Low Permeability Shale Research Articles

Effect of water and nitrogen fracturing fluids on initiation and extension of fracture in hydraulic fracturing of porous rock

An improved fracture initiation pressure criterion based on the initiation criterion of the mode I crack is proposed to interpret the different phenomena induced by water and nitrogen fracturing fluids. Hydraulic fracturing experiments on sandstone, coal and shale cores are performed using water and nitrogen to investigate the effects of the rock type and fracturing fluid type on the fracture initiation pressure and to verify the improved initiation pressure criterion. The crack propagation process and extended fracture complexity are also investigated based on hydraulic fracturing experiments. The sensitivity of the key parameter to the crack initiation pressure is explored using the improved initiation pressure criterion. The results show that the improved initiation pressure criterion is reliable. Nitrogen fracturing fluid can effectively reduce the fracture initiation pressure of rock compared with water, especially for low permeability shale. Micro-crack initiation occurs more easily before failure and the crack extension process is more violent in nitrogen fracturing. In water fracturing, a single fracture is induced, but complex fractures including tortuous and multiple fractures are produced in nitrogen fracturing. The extended fracture complexity in nitrogen fracturing is more likely to be affected by the lithologic character of rock compared with water fracturing. From the parameter sensitivity study, there are upper and lower limits on the permeability of shale causing pressurization rate to have a significant impact on the fracture initiation pressure. The upper and lower limits of permeability for nitrogen are four orders of magnitude greater than those for water. In the affected range of permeabilities, whether the fracturing fluid is water or nitrogen, changes in the fracture initiation pressure with the increase of the pressurization rate show an approximately logarithmic increase, linear increase and exponential increase in order of increasing permeability.

Element release and reaction-induced porosity alteration during shale-hydraulic fracturing fluid interactions

The use of hydraulic fracturing techniques to extract oil and gas from low permeability shale reservoirs has increased significantly in recent years. During hydraulic fracturing, large volumes of water, often acidic and oxic, are injected into shale formations. This drives fluid-rock interaction that can release metal contaminants (e.g., U, Pb) and alter the permeability of the rock, impacting the transport and recovery of water, hydrocarbons, and contaminants. To identify the key geochemical processes that occur upon exposure of shales to hydraulic fracturing fluid, we investigated the chemical interaction of hydraulic fracturing fluids with a variety of shales of different mineralogical texture and composition. Batch reactor experiments revealed that the dissolution of both pyrite and carbonate minerals occurred rapidly, releasing metal contaminants and generating porosity. Oxidation of pyrite and aqueous Fe drove precipitation of Fe(III)-(oxy)hydroxides that attenuated the release of these contaminants via co-precipitation and/or adsorption. The precipitation of these (oxy)hydroxides appeared to limit the extent of pyrite reaction. Enhanced removal of metals and contaminants in reactors with higher fluid pH was inferred to reflect increased Fe-(oxy)hydroxide precipitation associated with more rapid aqueous Fe(II) oxidation. The precipitation of both Al- and Fe-bearing phases revealed the potential for the occlusion of pores and fracture apertures, whereas the selective dissolution of calcite generated porosity. These pore-scale alterations of shale texture and the cycling of contaminants indicate that chemical interactions between shales and hydraulic fracturing fluids may exert an important control on the efficiency of hydraulic fracturing operations and the quality of water recovered at the surface.

Understanding hydraulic fracturing: a multi-scale problem.

Despite the impact that hydraulic fracturing has had on the energy sector, the physical mechanisms that control its efficiency and environmental impacts remain poorly understood in part because the length scales involved range from nanometres to kilometres. We characterize flow and transport in shale formations across and between these scales using integrated computational, theoretical and experimental efforts/methods. At the field scale, we use discrete fracture network modelling to simulate production of a hydraulically fractured well from a fracture network that is based on the site characterization of a shale gas reservoir. At the core scale, we use triaxial fracture experiments and a finite-discrete element model to study dynamic fracture/crack propagation in low permeability shale. We use lattice Boltzmann pore-scale simulations and microfluidic experiments in both synthetic and shale rock micromodels to study pore-scale flow and transport phenomena, including multi-phase flow and fluids mixing. A mechanistic description and integration of these multiple scales is required for accurate predictions of production and the eventual optimization of hydrocarbon extraction from unconventional reservoirs. Finally, we discuss the potential of CO2 as an alternative working fluid, both in fracturing and re-stimulating activities, beyond its environmental advantages.This article is part of the themed issue 'Energy and the subsurface'.

Three-dimensional investigation of multiple stage hydraulic fracturing in unconventional reservoirs

Production efficiency from low permeability shale reservoirs demands promoting techniques including horizontal well drilling and multiple hydraulic fracture stimulation. What significantly affects the fracture patterns and associated geometries is the stress field changes induced by pre-existing or simultaneous fractures, depending on proposed hydraulic fracturing scenarios. Devising a reliable and robust simulation tool for hydro-mechanical modeling of hydraulic fracturing is imperative inasmuch as an appropriate fracturing job in a porous medium cannot be extended to another owing to various characteristics and limited access to the field data acquisition. In order to present a numerical technique, which is capable of capturing the non-planar hydraulically fluid-driven crack propagation with unpredictable path, in one hand, and tackling the feasible emergence of multiple cohesive cracks in a porous medium with fracture process zone at the crack tip, on the other hand, the Cohesive segments method in combination with Phantom Node Method, called CPNM herein, is established to simulate 3-D non-planar hydraulically driven fracture problem in a quasi-brittle shale medium. The present simulation fully couple fracturing fluid flow inside the crack with poro-elasticity in porous formation and continuum-based leak-off on the crack surfaces, and capture the fracture process zone at the fracture tip in quasi-brittle shale. In this paper, two different key scenarios including sequentially and simultaneously multiple hydraulic fracturing in a quasi-brittle shale multi-layer are investigated by using CPNM. The interesting and new results show that later stages in sequentially hydraulic fracturing mainly secure larger values of fracture opening than that of simultaneously hydraulic fracturing, which can be attributed to the effect of stress interactions of fractures on each other. Detailed parametric studies shed new light on the impacts of pre-existing or simultaneous fluid-driven fractures on the pore pressure of the formation, crack propagation pattern, von Mises stresses, fracture opening, leak-off flow rate, and fracturing fluid pressure.

Poroelastic Dual-Porosity/Dual-Permeability After-Closure Pressure-Curves Analysis in Hydraulic Fracturing

SummaryThe dual-porosity and dual-permeability theory of poroelasticity is used to analyze the wellbore dual-pressure responses of dual-porosity or naturally fractured formations. The pressure decline is analyzed by modeling the dual-pressure regimes of the dual-porosity/dual-permeability medium during the after-closure phase of hydraulic fracturing. The analysis shows that both the matrix and natural-fracture permeability, as well as the developed-fracture length, can be estimated on the basis of the obtained pseudolinear and pseudoradial dual-pressure and dual-flow regimes.The estimations are made by use of the corresponding one-half and −1 slopes in the time-history plots of the wellbore-pressure derivative. The transition period between pseudolinear and pseudoradial regimes is also analyzed. The solution involves three time scales related to the rate of fluid flow through and in between the matrix and fractures network. Findings indicate the possible emergence of an additional −½ slope in the log-log pressure-derivative plot of low-permeability shale formations. It is further shown that the transient-pressure response of the formation could be calibrated by incorporating an appropriate interporosity flow coefficient as a measure of the linear-fluid-exchange capacity between the matrix and fracture porosities. The analytical expressions for the time markers of the upper limit for the pseudolinear regime, lower limit for the pseudoradial regime, and the time at which the dip bases occur in pressure-derivative curves are given to estimate this parameter.The solution is successfully applied to and matched with a published set of field data to provide estimations for the associated reservoir properties. The field-data analysis is elaborated by a corresponding sensitivity analysis, through which the prominent poroelastic parameters of the solution are determined. Last, the definitions of conventional key parameters attributed to solutions of this type, such as formation total compressibility, storage coefficients, and hydraulic diffusivity, are reformulated by use of the presented dual-porosity poroelastic approach to the problem.

Dispersion and dissolution of a buoyancy driven gas plume in a layered permeable rock

AbstractUsing a series of simplified models, we explore the controls on the migration, dispersion and eventual dissolution of a plume of hydrogen gas which may, in principle, rise under buoyancy through a layered permeable rock if released from a Geological Disposal Facility (GDF). We show that the presence of low permeability shale barriers causes the gas to spread laterally as it rises. Averaging over the length scale of the barriers, we use expressions for the Darcy velocity of the gas to describe the dispersion of a tracer and illustrate the effect with a new experiment using a baffled Hele‐Shaw cell. While the plume is flowing, a large volume of gas may build up beneath the barriers. If the gas flux subsequently wanes, much of the gas will drain upward through the formation and spread on the upper impermeable boundary of the formation. However, a significant capillary‐trapped wake of gas may develop beneath each barrier. Owing to the low solubility of hydrogen in water and assuming relatively slow groundwater flow rates, this trapped hydrogen may require a period of tens to hundreds of thousands of years to dissolve and form a cloud of hydrogen rich water. Although simplified, these models provide a framework to assess the possible travel times and pathways of such a gas plume.

Numerical simulation of the influence of stimulated reservoir volume on in-situ stress field

In recent years, the stimulated reservoir volume is a new developing technology applied to the effective exploitation of low permeability shale gas reservoirs. Despite of its superiority and potential, the geostress field is under a complex mechanical environment during the volume fracturing process due to excessive stimulated stages, large fracturing volume, high injection capacity, and increasing dense areas of microseismic events. Based on the drilling and completion data and microseismic monitoring data of Sichuan shale gas horizontal well X201-H1, the three-dimensional finite element model of volume fracturing is established, combining fluid-solid interaction mechanics with the basic theory of rock damage mechanics. According to the established model, the finite element analysis on different fracturing conditions is carried out, which finally results in the stress distribution of near-wellbore area after each staged fracturing operation. The results show that: 1) The change of pore pressure caused by volume fracturing can generate induced stress field, which leads to the re-orientation of in-situ stress field and even the appearance of tension stress areas and zero stress areas within the region of volume fracturing stimulation. 2) The existence of stress field interference in different stages of fracturing operations leads to the change in the magnitude and direction of stress field after each staged fracturing. Research methods and results of the paper will provide guiding significance to the optimization design of staged fracturing of horizontal wells to some extent.

Investigation of Hydromechanical Mechanisms in Microseismicity Generation in Natural Fractures Induced by Hydraulic Fracturing

SummaryEconomic success in producing oil/gas from low-permeability shale often relies on pre-existing natural fractures (NFs) to be activated or connected by hydraulic-fracturing (HF) stimulation. In practice, the reactivated NF network is often identified with the microseismicity (MS) monitored during the stimulation. However, the fundamental mechanisms of MS generation and focal mechanisms inferred from geophysical analysis near HFs are not currently well-understood (e.g., it is not clear whether the MS observed in the field can be mainly attributed to local shear slip along NFs when leakoff occurs and/or induced by stress changes as a result of HF propagation or fluid leakoff). The exact slippage area and amount of slip displacement generating the microseismic event are not well-understood either, thus requiring a “bridge” between geomechanics and geophysics. To bridge this gap, a set of experiments is performed in a geomechanics laboratory to observe whether, when, where, and how the acoustic-emission events are generated during various scenarios. The experiments are designed with the guidance of the fracture-flow/discrete-element method (DEM), coupling geomechanical simulations. In this paper, the reliability and accuracy of the fracture-flow/DEM coupling approach is validated through solving a few fundamental problems and comparing the numerical-simulation results with the corresponding analytical solutions. The coupling approach is then applied to simulate and optimize two fundamental laboratory experiments. The simulations indicate that, despite the difference in the magnitude, one could induce the local slip along NFs by both fluid leakoff and stress changes.

Predicting the proportion of free and adsorbed gas by isotopic geochemical data: A case study from lower Permian shale in the southern North China basin (SNCB)

The alternating marine-terrigenous shale facies of the Lower Permian Taiyuan (P1t) formation and the Lower Permian Shanxi (P1s) formation in the north margin of the southern North China basin (SNCB) are characterized by their high TOC values (1.76–5.09%), types II and III organic matter, and high Ro values (>3.0%). Geochemical parameters of 12 gas samples from the Lower Permian shale formations from well Weican-1 were analyzed in this study. The gases are dominated by methane, with small amounts of ethane, without propane and butane. Wetness of the gas is only 0.25–0.58% reflecting extremely high maturity of the source rock. The δ13C1 values range from −31.6‰ to −26.8‰ and the δ13C2 values range from −35.9‰ to −33.2‰, the δ2HCH4 values range from −221.1‰ to −187‰. Furthermore, carbon isotopic compositions of the alkane gases from the Lower Permian shale are characterized by δ13C1>δ13C2, this indicates that the gases released from Permian shale are of thermogenic origin and mostly sourced from the continental shale and coal measures, with minor contribution from oil cracked gas from marine mudstones. Geochemical fractionation during the adsorption/desorption process of the shale system may play a significant part in influencing δ13C1 values of shale gas. The results show that the δ13C1 becomes heavier with increasing degree of gas desorption. Based on isotope fractionation during desorption of gas in shales, an equation was established to estimate the proportion of free and adsorbed gas in shales using δ13C1 of shale gas. In comparison with other equations, this equation is based on the direct data of gas desorption experiment to avoid the adsorbed gas content often exhibit maxima from excess sorption isotherms experiment. This method provides efficient way to understand the gas storage behavior in shales and broaden the application of gas isotope.

Upstream Representations for the LNG Supply Chain

Summary Gas trapped in low-permeability tight shales has become accessible with advances in horizontal drilling and new completion techniques, making liquefied natural gas (LNG) an economically feasible product marketed worldwide. This paper explores the intricacies involved in modelling upstream field development and the scenarios required to provide reasonable estimates of the upstream asset that will feed the rest of the LNG chain, including investment required, growth potential, and long-term sustainability.

Data-driven proxy at hydraulic fracture cluster level: A technique for efficient CO2- enhanced gas recovery and storage assessment in shale reservoir

The continuing development of the organic-rich and extremely low permeability shale reservoirs in the United States has the potential to positively impact the future of carbon storage. Due to the unique characteristics of shale reservoirs, not only can CO2 be safely stored, it also can be preferentially adsorbed and displace methane, leading to enhanced gas recovery.However, CO2 storage in depleted or nearly depleted shale formations is not completely risk free. Thus, prior to making the economic commitment to a full-field CO2 sequestration project, a systematic analysis of the complete set of variables must be considered in the planning of a shale-CO2 storage initiative. Numerical modeling and simulation is a robust tool that can provide an insight into how the system may operate in order to further understand the feasibility and assist in the design and operation of such a project, and to predict changes that may occur.In order to perform a comprehensive uncertainty analysis, a large number of simulation runs are required. Designing and running simulation cases to model enhanced gas recovery and storage in shale by applying the Explicit Hydraulic Fracture modeling technique (EHF) is long and laborious, and its implementation is computationally expensive.In this paper, a data-driven approach with pattern recognition algorithms is used to develop a new generation of a shale proxy model at the hydraulic fracture cluster level, as a replica of a reservoir simulation model. For more accurate analysis, instead of commonly used mechanistic models, a history-matched hydraulic fractured Marcellus shale pad with multiple stages/clusters is used as a base case to perform the analysis. The detailed procedure for development of the Data-driven proxy model is explained and the model is validated using blind simulation runs. The developed Data-driven proxy model is capable of accurately reproducing the calculated CO2 injection, CO2/CH4 production profiles, and CO2 breakthrough time from the numerical simulation model, for each cluster/stage and horizontal lateral. Joint use of the deterministic reservoir model with the Data-driven proxy model can serve as a novel screening and optimization tool for the techno-economic evaluation of the CO2-Enhanced Gas Recovery (EGR) and Storage process in shale systems.

Paleozoic-aged microbial methane in an Ordovician shale and carbonate aquiclude of the Michigan Basin, southwestern Ontario

Interest in the origin and migrational history of methane in low permeability shales reaches beyond that of resource potential to include the evaluation of such formations as geological barriers for the purposes of isolating surface environments from the impacts of deep exploitation and the deep disposal of waste. Here, we present detailed isotope and geochemical profiles of porewaters and methane from an Ordovician shale and carbonate aquiclude on the eastern flank of the Michigan Basin, where a deep geological repository for low and intermediate level nuclear waste is proposed. The solute concentrations and stable isotopes of water (δ18O and δD) indicate that this aquiclude hosts saline brine (39% TDS), originating as evaporated seawater. Methane concentrations are < 4mmol/g in the shale section, with negative δ13C and δD signatures that are consistent with archaeal methanogenesis and are accompanied by a well defined positive excursion in δ13C of CO2. Below the aquiclude, porewaters contain lower concentrations of methane with a thermocatalytic signature, consistent with regional methane elsewhere in the Michigan Basin. No evidence for archaea was identified by microcosm experiments or through PCR rRNA analysis, suggesting that the microbial methane present in these sediments is not the result of recent microbial activity. Based on these results and considering that archaeal activity has not been observed in such hypersaline brines with low water activities (< 0.75), it is concluded that the methane likely formed prior to the infiltration of hypersaline Silurian seawater. The methane has since remained in place, making it, perhaps, the oldest documented occurrence of biogenic methane. This is consistent with helium isotope data, which also suggests authigenic production and accumulation in this aquiclude since the Paleozoic.

Combustion enhance recovery of shale gas

The amount of extracted natural gas from low permeable organic rich shale has increased rapidly over the past decade. The technologies used to improve the permeability of a shale gas reservoir are horizontal drilling and hydraulic fracturing. The potential environmental impact of hydraulic fracturing motivates research aiming at alternative permeability enhancement methods. In this paper the possibility of in-situ combustion to improve permeability is investigated. Two possibilities for the in-situ fuel source are considered, viz., methane or kerogen. A one dimensional model is considered. Under simplifying hypotheses a quasi-analytical solution for the corresponding Riemann problem is obtained. The solution was analysed with parameters that correspond to resonance conditions, i.e., conditions for which the speeds of the heat wave and the combustion wave are equal. We conclude that methane combustion cannot generate enough heat to enhance the permeability. However kerogen, if present in sufficient quantities, makes this possible. We present the set of parameters for which the combustion reaches the optimal temperature to improve the permeability. Finally, the analytical approximations are validated with direct numerical simulations. The pressure distribution in the reservoir and the production improvement by the thermal treatment are calculated with the numerical model.

Improved characterization and performance prediction of shale gas wells by integrating stimulated reservoir volume and dynamic production data

Gas flow in shale gas reservoirs occurs primarily from ultra low permeability shale rocks through a complex network of natural and induced hydraulic fractures. Consequently, fracture parameters (conductivity and half length), fracture location and distribution are the dominant factors influencing well drainage volumes and shale gas well performance. Stimulated reservoir volume or SRV, estimated from microseismic event clouds or rate/pressure transient analysis, describes a measurement of overall reservoir volume impacted by fracture treatments. With SRV as well as the dynamic production/pressure response, reservoir simulation models can be calibrated to actual well performance in shale gas reservoirs leading to improved understanding, forecasting and future well placement. In this paper, we first introduce a novel approach for computing well drainage volume for shale gas wells with multistage fractures and fracture clusters. Next, we calibrate the shale gas reservoir model by matching the drainage volume with the SRV within specified confidence limits. The matching of the SRV is done in addition to the traditional history matching of production/pressure response and further constrains the estimation of fracture parameters. An evolutionary algorithm with design of experiments is used for the assisted history matching. Sensitivities to various parameters such as fracture conductivity, fracture half lengths and rock compaction have also been investigated. The proposed approach has been applied to a generic shale gas well designed after a real field case. The results clearly indicate the benefits of including SRV during history matching, leading to improved fracture/matrix parameter estimation and performance forecasting. Our proposed approach provides an important tool that can be used to optimize well placement, fracture treatments and improve the economics of shale gas plays.

Design and optimisation of multi-stage hydraulic fracturing in a horizontal well in a shale gas reservoir in the Cooper Basin, South Australia

Multi-stage hydraulic fracturing in horizontal wells is a well-known technology and is a key mechanism for gas recovery from extremely low permeable shale gas reservoirs. Since Australia’s Cooper Basin has a more complex stress regime and higher temperatures when compared to US shale gas formations, the design and optimisation of this technology in the Cooper Basin has not been explored to the authors’ knowledge. The Murteree and Roseneath shale formations in the Cooper Basin are 8,500 ft in depth and have been targets for shale gas production by different oil and gas operators. Deeper zones are difficult to fracture, as fracture gradients are often above 1 psi/ft. In this study, 1D vertical mechanical earth modelling using petrophysical log data was developed. Then, the stress profile was tuned and validated using the minimum horizontal stress from a mini-frac test taken along a vertical well. A 3D hydraulic fracture simulation in a vertical well as developed as a pilot to select the best locations for horizontal drilling. The selection criteria for the best location included the stress regime, gas flow rate and fracture geometry. Then a multi-stage fracture treatment in a horizontal well was designed. A large number of cases were simulated based on different well lengths, stage spacing and the number of stages. The productivity index was selected as the objective function for the optimisation process. The best case finally was selected as the optimum multi-stage hydraulic fracturing in a horizontal well in the Cooper Basin.

A model describing flowback chemistry changes with time after Marcellus Shale hydraulic fracturing

Between 2005 and 2014 in Pennsylvania, about 4000 Marcellus wells were drilled horizontally and hydraulically fractured for natural gas. During the flowback period after hydrofracturing, 2 to (7 to ) of brine returned to the surface from each horizontal well. This Na-Ca-Cl brine also contains minor radioactive elements, organic compounds, and metals such as Ba and Sr, and cannot by law be discharged untreated into surface waters. The salts increase in concentration to () in later flowback. To develop economic methods of brine disposal, the provenance of brine salts must be understood. Flowback volume generally corresponds to ∼10% to 20% of the injected water. Apparently, the remaining water imbibes into the shale. A mass balance calculation can explain all the salt in the flowback if 2% by volume of the shale initially contains water as capillary-bound or free Appalachian brine. In that case, only 0.1%–0.2% of the brine salt in the shale accessed by one well need be mobilized. Changing salt concentration in flowback can be explained using a model that describes diffusion of salt from brine into millimeter-wide hydrofractures spaced 1 per m (0.3 per ft) that are initially filled by dilute injection water. Although the production lifetimes of Marcellus wells remain unknown, the model predicts that brines will be produced and reach 80% of concentration of initial brines after ∼1 yr. Better understanding of this diffusion could (1) provide better long-term planning for brine disposal; and (2) constrain how the hydrofractures interact with the low-permeability shale matrix.

Numerical Investigation on Stress Shadowing in Fluid Injection-Induced Fracture Propagation in Naturally Fractured Geothermal Reservoirs

In low permeability shale reservoirs, multi-stage hydraulic fracturing is largely used to increase the productivity by enlarging the stimulated rock volume. Hydraulic fracture created alters the stress field around it, and affects the subsequent fractures by the change of the stress field, in particular, mostly increased minimum principal stress at the area of subsequent fracturing. This is called stress shadow which accumulates as the fracturing stages advance from toe to heel. Hydraulic fractures generated in such altered stress field are shorter and compact with orientation deviating significantly from the far-field maximum horizontal stress orientation. This paper presents 2D discrete element-based numerical modeling of multi-stage hydraulic fracturing in a naturally fractured reservoir and investigates stress shadowing. The stress shadowing is tested with two different injection scenarios: constant and cyclic rate injections. The results show that cyclic injection tends to lower the effect of stress shadow as well as mitigates the magnitude of the induced seismicity. Another modeling case is presented to show how the stress shadow can be utilized to optimize a hydraulic fracture network in application to Gros Schonebeck geothermal reservoir, rather than being mitigated. The modeling demonstrated that the stress shadow is successfully utilized for optimizing the geothermal heat exchanger by altering the initial in situ stress field from highly anisotropic to less or even to isotropic.

Accurate and Efficient Simulation of Fracture–Matrix Interaction in Shale Gas Reservoirs

Gas production from low-permeability shale formations relies on natural or man-made fractures for gas flow pathways to production wells. Shale gas reservoir simulation includes fracture–matrix flow and fracture–matrix interactions as they are key. Attention has focused on modeling fractures in shale gas production, yet there have been few studies carried out to address how to accurately simulate fracture–matrix interaction in unconventional low-permeability gas reservoirs. The classic double porosity model and the MINC method represent studies designed to accurately simulate fracture–matrix interaction; however, methods continue to encounter issues causing them to fall short of the accuracy sought. Applicability of the classic double porosity model with a constant shape factor to low-permeability reservoir simulation is questionable and has not been validated as the required pseudo-steady-state flow condition timing may not sufficiently satisfy shale gas reservoirs. The MINC method treats inter-porosity flow in a fully transient mode by further subdividing individual blocks with a number of 1-D nested meshes. The MINC concept, however, assumes that fracture–matrix flow is controlled only by the distance to the nearest fracture surrounding the matrix block and is shown to be no longer applicable after the early rapid transient period of fracture–matrix flow. A comparative investigation of commonly used fractured reservoir simulation approaches for applicability to fracture–matrix interaction in unconventional reservoirs is presented in this paper. A new nested subdividing concept, referred to as the Schwarz–Christoffel conformal mapping approach, will be introduced. The new method is able to accurately and efficiently simulate the matrix–fracture interaction for the entire transient flow by combining the MINC and Schwarz–Christoffel conformal mapping concepts of gridding inside the matrix. The theoretical development, benchmarking, and application of the new modeling approach explanations follow.

Determination of the continuous stress-dependent permeability, compressibility and poroelasticity of shale

The continuous changes of the stress-dependent permeability, compressibility and poroelasticity of a tight oil and gas shale were characterized by using the Constant Rate of Strain (CRS) consolidation test. The CRS consolidation test compresses a thin disk test specimen at a given constant rate of strain under one-dimensional consolidation with one-sided drainage condition and measurement of excess pore pressure at the undrained end. Permeability is calculated from the one-dimensional consolidation equation assuming oedometric loading, incompressible solid grains, and an idealized excess pore pressure distribution in the sample. The CRS test method has been widely used for the determination of the stress-dependent permeability of soft sediments, but has not been utilized for very stiff and low permeability shale as well as to obtain their stress-dependent compressibility and poroelasticity parameters. To test its appropriateness to shale, CRS tests were performed on thin disk samples of Mancos shale using a high pressure and high temperature triaxial cell under high isotropic confining stresses. Two modifications were done to make the CRS test applicable to determination of the continuous stress-dependent hydro-mechanical properties of tight shale: (1) the test method was modified for isotropic loading, and (2) nonlinear poroelastic effects were accounted for in the solution of the pore pressure dissipation equation. The permeability values from the CRS tests with the modified analytical solution were found to be in agreement with those obtained from the Constant Pressure Gradient Permeability test, and Pressure-pulse Decay Permeability test using nitrogen as pore fluid and corrected for Klinkenberg and non-Darcy flow effects.

Investigation of the influence of stress shadows on horizontal hydraulic fractures from adjacent lateral wells

Production efficiency from low permeability shale gas reservoirs requires techniques to optimize hydraulic fracture (HF) completions. This may be complicated by the presence of high horizontal in-situ stresses that result in horizontal HF, for example in parts of the Western Canadian Sedimentary Basin in northeastern British Columbia. One strategy involves the simultaneous or near simultaneous hydraulic fracturing of adjacent lateral wells to maximize the fracture network area and stimulated reservoir volume. However, changes to the in-situ stress field caused by an earlier HF on subsequent HF are not accounted for in traditional hydraulic fracturing design calculations. Presented here are the results from a set of transient, coupled hydro-mechanical simulations of a naturally fractured rock mass containing two wellbores using the discontinuum-based distinct-element method. The results demonstrate the influence of stress shadows generated by a HF on the development of subsequent HF from an adjacent well. It is shown here that these interactions have the potential to change the size and effectiveness of the HF stimulation by changing the extent of the induced fracture around the secondary well. Also, the influences of in-situ stress and operational factors on the stress shadow effect are investigated and their effects on different operational techniques are studied.