Thermal Recovery Study for Improving Oil Recovery of Heavy Oil Accumulation with Strong Water Drive Mechanism in Sultanate of Oman

Abstract

Abstract Enhanced oil recovery (EOR) applications are strongly recommended and required in Sultanate of Oman to maintain stable oil production levels. Thermal EOR is of particular importance in view of the abundance of heavy, viscous oil within many field clusters in the Sultanate. The selected field for this study is located in South of Oman, where relatively-thin clastics reservoirs at moderate depths are dominant. Reservoir oil is highly under-saturated, 16 API gravity with very low solution gas oil ratio, initial oil viscosity over 800 cP and initial reservoir pressure of about 8,700 kPa. Experience to be gained in this moderate size reservoir has many possible applications in larger reservoirs with similar characteristics within the cluster. The selected reservoir is developed mostly by cold production using horizontal wells with landing points at maximum possible distance above the initial oil-water contact. Few vertical wells were also drilled with thermal compliance for Cyclic-Steam-Stimulation (CSS) applications. Initial cold production rates are in the range of 15 - 35 STm3/d/ well at negligible water-cut but within few months the oil rate declines and water-cut increases due to water cresting. CSS applications in thermally-completed vertical wells show encouraging response in terms of steam injectivity (up to 200 m3CWE/d) and gain in oil rate (up to 50 STm3/d/well) but led to sanding problems in some wells. Field production rate reached a peak two years after start of development then continued to decline with an increase in water-cut till current level of 85%. Cumulative oil production corresponds to only 5.4% of Stock-Tank-Oil-Initially-In-Place (STOIIP). Reservoir pressure indicated a slight decline (about 300 kPa) due to the strong bottom aquifer beneath the relatively thin oil column. Detailed reservoir characterization, modeling efforts for the dipping, truncated structure and optimum development scenarios (under both, cold production and CSS/steamflood applications) are discussed in this paper. Steamflood simulation includes defining the optimum flood pattern and injection scheme as well as quantifying the effect of bottom aquifer with emphasis on utilization of aquifer depletion wells. Predicted performance for the selected development scenarios are compared with common industry practice and analytical methods for similar heavy oil reservoirs. Basis for selecting an optimum location, pattern configuration and injection rate for a steamflood pilot are also included. Simulation results indicate that continued infill drilling using horizontal wells for cold production could achieve an ultimate recovery factor up to only 14% of STOIIP while steamflood (if aquifer depletion wells are successful) could add up to 47% of STOIIP over cold production case. The optimum flood pattern is based on horizontal producers (perpendicular to strike) drilled in the middle of oil column and vertical injectors midway in-between the producers. Effects of pattern size, injection interval, steam injection rate and steam quality on steamflood performance are also included. Cumulative steam-oil ratio is expected to be in the range of 4.0-4.5 m3CWE/STm3. Economic evaluation results are discussed to show the sensitivity of project economics to oil price and various alternatives of fuel supply for steam generation.