Effective Stress Coefficient through MFEM and Confining Pressure Dependency of Bibai Sandstone

The Marcellus Formation, a Devonian gas shale in the Appalachian Basin, is a heterogeneous rock as the result of a complex depositional, diagenetic, and deformational history. Although it is overpressured over a large portion of its economic area, the origin and distribution of pore pressure within the gas shale are not well-understood. We have used the sonic properties of the Marcellus and statistical analyses to tackle this problem. The sonic data come from a suite of 53 wells including a calibration well in the Appalachian Basin. We first analyze the influence of various extrinsic and intrinsic parameters on sonic velocities with univariate regression analyses. The sonic velocities of the Marcellus in the calibration well generally decrease with an increase in gamma-ray american petroleum institute (API) and increase with density and effective stress. Basin-wide median sonic velocities generally decrease with an increase in median gamma-ray API and pore pressure and increase with burial depth (equivalent confining stress), effective stress, and median density. Abnormal pore pressure is verified by a stronger correlation between the median sonic properties and effective stress using an effective stress coefficient of approximately 0.7 relative to the correlation between the median sonic properties and depth. The relatively small effective stress coefficient may be related to the fact that natural gas, a “soft” fluid, is responsible for a basin-wide overpressure of the Marcellus. Following the univariate regression analyses, we adopt a multiple linear regression model to predict the median sonic velocities in the Marcellus based on median gamma-ray intensity, median density, thickness of the Marcellus, confining pressure, and an inferred pore pressure. Finally, we predict the pore pressure in the Marcellus based on median sonic velocities, median gamma-ray intensity, median density, thickness of the Marcellus, and confining pressure.

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Sandstone Stress Sensitivity Experiment and Stress Sensitivity Evaluation

Advanced Materials Research ◽

10.4028/www.scientific.net/amr.962-965.526 ◽

2014 ◽

Vol 962-965 ◽

pp. 526-530

Author(s):

Tao Gao ◽

Xiao Guo ◽

Hong Mei Yang ◽

Hai Tao Li ◽

Zheng Zhu

Keyword(s):

Pore Pressure ◽

Effective Stress ◽

Oil And Gas ◽

Confining Pressure ◽

Stress Sensitivity ◽

Differential Method ◽

Gas Field ◽

Sensitivity Experiment ◽

Stress Coefficient ◽

Pressure Experiment

Change confining pressure experiment or pore pressure experiment is one of the commonly used method to evaluate the reservoir core stress sensitivity. However, a large number of studies have shown that core net stress is not equal to the effective stress,the drawdown pore pressure experiment are consistent with the characteristics of oil and gas field real development process. The pressure stability of drawdown pore pressure experiment is bad, so, a reliable modified method of change confining pressure stress sensitivity experiment is eagerly expected. On the basis of the differential method principle, effective stress coefficient can be determined through core experiments,and with the use of effective stress coefficient , change confining pressure experiment is modified. Main conclusions are as follows:For sandstone core,at reservoir original stress condition with the pore pressure from 15MPa to 11MPa effective stress coefficient from 0.436 to 0.415;Based on Terzaghi effective stress exaggerate stress sensitivity, ontology effective stress can weaken the stress sensitive; Based on effective stress coefficient in this paper correction stress sensitivity is medium weak,impacts on production results almost coincident with the drawdown pore pressure test results.

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

SPE Journal ◽

10.2118/195552-pa ◽

2021 ◽

pp. 1-17

Author(s):

Ivan C. Aldana Gallego ◽

Laura P. Santos ◽

I. Yucel Akkutlu

Keyword(s):

Pore Pressure ◽

Effective Stress ◽

Pore Volume ◽

Storage Capacity ◽

Applied Pressure ◽

Confining Pressure ◽

Laboratory Method ◽

Biot Coefficient ◽

Pore Compressibility ◽

Stress Coefficient

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.

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