scholarly journals The water retention curve and relative permeability for gas production from hydrate-bearing sediments: pore-network model simulation

2016 ◽  
Vol 17 (8) ◽  
pp. 3099-3110 ◽  
Author(s):  
Nariman Mahabadi ◽  
Sheng Dai ◽  
Yongkoo Seol ◽  
Tae Sup Yun ◽  
Jaewon Jang
Keyword(s):  
Network Model ◽  
Relative Permeability ◽  
Water Retention ◽  
Model Simulation ◽  
Pore Network ◽  
Gas Production ◽  
Water Retention Curve ◽  
Pore Network Model ◽  
Retention Curve ◽  
Hydrate Bearing Sediments

A Pore-Network-Modeling Approach To Predict Petrophysical Properties of Diatomaceous Reservoir Rock

2007 ◽  
Vol 10 (06) ◽  
pp. 597-608 ◽  
Author(s):  
Liping Jia ◽  
Cynthia Marie Ross ◽  
Anthony Robert Kovscek
Keyword(s):  
Multiphase Flow ◽  
Capillary Pressure ◽  
Network Model ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Pore Network ◽  
Reservoir Rock ◽  
Pore Network Model ◽  
Rock Types ◽  
Capillary Pressure Curves

Summary A 3D pore-network model of two-phase flow was developed to compute permeability, relative permeability, and capillary pressure curves from pore-type, -size, and -shape information measured by means of high-resolution image analysis of diatomaceous-reservoir-rock samples. The diatomite model is constructed using pore-type proportions obtained from image analysis of epoxy-impregnated polished samples and mercury-injection capillary pressure curves for diatomite cores. Multiple pore types are measured, and each pore type has a unique pore-size and throat-size distribution that is incorporated in the model. Network results present acceptable agreement when compared to experimental measurements of relative permeability. The pore-network model is applicable to both drainage and imbibition within diatomaceous reservoir rock. Correlation of network-model results to well log data is discussed, thereby interpolating limited experimental results across the entire reservoir column. Importantly, our method has potential to predict the petrophysical properties for reservoir rocks with either limited core material or those for which conventional experimental measurements are difficult, unsuitable, or expensive. Introduction Model generation for reservoir simulation requires accurate entering of physical properties such as porosity, permeability, initial water saturation, residual-oil saturation, capillary pressure functions, and relative permeability curves. These functions and parameters are necessary to estimate production rate and ultimate oil recovery, and thereby optimize reservoir development. Accurate measurement and representation of such information is, therefore, essential for reservoir modeling. Relative permeability and capillary pressure curves are the most important constitutive relations to represent multiphase flow. Often, it is difficult to sample experimentally the range of relevant multiphase-flow behavior of a reservoir. In addition to the availability of rock samples, measurements are frequently time consuming to conduct, and conventional techniques are not suitable for all rock types (Schembre and Kovscek 2003). It is impossible, therefore, to measure all the unique relative permeability functions of different reservoir-rock types and variations within a rock type. This lack of constitutive information limits the accuracy of reservoir simulators to predict oil recovery. Simply put, other available data must be queried for their relevance to multiphase flow and must be used to interpret the available relative permeability and capillary pressure information.

scholarly journals Water retention curve for hydrate-bearing sediments

2013 ◽  
Vol 40 (21) ◽  
pp. 5637-5641 ◽  
Author(s):  
Sheng Dai ◽  
J. Carlos Santamarina
Keyword(s):  
Water Retention ◽  
Water Retention Curve ◽  
Retention Curve ◽  
Hydrate Bearing Sediments

scholarly journals Microscale Evaluation of Tight Oil Mobility: Insights from Pore Network Simulation

Energies ◽  
2021 ◽  
Vol 14 (15) ◽  
pp. 4580
Author(s):  
Yongchao Wang ◽  
Yanqing Xia ◽  
Zihui Feng ◽  
Hongmei Shao ◽  
Junli Qiu ◽  
...  
Keyword(s):  
Organic Matter ◽  
Computerized Tomography ◽  
Network Model ◽  
Relative Permeability ◽  
Water Saturation ◽  
Organic Matter Content ◽  
Pore Network ◽  
Matter Content ◽  
Water Phase ◽  
Pore Network Model

Pore network modeling based on digital rock is employed to evaluate the mobility of shale oil in Qingshankou Formation, Songliao Basin, China. Computerized tomography technology is adopted in this work to reconstruct the digital rock of shale core. The pore network model is generated based on the computerized tomography data. We simulate the dynamics of fluid flow in a pore network model to evaluate the mobility of fluid in shale formation. The results show that the relative permeability of oil phase increases slowly in the initial stage of the displacement process, which is mainly caused by the poor continuity of the oil phase. In the later stages, with the increase in the oil phase continuity, the range of relative permeability increases. With the increase of organic matter content, the permeability of the water phase remains unchanged at low water saturation, but gradually increases at high water saturation. At the same time, it can be seen that, with the increase in organic matter content, the isosmotic point of the oil–water phase permeability shifts to the left, indicating that the wettability to water phase gradually weakens.

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