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Journal articles on the topic 'Dual-Porosity'

Author: Grafiati

Published: 4 June 2021

Last updated: 31 January 2023

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1

El Husseiny, Ammar, and Tiziana Vanorio. "Porosity-permeability relationship in dual-porosity carbonate analogs." GEOPHYSICS 82, no. 1 (January 1, 2017): MR65—MR74. http://dx.doi.org/10.1190/geo2015-0649.1.

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We have investigated the effect of micrite content and macroporosity on the porosity-permeability relationship of dual-porosity carbonates using analog samples created in the laboratory. Specifically, we control the micrite-to-coarse-grains ratio to produce samples in which the micrite content is the only parameter changing. We also introduce into the microstructures controlled volumes of an acetone-soluble solid material (camphor) at the expense of the micrite aggregates, which functions as macropores after being dissolved. With regard to the effect of micrite on the porosity-permeability relationship, our results indicated that adding micrite to samples exhibiting a grain-supported microstructure reduces porosity and permeability drastically. By increasing the micrite content up to approximately 30%, the sample becomes micrite supported, at which point adding more micrite increases the porosity but no longer affects the permeability significantly. Samples characterized by a high micrite content were found to have lower permeability at any given porosity. When macropores are introduced at the expense of micrite aggregates, permeability increases drastically with porosity. The rate of increase in permeability decreases, however, as the micrite content of the original microstructure increases. Additionally, at any given micrite content, the permeability increases as the percentage of macropores increases because such pores do contribute more significantly to fluid flow as compared with the micropores characterizing micrite aggregates. We used the varying micrite-to-coarse-grains ratio and its effect on the porosity-permeability relationship to inform the Kozeny-Carman relation for a pack of spheres. Our analysis determined that micrite affects the porosity-permeability relationship of carbonates by reducing the effective particle size and increasing the percolation porosity. Additionally, incorporating the content of micrite and macropores into the analysis of the porosity-permeability relationship increased the coefficient of determination ([Formula: see text]) from 0.24 to 0.78. We concluded that knowledge of micrite content and macroporosity is of paramount importance to interpret and model porosity-permeability relationships in carbonates.

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2

Scruggs, Courtney R., Martin Briggs, Frederick D. Day‐Lewis, Dale Werkema, and John W. Lane. "The Dual‐Domain Porosity Apparatus: Characterizing Dual Porosity at the Sediment/Water Interface." Groundwater 57, no. 4 (December 13, 2018): 640–46. http://dx.doi.org/10.1111/gwat.12846.

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3

Bai, Mai, Qinggang Ma, and Jean-Claude Roegiers. "A nonlinear dual-porosity model." Applied Mathematical Modelling 18, no. 11 (November 1994): 602–10. http://dx.doi.org/10.1016/0307-904x(94)90318-2.

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4

Wang, Y. H., and D. Xu. "Dual Porosity and Secondary Consolidation." Journal of Geotechnical and Geoenvironmental Engineering 133, no. 7 (July 2007): 793–801. http://dx.doi.org/10.1061/(asce)1090-0241(2007)133:7(793).

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5

Al Hameli, Fatima, Abhijith Suboyin, Mohammed Al Kobaisi, Md Motiur Rahman, and Mohammed Haroun. "Modeling Fracture Propagation in a Dual-Porosity System: Pseudo-3D-Carter-Dual-Porosity Model." Energies 15, no. 18 (September 16, 2022): 6779. http://dx.doi.org/10.3390/en15186779.

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Despite the significant advancements in geomodelling techniques over the past few decades, it is still quite challenging to obtain accurate assessments of hydraulic fracture propagation. This work investigates the effect of fluid leak-off in a dual-porosity system on the hydraulic fracture propagation geometry, which, in turn, affects hydrocarbon recovery from tight and unconventional reservoirs. Fracture propagation within tight reservoirs was analyzed using the Pseudo Three-Dimensional-Carter II model for single- (P3D-C) and dual-porosity systems (P3D-C-DP). Previous studies have accounted for leak-off in single-porosity models; however, studies within dual-porosity systems are still quite limited. We present a novel approach to coupling fluid leak-off in a dual-porosity system along with a fracture-height growth mechanism. Our findings provide important insights into the complexities within hydraulic fracturing treatment design using our new and pragmatic modeling approach. The simulation results illustrate that fluid leak-off in dual-porosity systems contributes to a confined fracture half-length (xf), that is 31% smaller using the P3D-C-DP model as opposed to the single-porosity model (P3D-C). As for the fracture height growth (hf), the P3D-C-DP model resulted in a 40% shorter fracture height compared to the single-porosity model.

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6

Presho, M., S. Wo, and V. Ginting. "Calibrated dual porosity, dual permeability modeling of fractured reservoirs." Journal of Petroleum Science and Engineering 77, no. 3-4 (June 2011): 326–37. http://dx.doi.org/10.1016/j.petrol.2011.04.007.

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7

Dershowitz, W., and Ian Miller. "Dual porosity fracture flow and transport." Geophysical Research Letters 22, no. 11 (June 1, 1995): 1441–44. http://dx.doi.org/10.1029/95gl01099.

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8

Saghir, M. Z., and M. R. Islam. "Double diffusive convection in dual-permeability, dual-porosity porous media." International Journal of Heat and Mass Transfer 42, no. 3 (February 1999): 437–54. http://dx.doi.org/10.1016/s0017-9310(98)00183-5.

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9

Leung, Woon F. "A New Pseudosteady-State Model for Dual-Porosity/Dual-Permeability Aquifers and Two Interconnected Single-Porosity Aquifers." SPE Reservoir Engineering 1, no. 05 (September 1, 1986): 511–20. http://dx.doi.org/10.2118/12277-pa.

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10

Hou, Jiangyong, Meilan Qiu, Xiaoming He, Chaohua Guo, Mingzhen Wei, and Baojun Bai. "A Dual-Porosity-Stokes Model and Finite Element Method for Coupling Dual-Porosity Flow and Free Flow." SIAM Journal on Scientific Computing 38, no. 5 (January 2016): B710—B739. http://dx.doi.org/10.1137/15m1044072.

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11

LI, Xia, Wenzhi ZHAO, Cancan ZHOU, Tongshan WANG, and Chaoliu LI. "Dual-porosity saturation model of low-porosity and low-permeability clastic reservoirs." Petroleum Exploration and Development 39, no. 1 (February 2012): 88–98. http://dx.doi.org/10.1016/s1876-3804(12)60019-6.

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12

Denney, Dennis. "Transient Dual-Porosity Behavior for Horizontal Wells." Journal of Petroleum Technology 54, no. 02 (February 1, 2002): 64. http://dx.doi.org/10.2118/0202-0064-jpt.

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13

Bai, M. "On equivalence of dual-porosity poroelastic parameters." Journal of Geophysical Research: Solid Earth 104, B5 (May 10, 1999): 10461–66. http://dx.doi.org/10.1029/1999jb900072.

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14

Elsworth, Derek, and Mao Bai. "Flow‐Deformation Response of Dual‐Porosity Media." Journal of Geotechnical Engineering 118, no. 1 (January 1992): 107–24. http://dx.doi.org/10.1061/(asce)0733-9410(1992)118:1(107).

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15

Futaba, Don N., Koji Miyake, Kazuhiro Murata, Yuhei Hayamizu, Takeo Yamada, Shinya Sasaki, Motoo Yumura, and Kenji Hata. "Dual Porosity Single-Walled Carbon Nanotube Material." Nano Letters 9, no. 9 (September 9, 2009): 3302–7. http://dx.doi.org/10.1021/nl901581t.

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16

Zhang, Jincai, Mao Bai, and J. C. Roegiers. "Dual-porosity poroelastic analyses of wellbore stability." International Journal of Rock Mechanics and Mining Sciences 40, no. 4 (June 2003): 473–83. http://dx.doi.org/10.1016/s1365-1609(03)00019-4.

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17

Elsworth, D., and M. Bai. "Flow-deformation response of dual-porosity media." International Journal of Rock Mechanics and Mining Sciences & Geomechanics Abstracts 29, no. 4 (July 1992): 239–40. http://dx.doi.org/10.1016/0148-9062(92)90790-7.

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18

Benavente, D., J. Martínez-Martínez, N. Cueto, and M. A. García-del-Cura. "Salt weathering in dual-porosity building dolostones." Engineering Geology 94, no. 3-4 (November 2007): 215–26. http://dx.doi.org/10.1016/j.enggeo.2007.08.003.

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19

Hulin, Claudie, and Lionel Mercury. "Capillarity-driven supersolubility in dual-porosity systems." Geochimica et Cosmochimica Acta 252 (May 2019): 144–58. http://dx.doi.org/10.1016/j.gca.2019.02.026.

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20

Zaman, M., J. Cao, M. Bai, and J. C. Roegiers. "Modeling flow in heterogeneous dual-porosity media." International Journal of Rock Mechanics and Mining Sciences 35, no. 4-5 (June 1998): 473. http://dx.doi.org/10.1016/s0148-9062(98)00073-4.

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21

Truswell, William H. "Dual-Porosity Expanded Polytetrafluoroethylene Soft Tissue Implant." Archives of Facial Plastic Surgery 4, no. 2 (April 1, 2002): 92–97. http://dx.doi.org/10.1001/archfaci.4.2.92.

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22

Bai, M., Q. Ma, and J. C. Roegiers. "Dual-porosity behaviour of naturally fractured reservoirs." International Journal for Numerical and Analytical Methods in Geomechanics 18, no. 6 (June 1994): 359–76. http://dx.doi.org/10.1002/nag.1610180602.

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23

Liu, Min, and Peyman Mostaghimi. "Reactive transport modelling in dual porosity media." Chemical Engineering Science 190 (November 2018): 436–42. http://dx.doi.org/10.1016/j.ces.2018.06.005.

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24

Wang, Yong, Fu Rong Wang, Shun Chu Li, and Dong Dong Gui. "Similar Structure of Solution for Effective Wellbore Radius Model in the Spherical-Shaped Matrix of Dual-Porosity Reservoir." Advanced Materials Research 868 (December 2013): 686–91. http://dx.doi.org/10.4028/www.scientific.net/amr.868.686.

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On the basis of percolation mechanism for dual-porosity, an effective wellbore radius model in the dual-porosity was established, and the Laplace space solution could be obtained by solving this model. The solution had a similar structure and could be simplified into a unified expression in the different outer boundary conditions. The solution with a similar structure can avoid the complex calculations, it is beneficial to analyze the influence of various parameters on the solution in the dual-porosity model, and facilitate to master and use by engineering technicians.

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25

Liu, Chao, and Dung T. Phan. "Poroelastodynamic responses of a dual-porosity dual-permeability material under harmonic loading." Partial Differential Equations in Applied Mathematics 4 (December 2021): 100074. http://dx.doi.org/10.1016/j.padiff.2021.100074.

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26

Li, Daolun, Wenshu Zha, Dewen Zheng, Longjun Zhang, and Detang Lu. "Effect of Matrix-Wellbore Flow and Porosity on Pressure Transient Response in Shale Formation Modeling by Dual Porosity and Dual Permeability System." Journal of Chemistry 2015 (2015): 1–9. http://dx.doi.org/10.1155/2015/426860.

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A mathematical dual porosity and dual permeability numerical model based on perpendicular bisection (PEBI) grid is developed to describe gas flow behaviors in shale-gas reservoirs by incorporating slippage corrected permeability and adsorbed gas effect. Parametric studies are conducted for a horizontal well with multiple infinite conductivity hydraulic fractures in shale-gas reservoir to investigate effect of matrix-wellbore flow, natural fracture porosity, and matrix porosity. We find that the ratio of fracture permeability to matrix permeability approximately decides the bottom hole pressure (BHP) error caused by omitting the flow between matrix and wellbore and that the effect of matrix porosity on BHP is related to adsorption gas content. When adsorbed gas accounts for large proportion of the total gas storage in shale formation, matrix porosity only has a very small effect on BHP. Otherwise, it has obvious influence. This paper can help us understand the complex pressure transient response due to existence of the adsorbed gas and help petroleum engineers to interpret the field data better.

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27

Yeargin, Ryan, Rob Ramey, and Cindy Waters. "Porosity Analysis in Porous Brass Using Dual Approaches." American Journal of Engineering and Applied Sciences 9, no. 1 (January 1, 2016): 91–97. http://dx.doi.org/10.3844/ajeassp.2016.91.97.

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28

Jahović, Ilma, You-Quan Zou, Simone Adorinni, Jonathan R. Nitschke, and Silvia Marchesan. "Cages meet gels: Smart materials with dual porosity." Matter 4, no. 7 (July 2021): 2123–40. http://dx.doi.org/10.1016/j.matt.2021.04.018.

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29

Williams, Stuart K., Vangie B. Patula, Leigh B. Kleinert, Paul Martakos, John P. Lane, and Ted Karwoski. "Dual Porosity Expanded Polytetrafluoroethylene for Soft-Tissue Augmentation." Plastic and Reconstructive Surgery 115, no. 7 (June 2005): 1995–2006. http://dx.doi.org/10.1097/01.prs.0000163324.17001.e3.

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30

Glubokovskikh, Stanislav, Boris Gurevich, and Nishank Saxena. "A dual-porosity scheme for fluid/solid substitution." Geophysical Prospecting 64, no. 4 (May 24, 2016): 1112–21. http://dx.doi.org/10.1111/1365-2478.12389.

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31

Dykhuizen, R. C. "A new coupling term for dual-porosity models." Water Resources Research 26, no. 2 (February 1990): 351–56. http://dx.doi.org/10.1029/wr026i002p00351.

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32

Firoozabadi, Abbas, and L. Kent Thomas. "Sixth SPE Comparative Solution Project: Dual-Porosity Simulators." Journal of Petroleum Technology 42, no. 06 (June 1, 1990): 710–63. http://dx.doi.org/10.2118/18741-pa.

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33

Kozlov, Evgenii. "Seismic signature of a permeable, dual-porosity layer." GEOPHYSICS 72, no. 5 (September 2007): SM281—SM291. http://dx.doi.org/10.1190/1.2763954.

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Of the key reservoir properties, permeability seems to be the most elusive. Since the middle of the 90s, various seismic attributes have been proposed to map permeability by using detailed analysis of the frequency content of reflected wavetrains. Some attributes are expected to show a relative increase of high-frequency content with increased permeability; other attributes assume the opposite. Actually, both these trends were observed. A possible explanation of these observations is here derived from an effective model of a permeable dual-porosity layer enclosed by impermeable rocks. For such a model, the reflected wavetrain can be regarded as a sum of three components, one of which is related to acoustic-impedance contrasts, another to extra compliance caused by P-wave-induced fluid flows between fractures and intergranular pores with a high aspect ratio, and a third to the fluid-flow-induced, inelastic attenuation. In layered reservoirs, all the components tend to be frequency dependent, and the well-known dependence of the first component on the reflecting-layer thickness may strongly dominate the effects of permeability. Hence, predicting the behavior of a permeability attribute in a particular environment requires a modeling formalism that can be called permeability substitution by analogy with the widely used fluid-substitution technique.

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34

Markicevic, B., and T. D. Papathanasiou. "The Hydraulic Permeability of Dual Porosity Fibrous Media." Journal of Reinforced Plastics and Composites 20, no. 10 (July 2001): 871–80. http://dx.doi.org/10.1177/073168401772678977.

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35

Bai, M., Y. Abousleiman, L. Cui, and J. Zhang. "Dual-porosity poroelastic modeling of generalized plane strain." International Journal of Rock Mechanics and Mining Sciences 36, no. 8 (December 1999): 1087–94. http://dx.doi.org/10.1016/s1365-1609(99)00065-9.

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36

Boutin, C., P. Royer, and J. L. Auriault. "Acoustic absorption of porous surfacing with dual porosity." International Journal of Solids and Structures 35, no. 34-35 (December 1998): 4709–37. http://dx.doi.org/10.1016/s0020-7683(98)00091-2.

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37

Zhao, Ying, and Mian Chen. "Fully coupled dual-porosity model for anisotropic formations." International Journal of Rock Mechanics and Mining Sciences 43, no. 7 (October 2006): 1128–33. http://dx.doi.org/10.1016/j.ijrmms.2006.03.001.

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38

Markicevic, B., and T. D. Papathanasiou. "The Hydraulic Permeability of Dual Porosity Fibrous Media." Journal of Reinforced Plastics and Composites 20, no. 10 (July 2001): 871–80. http://dx.doi.org/10.1177/15307964-01020010-05.

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39

Dykhuizen, R. C. "A new coupling term for dual porosity models." Water Resources Research 26, no. 2 (1990): 351–56. http://dx.doi.org/10.1029/89wr02796.

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40

Duan, Yong-Gang, Ke-Yi Ren, Quan-Tang Fang, Ming-Qiang Wei, Morteza Dejam, and Wei-Hua Chen. "Pressure Transient Analysis for a Horizontal Well in Heterogeneous Carbonate Reservoirs Using a Linear Composite Model." Mathematical Problems in Engineering 2020 (February 24, 2020): 1–16. http://dx.doi.org/10.1155/2020/3267458.

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Carbonate reservoirs usually have strong anisotropy. Oil and gas recovery from fractured reservoirs is highly challenging due to complicated mechanisms involved in production from these reservoirs. A horizontal well completed in these reservoirs may extend through multiple zones, including homogeneous, dual-porosity, and triple-porosity formations. Traditional well test models assume that the entire length of a horizontal or multilateral well remains in the same formation with uniform properties. A well test model for pressure transient analysis of horizontal wells extending through a carbonate reservoir consisting of natural fractures, rock matrix, and vugs with different properties is presented in this study. The focus of this study is on dual-porosity (fracture-matrix) and triple-porosity (fracture-matrix-vug) reservoirs, considering the pseudosteady interporosity flows from rock matrix and vugs into fractures. A multizone triple-porosity model was established and solved by using the point source function, Green’s function, and coupling of multiple reservoir sections. The corresponding type curves were developed, and sensitivity analysis was carried out. The type curves of flow stage division reveal that a horizontal well traversing a three-section reservoir including homogeneous, dual-porosity (fracture-matrix)/triple-porosity (fracture-vug-matrix), and homogeneous sections identifies the stages of pseudosteady interporosity flow from matrix and vug into fracture, fracture pseudoradial flow, system linear flow, system pseudoradial flow, and pseudosteady flow occur in sequence. The greater the difference of permeability between the dual-porosity/triple-porosity section and the two homogeneous sections, the more obvious the interporosity flow on the pressure derivative curve. This approach satisfies the need for pressure transient analysis for a horizontal well that traverses two or more regions with distinct properties in heterogeneous carbonate reservoirs.

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41

Liu, Chao, Amin Mehrabian, and Younane N. Abousleiman. "Poroelastic Dual-Porosity/Dual-Permeability After-Closure Pressure-Curves Analysis in Hydraulic Fracturing." SPE Journal 22, no. 01 (June 28, 2016): 198–218. http://dx.doi.org/10.2118/181748-pa.

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Summary The dual-porosity and dual-permeability theory of poroelasticity is used to analyze the wellbore dual-pressure responses of dual-porosity or naturally fractured formations. The pressure decline is analyzed by modeling the dual-pressure regimes of the dual-porosity/dual-permeability medium during the after-closure phase of hydraulic fracturing. The analysis shows that both the matrix and natural-fracture permeability, as well as the developed-fracture length, can be estimated on the basis of the obtained pseudolinear and pseudoradial dual-pressure and dual-flow regimes. The estimations are made by use of the corresponding one-half and −1 slopes in the time-history plots of the wellbore-pressure derivative. The transition period between pseudolinear and pseudoradial regimes is also analyzed. The solution involves three time scales related to the rate of fluid flow through and in between the matrix and fractures network. Findings indicate the possible emergence of an additional −½ slope in the log-log pressure-derivative plot of low-permeability shale formations. It is further shown that the transient-pressure response of the formation could be calibrated by incorporating an appropriate interporosity flow coefficient as a measure of the linear-fluid-exchange capacity between the matrix and fracture porosities. The analytical expressions for the time markers of the upper limit for the pseudolinear regime, lower limit for the pseudoradial regime, and the time at which the dip bases occur in pressure-derivative curves are given to estimate this parameter. The solution is successfully applied to and matched with a published set of field data to provide estimations for the associated reservoir properties. The field-data analysis is elaborated by a corresponding sensitivity analysis, through which the prominent poroelastic parameters of the solution are determined. Last, the definitions of conventional key parameters attributed to solutions of this type, such as formation total compressibility, storage coefficients, and hydraulic diffusivity, are reformulated by use of the presented dual-porosity poroelastic approach to the problem.

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42

Shahin, Alireza, Michael T. Myers, and Lori A. Hathon. "Borehole Geophysical Joint Inversion to Fully Evaluate Shaly Sandstone Formations." Applied Sciences 12, no. 3 (January 25, 2022): 1255. http://dx.doi.org/10.3390/app12031255.

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Simultaneous inversion of sonic, density, and electrical resistivity borehole-derived well logs, has been addressed in literature in recent years. However, this problem is not broadly studied for dual-porosity sandstone formations. In addition, most authors presumed salinity and matrix properties as known parameters in their studies. We integrate the conservation of mass to model density, a differential effective medium theory for elastic modeling, and a laboratory-supported model for electrical resistivity of dual-porosity sandstones. Utilizing this methodology, we simulate electrical resistivity, sonic, and density well-log data. We develop a stochastic global search engine to jointly invert petrophysical properties. We build a dual-porosity formation with associated petrophysical properties and show the proposed workflow accurately replicates true well-log responses in the oil column, water leg, and transition zone. Local petrophysical properties (microporosity, intergranular porosity, total porosity, and water saturation) and global model parameters (salinity, matrix properties, critical porosity, resistivity lithology exponents, and sonic length scales for different pore networks) are all well recovered. The developed multiphysics calibrated rock models will assist petrophysicists and seismic analysts to identify and distinguish sandstone facies characteristics from well-log and prestack seismic data.

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43

Deng, Ya, Rui Guo, Zhongyuan Tian, Cong Xiao, Haiying Han, and Wenhao Tan. "Productivity Model for Shale Gas Reservoir with Comprehensive Consideration of Multi-mechanisms." Open Petroleum Engineering Journal 8, no. 1 (July 31, 2015): 235–47. http://dx.doi.org/10.2174/1874834101508010235.

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Multi-stage fracturing horizontal well currently has been proved to be the most effective method to produce shale gas. This method can activate the natural fractures system defined as stimulated reservoir volume (SRV), the remaining region similarly is defined as un-stimulated reservoir volume (USRV). At present, no type curves have been developed for hydraulic fractured shale gas reservoirs in which the SRV zone has triple-porosity dual-depletion flow behavior and the USRV zone has double porosity flow behavior. In this paper, the SRV zone and USRV zone respectively are simplified as cubic triple-porosity and slab dual porosity media. We have established a new productivity model for multifractured horizontal well shale gas with Comprehensive consideration of desorption, diffusion, viscous flow, stress sensitivity and dual-depletion mechanism in matrix. The rate transient responses are inverted into real time space with stehfest numerical inversion algorithm. Type curves are plotted, and different flow regimes in shale gas reservoirs are identified. Effects of relevant parameters are analyzed as well. The whole flow period can be divided into 8 regimes: bilinear flow in SRV; pseudo elliptic flow; dual inter-porosity flow; transitional flow; linear flow in USRV; inter-porosity flow and boundary-dominated flow. The stress sensitivity basically has negative influence on the whole productivity period .The less the value of Langmuir volume and the lager the value of Langmuir pressure, the more lately the inter-porosity flow and boundary-dominated flow occurs. It in concluded that the USRV zone has positive influence on production and could not be ignored.

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44

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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45

Shahin, Alireza, Mike Myers, and Lori Hathon. "Global optimization to retrieve borehole-derived petrophysical properties of carbonates." GEOPHYSICS 85, no. 3 (May 1, 2020): D75—D82. http://dx.doi.org/10.1190/geo2018-0863.1.

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Joint modeling and inversion of frequency-dependent dielectric constant and electrical resistivity well-log measurements has been addressed in literature in recent years. However, this problem is not studied for dual-porosity carbonate formations. Besides, the salinity and matrix dielectric constant are presumed to be known in previous studies. We have combined a model for brine dielectric constant and two laboratory-supported models for the electrical resistivity and dielectric constant of dual-porosity carbonates. Using this methodology, we replicate electrical resistivity and dielectric well-log measurements. Using a stochastic global optimization algorithm, we formulate a joint inversion workflow to estimate petrophysical properties of interest. For a constructed dual-porosity carbonate reservoir, we determine that the inversion workflow matches the forward-modeled data for the oil column, water column, and transition zone. We also found that our inversion workflow is capable to retrieve local model parameters (water-filled intergranular porosity and water-filled vuggy porosity) and global model parameters (matrix dielectric constant, lithology exponents for intergranular and vuggy pores, and salinity) with reasonable accuracy.

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46

Chen, Jing, Xinmin Song, Baozhu Li, Wuguang Li, Changlin Liao, and Lei Yang. "Mathematical Simulation about Gas Transport in a Dual-Porosity Tight Gas Reservoir considering Multiple Effects." Geofluids 2021 (August 5, 2021): 1–7. http://dx.doi.org/10.1155/2021/7483445.

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Threshold pressure gradient, gas slippage, and stress sensitivity have important effects on the production of a tight gas reservoir. But previous studies only focused on one or two of these effects. In this study, a mathematical model considering these three effects was established to describe gas transport in a dual-porosity tight gas reservoir. Threshold pressure gradient, gas slippage, and stress sensitivity are simultaneously considered in the velocity term of continuity equation which is mainly different from the previous research results. The partial differential equation and definite solution condition are discretized by a central difference method. A finite difference procedure was compiled and applied to solve this numerical model and predict the productivity of a production well in a dual-porosity tight gas reservoir. The difference between the predicted and tested cumulative production is less than 10%, which indicates that the proposed mathematical model can be used to describe the characteristics of gas flow in the dual-porosity tight gas reservoir. Then, gas productivity of five different scenarios considering these effects was compared. Results show that both stress sensitivity and threshold pressure gradient are negatively correlated with gas production, while gas slippage is positively correlated with gas production. Among them, stress sensitivity has the greatest impact on the production of a dual-porosity tight gas reservoir. Overall, these three effects have great influence on the development of the dual-porosity tight gas reservoir, which should be considered in the production prediction.

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Geiger, S., M. Dentz, and I. Neuweiler. "A Novel Multirate Dual-Porosity Model for Improved Simulation of Fractured and Multiporosity Reservoirs." SPE Journal 18, no. 04 (May 27, 2013): 670–84. http://dx.doi.org/10.2118/148130-pa.

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Summary A major part of the world's remaining oil reserves is in fractured carbonate reservoirs, which are dual-porosity (fracture-matrix) or multiporosity (fracture/vug/matrix) in nature. Fractured reservoirs suffer from poor recovery, high water cut, and generally low performance. They are modeled commonly by use of a dual-porosity approach, which assumes that the high-permeability fractures are mobile and low-permeability matrix is immobile. A single transfer function models the rate at which hydrocarbons migrate from the matrix into the fractures. As shown in many numerical, laboratory, and field experiments, a wide range of transfer rates occurs between the immobile matrix and mobile fractures. These arise, for example, from the different sizes of matrix blocks (yielding a distribution of shape factors), different porosity types, or the inhomogeneous distribution of saturations in the matrix blocks. Thus, accurate models are needed that capture all the transfer rates between immobile matrix and mobile fracture domains, particularly to predict late-time recovery more reliably when the water cut is already high. In this work, we propose a novel multi-rate mass-transfer (MRMT) model for two-phase flow, which accounts for viscous-dominated flow in the fracture domain and capillary flow in the matrix domain. It extends the classical (i.e., single-rate) dual-porosity model to allow us to simulate the wide range of transfer rates occurring in naturally fractured multiporosity rocks. We demonstrate, by use of numerical simulations of waterflooding in naturally fractured rock masses at the gridblock scale, that our MRMT model matches the observed recovery curves more accurately compared with the classical dual-porosity model. We further discuss how our multi-rate dual-porosity model can be parameterized in a predictive manner and how the model could be used to complement traditional commercial reservoir-simulation workflows.

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Xu, Bingxiang, Manouchehr Haghighi, and D. Cooke. "Simulation and history matching of a shale gas reservoir using different models in Eagle Ford Basin." APPEA Journal 52, no. 2 (2012): 648. http://dx.doi.org/10.1071/aj11062.

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Eagle Ford Shale in South Texas is one of the recent shale play in the US, which began developing in late 2008. To evaluate the reservoir performance and make the production forecasting for this reservoir, one multi-stage fractured horizontal well was modelled and history matching was done using the available 250 days of production data. Two different flow models of dual-porosity and multi-porosity have been examined. In the multi-porosity model, both approaches of instant and time-dependent sorption have been investigated. Also, two approaches of negative skin and transverse fractures were used to model the effect of hydraulic fracturing. For history matching of early production data, all the models were successfully matched; however, all models predict differently for production forecasting. Comparing both production forecasts for 10 years, the multi-porosity model forecasts 14% more than dual-porosity model. This is because in the dual-porosity model, only free porosity is considered and no adsorbed gas in micro-pores is assumed; in multi-porosity model, both macro and micro porosities are active in shale gas reservoir. It is concluded that the early production data is not reliable to validate the simulation and make the production forecasting. This is because in early production data, all gas are produced from the fracture system and the matrix contribution is not significant or it has not been started yet. Furthermore, the effect of matrix sub-division on the simulation was studied: the free gas in matrix can contribute to production more quickly when matrix sub-cells increase.

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Li, Mengmeng, Gang Bi, Jie Zhan, Liangbin Dou, and Hailong Xu. "A Semianalytical Two-Phase Imbibition Model in Dual-Porosity and Dual-Permeability Reservoirs." Geofluids 2021 (April 5, 2021): 1–14. http://dx.doi.org/10.1155/2021/5589936.

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The pressure transient behavior of water injection well has been extensively investigated under single-phase flow conditions. However, when water is injected into formation, there are saturation gradients within the water flooded area. Additionally, water imbibition is essentially important for oil displacement in dual-porosity and dual-permeability (DPDP) reservoirs. In this work, a novel semianalytical two-phase flow DPDP well test model considering both saturation gradient and water imbibition has been developed. The model was solved by the Laplace transform finite difference method. Type curves were generated, and flow regimes were identified by the model. The model features and effect of parameters were analyzed. Results show that water imbibition reduces the advancing speed of water drive front in the fracture system and slows down the water cut raising rate and the expansion speed of the two-phase zone in the fracture system. Therefore, the fluid exchange between the fracture and matrix systems becomes more sufficient and more oil will be recovered from the DPDP reservoir. The shape of pressure curves is similar for the single-phase and two-phase flow DPDP model, but the position of the proposed model is above the curves of the single-phase model. Shape factor mainly influences the interporosity period of the pressure derivatives. Water imbibition has a major effect on the whole system radial flow period of the curves. The findings of this study can help for better understanding of the oil/water two-phase flow pressure transient behavior in DPDP reservoirs considering saturation gradients and water imbibition.

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Choi, E. S., T. Cheema, and M. R. Islam. "A new dual-porosity/dual-permeability model with non-Darcian flow through fractures." Journal of Petroleum Science and Engineering 17, no. 3-4 (May 1997): 331–44. http://dx.doi.org/10.1016/s0920-4105(96)00050-2.

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