Feasibility of CO 2 Flooding Higher Viscosity Oils, Field Results, and Screening. Presented by: Richard Baker, December 7, 2012

Transcription

1 Feasibility of CO 2 Flooding Higher Viscosity Oils, Field Results, and Screening Presented by: Richard Baker, December 7, 2012

2 Steve s Challenge; Population of CO 2 Flooded Oils: Gravities and Viscosities U.S. and San Andres CO2 Flood Oil Gravities* 30 Cdn Immiscible CO 2 No. of CO2 Floods San Andres (PB) All US Eastern Mississippi Floods Means 0 < >44 * OGJ Production Volume, Apr 2, 2012 Oil Gravities Degrees API 12 San Andres CO2 Flood Oil Viscosities* No. of CO2 Floods Means Reservoir Oil 6 cp Cdn Immiscible CO >4 but <10 >10 * OGJ Production Volume, Apr 2, 2012 Oil Viscosity Degrees API

3 Organization of Immiscible CO 2 Talk Executive Summary Summary of Field experience in immiscible floods California (Wilmington) Arkansas (Lick Creek) Trinidad Malaysia Turkey Canada (Retlaw) Screening Criteria

4 Executive Summary Limited immiscible pilots in literature show the promise immiscible CO 2 flooding Laboratory work seems to show promise of improved recovery ( RF=6-15%OOIP) Review of Old CO 2 Pilot Project in Canada shows good response Rough oil = 30cP ( RF CO2-wtrfld oil = 20cP ( RF CO2-wtrfld oil = 5cP ( RF CO2-wtrfld ~+20%OOIP) Criteria; Oil saturation S O current >50% Successful waterflood; volumetric sweep E vol >50% Biggest hurdle; Inexpensive CO 2 corrosion hurdle existing pipe systems +CTP API gravity 15-25API Insitu viscosity= cP

5 Why Medium Grade Oil Pools? API, oil viscosity cP, CRF>20% In excellent quality reservoirs, predictable and well understood water flood development High permeability and porosity High oil saturation Thin (3-5m), but good continuity

6 Map of Alberta Pools API As well as Sask. side ~8 Bbbl

7 USA Target Heavy oil fields Baker Hughes Incorporated. All Rights Reserved.

8 OLD IMMISCIBLE CO 2 PILOTS Baker Hughes Incorporated. All Rights Reserved.

9 Summary of Field Experience in Immiscible Floods Wilmington Calif. USA Lick Creek Arkansas USA Trinidad Malaysia

10 CO 2 Recovery of Heavy Oil: Wilmington Field Test Saner, W.B., Patton, J.T., CO 2 recovery of Heavy Oil: Wilmington Field Test, SPE paper 12082, JPT, July 1986

11 CO 2 Recovery of Heavy Oil: Wilmington Field Test Saner, W.B., Patton, J.T., CO 2 recovery of Heavy Oil: Wilmington Field Test, SPE paper 12082, JPT, July 1986

12 CO 2 Recovery of Heavy Oil: Wilmington Field Test Saner, W.B., Patton, J.T., CO 2 recovery of Heavy Oil: Wilmington Field Test, SPE paper 12082, JPT, July 1986

13 CO 2 Recovery of Heavy Oil: Wilmington Field Test Five fold increase in oil rate Decrease in watercut 14 API oil after waterflood Saner, W.B., Patton, J.T., CO 2 recovery of Heavy Oil: Wilmington Field Test, SPE paper 12082, JPT, July 1986

14 Wilmington Field Actually, CO 2 displacement of viscous crude is not as efficient as the miscible displacement lighter crude. However, the difference in efficiency is more than offset by the generous oil saturation present at the end of waterflooding in reservoirs that contain viscous crudes. Saner, W.B., Patton, J.T., CO2 recovery of Heavy Oil: Wilmington Field Test, SPE paper 12082, JPT, July 1986

15 Retlaw Mannville V CANADIAN IMMISCIBLE FLOOD Baker Hughes Incorporated. All Rights Reserved.

16 Mannville Retlaw V map view 1 mile Oil initial reservoir conditions 30cp CO2 allocation to HC gas injected is at an average of 0.5 (ranges from )

17 Summary Data for Retlaw Mannville V Oil Pool Pay Thickness 5.03 ft Porosity 18.9% Water Saturation 28.4% μ oil = 30 cp Bo 1.12 Initial Pressure Fm Temperature API Gravity OOIP 1743 psia ~Psat=MMP 89.6 F 18.1 API OOIP Remaining 71% 12 MMBbl Number of wells 47

18 CO2 & Gas Injection Rate, Oil Production Rate vs Time 10 MMcf/d 1000 Stk bbl O/ d

19 Water Rate Injected, Gas Rate and CO2 Rate Injected vs Time 6 mmcf/d Start, middle and late time CO 2 injection.

20 Retlaw Mannville V background Current RF = 29% 47 wells in total, 33 Oil producers, 13 injection wells (6 CO2 injectors) 1 st cycle of CO2 injection began October 1983 and concluded on April nd cycle of CO2 injection began on January 1991 and concluded on April Water injection began on May 1987

21 Recovery Factor vs. HCPVI For the geeks Injection of CO2 Stops Total (water +CO 2 )

22 RF vs HCPVI Water injected Injection of CO2 Stops

23 Cum Gas & CO2 Inj for Retlaw Mannville V Cum Gas Injected : 1.1 MMMcf Cum CO2 injected : 4.8 MMMcf

24 Cum Oil Prod for Retlaw Mannville V July 2012

25 Cum Gas Prod for Retlaw Mannville V

26 North South Pressure Regions OIL PRESSURE NORTH PRODUCERS SOUTH PRODUCERS Initial pressure P si =P bubbble = MMP UNTITLED PROJECT DATE All Wells GROUP1 GROUP3 NORTH PRODUCERS SOUTH PRODUCERS OIL PRESSURE [kpa] More Injection in South Region _TIME_ [Years]

27 SIMULATION MODEL

28 History Matching Parameters Liquid Rate Constraint Frac Pressure Injection Well Constraint Perm Increase around producing wells K = 100mD Kv/Kh = 0.1 Pi = Pb = 120bar 2 perm streaks introduced between inj prod pairs

29 Ternary Saturation Diagrams Well location Feb 1971 Aug 2008 Injected water into gas cap

30 History Match Water Production 30

31 History Match Gas Production 31

32 Sensitivity to oil viscosity; What did we do? 20 cp Waterflood CO 2 Waterflood CO 2 Waterflood CO Baker Hughes Incorporated. All Rights Reserved.

33 Incremental recovery vs. Oil Viscosity Incremental recovery factor for CO 2 immiscible flooding vs. waterfloods Baker Hughes Incorporated. All Rights Reserved.

34 SCREENING FOR IMMISCIBLE CO Baker Hughes Incorporated. All Rights Reserved.

35 Screening for Immiscible CO 2 criteria Oil saturation S O current >50% Successful waterflood; volumetric sweep E vol >50% Biggest hurdle; Inexpensive CO 2 corrosion hurdle existing pipe systems +CTP API gravity 15-25API Insitu viscosity= cP But at low temperatures and higher viscousity there is a larger viscosity effect on Oil Baker Hughes Incorporated. All Rights Reserved.

36 Insitu viscosity= cP why is screening problematic As temperature the change in oil viscosity goes up ~50 time drop ~10 time drop Baker Hughes Incorporated. All Rights Reserved.

37 What Really Controls Recovery? Recovery Factor = E d E vol E vol volumetric efficiency E d displacement efficiency Without Horizontal Well Maximize the contacted rock volume 37

38 Displacement Efficiency E d ( S oi S ROS) oi ROS is high for heavy oils therefore change Is significant if oil saturated with CO 2 where: E d = displacement efficiency S oi = initial oil saturation ROS = the remaining average oil saturation after one movable pore volume has been injected. Epic Copyright

39 Summary Limited immiscible pilots in literature show the promise immiscible CO 2 flooding Laboratory work seems to show promise of improved recovery ( RF=6-15%OOIP) Field projects show promise Simulation of Canadian pilot oil = 30cP ( RF CO2-wtrfld =7%OOIP) Simulation oil = 5cP ( RF CO2-wtrfld ~+20%OOIP) Screening Oil saturation S O current >50% Successful waterflood; volumetric sweep E vol >50%