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Light hydrocarbons produced from unconventional tight shale reservoirs with matrix permeability in nano-Darcy range accounts for more than half of the petroleum production in the United States in the past several years. This has been enabled mainly by the drilling of long horizontal wells coupled with extensive hydraulic fracturing. A typical fracturing job for a horizontal well requires two to five million gallons of water which imposes significant challenges in many areas of the world that lack water resources. In addition, treatment and disposal of produced fracturing fluids can be expensive and may negatively impact the environment. Here we show a ‘water-free’ stimulation method to produce light hydrocarbons from the extremely tight reservoirs using electromagnetic (EM) waves to heat the formation and elevate pore-water pressure. We demonstrated in the laboratory that microwave heating pulverized shales and other tight rocks without confinement and generated extensive fractures within shales with 15 MPa isotropic confinement pressures. Our calculation indicates that for typical shale reservoirs pore-water pressure can increase to 90 MPa or higher that is sufficient to stimulate the formation for production with a less than 100 °C temperature increase of the reservoir. Using a simplified coupled model of EM heating and thermal diffusion, we estimated that with practically reasonable amount of power input the EM heating can stimulate a sufficiently large volume of tight reservoirs to produce light hydrocarbons.

The pressure pulse-decay test has been one of the most widely used techniques to measure permeability for low-permeability rocks including shale, largely because relatively simple analytical solutions to fluid flow in a rock sample (characterized as a single continuum) exist for analyzing late-time test data. This work develops a new analytical solution for analyzing late-time pulse-decay test data for dual-continuum rock samples, motivated by the possibility that shale matrix (not including fractures) may exhibit dual- or multiple-continuum gas-flow behavior owing to its wide spread pore size distributions and property differences between organic and inorganic components of the shale matrix. This issue has important implications for characterizing and modeling gas flow in shale, because a dual-continuum medium involves more flow parameters and requires more complex modeling approaches than a single-continuum medium. Our new analytical solution shows that the relationship between gas pressure measurements from a pulse-decay test and permeability remains the same for both single- and dual-continuum systems, suggesting that shale-matrix permeability data in the literature, previously obtained from pulse-decay tests, are valid although the corresponding shale samples ought to be treated as dual-continuum instead of a single continuum system. In addition, our analytical solution relates mass transfer (between the two continua) to pressure change during late-time of a test. This relationship, with a clear and intuitive physical interpretation rooted in the mass balance principle, provides a simple and practical analysis technique to identify dual-continuum behavior from pulse-decay test data and to estimate mass transfer coefficient between the two continua if the dual-continuum behavior exists. The usefulness of the analytical solution is demonstrated by satisfactory matches with several pulse-decay test data sets. The data analysis results also indicate that not all shale samples exhibit dual-continuum gas-flow behavior regardless of their make-up and complex pore structures.

SummaryTensile strength is a critical parameter for hydraulic fracturing, predicting fracture initiation and propagation in reservoirs, especially in shale reservoirs with complex natural fractures and fissures. The tensile strength of conventional rocks, such as sandstone and limestone, has been well-studied and -documented. There are many studies of the tensile strength of laminated shale, which focus on scale effects, loading direction, and temperature effects; however, the studies on effects of mineralogy and the water content on tensile strength of organic-rich shales are very limited.The objectives of this paper are to (1) critically review the key parameters that affect the tensile strength of shale and 2) experimentally examine the effects of water content, mineralogy, and lamination on tensile strength. To do so, a rigorous workflow is followed: 1) Each 1-in.-long shale sample is cut into two subsamples, A and B, of similar length; (2) X-ray computed-tomography (CT) scan is performed to diagnose pre-existing cracks and defects inside the core plugs; (3) nuclear magnetic resonance (NMR) is then used to measure the air dry samples’ water content; (4) Sample A is placed on a load frame to measure the tensile strength; (5) Sample B is vacuumed and then saturated; (6) NMR is used to measure the water content after saturation; (7) tensile strength of the saturated Sample B is measured; and (8) after the sample fails, the pieces are used for X-ray diffraction (XRD), scanning electron microscopy (SEM), and pyrolysis to estimate the mineralogy and total organic content (TOC).A total of 70 Mancos and 48 Eagle Ford shale samples have been tested. The experimental results show that (1) bedding plane/lamination has a significant effect on Eagle Ford tensile strength, but no pronounced impact is observed for the Mancos shale; (2) the imbibed water significantly reduces the tensile strength by 4.4 to 51.7% as water content increases from 4.45 to 11.7%; (3) pre-existing detectable microfractures can significantly reduce the tensile strength by up to 66%; (4) Eagle Ford exhibits typical brittle hard-rock failure configuration, with primary fractures and secondary fractures being observed, whereas for the Mancos shale, only primary fractures are observed; (5) acoustic velocity-test results confirm that Eagle Ford is mechanically transversely isotropic, and Mancos is likely mechanically isotropic.

Summary Acoustic-velocity measurements are an important nondestructive way to investigate dynamic rock-mechanical properties. Water content and bedding-plane-induced anisotropy are reported to significantly affect the acoustic velocities of siliciclastic sandstones and laminated carbonates. This relationship in organic-rich shales, however, is not well-understood and has yet to be investigated. The mechanical properties of organic-rich shales are affected by changes in water content, laminations, total organic content (TOC), and microstructures. In particular, kerogen density that accompanies changes in the composition of the TOC during maturity can significantly influence the acoustic responses within source rocks. To understand how these variables influence acoustic responses in organic shales, two sets of cores from the Eagle Ford shale were investigated: one set cut parallel to bedding and the other perpendicular to bedding. Textures of the samples from each set were characterized by use of computed-tomography (CT) scanning. Nuclear magnetic resonance (NMR) was used to measure the water content, and X-ray diffraction (XRD) to analyze the mineralogy. Scanning electron microscope (SEM) was also used to characterize the microstucture. Acoustic-velocity measurements were then made on each set at various confining pressures with the ultrasonic pulse-transmission technique. The results show that confining pressure, water content, and laminations have significant impact on both compressional-wave (P-wave) and shear-wave (S-wave) velocity. Both velocities increase as confining pressure increases. Velocities measured from cores cut parallel to bedding are, on average, 20% higher than those cut perpendicular to bedding. Increasing water content decreases both velocities. The impact of water content on shear velocity was found to be significant compared with the response with compressional velocity. As a result, the water content was found to lower both Young's modulus and shear modulus, which is opposite to the reported results in conventional reservoir lithology. In addition, both P- and S-wave velocities show a linear decrease as TOC increases, and they both decrease with increasing of clay content. The mechanisms that lead to water-content alteration of rock-mechanical properties might be a combined result of the clay/water interaction, the chemical reaction, and the capillary pressure changes.

The understanding of methane adsorption is important for many industrial applications, especially for the shale gas production, where it is critical to understand the adsorption/desorption of methane in pores even as small as a few nanometers. Using small-angle neutron scattering (SANS), we have studied the adsorption of deuterated methane (CD4) into one model mesoporous material, SBA-15, with pore diameter approximately 6.8 nm at the temperature range from 20 to 295 K at low pressure (≈100 kPa). A new scattering model is developed to analyze the SANS patterns of gas adsorption in SBA-15. The surface roughness of the SBA-15 matrix is estimated. The gas adsorption behaviors on the surface regions are extracted from the fitting. The rough surface of the pores is found to retain a large amount of CD4 at the temperature above the capillary condensation temperature (Tc). At temperatures below Tc, the confined liquid and solid methane are estimated to be less dense than the corresponding bulk liquid and solid m...

It is extremely challenging to measure the variation of pore surface properties in complex porous systems even though many porous materials have widely differing pore surface properties at microscopic levels. The surface heterogeneity results in different adsorption/desorption behaviors and storage capacity of guest molecules in pores. Built upon the conventional Porod’s law scattering theory applicable mainly to porous materials with relatively homogeneous matrices, here we develop a generalized Porod’s scattering law method (GPSLM) to study heterogeneous porous materials and directly obtain the variation of scattering length density (SLD) of pore surfaces. As SLD is a function of the chemical formula and density of the matrix, the non-invasive GPSLM provides a way to probe surface compositional heterogeneity, and can be applied to a wide range of heterogeneous materials especially, but not limited to, porous media and colloids, using either neutron or X-ray scattering techniques., Surface heterogeneity significantly influences the properties of porous materials, but remains extremely difficult to characterize. Here, the authors extend Porod’s scattering law from homogeneous to heterogeneous porous materials, allowing for surface variation to be non-invasively probed.

A detailed sensitivity analyses was conducted on an analog simulation model of a hydraulically fractured shale gas well to assess the effects of various controlling parameters on gas rates throughout the production life. Differentiating operational parameters from reservoir properties facilitates high grading shale gas exploration play evaluation and provides guidance to optimize gas production, and manage uncertainties associated with reservoir properties for predictive forecasting. The sensitivity analyses suggest that early-time gas rates are primarily dominated by the characteristics of stimulated rock volume (SRV), while late-time rates are controlled by reservoir properties. The learnings from sensitivity analyses were applied to predict production rates and estimated ultimate recovery (EUR) for a shale gas well in the KSA with flowback data. Early-time wellhead pressure data is very likely controlled by the effect of transient liquid loading and wellbore dynamics, and, as such, may mask the actual reservoir pressure response. While history matching the flow-back period may reduce the uncertainties associated with the quantification of SRV, wellbore dynamics, and initialization, large uncertainties in the estimates of reservoir properties remain the same. This reduces the confidence in predicting long-term production. Therefore, accurate measurement of reservoir properties before massive hydraulic fracturing, independent of history matching the early-time response, is critical for obtaining reliable predictions of gas rates and EUR.

Premature breakthrough and low sweep efficiency during waterfloods result from heterogeneity in the permeability field in a reservoir. Production wells with inflow control valves/inflow control devices (ICVs/ICDs) have the ability to reduce the water-oil ratio by shutting in flow ports with high water cut. Subsequently, this technology has been limited to a response based on detection of water breakthrough at production wells. Deep reading technologies have been reported to be successful in detecting the approaching waterfront before its breakthrough. The objective of this study is to investigate if the technology for early front detection combined with ICVs/ICDs can improve sweep efficiency in horizontal waterfloods. In this study, a synthetic horizontal well pair model is built using a black oil reservoir simulator to study performance of waterflooding in a single layer heterogeneous oil reservoir and to understand the value of information obtained from deep reading technology to control ICVs/ICDs for optimizing waterfloods. The simulation results show that using ICVs/ICDs at the horizontal production well significantly improves sweep efficiency and reduces water production. Early detection of waterfront with deep reading technologies provides incremental oil recovery. An optimum location for waterfront detection exists between the injector and the producer to improve oil production with specified injection and production constraints. Deep reading technologies may also provide valuable information about the mobility field between the well pair to reduce uncertainty in heterogeneity, which can be used to update the geological model for better history matching and forecasting production.

Acoustic velocity measurements are an important non-destructive way to investigate dynamic rock mechanical properties. Water content and bedding-plane-induced anisotropy are reported to significantly impact the acoustic velocities of siliciclastic sandstones and laminated carbonates. This relationship in organic-rich shales however is not well understood and has yet to be investigated. The mechanical properties of organic-rich shales are affected by changes in water content, laminations, total organic content (TOC), and microstructures. In particular, kerogen density that accompanies changes in the composition of the TOC during maturity can significantly influence the acoustic responses within source rocks. To understand how these variables influence acoustic responses in organic shales, two sets of cores from the Eagle Ford shale were investigated: one set cut parallel to bedding and the other perpendicular to bedding. Textures of the samples from each set were characterized using CT scanning. NMR was used to measure the water content, and XRD to analyze the mineralogy. Scanning Electron Microscope (SEM) was also used to characterize the microstucture. Acoustic velocity measurements were then made on each set at various confining pressures using the ultrasonic pulse transmission technique. The results show that confining pressure, water content and laminations have significant impact on both compressional (P-wave) and shear wave (S-wave) velocity. Both velocities increase as confining pressure increases. Velocities measured from cores cut parallel to bedding are on average 20% higher than those cut perpendicular to bedding. Increasing water content decreases both velocities. The impact of water content on shear velocity was found to be significant compared to the response with compressional velocity. As a result, the water content was found to lower both Young's modulus and shear modulus, which is opposite to the reported results in conventional reservoir lithology. In addition, both P- and S- wave velocities show a linear decrease as TOC increases, and also they both decrease with increasing of clay content. The mechanisms that lead to water content alternation of rock mechanical properties might be a combined result of the clay-water interaction, the chemical reaction, and the capillary pressure changes.

Abstract Traditional gravimetry applications are mining/oil exploration surface gravity and formation bulk density borehole gravity logging. Large-scale reservoir saturation monitoring is a new gravimetry application. Substitution of oil or gas by water leads to density changes in large reservoir volumes, which causes time dependent subsurface and surface gravity field variations. This case study presents a complex multilayered reservoir time-lapse gravity data inversion problem. The customary bitmap approach requires many input parameters with a well-known inversion ambiguity. This ambiguity is in this work reduced by introducing a priori information obtained by biasing the inversion with history matched reservoir simulation output. A synthetic gravity data set was first generated by forward gravity modeling using the simulation saturation output from an onshore giant Middle Eastern oil field. By analyzing the simulation saturation data, the reservoir layer specific behavior of the water saturation and oil-water flood front was understood and used as a priori input in the optimized inversion algorithm used to fine-tune the predicted location of the oil-water flood front on the basis of the synthetic gravity data. Numerical examples with associated graphics demonstrate how inversion and accuracy estimates work for this data set. The proposed inversion technique will depict differences from the history matched simulation saturation and the gravity data; therefore, actual field gravity data will allow the enhancement of the reservoir simulation history match precision. The presented inversion of time-lapse gravity data demonstrates a substantial potential for the 4D microgravity. Since borehole gravity sensors are less affected by near surface changes, the borehole gravity data has significantly improved spatial resolution and much higher measured ? in the gravity signal resulting from the fluid substitution of hydrocarbons by water. In the presented inversion work, the maximum synthetic time-lapse ? gravity signal at the top reservoir was 18 times greater in magnitude compared to the predicted maximum surface time-lapse gravity signal amplitude. For microgravity to be a serious alternative for inter-well hydrocarbon saturation mapping for oil fields under waterflood, the borehole microgravity hardware development needs to be given significant R&D priority to reduce the diameter of the borehole gravity tool and improve gravity meter precision for both surface and borehole sensors. Introduction Geology and reservoir engineering describe the subsurface reservoir by utilizing sparse well data. As only a very small fraction of the subsurface can be observed through cores, well logs and well production data, the inter-well reservoir characterization is very challenging, especially in heterogeneous or fractured reservoirs, where simply interpolating wellbore data is not adequate to infer fluid distribution. At present, dynamic changes between wellbore control points is only understood via matching reservoir simulation models to reproduce the acquired well data. In the Journal of Petroleum Technology (JPT) May 2011 issue, the Society of Petroleum Engineers (SPE) Research & Development (R&D) Committee defined the five grand R&D challenges facing the oil and gas industry (Judzis et al. 2011), which included higher resolution subsurface imaging of hydrocarbons. In a follow-up JPT article, Neal and Krohn (2012) identified the most advanced technology options offering a solution to the inter-well hydrocarbon mapping problem as:3D/4D Seismic: surface, borehole and cross-well acquisition;Electromagnetic: borehole to surface and crosswell;Microgravity: borehole and surface acquisition; andNanotechnology.