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Repository for Oil and Gas Energy Research (ROGER)
The Repository for Oil and Gas Energy Research, or ROGER, is a near-exhaustive collection of bibliographic information, abstracts, and links to many of journal articles that pertain to shale and tight gas development. The goal of this project is to create a single repository for unconventional oil and gas-related research as a resource for academic, scientific, and citizen researchers.
ROGER currently includes 2303 studies.
Last updated: September 01, 2024
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A review of water and greenhouse gas impacts of unconventional natural gas development in the United States
Arent et al., September 2024
A review of water and greenhouse gas impacts of unconventional natural gas development in the United States
Douglas Arent, Jeffrey Logan, Jordan Macknick, William Boyd, Kenneth III Medlock, Francis O'Sullivan, Jae Edmonds, Leon Clarke, Hillard Huntington, Garvin Heath, Patricia Statwick, Morgan Bazilian (2024). MRS Energy & Sustainability - A Review Journal, . 10.1557/mre.2015.5
Abstract:
ABSTRACT This paper reviews recent developments in the production and use of unconventional natural gas in the United States with a focus on water and greenhouse gas emission implications. If unconventional natural gas in the U.S. is produced responsibly, transported and distributed with little leakage, and incorporated into integrated energy systems that are designed for future resiliency, it could play a significant role in realizing a more sustainable energy future; however, the increased use of natural gas as a substitute for more carbon intensive fuels will alone not substantially alter world carbon dioxide concentration projections. This paper reviews recent developments in the production and use of unconventional natural gas in the United States with a focus on environmental impacts. Specifically, we focus on water management and greenhouse gas emission implications. If unconventional natural gas in the United States is produced responsibly, transported and distributed with little leakage, and incorporated into integrated energy systems that are designed for future resiliency, it could play a significant role in realizing a more sustainable energy future. The cutting-edge of industry water management practices gives a picture of how this transition is unfolding, although much opportunity remains to minimize water use and related environmental impacts. The role of natural gas to mitigate climate forcing is less clear. While natural gas has low CO2 emissions upon direct use, methane leakage and long term climate effects lead to the conclusion that increased use of natural gas as a substitute for more carbon intensive fuels will not substantially alter world carbon dioxide concentration projections, and that other zero or low carbon energy sources will be needed to limit GHG concentrations. We conclude with some possible avenues for further work.
ABSTRACT This paper reviews recent developments in the production and use of unconventional natural gas in the United States with a focus on water and greenhouse gas emission implications. If unconventional natural gas in the U.S. is produced responsibly, transported and distributed with little leakage, and incorporated into integrated energy systems that are designed for future resiliency, it could play a significant role in realizing a more sustainable energy future; however, the increased use of natural gas as a substitute for more carbon intensive fuels will alone not substantially alter world carbon dioxide concentration projections. This paper reviews recent developments in the production and use of unconventional natural gas in the United States with a focus on environmental impacts. Specifically, we focus on water management and greenhouse gas emission implications. If unconventional natural gas in the United States is produced responsibly, transported and distributed with little leakage, and incorporated into integrated energy systems that are designed for future resiliency, it could play a significant role in realizing a more sustainable energy future. The cutting-edge of industry water management practices gives a picture of how this transition is unfolding, although much opportunity remains to minimize water use and related environmental impacts. The role of natural gas to mitigate climate forcing is less clear. While natural gas has low CO2 emissions upon direct use, methane leakage and long term climate effects lead to the conclusion that increased use of natural gas as a substitute for more carbon intensive fuels will not substantially alter world carbon dioxide concentration projections, and that other zero or low carbon energy sources will be needed to limit GHG concentrations. We conclude with some possible avenues for further work.
Surface water geochemical and isotopic variations in an area of accelerating Marcellus Shale gas development
Adam J. Pelak and Shikha Sharma, December 2014
Surface water geochemical and isotopic variations in an area of accelerating Marcellus Shale gas development
Adam J. Pelak and Shikha Sharma (2014). Environmental Pollution, 91-100. 10.1016/j.envpol.2014.08.016
Abstract:
Water samples were collected from 50 streams in an area of accelerating shale gas development in the eastern U.S.A. The geochemical/isotopic characteristics show no correlation with the five categories of Marcellus Shale production. The sub-watersheds with the greatest density of Marcellus Shale development have also undergone extensive coal mining. Hence, geochemical/isotopic compositions were used to understand sources of salinity and effects of coal mining and shale gas development in the area. The data indicates that while some streams appear to be impacted by mine drainage; none appear to have received sustained contribution from deep brines or produced waters associated with shale gas production. However, it is important to note that our interpretations are based on one time synoptic base flow sampling of a few sampling stations and hence do account potential intermittent changes in chemistry that may result from major/minor spills or specific mine discharges on the surface water chemistry.
Water samples were collected from 50 streams in an area of accelerating shale gas development in the eastern U.S.A. The geochemical/isotopic characteristics show no correlation with the five categories of Marcellus Shale production. The sub-watersheds with the greatest density of Marcellus Shale development have also undergone extensive coal mining. Hence, geochemical/isotopic compositions were used to understand sources of salinity and effects of coal mining and shale gas development in the area. The data indicates that while some streams appear to be impacted by mine drainage; none appear to have received sustained contribution from deep brines or produced waters associated with shale gas production. However, it is important to note that our interpretations are based on one time synoptic base flow sampling of a few sampling stations and hence do account potential intermittent changes in chemistry that may result from major/minor spills or specific mine discharges on the surface water chemistry.
Assessing impacts of unconventional natural gas extraction on microbial communities in headwater stream ecosystems in Northwestern Pennsylvania
Trexler et al., November 2014
Assessing impacts of unconventional natural gas extraction on microbial communities in headwater stream ecosystems in Northwestern Pennsylvania
Ryan Trexler, Caroline Solomon, Colin J. Brislawn, Justin R. Wright, Abigail Rosenberger, Erin E. McClure, Alyssa M. Grube, Mark P. Peterson, Mehdi Keddache, Olivia U. Mason, Terry C. Hazen, Christopher J. Grant, Regina Lamendella (2014). Aquatic Microbiology, 522. 10.3389/fmicb.2014.00522
Abstract:
Hydraulic fracturing and horizontal drilling have increased dramatically in Pennsylvania Marcellus shale formations, however the potential for major environmental impacts are still incompletely understood. High-throughput sequencing of the 16S rRNA gene was performed to characterize the microbial community structure of water, sediment, bryophyte, and biofilm samples from 26 headwater stream sites in northwestern Pennsylvania with different histories of fracking activity within Marcellus shale formations. Further, we describe the relationship between microbial community structure and environmental parameters measured. Approximately 3.2 million 16S rRNA gene sequences were retrieved from a total of 58 samples. Microbial community analyses showed significant reductions in species richness as well as evenness in sites with Marcellus shale activity. Beta diversity analyses revealed distinct microbial community structure between sites with and without Marcellus shale activity. For example, operational taxonomic units (OTUs) within the Acetobacteracea, Methylocystaceae, Acidobacteriaceae, and Phenylobacterium were greater than three log-fold more abundant in MSA+ sites as compared to MSA− sites. Further, several of these OTUs were strongly negatively correlated with pH and positively correlated with the number of wellpads in a watershed. It should be noted that many of the OTUs enriched in MSA+ sites are putative acidophilic and/or methanotrophic populations. This study revealed apparent shifts in the autochthonous microbial communities and highlighted potential members that could be responding to changing stream conditions as a result of nascent industrial activity in these aquatic ecosystems.
Hydraulic fracturing and horizontal drilling have increased dramatically in Pennsylvania Marcellus shale formations, however the potential for major environmental impacts are still incompletely understood. High-throughput sequencing of the 16S rRNA gene was performed to characterize the microbial community structure of water, sediment, bryophyte, and biofilm samples from 26 headwater stream sites in northwestern Pennsylvania with different histories of fracking activity within Marcellus shale formations. Further, we describe the relationship between microbial community structure and environmental parameters measured. Approximately 3.2 million 16S rRNA gene sequences were retrieved from a total of 58 samples. Microbial community analyses showed significant reductions in species richness as well as evenness in sites with Marcellus shale activity. Beta diversity analyses revealed distinct microbial community structure between sites with and without Marcellus shale activity. For example, operational taxonomic units (OTUs) within the Acetobacteracea, Methylocystaceae, Acidobacteriaceae, and Phenylobacterium were greater than three log-fold more abundant in MSA+ sites as compared to MSA− sites. Further, several of these OTUs were strongly negatively correlated with pH and positively correlated with the number of wellpads in a watershed. It should be noted that many of the OTUs enriched in MSA+ sites are putative acidophilic and/or methanotrophic populations. This study revealed apparent shifts in the autochthonous microbial communities and highlighted potential members that could be responding to changing stream conditions as a result of nascent industrial activity in these aquatic ecosystems.
Direct and indirect challenges for water quality from the hydraulic fracturing industry
Sharon C. Long, November 2014
Direct and indirect challenges for water quality from the hydraulic fracturing industry
Sharon C. Long (2014). Journal American Water Works Association, 53-57. 10.5942/jawwa.2014.106.0155
Abstract:
Wellbore stability model for shale gas reservoir considering the coupling of multi-weakness planes and porous flow
Liang et al., November 2014
Wellbore stability model for shale gas reservoir considering the coupling of multi-weakness planes and porous flow
Chuan Liang, Mian Chen, Yan Jin, Yunhu Lu (2014). Journal of Natural Gas Science and Engineering, 364-378. 10.1016/j.jngse.2014.08.025
Abstract:
Irregular wellbore collapse phenomena and accidents frequently occur during drilling operations in Longmaxi shale gas reservoir. Considering shale formation with natural cross beddings and fractures, we propose a multi-weakness plane instead of a single weakness plane failure model. Shale samples obtained from the Lower Silurian Longmaxi Strata of Sichuan Basin are investigated based on characterization and analysis of mineralogy, pore structure, sliding failure condition, and rock mechanics to study the impact of porous flow on jointed shale masses. Results show that Longmaxi gas shale is a brittle and fracture-prone material with poor hydrating capacity and extremely low permeability in rock matrices. Reduction of rock strength under porous flow may contribute to changes in intensity parameters of the weakness planes. Therefore, considering the failure of multi-weakness planes under porous flow, we present a wellbore stability model for shale gas reservoir. Two types of weakness plane distribution patterns are examined to discuss the effect of the occurrence, numbers, and water saturation of weakness planes. The results demonstrate that the number of weakness planes, difference in weakness plane occurrence, and diverse water saturation levels significantly affect wellbore stability during drilling.
Irregular wellbore collapse phenomena and accidents frequently occur during drilling operations in Longmaxi shale gas reservoir. Considering shale formation with natural cross beddings and fractures, we propose a multi-weakness plane instead of a single weakness plane failure model. Shale samples obtained from the Lower Silurian Longmaxi Strata of Sichuan Basin are investigated based on characterization and analysis of mineralogy, pore structure, sliding failure condition, and rock mechanics to study the impact of porous flow on jointed shale masses. Results show that Longmaxi gas shale is a brittle and fracture-prone material with poor hydrating capacity and extremely low permeability in rock matrices. Reduction of rock strength under porous flow may contribute to changes in intensity parameters of the weakness planes. Therefore, considering the failure of multi-weakness planes under porous flow, we present a wellbore stability model for shale gas reservoir. Two types of weakness plane distribution patterns are examined to discuss the effect of the occurrence, numbers, and water saturation of weakness planes. The results demonstrate that the number of weakness planes, difference in weakness plane occurrence, and diverse water saturation levels significantly affect wellbore stability during drilling.
New Tracers Identify Hydraulic Fracturing Fluids and Accidental Releases from Oil and Gas Operations
Warner et al., October 2014
New Tracers Identify Hydraulic Fracturing Fluids and Accidental Releases from Oil and Gas Operations
N. R. Warner, T. H. Darrah, R. B. Jackson, R. Millot, W. Kloppmann, A. Vengosh (2014). Environmental Science & Technology, . 10.1021/es5032135
Abstract:
Identifying the geochemical fingerprints of fluids that return to the surface after high volume hydraulic fracturing of unconventional oil and gas reservoirs has important applications for assessing hydrocarbon resource recovery, environmental impacts, and wastewater treatment and disposal. Here, we report for the first time, novel diagnostic elemental and isotopic signatures (B/Cl, Li/Cl, δ11B, and δ7Li) useful for characterizing hydraulic fracturing flowback fluids (HFFF) and distinguishing sources of HFFF in the environment. Data from 39 HFFFs and produced water samples show that B/Cl (>0.001), Li/Cl (>0.002), δ11B (25?31?) and δ7Li (6?10?) compositions of HFFF from the Marcellus and Fayetteville black shale formations were distinct in most cases from produced waters sampled from conventional oil and gas wells. We posit that boron isotope geochemistry can be used to quantify small fractions (?0.1%) of HFFF in contaminated fresh water and likely be applied universally to trace HFFF in other basins. The novel environmental application of this diagnostic isotopic tool is validated by examining the composition of effluent discharge from an oil and gas brine treatment facility in Pennsylvania and an accidental spill site in West Virginia. We hypothesize that the boron and lithium are mobilized from exchangeable sites on clay minerals in the shale formations during the hydraulic fracturing process, resulting in the relative enrichment of boron and lithium in HFFF.
Identifying the geochemical fingerprints of fluids that return to the surface after high volume hydraulic fracturing of unconventional oil and gas reservoirs has important applications for assessing hydrocarbon resource recovery, environmental impacts, and wastewater treatment and disposal. Here, we report for the first time, novel diagnostic elemental and isotopic signatures (B/Cl, Li/Cl, δ11B, and δ7Li) useful for characterizing hydraulic fracturing flowback fluids (HFFF) and distinguishing sources of HFFF in the environment. Data from 39 HFFFs and produced water samples show that B/Cl (>0.001), Li/Cl (>0.002), δ11B (25?31?) and δ7Li (6?10?) compositions of HFFF from the Marcellus and Fayetteville black shale formations were distinct in most cases from produced waters sampled from conventional oil and gas wells. We posit that boron isotope geochemistry can be used to quantify small fractions (?0.1%) of HFFF in contaminated fresh water and likely be applied universally to trace HFFF in other basins. The novel environmental application of this diagnostic isotopic tool is validated by examining the composition of effluent discharge from an oil and gas brine treatment facility in Pennsylvania and an accidental spill site in West Virginia. We hypothesize that the boron and lithium are mobilized from exchangeable sites on clay minerals in the shale formations during the hydraulic fracturing process, resulting in the relative enrichment of boron and lithium in HFFF.
Modelling the hypothetical methane-leakage in a shale-gas project and the impact on groundwater quality
Michael O. Schwartz, October 2014
Modelling the hypothetical methane-leakage in a shale-gas project and the impact on groundwater quality
Michael O. Schwartz (2014). Environmental Earth Sciences, 4619-4632. 10.1007/s12665-014-3787-3
Abstract:
The hypothetical leakage of methane gas caused by fracking a 1,000-m deep Cretaceous claystone horizon at Damme, Germany, is simulated in a TOUGHREACT reactive-transport model with 5,728 elements. A hypothetical leakage zone connects the Cretaceous horizon with a Quaternary potable-water aquifer (q1). Methane gas rises up to the q1 horizon in less than 2 days in all calculated scenarios. The simulations include the major constituents of groundwater as well as the seven most hazardous trace components that are natural constituents of groundwater (As, Cd, Cr, Ni, Pb, Se and U). The general trend is characterised by depletion of the natural hazardous components with decreasing acidity and oxygen fugacity in the relevant pH range (7–9). Nevertheless, the concentrations of elements whose dominant aqueous species are negatively charged in this pH range (Cr and Se) rise against the general trend due to desorption reactions. Slight enhancement effects are produced by the dissolution of contaminant-bearing oxides such as Cr-bearing goethite. In summary, the geological risks of a fracking operation are minor. The technical risks are more important. This is especially the case when rising methane gas gets into contact with fracking fluid that accidentally escapes through faulty well seals.
The hypothetical leakage of methane gas caused by fracking a 1,000-m deep Cretaceous claystone horizon at Damme, Germany, is simulated in a TOUGHREACT reactive-transport model with 5,728 elements. A hypothetical leakage zone connects the Cretaceous horizon with a Quaternary potable-water aquifer (q1). Methane gas rises up to the q1 horizon in less than 2 days in all calculated scenarios. The simulations include the major constituents of groundwater as well as the seven most hazardous trace components that are natural constituents of groundwater (As, Cd, Cr, Ni, Pb, Se and U). The general trend is characterised by depletion of the natural hazardous components with decreasing acidity and oxygen fugacity in the relevant pH range (7–9). Nevertheless, the concentrations of elements whose dominant aqueous species are negatively charged in this pH range (Cr and Se) rise against the general trend due to desorption reactions. Slight enhancement effects are produced by the dissolution of contaminant-bearing oxides such as Cr-bearing goethite. In summary, the geological risks of a fracking operation are minor. The technical risks are more important. This is especially the case when rising methane gas gets into contact with fracking fluid that accidentally escapes through faulty well seals.
Analysis of the Groundwater Monitoring Controversy at the Pavillion, Wyoming Natural Gas Field
Daniel B. Stephens, September 2014
Analysis of the Groundwater Monitoring Controversy at the Pavillion, Wyoming Natural Gas Field
Daniel B. Stephens (2014). Ground Water, . 10.1111/gwat.12272
Abstract:
The U.S. Environmental Protection Agency (EPA) was contacted by citizens of Pavillion, Wyoming 6 years ago regarding taste and odor in their water wells in an area where hydraulic fracturing operations were occurring. EPA conducted a field investigation, including drilling two deep monitor wells, and concluded in a draft report that constituents associated with hydraulic fracturing had impacted the drinking water aquifer. Following extensive media coverage, pressure from state and other federal agencies, and extensive technical criticism from industry, EPA stated the draft report would not undergo peer review, that it would not rely on the conclusions, and that it had relinquished its lead role in the investigation to the State of Wyoming for further investigation without resolving the source of the taste and odor problem. Review of the events leading up to EPA's decision suggests that much of the criticism could have been avoided through improved preproject planning with clear objectives. Such planning would have identified the high national significance and potential implications of the proposed work. Expanded stakeholder involvement and technical input could have eliminated some of the difficulties that plagued the investigation. However, collecting baseline groundwater quality data prior to initiating hydraulic fracturing likely would have been an effective way to evaluate potential impacts. The Pavillion groundwater investigation provides an excellent opportunity for improving field methods, report transparency, clarity of communication, and the peer review process in future investigations of the impacts of hydraulic fracturing on groundwater.
The U.S. Environmental Protection Agency (EPA) was contacted by citizens of Pavillion, Wyoming 6 years ago regarding taste and odor in their water wells in an area where hydraulic fracturing operations were occurring. EPA conducted a field investigation, including drilling two deep monitor wells, and concluded in a draft report that constituents associated with hydraulic fracturing had impacted the drinking water aquifer. Following extensive media coverage, pressure from state and other federal agencies, and extensive technical criticism from industry, EPA stated the draft report would not undergo peer review, that it would not rely on the conclusions, and that it had relinquished its lead role in the investigation to the State of Wyoming for further investigation without resolving the source of the taste and odor problem. Review of the events leading up to EPA's decision suggests that much of the criticism could have been avoided through improved preproject planning with clear objectives. Such planning would have identified the high national significance and potential implications of the proposed work. Expanded stakeholder involvement and technical input could have eliminated some of the difficulties that plagued the investigation. However, collecting baseline groundwater quality data prior to initiating hydraulic fracturing likely would have been an effective way to evaluate potential impacts. The Pavillion groundwater investigation provides an excellent opportunity for improving field methods, report transparency, clarity of communication, and the peer review process in future investigations of the impacts of hydraulic fracturing on groundwater.
Noble gases identify the mechanisms of fugitive gas contamination in drinking-water wells overlying the Marcellus and Barnett Shales
Darrah et al., September 2014
Noble gases identify the mechanisms of fugitive gas contamination in drinking-water wells overlying the Marcellus and Barnett Shales
Thomas H. Darrah, Avner Vengosh, Robert B. Jackson, Nathaniel R. Warner, Robert J. Poreda (2014). Proceedings of the National Academy of Sciences, 201322107. 10.1073/pnas.1322107111
Abstract:
Horizontal drilling and hydraulic fracturing have enhanced energy production but raised concerns about drinking-water contamination and other environmental impacts. Identifying the sources and mechanisms of contamination can help improve the environmental and economic sustainability of shale-gas extraction. We analyzed 113 and 20 samples from drinking-water wells overlying the Marcellus and Barnett Shales, respectively, examining hydrocarbon abundance and isotopic compositions (e.g., C2H6/CH4, δ13C-CH4) and providing, to our knowledge, the first comprehensive analyses of noble gases and their isotopes (e.g., 4He, 20Ne, 36Ar) in groundwater near shale-gas wells. We addressed two questions. (i) Are elevated levels of hydrocarbon gases in drinking-water aquifers near gas wells natural or anthropogenic? (ii) If fugitive gas contamination exists, what mechanisms cause it? Against a backdrop of naturally occurring salt- and gas-rich groundwater, we identified eight discrete clusters of fugitive gas contamination, seven in Pennsylvania and one in Texas that showed increased contamination through time. Where fugitive gas contamination occurred, the relative proportions of thermogenic hydrocarbon gas (e.g., CH4, 4He) were significantly higher (P < 0.01) and the proportions of atmospheric gases (air-saturated water; e.g., N2, 36Ar) were significantly lower (P < 0.01) relative to background groundwater. Noble gas isotope and hydrocarbon data link four contamination clusters to gas leakage from intermediate-depth strata through failures of annulus cement, three to target production gases that seem to implicate faulty production casings, and one to an underground gas well failure. Noble gas data appear to rule out gas contamination by upward migration from depth through overlying geological strata triggered by horizontal drilling or hydraulic fracturing.
Horizontal drilling and hydraulic fracturing have enhanced energy production but raised concerns about drinking-water contamination and other environmental impacts. Identifying the sources and mechanisms of contamination can help improve the environmental and economic sustainability of shale-gas extraction. We analyzed 113 and 20 samples from drinking-water wells overlying the Marcellus and Barnett Shales, respectively, examining hydrocarbon abundance and isotopic compositions (e.g., C2H6/CH4, δ13C-CH4) and providing, to our knowledge, the first comprehensive analyses of noble gases and their isotopes (e.g., 4He, 20Ne, 36Ar) in groundwater near shale-gas wells. We addressed two questions. (i) Are elevated levels of hydrocarbon gases in drinking-water aquifers near gas wells natural or anthropogenic? (ii) If fugitive gas contamination exists, what mechanisms cause it? Against a backdrop of naturally occurring salt- and gas-rich groundwater, we identified eight discrete clusters of fugitive gas contamination, seven in Pennsylvania and one in Texas that showed increased contamination through time. Where fugitive gas contamination occurred, the relative proportions of thermogenic hydrocarbon gas (e.g., CH4, 4He) were significantly higher (P < 0.01) and the proportions of atmospheric gases (air-saturated water; e.g., N2, 36Ar) were significantly lower (P < 0.01) relative to background groundwater. Noble gas isotope and hydrocarbon data link four contamination clusters to gas leakage from intermediate-depth strata through failures of annulus cement, three to target production gases that seem to implicate faulty production casings, and one to an underground gas well failure. Noble gas data appear to rule out gas contamination by upward migration from depth through overlying geological strata triggered by horizontal drilling or hydraulic fracturing.
Enhanced Formation of Disinfection By-Products in Shale Gas Wastewater-Impacted Drinking Water Supplies
Parker et al., September 2014
Enhanced Formation of Disinfection By-Products in Shale Gas Wastewater-Impacted Drinking Water Supplies
Kimberly M. Parker, Teng Zeng, Jennifer Harkness, Avner Vengosh, William Armistead Mitch (2014). Environmental Science & Technology, . 10.1021/es5028184
Abstract:
The disposal and leaks of hydraulic fracturing wastewater (HFW) to the environment pose human health risks. Since HFW is typically characterized by elevated salinity, concerns have been raised whether the high bromide and iodide in HFW may promote the formation of disinfection byproducts (DBPs) and alter their speciation to more toxic brominated and iodinated analogues. This study evaluated the minimum volume percentage of two Marcellus Shale and one Fayetteville Shale HFWs diluted by fresh water collected from the Ohio and Allegheny Rivers that would generate and/or alter the formation and speciation of DBPs following chlorination, chloramination and ozonation treatments of the blended solutions. During chlorination, dilutions as low as 0.01% HFW altered the speciation towards formation of brominated and iodinated trihalomethanes (THMs) and brominated haloacetonitriles (HANs), and dilutions as low as 0.03% increased the overall formation of both compound classes. The increase in bromide concentration associated with 0.01%-0.03% contribution of Marcellus HFW (a range of 70 to 200 g/L for HFW with bromide = 600 mg/L) mimics the increased bromide levels observed in western Pennsylvanian surface waters following the Marcellus Shale gas production boom. Chloramination reduced HAN and regulated THM formation; however iodinated trihalomethane formation was observed at lower pH. For municipal wastewater-impacted river water, the presence of 0.1% HFW increased the formation of N-nitrosodimethylamine (NDMA) during chloramination, particularly for the high iodide (54 ppm) Fayetteville Shale HFW. Finally, ozonation of 0.01%-0.03% HFW-impacted river water resulted in significant increases in bromate formation. The results suggest that total elimination of HFW discharge and/or installation of halide-specific removal techniques in centralized brine treatment facilities may be a better strategy to mitigate impacts on downstream drinking water treatment plants than altering disinfection strategies. The potential formation of multiple DBPs in drinking water utilities in areas of shale gas development requires comprehensive monitoring plans beyond the common regulated DBPs.
The disposal and leaks of hydraulic fracturing wastewater (HFW) to the environment pose human health risks. Since HFW is typically characterized by elevated salinity, concerns have been raised whether the high bromide and iodide in HFW may promote the formation of disinfection byproducts (DBPs) and alter their speciation to more toxic brominated and iodinated analogues. This study evaluated the minimum volume percentage of two Marcellus Shale and one Fayetteville Shale HFWs diluted by fresh water collected from the Ohio and Allegheny Rivers that would generate and/or alter the formation and speciation of DBPs following chlorination, chloramination and ozonation treatments of the blended solutions. During chlorination, dilutions as low as 0.01% HFW altered the speciation towards formation of brominated and iodinated trihalomethanes (THMs) and brominated haloacetonitriles (HANs), and dilutions as low as 0.03% increased the overall formation of both compound classes. The increase in bromide concentration associated with 0.01%-0.03% contribution of Marcellus HFW (a range of 70 to 200 g/L for HFW with bromide = 600 mg/L) mimics the increased bromide levels observed in western Pennsylvanian surface waters following the Marcellus Shale gas production boom. Chloramination reduced HAN and regulated THM formation; however iodinated trihalomethane formation was observed at lower pH. For municipal wastewater-impacted river water, the presence of 0.1% HFW increased the formation of N-nitrosodimethylamine (NDMA) during chloramination, particularly for the high iodide (54 ppm) Fayetteville Shale HFW. Finally, ozonation of 0.01%-0.03% HFW-impacted river water resulted in significant increases in bromate formation. The results suggest that total elimination of HFW discharge and/or installation of halide-specific removal techniques in centralized brine treatment facilities may be a better strategy to mitigate impacts on downstream drinking water treatment plants than altering disinfection strategies. The potential formation of multiple DBPs in drinking water utilities in areas of shale gas development requires comprehensive monitoring plans beyond the common regulated DBPs.
Oil and gas wells and their integrity: Implications for shale and unconventional resource exploitation
Davies et al., September 2014
Oil and gas wells and their integrity: Implications for shale and unconventional resource exploitation
Richard J. Davies, Sam Almond, Robert S. Ward, Robert B. Jackson, Charlotte Adams, Fred Worrall, Liam G. Herringshaw, Jon G. Gluyas, Mark A. Whitehead (2014). Marine and Petroleum Geology, 239-254. 10.1016/j.marpetgeo.2014.03.001
Abstract:
Data from around the world (Australia, Austria, Bahrain, Brazil, Canada, the Netherlands, Poland, the UK and the USA) show that more than four million onshore hydrocarbon wells have been drilled globally. Here we assess all the reliable datasets (25) on well barrier and integrity failure in the published literature and online. These datasets include production, injection, idle and abandoned wells, both onshore and offshore, exploiting both conventional and unconventional reservoirs. The datasets vary considerably in terms of the number of wells examined, their age and their designs. Therefore the percentage of wells that have had some form of well barrier or integrity failure is highly variable (1.9%–75%). Of the 8030 wells targeting the Marcellus shale inspected in Pennsylvania between 2005 and 2013, 6.3% of these have been reported to the authorities for infringements related to well barrier or integrity failure. In a separate study of 3533 Pennsylvanian wells monitored between 2008 and 2011, there were 85 examples of cement or casing failures, 4 blowouts and 2 examples of gas venting. In the UK, 2152 hydrocarbon wells were drilled onshore between 1902 and 2013 mainly targeting conventional reservoirs. UK regulations, like those of other jurisdictions, include reclamation of the well site after well abandonment. As such, there is no visible evidence of 65.2% of these well sites on the land surface today and monitoring is not carried out. The ownership of up to 53% of wells in the UK is unclear; we estimate that between 50 and 100 are orphaned. Of 143 active UK wells that were producing at the end of 2000, one has evidence of a well integrity failure.
Data from around the world (Australia, Austria, Bahrain, Brazil, Canada, the Netherlands, Poland, the UK and the USA) show that more than four million onshore hydrocarbon wells have been drilled globally. Here we assess all the reliable datasets (25) on well barrier and integrity failure in the published literature and online. These datasets include production, injection, idle and abandoned wells, both onshore and offshore, exploiting both conventional and unconventional reservoirs. The datasets vary considerably in terms of the number of wells examined, their age and their designs. Therefore the percentage of wells that have had some form of well barrier or integrity failure is highly variable (1.9%–75%). Of the 8030 wells targeting the Marcellus shale inspected in Pennsylvania between 2005 and 2013, 6.3% of these have been reported to the authorities for infringements related to well barrier or integrity failure. In a separate study of 3533 Pennsylvanian wells monitored between 2008 and 2011, there were 85 examples of cement or casing failures, 4 blowouts and 2 examples of gas venting. In the UK, 2152 hydrocarbon wells were drilled onshore between 1902 and 2013 mainly targeting conventional reservoirs. UK regulations, like those of other jurisdictions, include reclamation of the well site after well abandonment. As such, there is no visible evidence of 65.2% of these well sites on the land surface today and monitoring is not carried out. The ownership of up to 53% of wells in the UK is unclear; we estimate that between 50 and 100 are orphaned. Of 143 active UK wells that were producing at the end of 2000, one has evidence of a well integrity failure.
The fate of residual treatment water in gas shale
Engelder et al., September 2014
The fate of residual treatment water in gas shale
Terry Engelder, Lawrence M. Cathles, L. Taras Bryndzia (2014). Journal of Unconventional Oil and Gas Resources, 33-48. 10.1016/j.juogr.2014.03.002
Abstract:
More than 2 × 104 m3 of water containing additives is commonly injected into a typical horizontal well in gas shale to open fractures and allow gas recovery. Less than half of this treatment water is recovered as flowback or later production brine, and in many cases recovery is <30%. While recovered treatment water is safely managed at the surface, the water left in place, called residual treatment water (RTW), slips beyond the control of engineers. Some have suggested that this RTW poses a long term and serious risk to shallow aquifers by virtue of being free water that can flow upward along natural pathways, mainly fractures and faults. These concerns are based on single phase Darcy Law physics which is not appropriate when gas and water are both present. In addition, the combined volume of the RTW and the initial brine in gas shale is too small to impact near surface aquifers even if it could escape. When capillary and osmotic forces are considered, there are no forces propelling the RTW upward from gas shale along natural pathways. The physics dominating these processes ensure that capillary and osmotic forces both propel the RTW into the matrix of the shale, thus permanently sequestering it. Furthermore, contrary to the suggestion that hydraulic fracturing could accelerate brine escape and make near surface aquifer contamination more likely, hydraulic fracturing and gas recovery will actually reduce this risk. We demonstrate this in a series of STP counter-current imbibition experiments on cuttings recovered from the Union Springs Member of the Marcellus gas shale in Pennsylvania and on core plugs of Haynesville gas shale from NW Louisiana.
More than 2 × 104 m3 of water containing additives is commonly injected into a typical horizontal well in gas shale to open fractures and allow gas recovery. Less than half of this treatment water is recovered as flowback or later production brine, and in many cases recovery is <30%. While recovered treatment water is safely managed at the surface, the water left in place, called residual treatment water (RTW), slips beyond the control of engineers. Some have suggested that this RTW poses a long term and serious risk to shallow aquifers by virtue of being free water that can flow upward along natural pathways, mainly fractures and faults. These concerns are based on single phase Darcy Law physics which is not appropriate when gas and water are both present. In addition, the combined volume of the RTW and the initial brine in gas shale is too small to impact near surface aquifers even if it could escape. When capillary and osmotic forces are considered, there are no forces propelling the RTW upward from gas shale along natural pathways. The physics dominating these processes ensure that capillary and osmotic forces both propel the RTW into the matrix of the shale, thus permanently sequestering it. Furthermore, contrary to the suggestion that hydraulic fracturing could accelerate brine escape and make near surface aquifer contamination more likely, hydraulic fracturing and gas recovery will actually reduce this risk. We demonstrate this in a series of STP counter-current imbibition experiments on cuttings recovered from the Union Springs Member of the Marcellus gas shale in Pennsylvania and on core plugs of Haynesville gas shale from NW Louisiana.
Leakage detection of Marcellus Shale natural gas at an Upper Devonian gas monitoring well: a 3-D numerical modeling approach
Zhang et al., August 2014
Leakage detection of Marcellus Shale natural gas at an Upper Devonian gas monitoring well: a 3-D numerical modeling approach
Liwei Zhang, Nicole Anderson, Robert Dilmore, Daniel J. Soeder, Grant Bromhal (2014). Environmental Science & Technology, . 10.1021/es501997p
Abstract:
Potential natural gas leakage into shallow, overlying formations and aquifers from Marcellus Shale gas drilling operations is a public concern. However, before natural gas could reach underground sources of drinking water (USDW), it must pass through several geologic formations. Tracer and pressure monitoring in formations overlying the Marcellus could help detect natural gas leakage at hydraulic fracturing sites before it reaches USDW. In this study, a numerical simulation code (TOUGH 2) was used to investigate the potential for detecting leaking natural gas in such an overlying geologic formation. The modeled zone was based on a gas field in Greene County, Pennsylvania, undergoing production activities. The model assumed, hypothetically, that methane (CH4), the primary component of natural gas, with some tracer, was leaking around an existing well between the Marcellus Shale and the shallower and lower-pressure Bradford Formation. The leaky well was located 170 m away from a monitoring well, in the Bradford Formation. A simulation study was performed to determine how quickly the tracer monitoring could detect a leak of a known size. Using some typical parameters for the Bradford Formation, model results showed that a detectable tracer volume fraction of 2.0 x 10-15 would be noted at the monitoring well in 9.8 years. The most rapid detection of tracer for the leak rates simulated was 81 days, but this scenario required that the leakage release point was at the same depth as the perforation zone of the monitoring well and the zones above and below the perforation zone had low permeability, which created a preferred tracer migration pathway along the perforation zone. Sensitivity analysis indicated that the time needed to detect CH4 leakage at the monitoring well was very sensitive to changes in the thickness of the high-permeability zone, CH4 leaking rate and production rate of the monitoring well.
Potential natural gas leakage into shallow, overlying formations and aquifers from Marcellus Shale gas drilling operations is a public concern. However, before natural gas could reach underground sources of drinking water (USDW), it must pass through several geologic formations. Tracer and pressure monitoring in formations overlying the Marcellus could help detect natural gas leakage at hydraulic fracturing sites before it reaches USDW. In this study, a numerical simulation code (TOUGH 2) was used to investigate the potential for detecting leaking natural gas in such an overlying geologic formation. The modeled zone was based on a gas field in Greene County, Pennsylvania, undergoing production activities. The model assumed, hypothetically, that methane (CH4), the primary component of natural gas, with some tracer, was leaking around an existing well between the Marcellus Shale and the shallower and lower-pressure Bradford Formation. The leaky well was located 170 m away from a monitoring well, in the Bradford Formation. A simulation study was performed to determine how quickly the tracer monitoring could detect a leak of a known size. Using some typical parameters for the Bradford Formation, model results showed that a detectable tracer volume fraction of 2.0 x 10-15 would be noted at the monitoring well in 9.8 years. The most rapid detection of tracer for the leak rates simulated was 81 days, but this scenario required that the leakage release point was at the same depth as the perforation zone of the monitoring well and the zones above and below the perforation zone had low permeability, which created a preferred tracer migration pathway along the perforation zone. Sensitivity analysis indicated that the time needed to detect CH4 leakage at the monitoring well was very sensitive to changes in the thickness of the high-permeability zone, CH4 leaking rate and production rate of the monitoring well.
Strontium Isotopes Test Long-Term Zonal Isolation of Injected and Marcellus Formation Water after Hydraulic Fracturing
Kohl et al., August 2014
Strontium Isotopes Test Long-Term Zonal Isolation of Injected and Marcellus Formation Water after Hydraulic Fracturing
Courtney A. Kolesar Kohl, Rosemary C. Capo, Brian W. Stewart, Andrew J. Wall, Karl T. Schroeder, Richard W. Hammack, George D. Guthrie (2014). Environmental Science & Technology, 9867-9873. 10.1021/es501099k
Abstract:
One concern regarding unconventional hydrocarbon production from organic-rich shale is that hydraulic fracture stimulation could create pathways that allow injected fluids and deep brines from the target formation or adjacent units to migrate upward into shallow drinking water aquifers. This study presents Sr isotope and geochemical data from a well-constrained site in Greene County, Pennsylvania, in which samples were collected before and after hydraulic fracturing of the Middle Devonian Marcellus Shale. Results spanning a 15-month period indicated no significant migration of Marcellus-derived fluids into Upper Devonian/Lower Mississippian units located 900-1200 m above the lateral Marcellus boreholes or into groundwater sampled at a spring near the site. Monitoring the Sr isotope ratio of water from legacy oil and gas wells or drinking water wells can provide a sensitive early warning of upward brine migration for many years after well stimulation.
One concern regarding unconventional hydrocarbon production from organic-rich shale is that hydraulic fracture stimulation could create pathways that allow injected fluids and deep brines from the target formation or adjacent units to migrate upward into shallow drinking water aquifers. This study presents Sr isotope and geochemical data from a well-constrained site in Greene County, Pennsylvania, in which samples were collected before and after hydraulic fracturing of the Middle Devonian Marcellus Shale. Results spanning a 15-month period indicated no significant migration of Marcellus-derived fluids into Upper Devonian/Lower Mississippian units located 900-1200 m above the lateral Marcellus boreholes or into groundwater sampled at a spring near the site. Monitoring the Sr isotope ratio of water from legacy oil and gas wells or drinking water wells can provide a sensitive early warning of upward brine migration for many years after well stimulation.
Hydraulic "Fracking": Are surface water impacts an ecological concern?
Burton et al., August 2014
Hydraulic "Fracking": Are surface water impacts an ecological concern?
G. Allen Burton, Niladri Basu, Brian R. Ellis, Katherine E. Kapo, Sally Entrekin, Knute Nadelhoffer (2014). Environmental toxicology and chemistry / SETAC, 1679-1689. 10.1002/etc.2619
Abstract:
Use of high-volume hydraulic fracturing (HVHF) in unconventional reservoirs to recover previously inaccessible oil and natural gas is rapidly expanding in North America and elsewhere. Although hydraulic fracturing has been practiced for decades, the advent of more technologically advanced horizontal drilling coupled with improved slickwater chemical formulations has allowed extensive natural gas and oil deposits to be recovered from shale formations. Millions of liters of local groundwaters are utilized to generate extensive fracture networks within these low-permeability reservoirs, allowing extraction of the trapped hydrocarbons. Although the technology is relatively standardized, the geographies and related policies and regulations guiding these operations vary markedly. Some ecosystems are more at risk from these operations than others because of either their sensitivities or the manner in which the HVHF operations are conducted. Generally, the closer geographical proximity of the susceptible ecosystem to a drilling site or a location of related industrial processes, the higher the risk of that ecosystem being impacted by the operation. The associated construction of roads, power grids, pipelines, well pads, and water-extraction systems along with increased truck traffic are common to virtually all HVHF operations. These operations may result in increased erosion and sedimentation, increased risk to aquatic ecosystems from chemical spills or runoff, habitat fragmentation, loss of stream riparian zones, altered biogeochemical cycling, and reduction of available surface and hyporheic water volumes because of withdrawal-induced lowering of local groundwater levels. The potential risks to surface waters from HVHF operations are similar in many ways to those resulting from agriculture, silviculture, mining, and urban development. Indeed, groundwater extraction associated with agriculture is perhaps a larger concern in the long term in some regions. Understanding the ecological impacts of these anthropogenic activities provides useful information for evaluations of potential HVHF hazards. Geographic information system-based modeling combined with strategic site monitoring has provided insights into the relative importance of these and other ecoregion and land-use factors in discerning potential HVHF impacts. Recent findings suggest that proper siting and operational controls along with strategic monitoring can reduce the potential for risks to aquatic ecosystems. Nevertheless, inadequate data exist to predict ecological risk at this time. The authors suggest considering the plausibility of surface water hazards associated with the various HVHF operations in terms of the ecological context and in the context of relevant anthropogenic activities. Environ Toxicol Chem 2014;33:1679-1689. © 2014 SETAC.
Use of high-volume hydraulic fracturing (HVHF) in unconventional reservoirs to recover previously inaccessible oil and natural gas is rapidly expanding in North America and elsewhere. Although hydraulic fracturing has been practiced for decades, the advent of more technologically advanced horizontal drilling coupled with improved slickwater chemical formulations has allowed extensive natural gas and oil deposits to be recovered from shale formations. Millions of liters of local groundwaters are utilized to generate extensive fracture networks within these low-permeability reservoirs, allowing extraction of the trapped hydrocarbons. Although the technology is relatively standardized, the geographies and related policies and regulations guiding these operations vary markedly. Some ecosystems are more at risk from these operations than others because of either their sensitivities or the manner in which the HVHF operations are conducted. Generally, the closer geographical proximity of the susceptible ecosystem to a drilling site or a location of related industrial processes, the higher the risk of that ecosystem being impacted by the operation. The associated construction of roads, power grids, pipelines, well pads, and water-extraction systems along with increased truck traffic are common to virtually all HVHF operations. These operations may result in increased erosion and sedimentation, increased risk to aquatic ecosystems from chemical spills or runoff, habitat fragmentation, loss of stream riparian zones, altered biogeochemical cycling, and reduction of available surface and hyporheic water volumes because of withdrawal-induced lowering of local groundwater levels. The potential risks to surface waters from HVHF operations are similar in many ways to those resulting from agriculture, silviculture, mining, and urban development. Indeed, groundwater extraction associated with agriculture is perhaps a larger concern in the long term in some regions. Understanding the ecological impacts of these anthropogenic activities provides useful information for evaluations of potential HVHF hazards. Geographic information system-based modeling combined with strategic site monitoring has provided insights into the relative importance of these and other ecoregion and land-use factors in discerning potential HVHF impacts. Recent findings suggest that proper siting and operational controls along with strategic monitoring can reduce the potential for risks to aquatic ecosystems. Nevertheless, inadequate data exist to predict ecological risk at this time. The authors suggest considering the plausibility of surface water hazards associated with the various HVHF operations in terms of the ecological context and in the context of relevant anthropogenic activities. Environ Toxicol Chem 2014;33:1679-1689. © 2014 SETAC.
Using Discriminant Analysis to Determine Sources of Salinity in Shallow Groundwater Prior to Hydraulic Fracturing
Lautz et al., July 2014
Using Discriminant Analysis to Determine Sources of Salinity in Shallow Groundwater Prior to Hydraulic Fracturing
Laura K. Lautz, Gregory D. Hoke, Zunli Lu, Donald I. Siegel, Kayla Christian, John Daniel Kessler, Natalie G. Teale (2014). Environmental Science & Technology, . 10.1021/es502244v
Abstract:
High-volume hydraulic fracturing (HVHF) gas-drilling operations in the Marcellus Play have raised environmental concerns, including the risk of groundwater contamination. Fingerprinting water impacted by gas-drilling operations is not trivial given other potential sources of contamination. We present a multivariate statistical modeling framework for developing a quantitative, geochemical fingerprinting tool to distinguish sources of high salinity in shallow groundwater. The model was developed using new geochemical data for 204 wells in New York State (NYS), which has a HVHF moratorium and published data for additional wells in NYS and several salinity sources (Appalachian Basin brines, road salt, septic effluent, and animal waste). The model incorporates a stochastic simulation to predict the geochemistry of high salinity (>20 mg/L Cl) groundwater impacted by different salinity sources and then employs linear discriminant analysis to classify samples from different populations. Model results indicate Appalachian Basin brines are the primary source of salinity in 35% of sampled NYS groundwater wells with >20 mg/L Cl. The model provides an effective means for differentiating groundwater impacted by basin brines versus other contaminants. Using this framework, similar discriminatory tools can be derived for other regions from background water quality data.
High-volume hydraulic fracturing (HVHF) gas-drilling operations in the Marcellus Play have raised environmental concerns, including the risk of groundwater contamination. Fingerprinting water impacted by gas-drilling operations is not trivial given other potential sources of contamination. We present a multivariate statistical modeling framework for developing a quantitative, geochemical fingerprinting tool to distinguish sources of high salinity in shallow groundwater. The model was developed using new geochemical data for 204 wells in New York State (NYS), which has a HVHF moratorium and published data for additional wells in NYS and several salinity sources (Appalachian Basin brines, road salt, septic effluent, and animal waste). The model incorporates a stochastic simulation to predict the geochemistry of high salinity (>20 mg/L Cl) groundwater impacted by different salinity sources and then employs linear discriminant analysis to classify samples from different populations. Model results indicate Appalachian Basin brines are the primary source of salinity in 35% of sampled NYS groundwater wells with >20 mg/L Cl. The model provides an effective means for differentiating groundwater impacted by basin brines versus other contaminants. Using this framework, similar discriminatory tools can be derived for other regions from background water quality data.
Use of stable isotopes to identify sources of methane in Appalachian Basin shallow groundwaters: a review
J. Alexandra Hakala, July 2014
Use of stable isotopes to identify sources of methane in Appalachian Basin shallow groundwaters: a review
J. Alexandra Hakala (2014). Environmental Science: Processes & Impacts, . 10.1039/C4EM00140K
Abstract:
Development of unconventional shale gas reservoirs in the Appalachian Basin has raised questions regarding the potential for these activities to affect shallow groundwater resources. Geochemical indicators, such as stable carbon and hydrogen isotopes of methane, stable carbon isotopes of ethane, and hydrocarbon ratios, have been used to evaluate methane sources however their utility is complicated by influences from multiple physical (e.g., mixing) and geochemical (e.g., redox) processes. Baseline sampling of shallow aquifers prior to development, and measurement of additional geochemical indicators within samples from across the Appalachian Basin, may aid in identifying natural causes for dissolved methane in shallow groundwater versus development-induced pathways.
Development of unconventional shale gas reservoirs in the Appalachian Basin has raised questions regarding the potential for these activities to affect shallow groundwater resources. Geochemical indicators, such as stable carbon and hydrogen isotopes of methane, stable carbon isotopes of ethane, and hydrocarbon ratios, have been used to evaluate methane sources however their utility is complicated by influences from multiple physical (e.g., mixing) and geochemical (e.g., redox) processes. Baseline sampling of shallow aquifers prior to development, and measurement of additional geochemical indicators within samples from across the Appalachian Basin, may aid in identifying natural causes for dissolved methane in shallow groundwater versus development-induced pathways.
The integrity of oil and gas wells
Robert B. Jackson, July 2014
The integrity of oil and gas wells
Robert B. Jackson (2014). Proceedings of the National Academy of Sciences, 201410786. 10.1073/pnas.1410786111
Abstract:
Assessment and risk analysis of casing and cement impairment in oil and gas wells in Pennsylvania, 2000–2012
Ingraffea et al., June 2014
Assessment and risk analysis of casing and cement impairment in oil and gas wells in Pennsylvania, 2000–2012
Anthony R. Ingraffea, Martin T. Wells, Renee L. Santoro, Seth B. C. Shonkoff (2014). Proceedings of the National Academy of Sciences, 201323422. 10.1073/pnas.1323422111
Abstract:
Casing and cement impairment in oil and gas wells can lead to methane migration into the atmosphere and/or into underground sources of drinking water. An analysis of 75,505 compliance reports for 41,381 conventional and unconventional oil and gas wells in Pennsylvania drilled from January 1, 2000–December 31, 2012, was performed with the objective of determining complete and accurate statistics of casing and cement impairment. Statewide data show a sixfold higher incidence of cement and/or casing issues for shale gas wells relative to conventional wells. The Cox proportional hazards model was used to estimate risk of impairment based on existing data. The model identified both temporal and geographic differences in risk. For post-2009 drilled wells, risk of a cement/casing impairment is 1.57-fold [95% confidence interval (CI) (1.45, 1.67); P < 0.0001] higher in an unconventional gas well relative to a conventional well drilled within the same time period. Temporal differences between well types were also observed and may reflect more thorough inspections and greater emphasis on finding well leaks, more detailed note taking in the available inspection reports, or real changes in rates of structural integrity loss due to rushed development or other unknown factors. Unconventional gas wells in northeastern (NE) Pennsylvania are at a 2.7-fold higher risk relative to the conventional wells in the same area. The predicted cumulative risk for all wells (unconventional and conventional) in the NE region is 8.5-fold [95% CI (7.16, 10.18); P < 0.0001] greater than that of wells drilled in the rest of the state.
Casing and cement impairment in oil and gas wells can lead to methane migration into the atmosphere and/or into underground sources of drinking water. An analysis of 75,505 compliance reports for 41,381 conventional and unconventional oil and gas wells in Pennsylvania drilled from January 1, 2000–December 31, 2012, was performed with the objective of determining complete and accurate statistics of casing and cement impairment. Statewide data show a sixfold higher incidence of cement and/or casing issues for shale gas wells relative to conventional wells. The Cox proportional hazards model was used to estimate risk of impairment based on existing data. The model identified both temporal and geographic differences in risk. For post-2009 drilled wells, risk of a cement/casing impairment is 1.57-fold [95% confidence interval (CI) (1.45, 1.67); P < 0.0001] higher in an unconventional gas well relative to a conventional well drilled within the same time period. Temporal differences between well types were also observed and may reflect more thorough inspections and greater emphasis on finding well leaks, more detailed note taking in the available inspection reports, or real changes in rates of structural integrity loss due to rushed development or other unknown factors. Unconventional gas wells in northeastern (NE) Pennsylvania are at a 2.7-fold higher risk relative to the conventional wells in the same area. The predicted cumulative risk for all wells (unconventional and conventional) in the NE region is 8.5-fold [95% CI (7.16, 10.18); P < 0.0001] greater than that of wells drilled in the rest of the state.
Hydraulic Fracture Extending into Network in Shale: Reviewing Influence Factors and Their Mechanism
Ren et al., June 2014
Hydraulic Fracture Extending into Network in Shale: Reviewing Influence Factors and Their Mechanism
Lan Ren, Jinzhou Zhao, Yongquan Hu (2014). The Scientific World Journal, e847107. 10.1155/2014/847107
Abstract:
Hydraulic fracture in shale reservoir presents complex network propagation, which has essential difference with traditional plane biwing fracture at forming mechanism. Based on the research results of experiments, field fracturing practice, theory analysis, and numerical simulation, the influence factors and their mechanism of hydraulic fracture extending into network in shale have been systematically analyzed and discussed. Research results show that the fracture propagation in shale reservoir is influenced by the geological and the engineering factors, which includes rock mineral composition, rock mechanical properties, horizontal stress field, natural fractures, treating net pressure, fracturing fluid viscosity, and fracturing scale. This study has important theoretical value and practical significance to understand fracture network propagation mechanism in shale reservoir and contributes to improving the science and efficiency of shale reservoir fracturing design.
Hydraulic fracture in shale reservoir presents complex network propagation, which has essential difference with traditional plane biwing fracture at forming mechanism. Based on the research results of experiments, field fracturing practice, theory analysis, and numerical simulation, the influence factors and their mechanism of hydraulic fracture extending into network in shale have been systematically analyzed and discussed. Research results show that the fracture propagation in shale reservoir is influenced by the geological and the engineering factors, which includes rock mineral composition, rock mechanical properties, horizontal stress field, natural fractures, treating net pressure, fracturing fluid viscosity, and fracturing scale. This study has important theoretical value and practical significance to understand fracture network propagation mechanism in shale reservoir and contributes to improving the science and efficiency of shale reservoir fracturing design.
Effect of Hydrofracking Fluid on Colloid Transport in the Unsaturated Zone
Sang et al., June 2014
Effect of Hydrofracking Fluid on Colloid Transport in the Unsaturated Zone
Wenjing Sang, Cathelijne R Stoof, Wei Zhang, Veronica L. Morales, Bin Gao, Robert W Kay, Lin Liu, Yalei Zhang, Tammo S. Steenhuis (2014). Environmental Science & Technology, . 10.1021/es501441e
Abstract:
Hydraulic fracturing is expanding rapidly in the US to meet increasing energy demand and requires high volumes of hydrofracking fluid to displace natural gas from shale. Accidental spills and deliberate land application of hydrofracking fluids, which return to the surface during hydrofracking, are common causes of environmental contamination. Since the chemistry of hydrofracking fluids favors transport of colloids and mineral particles through rock cracks, it may also facilitate transport of in-situ colloids and associated pollutants in unsaturated soils. We investigated this by subsequently injecting deionized water and flowback fluid at increasing flow rates into unsaturated sand columns containing colloids. Colloid retention and mobilization was measured in the column effluent and visualized in-situ with bright field microscopy. While <5% of initial colloids were released by flushing with deionized water, 32-36% were released by flushing with flowback fluid in two distinct breakthrough peaks. These peaks resulted from 1) surface tension reduction and steric repulsion, and 2) slow kinetic disaggregation of colloid flocs. Increasing the flow rate of the flowback fluid mobilized an additional 36% of colloids, due to the expansion of water filled pore space. This study suggests that hydrofracking fluid may also indirectly contaminate groundwater by remobilizing existing colloidal pollutants.
Hydraulic fracturing is expanding rapidly in the US to meet increasing energy demand and requires high volumes of hydrofracking fluid to displace natural gas from shale. Accidental spills and deliberate land application of hydrofracking fluids, which return to the surface during hydrofracking, are common causes of environmental contamination. Since the chemistry of hydrofracking fluids favors transport of colloids and mineral particles through rock cracks, it may also facilitate transport of in-situ colloids and associated pollutants in unsaturated soils. We investigated this by subsequently injecting deionized water and flowback fluid at increasing flow rates into unsaturated sand columns containing colloids. Colloid retention and mobilization was measured in the column effluent and visualized in-situ with bright field microscopy. While <5% of initial colloids were released by flushing with deionized water, 32-36% were released by flushing with flowback fluid in two distinct breakthrough peaks. These peaks resulted from 1) surface tension reduction and steric repulsion, and 2) slow kinetic disaggregation of colloid flocs. Increasing the flow rate of the flowback fluid mobilized an additional 36% of colloids, due to the expansion of water filled pore space. This study suggests that hydrofracking fluid may also indirectly contaminate groundwater by remobilizing existing colloidal pollutants.
Surface disposal of produced waters in western and southwestern Pennsylvania: Potential for accumulation of alkali-earth elements in sediments
Skalak et al., June 2014
Surface disposal of produced waters in western and southwestern Pennsylvania: Potential for accumulation of alkali-earth elements in sediments
Katherine J. Skalak, Mark A. Engle, Elisabeth L. Rowan, Glenn D. Jolly, Kathryn M. Conko, Adam J. Benthem, Thomas F. Kraemer (2014). International Journal of Coal Geology, 162-170. 10.1016/j.coal.2013.12.001
Abstract:
Waters co-produced with hydrocarbons in the Appalachian Basin are of notably poor quality (concentrations of total dissolved solids (TDS) and total radium up to and exceeding 300,000 mg/L and 10,000 pCi/L, respectively). Since 2008, a rapid increase in Marcellus Shale gas production has led to a commensurate rise in associated wastewater while generation of produced water from conventional oil and gas activities has continued. In this study, we assess whether disposal practices from treatment of produced waters from both shale gas and conventional operations in Pennsylvania could result in the accumulation of associated alkali earth elements. The results from our 5 study sites indicate that there was no increase in concentrations of total Ra (Ra-226) and extractable Ba, Ca, Na, or Sr in fluvial sediments downstream of the discharge outfalls (p > 0.05) of publicly owned treatment works (POTWs) and centralized waste treatment facilities (CWTs). However, the use of road spreading of brines from conventional oil and gas wells for deicing resulted in accumulation of Ra-226 (1.2 ×), and extractable Sr (3.0 ×), Ca (5.3 ×), and Na (6.2 ×) in soil and sediment proximal to roads (p < 0.05). Although this study is an important initial assessment of the impacts of these disposal practices, more work is needed to consider the environmental consequences of produced waters management.
Waters co-produced with hydrocarbons in the Appalachian Basin are of notably poor quality (concentrations of total dissolved solids (TDS) and total radium up to and exceeding 300,000 mg/L and 10,000 pCi/L, respectively). Since 2008, a rapid increase in Marcellus Shale gas production has led to a commensurate rise in associated wastewater while generation of produced water from conventional oil and gas activities has continued. In this study, we assess whether disposal practices from treatment of produced waters from both shale gas and conventional operations in Pennsylvania could result in the accumulation of associated alkali earth elements. The results from our 5 study sites indicate that there was no increase in concentrations of total Ra (Ra-226) and extractable Ba, Ca, Na, or Sr in fluvial sediments downstream of the discharge outfalls (p > 0.05) of publicly owned treatment works (POTWs) and centralized waste treatment facilities (CWTs). However, the use of road spreading of brines from conventional oil and gas wells for deicing resulted in accumulation of Ra-226 (1.2 ×), and extractable Sr (3.0 ×), Ca (5.3 ×), and Na (6.2 ×) in soil and sediment proximal to roads (p < 0.05). Although this study is an important initial assessment of the impacts of these disposal practices, more work is needed to consider the environmental consequences of produced waters management.
Water resource impacts during unconventional shale gas development: The Pennsylvania experience
Brantley et al., June 2014
Water resource impacts during unconventional shale gas development: The Pennsylvania experience
Susan L. Brantley, Dave Yoxtheimer, Sina Arjmand, Paul Grieve, Radisav Vidic, Jon Pollak, Garth T. Llewellyn, Jorge Abad, Cesar Simon (2014). International Journal of Coal Geology, . 10.1016/j.coal.2013.12.017
Abstract:
Improvements in horizontal drilling and hydrofracturing have revolutionized the energy landscape by allowing the development of so-called “unconventional” gas resources. The Marcellus play in the northeastern U.S.A. documents how fast this technology developed: the number of unconventional Marcellus wells in Pennsylvania (PA) increased from 8 in 2005 to ~ 7234 today. Publicly available databases in PA show only rare evidence of contamination of surface and groundwaters. This could document that incidents that impact PA waters have been relatively rare and that contaminants were quickly diluted. However, firm conclusions are hampered by i) the lack of information about location and timing of incidents; ii) the tendency to not release water quality data related to specific incidents due to liability or confidentiality agreements; iii) the sparseness of sample and sensor data for the analytes of interest; iv) the presence of pre-existing water impairments that make it difficult to determine potential impacts from shale-gas activity; and v) the fact that sensors can malfunction or drift. Although the monitoring data available to assess contamination events in PA are limited, the state manages an online database of violations. Overall, one fifth of gas wells drilled were given at least one non-administrative notice of violation (NOV) from the PA regulator. Through March 2013, 3.4% of gas wells were issued NOVs for well construction issues and 0.24% of gas wells received NOVs related to methane migration into groundwater. Between 2008 and 2012, 161 of the ~ 1000 complaints received by the state described contamination that implicated oil or gas activity: natural gas was reported for 56% and brine salt components for 14% of the properties. Six percent of the properties were impacted by sediments, turbidity, and/or drill cuttings. Most of the sites of groundwater contamination with methane and/or salt components were in previously glaciated northern PA where fracture flow sometimes allows long distance fluid transport. No cases of subsurface transport of fracking or flowback fluids into water supplies were documented. If Marcellus-related flowback/production waters did enter surface or groundwaters, the most likely contaminants to be detected would be Na, Ca, and Cl, but those elements are already common in natural waters. The most Marcellus-specific “fingerprint” elements are Sr, Ba, and Br. For example, variable Br concentrations measured in southwestern PA streams were attributed to permitted release of wastewaters from unconventional shale gas wells into PA streams through municipal or industrial wastewater treatment plants before 2011. Discharge has now been discontinued except for brines from a few plants still permitted to discharge conventional oil/gas brines after treatment. Overall, drinking water supply problems determined by the regulator to implicate oil/gas activities peaked in frequency in 2010 while spill rates increased through 2012. Although many minor violations and temporary problems have been reported, the picture that emerges from PA is that the fast shale-gas start may have led to relatively few environmental incidents of significant impact compared to wells drilled; however, the impacts remain difficult to assess due to the lack of transparent and accessible data.
Improvements in horizontal drilling and hydrofracturing have revolutionized the energy landscape by allowing the development of so-called “unconventional” gas resources. The Marcellus play in the northeastern U.S.A. documents how fast this technology developed: the number of unconventional Marcellus wells in Pennsylvania (PA) increased from 8 in 2005 to ~ 7234 today. Publicly available databases in PA show only rare evidence of contamination of surface and groundwaters. This could document that incidents that impact PA waters have been relatively rare and that contaminants were quickly diluted. However, firm conclusions are hampered by i) the lack of information about location and timing of incidents; ii) the tendency to not release water quality data related to specific incidents due to liability or confidentiality agreements; iii) the sparseness of sample and sensor data for the analytes of interest; iv) the presence of pre-existing water impairments that make it difficult to determine potential impacts from shale-gas activity; and v) the fact that sensors can malfunction or drift. Although the monitoring data available to assess contamination events in PA are limited, the state manages an online database of violations. Overall, one fifth of gas wells drilled were given at least one non-administrative notice of violation (NOV) from the PA regulator. Through March 2013, 3.4% of gas wells were issued NOVs for well construction issues and 0.24% of gas wells received NOVs related to methane migration into groundwater. Between 2008 and 2012, 161 of the ~ 1000 complaints received by the state described contamination that implicated oil or gas activity: natural gas was reported for 56% and brine salt components for 14% of the properties. Six percent of the properties were impacted by sediments, turbidity, and/or drill cuttings. Most of the sites of groundwater contamination with methane and/or salt components were in previously glaciated northern PA where fracture flow sometimes allows long distance fluid transport. No cases of subsurface transport of fracking or flowback fluids into water supplies were documented. If Marcellus-related flowback/production waters did enter surface or groundwaters, the most likely contaminants to be detected would be Na, Ca, and Cl, but those elements are already common in natural waters. The most Marcellus-specific “fingerprint” elements are Sr, Ba, and Br. For example, variable Br concentrations measured in southwestern PA streams were attributed to permitted release of wastewaters from unconventional shale gas wells into PA streams through municipal or industrial wastewater treatment plants before 2011. Discharge has now been discontinued except for brines from a few plants still permitted to discharge conventional oil/gas brines after treatment. Overall, drinking water supply problems determined by the regulator to implicate oil/gas activities peaked in frequency in 2010 while spill rates increased through 2012. Although many minor violations and temporary problems have been reported, the picture that emerges from PA is that the fast shale-gas start may have led to relatively few environmental incidents of significant impact compared to wells drilled; however, the impacts remain difficult to assess due to the lack of transparent and accessible data.
Sources of High Total Dissolved Solids to Drinking Water Supply in Southwestern Pennsylvania
Wilson et al., May 2014
Sources of High Total Dissolved Solids to Drinking Water Supply in Southwestern Pennsylvania
Jessica M. Wilson, Yuxin Wang, Jeanne M. VanBriesen (2014). Journal of Environmental Engineering, B4014003. 10.1061/(ASCE)EE.1943-7870.0000733
Abstract:
Fossil fuel extraction activities generate wastewaters that are often high in total dissolved solids (TDS) and specific constituents that can affect drinking water, if these wastewaters enter surface waters. Control of TDS in source waters is difficult without identification of the potential sources of high TDS wastewater associated with fossil fuel activities. Characteristics of natural waters, oil and gas-produced waters, and coal-related wastewaters were analyzed to extract information about constituent concentrations and anion ratios. Statistical analysis of the anion ratios indicates that the SO4/Cl ratio is higher in coal-related wastewaters than in oil and gas-produced waters, suggesting that wastewaters can be distinguished based on this ratio. An approach that compared the SO4/Cl ratio with bromide concentration for the wastewaters can serve to separate oil and gas-produced waters from brine treatment plant discharges, and from the various coal-related wastewaters. This method was applied to surface water quality data collected from two tributaries in Southwestern Pennsylvania from September 2009 to September 2012. Results show that this constituent and ratio method, combined with mixing curve calculations, can be used to identify water quality changes in these two tributaries. Similar mixing models, when applied to regionally relevant high TDS wastewater data, may be used in other areas experiencing water quality changes resulting from fossil fuel extraction activities. (C) 2014 American Society of Civil Engineers.
Fossil fuel extraction activities generate wastewaters that are often high in total dissolved solids (TDS) and specific constituents that can affect drinking water, if these wastewaters enter surface waters. Control of TDS in source waters is difficult without identification of the potential sources of high TDS wastewater associated with fossil fuel activities. Characteristics of natural waters, oil and gas-produced waters, and coal-related wastewaters were analyzed to extract information about constituent concentrations and anion ratios. Statistical analysis of the anion ratios indicates that the SO4/Cl ratio is higher in coal-related wastewaters than in oil and gas-produced waters, suggesting that wastewaters can be distinguished based on this ratio. An approach that compared the SO4/Cl ratio with bromide concentration for the wastewaters can serve to separate oil and gas-produced waters from brine treatment plant discharges, and from the various coal-related wastewaters. This method was applied to surface water quality data collected from two tributaries in Southwestern Pennsylvania from September 2009 to September 2012. Results show that this constituent and ratio method, combined with mixing curve calculations, can be used to identify water quality changes in these two tributaries. Similar mixing models, when applied to regionally relevant high TDS wastewater data, may be used in other areas experiencing water quality changes resulting from fossil fuel extraction activities. (C) 2014 American Society of Civil Engineers.
Regional Variation in Water Related Impacts of Shale Gas Development and Implications for Emerging International Plays
Mauter et al., March 2014
Regional Variation in Water Related Impacts of Shale Gas Development and Implications for Emerging International Plays
Meagan S Mauter, Pedro J. J. Alvarez, G. Allen Burton, Diego Carlos Cafaro, Wei Chen, Kelvin B. Gregory, Guibin Jiang, Qilin Li, Jamie Pittock, Danny Reible, Jerald L. Schnoor (2014). Environmental Science & Technology, . 10.1021/es405432k
Abstract:
The unconventional fossil fuel industry is expected to expand dramatically in coming decades as conventional reserves wane. Minimizing the environmental impacts of this energy transition requires a contextualized understanding of the unique regional issues that shale gas development poses. This manuscript highlights the variation in regional water issues associated with shale gas development in the US and the approaches of various states in mitigating these impacts. The manuscript also explores opportunities for emerging international shale plays to leverage the diverse experiences of US states in formulating development strategies that minimize water related impacts within their environmental, cultural, and political ecosystem.
The unconventional fossil fuel industry is expected to expand dramatically in coming decades as conventional reserves wane. Minimizing the environmental impacts of this energy transition requires a contextualized understanding of the unique regional issues that shale gas development poses. This manuscript highlights the variation in regional water issues associated with shale gas development in the US and the approaches of various states in mitigating these impacts. The manuscript also explores opportunities for emerging international shale plays to leverage the diverse experiences of US states in formulating development strategies that minimize water related impacts within their environmental, cultural, and political ecosystem.
Evolving shale gas management: water resource risks, impacts, and lessons learned
Brian G. Rahm and Susan J. Riha, March 2014
Evolving shale gas management: water resource risks, impacts, and lessons learned
Brian G. Rahm and Susan J. Riha (2014). Environmental Science: Processes & Impacts, . 10.1039/C4EM00018H
Abstract:
Unconventional shale gas development promises to significantly alter energy portfolios and economies around the world. It also poses a variety of environmental risks, particularly with respect to the management of water resources. We review current scientific understanding of risks associated with the following: water withdrawals for hydraulic fracturing; wastewater treatment, discharge and disposal; methane and fluid migration in the subsurface; and spills and erosion at the surface. Some of these risks are relatively unique to shale gas development, while others are variations of risks that we already face from a variety of industries and activities. All of these risks depend largely on the pace and scale of development that occurs within a particular region. We focus on the United States, where the shale gas boom has been on-going for several years, paying particular attention to the Marcellus Shale, where a majority of peer-reviewed study has taken place. Governments, regulatory agencies, industry, and other stakeholders are challenged with responding to these risks, and we discuss policies and practices that have been adopted or considered by these various groups. Adaptive Management, a structured framework for addressing complex environmental issues, is discussed as a way to reduce polarization of important discussions on risk, and to more formally engage science in policy-making, along with other economic, social and value considerations. Data suggests that some risks can be substantially reduced through policy and best practice, but also that significant uncertainty persists regarding other risks. We suggest that monitoring and data collection related to water resource risks be established as part of planning for shale gas development before activity begins, and that resources are allocated to provide for appropriate oversight at various levels of governance.
Unconventional shale gas development promises to significantly alter energy portfolios and economies around the world. It also poses a variety of environmental risks, particularly with respect to the management of water resources. We review current scientific understanding of risks associated with the following: water withdrawals for hydraulic fracturing; wastewater treatment, discharge and disposal; methane and fluid migration in the subsurface; and spills and erosion at the surface. Some of these risks are relatively unique to shale gas development, while others are variations of risks that we already face from a variety of industries and activities. All of these risks depend largely on the pace and scale of development that occurs within a particular region. We focus on the United States, where the shale gas boom has been on-going for several years, paying particular attention to the Marcellus Shale, where a majority of peer-reviewed study has taken place. Governments, regulatory agencies, industry, and other stakeholders are challenged with responding to these risks, and we discuss policies and practices that have been adopted or considered by these various groups. Adaptive Management, a structured framework for addressing complex environmental issues, is discussed as a way to reduce polarization of important discussions on risk, and to more formally engage science in policy-making, along with other economic, social and value considerations. Data suggests that some risks can be substantially reduced through policy and best practice, but also that significant uncertainty persists regarding other risks. We suggest that monitoring and data collection related to water resource risks be established as part of planning for shale gas development before activity begins, and that resources are allocated to provide for appropriate oversight at various levels of governance.
Evidence and mechanisms for Appalachian Basin brine migration into shallow aquifers in NE Pennsylvania, USA
Garth T. Llewellyn, March 2014
Evidence and mechanisms for Appalachian Basin brine migration into shallow aquifers in NE Pennsylvania, USA
Garth T. Llewellyn (2014). Hydrogeology Journal, 1055-1066. 10.1007/s10040-014-1125-1
Abstract:
Multiple geographic information system (GIS) datasets, including joint orientations from nine bedrock outcrops, inferred faults, topographic lineaments, geophysical data (e.g. regional gravity, magnetic and stress field), 290 pre-gas-drilling groundwater samples (Cl–Br data) and Appalachian Basin brine (ABB) Cl–Br data, have been integrated to assess pre-gas-drilling salinization sources throughout Susquehanna County, Pennsylvania (USA), a focus area of Marcellus Shale gas development. ABB has migrated naturally and preferentially to shallow aquifers along an inferred normal fault and certain topographic lineaments generally trending NNE–SSW, sub-parallel with the maximum regional horizontal compressive stress field (orientated NE–SW). Gravity and magnetic data provide supporting evidence for the inferred faults and for structural control of the topographic lineaments with dominant ABB shallow groundwater signatures. Significant permeability at depth, imparted by the geologic structures and their orientation to the regional stress field, likely facilitates vertical migration of ABB fluids from depth. ABB is known to currently exist within Ordovician through Devonian stratigraphic units, but likely originates from Upper Silurian strata, suggesting significant migration through geologic time, both vertically and laterally. The natural presence of ABB-impacted shallow groundwater has important implications for differentiating gas-drilling-derived brine contamination, in addition to exposing potential vertical migration pathways for gas-drilling impacts.
Multiple geographic information system (GIS) datasets, including joint orientations from nine bedrock outcrops, inferred faults, topographic lineaments, geophysical data (e.g. regional gravity, magnetic and stress field), 290 pre-gas-drilling groundwater samples (Cl–Br data) and Appalachian Basin brine (ABB) Cl–Br data, have been integrated to assess pre-gas-drilling salinization sources throughout Susquehanna County, Pennsylvania (USA), a focus area of Marcellus Shale gas development. ABB has migrated naturally and preferentially to shallow aquifers along an inferred normal fault and certain topographic lineaments generally trending NNE–SSW, sub-parallel with the maximum regional horizontal compressive stress field (orientated NE–SW). Gravity and magnetic data provide supporting evidence for the inferred faults and for structural control of the topographic lineaments with dominant ABB shallow groundwater signatures. Significant permeability at depth, imparted by the geologic structures and their orientation to the regional stress field, likely facilitates vertical migration of ABB fluids from depth. ABB is known to currently exist within Ordovician through Devonian stratigraphic units, but likely originates from Upper Silurian strata, suggesting significant migration through geologic time, both vertically and laterally. The natural presence of ABB-impacted shallow groundwater has important implications for differentiating gas-drilling-derived brine contamination, in addition to exposing potential vertical migration pathways for gas-drilling impacts.
A Critical Review of the Risks to Water Resources from Unconventional Shale Gas Development and Hydraulic Fracturing in the United States
Vengosh et al., March 2014
A Critical Review of the Risks to Water Resources from Unconventional Shale Gas Development and Hydraulic Fracturing in the United States
Avner Vengosh, Robert B. Jackson, Nathaniel Warner, Thomas H. Darrah, Andrew Kondash (2014). Environmental Science & Technology, . 10.1021/es405118y
Abstract:
The rapid rise of shale gas development through horizontal drilling and high volume hydraulic fracturing has expanded the extraction of hydrocarbon resources in the U.S. The rise of shale gas development has triggered an intense public debate regarding the potential environmental and human health effects from hydraulic fracturing. This paper provides a critical review of the potential risks that shale gas operations pose to water resources, with an emphasis on case studies mostly from the U.S. Four potential risks for water resources are identified: (1) the contamination of shallow aquifers with fugitive hydrocarbon gases (i.e., stray gas contamination), which can also potentially lead to the salinization of shallow groundwater through leaking natural gas wells and subsurface flow; (2) the contamination of surface water and shallow groundwater from spills, leaks, and/or the disposal of inadequately treated shale gas wastewater; (3) the accumulation of toxic and radioactive elements in soil or stream sediments near disposal or spill sites; and (4) the overextraction of water resources for high-volume hydraulic fracturing that could induce water shortages or conflicts with other water users, particularly in water-scarce areas. Analysis of published data (through January 2014) reveals evidence for stray gas contamination, surface water impacts in areas of intensive shale gas development, and the accumulation of radium isotopes in some disposal and spill sites. The direct contamination of shallow groundwater from hydraulic fracturing fluids and deep formation waters by hydraulic fracturing itself, however, remains controversial.
The rapid rise of shale gas development through horizontal drilling and high volume hydraulic fracturing has expanded the extraction of hydrocarbon resources in the U.S. The rise of shale gas development has triggered an intense public debate regarding the potential environmental and human health effects from hydraulic fracturing. This paper provides a critical review of the potential risks that shale gas operations pose to water resources, with an emphasis on case studies mostly from the U.S. Four potential risks for water resources are identified: (1) the contamination of shallow aquifers with fugitive hydrocarbon gases (i.e., stray gas contamination), which can also potentially lead to the salinization of shallow groundwater through leaking natural gas wells and subsurface flow; (2) the contamination of surface water and shallow groundwater from spills, leaks, and/or the disposal of inadequately treated shale gas wastewater; (3) the accumulation of toxic and radioactive elements in soil or stream sediments near disposal or spill sites; and (4) the overextraction of water resources for high-volume hydraulic fracturing that could induce water shortages or conflicts with other water users, particularly in water-scarce areas. Analysis of published data (through January 2014) reveals evidence for stray gas contamination, surface water impacts in areas of intensive shale gas development, and the accumulation of radium isotopes in some disposal and spill sites. The direct contamination of shallow groundwater from hydraulic fracturing fluids and deep formation waters by hydraulic fracturing itself, however, remains controversial.
Estrogen and Androgen Receptor Activities of Hydraulic Fracturing Chemicals and Surface and Ground Water in a Drilling-Dense Region
Kassotis et al., March 2014
Estrogen and Androgen Receptor Activities of Hydraulic Fracturing Chemicals and Surface and Ground Water in a Drilling-Dense Region
Christopher D. Kassotis, Donald E. Tillitt, J. Wade Davis, Annette M. Hormann, Susan C. Nagel (2014). Endocrinology, 897-907. 10.1210/en.2013-1697
Abstract:
The rapid rise in natural gas extraction using hydraulic fracturing increases the potential for contamination of surface and ground water from chemicals used throughout the process. Hundreds of products containing more than 750 chemicals and components are potentially used throughout the extraction process, including more than 100 known or suspected endocrine-disrupting chemicals. We hypothesized that a selected subset of chemicals used in natural gas drilling operations and also surface and ground water samples collected in a drilling-dense region of Garfield County, Colorado, would exhibit estrogen and androgen receptor activities. Water samples were collected, solid-phase extracted, and measured for estrogen and androgen receptor activities using reporter gene assays in human cell lines. Of the 39 unique water samples, 89%, 41%, 12%, and 46% exhibited estrogenic, antiestrogenic, androgenic, and antiandrogenic activities, respectively. Testing of a subset of natural gas drilling chemicals revealed novel antiestrogenic, novel antiandrogenic, and limited estrogenic activities. The Colorado River, the drainage basin for this region, exhibited moderate levels of estrogenic, antiestrogenic, and antiandrogenic activities, suggesting that higher localized activity at sites with known natural gas–related spills surrounding the river might be contributing to the multiple receptor activities observed in this water source. The majority of water samples collected from sites in a drilling-dense region of Colorado exhibited more estrogenic, antiestrogenic, or antiandrogenic activities than reference sites with limited nearby drilling operations. Our data suggest that natural gas drilling operations may result in elevated endocrine-disrupting chemical activity in surface and ground water., AffiliationsDepartment of Obstetrics, Gynecology and Women's Health and Division of Biological Sciences (C.D.K., A.M.H., S.C.N.), University of Missouri, Columbia, Missouri 65211; US Geological Survey (D.E.T.), Columbia Environmental Research Center, Columbia, Missouri 65201; and Departments of Statistics and Health Management and Informatics (J.W.D.), University of Missouri, Columbia, Missouri 65211
The rapid rise in natural gas extraction using hydraulic fracturing increases the potential for contamination of surface and ground water from chemicals used throughout the process. Hundreds of products containing more than 750 chemicals and components are potentially used throughout the extraction process, including more than 100 known or suspected endocrine-disrupting chemicals. We hypothesized that a selected subset of chemicals used in natural gas drilling operations and also surface and ground water samples collected in a drilling-dense region of Garfield County, Colorado, would exhibit estrogen and androgen receptor activities. Water samples were collected, solid-phase extracted, and measured for estrogen and androgen receptor activities using reporter gene assays in human cell lines. Of the 39 unique water samples, 89%, 41%, 12%, and 46% exhibited estrogenic, antiestrogenic, androgenic, and antiandrogenic activities, respectively. Testing of a subset of natural gas drilling chemicals revealed novel antiestrogenic, novel antiandrogenic, and limited estrogenic activities. The Colorado River, the drainage basin for this region, exhibited moderate levels of estrogenic, antiestrogenic, and antiandrogenic activities, suggesting that higher localized activity at sites with known natural gas–related spills surrounding the river might be contributing to the multiple receptor activities observed in this water source. The majority of water samples collected from sites in a drilling-dense region of Colorado exhibited more estrogenic, antiestrogenic, or antiandrogenic activities than reference sites with limited nearby drilling operations. Our data suggest that natural gas drilling operations may result in elevated endocrine-disrupting chemical activity in surface and ground water., AffiliationsDepartment of Obstetrics, Gynecology and Women's Health and Division of Biological Sciences (C.D.K., A.M.H., S.C.N.), University of Missouri, Columbia, Missouri 65211; US Geological Survey (D.E.T.), Columbia Environmental Research Center, Columbia, Missouri 65201; and Departments of Statistics and Health Management and Informatics (J.W.D.), University of Missouri, Columbia, Missouri 65211
Distribution and Origin of Groundwater Methane in the Wattenberg Oil and Gas Field of Northern Colorado
Huishu Li and Kenneth H. Carlson, February 2014
Distribution and Origin of Groundwater Methane in the Wattenberg Oil and Gas Field of Northern Colorado
Huishu Li and Kenneth H. Carlson (2014). Environmental Science & Technology, 1484-1491. 10.1021/es404668b
Abstract:
Public concerns over potential environmental contamination associated with oil and gas well drilling and fracturing in the Wattenberg field in northeast Colorado are increasing. One of the issues of concern is the migration of oil, gas, or produced water to a groundwater aquifer resulting in contamination of drinking water. Since methane is the major component of natural gas and it can be dissolved and transported with groundwater, stray gas in aquifers has elicited attention. The initial step toward understanding the environmental impacts of oil and gas activities, such as well drilling and fracturing, is to determine the occurrence, where it is and where it came from. In this study, groundwater methane data that has been collected in response to a relatively new regulation in Colorado is analyzed. Dissolved methane was detected in 78% of groundwater wells with an average concentration of 4.0 mg/L and a range of 0?37.1 mg/L. Greater than 95% of the methane found in groundwater wells was classified as having a microbial origin, and there was minimal overlap between the C and H isotopic characterization of the produced gas and dissolved methane measured in the aquifer. Neither density of oil/gas wells nor distance to oil/gas wells had a significant impact on methane concentration suggesting other important factors were influencing methane generation and distribution. Thermogenic methane was detected in two aquifer wells indicating a potential contamination pathway from the producing formation, but microbial-origin gas was by far the predominant source of dissolved methane in the Wattenberg field.
Public concerns over potential environmental contamination associated with oil and gas well drilling and fracturing in the Wattenberg field in northeast Colorado are increasing. One of the issues of concern is the migration of oil, gas, or produced water to a groundwater aquifer resulting in contamination of drinking water. Since methane is the major component of natural gas and it can be dissolved and transported with groundwater, stray gas in aquifers has elicited attention. The initial step toward understanding the environmental impacts of oil and gas activities, such as well drilling and fracturing, is to determine the occurrence, where it is and where it came from. In this study, groundwater methane data that has been collected in response to a relatively new regulation in Colorado is analyzed. Dissolved methane was detected in 78% of groundwater wells with an average concentration of 4.0 mg/L and a range of 0?37.1 mg/L. Greater than 95% of the methane found in groundwater wells was classified as having a microbial origin, and there was minimal overlap between the C and H isotopic characterization of the produced gas and dissolved methane measured in the aquifer. Neither density of oil/gas wells nor distance to oil/gas wells had a significant impact on methane concentration suggesting other important factors were influencing methane generation and distribution. Thermogenic methane was detected in two aquifer wells indicating a potential contamination pathway from the producing formation, but microbial-origin gas was by far the predominant source of dissolved methane in the Wattenberg field.
Constraints on Upward Migration of Hydraulic Fracturing Fluid and Brine
Samuel A. Flewelling and Manu Sharma, January 1970
Constraints on Upward Migration of Hydraulic Fracturing Fluid and Brine
Samuel A. Flewelling and Manu Sharma (1970). Groundwater, 9–19. 10.1111/gwat.12095
Abstract:
Recent increases in the use of hydraulic fracturing (HF) to aid extraction of oil and gas from black shales have raised concerns regarding potential environmental effects associated with predictions of upward migration of HF fluid and brine. Some recent studies have suggested that such upward migration can be large and that timescales for migration can be as short as a few years. In this article, we discuss the physical constraints on upward fluid migration from black shales (e.g., the Marcellus, Bakken, and Eagle Ford) to shallow aquifers, taking into account the potential changes to the subsurface brought about by HF. Our review of the literature indicates that HF affects a very limited portion of the entire thickness of the overlying bedrock and therefore, is unable to create direct hydraulic communication between black shales and shallow aquifers via induced fractures. As a result, upward migration of HF fluid and brine is controlled by preexisting hydraulic gradients and bedrock permeability. We show that in cases where there is an upward gradient, permeability is low, upward flow rates are low, and mean travel times are long (often >106 years). Consequently, the recently proposed rapid upward migration of brine and HF fluid, predicted to occur as a result of increased HF activity, does not appear to be physically plausible. Unrealistically high estimates of upward flow are the result of invalid assumptions about HF and the hydrogeology of sedimentary basins.
Recent increases in the use of hydraulic fracturing (HF) to aid extraction of oil and gas from black shales have raised concerns regarding potential environmental effects associated with predictions of upward migration of HF fluid and brine. Some recent studies have suggested that such upward migration can be large and that timescales for migration can be as short as a few years. In this article, we discuss the physical constraints on upward fluid migration from black shales (e.g., the Marcellus, Bakken, and Eagle Ford) to shallow aquifers, taking into account the potential changes to the subsurface brought about by HF. Our review of the literature indicates that HF affects a very limited portion of the entire thickness of the overlying bedrock and therefore, is unable to create direct hydraulic communication between black shales and shallow aquifers via induced fractures. As a result, upward migration of HF fluid and brine is controlled by preexisting hydraulic gradients and bedrock permeability. We show that in cases where there is an upward gradient, permeability is low, upward flow rates are low, and mean travel times are long (often >106 years). Consequently, the recently proposed rapid upward migration of brine and HF fluid, predicted to occur as a result of increased HF activity, does not appear to be physically plausible. Unrealistically high estimates of upward flow are the result of invalid assumptions about HF and the hydrogeology of sedimentary basins.
A geochemical context for stray gas investigations in the northern Appalachian Basin: Implications of analyses of natural gases from Neogene-through Devonian-age strata
Baldassare et al., February 2014
A geochemical context for stray gas investigations in the northern Appalachian Basin: Implications of analyses of natural gases from Neogene-through Devonian-age strata
Fred J. Baldassare, Mark A. McCaffrey, John A. Harper (2014). AAPG Bulletin, 341-372. 10.1306/06111312178
Abstract:
As the pace of drilling activity in the Marcellus Formation in the northern Appalachian Basin has increased, so has the number of alleged incidents of stray natural gas migration to shallow aquifer systems. For this study, more than 2300 gas and water samples were analyzed for molecular composition and stable isotope compositions of methane and ethane. The samples are from Neogene- to Middle Devonian-age strata in a five-county study area in northeastern Pennsylvania. Samples were collected from the vertical and lateral sections of 234 gas wells during mud gas logging (MGL) programs and 67 private groundwater-supply wells during baseline groundwater-quality testing programs. Evaluation of this geochemical database reveals that microbial, mixed microbial and thermogenic, and thermogenic gases of different thermal maturities occur in some shallow aquifer systems and throughout the stratigraphy above the Marcellus Formation. The gas occurrences predate Marcellus Formation drilling activity. Isotope data reveal that thermogenic gases are predominant in the regional Neogene and Upper Devonian rocks that comprise the potable aquifer system in the upper 305 m (1000 ft) (average delta13C1 = minus43.53permil; average delta13C2 = minus40.95permil; average deltaDC1 = minus232.50permil) and typically are distinct from gases in the Middle Devonian Marcellus Formation (average delta13C1 = minus32.37permil; average delta13C2 = minus38.48permil; average deltaDC1 = minus162.34permil ). Additionally, isotope geochemistry at the site-specific level reveals a complex thermal and migration history with gas mixtures and partial isotope reversals (delta13C1 gt delta13C2) in the units overlying the Marcellus Formation. Identifying a source for stray natural gas requires the synthesis of multiple data types at the site-specific level. Molecular and isotope geochemistry provide evidence of gas origin and secondary processes that may have affected the gases during migration. Such data provide focus for investigations where the potential sources for stray gas include multiple, naturally occurring, and anthropogenic gases.
As the pace of drilling activity in the Marcellus Formation in the northern Appalachian Basin has increased, so has the number of alleged incidents of stray natural gas migration to shallow aquifer systems. For this study, more than 2300 gas and water samples were analyzed for molecular composition and stable isotope compositions of methane and ethane. The samples are from Neogene- to Middle Devonian-age strata in a five-county study area in northeastern Pennsylvania. Samples were collected from the vertical and lateral sections of 234 gas wells during mud gas logging (MGL) programs and 67 private groundwater-supply wells during baseline groundwater-quality testing programs. Evaluation of this geochemical database reveals that microbial, mixed microbial and thermogenic, and thermogenic gases of different thermal maturities occur in some shallow aquifer systems and throughout the stratigraphy above the Marcellus Formation. The gas occurrences predate Marcellus Formation drilling activity. Isotope data reveal that thermogenic gases are predominant in the regional Neogene and Upper Devonian rocks that comprise the potable aquifer system in the upper 305 m (1000 ft) (average delta13C1 = minus43.53permil; average delta13C2 = minus40.95permil; average deltaDC1 = minus232.50permil) and typically are distinct from gases in the Middle Devonian Marcellus Formation (average delta13C1 = minus32.37permil; average delta13C2 = minus38.48permil; average deltaDC1 = minus162.34permil ). Additionally, isotope geochemistry at the site-specific level reveals a complex thermal and migration history with gas mixtures and partial isotope reversals (delta13C1 gt delta13C2) in the units overlying the Marcellus Formation. Identifying a source for stray natural gas requires the synthesis of multiple data types at the site-specific level. Molecular and isotope geochemistry provide evidence of gas origin and secondary processes that may have affected the gases during migration. Such data provide focus for investigations where the potential sources for stray gas include multiple, naturally occurring, and anthropogenic gases.
Discharges of produced waters from oil and gas extraction via wastewater treatment plants are sources of disinfection by-products to receiving streams
Hladik et al., January 2014
Discharges of produced waters from oil and gas extraction via wastewater treatment plants are sources of disinfection by-products to receiving streams
Michelle L. Hladik, Michael J. Focazio, Mark Engle (2014). Science of The Total Environment, 1085-1093. 10.1016/j.scitotenv.2013.08.008
Abstract:
Fluids co-produced with oil and gas production (produced waters) are often brines that contain elevated concentrations of bromide. Bromide is an important precursor of several toxic disinfection by-products (DBPs) and the treatment of produced water may lead to more brominated DBPs. To determine if wastewater treatment plants that accept produced waters discharge greater amounts of brominated DBPs, water samples were collected in Pennsylvania from four sites along a large river including an upstream site, a site below a publicly owned wastewater treatment plant (POTW) outfall (does not accept produced water), a site below an oil and gas commercial wastewater treatment plant (CWT) outfall, and downstream of the POTW and CWT. Of 29 DBPs analyzed, the site at the POTW outfall had the highest number detected (six) ranging in concentration from 0.01 to 0.09 μg L− 1 with a similar mixture of DBPs that have been detected at POTW outfalls elsewhere in the United States. The DBP profile at the CWT outfall was much different, although only two DBPs, dibromochloronitromethane (DBCNM) and chloroform, were detected, DBCNM was found at relatively high concentrations (up to 8.5 μg L− 1). The water at the CWT outfall also had a mixture of inorganic and organic precursors including elevated concentrations of bromide (75 mg L− 1) and other organic DBP precursors (phenol at 15 μg L− 1). To corroborate these DBP results, samples were collected in Pennsylvania from additional POTW and CWT outfalls that accept produced waters. The additional CWT also had high concentrations of DBCNM (3.1 μg L− 1) while the POTWs that accept produced waters had elevated numbers (up to 15) and concentrations of DBPs, especially brominated and iodinated THMs (up to 12 μg L− 1 total THM concentration). Therefore, produced water brines that have been disinfected are potential sources of DBPs along with DBP precursors to streams wherever these wastewaters are discharged.
Fluids co-produced with oil and gas production (produced waters) are often brines that contain elevated concentrations of bromide. Bromide is an important precursor of several toxic disinfection by-products (DBPs) and the treatment of produced water may lead to more brominated DBPs. To determine if wastewater treatment plants that accept produced waters discharge greater amounts of brominated DBPs, water samples were collected in Pennsylvania from four sites along a large river including an upstream site, a site below a publicly owned wastewater treatment plant (POTW) outfall (does not accept produced water), a site below an oil and gas commercial wastewater treatment plant (CWT) outfall, and downstream of the POTW and CWT. Of 29 DBPs analyzed, the site at the POTW outfall had the highest number detected (six) ranging in concentration from 0.01 to 0.09 μg L− 1 with a similar mixture of DBPs that have been detected at POTW outfalls elsewhere in the United States. The DBP profile at the CWT outfall was much different, although only two DBPs, dibromochloronitromethane (DBCNM) and chloroform, were detected, DBCNM was found at relatively high concentrations (up to 8.5 μg L− 1). The water at the CWT outfall also had a mixture of inorganic and organic precursors including elevated concentrations of bromide (75 mg L− 1) and other organic DBP precursors (phenol at 15 μg L− 1). To corroborate these DBP results, samples were collected in Pennsylvania from additional POTW and CWT outfalls that accept produced waters. The additional CWT also had high concentrations of DBCNM (3.1 μg L− 1) while the POTWs that accept produced waters had elevated numbers (up to 15) and concentrations of DBPs, especially brominated and iodinated THMs (up to 12 μg L− 1 total THM concentration). Therefore, produced water brines that have been disinfected are potential sources of DBPs along with DBP precursors to streams wherever these wastewaters are discharged.
Assessing changes in gas migration pathways at a hydraulic fracturing site: Example from Greene County, Pennsylvania, USA
Sharma et al., September 2024
Assessing changes in gas migration pathways at a hydraulic fracturing site: Example from Greene County, Pennsylvania, USA
Shikha Sharma, Lindsey Bowman, Karl Schroeder, Richard Hammack (2024). Applied Geochemistry, . 10.1016/j.apgeochem.2014.07.018
Abstract:
Natural gas produced from a zone of thin Upper Devonian/Lower Mississippian sands approximately 1200 m above the hydraulically fractured Middle Devonian Marcellus Shale interval was monitored for evidence of gas migration. Gas samples were collected from seven vertical Upper Devonian/Lower Mississippian gas wells and two vertical Marcellus Shale gas wells 2 months prior to-, during-, and 14 months after the hydraulic fracturing of six horizontal Marcellus Shale gas wells at the study site. The isotopic and molecular compositions of gas from the two producing zones were distinct and remained so during the entire monitoring period. Over the time of monitoring, the molecular/isotopic signatures of gas from the Upper Devonian/Lower Mississippian field did not show any evidence of contamination from deeper Marcellus Shale gas that might have migrated upward from the hydraulically fractured interval. Our results indicate no hydrologic connectivity between the fractured interval and formations 1200 m above, which means that contamination of even shallower drinking water aquifers (∼2200 m above fractured interval) is unlikely at this study site. While localized consideration for geology and site development practices are extremely important, the monitoring methods used in this study are applicable when trying to understand and quantify natural gas mixing and migration trends.
Natural gas produced from a zone of thin Upper Devonian/Lower Mississippian sands approximately 1200 m above the hydraulically fractured Middle Devonian Marcellus Shale interval was monitored for evidence of gas migration. Gas samples were collected from seven vertical Upper Devonian/Lower Mississippian gas wells and two vertical Marcellus Shale gas wells 2 months prior to-, during-, and 14 months after the hydraulic fracturing of six horizontal Marcellus Shale gas wells at the study site. The isotopic and molecular compositions of gas from the two producing zones were distinct and remained so during the entire monitoring period. Over the time of monitoring, the molecular/isotopic signatures of gas from the Upper Devonian/Lower Mississippian field did not show any evidence of contamination from deeper Marcellus Shale gas that might have migrated upward from the hydraulically fractured interval. Our results indicate no hydrologic connectivity between the fractured interval and formations 1200 m above, which means that contamination of even shallower drinking water aquifers (∼2200 m above fractured interval) is unlikely at this study site. While localized consideration for geology and site development practices are extremely important, the monitoring methods used in this study are applicable when trying to understand and quantify natural gas mixing and migration trends.
Groundwater Ages and Mixing in the Piceance Basin Natural Gas Province, Colorado
McMahon et al., December 2013
Groundwater Ages and Mixing in the Piceance Basin Natural Gas Province, Colorado
Peter B. McMahon, Judith C. Thomas, Andrew G. Hunt (2013). Environmental Science & Technology, 13250-13257. 10.1021/es402473c
Abstract:
Reliably identifying the effects of energy development on groundwater quality can be difficult because baseline assessments of water quality completed before the onset of energy development are rare and because interactions between hydrocarbon reservoirs and aquifers can be complex, involving both natural and human processes. Groundwater age and mixing data can strengthen interpretations of monitoring data from those areas by providing better understanding of the groundwater flow systems. Chemical, isotopic, and age tracers were used to characterize groundwater ages and mixing with deeper saline water in three areas of the Piceance Basin natural gas province. The data revealed a complex array of groundwater ages (<10 to >50,000 years) and mixing patterns in the basin that helped explain concentrations and sources of methane in groundwater. Age and mixing data also can strengthen the design of monitoring programs by providing information on time scales at which water quality changes in aquifers might be expected to occur. This information could be used to establish maximum allowable distances of monitoring wells from energy development activity and the appropriate duration of monitoring.
Reliably identifying the effects of energy development on groundwater quality can be difficult because baseline assessments of water quality completed before the onset of energy development are rare and because interactions between hydrocarbon reservoirs and aquifers can be complex, involving both natural and human processes. Groundwater age and mixing data can strengthen interpretations of monitoring data from those areas by providing better understanding of the groundwater flow systems. Chemical, isotopic, and age tracers were used to characterize groundwater ages and mixing with deeper saline water in three areas of the Piceance Basin natural gas province. The data revealed a complex array of groundwater ages (<10 to >50,000 years) and mixing patterns in the basin that helped explain concentrations and sources of methane in groundwater. Age and mixing data also can strengthen the design of monitoring programs by providing information on time scales at which water quality changes in aquifers might be expected to occur. This information could be used to establish maximum allowable distances of monitoring wells from energy development activity and the appropriate duration of monitoring.
Hydraulic fracturing in faulted sedimentary basins: Numerical simulation of potential contamination of shallow aquifers over long time scales
Gassiat et al., December 2013
Hydraulic fracturing in faulted sedimentary basins: Numerical simulation of potential contamination of shallow aquifers over long time scales
Claire Gassiat, Tom Gleeson, René Lefebvre, Jeffrey McKenzie (2013). Water Resources Research, 8310-8327. 10.1002/2013WR014287
Abstract:
Hydraulic fracturing, used to economically produce natural gas from shale formations, has raised environmental concerns. The objective of this study is to assess one of the largely unexamined issues, which is the potential for slow contamination of shallow groundwater due to hydraulic fracturing at depth via fluid migration along conductive faults. We compiled publically available data of shale gas basins and hydraulic fracturing operations to develop a two-dimensional, single-phase, multispecies, density-dependent, finite-element numerical groundwater flow and mass transport model. The model simulates hydraulic fracturing in the vicinity of a permeable fault zone in a generic, low-recharge, regional sedimentary basin in which shallow, active groundwater flow occurs above nearly stagnant brine. A sensitivity analysis of contaminant migration along the fault considered basin, fault and hydraulic fracturing parameters. Results show that specific conditions are needed for the slow contamination of a shallow aquifer: a high permeability fault, high overpressure in the shale unit, and hydrofracturing in the upper portion of the shale near the fault. Under such conditions, contaminants from the shale unit reach the shallow aquifer in less than 1000 years following hydraulic fracturing, at concentrations of solutes up to 90% of their initial concentration in the shale, indicating that the impact on groundwater quality could be significant. Important implications of this result are that hydraulic fracturing should not be carried out near potentially conductive faults, and that impacts should be monitored for long timespans. Further work is needed to assess the impact of multiphase flow on contaminant transport along natural preferential pathways.
Hydraulic fracturing, used to economically produce natural gas from shale formations, has raised environmental concerns. The objective of this study is to assess one of the largely unexamined issues, which is the potential for slow contamination of shallow groundwater due to hydraulic fracturing at depth via fluid migration along conductive faults. We compiled publically available data of shale gas basins and hydraulic fracturing operations to develop a two-dimensional, single-phase, multispecies, density-dependent, finite-element numerical groundwater flow and mass transport model. The model simulates hydraulic fracturing in the vicinity of a permeable fault zone in a generic, low-recharge, regional sedimentary basin in which shallow, active groundwater flow occurs above nearly stagnant brine. A sensitivity analysis of contaminant migration along the fault considered basin, fault and hydraulic fracturing parameters. Results show that specific conditions are needed for the slow contamination of a shallow aquifer: a high permeability fault, high overpressure in the shale unit, and hydrofracturing in the upper portion of the shale near the fault. Under such conditions, contaminants from the shale unit reach the shallow aquifer in less than 1000 years following hydraulic fracturing, at concentrations of solutes up to 90% of their initial concentration in the shale, indicating that the impact on groundwater quality could be significant. Important implications of this result are that hydraulic fracturing should not be carried out near potentially conductive faults, and that impacts should be monitored for long timespans. Further work is needed to assess the impact of multiphase flow on contaminant transport along natural preferential pathways.
Hydraulic fracturing in unconventional gas reservoirs: risks in the geological system part 1
Lange et al., December 2013
Hydraulic fracturing in unconventional gas reservoirs: risks in the geological system part 1
Torsten Lange, Martin Sauter, Michael Heitfeld, Kurt Schetelig, Karolin Brosig, Wiebke Jahnke, Alexander Kissinger, Rainer Helmig, Anozie Ebigbo, Holger Class (2013). Environmental Earth Sciences, 3839-3853. 10.1007/s12665-013-2803-3
Abstract:
Hydraulic fracturing of unconventional gas reservoirs rapidly developed especially in the USA to an industrial scale during the last decade. Potential adverse effects such as the deterioration of the quality of exploitable groundwater resources, areal footprints, or even the climate impact were not assessed. Because hydraulic fracturing has already been practised for a long time also in conventional reservoirs, the expansion into the unconventional domain was considered to be just a minor but not a technological step, with potential environmental risks. Thus, safety and environmental protection regulations were not critically developed or refined. Consequently, virtually no baseline conditions were documented before on-site applications as proof of evidence for the net effect of environmental impacts. Not only growing concerns in the general public, but also in the administrations in Germany promoted the commissioning of several expert opinions, evaluating safety, potential risks, and footprints of the technology in focus. The first two publications of the workgroup “Risks in the Geological System” of the independent “Information and Dialogue process on hydraulic fracturing” (commissioned by ExxonMobil Production Deutschland GmbH) comprises the strategy and approaches to identify and assess the potential risks of groundwater contamination of the exploitable groundwater system in the context of hydraulic fracturing operations in the Münsterland cretaceous basin and the Lower Saxony Basin, Germany. While being specific with respect to local geology and the estimation of effective hydraulic parameters, generalized concepts for the contamination risk assessment were developed. The work focuses on barrier effectiveness of different units of the overburden with respect to the migration of fracking fluids and methane, and considers fault zones as potential fluid pathway structures.
Hydraulic fracturing of unconventional gas reservoirs rapidly developed especially in the USA to an industrial scale during the last decade. Potential adverse effects such as the deterioration of the quality of exploitable groundwater resources, areal footprints, or even the climate impact were not assessed. Because hydraulic fracturing has already been practised for a long time also in conventional reservoirs, the expansion into the unconventional domain was considered to be just a minor but not a technological step, with potential environmental risks. Thus, safety and environmental protection regulations were not critically developed or refined. Consequently, virtually no baseline conditions were documented before on-site applications as proof of evidence for the net effect of environmental impacts. Not only growing concerns in the general public, but also in the administrations in Germany promoted the commissioning of several expert opinions, evaluating safety, potential risks, and footprints of the technology in focus. The first two publications of the workgroup “Risks in the Geological System” of the independent “Information and Dialogue process on hydraulic fracturing” (commissioned by ExxonMobil Production Deutschland GmbH) comprises the strategy and approaches to identify and assess the potential risks of groundwater contamination of the exploitable groundwater system in the context of hydraulic fracturing operations in the Münsterland cretaceous basin and the Lower Saxony Basin, Germany. While being specific with respect to local geology and the estimation of effective hydraulic parameters, generalized concepts for the contamination risk assessment were developed. The work focuses on barrier effectiveness of different units of the overburden with respect to the migration of fracking fluids and methane, and considers fault zones as potential fluid pathway structures.
Hydraulic fracturing in unconventional gas reservoirs: risks in the geological system, part 2
Kissinger et al., December 2013
Hydraulic fracturing in unconventional gas reservoirs: risks in the geological system, part 2
Alexander Kissinger, Rainer Helmig, Anozie Ebigbo, Holger Class, Torsten Lange, Martin Sauter, Michael Heitfeld, Johannes Klünker, Wiebke Jahnke (2013). Environmental Earth Sciences, 3855-3873. 10.1007/s12665-013-2578-6
Abstract:
Hydraulic fracturing is a method used for the production of unconventional gas resources. Huge amounts of so-called fracturing fluid (10,000–20,000 m3) are injected into a gas reservoir to create fractures in solid rock formations, upon which mobilised methane fills the pore space and the fracturing fluid is withdrawn. Hydraulic fracturing may pose a threat to groundwater resources if fracturing fluid or brine can migrate through fault zones into shallow aquifers. Diffuse methane emissions from the gas reservoir may not only contaminate shallow groundwater aquifers, but also escape into the atmosphere where methane acts as a greenhouse gas. The working group “Risks in the Geological System” as part of ExxonMobil’s hydrofracking dialogue and information dissemination processes was tasked with the assessment of possible hazards posed by migrating fluids as a result of hydraulic fracturing activities. In this work, several flow paths for fracturing fluid, brine and methane are identified and scenarios are set up to qualitatively estimate under what circumstances these fluids would leak into shallower layers. The parametrisation for potential hydraulic fracturing sites in North Rhine-Westphalia and Lower Saxony (both in Germany) is derived from literature using upper and lower bounds of hydraulic parameters. The results show that a significant fluid migration is only possible if a combination of several conservative assumptions is met by a scenario.
Hydraulic fracturing is a method used for the production of unconventional gas resources. Huge amounts of so-called fracturing fluid (10,000–20,000 m3) are injected into a gas reservoir to create fractures in solid rock formations, upon which mobilised methane fills the pore space and the fracturing fluid is withdrawn. Hydraulic fracturing may pose a threat to groundwater resources if fracturing fluid or brine can migrate through fault zones into shallow aquifers. Diffuse methane emissions from the gas reservoir may not only contaminate shallow groundwater aquifers, but also escape into the atmosphere where methane acts as a greenhouse gas. The working group “Risks in the Geological System” as part of ExxonMobil’s hydrofracking dialogue and information dissemination processes was tasked with the assessment of possible hazards posed by migrating fluids as a result of hydraulic fracturing activities. In this work, several flow paths for fracturing fluid, brine and methane are identified and scenarios are set up to qualitatively estimate under what circumstances these fluids would leak into shallower layers. The parametrisation for potential hydraulic fracturing sites in North Rhine-Westphalia and Lower Saxony (both in Germany) is derived from literature using upper and lower bounds of hydraulic parameters. The results show that a significant fluid migration is only possible if a combination of several conservative assumptions is met by a scenario.
Hydraulic fracturing: a toxicological threat for groundwater and drinking-water?
Gordalla et al., December 2013
Hydraulic fracturing: a toxicological threat for groundwater and drinking-water?
Birgit C. Gordalla, Ulrich Ewers, Fritz H. Frimmel (2013). Environmental Earth Sciences, 3875-3893. 10.1007/s12665-013-2672-9
Abstract:
This paper deals with the possible impact of hydraulic fracturing (fracking), employed in the exploitation of unconventional shale gas and tight gas reservoirs, on groundwater, which is the most important source of drinking-water in Germany and many other European countries. This assessment, which is part of an interdisciplinary study by a panel of neutral experts on the risks and environmental impact of hydraulic fracturing, is based mainly on data obtained from three ExxonMobil drilling sites in northern Germany. First, the basic technical aspects of fracking and its relevant water fluxes are explained. The type, purpose and fate of the constituents of the fracking fluids are discussed. The chemicals used in the fracking fluids are assessed with regard to their hazardous properties according to the Regulation (EC) No. 1272/2008 of the European Parliament and of the Council on the classification, labelling and packaging of substances and mixtures (CLP regulation) and the German “Water Hazard Classes”. Contamination of groundwater by ingredients of fracking fluids may occur from under ground or may result from above-ground accidents associated with the transport, storage and handling of hazardous substances used as additives in fracking fluids. The degree of groundwater contamination cannot be predicted in a general way. Therefore, different dilutions of the fracking fluid in groundwater are considered. It is shown that the concentrations of most ingredients resulting from a 1:10,000 up to 1:100,000 dilution of the fracking fluid in groundwater are below health-based reference values such as the limit values of the European Drinking Water Directive, the WHO Guideline Values for Drinking-water Quality, and other health-based guide values for drinking-water. Regarding the salinity of fracking fluids, a dilution of 1:1,000 is sufficient to reach concentrations which are acceptable for drinking-water. From the human-toxicological point of view, the constituents of flowback water are more problematic with respect to drinking-water produced from groundwater than those of the fracking fluids. The few reliable data which have become available, as well as hydrogeological considerations, point in the direction of considerable salt concentrations and toxic constituents, e.g., Hg, As, Pb, Zn, Cd, BTX, PAHs, or even radioactive elements. The identification and assessment of reaction products and metabolites, which are produced as a result of the fracking operation and the metabolic activity of microorganisms, are important topics for further research. The recommendations include the need for a better understanding of the environmental impact of fracking operations, especially with regard to the development of sustainable rules for planning, permission, performance and management of fracking, and for the monitoring of groundwater quality around fracked drilling sites.
This paper deals with the possible impact of hydraulic fracturing (fracking), employed in the exploitation of unconventional shale gas and tight gas reservoirs, on groundwater, which is the most important source of drinking-water in Germany and many other European countries. This assessment, which is part of an interdisciplinary study by a panel of neutral experts on the risks and environmental impact of hydraulic fracturing, is based mainly on data obtained from three ExxonMobil drilling sites in northern Germany. First, the basic technical aspects of fracking and its relevant water fluxes are explained. The type, purpose and fate of the constituents of the fracking fluids are discussed. The chemicals used in the fracking fluids are assessed with regard to their hazardous properties according to the Regulation (EC) No. 1272/2008 of the European Parliament and of the Council on the classification, labelling and packaging of substances and mixtures (CLP regulation) and the German “Water Hazard Classes”. Contamination of groundwater by ingredients of fracking fluids may occur from under ground or may result from above-ground accidents associated with the transport, storage and handling of hazardous substances used as additives in fracking fluids. The degree of groundwater contamination cannot be predicted in a general way. Therefore, different dilutions of the fracking fluid in groundwater are considered. It is shown that the concentrations of most ingredients resulting from a 1:10,000 up to 1:100,000 dilution of the fracking fluid in groundwater are below health-based reference values such as the limit values of the European Drinking Water Directive, the WHO Guideline Values for Drinking-water Quality, and other health-based guide values for drinking-water. Regarding the salinity of fracking fluids, a dilution of 1:1,000 is sufficient to reach concentrations which are acceptable for drinking-water. From the human-toxicological point of view, the constituents of flowback water are more problematic with respect to drinking-water produced from groundwater than those of the fracking fluids. The few reliable data which have become available, as well as hydrogeological considerations, point in the direction of considerable salt concentrations and toxic constituents, e.g., Hg, As, Pb, Zn, Cd, BTX, PAHs, or even radioactive elements. The identification and assessment of reaction products and metabolites, which are produced as a result of the fracking operation and the metabolic activity of microorganisms, are important topics for further research. The recommendations include the need for a better understanding of the environmental impact of fracking operations, especially with regard to the development of sustainable rules for planning, permission, performance and management of fracking, and for the monitoring of groundwater quality around fracked drilling sites.
Hydraulic fracturing - a hazard for drinking water?
Ewers et al., November 2013
Hydraulic fracturing - a hazard for drinking water?
U Ewers, B Gordalla, F Frimmel (2013). Gesundheitswesen (Bundesverband der Ärzte des Öffentlichen Gesundheitsdienstes (Germany)), 735-741. 10.1055/s-0033-1355369
Abstract:
Hydraulic fracturing (fracking) is a technique used to release and promote the extraction of natural gas (including shale gas, tight gas, and coal bed methane) from deep natural gas deposits. Among the German public there is great concern with regard to the potential environmental impacts of fracking including the contamination of ground water, the most important source of drinking water in Germany. In the present article the risks of ground water contamination through fracking are discussed. Due to the present safety requirements and the obligatory geological and hydrogeological scrutiny of the underground, which has to be performed prior to fracking, the risk of ground water contamination by fracking can be regarded as very low. The toxicity of chemical additives of fracking fluids is discussed. It is recommended that in the future environmental impact assessment and approval of fracs should be performed by the mining authorities in close cooperation with the water authorities. Furthermore, it is recommended that hydraulic fracturing in the future should be accompanied by obligatory ground water monitoring.
Hydraulic fracturing (fracking) is a technique used to release and promote the extraction of natural gas (including shale gas, tight gas, and coal bed methane) from deep natural gas deposits. Among the German public there is great concern with regard to the potential environmental impacts of fracking including the contamination of ground water, the most important source of drinking water in Germany. In the present article the risks of ground water contamination through fracking are discussed. Due to the present safety requirements and the obligatory geological and hydrogeological scrutiny of the underground, which has to be performed prior to fracking, the risk of ground water contamination by fracking can be regarded as very low. The toxicity of chemical additives of fracking fluids is discussed. It is recommended that in the future environmental impact assessment and approval of fracs should be performed by the mining authorities in close cooperation with the water authorities. Furthermore, it is recommended that hydraulic fracturing in the future should be accompanied by obligatory ground water monitoring.
Impacts of Shale Gas Wastewater Disposal on Water Quality in Western Pennsylvania
Warner et al., October 2013
Impacts of Shale Gas Wastewater Disposal on Water Quality in Western Pennsylvania
Nathaniel R. Warner, Cidney A. Christie, Robert B. Jackson, Avner Vengosh (2013). Environmental Science & Technology, . 10.1021/es402165b
Abstract:
The safe disposal of liquid wastes associated with oil and gas production in the United States is a major challenge given their large volumes and typically high levels of contaminants. In Pennsylvania, oil and gas wastewater is sometimes treated at brine treatment facilities and discharged to local streams. This study examined the water quality and isotopic compositions of discharged effluents, surface waters, and stream sediments associated with a treatment facility site in western Pennsylvania. The elevated levels of chloride and bromide, combined with the strontium, radium, oxygen, and hydrogen isotopic compositions of the effluents reflect the composition of Marcellus Shale produced waters. The discharge of the effluent from the treatment facility increased downstream concentrations of chloride and bromide above background levels. Barium and radium were substantially (>90%) reduced in the treated effluents compared to concentrations in Marcellus Shale produced waters. Nonetheless, 226Ra levels in stream sediments (544?8759 Bq/kg) at the point of discharge were ?200 times greater than upstream and background sediments (22?44 Bq/kg) and above radioactive waste disposal threshold regulations, posing potential environmental risks of radium bioaccumulation in localized areas of shale gas wastewater disposal.
The safe disposal of liquid wastes associated with oil and gas production in the United States is a major challenge given their large volumes and typically high levels of contaminants. In Pennsylvania, oil and gas wastewater is sometimes treated at brine treatment facilities and discharged to local streams. This study examined the water quality and isotopic compositions of discharged effluents, surface waters, and stream sediments associated with a treatment facility site in western Pennsylvania. The elevated levels of chloride and bromide, combined with the strontium, radium, oxygen, and hydrogen isotopic compositions of the effluents reflect the composition of Marcellus Shale produced waters. The discharge of the effluent from the treatment facility increased downstream concentrations of chloride and bromide above background levels. Barium and radium were substantially (>90%) reduced in the treated effluents compared to concentrations in Marcellus Shale produced waters. Nonetheless, 226Ra levels in stream sediments (544?8759 Bq/kg) at the point of discharge were ?200 times greater than upstream and background sediments (22?44 Bq/kg) and above radioactive waste disposal threshold regulations, posing potential environmental risks of radium bioaccumulation in localized areas of shale gas wastewater disposal.
An Evaluation of Water Quality in Private Drinking Water Wells Near Natural Gas Extraction Sites in the Barnett Shale Formation
Fontenot et al., September 2013
An Evaluation of Water Quality in Private Drinking Water Wells Near Natural Gas Extraction Sites in the Barnett Shale Formation
Brian E. Fontenot, Laura R. Hunt, Zacariah L. Hildenbrand, Doug D. Carlton Jr., Hyppolite Oka, Jayme L. Walton, Dan Hopkins, Alexandra Osorio, Bryan Bjorndal, Qinhong H. Hu, Kevin A. Schug (2013). Environmental Science & Technology, 10032-10040. 10.1021/es4011724
Abstract:
Natural gas has become a leading source of alternative energy with the advent of techniques to economically extract gas reserves from deep shale formations. Here, we present an assessment of private well water quality in aquifers overlying the Barnett Shale formation of North Texas. We evaluated samples from 100 private drinking water wells using analytical chemistry techniques. Analyses revealed that arsenic, selenium, strontium and total dissolved solids (TDS) exceeded the Environmental Protection Agency?s Drinking Water Maximum Contaminant Limit (MCL) in some samples from private water wells located within 3 km of active natural gas wells. Lower levels of arsenic, selenium, strontium, and barium were detected at reference sites outside the Barnett Shale region as well as sites within the Barnett Shale region located more than 3 km from active natural gas wells. Methanol and ethanol were also detected in 29% of samples. Samples exceeding MCL levels were randomly distributed within areas of active natural gas extraction, and the spatial patterns in our data suggest that elevated constituent levels could be due to a variety of factors including mobilization of natural constituents, hydrogeochemical changes from lowering of the water table, or industrial accidents such as faulty gas well casings.
Natural gas has become a leading source of alternative energy with the advent of techniques to economically extract gas reserves from deep shale formations. Here, we present an assessment of private well water quality in aquifers overlying the Barnett Shale formation of North Texas. We evaluated samples from 100 private drinking water wells using analytical chemistry techniques. Analyses revealed that arsenic, selenium, strontium and total dissolved solids (TDS) exceeded the Environmental Protection Agency?s Drinking Water Maximum Contaminant Limit (MCL) in some samples from private water wells located within 3 km of active natural gas wells. Lower levels of arsenic, selenium, strontium, and barium were detected at reference sites outside the Barnett Shale region as well as sites within the Barnett Shale region located more than 3 km from active natural gas wells. Methanol and ethanol were also detected in 29% of samples. Samples exceeding MCL levels were randomly distributed within areas of active natural gas extraction, and the spatial patterns in our data suggest that elevated constituent levels could be due to a variety of factors including mobilization of natural constituents, hydrogeochemical changes from lowering of the water table, or industrial accidents such as faulty gas well casings.
A Stream-Based Methane Monitoring Approach for Evaluating Groundwater Impacts Associated with Unconventional Gas Development
Heilweil et al., January 1970
A Stream-Based Methane Monitoring Approach for Evaluating Groundwater Impacts Associated with Unconventional Gas Development
Victor M. Heilweil, Bert J. Stolp, Briant A. Kimball, David D. Susong, Thomas M. Marston, Philip M. Gardner (1970). Groundwater, 511–524. 10.1111/gwat.12079
Abstract:
Gaining streams can provide an integrated signal of relatively large groundwater capture areas. In contrast to the point-specific nature of monitoring wells, gaining streams coalesce multiple flow paths. Impacts on groundwater quality from unconventional gas development may be evaluated at the watershed scale by the sampling of dissolved methane (CH4) along such streams. This paper describes a method for using stream CH4 concentrations, along with measurements of groundwater inflow and gas transfer velocity interpreted by 1-D stream transport modeling, to determine groundwater methane fluxes. While dissolved ionic tracers remain in the stream for long distances, the persistence of methane is not well documented. To test this method and evaluate CH4 persistence in a stream, a combined bromide (Br) and CH4 tracer injection was conducted on Nine-Mile Creek, a gaining stream in a gas development area in central Utah. A 35% gain in streamflow was determined from dilution of the Br tracer. The injected CH4 resulted in a fivefold increase in stream CH4 immediately below the injection site. CH4 and δ13CCH4 sampling showed it was not immediately lost to the atmosphere, but remained in the stream for more than 2000 m. A 1-D stream transport model simulating the decline in CH4 yielded an apparent gas transfer velocity of 4.5 m/d, describing the rate of loss to the atmosphere (possibly including some microbial consumption). The transport model was then calibrated to background stream CH4 in Nine-Mile Creek (prior to CH4 injection) in order to evaluate groundwater CH4 contributions. The total estimated CH4 load discharging to the stream along the study reach was 190 g/d, although using geochemical fingerprinting to determine its source was beyond the scope of the current study. This demonstrates the utility of stream-gas sampling as a reconnaissance tool for evaluating both natural and anthropogenic CH4 leakage from gas reservoirs into groundwater and surface water.
Gaining streams can provide an integrated signal of relatively large groundwater capture areas. In contrast to the point-specific nature of monitoring wells, gaining streams coalesce multiple flow paths. Impacts on groundwater quality from unconventional gas development may be evaluated at the watershed scale by the sampling of dissolved methane (CH4) along such streams. This paper describes a method for using stream CH4 concentrations, along with measurements of groundwater inflow and gas transfer velocity interpreted by 1-D stream transport modeling, to determine groundwater methane fluxes. While dissolved ionic tracers remain in the stream for long distances, the persistence of methane is not well documented. To test this method and evaluate CH4 persistence in a stream, a combined bromide (Br) and CH4 tracer injection was conducted on Nine-Mile Creek, a gaining stream in a gas development area in central Utah. A 35% gain in streamflow was determined from dilution of the Br tracer. The injected CH4 resulted in a fivefold increase in stream CH4 immediately below the injection site. CH4 and δ13CCH4 sampling showed it was not immediately lost to the atmosphere, but remained in the stream for more than 2000 m. A 1-D stream transport model simulating the decline in CH4 yielded an apparent gas transfer velocity of 4.5 m/d, describing the rate of loss to the atmosphere (possibly including some microbial consumption). The transport model was then calibrated to background stream CH4 in Nine-Mile Creek (prior to CH4 injection) in order to evaluate groundwater CH4 contributions. The total estimated CH4 load discharging to the stream along the study reach was 190 g/d, although using geochemical fingerprinting to determine its source was beyond the scope of the current study. This demonstrates the utility of stream-gas sampling as a reconnaissance tool for evaluating both natural and anthropogenic CH4 leakage from gas reservoirs into groundwater and surface water.
Brominated THMs in Drinking Water: A Possible Link to Marcellus Shale and Other Wastewaters
States et al., August 2013
Brominated THMs in Drinking Water: A Possible Link to Marcellus Shale and Other Wastewaters
Stanley States, Georgina Cyprych, Mark Stoner, Faith Wydra, John Kuchta, Jason Monnell, Leonard Casson (2013). Journal - American Water Works Association, E432-E448. 10.5942/jawwa.2013.105.0093
Abstract:
Geochemical and isotopic variations in shallow groundwater in areas of the Fayetteville Shale development, north-central Arkansas
Warner et al., August 2013
Geochemical and isotopic variations in shallow groundwater in areas of the Fayetteville Shale development, north-central Arkansas
Nathaniel R. Warner, Timothy M. Kresse, Phillip D. Hays, Adrian Down, Jonathan D. Karr, Robert B. Jackson, Avner Vengosh (2013). Applied Geochemistry, 207-220. 10.1016/j.apgeochem.2013.04.013
Abstract:
Abstract Exploration of unconventional natural gas reservoirs such as impermeable shale basins through the use of horizontal drilling and hydraulic fracturing has changed the energy landscape in the USA providing a vast new energy source. The accelerated production of natural gas has triggered a debate concerning the safety and possible environmental impacts of these operations. This study investigates one of the critical aspects of the environmental effects; the possible degradation of water quality in shallow aquifers overlying producing shale formations. The geochemistry of domestic groundwater wells was investigated in aquifers overlying the Fayetteville Shale in north-central Arkansas, where approximately 4000 wells have been drilled since 2004 to extract unconventional natural gas. Monitoring was performed on 127 drinking water wells and the geochemistry of major ions, trace metals, CH4 gas content and its C isotopes (δ13CCH4), and select isotope tracers (δ11B, 87Sr/86Sr, δ2H, δ18O, δ13CDIC) compared to the composition of flowback-water samples directly from Fayetteville Shale gas wells. Dissolved CH4 was detected in 63% of the drinking-water wells (32 of 51 samples), but only six wells exceeded concentrations of 0.5 mg CH4/L. The δ13CCH4 of dissolved CH4 ranged from −42.3‰ to −74.7‰, with the most negative values characteristic of a biogenic source also associated with the highest observed CH4 concentrations, with a possible minor contribution of trace amounts of thermogenic CH4. The majority of these values are distinct from the reported thermogenic composition of the Fayetteville Shale gas (δ13CCH4 = −35.4‰ to −41.9‰). Based on major element chemistry, four shallow groundwater types were identified: (1) low (<100 mg/L) total dissolved solids (TDS), (2) TDS > 100 mg/L and Ca–HCO3 dominated, (3) TDS > 100 mg/L and Na–HCO3 dominated, and (4) slightly saline groundwater with TDS > 100 mg/L and Cl > 20 mg/L with elevated Br/Cl ratios (>0.001). The Sr (87Sr/86Sr = 0.7097–0.7166), C (δ13CDIC = −21.3‰ to −4.7‰), and B (δ11B = 3.9–32.9‰) isotopes clearly reflect water–rock interactions within the aquifer rocks, while the stable O and H isotopic composition mimics the local meteoric water composition. Overall, there was a geochemical gradient from low-mineralized recharge water to more evolved Ca–HCO3, and higher-mineralized Na–HCO3 composition generated by a combination of carbonate dissolution, silicate weathering, and reverse base-exchange reactions. The chemical and isotopic compositions of the bulk shallow groundwater samples were distinct from the Na–Cl type Fayetteville flowback/produced waters (TDS ∼10,000–20,000 mg/L). Yet, the high Br/Cl variations in a small subset of saline shallow groundwater suggest that they were derived from dilution of saline water similar to the brine in the Fayetteville Shale. Nonetheless, no spatial relationship was found between CH4 and salinity occurrences in shallow drinking water wells with proximity to shale-gas drilling sites. The integration of multiple geochemical and isotopic proxies shows no direct evidence of contamination in shallow drinking-water aquifers associated with natural gas extraction from the Fayetteville Shale.
Abstract Exploration of unconventional natural gas reservoirs such as impermeable shale basins through the use of horizontal drilling and hydraulic fracturing has changed the energy landscape in the USA providing a vast new energy source. The accelerated production of natural gas has triggered a debate concerning the safety and possible environmental impacts of these operations. This study investigates one of the critical aspects of the environmental effects; the possible degradation of water quality in shallow aquifers overlying producing shale formations. The geochemistry of domestic groundwater wells was investigated in aquifers overlying the Fayetteville Shale in north-central Arkansas, where approximately 4000 wells have been drilled since 2004 to extract unconventional natural gas. Monitoring was performed on 127 drinking water wells and the geochemistry of major ions, trace metals, CH4 gas content and its C isotopes (δ13CCH4), and select isotope tracers (δ11B, 87Sr/86Sr, δ2H, δ18O, δ13CDIC) compared to the composition of flowback-water samples directly from Fayetteville Shale gas wells. Dissolved CH4 was detected in 63% of the drinking-water wells (32 of 51 samples), but only six wells exceeded concentrations of 0.5 mg CH4/L. The δ13CCH4 of dissolved CH4 ranged from −42.3‰ to −74.7‰, with the most negative values characteristic of a biogenic source also associated with the highest observed CH4 concentrations, with a possible minor contribution of trace amounts of thermogenic CH4. The majority of these values are distinct from the reported thermogenic composition of the Fayetteville Shale gas (δ13CCH4 = −35.4‰ to −41.9‰). Based on major element chemistry, four shallow groundwater types were identified: (1) low (<100 mg/L) total dissolved solids (TDS), (2) TDS > 100 mg/L and Ca–HCO3 dominated, (3) TDS > 100 mg/L and Na–HCO3 dominated, and (4) slightly saline groundwater with TDS > 100 mg/L and Cl > 20 mg/L with elevated Br/Cl ratios (>0.001). The Sr (87Sr/86Sr = 0.7097–0.7166), C (δ13CDIC = −21.3‰ to −4.7‰), and B (δ11B = 3.9–32.9‰) isotopes clearly reflect water–rock interactions within the aquifer rocks, while the stable O and H isotopic composition mimics the local meteoric water composition. Overall, there was a geochemical gradient from low-mineralized recharge water to more evolved Ca–HCO3, and higher-mineralized Na–HCO3 composition generated by a combination of carbonate dissolution, silicate weathering, and reverse base-exchange reactions. The chemical and isotopic compositions of the bulk shallow groundwater samples were distinct from the Na–Cl type Fayetteville flowback/produced waters (TDS ∼10,000–20,000 mg/L). Yet, the high Br/Cl variations in a small subset of saline shallow groundwater suggest that they were derived from dilution of saline water similar to the brine in the Fayetteville Shale. Nonetheless, no spatial relationship was found between CH4 and salinity occurrences in shallow drinking water wells with proximity to shale-gas drilling sites. The integration of multiple geochemical and isotopic proxies shows no direct evidence of contamination in shallow drinking-water aquifers associated with natural gas extraction from the Fayetteville Shale.
Groundwater protection and unconventional gas extraction: the critical need for field-based hydrogeological research
Jackson et al., January 1970
Groundwater protection and unconventional gas extraction: the critical need for field-based hydrogeological research
R E Jackson, A W Gorody, B Mayer, J W Roy, M C Ryan, D R Van Stempvoort (1970). Ground water, 488-510. http://www.ncbi.nlm.nih.gov/pubmed/23745972
Abstract:
Unconventional natural gas extraction from tight sandstones, shales, and some coal-beds is typically accomplished by horizontal drilling and hydraulic fracturing that is necessary for economic development of these new hydrocarbon resources. Concerns have been raised regarding the potential for contamination of shallow groundwater by stray gases, formation waters, and fracturing chemicals associated with unconventional gas exploration. A lack of sound scientific hydrogeological field observations and a scarcity of published peer-reviewed articles on the effects of both conventional and unconventional oil and gas activities on shallow groundwater make it difficult to address these issues. Here, we discuss several case studies related to both conventional and unconventional oil and gas activities illustrating how under some circumstances stray or fugitive gas from deep gas-rich formations has migrated from the subsurface into shallow aquifers and how it has affected groundwater quality. Examples include impacts of uncemented well annuli in areas of historic drilling operations, effects related to poor cement bonding in both new and old hydrocarbon wells, and ineffective cementing practices. We also summarize studies describing how structural features influence the role of natural and induced fractures as contaminant fluid migration pathways. On the basis of these studies, we identify two areas where field-focused research is urgently needed to fill current science gaps related to unconventional gas extraction: (1) baseline geochemical mapping (with time series sampling from a sufficient network of groundwater monitoring wells) and (2) field testing of potential mechanisms and pathways by which hydrocarbon gases, reservoir fluids, and fracturing chemicals might potentially invade and contaminate useable groundwater.
Unconventional natural gas extraction from tight sandstones, shales, and some coal-beds is typically accomplished by horizontal drilling and hydraulic fracturing that is necessary for economic development of these new hydrocarbon resources. Concerns have been raised regarding the potential for contamination of shallow groundwater by stray gases, formation waters, and fracturing chemicals associated with unconventional gas exploration. A lack of sound scientific hydrogeological field observations and a scarcity of published peer-reviewed articles on the effects of both conventional and unconventional oil and gas activities on shallow groundwater make it difficult to address these issues. Here, we discuss several case studies related to both conventional and unconventional oil and gas activities illustrating how under some circumstances stray or fugitive gas from deep gas-rich formations has migrated from the subsurface into shallow aquifers and how it has affected groundwater quality. Examples include impacts of uncemented well annuli in areas of historic drilling operations, effects related to poor cement bonding in both new and old hydrocarbon wells, and ineffective cementing practices. We also summarize studies describing how structural features influence the role of natural and induced fractures as contaminant fluid migration pathways. On the basis of these studies, we identify two areas where field-focused research is urgently needed to fill current science gaps related to unconventional gas extraction: (1) baseline geochemical mapping (with time series sampling from a sufficient network of groundwater monitoring wells) and (2) field testing of potential mechanisms and pathways by which hydrocarbon gases, reservoir fluids, and fracturing chemicals might potentially invade and contaminate useable groundwater.
Hydraulic fracture height limits and fault interactions in tight oil and gas formations
Flewelling et al., July 2013
Hydraulic fracture height limits and fault interactions in tight oil and gas formations
Samuel A. Flewelling, Matthew P. Tymchak, Norm Warpinski (2013). Geophysical Research Letters, 3602–3606. 10.1002/grl.50707
Abstract:
The widespread use of hydraulic fracturing (HF) has raised concerns about potential upward migration of HF fluid and brine via induced fractures and faults. We developed a relationship that predicts maximum fracture height as a function of HF fluid volume. These predictions generally bound the vertical extent of microseismicity from over 12,000 HF stimulations across North America. All microseismic events were less than 600 m above well perforations, although most were much closer. Areas of shear displacement (including faults) estimated from microseismic data were comparatively small (radii on the order of 10 m or less). These findings suggest that fracture heights are limited by HF fluid volume regardless of whether the fluid interacts with faults. Direct hydraulic communication between tight formations and shallow groundwater via induced fractures and faults is not a realistic expectation based on the limitations on fracture height growth and potential fault slip.
The widespread use of hydraulic fracturing (HF) has raised concerns about potential upward migration of HF fluid and brine via induced fractures and faults. We developed a relationship that predicts maximum fracture height as a function of HF fluid volume. These predictions generally bound the vertical extent of microseismicity from over 12,000 HF stimulations across North America. All microseismic events were less than 600 m above well perforations, although most were much closer. Areas of shear displacement (including faults) estimated from microseismic data were comparatively small (radii on the order of 10 m or less). These findings suggest that fracture heights are limited by HF fluid volume regardless of whether the fluid interacts with faults. Direct hydraulic communication between tight formations and shallow groundwater via induced fractures and faults is not a realistic expectation based on the limitations on fracture height growth and potential fault slip.
Increased stray gas abundance in a subset of drinking water wells near Marcellus shale gas extraction
Jackson et al., July 2013
Increased stray gas abundance in a subset of drinking water wells near Marcellus shale gas extraction
Robert B. Jackson, Avner Vengosh, Thomas H. Darrah, Nathaniel R. Warner, Adrian Down, Robert J. Poreda, Stephen G. Osborn, Kaiguang Zhao, Jonathan D. Karr (2013). Proceedings of the National Academy of Sciences, 11250-11255. 10.1073/pnas.1221635110
Abstract:
Horizontal drilling and hydraulic fracturing are transforming energy production, but their potential environmental effects remain controversial. We analyzed 141 drinking water wells across the Appalachian Plateaus physiographic province of northeastern Pennsylvania, examining natural gas concentrations and isotopic signatures with proximity to shale gas wells. Methane was detected in 82% of drinking water samples, with average concentrations six times higher for homes <1 km from natural gas wells (P = 0.0006). Ethane was 23 times higher in homes <1 km from gas wells (P = 0.0013); propane was detected in 10 water wells, all within approximately 1 km distance (P = 0.01). Of three factors previously proposed to influence gas concentrations in shallow groundwater (distances to gas wells, valley bottoms, and the Appalachian Structural Front, a proxy for tectonic deformation), distance to gas wells was highly significant for methane concentrations (P = 0.007; multiple regression), whereas distances to valley bottoms and the Appalachian Structural Front were not significant (P = 0.27 and P = 0.11, respectively). Distance to gas wells was also the most significant factor for Pearson and Spearman correlation analyses (P < 0.01). For ethane concentrations, distance to gas wells was the only statistically significant factor (P < 0.005). Isotopic signatures (δ13C-CH4, δ13C-C2H6, and δ2H-CH4), hydrocarbon ratios (methane to ethane and propane), and the ratio of the noble gas 4He to CH4 in groundwater were characteristic of a thermally postmature Marcellus-like source in some cases. Overall, our data suggest that some homeowners living <1 km from gas wells have drinking water contaminated with stray gases.
Horizontal drilling and hydraulic fracturing are transforming energy production, but their potential environmental effects remain controversial. We analyzed 141 drinking water wells across the Appalachian Plateaus physiographic province of northeastern Pennsylvania, examining natural gas concentrations and isotopic signatures with proximity to shale gas wells. Methane was detected in 82% of drinking water samples, with average concentrations six times higher for homes <1 km from natural gas wells (P = 0.0006). Ethane was 23 times higher in homes <1 km from gas wells (P = 0.0013); propane was detected in 10 water wells, all within approximately 1 km distance (P = 0.01). Of three factors previously proposed to influence gas concentrations in shallow groundwater (distances to gas wells, valley bottoms, and the Appalachian Structural Front, a proxy for tectonic deformation), distance to gas wells was highly significant for methane concentrations (P = 0.007; multiple regression), whereas distances to valley bottoms and the Appalachian Structural Front were not significant (P = 0.27 and P = 0.11, respectively). Distance to gas wells was also the most significant factor for Pearson and Spearman correlation analyses (P < 0.01). For ethane concentrations, distance to gas wells was the only statistically significant factor (P < 0.005). Isotopic signatures (δ13C-CH4, δ13C-C2H6, and δ2H-CH4), hydrocarbon ratios (methane to ethane and propane), and the ratio of the noble gas 4He to CH4 in groundwater were characteristic of a thermally postmature Marcellus-like source in some cases. Overall, our data suggest that some homeowners living <1 km from gas wells have drinking water contaminated with stray gases.
Effects of Unconventional Gas Development on Groundwater: A Call for Total Dissolved Gas Pressure Field Measurements
J.w. Roy and M.c. Ryan, July 2013
Effects of Unconventional Gas Development on Groundwater: A Call for Total Dissolved Gas Pressure Field Measurements
J.w. Roy and M.c. Ryan (2013). Groundwater, 480-482. 10.1111/gwat.12065
Abstract:
Isotope Approach to Assess Hydrologic Connections During Marcellus Shale Drilling
Sharma et al., June 2013
Isotope Approach to Assess Hydrologic Connections During Marcellus Shale Drilling
Shikha Sharma, Michon L Mulder, Andrea Sack, Karl Schroeder, Richard Hammack (2013). Ground water, . 10.1111/gwat.12083
Abstract:
Water and gas samples were collected from (1) nine shallow groundwater aquifers overlying Marcellus Shale in north-central West Virginia before active shale gas drilling, (2) wells producing gas from Upper Devonian sands and Middle Devonian Marcellus Shale in southwestern Pennsylvania, (3) coal-mine water discharges in southwestern Pennsylvania, and (4) streams in southwestern Pennsylvania and north-central West Virginia. Our preliminary results demonstrate that the oxygen and hydrogen isotope composition of water, carbon isotope composition of dissolved inorganic carbon, and carbon and hydrogen isotope compositions of methane in Upper Devonian sands and Marcellus Shale are very different compared with shallow groundwater aquifers, coal-mine waters, and stream waters of the region. Therefore, spatiotemporal stable isotope monitoring of the different sources of water before, during, and after hydraulic fracturing can be used to identify migrations of fluids and gas from deep formations that are coincident with shale gas drilling.
Water and gas samples were collected from (1) nine shallow groundwater aquifers overlying Marcellus Shale in north-central West Virginia before active shale gas drilling, (2) wells producing gas from Upper Devonian sands and Middle Devonian Marcellus Shale in southwestern Pennsylvania, (3) coal-mine water discharges in southwestern Pennsylvania, and (4) streams in southwestern Pennsylvania and north-central West Virginia. Our preliminary results demonstrate that the oxygen and hydrogen isotope composition of water, carbon isotope composition of dissolved inorganic carbon, and carbon and hydrogen isotope compositions of methane in Upper Devonian sands and Marcellus Shale are very different compared with shallow groundwater aquifers, coal-mine waters, and stream waters of the region. Therefore, spatiotemporal stable isotope monitoring of the different sources of water before, during, and after hydraulic fracturing can be used to identify migrations of fluids and gas from deep formations that are coincident with shale gas drilling.