Correction of source-rock permeability measurements owing to slip flow and Knudsen diffusion: a method and its evaluation (original) (raw)
Related papers
Journal of Contaminant Hydrology, 2020
In a shale gas reservoir, the rock matrix has a relatively large porosity and gas in place, but extremely low permeability. Thus, the rock matrix is a bottleneck for shale gas flow from the reservoir to hydraulic fractures and then to the production well. We speculate that the next big thing after hydraulic fracturing for unconventional resources development is to enhance the matrix permeability in an economically feasible way. Consequently, the efficient and accurate characterization of rock matrix permeability in the laboratory is a critical task. The current laboratory techniques for source rock permeability measurement follow a "point-by-point" approach. They need multiple test runs to obtain a permeability-pressure curve, because they can only measure one permeability data point for one test run, and are thus time consuming. The root cause of this "point-by-point" approach is that these laboratory techniques are based on linearized gas flow theory requiring only small pore pressure disturbances to the experiment system. Liu et al. (2019) and this work introduce a new methodology that is based on the nonlinear gas flow theory and allows for direct measurement of the permeability-pressure curve with a single test run. This makes the approach highly time efficient. The feasibility and validity of the methodology are demonstrated in this work based on laboratory measurement results and their consistency with theoretical expectations and other independent measurements. The observed permeability exhibits a complex relationship with pore pressure as a result of the combined effects of Knudsen diffusion and mechanical deformation. For a given confining pressure, the observed permeability initially decreases with pore pressure because of Knudsen diffusion and then increases with pore pressure owing to the mechanical deformation. A rock sample with a lower permeability corresponds to a stronger Knudsen diffusion effect and weaker mechanical diffusion effect. This complex behavior highlights the need to accurately and efficiently measure the combined effects that may have important impacts on shale gas production.
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.
International Journal of Rock Mechanics and Mining Sciences, 2018
Permeability measurements on low-permeable rocks in the laboratory require much higher pressure gradients than those in real reservoirs to produce detectable flow rates in finite laboratory time. This may result in a high effective stress gradient that can cause non-uniform deformation of the pore system. To better understand the measured laboratory data, a theoretical model has been developed for calculating gas permeability of tight rock from laboratory measurements, which couples the effect of poroelastic deformation with the gas non-ideality and slippage effects. The proposed characteristic pressure model considers the poroelastic deformation and the real gas effects in the permeability calculation, which improves the accuracy of calculated permeability from laboratory measurements of tight rocks under large pressure gradients. The new model is validated by independent multiscale simulations, in which the poroelastic deformation and slippage effects are captured on the pore scale while the real gas behavior is captured on the core scale. The numerical results also indicate that the poroelastic deformation mainly affects the high-pressure region while the variation of gas properties dominates the low-pressure region. The new model is then applied to the calculation of gas permeability based on the laboratory measurements on coal and shale samples with non-ideal gas slippage and poroelastic effects considered. The poroelastic deformation and the real gas effect can be important as well as the slippage effect and the calculated apparent permeability will be overestimated if these two effects are neglected.
Study of Apparent Permeability in Shale Gas Reservoirs
International Journal of Engineering Research and, 2015
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.
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...
A new technique for permeability calculation of core samples from unconventional gas reservoirs
Fuel, 2019
Unconventional reservoirs and their outstanding characteristics have introduced a new field of research in reservoir engineering. The main challenge arises from the fact that in tight formations pore-throat size lays in the range of a few nanometers to a few dozens of nanometers, which makes the estimation of permeability a difficult task. When developing a permeability model for shale media, it is very important to accommodate for surface adsorption and transient flow effects, in addition to slippage effect and Knudsen diffusion, in order to achieve an accurate model. Prediction of fluid flow inside shale rock needs development of new models that take into account not only the diffusive flow but also the effect of high amount of gas adsorbed to the surface of the pores. In this work, we have proposed a new semi-empirical method for calculation of gas permeability inside tight formations. The method uses experimental data obtained from core plugs (canister data) and an analytical solution of continuity equation coupled with gas desorption in tight porous media. By matching the production data from core plugs, we have been able to calculate gas permeability by solving the analytical equation. We have been able to capture the effect of pore pressure on permeability by using production data at various core saturation pressures. We also compared our model with two previously proposed models. The results of this study show that the permeability calculated using our model is closer to experimental measurements of similar rock samples and comparable with other models.
Open Geosciences, 2019
Shale, a heterogeneous and extremely complex gas reservoir, contains low porosity and ultra-Low permeability properties at different pore scales. Its flow behaviors are more complicated due to different forms of flow regimes under laboratory conditions. Flow regimes change with respect to pore scale variation resulting in change in gas permeability. This work presents new insights regarding the change of pore radius due to gas adsorption, effective stress and impact of both on shale gas permeability measurements in flow regimes. From this study, it was revealed that the value of Klinkenberg coefficient has been affected due to gas adsorption-induced pore radius thickness impacts and resulting change in gas permeability. The gas permeability measured from new proposed equation is provides better results as compare to existing equation. Adsorption parameters are the key factors that affect radius of shale pore. Both adsorption and effective stress have an effect on the pore radius and...
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.
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.
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.