Showing papers on "Permeability (earth sciences) published in 2011"

Carbon Dioxide Storage Capacity of Organic-Rich Shales

Abstract: This paper (SPE 134583) was accepted for presentation at the SPE Annual Technical Conference and Exhibition, Florence, Italy, 20–22 September 2010, and revised for publication. Original manuscript received for review 28 June 2010. Revised manuscript received for review 28 September 2010. Paper peer approved 5 October 2010. Summary This paper presents an experimental study on the ability of organic-rich-shale core samples to store carbon dioxide (CO2). An apparatus has been built for precise measurements of gas pressure and volumes at constant temperature. A new analytical methodology is developed allowing interpretation of the pressure/volume data in terms of measurements of total porosity and Langmuir parameters of core plugs. The method considers pore-volume compressibility and sorption effects and allows small gas-leakage adjustments at high pressures. Total gas-storage capacity for pure CO2 is measured at supercritical conditions as a function of pore pressure under constant reservoir-confining pressure. It is shown that, although widely known as an impermeable sedimentary rock with low porosity, organic shale has the ability to store significant amount of gas permanently because of trapping of the gas in an adsorbed state within its finely dispersed organic matter (i.e., kerogen). The latter is a nanoporous material with mainly micropores (< 2 nm) and mesopores (2–50 nm). Storage in organic-rich shale has added advantages because the organic matter acts as a molecular sieve, allowing CO2—with linear molecular geometry—to reside in small pores that the other naturally occurring gases cannot access. In addition, the molecular-interaction energy between the organics and CO2 molecules is different, which leads to enhanced adsorption of CO2. Hence, affinity of shale to CO2 is partly because of steric and thermodynamic effects similar to those of coals that are being considered for enhanced coalbed-methane recovery. Mass-transport paths and the mechanisms of gas uptake are unlike those of coals, however. Once at the fracture/matrix interface, the injected gas faces a geomechanically strong porous medium with a dual (organic/inorganic) pore system and, therefore, has choices of path for its flow and transport into the matrix: the gas molecules (1) dissolve into the organic material and diffuse through a nanopore network and (2) enter the inorganic material and flow through a network of irregularly shaped voids. Although gas could reach the organic pores deep in the shale formation following both paths, the application of the continua approximation requires that the gas-flow system be near or beyond the percolation threshold for a consistent theoretical framework. Here, using gas permeation experiments and history matching pressure-pulse decay, we show that a large portion of the injected gas reaches the organic pores through the inorganic matrix. This is consistent with scanning-electron-microscope (SEM) images that do not show connectivity of the organic material on scales larger than tens of microns. It indicates an in-series coupling of the dual continua in shale. The inorganic matrix permeability, therefore, is predicted to be less, typically on the order of 10 nd. More importantly, although transport in the inorganic matrix is viscous (Darcy) flow, transport in the organic pores is not due to flow but mainly to molecular transport mechanisms: pore and surface diffusion.

Shale-Gas Permeability and Diffusivity Inferred by Improved Formulation of Relevant Retention and Transport Mechanisms

Abstract: 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.

A numerical study of microscale flow behavior in tight gas and shale gas reservoir systems

Abstract: Various attempts have been made to model flow in shale gas systems. However, there is currently little consensus regarding the impact of molecular and Knudsen diffusion on flow behavior over time in such systems. Direct measurement or model-based estimation of matrix permeability for these “ultra-tight” reservoirs has proven unreliable. The composition of gas produced from tight gas and shale gas reservoirs varies with time for a variety of reasons. The cause of flowing gas compositional change typically cited is selective desorption of gases from the surface of the kerogen in the case of shale. However, other drivers for gas fractionation are important when pore throat dimensions are small enough. Pore throat diameters on the order of molecular mean free path lengths will create non-Darcy flow conditions, where permeability becomes a strong function of pressure. At the low permeabilities found in shale gas systems, the dusty-gas model for flow should be used, which couples diffusion to advective flow. In this study we implement the dusty-gas model into a fluid flow modeling tool based on the TOUGH+ family of codes. We examine the effects of Knudsen diffusion on gas composition in ultra-tight rock. We show that for very small average pore throat diameters, lighter gases are preferentially produced at concentrations significantly higher than in situ conditions. Furthermore, we illustrate a methodology which uses measurements of gas composition to more uniquely determine the permeability of tight reservoirs. We also describe how gas composition measurement could be used to identify flow boundaries in these reservoir systems. We discuss how new measurement techniques and data collection practices should be implemented in order to take advantage of this method. Our contributions include a new, fit-for-purpose numerical model based on the TOUGH+ code capable of characterizing transport effects including permeability adjustment and diffusion in micro- and nano-scale porous media.

Mapping permeability over the surface of the Earth

Abstract: [1] Permeability, the ease of fluid flow through porous rocks and soils, is a fundamental but often poorly quantified component in the analysis of regional-scale water fluxes Permeability is difficult to quantify because it varies over more than 13 orders of magnitude and is heterogeneous and dependent on flow direction Indeed, at the regional scale, maps of permeability only exist for soil to depths of 1–2 m Here we use an extensive compilation of results from hydrogeologic models to show that regional-scale (>5 km) permeability of consolidated and unconsolidated geologic units below soil horizons (hydrolithologies) can be characterized in a statistically meaningful way The representative permeabilities of these hydrolithologies are used to map the distribution of near-surface (on the order of 100 m depth) permeability globally and over North America The distribution of each hydrolithology is generally scale independent The near-surface mean permeability is of the order of ∼5 × 10−14 m2 The results provide the first global picture of near-surface permeability and will be of particular value for evaluating global water resources and modeling the influence of climate-surface-subsurface interactions on global climate change

Transverse permeability of fibrous porous media

Abstract: In this study, the transverse permeability of fibrous porous media is studied both experimentally and theoretically. A scale analysis technique is employed for determining the transverse permeability of various fibrous matrices including square, staggered, and hexagonal arrangements of unidirectionally aligned fibers, as well as simple two-directional mats and simple cubic structures. In the present approach, the permeability is related to the porosity, fiber diameter, and tortuosity of the medium. In addition, the pressure drop in several samples of tube banks of different arrangements and metal foams are measured in the creeping flow regime. The pressure-drop results are then used to calculate the permeability of the samples. The developed compact relationships are successfully verified through comparison with these experimental results and the data reported by others. Our results suggest that fiber orientation has an important effect on the permeability; however, these effects are more pronounced in low porosities, i.e., ɛ<0.7.

Laboratory observations of permeability enhancement by fluid pressure oscillation of in situ fractured rock

Abstract: Received 5 June 2010; revised 5 November 2010; accepted 22 December 2010; published 24 February 2011. [1] We report on laboratory experiments designed to investigate the influence of pore pressure oscillations on the effective permeability of fractured rock. Berea sandstone samples were fractured in situ under triaxial stresses of tens of megapascals, and deionized water was forced through the incipient fracture under conditions of steady and oscillating pore pressure. We find that short‐term pore pressure oscillations induce long‐term transient increases in effective permeability of the fractured samples. The magnitude of the effective permeability enhancements scales with the amplitude of pore pressure oscillations, and changes persist well after the stress perturbation. The maximum value of effective permeability enhancement is 5 × 10 −16 m 2 with a background permeability of 1 × 10 −15 m 2 ; that is, the maximum enhanced permeability is 1.5 × 10 −15 m 2 . We evaluate poroelastic effects and show that hydraulic storage release does not explain our observations. Effective permeability recovery following dynamic oscillations occurs as the inverse square root of time. The recovery indicates that a reversible mechanism, such as clogging/unclogging of fractures, as opposed to an irreversible one, like microfracturing, is responsible for the transient effective permeability increase. Our work suggests the feasibility of dynamically controlling the effective permeability of fractured systems. The result has consequences for models of earthquake triggering and permeability enhancement in fault zones due to dynamic shaking from near and distant earthquakes.

Insights into pore-scale controls on mudstone permeability through resedimentation experiments

Abstract: At a given porosity, mudstone permeability increases by an order of magnitude for clay contents ranging from 57% to 36% (<2 μm). This increase in vertical permeability results from a dual-porosity system that develops through three mechanisms: (1) silt bridging preserves large pore throats, (2) stress bridges inhibit clay particle alignment, and (3) local clay particle compression within stress bridges alters pore throat size distribution. Uniaxial consolidation experiments on resedimented clay-silt mixtures illuminate how permeability varies as a function of clay fraction during burial. Backscattered electron microscope images show that silty mixtures have larger pore throats and fewer aligned clay particles than do more clay-rich mixtures. We describe the permeability of clay-silt mixtures with a geometric mean model. Our method provides a promising framework for modeling of mudstone permeability as a function of clay fraction and porosity. How permeability and consolidation evolve during burial affects the ability of mudstones to seal CO2 and hydrocarbons in the subsurface, how mudstones behave as gas reservoirs, and under what conditions mudstones will be overpressured. Dual-porosity systems have fundamentally different transient flow and solute transport behaviors.

Permeability of Laboratory-Formed Methane-Hydrate-Bearing Sand: Measurements and Observations Using X-Ray Computed Tomography

Abstract: Methane hydrate was formed in two moist sands and a sand/silt mixture under a confining stress in an X-ray-transparent pressure vessel. Three initial water saturations were used to form three different methane-hydrate saturations in each medium. X-ray computed tomography (CT) was used to observe location-specific density changes caused by hydrate formation and flowing water. Gas-permeability measurements in each test for the dry, moist, frozen, and hydrate-bearing states are presented. As expected, the effective permeabilities (intrinsic permeability of the medium multiplied by the relative permeability) of the moist sands decreased with increasing moisture content. In a series of tests on a single sample, the effective permeability typically decreased as the pore space became more filled, in the order of dry, moist, frozen, and hydrate-bearing. In each test, water was flowed through the hydrate-bearing medium and we observed the location-specific changes in water saturation using CT scanning. We compared our data to a number of models, and our relative permeability data compare most favorably with models in which hydrate occupies the pore bodies rather than the pore throats. Inverse modeling (using the data collected from the tests) will be performed to extend the relative permeability measurements.

Experimental measurement of, and controls on, permeability and permeability anisotropy of caprocks from the CO2 storage project at the Krechba Field, Algeria

Abstract: [1] The long-term success of the geological storage of CO2 is dependent on the integrity of the sealing horizons, yet there is a paucity of data on permeability, permeability anisotropy, and factors that affect them. Using samples from an ongoing field trial for CO2 sequestration, this paper presents measured vertical (kv) and horizontal (kh) permeabilities across a range of effective pressures. Petrological and petrophysical analyses highlight what are the dominant controls on permeability. The Krechba field in Algeria is one of the largest CO2 storage projects currently running with over 3M tonnes of CO2 injected since 2004. Experimental samples of the caprock and underlying storage domain were recovered from the base of the succession. Caprock permeability ranges from 10−23 to 10−19 m2. Permeability decreases with decreasing porosity and pore throat radius and increasing clay mineral content. Primary depositional heterogeneous distribution of clay minerals produced contrasting layers of relatively low and high permeability resulting in extreme kh/kv ratios of up to 50,000. Samples with the same porosity, mean pore throat size and clay mineral content can have kh/kv differing by >4 orders of magnitude. The data was used to model permeability using the Yang-Aplin model. Accuracy of the predicted permeabilites was found to reflect the measured permeability anisotropy. The results highlight that lateral migration of CO2 will be significant and that the caprock succession at Krechba should provide a good seal, even with decreasing effective pressure during injection, in the absence of significant modification by deformation and/or reaction with the CO2-rich fluids.

Shale Oil Production Performance from a Stimulated Reservoir Volume

Abstract: The horizontal well with multiple transverse fractures has proven to be an effective strategy for shale gas reservoir exploitation. Some operators are successfully producing shale oil using the same strategy. Due to its higher viscosity and eventual 2-phase flow conditions when the formation pressure drops below the oil bubble point pressure, shale oil is likely to be limited to lower recovery efficiency than shale gas. However, the recently discovered Eagle Ford shale formations is significantly over pressured, and initial formation pressure is well above the bubble point pressure in the oil window. This, coupled with successful hydraulic fracturing methodologies, is leading to commercial wells. This study evaluates the recovery potential for oil produced both above and below the bubble point pressure from very low permeability unconventional shale oil formations. We explain how the Eagle Ford shale is different from other shales such as the Barnett and others. Although, Eagle Ford shale produces oil, condensate and dry gas in different areas, our study focuses in the oil window of the Eagle Ford shale. We used the logarithmically gridded locally refined gridding scheme to properly model the flow in the hydraulic fracture, the flow from the fracture to the matrix and the flow in the matrix. The steep pressure and saturation changes near the hydraulic fractures are captured using this gridding scheme. We compare the modeled production of shale oil from the very low permeability reservoir to conventional reservoir flow behavior. We show how production behavior and recovery of oil from the low permeability shale formation is a function of the rock properties, formation fluid properties and the fracturing operations. The sensitivity studies illustrate the important parameters affecting shale oil production performance from the stimulated reservoir volume. The parameters studied in our work includes fracture spacing, fracture half-length, rock compressibility, critical gas saturation (for 2 phase flow below the bubble point of oil), flowing bottom-hole pressure, hydraulic fracture conductivity, and matrix permeability. The sensitivity studies show that placing fractures closely, increasing the fracture half-length, making higher conductive fractures leads to higher recovery of oil. Also, the thesis stresses the need to carry out the core analysis and other reservoir studies to capture the important rock and fluid parameters like the rock permeability and the critical gas saturation.