Draft Report – February 2011 

Current and Projected Water Use in the 

Texas Mining and Oil and Gas Industry 

Prepared for 

Texas Water Development Board 

Bureau of Economic Geology 

Scott W. Tinker, Director 

Jackson School of Geosciences 

The University of Texas at Austin 

Austin, Texas 78713-8924 
Cover photo: Aggregate facility in Bexar County (courtesy of Google Earth) 
Prepared for 

Texas Water Development Board 

under 

Contract No. 0904830939

Jean-Philippe Nicot, P.E., P.G., Anna K. Hebel, Stephanie M. Ritter, 

Steven Walden1

, Russ Baier1, Peter Galusky2, P.E., P.G., James Beach3, P.G.,

Richard Kyle4

, P.G., Leigh Symank3, and Cari Breton 

February 2011

Bureau of Economic Geology 

Scott W. Tinker Director 

Jackson School of Geosciences 

The University of Texas at Austin 

Austin, Texas 78713-8924 

1

Steve Walden Consulting, Austin, TX 

2

Texerra, Midland, TX 

3

LBG-Guyton, Austin, TX 

4

Deparment of Geological Sciences, The University of Texas at Austin, Austin, TX 

iii 

Table of Contents 

Table of Contents .......................................................................................................................... iii 

List of Figures ......................................................................................................................... vii 

List of Tables ........................................................................................................................ xiii 

Glossary and Abbreviations...........................................................................................................xv 

Acknowledgments....................................................................................................................... xvii 

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

2 Introduction ............................................................................................................................5 

2.1 Overview of Mining Activities in Texas and a High-Level Perspective on 

Water Use in the Industry ................................................................................................5 

2.1.1 Mined Substances ..........................................................................................................5 

2.1.2 Mining Facilities ............................................................................................................7 

2.1.3 Water-Use Overview .....................................................................................................8 

2.2 Overview of Recent Projections ......................................................................................9 

3 Methodology and Sources of Information .............................................................................20 

3.1 General Sources of Information.....................................................................................20 

3.2 Definition of Mining Water Use for the Purpose in this Report....................................21 

3.3 Methodology: Historical Water Use ..............................................................................23 

3.3.1 Oil and Gas Industry ....................................................................................................23 

3.3.1.1 Gas Shales and Other Tight Formations ........................................................... 23 

3.3.1.2 Waterflooding and Drilling............................................................................... 25 

3.3.2 Coal/Lignite .................................................................................................................26 

3.3.3 Aggregates ...................................................................................................................27 

3.3.4 Other Mined Substances ..............................................................................................29 

3.3.5 Groundwater–Surface Water Split...............................................................................29 

3.4 Methodology: Future Water Use ...................................................................................30 

3.4.1.1 Gas Shales......................................................................................................... 32 

3.4.1.2 Tight Formations............................................................................................... 37 

3.4.1.3 Drilling and Waterflooding of Oil and Gas Reservoirs .................................... 37 

3.4.1.4 Coal................................................................................................................... 37 

3.4.1.5 Aggregates ........................................................................................................ 37 

3.4.1.6 Other Mineral Commodities ............................................................................. 39 

4 Current Water Use .................................................................................................................51 

4.1 Shales and Tight Sands ..................................................................................................51 

4.1.1 Location and Extent .....................................................................................................51 

4.1.2 Gas (and Oil) Shales ....................................................................................................52 

4.1.2.1 Barnett Shale..................................................................................................... 52 

4.1.2.2 Haynesville and Bossier Shales ........................................................................ 53 

4.1.2.3 Eagle Ford Shale............................................................................................... 54 

4.1.2.4 Woodford, Pearsall, Bend, and Barnett-PB Shales........................................... 54 

4.1.2.5 Conclusions on Gas Shales ............................................................................... 55 

4.1.3 Tight Reservoirs...........................................................................................................79 

4.1.3.1 Anadarko Basin................................................................................................. 79 

4.1.3.2 East Texas Basin............................................................................................... 79 

4.1.3.3 Fort Worth Basin............................................................................................... 80 
iv 

4.1.3.4 Permian Basin ................................................................................................... 80 

4.1.3.5 Maverick Basin and Gulf Coast........................................................................ 81 

4.1.3.6 Conclusions on Tight Formations..................................................................... 82 

4.2 Oil and Gas Drilling and Waterflooding......................................................................105 

4.2.1 Waterflooding ............................................................................................................105 

4.2.1.1 Information available before this study .......................................................... 105 

4.2.1.2 Extrapolations from the RRC 1995 Survey .................................................... 106 

4.2.1.3 Current Waterflooding Water Use.................................................................. 108 

4.2.2 Drilling.......................................................................................................................109 

4.3 Coal and Lignite...........................................................................................................127 

4.4 Aggregates ...................................................................................................................136 

4.4.1 General Aggregate Distribution.................................................................................136 

4.4.2 Description of Mining Processes ...............................................................................136 

4.4.2.1 Crushed Limestone Mining............................................................................. 136 

4.4.2.2 Sand and Gravel Mining ................................................................................. 137 

4.4.3 External Data Sets......................................................................................................138 

4.4.3.1 TCEQ Central Registry................................................................................... 138 

4.4.3.2 TCEQ Surface-Water Diversion..................................................................... 138 

4.4.3.3 TCEQ TPDES................................................................................................. 139 

4.4.3.4 TCEQ SWAP Database .................................................................................. 139 

4.4.4 BEG Survey Results ..................................................................................................139 

4.4.4.1 Survey of Facilities ......................................................................................... 139 

4.4.4.2 Survey of GCDs.............................................................................................. 141 

4.4.5 Historical and Current Aggregate Water Use ............................................................141 

4.5 Other Nonfuel Minerals ...............................................................................................151 

4.5.1 Dimension Stone........................................................................................................151 

4.5.2 Industrial Sand ...........................................................................................................152 

4.5.3 Chemical Lime...........................................................................................................152 

4.5.4 Clay Minerals.............................................................................................................153 

4.5.5 Gypsum, Salt, and Sodium Sulfate ............................................................................153 

4.5.6 Talc ............................................................................................................................154 

4.5.7 Uranium .....................................................................................................................155 

4.5.8 Other Metallic Substances .........................................................................................155 

4.6 Historical Mining with High Water Use......................................................................162 

4.7 Conclusions and Synthesis for Historical Water Use ..................................................162 

5 Future Water Use .................................................................................................................165 

5.1 Gas Shales and Tight Formations ................................................................................165 

5.1.1 Projected Future Water Use of Individual Plays........................................................166 

5.1.2 Correcting Factors......................................................................................................168 

5.1.2.1 Recycling ........................................................................................................ 168 

5.1.2.2 Refracing......................................................................................................... 170 

5.1.2.3 Infill drilling.................................................................................................... 170 

5.1.2.4 New or Updated Technologies........................................................................ 170 

5.1.3 Conclusions on Fracing Water Use............................................................................171 

5.2 Conventional Oil and Gas............................................................................................186 

5.2.1 Water and CO2 Floods ...............................................................................................186 
v 

5.2.2 Drilling.......................................................................................................................187 

5.3 Coal..............................................................................................................................196 

5.4 Aggregates ...................................................................................................................201 

5.5 Industrial Sand .............................................................................................................208 

5.6 Other Nonfuel Minerals ...............................................................................................208 

5.6.1 Uranium .....................................................................................................................208 

5.6.2 Other Metallic Minerals.............................................................................................208 

5.6.2.1 Shafter Deposit................................................................................................ 209 

5.6.2.2 Round Top Deposit......................................................................................... 210 

5.6.2.3 Cave Peak Deposit .......................................................................................... 210 

5.6.3 Conclusions................................................................................................................210 

5.7 Water Use for Speculative Resources..........................................................................214 

5.7.1 Heavy Oil...................................................................................................................214 

5.7.2 Enhanced Coalbed Methane Recovery ......................................................................215 

5.7.3 Coal to Liquid ............................................................................................................215 

5.8 Conclusions and Synthesis for Future Water Use........................................................216 

6 Conclusions and Recommendations ....................................................................................219 

7 References ........................................................................................................................229 

8 Appendix List.......................................................................................................................243 

9 Appendix A: Relevant Websites..................................................................................245 

10 Appendix B: Postaudit of the 2007 BEG Barnett Shale Water-Use Projections ......249 

10 Appendix C: Relevant Features of the Geology of Texas ...........................................263 

11 Appendix D: Survey Questionnaires ...........................................................................273 

11.1 Survey of Facilities ......................................................................................................275 

11.1.1 About the Trade Associations..............................................................................275 

11.1.2 Response Rates ....................................................................................................275 

11.2 Survey of GCDs...........................................................................................................275 

11.3 Questionnaire Forms....................................................................................................279

11.4 Survey of West Texas Oil Operators ...........................................................................284 

12 Appendix E: Supplemental Information Provided by GCDs.......................................291 

13 Appendix F: Water-Rights Permit Data and 2008 Water-Rights Reporting Data.....295 

14 Appendix G: vvvvv......................................................................................................315 

15 Appendix H: zzzzz.......................................................................................................317 

16 Appendix I: yyyyy .......................................................................................................321 

17 Appendix J: List of Files Submitted to TWDB and Content......................................325 

17.1 List of Files with Nonproprietary Content...................................................................327 

17.2 List of Files with Proprietary Content .........................................................................327 

18 Appendix K: Responses to Review Comments ...........................................................329 

vii 

List of Figures 

Figure ES1. Summary of estimated water use by mining industry segment (year 2008)............... 2 

Figure ES2. Summary of projected water use by mining industry segment (2010-2060).............. 3 

Figure 1. Location map of all wells with a spud date between 2005/01/01 and 2009/31/12 

(approximately ~75,000 wells) ....................................................................................13 

Figure 2. Map showing locations of all frac jobs in the 2005–2009 time span in the state of 

Texas. Approximately 23,500 wells are displayed ......................................................14 

Figure 3. Location map of coal/lignite operations.........................................................................15 

Figure 4. Location map of aggregate operations from NSSGA database (data points) and 

MSHA database (selected counties) ............................................................................16 

Figure 5. Location map of crushed-stone operations from NSSGA database (data points) 

and MSHA database (selected counties illustrating number of operations)................17 

Figure 6. Location map of sand and gravel operations from NSSGA database (data points) 

and MSHA database (selected counties illustrating number of operations)................18 

Figure 7. Example or representation provided by the SWAP database.........................................19 

Figure 8. Map of Regional Water Planning Groups ......................................................................40 

Figure 9. State map of RRC districts .............................................................................................41 

Figure 10. GCDs and active and inactive mine locations in the TCEQ SWAP database..............42 

Figure 11. Trap vs. resource play...................................................................................................43 

Figure 12. Comparison of the two approaches to compute lateral length .....................................43 

Figure 13. Map illustrating population-count mechanism for crushed-stone facilities. ................44 

Figure 14. Making long-term projections is an art—part 1 ...........................................................45 

Figure 15. Making long-term projections is an art— part 2 ..........................................................45 

Figure 16. Multiple EUR projections extrapolated from limited early data for an Eagle 

Ford well ......................................................................................................................46 

Figure 17. Decline curves assumed in this study (production-based approach)............................46 

Figure 18. Lateral length vs. estimated impacted width. ...............................................................47 

Figure 19. Example of Barnett Shale density of laterals (Dallas-Tarrant county line)..................47 

Figure 20. Example of Barnett Shale density of laterals (Johnson County)..................................48 

Figure 21. Active rig count in the U.S. and Texas from 1990 to current ......................................48 

Figure 22. Rig count as of June 25, 2010. (a) Red and blue dots denote gas and oil rigs, 

respectively; (b) red, blue, and green diamonds denote horizontal, vertical, and 

directional rigs. ............................................................................................................49

Figure 23. EIA spatial definition of shale-gas and tight-gas plays................................................59 

Figure 24. Map showing locations of all frac jobs 2005–2009, and main (mostly) gas plays ......60 

Figure 25. Percentage of frac jobs (not water use) in major plays in 2005-2008..........................60 

Figure 26. Major geologic regions (basins and uplifts) in Texas ..................................................61 

Figure 27. Barnett Shale—vertical vs. horizontal and directional wells through time..................61 

Figure 28. Barnett Shale footprint .................................................................................................62 

Figure 29. Barnett Shale – Annual number of frac jobs superimposed to annual average, 

median, and other percentiles of individual well frac water use for (a) vertical 

wells, and (b) horizontal wells.....................................................................................63 

Figure 30. Barnett Shale— Histograms of frac water volume for vertical wells for (a) all 

wells, (b) pre-2000 wells, and (c) 2000–2010 wells....................................................64 

Figure 31. Barnett Shale—frac water use: (a) total volume, (b) intensity in 1,000 gal/ft .............65 
viii 

Figure 32. Barnett Shale—vertical well: (a) total proppant amount and (b) proppant 

loading..........................................................................................................................66 

Figure 33. Barnett Shale—Horizontal well: (a) total proppant amount and (b) proppant 

loading..........................................................................................................................66 

Figure 34. Haynesville Shale footprint ..........................................................................................67 

Figure 35. Haynesville Shale—annual number of frac jobs superimposed on annual 

average, median, and other percentiles of individual well frac water use ...................67 

Figure 36. Haynesville Shale—vertical vs. horizontal and directional wells through time ..........68 

Figure 37. Haynesville—horizontal well frac water use: (a) total volume; (b) intensity in 

1,000 gal/ft (2008 and beyond)....................................................................................68 

Figure 38. Haynesville—horizontal well: (a) total proppant amount and (b) proppant 

loading (2008 and beyond) ..........................................................................................69 

Figure 39. SW-NE schematic strike cross section illustrating regional lithostratigraphic 

relationships across the Eagle Ford play area..............................................................70 

Figure 40. Isopach map of upper Eagle Ford Shale.......................................................................70 

Figure 41. Isopach map of lower Eagle Ford Shale.......................................................................71 

Figure 42. Eagle Ford Shale—Annual number of frac jobs superimposed on annual 

average, median, and other percentiles of individual well frac water use ...................71 

Figure 43. Eagle Ford Shale—vertical vs. horizontal and directional wells through time............72 

Figure 44. Eagle Ford—horizontal well frac water use: (a) total volume; (b) intensity in 

1,000 gal/ft (2008 and beyond)....................................................................................72 

Figure 45. Eagle Ford—horizontal well: (a) total proppant amount and (b) proppant 

loading (2008 and beyond) ..........................................................................................73 

Figure 46. Woodford (Upper Devonian) occurrences in Texas.....................................................74 

Figure 47. Mississippian (including Barnett) facies distribution...................................................75 

Figure 48. Woodford-Pearsall-Barnett PB—annual number of frac jobs superimposed on 

annual average, median, and other percentiles of individual well frac water use .......76 

Figure 49. Woodford-Pearsall-Barnett PB—vertical vs. horizontal and directional wells 

through time.................................................................................................................76

Figure 50. Woodford-Pearsall-Barnett PB horizontal and vertical well frac water use ................77 

Figure 51. Water use for well completion in gas shales and tight formations (2008) ...................77 

Figure 52. County-level fracing water use (2008).........................................................................78 

Figure 53. Location of basins in Texas containing low-permeability sandstone with 

historical frac jobs........................................................................................................84 

Figure 54. Anadarko Basin—annual number of frac jobs (b) superimposed on annual 

average, median, and other percentiles of individual well frac water use (a)..............85 

Figure 55. Anadarko Basin—frac water use in vertical wells (a), nonvertical wells (b), and 

water-use intensity in selected horizontal wells (c) .....................................................86 

Figure 56. Anadarko Basin—vertical vs. horizontal and directional wells through time..............87 

Figure 57. Anadarko Basin—fraced well count per formation......................................................87 

Figure 58. Distribution of Cotton Valley reservoir trends in East Texas ......................................88 

Figure 59. East Texas Basin—vertical vs. horizontal wells through time.....................................88 

Figure 60. East Texas Basin—Fraced well count per formation from 1950 (a) and 1990 (b) ......89 

Figure 61. East Texas Basin—annual number of frac jobs (b and d) superimposed on 

annual average, median, and other percentiles of individual well frac water use 

(a and c) for 1950–~2008 (a and b) and 1990–~2008 (c and d) periods......................90 
ix 

Figure 62. East Texas Basin—frac water use in vertical wells (a) and horizontal wells (b).........92 

Figure 63. Main clastic plays in the Permian Basin.......................................................................93 

Figure 64. Permian Basin geologic features ..................................................................................94 

Figure 65. Regional sequence stratigraphy of the Leonardian (Permian) .....................................94 

Figure 66. Bone Spring footprint and elevation of top of Wolfcamp............................................95 

Figure 67. North-south Midland Basin cross section of Permian (Leonard and Wolfcamp), 

Pennsylvanian, Mississippian, and Devonian..............................................................96 

Figure 68. Permian Basin—annual number of frac jobs superimposed on annual average, 

median, and other percentiles of individual well frac water use (all 50,000+ 

wells)............................................................................................................................96 

Figure 69. Permian Basin—annual number of frac jobs superimposed on annual average, 

median, and other percentiles of individual well frac water use (water use > 0.1 

Mgal)............................................................................................................................97 

Figure 70. Permian Basin—annual number of frac jobs superimposed on annual average, 

median, and other percentiles of individual well frac water use (water use >0.1 

Mgal since 2000)..........................................................................................................97 

Figure 71. Permian Basin—frac water use in vertical wells..........................................................98 

Figure 72. Permian Basin—vertical vs. horizontal wells through time.........................................98 

Figure 73. Permian Basin—fraced well count per formation from 1950 (a) and from 1990 

(b) (linear scale—including Caballos/Tesnus).............................................................99 

Figure 74. Permian Basin—fraced well count per formation from 1950 (a) and 1990 (b) 

(log scale—including Caballos/Tesnus) ....................................................................100 

Figure 75. Caballos-Tesnus—annual number of frac jobs superimposed on annual average, 

median, and other percentiles of individual well frac water use................................101 

Figure 76. Caballos-Tesnus—frac water volume ........................................................................101 

Figure 77. Gulf Coast Basin—annual number of frac jobs superimposed on annual 

average, median, and other percentiles of individual well frac water use .................102 

Figure 78. Gulf Coast Basin—vertical vs. horizontal wells through time...................................102 

Figure 79. Gulf Coast Basin—fraced well count per formation from 1950 (a) and 1990 (b) .....103 

Figure 80. Gulf Coast—frac water volume (2008)......................................................................104 

Figure 81. Gulf Coast—proppant volume (2008)........................................................................104 

Figure 82. Gulf Coast—proppant loading (all years) ..................................................................104 

Figure 83. Map of counties using fresh water in EOR operations according to the 1995 

RRC data....................................................................................................................118

Figure 84. Histogram (year 1995) of county-level waterflood water-use coefficient (wide 

columns) and fraction of total fresh-water use for each bin ......................................119 

Figure 85. Histogram (year 1995) of water-use coefficient in waterflooded oil fields (wide 

columns) and fraction of total fresh-water use for each bin ......................................119 

Figure 86. Production histories of significant-sized oil reservoirs in the Permian Basin by 

lithology .....................................................................................................................120 

Figure 87. Annual oil production per district (1993–2009).........................................................120 

Figure 88. RRC district-level annual waterflood-dedicated injection volume in Texas 

(1998–2002): (a) log scale, (b) linear scale ...............................................................121 

Figure 89. RRC district-level fraction of injected water (of all types) used for 

waterflooding .............................................................................................................122 

Figure 90. Oil production in districts 8 and 8A ...........................................................................122 
x 

Figure 91. RRC district annual total water (of all types) injection volume (1998–2002 and 

2007–2008): (a) log scale, (b) linear scale.................................................................123 

Figure 92. Comparison of oil production and water injection in RRC districts 08 and 8A 

(1998–2008)...............................................................................................................124 

Figure 93. Historical and forecast for oil production in districts 8, 8A, and 7C..........................124 

Figure 94. Estimated current and projected fresh- and brackish-water use for pressure 

maintenance and secondary and tertiary recovery operations ...................................125 

Figure 95. Number of holes drilled and of oil and gas wells completed in Texas between 

1960 and 2009............................................................................................................125 

Figure 96. Estimated fresh-water use for waterfloods (2008) .....................................................126 

Figure 97. Distribution of Texas lignite and bituminous coal deposits, coal mines currently 

permitted by the RRC with 2008 annual production in short tons ............................132 

Figure 98. Statewide coal/lignite annual production (1975–2009)..............................................133 

Figure 99. Lignite mine groundwater production 2001–2009.....................................................133 

Figure 100. Production of Texas coal mines (1976–2007)..........................................................134 

Figure 101. County population in 2010 (TWDB projection) and crushed-stone NSSGA 

facilities......................................................................................................................147 

Figure 102. Flow diagram of typical crushed-stone process .......................................................147 

Figure 103. Counties with NSSGA-listed facilities; highlighted county lines represent 

those counties with information from the BEG survey .............................................148 

Figure 104. Water use from BEG survey for (a) crushed stone facilities; (b) sand and 

gravel facilities...........................................................................................................149

Figure 105. Histograms of aggregate net water use for washing and dust control: (a) per 

facility, (b) and (c) per unit production......................................................................150 

Figure 106. County-level count of dimension-stone facilities.....................................................159 

Figure 107. County-level count of industrial-sand facilities .......................................................159 

Figure 108. Texas and U.S. industrial-sand production (1992–2008).........................................160 

Figure 109. Texas lime production (1986–2009) ........................................................................160 

Figure 110. Texas gypsum production (1990–2008)...................................................................161 

Figure 111. U.S. uranium production and employment (1993–2009).........................................161 

Figure 112. Summary of water use by mining industry segment (2008).....................................164 

Figure 113. Summary of water use by category (2008)...............................................................164 

Figure 114. Cumulative gas production and water use in the Barnett Shale play from the 

origins ........................................................................................................................183 

Figure 115. Monthly wet-gas production and number of producing oil and gas wells 

(1990–2008)...............................................................................................................183 

Figure 116. Projected state fracing water use ..............................................................................185 

Figure 117. Annual oil production in Texas (1936–2009) ..........................................................194 

Figure 118. Future annual oil production, Districts 8, 8A, and Texas.........................................194 

Figure 119. Historical and projected fresh-water use in secondary and tertiary recovery 

operations...................................................................................................................195 

Figure 120. Projected drilling-water use......................................................................................195 

Figure 121. Projected lignite-mine water use (2010–2060).........................................................199 

Figure 122. Total water use for each coal-mining facility...........................................................200 

Figure 123. Relative growth of Texas (negative) and western (positive) coal ............................200 

Figure 124. Historical population and aggregate production in Texas........................................205 
xi 

Figure 125. Historical population and projection for population and aggregate production 

in Texas......................................................................................................................205 

Figure 126. Crushed-stone water-use projections per county through 2060 ...............................206 

Figure 127. Sand and gravel water-use projections per county through 2060.............................207 

Figure 128. Projection of industrial-sand production ..................................................................212 

Figure 129. Counties prospective for uranium mining as of 2010 ..............................................213 

Figure 130. Summary of projected water use by mining-industry segment (2010–2060) ..........217 

Figure 131. Summary of projected water use in the oil and gas segment (2010–2060)..............217 

Figure 132. Summary of relative fraction of projected water in the oil and gas segment 

(2010–2060)...............................................................................................................218 

Figure 133. Summary of relative fraction of projected water use by mining-industry 

segment (2010–2060).................................................................................................218 

Figure 134. Historical estimation of historical mining-water use................................................228 

Figure 135. Comparison of high mining water use......................................................................228 

Figure 136. Distribution of water use for vertical wells (a), horizontal wells (b), and per 

linear of lateral of horizontal wells (c).......................................................................253 

Figure 137. Uncorrected entire water use....................................................................................254

Figure 138. Projected annual completions...................................................................................254 

Figure 139. 2007 report projected frac total water use (a) and projected frac groundwater 

use (b).........................................................................................................................256 

Figure 140. Comparison of water-use projections and actual figures in the Barnett Shale 

(2005–2010)...............................................................................................................258 

Figure 141. Comparison of cumulative water-use projections and actual figures in the 

Barnett Shale (2006–2010) ........................................................................................259 

Figure 142. Comparison of actual vs. projected (high scenario) water use for four counties: 

Denton, Johnson, Tarrant, and Wise..........................................................................260 

Figure 143. Comparison of actual vs. projected (high scenario) water use for all Barnett 

Shale counties ............................................................................................................261 

Figure 144. Generalized tectonic map of Texas showing location of sedimentary basins..........266 

Figure 145. Map of major oil and gas fields in Texas .................................................................267 

Figure 146. Stratigraphic column and relative oil production for the Gulf Coast and East 

Texas Basins (after Galloway and others, 1983) .......................................................268 

Figure 147. Stratigraphic column and relative gas production for the Gulf Coast and East 

Texas Basins (after Galloway and others, 1983) .......................................................269 

Figure 148. Stratigraphic column and relative oil production for the North-Central and 

West Texas Basins (after Kosters and others, 1989) .................................................270 

Figure 149. Stratigraphic column and relative gas production for the North-Central and 

West Texas Basins (after Kosters and others, 1989) .................................................271 

Figure 150. GCDs that have returned information on mineral mining water use in their 

district ........................................................................................................................278 

xiii 

List of Tables 

Table 1. Fuel and nonfuel raw mineral production in Texas .........................................................10 

Table 2. Estimate of the number of mining facilities in the State of Texas in 2002 

(USCB) ..........................................................................................................................11 

Table 3. Number and diversity of minerals mining operations in Texas (MSHA)........................12 

Table 4. Historical projected mining water use (top) and total water use (bottom) for all 

water uses in Texas by TWDB (MAF)..........................................................................12 

Table 5. Historical mining water use in Texas by USGS (thousand AF)......................................12 

Table 6. List of formations currently being fraced heavily or with the potential of being 

fraced heavily in the future ............................................................................................56 

Table 7. Well statistics and water use for 2010 .............................................................................57 

Table 8. Major active formations in 2010 completed well count ..................................................57 

Table 9. County-level shale-gas-completion water use in the Barnett Shale (2008).....................58 

Table 10. Summary of fracing water use.......................................................................................58

Table 11. Simplified stratigraphic column of the East Texas Basin showing commonly 

fraced intervals, as well as potential targets (in bold)....................................................82 

Table 12. Simplified stratigraphic column of the Permian Basin showing commonly 

fraced intervals, as well as potential targets (in bold)....................................................83 

Table 13. Simplified stratigraphic column of South Texas Gulf Coast showing commonly 

fraced intervals, as well as potential targets (in bold)....................................................83 

Table 14. County-level tight-formation-completion water use (2008)..........................................83 

Table 15. Historical water use in secondary and tertiary recovery (million barrels)...................112 

Table 16. Fresh-water use in EOR operations (1995 RRC survey).............................................112 

Table 17. Number of permitted fresh-water injection wells as of January 2010.........................113 

Table 18. District-level total water injection volume vs. waterflood volumes (1998) ................113 

Table 19. District-level total water-injection volume vs. waterflood volumes (2002)................114 

Table 20. Estimated district-level fraction of fresh-water in waterflood water volumes ............114 

Table 21. Initial guess for extrapolated district-level fresh-water use for waterfloods ...............115 

Table 22. County-level estimate of fresh-water use for waterfloods...........................................115 

Table 23. Estimated and calculated oil and gas well drilling water use ......................................117 

Table 24. New drill per district....................................................................................................117 

Table 25. Lignite and coal-mining operations in Texas ..............................................................129 

Table 26. Water fate for current lignite operations in Texas .......................................................130 

Table 27. Water source for current lignite operations in Texas...................................................130 

Table 28. Estimated lignite mine water use per county in AF/yr (2010).....................................131 

Table 29. TCEQ Central Registry records of mining facilities in Texas.....................................143 

Table 30. Water-use survey results from selected aggregate operations.....................................143 

Table 31. Aggregate net water use/consumption based on BEG survey results..........................144 

Table 32. Net water-use breakdown by water source..................................................................145 

Table 33. Historical water-use coefficients for aggregates (gal/st) .............................................145 

Table 34. Results from recent TWDB WUS ...............................................................................145 

Table 35. Estimated county-level crushed-stone and sand and gravel water use for 2008 .........146 

Table 36. Estimated county-level industrial sand-water consumption ........................................157 

Table 37. Estimated county-level lime mining-water consumption (AF) ...................................157 

Table 38. Estimated county-level gypsum mining-water consumption (AF)..............................157 
xiv 

Table 39. Estimated county-level salt mining-water consumption (AF).....................................158 

Table 40. Estimated county-level uranium mining-water consumption (2009) ..........................158 

Table 41. Summary of water use not in the oil and gas, coal, or aggregate categories ...............158 

Table 42. Flowback volume characteristics.................................................................................172 

Table 43. Compilation of published Texas oil and gas reserves..................................................172 

Table 44. Compilation of published reserves for oil and gas shales and tight formations ..........173 

Table 45. Compilation of published operational characteristics for oil and gas shales and 

tight formations............................................................................................................174

Table 46. Summary description of parameters used in water-use projections (shale-gas 

plays)............................................................................................................................175 

Table 47. Summary description of parameters used in water-use projections (tight 

formations)...................................................................................................................176 

Table 48. Projected water use in the Barnett Shale (Fort Worth Basin)......................................177 

Table 49. Projected water use in the Haynesville Shale ..............................................................178 

Table 50. Projected water use in the Bossier Shale .....................................................................178 

Table 51. Projected water use in the Eagle Ford Shale................................................................178 

Table 52. Projected water use in the Woodford and Barnett Shales in the Delaware Basin .......179 

Table 53. Projected water use in the Pearsall Shale.....................................................................179 

Table 54. Projected water use in the Wolfberry play...................................................................180 

Table 55. Projected water use in East Texas tight-gas plays .......................................................180 

Table 56. Projected water use in Anadarko Basin tight formations ............................................181 

Table 57. Projected water use in the South Gulf Coast Basin tight-gas plays.............................181 

Table 58. Projected water use in the Permian Basin tight formations.........................................182 

Table 59. County-level fresh and brackish water-use projections for waterflood.......................189 

Table 60. Projected lignite-mine water use per county in AF/yr (2010–2060) ...........................197 

Table 61. Historical and projected population and aggregate production ...................................202 

Table 62. Crushed-stone water use projections per county through 2060...................................202 

Table 63. Sand and gravel water-use projections per county through 2060................................203 

Table 64. Summary of aggregate water-use projections..............................................................204 

Table 65. Projected county-level industrial-sand water consumption.........................................211 

Table 66. Projected county-level lime-mining water consumption (AF) ....................................211 

Table 67. Projected county-level gypsum-mining water consumption (AF)...............................211 

Table 68. County-level summary of mining water use (oil and gas drilling not included) .........220 

Table 69. County-level summary of 2010-2020 projections for mining water use (oil and 

gas drilling not included) .............................................................................................222 

Table 70. Summary description of parameters used in 2007 report water-use projections.........255 

Table 71. GCD mine-data questions and response percentages ..................................................276 

Table 72. Mining water-use changes reported by certain GCDs.................................................277 

Table 73. Example of information provided by the SWAP database (Lost Pines GCD) ............288 

Table 74. Example of information provided by the MSHA database sent to GCDs ...................289 

Table 75. Example of information provided by the 2007 TWDB water plan sent to GCDs 

(Lost Pines GCD).........................................................................................................289 

Table 76. 2008 Water-rights reporting data.................................................................................297 

Table 77. Water-rights permit data ..............................................................................................302 
xv 

Glossary and Abbreviations 

AAPG American Association of Petroleum Geologists 

AF Acre-foot (1 AF = 325,851 gallons) 

Bbbl Billion barrels 

Bcf Billion cubic feet (1 Bcf = 103

 MMcf = 106 Mcf) 

bgs below ground surface 

BTU British Thermal Unit 

CBM Coal-bed methane 

CCS Carbon capture and storage 

EIA Energy Information Agency 

EOR Enhanced oil recovery 

EUR Estimated ultimate recovery 

GAM Groundwater availability model 

GC Gulf Coast 

GCD Groundwater conservation district 

GIP Gas-in-place 

GSA Geological Society of America 

IP Initial production 

ISL In situ leaching 

ISR In situ recovery 

LCRA Lower Colorado River Authority 

LPG Liquefied petroleum gas 

MAF Thousand acre-feet 

MGD Million gallons per day 

Mcf Thousand cubic feet 

MMbbl Millions of barrels 

MMBTU Million BTU 

MMcf Million cubic feet (1 MMcf = 103

 Mcf) 

NGL Natural gas liquid 

NGW Natural Gas Week Journal 

NOGA National oil and gas assessments (by USGS) 

NORM Naturally occurring radioactive materials 

O&GJ Oil and Gas Journal 

OOGP Original gas in place 

OOIP Original oil in place 

OSHA Occupational Safety and Health Administration 
xvi 

PBSN Powell Barnett Shale Newsletter 

PGC Potential Gas Committee 

PPA Pounds of proppant added per gallon of fluid 

RRC Railroad Commission of Texas 

RWPG Regional water planning group 

SIC Standard industrial classification 

st Short ton 

TACA Texas Aggregate and Concrete Association

TCEQ Texas Commission on Environmental Quality 

Tcf One trillion cubic feet (1 Tcf = 103

 Bcf = 106 MMcf = 109 Mcf) 

TDS Total dissolved solids 

Th. AF Thousand acre-feet 

TMPA Texas Municipal Power Agency 

TMRA Texas Mining and Reclamation Association 

TOC Total organic content 

TWBD Texas Water Development Board 

TXOGA Texas Oil and Gas Association 

UIC Underground injection control 

USGS U.S. Geological Survey 

VR Vitrinite reflectance 

WAG Water alternating gas 

WCAC Water Conservation Advisory Council 

WUG Water user group (TCEQ jargon) 

WUS Water use survey (TWDB jargon) 

Note to the reader: 

In the oil industry m or M stands for 1,000 (one thousand, as in Mcf, one thousand cubic feet) 

but it means million in the water industry (as in MGD, million gallons per day). We try to spell 

out numbers or use plain units to limit the confusion. 
xvii 

Acknowledgments

The authors would like to thank all individuals and organizations that helped make this work 

successful. We benefited from discussions with members of the Water Planning team involved in 

this study (Stuart Norvell, Kevin Kluge, and Dan Hardin) at the Texas Water Development 

Board (TWDB). We are grateful as well to Lana Dieterich (BEG) for her editing of this report, as 

well as many BEG researchers and graduate students: Bill Ambrose, Sigrid Clift, Michelle Foss, 

Scott Hamlin, Ursula Hammes, Tucker Hentz, Hamid Lashgari, Bob Loucks, Seay Nance, Eric 

Potter, Steve Ruppel, and Silvia Solano. Staff from other state agencies were also extremely 

helpful: Fernando De Leon, Doug Johnson, and Tim Walter at the Railroad Commission of 

Texas (RRC). 

We are also appreciative of the time and effort by our contacts at the trade associations, Shannon 

Lucas at TMRA, Don Bell at TACA, and C. J. Tredway at TXOGA, as well as others, for 

advertising the surveys and pushing their membership to respond to and contribute to this work. 

We are grateful to all members of these associations for the useful information we collected. We 

also thank individuals who spent time discussing and explaining these issues to us: Steve Eckert, 

David Freeman, Bob Hook, Matt Mantell, Michael Nasi, Charlie Smith, Ed Steele, Joel Trouart, 

Paul Weatherby, and many others. We also thank the review panel who agreed to spend time 

reviewing the document. 

Last, we would like to acknowledge our University sponsors for free access to their databases: 

IHS Energy and Drillinginfo. 

1 

1 Executive Summary 

In the middle of 2009, we undertook a study of water use in the so-called mining industry in 

Texas, both current and projected for the next 50 years. The study concerned the upstream 

segment of the oil and gas industry (that is, water used to extract the commodity until it leaves 

the wellhead), the aggregate industry (sand and gravel and crushed rock operations, washing 

included but no further processing), the coal industry (mostly pit dewatering and aquifer 

depressurizing), and other substances mined in a fashion very similar to that of aggregates 

(industrial sand, lime, etc.), as well as through solution mining. In general we followed the 

definition of mining according to SIC/NAICS codes. It follows that cement facilities, despite 

their large quarries, are considered to belong to the manufacturing, not mining, category. The 

objective of the study, that was essentially prompted by the sudden increase in shale-gas 

production, was to help in the next cycle of water planning by the state agency in charge of such 

planning, the Texas Water Development Board (TWDB). 

The approach to the study is twofold: (1) to collect water-use data and auxiliary information by 

contacting actual mining facilities and (2) to interview experts and other knowledgeable 

individuals in their respective fields to fill in the gaps in water-use data and to understand future 

development/contraction of water use in the different segments of the mining industry. We 

surveyed the industry either through formal questionnaires sent to the membership of trade 

associations (TACA for aggregates; TMRA for aggregate, coal, and uranium; TXOGA and 

others for oil and gas), through surveys sent to water providers/observers such as GCDs, or 

through survey results from other organizations (MSHA, RRC, TCEQ, TWDB, USGS), and 

especially private vendors of the oil and gas industry. We contacted and had in-depth interviews 

with multiple representatives of every major segment of the mining industry to help us 

understand how the water is used, how much is recycled, what its source is (groundwater, surface 

water or something else), whether it is fresh or brackish (saline water use is not tallied in this 

study), how much is rejected outside of the mining facility, etc. 

Results from the surveys were useful but not as extensive as hoped for us to assemble a 

representative sample of the hundreds of mining facilities in the state, with the exception of the 

coal industry (a significant water user) and the uranium industry (a minor water user). We were 

also able to gather relatively accurate data from the stimulation stage when a well is being 

readied for production (the so-called fracing process), but we are more uncertain about water use 

for drilling wells and waterfloods. Results of current water use for the aggregate industry relied 

on previous information somewhat calibrated and updated by survey results. Overall, in 2008 

(latest year with complete information), we estimate that the state used ~139 thousand acre-feet 

(AF) in the mining industry (Figure ES1), including 35.8 thousand AF for fracing wells (mostly 

in the Barnett Shale/Fort Worth area) and ~21.0 thousand AF for other purposes in the oil and 

gas industry, although more spread out across the state, with a higher demand in the Permian 

Basin area in West Texas. The coal industry used 26.7 thousand AF along the lignite belt from 

Central to East Texas. The 43.0 thousand AF used by the aggregate industry is distributed over 

most of the state, but with a clear concentration around major metropolitan areas. The remainder 

amounts to 12.2 thousand AF and is dominated by industrial sand production (~80% of total). 
2 

0

10

20

30

40

50

60

Oil and Gas

Coal

Aggregates

Others

2008 Water Use (Thousand AF)

Figure ES1. Summary of estimated water use by mining industry segment (year 2008) 

Water is used mostly for drilling wells, stimulating/fracing wells, and secondary and tertiary 

recovery processes (oil and gas industry); for dewatering and depressurizing pits, with a small 

amount used for dust control (coal industry); and for dust control and washing (aggregate 

industry and industrial sand). Reuse/recycling has been accounted for in water-use figures, as 

well as opportunity usages, such as stormwater collection (aggregates). As such, the numbers 

represent mostly consumption. Only some of the coal-water use could be construed as 

nonconsumed withdrawal when groundwater extracted for depressurization purposes is 

discharged into streams (40–50% of total). The split between surface water and groundwater is 

difficult to assess, short of having information directly from facilities (such as for coal and some 

aggregate facilities), especially for exempt use in the oil and gas industry. 

Projections for future use were done by extrapolating current trends, mainly for coal (more or 

less stable) and aggregates (following population growth). Projections for the oil and gas 

industry were made with the help of various sources by estimating the amount of oil and gas to 

be produced in the state in the next decades and by distributing it through time. Given the 

volatility of the price of oil and gas, it is easy to see that the figures provided are only indicative 

of a possible future. We projected that the state overall water use will peak in the 2020–2030 

decade at ~250 thousand AF (Figure ES2), thanks to the oil and gas unconventional resources 

that will start to decrease in terms of water use around that time. Both coal and aggregates are 

slated to keep increasing, more strongly for aggregates. 

Note (1) that we endeavored to generate results at the county level but, given the uncertainty 

inherent to future production and to the approach, we estimate that individual counties may be 

MiningWaterUse2008 2.xls
3 

off by a factor of 2 or 3, although a group of counties will have a much lower range of 

uncertainty; (2) that projections presented in this report are not binding to the facilities cited in 

the report and are made through integration of many other external factors; and (3) that these 

figures do not represent official TWDB projections but that they will be used as a tool by TWDB 

to make official projections for use in the next water-planning cycle. 

0

50

100

150

200

250

300

2010 2020 2030 2040 2050 2060

Calendar Year

Water Use (thousand AF)

ALL O&G Aggregate Coal Others

Figure ES2. Summary of projected water use by mining industry segment (2010–2060) 

.

MiningWaterUse2010-2060_2.xlss 

5 

2 Introduction 

The Texas Water Development Board (TWDB) has contracted the Bureau of Economic Geology 

(BEG) at The University of Texas at Austin to compile information about current water use in 

the mining industry (to be more thoroughly defined later) and to make water-use projections for 

the next 50 years to 2060. The project was launched as a response to a Request for Statements of 

Qualifications on Topic 3 of the 2009 Water Research Study Priority Topics by TWDB Water 

Resources Planning Division, headed by Dr. Dan Hardin. The present report documents results 

for the four tasks described in the scope of work of Contract #0904830939: (1) identify major 

mining operations and analyze water-use patterns, (2) estimate current water use withdrawal and 

consumption (3) develop long-term water-demand projections at the county level, and (4) report 

the findings of the study and prepare an electronic database. The project is the result of the 

collaboration between the Bureau of Economic Geology at The University of Texas at Austin; 

Steven Walden Consulting, Austin, TX; Texerra, Midland, TX; and LBG-Guyton, Austin, TX. 

The project also benefited from strong cooperation from major players in the Texas mining 

industry, particularly the following trade associations: Texas Mining and Reclamation 

Association (TMRA), Texas Aggregate and Concrete Association (TACA), and Texas Oil and 

Gas Association (TXOGA). 

The report is divided into several sections. In each of them, we successively address oil and gas, 

coal, aggregates, and other mineral substances. Oil and gas activities are not always necessarily 

compiled with other mining activities, but they are for the purpose of this report. It is also 

consistent with the way the federal government catalogs all economic activities (SIC and NAICS 

codes; more on this later). In the next few paragraphs, we present an overview of the mining 

industry in Texas and a high-level discussion of its water use. In Section 3, we describe the 

methodology used to generate figures for current and projected water use. Section 1 describes 

current water use, whereas Section 5 addresses projected water use. The general approach in the 

latter section consists of extrapolating historical and current water-use trends and applying some 

corrections. We think that quantitatively attempting to include new processes or events that 

might emerge or occur in 50 years is a worthless exercise. The current shale-gas boom, largely 

unforeseen by industry watchers, is a case in point. It follows that projections are mostly valid in 

the 5- to 10-year term. We did add a subsection on speculative resources, whose water-use 

figures were not included in final totals. 

2.1 Overview of Mining Activities in Texas and a High-Level Perspective on 

Water Use in the Industry 

2.1.1 Mined Substances 

Before water use is discussed in detail, an understanding of the big picture, as well as the mining 

landscape in terms of operations, might be useful. USGS publishes regular updates to national 

nonfuel mining activities (http://minerals.usgs.gov/minerals/). The latest USGS (2009) 

compilation uses data from 2006 (Table 1). Estimated value of nonfuel minerals is $3.0 billion, 

62% of which is related to cement activities. Note that cement is included in the USGS 

compilation, although neither cement plants nor allied quarrying operations are included in this 

report. This definition of mining is consistent with previous approaches by TWDB. Oil and gas 
6 

importance dwarfs that of other minerals in terms of value (>$50 billion) but, as documented in 

this report, not in terms of water use (Table 1). 

Recently BEG (Kyle, 2008) released a factsheet presenting the industrial minerals in Texas 

consistent with information provided by the USGS. Kyle and Clift (2008) also provided geologic 

background, explaining in general regional terms why the diverse facilities are located where 

they are and the uses of these mined substances. In addition to the oil and gas produced over 

most of the state and to the coal produced within a narrow inland section parallel to the coast, the 

mining industry, in terms of volume, generates value through sand and gravel, mostly exploited 

along rivers, and crushed stone, mostly present in the footprint of the Edwards Limestone. 

Oil and gas resources are generally sorted into conventional and unconventional categories 

(Figure 1 and Figure 2). The former represents the archetypal reservoir traps in either sandstones 

or carbonates and is made up of interconnected pores that allow “easy” communication with the 

well bore. The latter is generally characterized by the use of advanced technologies and consists 

of different types of formation and/or extreme environmental conditions (pressure and 

temperature). In terms of amount produced, unconventional resources have already passed the 

“conventional” reservoirs (Stevens and Kuuskraa, 2009). Relevant characteristics include low 

permeability and a need to stimulate the reservoir through hydraulic fracturing. In this study, the 

unconventional category consists of tight formations, usually “tight gas,” and resource plays such 

as gas shales and liquid-rich shales. We do not describe the technology in this document; see, for 

example, King (2010) for a summary. Coalbed methane (CBM), producing mostly gas, could 

also be added to the list of unconventional reservoirs. Resource plays are generally defined as 

those plays with relatively predictable production rates and costs and with a lower commercial 

risk, as compared with conventional plays. Gas-shale plays with their extensive, continuous 

resources and “no dry well” are examples of resource plays. The challenge for operators is to 

find those sweet spots that will produce gas at a profit. 

Note that the exact terminology to describe hydraulic fracturing as practiced by the oil and gas 

industry has not been settled yet. We opted for “frac”, “fracing” and “fraced” although “frack”, 

“fracking” and “fracked” would have been acceptable too. We also refer to “gas shales” when 

the focus is on the formations as a generic term including Barnett, Eagle Ford, etc shales. In 

contrast, the terms “shale gas” or “shale oil” suggest that the focus is on the commodity itself not 

the formation. The term “oil shale” is sometimes understood as mostly applicable to those 

formations in Utah and Colorado which require more efforts and energy to recover the oil. To 

avoid confusion with common usage, we settled on the term “liquid-rich shale”. 

Coal is generally ranked as anthracite, bituminous, subbituminous, or lignite, listed in decreasing 

order of energy content. Low-rank, low-energy coals include lignite and subbituminous coals, 

and they are the only coals present in Texas in significant amounts (Figure 3). High-rank coals, 

including bituminous and anthracite coals, contain more carbon and lower moisture than lowerrank coals, and thus have higher energy content. Coal has been produced in Texas since the late 

1880’s. At that time the most common mining method was underground mining, but currently 

only surface mining is utilized. Lignite makes up most of the current coal production and will do 

so in the near future as well. Whereas bituminous resources are still available, the economically 

recoverable resources have already been mined. The lignite belt stretches diagonally across 

Texas from Louisiana to Mexico. It is represented by the Wilcox, Jackson, and Claiborne 

Formations of the upper Gulf Coast, whereas, farther west, Pennsylvanian and Permian pockets 
7 

represent bituminous resources. BEG has published many reports on Texas coal (for example, 

Fisher, 1963; Henry and Basciano, 1979; Kaiser et al., 1980). 

Aggregates (Figure 4), as sand and gravel and crushed stone are collectively known, are the most 

important category in terms of volume and dollar amount, after the oil and gas industry. Crushed 

stone consists mostly of limestone and dolomite, with many facilities located along the IH35 

corridor (San Antonio to the Dallas-Fort Worth metroplex) (Figure 5). Because of important 

capital costs, those operations tend to be larger than the sand and gravel facilities. The latter are 

concentrated along streams and on the coast (Figure 6). Allied mined substances include 

industrial sand and dimension stone. There are other substances but they tend to be mined at only 

a few locations (Table 2 and Table 3). Note that several mining activities do not require fresh 

water or even water. Brine production may require fresh water for drilling wells, but its use is 

nominal, which is equally true for gas wells producing from conventional reservoirs. Another 

less systemic example is crushed stone operations, which uses water only for occasional dust 

suppression. 

2.1.2 Mining Facilities 

The first step of the study, before estimating water use, consisted of determining the actual 

number of mining facilities. Their spatial distribution and count at the county level represent the 

next level of complexity as they guide the final mining water use at the county level. Oil and gas 

operations are present in most Texas counties. Number of traditional mining facilities is given by 

several sources, the most complete being from the U.S. Census Bureau (USCB). USCB reports 

survey data every 5 years. The 2002 survey was released in 2005, and the 2007 had not been 

released at the time this report was written. Disregarding oil and gas wells and other oil- and gasrelated facilities, the USCB listed a total of 11 lignite mines, 100+ crushed stone and ~200 sand 

and gravel operations, many of them small, and ~70 facilities of a different type, neither lignite 

nor aggregate. Not counting wells tapping the subsurface (solution mining), the vast majority of 

operations are open-pit operations. USCB (2005) reported six underground mining operations in 

2002, all but one (rock-salt operation) being very small. 

MSHA (Mining Safety and Health Administration) also manages a database of abandoned and 

active mines across the country because mines must submit health and safety applications and 

obtain permits. As of July 2010, 1,869 abandoned and 692 active mines (including cement plants 

and coal mines) were officially registered in the state of Texas (Table 3). However, the overlap 

with USCB data is not perfect because the MSHA database includes (1) facilities treating the raw 

material but not necessarily extracting it locally and (2) nonactive facilities that have not been 

officially abandoned. 

The database for the Source Water Assessment and Protection (SWAP) program, a federally 

mandated program managed by the Texas Commission of Environmental Quality (TCEQ), 

contains an inventory of potential sources of contamination (POSC) susceptible to contaminating 

sources in potable water (both groundwater wells and surface-water intakes). Those sources 

include a whole range of human activities from cemeteries to gun ranges to dry cleaners, 

including mining facilities (“Natural Resource Production”). TCEQ cites the Railroad 

Commission of Texas (RRC), the U.S. Geological Survey (USGS), and BEG as sources for the 

mining subset of the database. Information that can be depicted on an aquifer map is a more 

detailed and useful inventory than a listing of facilities (Figure 7, Bastrop and Lee Counties). 
8 

2.1.3 Water-Use Overview 

Overall, mining water use in Texas represents only a small fraction of total water use in the state, 

and estimates have varied, given the relatively low priority of this category of water use. 

Previous water-demand surveys and projections estimated ~280 thousand AF as the demand for 

water use in mining compared with 17 million AF (1.6%) for total water use in 2000 (TWDB, 

2007, Table 4.2), ~250 thousand AF and ~17 million AF (TWDB, 2002, Table 5.2), and ~200 

thousand AF and ~16.5 million AF (TWDB, 1997, Table 3.2), both also for year 2000 (Table 4). 

Those figures represent only fresh water, the generally accepted definition of which is any water 

with a total dissolved solid content (TDS) <1,000 mg/L. Livestock as well as crops tolerate 

higher TDS, perhaps as high as 6,000 and 10,000 mg/L, respectively. Some sources define fresh 

water as water <3,000 mg/L. Inability to reconcile the different definitions adds uncertainty to 

the final figures provided in this report. Under the Safe Drinking Water Act, any <10,000 mg/L 

non-exempt aquifer is considered a potential underground source of drinking water. Note that 

there is no consistency (including in the documents cited in this work) in the definitions of fresh, 

brackish, and saline water which depend mostly of the context. 

The overarching goal of this report is to confirm these figures. We provide some explanation on 

why results presented in this report differ from previous projections by TWDB, but they are due 

mostly to a change in accounting and to the impact of shale-gas production. The work presented 

in this report will not formally be included in the 2012 water plan, but will inform it. An issue of 

great impact to this work is the split between groundwater and surface water. This information is 

not always easy to identify, but in the course of this project, we tried to collect as much as 

possible. Approximately 59% of the water used in the state is groundwater (TWDB, 2007, p. 

176), although this statistic is biased because a sizable fraction comes from the Ogallala aquifer 

in the Texas Panhandle and is used for irrigation. In this area of Texas the groundwater-use 

fraction is somewhat higher, whereas elsewhere it tends to be smaller. Irrigation is an important 

category used by TWDB to detail water use in the state and is the largest in terms of volume. 

Other categories in approximately decreasing volumes are municipal, manufacturing, steamelectric, livestock, mining, and domestic/other. 

In addition to efforts at the state level, several federal organizations interpret information flowing 

from the states. USGS publishes every 5 years (with a lag of a few years relative to data 

collection) information about all types of water use across the nation. The most recent versions 

are authored by Kenny et al. (2009) for year 2005 and by Hutson et al. (2005) for year 2000 

(Table 5). Sources of data feeding the reports are left to the judgment of local state offices and 

vary with water-use type and state (Kenny, 2004). For the State of Texas, BEG, RRC, TCEQ, 

and TWDB are typically contacted. USGS also performs its own survey, although it is not 

always successful in obtaining comprehensive information from all facilities. USGS typically 

extrapolates from the information obtained and publishes only aggregated data. For the State of 

Texas, Kenny et al. (2009, Table 2B) reported a mining-water withdrawal of 102 and 614 

thousand AF/yr, respectively, for water of fresh (defined in the USGS report as <1,000 mg/L) 

and saline (>1,000 mg/L) quality. All saline water was reported as groundwater, whereas only 30 

thousand AF of the fresh-water category was reported as groundwater (Kenny et al., 2009, Table 

3B and Table 4B). Most of the saline water is counted toward secondary recovery of 

hydrocarbons (disposal not included). Kenny et al. (2009, p. 35) stated that dewatering 

operations are included in the water withdrawal total only if the water is put to beneficial use (for 

example, dust control). The work presented in this report follows a different approach (see 
9 

section on Methodology). USGS figures for the year 2000 (Hutson et al., 2005, Table 4) are 

somewhat different and more closely align with those of the TWDB, with a total fresh-water use 

of 246 thousand AF (144 groundwater and 102 surface water). The total amount of saline water 

(produced water) at 565 thousand AF is not sizably different. Whereas 1995 (Solley et al., 1998) 

figures are consistent with those of 2000, the difference between 2000 and 2005 figures 

corresponds to a change in accounting. 

2.2 Overview of Recent Projections 

The TWDB Office of Planning provides projection figures to the State Water Plan (e.g., TWDB, 

2007). Norvell (2009) represents the latest effort before the work presented in this report. An 

earlier effort by a consultant on behalf of TWDB (2003) includes manufacturing in addition to 

mining. Both Norvell (2009) and TWDB (2003) attempted to link economic activity at the 

county level to water use. In essence, the approach consisted of developing a correlation between 

historical water use and economic output at the county level and extrapolating future water use 

from a forecast of economic activity. The correlation was made through so-called water-use 

coefficients (ratio of water use and gross economic output) determined at the county level. 

Mining-specific constraints were dismissed and hidden as being part of the overall economic 

activity (TWDB, 2003, p. 2–3). Overall, results of this approach were not very satisfying for the 

mining category. 
10 

Table 1. Fuel and nonfuel raw mineral production in Texas 

Mined Substance Quantity 

Approx. Value 

(1,000s of $) 

MMbbl ~$57/bblf

Oila 344.5 ~19,000,000

Tcf $5/Mcfg

Gasb 7.53 ~37,650,000

1000s short tons ~$18/Short tonh

Coal/lignitec 37,099 ~668,000

 

Uraniumd Withheld Withheld 

Nonfuel Mineralse 1000s metric tons 

Cement (overwhelmingly portland) 11,682 1,120,700

Clays (common clay, bentonite) 2,289 14,900

Gypsum 1,430 11,800

Lime 1,650 130,000

Salt 9,570 132,000

Sand and gravel: 99,500 603,000

Industrial sand 1,530 65,600

Crushed stone: 136,000 824,000

Dimension stone 31i 12,600

Subtotal 2,902,000

Other: talc, brucite, clays (Fuller’s earth, kaolin), helium, 

zeolites, sulfur 78,000

Total 2,980,000

Source: a: http://www.rrc.state.tx.us/data/production/oilwellcounts.php —2009 data; 

b

: http://www.rrc.state.tx.us/data/production/gaswellcounts.php —2009 data; c

: http://www.rrc.state.tx.us/industry/_COALPRODthru2009.XLS —2009 data; 

d

: Information withheld for confidentiality (small number of producers) 

e

: USGS (2009) —2006 data; 

f

: 2009 annual average for Texas; http://www.eia.gov/dnav/pet/pet_pri_dfp1_k_a.htm g

: 2009 annual average for Texas; http://www.eia.gov/dnav/ng/ng_sum_lsum_dcu_STX_a.htm h

: 2008 annual average for Texas; http://www.eia.doe.gov/cneaf/coal/page/acr/table31.html i

: Seems to be a slow year or underreporting 
11 

Table 2. Estimate of the number of mining facilities in the State of Texas in 2002 (USCB) 

Industry Type 

Total Number of 

Establishments 

>20 

Employees

Crude petroleum and natural gas extraction 2803 286

Natural gas liquid extraction (includes sulfur extraction) 180 57

Total Oil and Gas Extraction 2983 343

Bituminous coal and lignite surface mining 11 9

Total Coal Mining 11 9

 

Fe ore mining 3 0

Au ore and Ag ore 4 0

Cu, Ni, Pb, and Zn ore mining 1 0

U, Ra, V ore mining 5 1

Other metal ore mining 2 0

Total Metal Ore Mining 15 1

 

Dimension stone mining and quarrying 18 5

Crushed and broken limestone mining and quarrying 71 23

Granite mining and quarrying 3 0

Other crushed and broken stone mining and quarrying 15 5

Total Stone Mining and Quarrying 107 33

Construction sand and gravel mining 198 51

Industrial sand mining 19 5

Kaolin and ball clay mining 1 1

Clay and ceramic and refractory minerals mining 11 4

Total Sand, Gravel, Clay, and Ceramic, and 

Refractory Minerals Mining and Quarrying 229 61

Potash, soda, and borate mineral mining 1 1

Other chemical and fertilizer mineral mining 6 1

All other nonmetallic mineral mining 19 2

Total Other Nonmetallic Mineral Mining and Quarrying 26 4

Total Nonmetallic Mineral Mining and Quarrying 362 98

Source: USCB (2005) 
12 

Table 3. Number and diversity of minerals mining operations in Texas (MSHA) 

Primary Commodity # of 

Fac. 

Primary Commodity # of 

Fac. 

Alumina 2 Dimension sandstone 11 

Barite barium ore 7 Dimension stone NEC 47 

Bentonite 3 Dimension traprock 1 

Cement 12 Fire Clay 7 

Clay, ceramic, refractory mnls. 2 Gypsum 8 

Common clays NEC 19 Iron ore 6 

Common shale 2 Lime 2 

Construction sand and gravel 250 Manganese ore 1 

Crushed, broken granite 1 Misc. nonmetallic mnls. NEC 1 

Crushed, broken limestone NEC 167 Pigment minerals 1 

Crushed, broken marble 3 Potassium compounds 1 

Crushed, broken sandstone 6 Salt 2 

Crushed, broken stone NEC 52 Sand, common 15 

Crushed, broken traprock 3 Sand, industrial NEC 10 

Dimension limestone 32 Talc 5 

Dimension marble 1 Zeolites 1 

NEC: 

Source: MSHA (http://www.msha.gov/DRS/DRSextendedSearch.asp), data from June 2008 

Table 4. Historical projected mining water use (top) and total water use (bottom) for all water 

uses in Texas by TWDB (MAF) 

Water Plan 1990 2000 2010 2020 2030 2040 2050 2060 

1997 149 

15,729 

205 

16,586 

187 

16,867 

182 

17,135 

191 

17,489 

194 

17,900 

188 

18,354 

2002 149 

15,729 

253 

16,919 

246 

17,662 

245 

18,195 

252 

18,732 

252 

19,369 

244 

20,022 

2007 279 

16,977 

271 

18,312 

281 

19,011 

286 

19,567 

276 

20,105 

277 

20,759 

286 

21,617 

Source: TWDB (1997, 2002, 2007) 

Table 5. Historical mining water use in Texas by USGS (thousand AF) 

 Fresh Saline Total 

1995 

Groundwater 143 458 602 

Surface water 93 0 93 

Total 236 458 694 

2000 

Groundwater 144 565 709 

Surface water 102 0 102 

Total 246 565 811 

2005

Groundwater 30 614 644 

Surface water 72 0 72 

Total 102 614 716 

Source: Kenny et al. (2009), Hutson et al. (2005), Solley et al. (1998) 
13 

Figure 1. Location map of all wells with a spud date between 2005/01/01 and 2009/31/12 

(approximately ~75,000 wells) 
14 

Source: IHS database 

Figure 2. Map showing locations of all frac jobs in the 2005–2009 time span in the state of 

Texas. Approximately 23,500 wells are displayed 
15 

Figure 3. Location map of coal/lignite operations 
16 

Source: NSSGA/USGS database and MSHA database 

Note: deleted from the NSSGA database were all facilities whose names included “yard,” “asphalt,” “concrete,” or 

“cement,” as well as plants of well-known cement producers; facilities with “chemical” are treated in the other 

nonfuel minerals section (Section 4.5) 

Figure 4. Location map of aggregate operations from NSSGA database (data points) and MSHA 

database (selected counties) 
17 

Source: NSSGA/USGS database and MSHA database 

Figure 5. Location map of crushed-stone operations from NSSGA database (data points) and 

MSHA database (selected counties illustrating number of operations) 
18 

Source: NSSGA/USGS database and MSHA database 

Figure 6. Location map of sand and gravel operations from NSSGA database (data points) and 

MSHA database (selected counties illustrating number of operations) 
19 

Figure 7. Example or representation provided by the SWAP database 

Mine Type 
20 

3 Methodology and Sources of Information 

With thousands of operations in the state and with no legal requirement to report production and 

water use (except partly for oil, gas, and coal), some choices had to be made to deliver an 

acceptable product within the allocated budget. We followed two guiding principles: (1) focus on 

the biggest users, that is, oil, gas, coal, and aggregates, and (2) if a county has no operations of 

the previous category, check for any minor mining activity. Several methodologies have been 

used in the past at the national and state level. Norvell (2009) and TWDB (2003) tried to link 

economic activity and water use to a black-box approach without including the detailed 

processes specific to each mining sector. This approach cannot predict groundwater/surface 

water split. 

Another approach calls for the use of water-use coefficients. These coefficients, intensive in 

nature, are obtained by taking the ratio of two extensive values for a few facilities: (1) water use 

and (2) commodity production that results in a unit of gallons per weight or volume of the 

commodity. In a second step, the overall water use for all facilities of that type is computed by 

applying the water-use coefficient to the overall production for each facility, each county, or 

across the state. This approach has limitations because 1) the few facilities used to develop the 

coefficients may not be representative of the overall industry (they are typically chosen because 

they provided information not because they are representative), and 2) a large state, such as 

Texas, has considerable climate differences which make it more difficult to apply a single, 

general coefficient to all facilities. USGS presented in a recent report its approach to estimating 

mining water use at the national level in 2005 (Lovelace, 2009) and, for the most part, it made 

use of water-use coefficients. Unfortunately, the specific water-use coefficients are not publicly 

available. Lovelace (2009, Table 1) gave a broad range in the following general categories that 

are applicable to the whole nation: metal mining (140 to 1,567 gal/st), coal mining (50 to 59 

gal/st), and mining and quarrying of nonmetallic minerals except fuels (30 to 997 gal/st). 

This second approach does not work for oil and gas water use because many oil and gas areas 

use only water to drill and stimulate wells, usages not directly related to hydrocarbon production. 

A third approach consists of actually obtaining the information directly from the 

facilities/operators responsible for most of the water use. This approach is particularly effective 

when databases contain the information, such as in the case of shale gas and oil. 

3.1 General Sources of Information 

The TWDB Office of Planning obtains material for its projections by regularly collecting data 

through annual water-use surveys (WUS—http://www.twdb.state.tx.us/wushistorical/) for input 

into water planning. In Texas, water planning is done through 16 Regional Water Planning 

Groups (Figure 8; http://www.twdb.state.tx.us/wrpi/rwp/rwp.asp). Data collection by TWDB 

goes back >50 years to 1955, although the legislature increased the impetus when Senate Bill 1 

was passed in 1997, requiring State and local governments to become better informed on how 

water was utilized in their jurisdiction. Sending back the requested information to TWDB is 

voluntary, however. TWDB then extrapolates the incomplete information to the whole state. 

BEG has access to the data collected by TWDB, and the latest water-mining-use information is 

available is 2007. Unfortunately, the response rate for a given year is low, although through the 

years many companies have returned surveys. 
21 

Overall, during the course of this study, we acquired both soft and hard data. Soft data, such as 

guesstimates of the future direction of the different mining sectors, were attained mostly through 

(1) discussion with professionals from the industry and (2) by perusing the web (USGS, EIA, 

etc.) and other sources of reports and papers (for example, Powell’s Barnett Shale Newsletter, a 

weekly newsletter providing information on various gas shales in the U.S.; the Oil&Gas Journal; 

Energy Intelligence Natural Gas Weekly; Texas Drilling Observer; SPE onepetro database 

articles, Fort Worth Oil and Gas Magazine, and DOE news alerts). 

The large amount of knowledge accumulated about production from shales has not fully made its 

way to the peer-reviewed literature yet, thus requiring us to rely on many noncitable data. As 

such, this project involved a great deal of interaction with workers in the field, indispensable to 

locating the latest source of information and to updating it to current knowledge. Fairly complete 

hard data on water use in the gas industry (“frac jobs”) were obtained from IHS Energy, a private 

vendor compiling all information filed by operators to the RRC (as well as many other 

governmental entities around the world), and putting it into a format easy to search and retrieve. 

We also directly used the query tool available from the RRC website. However, not having direct 

access to the database for custom queries was a handicap. RRC aggregates its data by fields, 

counties, or districts (Figure 9). 

Data on water use for drilling and waterflooding are much harder to obtain because operators do 

not have to report their water use as such. The latest thorough data collection of water use in the 

oil and gas industry was the 1995 RRC survey (De Leon, 1996). We updated these 15-year old 

data by contacting a trade association, TXOGA, and by surveying operators in West Texas, the 

area with the most waterflooding in the state, which helped constrain current and future water 

use. 

Data on the coal industry were obtained through a survey of Texas coal operators (~100% 

response rate) and a follow-up with them, consulting with RRC and collecting information from 

its paper files. Information about the aggregate industry was obtained through surveys we 

requested from two trade organizations (TMRA and TACA) and discussion with selected 

operators. For all other operations, we did not gather additional information but relied on 

published information. Exceptions were a few clay operations, as well as a few uranium 

operators affiliated with TMRA, from whom we also received survey results. The search was 

guided by previous work from the TWDB, as well as by published and unpublished documents. 

We also sent out, with modest success (see Appendix D), a questionnaire to various water 

governmental entities for information on mining activities in their jurisdictions. Apart from those 

mentioned in the body of this report, very few Groundwater Conservation Districts (GCDs) have 

accurate knowledge on the amount of water used in their areas in the mining category unless the 

information is readily available (for example, lignite operations) (see Appendix E for details). 

Figure 10 displays a current map of GCD locations, with active and inactive mine locations 

superimposed. 

3.2 Definition of Mining Water Use for the Purpose in this Report

For consistency with previous estimates and comparison with other studies, we followed the 

standard classification for economic activities. According to the Standard Industrial 

Classification (SIC), mining industries are given the following four-digit codes: 

Major group 10 (1000 to 1099): metal mining 
22 

Major group 12 (1200 to 1299): coal mining 

Major group 13 (1300 to 1399): oil and gas extraction 

Major group 14 (1400 to 1499): mining and quarrying of nonmetallic minerals, except fuels 

These major groups also include beneficiation. Operations that take place in beneficiation are 

primarily mechanical, such as milling–crushing and grinding, washing, dust suppression on 

service roads, and outdoor machinery. Manufacturing, which includes chemical and more 

involved processes, is represented by major groups 20 to 59. Major group 32 consists of stone, 

clay, glass, and concrete products, including cement (3241 is hydraulic cement) and clay 

products. SIC codes have been superseded by NAICS codes but are still widely in use. The more 

recent six-digit NAICS code defines “Mining, Quarrying, and Oil and Gas Extraction” as Sector 

21. Beneficiation of mined material is included in this category that also includes the following 

groups: 211xxx oil and gas extraction, 212xx mining (2121xx coal mining; 2122 metal ore 

mining, 2123 nonmetallic mineral mining, and quarrying), 213xxx: support activities for mining. 

Similar to the SIC classification, several potential mining products are in an ambiguous position: 

clay and refractory products, cement (SIC3241 hydraulic cement and 3273xx cement and 

concrete product manufacturing), and lime manufacturing. 

Introduction to the SIC3241 group (hydraulic cement) on the official website states: “When

separate reports are available for mines and quarries operated by manufacturing establishments 

classified in this major group, the mining and quarrying activities are classified in (...) mining. 

When separate reports are not available, the mining and quarrying activities (...) are classified 

herein with the manufacturing operations.” In this report, we have included small clay pits but 

have not included cement raw materials, limestone and clay, that are sintered together to make 

the clinker that will be finely ground to become the main constituent of portland cement. Some 

cement-producing facilities just grind the clinker and include additives without performing any 

quarrying activities. More generally, concrete plants of the ready-mix or central mix type are not 

included in this study. A rough calculation yields ~125 gal water/st of cement to make concrete 

or, equivalently, 30 gallons of water per short ton of aggregate. Including concrete 

manufacturing in the water use of aggregate quarrying operations would inflate mining water 

use. This distinction seems logical on paper but may be hard to apply in the field, where different 

water uses may not be tracked separately, or worse, water use for the whole process may be 

reported as mining. Similarly, asphalt plants and brick manufacturing plants are not included. We 

also excluded as much as possible water used to convey materials from extraction sites to offsite 

processing facilities. Thus, water for slurry pipelines and tank farms was not classified as mining 

water. 

The opposite issue occurs with gas plants and other oil and gas facilities located not far from the 

extraction wells. They are listed with a mining code (SIC 1321) and are excluded from this 

study. Similarly, some other operations are listed with a mining SIC, for example SIC1459 (clay, 

ceramic, and refractory minerals), but most of the water is used in manufacturing, not mining 

activities. The matter can worsen if some of the raw material used in the plant is not locally 

extracted. 

Another important issue is dewatering, especially of coal mines. In agreement with TWDB, we 

considered aquifer dewatering as consumption because the water is no longer available for other 

aquifer users. It should be noted, however, that the water could still be put to beneficial use when 

discharged to local streams and rivers. In other words, some mining operations could be 

considered as net producers of water, not as users of water, for planning purposes. And yet the 
23 

position taken in this document is that, as long as there is no directly specifically targeted user, 

the water must be counted toward consumption. 

3.3 Methodology: Historical Water Use 

Historical water use was computed using direct data if available (for example, shale gas, coal), 

with the potential problem of completeness (missing facilities), in which case extrapolations 

were performed. In other cases, water-use coefficients were used. We used the year 2008 as the 

reference year because at the beginning of this work, not all 2009 data were yet available and 

because the year 2009 is likely not representative, owing to the economic slowdown. 

3.3.1 Oil and Gas Industry 

3.3.1.1 Gas Shales and Other Tight Formations 

Gas shales are called resource plays in the sense that most wells will yield some gas over a large 

regional area, as opposed to conventional oil and gas production that needs to tap actual 

reservoirs of limited spatial extent (Figure 11). We extracted data from the IHS database relative 

to all fracing operations from the origins of the technology. We collected names of plays 

typically fraced by consulting BEG researchers with expertise in this field. Collecting all 

historical information allows for an understanding of the evolution of the technology—from 

small-scale fracing to improve permeability around the well bore in relatively permeable oil and 

gas formations, to medium-scale operations on tight gas to generate fracture permeability 

required to produce gas, to recent large-scale operations on shales (to recover mostly gas but also 

more and more oil). 

We determined the plays with active frac jobs by downloading from a database provided by a 

private vendor: IHS Energy. The ultimate source of most of the information was forms submitted 

to the RRC by operators, but with the added advantage of a powerful querying tool. Before 

drilling a well, including recompletion, operators must apply to the RRC for a drilling permit 

(form W-1). Once completed, operators submit a W-1 form (for oil-producing wells) or G-1 form 

(for gas-producing wells). The two latter forms contain information about well stimulation, 

including slick-water fracing. 

We compiled all wells completed in the 2005–2009 period (5 years) and then selected wells with 

water use >0.1 Mgal. This threshold is somewhat arbitrary and was used to distinguish true frac 

jobs from simple well stimulation by fracing and acid jobs. This approach is better than relying 

on operator classification of acid vs. frac vs. some other IHS category because our experience 

shows this method to be unreliable. We then compiled all plays with at least one frac job in that 

period and returned to the IHS database to obtain all wells fraced in these plays (including earlier 

than 2005). Further processing is detailed later. An additional download of the 2010 data was 

done in November 2010 to identify recent trends. 

Nicot (2009a) and Nicot and Potter (2007) (also in Appendix B of Bené et al., 2007) detailed one 

of the methodology approaches followed in this current work as applied to the Barnett Shale. 

Appendix B presents the successful postaudit of the projections made during the 2006–2007 

Barnett Shale study. Because of budget constraints, it is not possible to reproduce the finer level 

of granularity achieved in the previous study, but the general methodology stays identical: (1) 

gage the eventual level of drilling (and upper bound of ultimate water consumption) at the end of 

the play history by estimating reserves and prospectivity and (2) distribute water use through 

time by estimating rig availability for the next few decades and by applying time-varying 
24 

correcting factors. Many papers emphasize that each play is different and that even wells in close 

proximity show widely different behavior (Matthews et al., 2007; Chong et al., 2010; King, 

2010). However, we assume that, at the county level, most of these differences average out and 

that it is appropriate to use averages. 

The whole process relies on having accurate historical data, which, in this work, are obtained 

from the IHS database (header and test treatment options). The first step of the processing is to 

check the data and fix possible typos (wrong units, additional or missing zeros, etc.). Not paying 

attention to the typos (generally <10% of the selected portion of the database) could decrease or 

increase individual well-water use. Typos artificially increasing water use represent the larger 

risk. The general approach to achieving this goal was to compute proppant loading and water-use 

intensity for each individual well (not individual stage). 

Proppant loading is computed by summing up the amount of proppant mixed and the amount of 

water used and taking the ratio. Field units are pounds per gallon (ppg or lb/gal). An acceptable 

value is near 1 (0.5 to 2, e.g., Curry et al., 2010, p. 3; our own statistics). This parameter has to 

be used with caution because, in past treatments, proppant loadings were at least twice as high 

but with a smaller water volume. Hamlin et al. (1995, p. 9) mentioned 50,000 to 70,000 gal of 

gel and 100,000 to 120,000 lb of sand for Canyon Sands in the Val Verde Basin of West Texas. 

Dutton et al. (1993, p. 45) cited a typical treatment in the Cotton Valley sandstones of 0.4 Mgal 

and 1.7 million lb of sand. They also indicated (p. 79) that 150,000 gal of x-linked gel and 

450,000 lb of proppant were appropriate for the tight sands of the Vicksburg Formation of South 

Texas. 

Water-use intensity is computed by dividing up total amount of water used by length of the 

productive interval, either vertical length for vertical wells or total lateral length for horizontal 

wells. Lateral length can be computed from two techniques that generally agree: distance 

between surface location of the wellhead and bottom-hole location and/or length of total driller 

depth minus true depth (Figure 12). These are approximations that work well as long as they are 

applied consistently across a play and as long as most wells are constructed similarly. The socalled directional wells present a challenge, but they are not very numerous in the IHS database 

and are folded into the horizontal-well category. 

Total water use, total proppant amount, water-use intensity, or proppant loading out of the 

common range create additional scrutiny for that particular frac job. The process is 

semiautomated because there have been tens of thousands of frac jobs across the state in the past 

few years. Building a histogram or using the filter feature in Excel are the two ways used to 

catch these outliers. Many errors can be caught by looking at the consistency of metrics. The 

decision is then made to fix an obvious typo (for example, barrel unit instead of gallons or tons 

instead of pounds or an extra zero for water a figure that matches expected water intensity and 

proppant loading only when it is removed). If no fix is evident, the frac job receives the median 

water use for that play and year(s). Frac jobs with missing water use are also treated by 

estimating what they should be from the proppant amount and the median proppant loading for 

that play and year(s). If neither the water volume nor the proppant amount is given (can be as 

high as 30% of the data set for a play), the frac job receives the median water use for that play 

and year(s). The focus is more on the median than on the average, which can be heavily biased 

(Nicot and Potter, 2007). 
25 

Once the selected data set were cleaned up, we used in-house visual basic scripts within Excel to 

build various histograms and plots for each play: (1) location map and geological information as 

available, (2) plots of historical number of frac jobs per year in combination with percentiles of 

water use (for vertical then horizontal wells), (3) comparison of distribution of vertical vs. 

horizontal wells through time, (4) histogram of water use per vertical well, (5) histogram of 

water use per horizontal well, (6) histogram of water use intensity for horizontal wells, (7) 

histogram of proppant amount, and (8) histogram of proppant loading. Historical plots do not 

include wells with no water-use value, but those wells are added to the 2008 reference year, 

assuming a median water-use value. 

A major assumption is that all makeup water is fresh. Typically, higher TDS water (mostly 

because of calcium) will increase friction-reducer demand, one of the additives. Hayes (2007) 

discusses the industry requirements in terms of TDS and ionic makeup. A brackish water (or 

even saline water, for example, from the underlying Ellenburger Formation in the Barnett Play) 

could be used if the pressure required to frac the shale is not too high (translating into lower 

pumping rate and, consequently, less friction reducer). Some higher-TDS water (from reuse of 

flowback) can be used too, but it is accounted for in the use of a recycling coefficient. 

3.3.1.2 Waterflooding and Drilling 

RRC neither systematically compiles information on waterflooding and similar recovery 

processes nor does it collect data about drilling-water use. RRC does post information about 

injected fluid volumes, but there is no systematic information on the nature of the fluid. Most is 

likely water, but often there is no indication of the TDS of the water, nor is the 

groundwater/surface water split well constrained. Fresh-water injection wells need to be 

permitted as such. Form H-1 asks for the type of injected fluid (saltwater, brackish water, fresh 

water, CO2, N2, air, H2S, LPG, NORM, natural gas, polymer, and others). For waters other than 

saltwater, the form requires the applicant to provide information on the source of the injection 

water “by formation, or by aquifer and depths, or by name of surface water source” (fresh-water 

questionnaire or form H-7) and to demonstrate that no other source water of adequate quality is 

available nearby. A companion form (form H-1A) requests maximum daily or estimated daily 

injection rates of each fluid type (including fresh and brackish water when appropriate). Actual 

water use is reported on form H-10 (http://webapps.rrc.state.tx.us/H10/h10PublicMain.do). A 

UIC query (http://webapps2.rrc.state.tx.us/EWA/uicQueryAction.do) also provides useful 

information about individual wells, although no breakdown in type of injected fluids. In addition, 

the regulatory focus is on the total volume injected and the pressure rather than the type of fluid 

injected. Experience has shown that H1 forms are only of little use in estimating fresh-water use; 

rates provided by the applicant largely overestimate actual rates. 

Other researchers have also tried to collect waterflood information. Lovelace (2009), in a USGS 

summary of the approach used to estimate 2005 oil and gas water use across the nation, 

presented the assumptions made to develop the final figures including into his fresh and saline 

categories. (1) all water is groundwater; (2) if several water types are indicated in the H10 form, 

they are assumed to be of equal volume; and (3) because injection volumes are not provided for 

individual wells, all wells were assumed to contribute equivalent volumes of water. However, the 

1995 RRC study (De Leon, 1996) invalidates some of those assumptions; a significant fraction 

of the water is surface water. 

In the end, to gather information about waterflooding, we decided to send quantitative survey 

forms to ~25 leading oil-producing companies in West Texas, where waterflooding and EOR 
26 

operations are concentrated (Galusky, 2010). This mailing was followed up with telephone calls 

and e-mails, and we communicated to them that all of the information and data that they 

provided would be held in strict confidence by Texerra/P. Galusky, who would submit only an 

aggregate compilation and summary of key findings in its report to BEG. Additional data and 

information on drilling activity, oil production, and related parameters were obtained from 

various publicly (internet) available and private (commercial) data sources. 

Drilling-water use is generally not reported, and waterflood reporting combines all water sources 

from fresh to saline. A logical approach is then to collect information from operators. Drillingwater-use information was collected through informal discussions with practicing field 

engineers. 

3.3.2 Coal/Lignite

Determining the amount of water used within the coal mining industry proves to be a 

complicated task because no entity currently tracks consumption; however, all coal mine 

operators must report total pumping rates to the RRC as a requirement for their mine operating 

permits under Title 16, Part 1, Chapter 12 of the Texas Administrative Code. When a mine 

operator applies for a new permit, estimates of current conditions and future drawdown must be 

provided to allow the RRC to determine allowable pumping rates. Once mines are in operation, 

operators must report their drawdown and pumping rates quarterly for the first 2 year, and then 

once every year following the 2-year period. The RRC does not restrict the amount of water to be 

pumped. The agency simply tracks pumping rates and requires documentation of the drawdown 

impact of mining operations on the surrounding areas (T. Walter, RRC, 2009, personal 

communication). Dewatering and depressurization totals were collated from each mine from 

RRC public records with the cooperation of Tim Walter, as well as results from the survey sent 

to each operator. 

To help in the process of collecting data, in-depth literature searches and discussions with 

industry experts were conducted to help us decide on the best route for determining withdrawal 

and consumption estimates. We concluded that estimates for specific mining activities, such as 

hauling or dust suppression, vary for each active mine, depending on climate, location geology, 

production techniques, and other factors. Therefore, it would be necessary to analyze each mine 

individually. Fortunately the number of facilities is small, and all of them are large and well 

documented. We launched a survey in coordination with the Texas Mining and Reclamation 

Association (TMRA), which was very successful (~100% response rate). 

An important question was whether to include pit-dewatering volumes into water 

consumption/withdrawal. Pit water originates from rain falling into the pit and being captured by 

its drainage area, as well as seepage from the overburden. The latter can be minimized but never 

eliminated by pumping groundwater from the formations to be removed before mining. Many 

mines divert runoff and pit water from precipitation into retention ponds and use it, for example, 

for dust control. For consistency with the approach followed in the aggregate category, we did 

not include pit dewatering (strictly defined) in water use. 

Aquifer depressurization also lacks the clear-cut classification of some other water uses. 

Although the amount pumped for depressurization represents a net loss to the aquifer, the water 

is available for other uses, in particular environmental flow. In addition, in at least one mine, 

depressurization is put to immediate beneficial use when some wells are turned over to a water 

supply company (T. Walter, RRC, 2009, personal communication). This amount of water is not 
27 

counted toward mining so as to avoid double-counting when merging all water uses, although it 

could bias water-use coefficients (they are not, however, used for coal in this study). 

3.3.3 Aggregates

The approach for aggregates is different from that for oil and gas, about which relatively little is 

known or for coal/lignite, about which a complete data set exists. TWDB already has a working 

database from past water-use surveys. Various other reference sources and data sets were 

examined in an effort to determine whether available information could be used to further 

validate the TWDB water-use estimates and/or to refine our estimates at the county level. 

Resources examined include 

! USGS 

! MSHA 

! TWDB 

! TCEQ 

! Interaction with and web search of the largest producers in the state (Martin Marietta 

Materials, Inc., Vulcan Materials, Inc., and Capitol Aggregates). 

Furthermore, we recognized that although most aggregate operations recycle or reuse a large 

proportion of the water used in their processes, water-use data sometimes reflect the full volumes 

used and do not account for the recycled volumes. Such an uncertainty may result in 

inappropriate inflation of the values used for planning purposes. This report also attempts to 

assess the availability of additional information that may differentiate between water used in 

aggregate mining and that actually consumed or lost in these processes. A significant effort was 

made to conduct a survey in coordination with TMRA and TACA to obtain water-use and waterconsumption data for a sampling of representative member companies and facilities across the 

state (survey questionnaires in Appendix D). Despite the cooperation of the two associations and 

multiple attempts to encourage participation, only seven companies of the many companies 

contacted responded to the survey request. They provided information for 27 separate facilities 

with information on location, production, water use, recycling rate, and source water. 

These database reviews and survey results were analyzed and compared in order to supplement 

the information obtained by earlier surveys and planning documents. Results of the survey were 

highly variable, with some data tending to validate information obtained from earlier work by 

other agencies and some data suggesting significant differences. The survey highlighted the 

difficulties in using this approach to gather information on the industrial mineral mining sector. 

Some of the factors that may have influenced the response include the number, diversity, and 

relatively small size of many of the mining operations; the concern expressed by many in the 

mining industry of disclosing competitively sensitive information; the lack of available personnel 

to compile or calculate data; and the lack of regulatory requirements to collect and report 

requested information. 

Issues we had to overcome or mitigate included (1) information on the types and numbers of 

industrial mineral mining facilities in Texas obtained from the Mining Safety and Health 

Administration (MSHA)—681—differed significantly from data from TCEQ—3,125 and (2) 

water-consumption coefficients, expressed in terms of gallons per ton of product extracted (gal/t) 

or gallons per dollar of production output (gal/dollar), which have been developed to estimate 

current and future demands on the basis of population growth or financial forecasts. The 

coefficients for washed crushed-stone mining derived from the survey were significantly 
28 

different from those previously determined by either the USGS or the TWDB, whereas the 

coefficients for construction sand and gravel operations were similar to previous estimates. 

Directly useful data in our possession were 

(1) Production and water-use information for a few facilities (27) from the BEG survey; 

(2) Water-use information from TWDB WUS survey dating back from 1955, although only 

recent information was used (26 facilities with some overlap with the BEG survey); 

(3) List and locations of facilities trying to limit the potential problem of having listed the 

location of the company headquarters possibly located in a county different from that of 

the quarry/pit; 

(4) Generic industry water-use coefficients from other studies; 

(5) Water-use information at the county level for all mining activities from USGS (year 

2005); it is thought that the fresh-water-use data include mostly coal and aggregates; 

(6) County-level population information from TWDB projections; 

(7) Annual state production in 2008 (153 million tons crushed stone and 87.7 million tons 

sand and gravel) and earlier years (for example, 136 and 99.5 million in 2006, 

respectively) 

As noticed by earlier workers, there is no clear correlation between production and water use, an 

observation again confirmed by the BEG survey. If that were the case, we could simply infer 

water use from production. However, neither production nor water-use figures are readily 

available. Actually, production figures are available that are aggregated only at the state level 

and do not result from direct data compilation. USGS collects production information and does it 

through surveys (and information collected from state agencies) but is never able to collect 

comprehensive data and has to rely on extrapolations. TWDB is focused on water use and does 

similar regular surveys but with limited success. Some companies consistently and voluntarily 

report their water use, whereas others are less straightforward. Regional Water Planning Groups 

(RWPGs) (Figure 8) know the reality of their region but are rarely focused on mining, which is 

typically a small fraction of total water use, and often relies on TWDB figures. Similar to 

previous USGS and TWDB reports, we elected not to link the data we present later in this report 

to individual facilities. 

We used a two-pronged approach to assess aggregate water use: 

(1) When water-use figures are known for a given county, they are used. 

(2) For counties with only partial or no information on water use, we rely on estimated 

production combined with an estimated water-use coefficient. Water-use coefficients are 

computed from (1) a BEG survey and (2) generic coefficients from previous work. 

Estimated production at the county level is computed from local population and number 

of facilities. A higher number of facilities in a county relative to the population suggest a 

particularly favorable geology and a higher production per facility. 

These detailed steps were used for crushed-stone water use: 

(1) Derive statistics from BEG survey results. 

(2) Compare with TWDB WUS and USGS county-level mining-water use. 
29 

(3) Compare with generic aggregate water use. 

(4) Determine counties with crushed-stone facilities. Sort into two types: (a) of primary 

importance and listed on the NSSGA/USGS database, potentially deserving markets up to 

50 miles away and lasting to the end period of this study and beyond or (b) of secondary 

importance and listed only on the MSHA database with only local subcounty impact and 

likely ephemeral in nature (a few years). 

(5) Distribute crushed-stone production throughout the state using facility list from 

NSSGA/USGS; county-level production is anchored by the few counties for which 

production is known and scaled from the state production according to local population 

(more details on the mechanics of this in the methodology section for future water use—

Section 3.4). Counties with facilities listed in the NSSGA/USGS directory are assigned 

the population of that county and that of surrounding counties; counties with facilities 

solely in the MSHA database are not included (Figure 13). 

(6) Apply average/generic water use for those counties with no information. Given the large 

range in water-use coefficients, although likely relatively accurate at the state level, 

estimated county-level figures may diverge from actual figures if their facilities are more 

water conscious or less efficient than those of the average facility. USGS uses 

employment data from MSHA to estimate size of facility. We confirmed the size of some 

facilities, especially those with seemingly high water use, through Google Earth. 

Combined with other sources of information, Google Earth could be a good tool for 

estimating more accurate water use, especially through time, using the historical imager 

option. Excavation changes through time would help put bounds on production, and pond 

size and other water features would suggest water use. 

Water use in the sand and gravel category follows the same approach except that all production 

is assumed to be consumed locally within the county; that is, population of surrounding counties 

does not figure into the calculation. Again, note that we did not include cement or concrete 

facilities (as far as we can tell by the description given in the databases) in this study. They are 

part of manufacturing, even if they have quarry operations onsite. 

3.3.4 Other Mined Substances 

Methodology for other mined substances is done on an ad hoc basis but mostly it is done by 

collecting information from TWDB WUS. We also collected direct information from some 

uranium and clay facilities with the survey through TMRA (Appendix D). Specific details are 

given in the current water-use section (Section 4.5). We included industrial sand operations in 

the “other” category, although they bear many similarities to the aggregate industry, although the 

much higher water use coefficient sets them apart. 

3.3.5 Groundwater–Surface Water Split 

Accessing the source of water used is difficult in most cases. Water use is well documented for 

some mining-industry segments, such as coal mining, but it varies widely for oil and gas and 

aggregate-mining segments. Historically the trend in the state has been to rely more and more on 

surface water. The best source of information is direct surveys, but even knowledge of current 

sources may have little predictive power. For example, in Louisiana, Haynesville shale frac 

water initially from the Carrizo-Wilcox aquifer (Hanson, 2009) has switched to alluvial aquifers 

and, mostly, surface water (Red River) after suggestions by the Louisiana Department of Natural 
30 

Resources. And treated wastewater from a paper mill in northern Louisiana has recently been 

added to the mix of water sources used in the play. 

We provided information about the groundwater– surface water split as it became available 

during the data-collection process but did not try to generalize to the whole mining industry. 

3.4 Methodology: Future Water Use 

What are the substances currently being mined? How much longer will they be mined? Do any 

of the substances mined in the past have a credible chance of being exploited again, both in terms 

of substance and location? What are the new substances that could be mined in the future? Some 

of these questions are not easy to answer, but overall the main driver of water use in the mining 

sector is mostly (1) population growth and (2) economic development, especially concomitant 

energy demand nationally. Population growth relates to resources consumed within the state 

(aggregates, coal), whereas economic development impacts all substances, including those 

mostly exported out of the state either in their raw form or transformed. A project such as this 

includes many levels and types of uncertainties. A tentative comprehensive sampling despite the 

appearance of completeness can overlook several facilities, although not any one large facility. 

Operators can make honest mistakes when reporting information or include water-use categories 

that should not be included. Even more uncertain is extrapolating for long periods of time from a 

short period of time of a few years, such as for shale gas and oil. Long-term energy projections 

do not have a very good track record (Figure 14, Figure 15). Figure 14 provides an example of 

the difficulty of making projections. A natural tendency is to extrapolate trends; projection of 

U.S. gas consumption made in 1970 is a simple extrapolation of the strong trend of the previous 

year. Projection for 1972 follows the same model with a smaller growth rate. Year 1974 

projection continues to extrapolate, although one of the marking events, energy-wise, of the 

second half of the 20th century occurred in 1973. Figure 15 demonstrates that, even in the midst 

of a known energy-paradigm change, shale-gas production (and, by extension, water use) was 

consistently underestimated. Hindsight or postaudits are a great way to improve the reliability of 

such scenarios. BEG published an analysis of water use in the Barnett Shale using data from 

2005 (Nicot and Potter, 2007), and a comparison to actual water use is presented in Appendix B. 

The overall conclusion is that projections match recent data but only because of the recent 

economic slowdown. 

We debated having deterministic vs. a range of projections (for example, high, medium, low) and 

concluded that we would focus on a single best-guess scenario, with the understanding that 

uncertainty increases with annual horizon. Although working on a 50-year horizon helps in an 

understanding of heavy trends, we tried to focus on the next 10 years, the timeframe in which 

this work could have the most impact. Another concern is higher-frequency changes, again 

mostly applicable to shale gas, such as the current economic slowdown. A long-term decadelevel horizon makes it easier to ignore these high-frequency cycles and to focus on long-term 

trends. The downside of such an approach is that projections may not be correct in the rate of 

change of water use from one year to the next but they may be more accurate cumulatively. 

Post-mortem analyses of long-term projections show that they often deviate from actual figures 

because of unpredicted events. A case in point is the rapid development of water-intensive gas 

production from gas shales. Such events are by nature unpredictable and, although we can 

develop scenarios, their multiplicity quickly becomes unmanageable: what year does it begin, 

how fast does it develop, is it permanent or transitory, what is the magnitude of impact, etc.? 
31 

Including the uncertainty of abrupt changes in water use, projections would render them 

meaningless, so our approach has been to assume that current trends will continue. In contrast 

to abrupt changes, long-term shifts in water use, particularly in the energy sector, can be better 

tackled. As discussed previously, a large fraction of the mining output is related to energy 

production (oil, gas, coal). King et al. (2008) discussed future directions of the energy sector in 

Texas as it relates to water use. For example, development of nuclear power would merely 

transfer water use from the mining category to the power-generation category, as well as move it 

to different counties and regions, as would a shift from coal to natural gas. This project does try 

to predict the unpredictable but always assumes a slow rate of change, such as gas slowly 

overtaking coal as the major electricity-generating fuel in Texas or the rise and decline of gas 

production. However, most gas is exported out of state and, because of a projected overall 

increase in energy consumption, is not denting water use by the coal industry. 

Next, we discuss the relationship between three of the major water users in the mining industry: 

oil vs. gas and gas vs. coal. Oil in terms of energy has always been at a premium relative to gas 

(for example, Kaiser and Yu, 2010), being sold at a higher price for the same energy content. 

Natural gas, being a gas at surface conditions, requires more advanced technologies for it to be 

transported to areas of consumption. The year 2010 has seen a rush toward the oil window, 

thought to be more profitable, in some so-called gas shales but more accurately described as 

liquid-rich shales, such as the northern confines of the Barnett Shale or the western section of the 

Eagle Ford. Such a trend of operators focusing on oil rather than gas, if it persists, will impact 

water use at the county level, if not at the state level. This focus on oil is analogous to a smallerscale shift in oil and gas operators’ thinking. In this project, we assigned a slightly higher weight 

to these oil window/combo counties, but on the whole we consider this oil focus a short-term 

deviation. Another example concerns some gas plays very much in the news 2 or 3 years ago, 

such as the Pearsall Formation in South Texas or formations of the Palo Duro Basin in the Texas 

Panhandle, that have since disappeared from the radar, while others such as the Haynesville and, 

even more so, the Eagle Ford, have exploded in terms of activity. In this ever-changing 

environment, it is challenging to predict where the gas industry will be active 5 years from now. 

Another single event with possible repercussions, particularly in terms of legislation, is the 

Macondo well. On April 20, 2010, a grave accident occurred in the deep offshore Gulf of 

Mexico. Responding to a likely increase in regulatory scrutiny and, therefore, increased cost, 

many operators, particularly independents, may redirect their efforts onshore, especially to 

unconventional oil plays (the Eagle Ford, Barnett Shale oil windows). 

Coal and natural gas are used mostly for energy production. Both industries are optimistic about 

their futures. The Texas energy portfolio consists of mostly coal, nuclear, natural gas, and others, 

including oil and renewables. King et al. (2008), looking at energy use in Texas by 2060, 

assumed an annual electricity growth rate of 1.8% in business-as-usual scenarios. These workers 

also investigated a low-energy-usage case. They described four scenarios combining high/low 

natural gas prices and implementation (or not) of carbon capture and storage (CCS). In both 

high-natural-gas-price cases, coal use expands and natural gas use stays steady. However, if 

natural gas price stays low, coal share decreases even if overall energy consumption decreases. 

If, in addition, CCS is made mandatory through a hypothetical cap-and-trade or carbon-tax 

legislation (to deal with climate change, the advantage of natural gas relative to coal is that it 

releases less CO2 per unit energy than coal), coal share in the energy mix decreases even faster. 

However, EIA (2010, p. 79) suggested that lignite production may increase in Texas. Coal mined 

in Texas is always used locally (mouth-of-mine coal-fired power plants), but a significant 
32 

fraction of the gas goes into the general market and is exported out of state. For example, 45+% 

of electricity consumed in the state is produced by natural gas, for a total of ~200,000,000 MWh 

(equivalent to 0.68×109

 MMBTU, with 1 MMBTU = 0.2931 MWh). In 2009, natural gas 

production in the state was 7.66×109 Mcf (equivalent to 7.66×109 MMBTU, with 1 Mcf =1 

MMBTU). Major growth in other parts of the world may boost the gas industry for export, and 

development of LNG terminals in Texas or the glut of the gas commodity may keep the prices 

too low for its development to have a major impact on water use (averaged over decades). An 

authoritative recent study on natural gas (MIT, 2010) suggests that use of natural gas will expand 

and an earlier study by the same organization (MIT, 2007) acknowledges that coal use is likely 

to increase overall even if its relative share in the energy mix decreases. 

To develop our own understanding of those issues, we collected material from Washingtonbased think tanks, attended specialized conferences (Nicot, 2009a; Nicot and Ritter, 2009; Nicot 

et al., 2009; Hebel et al., 2010; Nicot and McGlynn, 2010; Ritter et al., 2010) and discussed the 

matter with experts. Overall, we decided to use a middle-of-the-road scenario, and because of the 

mixed signals received from different entities about coal consumption, either up or down, we 

assumed that it stays at its current level with no sharp increase or decrease in absolute figures 

(but decreasing in the state energy portfolio), in agreement with discussions with coal producers. 

Texas gas production is controlled by external factors independently of population growth, 

whereas aggregate production is controlled entirely by population growth. 

Judgment on future water use of nonfuel substances is either more straightforward (aggregate) or 

less consequential in terms of total water use. Information about future water use was determined 

not only through direct results of forward-looking survey questions and general understanding of 

the commodity, but also by scouring Regional Water Planning Group (RWPG) reports. Texas is 

composed of 16 RWPGs, each of which is charged by law to project water needs and water 

sources for its own area and to submit information for incorporation into the state water plan. 

Water Plans (TWDB, 2002, 2007; http://www.twdb.state.tx.us/wrpi/data/proj/demandproj.htm

for year 2007) present projections but in general are aggregated at the regional planning level. 

3.4.1.1 Gas Shales 

The general philosophy of the approach is top-down, that is, distributing estimated overall oil 

and gas production, as well as water use, across counties, rather than a bottom-up approach, in 

which a time-consuming and hard-to-get detailed compilation of fields, formations, and local 

input would be aggregated to deliver county-level figures. This section is untitled gas shales but 

includes the oil window generally located updip of gas shale proper (liquid-rich shales). As far as 

water use is concerned, well stimulation does not seem to be approached very differently. 

Quantitative approaches to future water use in shales fall into two broad categories: (1) 

production-based approach and (2) resource-based approach. The latter was applied to the 

Barnett Shale by Nicot and Potter (2007) and Nicot (2009a). In this report, we followed both 

approaches simultaneously, making sure results were consistent. 

A production-based approach follows five steps, which are further described later in this 

section: 

(1) Determine with the help of BEG experts (or gather from the literature) the total amount 

of gas/oil contained in the shale, as well as the recoverable fraction and the estimated 

annual production level. This step also involves recognizing the boundaries of the play. 
33 

(2) Decide on (or gather from the literature) the average Estimated Ultimate Recovery (EUR) 

for a single well. 

(3) Compute the total number of wells needed. 

(4) Apply the average water use per well (computed from historical data, we have a good 

handle on water use of many individual wells across many gas plays in the state, as 

detailed in Section 4.1), possibly corrected by factors accounting for technology advances 

and increased recycling and, perhaps, additional rounds of well stimulation. Well count 

for the first few years is estimated, given rig availability, which after a few years 

becomes irrelevant because the service industry will respond to needs by constructing 

them. 

(5) Distribute through time (expected life of the play) and space (county level) as a function 

of prospectivity and other parameters. This step is the most uncertain and open to 

interpretation. 

A resource-based approach follows four steps: 

(1) Gather historical data in terms of average well-water use and average well spacing. 

(2) Estimate ultimate well density across the play; it is a function of factors, such as 

geological prospectivity (for example, within play core or not, shale thickness) and 

cultural features (urban/rural). In this step, ultimate boundaries of the play are identified. 

(3) Compute total number of wells needed. 

(4) Distribute through time and space, constrained by the assumed number of drilling rigs 

available (see earlier comment). 

As an entity whose strength is applied geology, BEG had the opportunity to develop its own 

assessment of shale-gas reserves in Texas. Gas accumulations can be biogenic, in which 

microbes biodegrade organic matter to release methane, or, as in all Texas shale-gas plays, 

thermogenic. Thermogenic gas is produced by the natural cracking of complex organic 

molecules into oil and gas, owing to an increase in pressure and temperature, as well as sufficient 

time at required depths. The deeper the conditions (without some limits), the more advanced the 

cracking of the organic matter, whose ultimate fate is methane. Some shale plays contain only 

gas (if they stay in the gas window for long enough)—an example is the Haynesville Shale—

others contain both oil and gas either at the same location (a well will produce both oil and gas) 

in a so-called combo play (for example, the northern section of the Barnett) or spatially distinct 

oil and gas zones with a mixed transition combo zone (for example, the Eagle Ford Formation). 

There is a relationship between total organic content (TOC) and potential gas content. Vitrinite 

reflectance (VR) is a measure of the maturity of the evolved organic matter/kerogen: the higher 

its value the more likely it is to be in the dry-gas window (VR>~1.5–2). For VR values ranging 

between 1 and 1.5, the shale is likely to be in the wet gas window. Below a value of 1, oil is 

produced, whereas if VR<0.6, the sediment is immature, and no commercial accumulations are 

likely to be found. Combining information about formation thickness, TOC, VR, and a few 

exploratory wells, specialists can infer gas resources. The core area of a play is subjectively 

defined as the area where the most favorable combination of thickness, TOC, and VR exists. The 

core areas of the Barnett and of the Texas portion of the Haynesville consists of each of four 

counties, whereas they have an additional 20+ whole or not counties and ~10 counties 

considered noncore, respectively. Core counties have not been defined for other shale-gas plays, 
34 

including the Eagle Ford Formation, yet. Other known important factors are not used in this 

study; for example, an emerging model (S. Ruppel, BEG, personal communication, 2010) 

suggests that margins of shale plays are more prospective because of the influx of carbonate and 

other clasts with the right combination of organic matter and detrital material, making the setting 

more favorable. 

We decided early on to rely as much as possible on published information rather than developing 

our own estimates. Nevertheless, knowledge of these parameters helps in determining the 

prospectivity of an area (county in this case), that is, its attractiveness to operators, which is 

obviously linked to water use as well as the boundaries of the play. Geological maps and 

previous drilling and production activity help in constraining the final spatial extent of the play. 

In practice, prospectivity (maturity, core area) is a positive number "1. Each county within a play 

is assigned a prospectivity factor (generally 1, 0.75, 0.5, or 0.3). This assignment was done in a 

purely ad hoc manner and in a more cursory manner than in Nicot and Potter (2007), as this 

parameter is softer than, for example, the play footprint and, owing to a lack of information, 

includes some guess work relative to where the industry is headed. 

Many gas-production projections are published at the national level (EIA, USGS, PGC) 

aggregated from individual plays and sometimes extrapolated to prospective shale plays. 

Information about recoverable reserves of individual shale plays (in general, ~30% of OGIP or 

OOIP) are relatively easy to collect, but unfortunately there is a lack of consistency between the 

different figures we can gather, mostly because the methodology used to arrive at those figures is 

not explained in most cases. In the Future Water Use section (Section 5.1), we list figures for all 

Texas shale plays and explain the choice of the value we used. Another difficulty relates to the 

fine granularity (county level) we attempt to meet. Projections made at the national level perhaps 

end up being more accurate because of the low granularity of the system (many oil and gas 

plays), as opposed to a single state even if it is large because only a few shale plays exist. For 

example, Appendix B shows that careful work does not necessarily generate accurate predictions 

at the county level, even though they might be at the multicounty or regional/play level. We 

expect the same observation to be truer in this higher level study. Results at the county level may 

be off by a factor or 2 or 3, especially when the time component is added. 

Later we focus on the production-based approach because the resource-based approach was 

already described by Nicot (2009a) and Nicot and Potter (2007). Some published EUR values 

seem to be problematic. Individual-well EUR can be estimated at 0.5 to 3 Bcf, maybe up to 10 

Bcf, in highly profitable wells. Most EUR is derived from limited data, not necessarily in terms 

of number of wells but in terms of time frame (Figure 16). Reported average EUR values most 

likely reflect good wells drilled in the core area of a play and might be inflated. Water use 

computed from number of wells based on EUR and total recoverable gas only is therefore highly 

uncertain because both can vary substantially. For example, the commonly found EUR value for 

Barnett wells of 3 Bcf, combined with an assumed <60 Tcf of recoverable gas, yields <20,000 

wells. Clearly, even taking into account that many of these wells are vertical wells with a lower 

EUR, more wells will be drilled in the Barnett. The very first well drilled in the core area of the 

Barnett in 1982 has produced 1.7 Bcf so far (PBSN, Nov.1, 2010). 

Therefore, in the Barnett, either recoverable reserves are underestimated or average EUR is 

overestimated; that is, production drops faster than currently projected. This report puts more 

weight on the latter explanation, but without negating the possibility of the former. Actually, 

there are voices (Shook in NGW, 2009) advocating that shale gas will not carry all the promises 
35 

put forward by operators. For example, SPEE-Anonymous (2010), Berman (2009), and Wright 

(2008) suggested that decline curves were too optimistic, but they seem to be in the minority. 

Their approach has been strongly contested by the gas industry in the literature, as well as in the 

field, as majors (ExxonMobil, Shell, Total, ENI, Statoil, BP) started investing in shale gas. It 

seems that with a diversified gas-well portfolio and a statistically sufficiently high number of 

wells, good producers more than make up for more numerous low-performing, uneconomical 

wells and render the whole operation profitable for most gas operators. In other words, the 

viability of a play is determined by its top producers, perhaps the top 10th or 20th percentiles. 

Note that from a water use standpoint, however, uneconomical wells and good producers 

consume the same amount of water during fracing. Low-rated wells may even be fraced a second 

time shortly after the initial frac job in an effort to improve gas production. 

A typical play containing 100 Tcf of gas in place, 30% of which is recoverable, translates into 

15,000 wells at 2 Bcf EUR, on average. Distributing projected production/water use through time 

is difficult but is the essence of this project. We relied on several sources in addition to informal 

information, but particularly Mohr and Evans (2010) and Mohr (2010, Chapter 6), who 

inventoried all relevant gas shales at the time and summarized available information on projected 

gas production for the Barnett and Haynesville Shales. They also provided a peak year for gas 

production (best guess of 2015 and 2031, respectively). Similarly we assigned a peak year for 

each gas-shale play, which is clearly highly uncertain. Most publications assign a peak year for 

gas production, which typically comes after the peak year for initial well completion. However, 

translation from gas production to water use requires the knowledge of the EUR and the details 

of the production decline curve. It has been commonly observed that production decreases from 

an “initial production” (IP) (Figure 16). Given the relatively steep decline from IP, new wells 

must be drilled to sustain production. Information received from informal discussion suggests 

that 3000+ new wells a year are needed to sustain production at current 2010 production rates. 

A commonly circulated IP value in the Barnett is 5 MMcf/d. Overpressured plays, such as the 

Haynesville, have generally a higher IP—reported value can be as high as 8 or even 20 MMcf/d. 

More generally, individual gas-well performance is characterized by their IP, how fast they 

decline from the IP (decline curve), and their cumulative potential (EUR). There is some 

evidence that pushing production to its max IP is detrimental to the EUR, so most operators 

throttle production to a rate somewhat lower than the possible maximum. Doing so also makes 

sense economically when gas prices are depressed. A large body of literature deals with decline 

curves, which have been a topic of considerable interest in the petroleum industry because they 

help forecast future performance and production. Two broad families of these mostly empirical 

curves exist: exponential and hyperbolic (see for example, the classic Arps, 1945; Economides et 

al., 1994; Ilk et al., 2008; Lee and Sidle, 2010; Valko and Lee, 2010). The former curve model is 

used when the decline is linear on a semilog plot against time. We tentatively used a simplified 

version of the Arps decline-curve equations for hyperbolic decline, which is typically faster than 

exponential decline. 

q q " # Dt % i exp $ (exponential decline) Equation 1a 

" # 1 0 1 1/ % ' & & $ q q Dbt b b

i (hyperbolic decline) Equation 1b 

Although the parameter b should be & 1 to meet model assumptions, it is often set to values >1 

for tight formations (Ilk et al., 2009). This parameter is difficult to assess with the limited 
36 

information available early in the history of a well. Assuming an average well EUR, a decline 

curve, and a given life, we can attribute a fraction of the EUR to each year. After some trial and 

error, we were able to match gas production from Mohr and Evans (2010), assuming an average 

EUR substantially lower that the most-cited core ones and with input from the resource-based 

approach. Note that the chosen production model is only one among many, although a middle-ofthe-road, defensible one. Exploring all possible production outcomes would entail much larger 

efforts than available for this study. The fraction produced during the first year is ~45% and 

~25% for what we defined as an overpressured Haynesville type and a normally pressured 

Barnett type, respectively (Figure 17), over the 30 years of the producing life of a well. The 

curves displayed in Figure 17 show a drop of 75% and 60% between average production in years 

1 and 2 in Haynesville and Barnett types, respectively. Figures are consistent with those 

presented in Jarvie (2009) that document decrease in the 60–80% range during the first year of 

production for various shale plays in Texas and elsewhere. Note that the decline curve is just one 

component in estimating water use, and, although it obviously has a large impact on the 

production numbers, water use is less sensitive to it, especially when the production-based 

approach is compared with the resource-based approach. 

Spatial coverage density is an important step in the resource-based approach. Figure 19 and 

Figure 20 display examples of thorough coverage from multiwell pads. Horizontal-well laterals 

are all oriented in the approximate direction that is perpendicular to minimum local horizontal 

stress. Nicot (2009a) and Nicot and Potter (2007) used a range of 800– 2000 ft. Generally 

speaking, 16 40-acre vertical wells (16 × 1.7424×106

 ft2 = 1 square mile) translates into seven 

4000-ft-long laterals with 1000-ft spacing that could be all drilled from the same pad with a 

much larger recovery. There seems to be a relationship between lateral length and lateral spacing 

(Figure 18). 

A limiting factor controlling the number of wells drilled every year in a play is the number of 

drilling rigs available. Figure 22 illustrates a time snapshot in the distribution of drilling rigs in 

Texas in June 2010. Rigs typically specialize as gas or oil rigs and are binned as a function of the 

maximum depth they can reach and the type of well they can drill (horizontal vs. vertical), but 

this level of detail was not included in the study. We estimate that it takes 3 to 6 weeks to drill a 

vertical section and a lateral in the Barnett and Haynesville, respectively. An average spud-torelease time in the Haynesville was 44 days in early 2010 (LRNL, 2010). Nicot and Potter (2007) 

estimated an average spud-to-spud time of 1 month in the Barnett, which is currently down to ~3 

weeks. Figure 21 demonstrates the high variability in the number of active drilling rigs. Rigs 

travel from one play to the next and across state lines, depending on demand and on the 

perceived or actual potential of a play. Figure 21 shows a rig count increasing at a rate of ~100 

rigs/yr between Spring 2002 and Fall 2008, then a sharp drop, and a sharper increase rate at ~375 

rigs/yr between June 2009 and June 2010. This steep rate is likely due to rigs mothballed near the 

new drilling sites and being put back in use quickly. As of December 2010, the Barnett Shale 

play had ~80 rigs, and that number has varied little since early 2009 (multiple issues of PBSN). 

Most of the previous year, in 2008, the rig count was at ~180 active rigs. The number of frac jobs 

(that is, water use) is clearly related to the rig count. Nicot and Potter (2007) underestimated the 

ability of operators to bring in more rigs to the state. Emergence of more efficient rigs will 

shorten the rotation time between drilling sites and increase the number of boreholes that a single 

rig can drill in a year. But again, showing the difficulty of making projections, the industry may 

run out of trained crews to man the rigs. 
37 

Details on recycling, refracing, and other approaches are given in Section 5.1.2. We did not try to 

resolve the surface water– groundwater split for future decades. 

3.4.1.2 Tight Formations 

Tight gas (for example, the Cotton Valley Formation in East Texas) or other tight formations 

containing oil (for example, the Wolfberry play in the Permian Basin) are also subject to 

hydraulic fracturing. The main difference between them and gas shales, from a practical 

standpoint, is that (1) these tight formations are conventional resources in the sense that they 

occur in a discontinuous manner and (2) they are not new plays and have been producing gas/oil 

for years or even decades for the most part. We applied the same approach to compute future 

water use, as was employed for the gas-shale category. The approach is particularly similar to 

that used for the Barnett shale, which already has significant production. At the county or field 

level, we examined the burn rate of the reserves as well as the remaining reserves. Coleman 

(2009) presented a recent historical overview of gas production from tight sandstones. 

3.4.1.3 Drilling and Waterflooding of Oil and Gas Reservoirs 

Future water use for drilling was estimated at the state level only by assuming water use for 

shale-gas wells as provided by the literature for several plays (Section 5.2.2) and assuming an 

average value for the remainder of the wells. The number of wells to be drilled in the future was 

computed from (1) the oil subcategory for which we used recent work by Galusky (2010) in the 

Permian Basin; we then applied a multiplier to account for oil production outside of the Permian 

Basin; and (2) the gas subcategory, for which we used results from the production-based 

approach for shale and tight-gas plays, and to which we, in turn, applied a multiplier to account 

for conventional gas production. 

Water use for secondary and tertiary oil production is less dependent on the number of rigs 

because most of the consumption occurs after drilling and during pressure maintenance or 

enhanced-recovery operations. We assumed that waterflooding activities occur mostly in the 

Permian Basin, which is also the world center of CO2 EOR (a WAG process is typically used, in 

which water is injected behind slugs of CO2). Estimates in this category are obtained through a 

combination of historical data, survey results, and knowledge of the industry. 

3.4.1.4 Coal

Energy makeup of the state still relies heavily on coal-fired power plants (although some of the 

coal is imported from out of state), with nuclear energy as a distant second. The complement 

comes partly from natural gas and oil. As discussed earlier, we assumed a business-as-usual 

scenario for the coal industry and accepted figures provided by the comprehensive survey of all 

operators in the state. The main uncertainty resides in the possibility that the industry will start 

relying on coal imported from western states to feed the coal-fired power plants instead of 

relying on local lignite resources. Another uncertainty is the possibility of having most 

depressurization water volumes captured for municipal use or other beneficial use (for example, 

fracing), in which case mining water use may be different but not the total water use. Such a 

development is not accounted for in this study. 

3.4.1.5 Aggregates

If some mining activities such as oil and gas are independent of the state population because their 

products are not necessarily consumed in the state, others, such as aggregates and lignite coal, 

which have high transportation costs, are consumed mostly locally and depend more strongly on 
38 

the population level in the state, nearby counties, and economic activity. Future aggregate 

production (and concomitant future water use) is correlated with population growth. Population 

of the state is predicted to grow by 20 million people, from ~25 million in 2010 to ~45 million in 

2060 (both are estimates). We used TWDB population projections, which are slightly different 

from those of the U.S. Census Bureau, although differences are well below the level of 

uncertainty brought about by other parameters. 

To estimate future aggregate production we relied on extrapolation from historical data and 

noted that aggregate production is coupled to absolute population level, but also to its derivative 

through time (population growth). Numerical details of the analysis are given in Section 5.4 

(future water use in the aggregate category), but we based extrapolation of production and 

population on their changes in the past 20 years. In 2008, the amount of crushed stone produced 

per capita was ~153 Mt/ 24,000,000 people; that is, ~ 6.5 ton/capita/yr. During the same 1-year 

period, population growth was ~0.5 million people, that is, ~310 ton/capita growth/yr. A similar 

analysis yields ~4 ton/capita/yr and ~200 ton/capita growth/yr for the sand and gravel category. 

Extrapolating solely from gross population numbers seems unrealistic. Norvell (2009) used 

historical data and determined that over a 20-year span (1982–2003), aggregate production was 

best predicted by a combination of total population and the state gross product (GDP) related to 

construction. Population and state GDP were both approximately equally weighted in terms of 

coefficients, but construction state GDP in billions is about twice the population in millions, so 

its weight is, in essence, higher. The report states “coefficients indicate that on average as 

population grows by 1000 people, aggregate output in Texas rises by 4,800 tons (i.e., about 4.8 

tons per person), and every $1 million increase in gross product for the construction industry 

results in an additional 5,760 tons of aggregate extracted.” The figure of 4.8 t/capita/yr is 

somewhat lower than the average of our two figures, although plainly consistent with them. 

Given the time and budget constraints to develop this report, we assume that population growth 

is somewhat equivalent to the economic output variable of Norvell (2009) and other economic 

analyses. As a whole, additional people will need houses, highways, and other facilities at a 

higher rate than people already living, the state supporting the assumption that population growth 

has a greater impact on aggregate consumption than the population parameter itself: 

Aggr.Prod. = 2/3×Pop.×Rate1 + 1/3×Pop.Growth×Rate2 Equation 2 

The population-growth component stays at a stable absolute level because growth rate itself stays 

stable, whereas the population as a whole component keeps increasing in absolute value and as a 

fraction of the total. 

Once aggregate production at the state level has been determined, we could apply water-use 

coefficients already gathered in the previous phase of the work to obtain aggregate water use at 

the state level. Difficulties arose when we tried to distribute state-level water use to individual 

counties. In order to limit distortions due to the impact of artificial administrative boundaries (for 

instance, large growth in a county next to that of the aggregate facility, as we did for current 

crushed-stone water use), we used a simplified radius of influence technique (county of interest 

and neighboring counties) to apportion water use, whereas sand and gravel production is 

assumed consumed within the county in which it is produced. We also assumed that aggregate 

production and consumption strictly stay within state lines. Counties on state lines do not take 

into account growth on the other side of the state line or the possibility of importing aggregate 

from out of state. Future water used for those few counties for which we have reasonable 

knowledge of production and water use was extrapolated from current use and county population 
39 

projection according to Eq. 2, with the caveat presented later for urban counties. The remainder 

of state-level water use was distributed among the remaining counties. Lack of data on individual 

facilities compelled us to use this approach involving averages that may not necessarily give 

accurate results at the county level. This lack of data is made worse by the high variability in 

reported water use. If need be, when new sources of information update average water use, the 

figures given in this report can simply be scaled by a more accurate value. 

Because we based our projections on population growth, aggregate use will also include 

aggregate recycling (presumably classified in the manufacturing category) and export/import 

balance from neighboring states. We assumed that both are small and will stay small. Some 

aggregate recycling has been estimated at 5% of total consumption in 1998 across the nation 

(USGS, 2000). More recent figures put the amount at 1.7 million tons (USGS, 2010) in Texas 

(<1%). In addition, we did not assume more water recycling than is currently done. Nor did we 

include reclamation and irrigation water use in aggregate water use (at least not explicitly). 

We also assumed that the same counties will keep operating the same facilities or their 

extensions, particularly crushed-stone facilities, because of the difficulty to gain acceptance from 

the public of new large facilities (Robinson and Brown, 2002, p. 3). The main exception 

concerns urban counties. These authors stated that “although development and maintenance of 

infrastructure in metropolitan areas require a continuing supply of aggregate, aggregate 

production rates begin to fall in counties when the population density reaches approximately 

1000 people per square mile. At population densities of about 2000 people per square mile, 

production of aggregate in many counties may diminish significantly.” One of the problems of 

linking population growth and aggregate output at the county level is that counties with high 

growth are likely to crowd out mining operations and rely on neighboring counties for their 

aggregate needs. This scenario is assumed true for Travis County in the crushed-stone category 

and for Bexar, Dallas, Harris, Tarrant, and Travis Counties in the sand and gravel category. 

3.4.1.6 Other Mineral Commodities 

As was done in the Current Water-Use Methodology Section, future water-use methodology for 

other mined substances is done on an ad hoc basis. Specific details are given in the Current 

Water Use section (Section 4.5). 
40 

Source: TWDB - http://www.twdb.state.tx.us/mapping/maps/pdf/sb1_groups_8×11.pdf 

Figure 8. Map of Regional Water Planning Groups 
41 

Source: RRC website http://www.rrc.state.tx.us/forms/maps/ogdivisionmap.php 

Figure 9. State map of RRC districts 
42 

Source: TWDB (GIS coverage of GCDs) and TCEQ SWAP 

Figure 10. GCDs and active and inactive mine locations in the TCEQ SWAP database 
43 

Source: Devon Energy website 

Figure 11. Trap vs. resource play 

y = 0.8944x + 515.5

R2

 = 0.6115

y = 1.0551x

R2

 = 0.5901

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000

Lateral Length (Well Depth)

Lateral Length (Surface and BH coord.)

5,456 Barnett Wells

Note: equation for best fit and fit through the origin are shown. Only those points for which both values are available 

are shown. Plot also provides estimate of typical and maximum lateral length. 

Figure 12. Comparison of the two approaches to compute lateral length 

Barnett AllPlay JP2LL.xls
44 

Figure 13. Map illustrating population-count mechanism for crushed-stone facilities. 

Also showing Potter County and relevant surrounding counties; Bell County and surrounding 

counties; Harris County count with no NSSGA facility does not include surrounding counties. 

Potter County 

Harris County 

Bell County 
45 

Source: Schanz (1977) and EIA website (gas consumption) 

Note: figure superimposes plot from Schanz (1977) showing actual data until 1974 and projections done in 1970, 

1972, and 1974 and actual data (red line) until 2009 downloaded from EIA website. 

Figure 14. Making long-term projections is an art—part 1 

Source: presentation by R. Smead, Navigant 

http://www.naseo.org/events/winterfuels/2010/Rick%20Smead%20Presentation.pdf 

Figure 15. Making long-term projections is an art— part 2 

EIA=N9140US2a+Schanz.xls 

1970 

projection 

1972 projection 

1974 projection

Actual 
46 

Source: modified from Vassilellis et al. (2010, Fig. 4) 

Figure 16. Multiple EUR projections extrapolated from limited early data for an Eagle Ford well 

0.0

0.1

0.2

0.3

0.4

0.5

Year

1

Year 3

Year 5

Year 7

Year 9

Year

11

Year

13

Year

15

Year

17

Year

19

Year 21

Year 23

Year 25

Year 27

Year 29

Fraction of EUR

0.001

0.01

0.1

1

Haynesville Type (linear) Barnett Type (linear)

Haynesville Type (log) Barnett Type (log)

Figure 17. Decline curves assumed in this study (production-based approach) 

IP&EURH Barnett+HaynesvilleTypes.xls
47 

Source: Chong et al. (2010) modified from Cipolla et al. (2008) 

Figure 18. Lateral length vs. estimated impacted width. 

Source Courtesy of DrillingInfo 

Figure 19. Example of Barnett Shale density of laterals (Dallas-Tarrant county line) 

Note: map displays an 

average drainage area 

of ~80 acres / well 

(laterals not pads) 

where laterals are 

dense. 
48 

Source: Courtesy EOG Resources— Presentation to analysts, January 2008 

Note: 16 completed wells (red trace) and 27 to be completed (planned in 2008) 

Figure 20. Example of Barnett Shale density of laterals (Johnson County) 

0

500

1,000

1,500

2,000

1990 1995 2000 2005 2010

Calendar Year

Active Rig Count (two-week average)

Texas onshore

U.S. onshore

~100 rigs/yr

~375 rigs/yr

Source: Baker-Hughes website 

Figure 21. Active rig count in the U.S. and Texas from 1990 to current 

US_Rig_Report_062510_JP.xls 
49 

 (a) 

 (b) 

Source: Baker-Hughes website 

Figure 22. Rig count as of June 25, 2010. (a) Red and blue dots denote gas and oil rigs, 

respectively; (b) red, blue, and green diamonds denote horizontal, vertical, and directional rigs. 

51 

4 Current Water Use 

We chose the year 2008 as representative of current use for two reasons: (1) this work started in 

2009, and not all the 2009 data were yet available, and (2) 2009 is not a representative year 

because of the economic slowdown; 2008 is the last year with water use more representative of 

what might occur in the future and is thus more appropriate as a starting point for projections. 

4.1 Shales and Tight Sands 

The literature on gas shales and related water use is abundant (for example, Arthur et al., 2009; 

U.S. DOE, 2009) and will not be reprised herein. Several reports also detail current practices in 

well-pad construction, drilling, completion, and well stimulation for fraced wells. (Veil, 2007; 

U.S. DOE, 2009; Veil, 2010). 

4.1.1 Location and Extent 

Section 4.1 provides an overview of the different shale and tight-sand plays in Texas. Present in 

all corners of the state (Figure 23, Figure 24), they include the Barnett Shale, Haynesville and 

Bossier Shales, Eagle Ford Shale, Barnett Shale in West Texas, and Woodford Shale, as well as 

liquid-rich plays such as the Granite Wash in the Anadarko Basin and the Wolfberry in the 

Permian Basin, the Bossier, Travis Peak and Cotton Valley Tight Sands in East Texas, and 

multiple formations in South Texas. U.S. DOE published a primer (U.S. DOE, 2009) 

summarizing the state of knowledge on fracing of gas shales and other tight formations. Good 

general background can also be found in PGC (2009, p. 179–192). They exist in all major basins 

of the state (Figure 26). 

In terms of approximate numbers, as given by the scoping analysis of the 2005–2009 period, 

number of frac jobs was >2,500, >4,500, >6,200, >6,600, and >3,700, respectively, from 2005 

through 2009, for a total of >23,500 frac jobs (2009 might be incomplete, data downloaded in 

April 2010). The “>” is used because a nonnegligible fraction of frac jobs is described as such 

but with no corresponding water-use amount in the IHS database, although it does show 

proppant use or long laterals, etc. These “zero” water-use wells are assigned water-use amounts 

as described in the methodology section. In this 5-year period, ~100 formations were fraced 

(Table 6), but the bulk of the frac jobs are limited to a few formations (Figure 25). In 2005, the 

Barnett Shale had the larger number of frac jobs (~42%), followed by the Cotton Valley of East 

Texas (~23%; ~27% if Travis Peak is added), Granite Wash (Anadarko Basin) at ~13%, and 

Wolfberry in the Permian Basin at 7%. In 2006, the order had not changed: Barnett (~57%), 

Cotton Valley and some Travis Peak (16%), Granite Wash (~10%), and Wolfberry (~6%). In 

2007, the Barnett Shale was still dominant (~62%), but followed by Granite Wash (14%), Cotton 

Valley and Travis Peak (15%), and then Wolfberry (5%). In 2008, the Barnett Shale still led 

(~40%), but Wolfberry collected ~15%, followed by Cotton Valley and Travis Peak (~11%) and 

Granite Wash (~7%). In addition, there is a clear increase in geographic coverage because other 

plays in the Permian Basin (Grayburg, Canyon, Caballos, Clear Fork), Anadarko Basin 

(Cleveland), and South Texas (Vicksburg, Olmos) are starting to be fraced. The year 2009 saw 

an overall decrease in the number of frac jobs, but they are still led by the Barnett Shale (~41%) 

and Wolfberry (19%). Other previously strong plays, such as Granite Wash (6%) and Cotton 

Valley (~6%), lose rank as newer fraced plays such as in the Pennsylvanian and Permian of the 

Permian Basin keep growing in terms of the number of frac jobs. Many plays all around the state 

go beyond the testing stage as tens of frac jobs are performed on 10+ additional formations. Note 
52 

that this ranking is done in terms of number of frac jobs, which may or may not be the same as 

ranking for water use. 

To address the last comment and as a final check on the trends in this fast-evolving field, we 

performed an analysis of all wells completed in 2010 to date (early November 2010). Among a 

total of 10,268 completed wells, 7650 (~75%) received a treatment making use of water, 

including ~3850 wells (~37% of total) using >0.1 Mgal of water (Table 7 and Table 8). The 

minimum amount of water used is over 6 billion gallons or ~18.5 thousand AF, almost # of it in 

the Fort Worth Basin Barnett Shale. 

4.1.2 Gas (and Oil) Shales 

This report does not comprehensively document the different formations described in this 

section, but rather focuses on water use and mostly provides information needed to access it and 

make projections. Water use is different in each play and is impacted by local geological factors. 

There are three very active “shale gas” (oil is also produced) plays as of end of 2010 in Texas: 

Barnett, Haynesville/Bossier, and Eagle Ford shales. To them can be added the Pearsall Shale, 

Barnett and Woodford Shales in the Permian Basin, and perhaps the Bend Shale in the Palo Duro 

Basin in the Texas Panhandle. A map by EIA (Figure 23a) does display them all but with 

inaccurate footprints. 

4.1.2.1 Barnett Shale 

The Barnett Shale (Figure 28) is the formation where the current technology was pioneered, and 

it has been producing gas since the early 1990s. Productive Barnett Shale is found at depths 

between 6,500 and 8,500 ft in North-Central Texas, with a net thickness ranging from 100 to 600 

ft. Pollastro et al. (2007) and Galusky (2009) provided an update to information presented in 

Nicot and Potter (2007), whereas Martineau (2007) summarized the history of the play. The 

Mitchell Energy / C. W. Slay #1, a vertical well, went into production in June 1982, has 

produced over 1.7 Bcf of gas, and is still producing after 28+ years. It is given credit as the first 

Barnett Shale producer (PBSN, Nov 1, 2010). As slick-water-frac and horizontal-drilling 

technologies were being perfected, the balance of wells initially favoring vertical wells is now 

disproportionally in favor of horizontal wells (Figure 27), with >2500 horizontal wells and only 

100+ vertical wells completed in 2008. Figure 29 illustrates the transition and its impact on water 

use. There is a clear jump in the average water use in 1998 for both horizontal and vertical wells 

to ~1.5 million gallons/well. The amount of water used then stays more or less constant through 

time for vertical wells but with a much larger variance, whereas it keeps increasing for horizontal 

wells until it reaches a current average of 3–4 million gal/well. Progress in the technology is also 

visible on the histograms of the frac water volume, with a clear bimodal distribution (Figure 

30a). The most recent vertical fracs (Figure 30c) display a well-behaved normal distribution 

centered on ~1.3 million gal/well. A histogram of horizontal well-water use, depicted in Figure 

31a, also shows a well-behaved distribution, but with a broad mode and a very large range (from 

<1 million to >8 million gal/well). However, when reported to the total lateral length (Figure 

31b), water intensity seems normally distributed, with a mean/mode of ~1000 gal/ft. Proppant 

amount distribution is biased toward lower values, with a long tail toward high proppant amount 

(Figure 32a and Figure 33a). The observation remains true in a plot of proppant loading (Figure 

32b and Figure 33b). 

Core counties consist of Denton, Johnson, Tarrant, and Wise Counties. Production has been 

relatively stable in the past 2 years at ~5 million Mcf/d (PBSN, Nov 1, 2010) although the so-
53 

called “combo” play in Montague and Clay Counties in the oil window has seen a recent increase 

in activity. Other counties (Stephens, Shackelford) south of the core area and in the oil window 

also seem to stir some interest. Other counties producing from the Barnett are Archer, Bosque, 

Comanche, Cooke, Coryell , Dallas, Eastland , Ellis, Erath, Hamilton, Hill, Hood, Jack , Palo 

Pinto, Parker, and Somervell Counties. In 2008, water use in the Barnett Shale was ~25 thousand 

AF (Table 9). Table 9 also presents completion water use at the county level, with Johnson 

County displaying the highest water use at ~8.5 thousand AF, followed by Tarrant County at 5.1 

thousand AF, and Denton, Wise, and Parker Counties at 2.8, 2.1., and 1.8 thousand AF, 

respectively. 

4.1.2.2 Haynesville and Bossier Shales 

The productive interval of the Haynesville Shale of Jurassic age is >10,000 ft deep. It is an 

organic-rich, argillaceous, silty, calcareous mudstone that was deposited in a restricted, intrashelf 

basin in relatively shallow water (for example, Spain and Anderson, 2010). The current core area 

(Texas section) includes Harrison, Panola, Shelby, and San Augustine Counties, but the play also 

covers Angelina, Gregg, Marion, Nacogdoches, Rusk, and Sabine Counties (Figure 34). Typical 

thickness of the Haynesville Shale ranges between 300 and 400 ft in western Louisiana and 200 

and 300 ft in Texas, at burial depths between 11,000 and 14,000 ft. Further west, the shale 

transitions to the so-called Haynesville carbonates, which are known for their excellent 

production from carbonate shoals and pinnacle reefs in the East Texas Salt Basin (Hammes, 

2009; Hammes et al., 2009). The Haynesville Shale is overpressured, increasing the amount of 

gas per unit rock relative to a normally pressured shale. 

The first year with significant fracing water use was 2008 (Figure 35), before which date any 

frac was mostly exploratory in nature. The few vertical wells stimulated in the early years of 

2000 (Figure 36) probably targeted carbonate facies. Currently the bulk of wells are horizontal, 

with a wide range of water use from <1 million to >10 million gal/well (Figure 37a). Water 

intensity (Figure 37b) is not as clearly defined as it was in the Barnett Shale because of the much 

smaller sample size, but it stays in the same 1000 to 1200 gal/ft range (we used 1100 gal/ft). 

Proppant loading is higher on average than that in the Barnett Shale (Figure 38). As of October 

2010, the IHS database contained ~100 wells of which ~50 of which have water-use information. 

After we corrected for obvious typos by assessing water-use intensity (gal/ft) and proppant 

loading (lb/gal), the total reported water use to date is ~260 million gal. Assigning reasonable 

water-use values to wells with missing data (through knowledge of proppant amount and/or 

lateral length), total water use to date (2008 to ~mid-2010) is ~0.5 billion gal or 1.5 thousand AF, 

7% of which (0.1 thousand AF) was used in 2008, 50% (0.75 thousand AF) in 2009, and 43% 

(0.65 thousand AF) during the first ~8 months of 2010. 

Groundwater–surface water split is unclear in Texas. However, Louisiana parishes bordering the 

Texas state line, where gas production started, are also part of the Haynesville core. Initially frac 

jobs relied heavily on the local groundwater resources of the Carrizo-Wilcox aquifer (Hanson, 

2009) but, thanks to a grass-root effort, the bulk of the water use has shifted to surface water 

(Gary Hanson, LSU Shreveport, personal communication, 2010). 

The Bossier Shale directly overlies the Haynesville Shale and represents distal parts of the 

overlying Cotton Valley siliciclastic wedge. The upper Bossier Shale, dominated by siliciclastics, 

is not as overpressured, is less organic rich, and contains less TOC than the Haynesville Shale 

(Hammes, 2009; Hammes and Carr, 2009). The RRC webpage describing the Haynesville 

combines Haynesville and Bossier, owing to a terminology issue. 
54 

4.1.2.3 Eagle Ford Shale 

The Eagle Ford Formation of Late Cretaceous age covers a large section of South Texas all the 

way to East Texas, where it meets the deltaic deposits of the Woodbine Formation of equivalent 

age, as depicted in the schematic cross section of Figure 39. It lies below the Austin Chalk and is 

probably the source of its hydrocarbon accumulation. Located at a depth of 4,000–11,000 ft, the 

play is slightly overpressured (pressure gradient of 0.43 to 0.65 psi/ft; Vassilellis et al., 2010), 

making it more attractive because of the higher initial production rates. Most current interest is 

focused on the South Texas section of the Eagle Ford (Figure 40 and Figure 41). The discovery 

well was drilled by Petrohawk in 2008 in La Salle County (PBSN, Sept 20, 2010). The formation 

produces natural gas, condensate, and oil. Earlier wells were vertical, located in Central Texas 

(Brazos, Burleson Counties), and looking for oil. The Central Texas play is somewhat 

disconnected from the South Texas play (from the Mexican border to Gonzales and DeWitt 

Counties) by the San Marcos Arch, a constant higher-elevation structural feature (Figure 39). 

The Eagle Ford Shale contains oil updip, gas downdip, and gas and condensates in between. The 

“shale” is carbonate rich, up to 70% calcite (Cusack et al., 2010, p. 171), much higher than that 

of the Barnett Shale, which makes it more prone to fracing. The play is still too young to 

determine the location of the core area, if it exists, but most of the fracing has taken place in 

Dimmit, LaSalle, and Webb Counties. 

As of October 2010, the IHS database contained ~270 wells, 174 of which have water-use 

information (Figure 42), almost all of them horizontal (Figure 43). The average frac water 

amount is higher than either the Barnett or Haynesville (Figure 44a), ranging from ~1 to >13 

million gal/well. A histogram of water intensity shows that this shale is not as well behaved as 

the two previous shales (Figure 44b). We used an average of 1250 gal/ft. Total proppant amount 

being correlated to total water use is higher than in the Barnett and Haynesville (Figure 45a), but 

the proppant loading lies in between (Figure 45b). After correcting for obvious typos by 

assessing water-use intensity (gal/ft) and proppant loading (lb/gal), we found the total reported 

water use to date to be ~977 million gal. Assigning reasonable water-use values to wells with 

missing data (through knowledge of proppant amount and/or lateral length), we found total water 

use to date (~mid-2008 to ~mid-2010) to be 1.43 billion gal, or 4.4 thousand AF, 3% of which 

was used in 2008 (0.13 thousand AF), 37% (1.6 thousand AF) in 2009, and 60% (2.6 thousand 

AF) during the first ~8 months of 2010. 

4.1.2.4 Woodford, Pearsall, Bend, and Barnett-PB Shales 

The extent of the Woodford Formation of Devonian age is shown in Figure 46. It covers most of 

the Permian Basin and a small area of what would become the Central Basin Platform. It can be 

as thick as 600 ft in Loving and Winkler Counties but radially decreases to <100 ft outward to 

subcrop boundaries. In the Delaware Basin depth can reach 15,000 ft, whereas shale is ~7,000 to 

9,000 ft deep in the Midland Basin. The main current target in the Anadarko Basin in Oklahoma 

is also shown, where the formation is called the Caney Shale. The Woodford Shale is 

stratigraphically equivalent to several Devonian black shales in North America, including the 

Antrim Shale in the Michigan Basin and the Bakken Formation in the Williston Basin (Comer, 

1991, p. 6). Overall, maturity of the Woodford in the Permian Basin seems low and unpromising. 

The Permian Basin Barnett seems more clay rich and not as organic rich as in the Fort Worth 

Basin. Figure 47 displays occurrences of the Barnett Shale in the Permian Basin. Its well-known 

occurrence in the Fort Worth Basin is also displayed. Kinley et al. (2008) provided a description 

of its most promising occurrences in the Delaware Basin. Thickness of Mississippian-age 
55 

sediments in the Permian Basin is larger and can be >2000 ft in what would become the 

Delaware Basin and has a maximum of 700 ft in the Midland Basin. 

The Pearsall Shale (Loucks, 2002; Hackley et al., 2009a) is overpressured (Wang and Gale, 

2009, p.785–786; Vassilellis et al., 2010) with a pressure gradient of 0.80 to 0.89 psi/ft and is 

located at depths between 7,000 and 12,000 ft. Water use has been small, given the limited 

number of wells drilled so far. 

Figure 48 displays the surge in drilling starting in 2006 and subsiding in 2009 in those 3 West 

Texas plays (13 in the Woodford, 12 in the Pearsall, and 22 in the Barnett-PB), with a mix of 

vertical and horizontal wells (Figure 49). Overall frac water use per well remains small (Figure 

50) at <2 million gal per well, probably because the plays have not seen much activity in the past 

2 years. Woodford, Pearsall, and Barnett-PB shales total 11.3, 44.2, and 37.8 million gal, 

respectively, that is, 0.035, 0.14, and 0.12 thousand AF, respectively. 

The Bend Shale in the Palo Duro Basin does not seem to live up to earlier expectations, although 

older BEG and other reports (Dutton, 1980; Dutton et al., 1982; Brister et al., 2002; Jarvie, 2009) 

have credited the basin with some oil and gas generation potential. There is a scarcity of 

information on this shale that was described early on as a good prospect. The Palo Duro’s Bend 

Shale tests as thermally mature and reaches gross thicknesses between 500 and 1,000 ft at depths 

from 7,000 to 10,500 feet (Wagman, 2006). No further work is done in this study on the Bend 

Shale in the Palo Duro Basin. 

4.1.2.5 Conclusions on Gas Shales 

Completion water-use shale-gas wells was dominated (99.0%) by the Barnett Shale in 2008 at 

~25.5 thousand AF used (Figure 51 and Figure 52), whereas, as detailed in the next section, all 

tight formations across the state amount to ~10.4 thousand AF (Table 10). In 2008, Johnson 

County in the Barnett Shale footprint achieved the highest water use at 8.5 thousand AF. Note 

that this water-use amount includes some recycling, but, as will be described in the Future Water 

Use section, it is likely to be at the very most 10% and more likely just a few percent. Also note 

that some of the water used directly originates from stormwater collection systems and is thus 

not considered surface water or groundwater. However, the fraction of this source among the 

total water used cannot be determined easily because undoubtedly many surface ponds are filled 

with landowner-supplied groundwater. 
56 

Table 6. List of formations currently being fraced heavily or with the potential of being fraced 

heavily in the future 

Name Basin/Subbasin IHS Word Search 

Gas Shales: 

Barnett Fort Worth Barnett, Ellenburger, Forestburg, Marble Falls, Viola 

Barnett PB Permian Barnett 

Haynesville East Texas Haynesville 

Eagleford GC Rio Grande Eagleford 

Pearsall Maverick Pearsall 

Woodford-PB Permian Woodford 

Woodford-AB Anadarko Woodford 

 

Tight Gas 

Anadarko Basin 

Atoka-AB Anadarko Atoka, Bend, Morrow, Granite Wash, Pennsylvanian 

Cleveland Anadarko Cleveland, Marmaton, Cherokee, Kansas, Caldwell 

 

East Texas Basin 

James East Texas James 

Pettet East Texas Pettet, Pettit, Sligo 

Travis Peak East Texas Travis Peak, Hosston 

Cotton Valley East Texas Cotton Valley, Austin Chalk, Taylor, Gilmer, Schuler, Buckner 

Bossier East Texas Bossier 

Smackover East Texas Smackover 

 

Fort Worth Basin 

Atoka-FWB Fort Worth Atoka, Bend, Morrow, Granite Wash, Pennsylvanian 

 

Permian Basin 

San Andres Midland+CBP San Andres, Grayburg (Glorieta, Abo, Wichita) 

Spraberry Midland Spraberry, Dean 

Clear Fork CBP Clear Fork 

Bone Spring Delaware Bone Spring 

Wolfcamp Midland Wolfcamp 

Cisco Permian Cisco, Canyon, Strawn, Pennsylvanian 

Canyon Permian Cisco, Canyon, Strawn, Pennsylvanian 

Strawn Permian Cisco, Canyon, Strawn, Pennsylvanian 

Atoka-PB Permian Atoka, Bend, Morrow, Granite Wash 

Devonian Permian Devonian, Thirtyone, Devonian Cherts, “Silurian” 

Canyon Sands Val Verde Canyon, Canyon Sands 

Caballos Marathon Caballos, Tesnus 

 

Gulf Coast Basin 

Vicksburg Gulf Coast Vicksburg, Frio, Hackberry 

Wilcox Gulf Coast Wilcox, Indio, Tucker, Lobo, Sabine Town 

Olmos Gulf Coast Olmos, San Miguel, Navarro, Escondido 
57 

Table 7. Well statistics and water use for 2010 

Category 

Water Use 

(% of Total) 

Number of Wells 

(% of Total) 

Vertical Wells 

(% of Wells for Category) 

Not fraced 0.0% 25.6% 

Stimulated 1.7% 34.6% 

Anadarko Basin 3.0% 2.2% 28.1%

East Texas Basin 7.8% 5.0% 44.8%

Fort Worth Basin 57.3% 13.6% 2.0%

Gulf Coast 12.3% 4.8% 33.4%

Permian Basin 17.9% 14.1% 94.1%

Table 8. Major active formations in 2010 completed well count 

Category Play/Formation Count 

Granite Wash and others 124 

Cleveland 50 

Marmaton 18 

Others 18 

Anadarko Basin 

Total 210 

Delaware Group 32 

Spraberry/Dean/Wolfcamp 863 

Clear Fork 232 

Canyon Sands 48 

Caballos/Tesnus 19 

Others 168 

Permian Basin 

Total 1362 

Cotton Valley Group 200 

Travis Peak 47 

Haynesville/Bossier Shales 115 

Cotton Valley Sands 26 

Others 99 

East Texas Basin 

Total 487 

Eagle Ford 193 

Olmos 68 

Vicksburg 39 

Wilcox/Lobo 64 

Frio 20 

Others 80 

Gulf Coast Basin 

Total 464 

Barnett Shale 1295 

Fort Worth Basin Others 23 

Total 1318 

Permian Basin 2460 

East Texas 315 

Gulf Coast 169 

Fort Worth 132 

Others 733 

Stimulated only 

(<0.1 Mgal) 

Total 3809 

Frio 482 

Wilcox 185 

Austin Chalk 140 

Others 1811** 

Not Stimulated 

Total 2712 
58 

Table 9. County-level shale-gas-completion water use in the Barnett Shale (2008) 

County 

Water Use 

(thousand AF) County 

Water Use 

(thousand AF) 

Archer 0.003 Jack 0.085 

Brazos 0.008 Johnson 8.459 

Burleson 0.034 La Salle 0.010 

Clay 0.020 Maverick 0.007 

Cooke 0.229 Montague 0.571 

Culberson 0.045 Palo Pinto 0.206 

Dallas 0.076 Panola 0.036 

Denton 2.752 Parker 1.768 

Dimmit 0.044 Reeves 0.048 

Eastland 0.012 Rusk 0.011 

Ellis 0.096 Somervell 0.171 

Erath 0.295 Tarrant 5.147 

Harrison 0.058 Webb 0.007 

Hill 1.137 Wise 2.217 

Hood 2.154 Total 25.70 

Table 10. Summary of fracing water use 

Play 

Water Use 

(thousand AF) 

Barnett Shale 25.45 

Haynesville Shale 0.11 

Eagle Ford Shale 0.07 

Woodford/Barnett PB/Pearsall Shale 0.09 

Anadarko Tight Formation 2.22 

East Texas Tight Formation 4.26 

Permian Basin Tight Formation 3.09 

Gulf Coast Tight Formation 0.6 

Caballos/Tesnus Tight Formation 0.17 

Sum Shale (filtered at >0.001 Mgal) 25.71 

Sum Tight Fm. (filtered at >0.001 Mgal) 10.33 

Sum All (filtered at >0.001 Mgal) 36.04 

MiningWaterUse2008_2.xls 
59 

(a) 

(b) 

Source: EIA website, updated Spring 2010 Figure 23. EIA spatial definition of shale-gas and tight-gas plays 

, Red Fork, Cleveland
60 

Barnett Shale

Haynesville Shale

Eagle Ford Shale

Pearsall Shale

Shales

Tight Gas

Granite wash, Cleveland, Marmaton

Bossier Shale

Cotton Valley,

Travis Peak

Wolfberry

Canyon Sands

Vicksburg,

Wilcox

Olmos

Woodford Shale

Barnett Shale

Source: IHS database 

Figure 24. Map showing locations of all frac jobs 2005–2009, and main (mostly) gas plays 

0

20

40

60

80

100

2005 2006 2007 2008

Percent of Yearly Total Number of Frac jobs

Barnett Shale

Cotton Valley and Travis Peak

Granite Wash

Wolfberry

Others

Figure 25. Percentage of frac jobs (not water use) in major plays in 2005-2008 
61 

QAd6474(a)

0 100 km

0 100 mi

N

GC

(LU)

(OFB)

OMFB/LU

RRUMA (RRU)

(MA)

NETX

FWB

(A)

(PD)

PB

TPT (D)

DVV

(VV)

AU

PAN

ESPB

Source: Ambrose et al. (2010) 

Note: Regions are: AU Amarillo Uplift, DVV Delaware (D) and Val Verde (VV) Basins, ESPB Eastern Shelf of the 

Permian Basin, FWB Fort Worth Basin, GC Gulf Coast, LU Llano Uplift, NETX Northeast Texas, OFB Ouachita 

Foldbelt, OMFB/LU Ouachita and Marathon Foldbelts and Llano Uplift, PAN Texas Panhandle, PB Permian Basin, 

PD Palo Duro Basin, RRUMA Red River Uplift (RRU)-Muenster Arch (MA), TPT Trans-Pecos Texas 

Figure 26. Major geologic regions (basins and uplifts) in Texas 

0

500

1000

1500

2000

2500

3000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Number of Frac Jobs

Vertical Horizontal

Figure 27. Barnett Shale—vertical vs. horizontal and directional wells through time 
62 

Hill

Bell

Clay

Ellis

Erath

Jack Wise

Llano

Milam

Falls

Mills

Burnet

Coryell

Dallas

Brown

Young

Coleman

Cooke

Mason

Parker

Baylor Archer

Denton

Bosque

Tarrant

Knox

San Saba

Eastland Callahan

Williamson

McLennan

McCulloch

Collin

Grayson

Stephens

Haskell

Palo Pinto

Montague

Hamilton

Wilbarger

Comanche

Wichita

Johnson

Hood

Foard

Jones Shackelford

Menard

Taylor

Lampasas

Concho

Throckmorton

Navarro

Limestone

Burleson

Hardeman

Runnels

Robertson

Somervell

Kaufman

Rockwall

Brazos

1

0 20 40 60 80 10

Miles

Muenster Arch

Ouachita

Thrust Fold Belt

Ben

d

Arch

Lampasas Arch

Source: Nicot and Potter (2007) 

Note: Forestburg limit modified from Zhao et al. (2007); all others modified from Montgomery et al. (2005); major 

oil and gas reservoirs from Galloway et al. (1983) and Kosters et al. (1989). The Major Gas and Oil Reservoirs refer 

to non-Barnett production. 

Figure 28. Barnett Shale footprint 

Barnett Shale Extent

Gas Window Area (Montgomery et al., 2005)

Gas Maturation Line (Givens and Zhao, 2005)

Major Gas Reservoirs

Major Oil Reservoirs

Viola-Simpson Fm. absent west of this line

Marble Falls Fm. absent east of this line

Forestburg Lm. absent west of this line

Urban Areas
63 

0

0.5

1

1.5

2

2.5

3

3.5

1980 1985 1990 1995 2000 2005 2010

Calendar Year

Frac Water Use (Mgal)

0

100

200

300

400

500

600

700

800

Annual Number of Frac Jobs

Average

5th Percentile

30th Percentile

Median

70th Percentile

95th Percentile

(a) 

0

1

2

3

4

5

6

7

1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010

Calendar Year

Frac Water Use (Mgal)

0

500

1000

1500

2000

2500

3000

Annual Number of Frac Jobs

Average

5th Percentile

30th Percentile

Median

70th Percentile

95th Percentile

(b) 

Figure 29. Barnett Shale – Annual number of frac jobs superimposed to annual average, median, 

and other percentiles of individual well frac water use for (a) vertical wells, and (b) horizontal 

wells. 
64 

0

50

100

150

200

250

300

350

400

0-0.1

0.1-0.2

0.2-0.3

0.3-0.4

0.4-0.5

0.5-0.60.6-0.7

0.7-0.8

0.8-0.9

0.9-1

1- 1.1

1.1- 1.2

1.2- 1.3

1.3- 1.4

1.4- 1.5

1.5- 1.6

1.6- 1.7

1.7- 1.8

1.8- 1.9

1.9- 2

2- 2.1

2.1- 2.2

2.2- 2.3

2.3- 2.4

2.4- 2.5

>2.5

Vertical Frac Water Volume (millions gallons)

Number of bins: 26; Bin size: 0.1; Number of data points: 3946

Number of Frac Jobs

(a) 

0

20

40

60

80

100

120

140

160

180

0-0.1

0.1-0.2

0.2-0.3

0.3-0.4

0.4-0.5

0.5-0.6

0.6-0.7

0.7-0.8

0.8-0.9

0.9-1

1- 1.1

1.1- 1.2

1.2- 1.3

1.3- 1.4

1.4- 1.5

1.5- 1.6

1.6- 1.7

1.7- 1.8

1.8- 1.9

1.9- 2

2- 2.1

2.1- 2.2

2.2- 2.3

2.3- 2.4

2.4- 2.5

>2.5

Vertical Frac Water Volume (millions gallons) - pre-2000

Number of bins: 26; Bin size: 0.1; Number of data points: 547

Number of Frac Jobs

(b) 

0

50

100

150

200

250

300

350

400

0-0.1

0.1-0.2

0.2-0.3

0.3-0.4

0.4-0.5

0.5-0.6

0.6-0.7

0.7-0.8

0.8-0.9

0.9-1

1- 1.1

1.1- 1.2

1.2- 1.3

1.3- 1.4

1.4- 1.5

1.5- 1.6

1.6- 1.7

1.7- 1.8

1.8- 1.9

1.9- 2

2- 2.1

2.1- 2.2

2.2- 2.3

2.3- 2.4

2.4- 2.5

>2.5

Vertical Frac Water Volume (millions gallons) - 2000-2010

Number of bins: 26; Bin size: 0.1; Number of data points: 3399

Number of Frac Jobs

(c) 

Figure 30. Barnett Shale— Histograms of frac water volume for vertical wells for (a) all wells, 

(b) pre-2000 wells, and (c) 2000–2010 wells 
65 

0

100

200

300

400

500

600

0-0.2

0.4-0.6

0.8-1

1.2- 1.4

1.6- 1.8

2- 2.2

2.4- 2.6

2.8- 3

3.2- 3.4

3.6- 3.8

4- 4.2

4.4- 4.6

4.8- 5

5.2- 5.4

5.6- 5.8

6- 6.2

6.4- 6.6

6.8- 7

7.2- 7.4

7.6- 7.8

>8

Horizontal Frac Water Volume (millions gallons)

Number of bins: 41; Bin size: 0.2; Number of data points: 8165

Number of Frac Jobs

(a) 

0

100

200

300

400

500

600

700

0-0.1

0.2-0.3

0.4-0.5

0.6-0.7

0.8-0.9

1- 1.1

1.2- 1.3

1.4- 1.5

1.6- 1.7

1.8- 1.9

>2

Horizontal Frac Water Volume Intensity (1,000 gallons/ft)

Number of bins: 21; Bin size: 0.1; Number of data points: 6134

Number of Frac Jobs

(b) 

Figure 31. Barnett Shale—frac water use: (a) total volume, (b) intensity in 1,000 gal/ft 

0

250

500

750

1000

1250

1500

1750

2000

0-0.5

0.5-1

1- 1.5

1.5- 2

2- 2.5

2.5- 3

3- 3.5

3.5- 44- 4.5

4.5- 5

>5

Vertical Frac Proppant Amount (millions lbs)

Number of bins: 11; Bin size: 0.5; Number of data points: 8129

Number of Frac Jobs

(a) 
66 

0

200

400

600

800

1000

0-0.05

0.05-0.1

0.1-0.15

0.15-0.2

0.2-0.25

0.25-0.3

0.3-0.35

0.35-0.4

0.4-0.45

0.45-0.5

0.5-0.55

0.55-0.6

0.6-0.65

0.65-0.7

0.7-0.75

0.75-0.8

0.8-0.85

0.85-0.9

0.9-0.95

0.95-1

>1

Vertical Frac Proppant Loading (lbs/gal)

Number of bins: 21; Bin size: 0.05; Number of data points: 3893

Number of Frac Jobs

(b) 

Figure 32. Barnett Shale—vertical well: (a) total proppant amount and (b) proppant loading 

0

100

200

300

400

500

600

700

800

900

0-0.2

0.4-0.6

0.8-1

1.2- 1.4

1.6- 1.8

2- 2.2

2.4- 2.6

2.8- 3

3.2- 3.4

3.6- 3.8

4- 4.2

4.4- 4.6

4.8- 5

Horizontal Frac Proppant Amount (millions lbs)

Number of bins: 26; Bin size: 0.2; Number of data points: 8129

Number of Frac Jobs

(a) 

0

250

500

750

1000

1250

1500

1750

2000

0-0.1

0.2-0.3

0.4-0.5

0.6-0.7

0.8-0.9

1- 1.1

1.2- 1.3

1.4- 1.5

1.6- 1.7

1.8- 1.9

>2

Horizontal Frac Proppant Loading (lbs/gal)

Number of bins: 21; Bin size: 0.1; Number of data points: 8112

Number of Frac Jobs

(b) 

Figure 33. Barnett Shale—Horizontal well: (a) total proppant amount and (b) proppant loading 
67 

Sabine Uplift

Core Area of

Lower BossierHaynesville Shale 

Gas Play

Haynesville Shale

Haynesville Limestone

Potential

Haynesville

Shale-Gas Play

Source: courtesy Dr. Wang, BEG 

Figure 34. Haynesville Shale footprint 

Figure 35. Haynesville Shale—annual number of frac jobs superimposed on annual average, 

median, and other percentiles of individual well frac water use 
68 

0

10

20

30

40

50

2001

2002

2003

2004

2005

2006

2007

2008

2009

Number of Frac Jobs

Vertical Horizontal

Figure 36. Haynesville Shale—vertical vs. horizontal and directional wells through time 

0

1

2

3

4

5

6

7

8

0-0.5

1- 1.5

2- 2.5

3- 3.5

4- 4.5

5- 5.5

6- 6.5

7- 7.5

8- 8.5

9- 9.5

10- 10.5

HAY - Horizontal Frac Water Volume (millions gallons)

Number of bins: 23; Bin size: 0.5; Number of data points: 53

Number of Frac Jobs

(a) 

0

1

2

3

4

5

6

7

8

0-0.1

0.2-0.3

0.4-0.5

0.6-0.7

0.8-0.9

1- 1.1

1.2- 1.31.4- 1.5

1.6- 1.7

1.8- 1.9

2- 2.1

2.2- 2.3

2.4- 2.5

HAY - Horizontal Frac Water Volume Intensity (1,000 gallons/ft)

Number of bins: 26; Bin size: 0.1; Number of data points: 50

Number of Frac Jobs

(b) 

Figure 37. Haynesville—horizontal well frac water use: (a) total volume; (b) intensity in 1,000 

gal/ft (2008 and beyond) 
69 

0

2

4

6

8

10

12

14

16

18

20

0-0.5

1- 1.5

2- 2.5

3- 3.5

4- 4.5

5- 5.5

6- 6.5

>7

HAY - Horizontal Frac Proppant Amount (millions lbs)

Number of bins: 15; Bin size: 0.5; Number of data points: 97

Number of Frac Jobs

(a) 

0

1

2

3

4

5

6

7

8

9

10

0-0.1

0.2-0.3

0.4-0.5

0.6-0.70.8-0.9

1- 1.1

1.2- 1.3

1.4- 1.5

1.6- 1.7

1.8- 1.9

2- 2.1

2.2- 2.3

2.4- 2.5

HAY - Horizontal Frac Proppant Loading (lbs/gal)

Number of bins: 26; Bin size: 0.1; Number of data points: 48

Number of Frac Jobs

(b) 

Figure 38. Haynesville—horizontal well: (a) total proppant amount and (b) proppant loading 

(2008 and beyond) 
70 

Source: Hentz and Ruppel (2010, Fig. 9) 

Note: cross section hangs on top of Eagle Ford; top of Eagle Ford shallower in East Texas Basin than in Maverick 

Basin to the southwest 

Figure 39. SW-NE schematic strike cross section illustrating regional lithostratigraphic 

relationships across the Eagle Ford play area 

Source: Hentz and Ruppel (2010, Fig. 7) 

Figure 40. Isopach map of upper Eagle Ford Shale 
71 

Source: Hentz and Ruppel (2010, Fig. 6) 

Figure 41. Isopach map of lower Eagle Ford Shale 

Figure 42. Eagle Ford Shale—Annual number of frac jobs superimposed on annual average, 

median, and other percentiles of individual well frac water use 
72 

0

20

40

60

80

100

2001

2002

2003

2004

2005

2006

2007

2008

2009

Number of Frac Jobs

Vertical Horizontal

Figure 43. Eagle Ford Shale—vertical vs. horizontal and directional wells through time 

0

2

4

6

8

10

12

14

16

0-0.5

1- 1.5

2- 2.5

3- 3.5

4- 4.5

5- 5.5

6- 6.5

7- 7.5

8- 8.5

9- 9.5

10- 10.5

11- 11.5

12- 12.5

>13

E-F - Horizontal Frac Water Volume (millions gallons)

Number of bins: 27; Bin size: 0.5; Number of data points: 157

Number of Frac Jobs

(a) 

0

2

4

6

8

10

12

14

16

0-0.1

0.2-0.3

0.4-0.5

0.6-0.7

0.8-0.9

1- 1.1

1.2- 1.3

1.4- 1.5

1.6- 1.7

1.8- 1.9

2- 2.1

2.2- 2.3

2.4- 2.5

E-F - Horizontal Frac Water Use Intensity (1,000 gallons/ft)

Number of bins: 31; Bin size: 0.1; Number of data points: 155

Number of Frac Jobs

(b) 

Figure 44. Eagle Ford—horizontal well frac water use: (a) total volume; (b) intensity in 1,000 

gal/ft (2008 and beyond) 
73 

0

5

10

15

20

25

30

0-0.25

0.5-0.75

1- 1.25

1.5- 1.75

2- 2.25

2.5- 2.75

3- 3.25

3.5- 3.75

4- 4.25

4.5- 4.75

5- 5.25

5.5- 5.75

>6

E-F - Horizontal Frac Proppant Amount (millions lbs)

Number of bins: 25; Bin size: 0.25; Number of data points: 240

Number of Frac Jobs

(a) 

0

5

10

15

20

25

0.5-0.6

0.7-0.8

0.9-1

1.1- 1.2

1.3- 1.4

1.5- 1.6

1.7- 1.8

1.9- 2

2.1- 2.2

2.3- 2.4

>2.5

E-F - Horizontal Frac Proppant Loading (lbs/gal)

Number of bins: 26; Bin size: 0.1; Number of data points: 78

Number of Frac Jobs

(b) 

Figure 45. Eagle Ford—horizontal well: (a) total proppant amount and (b) proppant loading 

(2008 and beyond) 
74 

Source: Craig et al. (1979) modified by Stephen Ruppel and mudrock group (BEG) 

Note: plot also displays thickness of the Wilberns Formation of Cambrian age 

Figure 46. Woodford (Upper Devonian) occurrences in Texas 
75 

Source: Craig et al. (1979) modified by Stephen Ruppel and mudrock group (BEG) 

Figure 47. Mississippian (including Barnett) facies distribution 
76 

Figure 48. Woodford-Pearsall-Barnett PB—annual number of frac jobs superimposed on annual 

average, median, and other percentiles of individual well frac water use 

0

5

10

15

20

20012002

2003

2004

20052006

2007

2008

2009

Number of Frac Jobs

Vertical Horizontal

Figure 49. Woodford-Pearsall-Barnett PB—vertical vs. horizontal and directional wells through 

time 
77 

0

2

4

6

8

10

0-0.25

0.5-0.75

1- 1.25

1.5- 1.75

2- 2.25

2.5- 2.75

3- 3.25

3.5- 3.75

4- 4.25

4.5- 4.75

>5

Frac Water Volume (millions gallons) - 2007-2010

Number of bins: 21; Bin size: 0.25; Number of data points: 39

Number of Frac Jobs

Figure 50. Woodford-Pearsall-Barnett PB horizontal and vertical well frac water use 

0

5

10

15

20

25

30

Barnett Sh.

Haynesville Sh.

Eagle Ford Sh.

Woodford/BarnettPB/Pearsall Sh.

Anadarko TG

East Texas TG

Permian Basin TG

Gulf Coast TG

Caballos/Tesnus TG

2008 Water Use (Thousand AF)

Figure 51. Water use for well completion in gas shales and tight formations (2008) 

MiningWaterUse2008_2.xls 
78 

Figure 52. County-level fracing water use (2008) 
79 

4.1.3 Tight Reservoirs 

Tight-sand plays are more numerous than shale-gas plays and have a longer history, going back 

to the 1950s and early days of the frac technology. In each basin, many formations have been 

fraced one time or another, and in this report they are grouped by rock type and geological 

affinity. BEG published many reports in the 1980s and 1990s in collaboration with GRI (Gas 

Research Institute, now GTI) related to tight-gas hydrocarbon accumulations. Extended 

summaries were presented by Finley (1984) and then Dutton et al. (1993), who considered the 

following Texas tight gas plays: Travis Peak (Hosston) Formation and Cotton Valley Sandstone 

in East Texas, Cleveland Formation and Cherokee Group in the Anadarko Basin in the Texas 

Panhandle, Olmos Formation in the Maverick Basin of South Texas, and the so-called Davis 

sandstone in the Fort Worth Basin (informal unit of the Atoka Group) (Figure 53). They were 

chosen because they were major gas producers at the time. Dutton et al. (1993) added the 

Vicksburg Formation and Wilcox Group along the Gulf Coast, the Granite Wash to the 

Anadarko Basin, the Morrow Formation in the Permian Basin, and the Canyon Sands in the Val 

Verde Basin. An observation made about many of these tight reservoirs is that low permeability 

is diagenetic and is caused by pore occlusion rather than depositional due to a clay matrix. In 

opposition to the gas shales previously discussed, tight sands are conventional in that they form 

reservoirs and local accumulations (Dutton et al., 1993, p. 5). A map by EIA (Figure 23b) cites 

them all, but with inaccurate footprints. 

4.1.3.1 Anadarko Basin 

Sediments of the Anadarko Basin occur mostly in Oklahoma, but its western section is located in 

the northern Texas Panhandle, including Gray, Hansford, Hemphill, Hutchinson, Lipscomb, 

Ochiltree, Oldham, Roberts, Sherman, and Wheeler Counties. The Anadarko Basin contains a 

thick (>18,000 ft) accumulation of siliciclastics and carbonate sediments resulting from the 

deposition of large volumes of arkosic sediments eroded from the Amarillo Uplift (Ambrose et 

al., 2010). These sediments are overlain and interfingered by carbonate and sandy deposits of the 

Marmaton Group and Cleveland Formation (Hentz and Ambrose, 2010). Most of the historical 

tight gas occurs within the thick undifferentiated interval of the so-called Granite Wash of 

Pennsylvanian and Permian age. Formations of similar age, such as the Caldwell, Cherokee, 

Cleveland, and Marmaton, contain tight-gas reservoirs as well as oil. 

The basin has seen several cycles of activity since the 1950s, as evidenced by its fracing history 

(Figure 54b). However, the wells were vertical and the fracing water volumes were small (<0.1 

Mgal/well) (Figure 54a). Since 2008, the frac water volume has increased to an average of 0.4

Mgal/well (Figure 54a) but with a very long tail (Figure 55a). More recently, deviated vertical 

(directional) and horizontal have been developed in the basin (multimodal histogram of Figure 

54b). Average water intensity is ~450 gal/ft (Figure 54c) with a broad mode. Both horizontal and 

vertical wells have been growing (Figure 56). The formation described as the Granite Wash has 

been fraced the most often, followed by the Cleveland Formation (Figure 57). In 2008, 2.22

thousand AF of water was used for fracing purposes. 

4.1.3.2 East Texas Basin 

The East Texas Basin, sometimes incorporated into the Gulf Coast Basin in high-level regional 

studies, is a clearly individualized feature in northeast Texas with thick sediments of mostly 

Cretaceous age. It consists of a deep trough aligned in Anderson and Smith Counties (East Texas 

Salt Basin) and two flanks with formations of similar age but not necessarily of similar lithology 
80 

on each side (Table 11). The eastern flank abuts the Sabine Uplift over the Texas-Louisiana state 

line. The Travis Peak (also called Hosston) Formation (Early Cretaceous) and the Cotton Valley 

Sandstone (Late Jurassic) have been historical targets and producers in the tight-gas category, 

most of the activity being confined east of the trough, although many opportunities also exist 

farther west. The Cotton Valley Sandstone (Figure 58) has a spatial distribution similar to that of 

the Haynesville Shale. It consists of multiple generally low-permeability sand layers interspersed 

with shaly material. So that the reservoir could drain efficiently, well spacing has been reduced 

to 20 acres in many places (Baihly et al., 2007). Cotton Valley is the formation currently being 

fraced the most, followed by the Travis Peak Formation (Figure 60), although several other 

formations are also being stimulated, such as the Bossier and the Pettet Formations. 

Most of the wells are vertical, although the proportion of horizontal wells is growing (Figure 59). 

Fracing took off in the 1990s, as it did in other tight formations, with a sharp increase in average 

water use in recent years (Figure 61)— 0.9 Mgal and 3 Mgal/well for vertical and horizontal 

wells, respectively (Figure 62). In 2008, the East Texas Basin used a total of 4.26 thousand AF

of water for fracing purposes. 

4.1.3.3 Fort Worth Basin 

The Fort Worth Basin hosts the Barnett Shale and is home to the areally extensive and highly 

productive Pennsylvanian fan-delta sandstone and conglomerate play (Kosters et al., 1989) 

(likely sources from the Barnett). Formations include Atoka and Bend Conglomerate 

(Thompson, 1982). This area has not been traditionally an area with significant tight-gas 

accumulations. Dutton et al. (1993) mentioned an interval called the Davis Sandstone, but it does 

not seem to be of significance, given the few wells possibly fraced recently in this interval (Table 

8). In addition, any completion would be dwarfed by the Barnett Shale. 

4.1.3.4 Permian Basin 

The Permian Basin contains a thick accumulation of sediments from Cambrian to Permian age 

on a Precambrian basement. Despite its long hydrocarbon production history (>30 Bbbl, or about 

half the state’s overall oil production) as compiled according to play by Dutton et al. (2005a,b), 

the basin still contains important reserves because <30% of the OOIP has been produced (Dutton 

et al, 2005a, p. 343). Most of the Permian Basin is in the oil window, although significant 

amounts of gas may exist deeper. Major operators have been content to focus on the abundant oil 

resources (Figure 63). The classical division of the Permian Basin into the Delaware Basin, 

Central Basin Platform, and Midland Basin, from west to east (to which the Eastern Shelf can be 

added), holds only for Permian and Pennsylvanian times (Table 12, Figure 64). At earlier 

periods, the Permian Basin area was not individualized in basins but presented a more complex 

but more regionally uniform geometry, with sediments deposited before the expression of the 

Delaware and Midland Basins. This geological history allows for grouping of the many series 

described in the IHS database into logical larger groups. However, techniques used by the 

operators respond more to the nature of the rock than to its age. 

The Delaware Basin is in general deeper than the Midland Basin (on the other side of the Central 

Basin Platform) for a formation of the same age. For example, Bone Spring, Clear Fork, and 

Spraberry are formations of equivalent age (Figure 65). Similarly the Delaware Mountain Group 

in the Delaware Basin is equivalent to the San Andres-Grayburg on the Central Basin Platform 

and in the Midland Basin. Carbonates dominate the platform sediments, but clastics and 

calcareous mudrocks are more prevalent in the basins. 
81 

In Texas, the Delaware Basin includes Culberson, Reeves, and Loving Counties, as well as parts 

of Jeff Davis, Pecos, Ward, and Winkler Counties. The Central Platform extends from Gaines to 

Pecos Counties, and the Midland Basin from Terry and Lynn Counties to the north to Crockett 

County to the south. The Eastern Shelf parallels the Midland Basin to the east, all the way to the 

Bend Arch and the Fort Worth Basin and Llano Uplift. 

The Delaware Basin also contains formations of interest, such as the Bone Spring Formation 

(also called the Avalon Shale or Leonard Shale in New Mexico) (Figure 66). It is present in 

Loving, Reeves, and Ward Counties, although maturity drops off quickly. The Bone Spring has 

seen a surge in interest but is still relatively unexplored. The Delaware Mountain Group, 

stratigraphically above the Bone Spring Formation, but similar in terms of lithology and broad 

depositional environments, has many reservoirs from shallow depth (2,500 ft) to much deeper 

levels (>8,000 ft). Recovery is low, <30% after secondary and possibly tertiary production 

(Dutton et al., 2005a, p. 312–314). The top of the gas window in the Delaware Basin is estimated 

to be at ~10,000 ft. 

The important development of the so-called Wolfberry play in the Midland Basin corresponds to 

operators fracing similar rocks of stacked Spraberry, Dean, and then Wolfcamp (Figure 67), and 

possibly Strawn basinal deposits involving up to 12 stages in vertical wells at a depth of >7,000 

ft. Spraberry/Dean reservoirs have historically had a fairly low recovery (10% of OOIP, Dutton 

et al., 2005a, p. 205). Most of the fracing has focused on the margins of the basin along the 

Central Platform and the Eastern Shelf. There has been a considerable interest in the Wolfberry 

play in the past few years, as illustrated by the number of recent wells (Figure 24). 

Canyon Sands in the Val Verde Basin, a southeastern extension of the Permian Basin south of 

the Ozona Arch (Crockett County), were deposited in deep environments (Dutton et al, 1993, p. 

122). The Canyon Sands, initially thought equivalent to the Canyon Formation in the Permian 

Basin, are actually mostly of Permian age (Hamlin et al., 1995, p. 4-5), although the name 

remains. For convenience, we also added the Devonian Caballos and Mississippian Tesnus 

Formations south of the Ouachita Front (Figure 46 and Figure 47) to the Permian Basin category. 

Overall the Permian Basin has seen 50,000+ frac jobs in the past 50 years (Figure 68), including 

18,300+ with water use >0.1 Mgal (Figure 69), and ~2,900 frac jobs with water use >0.5 Mgal, 

mostly in the past few years. The plots show a clear upward trend in all percentiles since 2000, 

with average water use approaching 1 Mgal/well (Figure 70) with a broad distribution (once 

<0.1Mgal jobs are removed) (Figure 71). This is a relatively modest amount per current 

standards, but most of the wells are vertical (Figure 72). Many formations are being fraced, but 

the Spraberry/Dean in the Midland Basin, the Clear Fork in the Central Platform, and the 

Wolfcamp underlying both form the bulk of the frac jobs (Figure 73 and Figure 74). Devonian 

formations are also the subject of interest. We treated the Caballos and Tesnus Formations 

separately because they are located farther south, but their statistics are similar to those of other 

formations of West Texas, with a sharp increase in recent years (Figure 75) and an average water 

use at ~0.35 Mgal/well (Figure 75 and Figure 76). 

In 2008, the Permian Basin (Texas section) used a total of 3.25 thousand AF of water for 

fracing purposes (including 0.17 for the Caballos/Tesnus). 

4.1.3.5 Maverick Basin and Gulf Coast 

The Texas southern Gulf Coast province is well known for its gas-prone hydrocarbon 

accumulations and includes the Frio Formation, a prolific conventional gas producer, as well as 
82 

the Wilcox deltaic (Table 13; Figure 147 in Appendix C). Tight-gas formations such as 

Vicksburg and Wilcox Lobo tend to occur deeper (Dutton et al., 1993). The Maverick Basin, 

included in the Gulf Coast area for the purpose of this study, contains the Olmos Formation, 

another important tight-gas formation. Overall, Gulf Coast tight formations have not seen the 

increase in average frac water volume as seen in all other basins, despite a sharp increase in the 

number of frac jobs (Figure 78). The reason may be due to the lack of horizontal wells (Figure 

73). Recently active plays include the Vicksburg, the Wilcox, and the Olmos Formations, which 

have been traditionally fraced (Figure 79). The amount of water used is low (<0.2 Mgal/well for 

the most part) (Figure 80), but the proppant amount is relatively high (Figure 81), leading to a 

high proppant loading (Figure 82). These plays have most likely not been swept by the new 

fracing technologies, but we assume that they will in the future (we assume a water use of 0.5

Mgal/well or projections), as operators revisit older plays through refracing and infill wells. 

In 2008, the Gulf Coast Basin used a total of 0.60 thousand AF of water for fracing purposes. 

4.1.3.6 Conclusions on Tight Formations 

Water use for tight formation completion is less than half of that for gas shales, at 10.4 thousand 

AF (Table 10 and Figure 51). Table 14 lists all counties with a total use >0.001 AF in 2008. 

Average water use across the 84 counties (Figure 52) is~120 AF, and Wheeler County, in the 

Panhandle, has the highest water use at 1.07 thousand AF. 

Table 11. Simplified stratigraphic column of the East Texas Basin showing commonly fraced 

intervals, as well as potential targets (in bold) 

System Age Formation / Group

 Salt Basin 

Austin Chalk* 

 Glen Rose/Fredericksburg/ 

Washita/Eagle Ford 

 

 Pearsall / Rodessa / James 

 Sligo / Pettet* 

 Hosston/Travis Peak* Hosston/Travis Peak*

Cretaceous 

Cotton Valley* Cotton Valley*

Bossier Sands* Bossier Shale* 

Jurassic Haynesville Limestone Haynesville Shale* 

 Smackover/Buckner 
83 

Table 12. Simplified stratigraphic column of the Permian Basin showing commonly fraced 

intervals, as well as potential targets (in bold) 

System Age Formation / Group 

Delaware Basin Central Platform Midland Basin 

Ochoan Salado/Rustler/Dewey Lake and Dockum 

Guadalupian Delaware Mountain Queen/Seven Rivers/Yates*/Tansill 

Group* (Brushy, 

Cherry, & Bell 

Canyon) San Andres Grayburg 

Leonardian Bone Spring* Clear Fork Spraberry*/Dean* 

Permian 

Wolfcampian Wolfcamp Basin Wolfcamp Platform Wolfcamp Basin* 

Pennsylvanian Morrow/Atoka/Strawn/Canyon/Cisco 

Mississippian Barnett* N/A Platform Carbonates 

Barnett* 

Devonian Devonian*/Woodford* 

Silurian Siluro-Devonian* 

Ordovician Simpson Group/Ellenburger 

Cambrian Wilberns 

Table 13. Simplified stratigraphic column of South Texas Gulf Coast showing commonly fraced 

intervals, as well as potential targets (in bold) 

System Age Formation / Group 

Oligocene Vicksburg*/Frio* 

Eocene / Paleocene Wilcox-Lobo*/Carrizo/Queen City/Sparta/ 

Yegua/Jackson 

Paleocene (Early) Midway 

San Miguel*/Olmos*/Escondido* 

 Austin Chalk* 

Eagle Ford* 

Glen Rose/Edwards/Stuart City/Georgetown/Del 

Rio/Buda/ 

Pearsall* 

Cretaceous 

 Hosston/Sligo 

Jurassic Cotton Valley 

Table 14. County-level tight-formation-completion water use (2008) 

County 

Water Use 

(thousand AF) County 

Water Use 

(thousand AF) County 

Water Use 

(thousand AF) 

Andrews 0.132 Harrison 0.815 Ochiltree 0.071

Angelina 0.090 Hemphill 0.721 Panola 0.908

Bee 0.006 Henderson 0.028 Pecos 0.183

Borden 0.003 Hidalgo 0.074 Reagan 0.308

Brazoria 0.003 Houston 0.013 Real 0.002

Brooks 0.015 Howard 0.047 Reeves 0.057

Calhoun 0.003 Irion 0.062 Roberts 0.216
84 

County 

Water Use 

(thousand AF) County 

Water Use 

(thousand AF) County 

Water Use 

(thousand AF) 

Cherokee 0.120 Jackson 0.004 Robertson 0.208

Colorado 0.002 Jim Hogg 0.002 Rusk 0.540

Crane 0.003 Kenedy 0.027 San Augustine 0.088

Crockett 0.026 La Salle 0.017 San Patricio 0.002

Culberson 0.012 Lavaca 0.018 Smith 0.052

Dawson 0.007 Leon 0.055 Starr 0.068

DeWitt 0.013 Limestone 0.264 Sterling 0.022

Dimmit 0.004 Lipscomb 0.141 Terrell 0.008

Duval 0.020 Live Oak 0.003 Terry 0.004

Ector 0.183 Loving 0.030 Upshur 0.030

Edwards 0.002 McMullen 0.044 Upton 0.999

Fort Bend 0.003 Marion 0.029 Val Verde 0.001

Freestone 0.501 Martin 0.560 Van Zandt 0.002

Frio 0.004 Matagorda 0.008 Ward 0.067

Gaines 0.018 Maverick 0.015 Webb 0.112

Glasscock 0.096 Midland 0.371 Wharton 0.006

Goliad 0.009 Mitchell 0.027 Wheeler 1.071

Gregg 0.128 Nacogdoches 0.384 Willacy 0.005

Hale 0.002 Navarro 0.004 Winkler 0.014

Hansford 0.003 Newton 0.001 Yoakum 0.005

Hardin 0.001 Nueces 0.008 Zapata 0.107

Source: modified from Dutton et al. (1993, Fig. 1) 

Figure 53. Location of basins in Texas containing low-permeability sandstone with historical 

frac jobs 

2: Travis Peak Formation and Cotton Valley Sandstone 

3: Olmos Formation 

4: Vicksburg Formation and Wilcox Group 

5: Davis Sandstone 

6: Cleveland Formation, Cherokee Group, and Granite 

Wash Formation 

7: Morrow Formation 

8: Canyon Sands 

MiningWaterUse2008_2.xls 
85 

0

0.2

0.4

0.6

0.8

1

1.2

1950 1960 1970 1980 1990 2000 2010

Calendar Year

Frac Water Use (Mgal)

0

50

100

150

200

250

300

350

400

450

500

Annual Number of Frac Jobs

Average

5th Percentile

30th Percentile

Median

70th Percentile

95th Percentile

Figure 54. Anadarko Basin—annual number of frac jobs (b) superimposed on annual average, 

median, and other percentiles of individual well frac water use (a) 

Histogram2.0_Anadarko.xls 

Histogram2.0_Anadarko.xls 

(a) 

(b) 
86 

0

50

100

150

200

250

300

350

0-0.1

0.2-0.3

0.4-0.5

0.6-0.7

0.8-0.9

1- 1.1

1.2- 1.3

1.4- 1.51.6- 1.7

1.8- 1.9

2- 2.1

2.2- 2.3

2.4- 2.5

2.6- 2.7

2.8- 2.9

>3

Vertical Frac Water Volume (millions gallons) -2001-2010

Number of bins: 31; Bin size: 0.1; Number of data points: 2414

Number of Frac Jobs

(a) 

0

5

10

15

20

25

30

35

40

45

0-0.1

0.2-0.3

0.4-0.5

0.6-0.7

0.8-0.9

1- 1.1

1.2- 1.3

1.4- 1.5

1.6- 1.7

1.8- 1.9

2- 2.1

2.2- 2.3

2.4- 2.5

2.6- 2.7

2.8- 2.9

3- 3.1

3.2- 3.3

3.4- 3.5

3.6- 3.7

3.8- 3.9

>4

Non-Vertical Frac Water Volume (millions gallons) -2008-2010

Number of bins: 41; Bin size: 0.1; Number of data points: 342

Number of Frac Jobs

(b) 

0

5

10

15

20

25

30

35

40

45

50

0-0.025

0.05-0.075

0.1-0.125

0.15-0.175

0.2-0.225

0.25-0.275

0.3-0.325

0.35-0.375

0.4-0.425

0.45-0.475

0.5-0.525

0.55-0.575

0.6-0.625

0.65-0.675

0.7-0.725

0.75-0.775

0.8-0.825

0.85-0.875

0.9-0.925

0.95-0.975

>1

Horizontal Frac Water Volume Intensity (1,000 gallons/ft)

Number of bins: 41; Bin size: 0.025; Number of data points: 506

Number of Frac Jobs

(c) 

Note: (c) uses only those “H” wells for which lateral length can be computed—histograms include only those frac 

jobs using >0.1 Mgal. 

Figure 55. Anadarko Basin—frac water use in vertical wells (a), nonvertical wells (b), and wateruse intensity in selected horizontal wells (c) 
87 

0

200

400

600

2001

2002

2003

20042005

2006

2007

2008

2009

Number of Frac Jobs

Vertical Horizontal

Figure 56. Anadarko Basin—vertical vs. horizontal and directional wells through time 

0

100

200

300

400

500

600

1950 1960 1970 1980 1990 2000 2010

Fraced Well Count

Atoka (159)

Caldwell (46)

Cleveland (651)

Granite Wash (2746)

Marmaton (240)

Figure 57. Anadarko Basin—fraced well count per formation 
88 

Source: Dutton et al. (1993, Fig. 24)

Figure 58. Distribution of Cotton Valley reservoir trends in East Texas 

0

500

1000

1500

2000

2001

2002

2003

20042005

2006

2007

2008

2009

Number of Frac Jobs

Vertical Horizontal

Figure 59. East Texas Basin—vertical vs. horizontal wells through time 

Texas Louisiana
89 

0

100

200

300

400

500

600

700

800

1950 1960 1970 1980 1990 2000 2010

Fraced Well Count

Bossier (1480)

Bossier Sand (191)

Cotton Valley Group (9555)

Cotton Valley Sand (3501)

Cotton Valley Lime (284)

James Lime (441)

Pettet (2800)

Rodessa (107)

Taylor (517) 

Travis Peak (5322)

(a) 

0

100

200

300

400

500

600

700

800

1990 1995 2000 2005 2010

Fraced Well Count

Bossier (1386)

Bossier Sand (191)

Cotton Valley Group (7421)

Cotton Valley Sand (3370)

Cotton Valley Lime (284)

James Lime (316)

Pettet (1229)

Rodessa (8)

Taylor 470) 

Travis Peak (3409)

(b) 

Figure 60. East Texas Basin—Fraced well count per formation from 1950 (a) and 1990 (b) 
90 

0

1

2

3

4

5

6

1950 1960 1970 1980 1990 2000 2010

Calendar Year

Frac Water Use (Mgal)

Average

5th Percentile

30th Percentile

Median

70th Percentile

95th Percentile

Figure 61. East Texas Basin—annual number of frac jobs (b and d) superimposed on annual 

average, median, and other percentiles of individual well frac water use (a and c) for 1950–

~2008 (a and b) and 1990–~2008 (c and d) periods 

(a) 

(b) 
91 

0

1

2

3

4

5

6

1990 1995 2000 2005 2010

Calendar Year

Frac Water Use (Mgal)

Average

5th Percentile

30th Percentile

Median

70th Percentile

95th Percentile

Figure 61. East Texas Basin—annual number of frac jobs (b and d) superimposed on annual 

average, median, and other percentiles of individual well frac water use (a and c) for 1950–

~2008 (a and b) and 1990–~2008 (c and d) periods (continued). 

(c) 

(d) 
92 

0

5

10

15

20

25

30

35

40

45

50

0-0.1

0.2-0.3

0.4-0.5

0.6-0.7

0.8-0.9

1- 1.1

1.2- 1.3

1.4- 1.5

1.6- 1.7

1.8- 1.9

2- 2.1

2.2- 2.3

2.4- 2.5

2.6- 2.7

2.8- 2.9

3- 3.1

3.2- 3.3

3.4- 3.5

3.6- 3.7

3.8- 3.9

>4

ETx - Vertical Frac Water Volume (millions gallons) - 2009-10

Number of bins: 41; Bin size: 0.1; Number of data points: 371

Number of Frac Jobs

(a) 

0

2

4

6

8

10

12

14

16

18

0-0.25

0.5-0.75

1- 1.25

1.5- 1.75

2- 2.25

2.5- 2.75

3- 3.25

3.5- 3.75

4- 4.25

4.5- 4.75

5- 5.25

5.5- 5.75

>6

ETx - Horizontal Frac Water Volume (millions gallons) - 2009-10

Number of bins: 25; Bin size: 0.25; Number of data points: 133

Number of Frac Jobs

(b) 

Note: Histograms include only those documented frac jobs using >0.1 Mgal 

Figure 62. East Texas Basin—frac water use in vertical wells (a) and horizontal wells (b) 
93 

Source: Dutton et al. (2005a—GIS files) 

Figure 63. Main clastic plays in the Permian Basin 
94 

Source: from GIS coverage of companion CD of Dutton et al. (2005a) 

Figure 64. Permian Basin geologic features 

Source: Courtesy of Stephen Ruppel and Mudrock group at BEG 

Figure 65. Regional sequence stratigraphy of the Leonardian (Permian) 
95 

Eddy Co. Lea Co.

Andrews Co.

Gaines Co.

Loving Co.

Culberson Co. Reeves Co.

Ward Co.

0 10 20 30 40 50 mi

0 20 30 40 50 60 70 80 km 10

Source: Seay Nance and the Mudrock Group at BEG 

Figure 66. Bone Spring footprint and elevation of top of Wolfcamp 

Bone Spring play boundary

Cumprod>1MM Bbls

Elevation (ft)

on top of Wolfcamp

Cumprod<1MM Bbls

Bone Spring Fields
96 

50 miles

Hoc. Ter. Lynn Martin Midland Upton Crockett Dawson

1000

2000

3000

4000

0

Northern

Slope Midland Basin

Ozona

Arch

Val

Upper Spraberry

Lower Spraberry

Dean

Wolfcamp

Cisco/Canyon

Strawn Atoka

Mssp

Woodford

“Canyon

Canyon”

Sands

Source: Scott Hamlin and the Mudrock Group at BEG; vertical scale in feet 

Figure 67. North-south Midland Basin cross section of Permian (Leonard and Wolfcamp), 

Pennsylvanian, Mississippian, and Devonian 

Figure 68. Permian Basin—annual number of frac jobs superimposed on annual average, 

median, and other percentiles of individual well frac water use (all 50,000+ wells). 
97 

 

Figure 69. Permian Basin—annual number of frac jobs superimposed on annual average, 

median, and other percentiles of individual well frac water use (water use > 0.1 Mgal) 

Figure 70. Permian Basin—annual number of frac jobs superimposed on annual average, 

median, and other percentiles of individual well frac water use (water use >0.1 Mgal since 2000) 
98 

0

100

200

300

400

500

600

0-0.1

0.2-0.3

0.4-0.5

0.6-0.7

0.8-0.9

1- 1.1

1.2- 1.3

1.4- 1.5

1.6- 1.7

1.8- 1.9

>2

Frac Water Volume (millions gallons) - Year 2008

Number of bins: 21; Bin size: 0.1; Number of data points: 2157

Number of Frac Jobs

Figure 71. Permian Basin—frac water use in vertical wells 

0

500

1000

1500

2000

2500

2001

2002

2003

2004

2005

2006

2007

2008

2009

Number of Frac Jobs

Vertical Horizontal

Figure 72. Permian Basin—vertical vs. horizontal wells through time 
99 

0

200

400

600

800

1000

1200

1400

1950 1960 1970 1980 1990 2000 2010

Fraced Well Count

Atoka/Bend (620) Bone Spring (144)

Clear Fork (15,445) Devonian (5,303)

Spraberry/Dean (23,062) Wolfcamp (6,054)

Others (1,175) Caballos/Tesnus (618)

(a) 

0

200

400

600

800

1000

1200

1400

1990 1995 2000 2005 2010

Fraced Well Count

Atoka/Bend (620) Bone Spring (144)

Clear Fork (15,445) Devonian (5,303)

Spraberry/Dean (23,062) Wolfcamp (6,054)

Others (1,175) Caballos/Tesnus (618)

(b) 

Figure 73. Permian Basin—fraced well count per formation from 1950 (a) and from 1990 (b) 

(linear scale—including Caballos/Tesnus) 
100 

10

100

1000

10000

1950 1960 1970 1980 1990 2000 2010

Fraced Well Count

Atoka/Bend (620) Bone Spring (144)

Clear Fork (15,445) Devonian (5,303)

Spraberry/Dean (23,062) Wolfcamp (6,054)

Others (1,175) Caballos/Tesnus (618)

(a) 

10

100

1000

10000

1990 1995 2000 2005 2010

Fraced Well Count

Atoka/Bend (620) Bone Spring (144)

Clear Fork (15,445) Devonian (5,303)

Spraberry/Dean (23,062) Wolfcamp (6,054)

Others (1,175) Caballos/Tesnus (618)

(b) 

Figure 74. Permian Basin—fraced well count per formation from 1950 (a) and 1990 (b) (log 

scale—including Caballos/Tesnus) 
101 

Figure 75. Caballos-Tesnus—annual number of frac jobs superimposed on annual average, 

median, and other percentiles of individual well frac water use 

0

20

40

60

80

100

120

140

160

0-0.1

0.1-0.2

0.2-0.3

0.3-0.4

0.4-0.5

0.5-0.6

0.6-0.7

0.7-0.8

0.8-0.9

0.9-1

>1

Frac Water Volume (millions gallons)

Number of bins: 11; Bin size: 0.1; Number of data points: 399

Number of Frac Jobs

Figure 76. Caballos-Tesnus—frac water volume 
102 

Figure 77. Gulf Coast Basin—annual number of frac jobs superimposed on annual average, 

median, and other percentiles of individual well frac water use 

0

300

600

900

1200

1500

2001

2002

2003

2004

20052006

2007

2008

2009

Number of Frac Jobs

Vertical Horizontal

Figure 78. Gulf Coast Basin—vertical vs. horizontal wells through time 
103 

0

50

100

150

200

250

300

350

400

450

1950 1960 1970 1980 1990 2000 2010

Fraced Well Count

Frio (3,665) Lobo (2,106)

Escondido/Navarro (417) Olmos (4,165)

San Miguel (2,383) Vicksburg (3,055)

Wilcox (6,851) Others (85)

(a) 

0

50

100

150

200

250

300

350

400

450

1990 1995 2000 2005 2010

Fraced Well Count

Frio (3,665)

Lobo (2,106)

Escondido/Navarro (417)

Olmos (4,165)

San Miguel (2,383)

Vicksburg (3,055)

Wilcox (6,851)

Others (85)

(b) 

Figure 79. Gulf Coast Basin—fraced well count per formation from 1950 (a) and 1990 (b) 
104 

0

50

100

150

200

250

300

350

400

0-0.1

0.2-0.3

0.4-0.5

0.6-0.7

0.8-0.9

>1

Vertical Frac Water Volume (millions gallons)

Number of bins: 11; Bin size: 0.1; Number of data points: 567

Number of Frac Jobs

Figure 80. Gulf Coast—frac water volume (2008) 

0

20

40

60

80

100

120

0-0.05

0.1-0.15

0.2-0.25

0.3-0.35

0.4-0.45

0.5-0.55

0.6-0.65

0.7-0.75

0.8-0.85

0.9-0.95

1- 1.05

1.1- 1.15

1.2- 1.25

1.3- 1.35

1.4- 1.45

1.5- 1.55

1.6- 1.65

1.7- 1.75

1.8- 1.85

1.9- 1.95

>2

Proppant amount (million lbs)

Number of bins: 41; Bin size: 0.05; Number of data points: 713

Number of Frac Jobs

Figure 81. Gulf Coast—proppant volume (2008) 

0

100

200

300

400

500

600

700

800

0-0.5

0.5-1

1- 1.5

1.5- 2

2- 2.5

2.5- 3

3- 3.5

3.5- 4

4- 4.5

4.5- 5

5- 5.5

5.5- 6

6- 6.56.5- 7

7- 7.5

7.5- 8

>8

Proppant Loading (lbs/gal) - 2000-2010

Number of bins: 17; Bin size: 0.5; Number of data points: 3738

Number of Frac Jobs

Figure 82. Gulf Coast—proppant loading (all years) 
105 

4.2 Oil and Gas Drilling and Waterflooding 

Besides stimulation, the oil and gas upstream industry makes use of fresh water during 

waterflooding operations and the drilling of wells. The amounts used are uncertain because they 

are not clearly documented in regulatory forms. In Texas, there is no requirement to document 

exactly the type of fluids injected in UIC Class II wells (such as those wells used for 

waterflooding); only the overall total volume and the types of fluids (by “checking a box” in the 

mandatory H10 form) need be documented, without specifying their share. A cursory calculation 

also shows that the amount of water used to develop drilling muds for the 10 to 20,000 wells 

drilled each year in the state could significantly contribute to total fresh water use in the mining 

category. U.S. DOE (2009, p. 64) put forward a figure of 400,000 and 1,000,000 gal to drill a 

well in the Barnett and Haynesville Shales, respectively. Volumes undoubtedly vary 

substantially between wells, and those horizontal wells with long laterals represent the high end 

of the range. Still, these values are significant and could have a large impact on overall mining 

water use if all the water is fresh and if the rate per well is sustained at the state level. 

4.2.1 Waterflooding

4.2.1.1 Information available before this study 

A look at historical reports suggests that the amount of fresh water used in the oil and gas 

industry has been decreasing during the past few decades. Guyton (1965, p. 40) estimated that in 

Texas (mostly Permian Basin) and southeast New Mexico, the industry used approximately 50 to 

70 thousand AF/yr of fresh water in the early 1960s for the extraction process. In the middle of 

the 20th century, the RRC used to publish biennial reports on secondary and tertiary recovery, 

including water use. The latest of such reports seems to have been published in 1982 (RRC, 

1982). Fresh-water use was reported at ~80 thousand AF in 1980 and 1981 (Table 15). The latest 

comprehensive survey of fresh-water use in the oil and gas industry dates back to the 1990s (De 

Leon, 1996), and fresh water use was estimated at ~30 thousand AF. The survey concerned 

mostly pressure maintenance, waterflooding, and other EOR techniques, but not drilling. We 

summarize next the content of the letter report. In 1996, the RRC sent a survey request of fresh 

and brackish water usage in EOR projects in 1995 to oil and gas operators. The survey was 

initiated in November 1996 using a special makeup water-survey form (Form H-17). A total of 

1,543 forms were mailed, with a return rate of ~84%. Whether the results were scaled to account 

for unresponsive operators is unclear, but they probably were not. The forms documented the 

injection of 251,716,698 bbl (32.444 thousand AF) of fresh water during calendar year 1995. 

Definition of fresh water is more lax than for the rest of this document because it includes all 

water with a TDS <3,000 mg/L. The volume of fresh water actually injected was only 7.6% of 

the total fresh water volume permitted for injection in 1995 (3.3 Bbbl). The volume of fresh 

water actually injected represents 3.3% of the total combined volume of all liquids (7.63 Bbbl) 

injected ca. 1995. The forms also documented the injection of 78,180,043 bbl (10.077 thousand 

AF) of brackish water during the same period. Brackish water in this RRC survey is defined as 

having a TDS between 3,000 and 10,000 mg/L. Brackish-water use represents about (24%) of 

the combined non-saline water. The top five counties (Gaines, Stephens, Hockley, Yoakum, and 

Andrews) represent 76% of the total fresh-water consumption, and adding five more (Cochran, 

Lubbock, Dawson, Garza, and Leon) represents 88% of the total (Table 16 and Figure 83). De 

Leon (1996) did not document the breakdown of brackish-water use by district or county. All of 

the top 10 counties belong to the Permian Basin except the last one (Leon County). A total of 55 

counties were reported by operators to receive fresh-water injection. Many others in the list are 
106 

also located in West Texas (Figure 83); RRC districts 8A+8 (~Permian Basin) correspond to 

69.4% of total fresh-water injection, and adding district 7B (>99% in Stephens County) increases 

the share to 92.0%. Adding district 7C instead of district 7B results in 69.7% of total fresh-water 

injection; a combination of districts 7C, 8, and 8A corresponds to a common definition of the 

Permian Basin using RRC districts. The large amount of water reported to have been used in 

1995 in Stephens County is anomalous, both in terms of its location and of its high county-level 

water-use coefficient (that is, water amount used in the county divided by county production) 

(Figure 84) and is investigated later because it makes up >20% of the total fresh water used in 

1995 in Texas oil fields. Recomputing the water-use coefficients by including production only 

from those fields being flooded (list provided in De Leon, 1996) still shows a high coefficient 

but within the tail of the distribution (Figure 85). Most of the fields are in the 2- to 7-bbl range of 

water/bbl of oil, although Stephens County regular fields display a water-use coefficient three 

times higher. Something like this could have happened if a large EOR operation had started 

around that time, but a look at the production of these combined fields does not show an uptick 

in production in 1995 (at ~3.7 million barrels) or shortly thereafter, but, instead, a slow decrease 

until 2002, at which time production stabilized at ~2 million bbl/yr. However, publications by 

Weiss (1992) and Weiss and Baldwin (1985) suggest that major EOR operations were ongoing at 

the time in Stephens County. 

Approximately 3⁄4 of the fresh water used in 1995 is groundwater, most of it from the Ogallala 

aquifer (~85% or ~60% of total injected fresh water). However, note that 1995 received less than 

average precipitation (NOAA historical climatological data and records for Midland) and that 

groundwater use in that year might have been anomalously high. Another important note 

concerns double-counting: in 1995 >40% of the fresh water was purchased. Anecdotal evidence 

suggests that water purchase is still current practice. There is no issue if the water was purchased 

from wholesalers, but if it was purchased from municipalities, then it may already have been 

counted toward municipal use. 

Total water use of fresh and brackish water in the oil and gas industry amounted to 330 million 

barrels (42.5 thousand AF) in 1995. RCC (http://www.rrc.state.tx.us/barnettshale/wateruse.php) 

projected that it would have decreased to 316, 276, 254, and 212 million barrels (40.7, 35.6, 

32.7, and 27.3 thousand AF) in 1998, 1999, 2000, and 2001, respectively. Note that these figures 

were extrapolated before shale-gas growth but may include reporting from tight-gas water use, 

particularly in East Texas. The basis for these figures is not explained in the RRC documents. 

4.2.1.2 Extrapolations from the RRC 1995 Survey 

Early studies suggest that most waterfloods take place in West Texas (RRC Districts 8, 8A, and 

7C; see Figure 9 for location). In addition, most of the oil produced in the state comes from the 

Permian Basin (Figure 86 and Figure 87). Only oil reservoirs are typically waterflooded. A look 

at the number of wells permitted to inject fresh water (Table 17) confirms that Districts 8 and 8A 

are the center of this practice. This section focuses on these districts. Given the current lack of 

specific reporting of fresh- and saline-water volumes, our approach is to relate known volumes 

of oil produced in 1995 with known waterflood water volumes. The 1995 RRC survey is the 

most recent comprehensive survey to be completed on waterflood water use and was used as a 

basis for estimating current water use. The RRC survey was combined with another survey 

performed for this study (Galusky, 2010). 

One way to compute future water use is to tie oil production and water use, which can be done at 

the county level and which is the elemental unit of this study (Figure 84), or at the finer field 
107 

level (Figure 85). The first step is to analyze 1995 production data vs. RRC survey 

fresh/brackish-water use (De Leon, 1996). Production numbers were extracted from the RRC 

online query engine for the calendar year 1995. At the coarsest state level, Texas produced 1134 

million barrels in 1995, resulting in an average water use of 0.22 bbl/bbl. If one considers only 

those counties that reported fresh-water use, the average climbs to 0.79 bbl/bbl for oil production 

of 319 million barrels. Average water use can be low in some counties (<1 bbl/bbl) because 

many fields may not undergo secondary or tertiary recovery, but in those counties regularly 

performing waterfloods, a reasonable average is between 1 and 2.5 bbl/bbl. Field scale seems the 

most appropriate scale for understanding water use, but even then figures depend on the stage of 

the waterflood and on the fraction of those production wells not yet impacted by the flood. 

However, given the relatively large number of fields considered (~100), we expect the data to be 

representative of waterflood water use in 1995. The “Stephen County Regular” oil field has an 

anomalously high water use, accounting for ~20+% of total 1995 fresh-water use. Overall freshwater consumption obtained by summing up all field oil production and water use and taking the 

ratio is 2.28 bbl/bbl, which is equivalent to making the average per field weighted by the field 

production. Taking the average, giving the same weight to all fields, results in a value of 5.67 bbl 

of fresh water/bbl of oil. Somewhat arbitrarily dismissing outlier fields with an average >15 or 

<1 bbl/bbl results in an average of 4.5 bbl of makeup fresh water/bbl of oil. 

A piece of information more readily available than fresh-water injection is total injected fluid 

volume (made available in RRC records as disposal in producing formations, disposal in 

nonproducing formations, and waterfloods and other secondary and tertiary recovery processes). 

Thus, in order to make fresh-water-use projections, we need an estimate of the share of fresh 

water relative to all water being injected for waterflood secondary-recovery processes. 

Unfortunately, the RRC website does not currently include injection volumes for 1995, the 

reference year for fresh-water injection, and we were not able to access the information. It does, 

however, contain injection volume at the district level for 1998 through 2002 (Table 18, Table 

19, and Figure 88). The website (http://www.rrc.state.tx.us/data/wells/statewidewells.php) breaks 

down water as injected into disposal wells (either in the producing formation or not) or for 

recovery. Here we are only interested in water used for waterflooding and other recovery 

processes that represents ~58% of total injection in this year range. Although variable across the 

years, a representative number is 3.5 million barrels, ~75% of which is injected in districts 08 

and 8A in the Permian Basin, and ~90% if districts 7B and 09 are also included. In these four 

districts, making up almost of the water used for secondary and tertiary recovery, most of the 

water is used for secondary recovery (>75%) and not disposed of (Figure 89). Percentage of 

fresh water in the total volume of water used in waterflood varies (Table 20). Contrasting 

reported waterflood volume (all water types) during the 1998–2002 period to reported fresh 

water used in 1995 suggests that, at least 10 to 15 years ago, at most 4% of waterflood water was 

fresh (later we will add correction factors). District 7C is anomalously high at ~14%; a likely 

reason is that there is less produced water available near the waterflooded field and the proximity 

of Possum Kingdom Lake in Stephens and neighboring counties. District 8A, with more than 

half of the state volume of waterflood fresh water, shows a percentage close to 10% fresh-water 

use, and close to 13% if brackish water is added. 

Closer to 2008, after a lack of data for a few years (2003–2006), the RRC website provides data 

from 2007 through an interactive query site compiled from H10 forms 

(http://webapps.rrc.state.tx.us/H10/h10PublicMain.do). However, unlike the 1998–2002 period, 

there is no breakdown in water type. A plot of injection volumes collecting 1998–2002 and 
108 

2007–2008 data sets (Figure 91) shows no major change in the injection volume pattern. A 

simple extrapolation, assuming that waterflood/total injection and fresh-water waterflood ratios 

have not changed in the past 15 years and using total injection figures from 2007 and 2008, 

results in total waterflood water use of ~28 thousand AF (Table 21), most of it in district 8A. 

This value must be considered only preliminary because, as described in the next section, adding 

correction factors more than halves this initial water-use estimate. 

4.2.1.3 Current Waterflooding Water Use 

In this section, we integrate results from the Permian Basin operator survey (Galusky, 2010). The 

survey provided information (1) on added operator reliance on brackish water as opposed to 

fresh water, (2) on switching from disposal into nonproducing formations to useful injection into 

producing intervals, and (3) increased dependence on secondary and tertiary recovery, as 

illustrated in Figure 92, with a stable water-injection level combined with decreasing oil 

production. The 1995 RRC survey (De Leon, 1996) reports a fresh-water–brackish-water split of 

~75%– 25%. New confidential, anecdotal information obtained through the informal survey of 

Permian Basin producers suggests that the 2010 fresh– brackish water split now favored brackish 

water –20% fresh water and 80% brackish water. In other words, the fraction of fresh water in 

the usable (fresh+brackish) water category went down from 75% to 20% in 15 years. In addition, 

although the information was gathered from Permian Basin operators, we assumed it valid across 

the state (error, if any, is small at the state level because most fresh water for waterflooding 

purposes is injected into the Permian Basin). We also assumed that, overall, increased reliance 

on waterfloods and other recovery processes is balanced by the increased useful use of saline 

water. 

Note that in the following developments we discuss projections to 2060, as well as current freshwater use. Both are calibrated in the same calculation with the help of the 1995 RRC survey. The 

estimation (more accurate than the preliminary estimate of the previous section) of historical and 

forecast water use for oil-field-pressure maintenance in EOR (waterfloods and CO2 floods) 

production entailed the following steps: 

a- Historical (1995–2010) annual oil production from EOR was estimated on the basis of 

published data and company surveys and anecdotal information (for waterflood oil 

production) (Figure 93). 

b- Applying and generalizing basic reservoir engineering principles, we estimated that at least 

1.3 bbl of water is required for EOR pressure maintenance for every barrel of oil produced. 

c- The fresh-water fraction of EOR makeup water in 1995 was estimated to be ~75% of the 

total. The fresh-water fraction of EOR makeup water in 2010 was estimated to be 20% of the 

total and was taken from the returned company surveys. We assumed that there has been a 

linear decline in the fraction of fresh water used in EOR between these periods and that this 

decline will continue until it reaches a value of 5% by 2023, at which point we forecast that it 

will hold this percentage through 2060. 

d- We estimated the fraction of oil production from EOR in 1995 to be approximately 61% of 

total oil production and assumed that this fraction increased linearly to a value of 66% in 

1997, as estimated by RRC. We then held this rate of annual increase through the last year of 

the forecast period of 2060. Anecdotal evidence (for example, Henkhaus, 2007) suggests that 

about #of the oil is produced through EOR processes. 
109 

e- Total annual oil production was forecasted by extrapolating 1995– 2010 production through 

2060 using a simple exponential decline curve. 

f- Makeup water use was then estimated by multiplying the total annual oil production times the 

fraction of oil production from EOR, times the makeup water factor (1.3 bbl water/bbl oil as 

described earlier), times the respective water fractions (fresh versus saline/brackish). Makeup 

water use was calculated in this way for both the historical period of record (1995–2010) and 

forecasted through the year 2060. This calculation was done on the basis of aggregate 

regional oil production and on a county-level basis, according to their respective historical 

and forecast total annual oil production values. 

A simple scaling was then applied to those counties outside of districts 8, 8A, and 7C according 

to their fresh-water use in 1995 and total injection volume in the 2002–2005 period. The statelevel estimated 2008 water use for nonprimary recovery processes is ~13 and 25.5 thousand 

AF for fresh and brackish water, respectively (Figure 94 and Table 22). As expected, the 

spatial distribution of waterflood water use is heavily weighted toward the Permian Basin 

(Figure 96). We are reasonably confident in the total of 38.5 thousand AF, but less in the 

distribution between fresh and brackish categories. 

4.2.2 Drilling

The number of holes drilled per year in the past 50 years has varied from 30,000+ to <10,000, 

whereas the number of oil and gas wells completed during the same period has varied from 

5,000+ to <25,000 (Figure 95). The holes-drilled category includes, in addition to completed 

wells, dry holes, service wells, and the like. The past decade has seen a steady increase in the 

number of wells drilled per year in Texas, which was interrupted only by the recent economic 

slowdown. A significant fraction is related to recent shale-gas production (gas-well curve 

crossing over the oil-well curve in Figure 95), but the recent interest in unconventional oil is also 

visible; many other wells were drilled in conventional reservoirs. 

Well drilling requires a fluid carrier to remove the cuttings and dissipate heat created at the drill 

bit. The fluid also keeps formation-water pressure in check. Broadly, three types of fluids are 

used: (1) air and air mixtures, (2) water-based muds, and (3) oil-based muds. By far the most 

common method involves water-based muds. Clean water is needed to optimize the mud 

performance. Air drilling is traditionally used in the thick unsaturated zone with no source of 

water nearby or low-permeability formations with sufficient strength, but it is becoming more 

popular (U.S. DOE, 2009, p. 55), as in the Marcellus Shale in Pennsylvania, in which many 

wells are drilled in the formation with little added water. For similar subsurface conditions, 

drilling practices differ from region to region, and we did not attempt a comprehensive study of 

drilling practices. Oil-based mud is typically used at greater depths or when sensitive clays, for 

example, could be a problem. As a general rule, a water-supply well (typically the most 

convenient way of obtaining water) is drilled next to the drilling site, although the amount of 

water used is not always metered. The amount of water required is what is needed to fill up the 

well bore, as well as the mud pit (must be large enough to allow time for the fine rock cutting to 

settle), if neither a closed loop is used nor auxiliary equipment. An additional factor is that for 

many wells, the mud system has to be changed, at least partly, in the course of the drilling. An 

approximate rule of thumb would be to multiply the borehole volume by some coefficient. 

Anecdotal evidence suggests that this multiplier could range from 3 to 6 or higher. Additional 

water is used to wash equipment to prepare the cement slurry for these wells to be completed. A 
110 

proper cement set up also requires clean water. Overall, the water used is typically fresh or 

slightly brackish; produced water is typically not used because it is dirty and the operator would 

need to treat it at a cost before using it. 

Several approaches were followed to collect data on drilling-water use: (1) survey of operators in 

the Permian Basin (Galusky, 2010), (2) borehole-volume approach with information downloaded 

from the IHS database, and (3) other, less structured evidence gathered from the literature and 

through informal discussion with site engineers. 

The last category includes documentation published by Chesapeake (2009) of 400,000 gal/well 

in the Barnett Shale, 600,000 gal/well in the Haynesville Shale, and 125,000 gal/well in the 

Eagle Ford Shale (Marcellus consumes only 100,000 gal/well). A Chesapeake Barnett well is 

drilled all the way using water-based mud. The Haynesville is typically much deeper than the 

Barnett, and the horizontal section is drilled using oil-based mud, whereas most of a Chesapeake 

Marcellus well is drilled using oil-based muds except for the air-drilling USDW section (M. E. 

Mantell, personal communication, 2010). No data were collected on the drilling approach in the 

Eagle Ford Shale. Computing average well-bore volume from the IHS database for the 

Chesapeake Barnett and Haynesville wells (17.3 and 36 thousand gallons, respectively) provides 

a multiplier on the order of 15. Barnett Shale survey results from Galusky (2007, p. 7 and Table 

1) indicate that, in 2006, about 10% of total water use was dedicated to drilling, that is, 150,000 

to 300,000 gal/well. The split between groundwater and surface water is likely to be similar to 

that of completion (about equal) for those fraced wells. However, the split is unknown for 

nonfraced wells, although likely to favor groundwater because laying pipes from surface-water 

bodies would be prohibitively expensive to obtain the relatively small amount of water needed 

for drilling. More anecdotal evidence from the Middle Pecos GCD suggests that water use for 

well drilling was in the range of 200,000 to 300,000 gal/well in 2009. A significant fraction of 

major and minor aquifers in Pecos County are brackish, however, so average fresh water is 

probably about half of this figure. A rule of thumb applicable at least in the Permian Basin 

suggests 0.3 to 1 bbl/ft, that is, between 75,000 and 250,000 gal/well for a 6,000-ft-deep well. In 

Texas, many wells are drilled to the 5,000- to 7,000-ft depth range because many reservoirs are 

located around those depths (Nicot, 2009b). Another rule of thumb heard during this study was 1 

barrel of water per cubic foot of hole, which translates into a multiplier of 5.6. 

The borehole-volume approach consists of extracting dimension information about all wells 

drilled in Texas in a given year (Table 23), correcting for those wells with no casing information 

(20% on average) and applying a multiplier to estimate drilling-water use. The average Texas 

well has a volume of ~15,000 gallons. Clearly, the deeper the well, the larger the water use. 

However, the increase is not linear for several reasons: borehole diameter decreases with depth 

in a stepwise fashion, the use of several mud systems is more likely, surface installation are 

larger. We initially used a multiplier of five to find average drilling-water use during the past 

decade of ~3,000 AF, varying from 2.4 to 4.6 thousand AF/yr. However, in light of survey 

returns (see later section) and increased interest in generally deeper gas shales, a multiplier of 10 

seemed more realistic, resulting in an initial preliminary estimate for average drilling-water use 

of 6 thousand AF/yr in the past decade across the state. 

The third approach consisted of accessing the information through an operator survey in the 

Permian Basin (Galusky, 2010) in districts 8, 8A, and 7C, which consistently represent one-third 

of the wells drilled in Texas (Table 24). A reasonable value used for the computation was 

~130,000 gal/well (0.41 AF/well) of fresh water combined with ~500,000 gal/well (1.59 
111 

AF/well) of brackish and saline water. This computation resulted in total water use for the three 

districts of ~2,300 AF in 2008 (~6,300 wells spudded according to IHS database) and ~2,200 AF 

in 2010, amounts not predicted to grow unless shale-gas production takes hold in a strong way in 

West Texas. 

Although not negligible at the state level, drilling water use is distributed across all oil- and gasproducing counties in the state. In 2008, about ~20,000 wells had been spudded in Texas (IHS 

database and RRC website). Barnett Shale Tarrant and Johnson Counties had the most wells 

spudded, 825 and 890, respectively. Assuming an average 0.4 million gal water use per well 

(conservative because vertical wells are also included in the count) results in drilling-water use 

of 1,000 AF in each county. Next are Permian Basin counties (Andrews, Upton, Ector, Pecos, 

Webb, Martin, and Midland, in decreasing order of number of wells), with 550 to ~250 wells 

spudded per county in 2008, resulting in 0.23 to 0.1 thousand AF per county. A final figure of 

130,000 gal/well for 20,000 wells was eventually retained, leading to a drilling-fresh-water use 

of 8.0 thousand AF. Note that reuse is likely occurring in the drilling field as flowback water 

from fracing operations can be used for drilling additional wells. There is no data on how 

widespread the practice is. 
112 

Table 15. Historical water use in secondary and tertiary recovery (million barrels) 

Saltwater Brackish Water Fresh Water BW FW 

(million bbl) 

District 1980 1981 1980 1981 1980 1981 1995 1995 

1 13.0 12.4 13.3 17.3 4.5 3.4 1.4

2 31.6 20.6 0.0 0.0 0.0 0.0 0.0

3 71.6 59.9 0.0 0.0 0.1 0.0 0.0

4 84.8 79.6 0.1 0.0 0.0 0.0 0.0

5 14.3 9.3 0.0 0.0 1.1 1.0 4.2

6 57.8 57.5 2.4 2.4 23.8 24.6 8.5

6E 0.5 1.6 5.1 6.2 1.0 1.0 0.8

7B 131.6 133.5 1.7 1.4 46.0 41.5 57.0

7C 53.2 52.1 8.3 6.7 5.8 4.7 1.0

8 603.8 617.2 462.7 440.4 73.5 81.2 19.3

8A 791.3 855.1 42.1 41.0 453.3 413.3 155.3

9 277.8 292.3 3.3 3.3 12.4 12.1 1.1

10 19.6 20.5 0.0 0.0 15.9 14.5 3.1

Total 2150.9 2211.6 539.1 518.7 637.5 597.3 78.2 251.7

Source: RRC (1982) and De Leon (1996) 

Table 16. Fresh-water use in EOR operations (1995 RRC survey) 

County 

Fresh-Water 

Use (bbl) County 

Fresh-Water Use 

(bbl) County 

Fresh-Water 

Use (bbl) 

Gaines 59,347,090 Frio 1,076,890 Williamson 95,238

Stephens 56,208,617 Irion 963,590 Bastrop 88,625

Hockley 42,684,399 Scurry 896,000 Ward 73,000

Yoakum 19,466,366 Gregg 818,571 Bowie 70,262

Andrews 12,520,625 Marion 640,379 Cass 54,750

Cochran 8,857,214 Franklin 628,405 Stonewall 44,147

Lubbock 8,146,162 Nolan 557,791 Panola 42,323

Dawson 5,517,713 Young 534,265 Hardin 40,783

Garza 4,448,645 Winkler 365,000 Atascosa 22,850

Leon 4,203,810 Howard 220,462 Jack 15,602

Ector 3,574,347 Martin 214,778 Archer 4,305

Anderson 3,145,589 Dickens 196,060 Coleman 3,000

Gray 3,145,143 Clay 194,280 Callahan 1,800

Hale 2,421,237 Rusk 163,173 Tom Green 375

Terry 2,139,628 Eastland 158,393 Wilson 45

Smith 1,933,184 Zavala 143,054 

Wood 1,658,113 Cooke 134,394 Total (bbl) 251,716,698 

Pecos 1,257,715 Camp 120,745 Total (AF) 32,444 

Lynn 1,149,368 Knox 117,233 

Mitchell 1,090,170 Wichita 100,995 

Source: De Leon (1996) FreshWater+OilProduction_RCC1995.xls 

Historical Injection 2=fromRRC1982Report.xls
113 

Table 17. Number of permitted fresh-water injection wells as of January 2010 

District 

Injection into 

Nonproducing 

Intervals 

Injection into 

Production 

Formation 

Secondary 

Recovery Total 

01 5 18 380 403 

02 1 1 0 2 

03 0 1 3 4 

04 3 0 5 8 

05 1 0 68 69 

06 3 42 244 289 

6E 0 8 40 48 

7B 1 39 628 668 

7C 0 5 87 92 

08 1 81 3,961 4,043 

8A 5 368 9,075 9,448 

09 2 12 112 126 

10 2 30 199 231 

Total 24 605 14,802 15,431 

Source: Fernando De Leon (RRC, January 2010) custom data pull 

Table 18. District-level total water injection volume vs. waterflood volumes (1998) 

1998—All volumes in bbl 

District 

Disposal in 

nonprod. zone 

Disposal in 

prod. zone Waterflood Other Total 

Waterflood/ 

Total 

1 221,676,839 36,224,868 21,626,651 0 279,528,358 7.7%

2 121,625,598 29,673,891 58,255,145 0 209,554,634 27.8%

3 378,303,159 77,043,184 38,606,639 1,653,895 495,606,877 7.8%

4 77,713,906 19,949,912 29,217,354 0 126,881,172 23.0%

5 24,783,981 29,833,615 15,594,964 0 70,212,560 22.2%

6 122,873,017 73,922,979 53,064,690 0 249,860,686 21.2%

6E 0 356,784,106 26,290,016 0 383,074,122 6.9%

7B 25,100,019 28,512,343 321,250,271 0 374,862,633 85.7%

7C 45,307,377 73,054,222 79,496,652 0 197,858,251 40.2%

8 139,510,861 208,640,430 1,203,840,221 341,660 1,552,333,172 77.6%

8A 68,752,368 115,105,922 1,211,495,952 0 1,395,354,242 86.8%

9 24,556,396 36,674,585 198,195,141 15,370 259,441,492 76.4%

10 25,714,081 24,599,525 20,115,688 0 70,429,294 28.6%

Totals: 1,275,917,602 1,110,019,582 3,277,049,384 2,010,925 5,664,997,493 57.8%

Source: RRC website 

http://www.rrc.state.tx.us/data/wells/statewidewells.php

Note: includes all water types (fresh to saline, produced and others) 

InjectionVolume 2002 RRC +1998-2001.xls
114 

Table 19. District-level total water-injection volume vs. waterflood volumes (2002) 

Year 2002—All volumes in bbl 

District 

Disposal in 

nonprod. 

zone 

Disposal in 

prod. zone Waterflood Other Total 

Waterflood

/ Total 

1 209,482,615 29,795,963 12,464,957 0 251,743,535 5.0%

2 112,608,696 20,504,067 56,234,669 0 189,347,432 29.7%

3 323,989,781 71,070,254 23,308,202 292,511 418,660,748 5.6%

4 84,577,088 13,963,848 21,024,812 0 119,565,748 17.6%

5 36,118,853 28,867,538 15,452,586 0 80,438,977 19.2%

6 149,292,665 86,293,340 41,801,873 0 277,387,878 15.1%

6E 158,881 348,180,269 31,694,999 0 380,034,149 8.3%

7B 24,602,044 26,477,559 252,445,261 1,528 303,526,392 83.2%

7C 40,711,999 63,911,860 88,144,873 0 192,768,732 45.7%

8 152,802,343 194,498,880 1,163,394,951 159,900 1,510,856,074 77.0%

8A 65,416,720 114,281,934 1,258,302,110 0 1,438,000,764 87.5%

9 26,395,288 30,699,374 156,616,151 27,386 213,738,199 73.3%

10 16,073,237 19,443,141 16,880,842 0 52,397,220 32.2%

Totals: 1,242,230,210 1,047,988,027 3,137,766,286 481,325 5,428,465,848 57.8%

Source: RRC website 

http://www.rrc.state.tx.us/data/wells/statewidewells.php

Note: includes all water types (fresh to saline, produced and others) 

Table 20. Estimated district-level fraction of fresh-water in waterflood water volumes 

District 

Waterflood water use 

average (all types) 

1998–2002 

(million bbl) 

1995 fresh-water use 

(million bbl) Fresh / Total 

Fresh + 

Brack 

/ Total* 

01 267.0 1.43 0.53% 0.70%

02 

03 496.5 0.04 0.01% 0.01%

04 

05 81.6 4.20 5.15% 6.75%

06 288.4 8.46 2.93% 3.84%

6E 420.7 0.82 0.19% 0.00%

7B 393.8 56.97 14.47% 18.95%

7C 223.6 0.96 0.43% 0.56%

08 1,689.3 19.32 1.14% 1.50%

8A 1,578.3 155.27 9.84% 12.89%

09 252.1 1.10 0.44% 0.57%

10 69.6 3.15 4.52% 5.92%

Totals 5,760.8 251.72 4.37% 5.59%

*Obtained by multiplying by the same coefficient of 1.31 for all districts to account for brackish-water use 

InjectionVolume_2002_RRC_+1998-2001.xls 

InjectionVolume 2002 RRC +1998-2001.xls
115 

Table 21. Initial guess for extrapolated district-level fresh-water use for waterfloods 

District 

1998–2002 Average 

Fraction of 

Waterflood vs. Total 

Injection 

1995 Fresh-Water 

Use Fraction vs. 

Total Waterflood 

Average 

2007–2008 

Total 

Injection 

(million bbl) 

Extrapolated 

Fresh-Water 

Use (thousand 

AF) 

01 6.1% 0.53% 485.0 0.02 

02 28.5% 0% [213.7] 

03 6.3% 0.01% 469.0 0.00 

04 20.3% 0% [137.0] 

05 19.8% 5.15% 197.0 0.26 

06 11.7% 2.93% 756.6 0.15 

7B 84.8% 14.47% 388.0 6.13 

7C 42.9% 0.43% 287.5 0.07 

08 77.2% 1.14% 1,652.7 1.88 

8A 87.5% 9.84% 1,716.3 19.03 

09 74.0% 0.44% 263.9 0.11 

10 31.5% 4.52% 105.7 0.19 

Total 58.2% 4.37% 6321.62 27.85 

Table 22. County-level estimate of fresh-water use for waterfloods 

County 

Fresh

2008 

Fresh

2010 

Brack

2008 

Brack

2010 County 

Fresh

2008 

Fresh

2010 

Brack.

2008 

Brack.

2010 

State Total 12.95 7.87 25.52 29.91 

Anderson 0.013 0.008 0.026 0.031 Lipscomb 0.005 0.003 0.009 0.011

Andrews 0.552 0.384 1.243 1.457 Loving 0.038 0.074 0.240 0.282

Archer 0.005 0.003 0.009 0.010 Lubbock 0.359 1.307 4.239 4.968

Atascosa 0.001 0.001 0.002 0.002 Lynn 0.051 0.207 0.670 0.785

Baylor 0.000 0.000 0.001 0.001 Marion 0.001 0.001 0.002 0.002

Borden 0.123 0.000 0.000 0.000 Martin 0.009 0.084 0.273 0.320

Brown 0.008 0.005 0.016 0.018 Maverick 0.001 0.001 0.003 0.003

Callahan 0.029 0.018 0.057 0.067 McCulloch 0.010 0.009 0.029 0.034

Camp 0.004 0.003 0.009 0.010 McMullen 0.001 0.000 0.001 0.001

Carson 0.001 0.000 0.001 0.001 Menard 0.002 0.250 0.809 0.948

Clay 0.002 0.001 0.004 0.004 Midland 0.328 0.035 0.114 0.134

Cochran 0.390 0.005 0.017 0.020 Mitchell 0.048 0.003 0.009 0.011

Coke 0.034 0.109 0.355 0.416 Montague 0.006 0.004 0.012 0.014

Coleman 0.035 0.021 0.068 0.080 Moore 0.001 0.001 0.003 0.003

Comanche 0.001 0.000 0.001 0.001 Motley 0.004 0.027 0.089 0.104

Concho 0.027 0.108 0.351 0.412 Navarro 0.004 0.002 0.007 0.008

Cooke 0.007 0.004 0.014 0.016 Nolan 0.074 0.045 0.146 0.171

Cottle 0.002 0.007 0.022 0.026 Ochiltree 0.006 0.004 0.012 0.015

Crane 0.399 0.027 0.086 0.101 Oldham 0.005 0.003 0.010 0.012

InjectionVolume 2002 RRC +1998-2001 1.xls
116 

County 

Fresh

2008 

Fresh

2010 

Brack

2008 

Brack

2010 County 

Fresh

2008 

Fresh

2010 

Brack.

2008 

Brack.

2010 

Crockett 0.086 0.007 0.021 0.025 Palo Pinto 0.029 0.018 0.058 0.068

Crosby 0.020 0.228 0.739 0.866 Pecos 0.055 0.066 0.212 0.249

Culberson 0.007 0.033 0.108 0.127 Potter 0.001 0.000 0.001 0.002

Dawson 0.243 0.039 0.125 0.146 Reagan 0.152 0.024 0.077 0.090

Dickens 0.009 0.000 0.000 0.000 Red River 0.001 0.001 0.003 0.003

Dimmit 0.001 0.000 0.001 0.002 Reeves 0.027 0.019 0.061 0.071

Eastland 0.115 0.070 0.228 0.267 Runnels 0.027 0.060 0.194 0.228

Ector 0.158 0.019 0.061 0.072 Rusk 0.019 0.011 0.037 0.044

Fisher 0.150 0.091 0.295 0.345 Schleicher 0.016 0.030 0.096 0.112

Floyd 0.000 0.031 0.101 0.119 Scurry 0.039 0.000 0.000 0.000

Foard 0.001 0.001 0.002 0.002 Shackelford 0.075 0.046 0.148 0.173

Franklin 0.002 0.001 0.004 0.004 Sherman 0.003 0.002 0.006 0.007

Freestone 0.002 0.001 0.004 0.005 Smith 0.007 0.004 0.014 0.016

Gaines 2.616 0.002 0.007 0.008 Stephens 1.786 1.086 3.520 4.126

Garza 0.196 0.011 0.036 0.042 Sterling 0.045 0.007 0.023 0.027

Glasscock 0.156 0.085 0.276 0.324 Stonewall 0.218 0.132 0.430 0.503

Gray 0.024 0.014 0.047 0.055 Sutton 0.001 0.001 0.005 0.005

Grayson 0.002 0.001 0.004 0.004 Taylor 0.025 0.015 0.049 0.057

Hale 0.107 0.271 0.880 1.031 Terrell 0.004 0.106 0.343 0.401

Hansford 0.002 0.001 0.003 0.004 Terry 0.094 0.019 0.061 0.072

Hartley 0.003 0.002 0.005 0.006 Throckmorton 0.069 0.042 0.137 0.160

Haskell 0.031 0.019 0.061 0.072 Titus 0.003 0.002 0.005 0.006

Hockley 1.881 0.001 0.004 0.005 Tom Green 0.032 0.011 0.036 0.042

Hopkins 0.015 0.009 0.029 0.034 Upshur 0.012 0.007 0.024 0.028

Howard 0.010 0.014 0.046 0.053 Upton 0.315 0.000 0.001 0.002

Hutchinson 0.006 0.004 0.013 0.015 Van Zandt 0.019 0.012 0.038 0.044

Irion 0.042 0.169 0.548 0.642 Ward 0.003 0.003 0.010 0.012

Jack 0.001 0.001 0.002 0.002 Wheeler 0.001 0.000 0.001 0.002

Jones 0.041 0.025 0.080 0.094 Wichita 0.020 0.012 0.040 0.047

Kent 0.297 0.006 0.019 0.023 Wilbarger 0.003 0.002 0.005 0.006

King 0.121 1.818 5.893 6.907 Wilson 0.001 0.000 0.001 0.001

Knox 0.001 0.001 0.002 0.003 Winkler 0.016 0.022 0.071 0.083

Lamb 0.013 0.136 0.442 0.518 Wood 0.006 0.004 0.012 0.014

Leon 0.019 0.011 0.037 0.043 Yoakum 0.858 0.219 0.709 0.832

Limestone 0.001 0.001 0.002 0.003 Young 0.003 0.002 0.005 0.006

InjectionVolume_2002_RRC_+1998-2001_1.xls 
117 

Table 23. Estimated and calculated oil and gas well drilling water use 

No. of 

Wells 

w/ 

Casing 

Data 

Average 

Borehole 

Volume 

(gal/well) 

Total 

BH 

Volume 

(Mgal) 

Total 

BH 

Volume 

(Th. AF) 

Total 

No. of 

Wells 

Corrected 

Total BH 

Volume 

(Th. AF) Multiplier 

Water 

Use 

(Th. AF 

/yr) 

2009 9,019 16,093 145.1 0.445 11,542 0.570 10 5.70

2008 16,311 15,585 254.2 0.780 19,121 0.915 10 9.15

2007 14,513 15,168 220.1 0.676 16,930 0.788 10 7.88

2006 13,273 14,890 197.6 0.607 15,832 0.723 10 7.23

2005 11,535 15,744 181.6 0.557 13,929 0.673 10 6.73

2004 9,964 15,851 157.9 0.485 12,488 0.607 10 6.07

2003 9,067 15,709 142.4 0.437 11,539 0.556 10 5.56

2002 7,013 16,203 113.6 0.349 9,146 0.455 10 4.55

2001 8,676 15,628 135.6 0.416 11,504 0.552 10 5.52

2000 7,412 14,897 110.4 0.339 10,411 0.476 10 4.76

Source: IHS database 

Table 24. New drill per district 

District 01 02 03 04 05 06 7B 7C 08 8A 09 10 Total 

2006 369 510 451 1,354 555 1612 409 1,539 1,557 778 1,614 1,003 12,188

2007 354 398 422 982 621 1,968 327 1,565 1,789 698 2,214 952 12,291

2008 428 447 496 1,162 678 1,884 689 2,033 2,368 532 3,492 1,046 15,255

Source: RRC website 

Results 2000-2009 1.xls.xls
118 

Source: 1995 RRC survey 

Figure 83. Map of counties using fresh water in EOR operations according to the 1995 RRC data 

(1 million bbl = 129 AF) 
119 

0

10

20

30

40

>0-0.5

0.5-1

1-1.5

1.5-2

2-2.5

2.5-3

3-3.5

3.5-4

4-4.5

4.5-5

5-5.5

5.5-6

6-6.5

6.5-7

7-7.5

7.5-8

8-8.5

8.5-9

9-9.5

9.5-10

>10

Water use (bbl fresh water / bbl oil)

Number of Counties with Fresh Water Use

0

10

20

30

40

50

% of Total Fresh Water Use

Williamson Co. Stephens Co.

1995 <3,000 mg/L water use 252 millions bbl

1995 Texas oil production: 1,134 millions bbl (0.22 bbl/bbl)

1995 fresh water using counties

 oil production 319 millions bbl (0.79 bbl/bbl)

Note: obtained by dividing fresh-water use as reported by RRC by county production regardless of the actual 

number of fields being waterflooded

Figure 84. Histogram (year 1995) of county-level waterflood water-use coefficient (wide 

columns) and fraction of total fresh-water use for each bin 

0

10

20

30

40

>0-1

1-2

2-33-4

4-5

5-6

6-7

7-8

8-9

9-10

10-11

11-12

12-1313-14

14-15

15-1616-17

17-1818-19

19-20

>20

Water use (bbl fresh water / bbl oil)

Number of Fields with Fresh Water Use

0

10

20

30

% of Total Fresh Water Use

Stephens County

Regular Oilfield

Figure 85. Histogram (year 1995) of water-use coefficient in waterflooded oil fields (wide 

columns) and fraction of total fresh-water use for each bin 

FreshWater+Oil Production RCC1995.xls

FreshWater+OilProduction RCC1995.xls
120 

Source : Dutton et al. (2005a, Fig. 130) 

Figure 86. Production histories of significant-sized oil reservoirs in the Permian Basin by 

lithology 

0

50

100

150

200

1993 1995 1997 1999 2001 2003 2005 2007 2009

Calendar Year

Oil Production (million bbl)

01

02

03

04

05

06

6E

7B

7C

08

8A

09

10

Source: RRC online system http://webapps.rrc.state.tx.us/PDQ/generalReportAction.do 

Figure 87. Annual oil production per district (1993–2009) 

FreshWater+OilProduction_RCC1995.xls 
121 

1

10

100

1,000

10,000

01

0203

04

0506

6E

7B7C

08

8A

0910

Total

RRC Districts

 Waterflood Injection Volume 

(million Bbl)

1998 1999 2000 2001 2002

0

400

800

1,200

1,600

2,000

0102

0304

05

06

6E

7B

7C

08

8A

09

10

RRC Districts

 Waterflood Injection Volume 

(million Bbl)

1998 1999 2000 2001 2002

Source: RRC website http://www.rrc.state.tx.us/data/wells/statewidewells.php 

Note: figures were corrected by the statewide correction factor for incomplete data (typically 10% more than 

reported) 

Figure 88. RRC district-level annual waterflood-dedicated injection volume in Texas (1998–

2002): (a) log scale, (b) linear scale 

(a) 

(b) 

InjectionVolume 2002 RRC +1998-2001.xls
122 

0%

25%

50%

75%

100%

1998

1999

2000

2001

2002

Calendar Year

 Fraction of Injected Water 

used for Waterflooding

01

02

03

04

05

06

6E

7B

7C

08

8A

09

10

Total

Source: RRC website 

http://www.rrc.state.tx.us/data/wells/statewidewells.php

Figure 89. RRC district-level fraction of injected water (of all types) used for waterflooding 

0

150

300

450

600

1993 1995 1997 1999 2001 2003 2005 2007 2009

Calendar Year

Oil Production (million bbl)

08 8A

08 and 8A Total

Source: RRC online system http://webapps.rrc.state.tx.us/PDQ/generalReportAction.do 

Figure 90. Oil production in districts 8 and 8A 

InjectionVolume 2002 RRC +1998-2001.xls

FreshWater+OilProduction_RCC1995.xls 
123 

1

10

100

1,000

10,000

01

02

03

04

05

06

7B

7C

08

8A

09

10

Total

RRC Districts

 Total Water Injection Volume 

(million Bbl)

1998 1999 2000 2001 2002 2007 2008

0

400

800

1,200

1,600

2,000

01

02

03

04

05

06

7B

7C

08

8A

09

10

RRC Districts

 Total Water Injection Volume 

(million Bbl)

1998 1999 2000 2001 2002 2007 2008

Source: RRC website http://www.rrc.state.tx.us/data/wells/statewidewells.php for years 1998 to 2002 and 

http://webapps.rrc.state.tx.us/H10/h10PublicMain.do for years 2007 and 2008 

Note: districts 6 and 6E are now combined 

Figure 91. RRC district annual total water (of all types) injection volume (1998–2002 and 2007–

2008): (a) log scale, (b) linear scale 

(a) 

(b) 

InjectionVolume_2002_RRC_+1998-2001.xls 
124 

2,500

2,700

2,900

3,100

3,300

3,500

1998

1999

2000

2001

2002

2003

2004

2005

20062007

2008

Calendar Year

Water Volume (million bbl)

200

220

240

260

280

300

Oil Prouction (million bbl)

Waterflood (including saline water)

Total Water (including disposal)

Oil Production

Districts 08 and 8A

Figure 92. Comparison of oil production and water injection in RRC districts 08 and 8A (1998–

2008) 

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1990 2000 2010 2020 2030 2040 2050 2060

Calendar Year

Oil Production (million bbl/day)

Total Est. Waterflood

Est. CO2 Flood Est. Total EOR

Note: data only for historical total production 

Figure 93. Historical and forecast for oil production in districts 8, 8A, and 7C 

InjectionVolume_2002_RRC_+1998-2001.xls 

PB Oil Production & Water Use Summary 10.14.10 lpg_JP.xlsx 
125 

0

10

20

30

40

50

1990 2000 2010 2020 2030 2040 2050 2060

Calendar Year

Water Use (thousand AF)

Fresh Water Brackish Water Fresh+Brackish

Note: Only data points are from 1995 RRC survey 

Figure 94. Estimated current and projected fresh- and brackish-water use for pressure 

maintenance and secondary and tertiary recovery operations 

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

1960 1965 1970 1975 1980 1985 1990 1995 2000 2005 2010

Calendar Year

Number of Wells

Oil Well Completed Gas Well Completed Holes Drilled

Source: RRC website http://www.rrc.state.tx.us/data/drilling/txdrillingstat.pdf 

Note: completions include mostly new drills but also re-entered and recompleted wells (10-15% of total) 

Figure 95. Number of holes drilled and of oil and gas wells completed in Texas between 1960 

and 2009 

InjectionVolume_2002_RRC_+1998-2001.xls 

WellCount 1.xls
126 

Figure 96. Estimated fresh-water use for waterfloods (2008) 
127 

4.3 Coal and Lignite 

Total coal production for 2009 was >1 billion short tons for the country, 35+ million short tons 

of which the state of Texas produced (Table 1). Currently Texas has 11 active coal mines or 

groups of mines, with 2 mines (Kosse and Twin Oak mines) coming fully online in the next few 

years (Figure 97).Total production has been decreasing for 2 decades (Figure 98 with more 

details in Figure 100). All mines are above ground, mining lignite grade resources to a depth of 

250 ft. All coal operations in Texas are currently mine-mouth, meaning the coal is used to power 

a power plant or other facility close to the mine. All mines with significant production in the past 

decades are still in operation, except for Sandow transitioning to the adjoining Three Oaks, both 

operated by ALCOA, Inc., (Williams, 2004) and the two Gibbons Creek locations (operated by 

the Texas Municipal Power Agency, TMPA–Bryan College Station), idle since 1996. The survey 

went only to current operators. From north to south, mines with recent activity as listed on the 

RRC website are given in Table 25. 

In general, coal-mining processes require water during operations for activities such as dust 

suppression, waste disposal, reclamation and revegetation, coal washing, transportation, and 

drilling. In Texas, coal mining does not require drilling, coal washing, or transportation by slurry 

pipeline, and water use is limited to dust suppression and equipment washing. However, there is 

a need for dewatering and depressurization for most mines (Table 26). The water pumped is 

either discharged into a lake or stream or first discharged into a retention or sedimentation pond 

and then routed to a lake or stream. Therefore, once the water has been initially pumped from the 

ground to allow initial mining to occur, the water becomes available for use as surface water. 

Many mines also contract additional water from water-supply wells and water rights in order to 

supply fresh water to office operations (Table 27). Additionally, water for mining activities such 

as dust suppression and hauling activities may come either from these separate water-supply 

wells or from the retention ponds. Tracking where the water is routed, from where and what it is 

used, and the exact amount of consumption prove to be a difficult task. Whereas agencies track 

water pumped for operations and discharged into local surface waters, no central agencies tracks 

the entire operation when it comes to mining. The TWDB sends a survey to operators for 

groundwater pumped from water-supply wells, whereas the RRC tracks water pumped for 

depressurization and dewatering. Additionally, mining operators must report water-quality 

information on discharged water to lakes and streams to TCEQ. In order to further delineate the 

data, a questionnaire (Appendix D) was sent to mining operators regarding their water usage via 

TMRA. 

In 2009, 37.1 million short tons of lignite was produced in the state, requiring production of 25.7 

thousand AF of water and resulting in an average raw water use of 227.5 gal/st. However, 

including only consumption (and not dewatering), the same coal production required only 2.6 

thousand AF or 22.8 gal/st. For comparison purposes, Chan et al. (2006) reported that, in 2003, 

given national coal-production statistics, a rough estimate of overall water required for coal 

extraction (mining and washing) ranged roughly from 86 to 235 million gal/day for an overall 

coal production of 1,071.7 million short tons, including 86.4 million short tons of lignite (EIA) 

(30 to 80 gal/st). These nationwide numbers represent a mix of uses, coal washing for 

Appalachian and interior coals, depressurization for lignite, and slurry pipelines. 

The Sandow mine used to contribute a large fraction of total coal-mining water use (Figure 99), 

more than half of the ~40,000 AF/yr of produced groundwater until 2008. The current overall 
128 

amount is <20,000 AF/yr. Currently no mine comes close to the threshold of 10 thousand AF/yr. 

However, surface water is also used in some mines, according to data we collected for the years 

2009–2010. Overall, we assumed that the amount and distribution of the water used in 2009–

2010 are very similar to those used in 2008 (year chosen as representative) in the coal industry. 

Luminant mines in East Texas (Monticello Thermo, Monticello Winfield, Oak Hill, Martin Lake, 

and Big Brown) have a total water use of between 1 and 2.5 thousand AF/yr, which is mostly due 

to overburden dewatering, do not need to be depressurized (or very little), and have to pump 

supplementary (variable across mines) amounts of water to satisfy their operational needs. All of 

the water is fresh and is used mostly for dust suppression. An additional mine in the same Sabine 

Uplift area (South Hallsville in Harrison County operated by Sabine Mining Company) shows a 

larger water volume being processed at 5.8 thousand AF/yr, but that includes no groundwater 

pumping for overburden dewatering or for depressurization. The operating technique here 

appears to allow for overburden seepage to collect in the pit and mix with surface water. 

Central Texas mines (including Jewett, Calvert/Twin Oak, Sandow/Three Oaks) are 

characterized by some depressurization pumping. Levels of depressurization and dewatering 

vary considerably across mines. Mines located in the Calvert Bluff Formation above the prolific 

Simsboro aquifer of Central Texas (between the Colorado and Trinity Rivers ) are forced to 

produce large amounts of water to depressurize and avoid heaving of the mine floor (for 

example, Harden and Jaffre, 2004). The Sandow mine in Milam County used to pump large 

amounts of water from the Simsboro, in excess of 20 thousand AF/yr. 

Gibbons Creek and San Miguel mines tap the Jackson Group lignite, not the Wilcox. The San 

Miguel mine does produce groundwater, but it is saline and is reinjected into the subsurface. For 

the purpose of this study, the San Miguel mine has zero water use. Two new mines will be 

developed in the future: Twin Oaks, next to the current Calvert mine in Robertson County and 

Kosse Strip in Limestone County. They will be discussed in the Future Use section. 

Table 28 summarizes our findings: a total of 25.6 thousand AF is pumped, only 2.6 thousand AF 

of which is consumed. Most is groundwater (18.4 thousand AF), 1.1 thousand AF of which is 

consumed. 
129 

Table 25. Lignite and coal-mining operations in Texas 

Name County Current Operator 

Cumul. Prod. 

1976–2007 

(million st)A

Water-Use 

Range 

(thousand 

AF/yr) Status 

Monticello Thermo Hopkins Luminant 35.4 ~0.9 Active in 2009 Monticello Winfield Titus Luminant 268.1 0.6–1.0 Active in 2009 Darco Harrison Norit Americas Inc. 6.8 Not in operation 2001 last prod. Hallsville Harrison Sabine Mining Company 80.4 ~5.8 Active in 2009 Oak Hill Rusk Luminant 101.2 1.2–1.7 Active in 2009 Martin Lake Panola Luminant 265.9 ~1.0 Active in 2009 Big Brown Freestone Luminant 160.7 ~2.5 Active in 2009 Jewett Freestone/ Leon Tx Westmoreland Coal Company (NRG) 167.7 ~2.0 Active in 2009 Calvert Robertson Walnut Creek Company 32.6 7.2 Active in 2009 Sandow Milam ALCOA Inc. 151.0 >25 1990–2008 average Not in operation 2005 last prod. Three Oaks Bastrop/Lee ALCOA Inc. 13.7 4.0-5.0 Active in 2009 Gibbons Creek Grimes TMPA 43.0 Not in operation 1996 last prod. Powell Bend LCRA 1.6 No longer permitted 1993 last prod. San Miguel Atascosa/ McMullen San Miguel Electric Cooperative 80.2 0.2 saline No fresh or brackish water use Little Bull Creek Amistad Fuel Company 0.43 No longer permitted 1987 last prod. Eagle Pass Maverick Dos Republicas Resources Co., Inc. 0 Not (ever?) in operation. Palafos, Rachal, Trevino Webb Farco Mining, Inc. 7.2 Not in operation 2004 last prod. Thurber Thurber Coal Company 0.46 No longer permitted 1983 last prod. Note: mine locations not in operation are in italics in smaller print A: RRC website file tx_coal.xls 
130 

Table 26. Water fate for current lignite operations in Texas 

Name County Dewatering Depress. Other Use 

Monticello 

Thermo Hopkins 77.7% overburden 0% 22.3% water supply 

95% dust suppression 

5% washing 

Monticello 

Winfield Titus 0% 0% 100% water supply 

95% dust suppression 

5% washing 

Hallsville Harrison 99.9% pit 0% 0.1% water 

supply 

Oak Hill Rusk 54% 

overburden 0% 46% water supply 

95% dust suppression 

5% washing 

Martin Lake Panola 12.9% 

overburden 0% 87.1% water 

supply 

95% dust suppression 

5% washing 

Big Brown Freestone 92.5% 

overburden 3% 4.5% water supply 

95% dust suppression 

5% washing 

Jewett Freestone/ 

Leon 

98% but mostly overburden 

dewatering 

2% water 

supply 

Calvert Robertson 2% overbrd. 

2% pit 95% 1% water supply Mine operations + discharge 

Sandow Milam 100% 

Three Oaks Bastrop/ 

Lee 99% 1% water supply 

San Miguel Atascosa/ 

McMullen 2% pit 98% unknown Discharge to Class V 

injection wells 

Table 27. Water source for current lignite operations in Texas 

Name County Fresh Brackish GW SW 

Monticello 

Thermo Hopkins 100% 0% 80% 20% (water rights) 

Monticello 

Winfield Titus 100% 0% 50% 50% 

Hallsville Harrison 100% 0% 100% pit dewatering but also 

seepage (GW) 

Oak Hill Rusk 100% 0% 58.5% 41.5% (water rights) 

Martin Lake Panola 100% 0% 100% 0% 

Big Brown Freestone 100% 0% 100% 0% 

Jewett Freestone/ 

Leon 95% 5% Unknown Assumed all GW 

Calvert Robertson 100% 0% 100% 

Sandow Milam 100% 0% 

Three Oaks Bastrop/ 

Lee 100% 0% 100% 0% 

San Miguel Atascosa/ 

McMullen 0% 0% 100% 

saline 0% 
131 

Table 28. Estimated lignite mine water use per county in AF/yr (2010) 

Contributing Mine County 

Total Pumpage 

Total Consumption 

Pumpage Groundwater 

Consumption Groundwater 

Pumpage Surface Water 

Consumption Surface Water 

Pumpage Fresh Water 

Consumption Fresh Water 

San Miguel Atascosa 0 0 0 0 0 0 0 01/2 Three Oaks Bastrop 2,089 21 2,089 21 0 0 2,089 21Big Brown, 1/3 Jewett Freestone 3,129 124 3,129 124 0 0 3,095 124South Hallsville Harrison 5,800 6 6 6 5,794 0 5,800 6Monticello Thermo Hopkins 920 205 735 21 185 185 920 2051/2 Three Oaks Lee 2,089 21 2,089 21 0 0 2,089 211/3 Jewett Leon 667 13 667 13 0 0 633 131/3 Jewett, Kosse Strip Limestone 694 41 694 41 0 0 661 41Martin Lake Panola 982 855 554 428 428 428 982 855Calvert, Twin Oak Robertson 7,436 74 7,436 74 0 0 7,436 74Oak Hill Rusk 1,265 582 741 58 524 524 1,265 582Monticello Winfield Titus 619 619 310 310 310 310 619 619TOTAL 25,689 2,562 18,449 1,116 7,240 1,446 25,589 2,562
132 

Source: Ambrose et al. (2010) 

Figure 97. Distribution of Texas lignite and bituminous coal deposits, coal mines currently 

permitted by the RRC with 2008 annual production in short tons 
133 

0

10

20

30

40

50

60

1975 1980 1985 1990 1995 2000 2005 2010

Calendar Year

Statewide Annual Production (MM st)

Source: RRC website file tx_coal.xls 

Figure 98. Statewide coal/lignite annual production (1975–2009) 

0

2

4

6

8

10

2001 2002 2003 2004 2005 2006 2007 2008 2009

Calendar Year

Water Volume (thousand AF/yr)

0

10

20

30

40

50

Water Volume (thousand AF/yr) - 

Total&Sandow

Big Brown

Mont. Winfield

Mont. Thermo

Martin Lake

Oak Hill

Jewett

Three oaks

Calvert

Sandow

Total

Figure 99. Lignite mine groundwater production 2001–2009 

Tx_coal_JP..xls 

Dewatering Production 2001-2009_JP.xls 
134 

86420

141210

1975 1980 1985 1990 1995 2000 2005 2010

Calendar Year

Annual Production (MM st)

Sandow (1E)Three Oaks (48)Little Bull Creek (7A)Eagle Pass (42)Palafox (37C)Rachal (9D)Treviño (45B)Powell Bend (35B)Darco (29C)Jewett (32F)Jewett E/F (47)S. Hallsville No. 1 (33G)San Miguel V (11F)Gibbons Creek (26D)Gibbons Creek V (38D)Big Brown (3D)Martin Lake (4J)Oak Hill (46B)Monticello-Winfield (34E)Monticello Thermo (5F)Twin Oak Mine (49)Kosse Mine (50)Calvert (27F)Thurber (10)

(a) linear scale 

Note: permit numbers in brackets Figure 100. Production of Texas coal mines (1976–2007) 

Tx_coal_JP..xls 
135 

1.00.10.0

10.0

100.0

1975 1980 1985 1990 1995 2000 2005 2010

Calendar Year

Annual Production (MM st)

Sandow (1E)Three Oaks (48)Little Bull Creek (7A)Eagle Pass (42)Palafox (37C)Rachal (9D)Treviño (45B)Powell Bend (35B)Darco (29C)Jewett (32F)Jewett E/F (47)S. Hallsville No. 1 (33G)San Miguel V (11F)Gibbons Creek (26D)Gibbons Creek V (38D)Big Brown (3D)Martin Lake (4J)Oak Hill (46B)Monticello-Winfield (34E)Monticello Thermo (5F)Twin Oak Mine (49)Kosse Mine (50)Calvert (27F)Thurber (10)Statewide Total

(b) log scale 

Source: RRC website file tx_coal.xls Figure 100. Production of Texas coal mines (1976–2007) (continued) 

Tx_coal_JP..xls 
136 

4.4 Aggregates

This section summarizes work presented in Walden and Baier (2010) that addresses nonfuel 

industrial mineral mining, including aggregates, stone, clays, metals, and nonmetallic minerals. 

Most of the information focuses on crushed stone and construction sand and gravel, which make 

up the largest portion of the industrial mineral mining industry in Texas and constitute one of the 

greatest water users. As detailed in the methodology section (Section 3.3.3), the current TWDB 

data set is used as a basis and is compared with the newer BEG survey. In Section 4.4, we 

describe our efforts to bring in additional information, particularly confirmation of water-use 

coefficients. 

4.4.1 General Aggregate Distribution 

Aggregates fall into two major categories: crushed stone and sand and gravel, as well as a 

miscellaneous third category. Having a low value on a mass basis, aggregates tend to concentrate 

around urban areas because transportation costs can be prohibitive unless they possess an 

intrinsically higher value such as industrial sand (used in hydraulic fracturing) or igneous 

crushed stones (Figure 101). Aggregate products can be economically trucked up to 50 miles and 

can be shipped by rail up to 200–250 miles. 

Carbonates (limestone and dolomites) for crushed rock exist in large quantities across most of 

the state but typically come from selected formations such as the Edwards Limestone (Garner, 

1994), especially along the Balcones Fault Zone (west of San Antonio to south of Dallas). 

Overall, crushed stone consists mostly of limestones but also sandstones, as well as granitic 

rocks in the Llano area and volcanic rocks (“trap rock”) in the Uvalde area. Carbonates, and 

more generally crushed stones, have several purposes, including concrete making, ballast, base 

material under foundations, roads, and railroads, but also manufacture of cement and lime. Sand 

and gravel facilities are located mainly along streams and rivers and in the Gulf Coastal Plains 

and tend to be smaller and sometimes intermittent. 

Some facilities are located below the water table and need to pump seeping groundwater (as well 

as stormwater) from the exploitation pit. It is difficult to estimate the amount of groundwater 

(which should be counted toward withdrawal) relative to the amount of stormwater (which 

should not be counted as either groundwater or surface-water withdrawal) without undertaking a 

study of the local hydrologic system, unless a water-source breakdown is provided by the 

operator. 

4.4.2 Description of Mining Processes 

4.4.2.1 Crushed Limestone Mining 

Hard-rock limestone is mined by blasting large sections of the quarry wall and extracting the 

shot rock with excavators, loaders, or other mechanical equipment. Large dump trucks transport 

the material to rock crushers, where it is reduced to a size that can be moved by conveyor belts to 

other parts of the operation. No water is used during extraction except for roadway watering and 

dust suppression, as needed. Initial rock crushing and separation are also performed dry except 

for dust suppression. Road-base products, which contain higher proportions of clay and pit fines, 

are produced in this dry section of the plant. Harder rock is passed sequentially through a series 

of crushers, shakers, and screens with a multistage washing system to produce a variety of 

product sizes. Amount of water used depends on how dirty the rock is and the number of 

products to be generated. Different sized products are separated and stockpiled for delivery to 
137 

customers. Products can be mixed in various proportions to satisfy specific customer 

specifications. The wash water removes very fine particles and impurities from the larger 

aggregate products. These small particles are further separated from the wash water using 

cyclones, rotating screws, weirs, and fine screens to produce manufactured sand. Figure 102 

represents a simple flow diagram of a typical crushed-stone mining process. 

The remaining water is captured and typically routed to large settling ponds to allow super-fine 

particles of silt and clay to settle out of suspension before being pumped back to supply ponds to 

be recycled for reuse in the process. Smaller operations or quarries with limited available space 

may use closed filtration or similar equipment to further clean and recycle wash water. Discharge 

of water is rare and generally only occurs during seasonal, heavy rainfall events that overwhelm 

the retention ponds. As a result of the active water recycling and reuse efforts in place at most 

crushed-stone quarries, only ~20 to 30 percent of the water used in the operation is actually 

consumed and must be replaced. Water loss generally results in four ways: (1) retention of water 

in the moisture content of final product shipped to customers; (2) application of water on 

roadways, conveyor belts, and transfer points to suppress dust; (3) spillage and absorption of 

water from washing process equipment and pipes; and (4) evaporation from ponds and open 

equipment. 

Rainwater, spillage, and drainage from stockpiles are collected and routed to settling ponds or 

other equipment to reduce the amount of makeup water required. Surface ponds that are below 

the local water table may also have significant groundwater seepage into the ponds. In some 

areas of the state, this seepage is often enough that active pumping from groundwater or surfacewater sources is not required or may only be necessary during summer months or periods of 

extreme drought. Brackish or saline water cannot be used for aggregate mining because the salt 

will adversely impact the quality of the concrete, asphalt, and other products manufactured from 

the materials. 

4.4.2.2 Sand and Gravel Mining 

In open-pit sand and gravel mining, material is removed using excavators, front-end loaders, 

draglines, or shovels and transported by trucks for processing. Deposits are frequently located 

near streams or waterways and are mined moist. No water is required for extraction and, in some 

cases, water must be pumped away from the mining site to allow access by machinery, although 

some facilities with deposits below the water table use dredges. Dewatering of groundwater 

seeping into the mining site is often used as wash water but may also need to be supplemented by 

groundwater and surface-water sources. 

In most dredge-type sand and gravel mining, materials are pumped from the bottom of a body of 

water and piped to the processing plant in a high volume of water. The sand and gravel are 

separated, and the bulk of the water is returned to the original location. This return water is 

critical to maintaining an adequate volume of water at the mine site to allow continued pumping. 

Some dredge mines use bucket dredges to load material onto barges or other means of transport 

to processing locations. 

Sand and gravel are processed through a series of shakers, screens, and washers to size, separate, 

and clean different products. Larger rocks may be crushed or removed for other uses. Rotating 

screens with water sprays are used initially to treat wet materials before log washers or rotary 

scrubbers remove clays and organic materials. Screening is used to separate product by size. 

Products are dewatered with screw conveyors, cyclones, or other separators and then transported 
138 

to stockpiles. Wash water is routed to stormwater retention ponds, where particles are allowed to 

settle out. It is then recycled as process water or applied on plant roadways for dust suppression, 

as needed. Because sand and gravel are typically wet, little if any water is required on conveyors 

or other equipment for dust suppression. The moisture content of sand and gravel can be ~5% to 

6%, resulting in proportional loss of water. 

4.4.3 External Data Sets 

Several databases (MSHA, USCB) list aggregate facilities and related commodities but do not 

include information on their production (Table 2, Table 3). A trade association (NSSGA) in 

association with USGS also reports names and locations of aggregate facilities but, similar to 

USCB and MSHA, does not provide commodity production or water use. As described next, we 

investigated with little success the possibility that TCEQ own information about water use. 

TCEQ regulates surface-water rights. We also conducted a survey of GCDs to access 

information on groundwater use. 

4.4.3.1 TCEQ Central Registry 

TCEQ is responsible for the regulation and permitting of all sources of air and water pollution 

and has adopted rules that specify the control technologies and emissions limits that must be met 

by industries, including mining operations, in Texas. The TCEQ has established a Central 

Registry of all regulated entities, which contains information about the companies and specific 

locations of industrial sites. Each regulated site is issued a Registration Number or RN Number, 

which allows the agency and the public to readily access this information and links to other 

program records related to permitting, compliance, inspections, enforcement, and other actions 

taken by the TCEQ. The Central Registry database was queried to extract information on all 

active facilities with major, two-digit SIC Codes of 10, regarding metal mining, and 14, 

regarding mining and quarrying of nonmetallic minerals, except fuels. The numbers and types of 

facilities identified by this search were far larger than identified by MSHA and NCCGA and are 

shown in Table 29. 

4.4.3.2 TCEQ Surface-Water Diversion 

The TCEQ issues and regulates water-rights permits and withdrawals of most surface water in 

Texas including navigable waters, reservoirs, and major impoundments. Each water right holder 

must submit monthly reports indicating the amount of water diverted, amount returned, and the 

amount consumed. The TCEQ provided spreadsheet data on water-rights reports from entities 

identifying themselves as mining users for 2006–2008. The agency was unable to segregate the 

mineral-mining facilities from other mining interests, such as oil and gas or coal, so it was 

difficult to clearly differentiate the available data. Many of the companies that were clearly 

recognizable as mineral mining reported no surface-water diversions, or they indicated that they 

consumed 100 percent of the amount that they did divert. In some cases, companies did report 

significant return-flow quantities. However, there appeared to be some confusion on the 

appropriate reporting requirements because some companies reported that the sum of the amount 

returned and consumed exceeded the amount that was diverted throughout the year. Appendix F 

includes a table that provides all of the active water-rights holders in the mining industry, along 

with the amount of water they are authorized to withdraw in acre-feet per year. It also includes a 

table of the 2008 Water Rights Reporting Data. 

Further evaluation of the TCEQ Water Rights data to identify and extract industrial mineral 

mining information and to resolve gaps and inconsistencies in the reported values may be 
139 

worthwhile. However, most mineral mining operations do not depend on surface-water-rights 

diversions except to supplement captured stormwater and recycled water when needed. 

The TCEQ does not regulate the extraction of groundwater. Local GCDs have been established 

to monitor and control the amount of water withdrawn from aquifers in many areas of the state. 

No centralized data are available for specific types of water use, and additional investigation 

would be required to survey GCDs to determine whether they maintain data on mining activities 

within their jurisdiction. Information gathered from GCDs is posted in Appendix E. 

4.4.3.3 TCEQ TPDES 

The TCEQ regulates wastewater from major industrial and commercial sources under the Texas 

Pollution Discharge Elimination System (TPDES) through permits that control the amount and 

quality of effluent discharged. Discharge of process water requires an individual, site-specific 

permit, whereas discharge of stormwater can often be authorized under the Multi-Sector General 

Permit (MSGP) for major industrial activities. All of the SIC code categories for mineral mining 

operations (major two-digit Groups 10 and 14) are subject to the MSGP. Facilities are required to 

monitor and report the quantity of discharges but do not need to report captured or recycled 

water if it does not leave their property. Because most mining operations actively recycle much 

of their water, they only discharge during periods of exceptionally heavy rain. Examination of 

individual TPDES permits and discharge-monitoring reports will be of limited value in 

quantifying water use or consumption. 

The TCEQ regulates the emission of air pollutants to reduce or avoid the release of contaminants 

that could adversely affect public health or the environment. Mineral mining operations have the 

potential to emit particulate matter (PM) from a number of processes that require controls to be 

implemented. Rules and air-quality permit requirements most often direct mining operations to 

reduce these PM emissions by applying water sprays to crushers, conveyors, transfer points, 

stockpiles, and roadways to suppress dust. This application becomes a major source of water 

consumption because most or all of the water used for these purposes evaporates. TCEQ rules do 

not require sources to monitor or report the amount or frequency of water used for particulate 

controls. Although some facilities record some related activities, such as the number or 

frequency of water trucks used to spray roadways, for their own management needs, such data 

are not consistent and cannot be reliably used. Further evaluation of air permits or controls will 

have limited value in quantifying the amount of water used or consumed by the mining industry. 

4.4.3.4 TCEQ SWAP Database 

The federally mandated TCEQ Source Water Protection (SWAP) project database contains a 

wealth of information about current and past mining activities and is a good source to locate 

facilities. However, it does not provide information about water use. 

4.4.4 BEG Survey Results 

4.4.4.1 Survey of Facilities 

Results of the BEG survey are summarized in Table 30 (without reference to specific facilities or 

their location). Total production for crushed stone from the surveyed facilities translates into ~35 

million tons, or 22.5 % of state total production, and may be sufficient to imply some validity 

and predictive power to this aggregate category. On the other hand, sand and gravel survey 

results add up to only ~3.6 million tons, or 3.6% of the state total production, and thus provide 

more limited predictive power. Overall surveyed facilities are well distributed across the state 
140 

and are located in areas where most of the population resides (Figure 103). The 26 facilities (18 

crushed stone and 8 sand and gravel) show a large range in terms of production (<0.2 to >13 

million tons per year), reported gross water use (a few AF/yr to >4,000 AF/yr), reported net 

water use (a few AF to >2,000 AF/yr), and in a category called groundwater and surface-water 

net water use (from 0 to >1,000 AF/yr). The last category does not consider stormwater in net 

water use and account only for so-called external sources (surface water or groundwater). 

Plotting the information (Figure 104) graphically illustrates the relationship between these types 

of water use. 

The stormwater category is included because precipitation falling on the property is generally 

redirected to sumps and ponds to comply with TCEQ regulations. Often that stored stormwater 

alone can be sufficient to run aggregate operations. This study did not try to determine whether 

the drainage area and precipitation at a specific facility are consistent with the amount of 

stormwater reported to be used. Such a task goes beyond the scope of work, although data to 

perform it are readily available. Discriminating between stormwater and groundwater is difficult 

in a pit whose bottom might be deeper than the water table, but it is just as conceivable to think 

that the stored stormwater recharges the aquifer as to think the reverse. 

Water-use statistics are computed with and without accounting for stormwater (Table 31): the 

crushed-stone water-use coefficient is either 64 gal/st (with all water sources) or 36 gal/st 

(without counting stormwater), and sand and gravel water-use coefficient is either 68 gal/t (all 

water sources) or 47 gal/st (without storm water). Excluding dry process facilities and facilities 

from a company that seems to have much lower water-use coefficients produces 151 and 66 

gal/st for wet process and crushed stone facilities, respectively. However, we think that the 

fraction of dry vs. wet process facilities is representative of the state as a whole (because we 

obtained complete data from a large operator in the state) and that lower water-coefficient 

facilities should also be included in the average (because they come from several large facilities). 

Recall that in the methodology section we explained that averages were made on a production 

basis not as a simple average of each facility average. 

The amount of reported recycling varies widely from none for dry-process crushed-stone 

facilities, which only consumes water for dust suppression and a few wet-process crushed-stone 

facilities, possibly because they have stormwater in excess, to almost 100% in some highly 

water-conscious facilities. A few wet-process crushed stone facilities also reported no recycling, 

possibly because they have excess storm water available or because they misinterpreted the 

question. Most facility recycling rates range from 65% to 90%. For the washed crushed-stone 

mining operations that reported recycling, rates were in the expected range of from 49% to 86%. 

Recycling at surveyed sand and gravel operations was reported at rates ranging from 74% to 

99%. 

Unexpectedly, five operations indicated that no recycling of water was conducted at the mines 

and that all of the gross water used was consumed. This may be due to a misunderstanding of the 

survey questionnaire rather than an unrealistic indication that all water is used only once at the 

facility and is lost to product or evaporation. A more probably interpretation is that no 

exceptional recycling activities have been implemented to increase water reuse. In these cases, 

the reported amounts should be considered net water use. This study focuses on the net water use 

and did not need knowledge of gross water use or recycling rate because, unlike oil and gas 

activities, recycling serves only one single facility. The large spread in net water use is illustrated 

in Figure 105, which displays histograms of water consumption. However, values cluster ~0 to 
141 

30 gal/t for dust control (roads and machinery) and show a bimodal distribution at <20 gal/t and 

~50 gal/t for washing. Both distributions have very long tails. Gross-washing water use 

reportedly ranges from a minimum of 3.0 gpm/tph for very clean rock (rare) up to 15.0 gpm/tph 

for dirty rock (as sometimes seen in the Edwards Limestone), that is, 180 to 900 gal/t (Walden 

and Baier, 2010). 

The source of consumed water (Table 32) is equally difficult to generalize because of the limited 

size of the analyzed sample, but it seems that on average more than half of the consumed water is 

groundwater. This figure, however, represents an average that matches only a few facilities 

(Table 30). Water for most operations come from only one of three possible sources 

(groundwater, surface water, or stormwater). It is thus impossible to attribute water source at a 

county level without specific knowledge of the water use at each facility. 

4.4.4.2 Survey of GCDs 

Survey results are described in detail in Appendices D and E and integrated within the body of 

the report. Overall, except for a few very responsive districts, most GCDs either did not respond 

to the survey or did not have access to the requested information. In summary, findings indicate 

that most groundwater conservation districts do not collect estimates of groundwater use by 

mining operations. The districts generally rely on information reported by the TWDB, even 

though they may not be able to confirm the information. Fewer than 50 percent of the districts 

surveyed replied with any information. Of the respondents, only 20 percent provided any 

quantitative volumetric estimate of use or permitted use of groundwater by mining entities. No 

districts reported having monitoring systems in place to measure groundwater use that was 

permitted for mining. Therefore, other than the reported current use data in Appendix D (Table 

72), the districts were unable to provide better projections of water use by mining. 

4.4.5 Historical and Current Aggregate Water Use 

Table 33 summarizes some historical water-use coefficients, a parameter not easy to come by as 

discussed earlier. Old reports (for example, Quan, 1988, published by the Bureau of Mines) 

mention ~300 gal/st but variable across the years (470 to 220) (his Fig. 30) and probably across 

the country as well as a function of local conditions. About half is recycled water (Quan, 1988, 

Table 5). Crushed stone intensity of water use ranges from 60 to 150 gal/st (his Fig. 34). Quan 

(1988) presented data for 7 individual years between 1954 and 1984. The trend is towards 

reduction in water use but not in a regular fashion and actually shows an uptick in the last year 

(1984), amount of recirculated/recycled water increased from a small fraction in 1954 to 50% in 

1984. Quan (1988, p.32) estimating future water use in 2000 for the U.S. Bureau of Mines also 

relied on intensity of use coefficients using them as multipliers to the projected mineral 

production. Norvell (2009, Table 3) calibrated USGS water-use coefficients from Quan (1988) to 

Texas water-use surveys done ca. 2000. He doubled water-use relative to the U.S. average and 

assumed 80% recycling. Mavis (2003, Table 6.1–2) provided figures in the following 

subcategories for the sand and gravel category: 1–6 gal/t for dust control of machinery (this is 

consumed), 60–180 gal/t for wet screening, ~60 gal/t for sand screw, and ~90 gal/t for gravity 

classifier. The last three categories are for gross water use. 

Recent WUS surveys conducted by the TWDB have a small overlap with the BEG survey (Table 

34) in terms of facility, with an approximate agreement in terms of net water use. TWDB results 

cannot be used to develop water-use coefficients because production values are not provided, but 

they were integrated into their specific counties, as described in the methodology section. 
142 

Overall, ~24,700 AF and ~18,300 AF (total of 43,000 AF) was consumed across the state for 

aggregate production. Results for individual counties are listed in Table 35. 
143 

Table 29. TCEQ Central Registry records of mining facilities in Texas 

SIC Code Type of Mine 

No. of 

Mines 

SIC 

Code Type of Mine 

No. of 

Mines 

Major Group 10: Metal Mining 

1011 Iron Ore 4 1081 Metal Mining Services 8

1044 Silver Ore 6 1094 Uranium–Radium–

Vanadium Ore 52

1061 Ferroalloy Ore (except 

Vanadium) 4 1099 Misc. Metal Ore 18

Major Group 14: Mining and Quarrying of Nonmetallic Minerals, Except Fuels 

1411 Dimension Stone 118 1446 Industrial Sand 74 

1422 Crushed and Broken 

Limestone 1285 1455 Kaolin and Ball Clay 14

1423 Crushed and Broken 

Granite 8 1459

Clay, Ceramic, and 

Refractory Minerals (not 

elsewhere classified) 

1429 

Crushed and Broken 

Stone (not elsewhere 

classified) 

296 1474 Potash, Soda, and 

Borate Minerals 8

1442 Construction Sand and 

Gravel 1041 1479

Chemical and Fertilizer 

Mineral Mining (not 

elsewhere classified) 

60

 1481 Nonmetallic Minerals 

Services, Except Fuels 29

 1499 Misc. Nonmetallic 

Minerals, Except Fuels 100

Table 30. Water-use survey results from selected aggregate operations 

Source Water 

Production 

(Mt/yr) 

Gross 

Water 

Use 

(1000s 

AF/yr) 

Net Water 

Use 

(1000s 

AF/yr) 

GW &SW 

Net Use 

(1000s 

AF/yr) 

Water Use 

(gal/st) 

Recycle 

Rate (%) GW SW StW 

Crushed stone (wet process) 

4.00 4.1 1.3 0.00 107 68% 100%

1.76 2.9 0.5 0.54 100 81% 100% 

0.80 1.1 1.1 1.10 450 0% 100% 

1.33 1.6 0.4 0.41 100 75% 100% 

0.85 1.2 0.2 0.09 65 86% 50% 50%

1.50 1.4 1.4 0.00 300 0% 100%

0.20* 0.2 0.2 0.15 est 250 0% 100% 

0.65* 0.1 0.1 0.03 est 250 0% 55% 45%

0.18* 0.3 0.1 0.04 est 250 52% 30% 70%

0.33* 0.3 0.3 0.00 est 250 0% 100%

3.50 1.1 0.3 0.33 31 70% 100% 

13.70 4.3 1.1 1.06 25 75% 100% 

0.60 1.1 0.2 0.14 92 84% 80% 20%
144 

Source Water 

Production 

(Mt/yr) 

Gross 

Water 

Use 

(1000s 

AF/yr) 

Net Water 

Use 

(1000s 

AF/yr) 

GW &SW 

Net Use 

(1000s 

AF/yr) 

Water Use 

(gal/st) 

Recycle 

Rate (%) GW SW StW 

Crushed stone (dry process) 

0.29 0.01 0.01 0.01 9 0% 100% 

0.39 0.01 0.01 0.00 10 0% 100%

4.56 0.14 0.14 0.14 10 0% 100% 

2.28 0.07 0.07 0.00 10 0% 100%

5.00 0.02 0.02 0.02 2 0% 18% 82% 

Sand and gravel 

0.55 0.29 0.08 0.08 45 74% 100% 

0.52 0.12 0.04 0.04 26 67% 100% 

0.21 0.12 0.03 0.00 38 79% 100%

 

0.50 1.84 0.03 0.03 18 99% 100% 

0.50 2.00 0.35 0.35 228 83% 100% 

0.30 0.09 0.02 0.02 22 76% 100% 

0.52 0 Y 100%

0.48 0 Y 100%

*: estimated 

Note: some facilities may underreport their stormwater use 

Table 31. Aggregate net water use/consumption based on BEG survey results 

 Number of 

Data Points

- 

% of State 

Production 

1000s AF 

/million tons Gal/t 

Crushed-stone water-consumption coefficient 

All water sources 17–22.5% 0.197 64 

GW+SW only 17–22.5% 0.109 36 

Wet process crushed large w/o low water-use coefficient facilities 

All water sources 10–~8% 0.465 151 

GW+SW only 10–~8% 0.204 66 

Sand and gravel water consumption coefficient 

All water sources 6–3.6% 0.209 68 

GW+SW only 8–3.6% 0.143 47 
145 

Table 32. Net water-use breakdown by water source 

 Groundwater Surface water Stormwater 

Weighted by production 0.706 0.011 0.295 Crushed Stone 

Facility average 0.491 0.129 0.381

Weighted by production 0.689 0.291 0.020 Sand and gravel Facility average 0.250 0.375 0.250

Note: crushed stone survey represents ~22.5% of total production, whereas sand and gravel survey sample 

represents only 3.6% of production 

Table 33. Historical water-use coefficients for aggregates (gal/st) 

Withdrawal Recycled Total Discharge Consumption Source 

Sand and Gravel 

 220–470* Quan (1988, Fig.30) 1954-1984 

130 59 189 88 42 Quan (1988, Table C-5) 1984 

260 52 208 Modified from Norvell (2009, 

p.13) 

 211–336 Mavis (2003, Table 6.1-2) 

Industrial Sands 

806 2891 3697 259 547 Quan (1988, Table C-5) 1984 

1612 322 1290 Modified from Norvell (2009, 

p.13) 

Crushed Stone 

 60–150 Quan (1988, Fig.34) 1954-1984 

68 64 132 48 20 Quan (1988, Table C-5) 1984 

136 27 109 Modified from Norvell (2009, 

p.13) 

*including industrial sand 

Table 34. Results from recent TWDB WUS 

Sand and Gravel Crushed Stone 

Year Net Water Use (AF) Year Net Water Use (AF) 

2007 72 2007* 1,058 

2007 1,468 2007* 824 

2005 3,020 2007* 1,196 

2006 6 2007** 625**/0.9 

2007 0 2002 625 

2001 150 2007 4,822 

2007 2 2007 1,787 

2007 386 2007 185 

2007 112 2007 341 

2007 0 2007 0.6 

2004 5 2007 0.3 

2007 2,384 

*facility with water-use approximately confirmed by BEG survey 

**consistent with BEG survey only for earlier years 

Source: TWDB Office of Planning 
146 

Table 35. Estimated county-level crushed-stone and sand and gravel water use for 2008 

(other counties are assumed to have zero water use) 

County CS S&S County CS S&S 

Unit: 1000s AF 

Atascosa 0.350 Kaufman 2.063 0.195 

Bastrop 0.063 Kerr 0.059 

Bell 0.747 0.346 Lampasas 0.293 0.012 

Bexar 3.108 1.028 Liberty 0.108 

Borden 0.000 Limestone 0.210 

Bosque 0.013 Lubbock 0.415 

Brazoria 0.565 Maverick 0.052 

Brazos 0.230 McLennan 1.025 

Brown 0.000 Medina 0.287 0.063 

Burnet 0.280 0.031 Montague 0.104 0.010 

Callahan 0.131 Montgomery 0.028 

Coke 0.003 Navarro 0.062 

Colorado 1.540 Nolan 0.023 

Comal 3.634 0.099 Nueces 0.445 

Cooke 0.818 0.026 Oldham 0.165 0.002 

Coryell 0.275 Orange 0.136 

Dallas 1.574 Parker 0.170 0.253 

Denton 1.262 Potter 0.192 0.308 

Duval 0.604 Reeves 0.014 0.008 

Eastland 0.150 Sabine 0.053 

Ector 0.168 San Patricio 0.340 0.055 

El Paso 0.581 Smith 0.106 

Ellis 2.898 Somervell 0.386 

Fannin 0.006 Starr 0.142 

Fayette 0.082 Stonewall 0.019 

Floyd 0.169 Tarrant 1.093 

Fort Bend 0.000 Taylor 0.000 

Galveston 0.282 Travis 0.135 0.718 

Glasscock 0.095 Uvalde 0.055 

Grayson 0.041 Val Verde 0.031 

Guadalupe 0.186 Victoria 0.000 

Harris 2.494 Walker 0.454 

Henderson 0.115 Ward 0.016 

Hidalgo 0.170 0.603 Washington 0.018 

Hutchinson 0.127 0.023 Webb 0.226 0.005 

Jack 0.238 Williamson 2.273 

Jefferson 0.131 Wise 1.422 0.229 

Johnson 3.091 0.075 Young 0.035 

Jones 0.010 TOTAL 24.7 18.3 
147 

Figure 101. County population in 2010 (TWDB projection) and crushed-stone NSSGA facilities 

Figure 102. Flow diagram of typical crushed-stone process 
148 

Source: NSSGA/USGS database 

Figure 103. Counties with NSSGA-listed facilities; highlighted county lines represent those 

counties with information from the BEG survey 
149 

0

1

2

3

4

5

0 3 6 9 12 15

Production (million tons/yr)

Water Use (1000's AF/yr)

Gross water use Net water use Water use from external sources

 (a) 

0

1

2

3

0.0 0.2 0.4 0.6 0.8 1.0

Production (million tons/yr)

Water Use (1000's AF/yr)

Gross water use Net water use Water use from external sources

 (b) 

Figure 104. Water use from BEG survey for (a) crushed stone facilities; (b) sand and gravel 

facilities 

Results Summary revised 9-20-10_JP_3=SetUrbanAreasLow.xls 

Results Summary revised 9-20-10_JP_3=SetUrbanAreasLow.xls 
150 

0

1

2

3

4

5

6

7

0-5

10- 15

20- 25

30- 35

40- 4550- 55

60- 65

70- 75

80- 85

90- 95

>100

Dust Control Water Use (Mgal/yr)

Number of bins: 21; Bin size: 5; Number of data points: 25

Number of Facilities

(a) 

0

1

2

3

4

5

6

7

8

0-5

10- 15

20- 25

30- 35

40- 45

50- 55

60- 65

70- 75

80- 85

90- 95

100- 105

110- 115

120- 125

130- 135

140- 145

>150

Dust Control Water Use (gal/ton)

Number of bins: 31; Bin size: 5; Number of data points: 26

Number of Facilities

(b) 

0

1

2

3

4

5

6

7

0

10- 20

30- 40

50- 60

70- 80

90- 100

110- 120

130- 140

150- 160

170- 180

190- 200

210- 220

230- 240

Washing Water Use (gal/ton)

Number of bins: 26; Bin size: 10; Number of data points: 24

Number of Facilities

(c) 

Source: BEG survey 

Figure 105. Histograms of aggregate net water use for washing and dust control: (a) per facility, 

(b) and (c) per unit production 
151 

4.5 Other Nonfuel Minerals 

This section examines water in categories with smaller water use overall, although a few 

facilities may still use a significant amount of water. The dimension-stone category included 

many facilities, but other nonfuel facilities are too few to derive water use statistically, and they 

have to be analyzed individually. 

Water use from the cement industry is not included in this section, not because mining of raw 

material is not mining, but because it is usually associated with a manufacturing SIC code 

(#3241). There are currently 12 cement plants, which are largely associated with the extensive 

Cretaceous limestones in Central Texas (Kyle and Clift, 2008). In surveys, it could be difficult to 

discriminate between water use in the cement plant proper and in the quarries, particularly 

because water use for most installations is likely to be related to dust suppression only, a small 

fraction of total usage overall. However, we can still infer an order of magnitude amount of 

water consumed in mining proper by applying values derived from crushed-rock aggregate 

installations. In 2009, Texas produced 11 million metric tons of cement (USGS commodity 

website); about half of it comes from limestone and the other half from clay material. Assuming 

10 gal/t for dust control (Figure 105a) for limestone and half that value for clay rocks, yields an 

estimated total consumption of 250 AF (assuming no stormwater is used). This estimate is 

corroborated by a BEG survey returned by a large cement manufacturer in the state in which its 

water-use coefficient for dust suppression is even smaller. 

Only one zeolite-producing facility is turning out perhaps 5,000 to 10,000 t of product per year, 

and total production for the nation is ~60,000 t from 10 mines. Texas is ranked third in terms of 

production (USGS commodity website, http://minerals.usgs.gov/minerals/). Using the earlier 

approach, we found the contribution of this mine to water use is negligible. Although minerals 

such as barite and alumina are also listed in the MSHA database, they correspond to processing 

facilities not mines. 

We applied a similar approach for lime and gypsum, which, as raw materials, are typically 

transported dry to the processing plant. There is probably little washing of the material for 

cement, lime, or gypsum plants. Any water use past the quarrying stage would be considered part 

of the manufacturing process (for example, to soften the material), especially if the water is used 

within the processing-plant boundaries. 

4.5.1 Dimension Stone 

Dimension-stone facilities quarry their raw material mostly from Precambrian granites in Central 

Texas, Permian limestones in North-Central Texas, Cretaceous limestones in Central Texas, and 

Triassic Limestones in West Texas (Garner, 1992). The MSHA database lists 100+ facilities in 

this category, and the TWDB WUS survey lists only one facility with no recent water-use data. 

However, given the small production (44,000 tons in 2007, USGS Texas Minerals Yearbook) and 

assuming water use is related mostly to dust control and cutting, we tentatively based their water 

use on the highest water use coefficient for the crushed-stone aggregate (151 gal/ton, Table 31). 

This calculation results in a total water use of 18.5 AF/yr, with the additional assumption that the 

10 largest dimension-stone facilities consume most of the water, each using on average 1.8 

AF/yr. Even increasing the water-use coefficient by one order of magnitude yields values low 

enough to be neglected, given the uncertainty associated with larger uses such as aggregates, 

particularly because many of the counties with dimension-stone facilities also host crushed-stone 

or lime facilities (Figure 106). 
152 

4.5.2 Industrial Sand 

Industrial sand, typically used in glass making, foundry molding, and blast sands, has seen an 

uptick in production and use, probably owing to the large increase in hydraulic-fracturing 

activities in which it is used as a proppant. Production is concentrated in only a few 

areas/counties (Figure 107). Texas industrial sand production has increased in sync with U.S. 

production but seems to be growing faster in the past few years (Figure 108). Some of the 

operations are owned by gas companies. Current production is likely ~4 million tons (3.28 and 

3.58 million tons in 2007 and 2008, respectively, as given on the USGS website 

(http://minerals.usgs.gov/minerals/). 

Industrial sand facilities are similar to aggregate facilities and would require a similar amount of 

water for dust suppression on roads and conveyor systems but require more water per unit 

product for washing. Historical water-use coefficients for industrial sands (Table 33) show a total 

water use ~20 times higher than for aggregates but a higher recycling rate as well (80% in the 

1980s). Water consumption averaged across the U.S. was also 10+ times higher than that of 

crushed stone. The few data points collected for this study agree with this figure. 

The Hickory UWCD near the Llano Uplift reported 4,212 AF and 559 AF permitted in 

McCulloch and Mason Counties, respectively, in a total of five operations most likely related to 

industrial-sand (proppant) production. The UWCD also stated that actual use and permitted 

amounts were very close and that plant consumption (manufacturing) was not included. Other 

sources of information suggest that these two counties produce >1 million tons of industrial sand, 

particularly the Carmeuse Industrial Sand facility, and perhaps up to one-third of the state output. 

Assuming the latter sand production value results in a high water-use coefficient of 1,200 gal/t. 

A facility in Limestone County reports on the TWDB WUS database 

(http://www.twdb.state.tx.us/wrpi/wus/wus.asp) a consistent ~650 AF/yr throughout the year. A 

facility responding to the TACA/BEG survey and located in a county north of Houston reported 

0.2 million tons of production, water consumption of 315 AF/yr, and a significant fraction 

(~93%) of the water being recycled. A quick calculation yields a water-consumption coefficient 

of 514 gal/t for the latter facility, which reports no water use for dust suppression. 

How much stormwater is used is unclear. Note that some of the industrial sand facilities are 

collocated with regular aggregate facilities and that their water consumption may already be 

included in this category. Overall, when no other information is available, we assumed a wateruse coefficient of 600 gal/t, to which we added 20 gal/t for dust control, resulting in 9.7

thousand AF (Table 36). 

4.5.3 Chemical Lime 

Lime (and cement) plants tend to be sited next to the raw material (Edwards Limestone, Austin 

Chalk, and other pure limestones) being quarried. The year 2009 saw a short drop in lime 

production (1.04 million metric tons; 1.5 million metric tons in 2008), deviating considerably 

from the trend of the past 2 decades (according to which, production should have been over 1.7 

million tons) (Figure 109). According to USGS, as well as the MSHA website 

(http://www.msha.gov/drs/drshome.htm), there are five lime facilities in Texas, in Bosque, 

Burnet, Comal, Johnson, and Travis Counties. MSHA provided the annual number of employeehours, and we assumed that production is proportional to the number of hours worked. Most of 

the water use in lime facilities is associated with manufacturing. There is typically no washing; 

operators tend to avoid adding water because of the cost of heating it. Water use is only for dust 
153 

suppression and is likely hard to separate from overall plant use. We assumed that water 

consumption is due only to dust suppression at 10 gal/t (Figure 105a). The result is a small total 

water consumption of 46 AF (assuming no stormwater is used) (Table 37), which can be 

neglected. 

4.5.4 Clay Minerals 

Clay minerals mined in Texas fall into two categories—common clay (brick making, cement 

component) and specialty clays (ball clay, bentonite, fire clay, Fuller’s earth, kaolin). These five 

types’ usage and mineralogical make-up are: ball clay (kaolinitic sedimentary clays that 

commonly consist of 20–80% kaolinite, 10–25% mica, 6–65% quartz), which is used for 

ceramics; bentonite, which is used for drilling mud, among many other uses; fire clay (all clay 

minerals but bentonite), which is used to make refractory products; Fuller’s earth 

(montmorillonite or palygorskite or a mixture of the two), which is used as a adsorbent; and 

kaolin (kaolinite), which is used for porcelain and high-quality paper (Norvell, 2009, p.6). 

Clay mining is generally performed by scrappers, which remove materials and transport it to 

stockpiles for use in manufacturing processes, such as brick making. In some mines, excavators 

are used to remove and load clay onto railcars, barges, or other transport to off-site 

manufacturing plants. Clay mines may be online for only a few months each year to provide raw 

materials sufficient to support manufacturing throughout the year. No water is used in the actual 

mining process, although water is added during most of the manufacturing processes. In fact, 

clay mines are bermed to minimize rainwater inflow and must be dewatered, if necessary, to 

allow access and prevent excess water from affecting clay quality. Water is discharged into 

retention ponds or nearby surface water, and some is used for dust suppression on plant 

roadways. Water can be used for conveyance as slurry but cannot be included as mining use; it is 

instead considered as manufacturing use. 

Texas clay deposits are generally contained in Tertiary formations of the Gulf Coast. Brickmaking operations often tap the common clay of the Calvert Bluff Formation in Central Texas 

(Hunt, 2004). Altered volcanic ash layers in South Texas provide bentonite, and kaolinite is 

produced from the Simsboro Formation in North Texas. The main clay producers are in 

Gonzales (bentonite), Navarro (common clay), Limestone (kaolin), and Fayette (bentonite) 

Counties. Clay is also mined in an additional 20 counties. 

Texas mining production in 2008 was 2.14 million tons of various clay minerals, having 

remained relatively constant at that level during the past decade despite a bump of ~2.7 million 

tons in 2006 and 2005. Less water is probably needed for dust suppression in clay operations, 

and stormwater probably ponds more easily than in conventional aggregate operations. However, 

unlike for cement, lime, and gypsum operations, the clay washing step could be included as 

mining use, which we ultimately decided not to do. Assuming a water-use coefficient of 30 gal/t 

(Figure 105c) would have yielded only ~200 AF, a low value that falls below the uncertainty 

level of major users and is distributed across various operations in several counties. 

4.5.5 Gypsum, Salt, and Sodium Sulfate 

Gypsum is produced mostly from Permian evaporitic strata of North-Central Texas in 

Nolan/Fisher/Stonewall Counties and Hardeman County, as well as in Gillespie, Kimble, 

Wheeler, and (perhaps) Harris Counties. Texas production in 2008 was ~1.04 million metric tons 

and has seen large variations in production in the past decades, although seemingly relatively 

stable at 1.8 million tons/yr on average (Figure 110). The number of mining facilities has also 
154 

changed in sync with total production (four, five, or six facilities). The result is a small total 

water consumption of 32 AF (assuming no stormwater is used) (Table 38). 

There are only two salt mining operations in Texas: the Grand Saline Dome in East Texas in Van 

Zandt County and the Hockley Dome in the Houston area in Harris County, both of which use 

the classic room-and-pillar mining technique. The USGS commodity website 

(http://minerals.usgs.gov/minerals/) reports that the Hockley and Grand saline mines had a 

production capacity of 400,000 and 150,000 short tons of rock salt in 2008, respectively. Texas 

total salt production has ranged from 9 to 10 million metric tons/ yr in the past decade (9,080 

metric tons in 2008), ~20% to 25% of national production. In 2006, Morton-Thiokol’s salt mine 

in Grand Saline in Van Zandt County reported the use of self-supplied groundwater of 384.4 AF, 

diversion of 43.3 AF of surface water, and groundwater purchase of 43.5 AF, totaling 471 AF/yr 

(Table 39) (K. Kluge, TWDB WUS, personal communication, 2006). The Harris-Galveston 

Subsidence District reported that the Hockley mine in Harris County uses ~0.1 to 7.0 Mgal/yr 

from groundwater wells. The district is also purchasing surface water from the Gulf Coast Water 

Authority for ~150 to 200 Mgal/yr, which comes to a total of ~535 AF/yr and 1.0 thousand AF

overall (Table 39). However, solution mining is the most common method of obtaining salt. In 

theory, 800 gal of water is required to recover 1 metric ton of salt with little recycling. In Texas, 

salt is used mostly as a chemical feedstock for producing chlorine (a key ingredient in the 

production of plastics) and soda ash (a key ingredient in the manufacture of glass) and the saltsaturated brine is directed toward the manufacturing process. For example, Dow Chemical in 

Brazoria County uses water from the Brazos River and is injected onsite to recover salt for use in 

the chemical plant. The ~9 million tons of salt annually produced in the state minus underground 

mining production and minus 0.8 Mt evaporated at Baytown brings the total salt production 

through brine at 7,700,000 × 800 = ~19,000 AF. This use of feedstock in the chemical industry is 

considered manufacturing and is not included in the mining category tallied in this report. 

Sodium sulfate mining is extracted from brines underlying alkaline lakes in West Texas (Kyle, 

2008; Kyle and Clift, 2008), one of two such facilities in the U.S. The TWDB WUS survey 

shows annual groundwater withdrawals remaining consistently at ~400 AF in Gaines County in 

the past decade. Norvell (2009) noted that early in this decade the facility pumped 1,440 AF/yr, 

1,092 AF of which was saline water, increasing our confidence that the earlier mentioned 400

AF is fresh groundwater, not produced brine (which should not be counted toward water use). 

We assume that sulfate sodium production and concomitant water use remained stable in the 

study period. Growth of this commodity will be covered by sources other than mining natural 

accumulations. 

4.5.6 Talc

National production of talc decreased from 0.85 million tons in 2005 to 0.51 million tons in 2009 

(USGS website, http://minerals.usgs.gov/minerals/). It is produced from seven mines. Talc in the 

Allamoore district of Hudspeth and Culberson Counties in West Texas is produced from several 

quarries at ~100,000 t/yr. The most recent TWDB WUS (2003) reports a low water use of 1 AF. 

However, RWPG Region L (Far West Texas) initially prepared a report (2010) citing a value of 

1,500+ for Culberson County, increasing to 1,600+ in 2060 (see their section 2.4.7). The quarries 

are apparently in Hudspeth County, whereas the wells appear to be in Culberson County. The 

water consumption value was derived using a water-use coefficient approach (from USGS) and 

not using direct metering. Whether this figure includes processes that would belong to the 

manufacturing category is unclear. We were unable to collect better information, and we expect 
155 

no change in water use in the decades leading to 2060, assuming water consumption to be 

classified as mining ~0. 

4.5.7 Uranium

Although uranium could be considered a fuel for nuclear power plants, its main use, for 

convenience, is treated in this section. Only in situ leaching (ISL) or in situ recovery (ISR) 

technology is currently used to mine uranium (Campbell et al., 2007). The two main kinds of 

water-use consumption are (1) active mine and (2) reclamation/restoration, the latter requiring 

more water by far, although overall, the uranium extraction industry uses little water. A typical 

operation consists of injecting water with oxygen into the ore zone and producing the uraniumladen water, removing the uranium in ion-exchange resin, and reinjecting the water at a high 

recycling rate (>97%). The restoration phase follows, in which other soluble elements are 

brought back close to initial concentrations. A reverse osmosis technology is generally used. The 

recycling rate is lower, perhaps 33%, at least initially. As trace-element concentrations decrease, 

the RO system can be pushed further, resulting in a decreased waste stream. Other technologies, 

such as bioremediation, could consume less water. A given ISR facility often produces uranium 

and restores the subsurface at different nearby locations simultaneously. We retained an average 

value of 250 gal/ lb of uranium as an overall representation of water consumption. 

Uranium production is concentrated in South Texas (Blackstone, 2005; Carothers, 2008, 2009; 

Nicot et al., 2010). EIA reported (http://www.eia.gov/nuclear/) that in 2009 only two ISL 

operations were active in Texas: Alta Mesa (Brooks County) and Kingsville Dome (Kleberg 

County). In 2008 two more were operational: Rosita and Vasquez, both in Duval County. In the 

past few years uranium production in the U.S. has been close to 4 million lb U3O8 (Figure 111) 

and was 4.145 million lb U3O8 in 2009. These facilities have a nominal production of 1 million 

lb U3O8 each (except Vasquez, at 0.8 million lb U3O8). EIA reported only aggregated data to 

protect individual companies. With the additional help of survey returns, we estimated Texas 

production at ~28% of total production (that is, ~ 1.1 million lb U3O8). We reached this value by 

contrasting (1) production capacity in Texas (5.3 million lb U3O8 in 2009) with that of the U.S as 

a whole (20.45 million lb U3O8), that is 28%, with (2) employment numbers at 31% in Texas and 

Colorado the total number of employee-years. Clift and Kyle (2008) reported a total production 

of ~1.34 million lb U3O8 in 2007, more than two-thirds of it from Brooks County (Alta Mesa 

Project). This level of production results, in turn, in a water consumption of 275 million gal, or 

840 AF, for all producing mines in Texas. We assumed that restoration water consumption is 

combined with production. Because the number of operating mines is limited, actual water 

consumption can be much lower if no restoration is being done. For the purpose of this study, we 

attributed one-third of the estimated total to each county (Table 40). Reclamation by RRC of 

legacy open pits produced in the second half of the 20th century is not included in this count. 

4.5.8 Other Metallic Substances 

Texas has many other occurrences of metallic and industrial minerals, notably in west Texas and 

in the Llano Uplift of central Texas (e.g. Price et al., 1983; Price et al., 1985; Kyle, 1990; Kyle, 

2000). Some of these deposits have had minor production, but most known deposits are currently 

inactive. The scale of known resources provides little encouragement that most could represent 

viable mining operations in the foreseeable future. On the basis of decades-long evaluation and 

development activities, three deposits seem to have potential for near-term mining: (1) Shafter 

silver deposit, Presidio County; (2) Round Top beryllium-uranium-rare earth element deposit, 
156 

Hudspeth County; and (3) Cave Peak molybdenum deposit, Culberson County. They will be 

examined in the ‘Future Water Use” section. 
157 

Table 36. Estimated county-level industrial sand-water consumption 

County 

Estimated 

Number of 

Facilities 

Estimated 

Water Use 

(1000s AF) 

Atascosa 3 0.43

Colorado 3 0.43

Dallas 1 0.04

El Paso 1 0.04

Guadalupe 1 0.07

Harris 1 0.14

Hood 3 0.43

Hunt 1 0.07

Johnson 1 0.04

Liberty 2 0.14

Limestone 2 1.30

Mason 1 0.56

McCulloch 4 4.21

Montgomery 2 0.76

Newton 1 0.14

Orange 1 0.07

Robertson 1 0.04

San Saba 2 0.28

Smith 1 0.07

Somervell 1 0.14

Tarrant 3 0.21

Wise 1 0.07

Total 23 9.68

Table 37. Estimated county-level lime mining-water consumption (AF) 

Water Consumption 

(AF) 

Bosque 8.5

Burnet 2.8

Comal 6.6

Johnson 13.1

Travis 15.1

Total 46

Table 38. Estimated county-level gypsum mining-water consumption (AF) 

Water Consumption 

(AF) 

Fisher 3.3

Gillespie 3.3

Hardeman 6.6

Kimble 1.5

Nolan 14.8

Wheeler 1.2

Total 32
158 

Table 39. Estimated county-level salt mining-water consumption (AF) 

County 

Water Consumption 

(1000s AF) 

Harris 0.535

Van Zandt 0.471

Total 1.01

Table 40. Estimated county-level uranium mining-water consumption (2009) 

County 

Water Consumption 

(1000s AF) 

Brooks 0.28

Duval 0.28

Kleberg 0.28

Total 0.84

Table 41. Summary of water use not in the oil and gas, coal, or aggregate categories 

Mined 

Substance 

Estimated 

Water Consumption 

(1000s AF) 

Dimension Stone 0.018

Industrial Sand 9.7

Chemical Lime 0.046

Clay Minerals 0.2

Gypsum 0.032

Salt 1.01

Sodium Sulfate 0.4

Talc ~0

Uranium 0.84

Zeolite ~0

Cement N/A

Total 12.25
159 

Source: MSHA database 

Figure 106. County-level count of dimension-stone facilities 

Source: MSHA database 

Figure 107. County-level count of industrial-sand facilities 
160 

0

1

2

3

4

1992 1994 1996 1998 2000 2002 2004 2006 2008 2010

Calendar Year

Texas Industrial Sand Production (Mt)

20

24

28

32

36

U.S. Industrial Sand Production (Mt)

Texas

U.S.

Source: USGS commodity website 

Figure 108. Texas and U.S. industrial-sand production (1992–2008) 

0.0

0.5

1.0

1.5

2.0

1985 1990 1995 2000 2005 2010

Calendar Year

Texas Lime Production (million tons)

Source: USGS commodity website 

Figure 109. Texas lime production (1986–2009) 
161 

0.0

1.0

2.0

3.0

1990 1995 2000 2005 2010

Calendar Year

Texas Lime Production (million tons)

Source: USGS commodity website 

Figure 110. Texas gypsum production (1990–2008) 

0

1

2

3

4

5

1992 1994 1996 1998 2000 2002 2004 2006 2008 2010

Calendar Year

Production (million lbs U3O8)

0

250

500

750

1000

1250

1500

1750

Employement (employee-year)

U.S. Mine Production (Mlbs U3O8)

U.S. Employment (person-years)

Colorado&Texas Employement

Source: EIA website 

Figure 111. U.S. uranium production and employment (1993–2009) 
162 

4.6 Historical Mining with High Water Use 

Although no longer active, mines once having high water use should be noted. 

Sulfur

Once Texas was a major producer of Frasch sulfur from microbially altered evaporitic strata in 

west Texas (Hentz et al., 1989) and in salt dome cap rocks of the Gulf Coastal Plain (Kyle, 

2002). More than 350 million tonnes of sulfur were produced using the Frasch process from 

these native sulfur deposits in Texas, Louisiana, and Mexico during the 20th century (Kyle, 

2002). As recently as 1999, Frasch sulfur was produced from the Culberson deposit in Culberson 

County, one of the largest deposits of this type. Four smaller deposits in Pecos County had lesser 

amounts of Frasch sulfur production through the 1980s (Crawford, 1990). 

The shallow salt domes of the Gulf Coastal Plain were the sites of significant historical sulfur 

production (Myers, 1968; Flawn, 1970; Greene, 1983, p. 10; Kyle, 2002). The Boling salt dome 

cap rock in Wharton County was the largest known Frasch sulfur producer in the United States, 

with more than 87 Mt of production from 1916 until 1993. Other Texas counties with multiple 

historical Frasch sulfur producers include Brazoria (4), Fort Bend (4), and Jefferson (2). Other 

counties with single producers include Chambers, Duval, Liberty, and Matagorda. Most of the 

economic sulfur concentrations seem likely to have been exhausted during the Frasch mining 

period. 

The Frasch process requires extensive amounts of superheated water to inject into the native 

sulfur-bearing zone to melting the sulfur, allowing the pumping of liquefied sulfur to the surface 

(Ellison, 1971). The economics of the Frasch process dictate extensive recovery of water and its 

contained heat. Water usage in association with Frasch sulfur production at the Culberson 

deposit was nominally 2,000 gal per tonne of sulfur produced (J. Crawford, written 

communication, 2010), but with only 5% of the total water being “make-up” water for the sulfur 

extraction, i.e. 95% of the process water is recycled. Thus, using those figures, the water demand 

for the Culberson operation at a rate of ~2.5 million tonnes per year totaled about 900 AF per 

year (1990 case; Crawford, 1990). This make-up water was supplied from wells in Reeves 

County, 37 miles southeast of the sulfur production site (Crawford, 1990; Crawford et al., 1998). 

Bituminous Coal 

Texas bituminous coal occurs in six coalfields in North-Central Texas, Maverick County, and 

Webb County. More specifically, coal resources occur in the Eagle Pass, Santo Tomas, Eagle 

Spring, San Carlos, Big Bend, and west of Fort Worth in North-Central Texas. The largest 

annual production of bituminous coal occurred in 1917, with >1.25 million tons of bituminous 

coal produced in the state, followed by a steep decline in the early 1920s that was due to 

competition from oil and gas. Production of bituminous coal ended in 1943 after 15 yr of low 

production, <100,000 t/yr (Evans, 1974). Coal from these areas has been extensively mined, and 

we assume no further production through the next decades. 

4.7 Conclusions and Synthesis for Historical Water Use 

In 2008, the mining industry, defined as described in Section 4, consumed ~140 thousand AF of 

fresh water, distributed in a relatively balanced way between its main users (Figure 112). The oil 

and gas industry used ~57 thousand AF (41%), whereas the coal and aggregate industry used 

~27 (19%) and ~43 (31%) thousand AF, respectively. The “other” category (~12 thousand AF, 
163 

9%) is dominated by industrial sands. A more detailed breakdown (Figure 113) shows that water 

use included 35.8 thousand AF for fracing wells (mostly in the Barnett Shale/Fort Worth area) 

and ~21.0 thousand AF for other purposes in the oil and gas industry. Aggregate industry water 

use is distributed between crushed stone (24.7 thousand AF) and sand and gravel (18.3 thousand 

AF). Remaining water use amounts to 12.2 thousand AF and is dominated by industrial sand 

production (~80% of total). 
164 

0

10

20

30

40

50

60

Oil and Gas

Coal

Aggregates

Others

2008 Water Use (Thousand AF)

Figure 112. Summary of water use by mining industry segment (2008) 

0

5

10

15

20

25

30

35

40

Fracing

EOR

Drilling

Coal

Crushed Stone

Sand & Gravel

Industrial Sands

Others

2008 Water Use (Thousand AF)

Figure 113. Summary of water use by category (2008) 

MiningWaterUse2008_2.xls 

MiningWaterUse2008_2.xls 
165 

5 Future Water Use 

Most uncertainty about future water use in the mining category comes from unknowns in the 

rapidly evolving exploration of shales and tight formations, whose gas production is ultimately 

tied to national economic activity. Aggregates and coal-mining water use are better constrained 

and directly driven by local conditions, such as population growth, but are also connected to 

national economic activity. The latter is the most important driver for oil and gas long-term 

trends of interest to this study. An element strongly impacting future water use is the national 

energy policy, particularly the impact of any cap-and-trade legislation. The passage of some capand-trade or carbon-tax legislation during the next decade is likely to boost gas-fueled power 

plants, but it may also boost oil production through a greater availability of CO2 needed for 

tertiary recovery of oil currently nonrecoverable (assuming the type of WAG CO2 flood common 

in the Permian Basin). 

In the short term, oil and gas operators are likely to focus on plays such as the Wolfberry or the 

combo play of the Barnett Shale or the Eagle Ford, all producing oil with significantly better 

economics than gas. Gas is typically a regional commodity and does not travel as well as oil, 

which is a world commodity. This fact is currently reflected in current oil and gas prices. In 

terms of BTUs contained, oil and gas prices have tracked each other fairly well until about a 

decade ago. It follows that variation/change in price will vary more wildly for gas. Unless lease 

agreements were made early in the history of the plays, Barnett Shale or Haynesville Shale 

operators are probably on the wrong side of the breaking even at current low gas prices. The 

economic slowdown has also impacted aggregate and other material demand, as well as power 

demand. However, overall, we refrained from trying to model this short-term episode. 

5.1 Gas Shales and Tight Formations 

Future water use depends on the amount of oil and gas still in the ground that is ultimately 

recoverable. Resources are enormous. Holditch and Ayers (2009) suggested that technically 

recoverable reserves in any basin are 5 to 10 times the amount of conventional gas produced and 

reserves are from >10 times in the Fort Worth Basin to less than the average in the Gulf Coast, 

and it is very likely that the industry will operate beyond the Barnett, Haynesville, and Eagle 

Ford shales, which it is currently focusing on. From a practical standpoint, however, this study 

had to rely on spatially defined resources from published information. The shale-gas industry 

agrees that there will be no major discovery of gas shales in Texas, whose geology is well known 

(e.g., Chesapeake CEO, 2010). 

National organizations that develop, compile, and distribute national assessments of oil and gas 

reserves and resources (USGS, EIA, AAPG, PGC) have a hard time keeping up with rapid 

changes in the field. Figures provided by these organizations and others are not necessarily 

consistent as to the cutoff date for production, and other criteria may differ (resources and 

reserves vary through time as some are produced and additional ones are discovered), and the 

spatial footprint considered might be different or include areas outside of Texas. A compounding 

factor is that available data may not refer to a particular formation but simply a geographic area. 

Organizing such a large pool of information was a challenging endeavor, and we integrated the 

different and sometimes conflicting figures as best we could, given the time and budget 

constraints. As a comparison benchmark, state-level current gas production is ~7–8 Tcf/yr and 

increasing, whereas oil production is 0.3–0.4 Bbbl/yr. The latest figures from EIA are from 2008 
166 

(Table 43) and are categorized by RRC district (see map in Figure 9 for locations), as well as 

information on proved reserves. Speculative/undiscovered resources were provided by USGS 

(Table 43) and are not entirely consistent with data collected from other sources (Table 44). 

Overall, we assumed a total of 52 Tcf to be produced from the Barnett Shale. Eagle Ford and 

Haynesville-TX + Bossier-TX production potential is not included specifically but can be 

estimated at 161 Tcf and 28 + 21 Tcf, respectively. Permian Basin Barnett and Woodford USGS 

projections (Table 44; Schenk et al., 2008) seem optimistic and are assumed to be at ~20 Tcf. On 

the other hand, Wolfberry potential seems to be underestimated. Schenk et al. (2008) included 

only the Spraberry at a proposed ~510 million barrels of unconventional oil. 

More generally, the Schenk et al. (2008) study is an example of a resource assessment performed 

periodically by the USGS. Unfortunately, information on other important basins in Texas has not 

been updated yet and the recent sharp increase in resources has not been taken into account. The 

Fort Worth Basin assessment (USGS, 2004) dates back to 2003, and work on the Cotton Valley 

and Travis Peak Formations was performed in 2002. USGS (Schenk et al., 2008) provided 

figures for undiscovered resources in the Permian Basin and divided them into conventional and 

“continuous” resources. Continuous undiscovered resources were estimated at 35 Tcf of gas and 

1.3 Bbbl of oil and NGL. Overall the document may overestimate the potential of the Woodford 

and Barnett Shales and underestimate that of the Spraberry/Wolfberry. The same document 

assessed that 0.747 Bbbl oil, 5.2 Tcf gas, and 0.236 Bbbl NGL remain to be discovered, which is 

in addition to the ~5 Bbbl and ~0.3 Tcf of proven conventional reserves (Dutton et al., 2005b, p. 

554). In the end, we estimated that the Wolfberry will produce ~1 Bbbl in the coming decades. 

In general, we favor more optimistic predictions (more resources, more production, more water 

use) because predictions by EIA seem to have systematically underestimated actual production 

for the past decade because of unconventional gas. By combining proven and undiscovered 

recoverable resources (Table 43), we assume that the next 5 decades will see 10 Tcf produced 

from the Anadarko Basin, 16 Tcf from the East Texas Basin, 11 Tcf from the Gulf Coast Basin, 

and 15 Tcf from the Permian Basin (all tight gas and not necessarily all production). 

5.1.1 Projected Future Water Use of Individual Plays 

We next address gas shales individually (Barnett, Haynesville, Bossier, Eagle Ford, Pearsall, 

Woodford-PB and Barnett-PB) and basins with tight producing formations. Table 45 summarizes 

operational characteristics as collected from the literature to provide guidance for the parameters 

used in the production-based approach (see Methodology Sections 3.4.1.1 and 3.4.1.2). 

Parameters used for the production-based and resource-based projections are summarized in 

Table 46 (gas shales) and Table 47 (tight formations). Water use is contingent on the price of 

gas, and drilling activity is more sensitive to price than production. All gas plays, even with 

marginal permeability, will be fraced if gas prices reached $10/ Mcf, even more if the gas 

contains condensate, and development will be accelerated relative to that projected in this 

section. Conversely, if the price of gas stays below $5/Mcf for an extended period of time, 

projections may turn out to be too high in terms of water use. 

Given the current low price of gas relative to oil in terms of BTU content, more companies have 

become interested in wet gas, that is, gas that contains significant amounts of ethane, propane, 

and butane (that can form liquid at surface conditions), whose price more closely follows that of 

oils. Alternatively, operators are moving altogether into the oil window of the shale. This 

business transition is occurring in the Barnett, Eagle Ford and Granite Wash. The net effect on 
167 

water use will be to stabilize the amount used at the state level because companies will likely 

oscillate between dry and wet gas as a function of natural gas price. 

All basins but the Gulf Coast Basin show an increase in gas production in the recent study by the 

PGC (PGC, 2009), in which the U.S. is divided into work areas that follow the general geology: 

P-320 (East Texas), P-330 (Gulf Coast), P-430 (Fort Worth Basin), and P-440 (Permian Basin, 

including New Mexico and West Texas) (Figure 115). The East Texas Basin has shown an 

increase in both production and well count in the past few years after a long period of stability. 

Between January 2004 and December 2008, production increased from ~3,000 to ~5,000 

MMcfd, with ~10,000 incremental wells. The Fort Worth-Strawn Basins, after a slow decline in 

terms of production (~600 MMcfd) and well count since 1990, have shown a turnaround that 

started ca. 2000 and that corresponds to initial development of the Barnett Shale. Starting then, 

production increased to 2500 MMcfd in 2007 and increased faster to reach ~5000 MMcfd at the 

end of 2008. Gulf Coast production stayed more or less stable at 6,000 to 7,000 MMcfd but has 

been on a slow decreasing trend since 2000. The well count is stable as well. Production in the 

Permian Basin has remained stable at 4,000 MMcfd for the past 20 years (to the end of 2008), 

with an increase in well count showing the maturity of the plays and infill drilling. 

Barnett Shale 

The Barnett Shale represents a special case because a similar study was completed a few years 

ago (Nicot and Potter, 2007; Nicot, 2009a). Appendix B suggests that projections are correct so 

far. For the present study, we went back to initial projections at the county level (Bené et al., 

2007, Table 8, Appendix 2; Nicot and Potter, 2007, Table 8), supplemented by the study by Tian 

and Ayers (2010), who presented an update on the prospectivity of the shale in both the oil and 

gas windows. We also noted that average water intensity seems to have decreased from the 

estimated 1.2 Mgal/1,000 ft of lateral in Nicot and Potter (2007) to ~1 Mgal/1,000 ft, despite (or 

thanks to) an increase in lateral length. 

County-level results are presented in Table 48. Water use projections peak in 2017 at ~43 

thousand AF and then decrease to almost nothing in 2040. High-water-use counties are outside 

the core area because it has already passed its peak of drilling activity. Parker, Tarrant, and Wise 

Counties, for example, have a high water use, although it will drop during the next decade as 

activity moves to Clay and Montague Counties in the oil window and more peripheral counties 

outside of the core area. 

Haynesville/Bossier Shales 

The part of the Haynesville/Bossier shales lying in Texas is estimated at ~35% of each play. We 

also added a few counties west of the salt basin slated to start producing at a later date. 

Projections suggest that water use will peak at 22 thousand AF around the 2020 (Table 49 and 

Table 50). As expected (as well as by construction), counties from the core area (Harrison, 

Panola, San Augustine, Shelby) are projected to peak at the same time and to contribute the most 

to total water use. 

Eagle Ford Shale 

Because of the relative lack of information on Eagle Ford wells, the Eagle Ford Shale decline 

curve is assumed to be similar to that of the Haynesville but scaled by a smaller EUR. Cusack et 

al. (2010) attempted a similar analysis in the Eagle Ford play and concluded that 50,000 wells 

would be needed. This study came up with twice as many wells but spread over a much larger 
168 

area. The Eagle Ford Shale was projected to peak in 2031, with a water use of ~32 thousand AF 

(Table 51). Leading counties in terms of water use are such mostly because of their size because 

no core area has been delineated yet and water use is distributed over the whole play more or less 

evenly (but not entirely because of prospectivity variations still). 

Permian Basin Barnett and Woodford Shales 

Those two potentially gas-bearing shales cover large tracts of land in the Delaware Basin in West 

Texas and overlap (making them more attractive to operators). They have been tested several 

times, apparently with little success. Matthews et al. (2007) suggested that the lack of carbonates 

to the Barnett Permian Basin relative to the Fort Worth Basin subcrops is an unfavorable 

element. We also think that the level of interest is currently low. Mineral-rights owners would 

rather produce shallower oil with a more dependable worth. Similar to the Pearsall Shale, we 

assumed a delayed start of around 2020. Water-use is projected to peak at 9.8 thousand AF in 

2031 (Table 52). 

Pearsall Shale 

The Pearsall play has not been very active in the past couple of years but has showed potential in 

the past. It was assumed that after a period of time, operators in the Eagle Ford would redirect 

their attention to this play, which is slated to use water in significant amounts around 2020 and 

peak in 2031 at ~8.1 thousand AF (Table 53). 

Wolfberry Trend 

The Wolfberry Trend is assumed continuous and is treated in a way similar to that of gas shales. 

Projections result in a 2023 peak year, with a water use of 11.7 thousand AF. Counties with the 

highest water use are Irion, Reagan, and Upton Counties (Table 54). 

Tight-Gas Plays 

Tight-gas plays are discontinuous and cannot be approached exactly as the gas shales were. In 

addition, most of them have been producing both conventional and tight gas for many years. 

Their water use is also smaller for these very reasons: less gas to recover and only a small 

fraction of a county is of interest. Water use in the East Texas Basin tight-gas plays (Table 55) is 

projected to peak in 2024 at 5.5 thousand AF, with no county dominating. Water-use projections 

for the Anadarko Basin (Table 56) peak at 3.1 thousand AF in 2020, with a strong contribution 

from Hemphill and Wheeler Counties. The south Gulf Coast Basin (Table 57) has a small 

projected water use of 2.4 thousand AF distributed over many counties at its peak (2027), in 

agreement with the low level of interest local plays have received in the past few years. The 

Permian Basin (Table 58), which has a higher potential, shows the highest water use in 2017 at 

7.8 thousand AF, distributed over many counties as well. 

5.1.2 Correcting Factors 

Correcting factors include recycling, refracing/infill drilling, and potential development of new 

technologies. 

5.1.2.1 Recycling

Recycling figures depend on two parameters: (1) how much of the frac water flows back and 

how soon after the fracing operation itself? and (2) what fraction of it is usable again with or 

without treatment? The amount of water ultimately flowing back from an average fraced shalegas well is a strong function of the play. It can vary from three times the volume injected in the 
169 

Barnett Shale to a small fraction, as in the Marcellus in Pennsylvania. From a strictly operational 

standpoint, only the water flowing back early (10 days) in the history of the well is reusable, 

when all the water infrastructure is still in place (although a multiwall pad may mitigate this). 

The fraction of injected frac water satisfying this criterion is 16% and 5% in the Barnett and 

Haynesville Shales, respectively (Table 42). In addition, the quality of the such-defined flowback 

water is variable. Some initial flowback water can be reused with little treatment (filtration 

or/and mixing). Blauch (2010) stated that flowback water can be used without much treatment, 

mostly by straight blending with fresh water (5–10% flowback and 90–95% fresh water) and 

using new-generation chemical additives. However, Rimassa et al. (2009) suggested that full 

recycling will be hard to attain because degraded additives accumulate in the recycled water. At 

the other end of the spectrum, undergoing full recycling using more or less advanced treatments 

and producing distilled water can be expensive. However, a whole segment of the service 

industry has grown in the past decade to address the recycling needs of gas operators with the 

development of many mobile water-treatment units making use of different technologies (Horn, 

2009), such as osmosis, reverse osmosis, and thermal processes. 

The RRC website (http://www.rrc.state.tx.us/barnettshale/wateruse_barnettshale.php, accessed 

10/11/2010) mentioned that a company specializing in recycling of industrial water has treated 

enough produced water (at 80% recovery) to generate 9.3 million barrels of fresh water thanks to 

several mobile units. This amount is equivalent to 1.2 thousand AF over the course of a few 

years (since 2005). The RRC website also announced that a stationary facility in Parker County 

with a capacity of 30,000 bbl/d received the go-ahead. This capacity amounts to a production of 

1.13 thousand AF of recycled water a year, assuming no down time. Devon, using recycling 

mobile units, has recycled >400 million gallons, with an efficiency of ~80% (that is, >320 Mgal 

(~1 thousand AF), which was reused and >80 Mgal had to be disposed of (Devon website). This 

information has been reprised by RRC, as described earlier. It seems that only Devon has heavily 

invested in making use of flowback and treated produced water. According to the IHS database, 

Devon has drilled ~20% of the Barnett wells since 2005. The process did not seem competitive 

with new water and disposal of flowback water. It remains unclear how many operators follow a 

recycling program similar to that of Devon in the Barnett and elsewhere in Texas. 

Conservatively assuming that twice as many wells as involved in Devon’s flowback recycling 

program have been treated results in 3% of the injected frac water having been treated (~70 

thousand AF since 2005). Incorporating the fact that some flowback water was probably used 

without extensive treatment and not counted toward the figures presented earlier will increase 

this number. For example, reuse, although it probably depends on the operating company, can be 

as high as ~200,000 gal per well in Barnett wells with little treatment (M. Mantell, Chesapeake, 

personal communication, 2010), corresponding to a 6% reuse. Chesapeake does not typically 

reuse water from the Haynesville (too little and of poor quality). Overall, the recycling effort can 

be estimated in the 5–10% range in the Barnett and ~0% in the Haynesville. 

The industry is bound to make tremendous technological progress in recycling, driven mostly by 

issues external to the state of Texas. When a critical mass of companies involved in recycling is 

reached, substantial progress in efficiency and rate is expected. Particularly because of specifics 

in the Marcellus Shale area, such as limited use of injection wells and municipal wastewatertreatment facilities, the industry will make progress in recycling (as long as there is material to 

recycle). In this study we assumed that a maximum of 20% of the water used for fracing will be 

used again. 
170 

5.1.2.2 Refracing

How much refracing of wells already fraced is taking place is unclear, and the information is 

conflicting. Vincent (2010) did a systematic study of restimulation from the origins of hydraulic 

fracturing and concluded that it works (as documented in the literature) and fails (as not 

documented as often). However, discussion with operators suggests that very little refracing of 

recent or future wells will take place. Refracing activities so far have been restricted to wells 

completed early in the development of the slick-water technology and, thus, may be more 

common for vertical wells. However, Potapenko et al. (2009, p. 2), looking back at Barnett 

recompletions, found that despite great success with refracing of vertical wells, little success has 

come from restimulation of horizontal wells. Gel fracs performed early in the history of the play 

perhaps somehow may have damaged the formation and that the new water fracs have restored it 

to its full potential (King, 2010, p. 24). Similarly, it was found that “Some recent spacing 

between frac stages in horizontal wells by some operators are so close that it may be very 

difficult to refracture those wells as all the stages are communicated. Many earlier horizontal 

wells left large segments between stages unperforated for later refracturing development. Some 

now also believe that drilling horizontal well laterals close (250 ft.) and not simo-fracturing is 

leaving gas in place that may not be refractured successfully later on using current technology. 

Some of us believe that simo-fracturing provides gas today that might have been recovered years 

later through refracturing.” (PBSN, Sept. 23, 2008). Simo-fracturing consists of fracing 

neighboring wells at the same time. However, the same newsletter (PBSN, May 5, 2008; Oct. 5, 

2009) states “We believe most Barnett Shale horizontal wells will be refractured within the first 

seven years of production.” 

This work assumes that all the possible restimulations have already been done and that there will 

be no need to refrac newer wells. 

5.1.2.3 Infill drilling 

Infill drilling takes advantage of the new technologies (horizontal drilling and hydraulic 

fracturing) that can then be applied to older plays and reservoirs. Infill drilling is an important 

factor but has no need to be included explicitly as a correcting factor. It is already implicitly part 

of the methodology. 

5.1.2.4 New or Updated Technologies 

New or updated technologies that could further decrease reliance on fresh water include use of 

fluids other than water (propane, N2, CO2), sonic fracturing with no added fluid, and other 

waterless approaches with specialized drilling tools. N2 fracs may prove effective. Brannon et al. 

(2009) and van Hoorebeke et al. (2010) described a ~250,000-gal liquid N2 for a multistage frac 

job with a 3,000-ft-long lateral. These workers noted that although this kind of frac is not 

widespread, Marcellus operators may find advantages in using N2 fracs because of their limited 

need of water and lack of disposal issues. They went on to note that the Woodford and Barnett 

Shales present a favorable lithology for application of this technology. Other potential 

development includes cryogenic nitrogen or CO2 and high-energy gas fracturing (Zahid et al., 

2007). Friehauf and Sharma (2009) discussed the benefits of “energizing” frac fluids with gases 

such as N2 or CO2 (better). Gas addresses the water-trapping problem by creating high gas 

saturation in the invaded zone and facilitating gas flow. How this different approaches impact 

total water use is, however, unclear. As the cost of water increases, those methods potentially 

more expensive than water fracs could become more attractive and receive more attention. Some 

companies already seem to be using CO2 fracs in the Barnett and Eagle Ford. Some technologies 
171 

limit the amount to be disposed of but do not necessarily reduce the demand on local water 

resources, for example, using waste heat from compressors to evaporate (but not recover) water. 

This work does not account for such technological progress and assumes that all plays will be 

produced thanks to technologies currently applied on a wide scale. 

5.1.3 Conclusions on Fracing Water Use 

Overall water use for fracing will increase from the current ~37 thousand AF to a peak of ~120 

thousand AF by 2020–2030 (Figure 116). However, uncertainty is large. We assumed no major 

technological breakthrough in fracing technology and no more than small incremental annual 

increase in efficiency. Another way to measure uncertainty is to assess the two approaches used 

(production-based and resource-based approaches). Used independently, these would differ by a 

factor of two in terms of water use. In addition, there are still several other potential gas 

accumulations, particularly at larger depths than considered in this study—for example, Cotton 

Valley and pre-Pearsall Formations in South Texas (Ewing, 2010), Travis Peak potential tightgas resources downdip of the current play (Li and Ayers, 2008), and Silurian, Ordovician 

(Simpson Group), or even Cambrian targets in the Delaware Basin or the Permian Basin (Dutton 

et al., 2005a)—but which are all too speculative to be included in this study. Production from 

these formations would mean that water use, instead of decreasing after the peak of ~120 

thousand AF would stay at that level or possibly higher for a longer period of time. 
172 

Table 42. Flowback volume characteristics. 

Frac Water 

Volume (Mgal) 

Flowback @ 10 

Days (Mgal) 

Ultimate 

Produced Water 

(Mgal) 

Recovery 

Ratio 

Barnett 3.8 0.6 11.730 3.1

Haynesville 5.5 0.25 4.475 0.9

Fayetteville 4.2 0.5 0.980 0.25

Marcellus 5.5 0.5 0.700 0.15

Source: M. Mantell, GWPC Annual UIC Conference, Austin, TX, January 26, 2010 

Table 43. Compilation of published Texas oil and gas reserves 

 Oil (Bbbl) Gas (Tcf) Source 

Proved Reserves 

Texas 5.122 

4.56 

72.1 

81.8 

EIA (2008, Tables 4 & 5) 

RRC website (2010, data from 2008) 

Districts 4+2 (South TXs) 0.092 0.00 Shale 

10.3 Total 

EIA (2008, Table 9) 

EIA (2008, Tables 4 & 5) 

District 6 (East TX) 0.16 

0.16 Shale 

11.3 Total 

EIA (2008, Table 9) 

EIA (2008, Tables 4 & 5) 

Districts 8+8A+7C (~PB) 4.30 0.04 Shale 

13.3 Total 

EIA (2008, Table 9) 

EIA (2008, Tables 4 & 5) 

Districts 5+9+7B (~FWB) 0.23 

21.4 Shale 

26.8 Total 

EIA (2008, Table 9) 

EIA (2008, Tables 4 & 5) 

District 10 (~An. B) 0.05 0.00 Shale 

6.3 Total 

EIA (2008, Table 9) 

EIA (2008, Tables 4 & 5) 

Undiscovered Recoverable Resources (Mean) 

Permian Basin, including 

New Mexico 

0.75 Conv. 

0.51 Cont. 

1.26 Total 

5.20 Conv. 

0.26 Tight 

35.13 Shale 

40.58 Total 

USGS – NOGA website 2010* 

Anadarko (TX+OK+KS) 

0.40 Conv. 

0.00 Cont. 

0.40 Total 

14.20 Conv. 

0.00 Tight 

0.00 Shale 

14.20 Total 

USGS – NOGA website 2010* 

Fort Worth Basin (>Texas) 

0.10 Conv. 

0.00 Cont. 

0.10 Total 

0.47 Conv. 

0.00 Tight 

26.23 Shale 

26.70 Total 

USGS – NOGA website 2010* 

Western Gulf Coast 

(TX+LA) 

2.29 Conv. 

1.09 Cont. 

3.38 Total 

68.09 Conv. 

2.63 Tight 

0.00 Shale 

70.72 Total 

USGS – NOGA website 2010* 

East Texas** 

2.76 Conv. 

0.00 Cont. 

2.76 Total 

0.00 Conv. 

0.00 Tight 

0.00 Shale 

0.00 Total 

USGS – NOGA website 2010* 

*NOGA website http://energy.cr.usgs.gov/oilgas/noga/assessment_updates.html (updates) 

**The only information for East Texas is commingled with Mississippi salt-basin data 

Conv. = conventional; Cont. = continuous 
173 

Table 44. Compilation of published reserves for oil and gas shales and tight formations 

Play 

OOIP/OGIP 

(Tcf/Bbbl) 

Produced 

Amount 

Total Recoverable Reserves 

(variable unit) Source 

 7 Tcf* RRC website – to 2009  8.2 Tcf 

23.6 million bbl 

 PBSN (Nov.1, 2010) to 

09/01/2010 

250 Tcf 50-60 Tcf  33 Tcf EIA (2008) from website 327 Tcf 44 Tcf U.S. DOE (2009, p. 17)  26.2 / 1.0 Bbbl NGL Coleman (2009, Table 3) - 

Pollastro (2007) 

Barnett 

 36 Tcf (low); 59 Tcf (BG); 

102 Tcf (high) 

Mohr and Evans (2010) 

 150 / 25 Bbbl Basin O&G, Nov. 2010, p. 10 Eagle Ford 226 Tcfe** Cusack et al. (2010, p. 172)  Up to 100 Tcf Spain and Anderson (2010) 717 Tcf 251 U.S. DOE (2009, p. 17)  73 Tcf (low); 131 Tcf (BG); 

250 Tcf (high) 

Mohr and Evans (2010) Haynesville (TX+LA) 

 60 Tcf (for TX?) Hammes (2009) 

Bossier (TX+LA) 100 Tcf Hanson and Lewis (2010) Permian Basin (Woodford, Barnett, Wolfberry) 

 35 Tcf / 1.3 Bbbl oil+NGL Coleman (2009, Table 3) 

Woodford – Delaware Basin Undisc.: 15.1 Tcf / 0.30 Bbbl NGL Schenk et al. (2008) Barnett – Delaware Basin Undisc.: 17.2 Tcf / 0.34 Bbbl NGL Schenk et al. (2008) Woodford+Barnett – Midland B. Undisc.: 2.8 Tcf / 0.11 Bbbl NGL Schenk et al. (2008) Spraberry Undisc.: 0.26 Tcf /0.53 Bbbl Oil+NGL Schenk et al. (2008) *Through 2009, RRC website http://www.rrc.state.tx.us/barnettshale/index.php

**Undisc. = Undiscovered (mean); BG = Best Guess 1 bbl oil = 5.9 Mcf or 1 Bbbl = 5.9 Tcf 
174 

Table 45. Compilation of published operational characteristics for oil and gas shales and tight formations 

Play 

OGIP 

(Bcf/section) 

EUR 

(Bcf/well) 

IP 

(MMcfd) Source 

140 2.65 Bcf F. Wang, pers. comm. (2010) 65 U.S. DOE (2009, p. 17) 100150 Vassilellis et al. (2010)  3.3 Bcf (core) XTO Energy (2009)  3.0 Bcf Mantell (2010)  3.0 Bcf (Hor.) 0.74 Bcf (Ver.) Baihly et al.(2010) at 30 years  1.25 Bcf Jarvie (2009) at 30 years 

Barnett 

 1.16 Bcf Hor. SPEE-Anonymous (2010) 

150–170 7.5 (4.5-8.5) F. Wang, pers. comm. (2010) 160–240 Vassilellis et al. (2010)  3-6 Bcf Up to 30 Spain and Anderson (2010, p. 657)  6.5 Bcf Hammes (2009)  6.5 Bcf XTO Energy (2009)  6.5 Bcf Mantell (2010) 80 U.S. DOE (2009, p. 17)  5.9 Bcf Baihly et al. (2010) at 30 years  3.42 Bcf Jarvie (2009) at 30 years 

Haynesville 

 2.6 Bcf SPEE-Anonymous (2010) 

140–212 Cusack et al. (2010) 40–223 5-6 Bcf Vassilellis et al. (2010)  5-6 Bcfe DrillingInfo (2010) Eagle Ford 

 3.8 Bcf Baihly et al. (2010) at 30 years 

Pearsall 80–120 Vassilellis et al. (2010) 

 3.8 Bcf XTO Energy (2009) Woodford 

Cotton Valley 1.9 Bcf (Hor.) 1.0 Bcf (Vert.) Baihly et al.(2010) at 30 years Cleveland (Hor.) 0.8 Bcf (Hor.) ~0.5 Bcf (Ver.) Baihly et al.(2010) at 30 years Note: 1 section = 640 acres = 1 mi2. 
175 

Table 46. Summary description of parameters used in water-use projections (shale-gas plays)  Barnett Haynesville Eagle Ford Bossier Haynes. West Pearsall Woodford/Barnett 

Delaware Basin 

Resource-based Approach County Coverage 80% 80% 80% 80% 80% 60% 80% Lateral Spacing (ft) 1000 1000 1000 1000 1000 1000 1000 Intensity-Mgal/1000ft H.: 1.0 H.: 1.1 H.: 1.25 H.: 1.1 H.: 1.1 H.: 1.0 H.: 1.0 Uncorrected total water use (Th. AF) 1,020 440 1,513 225 37 358 434 Production-based Approach Play EUR (Tcf Equ.) from 2010 to 2060 

61 52 

44 28 

250 161 

33 21 2.2 25 25 

Peak year after start End year after start (county level) 

+8 +30 

+11 +50 

+16 +70 

+10 +50 

+15 +45 

+15 +70 

+15 +70 

Overall peak year 2015 2031 2035 2020 2033 2031 2031 Average well EUR (BCF) 

H.: 2 (core) H.: 1 (non-c.) V.: 0.8 

H.: 2 H.: 1.3 H.: 1.2 H.: 2 H.:1.5 H.: 1.5 

Average water use /well (Mgal) 3.3 6.1 6.2 3.3 6.1 3.3 3.3 Uncorrected total water use (Th. AF) 457 278 1897 356 23 193 193 Number of wells estimate 59,636 14,712 99,120 19,013 1,255 19,040 19,040 Reuse / Recycling -1% / year 

<20% 

-0.5% / year <3% 

-1% / year <20% 

-1% / year <20%

-0.5% / year <3% 

-1% / year <20% 

-1% / year <20% 

Total water use (final results in AF) 750 426 1070 191 36 223 270 
176 

Table 47. Summary description of parameters used in water-use projections (tight formations) 

 Anadarko Basin East Texas Wolfberry Gulf Coast Other Permian 

Basins 

Resource-based Approach County coverage 20% 150% 80% 8% 8% Lateral spacing (ft) 1000 n/a n/a n/a n/aIntensity (Mgal/1000 ft) 450 n/a n/a n/a n/aVertical well (Mgal) 0.4 0.9 1.0 0.5 0.8 Uncorrected total water use (Th. AF) 50 189 314 76 145 Production-based approach Play EUR (Tcf Equ.) from 2010 to 2060 10 16 1070 Bbbl 11 15 Peak year after start End year after start (county level) 

+6 +22 

+12 +50 

+15 +50 

+18 +60 

+8 +35 

Overall peak year 2015 2022 2023 2027 2017 Average well EUR (BCF) H : 1.2 (50%) 

V. : 0.6 (50%) 

H.: 2 (25%) V. : 0.5 (75%) 

H. : n/a V. : 0.06 MMbbl 

H.: n/a V. : 0.4 

H.: n/a V. : 0.3 

Average water-use /well (Mgal) H.: 1.3 

V.: 1 

H.: 3 V.: 0.9 

H.: n/a V.: 0.9 

H.: n/a V.: 0.5 

H.: n/a V.: 0.8 

Uncorrected total water use (Th. AF) 46 140 94 61 182 Number of wells estimate 13,197 33,961 34,031 33,650 71,513 Reuse / Recycling -1% / year 

<20% 

-1% / year <20% 

-1% / year <20% 0% -1% / year <20% 

Total water use (final results in AF) 49 165 283 78 150 
177 

Table 48. Projected water use in the Barnett Shale (Fort Worth Basin) 

2010* 2020 2030 2040 2050 2060 

County AF 

Archer 0 1,618 1,292 369 0 0

Bosque 913 2,547 1,065 0 0 0

Clay 634 3,731 1,663 0 0 0

Comanche 429 2,524 1,125 0 0 0

Cooke 101 282 118 0 0 0

Coryell 0 1,793 1,140 263 0 0

Dallas 620 769 271 0 0 0

Denton 1,674 587 0 0 0 0

Eastland 0 1,127 1,157 386 0 0

Ellis 325 235 63 0 0 0

Erath 2,017 2,500 882 0 0 0

Hamilton 190 1,118 498 0 0 0

Hill 1,008 1,249 441 0 0 0

Hood 1,720 990 215 0 0 0

Jack 1,835 1,706 535 0 0 0

Johnson 3,308 1,537 241 0 0 0

McLennan 0 1,380 680 62 0 0

Montague 539 3,174 1,415 0 0 0

Palo Pinto 446 2,627 1,171 0 0 0

Parker 4,003 1,787 153 0 0 0

Shackelford 0 1,121 1,151 384 0 0

Somervell 771 443 96 0 0 0

Stephens 0 1,854 1,178 272 0 0

Tarrant 3,147 1,104 0 0 0 0

Wise 4,220 1,961 308 0 0 0

Young 0 563 578 193 0 0

Total (Th. AF) 27.9 40.3 17.4 1.9 0.0 0.0

*Projected value, not actual observed water use (see Current Water Use Section) MohrDataBarnett_3.xls FinalReport-Sept.10.xls 
178 

Table 49. Projected water use in the Haynesville Shale 

2010* 2020 2030 2040 2050 2060 

County AF 

Angelina 0 426 534 367 200 33

Gregg 0 245 435 307 179 51

Harrison 344 2,506 1,848 1,211 574 0

Marion 0 413 517 356 194 32

Nacogdoches 0 1,683 1,582 1,055 527 0

Panola 308 2,242 1,654 1,083 513 0

Rusk 0 1,841 1,730 1,153 577 0

Sabine 0 856 804 536 268 0

San Augustine 221 1,613 1,189 779 369 0

Shelby 314 2,284 1,685 1,104 523 0

Upshur 0 440 781 551 321 92

Total (Th. AF) 1.2 14.5 12.8 8.5 4.2 0.2

Leon 0 57 201 183 96 9

Freestone 0 69 243 221 116 11

Total (Th. AF) 0.0 0.4 1.4 1.2 0.6 0.1

*Projected value, not actual observed water use (see Current Water Use Section) 

Table 50. Projected water use in the Bossier Shale 

2010* 2020 2030 2040 2050 2060 

County AF 

Nacogdoches 116 2,379 1,599 1,083 567 52

Sabine 210 1,411 949 643 337 31

San Augustine 213 1,432 962 652 342 31

Shelby 302 2,028 1,363 923 484 44

Total (Th. AF) 0.8 7.3 4.9 3.3 1.7 0.2

*Projected value, not actual observed water use (see Current Water Use Section) 

Table 51. Projected water use in the Eagle Ford Shale 

2010* 2020 2030 2040 2050 2060 

County AF 

Atascosa 0 1,443 2,273 1,836 1,399 962

Austin 0 48 256 279 221 163

Brazos 0 519 1,132 922 712 503

Burleson 0 594 1,295 1,055 816 576

Colorado 0 859 1,874 1,527 1,180 833

DeWitt 0 1,067 1,681 1,357 1,034 711

Dimmit 218 2,155 2,327 1,852 1,377 902

Fayette 0 842 1,838 1,497 1,157 817

Frio 0 82 438 477 378 278

Gonzales 0 79 420 458 363 267

Grimes 0 59 314 342 271 200

Karnes 0 1,113 1,350 1,080 810 540

MohrDataHaynesville.xls

MohrDataHaynesv.TemplateBossier.xls 
179 

2010* 2020 2030 2040 2050 2060 

County AF 

La Salle 242 2,390 2,581 2,054 1,528 1,001

Lavaca 0 571 1,776 1,591 1,245 899

Lee 0 47 249 272 215 159

Leon 0 635 1,976 1,771 1,386 1,001

Live Oak 0 79 420 458 363 267

McMullen 0 1,689 2,047 1,638 1,228 819

Madison 0 278 865 775 607 438

Maverick 0 430 1,338 1,199 938 678

Washington 0 366 1,139 1,021 799 577

Webb 138 1,369 1,478 1,177 875 573

Wilson 0 473 1,473 1,320 1,033 746

Zavala 0 434 1,352 1,211 948 685

Total (Th. AF) 0.6 17.6 31.9 27.2 20.9 14.6

*Projected value, not actual observed water use (see Current Water Use Section) 

Table 52. Projected water use in the Woodford and Barnett Shales in the Delaware Basin 

2010* 2020 2030 2040 2050 2060 

County AF 

Crane 0 20 63 50 39 28

Culberson 0 1,324 4,120 3,230 2,528 1,826

Pecos 0 666 2,071 1,624 1,271 918

Reeves 0 893 2,778 2,179 1,705 1,231

Ward 0 44 136 107 84 60

Winkler 0 30 92 72 56 41

Total (Th. AF) 0.0 3.0 9.3 7.3 5.7 4.1

*Projected value, not actual observed water use (see Current Water Use Section) 

Table 53. Projected water use in the Pearsall Shale 

2010* 2020 2030 2040 2050 2060 

County AF 

Atascosa 0 244 757 594 465 336

Dimmit 0 470 1,463 1,147 898 648

Frio 0 98 306 240 188 136

La Salle 0 521 1,622 1,272 995 719

Live Oak 0 94 294 231 180 130

McMullen 0 405 1,261 989 774 559

Maverick 0 458 1,427 1,119 876 632

Webb 0 48 149 117 91 66

Zavala 0 116 360 283 221 160

Total (Th. AF) 0.0 2.5 7.6 6.0 4.7 3.4

*Projected value, not actual observed water use (see Current Water Use Section) 

MohrDataHaynesv.TemplateEagleFord.xls 

MohrDataHaynesv.TemplateDelawareWoodford+Barnett.xls 

MohrDataHaynesv.TemplatePearsall.xls
180 

Table 54. Projected water use in the Wolfberry play 

2010* 2020 2030 2040 2050 2060 

County AF 

Andrews 71 404 383 232 97 0

Borden 42 242 229 139 58 0

Dawson 42 241 228 139 58 0

Ector 42 242 229 139 58 0

Gaines 71 405 384 233 97 0

Glasscock 171 975 924 561 235 0

Howard 172 980 929 564 236 0

Irion 197 1,124 1,065 647 271 0

Martin 172 977 926 562 235 0

Midland 171 974 923 560 234 0

Reagan 223 1,273 1,206 732 306 0

Schleicher 22 128 121 74 31 0

Sterling 44 248 235 143 60 0

Upton 234 1,336 1,266 768 321 0

Total (Th. AF) 1.7 9.5 9.0 5.5 2.3 0.0

*Projected value, not actual observed water use (see Current Water Use Section) 

Table 55. Projected water use in East Texas tight-gas plays 

2010* 2020 2030 2040 2050 2060 

County AF 

Anderson 0 24 83 66 41 15

Cass 0 52 66 46 25 4

Cherokee 23 254 288 188 89 0

Freestone 636 856 670 439 208 0

Gregg 132 177 138 91 43 0

Harrison 900 532 395 259 123 0

Henderson 0 259 327 225 123 21

Limestone 279 375 293 192 91 0

Marion 23 252 210 138 65 0

Nacogdoches 321 321 245 160 76 0

Panola 805 476 354 232 110 0

Robertson 287 606 487 319 151 0

Rusk 51 563 468 307 145 0

Shelby 0 228 288 198 108 18

Smith 0 103 130 90 49 8

Upshur 0 163 206 141 77 13

Total (Th. AF) 3.5 5.2 4.6 3.1 1.5 0.1

*Projected value, not actual observed water use (see Current Water Use Section) 

MohrDataHaynesv.TemplateWolfberry.xls

MohrDataHaynesv.TemplateEastTexas.xls
181 

Table 56. Projected water use in Anadarko Basin tight formations 

2010* 2020 2030 2040 2050 2060 

County AF 

Hansford 74 675 61 0 0 0

Hemphill 694 364 33 0 0 0

Hutchinson 6 59 6 0 0 0

Lipscomb 123 507 46 0 0 0

Ochiltree 73 671 61 0 0 0

Roberts 183 447 41 0 0 0

Sherman 7 61 6 0 0 0

Wheeler 697 365 33 0 0 0

Total (Th. AF) 1.9 3.1 0.3 0.0 0.0 0.0

*Projected value, not actual observed water use (see Current Water Use Section) 

Table 57. Projected water use in the South Gulf Coast Basin tight-gas plays 

2010* 2020 2030 2040 2050 2060 

County AF 

Aransas 9 17 22 16 11 5

Bee 23 47 58 43 29 14

Brazoria 37 75 94 70 46 21

Brooks 25 49 62 46 30 14

Calhoun 17 33 42 31 21 10

Cameron 25 50 62 46 30 14

Colorado 25 51 64 48 31 15

DeWitt 24 47 60 44 29 14

Duval 47 94 118 87 57 27

Fort Bend 23 46 58 43 28 14

Goliad 22 45 56 42 27 13

Hidalgo 42 83 105 78 51 24

Jackson 22 45 56 42 28 13

Jim Hogg 30 60 75 56 37 17

Jim Wells 23 45 57 42 28 13

Karnes 20 40 50 37 24 11

Kenedy 38 76 95 71 46 22

Kleberg 25 49 62 46 30 14

La Salle 39 77 97 72 47 22

Lavaca 25 51 64 47 31 15

Live Oak 28 56 70 52 34 16

McMullen 30 60 75 56 37 17

Matagorda 31 61 77 57 37 18

Nueces 22 45 56 42 28 13

Refugio 21 42 53 39 26 12

San Patricio 18 37 46 34 22 11

Starr 32 64 79 59 39 18

Victoria 23 46 58 43 28 14

Webb 88 177 222 165 108 51

MohrDataHaynesv.TemplateAnadarko.xls
182 

2010* 2020 2030 2040 2050 2060 

County AF 

Wharton 29 57 72 53 35 17

Willacy 16 31 39 29 19 9

Zapata 27 55 68 51 33 16

Total (Th. AF) 0.9 1.8 2.3 1.7 1.1 0.5

*Projected value, not actual observed water use (see Current Water Use Section) 

Table 58. Projected water use in the Permian Basin tight formations 

2010* 2020 2030 2040 2050 2060 

County AF 

Andrews 231 509 297 85 0 0

Borden 68 157 91 26 0 0

Crane 121 277 161 46 0 0

Crockett 53 123 72 21 0 0

Dawson 68 156 91 26 0 0

Ector 265 328 191 55 0 0

Gaines 114 263 153 44 0 0

Garza 68 156 91 26 0 0

Glasscock 138 316 184 53 0 0

Howard 139 318 185 53 0 0

Loving 103 236 138 39 0 0

Lynn 68 157 91 26 0 0

Martin 342 285 166 48 0 0

Midland 341 284 166 47 0 0

Mitchell 68 157 92 26 0 0

Pecos 37 86 50 14 0 0

Reagan 446 371 217 62 0 0

Reeves 400 917 535 153 0 0

Scurry 69 158 92 26 0 0

Sterling 70 161 94 27 0 0

Sutton 108 248 145 41 0 0

Terrell 45 103 60 17 0 0

Terry 68 155 90 26 0 0

Upton 525 454 265 75 0 0

Val Verde 22 51 30 9 0 0

Ward 126 289 168 48 0 0

Winkler 133 307 179 51 0 0

Yoakum 61 140 81 23 0 0

Total (Th. AF) 4.3 7.2 4.2 1.2 0.0 0.0

*Projected value, not actual observed water use (see Current Water Use Section) 

MohrDataHaynesv.TemplateGulfCoast.xls

MohrDataHaynesv.TemplatePB-TG.xls
183 

0

1

2

3

4

5

6

7

1993 1995 1997 1999 2001 2003 2005 2007 2009

Calendar Year

Cumul. Gas Production (TCF)

0

20

40

60

80

100

Cumul. Water Use (1000's AF)

Gas Production

Water Use

Figure 114. Cumulative gas production and water use in the Barnett Shale play from the origins 

Source: PGC (2009); raw data from IHS Energy 

Note: The most irregular curve represents gas production; a 1000-MMcfd unit in the production axis corresponds to 

0.365 Tcf 

Figure 115. Monthly wet-gas production and number of producing oil and gas wells (1990–2008) 

barnett counties_year Eric Projections_3Verbose_for FinalReport-Sept.10.xlss 
184 

Figure 115. Monthly wet-gas production and number of producing oil and gas wells (1990–2008) 

(continued) 
185 

0

50

100

150

2010 2020 2030 2040 2050 2060

Calendar Year

Water Use (thousand AF)

Fracing Water Use Shale Gas Tight Fm.

Figure 116. Projected state fracing water use 

MiningWaterUse2010-2060_2.xls 
186 

5.2 Conventional Oil and Gas 

Conventional oil and gas, although beyond their peak production, are likely to remain significant 

for many decades as operators assess and put online new reservoirs. After peak oil in Texas in 

the early 1970s, the following years showed a slow, more or less linear decrease in production 

(despite an increase in producing wells). Starting in the late 1990s, though, a graph shows a clear 

leveling off of the decrease (Figure 117), one section of which can be used to extrapolate future 

production (Figure 118). Much anecdotal evidence suggests that conventional oil and gas 

resources in Texas are far from being exhausted. For example, Ewing (2010) listed several likely 

deep plays (>10,000 ft) in South Texas equivalent to productive formations in East Texas. And 

operators in the Permian Basin still have to explore for the gas that may lie deeper than current 

production horizons. As described earlier, USGS oil and gas assessments evaluate the resource 

that is deemed to be technically recoverable using current and projected techniques. Reserves are 

defined as a subset of the resources that can be produced economically. The USGS-based 

National Oil and Gas Assessments (NOGA) is tasked to evaluate those undiscovered petroleum 

resources. NOGA divides the continental U.S. into many provinces, including “West Gulf,” 

“East TX, LA-MS Salt Basins,” “Bend Arch-Fort Worth Basin,” “Permian Basin,” and 

“Marathon Thrust Belt.” Except for the much smaller last province, all four other provinces go 

largely beyond Texas. The latest complete assessment of the U.S. was made in 1995, although 

updates of the assessment of some provinces were made very recently. 

5.2.1 Water and CO2 Floods 

Conventional oil and gas production use water for two purposes: drilling and EOR. As seen in 

the current water-use section, water use for waterfloods has been decreasing steadily, and we 

assume that it will keep making up a smaller and smaller fraction of fluid injected for 

waterfloods. Fresh water use has been declining strongly in the past decades, and we expect the 

trend to continue (Figure 119). The general trend of oil production in West Texas has been one 

of more or less continuous decline since its peak in the early 1970s. Galusky (2010) produced 

what we think are relatively accurate numbers for the Permian Basin (~10 Bbbl to 2060). Schenk 

et al. (2008) estimated undiscovered resources of conventional oil in the Permian Basin at 747 

million barrels. A study by the consulting firm ARI (Kuuskraa and Ferguson, 2008, Table 1) 

reports that Texas (including that portion of the Permian Basin in New Mexico) has >200 Bbbl 

of OOIP of which ~70 Bbbl is conventionally recoverable (primary and secondary recovery 

processes), an arguably optimistic projection. For comparison, Texas has produced ~60 Bbbl of 

oil since the origins. 

Dutton et al. (2005a) presented a comprehensive study of all known oil and gas fields in the 

Permian Basin and included a section on production forecast to 2015. The lack of full overlap 

between the Permian Basin and Districts 08 and 8A (New Mexico had 15.6% of cumulative 

production through 2000, Dutton et al., 2005a, p. 351) carries some uncertainty but the error 

introduced by assuming the Permian Basin and RRC Districts 08 and 8A coincide is small 

compared to the other assumptions used in this section. Dutton et al. (2005a) projected a 

production of 3.25 Bbbl of oil through 2015 from which the 1.9 Bbbl produced through 2010 

(since the publication of the Dutton et al., 2005a report) must be deducted yielding 1.35 Bbbl to 

be produced to 2015. This is consistent with Galusky (2010)’s projections at 1.44 Bbbl from 

2011 to 2015. Both workers have in common the slow decline of conventional oil production at a 

similar rate. 
187 

The slow pace of this decline (~2% per year) reflects the steady increase in EOR production 

techniques (waterfloods and CO2 floods). The general pattern of declining oil production has 

occurred through high-price as well as low price-intervals. It would thus seem reasonable to 

project this gradual decline through the forecast period of this study (2010– 2060). Oil drilling 

and completion activities and oil production are expected to be sustained at slowly declining 

levels in West Texas over the next 50 years. It is projected that EOR production methods will be 

responsible for 70% or more of total oil production by 2020 and beyond. Although EOR 

production requires copious quantities of water to sustain oil reservoir pressures, fresh water is 

expected to decline in use relative to brackish and saline (recycled produced) waters. Total 

brackish and saline water use is thought to have essentially peaked near the present estimated 

figure of ~38.5 thousand AF/yr and is then expected to decline over the coming decades. In 

contrast, total fresh-water use is expected to continue to decline from the present estimated figure 

of ~10,000 ac-ft/yr to less than half this level by 2020. In this study we did not investigate the 

possibility of having extensive waterfloods in the Gulf Coast area or elsewhere in the state. We 

did not include the real potential for extensive CO2 floods as it is not clear whether operators 

would use a WAG technique with concomitant water use or simply inject CO2 (which might be 

in abundance in the future, thanks to the presence of many coal-fired power plants along the 

Gulf). 

Table 59 summarizes our findings per county. Projections of overall water use, estimated at ~8 

thousand AF in 2010, is decreasing through time because of the built-in assumption of decreased 

fresh water use for the purpose of waterflood and other recovery processes. 

Going back to historical reports (for example, Torrey, 1967) is insightful in the sense that it 

allows comparison of projections with actual production and water use. The 1967 report author 

makes the correct statement (p. 2) that no reasonable alternative but to extrapolate currents can 

be made in a 50-year projection period. The report predicts average water use in the 1990–2000 

decade of ~220 thousand AF for much smaller oil production than actually occurred. Included in 

their water use is all nonproduced waters, of which it is unclear how much is fresh or brackish. 

The approach was to compute oil reserves amenable to water injection for pressure maintenance 

or waterflooding (25% increasing to 50% of projected production in 2010) and to apply a 

multiplier (average of 8.2 bbl of water used to produce 1 bbl of oil) corrected by the amount of 

produced water used (typically 10%– 20%, that is, most of water is makeup water, although the 

quality is not described). 

5.2.2 Drilling

In general, drilling and completion activities are much more sensitive to short-term price cycles 

than production. Periods of relatively high oil prices tend to incentivize and support a 

proportionally greater level of drilling activity than do periods of low prices. It would be 

virtually impossible to predict oil prices many years into the future with any level of real 

confidence. Projections of water use for drilling are thus more perilous than price or production 

projections. Nevertheless, it seems reasonable to project a gradual decline in fresh water use for 

oil drilling in the coming decades, Even as oil fields become depleted, an increase in drilling 

activity for oil can be expected because of the renewed interest in plays similar to the Wolfberry 

in the Permian Basin and because of an increased interest in waterflooding, requiring drilling of 

new wells. This increase in drilling is likely to be more than balanced by a decrease in freshwater use as the industry uses more and more brackish and saline water. Galusky (2010) 

proposed to assume that the fresh water use for drilling in the Permian Basin (which is more 
188 

densely drilled than the rest of Texas) will stay relatively stable until 2020, and will gradually 

decrease below about half its present level by 2060. We assume that the pattern is applicable to 

the whole state. Despite the general decrease of fresh-water use in oil production, it is likely that 

the water use for drilling will keep increasing for the next few years because of shale-gas 

activity. The amount of fresh water used in drilling shale gas wells is variable and a function of 

the play (Section 4.2.2). Including water use from shale-gas activity yields a peak of 13 thousand 

AF within the current decade (Figure 120). 
189 

Table 59. County-level fresh and brackish water-use projections for waterflood 

County 

Fresh 

2010 

Fresh 

2020 

Fresh 

2030 

Fresh 

2040 

Fresh 

2050 

Fresh 

2060 

Brack 

2010 

Brack 

2020 

Brack 

2030 

Brack 

2040 

Brack 

2050 

Brack 

2060 

State Total 7.87 2.39 1.49 1.29 1.12 0.96 29.91 31.49 31.93 28.34 24.58 21.26Anderson 0.008 0.002 0.002 0.001 0.001 0.001 0.031 0.033 0.033 0.029 0.025 0.022Andrews 0.384 0.117 0.073 0.063 0.055 0.047 1.457 1.534 1.556 1.381 1.197 1.036Archer 0.003 0.001 0.001 0.000 0.000 0.000 0.010 0.011 0.011 0.010 0.009 0.007Atascosa 0.001 0.000 0.000 0.000 0.000 0.000 0.002 0.003 0.003 0.002 0.002 0.002Baylor 0.000 0.000 0.000 0.000 0.000 0.000 0.001 0.001 0.001 0.001 0.001 0.001Borden 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000Brown 0.005 0.001 0.001 0.001 0.001 0.001 0.018 0.019 0.019 0.017 0.015 0.013Callahan 0.018 0.005 0.003 0.003 0.003 0.002 0.067 0.071 0.072 0.064 0.055 0.048Camp 0.003 0.001 0.001 0.000 0.000 0.000 0.010 0.011 0.011 0.010 0.008 0.007Carson 0.000 0.000 0.000 0.000 0.000 0.000 0.001 0.001 0.001 0.001 0.001 0.001Clay 0.001 0.000 0.000 0.000 0.000 0.000 0.004 0.004 0.004 0.004 0.003 0.003Cochran 0.005 0.002 0.001 0.001 0.001 0.001 0.020 0.021 0.021 0.019 0.016 0.014Coke 0.109 0.033 0.021 0.018 0.016 0.013 0.416 0.438 0.444 0.394 0.342 0.296Coleman 0.021 0.006 0.004 0.003 0.003 0.003 0.080 0.084 0.085 0.076 0.066 0.057Comanche 0.000 0.000 0.000 0.000 0.000 0.000 0.001 0.002 0.002 0.001 0.001 0.001Concho 0.108 0.033 0.021 0.018 0.015 0.013 0.412 0.434 0.440 0.390 0.338 0.293Cooke 0.004 0.001 0.001 0.001 0.001 0.001 0.016 0.017 0.017 0.015 0.013 0.012Cottle 0.007 0.002 0.001 0.001 0.001 0.001 0.026 0.027 0.027 0.024 0.021 0.018Crane 0.027 0.008 0.005 0.004 0.004 0.003 0.101 0.106 0.108 0.096 0.083 0.072Crockett 0.007 0.002 0.001 0.001 0.001 0.001 0.025 0.026 0.027 0.024 0.021 0.018Crosby 0.228 0.069 0.043 0.037 0.032 0.028 0.866 0.912 0.925 0.821 0.712 0.616Culberson 0.033 0.010 0.006 0.005 0.005 0.004 0.127 0.134 0.135 0.120 0.104 0.090Dawson 0.039 0.012 0.007 0.006 0.005 0.005 0.146 0.154 0.156 0.139 0.120 0.104
190 

County 

Fresh 

2010 

Fresh 

2020 

Fresh 

2030 

Fresh 

2040 

Fresh 

2050 

Fresh 

2060 

Brack 

2010 

Brack 

2020 

Brack 

2030 

Brack 

2040 

Brack 

2050 

Brack 

2060 

Dickens 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000Dimmit 0.000 0.000 0.000 0.000 0.000 0.000 0.002 0.002 0.002 0.002 0.001 0.001Eastland 0.070 0.021 0.013 0.012 0.010 0.009 0.267 0.281 0.285 0.253 0.219 0.190Ector 0.019 0.006 0.004 0.003 0.003 0.002 0.072 0.075 0.077 0.068 0.059 0.051Fisher 0.091 0.028 0.017 0.015 0.013 0.011 0.345 0.364 0.369 0.327 0.284 0.245Floyd 0.031 0.010 0.006 0.005 0.004 0.004 0.119 0.125 0.127 0.113 0.098 0.084Foard 0.001 0.000 0.000 0.000 0.000 0.000 0.002 0.002 0.003 0.002 0.002 0.002Franklin 0.001 0.000 0.000 0.000 0.000 0.000 0.004 0.004 0.005 0.004 0.004 0.003Freestone 0.001 0.000 0.000 0.000 0.000 0.000 0.005 0.005 0.005 0.004 0.004 0.003Gaines 0.002 0.001 0.000 0.000 0.000 0.000 0.008 0.009 0.009 0.008 0.007 0.006Garza 0.011 0.003 0.002 0.002 0.002 0.001 0.042 0.045 0.045 0.040 0.035 0.030Glasscock 0.085 0.026 0.016 0.014 0.012 0.010 0.324 0.341 0.346 0.307 0.266 0.230Gray 0.014 0.004 0.003 0.002 0.002 0.002 0.055 0.058 0.058 0.052 0.045 0.039Grayson 0.001 0.000 0.000 0.000 0.000 0.000 0.004 0.005 0.005 0.004 0.004 0.003Hale 0.271 0.082 0.051 0.045 0.039 0.033 1.031 1.085 1.100 0.977 0.847 0.733Hansford 0.001 0.000 0.000 0.000 0.000 0.000 0.004 0.004 0.004 0.004 0.003 0.003Hartley 0.002 0.000 0.000 0.000 0.000 0.000 0.006 0.006 0.006 0.006 0.005 0.004Haskell 0.019 0.006 0.004 0.003 0.003 0.002 0.072 0.075 0.076 0.068 0.059 0.051Hockley 0.001 0.000 0.000 0.000 0.000 0.000 0.005 0.005 0.005 0.005 0.004 0.003Hopkins 0.009 0.003 0.002 0.001 0.001 0.001 0.034 0.036 0.036 0.032 0.028 0.024Howard 0.014 0.004 0.003 0.002 0.002 0.002 0.053 0.056 0.057 0.051 0.044 0.038Hutchinson 0.004 0.001 0.001 0.001 0.001 0.000 0.015 0.016 0.016 0.014 0.012 0.011Irion 0.169 0.051 0.032 0.028 0.024 0.021 0.642 0.676 0.685 0.609 0.528 0.456Jack 0.001 0.000 0.000 0.000 0.000 0.000 0.002 0.002 0.002 0.002 0.002 0.002Jones 0.025 0.008 0.005 0.004 0.004 0.003 0.094 0.099 0.100 0.089 0.077 0.067Kent 0.006 0.002 0.001 0.001 0.001 0.001 0.023 0.024 0.024 0.022 0.019 0.016King 1.818 0.553 0.345 0.299 0.258 0.223 6.907 7.271 7.373 6.546 5.676 4.909
191 

County 

Fresh 

2010 

Fresh 

2020 

Fresh 

2030 

Fresh 

2040 

Fresh 

2050 

Fresh 

2060 

Brack 

2010 

Brack 

2020 

Brack 

2030 

Brack 

2040 

Brack 

2050 

Brack 

2060 

Knox 0.001 0.000 0.000 0.000 0.000 0.000 0.003 0.003 0.003 0.002 0.002 0.002Lamb 0.136 0.041 0.026 0.022 0.019 0.017 0.518 0.545 0.553 0.491 0.425 0.368Leon 0.011 0.003 0.002 0.002 0.002 0.001 0.043 0.045 0.046 0.041 0.035 0.031Limestone 0.001 0.000 0.000 0.000 0.000 0.000 0.003 0.003 0.003 0.002 0.002 0.002Lipscomb 0.003 0.001 0.001 0.000 0.000 0.000 0.011 0.011 0.011 0.010 0.009 0.008Loving 0.074 0.023 0.014 0.012 0.011 0.009 0.282 0.297 0.301 0.267 0.232 0.200Lubbock 1.307 0.398 0.248 0.215 0.186 0.160 4.968 5.230 5.303 4.708 4.082 3.531Lynn 0.207 0.063 0.039 0.034 0.029 0.025 0.785 0.826 0.838 0.744 0.645 0.558Marion 0.001 0.000 0.000 0.000 0.000 0.000 0.002 0.002 0.002 0.002 0.002 0.001Martin 0.084 0.026 0.016 0.014 0.012 0.010 0.320 0.337 0.342 0.303 0.263 0.227Maverick 0.001 0.000 0.000 0.000 0.000 0.000 0.003 0.004 0.004 0.003 0.003 0.002McCulloch 0.009 0.003 0.002 0.001 0.001 0.001 0.034 0.035 0.036 0.032 0.028 0.024McMullen 0.000 0.000 0.000 0.000 0.000 0.000 0.001 0.001 0.002 0.001 0.001 0.001Menard 0.250 0.076 0.047 0.041 0.035 0.031 0.948 0.998 1.012 0.899 0.779 0.674Midland 0.035 0.011 0.007 0.006 0.005 0.004 0.134 0.141 0.143 0.127 0.110 0.095Mitchell 0.003 0.001 0.001 0.000 0.000 0.000 0.011 0.011 0.011 0.010 0.009 0.008Montague 0.004 0.001 0.001 0.001 0.001 0.000 0.014 0.015 0.015 0.014 0.012 0.010Moore 0.001 0.000 0.000 0.000 0.000 0.000 0.003 0.003 0.004 0.003 0.003 0.002Motley 0.027 0.008 0.005 0.005 0.004 0.003 0.104 0.110 0.111 0.099 0.086 0.074Navarro 0.002 0.001 0.000 0.000 0.000 0.000 0.008 0.009 0.009 0.008 0.007 0.006Nolan 0.045 0.014 0.009 0.007 0.006 0.006 0.171 0.180 0.183 0.162 0.141 0.122Ochiltree 0.004 0.001 0.001 0.001 0.001 0.000 0.015 0.015 0.016 0.014 0.012 0.010Oldham 0.003 0.001 0.001 0.001 0.000 0.000 0.012 0.012 0.013 0.011 0.010 0.008Palo Pinto 0.018 0.005 0.003 0.003 0.003 0.002 0.068 0.071 0.072 0.064 0.056 0.048Pecos 0.066 0.020 0.012 0.011 0.009 0.008 0.249 0.262 0.266 0.236 0.205 0.177Potter 0.000 0.000 0.000 0.000 0.000 0.000 0.002 0.002 0.002 0.002 0.001 0.001Reagan 0.024 0.007 0.004 0.004 0.003 0.003 0.090 0.094 0.096 0.085 0.074 0.064
192 

County 

Fresh 

2010 

Fresh 

2020 

Fresh 

2030 

Fresh 

2040 

Fresh 

2050 

Fresh 

2060 

Brack 

2010 

Brack 

2020 

Brack 

2030 

Brack 

2040 

Brack 

2050 

Brack 

2060 

Red River 0.001 0.000 0.000 0.000 0.000 0.000 0.003 0.004 0.004 0.003 0.003 0.002Reeves 0.019 0.006 0.004 0.003 0.003 0.002 0.071 0.075 0.076 0.068 0.059 0.051Runnels 0.060 0.018 0.011 0.010 0.009 0.007 0.228 0.240 0.243 0.216 0.187 0.162Rusk 0.011 0.003 0.002 0.002 0.002 0.001 0.044 0.046 0.046 0.041 0.036 0.031Schleicher 0.030 0.009 0.006 0.005 0.004 0.004 0.112 0.118 0.120 0.106 0.092 0.080Scurry 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000Shackelford 0.046 0.014 0.009 0.007 0.006 0.006 0.173 0.182 0.185 0.164 0.142 0.123Sherman 0.002 0.001 0.000 0.000 0.000 0.000 0.007 0.007 0.007 0.007 0.006 0.005Smith 0.004 0.001 0.001 0.001 0.001 0.001 0.016 0.017 0.017 0.015 0.013 0.012Stephens 1.086 0.330 0.206 0.178 0.154 0.133 4.126 4.343 4.404 3.910 3.390 2.932Sterling 0.007 0.002 0.001 0.001 0.001 0.001 0.027 0.029 0.029 0.026 0.022 0.019Stonewall 0.132 0.040 0.025 0.022 0.019 0.016 0.503 0.530 0.537 0.477 0.414 0.358Sutton 0.001 0.000 0.000 0.000 0.000 0.000 0.005 0.006 0.006 0.005 0.005 0.004Taylor 0.015 0.005 0.003 0.002 0.002 0.002 0.057 0.060 0.061 0.054 0.047 0.041Terrell 0.106 0.032 0.020 0.017 0.015 0.013 0.401 0.423 0.429 0.380 0.330 0.285Terry 0.019 0.006 0.004 0.003 0.003 0.002 0.072 0.076 0.077 0.068 0.059 0.051Throckmorton 0.042 0.013 0.008 0.007 0.006 0.005 0.160 0.169 0.171 0.152 0.132 0.114Titus 0.002 0.001 0.000 0.000 0.000 0.000 0.006 0.007 0.007 0.006 0.005 0.004Tom Green 0.011 0.003 0.002 0.002 0.002 0.001 0.042 0.045 0.045 0.040 0.035 0.030Upshur 0.007 0.002 0.001 0.001 0.001 0.001 0.028 0.030 0.030 0.027 0.023 0.020Upton 0.000 0.000 0.000 0.000 0.000 0.000 0.002 0.002 0.002 0.002 0.001 0.001Van Zandt 0.012 0.004 0.002 0.002 0.002 0.001 0.044 0.047 0.047 0.042 0.036 0.032Ward 0.003 0.001 0.001 0.000 0.000 0.000 0.012 0.012 0.012 0.011 0.009 0.008Wheeler 0.000 0.000 0.000 0.000 0.000 0.000 0.002 0.002 0.002 0.002 0.001 0.001Wichita 0.012 0.004 0.002 0.002 0.002 0.002 0.047 0.050 0.050 0.045 0.039 0.033Wilbarger 0.002 0.000 0.000 0.000 0.000 0.000 0.006 0.006 0.006 0.006 0.005 0.004Wilson 0.000 0.000 0.000 0.000 0.000 0.000 0.001 0.001 0.001 0.001 0.001 0.001
193 

County 

Fresh 

2010 

Fresh 

2020 

Fresh 

2030 

Fresh 

2040 

Fresh 

2050 

Fresh 

2060 

Brack 

2010 

Brack 

2020 

Brack 

2030 

Brack 

2040 

Brack 

2050 

Brack 

2060 

Winkler 0.022 0.007 0.004 0.004 0.003 0.003 0.083 0.088 0.089 0.079 0.069 0.059Wood 0.004 0.001 0.001 0.001 0.001 0.000 0.014 0.015 0.015 0.013 0.011 0.010Yoakum 0.219 0.067 0.041 0.036 0.031 0.027 0.832 0.875 0.888 0.788 0.683 0.591Young 0.002 0.000 0.000 0.000 0.000 0.000 0.006 0.006 0.006 0.006 0.005 0.004

InjectionVolume_2002_RRC_+1998-2001_1.xls 
194 

0

300

600

900

1,200

1,500

1930 1940 1950 1960 1970 1980 1990 2000 2010

Calendar Year

Oil Production (million bbl)

0

50

100

150

200

250

Oil-Producing Wells (thousands)

Oil Production

Number of Producing Wells

Source: EIA website 

Figure 117. Annual oil production in Texas (1936–2009) 

y = -2.4757x + 5201.1

R2

 = 0.7803

0

150

300

450

2000 2010 2020 2030 2040 2050 2060

Calendar Year

Oil Production (million bbl)

08 8A

Total 08 and 8A

Linear (08 and 8A)

Source: RRC online system http://webapps.rrc.state.tx.us/PDQ/generalReportAction.do (historical data) 

Figure 118. Future annual oil production, Districts 8, 8A, and Texas 

Oil&GasProduction-RRC-EIA.xls 

FreshWater+OilProduction_RCC1995.xls 
195 

0

20

40

60

80

100

1980 1990 2000 2010 2020 2030 2040 2050 2060

Calendar Year

Fresh Water Use (thousand AF)

Source: RRC (1982) and De Leon (1996) for historical data 

Figure 119. Historical and projected fresh-water use in secondary and tertiary recovery 

operations 

0

5

10

15

2010 2020 2030 2040 2050 2060

Calendar Year

Projected Drilling Water Use (thousand AF)

Figure 120. Projected drilling-water use 

Historical Injection 2=fromRRC1982Report.xls

DrillingWaterUse.xls 
196 

5.3 Coal

Coal resources are plentiful in Texas and are unlikely to be exhausted within the next 5 decades 

at the current average production rate. Kaiser et al. (1980) gave an overview of the lignite 

resource in Texas and estimated reserves at >6 billion short tons. More recently, Warwick et al. 

(2002) identified 7.7 billion short tons of Central Texas lignite reserves, excluding resources 

within coal-mine lease areas. All mines currently in production, except Jewett mine, which is 

slated to end production around 2025, are assumed to keep producing at a rate similar to the 

current one. Three Oaks mine came on line recently (2005) after Sandow mine retired. Two new 

mines will come on line in the next few years: Kosse mine in Limestone County and Twin Oaks 

mine in Robertson County. Future water-use breakdown for these two mines was estimated from 

Jewett and Calvert mines, respectively. At the state level, water use is assumed to ramp up from 

~25,000 AF/yr to 40,000 AF/yr, mostly because of Three Oak and Twin Oak mines (Figure 121). 

Other mines’ water use remains relatively steady (Figure 122). Results per mine/per county are 

listed in Table 60. Robertson County exhibits higher water use, starting at ~7,500 AF currently 

and increasing to 10,000+ AF after 2040. All of the water is groundwater, very little of which is 

consumed and most of which is discharged to streams. 

The scenario we favor is one in which potential increase in energy needs will be covered by 

western coal (which has been competing with local coal for decades, Figure 123), by other fossil 

fuels (gas?), or by a different energy source (nuclear?), but not by a massive extension of mouthof-mine coal-fired power plants and concomitant increase in water use. In any case, a return to 

underground mining of subbituminous reserves is deemed unlikely. 
197 

Table 60. Projected lignite-mine water use per county in AF/yr (2010–2060) 

TOTAL PUMPAGE TOTAL CONSUMPTION

 2010 2020 2030 2040 2050 2060 2010 2020 2030 2040 2050 2060San Miguel Atascosa 0 0 0 0 0 0 0 0 0 0 0 01⁄2Three Oaks Bastrop 2,089 2,500 5,500 5,500 5,500 5,500 21 25 55 55 55 55Big Brown, "Jewett Freestone 3,129 3,833 3,000 3,000 3,000 3,000 124 152 135 135 135 135South Hallsville Harrison 5,800 6,380 6,380 6,380 6,380 6,380 6 6 6 6 6 6Monticello Thermo Hopkins 920 900 900 900 900 900 205 201 201 201 201 2011⁄2Three oaks Lee 2,089 2,500 5,500 5,500 5,500 5,500 21 25 55 55 55 55"Jewett Leon 667 833 0 0 0 0 13 17 0 0 0 0"Jewett, Kosse Strip Limestone 694 4,333 3,500 3,500 3,500 3,500 41 87 70 70 70 40Martin Lake Panola 982 982 1,500 1,500 1,500 1,500 855 855 855 855 855 855Calvert, Twin Oak Robertson 7,436 8,180 8,998 9,897 10,887 11,976 74 82 90 99 109 120Oak Hill Rusk 1,265 1,668 1,668 1,668 1,668 1,668 582 582 582 582 582 582Monticello Winfield Titus 619 1,000 1,000 1,000 1,000 1,000 619 619 619 619 619 619

TOTAL 25,689 33,110 37,946 38,845 39,835 40,924 2,562 2,650 2,668 2,677 2,687 2,668

PUMPAGE GROUNDWATER CONSUMPTION GROUNDWATER

 2010 2020 2030 2040 2050 2060 2010 2020 2030 2040 2050 2060San Miguel Atascosa 0 0 0 0 0 0 0 0 0 0 0 01⁄2Three Oaks Bastrop 2,089 2,500 5,500 5,500 5,500 5,500 21 25 55 55 55 55Big Brown, "Jewett Freestone 3,129 3,833 3,000 3,000 3,000 3,000 124 152 135 135 135 135South Hallsville Harrison 6 6 6 6 6 6 6 6 6 6 6 6Monticello Thermo Hopkins 735 719 719 719 719 719 21 20 20 20 20 201⁄2Three oaks Lee 2,089 2,500 5,500 5,500 5,500 5,500 21 25 55 55 55 55"Jewett Leon 667 833 0 0 0 0 13 17 0 0 0 0"Jewett, Kosse Strip Limestone 694 4,333 3,500 3,500 3,500 3,500 41 87 70 70 70 40Martin Lake Panola 554 554 1,072 1,072 1,072 1,072 428 428 428 428 428 428Calvert, Twin Oak Robertson 7,436 8,180 8,998 9,897 10,887 11,976 74 82 90 99 109 120Oak Hill Rusk 741 1,144 1,144 1,144 1,144 1,144 58 58 58 58 58 58Monticello Winfield Titus 310 691 691 691 691 691 310 310 310 310 310 310

TOTAL 18,449 25,294 30,130 31,030 32,020 33,109 1,116 1,209 1,227 1,236 1,246 1,227

County+Pop_1-to-All(from Katy)_5.27.10_JP.xls 
198 

Table 60. Projected lignite-mine water use per county in AF/yr (2010–2060) (continued) 

PUMPAGE SURFACE WATER CONSUMPTION SURFACE WATER

 2010 2020 2030 2040 2050 2060 2010 2020 2030 2040 2050 2060San Miguel Atascosa 0 0 0 0 0 0 0 0 0 0 0 01⁄2Three Oaks Bastrop 0 0 0 0 0 0 0 0 0 0 0 0Big Brown, "Jewett Freestone 0 0 0 0 0 0 0 0 0 0 0 0South Hallsville Harrison 5,794 6,374 6,374 6,374 6,374 6,374 0 0 0 0 0 0Monticello Thermo Hopkins 185 181 181 181 181 181 185 181 181 181 181 1811⁄2Three oaks Lee 0 0 0 0 0 0 0 0 0 0 0 0"Jewett Leon 0 0 0 0 0 0 0 0 0 0 0 0"Jewett, Kosse Strip Limestone 0 0 0 0 0 0 0 0 0 0 0 0Martin Lake Panola 428 428 428 428 428 428 428 428 428 428 428 428Calvert, Twin Oak Robertson 0 0 0 0 0 0 0 0 0 0 0 0Oak Hill Rusk 524 524 524 524 524 524 524 524 524 524 524 524Monticello Winfield Titus 310 310 310 310 310 310 310 310 310 310 310 310

TOTAL 7,240 7,815 7,815 7,815 7,815 7,815 1,446 1,442 1,442 1,442 1,442 1,442

PUMPAGE FRESH WATER CONSUMPTION FRESH WATER

 2010 2020 2030 2040 2050 2060 2010 2020 2030 2040 2050 2060San Miguel Atascosa 0 0 0 0 0 0 0 0 0 0 0 01⁄2Three Oaks Bastrop 2,089 2,500 5,500 5,500 5,500 5,500 21 25 55 55 55 55Big Brown, "Jewett Freestone 3,095 3,792 3,000 3,000 3,000 3,000 124 152 135 135 135 135South Hallsville Harrison 5,800 6,380 6,380 6,380 6,380 6,380 6 6 6 6 6 6Monticello Thermo Hopkins 920 900 900 900 900 900 205 201 201 201 201 2011⁄2Three oaks Lee 2,089 2,500 5,500 5,500 5,500 5,500 21 25 55 55 55 55"Jewett Leon 633 792 0 0 0 0 13 17 0 0 0 0"Jewett, Kosse Strip Limestone 661 4,292 3,500 3,500 3,500 3,500 41 87 70 70 70 40Martin Lake Panola 982 982 1,500 1,500 1,500 1,500 855 855 855 855 855 855Calvert, Twin Oak Robertson 7,436 8,180 8,998 9,897 10,887 11,976 74 82 90 99 109 120Oak Hill Rusk 1,265 1,668 1,668 1,668 1,668 1,668 582 582 582 582 582 582Monticello Winfield Titus 619 1,000 1,000 1,000 1,000 1,000 619 619 619 619 619 619

TOTAL 25,589 32,985 37,946 38,845 39,835 40,924 2,562 2,650 2,668 2,677 2,687 2,668
199 

0

10

20

30

40

50

2010 2020 2030 2040 2050 2060

Calendar Year

Water Use (thousand AF/yr)

Total

Consumption

 (a) 

0

10

20

30

40

50

2010 2020 2030 2040 2050 2060

Calendar Year

Water Use (thousand AF/yr)

Total

Total GW

Total SW

 (b) 

0

1

2

3

4

5

2010 2020 2030 2040 2050 2060

Calendar Year

Water Use (thousand AF/yr)

Consumption

Consumption GW

Consumption SW

 (c) 

Figure 121. Projected lignite-mine water use (2010–2060) 

County+Pop_1-to-All(from Katy)_5.27.10_JP.xls 
200 

0

2

4

6

8

10

12

2010 2020 2030 2040 2050 2060

Calendar Year

Water Use (thousand AF/yr)

0

10

20

30

40

50

60

Total Water Use (thousand AF/yr)

San Miguel

Three Oaks

Big Brown

Jewett

South Hallsville

Mont. Thermo

Kosse Strip

Martin Lake

Calvert

Twin Oak

Oak Hill

Mont. Winfield

TOTAL

Figure 122. Total water use for each coal-mining facility 

0.5

0.6

0.7

0.8

0.9

1.0

1.1

1.2

1.3

1.4

1.5

1995 1997 1999 2001 2003 2005 2007 2009

Calendar Year

Production (rel. to 1995)

Texas

West

East

Total

Figure 123. Relative growth of Texas (negative) and western (positive) coal 

NMAwebsite_c_production.pdf_COAL.xls 
201 

5.4 Aggregates

Key parameters for future aggregate water use relating population and aggregate production are 

presented in Table 61, Figure 124, and Figure 125. We assumed that crushed stone and 

construction sand and gravel will follow a trajectory similar to that of the past 2 decades. The 

production trajectory considered deviates from strict linear extrapolation of historical data and is 

somewhat flattened. The increased gap between crushed-stone and sand and gravel operations 

(Figure 125) is consistent with the societal trend of having large operations at one location for a 

long period of time, rather than having dispersed generally smaller sand and gravel operations. 

However, both categories are expected to grow in the future. The overall growth rate is 1.5%–2% 

(Table 61). Some analysts have projected an annual growth in the industry of 3%–5% (Walden 

and Baier, 2010). Although industry has been significantly impacted by the current economic 

recession, it is anticipated that demand for aggregate products will continue to grow with the 

population and the need for roadway and other building materials. It is not clear, however, how a 

3% annual growth (translating into a production of ~1,200 million tons/yr in 2060) can be 

sustained in terms of water use without increasing water recycling or developing dry processes. 

The aggregate water use projections presented in this report can therefore be construed as either 

modest annual growth with no change from current practices or higher annual growth with 

concomitant decrease in water use. In addition, although most mining facilities are operated for 

at least 20 years, and although some larger operations have 100 years or more of reserves, small 

“mom & pop” quarries may be operated for as little as 5 years and are often associated with 

specific development projects or other short-term, localized demands. This observation carries 

the understanding that many small facilities could appear in counties not listed in Table 63, 

which shows sand and gravel water-use projections. Table 62 does the same for crushed stone. 

Table 64 summarizes projections displayed at the county level in Figure 126 and Figure 127. 

Overall aggregate will increase from ~50 thousand AF/yr in 2010 to ~100 thousand AF/yr in 

2060. 
202 

Table 61. Historical and projected population and aggregate production 

Year 

Crushed Stone 

(million tons) 

Sand and Gravel 

(million tons) Population 

Average Annual 

Population Change 

1990 55 42 16,986,510 

2000 110 74 20,851,820 386,531

2010 164 105 25,388,403 453,658

2020 198 124 29,650,388 426,199

2030 232 144 33,712,020 406,163

2040 268 165 37,734,422 402,240

2050 307 187 41,924,167 418,975

2060 346 210 46,323,725 439,956

Table 62. Crushed-stone water use projections per county through 2060 

County 2008 2010 2020 2030 2040 2050 2060 

Bell 0.747 0.803 1.039 1.278 1.460 1.681 1.914 

Bexar 3.108 3.341 4.051 4.603 5.038 5.502 6.070 

Brown 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

Burnet 0.280 0.301 0.384 0.460 0.535 0.598 0.678 

Callahan 0.131 0.140 0.141 0.141 0.136 0.133 0.129 

Comal 3.634 3.907 4.739 5.473 6.123 6.651 7.378 

Cooke 0.818 0.880 1.133 1.349 1.576 1.893 2.181 

Coryell 0.275 0.296 0.355 0.397 0.429 0.463 0.505 

Eastland 0.150 0.161 0.168 0.178 0.211 0.213 0.225 

Ector 0.168 0.181 0.196 0.212 0.218 0.229 0.240 

Ellis 2.898 3.115 3.564 4.213 5.047 6.004 6.827 

Floyd 0.169 0.182 0.190 0.195 0.202 0.208 0.213 

Glasscock 0.095 0.102 0.107 0.112 0.114 0.117 0.121 

Hidalgo 0.170 0.183 0.244 0.310 0.364 0.415 0.477 

Hutchinson 0.127 0.137 0.152 0.172 0.186 0.193 0.207 

Jack 0.238 0.256 0.302 0.322 0.363 0.405 0.450 

Johnson 3.091 3.323 3.816 4.479 5.347 6.337 7.197 

Kaufman 2.063 2.218 2.492 2.903 3.507 4.263 4.864 

Lampasas 0.293 0.314 0.374 0.417 0.449 0.483 0.526 

Limestone 0.210 0.226 0.250 0.280 0.294 0.332 0.359 

Maverick 0.052 0.056 0.065 0.072 0.077 0.079 0.085 

Medina 0.287 0.308 0.360 0.397 0.425 0.453 0.491 

Montague 0.104 0.111 0.129 0.150 0.181 0.205 0.232 

Nolan 0.023 0.025 0.025 0.025 0.024 0.023 0.022 

Oldham 0.165 0.177 0.204 0.244 0.275 0.288 0.315 

Parker 0.170 0.183 0.218 0.264 0.318 0.372 0.425 

Potter 0.192 0.206 0.235 0.275 0.305 0.318 0.345 

Reeves 0.014 0.015 0.016 0.016 0.017 0.018 0.019 
203 

County 2008 2010 2020 2030 2040 2050 2060 

Sabine 0.053 0.057 0.060 0.063 0.066 0.069 0.072 

San Patricio 0.340 0.366 0.419 0.464 0.491 0.510 0.546 

Stonewall 0.019 0.021 0.020 0.019 0.019 0.018 0.017 

Taylor 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

Travis 0.135 0.145 0.188 0.230 0.272 0.310 0.355 

Uvalde 0.055 0.059 0.072 0.078 0.081 0.086 0.093 

Walker 0.454 0.488 0.660 0.842 1.086 1.337 1.572 

Webb 0.226 0.243 0.331 0.435 0.521 0.611 0.710 

Williamson 2.273 2.444 3.152 3.796 4.412 5.046 5.750 

Wise 1.422 1.529 1.882 2.263 2.685 3.177 3.639 

Young 0.035 0.038 0.040 0.043 0.045 0.049 0.052 

Table 63. Sand and gravel water-use projections per county through 2060 

County 2008 2010 2020 2030 2040 2050 2060 

Atascosa 0.350 0.420 0.526 0.615 0.698 0.755 0.846 

Bastrop 0.063 0.076 0.113 0.162 0.225 0.310 0.387 

Bell 0.346 0.415 0.523 0.622 0.710 0.800 0.907 

Bexar 1.028 1.233 1.233 1.233 1.233 1.233 1.233 

Borden 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

Bosque 0.013 0.015 0.018 0.018 0.019 0.021 0.023 

Brazoria 0.565 0.678 0.866 1.064 1.289 1.533 1.790 

Brazos 0.230 0.276 0.347 0.403 0.495 0.474 0.521 

Burnet 0.031 0.037 0.050 0.064 0.079 0.100 0.120 

Coke 0.003 0.004 0.004 0.005 0.005 0.006 0.006 

Colorado 1.540 1.848 2.033 2.190 2.372 2.440 2.543 

Comal 0.099 0.119 0.180 0.242 0.305 0.382 0.464 

Cooke 0.026 0.031 0.040 0.048 0.066 0.073 0.085 

Dallas 1.574 1.889 1.889 1.889 1.889 1.889 1.889 

Denton 1.262 1.514 2.106 2.678 3.332 4.293 5.191 

Duval 0.604 0.725 0.796 0.846 0.810 0.748 0.713 

El Paso 0.581 0.697 0.880 1.063 1.266 1.482 1.721 

Fannin 0.006 0.007 0.011 0.016 0.023 0.027 0.033 

Fayette 0.082 0.098 0.123 0.145 0.183 0.241 0.287 

Fort Bend 0.000 0.000 0.000 0.000 0.001 0.001 0.001 

Galveston 0.282 0.339 0.375 0.402 0.444 0.480 0.514 

Grayson 0.041 0.049 0.061 0.073 0.089 0.106 0.125 

Guadalupe 0.186 0.224 0.318 0.422 0.541 0.674 0.816 

Harris 2.494 2.993 2.993 2.993 2.993 2.993 2.993 

Henderson 0.115 0.138 0.181 0.235 0.304 0.395 0.477 

Hidalgo 0.603 0.723 1.045 1.444 1.850 2.272 2.750 

Hutchinson 0.023 0.027 0.028 0.027 0.026 0.027 0.026 
204 

County 2008 2010 2020 2030 2040 2050 2060 

Jefferson 0.131 0.157 0.180 0.202 0.230 0.280 0.315 

Johnson 0.075 0.090 0.121 0.162 0.214 0.281 0.342 

Jones 0.010 0.012 0.013 0.013 0.013 0.013 0.013 

Kaufman 0.195 0.234 0.296 0.386 0.491 0.646 0.783 

Kerr 0.059 0.071 0.076 0.080 0.100 0.102 0.111 

Lampasas 0.012 0.015 0.017 0.019 0.021 0.023 0.025 

Liberty 0.108 0.129 0.165 0.206 0.253 0.310 0.365 

Lubbock 0.415 0.498 0.554 0.601 0.676 0.745 0.807 

McLennan 1.025 1.230 1.444 1.732 1.868 2.228 2.509 

Medina 0.063 0.076 0.097 0.117 0.138 0.157 0.180 

Montague 0.010 0.012 0.013 0.014 0.015 0.017 0.018 

Montgomery 0.028 0.033 0.050 0.071 0.101 0.135 0.167 

Navarro 0.062 0.075 0.096 0.123 0.155 0.198 0.236 

Nueces 0.445 0.534 0.654 0.780 0.892 0.981 1.104 

Oldham 0.002 0.002 0.002 0.001 0.001 0.000 0.000 

Orange 0.136 0.163 0.176 0.191 0.220 0.238 0.256 

Parker 0.253 0.304 0.393 0.424 0.503 0.580 0.674 

Potter 0.308 0.370 0.456 0.583 0.711 0.790 0.909 

Reeves 0.008 0.010 0.011 0.013 0.015 0.016 0.018 

San Patricio 0.055 0.067 0.086 0.107 0.125 0.144 0.166 

Smith 0.106 0.127 0.154 0.184 0.246 0.317 0.376 

Somervell 0.386 0.463 0.552 0.613 0.636 0.668 0.715 

Starr 0.142 0.170 0.229 0.296 0.357 0.418 0.491 

Tarrant 1.093 1.312 1.312 1.312 1.312 1.312 1.312 

Travis 0.718 0.862 0.862 0.862 0.862 0.862 0.862 

Val Verde 0.031 0.037 0.046 0.054 0.060 0.065 0.072 

Victoria 0.000 0.000 0.000 0.000 0.000 0.000 0.000 

Ward 0.016 0.020 0.022 0.023 0.025 0.028 0.029 

Washington 0.018 0.022 0.024 0.026 0.030 0.032 0.035 

Webb 0.005 0.006 0.009 0.012 0.016 0.020 0.024 

Wise 0.229 0.275 0.345 0.445 0.584 0.734 0.886 

Table 64. Summary of aggregate water-use projections 

2010 2020 2030 2040 2050 2060 

Water-Use Projection (1000s AF) 

Crushed Stone 26.5 31.8 37.2 42.9 49.1 55.3

Sand and Gravel 22.0 25.2 28.6 32.1 36.1 40.3

Total 48.5 57.0 65.7 75.0 85.2 95.6
205 

0

40

80

120

160

1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010

Calendar Year

Production (million tons) 

15

20

25

30

Population (million)

Sand and Gravel

Crushed Stone

Population

Source: USGS (Aggregate production) and TWDB (population)

Figure 124. Historical population and aggregate production in Texas 

0

100

200

300

400

1990 2000 2010 2020 2030 2040 2050 2060

Calendar Year

Production (million tons) 

0

10

20

30

40

50

Population (million)

Sand and Gravel

Crushed Stone

Population

Source: USGS (aggregate production to 2008) and TWDB (population through 2060) 

Figure 125. Historical population and projection for population and aggregate production in 

Texas 

Results Summary revised 9-20-10_JP_3=SetUrbanAreasLow.xls 

Results Summary revised 9-20-10_JP_3=SetUrbanAreasLow.xls 
206 

0

1

2

3

4

5

6

7

8

2000 2010 2020 2030 2040 2050 2060

Calendar Year

Crushed Stone Annual County Water Use (1000's AF)

Bell

Bexar

Brown

Burnet

Callahan

Comal

Cooke

Coryell

Eastland

Ector

Ellis

Floyd

Glasscock

Hidalgo

Hutchinson

Jack

Johnson

Kaufman

Lampasas

Limestone

Maverick

Medina

Montague

Nolan

Oldham

Parker

Potter

Reeves

Sabine

San Patricio

Stonewall

Taylor

Travis

Uvalde

Walker

Webb

Williamson

Wise

Young

Figure 126. Crushed-stone water-use projections per county through 2060 

Results Summary revised 9-20-10_JP_3=SetUrbanAreasLow.xls 
207 

0

1

2

3

4

5

6

2000 2010 2020 2030 2040 2050 2060

Calendar Year

Sand and Gravel Annual County Water Use (1000's AF)

Atascosa

Bastrop

Bell

Bexar

Borden

Bosque

Brazoria

Brazos

Burnet

Coke

Colorado

Comal

Cooke

Dallas

Denton

Duval

El Paso

Fannin

Fayette

Fort Bend

Galveston

Grayson

Guadalupe

Harris

Henderson

Hidalgo

Hutchinson

Jefferson

Johnson

Jones

Kaufman

Kerr

Lampasas

Liberty

Lubbock

McLennan

Medina

Montague

Montgomery

Navarro

Nueces

Oldham

Orange

Parker

Potter

Reeves

San Patricio

Smith

Somervell

Starr

Tarrant

Travis

Val Verde

Victoria

Ward

Washington

Webb

Wise

Figure 127. Sand and gravel water-use projections per county through 2060 

Results Summary revised 9-20-10_JP_3=SetUrbanAreasLow.xls 
208 

5.5 Industrial Sand 

As seen in the Current Water Use section, industrial-sand mining is more water intensive than 

the closely related category of aggregate and consumes almost 10 thousand AF. Industrial-sand 

production is clearly connected to the increase in well stimulation/fracing through the use of 

proppants, although proppant sand used in Texas can be imported from out of state and sand 

produced in Texas exported out of state. There is no doubt that a significant fraction of the 

locally produced sand is used by the oil and gas industry. Assuming that a proppant loading of 1 

lb/gal translates into 0.163 million tons/ thousand AF of frac water, then 35.8 thousand AF (2008 

fracing water use) would correspond to 5.8 million tons. This figure is above the current Texas 

production of 3.58 million short tons in 2008 (Figure 128), suggesting that a significant fraction 

of the proppant is either not necessarily all natural sand or that it comes from out of state. A close 

examination of the production plot shows that departure from the background trend can be 

attributed to use to the oil and gas industry and that 1.5 million tons of industrial sand (only a 

fraction of the amount needed) was used, along with 38.5 thousand AF, to frac wells in Texas. 

We then assumed that this proportion stays constant in the next few decades (that is, that local 

production and imports from out of state grow at the same rate) and applied it to the water-use 

projections for fracing. We then distributed the results as they were distributed between counties 

and facilities in the Current Water Use section without incorporating important elements such as 

mining reserves or proximity to oil and gas plays. We assumed that the water coefficient would 

linearly improve from the current 620 gal/t to a value of 350 gal/t in 2060. The maximum water 

use close to 18 thousand AF is projected to be reached in the 2020–2030 decade (Table 65). 

5.6 Other Nonfuel Minerals 

In this section, we extrapolate from figures presented in the Current Water Use section. As we 

did previously, we neglect water use in the dimension-stone industry. We use extrapolation from 

current trends for lime and gypsum (Table 66 and Table 67) and expect no change in water use in 

clay, salt, sodium sulfate, or talc categories. 

5.6.1 Uranium

The South Texas uranium province has already produced ~80 million lb U3O8. In 2003, EIA 

(2010) projected that 27 million lb U3O8 at 0.089% U3O8 on average and 40 million lb U3O8 at 

~0.062% U3O8 on average remained in the ground in Texas, for a market price of $50 and 

$100/lb U3O8, respectively. As of January 2011, market price hovered at ~$60/lb. These reserves 

are, however, dwarfed by reserves in the western states (Wyoming, New Mexico, Arizona, 

Colorado, Utah), with 462 and 1,034 million lbs U3O8, for the same price cutoffs of $50 and 

$100/lb, respectively. In addition to the three counties with permits active in 2010 (Brooks, 

Duval, Kleberg), a sixth permit is pending at TCEQ in Goliad County; it has generated vigorous 

public participation. The RRC website lists exploration permits as of January 2011 in nine 

counties: Atascosa, Bee, Brooks, Duval, Goliad, Jim Hogg, Karnes, Kleberg, and Live Oak (and 

an additional permit in Briscoe County in the Texas Panhandle), to which can be added DeWitt, 

Jim Wells, McMullen, and Webb Counties (Figure 129). However, we assumed no change in 

current water use or of its distribution. 

5.6.2 Other Metallic Minerals 

On the basis of decades-long evaluation and development activities, three deposits seem to have 

potential for near-term mining: (1) Shafter silver deposit, Presidio County; (2) Round Top 
209 

beryllium-uranium-rare earth element deposit, Hudspeth County; and (3) Cave Peak 

molybdenum deposit, Culberson County. 

5.6.2.1 Shafter Deposit 

The Shafter deposit in Presidio County, 18 miles north of the Rio Grande, is the closest to actual 

production (http://www.aurcana.com/s/NewsReleases.asp?ReportID=439022), as plans for silver 

production by mid-2012 have been announced. This deposit is the downdip extension of the ore 

zone of the Presidio silver mine that was in production from 1883 until the early 1940s. The 

planned silver production follows a decade of activity by several predecessor companies, all 

building on an extensive exploration and limited development program in the late 1970s and 

early 1980s. The designed production rate for this underground mine is 1500 tons of ore per day, 

with measured and indicated reserves for more than 5 years of production, and additional 

resources for an additional 5 years of production, given favorable economic conditions. Burgess 

(2010) provided a detailed feasibility study for the Shafter mine, including plans for water 

management as: “Two distinct phases in the water management plan are envisaged. The first 

phase will involve mining operations performed above the water table with no ground water 

being produced from this activity. During this phase, mining operations will be a small net 

consumer of water in the form of drill water and dust control water. Process plant make-up 

water will be obtained from the old underground workings in Block 1 which lie below the water 

table and are flooded with an estimated 20 million gallons of water. These old workings are 

recharged from a deep aquifer at a rate of 350 gpm, this figured being based on the inflows 

observed by Gold Fields when they were developing Block 1 in the early 1980 ́s. During this first 

phase of operations, no excess water will be generated as only the net requirements of the 

process plant and the underground workings will be drawn from the old workings of Block 1.” 

and “The second phase is when the decline face encounters the water table at approximately 900 

Level, prior to which the 20 million gallons of water standing in the test mine in Block 1 will be 

pumped out through the Gold Fields shaft. By dewatering the Goldfields Shaft and Block 1 test 

mine in this manner, the water table will be lowered in advance of the decline face to reduce the 

amount of ground water encountered. The second phase also entails mining operations 

simultaneously occurring above the water table in Blocks 2 to 5. Mining Block 1 entails 

removing standing water (estimated at 20 million gallons) and groundwater inflows. This phase 

will produce a net excess of water of 350 gpm from ground water flowing into the underground 

mine which will be clarified in underground settling sumps to reach compliance with EPA 

criteria and then disposed of by discharge to the environment in a dry creek at the south west 

corner of the property (Arroyo del Muerto).” 

The Shafter ore zone is below the water table, so dewatering of the ore zone prior to and during 

production will more than account for any water used in mining per se. Furthermore, a 

considerable excess of water required for all of the Shafter operation will be produced. For the 

stated rate of ore production for the 5-year period, Burgess’ s analysis indicates that total water 

used by the operation will average 104 AF per year, of which less than 20 AF per year will be 

used in mining and surface use around the mine. Source water derived from pumping of the ore 

zone will average 565 AF per year for the designed ore production rate of 1500 tons per day 

(even accounting for a nominal 10% ore dilution and development headings). Thus, excess

water production for the five-year period will average more than 500 AF per year

(groundwater). If the current silver resources prove economically viable to extend production 
210 

beyond the initial five-year period, there is little reason to doubt that these relative figures would 

also apply to that extended amount and period of production. 

5.6.2.2 Round Top Deposit 

The Round Top beryllium-uranium-rare earth element deposit near Sierra Blanca in Hudspeth 

County is currently being reevaluated (http://www.standardsilvercorp.com/projects/round-top/), 

building on an extensive exploration program for beryllium in the 1980s (Rubin et al., 1990). 

The impetus for Round Top exploration has been boosted by the current emphasis on developing 

domestic REE sources to counter restricted supply from foreign sources, notably China. 

Although the mineralization controls at Round Top are only broadly understood, it is worth 

noting that this geologic environment is represented throughout a considerable portion of west 

Texas, suggesting regional potential for additional deposits. However, at this point, production 

even from the Round Top deposit would be hypothetical, and thus water needs are not possible 

to constrain. 

5.6.2.3 Cave Peak Deposit 

The molybdenum and associated metals deposit at Cave Peak in Culberson County has an 

exploration history also dating to the 1960s (Sharp, 1979). Following a considerable period of 

inactivity, the Cave Peak property has recently attracted renewed interest 

(http://www.quaterraresources.com/projects/cave_peak/). While geologically similar 

molybdenum deposits are sites of significant mining operations in other states, it is too early in 

the evaluation process to determine if Cave Peak represents an economically viable resource, let 

alone assess any potential water needs and impacts. 

5.6.3 Conclusions

Uranium solution mining is likely to continue in Texas but a large increase in production and 

water use is not expected because of the competition of other deposits in the U.S. and elsewhere. 

The planned Shafter mine has a life-expectancy in the decade range (currently 2012-2022), so 

barring discovery of substantial new resources locally, its water use (actually the mine’s local 

supply of excess water) would not have a long term impact on regional water issues. Should any 

of the other metallic and industrial mineral deposits prove economically viable even at modest 

mining rates, even though the total water consumption likely would be relatively small, there 

could be significant impacts on local (ground)water supplies in the arid west Texas region. 

Although Frasch sulfur is not produced anymore in Texas, sulfur remains a widely used 

industrial chemical, notably in the production of agricultural fertilizers, but the domestic and 

global sulfur supply currently is dominated by “nondiscretionary” sulfur recovery from refineries 

of sour crude oil and natural gas and from metal refineries as mandated by the Clean Air Act. 

Thus, it seems unlikely that Frasch sulfur production will ever return to economic viability in 

Texas, but should it do so, it could affect local water demand, particularly in west Texas. There 

are additional metal resources, namely zinc, lead, and silver, in association with some salt dome 

cap rocks that could represent a hypothetical mining activity over an extended timeframe (Kyle, 

1999). 
211 

Table 65. Projected county-level industrial-sand water consumption 

County 2008 2020 2030 2040 2050 2060 

Atascosa 0.43 0.79 0.72 0.54 0.44 0.35

Colorado 0.43 0.79 0.72 0.54 0.44 0.35

Dallas 0.04 0.07 0.07 0.05 0.04 0.03

El Paso 0.04 0.07 0.07 0.05 0.04 0.03

Guadalupe 0.07 0.13 0.12 0.09 0.07 0.06

Harris 0.14 0.26 0.24 0.18 0.14 0.12

Hood 0.43 0.79 0.72 0.54 0.44 0.35

Hunt 0.07 0.13 0.12 0.09 0.07 0.06

Johnson 0.04 0.07 0.07 0.05 0.04 0.03

Liberty 0.14 0.26 0.24 0.18 0.14 0.12

Limestone 1.30 2.37 2.18 1.64 1.32 1.07

Mason 0.56 1.02 0.94 0.71 0.57 0.46

McCulloch 4.21 7.69 7.07 5.32 4.27 3.46

Montgomery 0.76 1.39 1.28 0.96 0.77 0.62

Newton 0.14 0.26 0.24 0.18 0.14 0.12

Orange 0.07 0.13 0.12 0.09 0.07 0.06

Robertson 0.04 0.07 0.07 0.05 0.04 0.03

San Saba 0.28 0.51 0.47 0.35 0.28 0.23

Smith 0.07 0.13 0.12 0.09 0.07 0.06

Somervell 0.14 0.26 0.24 0.18 0.14 0.12

Tarrant 0.21 0.38 0.35 0.27 0.21 0.17

Wise 0.07 0.13 0.12 0.09 0.07 0.06

Total 9.68 17.68 16.26 12.24 9.82 7.95

Table 66. Projected county-level lime-mining water consumption (AF) 

2008 2020 2030 2040 2050 2060 

Bosque 8.5 11.3 12.7 14.1 15.4 16.8 

Burnet 2.8 3.7 4.1 4.5 5.0 5.4 

Comal 6.6 8.7 9.8 10.8 11.9 12.9 

Johnson 13.1 17.4 19.5 21.7 23.8 25.9 

Travis 15.1 20.0 22.5 24.9 27.3 29.8 

(AF) 46 61 69 76 83 91 

Table 67. Projected county-level gypsum-mining water consumption (AF) 

2008 2020 2030 2040 2050 2060 

Fisher 3.3 4.0 4.0 4.0 4.0 4.0 

Gillespie 3.3 4.0 4.0 4.0 4.0 4.0 

Hardeman 6.6 8.0 8.0 8.0 8.0 8.0 

Kimble 1.5 1.8 1.8 1.8 1.8 1.8 

Nolan 14.8 17.8 17.8 17.8 17.8 17.8 

Stonewall 1.2 1.4 1.4 1.4 1.4 1.4 

Wheeler 1.2 1.4 1.4 1.4 1.4 1.4 

(AF) 32 38 38 38 38 38 

Lime_count.xls 
212 

0

2

4

6

8

10

1990 2000 2010 2020 2030 2040 2050 2060

Calendar Year

Texas Industrial Sand Production (Mt)

Historical Production

Projected Production

Background Trend

Figure 128. Projection of industrial-sand production 

Gypsum_count.xls 

IndustrialSand_count.xls
213 

Figure 129. Counties prospective for uranium mining as of 2010 
214 

5.7 Water Use for Speculative Resources 

Given that these resources are fairly speculative at this point and that even order-of-magnitude 

projections are impossible, their water use was not included in the projections. Information is 

provided, however, to alert stakeholders that it may be an option in the future when market 

conditions are favorable. 

5.7.1 Heavy Oil 

Large resources exist across the country and North America (for example, Veil and Puder, 2006; 

Veil and Quinn, 2008). Texas contains perhaps the largest heavy oil/tar sands reserves in the U.S 

after Utah. Heavy oil is generally defined as having an API density of between 10o and 20o. 

Below 10o API, the term tar (or bitumen) is generally used. Tar sands (called oil sands in 

Canada) of interest are San Miguel D and Anacacho of Cretaceous age in mostly Kinney, 

Maverick, Medina, Ulvalde, and Zavala Counties in the Maverick Basin. Asphaltic material 

(residue that occurs where a reservoir crops out after evaporation of the volatile or after water 

washing such as a reservoir subject to shallow groundwater systems) is still being produced in 

quarries operated by Vulcan Materials and by Martin-Marietta (Ewing, 2009, p. 27). Seni and 

Walter (1993) also mentioned heavy-oil deposits of Eocene age along the South Texas Gulf 

Coast (whether these accumulations have been or are currently produced through conventional 

means is unclear). Reserves of at least 3 Bbbl are reported (4.8 Bbbl in Kuuskraa et al., 1987), 

but they could be as high as 10 Bbbl (Ewing, 2009, p. 17). The Oil&Gas Journal (Moritis, 2010) 

claimed 7–10 Bbbl of OOIP. Heavy-oil deposits are different from oil shales, in which oil has 

not left the source rock and may still be in the form of kerogen, the chemical precursor to oil. 

A typical production method consists of elevating the temperature of the deposits to lower the 

viscosity of the oil and allow it to flow to the production wells, which is done through steam 

injection or in situ combustion. Steam injection is used if the heavy oil is not too deep (<3,000 ft) 

because of heat loss along the well bores. Deposits, if shallow, can also simply be mined in open 

pits (as is done in Canada) and processed using steam. Stang and Soni (1984) mentioned a 

steam:oil ratio of 10.9 and 8.2 on two 1+-year-long test sites. U.S. DOE (ca. 2007) described the 

<3 ratio of Canada tar sands as being particularly favorable. Veil and Quinn (2008, p. 47) 

mentioned a ratio of 9 bbl/bbl for the Chevron operations in Kern River field in California, about 

half of the water being recycled. They also discussed other field-water use, ranging from 2 to 12 

bbl/bbl. Figures in Torrey (1967, Table 6) projecting water use for the whole state of Texas 

suggest an average ratio of 3.9 bbl/bbl (for an oil production of ~2.7 Bbbl). The Oil&Gas

Journal (Koottungal, 2010) reported that a steam flood is operating in Anderson County, 

although it is unclear what the target of the flood is. In a hypothetical case that 50% of the 

resource is recoverable (Tyler, 1984, p. 147; Stang and Soni, 1984), recovered solely through 

steam injection, and that it will be exhausted in 50 years, this scenario could be represented as 

5×109

 bbl /2 /50 yr × 5 bbl/bbl × 42 gal/bbl /325,851 gal/AF/1,000 = 32 thousand AF/yr, that is, 

16 thousand AF/yr with a recycling of 50%. This amount does not include potentially needed 

dewatering of the shallow aquifers. Other much smaller deposits also exist across the state 

(Tyler, 1984), but their potential production contribution is dwarfed by the uncertainty of the 

South Texas deposits. 

Cyclic interest (20–30 year cycle?) in these resources generally occurs when the price is oil is 

reasonably high—as it is currently (new tests were very recently performed) and as it was in the 

early 1980s. In the 1960s, although oil prices were stable, Texas underwent a steady growth in 
215 

field development as well, interrupted by the 1971 RRC decision to lift the production limit 

(Nicot, 2009b). 

5.7.2 Enhanced Coalbed Methane Recovery 

Coalbed methane (CBM) is generally produced by depressurization (that is, water production) of 

the formation that the coal seams are part of. A drop in pressure releases some of the methane 

sorbed to the coal matrix. PGC (2010, Table 91 and p. 359) mentioned a figure of 3.4 Tcf of gas 

in the speculative category (compared with 156.2 Tcf in the combined probable, possible, and 

speculative categories) for Texas and Louisiana Gulf Coast Pliocene-Eocene lignites. These 

figures are not entirely accurate at present because CBM is currently produced from Louisiana 

coal (Echols, 2001; Clayton and Warwick, 2006; Foss, 2009), although they do underline the 

small potential. Louisiana and East Texas Wilcox coal seams have a low dip, resulting in a large 

economical surface footprint whereas Central Texas Wilcox has a steeper dip resulting in a 

smaller potential for economic production (P. Warwick, USGS, personal communication, 2010); 

that is, coal plunges quickly beyond economical depth. The coal may have been charged through 

local bioprocesses (MacIntosh et al., 2010) or by thermogenic gas migrating from deeper in the 

basin (Arciniegas, 2006; McVay et al., 2007). How much of that water required being extracted 

would be fresh, brackish, or saline is unclear. 

In addition, a company has apparently successfully tested the gas potential of Olmos coals in the 

Maverick Basin (San Filipo, 1999; PGC, 2010, p. 359). PGC (2010, p. 360) pointed out that, 

despite the presence of Pennsylvanian-Permian coal, the Fort Worth/Strawn Basins do not seem 

to contain potentially recoverable resources, in disagreement with an interpretation by Hackley et 

al. (2009b). 

5.7.3 Coal to Liquid 

The production of coal and, thus, water through dewatering, may also be affected by an 

increasing interest in coal-to-liquids (or coal liquefaction) technologies (CTL). CTL involves the 

conversion of solid coal through direct or indirect coal liquefaction into liquid fuels and 

chemicals by breaking down coal’s molecular structure and adding hydrogen. Whereas no 

known pilot plants exist in Texas (one is planned in Natchez, Mississippi), future interest in the 

possibility of creating liquid fuel from lignite may increase coal production in the long term. 

Because lignite is cheap and abundant within Texas, its practical application is for mine-ofmouth operations. There are, therefore, no transportation costs, offsetting the cost of burning 

lower grade coal, a more dependable and local source of fuel. However, the need for liquid fuels 

to compete with oil and natural gas may increase the possibility that coal will be used for CTL 

production. A discussion of the implications, management strategies, and obstacles facing CTL 

production will provide insight into its application as a liquid fuel rather than a source of 

electricity. 

Because the need for a nearby abundant water supply can be a problem for many CTL plants, it 

would be logical to mine lignite where depressurization is needed, that is, the Wilcox lignite of 

Central Texas. An estimate comes to ~5 to 8 bbl of water per barrel of CTL (this is, 

manufacturing water use) (Hebel, 2010, Chapter 3). An average of 1.5 to 1.8 bbl of CTL is 

produced per ton of coal. Full-scale CTL plants are expected to operate at 30,000 to 80,000 bpd. 

At the low end, a plant would consume ~6.5 million tons of coal per year (Hebel, 2010, Chapter 

4), as well as 8.5 thousand AF/yr of water. The ability to use the water pumped from 

depressurization and dewatering needs of a coal mine would enhance the sustainability of a CTL 
216 

plant by not putting additional pressure on the groundwater resources. Also, it is likely that a 

CTL would need deep water wells as the nearby coal-mine operations draw down the aquifer, 

which increases the amount of energy needed to pump the water. Overall, start of coal-to-liquid 

operations will increase coal mining and water use in both manufacturing and mining sectors. 

5.8 Conclusions and Synthesis for Future Water Use 

Combining all water uses, projections suggest that peak mining-water use will occur in the 

2020–2030 decade at ~250 thousand AF, sustained by oil and gas activities (Figure 130). 

Hydraulic fracturing represents the most significant fraction of oil and gas mining use (Figure 

131). Percentages of oil and gas water use currently below 50% of total water use, would reach 

its largest fraction at 50+% in 2015–2030. Fracing is dominant in that use (Figure 132). 

Eventually oil and gas water use will be slowly taken over by aggregate-water use, which is 

projected to constitute >50% of total mining-water use by 2050 (Figure 133). 
217 

0

50

100

150

200

250

300

2010 2020 2030 2040 2050 2060

Calendar Year

Water Use (thousand AF)

ALL O&G Aggregate Coal Others

Figure 130. Summary of projected water use by mining-industry segment (2010–2060) 

0

50

100

150

2010 2020 2030 2040 2050 2060

Calendar Year

Water Use (thousand AF)

O&G Shale Gas Tight Fm. Waterflood Drilling

Figure 131. Summary of projected water use in the oil and gas segment (2010–2060) 

MiningWaterUse2010-2060_2.xls 

MiningWaterUse2010-2060_2.xls 
218 

0.0

0.2

0.4

0.6

0.8

1.0

2010 2020 2030 2040 2050 2060

Calendar Year

Fraction of O&G Water Use

Shale Gas Tight Fm. Waterflood Drilling

Figure 132. Summary of relative fraction of projected water in the oil and gas segment (2010–

2060) 

0.0

0.2

0.4

0.6

0.8

1.0

2010 2020 2030 2040 2050 2060

Calendar Year

Fraction of Total Water Use

O&G Aggregate Coal Others

Figure 133. Summary of relative fraction of projected water use by mining-industry segment 

(2010–2060) 

MiningWaterUse2010-2060_2.xls 

MiningWaterUse2010-2060_2.xls 
219 

6 Conclusions and Recommendations 

This study was undertaken to help in constraining water use in the mining industry. Overall in 

2008, the industry as a whole consumed ~140 thousand AF of fresh water. The uncertainty 

associated with this value is relatively high as only figures from the coal industry (26.7 thousand 

AF) are well known because of legal requirements. Water usage for fracing in the oil and gas 

industry is also relatively well-constrained (35.8 thousand AF) because reported to the RRC with 

other parameters gathered during well completion. Other water uses in the oil and gas industry 

such as for drilling and waterfloods (21 thousand AF) are known by about a factor 2. Fresh water 

use for aggregate and similar commodities (lime, industrial sand, etc) production are not wellknown and rely on educated guesses supported by limited survey results. We also estimate that 

fresh-water use is known by about a factor 2 for sand and gravel operations and maybe by a 

factor of 1.5 for generally larger crushed stone and industrial sand operations. Water use from 

some large facilities or some small contributors (uranium, metallic substances) are well 

documented but they make up only a small fraction of the total state water use. Applying those 

uncertainty factors implies that the true water use is within the 105-195 thousand AF range but 

those bounds are much less likely than the value of ~140 thousand AF derived in this document 

(Figure 134). Table 68 presents year 2008 overall water use results at the county leve. Clearly the 

uncertainty increases as the area of interest decreases in size, particularly if it contains 

unaccounted-for aggregate facilities or if the facility size has been overestimated. Comparison 

between published TWDB estimates and results of this work (Figure 135) shows that, by 

selecting the top 20 high water user counties in the mining category, only 10 of them overlapped. 

County-level projections for the 2010-2060 period are given in Table 69. They suggest that peak 

mining-water use will occur in the 2020–2030 decade at ~250 thousand AF, decreasing to ~175 

thousand AF by 2060. Many assumptions went into the building of the projections, in particular 

related to the activities of the oil and gas industry. Water use for those counties in which a large 

component of the mining water use is from shale gas fracing or those counties overlying 

currently little-known (mostly deep) oil or gas accumulations can deviate dramatically from the 

projections owing to political/legal and economic factors. Water use projections could be 

improved if the starting point, current water use, was better known. 

This study emphasized the difficulties in gathering information on water use and the 

disappointing limitations of voluntary surveys, in particular whether the surveyed entities are 

representative of their respective mining segment as a whole. In other words, our survey 

sampling is likely biased. The low response rate may reflect the general reluctance of the mining 

industry to provide competitively sensitive information that is not required or to divert staff 

resources to obtain and submit data that is not routinely kept for business purposes. 

Continuing to work with trade associations and expanding that cooperation to include other 

organizations appears to be necessary and appropriate to improve data collection. Lessons 

learned from this study can be used to develop refined, focused data collection, designed in 

consultation with a small workgroup of mining-industry representatives and related agencies and 

organizations, to effectively ground-truth water use/consumption and production assumptions in 

the industry and to calculate water-use coefficients on the basis of an acceptable, reproducible 

methodology. A useful alternative approach would be to make use of the recent progress in 

analyzing satellite imagery (in particular through time) to complement/confirm data obtained 

through surveys. 
220 

Table 68. County-level summary of mining water use (oil and gas drilling not included) 

County 

Mining Water 

Use (AF) County 

Mining Water 

Use (AF) County 

Mining Water 

Use (AF) 

Anderson 13 Gillespie 3 Moore 1

Andrews 684 Glasscock 346 Morris 0

Angelina 90 Goliad 9 Motley 4

Aransas 0 Gonzales 0 Nacogdoches 384

Archer 7 Gray 24 Navarro 70

Armstrong 0 Grayson 43 Newton 141

Atascosa 781 Gregg 128 Nolan 112

Austin 0 Grimes 0 Nueces 453

Bailey 0 Guadalupe 256 Ochiltree 77

Bandera 0 Hale 109 Oldham 171

Bastrop 2,152 Hall 0 Orange 206

Baylor 0 Hamilton 0 Palo Pinto 235

Bee 6 Hansford 4 Panola 1,926

Bell 1,093 Hardeman 7 Parker 2,191

Bexar 4,136 Hardin 1 Parmer 0

Blanco 0 Harris 3,169 Pecos 238

Borden 126 Harrison 6,673 Polk 0

Bosque 21 Hartley 3 Potter 501

Bowie 0 Haskell 31 Presidio 0

Brazoria 568 Hays 0 Rains 0

Brazos 239 Hemphill 721 Randall 0

Brewster 0 Henderson 143 Reagan 460

Briscoe 0 Hidalgo 847 Real 2

Brooks 295 Hill 1,137 Red River 1

Brown 8 Hockley 1,881 Reeves 153

Burleson 34 Hood 2,584 Refugio 0

Burnet 314 Hopkins 935 Roberts 216

Caldwell 0 Houston 13 Robertson 7,684

Calhoun 3 Howard 56 Rockwall 0

Callahan 160 Hudspeth 0 Runnels 27

Cameron 0 Hunt 70 Rusk 1,836

Camp 4 Hutchinson 156 Sabine 53

Carson 1 Irion 105 San Augustine 88

Cass 0 Jack 323 San Jacinto 0

Castro 0 Jackson 4 San Patricio 398

Chambers 0 Jasper 0 San Saba 280

Cherokee 120 Jeff Davis 0 Schleicher 16

Childress 0 Jefferson 131 Scurry 39

Clay 22 Jim Hogg 2 Shackelford 75

Cochran 390 Jim Wells 0 Shelby 0

Coke 37 Johnson 11,678 Sherman 3

Coleman 35 Jones 51 Smith 235

Collin 0 Karnes 0 Somervell 697

Collingsworth 0 Kaufman 2,258 Starr 209
221 

County 

Mining Water 

Use (AF) County 

Mining Water 

Use (AF) County 

Mining Water 

Use (AF) 

Colorado 1,972 Kendall 0 Stephens 1,786

Comal 3,740 Kenedy 27 Sterling 67

Comanche 1 Kent 297 Stonewall 238

Concho 27 Kerr 59 Sutton 1

Cooke 1,081 Kimble 1 Swisher 0

Coryell 275 King 121 Tarrant 6,450

Cottle 2 Kinney 0 Taylor 25

Crane 403 Kleberg 280 Terrell 12

Crockett 113 Knox 1 Terry 99

Crosby 20 Lamar 0 Throckmorton 69

Culberson 64 Lamb 13 Titus 622

Dallam 0 Lampasas 305 Tom Green 32

Dallas 1,690 La Salle 27 Travis 868

Dawson 250 Lavaca 18 Trinity 0

Deaf Smith 0 Lee 2,089 Tyler 0

Delta 0 Leon 740 Upshur 43

Denton 4,013 Liberty 248 Upton 1,313

DeWitt 13 Limestone 2,469 Uvalde 55

Dickens 9 Lipscomb 145 Val Verde 33

Dimmit 49 Live Oak 3 Van Zandt 492

Donley 0 Llano 0 Victoria 0

Duval 904 Loving 68 Walker 454

Eastland 277 Lubbock 774 Waller 0

Ector 509 Lynn 51 Ward 87

Edwards 2 McCulloch 4,220 Washington 18

Ellis 2,994 McLennan 1,025 Webb 349

El Paso 621 McMullen 44 Wharton 6

Erath 295 Madison 0 Wheeler 1,074

Falls 0 Marion 30 Wichita 20

Fannin 6 Martin 569 Wilbarger 3

Fayette 82 Mason 560 Willacy 5

Fisher 153 Matagorda 8 Williamson 2,273

Floyd 169 Maverick 75 Wilson 1

Foard 1 Medina 350 Winkler 30

Fort Bend 4 Menard 2 Wise 3,938

Franklin 2 Midland 700 Wood 6

Freestone 3,631 Milam 0 Yoakum 863

Frio 4 Mills 0 Young 38

Gaines 3,033 Mitchell 75 Zapata 107

Galveston 282 Montague 691 Zavala 0

Garza 196 Montgomery 788 SUM 129,662*

*: oil and gas drilling not included MiningWaterUse2010-2060_2.xls
222 

Table 69. County-level summary of 2010-2020 projections for mining water use (oil and gas 

drilling not included) 

County 2010 2020 2030 2040 2050 2060 

Anderson 8 26 84 67 42 16

Andrews 678 1,014 743 377 152 47

Angelina 0 426 534 367 200 33

Aransas 9 17 22 16 11 5

Archer 3 1,619 1,293 370 0 0

Armstrong 0 0 0 0 0 0

Atascosa 851 2,998 4,368 3,672 3,055 2,497

Austin 0 48 256 279 221 163

Bailey 0 0 0 0 0 0

Bandera 0 0 0 0 0 0

Bastrop 2,164 2,613 5,662 5,725 5,810 5,887

Baylor 0 0 0 0 0 0

Bee 23 47 58 43 29 14

Bell 1,218 1,562 1,901 2,170 2,481 2,821

Bexar 4,574 5,284 5,836 6,271 6,736 7,304

Blanco 0 0 0 0 0 0

Borden 109 395 318 165 58 0

Bosque 937 2,576 1,096 33 37 40

Bowie 0 0 0 0 0 0

Brazoria 716 941 1,157 1,359 1,578 1,812

Brazos 276 865 1,534 1,418 1,187 1,024

Brewster 0 0 0 0 0 0

Briscoe 0 0 0 0 0 0

Brooks 305 329 342 326 310 294

Brown 5 1 1 1 1 1

Burleson 0 594 1,295 1,055 816 576

Burnet 341 437 528 619 704 804

Caldwell 0 0 0 0 0 0

Calhoun 17 33 42 31 21 10

Callahan 158 146 145 139 135 131

Cameron 25 50 62 46 30 14

Camp 3 1 1 0 0 0

Carson 0 0 0 0 0 0

Cass 0 52 66 46 25 4

Castro 0 0 0 0 0 0

Chambers 0 0 0 0 0 0

Cherokee 23 254 288 188 89 0

Childress 0 0 0 0 0 0

Clay 635 3,731 1,664 0 0 0

Cochran 5 2 1 1 1 1

Coke 114 38 26 23 21 20

Coleman 21 6 4 3 3 3

Collin 0 0 0 0 0 0

Collingsworth 0 0 0 0 0 0
223 

County 2010 2020 2030 2040 2050 2060 

Colorado 2,304 3,728 4,851 4,490 4,087 3,744

Comal 4,033 4,928 5,725 6,438 7,044 7,855

Comanche 429 2,524 1,125 0 0 0

Concho 108 33 21 18 15 13

Cooke 1,016 1,457 1,516 1,643 1,966 2,267

Coryell 296 2,147 1,537 692 463 505

Cottle 7 2 1 1 1 1

Crane 144 297 225 99 43 31

Crockett 58 121 71 21 1 1

Crosby 228 69 43 37 32 28

Culberson 33 1,334 4,126 3,236 2,533 1,830

Dallam 0 0 0 0 0 0

Dallas 2,549 2,731 2,227 1,940 1,930 1,922

Dawson 147 404 324 170 63 5

Deaf Smith 0 0 0 0 0 0

Delta 0 0 0 0 0 0

Denton 3,188 2,693 2,678 3,332 4,293 5,191

DeWitt 24 1,114 1,740 1,402 1,063 725

Dickens 0 0 0 0 0 0

Dimmit 218 2,625 3,790 2,999 2,275 1,551

Donley 0 0 0 0 0 0

Duval 1,052 1,170 1,243 1,177 1,085 1,020

Eastland 231 1,317 1,348 608 223 234

Ector 499 762 630 413 290 243

Edwards 0 0 0 0 0 0

Ellis 3,440 3,799 4,276 5,047 6,004 6,827

El Paso 737 953 1,131 1,317 1,523 1,754

Erath 2,017 2,500 882 0 0 0

Falls 0 0 0 0 0 0

Fannin 7 11 16 23 27 33

Fayette 98 965 1,982 1,680 1,398 1,104

Fisher 94 32 21 19 17 15

Floyd 213 200 201 207 212 217

Foard 1 0 0 0 0 0

Fort Bend 23 47 58 44 29 14

Franklin 1 0 0 0 0 0

Freestone 3,766 4,862 4,268 3,984 3,493 3,026

Frio 0 180 744 717 566 414

Gaines 584 1,060 933 676 498 400

Galveston 339 375 402 444 480 514

Garza 77 155 91 27 2 1

Gillespie 3 4 4 4 4 4

Glasscock 492 1,414 1,230 740 364 131

Goliad 22 45 56 42 27 13

Gonzales 0 79 420 458 363 267

Gray 14 4 3 2 2 2

Grayson 50 62 73 89 107 125
224 

County 2010 2020 2030 2040 2050 2060 

Gregg 132 422 573 398 222 51

Grimes 0 59 314 342 271 200

Guadalupe 294 446 540 629 745 873

Hale 271 82 51 45 39 33

Hall 0 0 0 0 0 0

Hamilton 190 1,118 498 0 0 0

Hansford 75 675 62 0 0 0

Hardeman 7 8 8 8 8 8

Hardin 0 0 0 0 0 0

Harris 3,668 3,784 3,763 3,705 3,670 3,643

Harrison 7,044 9,418 8,624 7,850 7,076 6,380

Hartley 2 0 0 0 0 0

Haskell 19 6 4 3 3 2

Hays 0 0 0 0 0 0

Hemphill 694 364 33 0 0 0

Henderson 138 440 562 529 518 498

Hidalgo 948 1,372 1,858 2,292 2,738 3,251

Hill 1,008 1,249 441 0 0 0

Hockley 1 0 0 0 0 0

Hood 2,150 1,775 937 544 436 353

Hopkins 929 903 902 901 901 901

Houston 0 0 0 0 0 0

Howard 321 1,293 1,111 618 238 2

Hudspeth 0 0 0 0 0 0

Hunt 70 128 118 88 71 58

Hutchinson 174 240 206 213 221 233

Irion 366 1,176 1,097 674 295 21

Jack 2,091 2,008 857 363 405 450

Jackson 22 45 56 42 28 13

Jasper 0 0 0 0 0 0

Jeff Davis 0 0 0 0 0 0

Jefferson 157 180 202 230 280 315

Jim Hogg 30 60 75 56 37 17

Jim Wells 23 45 57 42 28 13

Johnson 6,774 5,565 4,969 5,633 6,682 7,598

Jones 37 20 18 17 17 16

Karnes 20 1,153 1,399 1,117 834 551

Kaufman 2,452 2,788 3,289 3,998 4,908 5,648

Kendall 0 0 0 0 0 0

Kenedy 38 76 95 71 46 22

Kent 6 2 1 1 1 1

Kerr 71 76 80 100 102 111

Kimble 1 2 2 2 2 2

King 1,818 553 345 299 258 223

Kinney 0 0 0 0 0 0

Kleberg 305 329 342 326 310 294

Knox 1 0 0 0 0 0
225 

County 2010 2020 2030 2040 2050 2060 

Lamar 0 0 0 0 0 0

Lamb 136 41 26 22 19 17

Lampasas 329 391 437 470 506 551

La Salle 280 2,989 4,300 3,398 2,570 1,742

Lavaca 25 621 1,839 1,638 1,276 914

Lee 2,089 2,547 5,749 5,772 5,715 5,659

Leon 678 1,680 2,701 2,431 1,732 1,034

Liberty 269 420 441 430 452 480

Limestone 2,500 7,333 6,258 5,630 5,242 4,928

Lipscomb 126 508 47 0 0 0

Live Oak 28 229 784 741 577 414

Llano 0 0 0 0 0 0

Loving 174 251 148 50 11 9

Lubbock 1,805 952 849 891 931 967

Lynn 273 214 128 59 29 25

McCulloch 4,219 7,690 7,073 5,324 4,274 3,460

McLennan 1,230 2,825 2,413 1,930 2,228 2,509

McMullen 30 2,154 3,383 2,682 2,038 1,395

Madison 0 278 865 775 607 438

Marion 24 665 728 494 259 33

Martin 588 1,279 1,103 622 247 10

Mason 560 1,023 941 708 568 460

Matagorda 31 61 77 57 37 18

Maverick 57 954 2,837 2,395 1,893 1,395

Medina 384 457 514 563 610 671

Menard 250 76 47 41 35 31

Midland 537 1,260 1,090 612 239 4

Milam 0 0 0 0 0 0

Mills 0 0 0 0 0 0

Mitchell 69 153 90 26 0 0

Montague 666 3,317 1,579 197 222 250

Montgomery 793 1,438 1,348 1,062 906 792

Moore 1 0 0 0 0 0

Morris 0 0 0 0 0 0

Motley 27 8 5 5 4 3

Nacogdoches 436 4,384 3,426 2,298 1,170 52

Navarro 77 97 124 156 198 236

Newton 140 256 235 177 142 115

Nolan 85 56 51 49 47 45

Nueces 556 699 837 934 1,009 1,118

Ochiltree 77 673 62 1 1 0

Oldham 182 207 246 277 289 315

Orange 233 304 309 308 309 314

Palo Pinto 464 2,632 1,174 3 3 2

Panola 2,095 3,700 3,507 2,815 2,123 1,500

Parker 4,489 2,398 840 821 952 1,098

Parmer 0 0 0 0 0 0
226 

County 2010 2020 2030 2040 2050 2060 

Pecos 102 769 2,132 1,648 1,280 926

Polk 0 0 0 0 0 0

Potter 576 692 859 1,016 1,108 1,254

Presidio 0 0 0 0 0 0

Rains 0 0 0 0 0 0

Randall 0 0 0 0 0 0

Reagan 679 1,640 1,420 796 310 3

Real 0 0 0 0 0 0

Red River 1 0 0 0 0 0

Reeves 431 1,815 3,330 2,362 1,742 1,270

Refugio 21 42 53 39 26 12

Roberts 183 447 41 0 0 0

Robertson 7,763 8,859 9,552 10,267 11,079 12,009

Rockwall 0 0 0 0 0 0

Runnels 60 18 11 10 9 7

Rusk 1,328 4,075 3,868 3,130 2,391 1,669

Sabine 268 2,327 1,816 1,244 674 102

San Augustine 435 3,044 2,152 1,431 711 31

San Jacinto 0 0 0 0 0 0

San Patricio 451 542 616 651 676 723

San Saba 280 511 470 354 284 230

Schleicher 52 137 127 78 35 4

Scurry 67 154 90 25 0 0

Shackelford 46 1,135 1,160 391 6 6

Shelby 616 4,540 3,335 2,225 1,114 62

Sherman 9 61 6 0 0 0

Smith 201 386 433 425 437 443

Somervell 1,373 1,251 945 813 810 830

Starr 202 292 376 416 456 510

Stephens 1,086 2,184 1,384 450 154 133

Sterling 119 406 328 170 61 1

Stonewall 154 61 46 42 38 34

Sutton 106 241 141 40 0 0

Swisher 0 0 0 0 0 0

Tarrant 4,669 2,799 1,665 1,577 1,525 1,484

Taylor 15 5 3 2 2 2

Terrell 149 132 78 34 15 13

Terry 84 156 91 28 3 2

Throckmorton 42 13 8 7 6 5

Titus 621 1,001 1,000 1,000 1,000 1,000

Tom Green 11 3 2 2 2 1

Travis 1,022 1,070 1,115 1,159 1,200 1,247

Trinity 0 0 0 0 0 0

Tyler 0 0 0 0 0 0

Upshur 7 605 988 694 400 105

Upton 744 1,776 1,522 842 321 0

Uvalde 59 72 78 81 86 93
227 

County 2010 2020 2030 2040 2050 2060 

Val Verde 59 96 83 68 65 72

Van Zandt 483 475 473 473 473 472

Victoria 23 46 58 43 28 14

Walker 488 660 842 1,086 1,337 1,572

Waller 0 0 0 0 0 0

Ward 145 347 323 179 112 90

Washington 22 391 1,166 1,051 831 612

Webb 475 1,934 2,296 1,995 1,705 1,425

Wharton 29 57 72 53 35 17

Wheeler 699 367 35 1 1 1

Wichita 12 4 2 2 2 2

Wilbarger 2 0 0 0 0 0

Willacy 16 31 39 29 19 9

Williamson 2,444 3,152 3,796 4,412 5,046 5,750

Wilson 0 474 1,473 1,320 1,033 746

Winkler 151 334 270 125 60 44

Wise 6,094 4,315 3,133 3,358 3,982 4,583

Wood 4 1 1 1 1 0

Yoakum 278 202 120 59 31 27

Young 40 604 621 238 49 52

Zapata 27 55 68 51 33 16

Zavala 0 550 1,712 1,494 1,169 845

SUM 136,639* 224,749* 229,263* 196,538* 181,116* 170,893*

*: oil and gas drilling not included MiningWaterUse2010-2060_2.xls 
228 

0

50

100

150

200

250

300

1970 1975 1980 1985 1990 1995 2000 2005 2010

Calendar Year

Historical Estimation of Historical 

Water Use (thousand AF)

0%

25%

50%

75%

100%

Fraction of Ground Water

GW SW Total GW fraction

Source: TWDB website 

Figure 134. Historical estimation of historical mining-water use 

Most likely year 2008 water use is highlighted by the large circle. Also shown is the range of 

uncertainty. 

0

5

10

15

20

Andrews

Bastrop

Bexar

Chambers

Coke

Colorado

Comal

Crane

Denton

Duval

Ector

Ellis

Freestone

Gaines

Harris

Harrison

Hood

Johnson

Kaufman

Kleberg

Lee

Limestone

McCulloch

Parker

Robertson

Tarrant

Travis

Waller

Williamson

Wise

County Mining Water Use (thousand AF)

This study (year 2008)

TWDB WUS (year 2007)

Figure 135. Comparison of high mining water use 

rptWaterUseSummaryByState_TWDB-WUS_1974-2004_+to 2007_JP.xls 

MiningWaterUse2008_2.xls 
229 

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243 

8 Appendix List 

Appendix A: Relevant Websites 

Appendix B: Post-Audit of 2007 BEG Barnett Shale Water Use Projections 

Appendix C Relevant Features of the Geology of Texas 

Appendix D: Survey Questionnaires 

Appendix E: Supplemental Information Provided by GCDs 

Appendix F: Water Rights Permit Data and 2008 Water Rights Reporting Data 

Appendix G: x 

Appendix H: x 

Appendix I: x 

Appendix J: List of Files Submitted to TWDB and Content 

Appendix K: Responses to Review Comments 

245 

9 Appendix A: 

Relevant Websites 
246 

All categories 

USGS mineral production: http://minerals.usgs.gov/minerals/

USGS water use: http://water.usgs.gov/watuse/ 

USGS e-library: http://pubs.er.usgs.gov/ 

U.S. Census Bureau: http://www.census.gov/econ/www/mi0100.html; 

http://www.census.gov/mcd/ 

TWDB water use survey (WUS): http://www.twdb.state.tx.us/wrpi/wus/wus.htm 

MSHA mine database (including abandoned mines): http://www.msha.gov/drs/drshome.htm 

 http://www.msha.gov/drs/asp/extendedsearch/statebycommodityoutput2.asp 

EIA: http://www.eia.doe.gov/ 

BEG publications: http://www.beg.utexas.edu/publist.php 

Aggregates:

Trade journals: 

Aggregate Manager: http://www.aggman.com/ 

Pit & Quarry: http://www.pitandquarry.com/ 

Rock Products: http://rockproducts.com/ 

Mining Engineering: http://www.smenet.org/ 

Trade Associations: 

National Stone, Sand, and Gravel Association (NSSGA): http://www.nssga.org/ 

TMRA: http://www.tmra.com/ 

TACA: http://www.tx-taca.org/ 

Oil and Gas: 

Operators

Chesapeake: http://www.chesapeake.com/Pages/default.aspx 

http://www.chk.com/Pages/default.aspx 

Devon Energy: http://www.devonenergy.com

Barnett Shale Water Conservation & Management Committee: 

http://www.barnettshalewater.org/ 

Trade Associations: 

TXOGA: http://www.txoga.org/ 

Regulators: 

RRC H10 query: http://webapps.rrc.state.tx.us/H10/h10PublicMain.do 

Permit application: http://www.rrc.state.tx.us/forms/publications/HTML/index.php 

All RRC forms: http://www.rrc.state.tx.us/forms/forms/og/purpose.php 

Fresh-water questionnaire: http://www.rrc.state.tx.us/forms/publications/HTML/fw-ques.php 

UIC query: http://webapps2.rrc.state.tx.us/EWA/uicQueryAction.do 

RRC Barnett Sh.: http://www.rrc.state.tx.us/barnettshale/index.php

RRC Haynesville Sh.: http://www.rrc.state.tx.us/bossierplay/index.php 

RRC Eagle Ford Sh.: http://www.rrc.state.tx.us/eagleford/index.php 

USGS NOGA: 

1995 assessment: http://energy.cr.usgs.gov/oilgas/noga/1995.html 

Gulf Coast: http://energy.er.usgs.gov/regional_studies/gulf_coast/gulf_coast_assessment.html 

Coal

CBM in Gulf Coast: http://energy.cr.usgs.gov/oilgas/cbmethane/pubs_data_gulf.html 

RRC maps of coal resources: http://www.rrc.state.tx.us/forms/maps/historical/historicalcoal.php 
247 

RRC table of coal production: http://www.rrc.state.tx.us/data/production/index.php 

Energy

Future of power generation in Tx: http://www.twdb.state.tx.us/RWPG/rpfgm_rpts.asp

Coal and uranium: http://www.rrc.state.tx.us/industry/smrd.php

Other useful sites: 

Information about drilling rig count: http://www.rigdata.com/index.aspx; 

http://investor.shareholder.com/bhi/rig_counts/rc_index.cfm 

IHS Energy: http://energy.ihs.com/

Drilling info: http://www.info.drillinginfo.com/ 

Aggregate industry: http://www.pitandquarry.com/pit-quarry-content/quarryology-101 

IMPLAN by MIG, Inc.: http://implan.com/V4/Index.php 

249 

10 Appendix B: 

Postaudit of the 2007 BEG Barnett Shale Water-Use 

Projections 

251 

In the 2007 TWDB update of the Northern Trinity GAM (Bené et al., 2007), BEG (Nicot and 

Potter, 2007, summarized in Nicot, 2009a) proposed a methodology for estimating future water 

use related to Barnett Shale activities for 2 decades through 2025. The purpose of this appendix 

is to compare water-use projections with actual water use for the 2007–2009 (report used data 

through mid- to late 2006). At the October 2009 GSA meeting in New Orleans, Nicot and Ritter 

(2009) presented an initial postaudit, which is completed here. 

2007 Report Methodology 

The following steps are a summary of the methodology applied in the 2007 report: 

Step 1: Derive the geographic extent in which frac jobs are likely to take place by integrating gas 

window, formation thickness, and well economics, defining high, low, and medium cases 

(somewhat subjectively). 

Step 2: Use historical data to define average water use per well or per linear of lateral (Figure 

136). Vertical well water use is nicely distributed along a normal distribution around a mean 

of 1.2 Mgal/well. Because defective database entries yielded unnatural water use at both low 

and high ends, averages used in the analysis are computed using data only between the 10th

and 90th percentiles. The raw average and average of the values between the 10th and 90th

percentiles for vertical wells is 1.25 and 1.19 Mgal, respectively. The raw average for 

horizontal wells (2005–2006) is 3.07 Mgal/well, whereas the truncated average is 2.65 

Mgal/well. The relatively more abundant frac jobs with low water use (Figure 136a), 

generating a dissymmetric histogram result from the addition of acid jobs and other common 

well-development and completion practices outside of strictly defined frac jobs. In contrast to 

vertical wells that have a relatively narrow range of lengths/depths, horizontal wells have 

laterals of very variable length (although the vertical sections, as for the vertical wells, belong 

to a relatively narrow range) that translates into a more uniform distribution (Figure 136b). 

Only those frac jobs performed in 2005 and 2006 were included in the histogram of Figure 

136b to avoid bias due to early trials of the slick-water frac technology. Using water-use 

intensity (volume of water per linear of lateral) instead of absolute water use per well yields a 

better-defined histogram (Figure 136c). The averages of values truncated beyond two 

complementary percentiles vary somewhat because of the additional uncertainty due to the 

lateral length, although a value of 2,400 gal/ft seems conservatively reasonable for the 

medium scenario. Values of 2,000 and 2,800 gal/ft were retained for low and high scenarios, 

respectively, for the 2007 report. 

Step 3: Define a maximum water use at the county level by assuming that the county is drilled up 

and apply an average water use per vertical well or per linear of lateral. This step assumes a 

vertical well spacing of at least 40 acres (see Table 70 for details) and a constant distance 

between horizontal well laterals. All horizontal wells were assumed to be parallel to each other 

and to the main fault direction (under the assumption made at the time that operators would 

not want to drill through a large fault because of the risk of watering out the well). This 

assumption results in an extremely large water volume (Figure 137) that needs to be corrected 

and distributed through time. 

Step 4: Apply time-independent correction factors: karst, operations, prospectivity. The sag 

avoidance (“karst”) correction factor was assumed to take into account some reluctance from 

the operators to drill through disrupted Barnett Shale strata that was due to karstic features in 

the underlying Ellenburger Formation. Early on, in the vertical well phase, drilling to and 
252 

connection to the Ellenburger Formation was detrimental to operators because of excessive 

water production. The Ellenberger is a well-known regional (saline water) aquifer. It was 

thought at the time that operators would avoid karstic feature-rich areas because they were 

avoiding well-known faults. It turned out to be less of a concern than thought. Prospectivity 

represents the overall maturity of the shale and its likelihood to contain large economic 

resources in a given county or fraction of county. Prospectivity/risk factor can be understood 

either as a fraction of the area that will be developed or, more accurately, as the mean of the 

probability distribution describing the likelihood of having the county polygon developed 

(already given the high, medium, or low scenario condition). This factor is used simply as a 

multiplier of hypothetical maximum water use. The 2007 report used a prospectivity factor of 

1 for core-area counties but one of 0.7 and 0.5 in Montague and Clay Counties, respectively. 

These oil-prone counties turned out to be more interesting than initially thought. The oil 

potential was thought to be not very prospective and, in fact, a hindrance to gas production. 

Step 5: Add correction factors associated with time-dependent constraints. Growth of recycling 

techniques was assumed to reach a maximum of 20% of total water use in 2025. 

Recompletion/restimulation frequency remains unclear. The 2007 report assumes no 

recompletion for horizontal wells and that a large fraction of the vertical wells would be 

recompleted. The last and most controlling factor is the availability of drilling rigs. There are a 

limited number of active drilling rigs around the country, and their number at a given play is a 

complex function of play activity, oil/gas price, economic climate, relative location of other 

plays, etc. Galusky (2007) reported ~57 and ~93 active rigs in the Barnett Shale play in 2005 

and 2006, respectively, resulting in 12 to 13 wells being drilled per year per rig, on average. 

The 2007 report assumes that there would be no more than 3,000 recompletions a year, 

starting in 2010 and ~2,400 in 2008, both in the “high” scenario case (Figure 138). This 

number turned out to be an underestimation in 2008. The actual number climbed to 2,500+ 

horizontal wells in 2008. 

Step 6: Apply activity weighting curve to each county. This factor takes into account the life 

cycle of hydrocarbon production: initial production, relatively quick increase to peak 

production, peak sustained for a relatively short interval, relatively quick production, followed 

by a slow decrease. The 2007 report based the activity curve on that of Wise County that was 

on its past-peak decreasing limb in 2006 and applied it to all other counties or fractions of 

counties. Start date of each county activity was a function of geographic proximity to the core 

area and prospectivity. 

Step 7: Apply GW/SW split. The 2007 report assumes increased reliance on groundwater. 

Groundwater use would reach 60% to 100% of total water use in 2025. 

Resulting final output of the 2007 report is presented in Figure 139. The high scenario yields a 

total groundwater use of 417,000 AF, an annual average groundwater use of 22,000 AF over the 

2007–2025 period, and a cumulative areal groundwater use of 0.05 AF/acre. The medium and 

low scenarios utilize a total 183,000 and 29,000 AF of groundwater for an annual average of 

~10,000 and 1,500 AF and a cumulative areal groundwater use of ~0.04 and 0.009 AF/acre, 

respectively. A survey completed in the same period (Galusky, 2007) showed that projections 

were accurate in the short term and were bounded by the high and medium scenarios. The next 

section analyzes medium-term projections to the 2010 horizon and compares them to actual 

figures. 
253 

0

100

200

300

400

500

600

700

<0.25

0.25-0.5

0.5-0.75

0.75-1

1-1.25

1.25-1.5

1.5-1.75

1.75-2

2-2.25

2.25-2.5

2.5-2.75

2.75-3

3-3.25

3.25-3.5

3.5-3.75

>3.75

Vertical Frac Water Volume (million gallon) - 2001-2006

Number of bins: 16; Bin size: 0.25 MGal

Number of Frac' Jobs

N=2508

(a) 

0

20

40

60

80

100

120

140

<0.25

0.5-0.75

1-1.25

1.5-1.75

2-2.25

2.5-2.75

3-3.25

3.5-3.75

4-4.25

4.5-4.75

>5

Horizontal Frac Water Volume (million gallon) - 2005-2006

Number of bins: 21; Bin size: 0.25 MGal

Number of Frac' Jobs

N=840

(b) 

0

20

40

60

80

100

120

140

160

<0.5

0.5-1

1-1.5

1.5-2

2-2.5

2.5-3

3-3.5

3.5-4

4-4.5

4.5-5

5-5.5

5.5-6

>6

Horiz. Frac Water Volume Intensity (1,000 gallon / ft) - 2005-2006

Number of bins: 13; Bin size: 1,000 Gal

Number of Frac' Jobs

N=840

(c) 

Source: Nicot and Potter (2007) 

Figure 136. Distribution of water use for vertical wells (a), horizontal wells (b), and per linear of 

lateral of horizontal wells (c). 
254 

0

50,000

100,000

150,000

200,000

250,000

300,000

Bosque

Clay

Comanche

Cooke

Coryell

Dallas

Denton

Ellis

Erath

Hamilton

Hill

Hood

Jack

Johnson

McLennan

Montague

Palo Pinto

Parker

Somervell

Tarrant

Wise

Uncorrected Entire Water Use (AF/county)

sum = 2.8 MAF

Source: Nicot and Potter (2007) 

Figure 137. Uncorrected entire water use 

0

500

1,000

1,500

2,000

2,500

3,000

1990 1995 2000 2005 2010 2015

Calendar Year

Annual Completion

s

High

Medium

Low

Source: Nicot and Potter (2007) 

Figure 138. Projected annual completions 

This is an Absolute Maximum 

Sum = 2800 MAF 
255 

Table 70. Summary description of parameters used in 2007 report water-use projections 

Category Comment High Water Use Medium Water Use Low Water Use 

County Polygon 

There are three binary variable couples: rural/urban—horizontal/vertical wells—within Viola footprint or not, resulting in four main categories: (1) Viola/urban (only horizontal wells), (2) Viola/rural (both horizontal and vertical wells), (3) no Viola/urban (only horizontal wells), and (4) no Viola/rural (only horizontal wells) 

Footprint Fraction A county polygon cannot be covered by >90% (vertical wells) or 80% (horizontal wells) of the maximum possible well coverage. Vertical Well Spacing 1 well/40 acres 0.5 well/40 acres 0.25 well/40 acres 

No Viola and/or urban 800 ft 1,000 ft 2,000 feet Horizontal Well 

Lateral Spacing Viola rural 800 × 4 ft 1,000 × 4 ft 2,000 × 4 ft 

Vertical well 100% Sag Feature Avoidance 

(“Karst”) Horizontal well 100% 75% 40% 

Vertical well 1.2 million gal 

Average Water Use Horizontal well (spread 

reflects uncertainty) 2,800 gal/ft 2,400 gal/ft 2,000 gal/ft 

1% 0% 0% 

Water-Use Progress FactorA (variations reflect technological progress) Water-use annual incremental improvement as a fraction of total water use, e.g., 100% of current use in 2005 with a 1% increment translates into 80% of water use in 2025 

compared with the same frac job executed in 2005 

100% 50% 0% Vertical well of initial completions executed 5 years before Recompletion 

Horizontal well 0% 0% 0% 

1% 0.33% 0% 

RecyclingA Recycling annual increment as a fraction of total water use (e.g., 0% in 2005 with a 1% 

increment translates into 20% recycling in 2025) 

Maximum Number of Sustained Annual Completions 

 3,000 completions/year 2,100 completions/year 1,500 completions/year 

Additional Water Use in Overlying Formations 0% 0% 0% 

In year 2005–2006 60% 60% 60% Annual increment in following years 2% 1% 0% 

Barnett Groundwater Use Expressed as % of Total Barnett Water Use In year 2025 100% 80% 60% Note: A These parameters do not maximize water use, but the likely competition for water in the high scenario suggests that recycling and water-use intensity will 

get better through time. Source: Nicot and Potter (2007) 
256 

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

2005 2010 2015 2020 2025

Calendar Year

Corrected Annual Water Use (AF) 

High

Medium

Low

Survey

(a) 

0

5,000

10,000

15,000

20,000

25,000

30,000

2005 2010 2015 2020 2025

Calendar Year

Corrected Annual Grd. Water Use (AF) 

High

Medium

Low

Survey

(b) 

Source: Nicot and Potter (2007) and Nicot (2009a); survey data points by Galusky (2007) 

Note: The data points used in a previous version of the same plot (Nicot, 2009a) are slightly lower because Galusky 

(2007) included drilling-water use. Nicot (2009a) was estimated at 20% of total water use whereas in this document, 

it is estimated at only 10%. “Survey” point for year 2007 in Galusky (2007) is also a projection but directed by data 

from the first few months of the year. 

Figure 139. 2007 report projected frac total water use (a) and projected frac groundwater use (b) 
257 

Postaudit:

The recent downturn in gas prices has showed us that we cannot expect a linear development of 

the play but that it will go through periods of intense activity followed by calmer phases. I 

Because predicting these cycles is impossible in the long term, we only need to recognize that 

they exist and understand that actual water use will fluctuate around some projected average. 

Nicot and Potter (2007) suggested that peak water use (but not necessarily peak gas production) 

would occur around 2011 (Figure 140a, early years magnified in Figure 140b) after a quick 

ramp-up, followed by a slow decline. Superimposed on the projections are actual water-use 

figures as extracted from the IHS database in the summer of 2010. Initial growth overshot 

projections of the high scenario before crashing down below projected values of the medium 

scenario in 2009 because of the economic downturn. The figure depicts both quarterly water use 

(expressed in AF/yr) and annual values. Cumulative water use falls between high and medium 

scenarios (Figure 141). 

If the match between actual and projected numbers is good at the aggregate level, it is somewhat 

less so at the county level. Water use from four of the counties with significant figures (Denton, 

Johnson, Tarrant, and Wise) are plotted in Figure 142. Individual county matches are acceptable, 

but trends are better preserved by aggregating the four counties. A cross-plot comparison at the 

county level (Figure 143) also suggests that the general trend was well captured regionally but 

that deviations exist at the county level. Comparison of actual data is made against the high 

scenario in Figure 143a (linear scale) and Figure 143b (log scale). The high scenario was 

constructed as bounding—that is, most of the points should be below the unit slope line. 

Neglecting the 2009 points, they are for the most part. The 2009 points are located above the line 

(projected > actual) because of the economic downturn. 

Several important conclusions can be drawn from this exercise: (1) it is possible to make sensible 

projections, at least at a 5-year horizon; (2) projections deviate from actual values as the size of 

the area of interest decreases— county-level projections seem to be noisy and more uncertain 

than projections made for larger geographic areas; (3) county-level projections can be off by a 

factor of 2 or more, even if projections are acceptable at the aggregate level. 
258 

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

2005 2010 2015 2020 2025

Calendar Year

Water Use (AF/yr)

High Medium Low

Actual Rate (Quarter) Actual Rate (Year)

(a) 

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

2005 2006 2007 2008 2009 2010

Calendar Year

Water Use (AF/yr) 

High Medium Low

Actual Rate (Quarter) Actual Rate (Year)

(b) 

Source: Projections from Nicot and Potter (2007); actual water use from IHS database 

Note: Tick for calendar year corresponds to the middle of the year (06/30); water use for each quarter (expressed in 

AF/yr) of a given year is on both sides of the calendar-year tick; 2010 yearly water use assumed that overall water 

use for the year will stay as in the first 2 quarters. 

Figure 140. Comparison of water-use projections and actual figures in the Barnett Shale (2005–

2010) 

barnett counties_year Eric Projections_3Verbose_for FinalReport-Sept.10.xls 
259 

0

25

50

75

100

125

150

2005 2006 2007 2008 2009 2010

Calendar Year

Cumulative Water Use (MAF) 

High Medium Low Actual

Source: Projections from Nicot and Potter (2007); actual water use from IHS database 

Note: Tick for calendar year represents the end of the year (12/31); origin of both projection and actual water use is 

set on 01/01/2006; MAF = thousand AF 

Figure 141. Comparison of cumulative water-use projections and actual figures in the Barnett 

Shale (2006–2010) 

barnett counties_year Eric Projections_3Verbose_for FinalReport-Sept.10.xlss 
260 

Denton County

0

2

4

6

8

10

2006 2007 2008 2009

Water Use (MAF/yr)

Actual Rate

Projections

Johnson County

0

2

4

6

8

10

2006 2007 2008 2009

Water Use (MAF/yr)

Actual Rate

Projections

Tarrant County

0

2

4

6

8

10

2006 2007 2008 2009

Water Use (MAF/yr)

Actual Rate

Projections

Wise County

0

2

4

6

8

10

2006 2007 2008 2009

Water Use (MAF/yr)

Actual Rate

Projections

Total!"!All 4 Counties

0

4

8

12

16

20

2006 2007 2008 2009

Water Use (MAF/yr)

Actual Rate

Projections

MAF = thousand AF 

Figure 142. Comparison of actual vs. projected (high scenario) water use for four counties: 

Denton, Johnson, Tarrant, and Wise. 

CountiesComparison_2010.10.11.xls 
261 

Comparison Actual/Projected

All Counties Included

0

5

10

15

20

25

30

0 5 10 15 20 25 30

Actual Water Use (MAF/yr)

Projected Water Use (MAF/yr)

2006

2007

2008

2009

Comparison Actual/Projected

All Counties Included

0.01

0.1

1

10

100

0.01 0.1 1 10 100

Actual Water Use (MAF/yr)

Projected Water Use (MAF/yr)

2006

2007

2008

2009

MAF = thousand AF 

Figure 143. Comparison of actual vs. projected (high scenario) water use for all Barnett Shale 

counties 

CountiesComparison_2010.10.11.xls 

263 

10 Appendix C: 

Relevant Features of the Geology of Texas 

265 

This appendix provides an overview of the geology of Texas at it applies to hydrocarbon 

accumulations summarized from Ewing (1991). The state can be divided into basins (Figure 

144). Most of West and Central Texas is underlain by Precambrian rocks that crop out mostly in 

the Llano Uplift in Central Texas and locally in the Trans-Pecos area. Starting in the Cambrian 

period, ~550 million years ago, failed continental rifting resulted in widespread deposition of 

shelf sediments on a stable craton (e.g., Ellenburger Group). Carbonate and clastic deposition 

continued until the late Devonian, 350 million years ago. Thickness of the deposits varies, with a 

maximum in the ancestral Anadarko Basin and total removal by erosion of some formations 

along a broad arch oriented NW-SE on the Amarillo-Llano Uplift axis. Beginning in the 

Mississippian period (starting 350 million years ago), the passive-margin history of rifting and 

subsidence was replaced by extensive deep-marine sedimentation and tectonic convergence on 

the eastern flank of the continental margin. This convergence episode yielded the so-called 

Ouachita Mountains, now eroded and buried, whose trace approximately follows the current 

Balcones Fault Zone that runs west from San Antonio and northeast through Austin to the east of 

Dallas. Behind the orogenic belt, during and after the compressive event, sedimentation 

continued in and around several inland marine basins, north and west of the current Balcones 

Fault Zone. Sedimentation was thicker in the basins and thinner or absent on platforms and 

arches. During these times (320– 270 million years ago) major subsidence and sediment 

accumulation, partly fed by the erosion of the Ouachita Mountains, occurred in the Permian 

Basin, including the Delaware and Midland Basins separated by the Central Platform Uplift. 

Farther north, the Anadarko Basin is separated from the Midland Basin by another basin and two 

structural highs. The Anadarko Basin also underwent abundant sedimentation during the 

Pennsylvanian and Permian and included coarse granitic detritus (“granite wash”) from the 

Amarillo Uplift. The Fort Worth Basin is also filled with Pennsylvanian and Permian sediments. 

Beginning in Triassic time (250 million years ago), Texas was again subject to extension and 

volcanism, leading to Jurassic rifting of the continental margin and creation of the Gulf of 

Mexico and Atlantic Ocean. The focus of major geologic events shifted to the eastern part of the 

state. The small rift basins that initially formed were buried under abundant salt accumulation 

(Louann Salt). As the weight of sediments increased, the salt became unstable and started locally 

to move upward in diapirs, a phenomenon still locally active today. During the Cretaceous, 

sediments deposited from shallow inland seas formed broad continental shelves that covered 

most of Texas. Abundant sedimentation in the East Texas and Maverick Basins occurred during 

the Cretaceous. In the Tertiary (starting 65 million years ago), as the Rocky Mountains to the 

west started rising, large river systems flowed toward the Gulf of Mexico, carrying an abundant 

sediment load, in the fashion of today’s Mississippi River. All the area west of the old Ouachita 

Mountain range was also lifted, generating a local sediment source, including erosional detritus 

from the multiple Tertiary volcanic centers in West Texas and Mexico. Six major progradation 

events, where the sedimentation built out into the Gulf Coast Basin, have been described. 

Many Texas basins contain hydrocarbons (Figure 145). Their stratigraphy is detailed for oil and 

gas productive formations in Figure 146 and Figure 147 for the Gulf Coast and East Texas 

Basins and in Figure 148 and Figure 149 for the North-Central and West Texas Basins. 
266 

 

N

LLANO

UPLIFT

ANADARKO

BASIN

HARDEMAN

BASIN

RED RIVER UPLIFT

 EAST

 TEXAS

EMBAYMENT

SABINE

UPLIFT

RIO

 GRANDE

 EMBAYMENT

Uplift

Moderate downwarping

Intensive downwarping

0

0 100 200

100 200 m

300 m

QAd3853 x

Source: modified from Kreitler (1989) 

Figure 144. Generalized tectonic map of Texas showing location of sedimentary basins 
267 

0 100 20 0 300 mi

0 10 0 20 0 30 0 400 km

QAd 373 0x

Major oil reservoirs

Major gas reservoirs

N

Source: BEG map from Galloway et al. (1983) and Kosters et al. (1989) 

Figure 145. Map of major oil and gas fields in Texas 
268 

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Basins (after Galloway and others, 1983) 
269 

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270 

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Figure 149. Stratigraphic column and relative gas production for the North-Central and West 

Texas Basins (after Kosters and others, 1989) 

273 

11 Appendix D: 

 Survey Questionnaires 

275 

During the course of this study, we performed two types of surveys: (1) one aimed at water users 

through trade associations: TMRA and TACA, and (2) one geared toward water 

suppliers/Groundwater Conservation Districts (GCDs). We performed an additional survey of oil 

operators in Texas to inquire about their waterflooding activities. 

11.1 Survey of Facilities 

As part of this study, we enlisted the assistance of two of the major associations representing the 

mining industry in Texas: the Texas Aggregate and Cement Association (TACA) and the Texas 

Mining and Reclamation Association (TMRA). With the endorsement of each association, letters 

were sent on behalf of the TWDB to all of the association member companies with a survey 

form. Forms were provided as both Word documents with narrative questions and as Excel 

documents in spreadsheet format. Examples of the forms are given at the end of this appendix. 

Survey questionnaires were sent to TMRA members in December 2009, and the association 

asked that all responses be returned for review of sensitive or proprietary information. Company 

survey questionnaires were sent to TACA members in February 2010 and handled the same way. 

11.1.1 About the Trade Associations 

The Texas Mining and Reclamation Association (TMRA) has a variety of members—in addition 

to individual members and consultancy, its membership includes the following companies: Clay 

Mining: Acme Brick Company, Boral Bricks, Inc., Elgin Butler Company, Southern Clay 

Products, U.S. Silica Company; Utilities/Lignite/Coal Mining: Luminant Mining, North 

American Coal Corporation, Texas Westmoreland Coal Company, Walnut Creek Mining 

Company, American Electric Power, NRG Energy, San Miguel Electric Cooperative, Inc., Texas 

Municipal Power Agency; Sand, Gravel and Stone Mining: Capitol Aggregates, LTD, Hanson 

Aggregates Central, Inc., Trinity Materials Company, Chemical Lime Company; and Uranium 

Mining: South Texas Mining Venture, Mestena Uranium, LLC, Rio Grande Resources 

Corporation, Signal Equities, LLC, Uranium Energy Corporation, Uranium Resources, Inc. 

The Texas Aggregate and Cement Association (TACA) does not release the list of its 

membership but does include many small aggregate producers. 

11.1.2 Response Rates 

Aggregates: 6 companies representing 27 sites provided responses to the BEG. Complete 

responses are provided in Appendix G and include 

Coal/Lignite: we received information back from all lignite mines in Texas (~100% success 

rate) 

Uranium: we received information from several operators 

11.2 Survey of GCDs 

LBG-Guyton was charged with the task of researching and evaluating groundwater use for 

mining in Texas. We compiled a packet of the mine data that we were able to obtain through 

statewide public sources to send to all GCDs so that they might address any changes to water 

usage that they might be aware of. To begin with, a series of maps and tables of mineral mine 

data and locations throughout Texas were produced so that each district could see what data were 

available publicly. These maps and tables were included in a mailed packet, along with a survey 

requesting any mining information the district had available, an explanation of the data included 
276 

in the packet, and a letter explaining the purpose of the study. The GIS maps contain all Texas 

GCDs and mine locations (active and inactive) in the TCEQ SWAP project database, and the 

data tables include mine data from MSHA and mining water-use projections from TWDB’s 2007 

Water for Texas Report. 

Forty-seven (47) out of one hundred (100) questionnaires (47%) that were sent to GCDs were 

returned. Figure 150 is a map showing the districts that replied, as well as the mine sites that the 

TCEQ report lists as active in the state of Texas. Districts that replied to the survey are colored 

and labeled; all other districts are gray. Questions included in this packet are predominantly yes 

or no questions with requests for explanations of the answers if confirmed. The questions are 

listed in Table 71, with the answer percentage (using only those 47 GCDs that returned 

responses). In addition to the leading questions, explanation was requested if the answer was 

reported as yes. Studying these comments helped us discover some general findings among the 

survey questionnaires returned. In general, we found that few GCDs had extensive knowledge of 

mineral mining or mining water use within the district. Some districts had a general idea of what 

mining operations were active and inactive and could speculate as to how much water was being 

used according to permits, but none of the districts monitored actual water use. 

Also, more districts thought that water use from mining data that had been reported in the 

TWDB report (such as presented in Table 75) was incorrect, excluding those that did not know. 

Few had contacted any of the mining entities, and even fewer had contacted the RRC to obtain 

data on mines. However, nine districts did report some quantitative knowledge of permitted 

volume of water use for specific mining entities. Table 72 details TWDB water use for mining 

WUG predictions from 2010 through 2060 and each of the district’s own reported volumes for 

comparison. 

Table 71. GCD mine-data questions and response percentages 

Question Total 

Answers % Yes % No % Unk† % >0 

1. Does your district independently estimate 

water use by mining? 45 16 % 84 % 

2. Have you contacted Texas Railroad 

Commission to obtain data on mines? 45 4 % 96 % 

3. Do you have any way of validating the 

mining use estimates in Table 3? 45 18 % 82 % 

4. What portion of total water use in your 

district is used for mining?* 36 42 % 36 % 

5. Have you contacted any of the entities 

listed in Table 1 or 2? 44 14 % 86 % 

6. Do you feel the data in Table 3 are 

accurate? 45 9 % 18 % 73 % 

7. Do you know of other mining facilities not 

included on the map? 43 9 % 91 % 

8. Do you have any additional information 

regarding groundwater or surface water use at the 

facilities? 

40 15 % 85 % 

† Unknown—answered “Don’t know” 

*18 % reported 0 % water use for mining 
277 

Table 72. Mining water-use changes reported by certain GCDs 

Volume (ac-ft) 

GCD 

2010 2020 2030 2040 2050 2060 District Reported 

Ratio of 

Reported/ 

Predicted 

2010 Values 

District Notes 

Barton Springs/Edwards Aquifer CD 1699 1821 1902 1982 2060 2116 826 49%

District-reported mine water use reported as industrial WUG. 

Bee GCD 

36 40 42 44 46 48 **105 292%

**% water use (201 ac-ft) split between Bee Co. and Live Oak Co. not specified so was assumed to be half for this exercise. 

Harris-Galveston Subsidence District 1547 1713 1815 1917 2020 2112 25 2%

Other water use reported as commercial or industrial WUG. 

Headwaters UWCD 167 165 164 163 162 161 109 65%Hickory UWCD No. 1 394 395 396 397 398 400 4771 1211%Live Oak UWCD 

3894 4319 4583 4845 5108 5341 **105 3%

**% water use (201 ac-ft) split between Bee Co. and Live Oak Co. not specified so was assumed to be half for this exercise. 

Lost Pines GCD 10483 10485 10486 5487 51 52 4410 42% Reported use by ALCOA in 2009 for lignite mining. McMullen GCD 195 203 207 211 215 218 1 1%Post Oak Savannah GCD 4025 4024 4024 3024 1524 1524 15000 373%

ALCOA water use reported as industrial WUG. Water rights end in 2038. 

*Of those districts that replied with volume calculations, " reported lower volumes of mining water use than in the 2007 state water plan 
278 

Figure 150. GCDs that have returned information on mineral mining water use in their district 
279 

11.3 Questionnaire Forms 

To coal mining operators (modified to save space): 

Date:!!

Name of Company and of Mining Operation (including SIC or SICs):

County of Mine Location:

Contact Name, Phone, E"mail, and Address:

Coal Production

1. Please rank factors affecting the amount of coal you produce from year to year in order from most

(#1) to least important?!!

a. General economy!! !!!!(rank= )

b. Electricity demand projections!! ! !(rank= )

c. Production capacity!! ! ! !! (rank= )

d. Other ______________________________!! (rank= )

e. Other ______________________________!! (rank= )

Water Source

1. Please indicate the approximate amount of water pumped each year as well as the unit used (acre"

feet, gallons, etc.)

_______________________ (unit: __________)

2. Please circle the sources of the water pumped at your operations and indicate the approximate

percentage of each applicable source:

a. Overburden dewatering (______%)

b. Pit dewatering (______%)

c. Depressurization (_____%)

d. Other _______________________ (______%)

Choice (d) is intended for facilities at which additional water not ultimately originating from dewatering

or depressurization is needed (e.g., river, another aquifer)!!

3. Please circle factors affecting the amount of water pumped? (check all that apply)

Dewatering

a. The amount of coal to be produced!!

b. Proximity to surficial aquifer

c. Other _______________________________

Depressurization

a. The amount of coal to be produced

b. The safety factor to prevent floor heave

c. Proximity to aquifer

d. Other _______________________________

Other

a. The amount of coal to be produced

b. Other _______________________________

4. What is the quality (Total Dissolved Solids) of the water pumped at your operations for:

Dewatering

a. Fresh (<1000 mg/L)

b. Brackish ( > 1000 mg/L and < 10,000 mg/L)

c. Saline ( > 10,000 mg/L and < 35,000 mg/L)

d. Very Saline ( > 35,000 mg/L)

Depressurization
280 

a. Fresh (<1000 mg/L)

b. Brackish ( > 1000 mg/L and < 10,000 mg/L)

c. Saline ( > 10,000 mg/L and < 35,000 mg/L)

d. Very Saline ( > 35,000 mg/L)

Other Source ____________________ :

a. Fresh (<1000 mg/L)

b. Brackish ( > 1000 mg/L and < 10,000 mg/L)

c. Saline ( > 10,000 mg/L and < 35,000 mg/L)

d. Very Saline ( > 35,000 mg/L)

5. How often do you monitor the rate and volume of water pumped for depressurization/dewatering?

a. Daily

b. Monthly

c. Every 2"5 months

d. Yearly

e. Other:______________

6. How often do you monitor the quality of water pumped for depressurization/dewatering?

a. Daily

b. Monthly

c. Every 2"5 months

d. Yearly

e. Other:______________!!

7. Do you report the rate and quality of water pumped to a federal, state or local agency?

a. None

b. Texas Railroad Commission

c. Texas Water Development Board

d. Local Groundwater Conservation District

e. Other (please list) ______________

Water Use

1. For what specific mining activities do you consume the water pumped from

dewatering/depressurization? (circle all that apply, provide approximate % if possible)

a. Dust suppression for mining! ! ! (______%)

b. Dust suppression for hauling!! ! (______%)!!

c. Reclamation/revegetation! ! ! (______%)

d. Coal washing! ! ! ! (______%)

e. Transportation! ! ! ! (______%)!!

f. Drilling !!!! (______%)

g. Other (please list) ______________!! ! (______%)

2. Do you report the rate and quality of water consumed to a federal, state or local agency?

a. None

b. Texas Railroad Commission

c. Texas Water Development Board

d. Local Groundwater Conservation District

e. Other (please list) ______________

3. Do you supply water to other entities? Please circle all that apply.

a. None

b. Municipality (Name(s): ________________________ )

c. Water supplier (other than municipality) (Name(s): _______________________ )

d. Local farmers/ranchers/landowners
281 

5. What factors affect whether or not pumped water is provided to these other entities? (circle all that

apply)

a. Quality of water

b. Quantity and consistency of the amount pumped

c. Request from outside water users!!

d. Fee provided by outside water users

d. Other (please list) _____________________________

Water Discharge

1. Where do you discharge the water not consumed during operations? (provide approximate

percentage as needed)!!

Dewatering

a. Freshwater lake or stream!! ! ! (_______%)

b. Retention pond then lake or stream!! ! (_______%)

c. Deep"well injection!! ! ! ! (_______%)!!

d. Other ______________________! ! (_______%)

Depressurization

a. Freshwater lake or stream!! ! ! (_______%)

b. Retention pond then lake or stream!! ! (_______%)

c. Deep"well injection!! ! ! ! (_______%)!!

d. Other ______________________! ! (_______%)

Other Source

a. Freshwater lake or stream!! ! ! (_______%)

b. Retention pond then lake or stream!! ! (_______%)

c. Deep"well injection!! ! ! ! (_______%)!!

d. Other ______________________! ! (_______%)

2. Is the amount of water discharged monitored?

a. Yes

b. No

3. Do you report the monitored quantity to a federal, state or local agency?

a. None

b. Texas Railroad Commission

c. Texas Water Development Board

d. Local Groundwater Conservation District

e. Other (please list) ______________

Future of Lignite mining in Texas

1. Do you foresee any future developments in coal production that would make it more efficient or less

water intensive? (Please list or describe any new technologies and the extent to which produced water

would be decrease)

2. Do you expect water depressurization and dewatering pattern to remain the same over the short"

term (1"9 years)?

a. Yes

b. No If not, why?!!

3. Do you expect water depressurization and dewatering pattern to remain the same over the long"term

(10"50 years)?

a. Yes

b. No

If not, why?!!
282 

To aggregate and other industrial mineral operators (modified to save space): 

Date:

Name of Company & Mining Operation (including SIC or SICs):

County of Mine Location:

Contact Name, Phone, E"mail, and Address:

1) Please provide a brief description of your mining process, the ways that water is used at the facility,

and the ways that water use is monitored or estimated (flow charts are OK). Please separate, if

possible, the industrial mineral mining operations from other product manufacturing (cement, brick,

etc.) that may occur on the same property.

2) Water Amount and Water Use. Please report the amount (specify unit: gallons, acre feet, etc.) of

water used, the amount recycled (actual or percentage), and the net amount consumed in mining

operations annually (or another time unit, in all cases, specify).

Please break this into amounts for each type of use (extraction, rock washing, roadway watering,

dust suppression on conveyor systems, etc.), if possible.

Please break this into amounts obtained from surface water, groundwater, storm water, etc. and

name the source water (stream, lake, aquifer, etc.). Please also note the water quality (fresh,

brackish, saline)

Please report the amount of water typically used in rock washing equipment in gallons per

minute/ton per hour (gpm/tph) of mineral product processed.

Is water discharge out of the facility boundaries sometimes needed? When? How much? Which

water type?

Are these monitored or estimated values? Based on what years?

3) Production. Please report maximum aggregate, sand & gravel, or other industrial mineral mining

production (in tons) authorized per year, and an estimate of the range of typical production in

recent years. Is production expected to increase, decrease, or remain unchanged in coming years?

4) Future Water Use. How many years has the mine been in operation and what is the projected life of

the facility? Are any new industrial mineral mining operations by your company anticipated (if so,

where and when)?!!

What, if any, plans have been made to reduce water use or identify alternative water sources if

water supply is reduced or becomes more expensive?!!

What techniques or technologies could be utilized to reduce water use in the industrial mineral

mining industry? Is use of saline or brackish water possible or likely to become more common?!!

What are the key issues or challenges regarding water use being faced by your industry today or in

the future?!!
283 

To aggregate and other industrial mineral operators (alternate format in excel) 

Name of Company & Mining Operation: Date:County of Mine Location: Type of Mine/SIC:

Contact Name, Phone, E"mail, and Address:

Brief description of your mining process, the ways that water is used at the facility, and the ways that water use is monitored or estimated.

Quantity of Water Used

(Total)

Quantity of WaterRecycled

Quantity of Water

Consumed (Lost)

Quantity of Water Usedin Extraction

Quantity of Water Usedfor Rock Washing

freshbrackishsaline

Quantity of Water Used

for Roadway Watering

Quantity of Water Usedfor Dust Suppression

Quantity of WaterDischarged if any Where? How often?

Rate of Wash Water Use(gpm/tph)

freshbrackishsaline

Surface Water (%)

Name of WaterSource(s) (lake X, river Y,

storm water, etc.) Groundwater (%)

Name of WaterSource(s) (aquifer X,local alluvium, etc.)

freshbrackishsaline

Product Name Typical Production (tpy)

Authorized Production(tpy)

Number of Years of

Mine Operation Projected Life of Facility

Product1Product2Product3Is water use estimated or monitored? Which is the base year?Is production expected to increase, decrease, or remain unchanged in coming years?

Are any new mineral mining operations by your company anticipated (if so, where and when)?

What, if any, plans have been made to reduce water use or identify alternative water sources if water supply is reduced or becomes more

expensive?What techniques or technologies could be utilized to reduce water use in your industry? Is use of saline or brackish water possible or likely to

become more common?

What are the key issues or challenges regarding water use being faced by your industry today or in the future?
284 

To uranium operators (modified to save space): 

Date:

Name of Company & Mining Operation (including SIC or SICs):

County of Mine Location:

Contact Name, Phone, E"mail, and Address:

1) Please provide a brief description of your mining process, the ways that water is used at the facility,

and the ways that water use is monitored or estimated (flow charts are OK). Please separate, if

possible, the mining operations from other operations that may occur on the same property.

2) Water Amount and Water Use. Please report the amount (specify unit: gallons, acre feet, etc) of

water used, the amount recycled (actual or percentage), and the net amount consumed in mining

operations annually.

Please break this into amounts for each type of use (subsurface ISR operations, surface ion exchange

operations, dust suppression, etc.), if possible.

Please break this into amounts obtained from surface water, groundwater, storm water, etc. and

name the source water (stream, lake, aquifer, etc.). Please also note the water quality (fresh,

brackish, saline)

Please report the amount of water typically used/consumed (specify) in gallons per pound of

product (specify U, U3O8, yellow cake, etc.) if possible.

Is water discharge out of the facility boundaries sometimes needed (deep well injection during

restoration)? When? How much? Which water type?

Are these monitored or estimated values? Based on what years?

3) Production. Please report production or an estimate of the range of typical production in recent

years. Is production expected to increase, decrease, or remain unchanged in coming years?

4) Future Water Use. How many years has the mine been in operation and what is the projected life of

the facility? Are any new uranium mining operations by your company anticipated (if so, where and

when)?!!

What, if any, plans have been made to reduce water use or identify alternative water sources if

water supply is reduced or becomes more expensive?!!

What techniques or technologies could be utilized to reduce water use in your industry? Is use of

saline or brackish water possible or likely to become more common?!!

What are the key issues or challenges regarding water use being faced by your industry today or in

the future?!!

11.4 Survey of West Texas Oil Operators
285 

For oil wells: 

Water Use

Fresh 

Water 

(<3,000 TDS) 

Brackish Water 

(3,000–10,000 

TDS) 

Saline Water 

(>10,000 TDS) 

Item Unit 

From 

GW 

From 

SW 

From 

GW 

From 

SW 

From 

GW 

From 

SW Notes/Explanation 

Water used in 2010 for well drilling bbl Project/estimate through 2010. Water used in 2010 for well completion (& fracturing) bbl Project/estimate through 2010. Water used in 2010 for waterflood operations bbl Project/estimate through 2010. Water used for CO2 flood operations bbl Project/estimate through 2010. Other substantial 2010 water use bbl Please note type of use and enter units as appropriate. Operational StatisticsItem Units Notes/Explanation No. vertical oil wells drilled in 2010 number Estimate/project through year's end. Average well depth for vertical wells ft Estimate No. horizontal oil wells drilled in 2010 number Estimate Average total lateral length for horizontal oil wells ft Estimate No. wells "fraced" in 2010 number Estimate/project through year's end. Average depth/length of wells being "fraced" ft Estimate No. acres in active waterflood number Estimate No. acres in active CO2 flood number Estimate Estimated total 2010 oil production from waterfloods bbl Estimate Estimated total 2010 oil production from CO2 floods bbl Estimate Estimated total 2010 associated gas production from waterfloods MMcf Estimate Estimated total 2010 associated gas production from CO2 floods MMcf Estimate 
286 

For gas wells 

Water Use

Fresh 

Water 

(<3,000 TDS) 

Brackish Water 

(3,000–10,000 

TDS) 

Saline Water 

(>10,000 TDS) 

Item Unit 

From 

GW 

From 

SW 

From 

GW 

From 

SW 

From 

GW 

From 

SW Notes/Explanation 

Water used for 2010 well drilling bbl Project/estimate through 2010. Water used for 2010 well completion (& fracturing) bbl Project/estimate through 2010. Other substantial 2010 water use bbl Please note type of use and enter units as appropriate. Operational Statistics Item Units Notes/Explanation No. vertical gas wells drilled in 2010 number Project/estimate through 2010. Average well depth for vertical gas wells ft Estimate No. horizontal gas wells drilled in 2010 number Project/estimate through 2010. Average total lateral length for horizontal gas wells ft Estimate No. wells "fraced" in 2010 number Estimate/project through year's end. Average depth of vertical gas wells being "fraced" ft Estimate Average total lateral length of horizontal gas wells being "fraced" ft Estimate 
287 

To GCDs: 

Several figures and tables (following questionnaires) were sent to each GCD in Texas, along 

with the following questionnaire requesting information about the district’s knowledge of mining 

operations within its borders. 

When answering the following questions, we asked that GCDs not include water use for oil/gas

activities.

1. Does your district independently estimate water use by mining?!!

a. If yes – please describe

2. Have you contacted Texas Railroad Commission to obtain data on mines?

3. Do you have any way of validating the mining use estimates in Table 3? (TWDB projections)

a. If yes – please describe method and result

4. What portion of total water use in your district is used for mining?

5. Have you contacted any of the entities listed in Table 1 or 2?

a. If yes – please describe what you found

6. Do you feel the data in Table 3 are accurate?

a. If yes – why?

b. If no – why?

7. Do you know of other mining facilities not included on the map?

a. If yes – do you have an estimate of the water use?

8. Do you have any additional information regarding groundwater or surface water use at the

facilities?

In addition to figures similar to Figure 7 (Introduction section), we provided the GCDs with 

tables extracted from (1) the SWAP database (Table 73), (2) the MSHA database (Table 74), and 

(3) projections for the TWDB 2007 water plan for the counties included whole or in part in the 

GCD (Table 75). Only the last table gives some indication of mining water use. 

 
288 

Table 73. Example of information provided by the SWAP database (Lost Pines GCD) 

PSOC ID SITE ID SITE NAME LATITUDE (DD) LONGITUDE (DD) HORIZONTAL DATUM LOCATION METHOD AGENCY ACTIVE MINE TYPE COMMODITY GEOLOGIC FORMATION

4343 021BSW201 30.118900 -97.432800 27 MAP-M2 BEG N SAND, GRAVEL WILLIS FORMATION4344 021ELE301 30.363100 -97.268600 27 MAP-M2 BEG Y CLAY-COMMON4345 021ELE501 30.321899 -97.323303 27 MAP-M2 BEG Y CLAY-COMMON4346 021ELE502 30.332800 -97.292503 27 MAP-M2 BEG Y CLAY-COMMON4347 021ELE601 30.322201 -97.285301 27 MAP-M2 BEG Y CLAY-COMMON4348 021LAB401 Powell Bend 30.187500 -97.333336 27 MAP-M1 TNRCC N STRIP MINE COAL-LIGNITE CALVERT BLUFF FORMATION4349 021LAB701 30.163601 -97.340797 27 MAP-M2 BEG Y SAND, GRAVEL FLUVIAL TERRACE DEPOSITS4350 021LAB702 30.156900 -97.339996 27 MAP-M2 BEG N SAND, GRAVEL FLUVIAL TERRACE DEPOSITS4351 021PAI701 30.128300 -97.124199 27 MAP-M2 BEG Y SAND, GRAVEL FLUVIAL TERRACE DEPOSITS4352 021SMI201 30.091101 -97.200798 27 MAP-M2 BEG N SAND, GRAVEL FLUVIAL TERRACE DEPOSITS4353 021SMI202 30.090000 -97.202202 27 MAP-M2 BEG N SAND, GRAVEL FLUVIAL TERRACE DEPOSITS4354 021SMI901 30.015600 -97.164200 27 MAP-M2 BEG N PIT SAND, GRAVEL FLUVIAL TERRACE DEPOSITS4355 021SNW201 30.228300 -97.175598 27 MAP-M2 BEG N SAND, GRAVEL REKLAW FORMATION4356 021TOG201 29.988300 -97.169998 27 MAP-M2 BEG Y SAND, GRAVEL WILLIS FORMATION4357 021TOG301 29.979200 -97.163300 27 MAP-M2 BEG N SAND, GRAVEL WILLIS FORMATION4359 021TOG303 29.988300 -97.129700 27 MAP-M2 BEG Y SAND, GRAVEL WILLIS FORMATION4361 021TOG305 29.973600 -97.134697 27 MAP-M2 BEG Y SAND, GRAVEL WILLIS FORMATION4362 021TOG306 29.975000 -97.137497 27 MAP-M2 BEG Y SAND, GRAVEL WILLIS FORMATION4363 021UTY101 30.223600 -97.464699 27 MAP-M2 BEG N SAND, GRAVEL FLUVIAL TERRACE DEPOSITS4364 021UTY401 30.208099 -97.490303 27 MAP-M2 BEG Y SAND, GRAVEL ALLUVIUM4365 021UTY601 30.175600 -97.413300 27 MAP-M2 BEG Y SAND, GRAVEL FLUVIAL TERRACE DEPOSITS4366 021WEP101 29.988100 -97.095802 27 MAP-M2 BEG N STRIP MINE SAND, GRAVEL ALLUVIUM4367 021WEP102 29.987499 -97.099403 27 MAP-M2 BEG N SAND, GRAVEL FLUVIAL TERRACE DEPOSITS

11080 287BEA701 30.411400 -97.250000 27 MAP-M2 BEG N PIT SAND, GRAVEL SIMSBORO SAND11081 287BEA702 30.392799 -97.237503 27 MAP-M2 BEG N PIT CLAY SPARTA SAND11082 287DIB201 30.343599 -96.805000 27 MAP-M2 BEG Y PIT SAND, GRAVEL YEGUA FORMATION11083 287DIB202 30.343100 -96.796898 27 MAP-M2 BEG N PIT SAND, GRAVEL YEGUA FORMATION11084 287DIB203 30.343300 -96.792503 27 MAP-M2 BEG N PIT SAND, GRAVEL YEGUA FORMATION11085 287DIB204 30.342199 -96.795303 27 MAP-M2 BEG Y PIT SAND, GRAVEL YEGUA FORMATION

Mine Sites in the Lost Pines GCD
289 

Table 74. Example of information provided by the MSHA database sent to GCDs 

Mine ID Mine Name Status Type

Primary 

Commodity

Secondary 

Commodity Operator Name County Street

PO 

Box City State Zip Nearest Town 

4100249 Athens Plant & Pits Intermittent Surface

Common Clays NEC Hanson Brick Henderson

200 Athens Brick Road Athens TX 75751 Athens

4100252 Balcones Pit & Plant Active Surface

Common Clays NEC

Balcones Minerals Corp Fayette

233 Balcones Lane Flatonia TX 78941 Flatonia

4100253 Barrett Base Plt Active Surface

Crushed, Broken Limestone NEC

Alamo Concrete Products Ltd Bexar

6889 EAST EVANS ROAD SAN ANTONIOTX 782662813 San Antonio

4100262 Kosse Plant Active Surface

Common Clays NEC U S Silica Company Limestone FM 2749 Kosse TX 76653 Kosse

4100264 Standard Pit Intermittent Surface

Clay, Ceramic, Refractory Mnls.

Acme Brick Company Bastrop

1776 Old McDade Road Elgin TX 78621 Elgin

Common Clays Elgin-Butler Brick 

Texas MSHA Mine Database

Table 75. Example of information provided by the 2007 TWDB water plan sent to GCDs (Lost Pines GCD) 

291 

12 Appendix E: 

 Supplemental Information Provided by GCDs 
292 

Some GCDs provided useful information. Some have already been mentioned in Appendix D 

(Table 72). As mentioned previously, few responses contained information useful to quantifying 

total groundwater usage by mining operations in Texas GCDs. However, a few are worth 

summarizing here because their account of groundwater usage varies from what is reported in the 

2007 Water for Texas Report. 

In addition, none of the GCDs located in the mining belt reported information regarding lignite 

mining. However, lignite mines and water use shown on the maps within these districts were not 

contested in any of the surveys we received. Five major areas in West Texas produce oil and/or 

gas: Andrews, Stephens, Hockley, Gaines, and Yoakum Counties. Three of these counties have a 

governing groundwater district: Hockley (High Plains UWCD), Gaines (Llano Estacado 

UWCD), and Yoakum (Sandy Land UWCD). We contacted these GCDs as well as Stephens and 

Andrews Counties’ AgriLife Extension Offices. The three GCDs replied to our requests but let 

us know that they do not retain any records of oil/gas water use within their respective districts. 

The two county offices contacted did not reply with any information. 

See Appendix A of LBG-Guyton (2010) for a more detailed summary table and scanned copies 

of responses received from the GCDs that were sent information. 

! The Barton Springs/Edwards Aquifer Conservation District reported one limestone 

mining operation not listed, as well as one mining operation listed as an active quarry that 

is no longer in use. 

! Bee County and Live Oak GCDs reported that they are unaware of any uranium mines 

that are using any water because the uranium mines have been closed, are still in 

reclamation phase, and should not use much or any water. It is conservatively reported 

that 201 ac-ft of groundwater is used for uranium mining between the two districts. 

! Harris-Galveston Subsidence District reported back on five known mining operations and 

their permitted water use: Swiley and Pit Plant (est. use, 100,000 gal/yr), Hockley Mine 

(est. use, 1 million gal/yr), Densimix (est. use, 0.1 million gal/yr), Megasand Enterprises 

(est. use, 3,960 gal/yr), and Petroleum Coke Grinding (est. use, 0 gal/yr). See Appendix 

A f LBG-Guyton (2010) for details on these water users by HGSD. 

! Headwaters UWCD provided a table of mine-water users and their information. It is 

noted in the table that the Wheatcraft pit has a groundwater permit for 62 ac-ft and that 

Martin Marietta has a groundwater permit for 47 ac-ft. See Appendix A of LBG-Guyton 

(2010) for details provided on these water users by HUWCD. 

! Hickory UWCD seemed to have the largest discrepancy between permitted mine-water 

use and reported estimates of water use in the 2007 WFT report. In a table including all 

but two mining operations, permitted water use was reported for McCulloch and Mason 

Counties. The total water permitted for McCulloch County came to 4,212 ac-ft, and the 

total permitted in Mason County, 559 ac-ft. These estimates are much larger than the 171 

and 6 ac-ft (respectively) reported in the 2007 WFT report. 

! Lost Pines GCD reported use of groundwater for lignite mining only. It reported the 

groundwater use by ALCOA in 2009 to be 4,410 ac-ft. 

! McMullen GCD reported that all sand and gravel pits in the district stopped operating and 

stopped using water 20 years ago. This fact may reduce assumed water use in this district 
293 

! Mesa UWCD reported very little water being used for mining currently. 

! Neches and Trinity Valleys GCDs reported that the amounts reported by the 2007 WFT 

report may be excessive because they are ~6% of total current water production in the 

district. 

! Post Oak Savannah GCD reported a 15,000-ac-ft permit for groundwater use by ALCOA 

that ends in 2038. 

! Sutton County UWCD reported no mining operations in Sutton County and that there 

should be no water used for such operations. 

! Red Sands GCD returned only a hand-drawn map showing known mining operations 

within the district, some of which were not shown on the GIS map that had been sent out. 

295 

13 Appendix F: 

Water-Rights Permit Data and 2008 Water-Rights 

Reporting Data 

297 

The following two tables (Table 76 and Table 77) list data dump from of the TCEQ database 

concerning surface-water rights. 

Table 76. 2008 Water-rights reporting data 

!! !! !! Annual Annual Annual

!! !! River Diverted Return Consumed

Year Name of Company Basin Amount Flow Amount

2008 AKIN Sabine 0 0 0

2008 ALAMO CONCRETE PRODUCTS LTD Brazos 165.424 150.205 15.219

2008 ALCOA INC Brazos 0 0 0

2008 ALCOA INC Brazos 0 0 0

2008 ALON USA REFINING INC Colorado 21.3 0 21.3

2008 ASH GROVE TEXAS LP Trinity 289.3 0 289.3

2008 BASELINE OIL & GAS CORP Brazos 1000 0 82.61

2008 BELL SAND COMPANY Neches 4.75 0 0

2008 BLUE SKY OILFIELD SERVICE LLC Brazos 0 0 0

2008 BLYTHE Colorado 0 0 0

2008 BOWIE, CITY OF Trinity 1.3738 0 1.3738

2008 BRAZOS RIVER AUTHORITY Brazos 5268 0 5268

2008 BRAZOS RIVER AUTHORITY Brazos 426 0 426

2008 BRAZOS RIVER AUTHORITY Brazos 0 0 0

2008 BRAZOS RIVER AUTHORITY Brazos 0 0 0

2008 BRAZOS RIVER AUTHORITY Brazos 0 0 0

2008 BRAZOS RIVER AUTHORITY Brazos 0 0 0

2008 BRAZOS RIVER AUTHORITY Brazos 0 0 0

2008 BRAZOS RIVER AUTHORITY Brazos 0 0 0

2008 BRAZOS RIVER AUTHORITY Brazos 0 0 0

2008 BRAZOS RIVER AUTHORITY Brazos 13 0 13

2008 BRAZOS WATER STATION Brazos 29.09 0 29.09

2008 BRECKENRIDGE GASOLINE CO Brazos 0 0 0

2008 BURLINGTON RESOURCES OIL & GAS CO LP Brazos 10 0 10

2008 BURLINGTON RESOURCES OIL & GAS CO LP Brazos 10 0 10

2008 CAMPBELL CONCRETE & MATERIALS LP Brazos 1135 997 140

2008 CAPITOL AGGREGATES LTD Brazos 53.61 0 53.61

2008 CAPITOL AGGREGATES LTD Colorado 0 0 0

2008 CARAWAY Brazos 0 0 0

2008 CAVERN DISPOSAL INC Trinity 36 0 36

2008 CERVENKA Colorado 0 0 0

2008 CHAMBERS"LIBERTY COS ND Trinity 0 0 0

2008 CHESAPEAKE ENERGY INC Brazos 0 0 0

2008 CHEVRON PHILLIPS CHEMICAL CO LP

Brazos"

Colorado 453.71 339.71 0
298 

!! !! !! Annual Annual Annual

!! !! River Diverted Return Consumed

Year Name of Company Basin Amount Flow Amount

2008

CITATION 1994 INVESTMENT LTD

PARTNERSHIP Brazos 0 0 0

2008

CITATION 1998 INVESTMENT LTD

PARTNERSHIP Brazos 0 0 0

2008

CITATION 1998 INVESTMENT LTD

PARTNERSHIP Brazos 58.4567 0 58.4567

2008 CLEBURNE, CITY OF Brazos 0 0 0

2008 COLORADO RIVER MWD Colorado 9 0 0

2008 COLORADO RIVER MWD Colorado 843.2 0 0

2008 COLORADO RIVER MWD Colorado 0 0 0

2008 COLORADO RIVER MWD Colorado 0 0 0

2008 COLORADO RIVER MWD Colorado 0 0 0

2008 CONOCOPHILLIPS CO

Brazos"

Colorado 0 0 0

2008 DALLAS, CITY OF Trinity 0 0 0

2008 DEVON ENERGY PRODUCTION CO LP Brazos 0 0 0

2008 EASTLAND INDUSTRIAL FOUNDATION Brazos 0 0 0

2008 EBAA IRON INC Brazos 0 0 0

2008 EL PASO CO WID 1 Rio Grande 0 0 0

2008 ENCANA OIL & GAS USA INC Brazos 0 0 0

2008 EOG RESOURCES INC Brazos 0 0 0

2008 EOG RESOURCES INC Brazos 0 0 0

2008 EOG RESOURCES INC Brazos 0 0 0

2008 EOG RESOURCES INC Brazos 0 0 0

2008 FAIR OIL LC Cypress 0 0 0

2008 FRANKLIN LIMESTONE COMPANY Brazos 0 0 0

2008 GEOCHEMICAL SURVEYS Brazos 0 0 0

2008 GRAHAM, CITY OF Brazos 0 0 0

2008 GREEN Canadian 0 0 0

2008 GREENBELT M&I WA Red 0 0 0

2008 GULF COAST WATER AUTHORITY Brazos 0 0 0

2008 H R STASNEY & SONS LTD Brazos 54.51 0 0

2008 HALLWOOD PETROLEUM Brazos 0 0 0

2008 HANSON AGGREGATES CENTRAL INC Trinity 2392.24 2221.34 2392.24

2008 HANSON AGGREGATES CENTRAL INC Trinity 0 0 0

2008 HANSON AGGREGATES WEST INC Trinity 0 0 0

2008 HANSON AGGREGATES WEST INC Trinity 125.75 114.44 125.75

2008 HENRIETTA, CITY OF Red 0 0 0

2008 HUDSPETH COUNTY CRD 1 Rio Grande 0 0 0

2008 INGRAM ENTERPRISES LP Brazos 43.85 0 43.85
299 

!! !! !! Annual Annual Annual

!! !! River Diverted Return Consumed

Year Name of Company Basin Amount Flow Amount

2008 J & W SUPPLY INC Brazos 30 0 30

2008 JACKSON SAND & GRAVEL INC Trinity 0 0 0

2008 JANES GRAVEL CO Brazos 446.23 0 0

2008 KEECHI VALLEY CATTLE CO Brazos 0 0 0

2008 KERSH Neches 4.75 0 0

2008 LATTIMORE MATERIALS COMPANY Brazos 63.53 0 63.53

2008 LATTIMORE MATERIALS COMPANY Brazos 572.14 0 572.14

2008 LEONARD WITTIG GRASS FARMS INC

Brazos"

Colorado 0 0 0

2008 LOWER COLORADO RIVER AUTHORITY Colorado 0 0 0

2008 LOWER COLORADO RIVER AUTHORITY Colorado 0 0 0

2008 LUMINANT GENERATION CO LLC Cypress 492 0 492

2008 LUMINANT MINING CO LLC Sabine 376 0 376

2008 LUMINANT MINING CO LLC Sabine 0 0 0

2008

MARTIN MARIETTA MATERIALS

SOUTHWEST INC Trinity 0.25 0 0.25

2008 MINERAL WELLS SAND & GRAVEL Brazos 0 0 0

2008 MOBLEY COMPANY INC Colorado 0 0 0

2008 MOBLEY COMPANY INC Colorado 0 0 0

2008 MOBLEY COMPANY INC Colorado 0 0 0

2008 MOHR Colorado 0 0 0

2008 MORTON SALT COMPANY INC Sabine 76.34 0 0

2008 NORTH CENTRAL TEXAS MWA Brazos 0 0 0

2008 NORTH RIDGE CORPORATION Brazos 0 0 0

2008

NORTH TEXAS LIVING WATER RESOURCES

LLC Brazos 0 0 0

2008

NORTH TEXAS LIVING WATER RESOURCES

LLC Brazos 0 0 0

2008 OCCIDENTAL PERMIAN LTD Brazos 0 0 0

2008 PITCOCK BROTHERS READY"MIX Brazos 0 0 0

2008 PLAINS PETROLEUM OPERATING CO Brazos 0 0 0

2008 PREMCOR PIPELINE CO Neches"Trinity 51.468 0 51.468

2008 PUMPCO INC Brazos 2.7496 0.4677 2.7496

2008 QUICKSILVER RESOURCES INC Brazos 1709.11 0 1709.11

2008 RED RIVER AUTHORITY Red 0 0 0

2008 SABINE MINING COMPANY Sabine 157.76 0 0

2008 SABINE MINING COMPANY Sabine 0 0 0

2008 SAN JACINTO RIVER AUTHORITY San Jacinto 0 0 0

2008 SAN JACINTO RIVER AUTHORITY Trinity 0 0 0

2008 SANCO MATERIALS CO Colorado 25.6 0 25.6
300 

!! !! !! Annual Annual Annual

!! !! River Diverted Return Consumed

Year Name of Company Basin Amount Flow Amount

2008 SANCO MATERIALS CO Colorado 8.76 0 8.76

2008 SCHKADE Brazos 0 0 0

2008 SHUMAKER ENTERPRISES INC Colorado 249.74 0 249.74

2008 SOUTHWESTERN GRAPHITE CO Colorado 0 0 0

2008 SWANSON MULESHOE RANCH LTD Brazos 0 0 0

2008 SWEPI LP Brazos 0 0 0

2008 TARRANT INVESTMENT CO INC Brazos 0 0 0

2008 TARRANT REGIONAL WATER DISTRICT Trinity 316 0 316

2008 TARRANT REGIONAL WATER DISTRICT Trinity 0 0 0

2008 TARRANT REGIONAL WATER DISTRICT Trinity 0 0 0

2008 TARRANT REGIONAL WATER DISTRICT Trinity 0 0 0

2008 TARRANT REGIONAL WATER DISTRICT Trinity 0 0 0

2008 TAYLOR Colorado 0 0 0

2008 TERRY JACKSON INC Colorado 0 0 0

2008 TERRY JACKSON INC Colorado 0 0 0

2008 TEX IRON INC Neches 0 0 0

2008 TEXAS INDUSTRIES INC Trinity 0 0 0

2008 TEXAS INDUSTRIES INC Colorado 0 0 0

2008 TEXAS MUNICIPAL POWER AGENCY Brazos 0 0 0

2008 TEXAS MUNICIPAL POWER AGENCY Brazos 0 0 0

2008 THISTLE DEW RANCH Brazos 0 0 0

2008 TLC INVESTMENTS LLC Brazos 0 0 0

2008 TRINITY MATERIALS INC Brazos 0 0 0

2008 TRINITY MATERIALS INC Trinity 0 0 0

2008 TRINITY MATERIALS INC Trinity 51.9814 0 0

2008 TXI OPERATIONS LP Brazos 0 0 0

2008 TXU BIG BROWN MINING CO LP Trinity 0 0 0

2008 TXU MINING COMPANY LP Sabine 0 0 0

2008 TXU MINING COMPANY LP Sabine 307 0 307

2008 TXU MINING COMPANY LP Brazos 0 0 0

2008 TXU MINING COMPANY LP Cypress 0 0 0

2008 TXU MINING COMPANY LP Sabine 0 0 0

2008 TXU MINING COMPANY LP Cypress 0 0 0

2008 TXU MINING COMPANY LP Sulphur 65 0 65

2008 TXU MINING COMPANY LP Cypress 132 0 132

2008 TXU MINING COMPANY LP Sabine 0 0 0

2008 TXU MINING COMPANY LP Sulphur 0 0 0

2008 UNDERWOOD Brazos 15.81 0 15.81
301 

!! !! !! Annual Annual Annual

!! !! River Diverted Return Consumed

Year Name of Company Basin Amount Flow Amount

2008 UNION OIL COMPANY OF CALIF Neches 0 0 0

2008 UNITED STATES DEPT OF ENERGY Neches"Trinity 50.69 0 50.69

2008 UNITED STATES OF AMERICA Rio Grande 0 0 0

2008 UPPER NECHES RIVER MWD Neches 0 0 0

2008 US DEPARTMENT OF ENERGY Brazos 81.06 0 81.06

2008 VULCAN CONSTRUCTION MATERIALS LLP Brazos 139.34 0 0

2008 W F COMPANY LTD Colorado 0 0 0

2008 WAGGONER Red 0 0 0

2008 WALNUT CREEK MINING COMPANY Brazos 0 0 0

2008 WEATHERFORD, CITY OF Trinity 0 0 0

2008 WEIRICH BROTHERS INC Colorado 0 0 0

2008 WEIRICH BROTHERS INC Colorado 0 0 0

2008 WEST CENTRAL TEXAS MWD Brazos 45.91 0 0

2008 WESTERN COMPANY OF TEXAS INC Brazos 1031.33 0 1031.33

2008 WHARTON COUNTY GENERATION LLC

Brazos"

Colorado 0 0 0

2008 WHITE RIVER MWD Brazos 7.75 0 7.75

2008 WHITE RIVER MWD Brazos 0 0 0

2008 WHITESIDE Red 0 0 0

2008 WICHITA CO WID 2 Red 22 0 22

2008

WILLIAMS PRODUCTION GULF COAST LLP

INC Brazos 0.346 0 0

2008 ZEBRA INVESTMENTS INC Brazos 53.4 0 53.4

!! !! !! !! !! !!

!! Totals! !! 564,147.36 259,933.12 168,660.45

Source: TCEQ Central Registry database 
302 

Table 77. Water-rights permit data 

Owner Name Site Name County

Amount

Diverted

(acre"feet)

Amount

Consumed

(acre"feet)

Remarks

UPPER NECHES RIVER MWD Anderson AM 10/14/92,9/28/99,3/1/00.MULTI"EVERYTHSAN MIGUEL ELECTRIC COOP INC SAN MIGUEL LIGNITE MINE Atascosa 120.00 SEDIMENTATION CONTROL AND DUST SUPPRESSION PURPOSESNORTH CENTRAL TEXAS MWA Baylor 500.00BRAZOS RIVER AUTHORITY Bell MAX RATE "UNSPECIFIED"BRAZOS RIVER AUTHORITY BellFRANKLIN LIMESTONE COMPANY Bell 138.00 69.00CAPITOL AGGREGATES INC CAGNON SAND & GRAVEL PLANT Bexar 431.00 5.00 AMEND 2/93,7/94,9/96,10/98.SC,08/28/02CAPITOL AGGREGATES INC CAGNON SAND & GRAVEL PLANT Bexar 769.00 10.00 AMEND 2/93,7/94,9/96,10/98.SC,08/28/02CAPITOL AGGREGATES INC CAGNON SAND & GRAVEL PLANT Bexar 3,304.00 585.00 AMEND 2/93,7/94,9/96,10/98.SC,08/28/02JOHN MCPHERSON ET AL Bosque AMENDED 5/15/2009: CHANGE TO MULTI"USE; ADDED MINING USECHEVRON PHILLIPS CHEMICAL

CO LP CLEMENS TERMINAL Brazoria 3,000.00

CHEVRON PHILLIPS CHEMICAL

CO LP CLEMENS TERMINAL Brazoria 2,350.00

UNITED STATES DEPT OF ENERGY BRYAN MOUND SPR SITE NEAR FREEPORT Brazoria 52,000.00 TOTAL 215K. AM 7/31/89, 3/26/2001APACHE CORPORATION Brazos 20.00LOWER COLORADO RIVERAUTHORITY Burnet SEE 5482"6.AM 10/89,3/90,3/96.AM C ABANDSOUTHWESTERN GRAPHITE CO DIV OF DIXON TICONDEROGA Burnet 400.00GUADALUPE"BLANCO RIVER

AUTHORITY Calhoun AM 4/91,5/04,9/04,5/1/2007:STAT DISTRICT

UNION CARBIDE CHEM &

PLASTICS Calhoun AMEND 4/17/91.PART OWNER WITH GBRA

DOUGLAS M BRICE Cameron AMEND 3/13/95, 6/4/99JOEL RUIZ ET UX Cameron RATE:23"2707.AMEND 10/30/84,7/2/99
303 

Owner Name Site Name County

Amount

Diverted

(acre"feet)

Amount

Consumed

(acre"feet)

Remarks

MICHAEL A MACMAHON Cameron 9.62 AMEND 6/6/97:DIVPTS 8 COS BELOW AMISTADPABLO A RAMIREZ INC Cameron " " .5 COUNTIES."TXU MINING COMPANY LP MONTICELLO"LEESBURG LIGNITE MINING AREA Camp 685.00 SCs.DUST SUPPR,CNSTR,EQUIP.AM A:CORR DPsCHAMBERS"LIBERTY COS ND Chambers AMEND 10/25/04:ADD USES & IBT TO 80000AFCHAMBERS"LIBERTY COS ND Chambers 800.00CITY OF HENRIETTA Clay 1.00COLORADO RIVER MWD Coke 8,427.00 MAY DIVERT 6000 AF IN CO 168. "COLORADO RIVER MWD Coke 1,000.00 MAY DIVERT 6000 AF IN CO 168. "PATTY LOIS CERVENKA Coke 100.00 & CO 200.AMEND 5/10/2007:ADD MINING USERAMONA A TAYLOR Coke 40.00 & IRRIGATION. 3 DIVPTS. AMEND 11/12/99SANCO MATERIALS CO Coke 35.00 DIVERT 309 AF.AMEND 10/96,10/98.3 DIVPTSSANCO MATERIALS CO Coke 32.00 DIVERT 320 AF.SC.AM 10/98,9/99.2 DIVPTSBRAZOS RIVER AUTHORITY ComancheR E JANES GRAVEL CO Crosby 450.00WHITE RIVER MWD Crosby 2,000.00CITY OF DALLAS Dallas AM 84,85,86,1/96,3/1/96,6/02,11/04,10/06H S JACKSON SAND & GRAVEL

INC Denton 3.00 8/07 MAIL RETD: RTS/BOX CLOSED/UTF

CHARLES LYDELL THALMANN Dimmit 1.00 AMEND 2/26/90GREENBELT M&I WA Donley 750.00EASTLAND INDUSTRIALFOUNDATION Eastland 607.00EBAA IRON INC Eastland 1,000.00EL PASO CO WID 1 MESILLA, AMERICAN, RIVERSIDE DIV DAMS El Paso ADJUDICATED FROM 5433"1HUDSPETH COUNTY CRD 1 El Paso & HUDSPETH CO. ADJUDICATED FROM 244/236"1 IN 2007UNITED STATES OF AMERICA MESILLA, AMERICAN, RIVERSIDE DIV DAMS El Paso ADJUDICATED FROM 5433"1ASH GROVE TEXAS LP Ellis 82.00 50.00 AMENDED 1/5/2001: INCREASE DIV RATETARRANT INVESTMENT CO INC Erath 30.00 USE 1 UNDER ADJ 4026. "; 7/09 MAIL RTD;RTS/ANK/UTFCAMPBELL CONCRETE &MATERIALS LP Fort Bend 2,300.00 230.00 AMEND 4/12/2000:ADD DIVPT,IMPOUNDMENT
304 

Owner Name Site Name County

Amount

Diverted

(acre"feet)

Amount

Consumed

(acre"feet)

Remarks

GULF COAST WATER AUTHORITY Fort Bend WHICH PRIORITY DATE?CAVERN DISPOSAL INC Freestone 31.00 129 AF USE 4 EXPIRED 12/92TARRANT REGIONAL WATER DIST Freestone ALSO CO 175. AMEND 1/4/2000, 2/8/2005TARRANT REGIONAL WATER DIST DISTRICT RETURN FLOWS Freestone AMEND 2/8/05:DISTRICT RETURN FLOWS.2 DPsTXU BIG BROWN MINING CO LP BIG BROWN CREEK Freestone 5.00 SC. 7 DIV PTSTXU BIG BROWN MINING CO LP BIG BROWN CREEK Freestone SC. 7 DIV PTSTXU BIG BROWN MINING CO LP BIG BROWN CREEK Freestone SC. 7 DIV PTSTXU BIG BROWN MINING CO LP BIG BROWN CREEK Freestone SC. 7 DIV PTSTXU BIG BROWN MINING CO LP BIG BROWN CREEK Freestone SC. 7 DIV PTSTXU BIG BROWN MINING CO LP BIG BROWN CREEK Freestone SC. 7 DIV PTSTXU BIG BROWN MINING CO LP BIG BROWN CREEK Freestone SC. 7 DIV PTSCITATION 2002 INVESTMENT LP Garza 200.00 AMEND 8/93; WITH WSC 2418WHITE RIVER MWD Garza 4,000.00 8/4/2005: CONSTR EXTENDED TO 7/24/2012. 1/21/2009: CONSTR EXTENDED TO 7/24/2016WAYNE E MOHR Gillespie 30.00 AMND 1/24/96:2ND DIV PT:30.272N/98.781WWEIRICH BROTHERS INC Gillespie 50.20 WASH GRAVEL. AMEND 8/25/95RED RIVER AUTHORITY Grayson 100.00G R AKIN ET AL Gregg 5.20TEXAS MUNICIPAL POWERAGENCY

GIBBONS CREEK LIGNITE

MINE Grimes AMEND 1/24/05:ADD USES 7, 8, 11

TEXAS MUNICIPAL POWERAGENCY

GIBBONS CREEK LIGNITE

MINE Grimes 200.00 AMEND 12/16/04:ADD USES

FAIR OIL LC Harrison 165.21 & CO 158SABINE MINING COMPANY PIRKEY POWER PLANT Harrison 200.00SABINE MINING COMPANY SOUTH HALLSVILLE #1 SURFACE LIGNITE MINE Harrison REDIRECT ALL OF BRANDY BR TO HATLEY CRKTARRANT REGIONAL WATER DIST Henderson AMEND 7/93, 1/4/2000, 2/8/05TARRANT REGIONAL WATER DIST DISTRICT RETURN FLOWS Henderson AMENDED 2/8/05:ADD DISTRICT RETURN FLOWSTEX IRON INC Henderson STORED GROUNDWATER. CRUSHED STONE WASHINGDOUGLAS M BRICE Hidalgo AMEND 3/13/95, 6/4/99
305 

Owner Name Site Name County

Amount

Diverted

(acre"feet)

Amount

Consumed

(acre"feet)

Remarks

HIDALGO CO IRR DIST 2 Hidalgo 100.00 7/14/81,6/10/87,5/15/90,5/8/95,4/13/2000HIDALGO CO WID 3 Hidalgo 100.00 AMENDED 10/10/78, 9/8/95HIDALGO COUNTY IRR DIST 16 Hidalgo 200.00 AMEND 8/11/95, 7/12/96JOEL RUIZ ET UX Hidalgo RATE:23"2707.AMEND 10/30/84,7/2/99LUCIO E GONZALEZ JR Hidalgo 5.00PABLO A RAMIREZ INC Hidalgo " " .5 COUNTIES."RUFINO GARZA ET AL Hidalgo 125.00 AMENDED 11/1/93, 8/30/94, 1/8/99SERGIO GALINDO Hidalgo 100.00 AMENDED 4/25/2007:CHG IRR TO MININGBRAZOS RIVER AUTHORITY HillCITY OF CLEBURNE HillBRAZOS RIVER AUTHORITY HoodBURLINGTON RESOURCES OIL &

GAS CO LP Hood 600.00 AMMENDED 2/6/2009"!INCREASED DIVERSION AMT FROM 400 AC"FT TO 600 AC"FT

CARRIZO OIL & GAS INC Hood 15.00CHESAPEAKE ENERGY INC Hood 2,000.00ENCANA OIL & GAS USA INC Hood 17.00 REPLACED 12179"9EOG RESOURCES INC Hood 680.00EOG RESOURCES INC EASTERN

DIVISION Hood 300.00

LOWELL UNDERWOOD Hood 100.00QUICKSILVER RESOURCES INC Hood 1,400.00WESTERN COMPANY OF TEXAS

INC Hood 1,000.00 SYSOP

WILLIAMS PRODUCTION GULF

COAST LLP INC Hood 86.00

TXU MINING COMPANY LP MONTICELLO"THERMO LMA Hopkins 220.00 DUST SUPPR,CONSTR,MISC.4 DPS,3 RES.SCsALON USA REFINING INC Howard 215.00 OIL WELL FLOODING; & USE 2COLORADO RIVER MWD BEALS CREEK PROJECT Howard 2,200.00 2,000.00 & WATER QUALITY IMPROVEMENTCOLORADO RIVER MWD NATURAL DAM LAKE PROJECT Howard 2,500.00 &CO 159;& USE 8"WATER QUALITY CTRL; IMPW F COMPANY LTD Howard 800.00 NOTIFY CLEANRIVERS OF CHG.MAIL RETD 6/07
306 

Owner Name Site Name County

Amount

Diverted

(acre"feet)

Amount

Consumed

(acre"feet)

Remarks

TEXAS INDUSTRIES INC BOONESVILLE PLANT Jack 50 AF PURCHASED FROM TARRANT CO WCID 1PREMCOR PIPELINE CO Jefferson 76.70UNITED STATES DEPT OF ENERGY BIG HILL SPR SITE Jefferson 30,000.00 AMND 7/12/90.87291 AF ABANDONED 3/20/96TRINITY MATERIALS INC CLEBURNE PLANT Johnson 125.00 CONSUMPTIVE USE UNDER WSC#2210GEOCHEMICAL SURVEYS Jones 40.00 2 LAKES.6/06 MAIL RETD:RTS/ANK/UTFRICHARD SCHKADE Jones 5.00 CLEANING AND REUSE IN ROCKSAW COOLINGTLC INVESTMENTS LLC Jones 338.00TRINITY MATERIALS INC SEAGOVILLE SAND & GRAVEL #280 Kaufman 100.00 WITH WSC 2300. AMEND 12/21/2006: MOVE DIVPT. MAIL RETD 3/09: RTS/NO MAIL RECEPTACLE/UTFOCCIDENTAL PERMIAN LTD COGDELL CANYON REEF UNIT Kent 3,525.00OCCIDENTAL PERMIAN LTD COGDELL CANYON REEF UNIT Kent 2,375.00DARRELL G LOCHTE ET AL Kerr 143.00 123 AF NONCONSUMPTIVE.9/07 MAIL RETD:RTSWHEATCRAFT INC Kerr AM 8/7/2000:CONTRACT.10/04/2006:MU, DPsWHEATCRAFT INC Kerr AMEND 4/18/2006: ADD MINING (MULTI"USE)WEIRICH BROTHERS INC KIMBLE CO PLANT Kimble 60.00 6.00PLAINS PETROLEUM OPERATING

CO Knox 235.00 SECONDARY OIL RECOVERY. W/WSC _____

SAN JACINTO RIVER AUTHORITY Liberty MULTI"USES,COUNTY,PRI. AMEND 5/95, 10/3/06TXU MINING COMPANY LP KOSSE LIGNITE MINE Limestone 1,000.00 DUST SUPPRESSION, CONSTRUCTION, & MISC MINING ACTIVITIESCOLORADO RIVER MWD O H IVIE RESERVOIR Martin DIV 2500 AF TOTAL FROM EITHER RESERVOIR FOR INDUSTRIAL OR MINING USETERRY JACKSON INC Mason 1.5 AF CONTRACT WATER. WITH WSC 12254"9ALAMO CONCRETE PRODUCTSLTD Maverick 78.00 15.00 AMEND 4/22/87,12/12/94.15 AF CONSUMPTIVEDE LOS SANTOS READY MIX Maverick 2.00 AMEND 1/24/91,3/14/01,4/18/01,11/03/03DOUGLAS M BRICE Maverick AMEND 3/13/95, 6/4/99EW RITCHIE III ET AL MaverickKATHRYN RITCHIE COTTER ET AL Maverick 10.00 AMEND 7/6/93MILDRED GOODSON Maverick AMEND 3/27/02, SPECIAL COND
307 

Owner Name Site Name County

Amount

Diverted

(acre"feet)

Amount

Consumed

(acre"feet)

Remarks

JIMMY A MUMME ET UX Medina 15.00 AMENDED 10/20/04:ADD DIV PT,FLOW RESTRICMOBLEY COMPANY INC Menard 3.00ALCOA INC SANDOW MINE RECLAMATION PROJ Milam STORE GW IN RESERVOIRS.SEE 5816"1.SCsALCOA INC Milam STORE GW IN RESERVOIRS.SEE 5803"1.SCsCITY OF BOWIE Montague 200.00CLARICE BENTON WHITESIDE Montague 9.00SAN JACINTO RIVER AUTHORITY Montgomery 5,500.00CITY OF CORPUS CHRISTI Nueces 12.00 TRANSBASIN TO BASINS 20, 22.ORDER 4/2001CITY OF CORPUS CHRISTI JC ELLIOTT LANDFILL & ADJACENT CITY PROP Nueces SCTOM W GREEN Oldham 30.003 N1 WATER SOLUTIONS Palo Pinto 250.003 N1 WATER SOLUTIONS Palo Pinto 250.00BASELINE OIL & GAS CORP Palo Pinto 1,000.00 REPLACED 2420"9BLUE SKY OILFIELD SERVICE LLC PALO PINTO 15.00BRAZOS RIVER AUTHORITY Palo PintoBRAZOS WATER STATION Palo Pinto 100.00 AMENDMENT CHANGES EXPIRE DATE TO 12/31/2009BRAZOS WATER STATION Palo Pinto 50.00BURLINGTON RESOURCES OIL &

GAS CO LP Palo Pinto 200.00 AMMENDED 2/6/09"!CHANGE DIVERSION AMT FROM 400 AC" FT TO 200 AC"FT

CITATION 1998 INVESTMENT LTD

PARTNERSHIP Palo Pinto 175.00 GOES W/ APP#5359(UPSTREAM CONTRACT)

DART OIL & GAS CORP Palo Pinto 10.00DEVON ENERGY PRODUCTION

CO LP Palo Pinto 100.00

EOG RESOURCES INC Palo Pinto 320.00 AMENDMENT ADDS A DIVERSION PT.EOG RESOURCES INC WESTERNDIVISION Palo Pinto 190.00INGRAM ENTERPRISES LP Palo Pinto 50.00LATTIMORE MATERIALS

COMPANY Palo Pinto 300.00
308 

Owner Name Site Name County

Amount

Diverted

(acre"feet)

Amount

Consumed

(acre"feet)

Remarks

MINERAL WELLS SAND & GRAVEL

INC Palo Pinto 15.00

NORTH RIDGE CORPORATION Palo Pinto 235.00NORTH TEXAS LIVING WATERRESOURCES LLC Palo Pinto 2,700.00 MULTIUSE=MINING & IRRIGATIONNORTH TEXAS LIVING WATERRESOURCES LLC Palo Pinto 650.00 MULTIUSE=MINING & IRRIGATIONPIONEER NATURAL RESOURCES

USA INC Palo Pinto 129.00 REPLACED 12062"9

R J CARAWAY Palo Pinto 41.00RANGE RESOURCESCORPORATION PALO PINTO 90.00THISTLE DEW RANCH Palo PintoVULCAN CONSTRUCTION

MATERIALS LLP Palo Pinto 2,000.00 REPLACED 1315"9

LUMINANT MINING CO LLC MARTIN LAKE LMA Panola 250.00 3 RES, 3 DIV PTS. ALSO RUSK CO. MINING, D&L, SEDIMENT CONTROL. AMENDED 5/11/2009: COMBINE 5004 INTO 5889TXU MINING COMPANY LP MARTIN LAKE LIGNITE MINING AREA Panola 600.00 21 DIV PTS.SCs.EXEMPT RES.AMN 3/30/07TXU MINING COMPANY LP MARTIN LAKE LIGNITE MINING AREA Panola 400.00 AMEND 3/30/07:ADD 400AF,RESES,USESTXU MINING COMPANY LP Panola 150.00 11 DIV PTS. SCsXTO ENERGY INC Panola 720.00CITY OF WEATHERFORD Parker AMEND 9/8/04TXI OPERATIONS LP TIN TOP ParkerAPACHE CORPORATION Robertson 20.00BRAZOS RIVER AUTHORITY RobertsonTXU MINING COMPANY LP TWIN OAKS LIGNITE MINING AREA Robertson 685.00 53.00 TOTAL OF 12 DIVPTS.SCs. GW FROM DEWATERTXU MINING COMPANY LP TWIN OAKS LIGNITE MINING AREA Robertson TOTAL OF 12 DIV PTS.SCsTXU MINING COMPANY LP TWIN OAKS LIGNITE MINING AREA Robertson TOTAL OF 12 DIV PTS.SCs
309 

Owner Name Site Name County

Amount

Diverted

(acre"feet)

Amount

Consumed

(acre"feet)

Remarks

TXU MINING COMPANY LP TWIN OAKS LIGNITE MINING AREA Robertson TOTAL OF 12 DIV PTS.SCsWALNUT CREEK MINING

COMPANY Robertson LIGNITE MINE SEDIMENTATION POND

BONNIE JO BLYTHE ET AL Runnels 70.00 2 TRACTS 531.4 ACRES, SC. "LUMINANT MINING CO LLC OAK HILL LIGNITE MINING AREA Rusk 680.00 SCLUMINANT MINING CO LLC OAK HILL LIGNITE MINING AREA Rusk SCLUMINANT MINING CO LLC OAK HILL LIGNITE MINING AREA Rusk SCLUMINANT MINING CO LLC OAK HILL LIGNITE MINING AREA Rusk SCLUMINANT MINING CO LLC OAK HILL LIGNITE MINING AREA Rusk SCTXU MINING COMPANY LP OAK HILL LIGNITE MINE AREA Rusk 680.00 DP1. DUST SUPPR, CONSTR, EQUIP WASH,MISCTXU MINING COMPANY LP OAK HILL LIGNITE MINE AREA Rusk DP2.DUST SUPPR,CONSTR, EQUIP WASH,MISCTXU MINING COMPANY LP OAK HILL LIGNITE MINE AREA Rusk DP3. DUST SUPPR, CONSTR, EQUIP WASH,MISCTXU MINING COMPANY LP OAK HILL LIGNITE MINE AREA Rusk DP4. DUST SUPPR, CONSTR, EQUIP WASH,MISCTXU MINING COMPANY LP OAK HILL LIGNITE MINE AREA Rusk DP5. DUST SUPPR, CONSTR, EQUIP WASH,MISCTXU MINING COMPANY LP OAK HILL LIGNITE MINE AREA Rusk DP6. DUST SUPPR, CONSTR, EQUIP WASH,MISCTXU MINING COMPANY LP OAK HILL LIGNITE MINE AREA Rusk DP7. DUST SUPPR, CONSTR, EQUIP WASH,MISCMOBLEY COMPANY INC Schleicher 3.00COLORADO RIVER MWD Scurry &CO 17.AMEND 9/26/2001:DIV PTS, ADD IRRH R STASNEY & SONS LTD Shackelford AMEND 5/13/2009: CHANGE TO MULTI"USE: LIVESTOCK, DOMESTIC, & MINING PURPOSESBELL SAND COMPANY Smith 60.00 6.00 SAND WASHING
310 

Owner Name Site Name County

Amount

Diverted

(acre"feet)

Amount

Consumed

(acre"feet)

Remarks

R E KERSH Smith 57.00 6.00 SAND AND GRAVEL WASHINGCLEMMACO LTD Starr AMEND 9/19/97, 7/30/2008: COMBINATIONSDOUGLAS M BRICE Starr AMEND 3/13/95, 6/4/99JOEL RUIZ ET UX Starr RATE:23"2707.AMEND 10/30/84,7/2/99PABLO A RAMIREZ INC Starr 30.00 " " .5 COUNTIES."ROSITA GRAVEL INC Starr 22.50 AMENDED 11/14/97: CHANGE USE 3 TO USE 4BRECKENRIDGE GASOLINE CO Stephens 6/06 MAIL RETD:RTS/NDAA/UTFSWANSON MULESHOE RANCHLTD Stephens 218.00 AMEND 8/12/86: REVERTS TO REC USEWEST CENTRAL TEXAS MWD Stephens AMEND 3/6/91,10/11/2002CITATION 1994 INVEST LTD PART Stonewall 235.00 WITH CONTRACT #1995 (? CONTRACT EXPIRED)MOBLEY COMPANY INC Sutton 3.00TARRANT REGIONAL WATER DIST TO FT WORTH HOLLY WWTP Tarrant B&B CONVEYANCE OF PIPELINE WATER. MAX RATE NOT TO EXCEED DISCHARGED RATETARRANT REGIONAL WATER

DISTRICT Tarrant AMEND 5/14/85, 1/4/2000, 2/21/2005. MAX RATE UNSPECIFIED

LUMINANT GENERATION CO LLC MONTICELLO STEAM ELECTRIC STATION Titus DUST SUPPRESSION,EQUIP WASHDOWN & MISCTXU MINING COMPANY LP MONTICELLO LIGNITE MINING AREA Titus 50.00 SCs. 13 DIVPTS, 7 RESERVOIRSTXU MINING COMPANY LP MONTICELLO LMA Titus 135.00 6 DPS, 2 RES. SCs.TXU MINING COMPANY LP MONTICELLO LIGNITE MINING AREA Titus 200.00 3 DIV SEGMENTS & 5 RES. SCsUPPER COLORADO RIVER AUTH Tom Green AMENDED 12/19/97, 5/30/2008, 6/13/2008CAPITOL AGGREGATES LTD AUSTIN SAND"GRAVEL PLANT READY MIX Travis 2,540.00 340.00 AMENDED 8/15/97: COMBINED WITH 5378"6; PERMIT EXPIRES UPON PERMANENT CESSATION OF MINING OPSCAPITOL AGGREGATES LTD AUSTIN SAND"GRAVEL PLANT READY MIX Travis 242.00 0.00 AMENDED 8/15/97: COMBINED WITH 5378"6. THIS IS NONCONSUMPTIVE MINING USELOWER COLORADO RIVERAUTHORITY Travis SEE 5478.AMEND 10/12/89,3/8/90,10/31/91SHUMAKER ENTERPRISES INC Travis 300.00 REPLACED 2208"9;AMENDED 11/01TERRY JACKSON INC Travis 1.50 1.5 AF CONTRACT WATER. SEE PERMIT 12244"1
311 

Owner Name Site Name County

Amount

Diverted

(acre"feet)

Amount

Consumed

(acre"feet)

Remarks

TEXAS INDUSTRIES INC GREEN SAND AND GRAVEL PLANT Travis 110.00 11.00 690 A/F EXP 12/31/93; ALL WATER RIGHTS EXPIRE WHEN MINING ENDS OR UPON EXPIRATION OF LEASE; FLOW RESTR ON EXPIRED WATERTYLER SAND COMPANY Upshur 200.00 1/99: SEE SC A, CO DEFUNCT; WUR/NOT NCAPITOL AGGREGATES INC DEL RIO PLANT Val Verde 166.00 17.00 AM 11/2/87.6/28/2001:ADD DIVPT & PLACEMORTON SALT COMPANY INC Van Zandt 251.00 EXEMPT LAKEUNION OIL CO OF CALIFORNIA Van Zandt 400.00UNION OIL CO OF CALIFORNIA Van Zandt 270.00UNION OIL CO OF CALIFORNIA Van Zandt 500.00BRAZOS RIVER AUTHORITY WashingtonALBERT F MULLER JR Webb 2.38ALICE SOUTHERN EQUIP SERVICE Webb 145.00 AMEND 7 & 11/93,12/94,10/30/98ALICE SOUTHERN EQUIP SERVICE Webb 175.00 AMENDED 10/30/98BARBARA T FASKEN FARCO MINE DAM AREA Webb 200.00BEN"HUR ENTERPRISES LTD Webb AMEND 1/24/91,3/14/2001,4/18/2001.2705"6CHRISTINE MCKEE Webb 1.00 AMEND 6/20/87. USE 4 IN ZAPATA & WEBBCITY READY MIX INC Webb 100.00 AMEND 10/15/91, 11/23/92DOUGLAS M BRICE Webb 131.56 AMEND 3/13/95, 6/4/99H B O'KEEFE ESTATE Webb 100.00 AMENDED 8/14/98: 100 AF USE 3 TO USE 4HACHAR REAL ESTATE COMPANY Webb 23.00 AMEND 6/30/86J & B CONTRACTORS INC Webb 2.00 AMEND 3/29/94JOEL RUIZ ET UX Webb RATE:23"2707.AMEND 10/30/84,7/2/99LAREDO SAND & GRAVEL CO Webb 20.00LOUIS C LECHENGER ET AL Webb 20.00 AMEND 4/14/88MANDEL PROPERTIES LTD Webb 100.00 AMEND 10/13/95MICHAEL ALLEN MACMAHON Webb 120.00 6/18/90RANCHO BLANCO CORPORATION Webb 300.00 AMEND 11/2/87,9/25/89,10/11/94,8/25/95RODOLFO GARCIA Webb 75.00 10.00RODOLFO GARCIA Webb 62.00SAMUEL A MEYER ET AL Webb 30.00 AMEND 10/17/94SAN ISIDRO NORTH LTD Webb AMEND 12/18/91, 5/31/96. AMEND 3/19/2008: ADD MINING USE. AMEND 7/2/2008: ADD INDUSTRIAL USE
312 

Owner Name Site Name County

Amount

Diverted

(acre"feet)

Amount

Consumed

(acre"feet)

Remarks

STEPHEN A MCKENDRICK

TRUSTEE Webb 2.38 W H MCKENDRICK TRUST

TOPAZ POWER PROPERTY MGMT

II LP Webb AMEND 2/7/97.REUSE 731.5 OF THE 2194.5

UNION PACIFIC OIL & GAS CO Webb 5.00 AMEND 6/16/92WILLIAM H MCKENDRICK III Webb 8.33CONOCOPHILLIPS CO WhartonLEONARD WITTIG GRASS FARMS

INC Wharton 1,000.00

WHARTON COUNTY

GENERATION LLC

NEWGULF POWERFACILITY Wharton

WICHITA CO WID 2 ET AL Wichita 2,000.00W T WAGGONER ESTATE Wilbarger 30.00 FROM MIDWAY LAKEJOEL RUIZ ET UX Willacy RATE:23"2707.AMEND 10/30/84,7/2/99PABLO A RAMIREZ INC Willacy " " .5 COUNTIES."ALAMO CONCRETE PRODUCTSLTD WEIR PLANT Williamson 300.00 30.00 AM 6/92,5/02.FORMERLY SOUTHWEST MATERIALBRAZOS RIVER AUTHORITY WilliamsonBRAZOS RIVER AUTHORITY WilliamsonCAPITOL AGGREGATES LTD GEORGETOWN QUARRY Williamson 118.00 AMENDED 8/15/97, 5/28/99: ADDED DIV PTGENE H BINGHAM ET AL Williamson 240.00 24.00 MAY CONSUMPTIVELY USE 24AFYHANSON AGGREGATES CENTRALINC

BRIDGEPORT STONEPLANT #2 Wise 345.00 69.00

HANSON AGGREGATES CENTRALINC

BRIDGEPORT STONEPLANT #2 Wise 1,505.00 301.00

HANSON AGGREGATES CENTRALINC

CHICO CRUSHED STONE

PLANT Wise 510.00 AMEND 5/7/91

HANSON AGGREGATES WEST INC Wise 1,475.00HANSON AGGREGATES WEST INC Wise 177.00 177.00MARTIN MARIETTA MATERIALSSOUTHWEST INC Wise 1,200.00TARRANT REGIONAL WATER DIST Wise 7,500.00 COS 249, 220TARRANT REGIONAL WATER DIST Wise AMEND 5/5/89,1/4/2000. COS 249,119
313 

Owner Name Site Name County

Amount

Diverted

(acre"feet)

Amount

Consumed

(acre"feet)

Remarks

TRINITY MATERIALS INC DECATUR PLANT #205 Wise 25.00 SC. W/WSC#1970CITY OF GRAHAM Young 500.00PITCOCK BROTHERS READY"MIX Young 100.00ANTONIO R SANCHEZ SR ESTATE Zapata 50.00 3/87,8/87,9/88,7/89,5/10/2000.9 COUNTIESANTONIO R SANCHEZ SR ESTATE Zapata 50.43 3/87,8/87,9/88,7/89,5/10/2000.9 COUNTIESDOUGLAS M BRICE Zapata AMEND 3/13/95, 6/4/99EDWIN H FRANK III Zapata 6.00 AMEND 1/4/90EL CAMPO FARM COMPANY Zapata 25.00 SEE 23"2787 FOR RATEFENDER EXPLORATION &PRODUCTION CO LLC Zapata 20.00 AMEND 10/25/2000:CHG 20 AF TO MINING USEFLF LTD Zapata 7.46 AMEND 1/4/90GALBERRY PROPERTIES LLC Zapata 5.60 AMEND 1/4/90HERRADURA RANCH Zapata 6.30 AMEND 1/4/90JAMES C GUERRA ET AL Zapata 12.50 AMEND 8/14/98: CHG POFD & USE 3 TO 4JAVIER ZAPATA ET AL Zapata 146.00JOEL RUIZ ET UX Zapata 20.00 RATE:23"2707.AMEND 10/30/84,7/2/99KCS RESOURCES INC Zapata 25.00LARRY G HANCOCK Zapata 6.10 AMEND 1/4/90LONE STAR LA PERLA LP Zapata 5.64 AMEND 1/4/90MARIA EVA URIBE RAMIREZ Zapata 10.00 AMEND 7/12/90MARTINEZ QUARTER HORSERANCH LTD Zapata AM 5/3/06:ADD MINING.6/13/07:ADD ACRESMARTINEZ QUARTER HORSERANCH LTD Zapata 2.80 AMEND 1/4/90MICHAEL T THRASHER Zapata 6.10 AMEND 1/4/90NEUHAUS & CO LTD Zapata 17.10 AMEND 1/4/90PABLO A RAMIREZ INC Zapata " " .5 COUNTIES."RAMIRO V MARTINEZ Zapata AMEND 3/16/05:ADD IND & MINING USESROBERTO J VIDAURRI Zapata AM 5/92,6/93,08/02,9/26/02,7/31/2009:MULTI"USE,DIVROSEMARIE ANN GEARY Zapata AM 12/1/86,4/12/94,7/27/01,11/4/03:MULTISDK FARMS Zapata 12.90 AMEND 1/4/90SDK FARMS LLC Zapata AM 5/3/06:ADD MINING.6/13/07:ADD ACRES
314 

Owner Name Site Name County

Amount

Diverted

(acre"feet)

Amount

Consumed

(acre"feet)

Remarks

TECOMATE CAPITAL PARTNERSLTD Zapata 4.00 AMEND 1/4/90UNICO CONSTRUCTION CO Zapata 11.24 AMEND 5/31/85,3/13/2003:CHG USE TO 4/AGWICHITA PARTNERSHIP LTD Zapata AM 1/30/95.6/21/2007:MULTIUSE.3/13/08:CMZAVALA"DIMMIT CO WID 1 Zavala 4.00ZAVALA"DIMMIT CO WID 1 ZavalaZAVALA"DIMMIT CO WID 1 ZavalaCITY OF HOUSTON

Source: TCEQ Central Registry database 
315 

14 Appendix G: 

 vvvvv 

317 

15 Appendix H: 

 zzzzz 

319 

321 

16 Appendix I: 

 yyyyy 

323 

325 

17 Appendix J: 

 List of Files Submitted to TWDB and Content 

327 

17.1 List of Files with Nonproprietary Content 

17.2 List of Files with Proprietary Content 

329 

18 Appendix K: 

 Responses to Review Comments 

331 

Responses to Review Comments 

ud ad.