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1
Egermann, Patrick, Nicole Doerler, Marc Fleury, Joelle Behot, F. Deflandre, and Roland Lenormand. "Petrophysical Measurements From Drill Cuttings: An Added Value for the Reservoir Characterization Process." SPE Reservoir Evaluation & Engineering 9, no. 04 (August 1, 2006): 302–7. http://dx.doi.org/10.2118/88684-pa.
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Summary Permeability and porosity are necessary for reservoir characterization, and cuttings can provide quick information using dedicated measurement techniques. In this paper, we present the first applications of these techniques on real reservoir characterization cases and the comparisons with logs and core data. The method of permeability measurement from cuttings is based on a pressure pulse applied to a cell filled initially with cuttings saturated with viscous fluid in the presence of trapped gas. The permeability is derived from the transient response of the oil invasion into the cuttings by using a numerical approximation of a mathematical model. The porosity of dry drill cuttings is measured using the routine helium technique. These methods were tested and validated by using various samples of crushed rock of known permeability and porosity. Both measurement techniques are fast, require light conditioning, are applicable over a large range of permeability, and need only 1 mL of sieved rock to be carried out. In this paper, we present a field application of an integrated drill cuttings measurement program [permeability, porosity, nuclear magnetic resonance (NMR) T2 distribution] on a carbonate reservoir. Various drilling conditions [including water-based mud (WBM) and oil-based mud (OBM)] and lithologies have been investigated to develop the different techniques that are presented in the paper. The question of whether measurements on cuttings are representative of the native reservoir is of primary importance and was checked by comparing the consistency of the porosity measurements obtained from cuttings with other data (cores or logs). The overall results demonstrate the added value of k and f measurements from cuttings in addition to the data that are commonly collected.
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Adebayo, Abdulrauf R., Lamidi Babalola, Syed R. Hussaini, Abdullah Alqubalee, and Rahul S. Babu. "Insight into the Pore Characteristics of a Saudi Arabian Tight Gas Sand Reservoir." Energies 12, no. 22 (November 12, 2019): 4302. http://dx.doi.org/10.3390/en12224302.
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The petrophysical characterization of tight gas sands can be affected by clay minerals, gas adsorption, microfractures, and the presence of high-density minerals. In this study, we conducted various petrophysical, petrographic, and high-resolution image analyses on Saudi Arabian tight sand in order to understand how a complex pore system responds to measurement tools. About 140 plug samples extracted from six wells were subjected to routine core analyses including cleaning, drying, and porosity–permeability measurements. The porosity–permeability data was used to identify hydraulic flow units (HFU). In order to probe the factors contributing to the heterogeneity of this tight sand, 12 subsamples representing the different HFUs were selected for petrographic study and high-resolution image analysis using SEM, quantitative evaluation of minerals by scanning electron microscope (QEMSCAN), and micro-computed tomography (µCT). Nuclear magnetic resonance (NMR) and electrical resistivity measurements were also conducted on 56 subsamples representing various lithofacies. NMR porosity showed good agreement with other porosity measurements. The agreement was remarkable in specific lithofacies with porosity ranging from 0.1% to 7%. Above this range, significant scatters were seen between the porosity methods. QEMSCAN results revealed that samples with <7% porosity contain a higher proportion of clay than those with porosity >7%, which are either microfractured or contain partially dissolved labile minerals. The NMR T2 profiles also showed that samples with porosity <7% are dominated by micropores while samples with porosity >7% are dominated by macropores. Analysis of the µCT images revealed that pore throat sizes may be responsible for the poor correlation between NMR porosity and other porosity methods. NMR permeability values estimated using the Shlumberger Doll Research (SDR) method are fairly correlated with helium permeability (with an R2 of 0.6). Electrical resistivity measurements showed that the different rock types fall on the same slope of the formation factors versus porosity, with a cementation factor of 1.5.
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Sueyoshi, Kazumasa, Tadashi Yokoyama, and Ikuo Katayama. "Experimental Measurement of the Transport Flow Path Aperture in Thermally Cracked Granite and the Relationship between Pore Structure and Permeability." Geofluids 2020 (November 7, 2020): 1–10. http://dx.doi.org/10.1155/2020/8818293.
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Fluid flow in rocks has a key role in many geological processes, such as in geothermal reservoirs and crustal deformation. Permeability is known to be dependent on porosity and flow path aperture, but direct quantification of pore structures is more difficult than direct estimation of permeability. The gas breakthrough method can be used to determine the radius of transport pores by using the gas pressure at which gas breaks through a water-saturated sample ( Δ P break ). In this study, we applied the gas breakthrough method under confining pressure to damaged granite, in order to evaluate the relationship between permeability and pore characteristics (i.e., porosity and transport flow path aperture) at pressures up to 30 MPa. The transport flow path aperture, permeability, and porosity of thermally cracked granite decrease with increasing confining pressure. We quantified the relationship between permeability and pore characteristics, which provides a better estimation of permeability by taking into account the fraction of hydraulically connected cracks.
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Kudasik, Mateusz. "Investigating Permeability of Coal Samples of Various Porosities under Stress Conditions." Energies 12, no. 4 (February 25, 2019): 762. http://dx.doi.org/10.3390/en12040762.
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Among the numerous factors that have an impact on coal permeability, coal porosity is one of the main parameters. A change in the mechanical stress applied to coal results in a change of porosity. The main objective of the conducted research was to answer the following question: is a decline in coal permeability a direct effect of a decrease in coal porosity, and does mechanical stress result solely in a porosity change? A study of coal porosity under mechanical stress conditions was conducted using a uniquely constructed measurement stand. The coal samples used were briquettes prepared from a granular coal material (middle-rank coal of type B—meta bituminous, upper carboniferous formation) from the “Zofiówka” coal mine, in Poland. In order to describe coal permeability, the Klinkenberg equation was used, as it takes into consideration the slippage effect, typical of porous media characterized by low permeability. On the basis of the obtained results, it was established that the values of the Klinkenberg permeability coefficient decrease as the mechanical stress and the corresponding reduction in porosity become greater. As the briquette porosity increased, the Klinkenberg slippage effect: (i) disappeared in the case of nitrogen, (ii) and was minor for methane. The briquettes used were characterized by various porosities and showed that mechanical stress results mainly in a change in coal porosity, which, in turn, reduces coal permeability.
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Yang, Zehao, and Mingzhe Dong. "A new measurement method for radial permeability and porosity of shale." Petroleum Research 2, no. 2 (June 2017): 178–85. http://dx.doi.org/10.1016/j.ptlrs.2017.07.004.
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Qu, Hai Yang, Zheng Ming Yang, and Ting Hu. "New Method Research of Tight Oil Reservoir Pulse Decay Permeability Measurement." Advanced Materials Research 1010-1012 (August 2014): 1768–71. http://dx.doi.org/10.4028/www.scientific.net/amr.1010-1012.1768.
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The permeability of tight oil reservoir is very low and general perm-plug method always has a big difference. The results can’t reach the test accuracy requirements. This paper measured 26 block rocks of Changqing tight oil reservoir and several typical tight oil reservoirs in CNPC with pulse decay new method. The result shows that the pulse decay permeability measured in the new method and steady-state Klinkenberg-corrected permeability have a good relationship. We drew a figure about the porosity and steady-state Klinkenberg-corrected permeability of these tight oil reservoirs. This research offers a technical support to the tight oil reservoirs about basic data permeability measurement.
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Ji, Xiaofeng, Dangyu Song, Haotian Zhao, Yunbo Li, and Kaikai He. "Experimental Analysis of Pore and Permeability Characteristics of Coal by Low-Field NMR." Applied Sciences 8, no. 8 (August 15, 2018): 1374. http://dx.doi.org/10.3390/app8081374.
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On the basis of the complexity of the pore structure characteristics of a coal reservoir, coal samples with different ranks were selected to study the difference in pore structures and permeability using nuclear magnetic resonance (NMR), scanning electron microscopy (SEM), mercury intrusion porosimetry (MIP), and permeability measurement. Porosity and pore size distribution (PSD) above 20 nm can be analyzed by the improved NMR equation, and the results were basically consistent with that of SEM and MIP. The NMR spectra of the coal samples from the same location were close, but the difference between the coal samples from different locations was quite large, which indicated that the heterogeneity of a coal reservoir was strong. An empirical equation of movable fluid porosity was proposed, which can be used to evaluate the fluid migration characteristics of the coal reservoir, and the porosity of movable fluid mainly came from the contribution of fissures and micro-fissures. The average movable fluid porosity of the coal samples from the Chengzhuang (CZ) coal mine, Wuyang (WY) coal mine, and Yujialiang (YJL) coal mine was 1.37%, 0.67%, and 4.26%, respectively. Although the permeability is related to the NMR porosity and movable fluid porosity, it was difficult to establish a widely used mathematical equation correlating permeability and porosity based on the experimental data.
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Alpak, Faruk O., Carlos Torres-Verdín, and Tarek M. Habashy. "Petrophysical inversion of borehole array-induction logs: Part I — Numerical examples." GEOPHYSICS 71, no. 4 (July 2006): F101—F119. http://dx.doi.org/10.1190/1.2213358.
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We have developed a new methodology for the quantitative petrophysical evaluation of borehole array-induction measurements. The methodology is based on the time evolution of the spatial distributions of fluid saturation and salt concentration attributed to mud-filtrate invasion. We use a rigorous formulation to account for the physics of fluid displacement in porous media resulting from water-base mud filtrate invading hydrocarbon-bearing rock formations. Borehole array-induction measurements are simulated in a coupled mode with the physics of fluid flow. We use inversion to estimate parametric 1D distributions of permeability and porosity that honor the measured array-induction logs. As a byproduct, the inversion yields 2D (axial-symmetric) spatial distributions of aqueous phase saturation, salt concentration, and electrical resistivity. We conduct numerical inversion experiments using noisy synthetic wireline logs. The inversion requires a priori knowledge of several mud, petrophys-ical, and fluid parameters. We perform a systematic study of the accuracy and reliability of the estimated values of porosity and permeability when knowledge of such parameters is uncertain. For the numerical cases considered in this paper, inversion results indicate that borehole electromagnetic-induction logs with multiple radial lengths of investigation (array-induction logs) enable the accurate and reliable estimation of layer-by-layer absolute permeability and porosity. The accuracy of the estimated values of porosity and permeability is higher than 95% in the presence of 5% measurement noise and 10% uncertainty in rock-fluid and mud parameters. However, for cases of deep invasion beyond the radial length of investigation of array-induction logging tools, the estimation of permeability becomes unreliable. We emphasize the importance of a sensitivity study prior to inversion to rule out potential biases in estimating permeability resulting from uncertain knowledge about rock-fluid and mud properties.
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Dong, Chensong. "A Fast Permeability Measurement Method Based on Hybrid Fiber Preforms." Journal of Manufacturing Science and Engineering 127, no. 3 (August 5, 2004): 670–76. http://dx.doi.org/10.1115/1.1954794.
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In this paper, a permeability measurement method using hybrid fiber preforms is presented. The hybrid fiber preform can be composed of different fiber mat types, different numbers of fiber mats of the same type, or both. The computational procedure for permeability based on flow front location and flow time data was derived. This approach was validated by both simulation and experimental studies. The results show that by using this method, permeability values of different fiber mat types or the relationship between permeability and fiber volume fraction (porosity) can be obtained through a single experiment. This permeability measurement method based on hybrid fiber preforms yields compatible measurement accuracies while significantly improving the measurement efficiency. It provides a fast, accurate, and easy-to-use approach for permeability characterization, which is of great significance for the integrated composite product and process development.
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Alnoaimi, K. R., C. Duchateau, and A. R. Kovscek. "Characterization and Measurement of Multiscale Gas Transport in Shale-Core Samples." SPE Journal 21, no. 02 (April 14, 2016): 573–88. http://dx.doi.org/10.2118/2014-1920820-pa.
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Summary This work introduces an experimental technique to probe simultaneously flow and diffusion of gas through shale. A core-scale pressure-pulse-decay experiment is used to study the upstream- and downstream-pressure responses of Eagle Ford and Haynesville shale samples. With the aid of numerical models, the pressure histories obtained from the experiments are matched and gas and rock properties are obtained. The experiments are conducted at varying pore pressure and net effective stress to understand the sensitivity of the rock porosity and permeability as well as the gas diffusivity. A dual-porosity model is constructed to examine gas transport through a system of micropores and microcracks. In this sense, the role of the two different-sized pore systems is deconvolved. In some cases, the micropore system carries roughly one-third of the gas flow. The porosity, permeability, and diffusivity obtained assign physical properties to the macroscales and microscales simultaneously. Results bridge the gap between these scales and improve our understanding of how to assign transport physics to the correct pore scale.
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Dvorkin, Jack, and Ivar Brevik. "Diagnosing high‐porosity sandstones: Strength and permeability from porosity and velocity." GEOPHYSICS 64, no. 3 (May 1999): 795–99. http://dx.doi.org/10.1190/1.1444589.
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Nonuniqueness in relating velocity to porosity in core and well‐log data complicates interpretation of sonic and seismic measurements. One reason for this nonuniqueness in sandstones is clay (e.g., Han, 1986). Another reason is textural variability among samples. Dvorkin and Nur (1996) examine two relatively clay‐free sandstone groups in the same porosity range, but whose velocities significantly differed (Figure 1a). By comparing the data with effective‐medium theories, they interpret this velocity difference as resulting from the difference in the position of diagenetic cement. The explanation is that in the “fast” (Oseberg) rocks (contact) cement is located predominantly at the grain contacts, whereas in the “slow” (Troll) rocks (noncontact) cement is located predominantly away from these contacts.
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Okon, Anietie, and Ukeme Edoho. "Experimental Study of Brine Concentration Effect on Reservoir Porosity and Permeability Measurement." Journal of Scientific Research and Reports 12, no. 2 (January 10, 2016): 1–9. http://dx.doi.org/10.9734/jsrr/2016/28930.
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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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Perraton, Daniel, Alan Carter, Michel Vaillancourt, and Bruno Lavoie. "Perméabilité in situ du béton de peau, établie à partir de la percolation d'un gaz en régime d'écoulement permanent." Canadian Journal of Civil Engineering 29, no. 3 (June 1, 2002): 360–68. http://dx.doi.org/10.1139/l02-009.
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In an attempt to apply the concepts developed by Carman and Klinkenberg for the measurement of permeability of a porous media using a gas, a permeameter for the in-situ measurement of intrinsic permeability of skin concrete has been developed. The established technique allows concentration of gas percolation through a well-defined zone in the superficial layer of concrete. The instrument, the measurement method, and the calculation procedure are described in details in this paper. Several series of tests have been performed in laboratory on concrete blocks (300 × 300 × 400 mm) to simulate measurements on the construction site. Three types of concrete, with different porosity, have been tested. The measurement of permeability performed on the concrete blocks have been accomplished both on shaped surfaces, which are representative of skin concrete, and on sawed surfaces, which are representative of mass concrete. Results show that the relationship between the water/cement ratio and the permeability of skin concrete varies distinctively compared with that of mass concrete. The permeameter allows quantification of what has been for a long time qualified as a determining element in terms of the durability of concrete against the corrosion of reinforcement, that is, the distinct permeability of skin concrete from that of mass concrete.Key words: skin concrete, in-situ permeability, intrinsic permeability, apparent permeability, permeameter, Klinkenberg.[Journal translation]
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Joseph, Jerry, Naga Siva Kumar Gunda, and Sushanta K. Mitra. "On-chip porous media: Porosity and permeability measurements." Chemical Engineering Science 99 (August 2013): 274–83. http://dx.doi.org/10.1016/j.ces.2013.05.065.
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Nababan, Benyamin Elilaski, Eliza Veronica Zanetta, Nahdah Novia, and Handoyo Handoyo. "ESTIMASI NILAI POROSITAS DAN PERMEABILITAS DENGAN PENDEKATAN DIGITAL ROCK PHYSICS (DRP) PADA SAMPEL BATUPASIR FORMASI NGRAYONG, CEKUNGAN JAWA TIMUR BAGIAN UTARA." Jurnal Geofisika Eksplorasi 5, no. 3 (January 17, 2020): 34–44. http://dx.doi.org/10.23960/jge.v5i3.34.
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Reservoir rock permeability and porosity are physical properties of rocks that control reservoir quality. Conventionally, rock porosity and permeability values are obtained from measurements in the laboratory or through well logs. At present, calculation of porosity and permeability can be calculated using digital image processing / Digital Rock Physics (DRP). Core data samples are processed by X-ray diffraction using CT-micro-tomography scan. The result is an image model of the core sample, 2D and 3D images. The combination of theoretical processing and digital images can be obtained from the value of porosity and permeability of rock samples. In this study, we calculated porosity and permeability values using the Digital Rock Physics (DRP) approach in sandstone samples from the Ngrayong Formation, North East Java Basin. The results of the digital image simulation and processing on the Ngrayong Formation sandstone samples ranged in value from 33.50% and permeability around 1267.02 mDarcy.
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Alabeed, Adel, Zeyad Ibrahim, and Emhemed Alfandi. "DETERMINATION CONVENTIONAL ROCK PROPERTIES FROM LOG DATA & CORE DATA FOR UPPER NUBIAN SANDSTONE FORMATION OF ABU ATTIFEL FIELD." Scientific Journal of Applied Sciences of Sabratha University 2, no. 1 (April 25, 2019): 29–37. http://dx.doi.org/10.47891/sabujas.v2i1.29-37.
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A reservoir is a subsurface rock that has effective porosity and permeability which usually contains commercially exploitable quantity of hydrocarbon. Reservoir characterization is undertaken to determine its capability to both store and transmit fluid. Petrophysical well log and core data, in this paper, were integrated in an analysis of the reservoir characteristics by selecting of three productive wells. The selected wells are located at Abu Attifel field in Libya for Upper Nubian Sandstone formation at depth varied form 12921 to14330 ft. The main aim of this study is to compare the laboratory measurement of core data with that obtained from well log data in order to determine reservoir properties such as shale volume, porosity (Φ), permeability (K), fluid saturation, net pay thickness. The plots of porosity logs and core porosity versus depth for the three wells revealed significant similarity in the porosity values. The average volume of shale for the reservoir was determined to be 22.5%, and average permeability values of the three wells are above 150 md, while porosity values ranged from 9 to 11%. Low water saturation 13 to 22% in the three wells indicates the wettability of the reservoir is water-wet.
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Santos, J. M. M., and I. Y. Y. Akkutlu. "Laboratory Measurement of Sorption Isotherm Under Confining Stress With Pore-Volume Effects." SPE Journal 18, no. 05 (August 18, 2013): 924–31. http://dx.doi.org/10.2118/162595-pa.
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Summary For unconventional gas resources such as coal and organic-rich shale, sorbed phase is an important component of storage and transport calculations. Routine measurements of sorption are, however, performed separately from the porosity and permeability measurements. In this work, a new gas-storage measurement technique is proposed that combines the porosity and sorption measurements. Because the measurement is performed by use of core plugs under confining stress, it allows investigating the storage capacity for varying effective stress and incorporating the storage data into a subsequent permeability measurement under the same conditions. During the construction of the sorption isotherm in the laboratory with the volumetric (gas expansion) method, at each pressure step, the sorbed gas taken up by the sample reduces the pore volume (PV) of the sample. As a result, the initially determined PV at low pressure must be corrected at the beginning and at the end of the pressure step. This correction can be performed relatively easily during the routine sorption measurements with the crushed samples; however, it is a challenging task with core plugs under confining stress because at each pressure step the PV could also change as a result of pore compressibility. Our approach is based on a new analytical model of total gas storability developed to interpret the measured multiple-step pressure data on a graphical domain in which the storage-parameter estimation can be performed fast and accurately with a straight line. The approach considers both the compressibility and the sorbed-phase effects on the porosity and the sorption parameters. Experimental storage data of shale and coal samples with varying total organic content (TOC) and maturity are used to demonstrate the applicability of the analytical method to the measurements. The results show that the sorption measurements can be performed with increased accuracy and relatively fast. The work is important for organic-rich sample characterization in the laboratory, and for gas-in-place and transport calculations.
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Altawati, Faisal, Hossein Emadi, and Rayan Khalil. "An experimental study to investigate the physical and dynamic elastic properties of Eagle Ford shale rock samples." Journal of Petroleum Exploration and Production Technology 11, no. 9 (July 26, 2021): 3389–408. http://dx.doi.org/10.1007/s13202-021-01243-w.
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AbstractUnconventional resources, such as Eagle Ford formation, are commonly classified for their ultra-low permeability, where pore sizes are in nano-scale and pore-conductivity is low, causing several challenges in evaluating unconventional-rock properties. Several experimental parameters (e.g., diffusion time of gas, gas injection pressure, method of permeability measurement, and confining pressure cycling) must be considered when evaluating the ultra-low permeability rock's physical and dynamic elastic properties measurements, where erroneous evaluations could be avoided. Characterizing ultra-low permeability samples' physical and elastic properties helps researchers obtain more reliable information leading to successful evaluations. In this study, 24 Eagle Ford core samples' physical and dynamic elastic properties were evaluated. Utilizing longer diffusion time and higher helium injection pressure, applying complex transient method, and cycling confining pressure were considered for porosity, permeability, and velocities measurements. Computerized tomography (CT) scan, porosity, permeability, and ultrasonic wave velocities were conducted on the core samples. Additionally, X-ray Diffraction (XRD) analysis was conducted to determine the mineralogical compositions. Porosity was measured at 2.07 MPa injection pressure for 24 h, and the permeability was measured using a complex transient method. P- and S-wave velocities were measured at two cycles of five confining pressures (up to 68.95 MPa). The XRD analysis results showed that the tested core samples had an average of 81.44% and 11.68% calcite and quartz, respectively, with a minor amount of clay minerals. The high content of calcite and quartz in shale yields higher velocities, higher Young's modulus, and lower Poisson's ratio, which enhances the brittleness that is an important parameter for well stimulation design (e.g., hydraulic fracturing). The results of porosity and permeability showed that porosity and permeability vary between 5.3–9.79% and 0.006–12 µD, respectively. The Permeability–porosity relation of samples shows a very weak correlation. P- and S-wave velocities results display a range of velocity up to 6206 m/s and 3285 m/s at 68.95 MPa confining pressure, respectively. Additionally, S-wave velocity is approximately 55% of P-wave velocity. A correlation between both velocities is established at each confining pressure, indicating a strong correlation. Results illustrated that applying two cycles of confining pressure impacts both velocities and dynamic elastic moduli. Ramping up the confining pressure increases both velocities owing to compaction of the samples and, in turn, increases dynamic Young's modulus and Poisson's ratio while decreasing bulk compressibility. Moreover, the results demonstrated that the above-mentioned parameters' values (after decreasing the confining pressure to 13.79 MPa) differ from the initial values due to the hysteresis loop, where the loop is slightly opened, indicating that the alteration is non-elastic. The findings of this study provide detailed information about the rock physical and dynamic elastic properties of one of the largest unconventional resources in the U.S.A, the Eagle Ford formation, where direct measurements may not be cost-effective or feasible.
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Salih, Moaz, John J. G. Reijmer, Ammar El Husseiny, Mazin Bashri, Hassan Eltom, Hani Al Mukainah, and Michael A. Kaminski. "Controlling Factors on Petrophysical and Acoustic Properties of Bioturbated Carbonates: (Upper Jurassic, Central Saudi Arabia)." Applied Sciences 11, no. 11 (May 28, 2021): 5019. http://dx.doi.org/10.3390/app11115019.
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Many of the world’s productive Jurassic reservoirs are intensively bioturbated, including the sediments of the Upper Jurassic Hanifa Formation. Hydrocarbon exploration and production from such reservoirs require a reliable prediction of petrophysical properties (i.e., porosity, permeability, acoustic velocity) by linking and assessment of ichnofabrics and trace fossils and determining their impact on reservoir quality. In this study, we utilized outcrop carbonate samples from the Hanifa Formation to understand the main controlling factors on reservoir quality (porosity and permeability) and acoustic velocity of bioturbated carbonates, by using thin-section petrography, SEM, XRD, CT scan, porosity, permeability, and acoustic velocity measurement. The studied samples are dominated by Thalassinoides burrows that have burrow intensity ranging from ~4% to 27%, with porosity and permeability values ranging from ~1% to 20%, and from 0.002 mD up to 1.9 mD, respectively. Samples with coarse grain-filled burrows have higher porosity (average µ = 14.44% ± 3.25%) and permeability (µ = 0.56 mD ± 0.55) than samples with fine grain-filled burrows (µ = 6.56% ± 3.96%, and 0.07 mD ± 0.16 mD). The acoustic velocity is controlled by an interplay of porosity, bioturbation, and mineralogy. Samples with relatively high porosity and permeability values (>10% and >0.1 mD) have lower velocities (<5 km/s) compared to tight samples with low porosities and permeabilities (<10% and <0.1 mD). The mineralogy of the analyzed samples is dominated by calcite (~94% of total samples) with some quartz content (~6% of total samples). Samples characterized with higher quartz (>10% quartz content) show lower velocities compared to the samples with lower quartz content. Bioturbation intensity, alone, has no control on velocity, but when combined with burrow fill, it can be easier to discriminate between high and low velocity samples. Fine grain-filled burrows have generally lower porosity and higher velocities (µ = 5.46 km/s) compared to coarse grain-filled burrows (µ = 4.52 km/s). Understanding the main controlling factor on petrophysical properties and acoustic velocity of bioturbated strata can enhance our competency in reservoir quality prediction and modeling for these bioturbated units.
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Miller, Kevin, Tiziana Vanorio, Sam Yang, and Xianghui Xiao. "A scale-consistent method for imaging porosity and micrite in dual-porosity carbonate rocks." GEOPHYSICS 84, no. 3 (May 1, 2019): MR115—MR127. http://dx.doi.org/10.1190/geo2017-0812.1.
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Unlike many other clastic rocks, relating velocity and permeability to porosity for micrite-bearing carbonate rocks has been largely unsuccessful. Recent studies have shown that additional parameters, most notably the distribution and/or proportion of micrite, can be used to parameterize the velocity and permeability behavior. However, there is currently no scale-consistent, 3D methodology for differentiating macroporosity and microporosity from the total porosity measured on bench-top laboratory equipment. Previous studies estimated microporosity and micrite content by combining total porosity measurements conducted on whole 50 mm cores with measurements of phase volumes on 1 mm digital rocks (i.e., scale-inconsistent). As a step forward from those, we imaged dual-porosity carbonate rocks using X-ray microcomputed tomography and then leveraged a recently developed, optimization-based technique, called data-constrained modeling, to map the macroporosity and microporosity distribution of our samples. We evaluate the volumetric proportions of macropores, micropores, and coarse-grained calcite as a function of micrite content — with their respective uncertainties — all measured on the same digital rock and with the same method. Finally, we determine how measurements of the volumetric phase proportions could be extended using standard effective medium models to predict reservoir physical properties. The sensitivity of these models to the proportion of micrite and microporosity within the micrite is evidence that the nonuniqueness among permeability, velocity, and porosity that is commonly observed of micrite-bearing carbonate rocks can be explained by a variation of micrite content and microporosity at a similar porosity.
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Yang, Jin, Jian Jiang, Ying Su, Xingyang He, Yingbin Wang, Shun Chen, Hongbo Tan, and Sang-Keun Oh. "Fluid Permeability of Ground Steel Slag-Blended Composites Evaluated by Pore Structure." Advances in Materials Science and Engineering 2020 (February 10, 2020): 1–14. http://dx.doi.org/10.1155/2020/6254835.
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The resource utilization of steel slag has attracted wide attention. In the present work, the pore structure of cement paste with and without ground basic oxygen furnace slag (BOFS) up to 180 days was investigated by mercury intrusion porosimetry. Permeability was evaluated from the tested pore structure. Results indicate that the porosity, critical pore radius, pore-throat radius, and permeability are increased with the BOFS content and levels off after 28 days. Lower gel porosity and higher coarse capillary porosity were observed in BOFS-blended composites. The calculated permeability (around 0.30–7.49 × 10−19 m2) based on the pore structure agrees well with the range of reported experimental measurements. Well-correlated linear and power-law relationship was noticed between permeability and porosity and characteristic pore radius, respectively.
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Oyewole, Emmanuel, Mehrnoosh Saneifar, and Zoya Heidari. "Multiscale characterization of pore structure in carbonate formations: Application to the Scurry Area Canyon Reef Operators Committee Unit." Interpretation 4, no. 2 (May 1, 2016): SF165—SF177. http://dx.doi.org/10.1190/int-2015-0123.1.
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Carbonate formations consist of a wide range of pore types with different shapes, pore-throat sizes, and varying levels of pore-network connectivity. Such heterogeneous pore-network properties affect the fluid flow in the formation. However, characterizing pore-network properties (e.g., effective porosity and permeability) in carbonate formations is challenging due to the heterogeneity at different scales and complex pore structure of carbonate rocks. We have developed an integrated technique for multiscale characterization of carbonate pore structure based on mercury injection capillary pressure (MICP) measurements, X-ray micro-computed tomography (micro-CT) 3D rock images, and well logs. We have determined pore types based on the pore-throat radius distributions obtained from MICP measurements. We developed a new method for improved assessment of effective porosity and permeability in the well-log domain using pore-scale numerical simulations of fluid flow and electric current flow in 3D micro-CT core images obtained in each pore type. Finally, we conducted petrophysical rock classification based on the depth-by-depth estimates of effective porosity, permeability, volumetric concentrations of minerals, and pore types using an unsupervised artificial neural network. We have successfully applied the proposed technique to three wells in the Scurry Area Canyon Reef Operators Committee (SACROC ) Unit. Our results find that electrical resistivity measurements can be used for reliable characterization of pore structure and assessment of effective porosity and permeability in carbonate formations. The estimates of permeability in the well-log domain were cross-validated using the available core measurements. We have observed a 34% improvement in relative errors in well-log-based estimates of permeability, as compared with the core-based porosity-permeability models.
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Krogulec, Ewa, Katarzyna Sawicka, Sebastian Zabłocki, and Ewa Falkowska. "Mineralogy and Permeability of Gas and Oil Dolomite Reservoirs of the Zechstein Main Dolomite Basin in the Lubiatów Deposit (Poland)." Energies 13, no. 23 (December 5, 2020): 6436. http://dx.doi.org/10.3390/en13236436.
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Permeability characterizes the ability of rocks to store and transport natural gas, crude oil and reservoir fluids. Permeability heterogeneity of reservoir rocks, including dolomites, results from overlapping geological and physicochemical processes. The permeability study of gas-bearing dolomites was carried out on the Lubiatów hydrocarbon deposit (Poland), located at the Ca2 carbonate platform toe-of-slope, which is a prospective area for hydrocarbon exploration in Europe. Due to the complicated rock textures and overlapping alteration processes, including secondary crystallization or dissolution of minerals, the permeability of the deposit is variable. Studies of dolomites from a depth of 3242–3380 m show high mineralogical diversity; the percentage of dolomite ranges from 79% to 95% with a variable content of other minerals: anhydrite, gypsum, quartz, fluorite, plagioclase and clay minerals. The porosity variability ranges from 4.69% to 31.21%, depending on the measurement method used. The mean permeability value is 35.27 mD, with a variation range of 0.9 to 135.6 mD. There is neither change in permeability with depth and mineral composition, nor a direct relationship between porosity and permeability.
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Kakarash, Tariq, and Qays M. Sadeq. "Development Permeability prediction for Bai Hassan Cretaceous Carbonate Reservoir." UHD Journal of Science and Technology 2, no. 1 (May 25, 2018): 8. http://dx.doi.org/10.21928/uhdjst.v2n1y2018.pp8-18.
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Permeability and porosity are the most difficult parameters to estimate in the oil reservoir because they are varying significantly over the reservoir, especially in the carbonate formation. Porosity and permeability can only be sampled at the well location. However, porosity is easy to estimate directly from well log data, permeability is not. In addition, permeability measurements from core samples are very expensive. Carbonate reservoirs are very difficult to characterize because of their tendency to be tight and heterogeneous due to deposition and diagenetic processes. Therefore, many engineers and geologists try to establish methods to get the best characterization for the carbonate reservoir. In this study, available routine core data from three wells are used to develop permeability model based on hydraulic flow unit method (HFUM) (RQI/FZI) for cretaceous carbonate middle reservoirs of Bai Hassan oil field. The results show that the HFUM is work perfectly to characterize and predict permeability for uncored wells because R2 ≥ 0.9. It is indicating that permeability can be accurately predicted from porosity if rock type is known.
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Kraishan, G. M., and K. Liu. "PERMEABILITY AND POROSITY DISTRIBUTION PATTERNS IN A SHOREFACE RESERVOIR: LOWER CRETACEOUS FLACOURT FORMATION, BARROW SUB-BASIN, NORTH WEST SHELF, WESTERN AUSTRALIA." APPEA Journal 38, no. 1 (1998): 745. http://dx.doi.org/10.1071/aj97049.
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Porosity and permeability measurements on 926 core plugs were taken from 18 exploration, wildcat and producing wells from the Lower Cretaceous Flacourt Formation, Barrow Sub-basin and analysed for their spatial and temporal variability using both sedimentological and geostatistical methods.The porosity and permeability distribution shows a strong relationship to depositional facies and diagenetic modification. The samples are variably cemented with porosity ranging from 1.3 to 39.4 per cent and permeability from less than 0.01 to 24,400 md. Both porosity and permeability exhibit strong heterogeneity as a result of change of the depositional facies within the same well and the amount of detrital matrix within each facies.The degree of spatial and temporal variability observed in both porosity and permeability data is well reflected by the Levy-stable statistical analysis and variogram modelling. The heterogeneity is shown to be strongly controlled by texture, composition and sedimentary structures of the specific sedimentary facies. The heterogeneity of both permeability and porosity for each individual facies was characterised by the correlation length in the vertical direction from both the variogram and Levy C-gram analyses, and Levy index parameter.The sands of the Flacourt Formation, which form the principal reservoirs in the Barrow Sub-basin, were deposited in a paralic environment. Five major facies were recognised including a tidal channel, an upper shoreface, a middle shoreface, a lower shoreface and a background facies.Sedimentological and statistical analysis of the porosity and permeability of the Flacourt Formation shoreface sandstones enabled us to better understand the heterogenity of the petrophysical properties. The finding can be used to understand similar heterogeneous reservoirs elsewhere, and will provide a basis for reservoir simulations. We have shown that the approach of using genetically related sedimentary facies, can significantly improve the predicability of the porosity and permeability distribution.
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Callow, Ben, Ismael Falcon-Suarez, Hector Marin-Moreno, Jonathan M. Bull, and Sharif Ahmed. "Optimal X-ray micro-CT image based methods for porosity and permeability quantification in heterogeneous sandstones." Geophysical Journal International 223, no. 2 (June 27, 2020): 1210–29. http://dx.doi.org/10.1093/gji/ggaa321.
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Summary 3-D X-ray micro-CT (XCT) is a non-destructive 3-D imaging method, increasingly used for a wide range of applications in Earth Science. An optimal XCT image-processing workflow is derived here for accurate quantification of porosity and absolute permeability of heterogeneous sandstone samples using an assessment of key image acquisition and processing parameters: image resolution, segmentation method, representative elementary volume (REV) size and fluid-simulation method. XCT image-based calculations obtained for heterogeneous sandstones are compared to two homogeneous standards (Berea sandstone and a sphere pack), as well as to the results from physical laboratory measurements. An optimal XCT methodology obtains porosity and permeability results within ±2 per cent and vary by one order of magnitude around the direct physical measurements, respectively, achieved by incorporating the clay fraction and cement matrix (porous, impermeable components) to the pore-phase for porosity calculations and into the solid-phase for permeability calculations. Two stokes-flow finite element modelling (FEM) simulation methods, using a voxelized grid (Avizo) and tetrahedral mesh (Comsol) produce comparable results, and similarly show that a lower resolution scan (∼5 µm) is unable to resolve the smallest intergranular pores, causing an underestimation of porosity by ∼3.5 per cent. Downsampling the image-resolution post-segmentation (numerical coarsening) and pore network modelling both allow achieving of a REV size, whilst significantly reducing fluid simulation memory requirements. For the heterogeneous sandstones, REV size for permeability (≥1 mm3) is larger than for porosity (≥0.5 mm3) due to tortuosity of the fluid paths. This highlights that porosity should not be used as a reference REV for permeability calculations. The findings suggest that distinct image processing workflows for porosity and permeability would significantly enhance the accurate quantification of the two properties from XCT.
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Heap, Michael J. "The influence of sample geometry on the permeability of a porous sandstone." Geoscientific Instrumentation, Methods and Data Systems 8, no. 1 (February 8, 2019): 55–61. http://dx.doi.org/10.5194/gi-8-55-2019.
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Abstract. Although detailed guidelines exist for measuring the physical and mechanical properties of laboratory rock samples, guidelines for laboratory measurements of permeability are sparse. Provided herein are gas permeability measurements of cylindrical samples of Darley Dale sandstone (with a connected porosity of 0.135 and a pore and grain size of 0.2–0.3 mm) with different diameters (10, 20, and 25 mm) and lengths (from 60 to 10 mm), corresponding to aspect (length ∕ diameter) ratios between 6.2 and 0.4. These data show that, despite the large range in sample length, aspect ratio, and bulk volume (from 29.7 to 1.9 cm3), the permeabilities of the Darley Dale sandstone samples are near identical (3–4×10-15 m2). The near-identical permeability of these samples is considered the consequence of the homogeneous porosity structure typical of porous sandstones and the small grain and pore size of Darley Dale sandstone with respect to the minimum tested diameter and length (both 10 mm). Laboratory permeability measurements on rock samples with inhomogeneous porosity structures or with larger grain and pore sizes may still provide erroneous values if their length, diameter, and/or aspect ratio is low. Permeability measurements on rocks with vastly different microstructural properties should now be conducted in a similar manner to help develop detailed guidelines for laboratory measurements of permeability.
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Prasad, Manika. "Velocity‐permeability relations within hydraulic units." GEOPHYSICS 68, no. 1 (January 2003): 108–17. http://dx.doi.org/10.1190/1.1543198.
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Relationships between seismic velocity and permeability have been difficult to establish. I show that by grouping and sorting rocks into hydraulic units, we can establish relationships between velocity and permeability. The hydraulic units are calculated from measured porosity and permeability values. Correlation between velocity and permeability is significant within each hydraulic unit (the correlation coefficient, R2, lies in the range 0.65–0.87). This correlation is an extension of the match between porosity and permeability within a hydraulic unit. I show how the compaction and cementation history of a sediment can have effects on its physical properties such as porosity and permeability and on its seismic properties. The measured velocity data are further approximated with the Biot model. The velocity‐permeability relation and modeling results are demonstrated for a large data set of laboratory measurements. The good match between calculated and measured data demonstrates that this relation can be used to predict permeability from velocity in well logs by zoning the data from training wells into hydraulic units. One possible application is shown where, by using site‐specific data, the velocity‐permeability relation is vastly improved with a correlation coefficient R2 of 0.9.
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Boaca, Tudor, and Ion Malureanu. "Determination of oil reservoir permeability and porosity from resistivity measurement using an analytical model." Journal of Petroleum Science and Engineering 157 (August 2017): 884–93. http://dx.doi.org/10.1016/j.petrol.2017.07.077.
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Pang, Y., M. Y. Soliman, H. Deng, and Hossein Emadi. "Analysis of Effective Porosity and Effective Permeability in Shale-Gas Reservoirs With Consideration of Gas Adsorption and Stress Effects." SPE Journal 22, no. 06 (July 14, 2017): 1739–59. http://dx.doi.org/10.2118/180260-pa.
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Summary Nanoscale porosity and permeability play important roles in the characterization of shale-gas reservoirs and predicting shale-gas-production behavior. The gas adsorption and stress effects are two crucial parameters that should be considered in shale rocks. Although stress-dependent porosity and permeability models have been introduced and applied to calculate effective porosity and permeability, the adsorption effect specified as pore volume (PV) occupied by adsorbate is not properly accounted. Generally, gas adsorption results in significant reduction of nanoscale porosity and permeability in shale-gas reservoirs because the PV is occupied by layers of adsorbed-gas molecules. In this paper, correlations of effective porosity and permeability with the consideration of combining effects of gas adsorption and stress are developed for shale. For the adsorption effect, methane-adsorption capacity of shale rocks is measured on five shale-core samples in the laboratory by use of the gravimetric method. Methane-adsorption capacity is evaluated through performing regression analysis on Gibbs adsorption data from experimental measurements by use of the modified Dubinin-Astakhov (D-A) equation (Sakurovs et al. 2007) under the supercritical condition, from which the density of adsorbate is found. In addition, the Gibbs adsorption data are converted to absolute adsorption data to determine the volume of adsorbate. Furthermore, the stress-dependent porosity and permeability are calculated by use of McKee correlations (McKee et al. 1988) with the experimentally measured constant pore compressibility by use of the nonadsorptive-gas-expansion method. The developed correlations illustrating the changes in porosity and permeability with pore pressure in shale are similar to those produced by the Shi and Durucan model (2005), which represents the decline of porosity and permeability with the increase of pore pressure in the coalbed. The tendency of porosity and permeability change is the inverse of the common stress-dependent regulation that porosity and permeability increase with the increase of pore pressure. Here, the gas-adsorption effect has a larger influence on PV than stress effect does, which is because more gas is attempting to adsorb on the surface of the matrix as pore pressure increases. Furthermore, the developed correlations are added into a numerical-simulation model at field scale, which successfully matches production data from a horizontal well with multistage hydraulic fractures in the Barnett Shale reservoir. The simulation results note that without considering the effect of PV occupied by adsorbed gas, characterization of reservoir properties and prediction of gas production by history matching cannot be performed reliably. The purpose of this study is to introduce a model to calculate the volume of the adsorbed phase through the adsorption isotherm and propose correlations of effective porosity and permeability in shale rocks, including the consideration of the effects of both gas adsorption and stress. In addition, practical application of the developed correlations to reservoir-simulation work might achieve an appropriate evaluation of effective porosity and permeability and provide an accurate estimation of gas production in shale-gas reservoirs.
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Kim, Sung H., Jae W. Jung, Mei X. Li, Sung W. Choi, Woo I. Lee, and Chung H. Park. "Unsaturated flow behavior in double-scale porous reinforcement for liquid composite molding processes." Journal of Reinforced Plastics and Composites 36, no. 2 (October 1, 2016): 85–97. http://dx.doi.org/10.1177/0731684416671422.
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We investigate the unsaturated resin flow behavior in a dual scale porosity preform by observing the pressure distribution and the void content. The experimental data show that the pressure profile in the unsaturated flow is nonlinear with positive curvature whereas that in the saturated flow is linear as expected from the classical Darcy’s law. To address this issue, the governing equation for mass conservation is modified by introducing a mass sink term. Eventually, it has been found that the discrepancy between the unsaturated and saturated permeability values comes from a misinterpretation of the pressure gradient at the flow front in the unsaturated permeability measurement method and the permeability for a given preform is a unique value regardless of measurement method or flow condition. Based on this investigation, the ratio of unsaturated permeability to saturated permeability is represented as a dimensionless number in terms of void content.
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Kendrick, Jackie E., Lauren N. Schaefer, Jenny Schauroth, Andrew F. Bell, Oliver D. Lamb, Anthony Lamur, Takahiro Miwa, Rebecca Coats, Yan Lavallée, and Ben M. Kennedy. "Physical and mechanical rock properties of a heterogeneous volcano: the case of Mount Unzen, Japan." Solid Earth 12, no. 3 (March 16, 2021): 633–64. http://dx.doi.org/10.5194/se-12-633-2021.
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Abstract. Volcanoes represent one of the most critical geological settings for hazard modelling due to their propensity to both unpredictably erupt and collapse, even in times of quiescence. Volcanoes are heterogeneous at multiple scales, from porosity, which is variably distributed and frequently anisotropic, to strata, which are laterally discontinuous and commonly pierced by fractures and faults. Due to variable and, at times, intense stress and strain conditions during and following emplacement, volcanic rocks span an exceptionally wide range of physical and mechanical properties. Understanding the constituent materials' attributes is key to improving the interpretation of the hazards posed by the diverse array of volcanic complexes. Here, we examine the spectrum of physical and mechanical properties presented by a single dome-forming eruption at a dacitic volcano, Mount Unzen (Japan), by testing a number of isotropic and anisotropic lavas in tension and compression with acoustic emission (AE) monitoring. The lava dome erupted as a series of 13 lobes between 1991 and 1995, and its ongoing instability means that much of the volcano and its surroundings remain within an exclusion zone today. During a field campaign in 2015, we selected four representative blocks as the focus of this study. The core samples from each block span a range in total porosity from 9.14 % to 42.81 % and a range in permeability from 1.65×10-15 to 1.88×10-9 m2 (from 1065 measurements). For a given porosity, sample permeability varies by >2 orders of magnitude and is typically lower for macroscopically anisotropic samples than for isotropic samples of similar porosity. An additional 379 permeability measurements on planar surfaces of both an isotropic and anisotropic sample block showed consistent minimum, maximum, and average permeabilities, and comparable standard deviations to measurements on core and disc samples; this indicated a negligible impact of sample size on recorded permeability across the range of sample sizes and absolute permeabilities tested. Permeability measured under confined conditions showed that the lowest permeability samples, whose porosity largely comprises microfractures, are most sensitive to effective pressure and that anisotropy of permeability is enhanced by confinement. The permeability measurements highlight the importance of the measurement approach, scale, and confinement conditions in the description of permeability. The uniaxial compressive strength (UCS) ranges from 13.48 to 47.80 MPa, and tensile strength (UTS) using the Brazilian disc method ranges from 1.30 to 3.70 MPa, with crack-dominated lavas being weaker than vesicle-dominated materials of equivalent porosity. UCS is lower in saturated conditions, whereas the impact of saturation on UTS is variable. UCS is between 6.8 and 17.3 times higher than UTS, with anisotropic samples forming each endmember. The Young's modulus of dry samples ranges from 4.49 to 21.59 GPa and is systematically reduced in water-saturated tests. The interrelation of porosity, UCS, UTS, and Young's modulus was modelled with good replication of the data, and empirical relationships are provided. Acceleration of monitored acoustic emission (AE) rates during deformation was assessed by fitting Poisson point process models in a Bayesian framework. An exponential acceleration model closely replicated the tensile strength tests, whilst compressive tests tended to have relatively high early rates of AEs, suggesting failure forecast may be more accurate in tensile regimes, though with shorter warning times. The Gutenberg–Richter b value has a negative correlation with connected porosity for both UCS and UTS tests which we attribute to different stress intensities caused by differing pore networks. The b value is higher for UTS than UCS, and it typically decreases (positive Δb) during tests, with the exception of cataclastic samples in compression. Δb correlates positively with connected porosity in compression and correlates negatively in tension. Δb using a fixed sampling length may be a more useful metric for monitoring changes in activity at volcanoes than the b value with an arbitrary starting point. Using coda wave interferometry (CWI), we identify velocity reductions during mechanical testing in compression and tension, the magnitude of which is greater in more porous samples in UTS but independent of porosity in UCS and which scales to both b value and Δb. Yet, saturation obscures velocity changes caused by evolving material properties, which could mask damage accrual or source migration in water-rich seismogenic environments such as volcanoes. The results of this study highlight that heterogeneity and anisotropy within a single system not only add variability but also have a defining role in the channelling of fluid flow and localisation of strain that dictate a volcano's hazards and the geophysical indicators we use to interpret them.
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Doder, Djordjije, Biljana Miljkovic, Borivoj Stepanov, and Ivan Pesenjanski. "Adapting the Forchheimer equation for the flow of air through wheat straw beds." Thermal Science 20, suppl. 2 (2016): 463–70. http://dx.doi.org/10.2298/tsci151005030d.
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The paper presents the results of an experimental investigation of air pressure drop while flowing through wheat straw beds. According to Darcy?s law, the smaller the porosity of the bed is, the bigger the pressure drop will be. The investigation was conducted using three different porosities (or three bed densities), and for two different air flow rates. After determining porosity (which is directly measurable), the permeability of straw could be found. For high flow velocities, such as the velocity of air flowing through a straw bale, the Forchheimer equation becomes more relevant as a correction of Darcy?s law with inertial effects included. Otherwise, the permeability tensor depends only on the geometry of the porous medium. With permeability known, the Forchheimer equation coefficients can be easily estimated. These results may be important for the future development of efficient biomass combustion facilities. The measurement methods and facility characteristics are described in more detail.
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Haleem, Noman, Sayed Ibrahim, Tanveer Hussain, Abdul Jabbar, Mumtaz Hassan Malik, and Zulfiqar Ali Malik. "Determining the Light Transmission of Woven Fabrics through Different Measurement Methods and Its Correlation with Air Permeability." Journal of Engineered Fibers and Fabrics 9, no. 4 (December 2014): 155892501400900. http://dx.doi.org/10.1177/155892501400900409.
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The study aims to present a relationship between air permeability of woven fabrics and their light transmission properties. Polyester / cotton (48:52) blended woven fabrics were utilized in the study. Air permeability is measured using the standard test method already established while the light transmission through the fabric is measured by means of two different methods. One method is based on measurement of light transmitted from a back lit fabric by means of a light sensor. The second method is based on image processing techniques which require a digital back lit image of fabric and an algorithm is applied to measure the amount of light transmitted through it. Results from both methods are compared and correlated with the air permeability and porosity of woven fabrics. Analysis shows that the results from former method have a stronger and more significant relationship with air permeability of woven fabrics comparatively.
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Gravestock, D. I., and E. M. Alexander. "POROSITY AND PERMEABILITY OF RESERVOIRS AND CAPROCKS IN THE EROMANGA BASIN, SOUTH AUSTRALIA." APPEA Journal 26, no. 1 (1986): 202. http://dx.doi.org/10.1071/aj85020.
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When effective porosity and permeability are measured at simulated overburden pressure, and grain size variation is taken into account, two distinct relationships are evident for Eromanga Basin reservoirs. Reservoirs in the Hutton Sandstone and Namur Sandstone Member behave such that significant porosity reduction can be sustained with retention of high permeability, whereas permeability of reservoirs in the Birkhead Formation and Murta Member is critically dependent on slight porosity variations. Logging tool responses are compared with core-derived data to show in particular the effects of grain size and clay content on the gamma ray, sonic, and density tools, where clay content is assessed from cation exchange capacity measurements. Sonic and density crossplots, constructed to provide comparison with a water-saturated 'reference' reservoir, are advantageous in comparing measured effective porosity from core plugs at overburden pressure with porosity calculated from logs. Gamma ray and sonic log responses of the Murta Member in the Murteree Horst area are clearly distinct from those of all other reservoirs, perhaps partly due to differences in mineralogy and shallower depth of burial compared with other formations.
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Al-Beyati, Fawzi. "Porosity and Permeability Measurements Integration of The Upper Cretaceous in Balad Field, Central Iraq." Iraqi Geological Journal 54, no. 1B (February 28, 2021): 24–42. http://dx.doi.org/10.46717/igj.54.1b.3ms-2021-02-21.
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The corrected porosity image analysis and log data can be used to build 3D models for porosity and permeability. This can be much realistic porosity obtainable because the core test data is not always available due to high cost which is a challenge for petroleum companies and petrophysists. Thus, this method can be used as an advantage of thin section studies and for opening horizon for more studies in the future to obtain reservoir properties. Seventy-two core samples were selected and the same numbers of thin sections were made from Khasib, Sa`di, and Hartha, formations from Ba-1, Ba-4, and Ba-8 wells, Balad Oilfield in Central Iraq to make a comprehensive view of using porosity image analysis software to determine the porosity. The petrophysical description including porosity image analysis was utilized and both laboratory core test analysis and well log analysis were used to correct and calibrate the results. The main reservoir properties including porosity and permeability were measured based on core samples laboratory analysis. The results of porosity obtained from well log analysis and porosity image analysis method are corrected by using SPSS software; the results revealed good correlation coefficients between 0.684 and 0.872. The porosity range values are 9-16% and 9-27% for Khasib and Sa’di in Ba-1 Well, respectively; 10-21%, 9-25%, and 16-27% for Khasib, Sa’di and Hartha in Ba-4 Well, respectively; and 11-24% and 15-24% for Khasib and Hartha in Ba-8 Well, respectively according to petrographic image analysis. By using the laboratory core analysis, the porosity range values are 12-26% and 17-24% for Khasib and Sa’di in Ba-1 Well, respectively; 6-28% and 14-27% for Sa’di and Hartha in Ba-4 Well, respectively; and 17-19% and 15-24% for Sa’di and Hartha in Ba-8 Well, respectively. Finally, the well log analysis showed that the porosity range values are 11-16% and 7-27% for Khasib and Sa’di in Ba-1 Well, respectively; 4-18%, 21-26%, and 16-19% for Khasib, Sa’di and Hartha in Ba-4 Well, respectively; and 9-24% and 15-23% for Khasib and Hartha in Ba-8 Well, respectively. The permeability range values based on laboratory core analysis are 1.51-8.97 md and 0.29-2.77 md for Khasib and Sa’di in Ba-1 Well, respectively; 0.01-24.5 md and 0.28-6.47 md for Sa’di and Hartha in Ba-4 Well, respectively; and 0.86-2.25 md and 0.23-3.66 for Sa’di and Hartha in Ba-8 Well, respectively.
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Yuan, Yujie, and Reza Rezaee. "Comparative Porosity and Pore Structure Assessment in Shales: Measurement Techniques, Influencing Factors and Implications for Reservoir Characterization." Energies 12, no. 11 (May 31, 2019): 2094. http://dx.doi.org/10.3390/en12112094.
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Porosity and pore size distribution (PSD) are essential petrophysical parameters controlling permeability and storage capacity in shale gas reservoirs. Various techniques to assess pore structure have been introduced; nevertheless, discrepancies and inconsistencies exist between each of them. This study compares the porosity and PSD in two different shale formations, i.e., the clay-rich Permian Carynginia Formation in the Perth Basin, Western Australia, and the clay-poor Monterey Formation in San Joaquin Basin, USA. Porosity and PSD have been interpreted based on nuclear magnetic resonance (NMR), low-pressure N2 gas adsorption (LP-N2-GA), mercury intrusion capillary pressure (MICP) and helium expansion porosimetry. The results highlight NMR with the advantage of detecting the full-scaled size of pores that are not accessible by MICP, and the ineffective/closed pores occupied by clay bound water (CBW) that are not approachable by other penetration techniques (e.g., helium expansion, low-pressure gas adsorption and MICP). The NMR porosity is largely discrepant with the helium porosity and the MICP porosity in clay-rich Carynginia shales, but a high consistency is displayed in clay-poor Monterey shales, implying the impact of clay contents on the distinction of shale pore structure interpretations between different measurements. Further, the CBW, which is calculated by subtracting the measured effective porosity from total porosity, presents a good linear correlation with the clay content (R2 = 0.76), implying that our correlated equation is adaptable to estimate the CBW in shale formations with the dominant clay type of illite.
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Testamanti, M. Nadia, Reza Rezaee, and Christopher Wong. "Gas permeability measurement of shales using the quasi steady-state technique." APPEA Journal 57, no. 2 (2017): 656. http://dx.doi.org/10.1071/aj16181.
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The decline in reserves from conventional reservoirs, paired with the technological advances made in the drilling, stimulation and production areas over the last two decades have placed unconventional reservoirs in the limelight. Shale plays, in particular, have become increasingly attractive prospects and production from these reservoirs has increased significantly during this period. Most of the petrophysical characterisation techniques routinely used in the laboratory were originally developed for rocks with relatively high porosity and permeability, making some of them unsuitable for tight rocks. Gas permeability measurements in shales can be particularly challenging due to their small pore and pore throat sizes, and even the validity of Darcy’s law under these conditions needs to be evaluated. The steady-state technique is generally unsuitable for measuring gas permeability in shales due to technical limitations of the instruments required, so the quasi steady-state method is proposed as an alternative. This paper presents the results of gas permeability measurements conducted on two shale core plugs using the quasi steady-state technique. Although the effect of variations in ambient conditions is not usually significant for tests performed on cores from conventional reservoirs, our results indicate that it should not be overlooked when experiments are conducted on shale samples. Furthermore, the length of the core plugs should be minimised to reduce the time required to measure gas permeability.
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Egermann, Patrick, Roland Lenormand, Daniel G. Longeron, and Cesar Zarcone. "A Fast and Direct Method of Permeability Measurements on Drill Cuttings." SPE Reservoir Evaluation & Engineering 8, no. 04 (August 1, 2005): 269–75. http://dx.doi.org/10.2118/77563-pa.
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Summary Permeability is one of the most important petrophysical parameters for reservoir characterization, but also one of the most difficult to obtain. Logs provide a good estimate of porosity and saturations, but the accuracy on permeability derived from nuclear magnetic resonance (NMR) is rather poor. So far, reliable values of permeabilities are obtained only from laboratory measurements on core samples for local measurements and well testing for a larger scale-averaged determination. We present an original method for measuring the permeability of drill cuttings without any specific laboratory conditioning (cleaning, coating, etc.). A volume of approximately 100 cm3 of cuttings is placed in a pressure vessel. The cell is then filled with a viscous oil. The process of oil invasion into the cuttings always traps a certain amount of gas. When a pulse of pressure is applied on the cell, the oil enters into the cuttings thanks to the gas compressibility. The permeability is then derived from the dynamic of the oil invasion by using a simple model. The method was tested by using various crushed-rock samples of known permeability. Excellent reproducibility and good agreement between cores and cuttings permeabilities were found for many decades of permeabilities. This method presents many advantages. The measurements can be performed in a few minutes, leading to the possibility of operating on site during drilling. The limitations of the method are related mainly to the size, the representativity of the drill cuttings, and the absence of the confining stress. In developing this method, our purpose is not to replace core analysis but, rather, to provide additional quick and inexpensive information on reservoir characterization. Introduction When a new well is drilled, the main concern of operating companies is to answer quickly two key questions: what are the reserves (porosity, saturation), and what is the well deliverability (permeability/viscosity ratio)? Most of the time, the logs provide a good estimate of porosity and saturation along the well. The viscosity value can be known either from existing pressure/volume/temperature (PVT) studies or by estimation, but its value is often considered as uniform within the reservoir, at least in the early stages of reservoir evaluation. In this paper, we will focus on the evaluation of the permeability profile, which is much more difficult to obtain because this parameter refers to a flowing property of the reservoir rock. We present an original method to perform a direct measurement of permeability from cuttings, which may be suitable during the drilling operation.
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Suriamin, Fnu, and Matthew J. Pranter. "Stratigraphic and lithofacies control on pore characteristics of Mississippian limestone and chert reservoirs of north-central Oklahoma." Interpretation 6, no. 4 (November 1, 2018): T1001—T1022. http://dx.doi.org/10.1190/int-2017-0204.1.
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We have determined how stratigraphy and lithofacies control pore structures in the Mississippian limestone and chert reservoir of north-central Oklahoma. There are 17 lithofacies and 29 high-frequency cycles documented in the Mississippian interval of this study. The high-frequency cycles have thicknesses ranging from 0.3 to 30.5 m (1–100 ft) and are mainly asymmetric regressive phases. The pore characteristics, measured through digital-image analysis (DIA) of thin-sections photomicrographs ([Formula: see text]100), exhibit unique correlations with core porosity, permeability, and lithofacies within a sequence-stratigraphic framework. There are five fundamental correlations observed. First, porosity from DIA and laboratory core measurements has a strong positive relationship ([Formula: see text]). However, some values from DIA porosity yield relatively higher values, specifically in spiculitic mudstone wackestones and argillaceous spiculitic mudstone wackestones. The difference is hypothesized due to the presence of isolated nanopores that are not accessible by helium during measurement of core porosity. Second, the relationship between pore circularity and permeability is indeterminate. The indeterminate relationship is related to a complex internal pore network, intensive diagenetic alteration, an unconnected microfracture network, and isolated pores. Third, positive moderate to strong correlations ([Formula: see text]) between porosity and permeability are observed only in four lithofacies. Fourth, coarse-grained lithofacies within the uppermost depositional sequence of the Mississippian interval have a heterogeneous pore-size distribution, whereas fine-grained lithofacies tend to exhibit a homogeneous pore-size distribution. Fifth, higher reservoir quality is associated with the upper intervals of high-frequency shallowing-upward cycles. This confirms that the sequence-stratigraphic variability of lithofacies is important to predict reservoir quality and its distribution. An alternative graphical method of pore-size distribution is also developed. To be a useful “technique,” examples of the plot are demonstrated using samples in this study. The plot successfully provides simple identification of pore-size classes, quantitative percentage of pore-size class, dominant pore class, and approximate minimum and maximum pore size.
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Peng, Rong, Bangrang Di, Paul W. J. Glover, Jianxin Wei1, Piroska Lorinczi, Pinbo Ding, Zichun Liu, Yuangui Zhang, and Mansheng Wu. "The effect of rock permeability and porosity on seismoelectric conversion: experiment and analytical modelling." Geophysical Journal International 219, no. 1 (June 3, 2019): 328–45. http://dx.doi.org/10.1093/gji/ggz249.
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SUMMARY The seismoelectric method is a modification of conventional seismic measurements which involves the conversion of an incident poroelastic wave to an electromagnetic signal that can be measured at the surface or down a borehole. This technique has the potential to probe the physical properties of the rocks at depth. The problem is that we currently know very little about the parameters which control seismoelectric conversion and their dependence on frequency and permeability, which limits the development of the seismoelectric method. The seismoelectric coupling coefficient indicates the strength of seismoelectric conversion. In our study, we focus on the effects of the reservoir permeability, porosity and frequency on the seismoelectric coupling coefficient through both experimental and numerical modellings. An experimental apparatus was designed to record the seismoelectric signals induced in water-saturated samples in the frequency range from 1 to 500 kHz. The apparatus was used to measure seismoelectric coupling coefficient as a function of porosity and permeability. The results were interpreted using a microcapillary model for the porous medium to describe the seismoelectric coupling. The relationship between seismoelectric coupling coefficients and the permeability and porosity of samples were also examined theoretically. The combined experimental measurements and theoretical analysis of the seismoelectric conversion has allowed us to ascertain the effect of increasing porosity and permeability on the seismoelectric coefficient. We found a general agreement between the theoretical curves and the test data, indicating that seismoelectric conversion is enhanced by increases in porosity over a range of different frequencies. However, seismoelectric conversion has a complex relationship with rock permeability, which changes with frequency. For the low-permeability rock samples (0–100 × 10−15 m2), seismoelectric coupling strengthens with the increase of permeability logarithmically in the low-frequency range (0–10 kHz); in the high-frequency range (10–500 kHz), the seismoelectric coupling is at first enhanced, with small increases of permeability leading to small increases in size in electric coupling. However, continued increases of permeability then lead to a slight decrease in size and image conversion again. For the high-permeability rock samples (300 × 10−15–2200 × 10−15 m2), the seismoelectric conversion shows the same variation trend with low-permeability samples in low-frequency range; but it monotonically decreases with permeability in the high-frequency range. The experimental and theoretical results also indicate that seismoelectric conversion seems to be more sensitive to the changes of low-permeability samples. This observation suggests that seismic conversion may have advantages in characterizing low permeability reservoirs such as tight gas and tight oil and shale gas reservoirs.
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Torres-Verdín, Carlos, Faruk O. Alpak, and Tarek M. Habashy. "Petrophysical inversion of borehole array-induction logs: Part II — Field data examples." GEOPHYSICS 71, no. 5 (September 2006): G261—G268. http://dx.doi.org/10.1190/1.2335633.
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We describe the application of Alpak et al.’s (2006) petrophysical inversion algorithm to the interpretation of borehole array induction logs acquired in an active North American gas field. Layer-by-layer values of porosity and permeability were estimated in two closely spaced vertical wells that penetrated the same horizontal rock formation. The wells were drilled with different muds and overbalance pressures, and the corresponding electromagnetic induction logs were acquired with different tools. Rock-core laboratory measurements available in one of the two wells were used to constrain the efficiency of gas displacement by water-based mud during the process of invasion. Estimated values of porosity and permeability agree well with measurements performed on rock-core samples. In addition to estimating porosity and permeability, the petrophysical inversion algorithm provided accurate spatial distributions of gas saturation in the invaded rock formations that were not possible to obtain with conventional procedures based solely on the use of density and resistivity logs.
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Dehghan Khalili, A., J. Y. Y. Arns, F. Hussain, Y. Cinar, W. V. V. Pinczewski, and C. H. H. Arns. "Permeability Upscaling for Carbonates From the Pore Scale by Use of Multiscale X-Ray-CT Images." SPE Reservoir Evaluation & Engineering 16, no. 04 (October 10, 2013): 353–68. http://dx.doi.org/10.2118/152640-pa.
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Summary High-resolution X-ray-computed-tomography (CT) images are increasingly used to numerically derive petrophysical properties of interest at the pore scale—in particular, effective permeability. Current micro-X-ray-CT facilities typically offer a resolution of a few microns per voxel, resulting in a field of view of approximately 5 mm3 for a 2,0482 charge-coupled device. At this scale, the resolution is normally sufficient to resolve pore-space connectivity and calculate transport properties directly. For samples exhibiting heterogeneity above the field of view of such a single high-resolution tomogram with resolved pore space, a second low-resolution tomogram can provide a larger-scale porosity map. This low-resolution X-ray-CT image provides the correlation structure of porosity at an intermediate scale, for which high-resolution permeability calculations can be carried out, forming the basis for upscaling methods dealing with correlated heterogeneity. In this study, we characterize spatial heterogeneity by use of overlapping registered X-ray-CT images derived at different resolutions spanning orders of magnitude in length scales. A 38-mm-diameter carbonate core is studied in detail and imaged at low resolution—and at high resolution by taking four 5-mm-diameter subsets, one of which is imaged by use of full-length helical scanning. Fine-scale permeability transforms are derived by use of direct porosity/permeability relationships, random sampling of the porosity/permeability scatter plot as a function of porosity, and structural correlations combined with stochastic simulation. A range of these methods is applied at the coarse scale. We compare various upscaling methods, including renormalization theory, with direct solutions by use of a Laplace solver and report error bounds. Finally, we compare with experimental measurements of permeability at both the small-plug and the full-plug scale. We find that both numerically and experimentally for the carbonate sample considered, which displays nonconnecting vugs and intrafossil pores, permeability increases with scale. Although numerical and experimental results agree at the larger scale, the digital core-analysis results underestimate experimentally measured permeability at the smaller scale. Upscaling techniques that use basic averaging techniques fail to provide truthful vertical permeability at the fine scale because of large permeability contrasts. At this scale, the most accurate upscaling technique uses Darcy's law. At the coarse scale, an accurate permeability estimate with error bounds is feasible if spatial correlations are considered. All upscaling techniques work satisfactorily at this scale. A key part of the study is the establishment of porosity transforms between high-resolution and low-resolution images to arrive at a calibrated porosity map to constrain permeability estimates for the whole core.
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Hu, Hai Yan. "Accumulation Mechanism of Ultro-Low Permeability Sandstone Reservoir, Huaqing Oilfield, Ordas Basin." Advanced Materials Research 868 (December 2013): 66–69. http://dx.doi.org/10.4028/www.scientific.net/amr.868.66.
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Ordos Basin is the second largest sedimentary basin in China with very rich oil and gas resources. The exploration targets are typical reservoirs of low permeability, low pressure and low output. To determine the accumulation mechanism of tight sandstone reservoir, thin section, fluid inclusion, porosity and permeability measurement, numerical calculation were used. The result showed that sandstone became tight while oil filling, buoyant force is too small to overcome the resistance of capillary force. Therefore, overpressure induced by source rock generation is the accumulation drive force.
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Alkhayyat, Raniah S., Fadhil S. Kadhim, and Yousif khalaf Yousif. "The Use of Nuclear Magnetic Resonance (NMR) Measurements and Conventional Logs to Predict Permeability for a Complex Carbonate Formation." Journal of Petroleum Research and Studies 11, no. 3 (September 19, 2021): 82–98. http://dx.doi.org/10.52716/jprs.v11i3.534.
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Permeability is one of the most important property for reservoir characterization, and its prediction has been one of the fundamental challenges specially for a complex formation such as carbonate, due to this complexity, log analysis cannot be accurate enough if it’s not supported by core data, which is critically important for formation evaluation. In this paper, permeability is estimated by making both core and log analysis for five exploration wells of Yammama formation, Nasiriyah oil field. The available well logging recorders were interpreted using Interactive Petrophysics software (IP) which used to determine lithology, and the petrophysical properties. Nuclear Magnetic Resonance (NMR) Measurements is used for laboratory tests, which provide an accurate, porosity and permeability measurements. The results show that the main lithology in the reservoir is limestone, in which average permeability of the potential reservoir units’ values tend to range from 0.064275 in zone YA to 20.74 in zone YB3, and averaged porosity values tend to range from 0.059 in zone YA to 0.155 in zoneYB3. Zone YB3 is found to be the best zone in the Yammama formation according to its good petrophysical properties. The correlation of core-log for permeability and porosity produce an acceptable R^2 equal to 0.618, 0.585 respectively
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Yamaguchi, Yoshiyuki. "Influence of Wall Effect on the Measurement of Permeability in High Porosity Fibrous Porous Media." Proceedings of the Thermal Engineering Conference 2020 (October 9, 2020): 0171. http://dx.doi.org/10.1299/jsmeted.2020.0171.
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Shar, Abdul Majeed, Aftab Ahmed Mahesar, Ghazanfer Raza Abbasi, Asad Ali Narejo, and Asghar Ali Alias Daahar Hakro. "Influence of diagenetic features on petrophysical properties of fine-grained rocks of Oligocene strata in the Lower Indus Basin, Pakistan." Open Geosciences 13, no. 1 (January 1, 2021): 517–31. http://dx.doi.org/10.1515/geo-2020-0250.
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Abstract Nari Formation is considered as one of the most important oil and gas exploration targets. These fine-grained tight sandstone reservoirs face enormous challenges due to their extremely low matrix porosity and permeability. Hence, in this regard, the study was carried out to collect the high-quality data on petrophysical properties along with mineralogy and microstructural characteristics and diagenesis. The experiments performed includes the petrographic study and scanning electron microscopy, and X-ray diffraction analyses. Besides, the measurement of petrophysical properties was carried out to assess the likely influence of the reservoir quality. The petrographic analysis shows predominantly fine- to medium-grained grey samples along with calcite, clay, lithic fragments and iron oxides. Further, the thin-section observations revealed that the quartz is a principal mineral component in all the analysed samples ranging from 52.2 to 92.9%. The bulk volume of clay minerals that range from 5.3 to 16.1% of. The porosity and permeability measured range from 5.08 to 18.56% (average 7.22%) and from 0.0152 to 377 mD (average 0.25 mD), respectively. The main diagenetic processes that affected the sandstones of Nari Formation are mechanical compaction, grain deformation, cementation and quartz dissolution and have played a significant role in influencing the quality of the reservoir rock. Overall, it appears that the primary petrophysical properties (porosity and permeability) were decreased due to the mechanical compaction, lithification, cementation, and framework grain dissolution. Based on the integrated mineralogical, microstructural analysis, and the laboratory-based petrophysical properties, the samples exhibited poor porosity, permeability, and moderate clay content, which indicate that the Nari Formation is a poor quality reservoir.
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Manescu, Adrian, and Stewart Bayford. "Application of nuclear magnetic resonance measurements in the evaluation of two coal seam gas wells in the Pedirka Basin." APPEA Journal 50, no. 2 (2010): 733. http://dx.doi.org/10.1071/aj09097.
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In 2008, Central Petroleum was involved in an extended exploration campaign in the Pedirka Basin. The main targets were conventional oil and coal seam gas (CSG). A comprehensive logging program including nuclear magnetic resonance (NMR) measurements was acquired, with the scope of evaluating both targets in two wells. NMR tools measure the magnetisation of hydrogen protons present in the flushed-zone of the formation pore space. By calibrating this measurement in a water tank, NMR tools provide formation porosity independent of lithology, while classical methods for deriving porosity (density, neutron, etc.) are lithology dependent. While in conventional plays (clastics, carbonates) porosity is needed for evaluating the reservoir storage capacity, in coal beds porosity is needed for evaluating the surface areas of the pores. As methane in coal is bound to the coal surface, total pore surface affects the coal bed methane producing capacity. NMR measurements also provide information about porosity/grain size distribution, permeability and hydrocarbon saturation in conventional formations. This information can be very useful for evaluating coal seam gas, provided the conventional models can be converted and applied in coal beds. Evaluation of coal seam gas prospects using nuclear magnetic resonance is an industry first. This presentation highlights the benefits and difficulties of nuclear magnetic resonance evaluation of CSG prospects in these two wells.
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Galloway, D. S. Hamilton W. E. "NEW EXPLORATION TECHNIQUES IN THE ANALYSIS OF DIAGENETICALLY COMPLEX RESERVOIR SANDSTONES, SYDNEY BASIN, NSW." APPEA Journal 29, no. 1 (1989): 235. http://dx.doi.org/10.1071/aj88022.
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The Sydney Basin, despite numerous encouraging shows of both free oil and gas from coal and petroleum exploration drilling, remains unproductive of commercial hydrocarbons. Reservoir potential has historically been the primary concern, owing to widespread distribution throughout the sequence of lithic, diagenetically- altered, clay- rich sandstones. This study aimed at defining areas of acceptable reservoir quality by careful examination of stratigraphic, depositional and diagenetic controls.Interpretation and extrapolation of reservoir distribution, attributes and quality were carried out within a genetic stratigraphic framework. Stratigraphic packages of widespread correlatability that were deposited during discrete episodes of basin filling provide the basis for delineation of component depositional systems and for further mapping of framework sandstone facies and associated mud rocks.The availability of numerous, continuous drill cores from existing coal bores and limited petroleum exploration wells provided an opportunity to directly quantify porosity and permeability. A visual method of estimating permeability was applied by comparison of the drill cores with a standard set of cores of known permeability. The comparison was made on fresh, dry rock surfaces with the aid of a binocular microscope at 20 × magnification. Reliability of the visual estimates was then assessed by laboratory measurement of a large representative sample set.Lithofacies maps of genetic stratigraphic packages define sand- body trends and allow interpretative extrapolation of reservoir facies tracts which, when integrated with the visually- estimated and laboratory- derived reservoir quality data, enabled mapping of regional permeability distribution and thickness.The principal conclusions of the study are that reservoirs with sufficient porosity, permeability and volume for conventional oil and gas production exist within the Sydney Basin. Best reservoir quality occurs in quartzose sandstones of the Narrabeen Group in the southwestern part of the basin. Potential reservoir sandstones are up to 20 m thick, have permeabilities in the 10- 1000 md range and porosity between 10 and 18 per cent. Calibration and testing of the visual estimation technique allowed accurate and efficient continuous recording and mapping of porosity and permeability, and this technique may have much wider application for the petroleum industry.