Topic
Permeability (earth sciences)
About: Permeability (earth sciences) is a research topic. Over the lifetime, 15424 publications have been published within this topic receiving 288535 citations.
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TL;DR: In this paper, the effects of temperature on the physical properties and mechanical and permeability behavior of sandstone were analyzed, and a series of empirical relations between the temperatures and physical and mechanical properties were derived, and are expected to aid in geothermal energy extraction from super-critical temperature resources.
133 citations
TL;DR: In this article, a large number of natural marine sediment samples from the Gulf of Mexico were determined through the use of laboratory consolidation tests and a statistical analysis of the natural log of permeability versus porosity was used to develop the permeability prediction equation for each of the groups listed.
Abstract: Permeability of a large number of natural marine sediment samples from the Gulf of Mexico was determined through the use of laboratory consolidation tests. The samples were divided into the following groups: Group 1, sediment consisting of more than 80% clay (material 2 μm or less in size); Group 2, sediment containing from 60 to 80% clay‐size material; Group 3, silty clays with less than 60% clay; and Group 4, silts and clays that have a significant sand‐size fraction present (more than 5% sand). The permeabilities of the groups ranged from 10−5 to 10−10 cm/s with 35% normal seawater being used as the saturating fluid.
A statistical analysis of the natural log of permeability versus porosity was used to develop the permeability prediction equation for each of the groups listed. The equation for Group 1 is k =en(15.05)‐27.37. for Group 2, k=en(14. 18)‐26.50. for Group 3, k= en(15.59)‐26.65. for Group 4 k=en(17.51)‐26.93.and for all data, k = en(14.30)‐26.30; wherc n is the porosity (in decimals) and k is the coefficient of permeability. These equations are useful for predicting changes in permeability with depth in fine‐grained sediments of the Gulf of Mexico. The ability to predict permeability in a continuous sequence, where the deposition history is known, may explain the large variations that we see in the physical properties in sediments similar in grain size and mineralogy.
132 citations
TL;DR: In this paper, the authors describe the construction and analysis of the results obtained from the two-and three-dimensional geomechanical and gas flow models experienced around an active deep UK longwall coal production panel.
132 citations
20 Mar 2012
TL;DR: In this paper, the authors discuss the state-of-the-art in petrophysical evaluation of shale gas reservoirs, summarize the experiences of operators and researchers, and bring some views on the criteria and techniques for the evaluation of cores and logs.
Abstract: Unconventional reservoirs have burst with considerable force in oil and gas production worldwide. Shale Gas is one of them, with intense activity taking place in regions like North America. To achieve commercial production, these reservoirs should be stimulated through massive hydraulic fracturing and, frequently, through horizontal wells as a mean to enhance productivity. In sedimentary terms, shales are fine-grained clastics rocks formed by consolidation of silts and clays. In log interpretation of conventional reservoirs, it is very common to observe that the clay parameters used to correct porosity and resistivity logs for clay effects are in fact read in shaly intervals rather than in pure clay. Although no considerable deviation have been observed in shaly sandstones, anyway these concepts and procedures must be reviewed to run log analysis in shale gas. Organic matter deposited with shales containing kerogen that matured as a result of overburden pressure and temperature, giving rise to source rocks that have yielded and expulsed hydrocarbons. Shale gas reservoir type is a source rock that has retained a portion of the hydrocarbon yielded during its geological history so that to evaluate the current hydrocarbon storage and production potential it is necessary to know the kerogen type and the level of TOC - total organic carbon - in the rock. Produced gas comes from both adsorbed gas in the organic matter and "free" gas trapped in the pores of the organic matter and in the inorganic portions of the matrix, i.e. quartz, calcite, dolomite. In these unconventional reservoirs, gas volumes are estimated through a combination of geochemical analysis and log interpretation techniques. TOC, desorbed total gas content, adsorption isotherms, and kerogen maturity among other things can be measured in cores, sidewall samples and cuttings, in the laboratory. These data are used to estimate total desorbed gas content and adsorbed gas content which is part of the total gas. Also in laboratory, porosity, grain density, water saturation, permeability, mineral composition and elastic modules of the rock are measured. Laboratory measurement uncertainty is high and consistency between different providers appears to be low, with serious suspicions that procedures followed by different laboratories are the source of such differences. The permeability is one of the most important parameters, but at the same time, one of the most difficult to measure reliably in a shale gas. Core calibrated porosity, mineral composition, water saturation and elastic modules can be obtained through electric and radioactive logs. All these information is used to estimate log derived total gas volume which results are also subject to a high degree of uncertainty that must be overcome. Once this key information is obtained, it is possible to estimate different gas in-situ volumes. Indeed, an estimate of porosity-resistivity based total gas in-situ and, on the other hand, geochemical based adsorbed gas in-situ can be performed. Log total gas in-situ can be, and it is advisable to do, compared with adsorbed gas estimations and also with another gas measurement called direct method - total gas desorption performed on formation samples. The difference between log total gas in-situ and adsorbed gas in situ should be the "free" gas in situ. Free gas occupies the pores of kerogen and matrix; also it can be stored in open natural fractures if such fractures are present. The main objective of this paper is to discuss the state-of-the-art in petrophysical evaluation of shale gas reservoirs, to summarize the experiences of operators and researchers, and to bring some views on the criteria and techniques for the evaluation of cores and logs. An inventory of laboratory tests and results, log responses in the presence of kerogen, log interpretation techniques and estimation methods for different volumes of gas in-situ, together with important aspects of the use of analogy in shale gas reservoirs has been done. At the end, a basic petrophysical workflow is outlined for the volumetric determination of gas in situ.
132 citations
TL;DR: In this paper, two averaging algorithms are proposed for determining block effective absolute permeability based on the experimental relationship between the effective permeability, the volume fraction of shale, and the anisotropy of the shales.
Abstract: In this paper two averaging algorithms are proposed for determining block effective absolute permeability. The experimental relationship between the effective permeability, the volume fraction of shale, and the anisotropy of the shales is first observed through repeated flow simulations. A power-averaging model and a percolation model are proposed to fit the experimentally observed relationship. The power-averaging model provides a surprisingly easy and efficient way to calculate block effective absolute permeability. A simple graph is given to determine the averaging power from the geometric anisotropy (aspect ratio) of the shales for both vertical and horizontal steady-state flow. A correction for large shales relative to small gridblocks is also proposed.
131 citations