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

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

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

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

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

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

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/

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

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

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

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

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

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

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

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

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

Close-up of Grid Centre leaky well injector

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

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

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

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

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

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

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

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

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

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

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

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

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

Result for Problem 2-1

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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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