Low Permeability Shale Research Articles

ASSESSING THE POTENTIAL FOR CARBON SEQUESTRATION IN DEPLETED HEAVY OIL RESERVOIRS USING ACOUSTIC LOGGING

As global warming due to anthropogenic greenhouse gases, notably carbon dioxide threatens to take a catastrophic dimension, geological storage of carbon dioxide has been widely accepted as a technically and economically viable remediation strategy. Consequently, targeted geological repositories are saline aquifers, salt caverns, deep unmineable coal seams and depleted oil and gas reservoirs. For storage in depleted oil reservoirs, the stratigraphic trapping capability of overlying low permeability shale is the principal motivating factor for long term containment of anthropogenic gas in oil reservoir until its dissolution and final immobilization by mineral carbonation reactions. Consequently, where the development of the oil reservoir by thermal recovery can lead to thermal pressurization of the cap rock layer, the ability of such a depleted reservoir to contain anthropogenic carbon dioxide must be thoroughly investigated to assess its competency as a proposed geological repository. In this study, seismic theory coupled with that of heat transfer has been used to derive interval velocity for a heavy oil reservoir under thermal recovery. The resulting equation has been validated using published works from literature sources.

Natural Fractures in shale: A review and new observations

Natural fractures have long been suspected as a factor in production from shale reservoirs because gas and oil production commonly exceeds the rates expected from low-porosity and low-permeability shale host rock. Many shale outcrops, cores, and image logs contain fractures or fracture traces, and microseismic event patterns associated with hydraulic-fracture stimulation have been ascribed to natural fracture reactivation. Here we review previous work, and present new core and outcrop data from 18 shale plays that reveal common types of shale fractures and their mineralization, orientation, and size patterns. A wide range of shales have a common suite of types and configurations of fractures: those at high angle to bedding, faults, bed-parallel fractures, early compacted fractures, and fractures associated with concretions. These fractures differ markedly in their prevalence and arrangement within each shale play, however, constituting different fracture stratigraphies—differences that depend on interface and mechanical properties governed by depositional, diagenetic, and structural setting. Several mechanisms may act independently or in combination to cause fracture growth, including differential compaction, local and regional stress changes associated with tectonic events, strain accommodation around large structures, catagenesis, and uplift. Fracture systems in shales are heterogeneous; they can enhance or detract from producibility, augment or reduce rock strength and the propensity to interact with hydraulic-fracture stimulation. Burial history and fracture diagenesis influence fracture attributes and may provide more information for fracture prediction than is commonly appreciated. The role of microfractures in production from shale is currently poorly understood yet potentially critical; we identify a need for further work in this field and on the role of natural fractures generally.

Anisotropy in Fracking: A Percolation Model for Observed Microseismicity

Hydraulic fracturing (fracking) using high pressures and a low viscosity fluid allow the extraction of large quantiles of oil and gas from very low permeability shale formations. The initial production of oil and gas at depth leads to high pressures and an extensive distribution of natural fractures which reduce the pressures. With time these fractures heal, sealing the remaining oil and gas in place. High volume fracking opens the healed fractures allowing the oil and gas to flow the horizontal productions wells. We model the injection process using invasion percolation. We utilize a 2D square lattice of bonds to model the sealed natural fractures. The bonds are assigned random strengths and the fluid, injected at a point, opens the weakest bond adjacent to the growing cluster of opened bonds. Our model exhibits burst dynamics in which the clusters extends rapidly into regions with weak bonds. We associate these bursts with the microseismic activity generated by fracking injections. A principal object of this paper is to study the role of anisotropic stress distributions. Bonds in the $y$-direction are assigned higher random strengths than bonds in the $x$-direction. We illustrate the spatial distribution of clusters and the spatial distribution of bursts (small earthquakes) for several degrees of anisotropy. The results are compared with observed distributions of microseismicity in a fracking injection. Both our bursts and the observed microseismicity satisfy Gutenberg-Richter frequency-size statistics.

Enhanced permeation of a hydrophobic fluid through particles with hydrophobic and hydrophilic patterned surfaces.

The wetting properties of solid surfaces are significant in oil/gas and liquid displacement processes. It is difficult for hydrophobic fluids to permeate channels filled with hydrophilic particles and an aqueous phase, and this is thought to be the primary cause of low yields in low permeability reservoir operations. Using three-dimensional lattice Boltzmann simulations, we show that particles with hydrophobic and hydrophilic patterned surfaces can greatly improve hydrophobic fluid permeation. Specifically, a hydrophobic fluid can easily access micro-channels in the hydrophobic regions, which extend rapidly even to the hydrophilic regions and accelerate hydrophobic fluid escape. This work enriches understanding of multiphase flow in porous media at the pore scale and fracture conductivity and is expected to have great significance in the exploitation of low permeability reservoirs and shale gas.

Improved reservoir characterization and monitoring of the Long Lake heavy oil SAGD project using time-lapse multicomponent seismic data

Kelsey Schiltz, Loren Zeigler and David Gray demonstrate how the integration of timelapse compressional and multi-component seismic data has resulted in a geologic model of low permeability shales and enhanced the understanding of the steam chamber through imaging of the heat and pressure fronts in the Long Lake bitumen field in Alberta, Canada. Long Lake is a bitumen field covering 63,000 acres within the Athabasca oil sands in Alberta, Canada. Bitumen is a special type of heavy oil that is less than 10 API and is immobile at in situ conditions. Long Lake bitumen (~8 API) is produced from the Lower Cretaceous McMurray Formation using an in situ thermal recovery method called steam-assisted gravity drainage (SAGD).

An absorption method for extraction and characterization of porewater from low-permeability rocks using cellulosic sheets

Characterization of porewater chemistry in low-permeability rocks can provide insight into the origin and residence time of porewater, the history of fluid movement and the nature of transport and reaction processes. However, the measurement of porewater chemistry in low-permeability rocks is challenging because of the small fluid volume and the difficulty of extracting representative samples. Several techniques are available, but the results they provide can be affected by ion exchange and mineral dissolution, and they may require independent porosity measurements. The objective of this work is to develop a method of extracting representative samples of in situ porewater from low-permeability rocks and accurately quantify solute concentrations in the extracted porewater. A preliminary trial demonstrated the feasibility of extracting porewater by absorption into hydrophilic cellulosic membranes from low-permeability shale (Georgian Bay Formation, Michigan Basin, southwest Ontario, Canada). Solute concentrations are calculated from independent measurements of solute mass quantified by Inductively-Coupled-Plasma Mass Spectrometry (ICP-MS) and water-content quantified by Near Infrared (NIR) spectrometry. Sorption experiments indicate that there is no preferential sorption of solutes (Na, Cl, Mg, Ca, K, Sr, and Br) to the cellulosic membrane. The results indicate that the method is capable of determining solute concentrations on absorbed porewater with analytical precision that is within the margins of error recommended by EPA Method 6020a for analysis of saline water samples.

Origin and Filling Model of Natural Gas in Jiannan Gas Field, Sichuan Basin, China

The chemical and stable isotopic compositions of natural gases from Jiannan Gas Field, Sichuan Basin, China, were investigated to elucidate the origin of the gas and to reconstruct the reservoir filling history. The natural gases in Jiannan Gas Field are dominated by CH4 with low amounts of non-hydrocarbon (e.g. CO2, H2S and N2) components. The stable carbon isotope compositions of methane and its homologues vary widely, with an isotope trend of δ13C1≥ δ13C2< δ13C3. Structural restoration and burial history reconstruction indicated contrasting gas-filling histories for the gas reservoirs. Natural gas in the Carboniferous reservoirs was sourced from oil and gas cracking and thermal decomposition of kerogen in the lower Silurian shale and sealed by Lower Permian shale. Natural gas in the Upper Permian reservoir was derived primarily from Upper Permian mudstone with a minor contribution from Lower Silurian shale. The sulfur-bearing gas was probably sourced from Permian marine source rocks and migrated into the Lower Triassic reservoirs along unconformities and faults. Long-distance vertial migration may have caused the loss of H2S.

"Fracking" vs. "Hydraulic Fracturing:" A Review of Search Terms.

The increased debate over the use of hydraulic fracturing to access natural gas found in low permeability shales has brought this well established method of retrieval to the attention of the public at large. Whereas scientific literature uses the term hydraulic fracturing, the media and general public often use the term fracking. Researchers unfamiliar with the scientific term may miss out on valuable information and research articles when searching indexes and databases using the term fracking. This article examines the differences in research outcomes when using the two terms, and provides an analysis of the source types found in each database. [ABSTRACT FROM AUTHOR]

Loopless nontrapping invasion-percolation model for fracking.

Recent developments in hydraulic fracturing (fracking) have enabled the recovery of large quantities of natural gas and oil from old, low-permeability shales. These developments include a change from low-volume, high-viscosity fluid injection to high-volume, low-viscosity injection. The injected fluid introduces distributed damage that provides fracture permeability for the extraction of the gas and oil. In order to model this process, we utilize a loopless nontrapping invasion percolation previously introduced to model optimal polymers in a strongly disordered medium and for determining minimum energy spanning trees on a lattice. We performed numerical simulations on a two-dimensional square lattice and find significant differences from other percolation models. Additionally, we find that the growing fracture network satisfies both Horton-Strahler and Tokunaga network statistics. As with other invasion percolation models, our model displays burst dynamics, in which the cluster extends rapidly into a connected region. We introduce an alternative definition of bursts to be a consecutive series of opened bonds whose strengths are all below a specified value. Using this definition of bursts, we find good agreement with a power-law frequency-area distribution. These results are generally consistent with the observed distribution of microseismicity observed during a high-volume frack.

Diffusion–reaction studies in low permeability shale using X-ray radiography with cesium

An X-ray radiography method for the determination of diffusion coefficients in rock has been modified to provide an estimation of diffusion–reaction parameters for the sorbing tracer, cesium (Cs+). Cesium tracer diffusion and sorption on cation exchange sites can be monitored in intact rock samples using data extracted from radiographs to plot time-series relative-concentration profiles of Cs+ as a function of transport distance. Cesium was found to be a very good tracer for these experiments because of the sensitivity of the X-ray attenuation measurements to Cs+ concentration.Reactive-transport modeling coupled with parameter estimation software was used to match experimental data and estimate pore diffusion coefficients for Cs+ (Dp-Cs=7.6×10−11m2/s), single-site selectivity coefficients for Cs+ exchange (logKCs+/Na+=1.5) and cation exchange capacity (CEC=8.4meq/100g) for drill core samples of Queenston Formation shale, from the Michigan Basin in Ontario, Canada.

Effects of Ion Advection and Thermal Convection on Pore Pressure Changes in High Permeable Chemically Active Shale Formations

Wellbore instability problems are often encountered while drilling in water active shales due to changes in pore pressure. The change in pore pressure is caused by hydraulic, thermal, chemical, and electrical potential gradients. In all previous studies it has been found that the effects of ion advection and thermal convection have a negligible effect on changes in pore pressure for a range of very low permeable shale formations (>10−5 md). This is an appropriate assumption for very low permeable shale formations. For high permeable shale formations (e.g., shale with a disseminated microfissure network), however, thermal convection and ion advection can play a significant role. The authors present a hydro-chemo-thermo-electrical model based on finite element method to investigate the effect of advection on ion transfer and thermal convection on temperature and their combined effect on pore pressure in shale formations. All equations are based on the thermodynamics of irreversible processes in a discontinuous system. The characteristic Galerkin discretization method is used to stabilize the solution of advection and convection equations in the finite element approach. Results of this study revealed that ion and heat transfer are controlled primarily by permeability of the shale formations. Movement of fluid into or out of the formation is due to a combination of hydraulic, chemical, electrical, and thermal osmotic flow. Results have also shown that in high permeable shale formations the chemical potential gradient between the pore fluid and drilling fluid reaches equilibrium faster than in low permeable shale formations. This is mainly due to the advection of ion from drilling fluid to the shale formation.

Tracing groundwater with low-level detections of halogenated VOCs in a fractured carbonate-rock aquifer, Leetown Science Center, West Virginia, USA

Measurements of low-level concentrations of halogenated volatile organic compounds (VOCs) and estimates of groundwater age interpreted from 3H/3He and SF6 data have led to an improved understanding of groundwater flow, water sources, and transit times in a karstic, fractured, carbonate-rock aquifer at the Leetown Science Center (LSC), West Virginia. The sum of the concentrations of a set of 16 predominant halogenated VOCs (TDVOC) determined by gas chromatography with electron-capture detector (GC–ECD) exceeded that possible for air–water equilibrium in 34 of the 47 samples (median TDVOC of 24,800pgkg−1), indicating that nearly all the water sampled in the vicinity of the LSC has been affected by addition of halogenated VOCs from non-atmospheric source(s). Leakage from a landfill that was closed and sealed nearly 20a prior to sampling was recognized and traced to areas east of the LSC using low-level detection of tetrachloroethene (PCE), methyl chloride (MeCl), methyl chloroform (MC), dichlorodifluoromethane (CFC-12), and cis-1,2-dichloroethene (cis-1,2-DCE). Chloroform (CHLF) was the predominant VOC in water from domestic wells surrounding the LSC, and was elevated in groundwater in and near the Fish Health Laboratory at the LSC, where a leak of chlorinated water occurred prior to 2006. The low-level concentrations of halogenated VOCs did not exceed human or aquatic-life health criteria, and were useful in providing an awareness of the intrinsic susceptibility of the fractured karstic groundwater system at the LSC to non-atmospheric anthropogenic inputs. The 3H/3He groundwater ages of spring discharge from the carbonate rocks showed transient behavior, with ages averaging about 2a in 2004 following a wet climatic period (2003–2004), and ages in the range of 4–7a in periods of more average precipitation (2008–2009). The SF6 and CFC-12 data indicate older water (model ages of 10s of years or more) in the low-permeability shale of the Martinsburg Formation located to the west of the LSC. A two-a record of specific conductance, water temperature, and discharge recorded at 30-min intervals demonstrated an approximately 3-month lag in discharge at Gray Spring. The low groundwater ages of waters from the carbonate rocks support rapid advective transport of contaminants from the LSC vicinity, yet the nearly ubiquitous occurrence of low-level concentrations of halogenated VOCs at the LSC suggests the presence of long-term persistent sources, such as seepage from the closed and sealed landfill, infiltration of VOCs that may persist locally in the epikarst, exchange with low-permeability zones in fractured rock, and upward leakage of older water that may contain elevated concentrations of halogenated VOCs from earlier land use activities.

Development of a Preliminary Hydrogeology Conceptual Model for a Heterogeneous Alluvial Aquifer using Geological Characterization

Geological characterization of a heterogeneous alluvial channel aquifer was conducted using outcrop mapping and analysis of lithological logs from 15 boreholes drilled at the site. The study was aimed at developing a preliminary hydrogeology conceptual model. A total of 12 lithological samples were tested in the laboratory using falling head permeameter to determine the hydraulic conductivity of each unconsolidated lithology unit. Shale and calcrete outcrops were observed on the study site. Outcrop mapping on the site also indicated the presence of a contact plane between the overlying unconsolidated sediments and the shale of the underlying bedrock where a groundwater discharge zone has been created. Geology logs show that the alluvial channel aquifer comprises of three distinct layered unconsolidated sediment materials (calcrete, clay-silt, sand-gravel deposited formations) that overlie low permeable shale formation. Geological lithology revealed the spatial variation in the nature and type of unconsolidated sediments deposits between boreholes that can influence groundwater occurrence and flow in the aquifer system. The gravel-sand aquifer layer that consists of medium to large pebbles is conceptually the main hydraulically conductive unit with an average laboratory determined hydraulic conductivity of 8.5 m/day. Hydraulic gradient calculated using a combination of boreholes ranges from 0.013-0.022.

Numerical Simulation of Steam-Assisted Gravity Drainage With Vertical Slimholes

Summary Steam-assisted gravity drainage (SAGD) is the primary in-situ recovery method for bitumen from the large Athabasca deposit in Alberta, Canada. SAGD field operations encounter a significant decrease in production performance when low-permeability shale barriers are present in the formation. These layers can reduce SAGD performance and impede the growth of the steam chamber. They also significantly limit the percentage of the deposit from which bitumen can be economically recovered with SAGD. The concept of drilling vertical slimholes to create flow paths through barriers was conceived and investigated at Alberta Innovates-Technology Futures (AITF), formerly the Alberta Research Council. The use of slimholes has the potential to significantly increase the amount of recoverable bitumen (reserves) and the rate at which it is produced during SAGD. For shallow reservoirs, the slimholes could be drilled from the surface at a relatively low cost. It is believed that the process can be economically viable after its technical operation has been optimized with improvements in drilling technology, slimhole size and spacing, and enhanced usage of the slimholes in the development of steam chambers above the shale layers. Alternatively, the slimholes could be drilled from the horizontal wellbores (to avoid surface disturbance) as either horizontal slimholes from the producer or as horizontal/vertical slimhole combinations from the injector. The 2D and 3D field-scale numerical simulations were performed by use of reservoir properties and operating conditions based on published information for the MacKay River SAGD operation in the Athabasca deposit. The reservoir depth was 135 m, the initial pressure 500 kPaa, the initial temperature 7.5°C, and the initial oil saturation (SO) 0.8. The simulations explored the effect of vertical slimholes, which were laterally offset 7 m from the horizontal well-pair in reservoirs with and without shale layers or shale lenses. The effects on SAGD performance that were investigated were slimhole cross section (25 cm × 25 cm or 50 cm × 50 cm), the distance between slimholes (12 or 24 m) in the direction parallel to the well pair, the permeability of the reservoir and the vertical slimholes, and horizontal slimholes from the injector or producer. The slimhole cross section represents the disturbed area adjacent to the drilled slimhole and the drilled hole itself and is therefore relatively large. The slimholes were represented as high-permeability vertical channels by use of refined grids. For a reservoir with a continuous shale layer, SAGD performance was improved by vertical slimholes because of the recovery of previously inaccessible oil from above the shale layer, where a secondary steam chamber was formed.

A 4D Synchrotron X-Ray-Tomography Study of the Formation of Hydrocarbon- Migration Pathways in Heated Organic-Rich Shale

SummaryRecovery of oil from oil shales and the natural primary migration of hydrocarbons are closely related processes that have received renewed interest in recent years because of the ever tightening supply of conventional hydrocarbons and the growing production of hydrocarbons from low-permeability tight rocks. Quantitative models for conversion of kerogen into oil and gas and the timing of hydrocarbon generation have been well documented. However, lack of consensus about the kinetics of hydrocarbon formation in source rocks, expulsion timing, and how the resulting hydrocarbons escape from or are retained in the source rocks motivates further investigation. In particular, many mechanisms have been proposed for the transport of hydrocarbons from the rocks in which they are generated into adjacent rocks with higher permeabilities and smaller capillary entry pressures, and a better understanding of this complex process (primary migration) is needed. To characterize these processes, it is imperative to use the latest technological advances. In this study, it is shown how insights into hydrocarbon migration in source rocks can be obtained by using sequential high-resolution synchrotron X-ray tomography. Three-dimensional images of several immature “shale” samples were constructed at resolutions close to 5 μm. This is sufficient to resolve the source-rock structure down to the grain level, but very-fine-grained silt particles, clay particles, and colloids cannot be resolved. Samples used in this investigation came from the R-8 unit in the upper part of the Green River shale, which is organic rich, varved, lacustrine marl formed in Eocene Lake Uinta, USA. One Green River shale sample was heated in situ up to 400°C as X-ray-tomography images were recorded. The other samples were scanned before and after heating at 400°C. During the heating phase, the organic matter was decomposed, and gas was released. Gas expulsion from the low-permeability shales was coupled with formation of microcracks. The main technical difficulty was numerical extraction of microcracks that have apertures in the 5- to 30-μm range (with 5 μm being the resolution limit) from a large 3D volume of X-ray attenuation data. The main goal of the work presented here is to develop a methodology to process these 3D data and image the cracks. This methodology is based on several levels of spatial filtering and automatic recognition of connected domains. Supportive petrographic and thermogravimetric data were an important complement to this study. An investigation of the strain field using 2D image correlation analyses was also performed. As one application of the 4D (space + time) microtomography and the developed workflow, we show that fluid generation was accompanied by crack formation. Under different conditions, in the subsurface, this might provide paths for primary migration.Key words in this work include 4D microtomography, 3D image processing, shale, strain field analysis, kerogen, petroleum generation, primary migration, petrography, and thermogravimetry.

A review of the uncertainties in estimates of global oil resources

This paper discusses the uncertainties that exist in estimating the remaining ultimately recoverable resources of oil globally including the reasons for these and, where possible, how they may be mitigated, resolved, or reduced in future assessments. The encompassing and ambiguous terms ‘conventional oil’ and ‘unconventional oil’ are disaggregated into the numerous categories of oil that exist within each. These categories are investigated individually in order to identify the specific uncertainties by which they are influenced and affected. A key finding is that there are intrinsic uncertainties within every category of oil. Future assessments of global oil resources and projections of oil production should hence acknowledge these issues, explain or assess the effects that they have on results, and present ranges in any estimates produced or provided. An initial estimate is made of the technically recoverable resources of the light tight oil often called ‘shale oil’: oil found in low permeability shale formations requiring stimulation to be extracted. These resources are estimated to range on a global scale between 150 and 508 billion barrels with a central estimate of 278 billion barrels.

Experimental investigation of CO 2 breakthrough and flow mechanisms in shale

Supercritical CO 2 breakthrough and flow mechanisms in shale have been investigated in laboratory experiments using a high pressure flow cell and cylindrical samples of shale from the Draupne formation in the North Sea. The main objective is to study the basic mechanisms involved in the breakthrough process and define the controlling parameters for supercritical CO 2 flow in a low permeable shale. Experimental testing provides new insight into the CO 2 breakthrough process through simultaneous measurements of deformation and ultrasonic velocities in the sample. A marked sample dilation associated with the CO 2 breakthrough is identified accompanied with a pronounced drop in ultrasonic velocities. X-ray images of the sample using a high resolution 3D computer tomography (CT) scanner provide information on macroscopic fracture distribution inside the sample before and after testing. The CO 2 breakthrough pressure for the Draupne material seems to depend on confining pressure and effective pressure rather than pore pressure difference across the sample. After breakthrough the effective CO 2 permeability was found to follow a simple model for permeability in fractured rock. The drop in ultrasonic velocity was associated with mechanical changes and possible micro fracturing inside the sample. Based on our observations we conclude that pressure-induced opening of micro-fractures during the breakthrough process is an important mechanism for flow in addition to capillary displacement. Our findings may have important consequences for later testing and estimation of CO 2 breakthrough pressure and flow in shale.

Controlled CO2 injection into heterogeneous geologic formations for improved solubility and residual trapping

Geologic CO2 storage (GCS) has been proposed as a potentially viable climate change mitigation option. Among the trapping mechanisms known for permanent CO2 storage in saline aquifers, solubility and residual trapping are important for safe short‐term entrapment. These storage mechanisms are hampered by density‐driven upward CO2 movement that inhibits the lateral migration of the plume, leaving a large portion of the aquifer volume unexposed to CO2 and unavailable for storage. Heterogeneity of aquifer hydraulic properties and high horizontal/vertical hydraulic conductivity ratio of geologic formations are two competing mechanisms that can hinder upward CO2 migration. Postinjection displacement of free‐phase CO2 is somewhat controlled by the heterogeneity in rock permeability and porosity distributions. In particular, low permeability shale layers that act as vertical flow barrier and high‐permeability horizontal channels that form flow conduits can spread the CO2 plume laterally in the aquifer. In this paper, we consider CO2 storage in heterogeneous saline aquifers and propose controlled CO2 injection, based on existing knowledge of heterogeneity, to increase CO2 contact with brine and improve the solubility and residual trapping and the overall aquifer storage potential. We examine two optimization methods: directly maximizing the total stored gas in the aquifer, and maximizing the sweep efficiency of the CO2 flood to promote uniform displacement in all directions. We consider the effect of geologic uncertainty on the performance of the controlled injection schemes by using an ensemble of model realizations to represent the uncertainty in aquifer property distribution. We also show how a controlled injection can be used to mitigate the risk of leakage from potential pathways, such as an abandoned well, by restricting CO2 movement toward the leakage zone. Our results suggest that controlled injection can lead to substantial improvements in residual and dissolution trapping and can be used to divert a CO2 plume from approaching sensitive zones or leakage pathways.

4D imaging of fracturing in organic-rich shales during heating

To better understand the mechanisms of fracture pattern development and fluid escape in low permeability rocks, we performed time-resolved in situ X-ray tomography imaging to investigate the processes that occur during the slow heating (from 60 to 400 C) of organic-rich Green River shale. At about 350 C cracks nucleated in the sample, and as the temperature continued to increase, these cracks propagated parallel to shale bedding and coalesced, thus cutting across the sample. Thermogravimetry and gas chromatography revealed that the fracturing occurring at {approx}350 C was associated with significant mass loss and release of light hydrocarbons generated by the decomposition of immature organic matter. Kerogen decomposition is thought to cause an internal pressure build up sufficient to form cracks in the shale, thus providing pathways for the outgoing hydrocarbons. We show that a 2D numerical model based on this idea qualitatively reproduces the experimentally observed dynamics of crack nucleation, growth and coalescence, as well as the irregular outlines of the cracks. Our results provide a new description of fracture pattern formation in low permeability shales.

Methane contamination of drinking water caused by hydraulic fracturing remains unproven

Shale gas extraction involves the drilling of organic-rich, low-permeability shale and then stimulation of hydraulic fractures that allows gas to be produced. Methane in aquifers located above the shale strata, for instance, in Pennsylvania, United States, has been attributed by some to be the result of contamination caused by the hydraulic fracturing process. The work by Osborn et al. (1) described geochemical data from 68 drinking water wells in northeastern Pennsylvania and upstate New York and evaluated whether the aquifers that the water wells penetrated were contaminated with thermogenic methane sourced from the underlying Marcellus and Utica shale formations. The work by Osborn et al. (1) concluded that contamination had occurred and that the contamination accompanied gas well drilling and hydraulic fracturing. The inference from the text and title of the paper is clear—hydraulic fracturing had a role. However, the evidential basis for implicating this specific process is not sound and needs to be closely scrutinized.