This paper presents a theoretically rigorous correlation of the effect of poroelasticity on pressurization/depressurization hysteresis of stress-dependent porosity and permeability of shale reservoirs. Naturally fractured shale formations are characterized as a matrix-fracture system. The constituents of this model are individually described by their own stress-dependent properties which are then coupled to determine the overall stress-dependent response of the shale system. This model accounts for the deformation, transformation, deterioration, and collapse of the shale pore structure during pressurization and depressurization processes and their effect on the porosity and permeability of shale reservoirs. The comprehensive model developed in this study is then validated by means of the experimental data gathered by testing of samples from various shale and sandstone reservoirs. The phenomenological parameters of the shale and sandstone samples are determined for best match of the experimental data. The data analyzed in this study indicates that pressurization/depressurization hysteresis has a significant effect on the stress-dependent porosity and permeability of shale reservoirs. The model developed in this paper can describe the stress-dependent porosity and permeability of shale rock more accurately than the commonly used empirical correlations.
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Transport of gas in nano-permeability shale-gas reservoirs involves complex processes of absorption, adsorption, poroelasticity, alterations of gas properties by pore-confinement, and significant deviations from Darcy-type flow. While recent modifications of Darcy’s law can account for molecular transport in shale depending on the Knudsen conditions, they nevertheless omit the corrections due to convective acceleration and inertial flow occurring through natural fractures and induced fractures formed by hydraulic fracturing and the threshold pressure gradient below which reservoir fluids cannot flow. This paper presents a physically rigorous modeling of shale-gas transport by considering the relevant effects in nanopores and fractures to derive a proper gas storage and transport model. This provides an improved model accounting for complex transport processes in organic and inorganic materials intersected by natural and induced fractures. A non-Darcy equation, comprehensive gas storage model, and quantification of relevant parameters are developed. The model is used to simulate gas transport in laboratory shale-core tests conducted under near-real shale-gas reservoir conditions.
Determination of the nanodarcy gas permeability and other parameters of naturally and hydraulically fractured shale formations by pressure-pulse transmission testing of core plugs, drill cuttings, and crushed samples is discussed. The methods available for interpretation of pressure tests are reviewed and modified with emphasis on difference between the intrinsic and apparent permeability. Improved formulations and analysis methods which honor the relevant physics of fluid and transport, and interactions with shale are presented. Better design and analysis of experiments for simultaneous determination of several unknown parameters that impact the transport calculations, including deformation, adsorption, diffusion, and deviation from Darcy flow are described. The permeability and other parameters of shale samples are recommended to be determined by simultaneous analysis of multiple pressure tests conducted under different conditions to accommodate for temporally and spatially variable conditions. The inherent limitations of the methods relying on the analytical solutions of the diffusivity equation based on the Darcy’s law are explained.
The permeability measured using a Darcy-like equation is not the intrinsic permeability but the apparent permeability which depends on the prevailing conditions of fluid, transport, and shale. The intrinsic permeability of shale depends on the temperature and effective stress conditions and therefore the conditions of a particular intrinsic value should also be specified. The primary reason for the contradictory values of permeability measured by application of the analytical models is explained by dependence of measured permeability of shale on particular testing conditions over which only a certain average permeability value is obtained from most analytical solutions.
Crushed samples have different size particles. The permeability of a particle depends on its size. Large particles are likely to have both the matrix porosity and fracture porosity. Consequently, it is not correct to assume all the particles of different sizes to have the same permeability. Whereas, most attempts in calculating the permeability using the pressure tests on crushed samples assume the same permeability for all particles. This assumption can only be applicable for samples of uninform particle sizes.
Transport of gas in extremely-low permeability shale-gas reservoirs involves complex processes of absorption, adsorption, and pore-confinement effect in nanopores; significant deviations occur from Darcy-type flow; and gas properties such as real gas deviation factor and viscosity are significantly altered compared to conventional reservoir conditions. This paper presents a physically rigorous modeling of shale gas transport by considering the various effects of importance in nanopores to derive the proper equations of gas storage and transport, and to demonstrate various applications of practical interest. First, previous approaches are critically reviewed to delineate their outstanding features and shortcomings. Then, a non-Darcy gas transfer equation, comprehensive gas storage model, and quantification of the relevant parameters including permeability are developed. Next, the improved model is used to simulate gas transport in laboratory tests conducted under near-real shale-gas reservoir conditions. Improved non-Darcy nanopore gas storage and flow model describes the shale gas transport properly and can be used satisfactorily in shale-gas reservoir simulation.
Although the theory of gas transport through extremely narrow flow paths in porous media have been reasonably well established, the analyses of experimental data have not been quite successful judging by the results reported in the literature. For example, Javadpour (2009) had to adjust the values of three empirical parameters to be able to achieve a matching of experimental data. Darabi et al. (2012) applied the apparent permeability function (APF) concept which was originally formulated by Ertekin et al. (1986). Darabi et al. (2012) also have three adjustable parameters. Unique determination of these three adjustable parameter values is questionable. Because of the error as pointed out in this paper, the model given by Javadpour (2009) did not match the measured data. The simulation results presented by Roy et al. (2003) and Veltzke and Thöming (2012) also deviate significantly from their own experimental data. These papers attempted to determine the values of their adjustable parameters using only one set of experimental data. Civan et al. (2012) explained that “one must run a minimum number of tests that is more than the number of adjustable parameters with the same system but conducted under different conditions to achieve uniqueness.”
Engineering and economic optimization of the value of water as an essential commodity and successful management of the overall water cycle are of great interests for the petroleum industry. The general objective is to maximize the benefits and safety in the utilization of water during the oil and gas production operations including for shale reservoirs while minimizing the environmental impact and the cost of operations. Accomplishing this objective requires scientifically guided and engineering prudent approaches. This paper provides a comprehensive overview of the various issues of critical importance in optimal management of the water cycle in the oil and gas fields. The present general discussion focuses on a review and an integrated analysis of the water resources, considering the issues of availability, characterization, production, processing, transportation, storage, disposal, reinjection, and utilization for production from the hydrocarbon-bearing reservoirs with their associated energy involvement and environmental safety requirements.
Exploring the most engineering, economic, and environmentally effective strategies for beneficial utilization of field water resources and optimization of the water cycle in reservoir operations and petroleum production systems requires a comprehensive understanding of the overall field water resources and issues of relevance for proper characterization and processing of water. This paper provides a concise and complete review of the water handling issues of practical importance by including some highlights from the available literature and the previous invited presentations of the author (Civan, 2012, 2013, 2014a, b). An overview of the technical and environmental issues of practical importance in dealing with balancing between the various water resources, water utilization options, regulations and measures, and efforts for informing and educating the public is provided in a concise manner.
Water involving the petroleum field operations is examined in two categories: Natural water sources (availability, accessibility, aquifer, ground, sea, compatibility, and injectivity) and wastewater (generation, quality, quantity, and composition in drilling, completion, and production). Water processing issues are reviewed in terms of three aspects: Water characterization (present and required quality), treatment methods (in-situ and surface, parameters, quality, capacity, separated materials and sludge), and equipment (gas/liquid/particulate separation, storage, transportation, and measurement).
This paper proposes that the crushed-sample permeability can match the core plug permeability measurements when tests are repeated with sufficient number of different mesh size crushed samples instead of relying on a single mesh size sample testing and then extrapolating the results to the representative bulk volume size of shale formations. The formulations necessary for this approach are developed by considering the averaging of the matrix and fracture porosities over the crushed sample particle volumes and the non-Darcy behavior and adsorption of real gasses under the pore-proximity effects.
Reservoir heterogeneity with high permeability zones attributed to channels, fractures, and large pore spaces can cause high water production in hydrocarbon producing wells. This paper investigates the performance of several particle-gel systems for near-wellbore (NWB) formation treatment to prevent or control the water production in mature oil fields. The particle-gel system consists of a polymer/crosslinker as the gel and silica flour as the particles that provide leakoff control. Fluid loss testing was conducted using sands of varying sizes and permeable filter disks, where the sand represents a gravel pack and the disk represents the formation. The filtrate volume was measured to determine the leakoff under different treatment and formation conditions. Effects of particulate concentration, pore space of the permeable filter disk, sand size, and temperature on the leakoff volume and the threshold-pressure, which must be overcome to initiate water flow, were studied. The experimental results reveal that filtrate loss decreases with increasing silica flour concentration and increases with increased pore size of the permeable filter disk, sand particle size, and temperature while the threshold pressure increases with increased silica flour concentration and decreases with increased sand particle size, pore size of the permeable filter disk, and temperature. Practical empirical correlations and charts are developed for fluid loss, pressure initiation for flow, and the critical silica flour concentration which can aid in selection of a suitable particle-gel system for effective NWB formation treatment. A methodology using these correlations and charts is presented for the design of optimal conformance control treatments for effective mitigation of water production in mature oil fields. A field case is also illustrated to demonstrate the importance of the developed empirical correlations in choosing suitable treatment fluids and evaluating the near-wellbore formation treatment under optimum application conditions.
Determination of the nanodarcy gas permeability and other parameters of shale by pressure-pulse transmission testing of core plugs, drill cuttings, and crushed samples is discussed. The methods available for interpretation of pressure-pulse decay tests are reviewed with emphasis on the difference between the intrinsic and apparent permeability. Improved formulation and analysis which honor the relevant physics of gas transport and interactions of flowing gas with the shale under the pore-proximity and elevated pressure conditions are presented. Modification of the shale and fluid properties under prevailing stress, and pore-size distribution, connectivity, and confinement conditions is shown to be important under any pressure conditions while the gas rarefaction and slippage effects diminish essentially at high pressures but become important at low pressures. The permeability and other parameters of shale samples are determined by numerical modeling and analysis of the pressure tests conducted under different conditions in order to accommodate for temporally and spatially variable conditions. Better design and analysis of experiments for simultaneous determination of several unknown parameters that impact transport calculations, including stress-deformation, adsorption, diffusion, and deviation from Darcy flow are described. The inherent limitations of the earlier methods which rely on the approximate analytical solutions of the simplified diffusivity equation based on the Darcy’s law are delineated. It is pointed out that the permeability measured using a Darcy-type equation is the apparent permeability and not the intrinsic permeability. Thus, the primary reason for the contradictory values of permeability measured by application of the analytical models is explained by dependence of the permeability of shale to different testing conditions over which only different average permeability values can be obtained when applying the approximate analytical solutions obtained based on the assumption of a constant permeability value.
Permeability cannot be measured directly; rather it is inferred by interpretation of experimental data using appropriate models. For this purpose, some experimental pressure and sometimes flow data are generated by inducing gas transport through porous materials and then the permeability is determined by adjusting a set of model parameters to match the measured data. Laboratory measurements need to be sufficiently representative of the in-situ conditions or alternatively, interpretation models (such as provided by Civan et al., 2011, 2012) need to provide the means to correct for any deviations or errors. Laboratory permeability measurements can be acquired using core plugs, drill cuttings, or crushed samples. A typical measurement method is transient-state pressure-pulse transmission. Permeability values obtained in this way depend on the measurement conditions and data interpretation methods and therefore the measurements of permeability reported by various laboratories may not necessarily agree.