Case Study: The Gorgon CO Injection Project - ga.gov.au · PDF filein joint venture with...

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© Chevron 2010 Operated by Chevron in joint venture with ExxonMobil, Shell, Chubu Electric, Osaka Gas and Tokyo Gas Case Study: The Gorgon CO 2 Injection Project Scott Ryan Senior Reservoir Engineer Gorgon CO 2 Injection Project

Transcript of Case Study: The Gorgon CO Injection Project - ga.gov.au · PDF filein joint venture with...

Page 1: Case Study: The Gorgon CO Injection Project - ga.gov.au · PDF filein joint venture with ExxonMobil, Shell, Chubu Electric, Osaka Gas and Tokyo Gas Case Study: The Gorgon CO 2 Injection

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Case Study:

The Gorgon CO2 Injection Project

Scott RyanSenior Reservoir EngineerGorgon CO2 Injection Project

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The Gorgon Project Joint Venture Partners have agreed to construct the world’s largest subsurface CO2disposal facility on Barrow Island, off Australia’s northwest coast

Subsurface disposal of CO2 requires many of the same technologies and skills as other major petroleum developments:

Data acquisition and subsurface evaluation using multidisciplinary subsurface teams

Coordinated approach to field development planning and uncertainty management

Integrated reservoir surveillance planning to monitor subsurface CO2 behaviour following injection

The CO2 Injection Project was therefore treated with the same attitude and approach as for the gas field development plans

The technical feasibility of CO2 disposal beneath Barrow Island has undergone several phases of Joint Venture and State Government sponsored peer review

Key Messages

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Gorgon Project Development Concept

Gas produced from subsea wells in Gorgon & Jansz fields (>2 Bcf/day gross)

LNG (15 MTPA) + Domestic Gas (300 TJ/d) processed & exported from Barrow Island

Gorgon gas ~14% CO2

Jansz gas <1% CO2

CO2 separated and injected into Dupuy formation below Barrow Island (1.6-2.4 Tcf total CO2)

Project now under construction

First gas production 2014

Additional discovered fields under evaluation for future tieback

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0.89

0.08

0.06

0.20

0.20

0.35

0.07

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

1998 Concept -GreenhouseChallengeAgreement

Use of Sub-SeaProduction System

LNG TechnologyImprovement

Improved WasteHeat Recovery

Reservoir CO2injection

Reference CaseEmissions Efficiency

Potential for FurtherReductions Based on

PerformanceTargets

Tonnes

CO

2e

/ Tonne

LNG

0.89

0.08

0.20

0.06

0.20

0.35

1998 Concept

Subsea Production

System

LNG Technology

Improvement

Improved Waste Heat Recovery

Reservoir CO2

Injection

Reference Case Emissions

Efficiency

Potential for Future

Reductions Based on Performance

Targets

Reservoir CO2 Injection Project

The first major project in Australia to significantly reduce project emissions by the underground injection of carbon dioxide

Project emissions expected to be reduced by approximately 40% (~3.4-4 MTPA CO2equivalent)

About A$2 billion will be invested in the design and construction of the CO2 project

Costs per tonne remain less expensive than alternate abatement options

Number of world firsts

First geosequestration legislation

First CO2 injection project to undergo detailed environmental impact assessment (including public review and comment)

Largest subsurface CO2disposal project in the world

0.07

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Site screening and selection

Four criteria considered:

Containment risk – e.g. security of top seal, distance to faults, number / condition of existing well penetrations

Storage capacity – e.g. gross rock volume, regional structure capacity, reservoir architecture, connected aquifer extent

Injectivity - e.g. permeability, thickness and extent of target reservoir sands

Risk to other assets – e.g. risk of fluid / pressure interference with other operating, discovered or undiscovered hydrocarbon fields

19 sites / concepts initially assessed in screening study:

Saline aquifers

Existing hydrocarbon fields

Enhanced Oil Recovery opportunities

Five sites further assessed with screening-level simulation studies

Barrow Island Dupuy Formation only site that adequately satisfied all criteria

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Project sited on north-east of islandNine CO2 injection wells (with space for nine more) from three drill centresFour water production wells + water injection wellsPeak stream day CO2 rate: 220 MMscf/dCO2 volume: 1.6 – 2.4 Tcf (~ 80-130 million tonnes)Reservoir Surveillance:

Surveillance wells - two initially plus two in later field life

Repeat 4D seismic (if successful) + Vertical Seismic Profiles

Soil Gas surveys

Abandonment of existing Dupuy wells in plume area; program for ensuring existing well penetrations in the plume area do not provide leakage pathwaysCommitment to make data from the ongoing monitoring available to the public

CO2 Reference Case Development Plan

Pressure management

wells

CO2injection

wells

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Proposed injection interval

Barrow Island Stratigraphy

~20 Km

BarrowFault

2000m

2500

App

roximate Dep

th (m

etres)

UpperDupuy

UpperMassive Sand

LowerDupuy

Din

goCl

ayst

one

~20 Km

Basal Barrow Group Shale

Barrow Group Delta 1

Basal Dupuy

Perforans Siltstone

S N

UMS Upper

UMS Lower

LD UpperPS 4

PS 3

Dupuy Formation

Site selection was vital – Dupuy has adequate permeability for injectivity but low enough for good residual gas trappingAdequate existing subsurface dataSeveral seals between injection zone and surface

CO2 Injection Interval – Barrow Island

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Reservoir Simulation – Testing Development Plan

CO2 plume migration influenced by pressure management wells, reservoir quality & distribution, buoyancy, rate of dissolutionEffects incorporated into reservoir simulation modelsWide range of subsurface uncertainties investigated using:

Full field models (testing overall development plan)Sector models (investigating specific effects, e.g. near-wellbore)

Development plan tested against two main criteria:

INJECTIVITY – i.e. scheme must handle rate of produced CO2 from GorgonCONTAINMENT – i.e. scheme must retain total volume of CO2 in the subsurface

Full field modeling

Sector modeling

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Pressure management required to reduce impact of rising pressure on CO2injection performance:

Maintain injection rates

Avoid reaching bottom hole pressure limit

100% offtake balance not necessary – expect large connected aquifer to “absorb” much of the pressure increase

Produced water injected into overlying Barrow Group (depleted)

Pressure Management Concept

4 water production

wells to manage reservoir pressure

60-80 krbbl/d

9 CO2injection

wells

220 MMscf/d

~150 krbbl/d

0 5

kilometres N65 years

CO2 plume movement – influence of pressure management wells

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0 7 14m

Net CO2 Thickness: Σ Sg.Φ.h

0 5

kilometres N

WEST EAST

Low Highφ

CO2 injection wells (proj.)

Water production well (proj.)

0 5kilometres

Growth of CO2 plume over time

Line of section

• Plume movement influenced by water offtake, reservoir depositional trends and structure

• Growth in plume area is rapid during injection, but limited following site closure

• CO2 concentrated in centre, very diffuse at edges

YEAR0005

Low HighSg

Upper Dupuy

Upper Massive Sand

Lower Dupuy

Basal Dupuy

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0 5

kilometres N

WEST EAST

Low Highφ

CO2 injection wells (proj.)

Water production well (proj.)

Growth of CO2 plume over time

Line of section

• Plume movement influenced by water offtake, reservoir depositional trends and structure

• Growth in plume area is rapid during injection, but limited following site closure

• CO2 concentrated in centre, very diffuse at edges

YEAR0010

0 7 14m

Net CO2 Thickness: Σ Sg.Φ.h

Low HighSg

Upper Dupuy

Upper Massive Sand

Lower Dupuy

Basal Dupuy

0 5kilometres

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0 5

kilometres N

WEST EAST

Low Highφ

CO2 injection wells (proj.)

Water production well (proj.)

Growth of CO2 plume over time

Line of section

• Plume movement influenced by water offtake, reservoir depositional trends and structure

• Growth in plume area is rapid during injection, but limited following site closure

• CO2 concentrated in centre, very diffuse at edges

YEAR0020

0 7 14m

Net CO2 Thickness: Σ Sg.Φ.h

Low HighSg

Upper Dupuy

Upper Massive Sand

Lower Dupuy

Basal Dupuy

0 5kilometres

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0 5

kilometres N

WEST EAST

Low Highφ

CO2 injection wells (proj.)

Water production well (proj.)

Growth of CO2 plume over time

Line of section

• Plume movement influenced by water offtake, reservoir depositional trends and structure

• Growth in plume area is rapid during injection, but limited following site closure

• CO2 concentrated in centre, very diffuse at edges

YEAR0040

0 7 14m

Net CO2 Thickness: Σ Sg.Φ.h

Low HighSg

Upper Dupuy

Upper Massive Sand

Lower Dupuy

Basal Dupuy

0 5kilometres

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0 5

kilometres N

WEST EAST

Low Highφ

CO2 injection wells (proj.)

Water production well (proj.)

Growth of CO2 plume over time

Line of section

• Plume movement influenced by water offtake, reservoir depositional trends and structure

• Growth in plume area is rapid during injection, but limited following site closure

• CO2 concentrated in centre, very diffuse at edges

YEAR0065

0 7 14m

Net CO2 Thickness: Σ Sg.Φ.h

Low HighSg

Upper Dupuy

Upper Massive Sand

Lower Dupuy

Basal Dupuy

0 5kilometres

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0 5

kilometres N

WEST EAST

Low Highφ

CO2 injection wells (proj.)

Water production well (proj.)

Growth of CO2 plume over time

Line of section

• Plume movement influenced by water offtake, reservoir depositional trends and structure

• Growth in plume area is rapid during injection, but limited following site closure

• CO2 concentrated in centre, very diffuse at edges

YEAR0100

0 7 14m

Net CO2 Thickness: Σ Sg.Φ.h

Low HighSg

Upper Dupuy

Upper Massive Sand

Lower Dupuy

Basal Dupuy

0 5kilometres

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0 5

kilometres N

WEST EAST

Low Highφ

CO2 injection wells (proj.)

Water production well (proj.)

Growth of CO2 plume over time

Line of section

• Plume movement influenced by water offtake, reservoir depositional trends and structure

• Growth in plume area is rapid during injection, but limited following site closure

• CO2 concentrated in centre, very diffuse at edges

YEAR0500

0 7 14m

Net CO2 Thickness: Σ Sg.Φ.h

Low HighSg

Upper Dupuy

Upper Massive Sand

Lower Dupuy

Basal Dupuy

0 5kilometres

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0 5

kilometres N

WEST EAST

Low Highφ

CO2 injection wells (proj.)

Water production well (proj.)

Growth of CO2 plume over time

Line of section

• Plume movement influenced by water offtake, reservoir depositional trends and structure

• Growth in plume area is rapid during injection, but limited following site closure

• CO2 concentrated in centre, very diffuse at edges

YEAR1000

0 7 14m

Net CO2 Thickness: Σ Sg.Φ.h

Low HighSg

Upper Dupuy

Upper Massive Sand

Lower Dupuy

Basal Dupuy

0 5kilometres

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Simulation

SurveillanceMitigation

40 150GR 0.2 20ILD 1MetersTVDSS

-2200

-2100

-2000

Signpost

Managing Risk –Reservoir Surveillance Objectives

Reservoir surveillance options have been selected to assist responsible reservoir management

Reservoir surveillance focused on early identification of uncertainty “signposts” (as per Uncertainty Management Plan)

When signposts are identified, then mitigation plans can be implemented to ensure the injected carbon dioxide continues to be properly managed

Integration of reservoir surveillance and reservoir simulation data will assist the demonstration of site integrity

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Integrated Monitoring Plan

CO2 Injection & Pressure Management Wells

Wellhead pressure and flow rate

Continuous down-hole pressure

PLT & casing/cement integrity logs

Surveillance Wells – Vertical distribution and volumetric calculation

Continuous downhole pressure (Barrow Gp)

Saturation & casing/cement integrity logs

Vertical Seismic Profiling (VSP)

4D Surface Seismic – Lateral extent and broad vertical distribution

3D baseline survey

Repeat 2D and 3D surveys determined by viability of seismic for monitoring plume position

Soil Gas - Verification

Soil gas flux sampling over the 3D seismic source grid and at potential near-surface seepage points

Surface – Safety & environment

Pressure sensors and CO2 detection equipment within compression and pipeline facilities

Surveillance well

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Injection Period

Post -Injection Period

Post -Closure Period

Conceptual Risk Profile

Time

High

Low

Site Closure

Ris

k

Reservoir Monitoring, Risk Mitigation & Site Closure

Monitoring aimed at identifying signposts so that effective mitigation actions can be implemented

Site closure is the point where operational responsibility ends and is marked by satisfaction of site closure criteria

Criteria to be determined by legislation

Future land use objectives can be met

Residual risk of leakage and resulting liability is acceptably low

Any ongoing costs are low or otherwise appropriately managed

Liability transferred to State and Commonwealth Governments

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Concluding Messages

The Gorgon CO2 Injection Project is first of its kind in many technical and regulatory aspects

The same attitude and approach to subsurface studies and development was adopted for the CO2 project as for the hydrocarbon fields

Much effort was invested into project assurance for internal and external stakeholders

Pressure management wells are fundamental to the development plan

Reservoir surveillance is important to maintain performance and to capture lessons learned

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Acknowledgements

The authors wish to thank Chevron and the Gorgon Joint Venture

Participants:

ExxonMobil

Shell

Chubu Electric

Osaka Gas

Tokyo Gas