Developing Flank Areas in a Giant Carbonate Field With Horizontal-Well Placement
- Chris Carpenter (JPT Technology Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- October 2013
- Document Type
- Journal Paper
- 120 - 123
- 2013. Society of Petroleum Engineers
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- 73 since 2007
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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 161591, "Development of Flank Areas in a Giant Carbonate Field With Optimal Placement of Horizontal Wells," by Sameer Khan, SPE, Ali Al-Shabeeb, Zankar Jani, Yousef Azoug, Nguyen Minh, and Harshad Patel, SPE, Zakum Development Company, prepared for the 2012 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 11-14 November. The paper has not been peer reviewed.
Successful development of flank areas depends on accurate reservoir characterization—in particular, water-saturation distribution—in addition to the optimal areal and vertical placement of wells. In relatively thin reservoirs, horizontal wells are generally preferred to increase reservoir contact; the proper spacing and vertical placement of these wells are critical. To test the initial concept in the field, two existing producers were converted into injectors, and pressures were monitored at the offset producers.
The subject oil field is one of the world’s largest offshore carbonate reservoirs and has a production life in excess of 100 years. The field was historically developed with wellhead tower platforms made of steel structures and a combination of vertical and 1-km-long horizontal wells in a five-spot pattern. A new development plan was proposed in 2008 that deployed artificial islands as drilling centers and used extended-reach- drilling technology. In addition, well counts were significantly reduced by deploying longer (3-km) horizontal laterals, referred to as maximum-reservoir-contact (MRC) wells. The development plan comprised both surface and subsurface components, which were effectively integrated to provide maximum flexibility in terms of development options as well as handling of reservoir uncertainties. Because the aquifer support for the subject field is weak, the development consists of a waterflood with line drive to be followed later by gas injection. This island-based plan was approved by shareholders in 2008, and implementation began soon thereafter.
The development plan includes a comprehensive subsurface development scheme based on the available data and prediction tools. Development-plan optimization soon began as more data were being acquired and new reservoir models were built. This work is focused on development-plan optimization of two large flank areas of the largest reservoir in the subject field (south and east flanks in Fig. 1). These flank areas contain very large capillary transition zones that, although only a few hundred feet high, extend to several kilometers areally because of very low reservoir dip (1 to 2°) in a 150-ft-thick reservoir. Therefore, appropriate areal and layer placement of MRC wells in flank areas is a critical task that requires careful attention.
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