An efficient laboratory method to measure the combined effects of Knudsen diffusion and mechanical deformation on shale permeability (original) (raw)
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Petroleum Science
Source-rock permeability is a key parameter that controls the gas production rate from unconventional reservoirs. Measured source-rock permeability in the laboratory, however, is not an intrinsic property of a rock sample, but depends on pore pressure and temperature as a result of the relative importance of slip flow and diffusion in gas flow in lowpermeability media. To estimate the intrinsic permeability which is required to determine effective permeability values for the reservoir conditions, this study presents a simple approach to correct the laboratory permeability measurements based on the theory of gas flow in a micro/nano-tube that includes effects of viscous flow, slip flow and Knudsen diffusion under different pore pressure and temperature conditions. The approach has been verified using published shale laboratory data. The ''corrected'' (or intrinsic) permeability is considerably smaller than the measured permeability. A larger measured permeability generally corresponds to a smaller relative difference between measured and corrected permeability values. A plot based on our approach is presented to describe the relationships between measured and corrected permeability for typical Gas Research Institute permeability test conditions. The developed approach also allows estimating the effective permeability in reservoir conditions from a laboratory permeability measurement.
SPE Reservoir Evaluation & Engineering, 2019
Summary This work proposes an innovative laboratory method to measure shale gas permeability as a function of pore pressure, a key parameter for characterizing and modeling gas flow in a shale gas reservoir. The development is based on a solution to 1D gas flow under certain boundary and initial conditions. The details of the theoretical background, including formulations to estimate gas permeability and conceptual design of the test setup, are provided. The advantages of our approach, surpassing the currently available ones, include that it measures gas permeability (as a function of pressure) with a single test run and without any presumption regarding the form of parametric relationship between gas permeability and pore pressure. In addition, our approach allows for estimating both shale permeability and porosity at the same time from the related measurements. Numerical experiments are conducted to verify the feasibility of the proposed methodology.
Apparent permeability of gas shales – Superposition of fluid-dynamic and poro-elastic effects
Fuel, 2017
h i g h l i g h t s Experimental measurements of apparent gas permeability on gas shales. Pitfalls in the evaluation of high pressure apparent gas permeability data. Terzaghi's principle is not valid for permeability of gas shales. A permeability minimum occurs in the P p range from 2 to 10 MPa. Poro-elastic and fluid-dynamic effects are superposed (0 to >20 MPa P p).
Experimental investigation of matrix permeability of gas shales
AAPG Bulletin, 2014
Predicting long-term production from gas shale reservoirs has been a major challenge for the petroleum industry. To better understand how production profiles are likely to evolve with time, we have conducted laboratory experiments examining the effects of confining stress and pore pressure on permeability. Experiments were conducted on intact core samples from the Barnett, Eagle Ford, Marcellus, and Montney shale reservoirs. The methodology used to measure permeability allows us to separate the reduction of permeability with depletion (because of the resultant increase in effective confining stress) and the increase in permeability associated with Knudsen diffusion and molecular slippage (also known as Klinkenberg) effects at very low pore pressure. By separating these effects, we are able to estimate the relative contribution of both Darcy and diffusive fluxes to total flow in depleted reservoirs. Our data show that the effective permeability of the rock is significantly enhanced at very low pore pressures (<1000 psi [<6.9 MPa]) because of the slippage effects. We use the magnitude of the Klinkenberg effect to estimate the effective aperture of the flow paths within the samples and compare these estimates to scanning electron microscopy image observations. Our results suggest effective flow paths to be on the order from tens of nanometers in most samples to 100-200 nm, in a relatively high-permeability Eagle Ford sample. Finally, to gain insight on the scale dependence of permeability measurements, the same core plugs were crushed, and permeability was again measured at the particle scale using the so-called Gas Research Institute method. The results show much lower permeability than the intact core samples, with very little correlation to the measurements on the larger scale cores.
Effects of rock mineralogy and pore structure on stress-dependent permeability of shale samples
Philosophical transactions. Series A, Mathematical, physical, and engineering sciences, 2016
We conducted pulse-decay permeability experiments on Utica and Permian shale samples to investigate the effect of rock mineralogy and pore structure on the transport mechanisms using a non-adsorbing gas (argon). The mineralogy of the shale samples varied from clay rich to calcite rich (i.e. clay poor). Our permeability measurements and scanning electron microscopy images revealed that the permeability of the shale samples whose pores resided in the kerogen positively correlated with organic content. Our results showed that the absolute value of permeability was not affected by the mineral composition of the shale samples. Additionally, our results indicated that clay content played a significant role in the stress-dependent permeability. For clay-rich samples, we observed higher pore throat compressibility, which led to higher permeability reduction at increasing effective stress than with calcite-rich samples. Our findings highlight the importance of considering permeability to be ...
Measuring low permeabilities of gas-sands and shales using a pressure transmission technique
International Journal of Rock Mechanics and Mining Sciences, 2011
Liquid and gas permeability measurements for tight gas-sand and shales were done using a pressure transmission technique in specially designed apparatus in which confining pressure, pore pressure, and temperature are independently controlled. Downstream pressure changes were measured after increasing and maintaining upstream pressure constant. The initial pressure difference changes only after the pressure pulse propagates across the sample. For low permeability samples, the downstream pressure increase is delayed but the measurement senses a greater sample volume. On the other hand, conventional pulse decay techniques provide a more rapid response but are sensitive to local sample permeability heterogeneity. Permeability measured for the rocks studied varies from 1.18 Â 10 À 15 to 3.95 Â 10 À 21 m 2. The measured permeability anisotropy ratio in gas shale varies from 20% to 31%. The magnitudes of permeability anisotropy remain almost constant, but the absolute permeability values decrease by a factor of 10 with a 29.79 MPa effective pressure. All samples showed a nonlinear reduction in permeability with increasing effective pressure. The rate of reduction is markedly different from sample to sample and with flow direction. This reduction can be described by a cubic k-s law and explained by preferential flow through microcracks.
Gas Multiple Flow Mechanisms and Apparent Permeability Evaluation in Shale Reservoirs
Sustainability, 2019
Gas flow mechanisms and apparent permeability are important factors for predicating gas production in shale reservoirs. In this study, an apparent permeability model for describing gas multiple flow mechanisms in nanopores is developed and incorporated into the COMSOL solver. In addition, a dynamic permeability equation is proposed to analyze the effects of matrix shrinkage and stress sensitivity. The results indicate that pore size enlargement increases gas seepage capacity of a shale reservoir. Compared to conventional reservoirs, the ratio of apparent permeability to Darcy permeability is higher by about 1–2 orders of magnitude in small pores (1–10 nm) and at low pressures (0–5 MPa) due to multiple flow mechanisms. Flow mechanisms mainly include surface diffusion, Knudsen diffusion, and skip flow. Its weight is affected by pore size, reservoir pressure, and temperature, especially pore size ranging from 1 nm to 5 nm and reservoir pressures below 5 MPa. The combined effects of mat...
Transport in Porous Media, 2011
A theoretically improved model incorporating the relevant mechanisms of gas retention and transport in gas-bearing shale formations is presented for determination of intrinsic gas permeability and diffusivity. This is accomplished by considering the various flow regimes according to a unified Hagen-Poiseuille-type equation, fully compressible treatment of gas and shale properties, and numerical solution of the non-linear pressure equation. The present model can accommodate a wide range of fundamental flow mechanisms, such as continuum, slip, transition, and free molecular flow, depending on the prevailing flow conditions characterized by the Knudsen number. The model indicates that rigorous determination of shale-gas permeability and diffusivity requires the characterization of various important parameters included in the present phenomenological modeling approach, many of which are not considered in previous studies. It is demonstrated that the improved model matches a set of experimental data better than a previous attempt. It is concluded that the improved model provides a more accurate means of analysis and interpretation of the pressure-pulse decay tests than the previous models which inherently consider a Darcian flow and neglect the variation of parameters with pressure.
IJERT-Study of Apparent Permeability in Shale Gas Reservoirs
International Journal of Engineering Research and Technology (IJERT), 2015
https://www.ijert.org/study-of-apparent-permeability-in-shale-gas-reservoirs https://www.ijert.org/research/study-of-apparent-permeability-in-shale-gas-reservoirs-IJERTV4IS030846.pdf The permeability of reservoir plays an important role in modeling gas production form reservoir. The transport mechanism in shale gas reservoirs is significantly different from conventional reservoirs. As the gas is mostly stored in the organic matter, the transport mechanism of this gas mainly depends on the diffusivity and desorption of gas from the source. To have better understanding of the flow mechanism the concept of relative permeability is very important, which has more impact on the well performance in shale reservoirs. In this paper, we have explained about importance of relative permeability and the different techniques to determine the relative permeability.
2013
Simultaneous flow of two liquid phases through an organic shale pore system was modeled using a Lattice-Boltzmann method. This paper describes the methods and results of this modeling project which was designed to quantify the range of expected permeability and relative permeability in samples from a shale formation in Colombia. Porosity versus absolute permeability trends were determined for 44 well samples using digital rock physics (DRP) methods. The formation samples average about 6% organic material content by volume. The total porosity range observed is from about 3 to 15%. For total porosity of 4% or above, the calculated horizontal permeability is generally above 100 nano-Darcy (nD). For porosity of 8%, the calculated horizontal permeability is typically 1000 nD or more. From these 44 samples, four were selected for oil-water and two for gas-water relative permeability analysis. Two phase flow modeling was conducted using several scenarios. Imbibition relative permeability c...