Gas-condensate flow modelling for shale reservoirs.

Labed, Ismail; Oyeneyin, Babs; Oluyemi, Gbenga

Abstract

Condensate banking is the most challenging engineering problem in the development of gas-condensate reservoirs where the condensate accumulation can dramatically reduce the gas permeability resulting in impairment of wells productivity. An accurate assessment of condensate banking effect is important to predict well productivity and to diagnose well performance. Traditionally, Darcy law, combined with relative permeability models, has been used for modelling condensate banking effect in conventional reservoirs. This approach is also widely adopted in reservoir engineering commercial tools. However, for shale gas-condensate reservoirs, the gas flow deviates from Darcy flow to Knudsen flow due to the very small pore size in shale matrix (3-300 nm), compared to conventional reservoirs (10-200 'm). This gas flow is highly dependent on pore size distribution and reservoir pressure. In this paper, the effect of condensate saturation on Knudsen flow in shale matrix kerogen is investigated using a 3D pore network with a random pore size distribution. The Knudsen flow is incorporated at the pore level and gas permeability is evaluated for the whole network. In addition, the pore distribution effect in terms of log-normal mean and standard deviation is investigated. The concept of relative permeability in Darcy flow is extended to Knudsen flow by defining a new parameter called relative correction factor to evaluate the effect of condensate banking on Knudsen flow. This parameter can be employed directly in reservoir engineering tools. Simulation results showed that the relative correction factor is not only dependent on condensate saturation but also on pressure. This is due to the impact of pressure on the contribution of pore size ranges into the gas flow. In addition, results showed the effect of the pore size distribution where the standard deviation controls mainly the behaviour of Knudsen flow under condensate saturation. Disregarding this effect can lead to an overestimation of Knudsen flow contribution in well production under condensate banking effect

Citation

LABED, I., OYENEYIN, B. and OLUYEMI, G. 2018. Gas-condensate flow modelling for shale reservoirs. Journal of natural gas science and engineering [online], 59, pages 156-167. Available from: https://doi.org/10.1016/j.jngse.2018.08.015

• Journal Article Type: Article
• Acceptance Date: Aug 17, 2018
• Online Publication Date: Aug 24, 2018
• Publication Date: Nov 30, 2018
• Deposit Date: Aug 31, 2018
• Publicly Available Date: Aug 25, 2019
• Journal: Journal of Natural Gas Science and Engineering
• Print ISSN: 1875-5100
• Electronic ISSN: 2212-3865
• Publisher: Elsevier
• Peer Reviewed: Peer Reviewed
• Volume: 59
• Pages: 156-167
• DOI: https://doi.org/10.1016/j.jngse.2018.08.015
• Keywords: Gas condensate reservoirs; Parameter; Gas; Pore size; Condensate blockage; Well productivity
• Public URL: http://hdl.handle.net/10059/3101