Presenting to

SACCCS Conference

24 Oct 2011

The CO2CRC Otway Project

Dr Matthias Raab Program Manager Storage

Cooperative Research Centre

for Greenhouse Gas

Technologies (CO2CRC) © CO2CRC

All rights reserved

Porosity vs Permeability

Tim Tam vs Aero Chocolate – can you spot the difference?

Key aspects for geological storage of CO2

• Where can we store? (Site Selection / Characterisation)

• How much can we store? (Storage Capacity)

• How can we best get it in there? (Injectivity)

• How do we know it will stay there? (Containment)

• How can we tell? (Measuring, monitoring, verification)

• How much will it cost? (Economics)

• What is the Risk? (Risk Assessment / Management)

• Making it happen (Regulatory, Liability, Public Perception)

CO2CRC Storage Program

• 1.0 Program Management

• 1.1 Otway Operations

• 1.2 Stage 1 Integration

• 1.3 Otway Saline Aquifer

• 1.4 Storage in Saline Aquifers

• 1.5 Reactive Reservoir Rocks

• 1.6 Geomechanics of Seals

• 1.7 Reservoir Modelling

• 1.8 Monitoring and Verification

• 3.2 Risk Assessment

• Stage 1: 65kt CO2 injected in depleted Gas Field

• Stage 2: Researching CO2 storage in saline aquifers

• Nine major research streams

• Two large field experiments (2b &2c)

• 79 researchers across 11 Institutions, 15 current PhD students

• 2011-12 FY budget of $11,900,000

• CO2 Sequestration facility in SW Victoria

Conducting world class research into Geological Carbon Storage

Program 1: Storage Research

1.0 Storage Science and Management

1.1 Development and operation of geological

storage research facilities, Otway site

1.2 Otway Phase I integration

1.3 CO2 storage in saline formations –

Otway Basin

1.4 Understanding CO2 storage in saline aquifers

1.5 Reactive reservoir rocks and their impact on

CO2 storage potential trapping

1.6 Seal geomechanics and potential for

CO2 leakage

1.7 Predictive modelling of storage reservoirs

1.8 Improved monitoring and verification

1.9 Developing CCS Risk Assessment Methodology

Structure of the Storage Program

Advanced CCS Projects involving CO2CRC

Major challenges for CCS

• Decreasing the cost of capturing and separating CO2

from major stationary sources

• Identification of safe and secure geological sites for the

safe storage of CO2 from major sources

• Ensuring public confidence in CCS technology through

communication, community consultation, education and

the establishment of an effective regulatory regime

• Large scale deployment of CCS

• Uncertain policy setting

What have been challenges for CO2CRC in the past year?

• Transitioning to the new phase of CO2CRC, and new

members, imposed a significant administrative burden

• New staff appointments

• Costs pressures from the resources boom

• Engaging with industry during boom times

• Funding for expensive and complex operations

• Uncertainties with carbon policy

• Maintaining research cooperation in a competitive

environment

• External funding complexities and opportunities

What have been some of the successes of CO2CRC in the past year?

• Maintenance of position as a leading collaborative CCS

R&D organisation, based in Australia, working globally.

• Addresses and integrates capture and storage systems

• Brings industry sectors together (coal, gas, power, etc)

• Brings together Commonwealth, States, local government

and the community in the Otway Project

• Includes major research institutions - CSIRO, GA,

Universities, major overseas institutions (LBNL, KIGAM)

• Bring together approx. 200 CCS researchers

• Broad international perspective and experience

• Successful track record in running major CCS facilities

• Number of patents and other IP

The CO2CRC Otway Project

• Australia’s only Sequestration Facility

• One of few operational sequestration sites in the world

• Operating since 2008

• Research and injection into depleted hydrocarbon reservoir (Stage 1)

• Research and injection into saline aquifer (Stage 2)

• Unique research facility with global collaboration

• Concept, research and facilities provide blueprints to other CCS projects

• Will remain Australia’s only CO2 injection site at least until 2015.

Getting a Carbon Storage up and running

The CO2CRC Otway Project Stages 1 & 2

The simple concept

• Someone who likes the project to succeed

• Source of CO2

• Suitable storage sites nearby

• Permits and regulations

• Local community agreement

• $$$

• Research capacity

• demonstrating safe Geological Carbon Storage, and

• ways to measure, monitor and assure that it is safe

CO2CRC Otway Project

- Australia’s first storage project • Injection commenced 2 April 2008 –

65,000 tonnes CO2 injected into

depleted Gas Field

• Stage 1 cost A$40M -completed 2010

• Stage 2 cost A$20M - underway

• Monitoring and verification a key

component

• Developments include regulation, risk,

liability, technology

• Successful science, ops,

communications, community, politics

• Stage 2 will examine fundamentals of

CO2 trapping and subsurface

processes

The CO2CRC Otway Project - Stage 1 & 2

CO2CRC Otway Project Aerial View

Buttress well – CO2 source

Naylor-1 well – ex reservoir storage

CRC-2 well – saline aquifer storage 1.4 km

Visitors centre

CRC-1 injection well

CO2 migration

CO2 pipeline

Risk Example – Pre Implementation

Regulatory Approvals

Activity Approvals/Permits Regulator Application Process

Production of CO2 Production Plan DPI - Petroleum Act 2000 (DPI).

Compression & Transport of

CO2:

1) Plant (compressor)

2) Gathering line

3) Other facilities (centre,

etc…)

Planning Approval,

Gathering Line

Approval

DSE, DPI,

Moyne Shire,

DOI

- Petroleum Act 2000 (DPI)

- Ministerial Amendment request of the Planning & Environment Act

1987 (Moyne Shire/DSE)

- Exemption of Pipeline Act 2005 (DPI)

- Cultural Heritage Act (DPI)

- Compensation agreement: consent to land access

- Project of Significance and Compulsory Acquisition (DOI)

- Exemption of Rural Fire Service (CFA)

Drilling of New well Drilling License SRW, DPI - Submit EMP, SPM and Drilling plan. Well drilled under water

license.

Injection of CO2

(CRC-2)

Disposal Approval SRW, EPA - Water Act 1989 Section 76 & 67: Application for approval to

dispose of matter by means of a bore

- Compensation agreement: consent to land access

Storage of CO2 Storage Approvals EPA - Environment Protection Act 1970: Research Development and

Demonstration (RDD) Approval (EPA)

Monitoring & Verification

1) Atmospheric

2) SOBN Water wells

3) Down-hole (Naylor-1)

Monitoring

Planning Approval,

Compensation

Agreement, DSE

access rights

EPA,DSE,

Moyne Shire

- Ministerial Amendment request of the Planning & Environment Act

1987 (Moyne Shire/DSE)

- Consent to use (SOBN) bores (DSE)

- Compensation agreement: consent to land access

3D surface seismic monitoring (Subsurface)

Geophysics

Assurance monitoring &

Storage integrity monitoring

Objective: to map the migration

path of CO2 plume from injector to

producer

Methods: 4D or time-lapse surveys

Repeatability of surveys before,

during and after the CO2 injection

is very important for every aspect of

acquisition (source and receivers

positioning; source signal;

hardware; time of year; processing)

Hydrodynamics & groundwater Monitoring (Near-Surface)

Geochemistry

Assurance Modelling

Objective:

- Monitor water levels to determine seasonal

variation, flow rate and direction

- Identify any chemical changes associated with

possible CO2 leakage

Methods:

- Dataloggers

- Water chemistry

Aquifers monitored:

- Shallow unconfined Port Campbell Limestone,

- Deep confined Dilwyn aquifer

Sc re e n

D a ta lo g g e r

W a te rle v e l

Ste e l C a b le

C a b le p e rm a n e n t ly in st a lle d

C a p

5 - 1 0 m

Soil Gas Monitoring (Surface)

Geochemistry

Assurance surface monitoring

Objective:

- Establish CO2 variations within the extended

area beyond the CO2CRC tenements

- Determine the likely source of origin

- Differentiate natural from injected CO2.

Methods:

- The soil gas program extracts air from the

unsaturated soil zone above the water table.

- Samples are analysed on site (portable gas

chromatograph) and in the laboratory for CO2,

CH4 and isotopes.

Frequency

- Baseline: Four surveys

- Once a year during and after the injection

Atmospheric Monitoring

Objectives:

To verify that injected CO2 stays underground; or in the unlikely event

of leakage to surface, demonstrate the capacity to detect and quantify

surface leakage Otway

Cap Grim

Figure X – U-tube surface facility

(yellow container) – above

Figure X – Isotube sample

cylinder – left

Figure X – Inside the u -tube

surface facility - right

Downhole fluid sampling

Injection phase: U-Tube-2 results

July – minor pH changes,

tracers detected

CO2 arrival

within

modelling

predictions August – significant pH

drop, increase in

dissolved CO2, tracers

peak September – gas lift

Otway Stage 2 – storage in saline aquifers

2A: Drill CRC-2

well

2B : Residual

gas saturation

test

2C: Test seismic

detection on

larger volume

injection

CO2CRC Otway Project Stage 2

Volumetric equation for capacity calculation

NETL DOE, 2006

= Volumetric storage capacity

A = Area (Basin, Region, Site) being assessed

hg = Gross thickness of target saline formation defined by A

f = Avg. porosity over thickness hg in area A

r = Density of CO2 at Pressure & Temperature of target saline formation

E = Storage “efficiency factor” (fraction of total pore volume filled by CO2)

EhAG gCO rf2

2COG

The $15M question: how to determine Sgr?

Trapping in a saline formation

Residual trapping is where small amounts of CO2 are

disconnected from each other, trapped in the pore space.

Stage 2b – Residual Gas Saturation Test

• Single well injection test evaluating residual CO2 trapping for

potential storage sites

• Applying a suite of five independent tests quantifying

maximum residual gas saturation in saline aquifers

1. Hydraulic pressure test

2. Tracer test

3. Thermal test

4. Measure hydrogen index using a pulsed neutron log (RST)

5. Dissolution test

• Ultimately determining the maximum capacity of a reservoir to

residually trap CO2

2b Test Activity and Timeline

CRC-2 Downhole Completions Equipment

Hydraulic pressure test

• Pressure data are sensitive to residual

gas saturation

• Pressure sensors are installed above

and below the perforation

• Pressure transients are recorded to

infer the amount of gas trapped in the

formation

→Pressure change depends on relative permeability

→Relative permeability depends on residual gas saturation

Noble Gas Tracer Test (Kr-Xe)

• Tracers are injected into the formation with water and then back

produced (U-Tube sampling)

• Noble Gas Tracers partition between aqueous and CO2-rich

phase

• Portions will partition into the gas and become immobile

(hence not produced back)

• Tracers in water remain mobile and are being back produced

→ Measured with GC’s and MS’s in Mobile Geochem Lab

→ Residual saturation can be inferred by comparing Break

Through curves

Tracer Test

Tracer Injection

0

200

400

600

800

1000

1200

0 20 40 60 80 100 120 140 160 180

trac

er

pp

m

water production (tonnes)

Kr

Xe

0

50

100

150

200

250

0 20 40 60 80 100 120 140 160 180tr

ace

r p

pm

Water production (tonnes)

Kr

Xe

Baseline Test (100% Pore Water) Residual CO2 Saturated

Kr-Xe Partitioning

Fiber-Optic Distributed Temperature Sensors

Thermal (Heat Transport) Test

• Temperature data are sensitive to residual gas saturation

• Thermal diffusivity depends on fluid composition (i.e. amount of CO2

in the system)

• Supercritical CO2 has 20 times smaller thermal diffusivity than

formation water

• Temperature is hotter in CO2 rich regions of the reservoir and thermal

decay is slower

• Heating/Cooling Test with fibre optic distributed temperature sensor

(DTS) for in situ conductivity measurements

• Simple test: 2 days heating, 3 days cooling

• High accuracy in monitoring thermal response (±0.1°C)

→ Detects CO2 saturation changes smaller than 0.05

→ Penetrates 1-2m into formation (RST only 20cm)

DTPS Temperature Screen shots

Sgr via pulsed neutron reservoir saturation tool (RST)

RST results TPHI

• CO2 has replaced formation

water

• Ø Sgr is ~20%

• Sgr ~23% in top half of

interval

• Sgr ~18% in bottom half of

interval

• Blue shaded region is CO2

saturation after CO2

injection

• Green shaded region is CO2

saturation after water

injection

Comparison of three RST runs: • Pre injection

• Post CO2 injection

• Post water injection

Pump Gassing up

Where from here?

• Preliminary results in Dec 11 at Symposium in Adelaide

• Final data interpretation and report in ca. 12 months

• Blueprint for other storage projects globally

• Controlled release of CO2 for to calibrate atmospheric

monitoring

• Site being mothballed

• In the meantime: 2c progressing through peer review and

regulatory approvals

• Providing continuous advice to national and international

Geological Sequestration Projects

Next research phase: Otway Stage 2c

Research objectives

• Minimum volume of free CO2 to be imaged by 3D seismic (10kt+)

– Demonstration of CO2 dissolution trapping (“diminishing” plume in

seismic image)

• Clear demonstration of CO2 residual trapping in an unconfined structural

trap (i.e. “immobilised” plume)

• Repeated borehole seismic testing whether CO2 plume evolution can be

monitored

• Migration and monitoring forecasts for new large-scale projects

Can we really see CO2?

- =

Post-injection Pre-injection Difference

What is the signal to noise?

Objectives of the simulations

• Understand the migration of 10,000 tonnes

of CO2 injected into the Paaratte saline

aquifer

• Assess the CO2 plume characteristics

Methodology

• Geological Model for Zone 1 in Paaratte Formation (5 realisations)

• Eclipse300 – Compositional Model (Peng-Robinson EOS)

• Injection Gas = 80% CO2 + 20% CH4 by mol fraction

• Pres = 142 bars @ perforation top; Tres 56.3 °C; Salinity < 2000 ppm

• Target Injection Rate: 111 t/d (10k tonnes / 90 days)

• Post-Injection Observation: short-term (90 days)

Well locations & splay fault

S

N W

E

CO2 plume evolution – case 1

3k tonnes

90d post

6k tonnes

1year post

10k tonnes

CO2 plume evolution – case 1 – 30k

10k tonnes

30k tonnes

20k tonnes

1year post

Water density– case 1

3k tonnes injected

90 days post-injection 1 year post-injection

10 tonnes injected

Plume characteristics

homogeneous

Case 4

Lateral extension (metres)

Avg. gas saturation

(%)

Avg. plume thickness (meters)

Injected gas inventory (%)

EW NS Free Trap-ped

Dissolved in water

When inj. ceased

400 >430 48 1.8 70 18 12

90-day post injection

500 >430 40 1.8 69 17 14

1-year post-injection

530 > 430 24 2.0 64 16 20

Case - 1

boundary effects in south

The fastest way to finish a project:

Finish it

The waterproof way of killing a project:

Do it slowly

Thank you

CO2CRC would like acknowledge the

Global CCS Institute for the support they

have provided for this presentation

Established & supported under the Australian Government’s Cooperative Research Centres Program

CO2CRC Participants

Supporting Partners: The Global CCS Institute | The University of Queensland | Process Group | Lawrence Berkeley National Laboratory

Government of South Australia | CANSYD Australia | Charles Darwin University | Simon Fraser University