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Li, Yongyi, Lev Vernik, Mark Chapman, and Joel Sarout. "Introduction to this special section: Rock physics." Leading Edge 38, no. 5 (May 2019): 332. http://dx.doi.org/10.1190/tle38050332.1.
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Rock physics links the physical properties of rocks to geophysical and petrophysical observations and, in the process, serves as a focal point in many exploration and reservoir characterization studies. Today, the field of rock physics and seismic petrophysics embraces new directions with diverse applications in estimating static and dynamic reservoir properties through time-variant mechanical, thermal, chemical, and geologic processes. Integration with new digital and computing technologies is gradually gaining traction. The use of rock physics in seismic imaging, prestack seismic analysis, seismic inversion, and geomechanical model building also contributes to the increase in rock-physics influence. This special section highlights current rock-physics research and practices in several key areas, namely experimental rock physics, rock-physics theory and model studies, and the use of rock physics in reservoir characterizations.
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Anderson, Iain, Jingsheng Ma, Xiaoyang Wu, and Dorrik Stow. "Determining reservoir intervals in the Bowland Shale using petrophysics and rock physics models." Geophysical Journal International 228, no. 1 (August 20, 2021): 39–65. http://dx.doi.org/10.1093/gji/ggab334.
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SUMMARY An evaluation of prospective shale gas reservoir intervals in the Bowland Shale is presented using a wireline log data set from the UK's first shale gas exploration well. Accurate identification of such intervals is crucial in determining ideal landing zones for drilling horizontal production wells, but the task is challenging due to the heterogeneous nature of mudrocks. This heterogeneity leads to stratigraphic variations in reservoir quality and mechanical properties, and leads to complex geophysical behaviour, including seismic anisotropy. We generate petrophysical logs such as mineralogy, porosity, and organic content and calibrate these to the results of core studies. If ‘reservoir quality’ is defined by combined cut-offs relating to these parameters, we find that over 100 m of reservoir quality shale is present in the well, located primarily within the upper section. To examine the link between geophysical signature and rock properties, an isotropic rock physics model is developed, using effective medium theories, to recreate the elastic properties of the shale and produce forward-looking templates for subsequent seismic inversion studies. We find that the mineralogical heterogeneity in the shale has a profound impact on modelled elastic properties, obscuring more discrete changes due to porosity, organic content and water saturation and that the best reservoir quality intervals of the shale bear a distinctive response on rock physics cross-plots. Finally, we consider the density of natural fractures in the shale by developing an anisotropic rock physics model to reflect high-angle fractures observed on micro-imagery logs. We invert crack density using shear wave splitting well log data and find a crack density of up to 4 per cent which correlates well with micro-imagery observations. Our work further supports previous authors’ core-based studies in concluding that the Bowland Shale holds good reservoir characteristics, and we propose that there are multiple intervals within the shale that could be targeted with stacked horizontal wells, should those intervals’ mechanical properties also be suitable and there be adequate stress barriers between to restrict vertical hydraulic fracture growth. Finally, our rock physics templates may provide useful tools in interpreting pre-stack seismic data sets in prospective areas of the Bowland Shale and picking the best locations for drilling wells.
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Xu, Hao, Wen Zhou, Runcheng Xie, Lina Da, Christopher Xiao, Yuming Shan, and Haotian Zhang. "Characterization of Rock Mechanical Properties Using Lab Tests and Numerical Interpretation Model of Well Logs." Mathematical Problems in Engineering 2016 (2016): 1–13. http://dx.doi.org/10.1155/2016/5967159.
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The tight gas reservoir in the fifth member of the Xujiahe formation contains heterogeneous interlayers of sandstone and shale that are low in both porosity and permeability. Elastic characteristics of sandstone and shale are analyzed in this study based on petrophysics tests. The tests indicate that sandstone and mudstone samples have different stress-strain relationships. The rock tends to exhibit elastic-plastic deformation. The compressive strength correlates with confinement pressure and elastic modulus. The results based on thin-bed log interpretation match dynamic Young’s modulus and Poisson’s ratio predicted by theory. The compressive strength is calculated from density, elastic impedance, and clay contents. The tensile strength is calibrated using compressive strength. Shear strength is calculated with an empirical formula. Finally, log interpretation of rock mechanical properties is performed on the fifth member of the Xujiahe formation. Natural fractures in downhole cores and rock microscopic failure in the samples in the cross section demonstrate that tensile fractures were primarily observed in sandstone, and shear fractures can be observed in both mudstone and sandstone. Based on different elasticity and plasticity of different rocks, as well as the characteristics of natural fractures, a fracture propagation model was built.
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Will, Robert, Tom Bratton, William Ampomah, Samuel Acheampong, Martha Cather, and Robert Balch. "Time-Lapse Integration at FWU: Fluids, Rock Physics, Numerical Model Integration, and Field Data Comparison." Energies 14, no. 17 (September 2, 2021): 5476. http://dx.doi.org/10.3390/en14175476.
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We present the current status of time-lapse seismic integration at the Farnsworth (FWU) CO2 WAG (water-alternating-gas) EOR (Enhanced Oil Recovery) project at Ochiltree County, northwest Texas. As a potential carbon sequestration mechanism, CO2 WAG projects will be subject to some degree of monitoring and verification, either as a regulatory requirement or to qualify for economic incentives. In order to evaluate the viability of time-lapse seismic as a monitoring method the Southwest Partnership (SWP) has conducted time-lapse seismic monitoring at FWU using the 3D Vertical Seismic Profiling (VSP) method. The efficacy of seismic time-lapse depends on a number of key factors, which vary widely from one application to another. Most important among these are the thermophysical properties of the original fluid in place and the displacing fluid, followed by the petrophysical properties of the rock matrix, which together determine the effective elastic properties of the rock fluid system. We present systematic analysis of fluid thermodynamics and resulting thermophysical properties, petrophysics and rock frame elastic properties, and elastic property modeling through fluid substitution using data collected at FWU. These analyses will be framed in realistic scenarios presented by the FWU CO2 WAG development. The resulting fluid/rock physics models will be applied to output from the calibrated FWU compositional reservoir simulation model to forward model the time-lapse seismic response. Modeled results are compared with field time-lapse seismic measurements and strategies for numerical model feedback/update are discussed. While mechanical effects are neglected in the work presented here, complementary parallel studies are underway in which laboratory measurements are introduced to introduce stress dependence of matrix elastic moduli.
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Alafnan, Saad. "The Impact of Pore Structure on Kerogen Geomechanics." Geofluids 2021 (September 15, 2021): 1–12. http://dx.doi.org/10.1155/2021/4093895.
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Production stimulation techniques such as the combination of hydraulic fracturing and lateral drilling have made exploiting unconventional formations economically feasible. Advancements in production aspects are not always in lockstep with our ability to predict and model the extent of a fracturing job. Shale is a clastic sedimentary rock composed of a complex mineralogy of clay, quartz, calcite, and fragments of an organic material known as kerogen. The latter, which consists of large chains of aromatic and aliphatic carbons, is highly elastic, a characteristic that impacts the geomechanics of a shale matrix. Following a molecular simulation approach, the objective of this work is to investigate kerogen’s petrophysics on a molecular level and link it to kerogen’s mechanical properties, considering some range of kerogen structures. Nanoporous kerogen structures across a range of densities were formed from single macromolecule units. Eight units were initially placed in a low-density cell. Then, a molecular dynamic protocol was followed to form a final structure with a density of 1.1 g/cc; the range of density values was consistent with what has been reported in the literature. The structures were subjected to petrophysical assessments including a helium porosity analysis and pore size distribution characterization. Mechanical properties such as Young’s modulus, bulk modulus, and Poisson ratio were calculated. The results revealed strong correlations among kerogen’s mechanical properties and petrophysics. The kerogen with the lowest porosity showed the highest degree of elasticity, followed by other structures that exhibited larger pores. The effect temperature and the fluid occupying the pore volume were also investigated. The results signify the impact of kerogen’s microscale intricacies on its mechanical properties and hence on the shale matrix. This work provides a novel methodology for constructing kerogen structures with different microscale properties that will be useful for delineating fundamental characteristics such as mechanical properties. The findings of this work can be used in a larger scale model for a better description of shale’s geomechanics.
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Shoemaker, Michael, Santhosh Narasimhan, Shane Quimby, and James Hawkins. "Calculating far-field anisotropic stress from 3D seismic in the Permian Basin." Leading Edge 38, no. 2 (February 2019): 96–105. http://dx.doi.org/10.1190/tle38020096.1.
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Minimum horizontal stress (Sh) is the controlling parameter when hydraulic fracture stimulating tight oil formations but is next to impossible to measure quantitatively, especially in the far field and away from the wellbore. In-situ stress differences between bedding planes control fracture containment, which defines the complexity of fracture propagation and fracture geometry including orientation, height growth, width, and length. Geomechanical rock properties define elastic behavior, influencing how the subsurface will deform under induced stress. These properties include dynamic and static Young's modulus, Poisson's ratio, and Biot's coefficient. When combined with pore pressure and overburden stress, the elastic rock properties describe the mechanical earth model (MEM), which characterizes the geomechanical behavior of the subsurface. The MEM also defines key inputs for calculating Sh using the Ben Eaton stress equation, which has been commonly used by geoscientists for decades. However, calculated Sh from this simple model historically produces uncertain results when compared to field-measured stress due to an assumed homogeneous and isotropic subsurface. This is particularly contrary to tight oil formations that represent shale (or mudrock) reservoirs that are highly laminated and therefore anisotropic. Optimal parameterization of fracture geometry models for well spacing and engineered treatment design requires an anisotropic far-field in-situ stress measurement that accurately captures vertical and lateral variability of geomechanical properties in 3D space. A method is proposed herein that achieves this by using a modified version of the anisotropic Ben Eaton stress model. The method calculates minimum Sh by substitution of inverted 3D seismic volumes directly into the stress equation, replacing the bound Poisson's ratio term with an equivalent anisotropic corrected closure stress scalar (CSS) term. The CSS seismic volume is corrected for anisotropy using static triaxial core and is calibrated to multidomain data types including petrophysics, rock physics, geomechanics, and completion and reservoir engineering field measurements.
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Zhang, Hui, Ke Xu, Binxin Zhang, Guoqing Yin, Haiying Wang, Zhimin Wang, Chao Li, Shujun Lai, and Ziwei Qian. "Influence of Stress Anisotropy on Petrophysical Parameters of Deep and Ultradeep Tight Sandstone." Applied Sciences 12, no. 22 (November 14, 2022): 11543. http://dx.doi.org/10.3390/app122211543.
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Rock mechanics parameters control the distribution of in situ stress and natural fractures, which is the key to sweet spot evaluation in reservoir engineering. Combined with the distribution of in situ stress, an experimental scheme of stress on rock physical parameters was designed. The results show that rock sonic velocity is extremely sensitive to water saturation under overburden pressure. At ultrasonic frequencies, when the water saturation increases from 0% to 80%, the P-wave velocity increases first and then decreases. When the water saturation continues to increase to 100%, the P-wave velocity increases. This is due to the effect of water saturation on the shear modulus. Saturation is negatively correlated with shear wave velocity and resistivity. Different minerals have different control effects on the rock P-S wave velocity ratio. Quartz content plays a dominant role, and the two are negatively correlated, followed by feldspar and clay, and the two are positively correlated with the P-S wave ratio. The confining pressure, axial compression, stress ratio and burial depth are positively correlated with the P-S wave and negatively correlated with the P-S wave ratio; in descending order, the influencing factors of stress on the petrophysical parameters are maximum stress ratio > confining pressure > axial pressure.
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Perry, Stephanie. "Technology Focus: Formation Evaluation (August 2021)." Journal of Petroleum Technology 73, no. 08 (August 1, 2021): 41. http://dx.doi.org/10.2118/0821-0041-jpt.
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Leading into the third quarter of this year, I am honored to be able to highlight and share three impactful SPE papers that demonstrate integration at its best. In reviewing the papers, five main technical themes emerged. These include * Machine learning and artificial intelligence as applied to formation evaluation * Production analysis methodologies and their effect on understanding rock characterization and behavior * Subsurface characterization primarily focused on rock typing and permeability * Tool advancements (openhole, cased-hole, or laboratory-based tools) * Subsurface-to-production integration across subdisciplines (e.g., geology, geochemistry, petrophysics, and engineering) The latter is the common thread between the three papers recommended and discussed here. In this new decade, the prevalence of integration is at the forefront of the scientific community. Every discipline, scientist, or company has a way in which they define the term “integration.” Regardless of how you define the effort that links disciplines quantitatively, the importance of constraining subsurface characterization to link it to production results and drive toward a predictive model is a critical accomplishment for our industry. As such, I’d like to highlight three papers in this feature (OTC 30644, SPE 201417, and SPE 202683) and the knowledge and workflow applications they define and demonstrate. Sharing these integrated work flows with the community aids in teaching and leads to best-practice components of integrative studies. These efforts also share and demonstrate how to bridge the gap between in-situ characterization and wellhead performance prediction and results—in other words, the static-to-dynamic link between rock and fluid properties as quantified and how they will inevitably produce hydrocarbon through the rock and fluid interactions. Recommended additional reading at OnePetro: www.onepetro.org. SPE 201334 Combined Experimental and Well-Log Evaluation of Anisotropic Mechanical Properties of Shales: An Application to Wellbore Stability in the Bakken Formation by Saeed Rafieepour, The University of Tulsa, et al. SPE 201486 A New Safe and Cost-Effective Approach to Large-Scale Formation Testing by Fluid Injection on a Wireline Formation Tester by Christopher Michael Jones, Halliburton, et al. SPE 201735 Integrated Reservoir Characterization With Spectroscopy, Dielectric, and Nuclear Magnetic Resonance T1-T2 Maps in a Freshwater Environment: Case Studies From Alaska by ZhanGuo Shi, Schlumberger, et al.
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Lavenu, Arthur P. C., Juliette Lamarche, Lisa Texier, Lionel Marie, and Bertrand D. M. Gauthier. "Background fractures in carbonates: inference on control of sedimentary facies, diagenesis and petrophysics on rock mechanical behavior. Example of the Murge Plateau (southern Italy)." Italian Journal of Geosciences 134, no. 3 (October 2015): 535–55. http://dx.doi.org/10.3301/ijg.2014.58.
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Askaripour, Mahdi, Ali Saeidi, Patrick Mercier-Langevin, and Alain Rouleau. "A Review of Relationship between Texture Characteristic and Mechanical Properties of Rock." Geotechnics 2, no. 1 (March 7, 2022): 262–96. http://dx.doi.org/10.3390/geotechnics2010012.
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The textural characteristics of rocks influence their petrophysical and mechanical properties. Such parameters largely control rock mass stability. The ability to evaluate both immediate and long-term rock behaviors based on the interaction between various parameters of rock texture, petrophysical and mechanical properties is therefore crucial to many geoengineering facilities. However, due to the common lack of high-quality core samples for geomechanics and rock texture laboratory tests, single and multivariable regression analyses are conducted between mechanical properties and textural characteristics based on experimental test data. This study presents a review of how rock texture characteristics influence the geomechanical properties of a rock, and summarizes the regression equations between two aspects. More specifically, a review of the available literature on the effects of mineralogy, grain size, grain shape, packing density, foliation index, porosity, degree of weathering, and other rock physical characteristics on geomechanics is presented. Similarly, a review of the literature discussing the failure criteria of anisotropic rocks, both continuous and discontinuous, is also presented. These reviews are accompanied by a comparison of the fundamentals of these methods, describing their equations and discussing their advantages and disadvantages. This exercise has the objective of providing better guidelines on how to use these criteria, allowing for safer underground excavations via an improved understanding of how rock texture parameters affects the mechanical behavior of rocks.
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Germay, C., T. Richard, E. Mappanyompa, C. Lindsay, D. Kitching, and A. Khaksar. "The Continuous-Scratch Profile: A High-Resolution Strength Log for Geomechanical and Petrophysical Characterization of Rocks." SPE Reservoir Evaluation & Engineering 18, no. 03 (July 17, 2015): 432–40. http://dx.doi.org/10.2118/174086-pa.
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Summary Knowledge of rock properties is essential to predict and optimize the performance of oil and gas reservoirs by means of the reduction of the uncertainty pertaining to standard subsurface issues such as the mechanical integrity of the borehole (Tiab and Donaldson 1996; Moos et al. 2003), the risk of sanding (Tronvoll et al. 2004), and the geometry and efficiency of hydraulic fractures. These properties are evaluated by combining different field-measurement techniques (wireline logs, results of well tests, seismic surveys) and laboratory-test results (Archie 1942, 1950; Serra 1986; Bassiouni 1994). When cores are available, empirical models are built from correlations derived between well logs and laboratory measurements to estimate rock properties in noncored wells. The validity of these empirical models is often limited to specific litho-facies (see reviews by Chang et al. 2006; Blasingame 2008; Khaksar et al. 2009), which makes the identification of lithofacies a necessity before applying the model for predictions in uncored wells (Massonnat 1999). Because of the heterogeneity of rocks (Haldorsen 1996), with characteristic length scales commonly smaller than the resolution of wireline logs or even the core-plug size, the robustness of correlations is determined by how plug samples capture the dispersion in rock properties over the lithofacies under consideration. The correlation between a very localized core-plug measurement and a low-resolution wireline log with inherent low-pass filtering properties raises issues related to the upscaling of a property from one length scale (few centimeters for core plugs) to another (up to 1 m for wireline log). As an illustration, consider the high-resolution, continuous profile X, where the variations of the measured property are quantified for length scales smaller than typical plug sizes. We filter this data to produce the profiles X5 and X50 (the subscript stands for the length scale in centimeters at which the signal is averaged out) with lower spatial resolutions similar to the plug and the well-log resolutions, respectively (Fig. 1). The resulting crossplot, shown in Fig. 2, of X5 vs. X50 exhibits a cloud of points in which the dispersion is governed by the properties of the signal (the degree of heterogeneity or the frequency content) and the difference between the two resolution length scales. Two linear-fit optimizations were carried out with the low-resolution-data X50 and the high-resolution-data X5 as the dependent variables, respectively. It is interesting to note that these linear fits yield different results, with a slope of 0.96 in the first case and 0.69 in the second case. This is a mathematical artifact caused by the minimization process inherent in the search for the best linear fit, which is most commonly a minimization of the vertical distance between the representative data points and the best-fit line. On the basis of this result, it should always be advisable to select the high-resolution data (plug) as the dependent variable. Discrete sampling (i.e., plugging) and the dispersion caused by the difference in resolution scales of two measurements are two important root causes of the errors often seen in correlations between two variables. The examples shown in Fig. 2 illustrate how the correlations derived from several sampling schemes can deviate from the expected one-to-one relation between the two variables. To circumvent these issues, petrophysicists usually select large quantities of plugs to build representative statistical data sets, with the hope that they are large enough to attenuate the effects listed previously. However, extensive plugging strategies imply longer lead times and higher costs, and are therefore not always viable (e.g., in the cases of rock-mechanics testing or special-core-analysis programs). As an illustration, consider the modeling of the variations of rock strength, one of the key geomechanical properties along a well trajectory. Such an exercise relies heavily on correlations derived between well logs and laboratory tests (uniaxial or triaxial compressive tests), because there is no wireline log providing a direct measure of a mechanical property related to strength. In their comprehensive review of existing literature, Khaksar et al. (2009) listed approximately 40 models designed to derive strength properties from wireline logs. The authors showed that the relevance of these as empirical is limited to specific rock types. A broader application of these models would require the considerations of additional complexity such as the coexistence of several facies within the same data set or the impact of diagenesis on petrophysical variability within one facies. The elements of reflection introduced previously all suggest that a continuous measure of a physical property such as the strength profiles generated from the scratch test, which provides some useful elements for the mapping of rock heterogeneity, could partially fill the gap between measurements on plugs and well logs and help with the optimization of the selection of plug samples. In the main sections of this paper, we first describe briefly the scratch test and outline the key intrinsic benefits of the test. We then discuss how standard and special core analysis could benefit most from all the features of the scratch test when introduced at a very early stage of the work flows. In particular, we illustrate with some examples how rock-strength profiles averaged to the relevant length scale can be correlated with other petrophysical properties either measured on core plugs or inferred from well logs.
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Siddiqui, Shameem, Taha M. Okasha, James J. Funk, and Ahmad M. Al-Harbi. "Improvements in the Selection Criteria for the Representative Special Core Analysis Samples." SPE Reservoir Evaluation & Engineering 9, no. 06 (December 1, 2006): 647–53. http://dx.doi.org/10.2118/84302-pa.
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Summary The data generated from special-core-analysis (SCAL) tests have a significant impact on the development of reservoir engineering models. This paper describes some of the criteria and tests required for the selection of representative samples for use in SCAL tests. The proposed technique ensures that high-quality core plugs are chosen to represent appropriate flow compartments or facies within the reservoir. Visual inspection and, sometimes, computerized tomography (CT) images are the main tools used for assessing and selecting the core plugs for SCAL studies. Although it is possible to measure the brine permeability (kb), there is no direct method for determining the porosity (f) of SCAL plugs without compromising their wettability. Other selection methods involve using the conventional-core-analysis data (k and f) on "sister plugs" as a general indicator of the properties of the SCAL samples. A selective technique ideally suited for preserved or "native-state" samples has been developed to identify reservoir intervals with similar porosity/permeability relationships. It uses a combination of wireline log, gamma scan, quantitative CT, and preserved-state brine-permeability data. The technique uses these data to calculate appropriate depth-shifted reservoir-quality index (RQI) and flow-zone indicator (FZI) data, which are then used to select representative plug samples from each reservoir compartment. As an example application, approximately 400 SCAL plugs from an Upper Jurassic carbonate reservoir in the Middle East were tested using the selection criteria. This paper describes the step-by-step procedure to select representative plugs and criteria for combining the plugs for meaningful SCAL tests. Introduction The main goal of coring is to retrieve core samples from a well to get the maximum amount of information about the reservoir. Core samples collected provide important petrophysical, petrographic, paleontological, sedimentological, and diagenetic information. From a petrophysical point of view, the whole-core and plug samples typically undergo the following tests: CT scan, gamma scan, conventional tests, SCAL tests, rock mechanics, and other special tests. The data are combined to get information on heterogeneity, depth shift between core and log data, whole-core and plug porosity and permeability, porosity/permeability relationship, fluid content (Dean-Stark), RQI, FZI, wettability, relative permeability, capillary pressure, stress/strain relationship, and compressibility. The petrophysical data generated in this way play important roles in reservoir characterization and modeling, log calibration, reservoir simulation, and overall field production and development planning. Among all the petrophysical tests, the SCAL tests (which include wettability, capillary pressure, and relative permeability determination) are critical and time-consuming. A reservoir-condition relative permeability test can sometimes run for several months when mimicking the actual flow mechanisms taking place in the field. Therefore, it is very important to design these tests properly and, in particular, to select the samples that ensure meaningful results. In short, the samples must be "representative samples," which can capture the overall variability within the reservoir in a more scientific way. Unfortunately, the most important aspect of all SCAL procedures, the sample selection, is one of those least discussed. According to Corbett et al. (2001), API's RP40 (Recommended Practices for Core Analysis) makes very little reference to sampling; similarly, textbooks on petrophysics do not have sections on sampling. The Corbett et al. paper reviewed the statistical, petrophysical, and geological issues for sampling and proposed a series of considerations. This has led to the development of a method (Mohammed and Corbett 2002) using hydraulic units in a relatively simple clastic reservoir. In this paper, some issues related to sample-selection criteria (with special focus on carbonate reservoirs) will be discussed. A large data set of conventional, whole-core, and special-core analyses on a well in an Upper Jurassic carbonate reservoir was used to characterize representative samples for SCAL tests.
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Abdul Aziz, Qahtan, and Hassan Abdul Hussein. "Mechanical Rock Properties Estimation for Carbonate Reservoir Using Laboratory Measurement: A Case Study from Jeribe, Khasib and Mishrif Formations in Fauqi Oil Field." Iraqi Geological Journal 54, no. 1E (May 31, 2021): 88–102. http://dx.doi.org/10.46717/igj.54.1e.8ms-2021-05-29.
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Estimation of mechanical and physical rock properties is an essential issue in applications related to reservoir geomechanics. Carbonate rocks have complex depositional environments and digenetic processes which alter the rock mechanical properties to varying degrees even at a small distance. This study has been conducted on seventeen core plug samples that have been taken from different formations of carbonate reservoirs in the Fauqi oil field (Jeribe, Khasib, and Mishrif formations). While the rock mechanical and petrophysical properties have been measured in the laboratory including the unconfined compressive strength, Young's modulus, bulk density, porosity, compressional and shear -waves, well logs have been used to do a comparison between the lab results and well logs measurements. The results of this study revealed that petrophysical properties are consistent indexes to determine the rock mechanical properties with high performance capacity. Different empirical correlations have been developed in this study to determine the rock mechanical properties using the multiple regression analysis. These correlations are UCS-porosity, UCS-bulk density, UCS-Vs, UCs-Vp Es-Vs, Es-Vp, and Vs-Vp. (*). For example, the UCS-Vs correlation gives a good determination coefficient (R2= 0.77) for limestone and (R2=0.94) for dolomite. A comparison of the developed correlations with literature was also checked. This study presents a set of empirical correlations that can be used to determine and calibrate the rock mechanical properties when core samples are missing or incomplete.
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Villeneuve, Marlène C. "Challenges of Tunnelling in Volcanic Rock Masses." BHM Berg- und Hüttenmännische Monatshefte 166, no. 12 (November 30, 2021): 612–17. http://dx.doi.org/10.1007/s00501-021-01175-2.
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AbstractVolcanic rock masses exhibit temporal and spatial variability, even at the scale and duration of engineering projects. Volcanic processes are dynamic, resulting in rock masses ranging from high-porosity, clay-rich, fractured, and soil-like to low-porosity, high-strength, brittle, and massive. Based on a number of studies in a variety of geological settings, such as active and fossil geothermal systems, on the surface of active volcanoes and up to 3000 m below the surface, the work presented in this article shows the relationship between geological characteristics and mechanical parameters of volcanic rocks. These are then linked to the resultant challenges to tunnelling associated with the mechanical behaviour of volcanic rocks and rock masses, ranging from ductile failure such as squeezing and swelling to dynamic failure such as spalling and rockburst.This article highlights some of the key parameters that should be incorporated in site and laboratory investigations to build representative ground models in volcanic rocks and rock masses. Rock mass characterisation needs to address the highly variable and anisotropic nature of volcanic rocks, ranging from millimetre to decametre scale. Ground models must include not only the mechanical properties, such as strength and stiffness, of typical lab investigations, but also petrophysical properties, such as porosity, and geological conditions, such as alteration. Geomechanical characterisation of these rock masses requires an understanding of geological processes to select appropriate field, lab and design tools. In volcanic rocks, perhaps more than any other rock types, the geology is critical to characterising and understanding the behaviour in response to tunnelling.
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Wang, Yao, Shengjun Li, Rui Song, Jianjun Liu, Min Ye, Shiqi Peng, and Yongjun Deng. "Effects of Grain Size and Layer Thickness on the Physical and Mechanical Properties of 3D-Printed Rock Analogs." Energies 15, no. 20 (October 16, 2022): 7641. http://dx.doi.org/10.3390/en15207641.
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Due to the complexity of the sedimentary and diagenetic processes, natural rocks generally exhibit strong heterogeneity in mineral composition, physicochemical properties, and pore structure. Currently, 3D printed (3DP) rock analogs fabricated from sandy materials (silica sand) are widely applied to study the petrophysical and geomechanical characteristics of reservoir rocks, which provides an alternative and novel approach for laboratory tests to calibrate the environmental uncertainties, resolve up-scaling issues, and manufacture customized rock specimens with consistent structure and controllable petrophysical properties in a repeatable fashion. In this paper, silica sand with various grain sizes (GS) and Furan resin were used to fabricate rock analogs with different layer thicknesses (LTs) using the binder-jetting 3DP technique. A comprehensive experimental study was conducted on 3DP rock analogs, including helium porosity measurement, micro-CT scanning, SEM, and uniaxial compression. The results indicate that the LT and GS have a great influence on the physical properties, compression strength, and failure behavior of 3DP rock analogs. The porosity decreases (the difference is 7.09%) with the decrease in the LT, while the density and peak strength increase (showing a difference of 0.12 g/cm3 and 5.67 MPa). The specimens printed at the 200 and 300 μm LT mainly experience tensile shear destruction with brittle failure characteristics. The ductility of the 3DP rocks increases with the printing LT. The higher the content of the coarse grain (CG), the larger the density and the lower the porosity of the specimens (showing a difference of 0.16 g/cm3 and 8.8%). The largest peak compression strength with a mean value of 8.53 MPa was recorded in the specimens printed with CG (i.e., 100% CG), and the peak strength experiences a decrease with the increment in the content percentage of the fine grain (FG) (showing a difference of 2.01 MPa). The presented work helps to clarify the controlling factors of the printing process and materials characteristics on the physical and mechanical properties of the 3DP rock analogs, and allows for providing customizable rock analogs with more controllable properties and printing schemes for laboratory tests.
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Civan, Faruk. "Effective Correlation of Stress and Thermal Effects on Porosity and Permeability of Naturally Fractured Formations by a Modified Power Law." SPE Journal 24, no. 05 (September 9, 2019): 2378–97. http://dx.doi.org/10.2118/198893-pa.
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Summary Effective theory and methodology are proposed and validated for accurate correlation of stress–dependent petrophysical properties of naturally fractured or induced–fractured reservoir formations by means of a matrix/fracture dual–compressibility treatment. Inspection of various experimental data indicates a sudden change in trends at a certain critical net effective stress in the stress dependence of petrophysical properties of porous rocks as a result of a stress shock caused by the opening or closing of fractures. The variation of petrophysical properties in fractured–rock formations subjected to stress loading/unloading and thermally induced stress occurs mainly by deformation of the fractures below the critical effective stress and the deformation of the matrix above the critical effective stress. The alteration of petrophysical properties and a slope discontinuity might also be experienced when the stress exceeds the onset of other rock–alteration/damaging processes, such as pore collapsing and grain crushing. Proper formulations of the relevant processes and special correlation methods are presented in a manner to capture this nature of the petrophysical experimental data obtained by testing of cores extracted from naturally fractured or induced–fractured reservoir–rock formations. The dependency of porosity and permeability of fractured–rock samples under stress because of thermal, hydraulic, and mechanical effects is represented accurately by a modified–power–law equation derived from a kinetics model as confirmed by effective correlations of various experimental data. It is shown that this new model represents the thermal effect better than the frequently used Arrhenius (1889) equation and Vogel–Tammann–Fulcher (VTF) equation (Vogel 1921; Fulcher 1925; Tammann and Hesse 1926).
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Alam, M. Monzurul, Morten Leth Hjuler, Helle Foged Christensen, and Ida Lykke Fabricius. "Petrophysical and rock-mechanics effects of CO2 injection for enhanced oil recovery: Experimental study on chalk from South Arne field, North Sea." Journal of Petroleum Science and Engineering 122 (October 2014): 468–87. http://dx.doi.org/10.1016/j.petrol.2014.08.008.
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Ishaq, Kashif, Sohail Wahid, Muhammad Yaseen, Muhammad Hanif, Shehzad Ali, Jawad Ahmad, and Mubashir Mehmood. "Analysis of subsurface structural trend and stratigraphic architecture using 2D seismic data: a case study from Bannu Basin, Pakistan." Journal of Petroleum Exploration and Production Technology 11, no. 3 (March 2021): 1019–36. http://dx.doi.org/10.1007/s13202-021-01110-8.
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AbstractThe present study is focused on the subsurface geology of Bannu Basin, a part of western Indus foreland Pakistan. For this purpose, some regional seismic profiles and deep exploratory wells data have been used in integration.A total of ten mappabale seismic reflection events have been identifed which are representative of specific geological units. In general, based on the seismic the formation trends, the horizons are dipping in the northwest direction of the study area. The area generally deepens toward the northwest due to sediments load toward the northwest. The seismic profile MWI-83 shows a unique faults bounded anticlinal structure that has also been mapped on the two-dimmensional contour maps. This could be regarded as potential hydrocarbon entrapment. The regional seismic profiles are contoured for the entire grid in both time and depth domain to obtain the clearer image of the subsurface individual stratigraphic units. The 2D contour maps for Lower Permian aged Warcha Sandstone, Middle Triassic aged Tredian Formation and Early Jurrasic aged Datta Formation have been prepared using gridded TWT of the seismic profiles. The time and depth contour maps of the Datta Formation and Tredian Formation show a four way clouser oriented in the southeast dierction. The area of the closure was computed which is 24 Sq km approximately. Furthermore, the formation tops of the five wells have been used to correlate the wells for understanding the lateral and vertical variations in the stratigraphic layers. The correlation shows that the Datta Formation’s thickness increases at the centre of the basin whereas decreases on the east and south flanks of the basin. Reasons of Wells failure were concluded on the basis of the final well report and concluded that these well failure occur due to poor quality of the data and also due to some mechanical problems. Reservoircharacterization using statistical rock physics and petrophysics coupled with core data analysis can provide further insights into the hydrocarbon exploration.
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John, Rotimi Oluwatosin, Ogunkunle Fred Temitope, Onuh Charles Yunusa, Ameloko Aduojo Anthony, Enaworu Efeoghene, Ekeledo Ifeoma Faith, and Gospel Chinwendu Amaechi. "Comparative Characterization of Petrophysical and Mechanical Properties of Siliciclastic Reservoir Rocks within a compressional structure of the Teapot Dome Oilfield, Wyoming, USA." Annals of Science and Technology 5, no. 2 (December 1, 2020): 1–12. http://dx.doi.org/10.2478/ast-2020-0009.
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AbstractWorking with subsurface engineering problems in Hydrocarbon exploration as regard rock elastic and petrophysical properties necessitate accurate determination of in-situ physical properties. Several techniques have been adopted in correlating log-derived parameters with petrophysical and mechanical behavior of the rocks. However, limited field applications show there are no particular parameters and correlations that are generally acceptable due to the regional variation in geologic features (i.e., degree of mineralogy, texture, etc.). This study presents a method that assesses the disparity in petrophysical properties of oil and gas reservoir rocks in relation to their elastic/mechanical properties from 10 well-logs and 3D migrated seismic data. Two distinct facies were identified from seismic data after computing attributes. Reflection strength attribute of 2.5 and above depicts Bright spots within the central section of the field as clearly revealed by Variance and Chaos attributes. Formation properties calculated from logs were conformally gridded in consonance with the reflection patterns from the seismic data. The average Brittleness index (BI) of 0.52 corresponds to Young’s modulus (E) values of between 8 and 16 for the dense portion. This portion is the laminated, reasonably parallel, and undeformed part, flanked by the unlaminated and chaotic zones. From cross plots, the distinguished lower portion on the plot is the segment with higher sand of more than 50 %. This segment corresponds to the reservoir in this study as confirmed from the genetic algorithm neural network Acoustic impedance inversion process result. Similarly, the plot of Compressional velocity (Vp) and Poisson’s ratio (ν), reveals the laminated sand value of not less than 0.32 of ν, and Vp of about 4.2 km/s. The average porosity is about 16 %, average water saturation is about 16 %, and average permeability is approximately 25 md. Rock properties trends in a unique pattern and showing fluctuation that confirms the compressive nature of the structure with corresponding petrophysical properties. This trend is sustained in permeability computed and suggests a significant gravity-assisted compaction trend and fluid movement. It gives a reasonable idea of the fluid movement interplay and mechanical property variation within the sequence and across the dome. This part probably has been subjected to fair compressional deformational forces initiated from outside the survey.
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Bhuiyan, Mohammad H., Nicolaine Agofack, Kamila M. Gawel, and Pierre R. Cerasi. "Micro- and Macroscale Consequences of Interactions between CO2 and Shale Rocks." Energies 13, no. 5 (March 4, 2020): 1167. http://dx.doi.org/10.3390/en13051167.
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In carbon storage activities, and in shale oil and gas extraction (SOGE) with carbon dioxide (CO2) as stimulation fluid, CO2 comes into contact with shale rock and its pore fluid. As a reactive fluid, the injected CO2 displays a large potential to modify the shale’s chemical, physical, and mechanical properties, which need to be well studied and documented. The state of the art on shale–CO2 interactions published in several review articles does not exhaust all aspects of these interactions, such as changes in the mechanical, petrophysical, or petrochemical properties of shales. This review paper presents a characterization of shale rocks and reviews their possible interaction mechanisms with different phases of CO2. The effects of these interactions on petrophysical, chemical and mechanical properties are highlighted. In addition, a novel experimental approach is presented, developed and used by our team to investigate mechanical properties by exposing shale to different saturation fluids under controlled temperatures and pressures, without modifying the test exposure conditions prior to mechanical and acoustic measurements. This paper also underlines the major knowledge gaps that need to be filled in order to improve the safety and efficiency of SOGE and CO2 storage.
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Hutami, Harnanti Yogaputri, Sonny Winardhi, Tiara Larasati Priniarti, Handoyo, Muchammad Andara, and Yoopy Christian. "Petrophysics Evaluation for Determining Porosity of Shale Reservoirs." IOP Conference Series: Earth and Environmental Science 830, no. 1 (September 1, 2021): 012057. http://dx.doi.org/10.1088/1755-1315/830/1/012057.
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Abstract Indonesia is known for its large potential of shale resources, yet the character of their physical properties remains unclear. This study focuses on how to assess the petrophysical properties of shale using conventional wireline logs. Shale has been largely known as a host rock producing hydrocarbon in the conventional petroleum system due to the amount of kerogen trapped during the depositional process. The kerogen or continuously called Total Organic Carbon (TOC) behaves like a porosity to a density log and this will be misleading to the higher porosity than the actual shale rock. Prior investigation evaluates the physical properties in shale rock, including shale porosity, TOC, and matrix mineralogy, at a certain limited depth. A solid rock is presumed to consist of a shale matrix and TOC. Meanwhile, shale porosity is contained only in water. TOC responses to sonic wave, density, and porosity logs. We calculated the experimental data to estimate the volume of TOC at the limited depth to obtain the correlation of available logs. Shale porosity is then computed using a density log with the TOC-influence removed. The results show that the shale porosity is to be TOC-free with a value range of 3-14%.
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Hutami, Harnanti Yogaputri, Sonny Winardhi, Tiara Larasati Priniarti, Handoyo, Muchammad Andara, and Yoopy Christian. "Petrophysics Evaluation for Determining Porosity of Shale Reservoirs." IOP Conference Series: Earth and Environmental Science 830, no. 1 (September 1, 2021): 012057. http://dx.doi.org/10.1088/1755-1315/830/1/012057.
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Abstract Indonesia is known for its large potential of shale resources, yet the character of their physical properties remains unclear. This study focuses on how to assess the petrophysical properties of shale using conventional wireline logs. Shale has been largely known as a host rock producing hydrocarbon in the conventional petroleum system due to the amount of kerogen trapped during the depositional process. The kerogen or continuously called Total Organic Carbon (TOC) behaves like a porosity to a density log and this will be misleading to the higher porosity than the actual shale rock. Prior investigation evaluates the physical properties in shale rock, including shale porosity, TOC, and matrix mineralogy, at a certain limited depth. A solid rock is presumed to consist of a shale matrix and TOC. Meanwhile, shale porosity is contained only in water. TOC responses to sonic wave, density, and porosity logs. We calculated the experimental data to estimate the volume of TOC at the limited depth to obtain the correlation of available logs. Shale porosity is then computed using a density log with the TOC-influence removed. The results show that the shale porosity is to be TOC-free with a value range of 3-14%.
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Weydt, Leandra M., Ángel Andrés Ramírez-Guzmán, Antonio Pola, Baptiste Lepillier, Juliane Kummerow, Giuseppe Mandrone, Cesare Comina, et al. "Petrophysical and mechanical rock property database of the Los Humeros and Acoculco geothermal fields (Mexico)." Earth System Science Data 13, no. 2 (February 23, 2021): 571–98. http://dx.doi.org/10.5194/essd-13-571-2021.
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Abstract. Petrophysical and mechanical rock properties are key parameters for the characterization of the deep subsurface in different disciplines such as geothermal heat extraction, petroleum reservoir engineering or mining. They are commonly used for the interpretation of geophysical data and the parameterization of numerical models and thus are the basis for economic reservoir assessment. However, detailed information regarding petrophysical and mechanical rock properties for each relevant target horizon is often scarce, inconsistent or distributed over multiple publications. Therefore, subsurface models are often populated with generalized or assumed values resulting in high uncertainties. Furthermore, diagenetic, metamorphic and hydrothermal processes significantly affect the physiochemical and mechanical properties often leading to high geological variability. A sound understanding of the controlling factors is needed to identify statistical and causal relationships between the properties as a basis for a profound reservoir assessment and modeling. Within the scope of the GEMex project (EU H2020, grant agreement no. 727550), which aims to develop new transferable exploration and exploitation approaches for enhanced and super-hot unconventional geothermal systems, a new workflow was applied to overcome the gap of knowledge of the reservoir properties. Two caldera complexes located in the northeastern Trans-Mexican Volcanic Belt – the Acoculco and Los Humeros caldera – were selected as demonstration sites. The workflow starts with outcrop analog and reservoir core sample studies in order to define and characterize the properties of all key units from the basement to the cap rock as well as their mineralogy and geochemistry. This allows the identification of geological heterogeneities on different scales (outcrop analysis, representative rock samples, thin sections and chemical analysis) enabling a profound reservoir property prediction. More than 300 rock samples were taken from representative outcrops inside the Los Humeros and Acoculco calderas and the surrounding areas and from exhumed “fossil systems” in Las Minas and Zacatlán. Additionally, 66 core samples from 16 wells of the Los Humeros geothermal field and 8 core samples from well EAC1 of the Acoculco geothermal field were collected. Samples were analyzed for particle and bulk density, porosity, permeability, thermal conductivity, thermal diffusivity, and heat capacity, as well as ultrasonic wave velocities, magnetic susceptibility and electric resistivity. Afterwards, destructive rock mechanical tests (point load tests, uniaxial and triaxial tests) were conducted to determine tensile strength, uniaxial compressive strength, Young's modulus, Poisson's ratio, the bulk modulus, the shear modulus, fracture toughness, cohesion and the friction angle. In addition, X-ray diffraction (XRD) and X-ray fluorescence (XRF) analyses were performed on 137 samples to provide information about the mineral assemblage, bulk geochemistry and the intensity of hydrothermal alteration. An extensive rock property database was created (Weydt et al., 2020; https://doi.org/10.25534/tudatalib-201.10), comprising 34 parameters determined on more than 2160 plugs. More than 31 000 data entries were compiled covering volcanic, sedimentary, metamorphic and igneous rocks from different ages (Jurassic to Holocene), thus facilitating a wide field of applications regarding resource assessment, modeling and statistical analyses.
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Hossain, Zakir, and Yijie Zhou. "Petrophysics and rock physics modeling of diagenetically altered sandstone." Interpretation 3, no. 1 (February 1, 2015): SA107—SA120. http://dx.doi.org/10.1190/int-2014-0048.1.
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We worked to establish relationships among porosity, permeability, resistivity, and elastic wave velocity of diagenetically altered sandstone. Many such relationships are documented in the literature; however, they do not consider diagenetic effects. Combining theoretical models with laboratory measured data, we derived mathematical relationships for porosity permeability, porosity velocity, porosity resistivity, permeability velocity, velocity resistivity, and resistivity permeability in diagenetically altered sandstone. The effects of clay and cementation were evaluated using introduced coefficients in these relationships. We found that clean sandstone could be modeled with Kozeny’s relation; however, this relationship broke down for clay-bearing and diagenetically altered sandstone. Porosity is the first-order parameter that affects permeability, electrical, and elastic properties; clay and cement cause secondary effects on these properties. Rock physics modeling results revealed that cementation had a greater effect on elastic properties than electrical properties and clay had a larger effect on electrical properties than elastic properties. The relationships we provided can greatly help to determine permeability, resistivity, and velocity from porosity and to estimate permeability from resistivity and velocity as well as to determine resistivity from velocity measurements.
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Del Moro, Yoryenys, Venkatesh Anantharamu, Lev Vernik, Alfonso Quaglia, and Eduardo Carrillo. "Seismic petrophysics workflow applied to Delaware Basin." Interpretation 8, no. 2 (May 1, 2020): T349—T363. http://dx.doi.org/10.1190/int-2019-0157.1.
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Petrophysical analysis of unconventional plays that are comprised of organic mudrock needs detailed data QC and preparation to optimize the results of quantitative interpretation. This includes accurate computation of mineral volumes, total organic carbon (TOC), porosity, and saturations. We used TOC estimation to aid the process of determining the best pay zones for development of such reservoirs. TOC was calculated as a weighted average of Passey’s (empirical) and the bulk density-based (theoretical) methods. In organic mudrock reservoirs, the computed TOC log was used as an input to compute porosity and calibrate rock-physics models (RPMs), which are needed for understanding the potential of source rocks or finding sweet spots and their contribution to the amplitude variation with offset (AVO) changes in the seismic data. Using calibrated RPM templates, we found that TOC is driving the elastic property variations in the Avalon Formation. We determined the layering and rock fabric anisotropy using empirical relationships or modeled in the rock property characterization process because reflectivity effects are often seen in the observed seismic used for well tie and wavelet estimation. A Class IV AVO response was seen at the top of the Avalon Formation, which is typical of an unconventional reservoir. We then performed solid organic matter (TOC) substitution to account for variability of elastic properties and their contrasts as expressed in seismic amplitudes. To complete the characterization of the intervals of interest, we used conventional seismic petrophysical methods in the workflow and found that the main driver modifying the elastic properties for the Avalon shales was TOC; this conclusion serves as a foundation in integrated seismic inversion that may target lithofacies, TOC, and geomechanical properties. Seismic reservoir characterization results are critical in constraining landing zones and trajectories of the horizontal wells. The final interpretation may be used to rank targets, optimize drilling campaigns, and ultimately improve production.
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Markov, Mikhail, Elena Kazatchenko, Aleksandr Mousatov, and Evgeny Pervago. "Novel approach for simulating the elastic properties of porous rocks including the critical porosity phenomena." GEOPHYSICS 78, no. 4 (July 1, 2013): L37—L44. http://dx.doi.org/10.1190/geo2012-0260.1.
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We tested an approach for calculating the effective elastic properties of rocks taking into account their critical porosity (the percolation threshold). The concept of critical porosity considers that when the porosity of a rock exceeds the critical value, the shear modulus of the rock tends to zero, making it lose its rigidity and the rock falls apart. The classical homogenization schemes do not describe the mechanical properties of a rock near the critical porosity. The approach proposed here is based on the generalized differential effective medium (GDEM) method. We introduce a model of porous elastic media composed of an elastic solid host containing ellipsoidal inclusions of two types. Inclusions of the first type (phase 1) represent pores, and inclusions of the second type (phase 2) contain elastic solid material described by the same elastic properties as the host (phase 0). In this model, with an increase in porosity, the concentration of the host decreased, and it tended to zero near the critical porosity. The model was used for simulation of rock elastic moduli. We compared the modeling results for elastic moduli and acoustic velocities with the experimental data and empirical petrophysical equations. The comparison showed that the GDEM model describes the elastic properties behavior in a wide range of porosity up to the critical value.
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Konoshonkin, D. V., and S. V. Parnachev. "Existing approaches to tight rock laboratory petrophysics: a critical review." IOP Conference Series: Earth and Environmental Science 24 (January 1, 2015): 012042. http://dx.doi.org/10.1088/1755-1315/24/1/012042.
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Akaha-Tse, Homa Viola, Michael Oti, Selegha Abrakasa, and Charles Ugwu Ugwueze. "Valuation of hydraulic fracturing potentials of organic-rich shales from the Anambra basin using rock mechanical properties from wireline logs." Scientia Africana 19, no. 3 (February 24, 2021): 45–44. http://dx.doi.org/10.4314/sa.v19i3.3.
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This study was carried out to determine the rock mechanical properties relevant for hydrocarbon exploration and production by hydraulic fracturing of organic rich shale formations in Anambra basin. Shale samples and wireline logs were analysed to determine the petrophysical, elastic, strength and in-situ properties necessary for the design of a hydraulic fracturing programme for the exploitation of the shales. The results obtained indicated shale failure in shear and barreling under triaxial test conditions. The average effective porosity of 0.06 and permeability of the order of 10-1 to 101 millidarcies showed the imperative for induced fracturing to assure fluid flow. Average Young’s modulus and Poisson’s ratio of about 2.06 and 0.20 respectively imply that the rocks are favourable for the formation and propagation of fractures during hydraulic fracking. The minimum horizontal stress, which determines the direction of formation and growth of artificially induced hydraulic fractures varies from wellto-well, averaging between 6802.62 to 32790.58 psi. The order of variation of the in-situ stresses is maximum horizontal stress>vertical stress>minimum horizontal stress which implies a reverse fault fracture regime. The study predicts that the sweet spots for the exploration and development of the shale-gas are those sections of the shale formations that exhibit high Young’s modulus, low Poisson’s ratio, and high brittleness. The in-situ stresses required for artificially induced fractures which provide pore space for shale gas accumulation and expulsion are adequate. The shales possess suitable mechanical properties to fracture during hydraulic fracturing. Application of these results will enhance the potentials of the onshore Anambra basin as a reliable component in increasing Nigeria’s gas reserves, for the improvement of the nation’s economy and energy security.
Key Words: Hydraulic Fracturing, Organic-rich Shales, Rock Mechanical Properties, Petrophysical Properties, Anambra Basin
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Julianti, D., Fatkhan, E. Dinanto, and A. S. Murtani. "Petrophysics Analysis for Determination of Density Porosity and Neutron-Density Porosity on Carbonate Rock in East Java Basin." IOP Conference Series: Earth and Environmental Science 1031, no. 1 (May 1, 2022): 012023. http://dx.doi.org/10.1088/1755-1315/1031/1/012023.
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Abstract Indonesia has much potential in energy resources. The exploration and exploitation activities in Indonesia help to fulfill the energy needs in Indonesia. The exploration activities in Indonesia help to find the potential energy resources such oil and gas. Reservoir characterization with petrophysics can be applied to define the lithology, porosity, water saturation, and permeability the rock under the ground. One of the important aspect to define the reservoir is to understand the porosity of the targe reservoir. In this paper, the author will calculate the porosity in the reservoir using petrophysics analysis with density and neutron-density. The result is the neutron-density porosity giving better result than the density porosity.
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Weinert, Sebastian, Kristian Bär, and Ingo Sass. "Database of petrophysical properties of the Mid-German Crystalline Rise." Earth System Science Data 13, no. 3 (April 1, 2021): 1441–59. http://dx.doi.org/10.5194/essd-13-1441-2021.
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Abstract. Petrophysical properties are a key element for reservoir characterization but also for interpreting the results of various geophysical exploration methods or geophysical well logs. Furthermore, petrophysical properties are commonly used to populate numerical models and are often critically governing the model results. Despite the common need for detailed petrophysical properties, data are still very scarce and often not available for the area of interest. Furthermore, both the online research for published property measurements or compilations, as well as dedicated measurement campaigns of the selected properties, which require comprehensive laboratory equipment, can be very time-consuming and costly. To date, most published research results are often focused on a limited selection of parameters only, and hence researching various petrophysical properties, needed to account for the thermal–hydraulic–mechanical behaviour of selected rock types or reservoir settings, can be very laborious. Since for deep geothermal energy in central Europe, the majority of the geothermal potential or resource is assigned to the crystalline basement, a comprehensive database of petrophysical properties comprising rock densities, porosity, rock matrix permeability, thermal properties (thermal conductivity and diffusivity, specific heat capacity) as well as rock mechanical properties as compressional and shear wave velocities, unconfined compressive strength, Young's modulus, Poisson's ratio, tensile strength and triaxial shear strength was compiled from measurements conducted at the HydroThermikum lab facilities of the Technical University of Darmstadt. Analysed samples were mostly derived from abandoned or active quarries and natural or artificial outcrops such as road cuts, riverbanks or steep hillslopes. Furthermore, samples of the cored deep wells Worms 3 (samples from 2175–2195 m), Stockstadt 33R (samples from 2245–2267 m), Weiterstadt 1 (samples from 2502–2504 m), Tiefbohrung Groß-Umstadt/Heubach, B/89–B02 and the cored shallow wells (Forschungsbohrung Messel GA 1 and 2) as well as GWM17 Zwingenberg, GWM1A Zwingenberg, Langenthal BK2/05, EWS267/1 Heubach, and archive samples of the Institut für Steinkonservierung e.V. in Mainz originating from a comprehensive large-scale sampling campaign in 2007 were investigated. The database (Weinert et al., 2020b; https://doi.org/10.25534/tudatalib-278) aims to provide easily accessible petrophysical properties of the Mid-German Crystalline Rise, measured on 224 locations in Bavaria, Hessen, Rhineland-Palatinate and Thuringia and comprising 26 951 single data points. Each data point is addressed with the respective metadata such as the sample identifier, sampling location, petrography and, if applicable, stratigraphy and sampling depth (in the case of well samples).
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Prioul, Romain, Richard Nolen-Hoeksema, MaryEllen Loan, Michael Herron, Ridvan Akkurt, Marcelo Frydman, Laurence Reynolds, et al. "Using cuttings to extract geomechanical properties along lateral wells in unconventional reservoirs." GEOPHYSICS 83, no. 3 (May 1, 2018): MR167—MR185. http://dx.doi.org/10.1190/geo2017-0047.1.
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We have developed a method using measurements on drill cuttings as well as calibrated models to estimate anisotropic mechanical properties and stresses in unconventional reservoirs, when logs are not available in lateral wells. We measured mineralogy and organic matter on cuttings using diffuse reflectance infrared Fourier transform spectroscopy (DRIFTS). We described the methodology and illustrated it using two vertical control wells in the Vaca Muerta Formation, Argentina, and one lateral well drilled in the low-maturity oil-bearing reservoir. The method has two steps. First, using a vertical control well containing measurements from cuttings, a comprehensive logging suite, cores, and in situ stress tests, we define and calibrate four models: petrophysical, rock physics, dynamic-static elastic, and geomechanical. The petrophysical model provides petrophysical constituent volumes (mineralogy, organic matter, and fluids) from logs or DRIFTS inputs to the rock-physics model for calculating the dynamic anisotropic elastic moduli. The dynamic-static elastic and geomechanics models provide the relationships for computing static elastic properties and the minimum stress. Second, we acquire DRIFTS data on cuttings in the target lateral well and apply the four models for calculating stresses. We find that the method is successful for two reasons. First, the sonic-log-derived elastic moduli could be reconstructed accurately from the rock-physics model using input from petrophysical volumes from logs and DRIFTS data. A striking observation is that the elastic-property heterogeneity in those wells is explainable almost solely by compositional variations. Second, petrophysical volumes can be reconstructed by the petrophysical model and DRIFTS data. In the lateral well, we observed horizontal variations of mineralogy and organic matter, which controlled variations of elastic moduli and its anisotropy, and, in turn, affected partitioning of the gravitational and tectonic components in the minimum stress. This methodology promises accurate in situ stress estimates using cutting-based measurements and assessments of unconventional-reservoir heterogeneity.
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Fedor, Ferenc, Zoltán Máthé, Péter Ács, and Péter Koroncz. "New results of Boda Claystone research: Genesis, mineralogy, geochemistry, petrophysics." Geological Society, London, Special Publications 482, no. 1 (December 7, 2018): 75–92. http://dx.doi.org/10.1144/sp482.13.
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AbstractBoda Claystone is a very tight clayey rock with extreme low porosity and permeability, nano-size pores and small amounts of swelling clays. Due to this character it is ideal as a potential host rock for research into the possibilities of high-level waste deposition in geological formation. Though the research started more than 30 years ago, the genesis, the geotectonic history of the Boda Claystone Formation (BCF) and the geology of surrounding areas has only been sketched out recently. On the basis of research of the past few years the process of sedimentation of different blocks was able to be reconstructed. Equipment and methodological developments were needed for the investigation of reservoir geological and hydrodynamic behaviour of this rock, which began in the early 2000s. Based on them the pore structure and reservoir could be characterized in detail. Only theoretical approaches were available for the chemical composition of free porewater. Traditional water-extracting methods were not adaptable because of excessively low porosity and nano-scale pore size distribution. Hence, new ways have to be found for getting enough water for analysis. These new results of BCF research help to prepare more sophisticated and directed experiments, in which there is a great interest internationally.
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Kunshin, Andrey, Mikhail Dvoynikov, Eduard Timashev, and Vitaly Starikov. "Development of Monitoring and Forecasting Technology Energy Efficiency of Well Drilling Using Mechanical Specific Energy." Energies 15, no. 19 (October 9, 2022): 7408. http://dx.doi.org/10.3390/en15197408.
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This article is devoted to the development of technology for improving the efficiency of directional well drilling by predicting and adjusting the system of static and dynamic components of the actual weight on the bit, based on the real-time data interpretation from telemetry sensors of the bottom hole assembly (BHA). Studies of the petrophysical and geomechanical properties of rock samples were carried out. Based on fourth strength theory and the Palmgren–Miner fatigue stress theory, the mathematical model for prediction of effective distribution of mechanical specific energy, using machine learning methods while drilling, was developed. An algorithm was set for evaluation and estimation of effective destruction of rock by comparing petrophysical data in the well section and predicting the shock impulse of the bit. Based on the theory provided, it is assumed that the given shock impulse is an actual representation of an excessive energy, conveyed to BHA. This excessive energy was quantitively determined and expressed as an adjusting coefficient for optimal weight on bit. The developed mathematical and predictive model helps to identify the presence of ineffective rock destruction and adjust drilling regime accordingly. Several well drilling datasets from the North Sea were analyzed. The effectiveness of the developed mathematical model and algorithms was confirmed by testing well drilling data.
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Torres-Verdín, Carlos, André Revil, Michael Oristaglio, and Tapan Mukerji. "Multiphysics borehole geophysical measurements, formation evaluation, petrophysics, and rock physics — Introduction." GEOPHYSICS 77, no. 3 (May 1, 2012): WA1—WA2. http://dx.doi.org/10.1190/geo-2012-0409-spsein.1.
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Yogi, Ade. "Petrophysics Analysis for Reservoir Characterization of Cretaceous Clastic Rocks: A Case Study of the Arafura Basin." Jurnal Geologi dan Sumberdaya Mineral 21, no. 3 (August 28, 2020): 129. http://dx.doi.org/10.33332/jgsm.geologi.v21i3.527.
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This study presents petrophysics analysis results from two wells located in the Arafura Basin. The analysis carried out to evaluate the reservoir characterization and its relationship to the stratigraphic sequence based on log data from the Koba-1 and Barakan-1 Wells. The stratigraphy correlation section of two wells depicts that in the Cretaceous series a transgression-regression cycle. The petrophysical parameters to be calculated are the shale volume and porosity. The analysis shows that there is a relationship between stratigraphic sequences and petrophysical properties. In the study area, shale volumes used to make complete rock profiles in wells assisted by biostratigraphic data, cutting descriptions, and core descriptions. At the same time, porosity shows a conformity pattern with the transgression-regression cycle.Keywords: petrophysics, reservoir characterization, Cretaceous, transgressive-regressive cycle
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Kieu, Duy Thong, Quy Ngoc Pham, Quang Man Ha, Huy Giao Pham, Huy Hien Doan, Viet Dung Bui, and Hong Trang Pham. "Porosity prediction using fuzzy clustering and joint inversion of wireline logs: A case study of the Nam Con Son basin, offshore Vietnam." Petrovietnam Journal 6 (July 18, 2022): 4–10. http://dx.doi.org/10.47800/pvj.2022.06-01.
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Petrophysical properties such as porosity, permeability and fluid saturations are important parameters for reservoir characterisation, which can be determined by experimental constitutive equations between rock parameters and well logging data. Thus, the same rock properties might demonstrate different patterns, depending on the input and equations used. In this work, we used the cross-properties (a common set of rock properties) that influence different measurements to reduce the ambiguity of the petrophysical property definition. We present an approach of using fuzzy c-means clustering to classify the well logs and core data in clusters and then running inversion for each cluster. The obtained results allowed us to establish suitable parameters in constitutive equations, which usually vary with rock units that may relate to clusters. Testing data applied to the Nam Con Son basin show a square correlation coefficient of 0.66 between the predicted and core measurement, suggesting a reasonable matching of the testing data set.
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Carpenter, Chris. "Integrated Work Flow Delivers Precise Properties Input for Unconventional Simulation." Journal of Petroleum Technology 73, no. 11 (November 1, 2021): 68–69. http://dx.doi.org/10.2118/1121-0068-jpt.
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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203374, “Is My Completions Engineer Provided With the Correct Petrophysical and Geomechanical Properties Inputs?” by Philippe Gaillot, Brian Crawford, and Yueming Liang, SPE, ExxonMobil, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. To simulate the performance of unconventional wells effectively, incorporating sufficient geological complexity is essential to allow for realistic variability in the petrophysical and mechanical properties controlling the productivity of the effective stimulated rock volume (ESRV). The complete paper presents an integrated work flow to model mechanical properties at sufficiently high resolution (centimeter scale) to accurately honor rock fabric and its height and complexity effects on hydraulic fracturing and, therefore, on production. Once upscaled, outputs of this work flow enable a more-realistic borehole view of reservoir quality, fluid-flow units, and geomechanical stratigraphy, all information key to optimal asset development. Introduction Simulating hydraulic fractures with pre-existing natural mechanical discontinuities remains an important challenge. In most cases, the trend is to include more details in the simulations and apply more computational power to solve the problem. While these complex numerical simulations allow simultaneous interaction between multiple phenomena, the validity of the predicted hydraulic fractures, and thus ESRV productivity, may be questionable if inputs to the hydraulic-fracturing and production models do not capture the effective fine-scale complexity of the formation properties, namely the minimum in-situ horizontal stress contrast between layers, the changing layer properties, and the mechanical and flow properties of the interfaces. The complete paper presents a seven-step work flow wherein core poroelastic anisotropies derived from quantitative mineralogy and well-established micro-mechanical theory are integrated into a high-vertical-resolution multiphysics petrophysical model able to capture the centimeter-scale level of heterogeneity observed from cores. The resulting high-vertical-resolution well frame-work enables a detailed well-scale calibration and recognition of facies and stacking patterns; an accurate and core-calibrated geochemical, petrophysical, and geomechanical characterization of individual beds; and an identification and characterization of the interfaces between beds.
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Tezuka, Kazuhiko. "^|^ldquo;Petrophysics - Current applications and challenges for evaluation of rock properties^|^rdquo;." Journal of the Japanese Association for Petroleum Technology 77, no. 1 (2012): 82–85. http://dx.doi.org/10.3720/japt.77.82.
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Hassane, Amadou, Chukwuemeka Ngozi Ehirim, and Tamunonengiyeofori Dagogo. "Rock physics diagnostic of Eocene Sokor-1 reservoir in Termit subbasin, Niger." Journal of Petroleum Exploration and Production Technology 11, no. 9 (August 20, 2021): 3361–71. http://dx.doi.org/10.1007/s13202-021-01259-2.
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AbstractEocene Sokor-1 reservoir is intrinsically heterogeneous and characterized by low-contrast low-resistivity log responses in parts of the Termit subbasin. Discriminating lithology and fluid properties using petrophysics alone is complicated and undermines reservoir characterization. Petrophysics and rock physics were integrated through rock physics diagnostics (RPDs) modeling for detailed description of the reservoir microstructure and quality in the subbasin. Petrophysical evaluation shows that Sokor-1 sand_5 interval has good petrophysical properties across wells and prolific in hydrocarbons. RPD analysis revealed that this sand interval could be best described by the constant cement sand model in wells_2, _3, _5 and _9 and friable sand model in well_4. The matrix structure varied mostly from clean and well-sorted unconsolidated sands as well as consolidated and cemented sandstones to deteriorating and poorly sorted shaly sands and shales/mudstones. The rock physics template built based on the constant cement sand model for representative well_2 diagnosed hydrocarbon bearing sands with low Vp/Vs and medium-to-high impedance signatures. Brine shaly sands and shales/mudstones were diagnosed with moderate Vp/Vs and medium-to-high impedance and high Vp/Vs and medium impedance, respectively. These results reveal that hydrocarbon sands and brine shaly sands cannot be distinctively discriminated by the impedance property, since they exhibit similar impedance characteristics. However, hydrocarbon sands, brine shaly sands and shales/mudstones were completely discriminated by characteristic Vp/Vs property. These results demonstrate the robust application of rock physics diagnostic modeling in quantitative reservoir characterization and may be quite useful in undrilled locations in the subbasin and fields with similar geologic settings.
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Gajic, Violeta, Vesna Matovic, Nebojsa Vasic, and Danica Sreckovic-Batocanin. "Petrophysical and mechanical properties of the Struganik limestone (Vardar zone, Western Serbia)." Annales g?ologiques de la Peninsule balkanique, no. 72 (2011): 87–100. http://dx.doi.org/10.2298/gabp1172087g.
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The Struganik limestone has been increasingly popular in recent years for interior and exterior building applications, due to easy workability, low cost and multi purpose suitability. The quality of limestone is determined by its mineralogical and textural characteristics and physico-mechanical properties. The Struganik stone corresponds to marl, clayey limestone and limestone (micritic and allochemical). The limestone is commonly layered, either thinly bedded or banked. Chert concretions are present in all varieties. The Upper and the Lower Campanian age were deduced by the abundant foraminifers. Micrite limestone is an autochthonous rock generated in a deep marine environment, whereas allochemical limestone is related to a shallow marine environment but subsequently brought into a deep-water system. The mass quality of the Struganik limestone is controlled by variability of lithology and layering. The values of physico-mechanical properties, such as density, porosity, water absorption and strength, were statistically analyzed and the obtained data were used to assess the rock quality in the quarry. The relationship among the quantified properties is described by regression analyses and the equations of the best-fit line. The Struganik limestone was qualified by its petrological and engineering properties coupled with statistical analysis. It satisfies the majority of the requirements of the Main National Standard as a decorative stone, but with a limiting factor regarding abrasive resistance.
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Ali Akbar, Muhammad Nur, István Nemes, Zsolt Bihari, Helga Soltész, Ágnes Bárány, László Tóth, Szabolcs Borka, and György Ferincz. "Naturally Fractured Carbonate Reservoir Characterization: A Case Study of a Mature High-Pour Point Oil Field in Hungary." Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description 63, no. 6 (December 1, 2022): 634–49. http://dx.doi.org/10.30632/pjv63n6-2022a4.
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An integrated technical study was conducted for a field development project in west Hungary. This study offers a better solution for estimating petrophysical properties and fracture facies vertically along the well and laterally for 3D static and dynamic models of naturally fractured reservoirs in carbonate rocks. More than 30 wells with 40 years of production history were used in order to build reliable static and dynamic models. The fracture class/facies plays an essential role in the spatial distribution of petrophysical properties during 3D reservoir modeling. It was defined by integrating conventional logs, image logs, drilling parameters, and production or well test data. Three fracture facies are defined as macrofracture (including permeable subseismic fault), microfracture, and host rock. Subsequently, the fracture class’s spatial distribution is guided by seismic attributes of fault likelihood combined with the geological concept of the fault and damage zone. As a result, the established fracture classes along the wells are validated by static and dynamic subsurface data. A spherical self-organizing map (SOM) was also implemented for predicting the open-fracture location in wells having limited subsurface data. Moreover, fracture lateral distribution follows the distribution of the fault zone of the fault core, high damage zone, low damage zone, and host rock. The higher the fault displacement, the wider the damage zone and fault core formed. Macrofractures and microfractures frequently appear around the fault core and high damage zone. While only microfractures are dominantly present in the low damage zones, in contrast, the unfractured class is dominantly distributed in the host-rock area. Also, the lithologies are considered in distributing the fracture class because the rock mechanic properties and the number of fractures are strongly controlled by rock compositions. Once the fracture class is distributed, porosity, permeability, and water saturation are modeled in the three-dimensional (3D) geocellular model. Finally, this fracture class also plays a role as a rock typing for reservoir simulation. The saturation height model is built using the fracture class distribution resulting in the initialization, history-matching process, and production forecast from 20 wells showing excellent quality. As a novelty, this study offers a better understanding of fracture distribution and accelerates the history-matching process with a more confident result of the production forecast. In the absence of advanced technologies, like image logs and production logging (PLT) measurements, this study still effectively assists us in recognizing the fracture presence and its quality in both well-depth interval and 3D spatial space, and successfully guided us in proposing new infill drilling with strong confidence and delivering on the high end of expected results.
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Magoba, Moses, and Mimonitu Opuwari. "Petrophysical interpretation and fluid substitution modelling of the upper shallow marine sandstone reservoirs in the Bredasdorp Basin, offshore South Africa." Journal of Petroleum Exploration and Production Technology 10, no. 2 (November 7, 2019): 783–803. http://dx.doi.org/10.1007/s13202-019-00796-1.
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Abstract The fluid substitution method is used for predicting elastic properties of reservoir rocks and their dependence on pore fluid and porosity. This method makes it possible to predict changes in elastic response of a rock saturation with different fluids. This study focused on the Upper Shallow Marine sandstone reservoirs of five selected wells (MM1, MM2, MM3, MM4, and MM5) in the Bredasdorp Basin, offshore South Africa. The integration of petrophysics and rock physics (Gassmann fluid substitution) was applied to the upper shallow marine sandstone reservoirs for reservoir characterisation. The objective of the study was to calculate the volume of clay, porosity, water saturation, permeability, and hydrocarbon saturation, and the application of the Gassmann fluid substitution modelling to determine the effect of different pore fluids (brine, oil, and gas) on acoustic properties (compressional velocity, shear velocity, and density) using rock frame properties. The results showed average effective porosity ranging from 8.7% to 16.6%, indicating a fair to good reservoir quality. The average volume of clay, water saturation, and permeability values ranged from 8.6% to 22.3%, 18.9% to 41.6%, and 0.096–151.8 mD, respectively. The distribution of the petrophysical properties across the field was clearly defined with MM2 and MM3 revealing good porosity and MM1, MM4, and MM5 revealing fair porosity. Well MM4 revealed poor permeability, while MM3 revealed good permeability. The fluid substitution affected rock property significantly. The primary velocity, Vp, slightly decreased when brine was substituted with gas in wells MM1, MM2, MM3, and MM4. The shear velocity, Vs, remained unaffected in all the wells. This study demonstrated how integration of petrophysics and fluid substitution can help to understand the behaviour of rock properties in response to fluid saturation changes in the Bredasdorp Basin. The integration of these two disciplines increases the obtained results’ quality and reliability.
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Alcaíno-Olivares, Rodrigo, Martin Ziegler, Susanne Bickel, Hesham Ismaiel, Kerry Leith, and Matthew Perras. "Rock Mechanical Laboratory Testing of Thebes Limestone Formation (Member I), Valley of the Kings, Luxor, Egypt." Geotechnics 2, no. 4 (September 26, 2022): 825–54. http://dx.doi.org/10.3390/geotechnics2040040.
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The Thebes Limestone Formation of Lower Eocene age is one of the most extensive rock units in Egypt. It is of importance to the apogee of the ancient Egyptian civilization, particularly in Luxor (South-Central Egypt), where the rock formation hosts the Theban Necropolis, a group of funerary chambers and temples from the New Kingdom Egyptian era (3500–3000 BP). In this work, we investigated the petrophysical and rock mechanical properties (e.g., rock strength, critical crack stress thresholds) through laboratory tests on eleven rock blocks collected from one area within the Theban Necropolis known as the Valley of the Kings (KV). The blocks belong to Member I of the Thebes Limestone Formation, including six blocks of marly limestone, three blocks of micritic limestone, one block of argillaceous limestone from the Upper Esna Shale Formation, and one block of silicified limestone of unknown origin. Special attention was given to the orientation of bedding planes in the samples: tests were conducted in parallel (PA) and perpendicular (PE) configurations with respect to bedding planes. We found that the marly limestone had an average unconfined compressive strength (UCS) of 30 MPa and 39 MPa for the PA and PE tests, respectively. Similarly, the micritic limestone tests showed an average UCS of 24 MPa for the PA orientation and 58 MPa for the PE orientation. The critical crack thresholds were the first ever reported for Member I, as measured with strain gauge readings. The average crack initiation (CI) stress thresholds for the marly limestone (PA: 14 MPa) and the micritic limestone (PA: 11 MPa; PE: 24 MPa) fall within the typical ratio of CI to UCS (0.36–0.52). The micritic limestone had an average Young’s modulus (E) of 19.5 GPa and 10.3 GPa for PA and PE, respectively. The Poisson’s ratios were 0.2 for PA and 0.1 for PE on average. Both marly and micritic limestone can be characterised by a transverse isotropic strength behaviour with respect to bedding planes. The failure strength for intact anisotropic rocks depends on the orientation of the applied force, which must be considered when assessing the stability of tombs and cliffs in the KV and will be used to understand and improve the preservation of this UNESCO World Heritage site.
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Skakal's'ka, L. "Physical and reservoir properties prediction for reservoir rocksin unconventional gas-bearing geological structures." Visnyk of Taras Shevchenko National University of Kyiv. Geology, no. 1 (64) (2014): 35–40. http://dx.doi.org/10.17721/1728-2713.64.07.35-40.
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Research into the behavior of elastic waves in thin-layered gas-bearing geological structures depends on the choice of geophysical and mathematical models of natural geological media and the numerical methods of problem solving. Hence the efficiency of a quasi-homogeneous, isotropic fractured-porous two-phase medium with given physical and mechanical properties. We have suggested a method of calculating empirical relationships between volumetric compression, porosity and pressure in porous rocks of an arbitrary geological region. Data on Zaluzhany wells were used to calculate the correlation and empirical relationships between reservoir properties and parameters of elastic waves and to distinguish dry and oil-gas saturated rocks. The least square technique made it possible to determine the correlation between the compressibility factor of fluid-saturated rocks and their porosity and pressure. Discrimination between oil and water was based on the density parameter. An algorithm has been suggested to do the corresponding calculations. The theoretical and practical implications of this study are as follows: – developing a numerical analytical predictive model for interpreting acoustic data on thin-layered rocks which is based on the correlations between their dynamic physical (effective wave propagation velocities, amplitude attenuation coefficients and their energy absorption) and reservoir (porosity, fracturing, compressibility) properties; – applying the proposed model and software products in geophysical exploration to interpret the geological and geophysical data on the structure and physical characteristics of sections and the physical properties of gas-bearing basins. In seismic acoustic exploration, the numerical model has to include experimental geological and geophysical data on the peculiarities of rock occurrence in the investigated area, with the physical and mechanical properties of different territories showing considerable variation. Such input data, as well as structural features and scattering properties of rocks (density, bedding, microporosity), ensure a significant increase in the accuracy of the numerical analysis. Preliminary testing was based on the data on the elastic moduli and S-wave velocities for dry and fluid-saturated rocks. Calculations were made of the elastic moduli and P-wave velocities for dry and fluid-saturated rocks of the Western oil and gas region of Ukraine (Zaluzhany-18 and Zaluzhany-19 wells). The aim of this work was to demonstrate the efficiency of the predictive method by examining the reservoir rock properties of the wells and to evaluate their gas saturation using the acoustic logging, geophysical and petrophysical data.
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Zeb, Jahan, Sanjeev Rajput, and Jimmy Ting. "Seismic petrophysics focused case study for AVA modelling and pre-stack seismic inversion." APPEA Journal 56, no. 1 (2016): 341. http://dx.doi.org/10.1071/aj15025.
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Hydrocarbon reservoirs are characterised by integrating seismic, well-log and petrophysical information, which are dissimilar in spatial distribution, scale and relationship to reservoir properties. Well logs are essential for amplitude versus offset (AVO) modelling and seismic inversion. The usability of well logs can be determined during wavelet estimation, seismic-to-well ties, background model building, property distribution for inversion, deriving probability density functions and variograms, offset-to-angle conversion of seismic data, and many other processes. For the implementation of seismic inversion workflows, accurate and geologically corrected compressional-sonic, shear-sonic and density logs are necessary. Preparing the logs for quantitative interpretation becomes challenging in a real-field environment because of bad borehole conditions including washouts, uncalibrated and variability of logging tools, invasion effects, missing shear logs and change of borehole size. Conventional petrophysical analysis is usually restricted to the reservoir interval, the calculation of reservoir versus non-reservoir (including sands or shales), and log corrections for smaller intervals; in contrast, seismic petrophysics encompasses the entire geological interval, calculates the volume of multi-minerals, incorporates boundaries between non-reservoir and reservoir, and often includes the prediction of missing compressional and shear-sonic for AVO analysis. A detailed seismic petrophysics analysis was performed for amplitude versus angle (AVA) modelling and attributes analysis. To perform the AVA modelling, a series of forward models in association with rock physics modelled fluid-substituted logs were developed, and associated seismic responses for various pore fluids and rock types studied. The results reveal that synthetic seismic responses together with the AVA analysis show changes for various lithologies. AVA attributes analysis show trends in generated synthetic seismic responses for various fluid-substituted and porosity logs. Reservoir modelling and fluid substitution increases understanding of the observed seismic response. This paper describes detailed data analysis using various techniques to confirm the rock model for petrophysical evaluation, rock physics modelling, AVA analysis, pre-stack seismic inversion, and the scenario modelling applied to the study of an oil field in Australia.
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Fjeldstad, Torstein, and Dario Grana. "Joint probabilistic petrophysics-seismic inversion based on Gaussian mixture and Markov chain prior models." GEOPHYSICS 83, no. 1 (January 1, 2018): R31—R42. http://dx.doi.org/10.1190/geo2017-0239.1.
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Seismic reservoir characterization focuses on the prediction of reservoir properties based on the available geophysical and petrophysical data. The inverse problem generally includes continuous properties, such as petrophysical and elastic attributes, and discrete properties, such as lithology/fluid classes. We have developed a joint probabilistic inversion methodology for the prediction of petrophysical and elastic properties and lithology/fluid classes that combined statistical rock physics and Bayesian seismic inversion. The elastic attributes depend on continuous petrophysical variables, such as porosity and clay content, and discrete lithology/fluid classes, through a nonlinear rock-physics relationship together. The seismic model relates the elastic attributes, such as velocities and density, to their seismic response (reflectivity, traveltime, and amplitudes). The advantage of our integrated approach is that the inversion method accounts for the uncertainty associated to each step of the modeling workflow. The lithology/fluid classes are assigned by a Markov random field prior model to capture vertical continuity and vertical sorting of the lithology/fluid classes. Because rock and fluid properties are in general not Gaussian, a spatially coupled Gaussian mixture prior model based on the lithology/fluid classes is constructed. The forward geophysical operator includes a lithology-/fluid-dependent rock physics model and a linearized seismic model based on the convolution of the seismic wavelet with the reflectivity coefficient series. The solution of the inverse problem consists of the posterior distributions of petrophysical and elastic properties and lithology/fluid classes. We proposed an efficient Markov chain Monte Carlo algorithm to sample from the posterior models and assess the uncertainty. Our methodology is demonstrated on a seismic cross section from a survey in the Norwegian Sea, and it shows promising results consistent with well-log data measured at the well location as well as reliable prediction uncertainties.
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Jackson, M. D. D., J. R. R. Percival, P. Mostaghimi, B. S. S. Tollit, D. Pavlidis, C. C. C. Pain, J. L. M. A. L. M. A. Gomes, et al. "Reservoir Modeling for Flow Simulation by Use of Surfaces, Adaptive Unstructured Meshes, and an Overlapping-Control-Volume Finite-Element Method." SPE Reservoir Evaluation & Engineering 18, no. 02 (May 6, 2015): 115–32. http://dx.doi.org/10.2118/163633-pa.
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Summary We present new approaches to reservoir modeling and flow simulation that dispose of the pillar-grid concept that has persisted since reservoir simulation began. This results in significant improvements to the representation of multiscale geologic heterogeneity and the prediction of flow through that heterogeneity. The research builds on more than 20 years of development of innovative numerical methods in geophysical fluid mechanics, refined and modified to deal with the unique challenges associated with reservoir simulation. Geologic heterogeneities, whether structural, stratigraphic, sedimentologic, or diagenetic in origin, are represented as discrete volumes bounded by surfaces, without reference to a predefined grid. Petrophysical properties are uniform within the geologically defined rock volumes, rather than within grid cells. The resulting model is discretized for flow simulation by use of an unstructured, tetrahedral mesh that honors the architecture of the surfaces. This approach allows heterogeneity over multiple length-scales to be explicitly captured by use of fewer cells than conventional corner-point or unstructured grids. Multiphase flow is simulated by use of a novel mixed finite-element formulation centered on a new family of tetrahedral element types, PN(DG)–PN+1, which has a discontinuous Nth-order polynomial representation for velocity and a continuous (order N +1) representation for pressure. This method exactly represents Darcy-force balances on unstructured meshes and thus accurately calculates pressure, velocity, and saturation fields throughout the domain. Computational costs are reduced through dynamic adaptive-mesh optimization and efficient parallelization. Within each rock volume, the mesh coarsens and refines to capture key flow processes during a simulation, and also preserves the surface-based representation of geologic heterogeneity. Computational effort is thus focused on regions of the model where it is most required. After validating the approach against a set of benchmark problems, we demonstrate its capabilities by use of a number of test models that capture aspects of geologic heterogeneity that are difficult or impossible to simulate conventionally, without introducing unacceptably large numbers of cells or highly nonorthogonal grids with associated numerical errors. Our approach preserves key flow features associated with realistic geologic features that are typically lost. The approach may also be used to capture near-wellbore flow features such as coning, changes in surface geometry across multiple stochastic realizations, and, in future applications, geomechanical models with fracture propagation, opening, and closing.
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Bär, Kristian, Thomas Reinsch, and Judith Bott. "The PetroPhysical Property Database (P<sup>3</sup>) – a global compilation of lab-measured rock properties." Earth System Science Data 12, no. 4 (October 13, 2020): 2485–515. http://dx.doi.org/10.5194/essd-12-2485-2020.
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Abstract. Petrophysical properties are key to populating local and/or regional numerical models and to interpreting results from geophysical investigation methods. Searching for rock property values measured on samples from a specific rock unit at a specific location might become a very time-consuming challenge given that such data are spread across diverse compilations and that the number of publications on new measurements is continuously growing and data are of heterogeneous quality. Profiting from existing laboratory data to populate numerical models or interpret geophysical surveys at specific locations or for individual reservoir units is often hampered if information on the sample location, petrography, stratigraphy, measuring method and conditions is sparse or not documented. Within the framework of the EC-funded project IMAGE (Integrated Methods for Advanced Geothermal Exploration, EU grant agreement no. 608553), an open-access database of lab-measured petrophysical properties has been developed (Bär et al., 2017, 2019b: P3 – database, https://doi.org/10.5880/GFZ.4.8.2019.P3. The goal of this hierarchical database is to provide easily accessible information on physical rock properties relevant for geothermal exploration and reservoir characterisation in a single compilation. Collected data include classical petrophysical, thermophysical, and mechanical properties as well as electrical conductivity and magnetic susceptibility. Each measured value is complemented by relevant meta-information such as the corresponding sample location, petrographic description, chronostratigraphic age, if available, and original citation. The original stratigraphic and petrographic descriptions are transferred to standardised catalogues following a hierarchical structure ensuring inter-comparability for statistical analysis (Bär and Mielke, 2019: P3 – petrography, https://doi.org/10.5880/GFZ.4.8.2019.P3.p; Bär et al., 2018, 2019a: P3 – stratigraphy, https://doi.org/10.5880/GFZ.4.8.2019.P3.s). In addition, information on the experimental setup (methods) and the measurement conditions are listed for quality control. Thus, rock properties can directly be related to in situ conditions to derive specific parameters relevant for simulating subsurface processes or interpreting geophysical data. We describe the structure, content and status quo of the database and discuss its limitations and advantages for the end user.
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Domagała, Kacper, Tomasz Maćkowski, Michał Stefaniuk, and Beata Reicher. "Prediction of Reservoir Parameters of Cambrian Sandstones Using Petrophysical Modelling—Geothermal Potential Study of Polish Mainland Part of the Baltic Basin." Energies 14, no. 13 (July 1, 2021): 3942. http://dx.doi.org/10.3390/en14133942.
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Important factors controlling the effective utilization of geothermal energy are favorable reservoir properties of rock formations, which determine both the availability and the transfer opportunities of reservoir fluids. Hence, crucial to the successful utilization of a given reservoir is the preliminary recognition of distribution of reservoir parameters as it enables the researchers to select the prospective areas for localization of future geothermal installations and to decide on their characters. The objectives of this paper are analyses and discussion of the properties of quartz sandstones buried down to a depth interval from about 3000 to under 5000 m below surface. These sandstones belong to Ediacaran–Lowery Cambrian Łeba, Kluki and Żarnowiec formations. The source data from the Słupsk IG-1 provided the basis for 1D reconstruction of burial depth and paleothermal conditions as well as enabled the authors to validate of the results of 2D models. Then, porosity distribution within the reservoir formation was determined using the modelings of both the mechanical and chemical compactions along the 70 km-long B’-B part of the A’-A cross-section Bornholm-Słupsk IG-1 well. The results confirmed the low porosities and permeabilities as well as high temperatures of the analyzed rock formations in the Słupsk IG-1 well area. Towards the coast of the Baltic Sea, the porosity increases to more than 5%, while the temperature decreases, but is still relatively high, at about 130 °C. This suggests the application of an enhanced geothermal system or hot dry rocks system as principal methods for using geothermal energy.
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Boguslavskiy, M. A., and A. A. Burmistrov. "Preliminary research on developing the methodology for predicting and estimation of productive sulfide mineralization of the Norilsk type using polarizing-optical and petrophysical methods (on the example of the Talnakh Deposit)." Moscow University Bulletin. Series 4. Geology 1, no. 2 (January 28, 2022): 55–63. http://dx.doi.org/10.33623/0579-9406-2021-2-55-63.
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The quantity of the mineral composition of ore and parent rocks was carried out. Ore sections from the core samples of two wells of the Talnakh field were used for these studying. Also a number of their physical, mechanical, magnetic and electrical properties were determined. The content of the main ore minerals and useful components in the studied samples were calculated due to comparison of these data of their petrophysical properties. Additionally petrophysical anomalies in the external contact of ore horizons were identified. Using of this methodology may contribute to improving the efficiency of survey and evaluation work on Norilsk type sulfide mineralization.