Controls on Reservoir Performance and Recovery Factor in Fractured Gas Reservoirs: Lessons Learned from Giant Gas Fields

Allan, Jack¹, Rod Sloan², S. Qing Sun³ (1) C&C Reservoirs Inc, Fullerton, CA (2) C&C Reservoirs, Maidenhead, Berks, United Kingdom (3) C&C Reservoirs Inc, Houston, TX

Forty-eight naturally fractured carbonate and sandstone gas reservoirs from around the world, many of them giants, were compared to identify key controls on recovery factors, which range from 34-92% (68% avg.). Brittle fracturing commonly aids recovery and is more common in carbonates than sandstones, which are more likely to develop gouge-filled shear fractures that restrict gas flow and reduce recovery factor. More than 85% of the reservoirs were fractured by compression or uplift rather than by extensional or wrench processes. Thus, high fracture densities and well productivities tend to be concentrated on structural crests. Much of the production comes from a few intensely fractured zones, which are rarely correlative. Most reservoirs produce by gas-expansion drive. When aquifer support is weak, highly fractured areas are the best drilling targets, but when strong, high phi*h areas with low fracture densities are better drilling targets.

If water incursion is minimal, hydraulic fracture treatment is commonly used to connect widely spaced natural fractures, open healed fractures, interconnect high phi*h areas, and penetrate near-wellbore formation damage. If water incursion is serious, careful choice of well location and completion interval is required. Adjusting production rates to maximize pressure drawdown in poorly fractured parts of a reservoir, which are least susceptible to water incursion, is also effective. Since most fractured gas reservoirs are produced to depletion without benefit of secondary recovery programs, reservoir management strategies designed to optimize gas recovery at the individual-well level often provide the best approach for maximizing recovery factor for the entire reservoir.