CO2 storage technology and pathway to global scale-upRITE CCS Workshop, Tokyo, Japan, 23 Jan 2020

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

CO2 Storage technologyKeeping greenhouse gases safely undergroundCan the world really go ‘low Carbon’ and deliver on the Paris agreement?

2Night time Sahara –Tim Peake 21may2016 - Copyright ESA & NASA

Talk Outline:

The emerging CCS hub in Norway

Insights into saline aquifer CO2 storage

Pathway to global scale up

Summary

The low Carbon energy mix

3

Dep

th (km

)

0

1

2

CO2 capture from power generation and industry

Renewable energy mix

Hydrogen and energy storage

CO2 storage

CO2 utilization and storage

Geothermal

Renewable energy – attractive and essentialCCS – essential and unattractive(?)

Cavanagh & Ringrose 2014 Ringrose 2018

Sleipner CCS operational since 1996

Snøhvit CCS operational since 2008

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 developed

Norway CCS: Building on experience

Norwegian CCS value chain project (Design phase 2016- )

4

Sleipner Project Summary

• Norway CCS

• Learnings from Sleipner

• Learnings from Snøhvit

• Plans for the new Norwegian CCS Demonstration project

• Future potential

5

• 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 from Gudrun field from 2017

Sleipner CO2 Injection Well Design

Sea Bed

Wellhead

26” Conductor

13 3/8” Casing

9 5/8” Casing83o sail angle7” Liner

Perforation Interval3102-3140mMD1010.5-1013mTVD

Gravel pack with sand screens

Stainless steel (25% Cr)

Sleipner CO2 injection well 15/9-A16

Long-reach horizontal well with stainless steel components has provided stable injection for 22 years

6

Demonstrates value of engineering design

Hansen et al. 2005

Top

stru

ctur

e

Monitoring the subsurface at Sleipner0 150

GR TVD (m)

850

900

950

1000

1050

DT240 40

Net/gross: 0.98Porosity: 35-40 %Permeability > 1 D~ 200 m thick

1000 m

Top

Uts

iraTw

o W

ay T

ime

[ms]

855

915

Utsira Formation

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ProducersInjector

Injection point

Insights from geophysical time-lapse monitoring

Kiær et al. 2016

Demonstrates value of geophysical monitoring

Assures conformance and containment

Sleipner Monitoring programme review

1996:Injection start

2019:18.5 Mt

Seismic

Gravimetry

Visual monitoring

Chemical sampling

• What was valuable?• How did it meet the regulations?

Con

tain

men

t

Con

form

ance

Furre et al. 2017

Regulatory compliance with new Directive

2015Re-permitting

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Snøhvit Project Summary

• 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-)

Gas

CO2

LNG plant (Melkøya)

First onshore capture - offshore storage project (combined with LNG)

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Monitoring the subsurface at Snøhvit

Down-hole data:Downhole flow log Down-hole pressure data

Time-lapse seismic(Amplitude difference)

Fluvio-deltaic reservoir Shallow marine

• 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 well

Successful well intervention guided by monitoring data

Hansen et al. 2013; Pawar et al., 2015

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Demonstrates value of flexible well design

The Norwegian CCS Demonstration project

Norcem Cement Factory, Brevik

EGE Energy Recycling plant, Oslo

OSLO

Storage sites• Project currently in the design stage• CO2 storage partnership comprises

Equinor, Shell and Total

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

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

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

CO2 capture, transport and storage concept

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Norwegian CO2 Storage: Future potential

Allows stepwise development of CCS from more regional hubs

Reduces risk and threshold for othersEnables additional CO2 storage

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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?

So what happens underground?What can we learn from Sleipner about CO2 trapping mechanisms?

Physical trapping

Residual trapping

CO2 dissolution

CO2 precipitation

Migrating CO2plume

Residual CO2

Convective mixing and CO2dissolution in brine

Free-phase CO2 in structural traps

Sleipner CO2 storage metrics(as of 2010 seismic survey)

Mass (Mt) Fraction of pore space occupied (ε)

Total injected 12.18 0.048

Free phase 11+0.5 0.044

Dissolved phase 1.2+0.5 0.004Mineral/pore-space reactions

5% efficiency

10% dissolved

14Ringrose 2018

Sleipner time-lapse difference datasets

• 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).

1 km

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Brief history of CO2 plume modelling at Sleipner

Chadwick & Noy (2010)

Lindeberg et al. 2000

Williams & Chadwick, 2017

20102008

Cavanagh (2013)

Early 5-layer model

Layer 9 models

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• 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).

B

r

Qwell

Analytical models for a CO2 plume

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

φπλλ

BtQr well

b

c=max

• When the flow is viscous dominated:

e.g. for storage at 1km depth into a 100m aquifer

Cc is around 0.25

well

b

QBk 22 λρπ ∆

=Γ

Mobility ratio

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Effects of buoyancy on capacity

0.1 1 10010

5

10

15

0

5

20

Gravity/Viscous ratio

Stor

age

Effic

ienc

y, ε

(% P

ore

spac

e oc

cupi

ed)

Domain for typical storage field conditions

Redrawn from Okwen et al. 2010

Storage efficiency at Sleipner after 20 years (~5%)

Injection well

Structural trapping

Viscous-dominated plume shape

Stor

age

unit

Effect of increasing gravity forces

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Modelling the Sleipner case

S

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

Geological model(sand in blue)Thin shales in redCaprock in green)

Example multi-phase flow simulation of CO2 plume at Sleipner (Nazarian et al. 2013)

Sleipner Reference dataset via the CO2 storage datashare initiativehttps://www.sintef.no/en/projects/co2-storage-data-consortium-sharing-data-from-co2-storage-projects/

Updated Sleipner reference model now released

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Pathway to large-scale global storage

Ringrose & Meckel (2019); minimum stress data from Bolaas and Hermanrud (2003)

Domain for large-scale storage

re-pressurization

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 Gt of these resource (globally)

2. However, large-scale storage will require a pressure management approach

3. Design and optimization will be key to scale-up

Depressurization pathways?

Oilfield with natural

buoyancy pressure

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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Idealized CO2 storage project lifetime pressure diagram

Pwell

Pinit

Time

Storage geometry B

Storage geometry A

Pfb

PfaPa

Pb

Project lifetime

Pfrac

Pres

sure

Design model for global storage development

Initial and final pressure per well can be used to estimate capacity

Generic ‘basin ∆P’ approach:Integration of the injectivity equation over the project lifetime:

𝑉𝑉𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝 = 𝐼𝐼𝐶𝐶 𝑝𝑝𝑤𝑤𝑝𝑝𝑤𝑤𝑤𝑤 − 𝑝𝑝𝑖𝑖𝑖𝑖𝑖𝑖𝑝𝑝 + �𝑖𝑖

𝑓𝑓𝐴𝐴 𝑝𝑝𝐷𝐷 𝑡𝑡𝐷𝐷 + 𝐹𝐹𝑏𝑏

where,Vproject = estimated volume storedIc = injectivityPwell = injection well pressurePinit = initial reservoir pressureApD(tD) = characteristic pressure function Fb = volume flux boundary condition

Ringrose & Meckel (2019)

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CO2 injection well data set (60 years of injection from 9 wells)

We also need to know well delivery rates

Statistics used for global basin forecasts:• P90 = 0.33 Mt/year • P50 = 0.70 Mt/year • P10 = 1.06 Mt/year

4 scenarios modelled to illustrate the range of expected behaviours

Shallow open

Deep confinedDeep open

Medium confined

1.2

1.0

0.8

0.6

0.4

0.2

0.0

1.2

1.0

0.8

0.6

0.4

0.2

0.0

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

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Application of ∆P method to basin-scale developments• Projected growth of CO2 injection

wells based on historical hydrocarbon well developments.

• Concept captures industrial maturation phases for global CO2storage

• Uncertainty range based on bounds (P10 - P90) from empirical injection rates

Main finding:We will need ~12,000 CO2 injection wells by 2050 to achieve 2Ds goal

0

1

10

100

1 000

10 000

100 000

1 000 000

10 000 000

1

10

100

1 000

10 000

100 000

2010 2030 2050 2070 2090

Cum

ulat

ive

CO

2 In

ject

ed (M

t)

Num

ber o

f Act

ive

CO

2 In

ject

ion

Wel

lsTexas Active GoM Active Norway ActiveTexas Cumulative CO2 GoM Cumulative CO2 Norway Cumulative CO2

# wells needed for 2DS

Main findings: Global scale-upUsing historical well development trajectories transposed into a future CO2 injection industry, we can infer 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 a Norwegian-scale offshore well development model:

− Resources are equitably distributed and would likely occur in multiple offshore basins close to the main locations of onshore capture

It will only take a fraction of the historic worldwide offshore petroleum well development rate to achieve the global requirements for geological storage of captured CO2 under the 2DS scenario

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Summary

1. The emerging CCS hub in Norway should help stimulate multiple CO2 capture projects in NW 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 historic worldwide petroleum well development rate

Main References• Cavanagh, A., & Ringrose, P. (2014). Improving oil recovery and enabling CCS: a comparison of offshore gas-recycling in

Europe 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 of injecting 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.” Energy Procedia, (2017), 114: 3916-3926.

• Nazarian, B., Held, R., Høier, L., & Ringrose, P. (2013). Reservoir management of CO2 injection: pressure control and capacity 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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