Moving CO EOR offshoreiea-eor.ptrc.ca/2010/assets/F5_Slides.pdf · 2011-12-04 · Oil saturation (%) CO 2 has water-like injectivity CO 2 has water-like injectivity 0 200 400 600

Copyright of Shell International LTD CONFIDENTIAL 20 October 2010 1

Moving CO2 EOR offshore

IEA Collaborative Project on Enhanced Oil Recovery

31st Annual Symposium and Workshop

Aberdeen, Scotland

Stephen Goodyear, Martin Koster, Keith Marriott,

Alison Paterson, Ton Sipkema and Iain Young

Copyright Shell International LTD CONFIDENTIAL

Introduction – Why CO2 EOR?

CO2 is the dominant anthropogenic greenhouse gas driving global warming

CO2 is an effective miscible flooding agent for EOR

Capturing CO2 from industrial sources in EOR projects can maximize hydrocarbon recovery and help provide a possible bridge to a lower carbon emissions future

Adding value through EORproduction and field life extension

Providing long term secure storagepost-EOR operations CO2 in reservoir is capillary trapped

at end of post-WAG waterflood

Saline aquifer storageIEA Collaborative Project on Enhanced Oil Recovery



Shell has been active in CO2 EOR since the 1970s

Shell has been active in CO2 flooding since the late 1970s

pilot projects

initiator and operator of large scale onshore CO2 EOR floods in the Permian Basin, USA.

Shell is working to implement new generation CO2 projects, including offshore applications.

This presentation describes some of the challenges and the solutions developed based on recent project experience of offshore CO2 EOR and carbon storage

Feasibility studies

Concept selection

20 October 2010 3IEA Collaborative Project on Enhanced Oil Recovery



Typical CO2 EOR Overview

1. CO2 captured

from flue gas

CO2Capture

WellheadProcessing

Oil

Flowlines

FlueGas

CO2 pipeline

Wells

CO2Flood

2. CO2 transported

offshore by pipeline 3. CO2 injected into

reservoir, alternating

cycles with water

4. CO2 sweeps oil

from reservoir

6. CO2 recycled

back to reservoir5. Oil separated for export,

water disposal

7. CO2 left in reservoir

after EOR

Offshore CO2 EOR project schematic



20 October 2010


Production profiles for phased CO2 EOR

Production profiles unlike conventional offshore developments

Production dominated by water and gas Oil a “by-product”

Pace of development driven by CO2 import

Peak oil achieved late

20 October 2010 5

Gas

han

dli

ng

Liq

uid

pro

du

ctio

n r

ate

Time

Water

Oil




Outline

Safety

Facilities and wells

Subsurface

Pilots

Surface and subsurface integration

Conclusions




Safe operation first priority

CO2 HSE

Significant experience of CO2 operations for onshore EOR projects

Operation of CO2 EOR offshore will introduce new set of challenges

Inventory, pressure, confined spaces, evacuation

RECYCLE COMPRESSORS

CO2 PUMPS

INJECTION

COMPRESSORS WELL

Plant tobeach valve

CPF platform

WHP platform

Export Pipeline to boarding valve Injection flow-linesProduction lines

100-1000 t CO2 ~10000 t CO2 ~ 50 t CO2 ~ 500 t CO2

(H2S, CH4)

~ 100 t CO2

(H2S, CH4)

Safety



20 October 2010


CO2 Test Program – Spadeadam, UKMar – Nov 2010

Main risks with CO2 releases:

Operational risks of working with dense phase CO2

Emergency response – evacuation, underwater pipeline releases, detection and mitigation

CO2 Release Program objectives:

Gather data on the release and dispersion of CO2 to evaluate and validate hazards consequence models and thereby reduce current conservatism necessary in hazard predictions

Study impact of cold CO2 in confined spaces on equipment, personnel, and emergency response

Test emergency response systems



20 October 2010


Outline

Safety


Subsurface

Pilots


Conclusions





EOR production always comes with requirement to handle significant volumes of back produced CO2

Re-use of existing facilities and wells for CO2 EOR limited by:

Corrosion

Compatibility of non-metallicmaterials with CO2

Large CAPEX commitment up front for infrastructure



Copyright Shell International LTD CONFIDENTIAL0

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To

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ides

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igh

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ou

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6 legged jacket limit

8 legged jacket limit

Offshore CO2 facilities weight

Separation of water/oil at high gas rates

Large first stage separators

Oil production at high water cuts

Large liquid production rates required

Large topsides weight.

Retrofit may not be feasible offshore.



Gas

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Design principles and key decisions

Overriding design principle HSE

Keep facilities simple but flexible (to minimise CAPEX, weight , space)

More requirement to get design right up front vs. e.g. ability to incrementally evolve gas handling capacity for onshore project

Key integrated surface/sub-surface decisions

Gas treatment

Artificial lift

Facilities capacity




Outline

Safety


Subsurface

Pilots


Conclusions




Subsurface issues

Operating onshore CO2 EOR projectscharacterised by

Low permeability, 1-100md

Tight pattern spacing ~10-20 acre

Generally viscous dominateddisplacements, CO2 goes wherewater has already been

Offshore EOR

Many offshore reservoirs are excellent quality with permeabilities of 100s to 1000s md

High well cost requires much larger well spacing to address sufficient oil in place to justify workovers or new wells

20 October 2010 14

Denver unit surface layout




Gravity segregation

In good quality reservoirs with high vertical permeability gravity causes CO2 override in waterflooded intervals

Poorer recovery unless significant attic oil volumes present

Unlike onshore projects can also be a significant density contrast between reservoir oil and injected CO2

20 October 2010 15

0

20

40

60

80

100

120

140

160

0 1000 2000 3000 4000 5000 6000 7000 8000

Pressure psiT

em

pera

ture

oC

North Sea fields

Draugen

Permian Basin

650 kg/m3

400 kg/m3

450 kg/m3

500 kg/m3

550 kg/m3

600 kg/m3

700 kg/m3

750 kg/m3

800 kg/m3

850 kg/m3

900 kg/m3

950 kg/m3

1000 kg/m3




Non-standard displacement mechanisms with high vertical permeability

CO2 plume moving up dip

Mobilised oil in rim between gas and water flooded zone

Difficult to capture

As vertical gridding refined solution converges to black oil solution with no gas resolution

Recovery controlled by transverse diffusion/dispersion at gravity stabilised interface between gas plume and oil rim

Slow net oil

movement

Oil collects in a bank as the water/oil

saturation shock moves down

Component transfer,

driven by diffusion and transverse dispersion

Impact of miscibility?

High gas rate



20 October 2010


Horizontal wells

Pattern arrays of alternating horizontal injectors and producers

Conformance management

Placement of horizontal wellstowards base of formation mitigate gravity segregation

reduce impact of permeability contrastsin coarsening upwards sequences

Low permeability reservoirs

Reduce well count to achieve necessary reservoir throughputrates for economics

Well PI has strong dependency on spacing and configuration of injectors and producers



P

P

PI

I


Outline

Safety


Subsurface

Pilots


Conclusions




Role of pilots – Permian Basin

Implementation of CO2 EOR in Permian Basin required large infrastructure investment to supply CO2

Investment underpinned by EOR pilot

Follow-on projects used existing infrastructure and could phase implementation through small scale demonstration projects

20 October 2010 19

Denver Unit CO2 Pilot - Key LearningsDenver Unit CODenver Unit CO22 Pilot Pilot -- Key Key LearningsLearnings

CO2 displaces tertiary oil


Movable PV CO2+ brine

within pressure core radius

0.1 1 10 100 1000

50

40

30

20

10

0

Oil saturation (%)





0.1 1 10 100 1000

50

40

30

20

10

0

Oil saturation (%)



0.1 1 10 100 1000

50

40

30

20

10

0

Oil saturation (%)

CO2 has water-like injectivity


200 400 6000

5

0

MRB CO2+ brine injected

Brine

RB/D-psi

CO2 Brine



200 400 6000

5

0


Brine

RB/D-psi

CO2 Brine

200 400 6000

5

0


Brine

RB/D-psi

CO2 Brine

Stratificationimportant


* basis 1 PV injected into total interval

75

14.2

5.5

4.9

None

2.24

0.81

0.53

0.39

None

23.7

17.6

10.4

12.7

25.6

% PoreSpace % Injected Fluid

PV Thruput*

•3/4 of CO2 goes after 1/4 of oil

•1/4 of pore space unswept



* basis 1 PV injected into total interval

75

14.2

5.5

4.9

None

2.24

0.81

0.53

0.39

None

23.7

17.6

10.4

12.7

25.6

% PoreSpace % Injected Fluid

PV Thruput*

•3/4 of CO2 goes after 1/4 of oil

•1/4 of pore space unswept

Denver Unit Pilot

Permian Basin

500 miles




Offshore CO2 pilots

Typical CO2 rate for injector in field development 20-40 MMscf/d

Similar order as large scale CO2 capture train

Early adopter has no existing supply infrastructure

Implications for facilities of back produced CO2

Offshore options, depending on uncertainties to be addressed

No pilot

Single well injection test with CO2

Target oil, microscopic sweep efficiency, injectivity

Miscible or immiscible hydrocarbon gas pilot Conformance

Offshore tankering of CO2 may provide increased range of options?

Additional safety and operational issues20 October 2010 20IEA Collaborative Project on Enhanced Oil Recovery



Outline

Safety


Subsurface

Pilots


Conclusions




Integrated decisions – Recycled gas treatment

Hydrocarbon gas present in recycled gas, but at high CO2

content

Options to consider

Recovery of methane

NGL only

Full or partial recovery

Integrated decision

CAPEX and module weight

Fuel gas requirement, CO2

content of recovered gas

Impact on EOR performance20 October 2010 22

Mo

l %

CO

2in

ga

s s

trea

m

Time

Produced gas stream

Injected gas stream

Change in gas composition for single pattern

with full recycle of produced gas




Impact of gas processing choices on reservoir performance

Full gas reinjection may have limited impact on Minimum Miscibility Pressure (MMP)

Methane (C1) increases MMP

NGLs (C2-C4) decrease MMP

Full gas recovery

Reduces total net gas injection and slows incremental recovery

Partial NGL recovery

Need to consider impact on MMP and recovery

20 October 2010 23

0%

20%

40%

60%

80%

100%

120%

140%

0 10 20 30

Fra

cti

on

of

pu

re C

O2 M

MP

Mole % C1 in Inj. Gas

Mole % C2-C4 in Inj. Gas

Recycle Gas Composition Path




Recycled gas treatment offshore

Recovery of C1 with current technology not attractive

Bulk extractive distillation – weight/space

Membranes – high unit technical cost, CO2 in recovered gas

Partial recovery of NGLs may be justified Turbo-expander

Refrigeration

Joule-Thompson cooling

JT preferred – lower CAPEX and simpler facilities

Shell developing new technology

Cryogenic techniques and novel membranes

20 October 2010 24

0.38 nm

0.38 nm

0.32 nm

0.36 nm

CO2

CH4

H2SPorous Support

Inorganic membranes

CryoCell




Integrated decisions – Artificial lift

Requirement for artificial lift to produce wells at high water-cut prior to CO2 breakthrough

Liquid rates 10-30 Mbpd

After CO2 breakthrough wells will autolift

During post-WAG waterflood wells may also require artificial lift

Conventional options

20 October 2010 25

ESP HSP Hydrocarbongas lift

•Can operate over required range•Experience in onshore CO2 floods, but not at high rates required offshore

•Volumes of power fluids required too high

•Prohibitive cost of hydrocarbon gas recovery system




Issues for ESPs

Requirement for additional surface system

Additional CAPEX, weight/space

Number of variable speed drives

has to be matched against uncertainty in reservoir injectivity/productivity, issue if designing for fixed CO2 import

ESP workover frequency

Compatibility with Smart well systems for monitoring and inflow control

Reliability of wet-connect




Integrated CO2 gas lift system

Use CO2 for lift gas

Protect casing from corrosion by injecting lift gas through insert string or dual string

Tapered production tubing to optimise performance

Lift gas rate adjusted in response to changes in back produced gas

Maximise throughput subject to flowing bottom hole pressure limits before breakthrough

Reduced rate for post-WAG production

20 October 2010 27

10 3/4" x 9 5/8"

13 3/8"

24"

18 5/8"

TOCsssv

PDG

6 5/8“ GRE lined tubing

7 5/8“ GRE lined Tubing

1 joint 4”

2 7/8“ double GRE lined insert string

10 3/4" x 9 5/8"

13 3/8"

24"

18 5/8"

TOCsssv

PDG

Produced gasLift gas

Lift gas

Time

Tota

l pro

duced g

as r

ate

Produced gasLift gas

Lift gas

Time

Tota

l pro

duced g

as r

ate




Advantages and issues for integrated CO2 gas lift (1)

Minimises additional CAPEX

Uses recycle system, only requires modest increase in capacity

Can utilise main gas injection line for remote WHPs in cluster developments

Intrinsic risk management

Flexibility over number of wells to be gas lifted

Low productivity outcome – more wells on gas lift but later gas breakthrough

High productivity outcome – fewer wells on gas lift but earlier gas breakthrough

Reduced requirement for well workovers

Limited impact of insert string during autolift period

Compatibility with Smart well configuration




Advantages and issues for integrated CO2 gas lift (2)

Improves operating envelope for recycle compression

Reduces variation in molecular weight of recycled gas Recycled gas from reservoir varies between hydrocarbon gas prior to main breakthrough,

through to high content CO2 in mature WAG patterns

CO2 lift gas dilutes HC gas prior to CO2 breakthrough

Before significant CO2 breakthrough only limited volumes of produced gas to recycle, giving large turn-down requirement CO2 lift in early patterns increases rate of gas handling, reducing turndown and gives

opportunity to use single compressor train

Set of issues to address

Early CO2 lift gas will be imported gas, requirement to reduce oxygen content to low levels

Fully integrated view needed from source through EOR facilities




Integrated decisions – Facilities sizing

Onshore CO2 projects can evolve facilities handling capacity to accommodate rising recycle levels

Follow reservoir response

Offshore projects have more limited scope for phasing capacity

Key choice is gas handling

At pattern level, increasingtotal CO2 slug injected increases pattern recovery

Larger slug sizes significantlyincrease level of recycled gasto be reinjected

20 October 2010 30

-50%

0%

50%

100%

150%

-25% 0% +25% +50% +75%

Change in slugsize as fraction of base case

Ch

an

ge in

pro

du

ce

d v

olu

me

s

Water

Gas




Facilities sizing

Integrated subsurface-surface decision

Uncertainty in reservoir performance

Impact of heterogeneity on gas breakthrough and incremental recovery as function of slug size

Options to manage flood in response to reservoir performance

Flexibility in CO2 import rate

Phasing of EOR implementation through reservoir or field cluster

Total slug size selection on pattern basis

WAG ratio

Post-WAG waterflood

Use of integrated acid gas lift system provides intrinsic uncertainty management




Conclusions

In Europe capturing CO2 from industrial sources for use in EOR projects may provide a bridge to a lower carbon emissions future

requires moving CO2 EOR offshore

Shell studies show that offshore CO2 EOR is feasible

HSE requires special attention because of different operating environment compared to onshore CO2 EOR projects

Significant investment in new facilities usually required to handle back produced CO2

Greater linkage between surface and subsurface concept selection decisions than in primary or secondary developments

Close integration essential




Documents

Moving CO EOR offshoreiea-eor.ptrc.ca/2010/assets/F5_Slides.pdf · 2011-12-04 · Oil saturation (%) CO 2 has water-like injectivity CO 2 has water-like injectivity 0 200 400 600