Examining the Feasibility of using Coal Mine Drainage as a Hydraulic Fracturing Fluid
By Andrew Kondash
Dr. Tim Johnson Adviser
Dr. Avner Vengosh Adviser
May 2013
Masters project topic for the Master of Environmental
Management degree in the Nicholas School of the Environment of
Duke University
1

Figures ........................................................................................................................................................... 3
Tables ............................................................................................................................................................ 3
Maps ............................................................................................................................................................. 3
Abstract ......................................................................................................................................................... 4
Introduction .................................................................................................................................................. 5
Waste Disposal .......................................................................................................................................... 8
Coal Mine Drainage ................................................................................................................................... 8
Mixing as Remediation ............................................................................................................................ 11
Methods ...................................................................................................................................................... 12
Sample Collection .................................................................................................................................... 12
Coal Mine Drainage Creation .................................................................................................................. 12
Sample Processing................................................................................................................................... 13
Mix Creation ............................................................................................................................................ 13
Cost Calculations ..................................................................................................................................... 13
Results ......................................................................................................................................................... 15
Mixing Experiment .................................................................................................................................. 15
Cost Calculations ..................................................................................................................................... 17
Discussion.................................................................................................................................................... 18
Conclusion ................................................................................................................................................... 19
Thanks ......................................................................................................................................................... 19
Works Cited ................................................................................................................................................. 20
Appendix: .................................................................................................................................................... 23
Trace Elemental Analysis ........................................................................................................................ 23
Regression Analysis ................................................................................................................................. 25
Other Removal Results ............................................................................................................................ 27
2

Figure 1: CMD Creation [26] ....................................................................................................................... 10
Figure 2: Experiment Design and Expected Results .................................................................................... 13
Figure 3: Model Inputs ................................................................................................................................ 14
Figure 4: Sulfate Removal,
Figure 5: Final Sulfate Concentration ......................................................................................................... 15
Figure 6: Barium Removal,
Figure 7: Final Barium Concentration ........................................................................................................ 16
Figure 8: Radium Removal,
Figure 9: Final Radium Concentration ........................................................................................................ 16
Figure 10: Barium Radium Correlation,
Figure 11: Barium Radium Removal Correlation ........................................................................................ 17
Figure 12: Extra CMD Costs,
Figure 13: CMD Freshwater Comparison .................................................................................................... 18
Figure 14: Local Meteoric Water Lines ....................................................................................................... 25
Table 1: Radium 226 Values [15] [12] [14] .................................................................................................... 6
Table 2: Barium, Calcium, and Chloride Values in Flowback and Produced Water [14] .............................. 6
Table 3: Coal mine drainage Concentrations .............................................................................................. 10
Table 4: Synthetic CMD Recipe,
Table 5: Synthetic CMD Chemistry ............................................................................................................. 12
Table 6: Pw and Fb Isotopes ....................................................................................................................... 24
Map 1: US Shale Plays ................................................................................................................................... 7
Map 2: Radium in Produced Water .............................................................................................................. 7
Map 3: Underground Injection Well Shipping Costs [19] ............................................................................. 8
Map 4: Proximity of CMD Sites to Unconventional Wells .......................................................................... 11
3

Much of the current concern about hydraulic fracturing revolves around the treatment and disposal of wastewaters that emerge out of the well after fracturing has occurred. These “produced waters” and
“flowback waters” in some cases are high in concentrations of total dissolved solids (TDS), naturally occurring radioactive material (NORM), and metals. There are currently many ways these wastewaters are managed including being recycled on site, treated at commercial waste water treatment plants, or shipped away for storage in federally permitted underground injection wells. This study suggests that by supplementing wastewater with high-sulfate coal mine drainage (CMD), on site recycling can be even more effective through the removal of high metal concentrations and NORM from the wastewater. This could potentially allow for complete wastewater recycling, in turn saving local water resources, effectively remediating a legacy of environmental problems attributed to coal mine drainage.
This study was focused on the idea that by mixing coal mine drainage with flowback or produced water, many of the negative characteristics of both fluids can be remediated. The sulfate can be removed from the coal mine drainage, and with it, the barium and radium can be removed from the coal mine drainage. Mix ratios of 1:4, 1:2, and 3:4 were used for this study and in almost every case a majority of the radium (100% for each ratio), barium (75, 90, and 80% respectively), and sulfate (90, 75, and 40% respectively) precipitated out of the mixture. Barium and radium concentrations were found to be strongly correlated within each the sample (r 2 of .815). In addition to that, the removal of those solutes was also found to be correlated (r 2 of .75). Finally, using spatial analysis and a number of input factors, it was found that on average the use of coal mine drainage is between $30 and $200 thousand more expensive to use per well than fresh water.
These results indicate that mixing AMD and flowback water is an effect means of water treatment for re-use as hydraulic fracturing fluid. Although not currently cost effective, the potential to clean up a legacy environmental problem has inspired policy makers to begin the process of making the use of coal mine drainage more cost effective with less legal consequence.
4

A growing population, rising energy demands, and increasing awareness and concern about the environment have been making headlines for many years. Recent discoveries of vast reserve of natural gas, trapped in “unconventional” shale formations deep underground coupled with the advancement in the technologies of horizontal drilling and hydraulic fracturing have brought about a large scale movement of the energy sector towards natural gas. In its annual energy outlook, the Energy
Information Administration estimates that, as of 2012, is 482 trillion cubic feet of technically recoverable shale gas trapped in various formations (Map 1) across the United States. [1] [2] [3] The push towards natural gas is quite compelling as it has lower lifecycle greenhouse gas emissions than coal plants and burns much cleaner than coal. [4] Despite the bright outlook, questions about the emissions, safety, and possible side effects of the extraction process have led many to oppose the development of these reserves. [5] [6] Energy demand and the vast potential locked away underground, have led to the mainline development of the Marcellus shale formation in Pennsylvania along with formations in many other states. [6] State and Federal Regulatory Agencies along with drilling companies have implemented regulations and best management practices respectively to maintain safe conditions, while keeping production efficient [5].
In spite of these efforts, academic investigation, public outcry, and journalistic inquisition have brought to light a number of daunting revelations. Chief among them are the naturally occurring radioactive materials (NORM) that are released when the shale fractures, the potential migration of methane
(natural gas) through improperly sealed well heads or natural pathways into shallow groundwater aquifers, as well as the effect of water being taken from local watersheds to fracture a well. [7] [8] In addition, much of the current concern about hydraulic fracturing revolves around the treatment and disposal of wastewaters that emerge from the well after fracturing has occurred. These “produced waters” and “flowback waters” in some cases have high concentrations of total dissolved solids (TDS), hydrocarbons, and other solutes. [9] There are currently many ways these wastewaters are dealt with including being recycled on site, treated, or shipped away for storage in federally permitted underground injection wells. This study suggests that by supplementing wastewater with coal mine drainage (CMD) (which is this report is also referred to as acid mine drainage (AMD) despite the samples not having a low pH), on site recycling can become even more effective, removing high metal concentrations from the wastewater and allow for complete wastewater recycling, while a legacy environmental problem may be remediated.
It takes between 1 and 5 million gallons of water to hydraulically fracture a well. [10] Most of this water comes from local rivers and lakes and is mixed with sand and various chemicals to become hydraulic fracturing fluid. Between 10 and 40% of the water injected to the well is recovered in the form of flowback water and produced water. [10] Flowback water is comprised mostly of the hydraulic fracturing fluid with a small amount of formation brine and comes up within the first few days of fracturing a well. Roughly 40% of the water coming back up out of a well is flowback water. [11] About a week into extraction, the water coming up out of the well is mostly formation brine and is then called produced water, which accounts for 47% of the post production water. [11] The solutes of interest commonly found in these produced waters for this study are radium 226, barium, calcium, and chloride.
5

Typical concentrations in both produced water and flowback water range from 1,000 to 12,000 pCi/L
226-Radium, 1,000 to 3,000 mg/L barium, 5,000 to 6,000 mg/L calcium, and 30,000 to 50,000 mg/L chloride (tables 1 and 2). [12] [13] These values are much higher than the EPA maximum contaminant levels for drinking water of 5 pCi/L Ra-226, 2 mg/L barium, and 250 mg/L chloride. This necessitates caution with their handling and disposal. [14]
Table 1: Radium 226 Values [15] [12] [14]
Table 2: Barium, Calcium, and Chloride Values in Flowback and Produced Water [14]
6

Map 1: US Shale Plays
Map 2: Radium in Produced Water
7

Currently, there are three ways to deal with the wastewater that comes up out of the well. The first is a high energy process known as reverse osmosis which uses membranes to filter out large molecules and ions. [16] Currently, 14% of produced water and 8% of flowback water is sent to reverse osmosis and other similar water treatment facilities. [11] The most common form of wastewater management is on site recycling. With a small amount of treatment or dilution, 60 % of produced water and 90% of flowback water are recycled at the well or to other well sites. [11] The final method is to ship the wastewater to federally permitted underground injection wells accounting for 27% of produced water and 3% of flowback water disposal. [11] [17] Shipping costs of two cents per gallon per hour and treatment costs of ten to twenty cents per gallon of flowback water makes proper disposal of wastewaters prohibitively expensive. [18] Costs to export the waste water from each well across
Pennsylvania to underground injection wells in Ohio can range from 10 to 40 thousand dollars per well just for transport (Map 3). In order to save on those costs, in addition to the cost of acquiring freshwater, many oil and gas companies are examining the use of coal mine drainage as a hydraulic fracturing fluid.
Map 3: Underground Injection Well Shipping Costs [19]
After two centuries of coal mining and billions of tons of coal extracted from Pennsylvania mines, waters present in abandoned underground mines are a management issue. This water is called coal mine
8

drainage or coal mine drainage (some of it can be alkaline, some acidic) and forms when pyrite (FeS
2
) and other sulfides are subject to oxidizing conditions (figure 1). CMD is usually found to have high concentrations of metals and sulfates, low pH (in many cases), and high acidity. [20] [21] The oxidation process starts when ferrous iron (Fe 2+ ) from the pyrite in the mine interior is released into solution and exposed to oxygen, where it becomes ferric iron (Fe 3+ ) at low pH values, which then precipitates according to the following overall reaction [21] [22]:
4𝐹𝑒𝑆
2(𝑆)
+ 15𝑂
2
+ 14𝐻
2
𝑂 → 4𝐹𝑒(𝑂𝐻)
−
3
+ 8𝑆𝑂
−
4
+ 16𝐻
+
These reactions continue as long as there is a supply of water and pyrite in the mines, increasing the acidity of the water throughout the process. Samples used in this study had sulfate concentrations ranging from 441 to 5,000 mg/L and Iron concentrations ranging from .3 to 900 mg/L compared to EPA secondary maximum contaminant loads for drinking water of 250 mg/L sulfate and 0.3 mg/L iron (table
3). [23]
CMD is responsible for the degradation of over 20,000 km of streams and rivers in and around
Pennsylvania, with Pennsylvania alone accounting for one third of the degraded waters in the entire US.
[22] [24] When CMD enters a water body, it has the potential to reduce diversity and total number of macroinvertebrate communities, kill off fish, and corrode manmade structures. [22] The National
Pollutant Discharge Elimination System (NPDES) puts out permits, described in the Clean Water Act, calling for the regulation of all point source discharges from mining operations. [21] While recent mines are regulated, legacy mines open prior to 1965 (in PA, 1972 nationally) or owned by companies that have gone bankrupt are abandoned and remain unregulated, contributing untreated CMD from thousands of wells across the state. These sites fall under the jurisdiction of the Pennsylvania
Department of Environmental Protection’s Bureau of Abandoned Mine Reclamation, which is only able to process a limited number of filings each year. [22]
Several treatment plans are currently being used to remove toxins from CMD including passive bioreactors, metal precipitation using sulfate-reducing bacteria (SRB), aerobic wetland remediation, ion exchange, reverse osmosis, electrodialysis, electrolytic recovery, and open limestone channels. [21] [22]
[25] According to Anthony Iannacchione, who is currently the Director of Mining Engineering at the
University of Pittsburgh, there are around 600 billion gallons of coal mine drainage in close proximity to many (around 1,600) of the active gas wells in western Pennsylvania. [18] Because it takes between 3 and 5 million gallons of water to hydraulically fracture a typical well, it has been proposed that with only a small amount of transport (Map 4), using this vast reserve of CMD or a mix of CMD and flowback water as the fracturing fluid would help remediate this environmental nuisance and make the state a cleaner, healthier place to live.
9

Figure 1: CMD Creation [26]
Table 3: Coal mine drainage Concentrations
10

Map 4: Proximity of CMD Sites to Unconventional Wells
Recent studies have shown promising results from the mixing of varying amounts of CMD and flowback water while CONSOL and other gas companies have begun tests using CMD as hydraulic fracturing fluid.
[18] [9] The idea behind the mixing is that the high sulfate concentrations in the CMD will foster the precipitation of the heavy metals out of the flowback water. Currently, passive bioreactors use this concept to stabilize metals in CMD, precipitating them out as carbonates, hydroxides, and sulfides. [24]
The problem with using pure or undiluted CMD to fracture a well is that the high concentration of anions such as sulfate could potentially react with metals such as barium, strontium, and calcium and precipitate as minerals within the well, effectively clogging the newly created fractures from which gas is being extracted. [18] [20] McSurdy (2011) recently completed a study showing that by mixing flowback water and CMD close to 100% of the barium, iron, and sulfate precipitate out from the mixture. [9]
One of the most important aspects of the mixing results that have been omitted in the literature thus far is the fate of the radionuclides found in the flowback and produced waters. Formation brine, which is comprised of highly concentrated sea water, trapped in the porous shale layers is being exposed to the decay of thorium and uranium and in the process has picked up concentrations of the decay’s daughter product, radium. [27] [8] Ideally, concentrations of radium-226 ranging from 1,000-10,000 picocuries per
11

liter (pCi/L) in the flowback and produced waters will form a precipitate which will settle out of the mix when mixed with CMD. The radioactive solid left over can then be disposal of using proper protocol, such as shipment of that waste to a landfill or reuse. [28] [29]
In order for the mixture to be considered usable as hydraulic fracturing fluid, panels representing
Barnett Shale as well as Marcellus Shale agreed upon the flowing standards for hydraulic fracturing fluids: 3,000 to 90,000 mg/L TDS, 350 mg/L calcium, less than 100 mg/L TSS, a pH between 6.5 and 7.5, iron concentration of less than 20 mg/L, and sulfate concentration less than 1,000 mg/L. [30] [18]
A total of 5 gallons of flowback water along with 5 gallons of produced water were obtained from CONSOL Energy (http://www.consolenergy.com), the leading diversified energy producer in the
Appalachian Basin. Each gallon was collected from a different Marcellus drilling site and represents the variability in the well sources CONSOL has access to. The idea behind taking 1 gallon samples from different locations comes from the fact that the chemistry of the flowback water and produced water from wells is variable depending on the geology underlying each location. Because of its reputation as a coal producing energy company, CONSOL also has access to a number of old coal mines that are currently being managed. CONSOL also provided 5 gallons of coal mine drainage that could potentially be used as hydraulic fracturing fluid.
In order to improve the accuracy and timing of the project, in addition to the CONSOL coal mine drainage, artificial coal mine drainage was created in the laboratory. Stock concentrations of
Fe(SO
4
)*7H
2
O, Mg(SO
4
)*7H
2
O, H
2
(SO
4
), NH
4
Cl
2
, and H
2
PO
4
were all combined in distilled 17.8mΩ water. The pH was raised from 2.4 to 6.8 using 2M sodium hydroxide. Proportions were taken from
Henrot and Wieder (1990). [31] [32] The following tables show mixing proportions and final elemental compostition of the synthetic CMD.
Table 4: Synthetic CMD Recipe Table 5: Synthetic CMD Chemistry
12

All major elemental chemistry tests for each of the acquired samples were conducted at Duke
University. Major anion concentrations were extrapolated through dilution and the running of a Dionex
IC DX-2100 ion chromatography machine. Major cation concentrations were similarly established using dilution along with a direct current plasma optical emission spectrometry (DCP-OES), while trace metal concentrations were found with a VG PlasmaQuad-3 inductively coupled plasma mass-spectrometer
(ICP-MS). Boron isotopes were investigated using thermal ionization mass spectrometry (TIMS) on a
ThermoFisher Trition. Oxygen, hydrogen, and carbon isotopes were found at the Duke Environmental
Isotope Laboratory (DEVIL) with a thermochemical elemental analysis/continuous flow isotope ratio mass spectrometer (TCEA-CFIRMS), using a ThermoFinnigan TCEA and Delta+XL mass spectrometer.
Finally, radionuclides were determined using a broad energy germanium gamma detector at Duke
University. [7]
For the experiment, mixes were created between flowback and coal mine drainage samples. Mix ratios of 25% CMD 75% flowback, 50% CMD and 50% flowback, and finally, 75% CMD and 25% flowback were created (figure 2). A total of 40 different mixes were created between 4 different CMD samples and the
5 flowback samples. The produced water samples were found to be weaker than expected, and trace elemental analysis revealed that the samples were heavily diluted with rain water (see appendix: trace elemental analysis). Each mix was shaken for 48 hours and allowed to settle for 24 hours. Using just the water, with no precipitate, elemental chemistry tests were again conducted.
Figure 2: Experiment Design and Expected Results
The final aspect of this project was to evaluate the economic impact of using CMD as hydraulic fracturing fluids. Cost estimates for storage, procurement, transport, and volume were found in the literature, while GIS was used to determine amounts of produced and flowback water, as well as distances to underground injection wells and water treatment plants. [33] [11] [18] An excel model was
13

then built with adjustable inputs which was used to determine how much more expensive using CMD is currently compared to freshwater.
Figure 3: Model Inputs
14

This study was based on the hypothesis that a sulfate precipitate would form from the mixing of high sulfate coal mine drainage with high levels of free radium and barium found in the flowback water.
After the 48 hours of mixing, a precipitate did indeed form as predicted in figure 2. In order to quantify the amount of precipitate that formed, expected concentrations of each of the solutes were calculated based on the mixing ratio and chemistry results from the inputs. The actual measured concentrations were then subtracted from expected concentrations, to provide an estimate of how much precipitate formed. For each solute, the percent removed was then calculated by dividing the measured mix concentration by the expected concentration.
The 25 and 50% CMD mixes were most effective at using all of sulfate to form a precipitate (figure 4) with over 90% use in the 25% mix and over 75% removal from the 50% mix. Final sulfate concentrations varied from 0 to 3000 mg/L for the mixes, while concentration was shown to be significantly related to the percentage of coal mine drainage used in the experiment (figure 5). Current industry caps of around
1000 mg/L sulfate for effective fracturing fluid would indicate that either the 25 or 50% mixes would be best suited for use as fracturing fluid. [30]
Figure 4: Sulfate Removal Figure 5: Final Sulfate Concentration
A similar analysis was conducted for barium. The 50% CMD mix was most effective at removing barium, with almost 100% removal, while the 75 and 25% CMD mixes both had over 75% removal (figure 6).
There were no available industry caps on barium, however, the final concentration of barium was found to be logarithmically related to the percentage of CMD used (figure 7).
15

Figure 6: Barium Removal Figure 7: Final Barium Concentration
In each case almost all of the radium precipitated out of mixture. This is a very significant discovery because some water treatment plants are not effective at removing all of the radium from flowback and produced waters. By simply mixing the produced waters with CMD, all of the radium could be precipitated out (figure 8), leaving final concentrations on par with drinking water standards (figure 9).
[14]
Figure 8: Radium Removal Figure 9: Final Radium Concentration
Another interesting result from this study was that barium and radium concentrations were found to be strongly correlated among these samples with an r squared value of 0.815 (figure 10). Because the removal of barium and radium from the mixes was also found to be strongly correlated, with an r squared value of 0.75 (figure 11), a simple 2 minute field test of barium concentration in a water sample could be used to approximate radium concentration instead of the 24-48 hour gamma detector measuring time. At this same time, using the equation displayed in figure 11, an approximate measure of how much radium will precipitate out of a mix can be found.
16

Figure 10: Barium Radium Correlation Figure 11: Barium Radium Removal Correlation
Using the cost comparison model, it was found that for mixes of 25, 50, 75, and 100% coal mine drainage, it is still 30-200 thousand dollars more expensive per well to use coal mine drainage than freshwater (figure 12). These calculations were conducted using values in the model shown in figure 3 and averages across all current fracturing wells. Additionally, a hypothetical model was created with variable inputs for distance to the water treatment plant, distance to the underground injection well, distance to the closest CMD source, and the amount of water used to fracture a well, all fields that were calculated using GIS for current wells shown in map 4.
17

Figure 12: Extra CMD Costs Figure 13: CMD Freshwater Comparison
Despite the large amount of available CMD, proximity to drilling platforms, and promise shown by these mixing results, there are still several road blocks in the way of widespread adoption of the use of CMD as a hydraulic fracturing water source. While laboratory tests have shown that it is technically possible to create water suitable for hydraulic fracturing, no actual field tests have been run yet using CMD. Many oil and gas companies are interested in using and developing technology for the incorporation of CMD into their hydraulic fracturing practices. In spite of their interest, current liability issues with the transport and use of CMD are currently holding the industry back. While this test and others have shown that the use of CMD is technically feasible, Legislators are working in Pennsylvania to improve the climate for drilling companies to proceed, but caution is being taken and development of this technology is being delayed because of it. [34] Legally, well operators would have to assume a huge liability risk with the transport, treatment, and use of CMD. [35] While well operators would be doing the environment a service by helping clean up legacy CMD concentrations, Pennsylvania’s
Environmental Good Samaritan Act as it is currently stated would not provide liability coverage for accidents resulting from the use of CMD. [36] [18] Additionally, the Solid Waste Management Act
(SWMA) and section 391.315 of the Clean Streams Law both require permitting for collection, transport, and injection of CMD into the ground. [18]
18

Economically, the use of CMD is also currently unfavorable for shale gas companies. While piping the
CMD is an option, many gas companies will have to truck in their supplies of CMD. A shipping rate of
$0.024 per gallon per hour is exceedingly prohibitive considering the 5-6 million gallons of water required to fracture a typical well. Currently flowback water costs $0.095 to $0.19 per gallon to treat while CMD will require special impoundments and treatment that could cost between $0.13 and $0.24 per gallon. By mixing CMD and flowback and reusing the water, much of this cost could be cut out.
However, as shown by the cost model, either government intervention or technological innovation needs to facilitate a transition because CMD is more expensive to use. [18]
One theory about coal mine drainage is that while concentrations and elemental composition are going to be different for each site and CMD sample, they should be roughly correlated to the pH or Alkalinity of the samples. [18] Among the samples from this study however, no significant correlations of note were found in regression results (see appendix: regression results) meaning pH most likely plays only a small role in elemental composition of CMD samples.
One possible opportunity for future study is to take the precipitate out of the centrifuge tubes and analyze which precipitates were actually formed. Also, a pilot field study for the mixing could be developed with the help of CONSOL or another hydraulic fracturing company and could prove the actual viability of mixing.
These results indicate that mixing CMD and flowback water is an effective means of water treatment for re-use as hydraulic fracturing fluid. The use of CMD instead of stream or river water would ease the strain on water resources especially during droughts, while at the same time cleaning up a legacy environmental problem. If not used for hydraulic fracturing, this study offers oil and gas companies an opportunity to be good neighbors and remove radium, barium, and sulfate from produced and flowback waters before shipping to water treatment plants.
All of the laboratory equipment and training was provided by Duke University. The samples of coal mine drainage, produced water, and flowback from wells was provided by Steve Winberg and Jim Locke from
CONSOL Energy. Dr. Tim Johnson and Dr. Avner Vengosh, as well as PhD student Nat Warner and Alissa
White assisted in project development, implementation, and interpretation of results. Also, Loren
Anderson of the Marcellus Shale Coalition helped by providing his guidance, networking, and project development expertise.
19

[1] United States Energy Information Administration, "Annual Energy Outlook," Department of Energy,
2012.
[2] "Carnegie Museum of Natural History Pennsylvania Unconventional Natural Gas Wells
Geodatabase," Pittsburgh, PA: Carnegie Museum of Natural History, 2000-2013. [Online]. Available: http://www.carnegiemnh.org/powdermill/gis-wells.html.
[3] "United States Energy Information Administration," EIA: Independent Statistics and Analysis,
Natural Gas, 2013. [Online]. Available: http://www.eia.gov/pub/oil_gas/natrual_gas/analysis_publications/maps/maps.html#geodata.
[4] Jiang M, et al., "Life cylce greenhouse gas emissions of Marcellus shale gas," Environmental
Research Letters, vol. 6, no. 3, p. 9, 2011.
[5] Howarth RW, Ingraffea A, Engelder T, "Natural Gas: Should Fracking Stop?," Nature, vol. 477, pp.
271-275, 2011.
[6] Kargbo D, Wilhelm R, Campbell D, "Natural Gas Plays in the Marcellus Shale: Challenges and
Potential Opportunities," Environmental Science and Technology, vol. 44, no. 15, pp. 5679-5684,
2010.
[7] Warner N, et al., "Geochemical evidence for possible natural migration of Marcellus Formation brine to shallow aquifers in Pennsylvania," Proceedings of the National Academy of Sciences of the
United States of America, 2012.
[8] Hopey D, Malloy D, "Radiation in Fracking Fluids is a New Concern," Tribune Business News, 2011.
[9] McSurdy S, Vidic R, "Utilizing Coal mine drainage for Marcellus Shale Activities in Pennsylvania,"
National Energy Technology Laboratory, 2011.
[10] Lutz, B., A. Lewis, and M. Doyle, "Generation, transport, and disposal of wastewater associated with
Marcellus Shale gas development," Water Resources Research, vol. 49, no. doi:10.1002/wrcr.20096, pp. 647-656, 2013.
[11] Maloney K, Yoxtheimer D, "Production and Disposal of Waste Materials from Gas and Oil Extraction from the Marcellus Shale Play in Pennsylvania," Environmental Practice, vol. 14, no. 4, pp. 278-287,
December 2012.
[12] J. Mauro, "Elevated Levels of Naturally Occurring Radioactive Material Associated with Shale Gas
20

Extraction," Search and Discovery , vol. Article #80266, October 2012.
[13] Dresel P, Rose A, "Chemistry and Origin of Oil and Gas Well Brines in Western Pennsylvania,"
Pennsylvania Geological Survey, 2010.
[14] United States Environmental Protection Agency, "National Primary Drinking Water Regultions," 05
June 2012. [Online]. Available: http://water.epa.gov/drink/contaminants/index.cfm.
[15] Idaho State University, "Radioactivity in Nature," Radiation Information Network, [Online].
Available: http://physics.isu.edu/radinf/natural.htm.
[16] J. Welch, "Reverse osmosis treamtent of CBM produced water continues to evolve," Oil & Gas
Journal, vol. 107, no. 37, pp. 45-50, October 2009.
[17] Puder M., and J. Veil, "Offsite Commercial Disposal of Oil and Gas Exploration and Production
Waste: Availability, Options, and Cost," Argonne National Laboratory: Environmental Science
Division, p. 148, 2006.
[18] Curtright AE, Giglio K, "Coal Mine Drainage for Marcellus Shale Natural Gas Extraction," in
Roundtable on Feasibility and Challenges, Pittsburgh, 2012.
[19] "Frac Focus: Chemical Disclosure Registry," Ground Water Protection Council , [Online]. Available: http://fracfocus.org/.
[20] Ziemkiewicz P, et al., "Coal mine drainage Treatment with Armored Limestone in Open Limestone
Channels," Journal of Environmental Quality, vol. 26, no. 4, pp. 1017-1024, 1997.
[21] Neculita C, Zagury G, Bussiere B, "Passive Treatment of Coal mine drainage in Bioreactors using
Sulfate-Reducing Bacteria: Critical Review and Research Needs," Journal of Environmental Quality,
Vols. 36,1, p. 16, 2007.
[22] Reinhardt CH, "Coal mine drainage in Pennsylvania Streams: "Ironing Out" The Problem,"
Restoration and Reclamation Review, vol. 5, no. 1, pp. 1-10, 1999.
[23] United States Environmental Protection Agency, "Secondary Drinking Water Regulations: Guidance for Nuisance Chemicals," May 2012. [Online]. Available: http://water.epa.gov/drink/contaminants/secondarystandards.cfm.
[24] Ziemkiewicz PF, Skousen JG, Simmons J, "Long-term Performance of Passive Coal mine drainage
Treatment Systems," Mine Water and the Environment, vol. 22, no. 3, pp. 118-129, 2003.
[25] Costa MC, Martins M, Jesus C, Duarte, "Treatement of Coal mine drainage by Sulphate-reducing
Bacteria Using Low Cost Matrices," Water, Air and Soil Pollution, pp. 189:149-162, 2008.
21

[26] S. Thomas, Artist, Acid Mine Draingae. [Art]. Westrn Pennsylvania Conservancy.
[27] Winston, K, "Advisers Urge Study of Fracking Water Treatment for Radiation, Byproducts," Inside
EPA's Risk Policy Report, vol. 18, no. 11, 2011.
[28] A. Lustgarten, "Is New York's Marcellus Shale Too Hot to Handle," ProPublica, 2009.
[29] "PSE Report: Research Needed to Address Signs of Health, Environmental Dangers of Fracking,"
Manufacturing Close-Up, 2012.
[30] Hayes, T, "Proceedings and Minutes of the Hydraulic Fracturing Expert Panel XTO Facilities," in
ASWCMC, Fort Worth, 2007.
[31] Hughes T, Gray N, "Co-Treatment of Coal mine drainage with Municipal Wastewater Using the
Activated Sludge Process: Preliminary Treatability Studies," in National Meeting of the American
Society of Mining and Reclamations, Bismarck, 2011.
[32] Henrot J, Wieder RK, "Processes of Iron and Manganese Retention in Laboratory Peat Microcosms
Subjected to Coal mine drainage," Journal of Environmental Quality, vol. 19, no. 3, pp. 312-320,
1990.
[33] Yoxtheimer D, Blumsack S, Murphy T, "The Decision to Use Acidic Coal Mine Drainage for Hydraulic
Fracturing of Unconventional Shale-Gas Wells," Environmental Practice, vol. 14, no. 4, pp. 301-307,
December 2012.
[34] Senate Bill 411, "An Act amending Title 27 (Environmental Resources) of the Pennsylvania
Consolidated Statutes," Pennsylvania General Assembly, 2013.
[35] Pennsylvania Department of Environmental Protection, "The Environmental Good Sumaritan Act:
DEP Fact Sheet," 2004.
[36] S. Phillips, "Environmentalists Throw Cold Water on Efforts to Amend Good Samaritan Act," NPR
State Impact, March 2013.
[37] Kendall C, Caldwell E, "Fundamentals of Isotope Geochemistry," in Isotope Tracers in Catchment
Hydrology, Amsterdam, Elsevier Science, 1998, pp. 51-86.
[38] Kendall C, Coplen T, "Distribution of oxygen-18 and deuterium in river waters across the United
States," Hydrological Processes, vol. 15, pp. 1363-1393, 2001.
[39] Lopez D, Gierlowski-Kordesch E, Hollenkamp C, "Geochemical Mobility and Bioavailablity of Heavy
Metals in a Lake Affected by Coal mine drainage: Lake Hope, Vinton County, Ohio," Water, Air and
Soil Pollution, vol. 213, pp. 27-45, 2010.
22

[40] Kalin M, Fyson A, Wheeler WN, "The chemestry of conventional and alternative treatment systems for the neutralization of coal mine drainage," Science of the Total Environment, vol. 366, pp. 395-
408, 2009.
[41] Bai H, et al., "Treatment of coal mine drainage by sulfate reducing bacteria with iron in bench scale runs," Bioresource Technology, vol. 128, pp. 818-822, 2013.
[42] Blowes DW, et al., "The Geochemistry of Coal mine drainage," Treatise on Geochemistry, vol. 9, pp.
149-204, 2003.
[43] Nash T, "Overview of Mine Drainage Geochemistry at Historical Mines, Humboldt River Basin and
Adjacent Mining Areas, Nevada," in Geoenvironmental Investigations of the Humboldt River Basin,
Northern Nevada, 2003, p. 28.
[44] Rose A, Cravotta A, "Geochemistry of Coal Mine Drainage," in Coal Mine Drainage Prediction and
Pollution Prevention in Pennsylvania, 1998, pp. 1-22.
[45] Teklehaimanot Y, "Evaluation of the Tab-Simco coal mine drainage treatment system: water chemistry, performance and treatment processes," Masters Thesis, Southern Illinois University,
2001.
Analyzing the changes or fractionations in the ratios of heavy to light isotopes of trace elements such as hydrogen and oxygen is important because their unique compositions can be indicative of the physical, chemical, and biological processes that formed those waters or solutes. [37]δ18O is the ratio of isotopes of oxygen 16 to those of oxygen 18 while δD is the ratio of isotopes of hydrogen 1 to hydrogen 2. These ratios can then be compared to standard mean ocean water (SMOW) using the following equation:
δ(in ‰) = (𝑅 𝑥
/ 𝑅 𝑠
− 1) · 1000
S
. [37] Differences in these ratios for the trace elements for both flowback and produced water samples are shown in table 6. The negative δ values shown in most of the table indicate that the isotopic ratios of the samples are lower than those of the standard.
23

Table 6: Pw and Fb Isotopes
One of the ways that these δ’s can be used is the local meteoric water line (LMWL), which portrays the linear relationship between δH and δO values and is useful in understanding evaporative processes.
Kendall and Coplen (2001) have defined this relationship for both the national average line as well as for a number of individually sampled sites. [38] Of particular interest to this project is the LMWL for State
College, Pennsylvania, which is the closest available approximation of the LMWL of western
Pennsylvania, where the flowback and produced water samples were taken from. The ratio was plotted on figure 14 using the equation: 𝛿𝐷 = 12.4 + 𝛿
18
𝑂(7.9) from Kendall and Coplen’s work. [38]In addition to the line from the State College data, produced water and flowback water were included in the analysis for comparison. Looking at this figure, it is clear that the LMWL for State College and the
Produced water MWL share the similar slopes while having different intercepts. The change in position of the line indicates that the produced water, which was most likely taken from rivers and streams in the area and injected into wells as hydraulic fracturing fluid, spent some time sitting in an evaporation pond.
Flowback water, which is released from pores in the shale when it is fractured, has a completely different slope and intercept because this brine has been stored in the formation for millions of years and has undergone a number of different geologic processes.
24

Figure 14: Local Meteoric Water Lines
Simple linear regression between pH and metal concentrations of coal mine drainage are shown below
25

Simple linear regression between alkalinity and metal concentrations of coal mine drainage.
Fretwell's Law: "Warning! Stable isotope data may cause severe and contagious stomach upset if taken alone. To prevent upsetting reviewers' stomachs and your own, take stable isotope data with a healthy dose of other hydrologic, geologic, and geochemical information. Then, you will find stable isotope data very beneficial." [37]
26

27

28

29