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4.2: Index Map of SWCC Region with Location of DOE and Other Seismic Data and Magnetotelluric Profiles.
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Detailed analyses of more than 50 core samples of western tight sands have resulted in several unanticipated observations that are set forth in this paper. Core analyses performed under stress representative of producing conditions provided data on porosity, pore volume compressibility, stress dependence of permeability to gas, and slope of the Kli...
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... The slippage coefficients or the Klinkenberg coefficients can be used to determine the average pore diameter of the porous shale conduits through which the gas is transported (Letham and Bustin, 2016a). The average pore diameter of the Eagle ford shale samples, which were identified through the study of Letham and Bustin (2016a) followed the method that was developed by Randolph, and the equation is expressed as (Randolph et al., 1984) ...
... Several studies have related pore system complexity to the presence of clay minerals (Randolph et al., 1984;Soeder et al., 1987;Zhao et al., 2017). Clay minerals represent significant portion of sedimentary rocks including sandstones. ...
Macro-, meso-, micro-pore systems combined with clay content are critical for fluid flow behavior in tight sandstone formations. This study investigates the impact of clay mineralogy on pore systems in tight rocks. Three outcrop samples were selected based on their comparative petrophysical parameters (Bandera, Kentucky, and Scioto). Our experiments carried out to study the impact of clay content on micro-pore systems in tight sandstone reservoirs involve the following techniques: Routine core analysis (RCA), to estimate the main petrophysical parameters such as porosity and permeability, X-ray diffraction (XRD), and scanning electron microscopy (SEM) to assess mineralogy and elemental composition, Mercury Injection Capillary Pressure (MICP), Nuclear Magnetic Resonance (NMR), and Micro-Computed Tomography (Micro-CT) to analyze pore size distributions. Clay structure results show the presence of booklets of kaolinite and platelets to filamentous shapes of illite. The Scioto sample exhibits a micro-pore system with an average pore body size of 12.6±0.6 μm and an average pore throat size of 0.25±0.19 μm. In Bandera and Kentucky samples illite shows pore-bridging clay filling with an average mineral size of around 0.25±0.03 μm, which reduces the micro-pore throat system sizes. In addition, pore-filling kaolinite minerals with a diameter of 5.1±0.21 μm, also reduce the micro-pore body sizes. This study qualifies and quantifies the relationship of clay content with primary petrophysical properties of three tight sandstones. The results help to advance procedures for planning oil recovery and CO2 sequestration in tight sandstone reservoirs.
... Such reservoirs consist of extremely tight formations through which transport of gas occurs by different mechanisms depending on the flow and porous formation conditions (Javadpour 2009;Civan et al. 2011;Haghshenas et al. 2013). Jenkins (2015) has shown the difficulty to estimate this parameter, mainly, in anisotropic permeability due to reservoir pressure change where it requires the confining stress method. In our study, permeability has been estimated using the Javadbour equation (Javadpour 2009) in the Barnet shale of the two horizontal wells. ...
Here, we suggest the use of the artificial neural network for permeability prediction in horizontally drilled well in unconventional shale gas reservoirs. Prediction of Permeability in shale gas reservoirs is a complicated task that requires new models where Darcy’s fluid flow model is not suitable. The proposed idea is based on the training of neural network machine using the set of well-logs data as an input and the measured permeability, from Javadbour model, as an output. In this case, the multilayer perceptron neural network machine was used with Levenberg Marquardt algorithm. Application to two horizontal wells drilled in the Barnett shale formation exhibits the power of the neural network model to enhance unconventional reservoir characterization.
... This is well reflected in the gas slippage factors obtained from inflow (bgas = 4.0 MPa, Table 4.2) and flow-through (bgas = 0.2 MPa, Table 3) for this sample set at 40 MPa confining pressure. As thoroughly discussed by Klinkenberg (1941), Randolph et al. (1984) or Letham et al. (2015) the gas slippage factor is inversely proportional to the average transport pore diameter (Klinkenberg, 1941) or average transport slit width (Randolph et al., 1984). ...
... This is well reflected in the gas slippage factors obtained from inflow (bgas = 4.0 MPa, Table 4.2) and flow-through (bgas = 0.2 MPa, Table 3) for this sample set at 40 MPa confining pressure. As thoroughly discussed by Klinkenberg (1941), Randolph et al. (1984) or Letham et al. (2015) the gas slippage factor is inversely proportional to the average transport pore diameter (Klinkenberg, 1941) or average transport slit width (Randolph et al., 1984). ...
During the last decade, there has been a remarkable increase in scientific studies describing transport and storage mechanisms in shale gas reservoirs, which is certainly related to the increasing importance of shale gas for global energy consumption. For this thesis, gas uptake experiments on shales were performed repetitively by merely changing the boundary conditions (e.g. gas type, overburden pressure, pore pressure, sample size). This allowed for a detailed testing of evaluation schemes characterizing transport and storage and for investigations of changes of petrophysical properties by changes of single boundary conditions. Samples that were utilized are: (1) the Cambro-Ordovician Alum Shale, (2) the Upper Jurassic Kimmeridge Clay, (3) the Upper Jurassic Bossier Shale, (4) the Jurassic/Cretaceous Bazhenov Shale, (5) the Lower Cretaceous Garau Shale and (6) the Late Cretaceous Eagle Ford Shale. Chapters 2 and 3 in detail discuss the influence of particle size and lithostatic stress on porosity and sorption capacity in these shales, whereas chapter 4 demonstrates an evaluation scheme that can be utilized to interpret gas permeability coefficients from gas uptake data. The results in chapter 2 show that particle sizes > 64 µm should be used for specific pore volume/porosity and sorption measurements because they are more likely to retain the properties of the rock fabric in terms of accessible pore volume and sorptive storage capacity. Particularly the sorption capacity may increase significantly upon grinding to smaller particle sizes. This increase indicates an opening of a considerable amount of micropores with large internal surface area upon mechanical disruption of the rock fabric and/or removal of included fluids. It may also be due to increased swelling abilities of clay minerals and organic matter upon destruction of stabilizing rock fabric with decreasing particle size. A more realistic approach to estimate gas storage capacities is to utilize plugs (largest “particle sizes” used in chapter 2) within triaxial flow cells in order to account for lithostatic stress effects on the intact rock fabric as well. Chapter 3 demonstrates that the specific pore volume/porosity but more importantly also the sorption capacity decreases significantly with increasing effective stress. While the reduction of specific pore volume/porosity is definitely due to poroelastic compression, the mechanism(s) leading to the reduction of excess sorption capacity with stress require further investigation but are likely due to a mixture of poroelastic compression as well as inhibition of sorption-related swelling. Gas storage calculations show that routine methods based on unconfined data may grossly overestimate the total storage capacity. In a scenario, at 2500 m depth, the total gas storage capacity will be overestimated by up to 28% if the stress-dependent reduction of volume and sorptive storage capacity is not considered. In chapter 4, the same gas uptake data as in the previous chapters is used for permeability estimation. To successfully determine apparent gas permeability coefficients 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. Generally, permeability coefficients derived from uptake tests on all samples do not show any systematic deviations from those obtained from standard pulse decay measurements. However, standard deviations of single apparent permeability coefficients derived from gas uptake experiments are higher by up to one order of magnitude than for those obtained from standard pulse decay tests under all tested conditions. For the Bossier sample, permeability coefficients obtained from standard pulse decay measurements were larger (by approximately two orders of magnitude) as compared to permeability coefficients from gas uptake data. It is demonstrated that this effect can be related to pore network anisotropy, indicating that a combination of standard pulse decay and gas uptake measurements can contribute significantly to a better understanding of the effects of anisotropy and/or the pore structure on the transport properties in shales. The findings presented in this thesis have important implications for Gas-In-Place estimations and demonstrate that gas uptake measurements may be used to reliably interpret total gas storage capacities as well as matrix permeability coefficients simultaneously.
... They provided insights into the geometry of pores in stressed samples and also the pore structure variation with stress during production. Randolph et al. (1984) introduced silt shaped pores width as a function of gas properties and gas slippage factor. The introduced equation is shown in Eq. (8). ...
This study investigates the effect of stress magnitude and stress history on porosity and permeability values of anhydride and carbonate rocks. Porosity and permeability properties are measured for twelve anhydride and carbonate core samples under stress loading and unloading conditions. The results of permeability measurements show that tighter core samples are more stress dependent while the anhydride samples are generally more sensitive to the stress. The gap between stress loading and unloading (hysteresis) is more considerable at lower effective stress values. The results also indicate that the hysteresis is more noticeable in the anhydride core samples. The gas slippage factor is also determined which specifies the flow channels systems of rocks. Three different flow channels systems are observed in the anhydride core samples while the carbonate core samples show one flow channels system. Porosity measurements show that, it has less sensitivity to the effective stress for both anhydride and carbonate core samples.
... To account for fluid dynamic effects, a Klinkenberg-correction (Klinkenberg, 1941) was applied to obtain the "Klinkenberg-corrected" permeability (k ∞ [1 D~10 −12 m 2 ]) of the respective sample to nitrogen. Additionally, utilizing the respective gas slippage factors (b [MPa]), effective pore diameters and slit widths were calculated using relationships that were established by Klinkenberg (1941) and Randolph et al. (1984). ...
... The comparison of the Lower and Upper Alum Shales and Kulm-Plattenkalk with Woodford, Barnett and Bakken shales is of special interest, because they were all deposited during the late Devonian/ Mississippian in close proximity to each other (the Atlantic Ocean did Klinkenberg (1941) and Randolph et al. (1984) Karg et al., 2005;Littke et al., 1994Littke et al., , 2000. Note, that deepest burial and highest temperatures occurred already during the "late Carboniferous". ...
The assessment of unconventional shale gas potential for the Mississippian Alum shales, the Kulm-Plattenkalk and the Lower Pennsylvanian Ziegelschiefer Formation in western Germany provides insight on how fluctuation in depositional environments has a significant role on lithofacies and shale gas potential. This paper uses a standard evaluation workflow for unconventional shale gas potential taking into account thickness, TOC content, mineral composition and brittleness, porosity and permeability data as well as thermal maturity. The average organic carbon content of the Lower and Upper Alum Shales reaches 2.4 wt% and 2.6 wt%, respectively and deposition took place in an oxygen-depleted marine environment, where hydrogen-rich type II kerogen was preserved in the sediments. In this study, the Kulm-Plattenkalk is investigated for the first time with regard to unconventional shale gas potential. The TOC content ranges between 0.22% and 6.85% (average: 2.45%) and carbonate content is 21% on average. In contrast, the Lower Pennsylvanian Ziegelschiefer Fm was deposited in a shallow marine suboxic to oxic environment with stronger terrestrial influence. TOC is 1.2% on average and the kerogen rich in terrestrial material has only a moderate original hydrocarbon generation potential. It should be noted that all samples are in the gas generation window and may hence have already lost about half of their original organic carbon content. A simple control of mineralogy on porosity and permeability was not evident, but a weak correlation was found between permeability and the average effective pore radii or slit widths. The Mississippian black shales have great similarity in terms of organic richness, thickness and quartz content with known gas shales of similar stratigraphic age from the US. However, differences with respect to burial and uplift history might have important influence on gas in place.
... Through the plot of permeability against inverse pore pressure, K ∞ is acquired by the intercept of linear fit with the permeability axis, and b can be calculated from the slope of the line divided by K ∞ . Randolph et al. (1984) estimated the width of slit-shaped pores (w) in shales by: ...
... (3) (Randolph et al., 1984;Letham and Bustin, 2015), whereas A p is independent on average pore width of shales (Fig. 10d). Hence there is no correlation between permeability anisotropy and gas slippage of shales. ...
... Because the occurrence of gas slippage is dependent on pore diameter, the pore pressure at which flow regime changes from Darcy to slip flow can be used to estimate pore diameter. As shown by Randolph et al. (1984), rearrangement of the modified Poiseuille's law (Poiseuille's equation for viscous flux through a slit-shaped pore combined with ...
A combination of permeability and ultrasonic velocity measurements allied with image analysis is used to distinguish the primary microstructural controls on effective-pressure dependent permeability. Permeabilities of cylindrical samples of Whitby Mudstone were measured using the oscillating pore pressure method at confining pressures ranging between 30-95 MPa and pore pressures ranging between 1-80 MPa. The permeability-effective pressure relationship is empirically described using a modified effective pressure law in terms of confining pressure, pore pressure and a Klinkenberg effect. Measured permeability ranges between 3×10-21 m2 and 2 ×10-19 m2 (3 and 200 nd), and decreases by ~1 order of magnitude across the applied effective pressure range. Permeability is shown to be less sensitive to changes in pore pressure than changes in confining pressure, yielding permeability effective pressure coefficients (χ) between 0.42 and 0.97. Based on a pore-conductivity model which considers the measured changes in acoustic wave velocity and pore volume with pressure, the observed loss of permeability with increasing effective pressure is attributed dominantly to the progressive closure of bedding-parallel, crack-like pores associated with grain boundaries. Despite only constituting a fraction of the total porosity, these pores form an interconnected network that significantly enhances permeability at low effective pressures.
... He also proposed Flow Zone Indicator (FZI) cut-offs to define the different rock types. Walls (1982), Randolph et al. (1984), Davies et al. (1993), and Rushing et al. (2008) found commonly used rock typing methods inadequate for tight reservoirs. They believed that other attributes such as rock texture and composition, core-based descriptions, and clay mineralogy are also important for rock typing in tight reservoirs. ...
Most US shale plays are spatially extensive with regions of different thermal maturity and varying production prospects. With increasing understanding of the heterogeneity, micro-structure and anisotropy of shales, efforts are now directed to identify sweet spots and optimum completion zones in any shale play. Rock typing is a step in this direction. In this paper, we present an integrated workflow for rock typing using lab petrophysical measurements on core samples and well logs. The integrated workflow has been applied in the Woodford Shale in a series of steps. In the first step, unsupervised clustering algorithms like K-Means and Self Organizing Maps (SOM) were used to define the rock types. Rock Type 1 is generally characterized by high porosity and Total Organic Carbon (TOC). Rock Type 2 had intermediate values of porosity and TOC and thus, moderate source potential and storage. Rock Type 3 had the highest carbonate content, poor storage, and source rock potential. In the next step, a classification algorithm, Support Vector Machines (SVM) was used to extend the rock types from the cores to the logs. A logging suite with gamma ray, resistivity, neutron porosity and density logs was used for extending the rock types. In the final step, a rock type ratio (RTR) was defined based on the fraction of Rock Type 1 over gross thickness. RTR was found to positively correlate with normalized oil equivalent production. A total of 7 wells with core data were considered for rock typing in the Woodford Shale. The cored intervals in these 7 wells formed the calibration dataset for the classification algorithm. The rock types were populated in the uncored sections of these 7 wells and additionally in 12 wells (taken from Drilling Info) using a trained SVM model. Additional wells were taken to have sufficient data for production correlation. © 2018 Society of Exploration Geophysicists and American Association of Petroleum Geologists.
... Stress sensitivity was first discovered in sandstone flow experiments by American scholars some researchers Fatt and Davis (1952). Then, some researchers (Jones, 1975;Jones et al., 1980;Walsh, 1981;Randolph et al., 1984;Jelmert et al., 1998) established a mathematical relationship between core permeability and effective stress, and found that the formula is applicable to naturally fractured carbonated reservoir and low permeability sandstone reservoir. Davies et al. (2001) compared the stress sensitivity characteristics of different permeability cores, and found that for unconsolidated cores with high permeability, the larger the porosity and permeability, the stronger the stress sensitivity. ...
During the development of naturally fractured carbonate reservoirs, understanding the change in fracture permeability is the basis for production evaluation and scientific development. The conventional method of analyzing fracture permeability is to take core samples for laboratory experiments. This paper presents a new method to calculate the fracture permeability decrease using actual reservoir pressure data. The mathematical model of fracture permeability change with pressure is established based on material balance in the production process of a fractured reservoir. The model considers crossflow coefficient as well as compression coefficient. According to the results of the model, the fracture permeability decreases with decrease of the formation pressure, but the degree of decline is related to the crossflow coefficient and the compression coefficient. By using this model, the change in fracture permeability can be calculated under different production pressures. This provides a new method for stress sensitivity determination of fractured reservoirs.
