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Dong Ma
Yangtze University, Jingzhou, China

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Original paper
Published: 30 January 2020 in Arabian Journal of Geosciences
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Spontaneous water imbibition is an important technique to enhance oil recovery in fractured reservoirs, but most existing models do not work well in some cases. Therefore for this reason, in paper, more better generalized recovery models for spontaneous imbibition, including the exponential recovery model and hyperbolic recovery model, were derived theoretically based on the Arp decline equation to find a suitable model. It was found that the proposed models could be reduced to the frequently used Aronofsky model, the Handy model, the Li-Horne model, and the Viksund model. In addition, a new exponential dimensionless time and new hyperbolic dimensionless time associated with initial decline rate were introduced and verified against experimental data from literatures. The fitting results demonstrated that both exponential dimensionless time and hyperbolic dimensionless time could successfully scale the experimental data in all the cases studied in this paper. And thus they were proposed as suitable ones for spontaneous water imbibition to oil recovery enhancement in fractured reservoirs.

ACS Style

Dong Ma; Jingyun Ouyang; Changwei Liu; Bhekumuzi Mgijimi Mahlalela. More generalized recovery models for spontaneous imbibition based on Arp decline equation. Arabian Journal of Geosciences 2020, 13, 1 -7.

AMA Style

Dong Ma, Jingyun Ouyang, Changwei Liu, Bhekumuzi Mgijimi Mahlalela. More generalized recovery models for spontaneous imbibition based on Arp decline equation. Arabian Journal of Geosciences. 2020; 13 (3):1-7.

Chicago/Turabian Style

Dong Ma; Jingyun Ouyang; Changwei Liu; Bhekumuzi Mgijimi Mahlalela. 2020. "More generalized recovery models for spontaneous imbibition based on Arp decline equation." Arabian Journal of Geosciences 13, no. 3: 1-7.

Journal article
Published: 21 December 2017 in Energies
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In north-west Jiangxi, China, most shale-gas exploration has been focused on the Lower Cambrian Hetang and Guanyintang formations, whereas the Upper Ordovician Xinkailing formation shale has been ignored for years due to heavy weathering. This study systematically analyzed gas source conditions, reservoir conditions and gas-bearing ability in order to reveal the shale-gas accumulation conditions of the Xinkailing formation. The results show that the Xinkailing formation is characterized by thick deposition of black shale (10–80 m), high organic content (with total organic carbon between 1.18% and 3.11%, on average greater than 2%), relatively moderate thermal evolution (with vitrinite reflectance between 2.83% and 3.21%), high brittle-mineral content (greater than 40%), abundant nanopores and micro-fractures, very good adsorption ability (adsorption content between 2.12 m3/t and 3.47 m3/t, on average about 2.50 m3/t), and strong sealing ability in the underlying and overlying layers, all of which favor the generation and accumulation of shale gas. The Wuning-Lixi and Jinkou-Zhelin areas of the Xinkailing formation were selected as the most realistic and favorable targets for shale-gas exploration and exploitation. In conclusion, the Wuning area has great potential and can provide a breakthrough in shale gas with further investigation.

ACS Style

Shangru Li; Li Zeng; Zhongpeng Wang; Jinchuan Zhang; Dong Ma. A New Insight into Shale-Gas Accumulation Conditions and Favorable Areas of the Xinkailing Formation in the Wuning Area, North-West Jiangxi, China. Energies 2017, 11, 12 .

AMA Style

Shangru Li, Li Zeng, Zhongpeng Wang, Jinchuan Zhang, Dong Ma. A New Insight into Shale-Gas Accumulation Conditions and Favorable Areas of the Xinkailing Formation in the Wuning Area, North-West Jiangxi, China. Energies. 2017; 11 (1):12.

Chicago/Turabian Style

Shangru Li; Li Zeng; Zhongpeng Wang; Jinchuan Zhang; Dong Ma. 2017. "A New Insight into Shale-Gas Accumulation Conditions and Favorable Areas of the Xinkailing Formation in the Wuning Area, North-West Jiangxi, China." Energies 11, no. 1: 12.

Journal article
Published: 17 August 2016 in Energies
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Static formation temperature (SFT) is required to determine the thermophysical properties and production parameters in geothermal and oil reservoirs. However, it is not easy to determine SFT by both experimental and physical methods. In this paper, a mathematical approach to predicting SFT, based on a new model describing the relationship between bottom hole temperature (BHT) and shut-in time, has been proposed. The unknown coefficients of the model were derived from the least squares fit by the particle swarm optimization (PSO) algorithm. Additionally, the ability to predict SFT using a few BHT data points (such as the first three, four, or five points of a data set) was evaluated. The accuracy of the proposed method to predict SFT was confirmed by a deviation percentage less than ±4% and a high regression coefficient R2 (>0.98). The proposed method could be used as a practical tool to predict SFT in both geothermal and oil wells.

ACS Style

Changwei Liu; Kewen Li; Youguang Chen; Lin Jia; Dong Ma. Static Formation Temperature Prediction Based on Bottom Hole Temperature. Energies 2016, 9, 646 .

AMA Style

Changwei Liu, Kewen Li, Youguang Chen, Lin Jia, Dong Ma. Static Formation Temperature Prediction Based on Bottom Hole Temperature. Energies. 2016; 9 (8):646.

Chicago/Turabian Style

Changwei Liu; Kewen Li; Youguang Chen; Lin Jia; Dong Ma. 2016. "Static Formation Temperature Prediction Based on Bottom Hole Temperature." Energies 9, no. 8: 646.

Journal article
Published: 01 May 2015 in Journal of Energy Resources Technology
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Relative permeability as an important petrophysical parameter is often measured directly in the laboratory or obtained indirectly from the capillary pressure data. However, the literature on relationship between relative permeability and resistivity is lacking. To this end, a new model of inferring two-phase relative permeability from resistivity index data was derived on the basis of Poiseuille's law and Darcy's law. The wetting phase tortuosity ratio was included in the proposed model. The relative permeabilities computed from the capillary pressure data, as well as the experimental data measured in gas–water and oil–water flow condition, were compared with the proposed model. Both results demonstrated that the two-phase permeability obtained by proposed model were generally in good agreement with the data computed from capillary pressure and measured in the laboratory. The comparison also showed that our model was much better than Li model at matching the relative permeability data.

ACS Style

Dong Ma; Changwei Liu; Changhui Cheng. New Relationship Between Resistivity Index and Relative Permeability. Journal of Energy Resources Technology 2015, 137, 032904 .

AMA Style

Dong Ma, Changwei Liu, Changhui Cheng. New Relationship Between Resistivity Index and Relative Permeability. Journal of Energy Resources Technology. 2015; 137 (3):032904.

Chicago/Turabian Style

Dong Ma; Changwei Liu; Changhui Cheng. 2015. "New Relationship Between Resistivity Index and Relative Permeability." Journal of Energy Resources Technology 137, no. 3: 032904.