Case Study: CO2 Injection into a Highly Depleted
Gas Field, SNS UK
Workflows and Considerations
Paul Williams and Kate Gibbons
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Content
• Components of CO2 Storage Design
• CO2 Properties & Conditions
• Modelling Objectives
• Well Modelling and Design
• Modelling the Storage Site
• Monitoring the Storage Site
• Workflow Summary
• Conclusions
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© 2011 Baker Hughes Incorporated. All Rights Reserved.
Components of CO2 Storage Design
CAPACITY
Ultimate potential
CO2 storage capacity
of the reservoir
INTEGRITY
Ability of reservoir to
retain CO2 without
significant losses
in the long term
INJECTIVITY
Well requirements
& configuration
required to support
CO2 injection
into the reservoir
FACILITIES
CO2 Composition & Delivery Conditions
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Data Acquisition – Capacity
Data Acquisition – Injectivity
Data Acquisition – Integrity
Case Study: Key Features of Storage Design
•
Reservoir
– Very low reservoir pressure ~3bar
– Excellent permeability ~1,000 mD
– Perceived good integrity
•
CO2 delivery constraints
– 99.8 % pure?
– 2 Delivery stages:
– Gas phase at 6,600 te/d @ ~30 bar
– Dense liquid at 26,400 te/d @ ~80 bar
– Low delivery temperature 4 to 6°C
Facilities / wells – 40 year design life
Storage reservoir design life >1,000 years
•
•
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CO2 Properties
Pressures & Temperatures
Final Reservoir
Conditions
100
Liquid Delivery
(Post Demonstration)
90
80
Dense
Phase
Pressure (bar)
70
60
50
Liquid
40
30
Gas
Gas Delivery
(Demonstration
~15 yrs)
20
Initial Reservoir
Conditions
10
0
-100
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-75
-50
-25
0
Temperature (°C)
25
50
75
CO2 Properties
Impact of Impurities (Nitrogen) on the Phase Diagram
90
80
100% CO2
99% CO2
Pressure (bar)
70
95% CO2
60
50
40
30
Critical Temperature Reduces
Critical Pressure Increases
2-Phase Region Opens Up
20
10
0
-40
-30
-20
-10
0
10
Temperature (deg C)
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20
30
40
CO2 Properties
CO2 Density (g/cm3)
Equation of State Models (52 °C)
0.70
0.65
0.60
0.55
0.50
0.45
0.40
0.35
0.30
0.25
0.20
0.15
0.10
0.05
0.00
~17%
Variation
Span Wagner
Conformal Solution Mixture
Peng Robinson
Sauve Redlich Kwong
Delivery
Pressure
Reservoir
Pressure
0
10
20
30
40
50
60
70
80
Pressure (bar)
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90
100 110 120 130 140
CO2 Properties
Viscosity & Density – Impact of Phase Change
1.20
Fluid Density (g/cm3)
1.00
0.80
0.60
-20 °C
0 °C
20 °C
Methane (0 °C)
0.40
0.20
0.00
0
10
20
30
40
50
60
70
80
Pressure (bar)
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90 100 110 120 130 140
Modelling Objectives
Injection and Storage
•
Models to assess:
– Well number and design
– Near wellbore effects
– Storage capacity
– Migration of CO2
•
Timelines:
• Injection
• Long Term Storage
P
P
T
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Purpose :
• Phase change in reservoir
• Impact of JT effects
• Evaporation of water
• Mixing with gas
• IPR comparison with well
modelling
q
Well Modelling
Challenge – JT Cooling
10
Delivery Temperature
0
Temperature (°C)
-10
-20
-30
Iso-enthalpic
21Pressure
bar
Initial Gasflash
Delivery
Limit for Standard
Oilfield Equipment
-40
Iso-entholpic
flash 34
bar
Final Gas Delivery
Pressure
Iso-enthalpic
flash
76 bar
Initial Liquid
Delivery
Pressure
-50
-60
0
10
20
30
40
Pressure (bar)
50
60
70
80
Well Modelling
Hydrates and Ice
Limit for Thermal
Induced fracturing
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Hydrate dissociation
Ice
Wellhead
Bottomhole
Near Wellbore
30
Pressure (bara)
25
Hydrate1
Hydrate
20
15
No &
Ice No
& No Hydrate
Hydrate
No Ice
10
5
Ice Deposition
No Hydrate
Ice
but noButHydrate
0
-30
-25
-20
-15
-10
Temperature (°C)
31 July
-5
0
5
10
Near Wellbore Model
Near Wellbore Issues
•
High pressure drop across sandface – JT effect!
•
Impact on the reservoir?
•
The near wellbore model also has limits (minimum temperature)
140
120
CO2 stabilises to
reservoir temperature
Temperature (°F)
100
80
60
40
CO2 heated by
reservoir
20
0
0
100
200
300
400
500
600
Distance From Wellbore (ft)
Cooling due to pressure drop across sandface
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700
800
900
1000
Well Design - Challenges
•
Drilling operating margins
• Too high – fracture
• Too low – collapse
31 July
•
Limits maximum deviation
•
Impact on well design and size
•
Impacts on number and location of wells
Well Design
• Maximum deviation
limited to 55 – 60
degrees depending on
well azimuth
• Central vertical well
• Use ‘spider web’ layout
to avoid inter-well
thermal interference
31 July
Wells – Summary
Life of Field
Pressure (bar)
120
Reservoir Pressure
BHIP
WHIP
BHIT
70
60
100
50
80
40
60
30
40
20
Heater at platform
20
10
0
0
3 Wells
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8Time
Wells
(years)
6 Wells
Temperature (deg C)
140
Dense Phase
80
Gaseous Phase
160
Modelling the Storage Site
Static Modelling
•
Similar to traditional hydrocarbon modelling, but in addition:
– Full overburden model
– Caprock characterisation
– Fracture & fault analysis – juxtaposition / boundary
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Moinitoring the Storage Site
Sally Benson, Stanford University
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Monitoring Objectives
Overview
•
Verification of well and reservoir integrity during and after injection
•
Detect migration, leakage and irregularities
•
Detect adverse effects on the surrounding environment
•
Monitoring and verify behaviour and migration of the CO2 plume to
compare actual versus forecast modelling
•
Allow update to short and long-term safety assessment of the
complex
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Monitoring Programme – What & Why?
A wide range of monitoring methods are available covering these elements
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Monitoring Programme – How?
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Monitoring Programme Screening
• Identification of Field Specific Scenarios
• Identification of what parameter/physical property is to be
measured
• Review suitable technologies in terms of:
– Technical (resolution, reliability, accuracy)
– Cost/benefit
– Experience from other project
– Government legislation /regulations
– Long term liability
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Workflow Summary
CAPACITY
INTEGRITY
INJECTIVITY
FACILITIES
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Workflow Summary
INJECTIVITY
INTEGRITY
CAPACITY
Well Modelling
Identify Leakage
Paths, Mechanisms
and Risk
Geomechanical
Analysis
Risk
Mitigation
3D Geological
Framework
Modelling
WHIT,WHIP,BHIT,BHIP
Injection Rates, Wells
Tubing Size
Conceptual
Completion
Design
Well
Abandonment
CO2 Pressure
Conceptual Well
Design
Monitoring
Near Wellbore
Modelling
CO2 Distribution
Reservoir Pressure
Caprock Description
Fault Sealing
Fault Reactivation
Wellbore Stability
Well Locations
Full Field Simulation
History Matching
Overburden
Reservoir Pressure
Injection Wells
Abandoned Wells
Validation of Max
Storage Capacity
Conclusions and Take Aways……..
•
Understand CO2 properties & expected CO2 composition
•
Have knowledge of delivery pressures, temperatures & rates
•
Understand limitations of software for CO2 particularly 2-phase flow
•
Impact of injection phase (gas or dense) on well numbers & size
•
Impact of Joule-Thomson effect - potential sub-zero temperatures
•
Metallurgical & cementing considerations for well construction design
•
Well integrity considerations for existing wells in the reservoir
•
Monitoring requirements for short & long term
•
Treat the project holistically, there is much interdependence!!
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Back Up
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Well Models
•
Nodal (Prosper)
– PVT (Peng Robinson)
– Improved Enthalpy Analysis
– No transient effects
•
Transient (OLGA)
– JT effects during start-up and shut-down
– Choke opening simulation
– Identify minimum temperatures
•
Near Wellbore (GEM)
– Impact of ΔP Across sandface
– Dehydration of near wellbore
•
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Result:
– 2-phase flow modelling not completely validated
– Design philosophy to prevent 2-phase flow in system
– Could consider adding contaminants (N2) to CO2 stream
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Injectivity Conceptual Well Design
•
•
9 5 /8" Csg
•
•
7" Tbg
4" Tbg
•
•
Design based on requirements for injection
rates based on modelling
Tubing stress analysis performed to ensure
design meets safety requirements
Components based on known technology
Metallurgy selected to minimise CO2
corrosion
Special cement and techniques used.
In-well monitoring: Fibre optic technology
Design Basis Requirements for Equipment
Selection in CO2/WAG
• Gas Composition
• Oxygen Content
• Water Content
• Water Composition
• Temperature
• Pressure
• Other Factors
(Velocity, Galvanic
Effects, Scale)
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CO2 Properties
Corrosion
•
Need to have H2O for corrosion to occur
– In supplied CO2
– In formation water
•
High Chrome / Super Duplex a solution – but subject to sulphur corrosion
•
May need to consider GRE tubing
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