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Prepared for:

U.S. Department of Energy

National Energy Technology Laboratory

Under Contract W-31-109-Eng-38

Prepared by:

Argonne National Laboratory

John A. Veil

Markus G. Puder

Deborah Elcock

Robert J. Redweik, Jr.

January 2004 
Produced Water White Paper i 

TABLE OF CONTENT 

Executive Summary............................................................................................................ v 

1 Introduction............................................................................................................. 1 

1.1 What Is Produced Water? ................................................................................... 1 

1.2 Purpose................................................................................................................ 1 

1.3 Layout of White Paper........................................................................................ 2 

1.4 Acknowledgments .............................................................................................. 2 

2 Produced Water Characteristics.............................................................................. 3 

2.1 Major Components of Produced Water .............................................................. 3 

2.1.1 Produced Water from Oil Production ............................................................. 3 

2.1.2 Produced Water from Gas Production ............................................................ 4 

2.1.3 Produced Water from Coal Bed Methane (CBM) Production........................ 5 

2.2 Specific Produced Water Constituents and Their Significance.......................... 5 

2.2.1 Constituents in Produced Waters from Conventional Oil and Gas ................ 6 

2.2.1.1 Dispersed Oil .............................................................................................. 6 

2.2.1.2 Dissolved or Soluble Organic Components................................................ 6 

2.2.1.3 Treatment Chemicals .................................................................................. 7 

2.2.1.4 Produced Solids .......................................................................................... 8 

2.2.1.5 Scales .......................................................................................................... 8 

2.2.1.6 Bacteria ....................................................................................................... 8 

2.2.1.7 Metals.......................................................................................................... 8 

2.2.1.8 pH................................................................................................................ 9 

2.2.1.9 Sulfates........................................................................................................ 9 

2.2.1.10 Naturally Occurring Radioactive Material (NORM)................................ 9 

2.2.2 Constituents in Produced Waters from CBM Production............................... 9 

2.2.2.1 Salinity ...................................................................................................... 10 

2.2.2.2 Sodicity ..................................................................................................... 10 

2.2.2.3 Other Constituents .................................................................................... 10 

2.3 Impacts of Produced Water Discharges............................................................ 11 

2.3.1 Impacts of Discharging Produced Water in Marine Environment................ 11 

2.3.1.1 Acute Toxicity .......................................................................................... 12 

2.3.1.2 Chronic Toxicity ....................................................................................... 13 
Produced Water White Paper ii 

2.3.2 Impacts of Discharging CBM Produced Waters........................................... 13 

2.3.3 Other Impact Issues....................................................................................... 14 

3 Produced Water Volumes ..................................................................................... 17 

3.1 Water-to-Oil Ratio ........................................................................................... 17 

3.2 Factors Affecting Produced Water Production and Volume ............................ 18 

3.3 Volume of Produced Water Generated Onshore in the U.S. ............................ 19 

3.4 Volume of Produced Water Generated Offshore in the U.S............................. 22 

4 Regulatory Requirements Governing Produced Water Management................... 25 

4.1 Introductory Remarks ....................................................................................... 25 

4.2 Discharge of Produced Waters ......................................................................... 25 

4.2.1 Calculation of Effluent Limits ...................................................................... 26 

4.2.1.1 Effluent Limitation Guidelines (ELGs) .................................................... 26 

4.2.1.1.1 Onshore Activities ............................................................................. 27 

4.2.1.1.2 Coastal Subcategory .......................................................................... 27 

4.2.1.1.3 Offshore Subcategory ........................................................................ 28 

4.2.1.2 Discharges from CBM Operations............................................................ 28 

4.2.1.3 Water Quality-Based Limits ..................................................................... 29 

4.2.1.4 Calculation of Effluent Limits .................................................................. 29 

4.2.2 Regional General Permits ............................................................................. 29 

4.2.2.1 Region 4 — Eastern Gulf of Mexico ........................................................ 29 

4.2.2.2 Region 6 — Western Portion of the OCS of the Gulf of Mexico............. 30 

4.2.2.3 Region 6 — Territorial Seas of Louisiana ................................................ 31 

4.2.2.4 Region 9 — California.............................................................................. 31 

4.2.2.5 Region 10 — Alaska Cook Inlet............................................................... 32 

4.2.3 Ocean Discharge Criteria Evaluation............................................................ 32 

4.2.4 Other NPDES Permit Conditions.................................................................. 33 

4.3 Injection of Produced Water............................................................................. 33 

4.3.1 Federal UIC Program.................................................................................... 35 
Produced Water White Paper iii 

4.3.1.1 Area of Review (40 CFR § 144.55 & 146.6)........................................... 35 

4.3.1.2 Mechanical Integrity (40 CFR §§146.8 & 146.23(b)(3)) ........................ 35 

4.3.1.3 Plugging and Abandonment (40 CFR §146.10) ...................................... 36 

4.3.1.4 Construction Requirements (40 CFR §146.22) ....................................... 37 

4.3.1.5 Operating Requirements (40 CFR §146.23(a))........................................ 37 

4.3.1.6 Monitoring and Reporting Requirements (40 CFR §146.23(b) & (c)).... 37 

4.3.2 State UIC Programs ...................................................................................... 37 

4.3.2.1 Texas......................................................................................................... 38 

4.3.2.2 California .................................................................................................. 38 

4.3.2.3 Alaska ....................................................................................................... 39 

4.3.2.4 Colorado.................................................................................................... 39 

4.3.3 Bureau of Land Management Regulations ................................................... 39 

4.3.4 Minerals Management Service Requirements .............................................. 40 

5 Produced Water Management Options ................................................................. 42 

5.1 Water Minimization Options ............................................................................ 42 

5.1.1 Options for Keeping Water from the Wells.................................................. 43 

5.1.1.1 Mechanical Blocking Devices .................................................................. 43 

5.1.1.2 Water Shut-Off Chemicals........................................................................ 43 

5.1.2 Options for Keeping Water from Getting to the Surface.............................. 45 

5.1.2.1 Dual Completion Wells............................................................................. 45 

5.1.2.2 Downhole Oil/Water Separators............................................................... 46 

5.1.2.3 Downhole Gas/Water Separators.............................................................. 48 

5.1.2.4 Subsea Separation ..................................................................................... 49 

5.2 Water Recycle and Reuse Options.................................................................... 49 

5.2.1 Underground Injection for Increasing Oil Recovery ................................... 49 

5.2.1.1 Examples of Produced Water Use for Increasing Recovery..................... 50 

5.2.2 Injection for Future Use............................................................................... 50 

5.2.3 Use by Animals............................................................................................ 51 

5.2.3.1 Livestock Watering................................................................................... 51 

5.2.3.2 Wildlife Watering and Habitat.................................................................. 51 

5.2.3.3 Aquaculture and Hydroponic Vegetable Culture...................................... 51 
Produced Water White Paper iv 

5.2.4 Irrigation of Crops........................................................................................ 52 

5.2.4.1 Examples of Use of Produced Water for Irrigation .................................. 53 

5.2.5 Industrial Uses of Produced Water ............................................................... 53 

5.2.5.1 Dust Control.............................................................................................. 54 

5.2.5.2 Vehicle and Equipment Washing.............................................................. 54 

5.2.5.3 Oil Field Use............................................................................................. 54 

5.2.5.4 Use for Power Generation......................................................................... 54 

5.2.5.5 Fire Control............................................................................................... 55 

5.2.6 Other Uses.................................................................................................... 55 

5.3 Water Disposal Options................................................................................... 55 

5.3.1 Separation of Oil, Gas, and Water ................................................................ 56 

5.3.2 Treatment before Injection............................................................................ 57 

5.3.3 Onshore Wells.............................................................................................. 57 

5.3.3.1 Discharges under the Agricultural and Wildlife Water Use Subcategory 57 

5.3.3.2 Discharges from CBM Operations............................................................ 57 

5.3.3.3 Discharges from Stripper Wells................................................................ 58 

5.3.3.4 Other Onshore Options ............................................................................. 58 

5.3.4 Offshore Wells.............................................................................................. 59 

5.3.4.1 What Is Oil and Grease? ........................................................................... 59 

5.3.4.2 Offshore Treatment Technology............................................................... 60 

6 The Cost of Produced Water Management........................................................... 64 

6.1 Components of Cost.......................................................................................... 64 

6.2 Cost Rates ($/bbl) ............................................................................................. 65 

6.3 Offsite Commercial Disposal Costs.................................................................. 65 

6.4 Costs for Rocky Mountain Region Operators.................................................. 65 

6.5 Perspective of an International Oil Company................................................... 66 

7 References............................................................................................................. 69 
Produced Water White Paper v 

Executive Summary 

Produced water is water trapped in underground formations that is brought to the surface 

along with oil or gas. It is by far the largest volume byproduct or waste stream associated 

with oil and gas production. Management of produced water presents challenges and 

costs to operators. This white paper is intended to provide basic information on many 

aspects of produced water, including its constituents, how much of it is generated, how it 

is managed and regulated in different settings, and the cost of its management. 

Chapter 1 provides an overview of the white paper and explains that the U.S. Department 

of Energy (DOE) is interested in produced water and desires an up-to-date document that 

covers many aspects of produced water. If DOE elects to develop future research 

programs or policy initiatives dealing with various aspects of produced water, this white 

paper can serve as a baseline of knowledge for the year 2003. 

Chapter 2 discusses the chemical and physical characteristics of produced water, where it 

is produced, and its potential impacts on the environment and on oil and gas operations. 

Produced water characteristics and physical properties vary considerably depending on 

the geographic location of the field, the geological formation with which the produced 

water has been in contact for thousands of years, and the type of hydrocarbon product 

being produced. Produced water properties and volume can even vary throughout the 

lifetime of the reservoir. Oil and grease are the constituents of produced water that 

receive the most attention in both onshore and offshore operations, while salt content 

(expressed as salinity, conductivity, or total dissolved solids [TDS]) is also a primary 

constituent of concern in onshore operations. In addition, produced water contains many 

organic and inorganic compounds that can lead to toxicity. Some of these are naturally 

occurring in the produced water while others are related to chemicals that have been 

added for well-control purposes. These vary greatly from location to location and even 

over time in the same well. The white paper evaluates produced water from oil 

production, conventional natural gas production, and coal bed methane production. 

The many chemical constituents found in produced water, when present either 

individually or collectively in high concentrations, can present a threat to aquatic life 

when they are discharged or to crops when the water is used for irrigation. Produced 

water can have different potential impacts depending on where it is discharged. For 

example, discharges to small streams are likely to have a larger environmental impact 

than discharges made to the open ocean by virtue of the dilution that takes place 

following discharge. Regulatory agencies have recognized the potential impacts that 

produced water discharges can have on the environment and have prohibited discharges 

in most onshore or near-shore locations. 

Chapter 3 provides information on the volume of produced water generated. According 

to the American Petroleum Institute (API), about 18 billion barrels (bbl) of produced 

water was generated by U.S. onshore operations in 1995 (API 2000). Additional large 

volumes of produced water are generated at U.S. offshore wells and at thousands of wells 

in other countries. Khatib and Verbeek (2003) estimate that for 1999, an average of 210 
Produced Water White Paper vi 

million bbl of water was produced each day worldwide. This volume represents about 77 

billion bbl of produced water for the entire year. As part of this white paper, an effort 

was made to generate contemporary estimates of onshore produced water volume in the 

United States (for the year 2002). This was challenging in that many of the states did not 

have readily available volume information. The 2002 total onshore volume estimate of 

14 billion bbl was derived directly from the applicable state oil and gas agencies or their 

websites, where data were available. If volume estimates were not available from a state 

agency or website, an estimated volume was calculated for that state by multiplying 2002 

crude oil production by the average historic water-to-oil ratio for that state. 

The volume of produced water from oil and gas wells does not remain constant over time. 

The water-to-oil ratio increases over the life of a conventional oil or gas well. For such 

wells, water makes up a small percentage of produced fluids when the well is new. Over 

time, the percentage of water increases and the percentage of product declines. Lee et al. 

(2002) report that U.S. wells produce an average of more than 7 bbl of water for each 

barrel of oil. For crude oil wells nearing the end of their productive lives, water can 

comprise as much as 98% of the material brought to the surface. Wells elsewhere in the 

world average 3 bbl of water for each barrel of oil (Khatib and Verbeek 2003). Coal bed 

methane (CBM) wells, in contrast, produce a large volume of water early in their life, and 

the water volume declines over time. Many new CBM wells have been drilled and 

produced since the last national estimate was made via API’s 1995 study. CBM wells 

quickly produce much water but will not be counted through the estimation approach 

used in this white paper (2002 crude oil production  ́ historical water-to-oil ratio). The 

actual total volume of produced water in 2002 is probably much higher than the estimated 

14 billion bbl. 

Chapter 4 describes the federal and state regulatory requirements regarding discharge and 

injection. In 1988, the U.S. Environmental Protection Agency (EPA) exempted wastes 

related to oil and gas exploration and production (including produced water) from the 

hazardous waste portions of the Resource Conservation and Recovery Act. Produced 

water disposal generally bifurcates into discharge and injection operations. Most onshore 

produced water is injected into Class II wells for either enhanced recovery or for 

disposal. Injection is regulated under the Underground Injection Control (UIC) program. 

The EPA has delegated UIC program authority to many states, which then regulate 

injection activities to ensure protection of underground sources of drinking water. 

Most offshore produced water is discharged under the authority of general permits issued 

by EPA regional offices. These permits are part of the National Pollutant Discharge 

Elimination System (NPDES). They include limits on oil and grease, toxicity, and other 

constituents. Under a few circumstances, onshore produced water can be discharged. 

Generally these discharges are from very small stripper oil wells, CBM wells, or from 

other wells in which the produced water is clean enough to be used for agricultural or 

wildlife purposes. 

Chapter 5 discusses numerous options for managing produced water. The options are 

grouped into those that minimize the amount of produced water that reaches the surface, 
Produced Water White Paper vii 

those that recycle or reuse produce water, and those that involve disposal of produced 

water. The first group of options (water minimization) includes techniques such as 

mechanical blocking devices or water shut-off chemicals that allow oil to enter the well 

bore while blocking water flow. Also included in this group are devices that collect and 

separate produced water either downhole or at the sea floor. Examples include downhole 

oil/water or gas/water separators, dual-completion wells, and subsea separators. 

The second group of options (reuse and recycle) includes underground injection to 

stimulate additional oil production, use for irrigation, livestock or wildlife watering and 

habitat, and various industrial uses (e.g., dust control, vehicle washing, power plant 

makeup water, and fire control). When the first two groups of management options 

cannot be used, operators typically rely on injection or discharge for disposal. The last 

portion of Chapter 5 describes various treatment technologies that can be employed 

before the produced water is injected or discharged. 

Chapter 6 offers summary data on produced water management costs. Produced water 

management is generally expensive, regardless of the cost per barrel, because of the large 

volumes of water that must be lifted to the surface, separated from petroleum product, 

treated (usually), and then injected or disposed of. The components that can contribute to 

overall costs include: site preparation, pumping, electricity, treatment equipment, storage 

equipment, management of residuals removed or generated during treatment, piping, 

maintenance, chemicals, in-house personnel and outside consultants, permitting, 

injection, monitoring and reporting, transportation, down time due to component failure 

or repair, clean up of spills, and other long-term liabilities. The cost of managing 

produced water after it is already lifted to the surface and separated from the oil or gas 

product can range from less than $0.01 to at least several dollars per barrel. The white 

paper includes discussion of several references that provide ranges or produced water 

management costs. 

The white paper is supported by more than 100 references, many of which have been 

published in the past three years. 

 
Produced Water White Paper 1 

1 Introduction 

One of the key missions of the U.S. Department of Energy (DOE) is to ensure an 

abundant and affordable energy supply for the nation. As part of the process of 

producing oil and natural gas, operators also must manage large quantities of water that 

are found in the same underground formations. The quantity of this water, known as 

produced water, generated each year is so large that it represents a significant component 

in the cost of producing oil and gas. 

1.1 What Is Produced Water? 

In subsurface formations, naturally occurring rocks are generally permeated with fluids 

such as water, oil, or gas (or some combination of these fluids). It is believed that the 

rock in most oil-bearing formations was completely saturated with water prior to the 

invasion and trapping of petroleum (Amyx et al. 1960). The less dense hydrocarbons 

migrated to trap locations, displacing some of the water from the formation in becoming 

hydrocarbon reservoirs. Thus, reservoir rocks normally contain both petroleum 

hydrocarbons (liquid and gas) and water. Sources of this water may include flow from 

above or below the hydrocarbon zone, flow from within the hydrocarbon zone, or flow 

from injected fluids and additives resulting from production activities. This water is 

frequently referred to as “connate water” or “formation water” and becomes produced 

water when the reservoir is produced and these fluids are brought to the surface. 

Produced water is any water that is present in a reservoir with the hydrocarbon resource 

and is produced to the surface with the crude oil or natural gas. 

When hydrocarbons are produced, they are brought to the surface as a produced fluid 

mixture. The composition of this produced fluid is dependent on whether crude oil or 

natural gas is being produced and generally includes a mixture of either liquid or gaseous 

hydrocarbons, produced water, dissolved or suspended solids, produced solids such as 

sand or silt, and injected fluids and additives that may have been placed in the formation 

as a result of exploration and production activities. 

Production of coal bed methane (CBM) involves removal of formation water so that the 

natural gas in the coal seams can migrate to the collection wells. This formation water is 

also referred to as produced water. It shares some of the same properties as produced 

water from oil or conventional gas production, but may be quite different in composition. 

1.2 Purpose 

DOE’s Office of Fossil Energy (FE) and its National Energy Technology Laboratory 

(NETL) are interested in gaining a better understanding of produced water, constituents 

that are in it, how much of it is generated, how it is managed in different settings, and the 

cost of water management. DOE asked Argonne National Laboratory to prepare a white 

paper that compiles information on these topics. If DOE elects to develop future research 

programs or policy initiatives dealing with various aspects of produced water, this white 

paper can serve as a baseline of knowledge for the year 2003. 
Produced Water White Paper 2 

Thousands of articles, papers, and reports have been written on assorted aspects of 

produced water. Given enough time and money, it would be possible to develop a 

detailed treatise on the subject. However, DOE preferred a quick-turn-around evaluation 

of produced water and provided only a moderate budget. Therefore, this document is 

written to provide a good overview of the many issues relating to produced water. It 

includes a lengthy list of references that can lead the reader to more detailed information. 

1.3 Layout of White Paper 

The white paper contains five chapters that discuss various aspects of produced water: 

- Chapter 2 discusses the chemical and physical characteristics of produced water, 

where it is produced, and its potential impacts on the environment and on oil and gas 

operations. 

- Chapter 3 provides information on the volume of produced water generated in the 

United States. To the extent possible, the data is segregated by state and by major 

management option. 

- Chapter 4 describes the federal and state regulatory requirements regarding discharge 

and injection. 

- Chapter 5 discusses numerous options for managing produced water. The options 

are grouped into those that minimize the amount of produced water reaching the 

surface, those that recycle or reuse produce water, and those that involve disposal of 

produced water. 

- Chapter 6 offers summary data on produced water management costs. 

1.4 Acknowledgments 

This work was supported by DOE-FE and NETL under contract W-31-109-Eng-38. John 

Ford was the DOE project officer for this work. We also acknowledge the many state 

officials that provided information for the produced water volume and regulatory sections 

of the white paper. The authors thank Dan Caudle for his review of and comments on the 

white paper. 
Produced Water White Paper 3 

 

2 Produced Water Characteristics 

Produced water is not a single commodity. The physical and chemical properties of 

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

geological formation with which the produced water has been in contact for thousands of 

years, and the type of hydrocarbon product being produced. Produced water properties 

and volume can even vary throughout the lifetime of a reservoir. If waterflooding 

operations are conducted, these properties and volumes may vary even more dramatically 

as additional water is injected into the formation. 

This chapter provides information on the range of likely physical and chemical 

characteristics of produced water, how much they vary, and why they vary. The chapter 

also discusses the potential impacts of discharging produced water, particularly to the 

marine environment. 

Understanding a produced water’s characteristics can help operators increase production. 

For example, parameters such as total dissolved solids (TDS) can help define pay zones 

(Breit et al. 1998) when coupled with resistivity measurements. Also, by knowing a 

produced water’s constituents, producers can determine the proper application of scale 

inhibitors and well-treatment chemicals as well as identify potential well-bore or 

reservoir problem areas (Breit et al. 1998). 

2.1 Major Components of Produced Water 

Knowledge of the constituents of specific produced waters is needed for regulatory 

compliance and for selecting management/disposal options such as secondary recovery 

and disposal. Oil and grease are the constituents of produced water that receive the most 

attention in both onshore and offshore operations, while salt content (expressed as 

salinity, conductivity, or TDS) is a primary constituent of concern in onshore operations. 

In addition, produced water contains many organic and inorganic compounds. These 

vary greatly from location to location and even over time in the same well. The causes of 

variation are discussed in a later section. 

2.1.1 Produced Water from Oil Production 

Table 2-1 shows typical concentrations of pollutants in treated offshore produced water 

samples from the Gulf of Mexico (EPA 1993). These data were compiled by EPA during 

the development of its offshore discharge regulations and are a composite of data from 

many different platforms. The first column of data represents the performance for a very 

basic level of treatment (best practicable technology, or BPT) while the second column of 

data represents a more comprehensive level of treatment (best available technology, or 

BAT). The data show that many constituents are present. The organic and inorganic 

components of produced water discharged from offshore wells can be in a variety of 
Produced Water White Paper 4 

physical states including solution, suspension, emulsion, adsorbed particles, and 

particulates (Tibbetts et al. 1992). 

In addition to its natural components, produced waters from oil production may also 

contain groundwater or seawater (generally called “source” water) injected to maintain 

reservoir pressure, as well as miscellaneous solids and bacteria. Most produced waters 

are more saline than seawater (Cline 1998). They may also include chemical additives 

used in drilling and producing operations and in the oil/water separation process. 

Treatment chemicals are typically complex mixtures of various molecular compounds. 

These mixtures can include: 

- Corrosion inhibitors and oxygen scavengers to reduce equipment corrosion; 

- Scale inhibitors to limit mineral scale deposits; biocides to mitigate bacterial fouling; 

- Emulsion breakers and clarifiers to break water-in-oil emulsions and reverse 

breakers to break oil-in-water emulsions; 

- Coagulants, flocculants, and clarifiers to remove solids; and 

- Solvents to reduce paraffin deposits (Cline 1998). 

In produced water, these chemicals can affect the oil/water partition coefficient, toxicity, 

bioavailability, and biodegradability (Brendehaug et al. 1992). With increased 

development of subsea oil fields in the North Sea and the Gulf of Mexico, many of these 

additives will be required in larger amounts, to assure flow assurance in subsea pipelines 

(Georgie et al. 2001). 

2.1.2 Produced Water from Gas Production 

Produced water is separated from gas during the production process. In addition to 

formation water, produced water from gas operations also includes condensed water. 

Produced waters from gas production have higher contents of low molecular-weight 

aromatic hydrocarbons such as benzene, toluene, ethylbenzene, and xylene (BTEX) than 

those from oil operations; hence they are relatively more toxic than produced waters from 

oil production. Studies indicate that the produced waters discharged from gas/condensate 

platforms are about 10 times more toxic than the produced waters discharged from oil 

platforms (Jacobs et al. 1992). However, for produced water discharged offshore, the 

volumes from gas production are much lower, so the total impact may be less. The 

chemicals used for gas processing typically include dehydration chemicals, hydrogen 

sulfide-removal chemicals, and chemicals to inhibit hydrates. Well-stimulation 

chemicals that may be found in produced water from gas operations can include mineral 

acids, dense brines, and additives (Stephenson 1992). Significant differences between 

offshore oilfield produced water and offshore gas produced water exist for other 

parameters as well. For example, Jacobs et al. (1992) report that, in the North Sea, 

ambient pH is 8.1 and chlorides are about 19 g/L. Produced water discharges from oil 
Produced Water White Paper 5 

platforms in that area have pH levels of 6-7.7, while those from gas platforms are more 

acidic (about 3.5-5.5). Chloride concentrations range from about 12 to 100 g/L in 

produced water associated with crude oil production and from less than 1 to 189 g/L in 

produced waters associated with natural gas production. 

2.1.3 Produced Water from Coal Bed Methane (CBM) Production 

CBM produced waters differ from conventional oil and gas produced waters in the way 

they are generated, their composition, and their potential impact on receiving 

environments. Beneath the earth’s surface, methane is adsorbed onto the crystal surfaces 

of coal due to the hydrostatic pressure of the water contained in the coal beds. For the 

methane to be removed from the crystalline structure of the coal, the hydrostatic head, or 

reservoir pressure, in the coal seam must be reduced. CBM produced water is generated 

when the water that permeates the coal beds that contain the methane is removed. In 

contrast to conventional oil and gas production, the produced water from a CBM well 

comes in large volumes in the early stages of production; as the amount of water in the 

coal decreases, the amount of methane production increases. CBM produced water is 

reinjected or treated and discharged to the surface. 

The quality of CBM produced water varies with the original depositional environment, 

depth of burial, and coal type (Jackson and Myers 2002), and it varies significantly across 

production areas. As CBM production increases and more water is produced, concern 

about the disposition of these waters on the receiving environment is increasing, since 

uncertainties abound regarding the impact of these waters, as regulators and operators try 

to ensure protection of the environment. CBM constituent data are growing, and many 

states maintain files with produced water data. Sources include the Colorado Oil and Gas 

Conservation Commission, the Groundwater Information Center at the Montana Bureau 

of Mines and Geology, the Utah Division of Oil, Gas, and Mining, and the Wyoming Oil 

and Gas Conservation Commission. In addition, the U.S. Geological Survey (USGS) 

Produced Waters Database contains data on the composition of produced water and 

general characteristics of the volume of water produced from specific petroleumproducing provinces in the United States (Breit et al. 1998). The data were originally 

compiled by DOE and the Bureau of Mines, and the USGS has reviewed, verified, and 

evaluated the reliability and quality of the data. However, information on the actual 

impacts of CBM discharges — which depend not only on produced water characteristics, 

but also on the characteristics of the receiving environment — are not well understood. 

2.2 Specific Produced Water Constituents and Their Significance 

This section describes constituents typically found in produced waters, and, to the extent 

that information is available, why they are of concern. Constituents typically associated 

with produced waters from conventional oil and gas production are described first, 

followed by those associated with CBM produced waters. 
Produced Water White Paper 6 

2.2.1 Constituents in Produced Waters from Conventional Oil and Gas Production 

 

Organic constituents are normally either dispersed or dissolved in produced water and 

include oil and grease and a number of dissolved compounds. 

2.2.1.1 Dispersed Oil 

Oil is an important discharge contaminant, because it can create potentially toxic effects 

near the discharge point. Dispersed oil consists of small droplets suspended in the 

aqueous phase. If the dispersed oil contacts the ocean floor, contamination and 

accumulation of oil on ocean sediments may occur, which can disturb the benthic 

community. Dispersed oils can also rise to the surface and spread, causing sheening and 

increased biological oxygen demand near the mixing zone (Stephenson 1992). Factors 

that affect the concentration of dispersed oil in produced water include oil density, 

interfacial tension between oil and water phases, type and efficiency of chemical 

treatment, and type, size, and efficiency of the physical separation equipment (Ali et al. 

1999). Soluble organics and treatment chemicals in produced water decrease the 

interfacial tension between oil and water. Water movement caused by vertical mixing, 

tides, currents, and waves can affect the accumulation cycle. Also, because precipitated 

droplets are often 46 microns in size, and current treatment systems typically cannot 

remove droplets smaller than 10 microns, the small droplets can interfere with water 

processing operations (Bansal and Caudle 1999). 

2.2.1.2 Dissolved or Soluble Organic Components 

 

Deep-water crude has a large polar constituent, which increases the amount of dissolved 

hydrocarbons in produced water. Temperature and pH can affect the solubility of organic 

compounds (McFarlane et al. 2002). Hydrocarbons that occur naturally in produced 

water include organic acids, polycyclic aromatic hydrocarbons (PAHs), phenols, and 

volatiles. These hydrocarbons are likely contributors to produced water toxicity, and 

their toxicities are additive, so that although individually the toxicities may be 

insignificant, when combined, aquatic toxicity can occur (Glickman 1998). 

Soluble organics are not easily removed from produced water and therefore are typically 

discharged to the ocean or reinjected at onshore locations. Generally, the concentration of 

organic compounds in produced water increases as the molecular weight of the 

compound decreases. The lighter weight compounds (BTEX and naphthalene) are less 

influenced by the efficiency of the oil/water separation process than the higher molecular 

weight PAHs (Utvik 2003) and are not measured by the oil and grease analytical method. 

Volatile hydrocarbons can occur naturally in produced water. Concentrations of these 

compounds are usually higher in produced water from gas-condensate-producing 

platforms than in produced water from oil-producing platforms (Utvik 2003). 

Organic components that are very soluble in produced water consist of low molecular 

weight (C2-C5) carboxylic acids (fatty acids), ketones, and alcohols. They include acetic 
Produced Water White Paper 7 

and propionic acid, acetone, and methanol. In some produced waters, the concentration 

of these components is greater than 5,000 ppm. Due to their high solubility, the organic 

solvent used in oil and grease analysis extracts virtually none of them, and therefore, 

despite their large concentrations in produced water, they do not contribute significantly 

to the oil and grease measurements (Ali et al. 1999). 

Partially soluble components include medium to higher molecular weight hydrocarbons 

(C6 to C15). They are soluble in water at low concentrations, but are not as soluble as 

lower molecular weight hydrocarbons. They are not easily removed from produced water 

and are generally discharged directly to the ocean. They contribute to the formation of 

sheen, but the primary concern involves toxicity. These components include aliphatic 

and aromatic carboxylic acids, phenols, and aliphatic and aromatic hydrocarbons. 

Aromatic hydrocarbons are substances consisting of carbon and hydrogen in benzene-like 

cyclic systems. PAHs are hydrocarbon molecules with several cyclic rings. Formed 

naturally from organic material under high pressure, PAHs are present in crude oil. 

Naphthalene is the most simple PAH, with two interconnected benzene rings and is 

normally present in higher concentrations than other PAHs. (In Norwegian fields, for 

example, naphthalenes comprise 95% or more of the total PAHs in offshore produced 

water.) PAHs range from relatively “light” substances with average water solubility to 

“heavy” substances with high liposolubility and poor water solubility. They increase 

biological oxygen demand, are highly toxic to aquatic organisms, and can be 

carcinogenic to man and animals. All are mutagenic and harmful to reproduction. Heavy 

PAHs bind strongly to organic matter (e.g., on the seabed) contributing to their 

persistency (Danish EPA 2003). Higher molecular weight PAHs are less water soluble 

and will be present mainly in or associated with dispersed oil. Aromatic hydrocarbons 

and alkylated phenols are perhaps the most important contributors to toxicity (Frost et al. 

1998). Alkylated phenols are considered to be endocrine disruptors, and hence have the 

potential for reproductive effects (Frost et al. 1998). However, phenols and alkyl phenols 

can be readily degraded by bacterial and photo-oxidation in seawater and marine 

sediments (Stephenson 1992). 

A greater understanding is needed of the chemistry involved in the production and 

toxicity of soluble compounds. A Petroleum Environmental Research Forum (PERF) 

project is under way to characterize and evaluate water-soluble organics to help 

understand the production of these substances. The results may help develop means to 

reduce production of such organics (McFarlane et al. 2002). 

2.2.1.3 Treatment Chemicals 

Treatment chemicals posing the greatest concerns for aquatic toxicity include biocides, 

reverse emulsion breakers, and corrosion inhibitors. However, these substances may 

undergo reactions that reduce their toxicities before they are discharged or injected. For 

example, biocides react chemically to lose their toxicity, and some corrosion inhibitors 

may partition into the oil phase so that they never reach the final discharge stream 

(Glickman 1998). Nonetheless, some of these treatment chemicals can be lethal at levels 
Produced Water White Paper 8 

as low as 0.1 parts per million (Glickman 1998). In addition, corrosion inhibitors can 

form more stable emulsions, thus making oil/water separation less efficient. 

2.2.1.4 Produced Solids 

Produced water can contain precipitated solids, sand and silt, carbonates, clays, proppant, 

corrosion products, and other suspended solids derived from the producing formation and 

from well bore operations. Quantities can range from insignificant to a solids slurry, 

which can cause the well or the produced water treatment system to shut down. The 

solids can influence produced water fate and effects, and fine-grained solids can reduce 

the removal efficiency of oil/water separators, leading to exceedances of oil and grease 

limits in discharged produced water (Cline 1998). Some can form oily sludges in 

production equipment and require periodic removal and disposal. 

2.2.1.5 Scales 

Scales can form when ions in a supersaturated produced water react to form precipitates 

when pressures and temperatures are decreased during production. Common scales 

include calcium carbonate, calcium sulfate, barium sulfate, strontium sulfate, and iron 

sulfate. They can clog flow lines, form oily sludges that must be removed, and form 

emulsions that are difficult to break (Cline 1998). 

2.2.1.6 Bacteria 

Bacteria can clog equipment and pipelines. They can also form difficult-to-break 

emulsions and hydrogen sulfide, which can be corrosive. 

2.2.1.7 Metals 

The concentration of metals in produced water depends on the field, particularly with 

respect to the age and geology of the formation from which the oil and gas are produced. 

However, there is no correlation between concentration in the crude and in the water 

produced with it (Utvik 2003). Metals typically found in produced waters include zinc, 

lead, manganese, iron, and barium. Metals concentrations in produced water are often 

higher than those in seawater. However, potential impacts on marine organisms may be 

low, because dilution reduces the concentration and because the form of the metals 

adsorbed onto sediments is less bioavailable to marine animals than metal ions in solution 

(Stephenson 1992). Besides toxicity, metals can cause production problems. For 

example, iron in produced water can react with oxygen in the air to produce solids, which 

can interfere with processing equipment, such as hydrocyclones, and can plug formations 

during injection (Bansal and Caudle 1999) or cause staining or deposits at onshore 

discharge sites. 
Produced Water White Paper 9 

2.2.1.8 pH 

Reduced pH can disturb the oil/water separation process and can impact receiving waters 

when discharged. Many chemicals used in scale removal are acidic. 

2.2.1.9 Sulfates 

Sulfate concentration controls the solubility of several other elements in solution, 

particularly barium and calcium (Utvik 2003). 

2.2.1.10 Naturally Occurring Radioactive Material (NORM) 

NORM originates in geological formations and can be brought to the surface with 

produced water. The most abundant NORM compounds in produced water are radium226 and radium228, which are derived from the radioactive decay of uranium and 

thorium associated with certain rocks and clays in the hydrocarbon reservoir (Utvik 

2003). As the water approaches the surface, temperature changes cause radioactive 

elements to precipitate. The resulting scales and sludges may accumulate in water 

separation systems. In the North Sea, where ambient concentrations of Ra-226 are 0.027-

0.04 Bq/L, measured concentrations in produced waters range from 0.23 to 14.7 Bq/L 

(Utvik 2003). Radium contamination of produced water has generated enough concern 

that some states have placed additional requirements on National Pollution Discharge 

Elimination System (NPDES) permits that limit the amount of radium that can be 

discharged. Compounding the NORM concern is that chemical constituents in many 

produced waters can interfere with conventional analytical methods, and, as a result, 

radium components can be lost, leading to a false negative result for samples that may 

contain significant amounts of NORM (Demorest and Wallace 1992). 

2.2.2 Constituents in Produced Waters from CBM Production 

The mix of constituents that characterizes CBM produced waters differs from that 

characterizing conventional produced waters. This is not surprising, since produced 

water from oil production has been in direct contact with crude oil for centuries and is 

probably at a chemical equilibrium condition. In comparison, CBM water has been in 

direct contact with coal seams. Therefore, different compounds are likely to enter the 

water. 

Much of the CBM produced water may be put to beneficial use, but some of the 

constituents and their concentrations may limit the use of these waters in certain areas. 

The final determination of whether a CBM produced water can be used for agricultural 

purposes (generally irrigation or stock watering), for example, will depend not only on 

the quality of the produced water but also on the conditions of the receiving areas. These 

conditions include soil mineralogy and texture, amount of water applied, sensitivity of 

plant species, and the length of time the water has been stored in impoundments prior to 

use (ALL 2003). Some of the important characteristics of CBM produced water of 
Produced Water White Paper 10 

potential concern are salinity, sodicity, and toxicity from various metals. This is 

discussed further in Chapter 5. 

2.2.2.1 Salinity 

Salinity refers to the amount of total dissolved salts (TDS) in the water and is frequently 

measured by electrical conductivity (EC), because ions dissolved in water conduct 

electricity and actual TDS analyses are expensive to conduct. Waters with higher TDS 

concentrations will be relatively conductive. TDS is measured in parts per million or 

mg/L and EC is measured in micro-Siemens per centimeter (μS/cm). Irrigation waters 

that are high in TDS can reduce the availability of water for plant use, diminish the 

ability of plant roots to incorporate water, and reduce crop yield. Studies have identified 

the tolerance of various crops to salinity (Horpestad et al. 2001). EC levels of more than 

3,000 μS/cm are considered saline (ALL 2003). However, determining salinity threshold 

values depends on additional factors such as the leaching fraction. Thus, salinity 

threshold values of 1,000 μS/cm have been calculated for the Tongue and Little Bighorn 

Rivers and Rosebud Creek, while salinity thresholds of 2,000 μS/cm have been 

determined for the Powder and Little Powder Rivers and Mizpah Creek (Horpestad et al. 

2001). 

2.2.2.2 Sodicity 

Sodicity refers to the amount of sodium in the soil. Irrigation water with excess amounts 

of sodium can adversely impact soil structure and plant growth. The sodium adsorption 

ratio (SAR) is the standard measure of sodicity. It is a calculated parameter that relates 

the concentration of sodium to the sum of the concentrations of calcium and magnesium. 

The higher the SAR, the greater the potential for reduced permeability, which reduces 

infiltration, reduces hydraulic conductivity, and causes surface crusting. Irrigation waters 

with SAR levels greater than 12 are considered sodic (ALL 2003). 

2.2.2.3 Other Constituents 

Also important for determining the suitability of CBM produced water for irrigation are 

the concentrations of iron, manganese, and boron, which are often found in CBM 

produced water (ALL 2003). Table 2-2 shows concentration ranges of several 

constituents in CBM produced waters in the Powder River Basin. 

Besides crops, CBM produced waters may also affect native riparian and wetlands plants. 

The SAR thresholds developed to protect irrigation uses, which apply seasonally, may or 

may not protect the riparian uses, which are continually exposed to water. Because of the 

lack of data and the site-specific nature of these potential impacts, specific threshold 

values for protecting riparian plant communities have not been developed. 

In some cases, CBM may be considered for domestic supplies and drinking water. 

However, CBM produced waters from coal seams that are greater than 200 feet in depth 

often have water that exceeds salinity levels appropriate for domestic uses. This level is 
Produced Water White Paper 11 

about 3,000 mg/L. Also, water with high metals contents can stain faucets and drains. 

Water used by municipalities with treatment systems may have some of the harmful 

constituents removed or their concentrations reduced by existing processes in those 

treatment systems (ALL 2003). 

2.3 Impacts of Produced Water Discharges 

The previous sections outline the many chemical constituents found in produced water. 

These chemicals, either individually or collectively, when present in high concentrations, 

can present a threat to aquatic life when they are discharged or to crops when the water is 

used for irrigation. Produced water can have different potential impacts depending on 

where it is discharged. For example, discharges to small streams are likely to have a 

larger environmental impact than discharges made to the open ocean by virtue of the 

dilution that takes place following discharge. Numerous variables determine the actual 

impacts of produced water discharge. These include the physical and chemical properties 

of the constituents, temperature, content of dissolved organic material, humic acids, 

presence of other organic contaminants, and internal factors such as metabolism, fat 

content, reproductive state, and feeding behavior (Frost et al. 1998). The following 

sections discuss the potential impact based on where the discharges occur and the type of 

produced water. 

2.3.1 Impacts of Discharging Produced Water in Marine Environment 

Impacts are related to the exposure of organisms to concentrations of various chemicals. 

Factors that affect the amount of produced water constituents and their concentrations in 

seawater, and therefore their potential for impact on aquatic organisms, include the 

following (Georgie et al. 2001): 

- Dilution of the discharge into the receiving environment, 

- Instantaneous and long-term precipitation, 

- Volatilization of low molecular weight hydrocarbons, 

- Physical-chemical reactions with other chemical species present in seawater that 

may affect the concentration of produced water components, 

- Adsorption onto particulate matter, and 

- Biodegradation of organic compounds into other simpler compounds. 

Within the marine environment, it is necessary to distinguish between shallow, poorly 

flushed coastal areas and the open ocean. For coastal operations, the receiving 

environments can include shallow, nearshore areas, marshes, and areas with moderately 

flushed waters. Numerous studies have been conducted on the fate and effects of 
Produced Water White Paper 12 

produced water discharges in the coastal environments of the Gulf of Mexico (Rabalais et 

al. 1992). These have shown that produced waters can contaminate sediments and that 

the zone of such contamination correlates positively with produced water discharge 

volume and hydrocarbon concentration (Rabalais et al. 1992). Recognizing the potential 

for shallow-water impacts, EPA banned discharges of produced water in coastal waters 

with a phase-out period starting in 1997, except for the Cook Inlet in Alaska, where 

offshore discharge limits apply. Note that Cook Inlet has deep water and swift currents, 

thereby providing more than adequate dilution. However, although sediment 

contamination is evident at most studied locations, impacts on the benthic communities 

may be localized or not evident. 

For offshore operations, key factors include concentration of constituents and other 

characteristics of the constituents such as toxicity, bioavailability, and form. Actual fate 

and effects vary with volume and composition of the discharge and the hydrologic and 

physical characteristics of the receiving environment (Rabalais et al. 1992). The details 

of the regulations and relevant discharge permits are described in Chapter 4. 

A key concern is the potential for toxicity effects on aquatic organisms resulting from 

produced water discharges to marine and estuarine environments. Numerous toxicity 

studies have been conducted, and EPA continues to require a series of toxicity tests by 

each produced water discharger on the Outer Continental Shelf. 

A constituent may be toxic, but unless absorbed or ingested by an organism at levels 

above a sensitivity threshold, effects are not likely to occur. A more detailed discussion 

of the relationships, interactions, and uncertainties associated with bioconcentration, 

bioavailability, and bioaccumulation is beyond the scope of this paper. However, it is 

important to understand that translating produced water constituents into actual impacts is 

not a trivial exercise. 

2.3.1.1 Acute Toxicity 

The main contributors to acute toxicity (short-term effects) of produced water have been 

found to be the aromatic and phenol fractions of the dissolved hydrocarbons (Frost et al. 

1998). In addition, sometimes, particularly with deep offshore operations, existing 

separation equipment cannot remove all of the oil and grease to meet regulatory limits. 

In these cases, chemicals are used, but some of these chemicals can have toxic effects. 

The impacts of produced water and produced water constituents in the short term depend 

largely on concentration at the discharge point. 

They also depend on the discharge location. Deep-water discharges, for example, where 

there is rapid dilution, may limit the potential for detrimental biological effects and for 

bioaccumulation of produced water constituents. Several studies have indicated that the 

acute toxicity of produced water to marine organisms is generally low, except possibly in 

the mixing zone, due to rapid dilution and biodegradation of the aromatic and phenol 

fractions (Frost et al. 1998; Brendehaug 1992). Actual impacts will depend on the 

biological effect (e.g., toxicity, bioaccumulation, oxygen depletion) of the produced 
Produced Water White Paper 13 

water at the concentrations that exist over the exposure times found in the environment 

(Cline 1998). 

2.3.1.2 Chronic Toxicity 

Most of the EPA permits for offshore oil and gas operations require chronic toxicity 

testing. The results of this testing do not indicate any significant toxicity problem in U.S. 

waters. Some of the North Sea nations have focused their attention more heavily on the 

combined impact of many chemical constituents and have followed a different approach 

to produced water control. As an example, Johnsen (2003) and Johnsen et al. (2000) 

report on the various programs used in Norway to promote “zero environmental harmful 

discharges.” The latest in a series of developments is the environmental impact factor 

(EIF), which employs a risk-based approach to compare the predicted environmental 

concentration for each constituent with the predicted no-effect concentration. The EIF 

can be calculated using the Dose-related Risk and Effect Assessment Model (DREAM). 

This approach involves a great deal of quantitative work to evaluate each discharge. 

However, since there are relatively few offshore discharges in the Norwegian sector of 

the North Sea, this approach is viable there. In contrast, several thousand offshore 

discharges occur in the Gulf of Mexico, and such an approach would probably not be 

workable here. The Gulf of Mexico approach of chronic toxicity testing with limits 

provides acceptable controls. 

2.3.2 Impacts of Discharging CBM Produced Waters 

In areas where CBM produced waters have dissolved constituents that are greater than 

those in the receiving water, stream water quality impacts are possible. The impacts of 

CBM produced water have not been studied to the same extent as those of conventional 

oil and gas produced waters. However, potential water quality impacts of CBM produced 

waters include the following: 

- Surface discharges of CBM produced water can cause the infiltration of produced 

water contaminants to drinking water supplies or sub-irrigation supplies. 

- Surface waters and riparian zones can be altered as a result of CBM constituents. 

Here, the specific ionic composition is a greater determinant than total ion 

concentration (EPA 2001). 

- New plant species may take over from native plants as a result of changes in soils 

resulting from contact with CBM produced water. 

- Salt-tolerant aquatic habitats in ponded waters and surface reservoirs may 

increase. 

- Local environments can be altered as a result of excess soluble salts, which can 

cause plants to dehydrate and die. The impacts of salinity on the environment are 
Produced Water White Paper 14 

related to the amount of precipitation. Where rainfall is relatively abundant, most 

of the salts are flushed to the groundwater or surface streams and do not 

accumulate in soils. However, where precipitation levels are low, salts may be 

present at high concentrations in the soils and in the surface and groundwater. 

- Local environments can be altered as a result of excess sodicity. Excess sodicity 

can cause clay to deflocculate, thereby lowering the permeability of soil to air and 

water, and reducing nutrient availability. 

- Oxygen demand in produced water can overwhelm surface waters and reduce the 

oxygen level enough to damage aquatic species. 

2.3.3 Other Impact Issues 

Produced water constituents can affect both the environment and operations. Produced 

water volumes can be expected to grow as onshore wells age (the ratio of produced water 

to oil increases as wells age) and coal bed methane production increases to help meet 

projected natural gas demand. In addition, deep offshore production is expected to 

increase, and treating produced water prior to discharge may become increasingly 

difficult due to space limitations and motion on the rigs, which limit the use of 

conventional offshore treatment technologies. This growth will increase produced water 

management challenges for which a knowledge and understanding of the constituents of 

produced water and their effects will be critical. 

As the amount of produced water increases, the amount of produced water constituents 

entering the water will increase, even assuming concentration discharge limits are met. 

Also, because actual impacts of produced water constituents will depend on the produced 

water as a whole in the context of the environment into which it is released, it will be 

important to understand effects of site-specific produced waters rather than addressing 

individual components. A variety of potential additive, synergistic, and antagonistic 

effects of multiple constituents can affect actual impacts. 

Cross-media impacts can occur when technologies designed to address one 

environmental problem (e.g., discharge of produced water to the marine or onshore 

environment) create other problems (e.g., increased energy use, air emissions, 

contamination of aquifers from CBM reinjection), which could result in a greater net 

impact to the environment. 

 
Produced Water White Paper 15 

TABLE 2-1 Produced Water Characteristics Following Treatment 

Constituent 

Concentration after BPTLevel Treatment (mg/L)a

Concentration after BATLevel Treatment (mg/L) – 

Gas Flotation Treatmentb

Oil and grease 25 23.5 

2-Butanone 1.03 0.41 

2,4-Dimethylphenol 0.32 0.25 

Anthracene 0.018 0.007 

Benzene 2.98 1.22 

Benzo(a)pyrene 0.012 0.005 

Chlorobenzene 0.019 0.008 

Di-n-butylphthalate 0.016 0.006 

Ethylbenzene 0.32 0.062 

n-Alkanes 1.64 0.66 

Naphthalene 0.24 0.092 

p-Chloro-m-cresol 0.25 0.010 

Phenol 1.54 0.54 

Steranes 0.077 0.033 

Toluene 1.901 0.83 

Triterpanes 0.078 0.031 

Total xylenes 0.70 0.38 

Aluminum 0.078 0.050 

Arsenic 0.11 0.073 

Barium 55.6 35.6 

Boron 25.7 16.5 

Cadmium 0.023 0.014 

Copper 0.45 0.28 

Iron 4.9 3.1 

Lead 0.19 0.12 

Manganese 0.12 0.074 

Nickel 1.7 1.1 

Titanium 0.007 0.004 

Zinc 1.2 0.13 

Radium 226 (in pCi/L) 0.00023 0.00020 

Radium 228 (in pCi/L) 0.00028 0.00025 

a BPT = best practicable technology.

b BAT = best available technology. 

Source: EPA (1993). 
Produced Water White Paper 16 

TABLE 2-2 CBM Produced Water Characteristics in the Powder River Basin 

Constituent 

Minimum 

(mg/L) 

Maximum 

(mg/L) 

Mean 

(mg/L) 

TDS 270 2,010 862 

SAR 5.7 32 11.7 

Sodium 110 800 305 

Calcium 5.9 200 36 

Magnesium 1.6 46 16 

Iron 0.02 15.4 0.8 

Barium 0.1 8 0.6 

Chloride 3 119 13 

Sulfate 0.01 17 2.4 

Source: EPA (2001). 

 
Produced Water White Paper 17 

3 Produced Water Volumes 

In the United States, produced water comprises approximately 98% of the total volume of 

exploration and production (E&P) waste generated by the oil and gas industry and is the 

largest volume waste stream generated by the oil and gas industry. According to the 

American Petroleum Institute (API), about 18 billion barrels (bbl) of produced water was 

generated by U.S. onshore operations in 1995 (API 2000). Additional large volumes of 

produced water are generated at U.S. offshore wells and at thousands of wells in other 

countries. Khatib and Verbeek (2003) estimate that, in 1999, an average of 210 million 

bbl of water was produced each day worldwide. This volume represents about 77 billion 

bbl of produced water for the entire year. 

Natural gas wells typically produce much lower volumes of water than oil wells, with the 

exception of certain types of gas resources such as CBM or Devonian/Antrim shales. 

Within the Powder River Basin, the CBM produced water volume increased almost 

seven-fold during the period of 1998 through 2001 to more than 1.4 million bbl/day. 

Between 1999 and 2001, the volume of water produced per well dropped from 396 

bbl/day to 177 bbl/day (Advanced Resources 2002). However, as discussed below, these 

differences in the produced water volumes are to be expected because of how the CBM is 

produced. 

3.1 Water-to-Oil Ratio 

Lee et al. (2002) report that U.S. wells produce an average of more than 7 bbl of water 

for each barrel of oil. API’s produced water surveys in 1985 and 1995 (see Table 3-1) 

also demonstrated that the volume of water produced increases with the age of the crude 

oil production. In these surveys, API had calculated a water-to-oil ratio of approximately 

7.5 barrels of water for each barrel of oil produced. For the survey of 2002 production 

prepared for this white paper, the water-to-oil ratio was calculated to have increased to 

approximately 9.5. For crude oil wells nearing the end of their productive lives, 

Weideman (1996) reports that water can compromise as much as 98% of the material 

brought to the surface. In these stripper wells, the amount of water produced can be 10 to 

20 bbl for each barrel of crude oil produced. 

Wells elsewhere in the world average 3 bbl of water for each barrel of oil (Khatib and 

Verbeek 2003). The volume of produced water from oil and gas wells does not remain 

constant over time. The water-to-oil ratio increases over the life of a conventional oil or 

gas well. For such wells, water makes up a small percentage of produced fluids when the 

well is new. Over time, the percentage of water increases and the percentage of 

petroleum product declines. For example, Khatib and Verbeek (2003) report that water 

production from several of Shell’s operating units has increased from 2.1 million bbl per 

day in 1990 to more than 6 million bbl per day in 2002. At some point, the cost of 

managing the water becomes so high that the well is no longer profitable. 

In contrast, production of CBM, a growing source of natural gas in North America, 

follows a different pattern. CBM is produced by drilling into coal seams and pumping 
Produced Water White Paper 18 

off the water as quickly as possible to lower the hydrostatic pressure in the seam. This 

allows the methane trapped in the coal to move to the well bore, where it can be 

collected. The water production cycle for CBM starts out high as the hydrostatic pressure 

is reduced in the coal seam and gradually declines. Methane production starts low, then 

rises after water production peaks and declines. 

3.2 Factors Affecting Produced Water Production and Volume 

A discussion of the factors affecting produced water production is important because of 

the economic burden that it places on oil and gas operators. Produced water is an 

inextricable part of the hydrocarbon recovery process (Khatib and Verbeek 2003), so if 

an operator cannot optimize water management, a valuable resource may be lost or 

diminished. Management of produced water is a key issue because of its sheer volume 

and its high handling cost. In addition, even though produced water is naturally 

occurring, its potential environmental impacts could be substantial if not properly 

managed. 

The following factors can affect the volume of produced water during the life cycle of a 

well (Reynolds and Kiker 2003). This is not intended to be an all-inclusive list but 

merely a demonstration of the potential impacts. 

- Type of well drilled – A horizontal well can produce at higher rates than a vertical 

well with a similar drawdown or can produce at similar rates with a lower drawdown, 

thus delaying the entry of water into the well bore in a bottom water drive reservoir. 

- Location of well within reservoir structure – An improperly drilled well or one 

that has been improperly located within the reservoir structure could result in earlier than 

anticipated water production. 

- Type of completion – A perforated completion offers a greater degree of control 

in the hydrocarbon-producing zone. Specific intervals can either be targeted for 

increased hydrocarbon production or avoided or plugged to minimize water production. 

- Type of water separation and treatment facilities – Historically, surface separation 

and treatment facilities have been used for produced water management. However, this 

type of operation involves lifting costs to get the water to the surface as well as 

equipment and chemical costs for treatment of the water. Once on the surface, 

introduction of oxygen into the produced water treatment environment requires that 

corrosion and microbial issues be addressed. Alternatives to surface treatment could be 

downhole separation equipment that allows the produced water to remain downhole, 

thereby avoiding some of the lifting, surface facility, and corrosion costs and issues. 

- Water flooding for enhanced oil recovery – The basic purpose of water flooding is 

to put water in the reservoir where the oil is located so that it will be driven to a 

producing well. As the water flood front reaches a producing well, the volume of 

produced water will be greatly increased. In many instances, it is advantageous to shut in 
Produced Water White Paper 19 

these producing wells or convert them to injection wells so as not to impede the 

progression of the water front through the reservoir. 

- Insufficient produced water volume for water flooding – If insufficient produced 

water is available for water flooding, additional source waters must be obtained to 

augment the produced water injection. For a water flood operation to be successful, the 

water used for injection must be of a quality that will not damage the reservoir rock. In 

the past, freshwater was commonly used in water floods. Because of increasing scarcity, 

freshwater is typically no longer used as a viable source water for water flooding. 

Regardless of the source, the increased addition of this water to the reservoir will result in 

an increased volume of produced water. 

- Loss of mechanical integrity – Holes caused by corrosion or wear and splits in the 

casing caused by flaws, excessive pressure, or formation deformation can allow 

unwanted reservoir or aquifer waters to enter the well bore and be produced to the surface 

as produced water. 

- Subsurface communication problems – Near-well bore communication problems 

such as channels behind casing, barrier breakdowns, and completions into or near water 

can result in increased produced water volumes. Additionally, reservoir communication 

problems such as coning, cresting, channeling through higher permeability zones or 

fractures, and fracturing out of the hydrocarbon producing zone can also contribute to 

higher produced water volumes. 

Each of the above factors can greatly affect the volume of produced water that is 

ultimately managed during the life cycle of a well and project. With increased produced 

water volumes, the economic viability of a project becomes an issue, due to the loss of 

recoverable hydrocarbons, the added expense of lifting water versus hydrocarbons, the 

increased size and cost of water treating facilities and associated treatment chemicals, and 

the disposal cost of the water. With the consideration of water impacts to a project, 

proper planning and implementation can minimize these expenses or at least delay their 

impact. 

3.3 Volume of Produced Water Generated Onshore in the U.S. 

According to the API website (www.api.org), exploration and production activities take 

place at nearly 900,000 separate locations in 33 states and on the Outer Continental Shelf 

(OCS. Unfortunately, no single mechanism exists for tabulating the volume of produced 

water generated by the oil and gas industry. Although some states have started to track 

this information and have this information available electronically on their websites, most 

do not. The majority of states do track the volume of produced water that is injected, but 

do not track the volume of produced water that is managed in ways other than injection. 

Hence, produced water volume figures are generally available for enhanced recovery or 

disposal in injection wells, but these data are not typically readily available for the other 

management techniques such as: 
Produced Water White Paper 20 

- Treatment and discharge (under the National Pollutant Discharge Elimination 

System [NPDES] program), 

- Evaporation and percolation ponds, 

- Beneficial uses such as irrigation, livestock/wildlife watering, and industrial, 

- Injection into aquifer storage and recovery wells (domestic use), 

- Land application, and 

- Roadspreading. 

Although the states do regulate the management of produced water under this set of 

techniques, the volumes are typically not recorded in a single location for easy tracking. 

With the advent of major CBM developments during the recent decade, it was also 

difficult to distinguish between produced water volumes from conventional oil and gas 

production operations versus CBM operations. Because of the differences between 

conventional and CBM operations and the limitations placed on the preparation of this 

report, the produced water volumes documented in this report may be somewhat distorted 

because of how the estimates were made for those states that did not provide data. 

API (1988 and 2000) had similar data collection issues when it conducted a survey of the 

oil and gas industry to gather information about E&P wastes in 1985 and then again for 

its 1995 update. As a result, API was forced to conduct a statistical survey to gather the 

E&P waste data (including produced water volume) that it needed for its study. These 

studies examined the volume of produced water and other wastes generated as a result of 

oil and gas E&P in the U.S. and how those wastes were managed and disposed of. Due 

to the differences between onshore and offshore management of produced water (i.e., 

injection versus discharge), the API studies are focused on the onshore area. Currently, 

the vast majority of produced water generated at OCS locations is discharged overboard 

in accordance with NPDES discharge permits. 

For this report, an update of the volume figures was prepared for produced water 

generated in the year 2002 (see Table 3-1). For those states that did not have data 

available, estimates were prepared based on the average water-to-oil ratios that were 

calculated for each applicable state from the 1985 and 1995 API studies. Table 3-2 

shows crude oil production by state and is provided to aid in the calculation of these 

average water-to-oil ratios so that the produced water volumes could be estimated for 

each state that did not provide this data. 

Table 3-1 provides a summary of the onshore produced water volumes for 1985, 1995, 

and 2002. The 1985 and 1995 data were taken from the API surveys while the 2002 

numbers were obtained directly from the applicable state oil and gas agencies or their 

websites. If numbers were not available from the state agency or website, an estimated 
Produced Water White Paper 21 

volume was calculated as described above based on the average historic water-to-oil ratio 

for that state. The final column in Table 31 indicates which produced water volume 

numbers were calculated estimates and which were obtained directly from the states. 

Since the produced water estimates were made based on historic water-to-oil ratios from 

API’s 1985 and 1995 studies, the estimates for 2002 do not reflect the fact that while 

CBM operations generate produced water, they did not produce any crude oil. In 

addition, since CBM wells generate the greatest amount of produced water early in the 

life cycle of the well (the opposite of conventional oil and gas operations), the 2002 

estimates are likely somewhat lower than the actual volume of produced water generated. 

For example, data from Kansas (see Tables 3-1 and 3-2) indicated a steady decline in 

both crude oil and produced water production. However, despite a continued decline in 

crude oil production in 2002, the volume of produced water nearly doubled from the 

1995 figures. Further analysis of the data indicated the start of CBM operations in 

Kansas during the 2000/2001 timeframe, thus explaining the tremendous increase in 

produced water volume. We acknowledge this shortcoming for the 2002 data, but for 

the purposes of this white paper, we did not have the resources or time to develop more 

sophisticated estimates. 

The crude oil production volumes in Table 3-2 offer an indication of the direction in 

which the oil and gas industry is heading. In the decade between 1985 and 1995 (as 

documented in API’s studies), crude oil production declined a total of 15%, or an average 

of about 1.5% per year. However, in the period between 1995 and 2002 (as documented 

in this report), crude oil production declined at an even greater rate by 37%, or by an 

average of about 6% per year. As anticipated, oil production within the U.S. is declining 

at an increasing rate. Between 1985 and 2002, U.S. crude oil production had declined a 

total of 46%. 

Table 3-1 shows that between 1985 and 1995, the volume of produced water generated 

declined 13% (average of 1.3% per year). Between 1995 and 2002, the volume of 

produced water continued to decline but at a lesser rate than the decline in crude oil 

production. If the produced water from CBM operations could be segregated and 

excluded from these figures, the decline in produced water production would have likely 

been as steep as the crude oil production decline during this same period. However, since 

the states do not typically track these numbers separately, the different types of produced 

water could not be segregated for this report. A more in-depth analysis would likely be 

able to provide segregated CBM and conventional oil and gas produced water volume 

data. 

API’s 1995 study indicated that the management and disposal of E&P wastes was 

following a trend toward less discharge and more reuse, recycling, and reclamation (API 

2000). With the advent of no discharge criteria for produced water in coastal areas, 

nearly all produced water from conventional oil and gas operations onshore is being 

injected. API’s study indicated that approximately 71% of all produced water is being 

injected for enhanced recovery (beneficial use) while 21% is being injected for disposal. 

Hence, a total of 92% of all produced water generated is being returned to the subsurface 
Produced Water White Paper 22 

from whence it came. For the remaining produced water volume, 5% is either treated and 

discharged or beneficially used for irrigation, livestock/wildlife watering, and other uses. 

For the last 3% of the produced water, percolation and evaporation ponds are the 

identified method of disposal. 

The 2002 onshore volume of approximately 14 billion barrels of produced water 

demonstrates that the oil and gas industry continues to generate a tremendous volume of 

water that must be properly managed. 

3.4 Volume of Produced Water Generated Offshore in the U.S. 

We were not able to get an accurate current count of produced water generation in the 

U.S. Outer Continental Shelf. Some previously unpublished data shed some light on the 

subject. In a PowerPoint presentation, Intek (2001) offers some general statistics for 

offshore produced water volume in 1999 based on an analysis of Minerals Management 

Service data. In that year, there were 2,399 offshore oil wells and 1,228 offshore gas 

wells that produced water. A very large percentage of these wells were located in water 

depths less than 200 meters (oil 93%; gas 98%). Nearly all of the gas wells were very 

low water producers, generating less than 10 bbl/day of water. The oil wells showed 

considerably more variation, with most wells reported in several volume groupings 

ranging from 50 to 1,000 bbl/day. The median oil well produced water volume was 

approximately 200 bbl/day. A rough estimate of the typical produced water generation 

rate can be derived by multiplying the median oil well volume by the total number of oil 

wells producing water. This estimate is about 480,000 bbl/day, or 175 million bbl/year. 

This estimate is only an order-of-magnitude approximation as it omits consideration of 

the wells in water depth greater than 200 meters and all gas wells and some of the data 

are extrapolated from bar graphs. It is included in this white paper only for informational 

purposes. 

 
Produced Water White Paper 23 

TABLE 3-1 Annual Onshore Produced Water Generation by State (1,000 bbl) 

State 1985a 1995b 2002c Source 

 

Alabama 87,619 320,000 99,938 State 

Alaska 97,740 1,090,000 813,367 State 

Arizona 149 100 88 Estimate 

Arkansas 184,536 110,000 90,331 Estimate 

California 2,846,078 1,684,200 1,290,050 Estimate 

Colorado 388,661 210,600 133,005 Estimate 

Florida No data available 76,500 48,990 Estimate 

Illinois 1,282,933 285,000 212,098 Estimate 

Indiana No data available 48,900 34,531 Estimate 

Kansas 999,143 683,700 1,174,641 State 

Kentucky 90,754 3,000 2,411 Estimate 

Louisiana 1,346,675 1,346,400 1,079,805 State 

Michigan 76,440 52,900 33,207 Estimate 

Mississippi 318,666 234,700 286,532 State 

Missouri No data available 100 1,200 State 

Montana 223,558 103,300 104,501 Estimate 

Nebraska 164,688 61,200 51,191 State 

Nevada No data available 6,700 2,765 Estimate 

New Mexico 445,265 706,000 112,934 State 

New York No data available 300 844 State 

North Dakota 59,503 79,800 78,236 Estimate 

Ohio No data available 7,900 6,416 State 

Oklahoma 3,103,433 1,642,500 1,252,870 Estimate 

Pennsylvania No data available 2,100 5,842 State 

South Dakota 5,155 4,000 3,293 State 

Tennessee No data available 400 275 Estimate 

Texas 7,838,783 7,630,000 5,031,945 State 

Utah 260,661 124,600 84,791 Estimate 

Virginia No data available 300 550 Estimate 

W. Virginia 2,844 6,000 4,284 Estimate 

Wyoming 785,221 1,401,000 2,119,394 State 

TOTAL 20,608,505 17,922,200 14,160,325

a

 1985 produced water volume (barrels) from API (1988). 

b

 1995 produced water volume (barrels) from API (2000). 

c

 2002 produced water volume data from state oil and gas agencies/websites unless 

estimated based on historic water-to-oil ratio. 

 
Produced Water White Paper 24 

TABLE 3-2 Annual Crude Oil Production by State (1,000 bbl) 

State 1985a 1995b 2002c

 

Alabama 21,581 18,731 8,631

Alaska 651,599 541,654 359,335

Arizona 175 71 63

Arkansas 19,044 8,910 7,344

California 353,550 350,686 258,010

Colorado 30,246 27,976 17,734

Florida 11,458 5,693 3,656

Illinois 30,265 16,190 12,051

Indiana No data available 2,778 1,962

Kansas 75,407 43,767 32,721

Kentucky 7,790 3,492 2,679

Louisiana 158,806 426,322 93,477

Michigan 27,300 11,383 7,219

Mississippi 30,641 19,911 18,015

Missouri No data available 120 95

Montana 29,768 16,529 16,855

Nebraska 6,943 3,794 2,779

Nevada No data available 1,342 553

New Mexico 78,530 64,508 67,041

New York No data available 304 165

North Dakota 50,857 29,335 30,993

Ohio No data available 8,258 6,004

Oklahoma 162,739 87,491 66,642

Pennsylvania No data available 1,939 2,233

South Dakota 1,596 1,344 1,214

Tennessee No data available 382 275

Texas 867,122 600,527 411,985

Utah 40,792 19,988 13,676

Virginia No data available 12 22

W. Virginia 3,555 1,948 1,382

Wyoming 128,514 78,884 54,717

TOTAL 2,788,278 2,394,269 1,499,528

a

 1985 crude oil production from API (1988). 

b 1995 crude oil production from API (2000). 

c

 2002 crude oil production from IPAA data. 

 
Produced Water White Paper 25 

4 Regulatory Requirements Governing Produced Water Management 

4.1 Introductory Remarks 

In 1980, Congress conditionally exempted oil and gas E&P wastes, including produced 

water, from the hazardous waste management requirements of Subtitle C of the Resource 

Conservation and Recovery Act (RCRA) — RCRA Sections 3001(b)(2)(A), 8002(m). In 

addition to directing the U.S. Environmental Protection Agency (the EPA or the Agency) 

to study these wastes and submit a report to Congress on the status of their management, 

Congress required the Agency either to promulgate regulations under Subtitle C of 

RCRA or make a determination that such regulations were unwarranted. In 1988, the 

EPA published its regulatory determination in the Federal Register (FR) at 53 FR 25447 

(July 6, 1988). Produced water ranks first on the list of wastes that are generally exempt 

and warrant no regulation under Subtitle C of RCRA. The EPA states in the Code of 

Federal Regulations (CFR) that “produced wastewater” is among “[s]olid wastes which 

are not hazardous wastes” (40 CFR §261.4(b)(5)). The federal E&P RCRA Subtitle C 

exemption did however not preclude these wastes from control under other federal and 

state regulations (including oil and gas conservation programs and some hazardous waste 

programs) (EPA 2002). 

Produced water management generally bifurcates into discharge and injection operations. 

Most of onshore produced water is injected, while most of the offshore produced water is 

discharged and only some is injected. Section 4.2 discusses regulatory requirements for 

surface discharge of produced waters. Section 4.3 covers subsurface disposal of 

produced waters. 

4.2 Discharge of Produced Waters 

The Clean Water Act (CWA) requires that all discharges of pollutants to surface waters 

(streams, rivers, lakes, bays, and oceans) must be authorized by a permit issued under the 

National Pollutant Discharge Elimination System (NPDES) program. The two basic 

types of NPDES permits issued are individual and general permits. Individual NPDES 

permits are specifically tailored to individual facilities. General NPDES permits cover 

multiple facilities within a certain category located in a specific geographical area. 

Under the CWA, the EPA has the authority to implement the NPDES program. The 

Agency may authorize states — as well as territories and tribes — to implement all or 

parts of the national program. Once approved, a state gains the authority to issue permits 

and administer the program. However, the EPA retains the opportunity to review the 

permits issued by the state and formally object to elements deemed in conflict with 

federal requirements. Absent approval of a state, the EPA operates the NPDES program 

in direct implementation. 
Produced Water White Paper 26 

4.2.1 Calculation of Effluent Limits 

Numerical effluent limits present the primary mechanism for controlling discharges of 

pollutants to receiving waters. The EPA has grouped pollutants into three categories 

under the NPDES program: conventional pollutants (five-day biochemical oxygen 

demand, total suspended solids, pH, fecal coliform, and oil and grease), toxic or priority 

pollutants (including metals and manmade organic compounds), and nonconventional 

(including ammonia, nitrogen, phosphorus, chemical oxygen demand, and whole effluent 

toxicity). The effluent limits describe the pollutants subject to monitoring as well as the 

appropriate quantity or concentration of pollutants. Permit writers derive effluent limits 

from the applicable technology-based effluent limitation guidelines (ELGs) and water 

quality-based standards. The more stringent of the two will be written into the permit. 

4.2.1.1 Effluent Limitation Guidelines (ELGs) 

ELGs are national technology-based minimum discharge requirements. These standards 

are developed by EPA on an industry-by-industry basis and represent the greatest 

pollutant reductions that are economically achievable for an industry sector or portion of 

the industry (e.g., offshore oil and gas platforms). The selection of ELGs involves 

consideration of technologies that have already been demonstrated in industrial 

applications, costs and economic impacts, and non-water quality environmental impacts. 

ELGs are applied uniformly to every facility within the industrial sector, regardless of the 

location of the facility or the condition of the water body receiving the discharge. 

Existing facilities must meet a level of performance known as best available technology 

economically achievable (BAT) for toxic and nonconventional pollutants. 

The EPA has defined the BAT as the performance associated with the best control and 

treatment measures that have been, or are capable of being, achieved. While the EPA 

must still consider the cost of attainability in the context of BAT, it is not required to 

balance the implementation cost against the pollution reduction benefit. (For 

conventional pollutants only, BAT is replaced by best conventional pollutant control 

technology [BCT].) New facilities must meet new source performance standards 

(NSPS). NSPS reflect the most stringent limits based on performance of the state-of-theart technologies. 

The EPA has developed ELGs for most major industrial categories. For the oil and gas 

industry, EPA developed separate ELGs for onshore activities in 1979, offshore activities 

in 1993, and coastal activities in 1996. The terms onshore, offshore, and coastal may be 

illustrated by drawing an imaginary line that runs along the coast of a country. The line 

crosses the mouth of rivers, bays, and inlets. Any facility to the ocean side of the line is 

an offshore facility. Any facility to the land side of the line and located on land is 

classified as an onshore facility. Any facility in or on the water or in wetlands on the 

land side of the line is a coastal facility. For example, a facility located in a marsh or 

inside a river mouth or bay is a coastal facility. The EPA has codified the ELGs in the 

Code of Federal Regulations (CFR) at 40 CFR Part 435 — oil and gas extraction point 

source category. 
Produced Water White Paper 27 

4.2.1.1.1 Onshore Activities 

Pursuant to Subpart C of 40 CFR Part 435, oil and gas activities located onshore may not 

discharge produced waters into navigable waters. However, two other subcategories 

provide for tailored exceptions to the onshore rule. Subpart E of 40 CFR Part 435 

presents the agricultural and wildlife water use subcategory. The regulations apply to 

those onshore facilities located in the continental United States and west of the 98th 

meridian for which produced water is clean enough for use in agriculture or wildlife 

propagation when discharged into navigable waters. The 98th meridian extends from 

near the eastern edge of the Dakotas through central Nebraska, Kansas, Oklahoma, and 

Texas. Produced water with a maximum oil and grease limit of 35 mg/L may be 

discharged from such sites. However, this subcategory requires that the produced water 

is of good enough quality to be used for wildlife or livestock watering or other 

agricultural uses and that the produced water is actually put to such use during periods of 

discharge. An undetermined number (believed to be a small number) of Western oil and 

natural gas operators are discharging under NPDES permits that conform to the ELGs. 

Veil (1997a) notes that four states (California, Colorado, South Dakota, and Utah) 

indicated that they issued NPDES permits to facilities that could be classified under the 

agricultural and wildlife water use subcategory. 

The second exception that allows for onshore discharges is offered in Subpart F for the 

stripper subcategory. It applies to facilities that produce 10 barrels per day or less of 

crude oil. The EPA has published no national discharge standards for this subcategory, 

effectively leaving any regulatory controls to the primacy states or the EPA’s regional 

offices for direct implementation programs. The EPA’s decision to provide a window 

for small oil wells reflects the consideration to minimize the economic burden imposed 

by an across-the-board zero-discharge standard. The stripper subcategory appears 

inconsistent because it gives relief only to small oil wells and not to marginal gas wells 

(typically 60 thousand cubic feet per day or less). In the absence of any regulatory 

exception for marginal gas well discharges, such discharges fall under the general 

onshore standards of Subpart C. Veil (1997a) reports that, in 1997, six states (Kentucky, 

Nebraska, New York, Pennsylvania, Texas, and West Virginia) issued NPDES permits 

for produced water discharges from stripper wells. All six states limited oil and grease 

and pH, and some of the states placed limits on different combinations of total suspended 

solids, iron, chlorides, and other pollutants. 

4.2.1.1.2 Coastal Subcategory 

Oil and gas activities located in coastal waters may not discharge produced waters to the 

marine environment. This discharge prohibition does not apply to the Cook Inlet, Alaska 

(which is treated in the same manner as offshore waters). Table 4-1 presents the ELGs 

for the coastal subcategory. 
Produced Water White Paper 28 

TABLE 4-1 ELGs for Coastal Subcategory 

Stream 

Pollutant 

Parameter BAT NSPS 

Produced water – 

all coastal areas except 

Cook Inlet 

— No discharge No discharge 

Produced water – 

Cook Inlet 

Oil and grease 42 mg/L (daily maximum); 

29 mg/L (monthly average) 

42 mg/L (daily maximum); 

29 mg/L (monthly average) 

4.2.1.1.3 Offshore Subcategory 

 

Offshore oil and gas facilities are allowed to discharge produced waters to the sea. The 

ELGs are presented in Table 4-2. 

TABLE 4-2 ELGs for Offshore Subcategory

Stream 

Pollutant 

Parameter BAT NSPS 

Produced water Oil and grease 42 mg/L (daily maximum); 

29 mg/L (monthly average) 

42 mg/L (daily maximum); 

29 mg/L (monthly average) 

4.2.1.2 Discharges from CBM Operations 

CBM production activities are somewhat different from conventional gas production. The 

EPA did not consider CBM production when it established its ELGs and has not yet 

revised its ELGs to include CBM discharges. Thus, state regulatory agencies have been 

able to issue NPDES permits allowing discharges of CBM water using their own “best 

professional judgment.” Veil (2002b) describes the regulations that govern water 

discharges from CBM wells as wells as those that do not apply. That report also 

describes the permitting procedures and limitations used by Alabama, Wyoming, 

Montana, and Colorado. Each state follows somewhat different permitting procedures 

and has different discharge standards. The states place limits on or require monitoring 

for oil and grease, salinity (e.g., chlorides, TDS, or conductivity), pH, total suspended 

solids, and toxicity. They also require limits or monitoring for other contaminants. In 

most situations, those CBM producers that are currently discharging are able to provide a 

minimal degree of treatment and meet the permit limits. 

The regulatory requirements for discharging CBM produced water have been evolving 

along with the increased demand for CBM production and water discharges. Elcock et al. 

(2002) discuss the current and potential regulatory issues and requirements for managing 

CBM water as CBM production expands in the United States. EPA Region 8 has been 

developing a set of best professional judgment discharge guidelines for CBM water 

discharges on tribal lands. During a September 2001 public meeting, EPA discussed 

several water management options: discharge with erosion control and iron removal, 
Produced Water White Paper 29 

discharge following treatment with reverse osmosis, and injection (EPA 2001). EPA has 

not yet issued its final guidance for this topic. 

4.2.1.3 Water Quality-Based Limits 

The Clean Water Act prohibits the discharge of toxic substances in toxic quantities. This 

goal is accomplished through water quality-based effluent limits designed to ensure that 

ambient receiving water concentrations are low enough to maintain the designated use of 

the waters (e.g., fishing). 

4.2.1.4 Calculation of Effluent Limits 

ELGs serve as a foundation for the effluent limits included in a permit, but the ELGs are 

based on the performance of a technology and do not address the site-specific 

environmental effects of discharges. In certain instances, the technology-based controls 

may not be strict enough to ensure that the aquatic environment will be protected against 

toxic quantities of substances. In these cases, the permit writer must include additional, 

more stringent water quality-based effluent limits in NPDES permits. These water 

quality-based limits may be numeric (the EPA has published numeric water quality 

criteria for more than 100 pollutants that can be used to calculate water quality-based 

limits) or narrative (e.g., “no toxic substances in toxic quantities”). The process for 

establishing the limits takes into account the designated use of the water body, the 

variability of the pollutant in the effluent, species sensitivity (for toxicity), and, where 

appropriate, dilution in the receiving water (including discharge conditions and water 

column properties). 

4.2.2 Regional General Permits 

Four of the EPA’s regional offices have issued permits to facilities discharging into ocean 

waters beyond the three-mile limit of the territorial seas and may also issue permits to 

facilities in the territorial sea if the adjoining state does not have an approved NPDES 

program. Regional NPDES permits impose additional operational, monitoring, testing, 

and reporting requirements. The following describes the five most important general 

permits for oil and gas exploration, development, and production operations issued for 

the Eastern Gulf of Mexico (Region 4), Western Gulf of Mexico (Region 6), California 

(Region 9), and North Slope and Cook Inlet, Alaska (Region 10) (Veil 2001a). 

4.2.2.1 Region 4 — Eastern Gulf of Mexico 

General Permit GMG280000 applies to operators of lease blocks located in the Outer 

Continental Shelf (OCS) federal waters seaward of 200 meters in the Eastern Planning 

Area and seaward of the outer boundary of the territorial seas in the Central Planning 

Area with existing or new source discharges originating from oil and gas exploration or 

development and production operations. The general permit includes the following 

additional requirements related to produced water discharges: 
Produced Water White Paper 30 

- No discharge allowed within 1,000 meters of Area of Biological Concern, 

- Toxicity: 96-hour LC50 (concentration of test material that is lethal to 50% of the 

test organisms in a toxicity test after 96 hours of constant exposure) must not exceed 

critical concentrations, 

- Testing using two species: 

Mysid shrimp (Mysidopsis bahia) 

Inland silverside minnow (Menidia beryllina), 

- Critical dilutions based on water depth, pipe diameter, and flow rate, 

- Dilution calculated using CORMIX 2 model, and 

- Dilution can be increased by using a diffuser, adding seawater, or installing 

multiple discharge ports. 

 

4.2.2.2 Region 6 — Western Portion of the Outer Continental Shelf of the Gulf of 

Mexico 

General Permit GMG290000 applies to discharges from new and existing sources in the 

offshore subcategory of the oil and gas extraction point source category to the federal 

waters of the Gulf of Mexico seaward of the outer boundary of the territorial seas 

offshore off Louisiana and Texas. The general permit includes: 

- No discharge within Area of Biological Concern, 

- Toxicity: 7-day no observed effect concentration (NOEC) must not exceed 

concentration determined by using critical dilutions, 

- Testing using two species: 

Mysid shrimp (Mysidopsis bahia) 

Inland silverside minnow (Menidia beryllina), 

- Critical dilutions based on water depth, discharge depth, pipe diameter, and flow 

rate, 

- Dilution calculated using CORMIX model, 

- Dilution can be increased by using a diffuser, adding seawater, or installing 

multiple ports, 

- Frequency of testing based on volume of discharge. 
Produced Water White Paper 31 

4.2.2.3 Region 6 — Territorial Seas of Louisiana 

General Permit LAG260000 applies to discharges from new and existing sources in the 

offshore subcategory of the oil and gas extraction point source category to the territorial 

seas of Louisiana. The general permit, which has expired, but is administratively 

extended, includes: 

- No discharge allowed: 

To areas intermittently exposed 

In parks or wildlife refuges 

Within 1,300 feet of oyster or sea grass bed, 

- Toxicity similar to Region 6 (>3 miles offshore), 

- Other chemical monitoring: 

Benzene, lead, phenol, thallium, radium 226, radium 228, and 

- Limits based on dilution. 

 

4.2.2.4 Region 9 — California 

General Permit CAG280000 applies to discharges from oil and gas exploration, 

development, and production operations in federal waters offshore of California. The 

general permit, which is being reissued, includes: 

- Sample produced water for 26 chemicals and effluent toxicity to determine if 

those substances are likely to cause a water quality problem, 

- Determine available dilution using PLUMES-UM model, 

- Dilution can be increased by using a diffuser or adding seawater, 

- The EPA has already set limits on selected chemicals at some platforms, 

- Discharge volume limits are set for each platform, 

- Conduct study of on-line oil and grease monitors, 

- Toxicity requirements: 

Quarterly chronic testing with red abalone (Haliotis rufescens) 

Annual chronic testing with plant (giant kelp – Macrocystis pyrifera) and fish 

(topsmelt – Atherinops affinis), 

- The EPA will set separate NOEC limits for each platform based on dilution: 
Produced Water White Paper 32 

If limits are exceeded, must sample more frequently 

If limits are still exceeded, must undertake a toxicity reduction evaluation 

Identify sources of toxicity 

Take actions to mitigate toxicity 

Retest to confirm results, and 

- Study of impacts of produced water discharges on fish. 

4.2.2.5 Region 10 — Alaska Cook Inlet 

General Permit AKG285000 applies to discharges from oil and gas development and 

production facilities into state waters north of the Forelands in the Upper Cook Inlet and 

from exploratory facilities to all state and federal waters in Cook Inlet north of the line 

between Cape Douglas on the west and Port Chatham on the east. The general permit 

includes: 

- Study of impacts of produced water discharges on fish, 

- NOEC toxicity limits set for each platform, and 

- Annual chronic testing using three species: 

Inland silverside minnow (Menidia beryllina) 

Mysid shrimp (Mysidopsis bahia) 

Mussel (Mytilus sp.) or Pacific oyster (Crassostrea gigas) 

If limits are exceeded, must sample more frequently 

If limits are still exceeded, must undertake a toxicity reduction evaluation 

Identify sources of toxicity 

Take actions to mitigate toxicity 

Retest to confirm results. 

4.2.3 Ocean Discharge Criteria Evaluation 

Discharges into territorial seas, contiguous zone, and the oceans must undergo an 

additional level of review to ensure that they do not cause unreasonable degradation of 

the marine environment. The review is based on the EPA’s ocean discharge criteria 

regulations codified at Subpart M of 40 CFR Part 125. 

Before issuing an NPDES permit for discharges to the territorial seas, contiguous zone, 

and the oceans, the EPA must consider various factors, including: the quantities, 

composition, and potential for bioaccumulation or persistence of the pollutants to be 

discharged; the potential transport of such pollutants by biological, physical, or chemical 

processes; the composition and vulnerability of the biological communities that may be 

exposed to such pollutants; the importance of the receiving water area to the surrounding 

biological community (including the presence of spawning sites, nursery areas, and 
Produced Water White Paper 33 

migratory pathways); the existence of special aquatic sites such as marine sanctuaries and 

refuges, parks, national and historic monuments, national seashores, wilderness areas, 

and coral reefs; the potential impacts on human health through direct and indirect 

pathways; existing or potential recreational and commercial fishing; and numeric water 

quality criteria for specific pollutants. 

NPDES permits for facilities discharging into marine waters are required to include limits 

that prevent unreasonable degradation of the marine environment. In certain cases, that 

may mean a discharge prohibition. If insufficient information is available to conduct the 

degradation assessment, the EPA will determine whether the discharge will cause 

irreparable harm to the marine environment and whether reasonable alternatives to onsite 

disposal exist. When assessing the potential for irreparable harm, the EPA determines 

whether the facility is likely to cause permanent and significant harm to the environment 

on the basis of additional information collected during a monitoring period. If the 

potential for irreparable harm is low, the EPA may allow a monitoring program to 

demonstrate that the discharge will not cause unreasonable degradation. If the data 

gathered through monitoring indicate that continued discharge may cause unreasonable 

degradation, the discharge must be halted or additional permit limitations must be 

established. 

President Clinton’s Executive Order (E.O.) 13158, issued on May 26, 2000, states that 

the EPA “shall expeditiously propose new science-based regulations, as necessary, to 

ensure appropriate levels of protection for the marine environment.” In the wake of the 

E.O., the EPA developed a proposal that would have made the ocean discharge 

regulations more stringent. However, in early 2001, the EPA withdrew the proposal. 

4.2.4 Other NPDES Permit Conditions 

Facilities are responsible for taking the steps necessary to demonstrate compliance with 

NPDES permit limits. Permits instruct each facility operator regarding the frequency for 

collecting wastewater samples, the location for sample collection, the pollutants to be 

analyzed, and the laboratory procedures to be used in conducting the analyses. Detailed 

records of these “self-monitoring” activities must be retained by the facility for at least 

three years. Furthermore, each facility is required to submit the results of these analyses 

to the regulators on a periodic basis. For most facilities, the reporting frequency is 

monthly or quarterly, but in no case may it be less than once per year. NPDES permits 

may also require operational or environmental effects monitoring. This includes the 

preparation of best management practices plans or spill prevention plans. 

Inspectors from the EPA visit the offshore platforms occasionally to monitor their 

discharges and make sure that all operations are in compliance with permit requirements. 

Failure to meet the permit limits can result in fines or loss of the permit. 

4.3 Injection of Produced Water 

The Safe Drinking Water Act of 1974 (Part C, Sections 1421-1426) gave the EPA the 

authority for Underground Injection Control (UIC) regulation. The UIC program is 
Produced Water White Paper 34 

designed to protect underground sources of drinking water (USDWs). A USDW is an 

aquifer or portion of an aquifer that supplies any public water systems or contains 

sufficient quantity of groundwater to supply a public water system; currently supplies 

drinking water for human consumption or contains fewer than 10,000 milligrams/liter 

total dissolved solids; and is not an aquifer exempted from UIC regulations. 

For regulatory control purposes, underground injection is grouped into five classes of 

injection wells. An injection well is defined as any bored, drilled or a driven shaft or a 

dug hole, where the depth is greater than the largest surface dimension that is used to 

inject fluids underground. Class I wells are used for the emplacement of hazardous and 

nonhazardous fluids (industrial and municipal wastes) into isolated formations beneath 

the lowermost underground source of drinking water. Class I operations are the most 

strictly regulated by the SDWA and are further controlled by the Resource Conservation 

and Recovery Act. Class II wells inject brines and other fluids associated with oil and 

gas production. Class III wells inject fluids associated with solution mining of minerals. 

Class IV wells, which involve the injection of hazardous or radioactive wastes into or 

above a USDW, are banned unless authorized under other statutes for groundwater 

remediation. Class V wells include underground injection wells not included in Classes I 

through IV. Class V governs wells that inject nonhazardous fluids into or above a 

USDW — typically shallow, onsite disposal systems, such as floor and sink drains 

discharging directly or indirectly to ground water, dry wells, leach fields, and similar 

types of drainage wells. 

Wells used for injecting produced water are considered Class II wells. Class II 

subclasses include enhanced recovery wells (Class II-R) and disposal wells (Class II-D). 

Numerous fields are operated under an enhanced recovery mode when water, steam, or 

other substances are injected to a producing formation to help move the crude oil to wells 

for collection. These are typically water-flood or steam-flood operations. The 

application of enhanced recovery can prolong the productive life of certain hydrocarbon 

deposits (i.e., water-drive reservoirs) and increases the resource yield. In this scenario, 

produced water ceases being a waste and becomes a beneficial resource. Produced water 

can also be injected solely for disposal. In this case, the water is typically injected to a 

formation other than the producing formation. 

The EPA’s regulations establish minimum standards for state programs prior to receiving 

primary responsibility (primacy) for the UIC program under Section 1422 of the SDWA. 

(A state program can always be more stringent than the federal blueprint.) In 1981, 

Congress added Section 1425 to the SDWA, which relieves oil and gas-related injection 

well programs in the states from having to meet the technical requirements in the federal 

UIC regulations. (This reinforced the statutory instruction that the EPA not interfere with 

the production of oil and gas unless the requirements are essential for the protection of 

USDWs.) Instead, the demonstration can be made that the state has an effective program 

(including adequate oversight, record-keeping, and reporting) in place to prevent the 

endangerment of USDWs by underground injection operations. The EPA thus can 

approve delegation of the UIC program to the states in several ways, including for (1) all 

well classes under Section 1422 of the SDWA, (2) oil and gas injection wells under 

Section 1425 of the SDWA, and/or (3) all but oil and gas injection wells under Section 
Produced Water White Paper 35 

1422 of the SDWA. A state could have full delegation of the UIC program and have one 

portion for oil and gas injection wells approved under Section 1425 and another for the 

other types of wells under Section 1422 of the SDWA. Because the Section 1425 

approval route offers greater flexibility, most states have obtained UIC primacy in this 

manner. The EPA’s website reports that the Agency has approved program primacy for 

all well classes in 34 states, that it shares responsibility in six states, and that it directly 

implements the program for all well classes in 10 states. The Agency provides grant 

funds to all delegated programs to help pay for program costs. States must provide a 

25% match on EPA funds (EPA 2003). 

4.3.1 Federal UIC Program 

The application, construction, operating, monitoring, and reporting requirements for 

Class II wells are found in 40 CFR 144 and 146. Some key features of the EPA’s federal 

regulations are highlighted below. 

All Class II-D wells existing on the effective date of the UIC program implementation 

were required to apply for a permit during the first years (40 CFR §144.21). Class II-R 

wells existing at the effective date of the UIC program implementation maintain rule 

authorization for the life of the well, if the owner/operator complies with the regulations 

governing rule authorization (40 CFR §144.22). Every new Class II-D and Class II-R 

well must be permitted prior to construction or injection. The owner/operator must file a 

permit application with the UIC Director containing the specific information listed in 40 

CFR Part 146 (Kobelski 2003). 

4.3.1.1 Area of Review (40 CFR § 144.55 & 146.6) 

Applicants for new Class II injection well permits must identify the location of all known 

wells within the injection well’s area of review (AOR) that penetrate the injection zone, 

or in the case of Class II wells operating over the fracture pressure of the injection 

formation, all known wells within AOR penetrating formations affected by the increase 

in pressure. If the review of the available completion and plugging records for all wells 

within the AOR yields conditions or pathways suggesting the potential for migration of 

formation or injection fluids out of the injection zone, corrective or preventive action 

must be taken before using the injection well. 

The AOR analysis allows the permitting authorities to determine whether a proposed 

injection has the potential to contaminate USDWs through wells, faults, or other 

pathways penetrating the injection zone. For permit applications, the AOR is referenced 

through computing the zone of endangering influence or through determining a fixed 

radius of at least one quarter of a mile. 

4.3.1.2 Mechanical Integrity (40 CFR §§146.8 & 146.23(b)(3)) 

Owners/operators must demonstrate the internal and external integrity of their injection 

wells. This includes the absence of significant leakage in the casing, tubing, or packer of 
Produced Water White Paper 36 

the injection wells. Moreover, operators must show that there is no significant fluid 

movement into a USDW through vertical channels adjacent to the well bore. The 

regulations specify the types of mechanical integrity test (MIT) methods that are 

approved by the EPA. 

The methods used to evaluate the absence of leaks include: 

- Following an initial pressure test, monitoring of the tubing-casing annulus 

pressure with sufficient frequency to be representative, as determined by the 

Director, while maintaining an annulus pressure different from atmospheric 

pressure measured at the surface; 

- Pressure test with liquid or gas; or 

- Records of monitoring showing the absence of significant changes in the 

relationship between injection pressure and injection flow rate for the following 

Class II-R wells: 

o Existing wells completed without a packer, provided that a pressure test has been 

performed and the data is available and provided further that one pressure test shall be 

performed at a time when the well is shut down and if the running of such a test will not 

cause further loss of significant amounts of oil or gas; or 

o Existing wells constructed without a long string casing, but with surface casing 

that terminates at the base of freshwater provided that local geological and hydrological 

features allow such construction and provided further that the annular space shall be 

visually inspected. 

 

The methods used to evaluate the absence of significant fluid movement include: 

- The results of a temperature or noise log, or 

- For Class II only, cementing records demonstrating the presence of adequate 

cement to prevent such migration. 

The Director may approve alternative mechanical integrity test methods. Mechanical 

integrity must be demonstrated at least every five years. 

4.3.1.3 Plugging and Abandonment (40 CFR §146.10) 

Injection wells that have not been in operation for two years must be plugged and 

abandoned unless special precautions are taken to avoid endangerment of USDWs. Prior 

to abandonment, Class II wells must be plugged with cement in a manner that will not 

allow movement of fluids into or between USDWs. Owner/operators must maintain 

bonds or other financial instruments to assure that a well that is no longer needed can be 

appropriately plugged and abandoned. 
Produced Water White Paper 37 

4.3.1.4 Construction Requirements (40 CFR §146.22) 

All new Class II wells must be sited to inject into a formation that is separated from a 

USDW by a confining zone free of known open faults or fractures within the AOR. 

Class II wells must be cased and cemented to prevent fluid movement into or between 

USDWs. The regulations list several criteria that must be considered in determining 

casing and cementing requirements. Logs and other tests are required during the drilling 

and construction of new Class II wells. Moreover, a report interpreting the logs and tests 

must be submitted to the regulator. The regulations prescribe minimum requirements for 

the logs and tests. 

4.3.1.5 Operating Requirements (40 CFR §146.23(a)) 

The operating requirements in UIC Class II permits must specify a maximum injection 

pressure that will not initiate new fractures or propagate existing fractures in the 

confining zone adjacent to the USDWs. Injection pressure must not cause the movement 

of fluids into USDWs. Injection into the space between the outermost casing protecting 

USDWs and the well bore is prohibited. 

4.3.1.6 Monitoring and Reporting Requirements (40 CFR §146.23(b) & (c)) 

Owner/operators must monitor the nature of injected fluids (at least once within the first 

year of authorization, and thereafter whenever changes are made to the injection fluid); 

injection pressure, flow rate, and cumulative volume at various frequencies specified in 

the regulations (weekly for disposal wells and monthly for enhanced recovery wells); 

mechanical integrity (at least once every five years), and other operational statistics. 

Owner/operators must submit at least an annual report of the monitoring results. In 

addition, well failures or other well-specific activities (including corrective action) must 

be reported. 

4.3.2 State UIC Programs 

State regulations are similar to the federal regulations, but not necessarily exact 

replications. While state programs must be at least as stringent as the federal blueprint, 

states are free to impose more stringent requirements. In this light, UIC regulations 

administered by the states exhibit differences in regulatory definitions and technical 

standards when compared to the federal minimum standards established by the EPA. The 

variations stem from historic reasons, differing geologies, and other factors. Many states 

have been active in the regulation of underground injection operations long before the 

EPA promulgated the technical UIC regulations. Most state UIC Class II programs were 

approved under the alternative effectiveness route made available under Section 1425 of 

the SDWA. The states with the largest number of oil and gas injection wells are Texas 

(53,000) and California (25,000). The following presents information for Texas, 

California, Alaska, and Colorado. 
Produced Water White Paper 38 

4.3.2.1 Texas 

In Texas, the Railroad Commission of Texas (the RRC) enjoys primacy over the UIC 

Class II program. The main differences between the RRC and EPA’s UIC programs 

relate to AOR and MIT regulation. While the EPA prescribes checking all plugging and 

completion reports for cement across the injection zone, the RRC does not conduct full 

AOR checks in all cases. Due to staffing limitations, full AOR checks are done only in 

specific problem areas. The RRC MIT program is generally based on a five-year testing 

interval. However, the RRC requires annual testing for wells that do not meet the new 

construction standard for well construction and groundwater protection. The regulations 

governing Class II-D wells and Class II-R wells are almost identical. Minor differences 

stem from the groundwater depth jurisdiction language in the Texas Water Code for 

Class II-D and the Texas Natural Resources Code for Class II-R. All groundwater depth 

recommendations are made by the Texas Commission on Environmental Quality 

(TCEQ). The Class II-D groundwater depth recommendation (from TCEQ) includes a 

review of geologic separation for shallowest allowed disposal (250 feet of cumulative 

clay/shale between the disposal zone and deepest groundwater). In the case of Class IIR, the TCEQ groundwater recommendation does not consider the geologic separation 

issue. Instead, RRC staff review the geologic separation. In the event of inadequate 

separation, the permit will include a fluid source limit allowing re-injection only of the 

produced water from the same zone. In addition to groundwater depth, the requirements 

for Class II-D wells and Class II-R wells differ with respect to the packer setting depth. 

Class II-D packers must be set within 100 feet of the disposal zone. Class II-R packers 

are typically placed subject to the same 100-foot limit, but may be set further away if 

well construction, proximity to groundwater, and impermeable intervening strata allow 

(De Leon 2003). 

4.3.2.2 California 

In California, the Division of Oil, Gas, and Geothermal Resources (the Division) in the 

Department of Conservation enjoys primacy over the UIC Class II program. California 

has adopted a much narrower E&P waste exemption than at the federal level, expressly 

exempting only geothermal E&P wastes from the scope of its hazardous waste program. 

The exemption applies in California if the waste displays the toxicity characteristic for 

hazardous wastes based solely on the Toxicity Characteristic Leaching Procedure 

(TCLP). The exemption does not apply if the toxicity is determined based on criteria 

other than the TCLP or if the waste meets any of the other three characteristics of 

hazardous waste—ignitability, corrosivity, and reactivity. 

In consequence, E&P wastes that exhibit a hazardous characteristic or contain a 

hazardous waste may be regulated as hazardous wastes. In this light, the Division 

carefully reviews what fluids are deemed Class II fluids. This is especially important in 

enhanced recovery operations (for example, using polymers to seal off zones with fluid 

loss). Moreover, the Division prescribes shorter MIT time intervals. Water-disposal 

wells must be tested at least once each year, water flood wells every two years, and steam 

flood wells every five years. For purposes of testing external integrity, the Division does 
Produced Water White Paper 39 

not allow cement bond logs but generally requires radioactive tracer surveys (Stettner 

2003b). 

4.3.2.3 Alaska 

In Alaska, the Alaska Oil and Gas Conservation Commission (the AOGCC) enjoys 

primacy over the UIC Class II program. As such, AOGCC regulation of produced water 

injection does not differentiate between injection for purpose of disposal and injection for 

enhanced recovery. Any differences relative to AOR, MIT, plugging and abandonment, 

construction, operation, monitoring, and reporting are driven by the presence or absence 

of a USDW. For example, on the North Slope of Alaska, the AOGCC has the ability to 

relax some of the mechanical integrity and construction requirements for injection wells 

because there are no USDWs. Occasionally circumstances may call for a larger AOR 

than the typical 1⁄4-mile radius around an injector, but the determination is not driven by 

produced water operations. In practice, the AOGCC rarely deviates from the 1⁄4-mile 

radius, even when a USDW is not present. AOGCC regulators emphasize that the “real 

sticking points” enter the picture when one contrasts Class I wells and Class II wells in 

terms of the types of fluids eligible to be injected into Class II wells (Regg 2003). 

4.3.2.4 Colorado 

In Colorado, the Oil and Gas Conservation Commission (the COGCC) enjoys primacy 

over the UIC Class II program. As part of the AOR regulation, the COGCC, unlike many 

other states, requires the identification of all oil and gas wells currently producing from 

the proposed injection zone within 1⁄2 mile of the disposal zone. In terms of produced 

water injection regulation, the COGCC may make a distinction between Class II-D wells 

and Class II-R wells when it comes to the allowable maximum operating pressure, which 

will be established by the COGCC upon approval (Kobelski 2003). 

4.3.3 Bureau of Land Management Regulations 

The Bureau of Land Management (the BLM) in the U.S. Department of the Interior has 

jurisdiction over onshore leasing, exploration, development, and production of oil and gas 

on federal lands. In addition, the BLM approves and supervises most oil and gas 

operations on American Indian lands. The BLM regulations governing onshore oil and 

gas operations are codified at 43 CFR Part 3160 (onshore oil and gas operations). 

Onshore oil and gas orders (OOGOs) implement and supplement the regulations found at 

43 CFR Part 3160 for conducting oil and gas operations on federal or Indian lands. 

Notices to lessees (NTLs) implement and supplement the OOGOs and the regulations. 

Disposal of produced water is governed by Onshore Oil and Gas Order (OOGO) No. 7, 

published in the Federal Register on November 2, 1993, at 58 FR 58506. It applies to 

disposal of produced water from completed wells on federal and Indian (except Osage) 

oil and gas leases. It does not apply to approval of disposal facilities on lands other than 

federal or Indian lands. Separate approval under the OOGO is not required if the disposal 

method has been covered under an enhanced recovery project approved by the authorized 

officer. 
Produced Water White Paper 40 

Operators of onshore federal and Indian oil and gas leases may not dispose of produced 

water unless and until approval is obtained from the authorized officer. All produced 

water from federal and Indian leases must be disposed of (1) by injection into the 

subsurface; (2) into lined or unlined pits; or (3) by other acceptable methods approved by 

the authorized officer, including surface discharge under NPDES permits. Injection is 

generally the preferred method of disposal. 

Operators shall submit a Sundry Notice Form 3160 when they request approval for onlease disposal of produced water in injection wells and in lined or unlined pits. When 

requesting approval for removal of water and off-lease disposal on leased or unleased 

federal and Indian lands in a pit, operators shall submit a Sundry Notice Form 3160. If 

the water is to be disposed of in injection wells, operators must also submit a copy of the 

UIC permit (unless the well is authorized by rule). Off-lease disposal on state and 

privately owned lands requires submission of a Sundry Notice Form 3160-5, along with a 

copy of the UIC permit for injection wells or pit permit, as required. 

In addition, OOGO No. 7 identifies informational requirements for injection wells and 

pits; requirements governing pit design, construction, maintenance, abandonment, and 

reclamation; requirements for other disposal methods; and reporting requirements for 

disposal facilities. Operators may request variances from the standards of the OOGO. 

4.3.4 Minerals Management Service Requirements 

The Outer Continental Shelf Lands Act (OCSLA) established federal jurisdiction over 

submerged lands on the Outer Continental Shelf (OCS) seaward of state boundaries. 

Under the OCSLA, the Secretary of the U.S. Department of the Interior (DOI) is 

responsible for the administration of mineral exploration and development of the OCS. 

The Minerals Management Service (MMS), a DOI bureau, manages the nation’s natural 

gas, oil, and other mineral resources on the OCS. The Offshore Minerals Management 

program features three regions: Alaska, Gulf of Mexico, and the Pacific. 

Because no USDWs exist below the seabed of the OCS, the EPA’s UIC program does not 

apply. Instead, the MMS has regulated sub-seabed disposal separately. The MMS 

regulations governing oil and gas operations in the OCS are codified at 30 CFR Part 250 

(oil and gas and sulphur operations in the Outer Continental Shelf). Each application for 

underground waste disposal must be authorized on a case-by-case basis by the MMS (see 

30 CFR §250.300(b)(2)). Notices to lessees (NTLs) clarify, describe, or interpret 

offshore regulations or standards. NTLs also may provide guidelines on special lease 

stipulations, explain the MMS’s interpretation of requirements, or transmit administrative 

information. There are two types of NTLs, those issued at the regional level pertinent to 

a particular region and those issued nationally that are effective nationwide for all MMS 

regions. The MMS Gulf of Mexico OCS Region (GOMR) has published NTL No. 99-

G22, “Guidelines for the Sub-Seabed Disposal and Offshore Storage of Solid Wastes.” If 

operators plan to inject produced waters through underground injection wells for 

purposes of disposal, the receiving formation must be located below the deepest 
Produced Water White Paper 41 

underground source of drinking water, must be isolated above and below by shale layers, 

and may not contain any producing wells. Operators must demonstrate that injection 

wells have mechanical integrity. In contrast to disposal operations, reinjection of 

produced water for enhanced recovery is considered part of processing not subject to the 

NTL. MMS officials note that most produced water is discharged overboard (subject to 

all applicable requirements) and that enhanced recovery operations are in the majority of 

cases conducted through gas injection. 

 
Produced Water White Paper 42 

5 Produced Water Management Options 

There are many approaches to managing produced water; some of these are discussed in 

this chapter. The most appropriate option for a given location will be a function of several 

factors, including site location, regulatory acceptance, technical feasibility, cost, and 

availability of infrastructure and equipment. The primary alternatives being used today 

are underground injection, discharge, and beneficial reuse, although some other options 

are used at selected locations. Historically, produced water was managed in ways that 

were the most convenient or least expensive. Today, many companies recognize that 

water can be either a cost or a value to their operations. For example, Shell has 

established a formal Water-to-Value program through which the company attempts to 

minimize the production of water, reduce the costs of water treatment methods, and look 

for ways in which existing facilities can handle larger volumes of water (Khatib and 

Verbeek 2003). Greater attention to water management allows production of 

hydrocarbons and the concomitant profits to remain viable. 

The commonly used approaches for managing CBM water are somewhat different than 

those used for other onshore conventional gas and crude oil production. This is a 

function of different regulations and the disparate nature of the constituents in the 

produced water from the two types of production. The discussions in this chapter help to 

point out the various approaches used. 

This chapter discusses water management technologies and strategies in terms of a threetiered waste management or pollution prevention hierarchy (Veil 2002a). In the first tier 

(water minimization), processes are modified, technologies are adapted, or products are 

substituted so that less water is generated. When feasible, water minimization can often 

save money for operators and results in greater protection of the environment. For the 

water that is still produced following water minimization, operators next move to the 

second tier, in which water is reused or recycled. Some water cannot be recycled or 

reused and must be disposed of by injection or discharge. 

5.1 Water Minimization Options 

Within a producing formation, water and petroleum hydrocarbons are not fully mixed; 

they exist as separate adjacent fluid layers, with the hydrocarbon layer typically lying 

above the water layer by virtue of its lower specific gravity. Operators try their best to 

design wells to produce from the hydrocarbon layer. As hydrocarbons are removed from 

the formation, the pressure gradient changes so that the water layer often rises up in the 

vicinity of the well, creating a coning effect. As production continues, an increasing 

portion of the produced fluids will be water. 

It is challenging to minimize the amount of water produced into the well, but there are 

some strategies that can be used to restrict water from entering the well bore. These 

involve mechanical blocking devices or chemicals that “shut off” water-bearing channels 

or fractures within the formation and prevent water from making its way to the well. 
Produced Water White Paper 43 

Although they help to avoid production of water and its associated environmental 

impacts, they are generally considered to be in the realm of reservoir and production 

engineering activities rather than environmental management tools. 

5.1.1 Options for Keeping Water from the Wells 

5.1.1.1 Mechanical Blocking Devices 

Operators have used various mechanical and well construction techniques to block water 

from entering the well. Seright et al. (2001) offer several examples of these techniques: 

- Straddle packers, 

- Bridge plugs, 

- Tubing patches, 

- Cement, 

- Well bore sand plugs, 

- Well abandonment, 

- Infill drilling, 

- Pattern flow control, and 

- Horizontal wells. 

These have been used for many years, but do not work well in all applications. Operators 

often do not put forth the time or expense to diagnose the cause of their overabundant 

water. Consequently, incorrect solutions are not uncommon. For example, Seright et al. 

(2001) identify 13 types of events that lead to excess water; these are divided into four 

categories of most viable remedies. Seright et al. (2001) recommend that mechanical 

approaches can be used to block casing leaks or flow behind pipe without flow 

restrictions and unfractured wells with barriers to cross flow. Those approaches may not 

be effective in solving other types of water production problems. 

5.1.1.2 Water Shut-Off Chemicals 

Another approach to shutting off water production while allowing continued production 

of oil involves the use of chemicals that are injected into the formation. In its most basic 

sense, the process of waste minimization would not generally support introduction of new 

chemicals into the ground. In this case, however, the chemicals are introduced deep in 

the earth where they are unlikely to affect the biosphere, and they have a net beneficial 

impact. Therefore, this option is included under the water management options 

discussion. 

Most of these products are polymer gels or their pre-gel forms (gelants). Gel solutions 

selectively enter the cracks and pathways that the water follows and displace the water. 

When the gels set up in the cracks, they block most of the water movement to the well 

while allowing oil to flow to the well. Many different types of gels can be prepared, 

depending on the specific type of water flow that is being targeted. Thomas et al. (2000), 

Mack (2003), Seright et al. (2001) and Green et al. (2001) offer thoughts on the key 
Produced Water White Paper 44 

factors to be considered when designing and conducting a gel treatment. Some important 

considerations include: 

- The component ingredients: 

o Type of gel polymer (often a polyacrylamide polymer; also microbial products or 

lignosulfonate have been tried) 

o Type of crosslinking agent (metal ion or organic) 

o Fluid used to mix the gel (freshwater or produced water) 

- The properties of the gel (these may vary in several stages throughout gel 

treatment): 

o Concentration of polymer 

o Molecular weight of polymer 

o Degree of crosslinking 

o Viscosity (affects the size of cracks or fractures that can be penetrated at a given 

pressure; can inject as pre-mixed gel or as gelant) 

o Density (if density is too heavy, gel can sink too far into the water layer and lose 

effectiveness) 

o Set-up time (this determines how far into the cracks or fractures the gel will 

penetrate) 

- The treatment procedure: 

o Preparation of well before treatment 

o Volume of gel used 

o Injection pressure 

o Injection rate. 

In the United States, most of the polymer gel treatments are made in wells producing 

from fractured carbonate or dolomitic formations that operate under a natural water drive 

(Reynolds et al. 2002). Mack (2003) and Reynolds et al. (2002) suggest the following 

criteria for selecting candidate wells for gel treatments: 

- Wells already shut-in or near the end of their economic life, 

- Significant remaining mobile oil in place, 

- High water-oil ratio, 

- High producing fluid level, 

- Declining oil and flat water production, 

- Wells associated with active natural water drive, and 

- High-permeability contrast between oil- and water-saturated rock. 

The results of many successful gel treatment jobs have been reported in the literature. 

Seright et al. (2001) report on 274 gel treatments conducted in naturally fractured 

carbonate formations. The median water-to-oil ratio (WOR) was 82 before the treatment, 

7 shortly after the treatment, and 20 a year or two after treatment. The oil production 

increased following treatment and remained above pretreatment levels for 1 to 2 years. 

Thomas et al. (2000) report that an initial investment of $231,000 for gel treatments 
Produced Water White Paper 45 

resulted in incremental profits of $1.7-2.3 million over a two-year period. Green et al. 

(2001) report that following a series of gel treatments at four Kansas wells, which cost 

$14,000 to $18,000 per well, including polymer and well servicing costs, total oil 

production increased by about 30 barrels per day (bpd) while water production dropped 

by about 1,000 bpd. Lifting costs associated with the lower fluid volume were reduced 

about $300/month/well. With less stress on the lifting equipment, well servicing costs 

were also reduced about $2,400/year/well. Through mid-2000, about 37,500 bbl of 

incremental oil were economically recovered, representing about $1.60 per incremental 

bbl to date — and several years of production is still anticipated. The gel polymer 

treatments extended the lease economic life at least seven years. 

5.1.2 Options for Keeping Water from Getting to the Surface 

Lifting water to the surface represents a substantial expense for operators. The process of 

lifting and managing the water at the surface puts the water in a location where it can 

harm the land surface and surface or ground water resources. A variety of technologies 

have been developed that attempt to manage water either in the well bore itself or at a 

remote location like the sea floor. Although these technologies do not minimize the 

volume of water entering the well, they do minimize the volume of water that comes to 

the surface. Thus, they are also included under the water minimization discussion in this 

chapter. 

5.1.2.1 Dual Completion Wells 

Oil production can decline in a well because water forms a cone around the production 

perforations, limiting the volume of oil that can be produced. This situation can be 

reversed and controlled by completing the well with two separate tubing strings and 

pumps. The primary completion is made at a depth corresponding to strong oil 

production, and a secondary completion is made lower in the interval, at a depth with 

strong water production. The two completions are separated by a packer. The oil 

collected above the packer is produced to the surface, and the water collected below the 

packer is injected into a lower formation (Shirman and Wojtanowicz 2002; Wojtanowicz 

et al. 1999). This technology has also been called a downhole water sink. In another 

version of the process, the water can be separately produced to the surface for 

management there. 

Swisher (2000) reports on the performance of a dual-completion well compared to three 

wells with conventional completions in a north Louisiana field. Although the dualcompletion well cost about twice as much to install, it took the same or fewer number of 

months to reach payout as the other wells. At payout, it was producing 55 bpd of oil 

compared to about 16 bpd from the other three wells. The net monthly earnings at payout 

for the dual completion well were nearly $26,000 compared to $5,000 to $8,000 for the 

other wells. Wojtanowicz (2003) offers some additional examples from more 

complicated geological settings. 
Produced Water White Paper 46 

5.1.2.2 Downhole Oil/Water Separators 

Downhole oil/water separators (DOWS, also referred to as DHOWS) separate oil from 

water in the well bore itself. DOWS technology reduces the quantity of produced water 

that is handled at the surface by separating it from the oil downhole and simultaneously 

injecting it underground. A DOWS system includes many components, but the two 

primary ones are an oil/water separation system and at least one pump to lift oil to the 

surface and inject the water. Two basic types of DOWS have been developed—one type 

using hydrocyclones to mechanically separate oil and water and one relying on gravity 

separation that takes place in the well bore. 

Hydrocyclones use centrifugal force to separate fluids of different specific gravity 

without any moving parts. A mixture of oil and water enters the hydrocyclone at a high 

velocity from the side of a conical chamber. The subsequent swirling action causes the 

heavier water to move to the outside of the chamber and exit through one end, while the 

lighter oil remains in the interior of the chamber and exits through a second opening. The 

water fraction, containing a low concentration of oil (typically less than 500 mg/L), can 

then be injected, and the oil fraction along with some water is pumped to the surface. 

Hydrocyclone-type DOWS have been designed with electric submersible pumps, 

progressing cavity pumps, gas lift pumps, and rod pumps. 

Gravity separator-type DOWS are designed to allow the oil droplets that enter a well bore 

through the perforations to rise and form a discrete oil layer in the well. Most gravity 

separator tools are vertically oriented and have two intakes, one in the oil layer and the 

other in the water layer. This type of gravity separator-type DOWS uses rod pumps. As 

the sucker rods move up and down, the oil is lifted to the surface and the water is 

injected. During the past few years, three North Sea-based companies collaborated to 

develop a new class of gravity-separation DOWS that works by allowing gravity 

separation to occur in the horizontal section of an extended reach well. The downhole 

conditions allow for rapid separation of oil and water. Oil is lifted to the surface, while 

water is injected by a hydraulic submersible pump (Almdahl et al. 2000). 

DOE (FE and National Petroleum Technology Office [NPTO]) have actively promoted 

DOWS technology. Through DOE funding, Argonne National Laboratory conducted an 

independent evaluation of the technical feasibility, economic viability, and regulatory 

applicability of DOWS technology in 1999 (Veil et al. 1999). Only a modest number of 

DOWS systems have been installed throughout the world. Veil et al. (1999) provide 

information on the geology and performance of 37 of these installations, representing 

most of the installations that had been made through 1998. Some of the key findings 

from those installations are summarized below: 

- More than half of the installations were hydrocyclone-type DOWS (21 compared 

with 16 gravity separator-type DOWS). 

- Twenty-seven installations were in Canada and 10 were in the United States. 
Produced Water White Paper 47 

- Of the 37 DOWS trials described, 27 were in four producing areas—southeast 

Saskatchewan, east-central Alberta, the central Alberta reef trends, and East 

Texas. 

- Seventeen installations were in 5.5-inch casing, 14 were in 7-inch casing, 1 was in 

8.625inch casing, and 5 were unspecified. 

- Twenty of the DOWS installations were in wells located in carbonate formations, 

and 16 were in wells located in sandstone formations. One trial did not specify 

the lithology. DOWS appeared to work better in carbonate formations, showing 

an average increase in oil production of 47% (compared with an average of 17% 

for sandstone formations) and an average decrease in water brought to the surface 

of 88% (compared with 78% for sandstone formations). 

- The rate of oil production increased in 19 of the trials, decreased in 12, stayed the 

same in 2, and was unspecified in 4. The top three performing hydrocyclone-type 

wells showed oil production increases ranging from 457% to 1,162%, while one 

well lost all oil production. The top performing well improved from 13 to 164 

bpd. The top three gravity separator-type wells showed oil production increases 

ranging from 106% to 233%, while one well lost all oil production. The top 

performing well in this group improved from 3 to 10 bpd. 

- All 29 trials for which both pre-installation and post-installation water production 

data were provided showed a decrease in water brought to the surface. The 

decrease ranged from 14% to 97%, with 22 of 29 trials exceeding a 75% 

reduction. 

Argonne later ran a program for two years under which funds were offered to companies 

to subsidize the cost of installing DOWS systems in exchange for receiving detailed 

operating data. Only two companies participated in this program. The data from a 

gravity-separator-type DOWS trial in New Mexico (Veil 2000) and a hydrocyclone-type 

DOWS trial in Texas (Argonne and ALL 2001) are available on Argonne’s website at 

http://www.ead.anl.gov/ 

project/dsp_topicdetail.cfm?topicid=18. 

Several organizations have worked to develop a DOWS unit that separates fluids using a 

centrifuge. DOE funded development of a centrifugal DOWS by Oak Ridge National 

Laboratory (Walker and Cummins 1999), but this technology has not been tested in a 

full-scale field application. Chachula (2003) reported on a separate research effort that 

was expected (as of April 2003) to complete a prototype centrifugal DOWS by the fourth 

quarter of 2003. 

Since 1999, DOWS have been used sparsely, although several new designs have been 

tested (Veil 2001b). Two papers summarize the status of DOWS as of early 2003 (Veil 

2003; Chachula 2003). During the first half of 2004, Argonne will review the status of 
Produced Water White Paper 48 

DOWS and downhole gas/water separators for DOE and try to identify the types of 

geological formations in which DOWS perform most effectively. 

One of the applications for which DOWS could be used is to improve the water handling 

and production rate on a field-wide basis. To date, DOWS have not been used for this 

purpose. The following examples lead in that direction. 

In 1999, DOE awarded a large grant to Venoco, Inc., a southern California offshore 

producer, to conduct a pilot application using downhole water separation units attached to 

electric submersible pumps. The goal was to improve field economics and minimize 

water disposal in the South Ellwood Field, offshore from Santa Barbara, California. 

Venoco continues to work on reservoir and fracture characterization but does not plan to 

install a DOWS until one of its wells receives a workover about the first quarter of 2004 

(Horner 2003). 

A second application involves an innovative approach to recover more oil from a field in 

a shorter amount of time. The so-called π-mode production strategy (Ehlig-Economides 

and Economides 2000; Guerithault and Ehlig-Economides 2001) relies heavily on the use 

of downhole oil/water separators to reinject water into the same formations from which 

the fluids originated and maintain formation pressure. This process accelerates the rate of 

recovering the available oil. 

Chachula (2003) discusses use of a DOWS as part of a “smart well” system that would 

control real-time choking, plugging, isolation, and monitoring. He acknowledges that 

this is an expensive, complex, and unproven technology. 

5.1.2.3 Downhole Gas/Water Separators 

Several companies have marketed devices similar to DOWS for gas wells. These are 

known as downhole gas/water separators. The Gas Research Institute (now known as 

Gas Technology Institute) funded Radian International Corporation to prepare a 

“consumer guide” to downhole gas/water separation. The study was released in CD 

format in 1999 (GRI 1999). GRI found 53 commercial field tests involving 34 operators 

in the U.S. and Canada. Sixty percent of the tests used modified plunger rod pumps, 

while another 32% used bypass tools. Gas production rates were increased in 57% of the 

tests with 47% of the field tests termed successful, confirming that there is still 

significant risk. Half of the 42% failures were attributed to water cycling or poor 

injectivity issues. 

Produced water rates and well depth exert the primary influence on which the DWGS 

tool is appropriate. Bypass tools are appropriate for water volumes from 25 to 250 bpd 

and depths in the 2,000 to 8,000-foot range. Modified plunger rod pumps can handle 250-

800 bpd at depths in this range. Fully burdened costs for bypass tools and modified 

plunger rod pumps are about the same, in the $0.30 to $1.10/bbl range. For higher water 

rates above 800 bpd, electric submersible pumps are typically the most cost effective 

($0.20-0.40/bbl), especially at depths greater than 6,000 ft. 
Produced Water White Paper 49 

5.1.2.4 Subsea Separation 

This technology involves remote oil/water separation at the sea floor rather than 

downhole. A Norwegian company developed a subsea separation and injection system 

(SUBSIS) that separates the produced fluids from an offshore well at a treatment module 

located on the sea floor. Because size is not limited to the dimensions of a well bore, the 

SUBSIS equipment is much larger than the DOWS tools previously described. The 

SUBSIS module weighs 400 tons and is 17 meters long and wide and 6 meters high. The 

SUBSIS began full operation in August 2001 at Norsk Hydro’s Troll field, in water at a 

depth of 350 meters and about 4 kilometers from the Troll C platform. Initial results 

indicated that 23,000 bpd of produced fluids were separated into 16,000 bpd of oil and 

gas and 7,000 bpd of water. The water was injected into a dedicated injection well 

directly from the SUBSIS unit (Wolff 2000; Offshore 2000). Von Flatern (2003) reports 

the results of a year-long trial of the SUBSIS. During the trial, the SUBSIS handled a 

maximum flow of 60,000 bpd and a typical flow of 20,000 bpd. The oil concentration in 

the separated water stream dropped from an initial level of about 600 ppm to a much 

lower 15 ppm. Because the water injected from the SUBSIS did not need to come to the 

surface at the Troll platform and occupy some of its water handling capacity, the Troll 

platform was able to produce an additional 2.5 million bbl of oil during the year-long trial 

(von Flatern 2003). 

5.2 Water Recycle and Reuse Options 

In many cases, produced water can be put to other uses. Sometimes the water can be 

used without treatment, particularly when the produced water is very clean to start with 

(e.g., many samples of CBM water) or the end use does not require high water quality 

(e.g., some water flood projects). In many other cases, the water must be treated before it 

can be reused. The cost of treating the water to meet an end use is an important factor in 

determining the types of reuse options that will be considered. This section describes a 

variety of approaches to recycling and reusing produced water. A recent report that 

focuses on beneficial reuse of CBM produced water (ALL 2003) provides more detail on 

many of the options described throughout Section 5.2. 

5.2.1 Underground Injection for Increasing Oil Recovery 

The most commonly used approach for managing onshore produced water is reinjection 

into an underground formation. Although some produced water is injected solely for 

disposal, most produced water (71%) is injected to maintain reservoir pressure and to 

hydraulically drive oil toward a producing well. This practice is referred to as water 

flooding, or if the water is heated to make steam, as steam flooding. When used to 

improve oil recovery, produced water ceases being a waste and becomes a resource. 

Without that produced water to use, operators would need to use other surface or 

groundwater supplies as sources of water for the water or steam flood. Typically, for 

water flooding, sufficient produced water volumes may not be available for injection. In 

these instances, other sources of water must be used to supplement the water flooding 
Produced Water White Paper 50 

operation. Historically, freshwater sources have been used for this purpose. However, 

due to the increasing scarcity of this resource, other brines or water sources are now 

typically used in lieu of freshwater resources. 

5.2.1.1 Examples of Produced Water Use for Increasing Recovery 

Significant volumes of produced water are injected in the United States. Recent data, 

summarized below, were collected through interviews with staff from three state oil and 

gas agencies. Note that the volume estimates reported here vary somewhat from the 

volume estimates shown in Table 3-1 for these three states. Table 3-1 data are based on a 

later round of interviews, and may have involved different state officials. We have not 

been able to rectify the difference between the values. 

Although this section of the white paper focuses on reuse, the volume of water injected 

for disposal in the three states is included in the same discussions for the sake of 

comparison. The ratio of produced water volume injected for water and steam flooding 

to the volume injected for disposal ranges from 1.8:1 to 4.0:1 for these three states. 

California: California has nearly 25,000 produced water injection wells. The annual 

injected volume is approximately 1.8 billion bbl, distributed as follows: disposal wells – 

360 million bbl; water flood – 900 million bbl; and steam flood – 560 million bbl 

(Stettner 2003a). 

New Mexico: As of February 2003, New Mexico has 903 permitted disposal wells, with 

264 of them active. It has an additional 5,036 wells permitted for enhanced recovery, 

with 4,330 of those active. The approximate volume of produced water injected for 

disposal is 190 million bbl, and the volume injected for enhanced recovery is about 350 

million bbl (Stone 2003). 

Texas: As of February 2003, Texas has 11,988 permitted disposal wells, with 7,405 of 

them active. It has an additional 38,540 wells permitted for enhanced recovery, with 

25,204 of those active. The approximate volume of produced water injected in 2000 

(there were similar well counts in 2000 and 2003) was 1.2 billion bbl disposed into 

nonproducing formations, 1 billion bbl disposed into producing formations, and 5.3 

billion bbl injected for enhanced recovery (Ginn 2003). 

5.2.2 Injection for Future Use 

Some types of produced water are relatively fresh and can be used directly with little or 

no treatment. This is particularly true for produced water from some CBM fields. This 

water may be used immediately for beneficial reuse or it can be injected into an aquifer 

where it can be recovered for later use. This process is known as aquifer storage and 

recovery (ASR). The EPA treats ASR wells as Class V injection wells. In a 1999 

survey, the EPA identified at least 130 ASR wells in use throughout the country (EPA 

1999), although these were not injecting produced water. ALL (2003) suggests that ASR 
Produced Water White Paper 51 

wells could be potentially used for CBM produced water, but does not indicate if they are 

actually being used for that purpose. 

Brost (2002) describes an operation in the Kern River field of California in which a blend 

of produced water and treated groundwater is filtered then sent to the local water district 

for use in both irrigation and aquifer recharge. That paper offers no details on how the 

water is further treated or injected. 

5.2.3 Use by Animals 

Some produced water is clean enough to be used directly or after some degree of 

treatment by animals (i.e., livestock or wildlife) as a source of drinking water or, in the 

case of fish and waterfowl, as habitat. This section describes several possible alternatives 

for beneficial reuse for animals. 

5.2.3.1 Livestock Watering 

Livestock can tolerate a range of contaminants in their drinking water. At some 

concentrations, the animals, although still able to survive, will begin to show some 

impairment. ALL (2003) provides a table showing the total dissolved solids (TDS) levels 

that are appropriate for livestock watering. In general, animals can often tolerate a higher 

degree of TDS if they are gradually acclimated to the elevated levels. Water with TDS 

less than 1,000 ppm is considered to be an excellent source water. Water with TDS from 

1,000 up to 7,000 ppm can be used for livestock but may cause some diarrhea (ALL 

2003). Some CBM projects on ranch land have created impoundments or watering 

stations to provide CBM produced water as a drinking water source for livestock. ALL 

(2003) describes an example from the 7 Ranch near Gillette, Wyoming, in which 

livestock are watered by using small reservoirs and old heavy-vehicle tires as watering 

tanks. 

5.2.3.2 Wildlife Watering and Habitat 

Some Rocky Mountain area CBM projects have created impoundments that collect and 

retain large volumes of produced water. In some cases, these may have surface areas of 

at least several acres. These impoundments provide a source of drinking water for 

wildlife and offer habitat for fish and waterfowl in an otherwise arid environment. It is 

important to make sure that the quality of the impounded water will not create health 

problems for the wildlife. The impoundments can also provide additional recreational 

opportunities for hunting, fishing, boating, and bird watching. 

5.2.3.3 Aquaculture and Hydroponic Vegetable Culture 

Jackson and Myers (2002) report on greenhouse experiments to raise vegetables (not a 

use by animals, but placed in Section 5.2.3 for convenience) and fish using produced 

water or potable water as the water source. The system used a combination of 

hydroponic plant cultivation (no soil) and aquaculture. Tomatoes grown with produced 

water were smaller than those grown in potable water. The produced water tank grew a 
Produced Water White Paper 52 

larger weight of tilapia fish (Orechromis niuloticus/aureus), although some of the fish 

died. None of the fish in the potable water tank died. The tests showed that produced 

water could serve as a water source for vegetables and fish when other potable water 

sources are not available. 

5.2.4 Irrigation of Crops 

Many parts of the United States and around the world have limited freshwater resources. 

Crop irrigation is the largest single use of freshwater in the United States, making up 39% 

of all freshwater withdrawn, or 150 billion gallons per day (USGS 1998). If produced 

water has low enough TDS and other characteristics, it can be a valuable resource for 

crop irrigation. 

ALL (2003) summarizes crop irrigation water quality requirements, noting that the three 

most critical parameters are salinity (affects crops), sodicity (affects soil), and toxicity 

(affects crops). Salinity is expressed as electrical conductivity in units of mmhos/cm or 

more currently in microSiemens per cm (μS/cm). Crops have varying susceptibility to 

salinity; as salinity rises above a species-specific salinity threshold, crop yields decrease. 

Excess sodium can damage soils. Higher SAR values lead to soil dispersion and a loss of 

soil infiltration capability. When sodic soils are wet, they become sticky, and when dry, 

they form a crusty layer that is nearly impermeable. Paetz and Maloney (2002) describe 

an approach for treating CBM water to mitigate its salinity and sodicity problems so it 

can be used in a managed irrigation program. 

Some trace elements in produced water can cause harmful effects to plants when present 

in sufficient quantities. ALL (2003) suggests that the most common sources of plant 

toxicity are chloride, sodium, and boron. 

Another source of information on the effects of applying produced water to soils is a 

manual developed for the American Petroleum Institute on remediation of soils that had 

experienced produced water spills (API 1997). The authors of that manual have 

subsequently taught a series of workshops on the same subject. The manual is a detailed 

guide with much useful technical information on the impacts of salinity and sodium on 

soils and vegetation. 

Texas A&M University established a program to develop a portable produced water 

treatment system that can be moved into oil fields to convert produced water to potable or 

irrigation water. The goal is to produce water suitable for agricultural use (less than 500 

mg/L of total dissolved solids and less than 0.05 mg/L of hydrocarbons). Such a system 

not only augments scarce water supplies in arid regions, but also provides an economic 

payback to operators that could allow the well to produce longer (Burnett et al. 2002; 

Burnett and Veil 2004). 
Produced Water White Paper 53 

5.2.4.1 Examples of Use of Produced Water for Irrigation 

Wyoming: ALL (2003) provides two case examples from Wyoming of irrigation using 

CBM water. The first project was conducted by Fidelity Exploration and Production. 

They irrigated livestock forage using pure CBM water on some plots and CBM water 

blended with surface water on other plots. Both pure and blended irrigation water created 

adequate crop production. When pure CBM water was used, it needed to be applied at a 

higher rate because the plants could not utilize it as efficiently as the surface water. 

The second project was conducted by Williams, a CBM producer. Large land were 

irrigated areas that previously had supported only the local drought-tolerant vegetation. 

Following irrigation with CBM produced water, the land was able to support healthy 

grass crops to serve as feed for livestock. Williams provided gypsum and other soil 

supplements between waterings to counteract the high SAR in the produced water. 

A third project is described by DeJoia (2002). CBM produced water was used in a 

managed irrigation project. After two years of applying soil amendments and CBM 

water, the test sites were converted from overgrazed range land to highly productive 

grasslands with both livestock and wildlife benefits. 

California: Brost (2002) describes a complex system used by ChevronTexaco to treat 

produced water in the Kern River field in central California. The treatment system 

provides about 480,000 bpd of water that is used for irrigation of fruit trees and other 

crops and for recharging shallow aquifers. An additional 360,000 bpd of water is further 

purified and used to make steam at a cogeneration facility. 

Powder River Basin (state not specified): Paetz and Maloney (2002) describe a project 

using 12,500 bpd of CBM water to irrigate 100 acres of arid land to produce a forage 

crop using a carefully managed approach. The project successfully produced, harvested, 

and sold the forage crop. 

 

5.2.5 Industrial Uses of Produced Water 

In areas where traditional surface and groundwater resources are scarce, produced water 

may be substituted in various industrial practices as long as the quality of the produced 

water meets the needs of the industrial process with or without treatment. Produced 

water is already being used for several industrial uses and may be suitable for others. 

These are discussed in this section. 
Produced Water White Paper 54 

5.2.5.1 Dust Control 

In most oil fields, the lease roads are unpaved and can create substantial dust. Some oil 

and gas regulatory agencies allow operators to spray produced water on dirt roads to 

control the dust. This practice is generally controlled so that produced water is not 

applied beyond the road boundaries or within buffer zones around stream crossings and 

near buildings. 

CBM produced water may be generated in areas with active surface coal mining. Surface 

mining, processing, and hauling are inherently dusty activities. Produced water can be 

used for dust suppression at those locations, too, if regulators allow the practice 

(Murphree 2002). 

5.2.5.2 Vehicle and Equipment Washing 

ALL (2003) notes that some state and federal agencies recommend that vehicles and 

equipment leaving production sites be washed to control the possibility of distributing 

seeds of undesirable weed species. ALL does not state if CBM produced water is 

actually being used for this purpose at the present time. 

5.2.5.3 Oil Field Use 

Peacock (2002) describes a program in New Mexico through which produced water is 

treated to remove hydrogen sulfide and then is used in drilling operations. This 

beneficial reuse saves more than 4 million bbl per year of local groundwater. 

5.2.5.4 Use for Power Generation 

In at least one case, produced water is used to supply water to make steam. About 

360,000 bpd of produced water from a ChevronTexaco facility in central California is 

softened and sent to a cogeneration plant as a source of boiler feed water (Brost 2002). 

Another potential use of produced water is cooling water. The electric power industry is 

the second largest user of freshwater in the United States, making up 38% of all 

freshwater withdrawn, or 150 billion gallons per day (USGS 1998). Conventional 

surface and ground water sources are no longer sufficient to meet increasing power plant 

needs in many parts of the country. Produced water represents a large-volume source of 

water that could potentially serve as make-up water for a power plant. In August 2003, 

DOE/NETL announced that it had awarded a contract to a group of researchers led by the 

Electric Power Research Institute to study the feasibility of using water produced from 

CBM production to meet up to 25% of the cooling water needs at the San Juan 

Generating Station in northwestern New Mexico. The researchers will evaluate the 

quality, quantity, and location of the produced water. They will also evaluate the existing 

produced water collection, transportation, and treatment systems for possible use in 
Produced Water White Paper 55 

delivering cooling water to the generating station. The results are expected in about two 

years. 

Argonne National Laboratory recently completed a study that evaluates the use of another 

alternative type of water supply for power plant cooling (Veil et al. 2003). Although that 

study considers underground pools formed in abandoned coal mines, many of the report’s 

discussions concerning water quality, water quantity, and mode of operation are relevant 

for using produced water as a cooling source. 

5.2.5.5 Fire Control 

Fires often break out during the driest portions of the year and in areas experiencing 

drought conditions. In many cases, only limited surface and ground water resources are 

available for fire fighting in these areas. Although application of large volumes of saline 

produced water can have an impact on soils, this impact is far less devastating than a 

large fire. ALL (2003) reports that firefighters near Durango, Colorado, used CBM 

produced water impoundments as sources of water to fill air tankers (helicopters that 

spray water onto fires) during the summer of 2002. 

5.2.6 Other Uses 

When water is scarce, its value increases. In water-poor areas, it may be cost-effective to 

treat produced water for use in many applications. It is likely that the range of potential 

uses will be expanded in the future. This is clearly an area where additional research 

could be fruitful. 

5.3 Water Disposal Options 

Ideally, operators will find cost-effective produced water management approaches that 

employ water minimization, recycling, or reuse. However, much of the world’s produced 

water is not managed in those ways. Instead, it is disposed of through either discharge to 

surface water bodies or by underground injection. Although there certainly are 

exceptions, the following premises generally apply: 

- Most U.S. onshore oil and natural gas well operators inject their produced water 

for either enhanced recovery or for disposal. To a large extent, this is necessary because 

discharge from most onshore wells is prohibited. 

- Many U.S. CBM well operators try to discharge produced water to surface water 

bodies if they can obtain permission to do so. Section 5.2 outlined many ways in which 

CBM water can be reused. Future requirements to treat CBM water to meet more 

restrictive discharge standards may change the mix of options used. 

- Most U.S. offshore operators discharge produced water to the ocean if they are 

permitted to do so. Offshore produced water is also typically discharged in other parts of 

the world. Not surprisingly, different countries employ different discharge standards. A 

small percentage of offshore produced water is used for enhanced recovery operations. 
Produced Water White Paper 56 

Occasionally disposal of untreated produced water is possible. In most cases, however, it 

is necessary to treat the produced water first. The type and extent of treatment are 

determined by a variety of factors: 

- Where the water is going (e.g., freshwater surface water body, ocean, ground), 

- The applicable regulatory requirements and allowable options, 

- The cost to transport and treat the water, 

- Site-specific factors (e.g., climate, availability of infrastructure), 

- The potential for long-term liability, and 

- A company’s familiarity with or preference for specific options. 

The remainder of this section describes different types of injection and discharge 

situations and the treatment technologies that are typically used before the produced 

water can be disposed of in those ways. 

5.3.1 Separation of Oil, Gas, and Water 

When reservoir fluids are produced to the surface, it is first necessary to segregate the oil, 

gas, and water into separate streams to maximize salable product. This is typically 

accomplished by gravity separation in a horizontal or vertical separator. A common type 

of separator is known as a free-water knockout tank. The gas stream is first removed. 

Historically, gas was often burned (flared) or, at many wells, it was provided to the 

landowner for domestic use. Today, the gas is often collected and sent to market where 

gathering lines are available. The marketable gas is generally treated to meet pipelinequality standards at a gas processing plant. 

The separated oil stream may contain some water, and the water stream may contain 

additional dissolved hydrocarbons or emulsified oil. These generally cannot be removed 

through basic gravity separation and require additional treatment. One common oil field 

treatment method used to break emulsions is the application of heat generated by burning 

gas and passing the hot exhaust gas through a pipe running through the middle of a tank 

known as a heater-treater. This treatment helps to break emulsions, thereby allowing 

gravity separation to take place. Other approaches that are used to break emulsions 

involve electrostatic precipitation and emulsion-breaking chemicals (demulsifiers). 

At some point, the oil is sent to market and the water is left for management or disposal. 

The next treatment steps, if needed, are dictated by the intended fate of the water. The 

next several sections describe some of the disposal modes and treatment processes that 

can be used to manage water that will be injected or discharged. Within these two broad 

categories, further subdivision is necessary based on the pollutants of concern for the 

environment into which the water will be disposed of. 
Produced Water White Paper 57 

5.3.2 Treatment before Injection 

It is important to ensure that the water being injected is compatible with the formations 

receiving the water, to prevent premature plugging of the formation or other damage to 

equipment. It may be necessary to treat the water to control excessive solids, dissolved 

oil, corrosion, chemical reactions, or growth of microbes. 

Solids are usually treated by gravity settling or filtration. Reynolds (2003) reports that a 

common rule of thumb for solids control is that all particulate matter larger than one-third 

the average pore-throat size of the receiving formation should be removed. 

Residual amounts of oil in the produced water not only represent lost profit for producers 

but also can contribute to plugging of formations receiving the injectate. Various 

treatment chemicals are available to break emulsions or make dissolved oil more 

amenable to oil removal treatment. 

Corrosion can be exacerbated by various dissolved gases, primarily oxygen, carbon 

dioxide, and hydrogen sulfide. Oxygen scavengers and other treatment chemicals are 

available to minimize levels of undesired dissolved gases. 

The water chemistry of a produced water sample is not necessarily the same as that of the 

formation that will receive the injected water. Various substances dissolved in produced 

water may react with the rock or other fluids in the receiving formation and have 

undesired consequences. It is important to analyze the constituents of the produced water 

before beginning a water flood operation to avoid chemical reactions that may form 

precipitates. If necessary, treatment chemicals can minimize undesired reactions. 

Bacteria, algae, and fungi can be present in produced water or can be introduced during 

water handling processes at the surface. These are generally controlled by adding 

biocides or by filtration. 

5.3.3 Onshore Wells 

5.3.3.1 Discharges under the Agricultural and Wildlife Water Use Subcategory 

Little information is available on the treatment methods used before discharging 

produced water from oil and conventional gas wells under this subcategory. 

5.3.3.2 Discharges from CBM Operations 

Some CBM water is clean enough that it can be discharged without treatment. Other 

produced water is bubbled over rocks to aerate it and allow iron to precipitate out before 

it is discharged to a stream. When more rigorous treatment is required, operators have 

sometimes used reverse osmosis. Reverse osmosis is an effective water pollution 
Produced Water White Paper 58 

treatment method that passes a dirty water stream across a semipermeable membrane. 

Fresh water diffuses through the membrane, leaving behind a concentrated waste stream. 

Reverse osmosis has only been used sparingly in the hydrocarbon-production field 

because it is expensive and the membranes can be fouled or damaged by constituents in 

raw produced water. Often, produced water must be pretreated before it can be treated 

with reverse osmosis. Lee et al. (2002) describe several pretreatment methods that are 

being tested at Sandia National Laboratories and the Petroleum Recovery Research 

Center at New Mexico Tech. These include chemical treatment, filtration, biological 

treatment, polymeric absorbents, and macroporous polymer extraction. 

Other researchers have been investigating the use of natural clays for ion-exchange 

(Janks and Cadena 1992) or electrostatic precipitation (Atlas 2002; Welgemoed 2002). 

ALL (2003) provides short descriptions of these and several other water treatment 

technologies that are either already being used or may be applicable for treating CBM 

water. That study summarizes nine types of treatment processes and indicates the relative 

effectiveness of reducing different produced water contaminants. 

5.3.3.3 Discharges from Stripper Wells 

Low oil production volumes do not contribute much income to stripper well operators. 

Consequently, they are not able to undertake complicated or expensive treatment. 

Adewumi et al. (1992) describe a simple, low-cost system used for produced water 

treatment in Pennsylvania. It involves separation, pH adjustment, aeration, solids 

separation, and filtration. DOE has funded a Stripper Well Consortium through 

Pennsylvania State University that supports research on ways to produce stripper wells 

and manage the water most cost-effectively. For more information on specific projects, 

see the Stripper Well Consortium’s website at: 

http://www.energy.psu.edu/swc/index.html. 

5.3.3.4 Other Onshore Options 

Rather than dealing with treatment of water from numerous small-volume wells, many 

stripper-well or other onshore operators pay a contractor to remove the water for offsite 

disposal. This is generally accomplished by having a pump truck visit the well locations 

periodically and remove the accumulated water. The truck hauls the water to a disposal 

facility. Veil (1997b) compiled information on offsite commercial facilities that accepted 

produced water for disposal. Those facilities were located in nine oil-producing states. 

The predominant disposal method was injection, although some facilities in arid areas 

relied on evaporation pits. Several companies in Pennsylvania and one company in 

Wyoming treated the produced water and then discharged it to a stream via NPDES 

permit or to a municipal sewer system. 

Boysen et al. (2002) describe numerous approaches for managing produced water in the 

Rocky Mountain region. Some involve recycle and reuse, but one that is appropriate for 

discussion in this section is evaporation by portable misting towers. These are essentially 

spray nozzles at the top of vertical pipes. The water is sprayed into the air and evaporates 
Produced Water White Paper 59 

before hitting the ground. Boysen et al. (2002) report that one operator was able to 

evaporate at a rate of 30 gallons per minute during the warm, dry Wyoming summer. 

Constructed wetlands can be used to treat produced water (Myers 2000). Over the past 

few years, researchers have studied the feasibility of treating produced water using 

constructed wetlands at the Rocky Mountain Oilfield Testing Center (Jackson and Myers 

2003). After two years of a three-year study, the authors noted that the wetlands 

improved water quality, good plant growth was observed, and wetland functions were 

similar to those found in natural wetlands. The treatment performance of the wetlands 

was affected by temperature. 

Boysen et al. (1996) describe an innovative process that relies on natural freezing and 

thawing coupled with evaporation to treat produced water (Freeze/Thaw Evaporation). 

This results in a concentrated brine stream and a clean water stream. Unless artificial 

refrigeration is employed, this process is limited to cold climates during cold times of the 

year. 

5.3.4 Offshore Wells 

The large majority of offshore produced water is discharged to the ocean. The primary 

pollutant of concern is oil and grease, which is regulated by EPA’s national ELGs for 

offshore activities and is made part of all U.S. offshore discharge permits. Unlike 

onshore discharges, for which salinity is a key consideration, offshore discharges need 

not worry about that parameter. Depending on the EPA region, operators must meet 

various other discharge limitations, including restrictions on flow rate, toxicity testing, 

and monitoring for several toxic metals, organics, and naturally occurring radioactive 

material (NORM). Most of the treatment technology for offshore produced water is 

geared toward removing oil and grease. The next section discusses some important 

issues concerning oil and grease, how it is measured, and the influence of measurement 

on permit compliance. 

5.3.4.1 What Is Oil and Grease? 

Oil and grease is not a single chemical compound, but a measure of many different types 

of organic materials that respond to a particular analytical procedure. Different analytical 

methods will measure different organic fractions and compounds. Therefore, the specific 

analytical method used is important in determining the magnitude of an oil and grease 

measurement. This is particularly important because of the phasing out of the use of 

Freon-113 as an extraction solvent (EPA Method 413.1) over the past decade. That 

longstanding standard-approved method (which was used to collect all the effluent data 

used in establishing the statistically derived ELGs limit for oil and grease) has been 

replaced by EPA Method 1664, which uses n-hexane as the extraction solvent. Raia and 

Caudle (1999) report on a study sponsored by the American Petroleum Institute to 

compare the results of the two methods. The standard deviations of the results were in 

the same order of magnitude or larger than the means, thereby making it difficult to 

determine if the results are comparable. Most of the samples showed higher values when 
Produced Water White Paper 60 

measured by the new method. This raises some concern over compliance. For example, 

if the new method measures 44 mg/L while the old method measures 40 mg/L for the 

same sample, this is the difference between compliance and noncompliance with the 

maximum ELGs limit for oil and grease of 42 mg/L. 

Subsequent papers have debated the use of alternative types of solvents (for example 

Keathley and Konrad 2000; Wilks 2001). These are highly technical chemical discourses 

that are outside of the scope of this white paper. Nevertheless, analytical measurement 

continues to be an important topic. It is also worth noting that the standard oil and grease 

method approved for measuring North Sea discharges is different from the two methods 

mentioned above (Yang and Tulloch 2003). 

Although there are many different oil and grease methods, only Method 1664 is approved 

for official NPDES compliance purposes. Some of the other methods may be quicker or 

less expensive. Some of them can be utilized in continuous on-line devices for process 

monitoring purposes, but those other methods cannot be substituted for the official permit 

samples. 

A second point is that not all produced waters contain the same constituents even if they 

have the same oil and grease content. Oil and grease is made up of at least three forms: 

- Free oil (this is in the form of large droplets that are readily removable by gravity 

separation methods), 

- Dispersed oil (this is in the form of small droplets that are more difficult to 

remove), and 

- Dissolved oil (these are hydrocarbons and other similar materials that are 

dissolved in the water stream; they are often challenging to remove). 

For example, take two untreated produced water samples, both of which contain 100 

mg/L of oil and grease. Produced water A has primarily free oil whereas produced water 

B has primarily dissolved oil. In order to meet the maximum discharge limit of 42 mg/L, 

the types of treatment processes and the cost of those processes would be vastly different. 

This is the challenge faced by offshore operators. McFarlane et al. (2002) report on a 

collaborative project between Oak Ridge National Laboratory and several major oil 

companies to better characterize and predict the types of water-soluble organics that are 

present in offshore produced water. 

With this background, the following sections describe different treatment processes that 

have been used to treat offshore produced water. 

5.3.4.2 Offshore Treatment Technology 

Offshore produced water treatment can be challenging because offshore facilities do not 

have abundant space or weight capacity for treatment equipment. In addition, offshore 

environments are remote and typically harsh; equipment and processes that operate there 

must be designed for those environments. For the past 13 years, a group of offshore 
Produced Water White Paper 61 

water specialists has gathered in Houston each January for the Produced Water Seminar. 

This gathering is informal yet highly informative for learning about new produced water 

management technologies and analytical and regulatory issues. Many of the references 

cited in this section are papers presented at the seminars. In recent years, this group has 

formed the Produced Water Society. Information about the society and ordering seminar 

papers is available at www.producedwatersociety.net. Other organizations in the United 

States and Europe have also held useful meetings focused on offshore produced water. 

Many authors have described programs for produced water treatment at offshore facilities 

(for example, Favret and Doucet 1999; Tyrie 2000; Caudle 2000; Robinson 2003; 

Greenwood 2003). The water is first pretreated by skimmers or other basic separation 

equipment to remove oil droplets greater than 100 microns in size. Devices to promote 

coalescence of small oil droplets into larger droplets may be used here, too. Tulloch 

(2003) describes a pre-coalescer device that consists of a bundle of oleophilic fibers 

placed inside of a flow line. The fibers serve to aggregate small oil droplets for easier 

downstream removal. 

Next, the water receives primary treatment to remove additional free oil. The types of 

equipment used for primary treatment include liquid/liquid hydrocyclones, corrugated 

plate separators, and centrifuges. Faucher and Sellman (1998) describe the use of 

centrifuges to remove oil and solids. 

Secondary treatment to remove emulsified oil and suspended solids is the next stage of 

treatment. Flotation cells, adsorption, ion exchange, filtration, and organic extraction are 

used in secondary treatment. 

Cline (2000) offers a useful overview of flotation technology. The principle of flotation 

is to create many very small air or gas bubbles that rise through a vessel filled with 

produced water and carry small oil droplets and solids particles to the surface of the 

vessel where they can be skimmed off. Chemicals may be added to help break 

emulsions. Cline reviews the flotation equipment offered by several different vendors, 

and discusses efficiencies, advantages, and disadvantages. Jahnsen and Vik (2003) report 

on North Sea trials of a compact flotation unit that combines separation, gas flotation, and 

centrifugal separation in the same device. Several years of trials showed very low oil and 

grease in the effluent. 

There are several types of filtration devices used for produced water treatment (Tyrie 

1998). Some utilize membrane filters that are often deployed as cartridges, which can be 

replaced when filled. Nicolaisen and Lien (2003) provide an overview of membrane 

filter applications and suggest that membranes in the ultrafiltration size range are 

appropriate for offshore produced water. Nanofiltration and reverse osmosis membranes 

have smaller pore size and can be deployed downstream of the ultrafiltration filters, if 

needed. Some operators use media filters that are backwashed periodically. Kozar 

(2000) reports on filters filled with crushed walnut shells. Brock et al. (2003) describes 

another type of media filter that features a radial flow design to allow on-line cleaning of 

the media without having to stop for backwashing. 
Produced Water White Paper 62 

Meijer and Kuijvenhoven (2002) describe an approach to removing dissolved organics 

from offshore produced water using fluid extraction. The process, known as Macro 

Porous Polymer Extraction (MPPE), takes place in the pores of polymer particles, and the 

particles can be regenerated in place with low-pressure steam. Grini et al. (2003) 

describe trials using the MPPE and another type of extraction process, the CTour, which 

utilizes gas condensate as the extraction fluid. 

Frankiewicz (2001) presents an overview of factors that lead to poor produced water 

quality. His presentation describes 12 common causes and groups them into 4 main 

categories: 

- Presence of inorganic or organic solids, 

- Excessive or highly varying fluid flow rates, 

- Gas breakout or slugging in or into process equipment, and 

- Improper chemical treatment programs. 

Frankiewicz (2001) provides a useful table that helps in selecting treatment equipment 

based on the size of the particles that need to be removed. That information is shown in 

Table 5-1. 
Produced Water White Paper 63 

TABLE 5-1 Particle Size Removal Capabilities 

Technology 

Removes Particles Greater Than 

Size Indicated (in microns) 

API gravity separator 150 

Corrugated plate separator 40 

Induced gas flotation without chemical 

addition 

25 

Induced gas flotation with chemical addition 3-5 

Hydrocyclone 10-15 

Mesh coalescer 5 

Media filter 5 

Centrifuge 2 

Membrane filter 0.01 

Source: Frankiewicz (2001). 

 
Produced Water White Paper 64 

6 The Cost of Produced Water Management 

There are many sources of site-specific costs in the literature. For the purposes of this 

white paper, it is impractical to list hundreds of single-cost values from different 

references. Instead, this chapter discusses the components that contribute to water 

management costs, and gives a few examples from references that report data from 

multiple sources. 

It is well understood that for conventional oil and gas production, the volume of water 

produced by a well and a field will increase over time and the volume of oil and gas 

produced will decline. At some time, the revenue from the oil and gas is not sufficient to 

cover the costs of operation (a growing portion of those costs will be water management) 

and the well will be shut in. 

6.1 Components of Cost 

Produced water management is generally expensive, regardless of the cost/barrel, because 

of the large volumes of water that must be lifted to the surface, separated from the 

petroleum product, treated (usually), and then injected or disposed of. The previous 

chapter outlined a wide array of options for managing wastes. These all are driven by 

minimizing some or all of the individual cost components. The following list includes 

many of the components that can contribute to overall costs: 

- Site preparation 

- Pumping 

- Electricity 

- Treatment equipment 

- Storage equipment 

- Management of residuals removed or generated during treatment 

- Piping 

- Maintenance 

- Chemicals 

- In-house personnel and outside consultants 

- Permitting 

- Injection 

- Monitoring and reporting 

- Transportation 

- Down time due to component failure or repair 

- Clean up of spills 

- Other long-term liability. 

As an example of how a large, multinational company looks at cost, Shell’s cost 

distribution is reported by Khatib and Verbeek (2003) as pumping (27.5%), deoiling 

(21%), lifting (17%), separation (15%), filtration (14%), and injecting (5%). 

 
Produced Water White Paper 65 

6.2 Cost Rates ($/bbl) 

The cost of managing produced water after it is already lifted to the surface and separated 

from the oil or gas product can range from less than $0.01 to at least several dollars per 

barrel. The following sections offer several examples of costs. 

6.3 Offsite Commercial Disposal Costs 

In 1997, Argonne National Laboratory compiled information on costs charged by offsite 

commercial disposal companies to accept produced water, rain water, and other “watertype wastes” (Veil 1997b). The reported costs are assumed to be lower than or 

comparable to the costs available for onsite management by the operators themselves. 

Costs for disposing of these wastes are listed in Table 6-1. Overall, disposal costs are 

$0.01-$8/bbl, although most are $0.25-$1.50/bbl. The highest cost, $8/bbl, is charged at 

one facility in Wyoming for particularly dirty wastes that need pretreatment before 

injection. The same facility charges as low as $0.75/bbl for cleaner wastes. The lowest 

cost is charged by a nonprofit facility in California that operates as a cooperative for 

several member users. These costs are solely disposal costs; the cost of transporting the 

water to the facilities is additional. 

By far, the most common commercial disposal method for produced water is injection. 

The range of costs for injection is the same as that described in the previous paragraph. 

Ten companies in Wyoming, five companies in Utah, and four companies in New 

Mexico use evaporation to dispose of produced water. The cost is $0.25-$2.50/bbl. 

Another New Mexico company uses a combination of evaporation and injection, at a cost 

of $0.69/bbl. The nonprofit California company described above, which also uses a 

combination of evaporation and injection, charges $0.01-$0.09/bbl. 

Six companies in Pennsylvania utilize surface water discharge options. Three of these 

companies treat and blend produced water and discharge it directly through an NPDES 

permit. Another company treats the waste and discharges it to a sanitary sewer that leads 

to a municipal wastewater treatment plant. They charge $1-$2.10/bbl. Two municipal 

wastewater treatment plants accept water-type wastes but not produced water. They 

charge $0.65-$1.50/bbl. Another company in Pennsylvania spreads produced water on 

roads in the summer and discharges to a municipal wastewater treatment plant in the 

winter. This company charges $1.30-4.20/bbl. 

6.4 Costs for Rocky Mountain Region Operators 

Jackson and Myers (2002, 2003) provide cost estimates for many produced water 

disposal methods that might be used in the states of Wyoming, Colorado, Utah, and New 

Mexico. Table 5-2 is based on data from that paper. The majority of their reported costs 

range from $0.01/bbl for surface discharge or evaporation to more than $5.50/bbl for 

commercial waste haulers. The magnitude of the cost depends on the water chemistry, 

the regulatory requirements imposed, and the amount of treatment needed. 
Produced Water White Paper 66 

Boysen et al. (2002) summarize the results of many interviews with operators in the San 

Juan, Powder River, and Greater Green River Basins concerning water management and 

disposal costs. In the Power River Basin, most CBM operators reported water 

management costs ranging from $0.01/bbl to $2/bbl. The low end of that range covered 

the costs for a pipeline and impoundment while the upper end of the range represented 

the cost of a commercial hauling company. Costs were somewhat different for the San 

Juan Basin, based on three separate surveys conducted in 1998 ($0.04/bbl to $1.88/bbl), 

early 2001 ($0.30/bbl to $2.80/bbl), and late 2001 ($0.50/bbl to $4.20/bbl). Note that 

different groups of operators were interviewed for the two 2001 surveys. 

Surveys were conducted in 1998 and 2001 in the Greater Green River Basin. The 1998 

results ranged from $0.40/bbl to $4/bbl, and the 2001 results were even higher, ranging 

from $0.50/bbl to $10/bbl. 

6.5 Perspective of an International Oil Company 

Khatib and Verbeek (2003) estimate that Shell Oil’s worldwide produced water 

management costs are more than $400 million per year. This translates to a cost rate of 

from $0.02/bbl to as much as $2.50/bbl, depending on the location and volume. Khatib 

and Verbeek suggest that the average cost for produced water management in the U.S. is 

about $0.10/bbl. 

 
Produced Water White Paper 67 

TABLE 6-1 Disposal Costs for Produced Water at Offsite Commercial Facilities 

State 

Number of Facilities 

Using This Process Type of Disposal Process Costa

CA 1 Evaporation/injection $0.01-$0.09/bbl 

 

KY 1 Injection $1/bbl 

LA 23 Injection $0.20-$4.50/bbl 

NM 4 Evaporation $0.25-$0.81/bbl 

NM 1 Evaporation/injection $0.69/bbl 

NM 1 Injection $0.69/bbl 

 

OK 1 Injection $0.30/bbl 

PA 3 Treat/discharge $1-$2.10/bbl 

PA 1 Treat/POTW $1.25-$1.80/bbl 

PA 1 POTW/road spread $1.30-$4.20/bbl 

PA 2 POTW $0.65-$1.50/bbl 

 

TX 9 Injection $0.23-$4.50/bbl 

UT 5 Evaporation $0.50-$0.75/bbl 

WY 10 Evaporation $0.50- $2.50/bbl

WY 1 Treat/injection or discharge $0.96/bbl 

WY 3 Injection $0.60-$8.00/bbl 

a

 Costs are those reported by disposal company operators in 1997. 

Source: Veil (1997b). 
Produced Water White Paper 68 

TABLE 6-2 Produced Water Management Costs 

Management Option Estimated Cost ($/bbl) 

Surface discharge 0.01-0.80 

Secondary recovery 0.05-1.25 

Shallow reinjection 0.10-1.33 

Evaporation pits 0.01-0.80 

Commercial water hauling 1.00-5.50 

Disposal wells 0.05-2.65 

Freeze-thaw evaporation 2.65-5.00 

Evaporation pits and flowlines 1.00-1.75 

Constructed wetlands 0.001-2.00 

Electrodialysis 0.02-0.64 

Induced air flotation for deoiling 0.05 

Anoxic/aerobic granular activated carbon 0.083 

Source: Jackson and Myers (2002, 2003). 
Produced Water White Paper 69 

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Produced Water White Paper 73 

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Factor – A Proposed Tool for Produced Water Impact Reduction, Management and 

Regulation,” SPE 61178, SPE International Conference on Health Safety and the 

Environment in Oil and Gas Exploration and Production, Stavanger, Norway, June 26-28. 

Johnsen, S., 2003, “Risk Assessment Based Environmental Management of Produced 

Water from Offshore Oil and Gas Fields,” presented at the Produced Water Workshop, 

Aberdeen, Scotland, March 26-27. 

Keathley, J., and K. Konrad, 2000, “EPA Method 1664, Comparison of Extraction 

Solvents in the Analysis of Oil in Produced Water,” Environmental Testing & Analysis, 

July/August, pp. 27-29. 

Khatib, Z., and P. Verbeek, 2003, “Water to Value – Produced Water Management for 

Sustainable Field Development of Mature and Green Fields,” Journal of Petroleum 

Technology, Jan., pp. 26-28. 

Kobelski, B, 2003, communication between Kobelski, U.S. Environmental Protection 

Agency, Washington, DC, and M. Puder, Argonne National Laboratory, Washington, 

DC, Oct. 16, 2003. 

Kozar, R., 2000, “The Use of Black Walnut Shell Filter Technology for the Treatment of 

Produced Water,” presented at the 10th Produced Water Seminar, Houston, TX, Jan. 19-

21. 

Lee, R., R. Seright, M. Hightower, A. Sattler, M. Cather, B. McPherson, L. Wrotenbery, 

D. Martin, and M. Whitworth, 2002, “Strategies for Produced Water Handling in New 

Mexico,” presented at the 2002 Ground Water Protection Council Produced Water 

Conference, Colorado Springs, CO, Oct. 16-17. (Paper available at: 

http://www.gwpc.org/Meetings/ PW2002/Papers-Abstracts.htm.) 

Mack, J., 2003, “Water Shut-Off in Producing Wells with Polymer Gels,” presented at 

Produced Water Management Workshop, Houston, TX, April 29-30. 
Produced Water White Paper 75 

McFarlane, J., D.T. Bostick, and H. Luo, 2002, “Characterization and Modeling of 

Produced Water,” presented at the 2002 Ground Water Protection Council Produced 

Water Conference, Colorado Springs, CO, Oct. 16-17. (Paper available at: 

http://www.gwpc.org/Meetings/PW2002/Papers-Abstracts.htm.) 

Meijer, D.T., and C.A.T. Kuijvenhoven, 2002, “Field-Proven Removal of Dissolved 

Hydrocarbons from Offshore Produced Water by the Macro Porous Polymer-Extraction 

Technology,” presented at the 12th Produced Water Seminar, Houston, TX, Jan. 16-18. 

Murphree, P.A., 2002, “Utilization of Water Produced from Coal Bed Methane 

Operations at the North Antelope/Rochelle Complex, Campbell County, Wyoming,” 

presented at the 2002 Ground Water Protection Council Produced Water Conference, 

Colorado Springs, CO, Oct. 16-17. (Paper available at 

http://www.gwpc.org/Meetings/PW2002/Papers-Abstracts.htm.) 

Myers, J.E., 2000, “Constructed Wetlands Overview for the Petroleum Industry,” SPE 

61181, presented at the SPE International Conference on Health, Safety and the 

Environment in Oil and Gas Exploration and Production, Stavanger, Norway, June 26-28. 

Nicolaisen, B., and L. Lien, 2003, “Treating Oil and Gas Produced Water Using 

Membrane Filtration Technology,” presented at the Produced Water Workshop, 

Aberdeen, Scotland, March 26-27. 

Offshore, 2000, “ABB Looking to Progress Subsea Processing into Ultra-Deepwater,” 

Offshore, Vol. 60, Issue 8, Aug. 1. 

Paetz, R.J., and S. Maloney, 2002, “Demonstrated Economics of Managed Irrigation for 

CBM Produced Water,” presented at the 2002 Ground Water Protection Council 

Produced Water Conference, Colorado Springs, CO, Oct. 16-17. (Paper available at 

http://www.gwpc.org/ 

Meetings/PW2002/Papers-Abstracts.htm.) 

 

Peacock, P., 2002, “Beneficial Use of Produced Water in the Indian Basin Field: Eddy 

County, NM,” presented at the 2002 Ground Water Protection Council Produced Water 

Conference, Colorado Springs, CO, Oct. 16-17. (Abstract available at 

http://www.gwpc.org/Meetings/ 

PW2002/Papers-Abstracts.htm.) 

Rabalais, N.N., B.A. McKee, D.J. Reed, and J.C. Means, 1992, “Fate and Effects of 

Produced Water Discharged in Coastal Louisiana, Gulf of Mexico, USA,” in Produced 

Water, J.P. Ray and F.R. Englehart (eds.), Plenum Press, New York. 

Raia, J.C., and D.D. Caudle, 1999, “Methods for the Analysis of Oil and Grease and 

Their Application to Produced Water from Oil and Gas Production Operations,” 

presented at the 9th Produced Water Seminar, Houston, TX, Jan. 21-22. 
Produced Water White Paper 76 

Regg, J., 2003, personal communication between Regg, Alaska Oil and Gas Conservation 

Commission, Anchorage, AK, and M. Puder, Argonne National Laboratory, Washington, 

DC, Oct. 28. 

Reynolds, R.R., and R.D. Kiker, 2003, “Produced Water and Associated Issues – A 

Manual for the Independent Operator,” Oklahoma Geological Survey Open File Report 

6-2003, prepared for the South Midcontinent Region of the Petroleum Technology 

Transfer Council. 

Reynolds, R., B. Kiker, and L. Cole, 2002, “Produced Water, and the Issues Associated 

with It,” PTTC Network News, Vol. 8, No. 3, 3rd quarter. 

Robinson, K., 2003, “Produced Water Management – An Integrated Approach,” 

presented at the Produced Water Workshop, Aberdeen, Scotland, March 26-27. 

Schiff, K.C., D.J. Reish, J.W. Anderson, and S.M. Bay, 1992, “A Comparative 

Evaluation of Produced Water Toxicity,” in Produced Water, J.P. Ray and F.R. Englehart 

(eds.), Plenum Press, New York. 

Seright, R.S., R.H. Lane, and R.D. Sydansk, 2001, “A Strategy for Attacking Excess 

Water Production,” SPE 70067, presented at the SPE Permian Basin Oil and Gas 

Recovery Conference, Midland, TX, May 15-16. 

Shirman, E.I., and A.K. Wojtanowicz, 2002, “More Oil Using Downhole Water-Sink 

Technology: A Feasibility Study,” SPE 66532, SPE Production and Facilities, Nov. 

Stephenson, M.T., 1992, “A Survey of Produced Water Studies,” in Produced Water, J.P. 

Ray and F.R. Englehart (eds.), Plenum Press, New York. 

Stettner, M., 2003a, personal communication between Stettner, California Department of 

Conservation, Sacramento, CA, and J. Veil, Argonne National Laboratory, Washington, 

DC, Feb. 13. 

Stettner, M., 2003b, personal communication between Stettner, California Department of 

Conservation, Sacramento, CA, and M. Puder, Argonne National Laboratory, 

Washington, DC, Oct. 17. 

Strikmiller, M.G., 2000, “Produced Water Toxicity – An Overview,” 11th Produced 

Water Seminar, Houston, TX, Jan. 17-18. 

Stone, B., 2003, personal communication between Stone, New Mexico Oil Conservation 

Division, Santa Fe, NM, and J. Veil, Argonne National Laboratory, Washington, DC, 

Feb. 14. 

Swisher, M., 2000, “Summary of DWS Application in Northern Louisiana,” presented at 

Downhole Water Separation Technology Workshop, Baton Rouge, LA, March 2. 
Produced Water White Paper 77 

Thomas, F.B., D.B. Bennion, G.E. Anderson, B.T. Meldrum, and W.J. Heaven, 2000, 

“Water Shut-Off Treatments – Reduce Water and Accelerate Oil Production,” Journal of 

Canadian Petroleum Technology 39(4):25-29, April. 

Tibbetts, P.J.C., I.T. Buchanan, L.J. Gawel, and R. Large, 1992, “A Comprehensive 

Determination of Produced Water Composition,” in Produced Water, J.P. Ray and F.R. 

Englehart (eds.), Plenum Press, New York. 

Tulloch, S.J., 2003, “Development & Field Use of the Mare’s Tail® Pre-Coalescer,” 

presented at the Produced Water Workshop, Aberdeen, Scotland, March 26-27. 

Tyrie, C.C., 1998, “The Technology and Economics of the Various Filters That Are Used 

in Oil Field Produced Water Clean Up,” presented at the API Produced Water 

Management Technical Forum and Exhibition, Lafayette, LA, Nov. 17-18. 

Tyrie, C.C., 2000, “Produced Water Management,” presented at the 10th Produced Water 

Seminar, Houston, TX, Jan. 19-21. 

USGS, 1998, “Estimated Use of Water in the United States in 1995,” U.S. Geological 

Survey Circular 1200. 

Utvik, T.I., 2003 “Composition and Characteristics of Produced Water in the North Sea,” 

Produced Water Workshop, Aberdeen, Scotland, March 26-27. 

Veil, J.A., 1997a, “Surface Water Discharges from Onshore Stripper Wells,” prepared for 

U.S. Department of Energy by Argonne National Laboratory, Office of Fossil Energy, 

Dec. 

Veil, J.A., 1997b, “Costs for Offsite Disposal of Nonhazardous Oil Field Wastes: Salt 

Caverns versus Other Disposal Methods,” prepared for DOE Office of Fossil Energy 

(April 1997); also published by DOE- National Petroleum Technology Office as 

DOE/BC/W-31-109-ENG-38-3, DE97008692, Sept. 

Veil, J.A., B.G. Langhus, and S. Belieu, 1999, “Feasibility Evaluation of Downhole 

Oil/Water Separation (DOWS) Technology,” prepared for U.S. Department of Energy, 

Office of Fossil Energy, National Petroleum Technology Office, by Argonne National 

Laboratory, CH2M-Hill, and Nebraska Oil and Gas Conservation Commission, Jan. 

(Available for downloading at http://www.ead.anl.gov/pub/dsp_detail.cfm?PubID=416.) 

Veil, J.A., 2000, “Summary of Data from DOE-Subsidized Field Trial #1 of Downhole 

Oil/Water Separator Technology - Texaco Well Bilbrey 30-Federal No. 5, Lea County, 

New Mexico,” prepared for U.S. Department of Energy, National Petroleum Technology 

Office, May. (Available for downloading at 

http://www.ead.anl.gov/pub/dsp_detail.cfm?PubID=1221.) 
Produced Water White Paper 78 

Veil, J.A., 2001a, “Offshore Waste Management – Discharge, Inject, or Haul to Shore?”

presented at the 8th International Petroleum Environmental Conference, Houston, TX, 

Nov. 6-9. 

Veil, J.A., 2001b, “Interest Revives in Downhole Oil/Water Separators,” Oil & Gas 

Journal, pp 47-56, Feb. 26. 

Veil, J.A., 2002a, “Drilling Waste Management: Past, Present, and Future,” Proceedings 

of the SPE Annual Technical Conference and Exhibition, San Antonio, TX, Sept. 29–Oct. 

2. Available from the Society of Petroleum Engineers, Richardson, TX. 

Veil, J.A., 2002b, “Regulatory Issues Affecting Management of Produced Water from 

Coal Bed Methane Wells,” prepared for U.S. Department of Energy, Office of Fossil 

Energy, National Petroleum Technology Office, by Argonne National Laboratory, Feb. 

Veil, J.A., 2003, “An Overview of Applications of Downhole Oil/Water Separators,” 

presented at the Produced Water Workshop, Aberdeen, Scotland, March 26-27. 

Veil, J., J. Kupar, and M. Puder, 2003, “Use of Mine Pool Water for Power Plant 

Cooling,” prepared by Argonne National Laboratory for the U.S. Department of Energy, 

National Energy Technology Laboratory, Sept. 

Von Flatern, R., 2003, “Troll Pilot Sheds Light on Seabed Separation,” Oil Online

(www.oilonline.com), May 16. 

Walker, J.F., and R.L. Cummins, 1999, “Development of a Centrifugal Downhole 

Separator,” OTC #11031, presented at the Offshore Technology Conference, Houston, 

TX, May 3-6. 

Weideman, A., 1996, “Regulation of Produced Water by the U.S. Environmental 

Protection Agency” in Produced Water 2: Environmental Issues and Mitigation 

Technologies, International Produced Water Symposium, M. Reed and S. Johnsen, eds., 

Plenum Press, New York. 

Welgemoed, T., 2002, “Capacitive Deionization Technology: A Cost Effective Solution 

for Brackish Ground Water Remediation,” presented at the 2002 Ground Water 

Protection Council Produced Water Conference, Colorado Springs, CO, Oct. 16-17. 

(Paper available at http://www.gwpc.org/Meetings/PW2002/Papers-Abstracts.htm.) 

Wojtanowicz, A.K., E.I. Shirman, and H. Kurban, 1999, “Downhole Water Sink (DWS) 

Completions Enhance Oil Recovery in Reservoirs with Water Coning Problem,” SPE 

56721, presented at the SPE Annual Technical Conference and Exhibition, Houston, TX, 

Oct. 3-6. 

Wojtanowicz, A.K., 2003, “Smart Dual Completions for Downhole Water Control in Oil 

and Gas Wells,” presented at Produced Water Management Workshop, Houston, TX, 

April 29-30. 
Produced Water White Paper 79 

Wilks, P, 2001, “Selecting a Solvent for TOG/TPH Analysis of Produced Water by 

Infrared Analysis,” presented at the 12th Produced Water Seminar, Houston, TX, Jan. 17-

19. 

Wolff, E.A., 2000, “Reduction of Emissions to Sea by Improved Produced Water 

Treatment and Subsea Separation Systems,” SPE#61182, presented at the Society of 

Petroleum Engineers International Conference on Health, Safety, and Environment, 

Stavanger, Norway, June 26-28. 

Yang, M., and S. Tulloch, 2003, “Oil-in-Water Monitoring – Where Are We Heading in 

the North Sea?” presented at the 13th Produced Water Seminar, Houston, TX, Jan. 15-17.