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Canadian R&D Activities on CO 2 Capture and Sequestration Presentation to Tsinghua University Beijing, PRC 4 Dec 2001 Dr. Kelly Thambimuthu CANMET Energy Technology Center Natural Resources Canada. CO 2 Capture and Sequestration. Canada’s Kyoto Challenge. Importance of CO 2 C&S in Canada.

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slide1

Canadian R&D Activities on CO2

Capture and SequestrationPresentation to Tsinghua UniversityBeijing, PRC4 Dec 2001Dr. Kelly Thambimuthu

CANMET Energy Technology CenterNatural Resources Canada

slide4

Importance of CO2 C&S in Canada

  • Identified as key part of Canada’s Kyoto response
    • Electricity Table, Oil & Gas Sub-table, Technology Table
  • Especially important in Western Canada where impacts of Kyoto could otherwise be severe
    • But significant potential in Central and Eastern Canada
  • Key to sustainable development of Canada’s coal reserves
  • Large point sources exist in proximity to storage/ sequestration sites
  • Some storage sites offer value-added utilization of CO2 (EOR, ECBM)
  • Some technology aspects fairly well developed but costs are high and uncertainties remain
slide5

Comparison of Emission Reduction

Sources by 2010 (AMG Results)*

* (Path “2”, Scenario “Canada alone”, $58 per tonne)

slide6

Current S&T Projects in Canada

CO2

Sources

Capture

Transpor-

tation

Storage/

Use

Solvent based

capture (ITC)

Enhanced Oil

Recovery (Weyburn)

Source

Inventories

Pipeline

(Weyburn)

Oxy-fuel

Combustion (CETC)

Enhanced Coal-Bed

Methane Recovery

(ARC)

CO2 Storage

(AGS/GSC)

Flue gas capture

demo (CCPC)

slide7

International Projects

  • Zero Emission Coal Alliance (ZECA)
  • Sleipner West Field CO2 Injection Project
  • Deep Ocean Disposal Project (IEA-CTI)
slide8

Source Inventories (large point sources)

  • Acid gas reinjection
    • Already common practice
  • Existing “pure” CO2 streams ~ 10 Mt/a
    • Alberta only
    • From ammonia plants, hydrogen production, natural gas processing, ethylene and ethane production
  • Flue gases from electricity generation ~ 110 Mt/a
    • In 1997, coal-fired electricity generation accounted for 18% of Canada’s CO2 emissions (~ 95 Mt/a)
    • Majority in Alberta (~50%) and Saskatchewan (~15%)
  • Other large point sources ~ ?
    • Oils sands, cement, fertilizer plants, etc.
slide9

Primary Region of Interest for CO2 C&S

Alberta & Saskatchewan which

form a large part of the western

Sedimentary basin

slide10

Geological Sinks Inventory

• Rough estimates of CO2 storage capacity

• Western sedimentary basin only

  • Aquifers - 105 - 106 Mt
  • Enhanced coal bed methane - 104 - 105 Mt
  • Depleted natural gas - 103 - 104 Mt reservoirs
  • Enhanced oil recovery - 102 - 103 Mt
slide11

R&D in CO2 Capture Technologies

  • Post combustion CO2 capture with solvents
    • International Test Center (University of Regina/Boundary Dam)
  • Oxy-fuel combustion for CO2 enrichment & capture
    • CANMET Energy Technology Centre (& University of Waterloo)
  • Coal-fired utility plant demos with CO2 capture
    • Canadian Clean Power Coalition (Utilities, Coal Producers, Govt)
slide12

International Test Centre - CO2 Capture with Solvents

  • Goal: To refine solvent based capture technologies and reduce the energy penalty & cost of capturing CO2 from flue gases.
    • MEA (base solvent) and MEA alternatives
    • Optimizing column internals
    • Process integration
  • Partners: University of Regina, governments of Canada, Saskatchewan, Alberta and US, international utilities and industry
  • Two locations:
    • University of Regina - lab and small pilot scale
    • Boundary Dam - field pilot on power plant slip stream
  • Status:
    • Boundary Dam refit well underway
    • Sponsored University program just beginning
slide13

CO2 Capture with Solvents – ITC Facilities

Boundary Dam

Semi-commercial testing

(20-m H18 in. ID)

Commercial unit

(30-m H 3-6 m ID)

U of R

Technology development

(10-m H12 in. ID)

U of R

Technology screening

(3-m H1 in. ID)

U of R

Technical feasibility

(3-m H4 in. ID)

slide14

CO2 Capture with Solvents – Column Packings

Structured Packing

Random Packing

16-mm

Pall Rings

IMTP#15

Mini Rings

Gempak 4A

slide16

CETC - Oxy-fuel Combustion Technology

Oxy-Fuel Combustion Research

- burner development

- integrated emissions control research

- novel mercury control prospects

Stack Gas

CO2 Recovery

Process Development

- software development

- system energy optimization for retrofit case study

Cooling

Flue

Gas

CO2 Product

Compression

Cooling

CANMET CO2 Consortium

- phase 6 program started with new work in advanced cycles

- legal framework established with steering committee

Partners

TransAlta McDermott Tech.

EPCOR US DOE Sask Power Alberta Government

Ontario Power

N.S. Power

slide17

A Vision for Oxy-fuel Combustion

Steam Reforming

or Gasification

Direct

Combustion

Oxygen

Zero Emissions

and Increasing

Efficiency

CO2

Retrofit

Applications

New Cycles &

Infrastructure

Hydrogen or

H2 Carriers

Electricity and/or Heat

slide18

Boiler Island

Boiler Island

Oxy-fuel Combustion with Coal

N2 to atmosphere

Retrofit Case

Coal

CO2

(80%)

95% O2

ASU

CO2 Capture

3% air

infiltration

CO2

(98% @ 150 bar)

Recycled flue gas

N2 to atmosphere

New Plant Case

Coal

CO2

(>80%)

+99% O2

ASU

CO2 Capture

Higher volume% O2 in Feed

CO2

(98% @ 150 bar)

Recycled flue gas

slide19

CETC Research Activities

1995

1996

1997

1998

1999

2000

2001

2002

Phase 1 - Commissioning

Phase 2 - O2 / synthetic recycle

Phase 3 - O2 / real recycle

- CFD modeling

Phase 4 - O2 / CO2 for retrofits

- emissions and TE surveys

Phase 5 - improved CFD simulations (kinetics, NOx)

- integrated emissions work (ESP and CHX)

- process modeling (boiler and plant)

Phase 6 - O2 / CO2 burner concept and scale-up

- enhanced HG removal in CHX

- advanced power cycles (pressurised)

slide21

Oxy-Fuel Combustion Research

Obtain experimental results using a variety of oxygen enhanced firing techniques and fuels

Investigate the role of kinetics and pollutant formation mechanisms in high O2 and CO2 environments

Validate Computational Fluid Dynamic (CFD) model

GOAL: novel O2/CO2 burner concept and combustor/boiler operating conditions

slide22

Pilot-scale Validation of CFD Models

T

O2

NO

CANMET vertical combustor 0.3 MWt, 8.3 m x 0.61 m ID

slide23

Integrated Emissions Control

Investigate NOx, SOx, fine particulates and trace element capture mechanisms in a condensing environment

Develop chemistry that addresses more than one pollutant at a time

GOAL: novel multi-pollutant control process

slide25

Advanced Power Cycles

Pressurized (Syngas/CH4)/O2/CO2 combustion………

Syngas/CH4 burned at pressure with O2 in recycled CO2

Advantages:

CO2 rich product stream available at pressure

Disadvantages:

higher capital cost for pressurized combustion

slide26

Gas Turbine Combined Cycles

Semi Closed Gas Turbine cycle….

Advantages:

CO2 rich product stream available

efficient in combined cycle mode

Disadvantages:

development time for turbomachinery

slide28

Fuel Cell - Gas Turbine Cycle

Fuel Cell - Gas Turbine cycle….

Syngas or CH4 reformed for use in pressurised fuel cell which exhausts to turbine

Advantages:

CO2 rich product stream available

efficient in combined cycle mode

Disadvantages:

limited size of current fuel cells

slide29

Recent Program Achievements

  • Second generation oxy-fuel burner installed and tested, excellent CFD code validation
  • New ESP and Condensing Heat Exchanger (CHX) installed, excellent scrubbing of SO2, strong possibilities for integrated treatment of mercury
  • HYSYS Extensions developed for boiler performance prediction in O2/CO2 environments
  • Comparative economics developed for 400 MWe PC fired power plant retrofit (O2/CO2 vs. MEA)
  • Successful Consortium Meeting (June 2001)
slide30

CETC Program - Near Term Initiatives

  • Investigate the fine particulate and mercury removal prospects of the CHX® ( Q4:2001 )
  • Third generation O2/CO2 burner design, testing and scale-up studies ( Q1:2002 )
  • Development of field demonstration opportunity for O2/CO2 combustion (Q2:2002 )
slide31

Canadian Clean Power Coalition

  • Goal: Full-scale demonstration of coal-fired power plant with capture of CO2 and virtual elimination of other emissions
    • Retrofit ~ 2006
    • Greenfields ~ 2010
  • Partners: Utilities, coal producers, federal and provincial governments
  • Location: lead performers and plants not yet defined
  • Status:
    • Discussions among sponsors completed
    • Currently letting contracts on Phase 1: Engineering feasibility assessment of technology options
slide32

Schedule for Demonstration Plants

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

Feasibility Studies

End-Result : Proven retrofit technology

which meets all emission control needs

Retrofit Technology Development

Feasibility studies completed

and technology design selected

Retrofit completed and plant is operating

End-result:Advanced

technology for coal

power plant demonstrated.

New Coal Demonstration Plant

Technology selected

New technologies developed through R&D

Plant built and operating

slide33

R&D in CO2 Storage and Use

  • Enhanced Coal Bed Methane Recovery (ECBM)
    • Alberta Research Council and Supporting Consortium
  • CO2 Storage Capacity
    • Alberta Geological Survey and Canadian Geological Survey
  • Enhanced Oil Recovery (EOR) - Weyburn
    • Petroleum Technology Research Center and Consortium
slide34

Enhanced Recovery of Coal-Bed Methane

  • Goal: Injection of CO2 into deep coal beds to sequester CO2 and to enhance coal-bed methane recovery
  • Partners: Alberta Research Council, Governments of Canada, Alberta, U.S., U.K., Australia, Netherlands, industry (oil & gas, utilities)
  • Location: at the Fenn Big Valley Field, Alberta.
  • Status:
    • Phase 3A is underway
slide35

1. Rocky mountain foothills region

2. Plains region

200 Tcf

68 Tcf

Remaining

Established

Conventional

Gas Reserves

in 1995

CBM

Resources

In-Place

(CGPC 1997)

CBM Resources of Western Canada

slide36

Coal-bed Methane Recovery in Canada

  • At the present time, no large-scale commercial recovery projects
  • In general, Alberta coals have very low permeability compared to San Juan Basin coals
  • Gas production rates are low
  • Needs enhanced coalbed methane (ECBM) recovery technology to improve to economical recovery rates
slide38

MATRIX

CH4

CH4

H2O +

N2+ CH4

N2

Reduce Methane Partial

Pressure in Cleats

CH4

CH4

CH4

N2 - Enhanced CBM Recovery Mechanism

  • Inject Nitrogen in Cleats
  • Keep Total Cleat Pressure High
  • Reduce Partial Pressure of Methane
  • Methane Desorbs from Matrix and Diffuses to Cleats
  • Methane and Nitrogen & Water Flow to Wellbore
slide39

CO2 - Enhanced CBM Recovery Mechanism

  • Inject Carbon Dioxide in Cleats
  • Keep Total Cleat Pressure High
  • Reduce Partial Pressure of Methane
  • Carbon Dioxide Diffuses into Matrix and Adsorbs onto Coal
  • Methane Desorbs from Matrix and Diffuses to Cleats
  • Methane & Water Flow to Wellbore

MATRIX

CO2

CO2

CH4

CH4

H2O

+

CH4

Reduce Methane Partial

Pressure in Cleats

CO2

CH4

CO2

CH4

CO2

CH4

slide40

P

P

I

P

P

Forecast 5-Spot Pattern CBM Production

slide43

Flue Gas

CO2

N2

N2

Separation

CH4 to

Sales

Injection

Coal

Green Power Plant

Deep Coalbed

CO2

CH4

CH4

CH4

Open Cycle Concept for ARC ECBM

Recovery with CO2 Sequestration

  • Enhanced coalbed methane (ECBM) recovery
  • Sequestration of CO2
slide44

CO2

Closed Cycle Concept for ARC ECBM

Recovery with CO2 Sequestration

Flue Gas

N2

CO2

N2

Separation

Injection

Unmineable Coal bed

CH4

CH4

CH4

slide45

ARC ECBM RecoveryProject

Measure Resource Properties of Alberta CBM Reservoirs

Measure Flue Gas Composition versus Reservoir Response

Improve Predictive Capability of ECBM Reservoir Simulators

Model to Calculate Costs of Flue Gas/CO2 Source

Economic Evaluation of

CO2-ECBM Reservoirs in Alberta

slide46

ARC ECBM RecoveryProject

PHASES

YEAR

1997

Proof of Concept

for Alberta

I

1998

Single Well

CO2 Micro-Pilot

II

In Deep Coals

>1000 meters

1999

Single Well

Flue Gas Micro-Pilot

III-A

Drill Shallow Coals

<500 meters

2001

III-A

2002

5-Spot Enhanced

CBM Production

III-B

2003

CO2 Sources

III-B

Targeting of Best

CBM Reservoirs

2003

1998--

slide47

Outcome of ARC Single Well

Micro-pilot Tests with N2, Flue Gas & CO2

  • All single well micro-pilot tests were successful
  • Coal characterization completed
  • CO2 sequestration in coalbed is feasible
  • High quality data base available for numerical model validation
    • Injection & production rates
    • Composition vs. time
    • Bottom-hole pressure & temperature
slide48

A Cost Challenge for ECBM with CO2

Flue Gas

$ 0.7 – 4/t

Per 100 km

Compression

Pipelining

Separation

$ 8 - 10/t

$ 30 - 50/t

Injection

$ 2 - 8/t

$20/t ?

Geological Formations

slide49

CO2 Storage Capacity of Canadian Coal Seams

  • Goal: To understand the adsorptive capacity for CO2 of representative coal samples from coal seams in Canada.
  • Partners: GSC, NRCan, Alberta Geological Survey
  • Location: Alberta.
  • Status: Underway
slide51

Weyburn CO2 Monitoring Project (IEA)

  • Goal: Assessment of the mobility and long-term integrity and fate of CO2 when used for enhanced oil recovery.
  • Partners: PanCanadian Resources Ltd, Governments of Canada, Saskatchewan, European Union and USA, Petroleum Technology Research Centre, oil/gas and utility industries, private sector and academic performers under auspices of IEA GHG R&D Programme
  • Location: Weyburn, Saskatchewan.
  • Status:
    • Agreements being finalized for full four year project
    • Reservoir baseline study conducted (pre-injection)
slide52

Weyburn EOR Project

Goal: Recover 120 million

additional barrels of oil

from a partially depleted

Reservoir using a CO2

miscible flood

Partners: Pan Canadian

Resources

(commercial project)

Location: Weyburn, Sask

Status: Underway

slide53

Enhanced oil production

  • Effect of CO2 injection starting in 2000

Thousands bbl/d

50

Base Waterflood Production

Incremental Vertical Production

40

Incremental Horizontal Production

Incremental Miscible Flood Production

30

20

CO2

10

0

1955

1965

1975

1985

1995

2005

2015

2025

Date

slide54

Alberta

Saskatchewan

Edmonton

Saskatoon

Calgary

Regina

Weyburn: CO2 Pipeline

Regina

Goal: deliver 5000 tonnes/d

of CO2 from Dakota Gas plant to

Weyburn EOR project (320km)

Partners: Dakota Gas and Pan

Canadian Resources

Status: In operation

Weyburn

Saskatchewan

Canada

USA

North Dakota

Bismarck

CO2

slide55

Surface Facilities for CO2

4th Stage

Compression

CO2

Receiving Terminal

FE

3rd Stage

Compression

Producing

Well

2nd Stage

Compression

1st Stage

Compression

CO2 Injection Well

Oil

Satellite

Battery Gas

Compressor

Separator

Inlet

Separator

Free Water

Knock Out

Treaters

(Existing)

Water Injection Well

Water

Injection Plant

Sales Oil

slide56

Progress of the flood

T.7

EOR Area

Phase 1a

T.6

Phase 1b

Phase 2

Phase 3

T.5

R.14

R.13

R.12

W2M

slide57

Why the Weyburn Project?

  • A world-class CO2 project (Can$1.5 billion).
  • Easily accessible site
  • Substantial historical data base
  • Extensively drilled
  • Baseline data has been gathered
  • Supportive industrial partner
slide58

Key Questions

  • Is sequestration acceptable to the public and regulatory agencies?
  • Can sequestration into geologic formations offer long-term permanent storage for CO2?
  • How much CO2 can actually be stored and verified?
  • What are the economic drivers?
slide59

Methodology

  • Pre-injection baseline data
  • Collection of field performance data
  • Geologic description
  • Geochemical sampling, monitoring and prediction
  • Monitoring CO2 movement (seismic, reservoir sim)
  • Risk assessment – long term fate
  • Storage economics
slide60

Data Collection

  • $4.8
  • Geology
  • $2.0
  • Geochemistry
  • $1.5
  • Monitoring CO2 Movement
  • $11.0
  • Sequestration Performance
  • $4.0
  • Total
  • $23.3

Budget

Currency: Canadian dollars (millions)

slide61

Operational Milestones

  • Pre-injection baseline data collected
  • CO2 Injection Date - September 15, 2000
  • Phase 1A development drilling and facilities complete
  • Tracer study to monitor CO2 breakthrough commenced January 2001
  • Expected breakthrough - 4 to 8 months