A new correlation to evaluate the fracture permeability changes as reservoir is depleted (original) (raw)
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Rock Mechanics and Rock Engineering, 2018
Shale gas has recently gained significant attention as one of the most important unconventional gas resources. Shales are fine-grained rocks formed from the compaction of silt-and clay-sized particles and are characterised by their fissured texture and very low permeability. Gas exists in an adsorbed state on the surface of the organic content of the rock and is freely available within the primary and secondary porosity. Geomechanical studies have indicated that, depending on the clay content of the rock, shales can exhibit a brittle failure mechanism. Brittle failure leads to the reduced strength of the plastic zone around a wellbore, which can potentially result in wellbore instability problems. Desorption of gas during production can cause shrinkage of the organic content of the rock. This becomes more important when considering the use of shales for CO 2 sequestration purposes, where CO 2 adsorption-induced swelling can play an important role. These phenomena lead to changes in the stress state within the rock mass, which then influence the permeability of the reservoir. Thus, rigorous simulation of material failure within coupled hydro-mechanical analyses is needed to achieve a more systematic and accurate representation of the wellbore. Despite numerous modelling efforts related to permeability, an adequate representation of the geomechanical behaviour of shale and its impact on permeability and gas production has not been achieved. In order to achieve this aim, novel coupled poro-elastoplastic analytical solutions are developed in this paper which take into account the sorption-induced swelling and the brittle failure mechanism. These models employ linear elasticity and a Mohr-Coulomb failure criterion in a plane-strain condition with boundary conditions corresponding to both open-hole and cased-hole completions. The post-failure brittle behaviour of the rock is defined using residual strength parameters and a non-associated flow rule. Swelling and shrinkage are considered to be elastic and are defined using a Langmuir-like curve, which is directly related to the reservoir pressure. The models are used to evaluate the stress distribution and the induced change in permeability within a reservoir. Results show that development of a plastic zone near the wellbore can significantly impact fracture permeability and gas production. The capabilities and limitations of the models are discussed and potential future developments related to modelling of permeability in brittle shales under elastoplastic deformations are identified.
GEOPHYSICS, 2006
Equivalent-medium theories can describe the elastic compliance and fluid-permeability tensors of a layer containing closely spaced parallel fractures embedded in an isotropic background. We propose a relationship between effective stress ͑background or lithostatic stress minus pore pressure͒ and both permeability and elastic constants. This relationship uses an exponential-decay function that captures the expected asymptotic behavior, i.e., low effective stress gives high elastic compliance and high fluid permeability, while high effective stress gives low elastic compliance and low fluid permeability. The exponential-decay constants are estimated for physically realistic conditions. With relationships coupling pore pressure to permeability and elastic constants, we are able to couple hydromechanical and elastodynamic modeling codes. A specific coupled simulation is demonstrated where fluid injection in a fractured reservoir causes spatially and temporally varying changes in pore pressure, permeability, and elastic constants. These elastic constants are used in a 3D finite-difference code to demonstrate time-lapse seismic monitoring with different acquisition geometries. Changes in amplitude and traveltime are seen in surface seismic P-to-S reflections as a function of offset and azimuth, as well as in vertical seismic profile P-to-S reflections and in crosswell converted S-waves. These observed changes in the seismic response demonstrate seismic monitoring of fluid injection in the fractured reservoir.
International Journal of Rock Mechanics and Mining Sciences, 1997
Faults, and composite fault and joint networks are common structural and hydrologic elements in reservoirs. The structural and hydrologic architecture of faults is complicated by the formation of striated slip surfaces, cataclasite and gouge, deformation of the adjacent wall rock, and hydrothermal mineralization. A prototype, analytical computer algorithm is presented to model faults as anisotropic fluid conduits, and joints as isotropic conduits. The permeability tensor of the rock mass is determined by the volume averaged contribution of each fault and joint in the population via tensor rotation from the local coordinate system of each fracture to the global, geographic reference frame. Permeability across the fracture walls and the permeability of the rock matrix are also considered in the algorithm. Application to a synthetic network of conjugate fractures illustrates that the anisotropic surface texture of faults is a fundamental feature determining the permeability of the rock mass. Modeling is also conducted to illustrate how changes in the stress tensor affect permeability anisotropy.
Fracture-permeability behavior of shale
Journal of Unconventional Oil and Gas Resources, 2015
The fracture-permeability behavior of Utica shale, an important play for shale gas 6 and oil, was investigated using a triaxial coreflood device and x-ray tomography in combination 7 with finite-discrete element modeling (FDEM). Fractures were generated in both compression 8 and in a direct-shear configuration that allowed permeability to be measured across the faces of 9 cylindrical core. Shale with bedding planes perpendicular to direct-shear loading developed 10
Characterizing natural fractures productivity in tight gas reservoirs
Journal of Petroleum Exploration and Production Technology, 2012
Tight formations normally have production problems mainly due to very low matrix permeability and various forms of formation damage that occur during drilling completion and production operation. In naturally fractured tight gas reservoirs, gas is mainly stored in the rock matrix with very low permeability, and the natural fractures have the main contribution on total gas production. Therefore, identifying natural fractures characteristics in the tight formations is essential for well productivity evaluations. Well testing and logging are the common tools employed to evaluate well productivity. Use of image log can provide fracture static parameters, and welltest analysis can provide data related to reservoir dynamic parameters. However, due to the low matrix permeability and complexity of the formation in naturally fractured tight gas reservoirs, welltest data are affected by long wellbore storage effect that masks the reservoir response to pressure change, and it may fail to provide dual-porosity dual-permeability models dynamic characteristics such as fracture permeability, fracture storativity ratio and interporosity flow coefficient. Therefore, application of welltest and image log data in naturally fractured tight gas reservoirs for meaningful results may not be well understood and the data may be difficult to interpret. This paper presents the estimation of fracture permeability in naturally fractured tight gas formations, by integration of welltest analysis results and image log data based on Kazemi's simplified model. Reservoir simulation of dual-porosity and dual-permeability systems and sensitivity analysis are performed for different matrix and fracture parameters to understand the relationship between natural fractures parameters with welltest permeability. The simulation results confirmed reliability of the proposed correlation for fracture permeability estimation. A field example is also shown to demonstrate application of welltest analysis and image log data processing results in estimating average permeability of natural fractures for the tight gas reservoir.
Experimental study of permeability change of organic-rich gas shales under high effective stress
Journal of Natural Gas Science and Engineering, 2019
Shale permeability and its variation under high stress are vital for gas production from deep shale gas reservoirs. Most experiments of stress-dependent permeability for organic-rich shale were conducted under lower stress less than 40 MPa, therefore, shale permeability evolution under high stress is not clear. In this work, the effects of high stress on the permeability and fracture compressibility of shales were investigated experimentally. Moreover, the impact of stress cycling on permeability were also studied. Four shale samples including two intact samples and two fractured samples from Cambrian Niutitang Shale formation and Silurian Longmaxi Shale formation were used. Permeability was measured using Helium under different stress conditions, including different confining pressure, different gas pressure, and constant effective stress. The highest effective stress and gas pressure in this work was 59.5 MPa and 10 MPa, respectively. Fracture compressibilities were calculated using the stress-dependent permeability data. The results show that the permeability of the intact samples and fractured samples decreased by one order of magnitude and three orders of magnitude, respectively, with the effective stress changing from 1.5 MPa to 59.5 MPa. The shale permeability results show a two-stage characteristic and nonlinearly decreasing trend with the increase of effective stress, demonstrating that the fracture compressibility is stress dependent and decreases with stress. The permeability hysteresis occurs between the loading and unloading cycles due to the inelastic compression of the pore. The modelling results also show that the Klinkenberg constant show a positive correlation with effective stress, as effective stress reduces the fracture opening and absolute permeability.
Pore Pressure and Fracture Pressure Analyses in Non-consolidated Rocks
2001
Pore and fracture pressure trends were analyzed to provide recommendations and support drill-ing of deep wells in non-consolidated formations of the Gulf-of-Mexico fields (Matagorda Island and East Cameroon). The main objectives were to predict pore pressure and fracture gradient, analyze compartmentali-zation, aid to well design and control drilling in the overpressured sections. We were particularly interested in understanding the role of diagenetic changes and tectonic activities (faulting) that control (enhance/damage) the sealing properties of shales. Faulting is an important mechanism in forming of the overpressured zones, but on the other hand it can partially destroy shale sealing properties. These two different events were ob-served in the Gulf-of-Mexico area and thoroughly documented. Assessment of both examples allows defining an influence of particular fault and predicting formation pressure with more confidence
Energies
Permeability prediction in hydrocarbon production is an important task. The decrease in permeability due to depletion leads to an increase in the time of oil or gas production. Permeability models usually are obtained by various methods, including coreflooding and the field testing of wells. The results of previous studies have shown that permeability has a power-law or exponential dependence on effective pressure; however, the difficulty in predicting permeability is associated with hysteresis, the causes of which remain not fully understood. To model permeability, as well as explain the causes of hysteresis, some authors have used mechanical reservoir models. Studies have shown that these models cannot be applied with small fluctuations in effective pressures in the initial period of hydrocarbon production. In this work, based on the analysis of well test data, we came to the conclusion that in the initial period of production under constant thermobaric conditions, the permeabilit...
Estimating compressibility of complex fracture networks in unconventional reservoirs
International Journal of Rock Mechanics and Mining Sciences, 2020
Previous studies show that fracture closure is the primary drive mechanism for fracture cleanup during flowback process in hydraulically stimulated reservoirs. Estimating fracture compressibility is practically essential to calculate effective fracture volume, evaluate fracture volume change, and forecast ultimate hydrocarbon recovery. However, limited experimental data are available for evaluating compressibility of fracture networks in unconventional reservoirs. In this paper, we categorize induced fractures into unpropped and propped fractures, and estimate their compressibilities from fracture conductivity measurements and Hertzian contact theory, respectively. We also investigate the effects of rock and proppant parameters on fracture compressibility. Finally, we propose a workflow to estimate compressibility of complex fracture networks and investigate the roles of propped and unpropped fractures during fracture closure. The results show that fracture compressibility depends on how fracture porosity and aperture change with effective stress. For propped fractures, the rate of porosity change primarily controls fracture compressibility. In addition, compressibility of complex fracture networks approximates that of unpropped fractures at low effective stress and that of propped fractures at high effective stress. Overall, the results highlight the role of unpropped fractures in hydrocarbon recovery from stimulated unconventional reservoirs.