Abstract

In the context of unconventional reservoir development, the issue of condensate banking–a factor contributing to reduced productivity in gas condensate reservoirs when the reservoir pressure falls below the dew point pressure–poses a constant concern. Prior to implementing any mitigation strategies, it is prudent to assess the potential occurrence of condensate banking in the future, based on the limited early production data. To address this, a specialized workflow was devised for a deep formation in the Permian Basin. This workflow aims to quantify the severity of condensate banking and subsequently optimize reservoir development strategies.

The integration of fracture and reservoir models has significantly enhanced the ability to accurately represent hydraulic fracturing conditions. The reservoir was subdivided into three distinct regions, fracture, stimulated rock volume (SRV), and matrix, each meticulously addressed through granular local grid refinement (LGR) cells. This precision allowed for an accurate depiction of pressure drop and, consequently, condensate dropout.

Through a comprehensive analysis involving fluid properties and reservoir simulations for condensate dropout and mobility across the three regions, the severity of condensate banking was quantified. Subsequent investigations into drawdown strategy optimization contribute to a refined approach for further optimizing reservoir development.

Condensate banking analysis: Condensate banking posed minimal concern in this context. The near-critical point fluid exhibited a milder condensate banking, due to the similarity of gas and oil mobilities. Moreover, the high contrast in permeability between fractures and matrix mitigated the condensate banking severity, as most pressure drops occurred around fractures, allowing the dropped condensate to be efficiently produced.

Gas condensate reservoir optimization: Development optimization primarily focuses on optimizing the flowback strategy. Following an investigation into the various drawdown strategies, the aggressive drawdown approach was found to accelerate production with minimal differences in estimated ultimate recovery (EUR). This provides further evidence that condensate banking has negligible impact.

Incorrectly estimating condensate banking severity could lead to decisions that adversely impact field development. The workflow developed reduced this risk by conducting an in-depth fluid-property analysis and reservoir simulation, specifically focusing on condensate dropout and mobility. The relationship between condensate banking and drawdown strategies was also investigated. All conclusions were subsequently validated through field observations. This comprehensive approach offers valuable guidance for the development of gas condensate fields in the deep formation of the Permian Basin.

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