Pore Fluid Content Research Articles

Porosity estimation based on the shear modulus inversion of seismic shear wave

Reliable estimation of subsurface porosity is necessary for hydrocarbon reservoir characterization and fluid identification. Porosity estimations from seismic data can provide the lateral distribution of subsurface porosity, but the results may be highly nonunique because subsurface elastic properties (such as velocity and density) can be affected by porosity and pore fluids. Because shear modulus is insensitive to pore fluid content, it can be effectively used to estimate porosity. We develop a novel porosity estimation method using the reflected SH wave (SH-SH wave), whose propagation characteristics depend mainly on shear modulus and S-wave velocity. We derive a new analytical expression for the SH-SH-wave reflection coefficient, which acts as a function of shear modulus and S-wave velocity in its natural logarithm form. This new approximation has high accuracy, and both coefficients corresponding to shear modulus and S-wave velocity are “model-parameter independent”; thus, there is no need for prior estimation of any model parameter during inversion. Numerical analysis indicates that shear modulus inverted from the SH-SH wave has lower uncertainty, the problem is better conditioned, and the method requires data with fewer incidence angles than algorithms that invert for the shear modulus from the PP wave. Furthermore, the highly correlated rock-physics relationships between porosity and shear modulus facilitate accurate porosity estimation. A field data application indicates that high-resolution porosity of fine structures can be reliably recovered using our method.

Coupled DEM/CFD analysis of impact of free water on the static and dynamic response of concrete in tension regime

In this paper, the quasi-static and dynamic behavior of partially fluid-saturated concrete under two-dimensional (2D) uniaxial tension at the mesoscale is investigated numerically. It was calculated what effect the free pore fluid content (gas and water) had on the fracture process and strength of concrete in a tension regime. An improved pore-scale hydro-mechanical model based on DEM/CFD was used to simulate the behavior of fully and partially fluid-saturated concrete in quasi-static and dynamic conditions. The foundation of the fluid flow idea was a network of channels in a continuous area between discrete elements. In very porous, partially saturated concrete, a two-phase laminar fluid flow was proposed. To track the liquid/gas content, the position and volumes of the pores and cracks were considered. Numerical simulations of bonded granular specimens of a simplified spherical mesostructure that resembled concrete were carried out under dry and wet circumstances for two different strain rates. Investigations were conducted on the effects of fluid pore pressures, fluid saturations, and fluid viscosities on the strength and fracture process of concrete. The quasi-static tensile strength dropped nonlinearly with increasing fluid saturation and fluid viscosity during fluid migration through pores and cracks which contributed to a promoted fracture process. However, during rapid dynamic tensile deformation, a fracture process attenuated due to a fluid migration constraint from insufficient time to exit the pores. It caused the dynamic tensile strength to rise nonlinearly as fluid saturation and fluid viscosity increased.

Formation of Billowed Structures Along Margins of Basaltic Intrusions: Insights from Big Bend National Park, Texas and 71 Gulch, Idaho

Billowed margins of basaltic intrusions provide opportunity to study the conditions of non-explosive magma-pore water interactions and how magma propagates and interacts with unconsolidated sediment in the subsurface. Basaltic intrusions exhibiting billowed structures that formed at different paleodepths in Big Bend National Park, Texas (200–500 m) and 71 Gulch, Idaho (≤24 m) have been examined and reconstructed in three dimensions (3D) using structure for motion (SfM) techniques. To characterize billowed structure diversity, a classification system was developed utilizing 21 high-resolution 3D models of outcrops from both locations. Seven structure types are recognized: linear, sinuous, teardrop, bulbous, circular, transitional, and overprinted. Relative abundances of each structure type are similar between both localities. All structures identified were recognized along dikes, apart from one sill. Each site hosts ≥3 structure types, no one structure type is dependent on another, and the dimensions of structure types are similar at both localities with insignificant variation in mean wavelength and amplitude of crests and troughs (≤6 cm), suggesting that depth of intrusion is not a major influence in the occurrence of different structure types. Aligned plagioclase laths and stretched vesicles along margins are evidence that billow formation occurred while margins were fluid, deformable, and flowing. These observations indicate billowed structures likely form during the initial stages of intrusion while the margins are experiencing Kelvin-Helmholtz instabilities during cooling. As billowed intrusions from varying paleodepths at the two localities both occur near phreatomagmatic diatreme structures, changes in the rate or flux of magma intrusion or local heterogeneities in the host sediment and/or pore fluid content may be more responsible for explosive vs. non-explosive interactions rather than simple arrival of magma.

Fluid Substitution Analysis Using Gassmann’s Equation Modification on Carbonate Environment

Gassmann’s equation can be used to determine the velocity of compressional waves that pass through rocks with various pore fluid contents, using fluid substitution concept, but is generally applied to certain conditions only (physical rock properties). Carbonate rock has properties in contrary of Gassmann’s assumption; is a heterogenic, anisotropic rock and does not have a well-interconnected pores. In this research, secondary data from laboratory measurements are used, consisting of carbonate rocks (limestone and dolomite) to test modified Gassmann’s equation on carbonate rocks. Two approaches of Gassmann’s equation are used by using k-dry and k-1 components, which are the value of compressional modulus bulk of saturated rocks. The result of both approaches shows that the usage of k-1 component is more optimal to be applied to carbonate rocks because it does not use k-dry component, which should only be used on field measurements, as there is a difference in the environment condition (air, temperature, and pressure) on reservoir and laboratory.

Caldera’s Breathing: Poroelastic Ground Deformation at Campi Flegrei (Italy)

Ground deformation at Campi Flegrei has fuelled a long-term scientific debate about its driving mechanism and its significance in hazard assessment. In an active volcanic system hosting a wide hydrothermal circulation, both magmatic and hydrothermal fluids could be responsible, to variable degrees, for the observed ground displacement. Fast and large uplifts are commonly interpreted in terms of pressure or volume changes associated with magma intrusion, while minor, slower displacement can be related to shallower sources. This work focuses on the deformation history of the last 35 years and shows that ground deformation measured at Campi Flegrei since 1985 is consistent with a poroelastic response of a shallow hydrothermal system to changes in pore pressure and fluid content. The extensive literature available for Campi Flegrei allows constraining system geometry, properties, and conditions. Changes in pore pressure and fluid content necessary to cause the observed deformation can then be calculated based on the linear theory of poroelasticity. The predicted pore pressure evolution and fluid fluxes are plausible and consistent with available measurements and independent estimates.

Genetic Types and Main Control Factors of Microfractures in Tight Oil Reservoirs of Jimsar Sag

Microfractures are key for migrating and aggregating hydrocarbon source rocks and fracturing oil-gas exploitation in tight reservoirs. In this study, rock samples from the Lucaogou Formation tight reservoirs in Xinjiang, China, were studied using multidisciplinary techniques to investigate the genetic types and main control factors of microfractures. Results indicated that the Lucaogou Formation mainly developed diagenetic microfractures followed by tectonic microfractures, with slight formations of granular microfractures. These observations were used to clarify the relationship between the development of microfractures and the pore fluid content, lithology, mineral composition, and stratum thickness. A higher pore fluid content corresponded to a lower compressive strength of the rocks and a larger ring count, resulting in a higher probability of failure and microfracture formation. Tight reservoirs containing more quartz and carbonate minerals were found to develop more microfractures. Quartz grains showed fractures at the margins under stress, which increased the pore permeability of rocks. Carbonate minerals tended to form microfractures owing to corrosion. Microfracture formation mechanisms differed depending on lithology, and microfractures were found to develop most in dolomite and dolomitic siltstones and least in mudstone. Muddy rocks developed fewer tectonic fractures because they can easily absorb stress and undergo plastic deformation. Within a certain stratum thickness range, the average single-well fracture space and stratum thickness showed positive correlations. Moreover, the fracture space increased and the fracture density decreased as the stratum thickness increased. When the stratum thickness was less than 2.5 m, the fracture space increased linearly with the stratum thickness, and when the stratum thickness was greater than 2.5 m, the fracture space remained constant. This study will provide an essential scientific basis for enhancing tight oil recovery.

Two-dimensional Bayesian inversion of magnetotelluric data using trans-dimensional Gaussian processes.

Bayesian inversion of electromagnetic data produces crucial uncertainty information on inferred subsurface resistivity. Due to their high computational cost, however, Bayesian inverse methods have largely been restricted to computationally expedient 1-D resistivity models. In this study, we successfully demonstrate, for the first time, a fully 2-D, trans-dimensional Bayesian inversion of magnetotelluric (MT) data. We render this problem tractable from a computational standpoint by using a stochastic interpolation algorithm known as a Gaussian process (GP) to achieve a parsimonious parametrization of the model vis-a-vis the dense parameter grids used in numerical forward modelling codes. The GP links a trans-dimensional, parallel tempered Markov chain Monte Carlo sampler, which explores the parsimonious model space, to MARE2DEM, an adaptive finite element forward solver. MARE2DEM computes the model response using a dense parameter mesh with resistivity assigned via the GP model. We demonstrate the new trans-dimensional GP sampler by inverting both synthetic and field MT data for 2-D models of electrical resistivity, with the field data example converging within 10d on 148 cores, a non-negligible but tractable computational cost. For a field data inversion, our algorithm achieves a parameter reduction of over 32× compared to the fixed parameter grid used for the MARE2DEM regularized inversion. Resistivity probability distributions computed from the ensemble of models produced by the inversion yield credible intervals and interquartile plots that quantitatively show the non-linear 2-D uncertainty in model structure. This uncertainty could then be propagated to other physical properties that impact resistivity including bulk composition, porosity and pore-fluid content.

Time-Dependent Stresses From Fluid Extraction and Diffusion With Applications to Induced Seismicity

Abstract Over recent decades, it has become clear that the extraction of fluids from underground reservoirs can be linked to seismicity and aseismic deformation around producing fields. Using a simple model with uniform fluid extraction from a reservoir, Segall (1989, “Earthquakes Triggered by Fluid Extraction,” Geology, 17(10), pp. 942–946) illustrated how poroelastic stresses resulting from fluid withdrawal may be consistent with earthquake focal mechanisms surrounding some producing fields. Since these stress fields depend on the spatial gradient of the change in pore fluid content within the reservoir, both quantitative and qualitative predictions of the stress changes surrounding a reservoir may be considerably affected by assumptions in the geometry and hydraulic properties of the producing zone. Here, we expand upon the work of Segall (1989, “Earthquakes Triggered by Fluid Extraction,” Geology, 17, pp. 942–946 and 1985, “Stress and Subsidence Resulting From Subsurface Fluid Withdrawal in the Epicentral Region of the 1983 Coalinga Earthquake,” J. Geophys. Res. Solid Earth, 90, pp. 6801–6816) to provide a quantitative analysis of the surrounding stresses resulting from fluid extraction and diffusion in a horizontal reservoir. In particular, when considering the diffusion of fluids, the spatial pattern and magnitude of imposed stresses is controlled by the ratio between the volumetric rate of fluid extraction and the reservoir diffusivity. Moreover, the effective reservoir length expands over time along with the diffusion front, predicting a time-dependent rotation of the induced principal stresses from relative tension to compression along the ends of the producing zone. This reversal in perturbed principal stress directions may manifest as a rotation in earthquake focal mechanisms or varied sensitivity to poroelastic triggering, depending upon the criticality of the pre-existing stress state and fault orientations, which may explain inferred rotations in principal stress directions associated with some induced seismicity.

Influence of upscaling on identification of reservoir fluid properties using seismic-scale elastic constants

Elastic constants derived from seismic-scale measurements are often used to infer subsurface petrophysical properties based on rock-physics relationships established from either theoretic model or core-scale measurements. However, the spatial heterogeneity of rock physical properties at the local scale has a significant impact on this relation. To understand this problem, we built a scaled physical model comprised of artificial porous layers with different pore fluids. After conducting a two-dimensional marine seismic survey over the physical model, the physical modeling data ware then used to retrieve the elastic constants of the layered package. The seismic-scale results reveal that the identification of reservoir fluid properties is improved using elastic constants that is more sensitive to pore fluid properties. The results of numerical simulations show that Lamé moduli provide more insight into rock properties and pore-fluid contents than P-wave impedances, and that the relationship between the upscaled elastic constants and the effective fluid bulk moduli at the seismic scale is usually not perfectly preserved at the reservoir scale. To interpret seismic-scale elastic constants for petrophysical properties, the rock physics relationship need to be carefully calibrated. The findings will help us understand the upscaling of rock-physics transform, which will improve the accuracy of geological property predictions from seismic-scale elastic constants.

The Seismic Response to Injected Carbon Dioxide: Comparing Observations to Estimates Based Upon Fluid Flow Modeling

AbstractTime‐lapse seismic amplitude differences and travel time shifts, obtained while monitoring enhanced oil recovery at Cranfield, Mississippi, reveal coherent changes that are associated with the injection of carbon dioxide. Rock physics modeling highlights the importance of the oil, brine, and gas content of pore fluids prior to the injection of carbon dioxide. For example, compressional velocity changes due to the injection of carbon dioxide can drop from 300 m/s to less than 100 m/s as the percentage of oil increases from 1% to 50%. Predictions based upon a new technique for modeling wave propagation in a poroelastic medium containing an arbitrary number of fluids, coupled with multicomponent numerical reservoir modeling at Cranfield, reproduce the general pattern of observed seismic amplitude changes and travel time shifts. In particular, time‐lapse amplitude changes suggest a significant and widespread lowering of compressional velocities due to the injection of CO2 into an aquifer bounding the oil rim of the reservoir. It appears that the large‐scale variations in preexisting pore fluid content have a major influence on seismic velocity changes, even in the highly heterogeneous reservoir at Cranfield.

Characterization of hydrocarbon reservoir by pore fluid and lithology using elastic parameters in an x field, Niger delta, Nigeria

Quantitative rock physics analysis was carried out to determine the lithology and pore fluid of a reservoir in the Niger Delta. Density, compressional wave velocity and shear wave velocity logs were used as input to calculate elastic parameters such as velocity ratio, Poisson’s ratio, and Bulk Modulus, after estimating the hydrocarbon reservoir in the X field. The calculated velocity ratio log was used to differentiate between sand, sandstone and shale. Poisson’s ratio and velocity ratio were used delineate pore fluid content; gas sand, oil sand and sandstone formation from cross plot analysis. The reservoir in the field lies ranges from 9050 - 9426.5ft, (2760.25 – 2874.93m), this confirm what is obtained in the Niger Delta Basin. The Net Pay zones show an economical viable reservoir, it Net pay depth is 39 – 73.5ft. The Porosity and Permeability of the reservoirs suggested a productivity hydrocarbon reservoir. The reservoir lies between Gas sands, Oil sands and Brine sands, reservoir 2 and reservoir 3 are oil sand reservoirs while reservoir 1 lies between an oil sand and a brine sand.

Joint inversion of nuclear magnetic resonance data from partially saturated rocks using a triangular pore model

Measurement of nuclear magnetic resonance (NMR) relaxation is a well-established laboratory/borehole method to characterize the storage and transport properties of rocks due to its direct sensitivity to the corresponding pore-fluid content (water/oil) and pore sizes. Using NMR, the correct estimation of, e.g., permeability strongly depends on the underlying pore model. Usually, one assumes spherical or cylindrical pores for interpreting NMR relaxation data. To obtain surface relaxivity and thus, the pore-size distribution, a calibration procedure by, e.g., mercury intrusion porosimetry or gas adsorption has to be used. Recently, a joint inversion approach was introduced that used NMR measurements at different capillary pressures/saturations (CPS) to derive surface relaxivity and pore-size distribution (PSD) simultaneously. We further extend this approach from a bundle of parallel cylindrical capillaries to capillaries with triangular cross sections. With this approach, it is possible to account for residual or trapped water within the pore corners/crevices of partially saturated pores. In addition, we have developed a method that allows determining the shape of these triangular capillaries by using NMR measurements at different levels of drainage and imbibition. We show the applicability of our approach on synthetic and measured data sets and determine how the combination of NMR and CPS significantly improves the interpretation of NMR relaxation data on fully and partially saturated porous media.

Discrimination of pore fluid and lithology of a well in X Field, Niger Delta, Nigeria

Quantitative rock physics analyses were used to determine the lithology and pore fluid of a reservoir in the Niger Delta. Inaccurate prediction of lithology and pore fluid results in the inaccurate determination of other petrophysical properties and parameters such as porosity, permeability, and net pay. This research is to predict lithology and pore fluid using rock physics analysis. However, reservoir zones were also predicted. Density, compressional wave velocity, and shear wave velocity logs were used as input to calculate elastic parameters such as velocity ratio, Poisson’s ratio, and bulk modulus. The calculated velocity ratio log was used to differentiate between sand and shale. Poisson’s ratio and velocity ratio using Goodway interpretation template were carried out and used to delineate pore fluid content, gas sand, oil sand, and sandstone formation from crossplot analysis.

Mobility Effect on Poroelastic Seismic Signatures in Partially Saturated Rocks With Applications in Time‐Lapse Monitoring of a Heavy Oil Reservoir

AbstractConventional seismic analysis in partially saturated rocks normally lays emphasis on estimating pore fluid content and saturation, typically ignoring the effect of mobility, which decides the ability of fluids moving in the porous rocks. Deformation resulting from a seismic wave in heterogeneous partially saturated media can cause pore fluid pressure relaxation at mesoscopic scale, thereby making the fluid mobility inherently associated with poroelastic reflectivity. For two typical gas‐brine reservoir models, with the given rock and fluid properties, the numerical analysis suggests that variations of patchy fluid saturation, fluid compressibility contrast, and acoustic stiffness of rock frame collectively affect the seismic reflection dependence on mobility. In particular, the realistic compressibility contrast of fluid patches in shallow and deep reservoir environments plays an important role in determining the reflection sensitivity to mobility. We also use a time‐lapse seismic data set from a Steam‐Assisted Gravity Drainage producing heavy oil reservoir to demonstrate that mobility change coupled with patchy saturation possibly leads to seismic spectral energy shifting from the baseline to monitor line. Our workflow starts from performing seismic spectral analysis on the targeted reflectivity interface. Then, on the basis of mesoscopic fluid pressure diffusion between patches of steam and heavy oil, poroelastic reflectivity modeling is conducted to understand the shift of the central frequency toward low frequencies after the steam injection. The presented results open the possibility of monitoring mobility change of a partially saturated geological formation from dissipation‐related seismic attributes.

Qualitative analysis of seismic amplitudes for characterization of Pliocene hydrocarbon sands, eastern offshore India

A comparative study of amplitudes of near- and far- stacks with prestack can be a simple and effective way for characterization of Pliocene hydrocarbon channel sands in offshore India. Synergetic studies of amplitude analysis constrained with well logs and testing data make it possible to predict quality of reservoir sands, the pore fluid content and their production potential. The amplitude studies can also help in taking decisions for testing doubtful zones in drilled wells. An example of a seemingly genuine high amplitude seismic anomaly is authenticated by AVO but testing water is also discussed as an example of seismic pitfall.

Near-Surface Attenuation and Velocity Structures in Taiwan from Wellhead and Borehole Recordings Comparisons

By analyzing the data from 28 seismic borehole stations deployed by the Central Weather Bureau Seismic Network throughout Taiwan from 2007 to 2014, we estimated the near-surface velocity (Vp and Vs) and attenuation (Qp and Qs) structures from surface to depths of approximately 300 m. To ensure that the deeper recordings were on the ray path between the seismic source and upper receiver, only events with an incidence angle of less than 35° were selected. Local magnitudes of analyzed events were between 1.1 and 6.6. The subsurface Qp and Qs were well modeled in the 5 - 40 Hz frequency band using the spectral ratio of direct P- and S-waves, respectively, at each station, under frequency-independent Q and ω^2 source model assumptions. The estimated Vp in the Coastal Plain, the Western Foothills, the Longitudinal Valley, and the Yilan Plain were approximately 1000 - 2000 m s^(-1), which was lower than the Vp of 2500 - 4000 m s^(-1) in the Central Mountain Range. In addition, the Vs in the plain areas were lower than that in the Central Mountain Range. The low Vp and Vs and high Vp/Vs ratio in the Coastal Plain and the Western Foothills can be attributed to the unconsolidated soil and high pore-fluid content of subsurface sediments in the plain areas. In contrast to the velocity distribution, low Qp and Qs were observed in the Central Mountain Range. The low Qp and Qs with low Vp/Vs and low Qs/Qp ratios in the Central Mountain Range was consistent with the high thermal temperature observed in the field investigation. The obtained velocity and attenuation structures near surface could also provide important constraints in validation of the crustal structure of Taiwan.

Three-dimensional Fréchet sensitivity kernels for electromagnetic wave propagation

Electromagnetic (EM) imaging methods are useful tools for monitoring subsurface changes in pore-fluid content and the associated changes in electrical permittivity and conductivity. The most common method for georadar tomography uses a high frequency ray-theoretic approximation that is valid when material variations are sufficiently small relative to the wavelength of the propagating wave. Georadar methods, however, often utilize EM waves that propagate within heterogeneous media at frequencies where ray theory may not be applicable. In this paper we describe EM wave propagation 3-D Fréchet sensitivity kernels that capture the data sensitivity to material perturbations for a given source–receiver combination. Various data functional types are formulated that consider all three components of the electric wavefield and incorporate near-, intermediate- and far-field contributions. We show that EM waves exhibit substantial variations for different relative source–receiver component orientations. The 3-D sensitivities also illustrate out of plane effects that are not captured in 2-D sensitivity kernels and can influence results obtained using 2-D inversion methods to image structures that are in reality 3-D.

Rock physics modeling to assess the impact of spatial distribution pattern of pore fluid and clay contents on acoustic signatures of partially-saturated reservoirs

The identification of pore fluid type, saturation and distribution pattern within the pore space is of great significance as several seismic and petrophysical properties of porous rocks vary largely by fluid type, saturation and fluid distribution pattern. With the help of rock physics modeling, the impact of fluid saturation as well as fluid distribution pattern on seismic velocities, acoustic impedances and seismic amplitudes is estimated on porous rock of early Cretaceous Mississauga sands. For this purpose two saturation patterns: uniform and patchy saturations are considered within the pore spaces. The primary goal of this study is to understand the vertical and horizontal trends of numerous seismic parameters such as P-wave velocity (V P ), S-wave velocity (V S ), their impedances, V P /V S ratio, bulk density (ρ b ), seismic reflectivity etc. as a function of fluid saturation, saturation pattern (patchy or homogeneous), porosity (ϕ) and clay content. The results reveal that the seismic parameters and offset dependent amplitudes are very sensitive to pore fluid saturation and distribution patterns and physical properties. As the hydrocarbons (oil/gas) saturation increases, the compressional wave velocity decreases. P-wave velocity is 20–40 % higher in case of patchy saturation than of homogeneous saturation. Similarly, reservoir porosity and clay matrix control the elastic response of porous rock due to which seismic velocities decrease with increase in porosity and clay content.

Scattering and intrinsic attenuation in Cairo metropolitan area using genetic algorithm

A total number of 46 local earthquakes (2.0≤ML≤4.0) recorded in the period 2000–2011 by the Egyptian seismographic network (ENSN) were used to estimate the total (Qt−1), intrinsic (Qi−1) and scattering attenuation (Qsc−1) in Cairo metropolitan area, Egypt. The multiple lapse time window analysis (MLTWA) under the assumption of multiple isotropic scattering with uniform distribution of scatters was firstly applied to estimate the pair of Le−1, the extinction length inverse, and B0, the seismic albedo, in the frequency range 3–24Hz. To take into account the effect of a depth-dependent earth model, the obtained values of B0 and Le−1 were corrected for an earth structure characterized by a transparent upper mantle and a heterogeneous crust. The estimated values of Qt−1, Qsc−1 and Qi−1 exhibited frequency dependences. The average frequency-dependent relationships of attenuation characteristics estimated for the region are found to be: Qt−1=(0.015±0.008)f(−1.02±0.02), Qsc−1=(0.006±0.001)f(−1.01±0.02), and Qi−1=(0.009±0.008)f(−1.03±0.02); showing a predominance of intrinsic absorption over scattering attenuation. This finding implies that the pore-fluid contents may have great effect on the attenuation mechanism in the upper crust where the River Nile is passing through the study area. The obtained results are comparable with those obtained in other tectonic regions.

A comparison of shale permeability coefficients derived using multiple non-steady-state measurement techniques: Examples from the Duvernay Formation, Alberta (Canada)

Matrix permeability, while an important control on fluid flow in unconventional reservoirs, is difficult to measure in the laboratory. There are now multiple methods for laboratory determination of permeability for shales, but little consensus on the appropriate method for permeability measurement. Each technique is based on different physical principles and utilizes reservoir samples at different scales. The combination of sample size and preparation and measurement conditions can lead to a wide range in permeability estimates, creating confusion for recipients of the data. In this work, we compare different non-steady state methods for determination of gas permeability in low-permeability Canadian shales and provide insight into the causes of permeability variation. Further, we analyze and discuss the effects of different controlling factors including porosity, pore-fluid content, mineralogy and effective stress on permeability.Gas permeability measurements were conducted on low-permeability (shale) samples from the Duvernay Formation (Alberta, Canada) using three different methods: profile (probe), pulse-decay and crushed-rock permeability techniques. The analyzed samples differ in total organic carbon (TOC) content, pore network characteristics (porosity, pore size distribution), pore-fluid content (“as-received” and cleaned/dried) and mineralogy. Profile (probe) and crushed-rock permeability measurements were performed on samples in the “as-received” and cleaned/dried conditions. Pulse-decay measurements were conducted on samples in the cleaned/dried state. Helium pycnometry/expansion measurements were performed using “as-received” and cleaned/dried samples under unconfined and controlled “in situ” effective stress conditions.Permeability values derived for the Duvernay samples are strongly dependent on measurement technique, sample size and sample conditions. In the “as-received” state, profile (probe) permeability values, both uncorrected (3.7×10−4–2.7×10−2mD) and corrected (1.5×10−5–5.7×10−4mD) for “in-situ” stress, are consistently higher than crushed-rock (3.7×10−7–5.9×10−6mD) permeability values. Similarly, in the cleaned/dried state, profile (probe) permeability values, both uncorrected (1.9×10−2–1.2mD) and corrected (5.8×10−5–1.4×10−2mD) for “in-situ” stress, are consistently higher than pulse-decay (8.4×10−5–7.6×10−4mD) and crushed-rock (3.8×10−5–1.1×10−3mD) permeability values. In the cleaned/dried state, pulse-decay permeability values (8.4×10−5–7.6×10−4mD) are comparable with crushed-rock (3.8×10−5–1.1×10−3mD) permeability values. Profile (probe) and crushed-rock permeability values measured on cleaned/dried samples are approximately two orders of magnitude higher than those measured on “as-received” samples.The observed discrepancies between permeability values derived from the various non-steady-state techniques is rationalized in terms of sample size, treatment, stress-state and physical principals of measurement. The combined use of these methods is however recommended to provide insight into the controls of sample heterogeneity at sub-cm scales, which is particularly important for shale samples.