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Solution of Benchmark Problems for CO 2 Storage Min Jin, Gillian Pickup and Eric Mackay Heriot-Watt University Institute of Petroleum Engineering

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Outline Introduction Problem 1 –Leakage through an abandoned well Problem 2 –Enhanced methane recovery Problem 3 –Storage capacity in a geological formation Conclusions

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Numerical Simulation Simulation is a very important tool for CO 2 storage Can give estimates of –migration of CO 2 gas –dissolution in brine –build-up of pressure around injection well –etc

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Reliability Depends on –Input data geological structure rock permeability/porosity measurements laboratory measurements Also depends –Adequate computer models flow equations representation of physical processes

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Reservoir Simulation Codes are complex Various different versions available for –gridding model –calculating fluid properties –solving equations May get slightly different answers

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Benchmark Problems Compare solutions using different codes If results are the same –gives confidence in simulation results If they are different –indicates where more work is needed

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Stuttgart Workshop, April 2008 Aim –Discuss current capabilities of mathematical and numerical models for CO 2 storage Compare results of 3 benchmark problems Focus model development on open questions and challenges 12 groups participating web site: http://www.iws.uni-stuttgart.de/co2-workshop/

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Heriot-Watt Entry Solutions to all 3 problems Eclipse 300 –Reservoir simulation software package –Compositional simulation –Schlumberger

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Outline Introduction Problem 1 –Leakage through an abandoned well Problem 2 –Enhanced methane recovery Problem 3 –Storage capacity in a geological formation Conclusions

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Problem 1 CO 2 plume evolution and leakage through an abandoned well aquifer aquitard leaky well 1000 m k = 0 mD, = 0.0 k = 200 mD, = 0.15 k = 200 mD, = 0.15

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Problem 1 CO 2 plume evolution and leakage through an abandoned well aquifer CO 2 injector aquitard leaky well

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Problem 1 CO 2 plume evolution and leakage through an abandoned well aquifer CO 2 injector aquitard ? leaky well

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Model Details Lateral extent of model: 1000 m x 1000 m Separation of wells: 100 m Aquifer thickness: 30 m –perm: 200 mD, poro = 0.15 Aquitard thickness: 100 m –impermeable Abandoned well –model as thin column of 1000 mD, poro = 0.15

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Details of Fluid Properties Problem 1.1 –Reservoir is very deep, ~3000 m –Simplified fluid properties constant with P and T Problem 1.2 –Shallower reservoir, <800 m –CO 2 can change state when rising –More complex fluid properties

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Other Inputs to Simulation Constant injection rate –8.87 kg/s Pressure should stay constant at the edges of the model No-flow boundaries top and bottom

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Challenges Gridding –Coarse over most of model –Fine near wells x y

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Close-up of Grid Centre leaky well injector

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Challenges Modelling of abandoned well a)Model as high perm column b)Model as closed well output potential production high perm cellsclosed well

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Challenges Maintaining pressure constant at boundaries Eclipse designed for oil reservoirs –assumes sealed boundaries leads to build up of pressure We added aquifers to sides of the model –fluids could move into the aquifer –prevented build up of pressure

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Challenges Fluid properties in Problem 1.2 a)User-defined b)Specified as functions of pressure and temperature We used constant T = 34 o C –Tuned equations density and pressure similar to specified values

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CO 2 Distribution after 100 Days, Problem 1.2 Injector Leaky well Gas Sat 0.0 0.2 0.4 0.6 0.8

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CO 2 Distribution after 2000 Days, Problem 1.2 Gas Sat 0.00.20.40.60.8 Injleaky well

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Results Leakage rate for Problem 1.2 leaky well modelled as high perm cells

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Summary of Problem 1 Successfully predicted well rate –Using high perm cells for leaky well well model overestimated leakage –Our results similar to others Leakage rate ~ 0.1% injected volume

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Outline Introduction Problem 1 –Leakage through an abandoned well Problem 2 –Enhanced methane recovery Problem 3 –Storage capacity in a geological formation Conclusions

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Problem 2 Enhanced recovery of CH 4 combined with CO 2 storage k h = 50 mD k v = 5mD = 0.23 CO 2 injector producer 200 m 45 m 200 m

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Model Details Two versions 1.homogeneous 2.layered Temperature = 66.7 o C Depleted reservoir pressure = 35.5 bar Molecular diffusion = 6 x 10 -7 m 2 /s

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Model for Problem 2.2 P x z I 0102030405060708090100 Perm (mD)

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Other Inputs to Simulation Constant injection rate for CO 2 –0.1 kg/s –inject into lower layer –produce from upper layer Constant pressure at production well –P = 35.5 bar No-flow across model boundaries

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Challenges Mixing of gases Changes in physical properties of gas mixture with composition –can be modelled in Eclipse 300 Numerical diffusion –will artificially increase the molecular diffusion

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Result for Problem 2-1

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Results – Homogeneous Model Mass Flux of CH 4 and CO 2

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Results – Layered Model Mass Flux of CH 4 and CO 2

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Results and Summary Assume well is shut down when CO 2 production reaches 20% by mass Relatively easy problem ProblemModelShut-in time (days) Recovery Efficiency (%) 2.1homogeneous172759 2.2layered184364

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Outline Introduction Problem 1 –Leakage through an abandoned well Problem 2 –Enhanced methane recovery Problem 3 –Storage capacity in a geological formation Conclusions

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Problem 3 Storage capacity in a geological model Inj x y z 0.170.190.210.230.25 porosity

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Model Details Lateral dimensions –9600 m x 8900 m Formation thickness –between 90 and 140 m Variable porosity and permeability Depth ~ 3000 m Temperature = 100 o C

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Challenges Simulation of system after injection has ceased –CO 2 continues to rise due to buoyancy –Brine moves into regions previously occupied by CO 2 –Brine can occupy small pores, trapping CO 2 in larger pores additional trapping mechanism hysteresis

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Challenges Trapping of CO 2 by hysteresis after Doughty, 2007 Plume of rising CO 2 CO 2 displacing brine brine displacing CO 2

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CO 2 Distribution after 25 Years Gas Sat 0.00.20.50.8 Y X with hysteresis fault

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CO 2 Distribution after 50 Years Gas Sat 0.00.20.50.8 Y X with hysteresis fault

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Results Mass of CO 2 in formation over time (kg)

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Results Leakage of CO 2 across the boundaries no hysteresis with hysteresis

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Summary of Problem 3 CO 2 did not move towards the fault –moved up-dip –leaked across model boundary Hysteresis did make difference, but not much difference in this example About 0.2 of the injected CO 2 dissolved after 50 years

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Outline Introduction Problem 1 –Leakage through an abandoned well Problem 2 –Enhanced methane recovery Problem 3 –Storage capacity in a geological formation Conclusions

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Benchmark solutions highlight difficulties –Adaptation of simulator for oil/gas reservoirs to CO 2 storage –Difficulties are surmountable –Schlumberger created new module for CO 2 storage Participation in the workshop –Giving us confidence in simulations

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Acknowledgements We thank Schlumberger for letting us use the Eclipse simulation software

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Solution of Benchmark Problems for CO 2 Storage Min Jin, Gillian Pickup and Eric Mackay Heriot-Watt University Institute of Petroleum Engineering

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