Degree Of Permeability Anisotropy Research Articles

Coupling model of gas-water two-phase productivity calculation for fractured horizontal wells in tight gas reservoirs

Tight gas reservoirs are exploited mostly by using horizontal wells in combination with multi-stage hydraulic fracturing. Up to now, there have been plenty of studies conducted to establish a series of productivity models that consider various factors. Despite this, insufficient consideration has been given to the ramifications resulting from secondary fractures, permeability anisotropy, wellbore pressure drop, and the actual distribution of fractures. To accurately evaluate productivity, the superposition principle of potential and the conformal transformation theory are adopted to define the two-phase generalized pseudo-pressure, with consideration given to the characteristics of non-Darcy seepage in tight gas reservoirs and the effects of secondary fractures and permeability anisotropy on productivity. On this basis, the homogeneous flow model of the horizontal wellbore is introduced to establish the coupling model of gas-water two-phase productivity calculation for fractured horizontal wells. The results obtained from the empirical calculation and analysis of various factors affecting productivity are as follows. Firstly, the relative error is 5.35% between the theoretical open flow capability obtained from the proposed model and the open flow capability determined through the deliverability test, which attests to the proposed model's accuracy. Secondly, in response to an increase in gas slippage factor, fracture conductivity, the number of fractures, and the degree of permeability anisotropy, there is an improvement in the productivity of the gas well. However, with a rise in the water-gas volume ratio, threshold pressure gradient, reservoir stress sensitivity index, and the angle formed between the horizontal wellbore and the main permeability, the productivity declines. Lastly, the pressure drop along the horizontal wellbore is relatively insignificant, which has no substantial impact on fracture production. However, when the effect of secondary fractures is ignored, the predicted productivity is relatively low. This study offers theoretical direction for the application of productivity prediction and fracturing optimization design.

Influence of stress redistribution and fracture orientation on fracture permeability under consideration of surrounding rock in underground gas storage

UGS (underground gas storage) is of great significance for ensuring emergent supply and CCUS (Carbon Capture, Utilization, and Storage). However, very different from gas reservoir development, some stress changes in reservoir, caprock, and bottom support rock may affect its operation. Sichuan Basin is rich in natural-gas resources and geological targets for the UGS rebuilt from fractured carbonate reservoirs. Moreover, gas storage is featured by rapid injection and production, and the change of in-situ stress affects intensively the permeability of reservoir fracture. However, most existing models on the fracture permeability assume that the surrounding-rock stress is constant. So, a new model has been established for the fracture permeability based on the Eshelby theory, considering the effect of both direct caprock and bottom support rock (also called surrounding rock) and the stress redistribution mechanism of the entire geological body during UGS injection and production. Results show that for the fracture, the permeability is related to not only its compressibility and orientation, but also reservoir shape and elastic property of the entire geological body including reservoir and surrounding rock. In most disk-shaped or elliptical reservoirs, vertical fracture is less susceptible to pore pressure than horizontal one. The surrounding-rock elastic property is also an important factor in the fracture-permeability model. Hard surrounding rock can reduce the stress sensitivity in fracture. When the elastic modulus ratio (elastic modulus of reservoir vs. that of surrounding rock) is 0.1, the fracture permeability decreases by only 15%. This model is also applicable to multiple fractures. Using the superposition principle, it is found that the main direction of permeability and the degree of permeability anisotropy may change when there are multiple fractures in the reservoir in spite of the same fracture compressibility.

The influence of inhomogeneous hydrate formation on permeability anisotropy of porous media

Hydrate formation is an inhomogeneous process, which results in permeability anisotropy, i.e., permeability differs in different directions. Permeability anisotropy of hydrate-bearing sands is analyzed based on CT (computed tomography) scanning and pore network modeling in this study. A digital sample is divided into eight different parts based on hydrate distribution. Eight equivalent micropore structures are extracted by the maximum ball method. The absolute and relative permeabilities of each part in three different directions (x, y, and z) are calculated by a permeability simulator. Before hydrate formation, the sand pack permeability in the different directions is nearly the same. After hydrate formation, the sample pore structures become more complex. Both the absolute and relative permeabilities vary in the different directions. When hydrate saturation exceeds a threshold, the degree of permeability anisotropy is weakened. Hydrate formation induces a more significant relative gas permeability anisotropy compared to relative water permeability anisotropy. The degree of relative water permeability anisotropy increases at high water saturations.

Permeability and paleoenvironmental implications of loess–paleosol sequence from Jingyang Loess Plateau

Eolian loess in China contains abundant information about paleoclimate evolution, but there have been few studies of the relationship between the changing permeability of loess and the paleoenvironment. To investigate how loess–paleosol permeability responds to climate change, 342 undisturbed soil samples were collected from the Jingyang Loess Plateau in the Guanzhong Basin. Permeability was measured by a TST-55 permeameter and soil microstructures were observed with a scanning electron microscope (SEM). The results showed that: (1) the permeability of the loess layers was higher than that of the paleosol layers; (2) loess–paleosol sequence permeability had a four-stage accumulation history; (3) the degree of permeability anisotropy (DPA) of most of the loess was greater than 1, whereas that of the paleosol layers were less than 1; (4) loess and paleosol microstructures were consistent with the results obtained by permeability, whose changes had been mainly caused by the pedogenesis controlled by the Quaternary climate. The higher permeability of the loess layers was largely the result of lower pedogenesis intensity due to the cold/dry climatic conditions at the time when the sediments were deposited. Conversely, the lower permeability of the paleosol layers was the result of higher pedogenesis intensity under warm/wet climatic conditions. Based on the permeability, DPA, and soil microstructures, we concluded that the gradual uplift of the Qinling Mountains and the changes in the intensity of the East Asian monsoon had played important roles in controlling the evolution of the climate in the Guanzhong Basin. Therefore, loess permeability can reflect Quaternary climate change and provide a new research method for interpreting the characteristics of the Jingyang Loess Plateau.

Characterizing anisotropy changes in the permeability of hydrate sediment

Natural gas hydrate is recognized as an ideal substitute for traditional energy resources. Gas production from hydrate reservoirs is accompanied by the phase transition of solid hydrate, which inevitably results in changes to the microstructure of hydrate sediments. Therefore, the interaction mechanism between the microstructure and permeation characteristics of hydrate sediments must be investigated, especially permeability anisotropy. In this study, we assess the variations in permeability anisotropy during krypton hydrate formation using a pore network model and X-ray computed tomography. The results showed that absolute permeability in the vertical (kv) and horizontal (kh) directions both decreased throughout the formation process, but that the decline in kv was steeper, thus resulting in a sharp increase in the degree of permeability anisotropy (kh/kv). The relative permeability to gas was always higher in the horizontal direction than of that in the vertical direction, whereas the relative permeability to water was the opposite. Moreover, the difference in the relative permeability to water and gas between the two directions increased with the increasing hydrate saturation (Sh). When extrapolating to the field-scale for hydrate field trials, we consider that horizontal wells provide a better option for gas production, especially for hydrate reservoirs with a higher hydrate saturation.

Vertical-horizontal permeability correlations using coring data

Most reservoirs have different degree of permeability anisotropy. Optimization of recovery is crucially dependent on the reservoir quality and ansitropy. The ratio of vertical and horizontal permeability is important when reservoir anisotropy (Kv/Kh) and heterogeneity cannot be neglected. Therefore, an accurate knowledge of vertical and lateral permeability distribution is essential for better reservoir characterization.This work uses routine core data for analysis to develop new correlations and characterization of a sandstone reservoir under development. The two main goals of this study are to use core data to (1) develop correlations capable to predict vertical permeability from horizontal permeability or mean hydraulic radius and (2) develop another correlation capable to predict the permeability anisotropy ratio (Kv/Kh) using porosity data.To accomplish the objectives of this project, various petrophysical properties were experimentally measured for 112 core samples extracted from an actual sandstone reservoir. The measurements included vertical permeability, horizontal permeability, effective porosity and saturations of oil and water.The data derived were used to develop new and improved correlations capable to predict vertical permeability from horizontal permeability for the zones that were analyzed. In addition, another correlation is developed to predict anisotropy ratio from effective porosity.Applications of the developed results of this study help enhancing the prediction of vertical permeability, improving reservoir characterization and providing better simulation studies.

Effect of Joint Geometry and Transmissivity on Jointed Rock Hydraulics

The effect of joint geometry parameters (joint orientation, joint density, and joint size) and joint transmissivity on the hydraulic properties of jointed rock blocks was examined in two dimensions using joint networks with two joint sets through numerical experiments. The chance for equivalent continuum hydraulic behavior and the average block permeability of jointed rock were found to be very sensitive to the relative orientation of the joint sets in a joint network system. Although both the equivalent continuum behavior and the average block permeability seem to be little affected by the change of the standard deviation of the joint orientation distribution, the degree of permeability anisotropy seems to depend on the standard deviation of the joint orientation especially for anisotropic joint systems. Chance for the equivalent continuum behavior and the average block permeability were found to increase with the increase of joint density and joint size. The chance for equivalent continuum behavior and the permeability anisotropy were found to depend on the distribution of joint hydraulic conductivity. The influence of the joint hydraulic conductivity is more prominent for joint systems with high joint density and large joint sizes. The greater the variation of the hydraulic conductivity value among the joints in a joint set, the lesser the chance for the medium to behave like an equivalent continuum porous medium.

Magnetic pore fabric analysis: a rapid method for estimating permeability anisotropy

SUMMARY The average orientation and fabric anisotropy of interconnected pore spaces in sandstones is derived from magnetic pore fabric analysis, a new technique which measures the anisotropy of magnetic susceptibility (AMS) of samples impregnated with a magnetic suspension. In magnetic pore fabric analysis, the permeable part of the porous network, consisting of pore bodies connected by pore throats, is rendered magnetically susceptible. AMS directly yields the average elongation direction of pore bodies and offers a simple way to investigate the effect of pore-shape anisotropy on petrophysical parameters such as hydraulic and electrical conductivity. AMS-derived pore fabric of sandstones of moderate diagenetic state is compared to permeability anisotropy measured directly on the same specimens. For any one sample, the orientation of the two tensors and their representation ellipsoids correlate closely. The preferred orientation of interconnected pores facilitates fluid flow parallel to the direction of pore elongation and causes the observed anisotropy of permeability. Axial ratios of the two anisotropy ellipsoids correlate less closely but show a trend of proportionality. Compared to the time-consuming measurement of directional permeabilities, magnetic pore fabric analysis may, therefore, provide a rapid way to estimate the orientation and, to a lesser extent, the degree of permeability anisotropy in porous sandstones. The analysis of six specimens extracted from a large, homogeneous block sample proves the accuracy and reliability of the method. In five fluvial sandstone samples, maximum permeability and pore elongation are roughly parallel to the palaeocurrent direction. Therefore, magnetic pore fabric analysis can also be used to study the relationship between permeability, pore fabric and sedimentary structures.

Determination of Permeability Anisotropy in a Two-Way Permeameter

Abstract This paper describes the use of a new item of laboratory equipment, a two-way permeameter for determination of the degree of permeability anisotropy of compacted or undisturbed samples of soil. The test is performed on a single sample of soil. The relevant theoretical solutions for seepage flow through the permeameter have been provided, based on exact solutions and manual sketching of flow nets.

The Behavior of Naturally Fractured Reservoirs

Abstract An idealized model has been developed for the purpose of studying the characteristic behavior of a permeable medium which contains regions which contribute significantly to the pore volume of the system hut contribute negligibly to the flow capacity; e.g., a naturally fractured or vugular reservoir. Unsteady-state flow in this model reservoir has been investigated analytically. The pressure build-up performance has been examined in some detail; and, a technique for analyzing the build-up data to evaluate the desired parameters has been suggested. The use of this approach in the interpretation of field data has been discussed. As a result of this study, the following general conclusions can be drawn:Two parameters are sufficient to characterize the deviation of the behavior of a medium with "double porosity" from that of a homogeneously porous medium.These parameters can be evaluated by the proper analysis of pressure build-up data obtained from adequately designed tests.Since the build-up curve associated with this type of porous system is similar to that obtained from a stratified reservoir, an unambiguous interpretation is not possible without additional information.Differencing methods which utilize pressure data from the final stages of a build-up test should be used with extreme caution. Introduction In order to plan a sound exploitation program or a successful secondary-recovery project, sufficient reliable information concerning the nature of the reservoir-fluid system must be available. Since it is evident that an adequate description of the reservoir rock is necessary if this condition is to be fulfilled, the present investigation was undertaken for the purpose of improving the fluid-flow characterization, based on normally available data, of a particular porous medium. DISCUSSION OF THE PROBLEM For many years it was widely assumed that, for the purpose of making engineering studies, two parameters were sufficient to describe the single-phase flow properties of a producing formation, i.e., the absolute permeability and the effective porosity. It later became evident that the concept of directional permeability was of more than academic interest; consequently, the degree of permeability anisotropy and the orientation of the principal axes of permeability were accepted as basic parameters governing reservoir performance. More recently, it was recognized that at least one additional parameter was required to depict the behavior of a porous system containing regions which contributed significantly to the pore volume but contributed negligibly to the flow capacity. Microscopically, these regions could be "dead-end" or "storage" pores or, macroscopically, they could be discrete volumes of low-permeability matrix rock combined with natural fissures in a reservoir. It is obvious that some provision for the inclusion of all the indicated parameters, as well as their spatial variations, must be made if a truly useful, conceptual model of a reservoir is to be developed. A dichotomy of the internal voids of reservoir rocks has been suggested. These two classes of porosity can be described as follows:Primary porosity is intergranular and controlled by deposition and lithification. It is highly interconnected and usually can be correlated with permeability since it is largely dependent on the geometry, size distribution and spatial distribution of the grains. The void systems of sands, sandstones and oolitic limestones are typical of this type.Secondary porosity is foramenular and is controlled by fracturing, jointing and/or solution in circulating water although it may be modified by infilling as a result of precipitation. It is not highly interconnected and usually cannot be correlated with permeability. Solution channels or vugular voids developed during weathering or burial in sedimentary basins are indigenous to carbonate rocks such as limestones or dolomites. Joints or fissures which occur in massive, extensive formations composed of shale, siltstone, schist, limestone or dolomite are generally vertical, and they are ascribed to tensional failure during mechanical deformation (the permeability associated with this type of void system is often anisotropic). SPEJ P. 245^