PreparedFor:

U.S.DepartmentofEnergy

NationalPetroleumTechnologyOffice

PreparedBy:

InterstateOilandGas

CompactCommission

and

ALLConsulting

InCooperationwith:A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

i

ACKNOWLEDGEMENTS

This project was funded by the National Energy Technology Laboratory (NETL) of the U.S. 

Department of Energy (DOE) program “Focused Research in Federal Lands Access 

and Produced Water Management in Oil and Gas Exploration and 

Production”. The project was developed under the Area of Interest 2: Produced 

Water Management Practices, and Topic 3: Produced Water Best Management 

Practices.

The Interstate Oil and Gas Compact Commission (IOGCC) and ALL Consulting (ALL) conducted 

this study as co-researchers in cooperation with the oil and gas agencies of Alaska (Alaska Oil 

and Gas Conservation Commission), Montana (Montana Board of Oil and Gas Conservation), 

Wyoming (Wyoming Oil and Gas Conservation Commission), Kansas (Kansas Corporation 

Commission), and Oklahoma (Oklahoma Corporation Commission). 

The effort was overseen by NETL’s, National Petroleum Technology Office in Tulsa, Oklahoma. 

The National Petroleum Technology Office project manager for this effort was Mr. John Ford. 

The research team also extends its appreciation to those companies operating in the Powder 

River, Big Horn, Williston, North Central Montana, Anadarko, Arkoma, Alaska North Slope, Cook 

Inlet, Permian and Fort Worth Basins, and the staffs of the Department of the Interior, 

Environmental Protection Agency, and the various state agencies who provided the technical 

input and assistance that enabled DOE to improve the scope and quality of the analysis. 

DE-PS26-04NT15460-02 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

ii

DISCLAIMER

This information is distributed solely for the purpose of technical peer review under applicable 

information quality guidelines. It has not been formally disseminated by the Department of 

Energy and should not be construed to represent any agency determination or policy. 

This material was prepared as an account of work sponsored by an agency of the United States 

Government. Neither the United States nor the United States Department of Energy, nor any of 

their employees, makes any warranty, expressed or implied, or assumes any legal liability or 

responsibility for the accuracy, completeness, or usefulness of any information, apparatus, 

product, or process disclosed, or represents that its use would not infringe privately owned 

rights.

The findings and conclusions in this report are those of the authors and do not necessarily 

represent the views of the Department of Energy. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

iii

TABLE OF CONTENTS

ACKNOWLEDGEMENTS .........................................................................................................................................i

DISCLAIMER ..................................................................................................................................................... ii

TABLE OF CONTENTS .......................................................................................................................................... iii

LIST OF TABLES ......................................................................................................................................................v

LIST OF FIGURES....................................................................................................................................................vi

LIST OF FIGURES....................................................................................................................................................vi

ACRONYM LIST .................................................................................................................................................. viii

SECTION 1.0 INTRODUCTION..........................................................................................................................1

SECTION 1.1 PURPOSE AND NEED ..........................................................................................................................5

SECTION 1.2 OVERVIEW OF RESEARCH ..................................................................................................................7

SECTION 1.3 PROJECT ADVISORY COUNCIL ...........................................................................................................8

SECTION 2.0 CURRENT INDUSTRY TRENDS...............................................................................................9

SECTION 2.1 DOMESTIC UNITED STATES OVERVIEW ...........................................................................................10

Section 2.1.1 Produced Water Quality Trends Across the United States....................................................10

Section 2.1.2 Understanding the Science of Produced Water Quality........................................................10

Section 2.1.3 Nationwide Trends in Produced Water Quantities................................................................13

SECTION 2.2 PRODUCTION TRENDS IN SELECT STATES ........................................................................................15

Section 2.2.1 Energy Prices Impact Trends ................................................................................................15

Section 2.2.2 New Technologies Impact Trends..........................................................................................20

Section 2.2.3 How Trends Impact Produced Water Management ..............................................................22

SECTION 3.0 CURRENT REGULATORY CHALLENGES...........................................................................27

SECTION 3.1 REGULATORY SYNOPSIS ..................................................................................................................27

Section 3.1.1 Clean Water Act and NPDES ................................................................................................28

Section 3.1.2 Safe Drinking Water Act and Underground Injection Control..............................................29

SECTION 3.2 BENEFICIAL USE OF PRODUCED WATER..........................................................................................29

SECTION 3.3 NPDES DISCHARGE CHALLENGES ..................................................................................................31

Section 3.3.1 Challenges in Wyoming.........................................................................................................31

Section 3.3.2 Inter-State Challenges between Wyoming and Montana.......................................................32

SECTION 3.4 UIC PROGRAM CHALLENGES ..........................................................................................................33

Section 3.4.1 The Evolution of Class V Wells .............................................................................................33

Section 3.4.2 Classification of Brine...........................................................................................................33

SECTION 3.5 WATERSHED BASED PERMITTING....................................................................................................34

Section 3.5.1 The Process ...........................................................................................................................34

Section 3.5.2 Advantages and Disadvantages.............................................................................................36

Section 3.5.3 Assimilative Capacity Allocation and Control System ..........................................................36

SECTION 4.0 PRODUCED WATER MANAGEMENT PRACTICES............................................................39

SECTION 4.1 CLASS I INJECTION...........................................................................................................................40

SECTION 4.2 CLASS II INJECTION .........................................................................................................................42

SECTION 4.3 CLASS V INJECTION .........................................................................................................................47

Section 4.3.1 Subsurface Drip Irrigation (SDI) ..........................................................................................47

Section 4.3.2 Aquifer Storage Recovery Wells ............................................................................................50

SECTION 4.4 SURFACE DISCHARGE ......................................................................................................................51

SECTION 4.5 SURFACE IMPOUNDMENTS ...............................................................................................................52

Section 4.5.1 Evaporation and Aeration .....................................................................................................53

Section 4.5.2 Wildlife and Stock Watering..................................................................................................54

SECTION 4.6 MANAGED IRRIGATION AND LAND APPLICATION............................................................................56
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

iv

SECTION 4.7 INDUSTRIAL USES............................................................................................................................57

Section 4.7.1 Oil and Gas Operations.........................................................................................................57

Section 4.7.2 Power Plant Cooling Water ..................................................................................................58

Section 4.7.3 Geothermal Power Generation .............................................................................................59

Section 4.7.4 Dust Suppression...................................................................................................................62

Section 4.7.5 Concentrated Animal Feeding Operations (CAFO)..............................................................63

SECTION 4.8 WATER TREATMENT TECHNOLOGIES ..............................................................................................65

Section 4.8.1 Packed Bed Adsorption .........................................................................................................65

Section 4.8.2 Decomposition in Constructed Wetland ................................................................................66

Section 4.8.3 Ion Exchange.........................................................................................................................67

Section 4.8.4 Electrodialysis (ED) and Electrodialysis Reversal (EDR) ....................................................72

Section 4.8.5 Capacitive Deionization Technology (CDT) .........................................................................75

Section 4.8.5 Capacitive Deionization Technology (CDT) .........................................................................76

Section 4.8.6 Electrochemical Activation (ECA) Technology.....................................................................77

Section 4.8.7 Electro-deionization (EDI)....................................................................................................78

Section 4.8.8 Evaporation...........................................................................................................................79

Section 4.8.9 Pressure Driven Membrane Separation Technologies..........................................................82

Section 4.8.10 NORM Treatment ..................................................................................................................91

SECTION 4.9 HANDLING OF WATER TREATMENT WASTE/CONCENTRATE .........................................................100

SECTION 5.0 PRODUCED WATER REDUCTION TECHNIQUES...........................................................103

SECTION 5.1 DOWNHOLE WATER SEPARATION AND INJECTION.........................................................................103

SECTION 5.2 ADVANCED PRODUCTION AND COMPLETION TECHNIQUES............................................................105

Section 5.2.1 Reverse Circulation Center Discharge................................................................................105

Section 5.2.2 Cavitation ............................................................................................................................105

Section 5.2.3 Well Stimulation ..................................................................................................................106

SECTION 5.3 HORIZONTAL DRILLING .................................................................................................................110

SECTION 6.0 ANALYSIS OF SELECT OIL & GAS BASINS.....................................................................115

SECTION 6.1 ALASKA NORTH SLOPE AND COOK INLET .....................................................................................115

SECTION 6.2 ANADARKO BASIN.........................................................................................................................122

SECTION 6.3 ARKOMA BASIN.............................................................................................................................126

SECTION 6.4 BIGHORN BASIN.............................................................................................................................129

SECTION 6.5 FORT WORTH BASIN......................................................................................................................131

SECTION 6.6 GREATER GREEN RIVER BASIN......................................................................................................136

SECTION 6.7 NORTH CENTRAL MONTANA BASIN ..............................................................................................139

SECTION 6.8 PERMIAN BASIN.............................................................................................................................141

SECTION 6.9 POWDER RIVER BASIN...................................................................................................................144

SECTION 6.10 WILLISTON BASIN .........................................................................................................................146

SECTION 6.11 WIND RIVER BASIN .......................................................................................................................149

SECTION 7.0 REGIONAL IMPLICATIONS TO PRODUCED WATER MANAGEMENT IN THE 

UNITED STATES ......................................................................................................................153

SECTION 7.1 WATER QUALITY AND QUANTITY .................................................................................................155

SECTION 7.2 SOCIO-ECONOMIC SETTING ...........................................................................................................158

SECTION 7.3 ANNUAL RAINFALL AND EVAPOTRANSPIRATION...........................................................................160

SECTION 7.4 POTENTIAL FOR NEW AND INNOVATIVE BENEFICIAL USES ...........................................................164

SECTION 8.0 REFERENCES ............................................................................................................................167

APPENDIX A – SITE VISIT SUMMARIES.....................................................................................................179
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

v

LIST OF TABLES

Table 4.1 Water Quality Guide for Livestock Use ............................................................. 64

Table 4.2 Results from ET Venture’s mobile produced water treatment system ................. 66

Table 4.3 Summary of the performance of NPR-3 Bio-treatment facility which included 

 wetland treatment.......................................................................................... 67

Table 4.4 Performance of Higgins Loop treatment for a field trial at Powder River Basin ... 72

Table 4.5 Produced water treatment performance at Wind River Basin, Wyoming ............. 74

Table 4.6 Performance of CDT for the CBNG produced water treatment ........................... 77

Table 4.7 Treatment capacity of CDT unit....................................................................... 77

Table 4.8 Average percentage removal of weakly ionized species using EDI...................... 79

Table 4.9 Rapid Spray Evaporation testing results (Source: WestWater Resources) ........... 81

Table 4.10 Applications of advanced membrane filtration technologies ............................... 83

Table 4.11 Performance of various zeolite membranes (Source: PRRC, NMIMT).................. 85

Table 4.12 GE pilot water treatment plant results.............................................................. 86

Table 4.13 A summary of utilized water treatment processes............................................. 87

Table 4.14 Results from field test with a produced water treatment system........................ 94

Table 4.15 Advantages, Disadvantages, and Applicability of Produced Water Treatment 

 Technologies.................................................................................................. 96

Table 7.1 Summary of Produced Water Quality Statistics ................................................157
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

vi

LIST OF FIGURES 

Figure 1.1 Oil and Natural Gas Production in the United States............................................ 3

Figure 2.1 Total Dissolved Solids from the USGS Produced Water Database in the United 

 States............................................................................................................ 11

Figure 2.2 Natural Water Progression in Basins Such as the Anadardko or Permian Basin ... 12

Figure 2.3 Water and Oil Production Volumes in the United States Since 2000 ................... 14

Figure 2.4 Water and Gas Production Volumes in the United States Since 2000.................. 14

Figure 2.5 Well Permitting Activity in Montana, by Resource Compared to Average Oil and 

Gas Prices 1990 - 2005 ............................................................................................... 16

Figure 2.6 Well Completion Activity in Montana, by Resource Compared to Average Oil and 

Gas Prices 1990 - 2005 ............................................................................................. 16

Figure 2.7 Well Permitting Activity in Wyoming, by Resource Compared to Average Oil and Gas 

Prices 1990 - 2005...................................................................................................... 17

Figure 2.8 Well Completion Activity in Wyoming, by Resource Compared to Average Oil and 

Gas Prices 1990 - 2005 ............................................................................................. 17

Figure 2.9 Well Permitting Activity in Alaska, by Resource Compared to Average Oil and Gas 

Prices 1990 - 2005.....................................................................................................168

Figure 2.10 Well Completion Activity in Alaska, by Resource Compared to Average Oil and Gas 

Prices 1990 - 2005 ...................................................................................................178

Figure 2.11 Well Permitting Activity in Kansas, by Resource Compared to Average Oil and Gas 

Prices 1990 - 2005...................................................................................................... 19

Figure 2.12 Well Completion Activity in Kansas, by Resource Compared to Average Oil and 

Gas Prices 1990 - 2005 ............................................................................................. 19

Figure 2.13 Water Produced in Montana from Oil and Gas Wells by Type, 1986 - 2005........ 20

Figure 2.14 Impact of New Technologies on Oil Production in Montana ............................... 21

Figure 2.15 The Impact of the Recent Development of the Bakken Formation on Oil Production 

 in Montana..................................................................................................... 21

Figure 2.16 Water Produced in Wyoming from Oil, Gas, and CBNG Wells, 1978 - 2005......... 22

Figure 2.17 Oil, Gas, and Water Production Trends for Montana from 1986 to 2005............. 23

Figure 2.18 Oil, Gas, and Water Production Trends for Wyoming from 1978 to 2005 ............ 24

Figure 2.19 Oil, Gas, and Water Production Trends for Alaska from 1978 to 2005.................25

Figure 4.1 Approximate Class I Well Count in Each State .................................................. 41

Figure 4.2 Approximate Class II Well Count in Each State ................................................. 44

Figure 4.3 Diagram of SDI System................................................................................... 48

Figure 4.4 Temperature (o

F) at 3 km (~9,800 ft) for the Continental United States .............. 58

Figure 4.5 Temperature (o

F) at 5 km (~16,400 ft) for the Continental United States............. 59 

Figure 4.6 DOE Naval Petroleum Reserve’s bio-treatment process ..................................... 66

Figure 4.7 Higgins Loop schematic .................................................................................. 70

Figure 4.8 An ED unit in operation................................................................................... 73

Figure 4.9 A conceptual diagram of an AquaCell during CDT operation .............................. 76

Figure 4.10 Schematic of an EDI cell ................................................................................ 78

Figure 4.11 A vertical tube falling film vapor compression evaporator................................. 80

Figure 4.12 A VSEP membrane avoids fouling by continuous sinusoidal vibration ................. 84

Figure 4.13 GE produced water treatment system, California.............................................. 85

Figure 4.14 Schematic of produced water treatment process .............................................. 87

Figure 4.15 A schematic of HERO system developed by GE Ionics....................................... 89

Figure 4.16 Newpark Environmental Services produced water treatment system .................. 93

Figure 5.1 A fracture propagates perpendicular to the minimum principal stress................107
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

vii

Figure 5.2 Vertically – dominated, Hydro-fractured CBNG well..........................................107

Figure 5.3 Horizontally – dominated, Hydro-fracturing a CBNG well ..................................108

Figure 5.4 A schematic of Z-pinnate drilling.....................................................................111

Figure 5.5 Multi horizontal wells penetrate through multiple coal seams............................112

Figure 6.1 Geologic Setting and Produced Water Quality Distribution of the Alaska North 

Slope ..................................................................................................................116

Figure 6.2 Geologic Setting and Produced Water Quality Distribution of the Alaska Cook Inlet 

Basin/ Kenai Peninsula ...............................................................................................117

Figure 6.3 Produced Water Quality from the Alaska North Slope.......................................131

Figure 6.4 Produced Water Quality from the Alaska Kenai Peninsula/Cook Inlet.................133

Figure 6.5 Geologic Setting and Produced Water Quality Distribution of the Anadarko Basin 

 ...................................................................................................................122

Figure 6.6 Produced Water Quality from the Anadarko Basin............................................124

Figure 6.7 Geologic Setting and Produced Water Quality Distribution of the Arkoma Basin...127

Figure 6.8 Produced Water Quality from the Arkoma Basin ................................................128

Figure 6.9 Geologic Setting and Produced Water Quality Distribution of the Bighorn Basin...129

Figure 6.10 Produced Water Quality from the Wyoming and Montana Portions of the Bighorn . 

 Basin ............................................................................................................131

Figure 6.11 Geologic Setting and Produced Water Quality Distribution of the Fort Worth Basin. 

 ...................................................................................................................132

Figure 6.12 Water Quality Distribution in the Fort Worth Basin ..........................................134

Figure 6.13 Geologic Setting and Produced Water Quality Distribution of the Greater Green 

River Basin ................................................................................................................137

Figure 6.14 Water Quality Distribution in the Greater Green River Basin .............................138

Figure 6.15 Geologic Setting and Produced Water Quality Distribution of the North Central 

Montana Basin...........................................................................................................139

Figure 6.16 Water Quality Distribution of the North Central Montana Basin.........................141

Figure 6.17 Geologic Setting and Produced Water Quality Distribution of the Permian Basin .... 

 ...................................................................................................................142

Figure 6.18 Water Quality Distribution in the Texas and New Mexico Portions of the Permian ..

 Basin ............................................................................................................143

Figure 6.19 Geologic Setting and Produced Water Quality Distribution of the Powder River 

Basin ...................................................................................................................144

Figure 6.20 Water Quality Distribution of the Entire Powder River Basin of Montana and 

 Wyoming ......................................................................................................146

Figure 6.21 Geologic Setting and Produced Water Quality Distribution of the Williston Basin147

Figure 6.22 Water Quality Distribution in the United States Portion of the Williston Basin ....148

Figure 6.23 Geologic Setting and Produced Water Quality Distribution of the Wind River Basin . 

 ...................................................................................................................150

Figure 6.24 Water Quality Distribution in the Wind River Basin ..........................................151

Figure 7.1 Major Hydrocarbon Producing Basins of the Contiguous United States ..............154

Figure 7.2 Total Dissolved Solids of Produced Water in the United States..........................156

Figure 7.3 Water Quality Statistical Analysis of Select Oil and Gas Basins ..........................157

Figure 7.4 Oil and Gas Basins compared to Population Density of the Contiguous United 

 States...........................................................................................................159

Figure 7.5 Annual Average Rainfall in the Contiguous United States..................................161

Figure 7.6 Annual Average Lake Evaporation in the United States.....................................162

Figure 7.7 Annual Average Water Available for Evapotranspiration in the United States .....163
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

viii

 ACRONYM LIST

AC Alternating Current 

API American Petroleum Institute 

ARI Advanced Resource International 

ASR Aquifer Storage and Recovery 

Ba Barium 

BAT Best Available Technology 

BCT Best Conventional Pollutant Control Technology 

BER Board of Environmental Review 

BLM Bureau of Land Management 

BOPD Barrels of Oil Per Day 

BPT Best Practicable Control Technology 

BTEX Benzene, Tolulene, Ethylbenzene, Xylene 

Ca Calcium 

CaCO3 Calcium Carbonate 

CAFO Concentrated Animal Feeding Operations 

CBNG Coal Bed Natural Gas 

CDT Capacitive Deionization Technology 

Cl Chloride 

COOH Carboxylic Acid 

CWA Clean Water Act 

DC Direct Current 

DOE Department of Energy 

DOWS Downhole Oil/Water Separation Technology 

ECA Electrochemical Activiation 

ED Electrodialysis 

EDI Electro-deionization 

EDR Électrodialysis Reversal 

EIA United States Energy Information Administration 

ESPs Electric Submersible Pumps 

FTE® Freeze Thaw Evaporation 

GAC Granular Activated Carbon 

GTI Gas Technology Institute 

GWPC Ground Water Protection Council 

H+ Hydronium 

HCO3 Bicarbonate 

HEEDTM High Efficiency Electodialysis 

HEROTM High Efficiency Reverse Osmosis 

HSWA Hazardous & Solid Waste Amendments 

HUC Hydrologic Unit Code 

HTC Hydrotalcite 

IID Class II Injection Disposal Wells 

IIR Class II Injection Recovery Wells 

IOGCC Interstate Oil and Gas Compact Commission 

kg/m2h kilograms per meters squared-hour 

KSU Kansas State University 

MBOGC Montana Board of Oil and Gas Conservation 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

ix

MCF Thousand Cubic Feet 

MMCF Million Cubic Feet 

MDEQ Montana Department of Environmental Quality 

MF Microfiltration 

Mg Magnesium 

MPDES Montana Pollutant Discharge Elimination System 

MWCO Molecular Weight Cutoff 

Na Sodium 

NaCl Sodium Chloride 

NaOH Concentrated Sodium Hydroxide 

NETL National Energy Technology Laboratory 

NF Nanofiltration 

NO3 Nitrate 

NORM Naturally Occurring Radioactive Materials 

NPDES National Pollutant Discharge Elimination System 

NPR-3 Naval Petroleum Reserve No. 3 

NRCS National Resource Conservation Service 

NSPS New Source Performance Standards 

PAC Project Advisory Council 

PCPs Progressive Cavity Pumps 

POD Project Plan of Development 

POTWs Publicly Owned Treatment Works 

PRRC Petroleum Recovery and Research Center 

ppm Parts Per Million 

psi Pounds Per Square Inch 

RCCD Reverse Circulation Center Discharge 

RCRA Resource Conservation and Recovery Act 

RO Reverse Osmosis 

RMOTC Rocky Mountain Oilfield Testing Center 

RSE Rapid Spray EvaporationTM 

SAC Strong Acid Cation 

SAR Sodium Absorption Radio 

SDI Subsurface Drip Irrigation 

SDWA Safe Drinking Water Act 

SEO State Engineer’s Office 

SNL Sandia National Laboratory 

SO3H Sufonic Acid Group 

TCEQ Texas Commission of Environmental Quality 

TCF trillion cubic feet 

TDS Total Dissolved Solids 

TMDL Total Maximum Daily Load 

TPH Total Petroleum Hydrocarbons 

UBD Underbalanced Drilling 

UF Ultrafiltration 

UIC Underground Injection Control 

USDW Underground Sources of Drinking Water 

USEPA United States Environmental Protection Agency 

USGS United States Geological Survey 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

x

VSEP Vibratory Shear Enhanced Processing 

WAC Weak Acid Cation 

WDEQ Wyoming Department of Environmental Quality 

WGR Water to Gas Ratios 

WGS Wyoming Geological Survey 

WOGCC Wyoming Oil and Gas Conservation Commission 

WOR Water to Oil Ratios 

WWQRR Wyoming Water Quality Rules and Regulations 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

1

SECTION 1.0 INTRODUCTION 

The make-up of the oil and gas industry in the United States today is different than it was 25 

years ago. The domestic oil and gas sector is no longer dominated by large oil and gas 

companies. Currently, 65 percent of the natural gas and 40 percent of the oil produced in the 

United States is produced by small independent oil and gas companies which typically employ 

no more than 10 full-time employees (DOE, 2006 and API, 2006). This core of independent 

producers might not have the financial aptitude to conduct the research required to make the 

technological advances necessary to continue to 

economically produce domestic energy resources, but the 

domestic oil and gas industry cannot sustain itself without 

the critical development of new technologies. This is a 

major concern that is addressed by the United States 

Department of Energy (DOE) National Energy Technology 

Laboratory (NETL) through research grants targeted to fill 

this void. 

Along with Congress, President George W. Bush set forth an 

Energy Bill in 2005 that focuses on increasing our nation’s 

ability to be more reliant on domestic sources of energy and less reliant on foreign oil and gas. 

President Bush stated the following in an address to the Sandia National Laboratory in 

Albuquerque, NM: 

“Meeting the needs of our growing economy also means expanding our domestic 

production of oil and natural gas, which are vital fuels for transportation and electricity 

and manufacturing.” 

To meet the goals of the President, NETL has focused research funding to develop oil and 

natural gas technologies and technology transfer projects to enhance the ability of domestic 

producers to extract energy resources while continuing to protect the environment (DOE, 

2006). Produced water management is widely recognized as a core issue that may be a barrier 

to continued economical and environmentally sensitive oil and gas development in the United 

States. Figure 1.1 is a map of the United States showing the distribution of oil and natural gas 

producing regions across the country. The distribution of producing areas is not uniform across 

the United States, as there are distinct regions where oil and gas production occurs. These 

regions include, but are not limited to: the Mid-Continent, Gulf Coast, the Rocky Mountain 

Region, Appalachian Mountain Region, California, and Alaska. The increased demand for 

energy resources in the United States has caused increases in oil and gas prices, which have led 

to a renewed interest in previously uneconomical or marginally economic areas. These once 

marginal, or high risk, plays include tertiary recovery projects, continuous reservoirs and other 

conventional and unconventional oil and gas plays that often have high water to oil ratios 

(WOR) and/or high water to gas ratios (WGR). Many of these new unconventional plays are 

under development and have resulted in a broad spectrum of new produced water 

management challenges. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

2

 Various technological advances 

such as improved water reduction 

procedures that lower the WOR 

and/or WGR at the wellhead and 

cutting edge produced water 

management alternatives that can 

treat large volumes of marginal 

quality water to beneficial use 

standards are constantly being 

developed. The benefit of these 

technological advances typically 

results in extending the productive 

life of a well, or in some cases an 

entire field. The benefits are not 

likely to be attained, however, if the 

technological advances are not 

widely available to the public and 

industry via technology transfer.

Advanced technology also might allow development of resources that were not previously 

economically viable, such as unconventional natural gas (e.g., coal bed natural gas, oil shales, 

tight sands, regionally extensive-highly permeable reservoirs) and mature oil and gas fields 

(“stripper” wells). More than 75 percent (423,000 out of 555,000) of our nation’s oil wells are 

classified as "stripper" wells, or wells that produce less than 10 barrels per day (BOPD), or 60 

million cubic feet (MMCF) of gas per day (IOGCC, 2005). On average, these stripper wells 

produce about 2 BOPD, but collectively, they account for nearly 15 percent of domestic oil 

production (API, 2006). The WOR on stripper wells can be as high as 40 barrels of water to 1 

barrel of oil produced (API, 2006). The economic and environmental benefit to lowering the 

WOR on stripper wells is wide reaching and can affect the industry on a nationwide basis. 

Water produced during oil and gas operations constitutes the industry’s most prolific product. 

By volume, water production represents approximately 98 percent of the non-energy related 

fluids produced from oil and gas operations, yielding approximately 14 billion barrels of water 

annually (Veil, 2004). When compared to the annual oil (1.9 billion barrels, EIA, 2006) and gas 

(23.9 TCF, EIA, 2006) production across the United States, the argument could be made that 

the oil and gas produced would be more appropriately identified as a byproduct to production of 

water.

Blackleaf Canyon Area 

– Rocky Mountain Front 

(Montana) 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

3

Figure 1.1 Oil and Natural Gas Production in the United States 

Source: Mast, et al, 1998 and ALL Consulting, 2006 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

4

In recent years, the oil and gas industry’s view on water production has changed dramatically. 

Produced water has historically been viewed by most as a waste stream that must simply be 

disposed of in the most cost efficient and environmentally sound manner possible. This 

outdated viewpoint has and is continuing to evolve in the upstream energy industry and in the 

eyes of many other stakeholders (e.g., landowners, government regulatory agencies, and nongovernmental organizations). The evolving view on produced water has stemmed from many 

issues the industry and our nation have faced, including lengthy droughts in areas of the 

western United States; water shortages for power generation; and many other environmental 

challenges facing our nation. This evolving viewpoint has led some to the belief that produced 

water is not a waste stream at all, rather it has created a desire to beneficially use the water 

opposed to simply disposing of it as a waste (ALL, 2006). 

The large volumes of high quality water produced today have 

resulted in operators looking for alternative means of managing 

this water in a cost-effective and environmentally safe manner. 

A common misconception is that there is one produced water 

management practice that will work throughout the United 

States. Quite the opposite is true. In fact, produced water 

management practices vary widely across the United States and 

in some instances across a single oil and gas field. A few 

examples of produced water management practices currently in 

use are: 

Water Treatment: Water treatment (purification or 

composition adjustment) technologies are advancing and 

expanding into oilfield use in many areas. The area that 

has led the drive to implement water treatment 

technologies is the coal bed natural gas development in 

the Powder River Basin located in northeastern Wyoming 

and southeastern Montana. Other areas have expanded 

the use of water treatment technologies for temperature 

correction, solids removal, oil and grease removal, and purification to facilitate drilling 

and stimulation. 

Enhanced Recovery: Produced water has long been used for enhanced oil recovery or 

even for pressure maintenance through waterflooding. The majority of injection wells 

used in the United States in association with the energy industry are used for enhanced 

recovery.

Deep Well Injection: In some cases, oilfield wastes do not meet the criteria to be 

injected into a Class II injection well and must be disposed of via a Class I industrial or 

hazardous waste disposal well. For instance, reject water from some water treatment 

facilities is disposed of in Class I injection wells. 

Sustainable Development Practices: In some areas of the country, water is difficult 

to obtain and operators are forced to make the best overall use of the water produced. 

In these areas, operators store and save produced water for drilling activities, dust 

suppression, stimulation, clean-up, and other uses to avoid acquiring water from 

substantial distances. 

Adding gypsum to produced 

water prior to discharge to 

meet discharge permit criteria

(PRB, Wyoming) 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

5

Beneficial uses of

produced water have 

been realized for years 

in the conventional Big 

Horn Basin fields 

(Elk Basin, Wyoming) 

Water Reduction: Technology continues to play a tremendous role in natural gas and 

oil development. In some reservoirs, water production poses tremendous problems for 

economic production of hydrocarbons. Many alternatives have been and are continuing 

to be used more prolifically. Water reduction alternatives such as downhole oil/water 

separation technology (DOWS) have a great potential to save money and reduce the 

environmental impacts of 

managing produced water at the 

surface (Veil, et al. 1999). 

Beneficial Uses: High quality 

water with a total dissolved 

solids (TDS) concentration of 

less than 10,000 parts per 

million (ppm) may be employed 

for an assortment of beneficial 

uses, providing recreational 

opportunities, drinking water for 

stock and wildlife, irrigation 

water in arid regions, and a 

supplemental source for 

municipal water supplies. In 

some basins, such as the Big 

Horn, in north-central Wyoming and south-central Montana, landowners have come to 

depend on the produced water for farming and ranching. 

The above mentioned practices are discussed in more detail in Section 4, along with several 

other practices and water treatment alternatives that are currently being tested, researched, 

and implemented on pilot scale studies to further the potential for beneficial use of produced 

water that normally would be considered as marginal to poor quality. 

Section 1.1 Purpose and Need 

Industry operators and state regulators share two goals: to effectively and efficiently manage 

produced water while 1) remaining protective of the environment and 2) continuing to 

economically develop domestic energy resources. This document aids in achieving these goals 

by compiling various sources of data and providing an analysis for how the data can be used to 

create innovative produced water management solutions. The data include: 

Produced Water Management Practices: A catalogue of water management 

practices, treatment technologies, and water reduction techniques is presented for use 

as a reference of water management practices currently available to operators. 

Leading edge technologies that have not yet been widely applied are also identified and 

discussed. Operational parameters of each water management practice are identified as 

well.

Produced Water Quality: The quality of produced water from various onshore oil and 

gas producing basins of the United States is presented in terms of TDS. TDS is a good 

indicator of salinity, which can be used to determine appropriate produced water 

management practices, because many practices might become uneconomical or 

impractical based on the salinity of the water. Case studies of water management 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

6

practices currently used to handle a wide range of water qualities in various basins are 

presented to provide examples of success stories and lessons learned. 

Socio-economic Setting and Climate: The ability to beneficially use water can be 

dependant on the socio-economic setting and the weather trends of the area from 

which it is produced. Arid areas with a high population density or areas highly 

dependant on agricultural activities to sustain their population are most likely to be 

interested in utilizing the produced water. Water quality data are geospatially 

presented along with average rainfall, evapotranspiration, and population density. The 

result is identification of areas of the United States where water management is 

considered of utmost importance because any beneficial use might improve the 

sustainability of that area.

Availability of Injection Zones: The ability to economically inject produced water 

may dictate the feasibility of marginal wells with extremely high salinity water that has 

no redeemable beneficial use other than enhanced recovery. A statistical analysis of 

permitted injection wells and their disposal rates is presented on a state-by-state basis 

to identify areas where injection is most common.

The analyses of these datasets include technology transfer recommendations by matching the 

applicable water management practices to relevant basins of the United States that meet or 

exceed the critical operational parameters. While each state is responsible for regulating the 

produced water management techniques implemented in their state, this analysis may prove to 

be instrumental to state and federal regulators’ decision-making process in regards to produced 

water regulations that are protective of the environment while avoiding economic impacts 

caused by the disruption of domestic oil and natural gas supply and delivery. 

This Guidebook may be utilized by operators during the planning phase for determining 

produced water management options as they move into areas of the United States that might 

be unfamiliar to them. Operators also can take advantage of the technology transfer 

recommendations by evaluating alternative options for water management as they seek to 

maintain economic production from older fields that have progressed to higher WORs and 

WGRs. This Guidebook also provides operators with a valuable reference to lead them as they 

pursue unconventional oil and gas plays that can involve large volumes of produced water and 

unusually high WOR and/or WGRs. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

7

Section 1.2 Overview of Research 

This document contains the results of research conducted to provide an overview of current 

issues as they relate to produced water and produced water management. This research 

focused on developing inter-basin technology transfer recommendations based on the findings. 

The following list presents the topics researched and presented in this document: 

Current and Emerging Trends: Where available, researchers compiled production 

data from the 37 oil and gas producing states. Nationwide production trends associated 

with produced water were noted and documented to support the growing concern that 

annual domestic produced water volumes continue to rise as annual domestic oil and 

gas production volumes decline.

Existing and Emerging Regulations: Researchers examined the applicable and 

relevant regulatory literature as it applies to produced water management of onshore oil 

and gas exploration and production sites. To expedite the process, the research team 

interviewed various state agencies that govern produced water issues of the oil and gas 

industry. Industry personnel also were interviewed in various states to determine what 

issues, if any, are relevant and germane to industry in terms of impacting the economic 

viability of oil and gas production. The Project Advisory Council (PAC) described in 

Section 1.3 was instrumental in identifying various regulatory issues and challenges that 

warranted further research. 

Produced Water Management Alternatives: Researchers examined various 

produced water management practices, water treatment technologies, and water 

reduction techniques to identify the operational requirements of each. Operational 

requirements may include water quality and quantity, environmental impacts, 

operational costs, applicability per resource type, regional setting, and basin statistics, 

among others. Strengths and weaknesses of the various management alternatives 

analyzed were noted and categorized for ease of technology transfer between regions of 

the United States. 

Case Studies: Several case studies were performed to gain further insight into 

produced water management alternatives in various basins. Industry personnel were 

interviewed as a part of the case study process, and the research team documented 

success stories and lessons learned. 

Watershed Based Permitting: Watershed based permitting is a relatively new 

concept intended to protect the environment while maintaining reasonable discharge 

limits based on the assimilative capacity of the watershed as a whole. The Wyoming 

Department of Environmental Quality (WDEQ) began implementation of a watershed 

based permitting program in the Powder River Basin in 2005. Members of the research 

team followed the progress of the WDEQ and attended various public meetings to gain 

input from various stakeholders. As part of the research phase of the project, the 

results of these meetings and the pending outcomes are documented in this report. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

8

Section 1.3 Project Advisory Council 

The research herein was conducted under the direction of the Interstate Oil and Gas Compact 

Commission, with oversight and direction from the PAC. The PAC is comprised of a diverse 

group with interests related to produced water management associated with oil and gas 

development that includes: oil and gas agency directors, state and federal agency 

representatives, industry representatives, and other stakeholders. Because the PAC includes 

such a diverse group, input actively was sought at various stages of the research to provide 

direction and to help identify issues that are relevant to the success of the research. The 

diversity of the PAC has resulted in the research obtaining rare perspectives into the produced 

water management issues associated with oil and gas development. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

9

SECTION 2.0 CURRENT INDUSTRY TRENDS 

Water production within the domestic oil and gas industry has increased with the industry’s 

efforts to increase production from existing fields (such as the de-watering projects in the 

Anadarko Basin) and from non-conventional fields (such as the Barnett shales in Northern 

Texas and the coal bed natural gas (CBNG) plays in various basins of the western United 

States). Furthermore, the past few years have seen a drastic increase in the price of crude oil 

and natural gas while demand for these resources has continued to rise. Operators in the 

United States have attempted to alleviate the shortage by increasing domestic production. 

Although production statistics typically lag a few years on a nationwide scale, indicators present 

in state data such as that from the Montana Board of Oil and Gas Conservation’s records show 

that oil production is increasing (as a result of the expansive development of the nonconventional Bakken shale oil fields), while other aging fields in Montana are producing less oil 

and more water (MBOGC, 2006). In general, this trend is correlative to the oil and gas industry 

across the United States. As a result, to increase daily oil and gas production, operators of 

these older fields also must increase daily water production. This ultimately leads to an 

increase in the production ratios of water to oil (WOR) and/or water to gas (WGR). 

In addition to the common aging trend, technological advances have allowed the oil and gas 

industry to focus on several new non-conventional plays that have intrinsically higher water 

production rates to facilitate the yield of oil and gas: 

CBNG often requires de-pressurization of the producing coal seam by pumping large 

volumes of high quality water (<10,000 mg/L TDS) to facilitate the production of 

natural gas.

Shales and diatomites such as the Barnett Formation of north-central Texas 

require high-volume hydraulic fracture treatments that produce water back to wells for 

a long period of time. This water can be fairly high quality but because of state and 

federal regulations, the water must be managed as an oil and gas waste. 

Dewatering of old reservoirs aims to drain the water from competing permeability 

systems to allow oil into the borehole. These projects require pumping of prodigious 

amounts of water as evidenced by the high rate disposal permits obtained in recent 

years within mid-continent fields in Oklahoma, Texas, and Kansas. 

The quality and quantity of produced water varies across the United States. Section 2.1 

explains how the water quality varies from region to region; introduces a scientific theory that 

explains why these differences may have come to be; and presents oil, gas, and water 

production trends across the United States that show how the average WOR and WGR have 

been increasing over the last few years. 

The production trends noted in Section 2.1 are representative of the WOR and WGR of the 

nation on average. This is useful information, but it does not necessarily explain what is 

impacting the increase in these ratios. Section 2.2 looks closer at individual state production 

trends, permitting activity, and completion activity to determine the key aspects that are 

impacting water production volumes, energy prices, and new technologies. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

10

Section 2.1 Domestic United States Overview 

As previously mentioned, the quality and quantity of produced water varies across the United 

States. Section 2.1.1 provides an illustration of how the quality of produced water varies and 

Section 2.1.2 provides a discussion that explains why these differences may have come to be. 

Section 2.1.3 demonstrates the nationwide impact of produced water quantities in terms of 

WOR and WGR. 

Section 2.1.1 Produced Water Quality Trends Across the United States 

Produced water quality data on a national level are available from the DOE-USGS Produced 

Water Database (USGS, 2002) and state-specific data are collected by some of the oil and gas 

producing states and stored in the producing states’ databases for oil and gas production. 

Figure 2.1 presents a summary map of the data from the USGS produced water database. The 

colored data points shown in Figure 2.1 represent a range of salinity (as represented by TDS) 

values collected from the produced water from oil and gas boreholes. TDS ranges are indicated 

by color, with the data ranges indicated in the legend of Figure 2.1. 

This database consists of approximately 53,000 individual produced water samples from 35 

states. Water quality information comes from the analysis of water taken from the boreholes 

during oil and gas production, from production tests, and from drill-stem tests. Data quality 

may vary across the sample set due to evaporation from surface tanks and contamination from 

rainwater or mud filtrate. The DOE-USGS database contains descriptors of sample type. Water 

chemistry data in the database vary from sample to sample with many samples consisting only 

of TDS while other samples include detailed cation and anion concentrations. Although 

individual ions may affect beneficial use, suitability for most beneficial uses can be ascertained 

by total salinity (as represented by TDS). The water quality from this database is analyzed in 

more detail for various basins in the United States in Section 6. 

Section 2.1.2 Understanding the Science of Produced Water Quality 

Water may be produced from oil and gas reservoirs as a part of routine operations. In the 

subsurface, water exists in the pores or other openings of the reservoir. Reservoir rocks can 

contain predominantly hydrocarbons, predominantly water, or a mixture of the two, but in each 

case the water is a part of the dynamic rock-fluid system. After sediments are laid down, 

subsequent movement of water and other fluids is largely lateral, driven by hydraulic pressure 

differences. However, net movement of water is consistently towards the surface, driven by 

induration, compaction, and maturation of the rock frame. As vertical movement continues, 

filter-pressing through shales rich in chemically active clay minerals can retard the passage of 

dissolved constituents, thereby increasing the salinity of the water in deeper reservoirs. The 

phenomenon of natural filter-pressing by shales is analogous to nano-filtration desalination 

(Cohen, et. al., 2001). If upward migrating water has reduced salinity, the pore water left 

behind will have higher salinity. In this way, the vertical flux of migrating water will give rise to 

a salinity gradient within the sedimentary column from shallow strata with pore water much like 

sea water (approximately 32,000 mg/L) to very strong brines (up to a saturated solution of 

approximately 350,000 to 400,000 mg/L) at depth. This, in general, is what is seen in many 

sedimentary basins, where the oldest sedimentary rocks have pore water that is nearly 

saturated and the younger, shallow strata contain water of lesser salinity. A diagram depicting 

this process of water movement is shown on the right-hand side of Figure 2.2. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

11

Figure 2.1 Total Dissolved Solids from the USGS Produced Water Database in the United States
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

12

Figure 2.2 Natural Water Progression in Basins Such as the Anadarko or Permian Basin 

Infiltration/Recharge

Compaction/Dewatering 

Cambrian to Permian

The general trend of increasing salinity can be modified by several more or less local processes 

including long-range, dip-wise migration of fresh water from the outcrop, driven by surface 

recharge. Surface recharge can be occurring at the present time in those areas near the outcrop 

belt on uplifted areas, or historical recharge could have occurred during times of uplift and deep 

erosion. It is unknown how far recharge with meteoric water can extend, but Tertiary-aged 

recharge of Mississippian Madison Formation under the Great Plains of Wyoming and Montana 

extends many miles down-dip from the outcrop. Recharge is driven by hydraulic pressure 

generated by elevation of the outcropping recharge area, causing downward flow of the lighter 

meteoric water column. Meteoric water begins at the surface as high quality rain water, but over 

time the comparatively fresh water infiltrates and obtains added salinity from soluble minerals 

within the strata overlying the reservoir rock. The downward progression of recharge water is 

depicted on the left-hand side of Figure 2.2. 

In addition to general upward flux of subsurface water and recharge from outcrops, reservoir 

rocks are subject to water variations caused by original water chemistry and fluid invasion from 

maturing, transforming shale masses (Hunt, 1979). As temperatures increase due to increasing 

burial, shales can expel water and entrained hydrocarbons. Simple compaction of the shale will 

drive out native pore water as the shales’ porosity decreases from an original 80%. At some 

point, however, clay minerals within the shale begin to change, driving out water of 

crystallization, which can have a very different chemical composition from the pore water. Near 

the same point (in terms of temperature), organic material within the shale begins to give off 

large volumes of hydrocarbons. This charge of fluids can migrate throughout the sedimentary 

basin, depending upon permeability connections. 

As an example, the Silurian-Devonian Hunton Formation is a prolific reservoir in the Anadarko 

Basin. Hunton oils found in Oklahoma fields have been geochemically correlated with overlying 

Woodford shales (Comer, 1992). On the other hand, thick, over-pressured Springer/Chester 

shales of the deep basin may be in connection with deep Hunton reservoirs by way of major 

regional faults, changing the water chemistry. It would be difficult to predict the salinity and 

chemistry of expelled water from the Woodford or Springer/Chester shales; that water would 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

13

likely be a combination of pore water squeezed physically out of the shales and water of 

crystallization displaced by clay mineralogy changes. 

Reservoir water chemistry in ancient sediments can be a product of original water chemistry. 

Some sediments, such as the Tertiary coals of the Powder River Basin, appear to have been laid 

down in fresh water, not sea water; this may be one of the reasons that the coals produce high 

quality, low TDS water. Other sediments such as the Permian Aged formations of the Anadarko 

Basin contain inter-bedded evaporates suggesting that deposition was in hypersaline 

environments resulting in reservoir waters that are very high in TDS. 

A comprehensive paper (Bein and Dutton, 1993) describes interpreted formation waters in the 

southern Mid-Continent from the Delaware Basin to the Anadarko Basin, throughout the 

Paleozoic section. With the help of detailed chemical analyses, including stable isotopes, the 

authors saw the presence of several migrating brines that have modified the characteristics of 

formation waters. The authors saw the influence of meteoric water reacting with strata 

containing halite, gypsum, clays and other minerals. Downward leaching gave rise to saturated 

brines and low salinity brines, depending upon the local intervening strata. The authors 

observed high salinity brines in reservoirs adjacent to the Wichita Uplift, presumed to be caused 

by meteoric waters leaching through thick Permian evaporites. The complex geological history 

of these basins has produced complex varieties of produced water that often can be resolved 

only on a local basis. 

Section 2.1.3 Nationwide Trends in Produced Water Quantities 

The IOGCC consists of 30 member states and seven associate member states representing the 

regions of domestic oil and gas production of the United States. Available data were collected 

from each state and then aggregated to determine the United States domestic production 

trends (oil, gas, and produced water) as a whole. Trends may vary on a state-by-state basis, 

but the overwhelming tendency for the nation is shown to be increasing volumes of water, 

while oil and gas production is decreasing. As a result, industry has been experiencing higher 

WOR and WGR than in recent history. Figure 2.3 presents the water and oil production and the 

WOR since 2000, and Figure 2.4 presents the water and gas production and the WGR since 

2000. The WOR has an upward trend with a high at around 9.8 barrels of water per 1 barrel of 

oil produced in 2005. The WGR also has an upward trend from 2000-2005; the high in 2005 

was approximately 1 barrel of water produced per 1.0 MCF of natural gas. 

Please note that if a state’s production data were not available for any of the three components 

(oil, gas or water), all data for that state were not included in the analysis. States not included 

as a result of these data gaps were: Missouri, New York, Nevada, West Virginia, Virginia, 

Tennessee, Texas, and Utah. Furthermore, some states did not have data available for 2004 

and/or 2005 (Arkansas, Mississippi, New Mexico, North Dakota, Ohio, and Pennsylvania), and 

the states that did have data for 2005 or only had partially complete datasets (Alaska, 

California, Colorado, Florida, Michigan, Montana, Nebraska, South Dakota, and Wyoming). 

Although this skews the total 2004 and 2005 production volumes of the oil, gas, and water 

produced, the oil/water and oil/gas ratios are believed to be representative of a complete 

dataset, which stresses the importance of the WOR and WGR versus actual production volumes 

when performing the comparative analysis. In general, the data support the notion that over 

time operators have had to produce more water to get the same amount (or less) of oil and gas 

production from a reservoir.
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

14

Figure 2.3 Water and Oil Production Volumes in the United States Since 2000 

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

2000 2001 2002 2003 2004 2005

Year

Billion BBLs Oil

Billion BBLs Water

0

2

4

6

8

10

12

Water:Oil Ratio

Oil Water Water:Oil

Figure 2.4 Water and Gas Production Volumes in the United States Since 2000 

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

2000 2001 2002 2003 2004 2005

Year

BCF Gas

Billion BBL Water

0.00

0.20

0.40

0.60

0.80

1.00

1.20

 Water:Gas Ratio

Gas Water Water:Gas

Note: Data for Figures 2.3 and 2.4 were compiled from the following state agencies:

2000 - 2003 – AK, AR, CA, CO, FL, MI, MS, MT, NM, ND, NE, OH, PA, SD, and WY 

2004 – AK, AR, CA, CO, FL, MI, MS, MT, ND, NE, SD, and WY 

(partial) 2005 – AK, CA, CO, FL, MI, MT, NE, SD, and WY 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

15

Section 2.2 Production Trends in Select States 

Oil, gas and produced water databases were analyzed from Montana, Wyoming, Alaska, and 

Kansas to identify and evaluate production trends and the driving forces behind those trends 

(i.e. hot play exploited within the state, new technologies incorporated, and energy price 

fluctuations). The primary driver that impacts domestic oil and gas production trends is the 

market price of oil and gas, which is driven by a number of factors, one of which is demand. 

Over the last few years domestic energy demands have reached new heights and as a result, oil 

and gas prices have continued to rise. Section 2.2.1 discusses how the rise in oil and gas 

prices has lead to a push for domestic oil and gas exploration and production to increase to 

lessen the need for foreign imports. Section 2.2.2 shows how the push for increased domestic 

oil and gas production has lead to unprecedented advances in the use of new technologies, 

such as horizontal drilling and horizontal re-completions. The end result is a net increase in 

produced water across much of the nation. However, the new technologies employed are not 

necessarily responsible for an increase in WOR and WGRs. Section 2.2.3 provides discussion of 

how new drilling technologies increase water production while also decreasing the WOR. With 

rising energy prices, this example of employing new technologies might now prove to be 

economical because the increased revenue from oil and gas production might offset or exceed 

the incremental increase in capital drilling costs and operational water management costs. 

Section 2.2.1 Energy Prices Impact Trends 

The price of oil and gas either can stimulate or chill domestic oil and gas exploration and 

production. Figures 2.5, 2.7, 2.9, and 2.11 illustrate the effect of pricing on permit activity in 

Montana, Wyoming, Alaska, and Kansas respectively. Likewise, Figures 2.6, 2.8, 2.10, and 2.12 

illustrate the effect of pricing on well completion activity in Montana, Wyoming, Alaska, and 

Kansas respectively. The data presented is for oil and gas wells in the representative state 

compared to the average oil and gas prices for the United States on an annual basis. The 

figures generally show that there is a positive correlation between oil and gas prices, permits 

issued, and well completion activity from 1990 to 2005. Alaska is the one state that does not 

appear to follow this trend directly, as can be seen in Figures 2.9 and 2.10. 

As oil prices declined and gas prices remained steady in the early 1990s the well permit activity 

in Montana, Wyoming, and Kansas declined, from nearly 400 permits in 1990 to a little over 200 

permits by 1993 in Montana, from over 1100 permits in 1990 to about 1000 permits in 1993 in 

Wyoming, and from almost 4000 permits in 1990 to less than 1500 permits in 1995 in Kansas. 

As energy prices have increased over the last 10 – 12 years, well permit activity also has 

increased for these three states. As oil and gas prices reached new highs in 2005, permit 

activity in Montana and Wyoming also reached new highs, with more than 1,300 well permits 

approved in Montana in 2005 and around 10,000 permits approved in Wyoming that same year. 

Kansas was also up in permits in 2005 with over 3500 permits approved. Figures 2.5, 2.7, and 

2.11 show the permit application data in terms of the primary energy resource extracted from 

the well from Montana, Wyoming, and Kansas respectively, while Figures 2.6, 2.8, and 2.12 

show the well completion data broken down in the same manner for these three states. The 

data presented in these figures show how new technologies (advances in horizontal well 

borings) and new developments (CBNG and the Bakken play) are impacting production of oil 

and gas resources in these states. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

16

Figure 2.5 Well Permitting Activity in Montana, by Resource Compared to Average Oil and Gas 

Prices 1990 - 2005 

0

200

400

600

800

1000

1200

1400

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Year

Permits Issued

$-

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

$/BBL or $/MCF

Oil Gas CBNG Other Avg $/bbl Avg $/MCF

Prepared by ALL Consulting, Tulsa Oklahoma (2006)

Figure 2.6 Well Completion Activity in Montana, by Resource Compared to Average Oil and 

Gas Prices 1990 - 2005 

0

200

400

600

800

1000

1200

1400

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Year

Completions

$-

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

$/BBL or $/MCF

Oil Gas CBNG Other Dry Avg $/bbl Avg $/MCF

Prepared by ALL Consulting, Tulsa Oklahoma (2006)
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

17

Figure 2.7 Well Permitting Activity in Wyoming, by Resource Compared to Average Oil and 

Gas Prices 1990 - 2005 

0

2000

4000

6000

8000

10000

12000

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Year

Permits Issued

$-

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

$/BBL or $/MCF

Oil Gas CBNG Other Avg $/bbl Avg $/MCF

Prepared by ALL Consulting, Tulsa Oklahoma (2006)

Figure 2.8 Well Completion Activity in Wyoming, by Resource Compared to Average Oil and 

Gas Prices 1990 - 2005 

0

2000

4000

6000

8000

10000

12000

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Year

Completions

$-

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

$/BBL or $/MCF

Oil Gas CBNG Other Avg $/bbl Avg $/MCF

Prepared by ALL Consulting, Tulsa Oklahoma (2006)
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

18

Figure 2.9 Well Permitting Activity in Alaska, by Resource Compared to Average Oil and Gas 

Prices 1990 - 2005 

0

50

100

150

200

250

300

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Year

Permits Issued

$-

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

$/BBL or $/MCF

Oil Gas CBNG Other Avg $/bbl Avg $/MCF

Prepared by ALL Consulting, Tulsa Oklahoma (2006)

Figure 2.10 Well Completion Activity in Alaska, by Resource Compared to Average Oil and 

Gas Prices 1990 - 2005 

0

50

100

150

200

250

300

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Year

Completions

$-

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

$/BBL or $/MCF

Oil Gas CBNG Other Dry Avg $/bbl Avg $/MCF

Prepared by ALL Consulting, Tulsa Oklahoma (2006)
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

19

Figure 2.11 Well Permitting Activity in Kansas, by Resource Compared to Average Oil and Gas 

Prices 1990 - 2005 

0

500

1000

1500

2000

2500

3000

3500

4000

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Year

Permits Issued

$-

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

$/BBL or $/MCF

Oil Gas CBNG Other Avg $/bbl Avg $/MCF

Prepared by ALL Consulting, Tulsa Oklahoma (2006)

Figure 2.12 Well Completion Activity in Kansas, by Resource Compared to Average Oil and 

Gas Prices 1990 - 2005 

0

500

1000

1500

2000

2500

3000

3500

4000

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Year

Completions

$-

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

$/BBL or $/MCF

Oil Gas CBNG Other Dry Avg $/bbl Avg $/MCF

Prepared by ALL Consulting, Tulsa Oklahoma (2006)
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

20

Section 2.2.2 New Technologies Impact Trends 

As previously mentioned, increases in domestic and worldwide energy demand has driven up 

the price of oil and gas, which has stimulated domestic exploration and production programs. 

Higher prices can allow operators to explore the use of experimental and new technologies, 

which can increase domestic exploration and production and allow for the development of new 

plays that previously might have been uneconomical or technologically unattainable. Figures 

2.6 and 2.8 document the affect the rise in energy prices had on the onset and increases in 

CBNG development, which was once considered uneconomical. 

Figure 2.13 presents the volume of water produced in the state of Montana per month from 

1986 through 2005 for different well classifications. Figure 2.13 shows the impact of new 

technologies such as horizontal wells on water production presenting the total Montana water 

production by month for horizontal oil, horizontal re-completed oil, vertical oil, conventional gas, 

and CBNG wells. Water production from conventional gas wells appears to be a minor 

percentage in relationship to the other well types. Furthermore, Figure 2.13 breaks down the 

water production for oil wells using different completion technologies, showing the decline in 

water production from conventional vertical oil wells, while horizontal oil and horizontal oil recompletion wells are all showing increasing volumes of water production. Horizontal oil wells 

allow for increased areas of the reservoir to be exposed to production, which results in 

increased oil and water output. 

Figure 2.13 Water Produced in Montana from Oil and Gas Wells by Type, 1986 - 2005 

0

2

4

6

8

10

12

14

Jan-86

Jan-87

Jan-88

Jan-89

Jan-90

Jan-91

Jan-92

Jan-93

Jan-94

Jan-95

Jan-96

Jan-97

Jan-98

Jan-99

Jan-00

Jan-01

Jan-02

Jan-03

Jan-04

Jan-05

Year

Monthly Water Production (Million BBLs)

 Vertical Oil Wells

 Horizontal Oil

Horizontal Oil Re-Completes

Prepared by ALL Consulting, Tulsa Oklahoma (2006)

Gas Wells

CBNG Wells

CBNG is not the only new play in Montana. The Bakken oil shale play in Richland County also 

has received attention due to the new horizontal development technologies applied as a result 

of the high oil and gas prices. When Figure 2.13 is compared to Figure 2.14 and Figure 2.15, 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

21

Figure 2.14 Impact of New Technologies on Oil Production in Montana 

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

Jan-86

Jan-87

Jan-88

Jan-89

Jan-90

Jan-91

Jan-92

Jan-93

Jan-94

Jan-95

Jan-96

Jan-97

Jan-98

Jan-99

Jan-00

Jan-01

Jan-02

Jan-03

Jan-04

Jan-05

Month and Year

Barrels of Oil per Month

VerticalOil HorizOil HRedrillOil

VERTICAL WELLS

HORIZONTAL 

HORIZONTAL 

RECOMPLETIONS

Prepared by MBOGC, Billings Montana (2006)

Figure 2.15 The Impact of the Recent Development of the Bakken Formation on Oil 

Production in Montana 

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

Jan-86

Jan-87

Jan-88

Jan-89

Jan-90

Jan-91

Jan-92

Jan-93

Jan-94

Jan-95

Jan-96

Jan-97

Jan-98

Jan-99

Jan-00

Jan-01

Jan-02

Jan-03

Jan-04

Jan-05

Month and Year

Barrels of Oil per Month

Others Fallon County Richland Co. Bakken

ALL OTHER COUNTIES

FALLON COUNTY

BAKKEN FORMATION 

PRODUCTION RICHLAND COUNTY

Prepared by MBOGC, Billings Montana (2006)
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

22

the economic impact to the state of Montana from the new technology is evident as the 

horizontal completions in the Bakken play and the horizontal completions and re-completions in 

the Cedar Creek Anticline of Fallon County have led to a 20-year peak in annual oil production 

in Montana. The evidence that this peak has occurred as a result of these technological 

advances can be seen in Figure 2.14 and 2.11 where despite the fact that oil production from 

the rest of the state (as shown by vertical well completions in Figure 2.14 and by the other 

counties’ line in Figure 2.15) has shown a decline for the last 20 years.

Figure 2.16 presents the volume of water produced in the state of Wyoming per year from 1978 

through 2005 for oil, gas, and CBNG wells. Figure 2.16 shows the impact of new CBNG 

production since 1998. Water production from conventional gas wells appears to be a minor 

percentage in relationship to oil and CBNG.

Figure 2.16 Water Produced in Wyoming from Oil, Gas, and CBNG Wells, 1978 - 2005 

0

500

1,000

1,500

2,000

2,500

1978

1979

1980

1981

1982

1983

1984

1985

1986

1987

1988

1989

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

Year

Annual Water Production (Million BBLs)

Oil Wells Conventional Gas Wells CBNG Wells

Prepared by WOGCC, Casper Wyoming (2006)

Section 2.2.3 How Trends Impact Produced Water Management 

As development evolves with the introduction of new technologies and increased production 

from new oil and gas plays, produced water management also must evolve to meet the needs 

of the volumes of water being produced. This section provides some analysis of observed 

trends in oil and gas produced water and how they affect management of it. The first example 

documents produced water management within the state of Montana and provides analysis 

related to the trends of the last 20 years of reported production data. The data analyzed in this 

section look at the gross production numbers for oil, gas and produced water as well as the 

WORs and WGRs. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

23

Figure 2.17 presents the gross production for oil, gas and water in Montana from 1986 through 

partial year data for 2005. Figure 2.17 also presents the WORs and WGRs over the same 

period of time. Analysis of the gross production trends for water in the state shows that water 

production had been on the decline from 1986 through 1999 with totals dropping from 

approximately 137 million barrels in 1986 to approximately 90 million barrels in 1999 (Figure 

2.17). Since 1999, water production in Montana has been increasing with output in 2005 

approaching 140 million barrels --- a volume greater than production in 1986 (Figure 2.17). 

Analysis of the gross oil production trends in the state of Montana shows a similar trend to the 

gross water production, with a decline in oil production from 1986 to 1999 from approximately 

28 million barrels to approximately 15 million (Figure 2.17). Since 1999, oil production has 

increased to greater than 30 million barrels in 2005 (Figure 2.17). Analysis of the gross 

production trends for gas shows that production has been increasing steadily from 1986 

through 2005 with total annual production rising from approximately 48 MMCF to greater than 

100 MMCF. 

Figure 2.17 Oil, Gas, and Water Production Trends for Montana from 1986 to 2005 

0

20

40

60

80

100

120

140

160

19861987198819891990199119921993199419951996199719981999200020012002200320042005

Year

Oil-Gas-Water Production in Millions (BBLs & MCFs)

0

2

4

6

8

10

12

14

16

18

20

Ratio

Oil Gas Water WOR WGR

Prepared by ALL Consulting, Tulsa Oklahoma (2006)

Analysis of WOR and WGR for the 1986 to 2005 time frame for Montana is also shown in Figure 

2.17. While the WGR shows a relatively steady decline from 1986 to 2005, the WOR shows 

several fluctuations from 1986 to 2005. WOR rose during two intervals --- from 1986 to 1992, 

and from 1998 to 2000 --- while there was a leveling off and slight decrease from 1993 to 1998. 

Data from 2001 to 2005 show the WOR to be declining. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

24

Figure 2.18 presents the gross production for oil, gas and water in Wyoming from 1978 through 

2005. Figure 2.18 also presents the WORs and WGRs over the same period of time. Analysis 

of the gross production trends for water in the state shows that water production had been on 

the decline from 1990 through 1998 with totals dropping from approximately 1.6 billion barrels 

in 1990 to approximately 1.4 billion barrels in 1998 (Figure 2.18). Since 1998, water production 

in Wyoming has been increasing with output in 2005 over 2.1 billion barrels --- a volume 

greater than production in any year since 1978 (Figure 2.18). Analysis of the gross oil 

production trends in the state of Wyoming shows a decline in oil production from 1978 from 

approximately 101 million barrels to approximately 41 million barrels in 2005 (Figure 2.18). 

Analysis of the gross production trends for gas shows that production has been increasing 

steadily from 1978 through 2005 with total annual production rising from approximately 338 

MMCF to almost 2 BCF. 

Figure 2.18 Oil, Gas, and Water Production Trends for Wyoming from 1978 to 2005 

0

500

1,000

1,500

2,000

2,500

1978

1979198019811982198319841985198619871988

1989199019911992199319941995

1996

19971998

1999

2000

20012002

20032004

2005

Year

Oil-Gas-Water Production in Millions (BBLs or MCFs)

0

10

20

30

40

50

60

Oil Gas Water WOR WGR

Prepared by WOGCC, Casper Wyoming (2006)

Analysis of WOR and WGR for the 1978 to 2005 time frame for Wyoming is also shown in 

Figure 2.18. While the WGR shows a relatively steady decline from 1978 to 2005, the WOR 

shows a steady climb from 1978 to 1998, and then a sharp increase from 1998 to 2003 while 

stabilizing somewhat from 2003 to 2005. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

25

Figure 2.19 presents the gross production for oil, gas and water in Alaska from 1978 through 

2005. Figure 2.19 also presents the WORs and WGRs over the same period of time. Analysis 

of the gross production trends for water in the state shows that water production has been on 

the steady incline from 1978 through 1998 with totals coming up from approximately 26 million 

barrels in 1978 to approximately 800 million barrels in 1998 (Figure 2.19). Since 1998, water 

production in Alaska has been increasing slightly with output in 2005 just over 880 million 

barrels --- a volume greater than production in any year since 1978 (Figure 2.19). Analysis of 

the gross oil production trends in the state of Alaska shows a rise in oil production from 1978 to 

1988 from approximately 450 million barrels to approximately 740 million barrels in 1988, and 

then a steady decline to 2005 where totals are approximately 315 million barrels (Figure 2.19). 

Analysis of the gross production trends for gas shows that production has been increasing 

steadily from 1978 through 1995 with total annual production rising from approximately 600 

MMCF to over 3.3 BCF in 1995, and then a slight incline to 2005 where totals are approximately 

3.6 BCF (Figure 2.19). . 

Figure 2.19 Oil, Gas, and Water Production Trends for Alaska from 1978 to 2005 

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

1978

1979

1980

1981

1982

1983

1984

1985

1986

1987

1988

1989

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

Year

Oil-Gas-Water Production in Millions (BBLs or MCFs)

0.00

0.50

1.00

1.50

2.00

2.50

3.00

Oil Gas Water WOR WGR

Prepared by ALL Consulting, Tulsa Oklahoma (2006)

Analysis of WOR and WGR for the 1978 to 2005 time frame for Alaska is also shown in Figure 

2.19. While the WGR shows a relatively steady incline from 1978 to 1991 at which point it 

stabilizes to 2005, the WOR shows a steady climb from 1978 to 2000, and then a slight dip from 

2000 to 2003, and then a sharp increase from 2003 to 2005. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

26

THIS PAGE INTENTIONALLY LEFT BLANK 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

27

SECTION 3.0 CURRENT REGULATORY CHALLENGES 

Water produced in association with oil and natural gas production comprises 80 percent of the 

oil and gas industry’s residual waste requiring management and disposal. It contributes to the 

overall cost of energy production (GTI, 2002). Management costs associated with produced 

water can impact the economics of oil and natural gas developments; thus, newly promulgated 

regulations and policies that have the potential to limit water management options possibly 

could halt some existing production operations that are marginally profitable. Approximately 

60% of produced water is managed via deep injection disposal wells at costs ranging from 

$0.50 to $1.75/bbl in wells that cost $400,000 to $3 million to install (Argonne National 

Laboratory, 2002). Other methods of management, such as beneficial use and discharge to 

surface waters, cost considerably less but may be limited by proposed regulations. Due to an 

increase in future expenses and disposal limitations resulting from proposed regulations, some 

existing water management options might become economically impractical. 

Management of produced water from the oil and gas industry is regulated under rules enacted 

federally by the Clean Water Act (CWA) and the Safe Drinking Water Act (SDWA). Recent 

research related to how produced water is regulated and managed has covered a wide range of 

topics such as how new natural gas developments are impacted by existing regulation as well 

as identifying alternative means (typically beneficial uses) of managing the water (ALL 

Consulting, 2003; ALL Consulting and MBOGC, 2004; Argonne National Laboratory, 2002; 

Jackson and Meyer, 2002; Jackson and Meyer, 2003; Reynolds, 2003; Veil, 1997). This section 

discusses how existing and proposed regulations are affecting the management of water 

produced from conventional production activities. Furthermore, the intent of this section is not 

to describe various state produced water regulations, or the history of their promulgation, but 

to focus on evolving regulatory challenges that could have long-reaching impacts on how 

produced water is managed. 

The prolific development of coal bed natural gas and other continuous reservoirs has prompted 

regulators to reconsider produced water management rules and policies to the point that the 

rules soon might be affecting conventional oil and gas operations. The proposed rule and policy 

changes are making it increasingly difficult to manage the produced water through traditional 

procedures at the same time policy is moving toward limiting the potential for many beneficial 

uses of this valuable resource. Beneficial use of produced water has become the mantra of 

many local, state, and federal agencies to avoid what these agencies consider to be wasting a 

valuable resource. These agencies are demanding that produced water of any redeemable 

quality be used beneficially and that uses such as irrigation, stock water, and wetlands 

maintenance be incorporated into all oil and gas operations where water quality is appropriate. 

At the same time, what could be one of the largest beneficial uses, discharge to downstream 

water users, is becoming more difficult for operators to get permitted. 

Section 3.1 Regulatory Synopsis 

The United States Environmental Protection Agency’s (EPA) regional offices typically initiate 

policy and the direction of enforcement actions under the Clean Water Act and Safe Drinking 

Water Act in an effort to protect human health and the environment. These two federal 

regulations are the basis for other federal and state regulatory programs that control the 

management of water produced during oil and gas development. The federal government has 

established several regulatory water classifications and standards. In some regulatory 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

28

programs, federal classifications and/or standards may be adopted by applicable state 

regulatory agencies. Water can be classified according to its characteristics, use, source, 

location, and other criteria. Water classifications generally take into consideration the use and 

value of water for public supplies; protection and propagation of aquatic wildlife; recreation in 

and on the water; and other potential uses (e.g., agricultural, industrial, municipal). Standards 

also might be established to maintain the quality of water as well as current and potential 

beneficial uses. In addition to federal programs, individual states also can have classifications 

and standards to account for local or regional environmental issues. 

Although the EPA acts at the federal level to set national standards, states and tribal 

governments can acquire primacy for Underground Injection Control (UIC) and National 

Pollutant Discharge Elimination System (NPDES) by meeting the EPA’s primacy requirements. A 

state that meets the primacy requirements is allowed to set more stringent state specific 

standards for these programs. Since individual states can acquire primacy over their respective 

programs, it is not uncommon to have varying requirements for these programs from state to 

state. This variation can affect how the oil and gas industry manages produced water within a 

basin that crosses between two states. 

Section 3.1.1 Clean Water Act and NPDES 

The Clean Water Act was established to protect water quality, which includes regulation of the 

NPDES permitting process. NPDES establishes, through a permit, pollutant limits on the 

discharge of produced water that generally include a volume (quantity) and concentration 

(quality) (U.S. EPA, 2004). Pollutants under the NPDES program fall into one of three 

categories: conventional, toxic, and non-conventional. There are two types of permits under 

the NPDES program that allow for the discharge of pollutants from point sources, individual 

permits, which are specific to an individual facility, and general permits, which cover multiple 

facilities within a specific permit category. 

There are two controls which are the basis for NPDES permit limit: 1) the EPA effluent limitation 

guidelines for a particular industry (which are technology based and vary by industry), and 2) 

water quality based limits (U.S. EPA, 2004). Effluent limitation guidelines developed by the EPA 

under the Clean Water Act include three guidelines for existing discharges and one for new 

discharges: 

Best conventional pollutant control technology (BCT) for conventional pollutants and 

applicable to existing discharges. 

Best practicable control technology currently available (BPT) for conventional, toxic, and 

non-conventional pollutants and applicable to existing discharges. 

Best available technology economically achievable (BAT) for toxic and non-conventional 

pollutants and applicable to existing discharges. 

New source performance standards (NSPS) for conventional pollutants and applicable to 

new sources. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

29

In addition to the controls on pollutant discharge established by the effluent limitation 

guidelines, the Clean Water Act has additional controls on pollutant discharges to water bodies 

that have been identified as currently being impaired because these waters do not meet water 

quality standards. The Total Maximum Daily Load (TMDL) program specifies the maximum 

amount of a pollutant that can be discharged to a body of water without exceeding established 

water quality standards and provides an allocation of the pollutant among the existing point and 

non-point sources of the pollutant (U.S. EPA 2005a). 

Section 3.1.2 Safe Drinking Water Act and Underground Injection Control 

The Safe Drinking Water Act was established to protect public health by regulating public 

drinking water supplies and to protect sources of drinking water. Through the Safe Drinking 

Water Act, the Underground Injection Control (UIC) Program was established to protect 

underground sources of drinking water from potential contamination from injection wells. 

Injection is responsible for approximately 60% of the produced water management activities for 

the oil and gas industry. The EPA’s classification of UIC wells defines a separate well class 

(Class II) for oil and gas brine injection wells, which includes disposal and enhanced recovery 

wells used in conventional oil and gas production (U.S. EPA, 2005b). Historically, Class I 

injection wells also have been used for disposal of oil and gas produced water. 

Class I injection wells typically are technologically sophisticated deep injection wells isolated by 

a confining zone from underground sources of drinking water; the injection formations typically 

are below the lowest underground source of drinking water (U.S. EPA, 2005b). Class I injection 

is sometimes identified as “deep” disposal injection when discussed relative to the oil and gas 

industry because the formations used for Class I injection are typically thousands of feet below 

the land surface and the injection of the fluids do not result in enhanced oil or gas recovery. 

The number of Class I injection wells in the United States is small relative to the number of 

Class II and Class V injection wells. 

Not all oil and gas produced water management injection wells are Class I and II wells. Recent 

activities associated with the management of produced water have started to utilize Class V 

wells. The Class V injection well category was created to categorize all the injection wells that 

did not fit into the more easily defined categories of Class I through Class IV. Class V wells can 

range from technologically simple septic systems to technologically advanced injection well 

systems. Simply put, the EPA defines Class V injection wells as any shallow well that is a bored, 

drilled, driven, or dug hole that is deeper than its width at its widest point. Class V wells 

typically are shallow wells which are used to place non-hazardous fluids below the land surface 

(U.S. EPA, 2005b). 

Section 3.2 Beneficial Use of Produced Water 

The beneficial use of produced water has become a popular water management alternative for 

regulators, operators, and landowners alike. Beneficial use in western states is considered a 

priority to prevent the potential wasting of a groundwater resource, and in many cases, oil and 

gas operators find beneficial uses to be a cost effective water management alternative. 

Additionally, the western United States’ climate is arid, and therefore water quality impacts and 

water wasting issues are a great concern. As a result, developers and resource managers are 

requested to find beneficial uses for produced water while minimizing potential impacts to the 

environment. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

30

Oil and gas operators are feeling pressure from both regulators and activist groups to find 

beneficial uses for the water produced with conventional oil and gas development activities. In 

general, some produced water is suitable for livestock and wildlife watering, agriculture, and 

other industrial uses. Beneficial uses of produced water have expanded in recent years with the 

invention of new treatment technologies. This has allowed more flexible management options 

for regulators to meet regional or local water needs. Examples of treatment technologies 

already in use are included in Section 4, and a discussion of cutting edge technologies currently 

being considered by the oil and gas industry is included in Section 5. 

Conventional oil and gas produced water can be of varying quality with lower quality produced 

water having TDS concentrations >200,000 mg/l, where some of the produced water from 

shallower oil and gas development can range from 100’s mg/l to 10,000’s mg/l TDS. A 

discussion of the water quality in various domestic oil and gas basins is included in Section 4. 

Higher TDS water typically will have more limited beneficial uses and treatment becomes more 

difficult and more expensive as TDS increases. Typically, water treatment technologies are 

limited to treating specific constituent types concentrated in water, e.g., dissolved solids, 

organics, conductive ions, etc. Depending on the eventual use of the water and the desired 

constituent concentrations, treatment processes are often coupled to achieve required water 

use objectives. For this reason, an integral aspect of the treatment process is the performance 

of water analysis to ascertain the presence of specific constituents for any given water source. 

This step provides various entities such as government agencies, oil and gas companies, or 

landowners the ability to choose a treatment technology (or technologies) best suited to 

achieve the necessary water quality objectives for beneficial use. 

Although states typically will define what they consider a beneficial use (generally incorporating 

the EPA’s beneficial use definition of livestock watering, wildlife watering, agricultural uses, and 

wetlands enhancement), other beneficial uses can include: 

Agriculture (impoundment stock water, irrigation, wildlife and waterfowl habitat, fish 

hatcheries, water leased) 

Municipal (domestic, fire protection, recreation uses) 

Industrial/Commercial (power, geothermal, mining, sediment control, erosion 

control, pollution abatement, navigation) 

In most cases, state regulations do not require that produced water be used for beneficial use, 

but instead mandate water quality standards specific to state water classification schemes that 

must be satisfied prior to the water’s beneficial use. The EPA, under 40 CFR Part 435, subpart 

E, provides the beneficial use exception rule to no discharge of produced water from oil and gas 

activities. This rule applies to the continental United States west of the 98th meridian, and 

allows for discharges of produced water if the produced water is clean enough to be used for 

wildlife and livestock watering or other agricultural use. Subpart E allows produced water of 

“good enough quality to be used for wildlife or livestock watering or other agricultural uses” but 

the water “must actually be put to such use during periods of discharge” (40 CFR Part 435, 

subpart E). However, Subpart E does not require beneficial use of good quality water nor does 

it require treatment of produced waters to meet the beneficial use options defined in Subpart E.
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

31

Section 3.3 NPDES Discharge Challenges 

The evolution of CBNG development and other continuous type reservoirs has resulted in the 

need to manage large quantities of produced water that are considered to be of high quality. 

One of the most economical means of managing high quality produced water is through direct 

discharge to surface waters, which also provides benefit to downstream users. 

Section 3.3.1 Challenges in Wyoming 

As the number of direct discharge outfalls from CBNG increases in the Wyoming portion of the 

Powder River Basin, Wyoming regulatory agencies and the EPA have begun to scrutinize 

Wyoming’s surface water quality and discharge regulations. Wyoming has primacy over their 

NPDES discharges, including produced water from both CBNG and conventional oil and gas 

operations. Currently, most of the discharges from conventional oil and gas development occur 

in watersheds that are Class 4, as defined by the Wyoming Chapter 1 surface water quality 

rules. Generally, Class 4 waters are those not designated as Class 1, where it has been 

determined that aquatic life uses are not attainable pursuant to the reclassification and sitespecific criteria provisions (WDEQ, 2001). Some of the surface waters in which conventional oil 

and gas produced water is being discharged have developed into perennial streams, which 

could result in their ability to support some species of fish. Conventional oil and gas operators 

have developed concerns that such a scenario is occurring. As a result, the EPA might 

reclassify these surface waters to Class 3 or better, which would prevent continued discharge of 

produced water (WOGCC Staff Personal Communication, 2005). This would negatively impact 

the ability to discharge, which could affect the ability of downstream users to beneficially use 

the water and damage the stream’s ability to support fish that have become acclimated to it. 

Personnel with the oil and gas operators in the Bighorn Basin have expressed concerns that a 

reclassification of waters from Class 4 to Class 3 or higher would require discharges of produced 

water to meet the Chapter 1 Water Quality Criteria for Priority Pollutants of Aquatic Life. Oil 

and gas operators believe the produced water being discharged from the actively permitted 

outfalls would not be capable of meeting the Chapter 1 standards without treatment. 

Draft changes currently available on the WDEQ Water Quality Division website for the Chapter 1 

Surface Water Standards might be the cause of some of the concerns that operators are having 

specific to the Priority Pollutant - chloride. The draft Chapter 1 regulation changes have in part 

been created to address concerns from the high salinity discharges from CBNG that have 

resulted in the development of Acute Aquatic Life Criteria for chloride of 230 ppm and Chronic 

Aquatic Life Criteria of 860 ppm. These changes, if applied to the current Chapter 1 water 

classifications, would be applicable to Class 3 surface waters in Wyoming, and thus could affect 

existing discharges to surface waters. However, the changes that are proposed in the draft 

version of the Chapter 1 standards for chloride currently are applicable only to certain surface 

water classifications. The proposed chloride standards are for surface waters in Class 1, 2AB, 

2B and 2C (WDEQ, 2005a). Therefore, the adoption of the draft three version of the Chapter 1 

Surface Water Standards, even if accompanied by a lowering of classification of the surface 

waters to which oil and gas operators in the Bighorn Basin are discharging into, would not 

result in an implementation of the chloride standard unless those waters change from Class 4 

waters to a Class 1, 2AB, 2B or 2C classification. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

32

Section 3.3.2 Inter-State Challenges between Wyoming and Montana 

Further complicating the management of CBNG produced water in the PRB is the fact that many 

of the significant watersheds in the basin flow in a northerly direction from Wyoming into 

Montana. This is the case with some of the major watersheds where CBNG development is 

occurring, including the Tongue and Powder River watersheds. In fact, much of the production 

from one of the thickest producing coal seams in the Wyoming portion of the basin, the Big 

George Coal, falls mainly within the Powder River Watershed. 

In an effort to limit impacts to watersheds flowing into Montana, Wyoming and Montana are 

working together and have generally agreed to manage CBNG produced water in such a fashion 

to avoid any changes in quality and quantity of the various applicable watersheds. More 

recently, Montana has proposed new rules presently being considered by the Montana 

Department of Environmental Quality’s (MDEQ’s) Board of Environmental Review (BER) to 

further restrict discharges of CBNG produced water. These proposed rules would change the 

way water would be managed throughout the entire PRB. Two of the more significant 

proposed amendments include Rules II and VIII. 

Proposed Rule II is a “zero discharge” requirement applicable to the Montana Pollutant 

Discharge Elimination System (MPDES) program. This proposed new rule requires that “(1) 

except as provided in [New Rules III through IX], point-sources of methane wastewater shall 

achieve zero discharge of pollutants, which represents the minimum technology-based 

requirement. Zero discharge shall be accomplished by reinjection [sic] of methane wastewater 

into suitable geologic formations in the project area in compliance with all other applicable 

federal and state laws and regulations.” The rule does provide a means to obtain an exemption 

from the injection requirement, but timeframes to obtain an exemption may be greater than 12 

months as the rule is currently proposed. 

Proposed Rule VIII establishes “treatment-based effluent limitations” for CBNG produced water.

The proposed rule requires that “(1) If the department grants a waiver from the zero discharge 

requirement for all or a portion of the wastewater pursuant to [New Rules II and III], the 

amount of wastewater that obtains the waiver shall achieve the following minimum technologybased effluent limitations at the end of the pipe prior to discharge:

(a) calcium average concentration between 0.1 mg/L and 0.2 mg/L; 

(b) magnesium average concentration between 0.1 mg/L and 0.6 mg/L; 

(c) sodium average concentration of 10 mg/L; 

(d) bicarbonate average concentration of 30 mg/L and instantaneous maximum 

 concentration of 115 mg/L; 

(e) sodium adsorption ratio instantaneous maximum of 0.5;

(f) electrical conductivity average concentration of 233 μmhos/cm; 

(g) total dissolved solids average concentration of 170 mg/L; 

(h) ammonia average concentration of 0.1 mg/L and instantaneous maximum 

 concentration of 0.3 mg/L; and 

(i) arsenic concentration of <0.0001 mg/L.”

Evaluation of the proposed amendments suggests that implementation of the new rules would 

significantly impede and/or likely cause the cessation of current and future CBNG development 

in the Wyoming portion of the PRB. Implementing a zero discharge requirement likely would 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

33

reduce production by 25 percent immediately upon enforcement of the rule. Within one year of 

implementation, production rates are expected to decrease by as much as 50 percent. Within 

five years, production likely would decline by 90 percent, eliminating much (if not all) of the 

potential production in the region. 

Section 3.4 UIC Program Challenges 

UIC wells for the management of produced water from conventional oil and gas activities are 

typically EPA Class II injection wells. Increasingly, however, produced water is being managed 

by way of Class V and Class I wells. 

Section 3.4.1 The Evolution of Class V Wells 

As oil and gas development expands into continuous reservoirs, the quality of water produced 

with the resources increases. As a result, water management options increasingly have begun 

to include the use of Class V injection wells. Class V injection wells have been used for aquifer 

recharge and aquifer storage and recovery in parts of the Rocky Mountain West as a means to 

beneficially manage produced water for future uses, including public water supply and as 

irrigation water. Class V wells are being used to manage large volumes of produced water from 

oil and gas production, something Class V was never meant to do. Class V wells that inject 

large volumes of produced water could be regulated as Class II wells by Class II agencies. If 

water is not being directly injected into active USDWs, the Class II agency has the background 

and regulatory framework to oversee wells that manage high volumes of low-toxicity wastes. 

Another question that has been raised by industry is whether subsurface irrigation could be 

considered to be a Class V injection activity. Subsurface irrigation facilities have the ability to 

manage large volumes of produced water, enabling ranchers and farmers to grow large 

amounts of hay and grain. The facilities share construction details with infiltration trenches that 

do not require Class V permits. Permitting subsurface irrigation in a reasonable manner will be 

a challenge for UIC regulators in the near future. Steps recently have been taken in Texas to 

allow for an authorization by rule; thus Class V approvals for subsurface drip irrigation have 

been streamlined to take no longer than 60 days (TCEQ, 2006). Similar steps can be taken in 

other states as well, as appropriate. 

Section 3.4.2 Classification of Brine 

Water produced with oil and gas can be treated to beneficial use standards. In the process of 

treatment, concentrated brine often is generated as a by-product. In respect to regulatory 

concerns, the brine is no longer considered as oil and gas production waste, and therefore does 

not qualify for the oil and gas exemption provided in the federal Resource Conservation and 

Recovery Act (RCRA). The brine can represent as little as 1% of the produced water volume, or 

as much as 70% of the produced water volume, depending on the quality of the produced 

water and the treatment process; however, it is considered an industrial process waste once the 

produced water has been treated. Currently, this brine can be determined to be either a Class I 

or Class II industrial process waste, and different states might have different criteria for making 

this determination. Classification of the brine appears to be sensitive to a number of things 

such as the physical arrangement of the treatment plant, the corrosiveness of the brine, and 

the use of the treated water. The classification may need to be standardized across the country 

to prevent the brine from being classified differently in the same basin, based on in which state 

the brine is generated. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

34

Section 3.5 Watershed Based Permitting 

The primary objectives of watershed based permitting are to develop an improved permitting 

process for surface discharges, improve environmental protection, and provide for more 

informed permitting decisions within a watershed by the governing regulatory agency. The 

approach is intended to: 1) provide a clear understanding of the limits and constraints of 

discharging produced waters; 2) provide equitable distribution of finite assimilative capacity; 

and 3) improve the mechanism to hear and address concerns of the stakeholders and 

understand the competing interests involved with the discharge of produced water. The holistic 

approach of looking at the impacts to an entire watershed allows the governing regulatory 

agency to make more informed decisions with regard to permitting discharges into the 

watershed.

Until recently, watershed based permitting had not been attempted. However, in 2005 the 

WDEQ implemented a watershed based approach to permitting discharge of CBNG produced 

waters into the Powder River watershed. Therefore, the steps the WDEQ has taken to 

implement watershed based permitting are included in Section 3.5.1 as a template for other 

state agencies to use in determining whether or not watershed based permitting would benefit 

their state. Advantages and disadvantages of watershed based permitting are discussed in 

Section 3.5.2. 

WDEQ’s approach was intended to address concerns over the increasing quantities and 

decreasing quality of produced water from CBNG development. A heightened concern by 

stakeholders over the cumulative impacts also spurred the process. These stakeholders include 

the landowners in Wyoming and downstream states of Montana and South Dakota, regulatory 

agencies in these states, and environmental interest groups. 

Parallel to the watershed based permitting process, the WDEQ developed an assimilative 

capacity allocation and control process for the Powder River mainstem to further preserve and 

protect the Powder River. The assimilative capacity control process has not been implemented 

at this time, but is expected to be in place soon. The Program Policy was issued for public 

comment and was presented in a September 2005 meeting of the Wyoming Water and 

Wastewater Advisory Board. The assimilative capacity control process will control the amount 

of TDS and sodium that can be discharged by CBNG produced water by using the calculated 

assimilative capacity of the Powder River and ‘credits’ calculated from coal volumes under an 

operator’s leased acreage. A description of the policy is included in Section 3.5.3 along with 

the implications of the calculated credits. 

Section 3.5.1 The Process 

The watershed based permitting process is a holistic approach that looks at surface water uses 

and processes within an entire watershed. The process can first be initiated by identifying all 

the stakeholders within a pre-defined watershed. These stakeholders may include government 

agencies, operators, landowners and users, and environmental interest groups. An initial public 

meeting can be held to discuss the watershed based permitting process. 

The next step can be collection of information about the surface water uses within the 

watershed. This information may be collected from sources that include the operators, 

landowners, USGS, EPA, BLM, Wyoming State Engineer’s Office (SEO), WDEQ, WOGCC, 

Wyoming Game and Fish Department, and the conservation districts. The data collected might 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

35

include information on seasonal stream flow quantity and quality, irrigation use, channel 

capacity, topography, erosion, and produced water quality and quantity. These data can be 

analyzed and summarized to identify water quality objectives. Water quality objectives may 

include:

Target flow volume limit, determined for each watershed. 

Target concentrations of constituents of concern, determined for each watershed. 

Potential water users. 

Based on these water quality objectives, discharge options can be evaluated, selected, and 

discussed with all area stakeholders at a public meeting. Current discharge options may include 

irrigation, on- and off-channel storage, direct discharge, treatment and discharge, re-injection, 

and consolidation of outfalls. 

Monitoring locations can be established within the watershed and a monitoring plan can be 

developed. The monitoring plan may address the constituents of concern, sampling and 

reporting frequency, responsibilities, and contingencies. Permitees can be held responsible for 

monitoring and reporting, and can conduct these activities independently, or they can 

collaborate with other permit holders within the watershed. 

The governing agency might then develop permit conditions and draft the permit. It is up to 

the area stakeholders involved whether a general permit will be issued for the watershed or if 

individual permits will be required. If a general permit is issued, a notice to the public may be 

published and the permit made available for public review and comment. The governing 

agency can respond to public comments, if any, and then issue the permit. The general permit 

can define TDS and sodium limits within the watershed at the monitoring points. The permit 

can also establish cumulative discharge limits for all the discharge points above the monitoring 

points. These discharge limits may be year-round limits or vary month-by-month, but are not 

to be exceeded. 

Any operator wishing to discharge under a general permit must submit a notice of intent to 

discharge to the governing agency prior to discharge. The notice of intent will specify the 

location of discharge points and the maximum discharge volume. The notice of intent also will 

supply analyses of the proposed discharge water to demonstrate its similarity to prevailing 

produced water quality standards. 

If stakeholders require individual permits, then a permit application must be filed by the 

operator and reviewed by the governing agency. The agency would then draft an individual 

permit, issue it for public review and comment, and then prepare a final permit after the 

comment period. 

Currently, the watershed based permitting process is underway for the undeveloped hydrologic 

unit code (HUC) 10 watersheds within the Powder River Drainage. As existing WPDES 

discharge permits for CBNG produced water expire, they will be rolled into a watershed based 

permit, either general or individual, based on the preference of the watershed stakeholders. 

CBNG produced water discharges within the Tongue and the Belle Fourche drainages in 

Wyoming will be subject to watershed based permitting in the future (WDEQ, 2005b). 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

36

Section 3.5.2 Advantages and Disadvantages 

The primary advantage of watershed based permitting is the involvement of all stakeholders 

and management of assimilative capacity within the watershed. Each stakeholder is given the 

opportunity to voice concerns and be included in decision making during the permitting process. 

As such, one disadvantage is the process may be exhaustive and can prolong the permitting 

process.

Section 3.5.3 Assimilative Capacity Allocation and Control System 

Parallel with the watershed based permitting process, the WDEQ has developed an Assimilative 

Capacity Allocation and Control System for protecting and managing the surface water quality 

of the Powder River consistent with both Wyoming and Montana conditions while providing for 

the development of the CBNG resources of Wyoming. A draft Program Policy was developed 

and issued for public comment. The WDEQ worked toward implementation of the policy, and 

believed it would be in effect in early 2006 (WDEQ, 2005b). Implementation of the assimilative 

capacity and control system on the Powder River mainstem involves five principle parts: 

1) Determine the assimilative capacity of the Powder River mainstem. The WDEQ 

will use ambient water quality data collected at the USGS gauging station near 

Moorehead, Montana, in predictive models to assess the assimilative capacity of the 

Powder River. The available load will be calculated in pounds per day for each month 

and will be reduced by 5 percent to allow a reasonable margin of safety. 

2) Establish credits for assimilative capacity. The modeled assimilative capacity will 

be divided into credits representing 10 pounds of total dissolved solids or sodium. The 

credits will be calculated from the CBNG operator’s share of mineral lease acreage 

multiplied by the calculated coal volume under the lease. Each credit is valid only for 

the month in which it is calculated and issued. Historical monthly flows of the Powder 

River are used for monthly allocation of credits. 

3) Regulate credits through issuance of a general permit. A general permit will be 

the vehicle used to regulate and allocate the calculated available mass loading of TDS 

and sodium for discharges of CBNG produced water in the entire Powder River mainstem 

watershed. The WDEQ will issue this permit after public notice and comment. 

4) Establish a Credit Registration procedure. The Wyoming Geological Survey (WGS) 

will act as the Registrar and will implement the registration procedures. The WGS will 

issue a map and list calculated coal thicknesses, by section, of the Powder River 

watershed. For the purposes of the assimilative capacity allocation and control policy, it 

will be assumed that all coal seams will produce the same volume of water per 

measured unit of thickness. 

5) Establish a Credit Tracking Mechanism, or credit bank. Permitted discharges 

based on appropriated credits will be debited from the appropriate CBNG operator’s 

credit bank account, which will be managed by the WDEQ. Individual and/or watershed 

permits will continue to regulate limits required by Chapter 1 and Chapter 2 (WWQRR) 

and as necessary to protect local and watershed conditions in addition to TDS and 

sodium for the Powder River mainstem. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

37

GENERAL POWDER RIVER MAINSTEM PERMIT AND CREDITS

All CBNG produced water discharging into the Powder River mainstem, tributaries, and onchannel reservoirs will require an applicable general, individual, or watershed permit in 

accordance with the Chapter 2, WWQRR. Upon implementation of the Assimilative Capacity 

Policy, new and renewed CBNG produced water discharge permits will be issued in conformance 

with available credits authorized by the Powder River Mainstem General Permit. Dischargers 

will continue to comply with their existing permit until reopened, renewed, or a major 

modification is made, at which time the individual permit will be brought into conformity with 

the Assimilative Capacity Policy. 

Upon application for a new permit, a major modification to an existing permit, or a permit 

renewal, the permittee must submit a water management plan that describes how the produced 

water will be discharged/managed through the use of credits, treatment, impoundment, or 

other means. The WDEQ will then verify through the credit bank that the applicant has 

sufficient credits or facilities to implement its water management plan. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

38

THIS PAGE INTENTIONALLY LEFT BLANK 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

39

SECTION 4.0 PRODUCED WATER MANAGEMENT PRACTICES 

It is paramount that produced water be managed in innovative ways that will both reduce the 

operational cost to produce oil and gas reserves as well as be protective of the environment. A 

common misconception is that there is one management practice that will work throughout the 

United States to manage the produced water in a responsible way. Quite the opposite is true. 

In fact, produced water management practices vary widely across the United States, and in 

some instances across a single oil and gas field. Produced water management falls under two 

broad categories: underground injection and surface management. Water treatment is also a 

produced water management practice, but the end result of a water treatment facility is 1) a 

higher quality stream of water that must be managed at the surface, and 2) a concentrated 

stream of wastewater that must be disposed through underground injection. Therefore, water 

treatment is discussed at the end of this section as a means of transforming the water quality 

to make best use of the water as a resource, and not as a “management practice”. 

Underground Injection encompasses a wide range of water management practices. The 

EPA classifies five different injection well categories, and three of them are applicable in one 

way or another to the management of produced water from oil and gas development. In 

general, oil and gas produced water is an exempt waste and therefore can be injected in 

Class II or Class V injection wells. Operators of Class II wells inject fluids associated with oil 

and natural gas production (EPA, 2005). Class II injection wells can either be classified as 

disposal wells (IID) or as enhanced recovery wells (IIR). The process wastewater that is 

the result of produced water treatment, however, does not carry the same exemption; 

therefore it must be disposed of in a Class I injection well. The EPA defines Class I wells as 

technologically sophisticated wells that inject hazardous and non-hazardous wastes below 

the lowermost underground source of drinking water (USDW). Injection occurs into deep, 

isolated rock formations that are separated from the lowermost USDW by layers of 

impermeable clay and rock (EPA, 2005). Class V wells (i.e. shallow injection, subsurface drip 

irrigation) are injection wells that are not included in the other classes, and generally their 

simple construction provides little or no protection against possible groundwater 

contamination; therefore, it is important to control what goes into them (EPA, 2005). 

Surface Management includes all water management practices where the water (whether 

it be raw produced water, or treated produced water) is managed at the surface by either 

discharging directly into a water course, into an impoundment, or to the land for some 

beneficial use. Once the water has been brought to the surface, a number of techniques, 

processes, approaches, and/or beneficial uses can be applied to enhance the management 

of the water and lower the associated costs for the operator. These include, but are not 

limited to, surface impoundments (i.e. stock watering/irrigation storage ponds, evaporation 

ponds, enhanced evaporation/aeration ponds, recreational ponds, constructed wetlands) 

and industrial uses (i.e. cooling tower water, dust suppression, truck wash station, oil and 

gas completion activities). 

As noted above, there is a wide range of water management practices and alternatives that fall 

under these two categories. This section provides a more detailed description of these water 

management practices and alternatives. Class I wells are discussed in terms of the applicability 

and constraints for managing the process wastewater from water treatment processes. Class II 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

40

wells, Class V wells, and the various surface management practices are discussed in terms of 

their applicability and their constraints for managing produced water. 

Section 4.1 Class I Injection 

Class I injection wells are technologically sophisticated wells that inject large volumes of 

industrial hazardous or non-hazardous wastes into deep, isolated rock formations that are 

separated from the lower most USDW by layers of impermeable clay and rock. Although most 

hazardous waste fluids are treated and released to surface waters, Class I wells account for 89 

percent of the hazardous waste fluids disposed of on land (GWPC, 2006). Class I wells are 

classified as hazardous or non-hazardous, depending on the characteristics of the wastewaters 

injected. For instance, municipal waste is classified as non-hazardous. The EPA regulates Class 

I underground injection wells under the Safe Drinking Water Act (SDWA) and the Hazardous 

and Solid Waste Amendments of the Resource Conservation and Recovery Act (RCRA). These 

regulations establish siting, design, construction, and monitoring requirements for these 

injection wells to ensure protection of USDWs from injected wastewater (EPA, 2001a). 

Underground injection of wastewater began in the 1930s when oil companies began disposing 

of oilfield brines and other oil and gas waste products into depleted reservoirs. Most of the 

early injection wells were oil production wells converted for wastewater disposal. In the 1950s, 

injection of hazardous chemical and steel industry wastes began. At that time, four Class I wells 

were reported; by 1963, there were 30 wells. In the mid 1960s and 1970s, Class I injection 

began to increase sharply, growing at a rate of more than 20 wells per year (EPA, 2001a). 

Currently, under the UIC Program, the EPA and the states regulate more than 400,000 injection 

wells. Class I wells comprise less than 1% of the injection wells in the U.S. (GWPC, 2006). 

There are 272 active Class I injection facilities nationwide. Of these, 51 are hazardous and 221 

are non-hazardous. These 272 facilities maintain approximately 529 Class I injection wells that 

are scattered throughout the U.S. in 19 states (EPA, 2006). The 51 hazardous injection 

facilities are composed of 163 Class I hazardous waste injection wells, most of which are 

located in Texas (78) and Louisiana (18) (see Figure 4.1). Eleven of the facilities are 

commercial hazardous waste injection facilities. These are the only facilities that can accept 

hazardous waste generated offsite for injection. Ten of them are located in the Gulf Coast 

region while one is located in the Great Lakes region. There are 366 Class I non-hazardous 

injection wells nationwide. While these wells are scattered through 19 states, most of them are 

found in the states of Florida (112) and Texas (110) (EPA, 2006). 

Class I wells are used mainly in the petroleum refining, metal production, chemical production, 

pharmaceutical production, commercial disposal, and municipal disposal industries (EPA, 2006). 

However, almost half of the fluids injected into non-hazardous and municipal waste injection 

wells are manufacturing wastes; municipal effluent accounts for approximately 28% of the Class 

I non-hazardous wastes (GWPC, 2006). 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

41

Figure 4.1 Approximate Class I Well Count in Each State
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

42

Applicability

The use of Class I injection wells for produced water management has limited applicability to 

the oil and gas industry. However, certain circumstances may arise that will require or dictate 

disposal via Class I injection. If produced water is used for industrial purposes, then the 

disposal of the water could be required by use of a Class I injection well (ALL and MBOGC, 

2002). Additionally, concentrated produced water waste streams generated as a byproduct 

from certain treatment technologies (e.g., reverse osmosis, ion exchange, distillation, etc.) 

could require disposal using Class I injection wells. 

Constraints

Class I wells must be sited so that wastewaters are injected into a formation that is below the 

lowermost formation containing, within one-quarter mile of the well, a USDW (EPA, 2001a). 

Typically, Class I fluids are injected deep into geologic formations thousands of feet below the 

land surface composed of brine-saturated formations or non-freshwater zones. In the Great 

Lakes region, for example, injection well depths typically range from 1,700 to 6,000 feet; in the 

Gulf Coast, depths range from 2,200 to 12,000 feet or more (EPA, 2001a). Fluids at these 

depths move very slowly, on the order of a few feet per hundred or even thousand years, 

meaning that fluids injected into the deep subsurface are likely to remain confined for a long 

time (EPA, 2001a). 

EPA requires that Class I wells be located in geologically stable areas that are free of 

transmissive fractures or faults through which injected fluids could travel to drinking water 

sources (EPA, 2001a). Well operators must also show that there are no wells or other artificial 

pathways between the injection zone and USDWs through which fluids can travel. Extensive 

pre-siting geological tests can be used to confirm that the injection zone is of sufficient lateral 

extent and thickness, as well as sufficiently porous and permeable, so that the fluids injected 

through the well can enter the rock formation without an excessive build-up of pressure and 

possible displacement of injected fluids outside of the intended zone (EPA, 2001a). In addition 

this “injection zone” should be overlain by one or more layers of relatively impermeable rock 

that will hold injected fluids in place and not allow them to move vertically toward a USDW 

(confining zone)( EPA, 2001a). 

In 1984, Congress enacted the Hazardous and Solid Waste Amendments (HSWA) to RCRA that 

banned the land disposal of hazardous waste, unless the hazardous waste is treated to meet 

specific standards. EPA amended the UIC regulations in 1988 to address the Hazardous and 

Solid Waste Amendments. Operators of Class I wells are exempt from the ban if they 

demonstrate that the hazardous constituents of the wastewater will not migrate from the 

disposal site for 10,000 years or as long as the wastewater remains hazardous. This 

demonstration is known as a no-migration petition (EPA, 2001a and EPA, 2006). 

Section 4.2 Class II Injection 

Injection wells used for disposal or enhanced recovery below any USDW are classified by the 

EPA as Class II wells, and they commonly are used for managing produced water in 

conventional oil and gas operations. Class II wells have to follow strict construction and 

conversion standards except when historical practices in the state and geology allow for 

different standards. A Class II well that follows EPA federal standards is built very much the 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

43

same as a Class I well. There are approximately 167,000 oil and gas injection wells in the 

United States, most of which are used for the secondary recovery of oil. The majority of the oil 

and gas injection wells are located in the Southwest, with Texas having the largest number 

(53,000) and California, Oklahoma, and Kansas following some distance behind with 25,000, 

22,000, and 15,000 wells, respectively. Figure 4.2 shows the approximate count for Class II 

injection wells in each state. 

Class II injection wells are subdivided as either IID (for disposal) or IIR (for secondary oil 

recovery). Over 2 billion gallons of produced water are injected daily into Class II injection 

wells in the United States (EPA, 2005). The largest portion of the water is injected into Class 

IIR wells. In a common configuration, one injection well is surrounded by four or more 

extraction wells. The recovered fluid is sent to a phase separator where the oil, gas, and water 

can be separated. In Class IID wells, excess water from production and some other activities 

directly related to the production process are injected solely for the purpose of disposal. 

Applicability

Class II injection is applicable for a wide range of produced water quality in terms of TDS; 

however, for produced water that is of high quality (i.e. TDS less than 10,000 mg/L) Class II 

may not be a reasonable option as the water resource may be wasted through injection into a 

lower quality aquifer. Successful Class II wells may be able to accept more than 50,000 barrels 

of water per day while unsuccessful wells will take little or no water. 

Class IIR injection is applicable in many conventional oil fields. Waterfloods consist of a number 

of injection wells in a particular field that are coordinated to move the oil that remains in the 

target reservoir toward the producing wells in the subject field. A waterflood project can 

consist of less than a dozen wells or several hundred wells. Each of the operating waterfloods 

uses injection wells to inject water back into the oil reservoir to maintain reservoir energy and 

drive more oil toward the producing wells. The injected water can be water produced from the 

field being waterflooded, or it can be “make-up” water obtained from another source. In some 

cases the original field wells do not produce enough water with the oil to support a flood project 

and in those cases the operator will either postpone the flood project or will find make-up water 

from nearby production, surface water, or groundwater produced through water supply wells. 

As the waterflood continues, the reservoir fills up and eventually the injected water and 

additional oil will be seen at the producing wells. As production continues, the water produced 

in the oil wells replaces make-up water and the flood becomes more or less self-sustaining so 

no outside water is needed. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

44

Figure 4.2 Approximate Class II Well Count in Each State
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

45

Class IID injection is applicable into underground reservoirs that are greater than 10,000 mg/L 

TDS or are identified as an exempted aquifer. Deep aquifers that could be suitable for injection 

may contain less than 10,000 mg/L TDS and would require an aquifer exemption in order to 

receive injectate. Aquifer exemptions are written in federal EPA regulations and are meant to 

avoid giving full protection to aquifers that will never be used for public water supply because of 

the cost of producing and treating the water. It would be risky to put a depth limit or water 

quality limit on an aquifer before it might qualify for an aquifer exemption; if the aquifer is 

deeper than 10,000 feet, it is unlikely that it would be an economic source of drinking water for 

a public water supply. These deep Class IID wells are generally expected to be able to inject 

large volumes of water in an environmentally safe and unobtrusive manner. These injection 

zones can be very deep and isolated by thick, impermeable confining zones safely confining the 

injectate away from drinking water aquifers. Wells will be inherently safe, thus providing 

minimal environmental concerns. 

Technological advances in the use of Class II wells has lead to the development of horizontal 

disposal and enhanced recovery wells that have opened up new fronts in once marginal fields. 

In the Oklahoma City field of the Arkoma Basin, once thought depleted, a process known as 

“de-watering” has proven to be effective in recovering oil and gas along with high volumes of 

water. The process is economical due to the efficient water management system that runs the 

water through a high volume phase separator prior to injection of the water in a horizontal 

disposal well capable of handling 60,000 barrels of water per day. 

Constraints

Feasibility of underground injection as 

a tool for managing produced water 

involves several technical 

considerations including geologic, 

economic, and engineering questions. 

These may vary significantly by 

operator and location. There are, 

however, a common set of questions 

that must be answered for any 

proposed injection well (ALL, 2006), 

including:

Formation Suitability: Selection 

of a suitable injection zone potentially might include reservoir characteristics; depth; relative 

location to producing wells and locally important aquifers; significance of local fracturing 

and faulting; condition of active and abandoned wells within the area; as well as other 

artificial penetrations. 

Isolation: The receiving formation must be vertically and laterally separated or otherwise 

confined from other USDWs. The well must also be equipped to isolate the receiving zone 

from other porous zones in the well to avoid unauthorized fluid movement into zones that 

are not permitted for injection. 

High Volume Phase 

Separator Used in a 

“De-watering” Project 

(Oklahoma)
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

46

Porosity: Porosity is the percentage of void spaces or openings in a consolidated or 

unconsolidated material (EPA, 1999). Reservoir rocks are typically high in porosity, while 

confining zone rocks range from high to very low porosity. 

Permeability: Permeability is defined as a measure of the relative ease with which a 

porous medium can transmit a liquid under a potential gradient (EPA, 1999). A reservoir 

rock will have sufficiently high permeability to allow fluid movement. Confining zone rocks 

will have very low permeability and will act as seals rather than zones of fluid movement. 

Often porosity and permeability are not correlative; highly porous sands can have very low 

permeability while low porosity sands can be highly permeable due to natural fractures. 

Storage Capacity: The storage capacity of a geologic unit can be estimated using a 

simplistic approach by estimating the pore volume of the entire injection zone. 

Reservoir Pressure: The reservoir pressure is the static pressure within the receiving 

formation expressed either as pound per square inch or fluid head. Reservoir pressure may 

limit the rate at which fluids can be injected and/or may limit the total volume of fluid that 

can be injected. 

Water Quality: The quality and chemistry of water of the injectate and water within the 

receiving formation will determine the type of injection well to be used. The chemical 

compatibility of their fluids will also play a part in the feasibility assessment of the injection 

plan. Compatibility tests can be run prior to installing necessary pipelines to deliver the 

water. In order to be reliable, the test will require sidewall or full-hole cores of the 

reservoir; these are usually obtained when an oil operator is beginning to exploit a new 

field. Important aspects of a compatibility test will be pore-throat size range to determine 

the filter system and the presence of clays and other mineral grains that can react, swell, or 

become mobile when exposed to the injected water. If incompatibility is discovered, the 

testing contractor will be able to recommend a chemical additive that may prevent the 

reaction.

Technically feasible injection requires that the injection rate is sufficient for the operator’s needs 

without exceeding the fracture pressure of the confining zone. The operator can test the 

injection zone to verify fracture pressure and injectivity – the injection rate as it is related to the 

injection pressure. Injection pressure can exceed the fracture pressure in the injection zone but 

cannot exceed the fracture pressure of the confining zone. This is best determined by step-rate 

tests. Prior to use, the injection zone may need to be stimulated by way of acidization or 

fracturing. This might involve pumping small amounts of weak acid or large volumes of fluid 

with sand to prop open the fractures in the injection zone (ALL, 2006). 

Class IID deep wells must be demonstrated to be safe and protective of the environment. 

Mechanical and engineering integrity must be shown prior to the well being used; the injection 

zone must be isolated from other aquifers and USDWs. The operator must show that the deep 

injection zone is isolated from other permeable zones away from the borehole and the injection 

perforations are isolated from the long-string casing in the well. The former – stratigraphic 

isolation – can be demonstrated by wire-line log cross-sections through the proposed injection 

well and nearby wells; stratigraphy can illustrate local and regional isolation. At the same time, 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

47

integrity of the injection tubing and packer on top of the injection perforations can be tested by 

pressuring up on the long-string casing to check for leaks. 

Section 4.3 Class V Injection 

Class V injection wells are defined by the EPA as any well that does not fit under the other four 

classes (I, II, III, and IV). Typically, Class V injection wells are shallow "wells," such as septic 

systems and drywells, used to place non-hazardous fluids directly below the land surface. The 

minimum requirements for a Class V injection well have been set by Volume 40 of the Code of 

Federal Regulations (40 CFR) Sections 144-147, as well as within state promulgated Rules and 

Regulations. The EPA estimates there are more than 650,000 Class V wells in the United States 

(EPA, 2001b). Examples of Class V injection wells used to manage produced water include: 

Subsurface Drip Irrigation (SDI) supplies water to crops by a system of hoses and 

pipes buried in a network of trenches under the field within the root zone of the crops. 

SDI allows enhanced crop production without negative environmental impacts 

associated with leaching or runoff. Water can be applied year-round instead of just 

during the typical growing season of most crops, allowing for more water to be 

beneficially used, and reducing or eliminating the need to store produced water during 

winter months. SDI application of water during non-growing months may not represent 

irrigation but may be seen as a beneficial use in the aid of the soil and subsoil, flushing 

the salts below the root zone. An added benefit is an increase in crop production for the 

surface landowner. 

Aquifer Storage and Recovery (ASR) is the process of injecting water into an 

aquifer for storage and subsequent recovery for beneficial use using the same well. 

Beneficial uses include, but are not limited to, public drinking water, agricultural uses, 

future recharge, and industrial uses. The storage aquifers may be the primary drinking 

water source for a region, a secondary drinking water source, or may be used for 

agricultural or industrial purposes. ASR is regularly used in areas with no drinking water 

source, areas undergoing seasonal depletions, and in areas where salt water is intruding 

into the fresh water aquifer (EPA, 1999). When injection is considered using Class V 

type wells for beneficial uses, pre-treatment of the produced water may be required 

before it is injected into an aquifer for either recharge or ASR. For example, treatment 

of water may be required to prevent the injection of bacteria contaminated water when 

the water has been temporarily stored in an impoundment. 

Section 4.3.1 Subsurface Drip Irrigation (SDI) 

Irrigation is a common and proven beneficial use of produced water when the water quality is 

sufficient and compatible with soil conditions. In arid regions, good sources of water for 

irrigation are not abundant except near rivers and reservoirs; therefore, good sources of usable 

water are desirable for farmers and ranchers for irrigation use. Some of the problems 

associated with typical surface irrigation include soil crusting on the surface, dispersion, and salt 

accumulation in the root zone. SDI supplies water to crops by a system of hoses and pipes 

buried in a network of trenches under the field. The water enters the soil below the soil surface 

avoiding these problems. Subsurface drip irrigation has long been used in Israel and Australia 

with high quality and saline water (KSU, 2005). Figure 4.3 illustrates a typical SDI system. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

48

Applicability

SDI appears to be a well suited type of irrigation available for use with produced water as it 

avoids some of the drawbacks of surface irrigation. There is increased flexibility in matching 

field shape and field size, and SDI’s pressure compensating systems are not as limited as 

surface irrigation in regard to the slope. Furthermore, since the SDI process applies irrigation 

water to the subsurface, operators might be able to pump water year round; field operations 

can occur during irrigation; less irrigation equipment is exposed to vehicular damage; there is 

no surface soil crusting; any salt accumulation is below the root zone; there is less or no runoff 

into streams; and reduced weather-related application constraints (especially high winds and 

freezing temperatures). Other advantages include decreased energy costs as compared to 

other irrigation systems; improved in-field uniformities, resulting in better control of the water, 

nutrients and salts; and the SDI system can be easily and economically sized to the available 

water supply. 

 Figure 4.3 Diagram of SDI System

Source: KSU, 2005 

Crop selection is also important with the use of SDI. Optimum plant species will vary with 

different regions of the United States. Perennial crops are the most suited for SDI, with alfalfa 

and refined grasses as some of the better candidates. Alfalfa, a forage crop, has high crop 

water needs and, thus, can benefit from highly efficient irrigation systems such as SDI. In 

some regions, the water allocation is limited by physical or institutional constraints, so SDI can 

effectively increase alfalfa production by increasing the crop transpiration while reducing or 

eliminating soil evaporation. Since alfalfa is such a high-water user and has a very long 

growing season, irrigation labor requirements with SDI can be reduced relative to less efficient 

alternative irrigation systems that would require more irrigation events. Currently, SDI is used 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

49

to irrigate a number of alfalfa fields in the Powder River Basin of Wyoming, and it is estimated 

that about 60 inches of water can be applied annually, with the crop using 40 inches of that 

water through evapotranspiration (Zupancic, 2005). Continuation of irrigation reduces the 

amount of water stress on the alfalfa and, thus, can increase forage production that is generally 

linearly related to transpiration. Salt tolerant or moderately tolerant grass species such as 

halophytes or mixes of grass should be chosen for use with SDI. 

Constraints

Constraints that may limit the attractiveness of utilizing a SDI system include, but are not 

limited to:

Regulatory - Permits vary from state to state. The permitting process can add to the 

time required before the operator can start using SDI irrigation with oil and gas 

produced water and can add to the cost of implementation. 

Water Pre-Treatment – Proper leaching leads to flushing salts below the root zone by 

applying more water than the plant needs. There is a potential for salt accumulation to 

occur above the root zone if appropriate leaching is not performed during irrigation. 

Often this leaching process can be facilitated by natural rainfall. However, gypsum, or 

other amendments, might need to be used to help reduce SAR in the soil. 

Operational Challenges – Various operational issues exist that may cause constraints 

to the installation of a SDI system. Examples include limitations to soil tillage options, 

lack of ability to visually inspect the system to troubleshoot malfunctions leading to more 

difficult subsurface repairs, and root intrusion into drip lines. 

Groundwater Impacts – If the groundwater in alluvial aquifers is shallow, there could 

be a possibility that saline water could affect the aquifer. For groundwater to be 

impacted by SDI systems, saturated flow must exist through the soil/unsaturated zone 

to the point where water is moving in a continuous wetting front under gravity to the 

groundwater table. If produced water is applied in accordance with crop needs, soil 

water holding capacities, climatic characteristics, soil infiltration rates, and leaching 

requirements, the aquifer should not be affected. It may be necessary to perform 

modeling to avoid this situation, especially if the water is applied on a continual basis 

throughout the year.
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

50

Section 4.3.2 Aquifer Storage Recovery Wells 

Underground injection into shallow aquifers offers a potential means for managing water 

produced from oil and gas wells. This type of injection uses boreholes drilled into shallow 

formations, such as sands, that are classified as USDWs, and then involves the pumping of the 

produced water into those formations to replenish depleted aquifers that might have 

experienced several years of pumping for domestic or municipal supply. 

Applicability

 The use of ASR wells for produced water management is applicable in areas where the quality 

of the produced water is of a useable nature, or can be easily treated to a useable level. 

Furthermore, this management practice is most 

likely to be applicable in arid regions where the 

water supply can be heavily impacted by 

droughts. Existing non-productive wells may 

be nearby and available to the operator at low 

cost with minimal pipeline costs, making this 

type of water management practice even more 

practical. Applicability further depends on the 

ability of the formation to accept water at a 

rate commensurate with the cost to implement 

this management practice. 

Perhaps the most prominent example of an 

ASR project was where the City of Gillette, 

Wyoming’s well field had been locally depleted. 

The well field was completed in Lower Fort 

Union sands at a depth of approximately 1,500 

feet. These sands had been pumped for a 

number of years to supply water for public use 

and consumption. Over time, water levels in 

the city’s wells had decreased considerably. 

The city coordinated with a CBNG operator to install Class V aquifer recharge wells that were 

sufficient to manage all of the produced water from a small, CBNG producing project. In this 

example, the best injection well averaged more than 1 million barrels per year for more than 

three years (Olson, 2005). Although this example is unique, it does illustrate the potential 

capability of ASR Class V shallow injection wells. 

Constraints

The most serious constraint for ASR Class V wells appears to be the loss of permeability over 

time. Permeability losses could be caused by plugging of reservoir pores with fines suspended 

in the water or by clay swelling (Olson, 2005). These problems are common to all types of 

injection wells that require careful pre-injection tests to determine the vulnerability of the 

aquifer’s rock-frame to plugging by fines and to chemical effects. Injection testing might 

involve either full-hole or sidewall cores through the aquifer and lab tests of pore-throat sizes 

and water-rock compatibility analysis. Tests might be necessary on each injection well due to 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

51

aquifer variations and other issues that have the potential to negatively impact placing water 

underground. 

Permeability constraints may be overcome by injecting at higher pressures. In Class V wells, 

this might mean pressures over the local fracture pressure. High pressure injection can be 

difficult to permit but might allow the disposal of large volumes of produced water. 

Water also might need to be treated before injection to insure that it meets water quality 

constraints that can be part of state permit requirements, or otherwise required by a water 

user. Treatment of the water is dependant upon the quality of the water, the proposed use of 

the water, and the storage history of the water, if any. 

Section 4.4 Surface Discharge 

Surface discharge involves release of produced water onto the earth’s surface, either to surface 

water or to a watercourse. Surface discharge is a water management option that allows water 

to augment stream water flow. Increasing stream water flow can enhance riparian areas and 

provide additional water resources to support agriculture. Releases to surface water resources 

must be carefully managed, however, to maintain state specified water quality standards and to 

avoid excessive riparian erosion. The specific amount of water that can be managed by surface 

discharge will depend upon the 

existing characteristics of the stream 

and the quality of the produced 

water.

Applicability

Surface discharges are applicable in 

a variety of instances, such as: 

Direct discharge to surface 

waters. In this situation, 

water is delivered to a 

stream by pipeline or dry 

drainage where it mixes with 

existing stream flow. 

Discharge to surface 

impoundments with possible infiltration into the subsurface and surface water. This is 

further discussed in Section 4.5. 

Discharge to surface soil with possible runoff to surface water. This involves the release 

and management of water through different irrigation techniques. Specific management 

and site conditions will determine the rate of water that can be discharged to the 

surface, as well as the possibility of any runoff and subsequent discharge to surface 

water. If irrigation and runoff rates are high, significant volumes of water can enter and 

mix with surface water. This is further discussed in Section 4.6. 

Surface discharges can be managed through evaporation and infiltration into subsoil and 

bedrock aquifers. When water enters a shallow aquifer, the water could migrate to surface 

water. Management of this water allows operators to discharge significant volumes of water 

Surface Discharge in 

the Belle Creek Field 

(Montana)
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

52

that can be available for beneficial use with minimal impact on the environment. Additionally, 

the discharge of produced water can bolster seasonal flows of local rivers and accommodate 

more beneficial uses. Various discharge scenarios can be considered based on the quantity and 

quality of the produced water and the receiving water. Discharges directly to surface waters, 

such as streams and rivers, can be accomplished by the use of pipelines. The pipeline method 

avoids erosion and the incorporation of suspended sediments, which can impact stream water 

quality. Pipeline use prevents interaction of produced water with local soil and bedrock. 

Water has successfully been managed through this technique for several years in the Big Horn 

Basin of Wyoming and Montana, as well as in the Belle Creek Field in the Powder River Basin of 

Montana. Prior to discharge the water is separated from fugitive oil and grease, but the quality 

of the water in many instances is such that it provides a tremendous source of beneficial uses 

to downstream water users. 

Constraints

The quality of the produced water is a major constraint on the ability to discharge to the 

surface. If the quality of the produced water is such that it negatively impacts the receiving 

water quality, then surface discharge is not an option without treating the water to an 

acceptable quality. 

The flow rate of the produced water stream in relation to the receiving stream may also limit 

the ability to discharge to the surface. If the produced water stream flow rate is considerably 

high relative to the receiving stream, then erosion may be a serious cause for concern as the 

additional flow may cause the side slopes and bed of the stream to be transported downstream, 

causing sedimentation issues at downstream reservoirs and low energy points along the stream. 

Section 4.5 Surface Impoundments 

A surface impoundment is an excavation or diked area that is typically used for the treatment, 

storage, or disposal of liquids (EPA, 1991) and can vary from less than one acre in size to 

several hundred acres. Impoundments are usually constructed in low permeable soils, with the 

possible exception of recharge ponds, to prevent or decrease raw water loss due to subsurface 

infiltration or percolation. Based upon an EPA national impoundment survey that characterized 

more than 180,000 impoundments, the oil and gas industry is considered one of the largest 

users of this technology. A breakdown of applied impoundment uses by this industry includes 

storage (29%), disposal (67%), and treatment (4%) (EPA, 1991). 

The impoundment of produced water from oil and gas production can be an option utilized by 

operators as part of their water management practices. In some producing basins, 

impoundments play a large role in water management practices, while in other basins 

impoundments might be used only during drilling operations. 

The impoundment of produced water is the placement of water produced during operations at 

the surface in a pit or pond. There are a variety of ways in which operators can impound 

produced water at the surface. Impoundments can be constructed on- or off-channel, and the 

regulatory authority in some states varies based on whether the impoundments are on- or offchannel. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

53

Impoundments can be used for a variety of water management options, including disposal by 

evaporation and/or infiltration; storage prior to other water management options such as 

injection or irrigation; or for beneficial use such as a fishpond, livestock and wildlife watering 

ponds, or a recreational pond. The impoundment of water can be performed in any area where 

there is sufficient construction space. Impoundments can be constructed to provide a single 

management option, or a combination of management options that include livestock and 

wildlife watering from wetlands, fisheries and recreational ponds, recharge and evaporation 

ponds, or other combinations. 

The purpose of the discussion in this section is to provide a brief overview for the management 

of produced water via impoundments. Operators, landowners, or other entities interested in 

the use of impoundments to receive produced water should contact their appropriate state 

authority, including Departments of Environmental Quality, State Engineer’s Office, Oil and Gas 

Commission, and Fish and Wildlife, for additional information, pertinent statutes, or clarification 

of the information provided within. 

Section 4.5.1 Evaporation and Aeration 

Evaporation ponds are usually off-channel constructed impoundments designed to store water 

at the surface so that natural evaporative processes can move the water from the land surface 

into the atmosphere. As evaporation occurs, pure water is removed from the pond, resulting in 

an increase in the TDS for the remaining water. Over time, as more water is lost to the 

atmosphere, the water remaining in the pond may become concentrated brine. 

Applicability

Evaporation and aeration (enhanced evaporation) is applicable in arid regions where the 

average annual rainfall is relatively low and the average annual evaporation is relatively high. If 

the evaporation pond is constructed solely for evaporative loss (no infiltration), the ponds are 

generally designed to be broad shallow pools that maximize the surface area allowing for 

increased evaporation rates. Additional consideration is given to exposure; areas with high 

winds and few natural windbreaks could provide additional evaporative potential, which would 

include finding areas with low-level vegetation. 

In the Battle Creek Field of 

Montana a zero-discharge system 

of managing produced water has 

been developed by utilizing 

enhanced evaporation ponds 

through aeration coupled with 

recycling the produced water for 

oilfield uses (such as well 

completions and dust prevention). 

Constraints

Climate conditions may provide 

constraints that interfere with the 

effectiveness of evaporation. In 

colder regions evaporation might 

Enhanced Evaporation 

in the Battle Creek 

Field (Montana) 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

54

be effective for only short periods throughout the year, making it an ineffective year round 

water management practice. In wet regions there may be more water provided to the pond via 

rainfall than can be managed via evaporation. 

Water quality and geological 

setting also can impact the ability 

to use evaporation as a water 

management practice. Depending 

on the quality of the water and the 

soil at the bottom of the 

evaporation pond, the bottom and 

toe areas may need to be lined to 

prevent infiltration and migration 

of the water. Lining the 

evaporation pond may make this 

an uneconomical water 

management option; however, it 

has proven to be cost effective in 

the Bowdoin Field in Montana by 

master planning the phased 

construction of several lined ponds 

adjacent to each other to ensure capacity while not over-designing the water management 

system.

In geologic settings where a suitable material is available to prevent infiltration, the ponds may 

be placed on natural confining layers such as bentonite rich clay soils, or exposed shales that 

prevent the downward migration of the groundwater. 

Section 4.5.2 Wildlife and Stock Watering 

Wildlife watering ponds are typically small off-channel reservoirs that are used to help 

supplement wildlife or livestock water demands in semi-arid to arid regions. There are many 

types of watering facility designs available and choosing the correct one depends on proper 

evaluation of the situation to ensure landowner needs are satisfied. 

The Natural Resource Conservation Service (NRCS) provides nationwide standards and technical 

guidelines for wildlife watering facilities (NRCS, 1982) to help facilitate the decision process and 

assure proper recommendations are presented to landowners. State NRCS offices in some 

cases have customized these standards to meet the demands or requirements for their 

particular region. 

Applicability

Where water quality allows, wildlife watering ponds function to improve, or enhance watering 

places and systems for wildlife, to provide adequate drinking water during drought periods, to 

create or expand suitable habitat for wildlife, and, in some cases, to improve water quality. 

Wildlife watering ponds are commonly constructed in areas of the western United States to 

enhance habitat limited by water supplies. In some areas, watering ponds provide wintering 

areas for migrating waterfowl, neotropical birds, or other transient species. In severe drought 

Lined Evaporation Pit

in the Bowdoin Field 

(Montana)
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

55

conditions, watering ponds are used to provide water to mule deer, coyotes, bobcats, badgers, 

and other wildlife (U.S. Fish and Wildlife, 2002). 

 Watering ponds should be located in habitats that can provide food and shelter for as many 

wildlife species as possible and should include water level control devices or a means for escape 

to prevent drowning (ALL, 2003). Other important considerations include aesthetics, 

accessibility for periodic maintenance, and the control of noxious weeds. In some cases, 

natural watering areas can be 

improved to function in the same 

manner as constructed watering 

ponds. Natural watering areas 

are often found where run-off 

water accumulates in 

depressions. These areas can 

be improved by deepening the 

catchments, by trenching run-off 

waters to the basin, or 

developing the springs and 

seeps (ALL, 2003). 

In general, surface 

impoundments for wildlife should 

have gentle slopes to reduce 

erosion and suspended solids 

(Rumble, 1989). The surface 

area and depth of the pond would depend on the climate and the species expected to utilize it. 

Ponds expected to sustain waterfowl populations should have a surface area of 0.4 to 4.0 ha (1 

to 10 ac) (Proctor et. al., 1983) and at least 25% of the pond should have a depth of 3 meters 

(10 ft) (Rumble, 1989). Watering ponds of this size and depth could also be used to sustain 

populations of shore and upland birds and fish. Ponds with a surface area less than 0.4 ha (1 

ac) would likely not be able to support fish populations without management (Marriage and 

Davison, 1971). 

A successful wildlife watering pond known as Custer Lake is located in the Oregon Basin of 

Wyoming. Approximately 30,000 barrels of water per day are discharged to what would 

normally be a seasonal playa lake. Wildlife such as waterfowl and big game flourish in the area 

as a result. 

Constraints

As with many beneficial uses, the quality of the produced water can prove to disallow the use of 

this water management practice. Typically water with TDS above 10,000 ppm is not of 

sufficient quality for wildlife consumption. Water quantity can also be a concern if this water 

management practice is employed, and it is likely that additional water management practices 

such as enhanced recovery would need to be used in conjuncture with this practice to manage 

all of the water produced. 

Custer Lake is a 

successful wildlife 

watering hole in the 

Oregon Basin 

(Wyoming)
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

56

Section 4.6 Managed Irrigation and Land Application 

This management option involves either the discharge of raw produced water directly to the 

land surface, or pre-treating 

the water with amendments 

just prior to applying the water 

to the land surface by way of 

irrigation methods. The 

common methods of irrigation 

include center-pivots, siderolls, and fixed or mobile 

water-guns.

Applicability

The direct discharge of water 

to the land surface can be a 

viable practice for operators, 

depending upon site-specific 

conditions. Under this 

management strategy, water 

can be discharged to fields and 

pastures in order to support plant growth, and disposed of through evaporation, transpiration 

by way of plant tissue, and infiltration into the soil. However, factors such as the quality of 

produced water, existing land uses, landowner’s future plans for use, soil type, vegetative 

cover, and other factors all affect the land’s ability to accept surface discharge produced water. 

Although it should be assumed that this management option could lead to runoff that reaches 

surface water, depending upon local conditions, many control or mitigation practices exist to 

minimize this effect.

Constraints

As mentioned before, the quality of the produced water can prove to disallow the use of this 

water management practice. Typically water with high salinity and/or high SAR values can 

damage plant life and make soil unusable in the future. In this instance, water quality can be 

improved by adding amendments either to the soil or to the water prior to application of the 

water to the soil. The required amendments would be site specific depending on the soil, 

water, and plant that the water would be irrigated with. 

Water quantity can also be a concern if this water management practice is employed, and it is 

likely that additional water management practices such as enhanced recovery would need to be 

used in conjuncture with this practice to manage all of the water produced. 

Surface Irrigation in 

the Hamilton Dome 

(Wyoming)
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

57

Section 4.7 Industrial Uses 

There are various beneficial industrial uses that may be applicable for produced water 

management depending on site-specific conditions and economics. Some examples discussed 

here include the use of the water in oil and gas operations (i.e. truck wash station, well 

completions, fracturing), use of the produced water for the cooling needs of a power plant, and 

dust suppression (i.e. at coal mines or on unpaved county roads). The applicability and 

constraints of these industrial uses are discussed here, along with examples of where these 

practices have already been employed. 

Section 4.7.1 Oil and Gas Operations 

Water is used for various things in the 

day-to-day operations of the oil and 

gas industry. Some uses such as 

truck washing, well completions, and 

fracture water may not require the 

water to be of high quality. Therefore 

produced water generated from oil 

and gas development can be used for 

these activities with little to no regard 

for the quality of the water. By 

utilizing produced water in this 

fashion, operators not only lower the 

cost to dispose of the produced water, 

but eliminate the cost to acquire the 

water necessary for operations. 

Applicability

The use of produced water in oil and gas operations is applicable in several regions under 

various scenarios. One example in the PRB of Wyoming is a water truck load-out facility that 

utilizes produced water to supply oil and gas activity with the water necessary for operations, 

thus taking some pressure off the local water supply to meet this demand. 

In the Barnett Shale play in Texas as much as 2 million of gallons of make-up water is required 

for a fracture job. This water is subsequently produced back to the surface in the early stages 

of development. To reduce the cost of fracturing wells, efforts are being made to reclaim and 

recycle this water as it is produced by utilizing it to fracture the next well. 

Another example previously discussed is in the Battle Creek Field of Montana. A zero-discharge 

system has been developed to manage produced water through enhanced evaporation ponds 

coupled with recycling the produced water for operational uses (such as well completions and 

dust prevention). The central evaporation ponds are used as a water supply source. Water 

trucks haul water from these ponds to the site where water is required. 

Constraints

The main constraint to using produced water for oil and gas operations is the fact that the 

volume of water used may be nominal when compared to the total volume of water produced, 

Construction of a Water 

Truck Loadout Facility 

(Wyoming)
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

58

and therefore it may be uneconomical to put practices in place solely to recycle the produced 

water for operational uses. This can be overcome by applying a portfolio of water management 

practices, such as in the Battle Creek Field example, where the water is readily available when 

needed for operations, but operations is not the sole source of managing the water. 

Section 4.7.2 Power Plant Cooling Water 

Electric generating power plants can have a considerable need for water for cooling. Nationally, 

water availability has been a limiting factor in the development of new power plants. With the 

current and projected over-abundance of produced water from development when combined 

with existing and potential future power plants in the United States, consideration of using 

produced water for cooling at power plants is reasonable. 

Applicability

In general, power plants have the capacity to individually generate between 80 and 2,110 

Megawatts (MW). As an integral part of the power generating process, these power facilities 

must employ water, air, mist, or a combination of these for cooling. Produced water could be 

used for cooling at power plants in several states, thus avoiding the need for costly air cooling, 

potentially reducing overall power generation costs. Further, the presence of a water surplus 

could be used to attract power generating facilities for exporting power. 

Water usage volumes can vary widely among power plants, with ranges from approximately 

20,000 bpd to more than 400,000 bpd (Schultz, 2005). As an example, Basin Electric operates 

a large power facility near Wheatland, Wyoming. Designed as a water-cooled facility, this plant 

has a capacity of 1,650 MW and requires approximately 400,000 bpd of water for cooling. 

Currently, its water comes from the Grey Rocks Reservoir on the North Platte watershed. This 

reservoir does not have an adequate supply of water to support its cool water fishery. Further, 

the entire watershed lacks sufficient water to support irrigation and to fulfill commitments to the 

Platte River Compact (Lawson, 2005). 

Constraints

Several technical constraints may exist for supplying produced water to power plants. These 

include water quality, water quantity, consistency of water quality and quantity, water 

treatment issues, distance from the producing area to the usage area, water transportation 

issues, and the length of time the water would be available. 

Plants are generally designed to accommodate cooling water of a relatively high and consistent 

quality. These issues are of particular concern with respect to produced water since 

considerable variations exist in both produced water quality and consistency of quality and 

volume across the nation. These issues would need to be considered and addressed when 

further pursuing the use of produced water for cooling at power plants. 

The issue of a single operator being able to commit to long-term supply needs of a power plant 

has been challenging (Cline, 2005). Furthermore, the costs of this water management strategy 

would include significant up-front capital costs and long-term operational costs for the water 

transportation pipelines. Therefore, to economically meet the short- and long-term water supply 

needs of a power plant, it is likely that a consortium of operators would need to cooperate for 

this management practice to be feasible. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

59

There has been some small-scale usage of produced water for cooling by power plants. This 

usage has been short-lived and minor from the standpoint of the power plants (Stafford, 2005). 

In all of the historical cases where produced water has been used, the usage point was very 

close to the production area, thus minimizing transportation costs (ALL, 2006). Unfortunately, 

due to rapid water production declines, the cases evaluated were unable to meet plant quantity 

requirements for an extended time, thus forcing the plant to seek cooling water from alternative 

sources. 

Water rights issues may provide additional constraints through public perception and outcry in 

the event that produced water is transported long distances over state and basin boundaries. 

Inter-basin transfer of water can involve complex water ownership issues that could delay or 

restrict the implementation of oil and gas projects. 

Section 4.7.3 Geothermal Power Generation 

Produced water that is at/above a temperature of approximately 215°F can be utilized for the 

economic generation of electric power (Blackwell, 2004). The electric power generated can 1) 

be used by the operator to supply the operational needs of the development, 2) be sold either 

to local end-users or to the local utility company. The amount of potential electric power 

generated is determined by the volume of water produced each day and the temperature of the 

water as it reaches the surface. 

The geothermal generation 

process does not interfere with 

the other management options 

discussed elsewhere in this 

chapter. For example, after 

running through the generator, 

the water may be put to 

further beneficial use if the 

water is of high quality, the 

water may subsequently be reinjected into the subsurface 

into a disposal zone, or into the 

original subsurface reservoir to 

maintain reservoir pressure and 

enhance oil production. 

Applicability

Given the right conditions, electrical power can be generated as part of an oil or natural gas 

development. Efficient and cost effective power generation requires high volumes of water 

production and high water temperatures. Current state-of-the-art technology generators 

require at least 15,000 barrels of water per day with a minimum temperature of 215°F 

(Blackwell, 2004). This volume of water is frequently exceeded by medium and large oil and 

gas fields in the United States where 100 producing wells may average 200 to 500 barrels of 

water per day each. Further, water of the required temperature can be found in many deep 

fields in the United States as shown in Figures 4.4 and 4.5. Figure 4.4 is a map of the United 

States showing estimated temperatures at a depth of approximately 9,800 feet (3 km), and 

Figure 4.5 depicts estimated temperatures at a depth of approximately 16,400 feet (5 km). 

750 kW Power Plant powered 

with 215° F fluid (Nevada) 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

60

Figure 4.4 Temperature (o

F) at 3 km (~9,800 ft) for the Continental United States 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

61

Figure 4.5 Temperature (o

F) at 5 km (~16,400 ft) for the Continental United States 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

62

Figure 4.4 shows promising areas in East Texas and some spots in the Rocky Mountains at a 

depth of 9,800 feet (3 km). At deeper depths, a large percentage of the area shown in Figure 

4.5 is underlain by strata in excess of 212°F at a depth of 16,400 feet (5 km), the approximate 

point of economic geothermal power generation. 

Several manufacturers can supply generators on an on-the-shelf basis. The 750 kW Nevada 

facility shown in this section can be assembled in a short time and moved to another location if 

production characteristics change. A facility like this may be located on the grounds of a water 

plant at a large producing field between separators and the water injection plant (Thomsen, 

2006). The generator shown requires a flow of 500 gpm (approximately 17,000 bpd) of water 

at 215°F to generate 750 kW. The power for this specific facility is sold to Sierra Pacific Power 

under a long term agreement. 

Constraints

The biggest constraint on the development of geothermal power generation at traditional oil 

and gas sites is the temperature of the produced water as it reaches the surface. Given that 

the minimum temperature for efficient and economic power generation is 215°F, and that the 

geothermal gradient throughout the petroleum basins of the United States ranges between 1.0 

and 1.2°F/100 feet, then the requisite temperature would be available at depths between 

12,100 feet (70°F surface temperature and 1.2°F/100 feet) and 16,500 feet (50°F surface 

temperature and 1.0°F/100 feet) below the surface. These depths are attainable in many 

states, however, oil and gas wells are more commonly produced from depths shallower with 

associated waters less than the required 215°F. Temperature constraints may change in the 

future as the technology of geothermal power generation continues to advance. 

Another serious constraint on the feasibility of generating efficient and economic power is the 

tendency of strata to lose porosity and permeability with increasing depth. When depth and 

pressures increase, both matrix porosity and fractures tend to close. Unless extraordinary 

forces keep pathways open, either by the action of local tectonic stresses or abnormally high 

fluid pressures, reservoir rocks at great depths will have limited ability to deliver the necessary 

volume of water to the power plant. Downhole permeability can be accurately measured by 

examining reservoir performance from oil, gas, and water production records. An operator with 

an interest in utilizing geothermal generators may be able to use historical production data to 

assess the feasibility. 

The presence of secondary or tertiary recovery facilities will not constrain the operator’s ability 

to install geothermal generation. The space requirements are small and water production is in 

no way hampered (Thomsen, 2006). Scaling can develop within the generator from some 

produced water chemistries; which will be similar to the scaling experienced by the operator in 

existing water handling facilities. Scaling can be controlled by existing chemical treatments. 

Section 4.7.4 Dust Suppression 

Fugitive dust impacts to local or regional air quality are important issues (ALL, 2006). Some 

industrial sites, such as coal mines, constantly need to control fugitive dust. Some areas are 

facing dust levels that may require curtailment of mining and other industrial activity. Truck 

traffic in coal mine operations can be heavy, depending on the number of active pits, and they 

can travel as much as 15 miles on gravel roads for each pit (mine) (Hutchinson, 2005). As this 

is done, loaded trains leave for power plants while empty trains arrive at loading docks. All of 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

63

this activity goes on continually year-round and almost all of this activity generates copious 

amounts of fugitive dust. The demand for water for dust suppression at mines is site-specific 

and dependant on the season; therefore, it can range anywhere from 2,400 bpd to 100,000 bpd 

(Murphree, 2005 and Hutchinson, 2005). Depending on the availability and cost of the water 

used to control the dust, produced water from oil and gas operations could be a viable option to 

supply this water. Produced water also can be used for washing trucks and other large 

equipment. 

Applicability

Coal mines require more water for dust control during the dry periods of the summer and fall. 

During other times, water can be stored on-site in pits and settling ponds. A typical large coal 

mine can have storage approaching 5.0 million bbls (Murphree, 2005). Helping area coal mines 

control dust by supplementing their water sources for dust control can benefit the mining 

sector, help all industrial interests in the basin, and improve air quality issues. In addition, 

reducing dust with supplemental produced water can give operators a low-cost, year-round 

option for managing the water. 

Several operators supply water to numerous coal mines, especially in Wyoming and Montana. 

The Spring Creek mine near Decker, Montana, receives between 200 and 800 gpm from the CX 

Ranch CBNG field in the area (Williams, 2005) and several mines near Gillette have previously 

received small amounts of water from adjacent CBNG fields (Stearns, 2005). 

Constraints

Technical constraints of this option involve water quality requirements that may limit usage. 

However, there are differing impressions of the quality limits for dust control water applied to 

roads. Some operators are concerned about the buildup of salt at the side of coal mine roads 

and have a self-imposed limit of 10 SAR (Murphree, 2005) while other companies have a 

corporate policy about using high quality water for dust control and emphasize the use of poor 

quality water (Stearns, 2005). Some operators add Magnesium Chloride (MgCl) to dust control 

water and, thus, are unconcerned about water quality for dust control (Hutchinson, 2005). 

The proximity of oil and gas operations to an industrial area where dust suppression is required 

is also a potential constraint from an economic standpoint. The cost to haul the water to the 

industrial site may preclude this as a viable option, and the capital cost required to construct a 

water pipeline would make it difficult for any operator to justify. As mentioned before, this 

option may become more viable if multiple operators collaborate in establishing the 

infrastructure necessary to transport the water from the wellhead to the site where it can be 

used for dust suppression. 

Section 4.7.5 Concentrated Animal Feeding Operations (CAFO) 

Livestock watering is one of the most common and proven beneficial uses of produced water. 

Most range and pasture used for livestock watering would require relatively minute quantities 

compared to the amounts of water produced; therefore, to support a concentrated animal 

feeding operation (CAFO) where large numbers of animals are confined and fed would manage 

a larger volume of produced water. The water needs of a CAFO could include animal 

consumption, irrigation of forage crops, and waste management. Current feedlot operators will 

already have sources of water; therefore, water would have to be provided at a very low cost 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

64

for this to be economically feasible for them. Costs associated with the beneficial use of 

produced water for feedlots mainly would include transporting the water to the feedlot facility. 

Applicability

Finishing cattle consume from 8 to 20 gallons of water per day, depending on the time of year 

and outdoor temperature (Guyer, 1977). For a larger feedlot handling 5,000 head, this would 

require a maximum volume of about 100,000 gallons, or 2,380 bpd of drinking water. The 

average size feedlot in the Great Plains is about 500 head (Davies and Widawsky, 1995); 

therefore, water use for livestock drinking would be about 240 bpd for an average size feedlot. 

Water requirements for waste management would increase this amount slightly. If produced 

water were to also supply irrigation for hay and grain adjacent to the feedlot, much more water 

would be required. 

Table 4.1 shows the acceptable quality of water for livestock. Water with a TDS below 10,000 

mg/L (EC <16 mmhos/cm) is generally considered acceptable. 

Table 4.1 Water Quality Guide for Livestock Use 

TDS (mg/L)* Livestock Watering Comments

Less than 1,000 

(EC < 1.5 mmhos/cm) Excellent for all classes of livestock. 

1,000 to 2,999 

(EC = 1.5-5 

mmhos/cm) 

Very satisfactory for all classes of livestock. May cause 

temporary and mild diarrhea in livestock not accustomed to 

them. 

3,000 to 4,999 

(EC = 5-8 mmhos/cm) 

Satisfactory for livestock, but may cause temporary diarrhea 

or be refused at first by animals not accustomed to them. 

5,000 to 6,999 

(EC = 8-11 

mmhos/cm) 

Can be used with reasonable safety for dairy and beef cattle, 

sheep, swine, and horses. Avoid use for pregnant or 

lactating animals. 

7,000 to 10,000 

(EC = 11-16 

mmhos/cm) 

Considerable risk in using for pregnant or lactating cows, 

horses or sheep, or for the young of these species. In 

general, use should be avoided although older ruminants, 

horses, poultry, and swine may subsist on them under 

certain conditions. 

Over 10.000 

(EC > 16 mmhos/cm) 

This water is considered unsatisfactory for all classes of 

livestock. 

(Source: NAS, 1974) 

Note: Electrical conductivity (EC) expressed in micromhos per centimeter at 25°C can be substituted for total 

dissolved solids without introducing a great error in interpretation.

Constraints

The quality of the produced water most likely would present the biggest constraint for use of 

this water management practice. As stated above, water with a TDS of 10,000 is considered 

unsatisfactory for animal consumption. Furthermore, transporting the water from the producing 

areas to the CAFO would be another difficult aspect of this water management practice. Either 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

65

trucking the water or building pipelines would be the most feasible solutions, but cost may be 

prohibitive, depending on the distances. 

The issue of a single operator being able to commit to long-term supply needs of feedlot could 

be challenging. Therefore, to meet short- and long-term water supply demands, it is likely that 

a consortium of operators would need to cooperate to make this a viable produced water 

management option. 

Section 4.8 Water Treatment Technologies 

Various water treatment technologies are available to the oil and gas industry. The options can 

differ in their inherent facility requirements, capital costs, operating expense, and waste 

streams; all three factors can be important to the oil and gas operator. Some technologies may 

have large space requirements that may not be possible in some oil and gas installations. Some 

technologies may be commercially available as small, skid-mounted units that easily can be 

relocated as production conditions change. Equipment costs are obviously important in some 

installations where a large amount of dedicated equipment must be purchased just for 

managing produced water. Higher power costs and chemical expenses could be unsupportable 

early in the life of an oil and gas development. Treatment wastes derived from produced water 

might no longer be classified as oil and gas wastes and might be more difficult and more 

expensive to manage. This section discusses various produced water technologies along with 

examples of how they are being implemented in the field. 

Section 4.8.1 Packed Bed Adsorption 

ET Ventures, L.L.C., South Carolina, field tested its new ET #1 produced water treatment 

system at Rocky Mountain Oilfield Testing Center (RMOTC) in July 1996 to determine its 

effectiveness in adsorbing hydrocarbons from produced water (Doyle, et al., 1997). Water 

produced from the Tensleep formation was atmospherically cooled (to 90°F) and flowed 

through a three-stage packed bed adsorption treatment system. Higher temperature affects 

the removal efficiency of the adsorbent. The first two stages contained ET #1, a sodium 

bentonite modified organoclay adsorbent. The final stage contained granular activated carbon 

(GAC). The picture below shows a mobile treatment trailer used for the operation. The system 

was operated at 10 gpm flow rate and maximum 10 psi pressure drop. 

A mobile packed bed 

adsorption system for the 

treatment of produced water 

(Wyoming)
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

66

The samples of inlet feed, effluent from ET #1 columns, and effluent from the GAC column 

were analyzed by a standard EPA (EPA 1664-A) analytical testing method. Table 4.2 shows the 

results obtained for one of the trials during the treatment. ET #1 treatment was sufficient to 

remove Total Petroleum Hydrocarbons (TPH) below detectable limits. Oil and grease values 

were below detectable levels after ET #1 adsorption treatment. Benzene, toluene, 

ethylbenzene, and xylene (BTEX) were removed to below detectable levels after GAC adsorption 

treatment. 

Table 4.2 Results from ET Venture’s mobile produced water treatment system 

Contents 

Before

Treatment

(ppm)

After Treatment 

(ppm)

TPH 148 1.1 

Oil and Grease 151 1.2 

Benzene 3.14 <0.5 

Toluene 4.97 <0.5 

Ethylbenzene 4.95 <0.5 

Xylene 29.7 <1 

 

Section 4.8.2 Decomposition in Constructed Wetland 

The DOE’s Naval Petroleum Reserve No. 3 (NPR-3) bio-treatment facility with average 

throughput of 35,000 bpd of water is located in Natrona County in east-central Wyoming 

(Myers, et al., 2001). The wetlands treatment facility started in January 1996 to provide a 

cheaper alternative to reinjection and to benefit local wildlife by way of water discharge. 

Wetlands are thin film bioreactors that utilize various species of plants and microbes along with 

sands that oxidize contaminants present in the water. A schematic of treatment process is 

shown in Figure 4.6. 

Figure 4.6 DOE Naval Petroleum Reserve’s bio-treatment process 

The process undergoes the following steps: 

1. Cooling tower followed by a shallow cooling trench to reduce the temperature of 

produced water from 180 – 200°F to below 100°F. Higher temperatures reduce the 

performance of plants in the subsequent wetlands pond. 

Cooling Tower Cooling 

Trench 

Netted Pond 

Wetland 

Cooling 

Trench 

Creek Oxidation 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

67

2. Netted pond or skimming pond further cools the water and also removes suspended 

solid and oil under gravity effects. Dispersed oil on the top surface is skimmed off. 

3. Specially developed flora and fauna, including hydrocarbon decomposing bacteria, 

sulfate reducing bacteria, nitrifying and denitrifying bacteria, iron related bacteria, algae, 

etc. biodegrade various contaminants present in produced water. 

4. Microorganisms in wetlands degrade most of the hydrocarbons and the remaining traces 

of hydrocarbons are removed in an oxidation process. 

The produced water from the Tensleep formation was blended with the produced water from 

other formations before the treatment. The blending process reduced the level of some of the 

contaminants and also lowered the temperature. While TDS was not affected, certain 

persistent contaminants such as organics, alkalinity, and ammonia were greatly attenuated. 

Table 4.3 shows the result obtained using the bio-treatment facility. 

Table 4.3 Summary of the performance of NPR-3 Bio-treatment facility which included 

wetland treatment 

Constituents Before treatment 

(ppm)

After treatment 

(ppm)

Overall removal 

(%)

NH3 2.03 0.54 73 

NO3 <0.1 <0.1 - 

Phosphorus 1.83 0.46 75 

BOD 28 2.3 92 

COD 48 29 40 

TOC 32.7 3.6 90 

TPH 112 5.8 95 

Oil & Grease 71.9 4.2 94 

Benzene 0.143 <0.001 100 

Toluene 0.135 <0.001 100 

Ethlybenzene 0.035 <0.001 100 

Xylene 0.162 <0.001 100 

Turbidity 45.4 4.76 90 

TDS 4380 4010 9 

Alkalinity 713 190 73 

Section 4.8.3 Ion Exchange 

The ion exchange process effectively removes arsenic, heavy metals, nitrates, radium, salts, 

uranium, and other elements from the produced water. Ion exchange is a reversible chemical 

reaction wherein positively or negatively charged ions present in the water are replaced by 

similarly charged ions present within the resin. The resins immersed in the water are either 

naturally occurring inorganic zeolites or synthetically produced organic resins. When the 

replacement ions on the resin are exhausted, the resin is recharged with more replacement 

ions.
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

68

Ion Exchange Resins 

Ion exchange resins are classified as cation exchangers, which exchange positively charged 

ions, and anion exchangers, which exchange negatively charged ions. The resins are further 

classified as: 

Strong Acid Cation (SAC) Resins: 

The hydrogen or sodium forms of the cation resins are highly dissociated and H+ or Na+ ions 

are readily exchangeable over the entire pH range. Equation 1 shows an example of salt 

removal with SAC. 

2(R SO H) NiCl (R SO )Ni 2HCl  3  2   4  ..(1) 

Equation 2 shows an example of Ca+ softening with SAC. 

  2(R  SO H)  Ca  (R  SO ) Ca  2H 2

3 3 ..(2) 

These resins would be used in the hydrogen form for complete deionization (Na, Ca, Mg, Ba, 

etc. removal); they are used in the sodium form for water softening (Ca and Mg removal). After 

exhaustion, the resin is regenerated to the hydrogen form by contact with a strong acid 

solution, or to the sodium form with a sodium chloride solution. 

Weak Acid Cation (WAC) Resins: 

Weak acid resin has carboxylic acid (COOH) group as opposed to the sulfonic acid group (SO3H)

used in strong acid resins. These resins behave similarly to organic acids that are weakly 

dissociated. WAC has high affinity for divalent salts. Equation 3 shows an example of Ca+

softening with WAC. Alkalinity present in bicarbonate form also can be removed by WAC. 

  2(R  COOH)  Ca  (R  COO) 2Ca  2H ..(3) 

Free H+ ions can react with bicarbonate (present as hardness, Ca(HCO3)2) to form carbonic 

acid. The carbonic acid decomposes in carbon dioxide as shown in equation 4. Removal of 

carbon dioxide or decarbonation (Moftak, 2002) is necessary during the water treatment 

process.

HCO3  H  H2CO3  CO2  H2O  

 ..(4) 

Weak acid resins exhibit a much higher affinity for hydrogen ions compared to strong acid 

resins. This characteristic allows regeneration to the hydrogen form with significantly less acid 

than is required for strong acid resins. Almost complete regeneration can be accomplished with 

stoichiometric amounts of acid. The degree of dissociation of a WAC is strongly influenced by 

the solution pH. Consequently, resin capacity depends in part on solution pH. 

Strong Base Anion Resins: 

Strong base resins are highly ionized and can be used over the entire pH range. These resins 

are used in the hydroxide (OH-

) form for water deionization. They will react with anions in 

solution and can convert an acid solution to nearly pure water. Equation 5 shows the reaction 

involved in an anion exchange step. 

(R  NH3OH)  HCl  (R  NH3Cl)  HOH ..(5) 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

69

Regeneration with concentrated sodium hydroxide (NaOH) converts the exhausted resin to the 

hydroxide form. 

Weak Base Anion Resins: 

Weak base resins exhibit minimum exchange capacity above a pH of 7. The weak base anion 

resins sorbs anions associated with weak acid. 

Applications

Ion exchange has several applications in water treatment processes such as hardness removal, 

desalination, alkalinity removal, radioactive waste removal, ammonia removal, and heavy metal 

removal. Since divalent ions (Ca, Mg, etc.) are favored over monovalent (Na, etc.) ions by the 

resin for replacement, secondary treatment for SAR (sodicity) is required. 

Powder River Gas, LLC 

In 2002 Powder River Gas, LLC proposed a Project Plan of Development (POD) (Bopst and Reid, 

2002) to drill and test for CBNG in eight federal and eight fee wells at eight locations (two wells 

per location) in an area northeast of the Tongue River Reservoir, Big Horn County of 

southeastern Montana. 

Part of their NO FEDERAL ACTION

alternative is to treat water produced 

from the wells using a Higgins Loop 

(continuous counter-current ion 

exchange) treatment facility prior to 

discharging to the Tongue River. The 

stationary Higgins Loop facility was 

constructed along with a series of 

impoundments and chemical storage 

tanks. All chemical storage tanks are 

surrounded by a shallow spill 

containment berm to prevent any 

Higgins Loop in operation accidental chemical spills. 

(Montana)
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

70

Figure 4.7 Higgins Loop schematic (Source: Seven Trent Services) 

Produced water from CBNG wells is to be treated stepwise within the treatment facility. Settling 

of suspended sediments and releasing of residual gas will be within the impoundment. Na+,

barium and other heavy metals from produced water will be removed using SAC resins in the 

Higgins Loop. Removal of CO2 produced during the ion exchange process and adjustment of 

pH will be achieved by adding calcium hydroxide. CO2 can be removed by air-stripping or 

membrane degasification. The physical law governing this process is the equilibrium between 

the gas phase and the concentration of the solute gas in the liquid phase. 

The schematic is shown in Figure 4.7. The Higgins Loop is a vertical cylindrical loop containing a 

packed bed of strong acid ion exchange resin that is separated into four operating zones by 

butterfly (loop) valves. These operating zones (Adsorption, Regeneration, Backwashing and 

Pulsing) function like four separate vessels. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

71

The Higgins Loop treats liquids in the adsorption zone with resin while the ions are being 

removed from loaded resin in the regeneration zone simultaneously. Intermittently, a small 

portion of resin is removed from the respective zone and replaced with regenerated or loaded 

resin at the opposite end of that zone. This is accomplished hydraulically by pulsing of the resin 

through the loop. The result is continuous and countercurrent contacting of liquid and resin. 

The cations (Ca+, Na+ etc.) are replaced by hydronium (H+) ions from resin beads. The 

hydronium ions are released in the treated water, which lowers the pH of the water. Cations 

are stripped from the resin in the regeneration zone concurrent with ion exchange in the 

adsorption zone. Dilute hydrochloric acid is injected into the loop and moves counter-current to 

the resin and the spent brine discharge, leaving the resin restored to the hydronium form. 

Concentrated brine volumes average 

approximately 1.0% of the total loop feed 

volume, depending on the cation loading that is 

removed from the treated water. Excess brine 

that is not recycled to other beneficial uses is 

proposed to be transported offsite by truck for 

disposal by injection into a permitted Class I, 

deep disposal well located in Wyoming. The 

waste stream from the treatment process, at 

maximum flow, will generate approximately 60 

barrels of brine or reject water per day. The 

treatment unit would discharge a total of 250 

gpm of treated water. 

EMIT Water Discharge Technology, LLC 

EMIT Water Discharge Technology, LLC (Dow, 

2003) developed a new treatment process that 

uses DOWEX G-26 (strong acid cation exchange resin manufactured by DOW Chemical 

Company). G-26 resin has a sulfonic acid (SO3H+) group that exchanges Na+, Ba+, Ca2+, and 

Mg2+ ions with H+ ion. The ion exchange process is accomplished in a Higgins Loop. The 

Higgins Loop operation is followed by calcium addition to adjust pH, balance SAR, and increase 

calcium concentration. Table 4.4 shows the results of a field trial for the treatment of produced 

water from Powder River Basin, Wyoming. The process focused on the removal of sodium ions 

and reduction of SAR using a combination of Higgins loop and calcium addition. 

The increment in calcium, chloride and sulfate levels were due to chemical addition during SAR 

adjustment. The field trial was conducted with throughput of 200 gpm. The treatment cost 

ranges from $0.05 to $0.20 per barrel of treated water depending on the influent composition, 

SAR, and availability of resources. The ion exchange treated water may then be discharged to 

the environment and the residue disposed of (ALL, 2003). 

Discharge to the Tongue 

River after Ion 

Exchange Treatment 

(Montana)
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

72

Table 4.4 Performance of Higgins Loop treatment for a field trial at Powder River Basin site 

Constituents Influent Produced 

Water Treated Water Removal%

Na, ppm 486 12 97.53 

Ca, ppm 22.2 113 -409 

Mg, ppm 13.2 <1 >93 

K, ppm 13.5 <1 >93 

Ba, ppm 0.72 ND 100 

Carbonate, ppm <1 <1 - 

Bicarbonate, ppm 1430 311 78.52 

Chloride, ppm 18 42 -133.33 

Sulfate, ppm 1 1.1 -10 

SAR 20.2 0.3 98.51 

pH 8.1 6.5 19.75 

Sandia Ion Exchange/Sorption Process 

Sandia National Laboratory (SNL) reported use of Hydrotalcite (HTC) as anion exchanger and 

Permutite as cation exchanger (Sattler, et al., 2004). These ion exchangers are comprised of 

durable inorganic oxides that provide stability over a large range of pH. Based on the results of 

various experiments, SNL reported average ion exchange capacity of HTC and Permutite as 2.5 

mEq/gram (measured with Na2So4), and 1.7-2.7 mEq/gram (measured with NaOH), 

respectively.

Anions in the inlet water are replaced by hydroxide ions (HTC anion exchange) and cations are 

replaced by hydrogen ions (Permutite cation exchange). Lime softening pretreatment is an 

optional stage. 

Ion exchangers are regenerated after they are exhausted. In the regeneration process ion 

exchangers regain their ion exchange capacity. It might not be possible to regain 100% ion 

exchange capacity during the regeneration process. SNL attempted to determine effects of 

regeneration on the ion exchange capacity of above mentioned ion exchangers and concluded 

that Permutite can regain ion exchange capacity without significant loss. Regeneration of HTC 

at low temperatures was not promising, and at high temperatures regeneration became costly. 

Section 4.8.4 Electrodialysis (ED) and Electrodialysis Reversal (EDR) 

Electrodialysis (ED) 

Most salts dissolved in water are ionic, being positively (cationic) or negatively (anionic) 

charged. These ions are attracted to electrodes with an opposite electric charge. 

In ED, membranes that allow either cations or anions (but not both) to pass are placed 

between a pair of electrodes. These membranes are arranged alternately. A spacer sheet that 

permits feed water to flow along the face of the membrane is placed between each pair of 

membranes. Figure 4.8 shows an ED assembly with feed spacer and ion exchange membrane 

placed between oppositely charged electrodes. Positively charged ions (Na+ etc) migrate to 

cathode and negatively charged ions (Cl-

 etc) migrate to anode. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

73

During migration the charged ions are rejected by similarly charged ion exchange membranes. 

As a result, water within the alternate compartment is concentrated leaving desalted water 

within the next compartment of the ED unit. The concentrate and desalted water are 

continuously removed from the unit. The basic electrodialysis unit consists of several hundred 

cell pairs bound together with electrodes on the outside and is referred to as a membrane 

stack.

Feed water passes simultaneously in parallel paths through all of the cells to provide a 

continuous flow of desalted water and brine to emerge from the stack. The feed water is 

circulated through the stack with a low-pressure pump with enough power to overcome the 

resistance of the water as it passes through the narrow passages. The raw feed water must be 

pretreated to remove materials that could harm the membranes or clog the narrow channels in 

the cells from entering the membrane stack. A rectifier is generally used to transform 

alternating current (AC) to the direct current (DC) supplied to the electrodes on the outside of 

the membrane stacks. 

Post-treatment consists of stabilizing the water and preparing it for distribution. This posttreatment might consist of removing gases such as hydrogen sulfide and adjusting the pH. 

Figure 4.8 An ED unit in operation (Source: Electrosynthesis Company, Inc) 

Cathode

( - ) 

Anode

( + ) 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

74

Electrodialysis Reversal Process (EDR) 

An EDR unit operates on the same general principle as a standard electrodialysis plant except 

that both the product and the brine channels are identical. At intervals of several times an 

hour, the polarity of the electrodes is reversed and the flows are simultaneously switched so 

that the brine channel becomes the product water channel and the product water channel 

becomes the brine channel. 

The result is that the ions are attracted in the opposite direction across the membrane stack. 

Immediately following the reversal of polarity and flow, enough of the product water is dumped 

until the stack and lines are flushed out and the desired water quality is restored. This flush 

takes about 1 or 2 minutes, and then the unit can resume producing water. The reversal 

process is useful in breaking up and flushing scales, slimes, and other deposits in the cells 

before they can build up and create a problem. Flushing allows the unit to operate with fewer 

pretreatment chemicals minimizing membrane fouling. The charges of the electrodes are 

reversed by a motorized valve. 

Applications

Electrodialysis is conducted at low pressure drops across the process (usually less than 25 psi). 

The pressure drop across the typical Reverse Osmosis (RO) membrane ranges from 400 – 1400 

psi, which indicates higher energy consumption. 

Wind River Basin, Lysite, Wyoming 

The produced water from a conventional well in Wind River Basin of Wyoming (Hayes, 2004) 

contains H2S, oil, acid, BTEX, dissolved solids, etc. About 93% of total TDS (8,300 to 10,000 

ppm) is accounted for as sodium, chloride, calcium, and bicarbonates. Oil and grease content 

was about 65 ppm and BOD value was more than 330 ppm (contributed by acetates and 

volatile acids). The treatment trailer consists of the following units: 

1. De-oiling via induced gas floatation unit. 

2. Dissolved organics removal via two fluidized bed reactors. First was the anaerobic 

and nitrate consuming reactor for reducing large amounts of organics. The second 

was the aerobic reactor ensuring oxidation of dissolved organics. 

3. Desalting/Demineralization using an ED unit. 

ED provided economical demineralization in this case. The feed water had approximately 9,000 

ppm TDS. As usual, the cost of the ED unit operation increases as the required TDS removal 

increases. Table 4.5 shows the overall removal of contaminants using different treatment 

technologies. The ED removed approximately 89% of TDS from the produced water. 

Table 4.5 Produced water treatment performance at Wind River Basin, Wyoming 

Parameter Influent

(ppm)

Effluent

(ppm)

Overall Removal 

(%)

Oil and Grease 90 4 95.5 

BOD 330 51 84.5 

BTEX 11 0.1 99.1 

TDS (using ED) 9,100 1,000 88.9 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

75

High Efficiency Electrodialysis (HEEDTM), Frac Water, Inc. 

Frac Water, Inc. developed mobile ED treatment units for treating CBNG produced water and 

reusing it in fracturing treatment. Several case studies suggest that the mobile treatment units 

treat the produced water with TDS ranges from 11,400 to 27,000 ppm and sulphates from 

4,000 to 14,000 ppm (Spitz, 2003). ED provides the following benefits over RO: 

1. ED can sustain high temperature; in fact higher temperature of produced water from 

the wellhead (140°F) improved the conductivity and reduced resistance during the 

ED process, which leads to lesser voltage usage. Also, higher temperature reduces 

viscosity. 

2. ED accepts feed water with Silt Density Index (SDI) value of 12 compare to SDI 

value of 3 for RO. Less SDI value indicates the necessity of pretreatment steps. 

The membranes are susceptible to fouling if feed water has high SDI. 

3. Certain levels of fouling also occur in ED operations. ED membranes can be cleaned 

or regenerated using weak acid treatment. 

4. Plate and frame configuration of the ED system enables easier maintenance and 

cleaning. 

The picture below shows mobile ED treatment units from Frac Water, Inc. ED treatment 

primarily recovers 80 to 90% of brackish water. The patents-pending electrodialysis HEEDTM 

stack configuration with dual or multiple side-by-side ion exchange membrane cells and 

improved gasket design results in greater separation efficiencies and affords greater flexibility in 

unit design. The improved design requiring up to 40% less membrane area resulted in an 

increase in energy efficiency of more than 70%. 

Mobile ED treatment trailer 

developed by Frac Water Inc 

(Wyoming)
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

76

Section 4.8.5 Capacitive Deionization Technology (CDT) 

Capacitive deionization technology (CDT) is a new technology being developed for the 

purification of ocean and brackish groundwater. A constant voltage is applied and soluble salts 

are collected on the surface of porous carbon electrodes, thus purifying the water for human 

consumption or industrial processes. In CDT, a brackish water stream flows between pairs of 

high surface area carbon electrodes that are held at a potential difference of 1.2 V. The ions 

and other charged particles (such as microorganisms) are attracted to and held on the 

electrode of opposite charge. The negative electrode attracts positively charged ions (cations) 

such as calcium (Ca), magnesium (Mg), and sodium (Na) while the positively charged electrode 

attracts negative ions (anions) such as chloride (Cl) and nitrate (NO3). Eventually, the 

electrodes become saturated with ions and must be regenerated. The applied potential is 

removed and the electrodes are flushed to release attached ions from the system producing the 

more concentrated brine stream. 

The current carbon aero gel electrodes provide approximately 500 m2

/g surface area. They 

provide high electrical conductivity and high ion permeability. Carbon aero gel electrodes are 

expensive and their ion storage capacity is relatively low. The main problem is that the cost of 

the electrodes is high due the high cost of the resorcinol (Resorcinol Fluoride, RF) from which 

the electrodes are made. TDA Research, Inc. developed electrodes that provide higher surface 

area. CDT System, Inc. is developing an impregnate of carbon nanotubes on the RF resins. 

Figure 4.9 shows a conceptual diagram of CDT. Exchange of ions does not occur; ions are 

adsorbed within the pores of charged electrodes under the effect of capacitance. 

Figure 4.9 A conceptual diagram of an AquaCell during CDT operation 

(Source: TDA Research, Inc.)

Positive electrode attracts negatively charged ions (anions). 

Chloride (Cl-

)

Nitrate (NO3

-

)

Silica (SiO2

-

)

Negative electrode attracts positively charged ions (anions). 

Sodium (Na+

)

Calcium (Ca+

)

Magnesium (Mg+

)
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

77

Applications

Desalination of produced water 

Table 4.6 shows the result of the treatment of produced water from a CBNG well in Wyoming 

using CDT. 

Table 4.6 Performance of CDT for the CBNG produced water treatment 

Constituent Before

Treatment After Treatment 

Conductivity (micro s/m) 2,100 < 800

Sodium ions (ppm) 280 84 

Bicarbonate ions (ppm) 520 144 

CDT Mobile Systems also can be used to produce drinking water and water for agriculture 

purposes at a low cost. Table 4.7 shows the throughput capacity of a 28-foot mobile CDT unit 

that includes 30 AquaCells with the capability to be field expanded to 88 AquaCells. The 

expected quality of treated water is fixed at 500 ppm TDS for drinking water and 1000 ppm 

TDS for agriculture water. 

Table 4.7 Treatment capacity of CDT unit 

Feed Water TDS 

(ppm)

Capacity, Potable 

Water

Capacity, Agriculture 

Water

< 1,500 30,000 GPD 30,000 GPD 

2,500 20,000 GPD 27,000 GPD 

3,500 10,000 GPD 17,000 GPD 

4,000 5,000 GPD 12,000 GPD 

Source: CDT Inc, Dallas, TX 

Section 4.8.6 Electrochemical Activation (ECA) Technology 

Electrochemical Activation (ECA) technology is an innovative water disinfection technology that 

involves the exposure of water, and the natural salts, to a substantial electrical potential 

difference. As an anode (+) and a cathode (-) are placed in pure water and direct current is 

applied, electrolysis of water occurs at the poles leading to the breakdown of water into its 

constituent elements. If sodium chloride (NaCI), or table salt, is used as a solution, the 

dominant electrolysis end product is hypochlorite, a chlorine based reagent that is commonly 

used to disinfect water and kill microorganisms. This disinfection technology is currently used 

in series with the capacitive deionization technology in an activated water type of application. 

With this technology the natural water chemistry is used to produce highly effective disinfection 

agents that would destroy viruses and bacteria. 

Typically, activated water would be dosed before and after the CDT AquaCells. Dosage before 

reduces the overall organic load into the AquaCells and also disinfects the feed stream, 

preventing biofouling. The dosage after the CDT AquaCells would then mainly serve as a final 

disinfection step specifically for potable water applications. Another benefit of the activated 

water technology is that the dosage before the AquaCells would also serve as a surfactant, thus 

reducing fouling - for example, membrane fouling by CaCO3 (Calcium Carbonate) precipitation.
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

78

Section 4.8.7 Electro-deionization (EDI) 

Weakly-ionized species such as carbon dioxide, boron, and ammonia are difficult to remove via 

such membrane processes as RO and EDR. EDI (Hernon, et al., 1999) is an electrically-driven 

membrane process. EDI combines ion-exchange resins, ion-exchange membranes, and a DC 

electrical field. In EDI, ionized species are removed much like conventional ED with the rate of 

ion removal greatly increased by the presence of the ion-exchange resins in the cell. In the 

cell, the DC electrical field splits water at the surface of the ion-exchange beads producing 

hydrogen and hydroxyl ions that act as continuous regenerants of the ion-exchange resins. 

This allows a portion of the resins in the EDI to always be in the fully regenerated state. Once 

ionized, these species are quickly removed under the influence of the DC electrical field. In 

effect, ionized species are removed in one area of an EDI stack, and weakly ionized species are 

removed in a second area. 

Figure 4.10 shows the removal of ions as water travels through the EDI cell. Strongly ionized 

species are removed first in the flow path and weakly ionized species are removed as the water 

moves down the flow path. Removal of ionized species such as sodium, chloride, sulfate, and 

calcium by EDI is usually well over 99% and has been well documented previously. Removal of 

weakly ionized species is an area where a properly designed EDI can also achieve extremely 

high removal rates.

Figure 4.10 Schematic of an EDI cell 

(Source: Ionics, Inc.)

Applications

Ionics, Inc. has installed EDI units in various power plants and semiconductor plants in the U.S. 

Table 4.8 shows the average removal of weakly ionized ions using EDI in such plants. The 

results are based on the EDI operation only and no pretreatment or post treatment results are 

included. For example, EDI was able to remove approximately 97% of boron from the RO 

permeate. In this case, RO was unable to effectively remove boron from the produced water. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

79

Table 4.8 Average percentage removal of weakly ionized species using EDI 

Treatment Performance

% removal (avg.) Comments

Silica > 99.2 

CO2 > 99.5 

Boron > 97.0 Post RO treatment only 

Ammonia > 97.4 

The advantage of EDI is that it doesn’t require addition of chemicals to remove weakly ionized 

species from the produced water. 

Section 4.8.8 Evaporation 

Direct treatment of the produced water in an evaporation system eliminates majority of 

chemical/physical treatment. The principle of this technique is to provide latent heat to the 

feed water to generate vapor that can be condensed into pure water form. The remaining 

stream contains high concentrations of salts/solids. 

Falling Film Vertical Tube Evaporators 

Falling film vertical tube evaporators (Heinz and Peterson, 2003) have the highest heat transfer 

coefficient, which is required to save energy (see Figure 4.11). It also minimizes chances of 

fouling by keeping tubing surface wetted during operations. Produced water is de-oiled and the 

pH is adjusted. Next, a pre-heater increases the temperature of the produced water/brine. Hot 

brine goes to de-aerator, which removes non-condensable gases. Hot de-aerated brine enters 

the evaporator sump where it combines with the re-circulating brine slurry. The slurry is 

pumped to the top of a bundle of heat transfer tubes and flows down into each tube through a 

liquid distributor. As the brine flows down the tubes, a small portion evaporates and the rest 

falls into the sump to be re-circulated. The vapor travels down the tubes with the brine and 

goes to a compressor through mist eliminators. Compressed vapor flows to the outside of the 

heat transfer tubes where its latent heat is transferred to the cooler brine slurry falling inside. 

As a result, vapor gets condensed into pure water form that is pumped back through the heat 

exchanger where it gives up sensible heat to the incoming wastewater. A small amount of 

concentrated slurry from the evaporator sump is continuously discarded through a blowdown 

valve to maintain density of the slurry in the evaporator. The concentrated blowdown can be 

disposed through a class I injection well or can be converted into solid waste in a crystallizer. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

80

Figure 4.11 A vertical tube falling film vapor compression evaporator

 (Source: Ionics, Inc.) 

Rapid Spray Evaporation (RSE) 

AquaSonics International has developed a Rapid Spray EvaporationTM (RSE) system of ejecting 

contaminated water at high velocities through a specialized injector-nozzle into waste heat. 

The unit uses a heating element for a heat source across which air is blown into the 

evaporation chamber. As the heated air moves along the evaporation chamber, nebulized 

wastewater is injected into the evaporation chamber. The moving vapor and brine droplets 

pass through a mechanical filter that traps the brine droplets. The pure vapor phase then 

passes on to a condenser. The brine droplets are periodically flushed from the filter with the 

water being treated. 

As the water vaporizes within milliseconds of ejection, the solids in the solution flash or 

separate out. The water vapor is condensed and collected while the precipitated solids form 

isolated crystalline particles that are collected through a vacuum process and sold as a 

byproduct. RSE ejects the salt water through a nozzle into a stream of heated air forming a 

mist of droplets that vaporize almost instantly. The minute flakes of solid salt left behind fall to 

the bottom of the evaporation chamber where they can be collected. The best success comes 

from developing nozzles that allow the process to work with hydraulic pressure. 

Applications

Tests on the RSE system (Turner, 2002) carried out by Westwater Resources, Albuquerque, 

New Mexico, confirmed that it can process water containing up to 16% salt. The operating 

costs for RSE are about one-third of the cost of conventional desalination methods alone, 

producing 1,000 liters of fresh water for between 16 and 27 cents. AquaSonics claims to attain 

nearly 100% salt conversion of salt water into fresh water. Table 4.9 shows the results 

obtained during the testing phase. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

81

Table 4.9 Rapid Spray Evaporation testing results (Source: WestWater Resources) 

Solute Untreated

(ppm)

Treated

(ppm)

Concentrate 

(ppm)

Calcium 79 1.6 20 

Magnesium 490 1.7 600 

Sodium 25,000 160 57,000 

Potassium 610 1.9 1,100 

Chloride 5,000 90 8,400 

Sulfate 31,000 150 35,000 

Bicarbonate 5,700 20 2,900 

Phosphate 1,200 0 - 

Carbon Dioxide 3,100 0 - 

TDS 130,000 440 180,000 

Freeze Thaw Evaporation (FTE) 

Freeze thaw evaporation (FTE®) is a process whereby produced water is first stored in a holding 

pond until air temperatures drop below 0°C (32°F). The water is then removed from the pond 

using pumps and sprayed onto a separate freezing pad which consists of an elevated pipe grid 

with strategically placed sprinklers. These sprinklers can be raised as the ice builds up on the 

pipe grid. The unfrozen brine water drains from the ice grid and is separated using 

conductivity-controlled valves. 

The concentrated brine water is then transported to separate storage ponds for either 

secondary treatment or for disposal. The picture below shows a Spray Freezing unit with 

sprinklers. The alternate to Spray Freezing process involves allowing the holding reservoir to 

freeze, and draining the brine that forms below the ice. The ice in the pond melts in the spring 

leaving fresh water. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

82

Source: Hart Energy Publications 

Applications

Crystal Solutions, LLC, a joint venture of Gas Technology and BC Technologies, utilized FTE 

(Lang, 2000) for produced water treatment at its first major commercial treatment facility near 

Wamsutter, Wyoming. The FTE uses naturally occurring ambient temperature swings to 

alternately freeze and thaw produced water, concentrating the dissolved solids and producing 

fresh water suitable for various beneficial uses. 

During the 1999-2000 cycle, produced water with 14,000 ppm of TDS was converted to a 

concentrated brine of approximately 64,300 ppm TDS and the fresh water (melt from ice) 

having 924 ppm TDS. Roughly 55% of the feed was converted to melt water; about 30% is 

lost to evaporation and/or sublimation; and only about 15% of the original feed remains as 

concentrated brine. In this case, due to the concentrated brine having a potassium chloride 

concentration in excess of 2% it was a usable product for drilling applications. 

Section 4.8.9 Pressure Driven Membrane Separation Technologies 

Microfiltration (MF), Ultrafiltration (UF), Nanofiltration (NF) and Reverse Osmosis (RO) utilize 

high pressure across the membranes to accomplish filtration of contaminants from the produced 

water. These technologies are the most common techniques of water purification. The 

membranes also are continuously being upgraded or modified for superior performance. 

Various applications of the pressure driven membrane technologies are listed in Table 4.10. 

Molecular Weight Cutoff (MWCO) is the ability of a membrane to reject the species of certain 

molecular weight measured as Daltons. 

Spray Freezing FTE unit 

in operation

(Wyoming)
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

83

Table 4.10 Applications of advanced membrane filtration technologies 

Membrane 

Filtration 

Separation 

Specifications Applications/Removal

Microfiltration (MF) >100,000 Daltons 

10 - 0.1μm

bacteria, viruses, suspended 

solids etc 

Ultrafiltration (UF) 10,000 to 100,000 Daltons 

0.05 - 5 e-3 μm

proteins, starch, viruses, colloid 

silica, organics, dyes, fats, paint 

solids etc 

Nanofiltration (NF) 1,000 to 100,000 Daltons 

5 e-3 - 5 e-4 μm

starch, sugar, pesticides, 

herbicides, divalent ions, 

organics, BOD, COD, detergents 

etc

Reverse Osmosis (RO) salts and lower MWCO 

1 e-4 - 1 e-5 μm

metal ions, acids, sugars, 

aqueous salts, dyes, natural 

resins, monovalent salts, BOD, 

COD, ions etc 

Gas Liquid Membrane CO2, H2S 

decarbonation, hydrogen sulfide 

removal

MF, UF and NF are based on the principle of rejection of species higher than the pore size of 

the membrane under pressure. RO uses the operating pressure higher than the osmotic 

pressure of salt present in the water to drive pure water through the membrane, thereby 

rejecting the salts. It is reversal of the osmosis process where water flows from the higher 

concentration solution to the lower concentration solution to attain natural equilibrium. The 

notion of these filtration technologies is discussed in the literature (“Membrane Filtration”, 

1999).

In gas-liquid separation, the pressure difference across a selective membrane is with pore size 

of about 0.03 micrometers (small enough to prevent water from leaking out, but large enough 

to allow CO2 to pass through) is applied. Gas penetrates into the membrane at a rate that 

depends on diffusivity and solubility of molecules in order to attain the equilibrium between the 

gas phase and the solute gas in liquid. The pressure difference is created by either vacuum or 

gas sweep through the membrane. 

Oil and gas operators exploit the clear advantages of using mobile produced water treatment 

units. GE Osmonics, one of the leading manufacturers of membranes focusing on produced 

water treatment applications, has been developing high performance compact membrane (such 

as spiral wound membrane) modules (GE, 2006). These membrane modules are easy to utilize 

in mobile systems. The spiral wound membrane offers the most efficient packing of membrane 

area to provide higher membrane contact area in limited space. The performance of these 

membranes is reduced by higher temperature; the upper limit for operating temperature is 113 

to 122°F, but some of the spiral wound elements it can be used up to 194°F. Higher 

temperature operations require more pressure differential across the membranes and so more 

energy is required to achieve desired separation. However, higher temperature reduces the 

viscosity of the solution which somewhat offsets the temperature effect (Barrufet, et al., 2004). 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

84

The pH of the solution is also an important factor during the membrane filtration operations. 

High pH RO operation effectively removes boron if the membrane can sustain high pH. 

Membrane fouling is a common problem in the various membrane filtration processes. Higher 

flow rate through the membrane module can produce enough shears near the membrane to 

avoid accumulation of oil and fouling agents. A hydrophilic membrane is less prone to oil 

fouling as it has a higher affinity for water and ability to reject oil and grease. New Logic 

Research developed a vibrating membrane mechanism to avoid membrane fouling caused by 

free oils and scaling agents (New Logic Research, 2003). The sinusoidal vibration of the 

membrane avoids the migration of colloids onto the membrane surface. The colloids are 

washed away with reject in the cross-flow configuration. The anionic membrane repels anions 

(monovalent, divalent, or multivalent) and associated cations (sodium, magnesium, copper, 

zinc, iron etc.). Figure 4.12 shows a conceptual picture of Vibratory Shear Enhanced Processing 

(VSEP) membrane. 

Figure 4.12 A VSEP membrane avoids fouling by continuous sinusoidal vibration

 (Source: New Logic Research Inc) 

Petroleum recovery and research center (PRRC) of New Mexico Institute of Mining and 

Technology has developed inorganic membranes for the produced water treatment focusing on 

the treatment of high salinity produced water (> 50,000 ppm in San Juan and > 100,000 ppm 

in Permian basin). The inorganic membranes made up from zeolite provided higher flux, pH 

compatibility, and thermal and chemical stability. Table 4.11 shows the higher removal 

efficiency, even lower differential pressure, and higher flux operations. Each row is for different 

membranes.
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

85

Table 4.11 Performance of various zeolite membranes (Source: PRRC, NMIMT) 

Membrane Ions in 

feed

TDS

(ppm)

Pressure

(psi)

Flux

(kg/m2.h) 

Rejection

(%)

1 Na+, K+,

Ca2+, Mg2+,

NH4

+, Cl39,000 350 0.112 74.5 

2 Na+, Cl- 5,500 300 0.135 89.2 

3 Mg2+, Cl- 9,400 300 0.081 68.6 

4 Ca2+, Cl- 11,000 300 0.096 57.6 

5 Na+, SO4

-

 14,200 300 0.097 57.4 

6 Na+, Cl- 5,000 300 0.24 76.8 

Applications

GE Pilot Study, California 

In 2001, GE Osmonics performed a pilot study (GE, 2001) to evaluate feasibility of membrane 

filtration technologies for the treatment of produced water in California near Bakersfield. The 

produced water came to the surface at 185°F with approximately 10,000 ppm of salt, a high 

level of suspended solids, and free oil. 

The three-step membrane separation combined with an ion exchange step proved to be 

sufficient to yield water suitable for irrigation (< 1,000 ppm TDS). The treated water contained 

5 to 10 ppm boron, which is higher than the 0.75 ppm limit for irrigation water. Purification of 

treated water using ion exchange produced boron levels below the 0.75 ppm limit. The 

schematic of produced water treatment is shown in Figure 4.13. 

Figure 4.13 GE produced water treatment system, California 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

86

The pH of the produced water from the oil separators was adjusted to 5.8 with sulfuric acid. 

The suspended solids were allowed to settle in a tank with a conical bottom. CO2 and H2S were 

degassed from the top of the tank and feed from the middle of the tank is discharged to a 

cartridge filter to remove smaller particles and oil. The effluent from the cartridge filter is 

passed through high temperature UF, NF and RO units followed by cooling operation and a low 

temperature RO unit. The overall system recovery was more than 80% considering the 

recycling of the UF concentrate and the use of the RO concentrate for various purposes. Table 

4.12 shows the results of the produced water treatment system composed of membrane 

filtration units. 

Table 4.12 GE pilot water treatment plant results 

Constituent Feed

(ppm)

UF Permeate 

(ppm)

NF Permeate 

(ppm)

RO Permeate 

(ppm)

Sodium 9,610 9,610 5,250 144 

Calcium 715 715 163 5 

Magnesium 412 412 115 2 

Potassium 174 174 77 2 

Ammonium 110 110 68 2 

Chloride 8,010 8,010 4,710 114 

Sulfate 1,090 1,090 Non-detectable Non-detectable 

Oil 10 – 50 < 1 Non-detectable Non-detectable 

Recovery, % - 90 – 95 % 90 – 95 % 80 – 90 % 

Placerita Canyon Oil Field, California 

The pilot water treatment unit at Placerita Canyon oilfield (Funston, et al., 2002) consisted of 

warm softening, coconut shell filtration, cooling (fin-fan), trickling filter, ion exchange, and 

reverse osmosis. The warm softening process removed approximately 95% hardness from the 

produced water. Silica levels in the softening effluent were 80 and 20 mg/l at a pH of 8.5 and 

9.5, respectively. Silica level decreased to 3 mg/l when 400 mg/l of MgCl2 were added. More 

than 95% of TDS was removed by RO. Approximately 90% removal of boron was achieved at a 

pH of 10.5 or above. Ammonia removal was 80% at a pH of 8.7 or below. The capital cost of 

the treatment varied from $3.4 million to $13.2 million. The annual estimated operation and 

maintenance cost varied from 6¢ to 27¢/barrel of water treated. Table 4.13 shows the 

summary of produced water treatment system. Figure 4.14 shows the schematic diagram of 

the produced water treatment system. 

The first step was the Warm Softening process in which lime, MgCl2 and ionic polymer were 

added to the produced water to precipitate calcium and magnesium hardness. Equation 6 

shows the removal of bicarbonate hardness by addition of lime. 

Ca(HCO3 )2 Ca(OH)2  2CaCO3  2H2O ..(6) 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

87

Table 4.13 A summary of utilized water treatment processes 

Process Specifications Treatment Comments 

Warm

Softening

100 gpm throughput with 

10 gpm/ft2 precipitate 

rising rate 

Hardness, Boron, Silica, 

Ammonia removal 

sodium hydroxide/ polymer

MgCl2 addition

Cooling Fin-fan heat exchanger cooling effluent from 

softening unit 

necessary to prevent 

damage of the downstream 

units

Trickling

Filter

400 ft3 of polypropylene 

packing 2.5 gpm/ft2 

Hydraulic loading 

Biological oxidation of 

organic carbon effluent with < 2 ppm TOC 

Ion

Exchange

5 ft3 of Ionac C-249 resin 

with capacity of 25-30 

grains/ft3

Pretreatment to RO 

stage

residual hardness 

removal

cation exchange 

membranes 

RO 4 X 40 spiral wound 

membrane

TDS, Boron, Silica 

removal high pH for Boron removal 

GAC

Adsorber activated carbon packing organics removal post trickling filter 

treatment 

Figure 4.14 Schematic of produced water treatment process 

Boron, silica, and ammonia were removed to some extent in the Lime Softening process. The 

effluent from the softening process was discharged to a fin-fan type heat exchanger to cool the 

water from more than 150°F to just above ambient air temperature as the units downstream of 

the softening unit were susceptible to damage at temperatures above 100°F. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

88

The next step was the trickling filter for biological oxidation of organics (U.S. EPA, 2000). A 

trickling filter is a plastic or rock packed system with large diameter to depth ratio. Influent 

water is trickled through from the top in the presence of air (oxygen). The microorganisms in 

the produced water attach on the surface of packed media to form a biological film. 

Subsequently, the organic materials are degraded by the biological film. As the biological film 

thickens through microbial growth, oxygen penetration to the packed media is affected. Also, 

portions of the film lose their ability as they are used to degrade organics. This causes the used 

layer to fall off from the packed media, known as sloughing process. Next the sloughed solids 

are removed in pressure filters. During most stages of testing, the trickling filter was bypassed 

to allow the microbes produced to acclimate to the water organics. When bypassing the 

trickling filter, the water was sent directly from the heat exchanger. 

Next, the processed water passed through the ion exchange softeners to remove any residual 

hardness. Finally, RO was used to remove TDS, boron, and additional organics. The RO 

permeate was sent to a 2,000-gallon polyethylene tank for storage and the concentrated reject 

stream was sent to the system drain. pH adjustment is the most important step in the 

treatment system because boron, silica, ammonia, and hardness removal depends on pH of the 

solution. The relationships among the constituents are not monotonous, which required careful 

pH adjustment during the process. For example, as the pH of the solution increases more silica 

gets ionized and that increases silica solubility, which may increase membrane leakage and 

deteriorates the silica removal. Opposite to that, as the silica solubility increases the chances of 

membrane fouling due to silica precipitation decreases, which improves RO membrane 

performance. As the pH of the solution increases ammonia solubility decreases, which 

diminishes ammonia removal by RO. 

High Efficiency Reverse Osmosis (HEROTM)

GE Ionics developed HEROTM (Hayter et al., 2004) to provide higher water recovery, higher 

quality permeate, higher operating flux, and lower overall cost than conventional RO treatment. 

The most important stage of HERO is pretreatment of the feed water before RO operation to 

raise the pH of feed water that enables higher efficiency. As discussed earlier, increase in pH 

improves boron removal and avoids membrane fouling. 

As shown in Figure 4.15, HERO is a three step process. 

1. Hardness removal: Calcium and Magnesium hardness can precipitate on RO membranes 

at high pH, which causes membrane fouling. Alkali is added to balance alkalinity and 

hardness which improves weak acid cation exchange (WAC) softening process efficiency. 

WAC resins exchange hardness from the produced water as discussed earlier. The H+ 

addition increases pH enabling conversion of bicarbonate alkalinity into carbon dioxide. 

2. Carbon dioxide removal: As discussed in earlier sections, degasification using air 

stripping removes carbon dioxide from the water. The carbon dioxide removal further 

increases pH of the produced water. 

3. High pH RO: High pH water increases solubility of silica and destroys biological 

organisms that cause membrane fouling. Dissolved solids are removed by the RO 

process.
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

89

Figure 4.15 A schematic of HERO system developed by GE Ionics 

The biggest advantage of the HERO system is the reduced capital cost (~15%) at higher flux 

rate (50 GPM). Because of reduced fouling and scaling of the RO membrane, the operating and 

energy costs for HERO are also less than conventional RO. The increase in water recovery is 

obvious with HERO systems due to the high performance of membrane. The shortcomings of 

HERO are the treatment chemical requirements and the higher costs at lower flux operations. 

GE Ionics tested a HERO system to upgrade the water purification plant of Sandia National 

Laboratories at Albuquerque, New Mexico. The system produced approximately 94% water 

recovery. The reported power usage was approximately 17 kWh per 1000 gallons of treated 

water. The reported operating cost was approximately $0.064 per gallon of treated water. 

Oxidation Reactor 

Newpark Environmental Services offers an innovative treatment system consisting of several 

components and is based on aggressive oxidation followed by precipitation of the contaminants 

present in the produced water (Lincz, 2004). Oxidation of contaminants is the most important 

part, which is accomplished in the Armel Reactor, a proprietary design of Newpark 

Environmental Services. The Armel Reactor is part of the chemical/physical treatment stage of 

this multi-stage technology. The chemical/physical stage is often adequate to achieve many 

water treatment requirements on its own. Dissolved contaminants such as monovalent salts are 

extremely resistant to oxidation/precipitation and may not be removed during the 

chemical/physical treatment stage. Such contaminants can be removed in the demineralization 

stage, which consists of MF, UF and/or RO units. The chemical/physical treatment stage before 

the demineralization stage removes contaminants that can plug the membrane and improves 

efficiency of the demineralization stage. 

The Newpark system contains three separate stages that can be used separately or in tandem: 

the chemical/physical stage, the demineralization stage, and the waste disposal stage. 

Chemical/Physical Stage 

The chemical/physical stage consists of the following elements: 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

90

Degasification – recovery of methane gas from produced water inflow from CBNG well 

and removal of CO2 from produced water. 

Solids Removal – water from degasification unit flows through patented Clasiker 

equipment that removes suspended solids ranging from debris to micro fines. 

pH Adjustment – pH of the water is adjusted to as neutral as possible, which would 

maximize the efficiency of oxidation reactor. 

Liquid Ring Blower – high volume, low pressure air is pumped into the water stream just 

prior to the HB. 

Armel Reactor (sonic oxidation) – the water/air mixture then flows through the reactor 

and is aggressively oxidized/energized. Water/air mixture then enters the reactor where 

millions of small micro-bubbles are generated from the entrained air by mechanical 

means (5 to 10 psi pressure drop). The micro-bubbles carry positive charge and repel 

other micro-bubbles, but attract negatively charged ions (these negatively charged ions 

are associated with positively charged ions) in the form of a contaminant (Ca+CO3-, 

Na2+SO4-2 etc.). 

The charged micro-bubbles attract more oppositely charged contaminants and become thicker, 

which increases their surface tension. Due to ever increasing surface tension, the size of the 

micro-bubble decreases and the pressures and temperatures inside the bubble significantly 

increase, which creates points of highly localized temperature. Under the effects of increased 

pressure and temperature, contaminants attached to micro-bubbles are violently reacted with 

O2 associated with atmospheric air inside the micro-bubble. The energy associated with this 

reaction results in ultrasonic wave and a very aggressive oxidation of contaminants. Those 

contaminants not oxidized are highly energized and in a very reactive state. The water (along 

with the oxidized and energized ions/contaminants) flows out of the reactor to the next stage. 

Degasser – at this stage all O2 has 

been consumed but a significant 

amount of N2 remains trapped in the 

water. Degasser removes the 

trapped N2.

Coagulation/Flocculation – a 

coagulant (lime) and flocculent 

(anionic polymer) is mixed into the 

water to precipitate out the treated 

contaminants in the form of 

flocculants. 

Frictioning – frictioner settles and 

removes the larger flocculants. 

High Rate Clarification – a series of 

tubes settles out and removes the 

smaller flocculants.

Sand/Activated Carbon Filtration –

the water is then filtered through a sand and activated carbon to remove the smallest 

flocculants. The water becomes clear through this process.

HB Reactor for aggressive 

oxidation of contaminants – 

proprietary design 

(Wyoming)
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

91

Demineralization Stage 

Complete removal of dissolved contaminants can be achieved in the demineralization stage by 

further treatment of effluent water from the chemical/physical treatment system. The 

demineralization stage consists of the following elements: 

MF Unit – sub-micron size particles or contaminants are removed in MF unit. This 

ensures that undissolved sub-micron particles do not enter the RO system and plug the 

membranes.

RO Unit – the water is then pumped at high pressure through a series of reverse 

osmosis membranes for the concentration and further removal of remaining dissolved 

contaminants. 

Waste Disposal 

Permeate from the RO unit can be utilized as a fresh water source with or without further 

treatment. Concentrate is generally hauled to the nearest disposal facility. Large volumes of 

concentrate, transportation costs, and limited capacity of disposal sites encourage further 

treatment of concentrate. Concentrate can be dried into a solid phase, which would be easier 

to handle. 

Crystallizer and Evaporator – Crystallizer further concentrates the RO concentrate 

stream by extracting water. Total volume of the concentrate is reduced while the 

associated TDS increases significantly. The water (extract phase) is re-circulated 

through the RO and concentrate (sludge-water) flows through evaporators. Water gets 

evaporated and the dissolved solids remain in sludge state. Handling and disposal of 

reduced volume of waste in sludge form is easier. 

Figure 4.16 shows a schematic of produced water treatment system designed by Newpark 

Environmental Services. Newpark has tested this system for the treatment of produced water 

from various sources on the pilot scale. 

Table 4.14 shows the performance of Newpark’s system for the treatment of produced water 

from three facilities. The quality of effluent or treated water at the end of both the 

chemical/physical treatment stage and demineralization stage was supervised. The Pinedale 

and Gillette plants are company-owned facilities that process operators’ water on a contract 

basis.

Section 4.8.10 NORM Treatment 

Naturally occurring radioactive materials (NORM), such as radium, are mobilized from the oil or 

gas formations because of the solubility in the presence of chloride ions which are present in 

the water within formation (Tenorm Page, 2004). Low solubility of the sulfate species is a 

factor in redeposition of NORM. The low solubility precipitates scale containing high 

concentrations of radium in the form of barium sulfate or barite [Equation 7] under the effects 

of varying temperature and pressure during the production operations. 

4 4 Ba  Ra  SO  Ba[Ra]SO   

 ..(7) 

The handling and treatment of the precipitated sulfate deposits containing decaying radioactive 

materials is an absolute necessity because of the dangers of radioactivity. BPF Inc., Texas 

(Mickley, 2001), developed a mobile automated treatment system that includes separation of 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

92

NORM solids from other oilfield waste (produced water) containing less than 30 pCi/g 

(picocuries per gram, a measurement of radioactivity) radium and dissolving it into aqueous 

solutions. Extraction of radionuclides from the scale is done by dissolving the radioactive 

material in one or more aqueous solvents in the hydroclone, which separates solids with no 

NORM from the solution. The NORM containing solution is transported to class II injection sites 

and reinjected into the formation (Smith, et al., 1997). 

Radioactive materials also occur in natural gas in the form of radon. One of the methods to 

treat the gas is packed bed adsorption of radon with activated charcoal. Monitoring of 

radioactivity is an essential part of NORM treatment, which is accomplished by in-situ 

radioassay capability. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

93

Figure 4.16 Newpark Environmental Services produced water treatment system 

(Source: Newpark Environmental Services) 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

94

Table 4.14 Results from field test with a produced water treatment system 

Pinedale, WY (Pinedale 

Field Produced Water) 

Big Hills, TX (Conventional Oil 

and Gas Produced Water) 

Gillette, WY 

(CBNG Water) 

Effluent Effluent Effluent Parameter

mg/L or 

ppm

Influent Chemical/

Physical 

After 

RO

Influent Chemical/

Physical 

After 

RO

Influent Chemical/

Physical 

After 

RO

Carbonate

(CO3) < 1 - - < 1 < 1 < 1 < 1 - < 1 

Bicarbonate

(HCO3) 842 - - 312 156 7.3 2,782 - 12.2 

Calcium 68 - - 2,388 303 0.96 43.67 - 1 

Chloride 4,589 - 56.5 70,978 8,922 355 115 - 18 

Magnesium 9 - - 90 93 0.3 32.87 - < 0.1 

Sodium 3,324 - 36.6 49,590 5,140 217 1,076 - 21.5 

Sulfates 1 - - 6 280 < 1 < 1 - <0.1 

Alkalinity as

CaCO3

582 - - 210 118 6 2,110 - 10 

TDS 11,957 3,004 93 174,452 19,053 93.1 3,203 1,358 46 

TPH 5 - - 8 2 1 1 - 1 

(Source: Newpark Environmental Services) 

A summary table of the various treatment technologies included in here is presented in Table 

4.15 for ease of use. The table describes advantages, disadvantages, and ranges of field 

applicability for each treatment technology evaluated. The table is segmented by treatment 

objective (for example “De-oiling”), and within each objective technologies can be compared in 

terms of their advantages, disadvantages, resulting waste stream, and applications to oil and 

gas fields. Advantages and disadvantages are described in comparative terms rather than 

absolute figures that are subject to change; the aim is to compare technological options for a 

given objective. Durability and cost are important factors that will depend on site-specific 

conditions and the specific commercial version picked by the operator. Comparisons of inherent 

durability can be made within each objective but these are only generalizations. No attempt was 

made to ascribe economic factors to these technologies since costs will vary from location to 

location and may be dependent upon commercial configurations and innovations. 

Waste products are specific to each technology; for example desalinization can result in a 

residue consisting of 20% of the input stream or a residue made up of 1% of the input. The 1% 

residue will be a more concentrated brine than the 20% residue. However, both may no longer 

be classified as oil and gas wastes because they are a result of a treatment process. “Raw” 

produced water can be disposed of by way of an exemption from standard industrial waste 

regulations under the federal Resource Conservation and Recovery Act (RCRA) as described in 

Section 3. The oil and gas exemption means that “raw” produced water can be sent to deep 

disposal wells that inject the water back into deep, salt water bearing reservoirs with minimal 

regulatory requirements and cost. Industrial brines, however, are subject to increased 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

95

regulatory compliance costs because the brines are a result of a treatment process. The 

challenges associated with the UIC process are discussed in more detail in Section 3, and the 

disposal options are discussed in Section 4.9. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

96

 Table 4.15 Advantages, Disadvantages, and Applicability of Produced Water 

Treatment Technologies 

TREATMENT DESCRIPTION ADVANTAGES DISADVANTAGES WASTE STREAM 

OIL AND GAS 

PRODUCED

WATER

APPLICATIONS 

De-oiling

Corrugated plate 

separator 

separation of free oil from 

water under gravity 

effects enhanced by 

flocculation on the surface 

of corrugated plates 

No energy required, 

cheaper, effective for 

bulk oil removal and 

suspended solid 

removal, with no 

moving parts, this 

technology is robust 

and resistant to 

breakdowns in the 

field. 

inefficient for fine oil 

particles, requirement of 

high retention time, 

maintenance 

suspended particles 

slurry at the bottom of 

the separator 

Centrifuge

separation of free oil from 

water under centrifugal 

force generated by 

spinning the centrifuge 

cylinder 

efficient removal of 

smaller oil particles 

and suspended 

solids, lesser 

retention time-high 

throughput 

energy requirement for 

spinning, high 

maintenance cost 

Hydroclone 

free oil separation under 

centrifugal force 

generated by pressurized 

tangential input of influent 

stream

compact modules, 

higher efficiency and 

throughput for 

smaller oil particles 

energy requirement to 

pressurize inlet, no solid 

separation, fouling, 

higher maintenance cost

suspended particles 

slurry as pretreatment waste 

Gas floatation 

oil particles attach to 

induced gas bubbles and 

float to the surface 

no moving parts, 

higher efficiency due 

to coalescence, easy 

operation, robust and 

durable 

generation of large 

amount of air, retention 

time for separation, skim 

volume 

skim off volume, 

lumps of oil 

Oil recovery from 

emulsions or water with 

high oil content prior to 

discharge. Produced 

water from water-drive 

reservoirs and water 

flood production are 

most likely feed-stocks. 

Water may contain oil & 

grease in excess of 

1000 mg/L. 

Extraction 

removal of free or 

dissolved oil soluble in 

lighter hydrocarbon 

solvent 

no energy required, 

easy operation, 

removes dissolved oil

use of solvent, extract 

handling, regeneration 

of solvent 

solvent regeneration 

waste 

Ozone/hydrogen

peroxide/oxygen

strong oxidizers oxidize 

soluble contaminant and 

remove them as 

precipitate 

easy operation, 

efficient for primary 

treatment of soluble 

constituents 

on-site supply of 

oxidizer, separation of 

precipitate, byproduct 

CO2 etc. 

solids precipitated in 

slurry form 

Adsorption 

porous media adsorbs 

contaminants from the 

influent stream 

compact packed bed 

modules, cheaper, 

efficient 

high retention time, less 

efficient at higher feed 

concentration 

used adsorbent media, 

regeneration waste 

Oil removal from water 

with low oil and grease 

content (< 1000 mg/L) 

or removal of trace 

quantities of oil and 

grease prior to 

membrane processing. 

Oil reservoirs and 

thermogenic natural gas

reservoirs usually 

contain trace amounts 

of liquid hydrocarbons. 

Biogenic natural gas 

such as CBNG may 

contain no liquids in the 

reservoir but when 

pumped to the surface, 

the water takes up 

lubricating fluids from 

the pumps. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

97

TREATMENT DESCRIPTION ADVANTAGES DISADVANTAGES WASTE STREAM 

OIL AND GAS 

PRODUCED

WATER

APPLICATIONS 

Disinfection 

UV light/ozone 

passing UV light or ozone 

produce hydroxyl ions that 

kills microbial 

simple and clean 

operation, highly 

efficient disinfection 

on-site supply of ozone, 

other contaminants 

reduce efficiency 

Chlorination 

chlorine reacts with 

water to produce 

hypochlorous acid which 

kills microbial 

cheaper and the 

simplest method 

does not remove all 

types of microbial 

small volumes of 

suspended particles at 

the end of the treatment 

Microbes may exist in 

the subsurface reservoir 

or can be introduced 

during production or 

during water 

treatments. Disinfection 

may need to be done to 

protect potability or to 

or to prevent fouling of 

the reservoir, tubulars, 

and surface equipment.

Desalinization

Lime softening 

addition of lime to remove 

carbonate, bicarbonate 

etc. hardness 

cheaper, accessible, 

can be modified 

chemical addition, post 

treatment necessary 

used chemical and 

precipitated waste 

Ion exchange 

dissolved salts or minerals 

are ionized and removed 

by exchanging ions with 

ion exchangers 

low energy required, 

possible continuous 

regeneration of resin, 

efficient, mobile 

treatment possible 

pre and post treatment 

require for high 

efficiency, produce 

effluent concentrate 

regeneration chemicals 

Electrodialysis 

ionized salts attract and 

approach to oppositely 

charged electrodes 

passing through ion 

exchange membranes 

clean technology, no 

chemical addition, 

mobile treatment 

possible, less 

pretreatment 

less efficient with high 

concentration influent, 

require membrane 

regeneration

regeneration waste 

Electrodeionization 

Enhanced electrodialysis 

due to presence of ion 

exchange resins between 

ion exchange membranes 

removes of weakly 

ionized species, high 

removal rate, mobile 

treatment possible 

regeneration of ion 

exchange resins, 

pre/post treatment 

necessary 

regeneration waste, 

filtrate waste from posttreatment stage 

Capacitive

deionization 

ionized salts are adsorbed 

by the oppositely charged 

electrodes 

low energy required, 

higher throughput 

expensive electrodes, 

fouling regeneration waste 

Electrochemical 

Activation 

ionized water reacts with 

ionized chloride ion to 

produce chlorite that kills 

microbial 

simultaneously salt 

and microbial 

removal, reduce 

fouling 

expensive electrodes regeneration waste 

Rapid spray 

evaporation 

injecting water at high 

velocity in heated air 

evaporates the water 

which can be condensed 

to obtained treated water 

high quality treated 

water, higher 

conversion efficiency 

high energy required for 

heating air, required 

handling of solids 

waste in sludge form at 

the end of evaporation 

These technologies 

typically require less 

power and less pretreatment than 

membrane technologies. 

Suitable produced 

waters will have TDS 

values between 10,000 

and 1,000 mg/L. Some 

of the treatments 

remove oil and grease 

contaminants and some 

of them require oil and 

grease contaminants to 

be treated before these 

operations. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

98

TREATMENT DESCRIPTION ADVANTAGES DISADVANTAGES WASTE STREAM 

OIL AND GAS 

PRODUCED

WATER

APPLICATIONS 

Freeze thaw 

evaporation 

utilize natural 

temperature cycles to 

freeze water into crystals 

from contaminated water 

and thaw crystals to 

produce pure water 

no energy required, 

natural process, 

cheaper 

lower conversion 

efficiency, long 

operation cycle 

Membrane Treatment 

Microfiltration 

membrane removes 

micro-particles from the 

water under the applied 

pressure 

higher recovery of 

fresh water, compact 

modules 

high energy required, 

less efficiency for 

divalent, monovalent 

salts, viruses etc. 

Ultrafiltration 

membrane removes ultraparticles from the water 

under the applied 

pressure 

higher recovery of 

fresh water, compact 

modules, viruses and 

organics etc. removal

high energy, membrane 

fouling, low MW 

organics, salts etc 

Nanofiltration 

membrane separation 

technology removes 

species ranging between 

ultrafiltration and RO 

low MW organics 

removal, hardness 

removal, divalent 

salts removal, 

compact module 

high energy required, 

less efficient for 

monovalent salts and 

lower MW organics, 

membrane fouling 

Removal of trace oil and 

grease, microbial, 

soluble organics, 

divalent salts, acids, and 

trace solids. 

Contaminants can be 

targeted by the 

selection of the 

membrane. The size 

distribution of the 

removable species for 

membrane filtration 

technologies is shown in 

Table 4.10. 

Reverse Osmosis 

pure water is squeezed 

from contaminated water 

under pressure differential 

removes monovalent 

salts, dissolved 

contaminants etc., 

compact modules 

high pressure 

requirements, even 

trace amounts of oil & 

grease can cause 

membrane fouling 

concentrated waste 

from membrane 

backwash during 

membrane cleaning, 

concentrate stream 

from the filtration 

operation Removal of sodium 

chloride, other 

monovalent salts, and 

other organics. Some 

organic species may 

require pre-treatment. 

While energy costs 

increase with higher 

TDS, RO is able to 

efficiently remove salts 

in excess of 10,000 

mg/L.

Miscellaneous Treatment 

Trickling Filter 

develops film of microbial 

on the surface of packed 

material to degrade 

contaminants within 

water 

cheaper, simple and 

clean technology 

oxygen requirement, 

large dimensions of the 

filter

Constructed 

wetland

treatment 

natural oxidation and 

decomposition of 

contaminants by flora and 

fauna

cheaper, efficient 

removal of dissolved 

and suspended 

contaminants

retention time 

requirement, 

maintenance, 

temperature and pH 

effects 

sludge waste at the end 

of the treatment 

Removal of suspended 

and trace solids, 

ammonia, boron, metals 

etc. Post-treatment is 

normally required to 

separate biomass, 

precipitated solids, 

dissolved gases etc. 

SAR adjustment addition of Ca or Mg ions cheaper option chemical addition 

Balance high SAR and 

very low TDS (higher 

percentage of sodium 

salts) after membrane 

processes. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

99

TREATMENT DESCRIPTION ADVANTAGES DISADVANTAGES WASTE STREAM 

OIL AND GAS 

PRODUCED

WATER

APPLICATIONS 

NORM Treatment 

NORM treatment 

extraction of radioactive 

material with aqueous 

solution 

efficient for reducing 

radioactive waste 

volume 

extracted radioactive 

materials need further 

treatment or disposal 

 Produced waters 

containing high levels of 

Uranium or Thorium. 

Unless treatment is 

accomplished, 

radioactive scale can 

form in surface 

equipment extensive 

remediation. 

Natural Gas Recovery 

Air stripping stripping of dissolved gas 

from water

concurrent or 

countercurrent 

operations, cheaper 

post treatment, lower 

efficiency 

Source: ALL, 2005 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

100

Section 4.9 Handling of Water Treatment Waste/Concentrate 

Produced water treatment technologies convert poor quality produced water into good quality 

water by removing contaminants and impurities. As discussed earlier, many such treatment 

technologies decontaminate inlet produced water producing a waste stream with higher 

concentration of contaminants and a treated water stream. For example, membrane systems 

separate influent water into cleaner product water and a more concentrated stream that is 

called concentrate in RO, NF, and EDR systems and backwash in UF and MF systems. 

Considering large scale of produced water treatment, the amount of concentrated waste volume 

needs to be considered when planning water treatment facilities. 

The selection of concentrate disposal practice depends on several factors such as regional 

disposal availability (geology, geographical, climate, etc), local availability (existence of suitable 

disposal site, distance, compatibility, etc), volume of concentrate stream, applicable 

environmental regulations (NPDES, underground injection control regulations, and underground 

water resource regulations, etc. are imposed by local, state, or federal agencies), environmental 

impacts, public reception, cost, etc. Along with cost contributing factors such as transportation, 

treatment, development of disposal site, etc., environmental regulations also have major 

impacts on the feasibility of any particular concentrate disposal method.

Disposal to surface water: 

Membrane wastes may be discharged to surface waters and ultimately reside within large 

receiving water bodies. Direct discharge to water bodies must have an NPDES permit (states’ 

authority), which requires meeting CWA regulations for effluent limitations. Large volumes of 

concentrate waste and level of contaminants in it are some of the limiting factors for this 

practice.

Disposal to Publicly Owned Treatment Works (POTWs): 

An NPDES permit is not required for the disposal into publicly owned treatment works (POTWs). 

However, POTWs may enforce pre-treatment before disposal according to federal regulations to 

control the level of wastewater pollutants entering the sewage system. 

Disposal with injection well: 

Injection of concentrated waste through a Class I injection well beneath the lowermost 

underground source of drinking water requires meeting UIC regulations according to state and 

federal standards. Research is being attempted to evaluate disposal of concentrate into 

depleted oil or gas fields through Class I wells (Nicot and Dutton, 2004). Formation damage, 

scaling, etc., are some of the concerns for using depleted oil or gas fields. 

Evaporation ponds: 

Evaporation ponds utilize solar energy to evaporate water into the atmosphere in vapor form 

leaving behind solids/salts in sludge form. This technology is limited to regions where solar 

irradiation is high. Permits may be required if a potential of leakage into surface water or 

drinking water aquifers exists. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

101

Spray evaporation: 

An NPDES permit may be required for spray evaporation if the potential of waste runoff to a 

receiving water body exists. 

Zero liquid discharge: 

The objective of zero liquid discharge is to eliminate any liquid waste at the end of the water 

treatment process. Evaporators or concentrators can be utilized to concentrate the waste 

stream. Conversion of concentrated sludge into solids/salts form can be accomplished by using 

a crystallizer. Disposal of solid waste from a crystallizer must avoid contamination of surface or 

groundwater. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

102

THIS PAGE INTENTIONALLY LEFT BLANK 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

103

SECTION 5.0 PRODUCED WATER REDUCTION TECHNIQUES 

A white paper studying the applicability of various water reduction techniques to the coalbed 

natural gas development of the Powder River Basin in Montana and Wyoming was prepared as 

part of a research project funded by the National Energy Technology Laboratory (NETL) of the 

DOE. This section presents a summary of the findings of this research as they may apply to 

various basins across the United States. The title of the white paper is: Reducing Produced 

Water Volumes from Coal Bed Natural Gas in the Powder River Basin (ALL, 2005). 

Across the CBNG industry, the following were identified as the more promising technologies for 

minimizing produced water on the surface: 

1) Downhole Water Separation and Injection – avoids producing the groundwater to the 

surface as it separates water from gas downhole and injects the water into underground 

disposal/injection zones. 

2) Advanced Production and Completion Techniques – controls unconfined fracture 

propagation and reduces hydraulic connectivity between water bearing formations other 

than the resource bearing formation near the producing well. 

3) Horizontal Drilling – improves resource recovery (often without stimulation) per barrel of 

produced water and appears to be a way to reduce net water production. 

The technologies listed above are commonly used in the development of oil and gas reservoirs 

but are not applicable to every field. Each technology has geotechnical limitations and 

operational pros and cons that are described in Section 5.1 for downhole water separation and 

injection; Section 5.2 for advanced production and completion techniques; and Section 5.3 for 

horizontal drilling. 

Section 5.1 Downhole Water Separation and Injection

Downhole separators separate water from oil or gas within the well bore; oil or gas with little or 

no water is then produced to the surface. Significant amounts of water are disposed into a 

non-producing formation above or below the oil or gas producing formation using injection tools 

within the well bore. The performance of downhole separators is influenced by the geology of 

disposal zone. The small amount of water produced to the surface along with oil or gas requires 

appropriate handling or treatment, or disposal in accordance with the existing regulations. The 

downhole separator assembly comprises a number of various compact elements installed within 

the actual well bore. 

1) Separation Tool – Separates water from incoming fluids from the reservoir. The tool is 

not a necessity for a gas producing wells, but is required for oil producing wells. 

2) Pump – Pressurizes large amounts of water from the separator and injects the water 

into the disposal zone. Sucker rod pumps, plunger pumps, progressive cavity pumps 

(PCPs) or electric submersible pumps (ESPs) are utilized depending on the requirements 

of injection pressure and volume. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

104

3) Motor – Heavy duty compact motor-modules are required to perform desired pumping 

duty. 

4) Miscellaneous – Downhole monitoring equipment, cables, surface controls, etc. may also 

be required for better controlled operations. 

The evaluation of both engineering and economic feasibility varies significantly by operator and 

location. Some of the technical issues of concern for downhole separation are the following: 

Producing and Receiving Formation Suitability 

Selection of a suitable injection zone/area within the producing formation may depend upon 

several criteria, including reservoir characteristics, depth, relative location to producing wells, 

and possible contamination of underground sources of drinking water (USDW). To be a suitable 

candidate for downhole separation, the productive zone would have to produce very few fines 

that could plug the receiving zone. 

Zonal Isolation

The receiving formation must be vertically and laterally separated or otherwise confined from 

producing formations and other USDWs. Suitability analyses also would require the 

examination of local fracturing and faulting as the fractures may be able to hydraulically 

connect injection and producing zones; this could cause recycling of produced water in the 

vicinity of the well bore. 

Porosity 

Injection formation must have sufficient porosity to adequately hold the injected formation 

fluids. 

Permeability 

A productive reservoir or an attractive injection zone will have sufficiently high permeability to 

allow sufficient fluid movement. Confining zones should have very low permeability in order to 

act as seals rather than zones that will allow fluid movement. 

Storativity 

The storage capacity of a geologic unit can be estimated using a simplistic approach by 

estimating the pore volume of the entire injection zone. For instance, a permeable unit that 

has 10% porosity, is 20 feet thick, and is homogenous and regionally extensive would have a 

storage capacity of 2 million barrels if the injectate front extended for 1⁄4 mile. Higher 

storativity is desired and contributes to the success of injection. 

Injection Pressure 

Reservoir pressure may limit the rate at which fluids can be injected and/or may limit the 

injectivity. Injection pressures may be so high that fracture-propagation could be initiated and 

augmented; fractures within and outside the injection zone could cause real problems at the 

injection site leading to injected fluids moving out of the zone into a nearby producing zone or 

USDW.
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

105

Fractures 

Natural fracture or fractures created during injection can be helpful if they are confined to the 

injection zone and do not create conduits for flow across the confining zones. Fractures can 

reduce the impacts of near well bore damage and improve injectivity. However, unconfined 

vertical fractures extending from the producing formation to an USDW can cause problems. 

Water Quality 

The chemical compatibility of the injectate fluids also plays a part in the feasibility assessment 

of the injection plan. If the injected water is incompatible with the underground water of the 

injection zone it can cause scaling problems (from the precipitation of minerals) that could 

damage or reduce the hydraulic conductivity of the formation. 

Injectivity Loss

Water being separated downhole and injected is not filtered in the same manner that water 

brought to the surface and then re-injected is filtered. Clogging of pores of the injection 

formation by sand or fine solid particles, scale, biological slimes, and precipitates can reduce the 

rate a formation can receive injectate. The processes that cause injectivity loss can reduce the 

success of the downhole water separation installation more than any other effect, especially if a 

large volume of water is being injected every day. The build-up of fines across the perforations 

can act as a cement. For example, if the injectate contains as little as 50 mg/L suspended 

fines, injecting 1000 bpd will result in approximately 70 lbs of fines being forced into the 

formation opposite the perforations every day of operation. Over a very short time, plugging 

can lead to irreparable damage to an injection zone. 

Section 5.2 Advanced Production and Completion Techniques 

Improvements to production and completion techniques are being attempted by operators to 

reduce the production of water to the surface during the production of oil and gas resources. 

Some of the new techniques that operators are trying to utilize are described below. 

Section 5.2.1 Reverse Circulation Center Discharge 

A recent innovation is a unique drilling program developed by Calgary-based K2 Energy Corp 

(Evergreen, 2002). The process is called “reverse circulation center discharge” (RCCD). The 

company, in conjunction with Midnight Sun Drilling of Whitehorse, Yukon, has recently 

completed nine shallow gas wells in northern Montana. RCCD creates minimum drilling damage 

to the formation, thus allowing shallow, low pressure gas to flow to the surface during drilling 

operations. RCCD drilling consists of three basic components: double-wall drillpipe, an air 

hammer, and a downhole blowout prevention system. The drillpipe has 4.5-inch outer and 

2.875-inch inner diameter tubulars. Air circulates between the two strings, drives the air 

hammer, and at the same time reverse circulates the formation cuttings back up the inner pipe 

to the surface. K2 reports that the well bore is perfectly straight from top to bottom, with no fill 

at the bottom of the well. The well can flow gas as it is drilled. 

Section 5.2.2 Cavitation 

As a stimulation or clean-up treatment, the cavitation process uses dynamic pressure changes 

to break apart the rock face and to widen the effective borehole across the producing zone. Air 

or foam is pumped into the well to increase the pressure in the reservoir followed by a sudden 

release that blows out the air/gas along with rock fragments (Oil and Gas Accountability, 2004). 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

106

This action is sometimes referred to as "surging," and it is accompanied by a jet engine-like 

noise that can last up to 15 minutes. The rock fragments, foam, water, and gas that escape 

from the well are directed at an earthen berm to prevent the materials from entering the 

greater environment. Some of the loose rock material remains in the well. It is cleaned out by 

circulating water or foam in the well and pumping the material into the recovery pit or steel 

tank. 

Cavitation Inc. developed a new cavitation and cleaning tool specifically for CBNG completion. 

The cavitation and cleaning tool is engineered and designed for enlarging hole size, completion, 

and work over uses. The cavitation and cleaning tool can be used with air, water, and drilling 

foam, or just water and foam. An air compressor can be sized to the depth of a well. For 

example, a 950 cfm and 350 psi air compressor can be used on a well as deep as 1,200 feet, 

according to how much water the well makes. The tool can be adjusted to depth and hole size. 

The advantages of this technology include enlargement and cleaning of the well bore in one run 

and replacement of “water enhancement” activities that could create unconfined fractures 

responsible for higher water production. Limitations of cavitation may include shortening the 

production life of the CBNG well. 

Section 5.2.3 Well Stimulation 

After the producing well is completed either in one open hole zone or one or more zones 

opened by perforations through casing, the well is often stimulated by the injection of a fluid 

under pressure. Stimulation is achieved by one of several technologies – hydraulic fracturing, 

propellant fracturing, and various other techniques. 

Hydraulic Fracturing: 

One option for the operator is to complete producing wells with high pressure hydraulic fracture 

stimulation. Hydraulic fracturing is often avoided to prevent fracturing the confining formations 

adjacent to the producing zones, which can significantly increase water production. If the 

fracture is confined within the producing zone, for example, horizontal fractures in a vertical 

well within the zone contribute to increased gas production. If the fracture extends in vertical 

direction it can possibly contact the overlying or underlying water bearing formations or even 

extend into those aquifers. The vertical fractures then have the possibility of increasing the 

volume of produced water because water will be drawn not only from the productive zone but 

also from the water saturated sands around it. Typically, operators are aware of this possibility 

and go to great lengths to avoid this scenario so as to protect valuable water resources and to 

preserve the economics of their development. 

Research related to the stress analysis of earthen materials has determined that an individual 

fracture extends or propagates perpendicular to the least principal stress. If the least principal 

stress is vertical or overburden then the hydraulic fractures propagate in the horizontal 

direction. If the least principal stress is horizontal, then fractures propagate in vertical direction 

(perpendicular to minimum of all horizontal stresses). This is illustrated in Figure 5.1, which 

shows the application of principal stresses to a cone of earthen material, the directions of least 

principal stress and the favored fracture development direction for the two previously discussed 

scenarios.
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

107

Figure 5.1 A fracture propagates perpendicular to the minimum principal stress.

An additional concern for hydraulic fracturing practices is unconfined fracture propagation. 

Figure 5.2 illustrates an example of the possible results from fracturing a coal under a verticallydominated stress field. This example holds true for conventional oil/gas hydraulic fracturing as 

well. In this case, if fractures are initiated and enlarged, they would tend to elongate in the 

horizontal direction; that is, stay within the producing coal seam. This may augment both 

natural gas and water production from the well. Although gas production may increase, water 

production rates may increase also, and the water to gas ratios may change as a result of the 

fracturing. 

Figure 5.2 Hydro-fracturing a CBNG well. Possible results under conditions of a verticaldominated stress field; horizontal fractures can be formed. 

In situ 

stresses Fracture

Claystone

Claystone

Water-saturated 

Sandstone

Water-saturated Sandstone

Coal

Vertical stress dominates; fractures 

elongate in the horizontal direction. Gas 

and water production increases.
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

108

If the horizontal stresses predominate in an area, fracture treatment of the coal may result in 

fractures elongated in a vertical direction (Figure 5.3) moving toward the overlying watersaturated sandstone reservoirs. Depending upon the relative fracture gradients of the coal and 

the sandstone, the vertical fractures may extend up to the contact with the sandstone or may 

actually enter the sandstone bed. In either case, the borehole may be opened to the adjacent 

sandstones that contain only water. If these fractures are created, water production may be 

increased while not increasing natural gas production rates. Natural fractures might exist 

locally in the coals but can be difficult to detect. These fractures might be oriented in the same 

directions as the local cleat or may be at different orientations. These natural fractures may be 

vertical and might already connect some coal seams to adjacent sands; therefore, this may be a 

factor as to why some coals produce more water than others. If natural fractures exist in a 

CBNG development zone, they may be augmented by hydro-fracturing treatments. 

Real time fracture height measurement can help in mapping fractures. Hydraulic fracturing 

models can be calibrated with real-time data to optimize treatment designs and to prevent 

undesired propagation of vertical fractures that could increase water production. Several 

diagnostic technologies are commercially available to map hydraulic fracture growth. Surface 

tilt meters can be used to measure fracture orientation, but there can be surface access issues. 

Figure 5.3 Hydro-fracturing a CBNG well. Possible results under conditions of a horizontaldominated stress field; vertical fractures can be formed. 

Horizontal stress dominates; fractures elongate 

in the vertical direction and enter the adjacent 

sandstone. Water production is increased

Claystone

Water-saturated 

Sandstone

Coal

Water-saturated Sandstone

In situ 

stresses
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

109

Various downhole tilt meter instruments are run into the well bore prior to beginning the 

treatment (Stutz and Fisher, 2004). The tools are coupled to the well bore with magnetic 

decentralizers. Pumping begins, and induced tilt is measured at each tool allowing fracture 

height to be measured in real time. Fracture geometry is directly measured as a function of 

actual treatment parameters. The result is a calibrated fracture model that enables optimized 

fracturing treatment design. The accurate treatment designing helps to avoid uncontrollable 

fracture propagation, which can cause higher water production volumes. 

Hydraulic Fracturing – Case Study 

Anadarko's CBNG production at Copper Ridge field in the PRB of Wyoming is a good example of 

real time fracture mapping used to optimize the fracture treatment design while avoiding 

excessive water production. The coals are present in 2-foot to 12-foot stringers spread over 

100–foot to 300-foot gross intervals at depths ranging from 2,600 to 3,000 feet. The most 

prolific seams are perforated and fracture stimulated using cross-linked gel with a combination 

of 16/30 and 20/40 sands as proppant. The Ericsson sand zone, used for water disposal, 

underlies the coal sections while higher permeability water sands overlay the sections. 

Fracture mapping occurred on six wells, and fracture engineering and modeling were 

performed. Where fractures were mapped, growth was measured in real time. The measured 

fracture growth was then incorporated into the software program, FracproPT, along with 

pressures, volumes, and injection rates. This allowed on-site adjustments to prevent fracturing 

into the adjacent water sands. The fracturing model was quickly optimized and used on all 

subsequent wells. 

The objectives that led Anadarko to obtain real time data and use them to model the fracture 

treatment were to: 

Stay out of overlying and underlying water zones;

Minimize the number of stages while still achieving complete interval stimulation; 

Create long fractures with adequate conductivity. 

Tilt meter data were obtained in real time while the proppant was being pumped. Previously, 

data had been gathered only during proppant-free stages, such as with mini-fracturing, acid 

fracturing, and water-only fracturing. Safe operating bounds for pumping rate, viscosity, sand 

concentration, and job duration, within which the tools and wire-line can be safely operated, 

were determined during pilot treatment. 

This treatment showed some tendency for upward fracture growth toward the overlying water 

sands. The proppant ramp was adjusted, accordingly, to be more aggressive early in the 

treatment. This ensured adequate conductivity if the treatment needed to be halted early due 

to the fracture top getting too close to the water sands. The propped treatment was pumped 

to completion while monitoring fracture height in real time. Treatment avoided growth into the 

overlying water sand. 

Fracturing treatments were optimized to avoid propagation into permeable water sands. 

Savings from reduced water production were $1.3 million in the first year. Research into such 

carefully monitored fracture jobs should include costs for the treatments as well as water 

management costs over time. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

110

Propellant Fracturing: 

Propellant fracturing (ARI, 1994) is a controlled pulse fracturing, tailored pulse loading, or high 

energy gas fracturing that involves the use of a wire-line run, electrically ignited propellant 

(similar to solid rocket fuel) placed across the formation to create a high pressure pulse. This 

pulse of gas creates multiple short (5 foot to 20 foot) radial fractures in the formation that 

connect to the well bore and are confined close to the zone stimulated. In addition, propellant 

fracturing avoids the resulting well bore damage often associated with explosive fracturing. 

In addition to minimizing near-well bore damage, propellant fracturing also controls vertical 

fracture growth. Fracture cracks are restricted to about one-half the horizontal length of the 

fracture. This is because the fracture growth is gas-dynamic, and there is not time nor energy 

available for the unrestricted height growth that can occur with a large hydraulic fracture. 

Therefore, knowing the distance to the reservoir cap, a propellant treatment can be designed to 

virtually guarantee that breakthrough will not occur. With recent concerns over the possibility 

that hydraulic fracturing could contaminate aquifers, this technique could be used to ensure 

that the fracture does not communicate with the overlying aquifers. 

By restricting or avoiding fracture propagation into the over- or under-lying water bearing 

formations, this technique can control excessive water production. 

One of the disadvantages of propellant technology is that the created fractures are left 

unpropped, and hence are susceptible to closure and plugging. It can be applied as an 

effective near-well bore damage removal technique. 

Miscellaneous:

Utilization of coil tube fracturing, multi-zone completions (DOE-NETL, 2003), hydraulic 

fracturing with high performance slurry, etc. improves gas recovery by means of improved 

accuracy in fracturing, reducing near-well-bore damage, improved connectivity, and other 

factors that contribute to enhance fracturing results in terms of gas production. However, on 

the basis of this literature search it is not clear that these techniques can reduce excessive 

water production during operations. 

Section 5.3 Horizontal Drilling 

The advantages of horizontal drilling typically are noted as higher recovery at accelerated rates 

and more uniform reservoir drainage. 

The Dallas-based company, CDX, has developed and demonstrated a Z-pinnate horizontal 

drilling and completion system as illustrated in Figure 5.4. Using horizontal laterals, CDX can 

access up to 1,200 acres from a single well site, significantly reducing surface impacts. (Vertical 

CBNG wells are often drilled on 80-, 40- or even 20-acre spacing.) CDX’s pinnate drilling pattern 

accelerates gas recovery allowing as much as 85% of the gas in place to be produced within 36 

months. 

The first step of pinnate drilling involves drilling a vertical well to the target producing zone. If 

producing zones are stacked, it is possible to extend the vertical well downward to pierce 

multiple zones. A cavity is reamed in the vertical well at each zone to create an accumulation 

chamber, or sump, for water collection. Next, a directional well is drilled nearby and steered to 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

111

intersect the cavity horizontally, then continuing to pierce the producing zone laterally. Laterals 

totaling as much as 25,000 feet are drilled off the main lateral to procure a roughly square 

drainage pattern. Subsequently, as many as three additional pinnates can be drilled from a 

single surface location in a “quad-pinnate” pattern. This provides 360° of drainage, optimizing 

production. Comparing a 500 MMcf horizontal pinnate well with a 500 MMcf fracture stimulated 

well, the pinnate well produces at a high initial rate and depletes in approximately 6 years; 

whereas, the conventional well will deplete at a lower rate in approximately 15 years. A onemile radius drainage pattern from each well can cover up to 1,200 acres from a single drilling 

location. In CBNG fields, maximal reservoir contact, as would be realized in a horizontal well, 

speeds up the depressurizing process meaning that first production is achieved more quickly 

and at greater rates. 

Figure 5.4 A schematic of Z-pinnate drilling 

Source: CDX technology 

The pinnate drilling program is not without problems. Its applicability to each field and the 

economics of drilling such an expensive well need to be evaluated against the cost of 

conventional completions. 

The typical well bore construction for a horizontal well involves going from vertical to horizontal 

mode in two phases. The first portion of the curve is achieved above the uppermost portion of 

the producing zone. Typically, the well is drilled out vertically below surface casing to a kickoff 

point, depending on the proximity of the uppermost zone. Then directional tools are conveyed 

into the well bore, and a curve is built with a 6°/100-foot to 8°/100-foot build rate so as not to 

create too severe a dogleg. A dogleg is a particularly crooked place in a well bore where the 

trajectory of the well bore in three-dimensional space changes rapidly. Minimizing the dogleg is 

important because artificial lift equipment may need to be run through this section. When the 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

112

well bore reaches a tangent angle between 60° and 75°, that tangent is held constant and 

laterally drilled through the entire producing zone, extending approximately 150 feet beneath 

the deepest zone to be completed. This drilling geometry for a CBNG project is illustrated in 

Figure 5.5. 

Figure 5.5 Multi horizontal wells penetrate through multiple coal seams

Improved ultimate gas recovery, higher gas production rates, greater effective drainage, and 

less surface disturbance are the major advantages of horizontal drilling. The chief limitation to 

using horizontal laterals in any field is to find suitable formations that will have sufficient 

drillability and borehole stability. Additional research is required to understand and evaluate the 

effects on water production and WGRs from horizontal wells. Success of horizontal drilling in 

eastern and central hard coal basins has been reported. Fracturing may not be needed with 

horizontal wells, even at later stages of production. This factor alone could reduce the chances 

for uncontrolled vertical fracture propagation and, hence, reduce the chances for unnecessary, 

higher water production. 

Weatherford International offers an underbalanced drilling (UBD) technique for creation of 

horizontal wells. UBD provides a non-damaging alternative for horizontal drilling within 

producing zones. UBD requires that the circulating bottom-hole pressure remain below 

reservoir pore pressure while, at the same time, the hole be cleaned as it is drilled. For soft 

formations it is possible to drill, even horizontally, at a rate higher than the cuttings can be 

cleaned from the well bore (Saikat and Heinz, 2004). This requires controlled drilling to keep 

the hole clean, and also to monitor and maintain the circulating pressure environment to 

continue to drill in an underbalanced fashion. 

Well bore stability remains the greatest barrier to horizontal drilling in many fields. For 

example, the Tertiary-age Fort Union Formation low-rank coals of the PRB are notoriously low in 

strength and have a tendency to slough into the borehole even in vertical wells. Only limited 

horizontal drilling has been attempted in the PRB, but those attempts have been failures 

because of sloughing. Horizontal boreholes in weak producing zones may not be able to stay 

open without a liner and may not even be drillable. This question is very important when 

considering horizontal drilling and completions. If the producing zone cannot be successfully 

drilled, then this water reduction technique is not applicable. Horizontal drilling innovations 

could eventually increase the drillability of soft formations. Currently, two innovative products 

Coal seam

Coal seam
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

113

may supply much needed information – designer mud systems forming a “stress-cage” within 

the borehole and borehole stability modeling. 

Stress-cage designer muds have been demonstrated on low-strength materials (Aston, 2004).

The mud is designed to be an ultra low fluid loss system that builds and maintains a bridge 

across the fractures in the borehole allowing the hole to stay open until a screen or liner can be 

installed. The stress-cage muds would then be dispersed prior to production. Economics of this 

horizontal technique are unknown at present time. 

STABView (McLelland and Hawkes, 2002) is a commercial well bore modeling program designed 

to use wire-line and core information to model borehole stability in low-strength rocks. The 

model uses log derived data, core analyses, and borehole stress measurements to predict 

borehole deformation and collapse. Work on Canadian coals suggests that results are depth 

sensitive and that mapping borehole deformation in vertical holes can predict stability in 

deflected holes and horizontal laterals. Borehole stability models could have application in 

selecting potential candidates in weak producing zones and predicting favorable depth ranges 

for horizontal drilling. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

114

THIS PAGE INTENTIONALLY LEFT BLANK
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

115

SECTION 6.0 ANALYSIS OF SELECT OIL & GAS BASINS 

In early years of oil and gas production, oily water was pumped into shallow ponds so that 

crude oil could be skimmed off and sold. The brine water in the ponds often seeped into the 

subsoil, causing salt scars that proved difficult to remediate. Around this same time, the oil and 

gas industry discovered a beneficial use for high-salinity produced water – secondary oil 

recovery via subsurface water floods. Individual states began to pass laws prohibiting pollution 

in general and the release of deleterious materials to air, water, and soil. Oil and gas producing 

states set up rules and regulatory agencies to control the production of crude oil, natural gas, 

and salt water by the petroleum industry. The regulatory process is designed to safeguard the 

physical environment, prevent the waste of the hydrocarbon resource, and protect correlative 

property rights on the land surface and in the subsurface. 

Oil and gas environmental regulation became a federal issue with the passage of the Safe 

Drinking Water Act in 1974 that included nationwide underground injection regulations. The 

federal regulations established a number of classes of injection wells with construction and 

operating requirements relevant to the various classes of wells. Most oil and gas injection and 

disposal wells fall under the Class II regulations. 

The produced water data presented in this report was assessed relative to Total Dissolved 

Solids (a representation of the produced waters salinity) to illustrate the range and distribution 

of the produced water salinities for each of the basins. Produced water quality data is also 

presented in two ways – numerically and geographically. The water classifications presented in 

the bar graphs for the individual basins use ranges based on classifications of groundwater 

quality and salinity expressed as TDS and were modified to reflect the relative management 

options for the waters. The ranges are 0 mg/L to 9,999 mg/L TDS (fresh to brackish waters in 

USGS classification), 10,000 mg/L to 49,999 mg/L TDS (low to moderate saline waters), 50,000 

mg/L to 99,999 mg/L TDS (moderate to high saline waters), 100,000 mg/L to 199,999 mg/L 

TDS (low to moderate brine waters), and 200,000 mg/L to 460,000 mg/L TDS (brine waters). 

Basic statistics are listed in the bar graphs to show the distribution of produced water quality 

samples collected within the individual basins for each of the classification groups listed above. 

While these statistics are calculated from the various reservoirs sampled within the basins, it is 

assumed for this report that these statistics approximate the distribution of salinities within the 

basin and within the total water volume produced each year, unless otherwise noted. Median 

TDS (salinity) as well as the lowest and highest TDS samples are presented for each chart to 

provide additional information of the variability of water salinity for each basin. The data is also 

plotted on maps to provide spatial analysis of the produced water quality distribution within the 

basins.

Section 6.1 Alaska North Slope and Cook Inlet 

North Slope 

The Alaska North Slope, which covers approximately 88,000 square miles, is the region of 

Alaska located on the northern slope of the Brooks Range foothills to the coast of the Arctic 

Ocean. The region contains the major petroleum reserves of Alaska, including Prudhoe Bay, 

which is North America's largest oil and gas field. The region also contains the Arctic National 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

116

Wildlife Refuge. Prudhoe Bay is a coastal feature of the Beaufort Sea approximately 250 miles 

north of the Arctic Circle and 1,300 miles south of the North Pole (Alyeska Pipeline, 2006). 

Prudhoe Bay includes 3,898 exploratory wells, 170 drilling pads, 500 miles of road, 1,100 miles 

of pipeline, 5 docks, and 25 production, processing, sea-water treatment, and power plants. 

The state of Alaska receives about 85% of its revenues from oil and gas activity. Most of these 

revenues come from the 1.5 million bpd production of the Prudhoe Bay field on the North Slope. 

Figure 6-1 depicts the location of the Alaska North Slope (red line) and defines the National 

Petroleum Reserve in Alaska (black line) and the Arctic National Wildlife Reserve (ANWR) as the 

green line; the water quality data presented on Figure 6.1 is from the Prudhoe Bay field which 

is located east of the National Petroleum Reserve and west of ANWR. 

Figure 6.1 Geologic Setting and Produced Water Quality Distribution of the Alaska North 

Slope

 (Source: USGS, 2005) 

Cook Inlet 

The Cook Inlet basin is about 380 km long and about 80 km wide and is bordered to the west 

and north by the Alaska and Aleutian Ranges and to the northeast and east by the Talkeetna, 

Chugach, and Kenai Mountains. Cook Inlet and its extensions, Turnagain Arm and Knik Arm, 

form a major marine re-entrant of the south-central Alaska coastline and subdivide the Cook 

Inlet Lowland into several natural subunits (Alaska Department of Natural Resources, 2003). 

These include the Kenai Lowland, which fronts the Kenai Mountains to the east; the Kustatan 

Lowland, a narrow coastal shelf fronting the Aleutian and Alaskan Ranges to the west; the 

Brooks Range
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

117

Susitna Lowland, a broad lowland between the Alaska Range and the Talkeetna Mountains that 

is drained by the Susitna River, which in turn flows into Cook Inlet from the north; and the 

lower Matanuska Lowland, drained by Knik Arm, which lies between the Talkeetna and Chugach 

Mountains to the northeast (Alaska Department of Natural Resources, 2003). 

The origins of the Alaska oil and gas industry began in Cook Inlet with the discovery of Alaska's 

first commercially viable oil find in the Swanson River field in 1957. After the Swanson River 

finding, additional wells were developed in Cook Inlet and more leases were approved 

throughout the basin. By 1959, 187,000 barrels of crude oil were produced annually in Cook 

Inlet (Alaska Department of Natural Resources, 2004). The Cook Inlet or Kenai Peninsula 

watershed is located in south-central Alaska and is approximately 47,000 square miles in size, 

lying generally below an elevation of 1,000 feet (Alaska Department of Natural Resources, 

2003). Figure 6.2 defines the boundary and geologic setting of the Cook Inlet Basin.

Figure 6.2 Geologic Setting and Produced Water Quality Distribution of the Alaska Cook Inlet 

Basin/ Kenai Peninsula 

(Source: USGS, 2005) 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

118

SIGNIFICANT GEOLOGIC FEATURES

North Slope 

The North Slope of Alaska is a major hydrocarbon-producing region of North America, but its 

geologic setting is still not completely understood (Alyeska Pipeline, 2006). This is in part due 

to the tectonic history of northern Alaska, where there is a complex interplay between the 

formation of the Brooks Range collisional orogen and the development of the nearby north 

Alaska rifted continental margin (Wallace and Hanks, 2005). 

In general, the North Slope consists of the Carboniferous Lisburne Group, a thick, 

heterogeneous and highly fractured sequence of carbonate rocks that acts as the reservoir 

horizon for some oilfields located in the North Slope (Wallace and Hanks, 2005). The Lisburne 

Group also is widely exposed throughout northern Alaska as an important element of the Brooks 

Range fold-and-thrust belt. The Lisburne Group was recognized as a potential reservoir horizon 

very early during petroleum exploration of northern Alaska and was considered by many to be 

the primary exploration target during the early phases of drilling on the North Slope (Wallace 

and Hanks, 2005). As in many carbonate reservoirs, naturally occurring fractures in the 

Lisburne Group play a major role in hydrocarbon production by providing both porosity and 

permeability. However, the distribution, density, and character of fractures within the Lisburne 

are highly variable and difficult to predict, and may depend on the lithology of the host rock, 

the structural setting of the reservoir, and/or other unidentified factors (Wallace and Hanks, 

2005).

Cook Inlet 

The present topography of Cook Inlet and adjoining areas is primarily the product of at least 

five major Pleistocene glaciations and two minor post-Pleistocene glacial advances (Karlstrom, 

1964). These are recorded by the distribution of moraines and ice scoured landforms, by 

discordant drainage relations, and by stratigraphic evidence of multiple drift sheets separated 

by major unconformities and weathering profiles (Karlstrom, 1964). The Cook Inlet basin 

occupies a structural trough, is underlain at variable depths by rocks of Middle Jurassic through 

early Cretaceous sediments (2,700 m), 4,300 m of Early and Late Cretaceous flysch, and up to 

6,500 m of Tertiary fluvial sediment (Alaska Department of Natural Resources, 2004). 

Semi-consolidated coal-bearing formations of Tertiary age crop out at the surface or occur at 

relatively shallow depth at the southwest end of the Kenai Lowland and along the flank of the 

Alaska Range between Tyonek and Peters Creek (Alaska Department of Natural Resources, 

2003).

OIL AND GAS PRODUCTION

North Slope 

Petroleum reserves in Prudhoe Bay were discovered in 1968 with initial recoverable reserves 

estimated at 9.6 billion barrels of oil and 26 trillion cubic feet of gas (Alaska Department of 

Natural Resources, 2004). Production was initially restricted to small quantities used to fuel 

field operations until the Trans Alaska Pipeline System (TAPS) was completed in July 1977. 

Until this, operators injected surplus crude and residual oil back into the Prudhoe Bay reservoir. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

119

North Slope gas production began near Barrow in the mid-1940s. Gross gas production on the 

North Slope in 2000 was 3.2 trillion cubic feet (8.7 billion cubic feet (BCF)) per day, but 93% of 

this volume was injected into oil producing reservoirs (Alaska Department of Natural Resources, 

2004). The remaining net gas production, equal to 297 BCF in 2003, is consumed locally on the 

North Slope to fuel oilfield equipment, operations, and pipelines. North Slope industrial yearly 

gas consumption is approximately equal to annual gas produced in Cook Inlet (Alaska 

Department of Natural Resources, 2004). 

From the beginning of Prudhoe Bay production, dissolved gas and water were separated from 

the crude oil and injected back into the reservoir. Over time the proportion of both produced 

gas and water to oil increased. Eventually, oil production was constrained by the rate at which 

the separating plants could process gas and water. The North Slope has produced 14.4 billion 

barrels of oil and natural gas liquids (NGLs) by the end of 2003; nearly all from the large 

Prudhoe Bay and Kuparuk fields (Alaska Department of Natural Resources, 2004). NGLs 

produced on the North Slope are blended with oil and shipped down TAPS or used to make 

miscible injectant for enhanced oil recovery projects. Today, incremental oil production from 

new fields brought on-line since 1995 account for about 27% of total yearly Alaska North Slope 

production. Oil production in the bay has slowed considerably and at the present time an 

average of 680,000 barrels per day is produced (Alaska Department of Natural Resources, 

2004).

Cook Inlet 

The Cook Inlet watershed contains more than 225 miles of active oil pipelines and more than 

690 miles of active natural gas pipelines, approximately 100 miles of active oil and natural gas 

gathering lines in several onshore production fields, and numerous miles of active natural gas 

distribution pipelines, particularly in the Anchorage area. First commercial production from an 

Alaska oilfield began at Swanson River, Cook Inlet in 1959. Five other Cook Inlet fields began 

production between 1965 and 1972. Most recently, West McArthur River began production in 

1993 and Redoubt in 2002. All Cook Inlet oil is currently shipped to the Tesoro refinery at 

Nikiski on the Kenai Peninsula. Oil from fields on the west side of Cook Inlet is transported by 

pipeline to the Drift River terminal, and then transported to Nikiski (Alaska Department of 

Natural Resources, 2004). Oil from the eastside fields is shipped by pipeline directly to the 

refinery. By year-end 2003, the Cook Inlet had produced almost 1.3 billion barrels of oil, 

including 10 million barrels of NGLs (Alaska Department of Natural Resources, 2004). 

Cook Inlet gas production began in 1959 as a by-product of Swanson River oil development. As 

more oil and gas fields were discovered, nearby markets for the gas were developed in 

Anchorage and Kenai to supply space heat and electricity generation. In 1968 Unocal started 

up the ammonia-urea plant at Nikiski to take advantage of the abundance of cheap stranded 

natural gas (Alaska Department of Natural Resources, 2004). In recent years, NGL exports to 

Japan accounted for about 33% of total Cook Inlet gas production. Industrial use of Cook Inlet 

gas has remained fairly constant since 1983; production has increased in step with the growing 

residential and commercial demand for space heating and electric power generation (Alaska 

Department of Natural Resources, 2004). By 1984, net annual natural gas production reached 

305 BCF per year and peaked at 311.5 BCF in 1990. Cook Inlet natural gas production has 

remained relatively stable at an average of 217 BCF per year from 1998 to 2005. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

120

PRODUCED WATER MANAGEMENT 

North Slope 

The numerical distribution of produced water quality for the Alaskan North Slope area is shown 

in Figure 6.3. The USGS produced water database contains 22 individual samples of produced 

water quality for the Alaskan North Slope; the Alaska Oil and Gas Conservation Commission also 

had two individual water quality samples from the area. Produced water salinity in the Alaskan 

North Slope included only two produced water quality ranges identified for analysis in this 

study; from 0 mg/L to 9,999 mg/L and 10,000 mg/L to 49,999 mg/L TDS. Median produced 

water salinity for the Alaskan North Slope was 28,230 mg/L TDS (saline). The range of salinity 

values for the Alaskan North Slope ranged from 786 mg/L to 45,640 mg/L with a median of 

28,320 mg/L (Figure 6-3). From the small sample set (24 total samples), the majority of 

samples (92%) indicate TDS results that fall within the 10,000 mg/L to 49,999 mg/L group; the 

remaining 8% of the samples fall in the group 0 to 9,999 mg/L. Additionally, no collected 

samples indicate results greater than 49,999 mg/L. 

Figure 6.3 Produced Water Quality from the Alaska North Slope 

0% 0%

92%

0%

8%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

<9,999

(fresh/brackish)

10,000-49,999

(low/moderate saline)

50,000-99,999

(moderate/high

saline)

100,000-199,999

(low/moderate brine)

200,000-460,000

(brine)

TDS Range in mg/L (produced water description)

Percent of Total Population

(24 Samples)

Median 

28,320 mg/L

Low

786 mg/L

High 

45,640 mg/L

Figure 6.1 documents the spatial distribution of the water quality samples from the USGS 

produced water database across the Alaskan North Slope showing that the produced water 

samples were all located in a single area, Prudhoe Bay. While Figure 6.1 graphically delineates 

the location of the 22 samples as all falling in a single production area, assessment of produced 

water quality in other regions cannot assume all produced water quality for the Alaskan North 

Slope would be of the same quality. Produced water from the Alaskan North Slope area is 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

121

either injected into the producing reservoirs for pressure maintenance and secondary recovery 

or into Cretaceous formations for injection disposal (ConocoPhillips, 2006). Secondary recovery 

and pressure maintenance is also being supplemented by make-up water collected by pumping 

sea water into the reservoir (Alyeska Pipeline, 2006). 

Cook Inlet 

The numerical distribution of produced water quality for the Cook Inlet Basin is depicted in 

Figure 6.4. The USGS produced water database contains 37 individual samples of produced 

water quality for the Cook Inlet Basin; the Alaska Oil and Gas Conservation Commission also 

had 38 individual water quality samples from the area. Produced water salinity in the Cook 

Inlet Basin included three produced water quality ranges identified for analysis in this study; 

from 0 mg/L to 9,999 mg/L, 10,000 mg/L to 49,999 mg/L, and 50,000 mg/L to 99,999 mg/L 

TDS. Median produced water salinity for the Alaskan North Slope was 9,605 mg/L TDS 

(brackish). The range of salinity values for the Cook Inlet Basin ranged from 178 mg/L to 

75,717 mg/L (Figure 6.4). Nearly all of the produced water quality samples from the Cook Inlet 

Basin (99%) have TDS concentrations below 50,000 mg/L (Figure 6.4). Fifty-one percent and 

48% of the produced water from this basin fall within TDS results of 0 to 9,999 mg/L or 10,000 

to 49,999 mg/L, respectively. Additionally, 1% of the produced water is described within the 

50,000 to 99,999 mg/L TDS group. 

Figure 6.4 Produced Water Quality from the Alaska Kenai Peninsula/Cook Inlet

1% 0%

51%

0%

48%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

<9,999

(fresh/brackish)

10,000-49,999

(low/moderate saline)

50,000-99,999

(moderate/high

saline)

100,000-199,999

(low/moderate brine)

200,000-460,000

(brine)

TDS Range in mg/L (produced water description)

Percent of Total Population

(75 Samples)

Median 

9,605 mg/L

Low

178 mg/L

High 

75,717 mg/L

Figure 6.2 documents the spatial distribution of the water quality samples from the USGS 

produced water database across the Cook Inlet Basin showing that the produced water samples 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

122

were concentrated in only a few areas. While Figure 6.2 graphically delineates the location of 

the 37 samples as all falling in a few production areas, assessment of produced water quality in 

other regions of this basin cannot assume all produced water quality for the Cook Inlet Basin 

would be of the same quality. In general, produced water from onshore oil and gas facilities in 

Cook Inlet Basin is disposed of via Class II disposal wells or is used for enhanced recovery. 

Since 1968, the produced water volume in the Swanson River Field has consistently fluctuated 

near 0.2 bbls/day, with a spike in volume between 1972 and 1973. 

Section 6.2 Anadarko Basin 

The Anadarko Basin covers a large portion of the Southern Great Plains; the majority of the 

basin is located in western Oklahoma and the basin extends into the northeastern Texas 

panhandle, southeastern Colorado, and southwestern Kansas (Henry and Hester, 1995). Figure 

6.5 shows the approximate extents of the basin, lying in a northwest to southeast orientation, 

with the Wichita Mountains to the south; the axis and deepest portion of the basin lying just 

north of the mountains. The basin is further bounded by the Palo Duro Basin to the southwest, 

Las Animas Arch to the northwest, the Central Kansas Uplift to the northeast, and Nemaha 

Ridge to the southeast. The Anadarko Basin covers an area of approximately 50,000 square 

miles (Henry and Hester, 1995). 

Figure 6.5 Geologic Setting and Produced Water Quality Distribution of the Anadarko Basin 

(Source: USGS, 2005) 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

123

Significant Geological Features 

The Anadarko Basin contains strata of Cambrian through Permian age with a thin veneer of 

Tertiary continental sediments. Most of the basin-fill volume is taken up with the Ordovician 

through Permian sediments that accumulated in the ancient seaway. The sources of the older 

sediments were the Paleozoic outcroppings to the north and the ancestral Rocky Mountains to 

the west. The important strata in the basin include the Lower Ordovician Arbuckle Formation, 

which is the same age and similar in lithology to the massive Knox carbonates of the 

Appalachians and the Ellenberger of Texas. The Upper Ordovician through Mississippian section 

is present as thickened versions of thinner strata that blanketed most of the Mid-Continent. 

During the Pennsylvanian and Permian eras the Wichita Mountains to the south began to 

emerge from the seaway as the Anadarko basin began to vanish. 

The result of this long history of sedimentation is the thick sedimentary column over 40,000 

feet thick in some places that holds a variety of hydrocarbon-bearing reservoirs. In addition, 

the sedimentary column holds several zones that make thick, permeable injection zones that 

are able to serve as disposal reservoirs. Formations such as the Permian Red Cave and 

Ordovician Arbuckle can receive water at rates of thousands of barrels per day on a long-term 

basis.

Oil and Gas Production 

Oil and gas has been produced from the basin’s shallow, prolific oil pools and deep, highpressured gas reservoirs. First production from the basin was in the 1890’s with more than 2.3 

billion barrels of oil (BBO) and more than 65.5 trillion cubic feet of gas (TCFG) having been 

produced to date. Since the conception of oil and gas activity in the Anadarko Basin, wells have 

produced low quality water, commonly referred to as brine. 

Earliest petroleum production was from shallow reservoirs that had prominent surface 

expression such as the Oklahoma City Field and Cement Field. As the technology progressed, 

deeper reservoirs could be exploited so that by the 1960’s, exploratory wells were being drilled 

below 30,000 feet in the Anadarko Basin. Currently, production in the basin is on the decline 

although the number of feet of exploratory holes drilled each year remains high. Among the 

plays generating interest are deep reservoirs near the center of the basin, stratigraphic traps 

throughout the basin, existing continuous reservoirs in the Permian Hugoton Gas Field, and new 

unconventional, continuous reservoir accumulations in the Woodford-Chattanooga sequence. 

These plays have implications for produced water management in the Anadarko Basin. 

Produced Water Management

Oil and gas operators in the Anadarko Basin have utilized several options for the management 

of produced water. Typically oil and gas production in the Anadarko Basin has utilized injection 

as the primary management practice for produced water. The presence of permeable disposal 

zones at readily drillable depths has helped the oil and gas industry in the Anadarko Basin to 

manage produced salt water volumes. Early in the production life of a field, operators are 

typically disposing of produced water in an injection zone not connected to the producing 

reservoir. As oil and gas fields in the basin age, production declines and operators have the 

option of initiating a water flood with their produced water.
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

124

Produced water quality data for this basin is presented in two ways – numerically and 

geographically. The numerical distribution of produced water quality is shown in Figure 6.6. 

The USGS produced water database contains 2,312 individual samples of produced water 

quality for the Anadarko Basin. Produced water salinity in the Anadarko Basin includes all of 

the ranges identified for analysis in this study, from <10,000 mg/L to >200,000 mg/L TDS. 

Median salinity expressed as TDS is relatively high at 132,158 mg/L (low to moderate brine 

waters). The range of salinity values for the Anadarko Basin ranged from 1,012 mg/L (slightly 

brackish) to 365,960 mg/L (brine) (Figure 6.6). More than half (56%) of the produced water 

samples collected from the Anadarko Basin had TDS concentrations greater than 100,000 mg/L, 

which would be classified as brines. Approximately 4% of the samples in the USGS produced 

water database had salinity values less than 10,000 mg/L (brackish waters). Produced water 

varies across the basin from saturated (approximately 350,000 mg/L) brines to waters less than 

10,000 mg/L (Bein and Dutton, 1993). While most of this produced water is used in secondary 

oil recovery operations, some water is disposed of into scattered commercial disposal wells. 

Figure 6.6 Produced Water Quality from the Anadarko Basin 

4%

25%

15%

28% 28%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

<9,999

(fresh/brackish)

10,000-49,999

(low/moderate saline)

50,000-99,999

(moderate/high

saline)

100,000-199,999

(low/moderate brine)

200,000-460,000

(brine)

TDS Range in mg/L (produced water description)

Percent of Total Population

(2,312 Samples)

Median 

132,158 mg/L

Low

1,012 mg/L

High

365,960 mg/L

(Source: USGS, 2002)

Figure 6.5 documents the geographical distribution of water quality samples across the basin 

showing that produced water quality varies randomly. This map indicates that the small 

amount of high quality produced water with TDS less than 10,000 mg/L is widely scattered from 

the deep basin to the Anadarko Shelf on the north side of the basin. Figure 6.5 shows that 4% 

of the water quality samples from the reservoirs held brackish quality water less than 10,000 

mg/L TDS. Some of this high quality water is shallow, the result of fresh water that has 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

125

entered oil reservoirs from the surface; this water could have a beneficial use if the oil and 

grease content was appropriate or could be removed prior to beneficial use. Water less than 

10,000 mg/L would appear to be of minor importance in the Anadarko Basin because of the 

relatively small percentage (4%) it represents of the produced water from the basin. 

Figure 6.5 shows that 25% of the produced water in the Anadarko Basin falls in the water 

quality range from 10,000 to 49,999 mg/L TDS (low to moderate saline waters). Although for 

most surface beneficial uses this water is of insufficient quality, there are some options for the 

treatment of this water to enable it to be used. Figure 6.5 shows the distribution of the 

majority of the water produced (TDS >50,000 mg/L) in the basin is scattered across the basin. 

This produced water can be used for secondary recovery in water floods of local oil reservoirs. 

Many times the water is filtered and treated and pumped back into the reservoir it came from. 

Other water is transported to another water flood in the area that is in need of “make-up” water 

to begin or maintain a flood. Often at the initiation of a flood, insufficient water volume exists 

in the field and outside water will need to be supplied. Oil and gas operators ensure that the 

outside water is fully compatible with the water chemistry of the flooded reservoir and that the 

water is free of suspended sediment. Material either dissolved or suspended in the flood water 

injected into the reservoir can cause plugging either in the injection wells or within the reservoir 

itself, thereby reducing flow and production. 

There are areas where water floods are not utilized, commonly in gas-producing areas; 

produced waters that are not able to be used for surface uses are disposed of by injection into 

saltwater-bearing reservoirs. Injection disposal is discussed in more detail in Section 4. 

Many parts of the Anadarko Basin have only minor oil production and, therefore, the need for 

secondary recovery water flood injection is not great. One of these areas is the giant Hugoton 

gas field in parts of Kansas, Oklahoma, and Texas. This shallow, continuous gas field was 

initially developed in the 1940’s and has been in operation since then. As the wells increase in 

age, they could begin to produce more water. In the Hugoton, the primary option for produced 

water management is to use dedicated disposal wells, either owned by the oil and gas operator 

or commercial wells. The expense of managing the increasing volumes of produced water from 

these wells can be enough to cause early abandonment of the producing well. Some operators 

have installed disposal wells but with the wide spacing of wells in the field, the disposal wells 

may be long distances from the producing wells, requiring additional transportation costs. 

A produced water reduction alternative is to use Downhole Gas/Water Separators (DGWS) and 

the injection of the produced water into a separate water-bearing zone perforated within a 

producing gas well. Produced water from nearby wells can also be accommodated in these 

wells if the receiving zone is capable of accepting the additional volume of water. Several gas 

wells have been equipped with DGWS in the Oklahoma and Kansas portions of the Hugoton. 

One of the benefits of DGWS technology is its hygiene; if water does not get to the surface for 

storage and filtering, it is less likely to pick up impurities, including sulfate-reducing bacteria. In 

parts of the Kansas portion of the Hugoton, H2S is being produced where none had been 

produced historically. This apparently has been caused by operators introducing surface waters 

into the reservoir formations where they have proliferated to liberate enough H2S gas to reduce 

the natural gas value and make it potentially harmful to livestock and humans. DGWS 

completions may have applicability in other gas fields as a way of efficiently managing produced 

water. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

126

Similar completions have been used in water floods to rapidly achieve fill-up of the reservoir. 

“Dump-flood” wells can produce saltwater from a prolific, non-hydrocarbon bearing zone and 

pump it directly into the flood zone without drawing the water to the surface. Such wells must 

be carefully engineered to convey clean water to the flooded reservoir and avoid suspended 

material that may plug the reservoir. Such wells in Oklahoma can move thousands of barrels of 

produced water every day at very low costs. 

Several “de-watering” projects are underway in Oklahoma and Kansas that utilize high rates of 

water production in a different setting. These projects produce large volumes of water from 

previously watered-out fields. Producing wells utilize large electric submersible pumps to 

produce high volumes of saltwater every day until oil begins to move to the wellbore. Produced 

water is disposed into injection wells utilizing thick, continuous injection zones such as the 

Arbuckle Formation. 

Section 6.3 Arkoma Basin 

The Arkoma Basin is a medium-sized interior basin located in southeastern Oklahoma and westcentral Arkansas (Perry, 1995). Figure 6.7 shows the approximate extents of the basin. The 

Arkoma Basin is bisected by the Oklahoma-Arkansas border and lies in slight southwest to 

northeast orientation (Figure 6-10). The basin is bounded by the Ozark uplift to the northeast, 

the Cherokee Basin to the northwest, and the Ouachita Foldbelt to the south as shown in Figure 

6.7. The Arkoma Basin covers an area of approximately 33,800 square miles (Perry, 1995). 

Significant Geological Features 

The Arkoma Basin is filled with Cambrian through Pennsylvanian sediments that have been 

folded, faulted, and heated to such an extent that the traps contain only dry gas. The basin 

contains nearly all of the early to middle Pennsylvanian section (Perry, 1995). The sedimentary 

rocks present in the basin range from 3,000 to 20,000 feet in thickness and are composed of 

pre-Mississippian carbonate shelf deposits, Mississippian marine shales and Pennsylvanian 

fluvial deposits (Perry, 1995). 

Heating that the area has undergone has driven out much of the pore water within the basin; 

only minor amounts of water are produced in conventional gas wells. Groundwater is present 

only in alluvium within the basin and any water wells will be sourced by this alluvium. 

Oil and Gas Production 

Natural gas has been produced in this basin since 1910 (Perry, 1995) and continues to the 

present. The geology of the basin indicates that little or no formation water is present in any of 

the oil and gas reservoirs. Gas is trapped in large structural reservoirs, in small- and mediumsized stratigraphic traps, and in coal bed natural gas accumulations. CBNG wells make only 

small amounts of formation water while conventional gas wells produce no formation water, but 

do produce small volumes of water that exist in the gas reservoir as water vapor entrained with 

the natural gas. When the natural gas is produced, the water vapor condenses at the surface. 

In high-flowing gas wells, the condensed vapor can represent a large volume. This water is 

typically very high quality and locally would have beneficial uses if the regulatory environment 

would allow its use. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

127

At the present time, the Mississippian Fayetteville shale is being developed as a source of 

unconventional shale gas similar to the Barnett play in the Fort Worth Basin. Drilling and 

production of gas from the Fayetteville could become as important as the Barnett play. The 

Mississippian Fayetteville is a thick, highly bituminous shale that can produce natural gas as a 

continuous reservoir. To date, approximately 82 wells have been completed, 53 are producing 

gas, and others are drilling or are awaiting completion. Of the 82 completed wells, 31 are 

horizontal wells; 13 of these have been completed and have an average production off 2.5 

mmcf per day. These wells are scattered over seven counties in Arkansas (Southwest Energy, 

2006). Like the Barnett wells, the Fayetteville wells are fracture treated before the wells 

produce sizable gas volumes. Fracturing has been done using high pressure nitrogen, although 

some wells have used water and sand. It is possible that in the future these shale-gas wells will 

be similar to Barnett wells in that they may receive large water-fracs that could cause the wells 

to produce large volumes of water with the natural gas. 

Figure 6.7 Geologic Setting and Produced Water Quality Distribution of the Arkoma Basin 

(Source: USGS, 2005) 

Produced Water Management 

The USGS produced water database lists 221 samples of produced water from the Arkoma 

Basin, and includes samples from a variety of formations and depths. Figure 6.8 documents the 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

128

quality of the produced water from the USGS produced water database for the Arkoma basin. 

The produced water from this basin appears to be relatively poor in quality with 1% of the 

samples having TDS concentrations greater than 200,000 mg/L (brine waters), 39% of the 

samples having TDS concentrations between 100,000 and 199,999 mg/L (low to moderate brine 

waters), and 18% of the samples having TDS concentrations between 50,000 and 99,999 mg/L 

(moderately saline to saline waters). The median produced water quality for the Arkoma Basin 

was saline water with a TDS of 88,115 mg/L. The salinity values for the basin range from a low 

of 1,201 mg/L (slightly brackish) to a high of 217,519 mg/L (moderate brine) (Figure 6.8). 

Approximately 23% of the samples in the USGS produced water database had a TDS less than 

10,000 mg/L (brackish waters); this is water of sufficient quality that it may have some 

beneficial uses. 

Figure 6.8 Produced Water Quality from the Arkoma Basin 

23%

19% 18%

39%

1%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

<9,999

(fresh/brackish)

10,000-49,999

(low/moderate saline)

50,000-99,999

(moderate/high

saline)

100,000-199,999

(low/moderate brine)

200,000-460,000

(brine)

TDS Range in mg/L (produced water description)

Percent of Total Population

(221 Samples)

Median 

88,115 mg/L

Low

1,201 mg/L

High 

217,519 mg/L

(Source: USGS, 2002) 

Figure 6.7 documents the distribution of USGS produced water quality samples across the 

Arkoma Basin showing the produced water quality distribution across the basin. The 

geographical distribution of water salinity as shown in Figure 6.7 indicates that the brackish 

quality produced water with TDS <10,000 mg/L (23% of the total) is scattered from the 

western edge of the basin to the center portion of the basin. Water volumes from conventional 

natural gas production are minor and scattered. Other brackish quality water is recovered from 

deep, high-flowing natural gas wells where the water comes to the surface as vapor entrained 

in the natural gas and condenses at the surface. Some of this water is produced in waterstarved areas such as southeastern Oklahoma and could have important beneficial uses if the 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

129

regulatory framework would allow (Baker, 2005). Most of the produced water is not a viable 

beneficial use source except for localized uses, unless Fayetteville shale-gas development 

becomes as prolific as the Barnett play and large volumes of water are produced from these 

wells. Oil and gas operators in the Arkoma Basin have utilized several options for the 

management of produced water. Typically oil and gas producers in the Arkoma Basin have 

utilized injection as the primary management practice for produced water. The presence of 

permeable disposal zones at readily drillable depths has helped the oil and gas industry in the 

Arkoma Basin to manage produced saltwater volumes. 

Section 6.4 Bighorn Basin 

The Bighorn Basin covers north-central Wyoming extending into south-central Montana (Fox 

and Dolton, 1995a). Figure 6.9 shows the approximate extents of the asymmetric heart-shaped 

Bighorn Basin which lies in a northwest to southeast orientation located between the Bighorn 

Range and the Rocky Mountain Range. Surrounding the basin are the Bighorn Mountains to the 

east, the Beartooth and Absaroka Mountains to the west, the Nye-Bowler Lineament to the 

north, and the Owl Creeks to the south. The Bighorn Basin covers an area of approximately 

13,200 square miles (Fox and Dolton, 1995a). 

Figure 6.9 Geologic Setting and Produced Water Quality Distribution of the Bighorn Basin

(Source: USGS, 2005) 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

130

Significant Geological Features 

The Bighorn Basin contains strata of Cambrian through Tertiary age. The sources of the 

sediment are the fault bounded Laramide uplifts that surround the basin (Fox and Dolton, 

1995a). The important strata for oil and gas development in the basin are the Permian and 

Cretaceous source rocks and reservoirs, which include the Pennsylvanian Tensleep Sandstone, 

Permian Phosphoria, and Upper Cretaceous Frontier sandstones. 

Oil and Gas Production 

Oil and gas has been produced from the basin margin anticlinal structures since their discovery 

in 1906 and 1907 (Fox and Dolton, 1995a). Oil and gas production in the Bighorn Basin has 

occurred from formations ranging in age from Cambrian to Late Cretaceous. 

Produced Water Management

Oil and gas operators in the Bighorn Basin have utilized both enhanced recovery and 

agricultural beneficial use for the management of produced water. Typically, oil and gas 

production in the Bighorn Basin has utilized injection for enhanced oil recovery as the primary 

management practice for produced water. 

The numerical distribution of produced water quality for the Bighorn Basin is shown in Figure 

6.10. The USGS produced water database contains 2,282 individual samples of produced water 

quality. Produced water salinity in the Bighorn Basin includes all of the ranges identified for 

analysis in this study, from <10,000 mg/L to >200,000 mg/L TDS. Median produced water 

salinity is relatively good at 4,891 mg/L (moderately brackish). The range of salinity values for 

the Bighorn Basin ranged from 1,017 mg/L (slightly brackish) to 220,200 mg/L (moderate brine) 

(Figure 6.10). Most of the produced water quality samples from the Bighorn Basin (79%) have 

TDS concentrations less than 10,000 mg/L, which would be classified as brackish waters with 

the potential for beneficial uses. The USGS produced water database also includes nearly 20% 

of the samples for the Bighorn Basin in the next highest water quality category from >10,000 

mg/L to <50,000 mg/L TDS. The three remaining produced water quality distributions 

discussed in this report contained less than 1.5% of total number of samples in the USGS 

produced water database (Figure 6.10). 

Figure 6.9 documents the spatial distribution of water quality samples across the Bighorn Basin 

indicating that the low TDS produced water is widely distributed. The higher salinity produced 

water (that produced water with TDS >100,000 mg/L) from the USGS produced water database 

is located in the southeastern portion of the basin in Washakie County, Wyoming (Figure 6.9). 

Some of the high quality water is from shallow reservoirs with fresh water recharging these 

zones from the surface, while the low quality water is from deeper reservoirs in the deeper 

portions of the basin. The Bighorn Basin contains a large portion of low salinity water that is 

widely distributed as shown in Figure 6.9. Once the oil and gas have been separated from the 

water, this low salinity water can have important beneficial uses in addition to enhanced 

recovery of resources; the water can be utilized by local landowners for livestock watering, 

irrigation, and other beneficial uses. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

131

Figure 6.10 Produced Water Quality from the Wyoming and Montana Portions of the Bighorn 

Basin

20%

1% 0.4% 0.04%

79%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

<9,999

(fresh/brackish)

10,000-49,999

(low/moderate saline)

50,000-99,999

(moderate/high

saline)

100,000-199,999

(low/moderate brine)

200,000-460,000

(brine)

TDS Range in mg/L (produced water description)

Percent of Total Population

(2,282 Samples)

Median 

4,891 mg/L

Low

1,017mg/L

High 

220,200 mg/L

Source: USGS, 2002 

Within the Bighorn Basin, water quality varies by producing formation; typically produced water 

quality decreases with depth in a basin. Produced water quality for the Madison, Phosphoria, 

and Tensleep formations of the Bighorn Basin from the Wyoming Oil and Gas Conservation 

Commission (WOGCC) are presented below. Produced water from the WOGCC for the Madison 

Formation varies from less than 500 mg/L to 4,000 mg/L TDS (WOGCC, 2006). The Phosphoria 

Formation produces water ranging from less than 500 mg/L to more than 80,000 mg/L TDS. 

The Tensleep Formation produces water ranging from less than 2,000 to more than 4,000 mg/L 

TDS. The majority of produced water from this basin is used in secondary recovery operations 

while some volumes are used for agricultural purposes. 

Section 6.5 Fort Worth Basin 

The Fort Worth Basin covers a large portion of north-central Texas and small portion of 

southwestern Oklahoma. The basin is bounded by the Wichita Mountains to the north, the 

Ouachita Front to the east and south, the Permian Basin to the west, and the Llano Uplift to the 

south (Ball and Perry, 1995). Figure 6.11 shows the approximate extents of the basin. The 

Fort Worth Basin has a similar geological history to the Anadarko Basin to the north and the 

Permian Basin to the south. Figure 6.11 shows the basin to lie in a north to south orientation 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

132

along its western edge where it junctions with the Permian Basin (Ball and Perry, 1995). The 

Fort Worth Basin covers an area of approximately 54,000 square miles. 

Figure 6.11 Geologic Setting and Produced Water Quality Distribution of the Fort Worth Basin

Source: USGS, 2005 

Significant Geological Features 

The sedimentary strata filling the Fort Worth Basin are mostly Paleozoic in age from Ordovician 

through Permian. A thin veneer of Cretaceous sediments hold the drinking water aquifers of 

the area and covers the older section containing oil, gas, and saltwater reservoirs. The total 

thickness of sediments in the Fort Worth Basin is approximately 12,000 feet or less. Some 

faulting is present on the edges of the basin. Conventional oil and gas development have taken 

place in the basin for a long time, but recently the development of unconventional gas in the 

Barnett shale has dominated the drilling in this basin. The Barnett gas play is currently the 

most active development in the United States. 

Oil and Gas Production 

The Fort Worth Basin has produced commercial quantities of oil and gas for most of the 20th

Century. First production from the basin was in the early 1900’s with more than 2.3 BBO and 

more than 65.5 TCFG having been produced to date. Productive reservoirs include the 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

133

Ellenberger, Mississippian, and prolific Pennsylvanian/Permian sands. Fields developing these 

formations have been producing mostly oil since the 1960’s. The biggest play at the present 

time is the Mississippian Barnett shale, a thick, highly organic, siliceous fine-grained rock laid 

down over most of the basin. The Barnett is a self-sourced reservoir that holds large quantities 

of dry natural gas that can be produced if the reservoir rock is fractured. Figure 6.11 shows the 

extent of the Barnett play in the basin. Horizontal wells have become prolific dry gas Barnett 

producers in the past few years. After drilling, the horizontal wells are fractured with huge 

volumes of water to open permeability in the fine-grained rock. Once natural gas production 

has been established, the water used to fracture the reservoir is produced back to the surface. 

Therefore, the Barnett wells produce large volumes of frac water that needs to be managed. 

The Newark East Barnett field (noted on Figure 6.11 as the Barnett Shale production area from 

1998 – 2004) is currently the largest gas field in Texas and the most active drilling area in the 

nation. Total production from the Barnett through October 2005 was 5.6 million barrels of oil 

and 1.6 TCFG. At the end of 2005 there were approximately 4,500 producing Barnett wells with 

total daily gas production rates of approximately 9.62 BCF and approximately 3,367 barrels of 

oil per day. There is an estimated 26 TCF of gas recoverable in the play (Rushworth, 2006). 

Produced Water Management

Most oil and gas production has associated water production in the basin, but other than the 

frac water from the Barnett wells, the volumes are not large. Management historically has been 

by way of water floods or injection disposal wells. Figure 6.12 charts the numerical distribution 

of water quality across the basin from the USGS produced water database, which contains 768 

individual samples of produced water quality for the Fort Worth Basin. Produced water salinity 

in the Fort Worth Basin includes the ranges from <10,000 mg/L to >200,000 mg/L TDS. 

Median salinity expressed as TDS is high at 151,192 mg/L (moderate brine). The range of 

salinity values for the basin ranged from 1,990 mg/L (brackish) to 345,503 mg/L (brine) (Figure 

6.12). The distribution is quite similar to the Permian and Anadarko basins suggesting their 

similar geological history. Of the 768 produced water quality samples from the Fort Worth 

Basin, the largest portion of the produced water quality samples (49%) for the Fort Worth Basin 

were reported in the 100,000 mg/L to 199,999 mg/L range (Figure 6-18). The next largest 

distribution of produced water quality for the basin (29%) was the 200,000 mg/L to 460,000 

mg/L TDS range (Figure 6-18). The large percentage (80%) of produced water in the brine 

quality ranges suggests that few beneficial uses exist for the produced water from this basin 

other than for water flood projects. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

134

Figure 6.12 Water Quality Distribution in the Fort Worth Basin 

1.6%

5%

16%

29%

49%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

<9,999

(fresh/brackish)

10,000-49,999

(low/moderate saline)

50,000-99,999

(moderate/high

saline)

100,000-199,999

(low/moderate brine)

200,000-460,000

(brine)

TDS Range in mg/L (produced water description)

Percent of Total Population

(260 Samples)

Median 

151,192 mg/L

Low

1,990 mg/L

High 

345,503 mg/L

(Source: USGS, 2002) 

Figure 6.11 documents the distribution of water quality samples across the Fort Worth Basin 

showing how the produced water quality varies throughout the basin. The geographic 

distribution of water salinity shown in Figure 6.11 reflects higher TDS water is more prevalent in 

the northern and western portions of the basin, and the lower TDS water is present in the 

central and eastern portions of the basin. Produced water with greater than 100,000 mg/L TDS 

is more prevalent in the northern portion of the basin, near the Texas-Oklahoma border (Figure 

6.11). The produced water quality samples with TDS less than 100,000 mg/L are more 

predominant in the central and eastern portions of the basin with some associated produced 

water samples of higher TDS present in this area (Figure 6-19). 

Currently the Barnett production has taxed the water management options when the water 

used to fracture the well is produced to the surface. Few disposal wells existed in the basin 

before the hundreds of Barnet wells were drilled. Over most of the basin, the Pennsylvanian 

sands and the Ellenberger carbonates water-bearing permeable units traditionally have been 

used for disposal by Class II disposal wells. The Ellenberger has more capacity, consisting of 

thick carbonates that often are naturally fractured and cavernous. Pennsylvanian sands are 

present above the Barnett and are drilled through by each producing well. The Ellenberger, 

however, is situated beneath the Barnett shale and is not drilled by the Barnett field wells. 

Produced water from the Barnett development is a challenge for operators in the basin. A 

fracture job on a horizontal well can utilize more than 2 million gallons of water that is then 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

135

produced back to the surface during the productive life of the well. Operators often use water 

from municipal water systems to be sure that the water is clean and contains no live bacteria 

that could be introduced into the formation. The fracture water that is brought back to the 

surface during production has picked up some oil and grease, dissolved salts, and may contain 

>100,000 mg/L TDS. Water of this quality could be treated to drinking water or irrigation 

quality, but to date the water has not been treated. However, some of this produced water is 

re-used by operators for fracturing other wells in the field. Most of the produced water is sent 

to disposal wells in the basin. 

In January 2005, the Texas Railroad Commission approved a pilot project to be conducted by 

Fountain Quail Water Management to treat fracture-job flow-back water in the Barnett Shale 

trend on a lease held by Devon Energy in North Texas for the purposes of recycling the fluid. 

The approval given by the Commission allows the recycling operations to go forward without 

the need to obtain certain permits or additional financial assurance for the operation. A skidmounted device located at the site of a Barnett well to be fracture stimulated is utilized to distill 

produced water brought in from off-site. The produced water is distilled through a series of 

heat exchangers yielding 2,000 barrels of distilled water for every 2,350 barrels of produced 

water put into the system. The remaining 350 barrels of saltwater and waste require off-site 

disposal at a conventional Class I injection facility. Once a sufficient volume of distilled water is 

produced, the water may be used for fracture stimulating a Barnett well on Devon’s lease 

(Forbis, 2005). 

In addition to using commercial injection wells, Class II (oil and gas) injection wells are also 

used for disposal of produced water in the Fort Worth Basin. Class II injection well permits can 

be difficult to obtain and the permit process can be delayed by citizen protests. One aspect of 

the Barnett play that is different from other oil and gas plays is the fact that oil and gas activity 

in the Barnett is centered on and around the city of Fort Worth, Texas, and its suburbs. 

Because the Barnett play is located near an urban area, development is often surrounded by 

residential homes with residents that may not be familiar with oil and gas production facilities. 

Because of the large urban population and their water needs, injection pressure gradients 

incorporated into disposal permits are curtailed in some areas for the shallow Pennsylvanian 

sands in order to prevent impact to overlying drinking water aquifers. At these lower injection 

pressures, Class II disposal wells completed into the Pennsylvanian sands often cannot inject 

enough water to make the wells economical to operate. One option is for operators to 

complete wells in the deeper Ellenberger zone where higher pressure gradients can be 

permitted to inject and large quantities of water can usually be injected. However, Barnett 

wells are completed at shallower depths than the Ellenberger zone; because of this, operators 

who wish to use an Ellenberger disposal well will need to drill a different well for this purpose. 

The necessity of drilling a separate disposal well to the Ellenberger adds considerably to the 

expense of the injection well installation. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

136

Section 6.6 Greater Green River Basin 

The Greater Green River Basin is located in the Rocky Mountain Foreland from western to 

south-central Wyoming and extends into northeastern Utah and northwestern Colorado (Law, 

1995). Figure 6.13 shows the basin to lie in a northwest to southeast orientation located 

between the Uinta Uplift to the southwest and the Hanna and Wind River Basins to the 

northeast and east. The Greater Green River Basin is further bounded by the Medicine Bow and 

Park Range Uplifts to the south-southeast, Wyoming-Utah-Idaho Thrust Belt to the northwest, 

and the Absaroka Mountains to the north. The Greater Green River Basin covers an area of 

approximately 19,700 square miles (DeJarnett et. al., 1997). 

Significant Geological Features 

The Greater Green River Basin contains strata of Cambrian through Tertiary age, which are 

believed to have been deposited in three stages (Law, 1995). The first stage of deposition is 

referred to as the shelf in which the area was inundated by shallow seaways from the Middle 

Cambrian to Middle Jurassic. The middle stage is the foreland stage in which sediments were 

supplied to the basin from uplift areas to the west (Idaho and Utah). The final stage is the 

inter-basin sedimentation stage in which sediments were derived from the uplift of local areas. 

The result of these three stages of deposition is an accumulated thickness of sediments in the 

northern part of the basin that approaches 32,000 feet (Law, 1995). The important strata for 

oil and gas development in the basin range from Paleozoic to Tertiary in age, with recent 

production focusing on tight sands of Cretaceous aged Almond and Frontier Formations 

(DeJarnett et. al., 1997). 

Oil and Gas Production 

Oil and gas production has been ongoing in the basin since discovery of the Lost Soldier field in 

1916 with the first gas play discovery in 1922 on the Rock Springs Uplift (Law, 1995 and 

Gibson, 1997). To date, more than 0.17 BBO and more than 13.75 TCFG have been produced 

from the Greater Green River Basin (Gibson, 1997 and WOGCC, 2006). The basin has seen 

sporadic testing of CBNG resources since the mid 1980’s into the early 1990’s. Much of the gas 

production has been occurring in tight sandstone formations in the center of the basin, which 

have resulted in large volumes of produced water co-produced with the gas. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

137

Figure 6.13 Geologic Setting and Produced Water Quality Distribution of the Greater Green 

River Basin

(Source: USGS, 2005) 

Produced Water Management

The numerical distribution of produced water quality data from the USGS produced water 

database for the Greater Green River Basin is shown in Figure 6.14. The database contains 183 

individual samples of produced water quality. Produced water salinity in the basin includes 

ranges from <10,000 mg/L to <200,000 mg/L TDS; there were no samples in the database for 

the 200,000 mg/L to 460,000 mg/L range (Figure 6-21). Median salinity expressed as TDS for 

the Greater Green River Basin was low at 6,455 mg/L (brackish water). The range of salinity 

values for the basin ranged from 148 mg/L (fresh water) to 192,000 mg/L (moderate brine). 

More than half of the produced water samples (65%) reported for the basin have TDS 

concentrations <10,000 mg/L. The next highest grouping of produced water quality samples 

(23%) was the 10,000 mg/L to 49,999 mg/L TDS (saline waters). The moderately saline (8%) 

to moderate brine (4%) categories contain the remaining 12% of the produced water quality 

samples. (Figure 6.14). 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

138

Figure 6.14 Water Quality Distribution in the Greater Green River Basin 

23%

8%

0%

4%

65%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

<9,999

(fresh/brackish)

10,000-49,999

(low/moderate saline)

50,000-99,999

(moderate/high

saline)

100,000-199,999

(low/moderate brine)

200,000-460,000

(brine)

TDS Range in mg/L (produced water description)

Percent of Total Population

(183 Samples)

Median 

6,455 mg/L

Low

148mg/L

High 

192,000 mg/L

(Source: USGS, 2002)

Figure 6.13 documents the distribution of water quality samples across the Greater Green River 

Basin and shows that fresh to brackish quality produced water (TDS <10,000 mg/L) is scattered 

across the basin. Similarly, the two groupings of saline produced water (10,000 mg/L to 49,999 

mg/L and 50,000 to 99,999 mg/L TDS) are also scattered across the basin (Figure 6.14). The 

one grouping of brine waters (100,000 mg/L to 199,999 mg/L TDS) identified for the basin from 

the USGS produced water database is present along the Wyoming-Colorado state line (Figure 

6.13). This grouping is likely indicative of production occurring in a deeper portion of the basin 

in formations that are not receiving fresh water recharge from the surface. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

139

Section 6.7 North Central Montana Basin 

The North Central Montana Basin covers a large portion of the center of the state of Montana 

(Figure 6-23). The U.S. portion of the basin is bounded by the United States-Canadian border 

to the north, the Williston Basin to the east, the Powder River Basin to the southeast, the Crazy 

Mountain Basin to the southwest, and the Montana Disturbed Belt to the west (Figure 6.15). 

Several geological features are present in the basin, including: Sweetgrass Arch, Kevin-Sunburst 

and Bowdoin Domes, Bearpaw Uplift, and Central Montana Trough (Dyman, 1995). The North 

Central Montana Basin is approximately 250 miles long and 250 miles wide and covers an area 

of approximately 60,000 square miles (Dyman, 1995).

Figure 6.15 Geologic Setting and Produced Water Quality Distribution of the North Central 

Montana Basin

(Source: USGS, 2005) 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

140

Significant Geological Features 

The North Central Montana Basin contains strata of Cambrian through Tertiary age, which are 

present both at the outcrop and in the subsurface throughout the basin (Dyman, 1995). Much 

of the active oil and gas production in the basin comes from the Cretaceous sandstones from 

the Kootenai Formation and the Madison Group carbonates. Other formations with potential 

plays include the Cambro-Ordivician and Jurassic-Cretaceous sandstones, carbonates of the 

Devonian-Mississippian, and shallow Cretaceous biogenic gas (Dyman, 1995). Recent activity 

includes the Bakken Shale play, which extends from the Williston Basin into the North Central 

Montana Basin. 

Oil and Gas Production 

Oil and gas production in the North Central Montana Basin has been ongoing since the early 

1900’s from the Bowdoin Field and the Cutbank oil field (Dyman, 1995). Both crude oil and 

natural gas are produced from Cretaceous through Devonian aged reservoirs across the North 

Central Montana Basin, with more than 0.46 BBO and more than 1.67 TCFG having been 

produced from the basin to date (Dyman, 1995 and MBOGC, 2006). 

Produced Water Management

The numerical distribution of produced water quality samples from the USGS produced water 

database for the North Central Montana Basin is shown in Figure 6.16. The USGS produced 

water database contains 583 individual samples of produced water quality for the North Central 

Montana Basin. Produced water salinity includes all ranges identified for analysis in this study 

from <10,000 mg/L to >200,000 mg/L TDS. Median salinity expressed as TDS is low at 4,111 

mg/L (brackish). The range of salinity values for the basin ranged from 1,081 mg/L (slightly 

brackish) to 323,047 mg/L (brine) (Figure 6.16). Produced water from this basin is very high 

quality with 86% of the samples in the USGS database having less than 10,000 mg/L TDS. 

Another 13% of the produced water samples were reported in the range from 10,000 mg/L to 

49,999 mg/L TDS. The remaining percentage (approximately 1.3%) were relatively evenly 

distributed through the remaining three water quality groupings analyzed in this report (Figure 

6.16).

Figure 6.15 documents the distribution of water quality samples across the basin showing that 

the high quality produced water is distributed across the producing regions. Since there is such 

a small percentage of low quality produced water (>50,000 mg/L TDS) it is difficult to assess 

the distribution of these samples within the basin. While the low quality water (<10,000 mg/L 

TDS) appears to be focused along several features close to the Montana-Canadian border, some 

scattered production reaches into the central part of Montana (Figure 6.15). The low salinity 

water might have beneficial uses that include enhanced recovery of oil and gas resources and 

agricultural. The majority of these low salinity samples are from production wells at depths less 

than 5,000 feet below the surface where fresh surface waters are recharging these zones. 

Many of the low TDS produced water quality samples were taken from the Mississippian aged 

Madison Formation, although many other formations were sampled. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

141

Figure 6.16 Water Quality Distribution of the North Central Montana Basin

13%

0.5% 0.3% 0.5%

86%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

<9,999

(fresh/brackish)

10,000-49,999

(low/moderate saline)

50,000-99,999

(moderate/high

saline)

100,000-199,999

(low/moderate brine)

200,000-460,000

(brine)

TDS Range in mg/L (produced water description)

Percent of Total Population

(583 Samples)

Median 

4,111 mg/L

Low

1,081mg/L

High 

323,047 mg/L

(Source: USGS, 2002) 

Section 6.8 Permian Basin 

The Permian Basin covers a large portion of western Texas and southeastern New Mexico. The 

majority of the basin is located in western Texas as seen in Figure 6.17. The basin contains a 

variety of hydrocarbon reservoirs that also produce water (Steuber, 1998). Figure 6.17 shows 

the Permian Basin to lie in a north to south orientation, with the Matador Arch to the north, the 

Eastern Shelf of the Midland Basin to the east, the Marathon-Ouachita Fold Belt to the south, 

and the Pedernal Uplift and Diablo Platform to the west (Ball, 1995). The Permian Basin is 

approximately 260 miles by 300 miles with a total surface area exceeding 86,000 square miles. 

Significant Geological Features 

The Permian Basin contains strata of predominantly Paleozoic in age with thinner extent of 

younger sediments; the basin’s current structural features developed from the Late 

Mississippian to Early Pennsylvania time (Dutton et. al., 2004). Most of the basin-fill volume is 

taken up with the Paleozoic strata with oil and gas production from rocks ranging from the 

Cambrian through Cretaceous age sediments. The important strata in the basin include the 

Ordovician Ellenburger carbonates, which are the same age and similar in lithology to the 

massive Knox carbonates of the Appalachians and the Arbuckle Formation of the Anadarko 

Basin. The stratigraphy of the Permian Basin includes a thick sequence of Paleozoic age rocks, 

which can be greater than 25,000 feet in thickness (Ball, 1995). 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

142

Figure 6.17 Geologic Setting and Produced Water Quality Distribution of the Permian Basin

(Source: USGS, 2005) 

Oil and Gas Production 

The Permian Basin continues to be one of most prolific and largest oil production basins in the 

United States. As of 2002, the Permian Basin production was 17% of the total United States oil 

production (BEG, 2002). Oil and gas production occurs in rocks dating from the Cambrian to 

the Cretaceous with most production coming from reservoirs of Paleozoic age (Ball, 1995). 

More than 35 BBO, 5.5 BBNGL, and 90.7 TCFG had been produced from the basin as of the 

early 1990’s (Ball, 1995). 

Produced Water Management

The numerical distribution of produced water for the Permian Basin is presented in Figure 6.18. 

The USGS produced water database contains more than 10,000 individual samples for the 

Permian Basin. Produced water salinity in the basin includes all ranges identified for analysis in 

this study from <10,000 mg/L to >200,000 mg/L TDS (Figure 6-27). Median salinity expressed 

as TDS was 87,612 mg/L with the range of salinity values ranging from 1,048 mg/L (slightly 

brackish) to 397,572 mg/L (brine). Approximately 6 percent of the water samples in the 

database were below 10,000 mg/L TDS and could have local beneficial uses; this high quality 

water is reported from shallow aquifers that do not produce hydrocarbons (USGS, 2002), but 

scattered wells have sampled productive formations that locally contain high quality water. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

143

Depths of those samples less than 10,000 mg/L range from 25 feet to more than 19,000 feet. 

Most of these low salinity water samples were taken less than 4,000 feet deep. Water this deep 

probably cannot be economically exploited by wells drilled expressly for water, but could be 

exploited as a by-product of oil and gas production. 

The largest grouping of produced water for the Permian Basin (31%) was reported in the 

100,000 mg/L to 199,999 mg/L TDS grouping, with slightly fewer samples (29%) in the 50,000 

mg/L to 99,999 mg/L TDS category (Figure 6.18). Figure 6.17 shows the distribution of 

produced water salinity values, showing that produced water quality varies randomly 

throughout the basin. The geographic distribution of the produced water salinity values show 

the high quality water samples (TDS <10,000 mg/L) to be located along the western boundary 

of the basin (Figure 6.17). This water may be able to satisfy some uses in its raw state without 

treatment while uses such as industrial and municipal water supply may require treatment. The 

other classifications of produced water appear to be much more evenly distributed with most of 

the produced water currently utilized for extensive secondary recovery operations in the basin’s 

oil fields. 

Figure 6.18 Water Quality Distribution in the Texas and New Mexico Portions of the Permian 

Basin

21%

29% 31%

13%

6%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

<9,999

(fresh/brackish)

10,000-49,999

(low/moderate saline)

50,000-99,999

(moderate/high

saline)

100,000-199,999

(low/moderate brine)

200,000-460,000

(brine)

TDS Range in mg/L (produced water description)

Percent of Total Population

(10,172 Samples)

Median 

87,612 mg/L

Low

1,048mg/L

High 

397,572 mg/L

Source: USGS, 2002 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

144

Section 6.9 Powder River Basin 

The Powder River Basin forms part of the Unglaciated Missouri Plateau section of the Great 

Plains province. It extends from northeastern Wyoming into southeastern Montana and 

contains strata of Cambian to Tertiary age (Figure 6.19). On the surface of the basin, there are 

several watersheds while outcropping formations are primarily Tertiary in age. Figure 6.19 

shows the Powder River Basin to lie in a northwest to southeast orientation that is bound by the 

Miles City Arch to the north, the Black Hills to the east, the Laramie Uplift and Casper Arch to 

the south, and the Bighorn Mountains to the west (Dolton and Fox, 1995). The Powder River 

Basin covers an area of approximately 34,000 square miles (Dolton and Fox, 1995). 

Figure 6.19 Geologic Setting and Produced Water Quality Distribution of the Powder River 

Basin

(Source: USGS, 2005) 

Significant Geological Features 

The basin is filled with a thick sequence of sediments from the Cambrian to Tertiary in age. 

The sediments result from accumulations of Paleozoic shelf carbonates, sandstones, and shales, 

overlain by a thick sequence of Mesozoic to Tertiary sediments that accumulated during the 

time of the Western interior seaway, with recent sediments for local uplifted areas (Dolton and 

Fox, 1995). Formations within the Powder River Basin important to oil and gas development 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

145

range from the shallow Tertiary coal beds to conventional oil and gas reservoirs from the 

Mississippian to lower Cretaceous. The stratigraphy of the basin includes a thick sequence of 

Phanerozoic strata, which can be greater than 18,000 feet in thickness near the basin’s axis 

(Dolton and Fox, 1995). 

Oil and Gas Production 

Oil and gas has been developed in the Powder River Basin since the discovery of the Salt Creek 

field in 1908 (Dolton and Fox, 1995). Since this initial discovery, recoverable resources have 

been estimated at 2.7 BBO and 2.3 TCFG within the basin (Dolton and Fox, 1995). 

Conventional oil and gas exploration has been declining in the Montana portion, with 

considerable decreases in oil production since 1986; natural gas production had been declining 

in the Powder River Basin until the start of CBNG production in 1990’s. Since then, the basin 

increasingly has become a larger source of natural gas revenues for Montana and Wyoming, 

with production of CBNG contributing to the majority of the increase in production. 

Produced Water Management

The numerical distribution of produced water quality for the Powder River Basin is presented in 

Figure 6.20. The USGS produced water database contains 3,012 individual samples for the 

Powder River Basin. Produced water salinity in the basin includes all ranges identified for 

analysis in this study from <10,000 mg/L to >200,000 mg/L TDS. Median salinity expressed as 

TDS is moderately brackish at 7,376 mg/L (Figure 6-30) with a range of salinity values from 

1,002 mg/L (slightly brackish) to 307,713 mg/L (brine). More than half the produced water 

quality samples (60%) in the USGS database for the basin have TDS concentrations of less than 

10,000 mg/L. Another 33% of the produced water samples were reported in the range from 

10,000 mg/L to 49,999 mg/L TDS. The majority of the remaining percentage (approximately 

7%) was distributed between the 50,000 mg/L to 99,999 mg/L (3%) and the 100,000 mg/L to 

199,999 mg/L (4%) groupings. Less than one percent (0.8%) of the produced water quality 

samples were reported in the highest salinity grouping from 200,000 mg/L to 460,000 mg/L 

(Figure 6.20). Formation water varies from strong brines in deep reservoirs, higher quality 

water trapped in Tertiary and Cretaceous reservoirs, and fresh meteoric water that has entered 

some of the aquifers at their outcrop and migrated into the basin. 

Figure 6.19 documents the distribution of water quality samples across the Powder River Basin 

showing how the produced water quality varies across the basin. The geographical distribution 

of water salinity as shown in Figure 6.19 indicates that the water quality reflects the geometry 

of the basin. Produced water of the fresh to brackish quality (0 mg/L to 9,999 mg/L TDS) is 

located along the basin margins with some scattering of this higher quality water into the center 

of the basin. The produced water quality of low-to-moderate salinity (10,000 mg/L to 49,999 

mg/L TDS) are predominately located toward the center of the basin inside the area of the 

fresh to brackish quality samples (Figure 6.19). The lower quality produced water samples 

(>50,000 mg/L TDS) are located toward the deeper portion of the basin as shown in Figure 

6.19.
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

146

Figure 6.20 Water Quality Distribution of the Entire Powder River Basin of Montana and 

Wyoming

33%

3% 4%

0.8%

60%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

<9,999

(fresh/brackish)

10,000-49,999

(low/moderate saline)

50,000-99,999

(moderate/high

saline)

100,000-199,999

(low/moderate brine)

200,000-460,000

(brine)

TDS Range in mg/L (produced water description)

Percent of Total Population

(3,012 Samples)

Median 

7,376 mg/L

Low

1,002mg/L

High 

307,713 mg/L

(Source: USGS, 2002)

Within the Powder River Basin, produced water varies by reservoir type and depth. CBNG 

produced water typically has a TDS between approximately 1,000 mg/L and 4,000 mg/L. CBNG 

fields are prodigious water producers and account for approximately 50% of all produced water 

in the basin (WOGCC, 2006). Water from the Muddy/Newcastle Formations varies from less 

than 2,000 mg/L to more than 50,000 mg/L; water from the Nugget Formation ranges from 

50,000 mg/L to 70,000 mg/L; water from the Madison Formation varies from less than 1,000 

mg/L to 8,000 mg/L; Dakota Formation water ranges between 2,000 mg/L to 8,000 mg/L; and 

the Minnelusa Formation contains water in excess of 150,000 mg/L TDS.

Section 6.10 Williston Basin 

The Williston Basin is located at the northern end of the Great Plains and covers approximately 

143,000 square miles within the United States, including parts of eastern Montana and North 

and South Dakota (Figure 6.21). The Williston Basin is bound in the east by the Canadian 

Shield, the southeast by the Sioux Uplift, to the southwest by the Black Hills Uplift, and to the 

west by the Miles City Arch and Porcupine Dome (Peterson, 1995). The Williston Basin is the 

result of subsidence, which is believed to have started as early as the Ordovician Period and 

continues today (Heck et al. 2002). The Williston Basin contains a nearly complete rock record 

reflecting the numerous transgressive/regressive sequences that have occurred in the basin 

(Heck et al. 2002). 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

147

Figure 6.21 Geologic Setting and Produced Water Quality Distribution of the Williston Basin

(Source: USGS, 2005) 

Significant Geological Features 

The sediments within the basin range from the Cambrian through Tertiary strata, with the 

maximum thickness of Phanerozois rocks being greater than 16,000 feet in the North Dakota 

portion of the basin (Peterson, 1995). Outcrops within the Williston Basin consist primarily of 

the Tertiary sediments from the Fort Union Formation, Cretaceous sediments from the Hell 

Creek Formation, and Quaternary Alluvium along the various river valleys. Oil and gas have 

been developed from Cretaceous, Mississippian, Devonian, Silurian, and Ordovician reservoirs 

within the basin (MBOGC, 2005). The Tertiary deposits contain sediments including various 

coals and lignites which to date have been sporadically tested for only CBNG in North Dakota. 

The Williston Basin contains several significant geologic features relative to oil and gas 

development, including the Cedar Creek Anticline, Nesson Anticline, the Poplar Dome, and the 

Bakken Formation. 

Oil and Gas Production 

Oil and gas has been produced from the Williston Basin since the 1910’s with production of 

shallow gas resources from the Cretaceous Eagle Sandstone on the Cedar Creek Anticline in 

Montana, and major oil production on the Nesson Anticline in North Dakota starting after World 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

148

War II (Peterson, 1995). Much of current activity in the Williston basin is focused on the Cedar 

Creek Anticline, which is currently experiencing exploration and production in the SiluroOrdovician with recent horizontal water-floods getting the most attention in the basin. Other 

recent oil and gas development in the Williston Basin has been focused on the continuous 

Bakken play of east central Montana and west central North Dakota. 

Produced Water Management

The numerical distribution of produced water quality for the Williston Basin is shown in Figure 

6.22. The USGS produced water database contains 3,902 individual samples for the Williston 

Basin. Produced water salinity for the Williston Basin includes all ranges identified for analysis 

in this study from <10,000 mg/L to >200,000 mg/L TDS. Median salinity expressed as TDS for 

the basin is relatively high at 149,748 mg/L (moderate brine waters) as shown in Figure 6.22. 

The range of salinity values for the Williston Basin ranged from 1,169 mg/L (slightly brackish) to 

399,943 (brine). The largest percentage (41%) of the water quality samples from the USGS 

produced water database for the Williston Basin had TDS concentrations between 200,000 mg/L 

and 460,000 mg/L. The next highest distribution percentage (19%) was the 100,000 mg/L to 

199,999 mg/L range. The remaining 39% are distributed between the 50,000 mg/L to 99,999 

mg/L (13%), the 10,000 mg/L to 49,999 mg/L (16%), and the <10,000 mg/L (10%) ranges. 

Figure 6.21 documents the distribution of water quality samples across the Williston Basin, 

showing how the produced water quality varies geographically. The distribution of water 

salinity as shown in Figure 6.21 indicates that the water quality reflects the geometry of the 

basin. Produced water of the fresh to brackish quality (0 mg/L to 9,999 mg/L TDS) is located 

along the basin margin with most of the higher quality water located along the southwestern 

edge of the basin. The low-to-moderate saline waters (10,000 mg/L to 49,999 mg/L) are 

predominately located inside of the fresh to brackish quality samples. The lower quality 

produced water samples (>50,000 mg/L) are located toward the deeper central portion of the 

basin as shown in Figure 6.21. 

Because most of this water is not of beneficial use quality (<10,000 mg/L TDS), the majority is 

utilized in secondary oil recovery operations or disposed of commercially. Almost 90% of the 

produced water from the Williston Basin is high in TDS and lacks any other use. Some 

reservoirs (Tertiary aged) within the Williston Basin do produce water low enough in TDS to 

support some uses, but at the present time no water is being produced from lignite coalbeds in 

the Tertiary Fort Union Formation. If these lignites ever prove productive of CBNG, this water 

may be of sufficient quality and quantity to sustain beneficial uses such as irrigation, cattle, or 

support of coal mining and power generation operations as is seen in the Powder River Basin. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

149

Figure 6.22 Water Quality Distribution in the United States Portion of the Williston Basin

13%

41%

16% 19%

10%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

<9,999

(fresh/brackish)

10,000-49,999

(low/moderate saline)

50,000-99,999

(moderate/high

saline)

100,000-199,999

(low/moderate brine)

200,000-460,000

(brine)

TDS Range in mg/L (produced water description)

Percent of Total Population

(3,902 Samples)

Median 

149,748 mg/L

Low

1,169 mg/L

High 

399,943 mg/L

(Source: USGS, 2002) 

Section 6.11 Wind River Basin 

The Wind River Basin is a major foreland basin in the Wyoming Rockies located in central 

Wyoming, south of the Bighorn Basin. The Wind River Basin is an asymmetric basin with a 

southeast-northwest orientation and contains major structures related to the bounding 

structural uplifts (Figure 6.23). The basin is bound by the Sweetwater Uplift to the south, the 

Wind River Mountains to the west, the Owl Creek Mountains to the north, and the Casper Arch 

to the east as shown in Figure 6.23 (Fox and Dolton, 1995b). The Wind River Basin covers an 

area of approximately 11,700 square miles (Fox and Dolton, 1995b). 

Significant Geological Features 

The basin has produced oil and gas since 1884 when Wyoming’s first oil well was completed in 

the Wind River Basin. The basin is split between oil and gas production with oil dominating 

production until the 1950’s when natural gas became more important. The basin is currently 

one of the most important natural gas producing areas in the state. Both crude oil and natural 

gas are produced from Cretaceous through Devonian aged reservoirs across the North Central 

Montana Basin, with more than 0.59 BBO and more than 4.73 TCFG having been produced from 

the basin to date (Fox and Dolton, 1995b and WOGCC, 2006). 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

150

Figure 6.23 Geologic Setting and Produced Water Quality Distribution of the Wind River Basin

(Source: USGS, 2005) 

In 2005, the Wind River Basin produced 3.95 million bbls of oil, 245.8 BCF of gas, and 209 

million bbls of water (WOGCC, 2006). No CBNG is currently produced in the basin. 

Produced Water Management

The numerical distribution of produced water quality for the Wind River Basin is shown in Figure 

6.24. The USGS produced water database contains 2,490 individual samples for the Wind River 

Basin. Produced water salinity in the basin includes all of the ranges identified for analysis in 

this study from <10,000 mg/L to >200,000 mg/L TDS. Median salinity expressed as TDS was 

low at 5,349 mg/L (brackish water) (Figure 6.24). Salinity values for the Wind River Basin 

ranged from 1,169 mg/L (slightly brackish) to 220,219 (brine). The largest percentage (75%) 

of the water quality samples have TDS concentrations <10,000 mg/L. The next highest 

distribution percentage (24%) was the 10,000 mg/L to 49,999 mg/L range. The remaining 

1.5% was distributed between the 50,000 mg/L to 99,999 mg/L (0.8%) range, the 100,000 

mg/L to 199,999 mg/L (0.6%) range, and the 200,000 mg/L to 460,000 mg/L (0.08%) range. 

Figure 6.23 documents the distribution of water quality samples across the Wind River Basin 

showing how the produced water quality varies. The geographical distribution of water salinity 

indicates that the highest produced water quality samples are distributed all across the basin. 

Produced water of the fresh to brackish quality (0 mg/L to 9,999 mg/L TDS) is located 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

151

throughout the basin with most of this higher quality water likely located in shallow formations 

receiving recharge from the surface (Figure 6.23). Much of this water could have local 

beneficial uses. The produced water quality of low-to-moderate saline waters (10,000 mg/L to 

49,999 mg/L) similarly are distributed across the basin and are likely produced from the deeper 

formations. The lower quality produced water samples (>50,000 mg/L) are located toward the 

north-central portion of the basin, but represent only a small percentage of the total samples 

(<2%).

Figure 6.24 Water Quality Distribution in the Wind River Basin

24%

0.8% 0.6% 0.08%

75%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

<9,999

(fresh/brackish)

10,000-49,999

(low/moderate saline)

50,000-99,999

(moderate/high

saline)

100,000-199,999

(low/moderate brine)

200,000-460,000

(brine)

TDS Range in mg/L (produced water description)

Percent of Total Population

(2,490 Samples)

Median 

5,349 mg/L

Low

1,169mg/L

High 

220,219 mg/L

(Source: USGS, 2002) 

The large volumes of water are of varying quality ranging from less than 300 mg/L to much 

stronger brines. Deep gas reservoirs typically produce very high quality water that likely 

represents condensed water present as vapor in the subsurface; this water could have local 

beneficial uses for agriculture and livestock watering. Oil reservoirs produce water at rates up 

to 100 times the rate of crude oil production; this water is most often injected back into the oil 

reservoirs to support oil production. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

152

THIS PAGE INTENTIONALLY LEFT BLANK 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

153

SECTION 7.0 REGIONAL IMPLICATIONS TO PRODUCED WATER 

MANAGEMENT IN THE UNITED STATES 

Section 6 presents a detailed analysis of several hydrocarbon producing basins located primarily 

in Alaska, Montana, Wyoming, Kansas, Oklahoma, and Texas. Several other major basins exist 

in the United States, as shown in Figure 7.1. The basins discussed in Section 6 provide a varied 

cross section of produced water issues sufficient to document the majority of proven water 

management practices utilized across the United States in the other basins shown in Figure 7.1. 

These issues include, but are not limited to: 

Produced Water Characteristics – The range in water quality is extreme across the 

United States. Produced water with TDS less than 10,000 mg/L may have significant 

beneficial uses for industrial and agricultural activities while water with a TDS greater 

than 50,000 mg/l has limited use other than enhanced recovery and will likely require 

injection disposal for proper management. Water quantity is difficult to predict because 

it is likely to change from well to well over time. Conventional wells typically yield more 

water as production progresses, while non-conventional plays, such as CBNG, may yield 

less water as production progresses. Regardless, understanding the water quality and 

quantity of a site is important when determining an appropriate water management 

practice.

Socio-economic and Political Setting – Socio-economic setting can be quantified 

by population density and industrial activity. Areas with a higher population density will 

typically yield more complicated water management issues than areas of low population 

density, and areas with a high level of industrial activity might have use for water that 

is low in quality, or water demand may be high enough to offset the cost to treat the 

water to a usable level. Political setting is a concept that is best considered 

qualitatively; however, it can be noted that regions where split estate is common, (i.e. 

surface ownership has been severed from mineral ownership) the political setting can 

be detrimental for oil and gas development as the produced water management options 

may be limited by legal issues. 

Climate Zones – Annual rainfall and evapotranspiration (ET) are two elements of the 

weather that may play a role in the effectiveness of different produced water 

management practices. In areas where the average rainfall is close to, or less than, the 

average ET, produced water beneficial use (for produced water less than 10,000 mg/L 

TDS) can help to sustain farmers and ranchers through irrigation and water supply for 

livestock. Furthermore, these areas might be able to capitalize on marginal produced 

water (with a TDS less than 50,000 mg/L) by treating the water for beneficial use and 

disposing of the lower quantity waste stream. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

154

Figure 7.1 Major Hydrocarbon Producing Basins of the United States 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

155

The culmination of these issues often dictates regional-specific problems and solutions that are 

not always shared outside that region. However, various regions can benefit from sharing 

problems experienced in other regions, and how operators have met with success (and failure) 

when solutions to these problems are employed in the field. This section attempts to close the 

information gap between hydrocarbon producing regions by identifying and sharing applicable 

produced water management practices that may have implications outside of their current 

region. Furthermore, in light of recent concerns that produced water can and should be treated 

as a resource rather than as a waste, this section provides a forward looking discussion in terms 

of treating and beneficially using produced water of marginal quality (i.e. with a TDS value 

greater than 10,000 mg/l, but less than 50,000 mg/l) versus wholesale disposal of this 

resource. 

Section 7.1 Water Quality and Quantity 

The range in water quality across the United States is great, as shown in Figure 7.2, which 

suggests that produced water has many possible origins, as described in Section 2. For 

example, large areas within the arid Great Plains and adjacent to recharge areas in the Rocky 

Mountains contain water that is low in TDS and has potential beneficial uses. The low TDS 

produced water often represents infiltrated meteoric water that enters porous strata at the 

outcrops on the edge of large basins. 

Water quality may be the single most important factor when considering the water 

management practice selected. Table 7.1 illustrates a numerical summary of the water quality 

statistical analyses in the oil and gas basins discussed in Section 6. Produced water less than 

10,000 mg/L might have significant beneficial uses for industrial and agricultural activities, and 

produced water less than 50,000 mg/L may have the potential to be treated and beneficially 

used in the same manner. Figure 7.3 is a graphical representation of the same data that shows 

how the basins compare to one another in terms of water quality. In Figure 7.3 the basins are 

ranked by percent of produced water that is either usable in the raw form (less than 10,000 

mg/L) or marginal quality water that is treatable (less than 50,000 mg/L). 

Of the basins analyzed, the following basins had a high percentage of high to marginal quality 

produced water that may be used or treated for beneficial uses: Alaska North Slope (100%), 

North Central Montana (99%), Bighorn (99%), Wind River (99%), Alaska Cook Inlet (99%), 

Powder River (93%), and Greater Green River (88%). The Arkoma Basin has a moderate 

percentage of usable or treatable water (42%). In many instances, the water from these 

basins is already being put to beneficial uses such as irrigation, stock and wildlife watering, 

supplemental public water supply, and fish hatcheries, to name a few. However, the actual 

implementation of these beneficial uses might not be realized to the fullest extent possible for a 

number of reasons (i.e. regulatory barriers, public outcry, economic barriers). It is important 

for produced water that is fresh or marginal in quality be recognized and utilized as a resource 

across the entire United States, especially in arid regions where water is not always in 

abundance.

Water with salinity above 50,000 mg/L is either cost prohibitive or technologically incapable of 

being treated for traditional beneficial uses. However, this water can be used for enhanced 

recovery water injection projects or recycled for multiple hydraulic fracturing jobs. As discussed 

in Section 6, this is a common practice is most basins, and more notably so in older fields that 

have been exploited for many years. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

156

Figure 7.2 Total Dissolved Solids of Produced Water in the United States
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

157

Table 7.1 Summary of Produced Water Quality Statistics 

Produced Water Quality Percentage for Ranges (mg/L TDS) 

Basin Name 0 – 

9,999

10,000 – 

49,999

50,000 – 

99,999

100,000 – 

199,999

200,000 – 

460,000

Alaska North Slope 8 92 0 0 0

Alaska Cook Inlet 51 48 1 0 0

Anadarko Basin 4 25 15 28 28

Arkoma Basin 23 19 18 39 1

Bighorn Basin 79 20 1 0.4 0.04 

Fort Worth Basin 0 4 15 49 31

Greater Green River 65 23 8 4 0

North Central Montana 86 13 0.5 0.3 0.5 

Permian Basin 6 21 29 31 13

Powder River Basin 60 33 3 4 0.8

Williston Basin 10 16 13 19 41

Wind River Basin 75 24 0.8 0.6 0.08 

Figure 7.3 Water Quality Statistical Analysis of Select Oil and Gas Basins

100 99 99 99 99

93

88

42

29 27 26

4 0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Alaska

North

Slope

North

Central

Montana

Bighorn Wind

River

Alaska

Cook Inlet

Powder

River

Greater

Green

River

Arkoma Anadarko Permian Williston Fort

Worth

Basin

Percent of Water in TDS Range

<9,999 (fresh/brackish) 10,000-49,999 (low/moderate saline)

50,000-99,999 (moderate/high saline) 100,000-199,999 (low/moderate brine)

200,000-460,000 (brine) Percent Useable/Treatable for Beneficial Use
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

158

Water quantity also can play a role in deciding how best to manage produced waters. Some 

potential industrial applications of produced water, such as cooling water for a power 

generation facility, need a reliable source of water in terms of daily quantity, longevity, and 

quality. Some industrial sites would prefer to pay for a reliable source of water that they know 

will be available to them rather than rely on a free source of water that may diminish or be cut 

off over time. This stems from the fact that water quantities are highly variable from field to 

field; therefore making broad generalizations about water quantities for different basins is not 

recommended. Furthermore, the dynamics of produced water quantities can vary as the field is 

developed. Conventional fields typically yield more water as production progresses, while nonconventional plays such as CBNG might yield less water as production progresses. However, 

operators can develop a site-specific understanding of their projected water quantities by 

tracking the water they produce, and therefore instill a better understanding of their water 

management options that can utilize the water in a beneficial manner and be more economical 

in the future. 

Section 7.2 Socio-Economic Setting 

The socio-economic setting of a region can influence the options for how produced water is 

managed in that region. For purposes of exploring this idea further, socio-economic setting is 

quantified by population density and potential industrial uses. Areas with a higher population 

density typically will yield more complicated water management issues than areas of lower 

population density; however, the high population density areas may have a greater demand for 

water supply. Figure 7.4 provides a geographical distribution of water that is generally 

considered treatable (TDS < 50,000 mg/L) and population density across the contiguous United 

States. Areas can be identified from this map that might provide suitable water management 

solutions in high population areas. For example, the city of Denver is located near sources of 

usable and treatable produced water. 

The impact of socio-economic setting is also evident when dealing with low quality water in 

areas such as the de-watering project in the Oklahoma City field of the Anadarko basin and the 

Barnett Shale play in and around Fort Worth, Texas. Surface use of the land in these densely 

populated areas precludes the drilling of wells at several well pad sites. Rather, multiple 

horizontal wells can be drilled from one well pad in various horizontal directions, which in turn 

can raise the costs of drilling when compared to similar projects in rural Oklahoma and Texas. 

In the Anadarko Basin the water is either re-injected for enhanced recovery, or it is injected into 

a horizontal disposal well capable of handling more than 60,000 barrels of water per day. In 

the Barnett Shale play the water may be recycled for use on fracturing additional wells in the 

area, thus saving the operator money on the cost of water for the fracture job, and saving local 

residents the burden on their local water supply. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

159

Figure 7.4 Oil and Gas Basins compared to Population Density of the Contiguous United 

States
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

160

Another factor that population density can be a predictor of is qualified and available work 

force. In general, highly populated areas have a larger pool of potential workers, and therefore 

it can be easier to find a suitable labor force. Rural areas may not have immediate work force 

available, which in turn can raise the cost of a drilling program if the work crew is transported 

in from another region. This does not necessarily impact the water management options 

available, but it can impact the overall cost of the drilling program, which indirectly can impact 

the ability to economically treat and beneficially use produced water of marginal quality. 

In regions where split estate is a common occurrence, (i.e. surface ownership has been severed 

from mineral ownership) the political setting might be unfavorable for oil and gas development 

because the produced water management options might be limited by legal issues between 

surface and mineral owners. This has been an issue with the CBNG resources in the Powder 

River Basin of Montana where federal mineral ownership is a common occurrence. 

Section 7.3 Annual Rainfall and Evapotranspiration 

Annual rainfall and evapotranspiration (ET) are two elements of the weather that can play a 

role in the effectiveness of different produced water management practices. Figures 7.5 and 

7.6 provide estimates for the annual average rainfall and annual average lake evaporation 

rates, and Figure 7.7 provides a state-by-state estimate of the water available for ET in the 

United States. The water available for ET was calculated on a state-by-state basis by examining 

statewide water budgets: 

Precip. + Surf. In-flow – Surf. Out-flow –Consumption = Water Available for ET 

These figures can be used together to identify areas with a net zero or negative supply of 

water. For example, in the Big Horn and Powder River Basins the annual lake evaporation is 

between 40 and 50 inches per year (Figure 7.6); however, there is less than 10 inches per year 

available for ET (Figure 7.7). Therefore, the region in general is in need of water for irrigation 

as the evaporation rate is 4 to 5 times greater than the water available for ET. 

If the produced water in these water starved areas is sufficient in quality for beneficial use (TDS 

less than 10,000 mg/L) the water can help to sustain farmers and ranchers through irrigation 

and water supply for livestock. Furthermore, these areas also might have the ability to use 

produced water that is marginal in quality (TDS less than 50,000 mg/L) by treating the water 

for beneficial use and disposing of a lower quantity waste stream. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

161

Figure 7.5 Annual Average Rainfall in the Contiguous United States and Alaska 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

162

Figure 7.6 Annual Average Lake Evaporation in the United States
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

163

Figure 7.7 Annual Average Water Available for Evapotranspiration in the United States
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

164

The arid Western states provide several other examples where evaporation rates far exceed the 

water available for ET. In general, the water available for ET in these states is less than 10 

inches per year; however, several basins intersect areas where evaporation is as high as 60 

inches per year and rainfall is not more than 20 inches per year. These include several basins 

where beneficial uses of the water are common, and have been for several years, such as the 

Big Horn Basin, the North Central Montana Basin, the Powder River Basin, and the San Joaquin 

Basin in California. Other areas that might not be as obvious include the Arkoma Basin of 

Arkansas and Oklahoma. The water available for ET (25-35 inches per year) is relatively high, 

but when compared to the average annual lake evaporation (between 40 and 60 inches per 

year) a potential need for irrigation water can be identified because the evaporation rate can be 

as much as twice the amount available for ET. Furthermore, the water quality in some portions 

of the Arkoma Basin is of sufficient quality for beneficial uses such as flood irrigation and 

livestock watering; however, a large percentage of this high quality water is being disposed of 

in commercial disposal wells. BP has initiated a pilot program to use this water beneficially in 

coordination with the Oklahoma Corporation Commission and the local landowners in the Red 

Oak field. Similar programs may be feasible in the basin where water can be economically 

managed while providing an asset to landowners. 

Historic annual precipitation and evapotranspiration ratios have changed in the past few years 

with a widespread drought in the upper Great Plains (Handwerk, 2005). This drought has 

lowered average annual precipitation and could be a cyclic phenomenon or a manifestation of 

Global Climate Change (Linden, 2006). Over the last century, the average temperature in 

Laramie, Wyoming, has increased 1.5°F. Precipitation has decreased by up to 20% in many 

parts of the state. Over the 21st Century, climate in the Great Plains may change even more 

due to the increases in greenhouse gases. By 2100, for example, temperatures in Wyoming 

could increase by 4°F in spring and fall, 5°F in summer, and 6°F in the winter. If temperatures 

and evaporation increase as forecast and the drought continues, surface water resources could 

be reduced drastically across the Great Plains. This could lead to severe competition for 

groundwater resources, including lesser quality groundwater that may require pre-use 

treatment. 

If this drought is a long-term climatic development for the Great Plains and adjacent areas, 

potential beneficial uses for produced water gain importance. If precipitation is indeed to be 

lower throughout the future, produced water may become valuable for augmenting base-flow in 

streams and supplying water to cities and towns. Competition for scarce water resources might 

lead to increased value for higher quality produced water and may lead to large scale treatment 

of lower quality water prior to its use. Important uses might include protection of habitat 

within the riparian zone, supplement to irrigation and animal husbandry, or supplement to 

drinking water systems in towns and cities of the Great Plains. If global climate change is 

occurring, beneficial use of the water produced with oil and gas will become more important. 

Section 7.4 Potential for New and Innovative Beneficial Uses 

As previously mentioned, the culmination of water quality, quantity, socio-economic setting, and 

climatic conditions often lead to the development of regional-specific produced water 

management solutions. The potential exists for implementing new and/or innovative 

management solutions for produced water by identifying and sharing applicable produced water 

management practices that may have implications outside of their current region. The purpose 

of this document is to serve as a tool for achieving this goal. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

165

In light of recent drought concerns and water shortages in many western states, produced 

water can be treated as a resource rather than as a waste product. In Section 7.2, basins were 

identified where a large portion of the produced water had quality that is currently deemed as 

“usable” (TDS values <10,000 mg/l) or “treatable” (TDS values >10,000 mg/l, but <50,000 

mg/l) versus wholesale disposal of this resource. The identified basins include the Alaska North 

Slope, North Central Montana, Bighorn, Wind River, Alaska Cook Inlet, Powder River, Greater 

Green River, and the Arkoma. Basins identified as having a small percentage of beneficially 

usable or treatable water were the Anadarko, Permian, Williston, and Fort Worth, where the 

current practice of injection, whether it be for enhanced oil recovery, or strictly for disposal, 

seem to be the most practical options in these basins. Furthermore, of the basins with a large 

percentage of beneficially usable or treatable water, the socio-economic setting and climatic 

conditions were not favorable for taking advantage of the quality of the water in the two 

Alaskan basins (North Slope and Cook Inlet). 

Marginal to Low Quality Water Basins 

The Anadarko, Permian, Williston, and Fort Worth Basins fall within a scattering of population 

and industry ranging from large cities to strictly rural expanses. The precipitation regime of the 

basin is largely semiarid with an average rainfall between 15 and 30 inches per year (Figure 

7.5), suggesting that surface water is a scarce commodity in these basins. There are a number 

of population centers as shown on Figure 7.4. Besides the historic petroleum industry, other 

forms of industry would include ranching and agriculture, which use copious amounts of water. 

The relatively low quality of the produced water of the basins, however, mitigates against its 

widespread use even for livestock watering. With low percentages of the reported produced 

water samples having less than 10,000 mg/L, it is unlikely that water in these basins would 

have industrial uses. A large percentage of the produced water quality samples from these 

basins was of poor quality with a TDS greater than 50,000 mg/L. If technologically possible, 

the costs of treating this water would be fairly high. Most industry users would prefer to use 

higher quality groundwater obtained locally if it can be attained economically. 

Another use that may become more important if the current drought discussed in Section 7.4 

continues is that produced water could be used for brush fire control. Brush fires have become 

more prevalent in the past several years across the United States. Depending upon their 

location, the large grass-fires and the need for water to control them may place undue stress 

on local reservoirs and aquifers that may have a higher use in support of agriculture or 

municipal water supply. High quality to marginal quality water produced through oil and gas 

operations could be used for fire suppression with minimal treatment. However, the means for 

transporting that water from the producing field where it is produced to the actual location of 

the fire may prove to be logistically complicated unless plans were made in advance to use the 

water in this manner. 

High Quality Water Basins with Unfavorable Water Re-Use Conditions 

As previously mentioned, the Alaskan North Slope and Cook Inlet have high percentages of 

beneficially usable and/or treatable quality water. However, these basins have other conditions 

that are unfavorable in regards to using the produced water. The low population density and 

the less than favorable annual climatic conditions lead to the conclusion that the current 

practice of injection, whether it be for enhanced oil recovery, or strictly for disposal, may be the 

most practical for Alaskan basins. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

166

High Quality Water Basins with Favorable Water Re-Use Conditions 

By considering water quality, socio-economic setting, and climatic conditions, the following 

basins have favorable characteristics for beneficially using produced water: North Central 

Montana, Bighorn, Wind River, Powder River, Greater Green River, and the Arkoma. 

All of the basins in this category are almost predominantly rural with small cities dispersed 

throughout. They include some of the driest regions in the country with several locations 

averaging less than 5 inches of rain per year. In addition to the arid conditions, the basins in 

Montana and Wyoming have been in a prolonged drought since 1999 (NCDC, 2006) where 

precipitation has averaged only 84% of the historic annual value. 

In the Bighorn Basin it is mostly agricultural users and local ranchers who have come to rely 

upon produced water for irrigation. The reliance is especially important during times of drought 

when rainfall can be very low. The basin appears to produce large volumes of high quality 

water that can be used for both stock watering and irrigation. The Bighorn Basin is similar in 

characteristics to other basins in Wyoming and Montana but unlike the others it has developed 

a system for utilizing produced water in the furtherance of agriculture. Therefore, the other 

basins in Montana and Wyoming have the potential for beneficially using the produced water in 

a way that can further the ability of farmers and ranchers. 

The Arkoma Basin is spread across forested portions of eastern Oklahoma and western 

Arkansas. It is an area with small population centers and ample rainfall of 30 to 50 inches per 

year. Agriculture is the common industrial activity including confined animal feeding operations 

(CAFO). As discussed in Section 4, water requirements are greater at CAFO facilities when 

compared to range livestock; therefore, there might be a local demand for water that could be 

satisfied with produced water. The quality of the local produced water may mean that 

treatment is required and the demand for water might allow the user to pay for the treatment. 

Over 20% of the water tested from this basin is less than 10,000 mg/L and a smaller portion is 

high enough in quality to use for irrigation. These minor volumes of produced water have 

begun to play a local role in the Red Oak field, but due to the low volumes of the water 

produced it appears to have minimal affect on the economics of the region. 

Population Centers Drive Water Demand 

Southern California is a good example of how high density population centers can drive water 

demand to the point that new and innovative ways to treat and use water become a necessity. 

Municipal water district planners in Southern California predict that future water supply in the 

region will fall short of urban demand by 2020 without development of new water resources 

and increased conservation savings (UCR, 1999). Figure 7.4 shows that the produced water 

generated from nearby basins, such as the San Joaquin Basin, may be of suitable quality that it 

can either be treated for human consumption or it may continue to be used for irrigation 

purposes on orchards to offset the demand for treated water. Basins upstream of Southern 

California near the Colorado River (Unita-Piceance, San Juan, Paradox) also might be suitable to 

discharge water to the Colorado River system, thus providing additional water resources to 

downstream users in California. Other potential markets that might couple well with oil and gas 

producing basins include the Denver Basin with the Denver Metro Area, the Uinta-Piceance or 

the Greater Green River Basins with the Salt Lake City metro area, and the Forest City Basin 

with the Kansas City Metro area. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

167

Section 8.0 References 

AAPG, 1992. Geothermal Map of the United States.

AAPG, 2006: Barnett Shale a Stimulating Play, in AAPG Explorer, Feb 2006. 

Alyeska Pipeline, 2006: Pipeline Facts: North Slope. accessed on March 7, 2006 @ 

http://www.alyeska-pipe.com/Pipelinefacts/North%20Slope.html.

Alaska Department of Natural Resources, 2003: Cook Inlet Oil & Gas. Department of 

Natural Resources. Division of Oil and Gas. Prepared by Tim Ryherd, Geologist, State of 

Alaska. July 29, 2003. 

Alaska Department of Natural Resources, 2004: Oil and Gas Report. Division of Oil 

and Gas. accessed at: 

http://www.dog.dnr.state.ak.us/oil/products/publications/annual/2004_annual_re

port/Section1.pdf

Alaska Department of Natural Resources, 2006: Alaska Oil and Gas Activities. 

Division of Oil and Gas. Prepared by William Van Dyke, Acting Director, Alaska 

Department of Natural Resources. January 17, 2006. Advanced Resource International 

(ARI) for the U.S. EPA, 1994, 68-W-00-094. “Fracturing Technologies for Improving 

CMM/CBNG Production”. 

ALL Consulting (ALL) and Montana Board of Oil and Gas Conservation (MBOGC), 

2002. Handbook on Best Management Practices and Mitigation Strategies for Coal Bed 

Methane in the Montana Portion of the Powder River Basin, prepared for United States 

Department of Energy – National Petroleum Technology Office, April 2002. 

ALL Consulting (ALL), July 2003. Handbook on Coal Bed Methane Produced Water: 

Management and Beneficial Use Alternatives. Prepared For the Ground Water Protection 

Research Foundation, U.S. Department of Energy - National Petroleum Technology 

Office, Bureau of Land Management. 

ALL Consulting (ALL), 2005. “Reducing Produced Water Volumes from Coal Bed Natural Gas 

in the Powder River Basin”. 

ALL Consulting (ALL), 2005. Technical Summary of Oil and Gas Produced Water 

Treatment Technologies. 

ALL Consulting (ALL), 2006. “Feasibility Study of Expanded Coal Bed Natural Gas 

Produced Water Management Alternatives in the Wyoming Portion of the Powder River 

Basin: Phase I”. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

168

ALL Consulting (ALL), 2006. “Phase One: Feasibility Study of Expanded Coal Bed Natural 

Gas Produced Water Management Alternatives in the Wyoming Portion of the Powder 

River Basin”.

ALL Consulting and MBOGC, 2004. Coal Bed Methane Primer: New Source of Natural 

Gas – Environmental Implications, Background and Development in the Rocky Mountain 

West, Prepared for: U.S. DOE National Petroleum Technology Office. 

Argonne National Laboratory, 2002. Regulatory Issues Affecting Management of 

Produced Water from Coal Bed Methane Wells, Argonne National Laboratory, prepared 

for U.S. DOE Office of Fossil Energy. 

American Petroleum Institute (API), 2006. “Where does the U.S. produce oil and 

natural gas?” Accessed online at: http://www.api.org

Aston, M.S., et al, SPE Paper 87130, March 2004. “Drilling Fluids for Well-bore 

Strengthening”. 

Barrufet M.A., Iglesias-Silva G., Petriciolet A., Patel C.V., and Burnett D., 

2004. “A Modular Design And Implementation of A Brine Conversion Process: Oil 

Removal and Desalting Units,” paper presented at the 11th IPEC, Albuquerque, NM. 

Baker, Tim, 2005. Personal conversation between Dr. Langhus and Jake Crissup of ALL 

Consulting and Tim Baker of the Oklahoma Corporation Commission. 

Ball, Mahlon, 1995. Permian Basin Province (044), in Gautier, D. L., Dolton, G.I., 

Takahashi, K.T., and Varnes, K.L., eds., 1995 National assessment of United States oil 

and gas resources--Results, methodology, and supporting data: U.S. Geological Survey 

Digital Data Series DDS-30. 

Ball, M., and W. Perry, 1995. Bend Arch-Fort Worth Basin Province (045), in Gautier, D. 

L., Dolton, G.I., Takahashi, K.T., and Varnes, K.L., eds., 1995 National assessment of 

United States oil and gas resources--Results, methodology, and supporting data: U.S. 

Geological Survey Digital Data Series DDS-30. 

Bein, A. and A. R. Dutton, 1993. Origin, distribution, and movement of brine in the 

Permian Basin: A model for displacement of connate brine. GSA Bull., vol. 105, pp. 695-

707.

Blackwell, D. D., and M. C. Richards, 2004. Geothermal Map of North America, 

scale 1:5,000,000, AAPG, Map Code #423, April 2004. 

Blackwell, D.D. et al, 2006. Geothermal Resources in Sedimentary Basins, 2006 

SMU Geothermal Conference, Dallas, March 2006. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

169

Bost A.L., and Reid T., 2004. “Powder River Gas L.L.C. Coal Creek CNBG POD – Hydrology 

Technical Report,” BLM Montana (November 2004). 

Bureau of Economic Geology, 2002. Play Analysis and Digital Portfolio of Major Oil 

Reservoirs in the Permian Basin: Application and Transfer of Advanced Geological and 

Engineering Technologies for Incremental Production Opportunities. Performed in 

cooperation with the New Mexico Bureau of Geology and Mineral Resources.

Cline, J., December 13, 2005. Personal conversation between Dr. Langhus and Jeff Cline 

of Anadarko Petroleum. 

Cohen, Y., J. Glater, A. Tsao and R-W Lee, September 9-13, 2001. "Nanofiltration 

Membranes for Agricultural Drainage Water Reclamation," Paper published in the 

proceedings of the International Conference on Membrane Technology for Wastewater 

Reclamation and Reuse, Tel-Aviv, Israel. 

Comer, J.B., 1992. Organic geochemistry and paleogeography of Upper Devonian 

formations in Oklahoma and northwestern Arkansas, in K.S. Johnson and B.J. Cardott, 

eds., Source rocks in the southern Mid-Continent, 1990 symposium: OGS Circular 93, p. 

70-93.

Davies, S. and D. Widawsky, 1995. The Impact of the Changing Size of Feedlots on 

Corn Marketing in Colorado. Journal of the American Society of Farm Managers and 

Rural Appraisers, Volume 59, No. 1: Pg 120-127. 

DeJarnett, B., F. Lim, and D. Calogero, 1997: Greater Green River Basin Production 

Improvement Project, prepared for the U.S. Department of Energy’s Federal Energy 

Technology Center and Union Pacific Resources Company. 

Dolton G., and J.E. Fox, 1995: Powder River Basin Province (033), in Gautier, D. L., 

Dolton, G.I., Takahashi, K.T., and Varnes, K.L., eds., 1995 National assessment of 

United States oil and gas resources--Results, methodology, and supporting data: U.S. 

Geological Survey Digital Data Series DDS-30.

The Dow Chemical Company (Dow), 2003. “A Low Cost Option to Reduce Sodium 

Levels in Coal Bed Methane Coproduced Wastewater using DOWEX G-26 Resin,” DOWEX 

Ion Exchange Resins. 

Doyle D.H., Daniel F., and Brown A.B., 1997. “Field Test of Produced Water Treatment 

with Polymer Modified Bentonite,” paper SPE 38353 presented at the 1997 Rocky 

Mountain Regional Meeting, Casper, Wyoming. 

Dutton, S., E. Kim, R. Broadhead, C. Breton, W. Raatz, S. Ruppel, and C. 

Kerans, 2004: Play Analysis and Digital Portfolio of Major Oil Reservoirs in the 

Permian Basin: Application and Transfer of Advanced Geological and Engineering 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

170

Technologies for Incremental Production Opportunities. Prepared by the Texas Bureau 

of Economic Geology and New Mexico Bureau of Geology and Mineral Resources. 

Dyman, T.S., 1995: North-Central Montana Province (028), in Gautier, D. L., Dolton, G.I., 

Takahashi, K.T., and Varnes, K.L., eds., 1995 National assessment of United States oil 

and gas resources--Results, methodology, and supporting data: U.S. Geological Survey 

Digital Data Series DDS-30. 

Evergreeen Resources Inc., CBM-1: A Supplement to the Oil & Gas Investor, 

December 2002. “Opportunities in CBNG”. 

Forbis, P., February 2006. Agency Approves Fluid Recycling of Frac Fluids in Pilot 

Project, in Texas Drilling Observer Newsletter, vol 7, Issue 4. 

Fox, J.E., and G. Dolton, 1995a. Bighorn Basin Province (034), in Gautier, D. L., Dolton, 

G.I., Takahashi, K.T., and Varnes, K.L., eds., 1995 National assessment of United States 

oil and gas resources--Results, methodology, and supporting data: U.S. Geological 

Survey Digital Data Series DDS-30. 

Fox, J.E., and G. Dolton, 1995b. Wind River Basin Province (035), in Gautier, D. L., 

Dolton, G.I., Takahashi, K.T., and Varnes, K.L., eds., 1995 National assessment of 

United States oil and gas resources--Results, methodology, and supporting data: U.S. 

Geological Survey Digital Data Series DDS-30. 

Funston R., Ganesh R., and Leong Lawrence Y.C., 2002. “Evaluation of Technical 

and Economic Feasibility of Treating Oilfield Produced Water to Create a “New” Water 

Resource,” paper presented at the 2002 Ground Water Protection Council (GWPC) 

meeting. 

GE Infrastructure Water & Process Technologies (GE), 2006. “Membrane 

Filtration of Oil and Gas Field Produced Water”. 

GE Infrastructure Water & Process Technologies (GE), 2001. “Produced Water 

Pilot Study”. 

Groundwater Protection Council (GWPC), 2006. About Class I Injection Wells. 

accessed on March 2, 2006. http://www.gwpc.org/UIC/Well-Types/classi.htm

Gas Technology Institute (GTI), 2002. accessed at:

http://www.gtionline.org/gti/main/main.cfm

Gibson, R.I., 1997. Greater Green River Basin: online at 

http://www.gravmag.com/grnriv.htm.

Guyer, P.Q. 1977. Water Requirements for Beef Cattle. University of Nebraska 

Cooperative Extension Service Bulletin G77-371-A. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

171

Handwerk, B, June 14, 2005. Plains Drought Cycle Has Long History, Ominous Future, 

National Geographic News

Hayes T., 2004. “The Electodialysis Alternative for Produced Water Management,” Gas 

Technology Institute (2004). 

Hayter S., Tanner S., Urbatsch E., and Zuboy J., June 2004. “Saving Energy, 

Water, and Money with Efficient Water Treatment Technologies,” DOE/EE-0294, A New 

Technology Demonstration Publication, Federal Energy Management Program. 

Heck, Thomas J., R.D. LeFever, D.W. Fischer, and J. LeFever, 2002. Overview of 

the Petroleum Geology of the North Dakota Williston Basin, N.D. Geological Survey 

Heins W., and Peterson D., June 2003. “Use of Evaporation for Heavy Oil Produced 

Water Treatment”, a paper presented at the 4th Canadian International Petroleum 

Conference held in Calgary, Canada. 

Henry, M. and T. Hester, 1995. Anadarko Basin Province (058), in Gautier, D. L., Dolton, 

G.I., Takahashi, K.T., and Varnes, K.L., eds., 1995 National assessment of United States 

oil and gas resources--Results, methodology, and supporting data: U.S. Geological 

Survey Digital Data Series DDS-30. 

Hernon B., Zanapalidou H., Prato T., and Zhang L., 1999. “Removal of WeaklyIonized Species by EDI,” Ionics Inc. 

Hutchinson, W., November 21, 2005. Personal conversation between Dr. Langhus and 

Wendy Hutchinson of Arch Coal Company. 

Hunt, J. M., 1979. Petroleum Geochemistry and Geology: W. H. Freeman and Sons, San 

Francisco, 617. 

Interstate Oil and Gas Compact Commission (IOGCC), 2005. “Marginal Oil and 

Natural Gas : American Energy for the American Dream” 

Jackson, L., and J. Myers, October 16-17, 2002. “Alternative Use of Produced Water 

in Aquaculture and Hydroponic Systems at Naval Petroleum Reserve No. 3,” presented 

at the 2002 Ground Water Protection Council Produced Water Conference, Colorado 

Springs, CO. (Paper available at http://www.gwpc.org/Meetings/PW2002/PapersAbstracts.htm.)

Jackson, L.M., and J.E. Myers, October 2003. “Design and Construction of Pilot 

Wetlands for Produced Water Treatment,” SPE 84587, presented at the SPE Annual 

Technical Conference and Exhibition, Denver, CO. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

172

Kansas State University (KSU), November 2005. Kansas State University Research 

and Extension Department Website http://www.oznet.ksu.edu/sdi/Photos/Photos.htm.

Karlstrom, Thor N.V., 1964: Quaternary Geology of the Kenai Lowland and Glacial History 

of the Cook Inlet Region, Alaska. U.S. Department of the Interior. Geological Survey 

Professional Paper-443. 

Lang K., 4th Quarter 2000. “Managing Produced Water”, Hart Energy Publications 

Excerpts in Petroleum Technology Transfer Council Network News. 

Law, Ben E., 1995, Southwestern Wyoming Province (037), in Gautier, D. L., Dolton, G.I., 

Takahashi, K.T., and Varnes, K.L., eds., 1995 National assessment of United States oil 

and gas resources--Results, methodology, and supporting data: U.S. Geological Survey 

Digital Data Series DDS-30. 

Lawson, J., November 18, 2005. Personal conversation between Dr. Langhus and John 

Lawson of the United States Bureau of Reclamation. 

Lincz R., December 2004. “Newpark’s HB Reactor Water Treatment Technology Used for 

Anadarko Coal Bed Methane Produced Water Treatment for Discharge County Line 

Production Field”, prepared by Newpark Environmental Services for DEQ-Water Quality 

Division.

Linden, E. 2006. The Winds of Change, Simon and Schuster, New York. 

Marriage, L.D., Davison, V.E., 197.. Fish Ponds-Construction and Management. in: 

Teague, R.D., ed. A Manual of Wildlife Conservation. Washington D.C.. The Wildlife 

Society: 100-102. 

“Membrane Filtration,” Tech Brief, National Drinking Water Clearinghouse Fact Sheet 

(1999).

Mickley M., September 2001. “Membrane Concentrate Disposal: Practices and 

Regulation”, prepared by Mickley & Associates for U.S. Department of The Interior under 

agreement no. 98-FC-81-0054, Desalination and Water Purification research and 

Development Program Report No. 69. 

Moftah K., October 2002. “High pH RO for Wastewater Treatment,” Pollution Engineering. 

Murphree, P., 2005. Personal conversation between Dr. Langhus and Mr. Murphree of 

Peabody Coal Company. 

Myers J.E., Jackson L.M., Bernier R.F., and Miles D.A., 2001. “An Evaluation of the 

Department of Energy Naval Petroleum Reserve No. 3 Produced Water Bio-Treatment 

Facility,” paper SPE 66522 presented at the 2001 SPE/EPA/DOE Exploration and 

Production Environmental Conference, San Antonio, Texas. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

173

Mast, R.F., Root, D.H., Williams, L.P., Beeman, W.R., and Barnett, D.L., 1998.

Areas of historical oil and gas exploration and production in the conterminous United 

States: U.S. Geological Survey Geologic Investigations Series I-2582, one sheet.

McLelland, P. and Hawkes, C., October 2002. “Assessing Bore-hole Instability Risks 

for Horizontal Wells in Coals and Fractured Shales”. 4th Annual Unconventional Gas and 

CBM Conference, Calgary 

Montana Board of Oil and Gas (MBOGC), 2005. Montana Board of Oil and Gas 

 Conservation online database, http://bogc.dnrc.state.mt.us/OnlineData.htm

Montana Board of Oil and Gas (MBOGC), 2006. Data compilation and analysis. 

NCDC, March 2006. Climate of 2005 - June , Wyoming Division 4 Drought, National Climate 

Data Center website, 

http://www.ncdc.noaa.gov/oa/climate/research/2005/jun/st048dv04pcp200506.html

New Logic Research, 2003. “Using VSEP to Treat Produced Water – An effective and 

economical solution”. 

Nicot Jean-Philippe, and Dutton A.R., September 2004. “Please Pass the Salt: 

Using Oil Fields for the Disposal of Concentrate from Desalination Plants,” a report 

presented to the U.S. Bureau of Reclamation. 

Olson, J., November 8, 2005. Personal conversation between Dr. Langhus and Joe Olson 

of Williams Production. 

Oil & Gas Accountability Project, April 2004. “Oil and Gas at Your Door – A 

Landowner's Guide to Oil and Gas Development”. 

Perry, William J., 1995. Arkoma Basin Province (062), in Gautier, D. L., Dolton, G.I., 

Takahashi, K.T., and Varnes, K.L., eds., 1995 National assessment of United States oil 

and gas resources--Results, methodology, and supporting data: U.S. Geological Survey 

Digital Data Series DDS-30. 

Peterson, James A., 1995. Williston Basin Province (031), in Gautier, D. L., Dolton, G.I., 

Takahashi, K.T., and Varnes, K.L., eds., 1995 National assessment of United States oil 

and gas resources--Results, methodology, and supporting data: U.S. Geological Survey 

Digital Data Series DDS-30. 

Proctor, B.R., Thompson, R.W., Bernin, J.E. et al, 1983. Practices for Protecting and 

Enhancing Fish and Wildlife on Coastal Surface Mined land in The Powder River-Ft. 

Union Region. United States Department of the Interior, Fish and Wildlife Service, 

FWS/OBS-83/10: 246. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

174

Reynolds Rodney R., 2003. “Produced Water and Associated Issues,” a manual for 

independent operator, Petroleum Technology Transfer Council.

Rumble, Mark, 1989. United States Department of Agriculture Forest Service, Surface Mine 

Impoundments as Wildlife and Fish Habitat. 

Rushworth, S. and M. Manning, Decmeber 12, 2005. Local Play Brings Business and 

New Technology, in Fort Worth Business Press. 

Saikat, Mazumder and Karl-Heinz, Wold A., Third Quarter, 2004. “A Different 

Direction for CBNG Wells”. Weatherford W Magazine. 

Stutz, Lloyd and Fisher, Kevin, PTTC Archive, June 2004. “Fracture mapping and 

modeling optimize CBNG fracture treatments”. 

Sattler A., Hightower M., Nenoff T., Pless J., Phillips M., Brister B., Arnold R., 

Cather M., and McPherson B., 2004. “Managing Coal Bed Methane Produced 

Water for Beneficial Uses, Initially Using The San Juan and Raton Basins as a Model”, 

Interim Progress Report prepared for NETL, Sandia National Laboratory. 

Shultz, J., December 9, 2005. Personal conversation between Dr. Langhus and John 

Shultz of Basin Electric Power Coop. 

Smith K.P., Williams G.P., Blunt D.L., and Arnish J.J., 1997. “Radiological Dose 

Assessment of NORM Disposal in Class II Injection Wells,” U.S. DOE contract W-31-109-

Eng-38.

Southwest Energy Company, February 2006. Home Page/Operations/Fayetteville 

Shale Gas, http://www.swn.com/

Spitz L.R., 2003. “Advanced Mobile Water Treatment Systems for Treating Coal Bed 

Methane Produced Water,” a paper presented at the 2003 Ground Water Protection 

Council meeting. 

Stafford, B., December 9, 2005. Personal conversation between Dr. Langhus and Bill 

Stafford of Basin Electric Power Coop 

Stearns, M., November 11, 2005. Personal conversation between Dr. Langhus and Marty 

Stearns of Kennecott Energy Company. 

The Tenorm Page, 2004. “Mobilization and Redeposition of NORM”. 

Texas Commission of Environmental Quality (TCEQ), January 24, 2006.

Personal communication between Jake Crissup of ALL Consulting and Bryan Smith of 

TCEQ.
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

175

Thomsen, Paul, A., 2006. New Technologies for Modular Geothermal Power Plants in 

Oil and Gas Settings, 2006 SMU Geothermal Conference, March 2006.

Turner W., 2002. “Report on Treatment of Power Plant Waste Water Using The Aquasonics 

Rapid Spray Desalination Process,” WestWater Resources, NM. 

United States Department of Agriculture and National Resource Conservation 

Service (NRCS), 1982. Agriculture Handbook Number 590, Ponds – Planning, 

Design, Construction. Revised 1997. 

United States Department of Energy Office of Fossil Energy and National 

Energy Technology Laboratory-Strategic Center for Natural Gas, 

DOE/NETL-2003/1193, September 2003. “Multi-Seam Well Completion 

Technology: Implications for Powder River Basin Coalbed Methane Production”. 

United States Department of Energy (DOE), 2006. “Oil and Natural Gas Supply,

Technology Transfer.” Accessed online at: http://www.netl.doe.gov

United States Energy Information Administration (EIA), 2006. “United States 

Crude Oil and Natural Gas Supply & Disposition”. Accessed online at: 

http://www.eia.doe.gov 

United States Environmental Protection Agency (EPA), September 1988.

Climate Change and Wyoming, EPA 236-F-98-007n. 

United States Environmental Protection Agency (EPA), 1991. Industrial Surface 

Impoundment Study in the United States. EPA 530-R-01-005. Washington, DC. 

United States Environmental Protection Agency (EPA), September 1999. “Class 

V Underground Injection Control Study”, U.S. EPA/816-R-99-014. 

United States Environmental Protection Agency (U.S. EPA), September 2000. 

“Wastewater Technology Fact Sheet – Trickling Filters,” 832-F-00-014. 

United States Environmental Protection Agency (EPA), March 2001a. Class I 

Underground Injection Control Program: Study of the Risks Associated with Class I 

Underground Injection Wells. EPA 816-R-01-007 

United States Environmental Protection Agency (EPA), April 2001b. “EPA 

Proposes to Continue with its Existing Approach for Managing Class V Injection Wells”. 

Accessed online at: http://www.epa.gov/safewater/uic/classvdetermination.html

United States Environmental Protection Agency (EPA), 2004. Water Permitting 

101, NPDES Permit Program Basics, available on the U.S. EPA website at 

http://www.epa.gov/npdes/pubs/101pape.pdf
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

176

United States Environmental Protection Agency (EPA), 2005a, Overview of 

Current Total Maximum Daily Load- TMDL- Program and Regulations, available on the 

U.S. EPA website at http://www.epa.gov/owow/tmdl/overviewfs.html

United States Environmental Protection Agency (EPA), 2005b, Underground 

Injection Control Program, available on the U.S. EPA website at 

http://www.epa.gov/safewater/uic/index.html

United States Environmental Protection Agency (EPA), February 14, 2005.

“Oil and Gas Injection Wells (Class II)”. Accessed online at: 

http://www.epa.gov/safewater/uic/classii.html

United States Environmental Protection Agency (EPA), March 1, 2006.

Underground Injection Control Program. Deep Wells (Class I). Accessed. 

http://www.epa.gov/OGWDW/uic/classi.html

United States Fish and Wildlife Service (U.S. Fish and Wildlife), October 2002.

Buffalo Lake National Wildlife Refuge. 

http://southwest.fws.gov/refuges/texas/buffalo.html.

United States Geological Survey (USGS), December 2004. “A Tapestry of Time 

and terrain: The Union of Two Maps – Geology and Topography” 

http://tapestry.usgs.gov/physiogr/physio.html.

United States Geological Survey (USGS), April 2002. “Produced Waters Database” 

Accessed online at: http://energy.cr.usgs.gov/prov/prodwat/intro.htm

United States Geological Survey (USGS), May 2002. United States Geological Survey 

Produced Waters Database, compiled by George N. Breit, Provisional Release, online at: 

http://energy.cr.usgs.gov/prov/prodwat/index.htm

United States Geological Survey (USGS), December 2004. “A Tapestry of Time 

and terrain: The Union of Two Maps – Geology and Topography” 

http://tapestry.usgs.gov/physiogr/physio.html

United States Geological Survey (USGS), 2005. United State Geological Survey 

National Oil and Gas Assessment, online at: http://energy.cr.usgs.gov/oilgas/noga/

United States Geological Survey (USGS), 2005. United States Geological Survey 

 National Oil and Gas Assessment Interactive Map Page, online at: 

 'http://certmapper.cr.usgs.gov/noga/servlet/MapWindowServ 

University of California Riverside (UCR), August 1999. “California Water Demand 

Snapshot”, UCRTRAC Newsletter 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

177

Veil, J. A., February 1997. Surface Water Discharge from Onshore Stripper Wells, 

Prepared for United States Department of Energy, Office of Fossil Energy. 

Veil, J.A., Langhus, B.G., and Belieu, S., January 1999. “Feasibility Evaluation of 

Downhole Oil/Water Separation Technology,” U.S. DOE Report. 

Veil, J.A., Puder M.G., Elcock D., and Redweik R. Jr. J., January 2004. “A White 

Paper Describing Produced Water from Production of Crude Oil, Natural Gas, and Coal 

Bed Methane,” USDOE, W-31-109-Eng-38. 

Wallace, W. K., and C. L. Hanks, 2005. Structural Geology of the Brooks Range. 

University of Fairbanks. Department of Geology and Geophysics. Accessed at: 

http://www.uaf.edu/geology/Research/research/structure.html.

Williams, B., 2005. Personal conversation between Dr. Langhus and Bruce Williams of 

Fidelity. 

Wyoming Department of Environmental Quality (WDEQ), 2001, Chapter 1 

Wyoming Water Quality Rules and Regulations; Wyoming Surface Water Quality 

Standards, Wyoming Department of Environmental Quality-Water Quality Division. 

Wyoming Department of Environmental Quality (WDEQ), 2005a, Chapter 1 

Wyoming Surface Water Quality Standards, Draft Three of the proposed changes to the 

Chapter 1 Regulations. 

Wyoming Department of Environmental Quality (WDEQ), December 2005b,

Personal communication between Heidi Kaiser of ALL Consulting and Jason Thomas of 

WDEQ.

Wyoming Oil and Gas Conservation Commission (WOGCC), June 27, 2005.

Personal communication between Jake Crissup of ALL Consulting and Craig Eggerman of 

WYOGCC. 

Wyoming Oil and Gas Conservation Commission (WOGCC), 2006. Online 

 Production Data available at: 

http://wogcc.state.wy.us/grouptrpMenu.cfm?Skip='Y'&oops=49.

Zupancic, J., October 31, 2005. Personal conversation between Dr. Langhus and John 

Zupancic of BeneTerra. 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

178

THIS PAGE INTENTIONALLY LEFT BLANK 
A Guide to Practical Management of Produced Water from Onshore Oil and Gas Operations in the United States 

179

 Appendix A – Site Visit Summaries 
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

SITE INFORMATION

OFFICE ADDRESS: VARIOUS SITES VISITED 

CITY: GARDEN CITY STATE: KS__ COUNTY: FINNEY, HASKELL________ 

BASIN: HUGOTON_________FIELD: STEWART____

CONTACT NAME/TITLE: PETE KUNEYL – PRODUCTION FOREMAN/ PETROSANTANDER

CONTACT NUMBER: (620)275-2388 

CONTACT NAME/TITLE: JIM HOLLAND & KEN JELHICK/ REGULATORY TECHNICIANS-KCC

CONTACT NUMBER: (620)225-8888 

WATER MANAGEMENT TECHNOLOGIES/PRACTICES IN PLACE

DESCRIPTION: THE FIRST SITE VISITED WAS THE PETROSANTANDER WATER FLOOD IN THE 

STEWART FIELD JUST NORTHEAST OF GARDEN CITY A FEW MILES. PETROSANTANDER 

TOOK THE WATER FLOOD OVER ABOUT 10 YEARS AGO, AND HAS WORKED WITH THE DOE

AND KANSAS GEOLOGICAL SURVEY (KGS) TO STUDY THE FLOOD AND IMPROVE 

EFFICIENCIES. IN TERMS OF WATER MANAGEMENT, PETROSANTANDER REINJECTS 100% OF 

THE WATER PRODUCED BACK INTO THE MORROW FORMATION FOR ENHANCED RECOVERY.

PRIOR TO REINJECTION THE WATER IS FIRST RUN THROUGH A PHASE SEPARATOR, WHICH 

SEPARATES THE WATER FROM THE OIL AND GAS. CHEMICAL AMENDMENTS ARE THEN

ADDED TO THE WATER (SCALE AND BACTERIA INHIBITORS) AND IT IS PUMPED TO A SERIES 

OF TANKS. THE WATER IS PUMPED CENTRIFUGALLY INTO THE TANKS TO PREVENT 

STAGNATION AND INCREASE RESIDENCE TIME IN EACH TANK. OIL IS SKIMMED OUT OF EACH 

TANK, AS NECESSARY. THE WATER IS THEN PUMPED THROUGH A 50 MICRON SOCK FILTER 

TO REMOVE SOILDS THAT MAY PLUG THE REINJECTION WELLS. THE WATER IS PUMPED 

BACK OUT INTO THE FIELD AND REINJECTED ALONG WITH ANY MAKEUP WATER THAT IS 

ADDED AS NECESSARY.

THE SECOND SITE VISITED WAS A WATER FLOOD OPERATED BY CHESAPEAKE. A NEARBY 

WELL (ONCE OPERATED BY MESA AND BOUGHT BY PIONEER) THAT WAS NOT PLUGGED 

PROPERLY HAD SEEPED SALTWATER INTO THE OGALLALA AQUIFER, WHICH IS A MAJOR 

DRINKING WATER AQUIFER. IN ORDER TO CONTAIN THE SALTWATER SEEP, SEVERAL WELLS 

WERE INSTALLED TO CAPTURE THE SALTWATER AND THEN REINJECT THE CONTAMINATED 

WATER AT A CENTRAL INJECETION WELL INTO A DEEPER AQUIFER. THE CENTRAL INJECTION

WELL WAS PRESSURING UP, AND THEREFORE PIONEER WAS LOOKING TO CONTRUCT A 

SECOND INJECTION WELL. CHESAPEAKE WAS LOOKING TO INSTALL SEVERAL MORE WATER 

SUPPLY WELLS TO SUPPLY WATER TO THEIR WATER FLOOD. INSTEAD, PIONEER WAS ABLE 

TO SUPPLY CHESAPEAKE WITH THE OGALLALA WATER, AND PREVENT THE NEED FOR A 

SECOND INJECITON WELL, AND CHESAPEAKE DID NOT HAVE TO BUILD ADDITIONAL WATER 
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

SUPPLY WELLS. CHESAPEAKE CURRENTLY USES ABOUT 2,200 BBLS/DAY OF THE 

CONTAMINATED OGALLALA WATER TO 1,400 BBLS/DAY OF WATER FROM SUPPLY WELLS.

THE THIRD SITE VISITED WAS A SERIES OF COMMERCIAL DISPOSAL WELLS. EACH DISPOSAL 

WELL CONSISTED OF A SERIES OF TANKS THAT ARE USED TO STORE THE WATER AS IT IS OFF 

LOADED FROM HAUL TRUCKS, AND SEPARATES ANY REMAINING OIL FROM THE WATER. THE 

WATER IS TYPICALLY STORED AT THE WELL HEAD IN CLOSED TANKS THAT MINIMIZE 

EVAPORATION (CRYSTALIZATION IS A CONCERN DUE TO HIGH TDS VALUES IN WATER) AND 

PREVENT WILDLIFE FROM COMING IN CONTACT WITH THE HIGH TDS WATER.

ENVIRONMENTAL IMPACTS/BENEFITS: OTHER THAN ENHANCED RECOVERY/WATER FLOOD,

THERE ARE NO KNOWN BENEFICIAL USES FOR THE LOW QUALITY PRODUCED WATER IN

WESTERN KANSAS. THE ONLY OTHER OPTION IS TO DISPOSE OF THE WATER IN DISPOSAL 

WELLS.

APPLICABILITY: ENHANCED RECOVERY/WATER FLOODING IS APPLICABLE WHERE THE 

QUALITY OF THE PRODUCED WATER IS LOW (AKA HIGH TDS) AND THE NEED FOR ENHANCED 

RECOVERY IN PRESENT DUE TO THE NATURE OF MATURE OIL AND GAS FIELDS.

COST: NO INFORMATION WAS COLLECTED ON COST.

ADDITIONAL NOTES: NONE

DATE: 7/29/2005____ INFORMATION COLLECTED BY:_JAKE CRISSUP
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

PHOTO LOG

VIEW OF A THREE PHASE SEPARATOR TANK AT PETROSANTANDER

VIEW OF THE CHEMICAL INJECTION TANKS THAT TREAT THE WATER BEFORE STORAGE
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF THE STORAGE TANKS AND ONE OF THE PUMPS

VIEW OF THE SOCK FILTER THAT REMOVES SOLIDS FROM THE WATER BEFORE REINJECTION
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF THE HEATER TREATER THAT SEPARATES THE WATER FROM THE OIL

VIEW OF A WATER SUPPLY WELL THAT PROVIDES MAKEUP WATER
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF A TYPICAL PRODUCTION WELL

VIEW OF A PROGRESSIVE CAVITY PUMP AT A PRODUCTION WELL HEAD
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF A TYPICAL STORAGE TANK AT A WELL HEAD

VIEW OF THE STORAGE TANKS THAT ARE USED IN THE REMEDIATION OF CONTAMINATED 

WATER
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF STORAGE TANKS AT A COMMERCIAL DISPOSAL SITE

VIEW OF A COMMERCIAL DISPOSAL WELL HEAD
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

SITE INFORMATION

OFFICE ADDRESS: PO BOX 1645

CITY: HAVRE STATE: MT COUNTY: BLAINE

BASIN: BATTLE CREEK_________FIELD: NORTH BATTLE CREEK____

CONTACT NAME/TITLE: MARK HEDSTROM/ FIELD SUPERVISOR – HELIS OIL AND GAS

CONTACT NUMBER: (406)357-3639

CONTACT NAME/TITLE: GARY KLOTZ/ FIELD INSPECTOR – MBOGC

CONTACT NUMBER: (406)698-4871

WATER MANAGEMENT TECHNOLOGIES/PRACTICES IN PLACE

DESCRIPTION: VISITED TWO CENTRALIZED EVAPORATION/AERATION PITS AND SEVERAL 

WELL SITES THAT HAVE BOTH LINED AND UNLINED EVAPORATION/AERATION PITS 

ADJACENT TO THE WELL HEADS. THE PRODUCING GAS WELLS (APPROXIMATELY 130 WELLS 

OPERATED BY HELIS) DISCHARGE WATER DIRECTLY TO A PIT ADJACENT TO THE WELL HEAD.

PITS THAT ARE MORE REMOTE (IE NOT EASILY ACCESSIBLE WITH A VACUUM TRUCK) HAVE 

LARGER PITS ADJACENT TO THE WELL HEAD AND AERATORS IN THE PIT TO ENHANCE 

EVAPORATION. THIS MINIMIZES THE NEED TO HAUL THE WATER AWAY. FOR LINED AND 

UNLINED PITS THAT HAVE A SMALLER CAPACITY, VACUUM TRUCKS ARE EMPLOYED ON AN 

AS NEEDED BASIS TO HAUL THE WATER TO A CENTRAL EVAPORATION/AERATION PIT. THERE 

ARE APPROXIMATELY 21 AERATORS ON EACH OF THE CENTRAL EVAPORATION/AERATION 

PITS. THE AERATORS MOVE APPROXIMATELY 150 GPM (CUMMULATIVE) ON THE 

CENTRALIZED PITS, AND ABOUT 5 GPM ON THE REMOTE PITS. THIS CIRCULATION AND

SPRAYING OF THE WATER ENHANCES THE EVAPORATION RATE. THE LEVEL OF 

ENHANCEMENT IS DEPENDANT ON WEATHER CONDITIONS (TEMP, WIND SPEED, CLOUD 

COVER, ETC).

ENVIRONMENTAL IMPACTS/BENEFITS: ALL WATER IS EITHER EVAPORATED AT THE WELL 

HEAD, OR EVAPORATED AT THE CENTRAL EVAPORATION/AERATION PITS. ALL PITS ARE 

FENCED TO PREVENT ENTRANCE OF LIVE STOCK AND WILDLIFE FROM CONSUMING THE 

WATER. NO OIL IS PRESENT IN THE WATER, SO HARM TO BIRDS AND MIGRATORY 

WATERFOWL IS NOT A CONCERN.

APPLICABILITY: THIS PARTICULAR TECHNOLOGY IS APPLICABLE TO GAS FIELDS,

PRODUCING LOW VOLUMES OF WATER, IN AN ARID ENVIRONMENT THAT ENCOURAGES 

EVAPORATION.

COST: COSTS WERE NOT COLLECTED ON THE OPERATING COST FOR HAULING WATER. THE 

CAPITAL COST FOR INSTALLING THE AERATORS IS AROUND $4,000, WITH THE BIGGEST 
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

SINGLE TICKET ITEM BEING THE CIRCULATOR PUMP, WHICH IS ABOUT $1,500. THE 

MONTHLY ELECTRIC COSTS FOR OPERATING THE PUMP AND AERATORS ON ONE OF THE 

EVAPORATION/AERATION PITS IS ESTIMATED TO BE $150/MONTH.

ADDITIONAL NOTES:_NONE.

DATE: 7/14/2005____ INFORMATION COLLECTED BY:_JAKE CRISSUP
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

PHOTO LOG

VIEW OF CENTRALIZED EVAPORATION/AERATION PIT

VIEW OF EVAPORATION PIT ADJACENT TO EVAPORATION/AERATION PIT
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF AN UNLINED INDIVIDUAL EVAPORATION/AERATION PIT AT REMOTE WELL HEAD

CLOSER VIEW OF INDIVIDUAL AERATOR AT REMOTE WELL HEAD
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF SOLAR PANEL AT REMOTE WELL LOCATION

VIEW OF A LINED EVAPORATION PIT ADJACENT TO A WELL HEAD
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

SITE INFORMATION

OFFICE ADDRESS: SOUTHEAST OF BROADUS OFF OF 544___________________________

CITY: BELL CREEK___________ STATE: MT__ COUNTY: POWDER______________ 

BASIN: BELL CREEK_________FIELD: BELL CREEK____

CONTACT NAME/TITLE: DARRELL HYSTAD/ FIELD INSPECTOR – MBOGC

CONTACT NUMBER: (406)698-4861

WATER MANAGEMENT TECHNOLOGIES/PRACTICES IN PLACE

DESCRIPTION: VISITED THE BELL CREEK FIELD WHERE 40-50 OIL WELLS ARE CURRENTLY 

PRODUCING. BELL CREEK HAS 27 INJECTION WELLS CURRENTLY ONLINE FOR ENHANCED 

RECOVERY. OF THE 13,000 BBLS/DAY OF WATER THAT IS PRODUCED, APPROXIMATELY 

8,000 BBLS/DAY IS RE-INJECTED FOR ENHANCED RECOVERY AND 5,000 BBLS/DAY IS 

DISCHARGED THROUGH A SERIES OF TANKS AND PITS TO SEPARATE OIL FROM THE WATER 

PRIOR TO DISCHARGE.

ENVIRONMENTAL IMPACTS/BENEFITS: DISCHARGED WATER IS CONSUMED BY CATTLE,

DEER, AND OTHER WILDLIFE, AND HABITAT IS CREATED FOR WILDLIFE WHERE NONE WOULD 

BE PRESENT DUE TO THE SEASONAL CONDITION OF THE DRAINAGE.

APPLICABILITY: THE COMBINATION OF INJECTION FOR ENHANCED RECOVERY AND 

DISCHARGE TO THE SURFACE IS APPLICABLE DUE TO THE QUALITY OF THE WATER OF THE 

MATURE NATURE OF THIS OIL FIELD TO REQUIRE ENHANCED RECOVERY.

COST: NO INFORMATION WAS COLLECTED ON COST.

ADDITIONAL NOTES:_NONE.

DATE: 7/12/2005____ INFORMATION COLLECTED BY:_JAKE CRISSUP
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

PHOTO LOG

VIEW OF THE FIRST OIL/WATER SEPARATOR PIT

VIEW OF SECONDARY PIT WITH T-SIPHON
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF SECONDARY PIT T-SIPHON TO PREVENT OIL FROM DISCHARGING 

VIEW OF SECONDARY PIT DISCHARGE TO BELL CREEK 
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

SITE INFORMATION

OFFICE ADDRESS: VISITED CENTRALIZED EVAPORATION PIT NORTH OF SACO

CITY: NORTH OF SACO STATE: MT COUNTY: PHILLIPS

BASIN: BOWDOIN_________FIELD: BOWDOIN____

CONTACT NAME/TITLE: BOB SCHMIDT/ FIELD INSPECTOR – MBOGC

CONTACT NUMBER: (406)698-5266

WATER MANAGEMENT TECHNOLOGIES/PRACTICES IN PLACE

DESCRIPTION: VISITED A CENTRALIZED EVAPORATION PIT CONSTRUCTED AND OPERATED 

BY FIDELITY. WATER IS COLLECTED AT INDIVIDUAL EVAPORATION PITS ADJACENT TO

EACH WELL HEAD. AS THE INDIVIDUAL EVAPORATION PITS FILL WITH WATER, A VACUUM 

TRUCK COLLECTS THE WATER AND TRANSPORTS IT TO THE CENTRALIZED EVAPORATION PIT 

THAT IS LINED WITH A GEOSYNTHETIC LINER. THE CENTRAL EVAPORATION PIT WAS A 

SEPARATOR BOX THAT PREVENTS SOLIDS (SOIL, ROCKS, ETC) FROM DISCHARGING TO THE 

EVAPORATION PIT, THUS EXTENDING THE LIFE OF THE LINER. FIDELITY HAS THREE 

ADDITIONAL CELLS THAT CAN BE LINED, AS NECESSARY, ONCE THE FIRST EVAPORATION PIT 

REACHES CAPACITY. THE EVAPORATION PIT IS A FEW FEET DEEP, THUS ENHANCING THE 

HEATING AND EVAPORATION OF THE WATER, WHICH IS SPREAD OVER A LARGE AREA 

(APPROXIMATELY 100 FEET WIDE BY 300 FEET LONG).

ENVIRONMENTAL IMPACTS/BENEFITS: ALL WATER IS EITHER EVAPORATED AT THE WELL 

HEAD, OR EVAPORATED AT THE CENTRAL EVAPORATION PIT. ALL PITS ARE FENCED TO 

PREVENT ENTRANCE OF LIVE STOCK AND WILDLIFE FROM CONSUMING THE WATER. NO OIL 

IS PRESENT IN THE WATER, SO HARM TO BIRDS AND MIGRATORY WATERFOWL IS NOT A 

CONCERN.

APPLICABILITY: THIS PARTICULAR TECHNOLOGY IS APPLICABLE TO GAS FIELDS,

PRODUCING LOW VOLUMES OF WATER, IN AN ARID ENVIRONMENT THAT ENCOURAGES 

EVAPORATION.

COST: COSTS WERE NOT COLLECTED ON THE EVAPORATION PIT OR THE TRUCKING COSTS 

FOR HAULING WATER.

ADDITIONAL NOTES:_NONE.

DATE: 7/13/2005____ INFORMATION COLLECTED BY:_JAKE CRISSUP
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

PHOTO LOG

VIEW OF EVAPORATION PIT ADJACENT TO A PRODUCING GAS WELL

CLOSER VIEW OF EVAPORATION PIT ADJACENT TO PRODUCING GAS WELL
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF CENTRALIZED EVAPORATION PIT THAT IS LINED

VIEW OF CELL ADJACENT TO EVAPORATION PIT FOR FURTHER EXPANSION OF THE SYSTEM
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF TRUCK OFF-LOADING AREA WHERE WATER IS OFF-LOADED INTO THE 

EVAPORATION PIT FROM TRUCKS

CLOSER VIEW OF DISCHARGE WEIR WHERE SOLIDS ARE SEPARATED OUT AS THE TRUCK IS 

OFF-LOADED PRIOR TO DISCHARGE TO THE EVAPORATION PIT
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

SITE INFORMATION

OFFICE ADDRESS: 115 N. MAIN (BURLINGTON RESOURCES)________________________

CITY: BAKER___________ STATE: MT__ COUNTY: FALLON______________ 

BASIN: CEDAR CREEK ANTICLINE_________FIELD: EAST LOOKOUT BUTTE____

CONTACT NAME/TITLE: DALE HINTON/ ENCORE 

CONTACT NUMBER: (406)

CONTACT NAME/TITLE: JIM ARMENTROUT/ BURLINGTON RESOURCES 

CONTACT NUMBER: (406)778-6401

CONTACT NAME/TITLE: DARRELL HYSTAD/ FIELD INSPECTOR – MBOGC

CONTACT NUMBER: (406)698-4861

WATER MANAGEMENT TECHNOLOGIES/PRACTICES IN PLACE

DESCRIPTION: VISITED THE CEDAR CREEK ANTICLINE FIELD WHERE WATER IS PRIMARLY 

INJECTED FOR DISPOSAL AND ENHANCED RECOVERY. WATER THAT IS ENTRAINED WITH OIL 

IS RUN THROUGH A MOBILE OIL RECOVERY UNIT THAT FURTHER SEPARATES THE OIL FROM 

THE WATER. SOLIDS REMOVED FROM THE OIL RECOVERY PROCESS ARE APPLIED TO AN 

ALKALINE FLAT LANDFARM WHERE THE PROPERTIES OF THE SOIL ARE IMPROVED FROM THE 

LANDFARMING TECHNIQUE. WATER REMOVED IS INJECTED AND OIL REMOVED IS SOLD TO 

RECOVER THE COST OF THE OIL RECOVERY PROCESS. 

ENVIRONMENTAL IMPACTS/BENEFITS: ALL WATER IS INJECTED FOR EITHER ENHANCED

RECOVERY OR DISPOSAL.

APPLICABILITY: THE INJECTION FOR DISPOSAL AND ENHANCED RECOVERY IS APPLICABLE 

DUE TO THE QUALITY OF THE WATER AND THE MATURE NATURE OF THIS OIL FIELD TO 

REQUIRE ENHANCED RECOVERY.

COST: NO INFORMATION WAS COLLECTED ON COST.

ADDITIONAL NOTES:_NONE.

DATE: 7/12/2005____ INFORMATION COLLECTED BY:_JAKE CRISSUP
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

PHOTO LOG

VIEW OF AN INJECTION WELL

VIEW OF PUMPING UNITS THAT PUMP WATER TO INJECTION WELLS
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF PRODUCING WELL WITH AN EVAPORATION PIT ADJACENT TO IT

CLOSER VIEW OF THE EVAPORATION PIT
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF A MOBILE OIL RECOVERY UNIT

VIEW OF A BIN THAT COLLECTS SOLIDS FROM THE MOBILE OIL RECOVERY UNIT 
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF LANDFARM WHERE ALKALINE SOILS ARE RECLAIMED
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF NATURAL ALKALINE SOILS ADJACENT TO LANDFARM
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

SITE INFORMATION

OFFICE ADDRESS: VARIOUS DISPOSAL SITES VISITED

CITY: SYDNEY AND MEDICINE LAKE STATE: MT COUNTY: RICHLAND AND SHERIDAN

BASIN: VARIOUS_________FIELD: VARIOUS____

CONTACT NAME/TITLE: BOB SCHMIDT/ FIELD INSPECTOR – MBOGC

CONTACT NUMBER: (406)698-5266

CONTACT NAME/TITLE: DARRELL HYSTAD/ FIELD INSPECTOR – MBOGC

CONTACT NUMBER: (406)698-4861

WATER MANAGEMENT TECHNOLOGIES/PRACTICES IN PLACE

DESCRIPTION: VISITED THREE DISPOSAL SITES.

LANDTECH, JUST NORTHWEST OF SYDNEY (APPROXIMATELY 12 MILES) WAS VISITED.

LANDTECH HAS BEEN ALLOWED TO MAINTAIN THE NETTED CONCRETE PIT SYSTEM DUE TO 

GRANDFATHER LAWS. LANDTECH HAS THREE CONCRETE PITS IN SERIES THAT SEPARATE 

THE OIL FROM THE WATER. THEY ALSO HAVE SEVERAL TANKS ONSITE FOR TEMPORARY

STORAGE PRIOR TO DISPOSAL INJECTION. LANDTECH DISPOSES ABOUT 2,000-5,000 BBLS

OF WATER/DAY.

NANCE OPERATES A COMMERCIAL DISPOSAL WELL JUST NORTH OF MEDICINE LAKE. THE 

NANCE DISPOSAL OPERATION HAS A SEPARATION PIT THAT IS NETTED AND IS USED TO 

SEPARATE THE OIL FROM THE WATER. BOTH NANCE AND LANDTECH UTILIZE THE MOBILE 

OIL RECOVERY UNITS TO FURTHER SEPARATE WATER FROM OIL AND SELL THE OIL 

COMMERCIALLY.

THE THIRD SITE VISITED WAS A DISPOSAL WELL THAT SERVICES 6 PRODUCING OIL WELLS.

THIS SITE HAD NO SURFACE PITS AS ALL OF THE WATER IS CONTAINED IN TANKS PRIOR TO 

DISPOSAL. THE WELL HOUSE IS CONNECTED TO THE FINAL TANK TO PREVENT FREEZING OF 

THE PIPES DURING WINTER MONTHS.

ENVIRONMENTAL IMPACTS/BENEFITS: ALL WATER IS INJECTED FOR DISPOSAL.

APPLICABILITY: THE INJECTION FOR DISPOSAL IS APPLICABLE DUE TO THE QUALITY OF THE 

WATER.

COST: DISPOSAL COSTS VARY BASED ON THE QUALITY OF THE WATER.
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

ADDITIONAL NOTES:_NONE.

DATE: 7/13/2005____ INFORMATION COLLECTED BY:_JAKE CRISSUP
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

PHOTO LOG

VIEW OF CONCRETE SEPARATION PITS IN SERIES AT LANDTECH

VIEW OF INSTRUMENTS USED TO DETERMINE WATER QUALITY AT LANDTECH
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF TANKS AND NETTED PIT AT NANCE

VIEW OF INJECTION WELLHEAD AT NANCE
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF A OILFIELD AND TANKS AT A “NO PIT” DISPOSAL SITE NEAR MEDICINE LAKE
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF A TANK WITH THE WELL HEAD HOUSED NEXT TO IT
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

SITE INFORMATION

OFFICE ADDRESS: SITES VISITED IN CX FIELD AND COAL CREEK EXPLORATORY POD

CITY: NORTHEAST OF DECKER STATE: MT__ COUNTY: BIG HORN_______ 

BASIN: POWDER RIVER_________FIELD: PRB CBM____

CONTACT NAME/TITLE: STEVE SASAKI/ DRILLING INSPECTOR- MBOGC

CONTACT NUMBER: (406)656-0040 

WATER MANAGEMENT TECHNOLOGIES/PRACTICES IN PLACE

DESCRIPTION: THE CX FIELD WAS VISITED AND AN EMIT WATER TREATMENT PLANT WAS 

VISITED NORTH OF THE TONGUE RIVER RESERVOIR JUST NORTH OF COAL CREEK. THE CX

FIELD HAS SEVERAL DISCHARGE POINTS INTO THE TONGUE RIVER THAT HAVE BEEN 

GRANDFATHERED AS MDPES DISCHARGE POINTS. 1600 GPM IS CUMMULATIVELY 

DISCHARGED INTO THE TONGUE RIVER FROM THE CX FIELD. FIDELITY HAS REQUESTED TO 

ALTER THE MPDES DISCHARGE PERMITS TO ALLOW FOR HIGHER DISCHARGE RATES 

DURING HIGH FLOW PERIODS OF THE TONGUE RIVER. THE EMIT PLANT VISITED WAS FROM 

THE COAL CREEK EXPLORATORY PLAN OF DEVELOPMENT (POD). ALL OF THE WATER 

PRODUCED FROM THE COAL CREEK EXPLORATORY POD IS PUMPED TO A CENTRAL TANK 

WHERE ANY GAS IS VENTED OFF. THE WATER IS THEN RUN THROUGH THE EMIT PLANT AS 

DESCRIBED BELOW. AFTER THE EMIT PLANT, THE WATER IS RUN THROUGH A LIMESTONE 

REACTOR BED, AND THEN THROUGH A RENTENTION PIT AND THEN AN AERATOR PIT PRIOR 

TO DISCHARGE. THE WATER IS THEN DISCHARGED TO THE TONGUE RIVER THROUGH A 

PERFORATED PIPE THAT IS TRENCHED BELOW THE BED OF THE RIVER. THE TRENCHED PIPE 

HAS A CLEAN OUT PIPE OF BOTH SIDES OF THE RIVER THAT DAYLIGHT SO THE TRENCHED 

PIPE CAN BE EASILY CLEANED OUT AS NEEDED.

THE FOLLOWING PROCESS DESCRIPTION WAS TAKEN FROM THE EMIT TECHNOLOGIES 

WEBSITE, WWW.EMITTECHNOLOGIES.COM :

COMMERCIALLY AVAILABLE CATION & ANION RESINS ARE USED TO PURIFY PRODUCED 

WATER OF SODIUM, CHLORIDE, SULFATE AND OTHER IONS IN BOTH A CONTINUOUS AND 

COUNTERCURRENT OPERATING MODE. THESE CHEMICAL ENGINEERING PRINCIPLES OF 

MASS TRANSFER MAXIMIZE THE RESINS’ ABILITIES IN PURIFYING WATER WITH A 

CONSISTENT QUALITY. THEY ALSO OPTIMIZE THE USE OF ACID AND ALKALI REGENERANTS,

MINIMIZE THEIR VOLUMES AND GENERATE A DENSE BRINE SOLUTION THAT MAY HAVE 

VALUE AS A CLEAR BRINE FLUID WITHIN THE OIL AND GAS INDUSTRY. THE KEY TO THE 

HIGGINS LOOP FEATURES IS ITS ABILITY TO MOVE THE RESIN THROUGH THE LOOP VIA 

INCREMENTAL “PULSING”. THE PULSE VESSEL SERVES AS A RESIN FLOW METER TO ENSURE 

ITS FLOW IS IN PROPORTION TO THE WATER TREATED AND THE AMOUNT OF REGENERANT 

CONSUMED.
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

PRODUCED WATER CONTAINING HIGH NA LEVELS IS FED TO THE ADSORPTION ZONE WITHIN 

THE HIGGINS LOOP WHERE IT CONTACTS STRONG ACID CATION RESIN WHICH LOADS NA+

IONS IN EXCHANGE FOR HYDROGEN (H-) IONS. TREATED WATER EXITS THE LOOP 

CONTAINING LESS THAN 10 MG/L NA.

CONCURRENT WITH ADSORPTION AND IN THE LOWER SECTION OF THE HIGGINS LOOP,

NA-LOADED RESIN IS REGENERATED WITH EITHER HYDROCHLORIC OR SULFURIC ACID TO 

PRODUCE A SMALL, CONCENTRATED SPENT BRINE STREAM. REGENERATED RESIN IS RINSED 

WITH WATER PRIOR TO REENTERING THE ADSORPTION ZONE TO REMOVE ACID FROM ITS 

PORES.

AS RESIN IN THE UPPER LAYER OF THE ADSORPTION ZONE BECOMES LOADED WITH NA, THE 

FLOWS TO THE HIGGINS LOOP ARE MOMENTARILY INTERRUPTED TO ALLOW ADVANCEMENT 

OF THE RESIN BED (PULSING) THROUGH THE LOOP IN THE OPPOSITE DIRECTION OF LIQUID 

FLOW. LIQUID FLOWS ARE RESTARTED AFTER RESIN PULSING IS COMPLETE.

TREATED WATER IS SLIGHTLY ACIDIC DUE TO ITS INCREASED H- ION STRENGTH, AND IT IS 

NEUTRALIZED WITH LIMESTONE, WHICH ALSO INCREASES ITS CALCIUM CONCENTRATION SO 

THAT THE WATER’S SODIUM ADSORPTION RATIO (SAR) IS LESS THAN 1.0. SPENT BRINE 

CONTAINING REMOVED NA+ IONS HAS A DENSITY HIGH ENOUGH FOR USE AS A KILL FLUID.

ENVIRONMENTAL IMPACTS/BENEFITS: TREATING PRODUCED WATER WITH THIS 

TECHNOLOGY PROVIDES ENVIRONMENTAL BENEFITS BY ALLOWING FOR THE WATER TO BE 

BENEFICIALLY USED BY IMPROVING THE SAR AND LOWERING THE TDS. ONCE THE WATER 

IS TREATED, IT CAN BE PUT BACK INTO A SURFACE STREAM FOR USE BY LIVESTOCK,

WILDLIFE, AND DOWNSTREAM WATER RIGHTS HOLDERS, OR IT CAN BE IRRIGATED 

IMMEDIATELY.

APPLICABILITY: THE HIGGINS LOOP HAS BEEN IN USE SINCE WWII, AND THE USE OF THE 

EMIT TECHNOLOGY IS GROWING IN THE POWDER RIVER BASIN ON BOTH THE WYOMING 

AND MONTANA SIDE. THIS TECHNOLOGY IS USEFUL IN LOWERING SODIUM, BICARBONATES,

SAR VALUES, AND OVERALL TDS TO BELOW NPDES PERMIT REQUIREMENTS.

COST: NO INFORMATION WAS COLLECTED ON COST. THE WEBSITE STATES THAT COST IS A 

FIXED COST AND IS CHEAPER THAN SEVERAL OF THE CURRENT TREATMENT ALTERNATIVES.

ADDITIONAL NOTES: NONE

DATE: 7/11/2005 ____ INFORMATION COLLECTED BY:_JAKE CRISSUP
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

PHOTO LOG

VIEW OF THE ENTRANCE TO CX RANCH

VIEW OF A MPDES DISCHARGE POINT ON CX RANCH
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF THE DISCHARGE POINT INTO THE TONGUE RIVER

CLOSER VIEW OF THE DISCHARGE POINT
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF THE COAL CREEK EMIT PLANT

VIEW OF A LIME REACTOR BED WITH AN AERATOR
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

CLOSER VIEW OF THE AERATOR PRIOR TO DISCHARGE TO RETENTION PIT
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF THE RETENTION AND AERATION PITS

VIEW OF THE DISCHARGE POINT TRENCHED BELOW THE RIVER 

CLOSER VIEW OF THE DISCHARGE POINT TRENCHED BELOW THE RIVER
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

SITE INFORMATION

OFFICE ADDRESS: NONE AVAILABLE (SUMMIT RESOURCES WAS THE OPERATOR)

CITY: NORTH OF CHINOOK STATE: MT COUNTY: BLAINE

BASIN: RABBITT HILLS_________FIELD: RABBITT HILLS____

CONTACT NAME/TITLE: GARY KLOTZ/ FIELD INSPECTOR – MBOGC

CONTACT NUMBER: (406)698-4871

WATER MANAGEMENT TECHNOLOGIES/PRACTICES IN PLACE

DESCRIPTION: VISITED A SURFACE DISCHARGE POINT AT THE RABBITT HILLS OIL FIELD.

SIMILAR OIL/WATER SEPARATION PITS WERE USED, ALONG WITH NETTING ON THE PRIMARY 

PIT TO PROTECT BIRDS AND WILDLIFE. A FILTER SOCK, WHICH IS FREQUENTLY CHANGED 

OUT, IS ALSO EMPLOYED JUST AFTER THE SECONDARY SEPARATION PIT TO ENHANCE THE 

OIL AND SOLIDS REMOVAL FROM THE DISCHARGE PRIOR TO DISCHARGING TO THE STOCK 

POND. FURTHERMORE, A 20-30 FOOT FLEXIBLE PLASTIC TUBE HAS BEEN CONNECTED TO 

THE PIPE SPILLWAY OF THE STOCK POND TO MINIMIZE EROSION DURING STORM EVENTS AND 

PERIODS OF HIGH FLOW. THE STOCK POND WAS NOT DISCHARGING OVER THE SPILLWAY AT 

THE TIME OF THE VISIT.

ENVIRONMENTAL IMPACTS/BENEFITS: DISCHARGED WATER IS CONSUMED BY CATTLE,

DEER, AND OTHER WILDLIFE, AND HABITAT IS CREATED FOR WILDLIFE WHERE NONE WOULD 

BE PRESENT DUE TO THE SEASONAL CONDITION OF THE DRAINAGE.

APPLICABILITY: THE DISCHARGE TO THE SURFACE IS APPLICABLE DUE TO THE QUALITY OF 

THE WATER AND THE ABILITY OF THE PROCESS TO REMOVE OIL FROM THE WATER PRIOR TO 

SURFACE DISCHARGE.

COST: NO INFORMATION WAS COLLECTED ON COST.

ADDITIONAL NOTES:_NONE.

DATE: 7/14/2005____ INFORMATION COLLECTED BY:_JAKE CRISSUP
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

PHOTO LOG

VIEW OF PRIMARY SEPARATION PIT THAT IS NETTED

VIEW OF SECONDARY SEPARATION PIT ENCLOSED WITH A FENCE AND A CATTLE GUARD
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF DISCHARGE POINT WITH SOCK FILTERS TO REMOVE OILY SOLIDS

VIEW OF STOCK POND THAT THE PRODUCED WATER IS DISCHARGED TO
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF STOCK POND DAM WITH PRIMARY SPILLWAY PIPES

CLOSER VIEW OF ENERGY DISSIPATION DEVICE AT DISCHARGE POINT TO REDUCE EROSION
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

SITE INFORMATION

OFFICE ADDRESS: SOUTH OF HAVRE IN/AROUND BEAR PAW MOUNTAINS

CITY: HAVRE STATE: MT COUNTY: HILL

BASIN: TIGER RIDGE_________FIELD: TIGER RIDGE____

CONTACT NAME/TITLE: GARY KLOTZ/ FIELD INSPECTOR – MBOGC

CONTACT NUMBER: (406)698-4871

WATER MANAGEMENT TECHNOLOGIES/PRACTICES IN PLACE

DESCRIPTION: VISITED TWO CENTRALIZED EVAPORATION PITS AND SEVERAL WELL SITES 

THAT HAVE LINED, UNLINED, AND OPEN TUB EVAPORATION PITS ADJACENT TO THE WELL 

HEADS. ONE LOCATION VISITED HAD AN OPEN RING TANK AND A COMPRESSOR TO 

INCREASE THE GAS PRESSURE TO PIPELINE QUALITY. ANOTHER LOCATION HAD AN 

ENCLOSED TANK ADJACENT TO THE WELL HEAD. IT WAS UNCLEAR WHY THE TANK HAD 

BEEN INSTALLED AS THE SITE WAS VERY REMOTE, AND A VACUUM TRUCK WOULD NOT BE 

ABLE TO EASILY ACCESS THE SITE FOR HAULING WATER. FOR LINED AND UNLINED PITS,

VACUUM TRUCKS ARE EMPLOYED ON AN AS NEEDED BASIS TO HAUL THE WATER TO A 

CENTRAL EVAPORATION PIT. THE CENTRAL EVAPORATION PITS ARE FENCED AND NETTED 

TO PREVENT WILDLIFE FROM ENTERING THEM.

ENVIRONMENTAL IMPACTS/BENEFITS: ALL WATER IS EITHER EVAPORATED AT THE WELL 

HEAD, OR EVAPORATED AT THE CENTRAL EVAPORATION PITS. ALL PITS ARE FENCED AND 

NETTED TO PREVENT ENTRANCE OF LIVE STOCK AND WILDLIFE FROM CONSUMING THE 

WATER.

APPLICABILITY: THIS PARTICULAR TECHNOLOGY IS APPLICABLE TO GAS FIELDS,

PRODUCING LOW VOLUMES OF WATER, IN AN ARID ENVIRONMENT THAT ENCOURAGES 

EVAPORATION.

COST: COSTS WERE NOT COLLECTED.

ADDITIONAL NOTES:_NONE.

DATE: 7/14/2005____ INFORMATION COLLECTED BY:_JAKE CRISSUP
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

PHOTO LOG

VIEW OF 30’ RING TANK THAT IS USED TO STORE PRODUCED WATER ADJACENT TO THE 

WELL HEAD

VIEW OF MOBILE COMPRESSOR UNIT USED TO INCREASE GAS PRESSURE
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF A CENTRALIZED EVAPORATION PIT OFF-LOADING AREA

CLOSER VIEW OF CENTRALIZED EVAPORATION PIT
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF A LINED PIT ADJACENT TO A WELL HEAD

VIEW OF AN EVAPORATION TUB ADJACENT TO WELL HEAD
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF A WELL HEAD WITH A TANK ADJACENT TO IT TO HOLD PRODUCED WATER
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

CLOSER VIEW OF PRODUCED WATER TANK ADJACENT TO WELL HEAD
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

SITE INFORMATION

OFFICE ADDRESS: 111 WEST 5TH STREET, SUITE 1000 (MAIN OFFICE)

CITY: TULSA STATE: OK__ COUNTY: OKLAHOMA________ 

BASIN: OKLAHOMA CITY_________FIELD: OKLAHOMA CITY____

CONTACT NAME/TITLE: JANET MCGEHEE/ PRODUCTION MANAGER – NEW DOMINION

CONTACT NUMBER: (918)465-4167 

CONTACT NAME/TITLE: TIM BAKER/ POLLUTION ABATEMENT MANAGER-OCC

CONTACT NUMBER: (405)522-2763 

WATER MANAGEMENT TECHNOLOGIES/PRACTICES IN PLACE

DESCRIPTION: A DEEP INJECTION WELL, NAMED “DEEP THROAT” HAS BEEN CONSTRUCTED 

IN THE MATURE OKLAHOMA CITY FIELD IN ORDER TO DISPOSE OF LARGE VOLUMES OF 

WATER THAT ARE PRODUCED AS A RESULT OF THE DEWATERING TECHNIQUE THAT IS BEING 

EMPLOYED BY NEW DOMINION, LLC. DEEP THROAT IS COMPLETED AS A MULTI-LATERAL 

HORIZONTAL DISPOSAL WELL IN THE LOWER ARBUCKLE FORMATION (OVER 8,000’ TOTAL 

DEPTH), AND IT IS PERMITTED TO DISPOSE OF 60,000 BBLS/DAY. THE OIL AND GAS IS BEING 

PRODUCED FROM THE UPPER PORTION OF THE ARBUCKLE FORMATION (~6,000’ DEPTH).

THE WATER PRODUCED IS EXTREMELY HIGH IN TDS, AND THE OKLAHOMA CITY FIELD IS IN 

THE MIDDLE OF A HIGHLY POPULATED AREA DUE TO THE GROWTH OF OKLAHOMA CITY,

THEREFORE THE ONLY FEASIBLE OPTION TO MANAGE THE HIGH VOLUMES OF WATER IS TO 

INJECT IT.

ENVIRONMENTAL IMPACTS/BENEFITS: THERE ARE NO KNOWN BENEFICIAL USES FOR THE 

HIGH TDS WATER, AND DUE TO THE PROXIMITY TO RESIDENTIAL AREAS, THE MAJOR 

ENVIRONMENTAL CONCERN IS FOR HUMAN SAFETY FOR THE SURROUNDING 

NEAIGHBORHOODS. PIPELINES CARRYING THE OIL, WATER, AND GAS ARE ALL BELOW 

GRADE, AND CARE HAS BEEN TAKEN TO RESTORE ALL PIPELINE CORRIDORS. DUE TO THE 

PROXIMITY OF HUMAN INHABITANCE, THE DRILLING SITES HAVE BEEN CONDENSED TO A 

SMALL AREA (~6 CONTIGUOUS ACRES FOR 8 DRILLING SITES). MULTI-LATERAL 

HORIZONTAL DRILLING TECHNOLOGY IS UTILIZED TO COMPLETE THE WELLS IN VARIOUS 

FORMATIONS, OVER A LARGE AREA, WHILE ONLY DISTURBING THIS SMALL SURFACE AREA.

APPLICABILITY: MULTI-LATERAL DEEP WELL INJECTION IS BEST SUITED FOR HIGHLY 

POPULATED AREAS, WHERE THE VOLUME OF WATER IS CONSIDERABLY LARGE, AND/OR THE 

QUALITY OF THE WATER IS SUCH THAT NO BENEFICIAL USE CAN BE REALIZED.
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

COST: NO INFORMATION WAS COLLECTED ON THE CAPITAL COST TO DRILL “DEEP 

THROAT”. THE COST TO HAVE IT WORKED ON, AS IT WAS BEING WORKED ON DURING THE 

SITE VISIT, IS APPROXIMATELY $15,000/DAY.

ADDITIONAL NOTES: NONE

DATE: 7/6/2005____ INFORMATION COLLECTED BY:_JAKE CRISSUP
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

PHOTO LOG

VIEW OF THE WELL HEAD FOR “DEEP THROAT” THE DEEP MULTI-LATERAL DISPOSAL WELL

VIEW OF THE DRILL RIG SETTING UP TO WORK ON “DEEP THROAT”
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF THE WELL HEAD OF A PRODUCING WELL

VIEW OF THE 3 PHASE SEPARATOR THAT IS SPECIALLY DESIGNED FOR A HIGH SEPARATION 

EFFICIENCY OF WATER, OIL, AND GAS
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF A FOUNDATION THAT HAS BEEN CONSTRUCTED FOR AN ADDITIONAL 3 PHASE 

SEPARATOR

VIEW OF TRANSMISSION LINES CONSTRUCTED TO ALLOW FOR FUTURE GROWTH
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

SITE INFORMATION

OFFICE ADDRESS: 1110 W. STOVALL ROAD

CITY: WILBURTON STATE: OK__ COUNTY: LATIMER________ 

BASIN: RED OAK_________FIELD: RED OAK____

CONTACT NAME/TITLE: JAY EUBANKS/ FIELD ENV. COORD. – BP AMERICA

CONTACT NUMBER: (918)465-4167 

CONTACT NAME/TITLE: TIM BAKER/ POLLUTION ABATEMENT MANAGER-OCC

CONTACT NUMBER: (405)522-2763 

WATER MANAGEMENT TECHNOLOGIES/PRACTICES IN PLACE

DESCRIPTION: CURRENTLY, BP ESTIMATES THAT THEY HAVE 450 ACTIVE PRODUCING 

WELLS IN THE RED OAK FIELD. IN 2004, A PILOT PROGRAM WAS INITIATED BY BP TO 

PROMOTE FLOOD IRRIGATION AROUND WELL SITES USING THE PRODUCED WATER TO 

IRRIGATE THE LAND VERSUS HAVING THE WATER HAULED OFF FOR DISPOSAL. CURRENTLY,

13 WELLS ARE PERMITTED, WITH LANDOWNER APPROVAL, TO UTILIZE THE WATER FOR 

FLOOD IRRIGATION. BP PLANS TO HAVE AS MANY AS 100 WELLS PERMITTED, WITH 

LANDOWNER APPROVAL, USING THE SAME TECHNIQUES BY THE END OF 2005.

AN AVERAGE OF 1⁄2 BBL OF WATER IS PRODUCED FOR EVERY 100,000 CUBIC FEET (CF) OF 

GAS PRODUCED. THE WATER IS TYPICALLY LOW IN OIL AND GREASE (<1,000 PPM) AND 

LOW IN TOTAL SUSPENDED SOLIDS (TSS) (<5,000 PPM). THE WATER HAS AN AVERAGE 

CHLORIDE VALUE BETWEEN 250 AND 500 PPM.

THE OKLAHOMA CORPORATION COMMISSION HAS A REQUIRED APPLICATION FOR SURFACE 

DISCHARGE THAT SHOULD BE FILED AND APPROVED FOR EACH WELL SITE PRIOR TO FLOOD 

IRRIGATION ACTIVITIES. THE PERMIT REQUIRES LANDOWNER NOTIFICATION AND 

APPROVAL, SOIL AND WATER SAMPLES TO BE COLLECTED AND ANALYZED, AND A 

CALCULATION OF THE APPLICATION RATE BASED ON THE MAXIMUM TSS AND THE 

MAXIMUM OIL AND GREASE THAT CAN BE APPLIED TO THE LAND ON A PER ACRE BASIS. THE 

LIMITING CONCENTRATION IS THEN DETERMINED TO BE EITHER TSS OR OIL AND GREASE,

DEPENDING ON WHICH CALCULATION IS MORE CONSERVATIVE. THE MAXIMUM TSS THAT 

CAN BE APPLIED OVER TIME IS 6000 LBS/ACRE, AND THE MAXIMUM OIL AND GREASE THAT 

CAN BE APPLIED OVER TIME IS 500 LBS/ACRE.

ONCE THE WELL SITE HAS BEEN PROPERLY PERMITTED AND APPROVED, BP CAN THEN 

COMMENCE THE FLOOD IRRIGATION OF THAT SITE. THE FLOOD IRRIGATION SYSTEM 

CONSISTS OF CONNECTING A HOSE TO THE DRAIN OF THE STORAGE TANK AT THE WELL SITE 

(EACH WELL SITE HAS A TANK WITH TEMPORARY STORAGE OF BETWEEN 100 AND 150 BBLS
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

OF WATER). WHEN THE TANK NEARS CAPACITY, A HOSE IS CONNECTED TO THE DRAIN OF 

THE TANK, AND A T-FITTING IS CONNECTED TO THE OPPOSITE END OF THE HOSE. TWO 

PERFORATED HOSES ARE THEN RUN IN OPPOSITE DIRECTIONS INTO THE AREA THAT WILL BE 

IRRIGATED. THE VALVE AT THE TANK DRAIN IS THEN OPENED AND THE WATER IN THE TANK 

IS THEN DRAINED INTO THE FIELD, THUS IRRIGATING THE FIELD. BP KEEPS RECORDS OF 

HOW MUCH WATER IS DISCHARGED, AND WHERE THE WATER IS DISCHARGED TO, SO THAT 

ONCE THE PERMIT LIMITS HAVE BEEN MET THEY WILL NO LONGER DISCHARGE TO THAT 

FIELD. THE TANKS TYPICALLY FILL UP IN ABOUT 6 WEEKS. DEPENDING ON THE SOIL AND 

WATER ANALYTICAL RESULTS, THE FIELDS CAN ACCEPT A WIDE RANGE OF WATER VOLUMES 

OVER TIME. FOR EXAMPLE, IF A 1 ACRE FIELD IS CALCULATED TO ACCEPT 30,000

BBLS/ACRE, THEN AT A RATE OF 100 BBLS IRRIGATED EVERY 6 WEEKS, THE FIELD CAN BE 

FLOOD IRRIGATED FOR THE NEXT 34 YEARS BEFORE THE PERMIT LIMITS ARE REACHED.

THIS IS A CONSERVATIVE ESTIMATE AS MOST FIELDS CAN ACCEPT MORE THAN 30,000

BBLSS/ACRE, AND MOST FIELDS HAVE MORE THAN 1 ACRE THAT IS ACCESSIBLE TO 

IRRIGATE.

SOME SITES ARE NOT ACCEPTABLE FOR THIS FLOOD IRRIGATION PRACTICE DUE TO THE 

TOPOGRAPHY OF THE WELL SITE. GENERALLY, THE WELL NEEDS TO BE LOCATED IN AN 

AREA WHERE THERE IS A LARGE FLAT (< 3:1 GRADE) AREA TO PREVENT EROSION, AS THE 

LOAMY SOILS IN THIS AREA CAN BE EROSIVE AT STEEPER GRADES.

ENVIRONMENTAL IMPACTS/BENEFITS: BY UTILIZING THE WATER FOR FLOOD IRRIGATION,

IMPROVEMENTS ARE REALIZED BY INCREASED LIVESTOCK AND WILDLIFE FORARING, AND 

GREATER YIELDS OF HAY.

APPLICABILITY: THE FLOOD IRRIGATION EMPLOYED IN THIS AREA IS ENABLED BY THE 

QUALITY OF THE WATER (LOW TSS AND LOW OIL AND GREASE), QUALITY OF THE SOIL (LOW 

TSS), SITE TOPOGRAPHY (< 3:1 GRADE), AND WILLINGNESS OF THE LANDOWNER TO ALLOW 

THE FLOOD IRRIGATION. SOME LANDOWNERS ARE RELUCTANT TO ALLOW THE FLOOD 

IRRIGATION TO TAKE PLACE ON THEIR PROPERTY WITHOUT MONETARY COMPENSATION, AT 

WHICH POINT BP OPTS TO HAVE THE WATER DISPOSED OF THROUGH INJECTION.

FURTHERMORE, WATER IS NOT USED FOR FLOOD IRRIGATION IS WEATHER DOES NOT PERMIT 

DUE TO INCLEMENT CONDITIONS, AT WHICH POINT, THE WATER IS THEN CONTRACTED TO BE 

HAULED AND DISPOSED THROUGH INJECTION.

COST: THERE IS LITTLE COST ASSOCIATED WITH DISCHARGING THE WATER THROUGH 

FLOOD IRRIGATION OTHER THAN THE CAPITAL COST OF FABRICATING THE HOSES AND THE 

OPERATING COST OF THE LABOR HOURS ASSOCIATED WITH MANAGING THE FLOOD 

IRRIGATION. THE ALTERNATIVE (DISPOSAL INJECTION) IS MORE COSTLY ON A PER BBL

BASIS.
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

ADDITIONAL NOTES: NONE

DATE: 7/7/2005____ INFORMATION COLLECTED BY:_JAKE CRISSUP
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

PHOTO LOG

VIEW OF A WELL HEAD IN THE RED OAK FIELD THAT USES FLOOD IRRIGATION

VIEW OF THE 150 BARREL TANK THAT WATER IS STORED IN
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF PERFORATED HOSE THAT IS USED TO FLOOD IRRIGATE

VIEW OF THE TEMPORARY INSTALLATION OF THE FLOOD IRRIGATION SYSTEM
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF THE DEPLOYMENT OF TEMPORARY FLOOD IRRIGATION SYSTEM

VIEW OF A FLOOD IRRIGATION SYSTEM AS WATER IS DRAINED FROM THE STORAGE TANK
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

SITE INFORMATION

OFFICE ADDRESS: 16 MILES NORTH HIGHWAY 295 _____________________________

CITY: POWELL ___________ STATE: WY__ COUNTY: PARK_______________________ 

BASIN: BIG HORN_________FIELD: ELK BASIN____

CONTACT NAME/TITLE: JEFF SCHWEIGHART/SENIOR REGULATORY ANALYST –ANADARKO 

CONTACT NUMBER: (307) 754-7314

CONTACT NAME/TITLE: CRAIG EGGERMAN/ SENIOR ENV. ANALYST-WYOGCC

CONTACT NUMBER: (307)234-7147 

WATER MANAGEMENT TECHNOLOGIES/PRACTICES IN PLACE

DESCRIPTION: VISITED THE SOUTH WATER FLOOD BATTERY 8 (AVG 2100 BBLS

WATER/DAY MANAGED), NORTH WATER FLOOD BATTERY 7 (AVG 4400 BBLS

WATER/DAY MANAGED), AND NW ELK BASIN (IN MONTANA, 35 GPM WATER MANAGED).

A SCALE INHIBITOR IS APPLIED TO THE WATER PRIOR TO PUTTING THE WATER INTO THE 

TREATMENT SYSTEMS FOR THE TWO WATER FLOOD BATTERIES. THE TREATMENT SYSTEM 

TREATS THE WATER PRIOR TO DISCHARGE BY RUNNING THE WATER THROUGH SEVERAL 

PITS/BASINS WHERE BOOMS ARE EMPLOYED TO SEPARATE THE OIL ON THE SURFACE OF THE 

WATER AND OIL IS SKIMMED OFF OF THE TOP OF THE WATER (PHYSICAL TREATMENT). THE 

DISCHARGE WATER FLOWS FROM THROUGH A T-SYPHON AND DISCHARGES TO THE SILVER 

TIP CREEK, WHICH FLOWS NORTH, INTO MONTANA. THE CONFLUENCES WITH SILVER TIP 

CREEK WERE ALSO VISITED, ALONG WITH THE “SAFETY PITS” THAT ARE USED TO PREVENT 

SPILLS FROM MIGRATING FURTHER DOWNSTREAM (ADDITIONAL T-SYPHONS AT CRITICAL 

POINTS SUCH AS ROAD CROSSINGS). THE NW ELK BASIN DISCHARGE IS ON THE MONTANA 

SIDE OF ELK BASIN, AND IT DISCHARGES JUST UPSTREAM OF A WASHED OUT DAM ALONG 

SILVER TIP CREEK. THE WASHED OUT DAM IS CURRENTLY AWAITING APPROVAL FROM 

MDEQ FOR THE WORKPLAN THAT HAS BEEN DEVELOPED TO REMEDIATE THE SITE AFTER A 

SPILL THAT OCCURRED EARLIER THIS YEAR. THE DAM WASHED OUT DURING A STORM 

EVENT AS IT HAD NO PRIMARY/EMERGENCY SPILLWAY TO ELEVIATE THE FLOOD 

CONDITIONS.

ENVIRONMENTAL IMPACTS/BENEFITS: DISCHARGED WATER IS CONSUMED BY CATTLE,

DEER, AND OTHER WILDLIFE, AND HABITAT IS CREATED FOR WILDLIFE WHERE NONE WOULD 

BE PRESENT DUE TO THE SEASONAL CONDITION OF THE DRAINAGE (ONLY FLOWS DURING 

STORM EVENTS). THE WATER IS ALSO USED FOR IRRIGATION BY LOCAL FARMERS FOR 

WATERING CROPS.
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

APPLICABILITY: THE IRRIGATION INFRASTRUCTURE IN THE BIG HORN BASIN ALLOW FOR 

MUCH OF THE PRODUCED WATER TO BE USED BY LOCAL FARMERS AND RANCHERS FOR 

IRRIGATING CROPS AND KEEPING STOCK PONDS FULL OF WATER.

COST: NO INFORMATION WAS COLLECTED ON COST, BUT ANADARKO INDICATED THAT IF 

THE WYPDES REQUIREMENTS BECOME ANY MORE STRINGENT IT WILL BE MORE COST

EFFECTIVE TO DISPOSE OF THE WATER THROUGH INJECTION.

ADDITIONAL NOTES:_EROSION IS A PROBLEM AT DISCHARGE POINTS, DUE TO THE SOIL 

CONDITIONS AND THE DIFFICULTY WITH ESTABLISHING VEGETATION THAT IS NOT 

CONSIDERED NOXIOUS WEEDS.

THE EPA (JANE NACKETT) HAS HAD A DIFFICULT TIME ACCEPTING THE “SAFETY PIT”

PRACTICE FRO SPILL PREVENTION AND MANAGEMENT. WYOGCC AND ANADARKO 

POINTED OUT THAT IT IS UNREALISTIC TO BUILD BERMS IN THIS TERRAIN (LOTS OF HILLS 

AND STEEP GRADES) THAT WILL HOLD THE AMOUNT OF WATER THAT MAY BE DISCHARGED 

IN THE EVENT OF A SPILL (UNTREATED OILY WATER IS THE MAIN CONCERN FOR SPILLS AT 

THIS FIELD).

THE 230 PPM CHLORIDE RULE IS ALSO A CONCERN IF A WAIVER IS NOT EXTENDED TO THE 

OIL AND GAS INDUSTRY AS IT WILL MAKE IT UNFEASIBLE TO DISCHARGE AND MEET THE 

WYPDES REQUIREMENTS.

DATE: 6/27/2005____ INFORMATION COLLECTED BY: _JON SEEKINS, JAKE CRISSUP
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

PHOTO LOG

VIEW OF ELK BASIN FIELD ENTRANCE

VIEW OF SECONDARY PIT WITH SKIMMING BOOM
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF SECONDARY PIT T-SIPHON TO PREVENT OIL FROM DISCHARGING 

VIEW OF SECONDARY PIT DISCHARGE TO SILVER TIP CREEK 
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF T-SIPHONS IN SILVER TIP CREEK DRAINAGE TO 

PREVENT OIL SPILLS FROM MIGRATING DOWNSTREAM 

VIEW OF A PRIMARY PIT WITH NETTING TO PROTECT WILDLIFE
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF A SURFACE DISCHARGE AFTER OIL HAS BEEN SKIMMED FROM WATER

VIEW OF A LIVESTOCK/WILDLIFE WATER HOLE SUPPLIED BY PRODUCED WATER
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF A PIT WHERE OIL IS SEPARATED FROM THE DISCHARGE WITH A T-SIPHON

CLOSER VIEW OF A PIT WHERE OIL IS SEPARATED FROM THE DISCHARGE WITH A T-SIPHON
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

SITE INFORMATION

OFFICE ADDRESS: 1501 STAMPEDE AVE. _____________________________

CITY: CODY___________ STATE: WY__ COUNTY: PARK_______________________ 

BASIN: BIG HORN_________FIELD: GARLAND____

CONTACT NAME/TITLE: MARVIN BLAKESLEY/HES PROFESSIONAL – MARATHON

CONTACT NUMBER: (307) 527-2127

CONTACT NAME/TITLE: RON ???/TECHNICIAN?–MARATHON 

CONTACT NAME/TITLE: CRAIG EGGERMAN/ SENIOR ENV. ANALYST-WYOGCC

CONTACT NUMBER: (307)234-7147 

WATER MANAGEMENT TECHNOLOGIES/PRACTICES IN PLACE

DESCRIPTION: VISITED THE ARNOLDUS LAKE WHERE AN AVERAGE OF 80,000 BBLS

WATER/DAY IS DISCHARGED. PRIOR TO DISCHARE, THE WATER IS PRETREATED TO SKIM OIL 

IN FOUR GRAVITY FLOW BASINS/PITS. ALL FOURS PITS ARE COVERED WITH NETTING TO 

PREVENT BIRDS FROM COMING INTO CONTACT WITH THE WATER PRIOR TO DISCHARGE.

BETWEEN THE THIRD AND FOURTH BASIN THERE IS A CONCRETE DITCH THAT IS SEVERAL 

HUNDRED YARDS LONG THAT ACTS TO FURTHER AERATE THE WATER. HYDROGEN SULFIDE 

IS A CONCERN. IN ADDITION TO THE WATER DISCHARED TO ARNOLDUS LAKE, THERE ARE 8

INJECTION WELLS THAT ALSO DISPOSE OF WATER INTO THE MADISON FORMATION. ONE OF 

THE WELLS IS CAPABLE OF DISPOSING 50,000 BBLS/DAY.

ENVIRONMENTAL IMPACTS/BENEFITS: THE LAKE IS A LOW SPOT IN THE TOPOGRAPHY, AND 

WOULD BE A PLAYA LAKE IF NOT FOR THE PRODUCED WATER DISCHARGE. SEVERAL 

WATER FOWL USE THE LAKE AS HABITAT, AND THE WATER FOWL IS HUNTED FOR 

RECREATIONAL PURPOSES AS WELL.

APPLICABILITY: THE IRRIGATION INFRASTRUCTURE IN THE BIG HORN BASIN ALLOW FOR 

MUCH OF THE PRODUCED WATER TO BE USED BY LOCAL FARMERS AND RANCHERS FOR 

IRRIGATING CROPS AND KEEPING STOCK PONDS FULL OF WATER.

COST: NO INFORMATION WAS COLLECTED ON COST, BUT MARATHON INDICATED THAT IF 

THE WYPDES REQUIREMENTS BECOME ANY MORE STRINGENT IT WILL BE MORE COST

EFFECTIVE TO DISPOSE OF THE WATER THROUGH INJECTION.

ADDITIONAL NOTES: THE EPA (JANE NACKETT) HAS HAD A DIFFICULT TIME ACCEPTING 

THE “SAFETY PIT” PRACTICE FOR SPILL PREVENTION AND MANAGEMENT. WYOGCC AND 

MARATHON POINTED OUT THAT IT IS UNREALISTIC TO BUILD BERMS THAT WILL HOLD THE 
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

AMOUNT OF WATER THAT MAY BE DISCHARGED IN THE EVENT OF A SPILL (UNTREATED OILY 

WATER IS THE MAIN CONCERN FOR SPILLS AT THIS FIELD).

THE 230 PPM CHLORIDE RULE IS ALSO A CONCERN IF A WAIVER IS NOT EXTENDED TO THE 

OIL AND GAS INDUSTRY AS IT WILL MAKE IT UNFEASIBLE TO DISCHARGE AND MEET THE 

WYPDES REQUIREMENTS.

DATE: 6/27/2005____ INFORMATION COLLECTED BY: _JON SEEKINS, JAKE CRISSUP
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

PHOTO LOG

VIEW OF ARNOLDUS LAKE WHERE AND AVERAGE OF 80,000 BBLS/DAY IS DISCHARGED

VIEW OF PRIMARY PIT WITH NETTING WHERE THE WATER IS SKIMMED WITH T-SIPHONS
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF SECONDARY PIT WITH NETTING WHERE THE WATER IS 

POLISHED FURTHER WITH T-SIPHONS

VIEW OF SECONDARY PIT DISCHARGE WHERE WATER IS AERATED
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF WATER CHANNEL AFTER SECONDARY PIT, WHICH FEEDS INTO THE TERTIARY PIT

VIEW OF TERTIARY PIT WHERE FINAL POLISHING IS COMPLETED WITH A T-SIPHON
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF TERTIARY PIT DISCHARGE WHICH FEEDS INTO ARNOLDUS LAKE

CLOSER VIEW OF TERTIARY PIT DISCHARGE WHICH FEEDS INTO ARNOLDUS LAKE
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

SITE INFORMATION

OFFICE ADDRESS: _____________________________

CITY: HAMILTON DOME__________ STATE: WY__ COUNTY: HOT SPRINGS___________

BASIN: BIG HORN_________FIELD: HAMILTON DOME____

CONTACT NAME/TITLE: ROGER HART/FIELD TECHNICIAN – MERIT

CONTACT NUMBER: (307) 

CONTACT NAME/TITLE: CRAIG EGGERMAN/ SENIOR ENV. ANALYST-WYOGCC

CONTACT NUMBER: (307)234-7147 

WATER MANAGEMENT TECHNOLOGIES/PRACTICES IN PLACE

DESCRIPTION: VISITED THE TWO DISCHARGES AT HAMILTON DOME. BOTH DISCHARGES 

ARE WYPDES DISCHARGE POINTS, AND HAVE PITS THAT ARE UTILIZED TO SKIM OIL FROM 

THE SURFACE OF THE WATER PRIOR TO DISCHARGE. IN 2004, WYPDES PERMIT #

WY0000680, ALSO KNOWN AS THE “PLACER RATHVON”, DISCHARGED AN AVERAGE OF 

128,000-130,000 BBLS/DAY AND INJECTED ANYWHERE FROM 0-4700 BBLS/DAY.

MEANWHILE, WYPDES PERMIT # WY0000175, ALSO KNOWN AS THE “CEMENT PIT”,

DISCHARGED AN AVERAGE OF 50,000-68,000 BBLS/DAY AND INJECTED ANYWHERE FROM 

43,000-69,000 BBLS/DAY. BOTH DISCHARGES ARE BENEFICIALLY USED FOR IRRIGATION 

PURPOSES BY LOCAL LANDOWNERS. THE PLACER RATHVON SYSTEM IS CHANNELIZED AND 

PIPED INTO AN EXTENSIVE IRRIGATION SYSTEM THAT IRRIGATES SEVERAL THOUSAND 

ACRES OF ALFALFA FIELDS, AND THE CEMENT PIT SYSTEM IS CHANNELIZED AND HAS 

SEVERAL DIVERSION BOXES ALONG THE CHANNEL WHERE THE LOCAL LANDOWNER DIVERTS 

THE WATER AS NEEDED TO FLOOD IRRIGATE HIS LAND. ALL WATER NOT DIVERTED IS 

DISCHARGED TO A DOWNSTREAM WATER RIGHTS HOLDER ON THE COTTONWOOD CREEK TO 

ENHANCE RIPRARIAN HABITAT AND WATER LIVESTOCK. DURING NON-GROWING SEASON 

WHEN IRRIGATION IS NOT NECESSARY, THE WATER FROM THE PLACER RATHVON 

DISCHARGE IS DIVERTED TO LAKE CHARLIE, WHICH HAS T-SIPHONS TO PREVENT A SPILL 

FROM REACHING COTTONWOOD CREEK. MERIT HAS 250 OIL PRODUCING WELLS IN THIS 

FIELD, AND UTILIZES 80 INJECTION WELLS.

ENVIRONMENTAL IMPACTS/BENEFITS: IF NOT FOR THE PRODUCED WATER DISCHARGES,

THERE WOULD NOT BE ENOUGH WATER TO IRRIGATE THE LAND IN THE HAMILTON DOME 

FIELD, AND THE FARMERS WOULD NOT BE ABLE TO ACHIEVE THE SAME LEVEL OF SUCCESS 

THEY ARE CURRENTLY EXPERIENCING.

APPLICABILITY: THE IRRIGATION INFRASTRUCTURE IN THE BIG HORN BASIN ALLOW FOR 

MUCH OF THE PRODUCED WATER TO BE USED BY LOCAL FARMERS AND RANCHERS FOR 

IRRIGATING CROPS AND KEEPING STOCK PONDS FULL OF WATER.
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

COST: NO INFORMATION WAS COLLECTED ON COST, BUT MERIT INDICATED THAT IF THE 

WYPDES REQUIREMENTS BECOME ANY MORE STRINGENT (NOTABLY FOR CHLORIDES) IT 

WILL BE MORE COST EFFECTIVE TO DISPOSE OF THE WATER THROUGH INJECTION. THIS 

WOULD DENY THE FARMERS FROM UTILIZING THE BENEFICIAL USE OF IRRIGATION WITH THE

PRODUCED WATER.

ADDITIONAL NOTES: THE EPA (JANE NACKETT) HAS HAD A DIFFICULT TIME ACCEPTING 

THE “SAFETY PIT” PRACTICE FOR SPILL PREVENTION AND MANAGEMENT. WYOGCC AND 

MERIT POINTED OUT THAT IT IS UNREALISTIC TO BUILD BERMS THAT WILL HOLD THE 

AMOUNT OF WATER THAT MAY BE DISCHARGED IN THE EVENT OF A SPILL (UNTREATED OILY 

WATER IS THE MAIN CONCERN FOR SPILLS AT THIS FIELD).

THE 230 PPM CHLORIDE RULE IS ALSO A CONCERN IF A WAIVER IS NOT EXTENDED TO THE 

OIL AND GAS INDUSTRY AS IT WILL MAKE IT UNFEASIBLE TO DISCHARGE AND MEET THE 

WYPDES REQUIREMENTS. IT IS BELIEVED THAT THE 230 PPM FOR CHLORIDES HAS BEEN 

ESTABLISHED TO PROTECT CERTAIN AQUATIC LIFE. WY IS THE ONLY STATE THAT HAS A 

CHLORIDE STANDARD FOR CLASS III WATERS.

DATE: 6/28/2005____ INFORMATION COLLECTED BY: _JON SEEKINS, JAKE CRISSUP
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

PHOTO LOG

VIEW OF “PLACER RATHVON” SECONDARY PIT WHERE WATER IS POLISHED WITH A TSIPHON BEFORE DISCHARGE TO IRRIGATION FIELD

VIEW OF “PLACER RATHVON” SECONDARY PIT DISCHARGE TO IRRIGATION FIELD
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF WATER IN CHANNEL GRAVITY FLOWING TO IRRIGATION FIELD

VIEW OF ALFALFA FIELDS THAT BENEFIT FROM IRRIGATION IN HAMILTON DOME
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF LAKE CHARLIE (BYPASS RESERVOIR DURING NON-GROWING SEASON)

CLOSER VIEW OF LAKE CHARLIE T-SIPHONS USED TO PREVENT 
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

SPILLS FROM ENTERING COTTONWOOD CREEK DRAINAGE

VIEW OF “CEMENT PIT” PRIMARY PIT INPUT WITH NETTING TO PROTECT WILDLIFE

VIEW OF “CEMENT PIT” PRIMARY PIT DISCHARGE TO IRRIGATION CHANNEL
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF “CEMENT PIT” IRRIGATION CHANNEL WYPDES SAMPLING POINT
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF “CEMENT PIT” IRRIGATION CHANNEL DIVERSION BOX USED FOR FLOOD 

IRRIGATION
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

SITE INFORMATION

OFFICE ADDRESS: PO BOX 127 _____________________________

CITY: MEETEETSE___________ STATE: WY__ COUNTY: PARK_________________ 

BASIN: BIG HORN_________FIELD: LITTLE BUFFALO BASIN____

CONTACT NAME/TITLE: KEITH LARSON/PRODUCTION FOREMAN – CITATION 

CONTACT NUMBER: (307) 868-9300

CONTACT NAME/TITLE: LARRY PUTNEY/FIELD TECHNICIAN – CITATION 

CONTACT NAME/TITLE: CRAIG EGGERMAN/ SENIOR ENV. ANALYST-WYOGCC

CONTACT NUMBER: (307)234-7147 

WATER MANAGEMENT TECHNOLOGIES/PRACTICES IN PLACE

DESCRIPTION: VISITED THE TWO DISCHARGES INTO BUFFALO CREEK. BOTH DISCHARGES 

ARE WYPDES DISCHARGE POINTS, AND HAVE SEVERAL PITS THAT ARE UTILIZED TO SKIM 

OIL FROM THE SURFACE OF THE WATER PRIOR TO DISCHARGE. CITATION HAS 70 OIL 

PRODUCING WELLS IN THIS FIELD, AND UTILIZES 140 INJECTION WELLS, WHICH ARE MOSTLY 

CONVERTED OIL WELLS THAT WERE NON-PRODUCING. OF THE 116,500 BBLS OF WATER 

PRODUCED DAILY, APPROXIMATELY 72,000 BBLS OF WATER IS REINJECTED FOR 

SECONDARY RECOVERY. 2,800 BBLS WATER/DAY IS THE MOST A WELL WILL ACCEPT IN 

THEIR FIELD, AND SOME WELLS ACCEPT AS LITTLE AS 50 BBLS/DAY.

ENVIRONMENTAL IMPACTS/BENEFITS: IF NOT FOR THE PRODUCED WATER DISCHARGES,

BUFFALO CREEK WOULD BE AN INTERMITTENT STREAM THAT WOULD BE DRY MOST OF THE 

YEAR. THE PRODUCED WATER HAS CREATED SOME RIPRARIAN HABITAT WHICH PROMOTES 

ANTELOPE, DEER, WATERFOWL, AMONG OTHER WILDLIFE SPECIES.

APPLICABILITY: THE IRRIGATION INFRASTRUCTURE IN THE BIG HORN BASIN ALLOW FOR 

MUCH OF THE PRODUCED WATER TO BE USED BY LOCAL FARMERS AND RANCHERS FOR 

IRRIGATING CROPS AND KEEPING STOCK PONDS FULL OF WATER.

COST: NO INFORMATION WAS COLLECTED ON COST, BUT CITATION INDICATED THAT IF THE 

WYPDES REQUIREMENTS BECOME ANY MORE STRINGENT (NOTABLY FOR CHLORIDES) IT 

WILL BE MORE COST EFFECTIVE TO DISPOSE OF THE WATER THROUGH INJECTION.

ADDITIONAL NOTES: THE EPA (JANE NACKETT) HAS HAD A DIFFICULT TIME ACCEPTING 

THE “SAFETY PIT” PRACTICE FOR SPILL PREVENTION AND MANAGEMENT. WYOGCC AND 

CITATION POINTED OUT THAT IT IS UNREALISTIC TO BUILD BERMS THAT WILL HOLD THE 
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

AMOUNT OF WATER THAT MAY BE DISCHARGED IN THE EVENT OF A SPILL (UNTREATED OILY 

WATER IS THE MAIN CONCERN FOR SPILLS AT THIS FIELD).

THE 230 PPM CHLORIDE RULE IS ALSO A CONCERN IF A WAIVER IS NOT EXTENDED TO THE 

OIL AND GAS INDUSTRY AS IT WILL MAKE IT UNFEASIBLE TO DISCHARGE AND MEET THE

WYPDES REQUIREMENTS. IT IS BELIEVED THAT THE 230 PPM FOR CHLORIDES HAS BEEN 

ESTABLISHED TO PROTECT CERTAIN AQUATIC LIFE. WY IS THE ONLY STATE THAT HAS A 

CHLORIDE STANDARD FOR CLASS III WATERS.

DATE: 6/28/2005____ INFORMATION COLLECTED BY: _JON SEEKINS, JAKE CRISSUP
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

PHOTO LOG

VIEW OF LITTLE BUFFALO BASIN FIELD OFFICE ENTRANCE

VIEW OF INJECTION WELL UTILIZED FOR ENHANCED RECOVERY
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF FIRST PIT WITH T-SIPHON TO PREVENT OIL FROM DISCHARGING 

VIEW OF FIRST PIT’S DISCHARGE TO BUFFALO CREEK
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF SECOND PIT WITH TWO T-SIPHONS TO PREVENT OIL FROM DISCHARGING 

VIEW OF SECOND PIT’S DISCHARGE TO BUFFALO CREEK
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

SITE INFORMATION

OFFICE ADDRESS: 1501 STAMPEDE AVE. _____________________________

CITY: CODY___________ STATE: WY__ COUNTY: PARK_______________________ 

BASIN: BIG HORN_________FIELD: OREGON BASIN____

CONTACT NAME/TITLE: MARVIN BLAKESLEY/HES PROFESSIONAL – MARATHON

CONTACT NUMBER: (307) 527-2127

CONTACT NAME/TITLE: CRAIG EGGERMAN/ SENIOR ENV. ANALYST-WYOGCC

CONTACT NUMBER: (307)234-7147 

WATER MANAGEMENT TECHNOLOGIES/PRACTICES IN PLACE

DESCRIPTION: VISITED THE CUSTER LAKE WHERE AN AVAERAGE OF 30,000 BBLS OF 

WATER/DAY IS DISCHARGED TO. THERE WERE NO DISCHARGES TODAY, AND MARATHON 

INDICATED THAT SOME WORK WAS PROBABLY BEING DONE. THE WATER IS PRE-TREATED 

PRIOR TO DISCHARGE INTO CUSTER LAKE BY RUNNING THE WATER THROUGH SEVERAL PITS

THROUGH GRAVITY FLOW AND SKIMMING OIL OFF OF THE SURFACE OF THE WATER 

THROUGH A SERIES OF BOOMS. A T-SYPHON IS EMPLOYED AT EACH PIT TO MINIMIZE OIL 

PROGRESSION TO THE NEXT PIT. APPROXIMATELY 500,000 BBLS OF WATER/DAY IS 

PRODUCED IN THIS FIELD, AND 400,000 BBLS/DAY OF IT IS REINJECTED INTO THE MADISON 

FORMATION FOR SECONDARY RECOVERY. LOCH CATRIN IS FURTHER DOWNSTREAM FROM 

CUSTER LAKE, AND PORTIONS OF LOCH CATRIN HAVE DRIED UP BECAUSE THE WATER HAS 

NOT MADE IT THAT FAR DOWNSTREAM FOR SOME TIME.

ENVIRONMENTAL IMPACTS/BENEFITS: SEVERAL SPECIES OF WILDLIFE AND WATER FOWL 

USE THE LAKE AS HABITAT, AND THE WATER FOWL IS HUNTED FOR RECREATIONAL 

PURPOSES AS WELL.

APPLICABILITY: THE IRRIGATION INFRASTRUCTURE IN THE BIG HORN BASIN ALLOW FOR 

MUCH OF THE PRODUCED WATER TO BE USED BY LOCAL FARMERS AND RANCHERS FOR 

IRRIGATING CROPS AND KEEPING STOCK PONDS FULL OF WATER.

COST: NO INFORMATION WAS COLLECTED ON COST, BUT MARATHON INDICATED THAT IF 

THE WYPDES REQUIREMENTS BECOME ANY MORE STRINGENT (NOTABLY FOR CHLORIDES)

IT WILL BE MORE COST EFFECTIVE TO DISPOSE OF THE WATER THROUGH INJECTION.

MARATHON HAS ESTIMATED THAT BASIN WIDE IT WOULD COST THEM 12-15 MILLION 

DOLLARS IN CAPITAL COSTS TO CONVERT TO A 100% DISPOSAL OPTION THROUGH 

REINJECTION, AND ABOUT 1-2 MILLION IN OPERATING COSTS PER YEAR.
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

ADDITIONAL NOTES: THE EPA (JANE NACKETT) HAS HAD A DIFFICULT TIME ACCEPTING 

THE “SAFETY PIT” PRACTICE FOR SPILL PREVENTION AND MANAGEMENT. WYOGCC AND 

MARATHON POINTED OUT THAT IT IS UNREALISTIC TO BUILD BERMS THAT WILL HOLD THE 

AMOUNT OF WATER THAT MAY BE DISCHARGED IN THE EVENT OF A SPILL (UNTREATED OILY 

WATER IS THE MAIN CONCERN FOR SPILLS AT THIS FIELD).

THE 230 PPM CHLORIDE RULE IS ALSO A CONCERN IF A WAIVER IS NOT EXTENDED TO THE 

OIL AND GAS INDUSTRY AS IT WILL MAKE IT UNFEASIBLE TO DISCHARGE AND MEET THE 

WYPDES REQUIREMENTS. IT IS BELIEVED THAT THE 230 PPM FOR CHLORIDES HAS BEEN 

ESTABLISHED TO PROTECT CERTAIN AQUATIC LIFE. WY IS THE ONLY STATE THAT HAS A 

CHLORIDE STANDARD FOR CLASS III WATERS.

DATE: 6/28/2005____ INFORMATION COLLECTED BY: _JON SEEKINS, JAKE CRISSUP
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

PHOTO LOG

VIEW OF ENTRANCE TO OREGON BASIN FIELD

VIEW OF CUSTER LAKE WITH OIL RIG IN BACKGROUND
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF CUSTER LAKE WITH PIT SYSTEM IN BACKGROUND

CLOSER VIEW OF PIT SYSTEM THAT DISCHARGES TO CUSTER LAKE
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

SITE INFORMATION

OFFICE ADDRESS: SITE VISITED NORTH OF I-90

CITY: BETWEEN GILLETTE AND BUFFALO STATE: WY__ COUNTY: JOHNSON________ 

BASIN: POWDER RIVER_________FIELD: PRB CBM____

CONTACT NAME/TITLE: RICK WAAS/ DRILLING INSPECTOR-WYOGCC

CONTACT NUMBER: (307)358-4101 

WATER MANAGEMENT TECHNOLOGIES/PRACTICES IN PLACE

DESCRIPTION: AN EMIT WATER TREATMENT PLANT WAS VISITED NORTH OF I-90 JUST OFF 

OF THE POWDER RIVER. THE WATER TREATMENT PLANT WAS NOT DISCHARGING AT THE 

TIME OF THE VISIT. THE FOLLOWING PROCESS DESCRIPTION WAS TAKEN FROM THE EMIT

TECHNOLOGIES WEBSITE, WWW.EMITTECHNOLOGIES.COM :

COMMERCIALLY AVAILABLE CATION & ANION RESINS ARE USED TO PURIFY PRODUCED 

WATER OF SODIUM, CHLORIDE, SULFATE AND OTHER IONS IN BOTH A CONTINUOUS AND 

COUNTERCURRENT OPERATING MODE. THESE CHEMICAL ENGINEERING PRINCIPLES OF 

MASS TRANSFER MAXIMIZE THE RESINS’ ABILITIES IN PURIFYING WATER WITH A 

CONSISTENT QUALITY. THEY ALSO OPTIMIZE THE USE OF ACID AND ALKALI REGENERANTS,

MINIMIZE THEIR VOLUMES AND GENERATE A DENSE BRINE SOLUTION THAT MAY HAVE 

VALUE AS A CLEAR BRINE FLUID WITHIN THE OIL AND GAS INDUSTRY. THE KEY TO THE 

HIGGINS LOOP FEATURES IS ITS ABILITY TO MOVE THE RESIN THROUGH THE LOOP VIA 

INCREMENTAL “PULSING”. THE PULSE VESSEL SERVES AS A RESIN FLOW METER TO ENSURE 

ITS FLOW IS IN PROPORTION TO THE WATER TREATED AND THE AMOUNT OF REGENERANT 

CONSUMED.

PRODUCED WATER CONTAINING HIGH NA LEVELS IS FED TO THE ADSORPTION ZONE WITHIN 

THE HIGGINS LOOP WHERE IT CONTACTS STRONG ACID CATION RESIN WHICH LOADS NA+

IONS IN EXCHANGE FOR HYDROGEN (H-) IONS. TREATED WATER EXITS THE LOOP 

CONTAINING LESS THAN 10 MG/L NA.

CONCURRENT WITH ADSORPTION AND IN THE LOWER SECTION OF THE HIGGINS LOOP,

NA-LOADED RESIN IS REGENERATED WITH EITHER HYDROCHLORIC OR SULFURIC ACID TO 

PRODUCE A SMALL, CONCENTRATED SPENT BRINE STREAM. REGENERATED RESIN IS RINSED 

WITH WATER PRIOR TO REENTERING THE ADSORPTION ZONE TO REMOVE ACID FROM ITS 

PORES.

AS RESIN IN THE UPPER LAYER OF THE ADSORPTION ZONE BECOMES LOADED WITH NA, THE 

FLOWS TO THE HIGGINS LOOP ARE MOMENTARILY INTERRUPTED TO ALLOW ADVANCEMENT 
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

OF THE RESIN BED (PULSING) THROUGH THE LOOP IN THE OPPOSITE DIRECTION OF LIQUID 

FLOW. LIQUID FLOWS ARE RESTARTED AFTER RESIN PULSING IS COMPLETE.

TREATED WATER IS SLIGHTLY ACIDIC DUE TO ITS INCREASED H- ION STRENGTH, AND IT IS 

NEUTRALIZED WITH LIMESTONE, WHICH ALSO INCREASES ITS CALCIUM CONCENTRATION SO 

THAT THE WATER’S SODIUM ADSORPTION RATIO (SAR) IS LESS THAN 1.0. SPENT BRINE 

CONTAINING REMOVED NA+ IONS HAS A DENSITY HIGH ENOUGH FOR USE AS A KILL FLUID.

ENVIRONMENTAL IMPACTS/BENEFITS: TREATING PRODUCED WATER WITH THIS 

TECHNOLOGY PROVIDES ENVIRONMENTAL BENEFITS BY ALLOWING FOR THE WATER TO BE 

BENEFICIALLY USED BY IMPROVING THE SAR AND LOWERING THE TDS. ONCE THE WATER 

IS TREATED, IT CAN BE PUT BACK INTO A SURFACE STREAM FOR USE BY LIVESTOCK,

WILDLIFE, AND DOWNSTREAM WATER RIGHTS HOLDERS, OR IT CAN BE IRRIGATED 

IMMEDIATELY.

APPLICABILITY: THE HIGGINS LOOP HAS BEEN IN USE SINCE WWII, AND THE USE OF THE 

EMIT TECHNOLOGY IS GROWING IN THE POWDER RIVER BASIN ON BOTH THE WYOMING 

AND MONTANA SIDE. THIS TECHNOLOGY IS USEFUL IN LOWERING SODIUM, BICARBONATES,

SAR VALUES, AND OVERALL TDS TO BELOW NPDES PERMIT REQUIREMENTS.

COST: NO INFORMATION WAS COLLECTED ON COST. THE WEBSITE STATES THAT COST IS A 

FIXED COST AND IS CHEAPER THAN SEVERAL OF THE CURRENT TREATMENT ALTERNATIVES.

ADDITIONAL NOTES: NONE

DATE: 6/30/2005____ INFORMATION COLLECTED BY: _JON SEEKINS, JAKE CRISSUP
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

PHOTO LOG

VIEW OF A EMIT ION EXCHANGE PLANT

VIEW OF A PULSE AND ADSORPTION TANK
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF A PULSE WATER TANK

VIEW OF THE BACK WASH LOOP
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF THE RESIN RECOVERY TANK

VIEW OF THE ACID FEED TANKS
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF A LIME REACTOR BED TO ADJUST PH PRIOR TO DISCHARGE

VIEW OF A POND THAT THE EMIT PLANT DISCHARGES TO PRIOR TO ENTERING THE 

POWDER RIVER
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

SITE INFORMATION

OFFICE ADDRESS: VARIOUS SITES VISITED SOUTH OF I-90

CITY: BETWEEN GILLETTE AND BUFFALO STATE: WY__ COUNTY: JOHNSON________ 

BASIN: POWDER RIVER_________FIELD: PRB CBM____

CONTACT NAME/TITLE: RICK WAAS/ DRILLING INSPECTOR-WYOGCC

CONTACT NUMBER: (307)358-4101 

WATER MANAGEMENT TECHNOLOGIES/PRACTICES IN PLACE

DESCRIPTION: VARIOUS CBM SITES WERE VISISTED, AND VARIOUS TYPES OF PRODUCED 

WATER MANAGEMENT TECHNIQUES AND TECHNOLOGIES WERE VIEWED. THE FIRST STOP 

WAS AT THE CONSTRUCTION SITE OF A FUTURE WATER TRUCK LOAD OUT FACILITY AND 

TRUCK WASH OUT STATION THAT WILL USE PRODUCED WATER AS THE SOURCE OF WATER 

FOR THE FACILITY. THE SITE WAS CONVENIENTLY LOCATED OFF OF I-90 BETWEEN 

GILLETTE AND BUFFALO.

ALSO NOTED JUST NORTH OF I-90 WAS A DRILL RIG THAT IS DRILLING A 14,250 FT DEEP 

INJECTION WELL FOR DEEP INJECTION DISPOSAL OF PRODUCED WATER.

THE NEXT WATER MANAGEMENT TECHNIQUE NOTED WAS A WATER TANK FOR CATTLE THAT 

WAS MADE FROM A TRACTOR TIRE AND HAS PRODUCED WATER “ON TAP”. THE WATER 

DOES NOT FLOW FREELY INTO THE WATER TANK, BUT RATHER, THE HYDRANT CAN BE 

TURNED ON AT THE RANCHERS DISCRETION. THE WATER IS PIPED TO THE WATER TANK AND 

IS UNDER PRESSURE SO THAT IT WILL FLOW. THIS IS A GOOD USE OF THE WATER BY 

ALLOWING A SOURCE OF WATER TO BE AVAILABLE IN A REMOTE LOCATION TO PROMOTE 

CATTLE FORAGING IN OTHER AREAS.

THE NEXT SITE VISITED WAS A POND WITH SPRAY EVAPORATION ATOMIZERS. THE 

TECHNOLOGY WAS NOT BEING OPERATED AT THE TIME WITH THE REASON CITED BY THE 

OPERATOR THAT THE EVAPORATION WAS NOT ENHANCED AS MUCH AS WAS EXPECTED.

WATER FROM THE 12 PRODUCING WELLS IN THIS AREA IS CURRENTLY BEING DISCHARGED 

INTO A SHALLOW AQUIFER AT A RATE OF 11,000 BBLS/DAY INTO 6 INJECTION WELLS THAT 

ARE ALL AROUND 100 FEET DEEP. CHLORINE TABLETS ARE ADDED TO THE WATER PRIOR TO 

INJECTION TO KILL BACTERIA AND PREVENT HYDROGEN SULFIDE ACCUMULATION. NO GAS 

HAS BEEN PRODUCED FROM THE 12 PRODUCING WELLS YET, AND THE OPERATOR IS WAITING 

FOR PRODUCTION TO INCREASE IN NEARBY LEASES TO HELP DRAW DOWN THE PRESSURE 

GRADIENT ON THE COAL SEAM.

ENVIRONMENTAL IMPACTS/BENEFITS: PROVIDING A CONSISTENT SOURCE OF WATER FOR 

LIVESTOCK AND WILDLIFE AND PROVIDING HABITAT FOR FISH AND WATERFOWL AND THE 
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

PRIMARY ENVIRONMENTAL BENEFITS ACHIVED BY THESE TREATMENT TECHNOLOGIES.

FURTHERMORE, BY UTILIZING THE PRODUCED WATER FOR INDUSTRIAL PURPOSES AT THE 

WATER TRUCK LOADOUT STATION, IT HELPS TO CONSERVE WATER FOR OTHER HUMAN USES 

SUCH AS CONSUMPTION.

APPLICABILITY: THE CBM WATER FROM THIS PORTION OF THE PRB CAN BE USED FOR 

INDUSTRIAL APPLICATIONS, STOCK AND WILDLIFE WATERING, AND RECREATION PURPOSES.

TREATMENT PROCESSES OBSERVED (ZEOLITE, REVERSE OSMOSIS, AND INO EXCHANGE)

ARE DISCUSSED INDIVIDUALLY IN SEPARATE SITE SUMMARIES.

COST: NO INFORMATION WAS COLLECTED ON COST.

ADDITIONAL NOTES: NONE

DATE: 6/30/2005____ INFORMATION COLLECTED BY: _JON SEEKINS, JAKE CRISSUP
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

PHOTO LOG

VIEW OF THE ENTRANCE TO A WATER TRUCK LOADOUT/WASH FACILITY JUST OFF OF I-90

THAT WILL USE CBM PRODUCED WATER

VIEW OF THE WATER TRUCK LOADOUT/WASH FACILITY UNDER CONSTRUCTION
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF A 14,250’ DEEP INJECTION WELL THAT IS BEING DRILLED NEAR I-90

VIEW OF A TIRE STOCK TANK THAT IS SUPPLIED BY CBM PRODUCED WATER ON DEMAND
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF ATOMIZER OPERATED BY MCCARTNEY ENGINEERING ON JONES PIT 41-18

VIEW OF A SHALLOW INJECTION WELL ON THE JONES RANCH OPERATED BY MCCARTNEY
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

SITE INFORMATION

OFFICE ADDRESS: VARIOUS SITES VISITED_______

CITY: WRIGHT, SIOUX RANCH______ STATE: WY__ COUNTY: CAMPBELL___________ 

BASIN: POWDER RIVER_________FIELD: PRB CBM____

CONTACT NAME/TITLE: RICK WAAS/ DRILLING INSPECTOR-WYOGCC

CONTACT NUMBER: (307)358-4101 

WATER MANAGEMENT TECHNOLOGIES/PRACTICES IN PLACE

DESCRIPTION: VISITED A CBM DISCHARGE INTO HAYS CREEK WHERE THE PRODUCED 

WATER IS USED TO IRRIGATE A GOLF COURSE NEAR THE TOWN OF WRIGHT, WY. ALSO 

VISITED THE 13,000 ACRE SIOUX RANCH14 MILES SOUTH OF WRIGHT ON HWY 59 AND 

VIEWED SEVERAL PONDS THAT HAVE BEEN REJUVENATED WITH CBM PRODUCED WATER.

ACCORDING TO THE LAND OWNER, EDDIE RENO, THE PONDS WERE DRYING UP DUE TO THE 

DROUGHT, AND THEY HAD NO WATER TO IRRIGATE WITH. THEY HAD TO STOP RUNNING 

CATTLE ON THE LAND IN ORDER TO ALLOW THE GRASS TO RECOVER FROM THE DROUGHT 

PERIOD. NOW THAT WATER IS READILY AVAILABLE FROM CBM PRODUCTION THE PONDS 

ARE FULL AGAIN AND WILDLIFE IS FLOURISHING, THE PONDS ARE USED FOR RECREATIONAL 

PURPOSES, AND THEY PLAN TO PUT CATTLE BACK ON THE LAND AS SOON AS NEXT YEAR.

ENVIRONMENTAL IMPACTS/BENEFITS: ACCORDING TO THE LAND OWNER AT SIOUX RANCH,

EDDIE RENO, THE EXISTING STOCK PONDS WERE DRYING UP DUE TO THE DROUGHT, AND 

THEY HAD NO WATER TO IRRIGATE WITH. THEY HAD TO STOP RUNNING CATTLE ON THE 

LAND IN ORDER TO ALLOW THE GRASS TO RECOVER FROM THE DROUGHT. NOW THAT 

WATER IS READILY AVAILABLE FROM CBM PRODUCTION THE PONDS ARE FULL AGAIN AND

WILDLIFE IS FLOURISHING, THE PONDS ARE USED FOR RECREATIONAL PURPOSES, AND THEY 

PLAN TO PUT CATTLE BACK ON THE LAND AS SOON AS NEXT YEAR.

APPLICABILITY: THE CBM WATER FROM THIS PORTION OF THE PRB IS FRESH, SO IT CAN 

READILY BE USED FOR IRRIGATION, STOCK AND WILDLIFE WATERING, AND RECREATION 

PURPOSES. NO TREATMENT IS REQUIRED.

COST: NO INFORMATION WAS COLLECTED ON COST.

ADDITIONAL NOTES: NONE

DATE: 6/29/2005____ INFORMATION COLLECTED BY: _JON SEEKINS, JAKE CRISSUP
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

PHOTO LOG

VIEW OF CBM PRODUCED WATER DISCHARGE TO HAYS CREEK, NEAR GOLF COURSE IN 

WRIGHT, WY 

VIEW OF A IRRIGATION POND ON GOLF COURSE WITH A FOUNTAIN TO AERATE THE WATER
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF A TIRE LIVESTOCK WATER TANK DISCHARGING TO AN EXISTING POND ON THE 

SIOUX RANCH

VIEW OF A PRODUCED WATER POND USED FOR FLOOD IRRIGATION ON THE SIOUX RANCH
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF A DEER NEAR A PRODUCED WATER POND ON THE SIOUX RANCH

VIEW OF A COMPRESSOR STATION ON THE SIOUX RANCH
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

SITE INFORMATION

OFFICE ADDRESS: SITE VISITED SOUTH OF I-90

CITY: BETWEEN GILLETTE AND BUFFALO STATE: WY__ COUNTY: JOHNSON________ 

BASIN: POWDER RIVER_________FIELD: PRB CBM____

CONTACT NAME/TITLE: RON LINCZ/ NEWPARK ENVIRONMENTAL WATER SOLUTIONS

CONTACT NUMBER: (403)861-4075 

CONTACT NAME/TITLE: RICK WAAS/ DRILLING INSPECTOR-WYOGCC

CONTACT NUMBER: (307)358-4101 

WATER MANAGEMENT TECHNOLOGIES/PRACTICES IN PLACE

DESCRIPTION: NEWPARK ENVIRONMENTAL WATER SOLUTIONS (NEWS) IS CONSTRUCING 

AND HAS PLANS FOR OPERATING A 20,000 BBLS/DAY WATER TREATMENT PLANT TO 

REDUCE SAR VALUES TO BELOW WYPDES PERMIT LEVELS AND ALLOW DISCHARGE TO 

THE SURFACE. THE WATER TREATMENT PLANT UTILIZES REVERSE OSMOSIS TECHNOLOGY

TO REMOVE THE CHARGED IONS AND LOWER THE SAR AND THE TDS IN THE WATER,

HOWEVER, IT ALSO EMPLOYS A PATENTED TECHNOLOGY TO TREAT THE WATER BEFORE THE 

RO UNIT TO MINIMIZE FOULING OF THE RO MEMBRANES.

THE PATENTED TECHNOLOGY IS BASED ON THE EMERGING SCIENCE OF SONOCHEMISTRY.

NEWS IS APPLYING THIS TECHNOLOGY INITIALLY TO WASTEWATER TREATMENT. HIGHFREQUENCY SOUND WAVES ARE USED TO POWER PHYSICAL-CHEMICAL REACTIONS. THESE 

ULTRASONIC SOUND WAVES, IN LIQUIDS, CAUSE THE FORMATION OF MICRO BUBBLES THAT 

COLLAPSE AT EXTREMELY HIGH TEMPERATURES AND PRESSURES AT THE MOLECULAR 

LEVEL GENERATING NOVEL CHEMICAL REACTIONS WITH MINIMAL EFFECT ON AMBIENT 

TEMPERATURES.

AT THE CORE OF THE NEWS WASTEWATER TREATMENT PROCESS IS AN INSTRUMENT 

REFERRED TO AS AN ARMEL ACTIVATOR. IT MANAGES THE FLOW DYNAMICS OF THE 

WASTEWATER STREAM BY PRESSURE AND SOUND FREQUENCY VARIATIONS. THIS PROVIDES 

TURBULENT MIXING, ULTRASONIC PRESSURE WAVES AND CAVITATION. INTERMOLECULAR 

DISTANCES ARE SHORTENED AMONG MOLECULES WITH AN INCREASE IN SPECIFIC CONTACT 

SURFACES.

THE RESULTS ARE THAT DESIRED REACTIONS DOWNSTREAM OF THE ARMEL ACTIVATOR 

(SUCH AS COAGULANT ADDITION AND FLOCCULATION) OCCUR WITH VERY SHORT 

RETENTION TIMES AND WITHOUT EXCESSIVE USE OF CHEMICAL ADDITIVES.

A SMALLER PLANT HAS BEEN CONSTRUCTED AND IS CURRENTLY IN USE TO REMOVE 
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

DISSOLVED SOLIDS FROM THE WASTEWATER GENERATED BY OIL AND GAS PRODUCTION 

ACTIVITIES IN THE PINEDALE/JONAH FIELDS IN THE GREATER GREEN RIVER BASIN OF 

WYOMING. CONSTITUENTS WILL BE LOWERED TO LEVELS THAT WILL ALLOW DISCHARGE 

UNDER AN NPDES PERMIT INTO THE COLORADO RIVER BASIN.

ENVIRONMENTAL IMPACTS/BENEFITS: TREATING PRODUCED WATER WITH THIS 

TECHNOLOGY PROVIDES ENVIRONMENTAL BENEFITS BY ALLOWING FOR THE WATER TO BE 

BENEFICIALLY USED BY IMPROVING THE SAR AND LOWERING THE TDS. ONCE THE WATER 

IS TREATED, IT CAN BE PUT BACK INTO A SURFACE STREAM FOR USE BY LIVESTOCK,

WILDLIFE, AND DOWNSTREAM WATER RIGHTS HOLDERS, OR IT CAN BE IRRIGATED 

IMMEDIATELY.

APPLICABILITY: THIS TREATMENT TECHNOLOGY IS EMERGING. THE SUCCESS OF THIS 

TECHNOLOGY WILL BE CLOSELY TIED TO THE SUCCESS OF THE TECHNOLOGY TO 

EFFECTIVELY AND EFFICIENTLY TREAT WATER FROM THE PINEDALE/JONAH FIELD AS WELL 

AS CBM WATER FROM THE POWDER RIVER BASIN TO BELOW THEIR PERMIT LIMITS.

COST: COST IS EXTREMELY VARIABLE BASED ON THE WATER QUALITY AND THE LEVEL OF 

THE DESIRED WATER QUALITY.

ADDITIONAL NOTES: NONE

DATE: 6/30/2005____ INFORMATION COLLECTED BY: _JON SEEKINS, JAKE CRISSUP
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

PHOTO LOG

VIEW OF A REVERSE OSMOSIS PLANT UNDER CONSTRUCTION

VIEW OF A SKID MOUNTED REVERSE OSMOSIS SYSTEM
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

SITE INFORMATION

OFFICE ADDRESS: VARIOUS SITES VISITED OF OFF I-90

CITY: BETWEEN GILLETTE AND BUFFALO STATE: WY__ COUNTY: JOHNSON________ 

BASIN: POWDER RIVER_________FIELD: PRB CBM____

CONTACT NAME/TITLE: RICK WAAS/ DRILLING INSPECTOR-WYOGCC

CONTACT NUMBER: (307)358-4101 

WATER MANAGEMENT TECHNOLOGIES/PRACTICES IN PLACE

DESCRIPTION: TWO EXISTING ZEOLITE FACILITIES WERE VISITED, AND ONE ZEOLITE 

FACILITY THAT IS UNDER CONSTRUCTION WAS VISITED. OF THE TWO EXISTING ZEOLITE 

FACILITIES, ONLY ONE WAS CURRENTLY BEING DISCHARGED TO.

ZEOLITE IS A NATURALLY OCCURING MINERAL THAT CAN BE MINED, CRUSHED, AND 

MODIFIED TO ENHANCE THE CATION EXCHANGE CAPACITY OF THE MINERAL. THE ZEOLITE 

IS THEN PLACED IN A COLUMN, OR A PIT, AND PRODUCED WATER IS PASSED THROUGH IT TO 

ALLOW FOR THE CHARGED IONS IN THE WATER (SUCH AS SODIUM) TO BE EXCHANGED FOR

THE CHARGED IONS IN THE ZEOLITE (SUCH AS CALCIUM AND MAGNESIUM). THE EXCHANGE 

OF SODIUM FOR CALCIUM AND MAGNESIUM ALLOWS FOR THE SODIUM ADSORPTION RATIO 

(SAR) TO BE LOWERED, WHICH IN EFFECT RENDERS THE WATER CAPABLE FOR USE IN 

IRRIGATION, OR FOR A DIRECT DISCHARGE TO A STREAM/CREEK.

ENVIRONMENTAL IMPACTS/BENEFITS: TREATING PRODUCED WATER WITH ZEOLITE 

PROVIDES ENVIRONMENTAL BENEFITS BY ALLOWING FOR THE WATER TO BE BENEFICIALLY 

USED BY IMPROVING THE SAR. ONCE THE WATER IS TREATED, IT CAN BE PUT BACK INTO A 

SURFACE STREAM FOR USE BY LIVESTOCK, WILDLIFE, AND DOWNSTREAM WATER RIGHTS 

HOLDERS, OR IT CAN BE IRRIGATED IMMEDIATELY.

APPLICABILITY: ZEOLITE IS AN EFFECTIVE TREATMENT TECHNOLOGY FOR USE ON WATER 

CONTAINING HIGH LEVELS OF SODIUM, AS IT IMPROVED THE SAR VALUES BY EXCHANGING 

SODIUM FOR CALCIUM AND MAGNESIUM.

COST: NO INFORMATION WAS COLLECTED ON COST.

ADDITIONAL NOTES: NONE

DATE: 6/30/2005____ INFORMATION COLLECTED BY: _JON SEEKINS, JAKE CRISSUP
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

PHOTO LOG

VIEW OF A ZEOLITE WATER TREATMENT SYSTEM

VIEW OF A ZEOLITE PLANT UNDER CONSTRUCTION
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

SITE INFORMATION

OFFICE ADDRESS: SALT CREEK OPERATION CENTER,1MILE SOUTH OF MIDWEST_______

CITY: MIDWEST__________ STATE: WY__ COUNTY: NATRONA___________ 

BASIN: POWDER RIVER_________FIELD: SALT CREEK____

CONTACT NAME/TITLE: JOHN FARRELL/ ANADARKO 

CONTACT NUMBER: (307)437-9568 

CONTACT NAME/TITLE: RICK WAAS/ DRILLING INSPECTOR-WYOGCC

CONTACT NUMBER: (307)358-4101 

WATER MANAGEMENT TECHNOLOGIES/PRACTICES IN PLACE

DESCRIPTION: VISITED TWO RECREATION PONDS THAT ARE SUPPLIED BY PRODUCED WATER 

FROM THE SALT CREEK FIELD. THE FIRST POND HAS AN EARTHEN SPILLWAY THAT 

REQUIRES SOME ADDITIONAL EARTHWORK DUE TO EROSION PROBLEMS THAT HAVE 

OCCURRED. THE SECOND POND HAS A PIPE SPILLWAY AND AN EARTHEN EMERGENCY 

SPILLWAY. THE TWO PONDS ARE SUPPLIED BY PRODUCED WATER AT A RATE OF 5 GPM.

WATER DISCHARGES FROM THE RECREATION PONDS TO THE SALT CREEK, WHICH 

EVENTUALLY FEEDS INTO THE POWDER RIVER. A TOTAL OF APPROXIMATELY 350 BBLS OF 

WATER/DAY IS DISCHARGED TO THE TWO PONDS, AND THE REMAINDER OF THE WATER

PRODUCED (CLOSE TO 600,000 BBLS/DAY) IS RE-INJECTED INTO ENHANCED RECOVERY 

WELLS AND DISPOSAL WELLS. THE SALT CREEK FIELD IS THE SECOND LARGEST WATER 

PRODUCING FIELD IN WYOMING.

ENVIRONMENTAL IMPACTS/BENEFITS: THE RECREATION PONDS ARE STOCKED WITH FISH 

AND ARE WIDELY USED BY SPORT FISHERMAN. WILDLIFE SUCH AS WATERFOWL AND 

ANTELOPE ALSO USE THE RECREATION PONDS FOR WATER AND HABITAT.

APPLICABILITY: THE INJECTION OF THE WATER FOR ENHANCED RECOVERY IS A BENEFICIAL

USE, AS WELL AS THE RECREATION USE OF THE WATER FOR FISHING AND WILDLIFE HABITAT.

A PIPELINE TO PIPE CBM PRODUCED WATER FROM THE POWDER RIVER CBM FIELDS IS 

ALSO UNDER CONSIDERATION FOR USE IN ENHANCED RECOVERY AND INJECTION DISPOSAL 

INO THE MADISON FORMATION TO COOL THE FORMATION.

COST: NO INFORMATION WAS COLLECTED ON COST.

ADDITIONAL NOTES: NONE

DATE: 6/29/2005____ INFORMATION COLLECTED BY: _JON SEEKINS, JAKE CRISSUP
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

PHOTO LOG

VIEW OF ENTRANCE TO RECREATION POND SUPPLIED BY SALT CREEK PRODUCED WATER

VIEW OF A PVC PIPE THAT DELIVER PRODUCED WATER TO RECREATION POND
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

SITE INFORMATION

OFFICE ADDRESS: _____________________________

CITY: TEAPOT DOME__________ STATE: WY__ COUNTY: NATRONA___________ 

BASIN: POWDER RIVER_________FIELD: TEAPOT DOME____

CONTACT NAME/TITLE: RICK WAAS/ DRILLING INSPECTOR-WYOGCC

CONTACT NUMBER: (307)358-4101 

WATER MANAGEMENT TECHNOLOGIES/PRACTICES IN PLACE

DESCRIPTION: VISITED THE ROCKY MOUNTAIN OILFIELD TESTING CENTER’S (RMOTC)

TESTING LABORATORIES WHERE PRODUCED WATER IS USED TO RAISE SHRIMP AND TILAPIA 

IN LARGE TANKS. A GREENHOUSE IS ALSO ONSITE TO TEST THE ABILITY OF DIFFERENT 

SPECIES OF PLANTS TO BE IRRIGATED WITH PRODUCED WATER THAT HAS HIGHER SALINITY.

THE TEAPOT NAVAL RESERVE IS ALSO A WORKING OIL AND GAS FIELD THAT PRODUCES 

ABOUT 700 BBLS OF OIL/DAY AND ABOUT 50,000 BBLS OF WATER/DAY. THE PRODUCED 

WATER IS MANAGED THROUGH RE-INJECTION FOR ENHANCED RECOVERY AS WELL AS A 

SURFACE DISCHARGE TO THE TEAPOT CREEK. SEVERAL PITS ARE IN PLACE TO SEPARATE 

THE OIL FROM THE WATER PRIOR TO THE PERMITTED DISCHARGE POINT.

ENVIRONMENTAL IMPACTS/BENEFITS: THE FIELD COVERS APPROXIMATELY 10,000 ACRES 

AND WILDLIFE ABOUNDS THROUGHOUT THE FIELD. THE PRODUCED WATER DISCHARGE TO 

TEAPOT CREEK IMPROVES THE RIPRARIAN HABITAT, WHICH WOULD BE SEASONAL AT BEST 

WITHOUT THE PRODUCED WATER.

APPLICABILITY: THE RMOTC LABORATORIES IS AN EXCELLENT PLACE TO PROVE NEW 

TECHNOLOGIES AND EXPERIMENT WITH EMERGING TECHNIQUES FOR PRODUCED WATER 

MANAGEMENT AND BENEFICIAL USE.

COST: NO INFORMATION WAS COLLECTED ON COST.

ADDITIONAL NOTES: NONE

DATE: 6/29/2005____ INFORMATION COLLECTED BY: _JON SEEKINS, JAKE CRISSUP
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

PHOTO LOG

VIEW OF TANKS WHERE TILAPIA AND SHRIMP ARE RAISED WITH PRODUCED WATER

VIEW OF A TILAPIA FISH THAT WAS RAISED IN PRODUCED WATER
 SITE VISIT SUMMARY

IDENTIFICATION, VERIFICATION, AND COMPILATION OF 

PRODUCED WATER MANAGEMENT PRACTICES 

FOR CONVENTIONAL OIL AND GAS PRODUCTION OPERATIONS

VIEW OF STEAM GENERATED FROM A NETTED PRIMARY SEPARATOR PIT

VIEW OF SECONDARY AND TERTIARY PITS PRIOR TO DISCHARGE TO TEAPOT CREEK