Permeability measurements in mudrocks using gas-expansion methods on plug and crushed-rock samples (original) (raw)
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Shale Permeability Measurements on Plugs and Crushed Samples
SPE Canadian Unconventional Resources Conference, 2012
The economic viability of a shale play is strongly dependent on permeability which is often on the order of nanodarcies. Permeabilities are measured on core plugs or crushed samples using unsteady state techniques. However, the resultant permeabilities are the sources of controversy, because of the inconsistency in the permeability values produced with different techniques and different laboratories. In this research we evaluated the experimental factors which could influence permeability measurements with the GRI technique, and also present some permeability measurements on shale plugs. To evaluate the GRI permeability measurement technique on crushed rock, we investigated the effect of particle size, sieving of the crushed samples, pore pressure, different gases, and initial state of the measurement apparatus. The measured crushed shale permeabilities display a dependency on all these parameters. However, the particle size and the pore pressure appear to be the more important factors. This makes the reported values strongly dependent on the exact measurement procedure. This study was complemented by the imaging of crushed shale samples with a micro-CT scanner. These images showed the presence of microcracks even in samples as small as the recommended GRI particle size (~0.7mm). The permeabilities of several Devonian and Ordovician age shale plugs were measured with a pressure build up technique using nitrogen as flowing gas. A permeability decrease by an order of magnitude was generally observed for the Ordovician shale plugs with an increase of confining pressure from 1000 to 5000 psi. For the same Ordovician shale, the permeability anisotropy was found to be close to 2 orders of magnitude.The permeability of the Devonian shale plugs decreased by a maximum of 3 orders of magnitude over the range of confining pressure. For most shales, the confining pressure dependency of permeability is driven by cracks which is confirmed by a fit to Walsh's crack permeability model. However, we also noticed that it is possible to close the cracks contained in some plugs and obtain a value more representative of matrix permeability.
2016
To assess how fractures affect the fluid flow in shale plugs, we conducted stressdependent permeability measurements on both intact and fractured shale samples. We characterized the degree of fracturing with the help of micro X-ray CT images. As expected, permeabilities decreased significantly during the initial effective stress increase. During the subsequent effective pressure decrease, the permeability remained relatively unchanged. The degree of hysteresis depended on the sample integrity, i.e. fracture density, type, and distribution. We recorded an average hysteresis loss of 35% for intact samples, 55% for samples with a low density of hairline or discontinuous midsized fractures, and over 75% for samples with thick fractures, high fracture density, or continuous mid-sized cracks. Micro X-ray CT images acquired of fractures subjected to increasing confining stress showed that both, hairline and mid-sized fractures closed up completely at sufficiently high confining pressure. W...
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 ...
Journal of Natural Gas Science and Engineering, 2019
Accurate and routinely applicable methods to determine porosities and permeability coefficients are needed in order to ensure effective hydrocarbon recovery in shale and tight sandstone plays. In this study 129 gas uptake measurements ("GRI method", "inflow" experiments) were performed on core plugs from three unconventional reservoir lithotypes (oil shales, gas shales and tight gas sandstones) under elevated effective stress conditions. The results were compared to those from "flow-through" tests (standard pulse decay) under similar experimental conditions, e.g. the same gas type and pore pressure range. The samples covered a porosity range from 1.3% to 12%. Equilibration times ranged from 10 2 s to 10 4 s and permeability coefficients from 10-18 to 10-21 m 2. In order to successfully determine apparent gas permeability coefficients and porosities and to reliably interpret fluid dynamic effects from gas uptake data it is necessary to ensure a sufficiently high excess pressure drop during the uptake tests. This can be controlled by adjustment of the reservoir to pore volume ratio and initial differential pressure. Permeability coefficients derived from uptake tests on all six samples do not show any systematic deviations from those obtained from flow-through measurements. Best results were achieved for a core plug from the Lower Palaeozoic Alum Shale (Djupvik, Öland, Sweden), where Klinkenberg regressions of inflow and flow-through differ only by 4% (slope) and 10% (y-axis intercept). Here, the gas storage capacity ratio was
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.
Permeability and Effective Pore Pressure of Shales
Laboratory-derived permeability and pore-pressure data obtained for Wellington and Pierre shales are used to describe swelling pressure, and spalling types of wellbore instability. Tests showed that increased pore pressures can lead to wellbore failure. The laboratory pore-pressure information developed displays a time-dependent swelling process followed by a Darcy type of flow. A "total aqueous chemical potential" concept is presented that describes the driving potentials that operate during both phases of flow. Experimental methods are presented to determine the "storage" of water shale during the swelling phase and the permeabilities with steady-state-flow and transient-flow techniques. Permeability values measured under effective stresses up to 8,000 psi show the Wellington shale to have values as low as 0.30 x 10 -6 md.
Confinement Effect on Porosity and Permeability of Shales
Scientific Reports, 2020
Porosity and permeability are the key factors in assessing the hydrocarbon productivity of unconventional (shale) reservoirs, which are complex in nature due to their heterogeneous mineralogy and poorly connected nano-and micro-pore systems. Experimental efforts to measure these petrophysical properties posse many limitations, because they often take weeks to complete and are difficult to reproduce. Alternatively, numerical simulations can be conducted in digital rock 3D models reconstructed from image datasets acquired via e.g., nanoscale-resolution focused ion beam-scanning electron microscopy (FIB-SEM) nano-tomography. In this study, impact of reservoir confinement (stress) on porosity and permeability of shales was investigated using two digital rock 3D models, which represented nanoporous organic/mineral microstructure of the Marcellus Shale. Five stress scenarios were simulated for different depths (2,000-6,000 feet) within the production interval of a typical oil/gas reservoir within the Marcellus Shale play. Porosity and permeability of the pre-and post-compression digital rock 3D models were calculated and compared. A minimal effect of stress on porosity and permeability was observed in both 3D models. These results have direct implications in determining the oil-/gas-in-place and assessing the production potential of a shale reservoir under various stress conditions. Conventionally, oil and gas have been recovered from sandstone or carbonate reservoirs where hydrocarbons are trapped in well-connected systems of pores and fractures. Thanks to recent advancements in petroleum technologies , such as horizontal drilling and hydraulic fracturing, oil and gas can also be recovered unconventionally from less-developed mudstone (shale) reservoirs-deep and tight rock formations of heterogeneous lithology and mineralogy with poorly-connected nanometer-/micrometer-size pore systems. Among the key factors in assessing the oil/gas productivity potential of shale reservoirs (also referred as to shales) are the porosity and permeability of these oil-and/or gas-bearing rock formations. Porosity of a rock is the volume of void space, which can be filled with different reservoir fluids (e.g., oil, gas, water) at various saturations, whereas permeability of a rock is the ability of these fluids to flow within and between the pore space. Shales are characterized by very low porosity (typically less than 5%) and very low permeability (typically less than 1,000 nD), which make them challenging in recovering economically viable hydrocarbons. Determining the volume of oil and/or gas present in a reservoir (oil-and/or gas-in-place), and its potential to flow through reservoir pore/fracture system into the wellbore, helps petroleum industry to understand and optimize the producibility of a reservoir. Porosity and permeability of shales are often determined by examining core rock samples recovered from oil/gas wells drilled deep into rock formation. Recently, modern 2D/3D imaging techniques, have been used to investigate mineralogy and porosity in very fine detail, down to the sub-nanometer level 1-4. These methods (and advanced image analysis) have facilitated characterization of the pore morphology within both the organic matter and non-organic (mineral) matrix of shales 5-14. However, there is a little debate whether this imaging data of recovered samples (from thousands of meters) can be considered representative of an unstressed rock. Therefore, the objective of this study was to investigate the effect of reservoir confinement on porosity and permeability of an organic-rich Marcellus Shale rock sample imaged with FIB-SEM nano-tomography at ultra-high-resolution (5 nm/voxel). Porosity and (absolute) permeability under non-confined and confined conditions (at different reservoir depths) were simulated and compared by compressing two digital rock 3D models and re-evaluating the above petrophysical properties.
of Lower Jurassic Whitby Mudstone samples collected from a wave-cut platform, NE England, were measured for flow of argon parallel and perpendicular to bedding across a range of effective pressures ( (10-70 MPa) using the oscillating pore pressure method. Petrographic analyses including X-Ray diffraction and scanning electron and optical microscopy show that samples comprise a silt-rich, clay bearing mudstone containing <2% organic matter, with measured porosities ranging between 6-9%. An anisotropic fabric is indicated by elongate clay rich lenses and oriented micas, weakened in some layers by bioturbation. Permeability parallel to this layering was measured to be 2-3 orders of magnitude higher than permeability perpendicular, suggesting increased flow-path tortuosity across the layering. Pressure cycling over the range = 10-70 MPa was repeated on each sample until a reproducible pattern of permeability variation with was observed. Cycling initially reduces the permeability by >2 orders of magnitude, after which permeability of samples parallel to the layering varies with according to: