Abstract Compared to conventional oil reservoirs, the development of heavy oil resources presents significant challenges due to the unconsolidated nature of the reservoir sands, high fluid viscosities, low productivity indices and vertical lift challenges. These complexities are further exacerbated by early water breakthrough and a rapid increase in water cut, driven by an unfavorable mobility ratio that promotes viscous fingering, an unstable displacement front during water/aquifer displacement or aquifer encroachment, - production and low recovery factors. Additional challenges include poor vertical lift process due to the high fluid densities associated with heavy oil, typically characterized by low API gravity and hydrostatic pressure exerted by the produced water within the tubing. To improve the productivity index, instead of vertical/deviated wells, horizontal wells with drain lengths of 1500+ft were deployed with the first trial deployed in mid-1990s. The longer drain lengths associated with horizontal wells resulted in higher reservoir contact with improved gross liquid rates at lower drawdowns compared to the vertical/deviated wells. However, the inflow which is impacted by tuning the well PI is only one part to the puzzle. The next critical hurdle to overcome is the vertical lift challenges. Historically, the use of gas lift, GL, and Electrical Submersible Pumps, ESPs, Progressive Cavity Pumps, PCPs, and Sucker Rods Pumps have been deployed to enhance the vertical lift and overcome frictional and gravity forces along the vertical path from the sand face to the wellhead. This work carried out a holistic review of the performance of GL and ESPs deployed in Field X over a 50-year production period. The result showed that wells equipped with GL alone, were limited in maximum gross liquid rates (1000 blpd). Production was also associated with high drawdowns which often resulted in early water breakthrough, attendant sand production and consequently limited well UR. While wells equipped with ESPs were able to deliver higher gross liquid rates of 4000+ blpd with lower drawdowns. As a result, the breakthrough time observed was longer compared to wells with GL while sand production was also lower compared to wells equipped with GL. There were challenges in the runtime of ESPs as hiccup's in power supply negatively impacted the run life. These learnings have informed the decision to deploy horizontal wells with ESPs (with GL as backup) for phase 4 development campaign in Field X. To support the planned phase 4 development, sensitivities were carried out on tubing sizes and offtake rates for 28 cP, 34 cP, 87 cP and 252 cP fluids. The results revealed a preference for ESPs in reservoirs with fluid viscosities greater than 30 cP with time to achieve 1 MMstb of oil within record time. While GL remained optimal for fluid systems with viscosities less than 30 cP.
Alaigba et al. (Mon,) studied this question.