Interpretation of Gas/Water Relative Permeability of Coal Using the Hybrid Bayesian-Assisted History Matching: New Insights

Zhang, Jiyuan; Zhang, Bin; Xu, Shiqian; Feng, Qihong; Zhang, Xianmin; Elsworth, Derek

doi:10.3390/en14030626

Cited by 9 publications

(7 citation statements)

References 62 publications

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“…The BADS algorithm is a fast, hybrid Bayesian optimization algorithm designed to solve difficult optimization problems, in particular related to fitting computational models. The BADS algorithm was first proposed by [23], which was then introduced by Zhang et al [29] to be used for estimating relative permeability of coal based on laboratory flooding test data. The BADS is a hybridization of the Bayesian optimization (BO) [30] and mesh adaptive direct search (MADS) [31] algorithms.…”

Section: Bads Algorithmmentioning

confidence: 99%

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Fast Assisted History Matching of Fractured Vertical Well in Coalbed Methane Reservoirs Using the Bayesian Adaptive Direct Searching Algorithm

2023

Processes

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The proper understanding of reservoir properties is an important step prior to forecasting fluid productions and deploying development strategies of a coalbed methane (CBM) reservoir. The assisted history matching (AHM) technique is a powerful technique that can derive reservoir properties based on production data, which however is usually rather time-consuming because hundreds or even thousands of numerical simulation runs are required before reasonable results can be obtained. This paper proposed the use of a newly developed algorithm, namely the Bayesian adaptive direct searching (BADS) algorithm, for assisting history matching of fractured vertical CBM wells to derive reservoir property values. The proposed method was applied on representative fractured vertical wells in the low-permeable CBM reservoirs in the Qinshui Basin, China. Results showed that the proposed method is capable of deriving reasonable estimates of key reservoir properties within a number of 50 numerical simulation runs, which is far more efficient than existing methods. The superiority of the BADS algorithm in terms of matching accuracy and robustness was highlighted by comparing with two commonly used algorithms, namely particle swarm optimization (PSO) and CMA-ES. The proposed method is a perspective in laboring manual efforts and accelerating the matching process while ensuring reasonable interpretation results.

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Section: Bads Algorithmmentioning

confidence: 99%

“…The BADS is a hybridization of the Bayesian optimization (BO) [30] and mesh adaptive direct search (MADS) [31] algorithms. The mathematical details of the BADS are available in references [23,29]. For the completeness of this paper, the basics of the BADS are briefly introduced as follows.…”

Section: Bads Algorithmmentioning

confidence: 99%

Fast Assisted History Matching of Fractured Vertical Well in Coalbed Methane Reservoirs Using the Bayesian Adaptive Direct Searching Algorithm

2023

Processes

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“…Permeability Correction with Water Saturation. The following supplementary equations for saturation and capillary pressure are necessary for solving the two-phase flow in a shale reservoir [60]:…”

Section: Competitive Adsorption In Organicmentioning

confidence: 99%

Two-Phase Flow Model for Numerical Investigation of Impact of Water Retention on Shale Gas Production

Fan

et al. 2021

Geofluids

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In this work, a triple-porosity, two-phase flow model was established to fill the knowledge gap of previous models focusing on gas production characteristics while ignoring the impacts of water injection. The proposed model considers the water flow in the fracture systems and clay minerals and the gas flow in the organic matter, inorganic pore, and fracture systems. The proposed model is solved using a finite element approach with COMSOL Multiphysics (Version 5.6) and verified with field data. Then, the evolutions of the intrinsic and relative permeabilities during water injection and gas production are examined. Furthermore, the impacts of water injection time and pressure are investigated. Good verification results are obtained; the goodness-of-fit value is 0.92, indicating that the proposed model can replicate both the water stimulation and the gas production stages. The relative gas permeability declines during water injection but recovers in the gas depletion stage. Furthermore, the intrinsic permeability increases during the water injection stage but decreases during the gas production stage. A higher water injection pressure and longer injection time would enlarge the intrinsic permeability, thus improving flow capacity. However, it would reduce gas relative permeability, thereby hindering gas flow. The shale gas production characteristic is controlled by the two abovementioned competing mechanisms. There exists a perfect combination of water injection pressure and injection time for achieving the maximum profitability of a shale gas well. This work can give a better understanding of the two-phase flow process in shale reservoirs and shed light on the field application of hydraulic fracturing.

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“…Most gas-containing reservoirs swell when the rock is immersed into the water, affecting the intrinsic permeability . Both the native formation water and injected water during the hydraulic fracturing process affect the degree of saturation and capillary pressure and in turn affect the relative permeability. , Gas and water relative permeability models have been widely studied, and two well-known relative permeability models were applicable. , While the impacts of water on the intrinsic permeability have been seldom examined.…”

Section: Introductionmentioning

confidence: 99%

Influence of Well Types on Optimizing the Co-production of Gas from Coal and Tight Formations

et al. 2022

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Co-production of gas from both coalbeds and tight formations is considered a viable means to improve well productivity. Most previous studies focused on the geology and resource estimates for gas production viability with little attention to the effectiveness of gas co-production with regard to well types. To make up for this weakness, a two-phase flow and reservoir deformation coupled model is proposed together with an anisotropic permeability model. The coupled model is first verified using gas and water production data from a vertical well from the Linxing block in the Ordos Basin, China. Then a reservoir model is built, including one coal seam and one tight gas formation separated by a low-permeability stratum with four simulation scenarios designed. Based on the results, the impacts of the crossflow between different reservoirs are addressed and the mechanisms of the gas co-production rate profile types observed in the Linxing block are analyzed. It is also found that high water-saturated adjacent reservoirs would keep the water relative permeability of the gas-rich reservoir at a high level, impeding the gas flow. The use of a horizontal well is strongly recommended when most gases are stored in a specific thin reservoir and the life of the well is short; however, a vertical well is favored when two or more gas-rich and high permeability reservoirs co-exist and the well life is relatively long. For the application of vertical wells, the hydraulic fractures should extend in the horizontal planes and interact with the pre-existing natural fracture. For horizontal wells, the hydraulic fracture should extend in the host reservoir and penetrate into the adjacent strata. This work can shed new light on the co-exploitation of coal measure methane.

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Interpretation of Gas/Water Relative Permeability of Coal Using the Hybrid Bayesian-Assisted History Matching: New Insights

Cited by 9 publications

References 62 publications

Fast Assisted History Matching of Fractured Vertical Well in Coalbed Methane Reservoirs Using the Bayesian Adaptive Direct Searching Algorithm

Fast Assisted History Matching of Fractured Vertical Well in Coalbed Methane Reservoirs Using the Bayesian Adaptive Direct Searching Algorithm

Two-Phase Flow Model for Numerical Investigation of Impact of Water Retention on Shale Gas Production

Influence of Well Types on Optimizing the Co-production of Gas from Coal and Tight Formations

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