Geological Storage of CO2A) Processes, Capacity and ConstraintsETH Course on CCS and the Industry of Carbon-Based Resources 23 March 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?

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

Talk Outline:

CO2 storage basics

Storage capacity estimation

Example projects

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- )

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Geological Storage of CO2

1. The basic concept is to store captured CO2 underground in reservoirs that would otherwise contain water, oil or gas

2. We need to be deep (greater than 800m) to ensure CO2 is in a dense form –the super-critical phase

3. These are also the depths where we are confident that natural gas has been trapped for millions of years

4. But the big questions are:

• Where do we store it?

• How much CO2 can we inject?

• Can we store it safely?

• Can we store it cost-effectively?

Capacity

Injectivity

ContainmentKey

Sto

rage

issu

es4

CO2 at depth• CO2 is stored at depths >800m to ensure

that CO2 is in a dense form

• This is also important for storage security, because storage seals become more effective with depth

• CO2 properties are highly variable, f(P,T)

Simplified CO2 density versus depth diagram (from CO2CRC)

At standard conditions (ISA) (1.013 Bar & 15oC) 1 m3 of CO2 has a mass of 1.87 kg 1bscf = 28.32 x106 m3

Mass of 1bscf = 52959.5 tonnes Mass of 1MMscf = 52.96 tonnes So a single well injecting 20 MMscf per day is

injecting about 1000 tonnes of CO2 per day

5

NB. Gas engineers tend to work in standard cubic feet (scf) while CO2 projects prefer to report mass

5

Rock properties versus depth• Conceptual sketch showing a shallow

stratigraphic sequence representative of the North Sea basin.

• Typically a Miocene CO2 storage target formations could be capped by a Pliocene mudstone sequences forming the main containment system.

• The role of shallow glacial channel and dewatering features in the Pleistocene may be a key issue for assuring storage containment.

• Reference porosity curves are shown based on (1) Sclater & Christie, 1980, and (2) Marcussen et al., 2010.

• The actual porosity and permeability of the shallow basin sequence is variable and uncertain and needs to be determined via site investigation

6

HPl

io.

Mio

.Pl

ei.

Porosity (fraction)

0.0 0.2 0.4 0.6 0.80.0

1.0

2.0

Depth (km)

Neo

gene

Pale

ogen

e

2

1

Glacial channels

Dewatering features

Petrophysical uncertainties

CO2 storage target Formations

ContainmentTrapping mechanisms involve both physical and geochemical factors:

• Physical trapping mechanisms related to basin-scale processes:

regional structure, basin history and pressure regimes

• Physical trapping mechanisms related to geometry of traps:

controlled by rock architecture of the storage complex

• Physical trapping mechanisms related to fluid flow processes:

Capillary interfaces between fluids

Retention of CO2 as a residual phase

• Geochemical trapping mechanisms:

CO2 dissolution in brine

CO2 precipitation as mineral phases

CO2 sorption/absorption (e.g. on clay minerals)

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Structural and Stratigraphic trapping

Increasing storage security over time

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• The IPCC special report (Metz et al. 2005) argued that the various CO2 trapping mechanisms would work over time to increase storage security in the long term:

1. Structural and stratigraphic trapping

2. Residual CO2 trapping

3. Solubility trapping

4. Mineral trapping

• Longer term processes – residual solubility and mineral trapping – should gradually work to “fix” CO2 permanently in the subsurface

Capillary forces and CO2 trapping• Capillary forces (interfacial tension) play an

important role in trapping of CO2:

− Both at the caprock interface (structural trapping)

− And as residual CO2 (as the plume migrates upwards)

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Migrating CO2plume

Residual CO2

CO2(Dense phase)

Brine phase

Aquifer with large grain and pore throats

Caprock with small grain and pore throats

Basic Trap behaviourThe thickness of a gas or oil column, Zg, that can be retained against gravity by the capillary entry pressure of the sealing rock is given by:

10

)()/1/1(cos2

gw

rescapg g

rrz

ρρθγ

−

−=

rcap and rres are the pore throat radii in the cap rock and reservoir γ is the interfacial tension, θ is the fluid contact angleρw and ρg are the densities of water and gas.

Analytical petroleum trap models (from Ringrose et al. 2000): A. Filled petroleum trap with leaky fault and tight caprock (leaking via spill point); B. Filled petroleum trap leaking through caprock (P > Pcritical)

Compilation of IFT data for (CO2+CH4)/water mixtures (Renet al., 2000) and for the pure CO2/water (Chiquet et al., 2007b). From Naylor et al. (2011)

Comparing CO2 and CH4

In general they found that: • The capillary entry pressure for pure

CO2/water systems is up to 50% lower than for gas/water systems

• The buoyancy force is however lower due the higher density of CO2

• These effects tend to cancel each other out so that column heights for CO2 and CH4 are about the same (but generally lower for CO2)

watergas

waterCO

watergas

waterCO

waterCO

watergasCOgas

/

/

/

/

/

//

22

2

2 coscos

γγ

θθ

ρρ

∆

∆=Ψ

Naylor et al. (2011) have compared CO2 and HC column heights.They used a column height ratio:

(Where cosθ is the fluid contact angle)

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Example CO2-brine relative permeability curves

Example CO2-brine relative permeability curves (Cardium Sandstone; IFT=56.2mN/m; Bennion, B., Bachu, S., 2006).

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Trapping of CO2 as a residual phase has two main controls:• Pore-scale behaviour

(captured by relative permeability functions)

• Plume dynamics and rock heterogeneity

Residual CO2

drainage

imbibition

Residual phase trapping• Simple visualisation of capillary trapping in a porous medium.

− In this experiment olive oil is retained in a granular water-wet porous medium (gravel clasts of around 2 to 3mm in diameter) with blue dye added to the water phase.

− Around 20% of the olive oil is prevented from migrating to the top of the sealed column due to capillary trapping in the pore spaces.

− Olive oil has a density of around 910 kg/m3 (room temperature) so the buoyancy force is quite weak compared to CO2 in the subsurface. The interfacial tension for olive-oil/water at room temperature is around 32mN/m (Sahasrabudheet al. 2017) which is actually quite similar to dense-phase CO2 in the subsurface (Naylor et al. 2011).

• Accurate measurement of residual CO2 trapping at reservoir conditions also gives around 20% (see Krevor et al. 2015).

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Rock architecture at multiple scales

Clockwise from top left:

• Lamina-scale permeability variations (Tilje Fm., Norway)

• Normal fault with fault gouge and clay smear (Sinai, Egypt)

• Tidal delta sedimentary architecture (Niell Klinter Formation, Greenland)

• Faulted Devonian siliciclastic sequences (Jameson Land, East Greenland)

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1cm 1dm

10m1000m

Capacity, injectivity and containment are ultimately controlled by the geological architecture of the rock system

Geochemical ProcessesTwo main processes concerning the CO2-minerals reactions in the pore space:1. CO2 can precipitate as carbonate minerals

(such as calcite and ankerite)2. CO2 sorption or adsorption on clay minerals

Classification: Internal 2012-05-0815

A. Before B. After reaction with CO2

Effect of CO2 reaction with shale (Kaszuba et al, 2003)

SEM image of sample from In Salah:• Cemented fractures filled with Fe-

carbonate cements (Ankerite, pink)• Chlorite grain coatings (green) and

quartz sandstone grains (yellow)

CO2 Dissolution• CO2 dissolution in brine has an important potential to assist and stabilise long-term

storage, but estimates of the effect vary enormously• We know that convective mixing >> molecular diffusion• The diffusive boundary layer needs to achieve a critical thickness before convection can

occur• Critical time (tc) for onset of convection and the characteristic wavelength (λc) are

estimated to be in the range of:• 10 days < tc < 2000 Years

• 0.3 m < λc< 200 m

• Riaz et al., 2006.

CO

2 C

once

ntra

tion

Density-driven flow in CO2 storage in saline aquifer, Pau et al, 2010.

Scope for reducing these ranges using:Field Case HistoriesLarge-scale lab experimentsGood geological models

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Summary: Containment and trapping mechanisms• Four basic classes of CO2 trapping mechanisms:

Structural and stratigraphic trapping

Residual CO2 trapping

Solubility trapping

Mineral trapping

• What do we need to know to ensure containment?

CO2 properties at depth

Factors controlled by rock architecture

Factors controlled by fluid dynamics (and especially capillary forces)

Factors controlled by geochemical reactions

What do we need to do to characterise the site in order to answer these questions?

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Storage Capacity Estimation• Many efforts and studies have been completed to map potential CO2 storage formations

and estimate the storage capacity, such as − The EU GeoCapacity Project on European Capacity for Geological Storage of Carbon Dioxide

(2009; http://www.geology.cz/geocapacity)

• Total mapped storage capacity is 360 Gt

− The North American Carbon Storage Atlas (2012; www.nacsap.org) (USA, Canada and Mexico)

• Storage potential of over 2,400 Gt (across the USA, Canada and Mexico)

− The CO2 atlas for the Norwegian Continental Shelf (2014; www.npd.no/en/Publications/Reports/Compiled-CO2-atlas/)

− Other national CO2 storage databases include UK (www.co2stored.co.uk), Australia and Brasil

• These national government-sponsored projects have set out to prepare nations for future large-scale CO2 storage activities

• However, there is also much debate about how realistic these estimates are:

We need to understand the basis for CO2 storage capacity estimates

Classification: Internal 2012-05-0818

Storage Capacity EstimationBachu et al (2007) provide a valuable review of the methods used in CO2 storage capacity estimation

Classification: Internal 2012-05-0819

• There are several different types of estimate which can be summarized by the Techno-Economic Resource–Reserve Pyramid

• We need to differentiate:

Theoretical capacity (the physical limit)

Effective capacity (a more realistic estimate using cut-off criteria)

Practical capacity (taking into account economic, technical and regulatory factors)

Matched capacity (site-specific storage for specific CO2 capture plants)

There are also various adaptations of this pyramid (e.g. for different stages of exploration and development)

Matched Capacity

• Map of CO2 emissions, infrastructure and storage capacity in NW Europe (from www.geocapacity.eu)

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Storage Capacity Estimation Saline Aquifers

Classification: Internal 2012-05-0821

• The theoretical storage capacity for a structural or stratigraphic trap can be simply estimated as:

Vtrap can be estimated from mapping or simple dimensions (e.g. thickness, area)

VCO2 = Vtrap φ (1-Swirr)

VCO2 = ∆Vswept φ (SCO2R)

• Theoretical storage capacity for residual phase trapping can also be estimated by

Where Vswept is the volume filled by CO2 and then subsequently invaded by water

MCO2 = ρCO2(P,T) VCO2Volume is converted to mass, using:

(Swirr = Irreducible water saturation, SCO2R = Residual CO2 saturation)

Storage Capacity Estimation Saline Aquifers

The effective storage capacity is based on a set of cut-offs to account for effects of fluid dynamics whereby the CO2 will only fill a fraction of the available pore space:

Classification: Internal 2012-05-0822

Vtrap = Bulk rock storage volume of trap

N/G = Net to gross ratio

ε = Storage efficiency factor

MCO2 = Vtrap φ N/G ρCO2(P,T) (1-Swirr) ε

The storage efficiency factor ε represents the cumulative effects if heterogeneity, buoyancy, and sweep efficiency:

• ε is difficult to estimate and is very site specific

• ε is typically in the range of 1.0 to 5.0% (e.g. nacsap.org, Appendix B).

• It can be estimated using reservoir simulation or more analytical approaches

• 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).

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B

r

Qwell

Analytical model for a CO2 plume

rmin rmax

Qwell

BThe shape of the curve depends on the gravity/viscous ratio Nordbotten and Celia (2006)

CO2 storage capacity coefficient• It is also useful to define a CO2 storage capacity coefficient:

Cc = Vinjected / VPV

• This is a more dynamic measure of storage efficiency which can be applied for an expanding cylinder containing the plume

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Vinjected

VPVrmax

• Note that at the end of injection Cc is essentially the same as the final storage efficiency, ε.

• For real cases the plume may be any shape, but for the analytical solution the plume is assumed to be circular.

CO2 storage capacity coefficient

We know the pore volume of a cylinder, so the storage capacity coefficient, Cc is given by:

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2max )(rB

tQV

VC well

PV

injectedc πφ

==

• For a real storage site rmax could be determined from monitoring data (e.g. first breakthrough to a monitoring well or by using time-lapse seismic images).

• For a predictive case, we might like to estimate this analytically. When the flow is viscous dominated and the buoyancy forces are small, Nordbotten & Celia (2006) showed that for the analytical case, rmax is given by:

φπλλ

BtQr well

b

c=max

where λc and λb are the fluid mobilities for CO2 and brine and t is the injection time interval. Note that for each phase, the fluid mobility is the ratio of relative permeability to viscosity, λi = ki/µi.

Effect of fluid MobilityThe analytical solution is for viscous-dominated flow in a horizontal continuous aquifer, where the Gravity/Viscous ratio is small (Γ<1), where the gravity factor, Γ, is given by (Norbotten et al. 2005):

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well

b

QBk 22 λρπ ∆

=Γ

For example, for storage at a depth of around 1km into a 100m aquifer, the analytical value for Cc is around 0.25 (assuming λr = 4 and ∆ρ = 300 kg/m3).

However, the value is very dependent on the mobility ratio.

Effect of buoyancy on capacity

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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

Illustration using SleipnerThe time-lapse seismic observations at Sleipner reveal the plume growth geometry.

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Time-lapse seismic difference reflection amplitude maps at Sleipner (cumulative for all layers) (redrawn from Eiken et al. 2011).

Illustration using Sleipner

• Seismic sections (N-S) at Sleipner showing pre-injection conditions (1994), enhanced reflection amplitudes due to CO2 invasion into multiple layers by 2008 and time-lapse difference reflection amplitudes (2008-1994).

• The uppermost layer (layer 9) has the best seismic imaging quality, as it avoids the complexities of seismic wave interference and time-delays which affect the lower layers.

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Capacity estimatesSleipner

• Estimates of the storage capacity coefficient, Cc, and storage efficiency factor, ε, for the Sleipner Utsira Case

• The actual value of the dynamic coefficient, Cc, varies as a function of time and depends on the assumptions made.

• However, the Sleipner case supports the argument that Cc

and e typically fall in the range of 0.01-0.05.

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Sleipner efficiency – for the whole structural closure

Global Status – Large-scale projects (GCCSI database)19 Large-scale CCS projects in operation, including: Sleipner & Snøhvit in Norway; Weyburn, Boundary Dam & Quest in Canada; Decatur & Petra Nova in USA, … ++

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https://co2re.co/FacilityData

Equinor CO2 storage projects

19962008 2004

Eiken et al., 2011

Unique blend of site experience:• Shallow/deep• Offshore/onshore• Vertical/horizontal wells• Different reservoir geology

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Brief introduction to the Sleipner fields

9% CO2 in the gas from Sleipner Vest

Sleipner West: Gas field with high CO2 content.

Sleipner East: CO2 is stripped off the gas and injected in the UtsiraFm at ~ 900 m depth (above the condensate reservoir).

> 18 Mt CO2injected since 1996

GasGas condensate

Oil

33

The Utsira Formation 0 150GR 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

34

Sleipner Monitoring programme review

1996:Injection start

2018:17 Mt

Seismic

Gravimetry

Visual monitoring

Chemical sampling

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

Cont

ainm

ent

Conf

orm

ance

Furre et al. 2017

Regulatory compliance with new Directive

2015Re-permitting

35Furre et al. 2017

1994

20

0 m

s

2 km1999–19942001–19942004–19942006–1994

1 km

Top Utsira Fm.

1 km

Injection point

Seismic time-lapse monitoring

36 Sleipner seismic refs: e.g. Chadwick et al. 2010, Furre et al., 2015

The Snøhvit LNG/CCS Project, Norway

• Snøhvit is an LNG project in the Barents Sea offshore Norway

• CO2 is captured onshore and transported in a 153km subsea pipeline to a subsea template.

• The CO2 is injected at a depth of ~2500m (below the gas reservoir).

• Injection of CO2 started in 2008, and by end 2019, 6.5 Mt has been stored

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Snøhvit: Onshore & Offshore

• CO2 injector line: 153 km• Seabed depth: 330 m• Two CO2 injectors• Injected gas is ~99% CO2

• Injected into Tubåen/Stø Fm at ~2500m depth

Reservoir system

Process Facility

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Snøhvit CO2 injection history and status

• CO2 injection into the Tubåen Formation until April 2011

• Injection then diverted into the Stø Formation following well intervention

• 6.5 Mt injected by end 2019 (1.1 Mt injected into Tubåen)

• Continuing stable injection of CO2

Nordmela

Stø2

Tubåen

Main field segment with gas producers

CO2 Injector

SN

GLC

X

39 Hansen et al. 2013

Snøhvit pressure history (2008-2013)

a

b

c

a) Early rise due to near-wellbore effects

b) Gradual rising trend due to geological barriers

c) Pressure decline following injection into Stø Fm.

40Hansen et al. 2013; Pawar et al., 2015

Snøhvit Operations• Gradual rise in reservoir pressure indicated

limited injection rate/capacity (Hansen et al., 2013)

• Repeat seismic survey (2009) showed CO2 injection mainly confined to lower unit – reservoir permeability lower than expected

• Well Intervention operation successfully completed May 2011

0.5 km

Increasin

g am

plitu

de

Amplitude change map

Top Fuglen Fm.

Base Tubåen Fm.

2009 Seismic Survey 4D (Amplitude difference)

Seismic sections

Island Wellserver

41 Hansen et al. 2013

Kb-1Kb-501

Kb-503

Kb-502

Krechba Carboniferous top reservoir porosity map

• CO2 from several fields in the In Salah Gas Development has been stored in the Krechba field Carboniferous saline aquifer

• Joint Industry Project on CO2 storage demonstration operated from 2006 to 2013

• Over 50 publications on related research and development

In Salah CO2 project experience

• Storage unit is ~1880m deep, 20m thick (k = 1-10mD)

• 5 crestal gas producers and 3 down-dip CO2 injectors

• 3.86 Mt CO2 has been injected (2004-2011)

Ringrose et al. 2011, 201342

Cretaceous sequence (900m)

Carboniferous mudstones (950m)

CO2 injection(3 wells)

Gas production(5 wells)

Gas from other fields

Amine C02 removal

In Salah CCS project schematicSatellite

monitoring(InSAR)

Gas Chemistrymonitoring

Fluid displacement monitoring (4D seismic)

Rock strain monitoring(Tilt, microseismicity)

Productionmonitoring(Tracers)

Definition and modelling of CO2 storage and migration

Definition and modelling of containment and potential cap-rock migration pathways

Monitoring, Measurement and Verification (MMV)

Ringrose et al, 201143

Monitoring Rock deformation using InSAR

• InSAR = Interferometric Synthetic Aperture Radar

• Allows mm-changes in ground surface elevation to be monitored

• Especially valuable at the In Salah CCS site (dry rock desert)

Applicable to most onshore sites

• Using rock mechanical models, we can use InSAR to monitor the sub-surface pressure field

• Addresses a key question for CO2 Storage – pressure management

May 2009

20mm uplift

Map of surface uplift

Modelled rock strain (section)

Injection Unit

44Classification: Internal 2012-05-08

Experience from CO2 Storage projectsOperational experience (saline aquifers) reveals several important learnings:

Injection rates of 0.3-0.9Mt CO2/year/well

Injectivity and capacity highly dependent on reservoir properties revealed during site operation

Geological heterogeneity means that flexible well solutions will be required

Rock mechanical response to Pinj may be a critical factor

Importance of pressure and fluid management

Need for fit-for-purpose reservoir monitoring portfolio

Injection well management

2008-1994Geophysical Monitoring

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Further info

Full course notes available as a short book (paperback or e-book)

• DOI https://doi.org/10.1007/978-3-030-33113-9

• https://www.springer.com/gp/book/9783030331122

References• Bachu, S., Bonijoly, D., Bradshaw, J., Burruss, R., Holloway, S., Christensen, N. P., & Mathiassen, O. M. (2007). CO2

storage capacity estimation: Methodology and gaps. International Journal of Greenhouse Gas Control, 1(4), 430-443. • Baines, S. J., & Worden, R. H. (2004). The long-term fate of CO2 in the subsurface: natural analogues for CO2 storage.

Geological Society, London, Special Publications, 233(1), 59-85.• Bennion, D. B., & Bachu, S. (2006, January). Supercritical CO2 and H2S-Brine Drainage and Imbibition Relative

Permeability Relationships for Intercrystalline Sandstone and Carbonate Formations. In SPE Europec/EAGE Annual Conference and Exhibition. Society of Petroleum Engineers.

• Baklid, A., Korbol, R., & Owren, G., 1996. Sleipner Vest CO2 disposal, CO2 injection into a shallow underground aquifer. SPE paper 36600-MS presented at SPE Annual Technical Conference and Exhibition.

• Bond, C., Wightman, R., and Ringrose, P., 2013, The influence of fracture anisotropy on CO2 flow, Geophysical Research Letters, 40, 1284–1289, doi:10.1002/grl.50313

• Chadwick, A., Clochard, V., Delepine, N., and others, 2010. Quantitative analysis of time-lapse seismic monitoring at the Sleipner CO2 storage operation. The Leading Edge, 29 (2). 170-177.

• Furre, Anne-Kari, Anders Kiær, and Ola Eiken, 2015. CO2-induced seismic time shifts at Sleipner. Interpretation 3.3 (2015): SS23-SS35.

• Gemmer, L., Hansen, O., Iding, M. Leary, S. and Ringrose, P., 2012. Geomechanical Response to CO2 injection at Krechba, In Salah, Algeria. First Break, 30, 79-84.

• Kaszuba, John P., David R. Janecky, and Marjorie G. Snow. "Carbon dioxide reaction processes in a model brine aquifer at 200 C and 200 bars: implications for geologic sequestration of carbon." Applied Geochemistry 18.7 (2003): 1065-1080.

• Lopez, O., Idowa, N., Störer, S., Rueslatten, H., Boassen, T., Leary, S. & Ringrose, P., 2011. Pore-scale modelling of CO2-brine Flow Properties at In Salah, Algeria. Energy Procedia, Volume 4, 3762-3769.

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References• Mathieson, A., Midgley, J., Dodds, K., Wright, I., Ringrose, P. and Saoula, N., 2010. CO2 sequestration monitoring and

verification technologies applied at Krechba, Algeria. The Leading Edge (February 2010), 216-221.• Naylor, M., Wilkinson, M., & Haszeldine, R. S. 2011. Calculation of CO2 column heights in depleted gas fields from

known pre-production gas column heights. Marine and Petroleum Geology, 28(5), 1083-1093. • Nordbotten, J. M., Celia, M. A., & Bachu, S., 2005. Injection and storage of CO2 in deep saline aquifers: Analytical

solution for CO2 plume evolution during injection. Transport in Porous media, 58(3), 339-360. • Okwen, R. T., Stewart, M. T., & Cunningham, J. A., 2010. Analytical solution for estimating storage efficiency of

geologic sequestration of CO2. International Journal of Greenhouse Gas Control, 4(1), 102-107. • Pau, G.S.H., Bell, J. B., Pruess, K., Almgren, A. S. Lijewski, M. J. and Zhang, K., 2010. High-resolution simulation and

characterization of density-driven flow in CO2 storage in saline aquifers. Advances in Water Resources, 33 (4), 443-455.

• Riaz, A., Hesse, M. Tchelepi, H. A. & Orr, F. M., 2006. Onset of convection in a gravitationally unstable diffusive boundary layer in porous media. Journal of Fluid Mechanics, 548, 87-111.

• Ringrose, P., Atbi, M., Mason, D., Espinassous, M., Myhrer, Ø., Iding, M., Mathieson, A. & Wright, I., 2009. Plume development around well KB-502 at the In Salah CO2 Storage Site. First Break, 27, 81-85.

• Ringrose, P. S., Mathieson, A. S., Wright, I. W., Selama, F., Hansen, O., Bissell, R., Saoula, N. & Midgley, J. 2013. The In Salah CO2 storage project: lessons learned and knowledge transfer. 11th Int. Conference on Greenhouse Gas Technology (GHGT11), 18th-22nd November 2012, Kyoto, Japan. www.sciencedirect.com

• Ringrose, P. 2020. How to Store CO2 Underground: Insights from early-mover CCS Projects. Springer• Vasco, D. W., Rucci, A., Ferretti, A., Novali, F., Bissell, R. C., Ringrose, P. S. Mathieson, A. S. and Wright, I. W., 2010.

Satellite-based measurements of surface deformation reveal fluid flow associated with the geological storage of carbon dioxide. Geophysical Research Letters, Vol. 37, L03303.

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