Energy and the New Reality, Volume 2: C-Free Energy Supply Chapter 9: Carbon capture and storage L. D. Danny Harvey [email protected] [email protected].

Energy and the New Reality, Volume 2:

C-Free Energy Supply

Chapter 9: Carbon capture and storage

L. D. Danny [email protected]

This material is intended for use in lectures, presentations and as handouts to students, and is provided in Powerpoint format so as to allow customization for the individual needs of course instructors. Permission of the author and publisher is required for any other usage. Please see www.earthscan.co.uk for contact details.

Publisher: Earthscan, UKHomepage: www.earthscan.co.uk/?tabid=101808

Definitions:• Carbon Capture and Storage (CCS) refers to the

capture and disposal of CO2 released from industrial processes

• This has also been referred to as Carbon Sequestration, but this term has also been applied to the removal of CO2 from the atmosphere through the buildup of biomass (above-ground vegetation) and/or soil carbon

• CCS involving burial of captured CO2 in geological strata (either on land or under the sea bed), shall be referred to here as geological carbon sequestration, while buildup of soil or plant C shall be referred to as biological carbon sequestration

CCS is viable only where there is a concentrated stream of CO2 that would

otherwise be released to the atmosphere

• Electric power plants• Oil refineries• Petrochemical plants• Blast furnaces (an old-fashioned technology)• Cement kilns• N fertilizer plants

Figure 9.1 A chemical solvent-based plant that captures a mere 200 tCO2/day

Source: Thambimuthu et al (2005, IPCC Special Report on Carbon Dioxide Capture and Storage, Cambridge University Press, Cambridge, UK)

CO2 is easiest to capture when both the concentration and absolute partial

pressure are large

Table 9.1 Properties of gas streams

Source: Gale et al (2005, ‘Sources of CO2’, in IPCC Special Report on Carbon Dioxide Capture and Storage, Cambridge University Press, Cambridge, UK)

All of the stationary CO2 sources worldwide of 0.1 MtCO2/yr or more account for about 54% of total

world CO2 emissions (see Table 9.2)

Options for capture of CO2 from fossil fuel powerplants:

• From the flue gases after normal combustion of fuel in air

• From the flue gases after combustion of fuel in pure oxygen (oxyfuel methods in Table 9.3)

• Prior to combustion, during the gasification of coal (IGCC pre-combustion in Table 9.3)

• During the operation of fuel cells using fossil fuels

Processes for separating CO2 from other gases (applicable to capture after

combustion in air or during gasification)

• Absorption

- chemical (if low CO2 concentration) (MEA is a common solvent)

- physical (if high CO2 concentration) (Selexol is a common solvent)• Adsorption• Membrane• Liquefaction

Energy is required

• Chemical solvents require heat to drive off the CO2 (in concentrated form) and regenerate the solvent

• Physical solvents require heat or a pressure drop for regeneration

• Adsorbants require heat or a pressure drop for regeneration• Membrane systems require electrical energy to maintain a

high P on one side of the membrane• Liquefaction requires cooling the exhaust gas to as low as ~

220 K

Figure 9.2 CO2 phase diagram, showing the T-P combinations needed to liquefy CO2

Criticalpoint

Liquid

Triplepoint

Gas

304.2

Temperature (K)

216.8

5.11

Pre

ssur

e (a

tm) Solid

72.8

Source: Holloway (2001, Annual Review of Energy and the Environment 26, 145–166)

Combustion in oxygen

• The only gases produced are CO2 and water vapour

• Pure CO2 is produced by cooling the gas enough to condense out the water vapour (giving 96% CO2) followed by distillation if desired

• Energy is required to separate O2 from air in liquid form (usually by cooling the air to 89 K, at which point O2 condenses as a liquid)

IGCC

• Involves converting the coal to CO2, CO, and H2 by heating it in 95% oxygen

• The CO can be reacted with steam to produce more CO2 and H2

• The resulting stream is almost completely CO2 and H2, and the CO2 is easily removed prior to combustion of the H2

• Conversely, CO and H2 can be fed to the turbine, burned in air, and the CO2 removed after combustion using a chemical solvent

• Finally, CO and H2 can be fed to the turbine, burned in O2, and the CO2 separated by condensing the water vapour that is produced from combustion of the H2

Fuel cells

• Require a hydrogen-rich input fuel, which can be produced from natural gas or coal

• Solid oxide and molten carbonate fuel cells can both use CO and H2 as fuel, which is fed to the anode

• Unreacted CO and H2 in the anode exhaust can be combusted in pure oxygen to produce additional electricity with a gas turbine

• The final exhaust consists of H2O and CO2, which can be separated by condensing the water vapour

All methods of CO2 capture involve an energy penalty

• Capture after combustion in air requires either a physical or chemical solvent that absorbs the CO2 but which needs to be regenerated using heat, or uses membranes but requires ~ 15% of the powerplant output to create high pressures

• Capture after combustion in oxygen is easy (only H2O and CO2 are produced), but energy is required to separate oxygen from air (cryogenically)

• Capture during gasification of coal or during operation of fuel cells entails a very small penalty (a few % at most)

Table 16.15: Energy penalties associated with CO2 capture only. PC=pulverized coal, IGCC=integrated gasification combined cycle, NGCC=natural gas combined cycle, MCM=mixed conducting membrane.

Using Advanced TechnologyProcess

Using existing

technologyIPCC

(2005)Damon et al.

(2006)Retrofitting existing PC powerplants 43-77%New PC powerplant, post combustion oxyfuel

24-40% 15-43%25-33%

9%9-12%

New IGCC, pre-combustion Oxyfuel

14-25% 21-24% 5-9%8%

New NGCC, post-combustion Pre-combustion with membrane Oxyfuel MCM

11-22% 16-25% 6%5-6%2-8%

Fuel cell/turbine hybrid 13-44%Biomass IGCC 36%a

Pulp & Paper mill using black liquor waste 19%b

H2 production from coal 2.2%

Table 9.3: Energy penalties associated with CO2 capture only. PC=pulverized coal, IGCC=integrated gasification combined cycle, NGCC=natural gas combined cycle, MCM=mixed conducting membrane.

a Rhodes and Keith (2005)

b Möllersten et al (2004)

Figure 9.3 Efficiency penalty associated with the capture of CO2

0

2

4

6

8

10

12

PC MEA

34.8%

PC KS-135.3%

PC Oxy

35.4%

NGCCMEA

47.4%

NGCCKS-149.6%

NGCCOxy

44.7%

IGCCShell34.5%

IGCCGE

31.5%

Eff

icie

ncy

Pen

alty

(%

)Oxygen plantWater shift reactionCO2 compression & purificationPower for CO2 captureSteam for CO2 capture

Souce: Davison (2007, Energy 32, 1163–1176, http://www.sciencedirect.com/science/journal/03605442)

Because of the efficiency penalty, more fuel is needed to produce the same amount of electricity, and the effective CO2 capture fraction is reduced

For example, if 80% of the CO2 in the exhaust is captured but the efficiency of the powerplant drops from 40% to 35%, then 40/35=1.143 times as much fuel is required. The CO2 emission is this 0.2 x 1.143 = 0.229, so the effective capture fraction is only 77.1% (1.0-0.229)

Table 9.4: Effective fraction of CO2 captured. PC=pulverized coal, IGCC=integrated gasification combined cycle, NGCC=natural gas combined cycle, MCM=mixed conducting membrane.

a Rhodes and Keith (2005)

b Möllersten et al (2004)

Using Advanced TechnologyProcess

Using existing

technologyIPCC

(2005)Damen et al

(2006)Retrofitting existing PC powerplants 63-94%New PC powerplant, post combustion oxyfuel

81-88%88-99.5%

85%90-100%

New IGCC, pre-combustion Oxyfuel

81-91% 90-91% 85-90%100%

New NGCC, post-combustion Pre-combustion with membrane Oxyfuel MCM

83-88%82-100%

85-90%100%

85-100%Fuel cell/turbine hybrid 86-92% 80-100%Biomass IGCC 39%a

Pulp & Paper mill using black liquor waste 88%b

H2 production from coal 98%

Table 9.5: Capital cost ($/kW) of powerplants equipped with technologies for capture of CO2. PC=pulverized coal, IGCC=integrated gasification combined cycle, NGCC=natural gas combined cycle, MCM=mixed conducting membrane. Costs are projected costs after some period of learning.

Using Advanced TechnologyProcess

Using existing

technologyIPCC(2005)

Damen et al(2006)

Reference powerplants (no C capture, actual costs today for NGCC and PC, projected for IGCC)

NGCC 515-724New PC 1200-1500IGCC 1200-1600

Powerplants with C capture (all costs are projected)

Retrofitting existing PC powerplants 650-1950New PC powerplant, post combustion

oxyfuel1900-2600 1700-1800

1850-28501520

1800-2200New IGCC, pre-combustion Oxyfuel

1500-2300 1450-2200 1450-22001420-1550

New NGCC, post-combustion Pre-combustion with membrane

Oxyfuel MCM

900-1300 950-1225 700-1010940

820-1250Fuel cell/turbine hybrid 1800 990-2060Biomass IGCC 1980a

a Rhodes and Keith (2005)

Figure 9.4 Contribution of different costs to the cost of electricity with and without capture, transport and sequestration of CO2

0

1

2

3

4

5

6

7

NGCC-ref

NGCC-cap

IGCC-ref IGCC-cap

PC-ref PC-cap

Co

st (

euro

cen

ts/k

Wh

)Sequestration

O & M cost

Fuel cost

Capital cost

€536/kW55.4%

€998/kW48.2%

€1395/kW42.7%

€1881/kW35.6%

€1151/kW41.8%

€1976/kW31.4%

Source: Tzimas and Peteves (2005, Energy 30, no 14, 2672-2689, http://www.sciencedirect.com/science/journal/03605442)

Reality Check: A proposed 450-MW IGCC powerplant with carbon capture in Saskatchewan was abandoned after estimated costs ballooned from Cdn$3778/kW to Cdn$8444/kW.

The US DOE FutureGen project (a 275-MW IGCC plant that would co-produce electricity and hydrogen) was cancelled after projected costs rose from $3250/kW to $6500/kW.

State-of-the-art NGCC (60% efficiency) costs $400-900/kW in mature marketsWind turbines cost $1000-1500/kW

Progress Ratios

Many new technologies initially increase in price after being introduced, due to the discovery of defects in the original design, the correction of which entails greater costs. Later, costs begin to decline following a progress ratio formulation, whereby

C(t) = Co PR(lnR(t)/ln2)

where Co is the initial cost after corrections of defects and R(t) is the ratio of cumulative production at time t to the cumulative production pertaining to Co. The cost is multiplied by a factor PR for every doubling in the cumulative production.

Observed progress ratios after an initial price increase:

• Flue gas desulphurization, 0.89• Selective catalytic reduction, 0.88• Gas turbine combined cycle, 0.90• Production of liquefied natural gas, 0.86

Progress ratios without an initial price increase

• Pulverized coal boilers, 0.95• Production of oxygen, 0.90• Steam methane reforming to produce H2, 0.73

Capturing CO2 from biomass powerplants

The most efficient method of producing electricity from biomass is through biomass integrated gasification combined cycle (BIGCC), a technology that is still under development

Gasification of biomass would occur in pure O2, producing syngas (a mixture of CH4, CO2, CO and H2) and a char residue that is combusted to provide heat for the gasification process.

The syngas would be used in a gas turbine to generate electricity, with waste heat from the gas turbine used to produce steam for use in a steam turbine to generate further electricity (as in natural gas combined-cycle power plants, NGCC)

NGCC state-of-the art powerplants have an efficiency of 55-60%

BIGCC efficiency would be after 34% without capture of CO2 and only 25% with capture of CO2

The result is an effective CO2 capture fraction of only 39% and an increase in the required biomass by 33%

Figure 9.5 Capture of CO2 from BIGCC electricity generation

Water ShiftReaction

G TC C

Com bustor

CO Capture2

G asifier

Heat

30% C

Biom ass

Syngas

CH , CO , CO, H4 2 2

70% C64% E

Char55% C

25% E NetElectric ity

CO Em ission2

Syngas, 7% C, 59% E

CO Em ission2

8% C

CO Em ission2

30% C

7% C

Table 9.6 Characteristics of capture of CO2 from BIGCC powerplants (with or without the water shift reaction) that could be available after 10 years

of intensive R & D

B IG C C w ith c a p tu re P a ra m ete r

B IG C C w ith o u t ca p tu re

w ith o u t w a te r sh ift

w ith w a te r sh ift

C a p ita l co st ($ /k W ) 1 2 5 0 1 7 3 0 1 9 8 0 N e t e ffic ie n c y (H H V b a s is )(% ) 3 4 2 8 2 5 E m issio n (k g C /k W h ) 0 -0 .1 4 -0 .2 0 C a r b o n c a p tu re fr a ctio n 0 .4 4 0 .5 5 E ffe ctiv e C O 2 c a p tu re fra c tio n 0 .3 2 0 .3 9 N o n -fu e l O & M ($ /k W -y r) 1 0 0 1 3 1 1 4 6 C o st o f e lec tr ic ity (c en ts /k W h ) 5 .9 8 .2 9 .3 C o st o f C O 2 rem o v ed ($ /tC ) 1 0 2 1 2 3 1 3 5

Source: Rhodes and Keith (2005, Biomass and Bioenergy 29, 440–450

Various schemes for capturing CO2 that would be produced from gasification of black liquor (a

processing waste) in integrated pulp and paper appear to be much more favourable, but would

also require many years of intensive research and development

Capturing CO2 during the production of H2 from fossil fuels

• Steam reforming of methane• Gasification of coal

Figure 9.6 Mass and energy flows for production of H2 from natural gas with capture of CO2

B o iler &S tea m

G en era to r

S tea m

C O v en tedw ith ex h a u st

2

A irW a ter

F u e l3 0 m o les

C H In p u t4

1 0 0 m o les@ 8 8 0 k J /m o le

F eed sto ck7 0 m o les

2 8 0 m o les H@ 2 8 4 k J /m o le

2

C a p tu red C O2

M eth a n e S tea m R efo rm er& S h ift R ea c to r

C H + 2 H O C O + 4 H4 2 2 2

Figure 9.7 Projected breakdown of costs in producing H2 from natural gas with capture of CO2

0

2

4

6

8

10

12

Methane SRwithoutcapture

Methane SRwith capture

Coalgasification

withoutcapture

Coalgasificationwith capture

Co

st (

euro

s/G

J)

SequestrationO & M costFuel costCapital cost

Source: Tzimas and Peteves (2005, Energy 30, no 14, 2672-2689, http://www.sciencedirect.com/science/journal/03605442)

Capture of CO2 during the production of N fertilizer

• Production of ammonium nitrate from natural gas or coal releases CO2 chemically, in addition to the CO2 released through the combustion of fuels in order to provide heat for the chemical reaction

3CH4 + 4N2 + 2H2O + 8O2 → 4NH4NO3 + 3CO2 ↑

• Production of ammonium bicarbonate consumes CO2 chemically, offsetting (at least in part) the CO2 produced from combustion of fuels to supply heat for the reaction

3CH4 + 4N2 + 14H2O + 5CO2 → 8NH4HCO3 ↓

Conversely, flue gases from combustion of fossil fuels or biomass could be used as a source of C for the production of ammonium bicarbonate through the net reaction

2CO2 + N2 +3H2 + 2H2O → 2NH4HCO3↓

with the H2 produced electrolytically from water using renewable energy to generate the required electricity. 90% of CO2 in flue gases would be taken up by the above net reaction.

Capture of CO2 from ambient air

One direct capture scheme involved the following steps:

• Absorption of CO2 by NaOH solution, producing dissolved Na2CO3

• Reaction with Na2CO3 with Ca(OH)2 to produce CaCO3 and NaOH

• Decomposition of CaCO3 to CaO (lime) and CO2

• Reaction of CaO with H2O to regenerate Ca(OH)2

C balance of the preceding scheme:

• If heat and electricity are provided by cogeneration using coal, the C capture per GJ of coal energy is 32kg, while the C released from combustion of the coal is 25kgC – giving only a small net gain

• If 1 GJ of solar energy is used to cogenerate heat and electricity at 30% electrical efficiency, 29 kgC are captured, whereas using solar generated electricity to displace coal-generated electricity would avoid an emission (from coal) of 17 or 21 kgC (for coal powerplant efficiencies of 45% or 35%, respectively)

Thus, using solar energy to capture CO2 instead of displacing coal would be worthwhile from a CO2 emission point of view (although landscape and other impacts related to the use of coal would remain)

Compression of CO2

• Compression would be required prior to transport by pipeline, with an energy requirement of 300-400 kWh/tC if compressed from 1.3 to 110 atm

• If applied to all of the CO2 produced by a coal powerplant with 40% efficiency, this corresponds to an energy cost of 7-10% of the electricity produced

Liquefaction of CO2

• Liquefaction would be required prior to transport by ship, with an energy requirement of about 400-440 kWh/tC.

• The latter would amount to an efficiency penalty of 10-12% if applied to the CO2 produced from a coal powerplant, but less than 2% if applied to the 71% of the CO2 that can be easily captured while producing H2 from natural gas

Figure 9.8 Cost of CO2 transport by offshore and onshore pipeline

onshore

offshore

Mass flow rate (MtCO yr )2-1

6.0

5.0

4.0

3.0

2.0

1.0

0.00 5 10 15 20 25 30 35

Source: Doctor et al (2005, IPCC Special Report on Carbon Dioxide Capture and Storage, World Meteorological Organization, Geneva)

Figure 9.9 Cost of CO2 transport by offshore and onshore pipeline and by ship

offshore pipelineonshore pipeline

ship costs

Distance (km)

0 1000 2000 3000 4000 50000

5

10

15

20

25

30

35

40

45

50

Source: Doctor et al (2005, IPCC Special Report on Carbon Dioxide Capture and Storage, World Meteorological Organization, Geneva)

Table 9.10 Compounded energy penalty for capture and subsequent sequestration of carbon produced during the generation of electricity using different fuels and technologies, or from the production of hydrogen using different feedstock.

Electricity production Hydrogen productionNGCC PC IGCC NG Coal Biomass

CO2 emission and capture Hydrogen production efficiency 0.874 0.718 0.692Electricity generation efficiency without capture 0.601 0.424 0.478 0.600 0.500 0.500Electricity generation efficiency with capture 0.541 0.361 0.435Energy penalty for capture 0.111 0.175 0.099 Energy use for compression and transport

Increase in fuel use (fraction) 0.035 0.099 0.080 0.031 0.069 0.049 Compounded energy use for capture, compression and transport

As a fraction of energy use without sequestration 0.149 0.290 0.187 0.031 0.069 0.049

PC=pulverized coal power plant, NGCC=natural gas combined cycle power plant,IGCC=integrated gasification combined cycle power plant (using coal).

Disposal sites:

• Deep saline aquifers on land and beneath the ocean bed

• Depleted oil and gas fields• Active oil fields, as part of enhanced oil recovery• Coal beds (displacing coal-bed methane)• Injection below the 3000 m depth in the ocean

(liquid CO2 is denser than seawater at this and greater depths)

Storage of CO2 in deep saline aquifers

• Some remains as a gas, under pressure• Some dissolves very slowly into pore water• In aquifers rich in calcium and magnesium

silicates, the CO2 will react with the rock and carbonate will precipitate, reducing the permeability of the rock and creating a permanent trap where none existed before – flood basalts are particularly good

Existing and planned aquifer storage projects:

• Sleipner West gas field, underneath the North Sea (off of Norway)

• Deep aquifers in Japan and US, planned for Australia, Germany, and Norway

Storage of CO2 in depleted oil and gas fields and for enhanced oil and gas recovery

• CO2 is currently injected into the base of oil and gas fields in order to increase the oil or gas pressure, thereby increasing the amount of oil or gas that can be extracted

• Only the net CO2 storage should count as credits against emissions

• Storage in already-depleted oil and gas fields is another possibility, but would provide no economic credits and, like enhanced oil or gas recovery, would require long-distance transport of CO2 from the major emission regions to the major oil and gas fields

Storage of CO2 in coal beds

• Coal usually contains methane that is adsorbed onto the surfaces of micro-pores

• This methane is call coal-bed methane, and there can be up to 0.76 GJ methane/tonne of coal (compared to a heating value of coal itself of 32 GJ/t)

• CO2 has a greater affinity for coal, so injection of CO2 into coal beds will displace methane while being stored in the coal

• Up to CO2 molecules are adsorbed for every CH4 molecule displaced

• The methane would be collected and used as an energy source

Estimated Cost of Storage Step Alone:

• Onshore saline aquifers: $1-23/tC• Offshore saline aquifers: $2-110/tC• Onshore depleted oil fields: $2-15/tC• Onshore depleted gas fields: $2-45/tC

Estimated Worldwide Storage Potential on Land

• Oil and gas reservoirs: 230 GtC• Deep saline aquifers: 55-15,000 GtC, likely

minimum: 270 GtC• Coal beds, 16-54 GtC theoretical potential, 2

GtC practical potential• TOTAL MINIMUM: about 500 GtC, equal to

about 125 years if storing the one half of current fossil fuel emissions that would be amenable to capture

Environmental and Safety Issues Associated with Capture,

Transmission and Storage of CO2

Capture of CO2

• Emissions during production and transport of materials used for capture of CO2 (chemical or physical solvents, limestone and ammonia)

• Transport and processing of waste produced during regeneration of solvents

• Additional requirements for ammonia, limestone and water compared to generation of electricity without CO2 capture

• Increase NOx and ammonia emissions from pulverized-coal powerplants with CO2 capture

Figure 9.10 Withdrawal and consumptive water use in powerplants with and without capture of CO2

0

1

2

3

4

5

6

7

Without With Without With Without With

Wat

er U

se (

litre

s/kW

h)

Withdrawal

Consumption

Sub-critical PC Super-Critical PC IGCCSource: Shuster (2008, Estimating Freshwater Needs to Meet Future Thermoelectric Generation Requirements. US Department of Energy, National Energy Technology Laboratory)

Transmission and injection of CO2

• Rapture of CO2 pipelines – careful selection of routes needed, constrains locations of capture sites

• Well blow-outs during injection of pressurized CO2 into the ground

Storage in deep saline aquifers• Slow leakage, the potential sources of leakage being:

- fracturing of rock during CO2 injection, which must be carried out at high pressure

- leakage through injection and exploration boreholes or through oil-extraction boreholes (of which there are 400,000 in Alberta and 1 million in Texas, many of which are unmapped)

• Upward displacement of saline water into aquifers• Mobilization of toxic materials due to the weak acidity produced as CO2

reacts with groundwater• Foreclosure of the possibility in the future of using saline groundwater as a

source of freshwater (through desalination) or of using minerals dissolved in saline groundwater (Li, Zn and Mn in particular)

Storage in coal beds

• A given mass of methane is 72 times as effective as CO2 in warming the climate over a 25-year time span, so if only a small fraction of displaced methane leaks to the atmosphere rather than being captured and burnt (for energy), the global warming effect would exceed the benefit from capturing and storing CO2

• Injection of CO2 and capture of released CH4 would require an dense grid of pipes on the ground over the coal beds that are being used

Injection of CO2 into the deep ocean

• About 15% of the injected CO2 eventually leaks into the atmosphere

• There would still be global-scale impacts on ocean acidity

• More pronounced acidification would occur near the injection sites

Figure 9.11: Fate of CO2 emitted into the atmosphere or injected into the ocean

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

0 500 1000 1500 2000

Year

Fra

cti

on

Fraction remaining in atmosphere

Carbon pulse injected into atmosphere

Carbon pulse injected into shallow ocean

Carbon pulse injected into deep ocean

Figure 9.12a Fossil fuel CO2 emission scenarios

0

5

10

15

20

25

30

2000 2025 2050 2075 2100

Year

Fo

ssil

Fu

el C

O2

Em

issi

on

(G

tC/y

r) Scenario 1

Scenario 2

Scenario 3

Scenario 4

Figure 9.14b Rates of injection of CO2 into the oceans, equal to the difference in emissions between Scenario 4 of Fig. 9.12a and

the indicated scenario

0

10

20

30

1900 2100 2300 2500 2700 2900 3100

Year

Ra

te o

f C

Se

qu

es

trat

ion

(G

tC/y

ear

)

Scenario 1

Scenario 2

Scenario 3

Figure 9.15a Atmospheric CO2 concentration for emission Scenario 1 with and without C sequestration, and for emission Scenario 4.

250

500

750

1000

1250

1500

1750

1900 2100 2300 2500 2700 2900 3100

Year

Atm

osp

her

ic p

CO

2 (

pp

mv)

Scenario 4

Scenario 1 without sequestration

Scenario 1 withsequestration

Figure 9.15b Atmospheric CO2 concentration for emission Scenario 2 with and without C sequestration, and for emission Scenario 4.

250

300

350

400

450

500

550

600

650

700

750

1900 2100 2300 2500 2700 2900 3100

Year

Atm

osp

her

ic p

CO

2 (p

pm

v)

Scenario 4

Scenario 2 without sequestration

Scenario 2 withsequestration

Figure 9.15c Atmospheric CO2 concentration for emission Scenario 3 with and without C sequestration, and for emission Scenario 4.

250

300

350

400

450

500

550

1900 2100 2300 2500 2700 2900 3100

Year

Atm

osp

her

ic p

CO

2 (p

pm

v)

Scenario 4

Scenario 3 without sequestration

Scenario 3 withsequestration

Figure 9.14a Impact on CaCO3 supersaturation in ocean mean surface water of fossil fuel scenarios without CCS (solid lines) and with CCS (dashed lines)

0.0

1.0

2.0

3.0

4.0

5.0

1900 2100 2300 2500 2700 2900 3100

Year

Su

per

satu

rati

on

Scenario 1

Scenario 2

Scenario 3 Scenario 4

Figure 9.14b Impact on the pH of ocean surface water of fossil fuel scenarios without CCS (solid lines) and with CCS (dashed lines)

7.5

7.6

7.7

7.8

7.9

8.0

8.1

8.2

8.3

8.4

8.5

1900 2100 2300 2500 2700 2900 3100

Year

pH

Scenario 1

Scenario 2

Scenario 3 Scenario 4

Conclusion with regard to injection of CO2 into deep ocean water:

This is environmentally acceptable, if at all, only where CO2 injection is used as a complement to strong reductions in the use of fossil fuels (accelerating the phase-out of CO2 emissions from, for example, 2100 to 2070)

Injection of CO2 into sediments beneath the bed of the sea

• Unlike in terrestrial sediments, CO2 in the upper few hundred metres of marine sediments would be denser than the pore fluids because the temperature at any pressure found in marine sediments would be lower than the temperature at the same pressure in terrestrial sediments

• Thus, CO2 in these sediments would be stable (it would not tend to rise)

• The potential storage capacity in buoyantly stable sediments within the US economic zone, for example, is estimated to be several thousand GtC

Time scale large-scale deployment of CCS:

• 1-2 generations of demonstration projects for capture techniques using a variety of different coals (10-15 years)

• Monitoring of full-scale (1 MtCO2/yr) injection of CO2 into aquifers in 10 or so different geological settings over a period of 10 years

• After both of the above, gradual replacement of existing powerplants with C-capture plants – clearly no significant impact on CO2 emissions before mid-century

• Thus, CCS cannot be deployed fast enough to deal with the impending climate emergency

Magnitude

• Sequestration of only 1 GtC/yr is equivalent to 1/3 of the total current flow of oil out of the ground, with the need for a corresponding infrastructure

Legal Issues

• A rigorous regulatory process that has broad public and political support will be required if CO2 is to be sequestered underground on a large scale

• Some sort of international monitoring system will be needed if countries or companies are going to engage in international trading of credits related to sequestration of CO2

• Issues related to prohibition by international conventions of dumping of industrial waste in the ocean will need to be resolved (would fossil fuel CO2 qualify as an ‘industrial waste’?)

Supply Constraints

• The assumption in pursuing CCS is that there are ample supplies of coal, such that if CO2 emissions can be largely eliminated, this source of energy could power industrial societies for at least one century, possibly 2 or 3

• However, evidence presented in Volume 1 (Chapter 2, subsection 2.5.3) indicates that recoverable coal resources are much less than is commonly believed, with some analyses indicating a likely peaking in the annual Chinese coal supply by about 2030 and in the annual US coal supply by about 2050

Strategic Considerations:

• Don’t waste low-cost C storage potential storing CO2 emissions that can be eliminated in other ways

• In particular, don’t waste it on CO2 from coal plants. We can get coal off of the grid altogether in North America and in Europe in 30 years through a wind/solar/biomass/geothermal/hydro system interconnected with a backbone grid of HVDC lines, almost certainly at less cost than CCS

Strategic Considerations (continued):

• Focus on CCS from CO2 sources that are not so easy to otherwise eliminate – steel, cement, ammonia manufacture in particular

• Prepare to deploy CCS of CO2 released from the use of biomass for electricity generation, so as to create negative CO2 emissions

Finally, pursuing CCS of coal, even if effective from a climatic point of view, means that the

severe landscape impacts associated with coal mining, illustrated in the following slides, will

continue.

Strip mining in Australia

Source: Emily Rochon, GreenPeace

Mountain decapitation in Appalachia

Source: Kent Kessinger, www.ilovemountains.org

Coal mine in South Africa

Source: Emily Rochon, GreenPeace

Risk of accidents such as this one (collapse of a dam holding coal ash owned by the Tennessee Valley

Association in December, 2008)

Source: Emily Rochon, GreenPeace

TVA coal dam collapse (continued)

Source: Emily Rochon, GreenPeace

TVA coal dam collapse (continued)

Source: Emily Rochon, GreenPeace

Tar sands mining in Alberta, Canada, the processing of which is another intensive source of CO2 that has been considered for CCS while pursuing business-as-usual growth in the rate of extraction.

Source: www.petropolis-film.com (GreenPeace)