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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 - PowerPoint PPT Presentation
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Solution of Benchmark
Problems for CO2 Storage
Min Jin, Gillian Pickup and Eric MackayHeriot-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 CO2 storage
• Can give estimates of– migration of CO2 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 CO2 storage
• Compare results of 3 benchmark problems
• Focus model development on open questions and challenges
• 12 groups participatingweb 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
• CO2 plume evolution and leakage through an abandoned well
aquifer
aquifer
aquitard
leaky well
1000 m
k = 0 mD,= 0.0
k = 200 mD,= 0.15
k = 200 mD,= 0.15
Problem 1
• CO2 plume evolution and leakage through an abandoned well
aquifer
aquifer
CO2 injector
aquitard
leaky well
Problem 1
• CO2 plume evolution and leakage through an abandoned well
aquifer
aquifer
CO2 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
– CO2 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 wellinjector
Challenges
• Modelling of abandoned wella) Model as high perm columnb) Model as closed well
• output potential production
high perm cells closed 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 1.2a) User-definedb) Specified as functions of pressure and
temperature
• We used constant T = 34 oC– Tuned equations
• density and pressure similar to specified values
CO2 Distribution after 100 Days, Problem 1.2
InjectorLeaky well
Gas Sat
0.0 0.2 0.4 0.6 0.8
CO2 Distribution after 2000 Days, Problem 1.2
Gas Sat
0.0 0.2 0.4 0.6 0.8
Inj leaky well
Results
• Leakage rate for Problem 1.2
0.00
0.02
0.04
0.06
0.08
0.10
0.12
0.14
0 500 1000 1500 2000 2500
time (day)
leak
age
volu
me/
inje
ctio
n v
olu
me
(%)
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 CH4 combined with CO2 storage
kh = 50 mDkv = 5mD = 0.23
CO2 injector
producer
200 m
45 m
200 m
Model Details
• Two versions1. homogeneous2. layered
• Temperature = 66.7 oC• Depleted reservoir pressure = 35.5
bar• Molecular diffusion = 6 x 10-7 m2/s
Model for Problem 2.2
P
x
z
I
0 10 20 30 40 50 60 70 80 90 100
Perm (mD)
Other Inputs to Simulation
• Constant injection rate for CO2
– 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
0.00
500.00
1000.00
1500.00
2000.00
2500.00
3000.00
0 200 400 600 800 1000 1200 1400 1600 1800 2000
time (day)
mas
s f
lux
(kg
/d)
CH4 CO2
• Mass Flux of CH4 and CO2
Results – Layered Model
0
500
1000
1500
2000
2500
3000
0 200 400 600 800 1000 1200 1400 1600 1800 2000
time (day)
mas
s fl
ux
(kg
/d)
CH4 CO2
• Mass Flux of CH4 and CO2
Results and Summary
• Assume well is shut down when CO2 production reaches 20% by mass
• Relatively easy problem
Problem Model Shut-in time (days)
Recovery Efficiency (%)
2.1 homogeneous 1727 59
2.2 layered 1843 64
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
z0.17 0.19 0.21 0.23 0.25
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 oC
Challenges
• Simulation of system after injection has ceased– CO2 continues to rise due to buoyancy
– Brine moves into regions previously occupied by CO2
– Brine can occupy small pores, trapping CO2 in larger pores
• additional trapping mechanism• hysteresis
Challenges
• Trapping of CO2 by hysteresis
after Doughty, 2007
Plume of rising CO2
CO2 displacing brine
brine displacing CO2
CO2 Distribution after 25 Years
Gas Sat
0.0 0.2 0.5 0.8
Y
X
withhysteresisfault
CO2 Distribution after 50 Years
Gas Sat
0.0 0.2 0.5 0.8
Y
X
withhysteresisfault
Results
• Mass of CO2 in formation over time
0.0E+00
2.0E+09
4.0E+09
6.0E+09
8.0E+09
1.0E+10
1.2E+10
1.4E+10
0 5000 10000 15000 20000
Time (days)
Mas
s o
f C
O2
totalfreedissolved
(kg)
Results• Leakage of CO2 across the boundaries
CO2 inter-region mass flow rate for Problem 3
0
0.2
0.4
0.6
0.8
1
1.2
1.4
1.6
0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000
Time (day)
Mas
s F
low
rat
e (k
g/s)
P3-1
P3-2no hysteresis
with hysteresis
Summary of Problem 3
• CO2 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 CO2 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
Conclusions
• Benchmark solutions highlight difficulties– Adaptation of simulator for oil/gas
reservoirs to CO2 storage
– Difficulties are surmountable
– Schlumberger created new module for CO2 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 CO2 Storage
Min Jin, Gillian Pickup and Eric MackayHeriot-Watt University
Institute of Petroleum Engineering
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