Experiences in managing CO storage projects · • Decline curves show well performance on a...

Experiences in managing CO2 storage projects

Philip RingroseStatoil ASA

IPIECA Workshop:Addressing the remaining gapsin knowledge for CCSWashington DC, September 2011

2 - IPIECA Workshop, Washington DC, September 2011

Talk Outline and Roadmap

1. Operational experience overview

2. Some well technology basics

3. Important lessons learned

Sleipner

In Salah

Snøhvit LNG

1996- 2004- 2008- 2011/12 ?

MongstadFull-scale

Test Centre Mongstad

Statoil’s CCS projectsAn Industrial Approach to the Climate Change Challenge


Snøhvit Sleipner In Salah

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Dep

th (k

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CO2 Storage Site Settings

A valuable blend of• Offshore/onshore• Shallow/deep• Horizontal/vertical wells


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1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Year

Acc

umul

ated

inje

cted

CO

2[m

illio

n to

ns]

Sleipner

In Salah

Snøhvit

CO2 Injection Performance

>17Mt CO2 stored so far (August 2011)


Operating the Sleipner CO2 Project1. Monitoring Data:

Wellhead pressure and flow rate is monitored continuouslyGas composition samples are taken intermittentlySeveral Time-lapse (4D) seismic surveys:

1994 (baseline), 1999, 2001, 2002, 2004, 2006, 2008, 2010

Several Gravimetric surveys• 2002, 2005, 2009

2. Key Uncertainties:Role of internal Utsira shale layersReservoir and wellbore modellingLong-term storage capacity


CO2 wellUtsira Fm.

Sleipner CO2 injection 1994

2001

2008

2008-1994

CO2 plume in map view

Time-lapse seismic data


• In Salah Gas (ISG) is a Joint Venture - BP, Sonatrach, Statoil.

• The gas fields have CO2concentrations of 1 to 10%

• The ISG made a discretionary investment in CO2 capture, compression and injection facilities

• Injection started in 2004 and since then > 3mmt CO2 have been injected

• CO2 injection via 3 long-reach horizontal wells in the aquifer leg

• An extensive monitoring portfolio

The In Salah CO2 Project, Algeria


Monitoring at the In Salah CCS ProjectWide range of monitoring data collected:

• Wellhead measurements:Pressures, ratesGas chemistry, tracers

• Subsurface data:Cores, logs, fluid samples

• Observation wells:1 Microseismic well5 shallow aquifer wellsAppraisal well KB-5

• Surface Measurements:Soil gas, passive gas,

• Satellite InSAR Surveys

• Time lapse (4D) seismic


Value of InSAR for pressure monitoring

• Interferometric Synthetic Aperture Radar (InSAR) data allows mm-changes in ground surface elevation to be monitored

• Has proven especially valuable at the In Salah CCS site (dry rock desert)

− Applicable to most onshore sites

• By combining satellite data with rock mechanical models, we can use InSAR to monitor the sub-surface pressure field related to CO2 injection

• Addresses a key question for CO2Storage – pressure management

May 2009 20mm uplift

Map of surface uplift

Modelled rock strain (section)

Injection Unit(1.9km deep)


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 2600m into the Tubåen/StøFormations (below the gas reservoir).

• Injection of CO2 started in 2008, and so far over 1 Mt have been stored.


Snøhvit: Onshore & Offshore

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

• CO2 injected into TubåenFm at 2430-2600m depth

Reservoir system

Process Facility


Snøhvit Operations• Gradual rise in reservoir pressure indicated

limited injection rate/capacity• 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

Increasingam

plitude

Amplitude change map

Top Fuglen Fm.

Base Tubåen Fm.

2009 Seismic Survey 4D (Amplitude difference)

Seismic sections

Island Wellserver


CO2 well technology basics• How do you design an injection well that ensures:

− Safe operation

− Long-term capacity

− Operational reliability

• The oil and gas industry has experience from:− 100,000’s of production wells

− 1000’s of water injection wells

− 10-100 CO2 injection wells (relatively limited experience)

• Some of the CO2-specific issues we know about are:

− CO2-brine reactions (e.g. salt precipitation)

− Thermal effects (CO2 hotter/colder than reservoir)

− Rock mechanical effects (what is a safe down-hole injection pressure)

− Reservoir heterogeneity effects (lower than expected permeability, reservoir barriers)


Decline Curve Analysis• Production well performance can be generally understood in terms of decline-

curve analysis (Arps, Fetkovich)

• Decline curves show well performance on a log-flow / log-time plot

• Production well performance varies enormously and the industry uses a whole Smörgåsbord of recipies for well operations and perforations to improve well performance

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1-

0.1 –

0.01 –

0.001 -

0.0001 0.01 1 100

qD

tD

Decline rate (b) controlled by fluid and

reservoir propertiesTransient

Depletion

b

• We have much more limited experience on CO2 injection wells

− early stages on the learning curve


Production/Injection well basics• Productivity Index [bbl/day/psi]

• PI for multiphase flow)/ln( weoo

roo

rrBhkkA

PqPI

μ≈Δ=

)( skinwfres PPPqPI Δ−−=

Pressure controlled reservoir geology &

wellbore effects

Multiphase radial flow equation

)( reswi PPqII −=

)]()([)(

resfhbp

resgasgas PmPm

qII −=

• The Injectivity Index is, in principle, similar:

• However, due to compressibility / multiphase effects we need something more complex for CO2 wells:

− e.g. pseudo-pressure method (Al-Hussainy et al. 1966)

dpZpPm

P

Pb

∫=μ

2)(


Well Injectivity Example• CO2 vs Water injectivity for wells which were converted from water to CO2

injection - Nagineni et al 2010 (SPE 132624)

From

CO2 Injection

Water Injection


Snøhvit CO2 Injectivity Example• Example CO2 Injectivity Index (IICO2) from Snøhvit (assuming contant Pres)

• Initial injectivityreduction / fluctuation

•Managed using chemical treatment

•Stable operating injectivity

•Some changes after shut-in period


Conclusions• At Sleipner, In Salah and Snøhvit single wells have successfully

injected 0.4-0.9 mmt of CO2 per year.

• These three mmt/year projects have succeeded in storing >17mmt of CO2 so far

• Global scale-up of CCS clearly requires 100’s of similar projects to be operational as soon as possible

• These early mover CO2 storage demonstration projects highlight some important requirements for the design of future projects


Recommendations1. Injection wells need to be managed and monitored

2. We need experience transfer from oil and gas production/injection wells to build experience for CO2 injection projects

3. Reservoir and operational uncertainties mean that multiple-well options will be needed for robust projects:

Multiple (smart) injection wells with field development options

Pressure and injection management strategies

4. Good monitoring data is vital for site management, especially:

Pre-injection baseline data

Geophysical monitoring programme (fit-for-purpose)

Down-hole gauges (where possible)


Philip RingroseStatoil ASA

www.statoil.com

Thank you

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