Lessons Learned from the Field-Scale Simulation of the Gas-Assisted Gravity Drainage GAGD Process in Heterogeneous Sandstone Oil Reservoirs

Abstract

Abstract Unlike the Continuous Gas Injection (CGI) and Water-Alternative Gas (WAG), the Gas-Assisted Gravity Drainage (GAGD) process takes advantage of the natural segregation of reservoir fluids to provide gravity-stable oil displacement and improve oil recovery. In the GAGD process, the gas is injected through vertical wells to formulate a gas cap to allow oil and water drain down to the horizontal producer (s). Therefore, the GAGD process was implemented through immiscible and miscible injection modes to improve oil recovery in a sector of the main pay/upper sandstone member in the South Rumaila oil field, located in Iraq. A high-resolution Multiple-Point Geostatistics-based reservoir characterization was reconstructed to model the lithofacies and petrophysical properties in order to provide the most realistic geological environment for the GAGD process simulation. After upscaling the geostatistical models, EOS-compositional reservoir simulation was built to evaluate the GAGD process and test its effectiveness to improve oil recovery. Next, a notable history matching was obtained with respect to the oil rates, cumulative production, water injection rate, and cumulative injection for the entire field and all the wells. Then, 20 vertical injectors and 11 horizontal producers were installed for CO2 injection and oil production, respectively. The reservoir has 12 layers and the gas injection wells are placed at the crest of the reservoir through the first two top layers to formulate a gas cap. The horizontal production wells were installed in the fifth, sixth, seventh, and eighth layer of high oil saturation. The 2nd, third, and fourth layers were left as transition zones to achieve the gravity drainage. The four bottom layers were left with no injection/production activates as they fully flooded with water. The base case of immiscible CO2-GAGD flooding with default settings of operational well decision factors was adopted for 10 years of future performance prediction. In addition, two other special cases for immiscible and miscible were implemented for 25 years of future performance prediction. The recovery factor given the remaining oil is approximately 7.6% through the primary production by the end of the prediction period. However, the immiscible base case of the GAGD process resulted in reaching recovery factor of 15% given the remaining oil. Additionally, the obtained amount of oil in 10 years primary production can be obtained in only one year by the GAGD base case. On the other hand, the recovery factor through immiscible and miscible special cases of 25 years prediction reached to 30% and 42% given the remaining oil, respectively. A fourth special GAGD process was compared to the Continuous Gas Injection (CGI) and Water-Alternative-Gas (WAG) processes on the same reservoir with similar well constraints. Given the remaining oil, the recovery factor by the end of prediction period is 23.72% through the GAGD process. However, the CGI and WAG have resulted in obtaining 12.35% and 11.37% recovery factors, respectively. Consequently, the feasibility of GAGD process to improve oil recovery was attained by obtaining higher recovery factors than CGI and WAG flooding methods.