Abstract

To successfully mitigate a near-wellbore condensate blockage, the status of the condensate blockage must be thoroughly understood. This case study proposes a new technique of pressure transient analysis (PTA) to investigate the formation and impact of condensate banking on well deliverability. This new PTA technique was successfully applied to the largest reservoir of the high-pressure high-temperature Hai Thach field, providing valuable information in designing mitigation programs. Finally, two mitigation methods (hydraulic fracturing and condensate bank removal) were investigated to evaluate their potential production enhancement.

The entire production history with many buildups was matched systematically and simultaneously by PTA to determine the skin factor evolution in addition to reservoir permeability. An increasing trend of skin factor confirmed the presence of condensate blockage in the near-wellbore area and provided information about the time required for the condensate bank to form. In addition, the size of the condensate blockage was obtained from the radius of the radial composite reservoir model. Finally, improvement on production rate by two mitigation methods was examined using typical skin factors achieved by these methods.

Two production wells from the main reservoir of Hai Thach field were selected for this study. From observed data, the gas rate of the first well reduced rapidly from 10 MMSCF/d to 4 MMSCF/d and the second well had a low stable rate of 3 MMSCF/d. The application of PTA revealed that skin factor of the first well dramatically increased from 0 to roughly 11 and similar behavior was also captured at the second well as this value increased from 0.5 to around 5. This upward trend of skin factor confirmed the presence of condensate blockage at near-wellbore regions of these wells and it took approximately 5 months to form the condensate bank. The radius of condensate bank was also determined at roughly 14 ft and the average permeability of these wells fall in the range of 0.2 to 0.5 mD. In addition, the mitigation analysis on two production wells showed that hydraulic fracturing and condensate bank removal methods could improve well production rate up to approximately 180% and 100%, respectively.

From conventional well testing techniques, it is challenging to obtain further information of condensate bank in a near-wellbore region. This case study proposes a novel application of PTA which successfully provided in-depth knowledge of condensate blockage, such as condensate bank size and formation time. This information is crucial in designing mitigation programs to improve recovery of affected wells. The potential enhancement on production rate from different condensate banking mitigation methods was also quantified, providing valuable information on the feasibility of such mitigation jobs.

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