Geological Storage of CO2:B) Project design and global scale-up

ETH 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

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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So how do you design a storage project?Things you need to know:

• CO2 supply – rates, pressures, temperatures

• Reservoir depth, water depth

• Storage site capacity

• Well design

• Site performance (plume behaviour)

• Reservoir properties

• Overburden & seal charactersitics

• Regional aquifer

Fill to spill line

VTRAP

Wellhead system

Depth >800m

Pwh

Pbh

Pbh

PresDistance from well

Pbh

Time (years)

CO2 supply (Q, P, T)

CO2 plume

Rock properties

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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(redrawn from Hansen et al. 2005).

Key elements of the design (Hansen et al. 2005):• Long-reach horizontal well with a sail angle of 83o

• Perforated injection interval of 38m with the top of the injection interval at 1010m TVD MSL

• High Chromium (25% Cr) stainless steel was used for the 7” injection tubing and the exposed sections of the 9 5/8” well casing.

N.B. Initial injection problems due to sand influx were solved by re-perforation of the injection interval and installation of sand and gravel packs (as shown here) and described by Hansen et al. 2005

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Injection well placementThe main choices for well placement are:• Good reservoir quality (hence injectivity)• Down-dip versus crestal• Vertical or deviated• Simple or multiple completion intervals

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Some key issues are:• Getting sufficient injectivity• Geological heterogeneity• Plume migration strategy • Ensuring long-term containment Good quality

sands

Wherever you choose to inject, basic physics tells us to expect upward migration – so injection near the base of the unit makes most sense

Transport systems

Capture

Compression

Well head

Storage

Liquefaction

Pumping

Well

Hub

Intermediate storage

Inside system

Outside system

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Snøhvit: first and only offshore CO2 pipeline

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Gas

CO2

LNG plant (Melkøya)

• Combines onshore capture (combined with LNG) with offshore storage project• 150km seabed CO2 transport pipeline

Small-scale CO2 ships already exist – Yara in North Sea

Source: Yara/Norsk Hydro1500 m3 capacity at ~20 bar and ~-20 C

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CO2 paths on phase diagram with typical conditions for CO2 storage operations

Pres

sure

(bar

a)

Temperature (ºC)

Vapour

LiquidSolid

-56.6 oC5.2 bara

30.98 oC73.8 bara

0.1

Big ships

Small ships

1

10

100

1000

0 50-50-100

Triple point

Critical point

Dense

(BH)Snøhvit (WH)

Sleipner (WH) (BH)

Surface

Two-phase flow

Liquid near boiling point

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CO2 compression and cooling in PH diagram

V+L

LL+SS

V

V+S 20 ºC

Pres

sure

(bar

a)

1

10

100

Enthalpy (kJ/kg)200 400 600 800

Courtesy Gelein de Koeijer, Equinor

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V+L

LL+SS

V

V+S 20 ºC

Pres

sure

(bar

a)

1

10

100

Enthalpy (kJ/kg)200 400 600 800

CO2 compression and cooling in PH diagram

Northern Lights – Design concept

Shipping concept• One ship per capture site• 7,500m3 of CO2 per ship

Pipeline design:110km - 12 inch

https://ccsnorway.com/

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Some issues for project design:1 - Changes in impurity concentrations

Capture Transport Storage

Changes in impurity concentrations ... ... can change

density and viscosity ...

... and change storage efficiency.

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Effect of some CH4 in CO2

0

25

50

75

100

125

150

175

200

0 5 10 15 20 25 30 35 40Temperature (C)

Pres

sure

(Bar

a)

boiling line pure CO2Hydrate pure CO2phase envelope 5% CH4Hydrate 5% CH4Typical for transportSnøhvit

In Salah

Sleipner

From capture

Critical point

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Courtesy Gelein de Koeijer, Equinor

Issue 2 - Corrosion

Capture Transport Storage

Remaining H2O (liquid), NOx or O2

from capture .... can lead to corrosion

in pipeline .. .. and wells.

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Corrosion example

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Soruce: http://octane.nmt.edu/WaterQuality/corrosion/CO2.aspx

Issue 3 - Rock mechanics• Pressures in rock formations are

controlled by the rock stresses and the ability of the fluids to escape

• Under normal conditions the pore fluids are assumed to be in hydrostatic equilibrium

• The rock stress are controlled by the lithostatic or overburden stress and the tectonic stress field

• Rock will fracture when the pore pressure exceeds a certain fracture pressure, which is controlled by the stress field and the rock properties

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20 40 60 100 12080

Pressure, MPa

Lithostatic gradient~ 1.0 psi/ft assuming ρ=2.3 g/cm3

Hydrostatic gradient~ 0.45 psi/ft (ρ=1.0 g/cm3)

Fracture gradient(depending on many factors)

σ1

σ2

σ3

Tectonic stress field

Depth km

1

2

3

4

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The capacity controversy• Ehlig-Economides & Economides (2010) published an analysis on “Sequestering carbon

dioxide in a closed underground volume.” They concluded that:

“… the volume of liquid or supercritical CO2 to be disposed cannot exceed more than about 1% of pore space. [And that this] renders geologic sequestration of CO2 a profoundly non-feasible option for the management of CO2 emissions.”

• This study argued that the maximum storage efficiency value, ε, was 1% – significantly lower than the values used by CO2 storage capacity estimation studies.

• There was a strong reaction to the E&E (2010) paper, e.g. from Cavanagh et al. (2010) who argued that:

the E&E analysis of open systems was flawed

the E&E closed-system model was based on an incorrect conceptual model

study used an overly simplistic mathematical analysis

and that large-scale geological CO2 storage is feasible.

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Is there enough room for CO2 storage?Most people agree that you cannot inject very much fluid into a “confined box.”

There are three important limiting factors:

1. The size of the box (the storage unit)

2. The properties of the box boundaries (faults and shale sealing units)

3. The ability of the box to absorb increased pressure (rock and fluid compressibility).

Sketch of open, closed or semi-closed systems, from Zhou et al. (2008)

Zhou et al. (2008) concluded that:• Storage efficiency is ~0.5% for closed systems• But that a semi-closed system with a seal

permeability of 10-17 m2 (0.01 md) or greater behaves essentially as open system with respect to pressure buildup (due to brine leakage).

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Issue 4 - The earthquake controversyIn 2012, Zoback and Gorelick created a stir by stating that:

There is a high probability that earthquakes will be triggered by injection of large volumes of CO2 into the brittle rocks commonly found in continental interiors.

[And that]…, in this context, large-scale CCS is a risky, and likely unsuccessful, strategy for significantly reducing greenhouse gas emissions.

Scaling parameters for earthquakes (from Zoback and Gorelick, 2012)

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• Their main argument was that the Earth’s crust is critically stressed and that fluid injection in deep wells can trigger earthquakes when injection increases the pore pressure close to potentially active faults.

• They also accept that individual projects (like Sleipner) can be executed safely, and mainly argued that it is large-scale CCS cannot be done safely

Earthquakes and CO2There were many responses to the Z&G (2012) statement, most notably Vilarrasaand Carrera (2015), who argued that: “Geologic carbon storage is unlikely to trigger large earthquakes and reactivate faults through which CO2 could leak”

They presented four main arguments supporting their case:i. Sedimentary basins are not normally

critically stressedii. Highest injection pressures occur at

the start and can be controllediii. Capillary forces retain CO2 while

allowing water to dissipateiv. CO2 gradually disolves in the

brine phase

Data and models of friction coefficients from Vilarrasa & Carrera (2015), PNAS

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Geomechanics overview

From Rutqvist (2012)

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Need to separate expected mechanical response from unwanted effects

Seismicity observed in CO2 injection projects

Weyburn micro-seismic monitoring (Verdon et al., 2013)showing geophones (gray triangles), injection wells (purple lines), and production wells (black lines). Events are colored by occurrence time: before CO2 injection (yellow), during the initial injection stages (dark blue), during a period of elevated injection (green), during the second phase of monitoring (light blue), and after injection well shut-in September 2010 (red).

General schematic (Verdon et al., 2013)At Weyburn (Verdon et al. 2013), the long field history led to complicated pattern of micro-seismicity:• Most events related to production wells and

during shut-in of CO2 injection well.

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Issue 5) Could it leak out? 1. A lot of public concern around the topic of possible leakage:

Based on evidence or rumours?

2. Many natural stores of CO2 in volcanically active regions of the world:

− Bravo Dome in New Mexico contains 1.6 Gigatons of CO2 which has been there for approximately 1.3 million years(Sathaye et al. 2014; PNAS)

3. Humans (especially the Romans!) have been living alongside natural CO2 vents for 1000’s of years

4. Study of a 400-thousand-year-old leaky fault in a CO2 volcanic region (Paradox Basin Utah) shows a maximum leakage rate of ~870 t/yr(Burnside et al. 2013; Geology, 41, 471-474)

− at the Crystal Geyser tourist spot!

“Jenn couldn't resist playing in the geyser. They don't let you do this in Yellowstone!” Travel blog from www.rvoutoftheratrace.com/My%20Albums/Utah%20Sep%202008/slides/Jenn%20playing%20in%20Crystal%20Geyser.html

Equivalent to annual emissions of 100

Norwegians!

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Communicating storage effectiveness

Laboratory demonstration of capillary seal - using an aquarium tank, air and a food sievehttps://www.youtube.com/watch?v=8-dXwakvmsI

Five arguments for storage safety

1. Climate protection

2. Physical basis

3. Operational experience

4. Geophysical monitoring

5. Regulatory compliance

(Furre et al. 2019, First Break 37, 83-89)

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Ongoing work on storage risksIn support of the Northern Lights project and for future storage scale up, Equinor and many partners are working on:

• Fault mapping from seismic

• Fault Seal and fault permeability

• Pressure communication

• 3D geological modelling

• Geomechanics and strain

• Micro-seismic monitoring

• Flow simulation

Long Wu et al (2019), EAGE Fault & Top Seal Conference

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Back to the big questions?• Is large-scale CCS at all realistic? If so, what would it take to actually deploy it?

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Global distribution and thickness of sediment accumulations on continental margins, with largest oilfields and main river systems (Ringrose & Meckel, 2019)

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 developmentRingrose & Meckel (2019) paper on feasibility of global offshore storage Propose that 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

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

We also need to know well delivery rates

4 scenarios modelled to illustrate the range of expected behaviours

Shallow open

Deep confined

Deep 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 B. Offshore wells only

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

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Application of ∆P method to global developments

• Projected growth of CO2

injection wells based on historical hydrocarbon well developments.

• Concept captures industrial maturation phases for global CO2

storage

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

Main finding:We will need ~12,000 CO2injection wells by 2050 to achieve 2DS goal

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1

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100

1 000

10 000

100 000

1 000 000

10 000 000

1

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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

ls

Texas Active GoM Active Norway ActiveTexas Cumulative CO2 GoM Cumulative CO2 Norway Cumulative CO2

# wells needed for 2DS

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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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A practical pathway for global CO2 storage

• Let’s assume we have five continental clusters around the planet

• What would the build-out rate look like?

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10 000 000

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2010 2030 2050 2070 2090

Cum

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CO

2 In

ject

ed (M

t)

Num

ber o

f Act

ive

CO

2 In

ject

ion

Wel

ls

Norway Active Norway Cumulative CO2

# wells needed for 2DS

Next 10 years: about 200 wells per cluster

By 2040: about 1000 wells per cluster

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Summary1. Reviewed main elements in CO2 storage project design:

− Building on operational experience

− Identifying some key issues and questions

2. Proposed an approach to quantify a pathway for global scale-up:

− Number of wells needed under the 2DS scenario is only a fraction of the historic worldwide petroleum well development rate

− CO2 storage is best achieved with a limited number of dedicated storage hubs/clusters

Main supporting references• Eiken, O., Ringrose, P., Hermanrud, C., Nazarian, B., Torp, T. A., & Høier, L. (2011). Lessons learned

from 14 years of CCS operations: Sleipner, In Salah and Snøhvit. Energy Procedia, 4, 5541-5548.

• Hansen, O., Gilding, D., Nazarian, B., Osdal, B., Ringrose, P., Kristoffersen, J. B., Hansen, H. (2013), Snøhvit: The history of injecting and storing 1 Mt CO2 in the fluvial Tubåen Fm. Energy Procedia, 37 3565-3573.

• Furre, A. K., Eiken, O., Alnes, H., Vevatne, J. N., Kiær, A. F. (2017) 20 years of monitoring CO2-injection at Sleipner. Energy Procedia, 114: 3916-3926.

• Furre, A. K., Meneguolo, R., Ringrose, P., & Kassold, S. (2019). Building confidence in CCS: From sleipner to the northern Lights project. First Break, 37(7), 81-87.

• 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.

• Ringrose, P. 2020. How to Store CO2 Underground: Insights from early-mover CCS Projects. Springer

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