Can Gas Permeability of Fractured Shale Be Determined Accurately by Testing Core Plugs, Drill Cuttings, and Crushed Samples?

SPE Journal ◽  
2019 ◽  
Vol 24 (02) ◽  
pp. 720-732 ◽  
Author(s):  
F.. Civan
Keyword(s):  
Viscous Dissipation ◽  
Gas Permeability ◽  
Porous Rock ◽  
Unknown Parameters ◽  
Apparent Permeability ◽  
Drill Cuttings ◽  
Shale Formations ◽  
Pressure Tests ◽  
Diffusivity Equation ◽  
Nonisothermal Conditions

Summary Determining the nanodarcy gas permeability and other parameters of naturally and hydraulically induced fractured shale formations by testing the pressure transmission of core plugs, drill cuttings, and crushed samples is discussed. The author reviewed and modified the available methods for interpreting pressure tests with an emphasis on the differences between intrinsic and apparent permeability, and the generally overlooked temperature effects. It is significant to note that the temperature of gas varies during transport through porous rock samples and various dead-volumes when testing equipment used for permeability measurement is involved; this is because of unavoidable viscous dissipation and Joule-Thomson effects. Improved formulations and analysis methods that honor the relevant physics of gas transport and interactions with shale are presented, for both the generally assumed isothermal conditions and the realistic case of nonisothermal conditions. These improved formulations provide valuable insights when comparing and evaluating the currently available equations used for permeability calculations with the experimental data obtained by various testing methods. Better design and analysis of experiments for simultaneously determining several unknown parameters that impact the transport calculations, including deformation, adsorption, diffusion, viscous dissipation, Joule-Thomson effect, and deviation from Darcy flow, are described. It is recommended that the permeability and other parameters of shale samples be determined by simultaneous analysis of multiple pressure tests conducted under different conditions to accommodate temporally and spatially variable conditions by consideration of the temperature effect. The inherent limitations of the methods that rely on analytical solutions of the diffusivity equation on the basis of Darcy's law are also explained.

scholarly journals Apparent Permeability Model for Gas Transport in Multiscale Shale Matrix Coupling Multiple Mechanisms

Energies ◽  
2020 ◽  
Vol 13 (23) ◽  
pp. 6323
Author(s):  
Xiaoping Li ◽  
Shudong Liu ◽  
Ji Li ◽  
Xiaohua Tan ◽  
Yilong Li ◽  
...  
Keyword(s):  
Pore Size ◽  
Water Distribution ◽  
Gas Transport ◽  
Water Saturation ◽  
Gas Permeability ◽  
Apparent Permeability ◽  
Permeability Model ◽  
Proposed Model ◽  
Irreducible Water Saturation ◽  
The Impact

Apparent gas permeability (AGP) is a significantly important parameter for productivity prediction and reservoir simulation. However, the influence of multiscale effect and irreducible water distribution on gas transport is neglected in most of the existing AGP models, which will overestimate gas transport capacity. Therefore, an AGP model coupling multiple mechanisms is established to investigate gas transport in multiscale shale matrix. First, AGP models of organic matrix (ORM) and inorganic matrix (IOM) have been developed respectively, and the AGP model for shale matrix is derived by coupling AGP models for two types of matrix. Multiple effects such as real gas effect, multiscale effect, porous deformation, irreducible water saturation and gas ab-/de-sorption are considered in the proposed model. Second, sensitive analysis indicates that pore size, pressure, porous deformation and irreducible water have significant impact on AGP. Finally, effective pore size distribution (PSD) and AGP under different water saturation of Balic shale sample are obtained based on proposed AGP model. Under comprehensive impact of multiple mechanisms, AGP of shale matrix exhibits shape of approximate “V” as pressure decrease. The presence of irreducible water leads to decrease of AGP. At low water saturation, irreducible water occupies small inorganic pores preferentially, and AGP decreases with small amplitude. The proposed model considers the impact of multiple mechanisms comprehensively, which is more suitable to the actual shale reservoir.

scholarly journals Applicability Analysis of Klinkenberg Slip Theory in the Measurement of Tight Core Permeability

Energies ◽  
2019 ◽  
Vol 12 (12) ◽  
pp. 2351 ◽  
Author(s):  
Jirui Zou ◽  
Xiangan Yue ◽  
Weiqing An ◽  
Jun Gu ◽  
Liqi Wang
Keyword(s):  
High Pressure ◽  
Gas Permeability ◽  
Fluid Dynamic ◽  
Dynamic Parameter ◽  
Low Pressure ◽  
Low Permeability ◽  
Apparent Permeability ◽  
Tight Reservoir ◽  
Gas Seepage ◽  
The Relationship

The Klinkenberg slippage theory has widely been used to obtain gas permeability in low-permeability porous media. However, recent research shows that there is a deviation from the Klinkenberg slippage theory for tight reservoir cores under low-pressure conditions. In this research, a new experimental device was designed to carry out the steady-state gas permeability test with high pressure and low flowrate. The results show that, unlike regular low-permeability cores, the permeability of tight cores is not a constant value, but a variate related to a fluid-dynamic parameter (flowrate). Under high-pressure conditions, the relationship between flowrate and apparent permeability of cores with low permeability is consistent with Klinkenberg slippage theory, while the relationship between flowrate and apparent permeability of tight cores is contrary to Klinkenberg slip theory. The apparent permeability of tight core increases with increasing flowrate under high-pressure conditions, and it is significantly lower than the Klinkenberg permeability predicted by Klinkenberg slippage theory. The difference gets larger when the flowrate becomes lower (back pressure increases and pressure difference decreases). Therefore, the Klinkenberg permeability which is obtained by the Klinkenberg slippage theory by using low-pressure experimental data will cause significant overestimation of the actual gas seepage capacity in the tight reservoir. In order to evaluate the gas seepage capacity in a tight reservoir precisely, it is necessary to test the permeability of the tight cores directly at high pressure and low flowrate.

Determining Shale Permeability to Gas by Simultaneous Analysis of Various Pressure Tests

SPE Journal ◽  
2012 ◽  
Vol 17 (03) ◽  
pp. 717-726 ◽  
Author(s):  
F.. Civan ◽  
C.S.. S. Rai ◽  
C.H.. H. Sondergeld
Keyword(s):  
Gas Flow ◽  
Pressure Pulse ◽  
Reference Conditions ◽  
Transient State ◽  
Data Interpretation ◽  
Model Parameters ◽  
Apparent Permeability ◽  
Core Samples ◽  
Pulse Transmission ◽  
Pressure Tests

Summary A model-assisted analysis is presented of pressure-pulse-transmission data obtained under different pressure conditions with core plugs of shale-gas formations. Applications and validations for steady-state and transient-state laboratory tests are provided. Best-estimate values of the intrinsic permeability and tortuosity at a reference condition and the Langmuir volume and pressure are determined by matching the solution of a modified Darcy model to several pressure-pulse-transmission flow tests with core samples simultaneously. The data-interpretation model considers the prevailing characteristics of the apparent permeability under the various flow regimes involving gas flow through extremely low-permeability core samples. Further, the present fully pressure-dependent shale-and gas-property formulation allows for model-assisted extrapolation from the reference conditions to field conditions once the unknown model parameters have been estimated under laboratory conditions. The improved method provides a better match to the measurements of the pressure tests than previous models, which assume only Darcy flow.

Analytical and Experimental Investigations of Gas-Flow Regimes in Shales Considering the Influence of Mean Effective Stress

SPE Journal ◽  
2016 ◽  
Vol 21 (02) ◽  
pp. 557-572 ◽  
Author(s):  
Alireza A. Moghadam ◽  
Rick Chalaturnyk
Keyword(s):  
Flow Regime ◽  
Effective Stress ◽  
Gas Flow ◽  
Gas Permeability ◽  
Slip Flow ◽  
Flow Regimes ◽  
Absolute Permeability ◽  
Apparent Permeability ◽  
Reservoir Conditions ◽  
Slip Flow Regime

Summary Flow conditions determine the flow regimes governing gas flow in porous media. Slip-flow regime commonly occurs in laboratory gas-permeability measurements, and one must consider the physics of that when finding the absolute permeability of a sample. Accurate permeability estimates are paramount for production forecasts, financial planning, and recovery estimation. Slip flow is present in low-permeability rocks, both in the laboratory environment and at reservoir conditions. Gas flow through the matrix lies under the slip-flow regime for the majority of low-permeability-reservoir production scenarios, and accurate prediction of pressure and production rate requires a good understanding of the flow regime. In this paper, an analytical study is conducted on the dominant flow regimes under typical shale-gas reservoir conditions. A flow-regime map is produced with respect to gas pressure and matrix permeability. Steady-state gas-permeability experiments are conducted on three shale samples. An analytical model is used to match the experimental results that could explain the order-of-magnitude difference between the permeabilities of gas and liquid in shales. Experimental results are combined with further tests available in the literature to inform a discussion of the model's parameters. The results improve the accuracy of gas-flow modeling and of absolute-permeability estimates from laboratory tests. Similar tests performed at various mean effective stresses investigate the influence of mean effective stress on flow regime and apparent permeability. The results indicate that flow regime is a function of mean effective stress, and that the apparent permeability of shale rocks is a function of both flow regime and mean effective stress.

scholarly journals Features of measuring absolute permeability of rocks

2020 ◽  
Vol 28 (2) ◽  
pp. 73-83
Author(s):  
Aleksander V. Pescov
Keyword(s):  
Oil And Gas ◽  
Gas Permeability ◽  
Darcy Law ◽  
Absolute Permeability ◽  
Regression Equations ◽  
Apparent Permeability ◽  
Pressure Drops ◽  
Permeability Coefficients ◽  
Small Pore ◽  
Scope Of Application

Aspects of gas permeability measurement on samples of terrigenic and carbonate rocks of oil and gas collectors, as well as artificial samples on the domestic Darsimeter plant are considered. The following types of reservoir rocks were used for the study: pore, fractured, cavernous. The scope of application of the Darcy Law for pore-type rocks was clarified, which is limited to small pore pressures. Permeability coefficients were determined taking into account the gas slip-law effect of Klinkenberg on regression equations. Apparent permeability at low pressure drops was determined. For a number of samples with low permeability, the pore size was calculated to relate to the apparent permeability value. The calculation was carried out on the basis of the obtained values of structural coefficients of rocks by the method of electrical resistivity and on the basis of porosity values determined using the Preobrazhenskiy method.For a number of crack and capillary samples, the relationship between the pressure gradient and the filtration rate became nonlinear, and types of filtration laws were determined. Establishing the applicability of Darcy 's law or nonlinear law was controlled by constructing indicator curves and calculating the Reynolds number. For terrigenic rocks of high permeability, errors of measurement of gas permeability coefficients at different pressure drop intervals were determined: dispersion and coefficient of variation showing low values were calculated.

scholarly journals Viscous Dissipation and Apparent Permeability of Gas Flow in Nanoporous Media

2020 ◽  
Vol 125 (2) ◽  
Author(s):  
Jianlin Zhao ◽  
Qinjun Kang ◽  
Youping Wang ◽  
Jun Yao ◽  
Lei Zhang ◽  
...  
Keyword(s):  
Viscous Dissipation ◽  
Gas Flow ◽  
Apparent Permeability ◽  
Nanoporous Media

Gas flow in ultra-tight shale strata

2012 ◽  
Vol 710 ◽  
pp. 641-658 ◽  
Author(s):  
Hamed Darabi ◽  
A. Ettehad ◽  
F. Javadpour ◽  
K. Sepehrnoori
Keyword(s):  
Porous Media ◽  
Large Scale ◽  
Gas Flow ◽  
Gas Permeability ◽  
Knudsen Diffusion ◽  
Initial Pressure ◽  
Flow In Porous Media ◽  
Upper And Lower Bounds ◽  
Apparent Permeability ◽  
Permeability Function

AbstractWe study the gas flow processes in ultra-tight porous media in which the matrix pore network is composed of nanometre- to micrometre-size pores. We formulate a pressure-dependent permeability function, referred to as the apparent permeability function (APF), assuming that Knudsen diffusion and slip flow (the Klinkenberg effect) are the main contributors to the overall flow in porous media. The APF predicts that in nanometre-size pores, gas permeability values are as much as 10 times greater than results obtained by continuum hydrodynamics predictions, and with increasing pore size (i.e. of the order of the micrometre), gas permeability converges to continuum hydrodynamics values. In addition, the APF predicts that an increase in the fractal dimension of the pore surface leads to a decrease in Knudsen diffusion. Using the homogenization method, a rigorous analysis is performed to examine whether the APF is preserved throughout the process of upscaling from local scale to large scale. We use the well-known pulse-decay experiment to estimate the main parameter of the APF, which is Darcy permeability. Our newly derived late-transient analytical solution and the late-transient numerical solution consistently match the pressure decay data and yield approximately the same estimated value for Darcy permeability at the typical core-sample initial pressure range and pressure difference. Other parameters of the APF may be determined from independent laboratory experiments; however, a pulse-decay experiment can be used to estimate the unknown parameters of the APF if multiple tests are performed and/or the parameters are strictly constrained by upper and lower bounds.

Lubrication of a Melting Slider Under Nonisothermal Conditions

1981 ◽  
Vol 103 (3) ◽  
pp. 436-442 ◽  
Author(s):  
V. Bicego ◽  
A. Figari ◽  
G. Poletti
Keyword(s):  
Theoretical Model ◽  
Friction Coefficient ◽  
Film Thickness ◽  
Liquid Film ◽  
Melting Temperature ◽  
Viscous Dissipation ◽  
Thermal Conduction ◽  
Heat Sources ◽  
Isothermal Case ◽  
Nonisothermal Conditions

A theoretical model is developed for a slider lubricated by its own surface melting. Heat for melting is assumed to be supplied both from viscous dissipation in the liquid film and by conduction from the track at a temperature higher than the melting temperature of the slider. The analysis allows prediction of film thickness and the friction coefficient. The overall behavior results to be clearly dependent on which of the two heat sources is prevailing. In particular, thermal conduction appears to be the cause for a generally much lower friction coefficient with respect to an isothermal case.

Sign in / Sign up

Export Citation Format

Share Document