CO2 storage technology andpathway to global scale-up
RITE CCS Workshop, Tokyo, Japan, 23 Jan 2020

Philip Ringrose

Norwegian University of Science and Technology (NTNU)
and Equinor Research Centre, Trondheim, Norway

CO2 Storage technology

Keeping greenhouse gases safely undergroundCan the world really go ‘low Carbon’ and deliver on the Paris agreement?

Talk Outline:
The emerging CCS hub in Norway
Insights into saline aquifer CO2 storage
Pathway to global scale upSummary
Night time Sahara –Tim Peake 21may2016 - Copyright ESA & NASA2

The low Carbon energy mix
CCS – essential and unattractive(?)

Renewable energy – attractive and essential
Renewable energy mix
CO2 capture from power
generation and industry

Hydrogen and energy
storageGeothermal

Depth (km)01
CO2 storage

CO2 utilization and storage

3Cavanagh & Ringrose 2014

Ringrose 20182

Norway CCS: Building on experience
Snøhvit CCS
operational
since 2008

Norwegian CCS value
chain project(Design phase 2016- )Sleipner CCS
operational
since 1996

CO2 capture test centre(TCM) operational
since 2012

 23 years of operations
 Building confidence in CCS
 >24 Mt CO2 stored New full-scale CCS projectbeing developed4

Sleipner Project Summary• Norway CCS• Learnings from Sleipner• Learnings from Snøhvit
• Plans for the new
Norwegian CCS
Demonstration project• Future potential• CCS part of gas field development• Amine capture from natural gas• 0.9 Million tonnes stored per year
• Injection started in Sept. 1996
• 23 years assurance monitoring• Sleipner platform processing CO2 fromGudrun field from 20175

Sleipner CO2 Injection Well Design
 Long-reach horizontal well with stainless steel components has provided stable injection for 22 years
 Demonstrates value of engineering design

Wellhead
Sea BedSleipner CO2 injection well 15/9-A1626” Conductor

Perforation Interval
3102-3140mMD
1010.5-1013mTVD

13 3/8” Casing
Stainless steel (25% Cr)

7” Linero83 sail angle

9 5/8” Casing
Gravel pack with sand screens

Hansen et al. 2005

6Monitoring the subsurface at Sleipner
Utsira Formation

GR0150TVD(m)DTInsights from geophysical time-lapse monitoring

240 40855

1000 mNet/gross: 0.98
850

Top Utsira Two Way Time [ms]Porosity: 35-40 %Permeability > 1 D
9009501000

Top structure~ 200 m thick1050

Injection pointKiær et al. 2016

7Injector

 Demonstrates value ofgeophysical monitoring Assures conformance andcontainment
Producers915

Sleipner Monitoring programme review• What was valuable?
• How did it meet the regulations?

8Re-permitting

2019:
18.5 Mt

SeismicContainment

Conformance

1996:
Injection start

Regulatorycompliance withnew Directive

2015

Gravimetry
Visual monitoring
Chemical sampling

Furre et al. 2017

Snøhvit Project Summary First onshore capture - offshore storage project (combined with LNG)
• 150km seabed CO2 transport pipeline• Saline aquifers c. 2.5km deep adjacent to gas field• CO2 stored initially in the Tubåen Fm. (2008-2011) and then in the Stø Fm. (2011-)
LNG plant(Melkøya)
CO2Gas9

Monitoring the subsurface at Snøhvit
Successful well intervention guided by monitoring data
• Rising pressure due to geological barriers led to well intervention• Integrated use of geophysical monitoring and down-hole gauges• Deployed back-up option in the injector wellTime-lapse seismic(Amplitude difference)Down-hole data:

Down-hole pressure data

Downhole flow log

Fluvio-deltaic reservoir

Shallow marine

Hansen et al. 2013; Pawar et al., 201510

 Demonstrates valueof flexible well design

The Norwegian CCS Demonstration project• Project currently in the design stage• CO2 storage partnership comprises
Equinor, Shell and Total

Storage sites

OSLO

EGE Energy
Recycling plant, OsloNorcem
Cement Factory, Brevik

Development solution issubsea wellhead connected
via pipeline to an onshore
intermediate storage port

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H21 Hydrogen Project• System approach to decarbonise northern England using hydrogen (NG to H2)• Large-Scale: ~85 TWh giving 17-18 Mt CO2 reduction per year
• Requires significant scale-up in storage

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CO2 capture, transport and storage concept

Full report at https://northerngasnetworks.co.uk/h21-noe

Norwegian CO2 Storage: Future potential
 Reduces risk and threshold for others Enables additional CO2 storage

 Allows stepwise development ofCCS from more regional hubs Basis for emerging CO2 value chains:• Natural gas to hydrogen• CO2 EOR North Sea CO2 storage hub:A catalyst for roll-out of CCS in Europe?

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So what happens underground?
Free-phase CO2 instructural traps

What can we learn from Sleipner about CO2 trapping mechanisms?
Physical trapping
Residual trapping

Residual CO2

Migrating CO2
plumeCO2 dissolution
CO2 precipitation

Convective mixing and CO2
dissolution in brine

Sleipner CO2 storage metrics(as of 2010 seismic survey)

Mass (Mt)

Fraction of porespace occupied (ε)

Total injected

12.18

0.048

Free phase

11+0.50.044

Dissolved phase

1.2+0.50.004

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5% efficiency
10% dissolved

Mineral/pore-space
reactions

Ringrose 2018

Sleipner time-lapse difference datasets

1 km• Sleipner time-lapse seismic data, showing amplitude difference between 2010 and 1994 surveys.
• Bright amplitudes reveal presence of CO2 complicated by effects of time-shifts and thin layer effects (Furre et al. 2015).
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Brief history of CO2 plume modelling at Sleipner
Layer 9 models

2008

Early 5-layer model

2010

Lindeberg et al. 2000
Chadwick & Noy (2010)

16

Cavanagh (2013)

Williams & Chadwick, 2017

Analytical models for a CO2 plume• For a vertical well injecting at a rate Qwell into a horizontal saline aquifer unit, with thickness B, the CO2 plume
will expand with a ‘curved inverted cone’ geometry with a radius, r (Nordbotten et al. 2005).
• When the flow is viscous dominated:
Mobility ratio

rmax =λc Qwell t
λb π Bφe.g. for storage at 1km
depth into a 100m aquifer
Cc is around 0.25

QwellrB

However, the shape of the cone and the efficiency
depends on the gravity/viscous ratio:

2π ∆ρ k λb B 2
Γ=
Qwell

17

Effects of buoyancy on capacity
Injection well
Structuraltrapping

Storage unit

5

Storage Efficiency, ε(% Pore space occupied)

15

Effect of increasing
gravity forces
Viscous-dominatedplume shape105Domain for typicalstorage field
conditions

20

Storage efficiency atSleipner after 20
years (~5%)

Redrawn from Okwen et al. 2010
00.1

1

10

Gravity/Viscous ratio
18100

Modelling the Sleipner case
Updated Sleipner reference model now released
S

Geological model(sand in blue)
Thin shales in red
Caprock in green)

Deviated injection well path (15/9-A-16)
with injection interval in light blue

Sleipner Reference dataset via the CO2 storage datashare initiative
https://www.sintef.no/en/projects/co2-storage-data-consortium-sharing-data-from-co2-storage-projects/19Example multi-phase flow simulation of CO2 plumeat Sleipner (Nazarian et al. 2013)

Pathway to large-scale global storage
Much discussion about the ‘do-ability’ of large-scale storage:
1. Many nations have mapped storage resources:• North Sea basin CO2 storage resource is >160 Gt• North American storage resource is >2400 Gt• So far we have only used 0.05 Gtof these resource (globally)
2. However, large-scale storage will requirea pressure management approach
3. Design and optimization
will be key to scale-up

Oilfield withnaturalbuoyancy
pressure

Depressurization
pathways?

Domain for largescale storage
re-pressurization
Ringrose & Meckel (2019); minimum stress data from Bolaas and Hermanrud (2003)

2020

Global offshore resources

Global distribution and thickness of sediment accumulations on continental margins, with largest oilfields and main river systems

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Design model for global storage development
 Initial and final pressure per well can be used to estimate capacity
Generic ‘basin ∆P’ approach:

Idealized CO2 storage project lifetime pressure diagramPressure

Pwell

Pfrac
Storage geometry BPb

Pfb

Storage geometry APfa

PaPinitProject lifetime

Time22Integration of the injectivity equation over theproject lifetime:
𝑓𝑓𝑉𝑉𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝 = 𝐼𝐼𝐶𝐶 𝑝𝑝𝑤𝑤𝑤𝑤𝑤𝑤𝑤𝑤 − 𝑝𝑝𝑖𝑖𝑖𝑖𝑖𝑖𝑖𝑖 + � 𝐴𝐴 𝑝𝑝𝐷𝐷 𝑡𝑡𝐷𝐷

where,𝑖𝑖

Vproject= estimated volume storedIc= injectivity

Pwell= injection well pressure

Pinit= initial reservoir pressure

ApD(tD)= characteristic pressure function

Fb= volume flux boundary condition+ 𝐹𝐹𝑏𝑏

Ringrose & Meckel (2019)

We also need to know well delivery rates
CO2 injection well data set (60 years of injection from 9 wells)
4 scenarios modelled to illustrate
the range of expected behaviours

A. All CO2 injection wells (SA) B. Offshore wells only
1.2

1.2

1.0

1.0

0.8

0.8

0.6

0.6

0.4

0.4

0.2

0.2

Shallow open
Medium confined

Statistics used forglobal basin forecasts:

Deep open
Deep confined• P90 = 0.33 Mt/year• P50 = 0.70 Mt/year• P10 = 1.06 Mt/year

0.0230.0

Application of ∆P method to basin-scale developments• Uncertainty range based onbounds (P10 - P90) from empiricalinjection rates
Main finding:We will need ~12,000 CO2 injection
wells by 2050 to achieve 2Ds goal

10 000 000# wells needed for 2DS

1 000 000

10 000100 000
10 000

1 000

1 000
100

1001010112010

2030

Texas Active
Texas Cumulative CO2

2050
GoM Active
GoM Cumulative CO2

2070

Cumulative CO2 Injected (Mt)

• Concept captures industrial
maturation phases for global CO2
storage

Number of Active CO2 Injection Wells• Projected growth of CO2 injection
wells based on historicalhydrocarbon well developments.

100 00002090
Norway Active
Norway Cumulative CO2

Main findings: Global scale-up
Using historical well development trajectories transposed into a future CO2 injection industry, we caninfer that:• A single ‘Gulf-of-Mexico well development’ CO2 injection model could achieve the 7 Gtpa storage by
2043 and 12 Gtpa by 2050. Cumulative storage in 2050 would be 116 Gt.
• Alternatively, five ‘Norway offshore well development’ models could achieve the 7 Gtpa storage by
2050. Cumulative storage in 2050 would be 73 Gt.
• Cumulative storage of >100 Gt by 2050 is most efficiently achieved with 5-7 regions pursuing aNorwegian-scale offshore well development model:− Resources are equitably distributed and would likely occur in multiple offshore basins close to themain locations of onshore capture
It will only take a fraction of the historic worldwide offshore petroleum well development rateto achieve the global requirements for geological storage of captured CO2 under the 2DS scenario25Summary
1. The emerging CCS hub in Norway should help stimulate multiple CO2 capture projects inNW Europe
2. Sleipner and Snøhvit projects give valuable insights for future saline aquifer CO2 storage
3. Geopressure capacity approach quantifies a pathway for global scale up
4. Number of wells needed under the 2DS scenario is only a fraction of the historicworldwide petroleum well development rate

Main References• Cavanagh, A., & Ringrose, P. (2014). Improving oil recovery and enabling CCS: a comparison of offshore gas-recycling inEurope to CCUS in North America. Energy Procedia, 63, 7677-7684.
• Hansen, O., Gilding, D., Nazarian, B., Osdal, B., Ringrose, P., Kristoffersen, J. B., Hansen, H. “Snøhvit: The history ofinjecting and storing 1 Mt CO2 in the fluvial Tubåen Fm.” Energy Procedia, 37 (2013): 3565-3573.
• Furre, A-K, Kiær, A., Eiken, O. “CO2-induced seismic time shifts at Sleipner.” Interpretation 3.3 (2015): SS23-SS35.
• Furre, A. K., Eiken, O., Alnes, H., Vevatne, J. N., Kiær, A. F. “20 years of monitoring CO2-injection at Sleipner.” EnergyProcedia, (2017), 114: 3916-3926.
• Nazarian, B., Held, R., Høier, L., & Ringrose, P. (2013). Reservoir management of CO2 injection: pressure control andcapacity enhancement. Energy Procedia, 37, 4533-4543.
• Ringrose, P. S. (2018). The CCS hub in Norway: some insights from 22 years of saline aquifer storage. Energy Procedia,
146, 166-172.
• Ringrose, P. S., & Meckel, T. A. (2019). Maturing global CO 2 storage resources on offshore continental margins to achieve
2DS emissions reductions. Scientific Reports, 9, 17944.

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