www.baker-rds.com M. J. Haigh Well Design Differentiators CO 2 Sequestration in Depleted Reservoirs SPE 124274 Presented at Offshore Europe 2009 Conference and Exhibition “Towards a Low Carbon Future”
Www.baker-rds.com M. J. Haigh Well Design Differentiators CO 2 Sequestration in Depleted Reservoirs SPE 124274 Presented at Offshore Europe 2009 Conference.
Mar 26, 2015
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M. J. Haigh
Well Design DifferentiatorsCO2 Sequestration in Depleted Reservoirs
SPE 124274
Presented at Offshore Europe 2009 Conference and Exhibition
“Towards a Low Carbon Future”
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Introduction
• Why is this subject important?
– Limited CCS well design knowledge available
– CCS to play key part in O&G future
• Feasibility study
– Depleted gas reservoir
• Other sources
– Specialist service companies
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Objectives
• Review environment of a CO2 injection well
• Identify main well design issues and hazards
• Evaluate and assess the impact
• Propose potential solutions
• Key areas:
– Injection Operations
– Well Integrity
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Project Management
• Technical workgroups
– Capacity
– Integrity
– Injectivity
• Identified areas of integration
• Provided practical project
framework
Capacity
InjectivityIntegrity
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Injection Operations
• Challenges during Injection:
– Establishing design constraints
– Review the effects of low wellhead
temperatures
– Accurately predicting CO2 phase
transition behaviour
– Reduced perforating efficiency in
depleted reservoirs
CorrosiveMixtures
IntegrityConcerns
ExplosiveDecompression
TemperatureFluctuations
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Design Constraints
• CCS developing concept
– New projects will consist of demonstrator schemes
– Late life cycle: Full base load injection
• Specific project requirements
– Initial gaseous ramp up stage
• Power generation companies
– Project management disconnect
• Fit for purpose injection strategy
required
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Low Wellhead Temperatures
• Temperature drop across choke
– Potential hydrates at tree valves
– Integrity issues
• Valves
• Tubing hanger seals
• Dehydrate flow stream
• Evaluate risk of hydrate
CoolingEffect
HydratesForming
IntegrityConcerns
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CO2 Phase Transition Behaviour
• Demonstrator scheme
– Gas phase injection / liquid phase injection
• Gas phase injection
– Reservoir pressure increases
– THIP increased to maintain injectivity
– Critical pressure reached
• Liquid phase injection
– Reservoir pressure continues
to increase
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CO2 Phase Transition Behaviour
• Phase transition
– Unstable phase behaviour
• What we think could happen:
– Fluid density increases
– Injection rate increases
– Depressurisation of wellbore
• Mitigation strategy:
– Maintain single phase in wellbore
– Velocity reducing insert string
– Modification of THIP
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CO2 Phase Envelope
0
200
400
600
800
1000
1200
1400
1600
1800
2000
-50 -40 -30 -20 -10 0 10 20 30 40 50
Temperature (˚C)
Pre
ssu
re (
psi)
100 v% CO2
Gas Injection - Initial
Gas Injection - Mid
Gas Injection - Final
LiquidPhase
SupercriticalRegion
C
GasPhase
TransitionRegion
Increasing Pr
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Injection Strategy
Increasing Reservoir Pressure / Time
Gas
Well 4
Well 1
Well 2
Well 3
Well 1
Well 4
Well 3
Well 2
Well 2
Well 1
Well 4
Well 3
Well 1
Well 2
Well 3
Well 4
Liq
uid
Inc. THIP
Inje
ction L
ife C
ycle
Retr
ofit In
sert
Str
ings
Liq
uid
Liq
uid
Inc. THIP
Inc. THIP
Inc. THIPActive Injection Duty
Offline Obs. / Cont. Duty
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Injection Strategy Benefits
• Avoids phase transition uncertainty
– Single phase flow in wellbore
• Simple architecture
– Flexibility from gas to liquid phase injection (stages overlap)
• Reduced hydrate risk downhole
• Well duty: Injection and observation
– Increased sink integrity (less penetrations)
• Reduced project CAPEX
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Perforating Efficiency
• Cased and cemented
– Best for long term hydraulic isolation
• Reduced perforation efficiency
– Conventional static underbalance not possible
• Perforating options
– Extreme overbalance perforating
– Reservoir k > 100 mD
– Leak off rate below fracture pressure
• Reactive perforating
– Suitable for depleted reservoirs
PSI
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Reactive Perforating
Normal crushed zone occurs
Exothermic reaction with pressure surge
Super-charged pressure surge removing damaged zone
Beneficial tip fracture
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Material Selection
• Metallurgy selection subject to range of views
• Tubular materials options
– Carbon steel
– Glass reinforced epoxy (GRE) lined CS
– 13% Cr stainless steel
– CRA such as Duplex
• Specific corrosion assessment
– Water solubility in CO2
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Water Solubility in CO2
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
10000
0 200 400 600 800 1000 1200 1400 1600 1800 2000
Pressure (psia)
Wat
er c
on
ten
t in
CO
2 f
luid
(p
pm
) 32 degF
43 degF
50 degF
PhaseBoundary
THIT 43 degFTHIP 580 psia
CO2 Solubility is 500 ppm
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Well Integrity Workflow
WellCharacterisation
Leakage ScenarioWorkshop
DegradationModelling
MonitoringPlan
Remediation Options
Risk Assessment
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Measurement and Monitoring
• In well monitoring
– Integrity risks
• Wellhead / packer feed through-ports
• Fibre optics selected
– Increased reliability and performance
– Integrity monitoring
– DTS
• Wellbore temperature correlation
• Injection profiling
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Summary
• Technical workgroups
– Capacity, Integrity and Injectivity
• Key injectivity challenges
– Potential CO2 phase instability
• Maintain single phase
• Velocity insert string
• Reduced perforation efficiency
– Reactive perforating
• Well integrity
– Leakage scenario workshop
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