A Laboratory Method for Estimation of Storage Capacity of Rock Samples under Effective Stress

Summary Fluid storage capacity measurements of core plugs in the laboratory consider pore volume as a function of effective stress. The latter is equal to applied confining pressure – n × applied pore pressure. However, the results are often reported as a function of difference in the applied pressures, because the effective stress coefficient (n) is an unknown. This creates confusion during the interpretation of laboratory data and leads to added uncertainties in the analysis of the storage capacity of the samples under in-situ conditions. In this paper, we present a new laboratory method that allows simultaneous prediction of the sample pore volume, the coefficient of isothermal pore compressibility, and the effective stress coefficient. These quantities are necessary to predict the fluid storage as a function of effective stress. The method requires two stages of gas (helium) uptake by the sample under confining pressure and pore pressure and measures pressure-volume data. Confining pressure is always kept larger than the equilibrium pore pressure, but their values at each stage are changed arbitrarily. The analysis is simple and includes simultaneous solutions of two algebraic equations including the measured pressure-volumedata. The model is validated by taking the reference pore volume near zero stress. The reference volume predicted matches with that measured independently using the standard helium porosimeter. For sandstone, shale, and carbonate samples, the estimated pore compressibility is, on average, 10−6 psi−1. The effective stress coefficient is higher than unity and is a linear function of the ratio of the applied pressure values. We present a new graphical method that predicts the Biot coefficient (α) of the rock sample, a fundamental quantity used during the strain calculations that indicates the tendency of the rock to deform volumetrically. A new fundamental rule is found between the applied pressure difference and the effective stress: σe/α = pc − pp. Interestingly, the predicted Biot coefficient values for the shale samples show values between 0.46 and 1.0. This indicates that features of the shale sample, such as mineral variability, fine-scale lamination, and fissility, come into play during the fluid storage measurements.

Estimation of Pore Volume Compressibility in Carbonate Reservoir Rocks based on a Classification

Taking a vast range of carbonate reservoir rock from Asmari and Bangestan formations in southern Iran basins, this study examined the petrographically classification, petrological and petrophysical characteristics, and their implications on the estimation of pore volume compressibility of the carbonate reservoirs. In the current study, a method is developed to classify the carbonate reservoir rocks based on the dominant factors which is involving in elastic property of pore volumes. In order to classifying, a number of 3702 thin sections were studied. Then, the pore volume compressibility of 200 core plugs corresponding to the range of classification parameters were obtained and quantified by a pre-proven equation. The results clearly show an acceptable narrow bandwidth between the upper and lower bound of estimations based on the studied classification. Furthermore, the estimation of pore compressibility-stress relationship was in a good agreement with the experimental observations. Also, the study shows that integrating the routine petrophysical properties are useful for estimation of stress related properties of pore volumes into carbonate reservoir rocks.

Shale Poroelastic Effects on Well Performance Analysis of Shale Gas Reservoirs

The effect of poroelastic properties of the shale matrix on gas storage and transport mechanisms has gained significant attention, especially during history-matching and hydrocarbon production forecasting in unconventional reservoirs. The common oil and gas industry practice in unconventional reservoir simulation is the extension of conventional reservoir simulation that ignores the dynamic behavior of matrix porosity and permeability as a function of reservoir effective net stress. This approach ignores the significant impact of the poroelastic characteristics of the shale matrix on hydrocarbon production. The poroelastic characteristics of the shale matrix highly relate to the shale matrix geomechanical properties, such as the Young’s Modulus, Poisson’s ratio, bulk modulus, sorption behavior, total organic content (TOC), mineralogy and presence of natural fractures in the multi-scale shale structure. In this study, in order to quantify the effect of the poroelasticity of the shale matrix on gas production, a multi-continuum approach was employed in which the shale matrix was divided into organic materials, inorganic materials and natural fractures. The governing equations for gas transport and storage in shale were developed from the basic fundamentals of mass and momentum conservation equations. In this case, gas transport in organics was assumed to be diffusive, while gas transport in inorganics was governed by convection. Finally, a fracture system was added to the multi-scale shale gas matrix, and the poroelastic effect of the shale matrix on transport and storage was investigated. A modified Palmer and Mansoori model (1998) was used to include the pore compression, matrix swelling/shrinkage and desorption-induced deformation of shale organic matter on the overall pore compressibility of the shale matrix. For the inorganic part of the matrix, relations between rock mechanical properties and the pore compressibility were obtained. A dual Langmuir–Henry isotherm was also used to describe the sorption behavior of shale organic materials. The coupled governing equations of gas storage and transport in the shale matrix were then solved using the implicit finite difference approach using MATLAB. For this purpose, rock and fluid properties were obtained using actual well logging and core analysis of the Marcellus gas well. The results showed the importance of the poroelastic effect on the pressure response and rate of gas recovery from the shale matrix. The effect was found to be mainly due to desorption-induced matrix deformation at an early stage. Coupling the shale matrix gas production including the poroelastic effect in history-matching the gas production from unconventional reservoirs will significantly improve engineering completion design optimization of the unconventional reservoirs by providing more accurate and robust production forecasts for each hydraulic fracture stage.

Technogenic factors of impact on productive sediments of hydrocarbon deposits and their relation to potential deformation of the Earth’s surface

The article presents the results of the studies of the assessment of subsidence of the Earth’s surface above hydrocarbon fields, obtained by mathematical modeling and on the basis of field observations. The purpose of these studies is the substantiation of changes in the initial physical-mechanical and strength properties of productive deposits in the process of exposure to them by various methods of development, comparison of estimates of subsidence of the Earth’s surface obtained by calculation and geodetic methods, taking into account the heterogeneity of the geological structure of the fields and the technogenic factors of impact. It is shown that the value of the calculated surface subsidence over the field, obtained on single data of the coefficient of pore compressibility of rocks and without taking into account the impact of the applied methods of development, does not allow an objective assessment of this process over the field area. The conclusion is made about the necessity of repeated profile leveling and gravimetric observations for a real assessment of the subsidence process of the Earth’s surface, which allows to control the industrial and environmental safety of natural and natural-technogenic objects in the field.

Investigation on the pore characteristics of coal specimens with bursting proneness

To achieve further insight into the pore characteristics, the coal specimens with different bursting proneness before and after uniaxial compression failure are tested and compared in this paper. The data of mercury intrusion test is corrected by that of low-temperature nitrogen adsorption and desorption test (LTNAD). The pore size distribution and pore volume of specimens are obtained. The pore compressibility coefficient is determined based on the fractal dimension of pore. Scanning electron microscope (SEM) and computed tomography (CT) are combined to evaluated the pore connectivity. The value of pore compressibility coefficient of specimens with high bursting proneness is larger than that of medium bursting proneness. It means more compressibility and abrupt failure under stress. The researches of both SEM and CT indicate that the pore connectivity of specimens with medium bursting proneness is better. The results show that great differences exist in the pore characteristics of specimens with high and medium bursting proneness, and uniaxial compression failure exacerbates the complexity of pore characteristics.