Repository for Oil and Gas Energy Research (ROGER)

Abstract:
The rapid expansion of unconventional oil and gas development (UD), made possible by horizontal drilling and hydraulic fracturing, has triggered concerns over groundwater contamination and public health risks. To improve our understanding of the risks posed by UD, we develop a physically based, spatially explicit framework for evaluating groundwater well vulnerability to aqueous phase contaminants released from surface spills and leaks at UD well pad locations. The proposed framework utilizes the concept of capture probability and incorporates decision-relevant planning horizons and acceptable risks to support goal-oriented modeling for groundwater protection. We illustrate the approach in northeastern Pennsylvania, where a high intensity of UD activity overlaps with local dependence on domestic groundwater wells. Using two alternative models of the bedrock aquifer and a precautionary paradigm to integrate their results, we found that most domestic wells in the domain had low vulnerability as the extent of their modeled probabilistic capture zones were smaller than distances to the nearest existing UD well pad. We also found that simulated capture probability and vulnerability were most sensitive to the model parameters of matrix hydraulic conductivity, porosity, pumping rate, and the ratio of fracture to matrix conductivity. Our analysis demonstrated the potential inadequacy of current state-mandated setback distances that allow UD within the boundaries of delineated capture zones. The proposed framework, while limited to aqueous phase contamination, emphasizes the need to incorporate information on flow paths and transport timescales into policies aiming to protect groundwater from contamination by UD.

Abstract:
Hydraulic fracturing (HF) is widely used in shale gas development, which may cause some heavy metals release from shale formations. These contaminants could transport from the fractured shale reservoirs to shallow aquifers. Thus, it is necessary to assess the impact of pollution in shallow aquifers. In this paper, a new analysis model, considering geological distributions, discrete natural fractures (NFs) and faults, is developed to analyze the migration mechanism of contaminants. Furthermore, the alkali erosion of rock caused by high-pH drilling of fluids, is considered in this paper. The numerical results suggest that both NFs and alkali erosion could reduce the time required for contaminants migrating to aquifers. When NFs and alkali erosion are both considered, the migration time will be shortened by 51 years. Alkali erosion makes the impact of NFs, on the contaminant migration, more significant. The migration time decreases with increasing pH values, while the accumulation is on the opposite side. Compared with pH 12.0, the migration time would be increased by 45 years and 29 years for pH 11.0 and 11.5, respectively. However, the migration time for pH 12.5 and 13.0 were found to be decreased by 82 years and 180 years, respectively. Alkali erosion could increase the rock permeability, and the elevated permeability would further enhance the migration velocity of the contaminants, which might play a major role in assessing the potential contamination of shallow aquifers.

Abstract:
The widespread use of unconventional drilling involving hydraulic fracturing (“fracking”) has allowed for increased oil-and-gas extraction, produced water generation, and subsequent spills of produced water in Colorado and elsewhere. Produced water contains BTEX (benzene, toluene, ethylbenzene, xylene) and naphthalene, all of which are known to induce varying levels of toxicity upon exposure. When spilled, these contaminants can migrate through the soil and contaminant groundwater. This research modeled the solute transport of BTEX and naphthalene for a range of spill sizes on contrasting soils overlying groundwater at different depths. The results showed that benzene and toluene were expected to reach human health relevant concentration in groundwater because of their high concentrations in produced water, relatively low solid/liquid partition coefficient and low EPA drinking water limits for these contaminants. Peak groundwater concentrations were higher and were reached more rapidly in coarser textured soil. Risk categories of “low,” “medium,” and “high” were established by dividing the EPA drinking water limit for each contaminant into sequential thirds and modeled scenarios were classified into such categories. A quick reference guide was created that allows the user to input specific variables about an area of interest to evaluate that site’s risk of groundwater contamination in the event of a produced water spill. A large fraction of produced water spills occur at hydraulic-fracturing well pads; thus, the results of this research suggest that the surface area selected for a hydraulic-fracturing site should exclude or require extra precaution when considering areas with shallow aquifers and coarsely textured soils.

Abstract:
Leakage of natural gas (mainly methane) along oil and gas wells contributes to fugitive greenhouse gas emissions. Natural gas leakage occurring outside the well casing and cement sheath and reaching the surface, hence the atmosphere, is known as Gas Migration (GM). In this paper an analysis of the occurrence of gas (methane) migration along wellbores in Alberta, Canada, is presented based on data obtained from the Alberta Energy Regulator. Gas migration (GM) has been reported in 3276 wells, i.e., in 0.73% of all the wells in the province. Most of these wells (2745) are located in the eastern, shallower part of the province, particularly in the Lloydminster – Cold Lake area. The wells are mostly shallow, with 2800 wells being shallower than 1000 m depth. About half of the wells are cemented to the top, showing that lack of cementing to the top or at least above the surface casing shoe is not a major factor in the occurrence of GM. Similarly, well orientation is not a strong indicator of GM potential or occurrence A slight majority (54.1%) of the wells with GM are conventional wells, with the balance (45.9%) being thermal wells, of which the great majority is in the Cold Lake oil sands area where cyclic steam injection is used for bitumen production. The analysis indicates that the production type, conventional for oil and gas, or thermal for heavy oil and bitumen, is a strong indicator of the potential for, or occurrence for GM. The depth of the gas source is provided in the database for 559 wells. When related to the well depth, the relative depth of the gas source has an average of 0.42, indicating that the origin of the gas source is, by and large, above the producing reservoirs. Isotopic studies of reservoir and migrating gas in Alberta, reviewed in this paper, indicate that in the great majority of cases the migrating gas is immature thermogenic gas originating in overlying shales, as well as coal gas originating from the various overlying coal beds. In a number of cases the migrating gas is of shallow, biogenic origin, likely sourced from shallow groundwater aquifers. Biogenic methanogenesis is enhanced by the high temperatures associated with thermal wells, which may explain the large number of GM cases associated with thermal wells.

Abstract:
The risk of environmental contamination by oil and gas wells depends strongly on the frequency with which they lose integrity. Wells with compromised integrity typically exhibit pressure in their outermost annulus (surface casing pressure, SfCP) due to gas accumulation. SfCP is an easily measured but poorly documented gauge of well integrity. Here, we analyze SfCP data from the Colorado Oil and Gas Conservation Commission database to evaluate the frequency of well integrity loss in the Wattenberg Test Zone (WTZ), within the Wattenberg Field, Colorado. Deviated and horizontal wells were found to exhibit SfCP more frequently than vertical wells. We propose a physically meaningful well-specific critical SfCP criterion, which indicates the potential for a well to induce stray gas migration. We show that 270 of 3923 wells tested for SfCP in the WTZ exceeded critical SfCP. Critical SfCP is strongly controlled by the depth of the surface casing. Newer horizontal wells, drilled during the unconventional drilling boom, exhibited critical SfCP less frequently than other wells because they were predominantly constructed with deeper surface casings. Thus, they pose a lower risk for inducing stray gas migration than legacy vertical or deviated wells with surface casings shorter than modern standards.

Abstract:
A holistic risk assessment of surface water (SW) contamination due to lead-210 (Pb-210) in oil produced water (PW) from the Bakken Shale in North Dakota (ND) was conducted. Pb-210 is a relatively long-lived radionuclide and very mobile in water. Because of limited data on Pb-210, a simulation model was developed to determine its concentration based on its parent radium-226 and historical total dissolved solids levels in PW. Scenarios where PW spills could reach SW were analyzed by applying the four steps of the risk assessment process. These scenarios are: (1) storage tank overflow, (2) leakage in equipment, and (3) spills related to trucks used to transport PW. Furthermore, a survey was conducted in ND to quantify the risk perception of PW from different stakeholders. Findings from the study include a low probability of a PW spill reaching SW and simulated concentration of Pb-210 in drinking water higher than the recommended value established by the World Health Organization. Also, after including the results from the risk perception survey, the assessment indicates that the risk of contamination of the three scenarios evaluated is between medium-high to high.

Abstract:
The development of shale gas resources was made possible by the combination of horizontal drilling and high-volume hydraulic fracturing (fracking). Environmental concerns have been raised relative to shale gas production, especially potential impacts on groundwater. Fluids related to unconventional oil and gas (O&G) operations contain chemical compounds that can impact groundwater quality. Such impacts can occur due to (1) the infiltration of surface contaminant releases, (2) failures of the integrity of O&G wells, and (3) upward fluid migration from a shale/tight reservoir along preferential paths that can be natural (faults or fracture zone) or man-made (O&G wells). Surface releases represent the most probable mechanism leading to groundwater contamination. Improvements in O&G drilling operations under stringent regulations can minimize this risk. Experts identify O&G well integrity as the most challenging issue that may lead to groundwater contamination. Failure of casing and cement can lead to upward fluid flow within or outside O&G wells, especially of methane. Integrity failures leading to fluid migration to shallow fresh water aquifers or to the surface are well understood and can be detected and repaired, but this can be complex and costly. A few regulators now impose groundwater monitoring to detect impacts from integrity failures. Occurrences of communication with existing O&G wells from fracking operations have also led some regulators to impose rules aiming to avoid such potential fluid migration paths. There is an ongoing scientific debate regarding the potential for fluids to migrate upward from exploited shale gas units to aquifers through natural preferential paths. WIREs Water 2017, 4:e1188. doi: 10.1002/wat2.1188 For further resources related to this article, please visit the WIREs website.

Abstract:
The shale slip, cement failure and micro annulus caused by hydraulic fracturing in shale gas well may generate local loads which have significant effects on the stress status and yield of the casing. Local loads are considered in the well integrity analysis based on the Mechanics of Materials. A mechanical model is established for the casing behavior under local loads. The accuracy of the model is verified by numerical simulation, Nesrter's method and field data. The effects of local loads and casing dimension on the casing failure are illustrated by the sensitivity analysis. The analysis results show that the casing collapse is more likely to occur under the radial local loads than under parallel ones. Increasing casing thickness and decreasing casing outer diameter are in favor of reducing the casing failure in shale gas wells. The local loads region has the greatest effect on anti-collapse strength of the casing when φ = 90°. Through decreasing the wellbore diameter of shale gas wells and intersecting the natural fractures of shale gas reservoir reasonably, the directional drilling safety, cementing quality and well integrity can be effectively improved, and the casing deformation can be much reduced.

Abstract:
A dramatic increase in unconventional drilling that utilizes hydraulic fracturing to extract oil/gas over the past decade has led to concern over handling and management of produced/ flowback water (PFW; hydraulic-fracturing wastewater) because the potential exists for its accidental release into the environment. This PFW contains high amounts of total dissolved solids acquired from interaction with the reservoir formation. Development and testing of geochemical methods, such as strontium (Sr) isotope ratio (87Sr/86Sr) analysis, to determine the origin of dissolved solids in an environment would be valuable. Samples acquired from different sources in Texas overlying and within the Barnett Shale, such as surface/ground water and PFW, contain unique Sr concentrations and 87Sr/86Sr values, with the potential to be used as a geochemical fingerprint. This study shows that because of the very high concentration of Sr in PFW and its high 87Sr/86Sr value, when as little as 1% of a sample is PFW, the sample experiences a measurable change in 87Sr/86Sr. To determine which phase within the reservoir rock imparts its 87Sr/86Sr to the PFW, sequential extractions were performed on powdered Barnett Shale core samples. Results of the extractions show varying geochemical affinities and distinct 87Sr/86Sr values by leaching solution. However, a direct link to the PFW sample was not conclusive, likely because of the unknown location of the PFW sample and the spatially variable 87Sr/86Sr of the Barnett Shale. Future work requires further cooperation with industry or federal agencies that could provide a more complete set of samples.

Abstract:
Extraction of oil and gas from unconventional sources, such as shale, has dramatically increased over the past ten years, raising the potential for spills or releases of chemicals, waste materials, and oil and gas. We analyzed spill data associated with unconventional wells from Colorado, New Mexico, North Dakota and Pennsylvania from 2005 to 2014, where we defined unconventional wells as horizontally drilled into an unconventional formation. We identified materials spilled by state and for each material we summarized frequency, volumes and spill rates. We evaluated the environmental risk of spills by calculating distance to the nearest stream and compared these distances to existing setback regulations. Finally, we summarized relative importance to drinking water in watersheds where spills occurred. Across all four states, we identified 21,300 unconventional wells and 6622 reported spills. The number of horizontal well bores increased sharply beginning in the late 2000s; spill rates also increased for all states except PA where the rate initially increased, reached a maximum in 2009 and then decreased. Wastewater, crude oil, drilling waste, and hydraulic fracturing fluid were the materials most often spilled; spilled volumes of these materials largely ranged from 100 to 10,000L. Across all states, the average distance of spills to a stream was highest in New Mexico (1379m), followed by Colorado (747m), North Dakota (598m) and then Pennsylvania (268m), and 7.0, 13.3, and 20.4% of spills occurred within existing surface water setback regulations of 30.5, 61.0, and 91.4m, respectively. Pennsylvania spills occurred in watersheds with a higher relative importance to drinking water than the other three states. Results from this study can inform risk assessments by providing improved input parameters on volume and rates of materials spilled, and guide regulations and the management policy of spills.

Abstract:
The rapid expansion in unconventional gas development over the past two decades has led to concerns over the potential impacts on groundwater resources. Although numerical models are invaluable for assessing likelihood of impacts at particular sites, simpler analytical models are also useful because they help develop hydrological understanding. Analytical approaches are also valuable for preliminary assessments and to determine where more complex models are warranted. In this article, we present simple analytical solutions that can be used to predict: (1) the spatial extent of drawdown from horizontal wells drilled into the gas-bearing formation, and rate of recovery after gas production ceases; (2) the potential for upward transport of contaminants from the gas-bearing formation to shallow aquifers during hydraulic fracturing operations when pressures in the gas-bearing formation are greatly increased; and (3) the potential downward leakage of water from shallow aquifers during depressurization of gas-bearing formations. In particular, we show that the recovery of pressure after production ceases from gas-bearing shale formations may take several hundred years, and we present critical hydraulic conductivity values for intervening aquitards, below which the impact on shallow aquifers will be negligible. The simplifying assumptions inherent in these solutions will limit their predictive accuracy for site-specific assessments, compared to numerical models that incorporate knowledge of spatial variations in formation properties and which may include processes not considered in the simpler solutions.

Abstract:
In recent years, concerns have been raised about the potential environmental impacts of oil and gas (O&G) exploitation, especially regarding groundwater resources. However, there have been few studies carried out to assess the actual risk of O&G exploitation based on specific local conditions. This paper reports on a study aiming to assess the potential risk to groundwater quality related to the development of a tight sandstone petroleum reservoir underlying a shallow fractured rock aquifer system in the Haldimand sector of Gaspé, Québec, Canada. In this generally rural setting, the drilling of a provincially permitted horizontal O&G exploration well was halted by new municipal regulations. Draft provincial environmental regulations were subsequently issued to define environmental requirements for hydrocarbon exploration wells. Our study thus also aimed to provide an example of how to comply with the new hydrogeological characterization requirements. This paper reports on the process followed to qualitatively assess the risk of O&G operations and natural oil seeps to groundwater quality. The assessment focused on indicators of potential preferential fluid migration paths between the reservoir level and shallow aquifers. Field work and data analysis were used to define geological, hydrogeological and geochemical contexts on which a numerical model was developed to represent groundwater flow, mass transport and groundwater residence time. The risk for groundwater quality was qualitatively assessed from the implications of the study area context relative to 1) the new provincial regulatory requirements; 2) potential contaminant release mechanisms related to O&G exploration drilling operations; and 3) the expected effects that contaminant releases could have on groundwater.

Abstract:
As shale and tight gas basins are increasingly used to extract natural gas, understanding how gas migrates is important. Wood and Sanei find that secondary migration in a tight-gas basin leads to up-dip transmission of enriched methane into surficial strata which may leak into groundwater and the atmosphere.

Abstract:
Interaction between hydraulically generated fractures and existing wells (frac hits) could represent a potential risk to groundwater. In particular, frac hits on abandoned oil and gas wells could lead to upward leakage into overlying aquifers, provided migration pathways are present along the abandoned well. However, potential risk to groundwater is relatively unknown because few studies have investigated the probability of frac hits on abandoned wells. In this study, actual numbers of frac hits were not determined. Rather, the probability for abandoned wells to intersect hypothetical stimulated reservoir sizes of horizontal wells was investigated. Well data were compiled and analyzed for location and reservoir information, and sensitivity analyses were conducted by varying assumed sizes of stimulated reservoirs. This study used public and industry data for the Eagle Ford Shale play in south Texas, with specific attention paid to abandoned oil and gas wells converted into water wells (converted wells). In counties with Eagle Ford Shale activity, well-data analysis identified 55,720 abandoned wells with a median age of 1983, and 2400 converted wells with a median age of 1954. The most aggressive scenario resulted in 823 abandoned wells and 184 converted wells intersecting the largest assumed stimulated reservoir size. Analysis showed abandoned wells have the potential to be intersected by multiple stimulated reservoirs, and risks for intersection would increase if currently permitted horizontal wells in the Eagle Ford Shale are actually completed. Results underscore the need to evaluate historical oil and gas activities in areas with modern unconventional oil and gas activities.

Abstract:
Environmental monitoring of shale gas production and geological carbon dioxide (CO2) storage requires identification of subsurface gas sources. Noble gases provide a powerful tool to distinguish different sources if the modifications of the gas composition during transport can be accounted for. Despite the recognition of compositional changes due to gas migration in the subsurface, the interpretation of geochemical data relies largely on zero-dimensional mixing and fractionation models. Here we present two-phase flow column experiments that demonstrate these changes. Water containing a dissolved noble gas is displaced by gas comprised of CO2 and argon. We observe a characteristic pattern of initial co-enrichment of noble gases from both phases in banks at the gas front, followed by a depletion of the dissolved noble gas. The enrichment of the co-injected noble gas is due to the dissolution of the more soluble major gas component, while the enrichment of the dissolved noble gas is due to stripping from the groundwater. These processes amount to chromatographic separations that occur during two-phase flow and can be predicted by the theory of gas injection. This theory provides a mechanistic basis for noble gas fractionation during gas migration and improves our ability to identify subsurface gas sources after post-genetic modification. Finally, we show that compositional changes due to two-phase flow can qualitatively explain the spatial compositional trends observed within the Bravo Dome natural CO2 reservoir and some regional compositional trends observed in drinking water wells overlying the Marcellus and Barnett shale regions. In both cases, only the migration of a gas with constant source composition is required, rather than multi-stage mixing and fractionation models previously proposed.

Abstract:
A system approach is used to investigate the potential risk of groundwater contamination from a failure associated with hydraulic fracturing. The focus is on the role of permeability anisotropy, initial saturation of the medium, leakage depth and leakage rate in controlling the contamination risk at environmentally sensitive locations. We numerically simulate the fluid flow and chemical transport in the geological formations, and use the Monte Carlo algorithm to quantify uncertainty. Geological and operational parameters are selected as random variables. We develop a risk framework to assess three environmental performance metrics: the solute concentration, the arrival times from source to receptor, and the ingestion hazard of the contaminated aquifer. We define risk as the probability of exceeding a certain threshold level for each metric. The effect of parametric uncertainty in risk is also analyzed. The results show that risk strongly depends on water saturation and the anisotropy of the permeability distribution. Furthermore, the measured risk value is more sensitive to leakage depth and leakage rate when compared to the hydrogeological properties. Findings of this study may be applied to situations with more stringent well integrity requirements to ensure that hydraulic fracturing is practiced in an environmentally safe and sound manner, with minimal risk to water contamination.

Abstract:
Shale gas production in the US, predominantly from the Marcellus shale, has been accused of methane emissions and contaminating drinking water under the suspicion that this is caused by hydraulic fracturing in combination with leaking wells. Misunderstandings of the risks of shale gas production are widespread and are causing communication problems. This paper discusses recent preliminary results from the US Environmental Protection Agency (EPA) draft study, which is revealing fact-based issues: EPA did not find evidence that these mechanisms have led to widespread, systemic impacts on drinking water resources in the United States, which contrasts many broad-brushed statements in media and public. The complex geological situation and extraction history of oil, gas and water in the Marcellus area in Pennsylvania is a good case for learnings and demonstrating the need for proper analysis and taking the right actions to avoid problems. State-of-the-art technology and regulations of proper well integrity are available, and their application will provide a sound basis for shale gas extraction.

Abstract:
The association between hydrocarbon-rich reservoirs and organic-rich source rocks means unconventional oil and gas plays usually occur in mature sedimentary basins—where large-scale conventional development has already taken place. Abandoned wells in proximity to hydraulic fracturing could be affected by increased fluid pressures and corresponding newly generated fractures that directly connect (frac hit) to an abandoned well or to existing fractures intersecting an abandoned well. If contaminants migrate to a pathway hydraulically connected to an abandoned well, upward leakage may occur. Potential effects of hydraulic fracturing on upward flow through a particular type of leaky abandoned well—abandoned oil and gas wells converted into water wells were investigated using numerical modeling. Several factors that affect flow to leaky wells were considered including proximity of a leaky well to hydraulic fracturing, flowback, production, and leaky well abandonment methods. The numerical model used historical records and available industry data for the Eagle Ford Shale play in south Texas. Numerical simulations indicate that upward contaminant migration could occur through leaky converted wells if certain spatial and hydraulic conditions exist. Upward flow through leaky converted wells increased with proximity to hydraulic fracturing, but decreased when flowback and production occurred. Volumetric flow rates ranged between 0 and 0.086 m3/d for hydraulic-fracturing scenarios. Potential groundwater impacts should be paired with plausible transport mechanisms, and upward flow through leaky abandoned wells could be unrelated to hydraulic fracturing. The results also underscore the need to evaluate historical activities.

Abstract:
Gas production from shale formations by hydraulic fracturing has raised concerns about the effects on the quality of fresh groundwater. The migration of injected fracking fluids towards the surface was investigated in the North German Basin, based on the known standard lithology. This included cases with natural preferential pathways such as permeable fault zones and fracture networks. Conservative assumptions were applied in the simulation of flow and mass transport triggered by a high pressure boundary of up to 50 MPa excess pressure. The results show no significant fluid migration for a case with undisturbed cap rocks and a maximum of 41 m vertical transport within a permeable fault zone during the pressurization. Open fractures, if present, strongly control the flow field and migration; here vertical transport of fracking fluids reaches up to 200 m during hydraulic fracturing simulation. Long-term transport of the injected water was simulated for 300 years. The fracking fluid rises vertically within the fault zone up to 485 m due to buoyancy. Progressively, it is transported horizontally into sandstone layers, following the natural groundwater flow direction. In the long-term, the injected fluids are diluted to minor concentrations. Despite the presence of permeable pathways, the injected fracking fluids in the reported model did not reach near-surface aquifers, either during the hydraulic fracturing or in the long term. Therefore, the probability of impacts on shallow groundwater by the rise of fracking fluids from a deep shale-gas formation through the geological underground to the surface is small.

Abstract:
One of the critical environmental questions about hydraulic fracturing in shales is the potential for contamination of ground and surface water. There are two specific concerns arising from hydraulic treatments: 1) whether hydraulic fractures extend upward through overlying strata to reach overlying aquifers containing drinking water, and 2) whether injected fluids push native fluids upward into these overlying aquifers. In this work, the extent of likely fracture growth through overlying layers during hydraulic treatment of the Marcellus shale was estimated using a hydraulic fracture model. A wide range of material and fluid flow properties in a multi-layered geologic model was considered. The model was based on conditions and characteristics applicable to the Marcellus shale in that part of the Appalachian basin within southwestern Pennsylvania. Predictions of vertical termination frequencies for hydraulic fractures were used in a multi-layer model of the strata and natural fractures for studying brine migration through the natural and induced fracture network. NFFLOW, the software for explicitly modeling flow within networks of fractures, was utilized to compute transient flow rates according to the schedule of injected fluid during hydraulic fracturing. To aid our analysis, the modeled sequence of geologic strata was capped with a fictitious unfractured, but moderately-permeable layer, which serves as a monitoring zone. The analysis assumes one well lateral was placed in the middle of the Marcellus shale with hydraulic fractures penetrating layers in the model. The newly-developed geomechanical module within NFFLOW was used to represent stress-sensitivity of the fractures. This allows the opening and closing of fracture apertures with changes in fluid pressures within fracture segments. Pressure increases in the formations overlying the Tully limestone, indicating fluid flow, was observed due to the hydraulic stimulation; and the impact of these increased pressures on brine migration towards the surface was considered.

Abstract:
Reports highlight the safety of hydraulic fracturing for drinking water if it occurs ?many hundreds of meters to kilometers underground?. To our knowledge, however, no comprehensive analysis of hydraulic fracturing depths exists. Based on fracturing depths and water use for ?44?000 wells reported between 2010 and 2013, the average fracturing depth across the United States was 8300 ft (?2500 m). Many wells (6900; 16%) were fractured less than a mile from the surface, and 2600 wells (6%) were fractured above 3000 ft (900 m), particularly in Texas (850 wells), California (720), Arkansas (310), and Wyoming (300). Average water use per well nationally was 2?400?000 gallons (9?200?000 L), led by Arkansas (5?200?000 gallons), Louisiana (5?100?000 gallons), West Virginia (5?000?000 gallons), and Pennsylvania (4?500?000 gallons). Two thousand wells (?5%) shallower than one mile and 350 wells (?1%) shallower than 3000 ft were hydraulically fractured with >1 million gallons of water, particularly in Arkansas, New Mexico, Texas, Pennsylvania, and California. Because hydraulic fractures can propagate 2000 ft upward, shallow wells may warrant special safeguards, including a mandatory registry of locations, full chemical disclosure, and, where horizontal drilling is used, predrilling water testing to a radius 1000 ft beyond the greatest lateral extent.

Abstract:
Methane and brine leakage rates and associated time scales along the cemented casing of a hypothetical decommissioned shale gas well have been assessed with a multiphase flow and multicomponent numerical model. The conceptual model used for the simulations assumes that the target shale formation is 200 m thick, overlain by a 750 m thick caprock, which is in turn overlain by a 50 m thick surficial sand aquifer, the 1000 m geological sequence being intersected by a fully penetrating borehole. This succession of geological units is representative of the region targeted for shale gas exploration in the St. Lawrence Lowlands (Québec, Canada). The simulations aimed at assessing the impact of well casing cementation quality on methane and brine leakage at the base of a surficial aquifer. The leakage of fluids can subsequently lead to the contamination of groundwater resources and/or, in the case of methane migration to ground surface, to an increase in greenhouse gas emissions. The minimum reported surface casing vent flow (measured at ground level) for shale gas wells in Quebec (0.01 m3/d) is used as a reference to evaluate the impact of well casing cementation quality on methane and brine migration. The simulations suggest that an adequately cemented borehole (with a casing annulus permeability kc ≤ 1 mD) can prevent methane and brine leakage over a time scale of up to 100 years. However, a poorly cemented borehole (kc ≥ 10 mD) could yield methane leakage rates at the base of an aquifer ranging from 0.04 m3/d to more than 100 m3/d, depending on the permeability of the target shale gas formation after abandonment and on the quantity of mobile gas in the formation. These values are compatible with surface casing vent flows reported for shale gas wells in the St. Lawrence Lowlands (Quebec, Canada). The simulated travel time of methane from the target shale formation to the surficial aquifer is between a few months and 30 years, depending on cementation quality and hydrodynamic properties of the casing annulus. Simulated long-term brine leakage rates after 100 years for poorly cemented boreholes are on the order of 10−5 m3/d (10 mL/d) to 10−3 m3/d (1 L/d). Based on scoping calculations with a well-mixed aquifer model, these rates are unlikely to have a major impact on groundwater quality in a confined aquifer since they would only increase the chloride concentration in a pristine aquifer to 1 mg/L, which is significantly below the commonly recommended aesthetic objective of 250 mg/L for chloride.

Abstract:
Abandoned oil and gas (AOG) wells can provide pathways for subsurface fluid migration, which can lead to groundwater contamination and gas emissions to the atmosphere. Little is known about the millions of AOG wells in the U.S. and abroad. Recently, we acquired data on methane emissions from 42 plugged and unplugged AOG wells in five different counties across western Pennsylvania. We used historical documents to estimate well depths and used these depths with the emissions data to estimate the wells effective permeabilities, which capture the combined effects of all leakage pathways within and around the wellbores. We find effective permeabilities to range from 10(-6) to 10(2) millidarcies, which are within the range of previous estimates. The effective permeability data presented here provide perspective on older AOG wells and are valuable when considering the leakage potential of AOG wells in a wide range of applications, including geologic storage of carbon dioxide, natural gas storage, and oil and gas development.

Abstract:
Hydrocarbon production from unconventional resources and the use of reservoir stimulation techniques, such as hydraulic fracturing, has grown explosively over the last decade. However, concerns have arisen that reservoir stimulation creates significant environmental threats through the creation of permeable pathways connecting the stimulated reservoir with shallower freshwater aquifers, thus resulting in the contamination of potable groundwater by escaping hydrocarbons or other reservoir fluids. This study investigates, by numerical simulation, gas and water transport between a shallow tight-gas reservoir and a shallower overlying freshwater aquifer following hydraulic fracturing operations, if such a connecting pathway has been created. We focus on two general failure scenarios: (1) communication between the reservoir and aquifer via a connecting fracture or fault and (2) communication via a deteriorated, preexisting nearby well. We conclude that the key factors driving short-term transport of gas include high permeability for the connecting pathway and the overall volume of the connecting feature. Production from the reservoir is likely to mitigate release through reduction of available free gas and lowering of reservoir pressure, and not producing may increase the potential for release. We also find that hydrostatic tight-gas reservoirs are unlikely to act as a continuing source of migrating gas, as gas contained within the newly formed hydraulic fracture is the primary source for potential contamination. Such incidents of gas escape are likely to be limited in duration and scope for hydrostatic reservoirs. Reliable field and laboratory data must be acquired to constrain the factors and determine the likelihood of these outcomes.

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.

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.

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.

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.

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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.

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.

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.

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.

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.

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.

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.

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.

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Abstract:
The risk of groundwater contamination from shale gas exploration and development is a major societal concern, especially in populated areas where groundwater is an essential source of drinking water and for agricultural or industrial use. Since groundwater decontamination is difficult, or nearly impossible, it is essential to evaluate exploration and production conditions that would prevent or at least minimize risks of groundwater contamination. The current consensus in recent literature is that these risks are primarily related to engineering issues, including casing integrity and surface activities, such as truck traffic (equipment and fluid haulage), waste management (mainly drill cuttings), and water storage and treatment when hydraulic fracturing is utilized. Concerns have also been raised with respect to groundwater contamination that could result from potential fracture or fault interconnections between the shale unit and surficial aquifers, which would allow fracturing fluids and methane to reach the surface away from the wellbore. Despite the fact that groundwater resources are relatively well characterized in some regions, there is currently no recognized method to evaluate the vulnerability or risks to aquifers resulting from hydrocarbon industry operations carried out at great depths. This paper focuses on the Utica Shale of the St. Lawrence Platform (Quebec), where an environmental study aiming to evaluate potential risks for aquifers related to shale gas development has been initiated. To provide the context of these research efforts, this paper describes the regional tectono-stratigraphic evolution and current stress regime of the Cambrian–Ordovician St. Lawrence Platform, as well as the Utica Shale internal stratigraphy, mineralogy and thermal maturation. Then, the hydrogeological context of the St. Lawrence Platform is discussed. Finally, the methodology for this environmental study, based on geological, geophysical, geomechanical, hydrogeological and geochemical data, is presented.

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In recent years, shale gas formations have become economically viable through the use of horizontal drilling and hydraulic fracturing. These techniques carry potential environmental risk due to their high water use and substantial risk for water pollution. Using probability bounds analysis, we assessed the likelihood of water contamination from natural gas extraction in the Marcellus Shale. Probability bounds analysis is well suited when data are sparse and parameters highly uncertain. The study model identified five pathways of water contamination: transportation spills, well casing leaks, leaks through fractured rock, drilling site discharge, and wastewater disposal. Probability boxes were generated for each pathway. The potential contamination risk and epistemic uncertainty associated with hydraulic fracturing wastewater disposal was several orders of magnitude larger than the other pathways. Even in a best-case scenario, it was very likely that an individual well would release at least 200 m³ of contaminated fluids. Because the total number of wells in the Marcellus Shale region could range into the tens of thousands, this substantial potential risk suggested that additional steps be taken to reduce the potential for contaminated fluid leaks. To reduce the considerable epistemic uncertainty, more data should be collected on the ability of industrial and municipal wastewater treatment facilities to remove contaminants from used hydraulic fracturing fluid.

Abstract:
An overview is given of the mechanisms and processes (viscous flow, diffusion, sorption, desorption) affecting transport in unconventional reservoir rocks. Processes are described, terms and definitions are given, and selected literature data are presented to document the state of knowledge and the data situation on gas, water and two-phase flow in low-permeable lithotypes. Gas transport in the matrix of shales and coals is controlled by and may be restricted to diffusion. Depending on the gas type (e.g. methane or carbon dioxide), transport may be strongly affected by sorption. In many instances, high capillary threshold pressures prevent gas from moving as a continuous phase through the conducting pore network. In contrast, tight sandstone reservoir rocks allow for capillary-controlled viscous flow of a gas phase. Because in these rocks the determination of the water saturation at the prevailing flow conditions is difficult or impossible, we propose to directly use the relationship between effective gas permeability and capillary pressure for the description of two-phase (gas/water) flow in these rocks. In ongoing studies this relationship is being studied systematically for both, steady state and non-steady state saturation conditions.