Relevant bibliographies by topics / Permeability and porosity measurement

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Academic literature on the topic 'Permeability and porosity measurement'

Author: Grafiati
Published: 4 June 2021
Last updated: 1 February 2022

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Journal articles on the topic "Permeability and porosity measurement"

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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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Dissertations / Theses on the topic "Permeability and porosity measurement"

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Profice, Sandra. "Mesure de propriétés monophasiques de milieux poreux peu perméables par voie instationnaire." Thesis, Bordeaux, 2014. http://www.theses.fr/2014BORD0142/document.

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Parmi la multitude des données pétrophysiques utilisées pour décrire une formationgéologique, certaines permettent spécifiquement d'en prédire la capacité de production,à savoir : la porosité, la perméabilité intrinsèque et le coefficient de Klinkenberg.Dans le cas particulier des gas shales, ces trois propriétés essentielles sont extrêmementdifficiles à mesurer précisément, compte tenu de la complexité de cesroches. Cette thèse s'inscrit dans la continuité de travaux menés au laboratoire I2M départementTREFLE, sur l'analyse et l'amélioration de la méthode Pulse Decay, quiconstitue la méthode de mesure transitoire classiquement utilisée dans l'industriepétrolière pour identifier une ou plusieurs des propriétés d'intérêt. Les multiplespoints faibles de la méthode Pulse Decay sont ici présentés, de même que les pointsforts de la nouvelle méthode issue du perfectionnement de la méthode Pulse Decay,à savoir la méthode Step Decay, développée au laboratoire I2M et brevetée en partenariatavec TOTAL. Plus précisément, les performances de la méthode Step Decaysont ici étudiée aussi bien numériquement qu'expérimentalement, en condition homogène,comme en condition hétérogène. Ce manuscrit fournit également les résultatsd'une analyse portant sur la méthode Pulse Decay sur broyat, qui forme une alternativepossible à la méthode Pulse Decay sur carotte mais dont la fiabilité est fortementremise en question
Among the multitude of petrophysical data used to describe a geological formation,some of them allow specifically to predict the production capacity, namely: the porosity,the intrinsic permeability and the Klinkenberg coefficient. In the particular case ofgas shales, these three essential properties are extremely difficult to measure precisely,because of the complexicity of these rocks. This thesis is the continuity ofworks led in I2M laboratory-TREFLE department, on the analysis and the improvementof the Pulse Decay method, which is the classical transient method of measurementused in the oil&gas industry to identify one or several of the properties ofinterest. The numerous weaknesses of the Pulse Decay method are here presented,as the strengths of the new method derived from the improvement of the Pulse Decaymethod, namely the Step Decay method, developed in I2M laboratory and patentedin partnership with TOTAL. More exactly, the performances of the Step Decaymethod are here studied numerically as well as experimentally, in homogeneouscondition, as in heterogeneous condition. This manuscript provides also the results ofan analysis dealing with the Pulse Decay method on cuttings, which forms a possiblealternative to the Pulse Decay method on plug but which reliability is highly questioned
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Esselburn, Jason Dennis. "Porosity and Permeability in Ternary Sediment Mixtures." Wright State University / OhioLINK, 2009. http://rave.ohiolink.edu/etdc/view?acc_num=wright1245949430.

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Hosa, Aleksandra Maria. "Modelling porosity and permeability in early cemented carbonates." Thesis, University of Edinburgh, 2016. http://hdl.handle.net/1842/16181.

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Cabonate-hosted hydrocarbon reservoirs will play an increasingly important role in the energy supply, as 60% of the world's remaining hydrocarbon resources are trapped within carbonate rocks. The properties of carbonates are controlled by deposition and diagenesis, which includes calcite cementation that begins immediately after deposition and may have a strong impact on subsequent diagenetic pathways. This thesis aims to understand the impact of early calcite cementation on reservoir properties through object-based modelling and Lattice Boltzmann ow simulation to obtain permeability. A Bayesian inference framework is also developed to quantify the ability of Lattice Boltzmann method to predict the permeability of porous media. Modelling focuses on the impact of carbonate grain type on properties of early cemented grainstones and on the examination of the theoretical changes to the morphology of the pore space. For that purpose process-based models of early cementation are developed in both 2D (Calcite2D) and 3D (Calcite3D, which also includes modelling of deposition). Both models assume the existence of two grain types: polycrystalline and monocrystalline, and two early calcite cement types specific to these grain types: isopachous and syntaxial, respectively. Of the many possible crystal forms that syntaxial cement can take, this thesis focuses on two common rhombohedral forms: a blocky form 01¯12 and an elongated form 40¯41. The results of the 2D and 3D modelling demonstrate the effect of competition of growing grains for the available pore space: the more monocrystalline grains present in the sample, the stronger this competition becomes and the lesser the impact of each individual grain on the resulting early calcite cement volume and porosity. The synthetic samples with syntaxial cements grown of the more elongated crystal form 40¯41 have lower porosity for the same monocrystalline grains content than synthetic samples grown following more blocky crystal form 01¯12. Moreover, permeability at a constant porosity is reduced for synthetic samples with the form 40¯41. Additionally, synthetic samples with form 40¯41 exhibit greater variability in the results as this rhombohedral form is more elongated and has the potential for producing a greater volume of cement. The results of the 2D study suggest that for samples at constant porosity the higher the proportion of monocrystalline grains are in the sample, the higher the permeability. The 3D study suggests that for samples with crystal form 01¯12 at constant porosity the permeability becomes lower as the proportion of monocrystalline grains increase, but this impact is relatively minor. In the case of samples with crystal form 40¯41 the results are inconclusive. This dependence of permeability on monocrystalline grains is weaker than in the 2D study, which is most probably a result of the bias of flow simulation in the 2D as well as of the treatment of the porous medium before the cement growth model is applied. The range of the permeability results in the 2D modelling may be artificially overly wide, which could lead to the dependence of permeability on sediment type being exaggerated. Poroperm results of the 2D modelling (10-8000mD) are in reasonable agreement with the data reported for grainstones in literature (0.1-5000mD) as well as for the plug data of the samples used in modelling (porosity 22 - 27%, permeability 200 - 3000mD), however permeability results at any given porosity have a wide range due to the bias inherent to the 2D flow modelling. Poroperm results in the 3D modelling (10 - 30, 000mD) exhibit permeabilities above the range of that reported in the literature or the plug data, but the reason for that is that the initial synthetic sediment deposit has very high permeability (58, 900mD). However, the trend in poroperm closely resembles those reported in carbonate rocks. As the modelling depends heavily on the use of Lattice Boltzmann method (flow simulation to obtain permeability results), a Bayesian inference framework is presented to quantify the predictive power of Lattice Boltzmann models. This calibration methodology is presented on the example of Fontainebleau sandstone. The framework enables a systematic parameter estimation of Lattice Boltzmann model parameters (in the scope of this work, the relaxation parameter τ ), for the currently used calibrations of Lattice Boltzmann based on Hagen-Poiseuille law. Our prediction of permeability using the Hagen-Poiseuille calibration suggests that this method for calibration is not optimal and in fact leads to substantial discrepancies with experimental measurements, especially for highly porous complex media such as carbonates. We proceed to recalibrate the Lattice Boltzmann model using permeability data from porous media, which results in a substantially different value of the optimal τ parameter than those used previously (0.654 here compared to 0.9). We augment our model introducing porosity-dependence, where we find that the optimal value for τ decreases for samples of higher porosity. In this new semi-empirical model one first identifies the porosity of the given medium, and on that basis chooses an appropriate Lattice Boltzmann relaxation parameter. These two approaches result in permeability predictions much closer to the experimental permeability data, with the porosity-dependent case being the better of the two. Validation of this calibration method with independent samples of the same rock type yields permeability predictions that fall close to the experimental data, and again the porosity-dependent model provides better results. We thus conclude that our calibration model is a powerful tool for accurate prediction of complex porous media permeability.
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Hudd, Raymond W. "Measurement of concrete permeability." Thesis, Loughborough University, 1989. https://dspace.lboro.ac.uk/2134/6722.

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A comparison was made between a number of laboratory and in-situ concrete permeability test methods. The laboratory tests used measured air, water, and water vapour permeability, whilst the in-situ tests used were the Initial surface absorption test, the Figg air and water tests, and a new in-situ method called the Egg test; a non-destructive surface test which measures air permeability properties. An initial set of tests were carried out on six concrete mixes with water: cement(w/c) ratios between 0.3 and 0.8. These tests showed that problems existed with both the laboratory and in-situ test methods. Some of these problems arose from the preparation of specimens or test procedures and these were overcome with practice or by modifying the test methods. However, it was found that a major problem is moisture in the concrete which decreases it's measured permeability. Further tests were carried out on a second set of concrete specimens with the same mix proportions as the first and a set of mortar specimens with w/c ratios ranging from 0.3 to 1.1 and cement: sand (c: s) ratios from 1: 1 to 1: 5. Results from tests on oven dry specimens were used to compare the different methods and showed that few simple relationships existed between the different methods. Comparing the test results with the mix proportions showed that in the majority of cases, the measured permeability values increased as the w/c ratio increased, but the relationships between the tests results and c: s ratio were more complicated. After these tests had been completed, specimens from twenty six of the mixes were retested after being conditioned to various different moisture contents. The results of these tests showed that in most cases there was a rapid increase in measured permeability as the specimens dried, followed by a slower increase (in some cases a decrease) as the specimens approached an oven dry condition. To complement this study a number of methods were examined for measuring in-situ moisture content. The most promising of these was a non-destructive method which operated by measuring the electrical permittivity of the material it was placed against. Because the electrical permittivity varies with the amount of water in the concrete, it is largely independent of the type material being tested. Results from this test showed a shallow linear drop from saturated to approximately half of the saturated moisture content, followed by a steep drop towards the oven dry condition.
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Phillips, Peter M. "POROSITY AND PERMEABILITY OF BIMODAL SEDIMENT MIXTURES USING NATURAL SEDIMENT." Wright State University / OhioLINK, 2007. http://rave.ohiolink.edu/etdc/view?acc_num=wright1189439106.

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Cox, Peter Alexander. "Porosity and permeability relationships of the Lekhwair and Lower Kharaib Formations." Thesis, University of Edinburgh, 2011. http://hdl.handle.net/1842/16161.

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Up to 60% of the World’s oil is now within carbonates, with over 50% in the Middle East. Many existing carbonate fields have very low oil recoveries due to multiple scales of pore heterogeneity. To secure better recoveries the controls from deposition and diagenesis towards the origin of carbonate pore heterogeneity needs better understanding. To provide good sample support, three High frequency Cycle’s were sampled (2 from the Lekhwair Formation and the third being the Lower Kharaib Formation) from an offshore field (Abu Dhabi) along a southwest-northeast transect, encompassing the oil leg, transition zone, water leg, the field crest and two opposing flanks. With respect to deposition, the 4th order Sequence Boundaries’ (hardgrounds) and the Maximum Flooding Surface’s were correlated across the field, within the sequence stratigraphic framework, showing that each HFC, of the Lekhwair Formation, contains laterally continuous reservoirs (4th order HST’s) which are compartmentalised above and below by impermeable seals (4th order TST’s). The Lower Kharaib Formation shows significant shoaling producing the shallowest platform (prolonged 3rd order TST) and the best connected reservoir facies. With respect to diagenesis, δ 18O isotopes trends, from calcite cement zones within macrocements from the water and oil legs, in comparison with oil inclusion abundances suggest that oil charge reduced cementation in the crest macropores. Stylolitisation in the water leg at deep burial provided solutes for new cement nucleation causing near complete macropore occlusion. The most open micropore networks coincide with the highest porosity/permeability relationships at the mid-late HST’s of each HFC. Considering these areas could be lower grade reservoirs, and that pore characterisation by Lucia (1999) does not include identifying and quantifying micropores, a new ‘Micropore model’ (using elements from the Petrotype atlas method) is devised. This new method highlights micropore-dominated areas alongside macropore-dominated areas within specific reservoir horizons. This provides information of pore heterogeneity at several scales within a carbonate reservoir and may determine the method for oil extraction and increase oil recovery from both the Lekhwair and Lower Kharaib Formations.
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Bashir, Abdulaadem A. "An experimental investigation of some capillary pressure-relative permeability correlations for sandstone reservoir rocks." Thesis, Robert Gordon University, 2000. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.310346.

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Drews, Michael C. "Modelling stress-dependent effective porosity-permeability relationships of metre-scale heterogeneous mudstones." Thesis, University of Newcastle Upon Tyne, 2012. http://hdl.handle.net/10443/1672.

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The importance of shales and mudstones to applied geosciences and in particular to fluid migration in sedimentary basins has never been more recognized than today. Prominent examples are conventional or unconventional petroleum systems, where shales and mudstones act as source, reservoir or cap rock, but also CO2 and nuclear waste storage or hydrogeology. Despite their importance, shales and mudstones are yet not as far well understood as sandstones or carbonate rocks. In particular, the influence of heterogeneity on fluid migration has been poorly addressed in the past, although many authors have identified and studied heterogeneities in shales and mudstones. Nevertheless, their flow properties are fairly well understood when treated as homogeneous on sample scale (centimetre-scale). Typical flow relevant heterogeneities are grain size and thus petrophysical property (e.g. porosity, permeability, capillary entry pressures) variations due to spatial lithological variation induced by primary and secondary sedimentary structures. In this study we investigate flow relevant heterogeneities of shales and mudstones on submetre scale derived from core and borehole images from an off-shore gas field in the Western Nile Delta, Egypt. Thereby, we combine latest models and published measurements of sample-scale petrophysical properties with interpretation, quantitative analyses, advanced modelling and numerical fluid flow simulation to assess the influence of shale and mudstone heterogeneity on fluid flow and hence, fluid migration, retention and mudstone seal capacity. Additionally, the set of mudstone heterogeneities used in this study has been derived from a combined visual and geostatistical interpretation of more than 500 m of mud-rich core and borehole images. As final results, we deliver stress-dependent effective porosity-permeability relationships for a broad range of shale and mudstone heterogeneities, representative model sizes and resolution as well as measures of uncertainty for each heterogeneity type. Moreover, probability density functions describing where and how these heterogeneities appear in larger scale geological units, such as seismic facies or local depositional environments, are provided. As a key result, heterogeneity and lithological variation have great influences on effective permeability and effective permeability anisotropy (Kh/Kv). Furthermore, our results indicate that mudstone heterogeneity is very common in all investigated larger scale geological units (hemipelagites, levees, channels). Modelling of fluid flow through mud-rich sedimentary basins without inclusion of these sub-metre scale heterogeneities of mudstones can therefore lead to misleading results. Thus, effective porosity-permeability (anisotropy) relationships are provided for different lithological variations and mudstone heterogeneities as a final result.
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Li, Bowei. "Implementation of full permeability tensor representation in a dual porosity reservoir simulator." Access restricted to users with UT Austin EID Full text (PDF) from UMI/Dissertation Abstracts International, 2001. http://wwwlib.umi.com/cr/utexas/fullcit?p3034930.

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張家齊 and Kar-chai Cheung. "Effect of sintering time and temperature on dental porcelain porosity." Thesis, The University of Hong Kong (Pokfulam, Hong Kong), 1999. http://hub.hku.hk/bib/B3122233X.

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Books on the topic "Permeability and porosity measurement"

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G, Jorgensen Donald. Using geophysical logs to estimate porosity, water resistivity, and intrinsic permeability. Washington, DC: Dept. of the Interior, 1989.

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G, Jorgensen Donald. Using geophysical logs to estimate porosity, water resistivity, and intrinsic permeability. [Washington, D.C.]: U.S. G.P.O., 1989.

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Lucia, F. Jerry. Rock fabric, permeability, and log relationships in an upward-shoaling, vuggy carbonate sequence. Austin, TX: University of Texas at Austin, 1987.

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Lucia, F. Jerry. Rock fabric, permeability, and log relationships in an upward-shoaling, vuggy carbonate sequence. Austin, Tex: Bureau of Economic Geology, University of Texas at Austin, 1987.

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Carleton, Glen B. Design and analysis of tracer tests to determine effective porosity and dispersivity in fractured sedimentary rocks, Newark Basin, New Jersey. West Trenton, N.J: U.S. Dept. of the Interior, U.S. Geological Survey, 1999.

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Skalny, Jan, and L. R. Roberts. Pore structure and permeability of cementitious materials. Edited by Roberts L. R, Skalny Jan, Materials Research Society, and Symposium on the "Pore Structure and Permeability of Cementitious Materials (1988 : Boston, Mass.). Pittsburgh, Pa: Materials Research Society, 1989.

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Mertz, Jean-Didier. Structures de porosité et propriétés de transport dans les grès. Strasbourg: Institut de géologie, Université Louis Pasteur de Strasbourg, 1991.

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Sara, MN, and LG Everett, eds. Evaluation and Remediation of Low Permeability and Dual Porosity Environments. 100 Barr Harbor Drive, PO Box C700, West Conshohocken, PA 19428-2959: ASTM International, 2002. http://dx.doi.org/10.1520/stp1415-eb.

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Everett, Lorne G., and Martin N. Sara. Evaluation and remediation of low permeability and dual porosity environments. Edited by Symposium on Evaluation and Remediation of Low Permeability and Dual Porosity Environments (2001 : Reno, Nev.) and ASTM International. W. Conshohocken, PA: ASTM, 2002.

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Safko, Paul S. A preliminary approach to the use of borehole data, including television surveys, for characterizing secondary porosity of carbonate rocks in the Floridan aquifer system. Tallahassee, Fla: U.S. Dept. of the Interior, U.S. Geological Survey, 1992.

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Book chapters on the topic "Permeability and porosity measurement"

1

Turgut, A., and T. Yamamoto. "Measurements of Compressional Wave and Shear Wave Speeds, Attenuation, Permeability, and Porosity in Marine Sediments." In Shear Waves in Marine Sediments, 403–10. Dordrecht: Springer Netherlands, 1991. http://dx.doi.org/10.1007/978-94-011-3568-9_46.

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Nakanishi, Kazuki. "Porosity Measurement." In Handbook of Sol-Gel Science and Technology, 1–11. Cham: Springer International Publishing, 2016. http://dx.doi.org/10.1007/978-3-319-19454-7_38-1.

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Nakanishi, Kazuki. "Porosity Measurement." In Handbook of Sol-Gel Science and Technology, 1399–409. Cham: Springer International Publishing, 2018. http://dx.doi.org/10.1007/978-3-319-32101-1_38.

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Samsonov, G. V. "Ionite Permeability and Porosity." In Ion-Exchange Sorption and Preparative Chromatography of Biologically Active Molecules, 10–41. Boston, MA: Springer US, 1986. http://dx.doi.org/10.1007/978-1-4684-8908-8_2.

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Kozlovsky, Yevgeny A. "Rock Density, Porosity, and Permeability." In The Superdeep Well of the Kola Peninsula, 332–38. Berlin, Heidelberg: Springer Berlin Heidelberg, 1987. http://dx.doi.org/10.1007/978-3-642-71137-4_17.

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Lowell, S., and Joan E. Shields. "Density measurement." In Powder Surface Area and Porosity, 227–34. Dordrecht: Springer Netherlands, 1991. http://dx.doi.org/10.1007/978-94-015-7955-1_22.

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Connolly, James A. D., and Yury Y. Podladchikov. "An analytical solution for solitary porosity waves: dynamic permeability and fluidization of nonlinear viscous and viscoplastic rock." In Crustal Permeability, 285–306. Chichester, UK: John Wiley & Sons, Ltd, 2016. http://dx.doi.org/10.1002/9781119166573.ch23.

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Luijendijk, Elco, and Tom Gleeson. "How well can we predict permeability in sedimentary basins? Deriving and evaluating porosity-permeability equations for noncemented sand and clay mixtures." In Crustal Permeability, 87–103. Chichester, UK: John Wiley & Sons, Ltd, 2016. http://dx.doi.org/10.1002/9781119166573.ch10.

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Byrne, A. J., and I. K. Farquhar. "Measurement of Alveolar-Capillary Permeability." In Update 1990, 146–57. Berlin, Heidelberg: Springer Berlin Heidelberg, 1990. http://dx.doi.org/10.1007/978-3-642-84125-5_15.

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Hayford, D. T., G. E. Kechter, R. J. Davis, and T. O. McCanney. "Nondestructive Measurement of Magnetic Permeability." In Review of Progress in Quantitative Nondestructive Evaluation, 1871–78. Boston, MA: Springer US, 1993. http://dx.doi.org/10.1007/978-1-4615-2848-7_240.

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Conference papers on the topic "Permeability and porosity measurement"

1

Luffel, D. L., and W. E. Howard. "Reliability of Laboratory Measurement of Porosity in Tight Gas Sands." In SPE/DOE Joint Symposium on Low Permeability Reservoirs. Society of Petroleum Engineers, 1987. http://dx.doi.org/10.2118/16401-ms.

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Chen, Zhongming, Jim McLemore, and J. P. Heller. "The Miniporopermeameter for Simultaneous Measurement of Permeability and Porosity." In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers, 1993. http://dx.doi.org/10.2118/26508-ms.

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Purl, R., J. C. Evanoff, and M. L. Brugler. "Measurement of Coal Cleat Porosity and Relative Permeability Characteristics." In SPE Gas Technology Symposium. Society of Petroleum Engineers, 1991. http://dx.doi.org/10.2118/21491-ms.

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Qin, Xuan, Xinding Fang, and De-Hua Han. "Measurement of porosity for gas shale and estimation of its permeability." In SEG Technical Program Expanded Abstracts 2020. Society of Exploration Geophysicists, 2020. http://dx.doi.org/10.1190/segam2020-3424960.1.

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Fisher, Q. J., C. Grattoni, K. Rybalcenko, P. Lorinczi, and T. Leeftink. "Laboratory Measurements of Porosity and Permeability of Shale." In Fifth EAGE Shale Workshop. Netherlands: EAGE Publications BV, 2016. http://dx.doi.org/10.3997/2214-4609.201600389.

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Sharma, Sanjay, and Dennis Siginer. "Permeability Measurement of Orthotropic Fibers Under an Acoustic Force Field." In ASME 2009 Fluids Engineering Division Summer Meeting. ASMEDC, 2009. http://dx.doi.org/10.1115/fedsm2009-78567.

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Using the validated acoustic method of determining physical properties of porous materials, acoustical properties of the orthotropic medium is used to predict longitudinal and transverse permeability. Measurement of samples in the impedance tube is conducted using ASTM E 1050 for a frequency range of 50 Hz to 6.4 KHz. The acoustical method is shown to compute longitudinal and transverse permeability for various porosity levels. The method describes permeability prediction for carbon, glass and hybrid lay ups. Longitudinal permeability calculated from the absorption coefficient of sized and unsized fibers is found to be the same in contrast to the flow methods.
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Potter, G. F., and D. R. Groves. "Displacements, Saturations, and Porosity Profiles From Steady-State Permeability Measurements." In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers, 1989. http://dx.doi.org/10.2118/spe-19679-ms.

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Duru, Obinna Onyinye, and Roland N. Horne. "Joint Inversion of Temperature and Pressure Measurements for Estimation of Permeability and Porosity Fields." In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers, 2010. http://dx.doi.org/10.2118/134290-ms.

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Milsch, Harald, and Guido Blöcher. "Direct and Simultaneous Measurements of Sandstone Porosity, Permeability, and Electrical Conductivity at Elevated Pressures." In Fifth Biot Conference on Poromechanics. Reston, VA: American Society of Civil Engineers, 2013. http://dx.doi.org/10.1061/9780784412992.169.

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Freire-Gormaly, M., H. MacLean, and A. Bazylak. "MicroCT Investigations and Pore Network Reconstructions of Limestone and Carbonate-Based Rocks for Deep Geologic Carbon Sequestration." In ASME 2012 6th International Conference on Energy Sustainability collocated with the ASME 2012 10th International Conference on Fuel Cell Science, Engineering and Technology. American Society of Mechanical Engineers, 2012. http://dx.doi.org/10.1115/es2012-91116.

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In this paper, we characterized the microstructure of Indiana Limestone rock samples using X-ray micro-computed tomography (microCT) measurements. Our preliminary results include the porosity, and three-dimensional pore reconstructions for each sample. The resulting porosity values are consistent with experimental permeability tests.
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Reports on the topic "Permeability and porosity measurement"

1

Lavoie, D. Porosity and permeability measurements for selected Paleozoic samples in Quebec. Natural Resources Canada/ESS/Scientific and Technical Publishing Services, 2009. http://dx.doi.org/10.4095/226437.

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Weir, G. J., and S. P. White. A Permeability-Porosity Relationship for Surface Deposition. Office of Scientific and Technical Information (OSTI), January 1995. http://dx.doi.org/10.2172/895954.

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Gleeson, Tom. GLobal HYdrogeology MaPS (GLHYMPS) of permeability and porosity. Consortium of Universities for the Advancement of Hydrologic Science, Inc. (CUAHSI), September 2014. http://dx.doi.org/10.4211/spatialdata-glhymps.

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Harbour, J., V. Vickie Williams, T. Tommy Edwards, R. Russell Eibling, and R. Ray Schumacher. SALTSTONE VARIABILITY STUDY - MEASUREMENT OF POROSITY. Office of Scientific and Technical Information (OSTI), August 2007. http://dx.doi.org/10.2172/913452.

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Diabira, I., L. M. Castanier, and A. R. Kovscek. Porosity and Permeability Evolution Accompanying Hot fluid Injection into Diatomite, SUPRI TR-123. Office of Scientific and Technical Information (OSTI), April 2001. http://dx.doi.org/10.2172/777917.

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Harbour, J., T. Tommy Edwards, and V. Vickie Williams. PERMEABILITY OF SALTSTONE MEASUREMENT BY BEAM BENDING. Office of Scientific and Technical Information (OSTI), January 2008. http://dx.doi.org/10.2172/923832.

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O'Connor, Peter A. Constant-pressure measurement of steam-water relative permeability. US: Stanford University, Stanford, CA, June 2001. http://dx.doi.org/10.2172/896521.

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Johnson, H. P. Measurement of in situ Permeability of Sandy Sediments. Fort Belvoir, VA: Defense Technical Information Center, September 2000. http://dx.doi.org/10.21236/ada610064.

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Clough, J. G. Porosity, permeability and grain density analyses of twenty Katakturuk Dolomite outcrop samples, northeastern Brooks Range, Alaska. Alaska Division of Geological & Geophysical Surveys, 1995. http://dx.doi.org/10.14509/1718.

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Morris, T. H. ,. Garner, A. Analysis of lithofacies, petrology/petrography, and porosity/permeability of the lower green river formation: Willow Creek. Office of Scientific and Technical Information (OSTI), April 1994. http://dx.doi.org/10.2172/10160532.

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