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Relevant bibliographies by topics / Gas condensate reservoirs. Gas condensate reservoirs

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Journal articles

Academic literature on the topic 'Gas condensate reservoirs. Gas condensate reservoirs'

Author: Grafiati

Published: 4 June 2021

Last updated: 7 February 2022

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Journal articles on the topic "Gas condensate reservoirs. Gas condensate reservoirs"

1

Chen, H. L., S. D. Wilson, and T. G. Monger-McClure. "Determination of Relative Permeability and Recovery for North Sea Gas-Condensate Reservoirs." SPE Reservoir Evaluation & Engineering 2, no. 04 (1999): 393–402. http://dx.doi.org/10.2118/57596-pa.

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Summary Coreflood experiments on gas condensate flow behavior were conducted for two North Sea gas condensate reservoirs. The objectives were to investigate the effects of rock and fluid characteristics on critical condensate saturation (CCS), gas and condensate relative permeabilities, hydrocarbon recovery and trapping by water injection, and incremental recovery by subsequent blowdown. Both CCS and relative permeability were sensitive to flow rate and interfacial tension. The results on gas relative permeability rate sensitivity suggest that gas productivity curtailed by condensate dropout c

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2

Hu, Wen Ge, Xiang Fang Li, Xin Zhou Yang, Ke Liu Wu, and Jun Tai Shi. "Energy Control in the Depletion of Gas Condensate Reservoirs with Different Permeabilities." Advanced Materials Research 616-618 (December 2012): 796–803. http://dx.doi.org/10.4028/www.scientific.net/amr.616-618.796.

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Energy control (i. e. pressure control) has an obvious effect on development effect in the depletion of gas condensate reservoir. Phase change behavior and characteristics of the relative pemeability in gas condensate reservoirs were displayed in this paper, then pressure and condensate distribution were showed through reservoir simulation. Finally, the influence of the pressure drop on condensate distribution and condensate oil production in gas condensate reservoirs with different permeabilities was studied. Results show that: First, in high / moderate permeability gas condensate reservoirs,

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3

Panja, Palash, and Milind Deo. "Factors That Control Condensate Production From Shales: Surrogate Reservoir Models and Uncertainty Analysis." SPE Reservoir Evaluation & Engineering 19, no. 01 (2015): 130–41. http://dx.doi.org/10.2118/179720-pa.

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Summary Rapid development of shales for the production of oils and condensates may not be permitting adequate analysis of the important factors governing recovery. Understanding the performance of shales or tight oil reservoirs producing condensates requires numerically extensive compositional simulations. The purpose of this study is to identify important factors that control production of condensates from low-permeability plays and to develop analytical “surrogate” models suitable for Monte Carlo analysis. In this study, the surrogate reservoir models were second-order response surfaces func

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4

Meng, Xingbang, Zhan Meng, Jixiang Ma, and Tengfei Wang. "Performance Evaluation of CO2 Huff-n-Puff Gas Injection in Shale Gas Condensate Reservoirs." Energies 12, no. 1 (2018): 42. http://dx.doi.org/10.3390/en12010042.

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When the reservoir pressure is decreased lower than the dew point pressure in shale gas condensate reservoirs, condensate would be formed in the formation. Condensate accumulation severely reduces the commercial production of shale gas condensate reservoirs. Seeking ways to mitigate condensate in the formation and enhance both condensate and gas recovery in shale reservoirs has important significance. Very few related studies have been done. In this paper, both experimental and numerical studies were conducted to evaluate the performance of CO2 huff-n-puff to enhance the condensate recovery in

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Shams, Bilal, Jun Yao, Kai Zhang, and Lei Zhang. "Sensitivity analysis and economic optimization studies of inverted five-spot gas cycling in gas condensate reservoir." Open Physics 15, no. 1 (2017): 525–35. http://dx.doi.org/10.1515/phys-2017-0060.

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AbstractGas condensate reservoirs usually exhibit complex flow behaviors because of propagation response of pressure drop from the wellbore into the reservoir. When reservoir pressure drops below the dew point in two phase flow of gas and condensate, the accumulation of large condensate amount occurs in the gas condensate reservoirs. Usually, the saturation of condensate accumulation in volumetric gas condensate reservoirs is lower than the critical condensate saturation that causes trapping of large amount of condensate in reservoir pores. Trapped condensate often is lost due to condensate ac

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6

Bilotu Onoabhagbe, Benedicta, Paul Russell, Johnson Ugwu, and Sina Rezaei Gomari. "Application of Phase Change Tracking Approach in Predicting Condensate Blockage in Tight, Low, and High Permeability Reservoirs." Energies 13, no. 24 (2020): 6551. http://dx.doi.org/10.3390/en13246551.

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Prediction of the timing and location of condensate build-up around the wellbore in gas condensate reservoirs is essential for the selection of appropriate methods for condensate recovery from these challenging reservoirs. The present work focuses on the use of a novel phase change tracking approach in monitoring the formation of condensate blockage in a gas condensate reservoir. The procedure entails the simulation of tight, low and high permeability reservoirs using global and local grid analysis in determining the size and timing of three common regions (Region 1, near wellbore; Region 2, c

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7

Hou, Dali, Yang Xiao, Yi Pan, Lei Sun, and Kai Li. "Experiment and Simulation Study on the Special Phase Behavior of Huachang Near-Critical Condensate Gas Reservoir Fluid." Journal of Chemistry 2016 (2016): 1–10. http://dx.doi.org/10.1155/2016/2742696.

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Due to the special phase behavior of near-critical fluid, the development approaches of near-critical condensate gas and near-critical volatile oil reservoirs differ from conventional oil and gas reservoirs. In the near-critical region, slightly reduced pressure may result in considerable change in gas and liquid composition since a large amount of gas or retrograde condensate liquid is generated. It is of significance to gain insight into the composition variation of near-critical reservoir during the depletion development. In our study, we performed a series ofPVTexperiments on a real near-c

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8

Ayala, Luis F., Turgay Ertekin, and Michael A. Adewumi. "Compositional Modeling of Retrograde Gas-Condensate Reservoirs in Multimechanistic Flow Domains." SPE Journal 11, no. 04 (2006): 480–87. http://dx.doi.org/10.2118/94856-pa.

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Summary A multimechanistic flow environment is the result of the combined action of a Darcian flow component (the macroscopic flow of the phase caused by pressure gradients) and a Fickian-like or diffusive flow component (diffusive flow caused by molecular concentration gradients) taking place in a hydrocarbon reservoir. The present work presents the framework needed for the assessment of the impact of multimechanistic flow on systems where complex fluid behavior—such as that of retrograde gas-condensate fluids—requires the implementation of compositional reservoir simulators. Because of the c

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9

Onoabhagbe, Gomari, Russell, Ugwu, and Ubogu. "Phase Change Tracking Approach to Predict Timing of Condensate Formation and its Distance from the Wellbore in Gas Condensate Reservoirs." Fluids 4, no. 2 (2019): 71. http://dx.doi.org/10.3390/fluids4020071.

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Production from gas condensate reservoir poses the major challenge of condensate banking or blockage. This occurs near the wellbore, around which a decline in pressure is initially observed. A good sign of condensate banking is a rise in the gas–oil ratio (GOR) during production and/or a decline in the condensate yield of the well, which leads to considerable reductions in well deliverability and well rate for gas condensate reservoirs. Therefore, determining the well deliverability of a gas condensate reservoir and methods to optimize productivity is paramount in the industry.

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10

Lopez Jimenez, Bruno A., and Roberto Aguilera. "Flow Units in Shale Condensate Reservoirs." SPE Reservoir Evaluation & Engineering 19, no. 03 (2016): 450–65. http://dx.doi.org/10.2118/178619-pa.

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Summary Recent work has shown that flow units characterized by process or delivery speed (the ratio of permeability to porosity) provide a continuum between conventional, tight-gas, shale-gas, tight-oil, and shale-oil reservoirs (Aguilera 2014). The link between the various hydrocarbon fluids is provided by the word “petroleum” in “Total Petroleum System” (TPS), which encompasses liquid and gas hydrocarbons found in conventional, tight, and shale reservoirs. The work also shows that, other things being equal, the smaller pores lead to smaller production rates. There is, however, a positive sid

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