;

and a set of selection criteria must be applied to narrow down multiple treatment 

options.

Beneficial uses of produced water include crop irrigation, livestock watering, 

streamflow augmentation, and municipal and industrial uses. Produced water also 

can be placed in aquifer storage for future use. The type of beneficial use most 

appropriate for a produced water application depends on the geographical location 

of the produced water generation, the location of the beneficial use, and the 

constituent concentrations in the produced water.
2

Given the large volumes of produced water generated in the Western United 

States and the growing need for new water supplies, produced water has the 

potential to augment conventional water supplies. Produced water, if managed as 

a resource rather than a waste for disposal, has the potential to be used 

beneficially.
3

2. Background

Produced water is defined as the water that exists in subsurface formations and is 

brought to the surface during oil and gas production. Water is generated from 

conventional oil and gas production, as well as the production of unconventional 

sources such as coal bed methane, tight sands, and gas shale. The concentration 

of constituents and the volume of produced water differ dramatically depending 

on the type and location of the petroleum product. Produced water accounts for 

the largest waste stream volume associated with oil and gas production.

2.1 Petroleum Resource Formation and Production 

2.1.1 Conventional Oil and Gas 

Oil is formed from plant and animal material that accumulates at the bottom of a 

water supply such as an ocean, river, lake, or coral reef. Over time, this material 

is buried by accumulating sediment and is pushed deeper into the earth’s surface 

where the pressure increases from the weight of the overlying sediment and the 

temperature increases due to heat from the earth’s core. Oil and gas reservoirs are 

created when hydrocarbon pyrolysis occurs in a confined layer of porous reservoir 

material. The confined material restrains the fossil fuel in the subsurface, while 

the permeable and porous reservoir material allows for accumulation. Oil exists 

underground as small droplets trapped inside the small void spaces in rock. When 

a well is drilled into an oil reservoir, the high pressure that exists in the reservoir 

pushes oil out of the small voids and to the surface.

2.1.2 Unconventional Petroleum Resources

Oil shale, gas shale, tight sands, and coal bed methane are considered 

unconventional petroleum resources. Oil shale reservoirs are confined in 

sedimentary formations. Oil shale formations do not convert hydrocarbons into 

crude oil. Oil shale commonly is refined to produce a cleaner energy product for 

high grade fuel use. Tight sedimentary formations retain the hydrocarbons 

requiring energy and water intensive well development. Fracturing polymers in 

combination with water are injected at high pressures into the reservoir formation. 

Fracturing is necessary to produce sufficient effective aquifer conductivity to 

allow the production of economical quantities of oil and gas. The United States 

has the largest oil shale deposits. The Green River formation in Wyoming, 

Colorado, and Utah contains the largest oil shale deposit in the United States. 

Seventy percent of the commercially attractive resource in the Green River 

formation resides on land managed by the United States Federal Government.

Gas shale also is produced naturally from the shale formation. Gas is stored in 

fractures, pore space, and adsorbed to the organic reservoir material. Gas shale
4

was first developed by producing it from large fractures in the formations that 

provided sufficient gas flow for economic development. Recent advances in well 

completion technology and artificial fracturing have increased the exploration of 

this resource. Shale gas has been produced for extend periods in the United States

in the Illinois and the Appalachian basins. Due to recent advances in technology,

the Barnett Shale in Texas also has been highly economical. 

Tight sands gas are an unconventional natural gas resource produced from low 

permeability compacted sediments. Similar to gas shale, advancements in 

technology have increased the development of tight sands into an economic 

resource. Gas is tightly contained in the low permeability reservoir formation,

and wells must be stimulated to produce from the reservoir formation. Tight 

sands basins in the United States overlap certain gas shales basins, but there is no 

coincidence of tight sands in shale gas basins. Tight sands production occurs in 

the Great Plains, Rocky Mountains, the Four Corners region, onshore gulf coast,

and in Arkansas/Oklahoma. 

Coal bed methane or coal bed natural gas is an unconventional natural gas 

resource extracted from coal beds. Methane (CH4) is formed in the coal seam as a 

result of both the bacterial processes (biogenic) and the chemical reactions that 

occur with high temperature and pressure during the bituminization phase 

(thermogenic). Methane from higher ranking coals is formed by thermogenic 

production, and lower rank coals produce methane by biogenic production. 

Additionally, the volume of gas increases with coal rank, depth, and reservoir 

pressure. Coal has a large surface area per volume, so that coal seams can contain 

large volumes of gas. Coal seams are capable of containing six to seven times 

more gas than conventional gas reservoirs of comparable size (Taulis 2007).

Because of the way in which coal is formed, large amounts of coal bed methane 

exist at shallow depths. The shallow depths make drilling wells for coal bed 

methane production relatively inexpensive. At greater depths, higher pressure 

causes fractures in the coal seam to close, making the formations less permeable 

and more difficult for gas to move through the coal. Many of the coal bed 

methane basins in the Rocky Mountain region, including the Powder River and 

the San Juan basins contain subbituminous coals. Subbituminous coal is soft 

enough that conventional well bores can be used, and the well is drilled to the top 

of the target coal seam. 

The Energy Information Administration publishes estimates of the proved 

reserves of coal bed methane. The proved reserves represent estimated quantities 

of coal bed methane (CBM)1

United 

States Energy Information Administration 2007

that analysis of geological and engineering data 

demonstrate, with reasonable certainty, to be recoverable in future years from 

known reservoirs under existing economic and operating conditions (

). Actual coal bed methane 

production data, formation testing, coal core analyses, and other data are used to 

 1 Also known as coal bed natural gas.
5

determine the economic production capacity of the coal formations. It is not 

necessary that production, gathering, or transportation facilities be installed or 

operative for a reservoir to be considered proved. Table 1 contains estimates of 

total and proved reserves for the major coal bed methane producing basins in the 

Western United States. In general, as more data becomes available and 

technology advances, the estimated recoverable reserves of CBM increase. 

Between 2002–2007, the estimated total United States reserves increased by 

18 percent (%) based on historical data provided by the U.S. Energy Information 

Administration (USEIA).

Table 1. CBM recoverable gas reserves and water quality

Basin

Cumulative 

Production (BCF)1

Proved

CBM 

Reserves

(BCF)1

2008 

Average 

Water 

Production 

(million 

barrels)2

Water to 

Gas Ratio

(bbl/MCF)2

Powder River 2,314 2,418 718 2.75

Raton 625 2,486 131 1.34

San Juan 13,147 8,446 46 0.031

Uinta 758 1,995 31 0.42

Piceance 41 NA 0.30 1.2

NA – information not available 1 United States Energy Information Administration 2007; BCF = billion cubic feet. 2 National Research Council (NRC) Committee on Management and Effects of Coalbed 

Methane Development and Produced Water in the Western United States 2010; bbl/MCF = 

barrels per million cubic feet.

2.2 Produced Water Generation and Production

2.2.1 Conventional Oil and Gas

On average, about 7 to 10 barrels, or 280 to 400 gallons, of water are produced for 

every barrel of crude oil. Formation water (or connate water) exists naturally in 

the porous aquifer with the hydrocarbons. Formation water generally reflects the 

water quality associated with the depositional environment for the reservoir—

marine, brackish, or continental fresh water. Oil reservoirs commonly contain 

larger volumes of water then gas reservoirs. This is due to the higher 

compressibility and sorption capacity of gas. Gas is stored and produced from 

less porous reservoirs that contain source rock with a lower water capacity. 

Produced water generation commonly increases over time in conventional 

reservoirs as the oil and gas is depleted during hydrocarbon production.
6

2.2.2 Unconventional Resources

Produced water from most unconventional resources is minimal due to tighter 

reservoir formations, such as in tight sands, oil shale, and gas shale reservoirs. 

Producers commonly import water to these operations for onsite use in drilling, 

fracturing, and production. Fresh water used in drilling applications and reservoir 

fracturing is contaminated by the saline terrestrial water associated with the 

reservoir depositional environment. Fresh water brought onsite for use in 

operations, such as flow back or frac water returning from fracturing applications, 

also is managed as a waste stream. This waste stream commonly is associated 

with the initial phase of well development and production. In most 

unconventional oil and gas operations, frac water is considered the largest waste 

stream of production.

Alternatively, coal bed methane produces the largest volumes of water during gas 

production as compared to other unconventional hydrocarbon production. The 

water in coal beds contributes to the pressure in the reservoir that keeps methane 

gas adsorbed to the surface of the coal. The water must be removed by pumping 

to lower the pressure in the reservoir and stimulate desorption of methane from 

the coal. Generally, as the gas production increases, the water production 

decreases; therefore, the volume of CBM-produced water generated decreases 

over time. Figure 1 shows the typical water and gas production profile for 

CBM producing gas wells. 

Figure 1. Typical water and gas production for CBM.
7

Coal beds contain fractures and pores that can transmit large volumes of water. In 

some areas, coal beds may function as local or regional aquifers and are important 

sources for ground water (Rice and Nuccio 2000). The volume of water varies 

significantly from basin to basin. These variations can occur for many different 

reasons depending on the part the CBM development cycle plays, the rank of the 

coal, the depth of the coal, and the hydrologic connectivity to other water bearing 

aquifers. Generally, deeper coal seams will contain less water, but the salinity of 

the water will be higher. Water to gas ratios are used to describe the volume of 

water produced per million cubic feet of natural gas. Water to gas ratios are used,

along with the estimated recoverable reserves of natural gas, to predict the volume 

of water that will be generated in each producing basin. 

2.3 Current Produced Water Management Practices

Water is considered a byproduct of oil and gas production and generally is treated 

by the oil and gas industry as a waste for disposal. Produced water management

practices are driven by the cost of the hydrocarbon resource. Produced water is 

the largest volume waste stream associated with oil and gas production. Because 

produced water is viewed as a waste byproduct to the oil and gas industry, 

historically, the most commonly practiced management strategies are aimed at 

disposal rather than beneficial use. The most common practices for produced 

water disposal include land application or discharge, subsurface injection, and 

offsite trucking. 

• Land application or discharge is a relatively inexpensive method of 

disposal for produced water. However, this is only an option for relatively 

high quality produced waters. If the water is of poor quality, 

contamination of the surrounding soil, water, and vegetation can occur. 

Regulatory guidelines also must permit land applications.

• Subsurface injection is the industry preferred alternative to produced water 

disposal. In some cases, re-injection of produce waters is not feasible 

because the subsurface formation does not have the capacity to receive the 

water. 

• In the event that land application or re-injection is not feasible, the water 

may be trucked to offsite, re-injection facilities. Re-injection facilities 

commonly are located around a feasible accepting geologic formation for 

injection. These facilities sometimes include minor treatment applications 

aimed at lowering the scaling potential of the reinjection water or modify 

the chemistry of the water to aid in disposal. 

Typically, producers have limited water treatment experience and are hesitant to 

employ produced water treatment technologies given their negative past 

experiences. From an oil and gas producer’s perspective, the primary concern of 

beneficial use of produced water as a management strategy is liability; therefore, 
8

re-injecting the water into the subsurface formation is the preferred disposal/

management method. However, in some areas, disposal is not possible because 

the geology of the subsurface formation cannot accommodate the water, or reinjection may cause contamination of other subsurface water supplies. Offsite 

trucking is another water management strategy preferred by producers from a 

liability standpoint; however, it is very costly. 

2.4 Environmental Impacts Caused by 

Produced Water

Environmental impacts caused by the disposal of produced water have been 

reported since the mid-1800s when the first oil and gas wells were drilled and 

operated. The most commonly reported environmental concerns are as follows: 

degradation of soils, ground water, surface water, and ecosystems they support 

(Otton 2006). Because many produced waters contain elevated levels of 

dissolved ions (salts), hydrocarbons, and trace elements, untreated produced water 

discharges may be harmful to the surrounding environment. 

Large water volumes also can cause environmental impacts through erosion, large 

land area disposal basins, and pipeline and road infrastructure. Water hauling 

spills and unplanned discharges are all risks when managing produced water. The 

volume of the receiving body is critical in determining environmental impacts as 

ocean discharge offers substantive dilution, while small streams offer low dilution 

capacity. Physical water properties of concern include temperature, 

effervescence, low dissolved oxygen concentrations, as well as high and low pH 

depending on the well type.

Sodium is the most commonly occurring dominant cation in produced water. 

High sodium levels compete with calcium, magnesium, and potassium for uptake 

by plant roots; therefore, excess sodium can prompt deficiencies of other cations. 

Elevated levels of sodium also can cause poor soil structure and inhibit water 

infiltration in soils (Davis, Waskom et al. 2007). Infiltration into shallow ground

water sources is also a concern when water is applied for irrigation use. Mineral 

accumulation due to subsurface ion exchange can change the water quality of 

shallow, underlying aquifers.

Trace elements, including boron, lithium, bromine, fluorine, and radium, also 

occur in elevated concentrations in some produced waters. Many trace elements 

are phytotoxic and are adsorbed in the soil. These elements may even remain in 

soils after the saline water has been flushed away. Radium-bearing scale and 

sludge found in oilfield equipment and discarded on soils pose additional hazards 

to human health and ecosystems. Meteoric water applied to contaminated soils 

has the potential to solubilize metals and transport them through the subsurface. 

Precipitation of metals and metal solubility are important considerations in 

applying these constituents to soils.
9

2.5 Study Objectives

The objectives of this project are as follows: 

(1) Describe the characteristics of produced water: constituent concentration 

and volumes produced.

(2) Identify potential beneficial uses of produced water and the geographical 

relationship between produced water generation and potential beneficial 

uses. Three case studies are presented.

(3) Identify constituents in produced water that exceed water quality 

requirements of beneficial uses and constituents that will be problematic 

for treatment of produced water

(4) Evaluate produced water treatment technologies (organic/particulate 

removal technologies, desalination, brine management technologies, and 

post-treatment or stabilization technologies) and describe benefits and 

limitations of each technology based on produced water specific design 

requirements.

11

3. Conclusions and Recommendations

Produced water is generated in large volumes across the Western United States

from both conventional and unconventional petroleum production with the 

majority of the water produced in Texas, Oklahoma, Kansas, California, and the 

Rocky Mountain region including Montana, Wyoming, Utah, Colorado, and New 

Mexico. Given the large volume of water generated during operations, produced 

water could be considered an alternative water resource in locations experiencing 

water shortage. 

Produced water could be used to augment conventional water supplies for use in 

irrigation and livestock watering, streamflow augmentation, and industrial 

applications. Water quality issues may need to be addressed for produced water 

to be used for these beneficial uses. For agricultural purposes, most produced 

water sources contain elevated levels of sodium and high conductivity that require 

treatment to eliminate the possibility of damage to crops and livestock. In some 

states, produced water volumes are large enough to make a significant 

contribution to the water demand for irrigation and livestock. 

Numerous treatment technologies have been suggested for produced water. This 

document provides a qualitative comparison of the different technologies and 

provides guidance on the benefits and limitations of each technology. Water 

quality constraints and site-specific design criteria should be used to select the 

most appropriate treatment technology for a given produced water source and 

desired beneficial use.

Three case studies were presented, which illustrate the large potential for 

beneficial use in the Western United States for different types of applications: 

agriculture, stream low augmentation, and industrial use. Appropriate 

management techniques will allow produced water to be used as a resource rather 

than treated as a waste to meet the growing water demand in the Western United 

States.

This work, along with research conducted by others (through the Department of 

Energy, National Energy Technology Laboratory, and the Research Partnership to 

Secure Energy for America), has thoroughly evaluated produced water 

occurrence, quality, quantity, beneficial uses of produced water, and produced 

water treatment technologies. Future work should focus on simultaneously 

considering all of this information to develop site-specific produced water 

management strategies that are both environmentally and economically efficient.

13

4. Geographical Occurrence of 

Produced Water

4.1 Conventional Oil and Gas Resources

Conventional oil and gas resources are explored across the United States. In 

2008, the U.S. Energy Information Administration estimated that 363,107 oil 

wells and 460,261 gas wells were producing in the United States. Of the wells in 

operation, 78% of the oil wells and 65% of the gas wells produced 10 barrels of 

energy (BOE) per day or less. Conventional resources are not commonly 

produced by a few wells with excellent production numbers. Instead, since a 

majority of wells produce less energy per day, production is compensated by 

drilling dense well populations to increase production in a field. The large 

quantity of wells also contributes to a large volume of produced water generated. 

The geographic location of oil and gas wells within the United States is shown in 

the context of the major producing basins and the top producing oil and gas wells;

see figure 2.

Conventional oil and gas wells in the Western United States represented 86% of 

the total oil and 72% of the total gas wells nationwide in 2008. States in the 

Western United States containing more than 25,000 oil wells include California, 

Kansas, Oklahoma, and Texas, while States containing more than 25,000 gas 

wells include Colorado, Kansas, New Mexico, Oklahoma, Texas and Wyoming. 

Conventional oil and gas wells in the Western States are presented in figures 3 

and 4. As mentioned previously, oil reservoirs commonly contain larger volumes 

of water then gas reservoirs. For conventional wells, States with the largest 

volumes of produced water quantities should include California, Kansas, 

Oklahoma, and Texas.

Conventional well fields across this Western United States are tabulated in 

table 2. The 22 basins recognized are included based on the number of wells 

associated with each basin. This table is not comprehensive to all oil and gas 

basins, which exist in this region. Idaho, Nevada, Oregon, and Washington are 

not included in the State distribution in table 2, due to the absence or small 

number of oil and gas wells in these locations. The USEIA does report that 

20 gas wells exist in the State of Oregon and 73 oil wells in the State of Nevada. 

It also should be noted that oil and gas operations also exist off shore in the Gulf 

of Mexico, off of Texas-Louisiana, and the Pacific Ocean off the coast of 

California. These wells and basins are not included in this assessment of Western 

State resources; however, information on these coastal basins and wells is 

available through the USEIA. 
14

Figure 2. Geographic location of major oil and gas producing wells and basins in the 

United States.
15

Figure 3. Geographic distribution of oil wells in the Western United States.

Figure 4. Geographic distribution of conventional gas wells in the Western 

United States.

16%

2%

0%

15%

5% 1%

1% 11%

45%

1% 0%

3%

Oil Wells

Arizona California

Colorado Idaho

Kansas Montana

Nebraska Nevada

New Mexico North Dakota

Oklahoma Oregon

South Dakota Texas

Utah Washington

Wyoming

1%

11% 0%

8%

2%

12%

18%

36%

2% 0%

10%

Gas Wells

Arizona California

Colorado Idaho

Kansas Montana

Nebraska Nevada

New Mexico North Dakota

Oklahoma Oregon

South Dakota Texas

Utah Washington

Wyoming
16
17

4.2 Unconventional Oil and Gas Resources

Unconventional oil and gas resources are produced nationwide. The 

unconventional resources focused upon in this report include oil shale, gas shale, 

tight sands gas, and coalbed methane. Table 3 summarizes the locations of 5 oil 

shale, 16 gas shale, 8 tight sands gas, and 6 coalbed methane basins in the 

Western United States. Again, Idaho, Nevada, Oregon, and Washington are not 

included in the State distribution in table 3, due to the absence or small number of 

wells in these locations. General summaries of the geographic distribution of 

unconventional wells are provided by unconventional resource in the following 

text.

4.2.1 Oil Shale

Oil shale basins in the Western United States are limited to Colorado, Utah, and 

Wyoming. The large water volumes associated with oil shale production 

originate from fracture watering. Fracturing water is primarily used during well 

development. This water represents a large volume over a small period of time, 

which is often difficult to manage. 

4.2.2 Gas Shale

Basins occur in the Western United States in 10 states. Texas, New Mexico, 

Oklahoma, Montana, and Utah contain the largest number of individual basins. 

Gas shale basins commonly overlap other unconventional resources such as 

coalbed methane. Gas shale layers commonly act as aquitards and confining 

layers to coal seams. The Raton, San Juan, Uinta, and Piceance all contain both 

resources. Specific gas plays are recognized in table 3 to differentiate these 

unconventional resources.

4.2.3 Tight Sands Gas

Basins are located in eight Western States and do not extend north of Wyoming or 

west of Utah. Colorado and Texas include the greatest number of basins. 

Specific gas plays are recognized in table 3 for tight sands gas as well. Similar to 

oil shale and gas shale, water production during gas production in this resource is 

low. Water is primarily associated with well development during artificial 

reservoir fracturing.

4.2.4 Coalbed Methane

Western basins are located along the Rocky Mountain regions of the United States

in Colorado, New Mexico, Utah, Wyoming, and Montana. The coal formations 

are commonly associated with conventional oil and gas as well as unconventional 
18
19
20

resources such as gas shale. Coal formations specific to coalbed methane 

production are provided in table 3. Coalbed methane represents the largest water 

contributor over a well lifetime of all the unconventional resources. Produced 

water volumes from unconventional resources are primarily from coalbed 

methane well production. In further sections, produced water from 

unconventional resources will be limited to coalbed methane. 

4.3 Geographic Distribution of Produced Water 

Generation

Over 80% of the produced water generated nationwide is produced in the Western 

United States. Conventional and unconventional resources contribute to produced 

water volumes. Figure 5 relates conventional and unconventional well numbers 

to one another by State locations. The geographic distribution of water volumes 

should follow a similar trend the well population of each State. It is expected that 

conventional oil wells will have a larger impact than conventional gas wells on 

produced water volumes. Therefore, it is expected that California, Kansas, 

Oklahoma, and Texas will produce large amounts of produced water due to the 

number of conventional wells present in these States. 

Coalbed methane wells in Wyoming, Montana, New Mexico, and Colorado also 

contribute to the produced water volumes generated by each State. 

Figure 6 summarizes the produced water quantities by State. Wyoming is 

associated with the second highest volumes for produced water in the Western 

United States. Wyoming generates substantial quantities of water due to the large 

number of coalbed methane wells in the Powder River basin. Conventional oil 

and gas wells supplement this volume; however, the unconventional wells 

represent a significant contribution. Texas dominates total well numbers in 

conventional resources with 45% of the gas and 36% of the oil wells in the 

Western United States. Texas also dominates the produced water generation at 

44% or 236,914 thousand acre-feet per year. This is a significant water volume 

for the State. If produced water is managed as a water resource instead of a waste 

product, the volumes generated annually in each State could supplement the water

supply required.
21

Figure 5. Conventional and unconventional well distribution by State.
22

Figure 6. Produced water quantities by State in the Western United States.
23

5. Beneficial Uses of Produced Water

The Nation faces an increasing set of water resource challenges: aging 

infrastructure, rapid population growth, depletion of ground water resources, 

impaired water quality associated with particular land uses and land covers, water 

needed for human and environmental uses, and climate variability and change. 

All play a role in determining the amount of fresh water available at any given 

place and time (WaterSMART). Figure 7 shows the areas of the Western United 

States that have the potential for conflict over water. With appropriate treatment 

and management strategies, produced water has the potential to augment 

conventional water supplies.

Figure 7. Overlay of oil and gas producing basins and areas with a potential for water 

conflict.
24

5.1 Produced Water Use

Although produced water from oil and gas wells commonly is considered a high 

volume, high salinity waste stream, produced water has the potential to be used to 

offset water demands and over allocation of water supplies. Waste stream 

management is necessary to continue hydrocarbon production from oil and gas 

wells. Therefore, for use of produced water for beneficial purposes to be 

effective, the value of produced water must be assessed in each use scenario. The 

value of treating and managing produced water to be used for beneficial purposes 

will, therefore, depend on the specific situation including the water volume, water 

characteristics, and proposed use.

Produced water operators include extensive costs in the handling and management 

of produced water. Costs include bringing the water to the surface, re-injecting 

the water into the formation for disposal, and transporting the large amounts of 

water to injection wells. Often, transportation of large water volumes is so 

expensive that produced water may be treated onsite, including desalination, for 

less cost. Treatment onsite, even with the creation of a brine or concentrate waste 

stream, minimizes the total waste volume that requires injection. Furthermore, 

treatment creates a product of sufficient quality to alleviate dependences on local 

fresh water sources for many applications. Water volumes available from oil and 

gas production and potential beneficial uses of produced water are outlined in this 

chapter.

5.2 Produced Water Volumes Compared to Use 

Demands

To determine how produced water volumes compare relative to water use in the 

United States, information from two studies was used. The first study provided 

comprehensive information on produced water in a report from the 

U.S Department of Energy (DOE), entitled “A White Paper Describing Produced 

Water from Production of Crude Oil, Natural Gas, and Coal Bed Methane.” This 

publication estimated the annual onshore U.S. produced water volumes for 1985, 

1995, and 2002. The U.S. Geological Survey (USGS) also has done 

comprehensive studies on water use in the United States for 2000 and 2005. 

Combining the data provided in those studies, the following information was 

extracted for the Western United States.

Volumes of fresh water used annually in the Western States range from an 

estimated 600 thousand acre-feet per year (AFY) in South Dakota to 

43,000 thousand AFY in California. Water supply uses are presented by State in

figure 8. Water usage in the Western United States is dominated by irrigation in 

most States. State specific trends in water use include elevated water 

consumption for thermoelectric power generation in Kansas, Nebraska, and 
25

Figure 8. Fresh water usage in the Western United States.

Texas. Texas also uses significant water quantities for mining applications. 

California and Texas, meanwhile, use more water for public supply and 

consumption than Western States such as Nevada, New Mexico, North Dakota, 

Oklahoma, and South Dakota, use annually. 

Significant oil and gas production takes place in the arid regions of the Western 

United States, consequently, producing large annual quantities of produced water. 

In the Western United States, produced water volumes have the potential to 

contribute to the overall water supplies utilized by each State. Produced water 

production was estimated in 2002, to be 1,487 AFY in the Western United States. 

The largest produced water production, in Texas, is almost double the quantity 

used in the state for livestock and agriculture (table 4). Due to arid to semi arid 

climates in these regions, there is an increased value for new water sources. 

Although a potential value exists for treated water sources, in the United States,

more than 98% of produced water from onshore wells is re-injected (Clark and 

Veil 2009). A number of options are available locally as potential uses of this 

water. The following section outlines potential beneficial uses of produced water 

and includes information on water quantities and quality requirements.
26

Table 4. Water use and produced water generation in the Western United States

State

Public 

Supply Irrigation

Livestock 

and 

Agriculture

Industrial, 

Mining, 

Thermoelectric

Total 

Water Use

Produced 

Water 

Generated

Arizona 1,242 6,060 230 7,533 0.01

California 7,180 34,200 1,061 632 43,073 168

Colorado 1,085 12,800 290 14,174 17

Idaho 370 19,100 2,249 62 21,781 0

Kansas 490 4,160 130 2,628 7,409 153

Montana 188 8,920 192 9,300 14

Nebraska 424 9,860 105 3,347 13,737 7

Nevada 730 2,360 53 3,143 0.4

New Mexico 367 3,210 75 3,652 15

North Dakota 85 163 1,031 1,278 10

Oklahoma 786 804 187 196 1,972 163

Oregon 720 6,810 236 7,765 0

South Dakota 116 418 47.1 12 592 0.4

Texas 4,887 9,680 346 12,880 27,793 654

Utah 733 4,330 130 147 5,340 11

Washington 1,280 3,400 1,229 5,909 0

Wyoming 126 5,050 368 5,544 276

TOTAL 20,808 131,325 4,256 23,608 179,996 1,487

Note: Water volumes are in 1,000 AFY.

5.3 Beneficial Uses of Produced Water

The following outlined beneficial uses of produced water do not represent a 

comprehensive list but are provided as examples of application scenarios for 

produced water. These examples were chosen due to the variable nature of the 

consumer, water quantity requirements, and water quality criteria. Although not 

discussed in detail within this report, ownership of produced water first must be 

assessed, and proper permitting must be acquired to execute a beneficial use of 

produced water. Information on regulatory guidelines and permitting is available 

through the DOE’s National Energy Technology Laboratory online Web site 
27

“Produced Water Management Information System” created by Argonne National 

Laboratories as a resource for technical and regulatory information for managing 

produced water, including current practices, State and Federal regulations, and 

guidelines for optimal management practices (Veil).

5.3.2 Livestock Watering

In 2000, it was estimated that livestock water use represented for livestock 

watering, feedlots, dairy operations, and other on-farm needs such as cooling of 

facilities for the animals and products, dairy sanitation and wash down of 

facilities, animal waste-disposal systems, and incidental water losses constituted 

1,760 million gallons per day of fresh water (USGS 2005). This represented less 

than 1% of the total water use in the United States in 2000; however, 50% of that 

consumption was used by California, Texas, and Oklahoma (USGS 2005). These 

states represented 53% of the produced water production in 2002 nationally

(Clark and Veil 2009).

Livestock water requirements depend on the animal and are influenced by several 

factors such as activity, feed intake and environmental temperature (Lardy, 

Stoltenow et al. 2008). Table 5 is a summary of water volumes required for 

different species. Water requirements vary throughout the year; and the gender 

and size of an animal also impacts the estimated water consumption. To 

encompass these variations, table 5 provides an estimated range of daily water 

consumption for each livestock species. For grazing species, such as cows and 

horses, water sources throughout grazing land are important in ranching regions. 

Table 5. Water intake volumes for livestock

Livestock Water Intake Units

Cattle 3.5 to 23.0 Gallons per day

Sheep 1.5 to 3.0 Gallons per day

Swine 0.5 to 5.5 Gallons per day

Horses 6.0 to 18.0 Gallons per day

While livestock can tolerate water of a lesser quality than humans, some 

important considerations must be made evaluating a potential water source. High 

levels of specific ions and salinity can harm the animals. The National Academy 

of Sciences offers upper limits for toxic substances in water (see table 6). 

Additional constituent concentrations and maximum levels that should be noted 

include sulfate and alkalinity not to exceed 2,000 mg/L and pH ranging between 

5.5–8.5 for livestock watering. 
28

Table 6. National Science Foundation

recommended levels of specific constituents 

for livestock drinking water

Constituent

Upper Limit

(mg/L)

Aluminium 5

Arsenic 0.2

Beryllium No data available.

Boron 5.0

Cadmium 0.05

Chromium 1.0

Cobalt 1.0

Copper 10.5

Fluorine 2.0

Iron No data available

Lead 0.1

Manganese No data available

Mercury 0.01

Molybdenum No data available

Nitrate + nitrite 100

Nitrite 10

Selenium 0.05

Vanadium 0.10

Zinc 24

Total dissolved solids 10,000

The total dissolved solid (TDS) cutoff concentration listed in table 6 of 

10,000 mg/L is the maximum concentration in water above which it is not 

recommended for livestock watering use. Table 7 includes additional 

information on TDS levels for livestock (Lardy, Stoltenow et al. 2008). Specific

TDS categories are outlined in table 7 because TDS requirements vary between 

species, with certain species being more susceptible to the impacts of saline 

water consumption than others. Also, table 7 notes the relative time periods 

water of certain quality may be utilized. It is important to consider not only 

the water quality but also the duration of consumption when predicting adverse 

effects.
29

Table 7. TDS categories for livestock water

TDS Category TDS Range1 Description

Level 1 < 1,000 Satisfactory

Level 2 1,000 to 2,999 Satisfactory, slight temporary illness

Level 3 3,000 to 4,999 Satisfactory for livestock, increased poultry 

mortality

Level 4 5,000 to 6,999 Reasonable for livestock, unsafe for poultry

Level 5 7,000 to 10,000 Unfit for poultry and swine, acceptable short 

term for livestock

Level 6 > 10,000 Not recommended

1 < = less than; > = greater than.

Water quality is an important consideration for livestock watering. Meeting limits 

for specific constituents is necessary to provide protection of livestock consuming 

produced water, and treatment is often necessary to meet requirements. Although 

water requirements for livestock watering are relatively low, oil and gas wells 

drilled on property leased from farmers and ranchers represent a local source of 

water available for use. The use of produced water for livestock watering is 

convenient, given large ranching areas in areas producing large volumes of 

produced water. These overlapping areas include States such as Oklahoma, 

Wyoming, Texas, and California.

5.3.3 Irrigation

In most States, irrigation represents the majority of fresh water use. In estimates 

for the Western United States in 2000, irrigation represented over 70% of total 

state water usage (USGS 2005). Water used for irrigation is less easily recovered 

than water used for public consumption. Water loss occurs through transpiration 

from plants and through evaporation, while irrigating or during transport. 

Nationally, 59% of irrigation water is supplied from surface water sources; while 

in the Western United States, 64% is supplied from surface water resources. 

Almost a quarter of the 5% discrepancy between the Western United States and 

the Nation reliance on surface water sources could be supplied by produced water 

resources discharged into streams and channels to be used downstream for uses 

such as irrigation.

Irrigation not only requires large water volumes, but also has stringent water 

quality criteria. Specifically for produced water, parameters such as the sodium 

adsorption ratio are important criteria for ensuring that the water quality is 

sufficient to not damage crops. The sodium absorption ratio (SAR) is a 

calculation of the suitability for a water source for irrigation. The equation for the 

calculation is:
30

2

[ ] [ ]]

[ ]

+2 +2

+

+

=

Ca Mg

Na SAR (1)

The concentrations of sodium (Na+

), calcium (Ca+2), and magnesium (Mg+2) are 

in milliequivalents per liter. When irrigation water has high SAR values, above 

three, then much more control of salt accumulation is needed. Water with high 

SAR can be used if enough water is applied to wash the salts down below the root 

zone of the crops. 

The SAR and electrical conductivity (ECw) of the water must be considered 

together to determine the probable affect of using the water for irrigation (Ayers 

and Westcot 1994) (see figure 9). When the source water has a higher 

conductivity, then there is a greater potential for salt damage at lower SAR levels. 

ECw normally is expressed as decisiements per meter (dS/m), which is the same 

as siemens per centimeter (S/cm). Given the saline nature of produced water with 

high sodium content the SAR and ECw are both important parameters to consider

before use.

Figure 9. Suitability of water for irrigation (adapted from Ayers and Westcot 1994).

Boron is also important to consider when identifying the healthy range for most 

plants. The Food and Agriculture Organization publication, Water Quality for 

Agriculture, outlines boron concentration considerations for various types of 

crops (Ayers and Westcot 1994). Boron concentration limits are summarized in

table 8.

0

5

10

15

20

25

30

35

40

0 1 2 3 4 5 6

Salinity (ECsin dS/m)

SAR

No Restriction on Use

Slight to 

Moderate 

Restriction

Severe Restriction
31

Table 8. Crop tolerance to boron in irrigation water

Tolerance

Level

Range of 

Boron 

Concentration Crops

Very Sensitive < 0.5 mg/L Lemon, blackberry

Sensitive 0.5–0.75 mg/L Avocado, grapefruit, orange, apricot, peach, cherry, 

plum, persimmon, fig, grape, walnut, pecan, 

cowpea, onion

Sensitive 0.75–1.0 mg/L Garlic, sweet potato, wheat barley, sunflower, 

mung bean, sesame, lupine, strawberry, jerusalem 

artichoke, kidney bean, lima bean, peanut

Sensitive 1.0–2.0 mg/L Red pepper, pea, carrot, radish, potato, cucumber

Moderately 

tolerant

2.0–4.0 mg/L Lettuce, cabbage, celery, turnip, kentucky 

bluegrass, oats, maize, artichoke, tobacco, 

mustard, sweet clover, squash, muskmelon

Tolerant 4.0–6.0 mg/L Sorghum, tomato, alfalfa, purple vetch, parsley, red 

beet, sugarbeet

Very tolerant 60–15.0 mg/L Cotton, asparagus

Specific constituent criteria for irrigation waters are outlined in table 9. The table 

outlines minor constituents that may be prohibitive to plant growth used at 

concentrations above those listed for short- and long-term applications. In 

addition to these constituents, the following constituents and parameters also are 

identified as potentially detrimental at high concentrations to crops (Texas 

Coorperative Extension 2003):

• pH normal range 6.5–8.4

• Chloride < 70 parts per million (ppm) generally safe for all plants

• Nitrate < 10 ppm nitrate nitrogen (NO3-N), 45 ppm nitrate (NO3)

5.3.4 Stream Flow Augmentation

Although previously discussed in the context of irrigation, the discharge of 

produced water into streams provides more benefits than just the use of a surface 

water body as a conduit. Streamflow augmentation is the addition of waters to 

surface bodies to supplement low flows, thereby sustaining the surface body 

ecosystem. When not provided by precipitation or runoff, surface bodies are 

primarily derived from ground water. Urbanization has lead to changes in the 

ground water gradient, which may result in streams shifting from perennial, 

biologically rich streams to ephemeral streams (Shaver, Horner et al. 2007). 

Additionally, climate variations also affect surface water flows. Produced water 

may be used to sustain stream flow levels during low flow periods.
32

Table 9. Constituent limits for irrigation water (adapted 

from Rowe and Abdel-Magid, 1995)

Constituent

Long-term Use

(mg/L)

Short-term Use

(mg/L)

Aluminum (Al) 5 20

Arsenic (As) 0.1 2

Beryllium (Be) 0.1 0.5

Boron (B) 0.75 2

Cadmium (Cd) 0.01 0.05

Chromium (Cr) 0.1 1

Cobalt (Co) 0.05 5

Copper (Cu) 0.2 5

Fluoride (F) 1 15

Iron (Fe) 5 20

Lead (Pb) 5 10

Lithium (Li) 2.5 2.5

Manganese (Mn) 0.2 10

Molybdenum (Mo) 0.01 0.05

Nickel (Ni) 0.2 2

Selenium (Se) 0.02 0.02

Vanadium (V) 0.1 1

Zinc (Zn) 2 10

The quantity of water required to augment low stream flows is specific to the 

water body of application and the natural variations in water flow. For instance, 

creation of a perennial stream from a historically ephemeral stream using 

produced water flows may create an unsustainable ecosystem, because, as wells 

are abandoned, water sources will no longer be available. Over allocated water 

resources, where water taken from a surface body exceeds the flow or water 

sources where downstream users are in need of additional flow when available,

are ideal situations for produced water augmentation. Produced water could be 

used to offset water use in surface bodies downstream from production, resulting 

in cheap transport of the water along a watershed and further dilution of the water 

through mixing with existing flow.

Important parameters to consider for this water management technique include 

impacts of elevated flows, which may include adverse affects such as erosion, 

total quantity losses due to evaporation, and impacts on the ecosystem based on 

water quality and physicochemical characteristics. Physical characteristics of the 

water that have potential to impact the ecosystem and aquatic life in a surface 

water body include temperature and dissolved oxygen (DO) levels resulting in 

high biological and chemical oxygen demand (BOD and COD). Depending on 

the species and application, water is expected to have DO levels from 3.0 to above 

7.0 mg/L prior to discharge (Shaver 2007, #88). Additionally, salinity and 
33

specific constituents also must be managed to protect the ecosystem. Table 10

outlines constituents for aquatic life requirements and includes values for both 

chronic and acute toxicity, which are commonly dictated by the water hardness 

(Colorado Department of Public Health and Environment 2010).

5.3.5 Rangeland Restoration

Rangelands consist of shrubs and grasses and covers approximately 50% of the 

land surface in the United States. The most common use for rangelands is 

livestock grazing. Overstocking and drought are two of the causes of rangeland 

degradation. Degradation of rangeland also is caused by improper use of vehicles 

and other industrial activity and changing weather patterns resulting in drought.

Produced water can be applied to rangeland to help the natural biotic community 

to reestablish vegetation and to increase the response of the native species (Fox 

and Burnett 2002) . SAR is an important criterion for using produced water for 

rangeland restoration. Similarly to irrigation water, high SAR values can further 

damage soils; therefore, treatment may be required for some produced water 

sources to be used for rangeland restoration.

5.3.6 Industrial Uses

5.3.6.1 Reuse in Oil and Gas Operations

Reuse of produced water on site at oil and gas operation includes multiple 

applications, such as well drilling, hydraulic fracturing, secondary oil recovery, 

and sustaining aquifer pressure, which require large water volumes. Use of fresh 

water supplies in these practices may be minimized by treating and recycling 

produced water resources. Well head generation makes the resource available on 

site lowering transportation and trucking costs. Therefore, the market for treating 

produced water on site to meet water quality standards for use becomes 

economical as costs are compared to the cost of trucking fresh water on site at the 

volumes required for these operations. Water treated at a produced water 

collection point in a well field represents a local source of water commonly in

closer proximity to most wells than fresh water sources. Although many onsite 

uses exist, two uses, well development through hydraulic fracturing and 

secondary recovery through enhanced oil recovery techniques, are described here 

in more detail.

Fracturing Water.—Unconventional resources commonly exist in subsurface 

formations with low permeability. Stimulation, in the form of hydraulic 

fracturing, is required to enhance permeability and allow for commercial 

production of the hydrocarbon resource. Hydraulic fracturing is the creation or 

extension of natural fractures in the formation material. Fractures increase the 

formation permeability as gas may flow unabated through these conduits to the 

wellhead. To create or extend naturally occurring fractures, pressurized hydraulic
34
35
36

fluid is pumped into the geologic formation through the well bore into the target 

formation. When the pressure exceeds the rock strength, the fluids open or 

enlarge fractures that can extend several hundred feet away from the well. 

Current fracturing processes use “Slick Water” or “Light Sand” fracturing, which 

uses larger volumes of water than historically used to complete the process 

(R.W. Harden & Associates 2007).

This hydraulic fluid is composed mainly of water and a proppant material, such as 

sand or ceramic beads, and is used to maintain openings after fracturing has 

concluded (R.W. Harden & Associates 2007, #8). Fracturing fluids can be up to 

99% water (USEPA 2010). Water used for fracturing (frac water) is usually fresh 

water containing low salt concentrations and low concentrations of sparingly 

soluble salt products such as barium and silica. Lower soluble salts are important 

considerations because precipitation of these salts in the formation would block 

fractures and lower formation permeability. Numerous chemical additives also 

are present in the hydraulic fluid mixture at low volume percentages as compared 

to the water/proppant mixture. Specific chemical additives can include friction 

reducers, biocides, and scale inhibitors.

Frac water is usually trucked onsite to the well head. Limited fresh water 

reservoirs are available onsite that provide sufficient quality and volume for 

the frac water mixture. Deep horizontal wells can require anywhere from 2–

10 million gallons of frac water to complete the well hydraulic fracturing 

(ProchemTech, 2008 #3). In the Barnett Shale in Texas, wells require 1.2 to 

3.5 million gallons of water for hydraulically fracturing, usually spanning an 

interval of about one month per gas well (R.W. Harden & Associates 2007). 

After frac water is injected, the internal pressure of the geologic formation causes 

the injected fracturing fluids to rise to the surface and recovered fracturing fluid is 

referred to as flowback water (USEPA 2010). Not all fracturing fluids injected 

during hydraulic fracturing are recovered. Estimates of the fluids recovered range 

from 15–80% of the volume injected depending on the site (USEPA 2010). 

Hydraulic fracturing can occur repeatedly throughout the well lifetime. Some 

companies reuse flowback to hydraulically fracture more than one well as a way 

of conserving water and recycling the fluids (USEPA 2010). Flowback water 

represents only a portion of the water injected into the formation, making this 

option sustainable only as long as the water quantity is sufficient for continued 

fracturing. Unlike the intermittent production of flowback water from fracturing 

operations, produced water is generated continuously as long as gas production is 

occurring. Treated produced water used to supplement water quantities for 

hydraulic fracturing lowers the use of fresh water sources for well development 

and creates a more sustainable water use cycle within the well drilling operation.

Enhanced Oil Recovery.—Enhanced oil recovery (EOR) is used to extract 

additional oil in place in a reservoir, since only 20–40% of the total amount of oil 

in place can be recovered by standard extraction methods (Petroleum Technology 

Transfer Council). A number of EOR techniques exist as secondary recovery 
37

mechanisms. Water injection into an aquifer will displace oil towards the 

production well. EOR involving the injection of water and carbon dioxide into 

depleted oil fields can extract up to 10% of the remaining oil. Meanwhile, 

chemical EOR uses a fluid injection consisting of chemicals that promote the 

hydrocarbon movement through the formation to aid in recovering more products

from a well (Petroleum Technology Transfer Council). Volumes of water used

depend on the reservoir, while water quality concerns for injection include 

lowering divalent cation and silica levels to minimize scaling. Ten barrels of 

water are produced for each barrel of crude oil during EOR, which can be treated 

and re-used for further EOR (Petroleum Technology Transfer Council). Produced 

water generated at alternative well sites during well production may be used and 

treated for EOR applications.

5.3.6.2 Dust Suppression

Produced water is often generated in arid regions that are dust-prone. Produced 

water can be used for dust suppression on unpaved lease roads in oil and gas 

fields. Typically, the spray of produced water for dust suppression is well 

controlled so that the water is not applied beyond the road boundaries or within 

buffer zones around stream crossings and near buildings (Veil). Produced water 

has also been used for dust suppression in surface coal mining operations.

5.3.6.3 Fire Protection

Produced water could potentially be used for wild-land firefighting or municipal 

fire hydrants and sprinkler systems. Often drinking water is used for fire fighting, 

however, water quality requirements for water used in fire fighting are not 

stringent, and the use of alternative water sources does not adversely affect 

drinking water supplies. 

In order to use produced water for fire protection, the water supply needs to be 

easily accessible and contain a sufficient volume. In 2002, CBM produced water 

stored in impoundments from the San Juan Basin was used effectively to fight a 

wildfire near Durango, Colorado (ALLConsulting 2003). 

5.3.6.4 Cooling Towers

Cooling towers for powerplants required large volumes of water. As water 

demands increase, alternative water sources are sought for use in cooling towers. 

In some cases, it may be possible to use produced water for a portion of the 

cooling water demand at powerplants located near produced water generation

(Veil). 

5.3.10 Domestic

In some cases, produced water is of sufficiently high quality that it could be 

considered for municipal drinking water (table 11). 
38

Table 11. USEPA drinking water standards

Inorganic 

Constituent (μg/L)

Maximum Contaminant Levels (MCLs)

California Department of 

Health Services

Environmental Protection 

Agency Limits

Regional 

Water Quality

Board Limits

Primary 

MCL Secondary MCL

USEPA 

Primary 

MCL

USEPA

Secondary 

MCL

Aluminum 1,000 200 50 to 200 200

Antimony 6 6 6

Arsenic 50 50 50

Asbestos 7 MFL 7 MFL 7 MFL

Barium 1,000 2,000 1,000

Beryllium 4 4 4

Cadmium 5 5 5

Chloride 250 mg/L 250 mg/L 10

Chromium (total) 50 100 50

Color 15 units 15 units 15 units

Copper 1,300 1,000 1,300 1,000 1,000

Corrosivity Noncorrosive Noncorrosive Noncorrosive

Cyanide 150 150 150

Fluoride 2,000 2,000 2,100

Iron 300 300 300

Lead 15 15 50

Manganese 50 50 50

Mercury, inorganic 2 2 2

Nickel 100 45

Odor 3 threshold units 3 threshold 

units

3 threshold 

units

pH 6.5 to 8.5 6.0 to 9.0

Radioactivity, 

Gross Alpha

15 pCi/L 15 pCi/L 15 pCi/L

Radioactivity, 

Gross Beta

50 pCi/L 4 mrem/yr Zero

Radium-226 + 

Radium-228

5 pCi/L 5 pCi/L 5 pCi/L

Selenium 50 50 5

Silver 100 100 50

Specific 

Conductance (EC)

900 umhos/cm

Strontium-90 8 pCi/L 8 pCi/L

Sulfate 250 mg/L 500 mg/L 250 mg/L 20 mg/L

Thallium 2 2 2
39

Table 11. USEPA drinking water standards (continued)

Inorganic 

Constituent (μg/L)

Maximum Contaminant Levels (MCLs)

California Department of 

Health Services

Environmental Protection 

Agency Limits

Regional 

Water Quality

Board Limits

Primary 

MCL Secondary MCL

USEPA 

Primary 

MCL

USEPA 

Secondary 

MCL

Total Dissolved 

Solids

500 mg/L 500 mg/L 300 mg/L

Total Hardness as 

CaCO3

225 mg/L

Total Nitrogen (TN) 5,000

10,000

Tritium 20,000 

pCi/L

20,000 pCi/L

Turbidity 5 NTU 1.0/0.5/0.1 

NTU

5 NTU

Uranium 20 pCi/L 20 pCi/L Zero 20 pCi/L

Zinc 5,000 5,000 5,000

1 MFL = million fibers per liter; μg/L = microgram per liter; pCi/L = picocuries per liter; mrem/yr = 

millirem per year; CaCO3 = calcium carbonate.

41

6. Produced Water Quality 

Characterization

Produced water is in contact with the hydrocarbon-bearing formation for centuries 

before it is produced and contains some of the chemical characteristics of the 

formation and the hydrocarbon (Veil et al. 2004). Additionally, naturally present 

water in the pore structure also reflects characteristics of the hydrocarbon 

depositional environment. Conventional and unconventional resources vary in 

depositional environment from continental fresh water deposits to brackish or 

marine water deposits. Resulting water quality of the produced formation water is 

a blend of the fresh to marine source environment origin and dissolved mineral 

species characteristic to source formation dissolution. To generalize the 

characteristics of produced water quality, information has been gathered from 

public resources on salt concentrations and composition, major and minor 

inorganic constituents, organic constituents, naturally occurring radioactive 

material, and chemical additives used during well development and well 

production.

The USGS has published an extensive online database of produced water quality 

for producing basins across the United States. This database contains major ion 

analysis and TDS concentrations for over 27,500 oil and gas wells nationwide. 

The database is limited in certain areas because it does not explicitly state which 

wells produce oil or natural gas, the age of the wells, the flow rate of water from 

the well at the time of the sampling, the sampling technique used or the analytical 

method. The database is best used to draw general conclusions about produced 

water generated by the petroleum industry as a whole. For the purpose of this 

report, data collected and analyzed from this source is considered to reflect 

conventional produced water quality. To supplement this database general water 

quality summary, studies on conventional oil and gas water quality such as 

Fakhru’l-Razi et al. (2009), Fillo and Evans (1990), Shepard et al. (1992) and 

Tibbetts et al. (1992) are used to provide general information on minor ions, 

organics, and radionuclides. 

State governing entities on oil and gas production also keep produced water 

quality records for conventional and unconventional resources. The Colorado Oil 

and Gas Conservation Commission (COGCC) keeps public records of both major 

and minor ions associated with conventional and unconventional oil and gas 

resources. Due to the extent of coal bed natural gas production in the Rocky 

Mountain region, the COGCC keeps categorized water quality information on 

CBM. Major CBM basins in Colorado include the San Juan and Raton basins of 

southern Colorado and the Piceance basin in western Colorado. Data varies in 

completeness by well log; but major ions, total dissolved solids data, and certain 

minor ions are available for 1,455 unconventional well in Colorado. This 
42

well data in combination with case studies in the Powder River and other national 

basins is used to draw general conclusions for unconventional gas produced water 

quality. 

For the purpose of this report, unconventional water quality data is categorized as 

CBM produced water. Information on CBM produced water quality is more 

easily found in the public domain than information on flowback water; however, 

an effort was made to distinguish water quality from initial production of 

flowback water during hydraulic fracturing operations in various unconventional 

resources from produced water quality information. The following sections 

describe the characteristics of both conventional and unconventional produced 

water quality. Information presented represents a general summary of water 

compositions reported in produced water quality databases and previous studies. 

A list of relevant resources, for specific wellhead database data or case studies on 

produced water, is provided at the end of this section. 

6.1 Salt Concentration and Composition

Produced water is a mixture of inorganic and organic compounds (Fakhru’l-Razi 

et al. 2009). Salinity is a general attribute of produced water. The properties of 

produced water vary depending on the geographic location of the field, the 

geological host formation, and the type of hydrocarbon product being produced 

(Veil et al. 2004). Salinity or salt concentration, described as TDS, can vary in 

conventional oil and gas well produced waters from 1,000–400,000 mg/L (United 

States Geological Survey 2002). Variations in TDS are related to geologic 

variations between basins, well location in a well field, and the resource 

produced. The USGS and COGCC databases are used to describe distinctions in 

TDS between wells producing conventional or unconventional resources.

The large range of TDS observed in the USGS database for conventional wells is 

broken down into basin entries in figure 10 (USGS 2005). Figure 10 

demonstrates the variations of TDS in Western United States basins through using

of a box and whisker plot. The top and bottom of the box represent the 75th and

25th percentiles, respectively. The midline through the box represents the 

50th percentile. The up and down bars, or whiskers, represent the minimum and 

maximum concentrations observed in the basins. The basins in figure 10 have 

been arranged to depict basin locations from north (left side of graph) to south 

(right side of graph).

The range of TDS, from minimum to maximum concentrations, in entries for the 

Western United States basins are extensive, spanning more than 150,000 mg/L in 

all basins and over 300,000 mg/L in more than half. The statistical percentiles, 

however, confine the expected span of water quality to more specific regions. For 

example, the Sweetgrass, Powder River, Big Horn, Wind River, Green River, 
43

Figure 10. Distribution of TDS for conventional basins.
44

Denver, Piceance, and San Juan are all comprised of 75th percentile TDS values 

below 50,000 mg/L; and a majority of these wells have a TDS of 35,000 ppm or 

less. Trends in TDS can be observed as the basins are located more southerly. 

Basin TDS concentrations in the southern basins—with the exception of the 

Williston basin in Montana, North Dakota, and South Dakota that also have 

higher TDS–contain a majority of entries above 50,000–100,000 mg/L. The 

formation environments as well as the formation material contribute to the overall 

salinity of the produced water in both conventional and unconventional wells. 

Increased salinity in the southern basins could be attributed to marine type 

depositional environments during the late cretaceous period. Reservoirs in these 

regions were formed in brackish to marine environments, while continental 

reservoirs such as the Powder River basin were formed in fresh water 

environments (Van Voast 2003). 

Comparing conventional wells to unconventional wells, a large distinction can be 

made in well type based on the observed range of TDS concentrations. While 

conventional wells can approach TDS concentrations of 400,000 mg/L, 

CBM wells are generally less than 50,000 mg/L (Benko and Drewes, 2008). 

Figure 11 depicts the distribution of TDS in conventional wells, and figure 12

shows the distribution in unconventional wells. The histogram charts use 

TDS bins to differentiate wells of different concentrations. The percentage of 

wells in each bin dictates the height of each bar. Note the difference in scale of 

the TDS concentrations for conventional versus unconventional well water 

qualities.

Distinct differences in the histogram shapes exist between conventional 

and unconventional wells in the distribution of TDS. Conventional wells 

consistently span the TDS range between 5,000–200,000 mg/L, but the 

percentage of wells in higher TDS ranges tends to decrease as TDS concentrations 

increase beyond 200,000 mg/L. The distribution of wells above 200,000 mg/L 

is 18%, while 53%, or the majority of wells, range from 50,000–200,000 mg/L; 

and 29% exhibit TDS concentrations below 50,000 mg/L. Conversely, 99% of 

the unconventional wells in the COGCC database exhibit TDS concentrations 

below 50,000 mg/L. Furthermore, 86% of unconventional wells exhibit a TDS of 

5,000 mg/L or less. Close to three times as many unconventional wells (86%) 

display TDS concentrations less than 5,000 mg/L as compared to conventional 

wells (29%) with TDS values less than 50,000 mg/L. Salt concentration, signified 

by TDS, represents a clear distinction in composition between waters produced 

from conventional wells versus CBM wells.

In addition to salt concentration, salt composition or makeup is equally 

important in distinguishing between produced water types. The dominant

cations observed for both conventional and unconventional produced water 

types include sodium, calcium, magnesium, and potassium. The dominant

anions are most commonly bicarbonate, chloride, and sulfate. Significant 

differences exist in the dominant ions of conventional and unconventional 
45

Figure 11. Distribution of TDS concentration for conventional oil and gas.

Figure 12. Distribution of TDS concentration for unconventional 

CBM basins.
46

produced water. Salinity in conventional resources is due mainly to dissolved 

sodium and chloride, with fewer contributions from calcium, magnesium, and 

potassium (Fakhru’l-Razi et al. 2009). Meanwhile, Rice and Nuccio (2000)

reported that TDS concentrations at CBM wellheads ranged from 370 to 

1,940 mg/L, generally a result of increased sodium and bicarbonate.

To verify the existence of significant cation and anion variations, the USGS and 

COGCC databases were used to create cation and anion makeup compositions for 

comparison of conventional and unconventional resources. These cations 

(calcium, magnesium, potassium, sodium) and anions (bicarbonate, chloride, and 

sulfate) were present for most wells in both the USGS and COGCC databases. In 

figure 13, conventional and unconventional produced water compositions are 

compared through pie charts relating the percentage concentrations of major 

cations and anions. These charts are separated for comparison purposes with 

conventional well compositions on the top and unconventional compositions on 

the bottom. The values plotted in these charts represent average cation and anion 

values for all basins in each database category. 

Sodium is the dominant cation for water produced from both conventional and 

unconventional wells. For conventional wells, sodium makes up 81% of the 

cations, but calcium also represents 14% of the cation makeup, while magnesium 

and potassium account for 5%. The unconventional wells are almost completely 

sodium dominated with calcium, magnesium, and potassium representing 5% of 

the cations. Distinict differences can be observed between the anion makeup in 

conventional and unconventional wells. Conventional wells are mainly chloride 

anions, which represent 97% of the total anions present. In unconventional wells, 

bicarbonate makes up 66% of the anions, while chloride makes up 32%. 

Dominance of chloride in conventional wells may be attributed to marine 

influence in the hydrocarbon depositional environment as aforementioned during 

the discussion of salt concentration. Bicarbonate concentrations, however, are 

likely attributes of subsurface anaerobic methanogensis or the creation of biogenic 

methane, which result in increased bicarbonate concentrations in CBM wells 

resulting in the precipitation of calcium and magnesium from solution (Van Voast 

2003). Low concentrations of sulfates also indicate that the coal reservoir has 

undergone, or is undergoing, methanogenesis (Rice, Flores et al. 2008). This 

subsurface process dictates anion dominance in the unconventional CBM water 

quality.

Although cations and anions makeups provide insight into the relative makeup of 

well water quality, the dominant salt is also an important descriptive factor. This 

descriptive factor differs from the cation and anion contributions previously 

presented. For example, although the average chloride concentrations may 

indicate chloride as 32% of the anion makeup in unconventional wells, dominant 

salt type of a well may not directly reflect these values. The dominant salt type 

represents the salt formed by the dominant anion and cation for each individual
47

Figure 13. Major cations and anions for produced water.

well. Using the databases, figure 14 was created to compare the salt makeup of 

individual conventional and unconventional wells. The salt types include sodium 

chloride and sodium bicarbonate type, while sodium sulfate, calcium sulfate, 

calcium chloride, and others are included in the category, “Other.” 

The salt type can reflect the formation environment as well as the system 

processes, such as the impacts of methanogenesis in CBM reservoirs. The 

dominant salt makeup of conventional produced water is mainly sodium chloride 

type. Sodium bicarbonate type exists for 4% of the conventional wells, but 

sodium bicarbonate type waters do not exceed the combined occurance of other 

salt types of which sodium sulfate and calcium chloride occur at 4 and 6%, 

respectively. The uncnventional CBM wells, alternatively, are made up primarily 

of sodium bicarbonate type waters at 82% and sodium chloride type waters at 

17%. The occurance of produced water from unconventional CBM wells falling 

under the “Other” category is only 1%. 

Dominant salt types also are variable based on their geographic location. 

Dominant salt type charts are included for the Western United States basins in 

figure 15. Data was obtained from the USGS database for each basin. This figure 

depicts the percentage of wells within each basin of the USGS database that were 
48

Figure 14. Dominant salt types of produced water.

Figure 15. Western United States oil and gas basins: dominant salt type distribution.
49

dominated by each type of salt. The salt types include, in clockwise order on the 

pie charts, sodium chloride, calcium sulfate, calcium chloride, sodium 

bicarbonate, sodium sulfate, calcium bicarbonate, and other as any remaining salts 

unlisted. 

Observed from figure 15, sodium chloride is the dominant salt in nearly all of the 

Western United States basins. The Big Horn and Sweetgrass Arch basins are the 

two main exceptions. The Big Horn basin has the largest makeup of sodium 

sulfate type waters; although the basin exhibits a variety of dominant salt types. 

Sodium bicarbonate is the dominant salt type in the Sweetgrass Arch, similar to 

the unconventional CBM basins. Kansas, Anadarko, and Permian basins show 

the least amount of subsequent salt types with most wells in those basins 

exhibiting sodium chloride type waters. The most common salts following 

sodium chloride across the Western United States basins include sodium 

bicarbonate and sodium sulfate. Dominant salt type is an important descriptive 

feature for produced water quality; however, other inorganic and organic 

constituents also exist at measurable concentrations in produced water. 

6.2 Inorganic Constituents

Produced water has high concentrations of dissolved constituents that build up 

during extended contact with formation material. Produced water contains some 

of the chemical characteristics of the formation waters originally associated with 

the formation environment as well as manipulations to the water by subsurface 

processes (Van Voast 2003). Produced water is in contact with the formation

environment for centuries, suggesting that mineral characteristics of the formation 

material will be reflected in the produced water quality (Veil 2004). These 

reflections can be in the form of mineral types, such as carbonate or silicate 

systems, but also can include minor heavy metals present in the subsurface 

including arsenic, lead, organic constituents, and naturally occurring radioactive 

materials (NORM). This section focuses on the inorganic characteristics of 

produced water, specifically commonly occurring, or major ions and lower 

concentration inorganic and organic constituents or minor ions. 

6.2.1 Major Ions

Based on the salt composition observations from the previous sections sodium 

is consistently present in both conventional and unconventional produced 

water types. There is potentional, due to produced water composition, that 

high ranges of SAR likely are associated with each water type. SAR represents 

the ratio of specific cations to one another, focusing on the relationship of sodium 

with calcium and magnesium. The higher the calcium and magnesium 

concentrations with respect to the sodium, the lower the value of SAR becomes. 

High TDS concentrations associated with conventional wells translate to a high 

SAR when sodium is the dominant cation in the wells. Although unconventional 
50

wells have lower overall TDS concentrations, the lack of calcium and magnesium 

in the cation makeup also suggest elevated SAR values in unconventional wells. 

To determine the impact of TDS on the SAR, SAR values were calculated for 

wells using the USGS database. These values were calculated by basin as, in 

conjunction with TDS; the SAR is also highly variable between basins. For the 

conventional basins included in figure 15, table 12 provides the median TDS and 

SAR values with the standard deviations for each basin. Large standard 

deviations in the data are a result of the variability associated with wells in each 

basin, while variations exist in TDS and SAR data for each basin may also be 

observed. 

Trends in SAR with respect to TDS are present at the higher TDS concentrations. 

At higher TDS concentrations (> 50,000 mg/L), the SAR increases with 

TDS concentration. For example the Williston basin in North Dakota has the 

highest average TDS concentration of the basins, while it also has the highest 

average SAR. This trend suggests that, at TDS above 50,000 mg/L, increases in 

TDS are caused by the sodium cation. TDS concentrations also can be 

significantly different between regions or States that are contained within the 

same basin. For example, wells in the South Dakota portion of the Williston 

basin have very low TDS concentrations compared to the North Dakota portion. 

Geographic location within the basin influences the produced water quality. This 

may be due to the presence of a recharge zone along outcrops, confined areas of 

formation water, or the transmission of fresh water into the hydrocarbon bearing 

formation (Rice and Nuccio 2000; Clearwater, Morris et al. 2002). 

Major inorganic constiuents identified in produced water include sodium, 

calcium, magnesium, potassium, chloride, bicarbonate, and sulfate. Barium and 

stronium also occur in produced water, although the concentration ranges can 

span from nondetect to elevated concentrations such as 850 mg/L for barium and 

6,250 mg/L for strontium in conventional basins. Ranges of these prevalent 

inorganic constituents in produced water are presented in table 13 for 

conventional wells.

CBM water traditionally has lower sulfate concentrations than conventional wells. 

Barium sulfate forms a sparingly soluble salt, controlled by the amount of barium 

or sulfate present in the water. Since the sulfate concentration in CBM wells 

is relatively low, the barium concentrations in the water can remain relatively 

high. The barium concentration in conventional produced water has a range 

of 0–850 mg/L (Fillo, Koraido et al. 1992). The COGCC database reports a 

barium range from 0.5–125 mg/L. This trend is consistent for other ions as well. 

For instance, maximum calcium, magnesium, potassium, and sulfate 

concentrations are one to two orders of magnitude lower in CBM wells than 

conventional wells. Due to lower TDS concentrations, unconventional wells tend 

to have lower concentrations of all major ions. 
51

Table 12. Conventional basins TDS and SAR statistics

Basin State

TDS (mg/L) SAR

Median

Standard 

Deviation Median

Standard 

Deviation

Williston

Montana 74,300 113,200 127.7 144.4

North Dakota 253,000 122,400 179.8 107.4

South Dakota 8,200 36,000 35.5 45.8

Sweetgrass Arch Montana 4,000 21,100 36.8 33.4

Powder River

Montana 7,000 5,400 70.3 42.1

Wyoming 7,400 35,300 76.8 204.1

Big Horn

Montana 3,200 8,300 16.9 45.0

Wyoming 4,900 12,900 10.5 31.3

Wind River Wyoming 5,300 14,800 52.5 55.3

Green River Wyoming 10,000 22,000 64.4 36.9

Colorado 7,500 16,800 76.5 46.3

Denver

Colorado 10,100 19,600 96.8 56.1

Nebraska 10,300 32,300 151.9 70.5

Piceance Colorado 15,000 34,900 79.0 41.2

Paradox

Colorado 137,900 102,600 95.6 41.0

Utah 55,700 87,300 62.2 98.1

Central Kansas Kansas 58,400 70,500 65.4 46.8

San Juan

Colorado 14,900 37,000 103.9 90.6

New Mexico 15,900 34,100 77.9 55.1

Anadarko

Kansas 108,300 81,300 98.0 50.6

Oklahoma 142,000 90,500 112.3 29.8

Texas 124,600 84,200 n/a1 n/a

Permian

New Mexico 63,300 83,100 81.5 98.8

Texas 99,600 73,500 93.4 64.7

1 n/a = data not available.
52

Table 13. Common inorganic constituents in conventional produced 

water

Constituent Units

Concentration Range

Low High Median Reference

TDS mg/L 100 400,000 50,000 USGS produced 

water database

Sodium mg/L 0 150,000 9,400 USGS produced 

water database

Chloride mg/L 0 250,000 29,000 USGS produced 

water database

Barium mg/L 0 850 Not 

Available

Fillo 1992

Strontium mg/L 0 6,250 Not 

Available

Fillo 1992

Sulfate mg/L 0 15,000 500 USGS produced 

water database

Bicarbonate mg/L 0 15,000 400 USGS produced 

water database

Calcium mg/L 0 74,000 1,500 USGS produced 

water database

Inorganic chemical composition information can be represented graphically in the 

form of a Stiff diagram. A Stiff diagram plots the concentrations of major cations 

and anions of a water type. The diagrams in figure 16 represent cations on the 

right and anions on the left of the center axis. The distance of each point 

representing an ion type from the center access is the ions’ equivalent 

concentration. The points are connected to outline a chemical pattern. By 

comparing the shape of the outlined figure, water types can be compared easily in 

a visual manner. Note that the scales are different on the conventional and 

unconventional diagrams and the concentrations compared are in milliequivalents

per liter (meq/L).

Figure 16. Geochemical fingerprints of conventional and 

unconventional basins.

Na

HCO3

Mg + K

SO4

Ca

Cl

2,000 1,000 0 1,000 2,000 meq/L

Conventional

Na

HCO3

Mg + K

SO4

Ca

Cl

60 40 20 0 20 40 60 meq/L

Unconventional
53

Both cation sides of the diagrams are bottom heavy where sodium is the dominant 

cation. Calcium, magnesium, and potassium have a higher contribution, or 

deviation from the center axis in convention produced water. Bicarbonate is 

relatively absent by comparison to chloride in conventional produced water. 

Bicarbonate and chloride both exist in the unconventional system, where 

bicarbonate is more often the dominant anion. This diagram can be applied to the 

Western basins to observe variations and similarities between basins. Figure 17 

shows the major Western conventional basins with the subsequent basinwide Stiff 

diagrams.

As a general theme, the geographic spatial distributions are similar across most

basins. Generally, the conventional basin diagrams are bottom heavy with their 

sodium chloride type waters and small relative influences from other ions. In 

certain basins, such as the Permian, Central Kansas, and Paradox, cations such as 

potassium, magnesium, and calcium occur at visible concentrations on the Stiff 

diagrams. These three diagrams share the same scale and, therefore, comparable 

concentrations. Sweetgrass Arch and Big Horn also contain visible 

concentrations of the alternate cations; however, the smaller scale suggests these 

concentrations may be visible on the diagram due to relatively lower 

concentrations of sodium. The same is true in these basins for the bicarbonate 

and sulfate anions.

The Williston and Anadarko basins have the highest ion concentrations, although 

both are dominated by sodium chloride type waters. The lowest ion 

concentrations are found in the Sweetgrass Arch, Big Horn, and Wind River 

basins. The overall trends for Stiff diagrams over the Western United States 

include a general increase in diagram scale, which is consistent to the increase in 

ion concentrations or TDS towards the Southern United States. Again, the 

exception to this trend is the Williston basin in Montana, North Dakota, and South 

Dakota. Although occurring at higher relative concentrations, these major ions 

are a small subset of the inorganic constituents present in produced water. The 

following section focuses on the remaining inorganic constituents, or minor ions, 

present in conventional and unconventional CBM produced waters.

6.2.2 Minor Ions

Minor ions present in produced waters include inorganic constituents such as 

metals at varying ranges of concentrations as well as nonmetals such as fluoride 

and boron. These minor ions are found at relatively lower concentrations than the 

major ions, mentioned previously, in most wells (McBeth and Reddy 2003). 

Ranges of ions may reflect wells with elevated concentrations of certain 

constituents, but overall minor ions make up less than 1% of the overall 

constituent contribution to dissolved solids. Minor ions are of interest for a 

number of reasons including their regulation in beneficial use standards, potential 

hazardous nature if concentrated during treatment, recoverable quantity for 

constituents of value, and preserving natural systems during practices such as 

water application to soils in irrigation.
54

Figure 17. Western United States oil and gas basins: water geochemistry.

Interest exists to beneficially use CBM water for various applications due to lower 

TDS. These applications include irrigation, livestock watering, and streamflow 

augmentation. Dissolved chemicals in CBM produced water can differ greatly 

from those in surface waters because of their origin within coal seam aquifers 

(Clearwater, 2002 #80);(Van Voast, 2003 #45). Therefore, it is important to 

determine the coal seam water quality, particularly that of minor ions that may 

precipitate or concentrate upon release to the surface. McBeth et al. (2003) 

collected CBM product water samples from discharge points and associated 

discharge ponds. This study focused on identifying changes in CBM produced 

water quality upon release to surface ponds. Although this report does not go into 

detail regarding downstream changes in water quality, the values analyzed by that 

study for discharge points, which included aluminium (Al), arsenic (As), boron 

(B), barium (Ba), chromium (Cr), copper (Cu),fluorine (F), iron (Fe), manganese 

(Mn), molybdenum (Mo), lead (Pb), selenium (Se), and zinc (Zn), which are also 

included in table 14 to supplement COGCC database values for minor ion 

concentrations. 

Table 14 includes a comprehensive list of inorganic constituents. Minor ion 

concentrations for conventional wells are provided from numerous studies in 

cooperation with the USGS database values. Fakhru’l-Razi et al. (2009) 

summarized oil and gas conventional water qualities separately (Fakhru'l-Razi, 

Pendashteh et al. 2009). Although those ranges have been combined for the 
55

Table 14. Ranges of inorganic constituents in produced water1

Constituent List Units Conventional Unconventional

Antimony mg/L n/a ND – 0.005 e

Aluminum mg/L < 0.50 – 410 b,d 0.005 – 1.52 f, g

Arsenic mg/L 0.004 – 151 a,b,d ND – 0.158 e

Barium mg/L ND – 1740 a,b,d 0.445 – 125 e, g

Beryllium mg/L < 0.001 – 0.004 d n/a

Bicarbonate mg/L ND – 14,750 h 4.53 – 49,031 g

Boron mg/L ND – 95 a,d 0.05 – 30.6 e

Bromide mg/L 150 – 1,149 a,b ND – 41.1 e

Cadmium mg/L < 0.005 – 1.21 a,b,d ND – 0.076 e

Calcium mg/L ND – 74,185 h ND – 5,530 e, g

Chloride mg/L 2 – 254,923 h ND – 52,364 e, g

Chromium mg/L ND – 1.1 a,d ND – 3.71 e, g

Cobalt mg/L n/a ND – 0.010 e

Copper mg/L < 0.002 – 5 b,d 0.001 – 1.448 e

Fluoride mg/L n/a 0.57 – 20 f, g

Iron mg/L ND – 1,100 a 0.001 – 258 e, g

Lead mg/L 0.002 – 10.2 b,d ND – 0.098 e

Lithium mg/L 3 – 235 b,d ND – 1.50 g

Magnesium mg/L ND – 46,656 h 1.2 – 918.9 e

Manganese mg/L < 0.004 – 175 d ND – 3.11 e, g

Mercury mg/L < 0.001 – 0.002 d ND – 0.014 e

Molybdenum mg/L n/a ND – 0.448 e

Nickel mg/L < 0.08 – 9.2 b ND – 0.082 e

Nitrogen, ammoniacal (N-NH3) mg/L 10 – 300 d n/a

Nitrate (N-N03) mg/L n/a ND – 26.1 g

Potassium mg/L 0 – 14,840 h ND – 1,100 g

Selenium mg/L n/a ND – 1.27 e

Silver mg/L < 0.001 – 7 b,d ND – 0.14 g

Sodium mg/L 1 – 149,836 h 97.3 – 32,013 e

Strontium mg/L 0.02 – 6,200 a,d ND – 47.9 g

Sulfate mg/L ND – 14,900 h ND – 2,200 e, g

Tin mg/L ND – 1.1 a n/a

Titanium mg/L < 0.01 – 0.7 d n/a

Uranium mg/L n/a ND – 2.5 g

Vanadium mg/L n/a ND – 0.290 e

Zinc mg/L 0.01 – 35 d 0.005 – 5.639 e

1 ND = nondetect; n/a = data not available; a = Fillo and Evans 1990; b = USEPA 2000; c =

Shepard, Shore et al. 1992; d = Tibbetts, Buchanan et al. 1992; e = Cheung, Sanei et al. 2009; f =

McBeth, Reddy et al. 2003; g = Colorado Oil and Gas Conservation Commission 2010; h = USGS

2002.
56

purpose of this report, the separated values can be found in table 1, natural gas 

produced water, and table 2, oilfield produced water, of that study.

In general, concentrations of minor ions are greater in conventional than 

unconventional CBM wells. Exceptions include bicarbonate as well as chromium 

and silver, although limited data is available for chromium and silver in 

conventional wells. Marine influences from the depositional environment may 

include boron, bromide, and chloride due to elevated concentrations in the source 

water. Conventional produced waters reflect marine influences containing 

elevated chloride and bromide concentrations ranging from 80–200,000 mg/L and 

150–1,149 mg/L, respectively. Minor ions generally originate from natural 

sources in the system such as prolonged contact with source rock or depositional 

environment characteristics, such as those marine water types.

In addition to naturally occurring minor inorganic compounds, organic 

compounds and NORM also exist in produced water samples. These compounds 

also are naturally occurring and are significant in meeting regulations and 

treatment for use. The minor ions addressed in the following sections are 

attributes of the reservoir system, subsurface processes, and producing 

hydrocarbons. Byproducts of drilling or additives to aid in well production or 

completion are addressed in the section following NORM. 

6.3 Organic Constituents

This section focuses on an explanation and overview of organic constituents 

present in produced water. Produced water is removed from an inherently organic 

system, where carbon sources have been converted to hydrocarbons over geologic 

time. This section will focus on organic constituents present from natural 

processes. Organic matter in produced water exists in two forms: dispersed oil 

and non-hydrocarbon organic material. Dispersed oil is small, discrete droplets 

suspended in the water. Nonhydrocarbon organic material is dissolved in the 

water (Stephenson 1992). 

6.3 Organic Constituents

This section focuses on an explanation and overview of organic constituents 

present in produced water. Produced water is removed from an inherently organic 

system, where carbon sources have been converted to hydrocarbons over geologic 

time. This section will focus on organic constituents present from natural 

processes. Organic matter in produced water exists in two forms: dispersed oil 

and non-hydrocarbon organic material. Dispersed oil is small, discrete droplets 

suspended in the water. Nonhydrocarbon organic material is dissolved in the 

water (Stephenson 1992). 
57

The amount and nature of soluble oil, or nonhydrocarbon organic materials in 

produced water is dependent on several factors: type of hydrocarbon being 

produced, volume of water production, artificial lift technique, and age of 

production. The only factor studied to any extent is the type of oil (paraffinic, 

asphaltenic, or gas condensate) (Stephenson 1992). Analysis of the organic 

content in produced water is complicated by interferences in the detection or 

measurement method. High inorganic content has been found to cause spectral 

interference and sample crystallization during the acid digestion process of metal 

analyses. Sample dilution is most often used to alleviate this problem.

Total organic carbon (TOC) ranges from nondetect concentrations to almost 

2,000 mg/L. TOC includes suspended carbon or carbon that is not dissolved. 

Suspended carbon could include oils or high carbon mass particles that can be 

removed by filtration. The chemical oxygen demand is a measure of the oxygen 

consumed per liter of solution. Due to the deep confined nature of produced 

water, reservoirs systems are anoxic, although oxidation may occur during 

pumping and transport if the water comes in contact with the atmosphere. COD is 

a reflection of this anoxic system, but it also indicates the high carbon content. 

Table 15 lists the concentration ranges of organic material commonly found in 

produced water from oil operations (Tibbetts, Buchanan et al. 1992).

Insoluble carbon commonly identified as a part of total suspended solids (TSS) or 

total oil also is provided with concentrations in table 15. The total oil content in 

water generated from conventional crude oil extraction can range from 40–

2,000 ppm depending on the water retention time in the three-phase separator (no 

chemicals or additional separation equipment used to generate these figures). 

Generally, polar water soluble organics found in produced water are distributed 

between the low and midrange of carbon content. The factor that most controlled 

the total water soluble organic content in produced water was aqueous phase pH. 

This study, conducted with water from oil operations, found that salinity had the 

least affect on the chemical character or the carbon size of water soluble organics 

in produced water.

Volatile compounds, compounds with low boiling points, include compounds 

such as nitrogen, carbon dioxide, hydrogen sulphide, and methane. These 

compounds likely are to be present at producing wells, but they also may be 

remnant as dissolved compounds in produced water. The organic components 

with the largest range of concentrations are the volatile fatty acids, which include 

acetate, propionate, and butyrate. Table 16 provides a breakdown of the volatile 

organics commonly found in produced water from natural gas extraction. These 

ranges of volatile organics were found in 75 to 80% of all gas produced water 

samples (Fillo, Koraido et al. 1992). Volatile organics concentrations were not 

reported for water from oil extraction, because the concentrations are typically 

low or not observed. Conversely, semivolatile organics are rarely found in gas 

produced water and are much more prevalent in oil produced water. Semivolatile 

organics concentrations were not reported for water from gas extraction, because 

the concentrations are typically low or not observed. 
58

Table 15. Organic material in produced water from oil operations1

Constituent Units

Concentration Range Technique

Low High Median (Method)

TOC mg/L ND 1,700 NA UV Oxidation/IR (USEPA

415.1)

COD mg/L 1,220 NA Redox Titration (USEPA

410.3)

TSS mg/L 1.2 1,000 NA Gravimetric (USEPA 160.2)

Total Oil mg/L 2 565 NA Gravimetric (USEPA 413.1)

Volatiles mg/L 0.39 35 NA GC/MS (USEPA 1624 Rev 

B and USEPA 24 & CLP)

Total Polars mg/L 9.7 600 NA Florisil column/IR

Phenols mg/L 0.009 23 NA Silylation GLC/MS

Volatile Fatty 

Acids

mg/L 2 4,900 NA Direct GLC/FID of water

1 ND = below detection limit; NA = not available.

Table 16. Volatile organics in produced water from gas operations1

Constituent Units

Concentration Range Analytical 

Low High Median Method Reference

Benzene mg/L ND 27 NA USEPA

Method 1624 

and 624

Fillo, 1992

Bis (2-chlorethyl) 

ether

mg/L ND 0.03 NA NA GRI report, 

1988

Ethylbenzene mg/L ND 19 NA USEPA

Method 1624 

and 624

GRI report, 

1988

Phenol mg/L ND 2.6 NA NA GRI report, 

1988

Toluene mg/L ND 37 NA USEPA

Method 1624 

and 624

Fillo, 1992

2-Butanone mg/L ND 0.37 NA NA GRI report, 

1988

1 ND = below detection limit; NA = not available.

Produced water from gas production tends to have higher contents of low 

molecular-weight aromatic hydrocarbons such as benzene, toluene, ethylbenzene, 

and xylene (BTEX) than water from oil production. Studies indicate that the 

produced waters discharged from gas/condensate platforms are about 10 times 
59

more toxic than produced waters discharged from oil platforms (Jacobs, Grant et 

al. 1992). The chemicals used in processing typically include dehydration 

chemicals, hydrogen sulfide removal chemicals, and chemicals to inhibit hydrates. 

Well-stimulation chemicals such as mineral acids, dense brines, and additives also 

can be found in gas produced water (Stephenson 1992). These additional 

compounds are discussed in a following section.

6.4 Naturally Occurring Radioactive Materials

Naturally occurring radioactive elements include uranium, thallium, radium, and 

radon. These elements dissolve into water at low concentrations while water is in 

contact with rock or soil. Naturally occurring radioactive materials (NORM) in 

oil and gas production are primarily in the form of radon 226 and 228. Beneficial 

use of produced water containing NORM can contaminate soil, ground water, and 

surface water. NORM also is present in scale deposits that coat pipes and storage 

tanks conveying and containing produced water. Radium accumulation in 

equipment became apparent in the United States in the 1980s when unacceptable 

levels of radioactivity were found in oilfield pipe shipments (Zielinski and Otton 

1999). In 1999, the USGS published Fact Sheet 0142-99, which focuses on the 

occurrence, regulations, and health concerns dealing with NORM in produced 

water. Figure 18 and the following information are summarized from this source. 

Color Legend: White = no data; gray to yellow = at background or marginally detectable; blue = 

less than five times the median background for all sites; pink = greater than five times the median 

background for all sites.

Figure 18. Radioactive oilfield equipment (USGS Fact Sheet 0142-99).
60

Figure 18 demonstrates the severity of radioactivity geographically by

categorizing United States basins through comparing radioactive concentrations in 

oilfield equipment to natural background concentrations. The sampling indicated 

that gamma ray radiation levels exceeded natural background radiation levels at 

42% percent of the sites. Along the gulf coast, in Texas, Illinois, and Kansas, 

radioactivity levels were found to be greater than five times the median 

background, and these elevated areas represented 10% of the study sites. 

Radon 226 and 228 were reported to range from 4.93–720 pCi/L and 22.2–

723 pCi/L in produced water outfalls in the Gulf of Mexico (Moatar, Shadizadeh 

et al. 2010). 

Pipe, casing, fittings, and tanks with prolonged contact with produced water were 

more likely to contain radioactive deposits than other parts of the plumbing 

system. Leakage or spills of produced water in the vicinity of production sites 

may affect soils. Radon (226+228) is regulated at a maximum concentration of 

5 pCi/L in drinking water sources; therefore, most sources require treatment to 

lower levels in produced water to meet this standard.

6.5 Chemical Additives

In addition to naturally occurring compounds mentioned in previous sections,

chemical additives also are present in produced water. Chemical additives used in 

chemical treatments for produced water are commonly employed for problems 

such as hydrate formation, water vapor, mineral deposits, chemical corrosion, 

bacterial corrosion, emulsions, foaming, and paraffin. Table 17 contains a brief 

description of each problem encountered, sources of the issue, treatment 

chemicals, and concentrations. The data in table 17 is not comprehensive but 

provides a general background on chemical treatment compounds that may be 

present in produced water streams (Hayward Gordon Ltd.).

6.6 Beneficial Use Potential

Given the information on water quality for produced water from oil and gas as 

well as unconventional gas wells, it is apparent the treatment is required to meet 

most beneficial use scenarios. The following sections provide information on 

applicable scenarios for beneficial use given produced water quality. The section 

compares standards mentioned previously in the report, section 5. This 

information is calculated based on database values and assimilated tables. 

Comparison to each scenario is based on untreated water quality. Specific 

technologies capable of meeting these beneficial use requirements are available in 

the following report section 8.

Generalizing the TDS requirements for five particular beneficial uses allows for 

comparing database wells to the following TDS standards: drinking water 

500 mg/L, ground water recharge 625 mg/L, surface water discharge 1,000 mg/L,
61

Table 17. Chemicals added for treatment of produced water

Problem Cause

Chemical 

Treatment

Chemical 

Concentrations

Chemical 

corrosion

Hydrogen sulfide gas, 

carbon dioxide or oxygen

Corrosion inhibitor: 

amine imidazolines, 

amines and amine 

salts, quaternary 

ammonium salts, and 

nitrogen

Active 

ingredient 

concentration 

3 –40%

Bacterial 

corrosion

Sulfate reducing bacteria 

reducing sulfate to hydrogen 

sulfide

Bactericides: 

quaternary amine salt, 

amine acetate, and 

gluteraldehyde

Concentrations 

ranging from 

10–50%

Hydrate 

formation

Natural gas hydrates formed 

in the presence of water 

usually at high pressure and 

low temperature

Hydrate inhibition: 

ethylene glycol and 

methanol

5–15 gallons 

per million 

cubic feet of 

produced gas

Water Vapor Water vapor present in 

natural gas is removed to 

meet sales specifications

Dehydration: 

Triethylene glycol 

(TEG)

n/a

Mineral 

deposits

Inorganic mineral 

compounds causing scale or 

deposits, such as calcium 

carbonate, calcium sulfate 

(gypsum), strontium sulfate, 

and barium sulfate

Scale inhibitor: 

phosphate esters, 

phosphonates, and 

acid polymers

Treatment 

concentrations 

from 3–5 ppm, 

but depend on 

the water type

Emulsion 

(normal and 

reverse)

Normal – water droplets 

dispersed in the oil phase

Reverse – oil droplets 

suspended in the 

continuous water phase

Emulsion breakers: 

oxyalklated resins, 

polyglycol esters, and 

alkl aryl sulfonates

Bulk 

concentrations 

of 30–50%

Foaming Oil froth Defoamers: silicones 

and polyglycol esters

Treatment 

concentrations 

are 5–25 ppm

irrigation 1,920 mg/L, and agriculture livestock watering 10,000 mg/L. These 

values are the least conservative concentrations allowable for each use. Utilizing 

this breakdown, figure 19 was created to depict the percentage of wells in each 

database suitable for each use. This chart is based purely on TDS concentration 

and does not take into account SAR or minor ions.

Results from comparing database TDS concentrations to use alternatives indicate 

that water quality of produced water from both conventional and unconventional 

wells is unsuitable for drinking or ground water recharge untreated. Only 4% 

of the unconventional wells meet these criteria. Meanwhile 10% of the 

unconventional wells meet the 1,000-mg/L surface criteria for discharge. In the 

Powder River basin in Wyoming, a significant amount of produced water is 

discharged into watersheds (Clearwater, Morris et al. 2002). Numerous studies
62

Figure 19. Conventional versus unconventional well distribution in the 

TDS requirement categories for each beneficial use.

are available on the Powder River that consider effects beyond salinity of surface 

discharges of produced water. Given the high maximum TDS concentration for 

livestock watering of 10,000 mg/L, 18% of conventional wells and 88% of 

unconventional wells meet this requirement. For unconventional CBM wells,

29% of that 88% also meets TDS standards. Of the two databases, 82% and 12% 

of the conventional and unconventional wells, respectively, do not meet any of the 

above listed standards. These waters may meet subsequent beneficial use 

opportunities such as dust control, hydraulic fracturing, or enhanced oil recovery, 

but requirements for these processes are not explored or compared in this report.

Potential use for these wells in the previous categories varies by location of the 

basin as well. By grouping drinking, ground water and surface water 

requirements into a single category, due to the low percentage of wells capable of 

meeting these standards, figure 20 was created. Using the same bar chart format, 

with consolidated categories, red bars represent water requiring treatment or water 

exceeding 10,000 mg/L TDS, yellow bars represent agriculture, green represents 

irrigation, and blue represents drinking, ground water or surface discharge. The 

results of the bar chart subsets are provided for the Western United States basins 

in figure 20.

Figure 20 shows that only four basins have a majority of wells with a TDS level 

unsuitable for use without treatment; Permian, Anadarko, Central Kansas, and 

Williston. Given the poor water quality in these basins, treatment is required to 

meet uses originating in this region. Recall Texas is also the largest generator of 

0% 0% 0% 1%

18%

82%

1% 3%

10%

29%

88%

12%

0%

20%

40%

60%

80%

100%

Percentage of wells meeting TDS criteria 

(%)

Conventional Unconventional
63

Figure 20. Western United States oil and gas basins: percentage of wells in 

various beneficial use categories.

produced water in the Western United States (Clark and Veil 2009). Although 

water generation of poor quality may be representative of this dataset, the amount 

of oil and gas production in the State suggests that onsite uses for production, 

enhanced well recover, and hydraulic fracturing could be accomplished through 

the treatment and use of produced water resources, thereby limiting requirements 

for fresh water resources in the State.

The Williston basin in Montana, North Dakota, and South Dakota is also of poor 

quality; however, given the relatively lower TDS concentrations in South Dakota,

a small portion of the basins water resource does meet standards for agriculture 

livestock watering. The Denver, Piceance, Paradox, and San Juan basins also 

contain a certain number of wells fit for agricultural purposes, although a majority 

of wells are unsuitable for these uses without treatment. The Powder and Green 

River basins all exceed unsuitable wells with wells meeting TDS requirements for 

agriculture. The Big Horn, Sweetgrass Arch, and Wind River basins are all 

dominated by agricultural type waters, with multiple wells meeting irrigation 

water qualities. 
64

TDS can be broken into subcategories based on specific irrigation and livestock 

requirements. Although the least conservative TDS values were used for the 

previous comparison, many less wells meet more stringent water quality 

requirements. For example, although 88% of the unconventional CBM wells 

meet the 10,000-mg/L criteria for livestock water, only 10% meet the satisfactory 

level preventing illness and mortality. Less than 1% of the conventional wells 

meet this satisfactory criterion. Although the TDS is acceptable in most wells for 

short periods of time, treating or blending water with a fresh water resource would 

be required to sustain this application. 

Table 18. Suitability statistics for produced water for agricultural uses

Irrigation TDS Categories

% of Wells in TDS Range

Conventional Unconventional

Class 1 Excellent < 160 0 % 0 %

Class 2 Good 160 – 480 0 % 1 %

Class 3 Permissible 486 – 1,280 0 % 14 %

Class 4 Doubtful 1,286 – 1,920 1 % 14 %

Class 5 Unsuitable > 1,920 99 % 71 %

Livestock Watering TDS Categories Conventional Unconventional

Level 1 Satisfactory < 1,000 0 % 10 %

Level 2 Satisfactory, slight 

temporary illness

1,000 – 2,999 4 % 37 %

Level 3 Satisfactory for 

livestock, increased 

poultry mortality

3,000 – 4,999 5 % 15 %

Level 4 Reasonable for 

livestock, unsafe for 

poultry

5,000 – 6,999 3 % 12 %

Level 5 Unfit for poultry and 

swine, acceptable 

short term for 

livestock

7,000 – 10,000 5 % 14 %

Level 6 Not recommended > 10,000 82 % 12 %

TDS concentration is not the only requirement specific for irrigation applications. 

SAR is as important as TDS when considering applications. Irrigation 

requirements for SAR can be split into four categories: low 1–9, medium 10–17, 

high 18–25, and very high > 26. Low SAR values may not be used on sodium 

sensitive crops; medium values require soil amendments such as gypsum; high 

values are generally unsuitable for continuous use; and very high values generally 

are unsuitable for use (Davis, Waskom et al. 2007). Figure 22 compares 

calculated SAR values for convention and unconventional wells to the 

aforementioned categories.
65

Figure 21. Conventional versus unconventional well distribution in the 

irrigation requirement categories for SAR.

Although 29% of CBM wells were suitable for irrigation based on TDS 

concentrations, only 10% meet the required low or medium SAR values. 

Conversely, although only 1% of the conventional wells met TDS requirements 

6% meet the low or medium SAR criteria. Since SAR is a calculation of the ratio 

between sodium, magnesium, and calcium conventional wells with higher TDS, 

but also high calcium and magnesium concentrations, increase the relative amount 

of wells meeting SAR standards.

A similar figure for SAR distribution of wells among basins was created for 

figure 22. Utilizing SAR as the qualities for irrigation demonstrates that only the 

Sweetgrass Arch, Bighorn, Wind River and Powder River basins contain wells 

meeting the low or medium categorical value. The remainder of the basins 

contains mostly unsuitable waters for irrigation purposes. The mapping of these 

criteria is helpful to determine the geographic variation of not only water quality, 

but potential uses in the area. A combined prediction of wells meeting the full 

extent of concentrations for all constituents and parameters would be beneficial to 

targeting beneficial use applications in specific basins and areas. 

Minor ions are regulated for a variety of types of beneficial uses. Table 19 

denotes minor ions potentially present at concentrations that exceed beneficial use 

standards based on recorded concentration ranges for three common beneficial 

use applications—drinking water, livestock watering, and irrigation. Drinking 

water standards consider primary and secondary national maximum contaminate 

levels in evaluation of water quality constituents. Note that not all wells will 

exceed these standards; but by using the range of concentrations spanning over
66

Figure 22. Western United States oil and gas basins: percentage of wells in 

SAR irrigation categories.

the maximum levels, there is a potential for wells to exceed standard 

requirements. Only beryllium (conventional) and antimony (unconventional) 

standards are not exceeded for drinking water within the range of recorded 

concentrations, table 19. For livestock watering, mercury is not exceeded in 

conventional wells; while aluminium, cobalt, and zinc are the only constituents 

not exceeded in unconventional wells. All other constituent levels are potentially 

exceeded for livestock watering including TDS, pH, and alkalinity as the recorded 

concentration ranges exceed standards. 

TDS concentrations and SAR values exceed most standard requirements for 

beneficial use. To use these resources, more produced waters will require 

treatment. Treatment processes, particularly those focused on removing salt from 

the system to lower TDS concentration, concentrate rejected ions into a brine 

stream. Concentration of certain minor ions, such as heavy metals, challenges the 

easy disposal of a potentially hazardous waste stream. Metals also may 

accumulate in soils. Metals at low concentrations in produced water, 

continuously applied to irrigation fields or streams, may deposit metals into the 

subsurface. These metals may concentrate in the subsurface contaminating the 

soil and also may be transported into potable shallow ground water sources at 

concentrations exceeding standards for use. Concentrations of minor ions present 
67

in solution are important considerations for both treatment design and usage 

applications. The following section outlines a variety of treatment processes 

currently applied or applicable to treating this water composition to meeting 

standards for beneficial use applications.

Table 19. Constituents with the potential to be detected above requirements1

Constituent 

List

Conventional Unconventional

Drinking 

Water

Livestock 

Watering Irrigation

Drinking 

Water

Livestock 

Watering Irrigation

Antimony n/a — — No — —

Aluminum Yes Yes — Yes No —

Arsenic Yes Yes — Yes Yes —

Barium Yes — — Yes — —

Beryllium No — — n/a — —

Boron — Yes Yes — Yes Yes

Cadmium Yes Yes — Yes Yes —

Chloride Yes — Yes Yes — Yes

Chromium Yes Yes — Yes Yes —

Cobalt — n/a — — No —

Copper Yes Yes — Yes Yes —

Fluoride n/a n/a — Yes Yes —

Iron Yes — — Yes — —

Lead Yes Yes — Yes Yes —

Manganese Yes — — Yes — —

Mercury — No — — Yes —

Nitrate (N-N03) n/a n/a n/a Yes Yes Yes

Selenium n/a n/a — Yes Yes —

Silver Yes — — Yes — —

Sodium — — Yes — — Yes

Strontium — — — — — —

Sulfate Yes Yes Yes Yes Yes Yes

Uranium — — — — — —

Vanadium — n/a — — Yes —

Zinc Yes Yes — Yes No —

1 Considered with respect to the ranges provided in table 14.

69

7. Assessment of Technologies for 

Treatment of Produced Water

Because produced water may contain many different types of contaminants and 

the concentration of contaminants varies significantly, numerous types of 

treatment technologies have been proposed to treat produced water. Most often,

an effective produced water treatment system will consist of many different types 

of individual unit processes used in series to remove a wide suite of contaminants 

that may not be removed with a single process. Organic and particulate removal, 

desalination, and disinfection are the major classifications of produced water 

treatment technologies. 

A qualitative comparison of produced water treatment technologies is presented to 

provide an assessment of the benefits and limitations of each technology for 

produced water applications. The criteria used to compare the technologies are 

robustness, reliability, mobility, flexibility, modularity, cost, chemical and energy 

demand, and brine or residual disposal requirements. 

• Robustness refers the ability of the equipment to withstand harsh 

environmental conditions, have high mechanical strength, and represents a 

technology in which the failure of an individual component does not

significantly affect the overall performance of the technology. 

• Reliability means that the technology will require minimal down time, can 

produce consistent water quality, and is not prone to failure. 

• Mobility measures the ease with which the equipment can be moved from 

one site to another.

• Flexibility is the measure of the capability of the technology to 

accommodate a wide range of feed water qualities and to handle an upset 

in water quality without failure or reduced product water quality. 

• Modularity refers to the ability to implement the technology as a unit 

process in a train of treatment technologies and the ability of ease with 

which the system can be modified to handle changing water volumes. 

Based on industry research and communication with industry contacts, these 

criteria were deemed most important for produced water applications. 
70

7.1 Organic, Particulate, and Microbial 

Inactivation/Removal Technologies

Organic chemical and particulate removal is most often required as a pretreatment 

step when desalination technologies must be employed to treat produced water. 

The technologies considered in this assessment are as follows: biological aerated 

filter, hydrocyclone, dissolved air flotation, adsorption, media filtration, 

oxidation, settling ponds, air stripping, surfactant modified zeolites, constructed 

wetlands, granular activated carbon, ultraviolet (UV) disinfection, and ceramic 

and polymeric micro- and ultrafiltration. 

The technologies were evaluated based on the whether they are an emerging 

technology or an established technology and whether they have previously 

employed for treatment of produced water. The size and type contaminants 

removed by the technology and the overall process recovery are presented. The 

technologies were then compared qualitatively based on the following criteria: 

chemical and energy requirements, maintenance requirements, ease of operation, 

cost, robustness, reliability, flexibility, mobility, modularity, volume of residuals 

generated, and the size of the plant or footprint.

The qualitative technology assessment and comparison is presented in tabular 

format; see table 20. A very brief summary of the current status of the 

technologies listed in the table is provided below; however, for more detailed 

information on each technology, please refer to other sources. 

7.1.1 Biological Aerated Filters

The term biological aerated filter (BAF) refers to a class of technologies, 

including fixed film and attached growth processes, roughing filters, intermittent 

filters, packed bed media filters, and conventional trickling filters. A BAF

consists of permeable media, such as rocks, gravel, or plastic media. The water to 

be treated flows downward over the media and, over time, generates a microbial 

film on the surface of the media. The media facilitates biochemical 

oxidation/removal of organic constituents. This is an aerobic process, and aerobic 

conditions are maintained by pumps and fans in the system. The thickness of the 

microbial layer continues to increase as the filter is used. Eventually, the 

microbial layer becomes thick enough that part of the slime layer becomes 

anaerobic and the microbial layer begins to slough off in the filter effluent

(USEPA 1991). Media should have high a surface area per unit volume, be 

durable, and inexpensive. The type of media often is determined based on what 

materials are available at the site. Media can be field stone or gravel, and each 

stone should be between 1–four inches in diameter to generate a pore space that 

does not prohibit flow through the filter and will not clog when sloughing occurs 

(EPA 1980).

BAF can remove oil, suspended solids, ammonia, and nitrogen, chemical oxygen 

demand, biological oxygen demand, iron, manganese, heavy metals, soluble 

71

organics, trace organics, and hydrogen sulfide. Iron and manganese removal in 

BAFs is mainly due to chemical oxidation rather than a biological process. Since 

BAFs do not remove dissolved constituents, however, high concentrations of salts 

can decrease the effectiveness of this technology due to salt toxicity effects. At 

chloride levels below 6,600 mg/L, there is no diminished contaminant removal 

with BAFs; and at 20,000 mg/L chloride levels, there will be a reduction in slime 

growth and BOD removal (Ludzack and Noran 1965). This technology can be 

used to treat water with much greater organic contaminant concentrations than 

typically found in CBM produced water. 

BAF is a well established technology and has been used for produced water 

treatment for many years (Doran 1997; Su, Wang et al. 2007). Because of this 

technology’s ability to remove oil and grease, it has been primarily used for 

oilfield produced water treatment (Su, Wang et al. 2007). Informal versions of 

BAFs require minimal equipment and can be made by flowing water over rock 

beds. These types of BAFs also have been used in CBM produced water 

treatment for iron removal and suspended solids removal.

BAF is most effective on waters with chloride levels below 6,600 mg/L (Ludzack 

and Noran 1965), oil concentrations less than 60 mg/L; COD less than 400 mg/L,

and BOD less than 50 mg/L. The maximum feed water constituent concentration 

for which this technology can be employed depends on desired removal and target 

water quality requirements. Removal capability of BAFs is dependent on the 

hydraulic loading rate on the filter and the raw water quality. The following are 

approximate removal capabilities of this technology:

• 60 to 90% nitrification

• 50 to 70% total nitrogen (USEPA 1991; Ball 1994)

• 70 to 80% oil (Su, Wang et al. 2007)

• 30 to 60% COD (Su, Wang et al. 2007)

• 85 to 95% BOD (Su, Wang et al. 2007)

• 75 to 85% suspended solids (Su, Wang et al. 2007)

There is nearly 100% water recovery from this process. The residuals 

generated are from the settling of the microbial layer that sloughs off the media. 

The residuals generation, which is highly dependent on the water quality, is 

approximately 0.4–0.7 pounds of dry solids per 1,000 gallons of water treated (for 

wastewater treatment) (Ball 1994). Solids disposal is required for the sludge that 

accumulates in the sedimentation basins, and solids disposal can account for up to 

40% of total cost of technology.

This technology has a long expected lifespan. BAFs require upstream and 

downstream sedimentation; therefore, they have a large footprint and are not very 

mobile or modular. Very little monitoring is required, and occasional emptying of 

sedimentation ponds is required; the use of this technology does not require 
72

skilled operators. BAF can easily accommodate highly varying water quantity 

and quality. There is little down time or need for maintenance. Electricity is 

required for pumps and for fans for aeration and circulating water. The majority 

of the overall cost of this technology is capital, and operation and maintenance

(O&M) costs are very low.

Primary sedimentation should be employed upstream of BAFs to allow the full 

bed of the filter to be used for removing nonsettling, colloidal, and dissolved 

particles if the water requires a large degree of contaminant removal. 

Sedimentation also should follow BAFs to remove the microbial layer that 

sloughs off of the filter. In addition to pumps and fans for aeration, other 

equipment such as distribution nozzles may be required. The estimated energy 

demand for BAFs is 1–4 kilowatt-hours per day (kWh/day). No chemicals are 

necessary for this treatment process (USEPA 1980). 

7.1.2 Hydrocyclone

Hydrocyclones are used to separate solids from liquids based on the density of the 

materials to be separated. Hydrocyclones normally have a cylindrical section at 

the top where the liquid is fed tangentially and a conical base. The angle of the 

conical section determines the performance and separating capability of the 

hydrocyclone. Hydrocyclones can be made from metal, plastic, or ceramic and 

have no moving parts. The hydrocyclone has two exits—one at the bottom, called 

the underflow or reject for the more dense fraction and one, called the overflow or 

product at the top for the less dense fraction of the original stream (K. Wagner 

1986).

Hydrocyclones can be used to separate liquids and solids or liquids of different 

densities. Hydrocyclones can be used to remove particulates and oil from 

produced water. Depending on the model of hydrocyclone employed, they can 

remove particles in the range of 5–15 micrometers (μm) (NETL). Hydrocyclones 

will not remove soluble oil and grease components (T. Hayes 2004). 

Hydrocyclones have been used extensively to treat produced water and are 

marketed by numerous companies for produced water treatment (Veil ; Sinker 

2007). Hydrocyclones were used to treat fracturing brine in the Barnett Shale 

play (Burnett 2005). In this research study, hydrocyclones were used in 

combination with organo-clays as a pretreatment to reverse osmosis. 

Hydrocyclones can be used to treat water with high solids and organic chemical 

concentrations and can reduce oil and grease concentrations to 10 ppm. High 

product water recovery is possible with this technology. The waste generated 

from a hydrocyclone is a slurry of concentrated solids. This is the only residual 

that requires disposal.

Hydrocyclones do not require any pre- or post-treatment. The hydrocyclone itself 

does not require any chemicals or energy; however, a forwarding pump may be
73

necessary to deliver water to the hydrocyclone or to recover pressure lost through 

the hydrocyclone. The hydrocyclone is the only piece of equipment necessary. 

There are no energy requirements unless the plant setup requires a forwarding 

pump to deliver water to the hydrocyclone. Depending on the size and 

configuration of the hydrocyclone, a large pressure drop can occur across the 

hydrocyclone.

Hydrocyclones have a long operational life due to the fact that they have no 

moving parts; however, they may suffer from abrasion when treating water with 

high particulate concentrations. Solid material can block the inlet, and scale 

formation can occur requiring cleaning; however, typical cleaning is minimal.

7.1.3 Flotation

Flotation is a process in which fine gas bubbles are used to separate small, 

suspended particles that are difficult to separate by settling or sedimentation. Gas 

is injected into the water to be treated, and particulates and oil droplets suspended 

in the water are attached to the air bubbles, and they both rise to the surface. As a 

result, foam develops on the surface, which is commonly removed by skimming. 

The dissolved gas can be air, nitrogen, or another type of inert gas. Dissolved 

air/gas flotation also can be used to remove volatile organics and oil and grease. 

Dissolved air flotation units have been widely used for treatment of produced 

water (Casaday 1993; Hayes 2004; Çakmakce, Kayaalp et al. 2008). 

Gas flotation technology is subdivided into dissolved gas flotation (DGF) and 

induced gas flotation (IGF). The two technologies differ by the method used to 

generate gas bubbles and the resultant bubble sizes. In DGF units, gas (usually 

air) is fed into the flotation chamber, which is filled with a fully saturated 

solution. Inside the chamber, the gas is released by applying a vacuum or by 

creating a rapid pressure drop. IGF technology uses mechanical shear or 

propellers to create bubbles that are introduced into the bottom of the flotation 

chamber (Veil). Coagulation can be used as a pretreatment to flotation.

The efficiency of the flotation process depends on the density differences of liquid 

and contaminants to be removed. It also depends on the oil droplet size and 

temperature. Minimizing gas bubble size and achieving an even gas bubble 

distribution are critical to removal efficiency (Casaday 1993). Flotation works 

well in cold temperatures and can be used for waters with both high and low 

TOC concentrations. It is excellent for removing natural organic matter (NOM) 

and can be used to treat water containing TOC, oil and grease, and particulates < 

7% solids (Burke). 

It is not ideal for high temperature feed streams. 

Dissolved air flotation (DAF) can remove particles as small as 25μm. If 

coagulation is added as pretreatment, DAF can remove contaminants 3–5 μm in 

size (NETL). In one reported study, flotation achieved an oil removal of 93% 
74

(ALL 2003). Flotation cannot remove soluble oil constituents from water. 

Product water is nearly 100% with this technology.

Because flotation involves dissolving a gas into the water stream, flotation works 

best at low temperatures. If high temperatures are present, a higher pressure is 

required to dissolve the gas in the water. 

Energy is required to pressurize the system to dissolve gas in the feed stream. 

Coagulant chemical may be added to enhance removal of target contaminants. 

Chemical coagulant and pumping costs are the major components of O&M costs 

for flotation. Treatment costs are estimated to be $0.60 per cubic meter

(Çakmakce, Kayaalp et al. 2008). Solids disposal will be required for the sludge 

generated from flotation.

7.1.4 Adsorption

Adsorption can be accomplished using a variety of materials, including zeolites, 

organoclays, activated alumina, and activated carbon. Chemicals are not required 

for normal operation of adsorptive processes. Chemicals may be used to 

regenerate media when all active sites are occupied. Periodically, the media is 

backwashed to remove large particulates trapped between the voids in the media. 

Typically, these processes can be gravity fed and do not require an energy supply, 

except during backwash. 

Adsorbents are capable of removing iron, manganese, total organic carbon, 

BTEX compounds, heavy metals, and oil from produced water. Adsorption is 

generally utilized as a unit process in a treatment train rather than as a stand-alone 

process. The adsorbent can be easily overloaded with large concentrations of 

organics, so this process is best used as a polishing step rather than as a primary 

treatment process (Veil). Adsorption is capable of removing over 80% of heavy 

metals (Spellman 2003) and can accomplish nearly 100% product water recovery.

Media usage rate is one of the main operational costs for adsorptive processes and 

may require frequent replacement or regeneration depending on media type and 

feed water quality. When all active sites of the adsorptive material have been 

consumed, the material must either be regenerated or disposed of. Regenerating 

the materials will result in a liquid waste for disposal. Solid waste disposal is 

necessary when the material needs to be replaced entirely. 

There will be a pressure loss incurred across the filter; however, depending on the 

plant configuration, this may not require any additional pumps. Pumps will be 

necessary to backwash the filters. Adsorption is best used as a polishing step to 

avoid rapid usage of adsorbent material. Waste disposal is required for spent 

media or the waste produced during regeneration of the media.
75

7.1.5 Media Filtration

Filtration can be accomplished using a variety of different types of media: walnut 

shell, sand, anthracite, and others. Filtration is a widely used technology for 

produced water, especially walnut shell filters for removing oil and grease. There 

are many vendors available that market filtration technologies specifically for 

produced water.

Filtration does not remove dissolved ions, and performance of filters is not 

affected by high salt concentrations; therefore filtration can be used for all 

TDS bins regardless of salt type. Filtration can be used to remove oil and grease 

and TOC from produced water with greater than 90% oil and grease removal. 

Removal efficiencies can be improved by employing coagulation upstream of the 

filter. Nearly 100% water recovery is achieved with filtration; some filtrate may 

be used for backwashes.

Minimal energy is required for these processes. Energy is required for 

backwashing the filter. Coagulant may be added to the feed water to increase 

particle size and enhance separation. Chemicals may be required for media 

regeneration. There will be a pressure loss incurred across the filter; however, 

depending on plant configuration, this may not require any additional pumps. 

Pumps will be necessary to backwash the filters. Solid waste disposal is required 

for spent media or the waste produced during regeneration of the media.

7.1.6 Oxidation

Chemical oxidation treatment can be used to remove iron, manganese, sulphur, 

color, tastes, odor, and synthetic organic chemicals. Chemical oxidation relies on 

oxidation/reduction reactions, which consist of two half-reactions: the oxidation 

reaction in which a substance loses or donates electrons, and a reduction reaction 

in which a substance accepts or gains electrons. Oxidation and reduction 

reactions will always occur together since free electrons cannot exist in solution 

and electrons must be conserved (AWWA 2005). Oxidants commonly used in 

water treatment applications include chlorine, chlorine dioxide, permanganate, 

oxygen, and ozone. The appropriate oxidant for a given application depends on 

many factors including raw water quality, specific contaminants present in the 

water, and local chemical and power costs (AWWA 2005). Chemical oxidation is 

well established, reliable, and requires minimal equipment (Reclamation 2003). 

Oxidation can be employed to remove organics and some inorganic compounds 

(i.e., iron and manganese) from produced water. The removal or oxidation rate 

may be controlled by applied chemical dose and contact time between oxidants 

and water with 100% feed water recovery. 

Chemical metering is required. Energy usage usually accounts for approximately 

18% of the total O&M for oxidation processes coupled with high chemical cost. 

Critical components of the oxidation process are the chemical metering pumps. 

Chemical metering equipment can have a life expectancy of 10 years or greater. 

Periodic calibration and maintenance of chemical meter pumps are required.
76

Capital costs can be near to $0.01 per gallon per day (gpd), and O&M costs can 

be approximately $0.05 per kilogallon (kgal) (>$0.01 per bbl). No waste is 

generated from oxidation processes.

No pretreatment is required for oxidation. Solid separation post-treatment might 

be required to remove oxidized particles. Chemical metering pumps are required 

for dosing. Some equipment may be required to generate the oxidant onsite, and 

chemical costs may be high. 

7.1.7 Settling

Settling can be achieved using a pond or a basin. In this process, particulates are 

removed by gravity settling. Settling ponds require a large footprint and 

environmental mitigation to protect wildlife. The volume of the settling basin 

required depends on the hydraulic residence time required for the desired level of 

contaminant removal. Settling ponds most likely will be used in combination 

with other treatment processes. There are no chemical requirements, but 

chemicals can be used to enhance sedimentation. Infrastructure requirements 

include liners. Settling ponds are used to remove large particulates from water 

sources. The degree of particle removal and size of particles removed depends on 

the water detention time in the pond. 

7.1.8 Air Stripping

Air stripping primarily is used for removing volatile organic chemicals (VOCs), 

oxidizing contaminants such as iron and manganese, improving taste, or removing 

odor. Air stripping is an USEPA BAT for some organic chemicals (VOCs) 

including benzene, toluene, xylene, tri/tetrachloroethylene, trihalomethanes, vinyl 

chloride and many others.

Air stripping is the process of transferring a contaminant from the liquid phase to 

the gas phase. In the air stripping process, air and water are contacted in a packed 

column designed to maximize the contact surface area between the water and air. 

Air stripping performance depends on factors such as:

• Characteristics of the volatile material (partial pressure, Henry’s constant, 

gas-transfer resistance, etc.) (AWWA 2005, Water Treatment Plant 

Design)

• Water and ambient air temperature

• Turbulence in gaseous and liquid phases

• Area-to-volume ratio

• Exposure time

Appropriate design of the packed column is necessary to ensure the desired level 

of contaminant removal based on the process operating temperature and the 
77

Henry’s Constant of the target contaminant. Scaling can occur when calcium 

exceeds 40 mg/L, iron exceeds 0.3 mg/L, magnesium exceeds 10 mg/L, and 

manganese exceeds 0.05 mg/L. Biological fouling also may occur depending on 

the feed water quality (U.S. Army Corps of Engineers 2001.

Spray aerators dissipate water in a vertical or inclined angle breaking the water 

into small drops. Multiple-tray aerators use uniquely designed trays to increase 

the surface area for aeration. Cascade and cone aerators allow water to flow in a 

downward direction over a series of baffles or pans (AWWA 2005). 

There are two main types of pressure aerators—one that sprays water on top of a 

tank that is constantly supplied with compressed air and one that injects 

compressed air directly into a pressurized pipeline adding fine air bubbles into the 

flowing water (AWWA 2005). 

Diffusion type aerators are similar to pressure aerators but are designed to allow 

air bubbles to diffuse upward through the tank of water to help produce 

turbulence and mixing (AWWA 2005). 

Mechanical aerators use a motor driven impeller to achieve air mixing. 

Occasionally, it also is used in combination with an air injection device 

(AWWA). 

Air stripping is a proven and widely used technology, able to be a low profile 

addition to a treatment process, with a high contaminant removal efficiency 

(> 99% ) (U.S. Army Corp of Engineers, 2001). Air stripping systems must be 

properly designed to provide the proper air and water balance to prevent flooding 

or excess air flow (U.S. Army Corp of Engineers, 2001); scaling, and biological 

fouling may impact the performance of the air stripper.

7.1.9 Surfactant Modified Zeolite Vapor Phase Bioreactor

Zeolites are naturally occurring hydrated aluminosilicates with a large surface 

area. Because of the natural shape and size of zeolites, they are suitable for flow 

through applications or media for fluidized beds. Treatment of zeolites with 

cationic surfactants changes the surface chemistry of the zeolites, allowing them 

to absorb nonpolar organic solutes. These materials also are capable of cation or 

anion exchange; however, their usefulness as a desalination technology is 

questionable.

A substantial amount of research has been conducted on using surfactant modified 

zeolites for organic chemical removal from produced water. This research 

suggests that this process is a promising produced water treatment technology 

(Ranck, Bowman et al. ; Bowman 2003; Altare, Bowman et al. 2007).
78

7.1.10 Constructed Wetlands

One of the major benefits of constructed wetlands is that these systems have low 

construction and operating costs. The estimated cost of constructed wetlands 

treatment is $0.01 to $0.02 per bbl. However, these systems are not efficient and 

the treatment rate is slow compared to other technologies. The average lifespan 

of a constructed wetland is approximately 20 years (Shutes, 2001).

A study was conducted to look at a hybrid reverse osmosis (RO) constructed 

wetland system for produced water treatment. This study showed that, while RO 

removes the majority of organic and inorganic constituents, it does not 

sufficiently remove dissolved organic compounds. These compounds were 

removed by the constructed wetland. Toxicity tests were conducted with a few 

different types of bacteria. All species of bacteria experienced a greater survival 

rate with water that had been passed through the constructed wetland. Many 

water quality parameters were increased following the wetland construction, such 

as TDS and calcium. SAR was decreased. Boron removal was not addressed in 

this study, and mention was made that for irrigation, the levels of boron in the 

treated water may be too high (Murry-Gulde 2003).

7.1.11 Granular Activated Carbon

Granular activated carbon (GAC) can be used to remove the following 

contaminants from produced water: mercury, cadmium, natural organic matter, 

BTEX compounds, synthetic organic chemicals—specifically benzo(a)pyrene, 

di(2-ethylhexyl)adipate, di(2-ethylhexyl)phthalate, hexachlorobenzene, dioxin, 

and radionuclides.

For source water with a large amount of bacteria, pretreatment in the form of 

filtration and disinfection prior to carbon treatment may be required. Filtration 

prior to GAC also may be required when dealing with high TSS waters.

GAC has an extremely large amount of adsorption surface area, generally around 

73 acres per pound (acre/lb) (650 square meters per gram [m2

/gram]) to 

112 acres/lb (1,000 m2

/gram) (AWWA, 2005, Water Treatment Plant Design). 

GAC is made of tiny clusters of carbon atoms stacked upon one another and is 

produced by heating the carbon source (coal, lignite, wood, nutshells, or peat) in 

the absence of air, which produces a high carbon content material. The 

adsorption isotherm for carbon and the source water will determine the total 

contaminant removal capacity. 

The physical removal of a contaminant by adsorption on to the carbon surface is

done in the mass transfer zone. Breakthrough is defined as the point at which the 

concentration of a contaminant in the effluent adsorption unit exceeds the 

treatment requirement (AWWA, 2005, Water Treatment Plant Design). This 

breakthrough time is important to note so that treatment goals are not exceeded 

and that backwashing rates can be optimized. Backwashing a GAC system 

follows the same general procedures as a conventional granular gravity filter 
79

system. The GAC typically will expand up to 75–100% in volume, but it may 

be only as much as 50% (AWWA, 2005, Water Treatment Plant Design). Empty 

bed contact time is the volume of the empty bed divided by volumetric flow rate 

of water through the carbon. A typical bed depth can contain up to 50% freeboard

excess capacity beyond the designed capacity to allow for bed expansion during 

backwashing. Surface loading rates, or the volume of water that is passing though 

a given area, typically range from 2–6 gallons per minute per square foot 

(5–15 meters per hour) (AWWA, 2005, Water Treatment Plant Design).

Biological growth can be desirable within GAC, which results in what is known 

as biologically active carbon (BAC). BAC can be beneficial by removing 

assimilable organic carbon (AOC) and other biodegradable compounds. If it is 

intended to have BAC, the GAC filters typically are preceded by ozonation that 

breaks down the organic carbon into a more assimable form. This process can 

enhance the overall contaminant removal of the GAC process. However, the 

biological growth needs to be controlled with frequent backwashing (once every 

5 days). The use of chlorine prior to the beds will not prevent growth, will 

produce DBPs that take up more GAC adsorption sites, and will make the carbon 

more brittle. Disinfection is recommended after the GAC filters to prevent 

biological growth in the distribution system and to achieve the highest removal of 

AOC within the plant. If biological growth is not controlled and anaerobic 

conditions develop, odor problems will occur, and undesirable organisms will 

begin to grow. Significant head loss and shorter filter runs can occur with too 

much biological growth. These two factors will be impacted even with beneficial 

biological growth and should be accounted for in GAC design (AWWA, 2005, 

Water Treatment Plant Design).

Regular reactivation or replacement of carbon media is required. If a GAC plant 

is large enough, regeneration can be done onsite, but it is typically performed off 

site. Onsite regeneration is typically not effective unless the carbon exhaustion 

rate is larger than 910 kg/day (AWWA, 2005, Water Treatment Plant Design). 

Reactivation frequency is dependent on contaminant type, concentration, rate of 

water usage, and type of carbon used. Careful monitoring and testing to ensure 

contaminant removal is achieved is necessary around the time of startup and 

breakthrough. Flushing is required if the carbon filter is not used for several days, 

and regular backwashing may be required to prevent bacterial growth (AWWA, 

2005, Water Treatment Plant Design).

Disposal of spent media is typically the responsibility of the contractor providing 

the media replacement or reactivation service. Backwash/flush water disposal is a 

required waste stream if it is included in the design of the filter (AWWA, 2005, 

Water Treatment Plant Design).

Benefits:

• Well established treatment technique

• Suitable for many organic chemicals, NOM, and trihalomethanes (THMs).
80

• Suitable for home use.

• Able to improve taste and odor and removes chlorine.

Limitations:

• Relatively expensive O&M cost for regeneration.

• Effectiveness is based on contaminant type, concentration, rate of water

usage, and type of carbon used.

• Requires careful monitoring when nearing breakthrough times.

7.1.12 Ultraviolet Disinfection

Ultraviolet (UV) radiation disinfection is a popular form of primary disinfection 

because of its ease of use, no need of chemicals, and no formation of disinfection 

byproduct (DBP). Water is pumped through a UV reactor, which is equipped 

with an array of UV lamps providing disinfection dosages of 30–50 megajoules 

per square centimeter. As pathogens path through the reactor, they are 

inactivated. They are exposed to the UV light for a predetermined period of time, 

depending on the desired level of disinfection. UV reactors typically are closed 

channel for potable water treatment and are installed in open channel for 

wastewater treatment. There are several types of UV lamps, with low pressurehigh output and medium pressure mercury vapor lamps being the most commonly 

used (Reclamation 2003). The lamps are housed inside of quartz lamp sleeves in 

the reactor to protect the lamp from breaking. 

The mechanism of UV disinfection is inactivation through UV damage of the 

microorganism’s deoxyribonucleic acid (DNA) and/or ribonucleic acid (RNA). 

Removal of suspended solids from the feedwater to UV is important to avoid 

shielding of microorganisms from the UV by suspended solids. This phenomenon 

is called “shadow effect.” UV disinfection does not provide a disinfectant 

residual. Therefore, addition of chlorine or chloramine as a secondary 

disinfectant might be required (Reclamation 2003). 

Disinfection is typically the last treatment step in most water treatment facilities, 

most suspended solids and/or dissolved ions, if any, should have been removed 

prior to disinfection. No waste is generated in UV disinfection. UV equipment 

including lamps must be properly checked to ensure they are working according 

to technical specifications. The lamps age with time and require periodic 

replacement. A cleaning system also must be installed on the lamp sleeves, 

because the sleeve itself reacts with compounds in water and would decrease the 

UV transmittance if they are not cleaned (Reclamation 2003). This disinfection 

has a high capital cost; with the USEPA estimated cost as $0.13 per gpd.
81

7.1.13 Microfiltration/Ultrafiltration

Microfiltration (MF) has the largest pore size (0.1–3 μm) of the wide variety 

of membrane filtration systems. Ultrafiltration (UF) pore sizes range from 

0.01–0.1 μm. In terms of pore size, MF fills in the gap between ultrafiltration 

and granular media filtration. In terms of characteristic particle size, the 

MF range covers the lower portion of the conventional clays and the upper half 

of the range for humic acids. This is smaller than the size range for bacteria, 

algae, and cysts, and larger than that of viruses. MF also typically is used for 

turbidity reduction and removal of suspended solids, Giardia, and 

Cryptosporidium. UF membranes are used to remove viruses, color, odor, and 

some colloidal natural organic matter (Technologies 2008). Both processes 

require low transmembrane pressure (1–30 pounds per square inch [psi]) to 

operate, and both now are used as a pretreatment to desalination technologies 

such as reverse osmosis, nanofiltration, and electrodialysis but cannot remove salt 

themselves (Reclamation 2003).

MF membranes can operate in either cross-flow separation as shown in figure 23

and also dead-end filtration where there is no concentrate flow. There are also 

two pump configurations, either pressure driven or vacuum-type systems. 

Figure 23. Dead-end versus cross flow filtration.

Pressure driven membranes are housed in a pressure vessel, and the flow is fed 

from a pump. Vacuum-type systems are membranes submerged in 

nonpressurized tanks, and product water is extracted by a vacuum pump on 

the product side. Typical recoveries can range from 85–95% (AWWA 2005). 

Flux rates range from 20–100 gallons per day per square foot depending on 

the application. Backwash usually is used to clean the membranes, and it 

is carried out for short durations (3–180 seconds) in relatively frequent intervals 

(5 minutes to several hours) (AWWA 2005). The frequency and duration of 

backwash depend on the specific application. A clean in place (CIP) also 

can be performed as a periodic major cleaning technique. Typical cleaning 

agents are sodium hypochlorite, citric acid, caustic soda, and detergents. 

They can be initiated manually and automatically controlled. CIP is 
82

initiated when backwashing and chemically enhanced backwash are not 

effective in restoring desirable performance (Reclamation 2003).

Factors affecting membrane selection are:

• Cost

• Percent recovery

• Percent rejection

• Raw water characteristics

• Pretreatment

Factors affecting performance are:

• Raw water characteristics

• Pressure

• Temperature

• Regular monitoring and maintenance

A self-backwashing 100-μm strainer is often used to protect the membranes and 

moderate particulate loading. Depending on the raw water quality, a coagulant 

may be added to form pin-sized floc and help improve rejection (Reclamation

2003).

7.1.13.1 Ceramic MF/UF Membrane

Ceramic UF and MF membranes are made from oxides, nitrides, or carbides of 

metals such as aluminum, titanium, or zirconium (Mulder 2003). Ceramic 

membranes are much more resilient than polymeric membranes and are 

mechanically strong, chemically and thermally stable, and can achieve high flux 

rates. Typically, a tubular configuration is used with an inside-out flow path, 

where the feed water flows inside the membrane channels and permeates through 

the support structure to the outside of the module. These membranes typically are 

comprised of at least two layers—a porous support layer and a separating layer.

Ceramic membranes are capable of removing particulates, organic matter, oil and 

grease, and metal oxides. Ceramic membranes alone cannot remove dissolved 

ions and dissolved organics. Precoagulation, injection of a chemical coagulant 

upstream from the membrane, improves removal efficiencies of dissolved organic 

carbon and smaller particulates. As with conventional UF and MF, a strainer or 

cartridge filter is necessary as pretreatment for ceramic membranes.

Numerous research studies have been conducted on using ceramic membranes to 

treat oil-containing wastewater and produced water (Faibish and Cohen 2001; 

Faibish and Cohen 2001; Konieczny, Bodzek et al. 2006; Lobo, Cambiella et al. 
83

2006; Gutierrez, Lobo et al. 2008). These research studies have shown that 

ceramic membranes perform better than polymeric membranes on oil-containing 

waters. Ceramic membranes also have been employed commercially to treat oil 

produced water (Wallace 2005). Ceramic membranes are employed as part of a 

large treatment train consisting of a multiple unit process at the Wellington Water 

Works to treat oilfield produced water. 

Energy requirements for ceramic membranes are lower than those required for 

polymeric membranes. Infrastructure requirements for ceramic membranes are 

similar to other membrane processes and include a break tank for the feed water, a 

feed pump, a rack for holding the membrane modules, a chemical metering 

system if necessary, a tank for the filtrate water, and a pump and valves for the 

backwash and cleaning systems.

Ceramic membranes have a higher capital cost than polymeric membranes. The 

use of ceramic membranes is increasing as more research and pilot studies are 

conducted. The capital cost of ceramic membranes will continue to decrease as 

they become a more widely used technology. Ceramic membranes do require 

frequent backwashes; backwash waste will require disposal. If ceramic 

membranes are operated in a cross-flow mode, then there will be a residual 

process stream requiring disposal.

6.1.11.2 Polymeric MF/UF Membrane

Polymeric MF/UF membranes are made from materials like polyacrylonitrile 

(PAN) and polyvinylidene (PVDF). Because there is a large market for 

polymeric ultrafiltration membranes, there are many vendors and suppliers for 

these membranes. They also are relatively inexpensive. Typically, package 

systems are purchased and installed by the vendor.

An important consideration for polymeric MF/UF membranes is integrity testing 

to ensure that the membrane is not damaged and is operating properly. Typically, 

the filtrate turbidity is monitored to give a rough indication of membrane 

integrity. Membrane integrity can be tested through a pressure decay test. In this 

test, pressurized air is applied to the membranes at a pressure less than would 

cause the air to flow through the membrane, and the pressure decay is measured. 

Regular monitoring of membrane performance is necessary to ensure that the 

membrane system is operating at the most effective loading rate and backwash 

regime. Membrane life typically is estimated at 7+ years with manufacturer 

warranties covering 5 years in municipal applications.

Product water is free of suspended solids. DOC removal is approximately 10%. 

Nearly all nondissolved organic carbon is removed, with 95% hydrocarbon 

removal—85–100% depending on feed water quality and mode of operation 

(dead-end versus crossflow).

Waste includes pretreatment waste, backwash flow, retentate flow (if applicable), 

and CIP waste. Waste streams are either discharged to the sewer or treated if 
84

discharging to surface waters. Waste streams being discharged to surface waters 

typically are processed for turbidity removal through settling ponds or other 

treatment systems. CIP waste is neutralized and usually combined with the rest of 

the waste. 

Capital cost for polymeric UF systems vary based on the size of the plant and feed 

water quality. Approximate capital costs will be near $1–2 per gpd, and O&M 

costs will be approximately $1–2 per kgal.

Bierle et al. performed a three-pass UF membrane pilot study to treat produced 

water at a temperature of 130 degrees Fahrenheit (°F) to reduce the total organic 

carbon concentration of the produced water from 29 mg/L to 11.9 mg/L (Bierle). 

7.2 Desalination Technologies

Desalination technologies are necessary to lower the total dissolved solids 

concentration and the concentration of ions that are too high for the desired 

beneficial use of co-produced water. Desalination technologies fall into the 

following categories: membrane, thermal, and alternative technologies. 

Desalination technologies, combined together and called hybrid technologies, are 

often employed to reduce the energy cost of the process or to enhance the product 

water recovery. The following membrane processes were evaluated: reverse 

osmosis, nanofiltration, and electrodialysis (ED). Hybrid membrane processes 

considered are two pass nanofiltration, dual RO with chemical precipitation, dual 

RO with HEROTM, dual RO with seeded slurry precipitation, and high efficiency 

electrodialysis. The thermal desalination technologies included in this report are: 

membrane distillation, multistage flash distillation, multieffect distillation, vapor 

compression, and freeze-thaw evaporation. Commercial processes evaluated are 

as follows: CDM HERO process, Veolia OPUS, Altela Rain, and 212 Resources.

The technologies were evaluated based on the whether they are an emerging 

technology or an established technology and whether they previously have been 

employed for treatment of produced water. The TDS range of applicability of 

these technologies and their salt rejection and product water recoveries are also 

presented. Specific sodium, organic, and heavy metal rejection capabilities are 

also presented. The technologies then were compared qualitatively based on the 

following criteria: pretreatment requirements, chemical and energy requirements, 

maintenance requirements, ease of operation, cost, robustness, reliability, 

flexibility, mobility, modularity, volume of residuals generated, and the size of 

the plant or footprint.

The qualitative technology assessment and comparison are presented in tabular 

format, see table 21. A very brief summary of the current status of each 

technology is described below; however, for more detailed information and a 

description of the technology, please refer to other sources. 

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7.2.1 Reverse Osmosis and Nanofiltration

Reverse osmosis and nanofiltration membranes also can be used to remove salt 

from produced water. Reverse osmosis membranes work on the premise that a 

pressure, greater than the osmotic pressure of the feed solution, must be applied to 

the system to force water through the membrane and reject the salt. The osmotic 

pressure is a function of the salinity of the water. For water with very high 

salinity, the osmotic pressure and, hence, the required system operating pressure 

are very high. For waters with high salinity, reverse osmosis is not a practical 

solution. Reverse osmosis generally is considered a cost effective treatment 

technology to use with seawater or the salinity up to 40,000 ppm TDS.

Current research on the use of RO and NF membranes for produced water 

treatment emphasizes the tendency for organic fouling to increase the treatment 

cost and reduce the process efficiency (Mondal and Wickramasinghe 2008). 

Effect pretreatment technologies and appropriate membrane materials must be 

selected to make produced water treatment with RO and NF effective.

Melo et al. investigate RO and NF use for treatment of produced water. They 

employed oil/water separation, warm softening, sand filters, ion exchange, and 

cartridge filtration as pretreatment to the RO and NF. The RO and NF were 

successful in meeting the treatment goals; however, fouling data was not 

presented, and further study is required to determine suitability of the water for 

beneficial use, the optimum process operating conditions, and the effects of the 

product water on soil for irrigation purposes (Melo, Schluter et al.).

Mondal, et al. observed significant organic fouling on RO and NF membranes 

from treatment of produced water. They found that large MWCO, smooth, 

hydrophilic membranes experienced the least amount of fouling (Mondal and 

Wickramasinghe 2008). 

Sagle, et al. have been developing fouling resistant coatings for RO membranes to 

minimize the fouling potential of produced water using polyethylene hydrogels 

(Sagle, Van Wagner et al. 2009). 

7.2.2 Electrodialysis/Electrodialysis Reversal

Electrodialysis is an electrically driven process consisting of a stack of alternating 

cation-transfer membranes and anion-transfer membranes between an anode and a 

cathode. An electrical current is passed through the water. The dissolved salts in 

the water exist as ions and migrate toward the oppositely charged electrode. The 

anion-transfer membrane only allows passage of negatively charged ions, and the 

cation-transfer membrane only allows passage of positively charged ions. 

Alternating anion and cation transfer membranes are arranged in a stack. The 

membranes are impermeable to water. These systems are operated at a very low 

pressure, usually below 25 psi. Electrodialysis reversal also can be implemented 

where the charge on the electrodes is frequently reversed. This prevents buildup 

of scale, biofilm, and other foulants on the membrane surface.
86

The energy required for ED treatment is related to the TDS of the water—the 

higher the TDS, the more energy required for treatment. Current research 

suggests that ED is not cost competitive for treating water with a TDS greater 

than 1,500 mg/L. Sirivedhin et al. tested ED on five simulated produced water 

types of high and low TDS using Neosepta® membranes. They found that at 6.5

volts per stack, ED was not capable of producing water with an SAR that would 

be suitable for irrigation because ED removes divalent ions to a greater extent 

than monovalent ions (Sirivedhin, McCue et al. 2004). If ED, using divalent 

selective membranes, is to be used to treat produced water for beneficial use as 

irrigation water, calcium and/or magnesium will need to be added back to the 

water to lower the SAR.

7.2.3 Forward Osmosis

Forward osmosis is an osmotically driven membrane process. Forward osmosis 

uses the feed water to be treated as the dilute process stream and water is moved 

across the membrane from the dilute feed water stream to a concentrated brine 

stream with a high osmotic pressure. The concentrated brine stream is called a 

draw solution. To enable forward osmosis to be cost effective, the components 

that contribute to the high osmotic pressure in the brine stream must be removed 

easily to leave behind the fresh water product.

7.2.4 Hybrid Membrane Processes

7.2.4.1 Two Pass Nanofiltration

Two pass nanofiltration involves treating produced water with nanofiltration and 

then further treating the permeate water with nanofiltration again. This process is 

used to obtain a permeate stream with an even lower TDS than a single pass 

NF process and is less energy intensive than reverse osmosis. Western 

Environmental pilot tested this process for produced water (Bierle).

7.2.4.2 Dual RO with Chemical Precipitation

Dual RO with chemical precipitation consists of a primary RO process. The 

concentrate from the first RO is further treated with lime softening and is then fed 

to a second stage RO. The permeate streams from both RO processes are 

collected and provide the product water from this process. Reported recoveries 

using this process are 95% and higher for brackish water applications. Utilizing 

this process enhances the recovery of the RO process but requires additional 

chemicals, additional equipment, and an increased footprint. 

7.2.4.3 Dual RO with Softening Pretreatment and Operation at High pH

This patented process is called HEROTM and consists of chemical softening as a 

pretreatment step, primary RO, and ion exchange, degasification, and pH increase 

on the concentrate from the first RO stage. The treated concentrate stream then is

treated with a secondary RO. The product water from the primary and secondary 
87

RO units is combined to make up the product water for this process. As with 

the dual RO with chemical precipitation, this process is designed to increase 

the product water recovery of the process. Reported recovery rates range 

from 90–95%. 

7.2.4.4 Dual RO with Slurry Precipitation and Recycling RO (SPARRO)

In this process, a single stage reverse osmosis membrane unit is used, and the 

concentrate from the RO process is treated using a seeded crystalline slurry to 

precipitate sparingly soluble salts from the water. The crystals then are separated 

from the concentrate process stream using a cyclone separator, and the remaining 

water then is recycled back to the RO feed. 

7.2.4.5 High Efficiency Electrodialysis (HEED®)

HEED® is an electromembrane process in which the ions are transported through 

a membrane from one compartment to another under the influence of an electrical 

potential. HEED® consists of dual or multiple side-by-side ion exchange 

membranes and contains an improved gasket design that results in greater 

efficiency than traditional ED processes (Corporation 2008). HEED® is more 

resistant to organic fouling than RO or NF. 

7.2.4.6 Electrodeionization

Electrodeionization (EDI) involves ion exchange resins, ion exchange 

membranes, and a direct current electrical current. The major difference between 

ED and EDI is that desalting compartments of EDI are filled with an ion exchange 

resin. Ions are transported to the ion exchange resin by diffusion; they are then 

transported through the resin by the current. The current flows through the ion 

exchange resin because this path is more electrically conductive. This process is 

capable of removing weakly ionized species and desalting water to very low 

concentrations.

7.2.5 Thermal Processes

7.2.5.1 Multistage Flash Distillation

Multistage flash distillation converts water to steam at low temperatures in a 

vacuum. At vacuum pressures, the boiling point of water is lower than at 

atmospheric pressure, requiring less energy. The water is preheated and then 

subjected to a vacuum pressure that causes vapor to flash off the warm liquid. 

The vapor then is condensed to form fresh water while the remaining concentrated 

brine that does not flash is sent to the next chamber where a similar process takes 

place. The multiple stages are designed to improve the recovery of the process. 

Many of the older seawater desalination plants use the multistage flash distillation 

process.
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7.2.5.2 Multieffect Distillation

In multieffect distillation, vapor from the first evaporator is condensed in the 

second evaporator and the heat of condensation is used to evaporate the water in 

the second evaporator. Each evaporator in the series is called an “effect.” 

7.2.5.3 Vapor Compression

In the vapor compression process, the feed water is preheated in a heat exchanger 

by the product and reject streams from the process. This process uses a still that

contains tubes. The water then is fed to the inside of the tubes, and the vapors 

then are fed to the outside of the tubes to condense. The gases that do not 

condense are removed from the steam-condensation space by a vent pump or 

ejector. The mechanical pump or ejector is a requirement of this process and is 

necessary to increase the pressure of the vapor to cause condensation. Vapor 

compression has been used for produced water treatment, and commercially 

available products currently are marketed for this application. 

7.2.5.4 Membrane Distillation

Membrane distillation is a thermally driven membrane processes that uses the

vapor pressure gradient between the feed solution and the product solution as the 

driving force. The membrane is hydrophobic and microporous. The flux and salt 

rejection of this process is independent of feed water salinity. There are many 

different configurations for the application of membrane distillation.

7.2.6 Alternative Desalination Processes

Alternative desalination processes do fall within the thermal or membrane 

categories and use other materials and mechanisms for desalination.

7.2.6.1 Capacitive Deionization

In capacitive deionization, water is passed through pairs of high surface area 

carbon electrodes that are held at a potential difference of 1.2 volts. Ions and 

other charged particles are attracted to the oppositely charged electrode. When 

the electrodes have become saturated with ions, they must be regenerated by 

removing the applied potential and rinsing the ions out of the system.

The carbon aero gel electrodes have a relatively high surface area (500 m2

/g) and 

provide high electrical conductivity, and have a high ion permeability. The 

electrodes are, however, expensive and have a relatively low ion storage capacity.

7.2.6.3 Softening

Softening can be used to remove hardness and silica from the water. Generally, if 

the water is to be used for agricultural purposes, softening would not be advised 

because, like nanofiltration, the SAR will be higher following treatment due to 

removing the divalent ions.
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7.2.6.4 Ion Exchange

The Higgins LoopTM is a sodium ion exchange technology for water with a high 

concentration of sodium. This process is beneficial if there are no other ions of 

concern besides sodium and if SAR adjustment is necessary. The cation 

exchange resin in the Higgins LoopTM process exchanges sodium ions for 

hydrogen ions. Up to 90% exchange levels are achieved. As the resin becomes 

loaded with sodium, the flows to the adsorption portion of the process temporarily 

are interrupted. The resin then is advanced by a pulsing action through the loop in 

the opposite direction of the liquid flow. The loaded resin then is regenerated 

with hydrochloric acid and rinsed before being advanced back into the adsorption 

portion of the loop. Treated water is slightly acidic because H+ ions are added to 

the water. Therefore, the pH is raised, and calcium is added by passing the treated 

water through a limestone bed in the pH controlling process step. 

For many produced waters, removing the sodium ions will have a large effect on 

the total dissolved solids concentration to render the water suitable for beneficial 

use.

Other ion exchange resins also may be employed to target specific ions for 

removal. The resin may or may not be able to be regenerated.

7.3 Commercial Processes

Numerous companies currently market package produced water treatment 

technologies. Most of these companies tailor their package plant to meet the 

specific treatment need for each individual application. The following sections 

contain a brief summary of some of the commercially available produced water 

treatment systems.

7.3.1 Freeze-Thaw/Evaporation (FTE®)

BC Technologies and Crystal Solutions utilizes the FTE® process to treat 

produced water for full scale facilities. In this process, when the outdoor air 

temperature is less than 32 °F, the water to be treated is sprayed or dripped onto a 

freezing pad, forming a large pile of ice. This process exploits the fact that saline 

water has a lower freezing point than fresh water; therefore, at temperatures 

cooler than 32 °F, the runoff from the ice pile will be salty brine. When the 

temperature is such that melting occurs, the runoff will be fresh water.

This process has been used successfully to treat produced water and is considered 

an established process for produced water treatment.

7.3.2 CDM Produced Water Technology

CDM has developed a process for treating produced water containing TDS levels 

up to 20,000 mg/L. The technology is not specific for coal bed methane produced 

water and has been pilot tested with tight sands produced water in the Piceance 
90

basin and with CBM produced water in the Powder River basin. CDM also is 

marketing the technology for treating flow-back water from subsurface hydraulic 

fracturing.

The treatment process is comprised of a train of different technologies in series to 

meet site-specific treatment goals (figure 24). The specific processes included in 

the treatment train are dictated by the feed water quality and the desired product 

water quality. Some of the technologies that may be used include: advanced 

filtration, weak acid cation IX softener, UV disinfection, low-pressure RO, 

antiscalant addition, seawater/high pressure RO, evaporation, and crystallization. 

The feed stream is kept anoxic to minimize oxidation of iron and other metals and 

to reduce the fouling potential of the water. Depending on the feed water quality, 

the process can achieve more than 97% recovery. A computer program was 

developed that assists in selecting the required technologies and predicts the 

performance and scale formation within the system based on feed water quality.

The pretreatment for the process consists of media filers and polymeric hollow 

fiber UF membranes to remove particulates, silt, oil, grease, coal fines, clay, and 

bacteria. The filtration system is backwashed using RO permeate. A weak acid 

cation (WAC) IX softener is used to reduce hardness and other metals. The resin 

is regenerated using hydrochloric acid. The water is then disinfected using UV. 

The calcium and magnesium-rich WAC regeneration solution is combined with 

the filter backwash and is either treated separately or combined with the product 

streams from the membrane processes and discharged, depending on the scenario 

and the feed water quality.

After pretreatment, low-pressure RO (capable of achieving 85% recovery) is 

employed. The train size and type of membrane employed is tailored based on 

the feed water quality. An antiscalant (approximately10 mg/L) is added to the 

concentrate stream to stabilize the silica and to prevent scale formation in the next 

high-pressure RO stage. The second RO stage consists of high-pressure or 

seawater RO membranes that can achieve 80% water recovery. The RO permeate 

is combined with the low-pressure RO permeate for discharge or beneficial use. 

The concentrate, approximately 2–3% of the initial feed volume, is either 

disposed of as a waste, or can be treated for zero liquid discharge (ZLD).

Because many produced waters contain high levels of sodium and low levels of 

divalent ions, the SAR may be too high, even after treatment, for beneficial use of

the water. In these cases, a limestone bed is used to add calcium to the water and 

lower the SAR.

The following cost estimates were presented based on the pilot testing experience 

in the Powder River basin: $0.14 per bbl or $3.33 per 1,000 gal (not including 

energy or brine disposal); $0.08 per bbl or $1.90 per 1,000 gal for brine disposal. 

Cost estimates were not provided for the pilot test on tight sands produced water.
91

To accommodate changing water volumes, modular systems can be designed to 

treat volumes from 5,000 bbl/day (200,000 gpd or 145.8 gpm) to 20,000 bbl/day 

(840,000 gpd or 583 gpm) with additional units added or removed, as necessary. 

A schematic diagram of the CDM process is provided in figure 24. 

Figure 24. Schematic diagram of CDM produced water treatment process.

7.3.3 Veolia OPUSTM

Veolia water currently is marketing their produced water treatment system, called 

OPUSTM, which stands for optimized pretreatment and unique separation. 

OPUSTM uses filtration and ion exchange as pretreatment to an RO system 

operated at a high pH. The process may be modified slightly depending on the 

specific water quality of produced water application.

7.3.4 Altela RainSM (Dewvaporation)

This process utilizes a humidification-dehumidification cycle to produce distilled 

water. Feed water is evaporated by hot air on one side of a heat transfer wall, and 

fresh water is condensed on the other side. The condensate or dew collects on the 

other side of the wall represents the purified water stream. This process has been 

utilized for produced water treatment and has undergone several pilot tests.

7.3.5 212Resources

212Resources is currently marketing a produced water treatment system. 

The core component to the process is vapor compression. The package 

treatment system also utilizes other unit processes in a package treatment 
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system; however, the specific details of the process are proprietary. 

212Resources claims the treatment system can produce clean water and 

recover marketable hydrocarbons and methanol. 

7.4 Implications of Water Quality for Treatment 

Technologies

Many application specific and water quality specific factors should be taken into 

account when selecting a produced water treatment process. For example, the 

temperature of the feed water may help determine which type of desalination 

treatment should be employed since some technologies work more efficiently at 

high temperatures, while others use a low temperature feed stream. Also, if ion 

removal is necessary, one must consider the type of ions that need to be removed. 

Membrane processes most often remove divalent ions to a greater extent than 

monovalent ions, which may make the sodium adsorption ratio higher and render 

the water less suitable for beneficial use as irrigation water or surface discharge.
93

8. GIS-Based Approach to Produced 

Water Management

Produced water management strategies should consider the geographical 

relationship between the produced water source and potential beneficial uses. 

Ideally, beneficial use of produced water will require minimal water conveyance. 

Geographic data can be used to describe the location of produced water and water 

uses.

8.1 Produced Water GIS Database

A GIS database has been compiled to describe the location of oil and gas 

producing wells and the water quality of produced water associated with the 

wells. From this database, a series of maps has been generated to qualitatively 

describe the potential for different types of produced water beneficial use. The 

database was designed such that data of interest can be viewed by selecting the 

corresponding data layers. Map layers were constructed to include a base map 

and reference data, petroleum basin and well locations, and water consumption by 

use.

8.1.1 Base Map and Reference Data

Shape files for State boundaries, city/town data, rivers, and lakes are contained 

within the database to provide a base map and to serve as a reference for the oil 

and gas data. City and town location data were obtained from ESRI Redlands, 

California, (www.esri.com), and population data were gathered from the 

U.S. Geological Survey (http://nationalatlas.gov/atlasftp-na.html). Shape files for 

rivers, streams, lakes, and reservoirs were obtained from the U.S. Geological 

Survey (http://edc2.usgs.gov/geodata/index.php). Figure 25 shows the base map 

with reference data.

8.1.2 Oil and Gas Distribution, Well and Basin Data

USEIA collects, analyzes, and publishes unbiased energy information for 

policymaking, market studies, and public knowledge. These data, which include 

energy production values, stock prices, energy demand, import and export 

volumes, and current prices, are intended to improve the understanding of energy 

and interaction with the economy and environment. 

Each year, USEIA publishes a list of the top 100 producing oil and gas well, 

based on proved reserves. We have used these data to identify areas with 

substantial amounts of petroleum production and, therefore, water production. 

USEIA also gathers data on the distribution of oil and gas production within the 
94

Figure 25. Base map with reference data and sources.

United States. This data can be used to infer information about the general 

distribution of petroleum from all wells, not only the top producing wells. Many 

basins produce both oil and gas. The latitude and longitude data for these top 

100 wells and the shape files for the distribution data are available by request 

from USEIA (www.eia.doe.gov). Figure 26 shows the top producing wells, 

petroleum basin boundaries, and distribution of oil and gas wells for the Western 

United States along with the base map with the reference data.

8.1.3.1 Hydrologic Units 

Hydrologic units represent natural and manmade watersheds. A watershed is a 

geographic area of land, water, and biota within the confines of a drainage divide. 

Watershed boundaries define the aerial extent of surface water drainage to a 

specific location. These watersheds divide regions based on the area drained by a 

river system, section of river, and its tributaries. Different levels of hydrologic 

units are defined based on the scale at which the drainage is evaluated. 

Hydrologic data was used as a layer on the base map. 
95

Figure 26. Location of oil and gas producing basins and the top 100 producing oil and gas 

wells in the Western United States.

Figure 27. Geographic relationship between hydrologic units and petroleum 

basins.
96

Hydrologic units are important for employing watershed approaches to water 

management. A watershed approach is a comprehensive interrelated approach to 

watershed and natural resources management because it is sensitive to the needs 

of all resources: soil, water, air, plants, animals, and people in relation to local 

social, cultural, and economic factors (2007). Most watershed efforts are focused 

on an eight-digit hydrologic unit basis.

8.1.3.2 Overall Need for Additional Water Supplies 

Water shortage and water-use conflicts have become increasingly common in 

many areas of the United States, even in normal water years. As competition for 

water resources grows—for irrigation of crops, growing cities and communities, 

energy production, and the environment—the need for information and tools to 

aid water resource managers also grows. Water issues and challenges are 

increasing across the Nation but particularly in the West and Southeast due to 

prolonged drought.

These water issues are exacerbating the challenges facing traditional water 

management approaches, which by themselves no longer meet today’s needs. 

Beneficial use of produced water is new tool that can be used in the Western 

United States to increase water supplies. Additionally, produced water often 

occurs in areas that also have a high potential for water conflict, as identified by 

Water 2025, figure 28.

Figure 28. Potential water conflict and produced water generation.
97

8.1.3.3 Agricultural Water Demand

Produced water, which can be generally described as brackish ground water, 

could easily be put to use as agricultural water for irrigation or livestock watering. 

Data was obtained for the U.S. Department of Agriculture to describe the amount 

of irrigation in the Western United States. These data were mapped on the base 

map, figure 29.

The maps presented in figures 28 and 29 can be used to draw general conclusions 

about the use of produced water for streamflow augmentation, municipal uses, 

general water supply augmentation, and agricultural uses. At the macroscopic 

level, it does appear that there is a geographical relationship between produced 

water generation and beneficial uses of produced water.

Figure 29. Areas of irrigated agriculture compared to produced water generation.

8.2 Examples of GIS-Based Approach

The Geographic Information System (GIS) database was used to identify 

produced water management options for three different geographic locations: 

conventional oil production in the Denver basin, coal bed methane production in 

the Powder River basin, and conventional gas production near a tributary of the 

Colorado River. This section is intended to illustrate the potential for use; legal 
98

and regulatory considerations are outside of the scope of this study. The need for 

treatment to render the produced water to the quality dictated by the different 

beneficial uses was not considered, since this is purely a conceptual analysis. In 

many cases, the actual beneficial use for produced water would be dependent 

upon the raw water quality of the produced water and the degree and cost of 

treatment required for the water to meet beneficial use water quality standards.

8.2.1 Denver Basin Example

Produced water generated in the Denver basin could potentially be used to 

augment the water supply in an urban area. The Denver basin falls within one of 

the areas outlined in the Water2025 study that has a large potential for water 

conflict by the year 2025. The Denver basin contains one of the USEIA top 

producing oil wells and a top producing gas well, figure 30.

Figure 30. Selection of top 100 producing well in the Denver basin.

Within the study area, the conventional water supply is from the Colorado-Big 

Thompson (CBT) Project. The Colorado-Big Thompson Project is the largest 

transmountain water diversion project in Colorado and is used to supplement the 

water supplies of 30 cities east of the Continental Divide with water from the west 

of the Continental Divide. The Colorado-Big Thompson Project annually delivers 

213,000 acre-feet of water to northeastern Colorado for agricultural, municipal, 

and industrial uses. For the purposes of this analysis, we will consider the use of 

produced water only to augment conventional supplies, not to replace or compete 

with conventional supplies. Therefore, it is important to note that, within the 

study area, it is not possible to purchase additional water (that is not already 
99

allocated) from the Colorado-Big Thompson Project. Therefore, to render 

produced water useful as a new water source, it does not need to be compared on 

the same cost basis as water from the Colorado-Big Thompson Project. 

The boundary conditions for this example are a 5-mile radius surrounding the well 

of interest. Agricultural data was obtained for this study area from the National 

Agricultural Imagery Program, figure 31.

Figure 31. Agricultural data within the study area.

Oil and gas well locations were obtained from the Colorado Oil and Gas 

Conservation Commission, figure 32. Abandoned wells are identified by a black 

cross, and producing wells are identified by a red cross. It is important to note 

that not only is there a top 100 producing gas wells, but also a top 100 producing 

oil wells and over 1,000 other producing wells within the study area.

The next layer added to the study area map shows the type of irrigation used—

sprinkler and flood, figure 33. Each sprinkler irrigated circle on the map is 

roughly 130 acres. Within the study area, there are 5,565 acres of flood irrigated 

land and 10,809 acres of sprinkler irrigate land.
100

Figure 32. Oil and gas well location data within the study area.

Figure 33. Irrigated land within the study area.
101

Within the study area, the most likely use for produced water is irrigation water. 

As can be seen from figure 33, there are approximately four producing wells 

within the sprinkler irrigated areas. Depending on the quality of the produced 

water, treatment may be required to treat the water to irrigation water standards. 

Another option is to use a pipeline to transport the produced water to the 

irrigations canal within the study area. The irrigation canals are shown as blue 

lines in figure 33.

8.2.2 Powder River Basin Example

Another example looked at the top 100 producing well locations within the 

Powder River basin in northeastern Wyoming, figure 34. 

Figure 34. Powder River basin example area.

Well location data was obtained from the Wyoming Oil and Gas Conservation 

Commission; producing wells are shown with a red cross, and abandoned wells 

are identified by a black cross, figure 35.
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Figure 35. Location of oil and gas wells within 5-mile radius of top producing well 

in the Powder River basin.

Irrigation data was obtained from the Wyoming Water Resources Center to 

identify irrigated agriculture and nonirrigated agriculture within the study area, 

figure 36. Within the 5-mile radius study area, there are 1,075 acres of irrigated 

agriculture and 6,219 acres of nonirrigated agriculture.

Based on the map data, produced water could be used locally within the study 

area to irrigate land or to convert nonirrigated land to irrigated land. It also could 

be possible to use pipelines to transport water to streams and rivers, identified by 

blue dashed lines in figure 36. There is also municipal and industrial water use 

within the study area that could be augmented with produced water.

8.2.3 Uinta-Piceance Basin Example

The map example was conducted within the Uinta-Piceance basin in eastern Utah, 

figure 37.

Oil and gas well location data for this study area was obtained from the Utah 

Department of Natural Resources – Oil, Gas, and Mining Division, figure 38.

There is limited agricultural water use in this area, so the most realistic beneficial 

use of produced water in this area is for streamflow augmentation by discharge 

from a pipeline, see figure 39. Surface discharge in this area falls within the 

Colorado River Basin and, therefore, has important implications for water 

managers within the Colorado River Basin.
103

Figure 36. Irrigated and nonirrigated agriculture within the study area.

Figure 37. Uinta-Piceance basin example study area.
104

Figure 38. Five-mile study radius for Piceance basin example.

Figure 39. Surface discharge beneficial use option for Uinta-Piceance 

study area.
105

While the maps presented in this section do not provide quantitative information 

regarding the feasibility or economics of treating and reusing produced water for 

beneficial uses, they do provide evidence that there is potential for multiple 

beneficial use options in many areas throughout the Western United States.

107

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