Extending Well-Productivity Life in a High-Pressure/ High-Temperature Tight Gas/Condensate Carbonate Reservoir by Acid Refracturing
- Dennis Denney (JPT Senior Technology Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- June 2011
- Document Type
- Journal Paper
- 63 - 64
- 2011. Society of Petroleum Engineers
- 1 in the last 30 days
- 138 since 2007
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This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 142444, "Extending Well- Productivity Life by Acid Refracturing in a High-Pressure/High-Temperature Tight Gas/Condensate Carbonate Reservoir in a Jurassic Formation of Northern Kuwait," by Mir Kabir, SPE, Qasem Dashti, SPE, J.R. Singh, SPE, and San Prasad Pradhan, SPE, KOC, and Ikhsan Nugraha, SPE, Liu Hai, and Hamed Al-Ghadhban, Schlumberger, prepared for the 2011 SPE Middle East Unconventional Gas Conference and Exhibition, Muscat, Oman, 31 January- 2 February. The paper has not been peer reviewed.
Productivity of the subject well, which had been on production for 3 years after an initial acid-fracture treatment with almost 90% of its cumulative production occurring during the last year, was declining faster than expected. Review of the well’s performance indicated two possible causes: reservoir-pressure decline and reduced fracture-length/conductivity ratio. Acid refracturing was chosen to restore the well’s productivity by extending the fracture half-length to enhance fracture conductivity. The results showed that the productivity index (PI) increased by a factor of 2.5 during the post-treatment production test. However, after 3 months of production, this declined to 1.2.
Several major fields in north-ern Kuwait, including Sabriyah, Raudathain, Umm Niqqa, Bahra, and Dhabi, produce gas from the Jurassic Middle Marrat formation, an important carbonate reservoir. Typical depth is 14,000 ft, reservoir pressure ranges from 10,000 to 12,000 psi, and the bottomhole static temperature averages 275°F. The Middle Marrat formation is mostly limestone (calcite>90%) with minor dolomitization. Only traces of clay and silt are found. High heterogeneity, both laterally and vertically, has been reported. Core permeability matches log permeability, and the high permeability value obtained from the core could be the result of induced fractures. Pressure-transient analyses of some wells showed dual-porosity behavior with low matrix permeability. Generally, the absolute matrix permeability is less than 1 md. The production mechanism is a combination of matrix and natural-fracture permeability.
In regions where acid fracturing is common, there are questions that arise. When is the best time to refracture? What is the justification to repeat the treatment? If there is justification, what needs to be done differently in the subsequent treatment? The decision usually relies on the post-treatment production behavior compared with the pretreatment condition.
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