Horizontal-Well Completions for Developing Low-Permeability Gas Reservoirs in a Complex Fluvial Deltaic Environment - A Case Study
- Dennis Denney (JPT Senior Technology Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- November 2009
- Document Type
- Journal Paper
- 53 - 54
- 2009. Society of Petroleum Engineers
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- 69 since 2007
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This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 116542, "Successful Application of Horizontal-Well Com pletions for Development of Low-Permeability Gas Reservoirs in a Complex Fluvial Deltaic Environment - A Case Study," by Chatib Hazman, Harry Alam, Shinta Damayanti, Andre Wijanarko, Zainal Arifin, R. Rahardjo, Heriadi Buhron, and Robert Nikijuluw, Virginia Indonesia Company; Gary J. Sable, ENI; and Ram K. Narayanan, Donn Schmohr, and Martin Rylance, BP plc, prepared for the 2008 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 20-22 October. The paper has not been peer reviewed.
Virginia Indonesia Company operates the Sanga-Sanga production-sharing contract (PSC) onshore at the Mahakam delta, East Kalimantan, Indonesia. The PSC has produced more than 70% of its estimated original gas in place. The fields are relatively mature, with the remaining gas resources in either pressure-depleted reservoirs or in low-permeability reservoirs for which conventional techniques have not been effective. A pilot development tested the use of horizontal completions.
The Sanga-Sanga PSC fields are in the Kutai basin. Hydrocarbon accumulations typically are within the Mid-Miocene upper-delta and delta-plain sandstone-reservoir depositions. Exploration of this area began in 1968. The Nilam field has more than 16,000 ft of stacked lenticular gas-bearing sands and more than 1,300 individual gas reservoirs. More than 250 production wells have been drilled in the field.
The condensate/gas ratio ranges from 5 to 30 bbl/MMscf. Liquid production presents two problems in the low-permeability sands: liquid loading and condensate banking. Conventional vertical wells are very susceptible to liquid-loading problems because the rates typically are below critical rates required to lift the fluid out of the well. Condensate banking exacerbates the problem by increasing near-wellbore oil saturation and reducing the relative permeability to gas. Horizontal wells are less affected by condensate-banking effects because of the larger flow area and, therefore, are able to handle higher flow rates.
The strategy was to drill and complete horizontal wells that would deliver sufficient rates for a long period, recovering the same reserves as and replacing two or three conventional vertical wells. The well-candidate selection approach was based on a combination of the geological, reservoir-evaluation, and drilling considerations to mitigate risk, maximize recovery, and minimize costs.
A horizontal-well team was established comprising geologists and reservoir, petroleum, and drilling engineers. The team established a three-step process: Successfully drill, prove productivity, and optimize (cost and productivity). This crossdiscipline team selects candidates, then models and plans each well, obtains approval, and executes the drilling and completion.
After each well was drilled and put on production, the horizontal-well team performed a post-well review, identifying lessons learned for use in designing the next well. This method provided continuity in the program and allowed a more rapid climb up the learning curve.
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