Performance Optimization of Water Alternating CO 2 Flooding in Tight Oil Formations

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1 Presenter s Name Paper Title & Session Date Chengyao Song and Daoyong (Tony) Yang Petroleum Systems Engineering University it of Regina Performance Optimization of Water Alternating CO 2 Flooding in Tight Oil Formations

2 Objectives To investigate recovery performance of waterflooding, miscible CO 2 flooding and miscible water alternating CO 2 (CO 2 WAG) flooding in tight oil formations; To identify and simulate the mechanisms of waterflooding, miscible CO 2 flooding and miscible CO 2 WAG flooding in tight oil formations; To obtain the optimum recovery performance by optimizing i i the operation parameters in the CO 2 WAG processes.

3 Methodology Experimental 33 rd IEAEOR Symposium Conduct 4 sets of coreflooding experiments including waterflooding, miscible continuous CO 2 flooding and miscible CO 2 WAG with different WAG ratios and slug sizes. Theoretical Develop the PVT model used for reservoir simulation; Numerically match the experimental measurements; Optimize the operation parameters including WAG ratio, cycle time and slug size to achieve the optimum oil recovery.

4 Experimental scenarios Scenario Flood scheme #1 Waterflooding #2 Miscible continuous CO 2 flooding #3 Miscible CO 2 WAG flooding WAG ratio=1.0 Water slug size=0.250 PV CO 2 slug size=0.250 PV #4 Miscible CO 2 WAG flooding WAG ratio=0.5 Water slug size=0.125 PV CO 2 slug size=0.250 PV

5 Core samplespropertiesproperties for scenario #1 4 Scenario Porosity (%) Permeability (md) Initial oil saturation (%) # # # #

6 Experimental setup 33 rd IEAEOR Symposium Air bath Core holder N 2 N 2 BPR CO 2 Oil Brine Separator Gas flow meter Heater Temperature controller Desktop computer Syringe pump

7 Experimental results of Scenario #1 Measured oil recovery, cumulative water production and pressure drop for waterflooding

8 Experimental results of Scenario #2 Measured oil recovery, cumulative gas production and pressure drop for miscible continuous CO 2 flooding

9 Experimental results of Scenario #3 Measured oil recovery cumulative water production cumulative gas production and Measured oil recovery, cumulative water production, cumulative gas production and pressure drop for miscible CO 2 WAG flooding with WAG ratio=1.0, water slug size=0.250 PV, CO 2 slug size=0.250 PV.

10 Experimental results of Scenario #4 Measured oil recovery, cumulative water production, cumulative gas production and pressure drop for miscible CO 2 WAG flooding with WAG ratio=0.5, water slug size=0.125 PV, CO 2 slug size=0.250 PV.

11 Theoretical 33 rd IEAEOR Symposium A grid system of grid block is applied Size of each grid in different scenarios: Scenario #1: cm Scenario #2: cm Scenario #3: cm Scenario #4: cm A PVT model of oil sample is built with a MMP value of 9.7 MPa

12 History matching results of Scenario #1

13 History matching results of Scenario #2

14 History matching results of Scenario #3

15 History matching results of Scenario #4

16 Optimization of WAG ratio (a) (a) Optimization of WAG ratio for Scenario #3.; and (b) Corresponding injection pressures (b)

17 Optimization of cycle time (a) (a) Optimization of cycle time for Scenario #4; and (b) Corresponding injection pressures (b)

18 Optimization of water slug size (a) (a) Optimization of water slug size for Scenario #4; and (b) Corresponding injection pressures (b)

19 Conclusions 33 rd IEAEOR Symposium Compared to waterflooding, superior recovery performance has been achieved in CO 2 flooding of a tight oil formation; Miscible CO 2 WAG leads to a higher recovery efficiency compared to continuous miscible CO 2 flooding; In the miscible CO 2 WAG process, water injection leads to higher injection pressures, while CO 2 injection tends to increase thefluidinjectivity; injectivity;

20 Conclusions 33 rd IEAEOR Symposium Optimum recovery performance in CO 2 WAG is obtained when the WAG ratios fall in the range of 4.0 to 8.0; Miscible CO 2 WAG flooding with a shorter cycle time shows a better recovery efficiency; Oil recovery of CO 2 WAG can be improved by using a larger water slug size, though the injection pressure tends to be high.

21 Thank You! Questions or Comments? Contact Infor.: Dr. Tony Yang, P.Eng. Professor and Program Chair Petroleum Systems Engineering University of Regina Tel.: