Data-Driven Strategy Maximizes Condensate Recovery in Mature Field

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 224936, “Block 61 Condensate-Decline-Management Strategy,” by Rovshan Mollayev, Mohammed Al Harrasi, and Ruqia Al Shidhani, BP, et al. The paper has not been peer-reviewed. _ Block 61 is a gas field in southwest Oman. The Khazzan Phase 1 project was initiated in 2017; the Khazzan Phase 2 project began in 2020. The Phase 2 project initially targeted high condensate/gas ratio (CGR) wells. At the start of the project, large volumes of condensate were introduced, prompting operation of wells at higher production rates. However, these higher production rates were observed to cause high condensate decline. A structured evaluation program was launched to identify the optimal gas production rate per well, aiming to maximize cumulative condensate recovery while sustaining reservoir pressure. Introduction Because of the field’s significant gas reserves and strategic importance in meeting Oman’s domestic gas demand and export commitments, a phased development approach was adopted. Phase 1 focused on the northern part of the field, characterized by a low CGR and predominantly lower-productivity-index wells. In contrast, Phase 2 was designed to develop the southern part of the reservoir, which features a higher CGR and greater well productivity. The primary objective of Phase 2 was to increase the gas-export capacity of the block from 1 to 1.5 Bscf/D. With the commencement of Phase 2 production, a significant increase in condensate production was observed because of the higher CGR in the southern wells. This led to an operational inclination to produce wells at higher gas rates (20–30 MMscf/D) to maximize short-term condensate output. However, field observations indicated that these higher production rates resulted in an accelerated decline in CGR, raising concerns regarding long-term condensate recovery and reservoir management. While condensate is a byproduct in a predominantly gas-driven development, excessive condensate loss posed several challenges, including a reduction in estimated ultimate recovery (EUR) per well, a negative effect on cumulative condensate production per well, and potential acceleration of condensate banking. These concerns underscored the need for a structured engineering assessment to optimize well-operating conditions. The objective was to develop a robust well-operating workflow and strategy that could be applied systematically in field operations to balance short-term production targets with long-term reservoir performance. Methodology and Evaluation The engineering team initiated a comprehensive well-operating strategy assessment to determine optimal gas-production rates, ensuring a balance between short-term production gains and sustainable reservoir management. Given the complexities associated with tight gas reservoirs and condensate behavior, a multifaceted approach was adopted, incorporating reservoir simulations, well-testing operations, and historical production-data analysis. This methodology provided a robust framework for developing an effective condensate-decline-management strategy while maximizing overall hydrocarbon recovery.