Evaluation of Factors in Horizontal Well Recovery in the Pattani Basin in the Gulf of Thailand

Abstract

Abstract The Gulf of Thailand (GoT) is south of Bangkok. The pay interval typically covers 3000 to 5000 vertical feet. It is composed of a series of stacked fluvial point bars sands that have limited areal extent. In addition, normal faulting breaks them up further. Because all 40 acre wells will be drilled at some point, the justification for drilling a horizontal well is based on incremental recovery over vertical wells. In 2010, a team was assembled to look at establishing a common method to evaluate horizontal wells. Production results from horizontal wells were compared to vertical wells. Concept models were used to evaluate different factors in horizontal well recovery. Where available, history matched simulation models were used to compare horizontal to vertical wells. In addition, the team looked at factors in horizontal well performance. The team collected information on all wells drilled. The team looked for relationships to EUR and recovery factor. Then, the team took a more in depth study of the best horizontals and the worst horizontals. The overall recovery factor averages 20% for horizontal wells and 12.5% for an equivalent vertical well. The average incremental is 7.5%. There are three sources for this difference. The first is improved areal sweep efficiency of a horizontal well. The second is lower abandonment pressure with deep gas lift valves than with a vertical well. In looking at the best and worst performing horizontal wells, the poorer wells were in small reservoirs, often drilled very close to contacts and some were drilled into depleted reservoirs. The best wells were drilled in large very continuous reservoirs and often had strong reservoir drive (either water drive or gas cap expansion). Description The Gulf of Thailand (GoT) is south of Bangkok. Figure 1 is a map of the Gulf of Thailand. The pay interval typically covers 3000 to5000 vertical feet. It is composed of a series of stacked fluvial point bars sands that have limited areal extent. In addition, normal faulting breaks them up further. The overall development strategy is to drill wells on equal spacing (40 acres) on the high side of the faults to encounter as many sands as possible. Figure 2 illustrates the stratagraphic and structural complexity. Chevron has drilled over 80 horizontal wells in the GoT with an average of about 5–10 every year. The targets are oil reservoirs that are at least 25 feet thick. By nature of the depositional and structural setting, these are relatively small reservoirs, usually with OOIP between 0.7 to 6.0 MMBO. The sands can have both a GOC and an OWC. Because all 40 acre wells will be drilled at some point, the justification for drilling a horizontal well is based on incremental recovery over vertical wells. Because the horizontal well design and execution plans are typically developed during the same drilling programs of vertical wells, a quick and reliable method of horizontal well evaluation is needed. In 2010, as part of the Reservoir Management Framework, a team was assembled to look at establishing a common method to evaluate horizontal wells. As part of this initiative, the team looked at factors in horizontal well performance. The study also included a comparison to vertical wells. The team used a multi faceted approach. Production results from horizontal wells were compared to vertical wells. Concept models were used to evaluate different factors in horizontal well recovery. Where available, history matched simulation models were used to compare horizontal to vertical wells.